Final Report - National Energy Technology Laboratory - U.S. ...

Central 

Alaska 

Colville/ 

North Slope 

Puget Sound 

/West flank 

Cascade Mtns 

Modoc 

(Hornbrook) 

Sacramento 

Monterey Fm 

Santa Maria 

San Joaquin 

Los Angeles 

(deep) 

Cook Inlet 

U. S. Department of the Interior 

Geological Survey 

BASIN-CENTERED GAS SYSTEMS OF THE U. S. 

Columbia 

Great 

Basin 

Tertiary 

Salton 

Trough 

Preliminary Study 

by 

Vito F. Nuccio, Marin A. Popov, Thaddeus S. Dyman, Timothy A. Gognat, 

Ronald C. Johnson, James W. Schmoker, Michael S. Wilson, and Charles Bartberger 

Snake River 

Downwarp 

Wasatch 

Plateau 

Paradox 

(Cane Creek) 

Central Montana 

(Sweetgrass Arch) 

Four Corners 

(Chuar Group) 

N. end 

San Rafael 

Swell (Dakota) 

Park (CO) 

Raton 

Rio Grande 

Rift 

Permian 

Hanna 

Denver 

Abo Fm 

Midcontinent 

Rift 

Anadarko 

Arkoma 

Austin Chalk; 

Eagle Ford Fm 

(deep) 

St. Peter Fm 

(Michigan) 

Black 

Warrior 

Travis Peak Fm 

/Cotton Valley Group 

Pre-Clinton 

/Clinton-Medina 

Triassic Rift 

This report is preliminary, has not been reviewed for conformity with U. S. Geological Survey 

editorial standards and stratigraphic nomenclature, and should not be reproduced or distributed. 

Any use of trade names is for descriptive purposes only and does not imply endorsement by the 

U. S. Government.

BASIN-CENTERED GAS SYSTEMS OF THE U.S. PROJECT 

DE-AT26-98FT40031 

U.S. Department of Energy, National Energy Technology Laboratory 

Contractor: U.S. Geological Survey Central Region Energy Team 

DOE Project Chief: Bill Gwilliam 

USGS Project Chief: V.F. Nuccio 

Contract Period: April, 1998-November, 2000 

Final Report

TABLE OF CONTENTS 

Scope of Assessment............................................................. 5 

Objective........................................................................... 5 

Introduction........................................................................ 5 

Project Organization............................................................. 6 

Basin-Centered Accumulation .................................................. 7 

PHASE I 

Anadarko Basin................................................................... 14 

Appalachian Basin, Clinton/Medina Groups................................ 21 

Arkoma Basin .................................................................... 29 

Black Warrior Basin............................................................. 37 

Central Alaska Basins .......................................................... 45 

Chuar Group (Precambrian Paradox Basin).................................. 53 

Columbia Basin.................................................................. 58 

Cook Inlet, Alaska.............................................................. 64 

Denver Basin ..................................................................... 72 

Great Basin (Tertiary)........................................................... 82 

Gulf Coast (Austin Chalk)..................................................... 91 

Gulf Coast (Eagle Ford Formation).......................................... 98 

Gulf Coast (Travis Peak/Cotton Valley Formation) .................... 104 

Hanna Basin .................................................................... 111 

Los Angeles Basin............................................................. 119 

Michigan Basin, St. Peter Sandstone...................................... 126 

Mid-Continent Rift............................................................ 132 

Modoc Plateau, Hornbrook Formation..................................... 139 

Paradox Basin (Pennsylvanian).............................................. 147 

Park Basins, Colorado........................................................ 157 

Permian Basin, Abo Formation............................................. 165 

Raton Basin..................................................................... 173 

Rio Grande Rift................................................................ 181 

Sacramento Basin.............................................................. 188 

Salton Trough.................................................................. 195 

San Rafael Swell .............................................................. 203 

Santa Maria Basin............................................................. 211 

Snake River Downwarp, Idaho .............................................. 218 

Sweetgrass Arch, Montana, Alberta Basin................................ 226 

Triassic Rift Basins (Eastern U.S.)........................................ 233 

Wasatch Plateau, Utah........................................................ 240 

Western Washington .......................................................... 247 

Western North Slope, Alaska, Colville Basin............................ 254 

References Cited............................................................... 267 

Selected Bibliography......................................................... 284

PHASE II 

Albuquerque Basin............................................................. 288 

Anadarko Basin................................................................. 314 

Cotton Valley.................................................................. 341 

Michigan Basin ................................................................ 388 

Pasco Basin..................................................................... 401 

Raton Basin..................................................................... 416 

Sacramento Basin.............................................................. 430 

Travis Peak..................................................................... 457 

PROJECT ABSTRACT ............................................................ 502

SCOPE OF THE ASSESSMENT 

The scope of this project was to identify and characterize the geologic and geographic distribution of 

potential basin-centered gas systems throughout the U.S., including Alaska. This project identifies the 

basin-centered gas systems, and for selected systems, estimates the location of "sweet spots" where basincentered 

gas resources are likely to be produced over the next 30 years. This project covered a thirty 

(30) month period of performance; twelve months for Phase I (April, 1998 through 

March, 1999) and eighteen months for Phase II (June, 1999 through November, 2000. 

OBJECTIVE 

The principal objective of this project was to perform an analysis of basin-centered gas occurrence in 

the U.S. and analyze its potential significance to future natural gas exploration and development. This 

project utilized state-of-the-art procedures and knowledge of basin-centered gas systems, including 

stratigraphic analysis, organic geochemistry, basin thermal dynamics, and reservoir and pressure analyses. 

INTRODUCTION 

The primary purpose of this report is to characterize thirty-three (33) potential basin-centered gas 

systems/accumulations throughout the U.S. The characterizations are based on data from the published 

literature and from internal computerized well and reservoir data files. The USGS is currently re-evaluating 

the resource potential of basin-centered gas accumulations in the U.S. due to changing geologic perceptions 

about these accumulations and the availability of new data. Newly defined basin-centered accumulations in 

regions of the U.S. may result in new plays based on an analysis of data available since the 1995 U.S. 

Geological Survey National Assessment (Gautier et al., 1996). These potential basin-centered gas 

accumulations vary qualitatively from low to high risk and may/may not survive rigorous geologic scrutiny 

leading toward a full geologic assessment based on plays 

For this report, we selected thirty-three potential basin-centered gas accumulations throughout the U.S. 

They include the: Sacramento/San Joaquin basins, Raton Basin, Rio Grande Rift, Anadarko Basin, Travis 

Peak/Cotton Valley, Columbia Basin/W. Flank of the Cascades, Michigan Basin/St. Peter Sandstone, 

Cook Inlet, Alaska, Permian Basin/Abo Formation, Hanna Basin, Paradox Basin (Pennsylvanian shales), 

Western North Slope of Alaska, Central Alaska, Wasatch Plateau, Puget Sound, Modoc/Northern 

California, Santa Maria Basin/Monterey Formation, Los Angeles Basin (deep), Salton Trough, Great Basin 

(Tertiary basins), Snake River downwarp, Paradox Basin (Precambrian Chuar Group), Denver Basin, Park 

Basins of Colorado, North end of San Rafael Swell (Dakota Formation), Central Montana (Sweetgrass 

Arch), Mid-continent Rift, Arkoma Basin, Austin Chalk, Eagle Ford Formation, Texas, Appalachian Basin 

(Clinton-Medina and older Formations), Eastern U.S. Triassic Rift Basins, and the Black Warrior Basin. 

For each, we summarize the geologic setting and data favoring the existence a potential basin-centered 

accumulation.

PROJECT ORGANIZATION 

TASKS: 

Phase I (April 1998 through March 1999) 

The USGS shall conduct a National inventory of known basin-centered gas systems, 

define new potential systems, rank them according to levels of geologic certainty, further 

delineate their geologic and geographic characteristics, and produce a map showing their 

distribution throughout the U.S. 

Task No. 1 April 1998 through March 1999 

Conduct a National inventory of known basin-centered gas systems and produce a map 

showing geographic location, and supporting documentation of their stratigraphic location 

and geologic characteristics. 

Task No. 2 April 1998 through March 1999 

Re-examine basins and other areas throughout the U.S. that were previously defined as 

conventional accumulations, and determine if they might have been mis-classified. If it is 

determined that these basins or areas exhibit characteristics that could be consistent with 

those of basin-centered gas systems, maps of their location and supporting geologic 

documentation will be provided. 

Task No. 3 October 1998 through March 1999 

Risk and rank the newly created list of basin-centered gas systems according to levels of 

geologic certainty. 

Phase II (June 1999 through November 2000) 

Phase II focuses on defining “sweet spots” (that portion of the basin-centered gas resource 

that will be available in 30 years) within the seven basin-centered gas systems determined 

in Phase I (Sacramento/San Joaquin Basins, Raton Basin, Rio Grande Rift, Anadarko 

Basin, Travis Peak/Cotton Valley, Columbia Basin/W. Flank of the Cascades, Michigan 

Basin/St. Peter Sandstone). 

Task No. 4 June 1999 through November 2000 

Through rigorous geologic analysis, define “sweet spots” within the selected basincentered 

gas systems. 


For the “sweet spots”, make judgments and recommendations as to the 30-year 

availability of the gas resource. 


Prepare a final report that documents the Phase I and Phase II activities. The final report 

shall include a digital map showing all defined basin-centered gas systems for the U.S., 

documentation of their geologic characteristics, identification of selected potential sweet 

spots, and judgments and recommendations as to the social relevance of the resource 

(availability over a 30-year time frame).

BASIN-CENTERED/CONTINUOUS-TYPE ACCUMULATIONS 

Basin-centered or continuous-type accumulations are large single fields having spatial dimensions equal 

to or exceeding those of conventional plays. They cannot be represented in terms of discrete, countable 

units delineated by downdip hydrocarbon-water contacts (as are conventional fields). The definition of 

continuous accumulations is based on geology rather than on government regulations defining low 

permeability (tight) gas. Common geologic and production characteristics of continuous accumulations 

include their occurrence downdip from water-saturated rocks, lack of obvious trap or seal, relatively low 

matrix permeability, abnormal pressures, large in-place hydrocarbon volumes, and low recovery factors 

(Schmoker, 1995). 

Continuous plays were treated as a separate category in the U.S. Geological Survey 1995 National 

Petroleum Assessment and were assessed using a specialized methodology (Schmoker, 1995). These 

continuous plays are geologically diverse and fall into the following categories: coal-bed gas, some biogenic 

gas occurrences, fractured gas shales, and basin-centered natural gas accumulations. Only continuous-type 

basin-centered gas plays comprise significant future undiscovered resources in deep sedimentary basins. 

Assessment of continuous plays is based on the concept that an accumulation can be regarded as a 

collection of hydrocarbon-bearing cells. In the play, cells represent spatial subdivisions defined by the 

drainage area of wells. Cells may be productive, nonproductive, or untested. Geologic risk, expressed as 

play probability, is assigned to each play. The number of untested cells in a play, and the fraction of 

untested cells expected to become productive (success ratio) are estimated, and a probability distribution is 

defined for estimated ultimate recoveries (EURs) for those cells expected to become productive cells. The 

combination of play probability, success ratio, number of untested cells, and EUR probability distribution 

yields potential undiscovered resources for each play. Refer to Schmoker (1995) for a detailed discussion of 

continuous-type plays and their assessment. 

In 1995 the USGS defined 100 continuous-type plays with oil and gas reservoirs in sandstones, shales, 

chalks, and coals for all depth intervals. Of the 100 identified plays, 86 were assessed, of which 73 were 

gas plays. Estimates of technically recoverable gas resources from continuous-type sandstones, shales, and 

chalks range from 219 Tcf (95th fractile) to 417 Tcf (5th fractile), with a mean estimate of 308 Tcf. 

Estimates of technically recoverable gas resources from coals in the lower-48 States range from 43 Tcf to 

58 Tcf, with a mean estimate of 50 Tcf. Continuous-type accumulations were not assessed or identified in 

many areas or regions of the U.S. 

Four categories of continuous-type accumulations can be identified with respect to new data and 

perceptions since the USGS 1995 National Petroleum Assessment: (1) Continuous-type plays that were 

correctly identified as such, assessed in 1995, but need to be updated because of new data. (2) Continuoustype 

plays that may have been identified incorrectly as conventional plays and assessed as such in 1995. (3) 

Continuous-type plays that were identified as such in 1995 but not assessed because of a lack of data. (4) 

New continuous-type plays that were not identified in 1995. 

Basin-centered gas accumulations form a special group of continuous-type gas accumulations and differ 

significantly in their geologic and production characteristics from conventional accumulations. They have 

the following characteristics: 

1. They are geographically large and cover from 10s to 100s of square miles in aerial extent often occupying the 

central deeper parts of sedimentary basins. 

2. They lack downdip water contacts and hydrocarbons are not held in place by the buoyancy of water. 

3. Reservoirs are abnormally pressured. They may be under- or overpressured. 

4. The pressuring phase of the reservoir is maintained by gas. 

5. Water production is usually low or absent, or water production is not associated with a distinct gas-water 

contact. 

6. Reservoir permeability is low—generally less than 0.1 md.

7. Reservoirs are overlain by normally pressured rocks containing gas and water. 

8. Reservoirs contain primarily thermogenic gas, although shallow biogenic reservoirs are similar but occur in 

different geologic environments. 

9. Source rocks are of a local nature from either interbedded or nearby lithologies. 

10. Structural and stratigraphic traps are secondary in importance. Compartments exist and generally forma an 

array of accumulation “sweet spots.” 

11. Multiple fluid phases contribute to seal development in reservoirs. 

12. The tops of basin-centered accumulations occur within a narrow range of vitrinite reflectance, usually 

occurring between 0.75 and 0.9 Ro.

LIST OF POTENTIAL BASIN-CENTERED GAS ACCUMULATIONS OF THE U.S. 

For Phase I, the following thirty-three (33) basins/areas were reviewed by the U.S. Geological Survey to 

characterize their potential for basin-centered gas accumulations. The basins/areas were grouped into two categories, 

and are listed below. Some of the considerations for our grouping included: 

(1) the amount of data available for an area, and our level of confidence in the data, 

(2) the 30-year impact of the potential accumulation, 

(3) the magnitude or size of the potential resource, 

(4) the geologic risk (e.g., depth, remoteness), 

(5) national distribution, and 

(6) the relationship to the USGS 1995 oil and gas assessment (have our perceptions about an area changed 

since then?). 

The list is divided into (1) High Potential Accumulations, or those for which we feel have high potential 

for development over the next 30 years, and (2) Other Potential Accumulations, those for which we feel have 

potential but will not be as high a priority within the next 30 years. The accumulations highlighted in bold type 

(within the high-potential list) are those studied in Phase II of this project. 

HIGH POTENTIAL ACCUMULATIONS: 

Sacramento/San Joaquin basins 

Raton Basin 

Rio Grande Rift 

Anadarko Basin 

Travis Peak/Cotton Valley 

Columbia Basin/W. Flank of the Cascades 

Michigan Basin/St. Peter Sandstone 

Cook Inlet, Alaska 

Permian Basin/Abo Formation 

Hanna Basin 

Paradox Basin (Pennsylvanian shales) 

OTHER POTENTIAL ACCUMULATIONS: 

Western North Slope of Alaska Denver Basin 

Central Alaska Park Basins of Colorado 

Wasatch Plateau North end of San Rafael Swell (Dakota Formation) 

Puget Sound Central Montana (Sweetgrass Arch) 

Modoc/Northern California Mid-continent Rift 

Santa Maria Basin/Monterey Formation Arkoma Basin 

Los Angeles Basin (deep) Austin Chalk 

Salton Trough Eagle Ford Formation, Texas 

Great Basin (Tertiary basins) Appalachian Basin (Clinton-Medina and older Formations) 

Snake River downwarp Eastern U.S. Triassic Rift Basins 

Paradox Basin (Precambrian Chuar Group) Black Warrior Basin

POTENTIAL BASIN-CENTERED GAS ACCUMULATIONS WITH RESPECT TO USGS 1995 

PETROLEUM ASSESSMENT 

This section briefly describes how the 33 accumulations identified for this study relate to the USGS 1995 

assessment. The reason we chose several of the accumulations for this study is that they were not either identified, 

assessed, or understood well in 1995. However, at the present time, we feel that all 33 have at least some potential 

for new gas resources. Shown, is the name of the accumulation, the Region of the U.S. where it is located (as 

defined in the 1995 assessment), the Province where the accumulation is located (as defined in the 1995 assessment), 

and a note about how the accumulation relates to the plays identified and assessed for that Province in 1995. 

Accumulation 

Region 

Province 

Notes 

Sacramento Basin 2 9 2 conventional plays assessed. No 

continuous plays assessed; potential for 

new gas resources. 

San Joaquin Basin 2 10 No continuous plays assessed; potential 

for new resources in Late Cretaceous 

strata. 

Raton Basin 4 41 No continuous plays assessed; potential 

in L. Tertiary and U. Cretaceous strata. 

Rio Grande Rift 3 23 5 conventional plays assessed. No 

continuous plays assessed. 

Anadarko Basin 7 58 5 conventional plays assessed. 1 

continuous play defined but not assessed. 

Potential for new continuous gas in 

Miss. and Penn. Strata. 

Travis Peak/Cotton Valley 6 49 2 conventional and 1 continuous Cotton 

Valley play assessed. Need to re-evaluate 

conventional to see if it is actually 

continuous. 

Columbia Basin/ 2 4 1 continuous play assessed. Need W. 

Flank of Cascades for further study based 

on new perceptions. 

Michigan Basin/St. Peter Ss 8 63 2 unconventional shale plays assessed. 

No continuous Ss plays assessed but 

potential new gas may be identified in 

Ss. 

Cook Inlet, Alaska 1 3 3 conventional plays assessed. No 

Continuous plays identified or assessed. 

Potential in Cretaceous and Jurassic 

strata. 

Permian Basin/Abo Formation 5 44 No continuous plays assessed. Potential 

in Abo Fm.

Accumulation 

Region 

Province 

Notes 

Hanna Basin 4 37 5 continuous plays assessed in the 

Greater Green River Basin. No 

continuous plays defined or assessed in 

the Hanna Basin. 

Paradox Basin (Penn. Sh) 3 21 6 conventional and 1 continuous play 

assessed. Potential for new gas resources 

in Penn. shales. 

Western North Slope of Alaska 1 1 11 conventional plays assessed. No 

continuous plays assessed, but potential 

in Jurassic and Cretaceous strata. 

Central Alaska 1 2 5 conventional plays assessed. No 

continuous plays assessed; little data. 

Wasatch Plateau 3 20 6 conventional and 15 continuous Plays 

assessed. No Wasatch Plateau Ss plays 

assessed. 

Puget Sound 2 4 9 conventional plays assessed. 1 

continuous play defined but not assessed. 

Modoc/Northern California 2 No plays identified or assessed. 

Santa Maria Basin/Monterey Fm. 2 12 4 conventional Monterey plays assessed. 

No continuous plays defined. 

Los Angeles Basin (deep) 2 14 7 conventional plays assessed. 1 

unconventional oil and gas play defined 

but not assessed. 

Salton Trough 2 Not addressed in the 1995 assessment. 

High risk/low priority. 

Great Basin (Tertiary basins) 3 19 6 conventional plays assessed. No 

continuous plays but potential in 

Tertiary basins. 

Snake River downwarp 3 17 4 conventional plays assessed. No 

continuous plays defined because of high 

risk. 

Paradox Basin (Precambrian) 3 21 Not addressed in the 1995 assessment. 

Denver Basin 4 39 6 conventional and 5 continuous oil and 

gas plays assessed. There is likely 

overlap between the two types of 

accumulations.

Accumulation 

Region 

Province 

Notes 

Park Basins of Colorado 4 38 2 conventional plays assessed, and 1 

continuous oil play identified. 

N. end San Rafael Swell 3 20 6 conventional and 15 continuous 

(Dakota Fm.) plays assessed. Potential 

for continuous play in Dakota Fm. 

Central Montana 4 28 8 conventional and 4 continuous 

(Sweetgrass Arch) plays assessed. 

Possibility that at least one conventional 

might be reassessed as continuous. 

Arkoma Basin 7 62 8 conventional plays assessed. No 

continuous plays identified but potential 

in Atokan strata. 

Austin Chalk/Eagle Ford Formation 6 47 3 Austin plays assessed. Potential for 

continuous gas play below the Austin 

Appalachian Basin (Clinton-Medina 8 67 18 conventional and 15 

and older strata) continuous plays assessed. Continuous 

plays require further delineation of sweet 

spots. 

Eastern U.S. Triassic Rift Basins 8 70 1 Mesozoic continuous play assessed. 

Black Warrior Basin 8 65 4 conventional plays and 4 continuous 

coalbed methane plays assessed.

ACKNOWLEDGEMENTS 

Various individuals contributed to project research and authoring. Alphabetically, these include C. 

Carothers, J.C. Fiduk, M.A. Heinrich, C. Marchand, S.K. Nodeland, A.M. Ochs, K.M. Peterson, S.S. 

Shapurji, R. Tauman, and R. Wells. 

REFERENCES 

Schmoker, J.W., 1995, Method for assessing continuous-type (unconventional) hydrocarbon 

accumulations, in Gautier, D.L., Dolton, G.L., Takahashi, K.I., and Varnes, K.L., eds., 1995 

National Assessment of United States oil and gas resources – Results, methodology, and 

supporting data: U.S. Geological Survey Digital Data Series DDS-30 [CD-ROM]. 

U.S. Geological Survey National Oil and Gas Resource Assessment Team, 1995, 1995 National 

Assessment of United States Oil and Gas Resources: U.S. Geological Survey Circular 1118, 20 

pp.

GEOLOGIC SETTING 

The Anadarko Basin extends from western Oklahoma to the eastern part of the Texas panhandle. Figure 1 

shows the geomorphic or tectonic features that border the basin: the Amarillo Uplift to the southwest, the Wichita- 

Criner Uplift to the south, the Arbuckle and Hunton-Pauls Valley Uplift to the southeast, the Nemaha Ridge and 

Central Oklahoma Platform to the east, and the Northern Oklahoma Platform to the north. The Anadarko Basin is 

asymmetric in profile and deepest along the steep southwestern flank near the Wichita Fault system. Displacement 

along this fault exceeds 30,000 feet (Al-Shaieb, et al., 1997a). 

One of the deepest basins in the United States, the Anadarko Basin contains over 40,000 feet of Paleozoic 

sediments. Figure 2 shows a generalized stratigraphic column of the basin. Hill and Clark (1980) have divided the 

deposits into five sequences: 1) a mid-Cambrian Arbuckle to post-Hunton-orogeny period (of mostly carbonate 

deposition), with hydrocarbons found mainly in structural traps; 2) Mississippian deposition of carbonates that 

formed stratigraphic traps for gas; 3) Pennsylvanian deposition of Morrow-Springer series clastic rocks (mostly in 

the northern shelf areas where the sediments were unaffected by orogenic movements in the southern parts of the 

basin); 4) post-Morrowan or Late Pennsylvanian deposition of segregated sand lenses; and 5) deposition of lower to 

middle Permian dolomitized shelf carbonates and Pennsylvanian Granite Wash sediments. 

Formation of the Anadarko Basin began during the collision of Gondwana with the southern continental margin 

of Paleozoic North America. Structural inversion of the core of the southern Oklahoma aulacogen into the Wichita 

thrust belt caused thrust loading of the region to the north, which subsided and became the Anadarko Basin. Late 

Pennsylvanian transpression formed numerous thrust-cored, en-echelon anticlines within the southeastern part of the 

basin that were later eroded and overlain unconformably by Permian carbonates. Subsidence of the basin continued 

into middle Permian time. The basin has remained quiescent since late Permian time (Perry, 1989). 

HYDROCARBON PRODUCTION 

Major hydrocarbon production from the Anadarko basin includes gas and oil from multiple Pennsylvanian 

reservoirs (Granite Wash, Atoka, Morrow, and Springer Formations). The largest Pennsylvanian Atoka field is the 

Berlin in Beckham County, Oklahoma, with an estimated ultimate recovery of 362 BCFG at 15,000 ft depth (Lyday, 

1990). Some deep production has occurred from Mississippian through Cambro-Ordovician strata: Washita Creek 

field in Hemphill County, Texas, from the Cambro-Ordovician at 24,450 ft depth (single well reserves as high as 24 

BCFG); and the Knox field (near the southeastern flank of the basin) from the Ordovician Bromide (Simpson) at 

15,310 ft depth (single well reserves as high as 6.2 BCFG). 

EVIDENCE FOR BASIN-CENTERED GAS 

Strong evidence for a basin-centered gas accumulation is present in the form of thermally mature source rocks, 

widespread production and shows of gas, and overpressuring (Figure 3) that cuts across stratigraphic boundaries. 

The Woodford shale forms the base of the pressure cell (Figure 4); the top of the cell climbs stratigraphically into 

the basin. Vitrinite reflectance values for the Woodford follow this same general trend. The Pennsylvanian Atokan 

source rocks may exhibit these same maturation trends. 

1

Province, Play and 

Accumulation Name: 

Geologic 

Characterization of 

Accumulation: 

KEY ACCUMULATION PARAMETERS 

Mid-Continent Province, Anadarko basin, Megacompartment Complex Play, 

Devonian Woodford through Pennsylvanian Oswego overpressured cell 

a. Source/reservoir interval includes Devonian Woodford shale through Pennsylvanian Oswego 

formation, overpressured Megacompartment Complex (Al-Shaieb et al., 

1997b) 

b.Total Organic Carbons 

(TOCs) 

values for the Woodford Shale range to 9%. Atokan values unknown, but 

assumed to be high (Hester et al., 1990) 

c.Thermal maturity Ro 0.5 – 2.0 (values from Woodford shale) (Hester et al., 1990) 

d.Oil or gas prone gas prone 

e.Overall basin maturity mature 

f.Age and lithologies Cambrian to Permian; sands, shales, carbonates, and granite wash 

g. Rock extent/quality apparent basin-wide source and reservoir-rock distribution; rocks often 

become tight in the deeper parts of the basin 

h.Potential reservoirs many producing reservoirs 

i.Major traps/seals Woodford Shale, Atokan shales, Cambrian through Devonian shales and 

carbonates 

j.Petroleum 

generation/migration 

models 

both in-situ generation and long distance migration of gases and oils from 

shales, carbonates and coaly rocks. The Bakken Shale model of Meissner 

(1978) for hydrocarbon generation and expulsion applies to evaluation of the 

Woodford Shale 

k.Depth ranges productive rocks occur at depths greater than 26,000 ft. Overpressure occurs 

below 10,000 ft (Al-Shaieb et al., 1997) 

l.Pressure gradients range from about 0.28 psi/ft outside the pressure cell to 0.8 psi/ft in the 

Springer-Morrow section, in the deepest part of the basin (Al-Shaieb et al., 

1997)

Production and Drilling 

Characteristics: 

Economic 


a. Important 

fields/reservoirs 

b.Cumulative production 

many fields produce from Cambrian through Permian rocks: Washita Creek 

field in Hemphill County, Texas, at the west end of the basin (from the 

Cambro-Ordovician at a depth of 24,450 ft; single well reserves as high as 24 

BCFG); 

Knox field near the southeastern flank of the basin (from Bromide (Simpson) 

production at 15,310 ft depth; single well reserves as high as 6.2 BCFG) (Al- 

Shaieb et al., 1997); 

Berlin field in Beckham County, Oklahoma (from the Pennsylvanian Atokan 

formation; estimated ultimate recovery of 362 BCFG at 15,000 ft depth 

(Lyday, 1990)) 

a. High inert gas content gases are generally high in Btu content and low in total inert gases 

b.Recovery recoveries vary depending on permeability, porosity and depth 

c.Pipeline infrastructure very good 

d.Overmaturity overmature in the deepest parts of the basin 

e.Basin maturity most of the basin is mature (Ro values for the Woodford exceed 0.7%) 

(Hester et al., 1992) 

f.Sediment consolidation most rocks are well indurated 

g. Porosity/completion 

problems 

Shales, tightly cemented sands & other tight (low permeability rocks) have 

the potential to produce where naturally fractured (many deep Anadarko 

basin fields have permeabilities of less than 0.1 md). Water sensitive clays 

also cause problems. 

h.Permeability ranges from less than 0.08 up to 6,000 md 

i.Porosity highly variable

AMARILLO 

UPLIFT 

Oklahoma 

Texas 

100° 98° 

96° 

NORTHERN OKLAHOMA 

PLATFORM 

ANADARKO BASIN 

WICHITA-CRINER 

UPLIFT 

RED RIVER UPLIFT 

MUENSTER-WAURIKA ARCH 

CENTRAL OKLAHOMA 

PLATFORM 

HUNTON 

PAULS VALLEY 

UPLIFT 

ARDMORE 

BASIN 

MARIETTA BASIN 

ARBUCKLE 

UPLIFT 

0 

0 100 km 

OZARK 

UPLIFT 

ARKOMA BASIN 

OUACHITA SYSTEM 

Figure 1. Tectonic map showing location of the Anadarko basin and the major structural features of Oklahoma. After Al-Shaieb and 

Shelton (1977), Arbenz (1956). 

100 mi 

37° 

36° 

35° 

34°

,, 

,, 

,, 

,, 

Dolomite 

Limestone 

Chert & conglomerate 

, ,,, 

PERMIAN 

BROWN DOLOMITE 

,,, HEEBNER 

TONKAWA 

,, ,, MEDRANO 

MARCHAND 

,, 

OSWEGO 

RED FORK 

ATOKA 

CHERT- ,,, , 

, 

CONGLOMERATE 

,,, 

MORROW 

WEDGE 

, 

SPRINGER 

PENNSYLVANIAN 

CHESTER 

,,, 

MISSISSIPPIAN 

MERAMEC 

OSAGE 

,,, 

, WOODFORD 

SILURO-DEVONIAN 

HUNTON 

,,, 

,,, 

SYLVAN 

VIOLA 

,,, 

ORDOVICIAN 

,,, 

SIMPSON 

,,, 

ARBUCKLE 

REAGAN 

CAMBRIAN 

BASEMENT 

, ,, ,, , , 

,, ,,, 

, , 

,, , ,,, 

,,, , 

ARKOSIC WEDGE 

,,, , ,,, , ,,, , 

,,, 

, 

, ,,, 

, 

, 

, 

, 

,, 

,,, , ,,, , 

,,,, 

,,,, 

EXPLANATION 

Shale 

Sandstone 

Tuff breccia 

MEGA COMPARTMENT COMPLEX 

LOCALIZED 

OVERPRESSURED 

COMPARTMENTS 

,,,, 

,,,, 

Basement complex 

Figure 2. Generalized stratigraphic column of the Anadarko basin showing the intervals contained within 

the Mega Compartment Complex (MCC) and the stratigraphic position of two localized 

overpressured compartments outside the MCC. After Evans (1979).

Depth (feet) 

0 

5,000 

10,000 

15,000 

20,000 

25,000 

30,000 

35,000 

EXPLANATION 

,,, 

,,, 

,,,, 

SW NE 

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PERMIAN 

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VIRGILIAN 

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MISSOURIAN 

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BASAL SEAL 

,,,,, ,,,,,,,,,,,,,,,,,,,,,, 

,,,,,,,,,,,,,,,,,,,,,, 

Limestone 

WICHITA 

MOUNTAINS 

,,,, Basement complex 

LATERAL SEAL 

Normal and subnormal pressure zone 

REYDON 

CHEYENNE 

AREA 

Mega Compartment Complex (overpressured) 

ATOKAN 

DESMOINESIAN 

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,, ,, 

, 

MORROW-SPRINGER 

VIOLA 

MISSISSIPPIAN 

HUNTON 

SIMPSON 

ARBUCKLE 

BASEMENT 

TOP SEAL 

SW NE 

0 

100 mi 

0 100 km 

100° 95° 

Figure 3. Generalized cross section of the Anadarko basin showing the spatial position of the Mega 

Compartment Complex (MCC) within the basin. Geopressures within the MCC are maintained by 

top, lateral, and basal seals. After Al-Shaieb et al. (1997). 

LEEDEY 

FIELD 

PUTNAM 

TREND 

WATONGA 

TREND 

37° 

34°

Depth (ft) 

0 

5,000 

10,000 

15,000 

20,000 

25,000 

0.465 psi/ft 

VIRGILIAN 

, , 

, 

MISSOURIAN 

0 5,000 10,000 

DESMOINESIAN "SKINNER" 

LEVEL 2 

Pressure (psi) 

DESMOINESIAN "RED FORK" 

WOODFORD SHALE 

UPPER MORROWAN 

ORDOVICIAN-DEVONIAN 

"HUNTON" 

15,000 20,000 

Figure 4. Graphical representation of a pressure-depth profile lillustrating the relationship among Levels 1, 2, 

and 3. Note that Level 2 compartments are essentially clusters of isolated Level 3 compartments. This 

pressure-depth profile represents the Reydon-Cheyenne area in western Oklahoma. 

After Al-Shaieb et al. (1997).


The Appalachian basin extends southwestward from the Adirondack Mountains in New York to central Alabama. 

Figure 1 includes the area’s location . Structural boundaries include the Cincinnati arch in western Ohio, the 

Allegheny Front to the east, and the Blue Ridge of West Virginia. The basin is about 900 miles long and 300 miles 

wide and includes at least 100 million surface acres (Roth, 1964). 

The Appalachian basin originated as a sedimentary trough on the Precambrian surface that was later covered by 

Cambrian seas. Deposition of great masses of marine and continental sediments occurred throughout the Paleozoic 

Era. Carbonate and siliclastic tongues extended basinward from opposite margins synchronously in response to sea 

level drops. The interplay of eustatic sea-level drop and local tectonic uplift resulted in stratigraphic sequences 

bounded by widespread unconformities (Brett et al., 1990). Figure 2 shows correlation of the stratigraphy across the 

basin. Three major orogenic events affected the basin: the Taconic Orogeny (Late Ordovician), the Acadian Orogeny 

(Late Devonian), and the Allegheny Orogeny (Late Permian). 

1 

The geotectonic history of the basin includes the following stages: 

1) Precambrian: metamorphic and igneous rocks of the Grenville deformation form a basement under the 

Appalachian Foreland. 

2) Early and Middle Cambrian: offset of the basement surface associated with the formation of the Iapetus 

Ocean during Late Precambrian and Early Cambrian (Schumaker, 1996). 

3) Upper Cambrian-Middle Ordovician: relative crustal stability and the formation of a broad carbonate shelf. 

In the Middle Ordovician, a Foreland basin develops from compression of the passive, carbonate-dominated 

continental margin during collision with an island arc system (Taconic Orogeny). Thick turbidite sequences 

record the early phases of the orogeny. 

4) Late Ordovician (Ashgillian): waning of the main Taconic pulse, and deposition of the Bald Eagle-Oswego 

sandstone wedge and the Juniata-Queenston red bed sequences. 

5) Late Ordovician to Early Silurian: tectonic rejuvenation of the Taconic Front. In New York State, evidence 

for a late Taconic pulse lies in the regionally extensive, low-angle unconformity at the Ordovician-Silurian 

boundary (Cherokee Unconformity). 

6) Early Silurian (Cherokee Unconformity) and Late Silurian (Salinic Unconformity): eastward subsidence of 

the Appalachian Foreland Basin, which coincides with tectonic quiescence and thrust-load relaxation. A 

thick Early Silurian clastic wedge results from this subsidence. Westward migration in the foreland basin 

occurred during the Middle Silurian, depositing finer-grained strata; increased tectonism and onset of the 

Salinic Disturbance may have caused this migration. A small-scale unconformity at the Siluro-Devonian 

boundary may represent the latest Silurian tectonic activity (Brett et al., 1990). 

7) Devonian-Late Permian: The Acadian (Devonian) and Allegheny orogenies (Late Permian) correlate to the 

collision of the North American plate with other continental plates, eventually creating Pangaea at the end 

of the Paleozoic (Schumaker, 1996). During the Allegheny (Appalachian) Orogeny, tremendous thrust 

pulses from the east and southeast intensely folded and faulted the rocks in the eastern area. The deformation 

becomes gradually less intense westward. The Ridge and Valley province shows the greatest folding of 

rocks. The Allegheny Orogeny primarily determined the present day geologic pattern dividing the area into 

two main parts–the Plateau province, and the Ridge and Valley province (Roth, 1964).


The Appalachian basin has the longest history of oil and gas production in the United States. Since Drake's 

Titusville discovery well in 1859, oil and gas has been continuously produced in the basin. Although opportunities 

for oil and gas still exist (Petzet, 1991), new field discoveries are rare, and the Appalachian basin has been considered 

a mature petroleum province as most of the significant plays have been already discovered and developed. 

2 

Conventional Plays: Production from Late Cambrian to Late Ordovician rocks is considered conventional: 

(1) The Upper Ordovician Queenston Formation produces gas from sandstones and sandy facies trapped in lowamplitude 

anticlines and fractures. 

(2) The Middle Ordovician Trenton play produces from fractured micrite in the transition zone between the 

Trenton limestone and the overlying Utica Shale (Ryder et al., 1995). 

(3) The Middle Ordovician St. Peter sandstone produces from structural traps. 

(4) The Late Cambrian-Late Ordovician Knox Dolomite produces from structural and stratigraphic traps. 

(5) The Cambrian pre-Knox Group (Conasauga Fm., Rome Fm., and Mt. Simon Sandstone) is extensive and 

underlies the productive "Clinton"/Medina play area. This play has had limited production and may still 

have potential for future gas production, including basin-centered gas. The section has been sparsely drilled, 

and thick untested intervals remain in parts of the Rome trough and other areas. Production from pre-Knox 

rocks has been limited to scattered wells in Kentucky, West Virginia, and Ontario, Canada. The area 

underlying the Clinton/Medina gas play is considered a low-risk area and has estimated recoverable gas 

resources of 460 BCF (Harris and Baranoski, 1996). 

Basin-centered gas plays: The Lower Silurian "Clinton" sands/Medina Group sandstones gas play is under 

development in New York, Pennsylvania and Ohio (Figure 1). Development of this continuous-type (or basincentered) 

gas play has expanded since the early 1970s. Ryder (1995) estimated the Appalachian basin to have about 

61 trillion (TCF) recoverable gas within Paleozoic sandstones and shales. An estimated 30 TCF may reside in basincentered 

gas accumulations in the Lower Silurian "Clinton"/Medina sandstones. Cumulative gas production per well 

is relatively low. This play appears attractive for four reasons: the overall success rate approaches 90%; the drilling 

and development costs remain low; there is low water production (and hence, low disposal costs); and the proximity 

to population centers provides a market for the gas. To maximize gas recovery, operators drill closely spaced (40 

acre) wells and horizontal/directional wells. Hydraulic fracturing techniques improved production success from low 

permeability sandstone reservoirs. 

Ryder (1995) defined four continuous-type gas plays (6728-6731) in the "Clinton”/Medina sandstones interval, 

flanked by two conventional plays that also have potential for continuous-type gas (6732 and 6727). Figure 1 shows 

well and play locations. Play 6728 has the best gas production potential and covers 16,901 square miles. 

The depositional sequence of the "Clinton"/Medina sandstones include the basal Whirlpool Sandstone and 

Medina Group, which unconformably overlie the Upper Ordovician Queenston Shale. These units represent 

transgressive shoreface deposits with a lowermost braided fluvial component. The lower part of the Grimsby 

Formation and "Clinton" sands are shoreface deposits. These sandstones constitute parts of progradational 

parasequences that successively overlap one another toward the northwest, pinch out seaward into the offshore marine 

shale of the Cabot Head and Power Glen Shales, and then appear to downlap across the underlying transgressive 

systems. Ryder et al. (1996) interprets the named sandstones in the Cabot Head Shale to be part of a progradational 

stacked-parasequence. The carbonate units (Reynales Limestone, Irondequoit Limestone, Dayton Limestone, and 

Packer Shell of drillers) appear to be offshore carbonates separated by inner shelf mudrocks (Keighin, 1998). These 

limestones are regionally extensive, but do have pinchouts and thickness changes in the intervening shale beds 

(Ryder et al., 1996).


While productive Cambrian and Ordovician reservoirs apparently are conventional gas plays, basin-centered 

hydrocarbon accumulation may exist in the Appalachian basin "Clinton"/Medina sandstone, especially in play 6728 

(Ryder, 1998; Ryder et al., 1996; Wandrey et al., 1997): 

3 

(1) Regionally extensive sandstones with a thick zone of gas saturation reside in the thicker, more deeply buried 

part of this foreland basin. Sandstone thickness ranges from 120 to 210 ft, and average net thickness is 25 

ft; sandstone-to-shale ratios range from 0.6 to 1.0. 

(2) Gas fields are coalesced, and a high percentage of wells have production or gas shows. 

(3) Reservoirs have low porosity and permeability; porosity ranges from 3 to 11% (averaging 5%). 

Permeability ranges from 0.2 to 0.6 mD (generally averaging less than 0.01 mD). 

(4) Formation pressures are abnormally low with a gradient ranging from 0.25 to 0.35 psi/ft. In the Tuscarora 

sandstone (play 6727), there is evidence for overpressuring with a gradient ranging between 0.50-0.60 psi/ft. 

(5) Structural traps are few. 

(6) A gas-water contact is absent. 

(7) Sandstones with higher water saturations are updip of the gas accumulation. 

(8) Water yields are low; reservoir water saturation is less than 9 to 13 BW/MMCFG. 

(9) Reservoir temperatures are high–at least 125° F (52° C).



Geologic 


Accumulation: 


Eastern U.S. Appalachian basin, (New York, Pennsylvania and Ohio). Play: 

Paleozoic Era - Late Cambrian and Ordovician sandstones and shales; Lower 

Silurian "Clinton" and Medina Group sandstones, and the equivalent 

Tuscarora Sandstone 

a. Source/reservoir the underlying Middle Ordovician Utica shale is the probable hydrocarbon 

source in the "Clinton"/Medina Group sandstones 


(TOCs) 

range from 3.0%-4.0% (Middle Ordovician Utica Shale, Trenton Limestone, 

Black River Limestone, and Wells Creek Formation); from 0.05% to 0.59% 

in the pre-Knox (Harris and Baranoski, 1996) 

c.Thermal maturity Kerogen: 50% type II and 50% Type III; Vit Ref Equivalent (VRE): 0.75- 

3.0; Conodont Alteration Index (CAI): 1.5-4.0; Tmax: 440-550. The 

Ordovician strata in the study area is mature for both oil and gas generation 

(Wandrey et al., 1997; Ryder et al, 1996) 

d.Oil or gas prone both oil and gas prone; vitrinite reflectance suggests the majority of the area 

is in the window of significant gas generation 

e.Overall basin maturity considered mature along with adjoining basins in the eastern and southern 

U.S. 

f.Age and lithologies Cambrian-Ordovician (pre "Clinton"/Medina); Lower Silurian 

"Clinton"/Medina Group sandstones and the equivalent Tuscarora Sandstone 

g. Rock extent/quality basin-wide source and reservoir-rock distribution. Porosity reduction 

commonly results from secondary silica cementation; porosity often 

enhanced by dissolution of calcite cement, feldspars, corrosion of 

h.Potential reservoirs 

silica cement and by natural fracturing. About half the resource 

(approximately 30 TCF) is estimated to reside in basin-centered gas 

accumulations 

i.Major traps/seals Cabot Head Shale (Medina Group), Rochester Shale ("Clinton" sands) 

j.Petroleum 


models 

Clinton/Medina" - evaluation with BASINMOD program (Platte River 

Assoc., Inc.). Hydrocarbon source: Utica shale (Middle Ordovician), gas 

migration occurred vertically (1000 ft to 1400 ft) via fractures. Organic 

carbon content data indicates good generative potential for the Middle 

Ordovician Utica shale, Trenton Limestone, Black River Limestone, and 

Wells Creek Formation. Each of these units may have locally sourced basin- 

centered gas potential; limited generative potential exists in the pre-Knox.



County (OH) 

Production 

k.Depth ranges pre-Clinton/Medina 6000 to 11,500 ft in eastern OH; Clinton/Medina in 

eastern OH and NW PA from 4,000 to 6,300 ft; SW PA as much as 10,000 

ft; NY 1,000 to 4,000 ft; and southern OH and eastern KY 2,000 to 3,000 ft 

(Wandrey et al, 1997; Ryder et al, 1996) 

l.Pressure gradients pre-Clinton/Medina - pre-Knox Group underpressured domain: 0.174 psi/ft 

(Innerkip field-Ontario); 

a. Important 


"Clinton"/Medina-(1) underpressured domain: 0.25 to 0.35 psi/ft (verified 

throughout most of NW PA and adjoining western NY) 

"Clinton"/Medina-2) overpressured domain: 0.5-0.6 psi/ft, east of the 

underpressured domain, in the Tuscarora Sandstone, near the Allegheny 

structural front (in Pennsylvania) 

Pre-"Clinton"/Medina: Birmingham-Erie Field (Knox Group) sandstone 

reservoir 100 MMCFG/well; Middle Ordovician fractured carbonates- 

Harlem gas field 2.1 BCFG; Trenton play Granville consolidated pool 50- 

100 MMCFG/year 

a few pre-Knox wells have produced gas in the Rome Trough from the 

Conasauga Group (sands, shales and sandy dolomites), some wells have 

produced gas with up to 78% nitrogen (uncombustible gas) 

"Clinton"/Medina basin-centered gas: Lakeshore, Adams/Waterford/ 

Watertown, Athens, Indian Springs Pool of Conneaut field, Kastle pool of 

Conneaut field, Cooperstown, Oil Creek Pool of Cooperstown field, Kantz 

Corners, North Jackson/Lordstown, NE Salem, Senecaville, Sharon Deep 

(Ryder, 1998) 

b.Cumulative production most of the basin-centered gas production occurs in Play 6728. Fields tend to 

merge together into continuous-type accumulations after additional drilling. 

E.g., the three or four Medina fields discovered in the 1960s in Chautauqua 

County, western New York, have now merged into the giant Lakeshore field, 

which has an ultimate recovery of 650 billion cf of gas. Assuming 40 acre 

spacing the median estimated ultimate recovery per well is 70 MMCFG 

(play 6728), 50 MMCFG (play 6729), and high risk/low success ratio for 

plays 6730 and 6731 (Wandrey et al., 1997). Below are some examples of 

production data (for the better wells) from the "Clinton" sands in Ohio. 

Township Operator Cumulative Gas 

(MMCF) per Lease 

Years of 

Production 

Noble....................Brookfield............Kingston Oil Corp. ...............146,835................1992-1995 

Noble....................Brookfield............Everflow Eastern...................206,736................1990-1995 

Noble....................Brookfield............Kingston Oil Corp. .................94,548................1993-1995 

Trumbull...............Fowler................Eastern Petroleum.................118,622................1987-1995 

Trumbull...............Fowler................Eastern Petroleum...................82,148................1985-1994 

Trumbull...............Fowler................Eastern Petroleum.................190,776................1984-1995 

Noble....................Center.................Kingston Oil Corp. ...............490,911................1985-1995

Economic 


a. High inert gas content in Ohio, average Clinton-Medina Nitrogen content is 5.1%, Carbon Dioxide 

content is 0.1% (Hugman et al., 1993). In the Rome Trough and adjacent 

areas, very high inerts in natural gas have been reported from pre-Knox 

rocks, sometimes rendering the gas non-combustible (up to 78% Nitrogen) 

b. Recovery Low. Continuous-type accumulations are characterized by low individual 

well-production rates and small well-drainage area. Directional/horizontal 

wells are being drilled to reduce the number of well sites. 

c. Pipeline infrastructure very good There are numerous gas lines in the basin. 

d. Overmaturity none 

e. Basin maturity mature 

f. Sediment consolidation consolidation/porosity reduction occurs with depth of burial 


problems 

tight sands. Improved hydraulic fracturing techniques in recent years resulted 

in higher gas recoveries. 

h. Permeability pre-Knox=1.0 md (Innerkip field, Oxford Co., Ontario) 

i. Porosity pre-Knox=3.5 to 22% (Innerkip field, Ontario)

N 

Kentucky 

Ohio 

Sandstone reservoir for gas 

Sandstone reservoir for oil 

Oil and gas field 

Basin-centerd gas accumulation 

Ontario 

Lake Erie 

West Virginia 

Lake Ontario 

Approximate updip limit of basincentered 

gas accumulation 

Approximate updip limit of 


Pennsylvania 

Well location with show of gas or oil 

New York 

0 50 mi 

Figure 1. Map showing regional hydrocarbon accumulation in Lower Silurian sandstone reservoirs of the Appalachian 

basin. Oil and gas shows seen in wells are from pre-Knox units. After Harris and Baranoski (1996), and 

Ryder (1998).

System 

Permian Lower Dunkard Gr 

Pennsylvanian 

Mississippian 

Devonian 

Silurian 

Ordovician 

Cambrian 

Precambrian 

Series North/West Central South 

Upper 

Middle 

Lower 

Upper 

Lower 

Upper 

Middle 

Lower 

Upper 

Lower 

Upper 

Middle 

Lower 

Upper 

Middle 

Lower 

Rockwell Mbr 

Riddleburg Sh Mbr 

Cussewago Ss Mbr 

Oswayo Mbr 

Dunkirk Sh 

Clinton Gr 

Ohio Sh 

West Falls Gr 

Genessee Fm 

Genesseo Sh Mbr 

Moscow Sh 

Ludlowville Sh 

Skaneateles Sh 

Marcellus Sh 

Onondaga Ls 

Keyser/Bass Islands 

Salina Gr 

Lockport Dol 

Medina Gr 

Queenston Fm 

Oswego Ss 

Rose Hill Ss 

Trempeleau Dol 

Kerbel Fm 

Price Fm 

Hamilton Gr 

Utica Fm/Antes Fm 

Rockwell Fm 

Monongahela Gr 

Conemaugh Gr 

Allegheny Gr 

Pottsville Gr Breathitt Fm 

Lee Fm 

Greenbrier Ls 

Catskill Fm 

Cleveland Sh Mbr 

Huron Sh Fm 

Rhinestreet Sh Fm 

Mahantango Fm 

Delaware Ls 

Columbus Ls 

Keyser Fm 

Tonoloway Fm 

Wills Creek Fm 

Bloomsburg Fm Williamsport Ss 

Mifflintown Fm McKenzie Fm 

Keefer Ss 

Shawangunk Fm Rose Hill Fm 

Massanutten Ss 

Reedsville Fm 

Antietam Fm 

Harpers Fm 

Weverton-Loudon Fms 

Juniata Fm 

Bald Eagle Ss 

Martinsburg Fm 

Wells Creek Dol 

Beekmantown Gr 

Newman Ls 

Price Fm 

Brallier 

Chemung 

Pennington Fm 

Bangor Ls 

Hartselle Ss 

Monteagle Ls 

St. Louis Ls 

Warsaw Ls 

Ft. Payne Fm 

Grainger Fm 

Hampshire Fm 

Tuscarora Fm Clinch Fm 

Conocheague Fm 

Elbrook Fm 

Bluestone Fm 

Princeton Ss 

Hinton Fm 

Maccrady 

Cloyd Cgl Mbr 

Sunbury Sh Mbr 

Berea Ss 

Harrell Sh 

Tully Ls 

Marcellus Sh 

Tioga Bentonite 

Onondaga Ls 

Huntersville Ch 

Needmore Sh 

Oriskany/Ridgeley Ss 

Helderberg Gr 

Black River 

/Trenton Ls 

Honaker Dol 

Rome Fm/Waynesboro Fm 

Shady Fm/Tomstown Dol 

Millboro Sh 

Liberty Hall Mbr 

Sevier/Blockhouse Sh 

Pond Spring Fm 

Copper Ridge Dol 

Maynardville Dol 

Nolichuchy Sh 

Sequatchie Fm 

Stone River 

/Nashville Gr 

Maryville Ls 

Rogersville Sh 

Rutledge Sh 

Pumpkin Valley Sh 

Mascot Dol 

Kingsport Fm 

Chepultepec Dol 

Erwin Fm 

Hampton Fm 

Unicoi Fm 

Walden Creek Gr 

Cades Ss 

Snowbird Gr 

Mount Rogers Fm 

Figure 2. Stratigraphic nomenclature and correlation chart for the Appalachian basin. After Milici (1996). 

Chilhowee Gr 

Borden 

Fm 

Chattanooga 

Sh 

Chickamauga 

Gr 

Knox Gr 

Conasauga Gr 

Conasauga Sh 

Ocoee 

Supergroup 

Sequence 

Alleghenian Flysch 

Lower Carboniferous 

Flysch Molasse 

Stable Shelf 

Acadian Flysch 

Post Taconic 

Molasse and 

Carbonate Shelf 

Taconic Flysch 

Iapetan Rift 

and 

Passive Margin


The Arkoma Basin follows an east-west trend from northern Arkansas into east-central Oklahoma. 

Figure 1 shows the structural features that border the area: the Ouachita Mountains to the south; the 

Seminole Arch and the Arbuckle Uplift to the west; and the Ozark Uplift to the north. Tertiary sediments of 

the Mississippi Embayment cover the eastern part of the basin. Figure 2 shows the basin is asymmetric in 

profile. 

The basin is characterized by normal faulting on the north and compressional structures on the south. 

Development occurred from Cambrian to early Pennsylvanian time. Prior to basin development, the area 

was a carbonate shelf (Horn and Curtis, 1996). Subsurface folds and thrust faults were formed during the late 

stages of foreland basin development. The basin was completely filled with late Pennsylvanian sediments 

(Horn and Curtis, 1996). 

Structural styles influence hydrocarbon production in the Arkoma basin. The northern Arkansas gas 

fairway and central basin are dominated by blind imbricate thrust faults that ramp over normal fault blocks 

at depths above 5000 feet. Gas reservoirs have been found below the thrust faults at depths of 5000 to 

10,000 feet. 

Seismic and well data reveal a southward thickening package of Carboniferous flysch (Figure 2) 

overlying thin Paleozoic shelf strata in western Arkansas (Figure 3). Total sediment thickness is estimated 

to be 46,000 feet in the southern Ouachita mountains. At least 39,000 feet of flysch were deposited north of 

the Ouachita mountain front (Lillie et al., 1983). 

North of the Ouachita mountains, the Cambro-Ordovician Arbuckle carbonates were deposited in a 

marine shelf environment (Gromer, 1981). The Devonian-Mississippian Arkansas Novaculite was deposited 

when rapid subsidence occurred in the Ouachita basin. The Mississippian Stanley shale Group, the 

Pennsylvanian Jackfork Group, the Johns Valley Formation and the Atoka Formation as the Arkoma basin 

continued to subside. The Atoka Fm includes 20,000 feet of shale, sandstone and coal beds. Flysch 

sedimentation continued until mid-Pennsylvanian time, when northward thrusting displaced the geosyncline 

(Gromer, 1981). The Ouachita fold belt was produced by a collision between an island arc and the North 

American plate (Wickham, et al., 1976). 


Natural gas was first produced in 1901 at a depth of 2,000 feet from Pennsylvanian sandstones in 

Sebastian County, Arkansas. The greatest exploration activity occurred along the northern part of the basin 

in Arkansas and Oklahoma. Most major fields were discovered within the first 30 years of industry activity 

(Horn and Curtis, 1996). In 1930, gas production was established from the Atokan Spiro sandstone at a 

depth of 6300 feet. Wilburton field, the Arkoma basin's second largest field, was discovered in 1929 with 

production from Upper Atokan sandstones at 2500 feet. The Spiro sandstone was tested in 1960 and soon 

became the main producing zone. Except for Wilburton and Red Oak fields, very few successful wells were 

drilled below 10,000 feet prior to the 1970’s (Horn and Curtis, 1996). 

Production was established from the Spiro sandstone and Arbuckle carbonates in northern Oklahoma 

and Arkansas during the late 1970s, opening a new fairway for deeper exploration. Production from 

Arbuckle (Cambro-Ordovician), Viola (Ordovician) and Hunton (Siluro-Devonian) was established at 

Wilburton field at depths of 13,000 to 14,500 feet in 1988 (Horn and Curtis, 1996). 

Limited shallow oil production occurs from the Stanley group (Mississippian) and fractured Paleozoic 

cherts (Devonian Arkansas Novaculite) in the southern Ouachitas (Horn and Curtis, 1996). 

1


The Atoka formation contains coals and shales with gas-prone kerogen. It extends over a wide area and 

is very thick. Middle Atokan Red Oak sands contain some of the largest gas reserves in the Oklahoma part 

of the Arkoma basin (Gromer, 1981). 

The Woodford shale, which contains type II oil prone kerogen, may have generated in excess of 22 

billion barrels of oil (Comer and Hinch, 1987). This oil has probably cracked to gas in the deepest parts of 

the Arkoma basin (Horn and Curtis, 1996). Other source rocks include the Womble (Ordovician), Polk 

Creek (Ordovician), Sylvan (Ordovician), Woodford (Devonian-Mississippian), Arkansas Novaculite 

(Devonian-Mississippian) and Caney (Mississippian) shales. Each of these has probably expelled significant 

hydrocarbons (Horn and Curtis, 1996). Atokan shales are estimated to have generated between 53 and 212 

TCFG. A large, relatively untested area in southwestern Arkansas contains thick sequences of interbedded 

source and reservoir rocks, and may contain large accumulations of gas (Horn and Curtis, 1996). 

Figure 4 illustrates profiles of depth vs. vitrinite reflectance (Ro) for undifferentiated wells in Arkansas 

and Oklahoma. Hendrick (1992) listed the following vitrinite reflectance values for producing zones at 

Wilburton Field: 

2 

Hartshorne Coal Ro < 1% 

Atoka Shale Ro = 2.3% at 7,500 ft 

Atoka Shale Ro = 2.6% at 9,400 ft 

Spiro Sandstone Ro = 2.7% at 10,000 ft 

Spiro Sandstone Ro = 3.0% at 11,500 ft 

Arbuckle Dolomite Ro = 3.8% 

These unusually high vitrinite values at moderate depths indicate a potentially overmature basin. 

Several thousand feet of sediment may have been eroded from the surface. 

The extensive source rocks and high thermal maturity levels in the Arkoma basin indicate that basincentered 

gas accumulations may exist which have not yet been identified. Thick Atoka shales probably 

provide the primary barriers to gas migration. In the lower Paleozoic section, several shale intervals 

encasing productive carbonate and sandstone reservoirs are thought to be effective seals (Horn and Curtis, 

1996).



Geologic 


Accumulation: 


Arkoma Basin Province, Play, Ordovician through Pennsylvanian 

Desmoinesian 

a. Source/reservoir Ordovician Womble shale through Pennsylvanian Desmoinesian shales and 

coals (Horn and Curtis, 1996) 


(TOCs) 

range up to 19.6% in Woodford Shale (Comer and Hinch, 1987) and average 

1.1% in Atokan shales (Horn and Curtis, 1996) 

c.Thermal maturity Ro ranges from



Economic 


a. Important 


Red Oak field produces from Pennyslvanian sandstones at depths ranging 

from 1400 ft to 13,000 ft; Wilburton field produces from Cambro-Ordovician 

Arbuckle at depths from 13,000 to 14,500 ft 

b. Cumulative production Red Oak field has produced 55 Bcfg from the Hartshorne, 700 Bcfg from the 

Red Oak, and 200 Bcfg from the Spiro sandstones as of 1987 

a. High inert gas content gases have high btu content and low total inert gas content 

b. Recovery recoveries depend upon permeability, porosity and depth 

c. Pipeline infrastructure very good 

d. Overmaturity probably overmature in the southern and eastern parts of the basin. 

Production exists where apparent overmaturity occurs 

e. Basin maturity most of the basin is mature to overmature 

f. Sediment consolidation most rocks are well indurated 


problems 

h. Permeability 0.1-200 md 

i. Porosity 5-23% 

shales, tightly cemented sands & other tight (low permeable rocks) have 

potential to produce where they are naturally fractured (many deep Anadarko 

basin ields have permeabilities of less than 0.1 md). Water sensitive clays 

also cause problems. Diagenetic permeability barriers are poorly understood.

35° 

34° 

Atoka 

96° 95° 94° 93° 

0 50 mi 

McAlester 

Tertiary 

Rocks 

Arbuckle 

Mountains 

A r k o m a 

Valley Fault 

Octavia 

Boktufola 

Choctaw Fault 

Frontal Margin of Oklahoma Structural Salien t 

COAL 

Eubanks 

Cretaceous 

Rocks 

PITTSBURG 

Willburton 

Fault 

Potato 

Hills 

Windingstair Fault 

Hartshorne ss 

and younger rocks 

(Desmoinesian, 

Virgillian) 

Red Oak 

1.0 

HASKELL 

LATIMER 

Fault 

Oklahoma 

Arkansas 

Fort Smith 

Valley 

B a s i n 

Waldron 

Boles 

Ouachita Mountains 

Fault 

Mount Ida 

Broken Bow — Benton Uplift 

Broken Bow Murfreesboro 

Atoka fm 

(Pennsylvanian) 

(including some 

older rocks) 

Oklahoma Arkansas 

LE FLORE 

1.5 

SEBASTIAN 

SCOTT 

Johns Valley sh 


Jackfork ss 


(including some 

younger Penn. rocks) 

Coastal 

Stanley sh 

and Hot Springs ss 

(Upper Mississippian 

and Pennsylvanian) 

Hollis 

Hot 

Springs 

Benton 

Plain 

Cambrian to 

Lower Mississippian 

(Arkansas novaculite 

and older rocks) 

Little Rock 

Igneous 

rocks 

(Cretaceous?) 

0 50 mi 

Figure 1: Geologic map of Ouachita Mountains and outline of present-day Arkoma basin. Vitrinite reflectance values derived from Hartshorne coal. 

After Gromer (1991), and Horn and Curtis (1996). 

LOGAN 

Ouachita Mountains Fold and Thrust Belt 

2.0 

YELL 

POPE 

CONWAY 

FAULKNER 

WHITE 

Mississippi 

Embayment 

2.0 

Well 

Scale 

Condensate Production 

Vitrinite Reflectance Contour

Formation Frontal Ouachitas 

Approximately 20 miles 

Central Ouachitas Formation 

Atoka Ss and Sh Atoka Group 

or 

Formation 

Wapanucka Ls 

Spiculite Bed 

Springer Sh and Ss 

Johns Valley Sh 

Caney Sh 

Game Refuge Ss 

Arkansas Novaculite 

Wesley siliceous sh 

Markham Mill 

Sandstone 

and Shale 

North North 

5000 ft 

4000 

3000 

2000 

1000 

0 

Limestone Siliceous 

Shale 

Siliceous Shale 


Middle Siliceous Shale 

Tuskahoma Siliceous Shale 

Lower Siliceous Shale 

Stanley-Arkansas NovaculiteTransitionBeds 


Prairie 

Mountain Fm 

Wildhorse 

Mountain Fm 

Chickasaw Creek 

Moyers Fm 

Upper 

Member 

Lower 

Member 

Tenmile Creek Fm 

Jackfork Group 

Stanley Group 

Morrowan Atokan 

Meramecan and Chesterian Series 

Kind B 

Osage 

Pennsylvanian System 

Mississippian System 

Arkansas Novaculite Devonian 

Shale Sandstone Spiculite Novaculite 

Figure 2. Diagrammatic cross section showing facies changes and correlations of the Late Mississippian and Early Pennsylvanian formations from the 

frontal Ouachitas to the central Ouachitas, southeastern Oklahoma, with thrust faults eliminated. After Gromer (1991) and Cline (1968).

System 

Pennsylvanian 

Mississippian 

Devonian 

Silurian 

Ordovician 

Cambrian 

Series 

Desmoinesian 

Atokan 

Morrowan 

Chesterian 

Meramecian 

Osagean 

Kinderhookian 

Upper 

and 

Middle 

Lower 

Niagaran 

Alexandrian 

Cincinnatian 

Champlainian 

Canadian 

Precambrian 

Arkoma Foreland Basin Facies 

Arkansas 

Boggy 

Savanna 

McAlester 

Hartshorne Ss 

Alma Series, Carpenter 

Basham 

Upper Hartford 

Nichols 

Middle Hartford,Turner 

Lower Hartford, Morris 

Tackett 

Cecil Series 

Spiro 

Orr 

Barton A, Barton B, Barton C 

Wapanucka Limestone 

Kessler 

Bloyd 

Brentwood 

Hale 

Pitkin Limestone 

Fayetteville Shale 

Hindsville Limestone 

Moorefield Formation 

Boone Formation 

Chattanooga Shale 

Sylamore Sandstone 

Penters Chert 

Lafferty Limestone 

St. Clair Limestone 

Brassfield Limestone 

Sylvan 

Cason Shale 

Fernvale Limestone 

Kimmswick Limestone, Plattin Limestone, 

Joachim Dolomite 

St. Peter Sandstone 

Tyner Formation 

Jasper Limestone 

King River Ss, Burgen Ss 

Powell Dolomite 

Cotter Dolomite 

Jefferson City Dolomite 

Roubidoux Formation 

Gasconade-Van Buren Formation 

Eminence Dolomite 

Polosi Dolomite 

Derby-Doerun-Davis Formation 

Bonneterre Dolomite 

Lamontte Sandstone 

Hunton Group 

Everton 

Formation 

Arbuckle 

Group 

Marmaton 

Cabaniss 

Krebs Group 

Oklahoma 

Salisaw Formation 

Frisco Formation 

Henryhouse Formation 

Chimneyhill Subgroup 

Petite Oolite 

Welling Formation 

Viola Springs Formation 

Bromide 

Tulip Creek 

Mclish 

Oil Creek 

Joins 

West Spring Creek 

Kinblade 

Cool Creek 

McKenzie Hill 

Butterfly Dolomite 

Singal Mountain Limestone 

Royer Dolomite 

Fort Sill Limestone 

Honey Creek Limestone 

Reagen Sandstone 

Boggy 

Savanna 

McAlester 

Hartshorne Ss 

Dirty Creek, Fanshawe 

Diamond, Red Oak 

Panola 

Brazil-Smallwood, Shay 

Spiro 

Wapanucka Limestone 

Union Valley 

Cromwell 

Goddard Shale 

Caney Shale 

Welden Limestone 

Woodford Shale 

Misener Sandstone 

Sylvan Shale 

Calvin 

Senora 

II 

III 

Relative Stratigraphic Position (ft)* 

15000 

10000 

5000 

0 

-5000 

-10000 

1 2 3 4 5 6 7 8 9 10 

* 

Mean Vitrinite Reflectance (% R o )* 

Estimated Woodford-Chattanooga top 

Estimated Arbuckle top 

Latimer County, OK 

Sebastian County, OK 

Yell County, AR 

Logan County, AR 

Faulkner County, AR 

White County, AR 

Stratigraphic position relative to top of basal Atokan (Spiro/Orr) sandstone 

Figure 4. Depth vs. vitrinite reflectance profile for wells in Arkansas and Oklahoma. These profiles use the Spiro 

sandstone as a stratigraphic datum and indicate that thermal maturity of eastern Arkansas wells does not 

follow the inferred west-to-east increase in maturity across the basin. After Horn and Curtis (1996) and 

Houseknecht et al. (1992).


The Black Warrior basin of Alabama and Mississippi is a foreland basin located in the major structural reentrant 

between the Appalachian fold-and-thrust belt to the southeast and the Ouachita fold-and-thrust belt to the southwest. 

Figure 1 shows the basin location and its major structural features. The northern margin of the basin is bounded by 

the Nashville dome. The basin is shaped like a kite with its tail facing south, and has a surface area of about 35,000 

square miles. North to south, the basin extends about 190 miles, and the east-west width is about 220 miles. The 

overall sedimentary section in the province includes rocks of Paleozoic, Mesozoic and Cenozoic age that range in 

thickness from about 7,000 ft along the northern margin to about 31,000 ft in the depocenter located in eastern 

Mississippi (Ryder, 1994). 

The geotectonic history of the basin includes 5 stages: 

1) Late Precambrian-Early Cambrian rift with associated deposition of coarse clastics. 

2) Middle Cambrian-Mississippian period of stable shelf deposition (7000 ft of shallow water carbonates) 

occurring on a passive continental margin. 

3) Late Mississippian (Chester) transitional episode; early stages of continental collision, marine deltaic 

sedimentation and several major regressive-transgressive cycles. 

4) Early-Late (?) Pennsylvanian time of maximum basin subsidence and synorogenic deposition related to 

maturation of the Appalachian-Ouachita thrust belts. Following a brief period of barrier bar development, 

thick clastic wedges prograded from source areas along the south margin. Abundant coal bed development in 

north-central portion of the basin. 

5) Permian-Cretaceous erosion/non-deposition ending with Late Cretaceous marine incursion and deposition 

into Early Tertiary shallow marine sediments (Mississippi Embayment). 

Figure 2 shows a regional cross section of Mississippian strata across northwestern Alabama. The Black Warrior 

basin was first downwarped in the Late Mississippian-Early Pennsylvanian and then subsequently filled by 

Pennsylvanian shallow marine and terrestrial clastic material shed from rising highlands along its southern margin. 

No Permian or early Mesozoic deposits exist in the basin. Indications are that the Black Warrior was uplifted above 

sea level in Latest Pennsylvanian-Early Mesozoic time (Petroleum Information Corp, 1986). Continental break-up 

during the Mesozoic resulted in the basin becoming downwarped to the southwest and eventually covered by the 

Mississippi Embayment marine transgressive episode (Mancini et al., 1983). Most of the basin and its thrust faulted 

margins are concealed beneath Tertiary and Cretaceous rocks of the Gulf coastal plain and the Mississippi 

embayment. 

1


The Black Warrior Basin is very prolific; the Lewis and Carter sandstones (Mississippian Chester Group) are the 

most productive. The depth to productive horizons ranges from 2,500 to 5,000 ft. Target intervals are generally 

shallower in Alabama than in Mississippi. The Carter Sandstone and other Mississippian productive intervals extend 

into deeper basin regions (Bearden and Mancini, 1985). Remarkably high wildcat success rates (50% and more) and 

the shallow depths of the primary Late Paleozoic reservoir targets (less than 5,000 ft) keep exploration interest high. 

There are over 90 individual fields producing oil and gas from two principal productive trends. The northerly 

trend produces principally from stratigraphic traps. The southern trend produces from structural and combination 

traps. One of most prolific fields is the unitized North Blowhorn Creek oil field (Lamar County, Alabama), 

completed in the Carter Sandstone which accounts for nearly 80% of the total oil produced in the entire basin 

(Petroleum Information Corp., 1986). 

There are multiple gas and gas-condensate reservoirs within the Late Paleozoic clastic units. Eleven individual 

reservoirs exist in the Mississippian Chester Group. At least 4 clastic units within the Lower Pennsylvanian 

Pottsville Formation produce gas (Figure 3). The clastic units consist of a series of prograding deltaic environments– 

delta front, bar finger, and distributary channel sands–separated by transgressive shales. Considerable lateral 

variability occurs in the reservoirs, and porosities range from 5% to 17%; permeabilities range from .01 to 100 md. 

Thickness of individual reservoirs range from less than 10 ft to about 50 ft. The total sandstone thickness is less 

than 1,000 ft. 

In addition, the deeper Cambro-Ordovician to Devonian carbonate units also produce in certain locations. To date 

there have been over 40 deep structural tests (deeper than 10,000 feet) drilled on the Mississippi side of the basin. 

Many of these tests encountered significant gas shows from Mississippian and Pennsylvanian sandstone sections and 

from deeper Cambro-Ordovician, Silurian and Devonian rocks (Ericksen, 1993; Henderson, 1991). The lower 

sections need further exploration, as correlative zones to the west (Hunton and Ellenburger groups) are highly 

productive (Petroleum Information Corp., 1986; Duchscherer, 1972; Devery, 1983). 

Also, the Alabama part of the Black Warrior basin is one of the main centers of coalbed degasification in the 

U.S. Lower Pottsville rocks yield gas from depths of less than 2,700 ft, and estimated resources range from 20 to 35 

Tcf. To date the Oak Grove, Pleasant Grove, Brookwood, and Cedar Cove fields combined have yielded 0.9 Tcf. 


Basin center gas potential exists in: 

a. thick clastic wedges off the carbonate platform, in western Alabama and eastern Mississippi, including the 

least-explored deeper depocenters in Mississippi. 

b. micritic and finely crystaline limestones and shale/siltstone intervals within Cambro-Ordovician formations. 

The basin covers about 1500 square miles. Gas shows are numerous and widespread throughout the basin. Major 

source rocks are fairly organic, amorphous and herbceous-prone pro-delta shales with interbedded sandstone. Available 

geochemical data (including total organic carbon (TOC) thermal alteration index) suggest the basin is mature and the 

Late Paleozoic shales should be mainly gas prone (Bearden and Mancini, 1985). Henderson (1991) considers the 

TOCs of the black shales within the Stone River Limestone (Ordovician) favorable for hydrocarbon generation. 

Pennsylvanian sands in southern Pickens County, Alabama, contain large volumes of in-situ gas; low gas recoveries 

indicate relatively low permeabilities (Ericksen, 1999) and low porosities (Champlin, 1999) of the rocks. Pressure 

gradients recorded to date are normal (Ericksen, 1999; Champlin, 1999). 

2



Geologic 


Accumulation: 


Eastern U.S., Black Warrior Basin, Cambrian through Pennsylvanian 

a. Source/reservoir interval includes Mississippian Floyd shale to top of Pennsylvanian Pottsville 

Formation. Eleven reservoirs within the Chester group and at least 4 clastic 

units within the Lower Pennsylvanian Pottsville Group. Carter 

b. Total Organic Carbons 

(TOCs) 

sandstone and other Mississippian productive intervals have been extended 

into deeper basin regions. 

0.07%-2.36% (Upper Mississippian shales); 2.2% Stone River Limestone 

shales. 

c. Thermal maturity mixed including amorphous, herbaceous, woody and coaly material. 

Alteration state of the kerogen indicates the thermal history is favorable for 

hydrocarbon generation. Thermal Alteration Index ranging from 2 to 3+ 

suggest the Upper Mississippian is primarily gas prone. 

d. Oil or gas prone both oil and gas prone 

e. Overall basin maturity considered mature along with adjoining basins in the southern U.S. 

f. Age and lithologies Cambrian through Lower Pennsylvanian: black shales of the Stone River 

Limestone (Ordovician); dark shales of the Conasauga Limestone 

(Cambrian); Chattanooga (Devonian/Mississippian), Floyd shale including 

Lewis sandstone; Packwood Formation including Carter sandstone and 

Pottsville Formation. 

g. Rock extent/quality basin wide source and reservoir rock distribution 

h. Potential reservoirs 

i. Major traps/seals interbedded Cambro-Ordovician shales; Floyd Shales and interbedded shales 

of the Packwood and Pottsville Formations 

j. Petroleum 


models 

k. Depth ranges from 2500 ft in Alabama to over 10,000 ft in the deeper basin regions in 

Mississippi 

l. Pressure gradients



Economic 


a. Important 


The Lewis and Carter intervals are the most highly productive, especially in 

the north-central part of the basin (Lamar and Fayette counties, Alabama and 

Monroe, Clay, and Lownders counties in Mississippi) 

Grove field Carter sandstone-67 Bcf; Coal Fire Creek Carter Sandstone-19 

Bcf, Lewis sandstone 6.9 Bcf, Fayette sandstone 2.5 Bcf; North Blowhorn 

Creek oil field Carter sandstone accounts for nearly 80% of the total oil 

produced in the entire basin (Petroleum Information, 1986), Carter sandstone 

11.4 Bcf, Millerella 10.5 Bcf; Sanders Ss one well (10,130-10,164 ft)-over 

12 Bcf in 10 years. Yellow Creek Devonian chert production; 

Fairview field Ordovician (Knox) dolomite-one well-1.8 MMcf monthly. 

b.Cumulative production cumulative production for Star field (Lamar county, Alabama) producing 

from a combination trap and numerous horizons: 

Producing Formation 

(gas sands) (10/98) 

a. High inert gas content 

Cumulative Oil 

(10/98) 

b.Recovery low in south Pickens County, Alabama 

c.Pipeline infrastructure very good There are numerous gas lines in the basin. 

d.Overmaturity none 

Cumulative Gas 

(10/98) 

Producing Wells 

Carter (Miss)...................... ............99,799............. .........19,218,189 .......... ................7 

Chandler (Penn)................... ............27,543............. .............226,233 .......... ................0 

Fayette (Penn)..................... ....................0............. ...............10,400 .......... ................1 

Lewis (Miss)...................... ............14,248............. .........13,146,529 .......... ................7 

Lower Nason (Penn)............. ................372............. .............757,692 .......... ................1 

Lower Millerella (Miss)........ ................797............. ..........1,264,601 .......... ................0 

Upper Nason (Penn)............. ................128............. .............187,983 .......... ................0 

Carter Oil (Miss)................. ............78,955............. .................6838.......... ................1 

Chandler Oil (Penn)............. ................865............. ......................0.......... ................0 

Total Cumulative Production...........222,707............. .........34,818,492 .......... ...............17

e.Basin maturity mature 

f.Sediment consolidation consolidation/porosity reduction occurs with depth of burial 


problems 

h.Permeability 0.01 to 100 md 

i.Porosity 5-17% 

most wells are shallow and problem-free. Low porosity in south Pickens 

County, Alabama (Champlin,1999; Ericksen, 1999).

35° 

34° 

33° 

32° 

31° 

30° 

91° 

Arkansas 

Mississippi 

Louisiana 

Ouachita Fold and 

Thrust Belt 

Boundary of 

Black Warrior Basin 

90° 89° 88° 87° 86° 

Jackson 

Memphis 

Pennsylvanian rocks 

Area of basin-centered 

gas potential 

Thrust fault, teeth in 

upper plate 

Subcrop limit of 

Pennsylvanian 

strata 

Nashville Dome 

Outcrop limit of 

Pennsylvanian strata 

Appalachian Fold and Thrust Belt 

Birmingham 

Alabama 

Florida 

Tennessee 

Eastern limit of Tertiary and Cretaceous 

rocks of the Gulf coastal plain and 

Mississippi embayment 

0 100 mi 

Figure 1. Location map of Black Warrior Basin, Mississippi and Alabama. After Ryder (1994).

A A' 

Clastic rocks 

Carbonate rocks 

Undifferentiated 

sedimentary rocks 

Southwestern Floyd/Parkwood 

clastic facies 

Northeastern Pennington 

clastic facies 

Central Bangor/Monteagle facies 

Pre-Chesterian carbonate platform facies 

A 

East Warrior platform 

A' 

Black Warrior basin 

0 100 mi 

Figure 2. Regional cross section of northwestern Alabama showing lithofacies of Mississippian strata across East 

Warrior platform into Black Warrior basin. After Thomas (1972), and Bearden and Manconi (1985).

Era System Series Geologic Unit Lithology 

Paleozoic 

Pennsylvanian 

Lower 

? ? ? ? 

Mississippian 

Devonian 

Silurian 

Ordovician 

Cambrian 

Precambrian 

Upper 

Lower 

Upper & 

Middle 

? ? ? 

Middle 

Lower 

Upper 

Middle 

Lower 

Pottsville Formation 

Parkwood Formation 

Floyd Shale 

Coal gas 

"Nason sandstone" 

"Fayette sandstone" 

"Benton sandstone" 

"Robinson sandstone" 

"Chandler sandstone" 

"Coats sandstone" 

"Gilmer sandstone" 

"Millerella limestone" 

"Millerella sandstone" 

"Carter sandstone" 

Bangor Limestone 

Hartselle Sandstone 

"Evans sandstone" 

"Lewis limestone" 

"Lewis sandstone" 

Tuscumbia Limestone 

Fort Payne Chert 

Chattanooga Shale 

Unnamed 

cherty limestone 


rocks 


rocks 

Stones River 

Group 

Knox 

Group 

Ketona Dolomite 

Conasauga Formation 

Rome Formation 

Basement Complex 

West East 

Source 

Explanation 

Coal 

Shale or claystone 

Siltstone 

Shaly sandstone 

Sandstone 

Conglomeratic 

sandstone 

Limestone 

Oolitic limestone 

Cherty limestone 

Argillaceous limestone 

Dolomitic limestone 

Dolomite 


igneous rocks 

Gas 

Oil and gas 

Figure 3. Generalized stratigraphic column for the Black Warrior basin, Alabama. After Geological Survey of 

Alabama (1986).


The interior basins of Alaska cover a broad area extending from the Canadian border on the east to the 

Bering Sea on the west. These basins occupy three geological provinces in central Alaska–Kandik, Alaska 

Interior, and Interior Lowlands–which collectively comprise the geographically defined Central Alaska 

Province (Figure 1). The Central Alaska Province covers about 300,000 square miles between the Brooks 

Range on the north and the Alaska Range on the south (Stanley, 1996). 

Central Alaskan geology is complex and varied, characterized by fold and thrust belts. Diverse crustal 

terranes formed along the ancestral North American cratonic margin, and structural deformation in this 

region is often severe (Magoon, 1993). Much of central Alaska experienced deformation in late Cretaceous 

to early Tertiary time (Stanley, 1996). The basins include areas of complexly deformed and locally 

metamorphosed flysch deposits underlying thick Cenozoic nonmarine sediments (Kirschner, 1988). 

1 

Three types of basins occur within the Central Alaska province(Magoon and Kirschner, 1990): 

1. segments of the Cordilleran fold and thrust belt. The Kandik province represents such a segment, 

and is characterized by thrust-faulted anticlines that largely affected clastic and carbonate reservoirs 

of Paleozoic to Tertiary age. The right-lateral Tintina fault truncates the province on the southwest 

(Magoon, 1993). 

2. Mesozoic flysch basins. The flysch belts and flysch terranes represent volcanic-plutonic arc-basin 

deposits (Magoon and Kirschner, 1990). The flysch belts of the Yukon-Koyukuk, Kuskokwim, 

and Bethel basins consist of deep marine turbidite sandstones and shales, shallow marine alluvial 

fans, and coal bearing deltaic and fluvial facies (Stanley, 1996). 

3. Cenozoic basins. These consist of undeformed to moderately deformed strata reflecting a distinctive 

gravity low (Magoon and Kirschner, 1990). They include a thick sequence of Tertiary and 

Quaternary rocks overlying Precambrian to Mesozoic igneous and metamorphic rocks (Stanley, 

1996). 

The stratigraphic section consists of a sequence of Precambrian rocks overlain by a succession of 

Paleozoic to Cenozoic sediments. Figure 2 illustrates the generalized stratigraphic nomenclature common 

across the Central Alaska province. The Kandik province contains the thickest stratigraphic section, with 

Proterozoic to Cenozoic rocks having a cumulative thickness greater than 40,000 feet (Hite, 1997). The 

Paleozoic section is approximately 15,000 feet thick. An unconformity at the top of the McCann Hill chert 

separates the Lower Paleozoic continental margin sediments from the overlying Upper Devonian to Permian 

foreland basin sequence (Hite, 1997). The Nenana and Middle Tenana basins of the Interior Lowlands 

province contain an assemblage of sedimentary rocks from the Middle and Lower Miocene to Pliocene 

Usibelli group, which nonconformably overlie Precambrian and Paleozoic rocks (Stanley et al., 1990). The 

Bethel and Yukon-Koyukuk basins of the Alaska Interior province contain thick, widely distributed 

Cretaceous strata, including a large volume of volcanic rocks. Basal andesitic rocks are overlain by about 

10,000 feet of graywacke and mudstones of lower Cretaceous Albian age (Patton, 1971).

HYDROCARBON POTENTIAL 

There is no known hydrocarbon production in the basins of central Alaska. Drilling is very sparse, but 

the few wells drilled have encountered numerous shows of oil and gas. Other similar regions in Alaska are 

richly productive. Exploration efforts began in the Central Alaska basins as a result of hydrocarbon 

discoveries on the North Slope. Cretaceous strata similar to those on the North Slope exist beneath alluvial 

lowlands. Operators drilled a 12,000 foot well near Nulato on the Yukon River, and a 15,000 foot hole in 

the Yukon-Kuskokwim basin. Neither wells had commercial shows (Patton, 1971). 

The sedimentary sequences in central Alaskan basins may provide favorable settings for basin-centered 

hydrocarbon accumulations. Reservoir rocks in the Tertiary basins of central Alaska may be similar to the 

reservoirs in the producing fields of the Cook Inlet-Beluga-Sterling play (Magoon and Kirschner, 1990). 

The Kandik and Middle Tanana basins appear to have the greatest hydrocarbon potential (Grether and 

Morgan, 1988). The Kandik and Yukon Flats basins may contain significant reserves of oil and gas within 

a 40,000 feet thick sedimentary package. 

Three exploratory wells have been drilled in the Kandik province. These wells encountered some 

porosity and bitumen in Devonian carbonates (DiBona and Kirschner, 1984). The Triassic Glenn Shale in 

the Kandik province is an organic equivalent to the Shublik Formation of the North Slope and may have 

generated as much as 1.5 billion barrels of oil per cubic mile of sediment (Hite, 1997). In the Middle 

Tanana basin, only two exploratory wells have been drilled–the Unocal Nanana No. 1, and the ARCO Totek 

Hills No. 1. Both wells penetrated a thick Tertiary coal-bearing section of the Usibelli Group and terminated 

in metamorphic basement (Smith, 1995). The ARCO Totek Hills well was drilled on the basin flank and 

passed through 3,015 feet of Tertiary rocks. The sandstones averaged 17% porosity and 11 md permeability. 

The claystones contained Type II kerogen and indicate some oil potential (Grether and Morgan, 1988). 

Smith (1995) suggests that Tertiary coals of the Yukon Flats, Nenana, and Middle Tanana basins provide 

opportunities for commercial gas production. 

2 

Three hypothetical petroleum systems occur in central Alaska (Stanley, 1996): 

1. Cenozoic gas play. This play includes organically rich source rocks and have a potential for 

nonassociated gas in undeformed to moderately deformed strata. 

2. Mesozoic gas play. This play lies within sequences of flysch deposits, particularly in the Yukon- 

Koyukuk and Kuskokwim basins where various authors have reported lateral facies changes from 

deep marine turbidites to deltaic and shallow marine sediments (Patton, 1971; Milson, 1989; and 

Box and Elder, 1992). These facies changes indicate possible stratigraphic traps and may contain a 

basin-centered gas accumulation. The Benedum Nulato Unit No. 1 well drilled in the Koyukuk 

basin penetrated gas-prone kerogens in the Cretaceous section (Stanley, 1996). 

3. Paleozoic oil play. This includes Ordovician, Silurian and Devonian graptolitic shales similar to 

ones found in basins elsewhere in North America, the Middle East and North Africa that contain 

oil-prone kerogen (Klemme and Ulmishek, 1991). These rocks may be potential sources for oil, 

and if heated sufficiently, a source for natural gas as well.


In the Central Alaska basins, basin-centered hydrocarbon accumulations potentially exist within thick 

fluvial and lacustrine units: sandstones, conglomeratic sandstones, turbidites shales, siltstones and coals. 

Available source and maturation data (TOC, TAI, Ro, and Tmax) indicate that the basins are marginally 

mature to overmature. Available vitrinite reflectance and Tmax data indicate that late Cretaceous and Tertiary 

source rocks are thermally immature (Stanley, 1996). 

The Kandik and Middle Tanana basins appear to have the most potential for basin-centered gas 

accumulation potential. In the Middle Tanana basin, Stanley et al. 1990 estimate the top of the oil window 

(Ro = 0.6) occurs at depths exceeding 4,500 ft. Vitrinite reflectance values in the Kandik basin fall within 

the gas generation window (Figure 3). In the Middle Tanana basin, data from the ARCO Totek Hills No. 1 

well indicates the presence of Types II and III kerogen, indicating the Usibelli Group strata may be oil and 

gas-prone. Based on present information regarding thermal maturity, wells drilled in the deeper parts of the 

central Alaska basins may encounter strata buried below the top of the oil window, and therefore, 

potentially encounter basin-centered hydrocarbon accumulations. 

3



Geologic 


Accumulation: 


Central Alaska, Interior basins, Paleozoic, Upper Triassic, and Tertiary 

potential basin-centered gas accumulation 

a. Source/reservoir Ford Lake shale, Calico Bluff, Glenn Shale (Devonian to Jurassic), Usibelli 

Group (Tertiary); Kerogen types: II, III, and IV. Reservoir: Nation River, 

Calico Bluff, shallow marine limestones of the Permian Tahkandit 


(TOCs) 

Formation, unnamed sandstones of Cretaceous and Tertiary ages. 

Kandik basin: 7% (Glenn Shale); Holitna basin: 0.61 to 1.59% (Cretaceous 

Kuskokwim group); Middle Tanana basin: 3.6% (Sanctuary formation of 

Tertiary Usibelli group), outcrop: 0.5 to 3.5%. 

c.Thermal maturity Kandik basin: Tmax = 427-579°C, Ro = 0.8% (mean); Middle Tanana basin: 

Tmax = 414 to 434° C, Ro = 0.6% (below 4500 ft depth) 

d.Oil or gas prone primarily oil prone; however, level of maturity probably reaches the "gas 

window" 

e.Overall basin maturity marginally mature to overmature (similar to North Slope) 

f.Age and lithologies Early Cambrian to late Permian (sandstones, shales and carbonates), Upper 

Cretaceous to Tertiary (sandstones, conglomeratic sandstones, shales, coals 

and siltstones) 

g. Rock extent/quality basin wide source and reservoir rock distribution; highly variable rock 

quality is anticipated as exists on the North Slope, including problems with 

silica cementation, siderite cementation, calcite cementation, and swelling 

and moveable clays. 

h.Potential reservoirs no production exists; however, potential reservoirs include Proterozoic 

Tindir group; Paleozoic carbonates (including Devonian Nation River, 

Mississippian and Pennsylvanian Calico Bluff formation); shallow marine 

limestones of the Permian Tahkandit formation; Cretaceous Kandik group; 

Tertiary Usibelli group; and other unnamed sandstones of Cretaceous and 

Tertiary ages. 

i.Major traps/seals structural and stratigraphic, Devonian and Pennsylvanian argillites, shales, 

siltstones and mudstones of Cretaceous and Tertiary ages 

j.Petroleum 


models 

Weimer's (1996) "Cooking Pot" model with current hydrocarbon generation 

and relatively short distance migration and Meissner's (1978) Bakken shale 

expulsion model 

k.Depth ranges surface to 40,000 ft, in some tertiary basins, top of the oil generation window 

may range from 5,000 to 10,000 ft, depending upon thermal gradients and 

vitrinite reflectance values 

l.Pressure gradients



Economic 


a. Important 


b. Cumulative production 


b. Recovery 

c. Pipeline infrastructure non-existent, except for the trans-Alaska oil pipeline 

d. Overmaturity probably in the deep parts of the basins and in shallower areas near high 

heatflow pathways 

e. Basin maturity marginally immature on the flanks of basins where burial depths have been 

limited 

f. Sediment consolidation moderate or better consolidation 


problems 

h. Permeability 

i. Porosity 

unknown due to no known completions

68° 

66° 

64° 

62° 

60° 

58° 

166° 162° 158° 154° 150° 146° 142° 

Seward Peninsula 

Nome 

Norton Sound 

Kuskokwim Bay 

3-mile 

limit 

Bethel 

basin 

Bethel 

Togiak 

Bristol Bay 

Yukon River 

Kobuk basin 

Galena 

Innoko basin 

Galena basin 

Kuskokwim 

River 

Kuskokwim Mountains 

Interior 

Lowlands 

Province 

Dillingham 

McGrath 

Alaska 

Interior 

Province 

Ruby-Rampart 

trough 

Minchumina 

basin 

Figure 1. Map showing various provinces and basins in central Alaska. After Magoon (1989). 

Cook 

Inlet 

Yukon River 

Yukon Flats 

basin 

Tanana River 

Nenana basin 

Susitna 

River 

Kandik 

Province 

Fairbanks 

Glenallen 

Anchorage 

Copper 

River 

Chitina River 

Copper River 

Basin 

Province 

Porcupine River 

Klondike River 

Northway 

lowlands 

Yukon Territory 

Copper 

River basin 

0 100 mi 

Alaska

System 

Tertiary Sandstone, mudstone, 

and conglomerate 

Cretaceous 

Jurassic 

Triassic 

Permian 

Pennsylvanian 

Mississippian 

Devonian 

Silurian 

Ordovician 

Cambrian 

Precambrian 

Kandik Province 

Glenn Shale 

Tahkandit Limestone 

Calico Bluff Formation 

Ford Lake Shale 

Nation River Formation 

McCann Hill Chert 

Road River Formation 

Hillard Limestone 

Adams Argillite 

Funnel Creek Limestone 

Tindir Group 

Interior Lowlands 

Province 

Nenana Gravel 

Usibelli Group 

Non-deposition or 

removal by erosion 

Birch Creek Schist 

Figure 2. Generalized stratigraphic column for Kandik and Interior Lowlands provinces, central Alaska. After Stanley, 

McLean, and Pawlewicz (1990), and Magoon (1993).

65° 30' 

65° 00' 

143° 142° 141° 

4.2 

Mardow Creek fault 

3.6 

3.3 

3.7 

Tintina fault 

1.9 

2.7, 3.5 

Kandik terrane 

1.9, 1.6 

2.1 

3.3, 3.5 

2.8 

Glenn Creek fault zone 

0.6, 0.9 

1.6 

1.7 

2.5, 2.9 

2.1 

0.7 

2.2, 1.8 

Step 

Mountain 

Tatonduk 

terrane 

0.7 

0.9 

Alaska 

0.8 

2.2 1.7 

Yukon Territory 

1.0 

2.1, 1.8 

1.2 

1.7, 1.8 

2.0 

Undifferentiated nonmarine 

cover sequences of Tertiary 

and Cretaceous age (TKs) 

Kathul graywacke (Kka), 

Cretaceous 

Undifferentiated rocks of 

Step Mountain outcrop 

Fault 

Anticline 

Syncline 

Sample location and vitrinite 

reflectance percentage 

0 10 mi 

Figure 3. Map of the Kandik province showing sample locations for and values of vitrinite reflectance (%Ro) relative to major geologic structures 

(Kathul Mountain syncline and Step Mountain anticline). After ? 

1.2


The Late Proterozoic Chuar Group extends north-south from southwestern Wyoming into northern Arizona. 

Figure 1 depicts a map of the regional extent and outcrop locations of the Chuar rocks. Exposures in the Grand 

Canyon reach a thickness of approximately 5,370 ft, and the rocks consist of organic-rich gray-black shale and 

siltstone interbedded with sandstones and cryptalgal and stromatolitic carbonates (Reynolds et al., 1988; Palacas, 

1992). The Chuar Group contains the lower Galeros Formation and the overlying Kwagunt Formation (Figure 2). 

The lithologies indicate various cyclical depositional environments, including a sediment-starved basin rich in 

organic material, coastal and alluvial plains, paludal swamp, and nearshore aqueous. Deposition of the Chuar Group 

occurred on a marine embayment on the passive edge of a continent (Reynolds et al., 1988). 


There have been some exploratory penetrations in the Chuar, but no production. Shows and tests of this section 

are rare. Geochemical analyses of outcrop samples from the Walcott Member of the Kwagunt Formation indicate 

good to excellent source-rock potential and thermal maturity for oil generation. Tmax values range from 424 to 452 

°C. Total organic carbon values (TOCs) average ~ 3.0 %, with highs ranging from 8.0 to 10.0 %. Samples from the 

upper part of the Walcott yielded higher values than those from the lower part (Palacas, 1992). The underlying 

Galeros Formation shows lower TOC values and appears thermally overmature, but still might be within the 

window for gas generation. 


The Walcott Member demonstrates good source-rock potential and may contain sandstones with good reservoir 

quality. Stratigraphic and conventional structural prospects may exist if the source rock is continuous. 

1



Geologic 


Accumulation: 


Grand Canyon area, Late Proterozoic, Chuar Group, Kwagunt and Galeros 

Formations 

a. Source/reservoir the Walcott Member may be a source rock; interbedded sandstones may be 

reservoirs. 


(TOCs) 

range from 1.0 % to 10.0% (average ~ 3.0%) in outcrop samples of the 

Kwagunt Formation. The values for the Galeros Formation are not 

available. 

c. Thermal maturity Tmax values in the Walcott Member of the Kwagunt Formation range from 

424 to 452° C 

d. Oil or gas prone the Walcott Member is oil prone. The lower portions of 

the Kwagunt Formation and the Galeros Formation are gas-prone. 

e. Overall basin maturity because of the virtually untested 

nature of the deposit, it is immature 

f. Age and lithologies 

g. Rock extent/quality 


i. Major traps/seals 

j. Petroleum 


models 

k. Depth ranges 




Economic 


a. Important 




b. Recovery 

c. Pipeline infrastructure 

d. Overmaturity 

e. Basin maturity 

f. Sediment consolidation 


problems 


i. Porosity

36° 30' 

36° 00' 

Arizona 

Extent of Chuar Group 

or equivalent 

Outcrop of Chuar Group 

or equivalent 

Well penetrating 

Chuar Group or equivalent 

Grand Canyon 

Kaibab Plateau 

0 10 mi 

Chuar outcrop 

Colorado Rive r 

112° 30' 112° 00' 

Utah 

Arizona 

Figure 1. Map showing regional extent and outcrops of Chuar Group rocks in Utah and Arizona. After Palacas (1992).


The Columbia Basin is located in south-central to southwestern Washington, northeastern Oregon, and 

western Idaho (Figure 1). Johnson et al. (1993) defined the basin as a broad low-lying area between the 

Cascade Range to the west, the Rocky Mountains to the east, the Okanogan highlands to the north, the 

Blue Mountains to the south, the western end of the Yakima fold belt, and the eastern limit of the Palouse 

slope. 

Within the Columbia Basin, Johnson et al. (1997) postulated a basin-centered gas deposit bounded by 

the Chumstick basin and Swauk basin to the northwest, the easterly apron of the Cascade Range and a 

projection of the Straight Creek fault zone on the west and southwest, on the south by the Columbia River 

and margins of the Blue Mountains, on the east and northeast by the projection of the Entiat fault (Figure 

2). 

The sedimentary rocks in the basin are covered by up to 20,000 ft of Miocene basalt that originated 

from dike systems near the Washington-Oregon-Idaho border area approximately 6.5 to 16.5 ma (Figure 3) 

(Johnson et al., 1997). Mesozoic sediments underlie the basalts. Rocks associated with subduction 

complexes, volcanic island arcs, and ophiolites and other sedimentary packages indicate a complex history 

of accretion of allochthonous terranes and arc tectonism. Sediments crop out along the northern, eastern, and 

southern margins of the basalt plateau and probably underlie the entire plateau. 

Development of the Idaho Batholith in Cretaceous time and unconformable deposition of marine 

sediments marked the end of accretionary deposition. This was followed by deposition of early Tertiary 

nonmarine sedimentary and volcanic rocks. Tectonic activity included volcanism and transtension in 

northeastern Washington, strike-slip faulting and folding in central and western Washington, and prolific 

volcanism in central Oregon. Paleocene to Eocene arkoses, mudstones and coals were deposited, varying in 

thickness from a few hundred feet to more than 20,000 ft Sparse exploratory drilling and magnetotelluric 

data suggest that an average 5,000 to 10,000 ft of sedimentary rocks exist below the basalts in central 

Washington (Tennyson, 1996). 

The western margin of the Columbia plateau contains Oligocene to Quaternary volcanic rocks of the 

Cascade arc complex. Deformation of the basalts occurred with folding and reverse faulting in the western 

part of the plateau (Tennyson, 1996). 


The Rattlesnake Hills field is the only commercial gas field producing in the Columbia Basin. The 

field was discovered in 1913 and developed in 1930, and produced approximately 1.3 BCFG through 1941 

from depths ranging between 700 ft and 1300 ft. The gas was mostly methane and 10% carbon dioxide. A 

faulted anticlinal structure trapped the gas in a vesicular basaltic zone thought to be clay sealed. Johnson et 

al. (1993) believe the gas migrated from Eocene coals buried below the basalts. 


Tests in deep wells in the Yakima-Pasco area yielded gas at depths ranging from 8,300 to 12,700 ft. 

Lingley (1995) estimated pressure gradients of 0.42 psi/ft to 0.45 psi/ft at 5,000 to 10,000 feet and 0.62 

psi/ft at 14,000 ft depth, indicating moderate overpressures in the deep part of the basin. Johnson et al. 

(1997) note most drill-stem tests recovered water-free gas, but some did recover water. 

Source rocks for this accumulation may be Eocene coals and carbonaceous shales interbedded with 

arkosic fluvial sandstones. Eocene sediments may reach a depth of 17,000 ft in the center of the basin.



Geologic 


Accumulation: 


Eastern Oregon-Washington Province, Columbia Plateau/Basin, basincentered 

gas play 

a. Source/reservoir Eocene Swauk, Chumstick, Roslyn, and Manatash formations 


(TOCs) 

c.Thermal maturity Ro 0.5 – 1.43 

values range from 0 to 17% 

d.Oil or gas prone gas prone; mostly type III kerogens with limited type II kerogen 

e.Overall basin maturity maturation levels are moderate, maturation levels increase west of the basin 

toward the crest of the Cascade mountains 

f.Age and lithologies Eocene, arkosic sands, coals, and shales 

g. Rock extent/quality wide source and reservoir rock distribution, rock quality is unknown except 

around basin margins and in the few wells that have been drilled. Expected 

reservoir quality is variable depending upon clay content, zeolite alteration 

and interbedded shales and coals. 

h.Potential reservoirs none presently; Rattlesnake Hills gas field produced 1.3 BCFG from 1930 to 

1941 from the Miocene age Columbia River Basalt Group. Vertical 

migration of gas from Eocene source rocks buried below the basalt flows. 

i.Major traps/seals interbedded Eocene age shales and coals 

j.Petroleum 


models 

both in-situ generation and long distance migration of gases shales and coals. 

Hydrocarbon generation is probably ongoing at depths below 12,000 feet. 

Geothermal gradients range from 28 to 58 degrees centigrade per kilometer 

(Lingley, 1995). Weimer’s (1996) Denver basin cooking pot model might 

apply. 

k.Depth ranges accumulation depths are thought to range from 8300 feet to 17,000 feet 

l.Pressure gradients range from estimated 0.42 psi/ft at 5,000 ft depth to 0.45 psi/ft at 10,000 ft to 

0.62 psi/ft at 14,000 ft. This conflicts with Johnson et al. (1997) which 

reported overpressuring occurring at depths of 8,300 ft to 12,700 ft.



Economic 


a. Important 


Rattlesnake Hills gas field 

b.Cumulative production only production to date was from 1930-1941. Rattlesnake Hills field 

produced 1.3 BCFG from Miocene age basalts 

a. High inert gas content gases from the Rattlesnake Hills field were reported to contain 10% nitrogen 

by Wagner (1966); Hammer (1934) reported 2.45% nitrogen and 0.15% 

carbon dioxide 

b.Recovery recoveries may vary depending upon permeability, porosity and depth; 

diagenetic alteration may increase with depth 

c.Pipeline infrastructure poor 

d.Overmaturity possibly overmature in the deepest parts of the basin 

e.Basin maturity most of the basin is mature (Ro range from 0.5 to 1.43) 



problems 

shales, clay and mica rich arcosic sands have high alteration potential, may 

have swelling clays and will produce migrating fines problems, average 

porosities range from 6 to 15 percent. Shales and coals are interbedded with 

sands. Zeolite and chlorite alteration has been reported. 

h.Permeability outcrop measurements range from 0.02 to 0.8 md 

i.Porosity

123° 120° 117° 

Western Washington- 

Bellingham Basin play 


Western Cascade Mountains play 


Southern Puget Lowlands play 

Figure 1. Map of Washington showing locations of unconventional petroleum plays. After Johnson et al. (1997) 

Columbia Basin- 

Basin-Centered Gas play 

0 50 mi 

49° 

47°

47° 

46° 

121° 120° 119° 

BN 23-35 

12,584 

YM 1-33 

16,199 

Quaternary deposits 

Columbia River 

Basalt Group 

Yakima River 

Oligocene and Miocene 

volcanic and plutonic rocks 

Eocene volcanic rocks 

Eocene sedimentary rocks 

Pre-Tertiary rocks 

1-29 Bissa 

14,965 

Colu mbia River 

RSH-1 

10,655 

Quincy 

13,190 

BN 1-9 

17,518 

RHGF 


0 25 mi 

RSH-1 

10,655 

Fold 

Monocline 

Fault 

Darcell 1-10 

8,556 

Snake Rive r 

Play Boundary 

Exploration well, 

with name and depth 

Figure 2. Geologic map of Columbia Basin, showing locations of basin-centered gas play and exloration wells. 

After Johnson et al. (1997).

Years Ma (millions ago) 

0 

10 

20 

30 

40 

50 

60 

Epoch 

Pleistocene 

Pliocene 

Miocene 

Oligocene 

Eocene 

Paleocene 

Northwest Columbia Plateau 

local non-marine deposits 


Basalt Group 

Roslyn 

Formation 

Teanaway Fm 

Swauk 

Formation 

? 

Wenatchee Formation 

Ellensburg 

Formation 

Chumstick 

Formation 

Figure 3. Stratigraphic column for Columbia Basin petroleum-play area. Shaded intervals indicate occurances of 

erosion or no deposition. After Tabor et al (1982, 1984), Taylor et al (1988), Evans and Johnson (1989), 

and Johnson et al (1997). 

? 

?


The Cook Inlet basin is a narrow elongate trough of Mesozoic and Tertiary sediments, covering 

approximately 11,000 square miles in south-central Alaska (Figure 1). The basin trends NNE-SSW and is 

bounded on the northwest by granitic batholiths of the Alaska-Aleutian range and the Talkeetna mountains, 

and on the southeast by the Chugach terrane that makes up the Kenai Mountains (Magoon, 1994). The 

Kenai mountains, Castle mountain, and the Bruin Bay fault zones are the major boundary features (Boss et 

al., 1975). The Outer Continent Shelf area lies between these faults and contains anticlinal structures and 

faults that may be potential traps for hydrocarbons (Magoon, 1976). 

Dickinson (1971) described the basin as a trench-arc gap type: a Cenozoic residual forearc basin in a 

convergent continental margin along the northwest Pacific Rim. Cook Inlet basin development began as a 

backarc basin during the Jurassic, evolving to a forearc basin in the Cenozoic (Magoon, 1994). Numerous 

high angle reverse faults indicate compression throughout the Mesozoic and Cenozoic. 

Kelly and Halbouty (1966) estimated the maximum sediment thickness in the deepest part of the basin 

to be 40,000 ft. Cook Inlet sediments range in age from Upper Triassic to Recent, but consist mostly of 

Upper Jurassic and Tertiary rocks (Figure 2). The Middle and Upper Jurassic units are thick, but a 

significant mid-Cretaceous unconformity has removed the Lower Cretaceous section. Boss et al. (1975) 

considered the Lower Jurassic volcanic rocks to be the economic "basement.” 

During the Tertiary uplift and erosion occurred continuously until termination by a widespread Late 

Pliocene-Pleistocene orogeny. The Tertiary section is part of the Kenai Group, which is separated from the 

West Foreland Formation (Eocene) by a thin but widespread unconformity marked by a basal conglomerate. 

The Kenai Group consists of three formations: Tyonek, Beluga, and Sterling. The Tyonek Formation 

includes the Hemlock Sandstone Member. 


The most significant hydrocarbon production in the Cook Inlet basin occurs in Tertiary rocks which 

reach a maximum thickness of 25,000 ft in the deepest part of the basin (Smith, 1995). These rocks consist 

of a thick sequence of alluvial deposits. Of the total oil produced to 1994, Magoon (1994) noted that 80% 

originated from the Hemlock Conglomerate, 20% from the Lower Tyonek, and minor amounts from the 

West Foreland Formation. Discovered resources exceed 1.2 BBO. Unassociated natural gas occurs in 

shallower younger reservoirs and accounts for most of the Cook Inlet gas production (Magoon and Kirchner, 

1990). This gas is found in the Beluga and Sterling formations, may be biogenic, and primarily originates 

from Tertiary coals (Molenaar, 1996). Only minor amounts of oil have been produced from Mesozoic rocks. 

The Middle Chuitna Formation in the upper Cook Inlet and the Upper Triassic-Middle Jurassic rocks in the 

lower Cook Inlet are the source rocks for oil. Siltstones and claystones associated with coals compose the 

seals. 

1 

Bird (1996) identified three petroleum systems in the Cook Inlet 

1. Hemlock-Tyonek oil play. 

2. Beluga-Sterling gas play. 

3. Late Mesozoic oil plays. This play includes Lower Jurassic to Upper Cretaceous rocks. This 

interval appears to be the only stratigraphic section capable of supporting a basin-centered gas play 

in the Cook Inlet basin.

To date, production in the Late Mesozoic play has been marginal because of poor reservoir-quality 

rocks. Limited production has occurred from marine and turbidite sandstones within the Upper Cretaceous 

Matanuska and Kaguyak Formations, Lower Cretaceous sandstones, and the Upper Jurassic Naknek 

Formation. Lateral permeability barriers within siltstones seal these reservoirs and the reservoirs in the 

unconformably overlying Lower Tertiary West Foreland Formation. However, most of these fields are 

faulted anticlinal structures truncated by overlying Tertiary rocks. Oil was generated during Eocene and 

Pliocene periods (Magoon et al., 1996). 

The Tertiary section (Beluga-Sterling gas play and Tyonek/Paleocene Chickaloon coals) in the upper 

Cook Inlet include coals as source rocks within an area described by Molenaar (1996) as thermally 

immature. This area contains gas fields having localized sources. In contrast, Smith (1995) reported carbon 

isotope analyses of gas from coals in the Tyonek Formation that indicated both biogenic and thermogenic 

origins. The reported gas volumes from coals ranged from 63 scf/ton at 521 ft in depth to 245 scf/ton at 

1,236 ft in depth. 


Although few holes were drilled in the central trough of the Cook Inlet, limited data (mostly from the 

COST No. 1 well shown in Figure 1) indicates a significant increase in thermal maturity to Ro = 0.87 in 

the lower part of the Middle Jurassic Naknek Formation. Thermal maturity of Middle Jurassic source rocks 

ranges from immature to mature on the flanks of the basin and postmature in the deepest part of the basin 

(Magoon, 1994). However, conflicting interpretations place the oil window (Ro = 0.6) at disparate depths: 

Magoon (1994) projects the depth at 21,000 ft in the vicinity of the Swanson River oil field (Figure 3), 

whereas Johnsson et al. (1993) place the oil window at about 16,400 ft depth (Figure 4). This difference 

dramatically changes the basin area that may be thermally mature. 

Frequent hydrocarbon shows occur within the Middle Jurassic interval. Significant variations in 

pressure gradients occur within the current oil and gas producing fields and flank the area of the potential 

basin-centered accumulation. Although this does not directly indicate pressure seals occur in the central 

trough of the Cook Inlet, the data suggests that lateral permeability barriers do exist within the 

conventionally trapped hydrocarbon accumulations. Source rocks within the Middle Jurassic Tuxedni Group 

indicate adequate but somewhat limited source potential (TOC content of 0.8 to 2.1 weight %). A normal 

geothermal gradient of 12.5 °F per 1000 ft (in the COST No. 1 well) also appears to lessen the possibility 

of a basin-centered accumulation at shallow depths. 

Depending on the oil generation window interpretation, basin-centered gas accumulations in the Cook 

Inlet may potentially range in depth from less than 3,280-19,685 ft for the upper limit, to 41,891 ft for the 

floor. 

2



Geologic 


Accumulation: 


Southern Alaska, Cook Inlet basin, lower Jurassic to upper Cretaceous 

overpressure 

a. Source/reservoir Middle Jurassic Tuxedni group, Reservoirs - Lower Jurassic Talkeetna fm, 

Middle Jurassic Tuxedni group, Upper Jurassic Naknek formation, and 

Upper Cretaceous Matanuska formation 


(TOCs) 

0.8-2.1 weight% (Middle Jurassic Tuxedni group) 

c. Thermal maturity Tmax from lower part of Naknek formation in the Cost #1 well is 

approximately 483° C; Ro maximum is approximately 0.87% 


e. Overall basin maturity immature to mature, anticipated to be postmature in the deepest part of the 

basin 

f. Age and lithologies Lower Jurassic Talkeetna formation (massive volcanic conglomerates, tuffs 

and sandstones), Middle Jurassic Tuxedni group (marine sandstone, 

conglomerates, siltstones and shales), Upper Jurassic Naknek formation 

(shallow marine fine grained, cross-bedded sandstone) Upper Cretaceous 

Matanuska formation (shallow marine turbidite sandstones). 

g. Rock extent/quality marginal basin wide source and variable reservoir rock distribution 

h. Potential reservoirs Talkeetna formation, Tuxedni group, Naknek formation and Matanuska 

formation 

i. Major traps/seals Tuxedni group 

j. Petroleum 


models 

Weimer's "Cooking Pot" model with current hydrocarbon generation and 

relatively short distance migration 

k. Depth ranges 3,280 to 41,900 ft (6 to11 km) 

l. Pressure gradients Granite Point field (Tyonek formation) 0.476 to 0.503 psi; McArthur River 

field (Hemlock formation) 0.399 to 0.454 psi; Middle Ground Shoal field 

(Tyonek formation) 0.263 psi, (Hemlock formation) 0.488 psi; Swanson 

River field (Hemlock formation) 0.504 to 0.518 psi; Trading Bay field 

(Tyonek formation) 0.487 psi, (Hemlock formation) 0.261 psi.



Economic 


a. Important 




b. Recovery 

c. Pipeline infrastructure good 

only marginal production occurs within the Upper Jurassic Naknek to Upper 

Cretaceous Matanuska formations. 

d. Overmaturity probably in the deep part of the basin 

e. Basin maturity immature on flanks of the basin 

f. Sediment consolidation good to moderate consolidation 


problems 

low porosity because of probable clays and migrating fines 

h. Permeability not available, but expected to be highly variable 

i. Porosity highly variable

62° 

60° 

58° 

Bruin Bay Fault 

Aleutian Range 

Alaskan Peninsula 

Mt. Douglas 

Mt. Iliamno 

Mt. Augustine 

Augustine 

Island 

Cape 

Douglas 

Shelikof Strait 

Mt. Redoubt 

Iniskin 

Peninsula 

Cost #1 

Barren 

Island 

Mt. Spurr 

A 

Basin-centered 

Gas Accumulation 

Afognak 

Island 

Homer 

Tyonek 

C 

D 

6 

E B 

F 

Kenai 

Kenai 

1 

7 

Peninsula 

Castle Mountain Fault 

Border Ranges Fault 

Gulf of Alaska 

Girdwood 

Seward 

Cook Inlet 

154° 152° 150° 148° 

Oil field Volcano 

Gas field 

Well 

12 

2 

4 

8 

5 

9 

11 

10 

A 

3 

A' 

Anchorage 

Fault, dashed where approximate, 

dotted where inferred or hidden 

Anticline, dashed where approximate 

Figure 1. Location map of Cook Inlet, Alaska. Modified from Magoon (1976, 1994). 

0 50 mi

System 

Quaternary 

Tertiary 

Cretaceous 

Jurassic 

Series 

Recent 

Pleistocene 

Pliocene 

Miocene 

Oligocene 

Eocene 

Upper 

Lower 

Upper 

Middle 

Lower 

Coal 

Formation 

(thickness) 

Alluvium 

Glacial 

Chuitna Member 

(1300-2600 ft) 

Middle Ground 

Shoal Member 

(2600-4900 ft) 

Shale or claystone 

Siltstone 

Sterling Formation 

(0-11,150 ft) 

Beluga Formation 

(0-5900 ft) 

Unnamed 

(0-1800 ft) 

Tuxedni Group 

(0-9800 ft) 

Tyonek Formation 

Hemlock Cgl (330-1000 ft) 

West Forland Formation 

(300-1300 ft) 

Mantanuska Formation 

(0-8500 ft) 

Naknek Formation 

(0-6900 ft) 

Chinitna Fm (0-2300 ft) 

Talkeetna Formation 

(0-8500 ft) 

Lithology 

Production 

Field Source Rock 

Depositional 

Environment 

Oil Gas Oil Gas 

B, D, E, 

F 

A, B, C, 

D, E, F 

E 

Sandstone 

Conglomerate 

Volcanic rock 

1, 2, 3, 

5, 7, 8, 

9 

1, 2, 8, 

9 

11 

4, 6, 

10, 12 

Nonmarine 

Figure 2. Generalized stratigraphic column for Cook Inlet, Alaska, showing producing intervals, oil and gas fields 

(noted on location map), source rock intervals, and depositional environment. After Magoon (1994). 

Marine 

Gas 

Oil

Sea Level 

Depth (in feet) 

1 

2 

3 

4 

5 

6 

7 

A A' 

Geographic Extent 

Trading Bay Field 

(projected) 

McArthur 

Swanson 

River Field Middle Ground 

River Field 

Coast Line Shoal Field 

Coast Line Kenai Lowlands 

Oil accumulation 

Beluga and Sterling 

Formations 

Hemlock Conglomerate 

and Tyonek Formation 

Stratigraphic Extent 

Matanuska Formation 

Naknek Formation 

and unnamed rocks 

Tuxedni Group 

Source Rock 

Talkeetna Formation 

Mesozoic intrusive rocks 

Oil field location 

0 20 mi 

Fault 

Top oil window 

(0.6% R o) 

Top gas window 

(1.3% R o) 

Figure 3. Cross section A-A' of Cook Inlet, Alaska, showing the geographic (horizontal) and stratigraphic (vertical) extent of the Tuxedni-Hemlock 

petroleum system. After Boss et al. (1976), Plafker et al. (1982), and Magoon (1994).

62° 

60° 

58° 

B r u i n Bay fault 

Mt. Iliamna 

Augustine 

Island 

Mt. 

Redoubt 

Mt. Spurr 

A 

L a k e Clark - C astle M ountain fau lt 

Seldovia arch 

Border Ran ges fault 

Matanuska Valley 

154° 152° 150° 148° 

Volcano 

Well 

1000 2000 

3000 

4000 

4000 

Contour interval = 1000 feet 

5000 

Figure 4. Contour map of the top of the paleo-oil generation window (%Ro = 0.6) in the Cook Inlet basin, Alaska. 

Elevation contours in feet below mean sea level. After Johnson, Howell and Bird (1993). 

3000 

4000 

3000 

A' 

2000 

Anchorage 

0 50 mi 

Anticline Contour, 

dashed where 

approximate 

Fault


The Denver basin is an asymmetric crustal downwarp located mainly in eastern Colorado, western 

Nebraska and southeastern Wyoming. It is surrounded by the Rocky Mountain Front Range on the west, 

the Laramie Range to the northwest, the Hartville Uplift to the north, the Chadron Arch and Cambridge 

Arch to the northeast, the Yuma Uplift to the east, the Los Animas Arch to the southeast, the Apishapa 

Uplift to the south and the Wet Mountains Uplift to the southwest (Bookout, 1980). The basin axis runs 

roughly north-southfrom Cheyenne, Wyoming to Denver, Colorado (about 320 miles), and the basin width 

extends about 180 miles (Figure 1). 

The basin’s sedimentary section reaches a maximum thickness of 13,000 ft along the axial trend 

(Clayton and Swetland, 1977), and consists mostly of Cretaceous, Permian and Pennsylvanian rocks 

(Figure 3). 

With the onset of the Laramide Orogeny in the Late Cretaceous, the ancestral Denver basin accumulated 

sediments that thickened westward (Figure 4). Deposition began with the Upper Cretaceous Fox Hills 

sandstone and continued through the Miocene (McCoy, 1953). 

The present-day Denver basin has undergone a full cycle of tectonic evolution since the Cambrian: 

Early Paleozoic troughs became Late Paleozoic mountain ranges, and Early Paleozoic highs subsided into 

lows. Late Paleozoic troughs were uplifted into post-Cretaceous mountain ranges, and Late Paleozoic 

mountain ranges subsided into Tertiary and Recent plateaus and low relief basins (McCoy, 1953). 


Cretaceous rocks are the primary strata producing petroleum (Figure 3). This interval consists mostly 

of deltaic and marine detrital rocks. Although oil and gas originate from a number of Cretaceous reservoirs, 

the Lower Cretaceous "D" and "J" sandstones account for more then 90% of the total oil and gas production 

of the basin" (Clayton and Swetland, 1977). 

The most significant hydrocarbon production in the Denver basin occurs in the Wattenberg field, where 

the "J" Sandstone is the dominant producing horizon (Figure 1). As of June 1998, cumulative production 

from the Wattenberg field was 1.5 trillion cubic feet of gas (TCFG), 67 million barrels of oil (MMBO), and 

13.3 million barrels of water (MMBW) at average depths of 7,600 ft for the "J" Sandstone and 5,100 ft for 

the Hygiene Sandstone (Petroleum Information Corp., 1998). 

Limited oil production occurs above the "D" and "J" in the Graneros Shale, the Greenhorn Limestone, 

and the Codell Sandstone. Two members of the overlying Niobrara Formation yield oil–the Fort Hays and 

the Smoky Hill members. The fractured Niobrara strata produced significant quantities of hydrocarbons from 

the Berthoud field (765 MBO and 1.85 BCFG; 4.3 MBW) and the Silo field in southeastern Wyoming (8.5 

MMBO and 6.8 BCFG; 3.7 MMBW) (Petroleum Information Corp., 1998). 

Figure 2 shows the locations of Niobrara gas fields. Beecher Island field (1,700 ft deep, cumulative 

production 39.6 BCFG between 1974 and 1998) and Goodland field (900 ft deep) represent shallow Niobrara 

biogenic gas fields in eastern Colorado and western Kansas (Figure 2). Oil production from the Niobrara is 

limited to the west flank of the basin along the Colorado and Wyoming eastern mountain front (Clayton 

and Swetland, 1977). 

1


Field data supports the existence of a basin-centered hydrocarbon accumulation in the Denver basin. 

Widespread hydrocarbon shows occur within the interval below the Hygiene sandstone. In the area of the 

Wattenberg field, Weimer (1996) reported overpressuring from the top of the Hygiene sandstone to the top 

of the Muddy sandstone (Figure 5). These depths conform to a vitrinite reflectance anomaly that Smagala et 

al. (1984) plotted at and below the Terry-Hygiene boundary (Figure 6). Geothermal gradients as high as 

30°F per 1,000 ft of burial–nearly double the norm for this basin–also occur in the vicinity of the 

Wattenberg field (Bookout, 1980). Well data indicate that the overpressure in the Denver basin has an upper 

window depth of approximately 4,500 ft. This overpressured zone eventually pinches out east of the 

Wattenberg field. 

Figure 2 shows biogenic gas fields exists east of the limit of thermally-mature Niobrara source rocks. 

Significant underpressuring occurs in this area with reported pressure gradients as low as 0.21 psi/ft at the 

Beecher Island field. Lockridge and Scholle (1978) note that Niobrara gas accumulations here are associated 

with low-relief anticlinal closures; thus this area has a low potential for continuous-type accumulations. 

2



Geologic 


Accumulation: 


Rocky Mountain, Denver Basin, early to late Cretaceous overpressure 

a. Source/reservoir includes Pierre Shale through Mowry Shale. "J" (Muddy) Sandstone 

(underpressured) is a probable target at base of overpressure zone. 


(TOCs) 

0.3-10.6% (Sharon Springs member of Pierre); 1.3-2.4% (Mowry and Skull 

Creek shales); 5.8% maximum (Smokey Hill chalk member of Niobrara) 

c. Thermal maturity Tmax 464 to 401° C, Ro 1.5 to Ro



Economic 


a. Important 


Wattenberg (J Sandstone), Berthoud (Niobrara Chalk), Silo (Niobrara 

Chalk), Beecher Island (Niobrara Chalk) 

b.Cumulative production Wattenberg-"J" Sandstone, 67 MMBO, 1.5 TCFG, 13.37 MMBW; Silo field, 

8.45 MMBO, 6.8 BCFG, 3.7 MMBW; Beecher Island, 0 BO, 39.6 BCFG, 

37.9 MMBW; Berthoud field, 765 MBO, 1.86 BCFG, 4.3 MMBW. 

a. High inert gas content no high inert gas content 

b.Recovery highly variable 

c.Pipeline infrastructure good 


e.Basin maturity east flank is immature 

f.Sediment consolidation consolidation/porosity reduction occurs with depth of burial, especially in the 

Niobrara Chalk (Pollastro and Martinez, 1985) 


problems 

chalks & other tight (low permeable rocks) produce where they are naturally 

fractured (Berthoud) 

h.Permeability deep basin (Wattenberg area), Niobrara chalk, approx. 0.001 to 0.01 md 

(Nydegger, 1999); eastern flank (Beecher Island field), Niobrara = 1 to 6 md 

i.Porosity deep basin (Wattenberg area), Niobrara chalk = 6.3%; eastern flank (Beecher 

Island area), Niobrara chalk = 39-42%

42° 

41° 

40° 

39° 

| | | | | | 

105° 104° 103° 102° 

Hartville uplift 

DB-1 

| | 

Cheyenne 

Denver 

DB-5 

DB-2 

DB-4 

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | 

DB-3 

Chadron arch 

Wyoming Nebraska 

Colorado Springs 

0 50 kilometers 

Colorado 

Denver Basin 

30 miles 

DB-1. Sussex (Terry) and Shannon DB-3 Niobrara Chalk Biogenic 

(Hygiene) Sandstone play Gas play 

DB-2 Codell Sandstone and Niobrara DB-4 D Sand play 

Formation (Wattenberg Area) play DB-5 Muddy (J) Sand play 

Kansas 

Figure 1. Index map of Denver basin showing boundaries of major (> 5 BCF) gas reservoirs. Modified from 

Shurr, 1980; Rice, 1984; and Hemborg, 1993. 

0

42° 

41° 

40° 

39° 

| | | | | | 

105° 104° 103° 102° 

Hartville uplift 

| | 

Cheyenne 

2500 

2000 

Denver 

Area of Niobrara 

oil production 

1500 

Area of Niobrara 

and/or Codell wet 

gas condensate 

and/or oil production 

500 

Limit of thermally-mature 

Niobrara source rocks 

(After Tainter, 1982) 

1000 

Area of shallow 

Niobrara biogenic 

gas fields 

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | 

Chadron arch 

Wyoming Nebraska 

Colorado Springs 

0 50 kilometers 

Colorado 

Denver Basin 

Figure 2. Index map of Denver basin showing Niobrara Formation gas reservoirs. Isopachs represent 

depth to top of Niobrara Formation. Contour values are in meters. Modified from Shurr, 1980; 

Rice, 1984; and Hemborg, 1993. 

0 

30 miles 

500 

Kansas

Era 

Cenozoic 

Mesozoic 

Paleozoic 

Tertiary 

Cretaceous 

Period 

Oligocene 

Eocene 

Paleocene 

Upper 

Lower 

Jurassic 

Triassic 

Permian 

Pennsylvanian 

Mississippian 

Subsurface 

Denver Basin 

White River Fm 

Denver-Dawson Fm 

Pierre 

Shale 

Niobrara 

Fm 

Carlile 

Shale 

Arapahoe Fm 

Laramie Fm 

Fox Hills Fm 

Greenhorn Ls 

Graneros Sh 

Mowry Sh Dakota Ss 

Muddy (J) Ss 

Skull Creek Sh 

Plainview Ss 

Lytle Ss 

Morrison Fm 

Ralston Creek Fm 

Entrada Fm 

Jelm Ss 

Lykins Ss 

Lyons Ss 

Fountain 

Fm 

Smoky Hill 

Fort Hayes Ls 

Codell Ss 

Blue Hill Sh 

Fairport Ch 

Ingleside Fm 

Virgilian 

Figure 3. Geologic Column of Denver basin. After Hemborg, 1993. 

Source 

Rock 

Interval 

Producing 

Units

Cody Sh 

Frontier Fm 

Mowry Sh 

Shell Creek 

Muddy 

A 

NW 

CENTRAL WYOMING 

Wall Cr Mbr 

Belle Fourche Mbr 

Thermopolis 

sec. 26-27 

T39N R83W 

sec. 32 

T34N R81W 

VIII 

VII 

IV 

Formation or member contact 

Unconformity 

Time surface 

(Subsurface marker bed of faunal zone boundary) 

III 

II 

I 

? 

? 

? 

DOUGLAS SW CORNER 

NEBRASKA 

? 

Benton Sh 

Niobrara Fm 

Graneros Fm 

NW CORNER 

KANSAS 

sec. 31 

T31N R71W T12N R59W T1S R42W 

Marine & 

Non-marine 

EXPLANATION 

Marine 

DENVER BASIN 

400 mi (645 km) 

D Sand 

Huntsman Sh 

Muddy (J) 

Skull Creek 

Mbr 

Shale 

Chalk or 

& Siltstone 

Calcareous Shale 

30 m 100 ft 

SHELF SLOPE BASIN 

Sea Level 

0 

30 mi 

50 km 

RUSSELL CO. 

KANSAS 

Mbrs 

Fort 

Hays 

Codell 

Blue 

Hill 

Fairport 

A' 

SE 

Jetmore & Pfeifer 

Heartland 

Lincoln 

Powder River 

Basin 

A 

WYOMING 

Laramie Basin 

Fms 

Niobrara 

Carlile 

Greenhorn 

Graneros 

Dakota 

Kiowa 

CENOMANIAN TURONIAN 

ALBIAN 

LOCATION MAP 

Denver Basin 

COLORADO 

NEBRASKA 

Figure 4. Restored stratigraphic cross section for D Sandstone and associated units from central Wyoming to central Kansas. After Weimer, 1983. 

KANSAS 

A'

Depth (ft) 

0 

1,000 

2,000 

3,000 

4,000 

5,000 

6,000 

7,000 

8,000 

9,000 

10,000 

Hydrostatic Gradient (0.43 PSI/ft) 

Underpressured 

0 1000 2000 3000 4000 5000 6000 7000 

Pressure (psi) 

Overpressured 

Migration 

Points 

Pierre Shale 

Sharon Ss Mbr 

Niobrara Fm 

Figure 5. Pressure plot for township T 3 N, R 65 and 66 W, and T 5 N, R 65 W. Dots indicate the 

stratigraphic level in wells for which pressure data are available. After Weimer, 1996. 

Terry Ss 

Hygiene Ss 

Codell Ss 

Benton Fm 

Muddy (J) Ss 

Source 

Rock 

Interval

Depth (ft) 

0 

1,000 

2,000 

3,000 

4,000 

5,000 

6,000 

7,000 

8,000 

9,000 

Vitrinite Reflectance (% R0) 

.1 .2 .3 .4 .5 .6 .7.8.91 2 3 4 

Surface Coals 

Terry-Hygiene 

Interval 

Skull 

Creek 

Figure 6. Plot of vitrinite reflectance versus depth from well and surface coal data (Wattenberg field 

area), showing dogleg maturation profile. After Smagala et al., 1984.


The Great Basin is part of the Basin and Range geologic province, which makes up most of Nevada. Figure 1 

shows the grabens (valleys) in the province. The state has undergone complex geological and structural development. 

At least four major orogenies affected the area prior to the initiation of Basin and Range extension during the 

Miocene (Montgomery, 1988). Uplift during the Antler orogeny (Late Devonian to Early Mississippian) created a 

north-south trending barrier, isolating a foreland basin to the east. Next, the Sonoma Orogeny (Late Permian through 

Early Triassic) emplaced the Golconda Allochthon in central Nevada. The Jurassic Nevadan Orogeny involved 

thrusting and folding in the central part of the state and ended the marine sedimentation. The Sevier/Laramide episode 

(Late Jurassic through the Eocene) resulted in extensive volcanism throughout much of western and central portion 

Nevada, and creation of the Rocky Mountain Thrust Belt. Another period of extensive volcanism began in the 

Oligocene. 

During the Paleozoic era and ending in the Permian, up to 50,000 feet of shallow water carbonate and clastic 

rocks were deposited (Peterson, 1988). From the Cretaceous through the Eocene, large lakes formed in the Black 

Rock Desert area and in the Carson Sink (Figure 1) and organic-rich rocks were deposited, including the Sheep Pass 

Formation (Late Cretaceous–Eocene), the Newark Canyon Formation (Late Cretaceous), and the Elko Formation 

(Eocene–Oligocene). In southeast and northwest Nevada, large lakes formed during Miocene and Pliocene time 

(Barker, 1996; Hastings, 1979). These lakes contain organic rich source rocks. Figure 2 shows stratigraphic columns 

for two areas in eastern Nevada. 

Crustal extension began in the Miocene, forming characteristic Basin and Range structures: alternating horsts 

and grabens (Peterson, 1988). Extensional faulting continues to the present. Block faulting broke up the Sheep Pass, 

Newark Canyon and Elko Basins. Their lacustrine and clastic fluvial deposits subsided into deep grabens. Figure 3 

shows a cross section across Railroad Valley in east-central Nevada. Several present day valleys contain over 10,000 

feet of late Tertiary and Pleistocene fluvial, lacustrine and volcanic valley fill (Peterson, 1988). These Tertiary 

lacustrine deposits provided the source rock for several oil fields in Nevada. The Sheep Pass Formation provided both 

source and reservoir strata for Eagle Springs Field and source rocks for Trap Springs Fields in Railroad Valley 

(Figure 2). 


There are 12 producing oil fields in Nevada at present. Reservoirs include the Garrett Ranch Volcanics, which 

produce at Trap Springs Field, and the Sheep Pass Formation, which produces at Eagle Springs Field. Most 

exploration has been along the faulted valley margins. 

All deep Tertiary basins will probably have at least one good source rock either in the basin, or subcropping 

against the basin fill. Barker (1996) states that Tertiary lacustrine shales and marls from six wells in the Carson Sink 

have a TOC range from 0.1 to 3.0%. The rocks have a hydrogen index over 400 mg/gram organic carbon and are oil 

prone. There is unusually high heat flow in the area. Strata buried only 3,300 to 6.600 ft deep during the Pliocene 

may now be in the oil generation window.


Gas shows have occurred in many exploration wells, indicating some of these basins have generated gas. Deep 

source rocks in the grabens probably lie on the gas-only generation window, because of high geothermal gradients. 

The Tertiary Sheep Pass, Newark Canyon and Elko Formations are considered the most prospective for 

hydrocarbon generation, migration and trapping (Figure 2). There are other hydrocarbon source rocks in Nevada, 

including the Mississippian Chainman Shale, which in Railroad Valley is a partial source for the Eagle Springs 

Field and the main source for the Grant Canyon Field. These pre-Tertiary source rocks may have helped charge 

possible basin-centered gas accumulations within the Tertiary graben valley fill. 

Regional gravity data show several basins that contain thick Tertiary fill. The valley fill is less dense than the 

older Paleozoic and Mesozoic strata that crop out in the bordering mountain ranges and form the basement in the 

grabens. Jachens and Moring (1990) published gravity maps that show the thickness of Tertiary strata. Figure 4 

shows areas with pronounced residual gravity minima that may indicate thick Tertiary strata. 

Several valleys in east-central Nevada have anomalously low gravity (Jachens and Moring, 1990). Tertiary 

lacustrine valleys are the most prospective for basin-centered gas. Their basin configurations are better known from 

seismic data than are other Basin and Range valleys. Some valleys fall within a gravity low, but are not in eastern 

Nevada and so remain speculative for basin-centered gas. 

The Carson Sink in Western Nevada does not fall within a gravity low, but seismic data indicates 11,000 ft of 

Tertiary fill, including organic-rich lacustrine source rocks (Barker, 1996), and several exploration wells have gas 

shows.



Geologic 


Accumulation: 


Basin and Range Province; Cenozoic Speculative Basin Centered Gas 

Accumulation 

a. Source/reservoir Organic-rich Tertiary lacustrine shales: Sheep Pass Fm (Paleocene-Eocene), 

Elko Fm (Paleocene), and Neward Canyon Fm (Cretaceous); several 

Paleozoic source rocks may also contribute hydrocarbons to this play 


(TOCs) 

(Peterson, 1988): Chainman Shale (Mississippian), Pilot Shale (Upper Dev. - 

Lower Miss.), Carbon Ridge Fm (Permian); Webb Fm (Miss.), Woodruff Fm 

(Devonian), Slaven Chert (Devonian), and Vinini Fm (Ordovician) 

All deep Tertiary basins will probably have at least one good source rock 

either in the basin, or subcropping against the basin fill. Barker (1996) states 

that Tertiary lacustrine shales and marls from 6 wells in the Carson 

Sink have a TOC range from 0.1 – 3.0%. The rocks have a hydrogen index 

over 400 mg/gram organic Carbon and are oil prone. There is unusually high 

heat flow in the area. Strata buried only 1 to 2 km deep during the 

Pliocene may now be in the oil generation window. 

Poole and Claypool (1984) report the following TOC values: 

Source System or Series Total Organic Carbon 

(TOC) (%) 

Sheep Pass Fm..............................Paleocene - Eocene................ ........ 3 - 4 avg, to 9.5 max 

Elko Fm ......................................Eocene - Oligocene (?)........... ........ 33.5 - 38.8 (oil shale) 

Newark Canyon Fm.......................Cretaceous........................... ........ to 5.66 

Chainman Shale............................Mississippian....................... ........ 2.3 - 3.84 avg, to 10.6 max 

Pilot Shale ...................................Upper Dev. - Lower Miss....... ........ 

Carbon Ridge Fm..........................Permian.............................. ........ 

Webb Fm.....................................Mississippian....................... ........ to 6.12 

Woodruff Fm................................Devonian............................. ........ 5.7 avg to 13.9 max 

Slaven Chert.................................Devonian............................. ........ 

Vinini Fm ....................................Ordovician........................... ........ 1 - 25 

Carson Sink..................................Tertiary............................... ........ 0.1 - 3 

c.Thermal maturity The discovery of 12 producing oil and gas fields in Nevada, indicates that 

there are source rocks at depth which have generated hydrocarbons. In 

Railroad Valley, Poole and Claypool (1984) interpret thermally mature 

conditions below 6,800 feet – extending from Eocene Sheep Pass Fm 

downward into the Mississippian Chainman Shale. 

d.Oil or gas prone Most exploration has been along the faulted valley margins. These areas 

have produced primarily oil. No drilling has been attempted to evaluate into 

the deepest parts of these Tertiary Basins, which may be gas prone, because 

of higher temperatures. The oil prone source rocks (Sheep Pass, Chainman 

Shale) may be buried within the dry gas window. Previously generated oil 

may be cracked into gas, creating possible basin-centered accumulations.



Economic 


e.Overall basin maturity Although there are presently 12 producing oil fields in Nevada, the state is 

still a high-risk, under-drilled immature exploration area. 

f.Age and lithologies In the Railroad and White River Valley areas, the most likely exploration 

targets are the Garrett Ranch Volcanics, which produce at Trap Springs 

Field, and the Sheep Pass Fm. (Paleocene – Eocene) which produces at Eagle 


Springs Field. Paleozoic formations which subcrop against the Tertiary 

formations may provide additional reservoirs. 

h.Potential reservoirs Garrett Ranch Volcanics, Sheep Pass Formation 

i.Major traps/seals Traps may be of all types: structural, stratigraphic, or a combination of both. 

For a Basin Centered Gas accumulation, the trap/reservoir may cross 

formation boundaries. 

j.Petroleum 


models 

The Tissot and Welte “Cooking Pot” model, where generated hydrocarbons 

are expelled into surrounding reservoir rocks (Tissot and Welte, 1984). 

k.Depth ranges Depth will vary, because hydrocarbon generation depends on both time and 

temperature. Subsurface temperatures where high will positively influence 

hydrocarbon generation in some areas. Variability of temperature and source 

rock richness will make predicting depth and location difficult. 

l.Pressure gradients Eagle Springs Field has a “normal” pressure gradient of 0.4347 psi/ft (Bortz 

and Murray, 1979) 

a. Important 



a. High inert gas content possible, but unknown 

b.Recovery unknown 

Eagle Springs, Trap Springs, Grant Canyon, and Blackburn Fields. Only 

Grant Canyon Field has no production from a Tertiary reservoir. 

c.Pipeline infrastructure There are no gas pipelines through the Eastern play area. A 16-inch natural 

gas pipeline enters Nevada just east of the Oregon border end runs southwest 

through Winnemucca and then along Interstate Highway I-80, through the 

northern part of the Carson Sink Basin to Reno. The pipeline continues 

through Carson City, then exits Nevada into California. An 8-inch trunk line 

runs east to Elko from Winnemucca, and a second 8-inch trunk line runs east 

east from north of Reno, along Highway US 50 to Frenchman.

d.Overmaturity Overmature source rocks are most likely to be a problem in the deepest parts 

of this play which may require a Paleozoic source rock. For Eagle Springs 

Field, the initial BHT (Bottom Hole Temperature) was 200° F (93° C), at 

6400 feet. The temperature gradient is 20 deg/1000 ft for the depth interval 

6000 – 10,000 ft (Bortz and Murray, 1979). The Carson Sink has a 

geothermal gradient of 25 deg/ 1000 ft (Hastings, 1979). 

e.Basin maturity Immature source rocks may be a problem only in the shallower basins which 

have not achieved deep enough burial to begin generation. 

f.Sediment consolidation Unknown, but poor consolidation has not been a serious problem in wells 

drilled through the Tertiary section. 


problems 

h.Permeability 

Unknown, low porosity and fracture production are expected in this play, 

both of which may cause drilling and completion problems. 

i.Porosity pre-Knox=3.5 to 22% (Innerkip field, Ontario)

120° 118° 116° 114° 

North Black 

Rock Valley 

Humboldt 

River Valley 

Carson Sink 

Smith Creek 

Valley 

Grass Valley 

Black Rock 

Desert Valley 

Buena 

Vista 

Valley 

Dixie Valley 

Reese Valley 

Independence 

Valley 

Pleasant 

Valley 

Big Smoky 

Valley 

Monitor 

Valley 

Little Fish 

Creek Valley 

Little 

Smoky 

Valley 

Railroad 

Valley 

Tickaboo Valley 

North 

Goshute 

Valley 

Figure 1. Map of Nevada showing grabens/valleys of the Basin and Range Province. Derived from Peterson (1988). 

0 

50 mi 

White 

River 

Valley 

Tiptoe 

Valley 

Spring 

Valley 

42° 

41° 

40° 

39° 

38° 

37° 

36° 

35°

Penn 

Mississippian 

Devonian 

Sil 

Ordovician 

Cambrian 

White Pine Range Railroad Valley 

Ely Limestone 1600' 

Dramond Peak Fm 600' 

Chainman Shale 1900' 

Joana Limestone 200' 

Pilot Shale 200' 

Guilmette Formation 1600' 

Simonson Dolomite 900' 

Sevy Dolomite 300' 

Laketown Dolomite 800' 

Fish Haven Dolomite 700' 

Eureka Quartzite 400' 

Pogonip Formation 2200' 

Windfall Formation 2100' 

Dunderberg Shale 450' 

Lincoln Peak Formation 2000' 

Pole Canyon Limestone 675' 

Pioche Shale 300' 

Prospect Mountain 

Quartzite 

Alluvium 

Shale 

Sandstone 

4500' 

Quaternary 

Tertiary 

Penn 

Mississippian 

Devonian 

Figure 2. Stratigraphic columns for White Pine Range and Railroad Valley, eastern Nevada, indicating primary source 

and reservoir units. After Peterson (1988). 

Pleistocene 

Miocene-Pliocene 

Oligocene 

Paleocene 

-Eocene 

Alluvium 

1500' 

Horsecamp Formation 2000' 

Garrett Ranch 

Volcanic Group 

1900' 

Sheep Pass Formation 1000' 

Ely Limestone 900' 

Scotty Wash Quartzite 160' 

Chainman Shale 2000' 

Joana Limestone 400' 

Guilmette Limestone 2000' 

Simonson Dolomite 1000' 

Limestone Volcanic rocks 

Dolomite 

Quartzite 

1900' 

Reservoir 

Source & 

Reservoir 

Source 

Reservoir 

Thickness of strata, 

in feet

Approximate Elevation (feet) 

5000 

Sea 

Level 

-5000 

-10000 

A A' 

Alluvium 

Shale 

Trap Spring Field Eagle Springs Field 

Interbedded shale and 

limestone 

Limestone 

Quartzite 


Paleozoic rocks 

Fault, dashed where 

inferred 

Unconformity 

200° F isotherm 

Volcanic rocks Oil-water contact 

0 2 mi 

Figure 3. Cross section across Railroad Valley, Nevada, showing trap types and possible location of basin-centered 

gas below 200° F isotherm. After Poole and Claypool (1984). 

0.0 

0.5 

1.0 

1.5 

2.0 

2.5 

3.0 

3.5 

Two-way Reflection Time (seconds)

120° 118° 116° 114° 

0 

20 

North Black 

Rock Valley 

20 

0 

0 

20 

20 

Humboldt 

River Valley 

Carson Sink 

Smith Creek 

Valley 

Gravity anomaly 

contour in mGal 

5 mGal gravity anomaly 

0 mGal gravity anomaly 

0 

Dixie Valley 

-5 mGal gravity anomaly 

Grass Valley 

-15 mGal gravity anomaly 

16-inch gas pipeline 

8-inch gas pipeline 

0 

Black Rock 

Desert Valley 

Buena 

Vista 

Valley 

0 

0 

0 

20 

Reese Valley 

Independence 

Valley 

Pleasant 

Valley 

0 

0 

0 

0 

20 

0 

20 

Big Smoky 

Valley 

Monitor 

Valley 

Little Fish 

Creek Valley 

0 

0 

Little 

Smoky 

Valley 

0 

0 

White 

River 

Valley 

A A' 

20 

0 

0 

20 

0 

Railroad 

Valley 

0 

0 

15 

Tickaboo Valley 

North 

Goshute 

Valley 

Figure 4. Gravity minima ("lows") indicating possible thick Tertiary valley fill where gravity low coincides with a 

graben/valley. Map shows locations of cross section A-A' and existing pipelines. After Peterson (1988). 

0 

50 mi 

Tiptoe 

Valley 

20 

0 

Spring 

Valley 

0 

0 

42° 

41° 

40° 

39° 

38° 

37° 

36° 

35°


The Late Cretaceous Austin Chalk was deposited in shallow water on the stable, gently dipping shelf of the 

Gulf Basin. The limits of deposition were from the present outcrop belt to the sharp break of the shelf edge (Figure 

1). The Chalk overlies the shales of the Eagle Ford formation and is unconformably overlain by the Taylor Group 

(Figure 2) The dominant lithology is carbonate skeletal debris with some bands of clay, shale and organic-rich marl. 

The Chalk becomes increasingly shaley basinward and grades into the shales of the underlying Eagle Ford. Thickness 

increases downdip from less than 100 ft near the outcrop to over 650 ft at depths of 9,500 ft. Thickness also varies 

along strike reflecting variations in the shelf. In the Maverick Basin (Rio Grande Embayment), the Chalk exceeds 

1,000 ft thickness, thins at comparable depth across the San Marcos Arch, and thickens again in the East Texas 

Basin. 

Most structure observed in the Chalk reflects an extensional structural style related to opening of the Gulf Basin. 

Locally, structure may be complex, influenced by salt flow, anticlinal growth or drape related to differential 

compaction in underlying sediments. 


The Austin Chalk has yielded oil and gas in both Texas and Louisiana for over 70 years. Development in Texas 

occurs in a 30 mile wide band that stretches from the Rio Grande in south Texas to the Louisiana state line. Until 

recently, production in Louisiana was incidental to deeper exploration. 

Austin Chalk production in Louisiana had been limited to the central part of the state and was incidental to 

deeper exploration. The successful application of horizontal drilling at Brookeland field in Sabine County, east 

Texas, led to the first successful drilling for the Chalk in western Louisiana. At the same time, operators in existing 

fields of Avoyelles Parish began to apply horizontal drilling to exploit Austin Chalk reserves. 

The Chalk in Louisiana generally produces from greater depths than in Texas. At Moncrief and North Bayou 

Jack fields, the Chalk produces high-GOR oil (oil ranging from 39° to 42.7° API gravity) from depths of about 

14,500 ft. Farther west at Masters Creek field, the Chalk produces condensate and gas from 14,800 ft. These depths 

yield dry gas at Giddings. This change in hydrocarbon charge may be related to a southeast to northwest shift in 

geothermal gradient (Pollastro, 1999, personal communication). Work on the geographic distribution of geothermal 

gradients in the Chalk remains incomplete, but will add substantially to understanding hydrocarbon generation 

beyond the models proposed in the Texas fairway. 

The Chalk produces from intraformational fractures. Consequently, most of the production is associated with 

known fault zones or other structural features responsible for fracture development (Stapp, 1977). Locally, high fluid 

pore pressure may have contributed to fracturing (Corbett et al., 1987). Gas expansion is the principal driving 

mechanism in the reservoirs. Gas to oil ratios generally show an inverse relationship to structural position; that is, 

gas rich reservoirs tend to be structurally lower while oil rich reservoirs are shallower. This reflects increased 

generation of gas at greater depth (Figure 3) Reservoirs are directly related to the amount of fracturing; this prevents 

extensive migration and most hydrocarbons stay near the depths at which they were generated. Thin bentonite or 

shale beds limit vertical fracture growth. Different horizons are productive in different geographical areas. Upper 

benches of the Chalk are productive at Pearsall field in the western area; the lowermost Bench is the pay at the 

Giddings Area. Farther east at Brookeland field and in Louisiana, the clay/shale interbeds are absent and the Chalk 

may be fractured for its entire height. The source for Austin Chalk reservoirs may be the underlying Eagle Ford 

shales or by carbonaceous beds within the Chalk itself (Stapp, 1977; Grabowski, 1981, 1984; Ewing, 1983; Hinds 

and Berg, 1990). 

Fracture production is characterized by high initial rates of production as open fracture systems are drained. 

Production declines are very rapid and are followed by extended periods of low volume production, as microfractures 

and/or matrix permeability produce fluid to the open fractures penetrated by the wellbore. 

1


The discovery of dry (non-associated) gas at the Giddings Deep field in Texas is of particular importance for 

exploration for other dry gas accumulations in the Austin Chalk. The Austin Chalk has generally been regarded as an 

oil play and certainly the drilling cycles of the 1970s and 1990s were driven by higher oil prices as well as technical 

advances. With an abundance of conventional and non-conventional gas plays in Texas, there has been little incentive 

for operators to drill the deeper, increasingly shaley Chalk in search of gas reserves, especially since the chalk was 

assumed to shale out at depths suitable for gas generation. Gas/oil ratios are relatively constant within most fields 

but at Giddings are known to increase about 10 fold across the field. Deep drilling was a deliberate effort to establish 

gas reserves. The deeper drilling also identified chalk lithology at greater depths than had previously been expected 

(Pollastro, 1999, personal communication). 

The Austin Chalk apparently can produce commercial gas at Giddings field in Texas. Local drilling at Giddings 

has extended the Chalk play downdip past its previously assumed limits. The extension of Chalk exploration into 

Louisiana has identified areas of gas and condensate production. Areas including east Texas, and western and southern 

Louisiana may be the best area for future gas development. Potential exists for westward extension of the play 

downdip of the oil producing trend. The presence of clean chalk beyond its currently assumed limits at the Cretaceous 

shelf edge will be a determining factor. Also necessary are fracturing mechanisms to produce reservoirs. The presence 

of source beds within the Chalk and the underlying Eagle Ford shale insure gas generation at sufficient depth and 

temperature. Salt flow, regional dip change, and faulting associated with flexure of the Cretaceous shelf edge could 

all contribute to fracture development. 

1) The Austin Chalk and the underlying Eagle Ford shale are sufficiently mature for gas and gas-condensate 

generation throughout the known extent of the play. The Chalk appears to be gas-prone at shallower depths 

in the western portion of the play in Texas. 

2) Clean, brittle chalk suitable for fracturing is present at depths of gas generation in east Texas and eastward 

into Louisiana. The downdip limits at which the chalk grades to shale in this area are not yet fully 

established. 

3) Fractures within the Chalk constitute the reservoir; therefore, reservoirs become limited to areas of 

fracturing. In this respect the Austin Chalk differs from a typical continuous gas accumulation. Although 

gas may be present in the chalk matrix, fracture permeability is necessary for production. Thus, the extent 

of fracturing will restrict formation of gas-producing reservoirs. Salt flow, faulting, differential compaction, 

and other structural or stratigraphic events can create fracturing throughout the known extent of the play. 

Fracture trends may be identified regionally, but fracturing suitable for reservoir development will be limited 

locally. 

4) Temperatures in the deep Chalk play reach 350 °F at Giddings field in Texas. The geothermal gradient 

apparently changes in Louisiana from northwest to southeast and appears to match the shift from gas-prone 

reservoirs to high-GOR oil reservoirs. The nature and extent of this change is not understood. A better 

understanding of this phenomenon might help identify gas-prone Austin Chalk in the eastern part of the 

play. 

5) The only significant water production in the deep Chalk play is at Masters Creek field in Louisiana, where 

the Chalk is in fracture communication with the underlying geopressured Eagle Ford Formation. 

2



Geologic 


Accumulation: 


West Gulf Coast, Texas and Louisiana, Deep Austin Chalk (Cretaceous) 

a. Source/reservoir underlying Eagle Ford shale and self-sourced from interbedded organic 

material (Grabowski, 1981, 1984; Stapp, 1977); intraformational fractures 

are the reservoir (Stapp, 1977; Corbett et al., 1987) 


(TOCs) 

Eagle Ford = 1.5-8% (Montgomery, 1990); Austin Chalk = 0.3-2.5% 

(Grabowski, 1981) 

c.Thermal maturity thermal alteration index ranges from 1+, 2 at 2000 ft to 3-, 3 at 9000 ft. 

Ratios of Extractable Organic Matter (EOM) to Total Organic Content 

(TOC) range from less than 10% in the immature zone to 45% in the oil 

generation zone. Ratios decrease with greater depth reflecting the expulsion 

of generated hydrocarbons (Grabowski, 1981, 1984; Ewing, 1983; Hinds and 

Berg, 1990). Temperature gradient changes from south-central Louisiana to 

the Louisiana - Texas state line suggest lower temperatures to east and higher 

temperatures to west (Pollastro, 1999, personal communication) 

d.Oil or gas prone oil and gas productive from south Texas to central Louisiana; non-associated 

gas produced in the deep Giddings area below 10,000 ft. 

e.Overall basin maturity Gulf Coast Basin normally mature regionally 

f.Age and lithologies Late Cretaceous, coccolith- and formanifera-rich chalk with thin interbedded 

shales and bentonites 

g. Rock extent/quality extends from Maverick Basin of south Texas to central Louisiana; rock 

quality varies locally from east to west, but chalk grades to shale basinward 

(Stapp, 1977; Montgomery 1995) 


i.Major traps/seals interbedded shale and bentonite beds terminate vertical fracture 

development; fracture development occurs in areas of extensional or 

halokinetic (salt flow) faulting, or structural drape over underlying sediments 

j.Petroleum 


models 

thermogenic generation related to depth of burial (Ewing, 1983; Hinds and 

Berg, 1990; Grabowski, 1981, 1984); limited migration due to fracture 

compartmentalization 

k.Depth ranges oil and gas productive at depths of 6000 ft to 14,000; dry gas productive at 

10,000 to 14,000+ ft at Giddings field 




Economic 


a. Important 


Giddings, Giddings Deep, Pearsall, Masters Creek, Brookeland, Moncrief 

b.Cumulative production Giddings (all)--2.8 TCFG, 414,800,000 BO; Pearsall--92 BCFG, 

142,000,000 BO; Masters Creek 17 BCFG, 4,630,000 BO; Moncrief 5.4 

BCFG, 447,000 BO 

a. High inert gas content up to 6.5% CO2 and unspecified amount of H2S at Giddings Deep (Moritis, 

1995) 

b.Recovery highly variable recoveries typical of fractured reservoirs 

c.Pipeline infrastructure good to excellent for most of play; fair in west-central Louisiana 

d.Overmaturity uncertain due to lack of deeper drilling in the Giddings Deep area 

e.Basin maturity the Chalk itself is generally immature above 6000 ft; the underlying Eagle 

Ford is also immature at shallower depths 

f.Sediment consolidation consolidation/porosity reduction occur with depth of burial 


problems 


i.Porosity 

high temperatures (350°)at Giddings Deep, require special mud systems and 

“hostile environment” downhole tools. Plugging of the fracture systems by 

drilling mud is a particular problem in Louisiana. Unlined laterals are more 

likely to collapse at the gas prone depths, (>10,000 ft) than in the shallower 

(6000-9000 ft) oil play. The underlying Eagle Ford shales are known to be 

geopressured in portions of the Louisiana play; fracture communication with 

the geopressured zones creates drilling hazards and increases water 

production. Greater weight of overburden may result in more rapid closure 

of fractures with withdrawal of fluid.

33° 

31° 

29° 

27° 

100° 

Austin Chalk 

Outcrop Belt 

Pearsall 

98° 96° 94° 92° 90° 88° 

Area of horizontal drilling 

Petroleum field 

Giddings 

Brookeland 

Kurten 

Burr Ferry 

Masters 

Creek 

Approximate Position 

of Cretaceous Shelf Edge 

North 

Hadden 

North 

Bayou 

Jack 

Moncrief 

0 50 100 mi 

Figure 1. Regional map showing productive trend of horizontal drilling in the Austin Chalk, Texas and Louisiana. 

Scale

Stage 

Danian Tertiary 

Maastrichtian 

Campanian 

Santonian 

Coniacian 

Turonian 

Cenomanian 

Albian 

Aptian 

Barremian 

Hauterivian 

Valanginian 

Berriasian 

Tithonian 

Kimmeridgian 

Oxfordian 

Callovian 

Bathonian 

Neocomian 

Upper 

Middle Upper 

Lower 

Period 

Cretaceous 

Jurassic 

Gulf 

Coast 

Usage 

Upper 

Middle 

Lower 

Gulfian 

Comanchean 

Coahuilan 

Circum- 

Gulf 

Mid-Cret. 

("MCU") 

Top Salt 

Base Salt 

Regional 

Seismic 

Reflectors 

East 

Texas 

Navarro 

Austin 

Buda 

James 

Top Salt 

Base Salt 

East Texas and West Louisiana 

N S 

Midway 

Navarro 

Austin 

Eagleford 

Woodbine 

Washita 

Fredericksburg 

Trinity 

Taylor 

Hosston 

Knowles 

Cotton Valley 

Gilmer 

Buckner 

Smackover 

Norphet 

Louann 

Georgetown 

Figure 2. Stratigraphic column and cross section for East Texas and Western Louisiana. After Winker and Bufler (1988). 

Kiamichi 

Edwards 

Paluxy 

Glen 

Rose 

Ferry 

Lake 

Pearsall 

Lower 

Glen 

Rose 

Shelf Margin 

Upper 

Glen Rose 

Sligo 

Stuart City 

Shelf 

Margin 

Bossier 

Sligo 

Shelf 

Margin 

Tuscaloosa 

Clastic wedge 

(mostly shale)

NW SE 

Outcrop 

Balcones 

Fault Zone 

Updip Fields 

(Luling, Salt Flat, etc.) 

Luling 

Fault Zone 

Austin 

Chalk 

Mexia-Fashing 

Fault Zone 

Midtrend-Giddings 

Immature 

Mature 

Shelf 

Margin 

Reef 

6000 ft 

9000 ft 

NW SE 

Outcrop 

Balcones 

Fault Zone 

Fractures 

(fault-related) 

Microfractures 

Oil well 

Pearsall Field 

Charlotte 

Fault Zone 

Well with oil 

or gas shows 

Gas well Dry well 

Gas 

Immature 

Mature 

Gas 

Shelf 

Margin 

Reef 

6000 ft 

9000 ft 

0 10 mi 

Figure 3. Generalized cross sections showing down-dip progression of hydrocarbon maturity levels and trap types in 

the Austin Chalk of southern Texas. After Ewing (1983).


The Eagle Ford Formation was deposited on the gently sloping shelf of the Gulf Coast. The formation 

unconformably overlies the Woodbine Group, which includes the Woodbine sands of east Texas and southwest 

Louisiana, the Tuscaloosa sands of central Louisiana, and the Buda limestone of Texas. The Austin Chalk 

unconformably overlies the Eagle Ford (Figure 1). The lower Eagle Ford is a transgressive unit composed of dark 

shales, while the upper unit is a highstand/regressive facies with thin limestones, shales, siltstones, and bentonites, 

and thin dolomites locally (Dawson et al., 1993; Stapp, 1977). Regionally, the formation ranges in thickness from a 

feather edge in Arkansas to 100-150 ft across much of Texas and Louisiana. In response to underlying structure, the 

formation thickens to 300 to 400 ft in the South Louisiana Salt Basin. Maximum thickness is about 800 ft in the 

East Texas Basin. Deposition occurred from the current outcrop band downdip to beyond the Cretaceous shelf margin 

(Figure 2). Dark shales in the upper Eagle Ford are absent in parts of east Texas, with the Austin Chalk overlying 

fine grained clastics mapped as Woodbine. Montgomery (1995) suggests this “missing” Eagle Ford may be due to 

changes in local terminology, but also states that the literature does not formally recognize this distinction. 

Structure in the Eagle Ford generally reflects down to the basin extensional faulting, but locally, salt flow, 

anticlinal growth, or differential compaction in the underlying Woodbine/Tuscaloosa may also influence structure . 


Production from the Eagle Ford is difficult to verify. Stapp (1977) noted completions of oil wells in the 

formation in Frio County, Texas (presumably in the Pearsall field area), but since these were in conjunction with 

Austin and/or Buda completions, there are no separate records of Eagle Ford production. Stapp further stated that the 

formation itself could not be considered a primary target because of its thinness and lack of permeability. More 

recently, Dawson (1997) found that low matrix permeabilities and low volumetric parameters of the formation 

preclude reservoir potential. The ductility of the shale interval hinders development of fractured reservoirs found in 

the more brittle overlying Austin Chalk and underlying Buda limestones, although carbonate and siliclastic beds in 

the upper interval may fracture. 

Values of total organic content (TOC) in the Eagle Ford range from 1.0 to almost 10.0 %wt and thus suggest a 

high quality source rock. Formation samples yield total hydrocarbon generation potential (THGP) values from about 

1 to over 50 mg HC/g rock. Plots of Hydrogen Index versus Oxygen Index suggest the Eagle Ford contains both 

type II and type III kerogens and is prone to both oil and gas generation (Robison, 1997). Maturation studies on 

Eagle Ford samples indicate onset of hydrocarbon generation at 7,500 ft original depth (Noble et al., 1997), 

matching the variation in maturity from deeper oil-prone Louisiana fields to shallower gas-prone fields in Texas. 

This generation depth corresponds to the results of maturation studies in the Austin Chalk (Grabowski, 1984; 

Ewing, 1983; Hinds and Berg, 1990 (Figure 3). 

EVIDENCE OF BASIN-CENTERED GAS 

The lack of verifiable production history and reported lack of reservoir make the Eagle Ford a poor candidate for 

significant gas accumulations. The similarity to maturity in the Austin Chalk allows extrapolation from Austin or 

Tuscaloosa gas production to likely areas and depths of gas generation in the Eagle Ford. As a regionally extensive 

organic rich source rock, the Eagle Ford could generate gas over a large area downdip from the traditional Austin 

Chalk oil trend and in the vicinity of deep dry-gas and gas-condensate production in the Giddings area of Texas and 

southwest Louisiana. Production of such gas will require the development of fracture reservoirs in the Chalk or the 

underlying Buda formation. The Woodbine sands of eastern Texas grade basinward to shale; the Tuscaloosa sands of 

southern Louisiana probably grade likewise. The Tuscaloosa-Eagle Ford transition occurs at depths greater than 

18,000 ft, a depth suitable for gas generation. The migration of such gas to conventional reservoirs would require 

faulting or fracturing (Montgomery, 1995). A widespread accumulation of gas in tight, silty Tuscaloosa sands in the 

transition zone is possible but speculative. Any such accumulation would be within the area of geopressuring in the 

Tuscaloosa, which would create drilling and completion problems. 

1



Geologic 


Accumulation: 


West Gulf Coast, Texas and Louisiana, Eagle Ford Shale (Cretaceous) 

a. Source/reservoir Eagle Ford shale is self-sourced (Noble et al., 1997; Robison, 1997; Stapp, 

1977); reservoir not developed (Stapp, 1977; Dawson, 1997) 


(TOCs) 

c.Thermal maturity 

Eagle Ford = 1.0 to almost 10% (Robison, 1997) 

d.Oil or gas prone oil and gas prone based on kerogen types (Robison, 1997) 

e.Overall basin maturity Gulf Coast Basin normally mature regionally 

f.Age and lithologies Late Cretaceous, lower section dominated by dark shales, upper section 

includes thin limestones, dolomites and bentonites in addition to shale 

(Stapp, 1977; Dawson, 1997) 

g. Rock extent/quality regionally extensive shale (see Figure 2); poor reservoir quality 


i.Major traps/seals 

j.Petroleum 


models 

Thermogenic generation related to depth of burial (Ewing, 1983; Hinds and 

Berg, 1990; Grabowski, 1981, 1984; Noble et al., 1997); migration by faults 

and fractures to Austin Chalk and Buda Lime, lateral migration to 

Woodbine sands (Stapp, 1977; Ewing, 1983; Wescott and Hood, 1993) 

k.Depth ranges oil and gas generative at current depths of 6000 ft to 14,000 ft 




Economic 


a. Important 




b. Recovery 


d. Overmaturity 




problems 


i. Porosity 

Not applicable 

Not applicable; source rock only

33° 

31° 

29° 

27° 

100° 

Pearsall 

Area of "missing" Eagle Ford 

Giddings 

Austin Chalk Productive 

Trend 


98° 96° 94° 92° 90° 88° 

Probable area of gas 

generation in Eagle Ford 

Approximate position 

of Cretaceous shelf edge 

Masters 

Creek 

Area of "missing" 

Eagle Ford 

Figure 1. Regional map showing gas generation from Eagle Ford Formation, Texas and Louisiana. 

North 

Bayou 

Jack 

Moncrief 

0 50 100 mi 

Scale

System Series Stage Central Texas 

Cretaceous 

Upper 

Maastrichtian 

Campanian 

Santonian 

Coniacian 

Turonian 

Cenomanian 

Escondido 

Olmos 

San Miguel 

Anscacho 

Upson 

Chalk interval Eagle Ford Formation 

Washita 

East Texas 

Basin 

Navarro Navarro 

Taylor 

Taylor 

Austin Chalk Austin Chalk 

Eagle Ford Eagle Ford 

Southeast Texas 

SW Louisiana 

Navarro 

Taylor 

Austin Chalk 

South Louisiana 

and Offshore 

Austin Chalk 

Navarro 

Taylor 

Ector 

Eagle Ford Eagle Ford 

Woodbine 

Woodbine Woodbine Tuscaloosa 

Buds Buds Buds Buds 

Del Rio Del Rio - Grayson 

Washita 

Grayson 

Figure 2. Stratigraphic column and correlation in the Upper Cretaceous interval, U. S. Gulf Coast. After Salvador and Muneton (1989). 

Washita 

Grayson 

Selma

NW SE 

Outcrop 

Balcones 

Fault Zone 

Fractures 

(fault-related) 

Microfractures 

Updip Fields 

(Luling, Salt Flat, etc.) 

Luling 

Fault Zone 

Midtrend-Giddings 

Austin Chalk Shelf 

Oil well 

Eagle 

Ford 

Mexia-Fashing 

Fault Zone 

Well with oil 

or gas shows 

Gas well Dry well 

Immature 

Figure 3. Generalized cross section showing down-dip progression of hydrocarbon maturity levels and trap types in the Eagle Ford Formation of southern 

Texas. After Ewing (1983). 

Mature 

Gas 

Margin 

Reef 

6000 ft 

9000 ft 

0 10 mi


The Lower Cretaceous Travis Peak Formation and Upper Jurassic Cotton Valley Group contain FERCdesignated 

tight gas sands that were widely deposited across eastern Texas, northern Louisiana and into the 

Mississippi Salt Basin (Figure 1). The lower part of the Cotton Valley also contains both reef-forming 

carbonates and oolitic shoals. Sandstone distribution in the Cotton Valley generally is more consistent than 

that in the Travis Peak. 

In east Texas, Travis Peak deposition occurred in a fluvial-deltaic environment that prograded from the 

northwest (Bushaw, 1968; Saucier, 1985; and Tye, 1989). Underlying Cotton Valley sands may be barrierisland 

type deposits. Interpretations of stratigraphic sequence have defined a number of depositional subenvironments 

(Figure 2) in east Texas and western Louisiana that consist of: 

1 

1. a braided to meandering fluvial system; 

2. interbedded deltaic/fluvial deposits–fluvial deposits distally become encased in deltaic rocks; 

3. paralic deposits that interfinger with the above two systems near the top of the Travis Peak; and 

4. shelf deposits near the downdip edge of the Travis Peak; these sediments interfinger with and onlap 

deltaic and paralic deposits (Dutton et al., 1993). 

Thickness of the Travis Peak Formation ranges from 500 to 2,500 ft, and generally increases to the 

southeast (Figure 2). The upper 200 ft of the formation holds the most potential for basin-centered gas 

development. Most productive intervals occur at depths of 3,100 to 10,900 ft. Cotton Valley low 

permeability sands range in thickness from 1,000 to 1,400 ft thick and occur at depths of 5,000 to 11,000 

ft; Schenk and Vigers (1996) suggest that Cotton Valley reservoirs may extend to depths as much as 20,000 

ft. Reservoir continuity is often interrupted by small-scale sedimentary disturbances that include bedforms, 

biogenic features, clay drapes, and scour surfaces (Gas Research Institute, 1991). 

Recent activity targeting the Cotton Valley involves the development of a pinnacle reef play since 

1980. This play is developing along the western shelf of the East Texas basin (Montgomery, 1996) and 

may extend into the Sabine Platform trend into Louisiana (Figure 1). Reef development appears to coincide 

with localized salt-tectonic positive features that provided a shoaling environment. These carbonate buildups 

ranged in thickness from 200 to 400 feet more than the surrounding interreef sediments and had an areal 

extent of 200 to 800 acres (Montgomery, 1996). 

Growth faulting throughout the area of the Cotton Valley and Travis Peak trends may play an 

important part in the upward migration of hydrocarbons. Jurassic rocks contain the greatest number of 

faults, probably related to salt tectonism (Montgomery, 1996). Salt structure formation provided shoaling 

environments for deposition of oolites and other high energy sediments. From the Jurassic to the Tertiary, 

salt tectonism generated local fracturing that enhanced reservoir permeability (Coleman and Coleman, 1981; 

Saucier, 1984). 

The East Texas and North Louisiana salt basins may have formed by graben development that resulted 

from continental rifting and the opening of the Gulf of Mexico basin (Figure 1). These grabens are bounded 

by down-to-the-basin faults, which include the Mexia-Talco and the South Arkansas fault zones (Kehle, 

1971; Wood and Walper, 1974; and Finley, 1986). Other dominant structural features in the play area 

include the Sabine uplift and the Monroe uplift in northeastern Louisiana. Development of the Sabine uplift 

is speculative; however, evidence points to a compressional origin (Jackson and Laubach, 1988).


As of 1993, 860 wells were completed within the Travis Peak Formation. Cumulative production from 

1970 to 1988 amounted to 508-plus BCFG, with an estimated ultimate recovery of 1,269 BCFG. Average 

recoveries per well varied from 1.8 BCFG in East Texas to 1.4 BCFG in North Louisiana. Initial 

production rates increased from 0 to 765 MCFGPD prior to stimulation to 500 to 1500 MCFGPD after 

fracturing. Production rates declined up to 65% in the first 1 to 2 years. Dutton et al. (1993) estimated the 

resource base to be 6.4 TCFG. 

Cotton Valley wells totaled 2,870 "tight completions" as of 1993. Cumulative production was 2,665.5 

BCFG, with an estimated ultimate recovery of 4,999 BCFG. Average recoveries per well varied from 1.8 

BCFG in East Texas to 2.4 BCFG in North Louisiana. Initial production rates increased from 50 MCFGPD 

prior to stimulation to 500 to 1,500 MCFGPD after fracturing. Decline rates were somewhat less than 

those of the Travis Peak, with an estimated 46% decline in the first 1 to 2 years of production. The rate of 

water production decreased to a 50 barrel per day average in the same time period. The presence of a 

gas/water contact in any part of the play remains unknown. Cluff (1999) believes multiple gas/water 

contacts exist. Dutton et al. (1993) estimated the resource base for Cotton Valley tight reservoirs to be 24.2 

TCFG. 

The early stages of development of the Cotton Valley play included easily identifiable "blanket"-type 

sands originating from well-developed strands, barrier islands, and tidal bars. Finley (1986) noted a newer, 

tight-gas sandstone play located generally downdip from the more permeable sands noted above. Distal to 

proximal delta-front deposits dominate this hypothetical play, which may extend from northwestern 

Louisiana into the eastern and central parts of the East Texas basin. 


Widespread production , gas shows, and the occurrence of overpressuring and underpressuring indicate a 

potential for basin-centered gas accumulations. Most Travis Peak and Cotton Valley fields are 

overpressured, but some data indicates underpressuring in the Cotton Valley interval of the Oak Hill field, 

and in the Travis Peak lower zone of the Waskom field; the Cotton Valley limestone at Teague field reaches 

a pressure gradient of 0.66 psi per ft (Kosters et al., 1989). Pressure gradients are highest in the underlying 

Cotton Valley carbonates. Pressure gradients appear slightly higher in Cotton Valley sandstone reservoirs 

than in Travis Peak sandstone reservoirs. This may result from their proximity to source rocks, with some 

leakage from the Travis Peak. Pressure communication between the Travis Peak and Cotton Valley 

reservoirs may exist in East Texas. 

In-situ generation of hydrocarbons does not appear likely for Travis Peak reservoirs. Thermal maturity 

data indicates that Travis Peak strata are well within the "oil window" (Ro values range from 1.0 to 1.8%); 

however, TOC values for interbedded Travis Peak shales generally are less than 0.5% (Dutton et al., 1993). 

Cotton Valley strata have a higher likelihood for in-situ hydrocarbon generation. Beneath the Cotton 

Valley sands is the Bossier shale (Figure 3). Montgomery (1996) calls the Bossier "a dark, somewhat 

organic-rich interval," and local thickness changes of 400 feet occur on the western shelf of the East Texas 

basin (Forgotson and Forgotson, 1976; Montgomery, 1996). The Bossier may have generated and expelled 

hydrocarbons in Late Cretaceous time (Wescott and Hood, 1991; and Montgomery, 1996). Schenk and 

Viger (1996) believe some sources of hydrocarbons for this play may have originated in mudstones in the 

lower part of the underlying Jurassic Smackover Formation (Figure 3). 

2



Geologic 


Accumulation: 


Eastern U.S. Appalachian basin, (New York, Pennsylvania and Ohio). Play: 

Paleozoic Era - Late Cambrian and Ordovician sandstones and shales; Lower 

Silurian "Clinton" and Medina Group sandstones, and the equivalent 


a. Source/reservoir Source rocks include: Bossier shale (Upper Jurassic Cotton Valley group), 

and mudstones and carbonates of the Upper Jurassic Smackover formation. 

Reservoir rocks include: Sandstones and carbonates of the Upper Jurassic 


(TOCs) 

Cotton Valley group and Lower Cretaceous Travis Peak formation. 

values for the interbedded Travis Peak shales range to less than 0.5%; 

content of the underlying Jurassic Bossier shale and Smackover shales and 

carbonates is unavailable. 

c.Thermal maturity Ro 1.0 – 1.8% (values from Travis Peak interbedded shales) 

d.Oil or gas prone both oil and gas prone; however, source rocks referred to are specifically 

noted by Wescott and Hood (1991) to have generated oil. 

e.Overall basin maturity maturation levels are moderate 

f.Age and lithologies Upper Jurassic to Lower Cretaceous sandstones 

g. Rock extent/quality apparent basin-wide source (Jurassic only) and reservoir rock 

distribution,;rocks are highly variable in reservoir quality because of quartz 

overgrowths and calcite cement, and minor amounts of clay and dolomite 

h.Potential reservoirs many producing reservoirs 

i.Major traps/seals carbonates and evaporites of the overlying Sligo and Pettet formations and 

mudstones within the Travis Peak 

j.Petroleum 


models 

little chance of in-situ generation within the Travis Peak; however, Cotton 

Valley reservoirs may be self-sourced as in Weimer’s Denver basin "cooking 

pot" model (Weimer, 1996). Migration of gases along fracture and fault 

systems from the Upper Jurassic into Travis Peak reservoirs probably occurs, 

but may not be necessary if the Bossier shale generated sufficient 

hydrocarbons to charge both the Cotton Valley sands and Travis Peak sands, 

provided the two units are in pressure communication with one another. 

k.Depth ranges Travis Peak reservoirs range from 3100 to 10,900 ft; potential reservoir 

depths may exceed 15,000 ft. Cotton Valley reservoirs range from 5,000 to 

11,000 ft and may go as deep as 20,000 ft. 

l.Pressure gradients Travis Peak - 0.38 to 0.52 psi/foot; Cotton Valley sands - 0.32 to 0.55 psi/ft; 

Cotton Valley carbonate (oolitic shoal reservoirs) - 0.50 to 0.66 psi/ft.



Economic 


a. Important 


Bethany (Travis Peak), Carthage (Travis Peak, Cotton Valley), Waskom 

(Travis Peak, Cotton Valley), Trawick (Travis Peak), Opelinka (Travis Peak, 

Rosewood (Cotton Valley), Henderson North (Travis Peak, Cotton Valley), 

Blocker (Cotton Valley). 

b. Cumulative production Travis Peak - 508.3 BCFG (1970-1988); Cotton Valley - 2,665.5 BCFG 

(1970-1988) 


b. Recovery Recoveries vary depending on permeability (degree of cementation and 

fracturing), and porosity. 

c. Pipeline infrastructure very good. 

d. Overmaturity possibly overmature in the deepest parts of the basins 

e. Basin maturity Most of the basin is mature (Ro values for the Travis Peak range from 1.0 to 

1.8%) 



problems 

iron oxide precipitates common in some Cotton Valley sandstone reservoirs, 

calcite and silica cementation restrict porosity, minor clay problems 

h. Permeability Travis Peak - 0.0004 to 0.8 md; Cotton Valley - 0.015 to 0.043 md 

i. Porosity Travis Peak - 5-17%; Cotton Valley - 6 to 11%

97° 

34° 

33° 

32° 

31° 

30° 

29° 

A 

A' 

96° 95° 94° 93° 92° 91° 90° 89° 

Mexia-Talco Fault Zone 

Potential Basin-centered gas Trend 

Area of uplift 

Anticline 

Ginger Fault Zone 

East Texas 

Salt Basin 

Rodessa Fault 

Mt. Enterprise Fault Zone 

Sabine 

Arch 

Sou t h Arkansas Fault Zone 

Comanchean Shelf Edge 

Texas Louisiana 

Normal fault; hachures 

on downthrown side 

Basin-centered gas trend 

North Louisiana Fault Zone 

North Louisiana 

Salt Basin 

Arkansas 

Monroe 

Uplift 

Pickens Fault Zon e 

Mississippi 

Salt Basin 

Mississippi 

0 50 mi 

Figure 1. Regional tectonic map of the central Gulf coastal province showing potential basin-centered gas trend. Location of cross section A-A' is 

approximate. After Gulf Coast Association of Geologic Societies (1972) and Dutton et al. (1993).

A A' 

North Hopkins 

Wood 

South 

Feet 

7000 

1000 

500 

0 

0 

Miles 

Braided-stream fluvial facies: 

very fine- to fine-grained sandstone and fineto 

medium-grained conglomerate sandstone 

? 

? 

Delta-front facies: 

interbedded very fine to fine-grained sandstone, 

siltstone, and mudstone 

Pro-delta facies: 

mudstone containing thin beds of very finegrained 

sandstone, siltstone, and limestone 

5 

8000 

10000 

8000 

10000 

Limestone 

10000 

Shallow-shelf and shallow-shelf transitional facies: 

interbedded very fine to fine-grained fossiliferous 

sandstone, siltstone, mudstone, and limestone 

10000 

10000 

10000 

10000 

10000 

Pettet Formation 

Hosston Formation 

(Travis Peak Formation) 

Cotton Valley Group 

Delta-front facies 

Pro-delta facies 

Gilmer Limestone 

Buckner Formation 

Smackover Formation 

Figure 2. North-south dip-oriented cross section showing Travis Peak and Cotton Valley sandstone facies in East Texas Basin, Hopkins and Wood Counties, 

Texas. After McGowen and Harris (1984), and Kosters et al. (1989).

System 

Cretaceous 

Jurassic Upper 

Series Group Formation 

Coahuilan Nuevo Leon 

Cotton Valley 

Louark 

Sligo/Pettet 

Travis Peak/Hosston 

Cotton Valley Sandstone 

(Upper Cotton Valley/Schuler) 

Bossier Shale 

Cotton Valley Limestone 

(Gilmer/Haynesville) 

Buckner 

Smackover 

Figure 3. Stratigraphic column of parts of the Jurassic and Cretaceous systems in east Texas and northern Louisiana. 

After Finley (1986).


The Hanna Basin is an intermontane basin in the Rocky Mountain foreland province in southeast Wyoming 

(Figure 1). The basin covers about 1,000 square miles and contains almost 38,000 ft of Cretaceous and Tertiary 

sediments (Figure 2). At least 18,000 ft of Late Cretaceous and early Tertiary sediments were deposited within 15 

my, creating thermally mature hydrocarbon source rocks in the basin center (Beirei, 1986, 1987). The Upper 

Cretaceous Medicine Bow, Lewis and Mesaverde Formations consist of up to 15,000 ft of dark marine organic-rich 

shales (Figure 3). The Eocene-Paleocene Hanna and Ferris Formations include almost 14,000 ft of organically rich 

lacustrine shales, coals and fluviatile sandstones (Perry, 1992; Beirei, 1987; Matson, 1984). This excessive 

sedimentation resulted from abrupt basin subsidence associated with Laramide tectonism (Lillegraven, 1995; Beirei 

and Surdham, 1986; Shelton, 1968). The basin is asymmetric and is surrounded by numerous Laramide thrust faults 

(Figures 1 and 2). 

The high subsidence rates that occurred in the Hanna basin are typical of wrench basins with strike-slip faulting 

(Perry, 1992). 


The Hanna basin has several fields that produce both oil and gas (Kaplan and Skeen, 1985; Matson, 1984; 

Porter, 1979; McCaslin, 1978) (Figure 3). Table 1 lists the cumulative production for various fields. To date, natural 

gas has been found only in sandstone reservoirs (Mitchell, 1968). The nonmarine rocks are currently being explored 

for coal and coal gas (Perry, 1992). There is no current production of coal gas in the basin. 


Sparse exploratory drilling and lack of data make comparisons difficult. The Hanna basin has similar rock 

sequences to the Greater Green River basin, where Law and others (1984; 1989) have described basin-center gas 

systems. Pontolillo and Stanton (1994) measured vitrinite reflectance values greater than 1% below 11,000 ft in the 

Champlin and Brinkerhoff wells; these values exceed the 0.8% threshold that generally indicates the top of abnormal 

pressures and possible thermogenic gas generation (Johnson and Finn, 1998; Law, 1984) (Figure 4). 

Late Cretaceous marine rocks in the basin show total organic carbon (TOCs) values greater than 0.5%. The 

Hanna, Ferris, Medicine Bow, and Mesaverde Formations have coal beds and carbonaceous shales with variable TOC 

values (0.5 to 35.6 wt% avg, 3.2 wt% TOC). Marine sediments of the Lewis, Steele, Niobrara, and Frontier 

Formations have TOC range of 0.4 to 4.3 and average of 1.5 wt% TOC (Beirei, 1987). 

Most of the known traps are structural closures around the edges of the basin (Matson, 1984). Several 

structural/stratigraphic traps are also present (Porter, 1979, McCaslin, 1978). Stratigraphic traps may occur in the 

deeper part of the basin, in low permeability and possibly overpressured Eocene, Paleocene and Upper Cretaceous 

rocks (Matson, 1984). Major seals include the black/dark shales of the Cretaceous Mowry, Steele, Thermopolis, and 

Mesaverde Formations, and Paleocene and Eocene rocks. 

Time-temperature calculations locate the oil generation window (O.G.W.) at 7,200 to 11,480 ft depth in the 

basin center. Apparently, hydrocarbon generation began about 80 Ma at the base of the Late Cretaceous section in 

the Hanna basin. Transformation models show that source rocks generated and expelled hydrocarbons very quickly. 

At present, the Hanna basin is not generating any significant amounts of hydrocarbons. 

1



Geologic 


Accumulation: 


Rocky Mountain Foreland Province; Upper Cretaceous and Paleocene Ferris 

and Hanna Formations 

a. Source/reservoir At least 5.5 km (18,000 ft) of Late Cretaceous and early Tertiary sediments 

were deposited within 15 m.y., creating thermally mature hydrocarbon 

source rocks in the basin center (Beirei and Surdham, 1986; Beirei, 1987). 

The 

Upper Cretaceous Medicine Bow, Lewis and Mesaverde formations consist 

of up to 4572 m (15,000 ft) of marine dark, organic rich shales. The Eocene- 

Paleocene Hanna and Ferris formations consist of up to 4270 m (14,000 ft) 


(TOCs) 

of organically richlacustrine shales, coals and fluviatile sandstones (Perry, 

1992; Beirei, 1987; Matson, 1984). 

Moderate to good late Cretaceous marine source rocks with TOCs greater 

than 0.5% (Figure 4). The Hanna, Ferris, Medicine Bow, and Mesaverde 

formations have coal beds and carbonaceous shales with variable TOC 

values 

(0.5 to 35.6 wt% avg, 3.2 wt% TOC). Marine sediments of the Lewis, Steele, 

Niobrara, and Frontier formations have TOC range of 0.4 to 4.3 and average 

of 1.5 wt% TOC (Beirei, 1987). 

c.Thermal maturity Ro >1% below 11,000 ft in the Champlin and Brinkerhoff wells; greater than 

the 0.8% threshold generally indicating the top of abnormal pressures 

(Johnson and Finn, 1998; Law, 1984). Ro < 0.7% to 10,000 ft depth in #1 

Hanna well; below 10,000 ft, Ro increase to 1.23% near bottom of hole, 

suggesting thermogenic gas generation and possible abnormal pressures 

below 10,000 ft (Perry, 1992; Spencer, 1987). Ro for Hanna and Ferris coals 

ranged from 0.45% to 0.6% (Pontolillo and Stanton, 1994). Pyrolysis profiles 

combined with Kerogen elemental analysis also suggest generation of gas and 

possible overpressuring in low permeability 

rocks within the deeper part of the basin (Beirei, 1987). Temperature-depth 

plots, time-temperature profiles, and the bottom hole temperature in the 

Forgoston, Amoco, and Humble wells ranging from 204 to 240° F, all 

suggest that overpressuring is present (Johnson and Finn, 1998; Spencer, 

1987). 

d.Oil or gas prone prone to both oil and gas. Several fields produce both oil and gas (Kaplan, 

1985; Matson, 1984; Porter, 1979; McCaslin, 1978). To date, natural gas has 

been found only in sandstone reservoirs (Mitchell, 1968) 

e.Overall basin maturity kinky vitrinite reflectance present in the basin: interpreted as evidence of 

abnormal pressures in low permeability gas bearing reservoirs (Law, et al., 

1989) 

f.Age and lithologies The Upper Cretaceous Medicine Bow, Lewis and Mesaverde formation 

consist of marine dark, organic rich shales. The Eocene-Paleocene Hanna 

and Ferris formations consist of organically rich lacustrine shale, coals and 

fluviatile sandstones. 

g. Rock extent/quality source and reservoir rocks extend throughout the basin. Rock quality 

unknown



h.Potential reservoirs dark, organic-rich marine shales of the Upper Cretaceous Medicine Bow, 

Lewis and Mesaverde formations, and organic-rich lacustrine shale, coals 

and fluviatile sandstones of the Eocene-Paleocene Hanna and Ferris 

formations 

i.Major traps/seals Most of the known traps are structural closures around the edges of the basin 

(Matson, 1984). Several structural/stratigraphic traps are also present (Porter, 

1979, McCaslin, 1978). Stratigraphic traps may be present in the deeper part 

j.Petroleum 


models 

of the basin, in low permeability possibly overpressured Eocene, Paleocene 

and Upper Cretaceous rocks (Matson, 1984). Major seals are the black/dark 

shales of the Cretaceous (Mowry, Steele, Themopolis Mesaverde), Eocene 

and Paleocene. 

The oil generation window determined from time-temperatures index 

calculations is at 7216 ft to 11,480 ft in the basin center. Hydrocarbon 

generation began near 80 Ma at the base of the Late Cretaceous section in 

the Hanna basin. Transformation models show that the source rocks 

generated and expelled hydrocarbons very quickly. The Hanna basin is not 

generating any significant amounts of hydrocarbons at present. The zone of 

maximum source rock expulsion is modeled at 8200 ft in the center of the 

basin. 

k.Depth ranges In the Hanna #1 well from 11,000 ft to 17,000 ft; Ro increased to 1.23 Ro 

near the bottom of the hole suggesting thermogenic gas generation and 

overpressuring below 10,000 ft (Perry, 1992). The bottom hole temperature 

l.Pressure gradients 

a. Important 


in the Forgoston, Amoco, and Humble wells ranged from 204 to 240° F, 

suggesting that overpressuring may be present. 

Rock River (discovered 1918): structural trap/asymmetric anticline. 

Cumulative production past 40 million bbl. Oil was produced from the 

Cretaceous Muddy, Dakota, Lakota, and Jurassic Sundance Formations. 

Allen Lake (discovered 1918): Muddy Clovely, Sundance. Big Medicine 

Bow (Steele, Muddy, Sundance, Tensleep fm.) Coper Cove, Diamond 

Ranch, Epsy, Ferris, Hatfield. Cedar Ridge (discovered 1980): Steele fm. 

Chapman Draw (discovered 1982): Morrison fm. oil and gas. Simpson Ridge 

(discovered 1923) Steele fm. Frontier and Clovely (1967) oil and gas.

Economic 


Field Name 



b. Recovery 

c. Pipeline infrastructure Major gas pipelines run west and south of the Hanna basin to transport gas 

from the Greater Green River basin and other gas fields in the Rocky 

Mountain Region. 

d. Overmaturity mature 




problems 


i. Porosity 

Cumulative Oil 

(bbl) (6/98) 

Cumulative Gas 

(MCF) (6/98) 

Cumulative Water 

(bbl) (6/98) 

Rock River ...................... ..........43,550,000 ........................ 9,838,602 ........... ......... 28,596,423 

Allen Lake....................... .................................................. 1,768,000 ........... ......................... 

Big Medicine Bow............. ........... 8,796,976 .......................13,712,086 ........... ......... 50,432,248 

Cedar Ridge...................... ................. 7,743 .................................................. ......................... 

Chapman Draw................. ................. 8,095 ...........................816,544 ........... ............... 17,288 

Simpson Ridge ................. ..............277,074 ........................ 2,523,981 ........... ............... 17,288

Seminoe 

R85W R80W 

U 

D 

Hanna 

Basin 

Wyoming 

St. Mary's 

6 

Walcott 

Mountains 

Anticline 

Syncline 

1 

Pass Creek Ridge 

Fault; U, upthrown side 

U 

D 

Thrust fault; teeth, upper plate 

Well 

Seismic 

Line 

5 

Bennett Hills 

2 

Hanna 

7 

Hanna Basin Axis 

4 

Elmo 

Saddeback Hills 

S w e t w a t e r A r c h 

3 

Explanation 

Elk Mtn. 

Freezeout Hills 

Simpson Ridge 

U 

D 

1. Forgaston 

2. Brinkerhoff 

3. Hanna #1 

4. Champlin 

5. unknown 

6. Amoco 

7. Humble #1 

Carbon 

Basin 

80 

U 

D 

BHT = 204 

Ro = 0.98 

Ro = 1.23 

Ro = 0.92 

gas show 

BHT = 217 

BHT = 240 

R77W 

30 

Medicine Bow 

Well Name Parameter Total Depth (ft) 

15,322 

10,485 

14,855 

16,800 

Figure 1: Index map of the Hanna Basin, showing well locations and relevant gas data. After Kaplan (1985). 

T 

24 

N 

T 

20 

N

Aproximate Depth (ft) 

0 

10,000 

20,000 

30,000 

40,000 

Th 

TKf 

Kmb 

Kle 

Humble Oil No. 1 (Pass Creek Ridge unit) 

Kmv 

Kn 

Pt 

pC 

Hanna Formation 

Ferris Formation 

Medicine Bow Formation 

Lewis Shale 

Th 

TKf 

Kmb 

Kle 

Kmv 

Kn 

Pt 

pC 

Explanation 

Mesaverde Formation 

Niobrara Formation 

Tensleep Formation 

Precambrian rocks, undifferentiated 

Figure 2. Geologic cross section across Hanna Basin. After Kaplan and Skeen (1985). 

Kmv 

Kn 

Pt 

pC 

Kn 

Kmv 

Kle 

0 

Kmv 

Scale (miles) 

Kmv 

pC 

N 

Coarser near-shore facies 

pC 

5

Age Unit Lithology Thickness 

Tertiary 

Upper 

Cretaceous 

Lower 

Cretaceous 

Jurassic 

Triassic 

Permian 

Pennsylvanian 

Mississippian 

Cambrian 

Precambrian 

Hanna 

Ferris 

Medicine Bow 

Lewis 

Mesaverde 

Steele 

Niobrara 

Frontier 

Mowry 

Muddy 

Thermopolis 

Cloverly 

Morrison 

Sundance 

Chugwater 

Goose Egg 

Tensleep (Casper) 

Amsden 

Madison 

Flathead 

siltstone, silty sandstone, and 

shale; carbonaceous shale 

underlying coal beds 

continental silty sandstone, and 

shale; with carbonaceous shale 

and coal; minor conglomerate 

dark gray marine shale 

upper: nearshore silty sandstone, 

shale, carbonaceous shale, coal 

lower: marine shale, sitly 

sandstone 

dark gray siltstone, shale; some 

limited silty sandstone 

chalky shale and non-calcareous 

shale; limited siltstone 

marine shale and siltstone 

black, siliceous shale 

sandstone and silty sandstone; 

shale 

dark gray shale; bentonite 

fine-grained silty sandstone; 

siltstone and shale 

silty sandstone, shale; occasional 

carbonaceous shale 

silty sandstone, shale; and 

infrequent oolitic limestone 

red siltstone, silty sandstone, and 

shale 

interbedded red shale, siltstone, 

limestone, and gypsum 

silty sandstone; large cross-beds 

in places; shale, dolomite, anhydrite 

shale, silty sandstone, minor 

limestone, siltstone 

limestone and dolomite thoughout; 

limited shale; siltstone at base 

transgressive silty sandstone, 

siltstone, and shale 

schists, gneisses, and migmatites 

of Archean Age; intrusive granites 

19,800 ft 

6,000 ft 

2,100 ft 

2,600 ft 

3,000 ft 

1,200 ft 

800 ft 

200 ft 

63 ft 

80 ft 

200 ft 

375 ft 

300 ft 

700 ft 

400 ft 

400 ft 

300 ft 

500 ft 

65 ft 

Hydrocarbon 

Potential 

Figure3: Stratigraphic chart of units present in the Hanna Basin, Wyoming, showing hydrocarbon 

potential. After Kaplan (1985).

Depth (ft) 

0 

1,000 

2,000 

3,000 

4,000 

5,000 

6,000 

7,000 

8,000 

9,000 

10,000 

11,000 

Champlin Well 

r = 0.92 

0.4 0.6 0.8 1.0 2.0 

Vitrinite Reflectance (R0 %) 

Depth (ft) 

0 

1,000 

2,000 

3,000 

4,000 

5,000 

6,000 

7,000 

8,000 

9,000 

10,000 

11,000 

12,000 

13,000 

Brinkerhoff Well 

r = 0.56 

r = 0.98 

0.4 0.6 0.8 1.0 2.0 

Vitrinite Reflectance (R0 %) 

Figure 4. Down-hole vitrinite reflectance profiles from the Champlin and Brinkerhoff wells (see Figure 1 for borehole locations). After Bierei (1987).


The present day Los Angeles Basin is a deep structural depression about 50 miles long and 20 miles wide located 

on the west coast of southern California (Figure 1). The Santa Monica and San Gabriel Mountains form the northern 

boundary and the Santa Ana Mountains mark the eastern edge. The Pacific Ocean limits the basin on the west and 

the south. The basin contains at least 24,000 ft of Late to Middle Miocene and younger marine clastic rocks 

overlying older Cenozoic sedimentary rocks and Mesozoic basement rocks (Figure 2). There are four large structural 

blocks in Los Angeles basin–the southwestern, northwestern, central, and northeastern–separated by faults or flexures 

in the basement rocks (Figure 1). Figure 3 shows the different stratigraphic units in the four blocks (Yerkes et al., 

1965; Beyer, 1996; Brown, 1966). A potential basin center gas accumulation may be present in the central block. 

Sedimentary rocks range in age from latest Cretaceous to Holocene and divide into two groups: a "pre-basinal" 

suite of Upper Cretaceous to Lower Miocene rocks, and "basinal" marine sediments deposited in a rapidly subsiding 

trough since Middle Miocene time (Yerkes et al., 1965). 

The geotectonic history of the Los Angeles Basin can be explained by the constant-motion plate tectonic model, 

which links movements of the San Andreas fault to the Cenozoic sea floor spreading in the northeastern Pacific 

(Campbell and Yerkes, 1976). The Santa Maria basin formed by Middle Miocene to Early Pliocene extension, 

strike-slip faulting and block rotation, and Late Pliocene to Recent north-south compression (Beyer, 1996). 

Extensive igneous flows, intrusive rocks, and tephra were emplaced within and around the basin during Late 

Miocene. 


Oil production from the basin has occurred since the 1890s (Table 1). The Los Angeles basin ranks first worldwide 

in total discovered oil-in-place per unit volume. The hydrocarbon richness of the basin results from a favorable 

sequence of events including: 

1 

1) the deposition of oil-prone organic matter in low oxygen environments, 

2) rapid burial which preserved the organic matter, 

3) maturation and expulsion of oil coinciding with trap formation, and 

4) production of hydrocarbons before uplift and erosion could destroy a significant portion of the reservoirs. 

Fifteen of the sixteen largest oil fields, which account for 91% of the basin’s total, were discovered before 1933. 

Significant discoveries include the Beverly Hills, La Cienega, Riviera, and San Vicente fields–all found during the 

1960s. Urbanization has constrained exploration. Drilling activity during the last 40 years has averaged just two 

wells per year. Cumulative production and estimated reserves exceed 9.6 BBO and 8.7 TCFG (Beyer, 1996). All 

significant gas reserves in the basin have been associated with oil accumulations (Gardett, 1970). Most of the 

discovered accumulations have been structural/stratigraphic traps in Miocene and Pliocene turbidite sandstones, 

ranging from distal turbidite sandstones to proximal conglomeratic sandstones. Several minor reservoirs have been 

discovered in Pleistocene, Pliocene and middle Miocene sandstones. Reservoir depths range from 900 to 11,900 ft, 

and thicknesses range from 15 to 1,200 ft. Structure has been the dominant trapping mechanism for discovered 

hydrocarbons. Traps north and south of the basin center include faulted anticlines, faulted noses, homoclines, domes, 

and various stratigraphic traps. To date, the basin center area remains undrilled, except for the American Petrofina 

Core Hole well in the basin center (Stark, 1972; Beyer, 1988).


The American Petrofina Core Hole well bottomed at a depth of 21,215 ft in Delmontian rocks in the basin 

center syncline. Unfortunately, the well did not reach the Mohnian section, which may be the equivalent of the 

organic-rich "nodule shale" found elsewhere in the basin. Therefore, drilling has not yet confirmed the presence of 

source and reservoir rocks in the basin center. Shallower wells on the east flank of the Newport-Inglewood zone 

penetrated interbedded sandstone and shale containing type II kerogen in the lower Mohnian section. The Mohnian 

rocks may be fractured because of fluid overpressuring during maturation of kerogen in the organic-rich shale. The 

play, if present, will be in the upper Miocene lower Mohnian section (Figure 1). Favorable conditions for basin 

center gas accumulations are present in the Los Angeles basin for the following reasons: 

2 

1) Thermally mature source rocks (Ro values > than 1.2% and TOC's of 1-9%) are present in the basin center; 

2) Abnormally high formation pressures were measured both in the American Petrofina Core Hole in the basin 

center syncline, and in the Standard Oil of California well (0.72 psi/ft) located northeast of the basin center 

(Bostick et al., 1978); 

3) High reservoir temperatures ranging from 205 to 304° F were measured in the central basin syncline (8,900 

to 15,500 ft); 

4) Hydrocarbons are present in the basin center–the American Petrofina Core Hole well yielded 43° API gravity 

oil, with a high gas-oil ratio at 21,215 ft depth; and 

5) A thick section of Upper Miocene (Mohnian) rocks ranging in thickness from 3,000 to 7,000 ft may be 

present in the basin center.



Geologic 


Accumulation: 


Pacific Coast- Los Angeles Basin, California. Middle to Late Miocene and 

Early Pliocene age rocks (upper Mohnian, Delmontian and "Repettian" 

stages). 

a. Source/reservoir southwestern shelf: the organic-rich basal "nodular shale" of late Middle 

Miocene Modelo Formation, sourcing the underlying schist conglomerate 

and the overlying marine sandstone reservoirs (Bostick et al., 1978); 


(TOCs) 

central syncline: source rocks may occur in the lower Mohnian section, 

analogous to the "nodular shale" (Schmoker et al., 1995). 

1.0% - 9.0% 

c.Thermal maturity type II; Ro = 0.24-0.89 (Bostick et. al., 1978); greater than 1.2% in the 

American Petrofina Core Hole well at 21,215 ft. (Hydrocarbon rich shales 

found in the basin may retard/suppress vitrinite reflectance values) 

d.Oil or gas prone both oil and gas prone 

e.Overall basin maturity considered mature along with adjoining basins in the Pacific Coast 

f.Age and lithologies Middle to Late Miocene and Early Pliocene age rocks (upper Mohnian, 

Delmontian and "Repettian" stages). Lithologies are primarily turbidite 

sandstones, siltstones and shales. 

g. Rock extent/quality basin-wide source and reservoir-rock distribution. 


i.Major traps/seals structural in producing fields; basin center traps-unknown but postulated as 

(1) deep continuous volume reservoirs without clear boundaries, (2) 

localized reservoirs where fracturing is a function of lithofacies, (3) 

structurally 

bounded reservoirs because of faulting or folding. Basin center seals: shales. 

Also, the presence of laumontite that was reported at depth in the American 

Petrofina Core Hole well may degrade the quality of the reservoir rocks and 

j.Petroleum 


models 

help form seals (Beyer, 1996). 

migration began during early Pliocene or earlier and probably continues 

today. Migration is not necessary for postulated self sourcing reservoirs. 

k.Depth ranges 900 to 11,900 ft (producing fields); 21,000 to 24,000 ft in the basin center. 

l.Pressure gradients overpressured aqueous pore fluids of 0.72 psi/ft were reported in the 

Standard Oil of California "Houghton Comm. One" No. 1 well, located 

northeast of the central synclinal trough. This 14,000 ft deep well was drilled 

on the 

Santa Fe Spring fold (Bostick et al., 1978).



Economic 


a. Important 


Wilmington-Belmont (discovered 1932, >2.857 BBO and 1.235 TCFG); 

Huntington Beach (discovered 1920, >1.138 BBO and 861 TCFG); Long 

Beach (discovered 1921, >945 MMBO and1.088 TCFG); Santa Fe Springs 

(discovered1919, >634 MMBO and 839 BCFG); Brea-Olinda (discovered 

1880, >430 MMBO and 482 BCFG); Inglewood (discovered1924, >400 

MMBO and 285 BCFG); Beverly Hills (discovered 1966, >135.5 MMBO 

and 202 BCFG); Torrance (discovered 1922 >246 MMBO and 158 BCFG); 

Richfield (discovered 1919, 203 MMBO and173 BCFG); Coyote East 

(discovered 1911, 122 MMBO and 61 BCFG). 

b. Cumulative production see Important fields/reservoirs above 


b. Recovery good 

c. Pipeline infrastructure very good There are numerous gas lines in the basin. 





problems 


i. Porosity 

no expected completion problems based on existing field information

36° 

34° 

32° 

Northwestern Block 

120° 118° 116° 

Santa 

Barbara 

California 

Point Dume 

Los Angeles 

Basin 

San Diego 

Potential basin-centered 


Boundary of structural 

block 

Santa Monica Mountains 

Santa Monica Bay 

San Fernando Valley 

Santa Monica Fault 

Santa 

Monica 

A 

Pacific Ocean 

Beverly 

Hills 

Baldwin 

Hills 

Palos Verdes 

Hills 

Anticline, showing 

plunge direction 

Syncline, showing 



approximate 

Verdugo 

Hills 

Elysian 

Hills 

Dominguez 

Hills 

San Rafael 

Hills 

Los 

Angeles 

Long 

Beach 

Palos Verdes Hills Fault 

San Gabriel Mountains 

Repetto Hills 

Signal 

Hill 

Sierra Madre 

Raymond Hill Fault 

Whittier 

Hills 

Newport-Inglewood Fault 

Huntington 

Beach 

Mesa 

San Gabriel Valley 

Whittier Fault 

La Habra Fault 

La Habra 

Valley 

Coyote Hills Uplift 

Anaheim Nose 

0 10 mi 

Newport 

Mesa 

A' 

El Modeno Fault 

Shady Canyon Fault 

Cucamonga Fault 

San Jose Hills 

Pelican Hill Fault 

Puente 

Hills 

Central Block 

Northeastern 

Block 

Santa Ana Mountains 

Figure 1. Index map of the Los Angeles basin, California, showing major structural features on the basement surface and four informal structural blocks. 

After Yerkes et al (1965) and Beyer (1988). 

San Joaquin 

Hills 

Dana Point 

Elsinore Fault 

Corona

Sea 

Level 

Depth in Miles 

10 

20 

A A' 

Palos Verde 

Hills 

Post-Late Pliocene 

Torrance Dominguez 

Central Basin Montebello 

San Gabriel 

Hills 

West East 

Valley 

? 

? 

Late Pliocene and Upper Miocene 

Middle Miocene and older 

Western basement complex 

(Catalina Schist) 

(Eastern) basement complex 

Oil field 

Figure 2. Generalized cross-section A-A' of the Los Angeles basin, California, showing selected oil fields. After Beyer (1988). 


inferred

System 

Quaternary 

Tertiary 

Late 

Cretaceous 

Pre-Turonian 

Mesozoic 

Series/Stage Age 

(mya) Santa Monica Mountains "Catalina Block" 

Santa Ana Mountains 

Pliocene 

Upper Miocene 

Middle 

Miocene 

Lower Miocene 

Oligocene 

? ? 

Eocene 

? ? 

Paleocene 

Maastrichtian 

Campanian 

Santonian 

Coniacian 

Turonian 

Shale, cherty shale, 

and sandstone 

Sandy shale, siltstone, 

sandstone, and/or 

conglomerate 

10 

20 

30 

40 

50 

60 

70 

80 

90 

100 

Pico Fm 

Repetto Fm 

Modelo Fm 

Upper Topanga Fm 

Undifferentiated volcanic 

rocks/Topanga Fm 

Vaqueros Fm 

Sespe Fm 

Llajas Fm (?) 

Unconformity 

Martinez Fm 

Unconformity 

Chico Fm 

San Pedro Fm 

Pico Fm 

Repetto Fm 

Monterey Fm 

"B" sedimentary rocks/ 

"B" volcanic rocks 

Disconformity 

Upper San Fernando Fm 

Lower San Fernando Fm 

Puente Fm 

Undiff volcanic rocks 

Topanga Fm 


marine 

sedimentary rocks 

Vaqueros 

and Sespe Fms 

Santiago Fm 

Silverado Fm 

Ladd Fm 

Williams Fm 

Trabuco Fm Trabuco Fm 

Santa Monica Slate/ 


granitic rocks 

Shale 

Siltstone 

Marine 

sandstone 

Non-marine 

sandstone 

Catalina Schist 

Conglomerate 

Breccia 

Malibu Coast Fault 

Unconformity 

Unconformity 

Holz 

Shale 

Member 

Baker 

Canyon 

Sandstone 

Member 

Santiago Peak volcanic 

rocks/ 

Bedford Canyon Fm/ 


granitic rocks of the 

Southern California 

Batholith 


volcanic rocks 


metamorphic rocks 

Newport-Inglewood 

Fault Zone 

Schist or slate 


igneous rocks 

Figure 3. Generalized stratigraphic columns for the Los Angeles basin, California. After Yerkes et al. (1965), and Campbell and Yerkes (1971).


The Michigan Basin is a circular-shaped intracratonic basin covering about 80,000 square miles (Catacosinos and 

Daniels, 1991). Structural boundaries of the basin include the Canadian Shield on the north, the Algonquin Arch on 

the east, the Findlay Arch on the south and east, and the Kankakee and Wisconsin Arches on the south and west 

(Figure 1). The basin contains Paleozoic marine sediments overlying Precambrian basement (Figures 1 and 2). 

The Middle Ordovician St. Peter Sandstone consists of massive sandstones interbedded with thinner dolomites 

(Figure 2). Deposition of this transgressive marine succession occurred in peritidal to storm-dominated outer-shelf 

environments (Catacosinos and Daniels, 1991). In the center of the Michigan Basin, the St. Peter conforms to and 

interfingers with the Trempeleau and Prairie du Chien Formations; however, at the basin margins, the sandstone lies 

unconformably over underlying units (Figure 2). Similarly, at the basin center the St. Peter grades to the overlying 

Glenwood Formation, but rests unconformably over underlying units at the basin margins. The St. Peter thickens to 

almost 1,100 ft in the basin center (Figure 3). 

The quartzose sandstones are fine- to medium-grained and cemented with silica and dolomite. Diagenesis has 

generally reduced porosities to less than 3%, but locally they may reach 10 to 15%. Porosity reduction occurred early 

in the burial history of the St. Peter (Drzewiecki et al., 1991). The formation contains several repetitive sequences 

that reflect the transgressive and highstand cycles resulting from major subsidence and structural movement within 

the basin. The sequences appear in wireline log signatures and corresponding lithologies (Figure 4) (Dott and Nadon, 

1992). The repetition of sandstone, claystone, and dolomite has not only influenced the diagenetic banding of the 

sandstone reservoirs, but also has compartmentalized the reservoir pressures. 

1 

Sandstone permeability ranges from 1.0 to >100 md (Figure 5). 


The St. Peter has historically had some exploration, but well penetration and testing occurred only in the usually 

tight upper part. Over 36 gas fields have been discovered in the Glenwood-St. Peter “Deep Play” since the late 1980s 

(Barnes et al., 1992). Production depths vary from about 5,000 to 11,500 ft. Falmouth field produced 5.1 BCF from 

1987 to 1990, and some estimates place the per-well reserves at 2.0 to 14-plus BCF per 640 acre spacing. Test 

within the St. Peter Sandstone indicate overpressure exceeds 300 psi (Figure 5). Dott and Nadon (1992) believe 

overpressuring in the formation resulted from hydraulic head created during Wisconsinan glaciation. Figure 3 shows 

the mapped area of overpressure. 

Most traps are structural , and consist of several-mile long anticlines having closures of 20 to 80 ft west of the 

Mid-continent Rift and 100 to 200 ft east of the rift (Figure 3). Stratigraphic traps potentially exist. The reservoir 

“megacompartment” divides into smaller compartments within the St. Peter that correspond to repetitive depositional 

sequences (Figure 4). Fracture systems may also be present. 

Organic-rich shales in the Ordovician Foster Formation probably source the St. Peter Sandstone. 


Vitrinite reflectance data suggests the Michigan Basin Ordovician section is thermally mature. Cercone and 

Pollack (1991) noted that the present-day geothermal gradient and overburden depth could not account for the 

maturation and concluded that a steeper gradient with an overburden composed of fluvial-deltaic sediments would 

create a tighter seal to cook the organic material. 

Although structure controls most gas production from the St. Peter, mapping the internal depositional and 

diagenetic sequences could identify stratigraphically controlled reserves (Dott and Nadon, 1992; Winter et al., 1995). 

If a seal exists, the erosional limit of the St. Peter Sandstone may hold a regional stratigraphic pinch-out play.



Geologic 


Accumulation: 




Michigan Basin, Ordovician, St. Peter Sandstone, overpressured. 

a. Source/reservoir The St. Peter Sandstone is probably sourced from organic-rich shales in the 

Ordovician Foster Fm. Production associated with anticlinal structures 

suggests the presence of fracture systems. Overpressuring is the result of the 


(TOCs) 

hydraulic head created during the last glacial event. 

c. Thermal maturity Vitrinite reflectance values vary from .50 to 1.5 for the Ordovician. 

d. Oil or gas prone gas prone 

e. Overall basin maturity mature basin based on later Paleozoic exploration and production. 

f. Age and lithologies Middle Ordovician sandstones, dolomites, and shales. 

g. Rock extent/quality basin-wide source and reservoir-rock distribution. Currently 36 fields 

produce from this interval. 


i. Major traps/seals Most production occurs in anticlinal features with 20 ft to 200 ft closures 

associated with structural deformation occurring along the Midcontinent Rift 

System. Potential exists for stratigraphic traps as well. 

j. Petroleum 


models 

k. Depth ranges 1.5 km to 3.5 km 

l. Pressure gradients Pressures reported to be 300 psi in excess of expected formation pressures. 

a. Important 


Falmouth field plus 35 other fields produce from the St. Peter Sandstone.

Economic 


b. Cumulative production Falmouth field has produced in excess of 5.1 bcf from 1987 to 1990. 

a. High inert gas content none 

b. Recovery good to moderate 

c. Pipeline infrastructure good 



f. Sediment consolidation good to moderate consolidation 


problems 

h. Permeability 0.01 to 100 md 

i. Porosity 3 to 10% 

low porosities and variable permeabilities may require stimulation of the 

reservoir

Michigan 

Michigan 

Basin 

Wisconsin 

Illinois 

Wisconsin Arch 

Lake Superior 

Lake 

Michigan 

cipi 

o T 

Indiana 

Kankakee 

Arch 

Ohio 

Jurassic sandstone and shale 

Lake Superior 

Syncline 

Pennsylvanian shale and sandstone 

Mississippian shale and sandstone 

Devonian evaporites and carbonates 

Silurian evaporites and carbonates 

Al 

bio 

n-S 

re 

n 

d 

H 

ow 

ell 

Bowling Green Fault 

Ant 

ic 

li 

n 

e 

Ontario 

Lake 

Huron 

Figure 1. Geologic map of the Michigan Basin. After Catacosinos and Daniels (1991). 

Grenville Front 

Findlay Arch 

Lake Erie 

Waverly Arch 

Algonquin Arch 

Chatham 

Sag 

0 50 mi 

Ordovician evaporites and 

carbonates 

Anticline 

Syncline 

Normal fault, hachures on 

downthrown side

Era System Sequence West East 

Mesozoic 

Paleozoic 

Precambrian 

Cambrian Ordovician 

Silurian 

Devonian 

Carboniferous Jurassic 

Zuni I 

Absaroka I 

Kaskaskia II 

Kaskaskia I 

Tippecanoe II 

Tippecanoe I 

Sauk 

III 

Sauk 

II 

Traverse 

Detroit River 

Bass Islands 

Salina 

Niagara 

Cataract 

Richmond 

Trenton 

Black River 


Prairie du Chien 

Lake Superior 

Keweenawan ? 

"Red Beds" 

Grand River 

Saginaw 

Bayport 

Michigan 

Marshall 

Coldwater 

Ellsworth 

Bell 

Sylvania 

Bois Blanc 

Garden Island 

Cabot Head 

Manitoulin 

Utica 

Trempeleau 

Munising 

Jacobsville 

Figure 2. Stratigraphic column of the Michigan Basin. After Dott and Nadon (1992). 

Immature clastic rocks derived 

from Appalachian and 

Ouachita sources 

Shale 

Shale, derived from east 

Sandstone, derived from 

orogen 

Sandstone, derived from 

northern and western 

basin margin outcrops 

Turbidite, derived from 

east (Appalachian Basin) 

Limestone 

Dolomite 

Karst topography 

Salt (halite) 

Igneous rock

Lake Michigan 

500 

Michigan 

Indiana 

700 

A 

Area of Midcontinent 

Rift System 

Area of gas production 

900 

300 

500 

1100 

900 

700 

700 

Ohio 

500 

900 

300 

100 

Lake Huron 

Lake Erie 

Figure 3. Isopach map of the St. Peter Sandstone overlain by the Midcontinent Rift system, gas production from 

the Glenwood Formation and St. Peter Sandstone, and pressure compartment outline. Cross section 

A-A' shown on Figure 4. After Catacosinos and Daniels (1991). 

A' 

Outline of pressure 

compartment (> 490 ft 

above mean sea level) 

50 mi 

1000 

Isopach of St. Peter 

Sandstone (in feet)


The Mid-Continent Rift is a 57,000 square mile horst and graben system located in the Superior 

Province of the north-central U.S. It follows an 800-mile long north-northeasterly trend from south-central 

Kansas to northeastern Minnesota, northwestern Wisconsin and to the western part of the Upper Peninsula 

of Michigan (Figure 1) (Palacas, 1995). Precambrian (Keweenawan) in age, this feature represents a failed 

continental rift characterized by broad horst blocks composed of layered basalts and flanked by high-angle 

normal faults that form the boundaries of adjacent sediment-filled half-grabens (Palacas, 1995). 

Development of the rift occurred approximately 1.1 billion years before present (Dickas, 1986). An adjacent 

structural depression related to the rift trends from Lake Superior southeastward into southern Michigan. 

Other provinces overlapping with or adjacent to the Mid-Continent rift trend include the Iowa Shelf, Forest 

City basin, Nemaha uplift, Salina basin, Sedgewick basin, and Cambridge Arch-Central Kansas uplift 

(Figure 1). Dickas (1986) mapped rift extent by recognizing significant gravity and magnetic anomalies 

throughout the trend. Newell et al. (1993) noted rejuvenation of some structural features by steeply dipping 

reverse faults, where the central horst has thrust over the basin margin. 

Stratigraphy appears generally similar along the rift complex, based on outcrop descriptions and logs 

for wells that have penetrated rift sediments (Figure 2). Sedimentary rocks in the Mid-Continent rift include 

arkosic and feldspathic sandstones, conglomerates, siltstones, and micaceous red, green and gray shales 

deposited in marine (Scott, 1966), alluvial plain (Dickas, 1986), and alluvial fan and lacustrine 

environments (Daniels, 1982; White and Wright, 1960; Tryhorn and Ojakangas, 1972; Kalliokoski, 1982; 

Catacosinos, 1973; and Fowler and Kuenzi, 1978). Layered basalts are common within the rift and compose 

a central horst block. 

The Defiance basin in Iowa is one of the deepest in the rift system. Geophysical modeling indicates 

32,800 ft of sediments (Anderson and Black, 1982). An exploratory well drilled in Iowa penetrated 1,355 ft 

of Keweenawan clastics, 55% of which were red-brown shales (Dickas, 1986). Two other exploratory wells 

penetrated significant thicknesses of Mid-Continent rift strata (Figure 1): the Texaco No. 1 Poersch 

(11,301 ft total depth/8,455 ft of rift strata penetrated) in northeastern Kansas; and the Amoco No. 1 

Eischeid (17,851 ft total depth/14,898 ft of rift strata penetrated) in west-central Iowa (Newell et al., 1993). 

Five wells have penetrated the Precambrian Nonesuch Shale and equivalents within the rift. 

Major traps or seals include interbedded shales, siltstones, layered basalts and fault gouge within the 

Nonesuch Formation, and tight horizons in the overlying Freda Sandstone and the Bayfield Group. 


There is no significant hydrocarbon production within the rift. In 1933, operators produced small 

amounts of oil from fractured Precambrian quartzites in central Kansas, at the southern end of the rift trend. 

Paleozoic source rocks probably expelled this oil, which then migrated laterally into the Precambrian rocks 

along structural highs (Walters, 1953). 

1


The Texaco No. 1-31 Poersch encountered several shows of oil and gas during drilling and testing (Paul 

et al., 1985). Total organic carbon values (TOCs) from the Amoco No. 1 Eischeid in Iowa ranged up to 

1.4%, but the section is overmature (average Tmax = 503° C). In southeastern Minnesota, the Lonsdale No. 

65-1 well encountered dark gray mudstone of the Solor Church (Nonesuch) Formation, and TOC values 

varied from 0.13% to 1.77% (Palacas, 1995); the average Tmax was 494° C (Hatch and Morey, 1984; 

1985). In 1929, a cable-tool rig drilled 822 ft of Precambrian carbonaceous shales and sandstones and had 

some oil and gas shows (Newell et al., 1988). This well was 21 miles northeast of the Texaco No. 1 

Poersch well. 

The Precambrian Nonesuch Fm and equivalents evidently have hydrocarbon generative potential 

throughout the rift system. The interval contains 250 to 700 ft of interbedded, laminated, dark gray to black 

siltstone, silty shale and sandstone. The silty shale contains TOC values averaging 0.6% and reaching a 

maximum of 3% (Imbus et al., 1990; Pratt et al., 1991). The greatest TOC values in the Nonesuch and 

equivalents occur near the middle of the unit and toward the eastern end of the rift system. 

Palacas (1995) reported that the Nonesuch generated oil and gas from type I and type II kerogens in the 

deeper parts of several rift basins. Thermal maturity was sufficient to crack oils into gaseous hydrocarbons 

in the Iowa and Minnesota segments of the rift. He concluded that two phases of hydrocarbon generation 

occurred, one during the early phase of rift extension, and the second during a compressional phase after the 

deposition of Paleozoic sediments. Remigration of hydrocarbons probably occurred during the second stage. 

Newell et al. (1993) measured a present day geothermal gradient of 15.6 °F per 1,000 ft in the 1-4 Finn 

well in northeastern Kansas (Figure 3); the bottom-hole temperature at 3,974 ft was 116 °F. Thus, bottomhole 

temperatures in deeply buried rift sediments should have sufficed for hydrocarbon generation. No 

pressure data is known to exist for wells drilled into the Nonesuch or equivalent rocks (Newell, 1999, 

personal communication). 

2



Geologic 


Accumulation: 


Superior Province, Mid-Continent rift, potential basin-centered gas play. 

a. Source/reservoir Oronto Group (Wisconsin), Nonesuch Formation (Michigan and Wisconsin), 

Solor Church Formation (Minnesota), Lower Red Clastics (Iowa), Red 

Clastics (Nebraska), and Rice formation (Kansas). 


(TOCs) 

range from 0 to 3% 

c.Thermal maturity Tmax 423 – 503° C 

d.Oil or gas prone oil prone; mostly type I and II kerogen 

e.Overall basin maturity maturation levels are moderate to high. Highest thermal maturity is in Iowa 

and Minnesota and with depth and proximity to central horst. 

f.Age and lithologies Precambrian (Keweenawan) age, Nonesuch (and equivalent) arkosic sands, 

silts and silty shales 

g. Rock extent/quality wide source and reservoir rock distribution. Reservoir quality is unknown 

because of few outcrops and few wells drilled. Expected reservoir quality 

varies depending on clay content, interbedded shales and silts and the degree 

of fracturing. 

h.Potential reservoirs No production. Precambrian Nonesuch and equivalents. 

i.Major traps/seals interbedded shales, siltstones, layered basalts and fault gouge within the 

Nonesuch formation, tight horizons have also been identified in the overlying 

Freda sandstone and in the Bayfield group. 

j.Petroleum 


models 

in-situ generation and short distance migration. Hydrocarbon generation may 

be ongoing in deeper basins. Present day geothermal gradient is 15.6° F per 

1000 ft. The Bakken shale model of Meissner (1978) may apply in the rft 

for hydrocarbon generation and explulsion directly into adjacent beds. 

k.Depth ranges accumulation depths are thought to range from 3000 ft to 25,000 ft 




Economic 


a. Important 


b. Cumulative production none 

a. High inert gas content unknown 

entire rift trend virtually untested; no production to date. 

b. Recovery Recoveries vary depending on permeability, porosity and depth; diagenetic 

alteration may increase with depth. 

c. Pipeline infrastructure poor 

d. Overmaturity probably overmature in the deepest parts of the basins 

e. Basin maturity most basins are mature (Ro ranges from 0.5 to 1.43) 



problems 


Silty shales, clay, and arcosic/feldspathic sands have high alteration 

potential; also may have swelling clays and will produce migrating fines 

problems. Silty shales and siltstones are interbedded with sands. 

i. Porosity average porosities range from 4% to 18% percent

49° 

45° 

40° 

North Dakota 

South Dakota 

Nebraska 

Kansas 

Rice Basin 

Oklahoma 

Mineola graben 

1 Poersch 

Manitoba 

1 Koutney 

Nemaha uplift 

Minnesota 

Northern 

boundary 

zone 

Defiance Basin 

1 Eischied 

1-4 Finn 

Wilson 1 

Iowa 

horst 

Iowa 

Ontario 

Lonsdale 65-1 

Stratford 

Basin 

Shenandoah 

Basin 

Missouri 

Arkansas 

Lake 

Superior 

Michigan 

Illinois 

X 

White Pine 

Mine 

Wisconsin 

Thurman/Redfield 

zone 

100° 95° 90° 

Keweenawan clastic rocks 

Mafic rocks 

0 50 mi 

Figure 1. Location map of the Mid-Continent rift system in the central United States. After Dickas (1986), 

Berendsen et al (1990), and Newell et al (1993). 

Well 

Fault, dashed where inferred, 

hatchure on downthrown side

Era Series Kansas 

Proterozoic 

Upper 

Keweenawan 

Middle 

Keweenawan 

Rice 

Formation 

Nebraska Iowa Minnesota Wisconsin 

"red clastics" 

horst flank horst flank horst flank 

* "upper 

red clastic 

sequence" 

* "lower 

red clastic 

sequence" 

Hinkley 

Sandstone 

Fond du Lac 

Formation 

Solor Church 

Formation 

Oronto 

Group 

Bayfield Group 

Chengwatana 

Volcanic 

Group 

Michigan 

Upper Peninsula 

Chequamegon 

Sandstone 

Devils Island 

Sandstone 

Orienta 

Sandstone 

Freda 

Sandstone 

Nonesuch 

Shale 

Copper Harbor 

Conglomerate 

Portage Lake 

Volcanics 

Volcanic rocks Tentative correlations (per Newell et al, 1993) 

* 

Figure 2. Stratigraphic correlation of units along the Mid-Continent rift system, central United States. After White (1972), Dickas (1986), Mudrey and 

Ostrom (1986), Witzke (1990), and Newell et al (1993). 

Jacobsville Sandstone

Depth (feet) 

0 

1000 

2000 

3000 

4000 

5000 

6000 

7000 

8000 

9000 

Time (Ma) 

1200 1100 1000 900 800 700 600 500 400 300 200 100 0 

? 

Precambrian 

Top is TTI = 15 

Base of gray 

siltstone 

1 

Original top of 

gray siltstone 

Paleozoic 

110° - 115° C (230° - 239° F) 

2 

Thermally immature 

Phanerozoic section 

3 

Mesozoic 

4 

1 

2 

3 

4 

Events 

Deposition of Arbuckle 

Group; uplift of southeast 

Nebraska arch 

Formation of Nemaha 

uplift 

Pennsylvanian and 

Permian deposition; 

post-Permian erosion 

Cretaceous deposition; 

subsequent erosion 

Oil window 

Rifting period 

Figure 3. Time-temperature index (TTI) model of the 1-4 Finn well. The graph depicts a 40° C/km (2.19° F/100 ft.) geothermal gradient following a heat 

pulse during rifting. The relationship of subsidence and thermal decline during rifting is speculative. After Newell et al (1993).


The Hornbrook Basin is located in the northeast corner of California and south-central Oregon, and is bounded on the west 

by the Klamath Mountains (Figure 1). The Cascade Mountains and the central Oregon volcanic plateaus form the basin’s 

northern boundary. The province becomes progressively more block-faulted eastward, eventually converging with the Basin and 

Range province. The southern boundary stretches across part of the Basin and Range, the northern end of the Sierra Nevada, the 

Sacramento Valley, and the Klamath Mountains. The Cascades overlap part of the province, dividing the Shasta Valley on the 

west from the Modoc Plateau to the east. 

Potential source and reservoir strata in the basin include the Upper Cretaceous Hornbrook Formation and the overlying 

Upper Cretaceous-Eocene Montgomery Creek Formation (Figures 2 and 3). Deposition of the Hornbrook occurred in a large, 

relatively undeformed successor basin called the “Hornbrook Basin.” This basin probably extended beyond the present Shasta 

Valley-Yreka Valley-Modoc Plateau limits, and probably connected with the Sacramento/Great Valley basins to the south and 

to the Ochoco Basin northeast in central Oregon. Some Hornbrook strata may have continuity with the Great Valley Sequence. 

The Hornbrook Formation derives mostly from debris shed from the Klamaths Mountains and rests unconformably on pre- 

Cretaceous metamorphic and igneous basement (Figure 3). The basal unit is a marine to marginal-marine conglomerate. The 

formation includes several fining-upwards marine sequences, and the last unit is a 2,600 ft-thick marine shale. At the type 

section, the Hornbrook thickens to 4,200 ft (Nilsen, 1984b). 

The Montgomery Creek Formation also contains much organic shale and siltstone, although deposition occurred mostly in 

a braided stream, non-marine environment (Higinbotham, 1986). 

Erskine et al. (1984) measured the integrated potential of the basin and deduced that non-magnetic strata (principally 

Hornbrook and lower Montgomery Creek rocks) thicken eastward under the Cascade Range volcanics and the basalts of the 

Modoc Plateau (Figure 2). They projected a thickness of 16,000 ft for this sequence of sedimentary strata. Erskine’s findings 

suggest the Hornbrook “basin” formed by uplift of the Klamaths during the Nevadan orogeny, and that it may be as relatively 

undeformed beneath the Modoc basalts as is the Upper Cretaceous Great Valley Sequence to the south. The basin continued to 

fill without significant tectonic interruption until the onset of Basin and Range deformation in the middle Miocene. Thereafter, 

horst-and-graben structures developed in the eastern Modoc Plateau. Thick plateau basalts covered the basin in the middle 

Miocene and early Pliocene. Cascade volcanism affected the west-central part of the original basin from the late Pliocene to the 

present. 


Most wells drilled to a depth of 500 ft or greater generally have had gas shows, including those for water or geothermal. 

One operator drilled three wells to 1.200 ft near the north end of Honey Lake and found flow rates of 200 to 450 MCFD, 

probably originating from a Pliocene lacustrine sand. The wells never produced commercially. Montgomery (1988) noted that 

the Klamath 1 Kuck well in northeastern Siskiyou County had oil shows from two Upper Cretaceous sands, but ultimately 

produced only salt water (Figure 1).


Several lines of evidence possibly indicate basin-centered gas in the Hornbrook Basin: 

1) gas seeps and a non-commercial gas field; 

2) source rocks capable of generating gas; and 

3) a possible 16,000-ft thick section of “non-magnetic sedimentary rock.” 

Total organic carbon (TOC) values for the Hornbrook Formation range from 0.1 to 1.2 wt%, and average 0.52 wt% 

(Figure 4) (Law et al., 1984). Figure 4 shows vitrinite reflectance of samples taken along the Interstate 5 corridor ranges from 

0.40 to 0.83. 

Potential source rocks include coal and coal-bearing shales within the Blue Gulch Mudstone and Dutch Creek Siltstone 

members of the Hornbrook Formation (Keighin and Law, 1984), and coal-bearing flood-plain and marsh mudstones and 

lacustrine deposits of the upper Cretaceous to Eocene Montgomery Creek Formation (Higinbotham, 1986). Some of these 

sediments crop out in the Shasta Valley and in other parts of the western basin. The units dip generally eastward to a depth of 

15,000 ft in the central Modoc Plateau. Thus, most of the source rocks probably lie at depths from 15,000 to 31,000 ft in 

much of the basin. At these depths the most likely hydrocarbons would be thermally generated natural gas. Law et al. (1984) 

noted the kerogen is Type III and would probably produce gas and little or no oil.



Geologic 


Accumulation: 


Shasta - Yreka Valley and Modoc Plateau, Northeastern California, Central 

Southern Oregon. Possible Cretaceous to Upper Tertiary Overpressured Gas 

Play. 

a. Source/reservoir Potential Source Rocks: Slope shales of the Hornbrook Fm. Coal and coal 

bearing shales within the Blue Gulch Mudstone Member, and the Dutch 

Creek Siltstone Member of the Hornbrook Fm (Keighin and Law, 1984) 


(TOCs) 

Coal-bearing flood plain, marsh mudstones and lacustrine deposits within the 

upper Cretaceous to Eocene Montgomery Creek Fm (Higinbotham, 1986). 

Possible, poorly-known Mid-Mesozoic dark brown to black shales 

underlying the Klamath Mountains. 

Late Cretaceous Hornbrook Fm. = 0.1 to 1.2 Wt % organic Carbon, 

averaging .52% TOC. These are surface samples that may have been strongly 

oxidized, so TOC may be conservative. (Law et. al. 1984) 

c.Thermal maturity Surface samples are generally marginally mature to mature (Law, et. al. 

1984). 

d.Oil or gas prone gas prone; kerogen is generally Type III; will probably produce gas and little 

or no oil (Law et. al. 1984). 

e.Overall basin maturity immature; this is a frontier exploration basin 

f.Age and lithologies Primary exploration target strata range in age from Late Cretaceous through 

the Miocene 


h.Potential reservoirs Potential Reservoir Rocks: Montgomery Creek Fm, Fluvial, Eocene, 

(Higinbotham, 1986). Hornbrook Fm., Late Cretaceous, (Nilsen, 1984a; 

1984b). Interbedded Mid to late Cenozoic volcanic and lacustrine rocks, 

rocks, similar to Rattle Snake Hills Gas Field (abandoned), South Central 

Eastern Washington (Hammer, 1934) 

i.Major traps/seals Traps may be of all types (structural and/or stratigraphic). 

j.Petroleum 


models 

Weimer (1996) “cooking pot model” 

k.Depth ranges Potential reservoir rocks occur from the surface in the Shasta Valley and 

Ashland, Oregon area, to an approximate depth of 9 km. Also in the eastern 

Modoc Plateau, near the transition with the Basin and Range Province. 


(Fuis et al., 1984); (Erskine et al. , 1984)



Economic 


a. Important 


none 

b.Cumulative production none 

a. High inert gas content Unknown though possible; other basins with a high volcanic and intrusive 

content often contain higher than normal CO2, helium, and other inert 

components. 

b.Recovery 

c.Pipeline infrastructure P G & E has a 36-in gas transmission line through the area. Additional lines 

are being built or are planned through the area to transport Canadian gas to 

the major Central and Southern California markets. 

d.Overmaturity Unknown; deeper parts of basin in the central and eastern Modoc Plateau 

may be mature to overmature. Those areas directly overlain by the Cascade 

Volcanic Range and the Plateau Volcanics surrounding the Medicine Lake 

Caldera to the east may be overmature. 

e.Basin maturity Shallow parts of basin are probably immature. 

f.Sediment consolidation Target formations are very competent 


problems 


i.Porosity 

Hornbrook Fm permeability measured from surface samples is low, 

generally less than 1.2 md. However, this is an active tectonic area, and may 

have well developed fracture porosity (Keighin and Law, 1984).

40° 

Trinity 

1 Kuck 

Klamath Expl. 

Redding 

Mt. Shasta 

Siskiyou 

Valley 

Klamath 

Mountains 

PG&E 12" 

Pipeline 

122° 

Pleasant 

Valley 

Sacramento Valley 

California 

Lower Klamath 

Lake Refuge 

Tule Lake 

Refuge 

Mt. Lassen 

Big 

Valley 

Goose Lake 

Valley 

Sierra Nevada 

(Mostly Accreted Terrane) 

Surprise 

Valley 

Siskiyou Modoc 

Shasta Lassen 

PG&E 36" Pipeline 

Plumas 

121° 

120° 

42° 

Susanville 

Well or Drill Hole 

Anschutz 

Madiline 

Plains 

Anschutz 

Anschutz 

Webber 

Honey Lake 

Valley 

41° 

40° 

120° 

Figure 1. Generalized geologic map showing natural gas pipelines and oil and gas exploration wells in the Modoc 

Plateau area, northeastern California. After Montgomery (1988).

Elevation in Feet 

10,000 

Sea 

Level 

10,000 

20,000 

123° 122° 45" 122° 30" 122° 15" 122° 121°45" 

Round 

Mountain 

Condrey Mountain Terrane 

(Non-magnetic metasediments) 

Dense and highly magnetic unit 

(ophiolite) 

Cottonwood 

Peak 

Klamath 

River 

Triassic amphibolite 

and serpentinite Landslide 

Volcanic landslide 

debris 

Sp 

Mica schist of unknown age and correlation 

Ql 

Qvb 

Tvb 

Twc 

Kh 

Depositional contact 

Fault 

Sp Serpentinite 

Quaternary lake deposits 

Quaternary basaltic volcanic rocks 

Tertiary basaltic volcanic rocks 

Eastern Paleozoic and Triassic Belt 

(Salmon River Terrane) 

Triassic amphibolite 

Tertiary (Oligocene-Eocene) Western Cascades sequence 

Cretaceous Hornbrook Formation 

Tertiary basaltic 

volcanics (Tvb) 

Eagle 

Rock 

Twc 

Tvb 

Ql 

Butte 

Valley 

Quaternary basaltic 

volcanics (Qvb) 

Twc 

Ql 

Western Cascades volcaniclastics 

Eocene to mid-Miocene 

Twc 

Kh 

Hornbrook Formation (Kh) 

(Cretaceous) 

Figure 2. Cross section derived from integrated potential field model of the western part of the Hornbrook Basin-Modoc Plateau region of Northeastern 

California. West-east section located approximately at latitude 41° 55" north. After Erskine et al. (1984). 

Ql 

Mahogany 

Mountain 

Qvb 

Twc 

Ash 

Creek 

Ql 

Qvb

System Series 

Lithology 

Quaternary Holocene Basalt; Lacustrine and Fluvial Sediments 

Tertiary 

Upper 

Cretaceous 

Pre-Cretaceous 

Pleistocene 

Pliocene 

Miocene 

Upper 

Oligocene 

Lower 

Oligocene 

Upper-Middle 

Eocene 

Maestrichtian 

Campanian 

Santonian 

Coniacian 

Turonian 

Cenomanian 

? ? ? 

Alturas Formation 

(Basalt, Lacustrine Sediments) 

Cedarville Series 

(Basalt, minor Rhyolite, 

Lacustrine Sediments) 

Weaverville Formation (Trinity County) 

(Non-marine Sandstones and Shales) 

Upper Montgomery Creek Formation 

(and equivalent) 

(Non-marine, Fluvial Sandstones and Shales) 

Lower Montgomery Ck. 

Hornbrook Formation 

(Marine) 

? ? ? 

Redding Formation 

(Marine) 

Klamath-Sierra Nevada 

Metamorphic and Intrusive Rocks 

Figure 3. Stratigraphic column of the Hornbrook Basin, Upper Cretaceous to Recent. After Montgomery (1988).

T36S 

T37S 

T38S 

T39S 

T40S 

T41S 

T48N 

T47N 

T46N 

T45N 

T44N 

R4W R3W R2W R1W R1E R2E R3E 

Rogue 

Jacksonville 

River 

13-16 

17-19 

Oregon 

California 

Klamath River 

Medford 

Ashland 

8-11 

38-40 

41-52 

53, 55-60 

Yreka 

61-62 

23-37 

20-22 

12 

Hornbrook 

Shasta River 

R11W R10W R9W R8W R7W R6W R5W 

Sample Location 

Scale 

N 

0 5 10 miles 

1-7 

Location 

1-7 

8-11 

12 

13-16 

17-19 

20,21 

22 

23-37 

38-40 

41-52 

53 

54 

55-60 

61,62 

54 

R0 .60 

.60 

.64 

.83 

.67 

.67 

.40-.52 

.67 

.52-.58 

.51 

.59 

TOC (%) 

0.9 

.33-.55 

.10-.76 

1.13 

1.14 

.34-.80 

Figure 4. Location of Hornbrook Formation source rock samples showing vitrinite (R0) and total organic carbon 

(TOC) values. After Law et al. (1984). 

23.6


The Paradox Basin extends across southeastern Utah and southwestern Colorado along a roughly 

northwest-southeast trend. Several structures form its boundaries and contributed sediments: the ancestral 

Uncompahgre Uplift to the northeast, the Monument Uplift to the southwest, and the Emery Uplift to the 

northwest (Figure 1) (Baars and Stevenson, 1981). Figure 2 shows a partial stratigraphy of the basin. 

During the Pennsylvanian (Desmoinesian) period, the basin accumulated deposits of algal carbonates 

and evaporites (halite, gypsum, and potash) which interfingered with clastic deposits shed from surrounding 

higher regions (mostly the ancestral Uncompahgre Uplift; the present Uncompahgre Plateau formed during 

the early Tertiary Laramide orogeny). Toward the basin depocenter, evaporite deposits interfinger with 

siltstones, organic-rich dolomites and black shales. Deposition of Uncompahgre alluvium deformed the 

underlying salts, which created northwest- to southeast-trending anticlines parallel to basement faults 

(Figure 3) (Hite and Buckner, 1981). 

The Cane Creek interval is the 22nd of 29 carbonate cycles identified within the Paradox Member of the 

Hermosa Formation (Figures 2 and 4) (Hite et al., 1984). Three units make up the Cane Creek interval: the 

uppermost "A" unit of interbedded red siltstone and anhydrite; the "B" unit of black, organic-rich shales and 

dolomites; and the lowermost "C" unit of interbedded red siltstone and anhydrite. The "B" unit represents the 

source and reservoir rock and varies in thickness from less than 10 ft to almost 30 ft. Combined, the three 

clastic units are almost 150 ft thick near the basin depocenter, but pinch out against the ancestral 

Uncompahgre flank (Morgan, 1992). The interval thins in synclines and thickens on anticlines; this 

occurrence may result from (1) original deposition associated with fault movement, (2) structural thickening 

from small-scale folding and faulting (i.e., repeat sections), and/or (3) flowage within anhydrite layers 

(Montgomery, 1992). 

HYDROCARBON PRODUCTION: 

Most production in the Paradox originates from Ismay and Desert Creek carbonates in the southern part 

of the basin. Some structures in the Mississippian Redwall and Leadville limestones also produce 

hydrocarbons. To date, Cane Creek production has occurred only in the northern part of the basin, and 

mostly from fractures and fracture intersections on the flanks of anticlines that parallel the ancestral 

Uncompahgre Uplift. The nature of the fracturing makes production very sensitive to drilling mud weights 

and completion techniques (Montgomery, 1992). As a result, recoveries vary greatly. 

Cane Creek wells show significant reservoir overpressuring, at least 6,000 to 6,500 psi at depths of 

7,200 to 7,500 ft. The overpressuring may result from salt flowage (Montgomery, 1992). Oil is typically 

sweet, having API gravities from 43 to 46. Gas associated with oil production is usually flared, because of 

the lack of pipelines in the area. The gas is sweet, containing between 1 and 2% nitrogen and/or carbon 

dioxide. 

The # 1 Long Canyon well drilled by Southern Natural Gas has yielded over 1 MBO since 1962. In 

1991, Columbia Gas completed Kane Creek 27-1 in the Cane Creek interval using horizontal drilling; 

cumulative production to 1992 exceeded 100,000 bbls of oil. 

1

EVIDENCE FOR BASIN CENTERED-GAS 

The play is mature in the northern part of the Paradox Basin, while the southern portion of the basin is 

immature and may have gas potential in subtle structures. Traps within the Cane Creek interval appear to 

be small tightly folded salt structures; stratigraphic traps are possible. Data from the Gibson Dome well 

(GD-1; Figures 3 and 4) shows total organic carbon (TOC) content in the interval to be 3.96 wt%; vitrinite 

reflectance (Ro) averaged 0.54, and Tmax reached 438 C (Hite et al., 1984). This data indicates the Cane 

Creek may be self-sourcing. The reservoir/source may communicate with other organic-rich reservoir/ 

source rocks. 

2



Geologic 


Accumulation: 


Rocky Mountain, Paradox Basin, Pennsylvanian, Hermosa Formation, 

Paradox Member, Cane Creek interval, overpressured. 

a. Source/reservoir The Cane Creek interval is self-sourcing, and current production indicates 

fracturing of the reservoir is required to produce economic quantities of oil 

and gas. Overpressuring largely occurs from salt deformation which may 


(TOCs) 

result from salt flowage in conjunction with basement structures. 

Cane Creek interval in the Gibson Dome #1 core hole = 3.96 wt% 

c. Thermal maturity Cane Creek interval in the Gibson Dome #1 core hole Ro = 0.54; Tmax = 

438° C 


e. Overall basin maturity considered to be among top Rocky Mtn basins in terms of maturity 

f. Age and lithologies Pennsylvnian aged black shales and dolomites 

g. Rock extent/quality basin-wide source and reservoir-rock distribution (although substantially less 

than the halite deposition limit typically used to define the limits of the 

Paradox Basin). About 486 wells (basin-wide) may have penetrated this 

interval 

h. Potential reservoirs Cane Creek interval is sporadically productive and other organic-rich 

intervals, such as the Chimney Rock and Gothic intervals along with many 

other unnamed units may deserve closer attention. 

i. Major traps/seals may be discrete tightly folded salt structures associated with basement fault 

blocks. Possible stratigraphic traps may result from lateral facies changes to 

continentally derived red-beds. 

j. Petroleum 


models 

k. Depth ranges 2000 ft; on some structures to 7500 ft 

l. Pressure gradients average formation pressure is approximately 0.85 psi/ft



Economic 


a. Important 


Bartlett Flat, Cane Creek, Gold Bar, Long Canyon, Shafer Canyon, Wilson 

Canyon. 

b. Cumulative production The Long Canyon well has produced in excess of 1 MMBO since 1962, and 

the Kane Creek Federal #27-1 has produced in excess of 100 MBO as of 

1992. 

a. High inert gas content no; from 1.0 % to 3.0 % 

b. Recovery highly variable 



e. Basin maturity For the Cane Creek interval the southern portion of the basin is immature. 

f. Sediment consolidation The producing interval is well inurated due to depth of burial. 


problems 


i. Porosity 

The reservoir/source rock is fractured and overpressured resulting in the use 

of heavy drilling mud weights, which may result in formation damage and 

difficult and costly completions. Production of hypersaline formation waters 

has often caused plugging of production tubing and equipment which may in 

turn give erroneous flow rates and production declines.

Olympic - Wichita 

Salt Lake City 

Cordilleran Hingeline 

Kaibab 

Mogollon Hingeline 

Colorado Plateau 

Structural feature 

Lineament 

Circle 

Cliffs 

Utah 

Lineament 

Colorado 

Flagstaff 

Uinta Uplift 

Emery 

Monument 

C o l orado 

Arizona 

Grand 

Junction 

Paradox 

Basin 

Defiance 

Basin 

Eagle 

Basin 

Uncompahgre Uplift 

San Juan 

Basin 

Zuni 

P lateau 

New Mexico 


approximate 

Thrust fault, teeth on 

upper plate 

Front Range Uplift 

Albuquerque 

Lineament 

Denver 

Colorado 

0 100 mi 

Figure 1. Location map of Paradox basin, showing the Colorado Plateau, other local basins, structural features, and 

their relationship to the major orthogonal set of lineaments. Northwest-trending lineaments are right lateral. 

Northeast-trending lineaments are left lateral. The stress ellipsoid indicates that maximum compression 

occurs in a north-south direction. After Baars and Stevenson (1981).

System 

Pennsylvanian 

Series Formation Member 

Virgilian 

Missourian 

Desmoinesian 

? 

Atokan 

? 

Morrowan 

Hermosa 

Molas 

Upper 

(Honaker 

Trail) 

Paradox 

Lower 

(Pinkerton 

Trail) 

Evaporite 

Facies Cycle 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 - 13 

14 

15 

16 

17 

18 

19 

20 

21 

23 

24 

25 

26 

27 

28 

29 

Production 

Interval 

Ismay 

Desert Creek 

Akah 

Barker Creek 

Alkali Gulch 

"Gothic" 

"Chimney 

Rock" 

"Cane Creek" 

Figure 2. Stratigraphic column for Pennsylvanian rocks in the Paradox basin. After Hite, Anders, and Ging (1984).

Emery 

Garfield 

Utah 

Arizona 

Green River 

San Juan 

Wayne 

Colorado River 

Uncompahgre Uplift 

SV-3 

A' 

A 

ER-1 

GD-1 

Moab 

SD-1 

Gibson Dome 

Monticello 

Grand 

Dolores 

Montezuma 

Cortez 

Mesa 

Montrose 

San Miguel 

San Juan River 020 mi 

Paradox basin Anticline Core hole 

Silverton Delta 

Colorado 

New Mexico 

Figure 3. Map of the Paradox basin showing core hole locations and basin boundary as determined by the limit of 

halite occurence in the Paradox Member. After Hite et al (1984).

A A' 

Hermosa 

Formation 

Upper 

Member 

Paradox 

Member 

Lower 

Molas Formation 

Shaffer Dome No. 1 

Sec 15 T27S R20E 

1 

TD = 

4160 ft 

29 

28 

2 

"Chimney Rock" 

"Cane Creek" 

? 

? 

27 

Gibson Dome No. 1 


3 

TD = 

6384 ft 

26 

4 5 

25 

Molas Formation 

Figure 4. Diagrammatic north-south cross section showing Pennsylvanian rocks and the carbonate cycles in three U. S. Department of Energy (DOE) core 

holes (SD-1, GD-1, and ER-1). Only the GD-1 core hole penetrated the Cane Creek interval. After Hite et al (1984). 

24 

23 

22 

21 

20 

"Gothic" 

19 

18 

Feet 

Elk Ridge No. 1 


17 

TD = 

3842 ft 

2000 

1500 

1000 

500 

0 

Upper 

Member 

Paradox 

Member 

Lower 

Member 

Hermosa 

Formation 

0 5 10 15 20 

Miles

Black River 

Formation 

Glenwood 

Formation 

St. Peter 

Sandstone 

Brazos 

Shale 

Prairie du 

Chien Group 

Upper St. Peter 

Lower St. Peter 

Sequence 7 

Sequence 6 

Sequence 5 

Sequence 4 

Sequence 3 

Sequence 2 

Sequence 1 

Transgressive sequence 

Early highstand sequence 

Late highstand sequence 

A A' 

39.1 mi 22.4 mi 2.5 mi 23.6 mi 30.4 mi 

Boyce Weingartz 

Ballentine Hunt-Martin 

Limestone or other carbonate rock 

Sandstone 

Shale 

Whyte 

Dolomite 

Well and well name 

Principal producing interval 

South Almer 

Figure 4. West-east cross section through central Michigan basin showing internal depositional, highstand and transgressive sequences within the St. Peter 

Sandstone and the Glenwood Formation. After Dott and Nadon (1992)

Elevation (ft. msl) 

Elevation (ft. msl) 

-3300 

-3400 

-3500 

-3600 

0.001 0.01 0.1 

-3300 

-3400 

-3500 

ρ = 1.16 g/cm 3 

-3600 

35,000 40,000 45,000 

Glenwood Formation (transition zone) 

Permeability (md) 


Prairie du Chien Group 

Glenwood Formation (transition zone) 

Pressure (kPa) 

Data point from drill stem test 

1 10 100 


Prairie du Chien Group 

Data point from repeat formation test 

50,000 55,000 

Figure 5. Permeability distribution and pressure variation within the St. Peter Sandstone, derived from drill stem tests 

and repeat formation tests in the Kielpinski well, Bay County, Michigan.


The Park Basins province is located 50 miles west of Denver, in central Colorado. Four mountain 

regions define the basin limits: the Front Range to the east; Medicine Bow Mountains to the north; Park, 

Gore, and Mosquito Ranges on the west; and the Thirty-nine Mile Volcanic Range to the south (Figure 1). 

Structural or stratigraphic differences separate the Park Basin into three intermontane basins–North, Middle, 

and South Park. Tertiary volcanics of the Rabbit Ears Range physically divide the otherwise structurally 

similar North and Middle Parks. Thirty miles to the south lies South Park Basin, which has undergone a 

more complex structural and stratigraphic history. Precambrian rocks and Tertiary intrusives of the 

Williams Fork and Vasquez Mountains isolate this basin from North and Middle Parks. 

The 50-by 180-mile Park Basin complex is predominantly a north-south trending, asymmetrical 

syncline. The complex was an uplifted feature of the ancestral Front Range throughout most of the 

Paleozoic. The narrow syncline formed during the Late Cretaceous to Early Tertiary Laramide orogeny. 

Tectonism progressed from Late Cretaceous thrust faulting and folding to later episodes of intrusion, 

volcanism, and reverse and normal faulting. Major thrusts occur along the northern and eastern margins of 

the basin and show as much as 20 miles of movement (Maughan, 1988). Superimposed within the syncline 

are high-angle reverse faults (up to 10,000 ft of displacement), normal faults, tight folds, and volcanic rocks 

(Figure 1). 

The basins preserve from 10,000 to 20,000 ft of sediments (sometimes stacked in thrust plates) (Savant 

Resources, 1999). Figure 2 shows stratigraphic columns for each park basin. Sediments of North and 

Middle Park Basins are largely Mesozoic sands, shales, and marls (Figure 3). Southwestern South Park 

exhibits a thick Paleozoic sequence of carbonates, shales, and arkosic sandstones (Figure 4). The Laramide 

orogeny caused a period of basin-wide non-deposition, so Tertiary sediments unconformably overlie 

Cretaceous rocks. The Tertiary section generally consists of non-marine clastics interspersed with coals and 

volcanics. Quaternary alluvium reflects the present quiescent phase of the basin. 


Exploration has found hydrocarbons in anticlinal folds associated with thrusting in the Upper Jurassic- 

Lower Cretaceous shoreline sands of the North Park Basin (Figure 3). The Colorado Oil and Gas 

Commission (1997) recorded16.5 MMBO and 12.3 BCF from Battleship, Lone Pine, and North and South 

McCallum fields. 

Target basin-centered gas intervals are in the Upper Cretaceous: the Apache Creek Sandstone of the 

Pierre Shale and the brittle, calcareous shales of the Niobrara (Figure 2). There are numerous hydrocarbon 

shows but no recorded production from the Apache Creek. The Pierre B sand is probably an equivalent 

sandstone and has produced approximately 1.4 MMCFG and 10.5 MBO (Maughan 1988). Fractured shales 

of the Niobrara Formation have produced about 278,000 BO and 156 MMCFG from the Delaney Butte, 

Michigan River, Canadian River, Coalmont, Johnny Moore Mountain, and Carlstrom fields (Colorado Oil 

and Gas Commission, 1997). Mallory (1977) provides details of this fracture play. 

1


The Apache Creek Formation in South Park has had significant hydrocarbon shows. In 1999 Savant 

Resources LLC evaluated the basin and obtained gas data for the Hunt Tarryall Federal 1-17 well (Figure 4). 

The company found a 24-ft section of the Apache Creek yielded 195 MCFD of pipeline-quality gas. Testing 

revealed 0.3 md matrix permeability, 8.3% average porosity, and 0.52 psi/ft pressure gradient, which 

indicated formation damage. Savant recalculated open flow for the entire section and found 1,500 to 2,945 

MCFD without hydraulic fracturing and 7,344 MCFD with induced fracturing. Based on the encouraging 

results, Savant expects to reenter and retest this well in 2000. 

The Federal 1-17 well data demonstrates Spencer’s (1987) and Surdham’s (1995) characteristics for 

accumulation of basin-centered gas: 

2 

1. Overpressuring of the formation occurs below 10,000 ft. The Apache Creek Sandstone at 11,150 

feet displayed a pressure gradient of 0.52 psi/ft. 

2. Dry hydrocarbons are the fluid-pressuring phase and rarely produce water. The pressure test 

recovered dry gas of pipeline grade (1021 Btu). 

3. Temperature of the overpressured rock is 180-230 0 F or greater. The temperature of the Apache 

Creek Sandstone was 230 0 F. 

4. Source beds can generate hydrocarbons at rates exceeding loss. Minimum vitrinite reflectance (Ro) 

is 0.6% in oil-producing source beds and greater that 0.7% in gas-producing source beds. Pierre and 

Upper Niobrara shales exhibit Ro values between 1.3 and 1.4% Ro. With TOC values around 

1.3% and S1 + S2 values up to 2.6 mg/gm, these rocks demonstrate additional generation 

potential. 

5. Overpressuring is in tight strata. Permeabilities ranging from 0.18 to 0.4 md typify the tight strata 

and suffice for production, after induced fracturing. 

Based on available information (such as a net pay of 100 ft and extensive reservoirs in the South Park 

thrust sheet), Savant Resources (1999) calculated gas reserves of 1.4-2.3 TCF in the Apache Creek play. 

Depth to the Apache Creek is 11,150 feet in the Hunt well and varies widely (Figure 4) (Wellborn, 1977). 

Similar thrusts containing the prospective horizon at the required depth could create additional prospects. 

Notable secondary targets include the Fox Hills Sandstone, the Upper Transition Member of the Pierre 

Shale, the Niobrara Formation, the Frontier Sandstone, the Dakota Group, and the Garo (Entrada) Sandstone 

(Figure 2). Although South Park has had no production to date, a blow-out in the Pierre Shale and 

hydrocarbon seeps (Elkhorn Thrust, Three Mile Seep, and Willow Creek Pass) indicate a potential for an 

unconventional deep gas play. Total organic carbon (C) content for the Pierre Shale ranged from 0.1 to 

1.5% (Barker et al., 1996; Savant Resources, 1999), and 1.4 to 2.1% for the Mowry Shale (Aldy, 1994). 

Since the Apache Creek Formation also exists in North and Middle Park, basin-centered gas plays may 

potentially occur in those basins as well.



Geologic 


Accumulation: 


Rocky Mountains and Northern Great Plains Province, Colorado Park 

Basins; unconventional basin-centered gas play, Upper Cretaceous Pierre 

Shale (Apache Creek Sandstone) through Jurassic Entrada. 

a. Source/reservoir Source Rocks: organic-rich layers of the Niobrara (Maughan, 1989) and the 

Sharon Springs Member of the Pierre Shale. (Gautier et al., 1984). Primary 

reservoirs: Upper Cretaceous Apache Creek Sandstone and 


(TOCs) 

calcareous shales of the Niobrara. Secondary reservoirs: Cretaceous Fox 

Hills Sandstone, Upper Transition Member of the Pierre Shale, Niobrara Fm, 

Frontier Sandstone, Dakota Group, and Jurassic Entrada Sandstone. 

Pierre Shale 0.1 to 1.5% (Barker, 1996) and 1.3% (Savant Resources, 1999); 

Mowry Shale 1.4-2.1% (Aldy, 1994). 

c.Thermal maturity Ro of Pierre and Niobrara ranges from 1.3 to 1.4. 


e.Overall basin maturity Source mature; basin is sparsely drilled. 

f.Age and lithologies North Park contains Permian through Tertiary sands, shales, and 

volcaniclastics, with lesser amounts of carbonates and marls. South Park 

contains a thick sequence of Paleozoic arkosic sandstones, carbonates, and 

shales. 

g. Rock extent/quality The shoreline sands of the Apache Creek appear throughout the 27 wells in 

South Park and have yet to be studied in North Park. Niobrara is present 

throughout the Park Basins; both are of tight reservoir quality. Niobrara and 

Pierre source rocks also occur basin wide and have adequate TOC and 

vitrinite reflectance values. 

h.Potential reservoirs Minor production in North Park Basin (Maughan 1988) in both the Pierre 

and Niobrara. 

i.Major traps/seals Pierre and Niobrara shales or any of the numerous thrust faults such as the 

Elkhorn or the South Park serve as physical seals. Pressure seals occur 

around a depth of 10,000 ft. 

j.Petroleum 


models 

In-situ generation is the accepted model. 

k.Depth ranges Minimum depth of 10,000-20,000 ft. 

l.Pressure gradients 0.52 psi/foot (Savant Resources, 1999)



Economic 


a. Important 


The only production is in North Park Basin. Niobrara fractured shale 

production occurs at Canadian River, Coalmont, Carlstrom, Grizzly Creek, 

Johnny Moore Mountain, North and South McCallum, Michigan River, and 

Delaney Butte fields. Pierre sand production is small and limited to North 

and South McCallum fields. 

b.Cumulative production 277.9 MBO and 156 MMCFG from the Niobrara (Colo. Oil and Gas Comm., 

1997) and 1.4 MMCFG and 10.5 MBO in the Pierre (Maughan, 1988) 

a. High inert gas content Gas at North & South McCallum fields measures 95% CO2 (Carpen, 1957). 

This may be a local phenomenon where igneous intrusions have carried CO2 

through the normal faults associated with these fields (Biggs, 1957). 

Savant Resources (1999) has sampled pipeline-grade gas (1021 Btu) in the 

Apache Creek Sandstone. There is very little test data of the Niobrara but 

one test at Delaney Butte shows a low Btu of 212 (Wellborn, 1983). 

b.Recovery Recoveries around 2 TCF are only hypothetical at this point and will be a 

function of permeability and porosity combined with natural and induced 

fracturing. 

c.Pipeline infrastructure Public Service of Colorado and Colorado Natural Gas pipelines are currently 

in the basin. 

d.Overmaturity Because of several periods of Laramide volcanism, certain areas of the basins 

such as Cameron Pass may be overmature; but this is generally not a problem 

(Maughan, 1988). 

e.Basin maturity most of the basin is mature 



problems 


i.Porosity 

Natural fractures and overpressuring enhance flow for tight sandstones and 

calcareous shales. Hydraulic fracturing is probably essential to develop this 

play.

41° 

40° 

107° Jackson 

106° 

N 

Sierra Madre 

Explanation 

Oil and gas field 

Precambrian rocks 

Extrusive igneous rocks 

Intrusive igneous rocks 

Fault 

Thrust fault 

Park Range 

Gore Range 

thrust fault 

Sheep Mountain 

Lone 

Pine 

Summit 

County 

0 10 

Scale 

20 mi 

Independence Mtn thrust fault 

Butler 

Creek 

Delaney 

Butte 

Coalmont 

Rabbit Ears Range 

Grand 

G 

o 

r 

e 

Michigan 

River 

Williams F ork 

R 

Battleship 

Carlstrom 

North 

McCallum 

McCallum 

South 

Grizzly 

Creek 

Blue Ri ver Valley 

a 

n 

g 

Mosquito 

e 

Spring Creek fault 

Medicine Bow Mountains 

North Park 

Middle Park 

Williams Range thrust fault 

Craig 

Steamboat 

Springs 

Glenwood 

Springs 

Grand 

Junction 

Park Basins 

Figure 1. Generalized geologic map of the Colorado Park basin province. After Tweto et al. (1978), Scott 

et al. (1978), Bryant et al. (1981), and Maughan (1989). 

Canadian 

River 

Johnny Moore 

Mountain 

Mountain s 

Range 

Never Summer 

Mtns. 

Vasquez Mountains 

South 

Park 

Vasqu ez 

thrust 

Elkhorn thrust fault 

B B' 

South Park fau lt 

Fort 

Collins 

Denver 

Colorado 

Springs 

Cañon City 

Location Map 

Gilpin 

Clear Creek 

Park 

Colorado 

41° 

40° 

39°

System 

Tertiary 

Cretaceous 

Jurassic 

Triassic 

Permian 

Pennsylvanian 

Mississippian 

Precambrian 

Northwestern 

Colorado 

Browns Park 

Formation 

Bridger, Green 

River, Wasatch, and 

Fort Union Fms 

Lance 

Formation 

Fox Hills Ss 

Mesaverde 

Formation 

Mancos 

Shale 

Frontier 

Formation 

Mowry Shale 

Dakota 

Sandstone 

Morrison 

Formation 

Curtis Formation 

Entrada 

Sandstone 

State Bridge 

Formation 

S. Canyon Creek Dolo 

Schoolhouse Ss 

Maroon 

Formation 

Eagle Valley 

Evaporite 

Minturn 

Fm 

Maroon 

Fm 

South Park 

Formation 

Niobrara 

Formation 

Dakota 

Sandstone 

Morrison 

Formation 

Garo 

Sandstone 

Minturn 

Formation 

Belden Shale Belden 

Sh 

Leadville Ls 

Leadville Limestone 

Gilman Ss 

lower Paleozoic 

rocks 

South Park Middle Park North Park 

Wagontongue Fm 

Antero Fm 

Balfour Fm 

Laramie 

Formation 

Fox Hills Ss 

Pierre 

Shale Pierre 

Shale 

Apache Creek 

Sandstone 

Rabbit Ears 

Volcanics 

Middle Park 

Formation 

Niobrara 

Formation 

Benton Shale Benton Shale 

Dakota 

Sandstone 

Morrison 

Formation 

North Park Fm 

White River Fm 

Sundance 

Formation 

Morrison 

Formation 

Upper 

Member 

Lower 

Member 

Sundance 

Formation 

Morrison 

Formation 

Chugwater 

Formation Red Peak 

Formation 

Forelle Limestone 

Glendo Member 

Entrada 

Sandstone 

Lyons Minnekahta 

Ss Opeche 

Owl Canyon Fm 

Ingleside 

Formation 

Fountain 

Formation 

Oil Gas Possible source rock in Park basins 

Figure 2. Stratigraphic column of Colorado Park basins showing source rock and reservoir potential. After 

U. S. Geological Survey (1995). 

Niobrara 

Fm 

Benton 

Shale 

Dakota 

Sandstone 

Coalmont 

Formation 

Pierre 

Shale 

Smoky Hill 

Shale Member 

Codell Ss Mbr 

Middle Shaly Mbr 

Mowry Shale Mbr 

Lykins Shale 

NE Colorado 

SE Wyoming 

Dawson Arkose 

Pierre 

Shale 

Smoky Hill 

Shale Member 

Niobrara 

Fm 

Ft. Hayes Ls Mbr Ft. Hayes Ls Mbr 

Upper Member 

Lower Member 

Benton 

Group 

Dakota 

Group 

Denver 

Formation 

Arapahoe and 

Laramie Fms 

Fox Hills Ss 

Codell Sandstone 

Carlile Shale 

Mowry Shale 

Muddy Sandstone 

Skull Creek Shale 

Fall River Ss 

Lakota Ss 

Goose Egg Fm 

Madison 

Ls

A A' 

SW NE 

0 2 mi 

Scale 

Tc 

Ku 

Kn 

Kl & J 

TR 

pC 

Lone Pine Butler Creek North McCallum Battleship 

Possible 

fracture 

Coalmont Formation 

Alluvial / fluvial sandstone and shales 

Pierre Shale 

Marine sandstones and shales 

Niobrara Formation 

Chalk and shale 

Dakota Grp, Morrison Fm & Entrada Fm 

Marine and nearshore sandstone and shale 

Chugwater Formation 

Red shales 

Precambrian rocks 

Crystalline basement 

Explanation 

Fault 

showing relative movement 

Contact 

Unconformity 

Well 

Oil and gas 

Producing zone 

Figure 3. Generalized cross section of North Park basin, Colorado. After Lange and Wellborn (1985). 

Park Range 

Lone 

Pine 

5000 

5000 A 

Coalmont 

0 

? 

0 

Walden syncline 

0 

Battleship 

Spring Creek fault zone 

(-5000) 

5000 

Medicine Bow Mountains 

0 

A' (Seismic Line) 

5000 

North Park syncline 

Location of Section 

0 20 mi 

Syncline 

Scale 

Coalmont 

Canadian River 

North McCallum 

Front Range 

Thrust fault Oil or gas field

B 

W 

T 

K 

K 

K & J 

Amoco 

State of Colorado 

#1 

Approximate top of 

overpressured 

basin-centered gas 

South Park Formation 

Pierre Shale 

Apache Creek Sandstone 

Dakota Ss & Entrada Ss 

Amoco 

Reinicker Ridge 

#1 (projection) 

South Park Thrust 

San Isabel Thrust 

Reinicker Ridge Thrust-Hayden Lineament 

Explanation 

Precambrian crystalline basement 

Figure 4. Generalized cross section B-B' of South Park basin, Colorado. After Savant Resources (1999). 

Pz 

pC 

Hunt Tarryall 

Federal #1-17 

NE NE 17-10S-75W 

Undifferentiated Paleozoic rocks 

Fault, showing 

relative movement 

Gas-charged unit 

Elkhorn Thrust 

Upper Thrust Sheet 

probable gas charge 

(hanging wall of the 

San Isabel Thrust) 

Middle Thrust Sheet 

known gas charge 

(hangingwall of the 

South Park Thrust) 

0 2 mi 

Scale 

B' 

E 

Well 

12,000 

8,000 

4,000 

Sea Level 

-4,000 

-8,000 

-12,000 

-16,000 

-20,000 

Gas production 

Elevation in Feet


The Permian Basin of west Texas and eastern New Mexico covers about 76,250 square miles of the southwest 

part of the North American mid-continent craton (Frenzel et al., 1988). Figure 1 shows the location and generalized 

structure of the area. This part of the craton remained exposed until Late Cambrian, when marine transgression 

formed the Tobosa Basin and filled it mainly with carbonate and fine-grained clastic sediments. The Tobosa Basin 

was relatively stable until the Late Mississippian, when structural deformation began forming the Pecos Arch and 

Matador, Central Basin and Diablo Uplifts. By the Early Pennsylvanian, the Tobosa Basin had broken up into the 

main elements making up the present day Permian Basin: Northwest Shelf, Delaware Basin, Central Basin Platform, 

Midland Basin, Val Verde Basin, and Eastern Shelf (Frenzel et al., 1988). Pennsylvanian strata of the basin consists 

of marine and paralic sandstones, shales, and carbonates. 

A final structural pulse deformed the Central Basin and Diablo Platforms in the Early Permian (Wolfcampian). 

Permian sedimentation filled the Delaware and Midland Basins with deep-water carbonates and shales, basin-margin 

reef carbonates, evaporites, and red-bed sequences. Permian strata contain most of the hydrocarbon reserves within 

the basin. Since the Triassic, the Permian Basin has remained tectonically stable. 


Figure 2 shows stratigraphic columns for various basins and platforms in the area. Originally assigned to a 

Permian (lower Leonardian) red-bed sequence in the Northwest Shelf, the Abo Formation now includes dolomitized 

carbonates along the northern margins of the Delaware Basin and the Central Basin Platform. The age-equivalent 

Wichita-Albany strata in the Central Basin Platform and in the Delaware and Midland Basins has produced 

hydrocarbons historically. In the Midland Basin, the age-equivalent and mature Spraberry Trend covers hundreds of 

square miles and has produced over 1,388 BCF of gas plus associated condensate (Bebout and Garret, 1989). 

Abo Formation production derives from two plays: platform carbonates and fluvial/deltaic sandstones. Most 

platform-carbonate production comes from the Abo reef trend (Figure 1). The reef reservoirs are stratigraphic traps 

with clean, white-tan-gray, fine to coarsely crystalline dolostones. Porosity is secondary, consisting of vugs, vertical 

fractures and intercrystalline pores. Cumulative production from the reef reservoirs was 456 BCF as of December 

31, 1990. A smaller shelf sub-play also exists, and consists of dolomitized back-reef sediments having irregularly 

distributed porosity and permeability. Traps are low-relief anticlines that have produced 227 BCF through 1990. The 

Abo fluvial/deltaic sandstone is a tight gas play on the Northwest Shelf. Production comes from lenticular, red, very 

fine to fine grained, silty, arkosic arenites (Broadhead, 1993). A clay-hematite matrix has reduced the primary 

porosity. Deep-seated faults that tap into older Paleozoic source beds have charged these reservoirs. The three main 

fields have produced 273 BCF from stratigraphic traps as of December 31, 1990. 

1


Neither of the two Abo plays are basin-centered. The carbonate play rings the Permian basin margin, and the 

sandstone play is confined to the northern Northwest Shelf area (Figure 3). However, both plays have anomalous 

pressure gradients associated with them. The fluvial/deltaic sandstones show a significant underpressure to 

producing fields. The single shelf-carbonate sub-play field has a normal pressure gradient. Abo reef carbonates 

display a trend: near-normal pressure gradients exist in the south and become underpressured northward. Similar 

south-to-north underpressure gradients are visible in data from the underlying Wolfcamp Formation, overlying Yeso 

Formation, and basinal-equivalent Bone Spring Formation. 

2 

Unit or Lithology Depth (ft) Pressure Gradient (psi/ft) Temperature (°F) 

Yeso Fm..................................5,000 – 7,030.................. 0.263 – 0.495..........................105 – 122 

Bone Spring Fm........................5,480 – 9,700.................. 0.343 – 0.428..........................128 – 180 

Abo sandstones.........................2,830 – 4,180.................. 0.295 – 0.387..........................101 – 114 

Abo reef carbonates...................6,020 – 8,650.................. 0.286 – 0.430..........................109 – 140 

Wolfcamp Fm ......................... 8,020 – 13,250................. 0.354 – 0.843..........................129 – 193



Geologic 


Accumulation: 


Southwestern U.S., west Texas and eastern New Mexico. Lower Permian 

Abo Formation 

a. Source/reservoir Source intervals: poorly documented and appear to be largely speculative in 

the literature. Major sources are thought to occur in Permian basinal shales 

and carbonates (Wolfcamp and Bone Springs), Permian shelf shales 


(TOCs) 

and low energy carbonates (Wolfcamp and Abo/Wichita-Albany), 

Pennsylvanian limestones and shales, and Upper Devonian 

(Woodford)–Mississippian (Barnett) shales (Broadhead, 1993; Hanson et al., 

1991). 

Reservoir intervals: Abo platform carbonates are mainly dolomite, Abo 

fluvial/deltaics are mainly red-bed sandstones. 

1-3% for Midland Basin Spraberry black shales (Ramondetta, 1982) 

c.Thermal maturity Kerogen Type: algal and amorphous for Midland Basin Spraberry black 

shales (Ramondetta, 1982) 

d.Oil or gas prone both oil and gas prone 

e.Overall basin maturity considered mature along with adjoining basins in the southern U.S. 

f.Age and lithologies Permian Abo platform carbonates-lower Leonardian, Permian Abo 

fluvial/deltaic sandstones-lower Leonardian (Broadhead, 1993). 

g. Rock extent/quality Source rock occurs basin wide, Abo platform carbonate reservoir rock has a 

distribution which follows the margin of the Delaware and Midland Basins 

and the Central Basin Platform, Abo fluvial/deltaic sandstones are found 


north of the barrier reef trend on the Northwest Shelf. 

i.Major traps/seals Abo platform carbonates: anticline/dome and lateral changes in porosity 

and/or permeability because of changes in depositional environment; Abo 

fluvial/deltaic sandstones: stratigraphic trap, but poorly understood 

j.Petroleum 


models 

(Broadhead, 1993). 

Barber (1979) 

k.Depth ranges Abo platform carbonates, 6020-8650 ft; Abo fluvial/deltaic sandstones, 2830- 

4180 ft (Broadhead, 1993) 




Economic 


Fields/ 

Reserves 

a. Important 



Cumulative 

Gas (BCF) 

Abo platform carbonates: Brunson South, Corbin, Empire, Lovington, 

Skaggs, Vacuum, Vacuum North, Wantz, and Kingdom 

Abo fluvial deltaic sandstones: Pecos Slope West, Pecos Slope South, and 

Pecos Slope 

a. High inert gas content Abo fluvial/deltaic sandstones: CH4-86.6%, C2H6-4.8%, all other CxHx- 

3.4% N2-5.22%, CO2-0.03% (Petroleum Information, 1983). 

Composite Abo data: CH4-84.0%, C2H6-4.7, all other CxHx-3.9%, CO2- 

0.2%, N2-6.6%, He-0.2% (Hogman et al., 1993) 

b.Recovery 



e.Basin maturity mature 

Number of 

Wells 

Abandoned 

Wells 

Spacing 

(acre) 

Brunson South..........................129.1......................165............ .............12........... .............40 

Corbin.....................................20.2.......................33............ .............10........... .............40 

Empire....................................293.6......................391............ .............47........... .............40 

Lovington.................................13.0.......................26............ .............43........... .............40 

Skaggs.......................................7.0.........................6............ ...............2........... .............40 

Vacuum...................................129.2......................134............ .............45........... .............40 

Vacuum North...........................40.8......................284............ ............115........... .............80 

Wantz......................................50.5......................144............ ............112........... .............40 

Kingdom..................................51.0......................184............ ............................ .............40 

Pecos Slope West.......................21.4......................170............ .............18........... ...........160 

Pecos Slope South .....................20.5......................107............ ...............4........... ...........320 

Pecos Slope.............................230.8......................603............ .............11........... ...........160

f.Sediment consolidation good to moderate consolidation 


problems 

h.Permeability 0.0067 md 

i.Porosity 12 to 14% 

Abo fluvial/deltaic sandstones are classified as tight gas. These reservoirs 

require acidization and artificial fracturing. Average in-situ permeability is 

0.0067 md; average porosity is 12-14% with 9% necessary for economic 

production. Production operates on a pressure depletion/gas expansion drive. 

Abo platform carbonates have an irregular distribution of secondary porosity, 

averaging 6-14% but ranging from 1.5-18.3%. Permeability also has an 

an irregular distribution resulting in poor fluid communication within the 

reservoir. Permeability averages 1.5-25 md but ranges from 0.1-1,970 md. 

This play operates on a primary gas-cap expansion drive augmented by 

secondary gas-cap growth due to pressure dissolution (Broadhead, 1993). In 

the Empire field some component of water drive may be operating (LeMay, 

1972).

New Mexico 

Texas 

Huapache 

Flexure 

Van Horn 

Dome 

Back Reef 

Chaves 

Eddy 

Fore Reef 

Delaware Basin 

Marathon 

Roosevelt 

Lea 

Thrust Belt 

Northern 

Platform 

Central Basin Platfo r m 

Russell 

Brown 

West 

Seminole 

Matador Uplift 

Horseshoe Reef 

Midland 

Basin 

Fore Reef 

Reagan 

Uplift 

Midland Basin Eastern Shelf 

Basin 

Basin 

Fore reef 

Diablo 

Platform 

Empire 

Fore Reef 

Loco 

Hills 

Northwest Shelf 

Ropes 

Corbin 

Lovington 

Vacuum 

Reef 

Back Reef 

Jones 

Ranch 

Brumley 

(Abo) 

West Anton 

Fore 

Ownby 

Wasson 

Reef 

Prentice 

Reef, with trend and 

dip direction; dashed 

where approximate 

Petroleum field, 

with field name 

Ropes 

West 

Lubbock 

(Abo) 

Southeast 

Garden City 

Interbedded sandstone, 

shaly limestone, and 

shale 

Interbedded shaly 

limestone, dolomite, 

and sandstone 

Fore 

Reef 

Back Reef 

Back Reef 

Back Reef 

Marvin 

(Abo) 

Eastern Shelf 

0 50 mi 

Massive dolomite 

and some limestone 

Interbedded shelf 

dolomite, anhydrite, 

and green & gray shale 

Anticline 

Monocline, with 

direction of dip 

Figure 1. Location map and generalized cross section of Permian Basin, west Texas and southeast New Mexico. Map 

shows Abo-Wichita-Albany Reef trend in the Permian Lower Leonard series. From Wright (1979).

System 

Quaternary 

Tertiary 

Cretaceous 

Triassic 

Permian 

Pennsylvanian 

Mississippian 

Devonian 

Silurian 

Ordovician 

Cambrian 

Series or Stage Delaware Basin 

Precambrian 

Recent 

Pleistocene 

Pliocene 

to 

Eocene 

Dockum 

Dockum 

Gulfian 

Comanchean Fredericksburg Ls Fredericksburg Ls 

Washita 

Fredericksburg Ls 

Trinity Paluxy ss Trinity Paluxy ss Trinity Paluxy ss 

Upper 

Santa Rosa 

Chinle 

Santa Rosa 

Tecovas 

Chinle 

Santa Rosa 

Tecovas 

Chinle 

Santa Rosa 

Tecovas 

Dewey Lake Dewey Lake Dewey Lake Dewey Lake 

Ochoan 

Rustler 

Salado 

Castile 

Rustler 

Salado 

Rustler 

Salado 

Rustler 

Salado 

Lamar 

Tansill 

Tansill 

Tansill 

Bell Canyon 

Yates 

Yates 

Yates 

Seven Rivers Seven Rivers 

Seven Rivers 

Guadalupean 

Cherry 

Canyon 

Queen 

Grayburg 

Queen 

Grayburg 

Queen 

Grayburg 

Brushy 

San Andres 

San Andres 

San Andres 

Canyon 

Glorieta 

Glorieta 

San Angelo 

Cutoff Member 

1st B. Spg. Sand 

U. Clear Fork 

Tubb Sand 

L. Clear Fork 

Paddock 

Blinebry 

Tubb 

Drinkard 

Upper 

Leonard 

Leonardian 

U. Spraberry 

2nd B. Spg. Sand 

Wichita Abo 

L. Spraberry 

3rd B. Spg. Sand 

Dean 

Wolfcampian 

Virgilian 

Missourian 

Desmoinesian 

Atokan 

Morrowian 

Chesterian 

Meramecian- 

Osagean 

Kinderhookian 

Upper 

Middle 

Lower 

Upper Niagaran 

Lower Niagaran 

Alexandrian 

Cincinnatian 

Mohawkian 

Chazyan 

Canadian 

Ozarkian 

Upper 

Delaware 

Mountain Group 

Bone Spring 

Simpson 

Alluvium Alluvium 

Wolfcamp 

Cisco 

Canyon 

Strawn 

Atoka 

Morrow 

Central Basin 

Platform 

Word Whitehorse 

Dockum 

Clear 

Fork 

Ogallala Ogallala Ogallala 

Husco 

Wolfcamp Wolfcamp Wolfcamp 

Bursum 

Cisco 

Canyon 

Strawn 

Atoka 

Whitehorse 

Word 

Yeso 

Northwest 

Shelf 

Alluvium Alluvium 

Cisco 

Canyon 

Strawn 

Atoka 

Morrow 

Capitan 

Goat 

Seep 

Midland Basin 

Whitehorse 

Word 

Clear 

Fork 

Wichita 

Cisco 

Canyon 

Strawn 

Atoka 

Barnett Shale Barnett Shale Barnett Shale U. Mississippian Ls 

Mississippian Ls 


Kinderhook Kinderhook 

Woodford 

Woodford 

U. Silurian Shale 

Fusselman 

Montoya 

Bromide 

Tulip Creek 

McLish 

Oil Creek 

Joins 

Ellenburger 

Simpson 


L. Mississippian Ls 

Kinderhook Kinderhook 

Woodford 

Woodford 

U. Silurian Shale U. Silurian Shale U. Silurian Shale 

Fusselman Fusselman Fusselman 

Montoya 

Bromide 

Tulip Creek 

McLish 

Oil Creek 

Joins 

Ellenburger 

Simpson 

Montoya 

Bromide 

Tulip Creek 

McLish 

Oil Creek 

Joins 

Ellenburger 

Figure 2. Stratigraphic column for west Texas-southeast New Mexico area basins. 

Sylvan Sh 

Montoya 

Bromide 

Tulip Creek 

McLish 

Oil Creek 

Joins 

Simpson 

Ellenburger 

Wilberns 

Hickory

34° 

33° 

32° 

New Mexico 

Texas 

0.430 

105° 104° 103° 15' 

Chaves 

Eddy 

Petroleum field, with 

value indicating 

pressure gradient 

0.367 

0.387 

0.295 

Northwest Shelf 

0.398 

Delaware 

Basin 

0.375 

0.422 

0.369 

0.286 

Roosevelt 

Lea 

0.389 

0.430 

0 20 mi 

Figure 3. Map showing pressure gradients by field for the Abo platform-carbonate and fluvial/deltaic sandstone plays, 

southeast New Mexico. Modified from New Mexico Bureau of Mines and Mineral Resources (1993).


The Raton basin straddles the Colorado-New Mexico state line in southeastern Colorado and 

northeastern New Mexico (Figure 1). The Apishapa Uplift and the Wet Mountains separate the Raton from 

the Denver basin to the north. The Sangre de Cristo Mountains form the western boundary, and the Las 

Animas Arch and Sierra Grande Uplift limit the east and southeast sides (Larsen, 1985). The Cimarron Arch 

separates the Las Vegas subbasin from the main part of the basin. The Raton displays an arcuate shape and 

asymmetric profile–its western flank dips steeply and is highly faulted. Figure 2 shows the post-Paleozoic 

stratigraphy for the basin; most rocks with hydrocarbon content are Cretaceous in age. 

The Raton is the southernmost basin formed during the Laramide orogeny of late Cretaceous to early 

Tertiary time. Initial Laramide uplift added coarse-grained siltstones, sands and sandy shales to the upper 

Pierre Shale and lower Trinidad Sandstone stratigraphy (Figures 2 and 3) (Stevens et al., 1992). The 

stratigraphic succession includes rocks from Precambrian to Miocene and Quaternary ages, but Cambrian 

through Silurian rocks are absent (Figure 2). A thin Devonian through Mississippian section rests directly 

on basement rocks. Gromer (1982) notes Raton sediments probably thicken to 25,000 ft at the western edge 

of the basin. The southern part of the basin does not contain late Cretaceous or Tertiary coal bearing strata. 

Intrusive activity began during the Eocene and continued throughout the Oligocene. In the immediate 

Spanish Peaks area, two stocks and radial dike swarms intruded the country rock. East-northeasterly trending 

dikes intruded an area east of the Spanish Peaks (Larsen, 1985). Other igneous bodies include late Tertiary 

and Quaternary basalt and andesite flows derived from the Raton volcanic field on the southeastern margin of 

the basin (Larsen, 1985). The plutonic and volcanic activity all contributed to thermal maturation of 

hydrocarbon source rocks. 


Aside from coalbed methane produced from the Vermejo and Raton coals within the past few years, no 

other commercial hydrocarbon production has occurred. Dolly and Meissner (1977) estimated these coal beds 

alone generated more than 20 trillion ft 3 of gas. 

Zones that have oil and gas shows include the Trinidad Sandstone, Pierre Shale, Niobrara chalks and 

shales, Benton Group (Graneros Shale, Greenhorn Limestone, Carlile Shale and Codell Sandstone), and 

lower Cretaceous Dakota Sandstone (Figure 2) 


Evidence that a basin-centered gas accumulation might exist within the Raton Basin includes the 

following: 

1 

1) a widespread resistivity anomaly pattern in the Trinidad Sandstone (Figure 4). Maximum resistivities 

in the Raton Sandstone increase with burial depth and near volcanic centers; 

2) extensive underpressuring (Dolly and Meissner, 1977); 

3) abundant gas shows found in wells drilled throughout the basin; and 

4) vitrinite reflectance (Ro) reaches a maximum of 1.5, indicating thermal maturity. Figure 5 shows 

Ro isopleths for the Raton Basin.



Geologic 


Accumulation: 


Rocky Mountain, Raton Basin, early to late Cretaceous 

a. Source/reservoir Cretaceous Dakota Sandstone and Pierre Shale through lower Paleocene 

Raton formation 


(TOCs) 

2.95% in the Trinidad area, 1.34-2.43% in the Raton area, 0.3 and 5.37% at 

Huerfano Park, west of Walsenberg (Sharon Springs member of the Pierre 

Shale) (Gautier et al., 1984) 

c.Thermal maturity Ro = 1.5% near the center of the basin to 0.7% near the southern, eastern 

and northern basin margins, along the Trinidad Sandstone outcrop (vitrinite 

values from Vermejo coals) 


e.Overall basin maturity thermally mature; immature stage of exploration 

f.Age and lithologies early to late Cretaceous and early Paleocene; Graneros Sh, Greenhorn Ls, 

Carlile Sh, Niobrara Chalk/Shale/Marl, Pierre Sh, Trinidad SS, Vermejo and 

Raton shales, sands and coals 

g. Rock extent/quality apparent basin-wide source and reservoir-rock distribution 

h.Potential reservoirs Trinidad SS, Pierre Sh, Niobrara Chalk/Sh/ Marl, Codell Sh 

i.Major traps/seals Pierre Shale, Vermejo Fm 

j.Petroleum 


models 

in situ generation of gases from intermixed source rock (coals, shales and 

chalks)/reservoir rock facies. Weimer’s Denver basin “cooking pot” model 

may be applied in this basin as well (Weimer, 1996) 

k.Depth ranges 5000+ ft Trinidad sandstone in the center of the basin to 1500 ft on the 

eastern flank. Dakota Sandstone is ±15,000 ft in the center 

l.Pressure gradients underpressured at shallow levels, Trinidad and upper Pierre = 0.33 psi/ft; 

Raton Formation (1630-1760 ft) = 0.25 psi/ft in the northern part of the 

basin. Possible deep overpressure in Dakota-Niobrara?



Economic 


a. Important 


b.Cumulative production none 

no producing fields except for shallow Raton & Vermejo coal-bed methane 

development 

a. High inert gas content the chemical content of the coal gases should approximate that expected 

from nearby underlying rocks. Heating value of the Raton & Vermejo coal 

gases range from 997-1272 btu/cu ft, with nitrogen ranging from 0.1 – 0.8%. 

Carbon dioxide content ranges from 0 – 1.1% (Scott, 1993) 

b.Recovery No current commercial gas production exists except from coal seams 

c.Pipeline infrastructure Currently poor, but will be developed with increasing coalbed methane 

drilling 

d.Overmaturity Probably none, based on Vermejo vitrinite reflectance data 

e.Basin maturity Most of the basin is mature. The outcrop of the Trinidad sandstone appears 

to fall within the 0.7-0.8 Ro (Vermejo coals) range. 

f.Sediment consolidation consolidation/porosity reduction occurs with depth of burial, especially in the 

Niobrara Chalk (Pollastro and Martinez, 1985) 


problems 

Chalks & other tight (low permeable rocks) have potential to produce where 

they are naturally fractured (Florence-Canon City Field to the north in the 

Canon City Embayment). Low pressures and water sensitive clays may 

cause additional evaluation problems (Dolly and Meissner, 1977). 

h.Permeability Trinidad sandstone=less than 0.1 to 344 md, shales and chalks=less than 1.0 

md 

i.Porosity Trinidad sandstone=12%; shales and chalks highly variable

R 71 W R 69 W R 67 W R 65 W R 63 W R 61 W 

Cuchara 

Costillo Co. 

Las Animas Co. 

Colfax Co. 

Taos Co. 

100 

125 

75 

Stonewall 

100 

125 

North Pontil Creek 

Huerfano River 

La Veta 

100 

| 

| 

125 

| | | | 

| | | | | 

100 

CIMARRON 

75 

125 

150 

150 

125 

125 

100 

| 

100 

200 175 

150 

Casa Grande 

200 

200 

200 

150 

150 

175 

150 

Cucharas 

150 

150 125 

125 

125 

Vermejo River 

100 

CO 

NM 

0 5 

Data point 

Scale 

N 

10 mi 

Explanation 

Isopach (in feet); dashed where 

approximated 

Contour interval = 25 feet 

Figure 1. Isopach of Trinidad Sandstone in Raton Basin (using gamma ray cut-off value of 

70-80 API units). After Advanced Resources International, 1992. 

River 

WALSENBURG 

Colfax 

Lyon 

Ludlow 

Koehler 

Huerfano Co. 


Apishapa 


150 

Purgatoire 

TRINIDAD 

RATON 

River 

Vermejo/Trinidad Contact 

COLORADO 

NEW MEXICO 

River 

Barela 

T 27 S 

T 29 S 

T 31 S 

T 33 S 

T 35 S 

T 32 N 

T 30 N 

T 28 N

ERA AGE STRATIGRAPHY LITHOLOGY THICKNESS RESERVOIR SOURCE 

CENOZOIC 

MESOZOIC 

Anhydrite 

Marlstone 

Limestone 

RECENT 

PLEISTOCENE 

PLIOCENE 

MIOCENE 

OLIGOCENE (?) 

EOCENE 

PALEOCENE 

CRETACEOUS 

JURASSIC 

TRIASSIC 

Niobrara 

Fm 

Benton 

Fm 

Alluvium, Dunes 

Landslide Deposits, 

Soil Zones 

Ogallala Fm 

Devil's Hole Fm 

Volcanic Intrusions, 

Plugs, Dikes, Sills 

Farasita Fm 

Huerfano Fm 

Cuchara Fm 

Poison Canyon Fm 

Raton Fm 

Vermejo Fm 

Trinidad Ss 

Pierre Sh 

Smokey Hill Marl 

Fort Hayes Ls 

Codell Ss 

Carlile Sh 

Greenhorn Ls 

Graneros Sh 

Dakota Ss 

Purgatoire Fm 

Morrison Fm 

Wanakah Fm 

Entrada Ss 

Dockum Group 

PALEOZOIC UNDIVIDED 

5,000 - 10,000 ft 

EXPLANATION 

Shale 

Sandy Shale 

Pebbly Mudstone 

200-500 

Shaly Sandstone 

Sandstone 

Pebbly Sandstone 

Figure 2. Columnar section of post-Paleozoic rocks in the Raton basin. After Rose et al. (1986), and 

Dolly and Meissner (1977). 

0-200 

0-1500 

0-1200 

0-2000 

0-5000 

0-2500 

0-2075 

0-360 

0-255 

1300-2900 

900 

0-55 

0-30 

165-225 

20-70 

175-400 

140-200 

100-150 

150-400 

30-100 

40-100 

0-1200 

PRIMARY SECONDARY 

Gas 

Oil

R 71 W R 69 W R 67 W R 65 W R 63 W R 61 W 

Cuchara 

Costillo Co. 


Colfax Co. 

Taos Co. 

Stonewall 

0.7 

0.8 

| | | 

| 

| | | 

| 

1.2 

North Pontil Creek 


La Veta 

CIMARRON 

1.1 

0.8 

0.7 

0.8 

1.0 

0.9 

0.9 

1.4 

1.5 

Casa Grande 

1.4 

1.3 

1.2 

1.1 

1.0 

Cucharas 

1.2 

1.1 

0.9 

1.0 

Vermejo River 

Apishapa 

1.0 

0.9 

0.8 

CO 

NM 

0 5 

Scale 

N 

10 mi 

Explanation 

Measured R0, corrected to Basal Kv 

Measured R0, uncorrected 

Calculated R0 (R0 vs. Vm), corrected 

T 27 S 

T 29 S 

T 31 S 

T 33 S 

T 35 S 

T 32 N 

T 30 N 

T 28 N 

Calculated R0 (R0 vs. Vm), uncorrected 

Isopleth; dashed where 

approximated 

Contour interval = 0.1% R0 

Figure 5. Isopleth of vitrinite reflectance in Raton Basin, adjusted to basal Vermejo 

Formation. After Advanced Resources International, 1992. 

River 

WALSENBURG 

Colfax 

Lyon 

Ludlow 

Koehler 

Huerfano Co. 



1.2 

Purgatoire 

TRINIDAD 

RATON 

River 

Vermejo/Trinidad Contact 

COLORADO 

NEW MEXICO 

River 

Barela

SW NE 

Vermejo 

Fm. 

Trinidad 

Sandstone 

Pierre 

Shale 

"High Energy" Sandstone 

Deltaic Sediments 

Siltstone 

Shale 

Delta No. 1 

Sea Level 1 

Coastal Swamps 

Distal Silty Zone 

Pro-delta Shales 

Delta No. 2 

Sea Level 2 

Figure 3. Cross section showing Trinidad Sandstone depositional environments in the Raton basin. After Rose et al. (1986). 

Vermejo 

Fm. 

Trinidad 

Sandstone 

Pierre 

Shale 

200 ft. 

100 ft. 

Datum: Interpreted sea level during deposition of Delta No. 1 

0

R69W R68W R67W R66W R65W 

Huerfano Co. 


40 Ω 

50 Ω 

50 Ω 

Trinidad Wet 

40 Ω 

30 Ω 

Postulated Gas Accumulation 

in Low Clay-High Energy 

Trinidad Sands 

Transitional Zone of 

Higher Water Saturation 

and Higher Clay Content 

Trinidad Wet 

Outcrop Boundary of Trinidad Sandstone Isopleth of Average Resistivity in 

Trinidad Sandstone, in ohms 

Outcrop of Tertiary Intrusive Rocks 

Figure 4. Delineation of postulated basin-centered gas accumulation in Trinidad Sandstone. After Rose 

et al. (1986). 

30 Ω 

30 Ω 

Huerfano Co. 


T27S 

T28S 

T29S 

T30S 

T31S 

T32S 

T33S


The late Cenozoic Rio Grande Rift extends from the upper Arkansas Valley near Leadville, Colorado, south 

through central New Mexico and the Big Bend area of Texas into the state of Chihuahua, Mexico (Figure 1) 

(Molenaar, 1996). The rift separates the North American Craton from the Colorado Plateau. Opening of the rift may 

have resulted from clockwise rotation of the Colorado Plateau about an Euler pole located in northeast Utah. 

The rift system developed in terrain elevated during Laramide time because of crustal thickening (Keller and 

Cather, 1994). Initial sedimentation commenced in late Oligocene to early Miocene, with rapid extension beginning 

in middle to late Miocene. Miocene extension in the north-central part of the rift was left-oblique. The amount of 

extension decreases in the southern half of the rift, which expands in width and becomes a series of parallel basins 

with intrarift uplifts and tilted fault blocks. 

The rift contains over thirty named basins (Figure 1), most of which are first-order half grabens; basin 

asymmetry shifts across accommodation zones (Chapin and Cather, 1994). Drilling and geophysical exploration 

continue to reveal and delimit new sub-basins. To date, tentative exploration has focused on two major basins, the 

San Luis in southern Colorado, and the Albuquerque basin in northwestern New Mexico. 

The deepest part of the rift occurs along the east side of the San Luis basin northwest of the Great Sand Dunes 

of southern Colorado. The San Luis basin consists of two half-grabens (the western Monte Vista graben and the 

eastern Baca) with a central horst between them. 

The Albuquerque basin lies between the Sandia and Manzano Mountains to the east and the Ladron and Lucero 

uplifts to the west. The basin contains two half-grabens separated by the northeast-southwest trending Tijeras fault 

zone (Figure 2). The west-dipping northern graben contains a listric fault system (Figure 3); the east-dipping 

southern graben exhibits high-angle normal faults (Figure 4). Pre-existing Precambrian basement structures may 

have controlled Tertiary structures (Russel and Snelson, 1994). 

Basin fill consists of poorly indurated alluvial fans, axial river sands and gravels, playa deposits, eolian dune 

sands, and pyroclastic volcanics of the Santa Fe Group. The San Luis basin contains at least 7,000 ft of fill; 

Mesozoic sediments lie beneath the Tertiary valley deposits. Over 14,000 ft of sediment fills the Albuquerque basin. 

Brister and Gries (1994) reported coal occurrence within the Santa Fe Group in the San Luis basin. 


Most exploration has concentrated on the San Luis and Albuquerque basins. In 1993 Lexam Exploration drilled 

42 gold exploration holes into the east side of the Baca graben at the base of the Sangre de Cristo Mountains; 27 

wells showed oil at depths between 300 and 800 ft.. Several test wells had gas shows within the Santa Fe Group, 

and one well reportedly intercepted coal within the Santa Fe Group. Six of the exploration wells penetrated a 

previously unknown Cretaceous section. Drilling in the Albuquerque basin has taken place in both grabens (Figures 

3 and 4). Of the 60 or so exploratory wells drilled, only two have penetrated the Mesozoic section (Black, 1998). 

Total organic carbon (TOC) content for the Cretaceous shales of the eastern San Luis basin ranges from 1.63 to 

7.31% (Morel and Watkins, 1997). For the Albuquerque basin’s north graben, Broadhead (1998) reported TOC values 

of about 1.4 to 10.1% in the Mancos Shale and 22.3 to 28.9% in the upper Mesaverde coals. 


Possible basin-centered gas might occur within the Cretaceous section of the Baca Graben in the San Luis Basin 

and in the Cretaceous and Jurassic sections of the Albuquerque basin. The areal extent of any potential accumulation 

within the Mesozoic sediments remains unknown. Other basins within the Rockies with a similar Cretaceous 

section such as the Piceance Basin do host basin-centered gas accumulations. 

1



Geologic 


Accumulation: 


Rio Grande Rift (Albuquerque-Santa Fe Rift, Province 023–Molenaar, 

1996), basin-centered gas play in Cretaceous sandstones of San Luis and 

Albuquerque Basins 

a. Source/reservoir Cretaceous shales (Mancos) of San Luis Valley and Albuquerque basins, 

Todilto Limestone additional source in Albuquerque Basin/Dakota in both 

basins with Morrison in Albuquerque Basin. 


(TOCs) 

San Luis Basin: Cretaceous shales of eastern basin, 1.63 to 7.31% (Morel 

and Watkins, 1997). Some coal had been found within the Santa Fe Group 

in the San Luis Basin (Brister and Gries, 1994). 

Albuquerque basin: Mancos shale (north graben) – 1.39 to10.1%, upper 

Mesaverde coals (also north graben) – 22.25-28.85% (Broadhead, 1998). 

c.Thermal maturity San Luis Basin: Modeling by Morel and Watkins (1997) indicated source 

rocks entered oil and gas window 10 to 15 Ma. 

Albuquerque basin: Levels of maturity (LOM) for on basin flanks from 9.0 

to 2.0 (oil window), Cretaceous section of Humble SFP #1 (sec. 18, T6N, 

R1W) from 12.0 to 14.0 (condensate and wet gas). Values from Black 

(1982). 

d.Oil or gas prone both oil and gas prone; type III kerogens limited; type II kerogen found in 

San Luis Basin 

e.Overall basin maturity San Luis Basin: moderate to mature. Albuquerque Basin: mature to 

overmature. Anthraxalite reported in Cretaceous sediments in Humble SFP 

#1 (Black, 1982). Play confined to shallower and less mature basin flanks. 

f.Age and lithologies Cretaceous shales, sandstone for both basins. Albuquerque Basin has 

Pennsylvanian Todilto limestones in addition to Jurassic Morrison and 

Entrada sandstones. 

g. Rock extent/quality Cretaceous section in eastern portion of San Luis Basin (identified primarily 

by geophysical methods (Morel and Watkins, 1997)) is up to 45 mi in length, 

18 mi wide and 3,000 ft thick. The section in the Albuquerque Basin 

appears to be similar to the San Juan Basin. The area where the Cretaceous is 

present extends from T2-3N and 2W-4E (Black, 1982). The section is 

composed of marine shales, marginal marine and fluvial channel sandstones. 

h.Potential reservoirs At the present time there is no hydrocarbon production within either the San 

Luis or Albuquerque Basins. 

i.Major traps/seals Stratigraphic traps within the sandstones are possible. The overlying 

Cretaceous marine shales and thinner shales within the sandstones provide 

seals. Jurassic shales are potential seals within the Albuquerque Basin. 

j.Petroleum 


models 

Structural traps may exist. 

both in-situ and long distance migration 

k.Depth ranges San Luis Basin: 7,000 ft to 17,000 ft; Albuquerque Basin: 5,000 ft to 

12,000 ft



Economic 


l. Pressure gradients Albuquerque Basin – 5,000 ft to 12,000 ft 

a. Important 



a. High inert gas content unknown at present 

b. Recovery 

The Santa Fe Group of the San Luis Basin supports substantial artesian water 

flows. Insufficient pressure data is available for the Mesozoic section. 

c. Pipeline infrastructure gas pipeline infrastructure is non-existent to limited 

d. Overmaturity The deep, central portion of the Albuquerque Basin is overmature. 

Prospective areas will be on the less mature flanks of the basin. The risk of 

overmaturation in the San Luis Basin is unknown. 


f. Sediment consolidation The Santa Fe Group is unconsolidated. The Mesozoic and Paleozoic 

sections are well indurated. 


problems 

h. Permeability unknown 

i. Porosity 8-24% 

There may be parts of the Albuquerque basin which are tightly cemented in 

the Cretaceous. Both basins are likely to have swelling clays within the 

Cretaceous sandstones that will need to be drilled and treated with 

appropriate 

fluids. Fracture stimulation will likely be needed to obtain commercial 

production.

SA 

W 

Mt 

LA 

108° 

Colorado 

Plateau 

UA 

Neogene basin-fill 

deposits 

Cenozoic volcanic 

fields 

E 

MDVF 

AS LJ 

Sc 

Socorro 

O 

MG 

SM 

P 

JM 

Mb 

SJVF 

JVF 

LM 

M 

SD 

T 

106° 104° 

An 

Alamosa 

SL 

TMVF 

PV 

LVF 

Mo 

Santa Fe 

Albuquerque 

Las Cruces 

El Paso 

H 

SBVF 

S 

EC 

Colorado 

Great 

Plains 

New Mexico 

TPVF 

BG 

Pr 

R 

Chihuahua 

Coahuilla 

0 50 100 mi 

0 100 200 km 

Scale 

Texas 

Figure 1. Map of southern Colorado, New Mexico, and western Texas showing Cenozoic volcanic fields and 

basins of the Rio Grande rift. After Keller and Cather (1994). 

Okla 

38° 

36° 

34° 

32° 

30° 

UA 

An 

PV 

SL 

Mo 

E 

SD 

A 

Sc 

LJ 

AS 

SA 

O 

MG 

SM 

Mt 

W 

LA 

P 

T 

JM 

Mb 

M 

LM 

H 

S 

EC 

Pr 

BG 

R 

TMVF 

SJVF 

LVF 

JVF 

MDVF 

SBVF 

TPVF 

Basins 

Upper Arkansas 

Antero 

Pleasant Valley 

San Luis 

Moreno 

Española 

Santo Domingo 

Albuquerque 

Socorro* 

La Jencia* 

Abbe Springs** 

San Agustin 

Oscura 

Milligan Gulch 

San Marcial 

Monticello 

Winston 

Las Animas 

Palomas 

Tularosa 

Jornada del Muerto 

Mimbres 

Mesilla 

Los Muertos 

Hueco 

Salt 

El Cuervo 

Presidio 

Black Gap 

Redford 

Volcanic Fields 

Thirtynine Mile 

San Juan 

Latir 

Jemez 

Mogollon-Datil 

Sierra Blanca 

Trans-Pecos 

* The Socorro and La Jencia basins and 

the intervening Lemitar Mountains 

comprise the early rift Popotosa basin 

** Also termed northern Milligan Gulch basin

D 

U 

N 

Ladron 

Uplift 

Lucero 

Uplift 

Fault scarp 

Rio Grande 

Master Fault 

Normal fault; U indicates upthrown block, D indicates downthrown block 

Fault; arrows indicate direction of displacement 

Intersection of Rio Grande fault with the north face of the block diagram 

Anticline, showing direction of axis 

Strike and dip direction 

Explanation 

Figure 2. Generalized structure model of the Albuquerque Basin showing opposing structural asymmetry of the 

north and south halves of the basin and the controlling master normal faults. After Russell and 

Snelson (1990); Rowley (ARCO, unpublished isostatic residual gravity map); and May and Russell 

(1994). 

D 

U 

Joyita 

Uplift 

Sandia 

Uplift 

Manzano Uplift 

Jeter — Santa Fe — Coyote Master Fault 

Tijeras 

"Transfer" Fault

Feet 

10,000 

5,000 

Sea Level 

-5,000 

-10,000 

-15,000 

-20,000 

-25,000 

-30,000 

-35,000 

W E 

Colorado 

Plateau 

Santa Fe 

Fault 

Laguna 

Bench 

Shell 

Laguna 

Cenozoic rift fill* 

North Graben Block Albuquerque 

Eastern Stable 

Bench 

Block 

Shell 

Rio Grande 

Fault 

Transocean 

Rio Puerco West Mesa 

Fault 

Isleta-2 

Rio Grande 

Isleta-1 

Hubbell Springs 

Fault 

Manzanita 

Mountains 

0 5 10 mi 

Mesozoic sedimentary rocks Oil or gas well 

Paleozoic sedimentary rocks 

Precambrian crystalline rocks 

LT 

Scale 

* Pre-rift lower Tertiary section 

(LT) indicated where discernible 

in wells or from seismic data. 

Figure 3. West-east cross section of the North Graben Block, Rio Grande Rift zone, New Mexico. After Russell and Snelson (1994). 

Feet 

10,000 

5,000 

Sea Level 

-5,000 

-10,000 

-15,000 

-20,000 

-25,000 

-30,000 

-35,000

Feet 

10,000 

5,000 

Sea Level 

-5,000 

-10,000 

-15,000 

-20,000 

-25,000 

-30,000 

-35,000 

W E 

Colorado 

Plateau 

Lucero Uplift 

? 

Comanche 

Fault 

⊕ 

Cenozoic rift fill* 

Rio Puerco 

Block 

Cat Mesa 

Fault 

Santa Fe 

Fault 

Mesozoic sedimentary rocks 

Paleozoic sedimentary rocks 

Precambrian crystalline rocks 

South Graben Block Albuquerque 

Eastern Stable Block 

Bench 

Humble Santa Fe & 

Pacific-1 

Rio Puerco 

Rio Grande 

Hubbell Springs 

Fault 

Manzano Mountains 

0 5 10 mi 

Figure 4. West-east cross section of the South Graben Block, Rio Grande Rift zone, New Mexico. After Russell and Snelson (1994). 

⊕ 

Montosa 

Fault 

Scale 

Oil or gas well 

⊕ 

Estancia 

Basin 

Fault motion into plane of section 

Fault motion out of plane of section 

* Pre-rift lower Tertiary section 

indicated where discernible 

in wells or from seismic data. 

Feet 

10,000 

5,000 

Sea Level 

-5,000 

-10,000 

-15,000 

-20,000 

-25,000 

-30,000 

-35,000


The present day Sacramento and San Joaquin Basins lie within California’s northwest-southeast trending Great 

Valley, between the Sierra Nevada Range on the east, the Coast Ranges on the west, the Klamath Mountains to the 

north, and the Tehachapi and San Emigdio Mountains on the south (Figure 1). The Stockton Arch separates the 

Sacramento from the adjoining San Joaquin basin to the south. 

Structural development began in late Jurassic time as a forearc basin formed between the Sierra highlands on the 

east and a wedge of Franciscan rock to the west. In early Cretaceous time, the basin began to fill with deep water 

sands and shales. By the late Cretaceous, delta-slope and turbidite fan systems dominated sedimentation, and the basin 

developed its characteristic asymmetry. The basin deep developed below the break in slope of the forearc’s shelf. 

Structural styles differ across the basin. The eastern flank exhibits high angle normal faults typical of 

extensional faulting of a stable shelf into an adjoining basin. Complex folding and faulting characterize the 

tectonically active western side. The Stockton Arch Fault developed at the close of the Cretaceous period and divided 

the forearc basin into the two present-day subbasins. Continued subsidence during the early Tertiary led to several 

cycles of marine deposits overlain by non-marine sediments. Structural deformation continued throughout the 

Tertiary, especially on the west sides of both basins (Callaway and Rennie, 1991; Montgomery, 1988). 

The Forbes Formation is a mud-rich turbidite fan system that prograded southward along the Sacramento Basin 

axis (Imperato et al., 1990), and has historically had significant oil and gas development. This formation 

unconformably lies over the late Cretaceous Dobbins Shale, and in turn underlies the late Cretaceous Kione Delta 

units and Sacramento Shale (Figure 2). 


Hydrocarbons in the Forbes usually occur in discreet, lenticular stratigraphic traps or in combination structuralstratigraphic 

traps, where structure has concentrated gas. Traps often involve multiple fault blocks with sealing faults 

and can be quite complex. Productive sands have porosities of 30% and permeabilities of 100 md (millidarcies), and 

are usually 15 to 30 ft thick. Stacked sands often allow multiple completions in each well bore. In the northern 

Sacramento Basin, the Forbes generally produces to a depth of 9,000 ft. Permeability decreases with depth, so few 

wells have penetrated the Forbes in the deeper southern half of the basin. One now-abandoned well exceeded 11,000 ft 

depth, but produced only a non-commercial 0.12 BCFG (Callaway and Rennie, 1991; Montgomery, 1988; Weagant, 

1972, 1986; and Zeiglar and Spotts, 1978). 

Overpressure often occurs in the Forbes Fm, and pressure gradients rise as high as 0.8 to 9 psi/ft below 6,000 ft 

depth (Lico and Kharaka, 1983). In some cases, changes in pressure gradients may correlate with hydrodynamic 

gradients or the post-depositional emplacement of magmatic stocks. Overpressure along the west flank of the 

Sacramento and San Joaquin basins may have some relation to structural compression associated with Mesozoic 

subduction and more recent plate movements (Montgomery, 1988; and Weagant, 1972, 1986) 

Shales of the Dobbins, the Sacramento and the Forbes Formation are likely gas sources. Cretaceous shales of 

the Sacramento and northern San Joaquin basins generally contain less than 1.0% total organic content (TOC). The 

organic material is largely humic or non-sapropelic and therefore gas prone. Gas generation in Cretaceous rocks 

probably began at burial depths of 13,000 to 15,000 ft (Figure 3). The “Delta depocenter” in the southern 

Sacramento Basin was probably the major source for gas in this basin and for the gas fields in the northern San 

Joaquin (Zieglar and Spotts, 1978, Callaway and Rennie, 1991). 

1


The northern Sacramento Basin is a dry-gas province, and the Forbes is a major conventional producer in the 

basin. While the overlying Cretaceous Kione and Tertiary sands are also important producers, the Forbes will most 

likely host a basin-centered accumulation. Evidence for such accumulations in the basin include the following: 

2 

1) Cretaceous shales of the Dobbins Forbes Formations are mature in the deepest parts of the Sacramento 

Basin, especially in the Delta depocenter (Zeiglar and Spotts, 1978). 

2) The turbidite fan nature of the Forbes ensures reservoirs encasement within the source shales (Weagant, 

1972, 1986; Montgomery, 1988). 

3) Overpressuring occurs in the Forbes, although hydrodynamics and post-depositional structural movement 

complicate pressure distribution in the formation. A better understanding of pressure distribution in the 

Forbes, especially in the deeper Sacramento Basin would aid in evaluating the potential for the preservation 

of reservoir permeability at depth. (Weagant, 1972, 1986; Montgomery, 1988).



Geologic 


Accumulation: 


Pacific Coast, Sacramento and San Joaquin Basins, Forbes formation 

a. Source/reservoir Dobbins and Sacramento shales and shales of the Forbes formation. 

Reservoirs are turbidite sands of the Forbes. Callaway and Rennie, 1991; 

Zeiglar and Spotts, 1978; Magoon et al., 1996; Weagant, 1972, 1986) 


(TOCs) 

less than 1.0% (Zeiglar and Spotts, 1978) 

c.Thermal maturity Cretaceous shales are gas mature below 13,000 ft. (Zeilar and Spotts, 1978) 

d.Oil or gas prone gas prone (Zeiglar and Spotts, 1978) 

e.Overall basin maturity basin normally mature 

f.Age and lithologies Late Cretaceous shales and sands 

g. Rock extent/quality Forbes present throughout Sacramento Basin; Forbes present in northern half 

of San Joaquin. Reservoir rocks are discontinuous and are distributed 

vertically throughout formation. 

h.Potential reservoirs Conventional production from Forbes; non-conventional, basin centered 

production not established. 

i.Major traps/seals Stratigraphic and combination structural-stratigraphic traps are common. 

Seals include encasing shales and sealing faults. 

j.Petroleum 


models 

Onset of gas generation at burial depths of 13,000 ft.; migration to 

conventional traps over distances of 60-100 miles. (Zeiglar and Spotts, 1978; 

Magoon et al., 1996) 

k.Depth ranges production from conventional reservoirs at depths of 4000 to 9000 ft.; 

deepest completion 11,064-11,144 ft (California Division of Oil, Gas and 

Geothermal Resources, 1997). 




Economic 


a. Important 


Rice Creek, Tisdale, Grimes, Arbuckle, (California Division of Oil, Gas and 

Geothermal Resources, 1997) 

b.Cumulative production Rice Creek, 35 BCFG; Tisdale, 45 BCFG; Grimes, 619 BCFG; Arbuckle, 78 

BCFG (California Division of Oil, Gas and Geothermal Resources, 1997) 

a. High inert gas content Nitrogen is common in the Sacramento Basin; gases are blended to reach 

commercial BTU levels. 

b.Recovery Forbes is currently regarded as a conventional play and operators are 

reluctant to compete zones that appear to have low deliverability/recovery. 

c.Pipeline infrastructure good to excellent 

d.Overmaturity normally mature 

e.Basin maturity normally mature, Tertiary of Sacramento Basin generally not mature 

f.Sediment consolidation normal consolidation with depth 


problems 


i.Porosity 

Forbes is currently regarded as a conventional play, and operators complete 

sands with 10% or greater porosities. Overpressure conditions occur 

throughout the play, but are often related to local structural conditions 

(Weagant, 1972, 1986; Montgomery, 1988).

Map 

Area 

Coast Ranges 

38° 

123° 

Sacramento basin 

Delta depocenter 

Clear Lake 

San Francisco 

Red Bluff 

40° 

122° 

38° 

122° 

Woodland 

Potential basin-centered accumulation Oil or gas field 

Sacramento Basin 

Northern 

Sacramento 

Sierra Nevada 

Sacramento 

Delta 

Stockton 

Arch 

0 20 mi 

Figure 1. Index map of the Sacramento basin and inclusive oil and gas fields, California. After California Division of 

Oil, Gas, and Geothermal Resources W6-1, 2 (1999).

Series Unit 

Upper 

Cretaceous 

Tracy Fm 

Winters 

Formation 

Guinda Fm 

Sites Fm 

HT Shale 

Dobbins Fm 

Funks Fm 

Yolo Fm 

Mokelumne River Formation 

Sacramento Shale 

Kione Formation 

Forbes Formation 

Figure 2. Stratigraphic column for the Sacramento basin, California. After Goudkoff (1945). 

Starkey 

Formation

Depth in Feet 

0 

5000 

10000 

15000 

20000 

25000 

30000 

Cretaceous 

80 60 40 20 0 

Time in MYA 

Eocene 

Paleocene 

Miocene 

Oil generation window Gas generation window 

Figure 3. Lopatin diagram showing stratigraphic reconstructions and oil and gas generation windows for the thickest 

part of the Delta depocenter, Sacramento basin, California. After Zieglar and Spotts (1978). 

100 

200 

300 

400 

500 

Temperature in °F


The Salton Trough is an active rift basin lying within the Imperial Valley at the northern end of the 

Gulf of California (Figure 1). The basin extends about 115 miles in length and 45 miles in width, and 

encompasses an area of 4,500 square miles (Barker, 1995). The rift apparently contains metamorphosed 

sediments, igneous intrusions and rising upper mantle material (Figure 2). The transfer zones between the 

major strike-slip faults may have active rhombic-shaped spreading centers, especially at the southern end of 

the Salton Sea and at Cerro Prieto (Figure 1) (Lonsdale, 1989; and Mueller and Rockwell, 1991). 

Paleogeographic reconstructions show that the Gulf of California opened during middle Miocene time 

and reached its maximum northward extent in the early Pliocene (Smith, 1991). Deltaic and lacustrine 

sediments from the Colorado River filled the northern end of the Gulf of California beginning 5.5 Ma, 

eventually cutting it off from the marine seaway by 4 Ma (Schmidt, 1990). The basin now contains 16,000 

to 20,000 ft of sediments and metasediments, including Miocene to Pliocene-age evaporites, marine and 

continental deposits, and a thick section of Pleistocene to Recent deltaic and lacustrine sediments (Helgeson, 

1968; Muffler and Doe, 1968). Figure 3 shows a general stratigraphic column for the Salton Trough 

(Muffler and Doe, 1968; Lucchitta, 1972). Dibblee (1984), Gibson et al. (1984), and Kerr and Kidwell 

(1991) have described the sedimentary formations exposed in outcrops along the western and eastern flanks 

of the Salton Trough. Mesozoic igneous and metamorphic rocks form the base of the exposed section. 

Above this crystalline basement are alluvial fans and breccias of the Miocene Anza and Split Mountain 

Formations. Interfingered with the Split Mountain is the Fish Creek Gypsum, a formation of gypsum and 

anhydrite that indicates rift basin development began in middle Miocene time. Breccias and marine turbidites 

overlie the evaporite beds and indicate rapid subsidence. The turbidites grade upward and laterally into 

shallow marine shoreline deposits of the Pliocene Imperial and Bouse Formations. These are overlain by 

deltaic and lacustrine sediments deposited by the Colorado River. This basin has continued to subside, and 

recent erosion has not removed any sediments. 

Active strike-slip motion complicates the rift basin geology within the San Andreas, Imperial and 

Cerro Prieto fault zones. Calculated slip rates for the various strike-slip faults in the Salton Trough range 

from 1.7 to 5.4 cm/year (Duffield, 1976; Suarez-Vidal et al., 1991). According to Elders (1979), the Salton 

Trough is one of the most earthquake-prone areas in North America. The basin undergoes active 

deformation, as indicated by movements observed from tiltmeter and survey data. Lippmann and Manon 

(1987) described recent earthquake activity along the Imperial and Cerro Prieto fault zones near Cerro Prieto 

geothermal field. Such seismic activity can potentially disrupt or breach hydrocarbon traps and pressure 

seals, preventing accumulation of hydrocarbons. 


To date, the Salton Trough has no recorded hydrocarbon production.


According to gas sample data from geothermal wells and fumaroles, the main gas expelled in the basin 

is CO 2. Most samples show 80 to 90 wt % CO 2 and only 3 to 5 wt% of hydrocarbon gases. For many 

years a dry-ice factory produced CO 2 from shallow wells near the Salton Sea. 

Thermal gradients and maturity levels vary throughout the basin. In cooler areas, conditions may favor 

generation and expulsion of natural gas. However, Colorado River sediments apparently lack hydrocarbon 

source material. Analyses of deep-well cuttings show small amounts (< 0.5 wt%) of total organic carbon 

(TOC). The only potential source rocks noted in the geologic literature have been minute coal fragments: 

Nehring and D’Amore (1981, 1984) reported dispersed lignite particles in deltaic sediments from a deep well 

(Prian #1) near Cerro Pietro. This coaly material may possibly generate the small amounts of hydrocarbon 

gases found in Cerro Pietro geothermal wells. Published lithology logs and formation descriptions include 

no coal beds or swamp environments in the sedimentary section, so the origin, extent and depositional trend 

of the carbonaceous units remain unknown. The lignite fragments in the Prian #1 well may represent 

allocthonous deposition of Cretaceous coal eroded from the Colorado Plateau. 

Vitrinite reflectance (R o) measurements for several areas in the Salton Trough indicate high thermal 

maturation. Barker (1995) reported an R o of 3% at 13,400 ft in the Chevron Wilson #1 well. Drilled within 

a relatively cool part of the basin, this well had a temperature gradient of only 60 ° C/km. 

Figure 4 shows a plot of vitrinite reflectance versus depth for several wells at the Cerro Prieto 

geothermal field (Barker and Elders, 1981). The graph displays considerable variability in vitrinite gradients 

that probably depends on proximity to a “hot spot.” Some wells show R o ranges from 0.7 to 1.0% at 

depths as shallow as 800 to 3,300 ft. In borehole M-84, vitrinite reflectance ranges from 0.12% at 790 ft 

to 4.1% at 5,580 ft (Barker and Elders, 1981). These data indicate that thermal maturation levels have 

reached or exceeded the wet-gas floor and dry-gas preservation limit (Dow, 1977) at very shallow depths in 

the hot spots. 

Although under-explored parts of the basin may contain undiscovered coal seams or lacustrine shale 

beds with high organic content, the data apparently indicate “normal” pressures at depth throughout the 

section, and observations conclude water has entirely saturated potential reservoir rocks. Thus, all the data 

indicate the Salton Trough probably contains no basin-centered gas accumulation.



Geologic 


Accumulation: 


Pacific Coast Province, Salton Trough, Imperial Valley, normally pressured, 

hydrogeothermal basin. 

a. Source/reservoir emote possibilities in the lacustrine shale beds (Miocene through Recent) and 

dispersed coally beds (Colorado River Recent sediments) 


(TOCs) 

0.09% (Palm Spring formation (Plio-Pleistocene)), 0.2% (Pliocene lacustrine 

and deltaic sediments), and 15 samples from the SSSDP well ranged from 

0.12% to 0.37% (Tmax ranged from 472 to 600) 

c. Thermal maturity Ro = 0.7 to 4.1 at depths from 3280-5576 ft. 

d. Oil or gas prone gas (CO2 is common; very minor concentrations of hydrocarbon gases) 

e. Overall basin maturity very high level of maturation due to post-Miocene hydrogeothermal activity 

f. Age and lithologies Miocene to Recent breccias, turbidites, deltaic and lacustrine deposits 

g. Rock extent/quality source rocks generally lacking, highly variable levels of induration 

throughout the stratigraphic section due to hydrothermal activity 

h. Potential reservoirs Colorado River deltaic and lacustrine (Recent) sediments 

i. Major traps/seals if not compromised by faulting, hydrothermal mineralization throughout the 

stratigraphic section, Pliocene lacustrine deposits, and Miocene Fish Creek 

Gypsum and Anhydrites. 

j. Petroleum 


models 

in-situ generation of dispersed coally material within the Colorado River 

deltaic sediments is a remote possibility; other source rocks are lacking 

k. Depth ranges sediment fill of up to 20,000 ft 

l. Pressure gradients wells drilled at the Salton Sea and Cerro Prieto geothermal fields had 

gradients that ranged from 0.40 to 0.42 psi per ft



Economic 


a. Important 


none 


a. High inert gas content High CO2 (80 to 90 wt%) 

b. Recovery 


d. Overmaturity possible; Ro values range 0.7% to 4.1% 

e. Basin maturity mature to overmature but with low present day geothermal gradient 

f. Sediment consolidation poorly consolidated sediments, except in the vicinity of geothermal 

anomalies where hydrothermal fluids have effectively cemented thousands of 

feet of section 


problems 


i. Porosity 

sediments deposited are mineralogically complex with a variety of clays; 

also problematic are well indurated rocks in geothermal areas

116° W 

Coachella 

Valley 


San Andreas Fault 

Borrego 

Basin 

Salton Sea 

A 

? 

San Jacinto Fault Zone 

Fish Creek 

Basin 

115° W 

Salton Buttes 

Brawley 

Fault Zone 

West 

Mesa 

33° N 116° W 

Primary transform fault 

Seismically active extension 

of transform fault 

Inactive fracture zone or 

fossil transform fault 

Explanation 

Figure 1. Geologic map of Salton Trough in southern California. After Lonsdale (1989). 

A' 

Sand Hills Fault 

California 

Mexico 

Cucapa Fault 

Spreading center 

33° N 

Imperial Fault 

Laguna Salada 

Fault 

Dip-slip extensional faults 

on rifted margin 

Cerro Prieto 

Volcano 

Laguna Salada 

Basin 

Col o r ado R iver 

Arizona 

Mexico 

Colorado Delta 

0 20 km 

Scale 

N 

Cerro 

Prieto Fault 

Basement rock (outcrop) 

Possible extent of 

continental basement 

115° W

Depth in Kilometers 

0 

10 

20 

A A' 

Thinned Continental Margin Newly Accreted "Basement" 

Continental Basement 

(Peninsular Ranges) 

2.9 

2.75 

Alluvial fill with minor 

igneous Intrusions 

Sedimentary fill with minor 

igneous intrusions 

Metamorphosed sediments 

with igneous intrusions 


3.1 

West Mesa 

Brawley Fault 

Zone 

2.3 

3.32 

2.55 

2.65 

Sand Hills Fault 

"Subbasement" 

(igneous crust or modified upper mantle) 

Explanation 

Continental Basement 

Normal Upper Mantle 

Figure 2. Cross section of Salton Trough in southern California. Dashed boundaries are controlled by gravity modeling only. After Fuis et al. (1982) 

and Lonsdale (1989). 

2.75 

Igneous crust or 

modified upper mantle 

Basement rocks 

Estimated density (g/cm 3) 

2.75 

Scale 

0 20 km

System 

Quaternary 

? 

Tertiary 

Pre-Tertiary 

Series 

Holocene 

Pleistocene 

? 

Pliocene 

? 

Miocene 

N S 

Ocotillo Conglomerate 

Canebrake 

Conglomerate 

Mecca Formation 

Sand and gravel 

Subaerial sand, silt, and clay 

Conglomerate 

Lacustrine sediments 

Marine sediments 

Explanation 

Breccia and conglomerate 

Formation 

Brawley Formation 

Borrego Formation 

Palm Spring Formation 

Imperial Formation 

Basement 

Igneous and metamorphic rocks 

Fish Creek Gypsum 

Split Mountain Formation 

Anza Formation 

Figure 3. Generalized stratigraphy of the Salton trough. After Muffler and Doe (1968), and Lucchitta (1972).

Depth in Feet 

0 

2,000 

4,000 

6,000 

8,000 

0.0 

0.5 

x 

x 

x 

x 

x x 

x 

x 

x xx 

M-84 

M-93 

x 

1.0 

1.5 

% Ro (Vitrinite Reflectance) 

x 

x 

2.0 

x x 

xx 

x 

x 

x xx 

x 

x 

x 

x 

x M-94 

Circled data points are from core samples. 

M-105 

All other data points are from cuttings samples. 

Figure 4. Average vitrinite reflectance as a function of sample depth in boreholes M-84, M-93, M-94, and M-105. Third-order polynomial regression curves 

plotted for M-84, M-93, and M-105 indicate the rank profile. After Barker and Elders (1981). 

x 

x 

x 

x 

2.5 

x x 

x 

x 

x 

3.0 

x 

x 

x 

x 

3.5 

4.0 

4.5 

0.0 

0.5 

1.0 

1.5 

2.0 

2.5 

3.0 

Depth in km


The San Rafael Swell is an uplift located on the northwest side of the Paradox Basin in north-central Utah 

(Figure 1). Two sub-parallel rows of southward-facing cliffs, the Book Cliffs and the Roan Cliffs, rim the Swell on 

the northeast, and the Richfield high-plateau volcanic area forms the southeast border. Rocks in the San Rafael Swell 

range in age from Permian through Cretaceous, with Eocene strata exposed to the north as the Swell merges with the 

south limb of the Uinta Basin (Figure 2). Maximum thickness of Phanerozoic sediments on the Swell ranges from 

5,000 to 8,000 feet. 

The Lower Cretaceous in this area includes the Cedar Mountain Formation (Albian), unconformably overlain by 

the Dakota Sandstone (Cenomanian), which is in turn unconformably overlain by the Tununk Member of the 

Mancos Shale (Turonian) (Young, 1960). The Dakota Sandstone, Cedar Mountain Formation, and the underlying 

Buckhorn Member together comprise the Dakota Group. Spieker (1946) designated the entire Cretaceous interval as 

the Indianola Group (Figure 3). 

The Dakota Group rocks derive from formations uplifted and thrusted eastward during the Sevier orogeny 

(Lawton, 1983, 1985; Peterson, 1994). Deposition occurred along the western shore of a Cretaceous seaway that 

traversed the continent from Mexico to the Arctic. Dakota sediments uncomformably onlap the Morrison Formation 

on the west and grade eastward into a marine shale (Figure 3) (McGookey et al., 1972). The Dakota Group represents 

four major stratigraphic sequences which reflect regional base-level fluctuations caused by both tectonics and eustatic 

sea level changes. Multiple unconformities and smaller-scale sequences occur within each megasequence, in response 

to variations in sediment supply, climatic fluctuations and local structural developments (Dolson and Muller, 1994). 

Elder and Kirkland (1964) present a relative sea-level curve and ammonite zonation for the Cenomanian of central 

Utah. 

Peterson (1969) subdivided the Dakota Formation into three lithic units: a lower conglomeratic sandstone and 

shale unit from 0 to 65 ft thick; a middle carbonaceous shale, coal and sandstone unit from 0 to 80 ft thick; and an 

upper marine sandstone unit from 0 to 85 ft thick. The upper unit contains a large and diverse marine molluscan 

faunal assemblage, consisting mostly of bivalves and ammonites (Eaton et al., 1990). Sandstones in the Dakota 

generally thicken and coarsen westward. 

The San Rafael Swell resulted from basement uplift and thin-skinned deformation, where the eastward-verging 

Sevier thrust belt impinged on the nearly horizontal strata of the Colorado Plateau. Exposures on the west flank of 

the Swell show detachment folds occur above a décollement in the Jurassic Carmel Formation, where a fold train lies 

above a thin gypsum layer. These folds developed in response to regional horizontal compression on the west limb 

of the Swell during Paleocene time (Royse, 1996). This décollement represents part of a stratigraphically-controlled 

regional detachment that occupies the east flank of the Jurassic evaporite basin. 

The Swell first became active as a region of reduced subsidence before it developed topographic relief. It began to 

grow in mid-Cretaceous time (about 90 Ma) as a low-relief structural welt in the Rocky Mountain foreland (Perry 

and Flores, 1997). Giuseppe and Heller (1998) compared sections of the Price River Formation (Campanian) to the 

laterally equivalent Farrer Formation and found variations across the swell crest, demonstrating tectonic uplift in Late 

Cretaceous time. 

1

HYDROCARBON POTENTIAL 

In central Utah very little exploration has occurred for Permian, Triassic and Cretaceous reservoirs. The flanks 

of the San Rafael Swell and the Circle Cliffs uplift represent prospective areas for both structural and stratigraphic 

traps (Sprinkel et al., 1997). Known petroleum resources of the area include gas in the Triassic Moenkopi 

Formation, the Cretaceous Ferron and Dakota Sandstones, and the Eocene Wasatch and Green River Formations 

(Figure 4). The Dakota Sandstone and Moenkopi Formation also contain small quantities of oil. Tar sands are 

common in the Moenkopi, and oil shale occurs in the Green River Formation. Weiss et al. (1990), and Bishop and 

Tripp (1993) reported extraction of some tar sands for local use, but the oil shale remains unexploited. 

Dakota Group rocks have yielded more than 2.0 BBOE of hydrocarbons, mostly from stratigraphic traps 

controlled by paleotopography (Dolson and Muller, 1994). The Moenkopi has produced significant quantities of oil 

from the Grassy Trail Creek field in the Swell. 

Nine gas fields exist in the area, in addition to Farnham Dome (carbon dioxide production) and Woodside Dome 

(helium reserves) (Table 1). Two fields, the Flat Canyon and Joe’s Valley, have produced natural gas from Dakota 

Formation reservoirs in the Wasatch Plateau adjacent to the San Rafael Swell. Dakota production may also have 

occurred from the abandoned Miller Creek field near Price, Utah; this field is located on the northwest plunge of the 

Swell. 


Indirect evidence exists for basin-centered hydrocarbons in the giant Altamont-Bluebell field in Uinta basin, 

about 70 mi northeast of Price. Altamont-Bluebell represents an atypical stratigraphic oil field; it contains source 

rock in which conversion of kerogen to oil actively continues at depth in the Green River oil shale. The reservoir 

consists of oil accumulations occurring in naturally fractured, low-porosity Tertiary lacustrine sandstones. Reservoir 

overpressure is high enough to approach lithostatic (Bredehoeft et al., 1994). Lucas and Drexler (1976) believe the 

field may exemplify deep-basin, organic-shale-related, overpressured accumulations. Entrapment is entirely 

stratigraphic on the monoclinal basin flank. Fractures are essential for achieving commercial flow rates. 

Other hydrocarbon evidence includes gilsonite veins exposed in several Cretaceous and Tertiary formations and 

the Moenkopi tar sands (Fouch et al., 1992). 

2



Geologic 


Accumulation: 


Provinces: Paradox Basin, and Uinta-Piceance Basin. Plays: Cretaceous 

Dakota to Jurassic; Uinta Tertiary Oil and Gas; Wasatch Plateau-Emery 

(unconventional-coal bed gas); Permo-Triassic Unconformity; and 

Cretaceous 

Sandstones; Accumulation: North end, San Rafael Swell 

a. Source/reservoir Organic-rich mudstones in the Mancos Shale and Cretaceous-age coals 

(Dakota Group, Ferron and Mesaverde formations) are the source rocks. The 

Ferron and Dakota sandstones are reservoirs for gas. Organic-rich shale of 

the 

the Permian Phosphoria and/or Park City formations may be a source of oil 

(Meissner and Clayton, 1984). 


(TOCs) 

c.Thermal maturity Type III Kerogen. Mean Ro ranged from 0.50 to 0.65 for Dakota Sandstone 

coal and shale samples in the region (Nuccio and Johnson, 1988). 

d.Oil or gas prone 

e.Overall basin maturity 

f.Age and lithologies Permian through Cretaceous in the basin area; Eocene strata exposed to north 

where San Rafael Swell merges with south limb of Uinta Basin. 

Conglomeratic sandstone, shale, carbonaceous shales, coal, and fossiliferous 

marine sandstones. 

g. Rock extent/quality possibly basin-wide source and reservoir-rock distribution; flanks of San 

Rafael Swell and Circle Cliffs uplift are prospective areas for structural and 

stratigraphic traps (Sprinkel et al., 1997) 

h.Potential reservoirs Triassic Moenkopi Formation, Cretaceous Ferron and Dakota Sandstones, 

and Eocene Wasatch and Green River Formations. 

i.Major traps/seals Structurally controlled (simple doubly-plunging folds and complexly faulted 

anticlines); probably stratigraphic, with discontinous sandstones in the 

Dakota and Ferron units. 

j.Petroleum 


models 

k.Depth ranges 


Fractures in Entrada Sandstone on the Swell acted as conduits for 

hydrocarbon migration, and both solid bitumen and live oil droplets occur in 

lamproite dikes and secondary calcite veins which now fill the fractures; a 

discontinuous corridor of sub-parallel faults extends updip from these dikes 

towards a large tar sand deposit southeast (Hulen et al., 1998).



Economic 


a. Important 



Field County Area 


b. Recovery 


d. Overmaturity mature to overmature 




problems 


i. Porosity 

Farnham Dome, Gordon Creek, Grassy Trail Creek, South Last Chance, 

Woodside Dome, Flat Canyon, Joe's Valley, Drunkards Wash, Miller Creek, 

Peters Point, and Stone Cabin 

Producing 

Formation 

Cumulative 

Oil (bbl) 

Production-1963 

Gas (mmcf) 

Farnham Dome. Carbon San Rafael Swell Navajo Ss 0 2.5 

Drunkards Wash Carbon San Rafael Swell Ferron coals - 66 BCF 

Miller Creek Carbon San Rafael Swell Ferron Ss - 

Gordon Creek Carbon Wasatch Plateau Permo-Triassic 0 0 

Peters Point Carbon Uinta Basin Wasatch Fm 142,852 5 

Stone Cabin Carbon, Duschesne Uinta Basin Wasatch Fm 23 715.3 

Grassy Trail Cr. Carbon, Emery San Rafael Swell Moenkopi Fm 540,000 145 

Woodside Dome Emery San Rafael Swell Permian Kaibab 0 0 

Last Chance, So. Emery Wasatch Plateau Permo-Triassic 0 0 

Flat Canyon Emery Wasatch Plateau Dakota Ss 317 1,441 

Joe’s Valley Sanpete Wasatch Plateau Ferron Ss 0 2,566 

“ “ “ Dakota Grp 0 1,646

39° 

70 

Tertiary rocks (T) 

111° 110° 

Castle Valley 

Mesaverde Group (Kmv) 

Mancos Shale (Kms) 

Price 

6 

San Rafael Swell 

Lower Cretaceous 

rocks (Kl) 

Jurassic rocks (J) 

Navajo Sandstone (Jn) 

Green River 

Green River 

Utah 

Map area 

0 20 mi 

Triassic and Upper 

Paleozoic (T R Pz) 

Figure 1. Generalized geologic map of the San Rafael Swell area, central Utah. The Mesaverde Group (Kms) includes 

the Dakota Sandstone. After Lawton (1983).

Cenozoic 

Mesozoic 

Tertiary 

Cretaceous 

Jurassic 

Triassic 

Age 

Eocene 

Paleocene 

Middle 

(part) 

Early 

Late 

Early 

Maestrichtian 

Campanian 

Santonian 

Coniacian 

Turonian 

Cenomanian 

Albian 

Aptian 

Neocomian 

Portlandian 

Kimmeridgian 

Oxfordian 

Callovian 

Bathonian 

Bajocian 

Aalenian 

Toarcian 

Pliensbachian 

Sinemurian 

Hettangian 

Upper 

Middle 

Lower 

East Wasatch 

Canyon 

Flagstaff 

Limestone 

North Horn 

Formation 

Castlegate Sandstone 

Star Point Ss 

Emery Sandstone Member 

Dakota Sandstone 

Price 

Canyon 

Price River Formation 

Curtis Formation 

Sunnyside 

Green River Fm 

Colton 

Formation 

Flagstaff Mbr of Green River Fm 

Blackhawk Formation 

Tununk Member 

Bluecastle Tongue 

Green 

River 

Blue Gate Member 

Ferron Ss Mbr 

Cedar Mountain Formation 

Morrison Formation 

Summerville Formation 

Entrada Sandstone 

Carmel Formation 

Navajo Sandstone 

Wingate Sandstone 

Chinle Formation 

Moenkopi Formation 

Sego 

Canyon 

Wasatch 

Formation 

Neslen Fm 

Westwater 

Canyon 

Dark Canyon 

sequence of Wasatch Fm 

Buck Tongue of Mancos Shale 



Tuscher and Farrer Formations 

Mancos Shale 


UT-CO 

State Line 

Figure 2. Generalized stratigraphic column for the Mesozoic and Cenozoic eras on the north end of the San Rafael 

Swell, Utah. After from A. A. P. G. (1967), McGookey et al. (1972), Berman et al. (1980), Eaton et al. 

(1990), and Fouch et al. (1992). 

Sego Ss 

Age 

(10 6 yr) 

50 

60 

70 

80 

90 

100 

110 

120 

130 

140 

150 

160 

170 

180 

190 

200 

210 

220

Sevier Orogenic Belt 

Paleozoic North Horn Fm 

Paleocene 

Nugget-Navajo Ss 

Indianola Grp 

Arapien Fm - Twist Gulch Fm 

Jurassic 

South Flat Fm 

Shale 

Sandstone with 

interbedded shale 

Sandstone 

Dakota Grp 

Morrison Fm 

Price River Fm 

Ferron Ss 

Emery Ss 

Aspen Shale 

Castlegate Ss 

Blackhawk Fm 

Lower Cretaceous 

Sandstone and 

conglomerate 

Limestone 

Dolomite 

Mesaverde Grp 

Mancos Shale 

Figure 3. Diagrammatic cross section across the Rocky Mountain Geosyncline in central Utah. After Armstrong (1968). 

Fox Hills Ss 

Lewis Shale 

Fault 

Pierre Shale 

Niobrara Ls

40° 

39° 

⊥ ⊥ 

⊥ 

Duchesne 

Carbon 

⊥ ⊥ ⊥ ⊥ ⊥ ⊥ ⊥ 

Emery 

⊥ 

110° 109° 108° 

⊥ 

⊥ ⊥ ⊥ ⊥ ⊥ 

Uintah 

Grand 

Paradox 

Basin 

⊥ 

Uinta 

Basin 

Greater Cisco Area 

⊥ 

Crescent 

Junction 

Cisco 

Dome 

⊥ 

Fence 

Canyon 

Westwater 

Cisco 

Springs 

East 

Canyon 

Bryson 

Canyon 

⊥ ⊥ 

Hells Hole 

Canyon 

Harley Dome 

(Helium) 

⊥ ⊥ ⊥ 

Cisco 

Wash 

Utah 

San 

Arroyo 

Colorado 

⊥ 

Baxter 

Pass 

Rangely 

⊥ ⊥ 

South 

Canyon 

Bridle 

Stateline Bar-X 

Winter Valley 

⊥ 

⊥ ⊥ 

Douglas 

Creek 

⊥ 

Trail 

Canyon 

⊥ 

⊥ ⊥ ⊥ 

Precambrian outcrop ≥ 5 BCF Dakota-Morrison field 

Axial basin uplift 

⊥ 

Grand 

Junction 

⊥ 

⊥ 

Piceance 

Basin 

⊥ 

⊥ ⊥ 

Debeque 

Maybell 

Meeker 

Shire Gulch 

Wilson Creek 

White River uplift 

⊥ ⊥ ⊥ ⊥ ⊥ ⊥ ⊥ 

⊥ ⊥ ⊥ ⊥ ⊥ 


direction of plunge 

Moffat 

Rio Blanco 

Garfield 

Mesa Pitkin 

⊥ ⊥ 

⊥ 

Delta Gunnison 

Glenwood 

Springs 

0 20 mi 

Figure 4. Map of eastern Utah and western Colorado, showing fields that have produced 5 billion cubic feet (BCF) of natural gas from Dakota, Cedar 

Mountain, and Morrison reservoirs. After Noe (1993).


The Santa Maria basin is a triangular depression in the California coastal belt northwest of Los Angeles (Figure 

1). The basin is 150 miles long and 10-50 miles wide and covers an area of 3000 square miles. The basin boundaries 

include the Santa Lucia and San Rafael Mountains on the north and northeast, respectively, the Santa Ynez 

Mountains on the south, and the Pacific Ocean on the west (Crawford, 1970; Dunham et al., 1991). 

The basin’s origin began with Andean-type subduction of North America’s western margin during the late 

Mesozoic and middle Tertiary. Subduction progressed until the margin reached the East Pacific Rise at 30 Ma, after 

which the relative motion changed to right-slip displacement. The Neogene basins of western California developed in 

response to right-lateral shearing of the continental margin (Dunham et al., 1991). 

1 

The geotectonic history of the Santa Maria basin includes the following stages: 

1) Late Cretaceous to early Miocene: right-slip movement along the Santa Maria River-Little Pine fault 

system and the Santa Ynez River fault to the south triggered initial subsidence and rifting of the basin 

(Dunham et al., 1991). Tectonic spreading may have formed pull-apart structures as the Mendocino triple 

junction migrated past the San Luis Obispo area about 20-28 Ma (Hall, 1981). The initial rifting and basin 

subsidence deposited the coarse alluvial conglomerates of the Late Oligocene-Early Miocene Lopse 

Formation. 

2) Miocene to Pliocene: continued wrench faulting resulted in rapid subsidence and development of a deep 

marine basin. Climatic and oceanographic changes produced favorable conditions for high plankton 

productivity in surface waters above the deep basin. The basin filled with organic-rich pelagic and 

hemipelagic sediments of the Monterey and Sisquoc Formations (Figure 2). Uplift of the Santa Ynez and 

San Rafael Mountains began during late Pliocene and contributed non-marine sediments. 

3) Post-Miocene: tectonic style changed from right-slip motion to northeast-southwest-directed compression 

and resulted in thrust faulting. Reverse faults border or cut nearly every field in the Santa Maria Basin 

(Figure 3). These compressional structures formed some of the major oil-producing anticlines in the region 

(Dunham et al., 1991). The thickness of the deformed basin fill probably approaches 15,000 ft in the 

footwalls of reverse fault systems (Figure 3). 


The Santa Maria basin is one of the oldest oil-producing regions in California. Exploratory drilling began in the 

late 1890s near several oil seeps in the area. By 1908, major oil discoveries included the Orcutt, Lompoc, and Cat 

Canyon fields (Figure 1). The offshore Santa Maria basin has seen exploration since the 1950s; major offshore 

discoveries occurred in the 1980s and include the Point Pedernales, San Miguel, Bonito, and Sword fields. In 1981 

Chevron discovered the Point Arguello field, the largest U.S. oil find since Alaska’s Prudhoe Bay; Point Arguello 

EUR has exceeded 300 MMBO. 

Offshore fields produce heavy oil, with gravities ranging from less than 5 to as light as 40° API (Dunham et al., 

1991). Onshore basin oils have low gravities ranging from 16 to 27° API, and high sulfur and nitrogen content. 

Natural gas comprises only a small portion of the hydrocarbons. The gas occurs as solution gas or, rarely, as gas 

caps (Dryden et al., 1965; Dunham et al., 1991). 

Net reservoir thickness averages 1000 ft and ranges from 50 to 3,000 ft. Porosities range from 15 to 20%, and 

permeabilities reach 1 darcy (Milton et al., 1996). Anticlines that formed above major reverse faults have trapped 

most oil and gas accumulation within the basin. To date, only one significant nonstructural field has a trap formed 

by a stratigraphic pinchout.

Several formations within the basin have yielded oil, but the naturally fractured siliceous shales and cherts of the 

Monterey Formation (Figure 2) have accounted for the greatest production. The Monterey ranges from 0 to 3000 ft 

thick and averages 1,000 ft (Figure 3) (Milton et al., 1996). The formation constitutes both a source rock and a 

reservoir. Organic-rich zones occur as 1.5 to 6.5 ft thick shale layers, interbedded with thin dolomite beds in the 

lower and middle members of the formation. Kerogen content commonly exceeds 5% and locally exceeds 18% within 

some shale beds. However, though interbedded with fractured reservoir rocks, those same shales may not have 

generated the oil. Instead, oil may have migrated a considerable distance up dip along fractures before becoming 

structurally trapped. 

Monterey organic matter is mostly amorphous algal material which matures at a significantly faster rate than 

structured organic debris such as vitrinite. Thus, vitrinite reflectance has proven unreliable as a maturity indicator. 

Monterey oils may have originated at unusually low temperatures because of the unusual formation chemistry. Rapid 

basin subsidence may have accelerated the entry of Monterey source rocks into the oil generation zone. In many areas 

of the basin, the Monterey Formation lies at depths where temperatures exceed 120 °C which is within the classic oil 

window (Dunham et al., 1991). 


Santa Maria basin source rocks contain mostly Type II oil-prone organic matter. To generate significant gas 

from Type II kerogens, the oil requires thermal cracking through deep burial. The window for oil-to-gas conversion 

occurs at a Tmax of 460 °F, and vitrinite reflectance (Ro) must exceed 1.2%. Unfortunately, vitrinite reflectance is 

not a reliable indicator for the Monterey Formation. 

Extrapolation of French's geothermal gradient for three fields in the Santa Maria basin indicates the deepest part 

of the basin (12,000-15,000 ft) has sufficient temperature and burial depth for gas generation and/or conversion from 

Type II kerogen (Magoon and Isaacs, 1983). This analysis assumes removal of 3000 ft of overburden. As the 

thickness of fill approaches 15,000 ft (Magoon and Isaacs, 1983; Tennyson, 1996), only the deepest part of the basin 

may be mature enough for basin-centered gas accumulation. 

2



Geologic 


Accumulation: 


Pacific Coast- Santa Maria basin, southern California. fractured chert and 

dolomite and cherty shale of middle to late Miocene Monterey formation 

a. Source/reservoir Monterey formation; source-organic rich shales; reservoir-fractured brittled 

rocks (chert and carbonate) 


(TOCs) 

17% (avg. 5%) 

c. Thermal maturity type II Kerogen; Ro is an unreliable indicator here; maturity established by 

depth of burial plots 

d. Oil or gas prone both heavy oil (12 to 35 degrees API) and gas prone (associated gas only) 

e. Overall basin maturity considered marginally mature to mature along with adjoining basins in the 

Pacific Coast 

f. Age and lithologies fractured chert and cherty shale of middle to late Miocene Monterey 

Formation 

g. Rock extent/quality basin-wide source and reservoir-rock distribution 


i. Major traps/seals producing fields-structural (nearly every field in the basin is bounded or cut 

by reverse faults); stratigraphic pinchouts 

j. Petroleum 


models 

migration began in the late Miocene and likely continues to the present in 

tectonically subsiding regions of the basin where immature Monterey shales 

are only now being carried into the oil window 

k. Depth ranges 1,300 to 10,000 ft (producing fields); 12,000-15,000 ft in the basin center 




Economic 


a. Important 


Orcutt, Lompoc, Casmalia, Cat Canyon, Santa Maria Valley Field, Point 

Arguello, Point Pedernales, and San Miguel 

b.Cumulative production Orcutt (disc. 1901, >180 MMBO); Lompoc (>47 MMBO); Casmalia (50 

MMBO); Cat Canyon (298 MMBO, 178 BCFG); Santa Maria Valley Field 

(184 MMBO); Point Arguello (disc 1981, 123 MMBO); Point Pedernales 

(disc. 1983, 20,000 BBO/day); San Miguel (disc. 1983, 3780 BBO/day) 

a. High inert gas content CO2: 20%-25% (Dryden et al., 1965); sulfur; nitrogen 

b.Recovery Low. Continuous-type accumulations are characterized by low individual 

well-production rates and small well-drainage area. Directional/horizontal 

wells are being drilled to reduce the number of well sites. 



e.Basin maturity immature in some places 

f.Sediment consolidation consolidation/porosity reduction occurs with depth of burial 


problems 


i.Porosity 

no problems; fractured reservoirs; porosity = 15-20%

San Andreas 

Fault 

Nacimiento 

Fault 

Offshore 

Santa Maria basin 

120° 30' 120° 20' 

Onshore 

Santa Maria 

basin 

Santa Maria Valley 

Santa Maria Valley Syncline 

San Antonio Valley Syncline 

Casmalia 

Oil field and field name 

Potential basin-centered 


Lompoc 

San Andreas 

Fault 

Orcutt 

A' 

A 

Anticline 

Cat 

Canyon 

Los Alamos Valley Syncline 

Purisima 

anticline 

0 5 mi 

Figure 1. Index map of the Santa Maria basin, California, showing locations of major structural features, oil fields, 

potential basin-centered gas accumulation, and cross section A-A'. After Magoon and Isaacs (1983). 

Fault 

Syncline Unconformity 

35° 00' 

34° 50' 

34° 40'

System 

Quaternary 

Tertiary 

Cretaceous 

Jurassic 

Series Unit Lithology Description 

Pleistocene 

Pliocene 

Upper 

Miocene 

Middle 

Miocene 

Lower 

Miocene 

Paso Robles Formation 

Careaga Sandstone 

Foxen Mudstone 

Repettian equivalent 

Mudstone 

Sisquoc Formation 

Upper Monterey 

Formation 

Middle Monterey 

Formation 

Lower Monterey 

Formation 

Point Sal Formation 

Tranquillon Volcanics 

Lospe Conglomerate 

Espada (?) Formation 

Point Sal Ophiolite 

Franciscan Complex 

Conglomerate 

Sandstone 

Shale and siltstone 

Diatomaceous mudstone 

Siliceous mudstone 

Interbedded siliceous 

shale and dolomite 


shale and chert 

Phosphatic shale 


shale and dolomite 

Shale and sandstone 

Sheared and compacted 

shale and siltstone 

Chert-basalt-gabbro 

and/or melange 

Figure 2. Stratigraphic column of the onshore Santa Maria basin, California. The facies change to deeper-water clastic 

rocks takes place in the Plio-Pleistocene interval of the offshore basin. After Dunham et al (1991).

South North 

Formations 

Alluvium (Quaternary) 

Orcutt (Pliocene to north) 

Paso Robles (Pliocene- 

Pleistocene to south) 

Careaga (Pliocene) 

Foxen (Upper Pliocene) 

Sisquoc (Lower Pliocene) 

Monterey (Middle-Upper Miocene) 

Point Sal (Middle Miocene) 

Lospe (Lower Miocene) 

Franciscan 

Complex 

Lompoc 

Oil Field 

Rincon (pre-Miocene) 

Orcutt 

Oil Field 

Franciscan 

Complex 

Vaqueros (pre-Miocene) 

Cozy Dell (Upper Eocene) 

Matilija (Upper Eocene) 

Alama (Cretaceous or older) 

Santa Maria Valley 

Oil Field 

0 12000 

0 

165° F Isotherm 

Geologic contact 

Figure 3. North-south cross section through the Santa Maria basin. After CA Division of Oil and Gas (1974); Magoon and Isaacs (1983). The depth to presentday 

temperature of 165° F (74° C) comes from the geothermal gradients for Lompoc, Orcutt, and Santa Maria Valley oil fields. After French (1940). 

1000 

2000 

3000 

Scale 

(in feet) 

Explanation 

Fault


The Snake River Downwarp is a generally east- to west-trending arcuate depression in southern Idaho and east-central Oregon 

(Figure 1). The Snake River traverses the entire length of the province. The area’s boundaries include the Columbia Plateau to the 

northwest, the Idaho Batholith to the north, the Montana thrust belt to the northeast, and the Yellowstone Plateau to the east. The 

Wyoming Overthrust Belt forms the southeastern border, while the Basin and Range province marks the southern to western limits. 

Until the Miocene, the downwarp existed as a relatively stable part of the Cordilleran miogeoclinal continental shelf. Onset of 

rifting during the Miocene created the present interior rift basin (Warner, 1977), and included normal block-faulting and left-lateral 

strike-slip faulting. At this time ancient Lake Bruneau formed and covered much of southern Idaho and adjacent parts of Oregon and 

Washington. Lake Bruneau shrank in size as rifting progressed, and by Pliocene time, a smaller remnant–Lake Idaho–occupied only the 

down-dropped central rift graben (Warner, 1977; 1980). The deepest part of Lake Bruneau was in the southwest part of the present 

basin, immediately north of the Owyhee Mountains (Figure 2). During the Pliocene, rifting shifted the axis of Lake Bruneau’s 

structural basin 12 miles northward, and lowered the basin’s northern flank relative to the southern. This became the primary 

depositional axis for Pliocene Lake Idaho, which expanded eastward almost to Wyoming (Figure 3). 

Paleozoic rocks vary from 0 to 45,000 ft thick in the downwarp, and thicken to over 15,000 ft in the surrounding area. Mesozoic 

strata thickness may reach 50,000 ft, but generally ranges from 15,000 to 30,000 ft in the downwarp area (Warner, 1980). The 

Miocene Sucker Creek Formation includes up to 3,500 ft of Lake Bruneau sediments (Figure 4). Lake Idaho deposits range to 9,000 ft 

in thickness and comprise the Poison Creek, Chalk Hills and Glenns Ferry Formations of the Idaho Group (Peterson, 1996). The 

thickest strata for both lakes occur in the western parts of their depositional basins (Figure 5). 

The downwarp area shows a high present-day geothermal gradient, probably resulting from emplacement of the Cretaceous Idaho 

Batholith (Figure 5). Various events have subjected the area to high-heat flows: the Miocene rifting and related extrusion of the 

Columbia Plateau Basalt and Owyhee Volcanics; and Pliocene to Recent extrusion of the Snake River Basalt. 


There is no existing or historical production in the area. Potential reservoirs include interbedded sands in the Idaho Group and the 

Sucker Creek Formation. Fracture production is possible from nearly any rock type containing an overpressured basin-centered 

accumulation. 


Factors that may indicate a basin-centered gas accumulation include abundant gas shows, and some oil shows from both water 

wells and hydrocarbon exploration wells. Warner (1980) and Peterson (1996) speculate that the Cenozoic section in the Snake River 

Downwarp may total 30,000 ft thick. To date, some drilling has occurred in horizons above 5,000 ft depth, but very little in the strata 

between 5,000 and 14,000 ft depth (Figure 2). Sediments at all depths appear to contain some hydrocarbons, although Miocene to 

Pliocene lacustrine sediments are most favorable for basin-centered accumulations. Because of the probable great depth and high 

thermal gradient in the basin, the deeper areas will only generate gas and may actually be at the peak to past-peak generation stage, 

depending on depth and location. 

1



Geologic 


Accumulation: 


Rocky Mountain Province; Snake River Downwarp in Southern Idaho. 

Possible Cenozoic Basin Centered Gas. 

a. Source/reservoir Lacustrine rocks, shale and mudstone of the Tertiary Pliocene Idaho Group 

and the Miocene Sucker Creek Fm. (Wood, 1994) 


(TOCs) 

in the Halbouty 1 J. N. James exploratory well, the 10 highest TOC samples 

ranged from 0.43 to 1.95% (Wood, 1994) 

c.Thermal maturity Pliocene Idaho Group: immature for the depth range 1000 to 2100 ft; Ro 

ranges from 0.2 to 0.7 (estimated from reported vitrinite colors) (Senftle and 

Landis, 1991); Rocks of probable Miocene age, below the seismic "Miocene 

Volcanics acoustic basement," are mature and range from Ro 0.7 - 1.3 at 

3840 ft to 2.0 at 8700 ft depth (estimated from an orange-brown to dark 

brown vitrinite color) (Senftle and Landis, 1991). This is in the wet gas to 

dry gas zone. Untested strata, between 2100 ft and 3840 ft, may be within the 

oil generating window (Wood, 1994). Kerogen is primarily woody, with 

secondary amounts of herbaceous spores, pollen and inertinite. This strata 

will be a good gas source and a poor oil source. Geothermal gradients in the 

Western Snake River Downwarp are high, ranging from 16.5 to 22° F per 

1000 ft (30 - 40° C) (Wood, 1994). 

d.Oil or gas prone Probably gas prone with associated gas liquids. Gas from a depth of 1979 ft 

in Oroco Oil and Gas 1 Virgil Johnson (c se 27, T8N, R4W) indicated 93% 

methane, 3% ethane, and 4 % unknown; Btu was 1102 per cu ft (Dwights, 

1999) 

e.Overall basin maturity probably mature 

f.Age and lithologies clastic and lacustrine strata of the Pliocene Idaho Group and Miocene Sucker 

Creek Formation 

g. Rock extent/quality potentially large extent of possible interbedded lacustrine source and clastic 

reservoir strata 

h.Potential reservoirs interbedded sands in the Idaho Group and Sucker Creek Formation 

i.Major traps/seals possibility of both structural and stratigraphic types 

j.Petroleum 


models 

Tissot and Welte “Cooking Pot” model, where generated hydrocarbons are 

expelled into the surrounding reservoir rocks 

k.Depth ranges Biogenic gas to 5000 ft depth. Speculative basin-centered gas from 5000 to 

25,000-plus ft (Warner, 1980)



Economic 


l. Pressure gradients 0.45 psi/ ft (±0.06 psi/ft) for shallow objectives. Deeper objectives are 

possibly overpressured. 

a. Important 


none 


a. High inert gas content less than 5% 

b. Recovery 

c. Pipeline infrastructure A single 24-inch pipeline passes through the area paralleling Interstate 84. 

Several small lateral lines serve the towns surrounding Boise, Idaho. A major 

trunk line runs from the southwest corner of Idaho to Reno, Nevada. 

d. Overmaturity unknown, but may occur in Paleozoic strata at great depth. Mid-depth 

Mesozoic and early Cenozoic strata could possibly be overmature. 

e. Basin maturity Shallow parts of the basin are probably immature. 

f. Sediment consolidation Poorly consolidated rocks may exist in the shallower parts of the basin. 


problems 


i. Porosity 

low porosity and permeability may be a problem, at least in underpressured 

or normally pressured areas

46° 

42° 

120° 116° 

112° 

Lake Idaho basin (Pliocene-Pleistocene) 

Lake Bruneau basin (Miocene) 

Idaho batholith 

Figure 1. Map of Snake River downwarp area in southwest Idaho, showing Cenozoic lake basins and Idaho batholith. 

After Warner (1981).

U D 

A 

13000 

10000 

12000 

15000 

A' 

14000 

8000 

8000 

Igneous rock 

9000 

13000 

0 12 mi 

11000 

Idaho Batholith 

Fault; U is upthrown side, D is downthrown side 

U D 

Snake River 

Halbouty-Chevron 1 J. N. James 

Hydrocarbon exploration well; drilled in 1976. SE 27, T4N R1W. Total depth = 14,000 ft. 

Total Organic Carbon range 0.43 to 1.95%. 

Oroco-Simplot 1 Virgil Johnson 

Hydrocarbon exploration well; drilled in 1955. SE 27, T8N R4W. Total depth = 4,040 ft. 

Well suffered gas blowout at 1,979 ft depth. 

Gas analysis: 1102 Btu/ft 3 , 93% methane, 3% ethane, 4% unknown. 

Figure 2. Isopachs showing total thickness of Pliocene and Sucker Creek strata, Snake River downwarp, Southwest 

Idaho. Contour interval is 1000 ft. Possible basin-centered gas at 200° F. The peak hydrocarbon generation 

isotherm occurs at 9,400 ft. approximately and greater depth. After Warner (1977).

A 

A' 

9000 

Igneous rock 

8000 

Idaho Batholith 

7000 

Halbouty-Chevron 1 J. N. James 

Oroco-Simplot 1 Virgil Johnson 

Snake River 

4000 

5000 

6000 

2000 

1000 

0 

4000 

3000 

3000 

2000 

0 12 mi 

Figure 3. Isopach of post-Sucker Creek Cenozoic strata, Snake River downwarp, Southwest Idaho. Contour interval is 1000 ft. After Warner (1977).

Series Depth Lith. Description Thickness 

Pleistocene 

Pliocene 

Miocene 

0 

1,000 

2,000 

3,000 

4,000 

5,000 

6,000 

7,000 

8,000 

9,000 

10,000 

11,000 

Glenns Ferry Formation 

This formation consists of a homogeneous mixture of light gray silty clay, containing beds of light 

siliceous volcanic ash and some sandstone. In some areas it contains considerable basalt. 

The formation represents the last stage of ancient Lake Idaho and the beginning of the Snake River 

Basalts. 

The sandstones of this formation are best developed in the central portion of the far western end of 

the Snake River Plain. Many shallow wells drilled in this formation have shown gas. 

Chalk Hills Formation 

Oolitic limestone 30-100 feet thick caps this formation. It consists of interbedded silty ashy clay, 

sandstone, and pure vitric ash. Also contains some basalts and tuffs. At least one algal reef is present 

in the upper portion. This is a lacustrine deposit containing beds rich in mollusc, diatom, ostracod, and 

fish fossils. The color of the entire formation is light gray, with the exception of a few ferruginous sands 

and some basalts. A white porcellanite bed forms the base of this formation. 

Poison Creek Formation 

A bright red crystalline volcanic ash (the Cherokee Ash) caps this formation. This formation is 

primarily volcanic, consisting of interbedded tuffs, ashes, volcanic sands, and a few basalts. The color 

is yellowish brown to greenish brown, and darker overall than the younger units above. Fossils are 

sparse. 

Owyhee Rhyolite 

This unit consists of a mix of rhyolite, dacite, latite, andesite, and a few basalt stringers. Rhyolite 

dominates, and it is brownish red to pink in the upper section, becoming more gray with depth. A few 

tuffs and ash beds are interbedded with the extrusive rocks. 

Columbia River Basalts 

(North and northwest part of downwarp) 

Sucker Creek Formation 

A mix of lacustrine, deltaic, and volcanic deposits. The upper part consists largely of ashy, silty, 

carbonaceous shale and siltstone. It contains much diatomite and many giant fossils, and it is highly 

lignitic. The formation is very finely laminated. 

Interbedded with the carbonaceous section are some very thick (50-100 feet) and extensive 

quartzitic sandstones. Ashes, tuffs, and porcellanite are common, and a few black organic shale beds 

are present. 

Distinct marker beds occur at the following depths: 

A green chloritic ash bed (Green Hornet Ash) at 7300 feet. 

A white porcellanite bed (Snowbird Shale) at 7750 feet. 

A bluish gray perlitic tuff at 8900 feet. 

The lower half of the section is similar to the upper half, but contains more volcanic rocks. 

Deep wells and drill stem tests have indicated good gas shows. 

Jarbidge Rhyolite 

A light to dark gray rhyolite with pink and greenish gray zones. It contains some porcellanite, ash, 

and tuff beds, and is locally rich in pyrite. The lower part is highly altered in spots, becoming 

porphyritic. 

Meta-Rhyolite 

Coarse porphyritic rhyolite with large quartz and feldspar phenocrysts. It resembles plutonic rock. 

Figure 4. Cenozoic stratigraphic column of the western Snake River Downwarp, Idaho. After Warner (1981) and Wood (1994). 

3000± ft 

300± ft 

400± ft 

0-3000+ ft 

0-9000+ ft 

0-2300+ ft

Depth in Feet 

0 

1,000 

2,000 

3,000 

4,000 

5,000 

6,000 

7,000 

8,000 

9,000 

10,000 

11,000 

12,000 

13,000 

14,000 

A A' 

Standard- 

Highland L & L #1 

Elevation 2631 ft. 

Total Depth = 10,682 ft. 

Sea level 

200° F 

(9400 ft) 

Glenns Ferry Fm 

Chalk Hills Fm 

Poison Creek Fm 


Basalt Section 

Sucker Creek Fm 

Halbouty- 

Chevron J. N. James #1 


Total Depth = 14,003 ft. 

Silty clay to ashy siltstone 

Carbonaceous shale 

Sandstone 


Basalt Section 

Fractures 

Recent 

Glenns 

Ferry Fm 

Chalk 

Hills Fm 

Poison 

Creek Fm 

Sucker 

Creek Fm 

Idaho 

Rift 

Poison Creek Fm 

Jarbidge Rhyolite 

Sucker Creek Fm 

Section on 

Sucker Creek 


Owyhee Rhyolite 

Ash, tuff, or porcellanite bed 

Rhyolite, dacite or andesite; locally 

interbedded with ash or tuff 

Basalt flow 

0 10 mi 

Paleozoic 

Rocks 

Figure 5. North-south cross section A-A', western Snake River Downwarp. Section shows the relationship between 

the stratigraphy and the estimated 200° F isotherm (derived by assuming an average annual surface 

temperature of 50° F. The 200° isotherm represents a possible present day top-of-the-peak hydrocarbon 

generation window. After Warner (1977).


As one of the largest foreland basins of the Rocky Mountains, the Alberta Basin extends from southern Alberta 

into northern Montana and terminates against the Sweetgrass Arch to the east (Figure 1). The Little Belt Mountains 

form the southern border, and the Montana Disturbed Belt close off the basin to the west. 

The Basin contains Paleozoic and Mesozoic sediments, but Ordovician, Silurian, Pennsylvanian and Permian 

strata are absent because of erosion or non-deposition (Figures 2 and 3). An unconformity separates Mississippian 

from Jurassic rocks in the area (Figure 2). Cretaceous rocks dominate the remaining sedimentary section (Figure 3) 

(Peterson, 1966). 

The late Cretaceous to early Tertiary Laramide orogeny gave the basin its present configuration. 


Figure 1 shows a map of oil and gas fields in the Alberta Basin-Sweetgrass Arch area. The Cut Bank field is the 

largest and represents a stratigraphic trap in the Cretaceous Cut Bank Sandstone. Cumulative production to date 

exceeded 168 MBO and 322 BCFG. Blackleaf Canyon field produces from the Mississippian Sun River Dolomite 

within a Disturbed Belt thrust sheet; to date the field has produced over 33,000 BO and more than 7 BCFG. The Two 

Medicine Field has produced more than 25,000 BO from the Cone Member fractured shales in the Upper Cretaceous 

Marias River Formation, and more than 11,000 BO and 274 BCFG from the Sun River Dolomite. 

The source rock for the most fields in the area is the Devonian-Mississippian Bakken Shale. Although Bakken 

oil and gas generation occurred deep in the Alberta Basin, fracturing in the Sun River Dolomite and across the 

Mississippian-Jurassic unconformity allowed extensive gas migration updip (Dolson et al., 1993). 


Studies of potential source rocks in the Disturbed Belt indicate the Cone Member of the Marias River 

Formation, and the Bakken Shale show the greatest potential for hydrocarbon generation (Clayton et al., 1982). 

These rocks are generally immature east of the Disturbed Belt (Figure 4), although the Bakken may be mature to 

post-mature where buried by thrust sheets (Clayton et al., 1982; Dolson et al., 1993). Vitrinite reflectance (Ro) for 

the Bakken ranges from less than 0.5 to 1.5% (Figure 4). Potential reservoirs include Devonian Nisku and Three 

Forks Formations, Jurassic Swift and Sawtooth Formations, and sandstones in the Cretaceous Blackleaf and 

Kootenai Formations. 

The southwest Alberta Basin and the Sweetgrass Arch have little apparent potential for continuous basincentered 

gas accumulations. Conventional accumulations in the area have produced large volumes of oil and gas, but 

the gas migrated from deeper zones along the Disturbed Belt.



Geologic 


Accumulation: 


Rocky Mountain, Alberta Basin, no accumulation 

a. Source/reservoir Potential sources: Bakken Shale and Cone Member, Marias River formation; 

potential reservoirs: Devonian Nisku and Three Forks formations, Jurassic 

Swift and Sawtooth Formations, and sandstones in the Cretaceous Blackleaf 

and Kootenai Formations. 


(TOCs) 

Devonian Three Forks/Bakken avg = 0.975%; Cretaceous Cone Member, 

Marias River Formation avg = 2.40% 

c. Thermal maturity Bakken Shale Ro =



Economic 


a. Important 


no basin-centered accumulation 

b. Cumulative production no basin-centered accumulation 

a. High inert gas content no basin-centered accumulation 

b. Recovery no basin-centered accumulation 

c. Pipeline infrastructure good near conventional fields 



f. Sediment consolidation no basin-centered accumulation 


problems 


i. Porosity 

no basin-centered accumulation

49° 

48 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23 

24 

48° 

48 

Kevin 

Sunburst-Shelby 

Devon 

"B" Square 

Rattlesnake Coulee 

Marias 

Cut Bank Gas 

Cut Bank Oil 

Dahlquist North 

Dahlquist South 

Lander 

McGuiness 

North Cut Bank 

Bradley 

Blackfoot 

Reagan 

South Darling 

Red Creek & 

Graben Coulee 

Darling 

Moulton Pools 

Border-Red Coulee 

Cobb 

Gypsy Basin 

Pondera 

Bannatyne 

Field Index 

25 

26 

27 

28 

29 

30 

31 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 

44 

45 

46 

47 

48 

49 

Glacier County 

Teton County 

Brady 

South Conrad 

Midway 

Whitlash 

Flat Coulee 

Laird Creek 

Blackjack 

Bears Den 

Keith 

East Keith 

Grandview 

Utopia 

Middle Butte 

Arch Apex 

Gold Butte 

Berthelote 

Miners Coulee 

Fred & George Creek 

Prichard 

West Butte 

Kicking Horse 

Bow & Arrow 

Hay Lake 

Two Medicine 

Blackleaf 

Approximate East Limit of Montana Disturbed Belt 

49 

15 

10 

14 

8 

13 

12 

23 

17 

17 

16 

11 

7 

47 

22 23 

23 

9 

18 19 

9 

21 

23 

20 

23 

5 

Alberta 

Montana 

Pondera County 

Toole County 

Sweetgrass Hills 

Figure 1. Location map of Alberta Basin-Sweetgrass Arch identifying oil and gas fields. From Montana Oil and Gas Conservation Commission (19__). 

112° 

112° 

1 

6 

26 

25 

2 

27 

West Butte 

46 

24 

45 

44 

41 

40 

4 

3 

43 

42 

39 

28 

38 

Middle 

Butte 

37 

28 

Liberty County 

28 

35 

35 

36 

29 

31 

32 

30 

East Butte 

EXPLANATION 

Oil field 

Gas field 

33 

Tertiary intrusive rocks 

0 5 10 15 mi 

34

Kootenai Fm 

Morrison Fm 

Swift Sandstone 

Rierdon 

Sawtooth/Piper 

Major Hiatus 

(Jurassic-Mississippian) 

Sun River Member 

Castle Reef Dolomite/ 

Mission Canyon Limestone 

Allen Mountain Limestone 

Lodgepole Formation 

Bakken Formation 

Three Forks Formation 

Potlatch Evaporites 

Jefferson 

Nisku (Birdbear) 

Duperow 

Souris River 

Dawson Boy 

Major Hiatus 

(Upper Devonian-Ordovician) 

(Upper Cambrian) 

Deadwood Formation 

(Middle Cambrian) 

Flathead Sandstone 

Gravelly 

Sandstone 

W E 

Flood Sandstone 

Belt Rocks 

(Precambrian) 

Sandstone Undifferentiated 

Rocks 

Major Hiatus 

(Precambrian) 

Major Hiatus 

(Jurassic-Mississippian) 

Major Hiatus 

(Upper Devonian-Middle Silurian) 

Fall River or Dakota Sandstone 

400 ft 

0 0 25 miles 

Limestone Dolomite Shale Conglomerate Undifferentiated 

Evaporites 

Green Shale, 

Limestone, 

& Sandstone 

Cretaceous 

Jurassic-Mississippian 

Mississippian 

Lower Devonian-Upper 

& Middle Silurian 

Lower Silurian 

Upper Ordovician 

Upper Cambrian 

Cambrian-Precambrian 


Metamorphic 

Rocks 

Figure 2. West-to-east cross section across Sweetgrass arch in northern Montana, showing major depositional units and intervening major 

depositional interruptions. After Dolson et al. (1993).

Cretaceous 

Jurassic 

System 

Triassic 

Permian 

Pennsylvanian 

Mississippian 

Devonian 

Cambrian 

Precambrian 

Upper 

Lower 

Upper 

Middle 

Lower 

Colorado 

Kootenai Formation 

Ellis Group 

Madison Group 

Marias 

River Shale 

Blackleaf 

Sweetgrass Area 

Northwest Montana 

Bear Paw 

Judith River 

Claggett 

Eagle 

Niobrara- 

Carlile 

Greenhorn 

Mowry Shale 

Bow Island Newcastle 

Skull Creek Shale 

Dakota Silt 


(1st Cat Creek/Flood Member) 

Red Lion 

Pilgrim 

Belt 

Cutbank 

Morrison 

Swift 

Rierdon 

Sawtooth 

Sun River 

Fuson 

calcareous 

Bakken 

Three Forks Formation 

Potlatch Formation 

Cambrian Shale 

Undivided 

Mission Canyon 

Lodgepole 

Nisku 

Duperow 

Souris River 

Flathead 

Moulton 

Sunburst 

Upper 

Colorado 

Lower 

Colorado 

Mannville (Blairmore) 

Ellis Group 

Rundle 

Group 

Turner 

Valley 

Southern Plains 

Alberta 

1st white specks 

2nd white specks 

base of fish scales zone 

Bow Island Viking 

basal Colorado 

glauconitic sandstone 

ostracod zone calcareous 

basal Blairmore 

Swift 

Moulton 

Sunburst 

Taber 

Rierdon 

Sawtooth 

Piper 

Upper 

Middle 

Elkton 

Shunda 

Pekisko 

Banff 

Exshaw 

Palliser 

Alexo Formation 

Birdbear 

Fairholme Group 

Purcell Group 

medial 

Cutbank 

Locally 

Undiff. 

Upper 

Colorado 

Lower 

Colorado 

Mannville 

Upper 

Lower 

Vanguard 

Shaunavon 

Southwest 

Saskatchewan 

J-1 

1st white specks 

2nd white specks 

base of fish scales zone 

Viking 

Joli Fou 

Lower 

Upper 

J-2 

Lower 

Gravelbourg J-3 

Watrous J-4 

Mission Canyon 

Devonian 

Undivided 

Cambrian 

Undivided 

Basement Basement Basement 

Figure 3. Geologic column for Sweetgrass arch vicinity. After Dolson et al. (1993). 

Lodgepole 

Bakken

50° 00' 

49° 00' 

1 

R o = 1.5% 

7 

2 

8 

R o = 0.75% 

12 

13 

14 

9 

4 

3 

Early Oil Generation 

Alberta, Canada 

Montana, USA 

47° 00' 

113° 49' 58" 111° 12' 

5 

R o = 0.5% 

11 

15 

6 

10 

Well 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

TOC H % Ro 1.7 213 1.4 

7.9 530 0.4 

8.2 520 0.4 

9.5 516 0.4 

11.8 494 0.4 

9.9 523 0.4 

6.2 400 1.1 

7.7 300 0.6 

7.1 370 0.6 

3.0 234 0.45 

7.3 - 14.1 

2.5 - 7.2 

8.7 

2.8 

700 - 800 0.5 

12.9 335 0.60 

Explanation 

0 

0 

Precambrian 

thrusted Belt 

metasediments 

Thrust fault, 

dashed where 

approximately 

located 

Vitrinite 

reflectance 

isopach 

Figure 4. Map of Bakken Formation total organic carbon (TOC) and maturation levels (hydrogen, H, and % vitrinite 

reflectance, % Ro). Thermally mature source strata are located on the extreme western margin of the 

Sweetgrass arch and within the footwall to the thrust belt in Montana and Alberta. After Dolson et al (1993). 

30 km 

18 mi


The Mesozoic rift basins of eastern North America formed in response to the break-up and separation of Pangaea 

in late Paleozoic to early Mesozoic time. Rift basins formed simultaneously on both the North Atlantic and Euro- 

African plates (Pyron, 1998). These basins consist of elongate, asymmetric, half-graben structures which contain 

thick Triassic through lower Jurassic clastic, evaporite and volcanic rocks. The basin fill rests unconformably on 

crystalline basement formed during the Acadian and Alleghenian orogenies. Sedimentary rock types include reddishbrown 

mudstones, course-grained "border" conglomerates, arkosic sandstones, siltstones, gray-black lacustrine shales, 

evaporites, and coal. Tholeiitic basalt flows, sills and dikes are also common. On-shore basins, both exposed 

(Piedmont and Blue Ridge Provinces) and inferred (Coastal Plain), extend from Georgia to Massachusetts and cover 

about 42,700 square miles (Figure 1). Individual basins range from 24 square miles (Taylorsville basin) to over 

3,100 square miles (Newark basin) in area. Offshore basins extend from Nova Scotia to the Florida Panhandle 

(Figure 1). The rift basins generally trend northeast, approximately perpendicular to the initial rifting of North 

America and Africa (Klitgord and Behrendt, 1977). 

The tectonic history of the basins includes 5 stages: 

1) Permian through Triassic: crustal thinning along the eastern margin of the North American continent. This 

is the earliest stage of Pangaea breakup. 

2) Middle Triassic: rifting and crustal extension. Late Triassic clastic deposition into subsiding basins. 

3) Early Jurassic: extension and clastic deposition in basins along tholeiitic basalt flows and intrusions. 

4) Middle Jurassic: sea-floor spreading and development of the Mid-Atlantic ridge system. 

5) Late Jurassic to present: lithospheric cooling, plate subsidence, and marine transgression with development 

of a passive continental margin (Schultz, 1988). 

The depositional history of a typical onshore Mesozoic rift basin of eastern North America includes four phases: 

1) Formation of a rift graben along a listric boundary fault. Alluvial fans form along the upthrown walls and 

coalesce into laterally extensive deposits of fanglomerate, and finer-grained sediments near the basin center. 

Conglomerates interfinger with sandstones and siltstones. Internal basin drainage produces intermittent 

playas with evaporite deposits. 

2) Tectonic subsidence of the basin ends. Alluvial fans become reworked; coarse to fine sediments enter from 

outside the rift structure. Internal drainage results in the formation of a lake in the basin center. Vegetation 

flourishes along the lake margins and provides organic material for sedimentation. Feeder streams deposit 

coarse sands and fanglomerates interfingered with lacustrine sediments. 

3) Fluvial and lacustrine sands become reworked and re-deposited parallel to the long axis of the basin. Diabase 

dikes, sills and sheets intrude along zones of weakness. The magma causes regional heating of the basin and 

consequent thermal maturation of organic sediments. 

4) Recent uplifting, tilting, and regional erosion created the present day geology. In many offshore basins, 

evaporite deposition followed continental deposition. During Cretaceous and Tertiary time, marine 

sediments covered the continental rocks (Pyron, 1998).


There is no hydrocarbon production from any Mesozoic rift basin in the eastern U.S. Seventy years of 

exploratory drilling in the rift system has yielded numerous shows of oil and gas but no commercial hydrocarbons. 


Other Mesozoic rift basins are productive, including the Ghadames basin in Algeria (Northeast Africa), the Cuyo 

basin in Argentina (South America), the North Sea (Europe), and the Jeanne d'Arc basin (Canada). Rift basins offer 

attractive exploration targets because the cycle of rifting, sedimentary fill and igneous activity provides reservoirs, 

source rocks and thermal maturity. 

Significant potential exists for basin-centered gas accumulations within thick lacustrine mudstones, black 

shales, siltstones, and sandstones in the deep parts of the eastern U.S. rift basins. Geochemical data, including total 

organic carbon (TOC), thermal alteration index (TAI), vitrinite reflectance (Ro), and Tmax measurements, indicate 

the basins are thermally mature. 

The Newark basin in central New Jersey and southeastern Pennsylvania may contain significant gas reserves. 

Figure 2 includes maps depicting the geology and structure of this basin; Figure 3 shows basin stratigraphyin three 

locations. The Newark forms a part of a larger rift system that also incorporates the Gettysburg and Culpeper basins 

and extends from New Jersey southwest to Virginia. The exposed sedimentary section along this system is over 

25,000 ft thick and appears gas prone. The Newark has had only three exploratory wells drilled. One well reached a 

depth of 10,500 ft and encountered gas shows within a 3,000-ft section of fractured lacustrine shale. 

The Danville basin (Virginia-North Carolina) is also gas prone with a 9840 ft thick sedimentary section. The 

Hartford basin appears to be oil prone (Hubert et al., 1992; Schultz, 1988; Kotra et al., 1988). 

Exploration may identify productive basins where suitable reservoir rocks occur. Basins with thin sedimentary 

sections, such as the Richmond and Taylorsville, would be less attractive exploration targets.



Geologic 


Accumulation: 


Eastern U.S. onshore Mesozoic basins; upper Triassic through lower Jurassic 

continental clastic and carbonate rocks. 

a. Source/reservoir late Triassic early Jurassic thick sequences of organic black and gray shales 

and black siltstones deposited along the centers of the basins 


(TOCs) 

Newark: 0.5-6.0% (lacustrine black shales); Hartford: 0.4-3.5% (lacustrine 

black shales); Culpeper: 0.4-8.0% (lacustrine black shales); Danville: 0.1- 

2.4% (black shale/coal); Deep River: up to 35% (black shale/coal); 

Richmond: up to 40% (black shale/coal) 

c. Thermal maturity Kerogen Type: Hartford and Richmond basins: lacustrine algae (Type 1) and 

mixed lacustrine algae/terrestrial plant debris (Type 2); Newark, Culpeper 

and Dan River basins: mixed (Type 2). Thermal alteration index (TAI): 

Newark 

(3+) and Danville basins (4.0); Hartford, Deep River and Richmond basins 

(2.5-to 3.0); Vitrinite reflectance (Ro): Hartford basin 0.5-1.0; Danville basin 

2.15. Tmax (°C): Newark basin 426-443; Danville basin 400+; 

Hartford, Deep River, Richmond, Taylorsville basins 441-455. 

d. Oil or gas prone both oil and gas prone: Newark and Danville basins-gas prone. Hartford, 

Deep River, Richmond basins-oil prone. 

e. Overall basin maturity highly variable. Extensive igneous activity and high heat flow cooked many 

of the lacustrine shales and coals in the southern basins. 

f. Age and lithologies upper Triassic through lower Jurassic 

g. Rock extent/quality basin-wide source and reservoir-rock distribution. 


i. Major traps/seals interbedded shales, siltstones and sandstones of alluvial fans and lacustrine 

sediments 

j. Petroleum 


models 

k. Depth ranges 10,000-20,000 ft 




Economic 


a. Important 




b. Recovery 

c. Pipeline infrastructure very good 

potential unknown: Newark, Culpeper, Richmond, Taylorsville, Dan River, 

Farmville 

d. Overmaturity overmature in some areas within basins due to high heat flow (eg. Hartford 

Basin) 

e. Basin maturity immature in some areas (Hartford basin) 



problems 


i. Porosity

N 

Newark basin 

Exposed basin 

Inferred basin 

Coastal Plain-Piedmont 

boundary 

0 500 mi 

Figure 1. Index map of exposed and inferred Mesozoic basins of eastern North America and the Coastal Plain- 

Piedmont boundary. After Manspeizer and Olsen (1981), and Froelich and Olsen (1985).

N 

Geologic Map 

Structure Map 

Thermal 

Maturation Map 

Basalt and diabase 

Triassic Stockton Formation 

Triassic Lockatong Formation 

Jurassic-Triassic Passaic 

Formation 

Jurassic undifferentiated 

rocks 

σ 2 

Extension 

460 

Extension 

435 

481 

(3.2) 

(4.8) 

428 

(0.7) 

440 

422 

434 

444 

(2.6) 

476 

(0.7) 

(1.7) 

Basin boundary 

Normal fault, with hachures 


Strike-slip fault, with some 

vertical displacement 

Strike and dip direction of 

bedding 

428 

421 

446 

435 

(0.4) 

435 

Anticline 

Syncline 

Isotherm 

460 

σ 2 

0 10 mi 

Shale sample location; 

temperature in F° and 

R o in percent (%) 

Figure 2. Maps of the Newark basin, showing geology, generalized structural features, direction of inferred extension and 

intermediate principal stress σ 2, and maximum pyrolitic yield and mean vitrinite reflectance Ro. After Manspeizer 

(1981), Ratcliffe and Burton (1985), Turner-Peterson and Smoot (1985), Pratt et al (1988), and Schultz (1988).

Series Stage 

Lower 

Jurassic 

Upper 

Triassic 

Toarcian 

Pliensbachian 

Sinemurian 

Hettangian 

Upper Norian 

Middle Norian 

Lower Norian 

Upper Carnian 

Middle Carnian 

Lower Carnian 

Narrow Neck 

of the Newark basin, 

Pennsylvania 

Hammer Creek Formation 

Stockton Formation 

Brunswick 

Group 

Newark basin, 

Pennsylvania 

upper part Brunswick Group 

Jacksonwald Basalt 

lower part 

Brunswick Group 

Perkasie Member 

Graters Member 

Lockatong Formation 

Newark basin, 

New Jersey-New York 

Brunswick 

Group 

Stockton Formation 

Figure 3. Stratigraphic columns for the Newark basin in Pennsylvania, NewJersey, and New York. After Froehlich and Robinson (1988). 

Boonton Formation 

Hook Mountain Basalt 

Towaco Formation 

Preakness Basalt 

Feltville Formation 

Orange Mountain Basalt 

Passaic Formation 

Perkasie Member 

Graters Member


The Wasatch Plateau is an 80 mi long by 25 mi wide uplift west of the San Rafael Swell in east-central Utah, 

within parts of Sanpete, Sevier, Emery and Carbon Counties, and lies sandwiched between Sanpete Valley to the 

west and Castle Valley to the east (Figure 1). Structural features west of the Plateau include the Gunnison Plateau 

and Wasatch Monocline (Figure 2). The Wasatch Plateau forms part of the Central Utah Transition zone, between 

the Colorado Plateau to the east and the Basin and Range province to the west. 

The Plateau’s history begins with Cretaceous synorogenic deposition of clastic sediments in a foreland basin 

east of the Cordillera. On the western periphery of the basin, local deposits of deltaic and paludal sediments alternated 

with deepwater mudstones deposited during several transgressive cycles (Figure 3). Eastward thrusting and uplift 

probably began during the late Jurassic-early Eocene Sevier Orogeny (Neuhauser, 1988). Diapiric movements and 

extensional faulting occurred during the Cenozoic era. Figure 2 shows fault structure for the area. 

Exposures of Quaternary alluvium, Tertiary sandstones and limestones, and Upper Cretaceous Mesaverde Group 

sandstones, shales and coalbeds occur atop the Plateau. Figures 3 and 4 show the area’s stratigraphy. 


Oil and gas production in the Wasatch Plateau occurs mostly from Cretaceous Ferron sandstones east of the 

Joe’s Valley Graben and west of the Ferron outcrop. The Cretaceous Dakota Group and Permian Kaibab Formation 

have had some minor production as well. The fields along the Plateau have produced over 158 BCFG and 132 MBO 

since 1951. 

On the eastern margin of the plateau, recent coalbed methane production from Ferron coals in Drunkards Wash 

Field (discovered in 1992) has sparked renewed interest in the area. To date, cumulative production including coalbed 

methane exceeds 224 BCFG. 

Production on the Wasatch Plateau has generally been from structural traps, probably enhanced by tectonic 

fracturing (Tripp, 1990). 


Not enough evidence exists to determine if an overpressure cell encompassing the Cretaceous rocks occurs at 

deeper drilling depths within the plateau. Production does occur from gas fields along the eastern plateau margin, but 

pressure gradients only range from 0.21 to 0.27 psi/ft. Also, the Ferron field shows downdip water flows, which 

indicates underpressuring and a probable gas-water contact at depth. Additionally, drillstem tests in much of the 

plateau area recovered water, indicating normal to underpressuring in the lower Cretaceous sediments. Most wells 

showing water are in close proximity to known mapped faults (Tripp, 1989). The high degree of tectonism and 

associated fracturing of the rocks may allow water to flow upward from the Paleozoic section or downward from 

Tertiary and Cretaceous rocks along the fault zones. If a “gas kitchen” once existed in this area, faulting may have 

breached it. 

Exploration the central part of the Plateau has been rare and many townships remain untested. However, in 1996 

Cimarron Energy Corporation re-entered a 20,505 ft deep test well; Cimarron completed two sidetracks within 

Tununk Shale at depths of 11,772 and 11,840 ft. Production through June of 1998 was 313 BO and 425 MCF. This 

significant show indicates a fractured shale play probably occurs on the Plateau.



Geologic 


Accumulation: 


Great Basin/Colorado Plateau, basin-centered gas play in deeper Cretaceous 

Rocks 

a. Source/reservoir Tununk and Bluegate Shale members of Mancos Shale/Dakota Group, 

Ferron and Emery Sandstone Members of Mancos Shale, Morrison 

Sandstones 


(TOCs) 

c.Thermal maturity Ro values for Ferron coals at Drunkards Wash Field (T14-15S, R9-10E) 

reportedly average 0.69% (Lamarre and Burns, 1997). Blackhawk coals 

sampled from mines in the Wasatch Plateau (Bodily et al., 1991)) are HVBc 

in rank; this would correlatewith an Ro of 0.60 – 0.78%. Vitrinite reflectance 

data for coals within the sandstone member in the Emery Coal Field (T14S- 

22S, R6-9E) range from 0.52 to 0.63%. Other coals within the 

field have measured values up to 0.74% (Hucka et al., 1997); these values 

are probably too low for a basin-centered gas accumulation. 

d.Oil or gas prone primarily gas prone, type III and type II kerogens 

e.Overall basin maturity fair to moderate 

f.Age and lithologies Cretaceous shales, coals, delta plain and alluvial sandstones. Dakota 

sandstone is conglomeratic. 

g. Rock extent/quality The Ferron and Emory extend over plateau. Sparse drilling of Dakota and 

Morrison tests render the regional extent unknown. Tununk and Bluegate 

Shales are regionally extensive. Individual Ferron coals are laterally 

discontinuous. 

h.Potential reservoirs Best reservoir rock occurs within channel facies. 

i.Major traps/seals Mostly structural with some stratigraphic. The Cretaceous Tununk Shale 

separating the Ferron and Dakota Sandstones and the Bluegate Shale above 

and below the Emery and Ferron are seal rocks. Interbedded shales within 

the 

sandstones may form seals. 

j.Petroleum 


models 

k.Depth ranges 8,500 to 12,000 ft 

In-situ generation and long distance migration. Geothermal gradient ranges 

from 23 to 29° C per km.



Economic 


l.Pressure gradients Subnormal pressure gradients range from .21 to .27 psi/ft. Some drillstem 

tests recovered water, indicating normal to underpressure in western portions 

of the plateau. Insufficient data exists to determine if an overpressure cell 

a. Important 



the Cretaceous rocks exists at deeper drilling depths within the plateau. 

a. High inert gas content not a problem. The Ferron gas is 90-98% methane with a Btu range from 990- 

1129. Flat Canyon Field Dakota gas is 1107 Btu with a methane content of 

91% (Tripp, 1991). Ferron coalbed methane had a Btu of 

987-1000 with methane concentrations from 95.8-98.3% and carbon dioxide 

contents of 0.7-0.30% (Lamarre and Burns, 1997). Tests of Paleozoic rocks 

on the Gordon Anticline, located east of the Plateau, have encountered CO2 

from the Moenkopi Formation and the Coconino sandstone (Tripp, 1990). 

b.Recovery low 

c.Pipeline infrastructure limited 


e.Basin maturity the extreme western edge of the plateau may be immature 

f.Sediment consolidation well indurated 


problems 

Formation damage due to swelling clays may reduce or prevent production if 

appropriate drilling and completion fluids are not utilized. 

h.Permeability Ferron permeability ranges from .05 to .14 md. Permeability for the Dakota, 

Morrison and Emery are unknown. 

i.Porosity Ferron porosity ranges from 8 to 17%; Dakota porosity at Flat Canyon Field 

averages 4% (Tripp, 1989; 1991; 1993).

112° 00' 

40° 00' 

39° 30' 

39° 00' 

28 

15 

Wasatch 

Range 

Nephi 

Gunnison Plateau 

89 

Gunnison 

Salina 

111° 30' 111° 00' 110° 30' 110° 00' 

Sanpete Valley 

89 

Ephraim 

Utah 

6 

Wasatch 

Plateau 

Emery 

Price Canyon 

Castle Valley 

Price 

Huntington 

San Rafael 

Swell 

Figure 1. Location map of Wasatch Plateau, Utah. After Franczyk and Pitman (1991). 

70 

Roan Cliffs 

Book Cliffs 

6 

Green 

River 

Green River 

0 20 mi

T. 12 S. 

T. 13 S. 

T. 14 S. 

T. 15 S. 

T. 16 S. 

T. 17 S. 

T. 18 S. 

T. 19 S. 

T. 20 S. 

T. 21 S. 

T. 22 S. 

T. 23 S. 

T. 24 S. 

T. 25 S. 

R. 1 E. R. 2 E. R. 3 E. R. 4 E. R. 5 E. R. 6 E. R. 7 E. R. 8 E. R. 9 E. R. 10 E. R. 11 E. 

Juab County 

Gunnison Plateau 

Wasatch monocline 

Sevier County 

Fault 

Sanpete County 

Musina Graben 

of top of Ferron Sandstone 

3000 Contour showing elevation 

Wasatch Plateau 

5500 

3000 

4000 

4500 

5000 

Paradise fault zone 

Fish Creek Graben 

Joe's Valley Graben 

3500 

5000 

4000 

3500 

3500 

3000 

4500 

4000 

4500 

4000 

Straight Canyon syncline 



Syncline, showing 


3500 

Carbon County 

4000 

4500 

3000 

Book Cliffs 

5000 

Emery County 

Ferron Sandstone outcrop edge 

San Rafael Swell 

0 10 mi 

Contours in feet; 

500 foot interval 

Figure 2. Structure map of the Wasatch Plateau area, showing the elevation of the top of the Ferron Sandstone. 

After Tripp (1989).

System Unit 

Upper 

Cretaceous 

Mancos 

Shale 

Ferron 

Sandstone 

Member 

Blue Gate 

Member 

Tununk 

Member 

Upper 

Lower 

Natural 

Gamma 

Resistivity Depth Lithology 

1900 

2000 

2100 

2200 

2300 

2400 

2500 

2600 

2700 

2800 

Depositional 

Environment 

Offshore Marine 

Undivided 

alluvial plain 

and 

delta plain 

Delta front 

Alluvial/delta 

Delta front 


Delta front 


Figure 3. Reference log for the Ferron Sandstone Member from the Willard Pease State of Utah No. 1-Q well. After 

Ryer and McPhillips (1983).

Cenozoic 

Mesozoic 

Tertiary 

Cretaceous 

Eocene 

Paleocene 

Age 

Middle 

(part) 

Early 

Late 

Early 

Maestrichtian 

Campanian 

Santonian 

Coniacian 

Turonian 

Cenomanian 

Albian (part) 

W Wasatch Plateau Area 

E 

Gunnison 

Plateau 

Green River 

Formation 

? 

Colton Fm 

Upper part of 

North Horn Fm 

Tongue of 

Flagstaff Ls 

Lower 

part of 

North 

Horn 

Fm 

conglomerate 

(Indianola Grp?) 

Indianola 

Group 

? 

Sanpete 

Valley 

Indianola 

Group 

Funk 

Valley 

Fm 

East 

Wasatch 

Canyon 

Flagstaff 

Limestone 

North Horn 

Formation 


Six Mile 

Canyon 

Fm 

Sanpete 

Fm 

Allen 

Valley 

Sh 

Star Point Ss 

Price 

Canyon Sunnyside 

Green Sego 

River Canyon Westwater UT-CO Age 

Canyon State Line (106 yr) 


Colton 

Formation 

Flagstaff Mbr of Green River Fm 

Price River Formation 

Emery Sandstone Member 


Blackhawk Formation 

Tununk Member 

Bluecastle Tongue 

Cedar Mountain Formation 


Ferron Ss Mbr 

Wasatch 

Formation 

Dark Canyon 

sequence of Wasatch Fm 

Tuscher and Farrer Formations 

Neslen Fm 

Sego Ss 

Buck Tongue of Mancos Shale 




Figure 4. Stratigraphic column and cross section for Wasatch Plateau and vicinity, northeastern Utah. After Franczyk and Pitman (1991). 

Mancos Shale 

50 

60 

70 

80 

90


The Willamette-Puget Sound trough extends south from Vancouver Island in British Columbia 490 mi 

to the Klamath Mountains in southwestern Oregon (Figure 1) (Johnson et al., 1997; Tennyson, 1995). In 

northern Washington, the Olympic Mountains interrupt this general trend . The Cascade Range forms the 

eastern boundary. The trough extends 50 to 140 mi offshore to an approximate depth of 3,300 ft on the 

continental shelf (Armentrout and Suek, 1985). The southern part of the trough includes the Tyee, South 

Willamette, North Willamette, Nehelem, and Seattle basins. The northern trough includes four subbasins: 

Coos Bay, Newport, Astoria, and Willapa basins (Armentrout and Suek, 1985; Johnson et al., 1997; and 

Tennyson, 1995). 

Around the northern, northeastern and southern margins, accreted terranes of Mesozoic sedimentary, 

volcanic and metamorphic rocks crop out and may underlie the eastern part of the trough (Johnson et al., 

1997; Tennyson, 1995). Up to 20,000 feet of Cenozoic forearc sediments overlie pre-Tertiary igneous and 

metamorphic basement. Figure 2 shows the stratigraphy for various play areas in western Washington. 

Depositional environments included fluvial, fan-delta, delta, shallow-marine, continental-slope and 

submarine fan (Johnson et al., 1997; Tennyson, 1995). 

Oligocene to Pliocene uplift occurred simultaneously with subsidence of local depositional areas. Late 

Miocene basalt flows flooded the Columbia River and northern Willamette Valleys, and associated intrusive 

activity occurred concurrently. The Columbia River deposited deltaic and shallow-marine sediments in 

southwestern Washington and northwestern Oregon (Astoria and Montesano Formations) during Pliocene 

time (Figure 2). Subduction along the continental margin during the Eocene caused extensive folding, 

faulting, uplift and subsidence (Johnson et al., 1997; Tennyson, 1995). 

Conventional sandstone reservoir candidates include the shallow marine Spencer and Cowlitz 

Formations, the deltaic Coaledo Formation, the deltaic to submarine fan Tye Formation, the fluvial 

Chuckanut Formation, and the deltaic Puget Group. 


Many oil and gas seeps occur along the Washington coast, and hydrocarbon exploration began in 1881. 

More than 500 wells have been drilled in the Pacific Northwest, but most are less than 5,000 feet deep. The 

only commercially productive hydrocarbon reservoir in the Willamette-Puget Sound trough is Mist gas 

field, a faulted, structural trap located northwest of Portland, Oregon. Since its discovery in 1979, Mist field 

has produced over 70 BCFG from sandstones in the Eocene Cowlitz Formation. 

Before discovery of the Mist gas field, the only hydrocarbon production in the region came from the 

Bellingham-Watcom County coal fields, the Rattlesnake Hills field near Yakima in the Columbia Plateau, 

and the Grays Harbor Ocean City field, which to date has produced about 12,000 BO plus some associated 

gas.


In the northern Willamette basin, the lower Cowlitz Formation strata entered the oil-generating window 

about 33 Ma (Armentrout and Suek, 1985). Upper Cowlitz rocks entered the generation window at 3 Ma. 

Present-day geothermal gradients average 15 °F per 1,000 ft; thus, present-day reservoir temperatures should 

support gas generation at depths exceeding 7,000 ft. This depth is slightly shallower than the 8,000 ft depth 

of the overpressured envelope. Favorable parameters exist elsewhere in the trough that suggest in-situ gas 

generation is taking place. 

Eocene coals and carbonaceous shales are potential gas-prone source rocks. Total organic carbon (TOC) 

content in the Willamette basin varies from 0.65% to 7.22% for marine shales and siltstones of the Cowlitz 

Formation; interbedded coals have up to 55% TOC. Vitrinite reflectance values range from 0.24 to 4.01 

across the basin (Figure 3). High values result from contact metamorphism near igneous intrusions along 

the Cascades. Projected temperatures within the hydrocarbon generation window range from 90 to 140 °C 

(Armentrout and Suek, 1985). 

The shales encasing the Mist field reservoir are thermally immature, with Ro values less than 0.4% 

(Armentrout and Suek, 1985). The gas within the reservoir probably generated deep in the basin and 

migrated updip into the shallow structural trap.



Geologic 


Accumulation: 


Western Washington Province, Willamette-Puget Sound Trough, basincentered 

gas play 

a. Source/reservoir interval includes Eocene Cowlitz, Puget Group, Raging River, Crescent 

formations and equivalents 


(TOCs) 

c.Thermal maturity Ro 0.24 - 4.01 

range from 0.5 to 7.22% in the middle to upper Eocene marine mudstones in 

the conventional Cowlitz-Spencer gas play area of the Southern Puget 

lowlands. Coals show up to 55% TOCs in the play area. 

d.Oil or gas prone gas prone; almost exclusively type III kerogens 

e.Overall basin maturity maturation levels are moderate and increase east of the trough toward the 

crest of the Cascades 

f.Age and lithologies Eocene arkosic sands, coals, siltstones and shales 

g. Rock extent/quality probable basin-wide source and reservoir-rock distribution. Rock quality is 

unknown except from a few wells and from outcrops around basin margins. 

Expected reservoir quality varies depending on clay content, zeolite 

alteration 

and interbedded shales and coals. 

h.Potential reservoirs none presently; very few conventional reservoirs exist; structurally trapped 

Mist field in northern Oregon has produced more than 70 BCFG. 

i.Major traps/seals interbedded Eocene age shales, siltstones and coals; diagenetic barriers 

might also be expected within micaceous and arkosic sands. 

j.Petroleum 


models 

primarily in-situ generation, but fracture zones offer the possibility of long 

distance migration of gases from shales and coals. Hydrocarbon generation 

is probablyongoing at depths below 7,000 ft. Low current day geothermal 

gradients occur with an estimated 12.5° F exist per 1000 ft (Armentrout and 

Suek, 1985). 

k.Depth ranges 8,000to 13,000 ft plus 

l.Pressure gradients overpressured intervals are referenced in Walsh and Lingley (1991) and 

Johnson et al. (1997)



Economic 


a. Important 


unknown 

b.Cumulative production the only existing production comes from a conventional structural trap at the 

Mist field (discovered in 1979) that has produced 70 BCFG from Eocene 

Cowlitz Fm 

a. High inert gas content gases from the Mist field contain from 2.7 to 5.3% nitrogen (Armentrout and 

Suek, 1985), with traces of CO2. Hydrocarbon composition exceeded 99.9% 

methane. Higher Btu and lower inerts content are expected for gases 

thermally generated within the continuous accumulation. 

b.Recovery Recoveries may vary depending upon permeability, porosity and depth; 

diagenetic alteration may increase with depth. 

c.Pipeline infrastructure poor 

d.Overmaturity Overmature in the deepest parts of the basin and on the eastern flanks of the 

Cascade Range 

e.Basin maturity A large part of the basin is mature (Ro ranges from 0.24 to 4.01) with a rapid 

rise in maturity on the flanks of the Cascade Range. 

f.Sediment consolidation probably moderate to good 


problems 

Shales, clay and mica rich arcosic sands have high alteration potential and 

possible swelling clays. Migrating fines may be a problem and average 

porosities are expected to be highly variable. Shales, siltstones and coals are 

interbedded with sands. 

h.Permeability Permeability declines with depth (Walsh and Lingley, 1991) 

i.Porosity Cowlitz reservoir strata in the Mist field area show porosities from 16 to 

41%. Porosity declines with depth (Walsh and Lingley, 1991)

Willapa 

Basin 

Astoria 

Basin 

Newport 

Basin 

Coos Bay 

Basin 

Vancouver Island 

10 

10 

10 

15 

15 

15 

15 

10 

10 

Eugene 

10 

Klamath 

Mountains 

124° 

10 

15 

10 

Late Cenozoic volcanic rocks 

and basalt flows 

Eocene volcanic rocks 

10 

15 

15 

Seattle 

Portland 

Paleozoic and Mesozoic 

metamorphic and ultramafic rocks 

Cascade Range 

British Columbia 

Washington 

Puget 

Basin 

Willamette 

Basin 

Oregon 

0 50 mi 

Figure 1. Location map of Cenozoic basins of western Washington and Oregon. Isopach contours are in thousands of 

feet. After Braislin et al (1971), Snavely et al (1977), and Armentrout and Suek (1985). 

49° 

42°

Years Ma (millions ago) 

0 

10 

20 

30 

40 

50 

60 

Epoch 

Pleistocene 

Pliocene 

Miocene 

Oligocene 

Eocene 

Paleocene 

Bellingham 

Basin 

local non-marine 

and marine 

deposits 

Boundary Bay 

Formation 

(of Mustard 

and Rouse 1994) 

? 

Huntingdon 

Formation 

Chuckanut 

Formation 

? 

Central Puget Lowland- 

Western Cascade Range 

local non-marine deposits 

Blakely 

Harbor 

Formation 

? 

Blakeley 

Formation 

Renton 

Formation 

Tukwila 

Fm 

Tiger Mtn. 

Formation 

ss 

of 

Scow 

Bay 

? 

Ohanapecosh 

Formation 

Puget 

Group 

Spiketon 

Fm 

Northcraft 

Fm 

Carbonado 

Fm 

Raging River 

Formation 

? 

Southern 

Puget Lowland 

local 

non-marine 

deposits 

Astoria 

Formation 

Lincoln Creek 

Formation 

Skookumchuck 

Fm Cowlitz 

Fm 

McIntosh 

Formation 

Crescent 

Formation 

Southwest Washington 

Coast Range 

upper structural plate 

McIntosh 

Fm 

local marine 

to deltaic 

deposits 

Montesano 

Formation 

Astoria 

Formation 

Lincoln Creek 

Formation 

Crescent 

Formation 

Humptulips 

Fm 

Coastal Washington 

lower structural 

plate 

local marine 

deposits 

Montesano 

Formation 

Tofino-Fuca 

basin 

? ? ? ? 

? 

Hoh 

rock assemblage 

? 

Ozette 

terrane 

Clallam 

Formation 

Twin River 

Group 

Lyre 

Formation 

Aldwell 

Formation 

Crescent 

Formation 

Figure 2. Stratigraphic column for western Washington petroleum-play areas. Shaded intervals indicate occurances of erosion or no deposition. After 

Snavely et al (1958, 1993), Rau (1973, 1986), Frizzell et al (1983), Frizzell and Easterbrook (1983), Rau et al (1983), Rau and Armentrout (1983), 

Snavely and Lander (1983), Johnson (1984a), Palmer and Lingley (1989), Moothart (1992), Johnson et al (1994), Mustard and Rouse (1994), and 

Johnson et al (1997).

6000 

0 

0 

3000 

3000 

6000 

123° 120° 

9000 

0 

0 

9000 

6000 

0 

3000 

6000 

0 50 mi 

Figure 3. Isopach map of depth (in feet) to vitrinite reflectance Ro = 0.5%. The hatchured contours indicate Ro > 1.4% 

(the "oil deadline," or end of oil generation, for this map). After Brown and Ruth (1984), Walsh (1984), 

Evans (1988), Snavely and Kvenvolden (1989), and Walsh and Lingley (1991). 

49° 

47°


The western Colville Basin covers about 64,000 square miles of the western half of Alaska’s North Slope. The Herald Arch 

and the Chukchi Platform form the basin’s western boundary and, west of Icy Cape and Point Barrow, “bend” the offshore part of 

the Colville trough axis northward into the Hanna Trough (Figure 1). The Barrow Arch borders the Colville’s northern flank 

eastward from the Chukchi Sea, and parallels the present Arctic Ocean coastline almost to the Canadian border. The Brooks Range 

thrust belt defines the basin’s eastern and southern limits, and partly overrides the Colville’s south flank along the Southern 

Foothills (Figure 2). 

The North Slope is primarily a composite basin whose northern edge includes late Paleozoic and Mesozoic south-facing 

continental-margin deposits overlain by Cretaceous and Tertiary north-facing foreland-basin sediments (Figure 3) (Bird, 1991); the 

margin rocks also form the southern flank of the present-day Canadian Basin. The Colville Basin itself appears generally 

asymmetrical, with the strata thickest along the Southern Foothills belt and generally thinning northward over the Barrow Arch 

(Figure 4). 

Uplift of the Brooks Range fold and thrust belt began during the Late Jurassic and shed sediments northward into the foredeep 

Colville Basin. Termed the Brookian Sequence, these deposits are mostly clastic and unconformably overlie older Ellesmerian rocks 

along the Barrow Arch (Figure 5). The Ellesmerian Sequence includes sandstones, shales, and up to 25% carbonates. Both 

sequences contain substantial amounts of good to excellent quality source rocks in close physical and stratigraphic proximity to 

porous reservoir units (Figure 4). Colville Basin stratigraphy includes all of the Brookian Sequence and most of the Ellesmerian 

Sequence rocks. At the basin axis, the total combined thickness of the Ellesmerian and Brookian strata may exceed 32,000 ft (Bird, 

1991). 


Outside the Prudhoe Bay complex near the northeast end of the Colville Basin, there is little production on the North Slope. 

The Prudhoe Bay Field contains recoverable petroleum reserves exceeding 13 BBO; oil production generally comes from the Ivishak 

Sand member of the Upper Ellesmerian Sadlerochit Group, and from the Lisburne Group of carbonates in the Lower Ellesmerian. 

1 

The South Barrow gas field presently supplies domestic gas only to the town of Barrow. 


To date, exploration outfits have drilled 41 wells deeper than 4,000 ft in and around the Colville Basin. Many wells had gas or 

oil shows, and consequently identified 13 fields potentially capable of generating gas. Several wells produced gas at rates above 2 

MMCFD. 

Equivalent rocks in Colville strata have already sourced fields along the Barrow Arch, including Prudhoe Bay. Bird (1991) and 

Sedivy et al. (1987) reported total organic carbon (TOC) content for Colville source rocks generally ranged from 1.5 to 3.0 wt%, 

with some oil shales in the Endicott Group reaching 16%. Some of those same source rocks have created overpressure conditions in 

the Prudhoe Bay field and could have charged a basin-centered accumulation in the Colville Basin (Gognat, 1999, personal 

communication).



Geologic 


Accumulation: 


Northern Alaska, Western Colville Basin, possible basin-centered 

accumulation 

a. Source/reservoir Sources: Upper Triassic and Neocomian rocks. Reservoirs: Ivishak Sand, 

Kuparuk River/Kemik Sands, Sag River Sand, sands within the Kingak 

Shale, plus sands within the Nanushuk Group, Colville Group, and 

Sagavanirktok Formation (Figures 4 and 6). 


(TOCs) 

range from 1.5 to 3.0%; some highly organic "paper shales"/oil shale range 

up to 16% 

c. Thermal maturity Maturity over much of the area falls within the peak-oil to peak-gas 

generation stage, with Ro ±2.0 (Figure 4, Figure 6, and Figure 7). The 

deepest parts of the basin may be cracking previously generated oil into gas. 


e. Overall basin maturity immature 

f. Age and lithologies Triassic and younger sands; Mississippian Endicott Group clastics 

g. Rock extent/quality potential 30,000 sq mi source and reservoir-rock distribution. Sandstones in 

the Triassic and younger strata often exceed 20% porosity. 

h. Potential reservoirs Ivishak Sand, Kuparuk River/Kemik Sands, Sag River Sand, sands within the 

Kingak Shale, plus sands within the Nanushuk Group, Colville Group, and 

Sagavanirktok Formation (Figures 4 and 6). 

i. Major traps/seals all traditional hydrocarbon traps 

j. Petroleum 


models 

The Tissot and Welte (1984) “Cooking Pot” model, where generated 

hydrocarbons are expelled into the surrounding reservoir rocks. 

k. Depth ranges 4,000 through 21,000 ft. Some gas production from depths shallower than 

4.000 ft, but occurring from smaller structural and stratigraphic traps 

unrepresentative of basin-centered accumulations (Figure 8). 

l. Pressure gradients Unknown, but many Prudhoe Bay wells intercept overpressured strata and 

some Brooks Range foothills belt wells may have shown occrurence of 

overpressuring.



Economic 


a. Important 


South Barrow, Fish Creek, Umiat, Meade, Simpson, Wolf Creek, Gubik, 

Square Lake, East Umiat, East Barrow, East Kurupa, Eagle Creek, Walakpa, 

and Sikulik (Figure 9). 

b. Cumulative production see Figure 10. Outside the Prudhoe Bay producing complex, there is little 

production on the North Slope. South Barrow Gas field presently supplies 

only domestic gas to the town of Barrow. 

a. High inert gas content possible, but unknown 

b. Recovery unknown 

c. Pipeline infrastructure poor to non-existent 

d. Overmaturity the base of the dry gas zone in the central Colville Basin area probably 

occurs below a depth of 19,500 ft (after Johnsson et al., 1993) 


f. Sediment consolidation moderate to good 


problems 

unknown 

h. Permeability probably high, but variable 

i. Porosity highly variable, but porosity in reservoirs exceeds 20%

Russia 

USA 

Herald 

Arch 

Chukchi Platform 

Hanna 

Chukchi Sea 

Axis 

Trough 

Brooks 

Oil field 

Well 

Well projected onto 

cross-section A-A' 

Figure 1. Map of the North Slope, Alaska. 

Southern 

Barrow 

Northern Foothills 

of Colville Basin 

Coastal Plain 

A 

NPRA 

A' 

Foothills 

Range 

(Passive Margin) 

Arch 

Beaufort Sea 

Kuparuk River Field 

Prudhoe Bay Field 

0 100 mi 

0 160 km 

Scale 

Arctic National 

Wildlife Refuge 

(ANWR)

Russia 

USA 

Herald 

Arch 

Chukchi Platform 

-4 

-6 

-2 

North 

Chukchi Basin 

-8 

Thrust fault 

Brooks 

Normal fault, hachures 


Contour, in km 

below sea level 

Figure 2. Structure map of the North Slope, Alaska. 

-6 

-10 

Hanna 

Axis 

-8 

Trough 

-10 

of 

-10 

-8 

-6 

-2 

Southern 

Barrow 

B 

-4 

Colville Basin 

-10 

-2 

-4 

-6 

-8 

Coastal Plain 


-10 

-10 

-6 

-6 

IB 

-8 

Foothills 

Range 

Arch 

UB 

-8 

Beaufort Sea 

-6 

-6 

-8 

-4 

-8 

-6 

-10 

B' 

-10 

0 100 mi 

0 160 km 

Scale

Chukchi 

Sea 

UTm 

Upper Tertiary marine 

UKm Upper Cretaceous marine 

UKc 

LKm 

Axis 

LKm 

Lower Cretaceous marine 

Figure 3. Geologic map of the North Slope, Alaska. 

of 

Brooks 

UKc 

LKc 

Foothills 


LTc 

LKc 

LKm 

Coastal Plain 

UKm 

Range 

Lower Tertiary continental 

UKc 

Upper Cretaceous continental 

Lower Cretaceous continental 

LTc 

UTm 

Kuparuk River Field 

Prudhoe Bay Field 

0 100 mi 

0 160 km 

Scale 

Oil field

Elevation in feet 

5000 

0 

5000 

10000 

15000 

20000 

25000 

30000 

South North 

A 

Brooks 

Range Foothills 

LSB 

Endicott Grp 

1.3 


Oil well 

Gas well 

Fault, showing direction 

of movement 

Colville River Teshekpuk Lake 

Figure 4. Cross-section A-A' of North Slope, Alaska. After Bird (1991). 

2.0 

Mean vitrinite reflectance % Ro 


Coastal Plain Coastline Continental Shelf 

EKP WFC3 SQL IGK NIK ETK DLT 

2.0 

0.6 

Torok Formation 

Pre-Mississippian 

Kingak Shale 

Nanushuk Group 

Sadlerochit Grp-Shublik Fm-Sag River Ss 

Endicott 

Group 

Umiat Basin 

Lisburne Group 

Colville Group 


Barrow Arch 

0 20 mi 

Scale 

No vertical exaggeration 

Nuwok Basin 

A'

Eon or 

Period 

Quaternary 

and 

Neogene 

Paleogene 

Cretaceous 

Jurassic 

Triassic 

Permian 

Pennsylvanian 

Mississippian 

Devonian 

Silurian 

Ordovician 

Cambrian 

Proterozoic 

Age 

(Ma) 

2 

24 

50 

66 

98 

144 

oup 

208 

245 

286 

320 

360 

408 

438 

505 

570 

Main potential reservoirs 

Main source rocks 

South and west North and east South North 

No Data 

Etivluk Gr 

No Data 

Lisburne 

Peninsula 

Stratigraphy Tectonic Events 

Colville 

Group 

Nanushuk 

Group 

Fortress Mtn 

Formation 

? 

Iviagik 

Group 

Pebble shale unit 

? 

? 

Kingak 

Shale 

Fire Creek Siltstone 

Member 

Kavik Member 

? 

Echooka 

Formation 

No Data 

Romanzof 

Mountains 

Sagavanirktok 

Formation 

Torok 

Formation 

Canning 

Formation 

Hue Shale 

Shublik Formation 

Lodge Sandstone 

Member 

Gubik Formation 

Gamma-ray zone 

Lower Cretaceous unconformity 

Kemik Sandstone 

Kuparuk Formation 

Simpson Sandstone 

Barrow Sandstone 

Sag River and Karen Creek 

sandstones, undivided 

Ivishak 

Formation 

Itkilyariak 

Formation 

Kayak Shale Kekiktuk 

Conglomerate 

? 

? 

? 

? 

Lisburne Group 

Neruokpuk 

Quartzite 

Mount Copleston 

Limestone 

? Nanook Limestone 

? 

Sadlerochit and 

Shublik Mountains 

Katakturuk Dolomite 

Sadlerochit 

Group 

Condensed basinal deposits 

Hiatus or erosional deposits 

Figure 5. Generalized stratigraphic column of North Slope subterrane (Arctic Alaska terrane). Ordovician and 

Silurian Iviagik Group is that of Martin (1970). Jurassic Simpson and Barrow sandstones are of local 

usage. Brookian sequence depicts North Slope units only; less well-known Brookian rocks in Lisburne 

Peninsula and northeastern Brooks Range are not shown. Absolute time scale (Palmer (1983) is 

variable. After Moore et al (1994) and Bird (1991). 

Endicott 

Group 

Brookian 

Sequence 

Ellesmerian 

Sequence 


Rocks 

(Sediment Provenance) 

(Transport SW to NE) 

Brooks Range Orogeny 

Colville Basin Subsiding 

Chert 

Marine shale 

Marine calcareous shale 

Marine clastic rocks 

Coarse-grained non-marine 

clastic rocks 

Conglomerate 

Limestone 

Dolomite 

(Sediment Provenance) 

(Transport N to S) 

Volcanic rocks 

Beaufort Sea 

Basin Subsiding 

Rifting 

Orogeny 

Sandy limestone

Elevation in Miles 

Elevation in Miles 

2 

1 

0 

-1 

-2 

-3 

-4 

-5 

-6 

0 

-1 

-2 

-3 

-4 

-5 

-6 

0.25 

0.6 

0.13 

2.0 

Post-Cenomanian 

rocks 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 

AWV OUM ECM KLU IGK NIK WFC FHC 

eroded section 

Present Day 

Late Cretaceous 

≈ 75 Ma 

Torok Formation and 

pebble shale unit, 

undivided 

Ikpikpuk- 

Umiat Basin 

Sadlerochit, Lisburne, 

and Endicott Groups, 

undivided 

Nanushuk Group 

Kingak Sh, Sag River 

Ss, and Shublik Fm, 

undivided 

Basement rocks 

Vitrinite Reflectance (%R o) 

Figure 6. Present-day and Late Cretaceous cross-sections B-B' of North Slope, Alaska, showing down-hole vitrinite reflectance values (%R o) 

1 

Well 

Oil field 

Barrow Arch 

0 50 mi 

0 100 km 

Vertical Exaggeration ≈ 15x 

coastline 

sea level 

0.25 

0.6 

1.3 

2.0 

4 

2 

0 

-2 

-4 

-6 

-8 

0 

-2 

-4 

-6 

-8 

-10 

Elevation in Kilometers 

Elevation in Kilometers

Russia 

USA 

Herald 

Arch 

Chukchi Sea 

Axis 

Immature 

Oil window 

Gas window 

Brooks 

Southern 


of Colville Basin 

Coastal Plain 

NPRA 

Foothills 

Beaufort Sea 

Figure 7. Thermal maturity of subsurface Shublik Formation and Kingak Shale, North Slope, Alaska. After Bird (1991). 

Range 

0 100 mi 

0 160 km 

Scale 

Arctic National 

Wildlife Refuge 

(ANWR)

-3550 

Axis of 

Well 

-8476 

Depth to top of 

overpressure (ft) 

Chukchi Sea 

-4200 to -6200 

-2682 

Colville 

Brooks 

-8015 

-475 ? 


Southern 

Coastal Plain 

0 100 mi 

0 160 km 

Figure 8. Approximate subsea depth to top of overpressure, North Slope, Alaska. Data from some US Navy wells (1944-53) is suspect. 

-5071 

Basin 

> -5094 

-2596 

-4371 

Range 

-1382 ? 

-5131 

-3775 

KNF 

-100 ? 

Foothills 

-11,000 

-388 ? 

-650 ? 

-4298 

Scale 

Beaufort Sea 

-2342 

-3550 

-1344 

-1187

Axis of 

Meade (4) 

AKK 

Eagle Creek (12) 

Field 

Well 

Chukchi Sea 

EGC 

Brooks 

Figure 9. Location map of wells and fields in North Slope, Alaska. 

TKC 

Colville 

TUN 

KAO 

PRD 


KUG 

Southern 

AWU 

South Barrow (1) 

Sikulik (14) 

Walakpa (13) 

Meade (4) 

Basin 

Coastal Plain 

MDE 

SBW3 

WKP1 

WKP2 

BTS 

SMD 

Range 

SBW1 

AVK 

KUY 

OUM 

LSB 

WDS 

TUP 

East Barrow (10) 

TUL 

SMP 

EOM 

ETP 

WKP 

NSM 

SSM 

ESP2 

FLU 

TIT 

KNF 

ESP1 

KLK 

IPK 

Simpson (5) 

DWP 

Foothills 

DLT 

ETK 

NIK 

IGK 

SQL 

EKP 

0 100 mi 

0 160 km 

Scale 

Beaufort Sea 

CPH 

Square Lake (8) 

Wolf Creek (6) 

East Kurupa (11) 

WFC3 UMT1 

FRN 

NKP 

WFC 

SBE 

UMT2 

ABB 

ATP 

FHC 

UMT11 

UMT5 

GRD 

SHB 

Fish Creek (2) 

Umiat (3) 

GBK1 

Gubik (7) 

GBK2 

East Umiat (9)

Axis of 

AKK 

AKK 

0.57 psi/ft 11080' Ft Mtn 

1.435 mmcfd 10470-11080' 

Torok/Ft Mtn 

OP 6200' - 12049' (TD) 

Well 

0.59 psi/ft 10810' Ft Mtn 

Tool plugged, no recovery 

OP 8500' - 17030' (TD) 

Chukchi Sea 

EGC 

TKC 

0.64 psi/ft 

32.0 mcfd 

5.1 mcfd 

Colville 

4655' Nanushuk 



+ 120 bbl water- 

Final rate 75 bwpd, no gas 

24.0 mcfd 7634' Torok 

OP 2800' - 8212' (TD) 

Brooks 

Range 

Southern 


Basin 

Figure 10. Oil and gas production data from selected wells in North Slope, Alaska. 

AWU 

0.87 psi/ft 

2057 bwpd 

Coastal Plain 

8243' Ft Mtn 

8243' Ft Mtn 

OP 6200' - 11200' (TD) 

0.53 psi/ft 

213 mcfd 

61 bbl water 

LSB 

11841' Lisburne 

7010' Shublik 

7662' Lisburne 

OP 6230' - 8040' (TD) 

0.47 psi/ft 

5 mcfd 

decrease to zero 

+ 33 bbl water 

+ mud 

10 mcfd 

+ 14 bbl water 

+ 4 bbl mud 

WKP 

"Tight hole" 

10190' Ft Mtn 

7070' Torok 

7950' Torok 

OP 6500' - 11060' (TD) 0.82 psi/ft 

3.8 mmcfd 

KLK 

EKP 

Foothills 

0 100 mi 

0 160 km 

Scale 

Beaufort Sea 

No tests 

OP 3600' - 10737' (TD) 

ABB 

400 mcfd 

Recovered 

47 bbl water 

10780' Ft Mtn 

7190' Torok 

12148' Ft Mtn 

OP 5900' - 12695' (TD)

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1 

POTENTIAL FOR A BASIN-CENTERED GAS ACCUMULATION IN THE 

ALBUQUERQUE BASIN OF NEW MEXICO 

INTRODUCTION 

By Ronald C. Johnson, Thomas M. Finn, and Vito F. Nuccio 

The Albuquerque Basin occupies the central portion of the Rio Grande rift system, an area of presently 

active extensional tectonics that extends from the Upper Arkansas Valley near Leadville, Colorado 

southward through New Mexico-Mexico into the state of Chihuahua, Mexico (Figure 1). The Rio Grande 

Rift is part of the greater Basin and Range province that has been undergoing extension since Oligocene 

time. 

For the past 24 years, the U.S. Geological Survey has been studying basin-centered gas deposits in 

Rocky Mountain basins under various projects funded what is now called the United States Department of 

Energy National Energy Technology Lab in Morgantown West Virginia. These investigations have added 

greatly to our understanding of these “unconventional” deposits formed. Basin-centered gas deposits cover 

vast areas of the deeper parts of Rocky Mountain basins formed during the Laramide orogeny (Late 

Cretaceous through Eocene) and appear to contain huge resources of in-place gas. These “unconventional” 

gas deposits are different from conventional gas deposits in that they occur in predominantly tight (< 0.1 

millidarcy) rocks, cut across stratigraphic units, occur downdip from water-bearing reservoirs, and have no 

obvious structural or stratigraphic trapping mechanism. Reservoirs within the accumulations are almost 

always either abnormally overpressured or abnormally underpressured indicating that they are isolated from 

the regional groundwater table. 

The Albuquerque Basin was chosen for study because its geologic history is significantly different from 

other Rocky Mountain basins that contain identified basin-centered gas accumulations. Like Laramide 

basins, the Albuquerque Basin contains a thick interval of Cretaceous-age coals, carbonaceous shales and 

marine shales. In Laramide basins, these Cretaceous-age source rocks are thought to be the source for gas 

found in basin-centered gas accumulations. Unlike the Laramide basins studied previously, the Albuquerque 

Basin is a currently actively subsiding. Subsidence in Laramide basins, in contrast, largely ceased near the 

end of the Eocene. Laramide basins have undergone significant erosion and cooling within the last 10 

million years as a result of regional uplift of the entire Rocky Mountain region. Rates of gas generation in 

Laramide basins have markedly declined since regional uplift began. In fact, gas generation has probably 

ceased altogether in all but the deeper areas of these basins. Thus gas is probably not being replenished to 

these accumulations, as fast as it is leaking out, and there is good evidence that these deposits are actively 

shrinking. 

In the Albuquerque basin, in contrast, source rocks for hydrocarbons are under near-maximum burial 

conditions and near maximum heating throughout the deeper areas of the basin. Gas is being generated by 

these source rocks today. This gas is probably migrating and accumulating in Upper Cretaceous sandstones 

at the present time. Whether this gas may be creating a basin-centered type gas accumulation is the subject 

of this report. 

STRUCTURE AND STRATIGRAPHY 

The Albuquerque Basin occupies the central portion of the Rio Grande rift, a series of generally northsouth-trending 

en echelon extensional basins that extend from central Colorado to at least southern New 

Mexico (Chapin, 1971; 1979). The basin contains a thick section of sedimentary rocks ranging in age from 

Mississippian to Recent (Figure 2). Rifting began about 32 to 27 million years ago in middle Oligocene 

time and is probably still occurring at the present time. The Albuquerque Basin covers an area of about 

2,160 square miles (5,600 km 2 ) and is one of the deepest basins along the Rio Grande rift (Lozinsky, 1994). 

In 1979, Shell drilled a well to a depth of 21,266 ft in one of the deepest parts of the basin and did not reach 

the base of the Oligocene and younger rift fill. Seismic data published by Russell and Snelson (1984) 

demonstrates that the basin generally consists a deep inner graben flanked by shallower benches (Figures 3-

6). The inner graben in the northern part of the basin is tilted eastward while in the southern part the 

graben is tilted westward. An east-west zone of accommodation occurs between these two opposite tilted 

blocks. 

Of importance to this investigation is a pre-Eocene unconformity which has removed varying amounts 

of the Cretaceous section in northern New Mexico, including the Albuquerque Basin area. The Cretaceous 

section contains both source and principle reservoir rocks for basin-centered gas accumulations in other 

Rocky Mountain basins, and had the Cretaceous section been largely removed by this unconformity there 

would be little chance that a basin-centered accumulation would be present in the basin. Both surface control 

on the flanks of the Albuquerque Basin and subsurface control within the basin indicate that much of the 

Cretaceous section is intact, although the Cretaceous section is completely removed in the Española Basin 

to the north (Molenaar, 1988). Cretaceous strata is similar to the highly gas productive Cretaceous interval 

in the San Juan Basin to the north, and many of the same stratigraphic names are used in both basins 

(Figure 2). 

DRILLING ACTIVITY IN THE ALBUQUERQUE BASIN 

The Albuquerque Basin has been sparsely explored for hydrocarbons. At the present time there is no 

established hydrocarbon production in the basin and no drilling for hydrocarbons since 1984. At least 46 

wells have been drilled for hydrocarbons in the basin with the oldest known test drilled in 1914. Drilling 

prior to 1953 was mainly shallow, penetrating only the Tertiary fill within the basin (Figure 18) (Black, 

1982). Numerous oil and gas shows were reported with these shallow tests. After 1953, the Cretaceous 

section beneath the Tertiary fill became the primary target for exploration (Black 1982). 

Between 1972 and 1976 Shell drilled five deep tests in the basin targeting Cretaceous rocks. These 

wells were largely targeting structures defined by seismic. The first well, the Shell no. 1 Santa Fe in sec. 

18, T. 13N., R. 3E. was drilled to a depth of 11,045 ft and bottomed in Precambrian basement. The second 

well, the Shell no. 1 Laguna Wilson Trust in sec. 8, T. 9N., R1W. was drilled to a depth of 11,115 ft and 

also bottomed in Precambrian. The third well, the Shell no. 2 Santa Fe in sec. 18, 13N., 1E. was drilled to 

a depth of 10,276 and bottomed in Triassic. All three wells encountered gas shows in the Cretaceous section 

but no completions were attempted. The fourth well drilled by Shell in 1974 was the no. 1 Isleta well in 

sec. 7, T. 7N., R. 2E. (Figure 3). The well penetrated the top of the Cretaceous section at 12,110 ft. It 

encountered a series of faults near the base of the nonmarine Cretaceous section, and the Dakota Sandstone, 

the primary objective of the test, was cut out. According to Black (1982, p. 315) the well encountered 

“tight” gas-saturated sandstones in the nonmarine Cretaceous interval. Several intervals were perforated in 

the nonmarine part of the Cretaceous between 12,209 ft and 13,246 ft, and non-commercial amounts of gas 

were produced. Maximum reported production was 29 MCFGPD between 13,210 and 13,226 ft. In 1976, 

Shell drilled the no. 3 Santa Fe well in sec. 28, T. 13N., R. 3E. to a depth of 10,276 ft and bottomed in 

the Triassic. Again, gas shows were encountered in the Cretaceous. 

In 1978, Shell farmed out part of their acreage to Trans Ocean who drilled the no. 1 Isleta well in sec. 

8, T. 8N., R. 3E. to a depth of 10,378 ft. The well bottomed in Precambrian and encountered gas shows in 

the Cretaceous. In 1979 Shell drilled the no. 2 Isleta well in sec. 16, T. 8N., R. 2E. The well was drilled to 

a depth of 21,266 ft and did not reach the Cretaceous. In 1980 and 1981 Shell drilled the Shell 1 West Mesa 

well in sec 24, T. 11N, R. 1E. to a 19,375 ft. and reportedly flared several hundred thousand cubic feet per 

day from the Cretaceous section (Black, 1989). The well was eventually plugged and abandoned apparently 

because rates of production were insufficient at these drilling depths to be economic. The last oil and gas 

test drilled in the Albuquerque Basin was the Utex no. 1-1J1E well in sec 1, T. 10N, R. 1E. The well 

apparently bottomed in the Point Lookout Sandstone at 16,665 ft. No tests or completions were reported. 

2

BOREHOLE TEMPERATURE DATA 

Previous investigations have found that there is unusually high heat flow in the vicinity of the Rio 

Grand Rift (Decker, 1969; Reiter and others, 1975; Edwards and others, 1978; Clarkson and Reiter, 1984), 

although there is some suggestion that the area of high heat flow occurs across a broad area of New Mexico 

and southern Colorado and is not confined to the immediate vicinity of the rift (Edwards and others, 1978; 

Clarkson and Reiter, 1984). Many heat flow measurements in the Albuquerque Basin area, however, have 

been taken at shallow depths. These heat flow measurements can be affected by local groundwater 

convection and hence may not be good measurements of regional heat flow patterns (Clarkson and Reiter, 

1984). 

Geothermal gradients calculated from temperatures recorded during logging runs in oil and gas tests is a 

less precise way to measure variations in heat flow since geothermal gradients vary between different 

lithologies. Nonetheless, geothermal gradients are commonly used because the data is readily available. 

Geothermal gradients were calculated by Grant (1982) for eight of the deepest boreholes in the basin. Grant 

(1982) calculated only one gradient for each hole using the temperature recorded at the bottom of the hole. 

Here we calculated geothermal gradients for all the temperatures recorded while these eight drill holes were 

being drilled. Figure 7 plots all geothermal gradients calculated for the eight drillholes. An average 

geothermal gradient was also calculated for each drillhole using all of the temperature readings taken. The 

standard AAPG correction factor was applied to all of the recorded temperatures, and a mean annual surface 

temperature of 45 o F was used. A correction factor is required because the rocks in the immediate vicinity of 

the borehole are quenched by comparatively cool mud circulated through the borehole during drilling. The 

time between when mud circulation stops and the temperature is recorded is seldom long enough for 

temperatures in the vicinity of the borehole to re-equilibrate. 

Geothermal gradients calculated from different logging runs in the same drillhole were surprisingly 

consistent. For instance, the eight individual geothermal gradients calculated for the Shell no. 1 Isleta hole 

varied from 1.77 o F/100 ft to 2.48 o F/100 ft. If only the six deepest temperatures are used variation is only 

from 1.95 o F/100 ft to 2.15 o F/100 ft. Shallower temperature readings in boreholes are generally less 

reliable than deeper readings largely because of the greater times required for borehole temperatures to reequilibrate 

once mud circulation is stopped. Average geothermal gradients for the eight drillholes varied 

from 1.7 o F/100 ft to 2.3 o F/100 ft (Figure 19). These values are not significantly different from geothermal 

gradients throughout northern New Mexico (Geothermal Gradient Map of North America, 1976). 

BURIAL RECONSTRUCTIONS FOR THE ALBUQUERQUE BASIN 

Burial reconstructions were made for three deep drillholes in the Albuquerque Basin from the time of 

deposition of the Cretaceous Dakota Sandstone to the present. The three wells used have picks on the tops 

of all three Cretaceous units used here the Dakota Sandstone, the Point Lookout Sandstone, and the 

Menefee Formation. These wells, the Shell no. 3 Santa Fe, the Shell no. 1 Santa Fe, and the Shell no. 1- 

24 West Mesa (Figure 3) were modeled using BasinMod version 7.01 developed by Platte River Associates 

in order to determine the timing of hydrocarbon generation. The Shell no. 3 Santa Fe and no. 1 Santa Fe are 

near cross section A-A’ in a comparatively shallow area in the northern part of the basin. The Shell no. 1- 

24 West Mesa well is in a much deeper part of the basin further to the south. 

Isopach maps of Tertiary rocks in the Albuquerque Basin were constructed using data from Lozinsky 

(1994) in order to better understand the subsidence history of the basin and to help define the deepest parts of 

the basin where a basin-centered gas accumulation is likely to occur. The isopach maps were constructed 

using only drillhole data, and no attempt was made to incorporate seismic information. The maps are thus 

very generalized and do not show thickness variations that occurs from the stair step faulting within the 

basin. The first isopach map is of the Eocene Galistero and Baca formations (Figure 9). Although these 

units predate the onset of subsidence in the basin, they nonetheless thicken somewhat toward the deep 

trough of the basin. The second isopach map (Figure 10) is of the Galistero and Baca formations and the 

overlying “unit of Isleta no. 2 well” defined by Lozinski (1994, p. 77). The unit is thought to be Late 

Eocene to Late Oligocene in age and thus spans the onset of rifting in the Albuquerque Basin. By Late 

Oligocene over 2,500 m of sediments and volcanic rocks (present day thickness) had accumulated along the 

3

developing deep basin trough west of Albuquerque (Figure 10). The last isopach map includes all Tertiary 

rocks and sediments to the present. More than 6,500 m of sediments and volcanic rocks have accumulated 

along the deep basin trough. 

The data used for the burial reconstruction’s is shown on the stratigraphic charts in Figure 12. The 

Cretaceous stratigraphy of the Albuquerque Basin is similar to that of the San Juan Basin to the north. 

Principle Cretaceous stratigraphic units used in the burial reconstruction’s are the Dakota Sandstone, the 

Point Lookout Sandstone and the top of the Menefee Formation. These units have not been placed within 

the standard Western Interior Cretaceous biozones in the area of the Albuquerque Basin but have been 

extensively studied in the San Juan Basin to the north. In the eastern part of the San Juan Basin the Dakota 

Sandstone in the San Juan Basin falls within the Acanthoceras amphibolum biozone (Dane, Cobban, and 

Kauffman, 1966) which has been dated at about 95 million years (Obradovich, 1993). The Point Lookout 

Sandstone falls near the top of the Scaphites hippocrepis zone (Gill and Cobban, 1966) which is dated at 

about 81.5 million years (Obradovich, 1993). The top of the Menefee Formation is assumed to be in the 

Baculites obtusus ammonite zone, which is about the age of the top of the Menefee in the easternmost part 

of the San Juan Basin (Gill and Cobban, 1966, Pl. 4). Age of the Baculites obtusus zone is 80.5 million 

years (Obradovich, 1993). 

Thickness of the interval from the top of the Dakota Sandstone to the top of the Point Lookout 

Sandstone varies from 2,071 ft in the Shell no. 1-24 West Mesa Well to 2,593 ft in the Shell no. 3 Santa 

Fe well. This is similar to the San Juan Basin where Law (1992) reported thicknesses of 2,020 ft and 2,200 

ft for the same interval (Law, 1992, figs. 6 and 7). The interval from the top of the Point Lookout to the 

top of the Cretaceous interval vary much more widely from 0 ft in the Shell no. 1-24 Mesa well to 2,070 ft 

in the Shell no. 3 Santa Fe well. This variation is due to differences in the amount of section removed 

beneath the Cretaceous-Tertiary unconformity. The same interval in the two wells cited by Law (1992) in 

the San Juan Basin varies from 2,980 ft for the well on the south flank of the basin to 4,020 ft for the well 

near the basin trough. 

As in the Albuquerque Basin, varying amounts of erosion beneath the Cretaceous-Tertiary 

unconformity are largely responsible for this variation. Law (1992, fig. 9) estimated that about 300 ft of 

section had been removed beneath the Cretaceous-Tertiary unconformity at the location near the basin 

trough for a total original thickness of post Point Lookout section of 4,320 ft. He (Law, 1992, fig, 10) 

estimated that about 750 ft of section had been removed beneath the unconformity at the location on the 

south flank of the basin for a total original thickness of 3,730 ft of post Point Lookout Cretaceous rocks. 

For the Albuquerque Basin reconstructions we will assume an original thickness of 4,000 ft of post Point 

Lookout Sandstone Cretaceous rocks. 

Figure 11 shows the sediment thicknesses and ages used in the burial reconstruction’s of the three 

wells. Age of the oldest rocks above the Cretaceous-Tertiary is Eocene (Lozinsky, 1994). An age of 50 

million years is assumed for the oldest Eocene strata at all three wells modeled. These Eocene strata are also 

present on the flanks of the Albuquerque Basin and predate the onset of rifting. It is assumed that 

downcutting of Cretaceous strata beneath the unconformity began at the end of the Cretaceous 66 million 

years ago and continued at an even pace until 50 million years ago. For two wells, the Shell no. 3 Santa Fe 

and the Shell no. 1 Santa Fe continuous deposition at a constant rate is assumed from 50 ma to the present. 

Somewhat more data is available for the Shell 1-24 West Mesa well. According to Lozinski (1994), 1109 ft 

of strata were deposited by late Eocene time, about 40 ma. An additional 7,169 ft of strata was deposited 

between 40 ma and the end of the Oligocene 25 ma. The remaining 8,540 ft of fill was deposited between 

25 ma and the present. Geothermal gradients used are 1.9 o F/100 ft for the no. 3 Santa Fe well, 2.1 o F/100 

ft for the Santa Fe no. 1 well, and 1.7 o F for the 1-24 West Mesa well. 

The burial reconstruction’s indicate that in two of the wells, the Shell no. 1 Santa Fe and the Shell 

no. 3 Santa Fe, potential source rocks in the Mancos Shale and overlying Cretaceous section are immature 

and have not generated significant hydrocarbons (Figures 13, 14). In the third well, the Shell no. 1-24 West 

Mesa, hydrocarbon generation began at the base of the Mancos Shale about 20 million years ago (Figures 

15-17). Cretaceous source rocks had not generated significant amounts of hydrocarbons prior to the onset of 

rifting and creation of the Albuquerque Basin in the Oligocene. The onset of significant hydrocarbon 

generation in the Shell no. 1-24 well corresponds to a temperature of about 212 o F (105 o C). Using an 

average geothermal gradient of 2.0 o F/100 ft (3.3 o C/100 m) for the basin, this temperature would occur at a 

4

depth of about 8,350 ft. (2,545 m). The Cretaceous section has been buried to this depth over a large area of 

the Albuquerque Basin (Figure 10). 

FORMATION PRESSURES 

Basin-centered accumulations are typically abnormally overpressured or abnormally underpressured, 

with overpressuring the result of volume increases during hydrocarbon generation and underpressured 

conditions developing during uplift and cooling. Because the Albuquerque Basin is currently under 

maximum burial and heating, it is unlikely that any basin centered accumulation there would be 

underpressured. If overpressured conditions exist in the basin then a basin-centered accumulation may be 

present. The most reliable formation pressure information is obtained from drillstem tests. Only two of the 

ten deepest wells in the basin had a reliable drillstem test in the Cretaceous section. The Dakota Sandstone 

was tested in the Shell 1 Laguna-Wilson Trust well (Figure 3) at a depth of 3,600 to 3,651 ft. The test 

recovered 48 barrels of water. Shut-in pressures indicate a fluid pressure gradient of 0.43 psi/ft indicating a 

normal pressure gradient. The Shell no. 1 Santa Fe well also tested the Dakota Sandstone but at a much 

greater depth of 6,720 to 6,753 ft. This test recovered 5,172 ft of water. Shut-in pressures indicate a fluid 

pressure gradient of 0.43 psi/ft or again normal hydrostatic pressure. The normally pressured water in the 

shallow test would be expected, as a basin-centered accumulation would not be expected at this depth. The 

deeper water test at over 6,700 ft is problematical. Active gas generation might be expected at this depth. 

Less reliable formation pressure information can be obtained from mud-weights measured during 

drilling. A continuous record of mud-weights used is typically recorded on mudlogs made while drilling. 

Mudlogs, however, are generally not available to the public. Spot recordings of mud-weights at the time of 

logging runs are listed on the header information on geophysical logs. Figure 12 plots mud-weights versus 

depth for nine of the deepest wells in the basin. A mud-weight of 10 lbs. corresponds to a pressure gradient 

of .519 psi/ft or moderate overpressuring. High mud-weights were used while drilling through the 

Cretaceous section in five of the deeper wells in the basin. 

CONCLUSIONS 

It appears likely that the deep central portion of the Albuquerque contains a basin-centered gas 

accumulation that is developing at the present time. The area contains a largely intact Cretaceous section 

similar to the Cretaceous interval that contains a basin-centered accumulation in the nearby San Juan Basin. 

High mud weights are typically used while drilling the Cretaceous interval in this area suggesting some 

degree of overpressuring. Gas shows have been reported while drilling through the Cretaceous interval 

throughout this area. Attempts to complete gas wells in the Cretaceous have resulted in sub-economic 

quantities of gas, primarily because of “tight rocks.” Little water has been reported. All of these 

characteristics are typical of basin-centered gas accumulations in other Rocky Mountain basins. Burial 

reconstruction’s suggest that large amounts of gas are being generated by Cretaceous source rocks at the 

present time. This is different from other Rocky Mountain basins were rates of gas generation have declined 

significantly since regional uplift and downcutting began about 10 million years ago. This regional uplift 

was offset in the Albuquerque Basin by rapid subsidence. 

The last attempt to complete a Cretaceous gas well in the Albuquerque Basin was in 1984. At that 

time, basin-centered gas was sub-economic throughout the Rocky Mountain region, and financial incentives 

by the government were required in order to entice oil and gas companies to drill these deposits. Subsequent 

improvements in completion technology has made basin-centered gas economic without financial incentives 

in many areas of the Rockies. Applying these new technologies to completing gas wells in the Albuquerque 

Basin should result in improved economics. 

5

REFERENCES CITED 

6 

Black, B. A., 1982, Oil and gas exploration in the Albuquerque Basin: in Grambling, J. A., and Wells, 

S. G., eds., Albuquerque Country II: New Mexico Geological Society Guidebook, 33 rd Field 

Conference, p. 313-324. 

Black, B. A., 1989, Recent oil and gas exploration in the northern part of the Albuquerque Basin: in 

Lorenz, J. C., and Lucas, S. G., eds., Energy Frontiers in the Rockies: Companion Volume for 

the 1989 Meeting of the American Association of Petroleum Geologists, Rocky Mountain 

Section, Hosted by the Albuquerque Geological Society Oct. 1-4, 1989, p. 13-15. 

Black, B. A., and Hiss, W. L., 1974, Structure and stratigraphy in the vicinity of the Shell Oil Co. 

Santa Fe Pacific No. 1 test well, southern Sandoval County, New Mexico: in Siemers, C. T., 

Woodward, L. A., and Callender, J. F., eds., Ghost Ranch Central-Northern New Mexico: New 

Mexico Geological Society Twenty-Fifth Conference, p. 365-370. 

Chapin, C. E., 1971, the Rio Grande rift, Part I-Modifications and additions: in James, H. L., ed., 

Guidebook of the San Luis Basin: New Mexico Geological Society, 22 nd Field Conference 


Chapin, C. E., 1979, Evolution of the Rio Grande rift-A Summary: in Riecker, R. E., ed., Rio Grande 

Rift, Tectonics and Magmatism: America Geophysical Union, Washington, D. C., p. 1-5. 

Clarkson, G. and Reiter, M., 1984, Analysis of terrestrial heat-flow profiles across the Rio Grand Rift 

and southern Rocky Mountains in northern New Mexico: in Baldridge, W. S., Dickerson P. W., 

Riecker, R. E., and Zidek, J., eds., Rio Grand Rift: Northern New Mexico: New Mexico 

Geological Society Thirty-fifth Annual Field Conference, Oct. 11-13, 1984, p.39-44. 

Dane, C. H., Cobban, W. A., and Kauffman, E. G., 1966, Stratigraphy and regional relationships of a 

reference section for the Juana Lopez member, Mancos Shale in the San Juan Basin, New 

Mexico: U.S. Geological Survey Bulletin 1224-H, p. 1-15. 

Decker, E. R., 1969, Heat flow in Colorado and New Mexico: Journal of Geophysical Research, v. 74, 

p. 550-559. 

Edwards, C. L., Reiter, M., Shearer, C., and Young, W., 1978, Terrestrial heat flow and crustal 

radioactivity in northeastern New Mexico and southeastern Colorado: Geological Society of 

America Bulletin, v. 89, p. 1341-1350. 

Geothermal Gradient Map of North America, 1976, American Association of Petroleum Geologists and 

the U.S. Geological Survey. 

Gill, J. R., and Cobban, W. A., 1966, The Red Bird section of the Upper Cretaceous Pierre Shale in 

Wyoming: U.S. Geological Survey Professional Paper 393-A, 73 p. 

Law, B. E., 1992, Thermal maturity patterns of Cretaceous and Tertiary rocks, San Juan Basin, 

Colorado and New Mexico: Geological Society of America Bulletin, vol. 104, p. 192-207. 

Lozinsky, R. P., 1994, Cenozoic stratigraphy, sandstone petrology, and depositional history of the 

Albuquerque Basin, central New Mexico: in Keller, G. R., and Cather, S. M., eds., Basins of the 

Rio Grand Rift: Structure, Stratigraphy, and Tectonic Setting: Geological Society of America 

Special Paper 291, p. 73-81. 

Lucas, S. G., 1984, Correlation of Eocene rocks of the northern Rio Grande Rift and adjacent areas: 

implications for Laramide tectonics: in Baldridge, W. S., Dickerson P. W., Riecker, R. E., and 

Zidek, J., eds., Rio Grand Rift: Northern New Mexico: New Mexico Geological Society Thirtyfifth 

Annual Field Conference, Oct. 11-13, 1984, p. 123-128. 

May, S. J., and Russell, L. R., 1994, Thickness of the syn-rift Santa Fe Group in the Albuquerque 

Basin and its relation to structural style: in Keller, G. R., and Cather, S. M., eds., Basins of the 

Rio Grand Rift: Structure, Stratigraphy, and Tectonic Setting: Geological Society of America 


McDonald, R. E., 1972, Paleocene and Eocene rocks of the central and southern Rocky Mountain 

basins: in Mallory, W. W., ed., Geologic Atlas of the Rocky Mountain Region: Rocky 


Molenaar, C. M., 1988, Cretaceous and Tertiary rocks of the San Juan Basin: in Sloss, L. L., ed., 

Sedimentary Cover-North American Craton: U.S., Chapter 8, Basins of the Rocky Mountain

7 

Region: The Geological Society of America, Decade of North American Geology, The Geology 

of North America, Volume D-2, p. 129-134. 

Molenaar, C. M., 1988, Petroleum and hydrocarbon plays of the Albuquerque-San Luis rift basin, New 

Mexico and Colorado: U.S. Geological Survey Open-File Report 87-450-S, 26 p. 

Obradovich, J. D., 1993, A Cretaceous time scale: in Caldwell, W. G. E., and Kauffman, E. G., eds., 

Evolution of the Western Interior Basin: Geological Association of Canada Special Paper 39, p. 

379-396. 

Reiter, M., Edwards, C. L., Hartman, H., and Weidman, C. 1975, Terrestrial heat flow along the Rio 

Grande rift, New Mexico and southern Colorado: Geological Society of America Bulletin, v. 86, 

811-818. 

Russell, L. R., and Snelson, S., 1994, Structure and tectonics of the Albuquerque Basin segment of the 

Rio Grand rift: in Keller, G. R., and Cather, S. M., eds., Basins of the Rio Grand Rift: 

Structure, Stratigraphy, and Tectonic Setting: insights from reflection seismic data: Geological 

Society of America Special Paper 291, p. 83-112.

40° 

37° 

32° 

108° 104° 

San Luis Basin 

San Juan Volcanic Field 

Brazos Uplift 

Chama Basin 

Jemez volcanic field 

Nacimiento Uplift 

Santo Domingo Basin 

Albuquerque - Belen 

Basin 

Lucero uplift 

Landron Uplift 

San Agustin 

Basin 

Black Range 

Uplift 

Cuchillo Negra 

Uplift 

Eagle Basin 

Palomas Basin 

Mimbres Basin 

Potrillo Volcanic 

Field 

COLORADO 

Normal Fault 

Thrust Fault 

Upper Arkansas Graben 

High-angle Reverse Fault 

Sangre De Cristo 

Uplift 

Española Basin 

Sandia Uplift 

Manzano Uplift 

Los Pinos Uplift 

Socorro Constriction 

San Marcial Basin 

Fra Cristobal Uplift 

Sacramento Uplift 

Caballo Uplift 

Jornada Uplift 

Tularosa Uplift 

Mesilla Basin 

NEW 

MEXICO 

EXPLANATION 

Cenozoic Sedimentary Rocks (Riftfill) 

Tertiary Volcanic Rocks 

Precambrian Crystalline Rocks 

Figure 1: General location map of basins and uplifts along that part of the Rio Grand Rift that occurs within 

the United States (modified from Russell and Snelson, 1994).

CENOZOIC 

MESOZOIC 

PALEOZOIC 

ERA 

AGE 

RECENT 

PLEISTOCENE 

PLIOCENE 

MIOCENE 

OLIGOCENE (?) 

EOCENE 

PALEOCENE 

CRETACEOUS 

NIOBRARA 

BENTON 

JURASSIC 

TRIASSSIC 

PERMIAN 

PENNSYLVANIAN 

MISSISSIPPIAN 

DEVONIAN 

PRE-CAMBRIAN 

STRATAGRAPHIC 

FORMATIONS 

ALLUVIUM, DUNES, 

LANDSLIDES, SOIL ZONES 

OGALLALA FM 

DEVILS HOLE FM 

VOLCANIC INTRUSIONS, 

PLUGS, DIKES, SILLS 

INTRUDES ENTIRE SECTION 

FARASITA FM 

HUERFANO FM 

CUCHARA FM 

POISON CANYON FM 

RATON FM 

VERMEJO FM 

TRINIDAD SS 

PIERRE SH 

SMOKY HILL MARL 

FT HAYES LS 

CARLILE SH 

GREENHORN LS 

GRANEROS SH 

DAKOTA SS PURGATOIRE FM 

MORRISON 

WANAKAH 

ENTRADA 

DOCKUM GROUP 

BERNAL FM 

SAN ANDRESS LS 

GLORIETA SS 

YESO FM 

SANGRE DE 

CRISTO FM 

MAGDALENA GROUP 

TERERRO FM 

ESPIRTU SANTO FM 

MALFIC GNEISS 

METAQUARTZITE GROUP 

GRANITE & GRANITE GNEISS 

LITHOLOGY 

0 - 200' 

200 - 500' 

0 - 1500' 

0 - 1200' 

0 - 2000' 

0 - 5000' 

0 - 2500' 

0 - 2075' 

0 - 360' 

0 - 255' 

1300 - 2900' 

900' 

0 - 55' 

165 -225' 

20 - 70' 

175 - 400' 

140 -200' 

100 -150' 

150 - 400' 

30 - 100' 

40 - 100' 

0 - 1200' 

0 - 125' 

10 - 20' 

0 -200' 

200 - 400' 

700 - 5300' 

4000 - 5000' 

40 - 50' 

25' 

7000' ? 

5000' ? 

4000' ? 

THICKNESS 

OIL AND 

GAS SHOWS 

RATON COAL 

(GAS) 

VERMEJO COAL 

(GAS) 

NIOBRARA 

(OIL) 

? 

GRANEROS 

(OIL) 

POTENTIAL 

SOURCE ROCKS 

INTRUSIVES 

MIOCENE 

EXTENT OF 

INTRUSION 

SHALLOW 

GAS 

OBJECTIVE 

SECTION 

Figure 2: Generalized stratigraphic chart for the Albuquerque Basin (from Molenaar, 1988). 

R-potential reservoir rock; SR-potential source rock.

B 

Lucero Uplift 

Ladron 

Mtns 

Nacimento 

Mtns 

10 

Quaternary Alluvium 

Tertiary-Quaternary Sedimentary Rocks 


8 

4 

A 

2 

13 

14 

9 

5 

6 

3 

1 

C C' 

Rio 

Puerco 

BERNARDO 

BELEN 

BERNALILLO 

7 

11 

12 

ALBUQUERQUE 

Rio Grande 

0 10 20 Miles 

Paleozoic-Mesozoic Sedimentary Rocks 


High Mudweights used in Creataceous 

1 Shell Santa Fe-1, 11045', (P-C) 

2 

3 

4 

5 

Shell Santa Fe-2, 14305', (Tr) 


Shell Laguna-1, 11115', (P-C) 

Shell Isleta-1, 16346', (P) 

6 Shell Isleta-2, 21260', (Tert.) 

7 Transocean Isleta-1, 10322', (P-C) 

8 Humble Santa Fe-1, 12690', (UK) 

9 Carpenter Atrisco-1, 6653', (Tert.) 

10 Humble Santa Fe, B1, 6016', (P-C) 

11 Grober-1, 6300', (Tert.) 

12 Norrins Realty-2, 5024', (Tert.) 

13 Shell 1-24 West Mesa, 19375', (Tr) 

14 UTEX 1-1J1E, (UK) 

Normal Fault 

Reverse Fault 

Transcurrent Fault 

Fault of Multiple Displacement 

Figure 3: Generalized geologic map of the Albuquerque Basin showing deep drillholes and seismic lines 

(modified from Russell and Snelson, 1994). Wells in which high (>10 lb.) mud was used while 

drilling through the Cretaceous section are also shown. 

B' 

Manzano 

Mtns 

A' 

Los 

Pinos 

Mtns 

Sandia 

Mtns 

Manzanita 

Mtns

Km 

2.5 

0 

-2.5 

-5.0 

-7.5 

-10.0 

WEST 

COLORADO 

PLATEAU 

Humble 

Feet Sante Fe B-1 

10,000 

High 

Mudweights 

Shell 

West Mesa Sante Fe-3 

Fault 

NORTH GRABEN BLOCK 

Shell 

Sante Fe-1 

EAST 

ALBUQUERQUE 

BENCH EASTERN STABLE BLOCK 

HAGAN EMBAYMENT 

Rio 

Feet 

Grande 

Rio Grande 

San Francisco- Espanaso 

10,000 

Fault 

Placitas Fault Ridge 

5,000 

5,000 

Sea Level 

-5,000 

-10,000 

-15,000 

-20,000 

-25,000 

-30,000 

A A' 

Cenozoic Rift Fill* Mesozoic Sedimentary Rocks Paleozoic Sedimentary Rocks Precambrian Crystalline Rocks 

*Note: Pre-rift lower Tertiary section indicted 

where decernable on Seismic or in wells 

Horizontal Scale = Vertical Scale 

Figure 4: Interpreted east-west seismic cross section of the northern part of the Albuquerque Basin. Line of section shown on Figure 3. 

High mud weights were used in the Shell No. 3 Santa Fe while drilling the Cretaceous section (modified from Russell and 

Snelson, 1984). 

Sea Level 

-5,000 

-10,000 

-15,000 

-20,000 

-25,000 

-30,000

N37° 

SAGUACHE 

ALAMOSA 

R 72 W R 70 W R 68 W 

R 66 W R 64 W R 62 W R 60 W 

NEW 

MEXICO 

COSTILLA 

COLORADO 

0 15 Miles 

0 20 Km 

COLORADO 

NEW MEXICO 

TAOS COLFAX 

W105° 


1.2 

1.2 

0.8 

0.7 

PUEBLO 

HUERFANO 

1.3 

1.1 

1.0 

Cucharas 

Stonewall Trinidad 

North Pontilo Creek 

1.5 

1.3 

1.4 

0.9 

Walsenburg 

0.9 

1.1 

1.0 

0.8 

0.7 

River 

Vermejo River 

Purgatoire River 

LAS ANIMAS 

River 

Apishapa 

EXPLANATION 

Low-volatile bituminus 

Medium-volatile bituminus 

High-volatile A bituminus 

High-volatile B bituminus 

High-volatile C bituminus 

Tertiary intrusive rocks 

T 

25 

S 

T 

27 

S 

T 

29 

S 

T 

31 

S 

T 

33 

S 

T35S 

T32N 

Eagle 

Nest 

0.7 

ARI Inc. (1991) 

Close (1988) 

Lake 

Cimarron 

Syncline 

T26N 

R 16 E R 18 E R 20 E R 22 E R 24 E R 26 E 

Raton 

Trinidad Sandstone- 

Pierre Shale contact 

Figure 5: Interpreted east-west seismic cross section of the central part of the Albuquerque 

Basin. Line of section shown on Figure 3. High mud weights were used in the Transocean 

No. 2 Isleta while drilling the Cretaceous section (modified from Russell and 


T 

30 

N 

T 

28 

N

N37° 

SAGUACHE 

ALAMOSA 

R 72 W R 70 W R 68 W 

R 66 W R 64 W R 62 W R 60 W 

COLORADO 

NEW 

MEXICO 

COSTILLA 

0 15 Miles 

0 20 Km 

COLORADO 

NEW MEXICO 

TAOS COLFAX 

W105° 

Raton Basin synclinal axis 

Stroud Apache 

Canyon area 

PUEBLO 

HUERFANO 

Amoco Cottontail 

Pass unit 


Raton 

Basin synclonal axis 

Walsenburg 

Lorencito 

Canyon area 

Evergreen Spanish 

Peak unit 

C.I.S. exploration 

project 

EXPLANATION 

Producing area 

Potential producing area 

Syncline 

Cimarron 

T26N 

R 16 E R 18 E R 20 E R 22 E R 24 E R 26 E 

Raton 

LAS ANIMAS 

Trinidad Sandstone- 

Pierre Shale contact 

Figure 6: Interpreted east-west seismic cross section of the southern part of the Albuquerque 

Basin. Line of section shown on Figure 3. The east part of the cross section was constructed 

from geologic inference and is not based on seismic data. High mud weights were used 

while drilling the Humble no. 1 Santa Fe and Pacific well (modified from Russell and 


T 

25 

S 

T 

27 

S 

T 

29 

S 

T 

31 

S 

T 

33 

S 

T35S 

T32N 

T 

30 

N 

T 

28 

N

N37° 

SAGUACHE 

ALAMOSA 

R 72 W R 70 W R 68 W 

R 66 W R 64 W R 62 W R 60 W 

COLORADO 

NEW 

MEXICO 

COSTILLA 

0 15 Miles 

0 20 Km 

COLORADO 

NEW MEXICO 

TAOS COLFAX 

W105° 

PUEBLO 

HUERFANO 

Huerfano River River 

25 

35 

West Spanish 

Peak 


25 20 

15 

La Veta 

East Spanish 

Peak 

North Pontilo Creek 

15 

45 

Casa Grande 

10 

Walsenburg 

Cucharas 

Vermejo River 

Purgatoire River 

LAS ANIMAS 

EXPLANATION 

>400 

300 - 400 

200 - 300 

Eagle 

100 - 200 

Nest 

Lake 

Cimarron 

Lucero Uplift 

B 

Ladron 

Mtns 

Nacimento 

Mtns 

8 

4 

95 

A 

10 

200 

427 

300 

2 

122 

400 

200 

3 

338 

13 

14 

9 

5 

294 

6 

454 

100 

300 

1 

205 

7 

0 

C C' 

Rio 

Puerco 





BERNARDO 

BELEN 

BERNALILLO 

11 

12 

ALBUQUERQUE 

Rio Grande 

0 10 20 Miles 

0 

B' 

Manzano 

Mtns 

A' 

Los 

Pinos 

Mtns 

Sandia 

Mtns 



454 Control Point 

400 

Contour interval : 100 Feet 


2 

3 

4 

5 

Manzanita 

Mtns 










11 Grober-1, 6300', (Tert.) 



14 UTEX 1-1J1E, (UK) 

Normal Fault 

Reverse Fault 



Figure 8: Isopach map of the Eocene Galistero and Baca formations, Albuquerque Basin, using data 

from Lozinsky (1994, Table 1).

Lucero Uplift 

B 

Ladron 

Mtns 

Nacimento 

Mtns 

8 

4 

A 

1051 

10 

1097 

2 

22 

1500 

13 

14 

9 

1000 

1000 

5 

6 

3 

2075 

1500 

2523 

2500 

2000 

991 

1 

7 

11 

205 

C C' 

Rio 

Puerco 





BERNARDO 

BELEN 

BERNALILLO 

12 

ALBUQUERQUE 

Rio Grande 

0 10 20 Miles 

0 

0 


2 

3 

4 

5 










11 Grober-1, 6300', (Tert.) 



14 UTEX 1-1J1E, (UK) 

Figure 9: Isopach map of the Eocene Galistero and Baca formations and unnamed “unit of Isleta #2 well” 

(late Eocene to late Oligocene?) identified by Lozinsky (1994) in the Shell No. 2 Isleta well in sec. 16, 

T. 8N., R. 2E. All thickness data used is from Lozinsky (1994, Table 1). The approximate area where 

the top of the Cretaceous section had achieved a temperature of 100 °C at the end of the time period 

represented by the isopach interval is shown. The isotherm assumes that the average present-day 

geothermal gradient of 2.0 °F/100 ft (see fig. 8). 

B' 

Manzano 

Mtns 

A' 

Los 

Pinos 

Mtns 

Sandia 

Mtns 




1000 

Contour interval : 500 Feet 

Manzanita 

Mtns 

Normal Fault 

Reverse Fault 


Fault of Multiple Displacement

Lucero Uplift 

B 

Ladron 

Mtns 

Nacimento 

Mtns 

8 

4 

A 

10 

2591 

50 

1245 

30 

13 

14 

60 

9 

5482 

5 

20 

6 

3 

10 

20 

30 

40 

50 

3679 

1 

1110 

BERNALILLO 

7 

1384 

1236 

C 40 

C' 

2511 

2 

BELEN 

11 

Rio 

Puerco 





BERNARDO 

10 

12 

ALBUQUERQUE 

Rio Grande 

B' 

Manzano 

Mtns 

0 10 20 Miles 

A' 

Los 

Pinos 

Mtns 

Sandia 

Mtns 


2 

3 

4 

5 




20 Contour interval : 1000 Feet 

Manzanita 

Mtns 










11 Grober-1, 6300', (Tert.) 



14 UTEX 1-1J1E, (UK) 

Normal Fault 

Reverse Fault 



100 °C at top of Cretaceous 150 °C at top of Cretaceous 

Figure 10: Isopach map of the total present-day thickness of Tertiary rocks in the Albuquerque Basin using 

subsurface drillhole data of Lozinsky (1994, Table 1). Tertiary faults are ignored and hence the isopach 

map is generalized. The approximate areas where the top of the Cretaceous has achieved a temperature 

of 100 °C and 150 °C at the present are shown. The isotherms assume an average present-day 

geothermal gradient of 2.0 °F/100 ft (see fig. 8).

0 

3995' 

72' 

50 MY 

66 MY 

4000' 

81.5 MY 

2593' 

95 MY 

SHELL 

#3 SANTA FE 

DAKOTA 

GRADIENT 

1.9°/100' 

0 

2969' 

50 MY 

66 MY 

81.5 MY 

95 MY 

EXPLANATION 

673' 

4000' 

2070' REMAINING 

COALS ABOVE 

POINT LOOKOUT 

POINT LOOKOUT 

MANCOS 

(SOURCE) 

2222' 

SHELL 

#1 SANTA FE 

Sandstone with Shale 

Mainly Shale 

DAKOTA 

GRADIENT 

2.1°/100' 

Coal 

0 

8540' 

25 MY 

7169' 

40 MY 

1109' 

50 MY 

66 MY 

4000' 

736' REMAINING 

81.5 MY 

POINT LOOKOUT 

MANCOS 

(SOURCE) 

2071' 

95 MY 

SHELL 

1-24 WEST MESA 

Missing Interval 

POINT LOOKOUT 

MANCOS 

(SOURCE) 

DAKOTA 

GRADIENT 

1.7°/100' 

0' REMAINING 

Figure 11: Stratigraphic diagrams showing present-day thicknesses and ages of rocks in the three wells 

used for burial reconstructions.

Depth (feet) 

25000 

20000 

15000 

10000 

5000 

EXPLANATION 

Depth (feet) 

Linear [Depth (feet)] 

150 °C 

100 °C 

0 0 2 4 6 8 10 12 

Mudweight (pounds) 

Figure 12: Graph of mud weight versus depth for the nine wells listed in Table 4. Approximate depth to 

the 100 °C and 150 °C isotherms are shown assuming an average geothermal gradient of 

2.0 °F/100 ft for the entire Albuquerque Basin.

Depth Subsurface (feet) 

0 

2000 

4000 

6000 

8000 

Shell #3 Sante Fe 

K P E O M P R Fm 

100°(F) 

10000 150 100 50 0 

Age (my) 

200°(F) 

t=0 

Tert 

Sandstone 

Mesaverde 1 

Mancos 

Dakota 

Figure 13: Burial reconstruction showing thicknesses of sediments and temperatures on °F for the Shell No. 3 Santa Fe well 

in sec. 28, T. 13N., R. 1E. Location of well shown on Figure 3.


0 

2000 

4000 

6000 

K 

Shell #1 Sante Fe 

100°(F) 

8000 150 100 50 0 

Age (my) 

P E O M P R Fm 

200°(F) 

t=0 

Tert 

Sandstone 

Mesaverde 1 

Mancos 

Figure 14: Burial reconstruction showing thicknesses of sediments and temperatures in °F for the Shell No. 1 Santa Fe well 

in sec. 18, T. 13N., R. 3E. Location of weltl shown on Figure 3. 

Dakota


0 

5000 

10000 

15000 

Shell 1-24 West Mesa 

K P E O M P R Fm 

100°(F) 

20000 150 100 50 0 

Age (my) 

100(F) 

200°(F) 

300°(F) 

t=0 

Tert 

Tert 1 

Sandstone 

Mancos 

Figure 15: Burial reconstruction showing thicknesses of sediments and temperatures in °F for the Shell No. 1-24 West Mesa well 

in sec. 24, T. 11N., R. 1E. Location of well shown on Figure 3. 

Dakota

Rate of Oil Generation (mg/g TOC*my) 

40 

30 

20 

10 


K P E O M P R 

0 Mancos 

150 100 50 0 

Age (my) 

Figure 16: Rate of oil generation in milligrams (mg) per gram (g) of total organic carbon (TOC) per million years (my) at the base of the 

Cretaceous Mancos Shale in the Shell No. 1-24 West Mesa well in sec. 24, T. 11N., R. 1E. Location of well shown on Figure 3.

Rate of Gas Generation (mg/g TOC*my) 

8 

6 

4 

2 


K P E O M P R 

0 

150 100 50 0 

Age (my) 

Figure 17: Rate of gas generation in milligrams (mg) per gram (g) of total organic carbon (TOC) per million years (my) at the base of the Cretaceous 

Mancos Shale in the Shell No. 1-24 West Mesa well in sec. 24, T. 11N., R. 1E. The second peak, which began about 5 ma is due to the breakdown 

of oil to gas. Location of well shown on Figure 3. 

Mancos

NUMBER OF WILDCATS 

10 

9 

8 

7 

6 

5 

4 

3 

2 

1 

ALBUQUERQUE BASIN 

WILDCAT HISTORY 

PRIMARY 

TERTIARY 

EXPLORATION 

1900 1910 1920 1930 1940 1950 1960 1970 1980 

YEARS 

PRIMARY 

MESOZOIC 

EXPLORATION 

SHELL'S 

PROGRAM 

Figure 18: Histogram showing exploration activity in the Albuquerque Basin from 1900 to 1984 (modified from Black, 1982).

Corrected temperature, in degrees Fahrenheit 

0 1000 2000 3000 4000 5000 6000 7000 

450 

400 

350 

300 

250 

200 

150 

100 

50 

Albuquerque Basin, composite 

2438 m 

2591 m 

3139 m 

Depth, in meters 

3962 m 

0 

0 5000 10000 15000 20000 25000 

100 °C 

Depth, in feet 

Figure 19: Bottom-hole temperatures recorded during logging runs for selected deep tests in the Albuquerque Basin. The geothermal 

gradients listed are average values for the entire hole calculated from uncorrected bottom-hole temperatures assuming a mean 

annual surface temperature of 45 °F.

ABSTRACT 

IS THERE A BASIN-CENTER GAS ACCUMULATION 

IN THE DEEP ANADARKO BASIN ? 

By Michael S. Wilson, Consulting Geologist 

Well data, formation test results and published studies of abnormal pressures, methane isotopes and thermal 

maturity were reviewed to evaluate the possibility that a basin-center gas accumulation might exist within the 

regionally overpressured Mississippian and Pennsylvanian-age Atoka, Morrow and Springer Groups or in the 

Mississippian and Devonian-age Woodford Shale in the central Anadarko basin, Oklahoma. 

The Woodford Shale is a laterally extensive, organic-rich source rock which has passed completely through the 

gas generation window in the deepest parts of the basin, but it does not appear to have developed overpressures on a 

regional scale. A review of drilling mud weights and pressure data indicate that the Woodford-Hunton interval has 

generally been drilled with 9 to 10.5 ppg mud and appears to be normally to subnormally pressured throughout most 

of the central basin. The underlying Hunton Group contains high permeability zones which frequently produce 

subnormally or normally pressured salt water. Hydrocarbons expelled from the Woodford Shale may have migrated 

downward into the Hunton aquifer and then moved laterally into structural and stratigraphic traps. Two isolated 

overpressured compartments were identified where high mud weights and unusual casing designs were used for the 

Woodford section. These appear to be uplifted fault blocks where structural juxtaposition of the Woodford Shale and 

overpressured Springer shales may have locally modified the typical plumbing system. The Woodford Shale does 

not appear to fit the basin-center gas model on a regional scale. 

The Atoka-Morrow-Springer section has many characteristics of known basin-center gas accumulations, 

including mature, gas-prone source rocks, temperatures greater than 200 °F, severe overpressures, tight sandstone 

reservoirs, and extensive gas production. However, formation test data and published descriptions of known gas 

fields reveal numerous examples of gas-water contacts and water production within the overpressured section. Most 

commercial gas accumulations have been found in traditional structural and/or stratigraphic traps, but many of the 

known gas reservoirs are water-saturated below distinct gas-water contacts. The available porosity in the reservoirs 

was apparently not fully charged with gas. Perhaps the source rocks were not rich enough, or perhaps they cooled 

down and ceased gas expulsion too early, so that the porosity available in the numerous sandstones was not 

completely gas-saturated. Depending on current interpretations of just how much moveable water is allowable in a 

‘continuous-type’ gas accumulation, the overpressured Atoka-Morrow-Springer section appears to contains too much 

moveable water. It does not quite fit the basin-center gas model on a regional scale. 

Several reservoir zones within the deep Anadarko Basin may be completely gas-saturated on a local scale. Well 

data and formation tests at North Broxton Field (T. 6 N., R. 12 W., Caddo County, Oklahoma) and Elk City Field 

(T. 10 N., R. 20 - 21 W., Washita and Beckham Counties, Oklahoma) indicate severe overpressures, high 

temperatures, prolific gas production and almost no water production from the Springer section at depths of 

approximately 18,500 to 20,500 feet. Further study of formation test results and detailed log analyses are 

recommended to determine if the deep Springer section might contain a small-scale basin-center gas accumulation. 

INTRODUCTION 

Well data, formation test results and published studies of abnormal pressures, methane isotopes, source rocks 

and thermal maturity were evaluated to determine if a basin-center gas accumulation might exist within the 

Mississippian and Devonian-age Woodford Shale or in the overpressured Mississippian and Pennsylvanian-age 

Atoka, Morrow and Springer section within the central Anadarko basin of western Oklahoma and northern Texas. 

Extensive overpressuring, high reservoir temperatures, mature source rocks, tight sandstone reservoirs and prolific 

gas production indicate that a continuous, basin-center gas accumulation might occur within this basin. However, 

detailed investigations of well logs and test results from several gas fields and various exploration wells show that

eservoirs with distinct downdip gas-water contacts have been found frequently within the overpressured zone. The 

porosity available within the overpressured mega-compartment may be only partly saturated with gas. 


The Anadarko basin (fig. 1) is a Pennsylvanian and Permian-age foreland depocenter located along a Cambrianage 

aulacogen (rift) in central Oklahoma, southwestern Kansas and northern Texas. The tectonic history of the 

region has been described by Brewer and others (1983), Hill (1984), Perry (1989), and Price (1998a). The basin is 

bounded on the south by the Wichita Frontal Fault Zone, a complex series of strike-slip and reverse faults along the 

northern edge of the Amarillo-Wichita Uplift (McConnell and others, 1990; Price, 1998a). Interpretations of seismic 

data acquired by COCORP (Brewer and others, 1983) show that basement blocks were thrust over the southern part 

of the basin along several reverse faults dipping 30 to 40 degrees to the southwest (fig. 2). Basement is 

approximately 35,000 to 40,000 feet below the surface in the deepest part of the basin (Perry, 1989). The basin 

becomes shallower to the north and emerges into a broad, shallow shelf in northwestern Oklahoma and southern 

Kansas. 

STRATIGRAPHY 

The sedimentary section in the Anadarko basin (fig. 3) includes shallow marine carbonates and clastics ranging 

from Cambrian through Silurian age, truncated by a regional unconformity at the top of the Silurian Hunton Group. 

The unconformity is covered by several hundred feet of Devonian and Lower Mississippian-age Woodford Shale and a 

thick section of shallow marine carbonates. These are overlain by marine and deltaic clastic rocks of Upper 

Mississippian through Permian age, including numerous sandstone and conglomerate units within the Springer, 

Morrow and Atoka Groups. Pennsylvanian-age arkosic conglomerates (Granite Wash) interfinger with the marine 

and deltaic section along the flanks of the Amarillo-Wichita Uplift. 

SOURCE ROCKS AND THERMAL MATURITY 

Hydrocarbon source rocks in the Anadarko basin include oil-prone shales in the Ordovician-age Viola Group, oilprone 

marine shales in the Mississippian and Devonian-age Woodford Shale, and gas-prone marine and deltaic shales 

in the Mississippian and Pennsylvanian-age Caney Formation, Springer Group and Pennsylvanian-age Morrow 

Group (Wang, 1993; Wang and Philp, 1997). Powers (1994) suggested that Caney, Springer and Morrow shales 

have high potential for hydrocarbon generation. The Caney Formation was deposited in deep marine environments 

within the southern Anadarko basin, and contains black-colored, bituminous shale with occasional siderite nodules 

(Peace, 1994). Upper Springer and Morrow shales were deposited in prodelta and delta environments (Al-Shaieb and 

others, 1990) and are described as gray to black-colored with thin coal seams and dispersed lignite fragments. Burruss 

and Hatch (1992) noted that Pennsylvanian-age Morrow and Springer shales are one of the three major source rock 

sections in the Anadarko Basin, and have gas-prone, Type III kerogen and TOC values greater than 1%. Wang 

(1993) found average TOC values of 1.65 % in Springer shale samples and 1.0% in Morrow shale samples. Plots of 

Hydrogen Index versus T-Max indicate that these source rocks contain mostly Type III, gas-prone kerogen. Price and 

others (1981) found TOC values ranging from 0.9% to 1.7% in the Morrow-Springer-Goddard section at 18,400 to 

22,500 ft in the Bertha Rogers No. 1 well (Washita County, Oklahoma). 

Vitrinite reflectance in the Morrow group ranges from less than 0.5% in the northern shelf near the Oklahoma- 

Kansas border to more than 3 % in the central Anadarko basin (Al Shaieb and others, 2000). Recent thermal 

maturity models indicate that the Atokan, Morrow and Springer Groups have been buried within the oil and gas 

generation window in the central Anadarko basin since the end of Pennsylvanian time (Carter and others, 1998).

The Woodford Shale has been studied by Pawlewicz (1989), Cardott and Lambert (1986, 1987), Comer and 

Hinch (1987), Cardott (1989), Hester and others (1990), Roberts and Mitterer (1992), Wang (1993), Price (1997), 

and Gallardo and Blackwell (1999). The Woodford ranges from 100 to 300 feet thick in the deep part of the basin. It 

unconformably overlies limestones and dolomites of the Devonian-age Hunton Group, and is covered by the 

Mississippian-age Osage, St. Louis and St. Genevieve Limestones. The Woodford is a rich, oil-prone source rock 

containing Type I and II kerogen. Hester and others (1990) and Wang (1993) described average total organic content 

(TOC) of 3 to 5%. Comer and Hinch (1987) noted TOC values ranging from 5.5 to 8.1% and abundant bitumen 

residue. 

Maps of vitrinite reflectance of the Woodford Shale (Cardott and Lambert, 1986; Cardott, 1989; Gallardo and 

Blackwell, 1999) show values of 0.5 to 1.0 %Ro along the shallow northern shelf, and much higher values in the 

deep basin. A generalized vitrinite reflectance versus depth profile (fig. 4) shows that Ro exceeds 1% at depths below 

10,000 feet, 2% below 20,000 feet and reaches 4 % below 24,000 feet (Pawlewicz, 1989; Price, 1997; Price and 

others, 1981). Reflectance values as high as 4.8% have been measured in the Woodford within a deep ‘hot spot’ in 

Roger Mills and Beckham Counties, just north of the Wichita Frontal Fault Zone. The Woodford Shale is still 

within the oil window along the shallow flanks and northern shelf of the basin, but it passed completely through the 

gas maturity phase in the deepest part of the basin by the end of Permian time (Carter and others, 1998). 

McMechan and Conway (1983) noted that the Anadarko basin has some of the lowest thermal gradients in 

the continental United States. Kennedy (1982) presented a temperature profile for deep wells drilled in the Anadarko 

basin, with a shallow temperature gradient of 1.0 °F/100 ft down to the top of the Morrow, and a steeper temperature 

gradient of 1.2 °F/100 ft through the overpressured Morrow-Springer-Caney section. Pawlewicz (1989) calculated 

thermal gradients for 29 deep wells in the Anadarko Basin and found that temperatures generally increase at 1.0 to 1.3 

°F/100 ft. He noted that vitrinite reflectance measurements for several wells do not match the present-day 

temperatures, and suggested that significant cooling may have occurred in this basin. Schmoker (2000) suggested 

that at least 2,000 ft of sediments may have been eroded from the surface of the Anadarko basin since Cretaceous 

time, and may have contributed to recent cooling in the subsurface. Basin models presented by Al Shaieb and others 

(2000) show approximately 3,000 feet of uplift and erosion since the Laramide Orogeny. 

PRESSURES IN THE WOODFORD SHALE AND HUNTON GROUP 

Well data and drilling mud weights were reviewed to determine if abnormal pressures might occur within the 

Woodford Shale and underlying Hunton Group in the central Anadarko basin. Al-Shaieb and others (1994, 2000) 

indicate that the overpressured megacompartment complex extends down into the Woodford section. However, mud 

weight data for 40 deep wells scattered throughout the central basin (Table 1) indicate that the Woodford section has 

generally been drilled with 9 to 10.5 ppg mud at depths ranging from 11,100 to 27,500 feet. These moderate mud 

weights indicate near-normal pore pressures on a regional scale. The Woodford has passed completely through the 

gas window, but the absence of regional overpressuring indicates that hydrocarbons expelled from the Woodford may 

have escaped into other zones without developing overpressures. Hydrocarbon-charged overpressure has apparently 

not been sustained within the Woodford interval on a regional scale. 

The Woodford Shale section appears to be locally overpressured in two isolated compartments located in T. 10 

N., R. 24-25 W., and in T. 8-9 N., R. 16-17 W. High mud weights and unusual casing designs were used in two 

deep wells at Southwest New Liberty Field: M.R.T Sanders Unit No. 1 (Sec. 24, T. 10 N., R. 25 W.) and M. R. T. 

Kirtley Unit No. 1 (Sec. 19, T. 10 N., R. 24 W.). Casing was set just above the Woodford in each of these wells 

and the Woodford was penetrated using 15.2 and 16.5 ppg mud, indicating that overpressuring may have been a 

problem. Liner was set at the base of the Woodford, and the deeper Hunton section was drilled using only 9.8 and 

9.4 ppg mud. A bottom hole pressure of 12,000 psi was reported in a gas-productive Hunton reservoir at 23,920 - 

24,996 feet (0.49 psi/ft) indicating near-normal pressure (Kennedy, 1982). The reason for casing off the Woodford 

before drilling into the Hunton is unclear, but may involve M.R.T Company’s special drilling practices or an 

unusual structural geometry. Unusually high drilling mud weights were also used in two wells which penetrated the 

Woodford Shale in the Cordell Fold Belt (Kennedy, 1982). The Phillips Wesner A No. 1 well (Sec. 35, T. 9 N., R.

17 W., Washita County) and the Forest Oil Bobwhite No. 1 (Sec. 16, T. 8 N., R. 16 W., Washita County) used 

18.1 ppg and 17.5 ppg drilling mud while drilling through the Woodford-Hunton section, indicating severe 

overpressuring. These wells may have penetrated uplifted fault blocks where the Woodford-Hunton section in the 

hanging wall is juxtaposed against the regionally overpressured Springer-Caney section in the footwall. Local 

overpressuring of the Woodford may have been caused by high-pressure gas and/or fluids from the Springer section 

which migrated across the fault zone. Detailed structural analyses are recommended to confirm the source of high 

pressures in these specific compartments. 

The Hunton group appears to be regionally water saturated, with gas trapped in conventional structural and/or 

stratigraphic traps. Normally or sub-normally pressured gassy salt water has been recovered during many formation 

tests of the deep Hunton reservoirs, and distinct gas-water contacts are noted on several Hunton structure maps and 

field descriptions (Kennedy, 1982). The OSU-GRI online database lists seventeen pressure data points for the Hunton 

Group in Wheeler County, Texas. All of these formation tests found near-normal pressure gradients (0.39 to 0.47 

psi/ft); no overpressures were encountered. Thirteen data points are listed for deep Hunton tests in Roger Mills 

County, Oklahoma, and all have pressure gradients ranging from 0.36 to 0.47 psi/ft. Of four pressure data points 

listed for deep Hunton tests in Beckham County, Oklahoma, three indicate normal pressures (0.43 psi at 24, 950 

feet; 0.45 psi/ft at 24,850 ft and 0.49 psi/ft at 16,824 feet). Moderate overpressure (0.61 psi/ft) was reported in the 

Hunton Fm at 24,200 feet in the Exxon Green well at Northeast Mayfield Field (Sec. 3, T. 10 N., R. 25 W., 

Beckham County). This appears to be another uplifted fault-block structure (Kennedy, 1982) where the Hunton 

section in the hanging wall may be juxtaposed with overpressured Springer-Caney shales in the foot wall. 

Overpressure is rare in the deep Hunton reservoirs; normal to subnormal pressures are most common. 

DISCUSSION: DOES THE WOODFORD FIT THE BASIN-CENTER MODEL ? 

As noted above, the Woodford Shale is a thin but organic-rich hydrocarbon source rock and is thermally mature 

to post-mature in the deep basin. The Woodford may have expelled as much as 22 billion barrels of bitumen and 16 

billion barrels of saturated hydrocarbons (Comer and Hinch, 1987). Thick, tight, Mississippian limestones with very 

low porosity should have made an effective regional seal above the Woodford, and should have trapped hydrocarbons - 

and excess pore pressures - within the Woodford interval. But the mud weight data listed in Table 1 indicate that the 

Woodford is not regionally overpressured (with the exception of two locally overpressured areas described above). The 

underlying Hunton section is generally normally or subnormally pressured. 

The absence of regional overpressure may be due to high permeability zones within the Hunton dolomites. 

Bebout and others (1993, Table 28) list permeabilities ranging from 0.01 to 30 mD in deep Hunton reservoirs, with 

average values ranging from 9 to 15 mD. These values greatly exceed the 0.1 to 1 mD threshold typically found in 

known basin-center gas accumulations. Hydrocarbons expelled from the Woodford source rock may have escaped 

downward into permeable zones within the Hunton, and may have been able to migrate into other zones relatively 

easily, without developing extensive overpressures. The combination of impermeable top seal, rich source rock and 

permeable underlying reservoir zones, saturated with normally to sub-normally pressured hydrocarbons and salt water, 

does not appear to match the typical basin-center gas model. 

OVERPRESSURES IN THE ATOKA, MORROW AND SPRINGER GROUPS 

Abnormal pressures within the Atoka, Morrow and Springer Groups have been described by Breeze (1971), 

Bradley and Powley (1994), Al-Shaieb (1991), and Al-Shaieb and others (1992; 1994; 1999). A regionally extensive 

“mega-compartment complex” (MCC) has been identified in the central Anadarko basin. The MCC contains many 

different abnormally pressured compartments, which are thought to be laterally bounded by cement-filled fault zones 

and sealed by impermeable bands of silica and calcite-cemented sandstone and shale (Price, 1998a and 1998b, Al- 

Shaieb, 2000). The top of overpressuring cuts across stratigraphic units at depths of 10,000 to 12,000 feet.

An online database of pressure measurements, pressure gradients and pressure versus depth plots for the 

Anadarko basin has been generated by Dr. Al-Shaieb and his associates at Oklahoma State University (OSU) and the 

Gas Research Institute (GRI). The pressure data are based on well reports available from Petroleum 

Information/Dwights Corporation, completion reports filed at the Oklahoma Oil and Gas Conservation Division, and 

Amoco well files (Al-Shaieb and others, 1992). Many of these pressure data points were derived from bottom hole 

shut-in pressures and drill-stem tests, and some were extrapolated from shut-in tubing pressures. Work in progress 

to describe the various fluid types found in different pressure compartments was summarized by Al-Shaieb and others 

(1999). 

Figures 5a and 5b show pore pressure versus depth plots for Roger Mills and Beckham Counties in the central 

Anadarko basin, based on pressure data retrieved from the OSU-GRI pressure database. In Roger Mills County, 

normal and sub-normal pressures are found down to depths of approximately 10,000 to 12,000 feet. Overpressures 

are encountered in the Atoka, Morrow and Springer section, with pressure gradients reaching 0.83 to 0.94 psi/ft in 

several deep reservoirs. Overpressures occur below 12,500 feet in Beckham County (fig. 5b) and increase with depth 

through the Atoka, Morrow and Springer section down to about 19,500 feet. The deep Hunton section below 

24,000 feet deep is subnormally to normally pressured in two tests, but is overpressured in one localized 

compartment. 

Kennedy (1982, p. 70) and Kinchloe and others (1973) described typical drilling mud weights and casing points 

for deep wells in the central Anadarko basin. Mud weights of 9 to 10 pounds per gallon (ppg) are used to balance 

normal pore pressures down to approximately 10,000 feet. Mud weights are usually raised above 12 ppg to control 

increasing pore pressures within the Pennsylvanian Red Fork and Atoka section. Intermediate casing is usually set 

at approximately 12,500 feet to prevent lost circulation problems as the mud weight is increased. Mud weights are 

gradually raised to 16 ppg through the Morrow Group, and additional casing is often set at approximately 16,000 

feet. Mud weights as high as 18 ppg are often used while drilling through the severely overpressured Morrow, 

Springer, Goddard and Caney section. In ultra-deep Hunton-Arbuckle tests, casing is usually set just below the base 

of the Caney Shale, in the Flag or St. Genevieve Limestone. Then the mud weight is dropped to approximately 9.5 

ppg while the normally or sub-normally pressured Woodford-Hunton-Arbuckle is penetrated. 

Figure 6 shows the approximate extent of overpressuring in the Atoka-Morrow-Springer section. Detailed 

contour maps showing pressure gradients for the Red Fork, Morrow and Hunton Groups have been published by Al- 

Shaieb and others (1994), and maps of pressure gradients in Ellis, Custer and Dewey Counties have been published 

by Al-Shaieb and others (1992). Al Shaieb and others (2000) note that overpressure gradients greater than 0.6 psi/ft 

coincide with vitrinite reflectance values greater than 1.5%, and suggest that overpressuring is closely related to gas 

generation. 

SUBNORMAL PRESSURES ALONG THE NORTHERN SHELF 

Extensive subnormally pressured zones occur along the shallow northern shelf. The transition zones where 

overpressures merge into the sub-normal and normal pressures are complexly interfingered (Al-Shaieb and others, 

1992). The shallow northern shelf was not investigated as part of this project, but deserves further study because the 

pattern in the Springer-Morrow section resembles the typical pattern of a shrinking basin-center gas accumulation 

which has receded from its maximum extent due to recent erosion and cooling. This pressure pattern includes 

overpressure in the deepest part of the basin, sub-normal pressures along the shallow shelf, and normal pressures near 

outcrops. As noted above, the Anadarko basin may have lost 2,000 to 3,000 feet of overburden since Permian time 

and may have cooled, so the occurrence of sub-normal pressures is not unexpected.

DEEP GAS FIELDS IN THE ATOKA, MORROW AND SPRINGER GROUPS 

At least forty deep gas fields have been discovered within the regionally overpressured Atoka, Morrow and 

Springer section (Kennedy, 1982). This hydrocarbon system has many characteristics of a basin-center gas 

accumulation, including mature source rocks, high temperatures, abnormal pressures (0.8 to 0.94 psi/ft), and 

extensive gas production from tight sandstone reservoirs. As noted above, gas-prone, Type III source rocks are 

present in the clastic section, and vitrinite reflectance profiles indicate that these source rocks are mature and within 

the gas generation window. The composition of the produced gas is generally 94 to 97% methane, 1 to 1.5% 

ethane, 1 to 1.5% CO2 and 1 to 2% nitrogen (Kennedy, 1982). Carbon 13 isotope values generally range from -37 

to -43, indicating thermogenic origins from mature source rocks (Rice and others, 1988). Reservoir temperatures 

range from 200 to 360 °F in the deep producing zones. 

Sandstone reservoirs with moderate to very low porosity and permeability are interbedded with the source rocks. 

Porosity trends for Morrow and Springer sandstones have been described by Hester and Schmoker (1990), Hester 

(1993) and Keighin and Flores (1993). The log-derived sandstone porosity values typically range from 4% to 18%. 

According to Keighin and Flores (1993), secondary porosity caused by the dissolution of chert and feldspar grains is 

the most important type of effective porosity. Levine (1984) noted porosities ranging from 9 to 14% and 

permeabilities ranging from 0.1 to 1 md in Red Fork sandstone reservoirs. Fritz (1985) described porosities ranging 

from 10 to 16% in the Britt Sandstone (Springer Group) at depths of 15,500 to 16,000 ft in the Eakly Field. Nonproductive 

wells along the downdip edge of the field showed only 2 to 8% porosity. McMechan and Conway (1983, 

p.42) described Springer and Goddard sandstone reservoirs at Fletcher Field, where log-derived porosities generally 

range from 6 to 10%. They note that sweet spots in this field have porosity as high as 14%. Permeabilities are 

generally less than 1 md, and most production comes from zones with 0.01 to 0.1 mD. Reservoirs in the Britt 

Sandstone produce gas from zones with permeabilities of 0.1 - 0.5 mD. These ranges are similar to those found in 

many known basin-center gas accumulations, where tight sandstone reservoirs usually have permeabilities of less 

than 0.1 to 1 mD. 

GAS-WATER CONTACTS IN PRODUCING FIELDS 

The overpressured Atoka-Morrow-Springer section appears to be extensively charged with natural gas, but close 

inspections of well logs, scout cards, and completion records available at the Denver Earth Resources Library (730- 

17 th Street, Denver, CO, 80202) reveal that many formation tests recovered water from these deep sandstone 

reservoirs. Several gas-water contacts were identified during detailed investigations of Morrow and Springer gas 

production in the deep Anadarko basin. The presence of numerous conventional gas-water contacts within the 

overpressured MCC raises doubts about the application of the continuously gas-saturated, basin-center gas model to 

this hydrocarbon system. 

West Cheyenne Field 

West Cheyenne Field (T. 13-14 N., R. 24-25 W., Roger Mills County, Oklahoma) produces overpressured gas 

from approximately 18 wells which penetrate a stratigraphic trap in the Puryear Sandstone of the Morrow Group 

(Voris, 1980; Johnson, 1990; Al-Shaieb and others, 1993). The Puryear has been interpreted as a fan-delta deposit 

containing chert pebble conglomerate and sandstone lenses in northeast-trending channels surrounded by gray-black 

deltaic shales (Al-Shaieb and others, 1990). The main Puryear channel is 25 to 50 ft thick in the center of the field, 

with average porosity of approximately 14 % at depths of 14,800 to 15,700 feet. Gas is trapped where the channel 

pinches out updip to the north. The reservoir temperature is approximately 265 to 272 °F (Voris, 1980), and bottom 

hole shut-in pressures range from 11,400 to 14,317 psi at 15,000 ft (Kennedy, 1982). Pressure gradients for wells 

in this field (Table 2) range from 0.73 to 0.92 psi/ft, and drilling mud weights range from 16.8 to 18 ppg, indicating 

severe overpressure in this area. Gas kicks, blowouts and problems with stuck drill pipe were reported in the 

discovery wells. Cumulative production ranges from 7.4 to 23.5 BCFG per well in the main part the field.

Deep resistivities measured from dual induction logs (Table 2) range from 40 to 170 ohms where the Puryear 

Sandstone is productive, and the average water saturation is 29% (Voris, 1980). But a contour map of the structure of 

the Puryear Ss published by Voris (1980) shows two abandoned wells on the southwestern, downdip edge of the field 

which are clearly labeled “WET”, and Voris noted that a Puryear sandstone lens “tested water” along the southwestern 

side of the field. The deep resistivity of the Puryear reservoir is only 8 to 29 ohms in the unproductive wells on the 

southeast (downdip) side of the field. El Paso Natural Gas Company’s Thurmond No. 3 well (Sec. 35, T. 13 N., R. 

24 W.) perforated the Puryear Sandstone at 15,945-949 feet. The deep resistivity was only 18 to 29 ohms, and a 

Schlumberger Cyberlook log shows porosities ranging from 6 to 16% and water saturations ranging from 55 to 100 

%. Formation test results were “not released”, but the Puryear zone was abandoned after this test. This well was 

plugged at 14,284 feet and completed uphole in the Atoka Group. 

The dual induction log for the L. P.C. X. Corporation Thurmond No. 34-A well (Sec. 34, T. 13 N., R. 24 W.) 

shows only 8 to 25 ohms of deep resistivity in the Puryear Ss at depths of 15,964 -16,004 feet. The Schlumberger 

Cyberlook log shows porosities ranging from 5 to 15% and calculated water saturations of 60 to 100%. Notes on 

the log indicate “probable water” in the Puryear reservoir. The Puryear zone was abandoned without tests and the 

well was completed uphole in a Cherokee sand. Several other wells which penetrated the Puryear in low structural 

positions were completed uphole in other reservoirs, or were abandoned for lack of productive gas reservoirs. The 

Puryear reservoir does not appear to be continuously gas-saturated in this area. 

The gas column at West Cheyenne Field is approximately 1200 ft tall (Kennedy, 1982). There has been prolific 

gas production from the Puryear reservoir at the top of the trap, but there is evidently a transition into a low 

resistivity water-producing zone downdip. The gas/water contact occurs at a depth of approximately 15,800 feet (- 

13,600 feet). This highly productive gas field is located within a regional overpressure zone and has many of the 

characteristics of known basin-center gas accumulations. But West Cheyenne Field has a traditional trapping 

mechanism and a traditional gas/water contact. The available porosity in the Puryear reservoir was only partially 

filled with gas. 

Northwest Reydon Field 

Northwest Reydon Field is a structural-stratigraphic trap which produces overpressured gas from the Upper 

Morrow Puryear and Pierce Sandstones in T. 13-14 N., R. 26 W., Roger Mills County, Oklahoma (Huber, 1974, Al 

Shaieb and others, 1993). An anticlinal fold creates a structural high, and updip pinchouts of fluvial channels cause 

the stratigraphic traps. Average porosity is 13% at depths of approximately 14,900 feet and permeabilities are as 

high as 15 mD in the chert pebble conglomerate lenses. The reservoir temperature is approximately 262 to 289 °F. 

A reservoir pressure of 12,337 psi at 14,890 feet (0.83 psi/ft) was reported in the OSU-GRI database. Drilling mud 

weights range from 16.3 to 18.4 ppg, indicating severe overpressuring. One of the discovery wells blew out and 

caught on fire, destroying the drilling rig. Cumulative production ranges from 14 to 33 BCFG per well in the main 

part of the field. 

Well logs, scout cards and production data were examined along a north-south transect through Northwest 

Reydon Field. Deep resistivities (Table 3) range from 40 to 80 ohms in the gas-producing zones at the top of the 

structure. But the deep resistivity in these reservoirs decreases downdip, and falls as low as 5 to 15 ohms in several 

unproductive wells located downdip from a gas/water transition zone. Dyco Petroleum Corporation’ s Pennington 

No. 1-18 well (Sec. 18, T. 13 N., R. 25 W.) tested 25 MCFD and 68 bwpd from the Puryear at 15,694 to 15,699 

feet, but was abandoned after producing only 139 MMCFG. The deep resistivity was only 9 to 34 ohms in the 

Puryear reservoir. Farther downdip, water flows of 61 bwpd were reported from the Puryear interval at 16,202 ft in 

Wagner-Brown McColgin no. 1-29 (Sec. 29 T. 13 N. R. 25 W.). The Pierce Sandstone flowed 100 MCFD and 43 

bwpd when tested, and the well was abandoned. These wells were drilled too low on the structure, and penetrated the 

Puryear reservoir below the gas/water contact.

This severely overpressured, highly productive gas field has a gas column approximately 500 ft tall and a 

traditional gas/water contact at approximately 15,400 ft. The Puryear reservoir has high resistivity and low water 

saturations near the top of the trap, but the resistivities decrease down-dip, and the reservoir produces water below a 

distinct gas-water transition. The porosity available in the Puryear Sandstone was not completely saturated with gas. 

These characteristics indicate a conventional structural-stratigraphic gas trapping mechanism, and do not fit the 

pattern of a continuously saturated basin-center gas accumulation. 

Southwest Minco Field 

Southwest Minco Field is another structural-stratigraphic trap which produces gas from the Cunningham 

Member of the Springer Group at depths of 12,450 to 13,500 feet in Grady County, Oklahoma (Pipes, 1980). Gas 

has been trapped where the Cunningham Sandstones are truncated by erosional unconformities along the northern 

shelf. Average reservoir porosity is reported to be 18%. The field is located along the updip margin of the 

overpressured megacompartment and shows interfingered overpressures and normal pressures. Pressure data retrieved 

from the OSU-GRI database indicate a mixture of normal pressures (0.44 - 0.57 psi/ft) and overpressures (0.65 - 0.77 

psi/ft) in this area. Pipes (1980) reported an original reservoir pressure of 9071 psi at 12,465 feet (0.727 psi/ft). 

A published isopach map for the Cunningham A Sandstone (Pipes, 1980) shows a distinct gas-water contact, 

and a “gas-water contact” is identified in the field description. Gas is evidently trapped in the Cunningham A 

Sandstone at Southwest Minco Field by a traditional stratigraphic pinch-out with a conventional gas-water contact. 

This field is located along the margin of the Springer-Morrow overpressured zone, but the trapping mechanism does 

not fit the typical basin-center gas model. 

East Apache Field 

East Apache Field is a faulted anticlinal structure located north of the Wichita Frontal Fault in T. 5 N., R. 10- 

11 W., Caddo County, Oklahoma (Kennedy, 1982). Well logs, scout cards and production data were examined along 

a southwest-northeast transect (Table 4). As of late 1998, this field has produced 122 BCFG and 32 MBO from 

several Morrow, Springer and Goddard sandstone reservoirs. Pressure data retrieved from the OSU-GRI database 

show normal pressures down to 12,000 feet, then severe overpressures at depths of 16,000 to 20,500 ft in the deeper 

Morrow and Springer section, with pressure gradients ranging from 0.81 to 0.87 psi/ft. Drilling mud weights range 

from 15 to 17 ppg and bottom hole temperatures reach 270 to 285 °F. The gas produced from a deep Springer 

reservoir (Rice and others, 1988, Table 1, No. 79) contains 95% methane, 1.5 % ethane, 1.7% nitrogen, and 1% 

CO2. One of the main reservoirs at East Apache Field is the Britt Sandstone Member of the Springer Group, a 15 

to 50 ft thick shallow marine deposit with extensive lateral continuity. Forest Oil Fort Sill Unit 4 No. 2 (Sec. 30, 

T. 5 N., R. 10 W.) has produced 12.27 BCFG from the Britt Ss at 16,771 - 16,796 feet (-15,393 ft) as of June, 

1999 (Table 4). Kirby Exploration Mindemann No. 1-30 has produced over 13.19 BCFG from the Britt at 16,971- 

17,010 ft (-15,619 ft). The original reservoir pressure gradient was 0.75 psi/ft in this well. 

The Britt Sandstone is a prolific, highly overpressured gas reservoir near the top of the anticline, but there 

appears to be a gas-water contact along the northeast flank at approximately -15,700 feet. The Britt reservoir was 

tested at a depth of 17,149 - 17,165 feet (-15,740 ft) in the Forest Oil Lopez No. 1 well (Sec. 19, T. 5 N., R. 10 

W.) and flowed water at the rate of 349 bwpd. The Britt was tested farther down dip at the Kirby Exploration Murray 

No. 1 well (Sec. 5, T. 4 N., R. 10 W) and flowed water at the rate of 200 bwpd from perforations at 17,856-17,884 

feet (-16,640 ft). Deep resistivity measurements (Table 4) show a similar pattern to that observed at Northwest 

Reydon and West Cheyenne Fields. The highest resistivities occur in gas producing zones near the top of the trap; 

lower resistivities occur within the water-producing zones down-dip. Once again, the available porosity has not been 

completely filled with gas, and the reservoir is water-saturated below a conventional gas/water contact. This field 

does not fit the typical basin-center gas model.

MANY DEEP FORMATION TESTS PRODUCED WATER 

Table 5 lists various deep wells which recovered water during formation tests within the overpressured MCC. 

The most important examples are Shell Rumberger No. 5 (Sec. 16, T. 10 N., R 21 W., Beckham County, 

Oklahoma) and the GHK Nix No. 1 well, which tested Springer sandstone reservoirs below 21,000 feet. These wells 

offset the GHK Green No. 1 well (Sec. 1-T. 10 N., R. 21 W.) which produced more than 17.4 BCFG from 

overpressured Springer reservoirs at 21,604-22,652 ft. In the Rumberger well, Springer sandstones which correlate 

with the producing zones at the Green well flowed salt water during testing. A scout card issued in 1959 by 

Rinehart’s Oil Reports indicates that perforations at 21,595-21,645 feet flowed 9 MCFD of gas, but some salt water 

was recovered by bailing. The perforations were treated with xylene and kerosene, but 96 barrels of salt water were 

recovered and the wellbore eventually filled with salt water. The zone was abandoned and a bridge plug was set at 

21,465 feet before testing shallower zones. Water was also recovered from perforations in the Atoka at 13,810- 

13,812 feet, and the well was eventually abandoned. 

At the GHX Nix No. 1 well (Sec. 2, T. 10 N., R 20 W.), a Springer sandstone with deep resistivity of 55 to 

120 ohm was perforated at 22,123-22,192 feet. Notations typed on the Schlumberger Dual Induction Log show that 

the zone “Rec. show gas & oil, 270 BSW,” indicating that 270 barrels of salt water (?) were recovered during the 

test. The drilling mud weight was 16.5 ppg and the bottom hole temperature was 351 °F. The well was abandoned 

after several shallower zones were tested without establishing commercial production. At the Gulf Oil Corporation 

Anna Tabor No. 1 well (Sec. 24, T. 8 N., R. 15 W.), perforations in a Morrow sandstone at 16,660 to 16,704 feet 

flowed 3.12 MMCFD with 3 to 4 barrels of water per hour, and later flowed 815 MCFD with 67 bwpd. This well 

was eventually abandoned. 

Table 5 shows several other examples of water production. Additional investigations would probably identify 

other wet tests. However, the scout cards and completion reports available to the public frequently lack specific 

details about fluid recoveries, so it is often difficult to construct a clear understanding of the test results. It is evident 

that salt water has been produced from several deep, high temperature, highly overpressured reservoir zones with the 

Anadarko basin. This hydrocarbon system does not appear to be continuously saturated with gas; on the contrary, 

much of the available reservoir porosity appears to be saturated with water. 

WATER PRODUCTION NOTED BY PREVIOUS AUTHORS 

Johnson (1990, p. 7) described gas/water contacts at South Dempsey Field (T12N-R24W) in the Pierce 

Sandstone Member of the Morrow Group, at depths of approximately 15,700 feet: “Hydrocarbon traps are formed by 

stratigraphic pinchouts of reservoir rocks against impermeable shales. Those shales are believed to have been the 

source rocks for the hydrocarbons. Each of the units (A, B, C) has its own gas-water contact which is determined by 

the local structure.” 

Fritz (1985, p. 15) described the discovery of gas in the Britt Sandstone Member of the Springer Group at Eakly 

Field in Caddo County (10N-12W, 11N-13W): “The formula for success in the Eakly Field has been to locate a wet, 

porous sand and follow it updip until it starts to pinch out.” Pressure gradients for Springer zones within the Eakly 

trend range from 0.73 to 0.85 psi/ft at depths of 15,500-16,000 feet (OSU-GRI database), indicating severe 

overpressuring in this area. However, water-saturated zones were encountered in low structural positions. A 

successful exploration strategy. Involved locating water-saturated sandstone reservoirs and tracking them updip into 

gas traps formed by conventional structural closures and stratigraphic pinchouts. McMechan and Conway (1983, p. 

42) described hydraulic fracture treatments in the deep Fletcher Field, and noted that there are some areas were the 

Britt Sandstone was wet. “The Britt zone has proved commercially productive in parts of the field and wet in 

others”. 

The Society of Petroleum Engineers (1975) listed many water analyses from formation tests of deep Morrow and 

Springer reservoirs in their catalog of formation water resistivities. However, tracking water production in the 

Anadarko basin is difficult, because operators frequently do not report the details of drill stem tests, production tests 

or water production rates on the state completion reports. Scout cards often contain notations indicating that test

esults were “not released” or “not reported”. Tables of gas and oil production available from Petroleum 

Information/Dwights, do not list produced water volumes for Anadarko wells. Additional investigations are 

recommended using drill-stem test data available from commercial vendors. Well log analysis might also be useful 

for identifying water-saturated reservoirs. 

NORTH BROXTON AND ELK CITY FIELDS : WATER-FREE ? 

A localized, small scale basin-center gas accumulation might be present in the vicinity of North Broxton Field, 

which produces gas from Springer, Goddard and Boatwright sandstones at depths ranging from 19,600 to 21,200 feet. 

This deep gas field is located just north of the Frontal Fault Zone in T. 6 - 7 N., R. 12 W., Caddo County, 

Oklahoma. Drilling mud weights range from 16 to 17 ppg and gradients reported in the OSU-GRI database indicate 

strong overpressures (0.74 psi/ft). Bottom hole temperatures range from 260 to 300 °F. A brief review of well logs 

and production histories for wells in North Broxton Field reveals numerous high resistivity sandstones, extensive 

crossover effects on neutron-density logs, and numerous wells with high cumulative gas production. No obvious 

indications of water production were found during a brief review of scout cards and well data for this field. The deep 

Springer section may be continuously gas-saturated and capable of water-free gas production in this area. 

A brief review of well logs, scout cards and production data for deep gas production from the Springer section at 

Elk City Field (T. 10 N., R. 20 - 21 W., Washita and Beckham Counties, Oklahoma) revealed similar 

characteristics, including high drilling mud weights, high temperatures (280 to 310 °F) and high gas production rates 

from Springer sandstones at depths of 18,200 to 19,400 feet. Pressure gradients retrieved from the OSU-GRI 

database ranged from 0.72 to 0.88 psi/ft, indicating severe overpressures in this part of the basin. Several deep wells 

in this field have produced as much as 15 to 47 BCFG. Water production was reported for only one well, the El 

Paso Natural Gas Neice No. 2 in Sec. 27, T. 10 N., R. 20 W., where the initial production rate was 21,137 MCFD 

with 40 bwpd. Otherwise the Springer zone in Elk City Field appears to be water-free, and may be a locally 

continuous, small-scale basin-center gas accumulation. 

There may be small-scale basin-center gas accumulations within localized pressure compartments scattered 

throughout the Anadarko mega-compartment complex. Additional investigation of the ultra-deep Springer trend is 

recommended, especially using well log analysis to identify zones with high gas saturation. Careful examination of 

abandoned wells along the margins of the field and interviews with operators might be useful for identifying zones 

which produced water-free gas or large volumes of water during formation tests. 

DISCUSSION: DOES THE BASIN-CENTER GAS MODEL FIT HERE ? 

The Atoka-Morrow-Springer section within the overpressured MCC has many of the characteristics of a typical 

basin-center gas accumulation, including severe overpressures, reservoir temperatures exceeding 200 °F, thermally 

mature source rocks, tight sandstone reservoirs and extensive gas production. But detailed investigations of several 

overpressured gas fields, well data and reports by previous authors indicate that several gas traps have distinct 

gas/water contacts, and formation tests in several deep exploration wells have recovered large volumes of water. 

These investigations were hindered by the frequent lack of details about formation tests or water production in scout 

cards, completion reports and production data. 

The Atoka-Morrow-Springer hydrocarbon system almost matches the continuous basin-center gas model, but the 

presence of gas-water contacts and formation tests which produced water are a cause for concern. The frequent 

occurrence of water production within the regionally overpressured Atoka-Morrow-Springer section indicates that gas 

has filled only part of the available porosity. The reservoirs are often water-saturated below the gas-water contacts 

and produce large volumes of water when tested. This reservoir volume has not been regionally de-watered.

Perhaps the source rocks were too lean, perhaps the thermal gradient was too low, or perhaps erosion of several 

thousand feet of sediment since Permian time caused the source rocks to cease generating gas before the de-watering 

process was completed. For whatever reason, the total volume of gas expelled from the source rocks may have been 

insufficient to drive the formation water out of pore system and fully saturate the available pore space with gas. The 

unusually good reservoir quality of many Morrow and Springer sandstones may be another important factor. Some 

of the reported permeabilities are higher than those typically found in known basin-center gas accumulations. 

Extensive vertical and lateral migration of hydrocarbons may have occurred through high permeability zones in the 

Atoka-Morrow-Springer section. 

CONCLUSIONS 

The Woodford is a rich hydrocarbon source rock and is thermally mature or post-mature throughout the deep 

Anadarko Basin. It is overlain by thick, tight Mississippian limestones which probably form an effective regional 

top seal above the source rocks. But drilling mud weights indicate that the Woodford is not regionally overpressured, 

except in two localized structural compartments. The Hunton carbonate section immediately below the Woodford is 

normally to subnormally pressured throughout most of the deep basin, and contains dolomite reservoirs with good 

porosity and permeability. Hydrocarbons expelled from the Woodford Shale may have migrated downward into 

permeable zones within the Hunton and then migrated laterally into structural and stratigraphic traps. The absence of 

regional overpressure in the Woodford Shale and the presence of an underlying, sub-normally normally pressured 

aquifer indicate that this hydrocarbon system does not fit the basin-center gas model. 

The regionally overpressured Atoka-Morrow-Springer section has many characteristics of a basin-center gas 

accumulation. Overpressures are regionally extensive and reach extremely high gradients (0.8 to 0.94 psi/ft) in some 

localities. Reservoir temperatures are usually greater than 200 °F, and reach 360 °F in the deepest producing wells. 

Gas-prone, Type III source rocks are present within the Morrow-Springer-Caney shales. Vitrinite reflectance profiles 

show that these source rocks are thermally mature and are in the gas generation window in the central part of the 

basin. The produced gas is mostly methane with carbon isotopes indicating thermogenic origins. Sandstone 

reservoirs above and within the source rock section have good to very low porosity and permeability. 

Detailed inspections of well logs, completion reports and published field descriptions reveal many examples of 

formation tests which recovered salt water, and several examples of fields with conventional structural and 

stratigraphic traps and distinct gas-water contacts within the overpressured Atoka-Morrow-Springer section. The deep 

resistivities, cumulative production totals and formation test results indicate that water saturation increases downdip 

from the top of the trap. Large volumes of moveable water have been recovered during formation tests of low 

resistivity reservoirs located downdip from gas-water contacts. Previous authors have referred to wet wells and 

gas/water contacts downdip from gas traps located within the overpressured mega-compartment. 

The presence of numerous gas/water contacts and the frequent recovery of water during formation tests indicates 

that the available porosity in the Atoka-Morrow-Springer section within the MCC is only partially filled with gas. 

This reservoir system is still relatively water-saturated. The Springer-Morrow source rocks apparently did not 

generate enough gas to completely de-water the available porosity and fully saturate the pores with gas. The 

overpressuring fluid appears to be ‘fizz-water’ - a mixture of gas and water. On a regional scale, the Atoka-Morrow- 

Springer hydrocarbon system within the Anadarko basin MCC is almost, but ‘not quite’ a basin-center gas 

accumulation. The presence of numerous gas-water contacts and the frequent production of water during formation 

tests are the main concerns. 

On a local scale, the deep Springer section below 18,500 feet at North Broxton Field and Elk City Field appears 

be continuously gas-saturated and almost water-free. Further investigation is recommended to determine whether 

these deep, overpressured sandstone reservoirs are part of a small scale, continuous basin-center gas accumulation.

Components of the Basin-Center Gas Model 

Conceptual models of basin-center gas accumulations have been described by Masters (1979), Davis 

(1984), Law and Dickinson (1985), Spencer (1987), Spencer (1989) and Law and Spencer (1993). Key 

components of a continuous basin-center gas accumulation include: 

1) Present day reservoir temperatures are at least 190 - 200 °F (88 - 93 °C). 

2) Organic-rich source rocks have minimum vitrinite reflectance of 0.8% for gas-prone source 

material. Many basin-center gas accumulations are in rocks with vitrinite reflectance in the 1 to 

3% range. 

3) Rich source beds have expelled enough gas to cause pore pressures to rise above normal pressure 

gradients (> 0.45 psi/ft). Temperature-induced hydrocarbon generation forces water out of pore 

spaces and saturates nearby reservoirs with hydrocarbons. Water saturations decline to irreducible 

levels. 

4) Extensive abnormal pressures, either overpressure or subnormal pressure. Overpressure is sustained 

by hydrocarbon generation at rates exceeding escape. 

5) Pressure gradients rise to the lowest fracture gradients in the rock sequence. High pore pressures 

fracture the rocks; hydrocarbons escape via the fractures. Calcite and silica cements episodically 

close the fractures. 

6) Hydrocarbons (oil and/or gas) are the primary fluid-pressuring phase. No truly “dry” holes are 

drilled, all wells have some gas shows. 

7) Gas/water contacts are absent. Little or no water is produced from the overpressured reservoirs. 

However, water may intrude via fractures, fault zones and permeable beds as reservoir pressure is 

reduced. 

8) Reservoirs are usually tight sandstones with low porosity (3 - 14 %) and very low permeability 

(usually < 0.1 md). Diagenetic cements are abundant. 

9) Uplift and erosion of the basin may result in cooling, pore volume expansion and gas escape. 

Subnormal pressures may develop in zones which were previously overpressured. Overpressured 

and/or subnormally pressured gas reservoirs generally occur downdip from normally pressured 

reservoirs with water drive mechanisms.

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Al-Shaieb, Z., Alberta, P.L., and Gaskins, M., 1990, Depositional environment, petrology, diagenenesis, and 

porosity of the Upper Morrow chert conglomerate in Oklahoma: Transaction Volume of the 1989 AAPG 

Mid-Continent Section Meeting, AAPG-OCGS, p. 13-29. 

Al-Shaieb, Z., 1991, Compartmentation, fluid pressure important in Anadarko exploration: Oil and Gas Journal, 

v. 89, p. 52-56. 

Al-Shaieb, Z., Puckette, J., Ely, P., and Abdalla, A., 1993, The Upper Morrowan fan-delta chert conglomerate 

in Cheyenne and Reydon Fields: completely sealed gas-bearing pressure compartments: Oklahoma 

Geological Survey Circular 95, p. 26-39. 

Al-Shaieb, Z., Puckette, J., Abdalla, A., and Ely, P., 1994, Megacompartment complex in the Anadarko basin: 

a completely sealed overpressured phenomenon: in Ortoleva, P., ed., Basin compartments and seals: 

American Association of Petroleum Geologists Memoir 61, p. 55-68. 

Al-Shaieb, Z., Puckette, J., and Deyhim, P., 1999, Compartmentalization of the overpressured interval in the 

Anadarko basin: American Association of Petroleum Geologists Bulletin v. 83, p. 1191 (abs). 

Al-Shaieb, Z., Puckette, J., and Deyhim, P., 2000, Compartmentalization of the overpressured interval in the 

Anadarko basin: in RMAG 2000 Basin Center Gas Symposium (abs), Rocky Mountain Association of 

Geologists, October 6, 2000. 

Bradley, J.S. and Powley, D.E., 1994, Pressure compartments in sedimentary basins: a review: in Ortoleva, P., 

ed., Basin compartments and seals: American Association of Petroleum Geologists Memoir 61, p. 3-26. 

Brewer, J.A., Good, R., Oliver, J.E., Brown, L.D., and Kaufman, S., 1983, COCORP profiling across the 

southern Oklahoma aulacogen: overthrusting of the Wichita Mountains and compression within the 

Anadarko basin: Geology, v. 11, p. 109-114. 

Breeze, A.F., 1971, Abnormal-subnormal pressure relationships in the Morrow sandstone of northwestern 

Oklahoma: Shale Shaker, v. 21, p. 172-193. 

Burruss, R.C. and Hatch, J.R., 1992, Geochemistry of Pennsylvanian crude oils and source rocks in the greater 

Anadarko basin, Oklahoma, Texas, Colorado, and Nebraska: an update: Oklahoma Geological Society 

Circular 93, p. 197. 

Cardott, B.J. and Lambert, M.W., 19865, Thermal maturation by vitrinite reflectance of Woodford Shale, 

Anadarko basin, Oklahoma: American Association of Petroleum Geologists Bulletin, v. 69, No. 11, p. 

1982-1998. 

Cardott, B.J., 1989, Thermal maturation of the Woodford Shale in the Anadarko Basin: Oklahoma Geological 

Survey Circular 90, p. 32 - 43. 

Carter, L.S., Kelley, S.A., Blackwell, D.D., and Naeser, N. D., 1998, Heat flow and thermal maturity of the 

Anadarko basin, Oklahoma: American Association of Petroleum Geologists Bulletin, v. 82, p. 291-316. 

Comer, J.B. and Hinch, H.H., 1987, Recognizing and quantifying expulsion of oil from the Woodford 

Formation and age-equivalent rocks in Oklahoma and Arkansas: American Association of Petroleum 

Geologists Bulletin v. 71, p. 844 - 858. 

Davis, T.B., 1984, Subsurface pressure Profiles in gas-saturated basins: in Masters, J.A., ed., Elmworth- Case 

study of a deep basin gas field: American Association of Petroleum Geologists Memoir 38, p. 189-203.

Davis, H.G. and Northcutt, R.A., 1991, Anadarko basin: in Gluskoter and others, eds., Geological Society of 

America, The Geology of North America, v. P-2, p. 325-338. 

Fritz, M., 1985, Anadarko gas still lures explorationists: American Association of Petroleum Geologists 

Explorer, v. 6, no. 8, p. 14-16. 

Gallardo, J.D. and Blackwell, D.D., 1999, Thermal structure of the Anadarko basin: American Association of 


Hester, T.C., 1993, Trends of sandstone porosity in the Anadarko Basin - a preliminary evaluation: Oklahoma 

Geological Survey Circular 95, p. 225 - 229. 

Hester, T.C. and Schmoker, J.W., 1990, Porosity trends of non-reservoir and reservoir sandstones, Anadarko 

basin, Oklahoma: AAPG Bulletin, v. 75, p. 594 (abs). 

Hester, T.C., Schmoker, J.W., and Sahl, H.L., 1990, Log-derived regional source-rock characteristics of the 

Woodford Shale, Anadarko basin, Oklahoma: USGS Bulletin No. 1866-D, 38 p. 

Hill, G.W., 1984, The Anadarko basin: a model for regional petroleum accumulations: in Borger, J.G., ed., 

1984, Technical Proceedings of the 1981 AAPG Mid-Continent regional meeting, Oklahoma City 

Geological Society, p. 1 - 29. 

Howery, S.D., 1994, Regional look at Hunton production in the Anadarko basin: Shale Shaker v. 44, no. 5, p. 

88-91. 

Huber, D.D., 1974, Reydon Field: in Berg, O.R., ed., Oil and Gas Fields of Oklahoma, Supplement 1, 

Oklahoma City Geological Society, p. 20-21. 

Johnson, B., 1990, Regional geology of the Pierce Member of the Upper Morrow Formation in the Anadarko 

basin, with a detailed look at South Dempsey Field in Roger Mills County, Oklahoma: Transaction 

Volume of the 1989 AAPG Mid-Continent Section Meeting, AAPG-OCGS, p. 1-12. 

Kennedy, C.L., ed., 1982, The Deep Anadarko Basin: Petroleum Information Corp. 

Keighin, C.W. and Flores, R.M., 1993, Petrology and sedimentology of Morrow/Springer rocks and their 

relationship to reservoir quality, Anadarko basin, Oklahoma: Oklahoma Geological Survey Circular 95, 

p. 25 (abs). 

Kinchloe, R., Hefner, R.A. III, and Wheeler, R., 1973, The drilling and production of ultra-deep natural gas 

accumulations occurring below 20,000 ft in the Anadarko basin, U. S. A.: International Gas Union, 12 th 

World Gas Conference, Nice, France, p.1 - 16. 

Levine, S.D., 1984, Provenance and diagenesis of the Cherokee sandstones, deep Anadarko basin, western 

Oklahoma: Shale Shaker, v. 34, no. 10, p. 120-144. 

Masters, J.A., 1979, Deep basin gas trap, western Canada: American Association of Petroleum Geologists 

Bulletin, v. 63, p. 152-181. 

McConnell, D.A., Goydas, M.J., Smith, G.N., and Chitwood, J.P., 1990, Morphology of the Frontal fault 

zone, southwest Oklahoma: implications for deformation and deposition in the Wichita uplift and 

Anadarko basin: Geology, v. 18, p. 634-637.

Oklahoma State University, Department of Geology, and Gas Research Institute, Oklahoma Pressure Data, 

listed at Internet site http://www.okstate.edu/geology/gri. 

Oklahoma Oil and Gas Conservation Division, Technical Department, 1983, Pressure and H2S Data. 

Peace, H.W., 1994, Mississippian facies relationships, eastern Anadarko basin, Oklahoma: Shale Shaker, v. 45, 

no. 2, p. 26-35. 

Perry, W.J., 1989, Tectonic evolution of the Anadarko basin region, Oklahoma: USGS Bulletin 1866-A, 19 p. 

Pipes, P.B., 1980, S. W. Minco Field: in Pipes, P.B., ed., Oil and Gas Fields of Oklahoma, Supplement II, 

Oklahoma City Geological Society. 

Powers, R.B., ed., 1994, Petroleum exploration plays and resource estimates, 1989, onshore United States- 

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Price, L.C., Clayton, J.L., and Rumen, L.L., 1981, Organic geochemistry of the 9.6 km Bertha Rogers No. 1 

well, Oklahoma: Organic Geochemistry, v. 3, p. 59 - 77. 

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southwestern Kansas, western Oklahoma, and Texas Panhandle: USGS Open-file Report No. 88-391. 

Roberts, C.T. and Mitterer, R.M., 1992, Laminated black shale - bedded chert cyclicity in the Woodford 

Formation, Southern Oklahoma: Oklahoma Geological Survey Circular 93, p. 330-336. 

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Oklahoma City Geological Society. 

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Basin, Oklahoma: American Association of Petroleum Geologists Bulletin, v. 81, p. 249-275.

APPENDIX 1: COMPONENTS OF THE BASIN-CENTER GAS MODEL 

Conceptual models of basin-center gas accumulations have been described by Masters (1979), Davis (1984), Law 

and Dickinson (1985), Spencer (1987), Spencer (1989) and Law and Spencer (1993). Key components of a 

continuous basin-center gas accumulation include: 


2) Organic-rich source rocks have minimum vitrinite reflectance of 0.8% for gas-prone source material. Many 

basin-center gas accumulations are in rocks with vitrinite reflectance in the 1 to 3% range. 

3) Rich source beds have expelled enough gas to cause pore pressures to rise above normal pressure gradients 

(> 0.45 psi/ft). Temperature-induced hydrocarbon generation forces water out of pore spaces and saturates 

nearby reservoirs with hydrocarbons. Water saturations decline to irreducible levels. 

4) Extensive abnormal pressures, either overpressure or subnormal pressure. Overpressure is sustained by 

hydrocarbon generation at rates exceeding escape. 

5) Pressure gradients rise to the lowest fracture gradients in the rock sequence. High pore pressures fracture the 

rocks; hydrocarbons escape via the fractures. Calcite and silica cements episodically close the fractures. 

6) Hydrocarbons (oil and/or gas) are the primary fluid-pressuring phase. No truly “dry” holes are drilled, all 

wells have some gas shows. 

7) Gas/water contacts are absent. Little or no water is produced from the overpressured reservoirs. However, 

water may intrude via fractures, fault zones and permeable beds as reservoir pressure is reduced. 

8) Reservoirs are usually tight sandstones with low porosity (3 - 14 %) and very low permeability (usually < 

0.1 md). Diagenetic cements are abundant. 

9) Uplift and erosion of the basin may result in cooling, pore volume expansion and gas escape. Subnormal 

pressures may develop in zones which were previously overpressured. 

10) Overpressured and/or subnormally pressured gas reservoirs generally occur downdip from normally pressured 

reservoirs with water drive mechanisms.

NEW MEXICO 

0 

-5,000' 

25 50 MILES 

0 25 50 100 KM 

OKLAHOMA 

TEXAS 

-3,000' 

Northwestern Shelf 

KANSAS 

Frontal Fault Zone 

ANADARKO 

BASIN 

-20,000' 

-10,000' 

-25,000' 

-5,000' 

-15,000' 

AMARILLO - WICHITA UPLIFT 

Figure 1. Map of Oklahoma showing the Anadarko basin, Amarillo-Wichita Uplift, Frontal Fault Zone and depth (in feet) of 

Precambrian basement. Modified from Bebout and others (1993, p. 15). 

NEMAHA RANGE

Depth, in thousands 

of feet 

0 

-30 

-60 

-90 

AMARILLO - 

SW WICHITA ANADARKO NE 

UPLIFT 

SEDIMENTARY ROCKS 

BASIN 

PRECAMBRIAN BASEMENT 

IGNEOUS & METAMORPHIC 

BASEMENT ROCKS 

0 100 KM 

Figure 2. Structural diagram showing the Amarillo-Wichita Uplift and Anadarko basin. 

Modified after Perry (1989, p. A6).

PERMIAN (PART) 

PENNSYLVANIAN 

MISSISSIPPIAN 

CAMBRIAN ORDOVICIAN SILURIAN DEVONIAN 

PERIOD 

GUADALUPIAN 

LEONARDIAN 

WOLFCAMPIAN 

VIRGILIAN 

MISSOURIAN 

DESMOINESIAN 

ATOKAN 

MORROWAN 

CHESTERIAN 

MERAMECIAN 

OSAGEAN 

KINDERHOOKIAN 

UPPER 

MIDDLE 

LOWER 

UPPER 

LOWER 

UPPER 

MIDDLE 

LOWER 

UPPER 

MIDDLE 

LOWER 

PROTEROZOIC 

"GRANITE WASH" 

GROUP/FORMATION 

CLOUD CHIEF FM. 

WHITEHORSE GR. 

EL RENO GROUP 

HENNESSEY SHALE 

GARBER SANDSTONE 

WELLINGTON FM. 

CHASE GR. 

COUNCIL CROVE GR. 

ADMIRE GR. 

WABAUNSEE GR. 

SHAWNEE GR. 

DOUGLAS GR. 

LANSING GR. 

KANSAS CITY GR. 

MARMATON GR. 

CHEROKEE GR. 

RED FORK 

ATOKAN GR. 

MORROW GR. 

SPRINGER GR. 

CHESTER GR. 

MERAMEC LIME 

OSAGE LIME 

WOODFORD SHALE 

HUNTON GR. 

SYLVAN SHALE 

VIOLA FM. 

SIMPSON GR. 

ARBUCKLE GR. 

TIMBERED HILLS GR. 

GRANITE, RHYOLITE, 

AND GABBRO 

GRANITE, RHYOLITE, 

AND METASEDIMENTS 

Figure 3. Stratigraphic column for the central Anadarko basin. Modified after Gallardo and 

Blackwell (1999, p. 337).

DEPTH, IN THOUSANDS OF FEET 

0 

4 

8 

12 

16 

20 

24 

28 

32 

0.2 

0.4 

0.6 

1.0 

1.5 

2.0 

4.0 

6.0 

MEAN VITRINITE REFLECTANCE, IN PERCENT 

Figure 4. Mean vitrinite reflectance (%Ro) versus depth profile for Woodford Shale samples in the 

Anadarko basin (dots) and for several units in the Bertha Rogers-1 well, Washita County, 

Oklahoma (crosses). Modified from Price (1997, p. 188) and Cardott and Lambert (1985). 

10.0


0 0 

5 

10 

15 

20 

25 

RED FORK 

ATOKA 

MORROW 

SPRINGER 

HUNTON 


HUNTON 

30 

25 

0 5000 10000 15000 20000 25000 30000 0 5000 10000 15000 20000 

PRESSURE (psi) PRESSURE (psi) 

5 

10 

15 

20 

GRANITE WASH 

DES MOINES 

RED FORK 

ATOKA 

MORROW 

SPRINGER 

Figures 5a and 5b. Pressure versus Depth Plots of formation test data in Roger Mills and Beckham Counties, Anadarko basin, 

Oklahoma. Sloping line shows a normal hydrostatic gradient (0.465 psi/ft). Modified from pressure data listed at Internet site 

www.okstate.edu/geology/gri/AnadarkoPr.

NEW MEXICO 

0 

-5,000' 

25 50 MILES 

0 25 50 100 KM 

OKLAHOMA 

TEXAS 

OCHILTREE 

ROBERTS 

LUPSCOME 

HEMPHILL 

ELLIS 

HARPER 

-3,000' 

Northwestern Shelf 

KANSAS 

Frontal Fault Zone 

WOODWARD 

ANADARKO 

BASIN 

-20,000' 

-10,000' 

-5,000' 

DEWEY 

CUSTER 

-25,000' 

WASHITA 

WOODS 

MAJOR 

BLALNE 

-15,000' 

CADDO 

AMARILLO - WICHITA UPLIFT 

Figure 6. Structure map showing contours on the top of the Morrow Group, central Anadarko basin, Oklahoma. Shaded area 

shows the approximate extent of overpressure within the Atoka, Morrow, and Springer section. Modified from Bebout and 

others (1993, p. 45) and pressure data listed at Internet site www.okstate.edu/geology/gri/AnadarkoPr. 

GRADY 

NEMAHA RANGE

Well Name FIELD Sec. Twp. Rg. Formation Mud Depth BHT Hunton Fm Test Hunton Pr/Depth Test Results, Comments 

ppg ft degF psi/ft 

Davis Oil Pickett #1 Watonga 10 16 N. 12 W. Woodford 10 11,112 187 WDFD= probably Normal Pressure 

Sunray DX Cullen #1 wildcat 34 10 N. 7 W. Woodford 9.8 11,550 181 WDFD= probably Normal Pressure 

Coquina Oil Bahan #1 wildcat 34 15 N. 12 W. Woodford 9 12,720 232 WDFD= probably Normal Pressure 

Southern UPC Droke #1 wildcat 10 15 N. 16 W. Woodford 10.4 14,502 230 perfs rec gas 0.43 psi/ft WDFD= probably Normal Pressure 

Helmerich&Pyne Cupp #1 W Mayfield 27 10 N. 26 W. Woodford 9.3 14,640 238 perfs rec gas 0.45 psi/ft WDFD= probably Normal Pressure 

Helmerich&P Cupp C#1 W Mayfield 22 10 N. 26 W. Woodford 9.5 14,895 261 perfs rec gas 0.42 psi/ft WDFD= probably Normal Pressure 

Helmerich&P Cupp #2 W Mayfield 27 10 N. 26 W. Woodford 9.6 14,930 215 WDFD= probably Normal Pressure 

Magnolia Troy Smith #1 wildcat 12 11 N. 11 W. Woodford 10.2 15,110 238 WDFD= probably Normal Pressure 

Helmerich&P Sutton #1 W Mayfield 23 10 N. 26 W. eroded? 10.2 15,160 216 perfs rec gas WDFD= probably Normal Pressure. 

McCulloch Schimmer #1 wildcat 5 14 N. 16 W. Woodford 9.5 15,634 262 DST rec SW WDFD= probably Normal Pressure 

ARKLA Expl'n Harrill #1 wildcat 29 17 N. 21 W. Woodford 9.5 16,224 249 DST rec SW WDFD= probably Normal Pressure 

El Paso Expl'n Penry #1 NW Leedy 27 17 N. 21 W. Woodford 9.9 16,490 250 perfd, no gas WDFD= probably Normal Pressure 

Getty Oil Hall #1 wildcat 19 16 N. 19 W. Woodford 10.1 16,590 272 WDFD= probably Normal Pressure 

Lone Star Berryman #1 wildcat 24 17 N. 24 W. Woodford 10.4 16,600 288 DST rec SW 0.44 psi/ft WDFD= probably Normal Pressure 

Hoover-Bracken Anders #1 Leedy 6 16 N. 20 W. Woodford 9.4 16,690 246 WDFD= probably Normal Pressure 

Continental Gordon U #1 W Mayfield 20 10 N. 26 W. Woodford 16,600 DST rec gas 0.49 psi/ft WDFD= probably Normal Pressure 

ARKLA Expl'n Harrell #1 wildcat 17 16 N. 21 W. Woodford 9.1 17,290 302 DST rec SW WDFD= probably Normal Pressure 

Continental Guenzel #1 W Mayfield 25 10 N. 26 W. 10.4 17,770 268 perfs rec g&w WDFD= probably Normal Pressure 

Hoover-Bracken Cecil #1 wildcat 4 16 N. 26 W. Woodford 10.8 17,845 320 perfs, NR, PB WDFD= probably Normal Pressure 

Woods Petrl'm Switzer #1 wildcat 32 16 N. 21 W. Woodford 9.5 17,900 266 WDFD= probably Normal Pressure 

Roden Oil Nickel #1 wildcat 35 13 N. 16 W. Woodford 9.4 18,025 312 DST rec SW 0.363 psi/ft WDFD= probably Normal Pressure 

Clark Cand'n Viersen #1 wildcat 8 15 N. 22 W. Woodford 9.6 18,710 325 0.427 psi/ft WDFD= probably Normal Pressure 

French Baker #1 Crawford 31 16 N. 25 W. Woodford 9.5 18,845 342 WDFD= probably Normal Pressure 

INEXCO Lovett #1 wildcat 21 14 N. 24 W. Woodford 9.5 20,490 360 perfs rec gas WDFD= probably Normal Pressure 

McCulloch Cross U #1 wildcat 4 14 N. 25 W. Woodford 10 20,540 346 WDFD= probably Normal Pressure 

Tenneco Bradshaw #1 wildcat 27 14 N. 24 W. Woodford 9.3 20,870 349 perfd, no gas 0.39 psi/ft WDFD= probably Normal Pressure 

JOC Expl'n Garver #1 wildcat 11 14 N. 26 W. Woodford 9.7 20,965 360 DST rec SW WDFD= probably Normal Pressure 

El Paso Expl'n Maddux #1 wildcat 27 14 N. 23 W. Woodford 9.3 21,250 364 WDFD= probably Normal Pressure 

Texas Pacific Libby #1 NW Reydon 33 14 N. 26 W. Woodford 9.4 21,656 369 perfd rec wtr WDFD= probably Normal Pressure 

El Paso Expl'n Pierce #1 wildcat 9 13 N. 25 W. Woodford 9.5 22,400 374 perfs rec gas 0.346 psi/ft WDFD= probably Normal Pressure 

Forest Oil Tahpoodle #1 wildcat 27 7 N. 12 W. Woodford 10.3 26,180 302 WDFD= probably Normal Pressure 

Lone Star Rogers #1 wildcat 27 10 N. 19 W. Woodford 10.1 27,520 385 0.380 psi/ft WDFD= probably Normal Pressure 

MRT Expl'n Sanders #1 wildcat 24 10 N. 25 W. Woodford 15.2 23,380 342 perfs rec gas 0.49 psi/ft Set csg at 23,272' ft. 15.2 ppg mud. WDFD=Overpr'd ? 

MRT Expl'n Kirtley #1 wildcat 19 10 N. 24 W. Woodford 16.5 23,755 346 perfs, stuck p Set csg at 20,594 ft. 16.5 ppg mud. WDFD=Overpr'd ? 

Natomas Patten #1 wildcat 14 10 N. 24 W. Morrow 18.2 19,500 283 18.2 ppg mud in Morrow north of the Frontal Fault 

Phillips Wesner A #1 wildcat 35 9 N. 17 W. Woodford 18.1 22,220 302 perfs, NR Set csg at 18,500'. 18.2 ppg mud. WDFD=Overpr'd ? 

Located in hangingwall of Cordell Fault Zone 

Shell Oil Britton #1 wildcat 28 9 N. 17 W. Springer 16.5 16,600 246 Located in hangingwall of Cordell Fault Zone 

Forest Oil Bobwhite #1 wildcat 16 8 N. 16 W. Woodford 17.6 21,790 285 stuck pipe 17.6 ppg mud Located in hangingwall of Cordell Fault Zone 

Gulf Oil Tabor #1 wildcat 24 8 N. 15 W. Springer 15.8 18,500 248 Springer test in footwall north of Cordell Fault Zone 

Table 1. Mud weights, depths, bottom hole temperatures, pressure gradients and formation test results for wells penetrating the Woodford Shale and Hunton Group in the deep Anadarko basin, Oklahoma, 

based on well logs, scout cards and completion reports available from Denver Earth Resources Library, 730 17th Street, Denver, Colorado, 80202. Approximate pressure gradients in Hunton reservoirs were 

calculated by dividing the maximum reported shut-in pressure (ISIP or FSIP) by the mid-point of the formation test interval.

Well Name No. FIELD Sec. Twp. Rg. Formation Mud Depth Pr/Depth BHT Rdeep Test Results, IP, CP, Comments 

ppg ft psi/ft degF ohmm 

El Paso N. G. Smith 1 W Cheyenne 5 13 N. 24 W. Puryear Ss 17.3 14,804 0.88 272 50 - 80 Gas kick. IP=6 MMCFD, no water. CP= 23.53 BCFG. 

Helmerich & Payne Lester 1 W Cheyenne 9 13 N. 24 W. Puryear Ss 17.7 15,092 0.84 278 70 - 90 IP= 10.4 MMCFD, no water. CP= 16.69 BCFG (6/99). 

El Paso N. G. Hunt-Cross 1 W Cheyenne 22 13 N. 24 W. Puryear Ss 16.8 15,521 0.92 272 50 - 170 IP= 10 MMCFD, no water. CP= 8.39 BCFG (12/92). 

El Paso N. G. Thurmond 1 W Cheyenne 27 13 N. 24 W. Puryear Ss 18 15,695 0.73 265 40 - 110 IP= 12.9 MMCFD, no water. CP= 7.43 BCFG (12/91). 

W Cheyenne Puryear Ss 15,800 1000 ft Gas column. Gas-water contact at approx. 15,800 ft. 

El Paso NG Thurmond 3 W Cheyenne 35 13 N. 24 W. Puryear Ss 17.6 15,955 246 18 - 29 Calculated Sw= 55-100%. Test results NR. Abd. 

L.P.C.X. Thurmond 34A W Cheyenne 34 13 N. 24 W. Puryear Ss 17.2 15,980 240


ppg ft psi/ft degF ohms 

Texas Pacific Nellie Libby 1 NW Reydon 33 14 N. 26 W. Puryear Ss 16.3 14,890 0.83 40 - 60 IP= 8.729 MMCFD, no wtr. CP= 33.24 BCFG (6/99). 

Gulf Oil Hartley 1 NW Reydon 34 14 N. 26 W. Puryear Ss 14.9 14,970 0.81 263 58 - 65 IP= 3.2 MMCFD + 3 bwpd. CP = 16.98 BCFG (6/99.) 

El Paso N. G. Scrivner 1 NW Reydon 35 14 N. 26 W. Puryear Ss 17 15,000 0.82 289 60 - 80 Gas kick, rig fire. IP= 8 MMCFD. CP= 14.09 BCFG. 

El Paso NG Robertson A 1 NW Reydon 1 13 N. 26 W. Puryear Ss 16.5 15,128 0.8 258 50 - 80 IP= 3.8 MMCFD, no wtr. CP= 8.82 BCFG (6/99). 

El Paso N. G. King 1 NW Reydon 6 13 N. 26 W. Puryear Ss 16.2 15,262 261 20 - 42 IP= 600 MCFD. Reservoir "depleted, non-commercial". Abd. 

Dyco Petr Yowell 1 NW Reydon 7 13 N. 25 W. Puryear Ss 16.4 15,360 23 - 24 IP= 500 MCFD. Probably watered out. Abd. 

NW Reydon Puryear Ss 15,400 500 ft Gas column. Gas-water contact at approx. 15,400 ft. 

Dyco Petr Pennington 1 NW Reydon 18 13 N. 25 W. Puryear Ss 16.5 15,695 270 9 - 34 IP=25 MCFD + 68 bwpd. CP= 139 MMCFG. Abd. 

El Paso N. G. Pennington 1 NW Reydon 17 13 N. 25 W. Puryear Ss 16.9 15,745 0.72 262 8 - 15 Swabbed Puryear, no gas shows, probably wet. Abd. 

Apexco Robinson Unit 1 NW Reydon 32 13 N. 25 W. Puryear Ss 18.4 16,125 5 - 15 Puryear Ss not tested. Very low resistivity, probably wet. Abd. 

Wagner & Brown McColgin 1 NW Reydon 29 13 N. 25 W. Puryear Ss 16,020 Puryear Ss flowed 61bw. Abd. 

Table 3. Mud weights, depths, bottom hole temperatures, pressure gradients, deep resistivities and formation test results for several wells at Northwest Reydon Field, Roger Mills County, 

Oklahoma, based on well logs, scout cards and completion reports available from the Denver Earth Resources Library, 730 17th Street, Denver, Colorado, 80202. There is evidently a gaswater 

contact at approximately 15,400 ft. Several wells located above the gas-water contact have produced large volumes of natural gas from high resistivity zones (20-80 ohm) in the 

overpressured Puryear Ss (Morrow Group). Downdip from the gas-water contact, the Puryear reservoir shows lower deep resistivity (4-16 ohm), flowed water at 61 to 68 bwpd, and 

the zone was abandoned. The available porosity in this reservoir was only partially filled with gas.

Well Name No. FIELD Sec. Twp. Rg. Formation Depth Mud Pr/Depth BHT Rdeep Test Results, IP, CP, Comments 

ft ppg psi/ft degF ohmm 

Forest Oil Fort Sill Unit 4 East Apache 30 5N 10W Britt Ss 16,780 16.0 0.75 55 - 62 IP= 7.3 MMCFD + 63 bwpd. CP= 12.27 BCFG (6/99). 

Kirby Exp Mindemann 1 East Apache 30 5N 10W Britt Ss 16,990 15.6 0.75 35 - 65 IP= 11.7 MMCFD, no water. CP= 13.19 BCFG (6/99). 

East Apache Britt Ss 17,115 Gas-water contact at approx. 17,115 ft (-15,700 ft)-. 

Forest Oil Lopez 1 East Apache 19 5N 10W Britt Ss 17,160 15.9 228 30 - 46 Britt Ss flowed 349 bwpd. Abd. 

Kirby Exp M. Murray 1 East Apache 5 4N 10W Britt Ss 17,870 Britt Ss flowed 200 bwpd. Abd. Completed uphole in Atoka. 

Table 4. Mud weights, depths, bottom hole temperatures, pressure gradients, deep resistivities and formation test results for several wells at East Apache Field, Caddo 

County, Oklahoma, based on well logs, scout cards and completion reports available from the Denver Earth Resources Library, 730 17th Street, Denver, Colorado, 80202. 

There is evidently a gas-water contact at approximately 16,970 ft (-15,640 ft). Two wells located above the gas-water contact have produced large volumes of natural gas 

from high resistivity zones (55-65 ohm) in the overpressured Britt Ss (Springer Group). Downdip from the gas-water contact, the Britt Ss reservoir shows lower deep 

resistivity (30-46 ohm). The Britt Ss flowed water at 200 to 349 bwpd, and the zone was abandoned. The available porosity in this reservoir was only partially filled 

with gas.


ppg ft psi/ft degF ohmm 

Hall-Jones Neely 1 wildcat 9 14 N. 11 W. Atoka 10,260 0.76 Atoka DST rec 3,330' ft gassy water. FSIP= 7754 psi. 

Mustang Prod Dolan 1 Watonga 25 13 N. 11 W. Morrow 11,399 Morrow flowed 200 MCFD + 129 bl swtr. Abd. 

Trigg Drilling Heiliger 1 Watonga 12 12 N. 11 W. Boatwright 11,606 0.67 29 - 34 Flowed 480 bl swtr. Abd. 

ONG Exp Cannon 1 wildcat 14 12 N. 11 W. Morrow 14.8 11,975 0.64 210 30 - 60 DST rec 5,000 ft gassy water. ISIP= 7792 psi. Abd. 

Bartex Exp Snow 1 Bridgeport 10 12 N. 11 W. Britt 12,020 Flowed 180 bwpd. Abd. 

Mustang Prod Lee-D 1 Bridgeport 16 12 N. 11 W. Morrow 14.8 12,278 60 Flowed 150 MCFD + 89 bl swtr in 22 hours. Abd. 

Texas Pacific Betcher A 1 wildcat 8 8 N. 16 W. Springer 17.6 14,036 208 10 - 25 Flowed 1.2 MMCFD + 10 bwph. Abd. 

Sanguine Brown 1 NE Oney 4 9 N. 11 W. Cunningham 15,112 Flowed 400 MCFD + 15 bwph. 

Gulf Oil Anna Tabor 1 wildcat 24 8 N. 15 W. Springer 15.6 16,685 0.61 248 Flowed 815 MCFD + 67 bwpd. Abd. 

Shell Oil Rumberger 5 Elk City 16 10 N. 21 W. Springer 15 21,625 324 75 Flowed 9 MCFD, bailed 96 bl swtr. Flowed more swtr. Abd. 

GHK Nix 1 wildcat 2 10 N. 20 W. Springer 16.5 22,165 351 55 - 120 Flowed 270 bl swtr + show of gas and oil. Abd. 

Table 5. Mud weights, depths, bottom hole temperatures, pressure gradients, deep resistivities and formation test results for various exploration wells which recovered water from 

within the overpressured mega-compartment, based on well logs, scout cards and completion reports available from the Denver Earth Resources Library, 730 17th Street, Denver, 

CO, 80202. Several deep, overpressured reservoirs have produced water. The continuously gas saturated, basin-center model does not appear to fit this hydrocarbon system.

ABSTRACT 

Is There a Basin-Center Gas Accumulation 

in the Cotton Valley Sandstone, Gulf Coast Basin, USA? 

Charles E. Bartberger 

Petroleum Geologist 

Potential of Upper Jurassic/Lower Cretaceous Cotton Valley sandstones in the northern Gulf Coast Basin to 

harbor a basin-center gas accumulation was evaluated by examining (1) depositional/diagenetic history and reservoir 

properties of Cotton Valley sandstones, (2) presence and quality source rocks for generating gas, (3) burial/thermal 

history of source rocks and time of gas generation/migration relative to tectonic development of Cotton Valley traps, 

(4) gas and water recoveries from drillstem and formation tests, (5) distribution of abnormal pressures based on shutin-pressure 

data, and (6) presence or absence of gas-water contacts associated with gas accumulations in Cotton 

Valley sandstones. 

Cotton Valley sandstones comprise a predominantly progradational sequence deposited in fluvial-deltaic, barrierisland, 

and shallow-marine environments across the northern Gulf Coast Basin from east Texas to Alabama. In 

northern Louisiana, barrier-island sands were reworked and spread landward during periodic transgressive events 

resulting in development of a stacked series of extensive sandstone tongues that are interbedded with, and pinch out 

northward into, lagoonal shales. Referred to informally as blanket sandstones, these transgressive sandstones have 

sufficient porosity and permeability to produce gas at commercial rates without fracture-stimulation treatment. 

Elsewhere across the northern Gulf Basin, stacked fluvial-deltaic and barrier-island sandstones of the Cotton Valley 

Group comprise a massive-sandstone sequence with poor reservoir properties. These massive sandstones have been 

designated as tight-gas sandstones and they require substantial hydraulic-fracture treatments to produce gas at 

commercial rates. High permeability of Cotton Valley blanket sandstones is not conducive to presence of a basincentered 

gas accumulation, but low-permeability massive sandstones provide the type of reservoir in which 

continuous-gas accumulations commonly occur. 

Source rocks that generated gas found in Cotton Valley sandstone reservoirs are considered to be Bossier marine 

shales situated directly beneath the Cotton Valley sandstone, and stratigraphically lower carbonate mudstones of the 

Jurassic Smackover Formation. Marine shales interbedded with Cotton Valley sandstones also might have 

contributed some gas. Burial- and thermal-history data suggest that generation and migration of gas occurred during 

the past 60 m.y. Gas migration postdates development of the Sabine Uplift, smaller structures on the Uplift, and salt 

structures in the East Texas and North Louisiana Salt Basins. 

Abnormally high pressures in Cotton Valley sandstone reservoirs occur in northeast Louisiana in both the 

permeable, blanket-sandstone and tight, massive-sandstone trends. However, most gas accumulations in the tight, 

massive-sandstone trend across north Louisiana and northeast Texas are normally pressured. Geographic distribution 

of overpressure suggests that it is not associated with thermal generation of gas, and pressure data do not support 

presence of a basin-center gas-accumulation in either the blanket- or massive sandstone trend. 

Presence of a gas-water contact perhaps is the most definitive criterion suggesting that a gas accumulation is 

conventional rather than a “sweetspot” within a basin-center, continuous-gas accumulation. Occurrence of short gaswater 

transition zones and well-defined gas-water contacts in gas fields within the blanket-sandstone trend is 

consistent with relatively high permeability of these reservoirs, and suggests that these gas accumulations are 

conventional. Within the tight, massive-sandstone trend, however, permeability is sufficiently low that gas-water 

transition zones are long, and gas-water contacts poorly defined. With increasing depth through these long gas-water 

transition zones, gas saturation in reservoir sandstones decreases and water saturation increases. Eventually gas 

saturation becomes sufficiently low that, in terms of cumulative gas production, wells become marginally 

commercial to non-commercial at a structural position still within the transition zone above the gas-water contact. 

Consequently, gas-water contacts in Cotton Valley tight-gas-sandstone accumulations rarely are encountered by

drilling, but best available data suggest that gas-water contacts are present. Presence of gas-water contacts associated 

with gas accumulations in the tight, massive Cotton Valley sandstone trend suggests that accumulations in this 

trend, too, are conventional, and that a basin-center gas accumulation does not exist within Cotton Valley sandstones 

in the northern Gulf of Mexico Basin. 

INTRODUCTION 

As part of the 1995 National Assessment of United States Oil and Gas Resources by the U.S. Geological 

Survey, Schenk and Viger (1996) identified one continuous-gas play and two conventional-gas plays (fig. 1) within 

the Cotton Valley sandstone trend in east Texas and northern Louisiana. Goals of this new study are to re-evaluate 

the 1995 play boundaries and parameters for establishing those boundaries through more-extensive evaluation of data 

on reservoir properties, reservoir pressures, gas and water recoveries, gas-production rates, and gas-water contacts in 

Cotton Valley sandstones. 

From a regional perspective, two productive trends of Cotton Valley sandstones can be identified based on 

sandstone-reservoir properties, gas-production rates, and necessity of hydraulic-fracturing treatments to achieve 

commercial production. Across northernmost Louisiana, so-called Cotton Valley blanket sandstones have sufficiently 

high porosity and permeability that commercial rates of gas production can be obtained without artificial well 

stimulation. South of this area in northern Louisiana and extending westward across the Sabine Uplift into northeast 

Texas, sandstones in the Cotton Valley massive-sandstone trend have poor reservoir properties and require massivehydraulic-fracturing 

treatments to achieve commercial rates of gas production. Because basin-center, continuous-gas 

accumulations characteristically occur within low-permeability reservoirs, the tight, massive Cotton Valley 

sandstone trend across northern Louisiana and northeast Texas is an ideal setting in which to look for basin-centered, 

continuous-gas accumulations. With wireline logs and mudlogs unavailable for this study, interpretations and 

conclusions presented herein are based entirely upon data reported in public literature and on production data 

accessible in a publicly available database from IHS Energy Group (petroROM Version 3.43). 

METHOD FOR EVALUATING POTENTIAL OF BASIN-CENTER GAS IN COTTON VALLEY 

SANDSTONES 

One of the main requirements for occurrence of a basin-centered, continuous-gas accumulation is presence of a 

regional seal to trap gas in a large volume of rock across a widespread geographic area. Within that large volume of 

rock, discrete gas accumulations with conventional seals and gas-water contacts are absent, and occurrence of gas 

often cuts across stratigraphic units. In classic basin-center-gas accumulations (Law and Dickinson, 1985; Spencer, 

1987; Law and Spencer, 1993), the regional seal is provided by low-permeability of the reservoir itself, as described 

above. To evaluate potential for presence of a continuous-gas accumulation within the Cotton Valley Sandstone, 

therefore, it is necessary to examine reservoir properties of Cotton Valley sandstones across the northern Gulf Coast 

Basin. Because reservoir properties of Cotton Valley sandstones are governed by diagenetic characteristics, which are 

controlled primarily by depositional environment, it is helpful to understand Cotton Valley depositional systems and 

related diagenetic patterns. 

Although gas production from Cotton Valley sandstones seems to occur from discrete fields, it is necessary to 

determine if those fields are separate, conventional accumulations or so-called “sweet spots” within a regional, 

continuous-gas accumulation. Thus, it is essential to understand what characterizes the apparent productive limits of 

existing Cotton Valley gas fields, including presence or absence of gas-water contacts. 

Finally, because continuous-gas accumulations commonly are characterized by overpressure associated with 

thermal generation of gas from source rocks in proximity to low-permeability reservoirs, it is important to evaluate 

presence and quality of potential source rocks, burial and thermal history of those source rocks, and reservoir-pressure 

data. 

2

GEOLOGIC SETTING FOR COTTON VALLEY GROUP IN NORTHERN GULF BASIN 

The Cotton Valley Group is an Upper Jurassic to Lower Cretaceous sequence of sandstone, shale, and limestone 

which underlies much of the northern Gulf of Mexico coastal plain from east Texas to Alabama (figs. 2 and 3). 

Cotton Valley strata occur only in the subsurface and form a sedimentary wedge that thickens southward into the 

Gulf Basin from a zero edge in southern Arkansas and East Texas (fig. 2). Downdip limit of the Cotton Valley 

Group has not been delineated by drilling to date. Depth to top of the Cotton Valley ranges from about 4,000 feet 

subsea near the updip zero edge to more than 13,000 feet subsea along the southern margins of the East Texas and 

Louisiana Salt Basins (figs. 2 and 4). In southeastern Mississippi, top of the Cotton Valley occurs at nearly 20,000 

feet subsea. Greatest thickness of Cotton Valley rocks penetrated exceeds 5,000 feet in southeastern Mississippi 

(Moore, 1983). 

The Cotton Valley Group and overlying Travis Peak (Hosston) Formation represent the first major influx of 

terrigenous clastic sediments into the Gulf of Mexico Basin following its initial formation during continental rifting 

180 Ma in Late Triassic time (Salvador, 1987; Worrall and Snelson, 1989). Earliest sedimentary deposits in East 

Texas and North Louisiana sub-basins (figs. 2 and 3) include upper Triassic nonmarine redbeds of the Eagle Mills 

Formation, the thick lower and middle Jurassic evaporite sequence known as Werner Anhydrite and Louann Salt, and 

the nonmarine Norphlet Sandstone. Following a major regional marine transgression across the Norphlet, upper 

Jurassic Smackover regressive carbonates were deposited, capped by redbeds and evaporites of the Buckner Formation 

(fig. 3). A subsequent minor marine transgression is recorded by the Gilmer or Cotton Valley Limestone in east 

Texas, although equivalent facies in north Louisiana and Mississippi are terrigenous clastics known as Haynesville 

Formation. The marine Bossier Shale, lowermost formation of the Cotton Valley Group (figs. 3 and 5) was 

deposited conformably atop the Gilmer-Haynesville. 

Louann Salt became mobile as a result of sediment loading and associated basinward tilting. Salt movement was 

initiated during Smackover carbonate deposition and became more extensive with influx of Cotton Valley clastics 

(McGowen and Harris, 1984). Many Cotton Valley and Travis Peak fields in east Texas, Louisiana, and Mississippi 

are structural or combination traps associated with Louann salt structures. Salt structures range from small, lowrelief 

salt pillows to large, piercement domes (McGowen and Harris, 1984; Kosters and others, 1989). 

As shown in figures 2 and 4, the Sabine Uplift is a broad, low-relief, basement-cored arch separating the East 

Texas and North Louisiana Salt Basins. With vertical relief of 2,000 feet, the Sabine Uplift has a closed area 

exceeding 2,500 square miles (Kosters and others, 1989). Isopach data across the Uplift indicate that it was a positive 

feature during deposition of Louann Salt in the Jurassic, but that main uplift occurred in late, mid-Cretaceous (101 to 

98 Ma) and early Tertiary time (58 to 46 Ma) (Laubach and Jackson, 1990; Jackson and Laubach, 1991). As a high 

area for the past 60 m.y., the Sabine Uplift has been a focal area for hydrocarbon migration in the northern Gulf 

Basin during that time. Numerous smaller structural highs on the Uplift in the form of domes, anticlines, and 

structural noses provide traps for hydrocarbon accumulations, including many gas fields in Cotton Valley sandstones. 

Origins of these smaller structures have been attributed to salt deformation and small igneous intrusions, as 

summarized by Kosters and others (1989). Because the Louann Salt is thin across the Sabine Uplift, Kosters and 

others (1989) suggest that most of the smaller structures across the Sabine Uplift developed in association with 

igneous activity. 

COTTON VALLEY STRATIGRAPHIC NOMENCLATURE 

Since the first penetration of Cotton Valley strata in north Louisiana in 1927, complex informal stratigraphic 

nomenclature developed as numerous Cotton Valley oil and gas fields were discovered across northern Louisiana 

through the 1940s. Nomenclature became complex because of local stratigraphic complexities within Cotton Valley 

strata in north Louisiana and also because of regional variations in Cotton Valley depositional systems across the 

northern Gulf Basin. Terminology established by Swain (1944) was used until the complete revision of Cotton 

Valley stratigraphy by Thomas and Mann (1963) and Mann and Thomas (1964). Most subsequent reports, including 

the classic work of Collins (1980), have used Mann-Thomas terminology. Refinements to that terminology have 

been contributed by Coleman and Coleman (1981) and Eversull (1985). 

3

Cotton Valley lithofacies and associated stratigraphic nomenclature in north Louisiana are shown in figures 5 

and 6. Basal formation of the Cotton Valley Group is the Bossier Shale, a dark, calcareous, fossiliferous, marine 

shale. In east Texas, isolated turbidite sandstones occur within the Bossier Shale (Collins, 1980). Overpressured gas 

currently is being produced from these sandstones in a rapidly developing new play (PI Dwights Drilling Wire, Jan. 

3, 2000; Exploration Business Journal, 2 nd quarter 2000). Completely encased in marine shale, these gas-charged 

sandstones in this newly developing play might represent a continuous-gas accumulation. The Bossier Shale grades 

upward into Cotton Valley sandstones with interbedded shales. These sandstones consist of stacked barrier-island, 

offshore-bar, strandplain, and fluvial-deltaic sandstones, and are known as the Terryville massive-sandstone complex 

in north Louisiana (Coleman and Coleman, 1981). In east Texas, the stratigraphically equivalent unit is called 

Cotton Valley Sandstone, and it consists of braided-stream, fan-delta, and wave-dominated-delta sandstones (Wescott, 

1983; Coleman, 1985; Dutton and others, 1993). Across the Cotton Valley hydrocarbon-productive trend in east 

Texas and north Louisiana, the Terryville or Cotton Valley Sandstone averages about 1,000 to 1,400 feet in 

thickness (Finley, 1984; Presley and Reed, 1984). Sand deposition was interrupted in early Cretaceous time by a 

regional transgressive event marked by deposition of Knowles Limestone, the uppermost formation of the Cotton 

Valley Group (figs. 5 and 6). In updip areas of east Texas and south Arkansas, the Knowles pinches out, and Travis 

Peak clastics directly overly Cotton Valley sandstones (figs. 3, 5 and 6). 

COTTON VALLEY DEPOSITIONAL SYSTEMS 

Regional Framework 

From East Texas to Mississippi, CottonValley/Terryville stacked barrier-island, strandplain, and fluvial-deltaic 

sandstones reflect influx of sands from a number of depocenters. Evolution of Cotton Valley depocenters and 

associated paleogeography across northern Louisiana are described and illustrated by Coleman and Coleman (1981) 

who subdivided the Terryville Sandstone into four depositional “events” based on widespread shale breaks. Across 

south-central Mississippi, Moore (1983) shows three sequential paleogeographic reconstructions of Cotton Valley 

Sandstone deposition. Although similar, concise paleogeographic reconstructions have not been published for East 

Texas Basin, McGowen and Harris (1984) and Wescott (1985) provide data from which basic paleogeographic maps 

can be constructed. I have integrated data from these various workers to generate a regional paleogeographic map of 

upper Cotton Valley depositional systems (equivalent to Terryville IV of Coleman and Coleman, 1981) across the 

northern Gulf Basin from east Texas to Mississippi (fig. 7). 

As shown in figure 7, Cotton Valley fluvial-deltaic depocenters were located in present-day northeast Texas, 

south-central Mississippi, and along the Louisiana-Mississippi border. The system along the Louisiana-Mississippi 

border represents the ancestral Mississippi River and was a locus of major clastic influx. Large quantities of sand 

delivered to the marine environment by this system were transported westward by longshore currents producing an 

extensive east-west barrier-island or strandplain complex (Thomas and Mann, 1966). Vertical stacking of these 

barrier-island/strandplain sands through time resulted in accumulation of the Terryville massive-sandstone complex 

(figs. 6 and 7). The east-west barrier-island complex across northern Louisiana sheltered a lagoon to the north from 

open-marine waters to the south (Thomas and Mann, 1966). Shales of the Hico Formation accumulated in the 

lagoon while fluvial and coastal-plain sandstones and shales of the Schuler Formation were deposited in continental 

environments north of the lagoon (figs. 6 and 7). Development of a similar, but smaller, lagoon associated with 

barrier islands formed from longshore-transported sands in south-central Mississippi was documented by Moore 

(1983), as shown in figure 7. In east Texas, during the earliest phase of Cotton Valley sandstone deposition, small 

fan deltas developed along the updip margin of East Texas Basin (McGowen and Harris, 1984; Wescott, 1985; Black 

and Berg, 1987). The drainage system was immature with small fan deltas formed by numerous small streams. 

According to McGowen and Harris, 1984, fan-delta deposition persisted through Cotton Valley time along the 

western margin of East Texas Basin where fan-delta deposits characterize most of the Cotton Valley sandstone 

interval. Along the northern flank of East Texas Basin in the region of the present-day Sabine Uplift, a mature 

drainage system developed as fan deltas prograded basinward and evolved into a wave-dominated delta system. Lower 

Cotton Valley sandstones from this system commonly are referred to as the Taylor Sandstone, according to Kast 

(1983) and Wescott (1985). After Taylor Sand deposition was terminated by a sub-regional transgressive event, delta 

4

progradation resumed with development of a more elongate, fluvial-dominated system in the upper Cotton Valley 

(fig. 7), referred to as the Lone Oak Delta by Kast (1983). 

Blanket Sandstones of Northern Louisiana 

In northern Louisiana, at least 20 distinct tongues of sandstone extend landward from barrier-island deposits of 

the Terryville massive-sandstone complex and become thinner northward before pinching out into shales of the Hico 

lagoon, as shown in figure 6. Some of these sandstones have limited geographic extent covering only part of the 

lagoon, whereas others extend across most or all of the lagoon and interfinger with continental deposits of the 

Schuler Formation on the landward side of the lagoon (Coleman and Coleman, 1981; Eversull, 1985). These 

sandstones have been interpreted as transgressive deposits with sand being derived from Terryville barrier islands and 

transported landward into the Hico lagoon during periods of relative sea-level rise and/or diminished sediment supply 

(Coleman and Coleman, 1981; Eversull, 1985). These transgressive sandstones have significantly better porosity and 

permeability than Terryville massive sandstones from which they were derived, and have been prolific producers of 

oil and gas from structural, stratigraphic, and combination traps discovered in the 1940s, 1950s, and 1960s across 

northern Louisiana (Collins, 1980; Bebout and others, 1992). Referred to informally as “blanket” sandstones 

(Eversull, 1985), they can be correlated readily across northern Louisiana, and as shown in Figure 6, they were given 

informal names by operators during drilling in the 1940s and 1950s (Sloane, 1958; Thomas and Mann, 1963; and 

Eversull, 1985). 

Based on isopach map patterns, Eversull (1985) identified two groups of blanket sandstones. Geographically 

more extensive sandstones of the first group span most of the Hico lagoon and often interfinger with continental 

deposits of the Schuler Formation. These sandstones generally are 30 to 70 feet thick and can reach a thickness of 

140 feet toward the south where they merge with barrier-island sandstones of the Terryville massive-sandstone 

complex. Blanket sandstones of the second group generally are less than 30 feet thick, have limited geographic 

extent, and most commonly occur in the eastern part of the Hico lagoon proximal to the fluvial-deltaic source. These 

sandstones pinch out northward into shales of the Hico lagoon. Transgressive, blanket sandstones of both groups 

collectively have significantly higher porosity and permeability than barrier-island sandstones of the Terryville 

massive-sandstone complex to the south (Collins, 1980; Bebout and others, 1992). 

Reservoir Properties Define Two Productive Trends: Blanket Sandstones and Massive 

Sandstones 

Significant differences in reservoir properties between transgressive, blanket sandstones on the north and 

massive, barrier-island sandstones to the south define two different hydrocarbon-productive trends of Cotton Valley 

sandstones (fig. 8). Blanket sandstones have significantly higher porosity and permeability than Terryville massive 

sandstones to the south. Eversull (1985) reported that blanket sandstones are cleaner and better sorted, and attributed 

their superior reservoir properties to high-energy reworking during transgressive events. Coleman (1985), however, 

reported that blanket sandstones exhibit an increase in calcite cement and clay content northward toward their 

pinchout edges, and that superior reservoir properties occur because (1) clays inhibited precipitation of quartz 

overgrowths and (2) secondary porosity was generated through widespread dissolution of calcite cement. Absence of 

detrital clay coats on sand grains in high-energy barrier-island sandstones of the Terryville massive-sandstone 

complex to the south, however, permitted widespread precipitation of quartz cement as syntaxial overgrowths, 

resulting in nearly complete occlusion of porosity (Sloane, 1958; Coleman and Coleman, 1981). Whatever the cause 

of porosity differences, blanket sandstones generally have sufficient porosity and permeability to flow gas or liquids 

on open-hole drillstem tests (DSTs) and to produce gas without fracture-stimulation treatment (Collins, 1980; 

Bebout and others, 1992). Terryville massive sandstones to the south and west, however, have such poor reservoir 

properties that they do not flow gas or liquids during DSTs, and they require massive-hydraulic-fracture treatments 

before commercial production can be obtained. 

5

DIAGENESIS OF COTTON VALLEY SANDSTONES 

Because understanding reservoir mineralogy is critical to successful wireline-log analysis and design of fracturestimulation 

treatments in Cotton Valley sandstones, considerable attention has been devoted to understanding 

diagenetic patterns of Cotton Valley sandstones, especially in the low-permeability, Cotton Valley massivesandstone 

trend. Focusing on those sandstones in east Texas, Wescott (1983) reported that Cotton Valley sandstones 

are very fine-grained, well-sorted quartz arenites and subarkoses with monocrystalline quartz and feldspar being the 

primary framework components. Principal cements include quartz, calcite, clays, and iron oxides. In unraveling the 

complex diagenetic history of these sandstones, Wescott (1983) interpreted two major diagenetic sequences. The most 

common sequence is (1) formation of clay coats, primarily chlorite, on framework grains, usually covering grains 

partially, not completely, (2) precipitation of syntaxial quartz overgrowths on quartz grains, (3) dissolution of 

unstable grains, most commonly feldspars, (4) precipitation of clays, primarily illite and chlorite with minor 

kaolinite, (5) precipitation of calcite cement in both relict primary pores and secondary pores, and (6) large-scale 

replacement of grains and cements by calcite, resulting in poikilotopic texture in which a few relict quartz grains are 

“floating” in calcite. In the other, less-common diagenetic sequence, which occurs primarily in cleaner, coarsergrained 

sandstones, calcite cementation commenced early and progressed to yield a fabric with widespread replacement 

of grains by calcite. 

Wescott (1983) classified Cotton Valley sandstones into three general groups on the basis of primary 

depositional texture and resulting diagenetic characteristics. In general, Wescott (1983) found that clean, well-sorted 

sands deposited in high-energy environments (Type I) generally are nearly completely cemented by quartz and/or 

calcite, have little or no porosity and permeability, and provide little reservoir potential. In some cases, these 

sandstones exhibit preservation of minor amounts of primary intergranular porosity from presence of authigenic 

chlorite coats (Hall and others, 1984). In sands deposited in lower-energy environments where abundant detrital clays 

remained (Type II), nucleation of quartz overgrowths generally was inhibited by clays. Most clay-bearing sandstones, 

however, contain significantly large amounts of clay, and although abundant microporosity is associated with these 

clays, permeability generally is low. Highest porosities, according to Wescott (1983), occur in Type III sandstones 

which developed abundant secondary porosity from dissolution of unstable grains and calcite cement. Hall and others 

(1984), however, reported that dissolution of unstable grains often is incomplete, secondary pores generally are 

poorly interconnected, and these sandstones, too, have poor permeability, and require fracture stimulation to produce 

gas commercially. 

In northern Louisiana, as interpreted by Russell and others (1984), upper Cotton Valley (Bodcaw) sandstones at 

Longwood Field on the east flank of the Sabine Uplift experienced a virtually identical diagenetic history to that 

described for Cotton Valley sandstones in east Texas by Wescott (1983). Like Wescott (1983), Russell and others 

(1984) reported that nucleation of quartz overgrowths was inhibited by presence of clays, but the quantity of porefilling 

clays generally is so large that permeability is low despite presence of high microporosity. Also, as in east 

Texas, best reservoir sandstones are those that have low clay content and developed abundant secondary porosity 

through dissolution of unstable grains and cement. Similar diagenetic patterns in north Louisiana also were reported 

for Cotton Valley sandstones at Frierson Field by Sonnenberg (1976) and for the lowermost Terryville Sandstone 

(Taylor Sandstone) at Terryville Field by Trojan (1985). In addition to authigenic constituents reported in east Texas 

and north Louisiana, Trojan (1985) also found small amounts of authigenic pyrite in Taylor Sandstones at Terryville 

Field. Pyrite occurs as small silt-size clusters (framboids) and volumetrically is the least abundant authigenic mineral 

reported by Trojan (1985), but its presence is significant because of its effect on wireline-log measurements of 

formation resistivity. 

IMPACT OF DIAGENETIC MINERALOGIES ON WIRELINE LOGS 

Complex diagenetic mineralogy of tight Cotton Valley sandstones prohibits use of standard calculation 

procedures in reservoir evaluation with wireline logs. The main difficulty is that properties of certain diagenetic 

constituents result in abnormally low resistivity measurements which lead to such high calculated water saturations 

that productive zones appear to be wet. Major factors contributing to abnormally low resistivities in tight Cotton 

Valley sandstones include bound water associated with pore-filling clays or clay coats and conductive authigenic 

minerals such as pyrite and ankerite (Janks and others 1985; Turner, 1997). 

6

Pore-lining and pore-filling clays have exceptionally high ratios of surface area to volume. Large surface area and 

high cation-exchange capacity of clays result in formation of a double ionic layer on clay surfaces (Almon, 1979; 

Snedden, 1984). This bound double layer can be significantly more conductive than pore waters, resulting in 

abnormally low measured resistivities, especially with induction logs (Almon, 1979; Wescott, 1983). Highly 

conductive authigenic minerals, such as ankerite and pyrite, in Cotton Valley sandstones also cause abnormally low 

resistivities. Trojan (1985) found that pyrite concentrations as low as one percent in Cotton Valley sandstones had a 

dramatic effect on resistivity measurements and hence on calculated water saturations. Standard calculation methods 

showed that pyrite-bearing sandstones at Terryville Field in north Louisiana had water saturations in excess of 100 

percent. Trojan (1985) showed that if these sandstones were pyrite-free, calculated water saturations would be closer 

to 50 percent. Although water saturations in productive Cotton Valley sandstones commonly are 25 to 30 percent, 

water-free gas production has been achieved from zones with calculated water saturations as high as 60 percent 

(Nangle and others, 1982; Wilson and Hensel, 1984; Dutton and others, 1993). 

Porosity measurements from wireline logs also can be affected adversely from diagenetic mineral constituents in 

Cotton Valley sandstones. In a study of Taylor Sandstones at Terryville Field in north Louisiana, Ganer (1985) 

demonstrated the negative impact of authigenic carbonates on porosity measurements from wireline logs. Located 

within the porous, permeable blanket sandstone trend, Terryville Field was discovered in 1954 with production from 

the Cotton Valley “D” Sandstone, one of the blanket sandstones. The Taylor Sandstone occurs in the lower part of 

the Cotton Valley Sandstone interval, and its productive potential at Terryville Field was not discovered until 1978. 

Unlike the stratigraphically higher blanket sandstones, the Taylor Sandstone has relatively poor reservoir properties 

similar to those of tight Cotton Valley massive sandstones to the south. Like Wescott (1983), Ganer (1985) found 

that although the Taylor Sandstone is predominantly a quartz sandstone, it contains authigenic carbonate cement, and 

locally can be composed of more than 50 percent carbonate resulting in a poikilotopic texture. With abundant 

secondary porosity from carbonate dissolution, these high-carbonate sandstones are the best gas producers within the 

Taylor Sandstone interval at Terryville Field. Ganer (1985) identified several different carbonate minerals in Taylor 

Sandstones, including calcite, ankerite, and siderite. Grain densities of these minerals are 2.71, 3.00, and 3.96 g/cm 3 , 

respectively. If porosity logs based on a sandstone matrix (grain density of 2.65 g/cm 3 ) are run across an interval 

containing abundant carbonate constituents with higher densities, such as the Taylor Sandstone, measured porosity 

values will be pessimistic. Working with 420 feet of conventional core from four wells at Terryville Field, Ganer 

(1985) reported sandstone intervals with abundant carbonate constituents where log-measured porosities were close to 

zero, but core-measured porosities exceeded six percent. With complex effects of diagenetic minerals on both porosity 

and resistivity measurements from wireline logs, Ganer (1985) showed that a single porosity/water saturation limit 

is not suitable for evaluating productive potential of Cotton Valley sandstones at Terryville Field. Ganer’s 

conclusions probably are applicable to most, or all, of the tight, massive Cotton Valley Sandstone trend across 

northeastern Texas and northern Louisiana. 

In comparing core-derived reservoir properties with wireline-log measurements for Cotton Valley sandstones 

from Carthage Field in east Texas, Wilson and Hensel (1984) reported that no apparent relationship exists between 

porosity and permeability. From core analyses, they noted that it is not uncommon to find a sandstone interval with 

10 percent porosity and 1 to 3 mD permeability adjacent to a zone with similar porosity but with permeability less 

than 0.05 mD. Similarly, Ganer (1985) reported that Taylor sandstones with 8 percent porosity at Terryville Field in 

north Louisiana have permeabilities ranging from 0.01 to 13 mD. For Carthage Field, Wilson and Hensel (1984) 

also noted that empirically derived values of cementation factor (m) and saturation exponent (n), used in calculation 

of water saturation, vary significantly from zone to zone. Wilson and Hensel (1984) derived general empirical values 

of m and n for Carthage Field area to achieve more accurate log-derived estimates of water saturation. Because of such 

difficulties in determining water saturations from wireline logs, Presley and Reed (1984) stress that gas-pay cutoff 

values should be based on experience by operators in a given area. 

A consequence of difficulties in accurate reservoir evaluation from conventional log analysis, of course, is that 

intervals capable of producing gas might be bypassed because of high calculated water saturations. For this study, the 

significance of these difficulties with wireline logs in tight Cotton Valley sandstones is that logs are of limited value 

in differentiating between gas-productive and wet intervals, and therefore in identifying gas-water contacts on the 

flanks of Cotton Valley fields. 

7

SOURCE ROCKS 

Relatively scant information has been published on source rocks for hydrocarbons produced from Cotton Valley 

reservoirs in north Louisiana and east Texas. In studying the overlying Travis Peak Formation in east Texas, Dutton 

(1987) showed that shales interbedded with Travis Peak sandstone reservoirs were deposited in fluvial-deltaic settings 

where organic matter commonly is oxidized and not preserved. With measured values of total organic carbon (TOC) 

in Travis Peak shales generally less than 0.5 percent, these shales are not considered as potential hydrocarbon source 

rocks (Tissot and Welte, 1978). Dutton (1987) suggested that the most likely sources for hydrocarbons in Travis 

Peak reservoirs in east Texas are laminated, lime mudstones of the lower member of the Jurassic Smackover 

Formation and prodelta and marine shales of the Bossier Shale, basal formation of the Cotton Valley Group (Figure 

3). Sassen and Moore (1988) demonstrated that Smackover carbonate mudstones are a significant hydrocarbon source 

rock charging various reservoirs in Mississippi and Alabama, and Wescott and Hood (1991) documented the Bossier 

Shale as a significant source rock in east Texas. Presley and Reed (1984) suggested that gray to black shales 

interbedded with Cotton Valley sandstones, as well as the underlying Bossier Shale, probably are the source for gas 

in Cotton Valley sandstone reservoirs. Similar implication is made for sourcing Cotton Valley sandstone reservoirs 

in north Louisiana by Coleman and Coleman (1981), who state that “hydrocarbons were generated from neighboring 

source beds”. In summary, despite limited source-rock data, it seems likely that adequate hydrocarbon source rocks 

occur in Bossier Shales immediately beneath Cotton Valley sandstones, and also in stratigraphically lower 

Smackover carbonate mudstones (fig. 3). 

BURIAL AND THERMAL HISTORY 

Vitrinite reflectance (R o) is a measure of thermal maturity of source rocks based on diagenesis of vitrinite, a type 

of kerogen derived from terrestrial woody plant material. In a study of diagenesis and burial history of the Travis 

Peak Formation in east Texas, Dutton (1987) reported that measured R o values for Travis Peak shales generally range 

from 1.0 to 1.2 percent, indicating that these rocks have passed through the oil window (R o = 0.6 to 1.0 percent) and 

are approaching the level of onset of dry-gas generation (R o = 1.2 percent) (Dow, 1978). Maximum R o of 1.8 percent 

was measured in the deepest sample from a downdip well in Nacogdoches County, Texas. Despite thermal maturity 

levels reached by Travis Peak shales, the small amount, and gas-prone nature, of organic matter in these shales 

precludes generation of oil, although minor amounts of gas might have been generated (Dutton, 1987). 

In the absence of actual measurements of R o, values of R o can be estimated by plotting burial depth of a given 

source rock interval versus time in conjunction with an estimated paleogeothermal gradient (Lopatin, 1971; Waples, 

1980). Dutton (1987) presented burial-history curves for tops of the Travis Peak, Cotton Valley, Bossier Shale, and 

Smackover for seven wells on the crest and western flank of the Sabine Uplift. The burial-history curves show total 

overburden thickness through time and use present-day compacted thicknesses of stratigraphic units. Sediment 

compaction through time was considered insignificant because of absence of thick shale units in the stratigraphic 

section. Loss of sedimentary section associated with late, mid-Cretaceous and mid-Eocene erosional events was 

accounted for in the burial-history curves. 

Dutton (1987) provided justification for using the average present-day geothermal gradient of 2.1º F/100 ft for 

the paleogeothermal gradient for the five northernmost wells. Paleogeothermal gradients in the two southern wells 

probably were elevated temporarily because of proximity to the area of initial continental rifting. Based on the crustal 

extension model of Royden and others (1980), Dutton (1987) estimated values for elevated paleogeothermal gradients 

for these two wells for 80 m.y. following the onset of rifting before reverting to the present-day gradient for the past 

100 m.y. 

Using estimated paleogeothermal gradients in conjunction with burial-history curves, Dutton (1987), found that 

calculated values of R o for Travis Peak shales agree well with measured values. Because of this agreement, Dutton 

(1987) used the same method to calculate R o values for tops of the Cotton Valley Group, Bossier Shale, and 

Smackover Formation in east Texas. Estimated R o values for the Bossier Shale and Smackover in seven wells range 

from 1.8 to 3.1 percent and 2.2 to 4.0 percent, respectively, suggesting that these rocks have reached a stage of 

thermal maturity in which dry gas was generated. Assuming that high-quality, gas-prone source rocks occur within 

8

these two formations, it is likely that one or both of these units generated gas found in overlying Cotton Valley and 

Travis Peak reservoirs. 

No such regional source-rock and thermal-maturity analysis is known for Travis Peak and Cotton Valley 

intervals in northern Louisiana. Scardina (1981) presented burial-history data for the Cotton Valley, but included no 

information on geothermal gradients and thermal history of rock units. Present-day reservoir temperatures in tight 

Cotton Valley sandstones of east Texas and the tight, massive Terryville sandstone in northern Louisiana both are in 

the 250º to 270º F range (Finley, 1986; White and Garrett, 1992). It is likely that Bossier and Smackover source 

rocks in north Louisiana experienced relatively similar thermal history to their stratigraphic counterparts in east 

Texas and, therefore, are sources for Cotton Valley gas in north Louisiana. Herrmann and others (1991) presented a 

burial-history plot for Ruston Field in the Cotton Valley blanket-sandstone trend in northern Louisiana. At Ruston 

Field, they suggest that Smackover gas was derived locally from Smackover lime mudstones and Cotton Valley gas 

from Cotton Valley and Bossier shales. Their burial-history plot shows the onset of generation of gas from 

Smackover and Bossier source rocks at Ruston Field occurred about 80 Ma and 45 Ma, respectively. As noted earlier 

in this report, the Sabine Uplift has been a positive feature for the past 60 m.y. (Kosters and others, 1989; Jackson 

and Laubach, 1991). Therefore, it would have been a focal area for gas migrating from Smackover, Bossier, and 

Cotton Valley source rocks in East Texas and North Louisiana Salt Basins. 

ABNORMAL PRESSURES 

Pore pressure or reservoir pressure commonly is reported as a fluid-pressure gradient in pounds per square 

inch/foot (psi/ft). Normal FPG is 0.43 psi/ft in freshwater reservoirs and 0.50 psi/ft in reservoirs with very saline 

waters (Spencer, 1987). Abnormally high pore pressures as high as 0.86 psi/ft have been encountered in Cotton 

Valley reservoirs, especially in northeastern Louisiana (fig. 9). Multiple FPG values for a particular gas field in 

figure 9 refer to gradients calculated for different, stacked blanket-sandstone reservoirs penetrated in that field. Across 

northern Louisiana, as shown in figure 9, highest FPGs of 0.84 and 0.86 psi/ft occur in the southeast, and gradients 

generally decrease to nearly normal values of 0.43 to 0.50 psi/ft in the northwest. This pattern exhibits general 

agreement with reservoir-pressure data for northern Louisiana summarized by Coleman and Coleman (1981), as 

shown in figure 10. The dashed line in figure 10 shows a modification of Coleman’s and Coleman’s (1981) pressure 

boundary to include the 0.63 psi/ft gradient in Hico-Knowles Field and 0.67 psi/ft gradient in Tremont Field (fig. 9). 

Most significant for this study, boundary between overpressured and normally pressured Cotton Valley sandstones 

(fig. 10) shows no relationship to the two different productive Cotton Valley Sandstone trends defined by differences 

in reservoir properties (fig. 8). Additionally, most Cotton Valley sandstone reservoirs, especially in the tight, 

massive-sandstone trend across western Louisiana and east Texas are normally pressured, as shown in figure 9. 

HISTORY OF COTTON VALLEY SANDSTONE EXPLORATION 

Beginning in 1937 and continuing through the 1940s, 1950s, and into the early 1960s, commercial gas 

production was established from porous and permeable Cotton Valley blanket-sandstone reservoirs across north 

Louisiana. Blanket sandstones flowed gas at commercial rates without artificial stimulation. Initial discoveries were 

in anticlinal traps associated with salt structures. Subsequent discoveries came from more complex and subtle traps, 

including (1) combination traps with blanket sandstones pinching out across anticlines or structural noses, and (2) 

stratigraphic traps with blanket sandstones pinching out on regional dip (Pate, 1963; Coleman and Coleman, 1981). 

By the early 1960s, the high-porosity blanket-sandstone play matured, and exploratory drilling waned. Low-porosity, 

low-permeability, massive Cotton Valley sandstones to the south in Louisiana and to the west on the Sabine Uplift 

in west Louisiana and east Texas flowed gas at rates less than 1,000 MCFD (thousand cubic feet of gas per day) and 

were not commercial with gas selling at $0.18/mcf in the 1960s (Collins, 1980). 

9

In the 1970s, production from low-permeability, massive Cotton Valley sandstones became commercial as a 

result of technical advances in massive-hydraulic-fracturing techniques together with significantly higher gas prices. 

At Bethany Field on the Sabine Uplift in east Texas in 1972, Texaco successfully increased rate of production from 

tight Cotton Valley sandstones from 500 MCFD to a sustained rate of 2,500 MCFD and 30 bcpd (barrels of 

condensate per day) through massive-hydraulic fracturing (Jennings and Sprawls, 1977). In conjunction with 

development of improved stimulation technology, price deregulation through the Natural Gas Policy Act (NGPA) of 

1978 spawned a dramatic increase in drilling for low-permeability Cotton Valley gas sandstones (Bruce and others, 

1992). In 1980, the Federal Energy Regulatory Commission (FERC) officially classified low-permeability Cotton 

Valley sandstones as “tight gas sands”, qualifying them for additional incentive gas prices. Production from tight 

Cotton Valley sandstones surged. At Carthage Field in east Texas, for example, Cotton Valley production increased 

from 2.2 BCFG (billion cubic feet of gas) in 1976 to 70.9 BCFG in 1980 (Meehan and Pennington, 1982). The 

large area across north Louisiana and northeast Texas within which Cotton Valley sandstones have been designated 

tight-gas-sandstones by FERC includes all the counties named in figure 4 (Dutton and others, 1993). 

COMPARISON OF BLANKET-SANDSTONE AND MASSIVE-SANDSTONE TRENDS 

Two productive Cotton Valley sandstone trends are identified based on reservoir properties (fig. 8). As described 

above, Cotton Valley sandstone reservoir properties are a function of diagenetic characteristics, which are controlled 

by depositional environment. Reservoir properties in turn govern gas-production characteristics, including both 

initial rate of gas production and necessity of hydraulic-fracture treatments to achieve commercial production rates. 

Table 1 summarizes these and other key parameters distinguishing blanket- and massive-Cotton Valley sandstone 

reservoir trends. Data presented in table 1 were derived from a variety of sources as indicated in the table caption, 

with much of the information coming from a series of seven reports by the Shreveport Geological Society on oil and 

gas fields in northern Louisiana (Shreveport Geological Society Reference Reports, 1946, 1947, 1951, 1953, 1956, 

1963, 1987). Detailed information obtained from those reports on more than 20 Cotton Valley oil and gas fields in 

northern Louisiana, including data on porosity, permeability, initial production rates, gas-water contacts, and FPGs, 

is presented in table 2. 

Most of the significant fields across northern Louisiana and northeastern Texas from which Cotton Valley 

sandstones produce gas are shown in figure 8. The area shown in figure 8 is part of the larger region shown in figure 

4 within which Cotton Valley sandstones were designated as tight-gas sandstones by FERC in 1980. As shown in 

figure 8, however, 15 Cotton Valley fields were excluded from FERC’s tight-gas sandstone designation. All but one 

of these fields are located within the porous and permeable Cotton Valley blanket-sandstone trend. 

Blanket-Sandstone Trend 

Transgressive, Cotton Valley blanket sandstones have porosities ranging from 10 to 19 percent and 

permeabilities from one to 280 mD (tables 1 and 2). Porosity and permeability data are not readily available for each 

individual, productive blanket sandstone in all Cotton Valley fields. However, sufficient data are available from 

several blanket sandstones within a dozen fields across northern Louisiana to observe the widespread distribution of 

relatively high-quality reservoir sandstones across the Cotton Valley blanket-sandstone trend (fig. 11). Data shown in 

figure 11 are derived primarily from field reports by the Shreveport Geological Society and from White and others 

(1992). Multiple values of porosity and permeability for a given field in figure 11 represent measured values for 

separate, stacked blanket sandstones within that field. Average porosity and permeability for Cotton Valley blanket 

sandstones, calculated from data in figure 11, are 15 percent and 115 mD, respectively. 

Relatively high porosity and permeability of blanket sandstones is reflected in (1) ability of these sandstones to 

flow gas and/or liquids on open-hole DSTs, and (2) high initial flow rates from these sandstones in production tests 

without massive-hydraulic fracture-stimulation treatments, as shown in figure 12. Multiple values of initial flow 

rates for a given field shown in figure 12 represent rates from different stacked blanket sandstones that produce in that 

field. Across the blanket-sandstone trend, as shown in figure 12, initial production rates range from 500 MCFD to 

25,000 MCFD, and average 5,000 MCFD. 

10

Gas-water contacts have been reported in seven fields across the blanket-sandstone trend as shown in figure 13. 

In Hico-Knowles, South Drew, and Choudrant Fields, separate gas-water contacts for individual blanket sandstones 

have been identified (table 2). No gas-water contacts were encountered in Cheniere Field as of 1963 or in Tremont 

Field as of 1980 (table 2). In all other Cotton Valley fields described in Reference Reports by the Shreveport 

Geological Society (1946, 1947, 1951, 1953, 1956, 1963, 1987), no mention of fluid contacts was made. 

Massive-Sandstone Trend 

Cotton Valley sandstones in the massive-sandstone trend (fig. 8 and table 1) have significantly poorer reservoir 

properties than those in the blanket-sandstone trend. Massive Cotton Valley sandstones have sufficiently low 

permeability that they generally do not flow gas or liquids during open-hole DSTs, and they require fracturestimulation 

treatment to obtain commercial rates of gas production (Collins, 1980). Commercial gas production 

from these sandstones was not achieved until technological advances in massive-hydraulic fracturing occurred together 

with higher gas prices from deregulation in the 1970s. Consequently, development of Cotton Valley fields in the 

tight, massive Cotton Valley sandstone trend did not occur until the late 1970s and 1980s. Cotton Valley 

development drilling in Elm Grove and Caspiana Fields in northern Louisiana continues at the time this report is 

being written (Al Taylor, former BP Amoco geologist, personal communication, April 2000). A consequence of 

such recent development of fields in the tight, massive Cotton Valley sandstone trend is less published information 

on characteristics of these fields than on older fields in the blanket-sandstone trend. 

Limited Data in Public Literature 

Summary information presented by Dutton and others (1993) for the tight, massive Cotton Valley sandstone 

trend across northeast Texas and north Louisiana indicates porosities in the 6 to 10 percent range. Based on 

measurements from cores in 11 wells in Carthage Field, one of the largest Cotton Valley fields in northeast Texas, 

Wilson and Hensel (1984) reported porosities ranging from 5.8 to 8.1 percent, with an average of 6.6 percent. 

Associated permeabilities range from 0.02 to 0.33 mD, with an average of 0.067 mD. From core data for 126 wells 

in Harrison and Rusk counties in northeast Texas, Finley (1984) reported average permeability of 0.043 mD for 

Cotton Valley sandstones. In northern Louisiana, average permeability was reported as 0.015 mD based on data from 

Cotton Valley cores in 302 wells. However, there are stratigraphic intervals within the tight, massive Cotton Valley 

trend with significantly higher permeabilities. Locally, permeabilities approaching 100 mD have been reported 

(Wilson and Hensel, 1984). 

Significantly poorer porosity and permeability of tight, massive Cotton Valley sandstones relative to blanket 

sandstones is reflected in poorer production characteristics. Average flow rate prior to fracture-stimulation treatment 

is 50 MCFD (Dutton and others, 1993). Post-stimulation rates generally are in the 500 to 2,500 MCFD range, 

although rates as high as 10,000 MCFD and 11,700 MCFD have been reported from Bethany Field (Jennings and 

Sprawls, 1977) and Carthage Field (Meehan and Pennington, 1982), respectively. 

Published data on presence of gas-water contacts or production of water without gas on the flanks of Cotton 

Valley fields in the tight, massive-sandstone trend are meager. Summary data presented by Nangle and others (1982) 

described gas-water contacts as poorly defined with long transition zones in contrast to short, well-defined transition 

zones with sharp gas-water contacts in the blanket-sandstone trend. Also suggesting presence of gas-water contacts 

with long transition zones is the statement by Dutton and others (1993) that for Cotton Valley Sandstone intervals 

200 feet above the free-water level, calculated water saturations should be less than 40 percent to achieve successful 

gas completions. 

In northeast Texas, where most of the drilling for tight Cotton Valley sandstones has occurred, best reservoir 

potential is reported to be in wave-dominated-delta Taylor Sandstones in the lower part of the Cotton Valley section 

(Wescott, 1983, 1985). In Oak Hill Field, production logs show that Taylor Sandstones contribute more than 80 

percent of the gas production and that sandstones in the middle and upper Cotton Valley section contribute most of 

the water production, although they produce significant gas as well (Tindall and others, 1981). Presley and Reed 

11

(1984) and Dutton and others (1993) both report presence of water-bearing sandstones in the upper Cotton Valley 

interval. To avoid production of water from these sandstones, fracture-stimulation treatments in stratigraphically 

adjacent gas-bearing sandstones in the upper Cotton Valley must be significantly smaller that those in the Taylor 

Sandstone. At Bethany Field, several wells reportedly were plugged because of production of salt water from Cotton 

Valley sandstones (Jennings and Sprawls, 1997). 

Analysis of Drillstem-Test and Production-Test Data 

As mentioned above, general statements in published reports suggest presence of gas-water contacts in fields that 

produce gas from tight Cotton Valley sandstones across northeastern Texas and northern Louisiana. Unlike data for 

the Cotton Valley blanket-sandstone trend, however, no documentation was found identifying specific gas-water 

contacts in Cotton Valley sandstones in any of the tight-gas sandstone fields in Texas or Louisiana. In the absence of 

such published data, and considering the difficulties using wireline logs to evaluate water saturations in tight Cotton 

Valley sandstones, an attempt was made to document presence or absence of gas-water contacts through analysis of 

data from DSTs and production tests. The goal was to determine if Cotton Valley fields that produce from tight-gas 

sandstones were flanked by dry holes that tested water only without gas, suggesting` presence of a gas-water contact. 

A data set of wells penetrating the Cotton Valley Group across most of northeastern Texas and northern Louisiana 

was extracted from a database provided by IHS Energy Group (petroROM Version 3.43) for analysis of drillstem-test 

and production-test data using ARCVIEW software. Because tight Cotton Valley sandstones generally do not flow 

fluids on open-hole DSTs, it was anticipated that most useful data would be derived from production tests made 

through perforations in casing following fracture-stimulation treatments. Well data were sorted and displayed in map 

view using ARCVIEW software such that wells which produce from Cotton Valley sandstones could be 

distinguished from dry holes with tests. While viewing the map display, test results from any particular well could 

be examined. 

Reconnaissance analysis of data from Carthage, Bethany, Oak Hill, Waskom, and Woodlawn Fields in 

northeastern Texas, and from Bear Creek-Bryceland, Elm Grove, and Caspiana Fields in northern Louisiana, revealed 

few dry holes penetrating Cotton Valley strata on the flanks of these Cotton Valley fields. No flanking dry holes 

were found which tested only water. The few Cotton Valley dry holes present generally did not report tests, 

suggesting that no tests were performed in those wells, and that, most likely, the wells were plugged based on 

evaluation of wireline logs. 

Test results from Cotton Valley sandstones in Oak Hill Field in Texas and Elm Grove/Caspiana Fields in 

Louisiana were evaluated more rigorously, revealing several general patterns. Initial rates of gas production generally 

are higher in crestal wells than in flank wells in these fields, as shown for Caspiana Field in figure 14. At both Oak 

Hill and Elm Grove-Caspiana Fields, initial rates of gas production from Cotton Valley sandstones range from 1,000 

to more than 4,000 MCFD in central regions of the fields, and generally are less than 1,000 MCFD in structurally 

lower wells on edges of the fields. Many flank wells exhibit initial rates less than 500 MCFD, as shown in Figure 

14. This trend exhibits more variability at Oak Hill Field, where a considerably greater number of low-rate wells 

occur in the center of the field. Such low-rate wells in the central region of the field could be attributed to a number 

of factors, including reservoir variability, formation damage during drilling, and poor fracture-stimulation treatments. 

All these wells must be fracture stimulated, and significant variation in success of such stimulation treatments is not 

uncommon. Also, initial rates on the west flank of Oak Hill Field are high and show an abrupt change to dry holes 

rather than showing a gradual decline toward the flank of the field. One well there flowed gas with an initial rate 

exceeding 4,000 MCFD and is flanked to the west by four Cotton Valley dry holes. In three of these dry holes, 

Cotton Valley sandstones apparently were not tested, and a test in the fourth must have resulted in non-commercial 

production with only “one unit of gas” reported. 

Initial rates of water production in bwpd (barrels of water per day) also were mapped at Oak Hill and Elm Grove- 

Caspiana Fields and show no obvious patterns across these fields. No attempt was made to contour water production 

data for several reasons. Not only is variability in initial rate of water production high and seemingly random, but 

also, data are incomplete. Whereas the IHS Energy database reports report initial rate of gas production for most all 

wells in these fields, initial rate of water production is not reported for a significant percentage of wells. In wells at 

12

Oak Hill, Elm Grove-Caspiana Fields for which a value is entered in the appropriate position of the database for 

water production, a null value is never reported. Some volume of water production seems to occur along with gas in 

all these wells. Hence, it does not seem appropriate to interpret absence of water-production data for a given well as 

meaning zero production of water. Absence of initial water production data is especially significant at Oak Hill Field, 

and that factor alone makes it difficult to analyze water production from that field. Data on initial water production at 

Elm Grove-Caspiana Fields are more complete. Although rates of water production were considerably higher at 

Caspiana Field, data were most complete for that field, and patterns of initial water production at Caspiana Field were 

evaluated by plotting barrels of water produced per MMCFG. As shown in Figure 15, wells in the central part of 

Caspiana Field commonly exhibit production of 100 or fewer bbls wtr/MMCFG. Progressing outward toward flanks 

of the field, rates of initial water production increase to 300 to more than 600 bbls wtr/MMCFG. Highest initial rate 

of water production occurs on the west flank of the field where production of 1,477 bbls wtr/MMCFG is reported 

(fig. 15). That same well had an initial rate of gas production of only 325 MMCFD, as shown in figure 14. 

Nevertheless, no wells were identified on the flanks of these fields that tested water only without gas from Cotton 

Valley sandstones and hence inferred a gas-water contact for the field. Surrounding Elm Grove-Caspiana Fields, 23 

Cotton Valley dry holes were identified. Of these, 19 wells reported no tests in the Cotton Valley sandstone interval, 

presumably indicating that no Cotton Valley tests were run, and that Cotton Valley completions were not made on 

the basis of wireline-log evaluation. Production tests after fracture-stimulation were run in two other wells. One 

reported “one unit of gas and one unit of oil”, presumably indicating non-commercial rates. The other well reported 

only “one unit of water”, suggesting that the Cotton Valley sandstone might be below a gas-water contact at that 

location. On the south and west flanks of Oak Hill Field, six Cotton Valley dry holes without tests were identified, 

again suggesting abandonment of Cotton Valley potential based on wireline-log evaluation. Production tests were 

run in Cotton Valley sandstones in two wells on the west flank of Oak Hill Field. One reported “one unit of gas”, 

the other “one unit of gas and one unit of water”. On the south flank of the field, production tests were run in Cotton 

Valley sandstones in two Cotton Valley dry holes, but no results were reported. Evaluation of test data from Oak 

Hill and Elm Grove-Caspiana Fields, therefore, provides no definitive information regarding or of presence or absence 

of gas-water contacts in these Cotton Valley fields. 

DISCUSSION OF EVIDENCE FOR AND AGAINST BASIN-CENTERED GAS 

Source Rocks and Burial/Thermal History 

Source rocks responsible for generating gas in basin-center gas accumulations commonly are in stratigraphic 

proximity to low-permeability reservoirs that they are charging with gas. As described above, published data on 

source rocks responsible for generating gas found in Cotton Valley sandstone reservoirs in both the blanket- and 

massive-sandstone trends are meager. However, the marine Bossier Shale, which is stratigraphically directly beneath 

Cotton Valley sandstones, and Smackover laminated lime mudstones, which lie below the Bossier Shale, are 

considered to be source rocks capable of generating gas for Cotton Valley sandstone reservoirs. Gray to black marine 

shales interbedded with Cotton Valley sandstones also are considered to be potential source rocks. Also, as 

summarized above, burial- and thermal-history data for the northern Gulf Coast Basin suggest that burial depths of 

Bossier and Smackover source rocks, in conjunction with the regional geothermal gradient, have been sufficient to 

generate dry gas. Time of generation of much of the gas postdates development of both the Sabine Uplift and 

structures in the East Texas and Louisiana Salt Basins. Hence, available data on presence of source rocks, burial and 

thermal history of source rocks, and timing of gas generation for Cotton Valley reservoirs would be consistent with 

interpretation of a potential continuous-gas accumulation in sandstones of the Cotton Valley Group. 

Porosity, Permeability, and Gas-Production Rates 

Basin-centered, continuous-gas accumulations commonly involve a large volume of gas-saturated rock in which 

presence of gas cuts across stratigraphic units. Such gas accumulations require a regional seal to trap gas, and that 

seal characteristically is provided by inherent low-permeability of reservoir rocks themselves. Thus, continuous-gas 

reservoirs characteristically have low permeability, and when reservoirs are sandstones, they often are referred to as 

tight-gas sandstones. 

13

As described above, Cotton Valley sandstone reservoirs across the northern Gulf of Mexico Basin can be divided 

into two groups based on reservoir properties and associated rates of gas production. Sandstones in the Cotton Valley 

blanket-sandstone trend across northernmost Louisiana have porosities in the 10 to 19 percent range and 

permeabilities from 1 to 280 mD (table 1). These sandstones generally flow gas and/or liquids during open-hole 

DSTs. Gas-productive sandstones flow at initial rates ranging from 500 to 25,000 MCFD without fracturestimulation 

treatment. Consequently, these sandstones are not tight-gas reservoirs, and most fields producing from 

Cotton Valley sandstones in the blanket-sandstone trend were excluded from tight-gas status by FERC in 1980 

(Figure 8). Therefore, in the absence of some other regional top seal that could allow development of basin-wide 

overpressure, sandstones in this trend would not be expected to harbor a basin-center gas accumulation. 

South of this blanket-sandstone trend in northern Louisiana lies the massive-Cotton Valley sandstone trend, and 

it extends westward across the Sabine Uplift into northeast Texas, as shown in Figure 8. Massive Cotton Valley 

sandstones generally have porosities in the 6 to 10 percent range with permeabilities commonly less than 0.1 mD. 

Most of these sandstones, therefore, would be defined as tight-gas sandstones, and most all fields producing gas from 

these sandstones were designated as tight-gas-sandstone fields by FERC in 1980. Tight, massive Cotton Valley 

sandstones generally do not flow gas and/or liquids on open-hole DSTs, and they require massive-hydraulic-fracture 

treatment to produce gas at commercial rates. As shown in table 1, pre-stimulation initial-production rates generally 

range from too-small-to-measure (TSTM) to 300 MCFD. Post-stimulation rates commonly are 500 to 2,500 

MCFD. Although higher-permeability intervals occur locally within the massive-sandstone trend as noted by Wilson 

and Hensel (1984), characteristic low permeability of sandstones throughout this trend suggests that they might have 

potential to provide their own seal for gas in a continuous-gas accumulation. 

Abnormal Pressures 

In a study of abnormally high pressures in basin-centered-gas accumulations in Rocky Mountain basins, Spencer 

(1987) considered reservoirs to be significantly overpressured if FPGs exceed 0.50 psi/ft where waters are fresh to 

moderately saline, and 0.55 psi/ft where waters are very saline. With formation-water salinity of Cotton Valley 

sandstone reservoirs on the order of 170,000 ppm TDS (Dutton and others, 1993), salinity is considered high, and 

reservoirs should be considered to be overpressured if their FPGs exceed 0.55 psi/ft. 

Based on Spencer’s (1987) cutoff value of 0.55 psi/ft, abnormally high reservoir pressures have been encountered 

in Cotton Valley sandstones in an area of northeastern Louisiana, as shown in Figure 10, where calculated pressure 

gradients of 0.63 to 0.86 psi/ft occur. Boundary between areas of overpressure and normal pressure cuts across the 

permeable, blanket- and tight, massive-sandstone trends such that overpressures occur within both reservoir trends. 

(Figures 8 and 10). Although overpressures associated with generation of gas might be anticipated in tight Cotton 

Valley sandstones, such overpressures would not be expected to develop in high-permeability blanket sandstones 

without a sub-regional top seal stratigraphically above the sandstones. As shown in Figure 9 and table 2, some of 

the separate, stacked blanket sandstones within Hico, Tremont, and Calhoun Fields are overpressured, whereas others 

are normally pressured. Examination of discovery dates of gas in individual sandstones shows that in all cases for 

these three fields, normally pressured sandstone reservoirs were discovered prior to overpressured ones. Thus, pressure 

differences among individual blanket-sandstone reservoirs indicate presence of separate, compartmentalized reservoirs, 

rather than pressure depletion from production of gas from different sandstones that are in pressure communication. 

Additionally, normally pressured Cotton Valley sandstones were encountered at South Drew Field, whereas, at 

Cheniere Field immediately to the west, Cotton Valley sandstones were significantly overpressured with a FPG of 

0.86 psi/ft. Thus, for gas fields in the blanket-sandstone trend where data are abundant, reservoir pressures exhibit 

significant variation from normal to abnormally high among separate sandstone reservoirs within individual gas 

fields, and also between adjacent fields. Such compartmentalization of overpressured reservoirs in proximity to 

normally pressured ones, rather than development of overpressure on a regional scale, is more indicative of 

conventional-gas fields than basin-center gas accumulations. 

14

Within the western half of the blanket-sandstone trend and spanning the vast majority of the tight, massivesandstone 

trend across northwest Louisiana and northeast Texas, FPGs range from 0.32 to 0.55 psi/ft, and therefore, 

would be considered normal, according to methodology of Spencer (1987). However, two episodes of erosion have 

occurred in northeast Texas, one in late mid-Cretaceous time, and the second in early mid-Tertiary time (Dutton, 

1987; Laubach and Jackson, 1990; Jackson and Laubach, 1991). During late mid-Cretaceous time, maximum erosion 

occurred on the crest of the Sabine Uplift where approximately 1,800 feet of sedimentary section was removed. 

Tertiary erosion resulted in removal of about 1,500 feet of section across much of northeast Texas. Burial-history 

data for Ruston Field area in northern Louisiana on the boundary between overpressured and normally pressured 

regions, show about 1,500 and 500 feet of uplift and loss of section, respectively, in two erosional periods 

(Herrmann and others, 1991). It is possible, therefore, that with deeper burial, reservoir pressures in much or all of 

the massive-sandstone trend were higher, and that reduction of pressure has occurred as a result of uplift and erosion. 

However, much of the gas found in Cotton Valley sandstone reservoirs is believed to have been derived from Bossier 

Shale source rocks. Migration of most of that gas into Cotton Valley sandstones probably commenced between 57 

and 45 Ma (Dutton, 1987; Hermann and others, 1991). Therefore, if basin-wide overpressure in Cotton Valley 

sandstones were to have developed in response to thermal generation of gas from Bossier Shale source rocks, its 

development would have postdated the Tertiary erosional event. 

The sharp boundary between overpressured and normally pressured areas of Cotton Valley sandstones (Figure 10) 

and presence of overpressure in both permeable, blanket- and tight, massive-sandstone trends, suggest that 

abnormally high pressures encountered in Cotton Valley sandstones in northeast Louisiana are not caused by thermal 

generation and migration of gas. Coleman and Coleman (1981) attributed development of overpressures in Cotton 

Valley sandstones across the region shown in figure 10 to a late-stage of diagenesis in which extreme pressure, 

presumably overburden pressure, and temperature caused dissolution of silica at contact points of quartz-sand grains 

and precipitation of silica in adjacent pores. With pore waters apparently unable to escape, porosity reduction 

associated with this late-stage chemical compaction reportedly resulted in development of overpressure in Cotton 

Valley sandstones across the area shown in figure 10. According to Coleman and Coleman (1981), a significant 

factor in preventing fluid loss from Cotton Valley sandstones during this late diagenetic episode was presence of a 

tight top seal provided by the Knowles Limestone and upper Cotton Valley/lower Hosston shales. 

If late-stage chemical compaction and cementation in conjunction with a top seal of tight limestone and shale 

are responsible for development of overpressure, it is not clear why the geographic distribution of overpressure 

exhibits the pattern shown in figure 10. Perhaps an alternative mechanism for generating the distribution of 

overpressures within Cotton Valley sandstones shown in figure 10 could be one reported by Parker (1972) as cause 

for overpressures in Jurassic Smackover sandstone and carbonate reservoirs to the east in Mississippi. Parker (1972) 

noted that that much of the Smackover gas is sour and has a high relatively high content of CO 2 and/or N 2. He 

suggested that migration of gases derived from late-Cretaceous emplacement of the Jackson (igneous) Dome might 

be responsible for “inflation” of pressures in well-sealed Smackover reservoirs. Specifically, Jones (1977) suggested 

that H 2S and CO 2 present in Smackover gas in Mississippi were derived from igneous intrusion of anhydrite and 

limestone/dolomite, respectively. The mapped pattern of overpressured Cotton Valley sandstones (fig. 10) extends 

east-southeastward into Mississippi directly toward location of Jackson Dome (Studlick and others, 1990). Evidence 

supporting such a mechanism of overpressure development in Cotton Valley sandstones of northeast Louisiana 

would be elevated levels of CO 2 and/or N 2 in overpressured Cotton Valley sandstone reservoirs, but such data are not 

known. 

In summary, within most of the tight, massive Cotton Valley sandstone trend across western Louisiana and 

northeast Texas, Cotton Valley reservoirs are slightly, but not significantly, overpressured. Based on methodology 

and terminology of Spencer (1987), these reservoirs would be characterized as normally pressured. As described 

above, basin-centered, continuous-gas accumulations characteristically are significantly overpressured. Although 

pressure data for the tight, massive Cotton Valley sandstone trend are not definitive, they tend to suggest that a 

basin-center gas accumulation characterized by abnormally high pressures from thermal generation of gas is not 

present within the Cotton Valley Sandstone. 

15

Gas-Water Contacts 

Perhaps the most definitive criterion for establishing presence of a continuous-gas accumulation is absence of 

gas-water contacts. Gas-water contacts are distinctive features of conventional gas accumulations. Presence of a gaswater 

contact indicates change from gas-saturated to water-saturated porosity within a particular reservoir unit. This 

implies that a well drilled into that reservoir structurally below the gas-water contact should encounter only water, 

thereby demonstrating the absence of a continuous-gas accumulation in that immediate area. 

Within the blanket-sandstone trend across northernmost Louisiana, gas-water contacts have been reported in 

seven fields, as shown in Figure 13. Because of relatively high porosity and permeability in blanket sandstones, gaswater 

contacts are sharp and often are reported as a subsea depth to the nearest foot. Separate gas-water contacts for 

individual, stacked blanket sandstones have been identified in Hico-Knowles, South Drew, and Choudrant Fields 

(table 2). The seven fields in which gas-water contacts have been described are widely distributed across the blanketsandstone 

trend (Figure 13). Because of the relatively uniform distribution of high-permeability Cotton Valley 

sandstone reservoirs with conventional shale seals in fields across the blanket-sandstone trend, it is likely that all 

Cotton Valley fields in this trend have well-defined gas-water contacts similar to those documented in the seven fields 

shown in Figure 13. The Cotton Valley blanket-sandstone trend was defined as a continuous-gas accumulation in the 

1995 National Assessment of United States Oil and Gas Resources by the U.S. Geological Survey, Schenk and 

Viger (1996). However, presence of abundant gas-water contacts across this area suggests that the blanket-sandstone 

trend should be redefined as a conventional-gas play. 

Evaluating presence or absence of gas-water contacts in the tight, massive Cotton Valley sandstone trend is 

considerably more difficult. No reference to specific gas-water contacts for Cotton Valley sandstones in any Cotton 

Valley gas field has been found in published literature. Nangle and others (1982) and Dutton and others (1993), 

however, make general statements indicating that gas-water contacts are present in Cotton Valley fields across the 

tight, massive Cotton Valley sandstone trend. 

Although Taylor Sandstones in the lower part of the Cotton Valley section produce gas in all significant Cotton 

Valley fields in the tight, massive-sandstone trend, water-bearing sandstones have been reported along with gascharged 

sandstones in the middle and upper Cotton Valley interval in some fields. The seal for gas in wavedominated-delta 

Taylor Sandstones reportedly is provided by marsh and lagoonal shales (CER Corporation and S. A. 

Holditch & Associates, 1991). This seal would be considered conventional rather than one provided by low 

permeability of the reservoir sandstones. Along with Taylor Sandstones, most of the upper Cotton Valley Sandstone 

interval produces gas at some fields, such as Carthage Field, according to Al Brake (BP Amoco engineer, personal 

communication, 2000). At other fields such as Woodlawn and Blocker, however, gas is produced only from lower 

Cotton Valley Taylor sandstones and from a few sandstones in the uppermost Cotton Valley section. Intervening 

middle- and upper-Cotton Valley sandstones are water-bearing. Presence of individual gas-bearing and water-bearing 

sandstone intervals separated by conventional shale seals suggests presence of gas-water contacts, and is more 

indicative of conventional-gas accumulations than of continuous-gas accumulations. 

Complex diagenetic mineralogy of tight Cotton Valley sandstones probably precludes use wireline logs to 

identify gas-water contacts. As reported above, complex diagenetic mineralogy of tight Cotton Valley sandstones 

dramatically affects values of resistivity and porosity measured by wireline logs, and hence determination of water 

saturation by standard calculation techniques. Because of vertical and lateral diagenetic variations, accurate 

determination of water saturation is difficult without accompanying lithologic data from cores or cuttings to calibrate 

wireline logs. Additionally, as described above, examination of production-test data from wells flanking many 

Cotton Valley gas fields in the tight-gas-sandstone trend reveals no dry holes that tested water only without gas. 

Therefore, even if wireline logs provided accurate estimates of water saturations in tight Cotton Valley sandstones, 

few wells apparently exist in which logs could be used to identify gas-water contacts. 

As described above, reconnaissance evaluation of DST and production-test data from Cotton Valley sandstones in 

a number of fields in the tight-gas sandstone trend revealed few dry holes penetrating Cotton Valley sandstones on 

flanks of those fields. No dry holes were found that tested water only without gas, thereby implying existence of a 

gas-water contact for a particular field. Detailed analysis of data on initial rates of gas and water production from Oak 

16

Hill and Elm-Grove/Caspiana Fields in the tight-gas-sandstone trend reveal no definitive understanding of presence or 

absence of gas-water contacts in these Cotton Valley fields. Initial rates of gas production from flank wells, however, 

generally are lower than from crestal wells in these tight-gas Cotton valley fields, as illustrated for Caspiana Field in 

figure 14. Also, as shown for Caspiana Field in figure 15, ratio of initial rate of water production to initial rate of 

gas production in terms of bbls wtr/MMCFG is significantly higher in flank wells. Initial rates of gas production 

from crestal wells commonly range from 1,000 to more than 4,000 MCFD and ratio of initial rate of water to gas 

generally is less than 200 bbls wtr/MMCFG and often below 100 bbls wtr/MMCFG (figs 14 and 15). Initial rates of 

gas production from flank wells generally are less than 1,000 MCFD, and water production initially is significantly 

higher, usually in the 300 to 600 bbls wtr/MMCFG range, but sometimes exceeding 1,000 bbls wtr/MMCFG (figs. 

14 and 15). These data suggest a decrease in gas saturation and accompanying increase in water saturation in Cotton 

valley sandstones from crestal wells to flank wells, and that a commercial limit to gas production has been reached, 

although gas-water contacts have not been encountered. 

Information suggesting that commercial limits generally have been established and that these tight-gas-sandstone 

Cotton Valley fields have gas-water contacts is provided by former BP Amoco geologist Al Taylor, who worked the 

Cotton Valley trend for BP Amoco and continues to prospect in that trend as an independent geologist. According to 

Al Taylor (personal communication, 2000), Cotton Valley fields in the tight-gas-sandstone trend have vertically 

extensive gas-water transition zones situated between structurally high regions of fields, where gas saturations are 

high, and gas-water contacts below. His interpretation is consistent with that reported by Nangle and others (1982), 

and with patterns observed at Caspiana Field, as shown in figures 14 and 15. In moving structurally lower through 

such a long gas-water transition zone toward the gas-water contact, gas saturation of sandstone reservoirs continually 

decreases while water saturation simultaneously increases. Wells that are low in the transition zone on the edges of 

Cotton Valley fields in the tight-gas sandstone trend exhibit low initial rates of gas production and high initial rates 

of water production, as shown by some flank wells at Caspiana Field in figures 14 and 15. Hyperbolic decline rates 

in conjunction with lower gas saturations of reservoir sandstones in these transition-zone wells result in such low 

cumulative production of gas that these wells are marginally commercial to non-commercial, and in effect are dry 

holes (Al Taylor, personal communication, 2000). Hence, commercial limits of gas production are reached before 

gas-water contacts are encountered by development drilling. To help illustrate this, it might be instructive to map 

cumulative gas production for wells in these Cotton Valley fields in addition to initial rates of gas and water 

production. 

Knowing gas saturations of Cotton Valley reservoir sandstones from log calculations and capillary properties of 

those sandstones from core analyses at Caspiana Field in northwest Louisiana, Al Taylor (personal communication, 

2000) estimated gas-column heights required to produce those gas saturations. From column-height data, he 

determined the subsea position of gas-water contacts. Estimates made in this fashion for structural level of the gaswater 

contact at Caspiana Field using data from a number of wells cluster within a zone about 75 feet thick, 

suggesting presence of a single gas-water contact for the field. A Cotton Valley well situated structurally below this 

estimated gas-water contact reportedly tested water only from Cotton Valley sandstones (Al Taylor, personal 

communication, 2000). 

Physical principles governing effects of porosity and permeability on capillary forces, and hence on thickness of 

transition zones in sandstones with different reservoir properties, are well understood. Arps (1964) diagrammatically 

showed a simple physics experiment in which glass tubes of different diameters are partially immersed in a container 

filled with water. As shown in Figure 16 the height to which water rises in the tubes is a function of diameter of the 

tubes. Water rises to the highest level in the tube with the smallest diameter in response to capillary forces. The 

same principle operates in reservoir sandstones in a geological structure, as depicted on the left side in Figure 16. In 

fine-grained, clay-rich, tight sandstones, where pore throats are small, water tends to rise higher above the free-water 

level than it does in cleaner, coarser-grained sandstones with higher porosity and permeability. Effect of different 

porosity and permeability on capillary-pressure forces also is illustrated by capillary-pressure curves shown on the 

graph on the right side of Figure 16. “Low”, “medium”, and “high” on the curves indicate relative magnitude of 

porosity and permeability of three hypothetical reservoir sandstones. The sandstone with lowest porosity and 

permeability clearly displays a considerably thicker transition zone than the sandstone with best reservoir properties. 

As Arps (1964) concluded from his discussion of Figure 16, the minimum vertical closure necessary to achieve 

water-free gas production is a function of porosity and permeability of a reservoir sandstone. As shown in the graph 

17

on the right side of Figure 16, minimum structural closure necessary to obtain water-free production of gas must 

exceed the vertical height required to be below the critical water saturation. Because such long gas-water transition 

zones are present in tight Cotton valley sandstones, Al Taylor (personal communication, 2000), suggests that 

structural or stratigraphic traps with less than 150 feet of vertical closure in the tight Cotton Valley trend will not 

have sufficient gas saturation to produce gas at commercial rates. 

In summary, Cotton Valley blanket sandstones across northernmost Louisiana have sufficiently high porosity 

and permeability that gas accumulations exhibit short transition zones and have sharp gas-water contacts. Gas fields 

in this trend have clearly defined productive limits, beyond which, wells produce water only. However, lowpermeability 

Cotton Valley sandstones in the tight-gas-sandstone trend across north Louisiana, the Sabine Uplift, 

and East Texas Basin, display long gas-water transition zones with poorly defined gas-water contacts. Productive 

limits of fields in this trend are difficult to define based on data from production tests or wireline logs. In conjunction 

with long gas-water transition zones, structural dips are gentle on the flanks of these gas accumulations. As 

development drilling progresses down the flank of one of these fields through the long gas-water transition zone, gas 

saturations in the sandstone reservoir decrease and water saturations increase. Eventually gas saturations become 

sufficiently low that, in terms of cumulative gas production, wells become marginally commercial to noncommercial 

at a structural position still within the transition zone above the gas-water contact. Hence, development 

wells on the flanks of these gas accumulations rarely encounter gas-water contacts. If drilling and completion costs 

hypothetically were reduced to zero, causing even the smallest amount of gas recovery to be commercial, 

development drilling probably would progress down the full length of transition zones, and gas-water contacts would 

be encountered in these gas accumulations. Presence of gas-water contacts in both Cotton Valley blanket- and 

massive-sandstone trends suggests that gas accumulations in these trends are conventional, and that a basin-center gas 

accumulation does not exist within Cotton Valley sandstones in the northern Gulf of Mexico Basin. 

Basin-Center Gas Potential within Bossier Shale 

As mentioned above in the section on Cotton Valley Stratigraphic Nomenclature, a basin-center, continuous-gas 

accumulation might have been discovered recently in sandstones within the Bossier Shale, the lower formation of the 

Cotton Valley Group. In a currently developing play on the western flank of East Texas Basin, gas is being produced 

from turbidite sandstones within the Bossier Shale. These turbidite sandstones probably are downdip time-equivalent 

deposits of deltaic sandstones in the lower portion of the Cotton Valley Sandstone and reportedly were deposited 

seaward of the underlying Haynesville carbonate platform edge in a slope or lowstand-fan setting. Accommodation 

space was provided by salt withdrawal such that updip and lateral traps currently are formed by pinchout of sandstone 

into shale. Two stacked, stratigraphically separate Bossier turbidite-fan systems occur at depths of 13,000 to 14,000 

feet. Two fields, Dew and Mimms Creek, with combined estimated recoverable reserves of more than one TCFG, 

currently are being developed by Anadarko Petroleum, one of the main operators. As of January 2000 (PI-Dwights 

Drilling Wire, Jan 3, 2000; Jan 12, 2000), Anadarko had drilled more than 100 wells with only one dry hole in this 

Bossier sandstone play. Gas-charged sandstones reportedly are overpressured, and no water has been encountered in the 

system (Exploration Business Journal, 2 nd quarter, 2000). Within the upper turbidite-fan interval, porosity ranges 

from 6 to 15 percent and permeability from 0.01 to 1.0 mD. Initial production rates from wells average 3 to 4 

MMCFGD after fracture stimulation and decline exponentially with estimated per-well recoveries of 1 to 5 BCFG. In 

the lower sandstone interval, porosity ranges from 9 to 20 percent, permeability from 1 to 10 md, pressures are 

higher, and initial production rates of up to 30 MMCFGD have been obtained. This play does not seem to involve 

the classic type of basin-center gas accumulation with trap produced by inherent low-permeability of reservoir 

sandstones. Instead, the trap seems to be provided by marine shales that completely encase these turbidite sandstones, 

but the sandstone reservoirs are overpressured, seem to lack water and gas-water contacts, and are gas-charged over an 

extensive area as witness by only one dry hole in more than 100 wells drilled. 

18

CONCLUSIONS 

19 

1) Cotton Valley Sandstone and underlying Bossier Shale represent the first major influx of clastic sediment 

into the Gulf of Mexico Basin. Major depocenters were located in south-central Mississippi, along the 

Louisiana-Mississippi border, and in northeast Texas. Sands supplied by the ancestral Mississippi drainage 

along the Louisiana-Mississippi border were swept westward by longshore currents, creating an east-west 

barrier-island or strandplain system across north Louisiana that isolated a lagoon to the north. More than 

1,000 feet of stacked barrier-island sands accumulated as the Terryville Massive-Sandstone complex. 

Periodic transgressive events reworked barrier-island sands, transporting them northward into the lagoon. 

These transgressive sandstones pinch out into lagoonal shales, can be correlated across north Louisiana, and 

are referred to informally as blanket sandstones. 

2) Two major trends of Cotton Valley sandstones are identified based on reservoir properties and associated 

characteristics of gas production. Transgressive, blanket sandstones across northernmost Louisiana have 

porosities ranging from 10 to 19 percent and permeabilities from 1 to 280 mD. These sandstones flow gas 

and/or liquids during open-hole DSTs, and do not require fracture-stimulation treatment to produce gas at 

commercial rates. Fields producing from these sandstone reservoirs were developed during the 1940s through 

1960s. Cotton Valley massive sandstones to the south and extending westward across the Sabine Uplift into 

east Texas exhibit porosities from 6 to 10 percent and permeabilities generally less than 0.1 mD. 

Designated as tight-gas sandstones, these reservoirs commonly do not flow gas or liquids during DSTs, and 

they require fracture-stimulation treatments to achieve commercial rates of production. Gas production from 

these sandstones in east Texas and north Louisiana was not established until the mid 1970s when advances 

in massive-hydraulic-fracture techniques occurred in conjunction with a significant increase in gas prices as a 

result of price deregulation. 

3) Porosity and permeability of Cotton Valley sandstones are controlled by diagenetic properties, which in turn 

are governed by depositional environment. Although diagenetic mineralogy and patterns are complex, highenergy, 

clean sandstones generally are cemented by authigenic quartz and/or calcite and have poor reservoir 

properties. In lower energy sandstones, clay coats on quartz grains inhibited development of quartz 

overgrowths, resulting in preservation of primary porosity. High clay content, however, generally imparts 

poor permeability to these sandstones. Best reservoir sandstones are those which have experienced 

development of significant secondary porosity from dissolution of calcite cement and unstable framework 

grains. 

4) Complex diagenetic mineralogy of tight Cotton Valley sandstones prohibits use of standard calculation 

methods in reservoir evaluation with wireline logs. Bound water associated with pore-filling clays or clay 

coats and conductive minerals such as pyrite result in abnormally low resistivity measurements leading to 

such high calculated water saturations that productive zones often appear wet. Also resulting in erroneous 

reservoir evaluations are pessimistic measurements of porosity with wireline logs caused by presence of 

high-density carbonate minerals such as ankerite and siderite. Therefore, without lithologic data from cores 

or drill cuttings to calibrate wireline logs, such logs are of limited value in differentiating between gasproductive 

and wet intervals, and therefore in identifying gas-water contacts on the flanks of Cotton Valley 

fields. 

5) Abnormally high reservoir pressures with fluid-pressure gradients exceeding 0.55 psi/ft occur in Cotton 

Valley sandstones in northeast Louisiana. Boundary between the overpressured area on the east and normally 

pressured region to the west cuts across the permeable, blanket- and tight, massive-sandstone trends such 

that overpressures occur within both reservoir trends. Within the blanket-sandstone trend, where pressure 

data are more abundant, some Cotton Valley fields are overpressured whereas adjacent fields are normally 

pressured. Also, within certain fields, some of the stacked blanket sandstones are overpressured whereas 

others are normally pressured. Such compartmentalization of overpressured reservoirs in proximity to 

normally pressured ones, rather than development of overpressure on a regional scale, suggests that these 

blanket-sandstone fields are conventional-gas accumulations and not part of a basin-centered accumulation. 

Also, occurrence of normally pressured reservoirs across the majority of the tight, massive Cotton Valley

20 

sandstone trend is not indicative of presence of a basin-center, continuous-gas accumulation. Geographic 

distribution of overpressures in Cotton Valley sandstones suggests that overpressuring was caused by 

“inflation” of existing pressures in tightly sealed reservoirs by gases derived from emplacement of nearby 

Jackson (igneous) Dome. 

6) Gas found in Cotton Valley sandstone reservoirs is believed to be derived from interbedded Cotton Valley 

marine shales, underlying marine shales of the Bossier Formation, and/or stratigraphically lower, Jurassic 

Smackover laminated, lime mudstones. These source rocks are believed to have been buried to sufficient 

depths relative to regional geothermal gradient to have generated dry gas during the past 60 m.y. Timing of 

gas generation and migration is favorable because it postdates development of the Sabine Uplift, smaller 

structures on and flanking the Uplift, and salt structures in the East Texas and North Louisiana Salt Basins. 

Stratigraphic proximity of source rocks with Cotton Valley sandstone reservoirs and appropriate thermal 

maturity and time of generation and migration would be consistent with interpretation of a potential basincentered 

gas accumulation. 

7) Presence of a gas-water contact is perhaps the most definitive criterion suggesting that a gas accumulation 

is conventional rather than a “sweetspot” within a basin-center, continuous-gas accumulation. Within the 

Cotton Valley blanket-sandstone trend across northernmost Louisiana, short gas-water transition zones and 

well-defined gas-water contacts have been reported in seven gas fields. Relatively high porosity and 

permeability of blanket sandstones and associated high gas-production rates achieved without fracture 

stimulation throughout the trend suggest that all gas fields within the blanket-sandstone trend probably have 

well-defined gas-water contacts, and therefore that these gas accumulations are conventional. 

8) Within the tight, massive-sandstone trend, porosity and permeability are sufficiently low that gas-water 

transition zones are long and gas-water contacts poorly defined. Productive limits of these tight-gassandstone 

Cotton Valley fields are not defined by wells which encounter a gas-water contact or test water 

only without gas from a zone below a gas-water contact, as in the blanket-sandstone trend. With increasing 

depth through long gas-water transition zones, gas saturation in reservoir sandstones decreases and water 

saturation increases. Eventually gas saturations become sufficiently low that, in terms of cumulative gas 

production, wells become marginally commercial to non-commercial at a structural position still within the 

transition zone above the gas-water contact. Therefore, development wells on the flanks of gas 

accumulations in the tight, massive Cotton Valley sandstone trend rarely encounter gas-water contacts. If 

even the smallest amount of gas recovery were commercial, development drilling probably would progress 

down the full length of transition zones, and gas-water contacts would be encountered in these gas 

accumulations. Presence of gas-water contacts in gas accumulations within the tight, massive Cotton 

Valley sandstone trend suggests that accumulations in this trend, too, are conventional, and that a basincenter 

gas accumulation does not exist within the Cotton Valley Sandstone in the northern Gulf of Mexico 

Basin. 

9) A basin-center, continuous-gas accumulation might occur in turbidite sandstones within the Bossier Shale, 

the lower formation of the Cotton Valley Group. In a currently developing play on the western flank of 

East Texas Basin, gas production with estimated recoverable reserves exceeding one TCFG is being obtained 

from sandstone reservoirs, interpreted as slope or lowstand fan deposits, that are completely encased in 

marine shales. Reservoirs are significantly overpressured and no water has been encountered in the system. 

More than one hundred successful wells have been drilled with only one dry hole.


I thank Steve Condon, USGS geologist in Denver, for extracting Cotton Valley well and test data from the IHS 

Energy Group database and preparing them for analysis with ACRVIEW software at the USGS Denver facility. 

Laura Biewick, USGS Denver, and Steve Condon provided expert instruction and assistance in using ARCVIEW to 

evaluate Cotton Valley well and test data. Ted Dyman, Chris Schenk, and Laura Biewick, USGS Denver, provided 

background information on the 1995 USGS assessment of Cotton Valley gas resources. I also thank the staff at the 

USGS library in Denver, USGS geologist Ted Dyman, and Gregory J. Zerrahn and Joseph A. Lott, geologists with 

Palmer Petroleum, Shreveport, Louisiana, for prompt and thorough assistance in obtaining reports, maps, and 

literature, without which, this study could not have been accomplished. Finally, thanks go to Al Brake, BP Amoco 

engineer, and Al Taylor, former BP Amoco geologist, for providing invaluable information on characteristics of 

Cotton Valley tight-gas accumulations not available in published literature. 

21

REFERENCES 

Almon, W.R., 1979, A geologic appreciation of shaly sands: Society of Professional Well Log Analysts, 

Twentieth Annual Logging Symposium, p. WW 1-14. 

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HEADINGS & ABBREVIATIONS FOR TABLE 2: COTTON VALLEY FIELDS 

Field Name of field producing from Cotton Valley (CV) sandstone 

FERC “Tight” Did FERC designate the field “Tight-gas sand” for Cotton Valley? 

Trap Trapping mechanism for field. 

Struct = structural trap 

Strat = stratigraphic trap 

Comb = combination structural & stratigraphic trap 

A = anticline 

FA = faulted anticline 

FC = facies change (sandstone pinchout) 

N = structural nose 

Disc Date Discovery date of field 

CV Disc Date: ss Date of CV sandstone discovery and specific CV ss that was productive 

Depth CV perfs Depth in feet of CV perforations in discovery well for specific ss 

IP (CV) IP for specific CV ss 

GOR Gas:oil ratio 

Por Porosity (decimal) 

Perm Permeability (mD) 

BHT Bottom hole temp (º F) 

BHP Bottom hole pressure (psi) 

FPG Fluid-pressure gradient (psi/ft) 

Sw Water saturation (decimal) 

GWC Information about gas-water contact 

Drive Drive mechanism 

SG = solution gas 

PD = pressure depletion 

GC = Gas-cap expansion 

WD = water drive 

SGS Ref Report Shreveport Geological Society Reference Report (vol: page)

Table 1. Comparison of two productive trends of Cotton Valley sandstones in east Texas and north Louisiana. Data from Shreveport Geological Society (1946, 

1947, 1951, 1953, 1958, 1963, 1980, 1987), Collins (1980), Nangle et al. (1982), Finley (1984, 1986), Bebout et al. (1992), and Dutton et al. (1993). 

PARAMETER BLANKET SANDSTONE MASSIVE SANDSTONE 

Porosity 0.10 to 0.19 (Ave = 0.15) 0.06 to 0.10 

Permeability (mD) 1.0 to 280 (Ave = 110) 0.042 (E. TX) 0.015 (N. LA) 

Open-hole DST Wells flow gas and/or liquids Wells generally do not flow gas or liquids 

Stimulation treatment No treatment necessary for commercial production Massive-hydraulic fracturing required to achieve commercial 

production 

Initial flow rates (MCFD) 500 to 25,000 (Ave 5,000) Pre-stimulation: TSTM1 to 300 

Post-stimulation: 500 to 2,500 

Sw in productive zones < 0.40 Can be as high as 0.60 

Gas/water contacts Short, well-defined transition zones and gas-water contacts Long transition zones with poorly defined gas-water contacts 

Formation damage Possible Commonly severe 

1 TSTM = Too small to measure

Field FERC Trap Disc CV Disc Date: ss Depth CV perfs IP (CV) GOR Por Perm (mD) BHT BHP FPG Sw GWC Drive SGS Ref Rpt (vol:pge) 

"Tight" Date (feet) MCFD BOPD BCPD BWPD Ave Min Max (F) (psi) (psi/ft) 

Ada-Sibley Comb (FA, FC) 1936 1954: CV 9,900 I: 93; I: 189 

Athens Struct (FA) 1941 1948: Vaughn 8,500-8,544 10,500 254 41,338:1 II: 385; III-2: 41; IV: 197 

1949: "B" 8,464-8,494 12,000 156 76,923:1 

1950:Bodcaw 8,148-8,186 694 2 347,000:1 

1951: "D" 8,145-8,170 3,370 208 16,201:1 

Bayou Middlefork Struct (A) 1953: Bodcaw 7,764 191 210 00,909:1 

Bear Creek-Bryceland Struct (A) 1937 1966 CV 10,700 I:97; V: 114 

Beekman No Comb (N, FC) 1942 1942: Cv 3,700-3,711 1,500 35 28 42,800:1 II: 391 

Benton Struct (A) 1944 1944: "D" 8,001-8,040 3,280 164 20,000:1 0.18 136 190 3,765 0.47 0.17 GWC -7,818 II: 395; VII: 44 

1945: Bodcaw 8,137-8,148 1,306 127 10,286:1 0.14 85 190 3,725 0.44 OWC -7,876 

Blackburn Comb (N, FC) 1953 1953: Bodcaw 8,717 1,301 54 24,092:1 

E. Blackburn 1959 

Cadeville 1955 9,700 

Calhoun No Struct (FA) 1948 1948: "D" 9,500 814 22 37,000:1 0.17 4,000 0.47 SG,PD No SGS report 

Comb (FA, FC) 1957: Cadeville 9,121-9,124 4,779 1,148 4,162:1 0.15 2,132 8,201 0.86 0.05 SG,PD Pate & Goodwin, 1961 

Carlton Struct (A) 1953 1953: Bodcaw 

N. Carlton No Comb (A,FC) 1964: Purdy 8,950 No SGS report 

1965: CV ? 9,470 

Cartwright 1960 

Caspiana Comb (N, FC) 1975: Cotton Valley 8,500 

Cheniere No Comb (N, FC) 1962 1962: Cadeville 9,682-9,697 4,401 528 8,335:1 8,188 0.84 v: 120 

1963: CV "A" 9,603-9,609 1,230 8 153,750:1 

Choudrant Struct (A) 1946 1946: "D" 9,097--9129 4,732 211 21,000:1 0.19 250 Separate GWCs in 2 "D" ss II: 409; III-2: 55 

Clay Struct (A) 1952: CV 9,700 No SGS report 

Cotton Valley No Struct (A) 1922 1937: Bodcaw 8,170 TD (OH) 5,323 455 11,700:1 0.16 121 775 231 4,000 0.49 0.15 GWC @ -8,420 WD II:413; VI:63 

1937: Davis 8,521-8,551 (OH) 4,800 400 12,000:1 0.15 280 4,368 0.51 0.10 GC 

1938: "D" 8,502-8,532 1,020 1,200 00,850:1 0.18 150 3,926 0.43 

1949: Justiss 9,050 0.16 34 4,700 0.55 0.22 GC 

"C" 

Taylor 

D'Arbonne 1947 1947: Bodcaw 8,157 4,100 88 46,590:1 

Dixie 1929 

Downsville 1948 

S. Downsville No Struct (A) 1961 1961: Vaughn 8,900 No SGS report 

S. Drew Strat (FC) 1972 1972: "D" 9,061-9,069 2,560 85,000:1 0.12 20 200 4,850 0.53 0.40 3 GWCs in "D" ss GC VI: 116 

1976: Vaughn 9,525-9,531 873 15 58,200:1 0.10 8 200 4,250 0.45 0.40 GC 

Elm Grove Struct (FA) 1973 Cotton Valley 7,768 0.08 1 247 4,154 0.53 0.45 

Greenwood-Waskom No 1924 

Haynesville Struct (A) 1921 1944: Taylor 8,835-8,920 373 01068:1 3,870 0.43 I: 119; III-1, 18 

1945: Camp 7,980-8,004 264 00500:1 

E. Haynesville 1945 1949: Tucker 8,588-8,600 2,898 276 10,500:1 II: 435; III-2: 63 

Hico-Knowles No 

Hico Struct (FA) 1946 1946: Vaughn 8,525-8,556 8,240 121 68,100:1 0.17 3,686 0.42 Multiple GWCs PD I:125; III-2: 75 

1946: Bodcaw 8,287-8,345 892 41 21,649:1 0.18 4,061 0.47 PD 

1949: Feazel-McFearin 8,914-8,929 2,880 308 9,350:1 0.15 5,616 0.63 

Knowles Struct (A) 1945 1945: Vaughn 8,700-8,750 5,212 139 37,500:1 3,500 0.40 III-2: 82 

1946: Bodcaw 8,630-8,670 8,516 158 53,900:1 

1948: McCrary 8,912-8,924 6,762 761 8,886:1 

1953: Feasel-McFearin 8,996-9,008 7,000 275 25,450:1 

Homer 1919 

Ivan 1952 

Lake Bistineau 1916 

Leatherman Creek Struct (FA) 1975 1975: Cotton Valley 10,400-10,800 0.12 1 0.30 PD VI: 70 

Lisbon No Struct (FA) 1936 1939: Vaughn 8,444-8,464 5,000 61 82,000:1 0.17 150 0.35 PD I: 143 

1940: Burgess-Simmons 8,766-8,806 1,993 160 12,458:1 0.14 40 PD 

N. Lisbon Comb (N, FC) 1941 1942: Burgess-Simmons 8,502-8,525 510 17 30,000:1 I: 169 

1943: Bodcaw 7,790-7,816 19,000 0.17 196 

Longwood Strat (FC) 1927 1948: Bodcaw 8,350 

Minden 1957 

Monroe 1916 

W. Monroe 1957 

Plain Dealing 1946 

Rocky Mount 1959 

Ruston No Comb (A,FC) 1943 1948: "D" 8,796-8,806 6,500 56 24,000:1 0.18 100 210 4,100 0.47 0.23 GWC in Vaughn ss PD I: 185; III-2: 87; VI: 108 

1949: Bodcaw 8,707-8,730 4,263 195 21,860:1 0.19 150 PD 

1949: Vaughn 8,809-8,838 7,995 390 20,501:1 PD 

1949: "D" 8,674-8,706 8,250 PD

Field FERC Trap Disc CV Disc Date: ss Depth CV perfs IP (CV) GOR Por Perm (mD) BHT BHP FPG Sw GWC Drive SGS Ref Rpt (vol:pge) 

"Tight" Date (feet) MCFD BOPD BCPD BWPD Ave Min Max (F) (psi) (psi/ft) 

1949: Bodcaw 8,760-8,810 15,500 PD 

1951: Feazel (Davis) 9,468-9,476 1,062 50 21,240:1 0.18 80 PD 

S. Sarepta Comb (FA,FC) 1949 1949: Bodcaw 8,710 2,160 173 12,485:1 0.17 265 4300 0.49 0.14 PD 

1949: Savis 9,000 0.13 75 4,500 0.50 0.15 PD 

1949: Ardis 9,150 0.12 50 4,525 0.49 0.14 GC 

Sentell No Comb (N, FC) 1951 1951: Bodcaw 8,320 25,500 455 56,043:1 0.16 50 No SGS report 

Shongaloo 1921 

Sligo No 1922 I: 193 

Sugar Creek Struct (FA) 1930 1957: Bodcaw 8,724-8,730 5,000 210 23,810:1 3,972 0.45 I: 213; VI: 126 

1957: Vaughn 8,780-8,795 2,850 48.5 58,763:1 2,955 0.34 

1958: "D" 7,917-7,925 21,000 896 23,437:1 

1962: "D" 7,686-7,693 3,200 112 28,571:1 

1962: McFearin 8,003-8,008 2,800 168 17,500:1 

1979: Price 9,462-9,474 520 

Terryville No Comb (N, FC) 1954 1954: "D" 9,203-9,227 3,739 277 13,514:1 0.10 125 GWC in "D" ss WD V: 196 

1957: "C" 9,169-9,182 1,030 38 29 27,105:1 

1959: "C" 9,049-9,053 133 00,934:1 

1962: McGrary 9,354-9,362 4,000 300 13,333:1 

Tremont Comb (N, FC) 1944 1944: Bodcaw 9,060-9,080 2,235 97 23,000:1 4,200 0.46 I: 219; VI: 133 

1971: Davis 9,633-9,706 1,145 144 7,951:1 0.14 34 217 6,519 0.67 0.15 PD 

Unionville Strat (FC) 1950 1950: Vaughn 8,550 

1950: Davis 8,700 

Vernon Strat (FC) 1967: Cadeville 10,900

34° N 

32° N 

30° N 

28° N 

OKLAHOMA 

TEXAS 

96° W 94° W 92° W 90° W 88° W 

4922 

4924 

ARKANSAS 

LOUISIANA 

4923 

Gulf of Mexico 

MISSISSIPPI 

ALABAMA 

0 50 

Miles 

100 

Figure 1. Map of north-central Gulf Coast Basin from Schenk and others (1996) showing outlines of three Cotton Valley plays identified 

by U.S. Geological Survey in the 1995 National Assessment of United States Oil and Gas Resources. Shown are the Cotton Valley 

Blanket Sandstones Gas Play (4923), identified as a continuous-gas play, and the Cotton Valley Salt Basins Gas Play (4922) and 

Cotton Valley Sabine Uplift Gas Play (4924), identified as conventional-gas plays. 

FL

34° N 

32° N 

30° N 

APPROX UPDIP LIMIT 

OF COTTON VALLEY GROUP 

(SWAIN, 1944) 

96° W 94° W 92° W 90° W 

MEXIA-TALCO 

GINGER 

FAULT 

FAULT ZONE 

ZONE 

EAST 

TEXAS 

SALT 

BASIN 

MT ENTERPRISE 

APPROX DOWNDIP LIMIT 

OF COTTON VALLEY 

SANDSTONE 

FAULT ZONE 

SOUTH 

SABINE 

ARCH 

COMANCHEAN SHELF 

TEXAS 

ARKANSAS 

LOUISIANA 

(THOMAS & MANN, 1966) 

ARKANSAS 

LOUISIANA 

NORTH 

LOUISIANA 

SALT 

BASIN 

EDGE 

FAULT ZONE 

0 20 40 

MILES 

60 80 

GULF OF MEXICO 

MONROE 

UPLIFT 

PICKENS 

MISSISSIPPI 

SALT 

BASIN 

MISSISSIPPI 

LOUISIANA 

FAULT ZONE 

Figure 2. Index map of north-central Gulf Coast Basin, modified from Dutton and others (1993), showing major tectonic features. 

Sabine and Monroe Uplifts were not positive features during deposition of Cotton Valley Group sediments, and major Cotton 

Valley sands depocenters were located across the entire northern Gulf Basin from east Texas to Alabama. Salt movement in East 

Texas and North Louisiana Salt Basins was contemporaneous with deposition of Cotton Valley Group clastic sediments. Cotton 

Valley Group is an entirely subsurface sequence of strata with approximate updip limits shown here.

SYSTEM 

TERTIARY 

PALEOGENE 

UPPER CRETACEOUS 

LOWER CRETACEOUS 

JURASSIC 

TRIASSIC 

SERIES 

EOCENE 

PALEOGENE 

GULFIAN 

COMANCHEAN 

COAHUILAN 

UPPER 

MIDDLE 

LOWER 

UPPER 

CHRONOSTRATAGRAPHIC SECTION OF NORTH LOUISIANA 

STAGE GROUP FORMATION 

YPRESIAN 

THANETIAN 

DANIAN 

MAESTRICHTIAN 

CAMPANIAN 

SANTONIAN 

CONIACIAN 

TURONIAN 

CENOMANIAN 

ALBIAN 

APTIAN 

BARREMIAN 

HAUTERIVIAN 

VALANGINIAN 

BERRIASIAN 

TITHONIAN 

KIMMERIDGIAN 

OXFORDIAN 

CALLOVIAN 

BATHONIAN 

BAJOCIAN 

AALENIAN 

TOARCIAN 

PLIENSBACHIAN 

SINEMURIAN 

HETTANGIAN 

RHAETIAN 

WILCOX WILCOX 

MIDWAY MIDWAY 

NAVARRO 

TAYLOR 

AUSTIN 

EAGLE FORD 

WOODBINE 

WASHITA 

FREDRICKSBURG 

TRINITY 

COTTON VALLEY 

GLEN 

ROSE 

HIATUS 

HIATUS 

HIATUS 

ARKADELPHIA 

NACATOCH 

SARATOGA 

ANNONA 

OZAN 

TOKIO 

AUSTIN 

EAGLE FORD 

BOSSIER 

AGE 

(MA) 

TUSCALOOSA 

100 

PALUXY 

WASHITA-FREDERICKSBURG 

MOORINGSPORT 

FERRY LAKE ANHYDRITE 

RODESSA 

JAMES 

PINE ISLAND 

PETTET (SLIGO) MBR 

SLIGO 

HOSSTON 

(TRAVIS PEAK) 

SCHULER 

HAYNESVILLE-BUCKNER 

SMACKOVER 

NORPHLET 

LOUANN 

WERNER 

EAGLE MILLS 

Figure 3. Chronostratigraphic section of north Louisiana from Shreveport Geological Society (1987) 

showing Cotton Valley Group comprised of Bossier and Schuler Formations. Schuler Formation 

was assigned to Lower Cretaceous in mid 1980s. Prior to that time, entire Cotton Valley Group 

was considered to be Upper Jurassic in age. 

60 

70 

80 

90 

110 

120 

130 

140 

150 

160 

170 

180 

190 

200 

210 

MILLIONS OF YEARS

DALLAS 

ELLIS 

COLLIN 

ROCK- 

WALL 

OKLAHOMA 

KAUFMAN 

NAVARRO 

LIMESTONE 

FANNIN 

HUNT 

FREESTONE 

DELTA 

RAINS 

VAN ZANDT 

HENDERSON 

LAMAR 

HOPKINS 

ANDERSON 

WOOD 

FALLS LEON 

ANGELINA 

MILAM 

-5000 

-10,000 

ROBERTSON 

-11,000 

BRAZOS 

-4000 

-12,000 

-5000 

-6000 

-7000 

-9000 

MADISON 

-13,000 

-10,000 

-8000 

-8000 

HOUSTON 

FRANKLIN 

SMITH 

CHEROKEE 

TRINITY 

RED RIVER 

TITUS 

CAMP 

UPSHUR 

MORRIS 

GREGG 

-9000 

RUSK 

NACODOCHES 

-11,000 

-12,000 

-13,000 

BOWIE 

CASS 

MARION 

HARRISON 

PANOLA 

-8000 

SHELBY 

-10,000 

SAN 

AGUSTINE 

0 10 20 30 40 50 

Miles 

Contour Interval: 1000 feet 

-6000 

BOSSIER 

CADDO 

DE SOTO 

SABINE 

SABINE 

WEBSTER 

RED RIVER 

ARKANSAS 

BIENVILLE 

NATCHITOCHES 

VERNON 

CLAIBORNE 

TEXAS LA 

LINCOLN 

JACKSON 

WINN 

GRANT 

UNION 

RAPIDES 

OUACHITA 

CALDWELL 

LA SALLE 

MOREHOUSE 

RICHLAND 

FRANKLIN 

CATAHOULA 

CONCORDIA 

MADISON 

TENSAS 

MISSISSIPPI 

Figure 4. Generalized structure contours on top of Cotton Valley Sandstone across northeast Texas and north Louisiana, modified from 

Finley (1984). Cotton Valley Sandstone has been designated as “tight-gas sandstone” in all counties shown on this map with 

exception of 15 gas fields in north Louisiana (see Figure 8). 

-7000 

-11,000 

-14,000 

-15,000 

-11,000 

-12,000 

-13,000 

-10,000 

-9000 

-7000 

-8000 

-5000 

-6000 

-4000

CRETACEOUS 

JURASSIC 

COTTON VALLEY GROUP 

(SOUTH) (NORTH) 

WINN LS 

DOWNDIP 

CALVIN 

MASSIVE 

SAND COMPLEX 

UNNAMED SANDS & SHALES 

KNOWLES LIMESTONE 

BLANKET 

SANDSTONES 

TERRYVILLE 

MASSIVE 

SAND COMPLEX 

BOSSIER SHALE 

HICO 

SHALE 

UPDIP 

HOSSTON FORMATION 

SCHULER FM 


SMACKOVER 

Figure 5. Generalized stratigraphic nomenclature of Cotton Valley Group in northern Louisiana, 

modified from Coleman and Coleman (1981).

A 

SOUTH 

1 

WINN LIMESTONE 

2 3 4 5 6 7 8 9 

CALVIN 

SANDSTONE 

KNOWLES LIMESTONE 

TERRYVILLE 

Figure 6a. North-south stratigraphic cross section of Cotton Valley Group across northern Louisiana 

based on data from 15 wells. Section is modified from Coleman and Coleman (1981) to show 

details of Cotton Valley blanket sandstones as identified and described by Eversull (1985) and 

Thomas and Mann (1963). Line of cross section shown in Figures 7 and 8.

10 

IV 

11 

MASSIVE 

BOSSIER SHALE 

12 

Cadeville 

B C 

D 

III 

(Barrier Islands 

offshore bars) 

HOSSTON 

13 

Bodcaw 

Vaughn Price 

McGreary 

Bolinger 

II 

SANDSTONES 

I 

Davis 

E 

Justiss 

Ardis 

(Lagoon/bay) 

Roseberry? 

14 

HICO SHALE 

SCHULER FORMATION 

(Alluvial, coastal plain, 

fluvial deltaic 

10 5 0 

Miles 

A' 

NORTH 

15 

Feet 

1000 

Figure 6b. North-south stratigraphic cross section of Cotton Valley Group across northern Louisiana based 

on data from 15 wells. Section is modified from Coleman and Coleman (1981) to show details of 

Cotton Valley blanket sandstones as identified and described by Eversull (1985) and Thomas and 

Mann (1963). Line of cross section shown in Figures 7 and 8. 

Sexton 

Taylor 

Tucker 

500 

0

OKLAHOMA 

TEXAS 

LONE OAK DELTA 

COTTON VALLEY 

DEPOCENTER 

MAXIMUM 

0 25 50 

Miles 

75 100 

UPPER COTTON VALLEY PALEOGEOGRAPHY 

TEXAS 

SOUTHERN EXTENT 

HICO LAGOON 

BARRIER ISLAND 

OF 

LOUISIANA 

8 

9 

TERRYVILLE 

A' 15 

7 

4 

3 

2 

1 

14 

13 

12 

11 

10 

A 

OK 

NM 

DETAIL 

AREA 

TX 

5 6 

AR 

LA 

AL 


LOCATION MAP 

ARKANSAS 

LOUISIANA 

MASSIVE SANDSTONES 

MS 

TN 

MISSISSIPPI 

LOUISIANA 

ANCESTRAL MISSISSIPPI 

RIVER COTTON VALLEY 

DEPOCENTER 

BAY/LAGOON 

BARRIER ISLAND 

Figure 7. Regional paleogeographic map showing sedimentary environments of Cotton Valley Group during deposition of uppermost 

Cotton Valley sandstones (Terryville IV sandstone of Coleman and Coleman, 1981). Map synthesized from data of Thomas and 

Mann (1966), Coleman and Coleman (1981), Moore (1983), McGowen and Harris (1984), Wescott (1985), and Eversull (1985).

OK 

Detail 

Area 

AR 

TX LA 

EAST 

TEXAS 

SALT 

BASIN 

MS 


LOCATION MAP 

AL 

Oak Hill 

Dirgin 

Woodlawn 

Blocker 

Carthage 

TEXAS 

Longwood 

Greenwood- 

Waskom 

Bethany- 

Plain 

Dealing 

S Sarepeta 

Rocky 

Mount 

Ivan 

Dixie 

Longstreet 

Benton 

Sentell 

Sligo 

Caspiana 

SABINE UPLIFT 

Shongaloo 

Cotton 

Valley 

Elm Grove 

E Haynesville 

Haynesville 

Minden 

Leatherman 

Creek 

Sibley 

Lake 

Bistineau 

NORTH 

A' 15 

Blackburn 

W Lisbon 

14 NE Lisbon 

Hico Knowes 

Homer 

13 

Lisbon 

Athens 

12 

Sugar 

Creek 

Rustin 

Ada 

Terryville 

10 

11 

Calhoun 

Bryceland 

9 

Clay Tremont 

8 Bear 

Creek 

Vernon 

7 

A 

3 

1 

2 

4 

Cotton Valley sandstone field 

(designated tight gas by FERC, 1980) 


(excluded from 1980 FERC tight-gas designation) 

Cotton Valley tight, massive sandstone trend 

(low porosity & permeability, frac required) 

Cotton Valley blanket-sandstone trend 

(good porosity & permeability, no frac required) 

East Texas & Louisiana Salt Basins 

5 

ARKANSAS 

LOUISIANA 

Unionville 

D'Arbonne 

Choudrant 

Downsville 

6 

S Downsville 

N Carlton 

Carlton 

S Drew 

Cheniere 

Cadeville 

LOUSIANA 

SALT BASIN 

Beekman 

0 25 

Miles 

50 

Figure 8. Map of northeast Texas and northwest Louisiana showing major fields that have produced hydrocarbons from Cotton Valley 

sandstones. Two different productive trends are recognized based on reservoir properties and resulting producing capabilities of 

Cotton Valley sandstone reservoirs. Fifteen fields excluded from “tight-gas” designation by FERC in 1980 are shown in solid color. 

Map modified from Collins (1980) and White and others (1992b).

OK 

Dallas 

TX 

AR 

DETAIL 

AREA 

CALHOUN 

0.86 

0.47 

LA 

MS 

AL 


LOCATION MAP 

OAK HILL 

0.32 

CARTHAGE 

0.55 

TEXAS 

LOUISIANA 

0.51 

LEGEND 


BENTON 

0.47 

0.44 

BETHANY EAST 

Fluid-pressure gradient (psi/ft) for 

different Cotton Valley sandstones 

FLUID-PRESSURE GRADIENTS (PSI/FT) 

COTTON VALLEY SANDSTONES 

HAYNESVILLE 

S SAREPETA 0.43 

0.50 

0.49 

0.49 

COTTON VALLEY 

0.55 

0.51 

0.49 

0.43 

ELM GROVE 

0.53 

SUGAR CREEK 

0.45 

0.34 

HICO KNOWLES 

0.63 

0.47 

ARKANSAS 

LOUISIANA 

0.42 RUSTON 

0.47 

CALHOUN 

0.86 

0.47 

CHENIERE 

0.84 

TREMONT 

0.67 

0.46 

S DREW 

0.53 

0.45 

0 25 

Miles 

50 

Figure 9. Map of northeast Texas and northwest Louisiana showing fluid-pressure gradients calculated from shut-in pressures in Cotton 

Valley sandstone reservoirs. Multiple pressure-gradient values for a particular gas field refer to gradients calculated for different, 

stacked blanket-sandstone reservoirs penetrated in that field. Shut-in-pressure data for Louisiana fields shown in Table 2. 

LOUISIANA 

MISSISSIPPI

OK AR 

Dallas 

TX 

DETAIL 

AREA 

LA 

MS 


LOCATION MAP 

AL 

TEXAS 

LOUISIANA 

DISTRIBUTION OF RESERVOIR PRESSURES 

COTTON VALLEY SANDSTONES 

NORMALLY 

ARKANSAS 

LOUISIANA 

PRESSURIZED 

OVER PRESSURIZED 

0 25 

Miles 

50 

Figure 10. Map of northeast Texas and northwest Louisiana modified from Coleman and Coleman (1981) showing geographic 

distribution of abnormally high pressures in Cotton Valley sandstone reservoirs. Dashed line shows modification of Coleman and 

Coleman’s (1981) pressure boundary to include the 0.63 psi/ft fluid-pressure gradient in Hico-Knowles Field and 0.67 psi/ft gradient 

in Tremont Field as shown in Figure 9 and documented in table 2. Comparison of this map with map in figure 8 shows boundary 

between overpressure and normal pressure cuts across two productive trends of Cotton Valley sandstones. 

LOUISIANA 

MISSISSIPPI

OK AR 

Dallas 

TX 

Porosity 

DETAIL 

AREA 

LA 

MS 


LOCATION MAP 

TREMONT 

0.14 34 

AL 

LEGEND 

TEXAS 

LOUISIANA 

Cotton Valley 

Sandstone field 

Permeability 

S SAREPETA 

0.17 

0.13 

0.12 

265 

75 

50 

POROSITY AND PERMEABILITY 

COTTON VALLEY BLANKET SANDSTONES 

ARKANSAS 

LOUISIANA 

LISBON 

0.17 150 

0.14 40 

NE LISBON 

0.17 196 HICO KNOWLES 

0.18 

0.17 

0.15 

BENTON 

COTTON VALLEY 

0.18 135 0.15 280 

0.14 85 0.18 150 

LEATHERMAN 

0.16 121 CREEK RUSTON 

0.16 34 0.12 1 0.19150 

TERRYVILLE 0.18100 

0.10 125 0.18 80 

CHOUDRANT 

0.19 250 

TREMONT 

0.14 34 

S DREW 

CALHOUN 

0.12 20 

0.17 

0.10 8 

0.15 

0 25 

Miles 

50 

Figure 11. Map of northeast Texas and northwest Louisiana showing measured values of porosity and permeability in Cotton Valley 

blanket sandstones. Porosity and permeability data documented in table 2. Multiple values of porosity and permeability for a given 

field represent measured values for separate, stacked blanket sandstone reservoirs in that field. 

LOUISIANA 

MISSISSIPPI

OK AR 

Dallas 

TX 

BENTON 

3,280 

1,306 

DETAIL 

AREA 

LA 

MS 


LOCATION MAP 

AL 

TEXAS 

LOUISIANA 

LEGEND 

Cotton Valley Sandstone field 

S SAREPETA 

2,160 

BENTON 

3,280 

1,306 

SENTELL 

25,500 

Initial rates of gas production (MCFD) from different 

Cotton Valley sandstones without fracture stimulation 

INITIAL RATES OF GAS PRODUCTION 

COTTON VALLEY BLANKET SANDSTONES 

COTTON 

VALLEY 

5,323 

4,900 

1,020 

HICO KNOWLES 

NE LISBON 8,516 

19,000 7,000 

E HAYNESVILLE 

2,898 510 6,762 

5,212 

2,880 

BLACKBURN 

1,301 

LISBON 

5,000 

1,993 

ATHENS 

12,000 

10,500 

3,370 

694 

ARKANSAS 

LOUISIANA 

RUSTON 

15,500 

8,250 

7,995 

6,500 

CHOUDRANT 

4,732 

4,263 

1,062 

SUGAR 

S DREW 

CREEK 

TERRYVILLE 

2,650 

21,000 

CHENIERE 

4,000 

873 

CALHOUN 

5,000 

4,401 

3,739 4,779 

3,200 

1,230 

1,030 814 

2,850 

TREMONT 

2,800 

2,235 

520 

1,145 

0 25 

Miles 

50 

Figure 12. Map of northeast Texas and northwest Louisiana showing initial rates of gas production from Cotton Valley blanket 

sandstones. Multiple values of initial flow rates for a given field represent rates from different stacked blanket sandstone reservoirs 

which produce in that field. All rates are from blanket sandstones, which do not require fracture-stimulation treatment for 

commercial production. 

LOUISIANA 

MISSISSIPPI

OK AR 

Dallas 

TX 

DETAIL 

AREA 

LA 

MS 


LOCATION MAP 

AL 

TEXAS 

LOUISIANA 

BENTON 

KNOWN FIELDS WITH GAS-WATER CONTACTS 

IN COTTON VALLEY SANDSTONES 

COTTON 

VALLEY 

ARKANSAS 

LOUISIANA 

HICO 

KNOWLES 

TERRYVILLE RUSTON 

CHOUDRANT 

S DREW 

0 25 

Miles 

50 

Figure 13. Map of northeast Texas and northwest Louisiana showing fields productive from Cotton Valley sandstones in which gaswater 

contacts have been identified and reported in public literature. Presence of gas-water contacts in these fields suggests they are 

conventional-gas accumulations. Details on gas-water contacts including sources of information are shown inTable 2. 

LOUISIANA 

MISSISSIPPI

325 

500 

785 

150 

860 

900 

800 

700 

1000 

605 

1450 

1 unit gas 

1454 

1410 

2000 

1850 

1170 

2061 

1350 

1020 

2014 

2108 

3230 

264 

666 

R 13 W R 12 W 

980 

1081 

583 

3100 730 

400 

905 

938 

1736 

1250 548 

2500 1250 

1512 1908 

4850 2883 1750 1832 

1 

1304 

1464 

561 

1200 

1439 

1250 

1800 

1000 

900 

1300 

2618 

2723 

2232 

2110 

1150 

980 

2041 

1591 

1776 

1800 

2100 

1687 1725 

2667 

2376 

2500 

2900 

2022 

1000 

1000 

2000 

2000 

3000 

4000 

3000 

1000 

2000 

2000 

1000 

950 

2100 

250 

762 

1500 

3050 

200 

956 

1035 

1400 

2256 

2450 

1592 

1587 

185 

200 

1500 

1700 

1117 

1200 

2006 

TD Cotton Valley 

No Cotton Valley tests 

482 

2006 

925 

927 

T 15 N 

T 14 N 

EXPLANATION 

Hosston producer 

(TD in Cotton Valley) 

LOUISIANA 

Map 

Area 

LOCATION MAP 

Figure 14. Map of Caspiana Field in northwest Louisiana in the tight, massive Cotton Valley sandstone trend showing initial rate of gas 

production (MCFD) from Cotton Valley sandstone reservoirs. Data from database of IHS Energy Group (petroROM Version 3.43). 

Contour interval is 1,000 MCFD. Map shows general decrease in initial rates of gas production from center to flank of fields. 

2000 

1000 

2000 

2000 

3000 

1000 

1000 

1000 

2000

1477 

1000 

600 

432 

500 

549 

800 

178,000 

600 

500 

378 

400 

300 

700 

344 

200 

241 

600 

500 

300 

400 

600 

500 

363 240 244 

694 

238 

800 400 

500 

377 

334 

368 

36 units wtr 

1 unit gas 

549 

398 

443 

627 

400 

300 

200 

270 144 

100 

33 

207 

18 71 

303 

424 

270 

470 

? 

267 

385 

95 

? 

38 

73 

? 

172 

114 

334 

? 

187 

199 

255 

? 

300 

R 13 W R 12 W 

200 

? 

200 

? 

500 

609 

73 

200 

214 

223 

114 

200 

177 

600 400 

290 

229 

293 

74 

138 

162 217 

? 

400 

300 

285 

278 

205 

75 

236 

286 

? 

160 

200 

300 

500 

100 

200 

? 

600 

695 

? 

500 

105 

571 

188 

155 

72 

? 

100 

200 

300 

400 

? 

367 205 

483 

100 

? 

350 

260 

300 

300 

400 

400 

300 

200 

100 

83 

25 

201 

200 

100 

? 

? 

? 

T 15 N 

T 14 N 

EXPLANATION 

? No data for water 

production 

Hosston producer 

(TD in Cotton Valley) 

Map 

Area 

LOUISANA 

LOCATION MAP 

Figure 15. Diagram, modified from Arps (1964), showing effect of porosity and permeability in a hydrocarbon reservoir on thickness of 

hydrocarbon-water transition zone and on minimum closure required for water-free hydrocarbon production.

MINIMUM 

CLOSURE 

MEDIUM PERMEABILITY & POROSITY 

WATER-FREE 

GAS PRODUCTION 

PRODUCTION OF GAS 

AND WATER 

WATER PRODUCTION 

REQUIRED MINIMUM CLOSURE REQUIRED FOR 

FREE WATER SURFACE 

SPILL 

POINT 

EFFECT OF PERMEABILITY ON 

THICKNESS OF 

GAS-WATER TRANSITION ZONE 

HIGH MEDIUM LOW 

WETTING PHASE (WATER) 

CAPILLARY PRESSURE (Pc) 

OR HEIGHT (FEET) 

CAPILLARY 

PRESSURE CURVES 

CRITICAL 

WATER 

SATURATION 

MEDIUM 

HIGH 

LOW 

0 45 100 

INTERSITIAL 

WATER SATURATION (S w ) 

MINIMUM 

CLOSURE 

REQUIRED


IN THE ORDOVICIAN-AGE GLENWOOD FORMATION AND ST. PETER 

SANDSTONE, CENTRAL MICHIGAN BASIN ? 

ABSTRACT 


Well data, structure maps, previous studies of abnormal pressures and thermal maturity, and published 

descriptions of gas fields were evaluated to determine if a basin-center gas accumulation might exist within 

the Ordovician-age Glenwood Formation and St. Peter Sandstone in the Michigan basin. The Glenwood-St. 

Peter section has several characteristics of typical basin-center gas accumulations, including thermally 

mature source rocks, low porosity sandstone reservoirs, extensive overpressure and extensive gas dry gas and 

condensate production. 

Well histories and data from more than 100 drill-stem tests reveal that many wells recovered significant 

volumes of salt water or gassy salt water with high chloride content (230,000 – 270,000 ppm Cl - ) from the 

Glenwood-St. Peter interval. Pressure gradients range from 0.4 to 0.56 psi/ft, indicating normal pressures to 

moderate overpressures. Core descriptions indicate fair porosity (4 to 13%, average 9%) within the St. Peter 

Sandstone. Permeabilities vary widely, ranging from


The Michigan basin (fig. 1) is a circular-shaped cratonic depocenter (fig. 2) containing sedimentary 

rocks of Pre-Cambrian through Jurassic age and a thin covering of Quaternary glacial deposits (Wollensak, 

1991; Catacosinos and Daniels, 1991). The basin contains numerous subtle anticlinal structures, but lacks 

major transverse fault zones or tectonic partitions. Thermally mature source rocks with measured vitrinite 

reflectance greater than 1 %Ro are present in the central part of the basin (Cercone and Pollack, 1991; 

Moyer, 1982; Fisher and Barratt, 1985; Wang et al., 1994). Oil, condensate and natural gas have been 

discovered in many different stratigraphic intervals (Wollensak, 1991). 

STRATIGRAPHY: GLENWOOD FORMATION AND ST. PETER SANDSTONE 

The Middle Ordovician-age Glenwood Formation and St. Peter Sandstone (fig. 3) are economically 

important reservoirs for natural gas and condensate. The term “St. Peter Sandstone” is used here to include 

the thick sandstone section below the Glenwood Formation and above the Brazos Shale and Foster 

Formation, which are members of the Prairie Du Chien Group. It includes previous oil field names such as 

the Massive Sandstone, Jordan Sandstone, Bruggers Formation, and Prairie Du Chien Formation. Previous 

disagreements about the pre-Glenwood stratigraphic nomenclature have been discussed at length by Barnes 

and others (1992) and Nadon and others (2000). 

The St. Peter Sandstone ranges from less than 100 ft thick along the basin margins (fig. 1) to more 

than 1,200 ft in the basin center (Fisher and Barratt, 1985). It contains supratidal sand flat, eolian dune, 

shallow marine barrier bar and marine shoreface deposits with intense bioturbation, fair porosity and good 

permeability (Barnes and others, 1992). Dolomite layers commonly found within the thick sandstone beds 

provide good markers for detailed sequence stratigraphic analyses (Nadon and others, 2000). 

OVERPRESSURED COMPARTMENT 

A regionally extensive overpressured mega-compartment has been identified within the St. Peter 

Sandstone and Glenwood Formation (Bahr and others, 1994; Dott and Nadon, 1992). Formation test results 

and pressure data were collected by these authors from the Michigan Department of Natural Resources and 

IHS-Petroleum Information, Inc. Hydrostatic heads were calculated from drill-stem test and reservoir 

pressures, and data points showing overpressured heads which exceed surface elevations were plotted on 

contour maps. Selected shut-in reservoir pressure points were plotted on pressure versus depth charts. Pore 

pressures exceed the normal pressure gradient for salt water brine (0.5 psi/ft or 1.16 g/cc) below depths of 

7,500 ft in the east-central part of the basin and along the shore of Lake Huron (fig. 4). 

CAUSE OF OVERPRESSURE 

The cause of the moderate overpressures in the St. Peter-Glenwood section has been attributed to glacial 

loading during the last ice age (Bahr and others, 1994; Dott and Nadon, 1992). However the occurrence of 

natural gas fields and thermally mature source rocks in this area (Cercone and Pollack, 1991; Moyer, 1982) 

raises the possibility that overpressure within the Glenwood-St. Peter section may have been caused by 

hydrocarbons expelled from nearby source rocks. Thin layers of organic-rich black shale and thin, 

carbonaceous algal lamination have been noted in cores collected from the Lower Ordovician Brazos (fig. 3) 

and Foster Formations (Fisher and Barratt, 1985). These potential hydrocarbon source rocks have reached 

thermal maturity and may have expelled large volumes of hydrocarbons in the basin center. The 

overpressuring observed in the Glenwood-St. Peter section may have been caused by hydrocarbon 

generation, and a continuously gas-saturated, basin-center gas accumulation might be present within the 

overpressured area.

WELL HISTORIES AND FORMATION TEST DATA 

Well histories, well logs, drill-stem test reports (available at the Denver Earth resources Library, 730- 

17 th Street, Denver, CO 80202, via microfiche from IHS-Petroleum Information, Inc.) and field descriptions 

published by the Michigan Basin Geological Society (Wollensak, 1991) were reviewed to evaluate mud 

weights, bottom hole temperatures, drill-stem test shut-in pressures, depth, porosity, permeability and fluid 

and/or gas recovery data. Table 1 lists well data for more than 100 St. Peter penetrations within and 

surrounding the overpressured area. The pressures listed are the maximum shut-in pressures reported by the 

operator, usually the initial shut-in or final shut-in pressures, without any additional extrapolations. In 

many cases these pressures are probably somewhat lower than true reservoir pressure due to short buildup 

times, and could be extrapolated higher by using Horner plots or similar methods. Fluid and/or gas 

recoveries were listed by the operator on Michigan DNR completion report forms, or noted in service 

company test reports. Porosities and permeabilities were derived from core analyses or from calculated 

values noted in drill stem test reports. 

EXTENSIVE SALT WATER SATURATION 

The formation tests listed in Table 1 generally recovered salt water from the Glenwood-St. Peter-Brazos 

section, with occasional gas shows indicating potentially commercial gas accumulations. The test data 

indicate regionally extensive salt water-saturation at “normal” to slightly above normal pressure gradients 

(0.4 to 0.56 psi/ft). Salt water appears to be the primary overpressuring fluid. Analyses of the salt water 

brines recovered during some of these formation tests show chloride contents ranging from 190,000 to 

300,000 ppm and fluid densities equivalent to 10.3 to 10.6 lb/gal drilling mud (+/- 1.24 - 1.27 g/cc). 

Drilling mud densities range from 9.1 to 11.3 pounds per gallon at depths ranging from 6490 to 11,850 ft. 

Reservoir temperatures in the Glenwood-St. Peter interval range from 125 to 191 °F throughout the region. 

These temperatures are lower than those typically found in known basin-center gas accumulations, which 

usually occur in reservoirs with temperatures greater than 190-200 °F. 

CORE DATA 

Bahr and others (1994) note average porosity of 11.4% and average permeability of 5 md in Glenwood- 

St. Peter reservoirs. Barnes and others (1992, p. 1529) presented conventional core analyses from three St. 

Peter Sandstone cores. Porosities range from approximately 2 to 21% at depths of 7920 - 9020 ft, 

depending on depositional environment, depth of burial, diagenetic cements, and development of secondary 

porosity. Permeability values greater than 10 md are common, and some intervals exceed 100 md. 

Core analyses for three other deep wells (Marathon Bentley No. 4-20, Sec. 20, T. 17N., R. 2E., 

Gladwin County; Marathon Trout River No. 3-18, Sec. 18, T. 22N., R. 2E., Ogemaw County; and Brown 

Gingrich No. 1-13, Sec. 31, T. 18N., R. 10W., Osceola County) show measured porosities ranging from 

1% to 14% at depths of 8600 to 12,100 ft. Measured permeabilities are highly variable, ranging from less 

than 0.1 mD to 750 mD. Many thin zones have permeabilities in the 11 to 88 mD range. These 

permeability values are much higher than those generally found in known basin-center gas accumulations, 

where tight sandstone reservoirs usually have permeabilities less than 0.1 mD. 

Cores of the St. Peter were often described as white, friable sandstone with abundant vertical fractures, 

burrow structures, excellent permeability and good intergranular porosity. Some of the cores were “sweating 

water” or “bleeding salt water” soon after removal from the core barrels. Measured water saturations (Sw) in 

cores from the two Marathon wells and the Brown well ranged from 26% to 95%. In the Marathon Bentley 

No. 4-20 well, measured water saturations in the St. Peter core ranged from 31 to 95%, with most Sw 

values near 77%. This well was plugged and abandoned after each of four drill stem tests recovered salt 

water. The St. Peter Sandstone was found to be convincingly water-productive at this location.

The salt water recoveries noted in many drill stem tests and the high water saturations listed in the core 

analyses indicate that the Glenwood-St. Peter reservoir section is regionally saturated with salt-water and 

probably contains high saturations only within localized structural gas traps. The extensive salt water 

saturation indicates that this is probably not a basin-center gas accumulation. 

SIXTEEN GAS FIELDS 

Detailed descriptions of sixteen fields which have produced natural gas and/or condensate from the 

Glenwood-St. Peter section have been published by the Michigan Basin Geological Society (Wollensak, 

1991). Figure 5 shows the location of these gas fields, and Table 2 lists pertinent reservoir data. All of the 

sixteen fields have been described as conventional hydrocarbon traps located within faulted anticlinal 

structures. Gas and/or condensate is typically found within the upper part of each trap, and salt water is 

found at lower levels. Some of the traps appear to be incompletely filled with gas. Most of the published 

field descriptions note distinct gas/water contacts, which are shown on marked logs, cross sections or 

structure maps. 

Strong water drives and problems with increasing water production were noted in several field reports. 

Increasing water production rates evidently caused some producing wells to be shut in. Abandoned wells 

located downdip from the gas traps frequently recovered salt water from the reservoir section. The formation 

waters are often described as black, sulfurous brines with chloride contents of 150,000 to 300,000 ppm. 

Reservoir pressure gradients range from normal to moderately overpressured. All of these fields have 

reservoir temperatures lower than 200 °F. The Glenwood-St. Peter reservoirs have relatively high 

permeabilities (30 mD to 119 mD, with sweet spots as high as 750 mD). These values are much higher 

than those typically found in known basin-center gas accumulations.

CONCLUSIONS 

Pressures, temperatures and fluid recoveries from at least 120 drill-stem tests and published descriptions 

of sixteen gas fields and were reviewed to evaluate the possibility that a basin-center gas accumulation 

might be present within the overpressured Glenwood Formation and St. Peter Sandstone in the central 

Michigan Basin. The formation test data indicate a regionally extensive, salt-water saturated aquifer system 

with relatively low temperature (< 191 °F), unusually high permeabilities (0.1 to 88 to 750 mD) and nearnormal 

(0.4 psi/ft) to moderately overpressured (0.56 psi/ft) reservoir pressure gradients. Formation water 

salinities (150,000 to 350,000 ppm chlorides) are remarkably consistent throughout the region. 

Published descriptions of sixteen gas fields producing from the Glenwood-St. Peter section indicate that 

all are located within conventional structural traps in anticlinal closures. Most of these fields have distinct 

gas/water contacts which are described in reports or shown on marked logs, cross sections and/or published 

structure maps. Gas-water transition zones for several fields are indicated by abandoned wells downdip which 

recovered salt water during drill stem tests. Numerous exploratory wells in between the producing fields 

have recovered salt water from the Glenwood-St. Peter section. 

Regional structure maps indicate a relatively uncomplicated basin structure lacking major transverse 

fault zones or major fault-bounded pressure compartments. Drill-stem test data and field descriptions indicate 

that salt water probably extends throughout the central basin within the Glenwood-St. Peter aquifer. The 

porosity available within the reservoir system has not been de-watered or continuously gas-saturated. 

Perhaps the Cambrian-Ordovician source rocks were not thick or rich enough to generate and expel 

enough gas to effectively saturate the available porosity, or perhaps the source rocks cooled down and ceased 

expelling gas too early. Perhaps the permeabilities were too high, so that large volumes gas escaped 

vertically into shallower reservoirs or migrate laterally toward the basin margins. For whatever reasons, the 

pore space available in the Glenwood Fm and St. Peter Sandstone appears to be extensively saturated with 

salt water. Reservoirs are charged with gas and/or condensate only within several localized structural traps. 

Based on review of well data and field descriptions, the Glenwood-St. Peter section in the Central Michigan 

basin does not contain a basin-center gas accumulation.


Bahr, J.M., Moline, G.R., and Nadon, G.C., 1994, Anomalous pressures in the deep Michigan basin: 

in Ortoleva, P J., ed., Basin Compartments and Seals, AAPG Memoir 61, p. 153-165. 

Barnes, D.A., Lundgren, C.E., and Longman, M.W., 1992, Sedimentology and diagenesis of the St. 

Peter Sandstone, central Michigan basin, United States: AAPG Bulletin v. 76, no. 10, p. 1507- 

1532. 

Catacosinos, P.A., and Daniels, P.A. Jr., 1991, Stratigraphy of Middle Proterozoic to Middle 

Ordovician formations in the Michigan basin: in Catacosinos, P.A., and Daniels, P.A., eds., 

Early sedimentary evolution of the Michigan basin: Geological Society of America Special 

Paper 256, p. 53-71. 

Cercone, K.R. and Pollack, H.N., 1991, Thermal maturity of the Michigan basin: in Catacosinos, 

P.A., and Daniels, P.A., eds., Early sedimentary evolution of the Michigan basin: Geological 

Society of America Special Paper 256, p. 1-11. 

Dott, R.H. Jr. and Nadon, G., 1992, Modeling of pressure compartments in the St. Peter Sandstone 

gas reservoir in the Michigan basin: Gas Research Institute Report no. 93-0015, 59 p. 

Fisher, J.H. and Barratt, M.W., 1985, Exploration in Ordovician of central Michigan basin: AAPG 

Bulletin v. 69, no. 12, p. 2065-2076. 

Moyer, R.B., 1992, Thermal maturity and organic content of selected Paleozoic formations, Michigan 

basin: M. Sc. Thesis, Michigan State University, East Lansing, Michigan, 62 p. 

Nadon, G.C., Simo, J.A., Dott, R.H. Jr., and Byers, C.W., 2000, High-resolution sequence 

stratigraphic analysis of the St. Peter Sandstone and Glenwood Formation (Middle Ordovician), 

Michigan basin, USA: AAPG Bulletin, v. 84, no. 7, p. 975-996. 

Wang, H.F., Crowley, K.D., and Nadon, G.C., 1994, Thermal history of the Michigan basin from 

apatite fission-track analysis and vitrinite reflectance: in Ortoleva, P. J., ed, Basin compartments 

and seals, AAPG Memoir 61, p. 167-177. 

Wollensak, M. S., ed., 1991, Oil and gas field manual of the Michigan basin: Michigan Basin 

Geological Society, 502 p.

LAKE MICHIGAN 

1000 

500 

0 Miles 100 

Contour Interval = 100 ft. 

500 

LAKE HURON 

LAKE ERIE 

Figure 1. Isopach map of the St. Peter Sandstone in the central Michigan basin. Modified 

from Barnes and others (1992, fig. 3).

LAKE MICHIGAN 

-5,000 

-10,000 

0 Miles 100 

Contour Interval = 1,000 ft. 

LAKE HURON 

LAKE ERIE 

Figure 2. Structure contour map of the top of the Glenwood Formation in the central 

Michigan basin. Modified from Fisher and Barratt (1985, fig. 12). 

D U 

D U 

D U

SYSTEM 

ORDOVICIAN S 

CAMBRIAN 

U 

M 

L 

U 

M 

L 

PRECAMBRIAN 

MILLION 

YEARS 

438 

478 

505 

523 

570 

FORMATION 

Cinncinnatian 

Utica 

Trenton 

Black River 

Glenwood 

St. Peter 

Brazos 

Foster 

Prairie Du Chien Group 

Trempealeau 

Franconia 

Galesville 

Eau Claire 

Mt. Simon 

Figure 3. Cambrian and Ordovician stratigraphic units in the Michigan basin, including the 

Glenwood Fm, St. Peter Sandstone, Brazos Shale and Foster Fm. Modified from Barnes and 

others (1992, fig. 2).

LAKE MICHIGAN 

0 100 

Miles 

LAKE HURON 

LAKE ERIE 

Figure 4. Map showing the overpressured area in the Glenwood Fm and St. Peter 

Sandstone, central Michigan basin. Modified from Bahr and others (1994, p. 158).

LAKE MICHIGAN 

Burdell 

Leroy 

Reed City 

Woodville 

Goodwell 

Ensley 

Falmouth 

Winterville 

S. Buckeye 

Fletcher 

Pond 

Rose City 

West Branch 

Clayton 

Kawkawlin 

0 100 

Miles 

Akron 

LAKE HURON 

Hardwood 

Point 

LAKE ERIE 

Figure 5. Map showing 16 gas fields which produce from the Glenwood-St. Peter Sandstone 

section. Modified from Wollensak (1991).

Well Name No. Sec. T. R. County Formation Mud Wt. BHT ISIP Depth PrGrad Perm Porosity Test Results, IP, Cores, Comments 

ppg degF psi ft psi/ft mD % 

Brown Snowplow 5-9 9 29 N. 5 E. Alpena St. Peter 10 145 3668 7,240 0.51 21 5 to 13 Perf'd 7220-7264 ft IP= 60 BCPD + 4900 MCFD. 

Shell Huber 1-36 26 20 N. 6 E. Arenac Brazos 10.7 5542 11,630 0.48 Perf's 11620-644 ft IP=26 BCPD + 4164 MCFD, no water. 

Shell Huber 1-36 26 20 N. 6 E. Arenac St. Peter 10.7 5410 10,450 0.52 DST rec gas + trace of condensate to surface. 

Shell Huber 1-36 26 20 N. 6 E. Arenac St. Peter 10.7 5464 10,565 0.52 DST rec 19 bl fm water + trace of gas. 

Shell Huber 1-36 26 20 N. 6 E. Arenac St. Peter 10.7 5681 11,050 0.51 DST rec gas + condensate-cut drilling mud. 

Shell Huber 1-36 26 20 N. 6 E. Arenac Brazos 10.7 6563 11,640 0.56 DST rec gas to surface at 3.7 MMCFD. 

Shell Eisenman 1-3 3 14 N. 4 E. Bay St. Peter 11.3 161 4312 10,510 0.41 DST rec cushion + drilling mud. 

Shell Dow 1-10 10 14 N. 5 E. Bay St. Peter 5158 10,550 0.49 DST rec cushion + drilling mud. 

Shell Walczak 1-7 7 14 N. 5 E. Bay St. Peter 166 5094 10,510 0.48 DST rec 5394 ft gassy salt water + 496 ft loose sand. 

Shell Walczak 1-7 7 14 N. 5 E. Bay St. Peter 160 5410 10,370 0.52 DST rec gassy mud + flowed gas to surface. 

Shell Walczak 1-7 7 14 N. 5 E. Bay Brazos 5416 11,090 0.5 Perf'd 11025-114 ft. IP= 305 BCPD + 6100 MCFD. 

Shell Vermeesch 1-21 21 14 N. 6 E. Bay Glenwood 153 5423 10,380 0.52 DST rec gas + condensate-cut mud, flowed gas to surf.ace 

Shell Vermeesch 1-21 21 14 N. 6 E. Bay St. Peter 5194 10,900 0.48 Perf'd 10832-980 ft. IP=122 BCPD, 2101 MCFD + 17 bwpd. 

Fed NatGas Metz 1-15 15 16 N. 4 E. Bay St. Peter 6067 11,690 0.52 DST flowed gas to surface at 220 MCFD. 

Fed NatGas Metz 1-15 15 16 N. 4 E. Bay St. Peter 5901 11,705 0.51 Perf'd 11635-11768 ft. IP= 150 MCFD, no water. 

Hunt Lease Mgmt 1-12 13 17 N. 7 W. Clare St. Peter 5063 10,630 0.48 Perf'd 10640-611, 10690-740 ft. IP= 708 MCFD + 31 bwpd. 

Petrostar Winterfield 1 19 20 N. 6 W. Clare St. Peter 10.1 5344 10,458 0.51 Perf'd 10452-462 ft. IP= 800 MCFD + 240 bwpd. 

Petrostar Winterfield 1 19 20 N. 6 W. Clare St. Peter 10.1 5271 10,430 0.5 DST rec 365 ft fm water. 

Petrostar Winterfield 1 19 20 N. 6 W. Clare Brazos 10.1 190 5508 10,950 0.5 DST rec 480 ft muddy water. 

NM Expl Gernat 2-19 19 20 N. 6 W. Clare St. Peter 10.6 4263 10,470 0.41 DST rec 3770 ft formation water. 

Hunt Winterfield A 1 30 20 N. 6 W. Clare St. Peter 10.8 130 4064 10,545 0.39 DST rec 19 stands water + 1 stand mud. 

Petrostar St Winterfield 1 31 20N 6W Clare St. Peter 195 5582 11,080 0.5 DST rec 540 ft formation water. 

Petrostar St Winterfield 1 31 20N 6W Clare St. Peter 10.4 191 4819 10,900 0.44 DST rec 20 ft condensate, 600 ft mud + 400 ft gassy fm water 

Petrostar St Winterfield 1 31 20N 6W Clare St. Peter 10.4 190 4581 11,300 0.4 DST rec 1120 ft muddy water 

Petrostar St Winterfield 1 31 20N 6W Clare St. Peter 10.4 190 5601 11,340 0.49 Perf'd 11323-354 ft IP=3 BOPD, 2650 MCFD + 37 bwpd 

JEM Dalrymple 1-16 16 22N 4W Clare St. Peter 4850 11,090 0.44 DST rec 480 ft gas-cut mud. sampler rec 3.8 cu ft gas 

JEM Dalrymple 1-16 16 22N 4W Clare St. Peter 5253 11,120 0.47 fair DST rec 1142 ft gas-cut mud. No fluor or cut in Ss 

Hunt Martin 1-15 15 17N 1E Gladwin St. Peter 11.2 178 5753 11,500 0.5 DST rec 1200 ft water-cut mud + 8136 ft gas-cut mud 

Marathon Bentley 4-20 20 17N 1E Gladwin St. Peter 10.3 167 1027 11,350 11 9 to 13 DST rec 200 ft fm water. Cored ss with good permeability 

Marathon Bentley 4-20 20 17N 1E Gladwin St. Peter 10.5 173 5700 12,055 0.43 0.005 7 DST rec 75 ft fm water, sampler rec water-cut mud 

Marathon Bentley 4-20 20 17N 1E Gladwin St. Peter 10.4 171 5883 11,490 0.51 0.7 8 to 10 DST rec 74 bl gassy water 

Amoco Letts Unit 2-36 36 18N 1W Gladwin St. Peter 10.5 171 5826 11,240 0.52 4.6 10 to 17 Perf'd 11218-252 ft. IP= 80 BCFD, 3095 MCFD + 32 bwpd 

Amoco Ballentine 1 35 18N 1W Gladwin St. Peter 10.3 5816 11,270 0.52 Perf'd 11260-280 ft. IP= 76 MCFD + 19 BWPD. Plug back 

Amoco Ballentine 1 35 18N 1W Gladwin St. Peter 10.3 5476 11,170 0.49 Perf'd 11147-183 ft. IP= 9 BCPD, 417 MCFD + 2 BWPD 

Sun Cameron 1-10 10 18N 2W Gladwin St. Peter 10.8 174 5464 11,290 0.48 DST rec cushion, 350 ft gassy water, flowed gas to surface 

Sun Cameron 1-10 10 18N 2W Gladwin St. Peter 10.8 168 5601 11,850 0.47 DST rec 8 bl gas-cut mud, flowd gas to surface 

Shell Gettel 1-5 5 15N 10E Huron St. Peter 11.1 152 5096 10,245 0.5 DST rec 10 bl fm water 

Cities Service Gettel 1 1 15N 9E Huron St. Peter 160 3941 10,650 DST rec gassy mud 

Shell Baranski 1-28 28 18N 13W Huron St. Peter 10.9 124 470 8,500 0.51 DST rec 30 bl gassy muddy fm water 

Shell Baranski 1-28 28 18N 13W Huron Brazos 10.9 143 4983 9,300 0.54 DST rec 90 bl formation water 

Shell Baranski 1-28 28 18N 13W Huron Brazos 10.9 141 4949 9,510 0.52 DST rec 37 bl water-cut drilling mud 

Amoco Oboyle 1-31 31 15N 3W Isabella St. Peter 10 182 5228 10,110 0.52 1.34 DST rec 56 bl formation water, 228,000 ppm Cl- 

Amoco Oboyle 1-31 31 15N 3W Isabella St. Peter 10.1 184 5099 10,130 0.5 good DST rec 8213 ft water. "Zone has good permeability" 

Sun Anderson 1-20 20 14N 10W Mecosta St. Peter 10.4 3643 7,880 0.46 good DST rec 66 bl gassy fm water 

Pure Oil Emery 1 21 13N 1W Midland St. Peter 180 4991 9,820 0.51 0.2 14 DST flowed gas at 2.6 MMCFD, water with 225,000 ppm Cl- 

KEP Schoenmaker 1 7 21N 6W Missauk St. Peter 4285 10,760 0.4 DST rec 514 ft gas + water cut mud. Core, good permeability 

Petromax M-Pollingt 1 2 21N 7W Missauk St. Peter 4660 10,770 0.43 DST rec 300 ft mud + 314 ft salt water 

Terra Cramer 1-20 20 21N 7W Missauk St. Peter 9.1 183 4077 10,640 DST rec 185 ft gassy salt water, with 286,000 ppm Cl- 

Cities Service Kuiper 1 29 21N 8W Missauk St. Peter 10.4 163 4376 10,620 0.41 5 to 10 DST rec 460 ft mud, 440 ft water. Core "bleeding salt water" 

JEM Doornbos 30-5 30 22N 6W Missauk St. Peter 4410 10,675 0.41 fair DST rec 1885 ft black sulfurous water, flowed gas to surface 

JEM Doornbos 30-5 30 22N 6W Missauk St. Peter 5181 10,850 0.48 DST rec 450 ft mud, 399 ft fm water 

JEM Workman 10-31 31 22N 6W Missauk St. Peter 10.4 4603 10,740 0.43 exc good DST rec 200 ft fm water. Core "sweating water" 

JEM Visser 3-35 35 22N 6W Missauk St. Peter 9.8 4778 10,870 0.44 DST flowed gas to surface, rec 730 ft fm water 

JEM Visser 3-35 35 22N 6W Missauk St. Peter 10,945 DST rec 2004 ft gassy fm water with 279,000 ppm Cl- 

Patrick Gilde 1-25 25 22N 7W Missauk St. Peter 10.9 175 5300 10,580 0.5 good Perf'd 10560-595 ft. IP=6.75 MMCFD 

JEM Koetje 1-25 25 22N 7W Missauk St. Peter 9.8 4325 10,690 0.4 fair DST rec 465 ft mud + 300 ft salt water 

JEM Koetje 1-25 25 22N 7W Missauk St. Peter 9.8 161 4785 10,745 0.44 DST rec 90 ft gas-cut mud + 520 ft fm water 

DART Edwards 7-36 36 22N 7W Missauk Black River 2893 10,154 DST rec 100 ft gassy salt water 

DART Edwards 7-36 36 22N 7W Missauk St. Peter 3434 10,580 DST rec 123 ft mud + 10,327 ft gas in drillpipe 

DART Edwards 7-36 36 22N 7W Missauk St. Peter 5265 10,620 0.5 Perf'd 10613-745 ft. IP= 12.26 MMCFD 

Petrostar Norwich 1-12 12 24N 5W Missauk Brazos 9.6 5109 11,640 0.44 good DST#1 rec 7048 ft salt water with 206,000 ppm Cl- 

JEM Bruggers 3-7 7 24N 6W Missauk St. Peter 4757 10,600 0.45 DST rec 1400 ft mud + 270 ft 10.7 pg salt water 

Jennings Crimmins 1 18 12N 9W Montcal St. Peter 4203 7,915 0.53 DST rec 60 ft fm water + trace of gas 

Jennings Crimmins 1 18 12N 9W Montcal St. Peter 3457 8,010 DST rec 465 ft fm water + 30 ft drilling mud + trace of gas 

Shell Houtm-Croton 1 33 12N 11W Newayg Brazos 3190 6,840 0.47 IP= 24 BCPD + 3128 MCFD 

Wolverine Wise 1-3 3 13N 11W Newayg St. Peter 10.5 125 3371 7,425 0.45 DST rec 150 ft gas + 1755 ft muddy water with 225,000 ppm Cl- 

Wolverine Wise 1-3 3 13N 11W Newayg St. Peter 10.5 127 3448 7,520 0.46 DST rec 5,290 ft muddy fm water with 246,000 ppm Cl- 

Terra Vanderly-Millis 1 5 14N 14W Newayg St. Peter 6,856 Perf'd 6,856-6,860 ft. Swabbed fm water 

Terra Vanderly-Millis 1 5 14N 14W Newayg St. Peter 6,606 Perf'd 6,600-6,612' ft. Swabbed fm water 

Terra Vanderly-Millis 1 5 14N 14W Newayg St. Peter 6,490 Perf'd 6,495-6,484 ft. IP= 24 BCPD + 2.2 MMCFD + 120 bwpd 

Ensource Thompson 1 27 15N 12W Newayg St. Peter 10.5 145 3379 8,390 0.4 DST rec 1,240 ft gassy muddy fm water 

Amoco Mansfield 1-36 36 21N 3E Ogemaw St. Peter 5561 10,700 0.52 Perf'd 10,662-10,758 ft. IP= 92 BCPD + 1.07 MMCFD + 7 bwpd 

Amoco Cailotto 1-31 31 21N 4E Ogemaw St. Peter 5552 10,620 0.52 Perf'd 10,584-750 ft. IP=235 BCPD + 2.45 MMCFD + 41 bwpd 

Marathon Robinson 1 13 22N 1E Ogemaw St. Peter 10.6 171 11,105 4.6 12.5 Cores: Perm=0.12 to 88 mD. Porosity= 2.7 to 13.7% 

Marathon Trout R 3-18 18 22N 2E Ogemaw St. Peter 10,600 3.7 7.8 Cores: Perm= 0.1 to 23 mD. Porosity= 1.8 to 14.5% 

Marathon Trout R 3-18 18 22N 2E Ogemaw St. Peter 174 5850 11,040 0.53 Perf'd 11,000-11,068 ft. IP=881 BCPD + 2.9 MMCFD + 5 bwpd 

Shell Foster 1-20 20 24N 2E Ogemaw St. Peter 10.5 165 5150 10,360 0.5 DST rec gas and condensate to surface 

Shell Foster 1-20 20 24N 2E Ogemaw St. Peter 10.5 180 5511 10,720 0.51 Perf'd 10,310-390, 10,695-765 ft. IP= 225 BCPD+ 6250 MCFD 

Shell Foster 1-21 21 24N 2E Ogemaw St. Peter 19 143 5038 10,373 0.48 good Perf'd 10,215-338 ft. IP=124 BCPD + 8.28 MMCFD + 288 bwpd 

Shell Foster 2-28 28 24N 2E Ogemaw St. Peter 10.1 167 4915 10,067 0.49 11 to 13 Perf'd 10,339-10,474 ft. IP=106 BCPD + 2.9 MMCFD. 

Shell State Foster 1-28 28 24N 2E Ogemaw St. Peter 10.3 166 10,450 6 to 9 Cored Ss, no shows. D&A. Downdip from Rose City Field 

Brazos State Foster 1 28 24N 2E Ogemaw St. Peter 10.8 148 5061 11,200 0.45 DST rec cushion, 100 ft mud + 790 ft salt water 

Brazos State Foster 1 28 24N 2E Ogemaw Brazos 10.7 180 11,800 Cored Foster Fm. Bleeding gas, black carbonaceous beds 

Brown Corvey 1 5 17N 10W Osceola St. Peter 9.4 142 3106 8,815 DST rec 400 ft muddy water + trace of gas 

Brown Corvey 1 5 17N 10W Osceola Brazos 9.4 4568 9,595 0.48 Perf'd 9,584-9,602 ft. IP=7.2 MMCFD + 16 bwpd 

Fairway Richmond 1 9 17N 10W Osceola Brazos 10.5 155 9,943 Mudlog: no gas shows in the St Peter Ss 

Brown Hayes 1-29 29 17N 10W Osceola St. Peter 155 3555 8,745 DST rec NR. "no shows" 

BWAB Rose City 1 7 17N 7W Osceola St. Peter 184 4602 10,050 0.46 good DST rec 196 ft gassy mud + 1,281 ft water with 263,000 ppm Cl- 

Brown Gingrich 1-31 31 18N 10W Osceola St. Peter 9,965 23 6.9 Perf'd 9,958-9,975 ft. IP=180 BCPD + 4 MCFD. Cored high perm Ss 

Sun Hopmeier 1 1 18N 10W Osceola St. Peter 10.6 164 4240 9,460 0.45 DST rec 1,600 ft gassy 10.4 ppg fm water 

Sun Hopmeier 1 1 18N 10W Osceola Brazos 10.6 160 4697 10,320 0.46 DST rec 860 ft 110.6 ppg salt water+O45 

Wolverine Greenwald 27 18N 10W Osceola St. Peter 10.4 164 4382 9,020 0.49 DST rec 120 ft gassy water + 2157 ft salt water 

Wolverine Greenwald 27 18N 10W Osceola St. Peter 10.4 168 4542 9,630 0.47 DST rec 5,851 ft gassy fm water 

Wolverine Greenwald 27 18N 10W Osceola Brazos 10.4 168 4745 9,840 0.49 DST rec 17 bl gas+condensate-cut drilling mud 

Wolverine Greenwald 27 18N 10W Osceola Brazos 10.4 168 4731 9,888 0.48 Perf'd 9,881-9,894 ft. IP= 3.4 MCFD 

Brown Lewsby 1-20 20 18N 10W Osceola St. Peter 9.4 156 4242 8,860 0.48 0.04 DST rec 557 ft muddy fm water 

Brown Lewsby 1-20 20 18N 10W Osceola St. Peter 9.4 162 4288 9,400 0.46 DST rec 5,316 ft salt water with 225,000 ppm Cl- 

Wolverine Giese 1 34 18N 10W Osceola St. Peter 172 4853 9,886 0.49 17.1 Perf'd 9,877-9,898 ft. IP= 6 BCPD + 4.3 MMCFD, no water 

Sun Zinger H 1 1 18N 10W Osceola St. Peter 157 4402 9,385 0.47 DST rec gas to surface at 3.2 MCFD + 834 ft gassy water 

Sun Zinger H 1 1 18N 10W Osceola St. Peter 163 4664 9,890 0.47 DST rec 1,620 ft gas-cut drilling mud 

Union Richards 1-19 19 18N 10W Osceola St. Peter 4080 8,980 0.45 DST rec 43 bl muddy water 

Union Richards 1-19 19 18N 10W Osceola St. Peter 4168 9,400 0.44 DST rec 2,470 ft gassy 10.6 ppg salt water 

Union Richards 1-19 19 18N 10W Osceola Brazos 4541 9,810 0.46 DST rec 74 bl salt water 

JEM McCormick 2-27 27 18N 8W Osceola St. Peter 4485 9,790 0.46 DST rec 900' water-cut mud 

Sun Loop 1-6 6 18N 9W Osceola St. Peter 10.5 167 4582 9,950 0.46 DST rec 1350' salt water, 9.6 ppg 

Sun Loop 1-6 6 18N 9W Osceola St. Peter 10.5 159 4647 9,440 0.49 DST rec 600' fm water 

Sun Loop 1-6 6 18N 9W Osceola Glenwood 10.5 150 3832 9,380 0.4 DST rec 220' muddy salt water 

Sun Sundmacher 1-33 33 18N 9W Osceola Brazos 10.6 9,845 

Petrostar Boyce 2-19 19 20N 10W Osceola St. Peter 3862 9,750 DST rec trace of gas to surface + 200 ft fm water 

Petrostar Boyce 2-19 19 20N 10W Osceola St. Peter 4478 9,745 0.46 Perf'd 9,740-9,748 ft. IP= 525 MCFD 

Sun Roseville 1-17 17 21N 1W Roscom St. Peter 5256 11,690 0.45 good DST rec 400 ft fm water. Cores "bleeding gas + water" 

Petrostar Roscom 1-30 30 21N 3W Roscom St. Peter 9.7 181 4378 11,320 0.06 7 to 12 DST rec 365 ft fm water with 220,000 ppm Cl-, BHP = 5700 psi 

Petrostar Roscom 1-30 30 21N 3W Roscom St. Peter 9.9 191 5900 11,707 0.5 DST rec 1,188 ft gassy muddy salt water with 190,000 ppm Cl- 

Sun State Lake 1-29 29 23N 4W Roscom St. Peter 11.3 182 4475 10,550 0.42 DST rec 1250' fm water 

Amoco Wahl Unit 1-14 14 24N 1W Roscom St. Peter 10.5 161 3126 10,300 DST rec 750' water 

Petrostar Almer Land 1 10 13N 9E Tuscola St. Peter 9.7 159 5103 10,340 0.49 0.02 10 DST rec 1,663' condensate-cut mud + 204 ft parafin 

Wolverine Dostal 1-27 27 21N 12W Wexford St. Peter 10.6 153 3840 8,520 0.45 DST rec 465 ft mud + 5,022 ft salt water with 236,000 ppm Cl- 

JEM Benson 1-14 14 21N 9W Wexford St. Peter 10.3 4359 10,260 0.43 DST rec 375 ft mud + 2,850 ft gassy salt water 

JEM Benson 1-14 14 21N 9W Wexford St. Peter 10.3 145 4717 10,350 0.46 DST rec 470 ft mud + 1440' ft gassy salt water 

Table 1. Michigan Basin DST Data

FIELD NAME Sec. T. R. County Formation Trap PrGrad BHT Porosity Permeability Wet DST ? G-WC at Depth Comments 

psi/ft degF % mD ft Refererence: Wollensak (1991) 

Akron 31 14 N. 8 E. Tuscola St. Peter anticline 0.49 155 3 to 28 .14 to 44 several G-WC -9,403 High swtr production, low BHT, gas-water contact. 

Burdell 19 20 N. 10 W. Osceola St. Peter anticline 0.46 165 0 to 11 G-WC -9,126 Water prod'n, low BHT, gas-water contact. 

Clayton 4 20 N. 4 E. Arenac St. Peter anticline 0.52 165 6 to 14 .3 to 3.5 several G-WC -9,952 200 bwpd, low BHT, gas-water contact. 

Ensley 7 11 N. 11 W. Newaygo St. Peter anticline 0.47 118 3 to 25 G-WC -5,825 High IP, then St. Peter perfs "watered out." 

Falmouth 36 22 N. 7 W. Missaukee St. Peter anticline 0.5 175 4 to 18 2 to 4 several G-WC -9,397 Low BHT, G/W contact. Cores "bleeding salt water." 

Fletcher Pond 9 29 N. 5 E. Alpena St. Peter anticline 0.51 145 7 to 15 .1 to 100 G-WC -6,400 Water prod'n, low BHT, gas-water contact. 

Goodwell 8 14 N. 11 E. Newaygo St. Peter anticline 0.45 140 5 to 24 several G-WC -6,900 Short gas column. Two gas-water contacts. 

Hardwood Point 28 29 N. 9 E. Alpena St. Peter anticline 0.55 114 5 to 10 2 to 119 G-WC -5,104 High water prod'n, gas-water contact. 

Kawkawlin 11 14 N. 4 E. Monitor St. Peter anticline 0.52 168 4 to 17 .1 to 750 several G-WC -9,950 High Perms. Two gas-water contacts. 

Leroy 27 19 N. 10 W. Osceola St. Peter anticline 0.48 171 6 to 10 55 to 65 G-WC -8,175 High water production, gas-water contact 

Reed City 19 18 N. 10 W. Osceola St. Peter anticline 0.46 168 5 to 14 .1 to 125 several G-WC -8,530 Low BHT, high permeabilities, gas-water contact. 

Rose City 21 24 N. 2 E. Ogemaw St. Peter anticline 0.5 174 7 to 14 .05 to 30 several G-WC -9,057 "Strong water drive," gas-water contact. 

South Buckeye 36 18 N. 1 W. Gladwin St. Peter anticline 0.52 171 6 to 19 4 to 28 several ? ? Water production. Salt water downdip at Martin No. 1-5. 

West Branch 21 22 N. 2 E. Ogemaw St. Peter anticline 0.53 174 9 to 15 1.3 to 13 G-WC -9,615 Water production. Two gas-water contacts. 

Winterfield 31 20 N. 6 W. Clare St. Peter anticline 0.51 191 fair several G-WC -9,288 Water production, gas-water contact. 

Woodville 29 15 N. 11 W. Newaygo St. Peter anticline 0.46 143 12 to 14 20 to 30 several G-WC -6,928 High water production, gas-water contact. 

Table 2. Michigan Basin Gas Field Data

ABSTRACT 


IN THE PASCO BASIN, CENTRAL WASHINGTON ? 


Well data, vitrinite analyses and previous geologic literature were examined to determine if the sparsely 

drilled Pasco basin in central Washington might contain a basin-center gas accumulation similar to those 

found in several Rocky Mountain basins. The limited geologic data available to the public show that many 

pre-requisites are present, including abnormal pressure gradients, thermally mature source rocks, high 

temperatures, abundant shows of natural gas, and tight sandstone reservoirs. However the results of twenty 

formation tests conducted in several deep exploration wells indicate that water-bearing zones have been 

encountered frequently. With the exception of a 1,850 ft thick section in the Roslyn Fm in the Shell 

Yakima Mineral Co. No. 1-33 well which might be gas-saturated, the test data indicate widespread “fizzwater” 

(gassy formation water) and several zones which produced water at high rates (> 50 bwpd). The 

sedimentary section does not appear to be extensively gas-saturated. 

The Pasco basin appears to be almost, but not quite a basin-center gas accumulation, with adequate 

temperatures, thermally mature, gas-prone source rocks, overpressure and gas shows. But the formation test 

results indicate too much water and not enough gas to completely match the definition. The volume of gas 

expelled from the source rocks may have been inadequate to effectively de-water the reservoir section. A 

Miocene-age regional hydrothermal event may have altered the plumbing of the basin. 

INTRODUCTION 

The Pasco basin (fig. 1) is located along the Columbia River near the cities of Pasco and Yakima in 

central Washington (Terra Graphics, 1981; Campbell, 1989; Johnson and others, 1993). This basin has also 

been called the Roslyn basin by Campbell (1989), and is part of a larger basin assemblage generally known 

as the Columbia basin (Lingley and Walsh, 1986). The boundaries and internal structure of the Pasco basin 

are poorly understood because the sedimentary section is almost entirely covered by thick, Miocene-age 

basalt flows of the Columbia River Basalt Group. 

In spite of obvious the difficulties of prospecting beneath basalt flows, the Columbia basin has been 

the focus of exploration activity by several petroleum companies. Early reports of gas and shows in shallow 

water wells stimulated several exploration drilling attempts. Gas shows, a gas kick, and strong water flows 

were reported in the Miocene Petroleum Company Union Gap well (Sec. 17, T. 12 N., R. 19 E., Yakima 

County) which reached a total depth of 3,810 ft in 1929. Shallow gas production was established in 1930 at 

the Rattlesnake Hills Gas Field in T. 11 N., R. 26 E., Yakima County, Washington. Low pressure gas 

containing 97% methane and 2.5% nitrogen was trapped in basalt flows at depths of only 700 to 915 ft in a 

faulted anticline structure (Hammer, 1934). Approximately 1.3 BCFG was produced from 16 wells above a 

distinct gas/water contact, but the field depleted rapidly and was finally abandoned in 1941 (McFarland, 

1979). 

Gas shows, a gas explosion and water flows (fig. 2, Table 1) were reported in the P. J. Hunt Snipes 1 

well (Sec. 33, T. 10 N., R. 22 E., Yakima County), which reached a total depth of 1,408 ft in 1945. A 

gas sample from 1,160 ft in this well contained 66% methane, 29% nitrogen and 4.5% oxygen. Johnson 

and others (1993) noted that methane gas has been found in many shallow aquifers within the Columbia 

River Basalts. They suggest that methane gas expelled from thermally mature Eocene-age coal beds has 

migrated vertically along fault zones into the shallow groundwater system within the basalt flows.

The Standard Oil Company drilled an exploratory well to test the deeper potential of the Ratttlesnake 

Hills anticlinal structure in 1958 (Standard Oil Rattlesnake 1, Sec 15-T11N-R24E). The well reached a total 

depth of 10,655 ft, but was abandoned with no significant oil or gas shows reported (Table 1). The drilling 

history and sample reports indicate that the well was still in basalt flows and tuff beds at total depth, and did 

not penetrate the sedimentary section which was thought to be buried beneath the basalts. 

RECENT EXPLORATION ACTIVITY 

Improvements in geophysical methods (Halpin and Muncey, 1982; Campbell, 1981) stimulated a 

second wave of exploratory drilling to evaluate the sedimentary section below the Columbia River basalts. 

Shell Western Exploration and Production Company drilled six deep wells in the Pasco basin during the 

1980’s (Table 1; fig. 2), and Meridian Oil and Gas Corporation drilled one deep well in 1989. All seven 

wells were plugged and abandoned without establishing commercial hydrocarbon production. The 

combination of MT surveys, regional seismic and gravity data, surface mapping and deep exploratory 

drilling resulted in an improved understanding of the stratigraphy and structure of the sediments buried 

beneath the flood basalts. 

A series of Cretaceous-age rift basins have been interpreted in south-central Washington and northcentral 

Oregon by Fritts and Fisk (1985a, 1985b) and Davis and others (1978). Several fault-bounded 

grabens (fig. 3) and half-grabens formed during Late Cretaceous and early Tertiary time, and filled with 

marine, lacustrine and fluvial sediments. The stratigraphic section (fig. 4) includes Jurassic and Cretaceousage 

igneous and metamorphic basement, Paleocene and Eocene-age marine and/or lacustrine deposits (Swauk 

Fm); alluvial, fluvial and coal deposits of the Eocene-age Roslyn Formation; and volcanic flows, tuff beds 

and arkosic sandstones of the Oligocene-age Naches, Ohanapecosh, Wenatchee, and Wildcat Creek 

Formations. The Tertiary sediments are almost completely covered by thick basalt flows and tuff deposits of 

the Miocene-age (17.2 to 15.6 Ma) Columbia River Basalt Group (Campbell, 1989; Johnson and others, 

1993; Baksi, 1989). 

Sumner and Verosub (1992) have suggested that a regional hydrothermal event occurred at 

approximately 23 to 24 Ma, pre-dating the Columbia River Basalts. Widespread low temperature 

hydrothermal activity is thought to have caused extensive chlorite, zeolite and siliceous alteration in the 

Cretaceous and Tertiary sediments, and acceleration of the thermal maturation of Tertiary source rocks. 

Sample descriptions noted in the mud-logs of several deep exploratory wells indicate the widespread 

occurrence of zeolite minerals (especially laumontite), silicified zones and chlorite diagenesis throughout the 

sedimentary section. An episode of tectonic compression during late Miocene caused extensive folding and 

faulting of the basalt flows. Maps showing the surface anticlines, synclines and fault structures have been 

published by Tolan and Reidel (1989), Campbell (1989) and Johnson and others (1993). 

HYPOTHETICAL BASIN-CENTER GAS PLAY 

Law (1995) reviewed the exploration activity in the Columbia basin as part of the USGS 1995 

Regional Assessment, and suggested that a hypothetical basin-center gas play (USGS No. 503) might be 

present in the Pasco basin northwest of the Columbia River. Law noted many of the characteristics 

typically found in known basin-center gas accumulations, including overpressuring, gas shows, and tight 

sandstones with 6 to 15% porosity in the sedimentary section below the basalt flows. Law (1995) noted 

that gas had been recovered at rates of 3.1 MMCFD but that “some water” had been recovered during drill 

stem tests in several deep wells.

EVALUATION OF WELL DATA 

Data from the deep wells drilled by Shell and Meridian and from several other wells in the region were 

reviewed to evaluate this hypothetical basin-center gas play in more detail. Well data were collected from 

MJ Microfiche Systems, the Denver Earth Resources Library (730-17th Street, Denver, CO, 80202), the 

USGS well log collection, and from several published reports. Drilling mud weights, bottom hole 

temperatures, reservoir pressures, vitrinite reflectance measurements, permeabilities, porosities and 

formation test results are summarized in Table 1. Figures 5 and 6 show stratigraphic and structural 

interpretations for most of these key wells. 

Bottom hole temperatures in the deep wells ranged from 218 to 362 °F (Table 1). These temperatures 

exceed the 190-200 °F threshold for basin-center gas accumulations proposed by Law and Dickinson (1985) 

and Law and Spencer (1989; 1993). Published vitrinite reflectance measurements (Lingley and Walsh, 1986; 

Summer and Verosub, 1987) range from 1.1 to 1.3 %Ro at depths of 10,800 to 15,820 ft in the Shell 

Yakima Mineral Co. No. 1-33 and Shell BN No. 1-9 wells. These values exceed the threshold of 0.75% to 

1 %Ro suggested by Law (1995), Spencer (1989) and Law and Spencer (1993) for typical basin-center gas 

accumulations. Lower vitrinite reflectance (0.57 %Ro at 10,080 ft) was measured in the Shell Bissa No. 1- 

29 well, which appears to be located on an uplifted fault block (fig. 6). 

Mud-logs for several Pasco basin wells are available from MJ Microfiche Systems and/or from the 

USGS well log collection. These show that moderate to low-level shows of background gas (mostly 

methane) were encountered throughout much of the sedimentary section. Stronger gas shows with heavier 

C3, C4 and iC4 hydrocarbons and occasional solvent cuts, oil stain, and yellow-green oil fluorescence were 

encountered in several of the deep wells, indicating the presence of condensate and light oil accumulations. 

Drilling mud weights and reservoir pressures (Table 1) indicate extensive overpressuring within the 

Roslyn, Teanaway and Swauk Formations throughout the Pasco basin. Mud weights as high as 16 to 17.3 

ppg were needed to control the deep wells in this area. Reservoir pressures measured during drill stem and 

production tests indicate moderate overpressures ranging from 0.55 to 0.72 psi/ft. Assuming that these 

measurements are accurate, the 16 to 17.3 ppg (0.83 to 0.89 psi/ft) drilling muds were significantly 

overbalanced. Most of the wells were drilled with water-based mud systems, and problems with borehole 

caving, sloughing and stuck pipe were reported in several drilling histories. There may have been problems 

with swelling clays in the volcanic ash deposits, which might have reacted with water in the drilling mud. 

Unusually high mud weights may have been used to stabilize boreholes which were sloughing or being 

squeezed due to swelling clays. 

Twenty formation tests (Table 1) were performed to evaluate hydrocarbon shows and zones of interest 

in the Wildcat Creek, Wenatchee, Ohanapecosh and Roslyn Formations below the basalt flows. Six of the 

twenty tests recovered no measurable volumes of gas or liquids. Five tests recovered natural gas at low, 

non-commercial flow rates. The formation test at 13,372-388 ft in the Shell BN No. 1-9 well recovered gas 

and condensate at a sub-commercial flow rate (3100 MCFD and 6 BCFD) after hydraulic fracture 

stimulation. However, this productive reservoir was sandwiched in between zones which produced water at 

high flow rates (3 to 5 bwph) when tested. Three of the twenty formation tests flowed gassy water at 

moderate rates (more than 50 bwpd), and five tests recovered water at high flow rates (120 to 5400 bwpd). 

In summary, eight of the fourteen productive tests flowed water or gassy water at moderate to high flow 

rates, and six tests flowed gas and/or condensate without water. The pressuring phase has often been water 

or gassy water, and less frequently gas without water. The available test data are limited, but they indicate 

that this hydrocarbon system contains abundant moveable water. The available porosity has not been 

extensively de-watered and does not appear to be continuously gas-saturated. 

Hydraulic fracture stimulations were used in four of the twenty formation tests. At the Shell BN No. 

1-9 well (sec. 9, T. 15 N., R. 25 E.) a fracture treatment using 7,500 gallons of 15% acetic acid at 14,056- 

14,346 ft resulted in water production at 3 BWPH with traces of gas containing 40 to 380 ppm hydrogen 

sulfide. This zone was plugged off. A hydraulic fracture stimulation using 90,000 pounds of Interprop at

13,372-13,388 ft increased gas production from 1,345 MCFD to the sub-commercial rate of 3,100 MCFD 

+ 6 barrels of 30.2° API condensate per day. The shut-in reservoir pressure was 7,800 psi (0.58 psi/ft) 

before the treatment and 6,900 psi (0.52 psi/ft) after the fracture treatment. Calculations reported by the 

operator indicate that the fracture stimulation nearly doubled the “kh” (permeability x height) of the 

reservoir, which was a thin sandstone layer with unusually good porosity. However, this productive zone 

was sandwiched in between upper and lower zones which produced water at 3 to 5 BWPH during tests. 

Farther uphole, perforations at 12,694-12,880 ft produced gas at 553 mcfd with no water before treatment. 

After fracture stimulation with 89,000 pounds of Interprop, the “kh” increased from 1.33 mDft to 2.02 

mDft and the zone flowed gas and water at a stabilized rate of 2,395 MCFD and 5.6 BWPH. This fracture 

treatment evidently improved the permeability of the reservoir, but also connected a gas-producing zone to a 

water-producing zone. An acid-fracture stimulation using 77,000 pounds of sintered bauxite proppant at 

12,430-12,380 ft in the Shell Yakima Mineral Company No. 1-33 well (Sec. 33, T. 15 N., R. 19 E.) 

resulted in a gas flow at 500 MCFD, but the flow rate declined to 150 MCFD within five days and the zone 

was eventually plugged. Hydraulic fracture stimulations in the Roslyn Formation evidently include 

significant risks: the induced fracture may improve reservoir permeability, but may also connect gasproducing 

zones with nearby water-producing zones. As noted by Johnson and others (1993), the 

sedimentary section may be cross-cut by fault and fracture zones which can function as permeable pathways 

for gas and water migrating upward into shallower zones. 

Four of the tests conducted at the Shell Yakima Mineral Company No. 1-33 well (Sec. 33, T. 15 N., 

R. 19 E., Yakima County) evaluated zones of interest in the Roslyn Fm between 10,604 ft and 12,450 ft. 

According to reports released by the operator, each of these tests flowed natural gas at low rates (10 MCFD; 

85 MCFD; 75 MCFD; 500 to 150 MCFD) without any water production. The bottom hole temperatures 

range from 228 to 244 °F in this interval, and published vitrinite reflectance measurements range from 1.1 

to 1.3 %, indicating thermal maturity. The maturity data and lack of water production during testing indicate 

that a gas-saturated section might be present within this 1,850 ft thick interval. However, zones above and 

below this depth range produced gassy water at very high rates when tested (1700 bwpd at 7,535-8,040 ft; 

5400 bwpd at 12,976-13,568 ft). So the potentially gas-saturated section is evidently sandwiched in between 

water-producing zones. 

DISCUSSION 

Fourteen of twenty formation tests in the Pasco basin were productive. Six tests recovered gas and/or 

condensate without water, and eight tests recovered water or gassy water at moderate to high flow rates. 

Based on the limited data available, water production is common, so the deep sedimentary section is 

apparently not continuously saturated with gas. Four tests in the Shell Yakima Min Co #1-33 well 

produced gas at very low rates, without any water, indicating a potential gas-saturated section between 

10,604 and 12,450 ft deep. However water was produced above and below this 1,850 ft thick section. 

Additional testing would be needed to prove that the 1,850 ft thick zone is continuously gas-saturated and 

would not produce water. 

Previous authors have suggested that coal beds within the Eocene-age Roslyn Fm are the source of 

natural gas and condensate in the Pasco Basin. But careful inspection of mudlogs, sample descriptions, 

caliper logs and density logs in the deep exploration wells indicates that the coal beds are very thin and 

relatively rare. No coal beds thicker than 5 ft were observed in the various density logs and mudlogs. The 

coal beds may have been formed in shallow, short-lived swamps which were frequently covered by volcanic 

ash flows or lava flows. The Roslyn Fm apparently lacks a thick, concentrated coal section where large 

volumes of gas might have been generated and expelled. The mud-logs also note fine-grained carbonaceous 

(lignite) material in sandstone, siltstone and shale samples within the Roslyn section. This organic material 

may be a widespread, disseminated source for natural gas. But by qualitative estimate, the overall volume of 

coal and carbonaceous material within the Roslyn Fm in the subsurface appears to be relatively low, while 

the total volume of porous sandstone and tuff appears to be quite high. This implies that the available

source rocks may have inadequate to fully de-water and gas-saturate the porosity in the Pasco basin. 

Additional studies of source rock volumes are recommended. 

One of the deep wells - Shell Bissa No. 1-29 (Sec. 29, T. 18 N., R. 21 E.) penetrated a thick section of 

black shale and limestone near total depth which has been identified as Eocene Swauk Formation 

(Campbell, 1989). Shows of heavy gases (C3, C4 and iC4), traces of oil in the drilling mud, oil stain, 

fluorescence and yellow solvent cuts were noted in an untested sandstone at 13,570 ft, just above the black 

shale section. Fluorescence and yellow cut were noted in samples of limestone at 13,760 ft, within the 

black shale. The Swauk Fm may contain oil-prone, organic-rich source rocks, and might be the source of 

condensates and heavy gases in the Roslyn Basin. The hydrocarbons encountered in the seven exploratory 

wells may have been derived from a dual-source system. Methane and light gases may have been expelled 

mainly from thin coal beds and disseminated carbonaceous material in the Roslyn Fm. Light oil, condensate 

and heavy gases may have migrated vertically from the shales Swauk Fm. Further study is needed to 

evaluate these possibilities. 

Based on the results of the seven exploratory wells drilled to date, it appears important to locate 

structural or stratigraphic traps where gas and condensate might be concentrated, and to carefully avoid 

perforating and/or fracturing reservoirs which produce water. The frequent discovery of water-producing 

zones makes the exploration process more difficult and more risky. The search for commercial hydrocarbon 

traps in the Pasco basin is complicated by the challenges involved in acquiring reliable geophysical images 

of potential structural or stratigraphic traps beneath the thick basalt flows.

CONCLUSIONS 

The Pasco basin has many of the prerequisites of a typical basin-center gas accumulation, including 

overpressures, high temperatures, thermally mature gas-prone source rocks, gas and condensate shows, and 

tight, low porosity sandstone reservoirs. Twenty formation tests have been conducted in several deep 

exploratory wells which have evaluated the Eocene-age Wenatchee, Roslyn and Swauk formations below the 

Columbia Basalt flows. Six of the twenty tests were unproductive, with no measurable fluids or gas 

recovered. Six tests recovered gas and/or condensate without any water, and eight tests recovered water or 

gassy water at moderate to high flow rates. Four hydraulic fracture stimulations were attempted to improve 

flow rates. One of these resulted in gas and condensate production at rates of 3100 MCFD and 6 BCPD 

from a thin sandstone reservoir with good porosity. But this reservoir interval was sandwiched in between 

upper and lower zones which produced water at high rates. Another fracture stimulation resulted in gas 

production at 500 MCFD, but the rate soon declined to 150 MCFD and the zone was abandoned. Another 

stimulation apparently connected a gas-producing reservoir to a water-bearing zone, and caused increased 

water production. The results of fracture stimulations have been mixed, and indicate significant risk of 

connecting gas reservoirs with water-producing zones. 

Four of the six tests which recovered gas without water indicate a possible gas-saturated interval 

between 10,604 ft and 12,450 ft in the Shell Yakima Mineral Co. No. 1-33 well. Gas was recovered at flow 

rates of 10 to 500 MCFD in this section. But water was produced at very high rates during formation tests 

above and below this zone, so additional testing is needed to confirm if the section is continuously gassaturated. 

The sedimentary section below the flood basalts evidently contains several water-bearing zones which 

are inter-bedded with gas-producing reservoirs. This implies that the available porosity in the sedimentary 

section is only partially saturated with hydrocarbons. The limited data available at this time indicate that the 

Pasco basin is almost, but not quite an unconventional, continuous-type basin-center gas accumulation. 

The volume of mature source rocks may be relatively low, and the gas expelled may have been insufficient 

to de-water and gas-saturate the available porosity. The sedimentary section may be cross-cut by several 

fault and fracture zones which serve as pathways for gas and fluids migrating upward into shallower zones.


Baksi, A.K., 1989, Reevaluation of the timing and duration of extrusion of the Imnaha, Picture Gorge, 

and Grande Ronde Basalts, Columbia River Basalt Group: in Reidel, S.P. and Hooper, P.R., 

editors, Volcanism and Tectonism in the Columbia River Flood-Basalt Province, GSA Special 

Paper 239, p. 105-111. 

Campbell, N.P., 1981, Geologic evaluation of the Great Western Oil Company oil and gas leases, 

Yakima County, Washington: consultant’s report. c/o Denver Earth Resources Library. 

Campbell, N.P., 1989, Structural and stratigraphic interpretation of rocks under the Yakima fold belt, 

Columbia Basin, based on recent surface mapping and well data: in Reidel, S.P. and Hooper, 

P.R., eds., Volcanism and Tectonism in the Columbia River Flood-Basalt Province, GSA 


Davis, G.A., Monger, J.W., and Burchfiel, B.C., 1978, Mesozoic construction of the Cordilleran 

“collage,” central British Columbia to central California: in Howell, D.G. and McDougall, 

K.A., eds., Mesozoic Paleogeography of the Western U. S., Pacific Section SEPM Pacific 

Coast Paleogeography Symposium no. 2, p. 1-32. 

Fisk, L.H. and Fritts, S.G., 1987, Field guide and road log to the geology and petroleum potential of 

North-Central Oregon: Northwest Geology, v. 16, p. 105-125. 

Fritts, S.G. and Fisk, L.H., 1985a, Tectonic model for formation of Columbia basin: implications for 

oil, gas potential of North Central Oregon: Oil & Gas Journal, v. 83, no. 34, August 26, 1985, 

p. 84-88. 

Fritts, S.G. and Fisk, L.H., 1985b, Structural evolution of south margin-relation to hydrocarbon 

generation: Oil & Gas Journal, v. 83, no. 35, September 2, 1985, p. 85-90. 

Halpin, D.L. and Muncey, G., 1982, Magnetotelluric Survey in the Northern Columbia River Plateau 

of South-central Washington: Geotronics Corporation, Austin, Texas, 70 p., report available at 

Denver Earth Resources Library, Denver, CO. 

Hammer, A.A., 1934, Rattlesnake Hills Gas Field: American Association of Petroleum Geologists 

Bulletin, v. 18, p. 847-855. 

Johnson, V.G., Graham, D.L. and Reidel, S.P., 1993, Methane in Columbia River basalt aquifers: 

isotopic and geohydrologic evidence for a deep coal-bed gas source in the Columbia Basin, 

Washington: American Association of Petroleum Geologists Bulletin, v. 77, no. 7, p. 1192- 

1207. 

Law, B.E., 1995, Play 503, Hypothetical Basin Center Gas Play, Columbia River Basin: in Gautier, 

D.L., Dolton, G.L., Takahahi, K.I. And Varnes, K.L., editors, 1995 National Assessment of 

United States Oil and Gas Resources-Results, Methodology, and Supporting Data: USGS 

Digital Data Series DDS-30. 

Law, BE. and Dickinson, W. W., 1985, Conceptual model for origin of abnormally pressured gas 

accumulations in low-permeability reservoirs: American Association of Petroleum Geologists 

Bulletin, v. 69, no. 8, p. 1295-1304. 

Law, B.E. and Spencer, C.W., 1993, Gas in tight reservoirs- an emerging major source of energy: in 

Howell, D.G., ed., The Future of Energy Gases: U. S. Geological Survey Professional Paper 

1570, p. 233-252.

Lingley, W.S. Jr. And Walsh, T.J., 1986, Issues relating to petroleum drilling near the proposed highlevel 

nuclear waste repository at Hanford: Washington Geologic Newsletter, v. 14, no. 3, p. 10- 

19. 

McFarland, C., 1979, History of oil and gas exploration in the state of Washington: Washington 

Geologic Newsletter, v. 7, no. 3, p. 1-3. 

Spencer, C.W., 1989, Review of characteristics of low permeability gas reservoirs in the western 

United States: American Association of Petroleum Geologists Bulletin, v. 73, no. 5, p. 613- 

629. 

Summer, N.S. and Verosub, K.L., 1987, Extraordinary maturation profiles of the Pacific Northwest: 

Oregon Geology, v. 49, no. 11, p. 135-140. 

Summer, N.S. and Verosub, K.L., 1992, Diagenesis and organic maturation of sedimentary rocks under 

volcanic strata, Oregon: American Association of Petroleum Geologists Bulletin, v. 76, no. 8, 

p. 1190-1199. 

Terra Graphics, Inc., 1981, Oil and Gas Map of Washington and Oregon. 

Tolan, T.L. and Reidel, S.P., 1989, Structure map of a portion of the Columbia River Flood-Basalt 

Province: in Reidel, S.P. and Hooper, P.R., eds., Volcanism and Tectonism in the Columbia 

River Food-Basalt Province, GSA Special Paper 239, map pocket.

124° 122° 120° 118° 

WASHINGTON 

0 5 10 20 

MILES 

Columbia 

OREGON 

Colu mbia 

YAKIMA 

PASCO 

PASCO BASIN 

Figure 1. Map showing the approximate outline of the Pasco Basin, central Washington. Modified from Campbell (1989, p. 217). 

River 

River 

S nake 

River 

IDAHO 

48° 

47° 

46° 

45°

A 

Scale: 

C 

DAN 

ELLENSBURG 

YAKIMA 

6 Miles 

SYM 1 

MUG 

C' 

SB1 

MBN 

Columbia 

HS 1 

B 

SRS 1 

15E 20E 25E 30E 5N 

SQ 1 

SBN 1 

RHGF 

River 

PASCO 

A' 

B' 

DAB 1 

Snake River 

Figure 2. Map showing Pasco, Yakima, Ellensburg, Columbia and Snake Rivers, and the locations of 

key wells and cross sections in the Pasco basin. Modified after Terra Graphics (1981), Johnson 

and others (1993, p. 1193), and Campbell (1989, p. 211). SD1 = Shell Darcell No. 1; DAB1= 

Development Associates Basalt Explorer No. 1; SQ1 = Shell Quincy No. 1; SBN1 = Shell 

Burlington Northern No. 1; SRS1 = Standard Oil Rattlesnake Hills No. 1; RHGF = Rattlesnake 

Hills Gas Field; HS1= P.G. Hunt Snipes No. 1; MUG = Miocene Union Gap well; SYM1 = Shell 

Yakima Mineral Company No. 1; MBN = Meridian Oil Co. B.N. No. 23; SB1 = Shell Bissa No. 1; 

DAN = Development Associates NORCO No. 1. 

25N 

20N 

15N 

SD 1 

10N


0 

8 

16 

24 

A A' 

ROSLYN 

Basalt 

NACHES 

ROSLYN 

SWAUK 

PASCO BASIN 

W E 

ROSLYN 

SWAUK 

GRANITE 

AND GNEISS 

Figure 3. Cross section showing an interpretation of the Pasco basin as a rift graben structure. Not to scale. Modified from 

Fritts and Fisk ( 1985b, p. 87).

PERIOD/ 

EPOCH 

PLEISTOCENE 

PLIOCENE 

MIOCENE 

OLIGOCENE 

EOCENE 

PALEOCENE 

CRETACEOUS 

JURASSIC 

AGE 

Ma 

3.3 

8.5 

13.5 

14.5 

15.6 

17.5 

30 

40 

47 

48 

54 

55 

63 

93 

138 

150 

205 


Basalt Group 

FORMATION LITHOLOGY 

Hanford 

Ringold 

Saddle Mountains 

Basalt 

Wanapum Basalt 

Grande Ronde Basalt 

Imnaha Basalt 

Wildcat Creek 

Wenatchee 

Ohanapecosh 

Naches 

Roslyn 

Teanaway 

Swauk 

Stuart 

Batholith 

Ingalls Metamorphic 

Complex 

Basalt and tuff 

Rhyolite and basalt flows 

interbedded with 

tuff and sandstone 

Arkosic and tuffaceous 

sandstone, siltstone, 

shale, coal, and 

conglomerate 

Basalt flows and tuff 

Lacustrine black shale, 

limestone, arkosic sandstone, 

conglomerate 

Granodiorite and 

quartz diorite 

Schist, amphibolite, 

gneiss, serpentine 

Figure 4. Stratigraphic units in the Pasco Basin, central Washington. Modified after Campbell 

(1989, p. 212) and Johnson and others (1993, p. 1195).


SOUTH NORTH 

4 

Sea 

level 

- 4 

- 8 

- 12 

- 16 

- 20 

B B' 

STANDARD OIL 

RATTLESNAKE No.1 

(1958) 

PASCO BASIN 

26 mi 

COLUMBIA 

RIVER 

BASALT 

GROUP 

SHELL 

B.N. No.1 

(1983) 

18 mi 

? ? ?? ? ? ? 

ROSLYN FM 

WENATCHEE FM 

? ? ? ? 

SWAUK FM 

? ? ? ? 

BASEMENT 

? 

? 

? 

? 

SHELL 

QUINCY No.1 

(1988) 

ROSLYN 

FM 

METAMORPHIC 

BASEMENT 

COLUMBIA 

RIVER 

BASALT 

GROUP 

? 

? 

? 

? 

40 mi 

? 

? 

? 

? 

? 

DEVELOPMENT 

ASSOCIATES 

BASALT 

EXPLORER No.1 

(1960) 

GRANITIC 

BASEMENT 

Figure 5: Correlation Diagram B-B’ showing key wells and stratigraphic units. Not to scale. 

Perforations 

VERTICAL SCALE: 1 in = 4,000 ft 

HORIZONTAL: NOT TO SCALE


SOUTH NORTH 

4 

Sea 

level 

- 4 

- 8 

- 12 

- 16 

- 20 

C C' 

SWAUK 

FM ? 

MIOCENE P. Co. 

UNION GAP 

(1929) 

BASEMENT ? 

TEANAWAY FM 

15 mi 

COLUMBIA 

RIVER 

BASALT 

GROUP 

? 

? 

? 

SWAUK FM ? 

BASEMENT ? 

OHANAPECOSH 

FM 

? 

STUCK PIPE 

? 

? 

? 

ROSLYN FM 

? 

PASCO BASIN 

SHELL 

YAKIMA M. Co. No.1 

(1980) 

DST 

? 

STUCK PIPE 

14 mi 

POSSIBLE 

GAS-SATURATED 

INTERVAL 

? 

? 

? 

? 

? 

? 

MERIDIAN 

B.N. No. 23 

(1989) 

? ? 

? 

? 

? 

11 mi 

COLUMBIA 

RIVER 

BASALT 

GROUP 

ROSLYN FM 

? 

SWAUK FM 

Perforations 

SHELL 

BISSA No.1 

(1982) 

GRANITIC 

BASEMENT 

VERTICAL SCALE: 1 in = 4,000 ft 

HORIZONTAL: NOT TO SCALE 

Figure 6: Correlation Diagram C-C’ showing key wells and stratigraphic units. Not to scale.

Table 1 Pasco Basin Well Data 

Well Name No. County Sec. T. R. Formation Depth Mud BHT Ro at Depth SIP Pgrad Perm Porosity Test Results, Cores, Comments 

ft ppg degF %, ft psi psi/ft mD % 

Shell Darcell 1-10 Walla 10 10 N. 33 E. basement 8,556 11.8 158 Base of Basalt=7820 ft. Tuff + Ss. Basement = gneiss at 8390 ft. 

P.J. Hunt Snipes 1 Yakima 33 10 N. 22 E. 1,176 Basalt to 1079 ft. Green shale to 1176 ft with gas shows, water flows. 

Standard Oil Rattlesnake 1 Benton 15 11 N. 24 E. basalt 9,495 68.0 230 Deep test at Rattlesnake Gas Field. TD = 10650 ft in basalt. 

Miocene Petr. Co. Union Gap Yakima 17 12 N. 19 E. Swauk ? 3,810 Basalt to 1811 ft. Shale + ls to 3811 ft with gas +oil shows, water flows. 

Bailey 1 Yakima 24 14 N. 17 E. basalt 530 TD in basalt. Tested 500 MCFD ? Gas = 69% N2 + 28% CH4. 

Shell Yakima Mineral Co. 1-33 Yakima 33 15 N. 19 E. Wildcat Ck 5,800 Perf'd 5,770-5,880 ft, rec 1,030 bwpd + trace of gas. Abd. 

Shell Yakima Mineral Co. 1-33 Yakima 33 15 N. 19 E. Ohanapecosh 7,700 Perf'd 7,535-8,040 ft, rec gas at 27 MCFD + 1700 bwpd. Abd. 

Shell Yakima Mineral Co. 1-33 Yakima 33 15 N. 19 E. Roslyn 10,796 228 1.1% at 10,810 ft Perf'd 10,604-10,930 ft, rec gas at 10 MCFD. Abd. 

Shell Yakima Mineral Co. 1-33 Yakima 33 15 N. 19 E. Roslyn 11,240 1.2% at 11,020 ft Perf'd 11,202-11,256 ft, acidized, rec gas at 85 MCFD. Abd. 

Shell Yakima Mineral Co. 1-33 Yakima 33 15 N. 19 E. Roslyn 11,746 15.0 244 1.38% at 11,870 ft Perf'd 11,598-11,652 ft, acidized, rec gas at 75 MCFD. Abd. 

Shell Yakima Mineral Co. 1-33 Yakima 33 15 N. 19 E. Roslyn 12,400 15.0 Perf'd 12,430-380 ft, acidized, frac'd, rec gas at 500 to 150 MCFD. Abd. 

Shell Yakima Mineral Co. 1-33 Yakima 33 15 N. 19 E. Roslyn 13,968 15.0 314 Perf'd 12,976-13,568 ft, flowed 570 MCFD & 5400 BWPD. Abd. 

Shell Yakima Mineral Co. 1-33 Yakima 33 15 N. 19 E. Roslyn 15,500 16.0 Perf'd 15,466-15,540 ft, acidized, rec trace of gas, no flow rate. Abd. 

Shell Yakima Mineral Co. 1-33 Yakima 33 15 N. 19 E. Teanaway 15,865 16.0 362 Stuck pipe at 16,199 ft. Top of fish= 15,870 ft. 

Shell Yakima Mineral Co. 2-33 Yakima 33 15 N. 19 E. Wildcat Ck 5,609 13.0 158 400 mD 10-20% Perf'd 5,133-5,174 ft, rec trace of gas. Abd. Basalts + tuff to 5,100 ft. 

Shell Yakima Mineral Co. 2-33 Yakima 33 15 N. 19 E. Wildcat Ck 5,609 13.0 158 Perf'd 5,282-5,322 ft, acidized, rec trace of gas. Abd. Cut 7 Cores. 

Shell Yakima Mineral Co. 2-33 Yakima 33 15 N. 19 E. Wildcat Ck 5,609 13.0 158 250 mD 10-15% Perf'd 5,360-5,397 ft, acidized, rec gas at 25 - 50 MCFD. Abd. 

Shell Burlington Northern 1-9 Grant 9 15 N. 25 E. Wenatchee 12,177 9.6 200 0.6% at 12,000 ft Basalt to 11,500 ft. Thin ss, sh, coal beds. Gas shows. Cut 9 cores. 

Shell Burlington Northern 1-9 Grant 9 15 N. 25 E. Roslyn 12,696 13.5 Perf'd 12,694-12,699 ft, rec gas at 2.4 MMCFD + 134 bwpd (L+W, 1986). 

Shell Burlington Northern 1-9 Grant 9 15 N. 25 E. Roslyn 12,792 13.5 8100.0 0.64 BHP = 8,100 psi at 12,696 ft (0.64 psi/ft) before fracturing stimulation. 

Shell Burlington Northern 1-9 Grant 9 15 N. 25 E. Roslyn 12,700 13.5 9065.0 0.72 DST at 12,792 ft, FSIP=9,065 psi (0.72 psi/ft), rec NR. 

Shell Burlington Northern 1-9 Grant 9 15 N. 25 E. Roslyn 12,800 13.9 Perf'd 12,880-694 ft, rec 553 MCFD. Frac'd 12,880-694 ft, rec 

Shell Burlington Northern 1-9 Grant 9 15 N. 25 E. Roslyn 2,395 MCFD & 5 bwph. Prefrac kh=1.33 mDft, Postfrac kh=2.02 mDft. 

Shell Burlington Northern 1-9 Grant 9 15 N. 25 E. Roslyn 13,300 14.4 Perf'd 13,288-304 ft, flowed water at 5 bwph. Zeolites below 13,100 ft. 

Shell Burlington Northern 1-9 Grant 9 15 N. 25 E. Roslyn 13,380 14.4 7800.0 0.58 0.23 mD 5 - 10% Perf'd 13,372-388 ft, rec 350 MCFD + 9 bwpd. Frac'd, rec 3100 MCFD 

Shell Burlington Northern 1-9 Grant 9 15 N. 25 E. Roslyn + 6 BCPD. Pre-frac kh= 3.8 mDft, post-frac kh= 7.1 mDft. CO2 + H2S. 

Shell Burlington Northern 1-9 Grant 9 15 N. 25 E. Roslyn 14,190 14.5 1.1% at 15,120 ft Perf'd 14,052-340', no flow, acidized, swabbed 3 bwph, tr gas+H2S. 

Shell Burlington Northern 1-9 Grant 9 15 N. 25 E. Roslyn 17,518 15.3 334 1.3% at 15,820 ft TD= 17,518 ft in ss and tuff with chlorite + zeolite matrix. 

Meridian B.N. 23-35 Kittitas 35 17 N. 20 E. Wenatchee 8,925 10.6 131 Basalt to 6680 ft, tuff to 7860 ft. RoslynFm, ss, coal and tuff to TD. 

Meridian B.N. 23-35 Kittitas 35 17 N. 20 E. Roslyn 11,372 12.3 194 >6700 >0.55 DST 12,584-11,919 ft, rec cushion, 3600 ft fm water with 500 ppm cl-. 

Meridian B.N. 23-35 Kittitas 35 17 N. 20 E. Roslyn 12,584 12.4 240 Stuck DST tool, left fish in hole. Abd. 

Shell Bissa 1-29 Kittitas 29 18 N. 21 E. Roslyn 8,393 9.2 175 0.53% at 9,220 ft Basalt to 4,580 ft. Perf'd 8,486-800 ft, rec trace of gas. Abd. 

Shell Bissa 1-29 Kittitas 29 18 N. 21 E. Roslyn 9,763 9.5 158 Perf'd 9,436-830 ft, rec trace of gas. Abd. 

Shell Bissa 1-29 Kittitas 29 18 N. 21 E. Roslyn 10,978 10.3 174 0.57% at 10,080 ft Perf'd 10,314-898 ft, acidized, rec trace of gas. Abd. 

Shell Bissa 1-29 Kittitas 29 18 N. 21 E. Roslyn 12,324 12.7 220 Heavy laumontite, zeoloite cements below 11,320 ft, no visible porosity. 

Shell Bissa 1-29 Kittitas 29 18 N. 21 E. Swauk 13,510 14.6 218 Gas show at 13,560', oil in mud, fluorescence and cut, not tested. 

Shell Bissa 1-29 Kittitas 29 18 N. 21 E. basement 14,965 17.3 270 Swauk Fm, sh, ls, ss below 13,655 ft. Granitic basement at 14,920 ft. 

Shell Quincy 1 Grant 22 18 N. 25 E. Roslyn 11,835 12.5 218 Basalt to 7200 ft. Ss + tuff to 12,790'. Coal bed, gas show at 10,200 ft. 

Shell Quincy 1 Grant 22 18 N. 25 E. basement 13,202 13.9 239 Metamorphic basement at 12,790 ft. No tests reported. Abd. 

Dev. Assoc. Basalt Explorer 1 Lincoln 10 21 N. 31 E. basement 4,682 138 Basalt to 4,465 ft, ss, sh, ss. Granitic basement at 4,667 ft.Abd. 

Dev. Assoc. Norco 1 Chelan 26 22 N. 20 E. Swauk ? 4,903 0.5% at 4,850 ft Drilled in 1935. Several gas shows. Re-entered, logged in 1974. Abd.

1 

POTENTIAL FOR A BASIN-CENTERED GAS ACCUMULATION IN THE RATON 

BASIN, COLORADO AND NEW MEXICO 

INTRODUCTION 

By Ronald C. Johnson and Thomas M. Finn 

The Raton Basin covers an area of about 4,000 square miles of southeastern Colorado and northeastern 

New Mexico. The basin is bounded on the west by the Sangre de Cristo Mountains, on the north by the 

Wet Mountains, on the southeast by the Sierra Grande arch, on the east by the Las Animas arch and on the 

northeast by the Apishapa arch (Figure 1). The basin is highly asymmetrical with the deep axis just east of 

the Sangre de Cristos. The east flank of the basin gently tilted toward the west at from 1 to 5 degrees 

whereas steep dips and thrust faults occur along the west flank adjacent to the Sangre de Cristo Mountains. 

The Raton Basin is in the southeastern part of the area in the Rocky Mountain region that was affected by 

the Laramide orogeny (Late Cretaceous through Eocene). 

The Raton Basin contains a thick stratigraphic section of Devonian through Recent rocks (Figure 2). 

The units considered most likely to contain a basin-centered gas accumulation include the Upper Cretaceous 

Trinidad Sandstone, Upper Cretaceous Vermejo Formation, Upper Cretaceous and Paleocene Raton 

Formation, and the Paleocene Poison Canyon Formation. 

The marginal marine Trinidad Sandstone conformably overlies the Pierre Shale throughout the basin 

and was deposited along an eastward prograding shoreline during the final retreat of the Cretaceous seaway 

from northern New Mexico and southern Colorado. It was deposited in shallow marine, shoreface, and 

deltaic environments (Pillmore and Maberry, 1976; Billingsley, 1977). The Trinidad Sandstone varies from 

0 to over 300 ft thick (Rose and others, 1986). It is truncated by the Poison Canyon Formation in the 

northernmost part of the basin. 

The Late Cretaceous Vermejo Formation conformably overlies the Trinidad Sandstone. The Vermejo 

Formation varies from 0 to 380 ft thick (Figure 2). It is truncated by the Poison Canyon Formation in the 

northernmost part of the basin. It was deposited in fluvial channel, overbank-levee, crevasse splay, 

floodplain lake, low-lying and raised mire environments environments (Strum, 1985; Flores, 1987; Flores 

and Pillmore, 1987). Total coal in the Vermejo Formation ranges to over 30 ft (Tyler and others, 1995). 

The Raton Formation varies from 0 to 2,100 ft thick in the basin (Figure 2). It is unconformable with 

the underlying Vermejo Formation throughout much of the basin. It is divided into a basal conglomeratic 

interval, a lower coal-rich interval, a sandstone-dominated interval, and an upper coal-rich interval (Figure 

3). The Cretaceous-Tertiary boundary is conformable in the Raton Basin and occurs near the top of the 

lower coal-rich interval (Figure 2) (Tsudy and others, 1984; Pillmore and Flores, 1984). The basal 

conglomerate is as much as 50 ft thick and consists of interbedded pebble conglomerate and quartzose 

sandstone (Pillmore and Flores, 1987). The lower coal-rich zone varies from 100 to 250 ft thick and the 

upper coal-rich zone varies from about 600 to 1,100 ft thick. Both are composed of interbedded sandstone, 

siltstone, mudstone, carbonaceous shale and coal. The coaly intervals include lenticular channel sandstones 

and thin comparatively persistent crevasse splay sandstones (Figures 4 and 5). Total net thickness of coal in 

the Raton Formation ranges to over 140 ft (Tyler and others, 1995). The sand-dominated interval separates 

the two coal-rich zones and varies from 180 to 600 ft thick. Sandstones are coarsest in the sand-dominated 

interval. Estimates of total coal in both the Vermejo and Raton formations vary from 1.5 to 4.8 billion 

short tons (Read and others, 1950: Wanek, 1963), however, more recently Amuedo and Bryson (1977) 

estimated 5 billion short tons in the Vermejo Formation alone. 

The Poison Canyon Formation is as much as 198 m thick and conformably overlies and intertongues 

with the Raton Formation (Figure 2) (Johnson and Wood, 1956; Flores, 1987). The Formation consists of 

interbedded coarse-grained conglomeratic sandstone, mudstone and siltstone (Hills, 1888; Johnson and 

others, 1966), and becomes finer-grained towards the east in the basin. The Poison Canyon contains little 

coal or carbonaceous shale. 

The Raton Basin was extensively intruded by dikes, sills, laccoliths, and stocks in middle to late 

Tertiary time. A major intrusive center of Miocene age (26 to 22 Ma), thought to represent the roots of 

breached volcanoes (Steven, 1975), occurs in the northern part of the basin (Figure 1). Two of these 

breached intrusions form East and West Spanish Peaks which tower over the basin at elevations of 12,683

ft and 13,724 ft respectively. Dikes and sills related to this intrusive center occur throughout the northern 

part of the basin. Sills related to this intrusive center have followed coal beds destroying tremendous 

quantities of coal in this area (Carter, 1956). 

COAL RANK IN THE RATON BASIN 

Coal ranks at the base of the Vermejo Formation vary from a vitrinite reflectance of 0.57% around the 

margins of the northern part of the basin to 1.58% along the Purgatoire River in the central part of the 

basin. Coal ranks of anthracite or greater occur locally near intrusions (Jurich and Adams, 1984). The 

unusually high coal ranks along the Purgatoire River are unusual in that they do not occur near the major 

intrusions found further to the north in the basin. Wells drilled near the river have, however, encountered 

some sills (ARI Inc., 1991) which may have played a role in elevating coal ranks. Merry and Larsen (1982) 

suggested that the high coal ranks may be due to a combination of deep burial during the Pliocene and 

proximity to intrusions. Tyler and others (1991) suggested that hot waters ascending to an ancestral 

Purgatoire River may account for the high values near the river. 

COALBED METHANE IN THE RATON BASIN 

It has long been known that coals in the basin contain large amounts of methane. Nearly all coal mines 

in the Raton Basin encountered some gas. Jurach and Adams (1984) reported that 2 million cubic feet of 

methane per day was being ventilated from just three mines in the west-central part of the basin. Reported 

gas contents for coal in the Vermejo Formation vary from 115 to 492 ft 3 /short ton (3.6-15.5 cm 3 /gm) while 

coals in the Raton Formation contain from 23 to 193 ft 3 /short ton (0.72-6.07 cm 3 /gm) (Tyler and others, 

1995). As of 1998 there were about 85 coalbed methane wells in the Raton Basin producing about 17.5 

million cubic feet of gas per day (Johnson and Flores, 1998) with a significant number of new coalbed 

methane wells having been drilled since 1998. Wells are completed mainly in the Vermejo Formation. 

Production thus far is concentrated in a 25 by 15-mile northeast trending area near the Purgatoire River, 

west of Trinidad in and area where coal ranks are unusually high. Coalbed methane exploration began in the 

Raton Basin by Amoco in 1980 at their Cottontail Pass unit. The best wells in Amoco’s unit yielded more 

than 590 MCFD. Maximum depth for coalbed methane wells in the basin is about 2,400 ft in the 

northwest part of Amoco’s Cottontail Pass unit. 

GEOLOGY OF BASIN-CENTERED GAS ACCUMULATIONS 

Extensive basin-centered gas accumulations have been identified in many Rocky Mountain basins that 

formed during the Laramide orogeny (Late Cretaceous through Eocene). Reservoirs within basin-centered gas 

accumulations typically have low permeabilities (in-situ permeability to gas of 0.1 millidarcy or less) and 

are commonly referred to as tight reservoirs (Spencer, 1989). These accumulations differ from conventional 

hydrocarbon accumulations in that they: (1) cut across stratigraphic units, (2) commonly occur structurally 

down dip from more permeable water-filled reservoirs, (3) have no obvious structural and stratigraphic 

trapping mechanism, and (4) are almost always either overpressured or underpressured. The abnormal 

pressures of these reservoirs indicate that water in hydrodynamic equilibrium with outcrop is not the 

pressuring agent. Instead, hydrocarbons within the tight reservoirs are thought to provide the pressuring 

mechanism (Spencer, 1987). 

Masters (1979) was one of the first to study these unique accumulations, which occur downdip from 

more permeable, water-wet rocks. Masters (1979) proposed that gases generated in the deep, thermally 

mature areas of sedimentary basins with low-permeability rocks, are inhibited from migrating upwards and 

out of the basin by a capillary seal. Masters (1979) pointed out that low-permeability rocks (1 md), with 

40% water saturation, are only three-tenths as permeable to gas as they are to water, and at 65% water 

saturation, the rock is almost completely impervious to the flow of gas. The concepts for the development 

of basin-centered gas accumulations in the Rocky Mountains have been further refined by a number of 

2

workers such as Jiao and Surdam (1993), Meissner (1980; 1981; 1984), McPeek (1981), Law, 1984; Law 

and others (1979; 1989), Law and Dickinson (1985), MacGowan and others (1993), Spencer and Law 

(1981), Spencer (1985; 1987), and Yin and Surdam (1993). In general, the conceptual models suggest that 

overpressuring, which is commonly encountered in these basin-centered accumulations, is the result of 

volumetric increases during hydrocarbon generation by the coals, carbonaceous shales, and marine shales 

that are interbedded with the sandstone reservoir rocks. Law (1984) suggested that migration distances from 

source rock to reservoir rock in the basin-centered gas accumulation of the Greater Green River Basin of 

Wyoming, Colorado, and Utah are generally less than a few hundred feet. Much of the water that originally 

filled the pore spaces in the potential reservoirs is driven out by hydrocarbons (Law and Dickinson, 1985). 

According to Law and Dickinson (1985), the capillary seal is activated as gas replaces water in the pore 

space, and hence the basin-centered gas accumulations seal themselves as they form. These seals are so 

efficient that they may be able to maintain abnormally high pressures for tens of millions of years 

(MacGowan and others, 1993). 

Many basin-centered gas accumulations in Rocky Mountain basins are partially to totally 

underpressured, and it is believed that all of these underpressured areas were overpressured at some time in 

the past (Meissner, 1978; Law and Dickinson, 1985). Moreover, it is believed that a previous period of 

overpressuring would have been necessary to drive much of the water out of the system. A change from 

overpressured to underpressured conditions can occur as a result of cooling related to uplift and erosion or to 

a decrease in thermal gradients (Meissner, 1978; Law and Dickinson, 1985). Most of the cooling in Rocky 

Mountain basins has occurred within the last 10 my as the onset of major regional uplift initiated a period 

of rapid downcutting throughout region. For a summary of the evidence for late Cenozoic uplift in the 

Rocky Mountain region see Keefer (1970) and Larson and others (1975). Overpressured areas became 

underpressured during cooling as gas contracts and the rate of gas generation decreases (Meissner, 1978; Law 

and Dickinson, 1985). Surface water enters the basin-centered accumulation through newly created 

permeability pathways created as pore throats and fractures dilate. According to Meissner (1978) this 

contraction may ultimately result in a “dead” basin where the basin-centered accumulation has been 

completely dissipated. Many Rocky Mountain basin-centered gas accumulations have underpressured zones 

surrounding an overpressured central core indicating that this process has only partially run to completion. 

The underpressured zone will grade outward into a predominantly water-bearing zone that is in pressure 

equilibrium with the local hydrodynamic regime. Any gas present in this water-bearing zone will be trapped 

in conventional reservoirs on anticlinal structures or in stratigraphic pinchouts. 

Levels of thermal maturity define areas where potential source rocks have generated gas at some time in 

the past and are commonly used as an indirect method of defining the limits of a basin-centered gas 

accumulation. Masters (1984, p. 27, Fig. 25) in a study of the basin-centered gas accumulation in the Deep 

Basin of Alberta, indicated that a vitrinite reflectance (Ro) of 1.0% corresponds approximately to the limit 

of the accumulation. In the Piceance Basin of western Colorado, Johnson and others (1987) used a vitrinite 

reflectance (Ro) of 1.1% to define the limits of the basin-centered gas accumulation. Ro values of from 0.73 

to 1.1% were used to define a transition zone containing both tight reservoirs and reservoirs with 

conventional permeabilities. Johnson and others (1996; 1999) used these same thermal maturity limits to 

help define the basin-centered gas accumulation in the Wind River Basin of Wyoming and the Bighorn 

Basin of Wyoming and Montana. In the Greater Green River Basin of Wyoming, Colorado, and Utah, Law 

and others (1989) used an Ro of 0.80% to define the top of overpressuring in the basin-centered gas 

accumulation. 

3

EVIDENCE FOR A BASIN-CENTERED GAS ACCUMULATION IN THE RATON 

BASIN 

Evidence for gas at shallow depths in Uppermost Cretaceous and Paleocene strata in the Raton basin 

was documented by Dolly and Meissner (1977). According to Dolly and Meissner (1977, p. 259) “gas flows 

encountered during the drilling and testing of exploratory and shallow water wells are of a nearly universal 

nature in sandstones, coals and fracture zones present in Poison Canyon, Raton, Vermejo, and Trinidad 

formations.” Dolly and Meissner (1977) describe sandstones in these formations as “tight, clay-filled” and 

similar to productive Cretaceous and Tertiary sandstones in many other Rocky Mountain basins. They site 

one well, the Filon no. 1 Golden Cycle in sec. 11 T. 29S., R. 67W. that tested 30 MCF of gas from a 

zone at 1,630 to 1,760 ft in the lower part of the Raton Formation. . An unusually low fluid pressure 

gradient of 0.25 psi/ft was noted by Dolly and Meissner (1977, p. 268) in the tested interval from this well 

indicating significant underpressuring. They noted that this pressure gradient corresponds to a potentiometric 

head of approximately 780 ft below the well site. Initial production testing after fracing with nitrogen foam 

and KCl inhibited water indicated a flow rate of 75 MCFPD and 1,500 barrels of water per day (BWPD). 

After two months, the well stabilized at about 72 MCFPD and 100 BWPD. It is unclear how much of the 

initial water production was frac water. Although Dolly and Meissner (1977, Fig. 13) clearly believed that 

discrete gas-water contacts existed in the productive lenticular sandstones, the presence of underpressured gas 

in tight reservoirs is characteristic of many basin-centered gas accumulations in the Ricky Mountain region. 

Underpressuring indicates that the reservoirs are isolated from the regional groundwater regime. 

More recently Rose and others (1986) used variations in resistivity logs to try to delineate the gassaturated 

basin-centered accumulation in just the Trinidad Sandstone in the northern part of the basin. The 

Trinidad is a marginal marine “blanket-like” sandstone that persists throughout the Raton Basin. This 

contrasts with the much more lenticular fluvial sandstones found in the nonmarine parts of the Upper 

Cretaceous and Paleocene section in the basin. Rose and others (1986) suggested that an analog to the 

Trinidad Sandstone may be the highly gas productive Upper Cretaceous marginal marine Pictured Cliffs 

Sandstone in the San Juan Basin to the west. The Pictured Cliffs Sandstone produces from stratigraphic 

traps formed by stratigraphic jumps toward the northeast (Meissner, 1984). 

Regional underpressuring at shallow depths in the Raton Basin has been documented by several workers 

(Howard, 1982; Geldon, 1990; Close and Dutcher, 1990; Tyler and others, 1995). A potentiometric surface 

map of the Vermejo-Raton aquifer constructed by Stevens and others (1992) and published by Tyler and 

others (1995, p. 170) indicates that underpressured conditions exist in the main coal-bearing intervals 

throughout most of the basin. Tyler and others (1995, p. 169-170) state that the pressure regime in the 

basin is poorly understood but list some of the possible causes for this underpressuring. They noted that 

low pressures indicate that the rocks are isolated from topographically high recharge areas along the west 

margin of the basin and suggest that low permeability in the sandstones and coal beds may limit hydrologic 

connection. 

4

DISCUSSION 

It has long been suspected that a substantial basin-centered type gas accumulation is present in Upper 

Cretaceous and Paleocene sandstones in the Raton Basin. Few attempts have been made to develop these 

resources because of the lack of gas pipelines out of the basin. Success with the current coalbed methane 

exploration in the basin will eventually alleviate this pipeline problem and should lead to new attempts to 

develop these sandstone gas resources. Gas resources found in coal beds and in adjacent sandstone reservoirs 

are developed concurrently in many Rocky Mountain basins. 

It is suggested here that the widespread gas shows encountered in the Vermejo and Raton formations 

along with abnormally low pressures indicates a basin centered gas accumulation developed in these units. 

Using analogs from other Rocky Mountain basins, sandstones where thermal maturities are greater than Ro 

1.1% were probably once overpressured and largely gas-saturated. At lower levels of thermal maturity, both 

gas-charged and water-wet sandstones were probably present. The big unanswered question in the Raton 

Basin is how much of the original accumulation is still intact? Present-day depths to the top of the 

Trinidad Sandstone are less than 3,500 ft throughout most of the basin except in the immediate vicinity of 

the Spanish Peaks were it obtains a depth of over 9,000 ft (Figure 7). The widespread reports of 

underpressured gas-saturated sandstones at shallow depths suggests that a largely intact basin-centered 

accumulation still exists in that part of the Trinidad Sandstone, Vermejo Formation and Raton Formation 

that was not eroded away as a result of regional uplift and downcutting. 

Coalbed gas and sandstone gas are typically developed together in Rocky Mountain basins. The San 

Juan Basin of New Mexico and Colorado has by far the most successful coalbed methane production the 

United States. Yet the original exploration targets were not the coal beds but the adjacent sandstones which 

were typically gas-charged (Dugan and Williams, 1988). Only after gas wells started experiencing increases 

in rates of production did operators begin to suspect that adjacent coal beds may be contributing 

significantly to production. At Grand Valley field in the Piceance Basin of western Colorado, lenticular 

fluvial sandstones interbedded with coals of the Cameo-Fairfield coal zone have become the principle 

exploration target in the field, although both coals and sandstones were originally targeted (Reinecke and 

others, 1991). Sandstones adjacent to the thick lower Tertiary coal beds in the Powder River Basin of 

Wyoming and Montana are typically gas-charged (Hobbs, 1978) and are increasingly becoming targets for 

exploration. Gas from coal beds and adjacent sandstone beds are typically commingled in the Upper 

Cretaceous Ferron play on the Wasatch Plateau in central Utah. 

It is suggested that within a few years the Raton Basin will evolve into both a coalbed methane play 

and a basin-centered sandstone gas play. At present, there appears to be no identified production in the Raton 

basin from sandstones within the basin-centered accumulation, and it is difficult to assess how successful 

this play will be. A more comprehensive study of this gas resource should be made once more reliable 

information is available concerning sandstone production characteristics in the basin. 

5


6 

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9. 

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7 

Johnson, R. C., Crovelli, R. A., Spencer, C. W., and Mast, R. F., 1987, An assessment of gas 

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Basin, Colorado: U.S. Geological Survey Open-File Report 87-357, 165p. 

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gas resources in the low-permeability basin-centered gas accumulation of the Bighorn Basin, 

Wyoming and Montana: U.S. Geological Survey Open-File Report 99-315-A, 123 p. 

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Larson, E. E., Ozima, M., and Bradley, W. C., 1975, Late Cenozoic basin volcanism in northwestern 

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Geological Society of America Memoir 144, p. 155-178. 

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Stroock, B., and Andrew, S., eds., Wyoming Geological Association Guidebook, Jubilee 

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Continuing Education Course Notes.

8 

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Hydrocarbon Source Rocks of the Greater Rocky Mountain Region: Rocky Mountain 


Merry, R. D., and Larsen, V. E., 1982, Geologic investigation of the methane potential of western 

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155 p. 

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Field Conference, p. 191-195. 

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Guidebook, vol. 3, p. 1-51. 

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9 

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Group, in Stroock, B., and Andrew, S., eds., Wyoming Geological Association Guidebook, 

Jubilee Anniversary Field Conference, p. 349-357.

Basin Axis 

Sangre De Cristo Mountains 

Stonewall 

0 15 Miles 

105° 

0 20 Kilometers 

Walsenburg 

Apishapa Arch 

Raton 

Sierra Grande Arch Las Animas 

Alluvium, slopewash, and 

landslide material 

Basalt flows 

Huerfano Formation 

Middle Tertiary intrusives 

Cuchara Formation 

Poison Canyon Formation 

Raton Formation 

Vermejo Formation 

Trinidad Sandstone and 

Pierre Shale undivided 

Pierre Shale/Niobrara undivided 

Precambrian rock undivided 

Raton Basin boundary 

Arch 

Colorado 

New Mexico 

N 

Colorado 

New 

Mexico 

Holocene and 

Quaternary 

} 

} 

Tertiary 

Cretaceous 

Raton Basin 

Figure 1: Generalized geologic map of the Raton 

Basin, Colorado and New Mexico. From Flores 

and Bader (1999). 

37°

TERTIARY 

MESOZOIC 

AGE 

PALEOCENE 


FORMATION NAME 

POISON CANYON 

FORMATION 

RATON 

FORMATION 

VERMEJO 

FORMATION 

TRINIDAD SANDSTONE 

PIERRE SHALE 

GENERAL DESCRIPTION 

SANDSTONE–Coarse to conglomeratic beds 13–50 feet 

thick. Interbeds of soft, yellow-weathering clayey 

sandstone. Thickens to the west at expense of 

underlying Raton Formation 

Formation intertongues with Poison Canyon Formation 

to the west 

UPPER COAL ZONE–Very fine grained sandstone, 

siltstone, and mudstone with carbonaceous shale 

and thick coal beds 

BARREN SERIES–Mostly very fine to fine grained 

sandstone with minor mudstone, siltstone, with 

carbonaceous shale and thin coal beds 

LOWER COAL ZONE–Same as upper coal zone; coal 

beds mostly thin and discontinuous. Conglomeratic 

sandstone at base; locally absent 

SANDSTONE–Fine to medium grained with mudstone, 

carbonaceous shale, and extensive, thick coal beds. 

Local sills 

SANDSTONE--Fine to medium grained; contains casts of 

Ophiomorpha 

SHALE--Silty in upper 300 ft. Grades up to fine grained 

sandstone. Contains limestone concretions 

{ {{ 

LITH- 

OLOGY 

APPROX. 

THICKNESS 

IN FEET 

500+ 

0?–2,100 

K/T Boundary 

0–380 

0–300 

1800-1900 

Figure 2: Generalized stratigraphic column for Cretaceous and Tertiary rocks in the Raton Basin. From 

Flores and Bader (1999), modified from Pillmore (1969), Pillmore and Flores (1987), and Flores (1987).

West East 

CRISTO MOUNTAINS 

COLO. 

N.MEX. 

w 

SANGRE DE 

0 

50 Miles 

0 50 Kilometers 

Coal 

Sandstone 

E 

Measured section 

Cross section 

N 

COLORADO 

NEW 

MEXICO 

INDEX MAP 

Siltstone and mudstone 

Poison Canyon Formation 

Basal Raton 

conglomerate 

VERMEJO FORMATION 

TRINIDAD SANDSTONE 

PIERRE SHALE 

See 

Figure SR-5 Sandstone-dominated 

interval 

Coarsening-upward 

megacycle 


megacycle 

RATON FORMATION 

Upper Coal Zone 

See Figure SR-4 

Lower Coal Zone 


megacycle 

Figure 3: East-west stratigraphic cross section across the southern part of the Raton Basin 

showing vertical and lateral variations in Upper Cretaceous and Paleocene rocks. The 

vertical variation is shown by the succession of coarsening-upward megacycles that 

divide the Cretaceous and Tertiary rocks. Modified from Flores (1987), Flores and 

Bader (1999). 

0 

300 

Feet

West East 

40 Feet 

1,000 Feet 

Coal 

Sandstone 



SUBSURFACE 

EROSIONAL 

Tin Pan 

Canyon coal 

SURFACE 

Potato 

Canyon coal 

SUBSURFACE 

Figure 4. Lateral and vertical variations of coal-bearing rocks in the lower part of the upper coal zone of the 

Raton Formation in the southern part of the basin. Modified from Strum (1984).

South North 

EROSIONAL 

SUBSURFACE 

York Canyon coal 

1,000 Feet 

SURFACE 

40 Feet 

Chimney Divide coal 

Coal 

Sandstone 



Figure 5. Lateral and vertical variations of coal bearing rocks in the upper part of the upper coal zone 

of the Raton Formation in the southern part of the basin. Modified from Strum (1984).

DOES THE FORBES FORMATION IN THE SACRAMENTO BASIN 

CONTAIN A 

BASIN-CENTER GAS ACCUMULATION ? 

ABSTRACT 


Well data, structural cross sections and published studies of abnormal pressures, methane isotopes, 

vitrinite reflectance measurements and thermal maturity were evaluated to determine if a basin-center gas 

accumulation might exist within the Cretaceous-age Forbes Formation in the Sacramento Basin, California. 

The Forbes Fm is a mud-rich turbidite system with thick marine shale deposits and discontinuous sandstone 

lenses. At least twenty-seven natural gas fields have been discovered in the Forbes Fm, mainly in traditional 

structural and stratigraphic traps with distinct gas-water contacts. 

Previous studies of source rock organic content show that the Forbes Fm contains low levels of gasprone 

organic material, mainly dispersed fragments of lignite, wood and land plants. A recent study of the 

Dobbins Shale notes extensive bioturbation and lack of laminations, indicating oxidizing conditions. 

Studies of source rock quality in outcrops along the western flank of the basin found low organic content 

throughout the Upper Cretaceous section. Thermal gradients and bottom hole temperatures are unusually 

low in the Sacramento Basin. Published vitrinite reflectance profiles show that the Forbes is immature to 

sub-mature throughout most of the basin. All Forbes gas production comes from thermally immature 

sandstone reservoirs with low temperatures (0.9% at 15,000 ft and 

Ro > 3% at approximately 26,000 ft. The lower Forbes, Dobbins, Funks and Yolo shales are probably 

within the gas generation window. If these source rocks are rich enough to generate large quantities of gas, a 

basin-center gas system might exist in the deepest parts of the Delta Depocenter. Several exploration wells 

have been drilled to 14,000 - 15,059 ft in this area. Well histories, well logs and drill stem test results were 

reviewed for evidence of basin-center gas conditions near total depth. High drilling mud densities indicate 

overpressures, but high-pressure salt water was recovered in several formation tests. The Forbes Fm is 

evidently still water-saturated at this depth. The formation test data do not indicate basin-center gas 

conditions in the 14,000 - 15,000 foot depth range. 

1

An ultra-deep basin-center gas system might exist below 16,000 ft in the Delta Depocenter, if gas 

expelled from mature source rocks has extensively saturated and de-watered the reservoirs. However, the 

complex Midland and Kirby Hills Fault zones may provide permeable migration paths for gas to escape 

from this deep gas kitchen. The gas kitchen may have been breached by faulting, and may have failed to 

become a continuous, basin-center gas accumulation. There have not yet been any wells drilled deep enough 

to evaluate this gas kitchen. The possibility of a basin-center gas accumulation in the Delta Depocenter 

should be considered highly speculative. 

INTRODUCTION 

The Upper Cretaceous-age Forbes Formation contains thick, mud-rich turbidite deposits with numerous 

discontinuous sandstone lenses which have been important targets for natural gas exploration in the 

Sacramento basin, California (fig. 1). At least twenty-seven commercial fields have produced gas from the 

Forbes Fm (table 1). The lower Forbes Fm and the underlying Dobbins Shale are highly overpressured 

throughout much of the basin, and most of the produced gas is over-mature methane, without any oil or 

condensate. This unusual combination indicates that a basin-center gas accumulation (Spencer, 1987; 1989; 

Law and Dickinson, 1985) might exist somewhere within the hydrocarbon system. 

Well data, drill stem test results, structural cross sections and previous studies of thermal maturity and 

abnormal pressures have been reviewed and evaluated to determine if a basin-center gas accumulation might 

exist within the Forbes Fm and/or Dobbins Shale. Results of the evaluation are presented below. Some 

characteristics of the Forbes gas system fit the typical basin-center gas model, but many do not. It is 

unlikely that the Forbes is extensively gas-saturated. However, a ‘gas kitchen’ may exist deep within the 

Delta Depocenter, a fault-bounded structural depression in the southwestern Sacramento basin. There may be 

a localized basin-center gas accumulation within this sub-basin. 


The Sacramento basin (fig. 1) is a north-south trending fore-arc depocenter located along the east flank 

of the Sierra Mountains in northern California (Ingersoll and Dickinson, 1990; Cherven, 1983). It is 

flanked on the east by granitic rocks and on the west by folded metasediments of the Jurassic and 

Cretaceous-age Franciscan assemblage. The western margin of the basin (fig. 2) has been folded and uplifted 

by active, east-directed thrusting of wedges of Franciscan blueschists above an east-dipping subduction zone 

where the Farallon plate descends beneath the North American plate (Unruh and others, 1995; Unruh and 

Moores, 1992). The Mesozoic and Tertiary stratigraphy of the Sacramento Basin is shown in Figure 3. The 

Great Valley Sequence thickens from east to west, and includes Upper Jurassic, Lower Cretaceous, Upper 

Cretaceous and Tertiary sediments resting on Jurassic-age metamorphic and granitic basement. 

FORBES FORMATION 

The Upper Cretaceous, Campanian-age Forbes Formation is 3,000 to 5,000 feet thick, and has been 

interpreted as a mud-rich marine turbidite fan system (Imperato and others, 1990; Nilsen, 1990) which 

overlies the thin, regionally extensive Dobbins Shale of Santonian-Campanian-age. During Upper 

Santonian and Lower Campanian time, clastic sediments from the Klamath and Sierra Mountains were 

deposited in prograding deltas (Kione Fm) along the northeastern margin of the basin. Some sediments were 

carried into far out the basin as the slope and turbidite deposits of the Forbes Formation. The turbidites 

filled an extensive north-south trending submarine canyon incised into the underlying Funks Shale and 

Guinda Sandstone near Willows and Arbuckle Gas Fields (Williams and others, 1998). 

2

The Forbes Fm contains thick marine shales, discontinuous turbidite channels and crevasse splay 

deposits (Imperato and Nilsen, 1990; Garvey, 1983). Diagenesis and development of secondary porosity in 

Forbes sandstones has been described by Mertz (1990). Secondary porosity was formed by dissolution of 

biotite and feldspar grains and leaching of carbonate cements. Compaction caused significant reduction of 

porosity with increasing depth of burial. Log-derived porosity values reported for Forbes sandstone 

reservoirs (table 1) generally range from 17 to 30% (CDOG, 1981). These reported porosity values are two 

to five times higher than those typically reported in known basin-center gas accumulations. 

TRADITIONAL GAS TRAPS 

Natural gas has been produced from Forbes reservoirs in at least twenty-seven gas fields in the central 

and northern Sacramento Basin (fig. 1; table 1). Maps and cross sections of the producing fields (Bowen, 

1962; CDOG, 1981; Weagant, 1972; Imperato and Nilsen, 1990) generally show traditional structuralstratigraphic 

traps with updip permeability barriers such as sandstone pinch-outs or sand/shale 

juxtapositions across faults. Downdip producing limits are usually drawn as horizontal boundaries, 

implying gas/water contacts. Field descriptions frequently note distinct gas/water contacts. Maps and cross 

sections of Grimes Gas Field show numerous thin Forbes sandstone lenses with pinch-outs, faulted 

truncations and clearly marked gas/water contacts (Weagant, 1972). The Forbes reservoirs at Arbuckle Gas 

Field have traditional structural and stratigraphic traps, pressure depletion drives and distinct gas/water 

contacts (Imperato and Nilsen, 1990). Drill stem test results at Arbuckle Gas Field (table 1) include a range 

of gas, gassy salt water and completely salt water recoveries. The water is generally recovered from downdip 

locations. The deepest Forbes production listed by the California Division of Oil and Gas (1981, 1999) was 

from Clarksburg Gas Field (32-T7N-R4E), where thin sandstone lenses contain gas in a fault trap with a 

down-dip gas-water contact at 11,100 ft. The temperature in the Forbes reservoir was 182 °F, the average 

porosity was 22%, and the pressure gradient was only 0.46 psi/ft, indicating normal pressures. 

OVERPRESSURE IN THE FORBES 

Previous studies by Burns and Surdam (1999), Unruh and others. (1992), Horan (1992), Rymer and 

Ellsworth (1990), Price (1988, 1986), Lico and Kharaka (1983), Berry and Kharaka (1981), and Berry (1982, 

1973, 1965), have shown that the lower Forbes Formation and Dobbins Shale are overpressured throughout 

much of the central and southern Sacramento basin. The top of overpressure occurs near the top of the 

Dobbins Shale in the northern part of the basin (fig. 4) and is generally found within the Forbes and 

Winters Formations in the central and southern parts of the basin (Lico and Kharaka (1983). 

Pressure versus depth trends at the Arbuckle, Kirk, Buckeye and Grimes Gas Fields show rapid 

increases in pore pressure below 5500 feet (fig. 5). Pressure gradients often exceed 0.7 psi/ft below 7700 to 

8000 feet and approach lithostatic gradient below 9,000 ft (Berry, 1973; Price, 1986; Price, 1988). 

Commercial gas accumulations generally occur only within the moderately overpressured zones, where 

gradients range from 0.5 to 0.7 psi/ft (Price, 1986; Price, 1988). Zones with pressure gradients exceeding 

0.70 psi/ft are seldom productive. Yerkes et al. (1990) and Berry (1973) found severe overpressures in deep 

wells along the west side of the San Joaquin Valley to the south (fig. 5). The overpressure phenomenon is 

regionally extensive, cross-cuts stratigraphy, and does not appear to be restricted to a particular geologic 

formation. 

3

PRESSURE GRADIENTS AND PORE FLUIDS 

Table 2 contains mud weights, bottom hole temperatures, drill stem test initial shut-in pressures, 

calculated pressure versus depth gradients, and reported fluid recoveries from deep wells in Arbuckle, Kirk, 

Buckeye and Grimes Gas Fields and the Rumsey Hills area (Figure 1), where the Forbes Fm is generally 

overpressured. Well data were also evaluated for several Forbes penetrations in T17N-R2W, for several wells 

with published vitrinite profiles (Jenden and Kaplan, 1989), and for several deep wells in the Delta 

Depocenter (table 3). Fluid pressure gradients were calculated by dividing the initial shut-in pressure by the 

depth of the middle of the test interval, and generally range from 0.5 to 0.92 psi/ft. Most drill stem tests 

recovered overpressured gassy salt water (“fizz-water”). A few tests produce gas with very little water, 

indicating potential gas-producing reservoirs. 

High pressure salt water flows were noted in many drilling histories, indicating that drilling mud 

densities were not high enough to balance overpressures in the Forbes Fm. Carlson (1982) described several 

exploration wells in the Rumsey Hills area which encountered high pressure salt water flows. The drilling 

history of Texaco Arbuckle Unit #1 (Sec 18-T13N-R1W) contains several notations such as “dumped 60 

bbl salt water after trip” while the Forbes section was being penetrated (table 2). High pressure salt water 

flowed into the borehole while the pipe was run out of the hole for drill bit changes, indicating that the 

drilling mud was under-balanced. 

The drill stem test data presented in Tables 2 and 3 show that the pore fluid causing the overpressure in 

the Forbes Fm is generally gassy salt water, and rarely gas. The overpressured Forbes section appears to be 

extensively water-saturated. It has not become de-watered and gas-saturated like most typical basin-center 

gas accumulations (Spencer, 1989; Law and Dickinson, 1985). 

SALT WATER SPRINGS 

Perennial salt water springs and gas seeps have been found in several outcrops along the west side of 

the Sacramento Valley (Figure 2) where the Upper Cretaceous section dips eastward into the basin (Irwin 

and Barnes, 1975; Unruh and others, 1992; Davisson and others, 1994). Waters flowing from these springs 

are indistinguishable from formation waters produced from the gas fields in the deep basin. Most of the 

spring waters contain low concentrations of sodium chloride (lower than normal sea water) and are enriched 

in calcium and quartz. The calcium may be derived from active clay diagenesis and albitization of 

plagioclase in the subsurface. These springs are evidently the surface discharge vents for high pressure 

formation waters migrating updip from the deep basin. Davisson and others (1994) suggested that some 

spring waters may originate as deep as 4 km, and flow updip through the fractured cores of deep anticlinal 

folds and fault zones. Berry (1982, 1986) noted that fractures and fault zones within the Forbes section 

provide permeable conduits for the migration of deep, high pressure formation waters. 

4

CAUSE OF OVERPRESSURE 

Previous authors (Berry, 1973; Berry, 1965; Berry and Kharaka, 1981; Lico and Kharaka, 1983; 

Davisson and others, 1994) considered the most important causes of overpressure in the Forbes to be 

tectonic compression and aquathermal pressuring. Berry (1973) identified a north-south trending zone 400 to 

500 miles long and 25 to 80 miles wide along the west side of the Sacramento and San Joaquin basins 

where near-lithostatic pore pressure gradients have been encountered in deep wells. He suggested that 

overpressuring was caused by tectonic compression of Cretaceous and Tertiary sediments crushed between 

the folded Franciscan blueschists on the west (fig. 2) and the Sierran granite on the east. High fluid 

potentials result from formation water being squeezed out of the thick, compressible Cretaceous and Tertiary 

shales. Direct evidence of active tectonic compression includes visible anticlinal folds and recent earthquake 

data, especially the Winters/Vacaville earthquake in 1892 (Unruh and others, 1995) and the Coalinga 

earthquake of 1983 (Yerkes and others, 1990). High fluid pressures probably assist the thrusting by sliding 

friction and facilitating movement along the deep faults. 

Price (1986) analyzed DST results, mud weights, shale resistivities and sonic transit times in Forbes 

reservoirs at Grimes Gas Field. She discovered that pore pressures calculated from shale compaction data 

were consistently lower than pressures measured by drill stem tests at the same depth. Due to this 

discrepancy, Price concluded that under-compaction was not the most significant cause of overpressure in 

this area. She suggested that tectonic compression and smectite dehydration may be more important causes 

of overpressuring in the Sacramento basin. 

HYDROCARBON SOURCE ROCKS 

Previous analyses of source rock potential in the Cretaceous-age shales outcropping along the west side 

of the basin (Trask and Hammar, 1934) showed low total organic content throughout the entire Cretaceous 

section. They noted a “discouraging” lack of thick, distinct organic-rich source rock layers. Organic content 

ranged from 0.6 to 1.0 % throughout the section. Kirby (1943) described massive, green-gray colored 

carbonaceous shale beds in the Forbes Formation and blue-gray colored shale with tan limestone concretions 

in the Dobbins Shale section. Kirby described thin beds of gray carbonaceous shale in the Guinda Fm, 

greenish gray shale and siltstone in the Funks Fm, and more shale in the Yolo Fm. None of these shale 

units were described as black colored or ‘sooty’ or unusually rich in organic material. These outcrop studies 

indicate lean, poor quality source rocks. 

Jenden and Kaplan (1989) analyzed organic matter from cuttings and cores in five wells and noted that 

source rocks in the Upper Cretaceous section have generally low total organic content (range = 0.2 to 2.0%, 

average = 1.0% TOC). Organic content in the Forbes Fm and Dobbins Shale ranged from 0.5 to 1.8% 

TOC. Older shales in the Funks, Sites and Venado Formations contained 1.1 to 1.3 % TOC. Most of the 

organic matter consists of gas-prone woody material and plant fragments. Several mudlogs and core 

descriptions reviewed for this study noted dispersed fragments of lignite and carbonaceous material in the 

Forbes, Dobbins and Guinda shales. A study of the Dobbins Shale by Trosper (1985) described limey, 

concretionary mudstone with extensive bioturbation and well preserved calcareous foraminifera. The 

Dobbins Shale was evidently deposited in an oxidizing environment and is bioturbated, indicated suboptimal 

conditions for the preservation of organic material. 

5

TEMPERATURE GRADIENTS 

Subsurface temperature gradients are relatively low in the Great Valley, ranging from 15 to 25 °C/km 

in the northern and central Sacramento basin and from 25 to 35 °C/km in the southwestern part (Yerkes and 

others., 1990; Lico and Kharaka, 1983; Price 1986). Horan (1992) described an average temperature gradient 

of 1.2 °F/100 ft in the Forbes Fm. Price (1986) found a shallow thermal gradient of 1.02 °F/100 ft and a 

deep gradient of 1.4 °F/100 ft in the Forbes at South Grimes Field. With these gradients, relatively deep 

burial would be needed for thermogenic gas generation. 

THERMAL MATURITY 

Berry (1986) and Horan (1990) noted that kerogen in the Forbes Fm is generally not sufficiently mature 

to generate hydrocarbon gases, and suggested that gas produced from the Forbes Fm has migrated long 

distances. Five published vitrinite profiles (Jenden and Kaplan, 1989, p. 436-437) indicate that the Forbes 

Fm is thermally immature throughout most of the basin, especially along the east side. They stated (p. 

443) that all of the gas fields in the Sacramento basin produce from thermally immature strata. 

Temperature data are listed in Tables 1 and 2. All of the Forbes gas fields (CDOG, 1981) and all the 

Forbes wells listed in Table 2 have bottom hole temperatures less than 190 °F. Bottom hole temperatures 

exceeding 200 °F were reported only in the Delta Depocenter (table 3). Vitrinite reflectance values greater 

than 0.7% were found only in two deep wells in the Delta Depocenter. These were used to constrain the 

thermal maturity model described below. 

METHANE ISOTOPES 

Gas samples from 94 producing wells were analyzed by Jenden and Kaplan (1989). The methane 

contains mixtures of immature biogenic (microbial) methane with light isotopic values, and overmature, 

thermogenic methane with very heavy isotope values. The overmature methane has apparently migrated 

long distances from deeply buried gas sources. Berry (1965, 1986) suggested that methane gas has migrated 

long distances from a deep gas kitchen to shallower, lower pressure gas traps via aqueous solution. The 

high percentage of methane gas and lack of heavier gases may be the result of selective dissolution. 

Methane is easily dissolved and transported in formation water. Heavier gases which could not be dissolved 

as easily may have been left behind near the gas kitchen. Horan (1992) noted the occurrence of gas 

condensates in fields near the Delta Depocenter and the absence of condensate elsewhere in the basin. Jenden 

and Kaplan (1989) noted the local occurrence of wet gases and condensates in the Delta Depocenter, west of 

the Midland Fault. 

DISCUSSION: BASIN-CENTER GAS MODEL DOES NOT FIT HERE 

The Forbes gas system has several characteristics of a typical basin-center gas accumulation, but many 

which don’t fit the model. The lower Forbes Fm and Dobbins Shale appear to be extensively overpressured, 

but the pressuring fluid is generally gassy salt water. The primary cause of overpressuring appears to be 

tectonic compression, not hydrocarbon saturation. Thick, rich source beds are conspicuously absent in the 

Upper Cretaceous section. Total organic carbon content is generally low, and is mainly plant and woody 

material. Regional temperature gradients are unusually low. Published vitrinite profiles indicate that the 

Forbes Fm is thermally submature to immature throughout most of the basin. The profiles indicate only 

two locations where %Ro exceeds 0.7%, whereas most known basin-center gas accumulations have vitrinite 

values exceeding 0.9% and often reaching 1 to 3%. All Forbes gas production has been from reservoirs with 

temperatures less than 190 °F, whereas most known basin-center gas accumulations are hotter than 190 to 

200 °F. 

6

Forbes gas is mostly methane, with some nitrogen. The methane consists of mixed biogenic gas and 

overmature, thermogenic methane which has apparently migrated long distances; whereas most basin-center 

gas accumulations are charged with thermogenic hydrocarbons expelled from nearby source rocks. Forbes 

gas accumulations have generally been found in traditional structural and stratigraphic traps with distinct 

gas/water contacts. Forbes sandstone porosities are relatively high (17 - 30%), much higher than typical 

porosity ranges in known basin-center gas accumulations. There do not appear to be any sub-normally 

pressured zones within the Forbes Fm. The Forbes Fm evidently does not contain a basin-center gas 

system in the central, northern or eastern parts of the basin. 

DELTA DEPOCENTER 

Berry (1981), Horan (1992) and Magoon (1994) suggested that the Delta Depocenter (Figure 1), located 

near the Kirby Hills and Rio Vista Gas Fields, may contain the ‘gas kitchen’ where much of the gas in the 

Sacramento Basin was generated. Published structural maps and cross sections (MacKevett, 1990; Johnson, 

1990; Krug and others, 1992) show a small, deep wrench basin bounded by the Kirby Hills Fault on the 

west and the Midland Fault on the east. Some authors have interpreted strike-slip motion along the Kirby 

Hills Fault. Mackvett (1990) interpreted these faults to be listric growth faults with opposite vergence 

(Figure 6). The top of the Forbes Fm is approximately 16,000 ft deep in this depression. The Dobbins 

Shale may be 18,000 to 20,000 ft deep, and older Cretaceous units such as the Funks Fm and Yolo Shale 

may be buried 23,000 to 27,000 ft deep, depending on westward thickening of the Cretaceous section. 

THERMAL MATURITY MODEL 

A thermal maturity model was constructed for the deepest part of the Delta Depocenter, using Basin- 

Mod software. The model is located in T4N-1E along an east-west cross section (fig. 6) modified after 

MacKevett (1990). Formation tops and bottom hole temperatures were verified by checking several 

annotated well logs available from MJ Microfiche, Inc. Projected depths for the Cretaceous units below the 

Forbes Fm are based on thicknesses of measured outcrop sections (Ojakangas, 1968; Kirby, 1943). 

Published source rock data, temperature gradients (Lico and Kharaka, 1983; Price, 1986) and a nearby 

vitrinite reflectance profile (Jenden and Kaplan, 1989) were used to calibrate the model. 

The thermal maturity model (fig. 7a, 7b) indicates that vitrinite reflectance may reach 0.9 %Ro in the 

Upper Cretaceous Winters Fm at approximately 15,000 ft deep. The 2.0 %Ro level probably occurs in the 

Funks Shale at approximately 22,000 ft. The 3.0 % reflectance level is reached near the top of the Venado 

Fm at 26,000 ft, and 4.0 %Ro is reached in the Lower Cretaceous section at approximately 30,000 ft. 

Significant gas generation and expulsion for the gas-prone, Type III organic material found in the 

Cretaceous rocks probably starts at about 0.9 %Ro (Leckie and others, 1988, p.824). Peak dry gas 

generation probably occurs at 1.2 to 2 %Ro. The maturity model shows that much of the Forbes Fm may 

be within the gas generation window below 16,000 ft. The Lower Forbes, Dobbins, Funks and Yolo shales 

are apparently within the peak gas generation window (%Ro greater than 1.2) below 18,000 ft. The burial 

history diagram indicates that these formations may have been generating dry gas since mid-Eocene time. 

The thermal maturity model indicates that a gas kitchen is probably located within the Delta Depocenter. If 

the source rocks are rich enough, and if the gas system has not been breached by recent strike-slip faulting, 

there might be a basin-center gas accumulation deep in this sub-basin. 

7

DEEP DRILLING RESULTS 

Several deep wells in the Delta Depocenter area reached 12,000 to 15,059 ft total depth. Well logs, 

drilling histories and test data for these wells were examined for evidence of possible basin-center gas 

conditions. DST pressure gradients, bottom hole temperatures and comments are listed in Table 3. Six 

wells reached the 14,000 to 15,059 ft depth range. Two of these were plugged back without any formation 

tests in the deep section. Two drill stem tests in the 14,700- 14,800 ft range (Cook 13 and Cook 15) 

recovered drilling mud or gassy mud, indicating tight reservoirs. Four deep drill stem tests recovered high 

pressure salt water (Cook 14 at 14,840 ft; Cook 15 at 14,215’; Cook 16 at 14,770’; Cook 16 at 14,255’). 

These few test recoveries indicate that the Forbes Fm is probably water-saturated, not continuously gassaturated, 

in the 14,000 to 15,000 ft depth range. The bottom hole temperatures (table 3) exceed the 190- 

200 °F threshold, which often coincides with the tops of basin-center gas accumulations (Law and 

Dickinson, 1985; Spencer, 1987, 1989), but these Forbes reservoirs flowed high pressure salt water. There 

is no convincing evidence from these deep exploratory wells to indicate that a basin-center gas accumulation 

exists within the 14,000 to 15,000 ft range. The source rocks might be too lean to have generated enough 

gas to saturate the reservoirs at this depth. 

ULTRA-DEEP BASIN-CENTER GAS ? 

Perhaps the peak gas generation window is even deeper. The thermal maturity model (fig. 7) indicates 

that the gas-window extends through depths greater than 16,000 ft. If rich, thermally mature source rocks 

have expelled enough gas to de-water the reservoirs, a localized, continuous basin-center gas accumulation 

might be present in this part of the basin. Figure 8 shows the approximate outline of a hypothetical, highly 

speculative basin-center gas system which might exist below 16,000 ft. The map shows a deep, narrow, 

NNW-SSE trending depression between the Midland and Kirby Hills Faults, based on structural 

interpretations by MacKevett (1992) and Krug and others (1992). The top of the Forbes Fm is probably 

15,000 to 16,000 ft deep in this highly faulted area. 

No wells have been drilled deep enough to evaluate this potential basin-center gas system. The high 

pressure salt water flows encountered in the Standard Oil Cook 14, 15 and 16 wells may have discouraged 

deep drilling in this area. The preservation of seals above the deep gas kitchen is a significant risk. Active 

strike-slip faulting may have breached the system, and much of the gas may have escaped. 

8

CONCLUSIONS 

Well data, drill stem test results, structural cross sections and previous studies of abnormal pressures, 

methane isotopes and thermal maturity were evaluated to determine if a basin-center gas accumulation might 

exist within the Upper Cretaceous-age Forbes Formation in the Sacramento basin, California. The Forbes 

Fm is overpressured in the central and southern parts of the basin, and produces methane gas from many 

sandstone reservoirs within an extensive, mud-rich turbidite fan system. Some characteristics of the Forbes 

Formation and its associated gas production indicate a possible basin-center accumulation, but many do not 

appear to fit the typical model. Bottom hole temperatures and measured vitrinite reflectances are low, and 

the Forbes appears to be thermally immature throughout most of the basin. The pore fluid causing the 

overpressure is usually gassy salt water. Drill stem tests and drilling mud weights indicate extensive 

overpressures, with gradients ranging from 0.5 to 0.92 psi/ft. Formation tests often recover abundant highpressure 

salt water. 

Methane gas in Forbes reservoirs is usually a mixture of immature biogenic gas and overmature, 

thermogenic methane which apparently migrated long distances from a deep gas kitchen. The gas traps 

discovered to date have generally been traditional structural and stratigraphic traps with distinct gas/water 

contacts. It is unlikely that the Forbes section is extensively gas-saturated. The geologic evidence does not 

indicate a basin-center gas accumulation within the Forbes Formation in the central, northern or eastern 

Sacramento Basin. 

Previous authors have suggested that a ‘gas kitchen’ may exist deep within the fault-bounded Delta 

Depocenter in the southwestern part of the basin. Much of the basin’s hydrocarbons may have been 

generated and expelled from this structural depression. A thermal maturity model was constructed using 

Basin Mod software, deep well data, published cross sections, thermal gradients and vitrinite profiles. The 

Forbes Fm may be within the gas generation window from 16,000 to 20,000 ft. A highly speculative, 

localized basin-center gas accumulation might exist deep in the Delta Depocenter. Several exploratory wells 

have been drilled as deep as 15,059 ft in this area, but drill stem tests recovered high pressure salt water or 

drilling mud. No wells have been drilled deep enough to evaluate the potential basin-center gas 

accumulation in this relatively narrow wrench basin. The gas kitchen may have been breached by active 

strike-slip faults.. If the source rocks were too lean or if too much gas escaped, continuous, gas-saturated 

basin-center gas conditions might not have developed here. The existence of a basin-center gas accumulation 

in the Delta Depocenter should be considered highly speculative. Deeper exploratory drilling (>16,000 ft) 

would be needed to evaluate this possibility. 

9


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10

Horan, E.P., 1992, Pressure-Temperature, Structural Trends and Natural Gas Distribution in the 

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11

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12

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13

Conceptual models of basin-center gas accumulations have been described by Masters (1979), Davis 

(1984), Law and Dickinson (1985), Spencer (1987), Spencer (1989) and Law and Spencer (1993). Key 

components of a basin-center gas accumulation include: 

1) Extensive abnormal pressure, either overpressure or subnormal pressure. 


3) Organic-rich source rocks with minimum vitrinite reflectance of 0.8% for gas-prone source 

material. Many basin-center gas accumulations are in rocks with vitrinite reflectance in the 1 to 

3% range. 

4) Rich source beds have generated enough gas to cause pore pressures to rise above normal pressure 

gradients (> 0.43 psi/ft). Temperature-induced hydrocarbon generation forces water out of pore 

spaces and saturates the reservoirs with hydrocarbons. Water saturations decline to irreducible 

levels. Overpressure is sustained by hydrocarbon generation at rates exceeding escape. 

5) Pressure gradients rise to the lowest fracture gradients in the rock sequence. High pore pressures 

fracture the rocks and create migration pathways for hydrocarbons to escape. Cementation 

episodically closes the fractures. 

6) Hydrocarbons (oil and/or gas) are the primary fluid-pressuring phase. Little or no water is produced 

from the overpressured reservoirs. However, water may intrude via fractures and more permeable 

beds as reservoir pressure is reduced. 

7) Reservoirs are frequently in tight sandstone with heavy cementation, low porosity (3 - 14 %) and 

very low permeability (usually < 0.1 md). 

8) Uplift and erosion of the basin may result in unloading, cooling, pore expansion and gas escape, 

leading to development of sub-normally pressured reservoirs in zones which were previously 

overpressured. 

9) Overpressured and/or sub-normally pressured gas reservoirs generally occur downdip from normally 

pressured reservoirs with water drive mechanisms. 

14

40° 00' 

39° 30' 

39° 00' 

A 

122° 30' 

38° 30' 

KIRKWOOD 

WILLOWS FAULT 

B 

MALTON- 

BLACK BUTTE 

WILLOWS- 

BEEHIVE BEND 

BOUNDE CREEK 

STEGEMAN 

COMPTON 

LANDING 

38° 00' 

ARTOIS 

WILLIAMS 

MOON BEND 

SYCAMORE 

GRIMES, W. 

ARBUCKLE 

122° 00' 

RANCHO 

CAPAY 

BUCKEYE 

DUNNIGAN 

HILLS 

C 

APTON 

37 30' 

122° 00' 

DDC 

GRIMES 

KIRK 

SACRA MENTO RIVER 

RIO 

VISTA 

SUTTER 

BUTTES 

ROBBINS 

C' 

B' 

KLAMATH 

MTS. 

COAST 

FREEPORT 

CLARKSBURG POPPY RIDGE 

MIDLAND FAULT 

STOCKTON 

121° 30' 

SAN 

A' 

SACRAMENTO 

FAULT 

JO AQUIN R. 

RANGES 

SIERRA NEVADA MTS. 

CALIFORNIA 

CENOZOIC VOLCANICS 

UPPER MESOZOIC GREAT 

VALLEY SEQUENCE 

SIERRAN BASEMENT 

ROCKS 

0 5 10 

MILES 

15 20 

Figure 1. Map of Sacramento basin showing gas fields which have produced from the Forbes Formation. 

Locations of cross sections A-A’, B-B’ and C-C’ are shown. DDC = Delta Depocenter. Modified from 

Jenden and Kaplan (1989, fig. 1).

A 

SW NE 

Coast Ranges Rumsey Hills Sacramento Basin 

Franciscan 

Blueschists 

Cretaceous 

Franciscan 

Blueschists 

SUBDUCTION ZONE 

Farallon Plate 

Franciscan 

Cretaceous 

Jurassic - Cretaceous 

Sediments 

Ophiolite 

Arbuckle Kirk Grimes 

Tertiary Sediments 

Cretaceous Sediments 

Moho 

Upper Mantle Lithosphere 

Sierran Basement 

Figure 2. Structural cross section A-A’ showing the Sacramento basin, Rumsey Hills, Coast Ranges, Arbuckle, Kirk and Grimes gas fields. 

Wedges of Franciscan blueschists, ophiolites and sediments have been thrust eastward along blind thrusts above an east-dipping 

subduction zone. Cretaceous sediments have been folded due to back-thrusting along the west flank of the basin. Modified from Unruh 

and others (1995). 

A' 

Kilometers 

-5 

-10 

-15 

-20 

-25 

-30 

-35 

8 

16 

24 

32 

40 

48 

56 

64 

72 

80 

88 

96 

104 

112 

120 

Depth, in thousands of feet

SYSTEM SERIES 

QUATER. 

TERTIARY 

CRETACEOUS 

SACRAMENTO BASIN STRATIGRAPHY 

PLIOCENE 

MIOCENE 

OLIGOCENE 

EOCENE 

PALEOCENE 

UPPER 

LOWER 

JURASSIC UPPER 

OIL GAS 

STRATIGRAPHIC UNIT PROD. PROD. 

Winters 

Formation 

Forbes 

Formation 

Tehama Formation 

Valley Springs Formation 

Markley Canyon fill 

Markley Formation 

Nortonville Shale 

Domengine Formation 

Capay Formation 

Meganos Shale 

Martinez Formation 

Mokelumne River Formation 

H & T Shale 

Sacramento Shale 

Dobbins Shale Member 

Guinda Formation 

Funks Formation 

Sites Formation 

Yolo Formation 

Kione 

Formation 

Venado Formation 

Shasta Formation 

Starkey 

Formation 

Middle and lower 

Great Valley sequence 

Knoxville Formation 

Figure 3. Stratigraphic units and hydrocarbon producing zones in the Sacramento basin, California. 

Modified from Jenden and Kaplan (1989) and Nilsen (1990).

SEA LEVEL 

Depth, in thousands of feet 

-2 

-4 

-6 

-8 

-10 

-12 

-14 

-16 

-18 

-20 

B B' 

Delta 

Malton- 

S N 

Depocenter Colusa Basin 

Black Butte 

BASEMENT ? 

MIDLAND FAULT 

ZONE 

TERTIARY 

TOP OF OVERPRESSURE 

FORBES FM 

DOBBINS SHALE 

CRETACEOUS 

BASEM ENT 

TOP OF OVERPRESSURE 

Figure 4. North-south cross section B-B’ showing the top of overpressure in the Sacramento basin. The Dobbins Shale is overpressured 

in the northern part of the basin. The Forbes Fm is overpressured in the central and southern parts of the basin. The Forbes Fm is 

buried deepest in the Delta Depocenter and Midland Fault Zone. Modified from Lico and Kharaka (1983, fig. 7). 

10 Miles 

16 Km


SEA 

LEVEL 

-2 

-4 

-6 

-8 

-10 

-12 

-14 

-16 

-18 

-20 

LITHOSTATIC GRADIENT ~ 1 PSI/FT 

ARBUCKLE FIELD 

GRIMES GAS FIELD 

KIRK- 

BUCKEYE 

FIELD 

SOUTHERN SAN JOAQUIN BASIN 

HYDROSTATIC GRADIENT ~ 0.43 PSI/FT 

2000 4000 6000 8000 10000 12000 

INITIAL SHUT-IN PRESSURE (PSI) 

Figure 5. Pressure vs depth trends for several overpressured Forbes Gas Fields - Arbuckle, Grimes and 

Kirk-Buckeye; also the average pressure versus depth trend for the southern San Joaquin Basin. 

Lithostatic (1 psi/ft) and hydrostatic (0.43 psi/ft) gradients are shown. Modified from Berry 

(1973, fig. 2), Price (1986, fig. 15) and Yerkes and others (1990).

C C' 

TERTIARY 

CRETACEOUS 

KIRBY HILLS FAULT 

MARTINEZ 

H&T SH 

STARKEY 

WINTERS 

FORBES 

DOBBINS SH 

GUINDA 

FUNKS 

SITES 

YOLO 

VENADO 

LOWER 

CRETACEOUS 

CAPAY 

DELTA DEPOCENTER 

WEST KIRBY HILLS NW RIO VISTA 

SHELL 

LAMBRY #3 

23-4N-1W 

SHELL 

PETERSEN #1 

32-5N-1E 

PACIFIC 

TURNER #2 

21-4N-1E 

DDBM 

CHEVRON 

EMIGH #1 

2-4N-1E 

OCCIDENTAL 

HATCH #1 

6-4N-2E 

UMC 

PETERSEN #1 

32-5N-2E 

STARKEY 

WINTERS 

FORBES 

DOBBINS SH 

MIDLAND FAULT 

FORBES 

H&T SH 

SIERRAN 

BASEMENT 

Figure 6. Structural cross section C-C’ through the Delta Depocenter, showing the Midland and Kirby Hills Faults and several deep wells. 

DDBM = Location of Delta Depocenter Basin Model. Modified from MacKevett (1992, fig. 12) and Krug and others (1992). 

STANDARD 

COOK #16 

10-4N-2E 

STANDARD 

COOK #13 

12-14N-2E 

STANDARD 

COOK #14 

12-4N-2E 

STANDARD 

COOK #15 

8-4N-3E 

EAST 

SEA 

LEVEL 

- 4 

- 8 

- 12 

- 16 

- 20 

- 24 

- 28 

- 32 

- 36 

- 40 

Depth, in thousands of feet


0 

- 5 

- 10 

- 15 

- 20 

- 25 

- 30 

- 35 

- 40 

- 45 

- 50 

Delta Depocenter 

* * 

GAS GENERATION WINDOW 

FOR TYPE III GAS- 

PRONE KEROGEN 

.9 1 2 3 4 10 

Maturity (%Ro) 

Figure 7a. Delta Depocenter Basin Model showing stratigraphic units at present depth of burial, two 

measured vitrinite reflectance data points (%Ro), predicted maturity curve, and predicted gas 

generation window for Type III kerogen. %Ro reaches 0.9% and top of gas generation window at 

approximately -15,500 ft, however several drill stem tests near this depth recovered high pressure 

salt water, not gas. Forbes, Dobbins, Funks and deeper Cretaceous source rocks may be within the 

peak gas generation window from -16,000 to -29,000 ft. 

Fm 

t=0 

Tertiary 

Markley 

Nortonville 

Domengine 

Capay 

Meganos C 

Martinez 

McCormick 

Mok River 

H&T Shale 

Starkey 

Winters 

Sac. Shale 

Forbes 

Dobbins 

Guinda 

Funks 

Yolo-Sites 

Venado 

L. Cret.


0 

- 5 

- 10 

- 15 

- 20 

- 25 

- 30 

- 35 

- 40 

- 45 

- 50 

Delta Depocenter 

100( F) 

200( F) 

CRETACEOUS PAL. EOCENE OLIG. MIOCENE P Fm 

300( F) 

400( F) 

500( F) 

600( F) 

700(F) 

160 150 100 50 0 

Age (my) 

Tertiary 

Markley 

Nortonville 

Domengine 

Capay 

Meganos C 

Martinez 

McCormick 

Mok River 

H&T Shale 

Starkey 

Figure 7b. Burial history curves, depths, ages (my) and temperatures for Cretaceous and Tertiary sediments in the Delta Depocenter, from 

BasinMod thermal maturity model. Forbes, Dobbins, Funks and Yolo source rocks may be within the gas generation window below 

16,000 ft and 300 °F within the deepest part of the Delta Depocenter. 

Winters 

Sac. Shale 

Forbes 

Dobbins 

Guinda 

Funks 

Yolo-Sites 

Venado 

L. Cret.

7N 

6N 

5N 

4N 

3N 

2N 

1N 

1S 

C 

KIRBY 

KIRBY 

HILLS 

HILLS FAULT 

N 

5 Miles 

BASIN AXIS 

DDBM 

RIO 

VISTA 

POTENTIAL 

GAS KITCHEN 

AND BASIN-CENTER 

GAS ACCUMULATION 

MARSH CREEK FAULT 

MIDLAND 

BRUSHY CRE EK FAULT 

2S 1W 1E 2E 3E 

Figure 8. Map showing outline of potential gas kitchen in the Forbes Fm and Dobbins Shale; also 

location of cross section C-C’[. If the source rocks have expelled large volumes of gas, there 

may be a localized, continuous basin-center gas accumulation here. However, active strike-slip 

and wrench faulting may have breached the system. Modified after Krug and others (1992, p. 43) 

and MacKevett (1992, fig. 12). 

FAULT 

C'

Table 1. Fields which produced gas from the Forbes Fm, with typical porosities and 

reservoir temperatures. All Forbes gas has been produced from thermally immature 

reservoirs with temperatures less than 190 °F. Data from California Division of Oil and 

Gas (1981, 1999). 

FIELD NAME Sec Twp Rg Prod Fm Depth Porosity Temp 

(Data: CDOG, 1981, 1999) feet % deg F 

AFTON 34 19N 1W Forbes 6,000 130 

ARBUCKLE 3 13N 1W Forbes 6,400 23 133 

ARTOIS 11 20N 3W Forbes 5,900 25 113 

BLACK BUTTE DAM 21 23N 4W Forbes 950 18 - 23 92 

BOUNDE CREEK 13 18N 2W Forbes 5,450 15 - 24 135 

BUCKEYE 24 13N 1W Forbes 8,500 143 

BUTTE SLOUGH 1 15N 1W Forbes 7,200 15 - 20 138 

CLARKSBURG 31 7N 4E Forbes 11,100 22 182 

COLLEGEVILLE EAST 33 1N 8E Forbes 7,450 20 144 

COMPTON LANDING 30 17N 1W Forbes 6,260 20 - 24 151 

DUNNIGAN HILLS 36 11N 1W Forbes 8,400 16 - 25 155 

FREEPORT 18 7N 5E Forbes 8,040 22 126 

GREENWOOD 35 22N 3W Forbes 5,400 

GRIMES 26 15N 1W Forbes 8,800 22 - 30 164 

KIRK 15 13N 1E Forbes 8,700 24 - 29 154 

KIRKWOOD 10 23N 3W Forbes 4,020 18 - 25 105 

MALTON-BLACK BUTTE 33 23N 3W Forbes 4,950 18 - 25 125 

MOON BEND 9 15N 1W Forbes 6,850 24 - 30 145 

POPPY RIDGE 5 6N 5E Forbes 7,270 23 - 27 

RANCHO CAPAY 4 22N 2W Forbes 5,000 18 - 24 166 

ROBBINS 5 12N 3E Forbes 7,100 17 - 23 167 

STEGEMAN 1 17N 2W Forbes 3,700 

SYCAMORE SLOUGH 22 15N 1W Forbes 7,370 135 

TISDALE 17 14N 2E Forbes 6,200 24 - 32 122 

WEST BUTTE 20 16N 1E Forbes 6,500 18 - 25 132 

WILLIAMS GAS 31 16N 2W Forbes 5,300 15 - 19 118 

WILLOWS-BEEHIVE 11 19N 2W Forbes 6,700 24 - 30 129

Table 2. Mud weights (lb/cubic ft), reservoir temperatures (°F), drill stem test shut-in pressures (highest pressure reported, either ISIP or FSIP), pressure gradients 

and gas or fluid recoveries for selected Forbes wells, central Sacramento basin. Well logs, drilling histories and DST data were collected from MJ Microfiche, Inc. 

and Petroleum Information/Dwights LLC. 

Well Name FIELD Sec Twp Rg Year TD FM at TD Mud Wt at Depth BHT DST SIP at Depth Pr/Depth Drill Stem Test Recoveries, Gas + Water Analyses, Comments 

ft lb/cubic ft ft deg F psi ft psi/ft 

Superior Glenn #72-20 31 21N 1W 1943 9178 basement 103.0 9178 193 See Jenden and Kaplan, 1989, p.436, %Ro=0.6 at 8200'. 

W. Gulf Hutton #2 Kirk 8 13N 1E 1961 8603 Forbes 106.0 8603 147 4532 7840 0.58 Recovered gas at 5820 mcfd + no fluid 

5440 8578 0.63 Recovered gas at 5720 mcfd + 399' salt water 

W. Gulf Wilkins G#1 Kirk 19 13N 1E 1960 9727 Forbes 112.0 8727 143 5090 8360 0.61 Recovered 1075' salt water, 1170 g/g cl-, no gas 

5540 8540 0.65 Recovered gas at 5920 mcfd, no water 

Shell Cameron Schor #1 Kirk 16 13N 1E 1961 8735 Forbes 103.0 8735 148 5744 8685 0.66 Recovered gas at 460 mcfd + 10 gal salt water 

5801 8700 0.67 Recovered 300' gassy watery mud 

W. Gulf G. Erdman #1 Kirk 15 13N 1E 1960 9512 Guinda 130.0 9512 157 5835 8750 0.67 Recovered gas, no fluid 

NahamaW Sanborn #1-3 Grimes 3 14N 1E 9607 Forbes 92.0 9607 3267 6460 0.51 Recovered gas at 3600 mcfd, no fluid 

3939 7010 0.56 Recovered gas at 3250 mcfd + 15' salt water, 4050 ppm cl- 

3954 7175 0.55 Recovered gasat 3000 mcfd, no fluid 

NahamaW East Grimes #1 Grimes 3 14N 1E 1982 7828 Forbes 90.0 7828 148 3034 6580 0.46 Recovered gas at 599 mcfd + 200' mud. %Ro, J&K, 1989 p. 436 

Mobil Grimes U4 #1 Grimes 4 14N 1E 1960 8242 Forbes 114.0 8242 145 3250 6550 0.5 Recovered gas at 2500 mcfd + 155' salt water, 680 g/g cl- 

3800 6970 0.55 Recovered gas at 1200 mcfd, no fluid 


King Resources Davis #1 wildcat 22 15N 1W 1969 8605 Forbes 127.0 8605 5131 7505 0.68 Recovered 3082' salt water + trace of gas 

6590 8279 0.795 Recovered 3015' salt water 

Coastal Gobel #1 W. Grimes 21 15N 2W 1986 7100 Forbes 6010 126 3490 6007 0.58 Recovered gas at 1906 mcfd, no fluid. Effective Perm = 0.27 md 

Coastal Abel Rd #1 W. Grimes 21 15N 2W 1986 7173 Forbes 97.0 4807 119 2266 4807 0.47 Recovered gas, gas analysis = 97% methane, 1.5% nitrogen 

Humble Davis #B-6 W. Grimes 22 15N 1W 1962 10017 Dobbins 129.0 10017 172 7200 9552 0.75 Recovered 446' muddy salt water, no gas 

Chevron C. City #4 W. Grimes 27 14N 1W 1981 9372 Forbes 119.0 9372 155 6049 8550 0.71 Recovered gas at 160 mcfd + 1380' gascut mud 

5299 9300 0.57 Recovered gas at 260 mcfd & flowed 268 bwpd 

Honolulu Balsdon #1 W. Grimes 34 14N 1W 1961 10005 Forbes 131.0 10005 160 6624 8760 0.76 Recovered gas at 714 mcfd + 120' salt water 


Occidental Sacheiter #4 W. Grimes 4 14N 1W 1961 9370 Forbes 128.0 9370 150 5368 7740 0.69 Recovered 60' muddy salt water, 1255 g/g cl- + trace of gas 

6927 8425 0.82 Recovered 220 muddy salt water, 1235 g/g cl- + trace of gas 

6584 8485 0.78 Recovered 208' muddy salt water, 1013 g/g cl-, no gas 

7334 8760 0.84 Recovered 120' muddy salt water, 600 g/g cl- + trace of gas 

8392 9383 0.89 Recovered 1130' muddy salt water, 1450 g/g cl-, no gas 

Chevron C. City #3A W. Grimes 34 14N 1W 1981 9800 Dobbins 133.0 9320 157 7811 9570 0.82 Recovered gas + 240' water-cut mud 

7398 9205 0.8 Recovered gas at 1.3 mcfd + flowed 24 bpd salt water 

Exxon Carter #3 Compton 7 17N 1W 1984 8100 Guinda 132.0 8100 162 3340 5200 0.64 Repeat Fm Tester pressures 

3246 5346 0.6 Repeat Fm Tester pressures 





Gulf Boggs Unit #1 wildcat 29 17N 1W 1964 8759' Forbes 130.0 8759 153 6313 7965 0.79 Recovered gas at 1541 mcfd + 271' wtr-cut mud, 96% CH4, 2.5% N 

Texaco Dennis #1 wildcat 30 17N 2W 1979 8191 Forbes 136.0 8191 179 6201 6770 0.92 Very high ISIP, recovered 1423' salt water 

4608 5520 0.83 Recovered 3300' salt water + trace of gas 

Chevron Thompson #1 wildcat 15 17N 2W 1981 8448 Forbes 127.0 8448 144 8168 Water shut off test flowed 75 mcfd + salt water at 96 bwpd 

6425 Flowed salt water to surface at 1400 bwpd 

6344 Recovered 1440' gassy salt water 

Honolulu West Larkins #1 wildcat 10 17N 2W 1961 8810 Forbes 134.0 8810 145 

NARECO Terhel Farm #1 wildcat 29 17N 1W 1981 8220 Forbes 122.0 8220 156 3662 6160 0.59 Recovered gas at 229 mcfd + 1085' salt water, 17000 ppm cl- 

6066 7920 0.77 Recovered 437' salt water + trace of gas


and gas or fluid recoveries for selected Forbes wells, central Sacramento basin. Well logs, drilling histories and DST data were collected from MJ Microfiche, Inc. 

and Petroleum Information/Dwights LLC. 

Well Name FIELD Sec Twp Rg Year TD FM at TD Mud Wt at Depth BHT DST SIP at Depth Pr/Depth Drill Stem Test Recoveries, Gas + Water Analyses, Comments 

ft lb/cubic ft ft deg F psi ft psi/ft 

Occidental SC Club #B-1 wildcat 11 16N 1W 7300 volc sill 123.0 7300 3088 4385 0.7 Recovered gas at 460 mcfd + 317' salt water, 920 g/g cl- 

3452 5340 0.65 Recovered 520' salt water, 925 g/g cl- + trace of gas 

Humble Capital #B-1 wildcat 3 16N 1W 1953 10126 basement 126.0 10014 163 Cored Dobbins Shales & Guinda SS 

Shell Kingsbury #4X-11 wildcat 11 11N 3W 1954 5500 Guinda 119.0 5500 137 3330 4710 0.71 Recovered 990' muddy salt water, 905 g/g cl-, cut cores 

Texaco Crawford #1 wildcat 32 13N 2E 1952 5013 Forbes 5013 107 Cored Forbes & Dobbins Sh, noted lignitic carbonaceous mat'l 

Occidental Dobbins #1 wildcat 8 13N 3W 1960 3643 Sites 114.0 3463 115 1442 2060 0.7 Recovered gas at 1390 mcfd + 1229' salt water, 1740 g/g cl- 

1774 2630 0.67 Recovered 80' drilling mud + trace of gas 

Texaco Arbuckle U1 #1 wildcat 18 13N 1W 1971 12210 Guinda 129.0 12200 180 Mudlog notes many severe salt water flows into borehole 

119.0 8970 "Well flowed during trip, dumped 20 bbls salt water" 

122.0 9704 "Dumped 16 bbl salt water after trip" High background gas 

127.0 10500 in Dobbins Shale. "Dumped 30 bbls salt water after trip" 

Occidental Arbuckle X #2 Arbuckle 34 14N 2W 6712 Forbes 3454 6180 0.56 Recovered gas at 1987 mcfd, no fluid 

Occidental Arbuckle Y #1 Arbuckle 35 14N 2W 6565 Forbes 3543 5970 0.59 Recovered 258' muddy salt water, 1170 g/g cl- 

Gulf Arbuckle UU#1 Arbuckle 5 13N 2W 7362 Forbes 3820 6560 0.58 Tool plugged after 1 hour shut in period 

W. Gulf Arbuckle AA #1 Arbuckle 11 13N 2W 1957 7000 Forbes 5252 6790 0.77 Recovered 4238' muddy salt water + trace of gas 

3355 6100 0.55 Recovered gas at 1507 mcfd + flowed salt water to surface 

Great Basins P-Munell #2 Arbuckle 15 13N 2W 1978 7453 Forbes 3485 5910 0.59 Recovered gas at 1232 mcfd + no fluid. Gas analysis, J&K 1989 

Great Basins P-Munell #1 Arbuckle 15 13N 2W 1977 7335 Forbes 7240 Recovered 1660' salt water, 17,800 ppm cl- 

Occidental Arbuckle S#1 Arbuckle 4 13N 3W 1959 6866 Forbes 95.0 6387 3954 6725 0.59 Recovered gas at 5980 mcfd + 400' salt water, 1250 g/g cl- 

W. Gulf Arbuckle T#1 Arbuckle 4 13N 2W 1957 6515 Forbes 3510 6400 0.55 Recovered gas at 1800 mcfd + 800' salt water, 2000 g/g cl- 


W. Gulf Wilkins B #2 wildcat 24 13N 1W 1960 8700 Forbes 111.0 8700 5900 8515 0.69 Recovered gas at 300 mcfd + 880' salt water, 1240 g/g cl- 


Hudson Zumwalt #1 wildcat 36 14N 3W 1958 7013 Forbes 115.0 7013 132 4015 5702 0.7 Recovered 3240' salt water 

2650 5178 0.51 Recovered 735' gassy salt water 

Phillips Swanston #1 wildcat 26 9N 3E 1961 11194 Dobbins 93.0 11185 165 Note %Ro data, %Ro=0.75 near TD, J&K 1989, p. 436


and gas or fluid recoveries for selected Forbes wells, Delta Depocenter, southwestern Sacramento Basin. Well logs, drilling histories and DST data were collected from 

MJ Microfiche, Inc. and Petroleum Information/Dwights LLC. 

Well Name FIELD Sec Twp Rg Year TD FM at TD Mud Wt at Depth BHT DST SIP at Depth Pr/Depth Drill Stem Test Recoveries, Water Analyses, Comments 

ft lb/cu ft ft deg F psi ft psi/ft 

Occidental CollinsHatch #1 wildcat 6 4N 2E 1980 12645 Winters 94.0 12,645 230 8,340 12,600 0.66 Recovered 1 bbl mud, no gas or water 

Chevron CH-Emigh #1-2 wildcat 2 4N 2E 1983 13026 Winters 120.0 13,026 234 12,818 Recovered 3648' salt water + 8082' gassy drilling mud 

12,870 Recovered 1000' drilling mud + 4200' salt water. 

Shell Petersen Ranch #1 wildcat 32 5N 1E 1960 15001 Forbes 130.0 14,518 298 9,840 12,070 0.82 Recovered 3660' gassy salt water 

129.0 15,001 Cut 3 cores 14042-14931', mostly shale & ss 

CSOG Emigh #8 wildcat 33 5N 1E 1986 12200 Winters 90.0 12,200 186 

Pacific SW Turner #2 wildcat 21 4N 1E 1962 12215 Starkey 105.0 12,215 228 11,472 Recovered 192' salt water, no gas, in Starkey Fm 

11,450 Recovered 3190' gassy salt water, 300 g/g cl-, in Starkey Fm 

Standard Oil P. Cook #13 wildcat 12 4N 2E 1961 15056 Forbes 124.0 15,056 214 14,780 Recovered 760' gassy mud. Retest recovered 1137' gassy mud 

Standard Oil P. Cook #14 wildcat 12 4N 2E 1963 15003 Forbes 126.0 15,003 238 14,840 Recovered 2700' muddy water, 240 g/g cl-, no gas 

10,512 12,900 0.82 Recovered 12,550' salt water + trace of gas, flowed salt water 

9,856 12,370 0.8 Recovered 3780' salt water, 380 g/g, + trace gas, flowed salt water 

Standard Oil P. Cook #15 wildcat 8 4N 3E 1964 15059 Forbes 116.0 15,059 232 14,785 Recovered 94' drilling mud, no gas or water 

4,697 14,215 0.33 Recovered 866' water, 250 g/g, no gas 

13,260 Water shut off test recovered 300' muddy water, 370 g/g cl- 

3,405 11,635 0.3 Recovered 100' muddy water, 235 g/g cl- 

4,057 9,480 0.43 Recovered 368' mud + 2397' salt water, 320 g/g cl- 

Standard Oil P. Cook #16 wildcat 10 4N 2E 1964 15050 Forbes 126.0 15,050 256 9,090 14,770 0.62 Recovered 4850' muddy water, 393 g/g cl- + trace of gas 

10,053 14,255 0.71 Recovered 680' salt water, 400 g/g cl- 

7,325 14,255 0.52 Retested, recovered 1746' salt water, 230 g/g cl- 

8,473 12,680 0.67 Rec gas tstm rec 758' salt water, 200 g/g & 910' mud 

8,291 11,830 0.7 Recovered 2460' salt water, 290 g/g cl- + trace gas, flowed water 

11,410 Recovered trace of gas, flowed water at 252 bwpd, 370 g/g cl- 

McCulloch Petersen #1-32 wildcat 32 5N 2E 1980 12550 Winters 108.0 12,500 223 12,448 Recovered 4500' salt water, no gas, swabbed salt water 

11,756 Water shut off test recovered 300' muddy water, 370 g/g cl- 

MCOR Anderson #1-5 wildcat 5 3N 2E 1980 14269 Winters 105.0 14,269 276 8,472 13,106 0.65 Recovered 2000' water, 2600 ppm cl-, in Starkey Fm, reversed SP 

This is the hottest BHT. Total Depth in Winters SS

ABSTRACT 

Is there a Basin-Center Gas Accumulation in the 

Travis Peak (Hosston) Formation, Gulf Coast Basin, USA? 

Charles E. Bartberger 

Petroleum Geologist 

Potential of Lower Cretaceous Travis Peak sandstones in the northern Gulf Coast Basin to harbor a basin-center 

gas accumulation was evaluated by examining (1) depositional/diagenetic history and reservoir properties of Travis 

Peak sandstones, (2) presence and quality source rocks for generating gas, (3) burial/thermal history of source rocks 

and time of gas generation/migration relative to tectonic development of Travis Peak traps, (4) gas and water 

recoveries from drillstem and formation tests, (5) distribution of abnormal pressures based on shut-in-pressure data, 

and (6) presence or absence of gas-water contacts associated with gas accumulations in Travis Peak sandstones. 

The Travis Peak Formation is a basinward-thickening wedge of terrigenous clastic sedimentary rocks that 

underlies the northern Gulf of Mexico Basin from east Texas across northern Louisiana to southern Mississippi. 

Clastic influx was focused in two main fluvial-deltaic depocenters located in northeast Texas and southeast 

Mississippi/northeast Louisiana. Across the main hydrocarbon-productive trend in east Texas and north Louisiana, 

the Travis Peak Formation is about 2,000 feet thick. In east Texas, stacked, fluvial-channel sandstones comprise the 

bulk of the Formation. Channel sandstones grade upward from braided to meandering, and are capped by a thin 

sequence of coastal-plain, paralic, and marine strata reflecting the overall transgression and relative rise in sea level 

that occurred during Travis Peak deposition. In north Louisiana, sandstones deposited in interdeltaic settings are 

separated by thicker shale intervals. 

Most Travis Peak hydrocarbon production in east Texas comes from drilling depths between 6,000 and 10,000 

feet. Significant decrease in porosity and permeability through that depth interval results primarily from increasing 

amounts of quartz cement with depth. Reservoir properties of many Travis Peak sandstones, however, are 

significantly better than those characteristic of basin-center gas reservoirs in which inherent, ubiquitous, lowpermeability 

provides an internal, leaky seal for thermally generated gas. Above 8,000 feet in east Texas, Travis 

Peak sandstone matrix permeabilities often are significantly higher than the 0.1 mD cutoff that characterizes tightgas 

reservoirs. Below 8,000 feet, matrix permeability of Travis Peak sandstones is low because of pervasive quartz 

cementation, but abundant natural fractures impart significant fracture permeability. In east Texas, oil and gas seem 

to be concentrated in meandering-channel and paralic sandstones in the upper 300 feet of the Travis Peak. This 

probably occurs because these sandstones are encased in thick shales that provide effective seals. The underlying thick 

fluvial sequence lacks widespread shale barriers, and stacked, braided-channel sandstones provide an effective upward 

migration pathway for gas. In north Louisiana, relatively thick shales throughout the Travis Peak provide effective 

seals for interdeltaic sandstones. 

Because of significant variation with depth in both reservoir properties and occurrence of shale seals in the 

Travis Peak Formation in east Texas, inaccurate interpretations can be made by using pressure data or presence of 

hydrocarbon-water contacts at a particular depth to characterize the entire Travis Peak at a given well location. 

Although pressure data within the middle and lower Travis Peak Formation are limited in east Texas, significant 

overpressure caused by thermal generation of gas, which is typical of basin-center gas accumulations, is not common 

within the Travis Peak. Significant overpressure was found in only one Travis Peak sandstone reservoir in one of 24 

oil and gas fields examined across east Texas and north Louisiana. Presence of a gas-water contact perhaps is the 

most definitive criterion indicating that a gas accumulation is conventional rather than a “sweetspot” within a basincenter 

gas accumulation. Hydrocarbon-water contacts within Travis Peak sandstone reservoirs were documented in 17 

fields, and probably occur in considerably more fields, across the productive Travis Peak trend in east Texas and north 

Louisiana. All known hydrocarbon-water contacts in Travis Peak reservoirs in east Texas, however, occur within 

sandstones in the upper 500 feet of the Formation. Widespread presence of hydrocarbon-water contacts indicates lack 

of significant basin-center gas accumulations within the Travis Peak Formation throughout north Louisiana, and

within the upper 500 feet of the Travis Peak in east Texas. Although no gas-water contacts have been reported 

within the lower three-fourths of the Travis Peak Formation in northeast Texas, gas production from that interval is 

limited. Best available data suggest that most middle and lower Travis Peak sandstones are water-bearing in northeast 

Texas, at least in some fields. These data together with absence of significant overpressure suggest that the middle 

and lower Travis Peak section, too, lacks significant basin-center gas in northeast Texas. 

Insufficient hydrocarbon charge relative to permeability of Travis Peak reservoirs might be primarily responsible 

for lack of overpressure and basin-center gas within the Travis Peak Formation. Shales interbedded with Travis Peak 

sandstones in east Texas are primarily oxidized floodplain deposits with insufficient organic-carbon content to be 

significant sources of oil and gas. Most likely sources for hydrocarbons in Travis Peak reservoirs are two 

stratigraphically lower units, Jurassic-age Bossier Shale of the Cotton Valley Group, and laminated, lime mudstones 

of the Jurassic Smackover Formation. Hydrocarbon charge, therefore, might be sufficient for development of 

conventional gas accumulations but insufficient for development of basin-center gas as a result of absence of 

proximal source rocks and lack of effective migration pathways from stratigraphically or geographically distant 

source rocks. Additionally, relatively high matrix and fracture permeability through significant portions of Travis 

Peak sandstone reservoirs might allow upward migration of gas to the degree that abnormally high pressure and 

basin-center gas cannot develop. 

INTRODUCTION 

In 1982 under the auspices of its Tight Gas Sands Program, the Gas Research Institute (GRI) conducted a 

nationwide survey of low-permeability gas-bearing sandstones (Fracasso and others, 1988; Holditch, and others, 

1988; Dutton and others, 1991a). From that survey, the Lower Cretaceous Travis Peak Formation was one of two 

formations selected for comprehensive geologic and engineering research. Goals of this research were to develop 

knowledge for improving recovery of gas and reducing costs of producing gas, from low-permeability sandstone 

reservoirs. Main emphasis was on developing more effective hydraulic-fracture treatments with anticipation of 

transferring this technology to other low-permeability gas reservoirs. As part of this research program, the Bureau of 

Economic Geology (BEG) at the University of Texas in Austin conducted comprehensive geological analyses of the 

Travis Peak Formation from 1983 to 1986. BEG focus was on depositional systems, sandstone diagenesis, natural 

fractures, source rocks, burial and thermal history, and structural evolution of East Texas and North Louisiana Salt 

Basins and the Sabine Uplift. Studies of reservoir engineering properties and production characteristics of Travis Peak 

sandstones in selected gas fields also were conducted. Much of this research was based on core, wireline-log, and 

production data which GRI contractors collected from seven cooperative Travis Peak wells with permission from 

operating companies. Results from this research prompted GRI to drill and complete three Staged Field Experiment 

(SFE) wells to test understandings developed and to acquire additional data (Dutton and others, 1991a). SFE No.1 

was drilled in August 1986 in Waskom Field, Harrison County, Texas, and SFE No. 2 was drilled in September 

1987 in North Appleby Field, Nacogdoches County, Texas. Research in these two wells focused on gas-productive 

sandstones near the top and base of the Travis Peak Formation. SFE No. 3 was drilled in September 1988 in 

Waskom Field to attempt to apply technologies developed in the Travis Peak to low-permeability Cotton Valley 

sandstones. As a result of research from this GRI Tight Gas Sands Program, a wealth of information on Travis Peak 

and Cotton Valley low-permeability sandstone reservoirs was published by both GRI and BEG. Those data and 

accompanying interpretations provide a significant part of the information used in this study to evaluate potential for 

basin-center gas in the Travis Peak. Because wireline-logs and mudlogs were not available for this study, 

interpretations and conclusions herein are based solely on data reported in public literature and on production data 

accessible in a publicly available database from IHS Energy Group (petroROM Version 3.43). 

2

METHOD FOR EVALUATING POTENTIAL OF BASIN-CENTER GAS IN TRAVIS PEAK 

SANDSTONES 

One of the main requirements for occurrence of a basin-center, continuous-gas accumulation is presence of a 

regional seal to trap gas in a large volume of rock across a widespread geographic area. In classic basin-center-gas 

accumulations (Law and Dickinson, 1985; Spencer, 1987; Law and Spencer, 1993), the regional seal is provided by 

low-permeability of the reservoir itself, as described above. To evaluate potential for a continuous-gas accumulation 

within the Travis Peak Formation, therefore, it is necessary to examine reservoir properties of Travis Peak 

sandstones across the northern Gulf Coast Basin. Because reservoir properties of Travis Peak sandstones are governed 

by diagenetic characteristics, which are controlled primarily by depositional environment, it is helpful to understand 

Travis Peak depositional systems and related diagenetic patterns. 

Although gas production from Travis Peak sandstones seems to occur from discrete fields, it is necessary to 

determine if those fields are separate, conventional accumulations or so-called “sweet spots” within a regional, 

continuous-gas accumulation. Thus, it is essential to understand what characterizes the apparent productive limits of 

existing Travis Peak gas fields, including presence or absence of gas-water contacts. 

Because continuous-gas accumulations commonly are characterized by overpressure associated with thermal 

generation of gas from source rocks that generally are proximal to low-permeability reservoirs, it is important to 

evaluate presence and quality of potential source rocks, burial and thermal history of those source rocks, and 

reservoir-pressure data. 

In northeast Texas, the 2,000-foot Travis Peak Formation is characterized by heterogeneities that require one to 

exercise caution when evaluating for potential of basin-center gas accumulations. Because permeability decreases by 

four orders of magnitude across the productive depth range from 6,000 to 10,000 feet, it is inappropriate to attempt 

to characterize the entire Travis Peak Formation in a particular well using a single value for permeability. Similarly, 

because of depositional heterogeneities, sandstones in the upper 300 feet of the Travis Peak commonly are isolated 

bodies encased in shales, whereas the bulk of the underlying Travis Peak consists of an interconnected network of 

multistory, multilateral sandstone bodies without widespread shale barriers. Whereas a single fluid-pressure gradient 

might characterize much of the interconnected sandstone sequence, that gradient might be considerably different than 

the gradient for one of the isolated sandstone units in the upper Travis Peak, hence the difficulty in attempting to 

characterize the entire formation with one fluid-pressure gradient. Likewise, presence of a gas-water contact within 

one upper Travis Peak sandstone reservoir in a particular Travis Peak field might not be indicative of deeper Travis 

Peak reservoirs in that area. Finally, because most Travis Peak hydrocarbon production in northeast Texas comes 

from sandstone reservoirs within the upper 300 feet of the Formation, significantly fewer data are available from the 

lower three fourths of the Travis Peak. 

GEOLOGIC SETTING FOR TRAVIS PEAK IN NORTHERN GULF BASIN 

The Travis Peak Formation, or Hosston Formation as it is known outside of Texas, is a Lower Cretaceous 

basinward-thickening wedge of terrigenous clastic sedimentary rocks that underlies the northern Gulf of Mexico 

coastal plain from east Texas across southern Arkansas and northern Louisiana into southern Mississippi. Thickness 

of the Travis Peak Formation ranges from less than 1,000 feet in southern Arkansas to more than 3,200 feet in 

north-central Louisiana. Downdip limit of the Travis Peak has not been delineated by drilling to date. Travis Peak 

strata crop out in portions of Brown, Mills, McCulloch, San Saba, and Lampasas Counties in east-central Texas 

(Hartman and Scranton, 1992). Across the hydrocarbon-productive trend of the Travis Peak Formation (figs. 1a, 1b, 

and 1c), depth to top of the Travis Peak ranges from about 4,000 feet subsea in southern Arkansas to more than 

18,000 feet subsea in north-central Louisiana and southern Mississippi (Saucier, 1985). Although Travis Peak 

sandstones produce gas from drilling depths in excess of 16,000 feet in southern Mississippi (Thomson, 1978), most 

Travis Peak production across the major productive trend in east Texas and northern Louisiana is from drilling depths 

between 6,000 and 10,000 feet (Dutton and others, 1993). Travis Peak production across east Texas and north 

Louisiana is primarily gas, but some fields produce oil as well (figs. 1a and 1b). 

3

As shown in figure 2, the Travis Peak (Hosston) is the lowermost formation of the Lower Cretaceous Trinity 

Group, which overlies the Upper Jurassic-Lower Cretaceous Cotton Valley Group. The Cotton Valley Group and 

overlying Travis Peak Formation represent the first two major influxes of terrigenous clastic sediments into the Gulf 

of Mexico Basin following its initial formation during continental rifting 180 Ma in Late Triassic time (Salvador, 

1987; Worrall and Snelson, 1989). Earliest sedimentary deposits in East Texas and North Louisiana Salt Basins 

(figs. 2 and 3) include Upper Triassic nonmarine redbeds of the Eagle Mills Formation, the thick lower and middle 

Jurassic evaporite sequence known as Werner Anhydrite and Louann Salt, and the nonmarine Norphlet Sandstone. 

Following a major regional marine transgression across the Norphlet, upper Jurassic Smackover regressive 

carbonates were deposited, capped by redbeds and evaporites of the Buckner Formation (fig. 2). A subsequent minor 

marine transgression is recorded by the Gilmer or Cotton Valley Limestone in east Texas, although equivalent facies 

in north Louisiana and Mississippi are terrigenous clastics known as Haynesville Formation. The marine Bossier 

Shale, lowermost formation of the Cotton Valley Group (fig. 2) was deposited conformably atop the Gilmer- 

Haynesville followed by progradation of the major fluvial-deltaic sequence known as Cotton Valley sandstone or 

Schuler Formation (fig. 2). 

A significant marine transgression that halted Cotton Valley fluvial-deltaic sedimentation is recorded by the 

Knowles Limestone, uppermost formation of the Cotton Valley Group (figs. 2 and 4). Prodelta and fluvial-deltaic 

deposits of the Travis Peak Formation overlie the Knowles Limestone, marking the second major influx of 

terrigenous clastics into the northern Gulf Basin. In updip regions of the Gulf Basin, the Knowles Limestone 

pinches out, and Travis Peak fluvial-deltaic strata rest directly on Schuler fluvial deltaic units of the Cotton Valley 

Group (fig. 4). Whereas most workers consider the Knowles-Travis Peak contact to be conformable, controversy 

exists regarding presence or absence of an unconformity between the updip Schuler and Travis Peak Formations. 

McFarlan (1977), Todd and Mitchum (1977), and Tye (1989) identify a major unconformity between the Schuler and 

Travis Peak, whereas Nichols and others (1968) and Saucier (1985) consider the contact to be conformable. There is 

general agreement that the upper contact of the Travis Peak with overlying shallow-marine carbonates of the Sligo 

Formation (known as Pettet Formation outside Texas) is conformable. Most of the 15-m.y. period of Travis Peak 

deposition occurred during a relative rise in sea level (McFarlan, 1977; Vail and others, 1977), and the Travis Peak- 

Sligo contact is a time-transgressive boundary with Sligo oolitic and micritic limestones onlapping Travis Peak 

paralic and marine clastics to the north out of the Gulf Basin (Tye, 1991) (figs. 2 and 4). 

The thick Louann Salt became mobile as a result of sediment loading and associated basinward tilting in late 

Jurassic and early Cretaceous time. Salt movement was initiated during Smackover carbonate deposition and became 

more extensive with influx of the thick sequence of Cotton Valley and Travis Peak clastics (McGowen and Harris, 

1984). Many Cotton Valley and Travis Peak fields in east Texas, Louisiana, and Mississippi are structural or 

combination traps associated with Louann Salt structures. Salt structures range from small, low-relief salt pillows to 

large, piercement domes (McGowen and Harris, 1984; Kosters and others, 1989). 

The Sabine Uplift (fig. 3) is a broad, low-relief, basement-cored arch separating the East Texas and North 

Louisiana Salt Basins. With vertical relief of 2,000 feet, the Sabine Uplift has a closed area exceeding 2,500 square 

miles (Kosters and others, 1989). Isopach data across the Uplift indicate that it was a positive feature during 

deposition of Louann Salt in the Jurassic, but that main uplift occurred in late, mid-Cretaceous (101 to 98 Ma) and 

early Tertiary time (58 to 46 Ma) (Laubach and Jackson, 1990; Jackson and Laubach, 1991). As a high area during 

the past 60 m.y., the Sabine Uplift has been a focal area for hydrocarbon migration in the northern Gulf Basin during 

that time. Numerous smaller structural highs on the Uplift in the form of domes, anticlines, and structural noses 

provide traps for hydrocarbon accumulations, including many oil and gas fields with Travis Peak reservoirs. 

Interpretations of the origins of these smaller structures have included salt deformation and small igneous intrusions, 

as summarized by Kosters and others, (1989). Because the Louann Salt is thin across the Sabine Uplift, Kosters and 

others, (1989) suggest that most of the smaller structures across the Sabine Uplift developed in association with 

igneous activity. 

4

TRAVIS PEAK STRATIGRAPHY 

The Travis Peak Formation is not divided formally into members. However, Saucier (1985) and Saucier and 

others (1985) distinguished three separate stratigraphic intervals within the Travis Peak across east Texas and north 

Louisiana based on relative amounts of sandstone and shale as reflected in spontaneous-potential (SP) and gamma-ray 

character of sandstones on wireline logs. As shown in figures 5 and 6, a thin, basal interval of mixed sandstones and 

shales interpreted as delta-fringe gradationally is overlain by a thick, sandstone-rich, sequence of fluvial and 

floodplain deposits that grades upward into another interval of sandstone and mudstone interpreted as coastal-plain and 

paralic deposits (Saucier, 1985; Fracasso and others, 1988; Tye, 1989, 1991). The middle fluvial/floodplain interval, 

which is thickest and forms the bulk of the Travis Peak section, consists of stacked, aggradational, braided-channel 

sandstone units that grade upward into more isolated meandering-channel sandstone deposits (fig. 6). Sandstone units 

are interpreted as braided based on blocky SP curves, bedforms observed in conventional cores, and sandstone-body 

geometry. Stacked, braided channel units generally are 12 to 45 feet thick, but because of the absence of preserved 

shales, amalgamated channel sandstones occasionally occur as massive sandstone units up to 250 feet thick with 

blocky SP curves (Saucier, 1985). Serrated gamma-ray curves within such intervals reflect abundant shale rip-up 

clasts at the scoured bases of individual channels (Tye, 1989). Upward-fining sequences are not common and occur 

only where individual channel units are isolated by siltstones and/or shales (Saucier, 1985). 

This thick fluvial/floodplain sequence gradationally overlies a much thinner sequence with considerably higher 

mudstone content in which discrete sandstones are separated by thicker mudstones. Sandstones in this lower Travis 

Peak sequence display a variety of upward-coarsening, upward-fining, and serrated SP signatures and are interpreted as 

delta-fringe deposits. 

The thick, middle fluvial/delta-plain sequence grades upward into the third interval recognized by Saucier (1985) 

which forms the uppermost portion of the Travis Peak. Like the lower Travis Peak delta-fringe interval, this upper 

interval is characterized by discrete sandstones separated by thicker mudstones. Many sandstones in the upper interval 

display thin, spiky upward-coarsening, upward-fining, and serrated SP signatures, and are interpreted as representing 

coastal-plain and paralic deposits. Upper Travis Peak paralic units are transgressive deposits that step upward and 

landward with time (fig. 2) as they interfinger with, and are gradationally overlain by, shallow-marine shelf 

carbonates of the Sligo (Pettet) Formation (Fracasso and others, 1988). Sligo carbonates thin updip to the northwest 

as they onlap Travis Peak paralic deposits. Contact of the Travis Peak with the overlying Sligo Formation, 

therefore, is time transgressive. 

TRAVIS PEAK DEPOSITIONAL SYSTEMS 

Regional Framework 

Following the regional marine transgression recorded by deposition of the Knowles Limestone at the close of 

Cotton Valley time, Travis Peak fluvial-deltaic systems began prograding basinward across surfaces of the Schuler 

and Knowles Formations (fig. 4). Two main Travis Peak fluvial-deltaic depocenters (fig. 3) have been documented 

along the arcuate northern Gulf Coast Basin (Saucier, 1985; Tye, 1989). One depocenter was located in northeast 

Texas where the ancestral Red River flowed into East Texas Salt Basin through a structural downwarp in the 

Ouachita thrust belt. Drainage area of the ancestral Red River most likely spanned a large portion of present-day 

southwestern and midwestern United States. Coarse clastic sediment probably was derived from highlands in western 

Utah and southern Arizona. Triassic redbeds were exposed in the provenance area during Travis Peak time, and these 

might be the source of abundant red siltstones within the Travis Peak Formation in East Texas (Saucier, 1985). 

The second Travis Peak depocenter was situated in southern Mississippi and northeast Louisiana where the 

ancestral Mississippi River, which had developed as a major fluvial system during Cotton Valley time (Coleman 

and Coleman, 1981), continued to transport clastic sediments to high-constructive, elongate Travis Peak deltas in the 

northeastern Gulf Basin (Reese, 1978; Saucier, 1985; Tye, 1989). Evidence for presence of these two depocenters is 

provided by sandstone isopach patterns from Saucier (1985) who divided the Travis Peak section at its midpoint and 

mapped gross sandstone thickness of the lower and upper halves of the Formation. 

5

Across the Travis Peak hydrocarbon-productive trend in east Texas, the Formation has been divided informally 

into three general sequences based on relative amounts of sandstone and shale, as described above. However, because 

of rapid early progradation of Travis Peak fluvial-deltaic systems, the lowermost delta-fringe sequence is thin (figs 5 

and 6). With the bulk of the Travis Peak Formation deposited during a relative rise in sea level, the Formation can 

be considered to be comprised of two main units, a lower aggradational to retrogradational fluvial sequence, and an 

upper retrogradational coastal-plain/paralic sequence 

DEPOSITIONAL ENVIRONMENTS AND SAND-BODY GEOMETRY 

Lower-Travis Peak Delta-Fringe Deposits 

The basal 100 to 500 feet of the Travis Peak Formation across much of east Texas is characterized by discrete 

sandstones separated by thicker mudstones. Sandstones display upward-coarsening, upward-fining, and spiky to 

serrated SP signatures, and are interpreted as representing distributary-channel, distributary-mouth-bar, delta-front, 

interdistributary-bar, barrier-bar environments. Upward in this section, sandstones become thicker and log character 

changes from upward-coarsening to blocky as depositional systems grade into the thick, massive, sandstone-rich 

fluvial section of the middle Travis Peak. Across much of east Texas, lower Travis Peak delta-fringe deposits are 

absent and Travis Peak fluvial sandstones directly overlie the Knowles Limestone or its updip fine-grained clastic 

equivalents (Saucier, 1985). This is because the stable Travis Peak shelf, which is underlain by continental crust, 

probably did not subside readily relative to rate of lower Travis Peak deposition, and lower Travis Peak rivers eroded 

and reworked their own delta-fringe deposits as Travis Peak fluvial-deltaic systems prograded seaward (Saucier, 1985). 

Little analysis is devoted to these lower delta-fringe sandstones in the Travis Peak literature, nor is any mention 

made of hydrocarbon production from them. Perhaps this is because they are absent across much of the updip portion 

of East Texas Basin, and also, as discussed below in the section on diagenesis, reservoir properties of Travis Peak 

sandstones deteriorate significantly with depth. 

Middle Travis Peak Fluvial Deposits 

As shown in figures 5 and 6, the middle Travis Peak sandstone-rich, fluvial interval accounts for approximately 

three fourths of the 2,000-foot thickness of the Formation in east Texas. Travis Peak fluvial systems prograded 

rapidly seaward across East Texas Basin, then slowly retreated landward with time, primarily in response to relative 

rise in sea level documented during this portion of Lower Cretaceous time (McFarlan, 1977; Todd and Mitchum, 

1977; Tye, 1989, 1991). However, the thick sequence of Travis Peak fluvial sandstones and associated finer-grained, 

floodplain deposits reflects deposition during a time when aggradation (sediment supply) and development of 

accommodation space (shelf subsidence) were in approximate balance. Although channel sandstones usually are 

stacked, amalgamated units with scoured basal contacts, there is little evidence of significant incision within the 

thick Travis Peak fluvial sequence (Davies and others, 1991). 

The relative rise in sea level that occurred during Travis Peak time might have been responsible for an observed 

evolution in patterns of fluvial deposition from braided to meandering (Tye, 1989, 1991), as shown in figure 6. 

Regional stratigraphic studies across East Texas Basin suggest that early Travis Peak fluvial systems consisted of 

low-sinuosity, braided channels with bed-load movement of sand being the dominant sediment transport mechanism. 

With relative rise in sea level, upper Travis Peak fluvial systems evolved into higher-sinuosity braided and 

meandering rivers carrying significantly larger volumes of mud in suspension in addition to bed-load sand. Data from 

cores indicate that channel sandstones comprise 65 percent of the total rock volume in the low-sinuosity fluvial 

section, with the remaining 35 percent being finer-grained, argillaceous crevasse-splay sandstones and overbank 

mudstones (Davies and others, 1991). In the higher-sinuosity, meandering fluvial system, channel sandstones 

comprise only 30 percent of the section, with 70 percent of the rock volume consisting of fine-grained, argillaceous 

overbank sandstones and floodplain shales. 

6

Whereas Tye (1989, 1991) suggests that Travis Peak fluvial systems evolved from low- to high-sinuosity with 

time, Davies and others (1991) report channel type varies more with geographic position within the Travis Peak 

depocenter. They suggest that high-sinuosity channels comprise the bulk of the fluvial section on the northeastern 

flank of the Travis Peak depocenter, while low-sinuosity channels predominate in central portions of the depocenter. 

Davies and others (1991), however, admit that distinguishing between high- and low-sinuosity channel systems 

using wireline-logs alone in the absence of core data is difficult, and they recognize that most of the 2,000-foot 

Travis Peak section in East Texas Basin is not cored. Evolution of fluvial systems from low- to high-sinuosity with 

time is consistent with the documented relative rise in sea level, gradation of fluvial deposits into paralic deposits in 

the upper Travis Peak, and culmination of the transgression with deposition of Sligo carbonates. Marzo and others 

(1988) showed that in moving from proximal to distal positions within a fluvial-sheet sandstone sequence, 

amalgamated sandstone bodies become less connected and more separated by mudstones. Vertical change from stacked 

braided-channel sandstones to meandering-channel sandstones isolated within floodplain shales in the Travis Peak 

Formation, therefore, might be expected at any given location in East Texas Basin as a result of landward 

displacement of fluvial-deltaic facies during the overall Travis Peak transgression. 

Low-Sinuosity Fluvial System 

Within the Travis Peak low-sinuosity fluvial system, average thickness of individual channel sandstones is eight 

feet (Davies and others, 1991). Abandoned-channel deposits of gray-black shale that cap channel sandstones are not 

common, and where present are only a few inches thick. Because channel sandstones, reflecting successive flood 

events, tend to accumulate in vertical or en echelon patterns, solitary channel deposits are rare. Although channels 

have scoured basal contacts, significant amounts of incision have not been observed. Basal-lag conglomerates with 

black-shale clasts are thin, and generally occur only above underlying channels that are capped by thin abandonment 

units. Travis Peak amalgamated channel-sandstone units range from 12 to 45 feet thick and consist of two to five 

stacked channels (Davies and others, 1991). Occasionally, massive sandstone units up to 250 feet in thickness occur 

(Saucier, 1985). Sedimentary structures consist predominantly of planar cross stratification and horizontal 

laminations, with minor amounts of ripples (Tye, 1991; Davies and others, 1991). Because of the low amount of 

mud transported as suspended load, mud drapes are not common. Main barriers to flow that might compartmentalize 

these reservoir sandstones, therefore, are zones where porosity is occluded as a result of extensive quartz cementation. 

Stacked channel sandstone sequences are capped by red and gray floodplain mudstones and siltstones that commonly 

show evidence of roots and would seem to provide top seals. However, lateral switching in conjunction with vertical 

and en echelon stacking of channels results in multi-lateral and multistory sandstone units which span wide 

geographic areas and probably have complex interconnections with respect to pressure communication and fluid 

migration. Low-sinuosity channels are broad, tabular sandstone bodies, with thickness to width ratios of 

approximately 1:800 (Tye, 1991; Dutton and others, 1991a). At North Appleby Field in Nacogdoches County, 

Texas, Tye (1991) found channel-belt widths ranging from three to six miles. In a gas-productive zone at the base of 

the low-sinuosity fluvial section at North Appleby Field, Tye (1991) reported average thickness of stacked channelbelt 

sandstones to be 26 feet and average channel-belt width to be 4.5 miles. Patterns of channel avulsion in lowsinuosity 

rivers tend to result in preservation of long sandstone bodies, and Davies and others (1991) demonstrated 

that Travis Peak channel-belt sandstone bodies commonly span areas of 5,000 acres or more. Tye reports individual 

productive channel-belt sandstone bodies can cover 25,000 acres. 

7

High-Sinuosity Fluvial System 

High-sinuosity channel deposits in the Travis Peak Formation commonly include a lower sandstone unit that 

accumulates as a migrating point-bar deposit in an active channel and an overlying mudstone plug deposited in the 

abandoned-channel stage (Davies others, 1991). Point-bar sandstone thickness commonly is 12 to 15 feet with the 

lower 8 to 10 feet consisting of relatively clean, trough-cross-bedded sandstone overlain by a thinner sequence of 

finer-grained often shaly, rippled, sandstone with mudstone drapes. Mudstone drapes are deposited during periods of 

normal, low-velocity flow in between flood events, and collectively they can compartmentalize the upper portions of 

point-bar sandstone units. Eventual cut off of meander loops by channel avulsion during floods results in isolation of 

point-bar sandstone units. Although high-sinuosity channel sandstone units in the Travis Peak occasionally exhibit 

vertical stacking or cross cutting of successive units, most such point-bar sandstone units are isolated from each 

other by overbank mudstones and siltstones, which comprise 70 percent of the high-sinuosity sequence (Davies and 

others, 1991). High-sinuosity Travis Peak fluvial-channel deposits generally have thickness to width ratios of 1:100 

(Dutton and others, 1991). Geological estimates of the size of fully developed Travis Peak point-bar units are 

approximately 300 acres, a figure which agrees closely with drainage areas predicted from GRI reservoir-engineering 

simulation (Davies and others, 1991). 

Upper Travis Peak Coastal-Plain and Paralic Deposits 

Cores from the upper Travis Peak interval reveal the most diverse assemblage of environments within the Travis 

Peak Formation, and this diversity manifests itself along depositional dip from northwest to southeast across east 

Texas into north Louisiana (Tye, 1989). In updip regions, sandstones represent meandering-channel and overbank, 

crevasse-splay deposits, and grade downdip into distributary-channel, distributary-mouth-bar, delta-front, 

interdistributary-bar deposits. Farther downdip, sandstones were deposited in estuarine, tidal-flat, tidal-channel, and 

marine settings. Point-bar sandstones in updip coastal-plain settings are slightly thinner (5 to 15 feet thick) than 

those in the underlying high-sinuosity channel sequence, but exhibit similar characteristics, including isolation from 

each other within overbank mudstone deposits (Tye, 1989). Farther downdip, blocky to upward-fining sandstones 10 

to 25 feet thick display trough and ripple cross bedding with abundant burrows, flaser bedding, bi-directional cross 

stratification indicative of tidal currents, coal streaks and organic debris, and occasional bivalve and gastropod shell 

fragments (Tye, 1989). These sandstones are interpreted as deposits from distributary-mouth bars, and tidal and 

estuarine channels. Thinner sandstones with spiky log characters are believed to have accumulated in tidal-flat 

settings. Most all these sandstones are isolated within mudstones. 

DIAGENESIS OF TRAVIS PEAK SANDSTONES 

Burial History 

Following deposition, the Travis Peak Formation experienced progressively deeper burial in east Texas until 

late, mid-Cretaceous time when the Sabine Arch witnessed the first of two periods of uplift and erosion (Jackson and 

Laubach, 1991; Dutton and Diggs, 1992). Prior to this late mid-Cretaceous uplift, total burial depth and depth from 

surface were identical because Travis Peak strata were essentially horizontal. Because late mid-Cretaceous erosion was 

significantly greater on the crest than on the flanks of the Sabine Uplift, Travis Peak strata no longer were horizontal 

as renewed burial commenced in late Cretaceous time. Burial continued into the early Tertiary when a second period 

of uplift and erosion resulted in removal of 1,500 feet of section across most of northeast Texas (Jackson and 

Laubach, 1991; Dutton and Diggs, 1992). Consequently, maximum burial depth for the Travis Peak at any given 

locale in northeast Texas is 1,500 feet greater than present burial depth. 

In northeast Texas, most Travis Peak sandstones are fine- to very-fine-grained quartzarenites and subarkoses. 

Average framework composition is 95 percent quartz, 4 percent feldspar, and 1 percent rock fragments (Dutton and 

Diggs, 1992). Dutton and Diggs (1992) defined clean sandstones as those with less that two-percent detrital clay 

matrix. Average grain size of clean fluvial sandstones is 0.15 mm versus 0.12 mm for clean paralic sandstones. 

8

COMPACTION AND CEMENTATION 

In northeast Texas, Travis Peak sandstones experienced a complex diagenetic history involving (1) mechanical 

compaction, (2) precipitation of cements and authigenic minerals, including dolomite, quartz, illite, chlorite, and 

ankerite, (3) generation of secondary porosity through dissolution of feldspar, and (4) formation of reservoir bitumen 

(Dutton and Diggs, 1992). Loss of primary sandstone porosity in near-surface settings following deposition was 

negligible in most fluvial sandstones. Minor loss of porosity occurred in paralic sandstones from precipitation of 

dolomite cement. From surface to a burial depth of about 3,000 feet, Travis Peak sandstones lost primary porosity 

mainly though mechanical compaction. Potential further compaction was halted by extensive quartz cementation that 

occurred between 3,000 and 5,000 feet. The next significant diagenetic event was creation of secondary porosity 

through dissolution of feldspar. Additional minor porosity reduction occurred by a depth of 7,500 feet from 

precipitation of authigenic chlorite, illite, and ankerite. Sandstones on higher parts of the Sabine Uplift did not 

experience further porosity reduction from cementation. However, in Travis Peak sandstones buried below 8,000 feet 

on the west flank of the Uplift, a second episode of extensive quartz cementation occurred in which silica was 

generated from pressure solution associated with development of stylolites. 

Reservoir Bitumen 

A late-stage diagenetic event that significantly reduced porosity and permeability in some Travis Peak sandstones 

in northeast Texas was formation of reservoir bitumen (Dutton and others, 1991a; Lomando, 1992). Reservoir 

bitumen is a solid hydrocarbon that lines and fills both primary and secondary pores in Travis Peak sandstones. 

Formation of reservoir bitumen occurred after precipitation of quartz and ankerite cement (Dutton and others, 1991a), 

and its occurrence is limited to sandstones within the upper 300 feet of the Travis Peak Formation, which are 

primarily paralic sandstones. Geochemical analyses suggest that reservoir bitumen formed from deasphalting of oil 

trapped in pores of upper Travis Peak sandstones (Rogers and others, 1974; Dutton and others, 1991). The oil 

probably was similar to oil currently being produced from some Travis Peak sandstone reservoirs in fields in 

northeast Texas. According to Tissot and Welte (1978), deasphalting commonly occurs in medium to heavy oil when 

large amounts of gas dissolve into the oil. Gas that dissolves in an oil to cause deasphalting can be generated from 

thermal alteration of the oil itself, or from introduction of new gas from outside the reservoir. Level of kerogen 

maturity in mudstones interbedded with Travis Peak sandstone reservoirs suggests that oils in Travis Peak sandstones 

were subjected to temperatures sufficient to generate gas internally (Dutton, 1987). 

Among sandstones in the upper Travis Peak that contain reservoir bitumen, average and maximum volumes of 

bitumen are 4 percent and 19 percent, respectively. Samples examined by Dutton and others (1991a) that contain 

reservoir bitumen had average porosity of 7.5 percent prior to formation of bitumen. Formation of reservoir bitumen 

reduced that average porosity to 3.5 percent, a loss of 55 percent of the pre-bitumen pore space. Within the paralic 

facies, where most of the reservoir bitumen occurs, permeability patterns probably controlled the pore spaces into 

which oil originally migrated and in which reservoir bitumen eventually formed. Cross-bedded and rippled sandstones 

that are clean and well-sorted contain large volumes of reservoir bitumen, whereas burrowed, shaly, poorly-sorted 

sandstones have little or no reservoir bitumen. Consequently, many sandstone intervals that had the highest porosity 

and permeability following compaction and cementation now have little or no porosity because of formation of 

reservoir bitumen. Dutton and others (1991a) provide a specific example demonstrating the deleterious effect of 

reservoir bitumen on porosity, permeability, and wireline-log measurement of porosity. They describe a Travis Peak 

sandstone that has no reservoir bitumen from a depth of 8,216.5 feet in a particular well as having 11.6 percent 

porosity as measured by porosimeter, in-situ permeability of 22.5 mD, and average grain density of 2.65 g/cm 3 . Less 

that one foot below at 8,217.2 feet, the sandstone contains reservoir bitumen, and has porosimeter porosity of 5.4 

percent, permeability of 0.0004 mD, and average grain density of 2.51 g/cm 3 . Not only does reservoir bitumen 

significantly reduce porosity and permeability, but it dramatically affects porosity measurements from a neutrondensity 

log. Although porosimeter porosity in the sandstone at 8217.2 feet was measured as 5.4 percent, porosity 

determined from a neutron-density log was 13 percent. Overestimation of porosity with a neutron-density log occurs 

because (1) density of reservoir bitumen is approximately the same as density of drilling-mud filtrate, which 

penetrates sandstone pores during drilling, and (2) 90 to 99 percent of reservoir bitumen is measured as porosity by a 

neutron log as a result of its hydrogen content. 

9

Porosity 

Porosity and permeability of Travis Peak reservoir sandstones are controlled directly by diagenetic factors 

described above. Most hydrocarbon production from Travis Peak sandstones in northeast Texas is from drilling 

depths between 6,000 and 10,000 feet, and sandstone porosity decreases significantly with depth through that interval 

(Dutton and Diggs,1992). Average porosity of clean Travis Peak sandstones decreases from 16.6 percent at 6,000 feet 

to 5.0 percent at 10,000 feet. For all Travis Peak sandstones (clean and shaly), average porosity decreases from 10.6 

percent at 6,000 feet to 4.4 percent at 10,000 feet (fig. 7). Decrease in porosity from 6,000 to 10,000 feet is not 

caused by increased compaction (Dutton and others, 1991a; Dutton and Diggs, 1992). Decrease in porosity with 

depth results primarily from (1) increasing amount of quartz cement, and (2) decrease in amount of secondary 

porosity. Secondary porosity was generated almost exclusively from dissolution of feldspar, and original feldspar 

content of Travis Peak sandstones decreases systematically with depth (Dutton and Diggs, 1992). High initial 

porosity together with high degree of connectivity of multi-lateral, multistory braided-channel sandstones permitted 

large volumes of diagenetic fluids to move through the thick Travis Peak fluvial-sandstone sequence. As a result, the 

thick fluvial section generally lost most of its primary porosity to extensive quartz cementation. However, because 

sandstones in the upper 300 feet of the Travis Peak are encased in mudstones, smaller volumes of diagenetic fluids 

moved through these sandstones, and they often retain significant primary porosity (Dutton and Land, 1988). 

Within Travis Peak fluvial-sandstone reservoirs at North Appleby Field, Tye (1991) reported that greatest 

thickness of porous sandstone generally occurs in the widest portions of channel belts, and highest porosities occur 

within three to five feet upwards from the base of channels. 

Permeability 

According to Dutton and Diggs (1992), average stressed permeability of clean Travis Peak sandstones in 

northeast Texas decreases by four orders of magnitude from 10 mD at 6,000 feet to 0.001 mD at 10,000 feet. For all 

sandstones, average stressed permeability declines from 0.8 mD to 0.0004 mD at 10,000 feet (fig. 8). Decrease in 

permeability from 6,000 to 10,000 feet primarily is a function of (1) decrease in porosity, which in turn is caused 

principally by increasing quartz cement, and (2) increasing overburden pressure that closes narrow pore throats. 

Whereas this latter effect has a significant impact on permeability, it has little effect on porosity. 

At any given depth within the Travis Peak Formation in northeast Texas, permeability ranges over 

approximately four orders of magnitude. Also, at any given depth, average permeability is 10 times greater in clean, 

fluvial sandstones than in clean, paralic sandstones. According to Dutton and Diggs (1992), superior permeability of 

clean, fluvial sandstones probably can be attributed to three factors. First, because paralic sandstones are finer 

grained, they had poorer permeability than coarser-grained fluvial sandstones at the time of deposition. Second, 

although paralic sandstones and fluvial sandstones contain similar amounts of quartz cement, paralic sandstones 

contain an average of seven percent more total cement by having significantly larger volumes of authigenic 

dolomite, ankerite, illite and chlorite, as well as more reservoir bitumen. Thirdly, much of the porosity in paralic 

sandstones is secondary porosity and also microporosity associated with authigenic illite and chlorite that occurs 

within secondary pores. Secondary porosity and microporosity both contribute significantly less to permeability than 

does primary porosity in which pores are better connected. 

10


Although clean, paralic sandstones have an order of magnitude poorer permeability than clean fluvial sandstones 

at any given depth, most hydrocarbon production from the Travis Peak Formation in east Texas has come from 

paralic and high-sinuosity fluvial sandstones in the upper 300 feet of the Formation (Fracasso and others, 1988; 

Dutton and others, 1991a; Dutton and others, 1993). Concentration of producible hydrocarbons in sandstones in the 

upper part of the Formation probably results from absence of effective traps and seals in the underlying sandstonerich, 

low-sinuosity fluvial sequence. Multi-story and multi-lateral fluvial-channel belts within the fluvial sequence 

afford a highly interconnected network of channel sandstones that provide effective migration pathways for 

hydrocarbons. Additionally, hydrocarbon migration through this sandstone network would be enhanced by presence of 

natural fractures which are significantly more abundant in the quartz-cemented, sandstone-rich, low-sinuosity fluvial 

sequence than in overlying paralic sandstones (Dutton and others, 1991a). Consequently, most hydrocarbons 

migrating upward into the Travis Peak Formation may have passed through the sandstone-rich fluvial section until 

they were trapped within upper Travis Peak paralic and high-sinuosity, fluvial sandstones, which are encased in 

mudstones that provide effective hydrocarbon seals. Main reservoirs within the paralic sequence include tidal-channel 

and tidal-flat sandstones along with high-sinuosity, fluvial-channel sandstones deposited in coastal-plain settings 

(Tye, 1989; Dutton and others, 1991b) 

Most Travis Peak hydrocarbon production comes from (1) structural, combination, or stratigraphic traps 

associated with low-relief closures or structural noses on the crest and flanks of the Sabine Uplift, and (2) structural 

or combination traps associated with salt structures in the East Texas and North Louisiana Salt Basins (Kosters and 

others, 1989; Dutton and others, 1991b). Combination and stratigraphic traps occur where fluvial sandstones pinch 

out into floodplain mudstones and/or paralic sandstones pinch out into tidal-flat, estuarine, or shallow-marine 

mudstones across closures, noses, or on regional dip. 

According to Fracasso and others (1988), wells on west flanks of structures in northeast Texas generally require 

hydraulic-fracture treatments to produce commercially from Travis Peak sandstone reservoirs, whereas wells on the 

east flanks usually flow gas at commercial rates without stimulation. These trends reflect a general east to west 

deterioration in Travis Peak sandstone porosity and permeability across structures. These east-west patterns in 

reservoir quality of upper Travis Peak paralic sandstones are not related to depositional facies changes. According to 

Fracasso and others (1988), these patterns are attributed to controls exerted by structures on regional flow of 

diagenetic fluids which resulted in cementation being fostered on western flanks, or inhibited on eastern flanks, or 

both. 

SOURCE ROCKS 

In a study of diagenesis and burial history of the Travis Peak Formation in east Texas, Dutton (1987) showed 

that shales interbedded with Travis Peak sandstone reservoirs were deposited in fluvial-deltaic settings where organic 

matter commonly was oxidized and not preserved. With measured values of total organic carbon (TOC) in Travis 

Peak shales generally are less than 0.5 percent, these shales are not considered as potential hydrocarbon source rocks, 

according to Tissot and Welte (1978). Dutton (1987) suggested that the most likely sources for hydrocarbons in 

Travis Peak reservoirs in east Texas are (1) prodelta and basinal marine shales of the Jurassic Bossier Shale, basal 

formation of the Cotton Valley Group, and (2) laminated, lime mudstones of the lower member of the Jurassic 

Smackover Formation (fig. 3). Sassen and Moore (1988) demonstrated that Smackover carbonate mudstones are a 

significant hydrocarbon source rock in Mississippi and Alabama. Wescott and Hood (1991) documented the Bossier 

Shale as a major source rock in east Texas. Presley and Reed (1984) suggested that gray to black shales interbedded 

with Cotton Valley sandstones, as well as the underlying Bossier Shale, could be a significant source for gas. In 

summary, despite limited source-rock data, it seems likely that significant hydrocarbon source rocks occur in Bossier 

Shales of the Cotton Valley Group, which underlies the Travis Peak Formation, and also in stratigraphically lower 

Smackover carbonate mudstones (fig. 3). 

11

BURIAL AND THERMAL HISTORY 

Vitrinite reflectance (R o) is a measure of thermal maturity of source rocks based on diagenesis of vitrinite, a type 

of kerogen derived from terrestrial woody plant material. In studying diagenesis and burial history of the Travis Peak 

Formation in east Texas, Dutton (1987) reported that measured R o values for Travis Peak shales generally range from 

1.0 to 1.2 percent, indicating that these rocks have passed through the oil window (R o = 0.6 to 1.0 percent), and are 

approaching the level of onset of dry-gas generation (R o = 1.2 percent) (Dow, 1978). Maximum R o of 1.8 percent 

was measured in the deepest sample from a downdip well in Nacogdoches County, Texas. Despite relatively high 

thermal maturity levels reached by Travis Peak shales, the small amount, and gas-prone nature, of organic matter in 

these shales precludes generation of oil, although minor amounts of gas might have been generated (Dutton, 1987). 

In the absence of actual measurements of R o, values of R o can be estimated by plotting burial depth of a given 

source rock interval versus time in conjunction with an estimated paleogeothermal gradient (Lopatin, 1971; Waples, 

1980). Dutton (1987) presented burial-history curves for tops of the Travis Peak, Cotton Valley, Bossier Shale, and 

Smackover for seven wells on the crest and western flank of the Sabine Uplift. The burial-history curves show total 

overburden thickness through time and use present-day compacted thicknesses of stratigraphic units. Sediment 

compaction through time was considered insignificant because of absence of thick shale units in the stratigraphic 

section. Loss of sedimentary section associated with late, mid-Cretaceous and mid-Eocene erosional events was 

accounted for in the burial-history curves. 

Dutton (1987) provided justification for using the average present-day geothermal gradient of 2.1º F/100 ft for 

the paleogeothermal gradient for the five northernmost wells. Paleogeothermal gradients in the two southern wells 

probably were elevated temporarily because of proximity to the area of initial continental rifting. Based on the crustal 

extension model of Royden and others (1980), Dutton (1987) estimated values for elevated paleogeothermal gradients 

for these two wells for 80 m.y. following the onset of rifting before reverting to the present-day gradient for the past 

100 m.y. 

Using estimated paleogeothermal gradients in conjunction with burial-history curves, Dutton (1987), found that 

calculated values of R o for Travis Peak shales agree well with measured values. Because of this agreement, Dutton 

(1987) used the same method to calculate R o values for tops of the Cotton Valley, Bossier, and Smackover 

Formations in east Texas. Estimated R o values for the Bossier Shale and Smackover in seven wells range from 1.8 to 

3.1 percent and 2.2 to 4.0 percent, respectively, suggesting that these rocks reached a stage of thermal maturity in 

which dry gas was generated. Assuming that high-quality, gas-prone source rocks occur within these two formations, 

it is likely that one or both of these units generated gas found in Travis Peak reservoirs. 

No such regional source-rock and thermal-maturity analysis is known for Travis Peak (Hosston) Formation in 

northern Louisiana. Scardina (1981) presented burial-history data for the Cotton Valley Group, but included no 

information on geothermal gradients and thermal history of rock units. Present-day reservoir temperatures in Travis 

Peak sandstones of east Texas and northern Louisiana both are in the 200º to 250º F range (Table 1). It is likely that 

Bossier and Smackover source rocks in northern Louisiana have experienced a relatively similar thermal history to 

their stratigraphic counterparts in east Texas and, therefore, are sources for Travis Peak gas in northern Louisiana. 

Herrmann and others (1991) presented a burial-history plot for Ruston Field in northern Louisiana. At Ruston Field, 

they suggest that Smackover gas was derived locally from Smackover lime mudstones and Cotton Valley gas from 

Cotton Valley and Bossier shales. Their burial-history plot shows onset of generation of gas from Smackover and 

Cotton Valley source rocks at Ruston Field occurred about 80 Ma and 45 Ma, respectively. These estimates are 

reasonably consistent with Dutton’s (1987) date of 57 Ma for onset of generation of dry gas from Bossier Shales in 

east Texas. Most salt structures in East Texas Salt Basin were growing during Travis Peak deposition (McGowen 

and Harris, 1984) and presumably were in North Louisiana Salt Basin, as well. Therefore, these structures would 

have provided traps for hydrocarbons generated from Smackover, Bossier and Cotton Valley source rocks. Also, as 

noted earlier in this report, the Sabine Uplift has been a positive feature for the past 60 m.y. (Kosters and others, 

1989; Jackson and Laubach, 1991). It therefore would have been a focal area for gas migrating from Smackover, 

Bossier, and Cotton Valley source rocks in East Texas and North Louisiana Salt Basins. 

12

ABNORMAL PRESSURES 

Pore pressure or reservoir pressure commonly is reported as a fluid-pressure gradient (FPG) in pounds per square 

inch/foot (psi/ft). Normal FPG is 0.43 psi/ft in freshwater reservoirs and 0.50 psi/ft in reservoirs with very saline 

waters (Spencer, 1987). In his study of abnormally high pressures in basin-center gas accumulations in Rocky 

Mountain basins, Spencer (1987) considered reservoirs to be significantly overpressured if FPGs exceed 0.50 psi/ft 

where waters are fresh to moderately saline, and 0.55 psi/ft where waters are very saline. With formation-water 

salinity of Travis Peak sandstone reservoirs on the order of 170,000 ppm TDS (Dutton and others, 1993), salinity is 

considered high, and these reservoirs should be considered to be significantly overpressured if their FPGs exceed 0.55 

psi/ft. 

Calculated FPGs for Travis Peak sandstone reservoirs for various oil and gas fields in northeast Texas and 

northern Louisiana are presented in table 1, and are shown in map view in figures 9 and 10. FPGs were calculated 

from initial-shut-in pressures reported in Herald (1951), Shreveport Geological Society Reference Reports (1946, 

1947, 1951, 1953, 1956, 1963, 1987), Kosters and others (1989), Shoemaker (1989), and Bebout and others (1992). 

Multiple FPG values for a particular field in figures 9 and 10 refer to FPGs calculated for different, stacked Travis 

Peak sandstone reservoirs in that field. As shown in table 1 and figures 9 and 10, most calculated FPGs are between 

0.41 and 0.49 psi/ft. Higher FPGs were encountered in three fields in northeast Texas (fig. 9), 0.53 psi/ft at Tri- 

Cities and Percy-Wheeler Fields, and 0.54 psi/ft at Carthage Field. A gradient of 0.79 psi/ft was calculated for one 

Travis Peak sandstone reservoir in Clear Branch Field in northern Louisiana, although gradients in three other Travis 

Peak reservoirs within the same field were 0.47, 0.48, and 0.48 psi/ft (table 1, fig. 10). A number of other fields 

scattered geographically across northeast Texas and northern Louisiana exhibit below normal FPGs ranging from 

0.36 to 0.38 psi/ft. Lowest FPG in the Travis Peak field trend is 0.27 psi/ft in Village Field, Columbia County, 

Arkansas (fig. 10). 

In north Louisiana where Travis Peak hydrocarbon production comes from various interdeltaic sandstones 

scattered throughout the Travis Peak section, shut-in pressure data are available from a variety of depths within the 

Formation. In northeast Texas, however, most production comes from sandstone reservoirs in the upper 300 feet of 

the Travis Peak Formation. Consequently, shut-in pressure data are abundant for the upper 300 to 500 feet of the 

Travis Peak, but are limited in the lower three-fourths of the Formation, which includes the thick fluvial sequence 

that characterizes the bulk of the Travis Peak in northeast Texas. Calculated FPGs from sandstone reservoirs at 

depths of 500 or more feet below top to the Travis Peak are normal at Appleby North, Bethany, Cedar Springs, and 

Trawick Fields, and sub-normal at Waskom and Whelan Fields (table 1, fig 9). Reservoirs in the middle and lower 

Travis Peak section at Woodlawn and Carthage Fields also are normally pressured, according to Al Brake (BP Amoco 

engineer, personal communication, 2000), who also reports no knowledge of any significant overpressure in Travis 

Peak reservoirs at any depth within the Formation in northeast Texas. Best available data, therefore, suggest that 

significant overpressures do not occur within any reservoirs throughout the entire Travis Peak Formation in 

northeast Texas. 

13

HYDROCARBON-WATER CONTACTS 

Based on data for various Travis Peak oil and gas fields reported primarily by the Shreveport Geological Society 

(1946, 1947, 1951, 1953, 1956, 1963, 1987), East Texas Geological Society (Shoemaker, 1989), and Texas Bureau 

of Economic Geology (Herald, 1951), hydrocarbon-water contacts have been documented in Travis Peak sandstone 

reservoirs in 10 fields across east Texas and north Louisiana (figs. 11 and 12). Field reports edited by Herald (1951) 

do not use the terms “gas-water contact” or “oil-water contact”, but do report “elevation of bottom of oil or gas” and 

“lowest oil or gas”. It seems likely that “lowest gas” refers to the lowest elevation gas had been encountered by 

drilling at the time the report was written, whereas “elevation of bottom of gas” refers to an actual gas/water contact. 

Supporting that interpretation is the fact that the term “elevation of bottom of gas” clearly was used to indicate 

elevation of a gas-oil contact at Henderson Field (Herald, 1951). If this interpretation of “elevation of bottom of gas” 

is correct, hydrocarbon-water contacts are documented in Travis Peak sandstone reservoirs in four additional fields 

(Herald, 1951), as indicated in table 1 and shown by dashed field outlines in figure 11. 

With most Travis Peak production in northeast Texas coming from the upper 300 feet of the Formation, 

hydrocarbon-water contacts documented in Travis Peak sandstone reservoirs in the seven Texas fields indicated in 

table 1 and figure 11, all occur within reservoirs in that upper part of the Formation. No documentation of 

hydrocarbon-water contacts in middle or lower Travis Peak reservoirs in northeast Texas has been found. At Appleby 

North Field, Nacogdoches County, Texas, Tye (1991) reported that gas seems to be present throughout the Travis 

Peak section, though not necessarily in commercial amounts, and a discrete gas-water contact does not exist within 

the Travis Peak. 

An attempt was made to document presence or absence of hydrocarbon-water contacts in additional Travis Peak 

fields through analysis of data from drillstem tests (DSTs) and production tests. The goal was to determine if fields 

that produce from Travis Peak sandstones are flanked by dry holes that tested water only without gas, indicative of 

presence of a gas-water contact. A data set of wells penetrating the Travis Peak and Cotton Valley Group across 

much of northeast Texas and north Louisiana was extracted from a database provided by IHS Energy Group 

(petroROM Version 3.43) for analysis of DST and production-test data using ARCVIEW software. Well data were 

sorted and displayed in map view using ARCVIEW software such that wells which produce from Travis Peak 

sandstones could be distinguished from Travis Peak dry holes with tests. While viewing the map display, test results 

from any particular well could be examined. 

Reconnaissance analysis of test data show that water was recovered without gas from production tests or DSTs 

in Travis Peak sandstone reservoirs in wells on one or more flanks of Bethany-Longstreet, Cheniere Creek, and 

Caspiana Fields in northern Louisiana (fig. 12). These data indicate presence of gas-water contacts within Travis 

Peak sandstone reservoirs in those fields. 

In summary, hydrocarbon-water contacts have been documented in Travis Peak sandstone reservoirs at various 

depths within the formation in north Louisiana and within the upper 300 feet of the Formation in northeast Texas. 

Although data from the middle and lower Travis Peak section in northeast Texas are limited, no hydrocarbon-water 

contacts have been reported from that interval in northeast Texas. 

14

DISCUSSION OF EVIDENCE FOR AND AGAINST BASIN-CENTER GAS 

Source Rocks and Burial/Thermal History 

Source rocks responsible for generating gas in basin-center gas accumulations commonly are in stratigraphic 

proximity to low-permeability reservoirs that they are charging with gas. As described above, shales interbedded with 

Travis Peak sandstone reservoirs in northeast Texas have passed through the oil window and are approaching the 

level of onset of dry-gas generation. However, these shales are primarily oxidized floodplain shales with TOC 

content generally less than 0.5 percent, and therefore are not considered as potential hydrocarbon source rocks (Tissot 

and Welte, 1978; Dutton, 1987). Dutton (1987) suggested that Travis Peak marine shales depositionally downdip 

from the Travis Peak hydrocarbon-productive trend probably have higher TOC content, and thus might be potential 

source rocks. Because these marine shales occur primarily in Louisiana, Dutton (1987) expressed concern about long 

lateral migration distances that would be required to move hydrocarbons from these shales to updip Travis Peak 

sandstone reservoirs in east Texas. Dutton (1987) concluded that source rocks most likely to have generated 

hydrocarbons produced from Travis Peak reservoirs in east Texas are the marine Bossier Shale, which is the 

lowermost formation of the Cotton Valley Group, and Smackover laminated lime mudstones, which lie below the 

Bossier Shale (fig. 3). Gray to black marine shales interbedded with Cotton Valley sandstones also might be 

potential source rocks. As discussed above, burial- and thermal-history data for the northern Gulf Coast Basin 

suggest that burial depths of Bossier and Smackover source rocks, in conjunction with the regional geothermal 

gradient, have been sufficient to generate dry gas. Also, as described above, time of generation of most of this gas 

postdates development of both the Sabine Uplift and structures in East Texas and North Louisiana Salt Basins. 

Available data, therefore, provide a reasonable scenario for charging Travis Peak sandstone reservoirs with oil and 

gas. Postulated Bossier Shale source rocks, however, are separated stratigraphically from Travis Peak sandstone 

reservoirs by at least 1,000 feet of tight Cotton Valley sandstones and interbedded shales, and also by the tight 

Knowles Limestones across much of the area (fig. 4). Potential Smackover source rocks are stratigraphically lower 

yet, and are separated from the Bossier by Haynesville/Buckner units, which include anhydrite. Although a reasonable 

scenario can be established for charging Travis Peak sandstone reservoirs with gas derived from stratigraphically 

lower source rocks, abundant gas-prone source rocks are not proximal to those reservoirs. This is not characteristic, 

in general, of classic basin-center gas accumulations. 

Porosity and Permeability 

Basin-center, continuous-gas accumulations commonly involve a large volume of gas-saturated reservoir rock in 

which presence of gas cuts across stratigraphic units. Such gas accumulations require a regional seal to trap gas, and 

that seal characteristically is provided by inherent low-permeability of reservoir rocks themselves. Thus, continuousgas 

reservoirs characteristically have low permeability, and when reservoirs are sandstones, they generally are referred 

to as tight-gas sandstones. 

As discussed in the introduction, the Travis Peak Formation was selected by GRI as one of two lowpermeability 

formations for comprehensive geologic and engineering studies under auspices of its Tight Gas Sands 

Program. Also, Travis Peak sandstones have been designated as “tight” by FERC in selected areas of northeast 

Texas, north Louisiana, and in one well in Jefferson Davis County, Mississippi (Dutton and others, 1993). That 

Travis Peak sandstones have been designated “tight” only in selected areas and not universally across the northern 

Gulf Basin, however, reflects relatively high permeability of Travis Peak sandstone reservoirs locally and significant 

variation of permeability with depth (fig. 8) and geographically across the northern Gulf Basin (figs. 13 and 14). 

As shown in figure 8, permeability of Travis Peak sandstones in northeast Texas varies significantly with depth. 

Above 7,500 feet, numerous Travis Peak sandstone samples exhibit permeability values above 0.1 mD, the general 

permeability cutoff for designation as a tight-gas sandstone. At depths less than 6,000 feet, permeability can exceed 

100 mD. As discussed above, decrease in permeability of Travis Peak sandstones by four orders of magnitude from 

6,000 to 10,000 feet in northeast Texas is controlled primarily by volume of quartz cement. Such variation with 

depth probably explains much of the apparent geographic variation in permeability of Travis Peak sandstones shown 

15

in Figures 13 and 14. Multiple values of permeability for a given field in figures 13 and 14 refer to measurements 

from different, stacked Travis Peak sandstones within that field. For many fields in Figures 13 and 14, a range of 

measured permeability values are given, probably reflecting primarily variation of sandstone permeability with depth 

within those fields. Abundance of high-permeability sandstones, especially in upper portions of the Travis Peak 

Formation, is not characteristic of reservoirs that harbor basin-center gas accumulations. This is because such higherpermeability 

reservoirs cannot provide their own internal, albeit leaky, seal for gas. Although sandstones throughout 

the entire Travis Peak Formation reportedly are charged with gas in some Travis Peak fields, though not necessarily 

in commercial quantities (Davies and others, 1991; Tye, 1991; Dutton and others, 1993), gas production comes 

primarily from sandstones in the upper 300 feet of the Formation (Fracasso and others, 1988; Al Brake, BP Amoco 

engineer, personal communication, 2000). To some degree, this might be a function of higher permeability of upper 

Travis Peak sandstones, resulting in preferential completion of upper Travis Peak zones by operators. However, 

Fracasso and others (1988) suggest that hydrocarbons tend to be concentrated in upper Travis Peak sandstones 

because these sandstones are encased in shales that provide effective traps. Underlying low-sinuosity fluvial 

sandstones, comprising the bulk of the Travis Peak Formation, form a highly interconnected reservoir not only by 

virtue of their inherent multistory, multilateral sand-body geometries, but also because of the abundance of natural 

vertical fractures within the highly quartz-cemented, fluvial-sandstone sequence. Thus, the thick fluvial sequence 

seems to provide an effective upward migration pathway for gas. Data from Woodlawn Field in Harrison County, 

Texas, corroborate this interpretation. According to Al Brake (BP engineer, personal communication, 2000), mudlog 

gas shows are prominent in sandstones within the upper 500 feet of the Travis Peak at Woodlawn Field, but 

generally absent in sandstones throughout the middle and lower Travis Peak. Completion attempts within the few 

thin middle and lower Travis Peak zones that exhibit gas shows and higher resistivities generally yield marginally to 

non-commercial quantities of gas before depleting and/or giving way to water production (Al Brake, BP engineer, 

personal communication, 2000). In summary, permeability within much of the Travis Peak Formation is 

significantly higher than the 0.1-mD cutoff value defining tight-gas sandstones. Traps for much of the gas in Travis 

Peak sandstone reservoirs are provided by mudstones that encase sandstone units in the upper portions of the 

Formation rather than by inherent low permeability of the sandstone reservoirs. Travis Peak sandstone reservoirs 

exhibit reservoir properties and trapping patterns that are not entirely characteristic of basin-center gas reservoirs in 

which inherent, ubiquitous, low-permeability provides a seal for thermally generated gas. 

Abnormal Pressures 

Based on the cutoff value of FPG = 0.55 psi/ft, above which Spencer (1987) considered reservoirs with highly 

saline waters to be significantly overpressured, virtually all Travis Peak sandstone reservoirs across northeast Texas 

and north Louisiana are normally pressured (figs. 9 and 10). Some Travis Peak reservoirs have slightly elevated 

FPGs between 0.43 and 0.54 psi/ft, and a few exhibit subnormal FPGs between 0.36 and 0.38 psi/ft. Based on data 

from 24 Travis Peak fields, the only Travis Peak sandstone reservoir that is significantly overpressured is one with a 

FPG of 0.79 psi/ft in Clear Branch Field, Jackson Parish, Louisiana (fig. 9). Three shallower Travis Peak sandstone 

reservoirs in Clear Branch field have normal FPGs of 0.47 to 0.48 psi/ft (fig. 9). Although pressure data for Travis 

Peak reservoirs in north Louisiana come from various depths throughout the Travis Peak Formation, most pressure 

data for Travis Peak reservoirs in northeast Texas are from sandstones within the upper 300 feet of the Formation. Of 

17 FPG values for Travis Peak reservoirs in northeast Texas, 6 are believed to be from reservoirs at depths of 500 

feet or greater below top of the Travis Peak (table 1 and fig. 9). Four of these six FPGs are normal and two are 

subnormal. Al Brake (BP engineer, personal communication, 2000) identified two additional fields in northeast 

Texas, Woodlawn and Carthage Fields, where Travis Peak reservoirs exhibit normal FPGs throughout the 

Formation. Al Brake is not aware of any significantly overpressured Travis Peak reservoirs in northeast Texas. 

Available data, therefore, suggest absence of significant overpressure throughout the Travis Peak Formation in 

northeast Texas. If significant overpressure does occur within the middle and lower Travis Peak Formation in 

northeast Texas, it probably would be a local phenomenon without regional extent. 

16

A number of Travis Peak reservoirs exhibit subnormal FPGs (0.27 to 0.38 psi/ft), as shown in figures 9 and 

10. It is possible that these lower FPGs represent errors in measurement or lack of development of equilibrium 

conditions during tests in low-permeability rock. Also it is possible that a subnormal FPG for a particular sandstone 

reservoir reflects depletion of pressure caused by hydrocarbon production from another Travis Peak sandstone that is 

in pressure communication with the apparently subnormally pressured interval. However, if one assumes that all the 

subnormal-FPG values shown in figures 9 and 10 reflect original, virgin pressures unaffected by depletion, one 

might argue that they represent pressure declines associated with Tertiary uplift and erosion. If that were true, perhaps 

many Travis Peak reservoirs that today are normally pressured or slightly overpressured might have been 

significantly overpressured prior to Tertiary uplift and erosion. During Tertiary uplift between 58 and 46 Ma, 

approximately 1,500 feet of strata were removed across much of northeast Texas (Dutton, 1987; Laubach and 

Jackson, 1990; Jackson and Laubach, 1991). However, if much of the gas found in Travis Peak reservoirs was 

derived from Bossier Shale source rocks, migration of that gas into Travis Peak sandstones probably commenced 

between 57 and 45 Ma (Dutton, 1987; Hermann and others, 1991). Therefore, most of the thermally generated gas 

that presumably would cause development of overpressure probably migrated into Travis Peak reservoirs following 

Tertiary uplift. If Tertiary uplift and erosion resulted in pressure reduction within Travis Peak sandstone reservoirs, 

subsequent introduction of thermally generated gas has not been able to produce significant widespread overpressure 

within those reservoirs. Perhaps most subnormal FPGs calculated for Travis Peak reservoirs, therefore, reflect 

depletion of pressure caused by hydrocarbon production from another Travis Peak sandstone reservoir that is in 

pressure communication with the apparently subnormally pressured interval, or lack of development of equilibrium 

conditions during the pressure test. Best available data indicate that widespread, abnormally high pressure caused by 

thermal generation of gas that is typical of basin-center gas accumulations does not occur within the Travis Peak 

Formation. Stated another way, occurrence of normally pressured, gas-charged sandstone reservoirs throughout most 

of the Travis Peak Formation across the northern Gulf Basin suggests that a significant basin-center accumulation is 

not present within the Travis Peak. 

It is interesting to speculate on the absence of widespread overpressure in Travis Peak sandstone reservoirs across 

east Texas and north Louisiana. Perhaps there is insufficient hydrocarbon charge associated with absence of proximal 

source rocks, or with poor migration pathways from stratigraphically or geographically distant source rocks. 

Additionally, relatively high matrix and fracture permeability of significant volumes of Travis Peak sandstone 

reservoirs might prevent the Travis Peak Formation as a whole from retarding upward migration of gas sufficiently 

to enable abnormally high pressures to develop. Insufficient hydrocarbon charge relative to effectiveness of Travis 

Peak sandstone reservoirs to transmit, rather than retard the flow of, gas could explain lack of regional overpressure 

within the Travis Peak Formation. 

Restriction of reservoir bitumen in Travis Peak sandstones to reservoirs in the uppermost 300 feet of the 

Formation might be significant in understanding hydrocarbon charge. Reservoir bitumen probably formed in pores of 

Travis Peak sandstones from deasphalting of oil caused by dissolution of gas in the oil. Was oil present throughout 

most of the Travis Peak Formation, but sufficient quantities of gas developed, or were introduced, only in the upper 

300 feet of the Travis Peak to promote deasphalting there? Or was oil that experienced deasphalting originally 

present only in sandstones within the uppermost 300 feet of the Formation, reflecting limited charge of oil into the 

Travis Peak? The latter explanation seems more logical because even within upper Travis Peak sandstones, bitumen 

occurs only in clean, well-sorted, rippled and cross-bedded sandstones. Absence of bitumen from burrowed, shaly, 

poorly sorted sandstones in the upper Travis Peak suggests that charge was insufficient to drive oil through smaller 

pore throats. Thus with respect to the oil phase, hydrocarbon charge seems to be limited. 

An additional question concerns the source of gas that promoted deasphalting of Travis Peak oil to produce 

reservoir bitumen. Was the gas generated in place through thermal alteration of Travis Peak oil, or was it introduced 

from some external source? The answer is unknown, although level of kerogen maturity in mudstones interbedded 

with Travis Peak sandstone reservoirs suggests that oils in Travis Peak sandstones were subjected to temperatures 

sufficient to generate gas internally (Dutton, 1987). However, the extensive volume of gas within Travis Peak 

reservoirs regionally might suggest that much of that gas was derived from an external source, presumably Bossier 

Shales and/or Smackover laminated, lime mudstones. Thus there might have been a two-phase of migration of 

hydrocarbons into Travis Peak reservoirs, perhaps similar to that described in general terms by Gussow (1954). As 

Bossier and Smackover source rocks were buried, they first generated oil, some of which might have migrated into 

17

Travis Peak sandstones where it was trapped. With continued burial, Bossier and Smackover source rocks reached the 

gas window, spawning an episode of gas generation that might be continuing today. This later gas might have 

caused deasphalting of previously emplaced oil in Travis Peak sandstones as well as displacement of oil from some 

Travis Peak reservoirs. However, as evidence seems to suggest a limited charge of oil into Travis Peak reservoirs, 

perhaps gas charge also is sufficiently limited relative to transmissibility of Travis Peak sandstone reservoirs to 

prohibit development of regional overpressure and accompanying basin-center gas. 

Hydrocarbon-Water Contacts 

Perhaps the most definitive criterion for establishing presence of a basin-center gas accumulation is absence of 

gas-water contacts. Gas-water contacts are distinctive features of conventional gas accumulations. Presence of a gaswater 

contact indicates a change from gas-saturated to water-saturated porosity within a particular reservoir unit. This 

implies that a well drilled into that reservoir structurally below the gas-water contact should encounter only water, 

thereby demonstrating the absence of a continuous-gas accumulation in that immediate area. Documentation of 

occurrence of gas-water contacts within a particular stratigraphic unit in various gas fields distributed across a 

particular basin argues strongly against presence of a continuous- or basin-center gas accumulation within that 

particular interval in the basin. 

As shown in figures 11 and 12, hydrocarbon-water contacts have been documented within Travis Peak sandstone 

reservoirs in 13 fields across east Texas and north Louisiana. As discussed above and as indicated by dashed field 

outlines in figure 11, four additional Travis Peak fields probably also have hydrocarbon-water contacts, depending 

upon interpretation of the term “elevation of bottom of gas” as reported by Herald (1951). Data for many Travis Peak 

fields presented in Shreveport Geological Society Reference Reports (1946, 1947, 1951, 1953, 1956, 1963, 1987) 

and Shoemaker (1989) either do not mention hydrocarbon-water contacts or report that none were encountered. 

However, because many of those reports were prepared not long after fields were discovered, sufficient development 

drilling probably had not occurred to encounter hydrocarbon-water contacts. In other cases, fluid contacts were not 

included as part of the field description. Lack of reported Travis Peak hydrocarbon-water contacts in such field reports, 

therefore, should not be interpreted as absence of oil-water or gas-water contacts in those fields. Consequently, it is 

likely that considerably more of the Travis Peak fields shown in figures 1a and 1b have hydrocarbon-water contacts 

than illustrated in figures 11 and 12. 

Supporting that inference is the inferred presence of Travis Peak gas-water contacts at fields such as Bethany- 

Longstreet and Cheniere Creek in northern Louisiana (fig. 12) based on recoveries of water without gas from 

production tests and DSTs of Travis Peak sandstone reservoirs on flanks of those fields. Although water recoveries 

from flank wells suggest presence of gas-water contacts within Travis Peak reservoirs in those fields, gas-water 

contacts were not reported for Travis Peak reservoirs in those fields in Shreveport Geological Society Reference 

Reports (1963, 1987). 

As discussed above, all hydrocarbon-water contacts within Travis Peak sandstone reservoirs in fields in northeast 

Texas documented in this report (table 1 and figure 11) occur the upper 300 feet of the Travis Peak Formation. No 

documentation of hydrocarbon-water contacts in middle or lower Travis Peak reservoirs in northeast Texas has been 

found. At Woodlawn Field in Harrison County, Texas, a discrete gas-water contact has not been identified in the 

lower Travis Peak Formation. However, commercial gas production from the middle and lower Travis Peak section 

at Woodlawn Field is limited, and most of that interval at Woodlawn Field is considered water-bearing, according to 

Al Brake (BP engineer, personal communication, 2000). In addition to sandstones within the upper 500 feet of the 

Travis Peak, a deeper sandstone interval about 200 feet above the bottom of the Travis Peak Formation produces gas 

in commercial quantities at Woodlawn Field. BP refers to this deeper productive interval at Woodlawn Field as the 

McGee Sandstone. Al Brake reports that the bulk of the Travis Peak section between the McGee Sandstone and 

productive sandstones in the upper 500 feet of the Travis Peak lacks mudlog gas shows and is not considered 

productive. Locally within the middle and lower Travis Peak interval at Woodlawn Field, Al Brake reports that 

scattered 10- or 12-foot sandstones occasionally have high resistivity within the upper one to three feet accompanied 

by mudlog gas shows, and lower resistivity below with no mudlog gas shows. Some of these thin, high-resistivity 

intervals have been perforated and tested. Typical cumulative production from one of these thin intervals ranges from 

18

insignificant to a maximum of only about 0.1 BCFG before the zone depletes and gives way to water production. 

Based on general lack of mudlog gas shows, scattered presence of only thin one- to three-foot high-resistivity gasbearing 

zones, and limited recovery of gas throughout the bulk of the Travis Peak section between the deeper McGee 

Sandstone and the uppermost 500 feet of the Formation, Al Brake (BP Amoco engineer, personal communication, 

2000) considers the middle and lower Travis Peak interval at Woodlawn Field to be largely water-bearing. If these 

reservoir and production characteristics are typical of other Travis Peak Fields, this information from Woodlawn 

Field tends to confirm the interpretation of Fracasso and others (1988) that commercial quantities of hydrocarbons in 

Travis Peak sandstones are concentrated within the sandstones in the upper 300 feet of the Formation. 

Patterns of gas occurrence and production at Woodlawn Field might have significance in understanding Travis 

Peak gas reservoirs at Appleby North Field in Nacogdoches County, Texas. According to Tye (1991), gas occurs 

throughout the Travis Peak Formation at North Appleby Field, though not necessarily in commercial amounts, and 

a discrete gas-water contact reportedly is not present. As at Woodlawn Field, however, sandstone reservoirs 

throughout the Travis Peak Formation at North Appleby Field, are normally pressured (Lin and others, 1985), which 

is not characteristic of basin-center gas accumulations. Furthermore, although most of the Travis Peak section at 

North Appleby Field reportedly is gas-charged, perforations in the field well shown by Tye (1991) are limited to only 

a few sandstones that are capped by thicker shale units. Perforated sandstones in this well are restricted to two zones, 

one within the upper 500 feet of the Travis Peak between depths of 8,200 and 8,500 feet, and a second zone about 

200 feet from the bottom of the Formation between depths of 9,800 and 10,000 feet. This pattern of perforations is 

strikingly similar to that described by Al Brake for Travis Peak sandstones at Woodlawn Field. Although cores were 

cut in several intervals within the thick intervening fluvial-sandstone section in that well at Appleby North Field, no 

zones were perforated between 8,500 feet and 9,800 feet. Examination of production-test data from other wells in 

Appleby North Field indicates that most perforations are restricted to the upper 500 feet of the Travis Peak section. 

Only two other wells in Appleby North Field were found with perforations in that deeper interval about 200 feet 

from the base of the Travis Peak. Initial-production rates of 72 and 114 MCFD from lower-Travis Peak perforations 

in these two wells suggest that this deeper zone at Appleby North Field probably is marginally to non-commercial. 

Limitation of perforations within the middle and lower Travis Peak Formation at Appleby North Field to one zone 

about 200 feet from the bottom of the Travis Peak shows striking resemblance to the pattern observed at Woodlawn 

Field where the normally pressured middle and lower Travis Peak section reportedly is largely water-bearing. 

Although mudlog data from wells in Appleby North Field were not available for this study, one might wonder if the 

bulk of the middle and lower Travis Peak section there the lacks gas shows and largely is water-bearing despite the 

report of being gas charged by Tye (1991). Tye’s report that the middle and lower Travis Peak Formation at Appleby 

North Field is gas charged was based on personal communication with no supporting data, and was accompanied by 

the qualification that gas might not be present in commercial quantities throughout the section. Such qualification 

bears some resemblance to the situation described by Al Brake at Woodlawn Field where scattered thin, highly 

resistive zones in the middle and lower Travis Peak produce small amounts of gas before depleting and yielding 

water. Finally, in considering the potential for basin-center gas, it is significant that despite the lack of documented 

gas-water contacts within the middle and lower Travis Peak at Woodlawn and Appleby North Fields, the entire Travis 

Peak interval at both fields reportedly is normally pressured. 

In summary, hydrocarbon-water contacts in Travis Peak sandstone reservoirs have been documented at various 

depths within the Travis Peak Formation in nine fields in north Louisiana. In northeast Texas, hydrocarbon-water 

contacts have been reported within Travis Peak sandstone reservoirs in eight fields, but these all occur within the 

upper 300 to 500 feet of the Travis Peak Formation. Rather than being clustered, however, these fields with 

documented hydrocarbon-water contacts are widely distributed across the east-Texas and north-Louisiana Travis Peak 

productive trend. Wide distribution of such conventional hydrocarbon accumulations with hydrocarbon-water contacts 

suggests absence of significant basin-center gas accumulations within the entire Travis Peak Formation in north 

Louisiana and within the upper 500 feet of the Travis Peak Formation in northeast Texas. Data on hydrocarbon-water 

contacts in the lower three fourths of the Travis Peak section in northeast Texas are limited and less conclusive. At 

fields such as Appleby North and Woodlawn in northeast Texas, clearly defined gas-water contacts reportedly are not 

present or have not been identified. Travis Peak reservoirs at Appleby North and Woodlawn Fields, however, are 

normally pressured, which is not characteristic of basin-center gas accumulations. Best available data suggest that the 

lower three fourths of the Travis Peak Formation across much of northeast Texas is characterized by a general lack of 

mudlog gas shows and only a few gas-charged sandstones that yield marginal to non-commercial production before 

19

depleting and giving way to water production. Operators consequently seem to focus efforts on Travis Peak 

completions within sandstone reservoirs in the uppermost 300 to 500 feet of the Travis Peak Formation, resulting in 

limited data in the lower three fourths of the Formation. Although pressure data from depths below 500 feet of top of 

the Travis Peak are limited, data from eight fields indicate normal or subnormal FPGs, and suggest absence of 

significant overpressure throughout the Travis Peak Formation in northeast Texas. In the absence of documented gaswater 

contacts below 500 feet of top of the Travis Peak Formation in northeast Texas, limited data indicating 

presence of abundant water-bearing sandstones and a lack of significant overpressure together suggest absence of 

significant basin-center gas accumulations within the middle and lower Travis Peak. 

CONCLUSIONS 

20 

1) The Travis Peak (Hosston) Formation is a Lower Cretaceous basinward-thickening wedge of terrigenous 

clastic sedimentary rocks that underlies the northern Gulf of Mexico Basin from east Texas across northern 

Louisiana into southern Mississippi. Clastic influx was focused in two main fluvial-deltaic depocenters 

associated with the ancestral Red River in northeast Texas and the ancestral Mississippi River in southern 

Mississippi and northeast Louisiana. 

2) Across its hydrocarbon-productive trend in northeast Texas, the Travis Peak Formation is divided into three 

informal units based on relative amounts of sandstone and shale. A thin lower interval consists of mixed 

sandstones and shales interpreted as delta-fringe deposits. It is gradationally overlain by a thick, sandstonerich, 

sequence that forms the bulk of the Travis Peak section comprised primarily of stacked, braidedchannel 

sandstones grading up into meandering-channel deposits. The third and uppermost interval consists 

of mixed sandstone and mudstone interpreted as coastal-plain, paralic, and marine deposits. Upward 

stratigraphic evolution from braided- through meandering-fluvial systems to paralic and marine strata reflects 

an overall transgression and relative rise in sea level that occurred during Travis Peak deposition. 

3) Most hydrocarbon production from the Travis Peak Formation in northeast Texas and north Louisiana is 

from drilling depths of 6,000 to 10,000 feet, and through that interval, porosity and permeability of Travis 

Peak sandstones decrease significantly with depth. In northeast Texas, average porosity of clean Travis Peak 

sandstones decreases from 16.6 percent at 6,000 feet to 5.0 percent at 10,000 feet. Average stressed 

permeability of clean sandstones decreases by four orders of magnitude from 10 mD at 6,000 feet to 0.001 

mD at 10,000 feet. Decrease in porosity with depth results primarily from (a) increasing amount of quartz 

cement, and (b) decrease in amount of secondary porosity, which was derived almost exclusively from 

dissolution of feldspar. Decrease in permeability with depth occurs mainly because of (a) decrease in 

porosity, which in turn is caused principally by increasing quartz cement, and (b) increasing overburden 

pressure that closes narrow pore throats. 

4) Reservoir properties of many Travis Peak sandstones are significantly better than those characteristic of 

basin-center gas reservoirs in which inherent, ubiquitous, low-permeability provides an internal, leaky seal 

for thermally generated gas. Although Travis Peak sandstones have received tight-gas designation across 

selected portions of east Texas and north Louisiana, at depths less than 7,500 feet in northeast Texas, the 

sandstones often exhibit permeabilities well above the 0.1-mD cutoff for qualification as a tight-gas 

reservoir. At depths less than 6,000 feet, permeability can exceed 100 mD. At depths below 8,000 feet, 

where matrix permeability generally is less than 0.1 mD as a result of extensive quartz cementation, natural 

fractures are common, imparting fracture permeability to the reservoir. In north Louisiana where interdeltaic 

sandstones are separated by shale intervals, hydrocarbon production comes from sandstones throughout the 

Travis Peak. In northeast Texas, most production of oil and gas from the Travis Peak comes from sandstone 

reservoirs in the upper 300 feet of the Formation. This seems to reflect a concentration of hydrocarbons in 

the upper Travis Peak, though in some fields, sandstones throughout the Travis Peak Formation are 

reportedly gas-charged. Concentration of oil and gas probably occurs in upper Travis Peak sandstones 

because these meandering-channel, tidal-channel, and tidal-flat sandstones are encased in thick shales that 

provide effective seals. Underlying low-sinuosity fluvial sandstones, comprising the bulk of the Travis Peak

21 

Formation, form a highly interconnected network because of their inherent multistory, multilateral sandbody 

geometries, as well as abundance of natural vertical fractures within the highly quartz-cemented 

sequence. Thus, the thick fluvial sequence with its lack of thick, widespread shale barriers seems to provide 

an effective upward-migration pathway for gas rather than affording inherent sealing capabilities typical of 

reservoirs harboring basin-center gas accumulations. 

5) Source rocks generating hydrocarbons produced from Travis Peak sandstone reservoirs are not proximal to 

those reservoirs. Vitrinite reflectance (Ro) of Travis Peak shales interbedded with reservoir sandstones in 

east Texas indicate that they have passed through the oil window and are approaching onset of dry-gas 

generation. However, these shales are primarily oxidized, floodplain shales with total organic carbon content 

less than 0.5 percent, and consequently are not considered likely sources of oil and gas. Travis Peak marine 

shales depositionally downdip in the Gulf Basin in central Louisiana might have generated hydrocarbons, 

but relatively long-distance lateral migration would be necessary. Most likely source rocks for gas and oil 

produced from Travis Peak sandstones are Jurassic Bossier Shale of the underlying Cotton Valley Group and 

stratigraphically lower, laminated, carbonate mudstones of the Jurrassic Smackover Formation. Burial- and 

thermal-history data for east Texas and north Louisiana suggest that onset of dry-gas generation from 

Smackover mudstones and Bossier Shales occurred about 80 Ma and 57 Ma, respectively. Bossier Shales, 

however, are separated from Travis Peak reservoirs by at least 1,000 feet of tight Cotton Valley sandstones 

and interbedded shales, and also by the tight Knowles Limestone across much of the area. 

6) Unlike basin-center gas reservoirs, which generally are abnormally pressured, Travis Peak sandstone 

reservoirs across east Texas and north Louisiana commonly are normally pressured. Of 24 fields for which 

pressure data are reported here, only one has a Travis Peak reservoir that is considered significantly 

overpressured, i.e., with FPG greater than 0.55 psi/ft. At Clear Branch Field, Louisiana, one sandstone has 

a FPG = 0.79 psi/ft, but three other Travis Peak sandstone reservoirs within that field are normally 

pressured. In north Louisiana, pressure data are available from sandstones throughout the Travis Peak, 

whereas in northeast Texas, most available pressure data are from reservoirs in the upper 300 to 500 feet of 

the Travis Peak Formation. Limited data from the lower three fourths of the Travis Peak in northeast Texas 

suggest absence of significant overpressures in that interval, too. Some fields exhibit underpressured 

reservoirs with FPGs ranging from 0.27 to 0.38 psi/ft. If these data are accurate, they might suggest 

pressure decrease associated with Tertiary uplift and erosion across northeast Texas. Most of the gas 

presumably generated from Bossier and Smackover source rocks probably migrated into Travis Peak 

reservoirs following Tertiary uplift. If Tertiary uplift and erosion resulted in pressure reduction within 

Travis Peak sandstone reservoirs, subsequent introduction of thermally generated gas has not been able to 

produce significant widespread overpressure in those reservoirs. Thus, Travis Peak reservoirs across the 

northern Gulf Basin are characterized by normal to slightly below normal pressures. Widespread abnormally 

high pressure caused by thermal generation of gas that is typical of basin-center gas accumulations does not 

occur within the Travis Peak Formation. 

7) Presence of a gas-water contact perhaps is the most definitive criterion suggesting that a gas accumulation 

is conventional rather than a “sweetspot” within a basin-center, continuous-gas accumulation. Hydrocarbonwater 

contacts within Travis Peak sandstone reservoirs have been documented in nine fields in north 

Louisiana and eight fields in northeast Texas. In all eight fields in northeast Texas, however, hydrocarbonwater 

contacts occur in sandstone reservoirs in the uppermost 300 to 500 feet of the Travis Peak Formation. 

In northeast Texas, no documented gas-water contacts have been found in Travis Peak reservoirs in the 

lower three fourths of the Formation. In a few Travis Peak fields, such as Appleby North Field, 

Nacogdoches County, Texas, gas reportedly is present, though not always in commercial amounts, in 

sandstones throughout the Travis Peak Formation, and a discrete gas-water contact reportedly is not present. 

However, Travis Peak reservoirs at North Appleby field are normally pressured. Perhaps vertically-extensive 

gas-water transition zones with poorly defined gas-water contacts occur in some Travis Peak reservoirs such 

as those at North Appleby Field, as is characteristic of normally pressured conventional gas accumulations 

in low-permeability reservoirs. Alternatively, pattern of perforated intervals at Appleby North Field is 

similar to that at Woodlawn Field where most of the middle and lower Travis Peak section reportedly is 

water-bearing. Despite lack of documented gas-water contacts within the lower three fourths of the Travis

22 

Peak in northeast Texas, limited data on pressures within that interval indicates lack of significant 

overpressure, and hence suggests absence of significant basin-center gas accumulations. Fields with clearly 

documented hydrocarbon-water contacts throughout the Travis Peak in Louisiana and within the upper 300 

to 500 feet of the Formation in northeast Texas are distributed widely across the Travis Peak productive 

trend. Wide distribution of conventional hydrocarbon accumulations with discrete hydrocarbon-water 

contacts indicates absence of a significant basin-center gas accumulation within the Travis Peak Formation 

in Louisiana, and within the upper 300 to 500 feet of the Travis Peak in northeast Texas. 

8) Insufficient hydrocarbon charge together with sufficiently high reservoir permeability might explain why 

Travis Peak sandstone reservoirs generally are normally pressured and commonly exhibit discrete 

hydrocarbon-water contacts. Perhaps lack of proximal source rocks and lack of effective migration pathways 

from stratigraphically or geographically distant source rocks result in insufficient hydrocarbon charge. 

Furthermore, Travis Peak sandstone reservoirs might have sufficiently high matrix and fracture permeability 

through sufficient stratigraphic thickness and across sufficient geographic extent to allow upward migration 

of gas to the degree that abnormally high pressure and basin-center gas cannot develop. The result might be 

that hydrocarbons are trapped primarily in sandstones encased in thick shales within the upper portion of the 

Travis Peak, which commonly does occur. 

9) Lack of proximal source rocks, relative abundance of reservoir sandstone with significant matrix and fracture 

permeability, and especially the abundance of normally pressured reservoirs together with widespread 

presence of hydrocarbon-water contacts suggest that basin-center gas is absent or insignificant within the 

Travis Peak Formation. If any areas of continuous gas occur within the Travis Peak Formation, they 

probably occur in northeast Texas southwest of the Sabine Uplift within the lower three fourths of the 

Travis Peak, and probably are not sufficiently large to have a significant impact on hydrocarbon resource 

assessment for the Travis Peak. 


I thank Steve Condon, USGS geologist in Denver, for extracting Travis Peak well and test data from the IHS 

Energy Group database and preparing them for analysis with ARCVIEW software at the USGS Denver facility. 

Laura Biewick, USGS Denver, and Steve Condon provided expert instruction and assistance in using ARCVIEW to 

evaluate Travis Peak well and test data. I also thank the staff at the USGS library in Denver, USGS geologist Ted 

Dyman, and Gregory J. Zerrahn and Joseph A. Lott, geologists with Palmer Petroleum, Shreveport, Louisiana, for 

prompt and thorough assistance in obtaining reports, maps, and literature, without which this study could not have 

been accomplished.

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3 

Presley, M.W., and C.H. Reed, 1984, Jurassic exploration trends of east Texas, in Presley, M.W., ed., The 

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Coast Assoc. Geol. Socs. Trans., v. 26, p. 59-63. 

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studies, western Canada Basin: Amer. Assoc. Petroleum Geologists Bulletin, v. 58, no. 9, p. 

1806-1824. 

Royden, L., J.G. Sclater, and R.P. Von Herzen, 1980, Continental margin subsidence and heat flow: important 

parameters in formation of petroleum hydrocarbons: Amer. Assoc. Petroleum Geologists Bull., v. 64, 

no. 2, p. 173-187. 

Salvador, A., 1987, Late Triassic-Jurassic paleogeography and origin of Gulf of Mexico Basin: Amer. Assoc. 

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211-0708, 233 p. 

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p. 


Arkansas, Mississippi, and Alabama: Shreveport Geological Society Reference Volume I, 333p. 


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4 

Shreveport Geological Society, 1980, Report on selected oil and gas fields, north Louisiana and south Arkansas: 

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Shreveport Geological Society, 1987, Report on selected oil and gas fields, Ark-La-Tex and Mississippi: 

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HEADINGS & ABBREVIATIONS FOR TABLE 1: TRAVIS PEAK FIELDS 

Field Name of field producing from Travis Peak sandstones 

County, State County and state in which field is located 

Disc Date Date of discovery of oil or gas in particular Travis Peak sandstone 

Trap Trapping mechanism for field. 

Struct = structural trap 

Strat = stratigraphic trap 

Comb = combination structural & stratigraphic trap 

A = anticline 

FA = faulted anticline 

FC = facies change (sandstone pinchout) 

N = structural nose 

FN = faulted structural nose 

Depth Depth in feet to particular productive Travis Peak sandstone reservoir 

Porosity Sandstone porosity (decimal) 

Perm Permeability (mD) 

BHT Bottom hole temp (º F) 

BHP Bottom hole pressure (psi) 

FPG Fluid pressure gradient (psi/ft) 

S w 

Water saturation (decimal) 

Fluid Contacts Gas-oil, oil-water, and gas-water contacts 

GOC = gas-oil contact 

OWC = oil-water contact 

GWC = gas-water contact 

IP = Initial production rate for specific Travis Peak sandstone reservoirs 

MCFD = thousand cubic feet per day (gas) 

BOPD = barrels of oil per day 

BCPD = barrels of condensate per day 

BWPD = barrels of water per day

Field County State Discovery Trap Depth Porosity Perm BHT BHP FPG Pos Sw Fluid Contacts IP IP IP IP 

Date (feet) (md) (F) (psi) (psi/ft) (mcfd) (bopd) (bcpd) (bwpd) 

Appleby North Nacogdoches TX Strat (FC) 8872 0.11 0.015 (ave) 254 3890 0.44 L 0.28 

Bethany Panola, Harrison TX 1940 Comb(FA, FC) 6024 2295 0.38 U 60,000 720 

1948 6300 0.15 115 206 3113 0.49 uL 0.34 

Blackfoot Anderson TX 1948 Comb(A, FC) 9918 U Elevation of bottom of oil -9589 63 

Carthage Panola TX 1942 Struct (A) 6128 Lenticular sandstones w/ complex GWCs 5,900 147.5 

1944 6,439 26.7 

1945 6230 0.15 10.8 3350 0.54 U 0.24 

Cedar Springs Upshur TX 1967 Struct(A) 8960 0.10 240 4409 0.49 L 0.30 

Chapel Hill Smith TX 1947 Comb(A, FC) U Elevation of bottom of gas -7835 

Cyril Rusk TX 1963 Strat (FC) 7650 0.09 -0.18

Field County State Discovery Trap Depth Porosity Perm BHT BHP FPG Pos Sw Fluid Contacts IP IP IP IP 

Date (feet) (md) (F) (psi) (psi/ft) (mcfd) (bopd) (bcpd) (bwpd) 

Holly DeSoto LA 1974 Strat(FC) 7000 

Leatherman Creek Claiborne LA 1975 Comb(FA, FC) 8387-9614 0.10 0.7 215 0.47 0.30 5,585 24 

Lisbon Claiborne LA 1941 Strat (FC) 5100 0.23 500 

Lisbon North Claiborne LA 1941 Struct(A) 5112 3,840 56 

Lucky Bienville LA 1943 Struct(FA) 7900 0.15 2800 0.35 2,000 

Ruston Lincoln LA 1943 Comb(A, FC) 5896 2400 0.41 Multiple sands with separate GWCs 45,000 

1944 5745 25,000 

Sailes Bienville LA 1945 Comb(FA, FC) 8847 0.14 0.3 432 

Shreveport Caddo, Bossier LA 1951 Struct(A) 6238 2,080 

Simsboro Lincoln LA 1936 Struct(FA) 6571 0.22 500 Multiple sands with separate GWCs 67,634 

1951 Struct(FA) 8069 0.15 2 to 50 16,500 

Sugar Creek Claiborne LA 1936 Comb(FA, FC) 5600 0.19 65 2300 0.41 20,000 

1937 5718 Multiple sands with separate GWCs & OWCs 205 

Vixen Caldwell LA 1945 Struct(A) 9700 3600 0.37 9,000 

Waskom Caddo LA Comb(A,FC) 

Village Columbia AR 1946 Struct(A) 4800 0.26 706 1300 0.27

Hill 

Falls 

OK 

DETAIL 

AREA 

TX 

Ellis 

Limestone 

Collin 

AR 

LA 

Navarro 

MS 


LOCATION MAP 

POKEY 

AL 

Hunt 

RISCHERS STORE 

REED 

TEAGUE WEST 

McBEE 

Henderson 

Freestone 

Van Zandt 

Leon 

Rains 

TRI CITIES 

Hopkins Franklin 

Anderson 

OPELIKA 

BLACKFOOT 

Travis Peak Gas 

Travis Peak Oil 

0 10 20 30 40 Miles 

Figure 1a. Map of northeast Texas showing major fields that have produced hydrocarbons from Travis Peak (Hosston) sandstone 

reservoirs. 

Wood 

Smith 

CHAPEL HILL 

Cherokee 

Titus 

Camp 

Upshaw 

WILLOW 

SPRINGS 

Gregg 

PERCY WHEELER 

CYRIL 

WHITE OAK 

CREEK 

CEDAR SPRINGS 

DANVILLE 

Rusk 

HENDERSON 

Angelina 

Morris 

HENDERSON 

SOUTH 

TRAWICK 

LANSING 

NORTH 

MINDEN 

Nacogdoches 

Cass 

LASSATER 

Marion 

WHELAN 

APPLEBY 

NORTH 

Harrison 

Panola 

Shelby 

TEXAS 

WOODLAWN 

CARTHAGE 

PINEHILL SOUTHEAST 

JOAQUIN 

San Augustine 

Miller 

LA 

Caddo 

LOUISIANA AR 

LONGWOOD 

WASKOM 

BETHANY- 

LONGSTREET 

De Soto 

Hemphill 

Sabine

Cass 

Marion 

Harrison 

TEXAS 

LOUISIANA 

WASCOM 

Panola 

Shelby 

Miller 

Caddo 

SHREVEPORT 

Lafayette 

Bossier 

CASPIANA 

BETHANY- 

LONGSTREET 

De Soto 

Sabine 

ELM 

GROVE 

Columbia 

COTTON 

VALLEY 

Claiborne 

ATHENS 

Webster 

LEATHERMAN 

CREEK 

SIBLEY 

SAILES 

Beinville 

LUCKY 

Red River 

ADA 

BRYCELAND 

WEST 

VILLAGE 

Natchitoches 

LISBON NORTH 

LISBON 

SUGAR 

CREEK 

DANVILLE 

ARCADIA 

Union 

ARKANSAS 

LOUISIANA 

HICO-KNOWLES 

Lincoln 

RUSTON 

SIMSBORO 

BRYCELAND 

Jackson 

BEAR CREEK CHATHAM 

HODGE 

CLAY 

Winn 

Travis Peak Gas 

Travis Peak Oil 

0 10 20 30 40 Miles 

Figure 1b. Map of north Louisiana and southern Arkansas showing major fields that have produced hydrocarbons from Travis Peak 

(Hosston) reservoirs. Modified from Bebout et al. (1992). 

Union 

DOWNSVILLE 

CHOUDRANT 

Ouachita 

CALHOUN 

CLEAR BRANCH 

CHENIERE 

CREEK 

VIXEN 

COTTON PLANT 

Caldwell 

Ashley 

Morehouse 

Catahoula 

Richland 

OK 

Franklin 

Dallas 

TX 

West 

Carroll 

Concordia 

AR 

DETAIL 

AREA 

LA 

East 

Carroll 

Tensas 

MS 


LOCATION MAP 

Madison 

LOUISIANA 

AL 

MISSISSIPPI

Amite 

St Helena 

Hinds 

Copiah 

Lincoln 

Pike 

Tangipahoa 

MONTICELLO 

Lawrence 

Walthall 

MISSISSIPPI 

LOUISIANA 

Washington 

St Tammany 

Rankin 

Simpson 

Jefferson Davis 

WHITESAND 

OAKVILLE 

KNOXO 

GREENS CREEK 

Travis Peak oil/gas fields 

Covington 

McRANEY 

BASSFIELD 

HOLIDAY CREEK 

MORGANTOWN EAST 

SANDY HOOK WEST 

0 10 20 30 

40 Miles 

TATUMS CAMP 

POPLARVILLE 

Figure 1c. Map of central Mississippi showing major fields that have produced hydrocarbons from 

Travis Peak (Hosston) reservoirs. Modified from Bebout et al. (1992). 

Marion 

OK 

Dallas 

TX 

AR 

DETAIL 

AREA 

LA 

Pearl River 


Lamar 

MS 

LOCATION MAP 

Hancock 

AL 

Jones 

Forrest 

Stone 

Harrison

SYSTEM 

TERTIARY 

PALEOGENE 


LOWER CRETACEOUS 

JURASSIC 

TRIASSIC 

SERIES 

EOCENE 

PALEOGENE 

GULFIAN 

COMANCHEAN 

COAHUILAN 

UPPER 

MIDDLE 

LOWER 

UPPER 

CHRONOSTRATAGRAPHIC SECTION OF NORTH LOUISIANA 

STAGE GROUP FORMATION 

YPRESIAN 

THANETIAN 

DANIAN 

MAESTRICHTIAN 

CAMPANIAN 

SANTONIAN 

CONIACIAN 

TURONIAN 

CENOMANIAN 

ALBIAN 

APTIAN 

BARREMIAN 

HAUTERIVIAN 

VALANGINIAN 

BERRIASIAN 

TITHONIAN 

KIMMERIDGIAN 

OXFORDIAN 

CALLOVIAN 

BATHONIAN 

BAJOCIAN 

AALENIAN 

TOARCIAN 

PLIENSBACHIAN 

SINEMURIAN 

HETTANGIAN 

RHAETIAN 

WILCOX WILCOX 

MIDWAY MIDWAY 

NAVARRO 

TAYLOR 

AUSTIN 

EAGLE FORD 

WOODBINE 

WASHITA 

FREDRICKSBURG 

TRINITY 

COTTON VALLEY 

GLEN 

ROSE 

HIATUS 

HIATUS 

HIATUS 

ARKADELPHIA 

NACATOCH 

SARATOGA 

ANNONA 

OZAN 

TOKIO 

AUSTIN 

EAGLE FORD 

AGE 

(MA) 

TUSCALOOSA 

100 

PALUXY 

WASHITA-FREDERICKSBURG 

MOORINGSPORT 

FERRY LAKE ANHYDRITE 

RODESSA 

JAMES 

PINE ISLAND 

PETTET (SLIGO) MBR 

SLIGO 

HOSSTON 

(TRAVIS PEAK) 

SCHULER 

BOSSIER 


SMACKOVER 

NORPHLET 

LOUANN 

WERNER 

EAGLE MILLS 

Figure 2. Chronostratigraphic section of north Louisiana from Shreveport Geological Society (1987) 

showing general stratigraphic succession for northern Gulf of Mexico Basin. Travis Peak 

Formation, lowermost formation of the Trinity Group, is designated as Hosston on this diagram. 

Upper contact of Travis Peak (Hosston) with overlying Sligo carbonates is time-transgressive. 

60 

70 

80 

90 

110 

120 

130 

140 

150 

160 

170 

180 

190 

200 

210 

MILLIONS OF YEARS

34° N 

32° N 

30° N 

ANCESTRAL 

RED RIVER 

TRAVIS PEAK 

DEPOCENTER 

(SAUCIER, 1985) 

96° W 94° W 92° W 90° W 

MEXIA-TALCO 

GINGER 

FAULT 

FAULT ZONE 

ZONE 

EAST 

TEXAS 

SALT 

BASIN 

MT ENTERPRISE 

APPROX DOWNDIP LIMIT 

OF TRAVIS PEAK SANDSTONE 

FROM SANDSTONE ISOPACH 

MAPS OF SAUCIER (1985) 

FAULT ZONE 

SOUTH 

SABINE 

ARCH 

COMANCHEAN SHELF 

TEXAS 

ARKANSAS 

LOUISIANA 

ARKANSAS 

LOUISIANA 

NORTH 

LOUISIANA 

SALT 

BASIN 

EDGE 

FAULT ZONE 

0 20 40 

MILES 

60 80 

GULF OF MEXICO 

MONROE 

UPLIFT 

PICKENS 

MISSISSIPPI 

SALT 

BASIN 

MISSISSIPPI 

LOUISIANA 

ANCESTRAL 

MISSISSIPPI RIVER 

TRAVIS PEAK 

DEPOCENTER 

(SAUCIER, 1985) 

FAULT ZONE 

Figure 3. Index map of northern Gulf of Mexico Basin from Dutton et al. (1993) showing major tectonic features, including Sabine 

Arch and Salt Basins of East Texas, North Louisiana, and Mississippi. Sabine and Monroe Uplifts were not positive features 

during Travis Peak deposition. Movement of salt in the salt basins commenced during deposition of Smackover carbonates, and 

became more extensive with influx of thick sequence of Cotton Valley and Travis Peak terrigenous clastic sediment.

TRINITY GROUP 

NORTH SOUTH 

Sligo 

Formation 

Travis Peak 

(Hosston) 

Formation 

COTTON 

VALLEY 

GROUP 

(fluvial-deltaic sandstones) 

Schuler Fm 

(fluvial-deltaic 

sandstones) 

INDEX 

INDEX 

MAP MAP 

N 

AR AR 

LA 

S 

ARKANSAS 

LOUISIANA 

Hico Shale 

(lagoonal) 

Feet 

1000 

500 

Restricted marine shale 

Knowles Limestone 

Terryville Sandstone 

(massive ss 

complex) 

Bossier Formation 

(marine shale) 

0 

0 10 

Miles 

20 

Calvin Ss 

Troy 

Ls 

? 

Winn Limestone 

contact projected 

CRET CRETACEOUS 

CRETACEOUS CEOUS 

JURASSIC JURASSIC JURASSIC Limit of well control 

Possible massive 

sandstone complex 

Open marine shale 

Figure 4. Diagrammatic north-south stratigraphic cross section across southern Arkansas and northern Louisiana showing depositional 

relationships among units of Cotton Valley Group and Travis Peak Formation (from Saucier, 1985). Datum is top of Cotton Valley Group. 

Relatively thick sequence of Cotton Valley (Terryville) Sandstone, with interbedded shales, and Knowles Limestone separates Bossier 

Shale source rocks from Travis Peak sandstone reservoirs. Coleman and Coleman (1981) consider Calvin Sandstone and Winn Limestone 

to be part of Cotton Valley Group.

Depth, in Feet 

0 

1000 

2000 

3000 

4000 

A 

WEST 

TEXAS 

A 

A' 

LOCATION MAP 

LOUSIANA 

Fluvial 

126 Miles 

TEXAS LOUISIANA 

Figure 5. East-west stratigraphic cross section of Travis Peak Formation across northeast Texas into west Louisiana showing major 

Travis Peak depositional systems (from Dutton et al., 1991b). Cross section oriented parallel to depositional dip. Threefold division 

of Travis Peak Formation across hydrocarbon-productive trend includes thin, basal deltaic unit overlain by thick fluvial sequence that 

grades upward into paralic deposits. Datum is top of Pine Island Shale. 

Datum 

Paralic 

Deltaic 

Shelf 

Shelf 

A' 

EAST 

Travis Peak Formation

Depth (feet) 

5000 

6000 

7000 

8000 

9000 

10000 

r = 0.56 

n = 1687 

= 95 percent 

confidence limit 

11000 

0 10 100 

Porosimeter porosity (percent) 

Figure 6. Composite wireline log with gamma-ray and resistivity responses through complete 

section of Travis Peak Formation in east Texas (modified from Davies et al., 1991). Gamma-ray 

and resistivity character distinguish thin basal deltaic sequence, thick middle fluvial sequence, 

and thin upper paralic interval. Log responses within thick fluvial sequence also distinguish 

lower interval of stacked braided-channel sandstones with minor floodplain mudstones from 

upper interval of meandering-channel sandstones encased in thicker overbank mudstones. Most 

Travis Peak hydrocarbon production in northeast Texas comes from sandstones encased in shales 

within the upper 300 feet of the Travis Peak Formation. Depth increments on log are 50 feet. 

2 

3 

Depth (kilometers)

Depth (feet) 

5000 

6000 

7000 

8000 

9000 

10000 

r = 0.63 

n = 649 

= 90 percent 

confidence limit 

11000 

.00001 .0001 .001 .01 0.1 1 10 100 1000 

Stressed permeability (md) 

Figure 7. Semi-log plot of porosimeter porosity versus depth for 1,687 Travis Peak sandstone 

samples from wells in east Texas (from Dutton et al., 1991a). Samples include both clean and 

shaly sandstones. 

2 

3 

Depth (kilometers)

Hill 

OK 

Falls 

DETAIL 

AREA 

TX 

AR 

LA 

Limestone 

Collin 

Navarro 

Rockwall 

MS 


LOCATION MAP 

POKEY 

0.46 

AL 

RISCHERS STORE 

0.41 

McBEE 

0.36 

Henderson 

Freestone 

Van Zandt 

Leon 

Rains 

Anderson 

Hopkins Franklin Titus 


Wood 

Smith 

TRI CITIES 

0.53 PERCY 

WHEELER 

0.53 

Houston 

Cherokee 

0 10 20 30 40 Miles 

CEDAR SPRINGS 

0.49 

Upshaw 

0.44 

WILLOW 

SPRINGS 

Gregg 

HENDERSON 

0.43 

Rusk 

TRAWICK 

0.43 

Angelina 

Nacogdoches 

WHELAN 

0.38 

0.43 

PINEHILL 

SOUTHEAST 

APPLEBY 

NORTH 

0.44 

Cass 

Harrison 

Marion 

WASKOM 

0.38 

Panola 

Shelby 

TEXAS 

CARTHAGE 

0.54 

San Augustine 

Miller 

LA 

LOUISIANA AR 

Caddo 

BETHANY- 

LONGSTREET 

0.38 

0.49 

Figure 8. Semi-log plot of stressed permeability versus depth for 649 Travis Peak sandstone samples from wells in east Texas (from 

Dutton et al., 1991a). Samples include both clean and shaly sandstones. Note that in addition to decrease in permeability with depth, 

permeability also varies by four orders of magnitude at any given depth. 

CYRIL 

0.46 

De Soto 

Hemphill 

Sabine

TEXAS 

LOUISIANA 

Miller 

Cass Lafayette Columbia 

Marion 

Harrison 

WASCOM 

0.58 

Panola 

Shelby 

Caddo 

BETHANY- 

LONGSTREET 

0.38 

0.49 

Bossier 

De Soto 

Sabine 

ELM 

GROVE 

0.46 

Webster 

LEATHERMAN 

CREEK 

0.47 

Beinville 

Red River 

VILLAGE 

0.27 

Claiborne 

Natchitoches 

SUGAR 

CREEK 

0.41 

LUCKY 

0.36 


Lincoln 

Union 

Jackson 

ARKANSAS 

LOUISIANA 

RUSTON 

0.41 

Winn 

CHATHAM 

0.38 

Grant 

Union 

DOWNSVILLE 

0.46 

0.49 

0.46 

CLEAR BRANCH 

0.47 

0.48 

0.48 

0.79 

Ouachita 

CHENIERE 

CREEK 

0.39 

VIXEN 

0.37 

COTTON PLANT 

0.48 

0.48 

LaSalle 

Caldwell 

0 10 20 30 40 Miles 

Ashley 

Morehouse 

Catahoula 

Richland 

OK 

Franklin 

Dallas 

TX 

Concordia 

Chicot 

AR 

DETAIL 

AREA 

LA 

Tensas 

MS 


LOCATION MAP 

Figure 9. Map of northeast Texas showing fluid-pressure gradients (psi/ft) calculated from original shut-in pressures in Travis Peak 

sandstone reservoirs. Multiple pressure-gradient values for a particular field refer to gradients calculated for different stacked 

sandstone reservoirs in that field. Shut-in pressure data are shown in Table 1 along with sources for those data. Underlined FPG 

values indicate those from depths 500 feet or greater below top of Travis Peak Formation. 

Madison 

LOUISIANA 

AL 

MISSISSIPPI

Hill 

Falls 

OK 

DETAIL 

AREA 

TX 

Morris 

KNOWN FIELDS WITH TRAVIS PEAK HYDROCARBON-WATER CONTACTS 

AR 

LA 

MS 


LOCATION MAP 

Limestone 

Collin 

Navarro 

Rockwall 

AL 

REED 

Hunt 

Henderson 

Freestone 

Rains 

Van Zandt 

Hopkins Franklin Titus 

BLACKFOOT 

Anderson 

Wood 

Hydrocarbon-water contacts reported in public literature 

Gas-water contact inferred from flank wells that tested water 

without gas from Travis Peak sandstones 

Field with probable hydrocarbon contacts depending on meaning 

of terms "elevation of bottom of gas or oil" from Herald (1951) 

0 10 20 30 40 Miles 

Nacogdoches 

Figure 10. Map of north Louisiana showing fluid-pressure gradients (psi/ft) calculated from original shut-in pressures in Travis Peak 

sandstone reservoirs. Multiple pressure-gradient values for a particular field refer to gradients calculated for different stacked 

sandstone reservoirs in that field. Shut-in pressure data are shown in Table 1 along with sources for those data. 

Smith 

CHAPEL HILL 

Cherokee 

CEDAR SPRINGS 

Upshaw 

Gregg 

Rusk 

HENDERSON 

HENDERSON 

SOUTH 

CYRIL 

Angelina 

LASSATER 

Marion 

Harrison 

CARTHAGE 

Cass 

Shelby 

TEXAS 

Panola 

San Augustine 

Miller 

LA 

LOUISIANA AR 

Caddo 

WASKOM 

BETHANY- 

LONGSTREET 

Hemphill 

De Soto 

Sabine

Cass 

Marion 

Harrison 

TEXAS 

LOUISIANA 

WASCOM 

Panola 

Shelby 

Miller 

Caddo 

Lafayette 

Bossier 

CASPIANA 

BETHANY- 

LONGSTREET 

KNOWN FIELDS WITH TRAVIS PEAK 

HYDROCARBON-WATER CONTACTS 

De Soto 

Sabine 

Columbia 

Webster 

Beinville 

Red River 

Natchitoches 

Claiborne 

SUGAR 

CREEK 

ARKANSAS 

LOUISIANA 

Lincoln 

RUSTON 

SIMSBORO 

BRYCELAND 

Jackson 

BEAR CREEK 

Winn 

Union 

DOWNSVILLE 

Ouachita 

Hydrocarbon-water contacts reported in public literature 

0 10 20 30 40 Miles 

CHENIERE 

CREEK 

Caldwell 

Gas-water contact inferred from flank wells that tested water 

without gas from Travis Peak sandstones 

Ashley 

Morehouse 

Catahoula 

Richland 

OK 

TX 

Franklin 

DETAIL 

AREA 

West 

Carroll 

Concordia 

AR 

LA 

East 

Carroll 

Tensas 

MS 


LOCATION MAP 

Figure 11. Map of northeast Texas showing fields in which hydrocarbon-water contacts have been identified in Travis Peak sandstone 

reservoirs. Solid pattern indicates fields in which Travis Peak hydrocarbon-water contacts have been reported in public literature 

(see Table 1). Diagonal lines indicate fields in which gas-water contacts are inferred based on presence of flank wells that tested 

water only, without gas, identified from IHS Energy data. Fields with dashed outlines are those which might have gas-water or 

oil-water contacts depending on meaning of terms “elevation of bottom of gas” and “elevation of bottom of oil,” as reported in 

Herald (1951) and discussed in this report. All Travis Peak hydrocarbon-water contacts in these fields occur within upper 300 to 

500 feet of Travis Peak Formation. 

COTTON 

PLANT 

Madison 

LOUISIANA 

AL 

MISSISSIPPI

Hill 

Falls 

OK 

DETAIL 

AREA 

TX 

AR 

Collin 

LA 

Limestone 

MS 

Navarro 

Rockwall 


LOCATION MAP 

AL 

Hunt 

Hopkins Franklin 

TRAVIS PEAK SANDSTONE PERMEABILITY Morris(md) 

Henderson 

Freestone 

Van Zandt 

Leon 

Rains 

TRI CITIES 

0.1 to 85.0 

Anderson 

Wood 

Smith 

Houston 

Cherokee 

Titus 

Camp 

WILLOW 

SPRINGS 

20 

1.48 (Ave) 

PERCY WHEELER 

0.076 (Ave) 

0 10 20 30 40 Miles 

Upshaw 

Gregg 

Rusk 

HENDERSON 

72 

CYRIL 

TEXAS 

LOUISIANA 

Miller 

Cass Lafayette Columbia 

Marion 

Harrison 

WASCOM 

65 

Panola 

Shelby 

Caddo 

Bossier 

BETHANY- 

LONGSTREET 

115 

De Soto 

Sabine 

Webster 

LEATHERMAN 

CREEK 

SIBLEY 

Beinville 

Red River 

0.7 

131 

VILLAGE 

706 

Claiborne 

ADA 

Natchitoches 

SUGAR 

CREEK 

BRYCELAND 

65 

BEAR CREEK 

LISBON 

500 

TRAVIS PEAK SANDSTONE PERMEABILITY (md) 

SIMSBORO 

170 

500 

2 to 50 

ARKANSAS 

LOUISIANA 

Lincoln 

Jackson 

CLEAR BRANCH 

Winn 

0 10 20 30 40 Miles 

OK 

DETAIL 

AREA 

TX 

AR 

LA 

MS 


LOCATION MAP 

Figure 13. Map of northeast Texas showing measured values of permeability for productive Travis Peak sandstones in various fields. 

Multiple values of permeability for a particular field refer to measured values for different stacked sandstone reservoirs in that field. 

Permeability data are shown in Table 1 along with sources for those data. 

Grant 

3.8 

1.4 

0.6 

0.3 

Union 

CHOUDRANT 

250 

LaSalle 

Ouachita 

CHENIERE 

CREEK 

COTTON 

PLANT 

166 

6.0 

Caldwell 

Ashley 

Morehouse 

Catahoula 

Richland 

Franklin 

Concordia 

Chicot 

Tensas 

Madison 

LOUISIANA 

AL 

MISSISSIPPI

GAMMA 

RAY 

COMPOSITE LOG PROFILE OF TRAVIS PEAK FORMATION 

100 FT 

RESISTIVITY 

TRAVIS PEAK 

Coastal Plain / Paralic / Marine 

High-Sinuosity Fluvial 

(Isolated channel sandstones encased in 

laterally extensive floodplain shales) 

Low-Sinuosity Fluvial 

(Stacked channel and splay sandstones 

with minor floodplain shales) 

Delta Fringe / Marginal Marine 

(Alternating shales and sandstones deposited 

during initial progradation of Travis Peak) 

COTTON VALLEY 

(Isolated distributary-channel, 

tidal-channel, and tidal-flat 

sandstones encased in shales) 

Figure 14. Map of north Louisiana showing measured values of permeability for productive Travis Peak 

sandstones in various fields. Multiple values of permeability for a particular field refer to measured 

values for different stacked sandstone reservoirs in that field. Permeability data are shown in Table 1 

along with sources for those data.

The following talk was presented at the Rocky Mountain Association of Geologists symposium on 

basin-center gas. 

GEOLOGIC SCREENING OF THIRTY-THREE POTENTIAL BASIN-CENTER GAS 

ACCUMULATIONS IN THE U.S. 

Vito F. Nuccio, Thaddeus S. Dyman, James W. Schmoker, and Ronald C. Johnson, USGS; 

Timothy Gognat, Marin A. Popov, Michael S. Wilson, and 

Charles Bartberger, Consulting Geologists 

Basin-center accumulations, a type of continuous accumulation, have spatial dimensions equal to or 

exceeding those of conventional oil and gas accumulations, but unlike conventional fields, cannot be 

represented in terms of discrete, countable units delineated by downdip hydrocarbon-water contacts. 

Common geologic and production characteristics of continuous accumulations include their occurrence 

downdip from water-saturated rocks, lack of traditional trap or seal, relatively low matrix permeability, 

abnormal pressures (high or low), local interbedded source rocks, large in-place hydrocarbon volumes, and 

low recovery factors. 

The U.S. Geological Survey, in cooperation with the U.S. Department of Energy, National Energy 

Technology Laboratory, Morgantown, West Virginia, is currently re-evaluating the resource potential of 

basin-center gas accumulations in the U.S. in light of changing geologic perceptions about these 

accumulations (such as the role of subtle structures to produce sweet spots), and the availability of new 

data. Better geologic understanding of basin-center gas accumulations could result in new plays or revised 

plays relative to those of the U.S. Geological Survey 1995 National Assessment (Gautier and others, 

1995). 

For this study, 33 potential basin-center gas accumulations throughout the U.S. were identified and 

characterized based on data from the published literature and from well and reservoir databases (Figure 1). 

However, well-known or established basin-center accumulations such as the Green River Basin, the Uinta 

Basin, and the Piceance Basin are not addressed in this study. 

The areas included in this study: 

Western North Slope of Alaska Hanna basin 

Central Alaska basins Park basins of Colorado 

Cook Inlet, Alaska Raton basin 

Puget Sound trough W. WA Denver basin 

Columbia basin/W. flank of the Cascades Permian basin 

Modoc/Northern California Rio Grande rift 

Sacramento/San Joaquin basins Anadarko basin 

Santa Maria basin Mid-continent rift 

Los Angeles basin (deep) Arkoma basin 

Salton trough Gulf Coast–Travis Peak/Cotton Valley 

Great Basin (Tertiary basins) Gulf Coast–Austin Chalk 

Snake River downwarp Gulf Coast–Eagle Ford Formation 

Central Montana (Sweetgrass arch) Black Warrior basin 

Paradox basin--Precambrian Michigan basin 

Paradox basin--Pennsylvanian Appalachian basin 

Wasatch Plateau Eastern U.S. Triassic rift basins 

North end San Rafael Swell

Figure 1: Map showing locations of the basins or areas screened for potential basin-center accumulations. 

For each potential accumulation, we summarized the geologic setting and the balance of evidence 

regarding the existence of a basin-center accumulation and mapped areas of favorable production 

characteristics (sweet spots) of the accumulation considered to have the best resource potential. This 

preliminary screening provides a rationale for planning and carrying out a program of detailed geologic 

studies leading toward full geologic assessments. 

The accumulations are described as to their potential (or in some cases, lack of potential). Some of the 

considerations for our determinations include: (1) the amount of data available for an accumulation, and our 

level of confidence in the data, (2) the 30-year impact of the potential accumulation, (3) the magnitude or 

size of the potential resource, (4) the geologic risk (e.g., depth, remoteness), (5) geographic distribution, 

and (6) the relationship to the USGS 1995 oil and gas assessment (have our perceptions about an 

accumulation changed since then?). Following is a list of the accumulations screened with a brief note as 

to the possibility or existence of a potential basin-center accumulation.

Basin or Area 

Evaluation of Area for Basin-Center 

Accumulation 

Western North Slope of Alaska Potential for basin-center accumulation. Multiple source 

and reservoir rocks, and gas shows in most wells drilled. 

To date, no off-structure wells have been drilled, so 

extent of accumulation uncertain. 

Central Alaska basins There are possibilities for basin-center accumulations in 

the Central Alaska basins. Source and reservoir rocks are 

present in Paleozoic through Cenozoic units, however, 

sparse data and remoteness make these plays fairly high 

risk. 

Cook Inlet, Alaska Potential for a basin-center accumulation is fair to low 

because of low thermal maturities, high permeabilities, 

and high water production. 

Puget Sound trough, W. WA Potential basin-center accumulation in the Upper Eocene 

Cowlitz Formation in the deeper parts of the trough. 

Columbia Basin/W. Flank of the Cascades Very limited data and a few wells with overpressuring 

indicate some potential in the Cretaceous and Tertiary, 

but high water production makes risk high. 

Modoc/Northern California Although speculative, a basin-center accumulation may 

exist in the Upper Cretaceous Hornbrook Formation and 

Eocene Montgomery Creek Formation. 

Sacramento/San Joaquin basins Small area in the deep basin may prove to have a basincenter 

gas accumulation in the Cretaceous Forbes 

Formation. 

Santa Maria basin Potential for a continuous accumulation in organic-rich, 

fractured shale of the Monterey Formation. 

Los Angeles Basin (deep) Potential basin-center accumulation in the deep Miocene 

section where mature source rocks may be present. 

Salton trough Low potential for basin-center accumulation due to lack 

of source rocks and extremely high temperatures. 

Great Basin (Tertiary basins) Source rocks along with high geothermal gradients may 

have contributed to basin-center gas accumulations 

within Tertiary grabens. 

Snake River downwarp Although speculative, several favorable factors necessary 

for a basin-center accumulation do exist in the Tertiary 

section. 

Central Montana (Sweetgrass arch) Potential for basin-center accumulation low. 

Paradox basin--Precambrian Chuar Group contains good source rocks, but virtually 

untested. Potential for a frontier basin-center 

accumulation, however risk is high. 

Paradox Basin--Pennsylvanian Possibility for a continuous-type oil (and where 

overmature, gas) accumulation in the Cane Creek 

interval. Fractures are critical to the success of the play. 

Wasatch Plateau Although located in proximity to a major coalbed 

methane play, potential for a basin-center accumulation 

here is low.

Basin or Area 


Accumulation 

North end San Rafael Swell Potential for a basin-center accumulation in the 

Cretaceous Dakota Formation is there, however, 

supporting data are sparse. 

Hanna basin Geologic relations within the basin, and comparison 

with other Rocky Mountain basins make a Cretaceous 

and lower Tertiary basin-center accumulation probable. 

Park basins of Colorado Potential for basin-center accumulation in Apache Creek 

Sandstone and Niobrara Fm., especially in the South 

Park basin. 

Raton basin Potential basin-center gas accumulation in the 

Cretaceous Vermejo and Cretaceous and Paleocene Raton 

Formation. 

Denver basin Potential for basin-center accumulation in strata from the 

top of the Niobrara to the base of the Cretaceous. 

Permian basin The Abo Formation, although productive with abnormal 

pressures, does not contain most of the parameters for a 

basin-center accumulation. 

Rio Grande rift Gas shows, low permeabilities, and other evidence 

suggest a basin-center gas accumulation in the 

Cretaceous section in the Albuquerque basin. 

Anadarko basin Exhibits some characteristics of a basin-center gas 

accumulation, but has excessive water production and 

hydrocarbon-water contacts. Potential for localized gassaturated 

accumulations in the deep basin. 

Mid-continent rift Lack of adequate source rocks indicates low potential for 

a basin-center accumulation. 

Arkoma basin Entire Ordovician through Pennsylvanian section appears 

to be gas saturated. Potential for basin-center 

accumulation in Pennsylvanian Atoka Formation. 

Gulf Coast--Travis Peak/Cotton Valley Exhibits some characteristics of a basin-center 

accumulation but contains diffuse hydrocarbon-water 

contacts. Low to moderate potential. 

Gulf Coast--Austin Chalk Not necessarily a true basin-center accumulation, 

however, hydrocarbon saturation is high throughout 

much of the trend. 

Gulf Coast--Cretaceous Eagle Ford Formation Potential for a basin-center accumulation but high risk 

geologically and possibly economically due to lack of 

fractures. It is, however, a potential source rock for 

reservoirs such as the Woodbine and Austin Chalk. 

Black Warrior basin Potential in Late Paleozoic clastic units, especially the 

Mississippian Chester Group; Cambro-Ordovician 

through Devonian carbonate units. 

Michigan basin Little to no potential for a basin-center accumulation in 

the Ordovician St. Peter Sandstone due to conventional 

nature including high water production.

Basin or Area 


Accumulation 

Appalachian basin Potential in the Lower Silurian Clinton and Medina 

Group sandstones. 

Eastern U.S. Triassic rift basins Potential in Triassic-Jurassic sequences of source and 

reservoir rock. The greatest potential appears to be in 

the Newark and Danville basins.

Final Report - National Energy Technology Laboratory - U.S. ...

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