The Petroleum SystemStatus of Research and 

Methods, 1992 

U.S. GEOLOGICAL SURVEY BULLETIN 2007 
PfTROLEUM SYSTEM DEFINITION 

A petroleum system encompasses a mature hydrocarbon source-rock and all generated oil and gas accumulations and includes all the geologic elements and processes that are essential if an oil and gas deposit is to exist. Petroleum includes high 

concentrations of any of the following substances: thermal and microbial natural gas found in conventional reservoirs as well as in 

gas hydrate, tight reservoirs, fractured shale, and coal; and condensates, crude oils, heavy oils, and solid bitumen found in reservoirs, generally in siliciclastic and carbonate rocks. System describes the interdependent elements and processes that form the 

functional unit that creates hydrocarbon accumulations. The elements include a petroleum source rock, reservoir rock, seal rock, 

and overburden rock whereas the processes are trap formation and the generation, migration, and accumulation of hydrocarbons. 

These essential elements and processes must be correctly placed in time and space so that organic matter included in a source rock 

can be converted into a petroleum deposit. A petroleum system exists wherever all these essential elements and processes are 

known to occur or are thought to have a reasonable chance or probability to occur. 

Characteristics and Limits.-The areal, stratigraphic, and temporal extent of the petroleum system is specific, as depicted in 

figures 1 to 4 for the Deer-Boar(.) petroleum system. The figures are as follows: a burial history chart depicts the critical 

moment (defined below) and the essential elements; a map and a cross section drawn at the critical moment depicts the spatial 

relation of the essential elements; and a petroleum system events chart shows the temporal relation of the essential elements and 

processes, and shows the duration time and the preservation time for the system. The duration of a system is the time required to 

deposit the essential elements and to complete the processes. The critical moment is usually near the end of the duration time when 

most hydrocarbons are migrating and accumulating in their primary traps. During the preservation time, existing hydrocarbons are 

either preserved, modified, or destroyed. 

The critical moment of a petroleum system is based on the burial history chart of the stratigraphic section where the source 

rock is at maximum burial depth. If properly constructed, the burial history chart shows the time when most of the hydrocarbons 

are generated. Geologically, migration and accumulation of petroleum occurs over a short time span, or in a geologic moment. 

Included with burial history curves, the essential elements of this system are shown; for example, in figure 1 the Deer Shale is the 

source rock. 

The areal extent of the petroleum system at the critical moment is defined by a line that circumscribes the mature source 

rock and all oil and gas deposits, conventional and unconventional, originating from that source at the time of secondary migration. A plan map drawn for the end of Paleozoic time, showing a line that circumscribes the pod of mature source rock and all 

related hydrocarbon accumulations, best depicts the areal extent of the system (fig. 2). 

Stratigraphically, the system includes the following rock units or essential elements: a petroleum source rock, reservoir rock, 

seal rock, and overburden rock at the critical moment. The function of the first three rock units are obvious; however, the overburden rock is more subtle, because, in addition to providing the overburden necessary to mature the source rock, it also can have 

considerable impact on the geometry of the underlying migration path and trap. The cross section, drawn for the end of the 

Paleozoic to show the geometry of the essential elements at the time of hydrocarbon accumulation, best depicts the stratigraphic 

extent of the system (fig. 3). 

The petroleum system events chart (fig. 4) shows two temporal episodes, the duration time and the preservation time. The 

duration is the time it took to form a petroleum system, and the preservation is the length of time that the hydrocarbons within that 

system could have been preserved, modified, or destroyed. A petroleum system needs sufficient amount of geologic time to 

assemble all the essential elements and to carry out the processes needed to form a petroleum deposit. If the source rock is the first 

element or oldest unit deposited and the overburden rock necessary to mature the source rock is the last or youngest element, then 

the age difference between the oldest and youngest element is the duration time of the petroleum system. 

Preservation time starts after generation, migration, and accumulation processes are complete. Processes that may occur 

during the preservation time are remigration, physical or biological degradation, or complete destruction of the hydrocarbons. 

During the preservation time, remigrated (tertiary migration) petroleum can accumulate in reservoirs deposited after the duration 

time. If insignificant tectonic activity occurs during the preservation time, accumulations remain in their original position. Remigration happens during the preservation time only if folding, faulting, uplift, or erosion occur. If all accumulations and essential 

elements are destroyed during the preservation time, then the evidence that a petroleum system existed is absent. An incomplete or 

just completed petroleum system is still in its duration time and thus is without a preservation time. 

Level of Certainty.-A petroleum system can be identified at three levels of certainty: known, hypothetical, and speculative. 

The level of certainty indicates the confidence for which a particular mature pod of source rock has generated the hydrocarbons in 

an accumulation. In a known petroleum system, in the case of oil, a good geochemical match exists between the source rock and 

the oil accumulations, or, in the case of natural gas, the gas is produced from a gas source rock. In a hypothetical petroleum 

system, geochemical information identifies a source rock, but no geochemical match exists between the source rock and the 

petroleum deposits. In a speculative petroleum system, the existence of source rocks and petroleum accumulations is postulated 

entirely on the basis of geologic or geophysical evidence. At the end of the system's name, the level of certainty is indicated by(!) 

for known, (.) for hypothetical, and (?) for speculative. 

Petroleum System Name.-The name of the petroleum system includes the source rock, followed by the name of the major 

reservoir rock, and then the symbol expressing the level of certainty. For example, the Deer-Boar(.) is a hypothetical system 

consisting of the Deer Shale as the source rock and the Boar Sandstone as the major reservoir rock. 
The Petroleum SystemStatus of Research and 

Methods, 1992 

LESLIE B. MAGOON, Editor 
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, WASHINGTON : 1992 

For sale by the 

Books and Open-File Reports Section 

U.S. Geological Survey 

Federal Center, Box 25425 

Denver, CO 80225 

Library of Congress Cataloging-in-Publication Data 

The petroleum system : status of research and methods, 1992 I Leslie B. Magoon, 

editor. 

p. em.- (U.S. Geological Survey bulletin; 2007) 

Includes bibliographical references. 

1. Petroleum-Geology-United States. 2. Gas, Natural-GeologyUnited States. 3. Petroleum-United States-Reserves. I. Magoon, Leslie. II. 

Series. 

QE75.B9 no. 2007 

[TN870.5] 

557.3 s-dc20 

[553.2'8'0973] 91-36739 

CIP 
CONTENTS 

Abstract 1 

Leslie B. Magoon 

Identified petroleum systems within the United States-1992 2 

Leslie B. Magoon 

A concise historical and current perspective on the kinetics of natural oil generation 12 

Michael D. Lewan 

Role of microbial processes in petroleum systems 16 

Jerry L. Clayton 

Coalbed methane 20 

BenE. Law 

Turbidity current processes 22 

William R. Nonnark and David J. W. Piper 

Porosity 32 

James W. Schmoker 

Facies, permeability, and heterogeneity in sandstone reservoirs 35 

Christopher J. Schenk 

Approaches to characterizing fluid-flow heterogeneity in carbonate reservoirs 40 

Christopher J. Schenk 

Mineral transformations in tar sand and heavy oil reservoirs induced by thermal recovery 

methods 44 

ChristropherJ.Schenk 

Biomarkers as thermal maturity indicators 49 

Paul G. Lillis 

Fission-track analysis in sedimentary basins-1992 53 

Nancy D. Naeser 

Vitrinite and solid bitumen reflectance: Some correlations and applications 58 

Mark J. Pawlewicz and J. David King 

Clay minerals as geothermometers-Indicators of thermal maturity for hydrocarbon 

exploration 61 

Richard M. Pollastro 

Influence of regional heat flow variation on thermal maturity of the Lower Cretaceous 

Muddy ("J'') Sandstone, Denver basin, Colorado 66 

Debra K. Higley, Donald L. Gautier, and Mark J. Pawlewicz 

Thermal maturity of the Mesaverde Group, Uinta basin, Utah 70 

Vito F. Nuccio and Thomas D. Fouch 

NERSL-National Energy Research Seismic Library 79 

David J. Taylor 

Branch of Petroleum Geology-1989 through 1990 bibliography 81 

Helen Y. Colburn, compiler 

Contents Ill 
IV Contents 

FIGURES 

1. Burial history chart Inside cover 

2. Map showing geographic extent of petroleum system Inside cover 

3. Geologic cross section showing stratigraphic extent of system Inside cover 

4. Petroleum system events chart Inside cover 

5. Index map for COSUNA charts 7 

6. Diagram showing factors controlling initiation, transport, and deposition in turbidite 

systems 23 

7. Graph showing sandstone porosity versus vitrinite reflectance 33 

8. Graph showing carbonate porosity versus Lopatin's time-temperature index 33 

9. Clay geothermometry map of the Niobrara Formation, Denver basin 63 

10. Map of isoreflectance of Muddy ("J'') Sandstone in Denver basin 67 

11. Graph showing isoreflectance sample depths and correlation curves 68 

12. Index map of Uinta and Piceance basins in Utah and Colorado 70 

13. Cross section A-A' from southwest to north-central Uinta basin 72 

14. Cross section B-B' from Altamont-Bluebell to Island gas field, Uinta basin 73 

15. Thermal maturity map at base of Mesaverde Group, Uinta basin 74 

16. Thermal maturity map at top of Mesaverde Group, Uinta basin 75 

17. Contour map of0.75-percent Rm relative to sea level, Uinta basin 76 

TABLES 

1. Identified petroleum systems within the United States as·revised and reorganized by 

age of source rock 3 

2. Name and level of certainty revisions of U.S. petroleum systems 8 

3. Distribution of petroleum systems by age and hydrocarbon type 9 

4. Classification of bacteria according to energy source and source of nutrition 

(carbon) 17 

5. Selected maturity ratios based on apparent biomarker reaction 50 
The Petroleum SystemStatus of Research and Methods, 1992 

Leslie B. Magoon, Editor 

ABSTRACT 

This publication, comprising 16 individually authored summaries by U.S. Geological Survey scientists, prese ts a reorganized table of the petroleum systems within the 

United States and summari es the status of research for a number of petroleum-related 

topics and investigative me hods. 

The table of petroleu systems within the United States has been reorganized by 

Magoon to show that a so rce rock interval can extend beyond a single system to be 

included in other systems, and to show, as other authors have, that petroleum source 

rocks occur unevenly thro ghout geological time. Lewan discusses the role of hydrous 

pyrolysis as a method to imulate the generation and expulsion of petroleum from a 

source rock. Clayton focu s on bacteria that mediate coupled oxidation-reduction reactions and use organic and inorganic substrates as a means of obtaining both the carbon 

and the energy necessary for metabolic processes. Law provides an overview of the 

occurrence of methane in oal and as an energy source. Normark and Piper examine 

the turbidite deposit, a pot ntial reservoir rock, using a series of analytical criteria: initiation and flow evolution; ransport in channels; flow processes implied from turbidite 

bedforms; and facies distri ution in turbidite systems. Schmoker discusses the growing 

body of literature dealing ith the relation between porosity and time-temperature exposure, or thermal maturity. chenk covers several petroleum reservoir topics: (1) facies, 

permeability, and heterog neity in siliciclastic sandstone reservoirs, (2) various approaches to characterizing luid-flow heterogeneity in carbonate reservoirs, and (3) mineral transformations in tar and and heavy oil reservoirs induced by thermal recovery 

methods. Lillis discusses t e use of biological markers as thermal maturity indicators. 

Naeser high I ights the considerable contribution that apatite fission-track analyses have 

made toward clarifying the thermal history of more than 40 sedimentary basins worldwide. Pawlewicz and King review vitrinite and solid bitumen reflectance and discuss 

certain thermal maturity c rrelations and applications. Pollastro reports on the current 

research status and activiti s related to day-mineral geothermometry and, as an example, discusses the use of cl y geothermometry as a predictor of oil or microbial gas in 

the Niobrara Formation. 8 contouring the thermal maturity of the Muddy Sandstone 

using vitrinite reflectance, igley and others show that thermal anomalies relate to differences in burial depth, he t flow, and basin hydrodynamics. Nuccio and Fouch discuss 

the thermal maturity of the Mesaverde Group in the Uinta basin in northeastern Utah. 

Taylor discusses the origin nd function of the National Energy Research Seismic Library 

(NERSL). Lastly, Colburn pr sents a list of publications written by personnel of the USGS 

Branch of Petroleum Geolo y and published during 1989 and 1990. 

Manuscript approved for p blication, September 24, 1991. 

The Petroleum System-Status of Research and Methods, 1992 1 
Identified Petroleum Systems within the United States-1992 

By Leslie B. Magoon1 

INTRODUCTION 

Considerable progress has been made toward explaining the usefulness of the petroleum system as an investigative approach for research and exploration. At the 

Annual Convention of the American Association of Petroleum Geologists, April 10, 1991, W.G. Dow and L.B. 

Magoon co-convened a well attended AAPG oral session 

on "The Petroleum System-From Source to Trap." Ten 

papers were presented. An introductory paper defined 

the petroleum system (Magoon and Dow, 1991), and an 

applications paper (Smith, 1991) showed how Shell Oil 

Company used the petroleum system for the last 25 

years to evaluate offshore tracts and onshore exploration 

ventures. Four papers covered various aspects of the petroleum system (Curiale, 1991; Demaison and Huizinga, 

1991; England, 1991; and Lewan, 1991) and four case 

studies were presented (Bacoccoli and others, 1991; 

Bird, 1991; Talukdar, 1991; and Ulmishek, 1991). Other 

papers presented at this meeting indicate that the petroleum system concept is gaining acceptance (Resnick, 

1991; Tinker, 1991). In the May 1991 issue of the 

AAPG Explorer magazine, a popularized article about 

the petroleum system was published (Shirley, 1991). 

The petroleum system definition, which appears on 

the inside of the front and back cover of this bulletin, 

has been revised and expanded from the previous bulletin (Magoon, 1989a) to include four figures. The text revision and figures expand on the temporal extent of the 

system by emphasizing the burial history chart (fig. 1) 

as evidence for the timing of generation, migration, and 

accumulation of hydrocarbons, and the petroleum system 

events chart (fig. 4) more clearly shows the relationship 

between the essential elements and processes. Also included are the map (fig. 2) and cross section (fig. 3) to 

show how the geographic and stratigraphic extent of the 

system are best depicted. Together, these four figures 

graphically portray what the revised text describes. 

1

U.S. Geological Sutvey, Menlo Park, Calif. 

2 The Petroleum System-Status of Research and Methods, 1992 

Because the petroleum system can be classified more 

than one way, the classification scheme was deleted. 

The list of petroleum systems within the United 

States (table 1) has been reorganized and revised since 

the last tabulation in 1989, in which 130 systems were 

identified (Magoon, 1989b). Table 1 was reorganized by 

age of source rock to more clearly emphasize two important points. First, a petroleum source rock can have 

an areal distribution beyond any one system and, in fact, 

can be part of different systems in other areas. Second, 

as other authors have noted, petroleum source rock intervals are unevenly distributed in the geologic record 

(Ulmishek and Klemme, 1990). The oldest age of the 

source rock is used to classify each system in the table. 

For example, a source rock whose age extends from 

Late Devonian through Early Mississippian is classified 

as Devonian. 

The total number of petroleum systems remains 

the same (Magoon, 1989b; table 2), but three names and 

two certainty levels were revised (table 2). The Elbert 

Formation is a reservoir rock rather than a source rock 

(Kent and others, 1988). The New Albany (.) is an oil 

system rather than gas, and most of the oil is in Chesterian age reservoirs (Barrows and Cluff, 1984). The level 

of certainty was changed to speculative for both Pennsylvanian systems [Pennsylvanian coals(?); Pennsylvanian-Late Paleozoic(?)] because of a lack of published 

information. Quotation marks were placed around "A-1" 

for the Salina "A-1"-Niagaran(!) system to more clearly 

separate it from Niagaran. As published information 

about U.S. petroleum systems becomes available, this 

list will be revised to incorporate the new information. 

SOURCE ROCK INTERVALS BY AREA 

In table 1, the region(s) and province(s) for the entire United States are listed to show the general areal 

distribution for each petroleum system. In many instances, each system covers more than one province, which 

can include one or more basin (structural or sedimentary), uplift (arch), or mountain range (fold and thrust 

belt). With few exceptions, each system is associated 
Table 1. Identified petroleum systems within the United States as revised and reorganized by age of source rock 

(modified from Magoon, 1989b, table 2) 

[Level of certainty: (!),known; (.),hypothetical; ('!),speculative; for certainty definitions see Magoon, 1988b; lith, lithology; pet, petroleum; res, reservoir; S, 

sandstone; C, carbonate. Region codes (fig. 5) and references m: listed below. CSD/C, Geological province code number (Meyer, 1974)/COSUNA chart 

stratigraphic column number] 

Atlantic Coast region (Jordan and Smith, 1983); 

Central California region (Bishop and Davis, 1984a); 

AC, 

CCA, 

CSR, 

GB, 

GC, 

MBA, 

MC, 

NAL, 

NAP, 

NCA, 

Central and Southern Rockies region (Kent and others, 1988); 

Great Basin region (Hintze, 1985); 

Gulf Coast region (Braunstein and others, 1988); 

Midwestern basin and arches region (Shaver, 1985); 

Mid-Continent region (Adler, 1987); 

Northern Alaska region (Schaff and Gilbert, 1987a); 

Northern Appalachian region (Patchen and others, 1985a); 

Northern California region (Bishop and Davis, 1984b); 

Petroleum systems Source 

[source-reservoir(certainty)) type• 

Cenozoic(.)-------------------------------------- III 

Neogene-Salt Lake(?)-------------------------- I 

Eel River-Rio Dell(?)--------------------------- II 

Beluga-Sterling(.) ------------------------------- III 

Miocene(.)--------------------------------------- III 

Miocene(?) -------------------------------------- II 

Monterey(?)------------------------------------- II 

Monterey-Puente(!)----------------------------- II 

Monterey-Repetto/Pico(.)----------------------- II 

Monterey-Stevens/Kern River(.)--------------- II 

Monterey-Tinaquaic(.) ------------------------- II 

Soda Lake-Painted Rock(.)--------------------- II 

Domengine-Cierbo/Briones(?) ----------------- II 

Green River-Wasatch(!)----------------------- I 

Kreyenhagen-Gatchell(?) ---------------------- II 

Ozette-Hoh(l)----------------------------------- III 

Pool Creek(.) ------------------------------------ III 

Sheep Pass-Garrett Ranch(!)------------------- I 

Stepovak-Bear Lake(.)------------------------- III 

Stillwater-Kulthieth(.)--------------------------- III 

Aspen/Bear River Nugget/Madison(?)--------- II 

Austin Chalk(!)---------------------------------- I 

Austin Chalk/Eagleford-Woodbine(?) --------- I 

Cretaceous(.) ------------------------------------ III 

See footnote at end of table. 

Res 

lith 

s 

s 

s 

s 

s 

s 

s 

s 

s 

s 

s 

s 

s 

s 

s 

s 

s 

s 

s 

s 

s 

c 

s 

s 

Pet 

type 

NE, 

NMC, 

NRW, 

NW, 

PBR, 

SAL, 

SAP, 

SCA, 

SSMC, 

TOT, 

Region 

code 

Cenozoic 

0/G GC 

Oil GB 

Pliocene 

Gas NCA 

Gas SAL 

Miocene 

Gas GC 

Oil CCA 

Oil CCA 

Oil SCA 

Oil SCA 

Oil CCA 

Oil CCA 

SCA 

Oil SCA 

Eocene 

0/G CCA 

Oil CSR 

Oil CCA 

Oil NW 

Oil SAL 

Oil GB 

Gas SAL 

Oil SAL 

Cretaceous 

Oil CSR 

GB 

0/G GC 

Oil GC 

G/0 CSR 

New England region (Skehan, 1985); 

Northern Mid-Continent region (Bergstrom and Morey, 1985); 

Northern Rockies/Williston basin region (Ballard and others, 1983); 

Northwest region (Hull and others, 1988); 

Piedmont/Blue Ridge region (Higgins, 1987); 

Southern Alaska region (Schaff and Gilbert, 1987b); 

Southern Appalachian region (Patchen and others, 1985b ); 

Southern California region (Bishop and Davis, 1984c); 

Southwest/Sruthwest :Mid-Continent region (Hills and Kottlowski, 1983); 

Texas-Oklahoma Tectonic region (Mankin, 1987); 

Province 

Name CSD/C 

Gu1f Coast basin 220/2-4,10-11 

Gu1fCoast offshore 

Great Basin province 625/15,16 

Eel River basin 720/1-2 

Pacific offshore 

Cook Inlet basin 820/13 

Mid-Gulf Coast basin 210/14,16,17 

Santa Cruz basin 735/6 

Pacific offshore 

Northern Coast Range 72513 

Pacific offshore 

Los Angeles basin 760/8-11 

Santa Maria basin 750/3 

Ventura basin 155!4-5 

Pacific offshore 

San Joa~ basin 745/16-21,27-29 

Coastal sin 740 

Santa Maria basin 750/2 

Pacific offshore 

Coastal basin 740 

Santa Maria basin 750/1 

Northern Coast Range 725/1 

Uinta basin 515 

San Joaquin basin 745/16-21,27-29 

Western Columbia basin 710/14 

Gulf of Alaska basin 810/24 

Great Basin 625/9 

Alaska Peninsula 825/12 

Bristol Bay basin 845/10,11 

Gu1f of Alaska basin 810/24,26,27 

Green River basin 535/11 

Uinta uplift 570 

Gulf Coast basin 220/1,4,10 

Mid-Gulf Coast basin 210/14,17 

Gulf Coast basin 220/10 

East Texas basin 230 

East Texas basin 260/5,6 

Green River basin 535/12-14 

Identified Petroleum Systems within the United States-1992 3 
Table 1. Identified petroleum systems within the United States as revised and reorganized by age of source rock 

(modified from Magoon, 1989b, table 2)-Continued 

Petroleum systems Source Res Pet Region Province 

[source-reservoir(certainty)] type' lith type code 

Name CSD/C 

Cretaceous 

Cretaceous(!}------------------------------------ III s Gas MC Sioux uplift 320/1-3 

NMC Salina basin 380/8 

NRW Chadron arch 390 

Williston basin 395 

Sweetgrass arch 500 

Central Montana uplift 510 

Powder River basin 515 

Denver basin 540 

Cretaceous(?) ----------------------------------- III s 0/G CSR Big Horn basin 520/3,4 

Cretaceous(?) ----------------------------------- III s Oil CSR Wind River basin 530/8 

Cretaceous(?) ----------------------------------- III s 0/G CSR Denver basin 540!21 

Cretaceous(?)----------------------------------- III s Oil CSR Powder River basin 515/6 

Cretaceous(?) ----------------------------------- III s Gas CSR Green River basin 535/9,15 

Cretaceous(?) ----------------------------------- III s Gas CSR North Park basin 545 

Cretaceous-Tertiary(?)------------------------- III s Gas CSR Big Horn basin 520/3,4 

Cretacous-Tertiary( I)--------------------------- III s Gas CSR Wind River basin 530/8 

Dollar Bay(.)------------------------------------ II c Oil GC South Florida 140131 

GuHCoast offshore 

Forbes (.) ----------------------------------------- III s Gas NCA Sacramento basin 730!27-29 

Greenhorn-Dakota(.)--------------------------- II s Oil CSR San Juan basin 580!29 

Hornbrook(?}------------------------------------ III s Gas NCA Klamath Mountains 715/3,5 

Hue-Sagavanirktok(!)-------------------------- II s Oil NAL Arctic Coastal Plain 890/5-6 

Lewis-Picture Qiffs(.) -------------------------- III s Gas CSR San Juan basin 580!29 

Lower Cretaceous-Paluxy(?)------------------- II s 0/G GC Mid-GuH Coast basin 210 

GuH Coast basin 220 

Arkla basin 230 

East Texas basin 260 

GuHCoast offshore 

Mesaverde(.) ------------------------------------ III s Gas CSR Uinta basin 575/16,17 

Mesaverde(.) ------------------------------------ III s Gas CSR Piceance basin 595/18 

Mancos-Tocito(.) ------------------------------- II s Oil CSR San Juan basin 580!29 

Mancos-Mesaverde(.)-------------------------- II s Gas CSR San Juan basin 580!29 

Moreno(?) II s Oil CCA Northern Coast Range 725 

San Joaquin basin 745!29,16,17 

Mowry-Muddy(!)------------------------------- II s Oil CSR Denver basin 540!20 

Niobrara(!)-------------------------------------- II c Gas CSR Las Animas arch 450131 

SSMC Denver basin 540!21 

Niobrara/Carlisle-Frontier(!)------------------- II c Oil CSR Denver basin 540!20,21 

Sligo(?) ------------------------------------------ III c Gas GC Mid-GuH Coast basin 210/14 

GuH Coast basin 220 

Arkla basin 230fl 

East Texas basin 260/5 

Starkey-Winters(.)------------------------------ III s Gas NCA Sacramento basin 730!20-26 

Sunniland(!) ------------------------------------- II c Oil GC South Florida 140131 

Gulf Coast offshore 

Torok-Nanushuk(.) ----------------------------- III s Oil NAL Arctic Coastal Plain 890/1-3 

Tuscaloosa(.)------------------------------------ II s Gas GC GuH Coast basin 220/3,10,11 

Jurassic 

Cotton Valley(?)--------------------------------- III s Gas GC Mid-Gulf Coast basin 210 

Gulf Coast basin 220/10 

Arkla basin 230 

East Texas basin 260 

Curtis-Entrada/Morrison(?)--------------------- II s Oil CSR Green River basin 535/13 

Piceance basin 595!18 

Jurassic-Cretaceous(?)------------------------- III s Gas Atlantic offshore 

Jurassic/Cretaceous(?)-------------------------- II s Oil NRW Sweetgrass arch 500/10,11 

Montana folded belt 505/6-8 

Central Montana uplift 510/12 

Smackover(!}------------------------------------ II c Oil GC Mid-GuH Coast basin 210 

Gulf Coast basin 220 

Arkla basin 230 

East Texas basin 260 

Gulf Coast offshore 

Todilto-Entrada(.)------------------------------- II s Oil CSR San Juan basin 580!29 

Tuxedni-Hernlock( .) ---------------------------- III s Oil SAL Cook Inlet basin 820/13 

See footnote at end of table. 

4 The Petroleum Syste~Status of Research and Methods, 1992 
Table 1. Identified petroleum systems within the United States as revised and reorganized by age of source rock 

(modified from Magoon, 1989b, table 2)-Continued 

Petroleum systems Source Res Pet Region Province 

(source-reservoir{certainty)] type I lith type code 

Name CSD/C 

Triassic 

Ellesmerian(l) ----------------------------------- II s Oil NAL Arctic Coastal Plain 890/1-8 

F avret(?)----------------------------------------- II c Oil GB Great Basin 625/2 

Newark(?)--------------------------------------- II s Oil NE New England 1oon-9 

PBR Piedmont Blue Ridge 150!11 

NAP N Appalachian basin N160/25,26 

Permian 

Permian(.) --------------------------------------- II c Oil SSMC Permian basin 430/18-20,23 

Permian(.) --------------------------------------- II c Oil SSMC Permian basin 430/20-21 

Phosphoria-Weber(!)--------------------------- II s Oil CSR Montana folded belt 505 

GB Central Montana uplift 510 

NRW Powder River basin 515 

Big Hom basin 520 

Yellowstone 525 

Wind River basin 530 

Green River basin 535 

Uinta uplift 570 

Uinta basin 575 

Snake River basin 615/22 

Wasatch uplift 630/23,27,28 

Pennsylvanian 

Desmoinesian-0 sandstone(!)------------------ II c Oil CSR Denver basin 540/20 

Minnelusa(!)------------------------------------- II s Oil CSR Powder River basin 515 

Denver basin 540/10,20 

Pennsylvanian(.)--------------------------------- II c Oil SSMC Permian basin 430/18-20 

Pennsylvanian(.)--------------------------------- II c Oil SSMC Permian basin 430/20-22 

Pennsylvanian cannel coals-sandstone(.) ------ I s Oil NAP N Appalachian basin N160/1,2,7-9 

SAP S Appalachian basin S160/11-24 

Pennsylvanian coals(?)-------------------------- III s Gas NAP N Appalachian basin N160 

SAP S Appalachian basin S160 

Pennsylvania-Late Paleozoic(?)---------------- III s Gas MC Forest City basin 335 

SSMC Arkoma basin 345/4-5 

TOT S Oklahoma folded belt 350/6 

Chautauqua platform 355/1,2 

Anadarko basin 360/26-29 

Cherokee basin 365 

Nemaha anticline 370!26 

Sedgwick basin 375/25 

Amarillo arch 440 

Paradox-Hermosa(.)---------------------------- II c Oil CSR Paradox basin 585/23 

Ty ler(l) ------------------------------------------ II s Oil NRW Williston basin 395/23 

Mississippian 

Chainman-Garrett Ranch(!)-------------------- II s Oil GB Great Basin 625/11 

Chainman-Simonson(?) ------------------------- II c Oil GB Great Basin 625/8,9,11,12, 

17,18,20,21 

Chainman-White Rim(?)------------------------ II s Oil CSR Paradox basin 585 

GB Wasatch uplift 630/29 

Chester(?) --------------------------------------- III s Gas TOT Warrior basin 200/17-19 

Heath-Tyler( I)---------------------------------- II s Oil NRW Williston basin 395/14 

Central Montana uplift 510/12 

Michigan-Stray(.)------------------------------- II s 0/G MBA Michigan basin 305/4-6 

Mississippian coals-sandstones(.)--------------- III s Gas SAP S Appalachian basin S160!25-26 

Sunbury-Berea(!)------------------------------- II s 0/G NAP N Appalachian basin N160/1,2,7,8,16,20 

SAP S Appalachian basin S160/18,21 Sunbury-Murrysville(.)------------------------- III s Gas NAP N Appalachian basin N160/16-18 

Devonian 

Aneth-Elbert/McCracken(?)------------------- II s Oil CSR Paradox basin 585/23 

Antrim(.)----------------------------------------- III s Gas MBA Michigan basin 305/3-5,15 

See footnote at end of table. 

Identified Petroleum Systems within the United States-1992 5 
Table 1. Identified petroleum systems within the United States as revised and reorganized by age of source rock 

(modified from Magoon, 1989b, table 2)-Continued 

Petroleum systems Source Res Pet Region Province 

[source-reservoir(certainty)] typet lith type code 

Name CSD/C 

Devonian 

Bakken-Madison(l) ----------------------------- II c Oil NRW Williston basin 395/13-20,23 

Chattanooga-Fort Payne(.)---------------------- III c 0/G SAP S Appalachian basin S160/11,12 

Devonian-Berea(?)----------------------------- II s Oil MBA Michigan basin 305/3-5 

Devonian Black Shales-Venango(!)----------- II s G/0 NAP N Appalachian basin N160/1-29 

Devonian-Detroit Riverffraverse(?)----------- II c Oil MBA Michigan basin 305/4-6 

Exshaw-Madison(.) II c Oil NRW Sweetgrass arch 500fl,l0,11 

Montana folded belt 505 

Marcellus-Bass Islands(.)----------------------- III c Gas NAP N Appalachian basin N160/21,27 

Marcellus-Onondaga(.)------------------------- III c Gas NAP N Appalachian basin N160/21 ,22,28 

Marcellus-Oriskany(.)-------------------------- III s Gas NAP N Appalachian basin N160 

Monroe(?)--------------------------------------- III c Gas GC Arkla basin 230/9 

New Albany-Chester(.)------------------------- II s Oil MBA Illinois basin 315fl-12,19-21 

Ohio-Big Injun(.)-------------------------------- II s G/0 NAP N Appalachian basin N160/1-3,7-9,16,17 

Ohio/Chattanooga-Corniferous(?)-------------- III c 0/G SAP S Appalachian basin S160/18 

MBA Cincinnati arch 300/24,25 

Ohio Shale(!)------------------------------------ II s G/0 NAP N Appalachian basin N160 

SAP S Appalachian basin S160 

Ohio/Sunbury-Greenbriar/Newman(?) -------- III c Gas NAP N Appalachian basin N160/1,2 

SAP S Appalachian basin S160/18,21 

Ohio-Weir(?) ----------------------------------- II s Gas NAP N Appalachian basin N160/l-3,7-14 

SAP S Appalachian basin S160/18-24 

Woodford/Chattanooga-Paleozoic(.)----------- II s Oil MC Forest City basin 335 

SSMC Arkoma basin 345!3-5 

TOT S Oklahoma folded belt 350/6 

Chautauqua platform 355 

Anadarko basin 360 

Cherokee basin 365 

Nemaha anticline 370/26 

Sedgwick basin 375 

Central Kansas uplift 385 

Chadron arch 390!15 

Amarillo arch 440 

Las Animas arch 450 

Woodford-Silurian/Devonian(.)---------------- II s Oil SSMC Permian basin 430/18-21 

Woodford-Sycamore(!)------------------------ II c Oil TOT S Oklahoma folded belt 350/6 

Silurian 

Cabot Head-Medina(.)-------------------------- I s Oil NAP N Appalachian basin N160/21 

Rose Hill-Keefer(?) ---------------------------- I s Gas NAP N Appalachian basin N160 

SAP S Appalachian basin S160/18 

Salina "A-1 "-Niagaran(!)----------------------- II c Oil MBA Michigan basin 305/3-6,15 

Salina-Newburg(?)----------------------------- I c Oil NAP N Appalachian basin N160fl ,8,15,16,20 

Ordovician 

Athens-Trenton/Knox(?)----------------------- I c Oil NAP N Appalachian basin N160/1-5 

SAP S Appalachian basin S160/11-15,17-26 

Glenwood-Rose Run(?)------------------------- I s Oil NAP N Appalachian basin N160/1,2,7,9,16,17,20,21 

SAP S Appalachian basin S160/16-18 

Glenwood-Trempealeau(?) -------------------- I c Gas NAP N Appalachian basin N160/15 

Ordovician-Prairie du Chien II c Oil MBA Cincinnati arch 300/14-17 

/Black Riverffrenton(?) Michigan basin 305/2-6,15 

Point Pleasant-Clinton(!)------------------------ II s Oil NAP N Appalachian basin N160/15-16 

Simpson-Ellenberger/Simpson(.) --------------- II c G/0 SSMC Permian basin 430/19-21 

Simpson-Viola( I)-------------------------------- I c Oil MC Forest City basin 335 

SSMC S Oklahoma folded belt 350/6 

TOT Chautauqua platform 355/1,2 

Anadarko basin 360/27 

Cherokee basin 365 

Nemaha anticline 370/26 

Sedgwick basin 375/25 

Simpson-Viola/Hunton(.) ----------------------- I c Oil MC Forest City basin 335/21 

Nemaha anticline 370/10,18,20 

Trenton( I) --------------------------------------- c Oil MBA Cincinnati arch 300/13,14 

Illinois basin 315fl-12,19-21 

U tica-Beekmantown(l) ------------------------- II s Gas NE New England 100/6 

Adirondack uplift 110/1 

See footnote at end of table. 

6 The Petroleum System-Status of Research and Methods, 1992 
Table 1. Identified petroleum systems within the United States as revised and reorganized by age of source rock 

(modified from Magoon, 1989b, table 2)-Continued 

Petroleum systems Source Res Pet Region Province 

[source-reservoir(certainty)] type1 lith type code 

Name CSD/C 

Ordovician 

Utica-Trenton(!)-------------------------------- I c Gas MBA New England 100/1,3 

NAP Adirondack uplift 11011 

NE N Appalachian basin N160 

Cincinnati arch 300/13,14,16-18 

Viola(!)------------------------------------------ II c Oil TOT S Oklahoma folded belt 350/6 

Winnipeg-Red River(!)------------------------- II c Oil NRW Williston basin 395/13-20,23 

Cambrian 

Conasauga-Knox(?) ---------------------------- II c Gas PBR Piedmont Blue Ridge 150/3-6 

SAP S Appalachian basin S160!25,26 

Conasauga-Knox(?) ---------------------------- II c Oil SAP S Appalachian basin S160/1-8 

TOT Warrior basin 200117.18 

Conasauga-Rome(.)----------------------------- II s Oil NAP N Appalachian basin N160/1-4,7-14,17,18 

SAP S Appalachian basin S160/11-24 

EauClair-Knox(?)------------------------------- II c Gas MBA Illinois basin 315/8-12,19-21 

Precambrian 

Nonesuch-Keweenawan(?)-------------------- II s Gas MC Wisconsin arch 310/20 

NMC Sioux uplift 320/12,13 

Iowa shelf 32513,4,12,14 

Nemaha anticline 370/10,20 

Salina basin 380/17 

Unknown 

Unknown-Eocene(?) --------------------------- II s Oil GC Mid-Gulf Coast basin 210 

Gulf Coast basin 220/10 

Arkla basin 230/8 

East Texas basin 260/5 

Unknown-Eutaw/Selma(?)--------------------- II s Oil GC Mid-Gulf Coast basin 210/13,14,16,28 

Gulf Coast basin 220/10 

Arkla basin 230 

East Texas basin 260/6 

Unknown-San Miguel/Olmos(?)---------------- II s Oil GC Gulf Coast basin 220/1 

SSMC Ouachita tectonic belt 400/16 

1

Refers to organic matter type, either I, II, or III, and is distinguished on the basis of the hydrogen and oxygen indices of the kerogen 

when plotted on the van Krevelen diagram. See Tissot and Welte (1984) for further explanation. 

COSUNA CHART INDEX MAP 

Figure 5. Index map of regions for the Correlation of stratigraphic units of North America (COSUNA) charts. See 

table 1 for region names and references. 

Identified Petroleum Systems within the United States-1992 7 
Table 2. Name and level of certainty revisions of U.S. petroleum systems 

[See text for sources of information leading to these revisions] 

Magoon, 1989b This publication 

Aneth/Elbert-McCracken(?)------------------------Aneth-Elbert/McCracken(?) 

New Albany(.)----------------------------------------- New Albany-Chester(.) 

Pennsy lv ani an coals(!)------------------------------ Pennsy lv ani an coals(?) 

Pennsylvania-Late Paleozoic(!)------------------- Pennsylvania-Late Paleozoic(?) 

Salina A-1-Niagaran(!)------------------------------Salina "A-1 "-Niagaran(!) 

with at least one basin because the basin contains the 

overburden rock that provided the burial depth (heat) to 

mature the source rock. Only systems that contain microbial gas have little need for overburden rocks. 

When the sedimentary basin of a source rock is on 

a continental scale, such as the Late Devonian of the 

United States, that organic-rich interval can be the 

source rock for more than one petroleum system. However, the stratigraphic nomenclature for this Upper Devonian source rock is different depending on the location 

(in parenthesis): the Ohio Shale and Devonian black 

shale (Appalachian area), the Antrim Shale (Michigan 

basin), the New Albany Shale (Illinois basin), the Woodford Shale (mid-Continent provinces), the Aneth Formation (Paradox basin; Kent and others, 1988), the Pilot 

Shale (Great Basin), the Bakken Formation (Williston 

basin), and the Exshaw Formation (Sweetgrass arch). 

Wherever this organic-rich rock is, or is thought to be, 

buried enough by overburden rock to generate oil or gas, 

a petroleum system exists. The petroleum systems that 

include these Upper Devonian source rocks are listed in 

table 1 under Devonian. 

What matures this Upper Devonian organic-rich interval is overburden rock deposited in smaller, post-Devonian basins (successor basins) located on or along the 

edge of the North American craton. Sedimentary basins 

on the craton are sags or rifts, whereas basins at the edge 

of the craton are foreland basins. Unless the sediments 

are created in situ (carbonates, evaporites, and coals), the 

provenance for the sediments dumped into all three basins is the craton, or the provenance for the foreland basin, both craton and the fold and thrust belt. The 

reservoir and seal rocks are either in the Upper Devonian 

strata or are part of the overburden rock. The trap- and 

petroleum-forming processes occur during deposition of 

the overburden rock. 

On a continental scale, the duration of these petroleum systems with Upper Devonian source rocks varies 

with the location of the system. Along the eastern and 

southern edge of the North American craton, these late 

Paleozoic foreland basins include the Appalachian, Warrior, and Anadarko and received only a minor amount of 

8 The Petroleum System-Status of Research and Methods, 1992 

post-Paleozoic sediments. Since the present-day petroleum accumulations had to have been generated and migrated by the end of Permian time or earlier, when 

maximum burial was achieved, the duration of these petroleum systems with Upper Devonian source rocks 

ranged from Late Devonian through Permian time. The 

preservation time extended through the Mesozoic and 

Cenozoic. In contrast, the western edge of the craton includes foreland basin sedimentary rocks as young as 

Cretaceous or early Tertiary, and one of the cratonic interior basin sags may be as young as Tertiary. The duration of these systems can range from Late Devonian 

through Cretaceous or Tertiary, respectively. 

Another organic-rich interval that is involved in 

many petroleum systems is the Miocene of California 

(table 1). Here, numerous strike-slip basins formed in the 

Miocene and continue to develop to the present day. At 

first, the basins were conducive to the formation and 

preservation of organic matter along with abundant biogenous silica and relatively little siliciclastic material. 

Deposition of coarser siliciclastic material became progressively more rapid during Pliocene to Pleistocene 

time; this sediment provided the necessary overburden to 

generate hydrocarbons in petroleum systems within the 

Los Angeles basin, Ventura basin (Santa Barbara offshore), Santa Maria basin, San Joaquin basin, and several other coastal basins. Again, what started out as 

organic-rich deposits over a large area eventually developed into smaller sedimentary basins that acquired sufficient overburden rock to generate hydrocarbons, and 

thus form separate petroleum systems. 

SOURCE ROCK INTERVALS BY TIME 

Meissner and others (1984) used a map of the interior part of the United States to show the distribution of 

hydrocarbon source rocks over nine time intervals. These 

intervals are as follows: Middle Ordovician, latest Silurian to Late Devonian, Late Devonian to mid-Mississippian, Late Mississippian, Pennsylvanian, Permian to 

Triassic, Jurassic, Cretaceous, and latest Cretaceous to 
Table 3. Distribution of petroleum systems by age and hydrocarbon 

type 

[Age of petroleum system is based on the oldest age of the source rock. Information on 

age of source rock is from table 1 1 

Age No. Oil 

Cenozoic undif. ------- 2 1 

Pleistocene------------- 0 NA 

Pliocene ---------------- 2 0 

Miocene ----------·------ 8 7 

Oligocene -------------- 0 NA 

Eocene ------------------ 8 6 

Paleocene--------------- 0 NA 

Cretaceous-------------- 33 13 

Jurassic ----------------- 7 5 

Triassic ----------------- 3 3 

Permian----------------- 3 3 

Pennsylvanian-------- 9 7 

Mississippian--------- 9 4 

Devonian--------------- 21 9 

Silurian ----------------- 4 3 

Ordovician ------------- 13 9 

Cambrian--------------- 4 2 

Precambrian------------ 1 0 

Unknown--------------- 3 3 

Total-----------------130 75 

early Tertiary. Dividing the geological time scale into 13 

segments, Ulmishek and Klemme (1990) inventoried the 

important source rock intervals in the world and found 

that six intervals account for 90 percent of the known oil 

and gas reserves. These six stratigraphic intervals are as 

follows: Silurian, Late Devonian to Tournaisian (Mississippian), Pennsylvanian to Early Permian, Late Jurassic, 

mid-Cretaceous, and Oligocene to Miocene. 

The distribution of U.S. petroleum systems by age 

shown in table 1 are summarized by age and hydrocarbon type in table 3. The most common age of the source 

rock is Cretaceous, whereas the Oligocene and Pleistocene contain none (table 3). The most to least common 

source-rock ages are as follows: Cretaceous (33), Devonian (21), Ordovician (13), Mississippian (9), Pennsylvanian (9), Eocene (8), Miocene (8), and Jurassic (7). The 

remainder of the age brackets have fewer than five. For 

the 130 petroleum systems, 85 were oil or mostly oil and 

Oil/Gas Gas/Oil Gas 

1 0 0 

NA NA NA 

0 0 2 

0 0 1 

NA NA NA 

1 0 1 

NA NA NA 

4 1 15 

0 0 2 

0 0 0 

0 0 0 

0 0 2 

2 0 3 

2 3 7 

0 0 1 

0 1 3 

0 0 2 

0 0 1 

0 0 0 

10 5 40 

45 were gas or mostly gas; a ratio of 2:1. Evidently, oil 

from Ordovician (13) and Eocene (8) source rocks in the 

United States are unimportant on a worldwide scale 

(Ulmishek and Klemme, 1990). 

SUMMARY 

A petroleum system includes all the hydrocarbons 

that originated either from a pod of mature source rock 

or, in the case of microbial gas, from an immature 

source rock. More simply, sedimentary organic matter 

must be heated over time or acted upon by microbes to 

generate petroleum. Sedimentary rock matter dumped 

into basins is the framework into which this organic 

matter and the resultant petroleum products move and 

reside. As discussed above, the areal distribution of organic matter for any particular geologic age can range 

Identified Petroleum Systems within the United States-1992 9 
from local to continental, and these rock intervals are 

unevenly distributed over geologic time. On a worldwide 

scale only six source-rock intervals generated over 90 

percent of known oil and gas (Ulmishek and Klemme, 

1990). The amount, type, and thermal maturity of this 

organic matter must have determined the amount and 

type of petroleum generated. 

The observation that laterally continuous source 

rocks are commonly involved in more than one petroleum system is important, because then regional studies of 

organic-rich rocks between systems can be used to better 

predict the amount and type of organic matter within a 

system where it is presently overmature. An organic-rich 

rock between systems is immature and is frequently penetrated by exploratory wells or is exposed at the surface 

where it can be examined, sampled, and analyzed. In 

contrast, the same organic-rich rock within a system is 

mature to overmature at maximum burial depth, is commonly too deeply buried to be sampled, and when analyzed can give a geochemical profile of a depleted 

source rock. 

By examining a source rock at different levels of 

maturity between and within petroleum systems, and 

comparing these results with the amount and type of recoverable hydrocarbons (cumulative production plus 

known reserves), then the efficiency of different petroleum systems can be compared to better assess the ultimate hydrocarbon potential of a system. For example, a 

map showing the richness, type, and thermal maturity of 

Upper Devonian organic-rich rocks for North American 

is necessary if reasonable calculations to determine the 

amount of hydrocarbons generated are to be compared to 

recoverable hydrocarbons by the petroleum system method. Properly done, this exercise may provide a reasonable estimate of total amount of ultimately recoverable 

hydrocarbons by system. 

The uneven distribution of source rocks over geologic time indicates that only certain intervals need to be 

mapped over large areas. Certainly in the United States, 

strata in the Late Devonian, Cretaceous, and possibly the 

Ordovician intervals need to be addressed on a continental scale. Tertiary source rocks need to be addressed on a 

much smaller scale, such as the Miocene of California. 

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Hills, J.M., and Kottlowski, F.E., 1983, Southwest/southwest 

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Identified Petroleum Systems within the United States-1992 11 
A Concise Historical and Current Perspective 

on the Kinetics of Natural Oil Generation 

By Michael D. Lewan1 

Kinetics is the branch of chemistry that studies the 

time dependency of reactions and the factors controlling 

reaction rates. The importance of time as well as temperature in oil-shale retorting (Franks and Goodier, 1922; 

Maier and Zimmerley, 1924) and natural coalification 

(Huck and Karweil, 1955; Karweil, 1955) was established long before it was recognized as being important 

in oil generation. Habicht (1964) showed the importance 

of oil-generation kinetics in identifying effective source 

rocks in the Gifhom trough. His approach was theoretically based on the Arrhenius kinetic parameters and 

first-order reaction rate suggested by Abelson (1964 ). 

Subsequently, Philippi (1965) showed the importance of 

time in assessing the amount of oil generated in the Ventura and Los Angeles basins. His approach was empirically based on organic geochemical data from subsurface 

wells. Although neither of these studies established an 

explicit method for evaluating oil-generation kinetics, 

they demonstrated the importance of time as well as 

temperature in natural oil generation. 

Tissot (1969) presented an explicit kinetic model 

for oil generation, which was later enhanced by Tissot 

and Espitalie (1975). This approach assumed an overall 

reaction of partial decomposition of kerogen to oil by 

means of six parallel, first-order reactions. Changes in 

the rate of each of these reactions with temperature were 

described by the Arrhenius equation, in which each of 

the six reactions had its own activation energy and frequency factor. In addition to presenting six sets of kinetic parameters for type II kerogens, Tissot and Espitalie 

(1975) also presented six sets of kinetic parameters for 

type I and type III kerogens. Each of the six parallel reactions has an assigned activation energy that is the 

same for all three major kerogen types, but the frequency factor and amount of kerogen consumed for each of 

the six parallel reactions vary among the three major 

kerogen types. This discrete distribution of activation energies assumes that only six types of bonds with known 

bond strengths are cleaved during oil generation. Tissot 

and Welte (1978, p. 504-505) stated that these prescribed 

1 U.S. Geological Survey, Denver, Colo. 

12 The Petroleum System-Status of Research and Methods, 1992 

kinetic parameters are based on extractable bitumen from 

naturally and experimentally matured source rocks, but 

the rationale and methods by which these values were 

determined were not presented. Although the derivation 

of kinetic parameters in this approach is not explicit, it 

revealed the possibility that one time-temperature relationship may not be sufficient to describe oil generation 

from all three major kerogen types. 

During this same time period, another approach 

based on coalification was being developed. A kinetic 

model for changes in reflectivity of vitrinite macerals 

with increasing coal rank was presented by Lopatin 

( 1971) and later modified by Lopatin and Bostick 

(1973). This model was calibrated with naturally matured coals and was based on the premise that the reaction rate doubled for every 1 0°C increase in temperature. 

The time-temperature indices derived from this approach 

were then deductively related to stages of oil generation 

by Hood and others (1975) and Lopatin (1976). The reasonable predictions the Lopatin approach gave for vitrinite reflectances without computer support made it 

particularly popular in petroleum exploration applications (Waples, 1980). However, its inherent premise that 

bond cleavage (thermal cracking) in oil generation from 

all types of kerogen is the same as bond formation (aromatic condensation) in vitrinite maturation was clearly 

an oversimplification. Although this approach may be 

considered a good measure of thermal stress experienced 

within a subsiding sedimentary basin, it is not necessarily a good measure of oil generation. 

Although an unspecified amount of experimental 

pyrolysis data were included in the kinetic model by Tissot and Espitalie (1975), both Arrhenius and Lopatin 

models were primarily dependent up to this time on 

available subsurface well data. Uncertainties in these 

natural data concerning paleotemperatures and gradients, 

uplift and erosion events, and rock unit ages encouraged 

the use of laboratory pyrolysis in developing kinetic 

models. In the years following 1975, the emphasis on 

laboratory pyrolysis in organic geochemical research increased significantly as recorded by the sharp increase in 

number of publications on the subject (Barker and 

Wang, 1988). 
Three categories under which these laboratory pyrolysis experiments may be grouped include open anhydrous pyrolysis, closed anhydrous pyrolysis, and hydrous 

pyrolysis. Open anhydrous pyrolysis involves removing 

vaporized products from the pyrolysis chamber in which 

they are generated in the absence of liquid water. The 

product is removed by either a carrier gas that sweeps 

the vapor products into an external detector (Barker, 

1974; Claypool and Reed, 1976) or an external cold trap 

that condenses liquids from self-purging vapor products 

(Heistand, 1976; Wildeman, 1977). Closed anhydrous 

pyrolysis maintains pyrolysis products in the pyrolysis 

chamber with no liquid water being present. Obtaining a 

liquid product by this method usually requires extracting 

the sample with an organic solvent after the experiment 

has been completed (Harwood, 1977). Hydrous pyrolysis 

involves pyrolyzing a sample in the presence of liquid 

water in a closed reactor. If the proper time and temperature conditions are applied to a potential source rock, 

this method generates an expelled oil that accumulates 

on the water surface (Lewan and others, 1979; Winters 

and others, 1983). 

In the late 1970's and early 1980's, the proliferation in pyrolysis studies was primarily focused on understanding the processes involved in petroleum formation 

and on evaluating hydrocarbon potential of source rocks. 

It was not until the mid-1980's that emphasis was pl~ced 

on laboratory pyrolysis in the derivation of kinetic models for oil generation. The two major pyrolysis approaches employed during this time were non-isothermal 

experiments with open anhydrous pyrolysis (Ungerer, 

1984; Braum and Burnham, 1987) and isothermal experiments with hydrous pyrolysis (Lewan, 1985). 

The non-isothermal approach using open anhydrous pyrolysis for natural oil-generation kinetics was 

first presented by Ungerer (1984) and later enhanced by 

Ungerer and others (1986). In the latest version of this 

approach (Ungerer and Pelet, 1987), aliquots of isolated 

kerogen are subjected to Rock-Eval pyrolysis at three 

different heating rates (for example, 0.34, 4.5, and 56°C/ 

min) that span at least two orders of magnitude. The 

flame-ionization responses to the volatile hydrocarbons 

generated at the three different heating rates are modeled 

by assuming that as many as 20 parallel first-order reactions are responsible for the resulting yield curves. These 

hypothetical reactions are assigned regularly spaced activation energies at 2 kcaVmol intervals between 40 and 

80 kcal/mol. A nonlinear optimization computer program 

(OPTIM) calculates a frequency factor and amount of 

kerogen consumed for each activation-energy interval 

that best reproduces the hydrocarbon-generation curves 

for all three heating rates. Results of this approach presented by Tissot and others (1987) showed narrow activation-energy distributions for oil-prone kerogens, with 

over 70 percent of hydrocarbon generation from type II 

kerogens being described by only two parallel reactions 

within 4 kcaVmol of one another and over 85 percent of 

hydrocarbon generation from type I kerogen being described by a single parallel reaction within a 2 kcal/mol 

interval. This kinetic approach has been shown to model 

changes in hydrocarbon yields as determined by RockEval pyrolysis in the Mahakam Delta (Ungerer and Pelet, 1987), but the relationship between total 

hydrocarbon yields from Rock-Eval pyrolysis and generation of expelled oil in nature needs further clarification. 

Braum and Burnham (1987) discussed the importance of using a distribution of activation energies in describing hydrocarbon generation from non-isothermal 

experiments. In addition to the discrete distribution employed by Ungerer and others (1986), they also considered the use of a Gaussian distribution in their 

discussion. This latter approach assumes that hydrocarbon generation consists of a number of first-order parallel reactions, which have the same frequency factor but 

different activation energies that collectively have a 

Gaussian distribution. Burnham and others (1987) compared these curve-fitting approaches with data generated 

by Rock-Eval pyrolysis. The discrete distribution fits the 

experimental data better than the Gaussian distribution, 

and when extrapolated to geological conditions, the 

Gaussian distribution predicts major hydrocarbon generation 1 0°C to 15°C lower than the discrete distribution. 

Burnham (1991) also did a similar comparison of curvefitting approaches with a modified Fischer assay apparatus. This type of open anhydrous pyrolysis generates a 

condensable oil, which may be kinetically described 

through a series of isothermal experiments. Unfortunately, the amount of oil generated is inversely dependent of 

heating rate, which when extrapolated to geological heating rates results in the total absence of a generated oil. 

In addition to questioning the validity of employing open 

anhydrous pyrolysis in determining kinetics for natural 

oil generation, extrapolating the curve-fitting kinetic 

models from non-isothermal experiments to geological 

conditions has also been questioned (Lakshmanan and 

others, 1991). 

The approach using isothermal hydrous-pyrolysis 

experiments for natural oil-generation kinetics was first 

presented by Lewan (1985). Aliquots of a rock sample 

are subjected to hydrous pyrolysis at temperatures typically in the range of 300°C to 365°C for 72-hour durations. A first-order rate constant is determined from the 

amount of expelled oil generated at each temperature 

and plotted on Arrhenius coordinates (natural log of rate 

constant versus reciprocal of absolute temperature). The 

resulting plots are adequately described by a straight 

line, which provides an activation energy and frequency 

factor in the classical kinetic approach (Lewan, 1985; 

Lewan and Buchardt, 1989). Extrapolation of these kinetic parameters to lower temperatures and longer duraA Concise Historical and Current Perspective on the Kinetics of Natural Oil Generation 13 
tions gives reliable predictions of oil generation from 

.source rocks subsiding in sedimentary basins (Hunt and 

others, 1991). Two important concepts that emerged 

from this experimental approach were that (1) rates of 

oil generation may vary significantly for type II kerogens and (2) rates of oil generation from type II kerogens increase in part with their organic sulfur content. 

The former concept further accentuated the limitations of 

the Lopatin approach as discussed by Wood (1988), and 

the latter concept was also deduced from natural data by 

Orr (1985). 

Unlike kinetics based on total hydrocarbon evolution from kerogen decomposition by Rock-Eval pyrolysis, hydrous pyrolysis more closely simulates nature and 

determines the kinetics of oil generation from the partial 

decomposition of bitumen (Lewan, in press a). As noted 

by Burnham and others (1987), the inability of RockEval pyrolysis to distinguish between bitumen, oil, and 

gas results in a broader oil window than that derived 

from hydrous pyrolysis kinetics. Another consideration 

is the importance of rapid vaporization of pyrolysis 

products in obtaining a volatile product from open anhydrous pyrolysis. Lewan (in press b) noted that this process is not operative in subsiding sedimentary basins, but 

formation of an immiscible oil as observed under hydrous pyrolysis is operative in subsiding sedimentary basins. The importance of water in the natural generation 

and expulsion of oil is continually becoming more evident, and further research on the kinetics of oil generation by hydrous pyrolysis is needed. As stated by 

Gardiner (1969), "If you should find that chemical kinetics is an underdeveloped science compared with other 

aspects of chemistry, be tolerant and recognize that timedependent problems are intrinsically more difficult than 

equilibrium ones, or be challenged and spend some of 

your scientific lifetime improving the situation." 

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Barker, C., and Wang, L., 1988, Applications of pyrolysis in 

petroleum geochemistry: A bibliography: Journal of Analytical and Applied Pyrolysis, v. 13, p. 9-61. 

Braum, R.L., and Burnham, A.K., 1987, Analysis of chemical 

reaction kinetics using a distribution of activation energies 

and simpler models: Energy & Fuels, v. 1, p. 153-161. 

Burnham, A.K., 1991, Oil evolution from a self-purging reactor: Kinetics and composition at 2°C/min and 2°C/h: Energy & Fuels, v. 5, p. 205-214. 

Burnham, A.K., Braum, R.L., Gregg, H.R., and Samoun, A.M., 

14 The Petroleum System---Status of Research and Methods, 1992 

1987, Comparison of methods for measuirng kerogen pyrolysis rates and fitting kinetic parameters: Energy & Fuels, v. 1, p. 452-458. 

Claypool, G.E., and Reed, R., 1976, Thermal-analysis technique for source-rock evaluation: Quantitative estimate of 

organic richness and effects of lithologic variation: American Association of Petroleum Geologists Bulletin, v. 60, 

p. 608-612. 

Franks, A.J., and Goodier, B.D., 1922, Preliminary study of the 

organic matter of Colorado oil shale: Quarterly of the 

Colorado School of Mines, v. 17, p. 3-16. 

Gardiner, W.C., Jr., 1969, Rates and mechanisms of chemical 

reactions: New York, W.A. Benjamin, 284 p. 

Habicht, J.K.A., 1964, Discussion on "The history of migration 

in the Githom trough (NW-Germany)": Proceedings of the 

Sixth World Petroleum Congress, Section 1, p. 479-480. 

Harwood, R.J., 1977, Oil and gas generation by laboratory pyrolysis of kerogen: American Association of Petroleum 

Geologists Bulletin, v. 61, p. 2082-2102. 

Heistand, R.N., 1976, The Fischer assay, a standard method?: 

American Chemical Society Division of Fuel Chemistry 

Papers, v. 21, p. 49-54. 

Hood, A., Gutjahr, C.C.M., and Heacock, R.L., 1975, Organic 

metamorphism and the generation of petroleum: American 

Association of Petroleum Geologists Bulletin, v. 59, p. 

986-996. 

Huck, G., and Karweil, J., 1955, Physio-chemical problems of 

coalification: Brennstoff -Chemie, v. 36, p. 1-11. 

Hunt, J.M., Lewan, M.D., and Hennett, J.C., 1991, Modeling 

oil generation with time-temperature index graphs based 

on the Arrhenius Equation: American Association of Petroleum Geologists Bulletin, v. 75, p. 795-807. 

Karweil, J., 1955, The metamorphosis of coal from the standpoint of physical chemistry: Zeitschrift fiir der Deutschen 

Geologigschen Gesellschaft, v. 107, p. 132-139. 

Lakshmanan, C.C., Bennett, M.L., and White, N., 1991, Implications of multiplicity in kinetic parameters to petroleum 

exploration: Distributed activation energy models: Energy 

& Fuels, v. 5, p. 110-117. 

Lewan, M.D., 1985, Evaluation of petroleum generation by hydrous pyrolysis experimentation: Philosophical Transactions of the Royal Society, v. 315, p. 123-134. 

---in press a, Laboratory simulation of petroleum formation: Hydrous pyrolysis, in Engel, M.H., and Macko, S.A., 

eds., Organic geochemistry: New York, Plenum. 

---in press b, Primary oil migration and expulsion as determined by hydrous pyrolysis: Proceedings of the 13th 

World Petroleum Congress, Section 2. 

Lewan, M.D., and Buchardt, B., 1989, Irradiation of organic 

matter by uranium decay in the Alum Shale, Sweden: 

Geochimica et Cosmochimica Acta, v. 53, p. 1307-1322. 

Lewan, M.D., Winters, J.C., and McDonald, J.H., 1979, Generation of oil-like pyrolyzates from organic rich shale: 

Science, v. 203, p. 897-899. 

Lopatin, N.Y., 1971, Temperature and geological time as factors of coalification: lzdatel'stvo Akademiya Nauk SSSR 

Ser. Geol., v. 3, p. 95-106. 

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and time on the catagenetic process of coalification and 

oil-gas generation, in Issledovaniya Organicheskogo 
Veshchestva Sovremennykhi i Iskopaemykh Osadkov: 

Moscow, Nauka, p. 361-366. 

Lopatin, N.V., and Bostick, N.H., 1973, The geological factors 

in coal catagenesis, in Priroda Organicheskogo 

Veshchestva Sovremennykh i Iskopaemykh Osadkov: 

Moscow, Nauka, p. 79-90. 

Maier, C.G., and Zimmerley, S.R., 1924, The chemical dynamics of the transformation of organic matter to bitumen in 

oil shale: University of Utah Bulletin, v. 14, p. 62-81. 

Orr, W.L., 1985, Kerogen/asphaltene/sulfur relationships in 

sulfur-rich Monterey oils: Organic Geochemistry, v. 10, p. 

499-516. 

Philippi, G.T., 1965, On the depth, time and mechanism of petroleum generation: Geochimica et Cosmochimica Acta, v. 

29,. p. 1021-1049. 

Tissot, B., 1969, First data on the mechanism and the kinetics 

of the formation of petroleum in sediments. Computer 

simulation 'of a reaction scheme: Revue de L'Institut 

Fran~ais du Petrole, v. 24, p. 470-501. 

Tissot, B., and Espitalie, J., 1975, Thermal evolution of organic matter in sediments: Applications of a mathematical 

simulation: Revue de L'Institut Fran~ais du Petrole, v. 30, 

p. 743-777. 

Tissot, B.P., Pelet, R., and Ungerer, P., 1987, Thermal history 

of sedimentary basins, maturation indices, and kinetics of 

oil and gas generation: American Association of Petroleum Geologists Bulletin, v. 71, p. 1445-1466. 

Tissot, B., and Welte, D., 1978, Petroleum formation and occurrence: Berlin, Springer-Verlag, 538 p. 

Ungerer, P., 1984, Models of petroleum formation: How to 

take into account geology and chemical kinetics, in 

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Ungerer, P., Espitalie, J., Marquis, F., and Durand, B., 1986, 

Use of kinetic models of organic matter evolution for the 

reconstruction of paleotemperatures, in Burruss, J., ed., 

Thermal modeling in sedimentary basins: Paris, Editions 

Technip., p. 531-546. 

Ungerer, P., and Pelet, R., 1987, Extrapolation of the kinetics 

of oil and gas formation from laboratory experiments to 

sedimentary basins: Nature, v. 327, p. 52-54. 

Waples, D.W., 1980, Time and temperature in petroleum formation: Application of Lopatin's Method to petroleum exploration: American Association of Petroleum Geologists 

Bulletin, v. 64, p. 916-926. 

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standard oil shale: American Chemical Society, Division 

of Petroleum Chemistry Preprints, v. 22, p. 760-764. 

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in Bjorfijy, M., Advances in organic geochemistry 1981: 

New York, Wiley, p. 524-533. 

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Method: Implications for petroleum explortion: American 

Association of Petroleum Geologists Bulletin, v. 72, p. 

115-134. 

A Concise Historical and Current Perspective on the Kinetics of Natural Oil Generation 15 
Role of Microbial Processes in Petroleum Systems 

By jerry L. Clayton 1 

Microorganisms are ubiquitous in most natural 

aquatic systems and pore waters of shallowly buried sediments (burial depths equivalent to temperatures less 

than about H>0°C). It is widely recognized that microorganisms play major roles in global chemical cycles (for 

example, carbon, sulfur, iron, nitrogen, and manganese) 

(Blackburn, 1983; J~rgensen, 1983; Krumbein and 

Swart, 1983; Nealson, 1983; Burdige and Nealson, 1986; 

Aller and Rude, 1988; Lovley and Phillips, 1988; Lovley 

and others, 1987, 1989a,b, 1990). This report reviews 

the roles of bacteria in the following processes that are 

important components of petroleum systems: (1) sediment diagenesis, (2) degradation of crude oil, and (3) 

formation of crude oil and natural gas. 

The focus of this paper is on bacteria that mediate 

coupled oxidation-reduction reactions using both organic 

and inorganic substrates as a means of obtaining both 

carbon and the energy necessary for metabolic processes. 

These types of bacteria obtain carbon from pre-existing 

organic matter (heterotrophy) or C02 (autotrophy) and 

use either organic or inorganic reactions as a source of 

energy. Some bacteria obtain carbon from dissolved C02 

and energy from photosynthesis via anaerobic pathways. 

Because of the light requirement imposed by photosynthesis, such bacteria are restricted to the phototrophic 

zone of the water column or to the uppermost sediment 

layers where the water is shallow enough to allow nearly 

unimpeded light penetration. Green and purple sulfur 

bacteria (Chlorobiaceae and Chromatiaceae) are important groups of anaerobic photosynthetic bacteria. Aerobic 

photosynthesis is carried out by blue-green bacteria living in the upper, phototrophic water column and on the 

surface of bottom sediments. 

Classical methods of classifying bacteria are based 

on morphology, gram stain reaction, cultural characteristics (that is, the kind of growth on media of different 

compositions), and biochemical reactions such as sugar 

fermentations and amino acid and vitamin requirements. 

More recent classification methods are based on the 

composition of nucleic acids (Fox and others, 1980). For 

understanding bacterial effects in petroleum systems, a 

1 U.S. Geological Survey, Denver, Colo. 

16 The Petroleum System-Status of Research and Methods, 1992 

classification based on energy and carbon source is convenient, because this type of classification groups the organisms according to inorganic products released into 

the sediment. These inorganic products are important in 

the formation or degradation of petroleum in that they 

play a role in mineral diagenesis or affect the carbon 

budget of the system. Accordingly, bacteria can be classified into two major groups of importance in petroleum 

systems (table 4). The two groups listed in table 4 include both aerobic and anaerobic types. Autotrophic bacteria use C02 as a source of carbon for synthesis of 

biomolecules and obtain the energy necessary for synthesis from light (photosynthesis) or from oxidation of inorganic substrates (chemosynthesis). These bacterial 

process are important in organic matter and sediment diagenesis. Heterotrophic bacteria generally use pre-existing organic compounds and are particularly important in 

degradation of petroleum. 

In sediments, bacterial activity generally decreases 

with increasing depth of burial owing to depletion of nutrients, changing pH or oxidation-reduction potential, accumulation of toxic by-products of metabolism, or 

increasing temperature. Within this overall trend of decreasing activity, zonation occurs in which different 

types of bacteria inhabit successive sediment layers in 

response to changing environmental conditions (Ponnamperuma, 1972; Claypool and Kaplan, 1974; Yoshida, 

1975; Champ and others, 1979; Froelich and others, 

1979; Winfrey and others, 1981; Reeburgh, 1983). This 

succession of bacterial populations can be divided into 

three zones: (1) the aerobic zone; (2) the anaerobic sulfate-reducing zone; and (3) the methanogenesis zone 

(Claypool and Kaplan, 1974; Rice and Claypool, 1980; 

Lovley and Goodwin, 1988). It is important to note that 

aerobic metabolism may occur also in porous rocks at 

greater depth where hydrodynamic conditions allows influx of oxygenated, meteoric water. This is the condition 

that allows aerobic, bacterial degradation of petroleum in 

a reservoir. 

SEDIMENT DIAGENESIS 

Chemical diagenesis in sediments includes authigenic mineral precipitation, replacement, and solution. 
Table 4. Classification of bacteria according to energy source and source of nutrition (carbon) 

Bacteria Energy source Carbon source 

Autotrophs ----------------------Photosynthesis (light energy) -------------------------------- C02 

Chemosynthesis (oxidize inorganics) ----------------------- C02 

Heterotrophs -------------------Oxidation (oxidize organics)--------------------------------- Organic compounds 

(some use C<>2,) 

Bacterial processes can play a major role in diagenetic 

reactions involving not only organic materials, but inorganic mineral phases as well. These processes are important in petroleum systems because they can affect 

reservoir properties. 

In general, bacterial metabolism under anaerobic 

conditions increases pore water alkalinity and decreases 

Eh. In the sulfate-reducing zone, SO/- (sulfate), HS-

(sulfide), and HC03- (bicarbonate) are among the most 

important dissolved species (Claypool and Kaplan, 1974; 

Goldhaber and Kaplan, 1974). In the methanogenesis 

zone, CH4 and H2 are among the most common dissolved species. Precipitation of iron sulfides and carbonate minerals are common diagenetic effects of 

accumulation of bacterial end-products in pore waters. 

Additional bacterial processes of importance in diagenesis are iron and manganese reduction (Aller and Rude, 

1988; Lovley and others, 1987, 1988, 1989a,b, 1990; 

Lovley and Phillips, 1988). Iron, sulfate, and carbonate 

reduction are particularly important because these reactions affect pore water concentrations of species involved directly in mineral reactions. However, bacterial 

processes in general affect the pore water pH, Eh, and 

ionic strength even though the inorganic substrates may 

or may not participate directly in mineral diagenetic reactions. Therefore, mineral stabilities in pore waters of 

organic-rich sediments can be affected indirectly by bacterial activity. 

PETROLEUM DEGRADATION 

Bacterial degradation can significantly diminish the 

economic value of a petroleum accumulation because of 

increased recovery and refinery costs. In addition, bacterial alteration of petroleum can be so extensive that geochemical evaluation of thermal maturity, source 

correlation, and secondary migration becomes nearly impossible. 

Effects of biodegradation of petroleum are summarized by Connan (1984) and references therein. According to Connan (1984), the requirements for aerobic 

biodegradation of petroleum include (1) moving water 

(meteoric), (2) oil-water contact since bacteria live in the 

aqueous phase, (3) supply of nutrients such as nitrogen 

and phosphorus, and (4) proper temperature (less than 

about 100°C). 

FORMATION OF CRUDE OIL 

AND NATURAL GAS 

Bacteria play important roles in the accumulation 

of sedimentary organic matter (formation of potential petroleum source rocks) and in generation of methane natural gas resources. In well-oxygenated sedimentary 

environments, oxidation of organic matter by aerobic 

bacteria contributes to poor preservation of organic matter of the type contained in effective petroleum source 

rocks (hydrocarbon-generating organic matter). Inhibition of aerobic decay by lower oxygen levels can contribute to preservation of better quality (more lipid-rich 

or oil-prone) organic matter. Harvey and others (1986) 

showed that degradation and mineralization of organic 

matter proceeds more rapidly under aerobic than under 

anaerobic conditions. Further, Harvey and others (1986) 

presented evidence that high organic carbon content in 

sediments inhibits bacterial degradation of lipids, so that 

in organic-rich sediments positive feedback may occur 

between preservation of large amounts of organic matter 

and depressed bacterial degradation of lipids. 

It is important to note, however, that complete oxidation of organic matter is possible in anaerobic sediments by bacteria using nitrate, sulfate, iron, or 

manganese as the sole electron acceptor (Pfenning and 

others, 1981; Starns and others, 1985; Szewzyk and 

Pfenning, 1987; Lovley and Phillips, 1988). Other factors also affect preservation of organic matter, such as 

rate of organic productivity in the water column, sedimentation rate, sediment particle size, and bioturbation, 

but bacteria are clearly important components in the 

overall process. 

Bacterial generation of gas is thought to account 

for about 20 percent or more of the world's resource of 

natural gas (Rice and Claypool, 1980). Methane generation is accomplished not by a single organism, but rather 

by a consortium of bacteria. Anaerobic bacteria produce 

extracellular enzymes that hydrolyze carbohydrates and 

Role of Microbial Processes in Petroleum Systems 17 
proteins to produce simple sugars and amino acids. The 

sugars and amino acids are then converted to ketoacids 

(pyruvate), hydroxy acids (lactate) and fatty acids (formate, acetate, propionate), C02, and H2• Proton-reducing 

bacteria convert protons to hydrogen gas, which in tum 

is used by the methanogenic bacteria as a reducing 

agent. Methanogenic bacteria reduce the C02 by reaction 

with H2 or split acetate produced from the preceding reactions to form methane and C02• 

The methanogens are a diverse group of bacteria 

that exhibit a wide tolerance of environments including 

virtually every habitat in which anaerobic degradation of 

organic matter occurs (Jones and others, 1983). Methanogens have been isolated from freshwater and marine 

sediments, and extreme environments such as geothermal 

springs and deep-sea hydrothermal vents (Huber and others, 1982; Jones and others, 1983). Methanogenic bacteria are most active at pH 6.5 to 8.0 and at temperatures 

of 4°C to 45°C (Zeikus and Winfrey, 1976). This "cosmopolitan" status of methanogens is attributable to their 

unique mode of metabolism (methane generation) and 

the fact that the compounds that serve as substrates are 

end products of other metabolic processes (Jones and 

others, 1983). 

ROLE IN EXPLORATION 

Besides their importance in sedimentary processes 

that form some rocks or reservoirs and in petroleum alteration, bacteria contribute biological marker compounds to sedimentary organic matter. These biomarkers 

are present in petroleum as well and can be useful indicators of thermal maturity and the depositional setting of 

the source rock or can be used for oil-source rock or oiloil correlation studies to identify petroleum systems. 

FURTHER WORK 

A number of studies have demonstrated that bacteria thrive in both oxygenated and anoxic marine and 

freshwater sediments, and isotopic evidence indicates 

clearly that bacterial metabolites are involved in various 

mineral reactions. Despite these field studies and anumber of laboratory studies in which bacteria have been 

studied under a wide range of growth conditions, considerable uncertainty remains with respect to constraints on 

bacterial activities in sedimentary environments. The 

principal limitations are certainly availability of nutrients, temperature, pH, Eh, osmotic pressure, toxicity of 

metabolic products, and competition among various bacteria for common substrates. The porosity, permeability, 

and hydrodynamic regime of a particular setting are also 

important because these factors influence the growth fac18 The Petroleum Syste~Status of Research and Methods, 1992 

tors listed above. However, the precise interplay of these 

factors with respect to either individual or cumulative 

bacterial processes is imperfectly understood. Improved 

understanding of the ecological requirements of various 

bacterial communities and their effects on the accumulation and composition of sedimentary organic matter is 

important for correlations and source-rock studies in petroleum systems. 

The depth in a sedimentary basin over which bacteria remain active or viable is poorly established. Methanogens are known to remain active at temperatures as 

high as 85°C (Postgate, 1984) if other suitable growth 

factors are present, and some sulfate-reducing bacteria 

have been reported at 100°C (Stetter and others, 1987). 

Another question is whether bacteria remain viable, even 

though inactive, during relatively deep burial (accompanied by high temperatures) so that when erosion occurs 

and the environment becomes more hospitable bacterial 

growth might be revitalized. 

Inorganic computer models of diagenetic reactions 

leave out possible effects of bacterial processes. Bacterial processes could introduce a large uncertainty into 

these models because metabolic pathways sometimes favor reactions (via coupled or multiple biochemical pathways) not predicted by thermodynamics. These bacterial 

processes could dramatically affect the pore water composition during early diagenesis in an unpredictable 

manner. Furthermore, as discussed previously, pore water Eh and pH can be significantly shifted by bacterial 

metabolism. Therefore, computer models of mineral diagenesis in organic-rich sediments need to allow for compositional changes in reactions mediated by bacteria. 

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Lovley, D.R., Chapelle, F.H., and Phillips, E.J.P., 1990, 

Fe(lll)-reducing bacteria in deeply buried sediments of the 

Atlantic Coastal Plain: Geology, v. 18, p. 954-957 .. 

Lovley, D.R., and Goodwin, F., 1988, Hydrogen concentrations 

as an indicator of the predominant terminal electron-accepting reactions in aquatic sediments: Geochimica et 

Cosmochimica Acta, v. 52, p. 2993-3003. 

Lovley, D.R., and Phillips, E.J.P., 1988, Novel mode of microbial energy metabolism: Organic carbon oxidation coupled 

to dissimilatory reduction of iron or manganese: Applied 

and Environmental Microbiology, v. 54, p. 1472-1480. 

Lovley, D.R., Phillips, E.J.P., and Lonegran, D.J., 1989a, 

Hydrogen and formate oxidation coupled to dissimilatory 

reduction of iron or manganese by Alteromonas 

putrefaciens: Applied and Environmental Microbiology, v. 

55, p. 700-706. 

Lovley, D.R., Stolz, J.P., Nord, G.L., Jr., and Phillips, E.J.P., 

1987, Anaerobic production of magnetite by a dissimilatory iron-reducing microorganism: Nature, v. 330, p. 252-

254. 

Nealson, K.H., 1983, The microbial iron cycle, in Krumbein, 

W.E., ed., Microbial geochemistry: Boston, Blackwell Scientific Publications, p. 159-199. 

Pfenning, N.W., Widdell, F., and Triiper, H.G., 1981, The dissimilatory sulfate-reducing bacteria, in Starr, M.P., Stolp, 

H., Triiper, H.G., Balows, A., and Schlegel, H.G., eds., 

The prokaryotes: New York, Springer-Verlag, p. 926-940. 

Ponnamperuma, F.N., 1972, The chemistry of submerged soils: 

Advances in Agronomy, v. 24, p. 29-96. 

Postgate, J.R., 1984, The sulphate-reducing bacteria: New 

York, Cambridge University Press, 208 p. 

Reeburgh, W.S., 1983, Rates of biogeochemical processes in 

anoxic sediments: Annual Review of Earth and Planetary 

Sciences, v. 11, p. 269-298. 

Rice, D.D., and Claypool, G.E., 1980, Generation accumulations, and resource potential of biogenic gas: American 

Association of Petroleum Geologists Bulletin, v. 67, p. 5-

25. 

Starns, A.J.M., Hansen, T.A., and Skyring, G.W., 1985, Utilization of amino acids as energy substrates by two marine 

Desulfovibrio strains: FEMS Microbiological Ecology, v. 

31, p. 11-15. 

Stetter, K.O., Laueres, G., Thomm, M., and Neuner, A., 1987, 

Isolation of extremely thermophilic sulfate reducers: evidence for a novel branch of archaebacteria: Science, v. 

236, p. 822-824. 

Szewzyk, R., and Pfenning, N., 1987, Complete oxidation of 

catechol by the strictly anaerobic sulfate-reducing 

Desulfobacterium catecholicum sp. nov.: Archives of Microbiology, v. 147, p. 163-168. 

Winfrey, M.R., Marty, D.G., Bianchi, A.J.M., and Ward, D.M., 

1981, Vertical distribution of sulfate reduction, methane 

production, and bacteria in sediments: Geomicrobiology 

Journal, v. 2, p. 341-362. 

Yoshida, T., 1975, Microbial metabolism of flooded soils, in 

Paul, E.A. and McLaren, A.D., eds., Soil biochemistry, v. 

3: New York, M. Dekker, p. 83-122. 

Zeikus, J.G., and Winfrey, M.R., 1976, Temperature limitation 

of methanogenesis in aquatic sediments: Applied Environmental Microbiology, v. 31, p. 99-107. 

Role of Microbial Processes in Petroleum Systems 19 
Coalbed Methane 

By Ben E. Law1 

INTRODUCTION 

Estimates of coalbed methane resources in-place in 

the United States range from 72 to 860 trillion cubic feet 

(tcf), with most estimates ranging from 300 to 500 tcf 

(Rightmire, 1984). Cumulative gas production from coal. 

beds through January 1991 was about 400 billion cubic 

feet. Commercial coal bed gas production in the United 

States began in about 1977 from the San Juan basin of 

New Mexico and Colorado and the Black Warrior basin 

of Alabama. Since 1989, gas production has expanded 

into the Piceance basin of Colorado, the Powder River 

basin of Wyoming, and the Cherokee basin of Kansas. In 

the Raton basin of Colorado and New Mexico, gas production is awaiting pipelines, and in the northern Appalachian region, where a few coalbed gas wells have been 

producing gas since the 1940's, the issue of gas ownership is a large obstacle to exploration and production. 

Additional areas with production potential, such as the 

Green River basin of Wyoming, have been hampered by 

environmental problems related to water disposal. 

Internationally, there is a growing interest in coalbed methane as an energy source. Exploration for coalbed methane has been initiated in Canada, Australia, 

China, Russia, and several European countries. Ironically, in some of these countries activity has been spurred 

by a desire to alleviate environmental problems associated with coal mining and the direct utilization of coal. 

The continued expansion of coalbed methane exploration and production into additional coal-bearing regions will require an improved understanding of these 

accumulations, as well as favorable economic conditions. 

Nearly all of the current research in the United States is 

in the Black Warrior and San Juan basins, where there is 

an emphasis on engineering and production aspects. The 

geologic variables that have been determined to be important in coalbed-methane accumulation and production 

include rank, pressure, temperature, permeability, and 

1

U.S. Geological Survey, Denver, Colo .. 

20 The Petroleum System-Status of Research and Methods, 1992 

moisture. Although the roles of these geologic criteria 

are known in a general way, there is a need to determine 

the relative importance of these variables in different 

coal-bearing basins. 

RANK 

It is well known that gas content increases with increasing coal rank (Juntgen and Karweil, 1966; Meissner, 1984). Low-rank coals (lignite through high-volatile 

C bituminous) contain as much as 80 standard cubic feet 

per ton (scf/ton), whereas higher rank coals contain as 

much as 700 scf/ton. The gas in low-rank coal is usually 

biogenic and gas in high-rank coal is thermogenic. 

Low-rank coals are usually normal or under-pressured 

and high-rank coals are commonly over- or underpressured. In areas of high-rank coals, such as the San Juan 

basin, economically recoverable gas accumulations are 

pervasive and are independent of structural and 

stratigraphic traps. Since most coal-gas research 

has been conducted in high-rank coals, there is some 

uncertainty regarding the nature of coalbed methane 

accumulations in low-rank coals. Additional research is 

needed to more accurately determine the relationships 

among coal rank, gas generation, gas content, and gas 

composition. 

PRESSURE AND TEMPERATURE 

The amount of gas contained in coal of a given 

rank is related to pressure and temperature (Juntgen and 

Karweil, 1966; Meissner, 1984); with increasing pressure, gas content increases and with increasing temperature, gas content decreases. In general, overpressured 

coals are more productive than normal or underpressured 

coals, and it is usually necessary to reduce formation 

pressure to initiate gas production. 

Current research is mainly on engineering aspects 

of pressure that include refining methods of measuring 

the adsoption capacity of coal and the effects of confining pressure on coal permeability. Geologically, there 

are only a few pressure and temperature studies related 

to coal-gas (Meissner, 1984; Kaiser and others, 1991). 
Additional research is needed to examine and relate the 

pressure and temperature histories of coal to present-day 

conditions. 

PERMEABILITY 

The principal permeability pathway in coal is 

through the cleat system (fractures). The cleat system in 

coal is defined by an approximately orthogonal set of 

fractures referred to as face and butt cleats. Face cleats 

constitute the dominant set and butt cleats the subordinate set. Due to the better development of face cleats, 

permeability in coal commonly exhibits varying degrees 

of anisotropy, with the better development parallel to the 

face cleat direction. In the absence of effective cleat permeability, economic levels of gas production from coal 

beds would be impossible. 

The origin of cleats is unknown, although hypotheses have been made that include tectonic deformation, 

shrinkage due to moisture loss, and extension related to 

the relaxation of stress (Moore, 1922; Price, 1966; Ting, 

1977). The factors that are known to affect the characteristics of cleats include bed thickness, coal quality (ash and 

maceral content), rank, and tectonic deformation (Macrae 

and Lawson, 1954; Ammosov and Eremin, 1960; Ting, 

1977). While these studies and more recent basinwide 

studies in the Piceance and San Juan basins (Grout, 1991; 

Tremain and others, 1991) facilitate characterization of the 

cleat system, they do not necessarily characterize the permeability of cleats under in situ confining pressures; at 

depth, permeability may be ineffective due to high confming pressures and a closed cleat system. 

MOISTURE 

One of the largest obstacles to economic recovery 

of coal bed methane is water. The presence of water inhibits desorption of gas from the coal and flow to the 

wellbore (Joubert and others, 1973). Consequently, coal 

beds are commonly dewatered to a point at which gas 

begins to desorb from the matrix. The period of time 

necessary to accomplish sufficient dewatering is highly 

variable and in some cases is never reached. The success 

of dewatering efforts depends on development of the 

cleat system and on the source of water, which may be 

from recharge at the outcrop, from adjacent aquifers, or 

from inherent moisture in coal. In those cases where the 

source of water can be determined, the feasibility of a 

dewatering program can be evaluated more objectively. 

However, current methods of determining the source of 

water are unreliable. 

REFERENCES CITED 

Arnmosov, I.I., and Eremin, I.V., 1960, Fracturing in coal 

(translated from Russian): Moscow, IZDAT Publishers, 

·109 p. 

Grout, M.A., in press, Coal cleats in the southern Piceance 

basin, Colorado: Correlation with both regional and local 

fold-related fracture sets, in Schwochow, S., ed., Coalbed 

methane of western North America: Denver, Colo., Rocky 

Mountain Association of Geologists. 

Joubert, J.l., Grein, C.T., and Bienstock, D., 1973, Sorption of 

methane in moist coal: Fuel, v. 52, p. 181-185. 

Juntgen, H., and Karweil, J., 1966, Gasbildung und 

gasspeicherung in steinkohlenflozen, part I and IT: Erdol 

und Koble, Erdgas, Petrochemie, v. 19, p. 251-258 and 

339-344. 

Kaiser, W.R., Swartz, T.E., and Hawkins, G.J., 1991, Hydrology of the Fruitland Formation, San Juan Basin, in Geologic and hydrologic controls on the occurrence and 

producibility of coalbed methane, Fruitland Formation, 

San Juan Basin: Gas Research Institute Publication, GRI91/0072, p. 195-241. 

Macrae, J.C., and Lawson, W., 1954, Cleat in coal seams: 

Transactions Leeds Geological Association, p. 227-242. 

Meissner, F.F., 1984, Cretaceous and lower Tertiary coals as 

sources for gas accumulations in the Rocky Mountain 

area, in Woodward, J., Meissner, F.F., and Clayton, J.L., 

eds., Hydrocarbon source rocks of the greater Rocky 

Mountain region: Denver, Colo., Rocky Mountain Association of Geologists, p. 401-431. 

Moore, E.S., 1922, Coal, its properties, analysis, classification, 

geology, extraction, uses, and distribution: New York, 

John Wiley & Sons, 462 p. 

Price, N.J., 1966, Fault and joint development in brittle and 

semi-brittle rock: New York, Pergamon Press, 176 p. 

Rightmire, C.T., 1984, Coalbed methane resource, in 

Rightmire, C.T., Eddy, G.E., and Kirr, J.N., eds., Coalbed 

methane resources of the United States: American Association of Petroleum Geologists Studies in Geology 17, p. 

1-13. 

Ting, F.T.C., 1977, Origin and spacing of cleats in coal beds: 

Journal of Pressure Vessel Technology, v. 99, p. 624-626. 

Tremain, C.M., Laubach, S.E., and Whitehead, N.H., ill, 1991, 

Coal fracture (cleat) patterns in Upper Cretaceous 

Fruitland Formation, San Juan Basin, Colorado and New 

Mexico: Implications for coalbed methane exploration and 

development, in Geologic and hydrologic controls on the 

occurrence and producibility of coalbed methane, 

Fruitland Formation, San Juan Basin: Gas Research Institute Publication, GRI-91/0072, p. 97-117. 

Coalbed Methane 21 
Turbidity Current Processes 

By William R. Normark1 and David j.W. Piper2 

INTRODUCTION 

Generalized facies models for turbidite deposits 

provide only a first-order interpretation of the detailed 

evolution of turbidite sequences and their relationship to 

sea-level fluctuations and source-area tectonism. A more 

powerful approach is to analyze a turbidite depositional 

system in terms of its sediment source, the processes 

controlling initiation of turbidity flows, how the resulting turbidity currents evolved during flow, the relation 

of flow characteristics to morphologic development of 

both the pathway(s) and depositional areas, and how 

these flows relate to depositional facies. 

Although our understanding of flow processes has 

been hampered by the difficulty of direct observation or 

monitoring turbidity currents at sea, recent advances in 

both field observation and numerical modeling indicate 

that the variety of turbidity-current flows has been underestimated in the past. An increasing body of evidence 

shows that many, if not most, recognizable turbidites 

were deposited from quasi-steady flows that last for 

many tens of hours. This conclusion is radically different 

from the catastrophic, high-density surges (volume concentration as much as 6 x 10-1

) envisaged by earlier 

workers (Kuenen, 1950; Heezen and Ewing, 1952). Bagnold (1962) showed that grain-to-grain collisions prevent 

turbulent transport of sediment above sediment concentrations of 9 x 10-2 (volume concentration). Recent work 

further shows that much of the sediment transport takes 

place in flows with sediment concentrations that are well 

below this limiting value or that approach it only near 

the base of the flow. 

Pertinent research from the last two decades (see 

review in Norm ark and Piper, in press) that exemplifies 

the broad range in the character of turbidity currents is 

summarized in three sections that reflect both the nature 

of the data and the degree of change in our understand1

U.S. Geological Survey, Menlo Park, Calif. 

2 Atlantic Geoscience Centre, Geological Survey of Canada, 

Dartmouth, N. S., Canada. 

22 The Petroleum System-Status of Research and Methods, 1992 

ing of the processes and products of these currents. 

These sections are (1) initiation processes, including fluid-flow and sediment-failure mechanisms; (2) the flow of 

turbidity currents in channels, recognizing that the 'channel properties reflect a rather limited range of flow conditions that might exist within any given turbidite 

system; and (3) inferences of flow processes from the 

deposits left by turbidity currents. This review concludes 

with the implications for facies distribution in the resulting turbidite deposits. Figure 6 and the expanded reference section parallel the text organization. 

INITIATION 

Significant new insights on processes that generate 

sustained turbidity currents have come from studies of 

flows generated by the injection of concentrated sediment suspensions that result either from river discharge 

or storm surges, and flows that evolve from mass failures on deltaic and basin slopes. Both the grain-size distribution and the volume of material available to form a 

turbidity current reflect the primary source area and the 

effects of any intermediate staging areas where sediment 

may temporarily accumulate before being remobilized. 

In addition, flow characters such as the speed, thickness, 

and sediment distribution within the flow itself reflect 

the source characteristics. Figure 6A shows our understanding of the relation between initiation processes for 

turbidity currents and sediment input parameters. Differ-

~Figure 6. Schematic representation of the principal 

factors controlling initiation, transport, and deposition in 

turbidite systems (developed from figures in Normark and 

Piper, in press). A, Typical total sediment volume and petrology/grain-size distribution for various types of flow initiation. B, Principal processes acting during channelized 

phases of sediment transport. Cross section shows general 

characteristics of sandy, mixed, and muddy turbidity currents; note that each of these types can show great variation in total size and thus flow thickness and duration. C, 

Typical sediment deposits resulting from different types of 

flow in a simple channel/levee system leading to a depositional lobe. 
Sandy 

GRAIN SIZE RANGE 

Mixed Muddy 

A 

Initiation requires a steep 

slope and a process to 

suspend sediment 

SIZE OF 

INITIAL 

FLOW, 

IN CUBIC 

METERS OF 

SEDIMENT. 

1010 

Spillover of tops of flows 

separates channel and 

overbank flows 

B 

Transport of many hours 

duration. Flow character 

depends on size of flow, type 

of sediment, and interaction 

with sea-floor morphology 

\ 

PLAN VIEW 

HIGH 

SEA 

LEVEL 

Conduit flushingErosion of channel by 

accelerating ignitive flow 

Flow expansion from 

gradient changes, 

channel widening, or 

overbank flow causes 

scours or rapid 

deposition 

Bedforms 

Mud waves from thick 

muddy flows 

Gravel waves from thin 

sandy flows 

,.....-~ -_-_-_-_-_-_-_-_-_-_-_-__:::-- ------~~-~ - ~ ----

c 

Deposition patterns result from 

flows of different grain size, 

thickness, and velocity 

interacting with pre-existing 

morphology 

Sandy flow-Thin, 

fast, erosive 

I 

LARGE 

SANDY 

FLOW 

Mixed flowIntermediate 

velocity 

/ 

Muddy flow-Slow, 

thick, and unconstrained by seafloor morphology, 

;fla~e \ 

REPEATED 

THIN 

MUDDY 

FLOW 

Turbidity Current Processes 23 
ent initiation processes involve different volumes and 

grain-size compositions and reflect the local geographic 

settings. Turbidity currents from reef-edge failures are 

generally much smaller but with a larger proportion of 

coarser sediment than those generated by failures on passive-margin slopes (fig. 6A). 

Initiation by River Discharge 

The direct, or hyperpycnal, flow of turbid rivers and 

tailings discharge into lakes has long been known to result 

in turbidity currents (Gould, 1951; Lambert and others, 

1976; Normark and Dickson, 1976; Weirich, 1984). For a 

turbidity current to develop from an initial suspension 

flow, the suspension flow must maintain a sufficient velocity (through inertial effects or external forcing) until there 

is a sufficient gradient for a turbidity current to be selfsustaining. Experimental studies and observations of flows 

into lakes and fjords have identified those conditions in 

which the gradient and suspended sediment concentration 

are sufficient for the turbidity-current flow to accelerate. 

Under these conditions, the flow can erode and put more 

sediment into suspension, thus providing additional power 

to the current This positive feedback situation is referred 

to as "ignition" (Parker, 1982). 

Initiation of Currents by Storms 

Ignitive flow of coastal sand down submarine canyons has been documented where rip currents associated 

with storm surges catastrophically remove sand from 

canyon heads (Fukushima and others, 1985). This mechanism is potentially significant wherever there is a narrow shelf and canyons intersect the littoral-drift system; 

thus, such environments would have been more common 

during Pleistocene low stands of sea level. 

Data from a suite of displaced current-meter moorings indicate that turbidity currents formed as a result of 

a storm surge across a reef front related to the passage of 

Hurricane Iwa through the Hawaiian Islands on 23 November 1982 (Dengler and others, 1984a,b). Carbonate 

turbidites and debris flows are common along carbonate 

margins, and many adjacent basinal turbidites show multiple entry points (Mullins, 1983), consistent with a 

storm-surge trigger for the flows; the data do not exclude, however, initiation resulting from seismic shaking. 

Sediment Failure Initiation Processes 

Most turbidity currents are commonly thought to 

result from seismically triggered mass failures, but there 

are remarkably few studies that document the relation 

24 The Petroleum System-Status of Research and Methods, 1992 

between sediment failure and turbidity-current flow. 

Some of the issues involved in the seismic initiation of 

turbidity currents are more clearly defined from recent 

studies of the 1929 Grand Banks turbidity current. The 

1929 event on the Laurentian Fan off eastern Canada has 

long been regarded as a type example of a catastrophic, 

seismically triggered turbidity current (Heezen and Ewing, 1952; Heezen and others, 1954). Numerous authors 

(the earlier ones reviewed by Menard, 1964; the more 

recent ones by Kirwan and others, 1986) have attempted 

to model the flow as a surge, but this is inconsistent with 

the evidence for prolonged and quasi-steady flow provided by the regular gravel bedforms and scours on the valley floor and by the sediment-flux requirements (Hughes 

Clarke and others, 1990). Failure did not take place in a 

single large slide; rather, there were numerous shallow 

slides, separated by less disturbed areas of seabed. 

Hughes Clarke (1988) argued that to maintain flow over 

a period of several hours, there must have been a continuous process of transformation of debris flows to turbidity currents. Silty sediment put into suspension following 

widespread slope failure could have flowed ignitively 

(Piper and others, 1991). The convergent valley pattern 

on the slope above the Laurentian Fan would aid in the 

concentration, maintenance, and acceleration of such ignitive flow. 

Turbidity currents triggered by large earthquakes 

may be recognized from their synchronous development 

in several different drainage basins (Adams, 1989; Anastasakis and Piper, 1991). In ancient basin-plain sequences, amalgamated beds may be evidence of large 

seismically triggered turbidity currents. Earthquakes are 

not the only triggers for failure of upper-slope sediment, 

where failure also may be induced by storm waves. Not 

all failures, however, will result in ignitive flow producing turbidity currents. 

Turbidity Current Initiation on Deltas 

Because sediment strength and seabed slope are 

important in determining whether sediments fail, rapidly 

accumulating deltaic sediment, which tends to be underconsolidated and has relatively low strength, is particularly susceptible to failure, especially where the deposit 

is prograding across steep slopes. Such deltaic environments also may be the site of hyperpycnal inflow of sediment-laden river discharge that can form a turbidity 

current directly. The high sediment concentrations associated with high-bedload-discharge rivers suggest that 

they may be the most likely to initiate turbidity currents. 

Recent case studies of fjord deltas off British Columbia 

and Baffin Island, Canada, provide our best evidence to 

date to evaluate hyperpycnal flow and slumping mechanisms for generating turbidity currents (Prior and others, 
1981, 1982, 1986, 1987; Syvitski and Rein, 1991; 

Syvitski and others, 1987). 

TRANSPORT 

Turbidity currents vary in the total amount of sediment transported, duration, grain-size distribution of 

transported sediment, velocity, and thickness. Smaller 

currents tend to deposit their load in more proximal environments; larger currents may transport sediment to 

distal environments. The morphology of deep-sea fan 

systems reflects the cumulative erosional and depositional effects of a large number of turbidity currents, each of 

which interacts with channel conditions in different 

ways. The ,volume of large turbidite beds cannot be 

equated directly to the volume of sediment released in a 

single initiating event; an accelerating large current may 

erode sediment from the floor of any conduits and transport substantial amounts of deep-water sediment, including that deposited by previous, probably smaller, 

currents. 

Channel overflow, erosion of channel walls, lateral 

migration of channels, and large-scale depositional bedforms are just some of the features that provide insight 

to flow characters that can be used to deduce flow conditions (fig. 6B). Limited field evidence shows that turbidity currents that transport a large proportion of sand 

are thinner than those that are predominantly of mud and 

also that there is a vertical gradient in the grain size of 

sediment transported by a turbidity current. These two 

general trends are a consequence of the dynamics of turbidity-current flow and are accentuated by entrainment 

of water at the top of the flow and erosion of sediment 

under ignitive conditions at the base. They are confirmed 

by flume experiments (Parker and others, 1987) and can 

be predicted by physical modeling (Stacey and Bowen, 

1988a,b). 

Different flows react in different ways to sea-floor 

relief (fig. 6B). A small flow may be confined within a 

fan valley system; a larger flow may be essentially channelized, but spill over the levees (Hay, 1987b ). Thick 

flows may experience flow-stripping of the upper part of 

the flow at abrupt bends in the channel (Piper and Normark, 1983), and a very thick flow may move downslope with the fan valley acting merely as a local 

roughness element (in cases where the flow thickness 

greatly exceeds the channel depth). 

The role of the Coriolis force, which is a geostrophic effect of the Earth's rotation that is proportional 

to latitude and· flow velocity, also reflects flow characters. Slow, muddy turbidity currents that exceed channel 

relief can develop a significant cross-flow gradient affecting deposition throughout the basin; the effect of 

thin, fast, sandy flows in controlling deposition is more 

pronounced immediately downslope from the channel 

termination zone. 

On mature passive-margin fans such as the Amazon and the Mississippi, there are highly sinuous fan 

channels with continuous levees (Flood and Damuth, 

1987; Kastens and Shor, 1985). Such channels appear in 

equilibrium with bankfull or smaller flows: there is no 

evidence for slightly larger flows that would be expected 

to breach levees on sharp bends, although the possibility 

of very thick flows oblivious to channel relief cannot be 

excluded. This suggests that flows are relatively slow, 

hence of relatively low density and long duration. Turbidity currents initiated by seismic failure (such as the 

Holocene deposits of Navy Fan and Cascadia Channel), 

or by bedload delta processes such as hyperpycnal flow 

or mouth-bar failure (such as Var Fan, late Pleistocene 

deposits of Navy Fan) appear to be much more variable 

in size, and variably erode or deposit on different parts 

of the fan system, thus yielding a more complex morphology (Piper and Normark, 1983; Savoye and Piper, 

1990). 

The deposition of sediment waves on levees (Normark and others, 1980) requires flow thicknesses substantially greater than channel depth, in order that 

channel processes do not interfere with the uniformity 

and continuity of the sediment waves. 

DEPOSITION 

Flow Processes Implied from Turbidite Bedforms 

Bedforms in turbidite systems provide evidence for 

the importance of prolonged turbulent fluid flow in the 

deposition of turbidite beds. They also have the potential 

for providing quantitative information on the characteristics of the flow, as has been done in studies of fluvial 

flow. Large-scale scours within turbidite deposits are, 

perhaps, the prime example of features that went unobserved because of their scale; in outcrop studies, erosional features of this size are generally misidentified as 

channels (Mutti and Normark, 1987). All of the scour 

examples referenced occur in, or immediately downslope 

from, areas of the turbidite deposits where the fan or 

channel gradients indicate that flows could be supercritical using layer-averaged flow models. In addition, all occur in areas within or downslope from regions where 

rapid flow expansion is implied, associated with an increased turbulence within the flow. 

The imaging of many deep-sea fans by sidescan 

sonar systems in the last decade has shown that coarse 

fan-valley and lobe sediments have a variety of largescale depositional bedforms. These include grayel waves, 

whose wavelength may be a measure of bed shear stress 

(velocity), and regular, large-scale sediment waves 

Turbidity Cunent Processes 25 
developed in predominantly fine-grained sediments 

(principally on levees) and for which the significance of 

size variation is poorly understood. 

Implications for Facies Distribution in Turbidite 

Systems 

The variability in source materials, initiating processes, and flow characteristics of turbidity currents leads 

to corresponding variability in deposits (fig. 6C). The architectural element approach, originally developed for 

fluvial systems (Miall, 1985), has more recently been applied to turbidite systems (Mutti and Normark, 1987). 

The channel element is a site of both erosion by fast 

ignitive flows, in part through large scours, and rapid 

deposition from smaller flows that have lost their upper 

parts by flow stripping. Ultimate preservation depends 

on base-level fluctuations and fan aggradation. On 

levees, flow expansion of smaller overbank flows leads 

either to erosion or to irregular deposition; thicker, muddy flows lack significant flow expansion across the levee 

and deposit uniform silty muds, in some cases associated 

with large-scale mud waves. 

Smaller muddy and mixed flows undergo flow expansion at the end of a channel-levee system, depositing 

on a small lobe that may aggrade steadily and be prograded over by the channel-levee system. Larger sandy 

flows tend to erode proximal lobe deposits, and thick 

muddy flows generally undergo little modification in 

passing through the channel-lobe transition zone. 

The deposition of sediment on distal parts of turbidite systems is very dependent on upstream flow behavior of turbidity currents: the majority of turbidity 

currents in a system never reach the distal part of a basin 

(Piper and Normark, 1983). It is only the very large 

flows that control the accumulation of distal fan sediment. Vertical flow expansion resulting from gradient 

changes probably provides the major control on deposition (Piper and Stow, 1991). 

Allocyclic Changes In the Basin 

The role of eustatic sea level change is to alter the 

types of flow-initiation process and hence the types of 

turbidity currents flowing into a basin. Falling sea level, 

if accompanied by fluvial incision, may promote hyperpycnal flow of turbidity currents into basins; if canyon 

incision occurs, the resulting increase in local slopes 

may trigger slumps and promote ignitive flow processes 

ahd conduit flushing, leading to mixed or muddy flows 

of variable size. Eustatic low stands provide the time of 

maximum direct input of fluvial sediment, which in 

sandy fans leads to flushing out of the channel systems. 

26 The Petroleum System-Status of Research and Methods, 1992 

During rising sea level, seismic triggering of flows predominates, resulting in some thick muddy flows (fig. 

6C). 

Sea-level changes may also influence coastal morphology, so that the locus of sediment supply is 

changed. For example, the northern Ascension Canyon 

source for Monterey fan intercepts littoral-drift sediment 

at low stands of sea level, but during high stands, this 

canyon is bypassed and sediment is intercepted primarily 

by· the more deeply incised Monterey Canyon itself 

(Hess and Normark, 1976). On Navy Fan at times of 

lowered sea level, the Tijuana River supplied sediment 

directly to the canyon head that leads to the fan whereas 

during high stands, this sediment was trapped on the 

shelf and the only turbidity currents to reach the fan result from seismically triggered failure of older prodeltaic 

sediments (Piper and Normark, 1983). 

Tectonic Settings of Turbidite Sequences 

The concept of variation in source material and 

type of turbidity current in determining basin architecture permits a broad classification of turbidite sequences. 

1. Young passive-margin systems with a narrow 

shelf and steep gradients have a dominance of sand supply. Rapid progradation of delta-mouth sediment leading 

to oversteepening, possible hyperpycnal flow of sandy 

river bedload, and seismic triggering of prodeltaic slides 

are likely on such margins, yielding mostly small turbidity currents of rather sandy composition (fig. 6A). 

2. Mature passive-margin systems have low sandto-mud ratios in their sediment supply, and fan morphology suggests that hyperpycnal flow from rivers is 

important in fan evolution, yielding uniform low-velocity flows that steadily build narrow levees that prograde 

over uniformly aggrading lobes. Sea-level changes predominate in triggering sediment failure; the resulting 

very large flows lead to basin aggradation. 

3. Active-margin systems resemble those of young 

passive margins but may have a more mature fluvial 

supply and a greater proportion of mud. Steep slopes and 

large magnitude earthquakes lead to seismic triggering 

predominating, at least during eustatic high stands: resulting turbidity currents tend to be large and of variable 

composition. 

4. Carbonate-margin systems receive sediment both 

from catastrophic failure of reef fronts and from stormdriven flows across the shelf break. The latter may lead 

to more stable channel systems that may be occupied by 

mixed clastic-carbonate turbidity currents at low stands 

of sea level. Shelf-break failure results in aprons of debris-flow deposits with thin distal fine-grained turbidites 

lacking well-developed channels. 
SUMMARY 

Predictive stratigraphic analysis of deep marine basins requires an understanding of the processes through 

which individual turbidity currents interact with and 

modify basin physiography. Overall basin shape and size 

are principally a consequence of regional tectonism, but 

many of the morphologic features that control turbidite 

depositional patterns result from the erosional and depositional effects of previous turbidity currents. The steady 

flow of turbidity currents over tens of hours interacts in 

a predictable way with basin physiography. The character of these flows depends on the nature of the sediment, 

the initiating process(es), and the physiographic setting 

in the source area. These parameters can be stochastically predicted from a knowledge of source-area tectonics, climate change, and eustasy. 

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Diego, University of California, Ph.D. thesis, 165 p. 

Normark, W.R., Gutmacher, C.E., Chase, T.E., and Wilde, P., 

1985, Monterey Fan, Pacific Ocean, in Bouma, A.H., 

Normark, W.R., and Barnes, N.E., eds., Submarine fans 

and related turbidite systems: New York, Springer-Verlag, 

p. 79-86. 

Nonnark, W.R., Piper, D.J.W., and Hess, G.R., 1979, Distributary channels, sand lobes and mesotopography of .Navy 

Submarine Fan, California Borderland: Sedimentology, v. 

24, p. 749-774. 

Normark, W.R., and Spiess, F.N., 1976, Erosion on the Line 

Islands archipelagic apron: Effects of small scale topographic relief: Geological Society of America Bulletin, v. 

87, p. 286-296. 

Piper, D.J.W., and Kontopoulos, N., 1990, Large gravel waves 

of turbidite origin: Ancient analogues of features seen by 

sidescan sonar: Abstracts, Geological Association of 

Canada-Mineralogical Association of Canada Joint Annual 

Meeting, Vancouver, B. C., p. A105. 

Prior, D.B., Bornhold, B.D., and Johns, M.W., 1986, Active 

sand transport along a fjord-bottom channel, Bute Inlet, 

British Columbia: Geology, v. 14, p. 581-584. 

Shor, A.N., Piper, D.J.W., Hughes Clarke, J., and Mayer, L.A., 

1990, Giant flute-like scour and other erosional features 

formed by the 1929 Grand Banks turbidity current: Sedimentology, v. 37, p. 631-645. 

Deposition: Implications for Facies Distribution 

in Turbidite Systems 

Damuth, J.E., and Kumar, M., 1975, Amazon Cone: Morphology, sediments, age, and growth pattern: Geological Society 

of America Bulletin, v. 86, p. 863-878. 

Hess, G.R., and Normark, W.R., 1976, Holocene sedimentation 

history of the major fan valleys of Monterey Fan: Marine 

Geology, v. 22, p. 233-251. 

Kayen, R.E., and Lee, H.J., 1989, Effect of sea-level fall induced gas-hydrate decomposition on stability of continental slope, Beaufort Sea: Eos (American Geophysical 

Union, Transactions), v. 70, p. 1152. 

Manley, R.L., and Flood, R.D., 1988, Cyclic sediment deposition within Amazon deep-sea fan: American Association 

of Petroleum Geologists Bulletin, v. 72, p. 912-925. 

Miall, A.D., 1985, Architectural-element analysis: A new 

method of facies analysis applied to fluvial deposits: Earth 

Science Reviews, v. 22, p. 261-308. 

Mutti, E., and Normark, W.R., 1987, Comparing examples of 

modem and ancient turbidite systems: Problems and concepts, in Leggett, J.K., and Zuffa, G.G., eds., Marine clastic sedimentology: Concepts and case studies: London, 

Graham and Trotman, p. 1-38. 

Mutti, E., and Ricci Lucchi, F., 1972, Le torbiditi dell' 

Appenino settentrionale: introduzione all' analisi di facies: 

Memorie della Societa Geologica Italiana, v. 11, p. 161-

199. 

Normark, W.R., Piper, D.J.W., and Hess, G.R., 1979, Distributary channels, sand lobes and mesotopography of Navy 

Submarine Fan, California Borderland: Sedimentology, v. 

24, p. 749-774. 

Piper, D.J.W., and Nonnark, W.R., 1983, Turbidite depositional patterns and flow characteristics, Navy Submarine 

Fan, California Borderland: Sedimentology, v. 30, p. 681-

694. 

Piper, D.J.W., and Stow, D.A.V., 1991, Fine-grained turbidites, 

in Einsele, G., Seilacher, A., and Rucken, A., eds., Sequence and event stratigraphy: New York, SpringerVerlag, p. 360-376. 

Savoye, B., and Piper, D.J.W., 1990, What controls on depositional 

architecture of the Var Canyon-Fan system? Evidence from 

side-scan sonar images and high resolution and very high resolution seismic profiles: Abstracts, 13th International Sedimentological Congress, Nottingham, p. 478. 

Shanmugam, G., and Moiola, R.J., 1988, Submarine fans: 

Characteristics, models, classification and reservoir potential: Earth Science Reviews, v. 24, p. 383-428. 

Shepard, F.P., and Dill, R.F., 1966, Submarine canyons and 

other sea valleys: Chicago, Rand McNally, 381 p. 

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the transport and sorting of fme-grained sediment by turbidity currents: Sedimentology, v. 27, p. 31-46. 

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as an analogue for small hydrocarbon-bearing fan deltas, 

in Whateley, M. K.G., and Pickering, K.T., eds., Deltas: 

Sites and traps for fossil fuels: Geological Society of London Special Publication 41, p. 21-43. 

Weimer, P., 1989, Sequence stratigraphy of the Mississippi Fan 

(Plio-Pleistocene), Gulf of Mexico: Geo-Marine Letters, v. 

9, p. 185-272. 

Turbidity Current Processes 31 
Porosity 

By James W. Schmoker1 

The discussion of porosity presented in this forum 

two years ago by Schmoker and Gautier (1989a) noted 

that, although porosity has often been inversely correlated to burial depth, plots of porosity versus thermal maturity offer an alternative to the prediction of porosity 

change during burial that may better integrate effects of 

burial history upon porosity modification. The present 

discussion reviews the growing body of literature dealing with relations between porosity and time-temperature 

exposure (thermal maturity). 

The idea that porosity change in the subsurface is 

controlled in part by time-temperature exposure has been 

present in the literature for some time. Maxwell (1964), 

working with a large body of data, found temperature to 

be an important variable affecting porosity loss in 

quartzarenites during burial. Maxwell also noted that 

time played a role in porosity modification because, all 

else being equal, older rocks in his data set tended to 

have lower porosities. The earliest reference I have 

found that specifically links porosity evolution in the 

subsurface to time-temperature exposure is an abstract 

by van de Kamp (1976). Lyons (1978, 1979) and Cassan 

and others ( 1981) expanded upon the idea that the porosity of sedimentary rocks can be advantageously considered in terms of thermal maturity. McCulloh and others 

(1978) reviewed processes of burial diagenesis affecting 

the porosity of clastic rocks and emphasized the importance of temperature upon most of these processes. They 

envisioned a certain order and predictability behind the 

complex details of porosity modification during burial, 

likening the typical net loss of porosity to the progressive alteration of kerogen with increasing thermal maturity. Siever (1983) regarded integrated time-temperature 

history as the relevant parameter for subsurface reaction 

kinetics. 

Schmoker (1984) presented data indicating that porosity loss in carbonate rocks can be empirically represented as a function of integrated time-temperature 

history. Dixon and Kirkland (1985) investigated sand1 U.S. Geological Survey, Denver, Colo. 

32 The Petroleum System-Status of Research and Methods, 1992 

stones in relatively young basins of southern California 

and found that the porosity of these rocks can be correlated with the thermal gradient. In laboratory experiments, Porter and James (1986) found that temperature 

had a significant influence on quartz solubility and thus 

on pressure solution. 

Within the last few years, studies describing porosity change in terms of integrated time-temperature history have become more common in the literature. 

Ehrenberg (1987) and Harris (1988) reported that porosities of Jurassic sandstones of the North Sea depend 

strongly upon thermal maturity. Bloch and others (1990) 

observed that porosity of the Mississippian Kekiktuk 

Formation of the North Slope of Alaska can be better 

predicted as a function of integrated burial history than 

of depth. Earlier, van de Kamp (1988) had linked the 

porosity of Ellesmerian-sequence sandstones of the 

North Slope (Carboniferous to lowermost Cretaceous) to 

thermal maturity as represented by vitrinite reflectance. 

Surdam and others (1989) and Jansa and Noguera Urrea 

(1990) discussed organic/inorganic reactions and consequent porosity change in terms of thermal maturity. 

The common thread running through the diverse 

set of references cited is that porosity change in the subsurface results from processes that can be advantageously treated as functions of time-temperature exposure. 

Porosity decrease in the subsurface was represented by Schmoker and Gautier (1988, 1989b) and Schmoker and Hester ( 1990) as a power function of 

time-temperature exposure: 

(1) 

where 0 is porosity, A and B (a negative number) are 

constants, and M is a measure of integrated time-temperature history. This equation treats porosity as evolving 

through time and responding to changes in temperature 

even if depth is unchanged. 

The practical problem exists of how best to numerically represent time-temperature exposure (M) in relations such as equation 1. The ideal index would closely 

reflect the kinetics of porosity-affecting processes, but 

such an index is unknown and is unlikely to be developed in the near future because of the great diversity of 

subsurface processes. 
30 

20 

1-- a:i 15 

u 

a: 

w 

Q. 10 

z 

-:.a 

~ Cii 6 

0 

a: 

0 

Q. 4 

3 ~ =~~:~ -50th 

-25th 

- 1Oth Percentile 

0.35 2~~~--~~--~~~~~~~~~~~~ 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 

VITRINITE REFLECTANCE, IN PERCENT 

Figure 7. Sandstone porosity versus vitrinite reflectance 

(RJ illustrating power-function relation of equation 1. Regression line is fit to median porosity (50th porosity percentile). Data represent lower Cretaceous J sandstone of 

Denver basin (from Schmoker and Hester, 1990). 

1--

z 

w 

u 

a: 

w 

Q. 

~ 10 

~ Cii 

0 

a: 

~ 90th 

75th 

50th 

25th 

1Oth Percentile 

A number of indices measuring time-temperature 

exposure have been put forward in connection with kerogen maturation. Among these, Lopatin's time-temperature 

index of thermal maturity (ITI) (described by Waples, 

1980) and vitrinite reflectance <Rc,) are probably the best 

known of the mathematical and laboratory indices, respectively. Til and R0 have been used in porosity models as convenient if somewhat imperfect measures of M. 

The use of ITI and R0 in the context of porosity 

prediction does not necessarily imply that porosity 

change is causally related to kerogen maturation. In the 

broader sense, TTl and Ra are simply general measures 

of time-temperature exposure. However, because TTl 

and Ra are commonly used to define stages of hydrocarbon generation, relations such as equation 1 can serve to 

place porosity change and petroleum generation in a mutual context. 

Plots reproduced here of sandstone porosity versus 

R0 (fig. 7) and carbonate porosity versus ITI (fig. 8) are 

of typical data sets and illustrate the correlation between 

time-temperature exposure and porosity change in the 

subsurface. The range of porosities about the regression 

lines of figures 7 and 8 is shown by box diagrams. Such 

porosity variability is common and probably is due to 

geologic heterogeneity within the rocks under consider2 L-----~--~-L~-L~-UL-----~--~-L_L-L~~------~--~-L-L~~~------~~~~ 

0.1 1.0 10 100 400 

TTl UNITS 

Figure 8. Carbonate porosity versus Lopatin's time-temperature index OTI) illustrating power-function relation of equation 

1. Regression line is fit to median porosity (50th porosity percentile). Data represent Lower Cretaceous to Eocene limestones and dolomites in 15 wells of South Florida basin (from Schmoker and Gautier, 1989b). 

Porosity 33 
ation. Research on relations between porosity variability 

and localized geologic heterogeneity, as well as on details of the particular subsurface processes responsible 

for generalized porosity-maturity trends such as are 

shown in figures 7 and 8, is likely to be active in the 

next several years. 

REFERENCES CITED 

Bloch, S., McGowen, J.H., Duncan, J.R., and Brizzolara, D.W., 

1990, Porosity prediction, prior to drilling, in sandstones 

of the Kekiktuk Formation (Mississippian), North Slope of 

Alaska: American Association of Petroleum Geologists 

Bulletin, v. 74, no. 9, p. 1371-1385. 

Cassan, J.P., Garcia Palacios, M.C., Bertrand, Fritz, and Tardy, 

Yves, 1981, Diagenesis of sandstone reservoirs as shown 

by petrographical and geochemical analysis of oil bearing 

formations in the Gabon basin: Bulletin des Centres de 

Recherches Exploration-Production Elf-Acquitaine, v. 5, 

no. 1, p. 113-135. 

Dixon, S.A., and Kirkland, D.W., 1985, Relationship of temperature to reservoir quality for feldspathic sandstones of 

southern California: Southwest Section, American Association of Petroleum Geologists 1985 Transactions, p. 82-

99. 

Ehrenberg, SN., 1987, Relationships between diagenesis and 

reservoir quality in upper Tomma Formation, 

Haltenbanken, offshore mid-Norway [abs.]: American Association of Petroleum Geologists Bulletin, v. 71, no. 5, p. 

552. 

Harris, N.B., 1988, Controls on porosity of Jurassic sandstones 

of northwest Europe [abs.]: American Association of Petroleum Geologists Bulletin, v. 72, no. 2, p. 194. 

Jansa, L.F., and Noguera Urrea, V.H., 1990, Geology and diagenetic history of overpressured sandstone reservoirs, 

Venture gas field, offshore Nova Scotia, Canada: American Association of Petroleum Geologists Bulletin, v. 74, 

no. 10, p. 1640-1658. 

Lyons, D.J., 1978, Sandstone reservoirs-Petrography, porosity-permeability relationship, and burial diagenesis: Report 

of the Technology Research Center, Japan National Oil 

Corporation, Tokyo, no. 8 (December), p. 1-69. 

--- 1979, Organic metamorphism and sandstone porosity 

prediction from acoustic data: Report of the Technology 

Research Center, Japan National Oil Corporation, Tokyo, 

no. 9 (March), p. 1-51. 

Maxwell, J.C., 1964, Influence of depth, temperature, and geologic age on porosity of quartzose sandstones: American 

Association of Petroleum Geologists Bulletin, v. 48, no. 5, 

34 The Petroleum System-Status of Research and Methods, 1992 

p. 697-709. 

McCulloh, T.H., Cashman, S.M., and Stewart, R.I., 1978, Diagenetic baselines for interpretive reconstructions of maximum burial depths and paleotemperatures in clastic sedimentary rocks, in Oltz, D.F., ed., Low temperature metamorphism of kerogen and clay minerals: Pacific Section, 

Society of Economic Paleontologists and Mineralogists, p. 

18-46. 

Porter, E.W., and James, W.C., 1986, Influence of pressure, salinity, temperature, and grain size on silica diagenesis in 

quartzose sandstones: Chemical Geology, v. 57, p. 359-

369. 

Schmoker, J.W., 1984, Empirical relation between carbonate 

porosity and thermal maturity: An approach to regional 

porosity prediction: American Association of Petroleum 

Geologists Bulletin, v. 68, no. 11, p. 1697-1703. 

Schmoker, J.W., and Gautier, D.L., 1988, Sandstone porosity 

as a function of thermal maturity: Geology, v. 16, no. 11, 

p. 1007-1010. 

--- 1989a, Porosity, in Magoon, L.B., ed., The petroleum 

system-Status of research and methods, 1990: U.S. Geological Survey Bulletin 1912, p. 25-27. 

--- 1989b, Compaction of basin sediments: Modeling 

based on time-temperature history: Journal of Geophysical 

Research, v. 94, no. B6, p. 7379-7386. 

Schmoker, J.W., and Hester, T.C., 1990, Regional trends of 

sandstone porosity versus vitrinite reflectance--A preliminary framework, in Nuccio, V.F., and Barker, C.E., eds., 

Applications of thermal maturity studies to energy exploration: Rocky Mountain Section-Society of Economic Paleontologists and Mineralogists, p. 53-60. 

Siever, Raymond, 1983, Burial history and diagenetic reaction 

kinetics: American Association of Petroleum Geologists 

Bulletin, v. 67, no. 4, p. 684-691. 

Surdam, R.C., Crossey, L.J., Hagen, E.S., and Heasler, H.P., 

1989, Organic-inorganic interactions and sandstone diagenesis: American Association of Petroleum Geologists 

Bulletin, v. 73, no. 1, p. 1-23. 

van de Kamp, P.C., 1976, Inorganic and organic metamorphism in siliciclastic rocks [abs.]: American Association 

of Petroleum Geologists Bulletin, v. 60, no. 4, p. 729. 

--- 1988, Stratigraphy and diagenetic alteration of 

Ellesmerian sequence siliciclastic rocks, North Slope, 

Alaska, in Gryc, George, ed., Geology and exploration of 

the National Petroleum Reserve in Alaska, 1974 to 1982: 

U.S. Geological Survey Professional Paper 1399, p. 833-

854. 

Waples, D.W., 1980, Time and temperature in petroleum formation: Application of Lopatin's method to petroleum exploration: American Association of Petroleum Geologists 

Bulletin, v. 64, no. 6, p. 916-926. 
Facies, Permeability, and Heterogeneity 

in Sandstone Reservoirs 

By Christopher J. Schenk1 

INTRODUCTION 

The seven principal types of siliciclastic sandstone 

reservoir hetePogeneity are related to (1) sandstone body 

geometry, (2) mudstone baffles to fluid flow, (3) facies 

and facies associations, (4) sedimentary structures, (5) 

laminae, (6) diagenesis, and (7) fracturing (Weber, 1986; 

Schenk, 1988}. The purpose of this paper is to review current research on heterogeneity related to facies architecture 

of sandstone reservoirs (third type of heterogeneity) and 

the relation of architecture to patterns of permeability. 

Architecture, defined as the patterns of facies that 

make up the internal construction of a reservoir, largely 

controls fluid flow in a reservoir because flow parameters 

such as permeability are strongly facies dependent. A 

knowledge of fluid flow patterns in a reservoir sandstone 

is required for successful field development, secondary 

·and enhanced hydrocarbon recovery operations, and determination of hydrocarbon recovery factors (Tyler and Finley, 1989; Weber and van Geuns, 1990). Permeability 

measurements by facies are becoming an integral component of architectural studies of reservoir sandstones (Chandler and others, 1989; Dreyer and others, 1990). 

The objective of analyzing sandstone architecture is 

to determine the spatial distribution and geometry of facies 

in a reservoir sandstone. Facies analysis can be done using 

outcrop or borehole log and core data, but for detailed examination of lateral facies transitions and facies geometry 

outcrops are essential, but not always available. Lateral 

profiling of outcrops documents the scales, types, complexity, and patterns of sandstone architecture that may be 

encountered or predicted in the subsurface (Miall, 1988, 

1989). 

Detailed studies of the lateral and vertical juxtaposition of sandstone facies, combined with permeability data 

by facies, provide realistic input to numerical models for 

reservoir simulation (Hearn and others, 1986; Krause and 

others, 1987; Rayenne and others, 1989; van de Graaff and 

Ealey, 1989). Facies comprising the major depositional en1 U.S. Geological Survey, Denver, Colo. 

vironments are well known (Walker, 1984a), but more 

quantitative data are needed on the geometries of sandstone 

facies and the scale over which measured permeabilities 

are valid in sandstone reservoirs. 

EOLIAN SANDSTONE RESERVOIRS 

Eolian sandstone reservoirs can be broken down into 

eolian dune (dune foreset and bottom-set), interdune, clastic sabkha, and sand sheet facies. Eolian-dune deposits are 

present in most sandstones recognized as eolian and are 

the most common petroleum-producing facies. The proportions of the other four facies vary considerably. 

Studies of permeability by facies in eolian sandstones have documented that eolian-dune foreset sandstones have the highest permeabilities whereas dune 

bottom-set, interdune, and sabkha sandstones have the 

lowest permeabilities (Andrews and Higgins, 1984; Weber, 

1987; Lindquist, 1988; Chandler and others, 1989; Krystinik, 1990). 

Permian sandstones in the upper part of the Minnelusa Formation in the Powder River Basin, Wyoming, contain eolian-dune and clastic-sabkha deposits, but 

sand-sheet and interdune deposits are absent (Fryberger 

and others, 1983). The predominance of eolian-dune sandstone in the producing horizons make these Permian sandstones a relatively simple matter to develop and produce 

(Jorgensen and James, 1988). Permeability contrast within 

this sandstone is mainly between eolian ripple and avalanche strata. 

In contrast, the Jurassic Nugget Sandstone in the 

Overthrust Belt of Wyoming and Utah contains eoliandune, interdune, and clastic-sabkha deposits (Lindquist, 

1988). The eolian-dune sandstones produce oil, but these 

sandstones are separated by nonproductive interdune and 

clastic-sabkha sandstones, making development and enhanced recovery difficult (Lindquist, 1988; White and others, 1990). Permeabilities between eolian-dune and 

interdune or sabkha sandstones can vary by several orders 

of magnitude. Prediction of the lateral distribution. and vertical arrangement of nonproductive and productive facies 

in the Nugget Sandstone, along with the distribution of 

Facies, Permeability, and Heterogeneity in Sandstone Reservoirs 35 
fractures, greatly assists in determining the proper method 

of field development and reservoir stimulation procedures 

(Krystinik and Schenk, 1989). 

Eolian-dune sandstones of the Jurassic Norphlet Formation at Hatter's Pondfield, Mobile County, Alabama, 

exhibit facies-related permeability variations (Mancini and 

others, 1990) similar to those in the Nugget Sandstone; eolian-dune sandstones have the highest permeabilities, interdune sandstones the lowest, and sand-sheet sandstones 

slightly higher than interdune sandstones. 

FLUVIAL SANDSTONE RESERVOIRS 

Facies of fluvial deposits have been defined and described in many studies (Allen, 1978, 1983; Miall, 1978, 

1988; Miall and Turner-Peterson, 1989), and the complexity of fluvial facies associations is well known. 

Walton and others (1986) divided fluvial sandstones 

of the Cherokee Group (Pennsylvanian) into five facies. 

Permeability is correlated to these facies, and the juxtaposition of facies has produced a strongly layered reservoir 

with respect to fluid flow. Cross-stratified channel sandstones have the highest permeabilities, but permeability in 

all facies was a function of compaction and clay content. 

Ebanks and Weber (1987) also demonstrated a strong correlation between facies and permeability in heavy-oil-bearing fluvial sandstones of the Cherokee Group in Missouri. 

Their study illustrates the extreme sedimentologic complexity of the fluvial reservoirs within the field, which 

would be difficult to unravel without the large number of 

wells with borehole logs and conventional core. 

Ravenne and others (1989) mapped the three-dimensional architecture of fluvial sandstones along cliff exposures in England as an analog for Jurassic fluvial 

reservoirs in the North Sea. Reservoir simulation models 

were built from lateral profiles of large outcrops, dimensions of fluvial sandstone bodies were mapped, and permeability variations by facies were measured. This study is 

an excellent example of combining architectural and permeability data to produce an analog for actual reservoir 

simulations. 

Atkinson and others ( 1990) measured permeability 

differences between several braided fluvial facies in sandstone reservoirs of the Ivishak Formation (Permian-Triassic), Prudhoe Bay field, Alaska. Here, the largest 

permeability differences were between fluvial and deltaic 

facies. In another study, Hastings (1990) found that 

fluvial-channel sandstones had higher permeabilities than 

flvvial channel margin sandstones in reservoirs of the 

Pennsylvanian Tyler Formation, North Dakota. 

In a study of Statfjord reservoirs in the North Sea, 

Henriquez and others (1990) stressed the importance of 

describing quantitatively sandstone body morphology, facies architecture, and hydraulic connectedness in develop36 The Petroleum System-Status of Research and Methods, 1992 

ing simulation models of fluvial reservoirs. They concluded that the available architectural data for fluvial deposits, 

including fluvial-channel thickness, width, length, and orientation, were a principal limitation to modeling fluvial 

reservoirs, in spite of the body of work available on fluvial 

deposits. 

DELTAIC SANDSTONE RESERVOIRS 

Deltaic sandstones are an important group of hydrocarbon reservoirs, but surprisingly few studies are available on the relationship between deltaic facies and patterns 

of permeability. 

Moslow and Tillman (1986) identified 12 facies in 

gas-productive wave-dominated deltaic sediments in the 

Cretaceous Frontier Formation along the Moxa arch, Wyoming. Permeability was strongly controlled by facies. Distributary channel facies had the best combination of 

porosity and permeability and formed the best reservoirs. 

Clay content (determined petrographically) was a critical 

factor in whether a distributary channel sandstone was a 

reservoir or not. Although facies dimensions could not be 

measured with borehole data from widely spaced wells, 

the sedimentologic model developed from the facies associations led Moslow and Tillman (1986) to conclude that 

typical well spacings in the Moxa arch area would not 

contact all of the isolated distributary channel sandstones. 

In Oklahoma, Boyer (1985) described six facies from 

fluvial-dominated deltaic sandstones in the Pennsylvanian 

part of the Springer Formation. Permeability in these deltaic 

sandstones strongly correlated to facies; proximal delta-front 

sandstones had the best combination of porosity and permeability. Other facies had higher clay and cement contents, 

resulting in poor fluid-flow properties. 

Tillman and Jordan (1987) found a relation between 

facies associations and permeability in Permian deltaic 

sandstones in the El Dorado field, Kansas. Of the six facies associations, the distributary channel and the splaybeach associations had the highest permea~ility and 

porosity. 

In a study of wave-dominated deltaic sandstones of 

the Brent Group in the North Sea, Scotchman and Johnes 

(1990) found that deltaic distributary channel sandstones 

had the highest permeabilities whereas delta-front and crevasse-splay sandstones had the lowest permeabilities. 

INTERDELTAIC SANDSTONE RESERVOIRS 

Facies of strand-plain and barrier sandstones are well 

known, consisting of sandstones from lower, middle, upper 

shoreface and foreshore environments (McCubbin, 1982; 

Snedden and Jumper, 1990). However, strand-plain sandstones can be associated with wave-dominated delta-front, 
distributary channel, delta fringe, crevasse splay, and finegrained marsh and levee deposits (Tyler and Ambrose, 

1985). The architecture of a strand-plain sandstone reservoir can be complex if constructed from these facies, but 

strand-plain sandstones in general make better reservoirs 

than deep-water or fluvial sandstones because of the general lack of mudstones or shale layers within the sandstone 

that impede fluid flow (Ambrose and Tyler, 1989). 

In a study of barrier sandstones of the Cretaceous 

Muddy Sandstone, Bell Creek field, Wyoming, Sharma 

and others (1990) found that upper and middle shoreface 

sandstones had much higher permeabilities than lower 

shoreface and overlying valley fill sandstones. Barrier 

sandstones can also be intercalated with tidal-inlet fills, 

flood- and ebb-tidal deltas, estuarine sandstones, washover-barrier flat sandstones, and back-barrier eolian sandstones, and can be nearly encased in fme-grained deposits 

(Galloway and Cheng, 1985; Fryberger and others, 1988). 

The presence of tidal-inlet deposits serves to disrupt 

the continuity of the barrier sandstones, resulting in a 

semi-compartmentalized reservoir sandstone that would 

not have been predicted using a simple barrier model for 

the reservoir (Galloway and Cheng, 1985). Studies of 

facies-related permeability are needed for these types of 

reservoirs. 

MARINE SHELF SANDSTONE RESERVOIRS 

Marine shelf sandstone facies are known in detail 

(Walker, 1984b), particularly the Cretaceous shelf sandstones of Wyoming (Tillman and Martinsen, 1984; Jackson and others, 1987). Shelf sandstones typically form 

lens-shaped bodies encased in marine mudstones, although 

facies associations and interbedding of reservoir and nonreseJVoir rock may be complex (Borer and Harris, 1991). 

Facies of the sandstones range from clean, cross-stratified 

sandstone to bioturbated muddy sandstone. Hearn and others (1986) identified five facies in the Cretaceous Shannon 

Sandstone Member of Wyoming, similar to Shannon facies 

interpreted by Tillman and Martinsen (1984, 1987). Hearn 

and others (1986) found that the reservoir sandstone could 

be divided into five flow units based on groupings of permeability data. The boundaries of the flow units generally 

matched the facies boundaries, but the match was imperfect. The flow units based on permeability, together with 

facies distributions and sandstone body thickness, were 

used to develop a layered reservoir simulation model for 

enhanced oil recovery. 

DEEP-WATER SANDSTONE RESERVOIRS 

Deep-water sandstones deposited in submarine fan 

and related environments contain many of the same facies 

as fluvial deposit:s--<;hannels, sediment gravity flows, lateral accretion deposits, fine-grained levee deposits, and 

laminated sand sheets-but the proportions of the facies 

may be quite different than in fluvial deposits (Normark, 

1990). The abundance of fme-grained layers in deep-water 

environments suggests that more mudstone layers are present within each facies and that deep-water sandstone reservoirs may be more compartmentalized by mudstones than 

fluvial sandstones (Phillips, 1987; Ambrose and Tyler, 

1989; Hall and Link, 1990; Kulpecz and van Geuns, 

1990). 

Scott and Tillman (1981) illustrated many examples 

of clay clasts and clay laminae that separate otherwise permeable beds of sandstone in the Stevens sand (Miocene), a 

subsurface unit in the San Joaquin basin, California. Clayfree medium- to coarse-grained channel sandstones form 

the best reseJVoir facies. Hall and Link (1990) also found 

that channel sandstones in Miocene turbidite reservoirs 

had higher permeabilities than sandstones of turbidite depositional lobe and channel/lobe facies. Berg and Royo 

(1990), in a study of Miocene turbidite reservoirs in the 

Yowlumne field, California, found that turbidite sandstones of the central channel facies had higher permeabilities than sandstones of channel margin and other facies. 

SUMMARY 

This review has illustrated some recent work relating 

facies to permeability in reservoirs representing several 

depositional environments. More studies are needed on the 

relation between facies, facies geometry, and permeability. 

In general, the architectural complexity of sandstone reservoirs increases as the sandstones assume channelized 

forms (that is, strand-plain and eolian sandstones are not 

as complex as fluvial sandstones, channelized submarinefan sandstones, or valley-fill complexes). 

Additionally, as the number of mudstone layers and 

lenses in the depositional system increases, the more potential reservoir sandstones are compartmentalized into 

discrete packages that may not be in fluid communication. 

Isolated reservoir pods will not be swept in a typical drilling pattern. Drilling must be more closely spaced and locations chosen carefully using a detailed sedimentologic 

model in these types of compartmentalized reservoirs to 

increase hydrocarbon recovery. 

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Facies, Permeability, and Heterogeneity in Sandstone Reservoirs 39 
Approaches to Characterizing Fluid-Flow Heterogeneity in 

Carbonate Reservoirs 

By Christopher J. Schenk1 

INTRODUCTION 

This report reviews recent research on approaches 

to characterize fluid-flow heterogeneity within carbonate 

reservoirs. Fluid-flow heterogeneity is defined as the inability of a rock matrix to allow fluid to flow evenly in 

all directions because the connections between pores is 

unevenly distributed. As a reservoir characteristic, carbonates exhibit extreme heterogeneity with respect to 

fluid flow (Jardine and others, 1977; Jardine and 

Wilshart, 1987; Kittridge and others, 1990; Wardlaw, 

1990a). When attempting to produce hydrocarbons from 

these reservoirs during any stage of recovery (primary, 

secondary, or tertiary), fluid-flow heterogeneity dictates 

production strategy and economics. 

Carbonate reservoirs consist of a diversity of particle types, sizes, and compositions that are highly susceptible to interparticle and intraparticle diagenesis, 

including dolomitization, cementation, dissolution (including vugs and karstification; Kerans, 1989), recrystallization, and fracturing. Spatial variations in depositional 

and diagenetic textures and fabrics, or the alteration of 

original porosity within carbonate reservoirs create fluidflow heterogeneity. In this respect, carbonate reservoirs 

differ from siliciclastic reservoirs, in that interparticle diagenesis dominates the evolution of porosity (Houseknecht, 1987; Jardine and Wilshart, 1987). 

HETEROGENEITY EVOLUTION 

Fluid capacity and fluid-flow potential in reservoir 

rocks are generally stated in terms of porosity and permeability, respectively. For carbonate reservoirs, detailed 

descriptions of porosity have evolved (Choquette and 

Pray, 1970; Wardlaw, 1979; Lucia, 1983), based on visual, petrographic, and scanning electron microscope examination. Carbonate porosity is complex and difficult to 

1 U.S. Geological Survey, Denver, Colo. 

40 The Petroleum System-Status of Research and Methods, 1992 

relate to permeability (Lucia, 1983; Lucia and Fogg, 

1990). Because carbonate particle type, size, and composition are related to depositional environment (Moore, 

1979), most studies of carbonate reservoir rocks begin 

with defining and describing sedimentary facies, frequently in great detail (Bebout and others, 1987; Moshier and others, 1988). Many studies have demonstrated a 

relation between facies and ranges of porosity (Keith and 

Pittman, 1983; Wiggins and Harris, 1984; Jardine and 

Wilshart, 1987; Dawson, 1988). 

However, the modification of depositional (original) porosity through diagenesis makes anything but a 

general porosity prediction difficult in carbonate reservoirs (Schmoker and Halley, 1982), and reservoir-scale 

porosity is impossible to accurately predict. Overprinting of depositional fabrics by dolomitization is common, 

and for many reservoirs dolomitization is critical for 

generating effective porosity. The uniformity of pore geometry created by dolomitization means the difference 

between reservoir and nonreservoir facies in many carbonate rock units (Wardlaw, 1979, 1990a; Bliefnick and 

Mariotti, 1988). 

Permeability is less related to facies than to porosity, because diagenetic alterations cause great spatial 

variability in p~re geometry. Thomeer (1983) showed 

that, for a given porosity, carbonates can exhibit any 

permeability because of possible combinations of porethroat size distributions resulting largely from diagenetic 

variations. This is the reason many porosity-permeability 

cross-plots exhibit a "shotgun blast" pattern. 

However, if pore-throat sizes exhibit a narrow 

range of sizes, then permeability shows a better correlation to porosity. Lucia (1983) demonstrated that permeability in a given carbonate reservoir can be correlated to 

certain types of porosity, not total porosity. Visual descriptions of porosity, especially the recognition of vugs, 

are essential in the process of attempting to correlate porosity with permeability. Bebout and others (1987) documented a relation between mean permeability and 

carbonate facies within the Permian Grayburg Formation 

in the Permian basin, but the range of permeability within each facies meant that permeability predictions based 

on mean values were impossible at a local scale. 
MEASURING HETEROGENEITY 

Scanning electron microscope analysis of pores 

and pore casts has been used to determine the size distribution of pores (Wardlaw, 1976, 1990b; Wardlaw and 

Li, 1987). In general, the lower the ratio of pore size to 

pore-throat size, the higher the porosity and permeability 

(Wardlaw, 1976, 1979) and the better the reservoir quality. Groupings of pore-throat sizes in carbonate reservoirs 

have been related to ranges of porosity and permeability 

(Lindsay, 1988), and this approach may be useful in providing a predictive capability for ranges of porosity and 

permeability for a given reservoir. These ranges may or 

may not follow facies boundaries, but may define reservoir flow units, which is the first step in defining fluid 

flow patterns and unraveling heterogeneity in reservoirs 

(Major and Holtz, 1990). 

A common approach to understanding fluid-flew 

heterogeneity in carbonate reservoirs is to measure porethroat size from mercury injection-capillary analyses 

(Keith and Pittman, 1983; Wiggins and Harris, 1984; 

Kent and others, 1988). This technique provides data 

that allow the calculation of size distributions of pore 

throats. The attractiveness of this approach is that the 

pore-throat size distribution integrates the effects of 

complex diagenetic alterations, including dolomitization, 

into a measurable quantity. Combining mercury injection-capillary pressure analyses with petrographic image 

analyses of pore geometries is a powerful method to 

quantify both the types of pores and the distribution of 

pores within a reservoir rock (Etris and others, 1988). 

Reservoir rocks with similar pore geometries may have 

similar permeabilities, and thus this technique may help 

to define flow units. 

Mercury injection-capillary pressure data will provide information on the pore geometry of the rock matrix, including the contribution of vugs to porosity, but in 

many carbonate reservoirs the flow paths and permeability depend on fractures. Fractures can be simple to extremely complex (Ijirigho, 1981), and fractures commonly 

are missed when samples are prepared for injection analyses. The contribution of fractures and brecciation to the 

permeability network of any carbonate rock must be carefully considered when defining flow units. 

INTRAWELL HETEROGENEITY STUDIES 

Intrawell studies demonstrate an approach that 

characterizes heterogeneity in carbonate reservoirs using 

pqre-throat and pore sizes to define flow units. Subsurface information available to the investigator include 

core and log data. 

Keith and Pittman (1983) used mercury injection 

curves to define sizes of pore throats in the Lower Cretaceous Rodessa Limestone, Running Duke field, East 

Texas basin. Pore-throat size and distribution were related to facies; skeletal limestone had a unimodal size distribution of pore-throat radii, whereas ooid limestone had 

a bimodal size distribution of pore-throat radii. Because 

micropores hold bound water in one part of the bimodal 

pore network, the ooid facies produced water-free gas 

compared to production from the unimodal-sized skeletal 

facies. They developed borehole log-based cross-plot 

techniques for identifying these types of pore systems 

throughout the field where core data were not available, 

and for allowing this type of heterogeneity to be traced 

throughout the field. 

Wiggins and Harris (1984), in a study of the Lower Cretaceous Pettit Limestone in the East Texas basin, 

recognized four major pore types and their associated 

pore-throat sizes. They related specific diagenetic alterations to each class of pore-throat size. Pore-throat size 

was the parameter that limited fluid access between 

pores and thus was a critical measurement for determining possible patterns of fluid flow. In addition, the examination of pore-throat sizes provided a perspective 

from which the importance of specific diagenetic effects 

on fluid flow in the reservoir were assessed. Wiggins 

and Harris (1984) found that reservoir quality depended 

on the proportions of blocky calcite spar cement to microspar cement because these cements controlled the sizes of pore throats. 

In a study of grainstone reservoirs of the Upper Jurassic Smackover Formation, Mississippi and Alabama, 

Bliefnick and Mariotti (1988) documented a correlation 

between increasingly dolomitized rock and improved 

reservoir quality. Pore-throat sizes determined from mercury injection became larger with increasing degree of 

dolomitization, as did the size of dolomite crystals. They 

concluded that fluid-flow heterogeneity in the Smackover Formation was a product of extreme lateral facies 

variability and irregular dolomitization. 

Kent and others (1988) described pore systems 

from 10 carbonate reservoirs in Mississippian rocks of 

the northern Williston basin. They documented the degree of size uniformity of pore-throat radii in each reservoir, and they related families of pore-throat sizes to 

individual cr combinations of porosity types. They found 

that dolomi1ization produced a rather uniform pore-throat 

size distrib lltion, and so dolomites made better reservoirs. They also found that carbonate reservoirs with 

similar porosities can exhibit vastly different pore-throat 

size distributions, again demonstrating that porosity correlations do not necessarily lead to flow-unit definition. 

Lindsay (1988) related ranges of pore-throat radii 

to ranges of porosity and permeability in Mississippian 

carbonate r1~servoirs of the Mission Canyon Formation, 

North Dakota. He developed a model of four pore types 

and two pore-throat sizes for the Mission Canyon, and 

Approaches to Characterizing Fluid-Flow Heterogeneity in Carbonate Reservoirs 41 
concluded that understanding heterogeneity meant knowing (1) all sizes of pore throats and pores, (2) how pores 

are connected, and (3) how fluids with different viscosities move through the pore system. Combinations of the 

four types of pores and pore throats create complex pore 

systems. 

Inden and others (1988) found that porosity alone 

did not differentiate reservoir from nonreservoir carbonate rock in the upper part of the Interlake Formation 

(Upper Ordovician and Silurian) in the Nesson anticline 

area, Williston basin. They found that the variability in 

morphology of pore connections, pore sizes, and pore 

distributions caused differences in permeability that had 

to be carefully examined, along with water saturations, 

to determine the spatial distribution of flow units. 

INTERWELL HETEROGENEITY STUDIES 

The intrawell studies demonstrate an approach that 

characterizes heterogeneity in carbonate reservoirs using 

pore-throat and pore sizes to define flow units. The principal difficulty is to make the step from core or log data 

to interwell correlations of flow units defined from studies of pore systems in several wells. 

Jardine and Wilshart (1987) studied fluid-flow heterogeneity of several Devonian carbonate reservoirs in 

the western Canada basin for the purpose of observing 

the progress of enhanced recovery techniques. Their reservoir analysis of reef carbonate of Judy field is particularly instructive. They grouped several carbonate facies 

into three classes of porosity and permeability to define 

three major flow units in reefal carbonate reservoirs. 

Borehole logs from 4 7 wells were used to construct 

cross sections depicting the three-dimensional configuration of the flow units in the field. The interlayering and 

juxtapositioning of the three flow units with relatively 

impermeable rock resulted in an extremely heterogeneous reservoir with respect to fluid flow. This study is an 

excellent example of an attempt to determine the interwell correlation of flow units and the degree of threedimensional fluid-flow heterogeneity in a carbonate 

reservoir. 

Lucia and Fogg (1990) used geostatistical techniques to determine the scale over which core permeabilities were valid in the Permian Grayburg Formation, 

Dune field, west Texas. Using a combination of core 

analysis, rock fabric, and log data, statistical techniques 

were used to determine interwell correlation of permeable carbonate units. Statistical techniques indicated a 

possible correlation of permeability values over vertical 

length scales of 4 to 5 feet and 12 to 13 feet, and a 

correlation of permeability values over horizontal length 

scales of 2,000 and 1,000 feet (parallel and perpendicular to the main grainstone trend, respectively). 

42 The Petroleum System-Status of Research and Methods, 1992 

Another approach to understanding carbonate fluidflow heterogeneity is to directly measure the three-dimensional distribution of permeability and determine the 

statistical correlation lengths of permeability in a grid 

placed on an outcrop. This approach focuses on determining the statistical length scales over which measured permeabilities are valid in the reservoir being investigated. 

Kittridge and others (1990), in a study of dolomite 

reservoir facies of the Lower Permian San Andres Formation, Permian basin, west Texas, compared vertical 

and horizontal permeabilities from outcrop and subsurface samples. They reported over four orders of magnitude variation in permeability, in bed-to-bed 

measurements and also within beds. The scale of spatial 

correlation of permeability varied with the spacing of 

measurements. They reported a correlation length of 3 to 

5 feet for permeabilities measured 0.5 feet apart and a 

correlation length of 0.25 feet for measurements taken 1 

to 0.5 inch apart. Given typical oil-field well spacings, 

these length scales suggest that interwell correlation of 

permeable units will be difficult. Although few of these 

types of studies have been completed, the value of using 

outcrops of carbonates to understand three-dimensional 

heterogeneity has been demonstrated (Waters and others, 

1989). 

SUMMARY 

Permeability variations in carbonates are controlled 

by variations in pore geometry, thus measuring the pore 

geometry directly is an attractive approach to begin to 

understand fluid-flow heterogeneity. Flow units defined 

from data on the geometry and distribution of pore systems, along with facies, porosity, permeability, and fracture data, may possibly be correlated well to well using 

stratigraphic or statistical techniques. 

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Approaches to Characterizing Fluid-Row Heterogeneity in Carbonate Reservoirs 43 
Mineral Transformations in Tar Sand and Heavy Oil Reservoirs 

Induced by Thermal Recovery Methods 

By Christopher j. Schenk1 

INTRODUCTION 

This paper reviews research on mineral transformations that occur when heavy oil and tar are produced 

from sand reservoirs using thermal recovery methods. 

Tar sands, more appropriately termed natural asphalts 

(Meyer and deWitt, 1990), exhibit viscosities greater 

than 10,000 centipoises (cP). Heavy and extra heavy oils 

have viscosities less than 10,000 cP, and also generally 

have API gravities of 10 to 20 degrees and less than 10 

degrees API, respectively (Cornelius, 1987). Viscosities 

of this order dictate that some method must be used that 

will reduce the viscosity so that the hydrocarbons can be 

mobilized and recovered. The most common method 

used is heating (thermal recovery), but chemical recovery methods are also beginning to be used. In situ thermal recovery technology is of two major types; steam 

injection and combustion. In either process, heat is transferred to the hydrocarbons to decrease viscosity and provide mobility. 

Steam Injection 

Steam injection is accomplished by one of two 

main processes: cyclic steaming or continuous injection. 

In cyclic steaming (also called steam soak or huff-andpuff), steam is injected into a pay zone, then the well is 

shut-in for a period of time, commonly 40 to 90 days, 

after which the hydrocarbons are recovered from the 

same well until recovery becomes uneconomic. The 

process is then repeated. In continuous steaming, steam 

is continuously injected into one well, and other wells in 

the pattern serve as recovery wells. 

Conditions of steaming vary, but steam is generally 

introduced at temperatures ranging from 300°C to 

350°C, and at pressures as high as 14 megapascals 

(MPa). The ratio of water to rock is high during the 

steaming process, and is relatively lower during combus1 U.S. Geological Survey, Denver, Colo. 

44 The Petroleum System-Status of Research and Methods, 1992 

tion. Recoveries of heavy oil or natural asphalt from the 

steam process rarely exceed 20 to 25 percent of the original oil-in-place (OOIP) (Carrigy, 1983), although recoveries of 60 percent have been noted from small zones in 

core (Hutcheon, 1984). 

In Situ Combustion 

In situ combustion is achieved by pumping air or 

oxygen down a well into a pay zone, and igniting the 

hydrocarbons by electrical or other means (Moore and 

others, 1989). The burning hydrocarbon front creates a 

zone of mobile oil that is then produced. Conditions of 

combustion are complex (Hutcheon, 1984); temperatures 

can reach 800°C in the immediate zone of combustion, 

but decrease rapidly away from the zone. Pressures are 

generally less than 20 MPa. The water-to-rock ratio is 

extremely low compared to steam injection, in part because combustion vaporizes formation water. Exceptions 

to this are combustion projects combined with waterflooding ("wet combustion"). Recoveries from pilot 

combustion tests vary, but recoveries as high as 67 percent of the OOIP (for natural asphalt deposits) have been 

reported (Carrigy, 1983). 

Mineral Transformations Studies 

Maximum temperatures associated with thermal recovery processes (300-350°C for steaming, 800°C for 

combustion) enhance chemical reactions between the 

reservoir rock, formation fluids, and injected fluids 

(Hutcheon, 1984). Important factors to consider in terms 

of diagenesis produced by thermal recovery ("artificial 

diagenesis" of Hutcheon, 1984) include changes in detrital framework mineralogy, authigenic mineralogy, distribution of authigenic minerals in a pore system, 

temperature distribution, length of exposure to maximum 

temperature, pore-fluid chemistry, injected fluid chemistry, the water-to-rock ratio, and the timing of diagenesis 

relative to permeability loss and hydrocarbon mobiliza-
tion. Only a few of these factors are known in detail for 

thermal recovery processes. Studies of artificial diagenesis are based on either ( 1) closely spaced cores taken before and after pilot tests of thermal recovery processes or 

(2) experimental steaming or burning of samples taken 

from field cores. 

STEAM INJECTION-FIELD STUDIES 

A detailed examination of cores from the Cretaceous Clearwater Formation in the Cold Lake area, Alberta, before and after 2 years of continuous 

steamflooding (maximum of 260°C for 1 year) was conducted by the Sedimentology Research 'Group (1981). 

The pre-steam pay sandstones were dominantly feldspathic litharenites, with chert, volcanic rock fragments, 

and shale composing the lithic fraction. Less than 10 

percent matrix was present. Pre-steam diagenesis was 

complex, and included quartz and feldspar overgrowths, 

minor zeolites, calcite and dolomite cements, kaolinite, 

illite, chlorite, and minor smectite. 

Post-steam analysis illustrated that most of the illite, 

chlorite, and kaolinite was removed, whereas coarse smectite coatings (4 to 20 J.Lm) and analcime formed in the pore 

system. Dissolution of the surfaces of detrital quartz, feldspar, and lithic grains was observed. Chert recrystallized to 

a coarser texture. The main chemical change appeared to 

be kaolinite plus quartz plus feldspar went to coarse smectite. Smectite growth and possibly some compaction associated with oil removal from these shallow reservoirs 

resulted in a 25 percent loss of porosity. The formation of 

pore-bridging smectite and the migration of clays and zeolites served to block pore throats, reducing visual permeability relative to pre-steam samples. 

Lefebvre and Hutcheon (1986) examined pre- and 

post-steamflood cores from a heavy oil reservoir in the 

Lower Cretaceous Sparky Formation, Lloydminster area, 

Saskatchewan. Pre-flood mineralogic analysis showed 

the sandstones to be dominantly quartz arenites, with 

less than 5 percent feldspar and lithic grains. Diagenetic 

minerals included quartz and feldspar overgrowths, kaolinite, siderite, and ankerite. 

Post-steam analysis indicated that illite and chlorite 

formed at the expense of kaolinite, detrital quartz, and 

feldspar. Chlorite may have formed from a reaction between siderite and kaolinite. Illite occurred as a replacement of potassium feldspar, and also as thin linings in 

pores and on kaolinite. However, these post-steam mineralogic changes-are minor when compared to the changes observed in lithic sands of the Clearwater Formation. · 

A similar comparison was made of pre- and poststeamflood mineralogic changes between quartz arenites 

of the Clearwater Formation from the Cold Lake area 

and lithic arenites of the Sparky Formation from the 

Lloydminster area (Hutcheon and others, 1989b). The 

extent of artificial diagenesis was less in quartz arenites 

than lithic arenites. As in previous studies, Hutcheon and 

others (1989b) found that smectite and analcime formed 

in the lithic arenites, whereas only minor diagenesis occurred in the quartz arenites. 

An important aspect of Hutcheon and others 

(1989b) is the documentation that the chemistry of produced waters reflects chemical reactions occurring in the 

reservoir during steaming, and that modeling of the water chemistry can be used qualitatively to predict chemical reactions. This use of water chemistry is an active 

area of research (Gunter and others, 1989; Russell and 

Bird, 1989; Hallam and others, 1990). 

C02 was documented as an important by-product 

of carbonate mineral dissolution during steaming in both 

formations. Cathles and others (1990) also documented 

the release of C02 from carbonate minerals during 

steaming. Hutcheon and others (1990) suggest that reactions involving natural asphalt, in addition to carbonate 

dissolution, may produce C02 during steam stimulation. 

STEAM INJECTION-EXPERIMENTAL STUDIES 

To understand the effect of steaming on reservoir 

mineralogy, many studies have experimentally steamed 

core in laboratory autoclaves. In an excellent early study 

of experimental steaming, Day and others (1967) 

steamed core recovered from 10 different reservoirs 

within the United States and documented all mineralogic 

changes. The most critical mineralogic change related to 

steaming that occurred in nearly all reservoirs was the 

formation of smectite at the expense of dolomite and kaolinite. Smectite that forms in a reservoir pore system 

can adversely affect permeability. 

Boon and Hitchon (1983a, b) experimented with 

tar sands from the Lower Cretaceous McMurray Formation in the Athabasca deposit, Alberta, Canada. They 

concluded that a major reaction in these deposits was illite plus kaolinite plus quartz converted to smectite. 

They also documented the dissolution of quartz and the 

formation of colloids. Colloids such as these produced 

experimentally might be missed in field studies of artificial diagenesis because of sampling problems. 

Boon and others (1983) steamed cores of lithic 

sandstones of the Clearwater Formation from the Cold 

Lake area of Alberta, which was the same reservoir rock 

studied in field cores by the Sedimentology Research 

Group (1981) and Hutcheon and others (1989a,b). Boon 

and others (1983) observed the dissolution of quartz, dolomite, and kaolinite and the formation of smectite, chlorite, and calcite. Smectite and chlorite grew as pore 

linings and bridges that were interpreted to cause the reduction in permeabilities from pre-steam values. ReacMineral Transformations in Tar Sand and Heavy Oil Reservoirs Induced by Thermal Recovery Methods 45 
tions were controlled by pH, temperature, and salinity. 

All experiments demonstrated the translocation of 

"fines" (probably clays) through the pore system, clogging pore throats and "significantly reducing" permeability. They suggested that all mineral reactions may not 

have a negative effect on hydrocarbon recovery; some 

reactions may result in a reduction of permeability in 

steam thief zones, decreasing steam losses and improving recovery. 

Bird and others (1986) experimented with what appear to be quartz arenites from the Lower Cretaceous McMurray Formation in the Athabasca area, Alberta, to 

document the process of quartz dissolution. Upon cooling, 

solutions charged with excess silica from quartz dissolution led to the formation of quartz cements, amorphous silica, and minerals including zeolites and smectite. High 

silica concentrations can also produce complex silica colloids during steaming (Potter and Dibble, 1983). Colloids 

can be disastrous to thermal recovery operations, as they 

can plug pumps, piping, and other equipment, but colloids 

may also be beneficial in plugging highly permeable steam 

thief zones. Colloids have been reported from nearly all 

experimental thermal studies (Boon and Hitchon, 1983a,b; 

Bird and others, 1986), and they should be expected to 

occur in field situations. 

Kirk and others ( 1987) steamed lithic sandstones 

of the Clearwater Formation from the Cold Lake area, 

Alberta. Pre-steam mineralogy included minor smectite, 

illite, kaolinite, zeolites, feldspar overgrowths, and pyrite. Post-steam analysis indicated that quartz, dolomite, 

and kaolinite dissolved, C02 was produced, smectite 

content doubled, and calcite cement formed. Post-steam 

fluids were supersaturated with respect to silica. Smectite was deposited as thick rims around framework 

grains, and was the cause of permeability reduction from 

50 to 98 percent of pre-steam permeability values. They 

concluded that (1) solution pH and temperature were the 

most important variables controlling diagenesis, and (2) 

solution kinetics were more rapid than expected. 

Gunter and Bird (1988) steamed chert-bearing sublithic arenites from the Cretaceous Grand Rapids Formation from the Cold Lake area, Alberta. Pre-steam 

authigenic minerals included kaolinite, calcite, minor illite, and smectite. Post-steam analysis showed that calcite was totally removed, much of the kaolinite and illite 

was removed, and some dissolution of quartz occurred. 

The smectite content increased by 35 percent. The main 

reaction appeared to be calcite plus quartz plus kaolinite 

converted to Ca-smectite plus C02• They noted that solution kinetics, especially the dissolution of calcite and the 

release of C02, were extremely rapid. 

This and other studies of artificial diagenesis have 

noted the production of C02 during steam injection. C02 

appeared to be a product mainly of carbonate mineral 

dissolution. C02 may actually improve recovery during 

46 The Petroleum System-Status of Research and Methods, 1992 

thermal stimulation by (1) further reducing hydrocarbon 

viscosity and (2) by causing swelling of the oil (by included gas) that results in higher oil saturations and increased recovery of the OOIP. 

Monin and Audibert ( 1988) heated heavy crude oil 

to 350°C in the presence of reservoir minerals to observe 

changes in the character of the oil. An important and 

detrimental by-product of heating was the rapid formation and deposition of insoluble organics (pyrobitumen). 

These experiments simulated steam conditions, and suggested that pyrobitumen could form rapidly as the oil 

was heated, possibly plugging permeability in a reservoir 

undergoing steam stimulation. 

Bizon and others (1984) experimentally steamed 

natural-asphalt-bearing carbonate rock from the Devonian Grosmont Formation of Alberta. Pre-steam mineralogy showed the samples to be 98 percent dolomite, the 

remainder being quartz, feldspar, diopside, kaolinite, 

smectite, and pyrite. Post-steam analysis showed dissolution of dolomite, quartz, diopside, feldspars, and possibly kaolinite. Calcite formed, as did amorphous 

Mg-Ca-Al silicates. 

In an extension of this study, Kubacki and others 

(1984) experimentally steamed carbonate rock of the 

Grosmont Formation with an initial mineralogy of 98 

percent dolomite, 1 percent quartz, and 1 percent illite 

and kaolinite. They reported the formation of calcite, 

amorphous Mg- and Mg-Al silicates, hydromagnesite, 

margarite, huntite, and amorphous Fe compounds. They 

also reported having trouble measuring permeability, but 

concluded that overall permeability had decreased during 

the experiments largely because of translocation of fines 

in the pore system. 

Hutcheon and Oldershaw (1985) experimentally 

flooded carbonate rock of the Grosmont Formation with 

solutions at 180°C. Pre-steam mineralogy of the carbonate rock was mainly dolomite, but included calcite, 

quartz, feldspar, illite, and kaolinite. Post-flood analyses 

indicated that smectite formed at the expense of dolomite and kaolinite. The formation of amorphous silicates as in the previous studies of carbonates was not 

reported. Authigenic smectite constituted less than 1 percent of the total rock mass, but smectite reduced permeability as much as 25 percent of pre-steam values, 

whereas porosity increased slightly. Although carbonate 

rocks do not appear to be as affected by steaming as siliclastic rocks, an increase in smectite content of about 1 

percent was enough to significantly impede the permeability in the complex pore system of the carbonate rock. 

COMBUSTION-FIELD STUDIES 

Many field pilot tests of in situ combustion have 

been made in the last 30 years (Moore and others, 1989), 
but few studies have documented the details of mineralogic changes induced by combustion. Lefebvre and 

Hutcheon (1986) examined quartz arenites from the 

Lower Cretaceous Sparky Formation in the Lloydminster 

heavy oil deposit, Saskatchewan, Canada, before and after combustion. Pre-fireflood mineralogy included 

quartz, feldspar, kaolinite, siderite, and ankerite. Postfireflood analysis indicated combustion temperatures had 

reached somewhat higher than 540°C. Illite, chlorite, and 

minor potassium feldspar and hematite formed in the 

burned zone, and kaolinite was removed. In general, 

fireflooding did not have much of an effect on the mineralogy of the sandstones, in part due to the lack of an 

aqueous phase compared to steamflooding. No smectite 

formed, and only a minor reduction in porosity was reported. However, Hutcheon (1984) noted that reservoir 

heterogeneity had a strong effect on the efficiency of 

fireflood sweep. 

COMBUSTION-EXPERIMENTAL STUDIES 

Perry and Gillott (1979) formed smectite in a simulated wet combustion process using mixtures of quartz, 

kaolinite, and dolomite. In the actual combustion zone, 

where much less water was present than in the surrounding zones, they documented the decomposition of kaolinite at 500°C to 550°C and the decomposition of smectite 

at about 650°C. They used lithic sandstones from the 

Cretaceous Clearwater Formation of the Cold Lake area, 

Alberta. Perry and Gillott (1982) expanded their frretube 

experiments to include other minerals, and determined 

the temperatures at which common minerals such as dolomite, kaolinite, illite, chlorite, and smectite decomposed in a combustion zone. Although this study has 

been criticized because the sandstones were disaggregrated and repacked before ignition (Hutcheon, 1984), it 

is one of the few laboratory studies that reports the effects of combustion on mineralogy. Hutcheon (1984) 

concluded that porosity may actually increase during 

combustion, and that overall much less permeability-reducing diagenesis occurs with dry combustion than with 

steam injection. 

Moore and others (1989) summarized the state of 

the art of combustion technology, and cited over 220 

firetube experiments using rock from 46 different reservoirs. However, these experiments were run primarily to 

investigate the operational aspects of fireflooding, such 

as temperature distribution, timing of bum, and the mobilization of hydrocarbons. Details of mineralogic changes are not provided. This is true of reservoir studies 

within the United States, where early firetube experiments were directed toward understanding fireflood technology rather than mineralogic changes (Burger and 

Sahuquet, 1973). 

SUMMARY 

More artificial diagenesis occurs during steam injection compared to combustion, probably because more 

water is present during steaming. However, more studies 

of the effects of combustion on mineralogy are needed 

and, in particular, studies on mineralogic changes that 

occur during wet combustion. In general, the more complex the pre-thermal mineralogy, the more artificial diagenesis can be expected in the reservoir rock. This 

review shows that few generalizations can be made in 

terms of specific mineralogic changes during thermal 

stimulation, except that smectite is commonly formed at 

the expense of dolomite, kaolinite, and illite. Carbonate 

reservoirs containing viscous hydrocarbons appear to be 

less damaged by thermal stimulation than siliciclastic 

reservoirs, but even minute growth of smectite significantly reduces permeability in carbonate pore systems. 

More information is needed on the timing of artificial diagenesis, its effect on porosity and permeability, 

and the timing of hydrocarbon mobilization. Although 

many studies have documented permeability reduction 

related to the growth of smectite or colloids, the unknown factor is the timing of the growth of these phases 

relative to oil mobilization. If they form after oil is mobilized and recovered, then most artificial diagenesis is 

not detrimental. If they form before or during oil mobilization, then any permeability reduction greatly affects 

recovery. The relatively low recoveries associated with 

steaming compared to combustion is a signal that diagenesis does have an effect on recovery. 

In a study of cores from a conventional reservoir 

that bears on this problem, Sayegh and others (1990) experimentally flooded sandstones with COrbearing water, 

and found that permeability decreased rapidly as fines 

were mobilized with high flow rates (similar to steaming), and partially plugged pore throats. However, as the 

experiment proceeded, permeability increased to about 

7 5 percent of initial values as carbonate minerals were 

dissolved. This study illustrated the dynamics of the 

chemical and flow system, and this type of experimentation needs to be done using cores containing heavy oil or 

natural asphalt to determine timing of oil mobilization 

relative to permeability changes. 

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Kubacki, W., Boon, J., Bird, G., and Wiwchar, B., 1984, Effect 

of mineral transformation on porosity and permeability of 

dolomite rock during in situ recovery of bitumen: A preliminary study: Bulletin of Canadian Petroleum Geology, v. 

32, p. 281-288. 

Lefebvre, R., and Hutcheon, 1., 1986, Mineral reactions in 

quartzose rocks during thermal recovery of heavy oil, 

Lloydminster, Saskatchewan, Canada: Applied Geochemistry, v. 1, p. 395-405. 

Meyer, R.F., and deWitt, W., 1990, Definition and world resources of natural bitumens: U.S. Geological Survey Bulletin 

1944, 14 p. 

Monin, J.C., and Audibert, A., 1988, Thermal cracking of 

heavy-oiVmineral matrix systems: Society of Petroleum Engineers, Reservoir Engineering, November, 1988, p. 1243-

1250. 

Moore, R.G., Bennion, D.W., and Ursenbach, M.G., 1989, A review of in situ combustion mechanisms, in Meyer, R.F., and 

Wiggins, E.J., eds., The Fourth UNIT AR!UNDP International 

Conference on Heavy Crude and Tar Sands, Volume 4, In 

Situ Recovery: New York, UNIT AR/UNDP Information Center for Heavy Crude and Tar Sands, p. 775-784. 

Perry, C., and Gillott, J.E., 1979, The formation of montmorillonite during the use of wet forward combustion in the 

Alberta oil sand deposits: Bulletin of Canadian Petroleum 

Geology, v. 27, p. 314-325. 

--- 1982, Mineralogical transformations as indicators of 

combustion zone temperatures during in situ combustion: 

Bulletin of Canadian Petroleum Geology, v. 30, p. 34-42. 

Potter, J.M., and Dibble, W.E., 1983, Formation damage due to 

colloid plugging: Society of Petroleum Engineers Reprint 

SPE 11801, p. 257-262. 

Russell, B., and Bird, G.W., 1989, Interpreting reservoir performance using produced water chemistry, in Meyer, R.F., and 

Wiggins, E.J., eds., The Fourth UNIT AR!UNDP International 

Conference on Heavy Crude and Tar Sands, Volume 4, In 

Situ Recovery: New York, UNIT AR/UNDP Information Center for Heavy Crude and Tar Sands, p. 673-683. 

Sayegh, S.G., Krause, F.F., Girard, M., and DeBree, C., 1990, 

Rock/fluid interactions of carbonated brines in a sandstone 

reservoir: Pembina Cardium, Alberta, Canada: Society of 

Petroleum Engineers, Formation Evaluation, p. 399-405. 

Sedimentology Research Group, 1981, The effects of in situ 

steam injection on Cold Lake oil sands: Bulletin of Canadian Petroleum Geology, v. 29, p. 447-478. 
Biomarkers as Thermal Maturity Indicators 

By Paul G. Lillis1 

Biological markers (biomarkers) are organic compounds in sedimentary rocks and petroleum that can be 

linked to biological precursor molecules derived from 

living organisms (Eglinton and Calvin, 1967; Speers and 

Whitehead, 1969). Biomarkers in rock extracts, pyrolysates, and petroleum are measured by gas chromatography-mass spectrometry, usually expressed as the relative 

abundance or ratios of specific biomarker compounds. 

Biomarkers are essentially molecular fossils and have 

been used as indicators of paleoecology, depositional environment, and paleogeography (Huang and Meinschein, 

1979; Didyk and others, 1978; Brassell and others, 1983; 

Brassell and others, 1987; see Clayton, 1989, for a bric!f 

literature review). 

Biomarkers rarely retain their original chemical 

structure because of diagenetic alterations in the water 

column and shallow sediments and the effects of temperature with deeper burial. Consequently, it is often difficult to correlate a biomarker found in the geosphere wilh 

a specific source organism. However, in some cases the 

biomarker reaction pathway from the biological fonn 

through several diagenetic steps to the most stable fonn 

has been studied in great detail (such as steroids; see de 

Leeuw and Baas, 1986, for details). 

Early studies revealed systematic changes in biomarker composition with increasing depth of burial 

(Philippi, 1965; Ensminger and others, 1974). Certain biomarker ratios were compared with the thermal maturation of organic matter, that is, changes in coal ranllc, 

vitrinite reflectance, or the generation of petroleum 

(Didyk and others, 1975; Mackenzie and others, 1980; 

Mackenzie and Maxwell, 1981; Radke and others, 1980), 

and consequently have been utilized as thermal maturity 

indicators for petroleum and source rocks in sedimentary 

basins. 

Biomarker ratios that systematically change wilh 

increasing burial (temperature and time) are a function 

of one or more geochemical reactions. In some cases a 

biomarker ratio has been attributed to a specific reaction 

(Mackenzie and McKenzie, 1983) (table 5) while most 

ratios are probably influenced by several reactions oe1 U.S. Geological Survey,_ Denver, Colo. 

curring simultaneously or in series. The rate of the specific or overall reaction is assumed to follow frrst-order 

kinetics, so the Arrhenius equation may be applied 

(Mackenzie and McKenzie, 1983; Alexander and others, 

1986). The Arrhenius equation can be expressed as: 

k' = A exp ( -EIRD 

where: 

k' = rate constant, 

A = frequency factor ( 1/s), 

E = activation energy (kJ/mol), 

R = gas constant, and 

T =temperature (K). 

(1) 

The extent of a reaction as expressed by a biomarker ratio (table 5) is proportional to exp ( -k' t) where t is 

elapsed time and k' is a function of temperature (equation 1). When the kinetic constants (A and E) are determined for the reaction, then the biomarker ratio may be 

used to help define the thermal history of sedimentary 

rocks (Beaumont and others, 1985; Hong and others, 

1986; Mackenzie and others, 1988; Chiaramonte and 

others, 1988). The thermal history may in tum be applied to quantitative models for petroleum generation 

and migration (Tissot and others, 1987; Suzuki, 1990). 

Several approaches have been utilized to determine 

the kinetic constants (A and E) using natural samples or 

laboratory experiments. Data from natural samples 

(downhole trend) may be used assuming a known sediment burial and thermal history, no significant facies 

variation downhole, and no sample contamination from 

migrated hydrocarbons. In determining the kinetic constants from a downhole trend, Mackenzie and McKenzie 

(1983) used an isothermal time-step model whereas Alexander and others ( 1986) used a linear heating rate 

function. On the other hand, Lewan and others (1986) 

and Rullkl>tter and Marzi (1988) derived the kinetic constants from a series of isothermal hydrous pyrolysis experiments which have the advantages of no facies 

variation (using replicate samples) and precisely known 

time and temperature conditions. However, hydrous pyrolysis conditions (high temperature, short time, closed 

system) differ from natural conditions, and the derived 

kinetics may not be applicable. Marzi and others (1990) 

Biomarkers as Thermal Maturity Indicators 49 
Table 5. Selected maturity ratios based on an apparent biomarker reaction (from Mackenzie, 1984) 

Apparent reaction Ratio End value 

Isomerization of C17a.,21~(H) homohopanes at C-22 chiral center --------------- 22S 

22S+22R 

20S 

20S+20R 

0.6 

Isomerization of 5a.(H)14a.(H)17a.(H) C29sterane at C-20 chiral center --------- 0.54 

Triaromatic Aromatization of C-ring monoaromatic sterane to triaromatic steroid------------- -------

Tri- + Monoaromatic 1.0 

C-C bond cleavage of C28 triaromatic steroid to C20 triaromatic steroicfl ------- C2o triaromatic 

(C2o+C2s) tri- 1.0 

·M~ckenzie (1984) stated that apparent catbon cleavage reaction may actually be a reflection of higher stability of the C20 

triarornatic steroid. 

suggested that more precise kinetic parameters may be 

derived from combining natural data with experimental 

data. 

Specific biomarker reactions are far from the ideal 

thermal maturity indicator (see Curiale and others, 1989 

for discussion) because they generally have a narrow dynamic range of maturity, and many reach the endpoint or 

equilibrium point before the main stage of petroleum 

generation (Mackenzie, 1984). Also, biomarker concentrations decrease significantly at higher maturity (eventually reaching the instrument detection limits), which 

increases the chance of contamination or alteration effects. Because biomarker reactions are typically measured as the relative abundance or ratio of the reactant 

and the product, the actual concentrations are not known. 

Therefore an apparent transformation may actually be 

one compound being destroyed at a faster rate than the 

other (Requejo, 1989) or be the combined effects of release reactions from a "bound" state and destruction reactions (Abbott and others, 1990). Competing reactions 

may be the cause of observed reversals in some biomarker maturity trends (Lewan and others, 1986; Strachan 

and others, 1989; Peters and others, 1990). 

Biomarker ratios need not be representative of a 

specific reaction to be useful as thermal maturity indicators. For example, Alexander and others (1986) defined 

some aromatic maturity indicators by determining the kinetics of the overall pseudo-reactions. Biomarker ratios 

that change systematically with burial may be used on a 

relative maturity basis or may be empirically calibrated 

with vitrinite reflectance (Radke and Welte, 1983) or a 

maturity index (van Grass, 1990). However, empirical 

calibrations are influenced by variations in stratigraphy, 

thermal history, and biomarker reaction kinetics; and the 

maturity parameter should be applied with caution to 

other areas. Changes in vitrinite reflectance are con50 The Petroleum Syste~Status of Research and Methods, 1992 

trolled by a complex series of reactions with the resulting large dynamic range in maturity (Burnham and 

Sweeney, 1989). Separate calibrations for an array of 

heating rates would be required to correlate the behavior 

of vitrinite maturation with a biomarker maturity ratio. 

Some biomarker ratios are sensitive not only to 

maturity but to composition of organic matter (Seifert 

and Moldowan, 1978; ten Haven and others, 1986), to 

pH or redox potential in the depositional environment 

(Moldowan and others, 1986), or to rock matrix effects 

(Lu and others, 1989; Strachan and others, 1989). Although some source and matrix effects are minor, these 

ratios should be used with caution if the effects cannot 

be taken into account. 

Despite all the above complications, biomarkers 

are a useful tool for determining the thermal maturity of 

oils and source rocks, and research continues to refine 

the technique. One promising area might be to use a distribution of activation energies to model a biomarker 

maturity parameter that describes a diversity of reactions 

(Burnham, 1989) analogous to some kinetic models applied to petroleum generation. For a more extensive discussion on the application of biomarkers as thermal 

maturity indicators, refer to Curiale and others (1989) 

and Mackenzie (1984). 

REFERENCES CITED 

Abbott, G.D., Wang, G.Y., Eglinton, T.l., Home, A.K. and 

Petch, G.S., 1990, The kinetics of sterane biological marker release and degradation processes during the hydrous 

pyrolysis of vitrinite kerogen: Geochimica et 

Cosmochimica Acta, v. 54, p. 2451-2461. 

Alexander, R., Strachan, M.G., Kagi, R.I., and van Bronswijk, 

W., 1986, Heating rate effects on aromatic maturity indi-
cators: Organic Geochemistry, v. 10, p. 997-1003. 

Beamnont, C., Boutilier, R., Mackenzie, A. S., and Rullkotter, 

J., 1985, Isomerization and aromatization of hydrocarbons 

and the paleothermometry and burial history of Alber1:a 

foreland basin: American Association of Petroleum Geologists Bulletin, v. 69, no. 4, p. 546-566. 

Brassell, S.C., Eglinton, G. and Howell, V.I., 1987, 

Paleoenvironmental assessment of marine organic-rich 

sediments using molecular organic geochemistry, in 

Brooks, J., and Fleet, A.J., eds., Marine petroleum sourc:e 

rocks: Geological Society Special Publication No. 26, 

Boston, Blackwell Scientific Publications, p. 79-98. 

Brassell, S.C., Eglinton, G., and Maxwell, R., 1983, The geochemistry of terpenoids and steroids: Biochemistry Society Transactions, v. 11, p. 575-86. 

Burnham, A.K., 1989, On the validity of the Pristane Formation Index: Geochimica et Cosmochimica Acta, v. 53, 

p.1693-1697. 

Burnham, A.K., and Sweeney, J.J., 1989, A chemical kinetic 

model of vitrinite maturation and reflectance: Gcochimica 

et Cosmochimica Acta, v. 53, p. 2649-2657. 

Chiaramonte, M.A., Tamburini, A., Salvator, T., and Bersani, 

A., 1988, Geochemical modelling in rapidly subsiding basins: Organic Geochemistry v. 13, p. 181-186. 

Clayton, J.L., 1989, Biological marker chemistry as indicator 

of depositional environment of source rocks and crude 

oils, in Magoon, L.B., ed., The petroleum system-Status 

of research and methods, 1990: U.S. Geological Survey 

Bulletin 1912, p.46-48. 

Curiale, J.A., Larter, S.R., Sweeney, R.E., and Bromley, B.W., 

1989, Molecular thermal maturity indicators in oil and gas 

source rocks, in Naeser, N.D. and McCulloh, T.H., eds., 

Thermal history of sedimentary basins-Methods and case 

histories: New York, Springer-Verlag, p. 53-72. 

Didyk, B.M., Alturki, Y.I.A., Pillinger, C.T., and Eglinton, G., 

1975, Petroporphyrins as indicators of geothermal maturaLtion: Nature, v. 256, p. 563-565. 

Didyk, B.M., Simoneit, B.R.T., Brassell, S.C., and Eglinton, 

G., 1978, Organic geochemical indicators of 

palaeoenvironmental conditions of sedimentation: N atur€:, 

v. 272, p. 216-221. 

Eglinton, G., and Calvin, M., 1967, Chemical fossils: Scientific 

American, v. 216, no. 1, p. 32-43. 

Ensminger, A., Van Dorsselaer, A., Spyckerelle, C., Albrechit, 

P., and Ourisson, G., 1974, Pentacyclic triterpenes of the 

hopane type as ubiquitous geochemical markers: Origirr 

and significance, in Tissot, B., and Bienner, F., eds., Advances in organic geochemistry 1973: Paris, Editions 

Technip, p. 245-260. 

van Graas, G.W., 1990, Biomarker maturity parameters for 

high maturities: Calibration of the working range up to thj~ 

oiVcondensate threshold: Organic Geochemistry, v. 16, 

p.1 025-1032. 

ten Haven, H.L., de Leeuw, J.W., Peakman, T.M., and Maxwell, J.R., 1986, Anomalies in steroid and hopanoid maturity indices: Geochimica et Cosmochimica Acta, v. 50, p. 

853-855. 

Hong Z-H., Li H-X., Rullkotter, J., and Mackenzie, A.S., 1986, 

Geochemical application of sterane and triterpane biological marker compounds in the Linyi Basin: Organic Geochemistry, v.10, p.433-439. 

Huang, W.Y., and Meinschein, W.G., 1979, Sterols as ecological indicators: Geochimica et Cosmochimica Acta, v. 43, 

p. 739-745. 

de Leeuw, J.W., and Baas, M., 1986, Early-stage diagenesis of 

steroids, in Johns, R.B., ed., Biological markers in the 

sedimentary record: Amsterdam, Elsevier, p. 101-123. 

Lewan, M.D., Bjorflty, M., and Dolcater, D.L., 1986, Effects of 

thermal maturation on steroid hydrocarbons as determined 

by hydrous pyrolysis of Phosphoria Retort shale: 

Geochimica et Cosmochimica Acta, v. 50, p. 1977-1987. 

Lu, Shan-Tan, Ruth, Edward, and Kaplan, I.R., 1989, Pyrolysis 

of kerogens in the absence and presence of montmorillonite--I. The generation, degradation and isomerization of 

steranes and triterpanes at 200 and 300°C: Organic Geochemistry,v. 14,no. 5,p.491-499. 

Mackenzie, A.S., 1984, Applications of biological markers in 

petroleum geochemistry, in Brooks, J., and Welte, D., 

eds., Advances in petroleum geochemistry: New York, 

Academic Press, v. 1, p. 115-214. 

Mackenzie, A.S., Leythaeuser, D., Altebamner, F-J., Disko, U., 

and Rullkotter, J., 1988, Molecular measurements of maturity for Lias delta shales in N.W. Germany: Geochimica 

et Cosmochimica Acta, v. 52, p. 1145-1154. 

Mackenzie, A.S., and Maxwell, J.R., 1981, Assessment of thermal maturation in sedimentary rocks by molecular measurements, in Brooks, J., ed., Organic maturation studies 

and fossil fuel exploration: London, Academic Press, p. 

239-254. 

Mackenzie, A. S., and McKenzie, D., 1983, Isomerization and 

aromatization of hydrocarbons in sedimentary basins 

formed by extension: Geological Magazine, v. 120, no. 5, 

p. 417-528. 

Mackenzie, A.S., Patience, R.L., Maxwell, J.R., 

Vandenbroucke, M., and Durand, B., 1980, Molecular parameters of maturation in the Toarcian shales, Paris Basin, 

France--1. Changes in the configurations of acyclic isoprenoid alkanes, steranes and triterpanes: Geochimica et 

Cosmochimica Acta, v. 64, p. 1709-1721. 

Marzi, R., Rullkotter, J. and Perriman, W.S., 1990, Application 

of the change of sterane isomer ratios to the reconstruction 

of geothermal histories: Implications of the results of hydrous pyrolysis experiments: Organic Geochemistry v. 16, 

p. 91-102. 

Moldowan, J.M., Sundararaman, P., and Schoell, M., 1986, 

Sensitivity of biomarker properties to depositional environment and/or source input in the Lower Toarcian of 

SW-Germany: Advances in Organic Geochemistry 1985, 

v. 10, p. 915-926. 

Peters, K.E., Moldowan, J.M., and Sundararaman, P., 1990, Effects of hydrous pyrolysis on biomarker thermal maturity 

parameters: Monterey phosphatic and siliceous members: 

Organic Geochemistry, v. 15, no. 3, p. 249-265. 

Philippi, G.T., 1965, On the depth, time and mechanism of petroleum generation: Geochimica et Cosmochimica Acta, v. 

29, p. 1021-1049. 

Radke, M., Schaffer, R.G., and Leythauser, D., 1980, Composition of the soluble organic matter in coals and its relation 

to rank and liptinite fluorescence: Geochimica et 

Cosmochimica Acta, v. 44, p. 1787-1799. 

Biomarkers as Thermal Maturity Indicators 51 
Radke, M., and Welte, D.H. 1983, The methylphenanthrene index: Maturity parameter based on aromatic hydrocarbons, 

in Bjor~y and others, eds., Advances of organic geochemistry 1981: Chichester, Wiley, p. 504-511. 

Requejo, A.G., 1989, Applications of quantitative biomarker 

analysis in petroleum geochemistry, in Biomarkers in petroleum-Memorial symposium for Wolfgang K. Seifert: 

American Chemical Society preprint, v. 34, p. 154-158. 

Rullkotter, J., and Marzi, R., 1988, Natural and artificial maturation of biological markers in a Toarcian shale from 

northern Germany: Organic Geochemistry, v. 13, p. 639-

645. 

Seifert, W.K., and Moldowan, J.M., 1978, Applications of 

steranes, terpanes and monoaromatics to the maturation, 

migration and source of crude oils: Geochimica et 

Cosmochimica Acta, v. 42, p. 77-95. 

52 The Petroleum Syste.._Status of Research and Methods, 1992 

Speers, G.C., and Whitehead, E.V., 1969, Crude petroleum, in 

Eglington, E., and Murphy, M.T.J., eds., Organic geochemistry-Methods and results:· New York, SpringerVerlag, p. 639-675. 

Strachan, M.G., Alexander, R., Subroto, E.A., and Kagi, R.I., 

1989, Constraints upon the use of 24-ethylcholestane diastereomer ratios as indicators of the maturity of petroleum: Organic Geochemistry, v. 14, no. 4, p. 423-432. 

Suzuki, N., 1990, Application of sterane epimerization to 

evaluation of Yoshii gas and condensate reservoir, Niigata 

basin, Japan: American Association of Petroleum Geologists Bulletin, v. 74, p. 1571-1589. 

Tissot, B.P., Pelet, R., and Ungerer, P., 1987, Thermal history 

of sedimentary basins, maturation indices, and kinetics of 

oil and gas generation: American Association of Petroleum Geologists Bulletin, v. 71, no. ~2, p. 1445-1466. 
Fission-Track Analysis in Sedirnentary Basins---1992 

By Nancy D. Naeser1 

INTRODUCfiON 

Fission tracks in apatite and zircon have been used 

in a wide range of studies in sedimentary basin analysis 

(reviewed in N.D. Naeser, 1989a; N.D. Naeser and others, 1989b). The annealing of fission tracks and the resulting effect on fission-track age and track lengths, 

particularly in apatite, have been used to reconstruct th~e 

thermal history of basins from the deposition and buri~l 

of sediments through subsequent cooling related to uplift 

and erosion. Annealing is also used to constrain localized temperature anomalies, such as those related to intrusions and to the passage of high-temperature fluids 

through a basin. Fission-track analysis of detrital zircons 

helps set limits on maximum paleotemperatures in basins 

and determine the provenance of sediments (C.W. Naeser, 1979b; Gleadow and others, 1983, 1986a, 1986b; 

N.D. Naeser and others, 1987b, 1989b; Green and others, 1989a; Hurford and Carter, 1991). Fission-track 

analysis is useful in sedimentary basin studies because it 

provides both temperature and time information over a 

temperature range that coincides with hydrocarbon generation (Gleadow and others, 1983; N.D. Naeser and others, 1989b) and burial diagenetic processes (for example, 

clay diagenesis and conodont color alteration) and with 

paleothermal anomalies associated with some mineral 

deposits (C.W. Naeser and others, 1980; Cunningham 

and Barton, 1984; C.W. Naeser and Cunningham, 1984; 

Beaty and others, 1988). 

Apatite fission-track analysis has been used to clar·· 

ify the thermal history of more than 40 sedimentary basins worldwide, including North America (Briggs and 

others, 1979, 1981; Dokka, 1982; Lakatos and Miller, 

1983; Crowley and others, 1985, 1986; Johnsson, 1985, 

1986; Giegengack and others, 1986, 1990; Miller and 

others, 1986, 1990; N.D. Naeser, 1986, 1989b; Zimmer·· 

mann, 1986; Duddy and others, 1987; N.D. Naeser and 

others, 1987a, 1989a, 1989b, 1990a, 1990b; Crowley and 

Kuhlman, 1988; Dumitru, 1988, 1989; O'Sullivan, 1988:; 

Geving and others, 1989, 1990, 1991; O'Sullivan and 

1 U.S. Geological Swvey, Denver, Colo. 

others, 1989, 1990; Arne and others, 1990a, 1990b; 

Kelley and Blackwell, 1990; Kohn and others, 1990b; 

Kveton, 1990; Roden and others, 1990; Crowley, 1991; 

Kelley and others, 1991; McMillen and O'Sullivan, in 

press; among others), Australia (Duddy and Gleadow, 

1982, 1985; Gleadow and others, 1983; Gleadow and 

Duddy, 1984; Marshallsea, 1986; Duddy and others, 

1987; Arne and others, 1989, 1990b; Green and others, 

1989a; Gleadow, 1990), New Zealand (Green and White, 

1985; Seward, 1989; Kamp and Green, 1990), Europe 

(Green, 1986, 1989a, 1989b; Qvale and others, 1990), 

and elsewhere (Duddy and others, 1984; Corrigan and 

Crowley, 1989; Feinstein and others, 1989; Hansen, 

1990; Hill, 1990; Kohn and others, 1990a). These studies 

have produced extensive information on fission tracks 

and their response to the thermal history of sedimentary 

rocks and in many areas have provided information on 

thermal history that would be difficult to obtain otherwise. At the same time, these studies have highlighted 

several questions that remain to be resolved before the 

full potential of apatite fission-track analysis in basin 

studies can be realized. 

ANNEALING KINETICS 

Although temperature is the dominant controlling 

factor in annealing, time cannot be ignored in interpreting thermal history. The temperature range for annealing 

of any given mineral depends on the duration of heating-the shorter the heating, the higher the temperature 

required for annealing. More research has been devoted 

to determining the annealing kinetics of apatite than of 

any other mineral, both by laboratory heating experiments (for example, C.W. Naeser and Faul, 1969; Mark 

and others, 1973; Zimmermann and Gaines, 1978; Crowley, 1985; Green and others, 1985, 1986, 1989b; Crowley and Cameron, 1987; Laslett and others, 1987; Duddy 

and others, 1988; Green, 1988; Crowley and others, 

1990, 1991; Hughes and others, 1990) and by empirical 

observations of annealing behavior in drill holes (C.W. 

Naeser, 1979a, 1981; Gleadow and Duddy, 1981). However, uncertainties still remain. At least nine laboratories 

are currently involved in research to more accurately deFission-Track Analysis in Sedimentary Basins--1992 53 
fine the kinetics of apatite annealing and thus improve 

the practical application of apatite annealing models. 

APATITE COMPOSITION 

Laboratory studies and observations from drill 

holes have established that Cl-apatite anneals at temperatures up to about 30°C higher than other common apatite 

varieties (F-, Sr-F-, and OR-apatite), affecting the variation in both age and track lengths with progressive annealing (Green and others, 1985, 1989a; Crowley and 

Cameron, 1987; Crowley and others, 1990; Hughes and 

others, 1990). Fortunately, apatite suites are commonly 

so dominated by F-apatite with insignificant amounts of 

chlorine (for example, Berry and Mason, 1959; Deer and 

others, 1962; N.D. Naeser and others, 1987a) that most 

samples can be reasonably interpreted using F-apatite 

annealing data. Composition may pose a problem, however, for interpreting thermal history in basins where the 

detrital apatites have a wide and variable range in Clcontent. Apatite composition is normally determined by 

electron microprobe. An ongoing challenge is to develop 

an altemati ve, routine method for determining composition (particularly Cl-content) in individual apatite grains 

that will eliminate the need for electron microprobe analysis (Siddall and Mendelssohn, 1990; C.W. Naeser, oral 

commun., 1991). 

INHERITED AGE AND THERMAL HISTORY OF 

DETRITAL APATITE 

It is obvious that detrital minerals entering a depositional basin carry with them previous! y formed fission 

tracks that reflect the thermal history of the sediment 

source. Furthermore, detrital apatites in sedimentary 

rocks are typically derived from parent rocks of widely 

varying age and thermal history. Thus, the observed variations in apatite age and track-length distribution with 

depth in any given sedimentary basin will reflect the 

age(s) and thermal history(s) of the parent rocks, as well 

as the thermal history of the depositional basin and the 

compositional variability of apatite. These factors, combined with the variation between sedimentary basins in 

annealing caused by differences in heating histories, 

must be considered when interpreting apatite fissiontrack data from sedimentary rocks. Models that assume 

that variation in age and track lengths is only related to 

the thermal history of the sedimentary basin, or that all 

apatites came into the depositional basin with a simple 

(volcanic) track-length distribution, can produce significant errors in interpreted thermal history, particularly in 

sedimentary rocks that have not been exposed to temperatures sufficient to totally anneal apatite. 

54 The Petroleum System-Status of Research and Methods, 1992 

RELATION BETWEEN TRACK LENGTH AND 

TRACK DENSITY 

The relation between the reduction in mean track 

length and fission-track age (track density) with progressive annealing is unclear. Some workers have determined a 1: 1 correlation between reduced density and 

reduced track length in apatite during the early (lowtemperature) stages of annealing (Green, 1988), but 

some research suggests otherwise (C.W. Naeser and others, 1989). Accurate determination of this relation is critical to the practice of some laboratories of "correcting" 

apatite fission-track ages based on the extent of tracklength reduction (for example, Kamp and Green, 1990). 

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history of the Arkoma basin and Ouachita Mountains from 

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Arne, D.C., Green, P.F., Duddy, I.R., Gleadow, A.J.W., Lambert, I.B., and Lovering, J.F., 1989, Regional thermal history of the Lennard Shelf, Canning basin from apatite fission track analysis: Implications for the formation of PbZn ore deposits: Australian Journal of Earth Sciences, v. 

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Berry, L.G., and Mason, B., 1959, Mineralogy: San Francisco, 

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--1991, Thermal history of Michigan basin and southern 

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and epeirogenic history of the Williston basin: Evidence~ 

from fission-track analysis of apatite: Geology, v. 13, p. 

680-685. 

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and Sr-apatite--1. Systematics and preliminary interpreta·· 

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---1981, The fading of fission tracks in the geologic environment-Data from deep drill holes [abs.]: Nuclenr 

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Fission-Track Analysis in Sedimentary Basins-1992 57 
Vitrinite and Solid Bitumen Reflectance: 

Some Correlations and Applications 

By Mark J. Pawlewicz and j. David King1 

The rudiments of coal petrography/petrology were 

established in the late 1800's when microscopy was first 

used to prove that most coal formed from the remains of 

terrestrial plants (Stach and others, 1982). From this beginning, coal petrography/petrology advanced through 

the observation of thin sections of coal, primarily for paleobotanical considerations, to the study of polished coal 

blocks with oil immersion techniques at about 1925. Improvements in optics and the discovery that vitrinite reflectance increases with increasing coal rank were 

instrumental in achieving great advances in the knowledge of coal. Equipment improvements were marked by 

progressions in the application for technological purposes, such as the determination of the coking quality of 

coal, as well as for academic purposes. The history of 

the application of reflectance analysis to exploration for 

oil and gas dates from the work of M. Teichmuller 

(1958) with her reflectance measurements of finegrained coaly inclusions in sedimentary rocks. 

Determination of vitrinite reflectance (Rm) has advantages and disadvantages in assessing thermal maturity 

with respect to generation of oil and gas. One advantage 

is the relative mechanical ease of analysis using prepared 

slides and pellets of coal and organic material (OM) concentrated from sedimentary rocks. Stach and others 

(1982) and Bustin and others (1983) presented excellent 

summaries on the aspects of coal petrology /petrography. 

Davis (1978) discussed the analytical methods for coal 

reflectance determination. All three references are recommended as they provide good crossover information 

for the observation and measurement of dispersed organic material. 

Vitrinite reflectance is used as a quick index to 

evaluate the level of thermal maturation of sedimentary 

rocks (Sikander and Pittion, 1978). Reflectance is correlative to a specific rank of coal, while Rm of dispersed 

organic matter (OM) is considered in terms of thermal 

maturity, or relation to the hydrocarbon (HC) generation 

1 U.S. Geological Survey, Denver, Colo. 

58 The Petroleum System-Status of Research and Methods, 1992 

window. Generally only the "window" of peak generation is used; 0.6 to 1.2 percent Rm for oil, and 1.2 to 2.0 

percent Rm for wet gas; greater than 2.0 percent for dry 

gas. Dow's (1977) correlation chart places the HC generation range between at 0.5 and 3.2 percent. Of course, 

this is not always the case. Reflectance values below this 

threshold would most likely be the result of the type of 

organic material (Waples, 1985), or some process, yet 

unexplained, operating on the OM (Graham and Williams, 1985; Price and others, 1986). Higher values can 

be partially explained by the high bireflectance of vitrinite, where a paucity of OM in rocks of high thermal 

maturity usually results in a wide histogram and a somewhat indeterminate mean value. More succinctly, Waples 

(1985) states, "Effective generation of HC requires that 

the generated products be expelled from the source-rock 

matrix and migrated to a trap. Timing and efficiency of 

expulsion depend on a number of factors, including rock 

physics and organic-geochemical considerations." 

Samples processed for their organic material can 

commonly have several distinct populations of vitrinite. 

For this reason the selection of vitrinite for reflectance 

measurement is possibly the most error-prone and inconsistent factor in thermal maturity determinations; problems and criteria related to this selection are discussed 

by Dembicki (1984), Barker and Pawlewicz (1986), Toxopeus (1983), and Powell and others (1982). Walker 

(1982) and Walker and others (1983) found anomalously 

low reflectance values, 0.2 to 0.3 percent Rm, in an offshore California HC producing sequence. Price and 

Barker (1985) provided much insight into these unexpected low Rm values. Local variations in OM type (see 

Tissot and Welte, 1984, for discussion of kerogen types 

and relation to HC generation), chemistry of the OM, 

and other factors determine the values for the "oil window" and affect the probability of any generation having 

taken place. 

A disadvantage of vitrinite reflectance is the lack 

of precision in predicting thermal maturity at the low 

end of the reflectance scale, between 0.2 and 0.45 percent Rm. Stach and others (1982) illustrated this in chart 

form as it applies to coal at the lignite and subbitumi-
nous levels. Low rank coals are sensitive to the physical 

environment, such that an increase in the moisture content alone can cause variations in reflectance of 0.1-0. tS 

percent Rm. This is an important consideration because~, 

due to ease of preparation, coal is the preferred material 

when working with borehole profiles. This problem is 

mitigated because the real interest lies at a higher reflectance level. Concentrated OM may or may not be as sensitive to changes in moisture content, but a certain 

awareness of this problem should be part of any maturity 

determination done on low rank material. 

An advantage of the technique is the direct correlation of reflectance to maximum temperature (Barker and 

Pawlewicz, 1986). Rm analysis of samples from borehole 

profiles is used to establish reflectance gradients. The 

gradients are then used to recognize the upper. and lowe.r 

thermal maturity boundaries of the oil/gas window. 

Knowing the upper and lower boundaries of the oil window could be used to determine the volume of the 

source rocks, useful for determining HC resources. 

Burial history reconstruction is widely used to illustrate the geologic history of various stratigraphic 

units. Related to this reconstruction is the use of thermal 

maturation profiles to estimate the amount of erosion, 

both at the top and within a sequence. This exercise is 

predicated on the belief that the reflectance value for vitrinite at the Earth's surface before burial is 0.2 percent 

By extrapolating a regression line through a plot of 

depth versus vitrinite reflectance to the 0.2 percent R1111 

intercept, the amount eroded is the difference between 

ground level and the intercept point (Dow, 1977). This 

simple exercise is complicated by the lack of an accepted surface baseline value. For example, Katz and others 

(1988) use 0.25 percent Rm in their examples, whereas 

Vellutini and Bustin (1990) use 0.15 percent Rm. 

Burial history reconstruction of Paleozoic basins, 

which have cooled from their maximum temperatures, 

presents another problem. Vitrinite reflectance. records 

the maximum temperature (Barker and Pawlewicz, 

1986), and it is irreversible. Drawing a regression line 

on this maximum will yield unrealistically high esti[-

mates of erosion. For the Anadarko basin in Oklahoma, 

the erosional estimate derived in this manner is greate~r 

than the entire Mesozoic and Cenozoic section 

(Pawlewicz, 1989). This approach is useful in Paleozoic 

basins, however, for studying the evolution of a basin, 

determining the timing of igneous intrusions and the onset of overpressuring and overthrusting, and for interpreting discontinuous Rm profiles (Katz and others, 

1988; Law and others, 1989). 

Coal is made of up to 90 percent or more vitrinite. 

Most coal is formed from plant material by diagenetic 

alteration involving bacteria, chemical activity, pressure 

and, primarily, heat. Though there is evidence for land 

plants existing from the pre-Silurian (Gray and others, 

1982), vitrinite is, at best, rare and unequally distributed 

in lithology and facies regardless of age. For this reason 

additional organic entities are analyzed to broaden the 

application of petrography for thermal maturation determination. Some of these entities are chitinozoans (Goodarzi, 1985), graptolites (Kurylowicz and others, 1976; 

Goodarzi and Norford, 1985; Kemp and others, 1985; 

Goodarzi, 1984), scolecodonts, and solid bitumens (Curiale, 1986; Bertrand, 1990). Bertrand and Heroux (1987) 

compared the former three and found a depth-reflectance 

relation for each type of zooclast, but not between the 

individual zooclasts. They noted that reflectance results 

for the zooclasts should not be pooled for the evaluation 

of thermal maturity. Refining earlier work, Bertrand 

(1990) found that (1) chitinozoan and telinite (cell wall 

of structured vitrinite) reflectances are similar, (2) 

scolecodonts are always less reflecting than chitinozoans, and (3) zooclast reflectances converge and become 

similar to that of vitrinite with increasing maturation. 

Bustin and others (1989), in a laboratory study, demonstrated a direct correlation between maximum and random reflectance of graptolites and vitrinite. 

Solid bitumens are ubiquitous in distribution and 

variety (Gentzis and Goodarzi, 1990). During burial, solid bitumens undergo irreversible chemical changes analogous to those of vitrinite. However, correlation of 

reflectance of solid bitumens and of vitrinite is imprecise. Regression lines for vertical profiles for solid bitumen and vitrinite intersect near 1.0 to 1.1 percent 

reflectance. Below 1.0 percent the reflectance of solid 

bitumen is less than, and above that value more than vitrinite. A susceptibility to alteration by deasphalting, water washing, biodegradation, and oxidation (weathering) 

reduces the utility of bitumen for maturation studies, as 

does its tendency to form fine-grained mosaic structures 

during rapid heating. The mosaic structures ruin the surface for reflectance measurements. Despite numerous 

shortcomings, the measurement of reflectance of solid 

bitumen is useful. Because vitrinite reflectance is the 

benchmark maturity indicator, mathematical equations 

have been derived to approximate the relation among 

vitrinite, bitumen, and zooclast reflectance (Bertrand and 

Heroux, 1987). 

REFERENCES CITED 

Barker, C.E., and Pawlewicz, M.J., 1986, The correlation of 

vitrinite reflectance with maximum temperature in humic 

organic matter, in Buntebarth, G. and Stegna, L., eds., 

Paleogeothermics, lecture notes in earth sciences, v. 5: 

Berlin, Springer-Verlag, p. 80-93. 

Bertrand, Rudolf, 1990, Correlations among the reflectances of 

vitrinite, chitinozoans, graptolites and scolecodonts: Organic Geochemistry, v. 15, no. 6, p. 565-574. 

Bertrand, Rudolf, and Heroux, Yvon, 1987, Chitinozoan, grapVitrinite and Solid Bitumen Reflectance: Some Correlations and Applications 59 
tolite, and scolecodont reflectance as an alternative to vitrinite and pyrobitumen reflectance in Ordovician and Silurian strata, Anticosti Island, Quebec, Canada: American 

Association of Petroleum Geologists Bulletin, v. 71, no. 8, 

p. 951-957. 

Bustin, R.M., Cameron, A.R., Grieve, D.A., and Kalkreuth, 

W.D., 1983, Coal petrology, its principles, methods and 

applications: Geological Association of Canada Short 

Course Notes, v. 3, 230 p. 

Bustin, R.M., Link, C., and Goodarzi, F., 1989, Optical properties and chemistry of graptolite periderm following laboratory simulated maturation: Organic Geochemistry, v. 14, 

p. 355-364. 

Curiale, J.A., 1986, Origin of solid bitumens, with emphasis on 

biological marker results: Organic Geochemistry, v. 10, p. 

559-580. 

Davis, Alan, 1978, The reflectance of coal, in Karr, C., ed., 

Analytical methods for coal and coal products, v. 1: London, Academic Press, p. 27-81. 

Dembicki, H., Jr., 1984, An interlaboratory comparison of 

source rock data: Geochimica et Cosmochimica Acta: v. 

48, p. 2641-2649. 

Dow, W.G., 1977, Kerogen studies and geologic interpretations: Journal of Geochemical Exploration, v. 7 p. 79-99. 

Gentzis, Thomas, and Goodarzi, Fariborz, 1990, A review of 

the use of bitumen reflectance in hydrocarbon exploration 

with examples from Melville Island, Arctic Canada, in 

Nuccio, V.F. and Barker, C.E., eds., Applications of thermal maturity studies to energy exploration: Rocky Mountain Section Society of Economic Paleotologists and Mineralogists, p. 23-36. 

Goodarzi, Fariborz, 1984, Organic petrography of graptolite 

fragments from Turkey: Marine and Petroleum Geology, 

v. 1, p. 201-210. 

---1985, Reflected light microscopy of chitinozoan fragments: Marine and Petroleum Geology, V. 2, p. 72-78. 

Gooaarzi, Fariborz, and Norford, B.S., 1985, Graptolites as indicators of the temperature histories of rocks: Journal 

Geological Society of London, v. 142, p. 1089-1099. 

Graham, S.A., and Williams, L.A., 1985, Tectonic, depositional, and diagenetic history of Monterey Formation 

(Miocene), central San Joaquin basin, California: American Association of Petroleum Geologists Bulletin, v. 69, 

no. 3, p. 385-411. 

Gray, Jane, Massa, D., and Boucot, A.J., 1982, Caradocian 

land plant microfossils from Libya: Geology, v. 10, p. 

197-201. 

Katz, B.J., Pheifer, R.N., and Schunk, D.J., 1988, Interpretation 

of discontinuous vitrinite reflectance profiles: American 

Association of Petroleum Geologists Bulletin, v. 72, no. 8, 

p. 926-931. 

Kemp, A.E.S., Oliver, G.H.J., and Baldwin, J.R., 1985, Lowgrade metamorphism and accretion tectonics: southern Uplands terrain, Scotland: Mineralogical Magazine, v. 49, p. 

335-344. 

Kurylowicz, L:E., Ozimic, S., McKirdy, D.M., Kantsler, A.J., 

60 The Petroleum System-Status of Research and Methods, 1992 

and Cook, A.C., 1976, Reservoir and source rock potential 

of the Larapinta Group, Amadeus basin, central Australia: 

Australian Petroleum Exploration Association Journal, v. 

16, p. 49-65. 

Law, B.E., Nuccio, V.F., and Barker, C.E., 1989, Kinky vitrinite reflectance profiles: Evidence of paleopore pressure in 

low-permeability, gas-bearing sequences in Rocky Mountain foreland basins: American Association of Petroleum 

Geologists Bulletin, v. 73, n. 8, p. 999-1010. 

Pawlewicz, M.J., 1989, Thermal maturation of the eastern 

Anadarko basin: U.S. Geological Survey Bulletin 1866-C, 

12 p. 

Powell, T.G., Creaney, S., and Snowdon, L.R., 1982, Limitations of use of organic petrographic techniques for identification of petroleum source rocks: American Association 

of Petroleum Geologists Bulletin v. 66 no. 4, p. 430-435. 

Price, L.C., and Barker, C.E., 1985, Suppression of vitrinite reflectance in amorphous rich kerogen-A major unrecognized problem: Journal of Petroleum Geology, v. 8., no. 1, 

p.59-84. 

Price, L.C., Daws, T.A., Pawlewicz, M.J., 1986, Organic metamorphism in the Lower Mississippian-Upper Devonian 

Bakken Shale-Part 1: Rock Eval pyrolysis and vitrinite 

reflectance: Journal of Petroleum Geology, v. 9, no. 2, p. 

125-162. 

Sikander, A.H., and Pittion, J.L., 1978, Reflectance studies on 

organic matter in lower Paleozoic sediments of Quebec: 

Bulletin Canadian Petroleum Geology, v. 26, p. 132-150. 

Stach, E., Mackowsky, M-Th., Teichmuller, M., Taylor, G.H., 

Chandra, D., and Teichmuller, R., 1982, Stach's textbook 

of coal petrology: Berlin, Gebruder Borntraeger, 535 p. 

Teichmuller, Marlies, 1958, Metamorphisme du charbon et 

prospection du petrole: Rev. Ind. Miner., Special Publication, p. 99-113. 

Tissot, B.P., and Welte, D.H., 1984, Petroleum formation and 

occurrence: Berlin, Springer-Verlag, 699 p. 

Toxopeus, J.M.A., 1983, Selection criteria for the use of vitrinite reflectance as a maturity tool: Geological Society of 

London Special Publication No. 12, p. 295-307. 

Vellutini, D., and Bustin, R.M., 1990, Organic maturation of 

Mesozoic and Tertiary strata, Queen Charlotte Islands, 

British Columbia: Bulletin of Canadian Petroleum Geology,v.34,no.4,p.452-474. 

Walker, Ann, 1982, Comparison of anomalously low vitrinite 

reflectance values with other thermal maturation indices at 

Playa del Rey oil fields, California: Master's thesis, University of Washington, 190 p. 

Walker, Ann, McCulloh, T., Peterson, N., Stewart, R., 1983, 

Discrepancies between anomalously low reflectance of vitrinite and other maturation indicators from an Upper Miocene oil source rock, Los Angeles basin, California [abs.]: 

American Association of Petroleum Geologists Bulletin, v. 

67, p. 565. 

Waples, D.,W., 1985, Geochemistry in petroleum exploration: 

Boston, International Human Resources Development Corporation, 232 p. 
Clay Minerals as Geothermolneterslndicators of Thermal Maturity for Hydrocarbon Exploration 

By Richard M. Pollastro1 

INTRODUCTION 

Clay minerals provide information on the burial 

and thermal history of sedimentary rocks that is useful in 

the exploration, evaluation, and production of hydrocarbons. Over the past decade or so, empirical relations between clay minerals and temperature have provided a 

basis for their use as geothermometers. The utility of 

clay-mineral geothermometry has been applied mainly to 

diagenetic, hydrothermal, and metamorphic settings, in 

an attempt to better understand the thermal histories of 

ore and mineral formation, migrating hydrothermal fluids, and hydrocarbon source beds. Several clay minerals, 

particularly illite, mixed-layer illite/smectite (I/S), chlorite, kaolinite, and corrensite, are indicators of specific 

temperatures or temperature ranges (Hoffman and Hower, 1979). This report only discusses the current research 

status and activities related to clay-mineral geothermometry. In addition, I will demonstrate the utility of the 

method by presenting a case history where the 1/S ge:othermometer has been applied successfully to a known 

petroleum system, the Niobrara(!) in the Denver basin 

and adjacent areas (table 1). In this example, the I/S ge:othermometer is applied regionally to correlate and predict the various degrees of thermal maturity in a 

formation that is both a petroleum source and reservoir 

rock and currently a major target for horizontal drilling. 

CURRENT RESEARCH AND EVENTS 

In USGS Bulletin 1912 (Magoon, 1989), I di[scussed briefly the state of research and presented an extensive bibliography on applications of clay mineralogy 

with particular attention to clay-mineral geothermometers (Pollastro, 1989). Since publication of Bulletin 

1912, additional studies have been published, and symposia have been organized, on the subject of clay-mineral 

1 U.S. Geological Survey, Denver, Colo. 

geothermometry; at the end of this report, an updated 

"Selected References" includes papers on this subject 

omitted from Pollastro (1989). 

Following a special symposium held at the Rocky 

Mountain Section meeting of AAPG in October 1989, 

Nuccio and Barker (1990) published a volume entitled 

Applications of Thermal Maturity Studies to Energy Exploration. In that volume, I reviewed the concept, methods, and basic temperature models of the 1/S 

geothermometer (Pollastro, 1990). 

Two symposia have been organized recently on the 

reactions, processes, and applications of clay minerals 

for geothermometry. In July 1990, a conference on 

"Phyllosilicates as Indictors of Very Low Grade Metamorphism and Diagenesis" was held at the University of 

Manchester, United Kingdom. The conference was cosponsored by the International Geological Correlation 

Programme (IGCP), Project 294 (Very Low Grade Metamorphism), and the Clay Minerals and Metamorphic 

Studies Groups. About 35 oral and 18 poster papers 

were presented to over 120 participants. The conference 

focused on the chemical and physical processes related 

to expandability, illitization, and "crystallinity" measurements of illite and 1/S, all which are common measurements used in clay-mineral geothermometry. Few papers 

were presented on specific temperature models for claymineral geothermometry or on comparison of temperatures derived from clay minerals to those for the 

maturity of organic matter. Selected papers from the 

conference will appear in future issues of Clay Minerals 

and Journal of Metamorphic Geology. 

In October 1991, a special symposium at the 28th 

Annual Meeting of the Clay Minerals Society in Houston, Texas, entitled "Clay Geothermometers and Geochronometers," was convened by Eric Eslinger and Reed 

Glasmann. Titles for the program included presentations 

on case-history studies, reaction kinetics and mechanisms, and clay-isotope geothermometers. A total of 28 

oral and 20 poster papers were presented. 

In my recent review of the concept and utility of 

1/S geothermometry (Pollastro, 1990), I proposed two 

simple models for the I/S geothermometer: (1) a shortClay Minerals as Geothermometers---lndicators of Thermal Maturity for Hydrocarbon Exploration 61 
life geothermal model (<2 million years of heating) typical of very young sediments and modern hydrothermal 

systems, and (2) the model of Hoffman and Hower 

(1979), which pertains to older rocks and geothermal 

settings, particularly long-term, progressive burial diagenetic sequences and basins ranging in age from about 2 

to 300 million years. Several case histories were presented in the paper to develop and support the temperature 

models. 

Most recently, Elliot and others (1991) studied the 

smectite-to-illite reaction in bentonites from cores and 

outcrops of the Upper Cretaceous Mowry Shale and Niobrara Formation, Denver basin. They found that both the 

percent illite layers and K-Ar ages of 1/S increase with 

increasing depth of burial. Mathematical models showed 

an overall fifth-order kinetic expression for the formation of illite. They concluded that, for most of the basin, 

the data are compatible with 1/S having been formed in 

response to increased temperature from progessive burial 

because the oldest K-Ar ages of I/S are from the deepest 

buried 1/S along the basin axis. In addition, 1/S from 

bentonites in core from the Wattenberg gas field was the 

most illitic and among the oldest measured; these data 

are in agreement with anomalously high temperatures 

suspected in the Wattenberg field from previous studies 

of geothermometers based on organic matter (Rice, 

1984; Higley and others, 1985, this volume)· and clay 

minerals (Pollastro and Scholle, 1986a, b). 

APPLICATION TO THE NIOBRARA 

FORMATION, DENVER BASIN 

The utility of I/S geothermometry is best shown 

using a study on the Niobrara Formation for the following reasons: (1) the Niobrara Formation in the Denver 

basin and adjacent areas is both a petroleum source and 

reservoir rock; (2) well-documented, progressive diagenetic changes occur relative to increased depth of burial 

and temperature that affect both the reservoir quality of 

the chalks and the type of indigenous hydrocarbons (microbial gas versus oil) produced (Pollastro and Scholle, 

1986a); and (3) within the past five years, the overall 

success of the many horizontal wells drilled, particularly 

in fractured, organic-rich, thermally mature chalk or 

chalky shale reservoirs, has rekindled interest in the Niobrara Formation throughout the Rocky Mountain region 

as an exploration target for oil. 

Although an earlier version of an 1/S geothermometry map of the Niobrara in the Denver basin and adjacent areas has been published (Pollastro and Scholle, 

1986a, b; Pollastro, 1990), I have recently updated, modified, and added data from about 20 wells to the current 

version (fig. 9). For example, data from the Silo field in 

southeastern Wyoming, where several horizontal wells in 

62 The Petroleum System-Status of Research and Methods, 1992 

the Niobrara are at various stages of completion, are included in this revised version. Additionally, localities 

where transitional stages of 1/S occur are identified. 

The concept and the model used in this study are 

simple; 1/S in bentonite beds from the Niobrara Formation and basal Pierre Shale is used to predict the type of 

hydrocarbons sourced by organic-rich chalk and chalky 

shale of the Niobrara. On the basis of X-ray powder diffraction profiles and the model of Hoffman and Hower 

(1979), randomly interstratified 1/S (commonly referred 

to as RO 1/S) is assumed stable below temperatures of 

about 100°C. At burial temperatures of about 100-

11 0°C, random or RO 1/S is converted to a short-range 

ordered 1/S (referred to as R1 1/S); thus, only ordered 

(R>O) 1/S is present above this temperature range in older (>2 million years) basin settings (see review by Pollastro, 1990). This study, and that recently reported by 

Elliott and others (1991), found few inconsistencies in 

1/S ordering among the several hundred samples from 

numerous well and outcrop localities. 

The temperature range of 100-110°C for the random-to-ordered 1/S transition is generally coincident 

with temperatures for the onset of peak (or main phase) 

oil generation in rocks of Late Cretaceous through early 

Tertiary age (Tissot and Welte, 1984, p. 180). These relations provide much of the basis for predicting hydrocarbon maturity within the Niobrara from 1/S 

geothermometry. Additionally, microbial methane (an 

immature gas generated at low temperatures by the decomposition of organic matter by anaerobic microorganisms) is produced from the Niobrara in areas where 

burial temperatures never exceeded 7 5°C (Rice and 

Claypool, 1981). The I/S geothermometer is, therefore, 

especially useful for Niobrara rocks because it outlines 

areas of different degrees of thermal maturity as related 

to hydrocarbon generation. Areas with little or no potential, that is, those where maximum burial conditions 

were either too hot for microbial gas or too cool for 

thermogenic oil and( or) gas production, and probably between about 75°C and H>0°C, can also be interpolated 

from 1/S ordering and well production data. Areas that 

are potential targets for horizontal wells in thermally 

mature, fractured, Niobrara oil reservoirs should, therefore, contain only ordered 1/S in bentonites. 

Figure 9 is the updated version of the 1/S geothermometry map applied to maturity of hydrocarbons generated within the Niobrara Formation. Random 1/S in 

bentonite indicates areas of maxim urn burial temperatures for Niobrara rocks <100°C, whereas ordered 1/S indicates areas where the Niobrara has been buried to 

temperatures > 100°C and is thermally mature with respect to oil generation. Similarly, transitional 1/S [localities where 1/S is in the initial or transitional stage of 

converting from random to ordered 1/S (see Pollastro and 

Martinez, 1985; Whitney and Northrop, 1988)] probably 
EXPLANATION 

RANDOM 1/S .CORE,AOUTCROP 

TRANSITIONAL 

VS .COREDOUTCROP 

ORDERED 1/S .CORE ):(OUTCROP 

50 MILES 

Figure 9. Geothermometry map as an indicator of thermal maturity and hydrocarbon type for the 

Niobrara Formation, Denver basin, Colorado. Temperature determined from the degree of ordering of 

illite/smectite (1/S) clay in bentonite as interpmted from X-ray powder diffraction profiles from samples 

of outcrop (open symbols) and core (solid symbols). Area of current microbial gas production from the 

Niobrara Formation is shown. Small arrows point to areas targeted for horizontal wells. 

Clay Minerals as Geothermometers-lndicators of Thermal Maturity for Hydrocarbon Exploration 63 
indicates maximum burial temperatures near HX>°C (perhaps about 90--l00°C) and can be interpreted as marginally mature with respect to oil generation. The area of 

current microbial gas production from Niobrara rocks is 

also indicated on figure 9 as the area of immature gas 

production. 

REFERENCES CITED 

Elliot, W.C., Aronson, J.L., Matisoff, G., and Gautier, D.L., 

1991, Kinetics of the smectite to illite transformation in 

the Denver basin: Clay mineral, K-Ar data, and mathematical model results: American Association of Petroleum Geologists Bulletin, v. 75, p. 436-462. 

Higley, D.L., Pawlewicz, M.J., and Gautier, D.L., 1985, 

Isoreflectance map of the "J" sandstone of the Denver basin of Colorado: U.S. Geological Survey Open-File Report 

85-384, 9 p. 

Hoffman, J., and Hower, J., 1979, Clay mineral assemblages as 

low grade metamorphic geothermometers-Application to 

the thrust faulted disturbed belt of Montana, in Scholle, 

P.A., and Schluger, P.S., eds., Aspects of diagenesis: Society of Economic Paleontologists and Mineralogists Special 

Publication 26, p. 55-79. 

Magoon, L.B., 1989, The petroleum system-Status of research and methods, 1990: U.S. Geological Survey Bulletin 1912, 88 p. 

Nuccio, V.F., and Barker, C.E., 1990, Applications of thermal 

maturity studies to energy exploration: Rocky Mountain 

Section, Society of Economic Paleontologists and Mineralogists, 175 p. 

Pollastro, R.M.,1989, Clays, in Magoon, L. B., ed., The petroleum system-Status of research and methods, 1990: US 

Geological Survey Bulletin 1912, p. 28-31. 

---1990, The illite/smectite geothermometer--Concepts, 

methodology, and application to basin history and hydrocarbon generation, in Nuccio, V.F., and Barker, C.E., eds., 

Applications of thermal maturity studies to energy exploration: Rocky Mountain Section, Society of Economic Paleontologists and Mineralogists, p. 1-18. 

Pollastro, R.M., and Martinez, C.J., 1985, Whole-rock, insoluble residue, and clay mineralogies of marl, chalk, and 

bentonite, Smoky Hill Shale Member, Niobrara Formation 

near Pueblo, Colorado-Depositional and diagenetic implications, in Pratt, L., Kauffman, E.G., and Zeit, F.B., 

eds., Fine-grained deposits and biofacies of the Cretaceous 

Western Interior seaway: Evidence of cyclic sedimentary 

processes: Society of Economic Paleontologists and Mineralogists Field Trip Guidebook no. 4, p. 215-222. 

Pollastro, R.M., and Scholle, P.A., 1986a, Diagenetic relationships in a hydrocarbon-productive chalk-The Cretaceous 

Niobrara Formation, in Mumpton, F.A., ed., Studies in 

diagenesis: U.S. Geological Survey Bulletin 1578, p. 219-

236. 

---1986b, Exploration and development of hydrocarbons 

from low-permeability chalks-An example from the 

Upper Cretaceous Niobrara Formation, Rocky Mountains 

region, in Spencer, C.W., and Mast, R.F., eds., Geology of 

64 The Petroleum System-Status of Research and Methods, 1992 

tight gas reservoirs: American Association of Petroleum 

Geologists Studies in Geology, no. 24, p. 129-142. 

Rice, D.D., 1984, Relation of hydrocarbon occurrence to thermal maturity of organic matter in the Upper Cretaceous 

Niobrara Formation, eastern Denver basin: evidence of 

biogenic versus thermogenic origin of hydrocarbons, in 

Woodward, J., Meissner, F.F., and Clayton, J.L., ed., Hydrocarbon source rocks of the greater Rocky Mountain region: Denver, Rocky Mountain Association of Geologists, 

p. 365-368. 

Rice, D.D., and Claypool, G.E., 1981, Generation, accumulation, and resource potential of biogenic gas: American Association of Petroleum Geologists Bulletin, v .65, p. 5-25. 

Tissot, B.P., and Welte, D.H., 1984, Petroleum formation and 

occurrence: Berlin, Springer-Verlag, 538 p. 

Whitney, G., and Northrop, H.R., 1988, Experimental investigations of the smectite to illite reaction-Dual reaction 

mechanisms and oxygen-isotopic systematics: American 

Mineralogists, v. 73, p. 77-90. 

SELECTED REFERENCES 

Ahn, H.J., and Peacor, 1986, Transmission and analytical electron microscopy of the smectite-to-illite transition: Clays 

and Clay Minerals, v. 34, p. 165-179. 

Anjos, S.M.C., 1986, Absence of clay diagenesis in Cretaceous-Tertiary marine shales, Campos basin, Brazil: Clays 

and Clay Minerals, v. 34. p. 424-434. 

Charnley, H., 1989, Clay sedimentology: New York, SpringerVerlag, 623 p. 

Connolly, C.A., 1989, Thermal history and diagenesis of the 

Wilrich Member shale, Spirit River Formation, northwest 

Alberta: Bulletin of Canadian Petroleum Geology, v. 37, 

p. 182-197. 

Dypvik, H., 1983, Clay mineral transformations in Tertiary and 

Mesozoic sediments from North Sea: American Association of Petroleum Geologists Bulletin, v. 67, p. 160-165. 

Eberl, D.D., and Srodon, J., 1988, Ostwald ripening and interparticle-diffraction effects for illite crystals: American 

Mineralogist, v. 73., 1335-1345. 

Eberl, D.D., and Velde, B., 1989, Beyond the Kubler index: 

Clay Minerals, v. 24, p. 571-577. 

Edman, J.D., and Surdam, R.C., 1986, Organic-inorganic 

interactons as a mechanism for porosity enhancement in 

the Upper Cretaceous Ericson Sandstone, Green River 

basin, Wyoming, in Gautier, D.L., ed., Roles of organic 

matter in sediment diagenesis: Society of Economic Paleontologists and Mineralogists Special Publication 38, p. 

85-109. 

Eslinger, E., and Sellars, B., 1981, Evidence for the formation 

of illite from smectite during burial metamorphism in the 

Belt Supergroup, Clark Fork, Idaho: Journal of Sedimentary Petrology, v. 51, p. 203-216. 

Foster, W.R., and Custard, H.C., 1983, Role of clay composition on extent of illite/smectite diagenesis [abs.]: American Association of Petroleum Geologists Bulletin, v. 67, 

p. 462. 

Freed, R.L., 1982, Clay mineralogy and depositional history of 
the Frio Formation in two geopressured wells, Brazoria 

County, Texas: Transactions ofthe Gulf Coast Associa1ion 

of Geological Societies, v. 32, p. 459-463. 

Freed, R.L., and Peacor, D.R., 1989, Variability in tempera1ure 

of the smectite/illite reaction on Gulf Coast sedime:nts: 

Clay Minerals, v. 24, p. 171-180. 

Geving, R.L., Suchecki, R.K., and Kelley, S.E., 1989, Kin·etic 

controls on the transformation of smectite to illite in the. 

Los Angeles basin as determined by apatite fission track 

analysis: Abstracts with Program, Geological Society of 

America, v. 21, no. 6, p. A349. 

Horton, D.G., 1985, Mixed-layer illite/smectite as a 

paleotemperature indicator in the Amethyst vein systt~m. 

Creede, Colorado, USA: Contributions to Mineralogy and 

Petrology, v. 18, p. 171-179. 

Hower, J., 1981, Shale diagenesis, in Longstaffe, F.J., c~ .• 

Clays and the resource geologists: Mine~alogical Society 

of Canada; Short Course Handbook 7, p. 60-80. 

Inoue, A., Korihiko, N., Kitagawa, R., and Watanabe, T., 1987, 

Chemical and morphological evidence for the conversion 

of smectite to illite: Clays and Clay Minerals, v. 35, p. 

111-120. 

Inoue, A., Velde, B., Meunier, A., and Touchard, G., 1988, 

Mechanism for illite formation during smectite-to-illite 

conversion in a hydrothermal system: American Mineralogist, v. 73, p. 1325-1334. 

International Geological Correlation Program, 1990, Phyllosilicates as indicators of very low grade metamorphism ;md 

diagenesis: Program and abstracts, Project 294: Very low 

grade metamorphism, University of Manchester, England, 

68 p. 

Jennings, S., and Thompson, G.R., 1986, Diagenesis of PlioPleistocene sediments of the Colorado River delta, southem California: Journal of Sedimentary Petrology, v. 56,. p. 

86-98. 

Kablanow, R.I., and Surdam, R.C., 1983, Diagenesis and hydrocarbon generation in the Monterey Formation, Huasna 

basin, California, in Isaacs, C.M., and Garrison, R.E., eds., 

Petroleum generation and occurrence in the Miocene Monterey Formation, California: Pacific Section, Society for 

Economic Paleontologists and Mineralogists, p. 53-68. 

Lanson, B., and Champion, D., 1991, The liS-to-illite reaction 

in the late stage diagenesis: American Journal of Science, 

v. 291, p. 473-506. 

Maxwell, D.T., and Hower, J., 1967, High-grade diagenesis 

and low-grade metamorphism of illite in Precambrian Belt 

series: American Mineralogist, v. 52, p. 843-857. 

McCubbin, D.T., and Patton, J.W., 1981, Burial diagenesis of 

illite/smectite-The kinetic model [abs.]: American Association of Petroleum Geologists Bulletin, v. 65, p. 956. 

Morton, J.P., 1985, Rb-Sr evidence for punctuated illite/smc~ctite diagenesis in the Oligocene Frio Formation, Texas 

Gulf Coast: Geological Society of America Bulletin, v. 96, 

p. 114-122. 

Nadeau, P.H., and Reynolds, R.C., Jr., 1981, Burial and contact 

metamorphism in the Mancos Shale: Clays and Clay M.inerals, v. 29, p. 249-259. 

Pearson, M.J., and Small, J.S., 1988, Illite-smectite diagenesis 

and paleotemperatures in North Sea Quaternary to Mesozoic shale sequences: Clay Minerals, v. 23, p. 109-132. 

Pollastro, R.M., 1985, Mineralogical and morphological evidence for the formation of illite at the expense of illite/ 

smectite: Clays and Clay Minerals, v. 33, p. 265-274. 

Pollastro, R.M., and Finn, T.M., 1990, Clay mineralogy and 

bulk rock composition of selected core and cutting samples from the Amoco Eischeid No. 1 well, Carroll County, 

Iowa-A reconnaissance study from X-ray powder diffraction, in R.A. Anderson, ed., The Amoco M.G. 

Eischeid No. 1 Deep Petroleum Test, Carroll County, 

Iowa: Iowa Department of Natural Resources Special Report Series 2, p. 143-152. 

Pollastro, R.M., and Schmoker, J.W., 1989, Relationship of 

clay-mineral diagenesis to temperature, age, and hydrocarbon generation-An example from the Anadarko basin, 

Oklahoma, in Johnson, K.S., ed., Anadarko Basin Symposium, 1988: Oklahoma Geological Survey Circular 90, p. 

257-261. 

Primmer, T.J., and Shaw, H., 1991, Variations in the delta D 

and delta 0 18 compositions of illite-smectites in a partly 

overpressured Tertiary sequence from an offshore well, 

Texas Gulf Coast, USA: Marine and Petroleum Geology, 

v. 8, p. 225-231. 

Ramseyer, K., and Boles, J.R., 1986, Mixed-layer illite/smectite minerals in Tertiary sandstones and shales, San Joaquin basin, California: Clays and Clay Minerals, v. 34, p. 

115-124. 

Rettke, R.C., 1981, Probable burial diagenetic and provenance effects on the Dakota Group Clay mineralogy, Denver basin: 

Journal of Sedimentary Petrology, v. 51, p. 541-551. 

Srodon, J., 1979, Correlation between coal and clay diagenesis 

in the Carboniferous of the Upper Silesian coal basin: Proceedings of the International Clay Conference, Oxford, p. 

251-260. 

Srodon, J., Andreoli, C., Elsass, F., and Robert, M., 1990, Direct high-resolution transmission electron microscopic 

measurement of expandability of mixed-layer illite/smectite in bentonte rock: Clays and Clay Minerals, v. 38, p. 

373-379. 

Velde, B., and Espitalie, J., 1989, Comparison of kerogen 

maturation and illite/smectite composition in diagenesis: 

Journal of Petroleum Geology, v. 12, p. 103-110. 

Velde, B., and Iijima, A., 1988, Comparison of clay and zeolite 

mineral occurrences in Neogene age sediments form several wells: Clays and Clay Minerals, v. 36, p. 337-342. 

Weaver, C.E., 1989, Clays, muds, and shales, Developments in 

sedimentology 44: New York, Elsevier, 819 p. 

Whitney, G., 1990, Role of water in smectite-to-illite reaction: 

Clays and Clay Minerals, v. 38, p. 343-350. 

Yeh, H-W., and Savin, S., 1977, Mechanisms of burial metamorphism of argillaceous sediments: 3. 0-isotope evidence: Geological Society of America Bulletin, v. 88, p. 

1321-1330. 

Clay Minerals as Geothermometers--1 ndicators of Thermal Maturilf for Hydrocarbon Exploration 65 
Influence of Regional Heat Flow Variation 

on Thermal Maturity of the Lower Cretaceous 

Muddy ("J") Sandstone, Denver Basin, Colorado 

By Debra K. Higley, Donald L. Gautier, and Mark j. Pawlewicz1 

INTRODUCTION 

Vitrinite isoreflectance (Rm) contours delimit regional variation in levels of thermal maturity for hydrocarbon (HC) source rocks adjacent to the Lower 

Cretaceous Muddy ("J") Sandstone in the Denver basin 

(fig. 10). Variation results from areal differences in burial depth, heat flow, and basin hydrodynamics. Thermal 

maturity trends also suggest the occurrence of one or 

more heating events, one of which may be associated 

with the Late Cretaceous Laramide orogeny. 

The Denver basin is an asymmetrical Laramide 

structural basin with a gently dipping eastern flank and a 

steeply dipping western flank; isoreflectance contours 

terminate against the Front Range uplift (fig. 10). The 

basin axis is approximated by a line connecting Denver, 

Colorado, and Cheyenne, Wyoming. Most Muddy ("J") 

Sandstone oil and gas fields are located on the shallow 

eastern flank of the basin. The Wattenberg gas field is 

enclosed by the 0.9 percent Rm contour and is located 

along the northeastern extension of the Colorado Mineral Belt (Sonnenberg and Weimer, 1981). 

The "J" sandstone is an informal economic unit of 

the Muddy Sandstone. About 90 percent of the 800 million barrels of oil and 1.2 trillion cubic feet of gas (tcfg) 

produced from the Denver basin has been from the "J" 

sandstone. This predominantly nearshore marine, deltaic, 

and valley-fill sandstone was deposited about 99 to 97 

million years ago (Ma) during a regression of the Cretaceous epicontinental seaway (Kauffman, 1977, Obradovich and Cobban, 1975, Weimer, 1984, Weimer and 

others, 1986). The Muddy ("J") Sandstone is bounded 

by marine shales, which are probably the main source 

rocks for oil and gas produced from the Muddy ("J") 

'Sandstone (Clayton and Swetland, 1980). These are the 

underlying Skull Creek, and overlying Mowry and Gran1 U.S. Geological Survey, Denver, Colo. 

66 The Petroleum System-Status of Research and Methods, 1992 

eros Shales; these shales were sampled at 14 outcrop locations and from cores of 42 wells for Rm analysis (Higley and others, 1985). 

Acknowledgments.-Roy Gallop of Core Laboratories, Denver, Colorado, supplied core data. Many oil 

companies generous! y released well data. Sources of Rm 

include unpublished data from Ernest Jones, Dudley 

Rice, and Jerry Clayton; their assistance is appreciated. 

ISOREFLECTANCE TRENDS 

Thermal maturation of HC source rocks depends 

largely on increasing depth of burial and areal variation 

in Denver basin heat flow. Rm increases almost exponentially with increasing burial depth in the Colorado portion of the basin, ranging from 0.41 percent at 4,900 ft 

(1,500 m) depth to 1.51 percent at 7,800 ft (2,400 

m)(Higley and others, 1985). The correlation coefficient 

for the linear regression of depth versus log Rm is -0.64 

for the Colorado samples (fig. 10). There is no correlation between depth and Rm for samples located in Nebraska and Wyoming ( +0.26). Correlations are 0.86 to 

0.93 for the least-squares regressions of down-hole depth 

versus log Rm for the four wells shown on figure 11. 

Differences in slopes of the lines result mainly from areal difference in heat flow. Poorer correlations for the 

Muddy ("J") Sandstone data than for the four wells results from variable rates of current and probable paleoheat flow across the basin, and also from influence of 

different thicknesses of eroded Tertiary sediment on 

computed maximum burial. 

In oil-prone types of organic matter, an Rm range 

of about 0.6 to 1.35 percent is commonly considered to 

be the main zone of oil generation. Thermogenic gas is 

the predominant product above an Rm of approximately 

1.35 percent (Waples, 1980). Source rocks with Rm values less than 0.60 percent are usually considered to be 

thermally immature for oil generation in the types II and 

III kerogen from which Muddy ("J") Sandstone oil and 
gas is produced (Clayton and Swetland, 1980). The 0.6 

percent isoreflectance contour line corresponds to a present-day depth of about 6,000 ft (1 ,800 m) in the Denver 

basin. Oil and gas production in areas of lesser Rm values suggests migration of oil from deeper and hotter 

areas of the basin. Studies of Cretaceous oils by Clayton 

and Swetland (1980) show that much of the Muddy ("J") 

Sandstone oil in the southeastern quarter of figure 10 

originated deeper in the basin. 

In general, the lowest Rm values are on the shallower eastern flank of the basin and at the Muddy Sandstone outcrops along the western flank (excluding th~e 

area directly west of the Wattenberg field). Cretaceous 

and older rocks that crop out on the west side of the 

basin were uplifted during the Laramide orogeny, which 

105° 

0 

0 

began about 68 Ma and ended about 50 Ma {Trimble, 

1980; Tweto, 1975, 1980). Because this uplift preceded 

the maximum burial depth attained in other parts of the 

basin, Rm values of outcrop samples are generally much 

less than in samples immediately basinward. Maximum 

burial for Muddy ("J") Sandstone source rocks in most 

of the basin was attained during the late Tertiary {Tainter, 1984; Higley and Gautier, 1988). Erosion of Tertiary 

and Upper Cretaceous rocks across the basin is associated with broad uplift of the Great Plains during the last 7 

to 10 million years (Epis, 1973, Izett, 1973, Lachenbruch 

and Sass, 1977, Taylor, 1973, Zoback and Zoback, 

1980). During this period of time a minimum 1,000 ft 

(300 m) and as much as 5,500 to 6,500 ft (1,700--1,900 

m) of rock was removed (Higley and Schmoker, 1989; 

104° 103° 

50 MILES 

50 KILOMETERS 

Figure 10. lsoreflectance contour map of the Lower Cretaceous Muddy ("J") 

Sandstone in Denver basin. Wattenberg field is approximately in "bulls eyr.-" of 

0.9 to 1.5 percent Rm. Contour interval is 0.1 percent Rm. Small solid dots are 

Rm sample locations; large symbols are locations for Sohio well No. 12-7 

Whitehead (triangle) and Amoco we~lls Nos. 1 Champlin 562A-1 (square) and 

1 Champlin 401 A and 344A-1 (dots). Dashed line is western boundary of 

Denver basin. Northeasterly trend of Colorado Mineral Belt (CMB) is shown. 

Influence of Regional Heat Flow Variation on Thermal Maturity of the Lower Cretaceous Muddy (

11J") Sandstone, Denver Basin, Colorado 67 
L.C. Price, oral commun., 1991). Estimates of erosion 

are based on stratigraphic reconstruction and on downhole thermal maturity plots of Cretaceous through Tertiary strata (fig. 11). 

The highest Rm values are in the Wattenberg gas 

field. The 1.3 percent Rm contour line approximates the 

onset of thermogenic gas generation; higher Rm values 

suggest that some of the gas is thermogenic in origin. 

Gas-prone type III kerogen also contributes to the more 

than 0.57 tcfg (to 1/89) produced from the Wattenberg 

field. Samples collected within the gas generation zone 

range from depths of 7,000 to 8,000 ft (2,100-2,400 m). 

Values of Rm in the Wattenberg field are anomalously high when compared to surrounding areas, even 

when reconstructed to maximum depths (Higley and 

Schmoker, 1989). In addition, the geothermal gradients 

are also anomalously high. This high heat flow probably 

results from several processes; three of these are (1) influence of lateral and upward moving fluids (Meyer and 

McGee, 1985), (2) possible effect of broad regional uplift, and (3) areal variation in heat conductivity of rocks 

and pore fluids. 

There is evidence of one or more heating events, 

probably associated with Laramide reactivation of northeast-trending Precambrian basement faults of the ColoraRm, IN PERCENT 

0.2 0.3 0.4 0.5 1.0 

8 

2 

6 

s 4 0 

0 

(/) 

a: 

~ 2 1-

w 

w 

LL 0 ~ 

w 

1-

w 

~ 

0 

0 ....I 

~ 

SURFACE 

:J:~ ~ 

~ 2 

w 

Cl 

::i 

~ w 4 Cl 

6 

2 

8 

10 ~------._ ____ ._ __ ~--~--~~----3 

Figure 11. lsoreflectance sample depths and correlation 

curves (extrapolated above ground surface) for Sohio well 

No. 12-7 Whitehead (triangles) and Amoco wells Nos. 1 

Champlin 562A-1 (squares) and 1 Champlin 344A-1 and 

401 A (dots) (modified from Tainter, 1984). Extrapolation of 

curves to a postulated above-surface Rm of 0.25 percent 

yields about 2,000 to 8,000 ft (6] 0-2,400 m) of eroded 

sediment thickness. Correlation curve (thin line) of "J" 

sandstone data set is also shown. 

68 The Petroleum System-Status of Research and Methods, 1992 

do Mineral Belt. Reactivation of these faults during and 

following the Laramide orogeny (Haun, 1968, Hoblitt 

and Larson, 1979, Sonnenberg and Weimer, 1981, Weimer, 1984) may have influenced the thermal maturity of 

overlying sediments, both through increased heat flow 

and by more efficient heat transfer through associated 

fracture and fault systems. Additional support for the 

mineral belt heat source includes this evidence: (1) 

Anomalously large Rm values occur in outcrop samples 

directly west of the Wattenberg field; (2) isoreflectance 

contours in Paleozoic formations of southwest Nebraska 

mimic the Muddy ("J") Sandstone source rock anomaly 

(J. Clayton, oral commun., 1990) and are on trend with 

the mineral belt; (3) laccolithic intrusions along the mineral belt are dated Laramide and younger (Armstrong, 

1969; Bryant and Naeser, 1980; Hoblitt and Larson, 

1975); and (4) conodonts of the Mississippian Leadville 

Limestone exhibit anomalously high color alteration index (CAl) values within the mineral belt. This CAl 

anomaly may be associated with Laramide hydrothermal 

flow (Bridges and McCarthy, 1990). 

While basin Rm trends are apparent, scatter in data 

is considerable. Some of the scatter results from uncertainty in the measure of vitrinite reflectance. Values of 

Rm may be affected by the presence of oxidized or recycled organic matter and inertinite macerals, which have 

reflectance levels greater than vitrinite. These macerals 

are common in the Nebraska and Wyoming samples (fig. 

10) and may have influenced Rm values. Some of the 

anomalous Rm data may be due to sampling; oil fields in 

the Rocky Mountain region are hotter than adjacent nonproducing areas (Meyer and McGee, 1985); this may be 

related to basin hydrodynamics and to the low thermal 

conductivity of hydrocarbons. Effects of the basin deep 

west of Cheyenne, Wyoming, are undocumented because 

of lack of data. However, clay mineral and radiometric 

work by Elliott (1988) suggests that source rocks here 

are within the oil generation window and may be within 

the gas generation window. 

REFERENCES CITED 

Armstrong, R.L., 1969, K-Ar dating of laccolithic centers of 

the Colorado Plateau and vicinity: Geological Society of 

America Bulletin, v. 80, p. 2081-2086. 

Bridges, L.W.D., and McCarthy, K., 1990, Tertiary subsurface 

solution in the Mississippian Leadville Limestone Geothermal Aquifer of Colorado: The Mountain Geologist, v. 

27, p. 57-67. 

Bryant, B., and Naeser, C.W., 1980, The significance of fission-track ages of apatite in relation to the tectonic history 

of the Front and Sawatch Ranges, Colorado: Geological 

Society of America Bulletin, v. 91, p. 156-164. 

Clayton, J. L., and Swetland, P. L., 1980, Petroleum generation 

and migration in the Denver basin: American Association 
of Petroleum Geologists Bulletin, v. 64, p. 1613-1633. 

Elliott, W.C., 1988, Bentonite illitization in two contrastiiJ.g 

cases: the Denver basin and the southern Appalachian 

basin: Cleveland, Ohio, Case Western Reserve University, 

Ph.D. thesis, 231 p. 

Epis, R.C., 1973, Geomorphic and tectonic implications of the 

post-Laramide late Eocene erosion surface in the Southem 

Rocky Mountains [abs.]: Geological Society of Americ:a 

Abstracts with Programs, v. 5, p. 479. 

Haun, J. D., 1968, Structural geology of the Denver basin--

Regional setting of the Denver earthquakes: Colorado 

School of Mines Quarterly, v. 63, no. 11, p. 101-112. 

Higley, D. K., Pawlewicz, M. J., and Gautier, D. L., 198S, 

Isoreflectance map of the "J" sandstone in the Denver basin of Colorado: U.S. Geological Survey Open-File Repo1rt 

85-384, 100 p. 

Higley, D.K., and Gautier, D.L., 1988, Burial history reconstruction of the Lower Cretacous "J" sandstone in the 

Wattenberg field, Colorado, "hot spot," in Carter, L.M.H., 

ed., USGS research on energy resource-1988: U.S. Gec~­

logical Survey Circular 1025, p. 20. 

Higley, D. K., and Schmoker, J. W., 1989, Influence of depositional environment and diagenesis on regional porosi~y 

trends in the Lower Cretaceous "J" sandstone, Denve.r 

basin, Colorado, in Coalson, E.B., ed., Petrogenesis and 

petrophysics of selected sandstone reservoirs of the Rocky 

Mountain region: Rocky Mountain Association of Geologists, p. 183-196. 

Boblitt, R., and Larson, E., 1979, Paleomagnetic and 

geochonologic data bearing on the structural evolution of 

the northeastern margin of the Front Range, Colorado: 

Geological Society of America Bulletin, v. 86, p. 237-242. 

lzett, G.A., 1973, Late Tertiary sedimentation and deformation 

in northern Colorado and adjoining areas [abs.]: Geological Society of America Abstracts with Programs, v. 5, p. 

487. 

Kauffman, E.G., 1977, Geological and biological overview; 

Western Interior Cretaceous basin: The Mountain Geologist, v. 14, nos. 3-4, p. 75-99. 

Lachenbruch, A.H., and Sass, J.A., 1977, Heat flow in the~ 

United States and the thermal regime of the crust: American Geophysical Union Geophysics Monograph Series 20, 

p. 626-675. 

Meyer, H.J., and McGee, H.W., 1985, Oil and gas fields ac·-

companied by geothermal anomalies in the Rocky Moun·-

tain Region: American Association of Petroleum Geolo--

gists Bulletin, v. 69, no. 6, p. 933-945. 

Obradovich, J.D., and Cobban, W.A., 1975, A time scale for 

the Late Cretaceous of the Western Interior of North 

America, in Caldwell, W.G.E., ed., The Cretaceous System in the Western Interior of North America: Geological 

Association of Canada Special Paper 13, p. 31-54. 

Sonnenberg, S.A., and Weimer, R.I., 1981, Tectonics, sedimentation, and petroleum potential, northern Denver 

basin, Colorado, Wyoming, and Nebraska, Colorado 

School of Mines Quarterly, no. 2, 45 p. 

Tainter, P. A., 1984, Stratigraphic and paleostructural controls 

on hydrocarbon migration in Cretaceous "D" and "J" 

Sandstones of the Denver basin, in Woodward, J., 

Meissner, F.F., and Clayton, J.L., eds., Hydrocarbon 

source rocks of the greater Rocky Mountain region: Denver, Rocky Mountain Association of Geologists, p. 339-

354. 

Taylor, R.B., 1973, Upper Tertiary tectonism and deposits in 

south-central Colorado [abs.]: Geological Society of 

America Abstracts with Programs, v. 5, p. 518. 

Trimble, D. E., 1980, Cenozoic tectonic history of the Great 

Plains contrasted with that of the southern Rocky Mountains; a synthesis: The Mountain Geologist, v. 17, no. 17, 

p. 54-67. 

Tweto, Ogden, 1975, Laramide (Late Cretaceous- Early Tertiary) orogeny in the southern Rocky Mountains, in Curtis, 

B. ed., Cenozoic geology of the southern Rocky Mountains: Geological Society of America Memoir 144, p. 1-

44. 

---1980, Summary of the Laramide orogeny in Colorado, 

in Kent, H., and Porter, K. eds., Colorado geology: Denver, Rocky Mountain Association of Geologists, p. 129-

134. 

Waples, D.W., 1980, Time and temperature in petroleum formation: Application of Lopatin's method to petroleum exploration: American Association of Petroleum Geologists 

Bulletin, v. 64, p. 6, p. 916-926. 

Weimer, R.I., 1984, Relation of unconformities, tectonics, and 

sea-level changes, Cretaceous of Western Interior, U.S.A., 

in Schlee, J. S., ed., Interregional unconformities and hydrocarbon accumulations: American Association of Petroleum Geologists Memoir 36, p. 7-35. 

Weimer, R.I., Sonnenberg, S.A., and Young, G.B., 1986, 

Wattenberg field, Denver basin, Colorado, in Spencer, 

C.W. and Mast, R.F., eds., Geology of tight gas reservoirs: American Association of Petroleum Geologists 

Studies in Geology No. 24, p. 143-164. 

Zoback, M.L., and Zoback, M., 1980, State of stress in the 

conterminous United States: Journal of Geophysical Research, v. 85, p. 6113-6156. 

Influence of Regional Heat Flow Variation on Thermal Maturity of the llower Cretaceous Muddy (HJ") Sandstone, Denver Basin, Colorado 69 
Thermal Maturity of the Mesaverde Group, 

Uinta Basin, Utah 

By Vito F. Nuccio andThomas D. Fouch1 

INTRODUCTION 

The level of thermal maturity achieved by hydrocarbon sourc'e rocks is one of the most important factors 

controlling petroleum generation. Thermal maturity studies also play an important role in assessing reservoir diagenesis, timing of structural movement, burial history 

reconstruction, fluid movement, and porosity prediction. 

0 

Salt Lake City 

Utah 

Lake 

111° 110° 

UINTA MOUNTAINS 

This paper summarizes the thermal maturity of the Mesaverde Group (Upper Cretaceous) in the Uinta basin, 

Utah (fig. 12). Using vitrinite reflectance (Rm), two maps 

show the Rm of rocks at the base and top of the Mesaverde Group. A map of elevation to 0.75 percent Rm illustrates the position for onset of gas generation for type III 

kerogen and the formation in which it occurs. Cross sections illustrate the stratigraphy, types of kerogen, levels 

PICEANCE 

CREEK 

BASIN 

UINTA 

BASIN 

39° 

~t----2.._,s--r1 __ s..._,o_K_,IL~METERS 

0 20 40 MILES 

Approximate outline of 

Uinta and Piceance Creek 

basins 

Figure 12. Index map of Uinta and Piceance basins in Utah and Colorado. Locations of cross sections A-A' (fig.13), B-8' 

(fig. 14), and Book Cliffs are shown. 

1 U.S. Geological Survey, Denver, Colo. 

70 The Petroleum System-Status of Research and Methods, 1992 
of thermal maturity, and the position of hydrocarbonproducing zones of lower Tertiary and Upper Cretaceous 

formations within the Uinta basin. 

This study is based on data collected as part of the 

U.S. Department of Energy's Western Tight Gas Program and the U.S. Geological Survey's Onshore Oil and 

Gas and Evolution of Sedimentary Basins Programs. The 

data base comprises several hundred core and cutting 

samples of coal and carbonaceous shale that were analyzed for vitrinite reflectance and Rock-Eva! pyrolysis. 

A large part of the present study is based on Johnson 

and Nuccio (in press), Nuccio and Johnson (1986, 1988), 

and the first author's unpublished data. 

KEROGEN TYPE AND SOURCE ROCK 

POTENTIAL 

Several models have been developed relating the 

generation of hydrocarbons to types of kerogen and thermal maturity (Tissot and others, 1974; Dow, 1977, Waples, 1980, 1985). Three general types of kerogen have 

the potential, under optimum conditions, to generate hydrocarbons: type I, alginite-sapropelic or lipid-rich; 

type II, exinite-phytoplankton, zooplankton, and othe:r 

microorganisms, and type III vitrinite-huminite (terrestrial plant debris). 

Type I kerogen is hydrogen-rich, occurs primarily 

in marine and lacustrine rocks, and generates mainly oill 

during catagenesis. The onset of oil generation from type 

I kerogen varies depending on the model one chooses. 

There is no absolute point at which hydrocarbon begins to 

be generated, and it probably begins over a range of Rm 

values depending on the specific type of organic matter. 

Dow (1977) used 0.50 percent Rm as the onset of oil generation for type I kerogen, while Anders and Gerrild 

(1984) and Tissot and Welte (1984) used 0.70 percent Rm. 

Type II kerogen occurs mainly in marine rocks, but 

can occur in lacustrine rocks as well, and generates 

mostly oil during catagenesis. Waples (1985) states tha.t 

oil generation begins over a range of Rm values of about 

0.45 to 0.50 percent for high-sulfur kerogen to 0.60 percent for "typical" type II kerogen. 

Huminite and vitrinite or type III kerogen is oxygen-rich and hydrogen-poor, occurs mainly in terrestrial, 

marginal lacustrine, or marginal marine rocks, and generates mainly methane gas during maturation. For typ1~ 

III kerogen, vitrinite reflectance is the best and most 

widely used measure of thermal maturity. Two important 

Rtn thresholds, 0.75 and 1.10 percent, are used to defin1~ 

regions of gas generation from type III kerogen. An Rm 

of 0. 7 5 percent represents the maturity required for the. 

onset of significant gas generation (Juntgen and Karweil, 

1966; Juntgen and Klein, 1975). Gas accumulations 

found in rocks with an Rm less than 0.75 percent contain 

either early microbial gas or thermal gas migrated in 

from more mature source rocks. In the Piceance basin, it 

appears that low-permeability Mesaverde rocks have 

negligible gas production where the Mesaverde has an 

Rm less than 0.73 percent (Johnson, 1989; Johnson and 

others, 1987). An Rm of 1.10 percent represents the level 

of maximum gas expulsion from type III kerogen 

(Meissner, 1984). The upper limit of maturity for gas 

preservation is still unknown, but could be as high as 4.0 

percent Rm (Waples, 1980). 

Types I, II, and III kerogen are present in the 

Green River Formation (Eocene), and these rocks have 

generated large amounts of oil and gas in the Uinta basin 

(cross section A-A', fig. 13; B-B', fig. 14). The thick 

Mancos Shale (Upper Cretaceous) is probably similar to 

the Mancos in the Piceance basin, where it contains significant amounts of types II and III kerogen and has generated oil and gas (Johnson and Rice, 1990). The 

nonmarine to nearshore marine Mesaverde Group contains dominantly type III kerogen and has the potential 

to generate large amounts of methane gas (Pitman and 

others, 1987). 

RM MAP OF BASE OF MESAVERDE GROUP 

The Rm map at the base of the Mesaverde Group 

shows a trend of increasing maturity from south to north 

(fig. 15). This trend generally follows the structural configuration of the base of the Mesaverde; this indicates 

maturity was set prior to or during early stages of structural movement. In some areas, however, the Rm lines 

cut across structure indicating that maturity continued 

during or for some time after structural movement. V ariation in heat flow could cause this crossing of Rm lines, 

but most likely toward the deepest part of the basin 

where the Tertiary overburden is thickest, and where the 

effects of structural movement and erosion are less, thermal maturity at the base of the Mesaverde continued 

during or after uplift and erosion which began 10 Ma. 

On the flanks of the basin, however, maturity may have 

been "frozen" at pre-structural levels. 

Four Rm lines and three zones of hydrocarbon generation are shown in figure 15. The 0.65 percent Rm reference line shows the thermal maturity at the base of the 

Mesaverde around the edge of the basin. The areas of 

the basin that are not mature enough for significant gas 

generation (<0.75 percent Rm) are shown by the light 

stipple pattern. The 0. 75 percent Rm line indicates the 

maturity for onset of significant gas generation from 

type III kerogen at the base of the Mesaverde. The area 

between 0.75 percent and 1.10 percent Rm (darker stipple) is the area of potential gas generation and accumulation in Mesaverde reservoirs. The area north of 1.10 

percent Rm (darkest pattern) is the zone of maximum gas 

Thermal Maturity of the Mesaverde Group, Uinta Basin, Utah 71 
generation and expulsion. The upper limit of gas generation in the northern and deepest, undrilled part of the 

basin is currently unknown. The 0.65 percent and 1.50 

percent Rm lines are for reference only. 

The base of the Mesaverde is greater than 0.75 

percent Rm over a large area of the Uinta basin. Except 

for the margins of the basin, where subsidence and 

amount of deposition were less, gas was probably being 

generated in Paleocene or early Eocene time as Tertiary 

sediments were being deposited. This generation continued until 10 Ma, when uplift and erosion caused regional 

cooling. Effects of uplift and erosion were not as great 

in the deepest part of the basin, and if temperatures were 

still great enough, and kerogen was available (not 

Southwest 

A 

Sunnyside 

Tar Sand 

Natural Buttes 

Island 

S Alluvial: fluvial, type Ill 

E2J Marginal lacustrine: fluvial and lake; type I and II 

D Open lacustrine: lake; type I 

---- Mahogany oil-shale bed 

- - - - - Middle marker 

Top of carbonate marker 

- - - Eocene-Paleocene boundary 

--- - - - Lower marker 

Fault-Arrows show direction of relative movement 

Petroleum-bea~ing interval projected into line of section 

"cooked out"), gas generation may have continued after 

10 Ma and may be actively generating today. It is likely 

that this gas was trapped in "tight reservoirs" throughout 

the generation history of the Mesaverde, and the areas of 

overpressuring in the basin today may mark the areas of 

active generation. 

RM MAP OF TOP OF MESAVERDE GROUP 

The Rm map at the top of the Mesaverde Group 

also shows a trend of increasing maturity from south to 

north (fig. 16). Rm lines generally follow the structural 

configuration of the top of the Mesaverde, suggesting 

that the observed maturity was reached prior to or during 

Northeast 

Pariette Bench 

Duchesne, Monument 

Altamont-Bluebell Field (A-B) 

Redwash Field (RW) 

Horseshoe Bend 

FEET 

6000 

3000 

0 

METERS 

2000 

1000 

4 8 

5 10 15 

12 16 20 MILES 

20 KILOMETERS 

A' 

9000 

3000 

SEA 

LEVEL 

-6000 

Figure 13. Generalized cross section A-A' from outcrops on southwest flank of Uinta basin, through Duchesne and 

Altamont-Bluebell oil fields, to north-central part of Uinta basin, Utah (modified from Fouch, 1975). Figure also contains 

commonly used subsurface stratigraphic markers, types of kerogen (types I, II, and Ill), and principal fields. Location of 

cross section on figure 12. 

72 The Petroleum System-Status of Research and Methods, 1992 
Southwest 

B 

AltamontBluebell 

0.50% Rm 

0.75% Rm 

2.0% Rm 

~ 

~ 

• 0 

TERTIARY 

Green River Fm.; open lake; 

type I 

Green River Fm.; marginal 

lacustrine; mixed lake and 

fluvial; types I, II, and Ill 

Colton and Wasatch Fms.; 

alluvial; type Ill 

0 0 

LJE] 

El 

Ill 

~Kcbh/ I 

Southeast 

0 

CHETACEOUS 

Pariette 

Bench 

• 

Nonmarine 

• 

Tuscher and Farrer Fms.; braided 

and meandering fluvial; type Ill 

Ne!slen Fm.; coastal plain; type Ill 

Marine 

Se,go Fm.; shore, nearshore 

Mancos Shale; open marine; 

types II and Ill 

Buck Tongue of Mancos Shale; 

types II and Ill 

Castlegate Sandstone and Blackhawk Fm.; 

littoral and shelf; type Ill 

B' 

Island 

Mahogany 

oil-shale bed 

Carbonate marker 

Eocene 

Paleocene 

0 Gas well 

• Oil well 

0 Dry hole 

...... Oil-producing zone 

<{ Gas-producing zone 

FEET METERS 

6soT 2oo~ O ~6 KILOMETERS 

16 MILES 

Figure 14. Cross section 8-B' from Altamont-Bluebell area (deepest part of basin) southeastward to Island gas field. Rm 

isoreflectance lines and hydrocarbon-producing zones are superimposed on cross section. Types I, II, and Ill are types of 

organic matter in the rocks. 

Thermal Maturity of the Mesaverde Group, Uinta Basin, Utah 73 
the early stages of final structural movement 10 Ma. As 

with the map for the base of the Mesaverde (fig. 15), Rm 

lines in some areas cut across structure. This indicates 

continued maturation during or after structural movement. Rm lines on the top of the Mesaverde Group 

equivalent to those at the base are located farther to the 

north, suggesting a larger area of less mature rock at the 

top of the Mesaverde. This pattern is a direct result of 

less depth of burial (up to several thousand feet) on the 

top of the Mesaverde. 

0 Price 

0 10 20 MILES 

I I I 

0 1 0 20 KILOMETERS 

Five Rm isoreflectance lines and three zones of hydrocarbon generation are shown in figure 16. The 0.50 

percent and 0.60 percent Rm lines are for reference, and 

show the general maturity for the top of the Mesaverde 

where it crops out around the edge of the basin. For the 

area south of the 0.75 percent Rm line (light stipple pattern), one would not expect significant gas generation 

from source rocks located near the top of the Mesaverde. 

The area between the 0.75 percent and 1.10 percent Rm 

(medium stipple pattern) lines is the zone of significant 

Figure 15. Vitrinite reflectance (RnJ map showing thermal maturity at base of Mesaverde Group, Uinta basin, Utah. Map 

indicates areas of no gas generation (<0.75 percent Rm or light stipple pattern), onset of significant gas generation (0.75-

1.1 0 percent Rm or medium stipple pattern), and maximum gas generation and expulsion (> 1.10 percent Rm or dark 

pattern). Black dots indicate location of bore-hole or outcrop sample. 

7 4 The Petroleum System-Status of Research and Methods, 1992 
gas generation, and the area north of the 1.10 percent B~ 

line (darkest pattern) is the zone of maximum generation 

and expulsion for type III kerogen source rocks near the 

top of the Mesaverde. The 2.0 percent Rm line is for reference only, but indicates maturity at the top of the M~esaverde in the most deeply drilled part of the basin. As 

discussed earlier for the base of the Mesaverde, the upper limit for gas preservation is poorly defined. 

The areal extent of rocks with greater than 0.75 

percent Rm is less for the top than that at the base of the 

0 

I 

0 10 

0 Price 

Zero edge of the 

Mesaverde Group 

10 

I 

I 

20 

I 

20 

I 

30 KILOMETERS 

30 MILES 

I 

Mesaverde and occurs further north in the deeper part of 

the basin. Again this pattern is due to less depth of burial on the top of the Mesaverde. Therefore, gas generation for the top of the Mesaverde began later than for the 

base, probably not until Eocene or Oligocene time. This 

timing agrees with Pitman and others (1987), who constrained timing of gas generation from the Upper Cretaceous Neslen and Blackhawk Formations to Oligocene 

and Miocene time. As with the base of the Mesaverde, 

gas generation continued through the Tertiary and was 

Figure 16. Vitrinite reflectance (Rm) map showing thermal maturity at top of Mesaverde Group, Uinta basin, Utah. Map 

indicates areas of no gas generation (<0.75 percent Rm or light stipple pattern), onset of significant gas generation (0.75-

1.1 0 percent Rm or medium stipple pattern), and maximum gas generation and expulsion (> 1.10 percent Rm or dark 

pattern). Black dots indicate location of bore-hole or outcrop sample. 

Thermal Maturity of the Mesaverde Group, Uinta Basin, Utah 75 
being emplaced into nearby reservoirs. Since 10 Ma, gas 

generation ceased at the top of the Mesaverde horizon in 

many parts of the basin; however, in the deeper parts, 

active generation is still possible today. 

MAP SHOWING ELEVATION TO 0.75 

PERCENT RM 

Figure 17 is a map showing the elevation from sea 

level to the 0.75 percent Rm line; the threshold for sigI 

~ 

I 

I 

0 

I 

I 

L, 

I 

0 Price 

10 

I 

I 

20 

I 

0 10 

I 

20 30 KILOMETERS 

Altamont 

0 

30 MILES 

I 

nificant gas generation. The 0.75 percent R.n line cuts 

across formation boundaries; it moves up stratigraphically to the north. For example, in the southernmost part 

of the basin, 0.75 percent Rm occurs in the Mancos 

Shale, whereas in the northern part of the basin near Altamont, 0.75 percent Rm occurs between the middle and 

carbonate markers of the Green River Formation (fig. 

14). The reason for this upsection movement is related 

generally to the structural movements and variations of 

burial depth in the basin. After final movement, the basin flanks were higher, and due to erosion there was less 

I 

I 

10 

~a 

:cl~ 

~!o ::JI.....J lo 

:u 

I 

Figure 17. Elevation (in feet) relative to sea level of 0.75 percent Rm line (onset of significant gas generation), Uinta 

basin, Utah. Shaded area indicates where 0.75 percent Rm line occurs in Mesaverde Group. South and east of shaded 

area, line is in pre-Mesaverde Group rocks. North of shaded area, line falls within Tertiary rocks. Black dots indicate 

location of bore-hole or outcrop sample. 

76 The Petroleum System-Status of Research and Methods, 1992 
overburden present. However in the center of the basin, 

where the effect of uplift and erosion was less, and more 

overburden was present, the rocks continued to mature. 

This caused an apparent raising of the Rm lines to stmtigraphically higher positions. 

The shaded pattern in figure 17 represents the area 

where the elevation of the 0.75 percent Rm line occurs in 

the Mesaverde Group. This map is useful in that it approximates the elevation (easily converted to depth) one 

would drill to encounter the threshold for significant gas 

generation, and which formation it could be found in. 

CROSS SECTION SHOWING RM LINES AND 

PRODUCTION 

Figure 14 shows Rm lines superimposed on a stratigraphic cross section through the Uinta basin. The cross 

section B-B' extends from the Altamont-Bluebell area 

(deepest part of the basin) southeastward to the Island 

gas field. As discussed earlier, the Rm lines climb stratigraphically going northward, toward the deeper part of 

the basin. The 0.50 percent Rm line shows where types I 

and II kerogens should be mature enough for oil generation. It is interesting to note that the oil-producing zones 

are found where mixed types I, II, and III kerogen and 

the optimum maturity range for oil generation (>0.50 

percent Rm) occur. The 0.75 percent Rm line indicates 

where the onset of significant gas generation for type HI 

kerogen should occur. Not surprisingly, the gas-producing zones coincide with type III kerogen and an ~ of 

around 0.75 percent. The 1.10 percent ~ line shows 

where maximum gas generation and expulsion would be 

found for type III kerogen. The 2.0 percent Rm line represents the level of thermal maturity for the top of tne 

Mesaverde in the deeper part of the basin. 

REFERENCES CITED 

Anders, D.E., and Gerrild, P.M., 1984, Hydrocarbon generation 

in lacustrine rocks of Tertiary age, Uinta Basin, Utahorganic carbon, pyrolysis yield, and light hydrocarbons, in 

Woodward, Jane, Meissner, F.F., and Clayton, J.L. eds., 

Hydrocarbon source rocks of the Greater Rocky Mounta.in 

Region: Denver, Rocky Mountain Association of Geo]ogists, p. 513-529. 

Anders, D.E., Johnson, R.C., and Palacas, J.G., in press, Th€~rmal maturity in the Uinta basin, Utah, in Fouch, T.D., 

Nuccio, V.F., and Chidsey, T.C., eds., Hydrocarbon and 

mineral resources of the Uinta basin, Utah and Colorado: 

Utah Geological Association Guidebook. 

Dow, W.G., 1977, Kerogen studies and geological interpretations: Journal of Geochemical Exploration, v. 7, p. 79-99. 

Fouch, T.D., 1975, Lithofacies and related hydrocarbon accumulations in Tertiary strata of the western and central 

Uinta basin, Utah, in Bolyard, D.W., ed., Symposium on 

deep drilling frontiers of the central Rocky Mountains: 

Denver, Rocky Mountain Association of Geologists, p. 

163-174. 

Johnson, R.C., 1989, Geologic history and hydrocarbon potential of Late Cretaceous-age, low permeability reservoirs, 

Piceance basin, western Colorado: U.S. Geological Survey 

Bulletin 1787-E, p. E1-E51. 

Johnson, R.C., Crovelli, R.A., Spencer, C.W., and Mast, R.F., 

1987, An assessment of gas resources in low-permeablilty 

sandstones of the Upper Cretaceous Mesaverde Group, 

Piceance basin, Colorado: U.S. Geological Survey OpenFile Report 87-357, 165 p. 

Johnson, R.C., and Nuccio, V.F., in press, A surface vitrinite 

reflectance study of the Uinta-Piceance basin area, westem Colorado and eastern Utah and its implications for the 

development of Laramide basins and uplifts: U.S. Geological Survey Bulletin, 48 p. 

Johnson R.C., and Rice, D.D., 1990, Occurrence and geochemistry of natural gases, Piceance basin, northwest Colorado: 

American Association of Petroleum Geologists Bulletin, v. 

74, p. 805-829. 

Juntgen, H., and Karweil, J., 1966, Gasbildung und 

gasspeicherung in steinkohlenflozen, Part I and IT: Erdol 

and Kohle, Erdgas, Petrochemie, v. 19, p. 251-258, 339-

344. 

Juntgen, H., and Klein, J., 1975, Entstehung von erdgas gus 

kohligen sedimenten: Erdol and Kohle, Erdgas, 

Petrochemie, Erganzungsband, v. 1, p. 52-69. 

Meissner, F.F., 1984, Cretaceous and Lower Tertiary coals as 

source for gas accumulation in the Rocky Mountain area, 

in Woodward, Jane, Meissner, F.F., and Clayton, J.L., 

eds., Hydrocarbon source rocks of the greater Rocky 

Mountain Region: Denver, Rocky Mountain Association 

of Geologists Symposium, p. 401-432. 

Narr, W., and Currie, J.B., 1982, Origin of fracture porosityExample from Altamont Field, Utah: American Association of Petroleum Geologists Bulletin, v. 66, p. 1231-

1247. 

Nuccio, V.F., and Johnson, R.C., 1986, Thermal maturity map 

of the Lower part of the Upper Cretaceous Mesaverde 

Group, Uinta basin, Utah: U.S. Geological Survey Miscellaneous Field Studies Map MF-1842, one plate. 

---1988, Surface vitrinite reflectance map of the Uinta, 

Piceance, and Eagle basins area, Utah and Colorado: U.S. 

Geological Survey Miscellaneous Field Studies Map MF2008-B, 21 p., one plate. 

Pitman J.K., Franczyk, K.J., and Anders, D.E., 1987, Marine 

and nonmarine gas-bearing rocks in Upper Cretaceous 

Blackhawk and Neslen Formations, eastern Uinta basin, 

Utah: American Association of Petroleum Geologists Bulletin, v. 71, p. 76-94. 

Sweeney, J.J., Burnham, A.K., and Braun, R.L., 1987, A model 

of hydrocarbon generation from type I kerogen: Application to Uinta basin, Utah: American Association of Petroleum Geologists Bulletin, v. 71, p. 967-985. 

Tissot, B.P., Deroo, G., and Hood, A., 1978, Geochemical 

study of the Uinta basin: Formation of petroleum from the 

Green River Formation: Geochimica et Cosmochimica 

Acta, v. 42, p. 1469-1485. 

Thermal Maturity of the Mesaverde Group, Uinta Basin, Utah 77 
Tissot, B.P., Durand, B., Espitalie, J., and Combaz, A., 1974, 

Influence of nature and diagenesis of organic matter in 

formation of petroleum: American Association of Petroleum Geologists Bulletin, v. 58, p. 499-506. 

Tissot, B.P., and Welte, D.H., 1984, Petroleum formation and 

occurrence, second edition: Berlin, Springer-Verlag, 699 p. 

78 The Petroleum System-Status of Research and Methods, 1992 

Waples, D.W., 1980, Time and temperature in petroleum formation: Application of Lopatin's method to petroleum exploration: American Association of Petroleum Geologists 

Bulletin, v. 64, p. 916-926. 

---1985, Geochemistry in petroleum exploration: Boston, International Human Resources Development Corporation, 232 p. 
NERSL-National Energy Research Seismic Library 

By David J. Taylor1 

Geology, a science dealing with the history of the 

Earth as recorded in its rocks, strives to visualize sub:mrface structure and stratigraphy. Early geologic infonnation came mainly from extrapolation of surface geology 

into the subsurface and from rock samples brought up 

during drilling operations. The application of physic8 to 

geologic science offered new and better ways to see below ground level. The evolution of modem geophysical 

techniques, especially multichannel seismic-reflection 

imagery, now supplies earth scientists with clearer pictures of subsurface geology. The U.S. Geological Survey 

(USGS) started collecting multichannel seismic-reflection data in the early 1970's to provide its programs with 

suitable subsurface information. Much of this data, acquired directly or through contract, is information available in the public domain. 

In the early 1980's Federal budgets for earth science research began to shrink, and money needed to acquire new seismic-reflection data became increasingly 

scarce. The inability to acquire new seismic data has 

started to jeopardize the ability of the USGS to thoroughly fulfill some of its key missions. A 1988 National 

Research Council (NRC) study of USGS energy-related 

programs recommended that the USGS develop a network of seismic-reflection data from both presently 

available and newly acquired seismic data (National 

Academy Press, 1988). The NRC report specifically stated that the USGS develop a scheme to catalog available 

seismic data and provide a means to access the data. In 

response to the NRC recommendations and the need to 

develop a data management policy for its digital multichannel seismic-reflection data inventory, the USGS 

established the National Energy Research Seismic Library, or NERSL, in late 1989. 

A reliable picture of the subsurface is usually helpful 

when solving most geologic problems. The purpose of the 

NERSL is to provide earth scientists in government, indiUstry, and academia with data needed to construct these pictures. Several critical USGS research programs, such as 

the Deep Continental Studies program, the Offshore Geo1 U.S. Geological Survey, Denver, Colo. 

logic Framework program, the Evolution of Sedimentary 

Basins program, the Geologic Risk Assessment program, 

and the Onshore Oil and Gas program, have benefited 

from having seismic data available to them. The aim in 

establishing a national seismic library is to supply researchers throughout the scientific community with data 

that are necessary but usually hard to obtain. 

The NERSL being a repository for unprocessed and 

processed multichannel seismic-reflection data can provide 

raw materials not only to those trying to solve specific geologic problems but also to those who are conducting research in the development of new reflection seismic data 

processing techniques. Finding solutions to unusual geologic problems often drives the development of new technology. Therefore, supplying the data needed to solve 

geologic problems and stimulate development of new technology is another goal of the NERSL. 

Regional grids of seismic-reflection data have provided USGS scientists with information leading to the 

formulation of new geologic concepts and the enhancement of previous work. A good example is the San Juan 

basin tectonic framework study under the Evolution of 

Sedimentary Basins program. Through purchase of proprietary information and contributions from private industry, USGS scientists were able to build a modest 

regional grid of seismic lines in the basin. Initially, a 

fault map of the thrusted northwestern edge of the basin 

was produced from the reprocessing and interpretation of 

the data (Taylor and Huffman, 1988). Using the larger 

grid of proprietary seismic data allowed this original interpretation to be extended and resulted in the creation 

of a basement fault map covering most of the basin area. 

This fault map was used to develop a story for the evolution of the San Juan basin and surrounding area (Huffman and Taylor, 1989). Correlation of the basement 

faults with the location of hydrocarbon production in the 

San Juan basin hints that movement along these faults 

through time may have influenced deposition creating 

the conditions needed to form accumulations of mineral 

and petroleum resources (Phelps and others, 1986; Huffman and Taylor, 1990). Similar USGS studies are in 

progress wherever seismic databases are available, and 

the objective of the NERSL is to supply the seismic data 

bases necessary to carry out these investigations. 

NERSL-National Energy Research Seismic Library 79 
Other government and nongovernment agencies have 

large multichannel seismic-reflection data libraries. Cornell 

University's Consortium for Continental Reflection Profiling (COCORP) makes available to the public its inventory 

of deep seismic reflection data (Nelson, 1988). Most government-collected geophysical data is offered to the public 

through the National Oceanic and Atmospheric Administration's (NOAA) National Geophysical Data Center 

(NGDC). There are also many small data brokerage firms 

operating that sell limited grids of proprietary seismic-reflection data. There has never been an attempt made to 

establish a national repository containing both field and 

processed digital seismic-reflection data collected from government and nongovernment sources which allows public 

access. All data released through COCORP, ~OAA-NGDC, 

or private industry is distributed on some form of magnetic 

tape, and costly processing systems are usually required to 

read these tapes. A design objective for the NERSL is to 

allow those owning inexpensive computer systems access 

to the seismic data base. Since the repository will hold the 

actual unprocessed field data, and its corresponding processed version, there needs to be a widely available low-cost 

way for the scientist to examine the data. Therefore, processed data will be distributed on commonly used compact 

disks with read-only memory, or CD-ROM' s. 

Low-cost CD-ROM readers that can be attached to 

standard personal computers are now available. Software 

accessible on the CD-ROM will allow the scientist to display, in color or black and white, the processed seismic 

sections with a map showing the location of the data. The 

software will also let the user scale the data, zoom in to 

produce a detailed display on a chosen part of the data, 

and plot the data to a ·low-cost dot-matrix printer. A description of the data and instructions on using the software 

resides on the disk in a file that can be displayed or printed. This information is also available as a USGS OpenFile Report (Hutchinson and others, 1990). 

The NERSL CD-ROM has been designed to hold 

the actual processed digital information and not just 

scanned images of paper displays. The major advantage 

compared to the COCORP atlas or NOAA-NGDC notices is that digital data can be downloaded from the NERSL CO-ROM's. The COCORP atlas, for example, 

contains only small scale paper copies of processed data, 

including information on buying magnetic tapes containing the original field data. The NERSL CD-ROM provides processed data already in an industry standard 

format on compact high-capacity media at a greatly reduced cost. 

After retrieving the digital information from the 

NERSL CD-ROM, the user can immediately process or 

redisplay the data using systems offering more advanced 

capabilities. Being able to use inexpensive hardware and 

public domain software to view and access large 

amounts of seismic-reflection data should provide users 

80 The Petroleum System-Status of Research and Methods, 1992 

throughout government, academia, industry, and the scientific community in general with information needed to 

carry on a variety of important research projects. 

Future enhancements to the NERSL CD-ROM 

products may include the addition of public domain well 

information located on or near the seismic lines residing 

on the disk. Appended software will allow the user to 

convert the well data into a synthetic seismogram which 

can be correlated with the actual seismic data. The well 

data would reside on the CD-ROM in an industry standard format so that it could be accessed and used by most 

commercial well log processing software packages. This 

feature would provide the scientist with the data and 

tools to correlate actual geologic information to seismicreflection events. 

NERSL developers are exploring the feasibility of 

using CD-ROM media for the storage and distribution of 

the original unprocessed field data. This may provide a 

solution to potential NERSL data storage problems and 

simultaneously provide the researcher raw data in a compact format which can be processed using the newest 

techniques. Occasional reprocessing of older data using 

state-of-the-art technology often supplies innovative solutions to geologic problems. 

REFERENCES CITED 

Huffman, A.C., Jr., and Taylor, D.J., 1989, San Juan basin 

faulting-More than meets the eye [abs.]: American Association of Petroleum Geologists Bulletin, v. 73, no. 9, p. 

1161. 

--1990, Basement fault control on the occurrence and development of San Juan basin energy resources [abs.]: Geological Society of America Abstracts with Programs, v. 

23, no. 4, p. 34. 

Hutchinson, D.R., Taylor, D.J., and Zihlman, F.N., 1990, U.S. 

Geological Survey multichannel seismic data National Energy Research Seismic Library NERSL CD-ROM 1: U.S. 

Geological Survey Open-File Report 90-699, 15 p. 

National Research Council, 1988, Energy-related research in 

the U.S. Geological Survey: Washington, D.C., National 

Academy Press, 95 p. 

Nelson, K.D., ed., 1988, The COCORP Atlas: Ithaca, N.Y., 

Cornell University-Institute for the Study of the Continents, v. 1, 8 p. 

Phelps, W.T., Zech, R.S., and Huffman, A.C., Jr., 1986, in 

Turner-Peterson, C.E., Santos, E.S., and Fishman, N.S., 

eds., A basin analysis case study-The Morrison Formation, Grants Uranium region, New Mexico: American Association of Petroleum Geologists Studies in Geology, no. 

22, p. 145-159. 

Taylor, D.J., and Huffman, A.C., Jr., 1988, Overthrusting in the 

northwestern San Juan basin, New Mexico, a new interpretation of the hogback monocline [abs.], in Carter, L.M., ed., 

USGS research on energy resources-1988 Pro'gram and 

abstracts: U.S. Geological Survey Circular 1025, p. 60. 
Branch of Petroleum Geolog·y-1989 through 1990 

Bibliography 

Compiled by Helen Y. Colburn1 

Agena, W.F., Lee, M.W., and Grow, J.A., 1989, Reprocessing 

of the COCORP data recorded across the Wichita MOlmtain uplift and the Anadarko basin in southern Oklahoma: 

U.S. Geological Survey Open-File Report 89-357, 20 p. 

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F.A., 1989, Extended cross-correlation methods for df~ep 

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Anders, D.E., 1990, Thermal maturation in the Uinta basin, 

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petroleum system--Status of research and methods, 1990: 

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Ball, M.M., Martin, R.G., and Foote, R.Q., 1990, Reassessmc~nt 

of tectonic history of the eastern Gulf of Mexico, in 

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on Mineral and Energy Resources: U.S. Geological Survey 

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1989, Reassessment of the tectonic style and crustal character in the foundation of south Florida and the westc::rn 

Florida shelf [abs.]: American Association of Petroleum 

Geologists Bulletin, v. 73, no. 3, p. 330. 

1 U.S. Geological Survey, Denver, Colo. 

Barker, C.E., 1989, Temperature and time in the thermal maturation of sedimentary organic matter, in Naeser, N.D., and 

McCulloh, T.H., eds., Thermal history of sedimentary basins-Methods and case histories: New York, SpringerVerlag, p. 74-98. 

Barker, C.E., 1989, Review of "Cathodoluminescence of Geological Materials," by D.J. Marshall: Society of Luminescent Microscopy and Spectroscopy Newsletter, v. 1, no. 1, 

p. 3-4. 

Barker, C.E., 1989, Techniques in luminescence microscopy: 

Society of Luminescent Microscopy and Spectroscopy 

Newsletter, v. 1, no. 2, 6 p. 

Barker, C.E., 1989, Fluid inclusion evidence for 

paleotemperatures within the Mesaverde Group, Multiwell 

Experiment site, Piceance basin, Colorado, Chapter M, in 

Law, B.E., and Spencer, C.W., Geology of tight gas reservoirs in the Pinedale anticline area, Wyoming, and at the 

Multiwell Experiment site, Colorado: U.S. Geological Survey Bulletin 1886, p. M1-M11. 

Barker, C.E., 1989, Rock-Eval analysis of sediments and ultimate analysis of coal, Mesaverde Group, Multiwell Experiment site, Piceance basin, Colorado, Chapter N, in 

Law, B.E., and Spencer, C.W., eds., Geology of tight gas 

reservoirs in the Pinedale anticline area, Wyoming, and at 

the Multiwell Experiment site, Colorado: U.S. Geological 

Survey Bulletin 1886, p. N1-N11. 

Barker, C.E., 1989, Geothermics applied to the reconstruction 

of subsurface temperature, in Magoon, L.B., ed., The petroleum system-Status of research and methods, 1990: 

U.S. Geological Survey Bulletin 1912, p. 36-42. 

Barker, C.E., 1990, Reconnaissance fluid inclusion study, 

Amoco Eischeid #1 well, Defiance basin, Midcontinent 

Rift System, Iowa: Iowa State Geological Survey Special 

Report Series, no. 2, p. 169-174. 

Barker, C.E .• 1990, Evidence for a geologically rapid increase 

and stabilization of vitrinite reflectance in response to a 

short-term temperature increase, Cerro Prieto geothermal 

system, Mexico, in Carter, L.M.H., ed., USGS research on 

energy resources-1990, Program and abstracts, Sixth 

V.E. McKelvey Forum on Mineral and Energy Resources: 

U.S. Geological Survey Circular 1060, p. 4-5. 

Barker, C.E., and Coury, A.B., 1989, Abstracts of the U.S. 

Geological Survey, Central Region, 1989 Poster ReviewCollected abstracts of selected poster papers presented at 

scientific meetings: U.S. Geological Survey Open-File Report 89-644, 26 p. 

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Geological Survey, Central Region, 1990 Poster Review: 

U.S. Geological Survey Open-File Report 90-656, 35 p. 

Barker, C.E., and Crysdale, B.L., 1990, Stabilization of kerogen thermal maturation-Evidence from geothermometry 

and burial history reconstruction, Niobrara Limestone, 

Berthoud oil field, western Denver basin, Colorado, in 

Carter, L.M.H., ed., USGS research on energy resources1990, Program and abstracts, Sixth V.E. McKelvey Forum 

on Mineral and Energy Resources: U.S. Geological Survey 

Circular 1060, p. 5-6 [Also, American Association of Petroleum Geologists Bulletin, v. 74, no. 5, p. 605]. 

Barker, C.E., and Dalziel, M.C., 1989, Using cathodoluminescence to map regionally zoned carbonate cements 

occurring in diagenetic aureoles above some oil reservoirs, 

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400 300 200 100 Ma 

PALEOZOIC MESOZOIC I CEN. Rock 

Unit 

Thick 

Fm. 

1-

2 

--------===f::;~-· ~~· George Sh. Top of oil window, r---::=====----=~~/1---;;:;::~:1 ,__ _-- :;::. Boar Ss. 

Top of gas window, " __ -- ----- - --- .::.:: 

' _ - - • iS#H'"?i Deer Sh. 

400 

,r-____ ------ ·o :·: ElkFm. 

f Critical Moment 

----GEOGRAPHIC EXTENT OF PETROLEUM SYSTEM ___ ____,_ 

\ 

STRATIGRAPHIC EXTENT OF 

PETROLEUM 

, ..... ~'!~!.E~. .. . .. . .. -,_,_,. 

' ,<:-' .· ~:Ji4 :~. ~: .. ~~~;-· 

' • ' • ' ,- - Petroleum accumulation 

' , -' -~~S~~£~1 j Fold and thrust belt-Arrows 

indicate direction of relative motion 

300 200 100 Ma 

D Overburden rock 

- Sealrock 

1'::.:-:'' .. : ·J Reservoir rock 

Source rock 

PALEOZOIC MESOZOIC CEN. 

K p 

Source Rock 

Reservoir Rock 

Seal Rock 

Critical Moment 

onFigure 1. Burial history chart shows critical 

moment for Deer-Boar(.) petroleum system. 

Rock unit names are fictitious. Lithologies 

shown: conglomerate-Thick, Placer, and Elk 

Formations (Fm.); shale-George Shale (Sh.); 

sandstone-Boar Sandstone (Ss.). 

Figure 2. Geographic extent of Deer-Boar(.) 

petroleum system at critical moment. 

EXPLANATION 

~ Line of cross section 

....b........./ Thrust bett-Sawteeth on upper plate 

....I.....J_ Fault-Hachures on downthrown block 

Plunging anticline 

Plunging syncline 

Top of oil window 

o o o Top of gas window 

Direction of petroleum migration 

.. Petroleum accumulation 

c=J Source rock 

[ :\': /:}I Reservoir rock 

Figure 3. Geologic cross section showing 

stratigraphic extent of Deer-Boar(.) petroleum 

system at critical moment. 

Figure 4. Events chart for Deer-Boar(.) petroleum system.