USGS RESEARCH ON ENERGY RESOURCES, 1992 

PROGRAM AND ABSTRACTS 

EIGHTH V.E. McKELVEY FORUM ON MINERAL AND ENERGY RESOURCES 

U.S. GEOLOGICAL SURVEY CIRCULAR 1074 
Cover.- "The Panorama from Point Sublime in the Kaibab," by William H. 

Holmes, from Sheet XV of Atlas to accompany the Monograph on the Tertiary 

history of the Grand Cafion District, by Clarence E. Dutton (U.S. Geological 

Survey Monograph 2, 1882). Redrawn by Rob Wells. 
USGS RESEARCH ON ENERGY RESOURCES, 1992 

PROGRAM AND ABSTRACTS 

Edited by L.M.H. CARTER 

EIGHTH V.E. McKELVEY FORUM ON 

MINERAL AND ENERGY RESOURCES 

U.S. GEOLOGICAL SURVEY CIRCULAR 1074 
U.S. DEPARTMENT OF THE INTERIOR 

MANUEL LUJAN, JR., Secretary 

U.S. GEOLOGICAL SURVEY 

Dallas L. Peck, Director 

Any use of trade, product, or firm names in this publication is for descriptive 

purposes only and does not imply endorsement by the U.S. Government. 

UNITED STATES GOVERNMENT PRINTING OFFICE: 1992 

Organizing Committee for the 1992 McKelvey Forum: 

Chair: Christine E. Turner 

Co-chairs: Neil S. Fishman, 

Program: 

Thomas S. Ahlbrandt 

AnnyB. Couey 

Thomas D. Fouch 

John A. Grow 

Robert B. Halley 

Joseph R. Hatch 

Samuel Y. Johnson 

Bonnie McGregor 

James K Otton 

James W. Schmoker 

Stanley P. Schweinfurth 

Christine E. Turner 

Edward A. Johnson 

Publicity: 

Helen L. Britton 

Sally J. Dyson 

Neil S. Fishman 

Vito F. Nuccio 

Budget: 

Patricia E. O'Connell 

Editorial: 

Lorna Carter 

Logistics: 

Sigrid Asher-Bolinder 

Bonnie L. Crysdale 

Russell F. Dubiel 

Mitchell E. Heney 

Edward A. Johnson 

Kathleen K Krohn 

Drafting: 

George M. Garcia 

Carol S. Holtgrewe 

Thomas Kostick 

Free on application to the Books and Open-File Reports Section, U.S. Geological Sutvey, Denver Federal Center, Box 25425, Denver, CO 80225 
A society's wealth depends on the use it makes of raw materials, 

energy, and especially ingenuity. 

- V.E. McKelvey 

Ill 
FOREWORD 

Dallas L. Peck, U.S. Geological Survey 

The extended abstracts in this volume are summaries of papers presented 

orally and as posters at the Eighth Annual V.E. McKelvey Forum on Energy and 

Mineral Resources. The McKelvey Forum serves as an opportunity for 

communication between the U.S. Geological Survey (USGS) and the earthscience and energy and mineral communities by presenting the results, recent 

progress, and pertinent data of current USGS research in formal lectures and 

posters. The poster sessions and the more informal meetings during the forum 

provide many opportunities for concerned persons to meet individually with our 

scientists. I hope that the 1992 McKelvey Forum will help make our programs even 

more responsive to the needs of these communities, particularly to the fossil-energy 

industry, and that the interaction and cooperation begun here will continue to 

expand. 

The forum is named for former Director Vincent E. McKelvey in recognition 

of his lifelong dedication to the study of mineral and energy resources as research 

scientist, Chief Geologist, and Director of the USGS. The forum is an annual event 

that alternates in subject matter between mineral and energy resources; this year 

the emphasis is on energy. Although the format and topics addressed change 

somewhat from year to year, the primary purpose of the forum remains the same: 

to encourage direct communication between USGS scientists, the representatives 

of other earth-science and mineral and energy organizations, and interested 

individuals. 

Energy programs of the USGS include investigations related to oil and gas, 

coal, geothermal resources, uranium, thorium, and oil shale. Our studies 

encompass the entire National domain. Presentations in this year's forum include 

recent research in basin evolution, reservoir characterization and computer 

applications in the energy fields. A growing number of citizens of this country are 

becoming increasingly aware of the importance of effective, efficient utilization of 

our Nation's energy endowment. Research results presented at this forum will 

contribute directly to that goal, and we are excited by the opportunity to present 

them to you and to start discussions with our colleagues in industry and academia. 

We welcome your suggestions concerning future energy research directions 

and projects and also for improving the McKelvey Forum. 

IV 

Dallas L. Peck, Director 

U.S. Geological Survey 
Eighth V.E. McKelvey Forum on Mineral and 

Energy Resources 

HOUSTON, TEXAS, FEBRUARY 17-20, 1992 

PROGRAM OF LECTURES AND DISCUSSIONS 

MONDAY, FEBRUARY 17,1992 

7:00-9:00 p.m. Registration/Ice Breaker (Cash Bar) 

Atrium, Wyndham Greenspoint Hotel 

TECHNICAL PROGRAM 

In the Atrium, immediately outside Raphael Ballrooms A and B, each speaker will be 

available during the first coffee break following his/her talk for informal discussions. Tables 

and chairs will be available for this purpose. Come share your thoughts and bring your 

questions. 

TUESDAY, FEBRUARY 18, 1992 

7:00a.m. 

8:30a.m. 

8:40 

8:50 

9:40 

10:00 

10:15 

10:40 

Registration 

OPENING SESSION 

Gary W. Hill and Donald L. Gautier, presiding 

Welcome and Opening Remarks Dallas L. Peck, Director, U.S. 

Geological Survey 

Welcome from Interior Secretary Manuel Lujan, Jr. John M. Sayre, 

Assistant Secretary for Water and Science, U.S. Department of the Interior 

Introduction William L. Fisher, Director and State Geologist, Bureau 

of Economic Geology, Texas 

KEYNOTE ADDRESS: Role of water in petroleum formation 

Michael D. Lewan 

TECHNICAL SESSION 

Gary W. Hill and Donald L. Gautier, presiding 

Field growth in the Gulf of Mexico-A progress report Lawrence J. 

Drew and Gary L. Lore 

Highlights of the McKelvey 'poster presentations Christine E. Turner 

and William G. Miller 

COFFEE BREAK AND POSI'ER SESSION 

Climate controls on Carboniferous cyclic sedimentation and organic 

productivity C. Blaine Cecil 

v 
PROGRAM OF LECTURES AND DISCUSSIONS (CONTINUED) 

11:00 

11:2<1 

11:40 

12:00 noon 

1:30 

1:50 

2:10 

2:30 

2:50 

3:10 

3:30 

3:50-6:00 

Bridging the gap between third- and fifth-order cycles in carbonate 

sequences-The western margin of the Great Bahama Bank Roben 

B. Halley and R. Jude Wilber 

Sequence stratigraphy in the search for hydrocarbons in nonmarine 

strata Peter l. McCabe 

Reservoirs and source rocks of the Upper Jurassic Norphlet 

Formation, Mississippi and Alabama C.J. Schenk and l. W. Schmoker 

Adjournment of session; lunch 

TECHNICAL SESSION 

Thomas S. Ahlbrandt and David J. Taylor, presiding 

Oil and gas-Where in the world, and why C.D. Masters 

Collisional tectonics and the global generation of oil and gas David 

G. Howell 

Oil field growth in the United States-How much is left in the barrel? 

D.H. Root and E.D. Attanasi 

Alaskan North Slope geothermics, geodynamics, and 

hydrology-Implications for oil and gas Kenneth J. Bird, David G. 

Howe!~ Mark J. Johnsson, and Leslie B. Magoon 

Huge indigenous oil in mature source rocks-Beyond elephants? 

Leigh Price 

Major frontier exploration plays in petroleum basins of the U.S.S.R. 

Gregory F. Ulmishek 

Adjournment of technical session 

POSTER SESSION AND RECEPTION 

TUESDAY EVENING, FEBRUARY 18, 1992 

7:30p.m. 

8:30-10:00 

USGS DIRECfOR'S LECTURE: Fractal nature of hydrocarbon 

accumulations and price-Implications for resource assessment, 

exploration and development strategies, and economic forecasting 

Christopher C. Barton 

POSTER SESSION (Cash Bar) 

WEDNESDAY, FEBRUARY 19, 1992 

8:30a.m. 

8:50 

TECHNICAL SESSION 

Bonnie A. McGregor and Joseph R. Hatch, presiding 

Redefining Hutton's unconformity-Geology in a digital world 

William G. Miller 

Architectural analysis of eolian sandstones-The Lower Jurassic 

Nugget Sandstone of northeastern Utah Fred Peterson and C.J. 

Schenk 

VI 
PROGRAM OF LECTURES AND DISCUSSIONS (CONTINUED) 

9:10 

9:30 

9:50 

10:20 

10:40 

11:00 

11:20 

11:40 

12:00 noon 

2:00 

2:20 

2:40 

3:00 

3:30 

Turbidity-current processes and turbidite elements-What you get is 

not what you see William R. Normark 

Ground-truthing the distal Mississippi fan with SeaMARC images and 

cores-What happens at the end of the pipe D.C. Twichel~ W.C. 

Schwab, C.H. Nelson, HJ. Lee, N.H. Kenyon, T.F. O'Brien, and W. 

Danforth 

COFFEE BREAK AND POSTER SESSION 

Diagenesis in a bottle-Experimental strategies for studying thermal 

maturity in clays and organic matter Gene "Whitney and Michael D. 

Lewan 

Some geologic controls of coalbed gas generation, accumulation, and 

production, Western United States Dudley D. Rice, Jeny L. Clayton, 

Romeo M. Flores, Ben E. Law, and Ronald W. Stanton 

Geologically oriented overview of horizontal drilling in the United 

States James W. Schmoker 

Gas hydrates in deep ocean sediments offshore southeastern United 

States-A future resource? William P. Dillon, Richard F. Mast, 

Kristen Fehlhaber, and Myung W. Lee 

Unconventional resources-Are they in our future? Thomas S. 

Ahlbrandt 

McKELVEY FORUM LUNCHEON-Wedgwood Room 

Remarks by FRANK A. BRACKEN, Deputy Secretary, U.S. 

Department of the Interior: A perspective on national energy policy 

FEATURING: An hour with 

-Live on Stage 

TECHNICAL SESSION 

Walter E. Dean and Harold J. Gluskoter, presiding 

Origin of fluid pressure, fracture generation, and the movement of 

fluids in the Uinta Basin, Utah J.D. Bredehoeft, J.B. Wesley, and T.D. 

Fouch 

Origin of the Santa Maria basin, California Richard G. Stanley, 

Samuel Y. Johnson, Ronald B. Cole, Mark A. Mason, Carl C. Swisher 

Ill, Mary Lou Cotton Thornton, Mark V. Filewicz, David R Vork, 

Michele L. Tuttle, and John D. Obradovich 

Petroleum geology research in the Santa Maria province, California 

C.aroline M Isaacs 

COFFEE BREAK AND POSTER SESSION 

Basin evolution in the foreland of thin- and thick-skinned thrust 

terranes-Example from the Sylhet trough, Bangladesh Samuel Y. 

Johnson and A.MN. Alam 

VII 
PROGRAM OF LECTURES AND DISCUSSIONS (CONTINUED) 

3:50 

4:10 

4:30 

4:50 

The regional context of Railroad Valley oil-fields-An integrated 

geological and geophysical transect, east-central Nevada Christopher 

J. Potter, John A. Grow, Karen Lund, and William J. Peny, Jr. 

Thermochronologic constraints on relation between extensional 

geometry of the northern Grant Range and oil occurrences in 

Railroad Valley, east-central Nevada Karen Lund, L. Sue Beard, L. W. 

Snee, and William J. Peny, Jr. 

Gulf Coast lignite quality-The needs of the 90's Robert B. 

Finkelman, W.R Kaiser, Susan J. Tewalt, and James A. Luppens 

Conclusion of technical lecture sessions 

THURSDAY, FEBRUARY 20, 1992 

8:00a.m. 

4:30p.m. 

SHORT COURSE: Recent advances in plate tectonics and 

continental crustal evolution WaJTen B. Hamilton (Raphael 

Ballrooms A and B) 

Conclusion of McKelvey Forum 1992 

VIII 
V.E. McKELVEY FORUM-POSTER SESSIONS 

The posters will be available for viewing from 8:00 a.m. to 4:30 p.m. Tuesday 

and Wednesday in Raphael Ballrooms C and D. Authors will be present in their 

booths during coffee breaks and during the main poster session on Tuesday 

afternoon from 3:50 to 6:00 p.m., at which time complimentary food and beverages 

will be available. Also, authors will be present on Tuesday evening from 8:30 to 

10:00 p.m., immediately following the Director's Lecture; a cash bar will be set up 

at this time. The following list of posters is arranged alphabetically by author. 

Petroleum geology and exploration potential of the Pripyat Basin, U.S.S.R. 

Mahlon M Ban leny L. Clayton, Gregory F. Ulmishek, Paul G. Lillis, Gordon L. Dolton, Ted A. 

Daws, Richard F. Mast, Augusta Warden, Michael Keller, Vladamir Bogino, and Zinovy 

Poznaikovitch 

Petroleum reseiVoir evaluation by borehole gravity suiVey 

Larry A. Beyer 

Interactive volume modeling of coal and associated depositional systems, Eocene Brunner Coal Measures, 

Buller coal field, New Zealand 

Laura RH. Biewick, Margaret S. Ellis, Dorsey Blake, Romeo M Flores, Richard Sykes, and Carol 

L. Molnia 

Sagavanirktok Formation-A new look with seismic data in the Prudhoe Bay-Kuparuk River region, 

Alaskan North Slope 

Kenneth I. Bird and Timothy S. Collett 

Gravity and aeromagnetic interpretation of structure in Railroad Valley and the Grant Range, east-central 

Nevada 

H. Richard Blank and John A. Grow 

Tectonostratigraphy and Neogene extensional tectonism on part of the California continental borderland-A seismic-reflection perspective 

R G. Bohannon and E.L. Geist 

Normal faulting in collisional foredeeps-Implications for basin analysis 

Dwight C. Bradley and W.S.F. Kidd 

Coal availability studies-An update 

M Devereux Carter, Nancy K. Gardner, lames C. Cobb, Roy S. Sites, and Nick Fedorko, III 

Natural gas hydrates-A proven resource 

Timothy S. Collett 

Tar sands and heavy oils-Resources, recovery, and realism 

B.L. Crysdale, C.J. Schenk, and RF. Meyer 

Evidence for petroleum-assisted speleogenesis, Lechuguilla Cave, Carlsbad Caverns National Park, New 

Mexico 

KI. Cunningham and Kl Takahashi 

Cretaceous resources, events, and rhythms-Continental Scientific Drilling Transect of the Western 

Interior seaway 

Walter E. Dean and Michael A. Anhur 

IX 
POSTER SESSIONS (CONTINUED) 

Undiscovered oil and gas resources of Federal lands and waters 

G.L. Dolton, RF. Mast, and RA. Crovelli 

Fluvial architecture and resetvoir heterogeneity-Triassic and Tertiary examples from the Colorado 

Plateau 

Russell F. Dubie~ Steven C. Good, and Christopher J. Schenk 

Origin of the Challenger Knoll oil, Gulf of Mexico 

N. Terence Edgar and Jeny L. Clayton 

Estimation of gas hydrate concentrations using seismic methods 

Kristen F ehlhaber, William P. Dillon, and Myung W. Lee 

Synsedimentary authigenic illite and implications for geothermometry in sedimentary basins 

Neil S. Fishman and Christine E. Turner 

High-resolution paleoclimate reconstruction from Alaskan ice-core records 

J.J. Fitzpatrick, T.K Hinkley, G.P. Landis, RO. Rye, and G. Holdsworth 

Tectonic and climatic changes expressed as sedimentary and geochemical cycles in Paleogene lake systems, 

Utah and Colorado-Implications for petroleum source and reservoir rocks 

Thomas D. Fouch and Janet K Pitman 

Late Cretaceous and early Tertiary evolution of the Uinta and Piceance basins (northeastern Utah and 

northwestern Colorado) and associated development of hydrocarbons 

KJ. Franczyk, T.D. Fouch, R.C. Johnson, C.M. Molenaar, and WA. Cobban 

Hydrocarbon source-rock evaluation of Desmoinesian (Middle Pennsylvanian) coals from southeastern 

Iowa, Missouri, southeastern Kansas, and northeastern Oklahoma 

Joseph R. Hatch 

Anadarko basin reservoir and non-resetvoir sandstones-A comparison of porosity trends 

Timothy C. Hester and James W. Schmoker 

Testing new coal models-The 1991 Kaiparowits Plateau Drilling Project 

RD. Hettinger and P.J. McCabe 

o

18C of terrestrial and marine organic matter in Cretaceous rocks of the Western Interior of North 

America 

Charles W. Holmes, John M'Gonigle, and Brent Dalrymple 

Seismic reflection studies of Lake Baikal, U.S.S.R. 

D.R Hutchinson, A.J. Golmshtok, T.C. Moore, M.JV: Lee, CA. Scholz, and KD. Klitgord 

The ARC/INFO Geographic Information System applied to geologic investigations of the Norphlet 

Formation, Alabama and Mississippi 

C. William Keighin and C.J. Schenk 

The Santa Maria Province Project, California 

Margaret A. Keller, Caroline M. Isaacs, and Richard G. Stanley 

X 
POSTER SESSIONS (CONTINUED) 

Fracturing and resetvoir development in the Katakturuk Dolomite, Arctic National Wildlife Refuge, 

Alaska 

John S. Kelley, Chester T. Wrucke, and Augustus K. Annstrong 

Major controls on accumulation of Upper Cretaceous coals in North America 

M.A. Kirschbaum, L.N.R. Roberts, and P.J. McCabe 

Evolution of the Illinois Basin 

Dennis R. Kolata, W. John Nelson, Janis D. Trewo'X)', Stephen T. Whitaker, Michael L. Sargent, 

Lloyd C. Furer, and MC. Noger 

GIS visualization of coal stratigraphic and geochemical information 

Kathleen K. Krohn, Carol L. Molnia, Susan J. Tewalt, and William G. Miller 

Alteration of lignin during biodegradation in peats and the early stages of coalification 

Hany E. Lerch, William H. Orem, and Timothy A. Moore 

Development of the Ellesmerian continental margin and the Brookian orogeny, Alaska-A DNAG 

perspective 

Thomas E. Moore, Wesley K. Wallace, Kenneth J. Bird, Susan M Karl, and C. Gil Mull 

Controls on gas generation and production, tight sandstone resetvoirs, Uinta Basin, Utah 

Vito F. Nuccio, James W. Schmoker, and Thomas D. Fouch 

The desktop core library, a CD-ROM approach 

Michael P. Pantea, Frances E. Gay, and Russell A. Ambroziak 

Petrography and Rock-Eval studies of organic matter in Precambrian rocks, U.S.A. and U.S.S.R. 

Mark Pawlewicz and James G. Palacas 

Relation of natural fractures to composition and cyclicity in chalk of the Niobrara Formation, Berthoud 

field, Colorado 

Richard M Pollastro 

USGS Core Research Center-A million feet of geologic history 

Diana L. Richards and Thomas C. Michalski 

Research thrusts of the current five-year USGS Evolution of Sedimentary Basins program-Illinois, 

Paradox, Eastern Great, and SW ANO basins 

J.L. Ridgley, A.C. Huffman, Jr., H.E. Cook, C.J. Potter, S.Y. Johnson, and W.E. Dean 

Isostatic residual gravity mapping of Wyoming 

S.L. Robbins and J.A. Grow 

Paleocene paleogeography, tectonics, and coal distribution in the Rocky Mountain region-An overview 

S.B. Roberts, MS. Ellis, R.M Flores, D.J. Nichols, W J. Peny, Jr., and G.D. Stricker 

Resetvoir heterogeneities in the Morrison Formation in southern Utah-A Prudhoe Bay analog 

John W. Robinson and Peter J. McCabe 

Geochemistry and origin of oil in Cambrian and Ordovician resetvoirs, Ohio 

Robert T. Ryder, Robert C. Bunuss, and Joseph R. Hatch 

XI 
POSTER SESSIONS {CONTINUED) 

Algodones depositional system-Modem analog for the Upper Jurassic Norphlet Formation, Mississippi 

and Alabama 

C.J. Schenk 

Tectonic and climatic controls on the sedimentary record of the early Mesozoic Newark Supergroup rift 

basins, Eastern North America 

Joseph P. Smoot 

Interactive computer display of petroleum exploration and undiscovered resource potential of the United 

States 

Kenneth I. Takahash~ Debra K. Higley, and Richard F. Mast 

NERSL-National Energy Research Seismic Library 

David J. Taylor and Frederick N. Zihlman 

Preliminary 1:100,000-scale geologic map of Santa Maria 30' x 60' quadrangle, central coastal 

California-Progress toward a digital compilation 

Marilyn E. Tennyson 

Multifaceted studies of a lacustrine source rock-The Paleogene Green River Formation, Colorado, Utah, 

and Wyoming 

Michele L. Tuttle, Walter E. Dean, Mark Stanton, James Collister, Wendy Hanison, Thomas D. 

Fouch, Janet Pitman, Trond Hanesand, and Nils Telnaes 

The Coal Resource Evaluation and Assessment Project (COALREAP) in Pakistan-Energy for the 

future 

Peter D. WtliWick, John R. SanFilipo, Roger E. Thomas, and James E. Fassett 

Late Paleocene and early Eocene terrestrial and marine environments, Lakhra coal field, Sindh Province, 

Pakistan 

Christopher Wnuk, Elisabeth M. Brouwers, and Nonnan Frederiksen 

Energy research on Indian lands 

R.S. Zech, H.H. Amd~ L.H. Biewick, J.K Hardie, R.C. Johnson, J.L. Ridgley, Courteney 

Williamson, and Robyn Wright-Dunbar 

XII 
Eighth V.E. McKelvey Forum on Mineral and Energy Resources 

USGS Research on Energy Resources, 1992 

Program and Abstracts 

Edited by L.M.H. Carter 

Unconventional ResourcesAre They in Our Future? 

Thomas S. Ahlbrandt 

Unconventional hydrocarbon resources are so 

designated because economic, technologic, or regulatory 

~nstraints do not allow their development. For example, 

m a 1978 PERC (Federal Energy Regulatory Commission) study, marsh gas collected beneath large plastic 

tents was only recoverable at $130/MCF (thousand cubic 

feet) and the study authors correctly concluded that it 

was not a viable methane resource at that time. Many 

unconventional resources have the advantage of large 

in-place volumes which, although in many cases widely 

disseminated, are intriguing because they represent 

reduced risk of dry holes during development. 

As constraining technologic or regulatory 

parameters will be modified, unconventional resources 

will increasingly become economic and may further 

displace conventional resources. Heavy oils have already 

displaced light oils domestically in several significant 

areas. Presently, 73 percent of all U.S. enhanced oil 

recovery and about 70 percent of. California's oil 

production are heavy oil. Heavy oil fields already 

represent about 15 percent of the total number of giant 

fields ( > 500 MMBO (million barrels of oil)) and in the 

U.S. include such giant fields as Smackover, San Ardo, 

Hawkins, Huntington Beach, Wilmington, South Belridge, Coalinga, Kern River, and Midway-Sunset. Heavy 

oil from Venezuela is expected to produce 500,000 

BOPD (barrels of oil per day) by 1995 from the degraded 

remnants of perhaps the world's largest oil accumulation, 

estimated to be 1.6 trillion BO (barrels of oil) in place at 

Manuscript approved for publication December 13, 1991. 

this time, of which 250 BBO is recoverable and viable in 

the $9-$12 per barrel range. The original accumulation 

is estimated to have been 8 trillion BO in place. Very 

large bitumen or natural asphalt resources, such as the 

Canadian Athabasca, Peace River, and Cold Lake 

Cretaceous and Devonian reservoirs, are thought to be 

viable in the $15-$20 per barrel range. 

Unconventional natural gas resources are also 

becoming increasingly viable. Coalbed methane, which 

accounts for about 25 percent of potential natural gas 

resources in the U.S., will displace nearly a trillion cubic 

feet (TCF) of gas from conventional resources in the 

near term and perhaps several TCF by the turn of the 

century. Similarly, production of gas from lowpermeability resources may displace some production of 

conventional gas as increasingly smaller conventional 

accumulations are developed. Coalbed methane and 

tight gas, both abundant in the Rocky Mountain and 

Appalachian regions, will likely experience significant 

production increases. Optimistic scenarios suggest that 

tight gas and coalbed methane resources may provide 

more domestic natural gas production than conventional 

resources by the year 2010. Horizontal drilling 

technology will most likely unlock the large currently 

uneconomic gas resources in tight reservoirs. 

Technologies like this will most certainly change the 

status of what are presently considered unconventional 

resources. 

Beyond the turn of the century, more speculative 

gas resources, particularly gas hydrates or even gas from 

oil shale, may become increasingly significant 

contributors. Geopressured gas-bearing brines, although 

clearly a large resource base, will most likely be used 

primarily for thermally enhanced oil recovery efforts and 

only secondarily as hydraulic, thermal or natural gas 

energy sources. If the concerns for global warming and a 

cleaner atmosphere are considered, then greater use of 

natural gas is anticipated and perhaps will provide 
additional incentives to develop unconventional gas 

resources. Clearly, for future hydrocarbon supplies, 

resources considered to be unconventional today, 

particularly gas resources, will increasingly displace 

conventional resources as economic, technologic, and 

regulatory barriers are modified. 

Petroleum Geology and Exploration 

Potential of the Pripyat Basin, U.S.S.R. 

Mahlon M. Ball, Jerry L. Clayton, 

Gregory F. Ulmishek, Paul G. Lillis, 

Gordon L. Dolton, Ted A. Daws, 

Richard F. Mast, Augusta Warden, 

Michael Keller, Vladamir Bogino, 

and Zinovy Poznaikovitch 

This study is an initial step in applying U.S. 

Geological Survey oil and gas assessment techniques to 

basins within the U.S.S.R. in order to compare methods 

used by U.S. and Soviet scientists. The goal of both 

groups of government earth scientists is to improve the 

ability to assess undiscovered recoverable oil and gas 

resources. 

The Pripyat basin is the extreme northwest end of 

the middle Paleozoic, Dnieper-Donets aulacogen that 

separates the Ukrainian shield from the rest of the 

Russian craton (fig. 1). Gravity, magnetic, and seismic 

refraction measurements show that its basement 

structure is typical of intracontinental rifts and that 

basement consists of east -west -trending tilted blocks 

bounded by listric normal faults believed to intersect 

mantle rocks, at a depth of approximately 40 km, above 

an elevated asthenospheric ridge. 

The sedimentary sequence within the Pripyat basin 

is as much as 6 km thick and is subdivided into five units: 

(1) The lowest, pre-rift unit consists of basal terrigenous 

clastics overlain by thin Middle Devonian quartz sands, 

shales, carbonates, and anhydrites. This lowermost unit 

grades upward into (2), a lower salt interval of Frasnian 

Age. The lower salt contains some interbedded 

carbonate. Above the lower salt, (3) a carbonate unit 

containing some black shale is referred to as the intersalt 

carbonate. ( 4) The upper salt, a relatively pure halite, 

caps the intersalt carbonate. Faults tend to die out 

upward in the upper salt interval, and salt flowage is 

mostly restricted to this interval. The upper salt is 

overlain by (5) terrigenous clastics ranging in age from 

youngest Devonian to Quaternary. Only the basal sands 

of unit 1 are pre-rift sediments. The remaining units are 

syn-rift deposits with the exception of the post-rift unit 5. 

Principal source rocks are black-shale facies in the 

intersalt carbonate formation. This same formation 

contains about two-thirds of the hydrocarbon reserves. 

2 

EXPLANATION 

G) Gulf of Finland 

® Lake Ladoga 

@ Russian craton 

@ Pripyat basin 

@ Dnieper-Donets basin 

@ Ukrainian shield 

0 MOSCOW 

500 KILOMETERS 

(j) Carpathian fold-thrust belt 

@ BlackSea 

@ Crimea 

@ Gulf of Azov 

+ Regional high 

Regional low 

N 

1 

Figure 1 (Ball and others). Regional index map of Pripyat 

basin, U.S.S.R. Solid contour encloses regional geophysical 

high; hachured contour encloses regional low. 

The remaining reserves are in carbonate and clastic rocks 

beneath the lower salt. Faulted structural traps control 

all fields. Stratigraphic pinchouts, lower Famennian 

(intersalt) reefs, and roll-over closures on downthrown 

blocks are potential exploration targets. 

Pyrolysis assay of 284 samples reveals the presence 

of potential source rocks (mostly in shales in the intersalt 

carbonate unit 3) containing as much as 3 weight percent 
organic carbon (types II and III kerogen). The rocks are 

generally marginally mature to mature (0.6-0.9 vitrinite 

reflectance equivalent) with respect to petroleum 

generation. Thermally immature oils (vitrinite reflectance equivalent of about 0.5 percent) occur in clastic 

and carbonate rocks in the central rift. Oil is only 

produced in the northern part of the basin and exhibits a 

range of thermal maturity levels, generally more mature 

than those toward the south. No systematic relationship 

exists between reservoir depth and degree of thermal 

alteration of the oils. We are currently conducting 

detailed studies of biological markers contained in the 

oils to determine whether multiple source rocks have 

expelled oil in the basin, or whether the oils were 

expelled from a single source rock over a range of 

maturities (burial depths). 

Fractal Nature of Hydrocarbon 

Accumulations and PriceImplications for Resource Assessment, 

Exploration and Development 

Strategies, and Economic Forecasting 

Christopher C. Barton 

Fractal geometry is a branch of mathematics that 

redefines how we may quantitatively describe and model 

complex patterns and distributions. It can be applied to 

three complex patterns and distributions of importance 

to the petroleum industry: (1) the size-frequency 

distribution of petroleum accumulations and its 

consequences on assessments of the volume of 

undiscovered petroleum resources, (2) the spatial 

clustering of petroleum accumulations and its 

consequences on exploration and development 

strategies, and (3) the fluctuation of oil price and the use 

of fractal statistics to quantify price behavior. 

Hydrocarbon accumulations vary in size over scales 

spanning many orders of magnitude. A proper 

mathematical description of this variation is sought in 

order to assess the volume of hydrocarbons contained in 

undiscovered accumulations. Size-frequency data sets 

extending over six orders of magnitude, from small fields 

in a play to giant fields of the world, have proven to be 

fractal; and any given population of hydrocarbon 

accumulations consists of the sum of many fractal subpopulations in nested hierarchical levels without a 

characteristic size scale. The volume of the undiscovered 

accumulations is calculated for several data sets using a 

convergence constraint which requires only that the 

volume of hydrocarbons in a given data set be finite, thus 

constraining the value of the exponent in the power-law 

distribution to be less than one. Data sets that include too 

3 

large an area or too diverse a set of subpopulations fail to 

meet the convergence requirement. This failure 

commonly follows from combining fractal subpopulations with different upper field-size limits indicating that 

predictions of the undiscovered resources on continental 

and world scales should be made for collections of 

smaller, geologically homogeneous populations which 

may then be aggregated. 

The spatial clustering of hydrocarbon 

accumulations also varies over length scales spanning 

many orders of magnitude. A fractal description of this 

clustering provides a mathematical characterization that 

can be used to optimize exploration and development 

strategies. The spatial clustering of hydrocarbon 

accumulations in 40 x 40 mile square portions of two 

stratified reservoirs, the J sandstone of the Denver basin 

and the Muddy Sandstone of the Powder River basin, is 

found to be fractal. Thus, the accumulations cluster at all 

scales tested, with the fractal dimension (D) 1.49 and 

1.43, respectively, over length scales ranging from 1 to 10 

miles. The fractal nature of the spatial clustering of 

hydrocarbon accumulations in a given reservoir has 

significant consequences on the selection of appropriate 

exploration and development strategies. 

The fluctuation of oil price as a function of time 

also exhibits fractal structure with a chaotic attractor 

underlying price behavior. This result reveals a 

mathematical structure of the oil market which could 

provide a new basis for economic forecasting of oil price. 

C.C. Barton can be reached at the USGS, 

(303) 236-1280. 

Petroleum Reservoir Evaluation by 

Borehole Gravity Survey 

Larry A. Beyer 

Borehole gravity surveys of petroleum reservoirs, 

which can provide unique bulk-density, porosity, and 

pore-fluid density information, have been made 

intermittently for more than 25 years and have gradually 

received greater industrial acceptance. However, today's 

requirements for improved description and monitoring 

of petroleum reservoirs argue for even broader use of 

borehole gravity surveys. Broader use and acceptance of 

borehole gravimetry require that its capabilities and 

limitations be fully understood and carefully applied to 

each case study; a logic flowchart that incorporates 

geologic, well-log, and reservoir information with the 

capabilities and limitations of borehole gravimetry can 

aid this decision-making process. Broader acceptance 

also comes about through successful demonstrations of 

improved reservoir description that, for example, 
~ 

0 100 0.2 2000 

J I I I 

1.8 1.9 2.0 2.1 2.2 2.3 2.4 

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c 2800 

~ 

·-...... 

;.... 

~ 3000 

I 3200 

3400 

3600 

. ... :.. . 

o: ··,-:::.;:~1~ o I 

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... ··:···· • · .. :.· .. z.:... · · • • • . ·~=·:: 

... ·.::~·:=,·~ 

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density /• 

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GAMMA RAY RESISTIVITY CHROMATOGRAPH 0 100 1 10 100 C1 C2 C3 C4Cs I W" I I I IS I I _y .~ I Y t Y IV IV 

".:: 

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~ 

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core bulk r· :····· ·.::. ~~-

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ensity ·: · · .::i( 

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~--------~~~46oo•~-~~--~~~~--~--~----L----L __ _j 1.8 1.9 2.0 2.1 2.2 

DENSITY 

(g/cm3) 

2.3 2.4 

0 100 0.2 2000 

GAMMA RAY RESISTIVITY 

Figure 1 (Beyer). Interval density profile based on borehole gravity 

survey through the lower part of the Sagavanirktok Formation 

(Cretaceous and Tertiary), West Sak 17 well, Kuparuk River oil field, 

Alaska. The unproduced oil-bearing sandstones of the lower part of the 

Sagavanirktok Formation are poorly consolidated fluvial to deltaic 

deposits, locally referred to (by M.A. Werner in a 1987 study) as the 

·ugnu and West Sak sands. • API gravities of oil in these sandstones 

generally range from 12° to 200. Gamma ray and resistivity logs (left) and 

portion of gas chromatograph log (right) also are shown. Bulk densities 

of conventional core samples of sandstone from three nearby wells and 

the interval-averaged gamma-gamma densities for four sandstone 

intervals from the formation density log of the West Sak 17 well also are 

plotted with the gravity-based density profile. Core densities, based on 

fresh-water saturation, are calculated from laboratory measurements of 

porosity provided by the Kuparuk field operator. Core porosities and 

calculated densities are not adjusted for overburden stress and 

reservoir pressures. 
delineate new productive intervals, define original or 

secondary gas zones, or more accurately assess porosity 

for improved reserve calculations and production. 

Borehole gravity measurements, because of their 

greater lateral sensing distance than those of 

conventional log methods, frequently improve evaluation 

of (1) carbonate reservoirs that are characterized by 

large-scale porosity and (2) poorly consolidated 

reservoirs or other reservoirs where borehole rugosity 

and formation invasion perturb shallow-sensing log 

methods. Borehole gravity measurements also are 

unaffected in a practical sense by metallic casing or 

cement behind casing. Because of their high precision 

and relatively high accuracy, borehole gravity 

measurements may allow detection of vertical variations 

or temporal changes of pore-fluid density in reservoirs 

with moderate to high porosity. 

Selected results of borehole gravity studies by the 

U.S. Geological Survey and industry in California, 

Alaska, Rocky Mountains, Gulf Coast, Michigan basin, 

and Middle East illustrate (1) improved description of 

carbonate and poorly consolidated clastic reservoirs, (2) 

through-casing evaluations of older or bypassed 

(potential) reservoirs, (3) discovery of otherwise 

undetected reservoirs, and ( 4) evaluation of vertical and 

temporal pore-fluid density variations in reservoirs, such 

as gas cap detection and monitoring. More accurate 

assessment of reservoir density (and therefore porosity) 

by borehole gravity survey is shown in figure 1, which 

compares core, gamma-gamma, and borehole gravity 

densities. In this study, the larger volume of these poorly 

consolidated reservoir rocks investigated by the borehole 

gravity measurements indicates the effectiveness of borehole gravity-based reservoir density (and porosity) over 

both core and gamma-gamma log data. 

Interactive Volume Modeling of Coal and 

Associated Depositional Systems, 

Eocene Brunner Coal Measures, 

Buller Coal Field, New Zealand 

Laura R. H. Biewick, Margaret S. Ellis, 

Dorsey Blake, Romeo M. Flores, 

Richard Sykes, and Carol L. Molnia 

Three-dimensional (3-D) computer modeling of 

lithofacies in the Eocene Brunner Coal Measures in the 

Buller coal field, South Island, New Zealand, enhances 

visualization of the evolution of depositional patterns 

associated with peat accumulation. Interactive displays 

show 3-D vertical and lateral variations of lithofacies 

augmenting detailed paleoenvironmental interpretations 

of the Brunner Coal Measures by Flores and Sykes. 

5 

The Buller coal field, which extends about 20 mi 

(32 km) along the West Coast of South Island, includes 

the sandstone-dominated, fining-upward Brunner Coal 

Measures. Conglomerates, sandstone grits, and 

subordinate siltstones and mudstones in the lower part of 

the Brunner Coal Measures were deposited on an 

undulating peneplain surface developed on Paleozoic 

and Cretaceous basement rocks. Above this lower 

interval is a middle interval consisting of coal in the Main 

Seam or splits of the Main Seam and detrital sediments in 

partings between the splits. The middle interval is 

overlain by interbedded sandstones, siltstones, and mudstones and minor coals of the upper interval, which 

laterally interfingers with marine mudstones of the 

Eocene Kaiata Formation. 

For this study we focused on the lower interval 

between the basement and the base of the Main Seam or 

lowest split, and on the middle interval extending from 

the base of the Main Seam or lowest split to the top of the 

Main Seam or highest split. Continuous-core data from 

the New Zealand Geological Survey, which included 

lithologic information from 1,108 exploratory drill holes, 

were used in this study. Data distribution is uneven: drill 

holes are clustered densely in areas of greater economic 

interest, such as the northeast-trending belt immediately 

west of the Mt. William fault, whereas large areas contain 

no data (for example, the north-central part of the coal 

field in the watershed of the Ngakawau River). 

Interactive Surface Modeling (ISM) and Interactive 

Volume Modeling (IVM) software of Dynamic 

Graphics, Inc., were used to analyze this data set. An 

important aspect of IVM modeling is the ability to cut 

into and rotate the display for detailed study in any 

direction. 

We created displays showing present -day sea level 

as datum and displays showing approximated paleosurfaces using the base of the Main Seam as datum. Some of 

the displays show the percentage of coarse-grained 

(conglomerate and (or) sandstone), or fine-grained 

(mudstone and siltstone) detritus with respect to the 

thickness of the lower interval. Other 3-D displays exhibit 

the percentage of coal or partings with respect to the 

thickness of the middle interval. Gridding the percentage 

(p) of each lithology within an interval required adding 

control points to the data set. Each drill-hole data point 

has a surface location ~J'), an elevation (z), and a 

percentage value (p) to be contoured. To produce an 

accurate 3-D representation showing the percentage of a 

lithology, the p value has to be constant at the drill-hole 

location throughout the interval thickness, not just 

represented at the top of the interval. To establish this 

constancy, control points at each drill-hole location were 

added with the same x, y, and p values, but with different 

z values spaced at 10-ft (3-m) intervals covering the 
01 

Figure 1 (Biewick and others). Display showing the percent of coarse-grained detrital sediments (conglomerate and (or) sandstone) in the lower interval of the 

Brunner Coal Measures, New Zealand. Datum is the base of the Main Seam. North is in the direction of the y-axis. 
thickness of the inteiVal. The resultant grids extrapolated 

p only between the drill holes, creating representative 

displays contoured in 3-D. 

One of the displays that were created with the base 

of the Main Seam as datum is shown in figure 1. General 

northeast-southwest trends in lithofacies may have been 

influenced by known syndepositional faults and a 

topographically controlled paleovalley. In the lower 

intetVal, areas with high percentages of coarse-grained 

material indicate gravel and sand buildup in channels 

infilling the paleovalley. The figure also shows a 

northeast-southwest-trending drainage and variable 3-D 

geometry of internal grain-size distribution. Interactive 

manipulation of the display (for example, slicing into the 

model on the z axis) reveals an extrapolated projection of 

changes in the sediment-load buildup and drainage 

pattern(s) through time. Similarly, displays created for 

the middle intetVal indicate generalized patterns of coal 

distribution and of peat accumulation through time when 

sliced along the z axis. 

The displays graphically and interactively illustrate 

lithologic trends that support and augment the 

interpretation of areal distributions of depositional 

systems and paleoenvironments by Flores and Sykes. 

According to their interpretation, the lower inteiVal 

represents deposits of trunk and tributary braided 

streams and the coal-bearing intetVal represents deposits 

of raised mires that developed on abandoned braidbelts. 

Interpretation of specific paleoenvironments 

requires detailed examination of sedimentologic and 

stratigraphic data. This computer study enabled the 

collation of a massive stratigraphic data base to show 

generalized lithofacies trends. Interactive 3-D computer 

modeling has proved to be an effective tool for analyzing 

and displaying the vertical and lateral relationships of 

lithofacies and paleoenvironmental distribution useful in 

the construction of predictive depositional models. 

Sagavanirktok FormationA New Look with Seismic Data in the 

Prudhoe Bay-Kuparuk River Region, 

Alaskan North Slope 

Kenneth J. Bird and Timothy S. Collett 

The Upper Cretaceous and Tertiary deltaic Sagavanirktok Formation constitutes the latest stage of filling 

of the Alaskan North Slope's Colville basin and a 

treasure trove of energy resources. These resources 

include an estimated 40-60 billion barrels (in place) of 

low-gravity oil, 37-44 trillion cubic feet of natural gas in 

hydrate form, and more than 600 billion metric tons of 

low-rank coal. Most oil and gas deposits in the 

7 

Sagavanirktok occur at shallow depths ( < 1,000 m) in a 

relatively restricted area overlying the giant oil and gas 

fields, Prudhoe Bay and Kuparuk River. The first 

commercial oil production from the Sagavanirktok 

Formation was initiated in the Milne Point field in 1990 

by the Continental Oil Company; however, at this time 

most Sagavanirktok oil and gas deposits are classified as 

unconventional resources. 

Access to approximately 200 km of multichannel 

seismic data in the Prudhoe Bay-Kuparuk River region, 

courtesy of the Exxon Company, provides new insight 

into the structural and stratigraphic framework of this 

area. These are the first modern seismic data available to 

us in this region; they represent a significant addition to 

our study of gas hydrates in the Sagavanirktok 

Formation, a project partially funded by the U.S. 

Department of Energy. Preliminary analysis of the 

seismic data confirms the northeast-trending regional dip 

and northward-expanding thickness of the Sagavanirktok 

Formation. The clinoform style of progradation, well 

demonstrated to the west in the National Petroleum 

ResetVe in Alaska, continues through the Prudhoe BayKuparuk River region: the Sagavanirktok representing 

the topset and the coeval Canning Formation 

representing the foreset and bottomset parts of the 

clinoform sequence. Bundles of strong reflections in· the 

topset strata delineate the main coal-bearing inteiVals. 

Local high-amplitude reflectors in the bottomset strata 

may indicate turbidite sand accumulations within 

prodelta mudstone of the Canning Formation. In the 

region of the Prudhoe Bay oil field, prominent flat-lying 

reflections, which occur discontinuously at about 0.7 s 

(two-way travel time), cut across northeasterly dipping 

reflectors that mark the regional dip of the Sagavanirktok 

Formation. Preliminary analysis reveals that these flatlying reflections occur at a depth of about 950 m, 

approximately coincident with the calculated base of ~he 

hydrate stability zone in this area. In the marme 

environment, prominent reflections coincident with the 

base of the hydrate stability zone are well known (bottom 

simulating reflectors, BSR's) and are postulated to be the 

result of free gas trapped below a hydrate seal. The 

reflectors obsetVed on the seismic section over the Prudhoe Bay oil field appear to be the onshore equivalent of 

aBSR. 

As production from the Prudhoe Bay and other 

North Slope oil fields declines, the enormous 

hydrocarbon resources of the Sagavanirktok Formation 

will become increasingly important. Exploration for new 

hydrocarbon resources will require appreciation of 

subtle structural-stratigraphic traps and other traps 

unique to the Arctic region, such as gas hydrates. 

Production of these hydrocarbon resources presents a 

major challenge and will require innovative approaches 

and new thinking. 
Alaskan North Slope Geothermics, 

Geodynamics, and HydrologyImplications for Oil and Gas 

Kenneth J. Bird, David G. Howell, 

Mark J. Johnsson, and Leslie B. Magoon 

Alaskan North Slope petroleum studies by the U.S. 

Geological Survey (USGS) are focused on the practically 

un~xplore~ fold-and-thrust belt of the Brooks Range, a 

regton estimated to have considerable resource potential. 

Questions being addressed include the quality, quantity, 

and distribution of reservoir- and source-rocks and the 

timing of trap formation relative to generation and 

migration of oil and gas. The answers to these questions 

will have an important bearing on this region's petroleum 

potential and, therefore, on resource assessment and 

exploration strategies. 

The North Slope is one of the most prolific 

petro~eum provinces in the United States. It currently 

supphes one-quarter of our daily domestic oil production 

( =2 million barrels/day), has productive and 

nonproductive conventional oil accumulations and 

nonp~oductive heavy oil accumulations that originally 

contruned nea~ly 70 billion barrels of oil (BBO) in place, 

and has large m-place volumes of principally associated 

natural gas (=40 trillion cubic feet of gas, TCFG) that 

are presently uneconomic. In the 1987 national 

assessment of undiscovered recoverable conventional oil 

and gas resources, the USGS estimated that, at the mean, 

nea~ly one-quarter of our Nation's remaining 

undiscovered conventional oil resources ( = 13 BBO) and 

one-seventh of its undiscovered natural gas resources 

(=54 TCFG) lie beneath the North Slope and adjacent 

State offshore waters. 

A peculiar feature of discovered North Slope oil 

and gas accumulations is their geographic concentration 

in a relatively small area on the foreland-more than 95 

perc~nt are located within 60 km of Prudhoe Bay. Yet the 

co~stderable volume of undiscovered oil and gas is 

estimated to be much more widely distributed-about 60 

percent in the fold:and-thrust belt region and 40 percent 

m ~he foreland re~on. T~e fold-and-thrust belt region is 

estimated to contam undiscovered resources amounting 

to =6 BBO (mean; range 1-18 BBO) and =32 TCFG 

(mean; range, 7-86 TCFG). The basis for these estimates 

is the existence of hundreds of undrilled structures the 

presence of clastic and carbonate reservoir r~cks abundant source rocks, seemingly favorable maturi~ patterns, oil and gas indications in wells and outcrop, and 

seven _small to medium-sized oil and gas fields (six gas, 

one otl). 

Our current studies are analyzing regional patterns 

of thermal maturity (based on vitrinite reflectance and 

8 

conodont color indices) and integrating surface and 

subsurface geology along a series of five planned 

transects oriented perpendicular to the fold-and-thrust 

belt and spaced, on the average, at 200-km intervals. We 

have completed thermal maturity mapping of the surface 

and subsurface of the North Slope and two seasons of 

field work on our first transect, located along the Dalton 

Highway. 

Our findings to late 1991 show that nearly 12 km of 

uplift has occurred in the central Brooks Range, where 

reflectance isograds are cut by major thrust faults, 

indicating that maximum burial postdated at least early 

phases of thrusting. In the foothills, warping of 

reflectance isograds indicates that some folding (and 

faulting?) continued subsequent to thermal imprinting, 

an observation which suggests that oil and gas 

exploration in the fold-and-thrust belt may be a matter of 

looking for re-migrated hydrocarbons. Regional patterns 

on the surface show that thermal maturity decreases 

northward from the Brooks Range to the coastline; 

minimal maturity values are found east of Prudhoe Bay. 

In the central North Slope (between about long 149° and 

158° W.), thermally immature rocks extend nearly to the 

front of the Brooks Range, whereas to the east and west 

thermally mature rocks are exposed. We interpret this to 

indicate regional differential uplift along the strike of the 

Brooks Range orogen, with greater uplift in the west and 

east than in the center. This central area should be 

prospective for oil for longer distances to the south than 

to adjacent areas west and east. 

A related USGS study in the National Petroleum 

Reserve in Alaska has found that geothermal gradients 

and heat flow are higher on the north (foreland) side of 

the basin and lower in the foothills (fold and thrust) belt 

of the Brooks Range. This thermal pattern is consistent 

with forced convection by a topography-driven groundwater flow system that would effectively cool the 

topographically higher fold-and-thrust belt and warm the 

topographically lower foreland region. Similarities 

between present-day thermal gradients and vitrinite 

reflectance profiles suggest that the postulated groundwater flow system probably has been a feature of the 

fold-and-thrust belt throughout its 150-m.y. history and 

may have provided a driving mechanism for petroleum 

migration. 

Gravity and Aeromagnetic Interpretation 

of Structure in Railroad Valley and the 

Grant Range, East-Central Nevada 

H. Richard Blank and John A. Grow 

. Potential-field anomalies in Railroad Valley and 

adJacent areas, used in conjunction with geologic, 
seismic, and drilling data, contribute uniquely to an 

understanding of upper crustal structure of this complex 

region and thereby help to constrain hypotheses for the 

generation and localization of its hydrocarbon deposits. 

Railroad Valley extends nearly 175 km in a generally 

north-south direction and has a maximum width of some 

25 km. The associated Bouguer gravity anomaly field, 

reflecting mainly the density contrast between preTertiary bedrock and late Cenozoic valley fill, delineates 

a buried axial trough much narrower than the full width 

of the valley. The trough is characterized by colinear 

deeps 30-50 km long that are separated by transverse 

rises. It is probably no coincidence that all six of the 

producing oil fields in Railroad Valley are situated on the 

margins of the deepest gravity low, which is located in 

Butterfield Marsh, west of the northern Grant Range. 

This low has a residual amplitude of -43 mGal. 

Exploration drilling has established that the thickness of 

valley fill (Tertiary and Quaternary deposits, including 

Tertiary volcanics) here exceeds 4.2 km. At such depths 

the prevailing geothermal gradient may be sufficient to 

convert organic material to oil, and high-angle faults on 

the margins of the deep could have facilitated upward 

migration to suitable traps and reservoirs. The density 

contrast corresponding to a 43-mGal anomaly produced 

by 4-5 km of valley fill is much less than the 0.40--0.45 

g/cm3 predicted for fill relative to Paleozoic carbonates, a 

discrepancy attributed to an abundance of high-density 

carbonate material in the Tertiary and Quaternary 

section. This conclusion is supported by data from downhole sonic and lithologic logs. Megaclasts of Paleozoic 

carbonate rock are locally present and in some places 

have been detected by high-precision commercial gravity 

surveys. 

The anomaly has horizontal gradients along its 

eastern flank of as much as 11 mGal/km, whereas those 

on the western flank are about half as strong. This 

asymmetry results from a bedrock surface in the form of 

a half-graben with its floor tilted down to the east, in 

agreement with seismic reflection data. The eastern 

marginal gradient continues as a well-constrained gravity 

feature for 65-70 km along the range front, 

approximately between lat 38°45' N. and 38°15' N. The 

locus of maximum gradients (fig.1) is a line 2-10 km west 

(basinward) of the nearest bedrock outcrops. This line 

roughly coincides with a line of springs and ground-water 

seepage, and marks the trace of the main boundary fault 

(range-front fault) on the west side of the Grant Range. 

East of Butterfield Marsh, and also just north of the 

Quinn Canyon Range, where the gradient is steepest, the 

fault or fault zone is probably a high-angle structure, but 

in the intervening segment (from the Grant Canyon oil 

field for about 15 km south), dips as low as 20° have been 

interpreted from seismic data. Both flatter dips and 

deeper burial of the density discontinuity could cause the 

9 

diminished gravity gradients. Down-hole logs show the 

rocks immediately east of the gradient maximum at 

Grant Canyon to be predominantly high-velocity, highdensity Paleozoic carbonate sand/gravel and breccia 

(identified as valley fill) below the uppermost 400 m or so 

of section. A transverse seismic profile in this area 

reveals east-dipping reflectors abutting an underlying, 

gently west dipping reflector interpreted as a low-angle 

normal fault. Thus at Grant Canyon the range-front fault 

apparently truncates a section that includes detached and 

rotated allochthonous Paleozoic strata (either megaclasts 

in valley fill or forming the hanging wall of a low-angle 

normal fault). 

The loci of gravity horizontal-gradient maxima in 

figure 1 are superimposed on a gray-scale map of the 

residual total-intensity aeromagnetic anomaly field 

(IGRF removed). The main aeromagnetic feature of 

interest is a broad positive anomaly that encompasses the 

north half of Railroad Valley and most of the Grant 

Range. The axis of this anomaly is roughly parallel to that 

of the negative gravity anomaly associated with Railroad 

Valley: both extend north-south across the area of figure 

1 and are convex eastward. No offset of the aeromagnetic 

feature is observed where it is transected by the rangefront fault, and the estimated depth to the top of the 

magnetic source is commensurate with a reasonable 

depth extent for the density discontinuity. Therefore the 

range-front fault is probably listric with respect to, or 

terminates at, a low-angle structure at or near the surface 

of the magnetic body. This structure may be the lowangle normal fault intepreted from seismic data at Grant 

Canyon. Mississippian Chainman Shale, a source rock for 

the hydrocarbons, may locally have been the horizon of 

detachment. Whether the low-angle fault passes beneath 

the Grant Range at depth or connects with a low-angle 

fault exposed on the west side of the Grant Range is not 

likely to be resolved from the potential-field data. 

In the absence of strongly magnetic Paleozoic 

strata, the possible sources of the broad aeromagnetic 

anomaly are limited to Precambrian crystalline basement 

and Phanerozoic intrusives. Shorter-wavelength highs 

superimposed on the broad anomaly are attributable to 

structural relief and (or) variable magnetization of either 

rock. Our preferred interpretation for the source body is 

a Phanerozoic granitic (chiefly quartz monzonitic) batholith. Granitic plutons are exposed in the southwestern 

White Pine Range, in the southwestern and central Grant 

Range, and in the northern Quinn Canyon Range, all 

localities that are close to the axis of the broad anomaly; 

and quartz monzonite has been penetrated in several drill 

holes in Railroad Valley. Potassium-argon ages for 

biotite of these plutons range from 36 to 23 Ma. 

However, a 70-Ma minimum age of crystallization was 

determined for the Troy pluton in the Grant Range on 

the basis of whole-rock Rb:Sr analysis; and it now seem·s 
360 

320 

280 

240 

200 

160 

120 

(/) 

<( 80 -' 

(/) 

UJ 

1-

0 

z 40 

<( 

z 

0 

-40 

-80 

-120 

-160 

-200 

-600 

10 20 30 KILOMETERS 

10 20 MILES 
Figure 1 (Blank and Grow) (facing page). Gray-scale map 

of residual aeromagnetic total-intensity anomaly field of 

Railroad Valley, Grant Range, and vicinity, east-central 

Nevada. Data of several surveys have been merged, draped 

to 1,000 ft (305 m) above terrain and reduced to the pole. 

Selected gravity anomaly features are also shown: (1) loci of 

horizontal-gradient maxima of the Bouguer anomaly field 

(heavy barbed lines where intense, indicating steep, nearsurface density discontinuities; light barbed lines where less 

intense, indicating less steep dips, more deeply buried 

density discontinuities, gradational density contrasts, or a 

combination of these); (2) areas of Airy isostatic residual 

anomaly lower than -20 mGal (outlined by solid lines); and 

(3) isostatic residual anomaly minima lower than -30 mGal 

(labeled "L"). Standard parameters have been used for the 

gravity reductions. Hachured areas in Railroad Valley are oil 

fields (fS, Trap Spring; ES, Eagle Springs; GC, Grant 

Canyon). Solid black areas denote exposed silicic intrusive 

rock, chiefly granitoid. 

likely that the plutons are part of a composite body, 

initially emplaced in Cretaceous time but becoming a 

locus of renewed heating and possibly magmatism in the 

Tertiary. 

The inferred batholith must have had a major role 

in the tectonic evolution of the Railroad Valley-Grant 

Range region. Initial emplacement occurred during a 

late stage of synkinematic regional metamorphism 

recorded in lower Paleozoic rocks of the Grant Range. 

Renewed magmatism in Oligocene-Miocene time may 

have contributed to arching of the range, as well as to 

high heat flow in Railroad Valley. In addition, a 

structural parallelism indicates that the presence of the 

batholith probably influenced the configuration of 

youthful extensional structures such as the Railroad 

Valley graben. 

Tectonostratigraphy and Neogene 

Extensional Tectonism on Part of the 

California Continental BorderlandA Seismic-Reflection Perspective 

R.G. Bohannon and E.L. Geist 

Tectonostratigraphic terranes and extensional 

structures are being studied on part of the California 

Continental Borderland using seismic-reflection data 

primarily from USGS line 120, which traverses the 

tectonic grain of the province south of San Clemente 

Island. After applying prestack multiple suppression and 

migration, we can present the data on line 120 in depth 

section. Ancillary data from two crossing lines and 

several nearby parallel lines, in standard stack sections, 

are also useful. We can enhance details of fault structures 

11 

by locally portraying the amplitude data in color. Stratigraphic control comes from onshore outcrops east of the 

end of the line at Oceanside and north of the line at San 

Clemente Island, and from well data on southern Cortes 

Bank. 

Line 120 crosses four tectonostratigraphic terranes. The offshore segment of the Santa Ana terrane 

near Oceanside has well-developed reflectors imaging a 

thick Cretaceous to Miocene section that dips gently 

westward above basement. Several large listric normal 

faults with intermediate to low eastward dips truncate the 

sedimentary section against schistose rocks of the 

adjacent Catalina terrane beneath the Neogene 

sediments in the Gulf of Santa Catalina. Reflective 

horizons are thin and discontinuous across the Catalina 

terrane where Miocene sedimentary and volcanic rocks 

lie directly on Catalina Schist (Mesozoic). Southwest of 

San Clemente Island the Nicolas terrane can be easily 

distinguished from the Catalina by a thick, welldeveloped, gently deformed reflective sequence of 

Cretaceous to upper Miocene strata present beneath 

southern San Nicolas basin and Cortes Bank. The 

boundary between the latter terranes is at an eastdipping normal fault that lies along the southwest side of 

the West Cortes Basin. In the Patton terrane, reflective 

strata are confined to small Neogene basins that 

developed in low-grade, acoustically chaotic metamorphic rocks. 

Numerous basins, primarily half-grabens, formed 

during the late Miocene to Holocene in the Nicolas, 

Catalina, and Santa Ana terranes along line 120. The 

southern Patton terrane has an irregular bathymetry, but 

basins are poorly developed or absent. East-northeastand west-southwest-facing half-grabens are bounded by 

normal faults that have intermediate to gentle dips. Some 

of the fault planes produce reflectors, but most are 

marked by terminations in stratal reflectors. Listric and 

planar fault geometries are both present. 

Normal Faulting in Collisional 

Foredeeps-Implications for 

Basin Analysis 

Dwight C. Bradley and W.S.F. Kidd 

We report the results of structural and stratigraphic analysis of three foredeeps cut by syncollisional 

normal faults (Ordovician Taconic foredeep, Carboniferous Arkoma basin, and present-day Timor-Aru 

trough), and we use these examples to generalize about 

extensional processes in environments of lithospheric 

flexure. Normal faults on the cratonic flanks of collisional 

foredeeps (those formed during arc-passive-margin 
' I 

/ 

I ' / 

I / " / I 

- ' / / 

/ / I 

, / / 

Active normal faults 

~-------..,250 KM --------~ 

Figure 1 (Bradley and Kidd). Schematic block diagram of 

Taconic collisional foredeep in New York, showing 

distribution of facies belts and extensional and contractional 

deformation regimes shortly before plate convergence 

ended. Timor-Aru trough and Arkoma basin are similar. Fault 

collision, as opposed to Andean-type foreland basins) are 

analogous to normal faults in deep-sea trenches, except 

that the faulted lithosphere is continental rather than 

oceanic. {See expanded discussion in a 1991 study of 

Bradley and Kidd.) Normal faulting occurs within an 

overall setting of plate convergence when the subducting 

lithosphere is flexed beyond its elastic limit. Because the 

top of the lithosphere extends while the lower lithosphere 

contracts, the dynamics of extension in this setting differ 

fundamentally from those of rifting induced by divergent 

plate motion. 

The normal faults we studied typically occur as far 

as 100 km toward the foreland from the thrust front and 

parallel with it, have throws of as much as about 1 km, 

are spaced 5-10 km apart, and account for regional 

near-surface extension typically of a few percent, locally 

10-15 percent. Most faults have down-to-basin 

displacement, together offsetting the underthrust plate 

like a descending escalator (fig. 1). Fault blocks are 

rotated with respect to the enveloping surface of the 

faulted plate, which implies that a detachment exists at 

depth to accommodate block rotation. In the Taconic 

foreland of New York, we estimate that steep normal 

faults ruptured the crust to a depth of 15-20 km, ending 

at a subhorizontal detachment. Dip-slip displacement on 

these normal faults was sufficient to produce water 

12 

dashed where inferred; barbs show direction of movement 

on faults; sawteeth on overthrust block. Patterns show rock 

types as follows: random dashes, Precambrian basement; 

bricks, carbonate rocks of passive-margin platform; parallel 

dashes, shale; stipple, graywacke and shale. 

depths in the Arkoma basin and Taconic foredeep 

comparable to those in the Timor-Aru trough. 

Accordingly, we suggest that normal faulting can be the 

primary mode of subsidence of the upper lithosphere in 

normal-faulted foredeeps. 

In each example, stratigraphic relations prove that 

normal faulting was largely syncollisional. In the Taconic 

foredeep of Newfoundland, the onset of normal faulting 

was synchronous with development of an unconformity 

attributed to migration of a forebulge across the passivemargin platform in advance of the convergent plate 

boundary (data from a 1991 study by I. Knight and 

others). Along strike in New York, normal faulting began 

after passage of the Taconic forebulge, during drowning 

of the carbonate platform beneath prograding foredeep 

clastics (fig. 1 ). In the Timor-Aru trough, normal faults 

are absent along the forebulge, but active faults cut the 

cratonic flank, where platform drowning is occurring 

today. In both the Arkoma basin (1986 study of D.W. 

Houseknecht) and the Taconic foredeep of New York 

{1991 study of Bradley and Kidd), the zone of active 

normal faulting migrated cratonward through time; 

normal faulting evidently ceased at any given location 

before arrival of the thrust front. The association of 

Mississippi-Valley-type Pb-Zn deposits (for example, in 

the northern Arkoma basin and the Taconic foredeep of 
Newfoundland) and hydrocarbon fields (for example, in 

Oman and Venezuela) with flexure-induced normal 

faults suggests that these structures can influence the 

regional-scale migration paths of basinal fluids (brines 

and hydrocarbons). 

Origin of Fluid Pressure, Fracture 

Generation, and the Movement of 

Fluids in the Uinta Basin, Utah 

J.D. Bredehoeft, J.B. Wesley, and 

T.D. Fouch 

The Altamont-Bluebell oil field in the deep Uinta 

Basin has reservoir pressures that approach lithostatic. 

One hypothesis to explain the high fluid pressures is that 

Type I kerogen has been converted to oil, a mechanism 

that decreases the density of the hydrocarbons during the 

change in phase. This phase change can result in 

increasing the pore fluid pressure. To test this hypothesis, 

a three-dimensional simulation of fluid flow within the 

Uinta Basin was performed. 

The kinetics of oil generation from oil shale 

(conversion of Type I kerogen) was investigated by 

several research groups. To a first approximation the 

reaction is a function of temperature. The temperature in 

a geologic environment is a function of the depth of 

burial and the geothermal gradient. The maximum depth 

of burial may have occurred as long as 10 million years in 

the past. A 3 °C/km change in the geothermal gradient is 

sufficient to change the rate of oil generation by an order 

of magnitude. The maintenance of high pressures at 

Altamont depends upon the permeability of the 

sediments. There is a linear relationship between the 

geothermal gradient and the reservoir permeability that 

is necessary to maintain the high fluid pressures. 

Natural hydrofractures are simulated by increasing 

the permeability tenfold where the reservoir fluid 

pressure exceeds the least principal stress. Simulated 

hydrofracs are restricted to the productive area of the 

field. 

The analysis demonstrates that oil generation can 

account for the high fluid pressure, and other fluidrelated phenomena in the Uinta Basin. 

Coal Availability Studies-An Update 

M. Devereux Carter, Nancy K. Gardner, 

James C. Cobb, Roy S. Sites, and 

Nick Fedorko, Ill 

In 1987, a cooperative program between the U.S. 

Geological Survey and the State geological agencies of 

13 

Kentucky, Virginia, and West Virginia was initiated in 

the Central Appalachian Region to (1) identify the major 

constraints to current coal mining that could inhibit the 

availability of coal resources and (2) estimate the amount 

of coal resources that may actually be available for 

development. 

This program has been tested in twelve 7 .5' 

quadrangles (five in Kentucky, four in West Virginia, and 

three in Virginia) to determine if the identified 

constraints to mining in the region would significantly 

affect the availability of coal for development. The 12 

study areas were selected to be representative of their 

general localities so that the results might be 

extrapolated to the surrounding regions of shared 

characteristics. 

Restrictions that could keep the coal resource from 

being mined fall into two general categories: land use 

(primarily human-caused) and technologic (maiqly 

geologic). Land-use restrictions applicable to the study 

areas to 1991 are power lines, pipelines, cemeteries, oil 

and gas wells, towns, major streams, public roads, 

railroads, airports, national and State parks, and a forest 

preserve. Technologic restrictions include coal beds 

considered too thin or too deep to mine, buffer zones 

around active or abandoned mines, mined and minable 

coal beds too close above or below one another, oil and 

gas wells penetrating underground-minable coal beds, 

and such geologic factors as washouts, faults, disturbed 

areas, and impurities within the coal beds. 

Within the 12 areas studied so far, only one-half the 

original coal resource is estimated to be available for 

mining. Coal mined and lost-in-mining accounts for 15 

percent of the reduction of the original resource, whereas 

land-use restrictions compose 3 percent, and 

technological restrictions 32 percent. More than 3.5 

billion tons are estimated to be unavailable because of 

restrictions to mining within the 12 study areas. 

Statistical analysis on sulfur data further indicates 

that only approximately one-half of the coal resources in 

these areas could be expected to meet current newsource performance standards of 1.2 pounds so2 per 

million Btu input. 

Economic considerations, such as mining costs, 

available transportation, both land and coal ownership, 

proximity to markets, and size of mining unit, and the 

application of recovery factors are beyond the scope of 

this study by USGS and State geological surveys. The 

U.S. Bureau of Mines (USBM) is conducting follow-on 

studies applying economic and recovery factors to 

determine the estimated amount of recoverable coal 

within the same quadrangle study areas. The USBM 

studies will result in an estimate of coal that is actually 

producible-a much smaller amount than the available 

resource. 
As expected, the results of the first 12 studies are 

inconclusive in terms of delineating regional trends. 

Studies in about 20 strategically placed 7.5' quadrangles 

may be necessary to adequately represent the entire 

Central Appalachian Region. Statistical analysis will 

begin in 1992, including extrapolation into the 

surrounding region. 

During 1991, coal availability studies were 

expanded into the Northern Appalachian Region in Ohio 

and West Virginia. Studies in Pennsylvania and 

Tennessee will commence in 1992. 

Climate Controls on Carboniferous Cyclic 

Sedimentation and Organic Productivity 

C. Blaine Cecil 

Cyclic sedimentation is generally attributed to 

tectonic and (or) eustatic controls. The stratigraphy of 

chemical and siliciclastic sedimentary rocks cannot, 

however, be explained on the basis of these physical 

processes alone. As an example, the Pennsylvanian 

System of the United States contains transgressiveregressive cycles (cyclothems) that appear to be eustatically driven; also, basins were tectonically active as 

subsidence was necessary to provide accommodation 

space. In the Western Interior, Eastern Interior and 

Appalachian basins, stratigraphic repetition of silidiclastic rocks and marine and nonmarine rocks that contain a 

strong chemical signature, such as coal beds, paleosols, 

black shales, and limestone, is indicative of paleoclimatic 

cycles as well as base-level change brought about by 

tectonics and (or) eustasy. Such climate cycles, induced 

by changes in rainfall patterns within catchment basins, 

are recorded in stratigraphic sequences by (1) changes in 

paleosediment flux; (2) formation of laterally extensive 

paleosols, whose individual characteristics range from 

modern Aridisols (arid-climate soils) to Vertisols 

(seasonal-climate soils) to Oxisols (ever-wet-climate 

soils); and (3) paleobotanical changes already long 

attributed to changes in paleoclimate. Furthermore, in 

the Appalachian basin, laterally extensive coal beds and 

the characteristics of coeval upland paleosols are 

cons.istent with pluvial periods, whereas the driest parts 

of chmate cycles are recorded in nonmarine sequences by 

l~custrine limestone beds that can be traced laterally into 

htghly calcareous paleosols that approach Aridisols in 

their structure, chemistry, and mineralogy. 

On a continental scale, zonal-circulation paleoclimates are also recorded in addition to paleoclimate 

cycles. The paleogeography of North America during the 

Pennsylvanian was such that the Eastern United States 

was equatorial relative to the Midcontinent and Western 

United States. The resulting paleoclimate gradient from 

14 

the Appalachian basin to the Western United States 

(wetter to drier, respectively) is indicated by the 

development of coal beds in the Appalachian basin while 

evaporites were being deposited in the Paradox basin 

contemporaneously with alluvial fans and eolianites in 

the Rocky Mountain region. 

Marine black shales, rich in organic matter, are 

important stratigraphic markers and are economically 

important as major hydrocarbon source beds and sources 

of metals. Such shales may also owe their origin to 

paleoclimate. Most models for the origin of black shales 

suggest that organic matter in these shales was preserved 

by anoxic bottom waters that resulted from (1) density 

stratification in silled basins, (2) deep-water conditions, 

or (3) high organic productivity in response to upwelling 

ocean currents as a control on the formation of shale rich 

in organic matter. However, organic productivity in 

tropical epeiric seas may also be related to climate cycles. 

Under dry climatic regimes, water loss from evaporation 

in epeiric seas is replaced by inflow of open marine water, 

a condition favorable for shallow-marine carbonates. In 

contrast, high rainfall during pluvial periods could slow 

or reverse inflow and provide a low density cap. The 

latter situation favors (1) influx of terrestrially derived 

materials including fine-grained siliciclastic sediment, 

nutrients and dissolved metals, and terrestrial organic 

matter; (2) increased marine biological productivity and 

deposition because of nutrient influx; and (3) cessation of 

carbonate deposition and the onset of black shale 

deposition. Such alternating wet and dry conditions 

during the Pleistocene and Holocene are known controls 

on the stratigraphic distribution of sapropels in the 

eastern Mediterranean Sea, and similar cycles have been 

suggested as a stratigraphic control for coal-bearing 

sequences of the Pennsylvanian System in the Eastern 

United States. Climate cycles, therefore, may also have 

influenced the origin of Paleozoic marine sequences, 

including their organic matter composition and the metal 

content of Carboniferous black shale. 

Although climate is a well-known control on 

sediment flux, including organic productivity, it is often 

assumed to be constant in tectonic and (or) eustatic 

models of stratigraphy and sedimentation. Carboniferous 

cyclic stratigraphy, however, appears to be a function of 

climatically driven changes in sediment flux as well as 

tectonic and eustatic changes in base level. 

Natural Gas HydratesA Proven Resource 

Timothy S. Collett 

Large volumes of hydrocarbon gas can occur in 

sediments in the form of gas hydrates. These substances 
are solids, composed of rigid cages of water molecules 

that trap molecules of gas. Cold surface temperatures at 

high latitudes are conducive to the development of 

onshore permafrost and gas hydrate in the subsurface. 

The combined information from Arctic gas-hydrate 

studies shows that in permafrost regions, gas hydrates 

may exist at subsurface depths ranging from =400 to 

=6,000 ft. Because large quantities of gas hydrates are 

widespread in permafrost regions, they may be a 

potential energy resource. Worldwide estimates of the 

amount of gas within continental gas hydrates range from 

500 to 1,200,000 trillion cubic feet. 

One of the primary objectives of the U.S. 

Geological Survey/U .S.S.R. Ministry of Geology 

(VNIGNI) cooperative research agreement is the 

assessment of the resource potential of the known Arctic 

gas-hydrate accumulations. The gas hydrates in the 

Soviet Messoyakha field, located in the West Siberian 

basin, and those of the Prudhoe Bay-Kuparuk River area 

in northern Alaska are the most studied gas-hydrate 

accumulations in the world and the focus of our 

cooperative research efforts. The production history of 

the Messoyakha field has demonstrated that gas hydrates 

are an immediate producible source of natural gas and 

that production can be started and maintained by 

conventional methods. Geologic similarities between the 

Messoyakha and Prudhoe Bay-Kuparuk River gashydrate accumulations further suggest that the Alaskan 

gas hydrates may also be a producible source of natural 

gas. 

The Messoyakha field, discovered in 1968, was the 

first producing field in the northern part of the West 

Siberian basin. Gas yields from the upper part of the 

Messoyakha reservoir were unusually low, and analyses 

of production data suggested the presence of naturaloccurring gas hydrates. Subsequent analyses of available 

temperature data and well logs confirmed the presence 

of gas hydrates in the upper part of the Messoyakha 

reservoir, thus separating the Messoyakha field into an 

upper, gas-hydrate, and lower, free-gas accumulation. 

Long-term production from the gas-hydrate part of the 

Messoyakha field has been achieved by a simple 

depressurization scheme. As production began in 1969, 

the reservoir pressures followed predicted values. 

However, by 1971 the measured reservoir-pressures 

began to deviate from predicted values, a deviation which 

has been attributed to the liberation of free-gas from 

dissociating gas hydrates. Soviet researchers have 

estimated that about 36 percent (=183 billion cubic feet) 

of the gas withdrawn from the Messoyakha field has 

come from the gas hydrates. 

Both the Messoyakha and Prudhoe Bay-Kuparuk 

River gas-hydrate accumulations occur in similar 

sequences of interbedded Cretaceous and Tertiary 

sandstone and siltstone reservoir rocks. Geochemical 

15 

analyses suggest that the gas hydrates of the Messoyakha 

and Prudhoe Bay-Kuparuk River fields are almost 

identical in composition, and they have been interpreted 

to contain a mixture of thermogenic methane that 

migrated from deep, mature sources and in-place, 

microbial methane. These similarities suggest that the 

origins of the two accumulations may be similar. The 

presence of a significant volume of free-gas trapped 

below both the Messoyakha and Prudhoe Bay-Kuparuk 

River gas-hydrate occurrences is very important to the 

consideration of potential production characteristics of 

gas hydrates in Alaska. Utilization of the gas-hydrate 

depressurization method of production requires that a 

portion of the accumulation be in a free-gas state. 

Therefore, the presence of free-gas below the Prudhoe 

Bay-Kuparuk River gas hydrates suggests that the 

depressurization production scheme utilized in the Messoyakha field may work in northern Alaska. 

The most striking difference between the Messoyakha and Prudhoe Bay gas-hydrate/free-gas occurrences 

is the size of the accumulations. The total mapped area of 

the gas-hydrate occurrences in the Prudhoe BayKuparuk River area is =650 mi2 , whereas the Messoyakha field covers an area of only =90 mi2

• This difference 

in field size accounts for the vast difference in the 

estimated gas volumes in the Messoyakha (2.8 trillion 

cubic feet) versus Prudhoe Bay-Kuparuk River (44 

trillion cubic feet) gas-hydrate accumulations, which 

suggests that the ultimate production capacity of the 

Prudhoe Bay-Kuparuk River gas-hydrate occurrences 

may be much greater than the historical production from 

the Messoyakha field. 

Tar Sands and Heavy OilsResources, Recovery, and Realism 

B.L. Crysdale, C.J. Schenk, and R.F. Meyer 

Resources.-Bitumen (tar-sand) and heavy-oil 

deposits represent a significant energy resource in the 

United States. The total bitumen resource for the United 

States is estimated to be 57 billion bbl. Utah has the 

largest resource, an estimated 29 billion bbl, followed by 

California with 9 billion bbl, Alabama with 6 billion, 

Texas with 5 billion, and Kentucky with 3 billion. 

California leads the United States in the amount of 

heavy-oil resources in place, with 42 billion bbl, followed 

by Alaska with 25 billion bbl (although some estimates 

put Alaska's heavy-oil resources as high as 50 billion bbl). 

Wyoming has 5 billion bbl, and Texas, Arkansas, and 

Louisiana each have 2 billion, for a total U.S. heavy-oil 

resource estimate of 80-100 billion bbl. 
Recovery.-Bitumens ( < 10° API gravity) and 

heavy oil (10°-20° API gravity) have high viscosities 

(100-10,000 cP (centipoises) for heavy oil; > 10,000 cP 

for bitumens) and cannot be recovered using 

conventional methods. The current technology for 

recovering these hydrocarbons involves thermal 

stimulation of reservoirs (generally steaming) to provide 

heat to the oil, which reduces the viscosity and allows the 

oil to be mobilized and thus recovered. Few tar sands, if 

any, are currently being exploited in the United States, 

except for road-surfacing material. 

Of the estimated 80-100 billion bbl of heavy-oil 

resources in place in the United States, approximately 

one-half is not economically recoverable using current 

technologies. The difficulty in recovering heavy oil is 

exemplified by the Santa Rosa Sandstone in northeast 

New Mexico, estimated to contain 95 million barrels of 

15° API gravity oil. Two steamflood projects were 

initiated, but only 365 barrels were ever produced. 

Realism.-Nearly all of today's economically 

recoverable heavy oil is in California, and is being utilized 

now. Seventy percent of California's present daily oil 

production is heavy oil. Production of light oil peaked in 

California in 1954, and more heavy oil than light oil has 

been produced there since 1972. Recovering Alaska's 

heavy oil is problematic due to transportation and 

environmental problems. 

Unless the economic market changes dramatically, 

the future of tar sands as a viable resource is marginal at 

best. However, new techniques or refinement of present 

ones that make the recovery of high-viscosity oils 

possible, such as fireflood or emulsion technology, may 

unlock some of the presently unavailable oil. 

Evidence for Petroleum-Assisted 

Speleogenesis, Lechuguilla Cave, 

Carlsbad Caverns National Park, 

New Mexico 

K.l. Cunningham and K.l. Takahashi 

Limited sulfur isotope, mineralogic, and cave morphogenetic data suggest that speleogenesis (cavern 

development) in the Guadalupe Mountains of New 

Mexico and Texas was the result of solution via sulfuric 

acid derived from H2S gas. The cave-bearing reef 

complex is adjacent to many oil and gas fields, and 

numerous gas migration routes into the reef complex are 

plausible. Cave gypsum and elemental sulfur isotopic 

values as light as -25.8 parts per mil (referenced to the 

Canyon Diablo Troilite) link these cave deposits to 

H2S-bearing gas deposits. Uncommon cave deposits of 

pH -dependent minerals like 10 A halloysite ( endellite) 

16 

indicate strongly acidic (pH= 1-2) conditions consistent 

with the sulfuric acid hypothesis. Blind passages, 

passages dying with depth, and long (300-1,000 meters) 

horizontal passage extents have also been cited as 

evidence that the majority of solution occurred at a 

lowering water table where H2S and atmospheric oxygen 

mixed to produce sulfuric acid. Whether or not the main 

acid-producing reaction occurred at the water table, in 

the mixing zone between fresh water and brines, or 

deeper in the system is debatable, and important to 

carbonate dissolution mechanisms. With the 1986 

discovery and subsequent aggressive exploration of 

Lechuguilla Cave, we have recently been provided with 

additional data from a uniquely preserved 100 + 

kilometer long cave and the only Guadalupian cave to 

penetrate to the apparent water table. 

Most caves in the Guadalupe Mountains, including 

Carlsbad Cavern, have been extensively invaded by seep 

water, resulting in the appreciable loss of massive and 

speleothemic gypsum. Sulfuric-acid-stage elemental 

sulfur is very rare: one small deposit is documented at 

Cottonwood Cave where oxidation has apparently slowed 

due to limited air exchange or other unknown factors. In 

contrast, Lechuguilla may contain more preserved 

gypsum and sulfuric-acid-stage sulfur than all other 

known caves in the Guadalupes combined: a laterally 

extensive siltstone caprock has apparently diverted most 

recent water away from the cave, such that occurrences 

of flowstone and other calcitic speleothems are highly 

contained and localized. Massive, chemically precipitated 

gypsum deposits and fragile, secondary speleothems 

begin near the entrance and extend to within 175 meters 

of the water table, an overall vertical distance of nearly 

290 meters. The gypsum deposits are up to 10 meters 

thick in large rooms, occasionally fill passages, and 

sometimes occur on steep slopes and balconies on the 

sides of vertical shafts. Replacement textures have been 

noted in some blocks, but most accumulations appear to 

be the result of chemical precipitation or oxidation of 

early-formed sulfur masses. Elemental sulfur occurs as 

multi-ton, massive, vuggy, or encrusting deposits at 

diverse vertical levels in the cave. The remarkable 

preservation of the deposits (in contrast with other 

Guadalupe caves) suggests that oxygen availability in 

Lechuguilla has been very limited after drainage. The 

sulfur is slowly oxidizing to gypsum and liberating COS 

and S02 into the humid cave atmosphere. This mi"<ture 

ascends convectively to the higher sections of the cave 

where modern solution of the carbonate bedrock occurs. 

Sulfur and gypsum isotopic compositions are light: 

average o

34 S values for the main Lechuguilla sulfur 

deposits are -23.29, and -25.55 for selenite from the 

Chandelier Ballroom. That inclusions in the sulfur 

contain a gas phase and both saline and fresh water 

strongly suggests that the deposits formed in the fresh 
water-saline water mixing zone at temperatures < 50 °C. 

The morphology of Lechuguilla passageways further 

supports a model where upwardly circulating H2S-rich 

saline water in joints and fractures encounters fresh, 

oxygen-rich water, resulting in greater-than-normal 

vertical solution above these leak points (vertical mazes). 

Zones of intensely dissolved and occasionally 

mineralized reef limestone ("todo corrodo" zones) are 

often associated with the bottom of these vertical mazes 

and are linked to underlying fissures that penetrate 

downward to the current water table. The structural 

attitude of these deep fissures is commonly dipping_ 

toward the back-reef beds (not into the basin) and may 

reflect a preferred ascending flow component in the 

system. 

This information is presented at the 1992 McKelvey Forum in an expanded visual form as a sequence 

of text, charts, and photographic images running on an 

Apple Macintosh Ilfx computer. 

Cretaceous Resources, Events, and 

Rhythms-Continental Scientific Drilling 

Transect of the Western Interior Seaway 

Walter E. Dean and Michael A. Arthur 

Some of Earth's largest existing phosphorite 

deposits and hydrocarbon reserves were produced 

through combinations of processes of tectonism, volcanism, atmospheric and ocean chemistry, climate, eustasy, 

and sediment supply during Cretaceous time. In addition, 

major reserves of coal, kaolinite, bauxite, bentonite, and 

manganese lie in Cretaceous rocks. To predict and 

understand the availability and distribution of these 

resources requires models based on a comprehensive 

knowledge of the Cretaceous world. Because the 

Cretaceous Period was long ( approx. 136-66 Ma) and 

left extremely widespread continental and marine strata 

in outcrop, subcrop, and ocean basins, its rock record 

provides important opportunities for understanding 

global processes and their variation. 

The Cretaceous Western Interior seaway was a 

northwest arm of the Tethys Ocean that extended from 

the present Gulf of Mexico to the Arctic Ocean, during 

its maximum transgressions. Owing to its restricted 

geographic location and latitudinal extent, the seaway 

was in a strategic position to record changes in climate, 

sea level, and ocean circulation. Consequently, the strata 

deposited in the seaway monitor global climatic change 

during the Cretaceous; they present complex problems of 

paleoclimate, paleoceanography, and sediment flux; they 

exhibit well-developed solar-terrestrial orbital (Milankovitch) cycles; and they crop out in striking transgressiveregressive cyclic sequences. 

17 

As part of this comprehensive project, scientists of 

the USGS and several academic institutions proposed a 

multidisciplinary study of Lower and Upper Cretaceous 

marine carbonate and terrigenous clastic rocks in cores 

from four holes or groups of holes in a transect from 

western Kansas to eastern Utah across the former 

seaway. Drilling and related activities form part of the 

U.S. Continental Scientific Drilling Program, 

coordinated by the USGS, National Science Foundation, 

and Department of Energy. The study will focus on, from 

_oldest to youngest, the Upper Cretaceous Graneros 

Shale, Greenhorn Limestone, Carlile Shale, Niobrara 

Formation, and lower part of the Pierre Shale. The rocks 

range from pelagic carbonates that contain organiccarbon-rich marine source rocks at the east end of the 

transect to nearshore coal-bearing units at the west end. 

Drill core will provide unweathered samples and the 

continuous smooth sequences required for studies in 

inorganic, organic and stable-isotopic geochemistry, 

mineralogy, and biostratigraphy, as well as thermal 

maturation and the migration of hydrocarbons along a 

burial gradient in organic-carbon-rich strata. Existing 

cores will be used where available, but some new holes 

will need to be drilled; the first phase of new drilling 

began in June 1991. 

The USGS Core Research Center in Denver has 

several cores from western Kansas and northeastern 

Colorado that will meet the objectives of study of the east 

(most pelagic marine) end of the transect; no new drilling 

is planned for this end of the transect. The USGS 

obtained three cores from the west end of the transect 

(Phase 1 of new drilling), in the Kaiparowits basin near 

Escalante, Utah, in June 1991. Two of these cores 

contain coal-bearing sequences of the middle Turonian 

to lower Campanian Straight Cliffs Formation, of which 

the John Henry Member is nearly the same age as the 

Niobrara Formation in eastern Colorado. The third core 

contains all of the marine Tropic Shale that is the 

approximate age equivalent (Cenomanian and Turonian) 

of the Greenhorn Limestone and Graneros Shale in 

eastern Colorado and western Kansas. Geophysical logs 

have been obtained for all three holes. 

The USGS Core Research Center also holds two 

cores of rocks equivalent in age in part to the Niobrara 

Formation and Pierre Shale, from the Mesaverde Group 

of the northern San Juan Basin on the Southern Ute 

Indian Reservation. The underlying Mancos Shale, which 

is the approximate age equivalent to the Graneros Shale, 

Greenhorn Limestone, and Carlile Shale, is scheduled 

for coring in the northern San Juan Basin near Durango, 

Colo., during Phase 2 of drilling in 1992. Another core 

hole to be drilled during Phase 2, in the vicinity of 

Florence and Canon City, Colo., is to be located on the 

Brush Hollow anticline east of the Florence oil field, the 

oldest oil field in the United States. One aim of this drill 
-

cj 

~2 

- .: · ,),: l,j, ,j: 

:.: r\'_ :, ' : ": ,, ,,, 

Figure 1 (Dillon and others). Part of seismic reflection profile from the continental rise off North Carolina, showing examples of 

seismic blanking caused by gas-hydrate cementation and the bottom simulating reflection (BSR) that marks the location of the 

base of the gas-hydrate stable zone. Location of this profile is shown on inset map of figure 2. 

hole will be to obtain core of probable source rocks for 

the Florence field oil, which will be useful for 

determining trends of organic richness and thermal 

maturation. The sedimentary sequence to be recovered 

from this drill hole, deposited in relatively deep water on 

the west side of the Western Interior seaway, will include 

cycles of terrigenous-clastic and pelagic-marine 

sediments that will contrast with the pelagic carbonatedominated cycles of Kansas and the clastic-dominated 

cycles of western Colorado and Utah. 

Gas Hydrates in Deep Ocean Sediments 

Offshore Southeastern United StatesA Future Resource? 

William P. Dillon, Richard F. Mast, 

Kristen Fehlhaber, and Myung W. Lee 

Gas hydrates hold immense amounts of methane in 

deep-sea marine sediments worldwide (they also bind 

methane in onshore and shallow-water offshore deposits 

18 

in Arctic regions; see abstract by T. Collett, this volume). 

A gas hydrate is a crystalline solid, which is formed of a 

gas molecule surrounded by a cage of water molecules, 

stabilized by hydrogen bonding; such material occurs at 

the temperatures and pressures that exist in oceanic 

sediments. Although marine gas hydrates have the 

disadvantage of being located in relatively deep water 

(several hundred to a few thousand meters depthapproximately 1,000 to 12,000 feet), they occur at very 

shallow drilling depths and may be located in energypoor regions and at relatively short distances from 

significant markets. We are examining a region of the 

continental rise off North and South Carolina where the 

existence of gas hydrate has long been known. Our 

purpose is to identify unusual concentrations of gas 

hydrate and determine the geologic, physical, and 

chemical factors that control these accumulations. 

We are using their characteristic acoustic 

signatures in seismic reflection profiles to map 

concentrations of gas hydrates. Formation of hydrate in 

the pore space causes significant changes in acoustic 

characteristics because gas hydrate has a high 
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Figure 2 (Dillon and others). Contours of inferred thickness of pure gas hydrate within Class 1 deposits in the study 

area. The two plays were chosen where the amount of pure gas hydrate in Class 1 deposits exceeded 30 m.lnset map 

shows location of the larger scale map relative to the coasts of North and South Carolina, as well as track coverage. 

19 
compressional wave velocity compared to sediments. 

Velocity of the sediments is increased, and cementation 

of sedimentary strata by gas hydrate also has the effect of 

reducing the amplitude of reflections from stratal 

boundaries in seismic profiles (known as "blanking" of 

reflections). We have used seismic modeling to estimate 

the amount of hydrate that would cause various amounts 

of blanking, and have chosen three classes of blanking 

that we believe represent predictable ranges of gashydrate admixture into sedimentary pore· space (fig. 1 ). 

Distribution of these classes has been mapped in the 

study area and used to estimate volume of hydrate (see 

abstract by K. Fehlhaber and others, this volume). 

The thickness of the layer of hydrate is described by 

mapping the distance from the sea floor to a reflection 

horizon that is caused by the change from higher velocity 

above to lower velocity below. This reflection follows the 

phase boundary conditions for gas-hydrate stability, that 

is, hydrate is stable above, and unstable below that 

boundary because of increasing temperature with depth. 

Because this reflection approximately parallels the sea 

floor, it is known as the Bottom Simulating Reflection, or 

BSR (fig. 1). It had been believed that the zone of 

hydrate stability (sea floor to BSR) would increase 

consistently as water deepened, based on the 

assumptions of steady-state conditions, uniform thermal 

gradient, and a pressure value dependent only on water 

depth. Mapping shows that this is not the case, and that 

great variations occur in thickness of the gas hydratestable zone, unrelated to water depth. 

Considerable variation also exists in concentration 

of hydrate within the stable zone, which we have 

described by mapping calculated thickness of pure 

hydrate across the study area. The three blanking classes 

display varying patterns of hydrate distribution. In the 

class having lowest concentration (Class 3), in which 

hydrates occupy about 2 percent of the sediment volume, 

hydrate is distributed nearly uniformly across the study 

area. Conversely, in the highest-concentration class 

(Class 1), in which hydrate occupies about 8 percent (to 

as much as 14 percent) of the sediment volume, the 

hydrate is strongly concentrated at two locations (fig. 2). 

These two locations also represent high concentrations of 

hydrate when the amounts contributed by the three 

classes are totaled, and they will be treated as plays for 

this report. The high-concentration areas are defined as 

the area surrounded by the 30-m contour of Class 1 

hydrate (fig. 2). 

Play 1.-This area occurs at the head of a very large 

landslide and near a trend of diapirs that follow the 

seaward side of the Carolina Trough, one of the four 

principal continental-margin troughs of the Eastern U.S. 

continental margin. Possibly the concentration occurs 

because of increased sources of gas here. The gas might 

be thermogenic gas that rose from deeper sources along 

20 

fractures provided by the diapirism, or it might be 

biogenic gas that was released when the landslide 

occurred (probably in Pleistocene time). The landslide 

would have removed lithified sediment (lithified by 

hydrate cementation) and therefore would have lowered 

pressure on underlying hydrate, causing it to break down; 

the released gas might then have migrated updip within 

continental rise strata to nourish development of 

hydrates at shallower water depths. 

Play 2.-This area is located on the crest of the 

Blake Ridge, a sedimentary drift deposit formed by 

relatively rapid deposition since Oligocene time. Gas 

hydrate might be concentrated here because the rapid 

deposition would have caused the sea floor to become 

shallower, which would be accompanied by upward 

migration of the sediment isotherms. This would cause 

breakdown of hydrate at the BSR, releasing free gas that 

would be available to nourish hydrate formation in the 

overlying sediments. The ridge shape of the 

accumulation could have aided this, as the concave-down 

shape of the BSR would create a trap, with hydratecemented sediment acting as a seal to retain the gas 

within the ridge. Velocity analyses imply that free gas is 

presently trapped beneath the BSR in the Blake Ridge. 

Estimates of gas volumes for the two plays and for 

the total area were calculated using Monte Carlo 

simulator. Uncertainties in the volumes of hydrated 

sediment for each class and the porosity of the hydrated 

rock were accounted for. The resource estimates were 

made for only the lower one-half of the hydrated layer, 

which contains the higher concentration of hydrates. The 

results of the assessments of estimated gas volume are as 

follows: 

ESTIMATED VOLUMES OF GAS 

Trillions of cubic meters Trillions of cubic feet 

F95 Mean F5 F95 Mean F5 

Play 1 13 20 28 459 706 989 

Play 2 12 18 25 424 636 883 

Total 

area 88 117 144 3,108 4,132 5,085 

(Note that fractile values (F95, F5) are not additive. F95 represents a 

19 in 20 chance and F5 represents a 1 in 20 chance of the occurrence 

of at least the amount tabulated.) 

The estimated mean volume of gas contained in the 

study area is 117 trillion cubic meters at a temperature of 

15 °C and pressure of 1 bar. Estimates range between 88 

and 144 trillion cubic meters. The gas is concentrated in 

the two play areas. Play 1 contains 19.4 percent of the gas 

in the study area but covers only 11.5 percent of the area; 

Play 2 contains 17 percent of the gas but covers only 9.4 

percent of the area. Class 1-type deposits account for 

94.2 percent of the gas in Play 1 and 88.2 percent in Play 

2. These plays are in approximately 3,000 m (10,000 ft) 
of water, =240 km (150 mi) from shore. The volume of 

gas contained in a cubic meter of Class 1 hydrated rock is 

estimated in this study to be 22.3 m3 • Gas reservoirs 

onshore are estimated to hold about 17m3 of gas in place 

per cubic meter of rock. 

At present, we know that very large amounts of gas 

are locked in gas hydrates in deep-sea sediments. 

Estimates of exactly how much exists at specific locations 

and analyses of the geological/geochemical controls, as 

suggested here, are speculative, but ideas are developing. 

The technology for extracting gas from gas-hydrate 

deposits surely is undeveloped; however, the amount of 

energy represented by such deposits is immense, so that 

continued study is imperative. 

Undiscovered Oil and Gas Resources of 

Federal Lands and Waters 

G.L. Dolton, R.F. Mast, and A.A. Crovelli 

In 1987, the U.S. Geological Survey (USGS), in 

conjunction with the Minerals Management Service 

(MMS), completed an assessment of the undiscovered 

OIL 

TOTAL 49.4 880 

conventional resources of crude oil and natural gas of the 

United States. The USGS was responsible for assessment 

of the onshore United States and adjoining State waters, 

and the MMS for the Outer Continental Shelf (OCS). 

Resources were: (1) those considered recoverable under 

current technology, and (2) those that could be 

developed and produced economically, once found, using 

an extrapolation of costs and prices prevailing at the time 

of assessment. Resources beneath Federal lands and 

waters were estimated as part of this assessment. 

More than half of the Nation's estimated 

undiscovered recoverable conventional oil and gas 

resources are beneath Federal lands and waters. 

Approximately 87 percent of these estimated Federal 

recoverable resources are located in the OCS and 

Alaska, which areas also are estimated to have potential 

for very large hydrocarbon accumulations as opposed to 

the smaller estimated accumulation sizes in the onshore 

lower 48 States. These areas of large potential can have 

major impact on domestic supply, but they are also areas 

where long lead-times are required for development and 

where the economically recoverable portion of resources 

is significantly lower than the technically recoverable 

portion due to the high costs associated with operations. 

GAS 

TOTAL 399.1 TCFG 

EXPLANATION 

Federal Onshore 

I Non-Federal ...___ __ ...., 

Figure 1 (Dolton and others). Distribution of undiscovered conventionally recoverable crude oil and natural gas resources in 

Alaska and the lower 48 States. 

21 
ESTIMATED UNDISCOVERED RESOURCES 

[BBO, billion barrels of oil; TCFG, trillion cubic feet of gas] 

Recoverable Economically recoverable 

F95 Mean FS F95 Mean F5 

Onshore Federal 

Oil (BBO) 4.0 12.1 26.4 1.8 8.3 21.6 

Gas (TCFG) 25.4 65.8 132.6 14.8 26.2 42.0 

Offshore Federal 

Oil (BBO) 9.2 16.1 25.6 4.0 8.2 14.3 

Gas (TCFG) 97.8 145.1 204.8 44.3 74.0 113.8 

Total U.S. Resources 

Oil (BBO) 33.2 49.4 69.9 20.7 34.8 53.8 

Gas (TCFG) 306.8 399.1 507.2 208.2 262.7 325.5 

The geographic distribution of undiscovered 

conventionally recoverable crude oil and natural gas 

resources in Alaska and the lower 48 States is shown in 

figure 1, and the importance of Federally owned 

resources is readily apparent. 

This assessment addresses only those undiscovered 

resources in oil and gas reservoirs that are amenable to 

production by conventional well-bore production 

techniques in use at the time of the assessment. The 

estimates of resources do not include intractable heavy 

oil deposits or tar deposits, oil shales, gas from fractured 

shale reservoirs or low-permeability "tight" gas 

s~ndstone reservoirs with in-place reservoir permeabilihes to gas less than 0.1 mD (millidarcy), coalbed 

methane, gas in geopressured shales and brines, or gas 

hydrates (clathrates). These kinds of occurrences, which 

are treated as "unconventional" resources, are 

recognized as potentially important future sources of 

hydrocarbons, and some oil and gas is currently produced 

from them. 

Two recent publications expand on the derivation 

~f !hese estimates: a USGS/MMS publication, 

Estimates of undiscovered conventional oil and gas 

!esources in the United States-A part of the Nation's 

energy endowment," by R.F. Mast and others, 1989, and 

USGS Open-File Report 90-705, "Estimates of 

undiscovered conventional resources of oil and gas for 

Federal lands, and for Indian and Native lands of the 

continental United States," by G.L. Dolton and others 

1990. ' 

Field Growth in the Gulf of MexicoA Progress Report 

Lawrence J. Drew and Gary L. Lore 

The idea that oil and gas fields grow in size 

throughout their productive lives dates from at least the 

22 

time of World War II, as reported in a 1960 study by J.R. 

Arrington. However, field growth is not a concept that 

has gained universal acceptance as a long-term stable 

process. Before we can say that we understand the 

phenomenon of field growth in the United States or 

elsewhere in the world, certain problems need to be 

solved, whose solutions require that tedious tasks be 

completed in data collection and data file construction at 

the field level. We need to determine the relationships 

among the mortality of fields, their size, and their 

economic setting and to resolve several philosophical 

issues that bear on the assumptions needed to structure 

a forecast that can predict how fields will grow in the 

future. 

In this study we report progress made in the 

analysis of the growth of oil and gas fields discovered 

between 1947 and 1987 on the Federal portion of the 

Gulf of Mexico Outer Continental Shelf (OCS). The field 

level data, taken from the Field and Reservoir Reserves 

Estimates file maintained by the New Orleans office of 

the U. S. Minerals Management Service (MMS), are 

available only from 1975 onward: Thus, the growth of all 

fields across all years cannot be examined. For example, 

data do not exist to compute a growth rate for 5-year-old 

fields in 1960 or 1970. Data can only be extracted from 

the time window 1975-onward to estimate field growth 

and mortality as a function of field size and type (salt 

dome versus non-salt dome fields). 

In the Gulf of Mexico OCS the annual growth rates 

for all oil and gas fields range from about 10 percent per 

year during the first decade of productive life to around 

5 percent during the second decade and about 3 percent 

during the third decade (fig. 1A ). The fields that have 

been producing more than 30 years continued to grow in 

the fourth decade of their productive life at rates of about 

2 percent per year (fig. lA). The high variability in the 

growth rate profile covering the 38th through the 41st 

year of life of the fields in the Gulf of Mexico OCS is 

caused by individual changes in the estimates of the 

ultimate productivity in the very few fields that reach this 

age (1 to 3 fields) (fig. 1A ). 

The annual growth rate for small fields is typified 

by the scatterplot shown in figure 1B for fields in the 3.04 

to 6.07 million barrels of oil equivalent (BOE) size 

range. This panel shows that the variability from year to 

year is high, and no fields of this size have produced for 

more than 19 years. Either they migrated (grew) into a 

larger field size class or they were abandoned before the 

20th year of their productive life. 

The mortality of fields in the Gulf of Mexico OCS 

is shown in table 1: 69 of the 750 total fields discovered 

between 1947 and 1987 have been exhausted and the 

leases returned to the .Federal Government. The size of 

the most frequently abandoned field is in the 3.04 to 6.07 

million BOE size class with 15 fields having been 

abandoned by the end of 1988. 
ALL FIELDS M BOE 3.04-6.07 M BOE 

0.3 I I I I 0.3 I I I I 

0.2 -* * - 0.2- -

:::c :::c * 

~ 0.1 * ** ~ * - ** * - 0 0.1 - * * * -

* a: **** * ** * * a: * * * * * (.!) *** * * * 

** *****"'" .... 

(.!) * * 

0.0 ** ** * 0.0 

* * * * 

I I I I -0.1 I I I I 

-0.1 

0 10 20 30 40 50 0 10 20 30 40 50 

A YEAR B YEAR 

SALT DOMES M BOE NON-SALT DOMES M BOE 

0.3 I I I I 0.3 I I I I 

* * 

0.2- - 0.2- -

:::c :::c 

~ 0.1- - ~ 0.1 1- * * * -

a: ** * * * * a: ** ** (.!) * * * * *** * ** * * ** * (.!) 

* ** .... ********** * * 

*** * * .... * * * ** * * * **** 

0.0 * 0.0 * .,.. * * * * * * * 

-0.1 I I I I -0.1 I I I * I 

0 10 20 30 40 50 0 10 20 30 40 50 

c YEAR D YEAR 

Figure 1 (Drew and Lore). Growth profiles for four classes of oil and gas fields in the Gulf of Mexico OCS. BOE, barrels of 

oil equivalent. Growth is a proportion; for example, 0.1 equates to 10 percent growth rate per year. A, all fields; 8, small fields; 

C, salt domes; D, non-salt domes. 

Another aspect of the problem of understanding 

the dimensions of field growth is determining whether 

fields with different geologic and engineering 

characteristics have different rates of growth and 

mortality. Salt domes with their numerous and disparate 

reservoirs are widely believed to have higher overall 

growth rates and longer productive lives (lower 

mortality). Our total data set of 750 fields was separated 

into subsets, and the growth rates for salt domes versus 

non-salt domes were computed. (Compare fig. lC and 

W.) The rate of growth in the estimated ultimate 

productivity of the non-salt dome fields is higher during 

the first 10 years of productive life than for the salt dome 

fields. Subsequently the salt dome fields have a higher 

and more variable rate of growth than the non-salt dome 

fields. 

Analyses by a USGS-MMS team are in progress to 

isolate the structural elements in field growth data, so 

that a statistical model can be constructed to predict the 

ultimate productivity within field size classes. These 

predictions will be used to estimate the volume of crude 

oil and natural gas forthcoming from the growth of 

previously discovered fields and to adjust field size data 

used in discovery process models to forecast future rates 

of discovery of fields and their associated volumes by size 

class. 

23 

Table 1 (Drew and Lore). Mortality table for oil and gas fields in the 

Gulf of Mexico OCS 

[Leaders(-), not applicable] 

Size Size range No. fields Avg. Min Max Previous 

class 108BOE in range life yr yr class 

3 0.01-0.02 1 9 9 1-10 

4 0.02-0.05 1 3 3 1-8 

5 0.05-0.10 2 7 3 10 2-10 

6 0.10-0.19 1 9 9 1-9 

7 0.19-0.38 7 8 3 16 1-7; 2-8; 

2-9; 1-10; 1-13 

8 0.38-0.76 7 9 4 16 2-8; 3-9; 1-10; 

1-12 

9 0.76-1.52 13 9 5 16 3-9; 3-10; 4-11; 

3-12 

10 1.52-3.04 12 11 4 16 4-10; 6-11; 2-12 

11 3.04-6.07 15 13 7 21 4-11; 8--12; 3-13 

12 6.07-12.14 8 14 6 30 6-12; 1-13; 1-14 

13 12.14-24.3 0 

14 24.3-48.6 1 20 20 1-14 

15 48.6-97.2 1 13 13 1-15 

69 
Fluvial Architecture and Reservoir 

Heterogeneity-Triassic and Tertiary 

Examples from the Colorado Plateau 

Russell F. Dubiel, Steven C. Good, and 

Christopher J. Schenk 

Reservoir heterogeneity is an important aspect of 

petroleum geology because internal permeability 

barriers at several scales may impede the recovery of 

hydrocarbons from sandstone reservoirs. Modeling of 

fluvial sandstone reservoirs can be improved over vertical 

profile analysis by incorporating data on threedimensional sandbody architecture and the geometry and 

extent of bounding surfaces, which are commonly 

delineated by impermeable facies. Fluvial sandstone 

reservoirs present acute challenges to reservoir modeling 

because they are formed by dynamic alluvial systems that 

produce numerous lateral facies changes and because 

preservation is determined by a complicated interplay 

between sediment accumulation rates and the rate of 

basin subsidence. Fluvial reservoirs are rarely tabular, 

they have complex internal geometry, and they vary 

widely in size within individual fluvial systems. 

We report preliminary data from outcrop examples 

of two low- to moderate-sinuosity fluvial sequences on 

the Colorado Plateau that contain sandbodies with 

complex three-dimensional internal geometry. Examples 

are from ribbon and sheet sandbodies of the Upper 

Triassic Chinle Formation in southeastern Utah and 

ribbon sandbodies of the lower to middle Eocene 

Wasatch Formation in western Colorado. In the study of 

each sequence, photomosaics of the outcrops were 

constructed in order to map and measure dimensions of 

individual depositional elements. We emphasized 

recognition of intermediate-scale third- and fourth-order 

bounding surfaces because they form the large-scale 

permeability barriers that significantly affect 

hydrocarbon migration in fluvial reservoirs. Smaller scale 

heterogeneities that delineate bedforms and sedimentary 

structures were not examined in detail, although we 

recognize that these small-scale features, along with 

inhomogeneities produced by diagenesis and bioturbation, are crucial for studies of individual fields. 

The Chinle Formation along White Canyon in San 

Juan County, southeastern Utah, contains three units 

deposited primarily by fluvial processes: the Shinarump, 

Moss Back, and Petrified Forest Members. The Shinarump and Petrified Forest fluvial systems deposited 

small ribbon sandbodies (5-15 m thick and 30-100 m 

wide), whereas the Moss Back fluvial system produced 

large sheet sandbodies (20-30 m thick, and 300-1,000 m 

or more wide). Despite these large-scale differences in 

sandbody dimensions, each of the three fluvial systems is 

24 

composed internally of large-scale lateral accretion 

stratification (LAS) elements produced by migration of 

point bars in low- to moderate-sinuosity streams. Among 

the Chinle fluvial systems, the LAS elements vary in 

thickness and width corresponding to the overall size of 

the sandbodies. Shinarump and Petrified Forest LAS 

elements are from 2 to 3 m thick and 5 to 10m wide, 

whereas Moss Back LAS elements are from 10 to 20 m 

thick and about 100 m wide. Within each sandbody, point 

bar components are complexly stacked to produce a 

three-dimensional point bar mosaic. In the Shinarump 

and Petrified Forest Members, sandbodies can be traced 

as far as 1 km, and in the Moss Back Member, they can 

be traced as far as 10 km; however, in each sandbody, 

LAS elements are generally no longer than 2 to 3 times 

their width. 

The Shire Member of the Wasatch Formation in 

the Piceance basin of western Colorado is well exposed in 

outcrops north of Interstate 70 from Rifle west to 

DeBeque. Fluvial systems deposited ribbon sandbodies 

5-15 m thick and 30-100 m wide that are encased by 

floodplain sandstones and mudstones. The Wasatch 

ribbon sandbodies mainly consist of LAS elements. The 

LAS elements are 3-5 m thick and 15-30 m wide and, 

like the Chinle examples, are vertically and laterally 

amalgamated to form three-dimensional point bar 

mosaics. Sandbodies can be traced as far as 0.5 km, but 

LAS elements are no longer than 2 to 3 times their width. 

Fluvial sandstones in the Wasatch Formation 

similar to those studied here produce gas farther north of 

this study area at White River dome in the Piceance 

basin, and although the Chinle sandstones described 

herein are not known to produce hydrocarbons, they 

provide comparative data and contribute to the 

evaluation of the variability of sandbody architecture in 

sinuous fluvial systems dominated by point bar 

deposition. These examples provide an initial data base 

on the different scales of point bar deposits, the threedimensional complexity of point bar sandbodies, and 

their potential effect on fluvial reservoir heterogeneity. 

Origin of the Challenger Knoll Oil, 

Gulf of Mexico 

N. Terence Edgar and Jerry L. Clayton 

DSDP Site 2, located in the Sigsbee abyssal plain, 

central Gulf of Mexico, was drilled into Challenger Knoll, 

a topographic high (3,572 m water depth) that is 

underlain by cap rock and a salt diapir (fig. 1 ). Oil 

recovered from the cap rock (cores 5 and 6) was 

described as being a young immature oil of low gravity 
Figure 1 (Edgar and Clayton). Map of the Gulf of Mexico showing the locality of oil samples discussed. Bathymetric contours 

in meters. 

and high sulfur content and (from analysis of it by J.B. 

Davis and E.E. Bray published in 1969) is similar to Gulf 

Coast Tertiary oils recovered from cap rock elsewhere. 

Since these analyses were conducted, analyses of oils 

from deep-water sites on the continental shelf edge and 

slope (Flex trend), from the Campeche shelf of Mexico, 

from DSDP Site 535 in the eastern Gulf of Mexico, and 

from the Lower Cretaceous Sunniland Limestone of 

south Florida have become available. In a 1986 study, 

J .A. Nunn and Roger Sassen suggested the Flex trend 

oils to be derived from Cretaceous and lower Tertiary 

sedimentary rocks. In 1990, K.F.M. Thompson and 

others concluded that deep-water Gulf Coast oils 

(Thompson's type 1b) are similar enough to Mexico, 

Challenger Knoll, and DSDP Site 535 oils to represent a 

single broad superfamily and that no compelling reason 

exists to reject the hypothesis that all these oils are 

derived from the same or similar source facies. 

25 

To further elucidate the origin of the Challenger 

Knoll oil, we determined the polycyclic biomarker 

composition of the Challenger Knoll oil and three oils 

produced from Mexico (Ixtoc, Abkatun-A, and Akal-J 

wells; fig. 1) using coupled gas chromatography-mass 

spectrometry. We determined the sterane (m/z 217) and 

terpane (m/z 191) distributions on whole-oil samples. We 

report the following results (bold type), with comments 

on each: 

1. All three Mexico oils are characterized by low 

pristane:phytane ratios; pr:ph averages 0.75, which 

compares closely with the value of 0.74 reported in a 

1969 study by Bruce Koons and P.H. Monaghan for the 

Challenger Knoll oil. The pr:ph is a useful oil-oil 

correlation parameter, and to a lesser degree, an 

indicator of depositional environment. This ratio differs 

from those of the Tertiary Gulf Coast oils, which are 

>1.0. 
2. Two of the Mexico oils (Abkatun and Akal-J) 

have a slight predominance of long-chain n-alkanes 

containing even numbers of carbon atoms. Oils from the 

Gulf Coast Flex trend typically have no predominance or 

a slight odd-carbon predominance. This subtle but 

important level of predominance indicates modest to 

high levels of thermal maturity; even- or odd-carbon 

predominances diminish irreversibly with increasing 

thermal maturation but cannot switch from one to the 

other. Even-carbon preferences are common in oils 

generated from carbonate and carbonate-evaporite 

source rocks deposited under strongly reducing 

conditions. These even-, odd-carbon values suggest that 

the Mexico and Gulf Coast oils came from different types 

of source rocks. 

3. Oleanane is absent in the Challenger Knoll 

sample. Oleanane, a pentacyclic compound, is common 

in Tertiary Gulf Coast oils but not reported in samples 

older than Late Cretaceous. Its absence does not restrict 

the source rock to Late Cretaceous or younger age; its 

presence would have. 

4. Terpane distributions in the Challenger Knoll 

oil are fairly typical of thermally mature oils, but the C35 

hopanes are slightly elevated with respect to C34 

hopanes. An elevated ~s hopane value is common in 

oils generated from carbonate-evaporite source rocks, 

but the differential commonly is more pronounced than 

in these samples. 

5. Sterane distributions (m/z 217) show 

consistent differences between Challenger Knoll oil and 

Mexico oils in the relative amounts or 24-

ethylcholestanes compared to the other steranes, and in 

the ratio of 20S:20R diastereomers of 24-ethylcholestane 

(aaa configuration). The Mexico oils contain more 

diasteranes. These differences in sterane distributions 

are unexplained but may be the result of low thermal 

maturity of the Challenger Knoll oil. 

6. Whole-oil stable carbon isotope ratios for the 

Challenger Knoll and Mexico oils fall within the range of 

values of Group lB (Flex trend) oils, but Challenger 

Knoll oil is slightly heavier than the Mexico oils. The 

differences between saturates and aromatics (1.12%o and 

0.67%o, respectively) are greatest between the 

Challenger Knoll and the Mexico oils. The isotopic 

differences among the Challenger, Mexico, and Group 

1B samples are not sufficiently great to discount a 

common source, because the range of values for oils of 

common origin in general is greater than observed here. 

Individually, these results are not definitive, but 

combined they lead us to the following conclusions: 

1. Our data are consistent with Thompson and 

others' 1990 hypothesis that the oils from the Flex trend, 

the Campeche shelf, and west Florida may be derived 

from the same or similar source facies. 

26 

2. The Challenger Knoll oil appears to be derived 

from a Mesozoic source rock, based on the absence of 

oleanane, on evidence for a carbonate-evaporite source, 

and on its high organic sulfur content. High sulfur 

content indicates a carbonate-evaporite source rock, 

whereas low sulfur content (generally < 0.5 percent but 

as much as 1.5 percent) is characteristic of Tertiary oils 

derived from siliciclastic sediments of the northern Gulf 

Coast. During the Mesozoic, sedimentation in the Gulf of 

Mexico was primarily carbonates and evaporites, 

whereas during the Cenozoic, siliciclastic sedimentation 

prevailed. 

3. Although the Challenger Knoll oil is similar to 

the Mexico oils, certain notable differences, such as the 

sulfur content, suggest that the source rock of the 

Challenger Knoll formed in a subbasin characterized by 

high evaporation and restricted ocean circulation. 

4. Properties of oil derived from widely 

distributed Mesozoic source rocks from Challenger 

Knoll(?), DSDP Site 535, Mexican wells, and from the 

Gulf Coast continental slope indicate that an extensive 

Mesozoic source rock may underlie a large part of the 

Gulf of Mexico. If this is correct, the amount of 

undiscovered petroleum resources in the Gulf of Mexico 

may be considerably underestimated. 

Estimation of Gas Hydrate 

Concentrations Using Seismic Methods 

Kristen Fehlhaber, William P. Dillon, and 

Myung W. Lee 

We are applying a new method of evaluating the 

volume of gas hydrates in sea-floor sediments in the 

Blake Ridge area (continental slope, U.S. Atlantic 

margin). We estimate volumes using two-channel seismic 

data and seismic models that analyze amplitude 

variations of the seismic profiles to predict the amount of 

hydrates in the sediments. Initial volume estimates 

indicate that more than 0.7 trillion cubic meters of gas 

hydrates are present beneath the 29,000 km2 study area. 

Gas hydrates exist in the pore space of the upper 

several hundred meters of ocean-floor sediment. Areas 

containing gas hydrates are identified by the presence of 

a BSR (bottom simulating reflection) and by 

"blanking" of the seismic reflections above the BSR. 

(See also Dillon and others, this volume.) The BSR 

parallels the sea-floor topography and represents the 

pressure/temperature-controlled base of hydrate 

cementation at the bottom of the gas-hydrate stability 

zone. The reflection occurs due to the impedance 

contrast between hydrated and nonhydrated sediments. 

"Blanking" is the result of the cementing effect of the 
hydrate, causing a reduction in the impedance contrast in 

these upper sediments. We have created seismic models 

to divide the profiling data into three classes of blanking, 

each class corresponding to a different level of bulk 

hydrate in the sediments. 

Seismic reflection data were collected specifically 

to image the shallow subbottom region, where hydrates 

exist. The seismic source was a single 160 in.3 airgun, and 

the data were recorded digitally from a two-channel 

streamer. We used the seismic processing system 

SIOSEIS to apply a gain function, and to stack, deconvolve, and filter the two-channel data. The processed, 

true-amplitude profiles were then interpreted for the 

presence of hydrate, as indicated by the presence of the 

BSR and (or) blanking. Next, the various blanking 

classes were marked on the seismic records. The visual 

interpretation and assignment of the blanking classes 

were checked using PSEUDO, a subprocess of SIOSEIS, 

which passes a window along the seismic profile in the 

depth range of 250-500 milliseconds below the sea floor, 

and estimates the median reflection amplitude in the 

window. The median reflection amplitude correlates 

directly to the three classes of blanking. The interpreted 

sections were then digitized and fed into a surfacemodeling program. The upper and lower surfaces of the 

hydrate classes were gridded to produce contour maps of 

total hydrate and to calculate the volume of sediments 

and hydrate equivalent belonging to each class. 

Preliminary results indicate that the 29,000 km2 

study area contains 7.86 x 1012 m3 of bulk methane 

hydrate within 1.67 x 1013 m3 of sediment. Because 

hydrate expands to 160 times its volume when it breaks 

down to form gas, the hydrate is equivalent to 1.26 x 1014 

m3 ( 4,440 TCF) of methane gas. This represents 

approximately 0.7 percent of K.A. Kvenvolden's 1988 

published estimate of methane hydrates contained in all 

ocean sediments. 

Gulf Coast Lignite QualityThe Needs of the 90's 

Robert B. Finkelman, W.R. Kaiser, 

Susan J. Tewalt, and James A. Luppens 

During the 1980's Gulf Coast lignite production 

was among the faster growing segments of the United 

States coal industry; seven surface mines were opened in 

Texas and Louisiana and a test pit was opened in 

Arkansas. From 1980 to 1989 production of Gulf Coast 

lignites increased by almost 80 percent compared to an 

27 

increase in production of less than 20 percent for all U.S. 

coals. Although this rapid growth has slowed in recent 

years, continued growth is projected for this region. 

However, stiff competition from western coal and natural 

gas and increased environmental constraints on coal 

utilization necessitate better understanding of the quality 

of Gulf Coast lignite. Increased knowledge of lignite 

quality should lead to more efficient and environmentally 

sound use of Gulf Coast lignite. Despite more than 100 

years of lignite mining in the Gulf Coast and the 

economic impact of the lignite (more than 58,500,000 

short tons produced in 1990), relatively little information 

on lignite quality is publicly available. The U.S. 

Geological Survey's National Coal Resources Data 

System contains the largest publicly available coal-quality 

data base in the U.S. It includes information on the 

physical and chemical properties of slightly more than 

250 Gulf Coast lignite samples in a data base of more 

than 13,000 entries. Information in the literature on 

lignite petrography and mineralogy is almost nonexistent. 

The Gulf Coast lignite-quality attributes that we 

expect to attract the most attention during the 1990's are 

as follows: 

Coal Quality Attribute 

Mineralogy 

Petrography 

Sulfur content 

Trace elements 

Ash chemistry 

Equilibrium 

moisture 

Significance 

Contributor to corrosion, erosion, and 

fouling. 

Indicator of conversion efficiency and 

spontaneous heating potential. 

Environmental impact, boiler design. 

Environmental impact, byproduct 

recovery. 

Contributor to fouling and slagging; 

environmental impact. 

Used for rank determination - impact 

taxes. 

As new technologies, for example, fluidized bed 

combustors, coal/water fuel mixtures, and briquetting, 

are implemented, and as new problems appear, other 

coal-quality attributes will attract attention. The ultimate 

goal of coal-quality research in the 1990's will be to 

develop predictive models-models to predict attributes 

that will affect lignite utilization and quality variation 

throughout a mine or prospect site. 

The Gulf Coast lignite-quality needs of the 90's 

represent a broad array of problems that impact on 

virtually every aspect of coal utilization. These needs can 

best be addressed through joint efforts of industry, State 

and Federal governments, and academia-perhaps by a 

jointly funded regional consortium dedicated to solving 

the Gulf Coast lignite needs of the 90's. 
Synsedimentary Authigenic Illite and 

Implications for Geothermometry in 

Sedimentary Basins 

Neil S. Fishman and Christine E. Turner 

Authigenic illitic mixed-layer illite/smectite (I/S) 

occurs in three distinct altered tuff beds in Pleistocene 

Lake Tecopa, an ancient alkaline, saline lake complex in 

eastern California. Within each tuff a concentric zonation 

of diagenetic mineral zones forms a crude bull's-eye 

N 

r 0 2 3 MILES 

5 KILOMETERS 

EXPLANATION 

r7/1 Distribution of smectitic illite/smectite 

ILL! (70-1 00% expandable layers) in tuffs 

~ Distribution of illitic illite/smectite 

(0-30% expandable layers in tuffs 

e Outcrop locality and number 

Figure 1 (Fishman and Turner). Generalized map showing 

diagenetic mineral zones in tuffs of Lake Tecopa (modified 

from a 1968 study by R.A. Sheppard and A.J. Gude, 3rd) and 

the crude bull's-eye pattern of zones, from fresh glass along 

the margins of the lake, to zeolites (chiefly phillipsite and 

clinoptilolite) farther basinward, to potassium feldspar 

(±searlesite) in the center of the lake basin. Authigenic illitic 

mixed-layer illite/smectite (D-30 percent expandable layers) 

occurs in all three tuffs, principally in the potassium feldspar 

(K-spar) and zeolite diagenetic mineral zones. Smectitic 

illite/smectite (7D-100 percent expandable layers) occurs in 

the fresh glass zone, as the only authigenic aluminosilicate 

present, and also in some tuffs in the zeolite zone; but it is 

rare in tuffs in the potassium feldspar diagenetic mineral 

zone. 

28 

Figure 2 (Fishman and Turner). SEM photograph of illitic 

clays from a sample from site 59. (See fig. 1 for location.) lllitic 

clays are fibrous, contain iron, and coat authigenic phillipsite 

(ph). Bar is 10 JLm in length. 

pattern, from fresh glass along the margins of Lake 

Tecopa, to zeolites (chiefly phillipsite and clinoptilolite) 

farther basin ward, to potassium feldspar ( ± searlesite) in 

the center of the lake (fig. 1). The illitic clays (0-30 

percent expandable layers) occur in tuffs in both the 

potassium feldspar and zeolite zones (fig. 1). Smectitic 

I!S (70-100 percent expandable layers) occurs in the 

fresh glass zone, where it is the only authigenic aluminosilicate present, and also in some zeolitized tuffs (fig. 1); 

but it is rare in tuffs that contain potassium feldspar. 

Tuffs containing illitic clays occur in close proximity to 

those containing smectitic clays (fig. 1). 

SEM observations indicate that the illitic clays are 

fibrous, postdate the authigenic zeolites (fig. 2), and 

appear to have precipitated directly from solution. Compositionally, the illitic clays are iron bearing, as indicated 

by SEM-EDS (scanning electron microscope-energy 

dispersive spectrometry) analyses, weak 5 A peak 

intensities, and the position of d(060) reflections 

(1.5090-1.5095 A). In contrast, the smectitic mixed-layer 

clays typically display a honeycomb texture and contain 

10-20 percent illite layers, as indicated by the positions of 

the d(002) and d(003) peaks (8.67 A and 5.58 A 

respectively) determined from X-ray diffraction analyses 

on oriented, glycolated samples. The nonintegral spacing 

of 001 reflections corroborates the mixed-layer nature of 

these clays. Smectitic clays are likely dioctahedral 

Al-smectite as indicated by the d(060) reflection at 1.497 

A. 

A similar burial history has been experienced by 

each of the tuffs throughout the lake basin, and none has 
ever been buried to depths in excess of about 50-75 m. 

The similar burial history experienced by illitic and 

smectitic tuffs alike, and the close proximity of tuffs 

containing different clays suggest that elevated 

temperatures due to burial did not play a role in the 

formation of illitic clays. Instead, the distribution of the 

illitic clays in the tuffs and their association with authigenic zeolites and feldspar argue strongly for pore-water 

chemistry as the main control on illite formation. 

Because pore waters at near-surface temperatures can 

control formation of authigenic illite, investigations 

should be cautious about using illitic phases as a geothermometer when evaluating the thermal history of a 

sedimentary basin. 

High-Resolution Paleoclimate 

Reconstruction From Alaskan 

Ice-Core Records 

J.J. Fitzpatrick, T.K. Hinkley, G.P. Landis, 

R.O. Rye, and G. Holdsworth 

Deep ice cores from the large continental ice sheets 

of Greenland and Antarctica provide long-term climate 

records. From Alaska, however, where the ice contains a 

record of a climate influenced by Northern Pacific Ocean 

weather patterns, little information is available. 

We selected as our study site the 4,420-m col 

between Mts. Churchill and Bona in the St. Elias Range 

of southeastern Alaska. The ice core we plan to recover 

will contain a high-resolution paleoclimate record dating 

back to as long as 1,200 years B.P. The site is a broad, 

relatively flat expanse of snow and ice, about 1.0 x 1.3 

km, sloping gently to the east. 

In late spring 1991 we conducted an initial, 

reconnaissance field season. This emphasized 

observation, sampling of snow strata from dug pits, and 

sampling of gases in the snow and firn using shallow and 

deep probes. 

The site is located in the dry facies zone and is part 

of the ultimate source of the Klutlan Glacier, well above 

the equilibrium line. No significant melting horizons 

were observed in snowpits. Net annual accumulation of 

snow is 1.9-2.0 m per year (approximately 70 em water 

equivalent), judging by the minimally compacted most 

recent year's strata. Snow densities of the topmost year 

range from a minimum, near the spring surface, of about 

0.18 g cm·3 to a maximum of about 0.43 g cm·3 at a depth 

of2 m. 

Preliminary analytical results show the following: 

The light stable isotopic composition of snow 

within 1 year's accumulation exhibits a large seasonal 

range (oD = -157 to -292), indicating at least two 

sources of moisture and a correspondingly large range in 

29 

temperature. Concentration of biologically produced 

oceanic methanesulfonic acid (MSA) in snow strata 

closely parallels the isotopic extremes, with a small time 

lag. MSA maxima appear with the most negative isotopic 

values (cold times). This may suggest that different 

latitudinal sources of moisture exist for different seasons, 

and that the more arctic re'gions produce more biogenic 

sulfur. Alternatively, these variations in stable isotopic 

composition, and biogenic sulfur, may be related to the 

tropospheric stratification proposed to dominate in these 

altitudes and latitudes. (See a 1991 study by Holdsworth 

and others.) 

Gases adsorbed from the atmosphere on 

accumulating snow crystals are present in different 

proportions than in the atmosphere. Upon recrystallization of snow grains, with aging and burial of the strata, 

excess adsorbed gases are released, and residual 

adsorbed gases approach atmospheric proportions, 

exchanging in an open system with the atmospheric gases 

that circulate through the permeable snowpack. At least 

a decade may be required in this locality for desorption 

and redistribution of gases from the snow and 

equilibration of firn gases with the atmosphere. Strata 

isolated by impermeable layers may retain the 

fractionated and anomalous proportions of adsorbed 

atmospheric gases. 

We anticipate that concentrations of rock-forming, 

sea-salt, and volcanic-exhalation metals in seasonal snow 

strata will give additional information about changing air 

mass sources. 

Tectonic and Climatic Changes 

Expressed as Sedimentary and 

Geochemical Cycles in Paleogene 

Lake Systems, Utah and 

Colorado-Implications for Petroleum 

Source and Reservoir Rocks 

Thomas D. Fouch and Janet K. Pitman 

Paleogene Lake Uinta strata .in the Uinta and 

Piceance basins, Utah and Colorado, record both longand short-term changes in climate and tectonic regime. 

Large, tectonically induced reconfigurations of the lake 

gave rise to relatively thick (several hundred meters), 

lithologically distinct stratigraphic sequences. Simultaneous changes in climate brought on by variations in 

solar radiation initiated very rapid rises and falls of the 

lake, as well as shifts in alkalinity and salinity of the water 

that resulted in the development of sedimentary and 

carbonate-geochemical cycles (parasequences) of up to 

tens of meters thick. Tectonically induced stratigraphic 

sequences represent environments that lasted several 
million years whereas climate-induced parasequences 

lasted several thousand years: together they brought on 

rapidly changing conditions. The resulting lake deposits, 

which reflect both tectonic and climatic cycles, now 

constitute the principal source and reservoir rocks for 

petroleum in the Uinta Basin. 

Middle Paleocene to late Eocene lake deposits are 

characterized by halite, sodium bicarbonate salts, and 

kerogen-rich shales containing organically derived 

carbonate minerals, indicating a highly organically 

productive, closed hydrologic system during much of the 

existence of the lake. Strata are cyclic: some cycles extend 

over several hundred meters of section, corresponding to 

a time span of several million years, while other cycles 

occur within millimeters and probably represent 

approximately 1 year. 

Throughout the lake system, a cyclic depositional 

sequence in a marginal-lacustrine setting from oldest to 

youngest consists of: (unit 1) mud-supported, laminated 

carbonate rock or oil shale with a flooding surface at the 

base shoaling to an ostracode-, pisolite-, and (or) oolitegrainstone; (unit 2) mudcracked mudstone and (or) 

stromatolitic carbonate; (unit 3) mudcracked overbank 

mudstone or sandstone; and (unit 4) coalesced channel 

sandstone that locally eroded down to the underlying 

carbonate (unit 1) and aggraded laterally to form a 

composite sandstone sheet. Each interv;Il within the 

sequence can vary greatly in thickness and areal extent 

depending upon its position within the depositional 

system. 

Major open-lacustrine units reflect expansions of 

the lake such as those associated with the carbonate 

marker, Flagstaff Member, and Mahogany oil-shale zone 

of the Green River Formation. They formed in response 

to episodes of tectonic reactivation of regional faults such 

as the subsurface Basin Boundary fault along the north 

flank of the Uinta Basin. Large reconfigurations of the 

Lake Uinta system are defined by unconformity-bounded 

sequence boundaries. Strata that bracket these 

boundaries represent major cycles and consist of thick, 

lithologically distinct tongues of open-lacustrine, 

marginal-lacustrine, and alluvial rock that extend over 

large regions of the depositional system. Flooding 

surfaces document major episodes of shore transgression 

and record deposition of open-lacustrine, mudsupported, laminated carbonate rocks that make up the 

condensed section for each sequence. 

Green River Formation strata contain numerous 

cycles of smaller dimensions than the large regional 

sequences just discussed. Recurrent and continuing 

climate change initiated very rapid expansions and 

contractions (and rises and falls) of the lake as well as 

shifts in alkalinity and salinity of its water. These changes 

resulted in small- to large-scale sedimentary and 

carbonate-geochemical parasequences within the larger 

30 

regional sequences. Solar radiation-induced sedimentary 

and geochemical cycles are similar in style to tectonic 

cycles, except that they commonly are recorded within a 

sedimentary thickness of 3-30 m and represent a few 

thousand to tens of thousands of years. In kerogenous 

open-lacustrine source rocks, carbon and oxygen isotope 

profiles for calcite and dolomite show generally 

synchronous geochemical cycles in which positive and 

negative excursions correspond to cyclic variations in 

organic carbon content and to changes in lithology. 

Small-scale carbon isotope cyclicity in carbonate matter 

documents salinity-induced changes in primary organic 

matter productivity and the amount of reduced carbon 

available for carbonate precipitation via methanogenesis. 

Large-scale carbon enrichment trends on carbonate 

curves record the effects of progressive acetate 

metabolism on the isotopic evolution of the inorganic 

carbon reservoir in a restricted, extended-residence-time 

system. Small-scale cyclic variations in oxygen in 

carbonates are related to climate-induced salinity 

changes that resulted from alterations in hydrologic 

balance during the lake's history. Major oxygen trends on 

the carbonate curves correspond to large-scale variations 

in lake level and salinity due to large alterations in 

inflow-evaporation balance coincident with major paleoclimate changes. 

The principal reservoirs for oil and gas are found in 

marginal-lacustrine channel sandstones. Channel 

sandstones in surface exposures on the basin's south 

flank can be separated into two types (I and II) with 

respect to geometry and width/depth (WID) ratios. The 

channel sequences (unit 4) occur within the parasequences described. Type I sandstones are characterized 

by a tabular geometry controlled by a planar lower 

bounding surface, an average channel depth of7.6 m, and 

an average WID ratio of 8.9. The planar channel bottom 

results from underlying resistant carbonate-rock units 

whose early lithification restricted downcutting and 

caused more extensive lateral aggradation compared to 

that of streams forming type II bodies. Type II 

sandstones are characterized by a lenticular geometry, 

with an average channel depth of 5.7 m, an average WID 

ratio of 3.6, and a concave-upward lower bounding 

surface. The absence of resistant carbonate rocks 

(because of erosion or nondeposition outside the limits 

of the lake) underlying streams that deposited type II 

bodies resulted in stream channels that, although similar 

in size, did not migrate laterally as much as those of type 

I. As a result, the size of individual channel sandstone 

bodies, and therefore reservoir units, is largely 

dependent upon induration of the substrate across which 

streams flowed. 
Late Cretaceous and Early Tertiary 

Evolution of the Uinta and Piceance 

Basins (Northeastern Utah and 

Northwestern Colorado) and Associated 

Development of Hydrocarbons 

K.J. Franczyk, T.D. Fouch, R.C. Johnson, 

C.M. Molenaar, and W.A. Cobban 

Paleogeographic reconstructions for Late Cretaceous through early Oligocene time in an area that 

includes the Uinta and Piceance basins and surrounding 

vicinity illustrate several major geologic events: the 

incursion of a Cretaceous sea, thin-skinned thrusting in 

the Sevier orogenic belt, eustasy, the breakup of a Late 

Cretaceous foreland and withdrawal of the sea, the 

formation of intermontane basins, and the appearance 

and disappearance of large lakes. Throughout most of 

the Late Cretaceous, the area was part of a foreland 

basin in which depositional patterns were controlled both 

by thrusting in the Sevier orogenic belt to the west and by 

eustasy. Organic detritus that accumulated in openmarine waters and in coastal plain swamps and marshes 

later produced the gas now found in low-permeability 

reservoirs in the Uinta and Piceance basins. In late 

Campanian through early Maastrichtian time, the sea 

withdrew from much of the paleogeographic map area, 

centers of greatest subsidence shifted, basement-involved 

uplifts developed, and small intermontane basins began 

to form in the western part of the map area. These basins 

formed on top of the thrust allochthon in the west-central 

and southwest parts of the map area and between the 

thrust front and the rising San Rafael structure east of 

the thrust front. 

By latest Maastrichtian time, the sea had 

withdrawn completely. Movement on the Uinta and 

Sawatch uplifts, in the north-central and southeastern 

parts of the map area, respectively, had begun; and 

sediment accumulated in the small intermontane basins 

in the western part of the map area. The more extensive 

intermontane basins that characterized much of this area 

during the Paleogene were developed by the middle 

Paleocene. Initially, in the last Maastrichtian through 

middle Paleocene, sediments were deposited primarily in 

alluvial fans and plains, shallow lakes, and lake-margin 

wetlands. The lakes expanded in late Paleocene and early 

Eocene time, and in the early Eocene they occupied large 

parts of both the Uinta and Piceance basins. Organic 

sediment was deposited locally in the older, smaller lakes 

as well as the younger, larger lakes. These deposits 

became the principal source rocks for the oil in areas of 

the Uinta Basin where they are thermally mature. 

Fluctuating lake levels produced interbedded lacustrine 

and fluvial reservoir rocks and source rocks. In the 

31 

middle Eocene, the lakes in the Uinta and Piceance 

basins expanded further, covering the Douglas Creek 

arch that had separated the lakes, and joined to form a 

single major lake, Lake Uinta. The Mahogany oil-shale 

bed formed during this time of maximum lake 

development, but it is too thermally immature to 

generate oil or gas. 

During the late middle Eocene, volcaniclastic 

sediments from the north began to fill the lake in the 

Piceance basin. From then through the late Eocene, Lake 

Uinta retreated westward and disappeared from the west 

end of the Uinta Basin in latest Eocene or earliest 

Oligocene time. The Uinta Basin was filled with clastics 

shed during the final tectonic event in the Uinta uplift; 

concurrently, volcanic material and reworked volcanic 

detritus accumulated in the western part of the map area. 

Bridging the Gap Between Third- and 

Fifth-Order Cycles in Carbonate 

Sequences-The Western Margin of the 

Great Bahama Bank 

Robert B. Halley and R. Jude Wilber 

Almost 100 km of high-resolution single-channel 

seismic data (200-300 ms two-way travel time) has been 

collected in the vicinity of published multichannel seismic 

records (1.0-1.5 s two-way travel time) from the western 

margin of the Great Bahama Bank. Comparisons of the 

overlapping portions of the two data sets, together with 

an understanding of the modern surface and shallowsubsurface sediments, provide insights into the 

interpretation of the upper portion of the multichannel 

lines. Both data sets are characterized by laterally stacked 

sigmoidal reflectors, attesting to western progradation of 

the shelf edge. The two uppermost sequence boundaries 

are clearly recognizable in the lower slope sediment 

wedge, but tracing these surfaces to their banktop 

equivalents is uncertain because correlations must pass 

through a reflection-free area, often interpreted as 

"reef?", associated with steep relief at the platform 

margin. 

Reefs do not occur on the platform margin today, 

yet shallow drilling has revealed reefal sediments beneath 

the platform edge. Westward flow of bank water, highly 

variable in salinity and temperature, generally precludes 

modern reef growth along this margin. Instead of reefs, 

the modern margin is characterized by sandy deposits in 

a band up to 4 km wide and a slope break between 55 and 

65 m water depth. Below the shelf break, the upper slope 

is a steep (1SO -30°) rocky incline characterized by 

sediment bypassing. At 140 to 180 m, the rocky slope 

gives way to a soft-sediment slope of bank-derived 
LINE 12 

, 250m >: 

25m j LIE = 5H .J 

HIGHSTAND 

SLOPE DEPOSITS .·, . .. , 

I-ILI 

5TH ORilER 

CYCLES 

FIGURE 1 

Figure 1 (Halley and Wilber). High-resolution seismic profile across the 

west edge of the Great Bahama Bank. 

carbonate mud and sand. This sediment wedge dips away 

from the base of the rocky slope at increasingly gentle 

angles into the Straits of Florida. 

Strong reflectors in lower slope sediments form the 

basinward portion of sigmoid oblique sequences. 

Sediments recovered from the youngest subsurface 

reflector yielded a 14C age of 10,000 yr. This reflector, 

when traced bankward, clearly underlies the base of the 

rocky upper slope before disappearing into the 

reflection-free area (fig. 1). Underlying reflectors mimic 

the morphology of the present sediment surface, 

suggesting that they are relict surfaces formed during 

hiatuses in sedimentation. Lower slope sediments 

presently exhibit evidence of rapid sedimentation at the 

surface and may be seen to onlap the base of the rocky 

upper slope. 

These observations have led to a conceptual model 

of platform aggradation and progradation during sealevel fluctuations, summarized in two stages: (1) When 

sea level falls below the general level of the platform, 

large carbonate-producing areas are subaerially exposed, 

32 

resulting in lithification and the development of strong 

reflectors. Sediment production on the bank is minimal 

except in the immediate vicinity of the shoreline, which 

may host fringing reefs. Basinward, the sea floor is 

sediment starved, allowing the formation of hardgrounds 

and winnowed coarse sediments that serve as reflectors. 

Allochthonous debris fields do not appear to be a major 

contributor to slope sediments in this area. As sea level 

rises and falls along the margins of the platform, 

accumulations of reef sediments build and maintain 

steep profiles on the slope. (2) During highstands, major 

aggradation and progradation take place when the banktop carbonate "factory" produces copious amounts of 

sediment, more than half of which is transported to the 

outer shelf and slope. On leeward margins, highstands 

are not characterized by reef development, but rather by 

shelf-margin carbonate sands and thick (up to 80 m) 

accumulations of bank-derived slope deposits. Steep 

portions of the upper slope become sediment-bypass 

areas subject to marine lithification and eventual 

development of strong reflecting horizons. 
The consequences of these complex sealevel/carbonate-sedimentation relations are that basinal 

and lower slope reflectors as well as banktop reflectors 

form when sea level is below the bank margin. At the 

platform margin, facies changes may be abrupt and the 

lateral distance between reflectors may be small, inviting 

correlation of horizons that appear continuous on multichannel seismic sections. Upper slope reflectors may 

form during highstands or not at all. Sequence 

boundaries may be inadvertently crossed through the 

reflection-free zone in areas where reflectors have not 

developed within the reef facies. Where sedimentation 

rates are high, fifth-order sequences approach the spatial 

scale of third-order sequences. Under these circumstances, additional control for making correlations is 

critical. Careful attention to complementary 

stratigraphic data is essential for detailed age assignments and interpretations of multichannel lines across 

leeward carbonate-bank margins. 

Hydrocarbon Source-Rock Evaluation of 

Desmoinesian (Middle Pennsylvanian) 

Coals from Southeastern Iowa, 

Missouri, Southeastern Kansas, and 

Northeastern Oklahoma 

Joseph R. Hatch 

Coals in the Desmoinesian (Middle Pennsylvanian) 

Cherokee Group and Marmaton Group in the Western 

Region of the Interior Coal Province, U.S.A., are 

potential source-rocks for methane and liquid 

hydrocarbons. To help evaluate this potential and better 

understand the organic geochemistry of these coals, 85 

samples were collected from core and surface-mines at 

21 locations in southeastern Iowa, Missouri, 

southeastern Kansas, and northeastern Oklahoma. 

Analyses performed include Rock-Eval pyrolysis, vitrinite reflectance (R0 ), CHCI3 extraction of coals, and gas 

chromatography to compare saturated hydrocarbon 

distributions from coals with those from Cherokee 

Group oils. The analyses are summarized from three 

geographic areas defined by increasing thermal maturity. 

Organic matter in coals from area 1 (southeastern Iowa 

and northern Missouri) is marginally mature with respect 

to petroleum generation (Rock-Eval T max= 430±4 °C, 

n =48; Ro s0.55%, n =9); in area 2 (southwestern 

Missouri, southeastern Kansas, and northeastern 

Oklahoma near the outcrop) organic matter is mature 

(Tmax =446±5 °C, n =25; 0.57 SR0 S0.80%, n =7); and 

in area 3 (cores from Osage County, northeastern 

Oklahoma) organic matter is near peak oil generation 

(Tmax =460±5 °C, n = 12; 0.80% SR0 S 1.0%, n =3). 

33 

For coals from area 1, mean genetic potential 

(Rock-Eval S1 + S2 mg HC/g sample) is 126±41 mg'g; 

from area 2, 139±46 mg'g; and from area 3, 115±35 

mg'g, which shows that coals from the three areas all 

have excellent potential to generate hydrocarbons. For 

coals from area 1, mean carbon-normalized volatile 

hydrocarbon content (S1/fOC, mg HC/g TOC) is 

4.4±3.1 mg'g; from area 2, 6.8±4.6; and from area 3, 

12±5 mg'g, which indicates that some hydrocarbon 

generation has taken place. 

For coals from area 1, mean content of CHC13 

extractable organic matter is 27 mg'g sample (geometric 

deviation [GD] = 1.7; n = 14); from area 2, 15 mg'g 

(GD = 1.6; n = 9); and from area 3, 9 mg'g (GD = 1.1; 

n = 5). This decrease is thought to be caused by a 

decrease in micropore interconnections with increased 

thermal maturity, which results in lower extraction 

efficiencies. In coal extracts from area 1, saturated hydrocarbon:aromatic hydrocarbon ratios are 0.31 ±0.12; from 

area 2, 0.33±0.08; and from area 3, 0.41±0.22. For coals 

from areas 1 and 2, saturated hydrocarbon distributions 

are dominated by pristane with low relative amounts of 

n-C25 through n-C31 ; in area 3, relative amounts of 

n-alkanes and isoprenoids are similar. In coals from area 

1, mean pristane:phytane ratio is 6.5 ±2.3; from area 2, 

5.7±1.9; and from area 3, 3.7±1.2. This decrease in 

pristane:phytane with increased thermal maturity follows 

trends observed in coals by previous researchers. 

Extracts from Desmoinesian coals immediately overlain 

by marine black shales are intermediate in composition 

between those of the black shales and other coals. This 

may result from the addition or preservation of bacterial 

biomass in the upper layers of the peat during early 

diagenesis or from migration of hydrocarbons from the 

overlying shale down into the coal. 

All coal extract compositions are dissimilar to oils 

produced from the Cherokee Group in southeastern 

Kansas and northeastern Oklahoma suggesting minimal 

generation or migration of liquid hydrocarbons from 

these coals. However, active exploration for coalbed 

methane is taking place in southeastern Kansas, and at 

least 74 gas wells have been completed. 

Anadarko Basin Reservoir and 

Non-Reservoir SandstonesA Comparison of Porosity Trends 

Timothy C. Hester and James W. Schmoker 

Sandstone porosity normally decreases during 

burial and is commonly treated as a function of burial 

depth. Treating sandstone porosity as a function of 

vitrinite reflectance (R0 ), however, minimizes the effects 
on porosity data of regional differences in burial history. 

Thus, porosity data from areas with regional differe?ces 

in burial, uplift, and thermal gradient may be combmed 

and (or) compared within a normalized context. 

Two porosity-R0 data sets representing sandstones 

of the Anadarko basin, Oklahoma, have been compiled: 

{1) non-reservoir sandstones of the central and souther~ 

Anadarko basin, and (2) hydrocarbon-reservOir 

sandstones of the Anadarko basin as a whole. Each of 

these data sets is compared to a composite set of 

sandstone porosity-R0 data from numerous basins that 

represents a preliminary porosity framework of 

sandstones in general, and the two are also compared to 

each other (fig. 1 ). 

Porosity data of non-reservoir sandstones in central 

and southern Anadarko basin consist of two populations; 

in both, porosity generally declines as a power function of 

increasing thermal maturity. For R0 < 1.1 percent, Anadarko basin non-reservoir sandstone porosity decreases 

more rapidly than does porosity of sandstones in general. 

For R0 > 1.1 percent, Anadarko basin non-reservoir 

sandstone porosity decreases less rapidly than does 

porosity of sandstones in general. 

Reservoir sandstones of the Anadarko basin, 

however, follow a different pattern. Reservoir sandstones 

lose porosity much more slowly than do non-reservoir 

sandstones (for R0 < 1.1 percent) and sandstones in 

general (fig. 1 ). This slower rate of porosity decline with 

increasing R0 could be due to geologic factors such as 

overpressuring or the inhibiting effects of early 

hydrocarbon emplacement on diagenesis, and (or) to 

economic factors inherent in the selection of 

hydrocarbon reservoirs. 

In any case, as Ro increases from about 0.65 

percent to about 1.1. percent, the porosity trends of 

Anadarko basin reservoir and non-reservoir sandstones 

rapidly diverge. Above about R0 = 1.1 percent, however, 

the porosity trends of Anadarko basin reservoir and 

non-reservoir sandstones have similar slopes, suggesting 

that sandstones of the central and southern Anadarko 

basin may retain sufficient porosity for economic 

, accumulations of hydrocarbons, even at high thermal 

maturities. 

Testing New Coal Models-The 1991 

Kaiparowits Plateau Drilling Project 

A.D. Hettinger and P.J. McCabe 

During the past 4 years, the USGS has conducted 

detailed stratigraphic studies on Upper Cretaceous strata 

exposed along the flanks of the Kaiparowits Plateau in 

southern Utah. The purpose of these studies was to 

34 

develop sequence stratigraphic models that relate coal 

deposition and quality to climate, tectonism, and eustasy. 

The study interval includes, in ascending order, the 

Smoky Hollow, John Henry, and Drip Tank Members of 

the Straight Cliffs Formation. The members are 

approximately 40, 260, and 60 m thick, respectively, and 

are late Turonian to early Campanian in age. In 1991, we 

collected continuous core from two 300-m holes drilled 

through these strata in the central regions of the plateau. 

With this core, we hope to test our models and g~in 

additional insight into the controls on coal accumulation 

by integrating coal petrography, geochemistry, and 

palynology with sedimentologic and stratigraphic data. 

A sequence stratigraphic model published in 1991 

by K.W. Shanley and P.J. McCabe divided the Straight 

Cliffs Formation into several systems tracts based on the 

recognition of unconformities, variations in stacking 

patterns, and sandstone geometries. The Calico bed, 

located in the upper part of the Smoky Hollow Member, 

and the Drip Tank Member consist of fluvial, valley-fill 

deposits that are underlain by thick, rooted paleosols. 

The intervening John Henry Member accumulated as a 

highstand deposit along the western margin of the 

Western Interior seaway. 

Stratigraphic sections described from the northeast 

flank of the plateau show that the John Henry Member is 

dominated by 225 m of thick shoreface parasequences 

characterized by upward-coarsening units that contain 

hummocky and swaley cross-stratified sandstone and 

marine fossils. In exposures 2 km to the southwest, 

several shoreface parasequences grade laterally into 

coastal plain strata characterized by rooted mudstone, 

carbonaceous shale, and coal. Here, the John Henry 

Member has a total coal accumulation of 9 m, and 

individual coal beds are as thick as 4 m. Core collected 

from the John Henry Member, 5 km inland from the 

stacked shoreface parasequences, is dominated by interbedded tidal and coastal plain strata; only 45 m of swaley 

bedded sandstone remains. Tidal strata are characterized 

by trough cross-stratified sandstone, wavy-lenticular 

bedding, double mud drapes, Teredolites burrows, ~nd 

oyster shell fragments. Here, the total coal accumulation 

has increased to 20 m, and individual coal beds are as 

thick as 7 m. Ten kilometers farther inland, a second core 

indicates that the John Henry Member consists entirely 

of interbedded coastal plain, tidal, and fluvial rocks; its 

total coal accumulation is 30 m, and individual coal beds 

are as thick as 7 m. By contrast, stratigraphic sections 

described along the south flank of the plateau, 35 km 

inland from the shoreface strata, show that the John 

Henry Member consists entirely of stacked alluvial strata 

containing only rare ooal beds less than 2 m thick. 

Preliminary interpretations indicate that peat 

accumulated in a 35-km-wide belt of coastal plain strata 

that accreted immediately landward of the vertically 
c.> 

(II 

-

cf-

>- r-

(f) 

0 

a: 

0 

a.. 

50 

10 

1.0 

PERCENTILES 

90th--

---- 0 - - "'!r__..L 10th.... --- -fS __ ........ c --

.... -~ 

ANADARKO B:S:........................................ Ap E ~ -~- -- RESERVOIR :r:; U Q 

SANDSTONES _[ i•.LL .................... ..._J:'..._.:r..._._ 

BOX DIAGRAM 

PERCENTILES 

~-- ..... ~-

SANDSTONES/ "'~-.... .......:. 

IN GENERAL / 

>-

>-

o; 

0 

a: 

0 

0.. 

(!) 

;;;:; 

en 

<( 

w 

a: 

(.) 

;;;:; 

90th 

10th 

PERCENTILE 

ANADARKO BASIN 

NON-RESERVOIR 

SANDSTONES 

0.2 ~-----r---r---r--r---;----r--,----,-------r------,...--

0.2 1.0 2.0 3.0 

VITRINITE REFLECTANCE (%) 

Figure 1 (Hester and Schmoker). Plot of porosity versus vitrinite reflectance for Anadarko basin non-reservoir and reservoir sandstones, and for sandstones in general. 
stacked shoreface parasequences. Several distinct 

deepening events are recognized in the core where thick 

tidal deposits overlie coal-bearing coastal plain strata. 

We were able to correlate these deepening events to 

minor transgressive episodes recognized on outcrop and 

depicted in our sequence stratigraphic models. 

Recognition of these transgressive episodes refines our 

models by allowing for a higher degree of correlation 

between shoreface, coastal plain, and fluvial strata than 

was previously possible; and it enhances our 

interpretations regarding the controls on coal 

accumulation. 

o

13C of Terrestrial and Marine Organic 

Matter in Cretaceous Rocks of the 

Western Interior of North America 

Charles W. Holmes, John M'Gonigle, and 

Brent Dalrymple 

Measurement of o13C composition of upper Phanerozoic coals demonstrates a relative decrease in o13C 

beginning in the middle Cretaceous. o13C determination 

in coals from the Upper Cretaceous (Cenomanian to 

Coniacian) Frontier Formation of western Wyoming 

suggests that the shift occurred prior to the Cenomanian. 

Values of o

13C of coals within these middle Cretaceous 

strata range from -25.6 to -26.4 Ofoo, averaging -26.0 °/oo. 

The narrow distribution of o13C values indicates that the 

composition of the carbon source was nearly constant 

during this time. The composition is approximately 2 Ofoo 

more negative (lighter) than older Phanerozoic coals and 

3 °/oo more positive (heavier) than late Cenozoic coals: 

Plants growing in a low-lying environment, such as 

the Okefenokee swamp, Georgia, obtain carbon from 

both the atmosphere and the waters flowing through the 

swamp mire. During the evolution of such an 

environment, the submerged portion of the mire is 

infilled, which produces a stratified hydric- to mesicderived peat deposit. The resulting peat contains varied 

( 4-6 °/oo) o

13C values, heavier because of the hydricderived peat and lighter because of the mesic-derived 

peat. In contrast, plants growing in a raised mire, in 

which the water comes from rain, obtain carbon solely 

from the atmosphere. Studies by C. Geissler and L. Belau 

in 1971 and H.M. Chung and W.M. Sackett in 1978 have 

shown no apparent effect on the o13C of the residual 

organic matter during coalification, and as the raisedmire plants assimilate their carbon from the atmosphere, 

the o

13C of the resultant coals may serve as a monitor of 

the atmosphere o13C-C02 at the time of deposition. 

Sedimentologic and chemical data on coals from the 

Frontier Formation in western Wyoming suggest that 

36 

these coals formed in raised mires on a fluvial plain near 

the shoreline; if so, we suggest that the distribution of 

o13C in the coals contains the middle Cretaceous 

atmosphere o13C signal, and the data indicate that it was 

relatively constant during this time. 

In contrast, L.M. Pratt and C.M. Threlkeld in a 

1984 study noted that the marine o13Corg record for 

Cenomanian and Turonian rocks from many localities in 

the interior sea has a 2-4 °/oo positive excursion over a 

background value of :::::::~-26 °/oo that spans the CenomanianTuronian boundary. W.E. Dean and others in 1986 

tentatively concluded that this excursion results from 

increased pC02 in the atmosphere. This conclusion 

contradicts the data from the terrestrial material on the 

adjacent land mass. An alternative explanation for the 

positive excursion is that it is due to an increase of 

productivity in the sea. Unpublished data by Holmes of 

the distribution of o

13Corg in the Mowry Shale shows a 

positive excursion (2-3 Ofoo) immediately above bentonite beds. As the isotopic excursion lies within the rocks 

whose time of deposition spans the CenomanianTuronian boundary, and as the excursion is associated 

with numerous bentonite beds, we propose that the 

volcanic ashes were sources of nutrients that increased 

productivity. This increased productivity led to the 

change in marine organic matter o13C but did not affect 

the terrestrial record perceptually. 

Collisional Tectonics and the 

Global Generation of Oil and Gas 

David G. Howell 

Models that integrate the principles of plate 

tectonics with the requirements for hydrocarbon 

accumulation (source, maturation, expulsion-migration, 

and entrapment) provide a way to evaluate the worldwide 

distribution of oil-and-gas resources. If tar sands and 

heavy oils are included along with the more conventional 

oil and gas, the principal habitat for the world's 

petroleum resources is seen to be fold-and-thrust belts 

and their associated foreland basins. 

The distribution of oil and gas in foreland basins is 

dictated by thermotectonic processes related to the collisional process. To create the petroleum habitat of 

fold-and-thrust belts and forelands, continental 

shortening, or A-subduction, is required. Such 

shortening can be caused by either of two distinct platetectonic events: (1) accretion of one or more volcanic 

arcs to a continental margin, or (2) the collision of two 

continents. Event 1 has produced such features as the 

Brooks Range of Alaska and the North American 
Cordillera, whereas event 2 has produced such features 

as the Appalachian-Ouachita-Marathon, Zagros, and 

Ural orogens. 

Regardless of the specific plate-tectonic process 

that triggers intracontinental shortening, the styles of 

continental crustal deformation are essentially identical. 

For these crustal-shortening settings to be petroliferous, 

however, one additional ingredient is required: an 

extensive, thermally immature, organic-rich source rock. 

This preexisting source rock is commonly, but not 

exclusively, Devonian, Triassic, Jurassic, and (or) 

Cretaceous black shales. Thus, the superimposition of a 

tectonic orogen across older, thermally immature source 

strata is a critical requirement in the generation of nearly 

all of the world's petroleum. 

Tectonic thickening in the orogen imposes a crustal 

load that creates a crustal sag, which is the foreland 

basin. The sedimentary fill within this basin depresses the 

older strata and effects petroleum maturation. In 

addition, the architecture of the foreland provides 

pathways toward a lithospheric bulge, above which vast 

amounts of oil can accumulate. Owing to inefficiencies in 

the expulsion of oil from source rocks, the extant oil and 

much of the still-rich source rock are depressed far below 

the oil-generating window, such that natural gas becomes 

the primary hydrocarbon generated during the later 

stages of the orogenic cycle. 

In young systems, oil may remain preserved in the 

fold-and-thrust belt, but in fully developed orogenic 

areas, multiple deformational events in the fold-andthrust belt result in the destruction of the early-formed 

architecture of traps and seals. Thus, the initial oil either 

remigrates or cracks, owing to increasing temperatures, 

to gas. In either case, the new structural configurations 

become gas habitats. The flux of gas continues long after 

the initial migration of oil. Therefore, in tectonically 

mature fold-and-thrust belts, we would expect to find 

primarily oil accumulations in regions distal from the 

orogen and primarily gas accumulations in regions 

proximal to the orogen. 

Seismic Reflection Studies of 

Lake Baikal, U.S.S.R. 

D.R. Hutchinson, A.J. Golmshtok, 

T.C. Moore, M.W. Lee, C.A. Scholz, and 

K.D. Klitgord 

Approximately 1,500 km of 12-fold multichannel 

seismic-reflection data was collected in Lake Baikal in 

1989 by the U.S.S.R. Academy of Sciences. These data 

were processed jointly by the U.S. Geological Survey and 

the U.S.S.R. Academy of Sciences. Shots were fired every 

37 

50 m using a 17-liter (1,000 in?) airgun and recorded 

through a 1,200-m, 24-channel streamer for a total 

recording length of 7 s. Velocities are resolved in this 

configuration to about 2-s subbottom. We assume 

velocities of 2.5-4 km/s for the deeper sedimentary units. 

Data were processed 12-fold. 

The data show that Lake Baikal contains three rift 

basins (South, Central and North) that are separated by 

fault-bounded basement highs, Academician Ridge and 

the Selenga Delta (fig. 1). The South and Central basins 

contain the thickest rift deposits (7.0 and 7.5 km 

respectively). Complex depositional patterns and the 

presence of boundary faults on both sides of the basins 

suggest that the style of deformation has varied through 

time and that these basins have not evolved as simple 

half-grabens. In contrast, the North basin has a simpler 

structural style with consistent depositional patterns, 

more suggestive of a uniform deformational regime; and 

maximum sediment thickness is much thinner, about 4.5 

km. These differences suggest that the South and Central 

basins are older than and (or) have extended (and 

subsided) more than the North basin. 

The geometry of each of these basins is 

asymmetric. From south to north, the greatest fault offset 

occurs on the north, northwest, and west sides of the 

basins (fig. 1 ). This overall geometry consists of rift 

segments that change orientation from east/west in the 

south to north/south in the north. The intervening 

basement highs are complex accommodation zones in 

which fault orientation therefore changes between 

adjacent rift segments. 

The seismic data indicate at least three phases of 

deposition, separated by significant tectonic movements 

and faulting. The oldest episode of faulting, which offsets 

basement blocks and the oldest acoustically opaque 

sedimentary units, is most prominent in the South and 

Central basins but may be locally present in the North 

basin. The second phase of faulting is characterized by 

steep primary and antithetic faults ( > 50°) that generally 

die out upward at about 0.5-1.0 s beneath the lake floor. 

This phase of faulting occurred contemporaneously with 

a seismic depositional unit which contains clear internal, 

laminated reflections. The youngest faulting is also very 

steep, occurs near the edges of all basins, offsets the lake 

floor, and rejuvenates some of the older faults. Some 

areas near Academician Ridge show indications of fault 

dip-reversal and slight compression. The steepness and 

linearity of the faults, the evidence for dip-reversal, and 

the progressively rotated orientation of the three basins 

suggest that oblique-sinistral slip tectonics have played a 

significant role in the development of the structures and 

stratigraphy beneath Lake Baikal. 
104° 106° 108° 

I 

\ 

I 

\ 

\ 

' \ + + + 

+ + + 

0 100 KM ~· __ ._~~~--~~· 

. • . 

.. : ~ .. , .... 

PRIMORSKY · . ~:::~· .~~~'< + 

52° 

Figure 1 (Hutchinson and others). Total sediment thickness (kilometers) beneath Lake Baikal from multichannel 

seismic reflection profiles. Dashed line indicates inferred thickness; query, contour position unknown. Dotted line, 

multichannel track line. Hachured line, fault. 

38 
Petroleum Geology Research in the 

Santa Maria Province, California 

Caroline M. Isaacs 

The USGS Onshore Oil and Gas Investigations 

Program has ongoing research focused on the petroleum 

geology of the Santa Maria province. This research 

centers on the Miocene Monterey Formation, the 

principal source and reservoir of petroleum in the 

onshore and offshore Santa Maria basins, and a major 

source and reservoir in the Santa Barbara-Ventura basin. 

Current stratigraphic research on the Monterey 

Formation is focused on establishing a firm age and 

facies framework, with the long-term goal of developing 

reliable regional correlations and paleogeographic 

reconstructions. Problems currently being addressed 

include (1) poor age control in much of the province, 

especially in the interval 5-10 Ma; (2) high small-scale 

( < 1 ft) variability, which has made comparison of 

sequences difficult and determination of regional trends 

unreliable; and (3) complex and poorly understood 

expression of lithotypes and lithofacies on well logs. 

Research has focused on detailed interrelation of the 

composition, well-log characteristics, age, and paleobathymetry of select subsurface sequences in the Orcutt, 

Point Arguello, South Elwood, and Hondo oil fields. 

Source-rock characteristics, another major topic of 

research, are being investigated mainly by the USGSsponsored Cooperative Monterey Organic Geochemistry 

Study. This international study group involves about 30 

organic geochemists and 10 geologists working in 

collaboration on the deposition, diagenesis, oil 

generation, and oil-source correlation of the Monterey 

Formation. The cent.er of the source-rock study is the 

comprehensive geologic and organic geochemical 

analysis of 22 rock samples and 11 oils from the Santa 

Maria and Santa Barbara-Ventura basins. Rock samples 

include a variety of lithotypes from two stratigraphic 

sections of differing maturity, and oil samples include a 

variety of gravities and sulfur contents from eight oil 

fields. Also part of the source-rock study is selected 

research on organic geochemical maturity of a deep 

( > 13,000 ft) offshore well profile. Topics addressed by 

the source-rock study include the interpretation of 

provenance and paleoenvironmental indicators in 

organic matter, compound identification, effect of sulfur 

on organic maturation, source-rock maturity assessment, 

early oil generation, application of biological marker 

compounds, and kinetic modeling. Methodological topics, 

such as interlaboratory comparisons and evaluation of 

both source-rock potential and maturity assessment by 

Rock-Eval pyrolysis, are also being addressed. 

39 

Other research in the USGS on the petroleum 

geology of the Santa Maria province includes (1) silica 

and clay diagenetic profiles in the Orcutt field and Los 

Alamos syncline of the onshore Santa Maria basin; (2) 

thermal and kinetic modeling of organic maturation in 

the same areas; (3) high-quality thermal surveys and 

regional heat-flow studies; ( 4) synthesis of petroleum 

occurrence in the region; ( 5) coordinated organic and 

inorganic geochemical research on outcrop weathering 

of source rocks; and (6) fractured-reservoir characterization by fractal analysis. 

Basin Evolution in the Foreland of 

Thin- and Thick-Skinned Thrust 

Terranes-Example from the Sylhet 

Trough, Bangladesh 

Samuel Y. Johnson and A.M.N. Alam 

The Sylhet trough is a subbasin of the Bengal Basin 

in northeastern Bangladesh that contains a thick fill 

(12-16 km) of upper Mesozoic and Cenozoic strata. The 

trough is bounded on the west by the Indian Shield 

platform; on the north by the Shillong Plateau, a 

basement-cored uplift in the foreland of the Himalayas; 

and on the east and southeast by the Chittagong-Tripura 

fold-and-thrust belt of the Indo-Burman ranges. To the 

south and southwest, the trough opens to the main part 

of the Bengal Basin. The tectonic evolution of this 

trough, inferred from outcrop, core, well-log, and seismic 

data, reflects the complex interactions of its bounding 

orogenic belts. 

The Sylhet trough occupied a slope and basinal? 

setting on a passive continental margin from late Mesozoic through Eocene time (fig.lA). Subsidence may have 

increased slightly in Oligocene time (fig. 1B) when the 

trough was located in the distal part of a foreland basin 

paired to the Indo-Burman ranges. 0 ligocene fluvialdeltaic strata (Bar ail Formation) were derived from 

incipient uplifts in the eastern Himalayas. Subsidence 

increased markedly in the Miocene Epoch (fig. 1C) in 

response to westward encroachment of the Indo-Burman 

ranges. Miocene to earliest Pliocene sediments of the 

Surma Group were deposited in a large, mud-rich delta 

system that may have drained a significant proportion of 

the eastern Himalayas. 

Subsidence rates in the Sylhet trough increased 

dramatically (3-8 times) from Miocene to PliocenePleistocene time (fig. ID) when the fluvial Tipam 

Sandstone and Dupi Tila Formation were deposited. 

These two units thin markedly over anticlinal crests, 

indicating that the frontal zone of Indo-Burman ranges 

deformation had advanced into the eastern Sylhet trough 
92° 

25° 

-Area of--_-_-_-_-_-_-_-_-_-_-_ 

-t.....='-=--=-==--=' _ Sylhet trough-_-_-_-_-_-_-_-_-_ 

_-_-shelf_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_ 

_ -_-_-_-edge_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-_ 

1\ =-=-=-=-=-=-=-=-=-=-=-=-=-=-=-=-=-=-=-=-=-=-=-=-=-=-=-=-= 92° 

92° 

......---- ~- .· .. _.__.A-_:-- ~-~?~ 

-&--:-.~~~~:.:: :: l;: ~~ 

:::::::::::::::: ::::.·.::: ::::::;/f/>ff;/( il 

· .. · .. · .. · .. · .. · .. · .. ··~-· I r ~ 

c 

10 ~ r 

92° 

100 KILOMETERS 

EXPLANATION 

Positive area 

Limestone 

Fluvial and delta-plain deposits 

c=J 

~ 

Delta-front and prodelta deposits 

Basinal deposits 

---- Approximate contact 

_ __..,_ Thrust fault-Sawteeth on overthrust block 

! ) Anticline-Showing plunge where known 

Figure 1 (Johnson and Alam). Schematic paleogeographic reconstructions showing four stages in the Cenozoic evolution of 

the Sylhet trough: A, middle Eocene; 8, Oligocene; C, Miocene; 0, Pliocene. Reconstructions A, 8, and C restore inferred 

Shillong Plateau southward displacement. ABA, ancestral Brahmaputra River; MBA, modern Brahmaputra River; MBT, Main 

Boundary thrust fault. Scale is approximate. 

40 
by the early Pliocene. The dramatic increase in 

subsidence rate is attributed to south-directed overthrusting of the Shillong Plateau on the Dauki fault for 

the following reasons: (1) Pliocene and Pleistocene strata 

in the trough thin markedly away from the Shillong 

Plateau, consistent with a crustal load emplaced on the 

northern basin margin. (2) The Shillong Plateau is 

draped by Mesozoic to Miocene rocks, but Pliocene and 

younger strata are not represented, suggesting that the 

massif was an uplifted block at this time. (3) Southdirected overthrusting of the Shillong Plateau is 

consistent with gravity data and with recent seismotectonic observations. Sandstone in the Tipam has a marked 

increase in sedimentary lithic fragments compared to 

older rocks, reflecting uplift and erosion of the 

sedimentary cover of the Shillong Plateau. 

Southward thick-skinned overthrusting of the 

Shillong Plateau and westward folding and thin-skinned 

thrusting in the Indo-Burman ranges have thus occurred 

in the Sylhet trough area since the early Pliocene. The 

frontal zone of the Indo-Burman ranges is being 

depressed by the Shillong Plateau into a foreland basin 

(fig. 1D). If the Dauki fault has a dip similar to that of 

other Himalayan overthrusts, then a few tens of 

kilometers of horizontal tectonic transport are required 

to carry the Shillong Plateau to its present elevation. 

Uplift of the Shillong Plateau probably generated a 

major (about 300 km) westward shift in the course of the 

Brahmaputra River. 

The ARC/INFO Geographic Information 

System Applied to Geologic 

Investigations of the Norphlet 

Formation, Alabama and Mississippi 

C. William Keighin and C.J. Schenk 

A desirable part of our program to evaluate the 

natural gas potential of deeply buried reservoirs in the 

Gulf Coast region was (1) to have a system in which 

existing map coverage could be integrated with various 

types of ancillary data, and (2) to display these 

coordinated data and maps in different combinations at 

convenient map scales. We found that, although 

numerous maps of the Gulf Coast area were available, 

base maps at the desired scale in digital format were not. 

To provide maximum flexibility in data display in the 

future, we utilized the GIS (Geographic Information 

Systems) laboratory of the USGS in Denver. Base maps 

containing the desired political boundaries and spatial 

(coordinate) data, obtained as black-line positives, were 

scanned by Tektronix laser scanning and converted into a 

data format usable in the ARC/INFO GIS system. Other 

41 

information, including location and outline of oil and gas 

fields, well data, structural data, and location of known 

salt domes, was added to the GIS system. Using the GIS 

system, the data could be manipulated to produce 

different layers of information, and the layers overlaid in 

different combinations to produce maps. 

An initial target for evaluation is the Upper Jurassic Norphlet Formation, because this formation is an 

important hydrocarbon reservoir in Alabama in Baldwin 

and Mobile Counties, offshore in Mobile Bay, and it 

produces condensate from the Flomaton field in Escambia County. Depth to the producing horizon varies, but it 

reaches approximately 21,000 ft in offshore wells in 

Mobile Bay. The Norphlet also contributes limited 

quantities of oil and gas in a few fields in Mississippi. In 

line with our recognizing the importance of map data 

integration and the usefulness of the GIS, we wanted to 

graphically relate distribution, depths, and production 

levels of Norphlet fields to known geologic features such 

as faults and salt domes, and to fields producing from 

other formations. We needed to display these 

relationships in various combinations and at different 

scales. Although Norphlet production does not appear 

directly related to distribution of salt domes in this 

region, because salt domes are important indicators of 

Gulf Coast geologic history, we wanted to graphically 

show their distribution and spatial relationship to other 

hydrocarbon-producing fields and formations. 

The Santa Maria Province Project, 

California 

Margaret A. Keller, Caroline M. Isaacs, and 

Richard G. Stanley 

The Santa Maria Province Project of the U. S. 

Geological Survey is an undertaking jointly sponsored by 

the Evolution of Sedimentary Basins and Onshore Oil 

and Gas Investigations Programs. The project is a 5-year 

study involving more than 60 researchers from 

government agencies, academia, the oil industry, and 

consulting firms. The study area is the onshore region 

west of the Sur-Nacimiento fault and north of the Santa 

Barbara Channel together with adjacent offshore areas, a 

region including the onshore Santa Maria basin proper, 

the offshore Santa Maria, western Santa BarbaraVentura, Pismo, and Huasna basins, and several other 

small basins and basin fragments. Onshore, the Santa 

Maria province contains the world's largest diatomite 

deposit as well as major petroleum deposits ( > 1 billion 

bbl recoverable). The province includes the most 

extensive fractured petroleum reservoirs in California 

and, in the offshore, the largest United States petroleum 

discoveries since Prudhoe Bay. 
The Santa Maria province has a complex tectonic 

history. Mesozoic and lower Paleogene rocks form a 

collage of tectonostratigraphic terranes that apparently 

accreted to the North American continent by late Eocene 

time. Many questions remain about the sites of origin of 

the terranes, their travel paths, and the processes and 

timing of terrane suturing and continental "docking." 

Overlying the pre-Eocene rocks and fragments of Eocene 

marine strata is a widespread and thick pile of 

sedimentary and igneous rocks deposited in numerous 

basins that began to form along the continental margin 

during the late Oligocene and early Miocene. The Oligocene to Pleistocene rocks of the province exhibit rapid 

lateral changes in facies and thickness and include (1) 

nonmarine alluvial fan, lacustrine, and fluvial deposits; 

(2) shallow-marine sandstones and conglomerates; (3) 

bathyal marine mudrocks, including the organic-rich 

biogenous strata of the Miocene Monterey Formation 

(source of the diatomite and petroleum deposits); and 

( 4) volcanic rocks ranging in composition from rhyolite 

to basalt. The origin of the Neogene basins is 

controversial; wrench tectonism, regional extension, 

large-scale block rotation, and combinations of these 

three mechanisms have been proposed. Differences 

among the mechanisms are great enough that Miocene 

paleolocations, onshore-offshore orientations, and basin 

geographies remain uncertain. However, Miocene facies 

and their subsequent structural, thermal, and 

compaction history controlled petroleum generation and 

reservoir formation in this region. 

Studies in the Santa Maria Project have focused on 

the stratigraphic and structural framework, with 

particular emphasis on detailed mapping in key areas and 

intensive study of important stratigraphic sections in 

outcrops and wells. Many good surface exposures occur 

in the province and extensive subsurface data are 

available from both onshore and offshore. Major 

geologic problems addressed by the project are (1) the 

origin and timing of terrane accretion; (2) the origin and 

history of the Neogene sedimentary basins; (3) Miocene 

paleogeography and lateral facies changes; and ( 4) the 

thermal and structural history of the province. 

Completed or nearly completed projects include 

(1) geologic mapping in the San Rafael Mountains and 

Santa Lucia Range; (2) detailed sedimentologic and 

biostratigraphic study of the Oligocene through Miocene 

nonmarine and marine sequence; (3) new radiometric 

dating of 0 ligocene and Miocene volcanic units; ( 4) 

equilibrium temperature surveys in key wells; (5) 

coordinated study of thermal history utilizing clay 

diagenesis, silica diagenesis, and biomarker maturation 

parameters; and (6) analysis of the USGS seismic data 

collected in 1990 in the offshore Santa Maria and Santa 

Barbara-Ventura basins. In addition, the following 

regional summaries are either underway or completed: 

42 

(1) major correlation sections based on outcrop, 

subsurface, and geophysical data; (2) compilations of the 

geology, gravity, and magnetics; and (3) a synthesis of the 

province's geologic evolution from Jurassic to Holocene. 

Completed project publications include a province 

bibliography, core workshop volume published by the 

Society for Sedimentary Geologists, numerous USGS 

Open-File Reports and Maps, numerous abstracts, and 

journal articles. Publications in progress include USGS 

Bulletin 1995 (a multiple chaptered series on the 

province studies), a 1:100,000-scale compiled geologic 

map of the province, and several more USGS Open-File 

Reports and Maps. 

Fracturing and Reservoir Development in 

the Katakturuk Dolomite, Arctic National 

Wildlife Refuge, Alaska 

John S. Kelley, Chester T. Wrucke, and 

Augustus K. Armstrong 

The Katakturuk Dolomite of Proterozoic age, a 

possible petroleum reservoir under the Arctic coastal 

plain of the Arctic National Wildlife Refuge (ANWR), is 

about 2,500 m thick in the Sadlerochit and Shublik 

Mountains. The Katakturuk in this area has a structural 

setting similar to that north and east of the Sadlerochit 

Mountains under the coastal plain of ANWR, where 

pre-Mississippian rocks are involved in Brooks Range 

thrusting. 

Reservoir properties of the Katakturuk Dolomite 

owing to depositional fabric and diagenesis are poor but 

likely are enhanced by fracturing. Reservoir properties 

were examined in thin section and measured from 

outcrop samples in the Sadlerochit Mountains and core 

from the Canning River Unit A-1 well west of the 

Sadlerochit Mountains, but their values are too low to 

explain the flow rate from a drill-stem test in the Katakturuk. In the Canning River Unit A-1 well, the Katakturuk yielded 134 barrels of fresh water with a calculated 

flow rate of 4,800 barrels per day (data from the 1987 

study of Bird and others). The drill-stem test from which 

the flow rate was calculated included the interval cored 

and sampled for porosity and permeability measurements. Enhancement of permeability through 

fracturing could explain the flow rate. Fractures are 

pervasive in the Katakturuk in the Sadlerochit Mountains 

and likely are related to folding and thrust faulting. 

Early dolomitization and cementation in the 

Katakturuk Dolomite largely obliterate porosity and 

permeability. Dolomite rhombs 2-6 p.m across replace 

framework clasts originally composed of peloids, 

microbial fragments, microbial-laminated clasts, ooids, 
pisolites, oncolites, mud pellets, coated grains, and 

fragments of microbial mats, early cements, and micrite. 

Dolomite cement, chalcedony, and spar calcite infill voids 

consisting of internal molds in oolites and pisolites and 

fenestral cavities in microbial mats and stromatolites. 

Much of the formation is massive dolostone composed of 

xenotropic dolomite rhombs 100-500 p.m across. The 

intercrystal pore space of the massive dolostone is mostly 

filled with dolo spar, calcite, and silica cements. 

Forty-three samples of the Katakturuk Dolomite 

from the Sadlerochit Mountains and 9 samples from core 

in the Canning River Unit A-1 well have low measured 

porosity and permeability (according to a 1987 study by 

K.J. Bird and others). Mean porosity for outcrop samples 

is 2.3 percent. Although a single outcrop sample had a 

porosity of 10 percent, all other samples had porosities of 

0.8 to 6.2 percent. Measured permeabilities from outcrop 

samples range from less than 0.1 to 1.6 mD (millidarcies ); nearly half the samples have permeabilities less 

than 0.1 mD. Samples from the Canning River Unit A-1 

well have a mean porosity of 0.7 percent and a range 

from 0.3 to 1.1 percent. Permeabilities for all well 

samples are 0.1 mD or less. 

The Katakturuk Dolomite in the Sadlerochit 

Mountains crops out in the south limb of an easttrending, doubly plunging regional anticline. The Katakturuk dips 100-30° more steeply to the south than unconformably overlying Mississippian and younger strata. The 

steeper dips in the Katakturuk largely result from the 

angular unconformity beneath Mississippian limestone. 

The south-dipping Weller thrust at the base of the 

Katakturuk extends the length of the anticline and 

emplaces the Katakturuk over steeply dipping strata of 

Paleocene age in the western Sadlerochit Mountains. 

Displacement on the thrust diminishes to the east and 

becomes negligible where the thrust separates the Katakturuk from underlying Precambrian argillite and 

sandstone in the eastern Sadlerochit Mountains. Two 

sets of high-angle faults in the Katakturuk subtend the 

direction of tectonic transport in the Sadlerochit 

Mountains. One set trends about N. 30° E. and the other 

set about N. 45° W. The northeast-trending faults have 

left -lateral separations that typically are greatest near the 

thrust and diminish upward and away from the thrust. 

Systematic offset is not recognized in northwest-trending 

faults. Fracturing in the Sadlerochit Mountains is most 

intense within the Katakturuk that crops out between the 

folded angular unconformity at the base of concentrically 

folded Mississippian strata and the Weller thrust. 

The fractures and faults in the Katakturuk 

Dolomite are thought to have resulted as the dolomite 

accommodated to concentric folding that developed 

during Tertiary time in Brooks Range thrusting. As 

concentric folds became dominant in the Mississippian 

limestone and younger strata, the angular relation 

43 

between the Katakturuk and Mississippian and younger 

strata severely limited bedding-plane slip as an 

accommodation to concentric folding within the Katakturuk. Pervasive fracturing and movement by distributed 

shear within the Katakturuk became the principal 

mechanism of deformation of the brittle carbonate strata 

of the Katakturuk as the dolomite became incorporated 

into the core of the fold during folding and thrusting. The 

sets of high-angle faults above the Weller thrust and 

mostly within the Katakturuk are likely conjugate faults 

that provided a mechanism of mass transport and 

contributed maximum contraction north-northwest, 

parallel to the direction of tectonic transport during 

folding and thrusting. 

Major Controls on Accumulation of Upper 

Cretaceous Coals in North America 

M.A. Kirschbaum, L.N.R. Roberts, and 

P.J. McCabe 

Climate, subsidence rates, and eustasy were the 

primary controls on the accumulation of the extensive 

Cretaceous coal deposits of North America. To better 

understand the relative importance of these controls, we 

constructed a series of paleogeographic and isopach 

maps for selected biostratigraphically constrained 

intervals. Our maps suggest that the higher subsidence 

rates associated with foreland basins were critical in 

determining the geographic location of thick Cretaceous 

coal deposits. In these basins, rates of base level change 

produced by subsidence and eustasy determined the 

stratigraphic position of the coals within the sedimentary 

sequence. 

Most Cretaceous peat-forming environments 

developed along broad coastal plains within 60 km of the 

Western Interior seaway. Restriction of the Cretaceous 

coals to coastal plain environments suggests that a 

maritime climate created by the epicontinental seaway 

was critical in mire development. In the Maastrichtian, 

for example, extensive non-coal-bearing fluvial strata and 

variegated paleosols, some containing carbonate 

nodules, accumulated inland from these coastal plains. 

Good drainage and lower rates of precipitation in the 

inland areas precluded the accumulation of peat. 

The thickest Cretaceous coals are thought to have 

accumulated in areas where peat accumulation kept pace 

with the tectonic subsidence rate. Subsidence rates can 

be estimated from sediment accumulation rates, which 

during the Cenomanian were as much as 280 m/m.y. The 

thickest Cenomanian coals formed in the foreland basin 

associated with the Sevier orogenic belt where sediment 

accumulation rates were between 70 and 215 m/m.y. The 
east side of the seaway also had suitable peat-forming 

environments, but because the subsidence rates were 

lower (sediment accumulation rates <50 m/m.y.), the 

coals are thinner and laterally less extensive than those of 

the foreland basin. 

Subsidence rates also affected paleogeographic 

configurations. For example, high subsidence rates in 

southern Wyoming and northern Colorado during the 

Maastrichtian produced a major embayment of the 

Western Interior seaway covering about 14,000 km2 • In 

this area, as much as 2,900 m of Maastrichtian strata was 

deposited over a period of about 6 m.y., and more than 

20 billion metric tons of coal accumulated in the coastal 

plain environments along this embayment in the Almond, 

Williams Fork, Laramie, and Lance Formations. 

Evolution of the Illinois Basin 

Dennis R. Kolata, W. John Nelson, 

Janis D. Treworgy, Stephen T. Whitaker, 

Michael L. Sargent, Lloyd C. Furer, and 

M.C. Noger 

The Illinois Basin is one of the major interior 

cratonic basins of North America, covering an area of 

approximately 110,000 mi2 (285,000 km2 ) in Illinois, 

Indiana, and Kentucky. It comprises about 120,000 mi3 

(500,000 km3

) of Paleozoic rocks containing a wealth of 

resources, including coal, oil and gas, ground water, and 

industrial minerals and metals. To the present time, 

some 4 billion barrels of oil has been produced from 

depths mainly shallower than 3,000 ft. About 9 billion 

tons of an estimated 268 billion tons of original in-place 

bituminous coal resources has been mined in the basin. 

Knowledge of the basin's structural and stratigraphic framework and tectonic history has been 

enhanced by new regional cross sections, subsurface 

mapping, and geophysical studies. 

The origin and evolution of the basin are closely 

related to the development of the Reelfoot rift and 

Rough Creek graben, a failed rift situated at the south 

end of the basin. The rift system formed during breakup 

of a supercontinent, apparently during late Precambrian 

to Early Cambrian time. Lithospheric extension within 

the rift system resulted in tensional block faulting and 

relatively rapid subsidence and sedimentation. By Late 

Cambrian the tectonic setting changed from a rift basin 

to a broad cratonic embayment centered over the rift. 

During the remainder of the Paleozoic Era, the protoIllinois basin was a broad trough extending from the 

continental margin in central Arkansas northward 

through Illinois, Indiana, and western Kentucky. 

Sedimentation during the Paleozoic was dominated by 

44 

deposition of carbonates and to a lesser extent by 

sandstone, shale, and siltstone. Basin fill, after 

Pennsylvanian rocks were deposited, exceeded 

thicknesses of 20,000 ft ( 6,000 m) in the Rough Creek 

graben area of southern Illinois and western Kentucky 

and probably was even thicker within the Reelfoot rift. 

Structural deformation in the basin began in Valmeyeran 

time concurrent with the initial accretion of continents 

that later formed the Pangea supercontinent. 

Compressional stresses emanating from the Allegheny 

and Ouachita orogenies were transmitted to the 

continental interior, reactivating faults within the Reelfoot rift and Rough Creek graben and causing uplift of 

basement-block structures throughout the Illinois basin. 

The compressional phase was followed by a post-Early 

Permian episode of extension that probably coincided 

with breakup of Pangea. Tensional stresses reactivated 

faults within and adjacent to the Reelfoot rift and Rough 

Creek graben. 

Post-Pennsylvanian, pre-Late Cretaceous uplift in 

the area of the Reelfoot rift structurally closed the south 

end of the Illinois basin, creating the present basin 

geometry. By the end of the Mesozoic Era, this uplift had 

been beveled and overlapped by Upper Cretaceous and 

lower Tertiary rocks of the Mississippi Embayment. The 

midcontinent region, including the Illinois Basin, is 

presently experiencing east-west compressive stress that 

apparently is reactivating faults within the southern part 

of the basin, particularly in the Reelfoot rift. 

The Illinois Basin Consortium (IBC), consisting of 

the Illinois, Indiana, and Kentucky Geological Surveys, is 

presently conducting joint basin-wide studies to gain a 

better understanding of the basin-forming, -filling, and 

-modifying processes. One of the primary missions of the 

IBC is to assess the potential for ground water, coal, oil, 

natural gas, and industrial-mineral resources. The IBC is 

conducting basin research in cooperation with geoscientists from universities, the USGS, and other government 

agencies. 

GIS Visualization of Coal Stratigraphic 

and Geochemical Information 

Kathleen K. Krohn, Carol L. Molnia, 

Susan J. Tewalt, and William G. Miller 

The National Coal Resources Data System 

(NCRDS) of the USGS is an integrated GIS 

(Geographic Information System) digital system that 

accesses a master data base and a suite of 2- and 

3-dimensional vector and raster mapping, display, and 

statistical capabilities for data analysis and visualization. 

Currently the system is composed of a network 

with main nodes in Reston, Va., and Denver, Colo., and 
is accessed by scientists and other coal experts within and 

outside the USGS. Twenty-two State geological agencies 

have cooperative agreements with NCRDS and either 

access the system from remote sites via commercial and 

USGS telecommunications networks or are implementing the public domain software on local 

workstations. Software modules operate on a range of 

hardware platforms running Unix and X-windows. 

Current hardware includes three Sun 4 servers, desktop 

workstations, microcomputers (IBM-PC compatibles), 

and mainframes. Enhancement of software and 

acquisition and integration of hardware are ongoing to 

provide coal geologists the means to analyze multiple 

coal data elements and to create a variety of maps with 

enhanced flexibility and interactivity. 

The data-base information includes stratigraphic 

descriptions and coal-quality data (trace element, Btu, 

ash, and sulfur analyses) located by latitude and 

longitude, as well as summary files (coal tonnage and 

coal-quality information) located by geographical area. 

The basic geologic data are used primarily to model coal 

deposits and analyze resource estimates in 2- and 3-

dimensional maps and diagrams. 

A major concern of NCRDS is to provide costeffective software solutions. Currently, NCRDS has 

found it necessary and desirable to use a combination of 

both in-house developed software and commercial 

software. A robust suite of raster-based GIS techniques 

is encompassed in GRASS (Geographic Resources 

Support System) being developed by the U.S. Army 

Corps of Engineers. USGS is enhancing GRASS 

software to meet NCRDS needs as both an analytical tool 

and a data-base access facility. At present, NCRDS has 

the following programs available for use for resource 

assessment and mapping: GRASS, Dynamic Graphic's 

Interactive Surface Modeling (ISM), a USGS version of 

semivariogram modeling and Krieging geostatistics, 

subsets of ARC/INFO, and USGS's GARNET. Image 

analysis techniques are being investigated for their 

applicability to coal geology analysis. 

Coal resource tonnage analysis provides an 

example of how multiple digital-mapping software 

capabilities are used. First, the data specified are gridded 

and contoured in software of choice. Then the areas of 

interest are defined by a series of boundaries that include 

outcrop geology, thickness, sulfur content, structure, 

overburden, and other variables of interest. Finally, 

volumes are determined and the tonnage of coal meeting 

specified criteria is calculated. These techniques have 

been used successfully in a variety of projects on a local 

(lease tract, quadrangle-based) and regional (basinal) 

scale. 

Research continues on the integration of objectoriented data-base-management (OODBMS) techniques to provide a link between the GIS data 

45 

visualization options and the master data base. Postgres 

is the extension to Ingres, which is the relational database management system in use by NCRDS. This 

software is being developed by the University of 

California at Berkeley. Investigations are underway to 

determine its suitability as a vehicle to meet the graphical 

analysis and data-management needs of geologists, for 

GIS projects of short- and long-range application. 

Alteration of Lignin During 

Biodegradation in Peats and the 

Early Stages of Coalification 

Harry E. Lerch, William H. Orem, and 

Timothy A. Moore 

Lignins are one of the most important groups of 

biosynthesized, organic macromolecules produced on 

Earth. They are produced exclusively by vascular plants 

primarily in wood, and have a cross-linked, methoxysubstituted, polyphenol chemical structure, often bonded 

to complex carbohydrates in plants via ether linkages (for 

example, as lignocellulose). The chemical structure of 

Iignins makes this group of compounds resistant to 

microbial degradation following the death or senescence 

of plant biomass. Thus, lignins and lignin residues are 

often abundant in soils, peats, and sediments. In addition, 

lignin residues are thought to be the major contributors 

to the aromatic structures of coals. 

Details of the changes in the macromolecular 

structure of lignins that occur during early diagenesis and 

the early stages of coalification are poorly understood, 

and our work has focused on the chemical structural 

changes in lignin biopolymers which occur during these 

processes. We are using a number of different organic 

geochemical techniques to elucidate these chemical 

changes, including solid state 13C nuclear magnetic 

resonance spectroscopy (NMR), pyrolysis-gas chromatography (PY -GC), and gas chromatography-mass 

spectroscopic (GC-MS) analysis of cupric oxide lignin 

oxidation products (LOP). Peat and low-rank coal 

samples from a number of different locations were 

studied; however, emphasis was placed on peat and coal 

samples from Kalimantan (Borneo), Indonesia. 

Results of 13C NMR studies of peats have shown 

that lignin is preserved in some environments and rapidly 

degraded in others. In all environments studied, 

carbohydrates are preferentially biodegraded compared 

to other biomolecules. However, in many extensive acidic 

peat deposits (such as Indonesian peats and Okefenokee 

Swamp peats), lignin is also rapidly degraded from the 

peat. In these low-pH environments, the remaining peat 

organic matter consists primarily of aliphatic substances 
such as cuticular waxes. The biodegradation of lignin 

produces aromatic-rich organic acids that may contribute 

to the low pH and dark color of the water in these 

wetlands. Pyrolysis-GC and GC-MS studies of LOP in 

these acidic peats have confirmed that lignin degradation 

is an important process. This process, however, does not 

involve the preferential biodegradation of individual phenols (such as vanillyl, syringyl, p-hydroxyl and cinnamyl 

phenols) that constitute the lignin macromolecule. Our 

LOP studies in a number of wetlands have shown that the 

relative proportions of the individual phenols in lignin 

remain about the same during biodegradation. Thus, 

specific lignin monomers are not selectively degraded. 

Our 13C NMR studies of low-rank coals indicated 

that fragments of the lignin molecule may be present in a 

relatively unaltered condition in some samples. This was 

implied by distinct peaks from methoxyl, phenolic, and 

aromatic carbons in the 13C NMR spectra. However, 

other samples showed little evidence of preserved lignin 

in their 13 C NMR spectra, although broad peaks in the 

aromatic region indicated that highly altered lignin was 

present. Further studies of two of these coal deposits 

from Indonesia (SS-1 and 1001), conducted using the 

LOP method and GC-MS, showed the presence of 

measurable amounts of unaltered lignin in both sets of 

samples. Thus, relatively unaltered lignin can survive 

both biodegradation and early stages of coalification and 

may provide information on the environments of coal 

deposition. In the case of the two Indonesian coals, the 

LOP results indicate that the SS-1 samples apparently 

formed in an angiosperm -dominated swamp and the 

1001 samples in a gymnosperm-dominated swamp. We 

are currently investigating the chemical structures of 

unknown peaks in the LOP chromatograms of these 

coals. This may provide information on subtle changes to 

lignin polymers that occur during the earliest stages of 

coalification. 

Role of Water in Petroleum Formation 

Michael D. Lewan 

Laboratory experiments show water to be a critical 

component in natural petroleum generation and 

expulsion. The significance of water is best demonstrated 

by an experimental approach referred to as hydrous 

pyrolysis. Similar to natural maturation in subsiding 

sedimentary basins, this experimental approach 

maintains a liquid water phase in contact with a source 

rock as it is heated. Although these experiments require 

higher temperatures (250-365 °C) to offset the longer 

durations at lower temperatures experienced in natural 

maturation, the products are similar in bulk chemical, 

molecular, physical, and isotopic character to natural 

46 

maturation products. Hydrous pyrolysis experiments 

conducted on potential source rocks show that petroleum 

formation involves two overall reactions: (1) partial 

decomposition of insoluble kerogen to soluble, highmolecular-weight bitumen; and (2) partial decomposition of bitumen to a liquid, expelled oil. 

The first overall reaction involves the cleavage of 

weak noncovalent bonds in the kerogen. Cleavage of 

these bonds to form the high-molecular-weight bitumen 

does not appear to be influenced by the presence of 

water. A volume increase associated with this overall 

reaction causes the generated bitumen to expand into 

micropores and along bedding-plane partings. It is 

crucial to the effectiveness of most source rocks that a 

continuous bitumen network develop through the rock 

matrix as a result of this overall reaction. Under hydrous 

conditions, a significant amount of interstitial water in 

the rock is dissolved in the bitumen network. This 

water-saturated bitumen network is maintained in 

hydrous pyrolysis experiments by the liquid water 

surrounding the source rock in the reactor, and in nature 

by the liquid water surrounding the source rock in 

dissecting fractures or faults and adjacent porous rocks. 

Unlike the first overall reaction, the second overall 

reaction, that of bitumen partially decomposing to oil, 

involves the cleavage of covalent bonds and is dependent 

on the presence of water. The role of water in this overall 

reaction is both chemical and physical. Chemically, the 

dissolved water in the bitumen network terminates freeradical sites by donating its hydrogen atoms during 

bitumen decomposition. This process reduces the 

frequency of 13-scission, disproportionation, and crosslinking reactions, thereby enhancing oil generation and 

inhibiting pyrobitumen generation. Physically, the 

resulting oil generated by this overall reaction is 

immiscible in the water-saturated bitumen and forms a 

separate phase. In addition to the buoyancy force 

generated by the density difference between the 

immiscible oil and the water-saturated bitumen, a net 

volume increase associated with the partial decomposition of bitumen to oil generates an internal force 

within the confining mineral matrix of a rock. As a result, 

the immiscible oil is expelled from the rock as it is being 

generated. 

The processes and mechanisms responsible for 

generation and expulsion of oil in hydrous pyrolysis 

experiments are considered the same as those in nature. 

However, the degree to which they are operative in nature 

remains to be determined through additional research. 

Overburden and confining pressures may have some 

influence on these processes and mechanisms, but as a 

first approximation, the higher temperatures used in 

hydrous pyrolysis are likely to have the greatest influence. 

The solubility of water in the bitumen network decreases 

with decreasing temperature. Therefore, a reduction in 
the amount of water dissolved in the bitumen under the 

lower temperatures characteristic of natural maturation 

may result in a corresponding reduction in immiscible-oil 

generation. The same processes and mechanisms may 

thus be operative in hydrous pyrolysis and natural 

maturation, but the amount of oil generated and expelled 

by hydrous pyrolysis may to some degree be exaggerated. 

An implication of this assessment is that thermally 

immature rocks incapable of generating and expelling oil 

in hydrous pyrolysis experiments are definitely incapable 

of becoming effective source rocks in nature. 

Thermochronologlc Constraints on 

Relation Between Extensional Geometry 

of the Northern Grant Range and 

Oil Occurrences in Railroad Valley, 

East-Central Nevada 

Karen Lund, L. Sue Beard, L.W. Snee, and 

William J. Perry, Jr. 

Geologic mapping in the northern Grant Range, 

east-central Nevada, has resulted in a new model for 

Neogene crustal attenuation in the Grant Range and 

adjacent Railroad Valley and for petroleum generation 

in Railroad Valley. During attenuation, source rocks in 

the upper plate may have undergone maturation and 

release of hydrocarbons due to juxtaposition of hotter 

mid-crustal lower plate rocks against the cooler upper 

plate rocks. Thermochronology, which shows the timing 

of heating and subsequent cooling of metamorphosed 

mid-crustal rocks, enables us to test whether generation 

of petroleum by heating of upper-plate source rocks 

coincided with cooling of the lower plate after Neogene 

tectonic thinning. 

In the northern Grant Range, a stacked set of 

curviplanar low-angle attenuation faults formed as the 

range arched about a north-northwest axis and as a 

structural basin formed in Railroad Valley to the west. 

The style and amount of attenuation were controlled by 

lithologic character and structural depth of rock units 

and, locally, by the geometry of the arch. On the steeper 

west side of the Grant Range arch, the curviplanar 

low-angle attenuation faults converge into a single westdipping low-angle fault zone. Along this zone, unmetamorphosed Mississippian units are juxtaposed over lowto medium-grade metamorphosed Middle Cambrian 

units and Late Cretaceous granite (fig. 1), creating the 

greatest amount of attenuation in the range. The distinct 

geometry of the arched curviplanar low-angle fault array 

is seen in windows into the structure low on the west side 

of the range. 

Seismic and drill-hole data suggest that the lowangle attenuation faults in the range extend into Railroad 

47 

Valley and control the structure buried in the valley. Both 

petroleum source and reservoir rocks in Railroad Valley 

oil fields are located in extensively fractured rocks in the 

upper plate of the major low-angle attenuation fault 

system. In the valley, as in the range, relatively cold upper 

plate rocks, immature with respect to hydrocarbon 

generation, were brought into contact with hotter lower 

plate rocks by extensional processes. Evidence for Neogene heat in metamorphic lower plate rocks is indicated 

by static mineral growth that overprints earlier dynamothermal metamorphic fabric. In addition, preliminary 40 ArP9 Ar thermochronologic results show that the dynamothermal metamorphism occurred in Late Cretaceous, 

but the thermal pulse associated with the secondary static 

mineral growth began in Oligocene. Protracted cooling 

of the hot lower plate and transfer of heat to the upper 

plate allowed maturation of upper plate source rocks. 

Oil and Gas-Where in the 

World and Why 

C.D. Masters 

From the inception of the World Energy Resources 

Program of the USGS, one of our most important 

objectives has been to identify new areas that might make 

a difference in available supplies of world oil and gas and 

to determine possible supply quantities that might derive 

from specific areas. Overall, our studies suggest that the 

occurrence of ultimate world oil resources (including 

Cumulative Production, Identified Reserves, and 

Undiscovered Resources) will be about 2,100 billion 

barrels (BB) and for gas, about 10,000 trillion cubic feet 

(TCF). From a Btu perspective (6,000 fe /barrel of oil), 

these resource numbers show more oil than gas. This is a 

surprising outcome in that, worldwide, we can expect to 

recover about 80 percent from a gas reservoir, whereas 

33 percent is an approximate average recovery for oil 

reservoirs; further, conventional wisdom suggests that 

more geologic opportunities exist for gas source rock 

than for oil. An explanation of these seeming 

contradictions may be in the enormous gas deposits 

found under unconventional circumstances as well as in 

the recognition that gas requires better sealing properties 

to hold it in place. The fact that the gas resource is less 

well developed than is the oil (80 percent of the ultimate 

oil resource has been discovered compared to only 60 

percent of the gas) offers room for continued adjustment 

of the ultimate resource proportions, but we judge that 

the two resources will ultimately be found to occur in 

approximately equal quantities. 

This amount of oil and gas is enormous relative to 

annual use: Identified Reserve to Production ratios 
~ 

<» 

WEST 

;; 

c;: 

..... o c;:> 

coc: 

'-CO 

c.9U 

N 

~ 

GRANT RANGE 

0 1 MILE I I 

EXPLANATION 

.......... 

. . . . . . . . . 

EAST 

I I Alluvial and colluvial deposits (Quaternary) l··n ...... . . . . . . ...... Simonson Dolostone (Middle Devonian), Sevy Dolostone (Lower Devonian), 

Laketown Dolostone (Silurian), and parts of Ely Springs Dolostone 

(Upper Ordovician) I P G -, 

Horse Camp Formation (Pliocene and Miocene), volcanic rocks undivided 

(Oligocene), and parts of Sheep Pass Formation (Eocene and Paleocene) 

Granite (Late Cretaceous) 

E~y Limestone (Pennsylvanian), Chainman Shale (Upper and Lower Mississippian), and parts of Joana Limestone (Lower Mississippian) 

Parts of Joana Limestone (Lower Mississippian) and Guilmette Formation 

(Upper and Middle Devonian) 

I ...... ~ -~ 

....... 

....... 

~ ~ "" "" "" I "" ~ 

Parts of Ely Springs Dolostone, Eureka Quartzite (Upper and Middle 

Ordovician), and upper parts of Pogonip Group (Middle Ordovician) 

Pogonip Group (Middle and Lower Ordovician) variably metamorphosed 

~=====E=3:fl Metasedimentary rocks (Upper and Middle Cambrian) 

------ Contact 

------ Attenuation fault-Dashed to indicate extent of fault above present surface 

or where inferred; barbs indicate movement 

/t: Trace of cleavages I'-' 

Figure 1 (Lund and others). Cross section showing tectonic relations in the northern Grant Range, east-central Nevada. No vertical exaggeration. Subsurface 

information generalized from drill-hole data, 1988 study of Veal and others. 
EXPLANATION 

Realms 

I I 

Boreal 

11111111 

Tethyan 

wa1 

South 

Gondwana 

~~ 

Pacific 

Resources 

Major • 

• Moderate 

Figure 1 (Masters). Geographic distribution of the four petroleum realms of the world showing the percent amount of 

discovered oil and gas in each realm. Also shown are the locations of the major and moderate occurrences of world petroleum. 

exceed 50:1 for oil and 60:1 for gas. Quantity, however, is 

not so much an issue as is the distribution of the 

resources relative to market. Seventy-five percent of the 

world's ultimate recoverable oil and gas is concentrated 

in the Middle East, the U.S.S.R., and North America. 

From an historical perspective, North America clearly is 

rich, but the data also show that we have been far and 

away the heaviest users of oil and gas and are, in turn, the 

most mature in its development and extraction. We have 

now reached a stage wherein our demand for oil far 

exceeds our capability to produce, and for best market 

terms we should prefer a wide spread of foreign 

suppliers. According to our resource analyses, such a 

broad supply base at present exists in oil and, given 

judicious changes to more broadly based gas resources, 

we can expect to benefit from a diversity of supply 

sources, but only for a couple of decades. Then, world 

supply will become increasingly, and more narrowly, the 

purview of the Middle East. 

This scenario assumes that the distribution of 

world oil and gas has been established. We believe that to 

49 

be true, for both statistical and geological reasons. For oil 

and gas to occur at all, five commonly independent 

variables, including source rock, reservoir rock, trap, 

seal, and timing, all must be positive; and for oil and gas 

to occur in large quantities, one or more of those 

variables must be unusually favorable. Given these 

requirements, we expect oil and gas to be distributed 

sparingly and only rarely present in large quantities. In 

the 12 years of our program geological studies, we have 

found confirmation of this statistical probability and we 

do not expect the discovery of any large new basins that 

would significantly alter the distribution of world oil. 

To explain the distribution of petroleum as we 

interpret it, two members of our World Energy 

Resources Program, Gregory Ulmishek and Doug 

Klemme, propose as a working hypothesis that paleoclimate and tectonics play such a predictable role in the 

generation and entrapment of oil that we can define four 

realms of petroleum occurrence (fig. 1): the Tethyan 

Realm, the Boreal Realm, the South Gondwana Realm, 

and the Pacific Realm. Three of the necessary 
independent variables to the occurrence of petroleum 

are climate controlled. (1) Source-rock-producing 

organisms occur in relatively greater quantities in 

equatorial waters between the 30° paleolatitudes, north 

and south; also, in low latitudes, the absence of lake 

turnover precludes an otherwise annual oxidizing event, 

thereby contributing to source rock development. (2) 

Carbonate reservoirs, which compose 50 percent of 

petroleum reservoirs, develop in significant quantities 

only in low latitudes. (3) Salt, the best of all sealing 

materials, forms mainly between the 30° latitudes, north 

and south. The identified Tethyan Realm enjoyed this 

geographic position throughout geologic history and is 

responsible for 68 percent of the world's discovered oil 

and gas. The geographic elements of the Boreal Realm 

passed Paleozoic time in the low latitudes before 

migrating into the temperate region. Except for the 

Upper Jurassic source rocks, which were deposited 

during an abnormally warm time, dominant source rocks 

in the Mesozoic and Cenozoic are gas prone; the Boreal 

Realm is responsible for 23 percent of the world's 

discovered oil and gas. The continental fragments of 

South Gondwana did not experience a move into 

equatorial waters until the Early Cretaceous, and most of 

its oil and gas, constituting 4 percent of the world's 

discovered total, is associated with Mesozoic and Cenozoic sedimentary rocks of passive continental margins. 

The Pacific Realm, through tectonic action, 

destroyed most of the sedimentary column below the 

Miocene and enriched the younger reservoir rocks with 

volcanic clasts and matrix. Windows of favorable rock, 

however, survived locally, and the Pacific Realm accounts 

for 5 percent of discovered oil and gas. 

Estimates of Undiscovered Resources suggest that 

the proportional distribution of the oil and gas assigned 

to the four different realms is similar to that calculated 

for discovered sources. 

Sequence Stratigraphy in the Search for 

Hydrocarbons in Nonmarine Strata 

Peter J. McCabe 

Depositional sequences are produced by the 

interplay of the basic controls of climate, eustasy, and 

tectonism. Close to a shoreline, changes in relative sea 

level, produced by the interplay of eustasy and 

subsidence, are critical in determining the packaging of 

strata. For at least tens of kilometers inland from a 

shoreline, valley incision and rates of change in 

accommodation space are primarily controlled by 

fluctuations in relative sea level. Farther inland, changes 

in stratigraphic base level and rates of sediment flux 

50 

increasingly become a function of tectonism in the source 

area and of climatic change. Some terrestrial strata, such 

as those deposited in intermontane basins, clearly are not 

directly influenced by changes in relative sea level; but 

they contain unconformities of regional extent and can, 

therefore, be subdivided into sequences. However, 

climate, eustasy, and tectonism are not independent 

variables. Eustasy, for example, is controlled in part by 

global climate, but regional variations in land/sea 

geometries, controlled by eustasy, influence local 

climatic regimes. At least in theory, therefore, it may be 

possible to correlate eustatically driven sequences with 

climatically driven sequences. 

Climate is a critical factor in determining the type 

and style of terrestrial sedimentation whereas rates of 

base-level change determine the thickness and stacking 

patterns of these facies. A clear link should therefore 

exist between the geometry of stratigraphic sequences 

and the lateral and vertical variations in facies within 

them. Recent work at the USGS has related the style and 

geometry of fluvial sediments and coal deposits to 

regional sequence stratigraphic interpretations in 

Cretaceous strata of the Western United States. These 

studies suggest that laterally amalgamated fluvial 

channel-sandstones and thin coals form at times of slow 

rates of base-level rise and are coeval with marked 

forward- or backward-stepping shoreface parasequence 

geometries. More isolated channel-sandstones and thick 

coal deposits form at times of faster rates of base-level 

rise and are coeval with vertically stacked shoreface 

deposits. Our studies also suggest that the local climate 

became more seasonal during lowstands in sea level: as a 

result, some facies, such as coal, are better developed at 

highstands, whereas other facies, such as braided river 

sediments, are better developed at lowstands. 

The development of models that relate sequence 

stratigraphy to depositional facies will allow better 

correlation of nonmarine strata than is otherwise 

possible. Such models could be used to predict the size of 

fluvial and eolian reservoirs and the location of economic 

facies, such as coal and lacustrine source rocks, or the 

presence of reservoir seals, such as mudstones. These 

models will have profound impact in the search for 

hydrocarbons in nonmarine strata. 

Redefining Hutton's 

Unconformity-Geology in a 

Digital World 

William G. Miller 

The USGS (U.S. Geological Survey) is producing 

many data products and publishing them in machine 
readable form. The CD-ROM has become the method of 

choice for digital publication. Different skills are 

required to use the digital products than were required of 

the obseiVational geologists of Hutton's day, and the 

markedly different approaches of obsetVational versus 

analytical geoscience have in some instances created a 

culture clash. The differences inherent in such a clash are 

often as striking as the geological differences obseiVable 

in, for example, the sandstone beds of the Yorkshire 

coast. 

Recent releases of digital publications on CD-ROM 

vary from basic cartography in the form of digital line 

graphs (1:2,000,000 DLG) to marine sonar studies (West 

Coast GLORIA) and images from the USGS core 

library. As of this writing, two disks have been released 

from the NERSL (National Energy Seismic Library). All 

these disks are very different from each other: data range 

from simple lines and polygons (1:2,000,000 DLG) to 

complete images (West Coast GLORIA) derived from 

remote sensing data collection. The scientific community 

requires specific computer skills to use the new digital 

products; management requires specific computer skills 

as well, to judge the quality of the USGS products and 

assess their utility in generating derivative products. 

Understanding the spatial resolution of the digital 

data and its intended use is important in assessing the 

data set's utility. For example, data points plotted on a 

map produced from the 1:2,000,000 DLG data may not 

plot in the State or county expected when displayed at a 

scale of 1:24,000. This mismatch of the data with its 

anticipated use will lead some to conclude that digital 

mapping is not worth the effort. Digital map production 

will be readily accepted by those who take this kind of 

information into account. 

Equipment must be matched with the intended use 

of the products. As examples of insufficient equipment, 

(1) a 9-pin dot matrix printer of the type commonly 

attached to personal computers will not produce a 

product of publication quality. (2) A 24-bit true color 

image cannot be usefully displayed on a 4-bit EGA 

adapter of a personal computer. (3) The 30-megabyte 

disk is insufficient to meet the 20,000 megabyte storage 

requirement for the TIGER data from the U.S. Bureau 

of the Census (digital cartographic data from the 1990 

census). Many USGS digital products are indeed usable 

on a personal computer; but most, to be used to full 

advantage, require more advanced hardware and 

software than generally available on personal computers. 

Budgets need to be adjusted to absorb the costs of 

the new information-producing technologies. For 

example, a common necessary decision is whether to 

gather more obsetVations in the field or provide a larger 

disk for a computer. A balance to strive for allows the 

gradual evolution of the installed computer hardware 

base without sacrifice of other aspects of a project: at 

51 

some phases of project completion, a technician is more 

useful than is a scientist. The skill level required to 

operate many computer systems may require months of 

training and practice to master, and scientists as such are 

often unable to invest the time required to master 

complex computer tools and produce complex products. 

Recognizing the virtues and limitations of digital 

techniques and their products will help establish realistic 

expectations for their use. Appropriately selected digital 

products can lead to enhanced productivity by increasing 

the quality of data produced by a given amount of effort. 

Digital techniques can also make it possible for a single 

individual to build upon the skills of others to perform 

tasks such as cartographic drafting that may be out of 

that individual's normal experience. Digital products are 

especially useful in situations where projects must be 

periodically repeated or the results must be passed on for 

further examination by others. 

Development of the Ellesmerian 

Continental Margin and the Brookian 

Orogeny, Alaska-A DNAG Perspective 

Thomas E. Moore, Wesley K. Wallace, 

Kenneth J. Bird, Susan M. Karl, and C. Gil Mull 

A synthesis of the geologic history of northern 

Alaska developed for the Decade of North American 

Geology (DNAG) project divides the stratigraphy of the 

region into the continental Arctic Alaska terrane and 

oceanic Angayucham terrane. The Arctic Alaska terrane, 

one of the largest terranes in Alaska, underlies the North 

Slope and most of the Brooks Range. Rocks of the Arctic 

Alaska terrane are divided, from bottom to top, into (1) 

structurally and stratigraphically complex Proterozoic to 

Middle Devonian rocks of diverse affinity; (2) a laterally 

extensive succession of uppermost Devonian and Lower 

Mississippian to Lower Cretaceous nonmarine to marine 

passive continental margin deposits (equivalent to the 

Ellesmerian sequence); and (3) upper Mesozoic and 

Cenozoic siliciclastic foredeep deposits (Brookian 

sequence). The pre-uppermost Devonian rocks 

apparently record early to middle Paleozoic convergent 

deformation and plutonism along the edge of North 

America, which was followed by rifting in Devonian time. 

The Devonian rifting event culminated in formation of an 

ocean basin and paleogeographically complex southfacing Ellesmerian passive margin by Late Devonian 

time. Subsidence along the passive margin resulted in (1) 

progressive northward onlap of nonmarine and 

carbonate platform deposits in Late Devonian and 

Mississippian time and (2) deposition of neritic to 

bathyal sediments in Mississippian to earliest Cretaceous 
time. The neritic to bathyal deposits are characterized by 

a southward increase in abundance of condensed basinal 

deposits. A second rifting event culminated in opening of 

the Canada basin in Early Cretaceous time and produced 

the Barrow arch and the modern northern continental 

margin of Alaska. 

. The Angayucham terrane, exposed in isolated klippen m the Brooks Range and beneath Jurassic to Lower 

Cretaceous volcanic-arc rocks of the Koyukuk basin to 

the south, structurally overlies the Arctic Alaska terrane. 

The Angayuch~m terrane consists of two subparallel, 

alloc~thonous lithotectonic assemblages, both of oceanic 

affimty. The structurally lower assemblage consists of 

imbricated Devonian to Jurassic ocean-island basalts and 

pelagic sedimentary rocks, whereas the structurally 

higher assemblage consists of ultramafic and gabbroic 

rocks of a Middle Jurassic ophiolite. Rocks of the lower 

unit were metamorphosed to amphibolite facies along 

the base of the ophiolitic assemblage in Middle Jurassic 

time. The Angayucham terrane is interpreted to 

rep~es~nt an accreted subduction complex and overlying 

ophiOlite that formed the forearc region of a Middle 

Jurassic volcanic arc in the ocean basin adjacent to the 

Ellesmerian continental margin. 

The Brookian orogeny began in the Middle and 

Late Jurassic with southward subduction and closure of 

the part of the Angayucham ocean basin that lay 

outboard of the south-facing passive margin of the Arctic 

Al~ska terrane (fig. 1A ). Fragments of the upper PaleoZOIC and lower Mesozoic oceanic upper crustal rocks 

were underplated by subduction beneath an intraoceanic 

~rc and ophio~ite and locally metamorphosed amphibolite, thus formmg the Angayucham terrane and overlying 

Koyukuk arc .terrane (fig. lB). ~n Late Jurassic and Early 

Cret~ceous time,. the outer (distal) south-facing passive 

contmental margm succession of the Arctic Alaska terrane was partially subducted and underplated beneath 

the Angayucham terrane (fig. 1C). Northward thrust 

imb~ication sequ~ntially placed more distal parts of the 

contm~ntal margi.n over its more proximal parts (fig.lD). 

· T~e axis of associated Brookian foredeep sedimentation 

mtgrated northward with the thrust front such that older 

fore~eep deposits were involved in later thrusting. The 

contmental substructure of the continental margin of the 

Arcti~ Al~ska terr~e was subducted to deeper levels, 

resultmg m tectomc thickening (fig. lE) and highpre.ssure-low-tem~erature metamorphism (blueschistfacies metamorphic rocks). By Albian time, the rate of 

un~erthrust.ing diminished, and the orogenic belt was 

~aptdl~ uplif~ed and unroofed, resulting in setting of 

Isotopic coohng ages and deposition of huge volumes of 

Brookian clastic detritus southward into the hinterland 

(Koyukuk basin) and northward into the foredeep 

(Colville basin) (fig. lF). Latest Early Cretaceous downto-the-south, low-angle normal faulting in the southern 

52 

Brooks Range contributed significantly to this unroofing 

and uplift and overlapped in time with the formation of 

the extensional northern Alaska continental margin. 

Subsequent Late Cretaceous and early Tertiary Brookian 

orogenesis resulted in deformation of the southern 

Colville basin. Deformation has continued to the present 

in the eastern Brooks Range, where thrusting and foredeep deposition have migrated northward into the 

offshore region. 

Turbidity-Current Processes and 

Turbidite Elements-What You Get 

Is Not What You See 

William R. Normark 

Turbidity-current processes generally are deduced 

from the physical properties of their conduits and their 

deposits, from laboratory experiments, or from 

observations of shallow-water flows in deltaic 

environments, because direct observation of turbidity 

currents in a deep-water marine environment has eluded 

even the most clever and optimistic would-be discoverer. 

The available data are thus generally restricted to a 

limited scale range (outcrops and laboratory flumes, 

shallow-water deltas), or lack resolution of both morphometric characters and bedding features (deep-water 

marine basins). As a result, existing models tend to 

underesti~ate the range in flow properties of turbidity 

currents m the deep sea. Analogies with subaerial flow 

proc~s.ses may provide an intuitive understanding of 

turbidity currents but can also reinforce the conservative 

view of what they can do. For example, bankfull flow for 

rivers indicates near-maximum flow thickness, but in 

turbidity currents, flow thickness apparently can greatly 

exceed channel depth based on observations of sediment 

distr!b~tion and key bedform indicators. Average-size 

turbidity currents overflow and build levee relief; larger 

flows can erode overbank areas. Flow thickness alone 

cannot be used to predict depositional conditions; sandy 

turbidity currents are in general thinner and faster, and 

muddy flows thicker and slower; thus, the sandier flows 

remain channelized. 

The effect of basin morphology differs between 

turbidite systems formed on oceanic crust and those in 

Figure 1 ~Moore and others) (fa~ing page). Development of 

the Brook1an orogeny; am, amphibolite; bs, blueschist-facies 

metamorphic rocks. Heavy line, fault; dashed where inferred· 

barb shows direction of relative movement. A, Middle Juras~ sic; 8! Late Jurassic; C, early Early Cretaceous (Berriasian); 

0, m1ddle Early Cretaceous (Hauterivian); E, late Early 

Cretaceous (Aptian); F, latest Early Cretaceous (Albian). 
SOUTH 

A 

8 

Angayucham ocean 

NORTH 

latest Devonian to Jurassic 

passive-margin sequence 

distal roximal 

• • Arctic Alaska terrane • + +++++++++ 

pre-Upper Devonian rocks 

+++++ ++ +++++++++++ 

• • • • • • • • • Arctic Alaska terrane • • • • • • • • 

53 

Canada 

basin 

spreading 

center 

Canada 

basin 
continental-margin slope basins. In the deep ocean, 

turbidity currents can rapidly bury extensive ~reas ~f 

low-relief abyssal hills. In general, coarse sediment IS 

deposited close to the termination of a channel as the 

rapidly spreading and thinning currents lose competency 

upon leaving the confines of the channel. Deep-water 

turbidite systems are therefore fan shaped, and the size 

and position of channel and lobe elements evolve through 

autocyclic controls. That is, depositional relief from 

previous turbidity currents greatly influences the fan 

growth pattern. Within narrow and elongate continentalslope basins, the larger turbidity currents spread laterally 

until they reach the basin walls, which confine the flow 

and maintain flow thickness and competence. In such an 

environment, much coarse sediment can be carried far 

into the basin, well beyond the end of channel features, 

and form classic tabular-bedded lobe deposits. 

The effects of (1) turbidity-current size and (2) 

grain-size distribution of suspended sediment in the flow, 

coupled with (3) effects of both basin and local 

(turbidite-formed) morphologic relief on the evolution of 

the flow produce a tremendous range in flow properties. 

If models of flow do not reflect this heterogeneity, they 

can lead to incorrect interpretation of the depositional 

environment (position within the basin and relation to 

source area). To improve models of turbidity-current 

flow that rely on observations of their deposits, we must 

focus on specific mappable features, that is, turbidite 

elements. Channel-fill, overbank, and lobe deposits are 

elements produced by deposition and (or) erosion from 

many events over periods of 104 years or longer. Largescale scours and megabeds are elements produced by 

single events. These five features are examples of the 

more common turbidite elements. Similar elements from 

different sequences can be compared to derive common 

flow properties, if the effect of scale differences among 

the examples is considered. An improved understanding 

of depositional environments of turbidite facies and basin 

analysis requires improved models of turbidity current 

initiation and flow evolution. 

Controls on Gas Generation and 

Production, Tight Sandstone Reservoirs, 

Uinta Basin, Utah 

Vito F. Nuccio, James W. Schmoker, and 

Thomas D. Fouch 

Uinta Basin rocks include a thick sequence of 

low-permeability (tight) sandstones that contain a large 

volume of gas. Most known gas accumulations occur in 

the eastern part of the basin in the Upper Cretaceous 

Mesaverde Group, uppermost Cretaceous to lower 

54 

Eocene North Horn Formation, and the Paleocene and 

Eocene Wasatch, Colton, and Green River Formations. 

Although the majority of tight-gas completions are in 

Tertiary strata, rocks in the underlying, sparsely drilled 

Mesaverde Group in the north-central part of the basin 

are potential targets as well. To characterize t~e gasbearing sandstones, we constructed a senes of 

interrelated maps and cross sections showing vitrinite 

reflectance (thermal maturity), porosity, lithofacies, and 

fluid pressure relations for the Uinta Basin. 

Vitrinite reflectance (Rm) for each of these lowpermeability sequences increases to the north. Levels of 

thermal maturation for the Mesaverde Group are 

sufficient for gas generation over large areas of the basin. 

Values for Rm at the base of the Mesaverde (fig. 1) 

increase from 0.65 percent at shallow depths along the 

south edge of the basin to 1.5 percent in the central basin 

at depths of about 11,000 ft (3,350 m). At the top of the 

Mesaverde (fig. 2), Rm values increase from 0.50 percent 

at outcrops along the south edge of the basin to 2.2 

percent near the town of Altamont, at depths of 

approximately 18,000 ft (5,500 m). . . 

Porosity-versus-Rm plots allow prediction of 

porosity for Mesaverde sandstones in unexplored areas 

of the basin. Porosity values of nonmarine Mesaverde 

sandstones with thermal maturity less than about 0.70 

percent Rm or greater than roughly 2.0 percent Rm 

decrease as thermal maturity increases, and follow 

"normal" sandstone trends. However, between 0.70 

percent Rm and 2.0 percent Rm, in the window of 

hydrocarbon generation, porosities do not decrease as 

thermal maturity increases (fig. 3). Overpressured, gassaturated Mesaverde sandstones are likely to have 

porosities in the 5-9 percent range. . . . 

Lithofacies is directly related to reservOir quahty m 

the tight gas sequences of Uinta Basin. In Tertiary and 

Cretaceous formations, by far the best reservoir rock 

quality is found in diagenetically altered (both early and 

late diagenesis) fluvial sandstones (figs. 4, 5). Other 

good-quality and economically important reservoir rocks 

are Tertiary open-lacustrine sandstones and Cretaceous 

lenticular fluvial and blanketlike marine sandstones. 

Projecting fluid-pressure and thermal maturity 

data from drilled areas of the basin into undrilled areas 

reveals the possibility of a regional, organic-rich, overpressured, basin-centered gas accumulation, wher~ gas 

generation is probably occurring at present. Pubhshed 

estimates of amounts of erosion in the region vary widely, 

ranging from 1,000 ft (300m) to almost 11,000 ft (~,350 

m). Our interpretation favors the lesser erosiOnal 

estimates, because significant cooling of strata due to 

uplift and erosion would have slowed or stopped the 

generation of hydrocarbons. Wells drilled in the Mesaverde and lower part of the Tertiary, in the areas where 

Rm at the base of the Mesaverde is greater than 1.1 
40' 30' 

40' 15' 

40' 00' 

39' 45' 

39' 30' 

39' 15' 

0 

I 

I 

0 

I 

L, 

I 

110' 45' 110' 30' 

0 

Price 

Study ~~ea 

10 

I I 

10 20 

I 

20 30 MILES 

I 

30 KILOMETERS 

109' 45' 109' 30' 109'1 5' 109' 00' 

Figure 1 (Nuccio and others). Vitrinite reflectance (Rm) map showing thermal maturity of the base of the Mesaverde 

Group, Uinta Basin, Utah. Light pattern, area of no gas generation; 0.75 percent Rm isoreflectance line and medium 

pattern, onset of significant gas generation; 1.10 percent Rm isoreflectance line and darkest pattern, maximum gas 

generation and expulsion. Dot, location of well and well samples or outcrop samples. 

55 
0 

I 

0 

0 Price 

Study ~'area 

10 

I I 

20 30 MILES 

I 

10 

I 

20 30 KILOMETERS 

Figure 2 (Nuccio and others). Vitrinite reflectance (Rm) map showing thermal maturity of the top of the Mesaverde 

Group, Uinta Basin, Utah. Light pattern, area of no gas generation; 0.75 percent Rm isoreflectance line and medium 

pattern, onset of significant gas generation; 1.10 percent Rm isoreflectance line and darkest pattern, maximum gas 

generation and expulsion. Dot, location of well and well samples or outcrop samples. 

56 
30~--~_,~-,-,~~--------,-----,---,--, 

25 

~ 10 w 9 u 8 

ffi 7 

~ 6 

~ 5 

U5 4 0 

~ 3 Q_ 

2 

25th to 75th PERCENTILES 

1L_ __ L_ __ L__L __ L_~~------~----~--~~ 

0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.5 2.0 2.5 3.0 

VITRINITE REFLECTANCE, IN PERCENT 

Figure 3 (Nuccio and others). Porosity versus vitrinite 

reflectance for middle range of core-plug porosity values, 

nonmarine sandstone intervals of Mesaverde Group, Uinta 

and Piceance Creek basins. Vertical lines connect 25th and 

75th porosity percentiles. Type curve and 10th and 90th 

porosity-percentile trend lines provide a reference framework 

that represents sandstones in general. 

Figure 4 (Nuccio and others). Paleogeographic map of 

rocks near the boundary between the Paleocene and Eocene 

in the Uinta Basin. Oil and gas are produced from marginallacustrine rocks in this zone in the north-central part of the 

map area; gas is recovered from Wasatch Formation alluvial 

units in the east-central part of the basin. 

57 

I 

I 

I 

I _r 

~-or~_: . · · <::: MOUNTAIN c o FRONT. 

....:_FANS I 

·61 .o I 40" . · 8 o BRAIDPLAIN 1 

o ley . . 1 

6 o ~~ r 

~L-!>rice -'---.:: ____ 1 .s:>.r~_. · !:li,,.. ~"' -~-, ...,,. J:;; 

Or-?]. 

0 Price ~~01) 

10 20 

I I I I I 

0 10 20 30 KILOMETERS 

109° 

Figure 5 (Nuccio and others). Restored paleogeographic 

map of Mesaverde Group rocks during the latter part of the 

Campanian. Gas-bearing rocks of this zone have been 

identified east of the Green River and are believed to underlie 

much of the north-central part of the basin. 

percent, should have the best potential for gas 

production. Overpressured gas reservoirs (Rm > 1.1 

percent) are likely to have no free water and to be 

surrounded by successive zones of mixed water and gas 

(Rm 1.1-0.75 percent), and of water only (Rm < 0.75 

percent). 

The Desktop Core Library, 

A CD-ROM Approach 

Michael P. Pantea, Frances E. Gay, and 

Russell A. Ambroziak 

The U.S. Geological Survey, through the Core 

Research Center in Denver, Colo., maintains a rock core 

repository containing rock core, thin sections, and core 

information. Most of the collection comes from oil and 

gas provinces in the central region of the United States. 

Other geologic localities in the United States and some 

international material are also represented. In order to 

catalog, archive, and distribute core information, we are 

creating a digital library of the rock core and core 

information housed at the Core Research Center. 

Publicly available information will be distributed on 

Compact Disk-Read Only Memory (CD-ROM) 

through government distribution centers. 

A CD-ROM sampler, prepared in association with 

the Core Research Center, was designed to help 
geologists, researchers, and students become familiar 

with the U.S. Geological Survey's Core Research Center. 

It presents a way to distribute pictures of rock core and 

thin section, and core information to a larger audience. 

This sampler contains rock-core, thin-section, and welllog pictures, as well as index and surface-geology maps, 

and text information about the wells and core. Text 

information is the header file for a well and often 

includes Township, Range, and Section, total depth, and 

formation picks. All data are displayed using software 

provided on the CD-ROM. Due to the volume of data 

being provided, the minimum computer configuration we 

recommend is an IBM or compatible 80386 PC with 

640KB RAM, MS or PC-DOS 3.3 or later, a VGA 

graphics system capable of displaying 640 x 480 pixels x 

256 colors, and a CD-ROM reader and software capable 

of reading ISO 9660 standards. 

Program features are accessed using a series of 

menus. An index map can be displayed showing either 

surface geology or icons marking well locations. Menu 

choices for use with the map allow display of: 

- Latitude and longitude for any spot on the index map 

- Primary and secondary roads, streams, lakes, and 

railroads 

- County boundaries 

- A zoom feature for detailed viewing of a portion of 

the index map 

Once a well location is chosen from the index map, 

additional information about that well is available and 

includes: 

- Well header information 

- Photo images of rock core 

- Photo images of thin sections 

- A zoom feature to allow detailed viewing of the rock 

core and thin-section photo images 

Description of data types.-Twenty-one cores from 

Colorado were selected for this demonstration CDROM. These cores come from the Denver basin, the Las 

Animas arch, the Paradox basin, the Piceance Creek 

basin, the Axial Basin uplift, and the Sand Wash basin. 

,The rocks range from Cretaceous through Cambrian 

ages, as identified from well records (current 

terminology shown in brackets), and include: 

- Cambrian carbonate rocks from the Arbuckle 

Formation [Arbuckle Group] 

- Devonian sandstones from the Elbert and 

McCracken Formations [McCracken Sandstone 

Member of the Elbert Formation] 

- Devonian limestone rocks from the Ouray Formation 

[Ouray Limestone] 

- Mississippian dolomite from the Leadville Formation 

[Leadville Dolostone) 

- Pennsylvanian carbonate rocks from the Lansing, 

Marmaton, Morrow, and Virgil Formations, and 

from the Desert Creek Member of the Paradox 

58 

Formation [Lansing and Marmaton Groups, Morrowan and Virgilian rocks, and the Desert Creek zone 

of the Paradox Formation] 

- Permian mudstones from the Phosphoria Formation 

- Cretaceous Dakota Sandstone siltstones from the 

Lewis Formation [Lewis Shale] 

Futureplans.-This CD-ROM sampler attempts to 

distribute rock core information to the public. It is the 

authors' intent that this product evolve and be of use in 

education and research, so comments and recommendations are encouraged. Other plans include 

migrating this product to the Macintosh platform, and 

creating CO-ROMs of the frequently viewed core and 

requested information at the Core Research Center. 

Comments and recommendations are welcome 

and can be addressed to the authors at: 

U.S. Department of the Interior 

U.S. Geological Survey 

Re: Open-File Report 91-355 

Mail Stop 975 

Box 25046, Denver Federal Center 

Denver, CO 80225-0046 

Copies of the CD-ROM sampler OF 91-355 can be 

obtained from the same address or: 

Books and Open-File Reports 

U.S. Department of the Interior 

U.S. Geological Survey 

Box 25425, Denver Federal Center 

Denver, CO 80225-0046 

Petrography and Rock-Eval Studies of 

Organic Matter in Precambrian Rocks, 

U.S.A. and U.S.S.R. 

Mark Pawlewicz and James G. Palacas 

Vitrinite-like particles were isolated from three 

widely scattered Precambrian terrains: the Late Proterozoic Chuar Group, Grand Canyon, Arizona, and the 

Middle Proterozoic Keweenawan Group (Nonesuch 

Shale equivalent), Midcontinent Rift System (MRS), 

western Iowa, and from the Vendian-Riphean rocks in 

the Lena-Tunguska Province, eastern Siberia, U.S.S.R. 

The samples were extracted with chloroform to remove 

soluble solid bitumen or exogenous hydrocarbons. Some 

of the remaining material, examined in reflected light, is 

indistinguishable from post-Silurian vitrinite-group macerals. The particles of organic matter are angular pieces, 

with a slight expression of internal cellular structure. In 

addition, in whole-rock samples the distribution of the 

organic matter was as isolated particles, disassociated 
from any bedding feature or mineral fabric, suggesting a 

nonbitumen macromolecular entity. 

With few exceptions, reflectance (Rm) values of the 

vitrinite-like particles agree with Rock-Eval pyrolysis 

Tmax values, providing a measure of validity to the 

reflectance measurements. Maturity values ranged from 

immature or marginally mature with respect to liquid 

hydrocarbon generation for some of the eastern Siberian 

samples (average 0.42 percent Rm, Tmax =432 °C), to 

mature for the Chuar Group (Kwagunt Formation) 

(average 0.73 percentRm, Tmax =437 oc), to overmature 

for the MRS (Keweenawan) rocks (average 2.2 percent 

Rm, Tmax =503 °C). 

The above factors taken together demonstrate that 

the reflectance technique can be extended to Precambrian rocks for determination of thermal maturation 

levels. 

Architectural Analysis of Eolian 

Sandstones-The Lower Jurassic 

Nugget Sandstone of Northeastern Utah 

Fred Peterson and C.J. Schenk 

The Lower Jurassic Nugget Sandstone is a 

heterogeneous eolian reservoir rock that produces oil 

and gas in the southern part of the Overthrust Belt of 

southwestern Wyoming and adjacent Utah. The purpose 

of this study is to examine the three-dimensional sedimentologic heterogeneity of the Nugget in excellent 

exposures near Vernal, Utah. The chief architectural 

elements in the formation are cross-stratified eolian dune 

sandstone and wavy to irregularly stratified sabkha 

sandstone. Corrugated surfaces, formed by differential 

erosion of crossbedded sandstone, are fairly common 

marker horizons in parts of the formation. The Nugget 

Sandstone is about 277m (910ft) thick in the study area 

and is divided into two informal members. 

The lower member is 42 m (137 ft) thick and 

consists of about equal amounts of sabkha sandstone and 

small-scale crossbedded eolian dune sandstone. Poor 

permeability of the sabkha sandstone indicates that these 

beds are effective barriers to fluid flow and make the 

lower member a poor reservoir rock. 

The upper member, about 236m (775ft) thick, is 

an important reservoir rock in the Overthrust Belt, 

although the distribution of architectural elements 

results in significant reservoir heterogeneity. The lower 

76 m (250 ft) of the upper member has large troughshaped sets of cross-strata more than 24m (80ft) thick 

and about 305m (1,000 ft) wide perpendicular to paleowind direction. Poor to moderate permeability of dune 

apron deposits (composed largely of eolian ripple strata) 

59 

at the base of the large troughs laterally and vertically 

compartmentalizes the permeable eolian dune crossstrata. The overlying 46 m (150ft) of the upper member 

consists of tabular-planar sets that are generally less than 

6 m (20 ft) thick. Apron deposits composed of eolian 

ripple strata form the main impediment to fluid flow in 

this zone. The upper 114m (375ft) of the Nugget is the 

most complex in terms of eolian architecture. This part of 

the formation consists of cross-stratified sandstone 

divided vertically into tabular-planar units by thin sabkha 

beds, generally less than about 1 m (3 ft) thick, or by 

corrugated surfaces, which are the lateral continuation of 

the sabkha beds in many cases. The bedding within the 

tabular units may consist of a single tabular-planar set or 

it may consist of a complex coset of troughs and tabularplanar sets. The apron deposits tend to impede fluid flow 

whereas the sabkha beds are effective barriers to fluid 

flow. The result is a reservoir that is vertically 

compartmentalized by the sabkha beds and is further 

complicated, both laterally and vertically, by the apron 

deposits in the tabular sandstone units that consist of 

complex cosets. 

Relation of Natural Fractures to 

Composition and Cyclicity in Chalk of the 

Niobrara Formation, Berthoud Field, 

Colorado 

Richard M. Pollastro 

Basic bulk composition was determined from acidinsoluble residue and acid-soluble carbonate contents of 

148 samples from core representing the entire section of 

the Upper Cretaceous Niobrara Formation in the 

Coquina Oil Corp., Berthoud State No. 3 well, Berthoud 

field, Larimer County, Colorado. The Smoky Hill Chalk 

Member comprises mostly impure chalks that contain, on 

average, about 30 wt. percent insoluble residue; the basal 

Smoky Hill, however, contains purer chalk beds. The 

underlying Fort Hays Limestone Member contains the 

purest chalk beds, some containing as little as 5 wt. 

percent insoluble residue. In the Berthoud State No. 3 

well, fracturing may be related to basic bulk composition; 

contrast in bed composition and thickness of interbedded 

chalk and shale beds may be important in understanding 

fracturing within the Niobrara Formation. 

Acid-insoluble residue and carbonate contents of 

the Niobrara Formation in the Berthoud State No. 3 well 

represent cyclic variations that correspond to large- and 

small-scale alternations of chalk and shale. Large-scale 

cyclicity that produced the major chalk and shale zones in 

the Niobrara Formation is related to second-order 

eustatic changes within an overall major transgressive 
WEIGHT PERCENT WHOLE ROCK 

0 20 40 60 80 100 

~ 1 

MJr 

vvv 

'VVI 

1-

w a: 

w w 

LL m 

:E ~ 

~ 2 

~ 

z 

:I: c 1-

c. z 

w c:( 

c w 

w z 

..J 

13 

0 

c. N 

:E w c:( 

C/) a: 

~ 

w 1-

a: 0 

0 c:( 

0 a: 

LL 

tff4 

A 

·~ 5 

8 

EXPLANATION 

0 INSOLUBLE RESIDUE 

0 CARBONATE 

Figure 1 (Pollastro). Insoluble residue and carbonate 

contents of the Niobrara Formation and numbered fracture 

zones in the Coquina Oil Corporation, Berthoud State No. 3 

well. Bold line A connects insoluble residue maxima, and 

bold line B connects carbonate content maxima. Note largeand small-scale cyclicity of insoluble- and carbonate-rich 

zones and the correlation between intervals of fractures and 

intervals of maximum difference in insoluble residue and 

carbonate contents (greatest separation of lines). Well depths 

in feet. Dashed line indicates 50 wt. percent insoluble residue 

and 50 wt. percent carbonate. 

event. Similar large-scale cyclicity of organic matter 

content in the nearby Coquina Oil, Berthoud State No. 4 

well generally correlates with insoluble-residue content. 

Smaller third-order cyclicity of beds, superimposed on 

the large-scale cycles, is related to climatic changes due 

60 

to Milankovich-type variations in the Earth's orbital 

patterns. 

Five fracture zones, four relatively minor in 

intensity (that is, size and space), are identified in core of 

the Berthoud State No. 3 well (fig. 1 ). Each of the 

fracture zones occurs in the upper half of a thick chalk 

unit that is immediately overlain by a thick shale. These 

thick chalk and shale units correspond to second-order 

eustatic changes that define the main lithologic units of 

the Niobrara Formation. Vertical fractures terminate 

within the overlying shale sequences. 

The major and most intense zone of fracturing 

occurs in the lower midportion of the formation. This 

zone shows evidence for extensive solution of carbonate, 

fluid movement, displacement, and related structural 

deformation. This 35-40 ft interval, informally referred 

to here as fracture zone 3, contains several beds of chalk 

with relatively low ( < 20 wt. percent) acid-insoluble 

content that are interbedded with shale having high (>50 

wt. percent) acid-insoluble content (fig. 1). The secondorder cycle curve for the Niobrara, as defined by the data, 

is shortened (thinner units) within this interval. This 

interval of major fracturing is also characterized by high 

electrical resistivity. Fracture zone 3 is bounded by two 

large spikes on the gamma-ray log at about 3,060 ft and 

3,140 ft. Fracture zone 3, however, corresponds to a 

cyclic low in the organic-matter profile for the nearby 

Berthoud State No. 4 well. 

Fractures in Niobrara strata of the Berthoud State 

No.3 well appear to be related to composition, as defined 

by acid-insoluble residue and carbonate contents, and 

correspond to intervals where strata have insolubleresidue content in excess of 50 wt. percent, and where 

composition differences among the alternating strata 

over the interval approach 50 wt. percent (fig. 1 ). These 

differences or contrasts in bulk composition, as defined 

by insoluble residue and carbonate contents, probably 

produce differences in thermal and mechanical behavior 

of interbedded units that result in fractures during stress. 

These tensile fractures that are formed in extremely 

tight, deeply buried, organic-rich chalks create porosity 

and permeability required for enhanced recovery of oil 

for economic production. 

The Regional Context of Railroad Valley 

Oil-fields-An Integrated Geological and 

Geophysical Transect, East-Central 

Nevada 

Christopher J. Potter, John A. Grow, 

Karen Lund, and William J. Perry, Jr. 

The Basin and Range province of the Western 

United States presents an unusual set of exploration 
challenges, primarily because of the complex tectonic and 

thermal history of the region. The province is cut by 

myriad basin-range extensional faults that are 

superimposed on Mesozoic contractional structures, 

middle to late Paleozoic structures related to terrane 

accretion, and a Proterozoic to early Paleozoic passive 

margin. Railroad Valley and Pine Valley, the two oilproducing valleys in Nevada, are in zones of complex 

Cenozoic extensional deformation, and moreover are in 

close proximity to poorly understood regions of Mesozoic 

shortening. Detailed understanding of all these 

structures and their regional significance is essential for 

the construction of models that guide hydrocarbon 

exploration in the eastern Great Basin. We are 

conducting an interdisciplinary investigation in eastcentral Nevada along a 120-km-long, east-west transect 

at lat 38°30' N. (fig. 1 ), which includes the Railroad 

Valley oil fields and extends from the Pancake Range in 

the west to Lake Valley in the east. Our approach 

involves integration of 90 km of regional seismic 

reflection data (ECN-1 and ECN-2, fig. 1), new geologic 

mapping, well data, thermal maturation studies, and new 

gravity and magnetic data. 

Contractional structures (including overturned 

folds, thrust faults that impose older strata on younger 

strata, and others) have been reported in the ranges that 

flank Railroad Valley. Geologic mapping by Lund, Perry, 

and others suggests that these structures fall into three 

categories: (1) those that formed during regional latest 

Paleozoic(?)-Mesozoic east-west shortening, (2) those 

that may record local contraction within a Cenozoic 

extensional fault system (see Lund and others, this 

volume), and (3) Cenozoic extension faults that produce 

fortuitous stratigraphic juxtapositions, mismapped as 

thrust faults. It appears unlikely that a major continuous 

Mesozoic thrust belt is a fundamental aspect of the 

geology of Railroad Valley oil fields. 

The magnitude and style of Cenozoic extension 

vary across the transect. Railroad Valley and the Grant 

Range (fig. 1) compose a zone of nonuniform east-west 

extension ranging from 50 percent to 150 percent; a 

low-angle fault system accomplishes much of this 

extension. Immediately to the east, the southern White 

River Valley, southern Egan Range, Cave Valley, 

southern Schell Creek Range, Muleshoe Valley, and 

Grassy Mountain make up a block that has undergone 

20-30 percent east-west extension along moderately to 

steeply dipping faults. Major Cenozoic faults that strike 

obliquely across the southern Egan and Schell Creek 

Ranges may record significant extension that has no 

expression on the seismic data, as only one of these faults 

crosses the seismic line. 

In the seismic data across the Grant Canyon oil 

field of Railroad Valley (fig. 2), a gently west dipping 

normal fault appears to have controlled the development 

61 

of the asymmetric, east-tilted Neogene basin. The fault is 

clearly defined by fault -plane reflections and by 

terminations of east-dipping reflections from Tertiary 

and Paleozoic strata; this fault projects into a low-angle 

extensional fault system mapped in the Grant Range to 

the east. Complex reflection patterns in other parts of the 

hanging-wall probably correspond to chaotically faulted 

Paleozoic through Paleogene rocks similar to those 

exposed nearby in the Grant Range. Well-log data 

suggest that a steep gravity gradient along the east side of 

the valley is produced in part by steep lateral density 

gradients within the Neogene basin fill. In the absence of 

these logs, the gravity gradient and a coincident line of 

springs could have been interpreted as signatures of 

listric normal faults that cut Paleozoic rocks and merged 

into the low-angle fault at depth. Between the Grant 

Canyon oil field and the front of the Grant Range, a local 

steepening of the low-angle fault is apparent on seismic 

data and may indicate modification of the fault system by 

steeply dipping faults. Alternatively, the steep segment is 

a minor ramp on the fault system along the western front 

of the Grant Range. Other workers have interpreted a 

number of steep faults associated with Railroad Valley 

oil fields. 

East of the Grant Range, extensional structures 

appear to be simpler. White River Valley (figs. 1, 2) 

contains several east-dipping subbasins, bounded by 

moderately to steeply dipping faults. A steep gravity 

gradient occurs along the eastern margin of the 

easternmost and largest of these subbasins. This gravity 

gradient could conventionally be interpreted as the 

signature of a steep normal fault bounding a thick section 

of basin-fill; alternatively, varying physical properties 

within the basin-fill may be a significant contributor to 

the gravity signature, as in Railroad Valley. The seismic 

line passes through a homoclinal east-dipping Paleozoic 

section in the Egan Range that bounds White River 

Valley to the east. Low-angle normal faults occur in this 

range north of the seismic line, and a Late Cretaceous to 

Paleogene extensional(?) basin is exposed in the Egan 

Range and is encountered in wells in nearby valleys. 

Related structures have no obvious expression on the 

seismic data. Pennsylvanian strata exposed in the Egan 

Range can be traced, as part of a simple homoclinal 

panel, beneath Cave Valley to the east (fig. 2). Cave 

Valley contains about 1.1 km of flat-lying Cenozoic strata 

above a 0.5-km-thick, synextensional, east-dipping 

sequence, suggesting that most of the basin-fill 

accumulated after a rapid(?) early extensional phase that 

was controlled by a west-dipping fault. Muleshoe Valley 

is a narrow sag basin that has no well-defined bounding 

faults and records little extension (fig. 2). 

All the oil fields in Nevada are intimately 

associated with Cenozoic extensional structures and 

basins. Our regional synthesis provides an opportunity to 
NEVADA 

Area of 

fig. 1 

38°30'N I--

tf # 

~ 

~ 

CJ"' # Q. 

0 

115° 

I 

! - >-I~ MV 

f-< z 

Z1;:J 0 olo u 

u z ~I ,..J >-10 z ~ 

l,_l 

I 

50 KILOMETERS 

GM 

GJ-

_J 

_J 

<X: 

> 

w 

~ 

<X: 

_J 

Figure 1 (Potter and others). Location of the geologic and geophysical transect, and ranges and valleys in the study area. 

ECN-1, ECN-2, seismic lines discussed in text; GM, Grassy Mountain; MV, Muleshoe Valley. 

Southern Southern 

Grant Egan Cave Schell Ck Muleshoe 

Railroad Valley Range White River Valley Range Valley Range v 11 7o """' ~""- --=~~ a ey 0 j -;/,' ' "-"~- 7 ~?:; ' '- if/ \;--' - -o.. -- ~ 

~~!~~---- ~ ___________ '__ r~ __ _-_ V. r _____ ---~-~-~----------~-

Lake Valley 

0 5 10 KILOMETERS 

Figure 2 (Potter and others). Cross section illustrating generalized patterns of seismic reflection data and Cenozoic 

basin-range structure. White areas, Oligocene to recent sedimentary and volcanic strata; patterned area, Paleozoic, 

Cretaceous, and lower Paleogene rocks that predated basin-range extension. Black line, position of major reflection on the 

seismic data; stippled line, Cenozoic fault. Barbs indicate relative movement. 

evaluate the importance of a variety of potentially 

relevant geologic parameters (fault geometry, basin 

geometry, basin depth, uplift and sedimentation rates, 

style of brittle upper-plate deformation, involvement of 

critical source and reservoir rocks, physical properties of 

62 

basin-fill) in combination with thermal-maturation 

studies. This work wiii serve as a basis for comparison 

with other weii-studied parts of the Basin and Range 

province, and wiiJ lead to a more useful conceptual 

framework for exploration in the province. 
Huge Indigenous Oil in Mature Source 

Rocks-Beyond Elephants? 

Leigh Price 

Numerous Rock-Eval analyses of organic-rich 

source rocks in different basins show large decreases in 

hydrogen indices (HI) without concurrent increases in 

either the Rock-Eval S1 pyrolysis peak or Soxhletextractable hydrocarbons (HC). Thus, many of us 

geochemists previously concluded that primary 

petroleum migration from such rocks was very efficient, 

as almost all the generated HC's appeared to have left 

the source rocks. However, new research and 

considerations suggest an alternate possible 

interpretation. Dramatic increases in electrical resistivity 

logging values in mature organic-rich source rocks 

demonstrate large increases in indigenous HC 

concentrations with increasing maturity in these rocks. 

Further, historic drilling observations document a large 

loss of generated HC's from mature source rocks to 

drilling mud from the large pressure decreases during 

the rock trip uphole. These pressure decreases cause 

such large volume expansions of HC gases coexisting 

with generated oil in fractures in source rocks that the oil 

is literally blown into drilling muds. If source rocks are 

both unfaulted and not bounded by hydraulically 

transmissive rocks, then most generated HC's should 

remain in mature rocks, even to high maturation ranks. 

This logic carries the implication of huge in-place oilresource bases in mature, fractured, organic-rich, selfsourced shales. 

The upper and lower shale members of the Lower 

Mississippian and Upper Devonian Bakken Formation, 

which are separated by the middle siltstone member, in 

the Williston basin, Montana and North Dakota, serve as 

a "type" example. New organic-geochemical studies 

show that bitumen extracted from the Bakken shales 

does not correlate to Mississippian mid-Madison Group 

oils, and that the Bakken shales have contributed only a 

minor percentage of the oil produced to date in the 

Williston basin. Also, few pathways exist for vertical 

migration of Bakken-generated oil to shallower midMadison reservoirs. Instead, organic-rich Madison 

Group marls may be an adequate source for the midMadison oils. Published calculations suggest that the 

Bakken shales have generated 100-150 billion barrels of 

oil. If the conventional reservoirs were not charged by 

Bakken-generated oil, this oil would not have leaked 

from the basin. Thus, an in-place resource base of 

100-150 billion barrels of Bakken-generated oil may still 

exist in fractures in the Bakken "source system," that is, 

within: (1) all three members of the Bakken, (2) the 

overlying lowermost Lower Mississippian Lodgepole 

63 

Limestone, and (3) the underlying uppermost Upper 

Devonian Three Forks Shale. Vertical wells in older 

"Bakken" oil pools (Antelope, Elkhorn Ranch, for 

example) are perforated in one or all of the three units 

(Three Forks, Lodgepole, and the middle siltstone 

member of the Bakken) adjacent to the two Bakken 

shales, but are not necessarily perforated in the Bakken 

shales. Rock-Eval analyses of 6-12-inch-spaced core 

samples taken through all Bakken source system units 

show that where Bakken shales are thermally mature, the 

three adjacent organic-poor units contain 10-20 times 

the HC's they could have generated. Thus, Bakkengenerated HC's clearly appear to have moved into the 

three adjacent units, probably via fractures created by 

volume expansion of organic matter during HC 

generation in the Bakken shales~ 

The mixed results of horizontal Bakken drilling 

thus far have been attributed to a lack of fractures. 

However, mature Bakken shales are oil-wet systems with 

no water in them, and any water introduced into these 

shales during drilling, completion, or workover 

operations will decrease or ruin the shales' oil-productive 

capabilities, due to the principles of two-phase fluid flow 

and the J amin effect. Review of vertical and horizontal 

Bakken well histories reveals that lack of success in some 

Bakken wells appears due to operational techniques 

inappropriate to the nonclassical characteristics of the 

Bakken source system, and not to a lack of fractures. Two 

other detriments to Bakken productivity also appear 

probable. First, significant physical damage may be 

inflicted on the plastic Bakken shales in the beginning 

and middle portions of Bakken horizontal wells, from the 

long times the drill bit and string spend there. Second, the 

overpressured and incompetent nature of the Bakken 

shales necessitates drilling with overbalanced mud to 

prevent either blowout or hole collapse, which results in 

the mud's intrusion into and caking on Bakken fracture 

walls. Horizontal drilling in the competent units adjacent 

to the two shale members of the Bakken would avoid 

both these problems. 

The Bakken source system is not unique, as 

examples exist of other fractured, self-sourced shales that 

are both currently and historically as productive as or 

more productive than the Bakken shales. If the Bakken 

shales have generated and contain 100-150 billion 

barrels of oil, then given the volume of mature source 

rocks in other United States basins, it is not difficult to 

arrive at an in-place oil-resource base estimate in the 

range of tens to hundreds of trillions of barrels for the 

lower 48 States. However, if such a large in-place oilresource base does exist in these mature source rocks, its 

commercial recovery clearly will depend on development 

of new exploration, drilling, completion, and production 

technologies appropriate to the nonclassical characteristics of this resource base. 
Some Geologic Controls of Coalbed Gas 

Generation, Accumulation, and 

Production, Western United States 

Dudley D. Rice, Jerry L. Clayton, 

Romeo M. Flores, Ben E. Law, and 

Ronald W. Stanton 

The presence of gas in coal beds has long been 

recognized because of explosions which have occurred 

during underground mining. Coal has been considered as 

a source of mainly nonassociated gas which has been 

expelled from and accumulated in adjacent reservoirs in 

many basins. Recently, coalbed gas has been recognized 

as a large, relatively untapped energy resource with the 

coal beds serving as both the source and reservoir rock. 

In-place estimates of coalbed gas in the United States are 

as much as 800 TCF; a 1991 assessment by the Potential 

Gas Committee of the recoverable resource is as much as 

145 TCF. 

Upper Cretaceous and Tertiary coal beds in 

Western U.S. basins such as the Piceance Powder River ' ' and San Juan are estimated to contain large resources of 

gas. Major efforts have been made to produce this gas 

especially in the San Juan Basin where a major regionai 

pipeline system is in place. Several factors, such as coal 

rank, gas content, pressure, moisture content, and 

permeability (cleats), have previously been identified as 

being important in controlling the generation, 

accumulation, and production of coalbed gas from these 

western coal beds; two other factors that we have 

recognized as important are coalbed heterogeneity and 

composition. 

.coal beds are distinguished by heterogeneity, 

especmlly lateral variability, which is a most elusive 

~haracteristic to determine. This extreme heterogeneity 

Is apparent when closely spaced control points are 

studied. Closely spaced control points ( < 0.5 mi) are 

generally only available from outcrop studies and not 

.from subsurface data sets. In general, coal beds 

deposited in fluvial and deltaic environments are more 

laterally discontinuous than coal beds deposited in backbarrie~ set~ings. The discontinuity resulting from splitting 

and pmchmg out of the coal beds and changes in coal 

quali~ is attributed to channel and crevasse-splay 

deposits. This extreme variability strongly affects the 

continuity and quality of the coal beds that are both 

hydrocarbon reservoir rocks and aquifers. 

~os.t ~estern U.S. coals are composed dominantly 

of the VItnmte maceral and are classified as humic (type 

III) kerogen. Such coals are generally considered to be 

gas prone. However, the examination of macerals in 

etched polished surfaces under both blue-light 

fluorescence and white light allows for the identification 

64 

of two main genetic types of vitrinite-structured humic 

material and matrix gels. These two types have different 

source- and reservoir-rock characteristics. 

Both types yield methane-rich bacterial gas in coal 

beds of low rank (Rm values < 0.6 percent), as illustrated 

by desorbed and produced gas in the Powder River basin. 

However, at Rm values of 0.6 percent and greater, 

thermogenic hydrocarbons are generated that vary in 

composition depending on the genetic type. Structured 

humic material is more oxygen rich and produces a 

methane-rich gas (CdC1 _5 values > 0.98). Rates of gas 

and water production are relatively high from coal beds 

dominated by this facies, indicating higher permeability. 

In contrast, matrix gels are more hydrogen rich and 

produce both liquids and wet gas (C1/C1_5 values =0.90). 

Liquid hydrocarbons have been produced during early 

stages of production in the San Juan and Piceance basins 

in coals characterized by significant amounts of matrix 

gels of relatively low rank (Rm values of 0.7-0.8 percent). 

These liquids contain high pristane:phytane ratios, a 

feature that is typical for coal-derived oils, and a slight 

predominance of odd-carbon numbered n-alkanes in the 

C25 + fraction. However, the saturated fraction consists 

predominantly of low-molecular-weight components 

(C4-C10 ), which results in the liquids having high API 

gravities ( =50°). In addition, the coal-derived liquids are 

commonly characterized by high pour points because 

they contain abundant long-chain n-alkanes derived from 

terrestrial plant waxes. The high pour points of the 

liquids commonly result in problems by plugging 

production equipment. The vitrinite-rich coals with 

abundant matrix gels probably have lower permeability 

than those with structured humic material, and their 

gas-production rates are generally lower. However, the 

negative effect of lower gas production rates is offset by 

lower rates of water production and higher gas Btu 

values in the vitrinite-rich coals. 

USGS Core Research CenterA Million Feet of Geologic History 

Diana L. Richards and Thomas C. Michalski 

The Core Research Center (CRC) of the USGS, 

situated in Denver, Colo., currently houses in excess of 

1,000,000 (1 million) feet of core from 25 States, the 

majority of which are from the Rocky Mountain and 

Great Plains regions; cores from Wyoming, Montana, 

Colorado, North Dakota, Utah, New Mexico, and Kansas 

constitute 95 percent of the collection. Increasing 

geologic and geographic diversity of samples at the CRC 

has resulted in its becoming one of the largest, best 

organized, and most heavily utilized public core 

repositories in the United States. 
Preservation of valuable core material for use by 

government, industry, and academia has been a concern 

of the USGS for many years, which resulted in the 

establishing of a permanent core storage and research 

facility in 1974. The goals of the repository are to gather 

cores from a wide variety of sources, process and store 

them efficiently, and make them available on a daily basis 

for examination and sampling by all interested scientists. 

Although gathered from a variety of sources, most cores 

in the collection were generated as a result of oil and gas 

exploration and have been donated by a large number of 

companies in the petroleum industry. A majority of the 

cores have been slabbed and photographed, and all are 

available for immediate viewing. In excess of 15,000 thin 

sections and a large number of analyses made from core 

in the CRC collection are available to users. The CRC 

also houses a unique collection of 240,000 feet of oilshale core. 

The recently renovated facility offers a pleasant 

environment for core examination and sampling: a large, 

well-lit, climate-controlled examination room provides 

an ideal setting where 1,500 feet of slabbed core can be 

examined at one time; a conference room and a small 

reference library are also available. To facilitate the 

extensive daily use of the collection, the CRC has 

established a core information database and provides 

custom computer searches of its holdings by operator, 

location, formation, or geologic age. A series of State 

core catalogs are available for purchase. The CRC 

encourages use of its facility by all interested geologists 

and welcomes inquiries about the collection, donation of 

core samples, computer printouts, and the location of 

other public repositories. More information can be 

obtained by contacting the CRC at: 

U.S. Geological Survey 

Core Research Center 

Box 25046, Denver Federal Center 

Mail Stop 975 

Denver, CO 80225; 

telephone (303) 236-1930. 

Research Thrusts of the Current 

Five-Year USGS Evolution of Sedimentary 

Basins Program-Illinois, Paradox, 

Eastern Great, and SWANO Basins 

J.L. Ridgley, A.C. Huffman, Jr., H.E. Cook, 

C.J. Potter, S.Y. Johnson, and W.E. Dean 

The U.S. Geological Survey has new, five-year, 

basin-analysis projects underway in the Illinois, Paradox, 

Eastern Great, and Tertiary southwest Washington and 

northwest Oregon (SWANO) basin provinces. The 

65 

research focus differs for each basin and is coordinated 

with ongoing research activities of other USGS 

programs, State geological surveys, academia, and 

industry. 

USGS studies of selected Paleozoic carbonate and 

clastic rocks in the Illinois Basin will focus on basinwide 

geochemical, diagenetic, and thermal maturation 

problems as they relate to movement of fluids in the 

basin. These studies will use local and regional structure 

to constrain theoretical fluid flow models and should 

provide additional insight and constraints on factors 

influencing hydrocarbon and mineral accumulations. 

Paradox Basin studies will concentrate on late 

Paleozoic development and infilling of the basin and on 

factors affecting hydrocarbon and mineral resource 

generation and accumulation. Sedimentologic, stratigraphic, structural, geochemical, thermal maturation, 

and paleontologic studies of upper Paleozoic carbonate 

and clastic rocks will provide insights on the structural 

history, sources and distributions of organic matter and 

hydrocarbon accumulations, and basin fluid movement. 

Geophysical studies will examine problems related to the 

structural evolution of the basin, including the role of salt 

tectonics and basement faults on basin development and 

depositional systems. 

Research in the Eastern Great Basin (eastern 

Nevada and western Utah) will focus on the geologic 

evolution of the region, as defined by a Paleozoic passive 

margin, an accretionary Paleozoic and Mesozoic foreland 

basin, and a Mesozoic compressional and Cenozoic 

extensional tectonic setting. Integrated geologic, 

geochemical, and geophysical studies from single sites 

and from defined north-south and east-west transects will 

evaluate multiple structural events, basin infilling 

processes, and depositional systems, and the relation of 

each of these to mineral and hydrocarbon accumulations. 

The SW ANO basin, a frontier energy province, 

occupies a fore-arc tectonic setting with a complex Cenozoic history of deformation and subsidence driven by 

oblique convergence, accretion, and strike-slip faulting. 

Comprehensive basin reconstructions are being 

generated from integrated structural, geophysical, stratigraphic, sedimentologic, and geochemical data to provide 

the framework for regional energy-resource evaluation, 

and for developing models and principles for analysis of 

other complex, convergent margins. 

Isostatic Residual Gravity 

Mapping of Wyoming 

S.L. Robbins and J.A. Grow 

Most complete Bouguer anomaly (CBA) gravity 

maps show systematic negative values in mountainous 
regions that are the effects of crustal thickness variations 

produced by isostatic adjustments. Isostatic residual 

anomaly (IRA) gravity maps are created from CBA 

maps when isostatic corrections are made using an 

Airy-Heiskanen model, and these are then subtracted 

from the CBA. The resultant IRA maps usually 

represent density variations in the upper crust more 

closely than do CBA maps. 

In Wyoming, CBA values range from -80 mGal 

over the mountains to -288 mGal over the basins. A 

significant part of this range reflects a regional 

topographic gradient from 1,200 m above sea level in 

northeastern Wyoming to 2,500 m in southwestern 

Wyoming. However, the values associated with the Laramide mountain uplifts are positive relative to those of the 

basins, and when IRA values are computed using local 

Airy isostatic assumptions, the positive anomalies 

become larger. The IRA map values range from -77 

mGal in the basins to + 75 mGal in the Bighorn 

Mountains; the average value is, however, near zero. 

Seismic reflection and two-dimensional gravity models 

indicate that Laramide mountain ranges are underlain by 

low-angle thrust faults that flatten within the lower crust. 

Therefore, the large positive CBA gravity values over the 

mountains, which are made even larger by assuming local 

roots beneath these mountains, are in actuality probably 

due to rootless mountains. In most continental tectonic 

regions where local mountain roots exist, local 

algorithms are the optimum choice for isostatic 

compensation. In Wyoming, however, the use of regional 

algorithms that average topography over wavelengths of 

more than 100 km will be required because of the 

rootless mountains. 

IRA maps are significant improvements over CBA 

maps in that regional effects are removed, and in their 

effectiveness for interpreting upper crustal anomalies. 

However, some tectonic regimes require more care in 

creating IRA maps because local isostatic algorithms 

may be based on incorrect assumptions. In these 

instances, regional (as opposed to local) algorithms may 

be useful in minimizing the relief in the IRA maps and 

still enhance shorter wavelength gravity anomalies in the 

upper crust that are caused by structures of economic 

interest. 

Paleocene Paleogeography, Tectonics, 

and Coal Distribution in the Rocky 

Mountain Region-An Overview 

S.B. Roberts, M.S. Ellis, A.M. Flores, 

D.J. Nichols, W.J. Perry, Jr., and G.D. Stricker 

A study of sedimentologic, tectonic, palynologic, 

and coal data from Paleocene basins of the north-central 

66 

Rocky Mountain region was undertaken in order to 

understand the relationship of Laramide tectonism to 

distribution and quality of Paleocene coals. Our study is 

based primarily on published and unpublished data 

pertaining to (1) depositional environments and paleocurrent trends in Paleocene fluvial/lacustrine sequences, 

(2) timing of uplifts, based on fission-track analysis and 

(or) development of synorogenic deposits, (3) palynomorph biozonation, and ( 4) coal distribution and 

apparent rank. Synthesis of the data has led to a current, 

''working hypothesis" relating Paleocene tectonism to 

coal-basin paleogeography and coal development 

The pattern and timing of Laramide uplifts in the 

north-central Rocky Mountain region indicate that a 

Laramide deformational front (LDF) advanced to the 

northeast from early to late Paleocene. Major coal depocenters in the region recorded a corresponding northeastward shift, suggesting that regional tectonism 

influenced coal development. The variance in apparent 

coal rank can also be attributed, at least in part, to 

regional tectonics, as those coals which formed in ~epacenters proximal to the LDF tend to have h1gher 

apparent ranks. 

In early Paleocene time (palynomorph zones Pl 

and P2), the LDF extended from the Madison Range in 

southwestern Montana, through the Wind River and 

Granite Mountains of central Wyoming, to the southern 

Front Range in Colorado. A network of trunk-tributary 

fluvial systems flowing east and northeast drained the 

region. Numerous, areally extensive coal depocenters 

developed in advance of the LDF (for example, Raton, 

Denver, and Wind River basins), while fewer coal depocenters developed behind the LDF (for example, Sand 

Wash/Washakie basin). 

During the middle Paleocene (palynomorph zones 

P3 and P4), the LDF advanced northeastward in 

Wyoming, as evidenced by uplift in the Washakie and 

Owl Creek Mountains. Progressive partitioning of the 

Rocky Mountain foreland at this time is demonstrated by 

the development of the intermontane Wind River, 

Bighorn, and Bull Mountain basins. The pattern of 

trunk-tributary fluvial systems was similar to that of the 

early Paleocene. However, lacustrine systems, forming in 

response to rapid subsidence along basin-margin thrust 

faults, were more widespread than in early Paleocene. 

Coal depocenters, which developed both ahead (Bighorn, 

Powder River, and Bull Mountain basins) and behind 

(Washakie, North Park, and Hoback basins) the LDF, 

were generally not as numerous or extensive as in the 

early Paleocene. 

In the late Paleocene (palynomorph zones P5 and 

P6), the LDF in Wyoming shifted farther to the 

northeast, resulting in thrust-uplift of the Beartooth 

Mountains, and increased uplift in the Bighorn 
Mountains. By this time, the Rocky Mountain foreland 

had been partitioned into a well-defined network of 

intermontane basins drained by east- to northeastflowing, trunk-tributary fluvial systems, and associated 

lacustrine environments. Numerous, extensive coal depocenters formed ahead of the LDF (Powder River and 

Williston basins), while fewer coal depocenters 

developed behind the LDF (Hanna basin). 

The apparent rank of 1,482 Paleocene coal samples 

was determined by calculating Btu!lb values (moist, 

mineral-matter-free basis) using the Parr formula. 

Evaluation of these data suggests that apparent rank 

trends are primarily related to the basinal tectonic 

history. In general, coal basins can be described as 

"active" or "passive," with respect to the level of tectonic 

activity and proximity to the LDF. Active basins 

(Bighorn, North Park, Hanna, and Raton basins) are 

proximal to · or within areas of deformation associated 

with the advancing LDF, and are characterized by coal 

deposits with relatively high apparent ranks (Subbituminous B-High Volatile A Bituminous; mean Btu/lb 

range= 10,890--14,950). Passive basins (Powder River, 

Bull Mountain, and Williston basins) developed away 

from active deformation associated with the LDF, and 

are characterized by relatively low apparent ranks 

(Lignite A-Subbituminous B; mean Btu/lb 

range= 6,980-10,240). Within active basins, the apparent 

increase in rank is attributed to (1) increased depth of 

burial (subsidence) and elevated geothermal gradients 

induced by active tectonism associated with the LDF and 

(or) (2) subsequent igneous intrusive activity. 

Although tectonism seems to have played a 

significant role in Tertiary coal development, climatic 

effects were undoubtedly important contributing factors. 

Continued studies of Paleocene tectonics and coal will 

necessarily incorporate aspects of paleoclimatology in 

order to develop a more complete understanding of early 

Tertiary coal basin evolution. 

Reservoir Heterogeneities in the 

Morrison Formation in Southern UtahA Prudhoe Bay Analog 

John W. Robinson and Peter J. McCabe 

Examination of the Salt Wash Member of the 

Morrison Formation (Jurassic) in the southern Henry 

Mountains region of southern Utah allows a better 

understanding of heterogeneities in fluvial reservoirs 

with high net -to-gross sandstone ratios. The Salt Wash 

Member is interpreted as the deposits of braided rivers 

that flowed towards the northeast into a playa lake in 

central Utah from a source area in north-central 

67 

Arizona. Cliffs and canyons provide exceptional 

exposures that allow a three-dimensional study of vertical 

and lateral facies relationships of the member over an 

area of 1,000 km2 • Interpretation of photomosaic 

panoramas of cliffs up to 350 m high and 3.2 km long 

allows for description of the facies architecture and 

measurement of potential large-scale reservoir 

heterogeneities. More detailed photomosaics of smaller 

areas allow an assessment of smaller scale 

heterogeneities. This work is being supplemented by 

measurement of detailed stratigraphic sections, minipermeameter analysis of outcrops and freshly cut cores, 

correlation of subsurface well logs, and petrographic 

studies. 

The Salt Wash Member is 150 m thick, and is 

composed predominantly of sandstones with < 10 

percent interbedded siltstones and mudstones. These 

sandstones have an overall coarsening-upward trend 

through the unit, with very fine grained quartz-rich beds 

at the base and chert granule and pebble conglomeratic 

sandstones toward the top. The sandstones form finingupward units, from 1 to 5 m thick, that are dominated by 

trough cross-stratification; the size of individual crossbeds increases higher in the section. The section also 

contains a few horizontal and ripple-laminated beds. 

Individual fining-upward units are laterally extensive 

over tens of meters and are separated by discontinuous, 

0.01- to 1-m-thick mudstone drapes and (or) mudstone 

intraclast pebble lags. Fining-upward units amalgamate 

to form sandstone sheets that are up to 20m thick and 

laterally extensive for 100 m to more than 2 km. These 

sandstone sheets have flat bases and tops and are 

separated by rooted and burrowed, red and green 

mudrock units generally less than 3 m thick. Minipermeameter data from outcrop and core average 600 mD 

in trough-crossbedded and massive sandstones, 200 mD 

in horizontal laminated sandstones, and < 50 mD in 

fine-grained deposits. 

We believe that conclusions from our study could 

be used to better model flow unit continuity in large 

fluvial reservoirs to aid in better reservoir development. 

Mudrock beds and intraclast conglomerates of varying 

thickness and continuity would divide a reservoir into 

flow unit compartments on various scales, influencing 

fluid migration and drainage. Data from these outcrops 

provide a guideline to predict the scale of reservoir 

heterogeneities from field-spaced core and log data. In 

particular, the Salt Wash Member appears similar to the 

Ivishak Formation of the Sadlerochit Group (Permian 

and Triassic) of the Prudhoe Bay field, Alaska. 

Similarities include (1) an overall coarsening-upward 

character to the strata; (2) presence of amalgamated 

sandstone sheets, deposited by braided fluvial streams, 

separated by discontinuous floodplain mudstones; (3) a 

vertical evolution of cross-stratification types; and ( 4) a 
high net sandstone composition dominated by a lithic 

chert component. The scale of our study (1,000 km2 area 

x 150 m thickness) allows a realistic three-dimensional 

comparison with a major reservoir such as the Ivishak 

(770 km2 area x 130m thickness). 

Oil Field Growth in the United StatesHow Much is Left in the Barrel? 

D.H. Root and E.D. Attanasi 

Since 1966, the estimated sizes of U.S. oil fields 

have generally been revised upward every year, as 

documented first by the American Petroleum Institute in 

1966--1979 and then by the Energy Information 

Administration in 1977-1989. A barrel of production 

results in less than a barrel reduction in reserves. Indeed, 

the estimated ultimate recovery from fields discovered in 

the lower 48 States before 1967 was estimated at yearend 1966 to be 111 BB (billion barrels). As of year-end 

1989, the estimated ultimate recovery from these fields 

was 154 BB. These fields had reserves in 1966 of 31.1 BB; 

they produced 57.7 BB from 1966 through 1989 and their 

reserves declined to 16.4 BB. Even fields discovered 

before 1900 are still growing. 

The Energy Information Administration has 

recently developed a new series of estimates of ultimate 

crude-oil recovery by year of discovery. We report on 

research in progress on the application of various 

methods of analysis to this new series to estimate the 

expected future growth of crude-oil recovery from known 

fields in the lower 48 States. Standard methods of field 

growth analysis as presented in studies by J .R. Arrington 

in 1960, R.G. Marsh in 1971, and D.H. Root in 1981 

require the analyst to make arbitrary choices concerning 

the level of aggregation between large and small fields, 

the number of successive years of data used in the 

analysis, and the cutoff age beyond which fields are 

assumed no longer to grow. 

Projections of future field growth estimated by 

applying the standard method to this new data series 

were found to be quite sensitive to these choices. These 

projections for the lower 48 had a range from 10 to 80 BB 

of oil. For instance, the future growth calculated when 

small and large fields are analyzed separately is one-third 

greater than when all fields are pooled and growth is 

projected for the aggregate amount of oil. In certain 

instances when the field growth cutoff age is reduced 

from 80 to 65 years, projected field growth declines by 

more than half the original amount. Projected future 

growth estimates are also sensitive to industry conditions 

that prevailed during the time period when the historical 

estimates of ultimate field sizes are made. The projected 

68 

future field growth was highest when the historical 

estimates were made during periods of rising oil prices 

and increasing development drilling. 

Biases in the standard projections of field growth 

result from the violation of the assumptions that field 

growth is proportional to ultimate size and fields of the 

same age are equally developed. It seems more realistic 

to assume that at any point in time, the annual field 

growth is proportional to remaining reserves, rather than 

to ultimate recovery. The uniformity hypothesis assumes 

that a field discovered in 1957 whose size was estimated 

in 1987 has the same relative amount of remaining 

growth as a field discovered in 1947 whose size was 

estimated in 1977. However, the 1957 field by 1987 had 

probably experienced more intense development than 

the 1947 field had by 1977 because of a higher price 

during its operating period and fewer years under prorationing. So, even at age 30 one would expect to find more 

growth left in the 1947 field than in the 1957 field. 

Alternatives to the standard procedure are 

presented that are designed to correct for deviations 

from the uniformity assumptions. 

Geochemistry and Origin of 

Oil in Cambrian and Ordovician 

Reservoirs, Ohio 

Robert T. Ryder, Robert C. Burruss, and 

Joseph R. Hatch 

Oils from stratigraphic traps along the Middle 

Ordovician Knox unconformity in Ohio were analyzed to 

determine their geochemical characteristics and source 

rocks. Seven samples were collected from the Upper 

Cambrian(?) Rose Run Sandstone; six samples were 

collected from the Upper Cambrian part of the Knox 

Dolomite; one sample was collected from the Upper 

Cambrian Krysik sandstone of informal usage; and one 

sample was collected from the Middle Ordovician Black 

River Limestone. Gas chromatograms of saturated 

hydrocarbon fractions from these oils show similar 

geochemical characteristics including (1) full profile of 

n-alkanes from nC5 to nC33, (2) slight odd predominance 

of n-alkanes in the nC13 to nC19 range (carbon 

preference indices from 1.1 to 1.2), and (3) pristane/nC17 

and phytane/nC18 between 0.28 and 0.45. These 

similarities suggest that the oils were generated from the 

same source rocks. Slight differences in the character of 

the oil are attributed to postemplacement maturation. 

An Ordovician source is inferred for the 15 oils studied 

here because they are geochemically similar to oil in the 

northern Illinois basin and adjoining areas that have been 

derived from Ordovician source beds. However, 
Gloeocapsamorpha prisca, blue-green algae whose 

distinct gas chromatographic signature is common in 

Ordovician oils, is not largely recognized in the Ohio oils. 

Ninety-two rock samples, predominantly from 

core, in Ohio, Tennessee, and West Virginia, were 

analyzed for their TOC (total organic content) and 

pyrolysis products to evaluate the source of the Ohio oils. 

Three possible source-bed intervals were tested: (1) 

Middle and Upper Cambrian strata in the Rome trough, 

(2) the Middle Ordovician Wells Creek Formation and 

the equivalent part of the Lower and Middle Ordovician 

Beekmantown Group, and (3) the Middle and Upper 

Ordovician Antes Shale and the equivalent Utica Shale. 

The Antes and Utica Shales have moderate TOC values 

(X= 1.6, n = 32; 20 values from other published sources) 

that identify them as potentially good petroleum source 

beds. The Wells Creek Formation and the upper part of 

the Beekmantown Group (x = 0.3, n = 40) and the Middle 

and Upper Cambrian strata in the Rome trough (x = 0.3, 

n = 22) have several samples whose TOC values fall in 

the 0.5-1.5 percent range, but most of them are too low 

in organic carbon to be considered source beds. A plot of 

the hydrogen index (HI) of these 92 rock samples against 

oxygen index (OI) of the samples shows low HI values 

( < 200 mgHC/gC) and a wide range of OI values 

(50-650 mgC02/gC). The low HI values are attributed to 

the low organic content of most of the samples and to the 

high thermal maturity of the few samples that have a 

greater-than-average organic content. The high OI 

values probably represent the C02 generated from 

partial thermal decomposition of the carbonate minerals 

in the samples during pyrolysis rather than C02 

generated from the kerogen. When HI and OI values of 

the Antes Shale from this study are combined with 

previously published values from the thermally immature 

to marginally mature Utica Shale in eastern and central 

Ohio, they indicate that the compositions of kerogens 

from the Antes-Utica sequence plot between organic 

matter Types II and III and, thus, are oil and gas prone. 

Based on these combined values, we conclude that the 

black shales of the Antes and Utica Shales are the most 

probable source of the Ohio oils. Locally, strata in the 

Wells Creek Formation, the upper part of the Beekmantown Group, and the Middle and Upper Cambrian strata 

in the Rome trough may also have been a source for 

some oil and gas. 

The required downward expulsion of oil through 

1,000 ft of the Middle Ordovician carbonates to reach the 

Knox unconformity probably was accomplished by high 

fluid pressure in the Antes-Utica interval. Once oil 

reached the porous beds accompanying the Knox unconformity, it easily migrated up the eastward-dipping slope 

of the foreland into Ohio. The superior sealing capacity 

of the overlying Upper Ordovician Reedsville Shale and 

Juniata Formation, compared to the underlying Middle 

69 

Ordovician Black River and Trenton Limestones, may 

also have facilitated the preferred down-section 

migration of oil derived from the Antes and Utica Shales. 

Algodones Depositional System-Modern 

Analog for the Upper Jurassic Norphlet 

Formation, Mississippi and Alabama 

C.J. Schenk 

The Upper Jurassic Norphlet Formation is a 

prolific gas reservoir in several offshore Alabama fields, 

and produces minor amounts of oil from several onshore 

fields. The Norphlet Formation was deposited along the 

southern margin of North America following rifting of 

North America and Africa-South America. The 

Appalachian Mountains formed the northeastern margin 

of the rift zone, and clastics of the Norphlet Formation 

were shed southwestward from the highlands, 

accumulating in alluvial fan, braidplain, sand sheet, interdune, playa, and eolian dune environments. Most of the 

gas in offshore fields is trapped in eolian dune 

sandstones, and most cores from the offshore are 

dominated by thick sequences of eolian stratification. 

However, the proximal facies of the Norphlet Formation 

are a complex intercalation of alluvial and eolian 

sandstones. These facies are well represented in cores 

from Escambia County, Alabama. 

The Algodones eolian dunes and related 

environments in the Salton trough, southeastern 

California, are an excellent analog for the intercalation of 

fluvial and eolian facies of the Norphlet Formation. The 

Salton trough is a complex extensional basin related to 

the rifting event that formed the Gulf of California. The 

Cargo Muchacho and Chocolate Mountains form 

highlands along the eastern boundary of the Salton 

trough, similar to the geography that existed along the 

Jurassic basin margin during Norphlet deposition. Clastics shed westward from the mountains adjacent to the 

Algodones form alluvial fan, braidplain, and sand sheet 

deposits. Small alluvial fans adjacent to the mountains 

grade to extensive braidplains characterized by 

ephemeral channels that are wide and shallow. Processes 

on the braidplains are dominated by flash-flood 

discharge through numerous shallow channels in 

proximal areas, and by sheetflooding on distal braidplains. Distal braidplain deposits commonly exhibit an 

intercalation of fine to medium sand with thin layers of 

pebbles and cobbles. This facies is common in the 

Norphlet Formation along the basin margins, where it is 

called the wadi facies. The Algodones braidplains grade 

to partially vegetated eolian sand sheets, on which 

sediment transport by wind dominates surficial 
processes. Alluvial sheetflood processes resulting from 

storms can inundate the eolian sand sheets, leaving thin 

layers of pebbles and cobbles and mud layers in 

otherwise laminated eolian sand. 

Basinward from the braidplains and sand sheets 

are the eolian dune sands of the Algodones. Overall, the 

Algodones dune field is about 70 km long and as much as 

10 km wide, and the dune sand is as much as 100 m thick. 

The dunes are large, complex transverse and barchanoid 

forms that are covered with small superimposed dunes. 

The dunes are generally migrating to the south and east, 

over the braidplain and sand sheet sands. Migration of 

these complex dunes would produce a thick sandbody 

composed of a complex assemblage of eolian dune 

deposits, with rare interdune deposits, similar to the 

eolian sandstones of the Norphlet Formation. 

10 

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22 

Reservoirs and Source Rocks of the 

Upper Jurassic Norphlet Formation, 

Mississippi and Alabama 

C.J. Schenk and J.W. Schmoker 

The Upper Jurassic Norphlet Formation in the 

offshore region of Alabama contains gas resources 

estimated to be in the range of several trillion cubic feet. 

The remarkable reservoir properties of the productive 

eolian sandstones of the Norphlet Formation, 

particularly porosity values as high as 15 percent at 

depths on the order of 20,000 ft, have been the subject of 

several studies. Our purpose in this study is to determine 

why the reservoir properties of the Norphlet are what 

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0.6 0.7 0.8 1.0 1.5 2.0 2.5 3.0 3.5 

Roeq• IN PERCENT 

Figure 1 (Schenk and Schmoker). Preliminary working trends of equivalent vitrinite 

reflectance (Roeq) versus present depth for five areas in southern Mississippi, 

southwestern Alabama, and the western Florida panhandle. Trends are derived from 

published and unpublished data that include vitrinite reflectance, bitumen reflectance, 

T max (Rock-Eval pyrolysis), and modeling based on time-temperature history. These 

Roeq-depth relations are subject to modification as additional data become available. 

Trend labeled (1) is from vicinity of Escambia County, Alabama, and Escambia County, 

Florida; (2) represents area of Mississippi and Alabama south of Wiggins arch; (3) 

represents Mississippi Interior Salt basin; (4) represents area centered on Rankin County, 

Mississippi, influenced by the thermal effects of the Late Cretaceous Jackson Dome; (5) 

represents northern peripheral fault zone of Mississippi Interior Salt basin near the 

Mississippi-Alabama border. Dashes represent extrapolations of data sets. 

70 
they are. Figure 1 represents a preliminary attempt at 

relating thermal exposure to depth for several regions in 

the Mississippi Interior Salt basin and southwestern 

Alabama, including offshore; regional thermal exposure 

has been shown to correlate with average porosity. The 

curves indicate that thermal maturity increases with 

increasing depth. Maturation values of about 1.5 to 3.0 

percent Ro characterize sandstones of the Norphlet 

Formation at depths ranging from about 15,000 to 22,000 

ft. Given these general trends of thermal maturation, 

average sandstone porosities of the Norphlet Formation 

from the Mississippi Interior Salt basin and offshore 

Alabama are much higher than average porosities of 

sandstones from numerous hydrocarbon-bearing 

sandstones worldwide. The reasons for this are not 

obvious, particularly because sandstones of the Norphlet 

Formation are not strikingly different petrographically 

from other productive eolian sandstones outside the Gulf 

Coast. The anomalously high porosities may be related to 

(1) the role of early cements such as halite, anhydrite, 

and carbonate in preserving intergranular space during 

burial, (2) the role of clay minerals, particularly chlorite, 

in preserving some porosity during burial, (3) the timing 

of diagenetic events such as clay growth and cement and 

framework-grain dissolution relative to gas emplacement, and ( 4) the role of hydrocarbons in inhibiting 

porosity-degrading diagenesis. 

Source rocks for Norphlet Formation 

hydrocarbons are generally considered to be the 

overlying organic-bearing algal carbonates of the Smackover Formation, but source rocks may also include a 

marine facies of the Norphlet shown by the Alabama 

Geological Survey to exist down depositional dip from 

the Norphlet Formation eolian sandstones. 

Geologically Oriented Overview of 

Horizontal Drilling in the United States 

James W. Schmoker 

A patent application for equipment designed to 

drill horizontal wellbores was filed in 1919. In 1929, 

horizontal laterals were successfully drilled from a 

vertical oil well. By 1954, drilling of horizontal drain 

holes was sufficiently common to warrant a review article 

on the subject by John Eastman. Despite these early 

beginnings, however, the pace of horizontal drilling 

remained relatively stagnant through the 1970's. 

The present cycle of horizontal-drilling activity 

stems from developments in the early to mid 1980's. 

Since 1985, the annual number of wells drilled with 

71 

horizontal segments longer than 1,000 ft (300 m) has 

been increasing worldwide at an exponential rate. 

Although such logarithmic growth cannot be sustained, 

most observers predict that significant numbers of 

horizontal wells will continue to be drilled. In the United 

States, horizontal wells have been tried in a majority of 

producing basins, but large numbers of individual 

formations and plays remain to be tested. 

The positive atmosphere associated with the oilprice boom of the early 1980's probably helped set the 

present horizontal-drilling cycle into motion. In the 

United States, where few horizontal wells have been 

drilled for exploration, a shifting emphasis from 

petroleum exploration to the exploitation of known 

hydrocarbon accumulations has driven horizontal 

drilling. 

In heterogeneous formations where pay zones are 

difficult to efficiently contact with wellbores, horizontal 

holes offer an alternative to the drilling and stimulation 

of vertical wells. In the United States, large volumes of 

movable oil are known to be present in heterogeneous 

formations. If the bulk of these known accumulations 

could be economically recovered through systematic 

horizontal drilling, the long-range energy outlook for the 

United States would be dramatically improved. 

Results of horizontal drilling to 1991, however, do 

not support such optimism. Drilling results argue instead 

for the localization of favorable production 

characteristics (sweet spots) within the regions 

encompassed by large oil accumulations. Successful 

horizontal wells in both the Austin Chalk and Bakken 

Formation plays, for example, are limited to 

comparatively small areas of the potential producing 

trends. 

The need to better comprehend the nature of sweet 

spots within regional trends offers opportunity for 

geologists. Improved understanding of sweet spots 

equates to improved understanding of the heterogeneity 

of sedimentary rocks in the subsurface. Fracture systems 

are only one aspect of the problem: depositional and 

diagenetic heterogeneities, on scales ranging from 

millimeters to kilometers, also significantly affect 

reservoir behavior. 

Relatively little is known about the distributions 

and characteristic dimensions of depositional and diagenetic heterogeneities. Field mapping, core examination, 

and thin-section studies, for example, are commonly used 

to investigate geologic processes but usually not the 

three-dimensional geometries resulting from such 

processes. Better understanding of depositional, diagenetic, and fracture geometries is needed for improved 

reservoir modeling and the reduction of horizontaldrilling risk. 
Tectonic and Climatic Controls on the 

Sedimentary Record of the Early 

Mesozoic Newark Supergroup Rift 

Basins, Eastern North America 

Joseph P. Smoot 

The Newark Supergroup consists of continental 

sedimentary and igneous rocks of Late Triassic to Early 

Jurassic age that fill a series of exposed half-graben 

basins along the eastern coast of North America. The rift 

basins formed along reactivated Paleozoic faults during 

extension that later led to the opening of the Atlantic 

Ocean. The basins had internal drainage systems, with 

local base level controlled by lake levels. Although the 

ages of the deposits differ in some basins, each basin 

exhibits a similar vertical succession of depositional 

facies from bottom to top: (1) Thin ( < 200 m ), 

discontinuous immature fluvial conglomerates unconformably overlie Paleozoic or Precambrian rocks; these 

deposits reflect local provenance and small drainages. (2) 

Moderately thick ( 500-1,000 m) conglomerates, crossbedded sandstones, and siltstones, deposited by braided 

rivers or low-sinuosity anastomosed streams, exhibit 

greater maturity than the basal conglomerates that they 

overlie, possibly unconformably. (3) Thick (500-2,000 

m) crossbedded to ripple crosslaminated, medium- to 

fine-grained sandstones and siltstones were deposited by 

high suspended-load meandering streams and on 

vegetated muddy plains. The fluvial deposits typically 

become finer grained and exhibit greater sinuosity 

upward in the section. (4) Very thick (1,000-6,000 m) 

lacustrine mudstones and siltstones, in most basins 

forming 2- to 10-m-thick cycles of deep-water to subaerial deposits, encompass deep and shallow perennial 

lakes, ephemeral lakes, dry-playa mudflats, saline mudflats, and vegetated mudflats. Dry-playa mudflat and 

saline mudflat deposits are absent in the southernmost 

basins and are restricted to discrete stratigraphic 

intervals in the northernmost basins. Fluvial 

conglomerates and sandstones and deltaic sandstones 

and siltstones commonly intertongue with the lacustrine 

deposits near the axial margins. Alluvial fan deposits, 

dominated by shallow-stream and debris-flow fabrics, are 

restricted to the faulted margin of the half-grabens where 

they intertongue with lacustrine and fluvial deposits. 

The vertical succession of depositional 

environments reflects the evolution of the drainage 

systems in response to rifting: (1) initial local drainages 

and erosional surfaces of a depositional depression prior 

to rifting; (2) basin subsidence and the localization and 

capture of regional drainages; (3) progressive loss of 

stream power as fault-related uplift constricted outlets 

and sediment aggradation lowered gradients, ( 4) partial 

72 

or complete hydrographic closure of the basins, as 

faulting restricted outlets. Timing of these events for 

each basin probably depended on the relation of the 

regional extensional field to the orientation and 

distribution of Paleozoic faults and preexisting drainages. 

Sparse paleocurrent data in each basin as well as 

provenance studies suggest that initial fluvial drainages in 

each basin had a variety of orientations with respect to 

the basin shape, but they eventually oriented parallel to 

the basin axis in the latter stages of fluvial deposition. 

Fault-related uplift created highlands that produced 

alluvial fans sometime before the end of drainage-system 

evolutionary stage 3. Tectonic activity may also be 

reflected by 10- to 20-m-thick coarsening-upward 

sequences in alluvial fan deposits and by radical shifts in 

the locations of marginal fluvial deposits. The geometry 

of the bounding faults apparently produced basins of 

increasing area during extension. This probable size 

increase is reflected by progressive vertical decrease in 

the abundance and thickness of deep-lake laminites 

within cyclic lacustrine strata, as suggested by Roy Schlische and Paul Olsen in 1990, accompanied by more 

regionally extensive fluvial and deltaic deposits that 

commonly built out as large-scale terminal fans. The 

increase of basin area was apparently interrupted by one 

or more episodes of flood basalt extrusion, apparently 

occurring simultaneously in several basins, producing 

increased subsidence and resulting in thicker and more 

common deep-lake laminites. The final stage of 

sedimentation in several basins is fluvial, suggesting a 

decrease in subsidence or lowering of the outlet. 

Climatic effects on the sedimentary record of the 

Newark Supergroup are pervasive at a finer scale than 

are the tectonic effects. The cyclic style of lake deposition 

common to most basins is attributed to variations of 

inflow and evaporation within a closed drainage, possibly 

due to Milankovitch periodicity forcing. This scale of lake 

fluctuations is also reflected in the style of deltaic 

deposits that intertongue with them. The cyclic climatic 

pattern is also visible as different order groupings of 

cycles and as large-scale (several hundreds of meters) 

variations in the abundance of arid climate features 

(playa, saline mudflat). The larger scale climatic 

fluctuations are also recognizable in fluvial deposits as 

alternations of perennial-dominated versus ephemeraldominated streams, and in alluvial fan deposits as 

dominance of high-discharge versus low-discharge flashflood fabrics. A regional gradation in climate of 

increasing aridity northward is also suggested by the 

occurrence of coals only in the southernmost basins and 

playa fabrics and eolian sandstones only in the 

northernmost basins. 
Origin of the Santa Maria Basin, 

California 

Richard G. Stanley, Samuel Y. Johnson, 

Ronald B. Cole, Mark A. Mason, Carl C. 

Swisher Ill, Mary Lou Cotton Thornton, 

Mark V. Filewicz, David R. Vork, 

Michele L. Tuttle, and John D. Obradovich 

More than 800 million barrels of oil and 800 billion 

fe of associated gas have been produced from the 

onshore Santa Maria basin of central California. Initial 

subsidence of this petroliferous Neogene basin is 

recorded by the lower Miocene Lospe Formation, an 

800-m-thick sequence of nonmarine and shallow-marine 

sedimentary rocks and interbedded tuffs. In its type area 

in the Casmalia Hills, the Lospe rests unconformably on 

Jurassic ophiolite, is conformably overlain by the lower 

Miocene (Saucesian and Relizian) Point Sal Formation 

and is of early Miocene (Saucesian) age on the basis of 

palynomorphs and benthic foraminifers obtained from 

mudstones, and radiometric ages from two beds of 

nonwelded rhyolitic tuff. A 40ArP9 Ar age of 17.70±0.03 

Ma (mean of seven determinations on sanidine) was 

obtained from a 20-cm-thick tuff about 30m above the 

base of the Lospe; a 40 ArP9 Ar age of 17.39±0.12 Ma 

(mean of six determinations on plagioclase) was 

measured on a 75-cm-thick tuff about 210 m above the 

base of the Lospe. Both tuffs are about the same age and 

may have erupted from the same volcanic source as a 

compositionally similar welded tuff yielding a 40 ArP9 Ar 

age of 17.79±0.10 Ma (mean of five determinations on 

sanidine) from the Tranquillon Volcanics (from a 1950 

study by Dibblee) on Tranquillon Mountain in the westernmost Transverse Ranges, about 30 km south of the 

Lospe outcrops. 

Alluvial fan and fan-delta facies within the basal 

part of the Lospe are as much as 200 m thick and consist 

mainly of reddish-brown and greenish-gray conglomerate 

and sandstone derived from nearby fault-bounded uplifts 

of Mesozoic sedimentary and igneous rocks. 

Conglomerate clast compositions and paleocurrent 

directions suggest that these coarse-grained facies were 

deposited in at least two subbasins separated by a 

northwest-trending paleohigh of Jurassic ophiolite. 

The alluvial fan and fan-delta deposits grade 

upward into a 600-m-thick sequence of interbedded 

greenish-gray sandstone and mudstone that accumulated 

mainly in a subaqueous environment, most likely a lake 

that was intermittently connected to the ocean. Many of 

the .s~ndstone beds are sheetlike, normally graded, and 

exh1b1t partial Bouma sequences, and probably were 

deposited by turbidity currents. The associated mudstones are bioturbated to laminated, display scattered 

73 

mud cracks that indicate infrequent desiccation, and 

contain sparse marine microfossils including dinocysts, 

suggesting occasional influxes of marine waters. Primary 

gypsum occurs in stromatolites and nodules in the lake 

deposits, and contains sulfate depleted in 34S (0 to + 3 

per mil), suggesting that the sulfur was derived from 

hydrothermal springs on the floor of the lake. Lenses of 

nonwelded rhyolitic tuff as much as 20 m thick are 

interspersed throughout this sequence. The tuffs consist 

almost entirely of bubble-wall vitric shards and pumice, 

and were deposited primarily as subaqueous pyroclastic 

flows and high-concentration turbidites that most likely 

originated from subaerial or shallow-water magmatic 

eruptions. In places, the tuffs are underlain by debris flow 

deposits that contain unusually large blocks of Jurassic 

ophiolite as much as 50 m long and 20 m across. 

The uppermost 30 m of the Lospe consists of 

storm-deposited, plane-laminated to bioturbated 

sandstone and bioturbated mudstone containing shallowmarine microfossils. These shallow-marine deposits are 

abruptly overlain by bathyal marine black shale of the 

Point Sal Formation, indicating rapid deepening from 

well-oxygenated shelf to oxygen-poor bathyal 

environments. The Saucesian-Relizian benthic foraminiferal stage boundary is about 2 m above the base of the 

Point Sal Formation. 

The Lospe Formation provides a clear record of 

substantial topographic relief, activ~ faulting, volcanism, 

hydrothermal activity, progressive deepening, and rapid 

subsidence during initial formation of the Neogene Santa 

Maria basin beginning about 17.7 Ma. These findings are 

inconsistent with an often-cited hypothesis which holds 

that the Santa Maria basin originated about 14 Ma as a 

pull-apart structure along a hypothetical right-slip fault 

system, the so-called "San Luis Obispo transform." 

Instead, our results support an alternative interpretation, 

based in part on paleomagnetic data, which holds that the 

basin originated about 17.7 Ma by local crustal extension 

and oblique right-slip faulting related to the beginning of 

clockwise rotation of the western Transverse Ranges. 

Interactive Computer Display of 

Petroleum Exploration and Undiscovered 

Resource Potential of the United States 

Kenneth I. Takahashi, Debra K. Higley, and 

Richard F. Mast 

The history of petroleum exploration across the 

United States is displayed using a self-contained SuperCard program on a Macintosh 11-series computer. Also 

included in the program are graphic displays of estimated 

undiscovered oil and gas resources for the United States. 
The continental United States, including Alaska, is 

divided into 47 major petroleum-producing areas. Color 

images of the oil, gas, oil and gas, and no-production 

category of each square mile in these regions are 

displayed in 5-year, cumulative increments for the period 

1900 through 1986. Included in each regional display are 

State and county boundaries, and other geographic 

reference points. The displays are analogous to a series of 

drill-hole maps that are animated by year of completion. 

Each symbol represents the producing category (oil, gas, 

oil and gas, or no production) of a 1-square-mile cell that 

has been drilled, rather than representing a single well. 

Each cell contains one or more wells that penetrate one 

or more target intervals. The display shows the earliest 

completion date (in 5-year increments) and the type of 

hydrocarbon occurrence (petroleum-producing 

category) for that cell. Estimates of undiscovered oil and 

gas resources for each area are also displayed. The 

displays of estimates of undiscovered oil and gas 

resources for the United States are shown by region and 

geologic province, as described in U.S. Geological Survey 

Open-File Report 88-373. 

Our display illustrates (1) the history of resource 

development, (2) the maturity of exploration in 

petroleum-producing regions across the United States, 

(3) relationships between estimates of undiscovered 

resources and where and how existing resources have 

been discovered, and ( 4) petroleum mapping 

applications using commercially available software on 

personal computers. 

Well locations, completion dates, and petroleumproducing categories were retrieved from the Well 

History Control System (WHCS) database of Petroleum 

Information Corporation and manipulated on a VAX 

11!780 by a series of FORTRAN utilities. These 

programs divide regions of the United States into 1-

square-mile areas and tabulate both the earliest well 

completion date and category of petroleum occurrence 

within each grid cell. By this method, the data on 1.7 

million wells are summarized in approximately 430,000 

cells that have been drilled across the United States. 

Based on the production categories for included 

wells, each cell is assigned a code for oil, gas, oil and gas, 

or no-production (dry) category. For example, if no wells 

within a cell produce hydrocarbons, then a dry cell 

symbol is posted. A cell containing oil, gas, and noproduction wells is assigned an oil and gas symbol. The 

year of earliest well completion is used to show when 

each cell was first drilled, and maps are displayed and 

animated relative to completion dates. Thus in cells that 

contain multiple plays or numerous drill holes, the 

earliest completion data may not correspond with results 

of subsequent exploration. For example, a cell that 

contained early nonproductive wells and later oil wells 

74 

would have an oil symbol color, but the date would 

represent the early, dry exploration. 

File structure in SuperCard consists of a window 

containing an index map of the U.S. and separate 

windows for each petroleum region. Maps of regions are 

accessed by clicking with the mouse on that part of the 

U.S. index map that contains the region of interest. The 

map sequence is animated by clicking on the region's 

exploration history button. Alternately, cumulative 

exploration for each separate 5-year increment can be 

displayed by clicking on the button with that year interval. 

For example, pressing the "45-49" button will display 

exploration from 1900 through 1949. The resource 

estimate data were drawn from published reports and 

linked to the exploration history areas by geographic 

region. 

Hardware requirements for this program are a 

Macintosh computer with color graphics capability, 8 

megabytes of memory, and a minimum 20 megabyte hard 

disk. 

NERSL-National Energy Research 

Seismic Library 

David J. Taylor and Frederick N. Zihlman 

The U.S. Geological Survey has been collecting 

multichannel seismic reflection data since 1973 in 

support of its missions and programs. The data, residing 

at locations in Denver, Colo., and Menlo Park, Calif., on 

standard nine-track magnetic tape, are becoming 

increasingly difficult to store and maintain properly. In 

an effort to decrease storage costs, protect data from 

deterioration, and provide a more convenient method of 

distributing seismic reflection data, the U.S. Geological 

Survey has established the National Energy Research 

Seismic Library (NERSL) in Denver. The NERSL 

catalogs, compacts, and distributes on Compact DiskRead Only Memory (CD-ROM) publicly available multichannel seismic reflection data held and acquired by the 

U.S. Geological Survey. 

The first of several NERSL products is a pilot 

CD-ROM containing processed seismic data in digital 

form which can be read by low-cost DOS-based 

microcomputers. The CD-ROM also contains 

navigation or location data for the various seismic lines, 

acquisition and processing information, and software to 

display the data and their location in either preview or 

detailed mode. The software can also be used to scale the 

data, adjust the colors assigned to trace amplitudes, and 

plot a screen image on a nine-pin dot matrix printer. In 

addition the software will allow users to retrieve the 

digital seismic reflection data in standard Society of 
Exploration Geophysicists (SEG) format for downloading to more sophisticated processing systems. 

Seismic reflection data contained in this first pilot 

CD-ROM represent nine lines from the Georges Bank 

basin off the northeastern U.S. coast, six lines from the 

southern San Juan Basin in the area of Church Rock, 

N.Mex., and one line from the northern Powder River 

basin in the area of Broadus, Mont. 

A second NERSL CD-ROM contains 29 seismic 

lines from the National Petroleum Reserve Alaska 

(NPRA) and a data base holding NPRA shotpoint 

locations in latitude and longitude, line intersection data, 

subsurface velocity information, and well information. A 

run-time version of "Paradox," a commercial data-base 

manager from Borland International, is present on the 

second NERSL CD-ROM and can be used to query the 

data base. Over the next 5 years, the aim of the NERSL 

is to broaden the software and data-base capability and 

reproduce current and future U.S. Geological Survey 

collections of publicly available digital seismic reflection 

data on CD-ROM. 

Preliminary 1 :1 00,000-Scale Geologic 

Map of Santa Maria 30' x 60' Quadrangle, 

Central Coastal California-Progress 

Toward a Digital Compilation 

Marilyn E. Tennyson 

A geologic map encompassing most of the onshore 

Santa Maria basin as well as adjoining parts of the 

southern California Coast Ranges and western 

Transverse Ranges is being compiled in support of a 

framework basin study of the Santa Maria province and 

as part of the cooperative Southern California Areal 

Mapping Project of the U.S. Geological Survey and the 

California Division of Mines and Geology. As the first 

step, in order to resolve differences between maps by 

different authors and pinpoint spots where additional 

field work is needed, published geologic maps of various 

vintages and scales, along with some unpublished new 

mapping, were photo-reduced and traced to make a 

preliminary composite. For part of the central Santa 

Maria basin, the only geologic map available is on a 

half-century-old photographic base; its contacts were 

transferred to a 1:24,000 topographic base by hand 

tracing before reduction. Some imprecision is inevitable 

using these methods, because of unstable base materials, 

differences in projection between some of the component 

maps and the 1:100,000 base map, and photographic 

distortion. In order to reduce such errors, tracings of the 

component maps are being scanned and imported into 

ARC/INFO, a commercial GIS software package. 

75 

ALACARTE, a menu interface for ARC/INFO 

developed at the U.S. Geological Survey, is being used to 

edit and tag linework, and to tag and label polygons with 

formation symbols. A plot of the partially completed 

digital version will be displayed. The scale is large enough 

to allow depiction of individual formations, but small 

enough to display regional structure. Recent revisions in 

age and correlation of stratigraphic units are 

incorporated in the map explanation. 

The map centers on the Santa Maria basin, which is 

floored by rocks of the Franciscan Complex, Coast 

Range ophiolite, and Great Valley sequence. Around the 

margins of the basin, great thicknesses of Mesozoic and 

Paleogene mostly marine sedimentary rocks are present 

beneath upper Oligocene to lower Miocene nearshore 

sandstone and bathyal mudstone. In the central part of 

the basin, lower Miocene nonmarine conglomerate and 

sandstone shed from uplifted blocks along basin-forming 

faults are present locally, resting unconformably on the 

Mesozoic rocks. Siliceous, organic-rich basinal mudrocks 

of middle Miocene to early Pliocene age blanket much of 

the region. Uppermost Miocene to Quaternary marine 

and nonmarine clastic rocks record filling of the basin 

and emergence of folded and faulted blocks. Petroleum 

generated from the Miocene basin-filling mudrocks is 

found in both sandstone and fractured reservoirs, 

trapped in Pliocene-Quaternary faulted anticlines and 

stratigraphic traps. 

Very young, large folds-two regional anticlines 

and flanking synclines-occupy the central part of the 

basin. The northern anticlinal trend (Casmalia-Orcutt) is 

separated from the Santa Maria Valley syncline to the 

north by a system of north-verging reverse faults. 

Another major north -verging reverse fault may lie in Los 

Alamos Valley, separating the southern anticline 

(Lompoc-Purisima) from the Los Alamos-San Antonio 

syncline; subsurface documentation will be required to 

confirm its existence. The geometry, offset history, and 

earthquake potential of most of the numerous faults that 

slice through the region are poorly known, and there are 

significant and as-yet unresolved differences between 

traces of major fold axes and faults as mapped by 

different workers. 

The compilation incorporates 1:24,000-scale 

mapping recently completed by J.G. Vedder and others 

(1991; U.S. Geological Survey OF 91-109, and unpub. 

data) along and southwest of the Sur-Nacimiento fault. 

This mapping shows that the East Huasna fault extends 

southeastward at least as far as the Sisquoc River and 

that the Suey fault, shown on State geologic maps, is not 

a throughgoing major structure. The West Huasna fault, 

which extends into the map area from the north, is the 

boundary between an apparent late early Miocene paleohigh on the west and a bathyal low on the east. More 

mapping and subsurface studies along the southeasterly 
projection of the West Huasna fault are needed (1) to 

establish whether it is continuous with the Little PineFoxen Canyon fault system to the southeast and (2) to 

evaluate possible strike-slip offset along the fault. 

Multifaceted Studies of a 

Lacustrine Source RockThe Paleogene Green River Formation, 

Colorado, Utah, and Wyoming 

Michele L. Tuttle, Walter E. Dean, 

Mark Stanton, James Collister, 

Wendy Harrison, Thomas D. Fouch, 

Janet Pitman, Trond Hanesand, and 

Nils Telnaes 

Geologic and geochemical studies of petroleum 

source rocks formed in lakes are fewer in number and, 

historically, less detailed than studies of source rocks 

formed in marine environments. Lacustrine sediments 

are less studied partly because of the large variability in 

physical, chemical, and biological processes within and 

among lakes. This variability limits the ability to 

construct depositional or diagenetic models that can be 

used to interpret study results from lacustrine units other 

than those originally modeled. However, we have found 

certain lithofacies of the lacustrine Paleogene Green 

River Formation to be well suited for source-rock studies 

because lithologic variability was minimal during 

hundreds of thousands to millions of years of deposition 

in the large Green River lakes. Our goal is to investigate 

processes active during deposition and diagenesis of the 

open-water facies of the Green River and to evaluate 

variability in processes among depositional basins and 

lake phases. 

The Green River formed in lakes that existed for 

10-23 m.y. in three Laramide fault-bounded basins that 

collectively covered more than 62,000 km2 • Ancient Lake 

Uinta occupied the Uinta Basin of Utah and the Piceance 

basin of Colorado, and ancient Lake Gosiute occupied 

the greater Green River basin of Wyoming. Part of the 

Green River is an excellent source rock, but in most 

areas the formation is not buried deep enough to thermochemically mature the kerogen. An exception is in the 

western portion of the Uinta Basin, Utah, where the 

lower part of the Green River is within the oil-generation 

window and has produced significant amounts of oil. 

Geochemical and biogeochemical studies used 

material cored from a 6-m.y. interval (latest early Eocene 

to middle Eocene) of the Green River that was deposited 

within the three lacustrine depocenters. The rocks within 

this interval are still immature with respect to petroleum 

generation. In order to better integrate results from each 

76 

study and to increase the applicability of these results to 

lacustrine source rocks in general, many of the analyses 

were performed on the same samples. Our studies span a 

wide range of disciplines-inorganic and organic 

chemistry; stable isotopy C4

SP2S), petrography, and 

trace-element content of sulfide minerals; stable isotopy 

of organic matter C3C/12C, 15N/4N, 34SP2S); evaluation 

of a modern lake as a geochemical analog for the ancient 

Green River Lakes Uinta and Gosiute; and an 

experimental study on iron diagenesis in saline, high-pH 

environments similar to those within the Green River 

lakes. Results and preliminary interpretations of these 

studies are appearing in U.S. Geological Survey Bulletin 

1973. Work in progress addresses major- and traceelement chemistry and stable isotopy of carbonate 

minerals C3

C/12C, 180/160), sedimentology of core 

material, and composition of the bitumen and kerogen of 

the Green River Formation. 

Results of these studies have identified chemical 

and biological processes active within each lake depocenter and variably influenced by climatic and tectonic 

cycles having observed durations from =0.1 to 5 m.y. 

Primary productivity (that of algae) is linked to these 

cycles because the cycles, in part, affected the availability 

of nutrients. Inflow was the source of sulfate and 

probably phosphate, but nitrogen was replenished by 

recycling through a complex set of inorganically and 

biologically mediated reactions. During fresh- and 

brackish-water phases, nutrients were abundant and 

productivity was high in both lakes. The abundant 

organic matter produced anoxic conditions within the 

sediment where anaerobic bacterial processes formed 

sulfide and carbonate minerals. During lake lowstands, 

Lake Uinta was sufficiently deep to remain stratified. 

Euxinic (H2S-bearing) bottom water conditions were 

established as bacteriogenic H2S diffused out of the 

sediment where extremely high porewater pH kinetically 

inhibited formation of iron sulfides. The extensive 

bacterial activity in Lake Uinta during this time, together 

with the very long stability of lake stratification, caused 

an evolution of the isotopic composition of both the 

sulfur and carbon reservoirs-in the case of sulfur, to 

unprecedented 34S enrichment. During compaction, 

saline waters were expelled, carrying solutes into 

overlying beds where additional sulfide and saline 

carbonate minerals formed. In contrast to Lake Uinta, 

Lake Gosiute was only intermittently stratified during 

lowstands due to frequent mixing of the shallow water 

column. Organic-matter production and preservation 

decreased under these conditions but were sufficient to 

support some anaerobic bacterial activity during early 

diagenesis. Again, high porewater pH inhibited iron 

sulfidization, but because the water column frequently 

mixed, euxinic conditions were ephemeral and isotopic 

evolution much less dramatic than in Lake Uinta. 
The interpretive results of these studies have 

increased our understanding of, and appreciation for, the 

complex geochemical processes affecting the Green 

River lakes. Similarities between Lakes Uinta and Gosiute have been proposed in previous studies and have 

often been used to justify extrapolations of study results 

from one lake to the other. We have shown that, although 

geochemical and biological processes within the two 

lakes were similar, depositional and diagenetic 

conditions were significantly different, and that the 

differences affected the hydrocarbon-producing 

capability of these lacustrine source rocks. 

Ground-Truthing the Distal Mississippi 

Fan with SeaMARC Images and CoresWhat Happens at the End of the Pipe 

D.C. Twichell, W.C. Schwab, C.H. Nelson, 

H.J. Lee, N.H. Kenyon, T.F. O'Brien, and 

W. Danforth 

In detailed high-resolution sidescan sonar studies 

of modern submarine fans, the channel systems have 

been the primary focus of attention. In studies of ancient 

submarine fans, the deposits at the ends of channels have 

received considerable attention; but the deposits at the 

ends of modern channels have heretofore received little 

study. The deposits and styles of deposition at the ends of 

channels on modern fan systems have been the direct 

subject of a SeaMARC I sidescan sonar and coring 

program conducted on the distal Mississippi Fan. 

In previous work, the entire Mississippi Fan was 

imaged by the GLORIA sidescan sonar system. These 

data enabled us to see the surface of the Mississippi Fan 

as a series of lobe-shaped deposits. Using the GLORIA 

image as a guide, we included in the SeaMARC I survey 

area part of the meandering main leveed channel that 

originates in the Mississippi Canyon and a smaller, 

slightly sinuous channel that extends from the main 

channel for 120 km across one of the lobe-shaped 

deposits to its distal edge, where the channel splays into 

a series of even smaller channels. These smaller channels 

have less than 2 m relief and terminate in areas of high 

acoustic backscatter. The channels, exclusive of the main 

channel, are less than 300 m wide; at the distal edge of 

the lobe, most channels are less than 100 m wide. The 

high-backscatter areas around the channels are elongate 

and have crenulated edges that have_ abrupt rather than 

gradational transitions to the surroUnding deposits. 

Relative backscatter intensity and crosscutting relations 

of the different channels and high-backscatter areas 

suggest that our survey area is composed of a series of 

even smaller depositional areas. 

77 

Cores from the survey area recovered three 

principal distinctive sedimentary facies. The first of these 

facies was gray mud with darker bands. This mud facies 

corresponded with areas of low acoustic backscatter on 

the SeaMARC images. The second facies was a graded 

clastic sand that comprised medium to fine sand at the 

base of the beds and showed no visible internal 

structures. These beds were mostly 30-50 em thick. The 

third facies was termed a chaotic sand. These chaotic 

sand beds were mostly 30-100 em thick, composed of 

Clastic sandy silt with interspersed clay clasts; they 

displayed distorted bedding and contained wood 

fragments in their upper parts. The distribution of the 

two sandy facies coincided with the areas of high acoustic 

backscatter on the SeaMARC images, but whether 

distribution of these two facies is systematic within the 

high-backscatter areas is not yet determined. Depth to 

the first sand layer varies roughly with backscatter 

strength on the sonar images. Relatively high backscatter 

areas appear to be relatively younger parts of the lobe 

inferred from the SeaMARC images, where the sandy 

facies are less deeply buried by muds. 

The SeaMARC images and coring results suggest 

that channelized flow rather than sheet flow was the 

dominant mechanism of transport of sandy sediments 

away from the main leveed channel on the Mississippi 

Fan. The presence of sand at the distal ends of the small 

channels indicates an efficient transport process across 

the outer part of the fan, and the abrupt edges of the sand 

deposits imply an abrupt transition from transport to 

deposition of the sands. The two types of sand facies 

suggest two mechanisms of sand transport. The graded 

beds are presumably transported by turbidity currents, 

and the chaotic sands as debris flows. The resulting facies 

at the ends of the channels appears to be a series of 

discontinuous lenses of sand separated by muds rather 

than a continuous sheet of sand as is inferred on ancient 

fans. This picture of the end of a channel system on a 

modern fan may be a valuable analog in the study of 

ancient as well as other modern fan systems. 

Major Frontier Exploration Plays in 

Petroleum Basins of the U.S.S.R. 

Gregory F. Ulmishek 

About 2 dozen sedimentary basins produce oil and 

gas in the U.S.S.R. (fig. 1). Several currently 

unproductive regions, many of them offshore, possess 

good potential for significant discoveries. Major 

exploration activity is concentrated at present in the West 

Siberian, Timan-Pechora, and North Caspian basins. 

These three basins and offshore areas of the North 
~ 

t:a::~o~ ( ~// 

.. I~::·.~~ ()~ I CARPATHIAN ·::., ··a;;:TIC (J [J [J BASI~/ BASIN 

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, 

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LENA-TUNGUSKA '• •••••• •• BASIN 

............. , 

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. .. --- 'u~rs~~T --~ 'o ~- ~<~::_;· ~<-:< .. : .. :·:;_:) .. :.:<<, ·.:·:' .. ... ::::'._;~/ :·.<·:\: Baikal Lake 1 ~ • , , 1 Aral Lake ~ '·:::·: ..... ...-' " .... \ I '-;.. ...... · .. ···· , I 

~-..:\··., ,' ,:··~~ CHU-SARYSU -........._'<?, _/ 

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TAJik ..... .L.L I 

BASIN -,J 

0 500 1000 KILOMETERS I I I I I I I I I I 

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Figure 1 (Ufmishek). Petroleum basins of the U.S.S.R. 

. . ?.···: 

0 

Sea of Okhotsk D 
Sakhalin and South Caspian basins currently attract most 

of the attention of international oil companies. 

In the oil-productive Middle Ob region of the West 

Siberian basin, most of the large structural traps in 

Neocomian rocks (main basin producer) have already 

been discovered. Major exploration efforts are directed 

now toward stratigraphic traps in the Neocomian deltaic 

section and to structural and stratigraphic traps in 

underlying Jurassic continental clastics. The efficiency of 

exploration in these deeper plays is significantly lower. In 

the gas-prone northern part of the basin, recent drilling 

offshore in the southern Kara Sea resulted in huge gas 

discoveries. However, the economic viability of these 

discoveries is very doubtful. 

The approach to exploration in the North Caspian 

basin is still strongly influenced by supergiant discoveries 

in the Tengiz (oil) and Karachaganak (gas condensate) 

fields. However, no additional significant discoveries 

have been made in more than 10 years. Carbonate 

platforms and associated reefs remain the main play, but 

poor seismic resolution hampers exploration. Clastic 

wedges (clinoforms) on the basin's margins are the 

secondary exploration objective. Better understanding of 

trap distribution and geochemical modeling are needed 

for success. 

The last 10 years of exploration in the TimanPechora basin were moderately successful. Although no 

giants were found, many medium-size fields were 

reportedly discovered. Two major exploration plays are 

Upper Devonian reefs and drape structures over them in 

the Vuktyl-Dzhebol intrashelf basin, and Upper Silurian 

through Lower Permian carbonates in structural traps in 

the previously unexplored northeastern area of the basin. 

An oil discovery in the ·prirazlomnaya field offshore 

sparked much interest, but the discovery itself is 

noncommercial. 

The Barents Sea may become an important 

hydrocarbon-producing province in the future. The giant 

(100-140 TCF) Shtokman discovery is undergoing a 

feasibility study. Several other discoveries, although 

much smaller, support a high resource assessment. 

However, Upper Triassic and Jurassic prospects are 

obviously gas prone, and the potential of deeper Paleozoic reservoirs for oil is uncertain. 

An important oil and gas discovery in the Yurubchen field on the southwest of the Lena-Tunguska basin 

(East Siberia) identified a new play with possibly 

significant exploration potential. The hydrocarbons are in 

Riphean vuggy carbonates, and the geology indicates that 

the source rocks are also in the Riphean. Previous 

discoveries were mostly in younger rocks of the NepaBotuoba arch, on which hydrocarbon-source rocks are 

practically absent. 

The offshore part of the North Sakhalin basin 

recently attracted much interest from western oil 

79 

companies. This offshore area is very lightly explored 

although several rather sizable (150-400 million barrels) 

discoveries have been made. In addition to the main 

exploration play in Miocene-Pliocene deltaic sandstones 

of the paleo-Amur River, the area has a good potential 

for significant oil reserves in fractured diatomaceous 

shales of Monterey Formation type. 

The South Caspian basin is the oldest oil producer 

in the U.S.S.R. However, the geology of the basin, and 

especially its offshore part, is still poorly understood. 

Water is deep (to 1,000 m) in the unexplored central part 

of the southern Caspian Sea, but the wide eastern shelf is 

also almost undrilled. More data on distribution of 

source rocks and reservoir rocks are needed for 

prospecting on the shelf. 

Many other, more maturely explored basins of the 

U.S.S.R. still possess a significant undiscovered oil and 

gas potential. Some frontier basins in the Arctic and 

Pacific Oceans are very poorly known, but may become 

interesting exploration targets. 

The Coal Resource Evaluation and 

Assessment Project (COALREAP) in 

Pakistan-Energy for the Future 

Peter D. Warwick, John R. SanFilipo, 

Roger E. Thomas, and James E. Fassett 

In August 1985, the U.S. Agency for International 

Development, as part of its long-range "Energy Planning 

and Development Project" in Pakistan, contracted with 

the USGS to assist the Geological Survey of Pakistan 

(GSP) in a multidisciplinary program to assess Pakistan's 

Tertiary coal resources (fig. 1 ), to train GSP geologists in 

various aspects of geology, and to improve the GSP's 

physical facilities. Investigations were carried out 

through 1989 to map and assess the quantity and quality 

of the coal resources of southern Sindh at 1:50,000 scale. 

Drilling in the Lakhra and Sonda coal fields by a private 

contractor and the GSP totaled 71 holes. 

Results indicate that presently known and mined 

coal fields in southern Sindh are not isolated coal basins; 

rather, much of southern Sindh, including the Thar 

Desert, appears to be continuously underlain by coalbearing rocks. Coal resources of 1,080 million t (metric 

tons) have been estimated for seven out of nine identified 

coal zones in those parts of the Lakhra area where 

coal-bed thicknesses range from a few centimeters to 5 

m. In the Sonda West area, 3, 700 million t of coal have 

been identified, the thickest coal bed being 6.3 m. In the 

Sonda East area, coal-bed thickness is as much as 2.4 m 

and coal resources for 10 zones have been estimated at 

1,500 million t. The apparent rank of the coal in these 
1 SONDA EAST 

2 SONDA WEST 

64. 

3 METING-JHIMPIR 

4 LAKHRA 

72. 

L:-

~orthern 

PEOPLE'S 

REPUBLIC OF 

CHINA 

5 THAR DESERT 

6 DUREJI 

Nort~ Areas 

West -)"-"-\._........,_ AFGHANISTAN ,/. ·· , ron-\e 7 BALGOR 

8 SANNI ( t · 125 cease-fire I ine 

~er" ..---

Fed. Admin. 2~1' .- '~\. Azad 22 

' - 4' K hm" 9 JOHAN 

( . 0 ----...:_,· as tr - 32" 10 MACH-AB E GUM 

11 ABI GUL 

12 MARGAT __ ./) 

13 PIR ISMAIL ZIARAT ~/· 15 19o ( 

14 " ,. ~ 6 1 7 ~8 1 

~-~ ... ,/ 1J 12 13 

9 0 1&'10 \ 

I 

Arabian Sea 

0 200 Km 

I I 

0 I 200 Mi 

Punjab 

14 SOR RANGE-DAGHARI 

15 KACH 

16 KHOST-SHARIG-HARNAI 

17 DUKI 

18 CHAMALONG 

19 BADINZAI 

20 MAKARWAL-KURD-SHO 

21 CHERAT 

22 CHOI 

23 SALT RANGE 

24 KOTLI 

25 KH I LLA MUZAFF ARABAD 

26 HANGU 

- 24" 

Figure 1 (Warwick and others). Location of Pakistan coal fields and occurrences. Box shows 

Punjab Regional Framework area. 

fields ranges from lignite to subbituminous. Additional 

drilling and field work, mainly to identify coal reserves for 

mine development, are scheduled for these areas. 

More than 400 core and mine samples were 

collected in south Sindh for proximate and ultimate 

analyses and determinations of major, minor, and trace 

elements. Analytical results on an as-received basis 

indicate that sampled coal beds contain on the average 

31.3 percent moisture, 17.3 percent ash, 4.5 percent 

sulfur, 23.2 percent fJXed carbon, 27.6 percent volatile 

matter, and 34.9 percent oxygen. Calculated heating 

potentials expressed as averaged calorific values are: 

Lakhra coal samples 3,660 Kcal/kg, Sonda West samples 

4,020 Kcal/kg, and Sanda East samples 3,720 Kcal/kg. 

80 

A second phase of COALREAP, begun in FY 88 

with surface exploration in the Salt Range coal field, 

Punjab Province, revealed an average coal bed thickness 

in the Salt Range area of 0.5 m and provided a 

preliminary coal-resource estimate of 235 million t. 

Analytical results on an as-received basis indicate that 

coal beds contain on the average 9.0 percent moisture, 

24.2 percent ash, 5.3 percent sulfur, 33.5 percent fJXed 

carbon, 33.3 percent volatile matter, and 16.1 percent 

oxygen. Calculated heating potential expressed as 

averaged calorific values is 4,970 Kcal/kg; apparent rank 

is bituminous. Similar resource exploration projects, 

including regional structural and biostratigraphic studies, 

are continuing in the other coal fields of Punjab, NorthWest Frontier, Sindh, and Balochistan Provinces. 
To supplement coal exploration work in the Salt 

Range-Potwar Plateau area, a regional framework study 

was undertaken in 1988. This program is designed to 

provide training to GSP geologists and technicians 

working with USGS counterparts, and when expanded to 

other regions, will serve as a guide for the 1:250,000-scale 

evaluation of the geologic framework of Pakistan's coal 

fields. 

COALREAP is scheduled for completion in 1992. 

Detailed descriptions of project work and results are 

included in 33 administrative reports, many of which 

have been released as USGS Open-File Reports or 

published in scientific journals. 

Diagenesis in a Bottle-Experimental 

Strategies for Studying Thermal Maturity 

in Clays and Organic Matter 

Gene Whitney and Michael D. Lewan 

Our experimental studies of clay diagenesis and oil 

generation demonstrate that it is possible to understand 

major aspects of complex diagenetic reactions by 

performing relatively simple experiments. It is difficult to 

understand the details of these diagenetic reactions in 

natural systems because the reactions (1) rarely reach 

equilibrium, (2) are often kinetically controlled and tend 

to be slow because of low temperatures, (3) are often 

irreversible, ( 4) usually involve a complex assemblage of 

heterogeneous fluids and fine-grained solids, and (5) 

proceed in an open chemical system. In addition, naturalsystems exhibit variations in lithofacies or organic facies, 

and samples representing an entire reaction series of 

interest are usually difficult or impossible to obtain. In 

fact, reactions used to monitor thermal maturity of 

sediments may actually be groups or series of 

fundamental reactions which cannot be thoroughly 

understood except through experimentation. 

Our general approach to experimental investigation of these reactions is: (1) identify a critical diagenetic reaction (or set of reactions) in nature, (2) devise 

experiments to test and measure the effects of key 

variables in the reaction, (3) conduct experiments over a 

range of temperatures and times using appropriate 

starting materials, ( 4) interpret reaction mechanisms and 

(or) calculate reaction rates and determine rate laws, and 

(5) validate the interpretations of experimental data by 

comparing experimental results with natural diagenetic 

settings. Using this approach, we have studied the illitization reaction (conversion of smectite to illite via an 

interstratified illite/smectite (1/S) intermediate phase) 

and oil generation. 

The illitization reaction has been used as a thermal 

maturity indicator, but our confidence in this reaction as 

81 

a geothermometer is diminished by some observed 

exceptions to empirical trends. Our experiments have 

shown that illitization is not a single reaction, but is in 

fact a complex series of dissolution and precipitation 

processes. The reaction consists of (at least) two separate 

stages that proceed by different mechanisms. The rate 

and extent of these reaction processes are predictably 

controlled primarily by temperature and time, but 

solution chemistry, chemical composition of the starting 

smectite, fluid:solid ratio, and texture also affect the 

overall reaction significantly. The two stages of illitization 

have different rates of isotopic exchange and different 

rates of solute release, thus affecting mass balance in 

shales during the course of diagenetic alteration. 

Kinetic models derived from natural data do not 

adequately describe or predict the timing of oil 

generation in sedimentary basins. Our experiments show 

that the rate and extent of oil generation from thermally 

decomposing organic matter cannot be described by one 

universal set of kinetic parameters or by direct 

correlation with a vitrinite reflectance scale. Bond types 

and the amount of sulfur bonding in organic matter are 

critical in determining the rate and extent of oil 

generation. Experiments have also demonstrated that 

pressure and water salinity may be important factors in 

oil generation. 

Oil generation and illitization reactions are both 

scientifically and economically important, and our future 

experimental work will be aimed at understanding and 

quantifying the interaction of clay minerals and organic 

matter during diagenesis. 

Late Paleocene and Early Eocene 

Terrestrial and Marine Environments, 

Lakhra Coal Field, Sindh Province, 

Pakistan 

Christopher Wnuk, Elisabeth M. Brouwers, 

and Norman Frederiksen 

The upper Paleocene sedimentary rocks of south 

Sindh are divided into four units. The coal-bearing upper 

part of the Bara Formation ( > 250 m) is stratigraphically 

lowest, followed by the Lakhra Formation (194m), the 

coal-bearing Sohnari Formation (58 m), and the basal 

part of the Meting Limestone and Shale Member of the 

Laki Formation (unmeasured). The Bara Formation 

consists of as many as 18 cycles of facies successions. 

Well-sorted, fine- to medium-grained quartz arenites 

occur at cycle bases. These sandstones contain planartangential crossbeds, some of which are as much as 15 m 

high; these sandstones exhibit unmistakable evidence of 

tidal influence, specifically, sigmoidal tidal bundles with 
clay couplets, graded crossbed laminae, and bidirectional 

crossbedding. All these marine sand bodies are in sharp 

or erosive contact with the terrestrial facies of the 

underlying cycle. The sediments of the basal facies are 

interpreted as sand waves and sand ridges that 

accumulated on tide-dominated inner shelf 

environments. The clean basal sandstones grade upward 

into estuarine and intertidal dirty sandstones, siltstones, 

and claystones containing wavy, flaser, and lenticular 

bedding. Coastal peat swamps prograded over and 

rooted through the intertidal sediments. In places, storm 

beds consisting of poorly sorted, dirty, calcareous 

sandstones and arenaceous limestones containing graded 

intraformational rip-up clasts and shell fragments are 

interbedded with the estuarine deposits. Abundant pyrite 

and carbonaceous debris suggest that the estuarine 

sediments were anoxic. That stunted ostracode faunas 

occur suggests that the sediment-water interface was 

dysaerobic at times. The coals formed in a marginal 

marine environment, which is indicated by mangrove 

pollen and dinoflagellates in beds adjacent to the coals, 

the occurrence of mangrove pollen in some coal samples, 

the high sulfur content of most coal beds, and the 

abundance of current-rippled quartz-arenite partings in 

the coal beds. The distribution of coal beds within cycles 

was controlled by the localized compaction and dewatering of the estuarine and intertidal sediments. 

Consequently, individual coal beds are lenticular and 

discontinuous even though coal zones are persistent. 

Patterns of increasing ostracode species diversity 

and specimen abundance show that the Bara Formation 

becomes increasingly marine upsection toward its 

gradational contact with the Lakhra Formation. The 

ostracode assemblages indicate that the uppermost part 

of the Bara and all of the Lakhra Formation were 

deposited in waters of normal marine salinity. 

The Lakhra Formation is mostly composed of beds 

of intensely bioturbated glauconitic sandstone, and less 

bioturbated, wavy, lenticular, and flatbedded siltstone 

and claystone. Cyclicity in ostracode abundance and 

diversity suggests that the cyclic shoaling-upward 

patterns of the Bara persist into the Lakhra. In contrast 

to the Bara, the Lakhra contains abundant shell 

fragments and glauconite and sparse carbonaceous 

debris; storm beds are abundant. Argillaceous foraminiferal limestone and cleaner, skeletal limestone appear in 

the upper part of the unit and compose about 20 percent 

of the total section, though geophysical logs indicate that 

the Lakhra may locally consist almost entirely of 

limestone. 

An increase in ostracode diversity and an increase 

in the proportion of delicately ornamented taxa imply 

that the depth of the water in which the sediments were 

deposited became greater upward within the Lakhra. 

Species diversity and abundance decrease near the top of 

the Lakhra as it grades into the more terrestrial Bara-like 

82 

Sohnari Formation. The Sohnari contains one coal zone, 

and sedimentation patterns become Lakhra-like again 

above the highest coal. The Sohnari fauna and flora 

contain alternating marginal-marine and shallow-marine 

assemblages, with several cycles indicated by fluctuations 

in ostracode abundance and diversity. 

The abrupt change from predominantly clastic 

sedimentation of the Bara, Lakhra, and Sohnari to the 

predominantly carbonate sedimentation of the Meting 

Limestone suggests an unconformity between the 

Sohnari and the Meting Limestone. Paleontological 

evidence suggests that the Paleocene-Eocene boundary 

occurs within the basal Meting, somewhere above the 

Sohnari-Meting contact. 

Energy Research on Indian Lands 

R.S. Zech, H.H. Arndt, L.H. Biewick, 

J.K. Hardie, R.C. Johnson, J.L. Ridgley, 

Courtenay Williamson, and 

Robyn Wright-Dunbar 

The U.S. Geological Survey conducts energyrelated research on Indian lands in cooperation with 

Tribal governments and the Bureau of Indian Affairs. 

These studies are conducted in areas that range from 

small and site specific to large regions containing several 

Reservations. The studies may include methods as 

diverse as the airborne measurement of magnetics, 

drilling, and laboratory measurement of vitrinite 

reflectance. Research projects on the Ute Mountain Ute, 

Wind River, Fort Peck, and Southern Ute Reservations 

are examples of investigations during the last 2 years that 

are completed or are in progress. 

Research on hydrocarbon reservoirs within the Ute 

Mountain Ute and Southern Ute Reservations 

(Colorado and New Mexico) focuses on the Upper 

Cretaceous Point Lookout Sandstone. This investigation 

has two parts: (1) description of sandstone geometry and 

depositional environments based on outcrop study, and 

(2) petrographic reservoir characterization from core 

samples. Outcrop sections in the area between Pagosa 

Springs and the mouth of Mancos Canyon, south of 

Cortez, Colo., show a change from thick deposits of a 

linear strandplain to thinner deposits of a delta. Studies 

of two drill cores obtained near the western boundary of 

the Southern Ute Reservation measured the porosity and 

permeability of sandstones and correlated these 

parameters to depositional environments and electric 

logs. These studies of the Point Lookout provide the 

basic data for characterizing the reservoir in this area and 

provide a model for other regressive sandstone reservoirs 

of the Western Interior seaway. The study should be 

completed in 1992. 
The assessment of the coal resource of the Fort 

Peck Reservation, Montana, began with collection of 

data from drilling, measured sections, and logging more · 

than 500 seismograph shot holes and water wells. From 

these data, isopach, structure, occurrence, and overburden maps were generated for each of the 15 potentially 

mineable coal beds identified in the area. Coal samples 

collected across the Reservation were analyzed, and 

thickness and extent of coal were entered into the 

National Coal Resources Data System. Surficial and 

subsurface mapping of rock units was conducted, and 

illustrative products including cross sections, geologic 

maps, structure maps, and isopach maps were generated. 

Coal resources were then calculated. In addition to 

providing an improved understanding of the geology and 

coal resources of the area, this study identified gravel 

deposits, aquifers, and possible hydrocarbon reservoirs. 

Assessment of oil, gas, and coal-bed methane 

resources of the Wind River Reservation, Wyoming, 

began in 1990 and will be completed in 1993. Oil and gas 

assessment here consists of several procedures: (1) 

structure-contour, lithologic, and isopach maps are 

constructed for productive intervals; (2) thermal 

maturity and source-rock studies indicate areas where 

hydrocarbons have been generated and help define 

possible migration pathways; (3) gravity and magnetic 

studies determine the structure; and ( 4) detailed surface 

and subsurface studies establish the depositional facies of 

productive beds and help integrate other aspects of the 

83 

investigation. Thus far the marginal lacustrine units in 

the Paleocene Fort Union Formation appear to have the 

greatest potential for undiscovered hydrocarbons. To 

evaluate coalbed methane resources, coal-rank maps, 

coal-isopach maps, and structure-contour maps are 

being constructed. In addition, a drilling program to 

determine the methane content of coals at shallow depth 

( < 1,000 ft) was carried out during 1990 and 1991. 

Significant quantities of methane were discovered in 

shallow Cretaceous coal over a large area in the southern 

and central parts of the Reservation. 

The Southern Ute Dakota project of southwestern 

Colorado has focused on the structural, sedimentologic, 

and depositional history of the Upper Cretaceous Dakota 

Sandstone, a major gas producer. The Dakota was 

divided into six genetic packages, each related to major 

or minor transgression or regression. Sandstone 

geometry and depositional systems for each genetic 

package were defined and compared to local and 

regional structure. The sandstone bodies have a 

pronounced NW~NE orientation coincident with the 

regional structural framework, suggesting subtle 

structural control on location and thickness of fluvial and 

coastal marine sandstone bodies. Gas production is from 

distributary channel, deltaic, and shoal sandstones and 

appears to be controlled more by depositional facies than 

by structure. This study was recently completed, and the 

results will be published as a U.S. Geological Survey 

Professional Paper. 
AUTHOR INDEX 

A 

Ahlbrandt, T.S., USGS, Denver.......................................................................................................................................................... 1 

Alam, A.M.N., Geological Survey of Bangladesh, Dhaka, Bangladesh ..................................................................................... 39 

Ambroziak, R.A., USGS, Reston ..................................................................................................................................................... 57 

Armstrong, A.K, New Mexico Bureau of Mines and Mineral Resources, Socorro, NM 87801 .......................................... 42 

Arndt, H.H., USGS, Denver .............................................................................................................................................................. 82 

Arthur, M.A., Department of Geosciences, The Pennsylvania State University, 503-A Deike Bldg., University Park, 

PA 16802 ........................................................................................................................................................................................... 17 

Attanasi, E.D., USGS, Reston .......................................................................................................................................................... 68 

B 

Ball, M.M., USGS, Denver.................................................................................................................................................................. 2 

Barton, C.C., USGS, Denver ............................................................................................................................................................... 3 

Beard, L.S., USGS, Flagstaff ............................................................................................................................................................. 47 

Beyer, L.A., USGS, Menlo Park ..................................................................................................................................... ,................... 3 

Biewick, L.R.H., USGS, Denver ................................................................................................................................................... 5, 82 

Bird, K.J., USGS, Menlo Park ................................................................................................................................................. 7, 8, 51 

Blake, Dorsey, USGS, Denver ........................................................................................................................................................... 5 

Blank, H.R., USGS, Denver ............................................................................................................................................................... 8 

Bogino, Vladamir, Petroleum Research Institute, Minsk, U.S.S.R ............................................................................................... 2 

Bohannon, R.G., USGS, Menlo Park ................................................................................................................................................ 11 

Bradley, D.C., USGS, Anchorage ..................................................................................................................................................... 11 

Bredehoeft, J.D., USGS, Menlo Park ............................................................................................................................................... 13 

Brouwers, E.M., USGS, Denver ....................................................................................................................................................... 81 

Burruss, R.C., USGS, Denver ........................................................................................................................................................... 68 

c 

Carter, M.D., USGS, Reston ............................................................................................................................................................. 13 

Cecil, C.B., USGS, Reston ................................................................................................................................................................. 14 

Clayton, J.L, USGS, Denver .................................................................................................................................................. 2, 24, 64 

Cobb, J.C., Kentucky Geological Survey, Lexington, KY 40506--0107 ........................................................................................ 13 

Cobban, W.A., USGS, Denver .......................................................................................................................................................... 31 

Cole, R.B., Department of Geological Sciences, University of Rochester, Rochester, NY 14627 ....................................... 73 

Collett, T.S., USGS, Denver ......................................................................................................................................................... 7, 14 

Collister, James, Department of Geology, Indiana University, Bloomington, IN 47405 ....................................................... 76 

Cook, H.E., USGS, Menlo Park ....................................................................................................................................................... 65 

Crovelli, R.A., USGS, Denver ........................................................................................................................................................... 21 

Crysdale, B.L., USGS, Denver .......................................................................................................................................................... 15 

Cunningham, KI., USGS, Denver ..................................................................................................................................................... 16 

D 

Dalrymple, Brent, USGS, Reston ..................................................................................................................................................... 36 

Danforth, W., USGS, Woods Hole .................................................................................................................................................. 77 

Daws, T.A., USGS, Denver ................................................................................................................................................................ 2 

Dean, W.E., USGS, Denver ................................................................................................................................................. 17, 65, 76 

Dillon, W.P., USGS, Woods Hole............................................................................................................................................. 18, 26 

Dolton, G.L., USGS, Denver ........................................................................................................................................................ 2, 21 

Drew, L.J ., USGS, Reston ................................................................................................................................................................ 22 

Dubiel, R.F., USGS, Denver............................................................................................................................................................. 24 

E 

Edgar, N.T., USGS, Reston .............................................................................................................................................................. 24 

Ellis, M.S., USGS, Denver ............................................................................................................................................................. 5, 66 

84 
F 

Fassett, J.E., USGS, Reston ............................................................................................................................................................ 79 

Fedorko, Nick III, West Virginia Geologic and Economic Sutvey, Morgantown, WV 26507-0879 ................................. 13 

Fehlhaber, Kristen, USGS, Woods Hole .................................................................................................................................. 18, 26 

Filewicz, M.V., Unocal Corp., P.O. Box 6176, Ventura, CA 93006 ......................................................................................... 73 

Finkelman, R.B., USGS, Reston ..................................................................................................................................................... 27 

Fishman, N.S., USGS, Denver ......................................................................................................................................................... 28 

Fitzpatrick, J.J., USGS, Denver ...................................................................................................................................................... 29 

Flores, R.M., USGS, Denver ................................................................................................................................................. 5, 64, ,66 

Fouch, T.D., USGS, Denver ................................................................................................................................... 13, 29, 31, 54,76 

Franczyk, KJ ., USGS, Denver .......................................................................................................................................................... 31 

Frederiksen, Norman, USGS, Reston .............................................................................................................................................. 81 

Purer, L.C., Indiana Geological Sutvey, 611 North Walnut Grove Ave., Bloomington, IN 47405 ................................... 44 

G 

Gardner, N .K., USGS, Reston ........................................................................................................................................................ 13 

Gay, F.E., USGS, Denver ................................................................................................................................................................. 57 

Geist, E.L., USGS, Menlo Park ........................................................................................................................................................ 11 

Golmshtok, A.J., Institute Oceanology, U.S.S.R. Academy of Sciences, Gelendzhik, U.S.S.R. .......................................... 37 

Good, S.C., Department of Geological Sciences, University of Colorado, Boulder, CO 80309 ......................................... 24 

Grow, J.A., USGS, Denver ..................................................................................................................................................... 8, 60, 65 

H 

Halley, R.B., USGS, St. Petersburg, FL .......................................................................................................................................... 31 

Hanesand, Trond, Norsk Hydro a.s. Research Centre Petroleum Geochemistry, Bergen, Norway................................... 76 

Hardie, J.K., USGS, Denver .............................................................................................................................................................. 82 

Harrison, Wendy, Department of Geology and Geological Engineering, Colorado School of Mines, Golden, CO 80401. 76 

Hatch, J.R., USGS, Denver ......................................................................................................................................................... 33, 68 

Hester, T.C., USGS, Denver ............................................................................................................................................................. 33 

Hettinger, R.D., USGS, Denver ..................................................................................................................................................... 34 

Higley, D.K., USGS, Denver ........................................................................................................................................................... 73 

Hinkley, T.K, USGS, Denver............................................................................................................................................................ 29 

Holdsworth, G., NHRI, Saskatoon, Saskatchewan........................................................................................................................ 29 

Holmes, C.W., USGS, Denver ........................................................................................................................................................ 36 

Howell, D.G., USGS, Menlo Park............................................................................................................................................... 8, 36 

Huffman, A. C., Jr., USGS, Denver.................................................................................................................................................. 65 

Hutchinson, D.R., USGS, Woods Hole........................................................................................................................................... 37 

Isaacs, C.M., USGS, Menlo Park ............................................................................................................................................... 39, 41 

J 

Johnson, R.C., USGS, Denver ..................................................................................................................................................... 31, 82 

Johnson, S.Y., USGS, Denver ............................................................................................................................................... 39, 65, 73 

Johnsson, M.J ., USGS, Menlo Park................................................................................................................................................. 8 

K 

Kaiser, W.R., Texas Bureau of Economic Geology, University of Texas at Austin, Austin, TX 78713.............................. 27 

Karl, S.M., USGS, Anchorage........................................................................................................................................................... 51 

Keighin, C. W., USGS, Denver ......................................................................................................................................................... 41 

Keller, M.A., USGS, Menlo Park ..................................................................................................................................................... 41 

Keller, Michael, Ministry of Geology, Moscow, U.S.S.R.............................................................................................................. 2 

Kelley, J.S., USGS, Anchorage ......................................................................................................................................................... 42 

Kenyon, N.H., Institute of Oceanographic Sciences, Wormley, U.K. ........................................................................................ 77 

Kidd, W.S.F., Department of Geological Sciences, SUNY, Albany, NY 12222 ..................................................................... 11 

Kirschbaum, M.A., USGS, Denver .................................................................................................................................................. 43 

Klitgord, K.D., USGS, Woods Hole ................................................................................................................................................. 37 

Kolata, D.R., Illinois State Geological Sutvey, 615 E. Peabody Dr., Champaign, IL 61821 ............................................... 44 

Krohn, K.K, USGS, Reston ............................................................................................................................................................. 44 

85 
L 

Landis, G.P., USGS, Denver ........................................................................................................................................................... 29 

Law, B.E., USGS, Denver ................................................................................................................................................................ 64 

ue, H.J ., USGS, Menlo Park........................................................................................................................................................... 77 

I..,ee, M.W., USGS, Denver .................................................................................................................................................. 18, 26,37 

urch, H.E., USGS, Reston .............................................................................................................................................................. 45 

l.,ewan, M.D., USGS, Denver ..................................................................................................................................................... 46, 81 

Lillis, P.G., USGS, Denver................................................................................................................................................................. 2 

Lore, G.L., Minerals Management Service, New Orleans, LA 70123 ....................................................................................... 22 

Lund, Karen, USGS, Denver ...................................................................................................................................................... 47, 60 

Luppens, J.A., Phillips Coal Co., 2929 N. Central Expressway, Richardson, TX 75080 ........................................................ 27 

M 

Magoon, L.B., USGS, Menlo Park ................................................................................................................................................... 8 

Mason, M.A., 1215 Roosevelt Ave., Richmond, CA 94801 ........................................................................................................ 73 

Mast, R.F., USGS, Denver............................................................................................................................................... 2, 18, 21~ 73 

Masters, C.D., USGS, Reston........................................................................................................................................................... 47 

McCabe, P.J., USGS, Denver ........................................................................................................................................ 34, 43, 50, 67 

Meyer, RF., USGS, Reston .................................................. :............................................................................................................ 15 

M'Gonigle, John, USGS, Denver ..................................................................................................................................................... 36 

Michalski, T.C., USGS, Denver ........................................................................................................................................................ 64 

Miller, W.G., USGS, Reston ....................................................................................................................................................... 44, 50 

Molenaar, C.M., USGS, Denver ....................................................................................................................................................... 31 

Molnia, C.L., USGS, Denver ........................................................................................................................................................ 5, 44 

Moore, T.A., USGS, Reston ............................................................................................................................................................. 45 

Moore, T.C., University of Michigan, Ann Arbor, MI 48190 ..................................................................................................... 37 

Moore, T.E., USGS, Menlo Park .................................................................................................................................................... 51 

Mull, C.G., Alaska Division of Geological and Geophysical Surveys, Fairbanks, AK 99709 ................................................ 51 

N 

Nelson, C.H., USGS, Menlo Park ................................................................................................................................................... 77 

Nelson, W.J., Illinois State Geological Survey, 615 E. Peabody Dr., Champaign, IL 61821 ............................................... 44 

Nichols, D.J., USGS, Denver ............................................................................................................................................................. 66 

Noger, M.C., Kentucky Geological Survey, uxington, KY......................................................................................................... 44 

Normark, W.R., USGS, Menlo Park ............................................................................................................................................... 52 

Nuccio, V.F., USGS, Denver ............................................................................................................................................................ 54 

0 Obrad~vich, J.D., USGS, Denver ..................................................................................................................................................... 73 

O'Brien, T.F., USGS, Woods Hole .................................................................................................................................................. 77 

Orem, W.H., USGS, Reston .............................................................................................................................................................. 45 

p 

Patacas, J.G., USGS, Denver ............................................................................................................................................................. 58 

Pantea, M.P., USGS, Denver ............................................................................................................................................................. 57 

Pawlewicz, Mark, USGS, Denver ...................................................................................................................................................... 58 

Perry, W.J., Jr., USGS, Denver............................................................................................................................................ 47, 60, 66 

Peterson, Fred, USGS, Denver ......................................................................................................................................................... 59 

Pitman, J.K., USGS, Denver ....................................................................................................................................................... 29, 76 

Pollastro, R.M., USGS, Denver........................................................................................................................................................ 59 

Potter, C.J., USGS, Denver ......................................................................................................................................................... 60, 65 

Poznaikovitch, Zinovy, Petroleum Research Institute, Minsk, U.S.S.R ...................................................................................... 2 

Price, uigh, USGS, Denver .............................................................................................................................................................. 63 

R 

Rice, D.O., USGS, Denver ............................................................................................................................................................... 64 

Richards, D.L., USGS, Denver......................................................................................................................................................... 64 

Ridgley, J.L., USGS, Denver ...................................................................................................................................................... 65, 82 

86 
Robbins, S.L., USGS, Denver .......................................................................................................................................................... 65 

Roberts, L.N.R, USGS, Denver....................................................................................................................................................... 43 

Roberts, S.B., USGS, Denver ........................................................................................................................................................... 66 

Robinson, J.W., Dept. of Geology and Geological Engineering, Colorado School of Mines, Golden, CO....................... 67 

Root, D.H., USGS, Reston ............................................................................................................................................................... 68 

Ryder, R.T., USGS, Reston............................................................................................................................................................... 68 

Rye, R.O., USGS, Denver ................................................................................................................................................................. 29 

s 

SanFilipo, J.R., USGS, Reston .......................................................................................................................................................... 79 

Sargent, M.L., Illinois State Geological Sutvey, 615 E. Peabody Dr., Champaign, IL 61821 ............................................... 44 

Schenk, C.J., USGS, Denver .............................................................................................................................. 15, 24, 41, 59, 69,70 

Schmoker, J.W., USGS, Denver ..................................................................................................................................... 33, 54, 70,71 

Scholz, C.A., Duke University Marine l..ab, Beaufort, NC 28516 ............................................................................................... 37 

Schwab, W.C., USGS, Woods Hole ................................................................................................................................................... 77 

Sites, RS., Virginia Division of Mineral Resources, Charlottesville, VA 22903 ...................................................................... 13 

Smoot, J.P., USGS, Denver ................................................................................................................................................................. 72 

Snee, L.W., USGS, Denver ................................................................................................................................................................. 47 

Stanley, R.G., USGS, Menlo Park ............................................................................................................ ~ .................................. 41, 73 

Stanton, Mark, USGS, Denver ........................................................................................................................................................... 76 

Stanton, R.W., USGS, Reston ............................................................................................................................................................ 64 

Stricker, G.D., USGS, Denver ............................................................................................................................................................ 66 

Swisher, C. C. III, Geochronology Center at the Institute for Human Origins, 2453 Ridge Road, Berkeley, CA 94709. 73 

Sykes, Richard, DSIR, Geology and Geophysics, Lower Hutt, New Zealand ............................................................................ 5 

T 

Takahashi, KI., USGS, Denver................................................................................................................................................... 16, 73 

Taylor, D.J., USGS, Denver ................................................................................................................................................................ 74 

Telnaes, Nils, Norsk Hydro a.s. Research Centre Petroleum Geochemistry, Bergen, Nmway .............................................. 76 

Tennyson, M.E., USGS, Denver ......................................................................................................................................................... 75 

Tewalt, SJ., USGS, Reston .......................................................................................................................................................... 27, 44 

Thomas, R.E., USGS, Reston ............................................................................................................................................................. 79 

Thornton, M.L.C., Unocal Corp., P.O. Box 6176, Ventura, CA 93006 ...................................................................................... 73 

Treworgy, J.D., Illinois State Geological Sutvey, 615 E. Peabody Dr., Champaign, IL 61821 .............................................. 44 

Turner, C.E., USGS, Denver ............................................................................................................................................................. 28 

Tuttle, M.L., USGS, Denver ........................................................................................................................................................ 73, 76 

Twichell, D.C., USGS, Woods Hole .................................................................................................................................................. 77 

U-V 

Ulmishek, Gregory, USGS, Denver............................................................................................................................................. 2, 77 

Vork, D.R., Unocal Corp., P.O. Box 6176, Ventura, CA 93006 .................................................................................................. 73 

w 

Wallace, W.K, Department of Geology and Geophysics, University of Alaska, Fairbanks, AK 99775 ............................... 51 

Warden, Augusta, USGS, Denver...................................................................................................................................................... 2 

Warwick, P.D., USGS, Reston .................................................................................................... _........................................................ 79 

Wesley, J.B., USGS, Denver, and Colorado School of Mines, Golden, CO ............................................................................ 13 

Whitaker, S.T., Illinois State Geological Survey, 615 E. Peabody Dr., Champaign, IL 61821 ............................................... 44 

Whitney, Gene, USGS, Denver .......................................................................................................................................................... 81 

Wilber, RJ., Sea Education Association, Woods Hole, MA 02543 ............................................................................................ 31 

Williamson, Courteney, USGS, Denver ............................................................................................................................................ 82 

Wnuk, Christopher, USGS, Reston................................................................................................................................................... 81 

Wright-Dunbar, Robyn, USGS, Denver ........................................................................................................................................... 82 

Wrucke, C.T., USGS, Menlo Park ..................................................................................................................................................... 42 

z 

Zech, R.S., USGS, Denver ................................................................................................................................................................. 82 

Zihlman, F.N., USGS, Denver ............................................................................................................................................................ 74 

87 
ORGANIZATION OF THE U.S. GEOLOGICAL SURVEY 

Office Name Telephone 

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Director Dallas L. Peck 703/648-7411 

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88 

ext. 3002 

City 

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This book was prepared In USGS Central region, Denver, CO 

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89 

*U.S. GOVERNMENT PRINTING OFFICE: 1992-673-049/46021