Jhe PetroreUm Sys:terrn~: 

Status of Researc" and 

Methods, 1990 
Petroleum System Definition and Classification Scheme 

A petroleum system encompasses a 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 concentrated occurrences 

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

sandstone, fractured shale, and coal; and condensates, crude oils, heavy oils, and solid bitumen found in reservoirs in siliciclastic and 

carbonate rocks. System describes the interdependent geologic elements that create oil and gas accumulations. These elements 

include a petroleum source rock, migration path, reservoir rock, seal, and trap; and the geologic processes that create each of these 

basic elements. All these elements 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 the basic elements are known to occur or are thought 

to occur. 

Characteristics and Limits.-The stratigraphic, areal, and temporal extent of the petroleum system is specific. Stratigraphically, the system includes the following rock units: a petroleum source rock, rocks through which migration has occurred, a sealed 

reservoir rock (trap), and the rock overburden (time and temperature) required for maturity. The areal extent of the petroleum 

system is defined by a line that circumscribes the mature source rock and all oil and gas deposits, conventional and unconventional, 

originating from that source. Since microbial gas originates from immature source rocks, the gas deposits themselves or the geologic 

setting defines the extent of the system. 

The events of a petroleum system are defined by two periods of geologic time, the duration time and the preservation time. 

The duration is the time required to form a petroleum system. If the source rock is the first or oldest unit deposited and the 

overburden 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 of the petroleum system. For example, a Devonian source rock (380-390 Ma) is buried by 

Pennsylvanian and Permian rocks (250-290 Ma) to maximum depth in the Late Permian(250 Ma); expulsion (primary migration) 

of hydrocarbons occurs during the Permian (250-275 Ma). These hydrocarbons migrate (secondary) and accumulate in reservoirs 

of Pennsylvanian age (300-315 Ma) and in traps that formed in the Late Pennsylvanian and Early Permian time (270-290 Ma). The 

duration of this petroleum system is 140 million years. 

Preservation time starts after migration (secondary) and accumulation are complete. If little or no tectonic activity occurs 

during the preservation time, accumulations will remain in their original position. Remigration (tertiary) happens during the 

preservation time if folding, faulting, uplift, or erosion occur. If all accumulations are destroyed during the preservation time, no 

record of the petroleum system will be left. In the example, the preservation time is 250 million years. 

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 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 Torok-Nanushuk(.) is a hypothetical system 

on the North Slope of Alaska consisting of the Cretaceous Torok Formation as the source rock and the Nanushuk Group sandstone 

as the major reservoir rock. 

Classification Scheme.-A petroleum system can be classified into one of 12 categories, based on the type of source rock (I, 

II, or III; Tissot and Welte, 1984, p. 512), the composition of the reservoir rock(siliciclastic or carbonate), and whether the system 

is purebred or hybrid. A purebred petroleum system was deposited in a geologic setting in which the structural framework did not 

change significantly during the geologic life of the system; in contrast, a hybrid system includes a major structural change, without 

which a petroleum system would not have formed. The composition of the reservoir rock refers to the lithology of the largest 

petroleum deposit, whether it is siliciclastic or carbonate. The organic-matter type may be 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 (Tissot and Welte, 1984). The 

organic-matter type that produced the petroleum in the largest petroleum deposit is used to classify the system. The largest 

petroleum deposit refers to a single pool that contains the most in-place hydrocarbons, or a series of pools that cumulatively contain 

the most in-place hydrocarbons in the system at the time of discovery. 

Reference Cited.-Tissot, B.P., and Welte, D.H., 1984, Petroleum formation and occurrence: New York, Springer-Verlag, 

699 p. 
The Petroleum SystemStatus of Research and 

Methods, 1990 

LESLIE B. MAGOON, Editor 

U.S. GEOLOGICAL SURVEY BULLETIN 1912 
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 

Library of Congress catalog card number 89-600765 

UNITED STATES GOVERNMENT PRINTING OFFICE, WASHINGTON 1989 

For sale by the Books and 

Open-File Reports Section, 

U.S. Geological Survey 

Federal Center, Box 25425 

Denver, CO 80225 
CONTENTS 

Abstract 1 

Leslie B. Magoon 

Identified petroleum systems within the United States-1990 2 

Leslie B. Magoon 

The value of stratigraphic cross sections 10 

Cornelius M. Molenaar 

Carbonate aprons-Their petroleum reservoir potential 13 

Harry E. Cook and Henry T. Mullins 

Deep-water fan systems 20 

William R. Normark 

Porosity 25 

James W. Schmoker and Donald L. Gautier 

Clays 28 

Richard M. Pollastro 

Fission-track analysis in petroleum basins 32 

Nancy D. Naeser 

Geothermics applied to the reconstruction of subsurface temperatures 36 

Charles E. Barker 

Role of kinetic modeling in petroleum exploration 43 

Jerry L. Clayton 

Biological marker chemistry as indicator of depositional environment of source 

rocks and crude oils 46 

Jerry L. Clayton 

Sulfur in source rocks and petroleum 49 

Jerry L. Clayton 

The geochemistry of evaporites and associated petroleum 53 

Donald E. Anders and Robert J. Hite 

Effect of biodegradation on crude oils 59 

G. Eric Michael 

Heavy oil and natural bitumen 63 

Richard F. Meyer 

Natural gas 69 

Keith A. Kvenvolden 

Natural gas hydrates 72 

Timothy S. Collett and Keith A. Kvenvolden 

Quantitative petroleum resource assessment methodologies 74 

Robert A. Crovelli 

Branch of Petroleum Geology-1988 bibliography 79 

Contents Ill 
FIGURES 

1. Index map for COSUNA charts 6 

2. Stratigraphic sequences and block diagrams for carbonate aprons 15 

3. Chart showing scale relations of physical co~ponents and observational techniques for deep-water fan systems 22 

4. Chart showing classes of sulfur compounds reported in rock extracts and crude 

oils 50 

5. Graph showing carbon and hydrogen isotopic compositions in methane 70 

TABLES 

1. Distribution of the 130 identified U.S. petroleum systems according to categories 

of the petroleum system classification scheme 3 

2. Revised, reorganized, and expanded list of petroleum systems within the United 

States 3 

3. References where oil/source rock correlation demonstrate a known petroleum 

system 7 

4. Commonly used geochemical parameters and how they are affected by 

biodegradation 60 

5. Summary of some past and present petroleum resource assessments by the U.S. 

Geological Survey 77 

IV Contents 
The Petroleum SystemStatus of Research and Methods, 1990 

Abstract 

Leslie B. Magoon, Editor 

This publication in 17 individually authored summaries by U.S. Geological 

Survey scientists presents a revised and expanded list of the petroleum systems within 

the United States and summarizes the status of research for a number of petroleumrelated topics and investigative methods. The revised and expanded list now includes 

130 petroleums systems within the United States, 25 of which are classified as known 

systems. 

In a brief description of the usefulness of the stratigraphic cross section, 

Molenaar shows how this type of graphic illustration depicts important vertical and 

lateral lithostratigraphic relations. Two summaries on ancient and modem deepwater sediments are included. The carbonate slope apron and base-of-slope apron are 

compared and contrasted by Cook and Mullins. Summarizing the work of many 

investigators, Normark indicates how siliciclastic fan models based on field mapping, 

submarine acoustic imaging, and subsurface seismic stratigraphy compare and 

contrast. Investigations about porosity in petroleum reservoir rocks are discussed by 

Schmoker and Gautier. Pollastro discusses the uses of clay minerals as exploration 

tools that help to elucidate basin, source-rock, and reservoir history. The status of 

fission-track analysis, which is useful for determining the thermal and depositional 

history of deeply buried sedimentary rocks, is outlined by Naeser. The various ways 

workers have attempted to determine accurate ancient and present-day subsurface 

temperatures are summarized with numerous references by Barker. Clayton covers 

three topics: (1) the role of kinetic modeling in petroleum exploration, (2) biological 

markers as an indicator of depositional environment of source rocks and composition 

of crude oils, and (3) geochemistry of sulfur in source rocks and petroleum. Anders 

and Hite evaluate the current status of evaporite deposits as a source for crude oil. The 

current knowledge on the effect of biodegradation on crude oils is covered by 

Michael. Research on the origin and recovery of heavy oil and natural bitumen is 

discussed by Meyer. Two contributions ~on gaseous hydrocarbons are included: 

Kvenvolden discusses the latest thinking on the origin of methane and nitrogen, 

redefines the terms associated with the origin of methane, and suggests possible 

implications these ideas have on exploration strategy; and Collett and Kvenvolden 

review investigations of marine and continental natural gas hydrate occurrences. 

Crovelli reviews quantitative aspects of petroleum resource assessment methodologies. Lastly, publications written by personnel of the USGS Branch of Petroleum 

Geology and published during 1988 are listed in a separate bibliography. 

Manuscript approved for publication, September 26, 1989. 

The Petroleum System-Status of Research and Methods, 1990 1 
Identified Petroleum Systems within the United States-1990 

By Leslie B. Magoon1 

INTRODUCTION 

Basin analysis, petroleum system, play, and prospect may be viewed as separate levels of investigation, all 

of which are needed to better understand the genesis and 

habitat of hydrocarbons. Basin analysis emphasizes structural depressions and the included sedimentary rocks, the 

petroleum system emphasizes the genetic relation between a source rock and an accumulation, the play 

emphasizes structural and stratigraphic reservoir trends, 

and the prospect emphasizes individual traps. Except for 

the petroleum system, these terms are widely utilized by 

petroleum geologists. A petroleum system encompasses 

a hydrocarbon source rock and all generated oil and gas 

accumulations and includes all those elements that are 

essential for an oil and gas deposit to exist: petroleum 

source rock, migration path, reservoir rock, seal, and trap 

(Magoon, 1988a). The system has a stratigraphic limit, 

geographic extent, and time duration. Its name combines 

the names of the source rock and the reservoir rock and 

also expresses a level of certainty. Petroleum systems are 

classified by using criteria such as type of source and 

reservoir rock and the complexity of its geologic history, 

as explained in Magoon (1988b; table 1). 

The list of petroleum systems within the United 

States (table 2) has been revised and expanded since the 

last tabulation in 1988, in which 119 systems were 

identified (Magoon, 1988b). As published information 

about U.S. petroleum systems becomes available, the list 

is revised to reflect this new information. Presently 130 

petroleum systems have been identified, of which, 89 are 

purebred (structurally simple) and 41 are hybrid (structurally complex) (table 1). Of 12 possible categories, the 

2 most common systems are in the purebred siliciclastic 

category and have either type II (32) or type m (19) 

source rocks (rocks containing type II or III organic 

matter). Presently, all hybrid carbonate systems contain 

type II source rocks. Siliciclastic reservoirs (90) occur 

more than twice as often as carbonate reservoirs ( 40). 

The most common source rock is type II (73), followed 

by type III (41), the least common being type I (16). For 

an explanation of kerogen types, see Tissot and Welte 

(1984). 

Table 2 in this publication is reorganized from 

table 6 in Magoon (1988b ). The petroleum systems in 

1 U.S. Geological SuiVey, Menlo Park, Calif. 

each category are arranged alphabetically. Rather than 

identifying their location by State, the geological provinces of the American Association of Petroleum Geologists 

are indicated for each system (Meyer, 1974; fig. 1, table 

2), and the geological province code number along with 

the Correlation of stratigraphic units in North America 

(COS UNA) chart column number are shown. Because 

the petroleum system is independent of political boundaries (States), and may even be independent of sedimentary basins or arches, it is more appropriate to indicate 

the approximate geographic extent of each system using 

already established geological provinces. 

Since the last tabulation in 1988, the list of petroleum systems within the United States has been expanded and revised to include 11 more systems and new 

information about previously identified systems (table 2). 

The 11 new systems are as follows: Chainman-Garrett 

Ranch(!)(Poole and Claypool, 1984), Desmoinesian-a 

sandstone(!)(Clayton, 1989), Mowry-Muddy(!)(Momper 

and Williams, 1984), Niobrara(!) (Rice, 1984), 

Niobrara/Carlisle-Frontier(!) (Momper and Williams, 

1984), Ozette-Hoh(!)(Kvenvolden and others, 1988), 

Point Pleasant-Clinton(!)(Cole and others, 1987), Soda 

Lake-Painted Rock(.)(Lillis, 1988), StillwaterKulthieth(.)(Magoon, in press), Viola(!)(Jones and 

Philp, in press), and Woodford-Sycamore(!)(Jones and 

Philp, in press). Three petroleum systems have been 

reclassified from purebred to hybrid because the systems 

have been affected by either the Ouachita orogeny 

(Woodford/Chattanooga-Paleozoic(.)) or the Laramide 

orogeny (Aneth/Elbert-McCracken(?) and Tyler(!)). 

Five petroleum systems are reclassified from type III 

source to type II (G.E. Claypool, oral commun.; Cole and 

others, 1987); these are Devonian Black ShalesVenango(!), Ohio-Big Injun(.), Ohio Shale(!), OhioWeir(?), and Sumbury-Berea(!). The names of six 

petroleum systems have been changed: BakkenMadison(.) is now Exshaw-Madison(.); HueSagavanirktok/Canning(!) is now Hue-Sagavanirktok(!); 

Monterey-Sisquoc(.) is now Monterey-Tinaquic(.); Poul 

Creek-Katalla(?) is now Poul Creek(.); SalinaNiagaran(.) is now Salina A1-Niagaran(!); and TriassicNewark(?) is now Newark(?). The level of certainty for 

four petroleum systems has been revised: Green RiverWasatch(.) is now Green River-Wasatch(!)(Tissot and 

others, 1978); Poul Creek-Katalla(?) is now Poul 

Creek(.)(Magoon, in press); Salina-Niagaran(.) is now 

Salina A1-Niagaran(!)(Gardner and Bray, 1984); and 

2 The Petroleum System-Status of Research and Methods, 1990 
Table 1. Distribution of the 130 identified U.S. petroleum systems according to categories of the petroleum system classification 

scheme 

(Numbers in parentheses indicate number of petroleum systems of that category. An example petroleum system is recorded for each category in 

nomenclature colmnn. Classification scheme is explained in Magooo (1988b)] 

Geologic 

setting 

Reservoir Source Nomenclature Number of 

rock type rock type Source-reservoir (certainty) systems 

Purebred (89) Siliciclastic (58) I Green River-Wasatch(!) 

n Heath-Tyler(!) 

m Torok-Nanushuk(.) 

Carbonate (31) I Austin Chalk(!) 

n Smackover(!) 

m Chattanooga-Fort Payne(.) 

Hybrid (41) Siliciclastic (32) I Sheep Pass-Garrett Ranch(!) 

n Ellesmerian(!) 

m Tuxedni-Hemlock(.) 

Carbonate (9) I None 

II Wirmipeg-Red River(!) 

m None 

Table 2. Revised, reorganized, and expanded list of petroleum systems within the United States 

[Level of certainty: (1), known; (.), hypothetical; (?), speculative; for certainty definitions see Magoon, 1988b] 

Total 

AC, Atlantic Coast region (Jordan and Smith, 1983) NMC, Northern Mid-Continent region (Bergstrom and Morey, 1985) 

7 

32 

19 

8 

16 

7 

1 

16 

15 

0 

9 

0 

130 

CCA, Central California region (Bishop and Davis, 1984a) NRW, Northern Rockies/Williston basin region (Ballard and otheiS, 1983) 

CSR, Central and Southern Rockies region (Kent and otheiS, 1988) NW, Northwest region (Hull and otheiS, 1988) 

GB, Great Basin region (Hintze, 1985) PBR, Piedmont/Blue Ridge region (Higgins, 1987) 

GC, Gulf Coast region (Braunstein and otheiS, 1988) SAL, Southern Alaska region (Schaff and Gilbert, 1987b) 

MBA, Midwestern Basin and Arches region (Shaver, 1985) SAP, Southern Appalachian region (Patchen and otheiS, 1985b) 

MC, Mid-Continent region (Adler, 1987) SCA, Southern California region (Bishop and Davis, 1984c) 

NAL, Northern Alaska region (Schaff and Gilbert, 1987a) SSMC, Southwest/Southwest Mid-Continent region (Hills and Kottlowski, 1983) 

NAP, Northern Appalachian region (Patchen and otheiS, 1985a) TOT, Texas-Oklahoma Tectonic region (Mankin, 1987) 

NCA, Northern California region (Bishop and Davis, 1984b) CSD/C, Geological province code number (Meyer, 1974)/COSUNA chart 

NE, New England region (Skehan, 1985) stratigraphic column number 

Petroleum systems Petroleum GeograEhic/stratigraEhic location 

Somce-reservoir( certain~) type Reg! on CSD/C 

PUREBRED, siliciclastic reservoir 

T~e I source 

Austin Chalk/Eagleford-W oodbine(?) Oil GC 220;260/3,6, 10 

Cabot Head-Medina(.) Oil NAP 160/21 

Glenwood-Rose Rm1(?) Oil NAP 160/8 

Green River-Wasatch(!)1 Oil CSR 575117 

Neogene-Salt Lake(?) Oil GB 625/15 

Permsylvanian cannel coals-sandstone(.) Oil NAP; SAP 160/1 

Rose Hill-Keefer(?) Gas NAP 160n-1o 

TI2e II source 

Conasauga-Rome(.) Oil NAP;SAP 160/20 

Curtis-Entrada/Morrison(?) Oil CSR 535;595/13 

Devonian-Berea(?) Oil MBA 305/3-6 

Devonian Black Shales-Venango(!)2 Gas/oil NAP 160/17,21 

Eel River-Rio Dell(?) Gas NCA 720/1-2 

Heath-Tyler(!) Oil NRW 510/12 

Hue-Sagavanirktok(!)3 Oil NAP 890/5-6 

Kreyenhagen--Gatchell(?) Oil CCA 745/16-21,27-29 

Lower Cretaceous-Paluxy(?) Oil/gas GC 21 0;220;230;260 

Michigan-Stray(.) Oil/gas MBA 305/4-6 

Miocene(?) Oil CCA 735/6 

Monterey(?) Oil CCA 725/3 

Monterey-Puente(!) Oil SCA 760/8-11 

Identified Petroleum Systems within the United States-1990 3 
Table 2. Revised, reorganized, and expanded list of petroleum systems within the United States-Continued 

Petroleum systems Petroleum GeograEhic/stratigraphic location 

Source-reservoir( certain!X) type Region CSD/C 

PUREBRED, siliciclastic reservoir 

Type ll source-Continued 

Monterey-Repetto/Pico(.) Oil SCA 755/4-5 

Monterey-Tinaquaic(.)3 Oil CCA;SCA 740;750/2 

Monterey-Stevens/Kern River(.) Oil CCA 745/16-21,27-29 

Moreno(?) Oil CCA 745/29 

Mowry-Muddy(!) 4 Oil CSR 540/20 

New Albany(.) Gas MBA 315n-12,19-21 

Newark(?)3 Oil NE;PBR 100/8;150/11 

Nonesuch-Keweenawan(?) Gas MC;NMC 310/20-21;320;325;370/10;380 

Ohio-Big Injun(.)2 Gas/oil NAC 160/8 

Ohio Shale(lY Gas/oil NAP; SAP 160/1 

Ohio-Weir(?)2 Gas NAP;SAP 160/1 

Point Pleasant-Clinton(!)4 Oil NAP 160/15-16 

Soda Lake-Painted Rock(.)4 Oil SCA 750/1 

Sunbury-Berea(!)2 Oil/gas MBA;NAP 300/16,18;160/1-3, 7-8 

Tuscaloosa(.) Gas GC 220/10 

Unkown-Eocene(?) Oil GC 210;220;230;260/5,7,10,11 

Unknown-Eutaw/Selma(?} Oil GC 210;260/6,12,13 

Unknown-San Miguel/()lmos(?) Oil GC 220/1 

W oodford-Silurian/Devonian(.} Oil SSMC 430/18-21 

Type ill source 

Antrim(.) Gas MBA 305/15 

Beluga-Sterling(.) Gas SAL 820/13 

Cenozoic(.) Oil/gas GC 220/2-4,10-11 

Chester(?) Gas TOT 200/17-19 

Cotton Valley(?) Gas GC 210;230;260 

Cretaceous(.) Gas/oil CSR 535/12-14 

Cretaceous(!) Gas MC;NMC;NRW 320;380;390;395;515 

Forbes(.) Gas NCA 730!23-24 

Hornbrook(?) Gas NCA 715/5 

Jurassic-Cretaceous(?) Gas Atlantic offshore 

Marcellus-Oriskany(.) Gas NAP 160/1-3,8-14 

Miocene(.) Gas GC 210/14,16,17 

Mississippian coals-sandstones(.) Gas SAP 160/25-26 

PeimSylvanian coals(!) Gas NAP; SAP 160/1-2,7-9,12-13 

PeimSylvania-Late Paleozoic(!) Gas MC;SSMC;TOT 335;345/4-5;350/6;355;360/27-29 

365;370/26;375/25;440 

Starkey-Winters(.) Gas NCA 730/26 

Stepovak-Bear Lake(.) Gas SAP 845/10-11 

Sunbury-Murrysville(.) Gas NAL 160/17-19 

Torok-Nanushuk(.) Oil NAL 890/1-3 

PUREBRED, carbonate reservoir 

T,IJ!!: I source 

Athens-Trenton/Knox(?) Oil NAP; SAP 160 

Austin Chalk(!) Oil/gas GC 220/1,4,5,11 

Glenwood-Trempealeau(?) Gas NAP 160/15 

Salina-Newburg(?) Oil NAP 160/16 

Simpson-Viola(!) Oil MC;SSMC;TOT 335;350/6;355/1-2;360/27 ;365 

370/26;375/25 

Simpson-Viola/Hunton(.) Oil MC 335/21 

Trenton(!) Oil MBA 300!13-14;315n-12,19-21 

Utica-Trenton(!) Gas MBA;NAP;NE 11 0; 160/20;300 

4 The Petroleum System-Status of Research and Methods, 1990 
Table 2. Revised, reorganized, and expanded list of petroleum systems within the United States-Continued 

Petroleum systems 

Source-reservoir( certainty) 

PUREBRED, carbonate reservoir 

Conasauga-Knox(?) 

Devonian-Detroit River/l'raverse(?) 

Desmoinesian-0 sandstone(!) 4 

Dollar Bay(.) 

EauClair-Knox(?) 

Niobrara(!)4 

Niobrara/Carlisle-Frontier(!) 4 

Ordovician-Prairie du Chien/Black River/l'renton(?) 

Permsylvanian(.) 

Permsylvanian(.) 

Permian(.) 

Permian(.) 

Salina A-1-Niagaran(!)1

•

3 

Simpson-Ellenberger/Simpson(.) 

Smackover(!) 

Sunniland(!) 

Chattganooga-Fort Payne(.) 

Marcellus-Bass Islands(.) 

Marcellus-Onondaga(.) 

Monroe(?) 

Ohio/Chattanooga-Comiferous(?) 

Ohio/Sunbury~reenbriar/Newman(?) 

Sligo(?) 

HYBRID, sllicidastic reservoir 

Sheep Pass-Garrett Ranch(!)1 

Aneth/Elbert-McCracken(?)5 

AspeQ/Bear River-Nugget/Madison(?) 

Chainman-Garrett Ranch(! )

4 

Chainman-White Rim(?) 

Domengine-Cierbo/Briones(?) 

Ellesmerian(!) 

Greenhorn-Dakota(.) 

Jurassic/Cre~us(?) 

Mancos-Mesaverde(.) 

Mancos-Tocito(.) 

Minnelusa(!) 

Phosphoria-Weber(!) 

Todilto-Entrada(.) 

Tyler(!)5 

Utica-Beekmantown(!) 

Woodford/Chattanooga-Paleozoic(.)-5 

Cr~us(?) 

Cre~us(?) 

Cre~us(?) 

Cr~(?) 

Cr~us(?) 

Petroleum ______ ......;G......;eo..;;.,lgra~P~hi=· c/=s;.;;.;;tra=n~·gr;r;;;.a.;;.~;phi=· c....;;;lo.;;..c~at..;.;;.io.;..;;n;;,.__ ___ _ 

type Region CSD/C 

TyPe ll source 

Oil SAP;TOT 

Oil MBA 

Oil 

Oil 

Gas 

Gas 

Oil 

Oil 

Oil 

Oil 

Oil 

Oil 

Oil 

Gas/oil 

Oil 

Oil 

CSR 

GC 

MBA 

CSR 

CSR 

MBA 

SSMC 

SSMC 

SSMC 

SSMC 

MBA 

SSMC 

GC 

GC 

Type m source 

Oil/gas SAP 

Gas NAP 

Gas NAP 

Gas GC 

Oil/gas MBA; SAP 

Gas NAP;SAP 

Gas GC 

Type I source 

Oil GB 

TyPe ll source 

Oil CSR 

Oil CSR 

Oil GB 

Oil CSR;GB 

Oil/gas CCA 

Oil NAL 

Oil CSR 

Oil NRW 

Gas CSR 

Oil CSR 

Oil CSR 

Oil CSR 

Oil CSR 

Oil NRW 

Gas NE 

Oil MC;SSMC;TOT 

TyPe m source 

Oil/gas CSR 

Oil CSR 

Oil/gas CSR 

Oil CSR 

Gas CSR 

160/1-8;200/17-19 

305/3-6 

540/20 

140/31 

315/9-12,19-21 

540/21 ;450/31 

540/20-21 

300/14-16;305/3-6,15 

430/18-19 

430/20-21 

430/18-19 

430/20-21 

305/3-6 

430/19-21 

210;220;230;260 

140/31 

160/11-13 

160/21 

160/22 

230/9 

160/18;300/25 

160/1-2,18,21 

220/5,7,14 

625/9,11 

585/23 

535;570/11 

625/11 

585;630/29 

725/1 

890/1-6 

580/29 

500/10,11;505/6,7;510/12 

580/29 

580/29 

515;540/6 

505-535;570;575;615;630 

580/29 

395/19 

100/14 

335;345/4-5;350/6;355;360/27-29 

365;370/26;375/25;385;440;450 

520/4 

530/8 

540/21 

515/6 

535/9,15 

Identified Petroleum Systems within the United States-1990 5 
Table 2. Revised, reorganized, and expanded list of petroleum systems within the United States-Continued 

Petrolemn systems 

Source-reservoir( certainty) 

Petrolemn 

type 

Geographic/stratigraphic location 

Region CSD/C 

HYBRID, siliciclastic reservoir 

Cretaceous(?) 

Cretaceous-Tertiary(?) 

Cretacous-Tertiary(!) 

Lewis-Picture Cliffs(.) 

Mesaverde(.) 

Mesaverde(.) 

Ozette-Hoh(!)4 

Poul Creek(.)1•

3 

Stillwater-Kulthieth(.)4 

Tuxedni-Hernlock(.) 

HYBRID, carbonate reservoir 

Bakken-Madison(!) 

Chainman-Simonson(?) 

Conasauga-Knox(?) 

Exshaw-Madison(.) 3 

Favret(?) 

Paradox-Hermosa(.) 

Winnipeg-Red River(!) 

Woodford-Sycamore(!) 4 

Viola(!)4 

1 Level of certainty revised. 

2Reclassified petroleum system from type ill source. 3Petroleum system name revised. 

4Newly identified petroleum system. 

5Reclassified petroleum system from purebred. 

Type ill source-Continued 

Gas CSR 545/20 

Gas CSR 500/4 

Gas CSR 530/8 

Gas CSR 580/29 

Gas CSR 575/17 

Gas 

Oil 

Oil 

Oil 

Oil 

Oil 

Oil 

Gas 

Oil 

Oil 

Oil 

Oil 

Oil 

Oil 

TyPe ll source 

CSR 

NW 

SAL 

SAL 

SAL 

NRW 

GB 

PBR 

NRW 

GB 

CSR 

NRW 

TOT 

TOT 

595/18 

710/14 

810/24 

810/24,26-27 

820/13 

395/13-20 

625/11,12,17,18,20 

150/4-6 

5oon.1o,u;5o5 

625/2 

585/23 

395/13-20 

350/6 

350/6 

Sheep Pass-Garrett Ranch(.) is now Sheep Pass-Garrett 

Ranch{!)(Poole and Claypool, 1984). These additions 

and revisions are footnoted on table 2. 

Many of the petroleum systems of the "known" 

level of certainty are documented in the literature. In a 

known petroleum system, in the case of oil, a good 

geochemical match must exist between the source rock 

and the oil accumulations; or, in the case of natural gas, 

the gas is produced from a gas source rock. Of the 35 

known systems, 25 are documented in the literature 

(table 3). 

COSUNA CHART INDEX MAP REFERENCES CITED 

Figure 1. Index map of regions for the Correlation of stratigraphic units of North America (COSUNA) charts. See table 

2 for region names and references. 

Adler, JA., 1987, Mid-Continent region, in Lindberg, F.A., 

chart ed., Correlation of stratigraphic units of North 

America (COSUNA) project: American Association of 

Petroleum Geologists, 1 sheet. 

6 The Petroleum System-Status of Research and Methods, 1990 
Table 3. References where oil/source rock correlation demonstrate a known petroleum system 

Petroleum system 

Source-reservoir( certainty) 

Austin Chalk(!) 

Bakken-Madison(!) 

Chainman-Garrett Ranch(!) 

Cretaceous(!) 

Cretaceous-Tertiary(!) 

Desmoinesian-0 sandstone(!) 

Devonian Black 

Shales-Venango(!) 

Ellesmerian(!) 

Green River-Wasatch(!) 

Heath-Tyler(!) 

Hue-Sagavanirktok(!) 

Minnelusa(!) 

Monterey-Puente(!) 

Mowry-Muddy(!) 

Niobrara(!) 

Niobrara/Carlile-Frontier(!) 

Ohio Shale(!) 

Ozette-Hoh(!) 

Pennsylvanian coals(!) 

Pennsylvania-Late Paleozoic(!) 

Phosphoria-Weber(!) 

Point Pleasant-Clinton(!) 

Salina A-1-Niagaran(!) 

Sheep Pass-Garrett Ranch(!) 

Simpson-Viola(!) 

Smackover(!) 

Sunbury-Berea(!) 

Sunniland(!) 

Trenton(!) 

Tyler(!) 

Utica-Beekmantown(!) 

Utica-Trenton(!) 

Viola(!) 

Winnipeg-Red River(!) 

Woodford-Sycamore(!) 

Reference 

Hunt and McNichol, 1984 

Dow, 1974; 

Williams, 1974 

Poole and Claypool, 1984 

No reference 

No reference 

Clayton, 1989 

No reference 

Seifert and others, 1980; 

Sedivy and others, 1987 

Tissot and others, 1978 

Rinaldi, 1988 

Anders and others, 1987 

Anders and Magoon, 1985 

Clayton and Ryder, 1984 

No reference 

Momper and Williams, 1984 

Rice, 1984 

Momper and Williams, 1984 

No reference 

Kvenvolden and others, 1988 

No reference 

No reference 

Momper and Williams, 1984 

Cole and others, 1987 

Gardner and Bray, 1984 

Poole and Claypool, 1984 

No reference 

Claypool and Mancini, 1989; 

Oehler, 1984; Sassen, 1989 

Cole and others, 1987 

Palacas and others, 1984 

Reed and others, 1986 

Dow, 1974; 

Williams, 1974 

No reference 

No reference 

Jones and Philp, submitted 

Dow, 1974; 

Williams, 1974 

Jones and Philp, submitted 

Anders, D.A., and Magoon, L.B., 1985, Oil-source correlation 

study in northeastern Alaska, in Leythaeuser, D., and 

Rullkotter, J., eds., Advances in organic geochemistry 

1985: Organic Geochemistry, v. 10, p. 407-415. 

Anders, D.A., Magoon, L.B., and Lubeck, S.C., 1987, Geochemistry of surface oil shows and potential source rocks, 

in Bird, K.J ., and Magoon, L.B., eds., Petroleum geology 

of the northern part of the Arctic National Wildlife 

Refuge, northeastern Alaska: U.S. Geological Survey 

Bulletin 1778, p. 181-198. 

Ballard, W.W., Bluemle, J.P., and Gerhard, L.C., 1983, Northern Rockies/Willistion basin region, in Lindberg, F.A., 

chart ed., Correlation of stratigraphic units of North 

America (COSUNA) project: American Association of 

Petroleum Geologists, 1 sheet. 

Bergstrom, D.J., and Morey, G.B., 1985, Northern MidContinent region, in Lindberg, F.A., chart ed., Correlation of stratigraphic units of North America (COSUNA) 

project: American Association of Petroleum Geologists, 

1 sheet. 

Bishop, C.C., and Davis, J.F., 1984a, Central California region, 

in Lindberg, F.A., chart ed., Correlation of stratigraphic 

units of North America (COSUNA) project: American 

Association of Petroleum Geologists, 1 sheet. 

---1984b, Northern California region, in Lindberg, F.A., 

chart ed., Correlation of stratigraphic units of North 

America (COSUNA) project: American Association of 

Petroleum Geologists, 1 sheet. 

---1984c, Southern California region, in Lindberg, F.A., 

chart ed., Correlation of stratigraphic units of North 

America (COSUNA) project: American Association of 

Petroleum Geologists, 1 sheet. 

Braunstein, J., Huddleston, P., and Biel, R., 1988, Gulf Coast 

region, in Lindberg, F.A., chart ed., Correlation of 

stratigraphic units of North America (COSUNA) 

project: American Association of Petroleum Geologists, 

1 sheet. 

Claypool, G.B., and Mancini, E.A., 1989, Geochemical relationships of petroleum in Mesozoic reservoirs to carbonate source rocks of Jurassic Smackover Formation, 

southwest Alabama: American Association of Petroleum 

Geologists Bulletin, v. 73, no. 7, p. 904-924. 

Clayton, J.L., 1989, Geochemical evidence for Paleozoic oil in 

Lower Cretaceous 0 sandstone, northern Denver basin: 

American Association of Petroleum Geologists, v. 73, 

no. 8, p. 977-:988. 

Clayton, J.L., and Ryder, R.T., 1984, Organic geochemistry of 

black shales and oils in the Minnelusa Formation (Permian and Pennsylvanian), Powder River basin, Wyoming, 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, p. 231-253. 

Cole, G.A., Drozd, R.J., Sedivy, R.A., and Halpern, H.l., 1987, 

Organic geochemistry and oil-source correlations, Paleozoic of Ohio: American Association of Petroleum Geologists Bulletin, v. 71, no. 7, p. 788-809. 

Dow, W.G., 1974, Application of oil-correlation and sourcerock data to exploration in Williston basin: American 

Association of Petroleum Geologists Bulletin, v. 58, p. 

1253-1262. 

Gardner, W.C., and Bray, E.E., 1984, Oils and source rocks of 

Niagaran Reefs (Silurian) in the Michigan basin, in 

Patacas, J.G., ed., Petroleum geochemistry and source 

rock potential of carbonate rocks: American Association 

of Petroleum Geologists Studies in Geology No. 18, p. 

33-44. 

Higgins, M., 1987, Piedmont/Blue Ridge region, in Lindberg, 

F.A., chart ed., Correlation of stratigraphic units of 

North America (COSUNA) project: American Association of Petroleum Geologists, 1 sheet. 

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

Mid-Continent region, in Lindberg, F.A., chart ed., 

Correlation of stratigraphic units of North America 

(COSUNA) project: American Association of Petroleum Geologists, 1 sheet. 

Identified Petroleum Systems within the United States-1990 7 
Hintze, L.F., 1985, Great Basin region, in Lindberg, F.A., chart 

ed., Correlation of stratigraphic units of North America 

(COSUNA) project: American Association of Petro 

leum Geologists, 1 sheet. 

Hull, D.A., Armentrout, J.M., Hintze, L.F., Beaulieu, J., and 

Rau, W.W., 1988, Northwest region, in Lindberg, F.A., 

chart ed., Correlation of stratigraphic units of North 

America (COSUNA) project: American Association of 

Petroleum Geologists, 1 sheet. 

Hunt, J.M., and McNichol, A.P., 1984, The Cretaceous Austin 

Chalk of south Texas-A petroleum source rock, in 

Patacas, J.G., ed., Petroleum geochemistry and source 

rock potential of carbonate rocks: American Association 

of Petroleum Geologists Studies in Geology No. 18, p. 

117-125. 

Jones, P.J., and Philp, R.P., in press, Oils and source rocks from 

Pauls Valley, Anadarko basin, Oklahoma: Applied Geochemistry, 48 p. 

Jordan, R.R., and Smith, R.V., 1983, Atlantic Coastal plain, in 

Lindberg, F.A., chart ed., Correlation of stratigraphic 

units of North America (COSUNA) project: American 

Association of Petroleum Geologists, 1 sheet. 

Kent, H.C., Couch, E.L., and Knepp, R.A., 1988, Central and 

Southern Rockies region, in Lindberg, F.A., chart ed., 

Correlation of stratigraphic units of North America 

(COSUNA) project: American Association of Petroleum Geologists, 1 sheet. 

Kvenvolden, K.A., Rapp, J.B., and Hostettler, F.D., 1988, 

Preliminary evaluation of the petroleum potential of the 

Tertiary accretionary terrane, west side of the Olympic 

Peninsula,' Washington: Comparison of molecular markers in oil and rock extract, part 2: U.S. Geological Survey 

Open-File Report 88-75, p. 27-49. 

Lillis, P .G., 1988, Correlation and characterization of oils using 

biological markers, Cuyama basin, California, in Bazeley, 

W.J.M., ed., Tertiary tectonics and sedimentation in the 

Cuyama Basin, San Luis Obispo, Santa Barbara, and 

Ventura Counties, California: Pacific Section Society of 

Economic Paleontologists and Mineralogists, v. 59, p. 

39-48. 

Magoon, L.B., ed., 1988a, Petroleum systems of the United 

States: U.S. Geological Survey Bulletin 1870, 68 p. 

---1988b, The petroleum system-A classification scheme 

for research, exploration, and resource assessment, in 

Magoon, L.B., ed., Petroleum systems of the United 

States: U.S. Geological Survey Bulletin 1870, p. 2-15. 

---in press, The geology of known oil and gas resources by 

petroleum system-Onshore Alaska, in Platker, G., 

Jones, D., and Berg, H., eds., Alaska volume: Geological 

Society of America, Decade of North American Geology, 50 p. 

Magoon, L.B., and Claypool, G.E., eds., 1985, Alaska North 

Slope oil/rock correlation study: American Association 

of Petroleum Geologists Special Studies in Geology 20, 

678p. 

Mankin, C.J., 1987, Texas-Oklahoma tectonic region, in Lindberg, F.A., chart ed., Correlation of stratigraphic units of 

North America (COSUNA) project: American Association of Petroleum Geologists, 1 sheet. 

Meyer, R.F., ed., 1974, AAPG-CSD Geological provinces code 

map: American Association of Petroleum Geologists, 

revised edition, 1 sheet, scale 1:5,000,000. 

Momper, J.A., and Williams, J.A., 1984, Geochemical exploration of the Powder River basin, in Demaison, Gerard, 

and Murris, R.J ., eds., Petroleum geochemistry and basin 

evaluation: American Association of Petroleum Geologists Memoir 35, p. 181-191. 

Oehler, J.H., 1984, Carbonate source rocks in the Jurassic 

Smackover trend of Mississippi, Alabama, and Florida, 

in Palacas, J.G., ed., Petroleum geochemistry and source 

rock potential of carbonate rocks: American Association 

of Petroleum Geologists Studies in Geology No. 18, p. 

63-69. 

Patacas, J.G., Anders, D.E., and King, J.D., 1984, South Florida 

basin-A prime example of carbonate source rocks of 

petroleum, in Patacas, J.G., ed., Petroleum geochemistry 

and source rock potential of carbonate rocks: American 

Association of Petroleum Geologists Studies in Geology 

No. 18, p. 71-96. 

Patchen, D.G., Avary, K.L., and Erwin, R.B., 1985a, Northern 

Appalachian region, in Lindberg, F.A., chart ed., Correlation of stratigraphic units of North America (COSUNA) project: American Association of Petroleum 

Geologists, 1 sheet. 

-Southern Appalachian region, in Lindberg, F.A., chart 

ed., Correlation of stratigraphic units of North America 

(COSUNA) project: American Association of Petroleum Geologists, 1 sheet. 

Poole, F.G., and Claypool, G.E., 1984, Petroleum source-rock 

potential and crude-oil correlation in the Great Basin, 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, p. 179-229. 

Reed, J.D., Illich, HA., and Horsfield, B., 1986, Biochemical 

evolutionary significance of Ordovician oils and their 

sources, in Leythaeuser D., and Rullkotter, J., eds., 

Advances in organic geochemistry: Organic Geochemistry, v. 10, p. 347-358. 

Rice, D.D., 1984, Occurrence of indigenous biogenic gas in 

organic-rich, immature chalks of Late Cretaceous age, 

eastern Denver basin, in Palacas, J.G., ed., Petroleum 

geochemistry and source rock potential of carbonate 

rocks: American Association of Petroleum Geologists 

Studies in Geology No. 18, p. 135-150. 

Rinaldi, G.G., 1988, Oil-source studies in central Montana: 

Correlations and migration implications, in Mattavelli, 

L, and Novelli, L., eds., Advances in organic geochemistry 1987: Organic Geochemistry, v. 13, no. 1-3, p. 

373-376. 

Sassen, Roger, 1989, Migration of crude oil from the Smackover source rock to Jurassic and Cretaceous reservoirs of 

the northern Gulf Rim: Organic Geochemistry, v. 14, no. 

1, p. 51-60. 

Schaff, R.G., and Gilbert, W.G., 1987a, Northern Alaska 

region, in Lindberg, FA., chart ed., Correlation of 

stratigraphic units of North America (COSUNA) 

project: American Association of Petroleum Geologists, 

1 sheet. 

---1987b, Southern Alaska region, in Lindberg, F.A., chart 

ed., Correlation of stratigraphic units of North America 

(COSUNA) project: American Association of Petro8 The Petroleum System-Status of Research and Methods, 1990 
leum Geologists, 1 sheet. 

Sedivy, R.A., Penfield, I.E., Halpern, H.l., Drozd, R.J., Cole, 

G.A., and Burwood, R., 1987, Investigation of source 

rock-crude oil relationships in the northern Alaska 

hydrocarbon habitat, in Tailleur, I.L., and Weimer, Paul, 

eds., Alaskan North Slope geology: Bakersfield, Calif., 

Pacific Section, Society of Economic Paleontologists and 

Mineralogists and Alaska Geological Society, v. 1, p. 

169-179. 

Seifert, W.K., Moldowan, J.M., and Jones, R.W., 1980, Application of biological marker chemistry to petroleum exploration: Proceedings lOth World Petroleum Congress, 

v. 2, p. 425-438. 

Shaver, R.H., 1985, Midwestern basin and arches region, in 

lindberg, F .A., chart ed., Correlation of stratigraphic 

units of North America (COSUNA) project: American 

Association of Petroleum Geologists, 1 sheet. 

Skehan, S.J., 1985, New England region, in Lindberg, F.A., 

chart ed., Correlation of stratigraphic units of North 

America (COSUNA) project: American Association of 

Petroleum Geologists, 1 sheet. 

Tissot, B., 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, no. 10, p. 1469-1485. 

Tissot, B.P., and Welte, D.H., 1984, Petroleum formation and 

occurrence: New York, Springer-Verlag, 699 p. 

Williams, J.A., 1974, Characterization of oil types in Williston 

basin: American Association of Petroleum Geologists, v. 

58, no. 7,p. 1243-1252. 

Identified Petroleum Systems within the Unhed Statea-1990 I 
The Value of Stratigraphic Cross Sections 

By Cornelius M. Molenaar1 

INTRODUCTION 

In recent years, the great proliferation of geologic 

literature has made it ever more time consuming for 

geologists to keep up with the latest concepts and developments, even in only one geologic specialty. Many 

geologists may only read an abstract of a report and 

briefly review the figures. For this reason, it is important 

that authors carefully prepare their illustrations to show 

as clearly as possible the concepts or details they are 

trying to convey. The old adage that "one picture is worth 

a thousand words" could never be truer, especially when 

many readers never thoroughly read a paper. This report 

is a brief discussion on the value of one type of illustration, the stratigraphic cross section, which is an excellent 

method of graphically showing vertical and lateral lithostratigraphic relations. 

Some cross sections are schematic (cartoons) and 

are intended to show only overall relations without 

regard to scale, precise location, and actual details. 

Others are constructed using "hard" data, such as data 

from boreholes or measured sections. This latter type 

takes more time and effort to construct, but shows the 

basic data to support the interpretations. The following 

discussion relates to these data-based stratigraphic sections. 

DATA, AND SIZE AND SCALE OF 

ILLUSTRATION 

Data used in constructing stratigraphic cross sections are usually derived from measured outcrop sections 

or geophysical logs of boreholes. The combination of 

data from outcrop sections and borehole logs adds immeasurably to detailed stratigraphic studies. If the quality of outcrops is good, surface sections are much better 

than borehole logs for interpreting details of lithology, 

contact relations, bedding features, and depositional environments. Conversely, borehole logs are generally 

much better for measuring thicknesses, correlating 

marker beds in shale sections, and showing lateral relations of subjacent lithologic units. Thus the two types of 

data complement each other. 

1

U.S. Geological Sutvey, Denver, Colo. 

Depending on the scale and size of the illustration 

(that is, page size or large plate size) measured outcrop 

sections or borehole logs can be used to show the graphic 

data, or vertical lines ("stick" sections) can be substituted 

for the data when space or size is limited. Whichever type 

is used, it is important to plan the layout carefully to 

make maximum use of the available space. If more than 

one cross section is planned to show relations across 

different parts of the basin or area of interest, the same 

vertical scale should be used, if feasible, to aid direct 

comparisons of the different sections. When constructing 

a line of section through numerous control points, such 

as borehole logs or outcrop sections, positioning the 

control points relative to their actual horizontal separation is helpful in order to best show rates of change of 

lithologic units or rates of convergence or divergence. 

This positioning is a simple matter if vertical stick sections are used for each control point. But if the actual 

borehole logs or graphic columnar outcrop sections are 

used, allow for the addition of an average width of the 

borehole logs or columnar sections in addition to the 

distance between control points. 

The choice of vertical and horizontal scales depends on the size of the illustration and the purpose of 

the cross section. If a regional overview is the objective, a 

section must be prepared at a small scale, but details will 

be somewhat generalized. Larger scales should be used 

to show stratigraphic details of a specific lithologic unit. 

A cross section in Molenaar and others (1986) is an 

example of a small-scale stratigraphic cross section. This 

section shows a 355-mi (570 km)-long subsurface section 

across the North Slope of Alaska using gamma-ray and 

resistivity logs of 18 boreholes at a vertical scale of 

1:24,000 and horizontal scale of approximately 1:870,000 

(1 in.= 14 mi or 1 em= 8.7 km). Vertical exaggeration is 

about 36X. Even at this scale, the log character substantiates most of the correlations shown. Pl~te-size cross 

sections in Hook and others (1983) are examples of 

moderate-scale cross sections. Two sections show correlations of numerous measured outcrop sections of approximately 1,000 ft (300 m) of middle Cretaceous rocks 

in west-central New Mexico. The vertical scale is about 

1:1,900 (the unusual scales are due to photographic 

reduction of the work sections) and the vertical exaggerations are about 146 and 256X. At this scale, the lithologic details that are shown support the correlations of 

rock units. In addition, numerous molluscan fossils are 

listed where they occur on the sections. The detailed 

10 The Petroleum System-Status of Research and Methods, 1990 
sections in Hook and others (1983) are also shown as less 

detailed page-size figures in which vertical lines (sticks) 

are substituted for the actual measured section. Supplemental page-size figures permit the reader to visualize 

the overall relations; the larger plates can be unfolded if 

the reader wants to inspect the details. 

DATUMS 

Choosing a datum is also an important consideration in constructing cross sections. Again, it depends on 

the features the author wants to show. To illustrate the 

stratigraphic details of a particular formation, it is best to 

use a horizontal datum a short distance above the formation. In some cases, using a datum below the formation of interest, even though correctly correlated, can 

make lateral relations appear quite different, especially if 

the section thickens or a stratigraphic rise occurs between control points. On some cross sections a variable 

datum is appropriate, such as a section where the control 

in one part of the section does not include higher (or 

lower) parts of the stratigraphic interval included in other 

parts of the cross section. On cross sections showing 

numerous correlated marker beds, a specific datum is 

not actually necessary. 

Using sea level or an elevation above or below sea 

level as a datum will show formations at their present 

structural positions. Showing structure between control 

points is inadvisable unless it is desirable to show the 

projected formations at their low point in a basin or their 

high point on a structural high. But trying to show details 

of folding and faulting (unless they are syndepositional) 

and still show details of stratigraphy is difficult because 

the· vertical scale necessary for detailed stratigraphic 

sections is vastly different from an appropriate scale for 

structure cross sections. 

Commonly, an unconformity or the base of a 

marine transgression is used as a datum. Both of these 

surfaces are usually essentially flat surfaces prior to 

deposition of overlying strata. Their use as a datum 

illustrates the post-truncation relations of underlying 

strata. In some cases, however, unconformities can have 

significant relief. Such surfaces should be avoided for use 

as flat datums. 

USE OF TIME MARKER BEDS 

In constructing a stratigraphic cross section, the 

correlation of many marker beds (time lines) both above 

and below the rock unit of interest provides a timebounded framework that greatly aids in illustrating and 

understanding the depositional architecture. Usually 

there are many correlatable marker beds in marine shale 

sequences, such as the Upper Cretaceous Mancos Shale 

or equivalents in the Western Interior seaway, that can be 

recognized on geophysical logs of boreholes, especially 

on the conductivity log. Recognition of marker beds is 

facilitated by lithologic changes within marine shales. 

Some of these changes can be quite subtle. Bentonite 

beds and sandstone-shale contacts are examples of obvious changes. The subtle changes, which also are very 

reliable for long-distance correlations, are due to changes 

in content of carbonate, intermixed bentonite, and silt or 

sand within the shale section and possibly differences in 

clay mineralogy. All such lithologic variations are expressed by variations on resistivity or conductivity logs~ 

Some markers are recognized as solitary deflections or 

spikes on the log. Others are recognizable resistivity or· 

conductivity patterns over an interval of as much as 100 ft 

(30m). 

CONCLUSION 

Detailed stratigraphic cross sections, using correlated time marker beds as well as lithologic units and a 

carefully selected datum (or datums), show not only the 

correlations of lithologic units, but how they correlate 

with respect to time lines. The large vertical exaggeration 

used in constructing most stratigraphic cross sections 

permits recognition and measurement of subtle depositional and paleostructural features, such as (1) diachronism and stratigraphic rising (relative sea-level rise) of 

shoreface sandstone bodies, (2) shelf to slope to basinal 

topography, if developed, in thick marine shale sequences, (3) low-amplitude paleostructural features, and (4) 

differential compaction features associated with lateral 

heterogeneities in sand-shale sections. The plates in 

Molenaar and Baird (1989) show examples of subsurface 

correlations across the northern part of the San Juan 

basin in southwest Colorado using time mp-ker beds to 

illustrate some of the above-listed features. 

In summary, prope~ly constructed stratigraphic 

cross sections are an excellent method for depicting 

obvious and subtle stratigraphic features. Unlike maps 

that show isopachs of specific intervals (either time 

bounded or facies bounded), isoliths, or generalized 

lithofacies distnbution patterns, stratigraphic sections 

show how the rocks fit together, and meaningful stratigraphic sequences in the order that they were deposited. 

Moreover, by annotation, much additional data can be 

shown on the cross sections, such as geochemical, paleontologic, petrologic, and hydrocarbon test or completion data. 

REFERENCES CITED 

Hook, S.C., Molenaar, C.M., and Cobban, W.A., 1983, Stratigraphy and revision of nomenclature of upper CenomanThe Value of Stratigraphic Croas Sections 11 
ian to Turonian (Upper Cretaceous) rocks of westcentral New Mexico, in Hook, S.C., compiler, 

Contributions to mid-Cretaceous paleontology and stratigraphy of New Mexico-Part IT: New Mexico Bureau of 

Mines and Mineral Resources Circular 185, p. 7-28. 

Molenaar; C.M., and Baird, J.K, 1989, North-south stratigraphic cross sections of Upper Cretaceous rocks, northem San Juan Basin, southwestern Colorado: U.S. 

Geological Survey Miscellaneous Field Study Map MF2068. 

Molenaar, C.M., Bird, KJ., and Collett, T.S., 1986, Regional 

correlation sections across the North Slope of Alaska: 

U.S. Geological Survey Miscellaneous Field Studies Map 

MF-1907. 

12 The Petroleum System-Status of Research and Methods, 1990 
Carbonate Aprons-Their Petroleum Reservoir Potential 

By Harry E. Cook1 and Henry T. Mullins2 

INTRODUCTION 

Occurrence of Allochthonous Carbonate 

Debris 

Sediment gravity-flow deposition along the deepwater flanks of carbonate platforms typically does not 

produce submarine fans. Instead, wedge-shaped carbonate aprons develop parallel to the adjacent shelf-slope 

break (Schlager and Chermak, 1979; Crevello and 

Schlager, 1980; Cook, 1983a; Mullins, 1983, 1986; Mullins and Cook, 1986; Sarg, 1988). The major difference 

between submarine fans and carbonate aprons is a point 

source with channelized sedimentation on fans, versus a 

line source with sheet-flow sedimentation on aprons. 

Modern and ancient siliciclastic deposits formed by 

sediment gravity flows have been reported from a wide 

variety of geologic settings throughout the geologic 

record (for example, Nelson and others, 1970; Cook and 

others, 1982; Howell and Normark, 1982; Walker, 1984; 

Bouma and others, 1985; Shanmugam and Moiola, 

1988). Likewise, since the late 1960's it has been known 

that carbonate mass-transport deposits occur virtually 

throughout the Phanerozoic in widely diverse tectonic 

and stratigraphic settings (for example, Thomson and 

Thomasson, 1969; Cook and others, 1972; Mountjoy and 

oth~rs, 1972; Wilson, 1975; Cook and·Enos, 1977; Cook, 

1979; Mullins and Neumann, 1979; Cook and others, 

1983; Cook and Mullins, 1983; Crevello and Harris, 

1985; Bourrouilh and Doyle, 1987; Cook and others, 

1989a). It is normal to find allochthonous carbonate 

sediments in carbonate slope, base-of-slope, and basinplain sequences (Cook and Mullins, 1983), regardless of 

the type of carbonate platform (Read, 1982) or the type 

of carbonate slope margin (Mullins, 1978; Cook, 1983a; 

James and Mountjoy, 1983; Mcllreath and James, 1984). 

INTERPRETATION AND SIGNIFICANCE 

Early studies tended to interpret carbonate petroleum reservoirs consisting of coarse-grained carbonate 

sandstones and conglomerates as representing shoal1

U.S. Geological Sutvey, Menlo Park, Calif. 2

Department of Geology, Syracuse University, Syracuse, N.Y. 

water carbonate facies (for example, Barnetche and 

Illing, 1956). Later studies, however, showed that some 

of these facies had been misinterpreted and that the 

reservoirs actually consisted of allochthonous carbonate 

sediments, the constituents of which had been transported tens of kilometers from bank and reef margins by 

turbidity currents and debris flows (for example,' 

Viniegra and Castillo-Tejero, 1970; Cook and others, 

1972; Cook, 1983b; Enos, 1977). Even so, industry did 

not begin to actively explore for deep-water carbonate 

turbidite or debris-flow reservoirs until the early 1980's. 

Furthermore, outcrop studies of allochthonous carbonate debris did not focus on their reservoir potential but 

rather on their uses: (1) for signaling the existence of 

carbonate buildups or reefs in an area, (2) as proximity 

indicators for locating potential petroleum reservoirs in 

shoal-water carbonate environments, (3) for correlation 

in the basin facies, and (4) for genetic interpretation of 

the morphologic development and diagenesis of carbonate complexes (Cook and others, 1972; Mountjoy and 

others, 1972). 

CARBONATE APRON MODELS 

Background 

The submarine fan model (Nelson and others, 

1970; Mutti and Ricci Lucchi, 1978; Normark, 1978; 

Walker, 1978), as well as its variations '(Bouma and 

others, 1985; Shanmugam and Moiola, 1988), is well 

established in the geologic literature and is widely used 

both for paleoenvironmental interpretations of coarsegrained, deep-sea facies and as a predictive tool in the 

exploration for petroleum from deep-water reservoirs. 

Although the model has had considerable success in 

application to siliciclastic facies, studies of both modern 

carbonate mass-transport sequences (Mullins, 1978, 

1983, 1986; Mullins and Neumann, 1979; Schlager and 

Chermak, 1979; Crevello and Schlager, 1980; Mullins 

and others, 1984) and ancient ones (Koss, 1977; Biddle, 

1979; Kepper, 1981; Jordan, 1981; Cook, 1982, 1983a) 

have clearly demonstrated that the submarine-fan model 

cannot be applied unequivocally to carbonate-sediment 

gravity-flow deposits. Instead of orderly stratigraphic 

sequences of outer, middle, and inner fan facies that 

originate from a point source, many ancient carbonate 

mass-transport deposits consist of a seemingly random 

Carbonate Aprons-Their Petroleum Reservoir Potential 13 
distribution of debris that has more affinity with the 

debris-sheet model (Cook and others, 1972) and apron 

model (Cook, 1983a; Mullins and Cook, 1986). In fact, 

documented examples of ancient carbonate submarine 

fans with recognizable fan facies are quite rare (for 

example, Cook and Egbert, 1981; Cook, 1983b; RuizOrtiz, 1983; Wright and Wilson, 1984; Watts, 1985, 1986; 

Cook and others, 1989a,b ), and to date no complete 

modem examples have been discovered (Mullins and 

Cook, 1986). Despite this, numerous papers in the literature have indiscriminately used the term "fan" or "submarine fan" in their discussion of carbonate mass-flow 

facies sequences without presenting evidence that documents the existence of distinct fan facies associations. 

Unlike aprons, submarine fans develop at the mouth of 

large submarine canyons by mass-flow processes that are 

typically well channelized. Thus, one basic criterion that 

distinguishes fans from aprons is the high percentage of 

channelized facies in fans versus the dominance of nonchannelized sheet-flow facies in aprons (Mullins and 

Cook, 1986). 

In the rock record, two distinct types of carbonate 

aprons have been recognized (Cook, 1983a; Mullins and 

Cook, 1986) the slope apron and base-of-slope apron (fig. 

2). The major difference between the two models is that 

the base-of-slope model involves an upper-slope bypass 

zone, whereas in the slope apron model, redeposited 

carbonates extend up to the shelf edge without an 

intervening bypass slope. 

Slope Apron 

Slope aprons are most abundant along carbonate 

platform margins that have a relatively gentle gradient 

(less than 4 degrees) into the adjacent basin, such as the 

Upper Devonian Ancient Wall and Miette carbonate 

banks in Alberta, Canada, as well as the Upper Silurian 

to Lower Devonian of central Nevada (Cook, 1983a; 

Cook and Taylor, 1987). In the slope-apron model, 

carbonate gravity flow deposits extend up to the adjacent 

shelf-slope break without an upper slope bypass zone. 

Turbidity current and debris-flow deposits are abundant 

in slope aprons, but they do not develop systematic 

vertical cycles (fig. 2). Carbonate slope aprons have yet to 

be identified in modem environments, even those platform margins with slopes of less than 4 degrees (Mullins 

and Cook, 1986). The reason for this is not clear although 

it may be due to the fact that modem platforms tend to 

have relatively high relief. Future studies of upper slopes 

in modem environments may reveal the presence of 

slope aprons. 

Base-of-Slope carbonate Apron 

Base-of-slope apron sediments (fig. 2) bypass upper slopes via numerous small gullies and canyons, as 

well as by sheet-flow events. This kind of carbonate apron 

develops along relatively steep (greater than 4 degrees) 

high-relief platform margins, such as those in parts of the 

Upper Devonian and Lower Mississippian of the Great 

Basin or the Permian of west Texas (Cook, 1983a, b; 

Cook and Taylor, 1987), and the Carboniferous of eastcentral Alaska (Cook and others, 1987). These examples 

exhibit thickening-upward cycles (fig. 2). The relatively 

steep bypass slopes commonly have numerous submarine slides and slumps; this is in contrast to carbonate 

slope aprons, which are rarely associated with submarine 

slides and slumps. 

In the northern Bahamas, well-developed modem 

base-of-slope carbonate aprons have been described 

from the Little Bahama Bank (Mullins, 1985; Mullins 

and others, 1984), southern Tongue of the Ocean 

(Schlager and Chermak, 1979), and Exuma Sound (Crevello and Schlager, 1980; Austin and others, 1986, 1988). 

PETROLEUM EXPLORATION FOR 

CARBONATE APRONS 

Deep-water, carbonate sediment-gravity-flow deposits are now recognized as very important and attractive reservoirs for petroleum (Cook and Enos, 1977; 

Scholle, 1977; Mullins and Cook, 1986). A good example 

of extensive petroleum production from an ancient baseof-slope carbonate apron is the Cretaceous Tamabra 

Limestone of Mexico, where production and proven 

reserves exceed 2.3 billion barrels of oil (Enos, 1977, 

1985; Enos and Moore, 1983). Production is mainly from 

solution porosity in grainstone-packstone sediment gravity flow facies that are encased in fine-grained, deepwater deposits (Enos, 1977, 1985). 

Numerous giant oil fields also have been recently 

discovered in the "Great Carbonate Bank of Yucatan" of 

southern Mexico and offshore Campeche, which has 

been considered to be a major world petroleum province 

(Meyerhoff, 1980; Viniegra, 1981). One of the largest 

fields is a stratigraphic trap, where detrital calcarenites 

wedge out into finer grained facies (Viniegra, 1981 ), in a 

fashion possibly similar to the idealized base-of-slope 

carbonate apron. As of 1979, proven reserves for this 

petroleum province exceeded 18 billion barrels of oil and 

15 trillion cubic feet of gas (Meyerhoff, 1980; Viniegra, 

~981). 

More recent petroleum discoveries in the southeast 

area of Mexico's Reforma-Jalpa were reported by 

Aguayo and others (1985). There, Upper Jurassic and 

Lower Cretaceous carbonate petroleum reservoirs occur 

in platform and slope environments. The basin . and 

carbonate platform are separated by a slope 20 km wide. 

Carbonate slope sediments are described as being 

formed of ''breccia beds interlayered and interfmgered 

with pelagic horizons" (Aguayo and others, 1985). Pro14 The Petroleum System-Status of Research and Methods, 1990 
a:_ ~z 

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a.. 

0 

_J 

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z 

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SLOPE APRON 

BASE-OF-SLOPE APRON 

EXPLANATION 

1~ ,..j Platform margin carbonate 

~~·P.I Carbonate debris-flow deposit 

CJ Carbonate turbidity-flow deposit 

~ Carbonate submarine slide and slump 

D In-situ slope and basinal carbonate sediments 

Figure 2. Schematic, three-dimensional brock-diagram models for carbonate slope apron and baseof-slope apron. Along left-hand margins are highly generalized seaward-prograding stratigraphic 

sequences that one might expect to find associated with these apron models. From Cook (1983a) and 

Mullins and Cook (1986). 

Carbonate Aprons-Their Petroleum Reservoir Potential 15 
duction occurs in these slope breccias starting from 

about 5 to about 12 km seaward of the platform margin. 

As of 1985, production occurred for a distance of 15 km 

laterally along the slope (Aguayo and others, 1985, fig. 

7). 

Petroleum reserves also occur in Permian deepwater carbonate gravity-flow facies along slope and baseof-slope settings in the Delaware and Midland basins of 

west Texas (Cook, 1983a,b; Mazzullo, 1984; Hobson and 

others, 1985a,b). We do not know whether these reservoirs represent debris sheets, fans, carbonate aprons, or 

some combination of all three models (Cook, 1983a,b; 

Mazzullo, 1984; Hobson and others, 1985a,b ). Probably 

allochthonous carbonate deposits extend around much of 

the Permian platform margin in the Midland basin 

(Mazzullo, oral communication, 1983; Mazzullo, 1984; 

Mazzullo and Reid, 1987). Oil fields in these Permian 

carbonate rocks occur 15 to 30 km seaward from platform margins, extend basinward for distances up to 25 

km, and are about 40 km long parallel to the slope (Cook, 

1983b). Production occurs from megabreccias, grainsupported conglomerates, and pebbly calcarenites. Much 

of the porosity is secondary, resulting from postdepositional dissolution of unstable aragonite and magnesian calcite constituents. Fracture porosity and 

intercrystalline dolomitic porosity are also important. 

Downslope transport probably involved a variety of 

mechanisms including submarine slides, debris flows, 

and turbidity-current flows. Many of the boulder-bearing 

megabreccia debris flows may have originated as 

platform-margin-generated slides. The transition from 

sliding to debris flow to turbidity-current flow is a subject 

studied by Hampton (1972) in laboratory experiments 

and for subaerial mass-transport deposits, by Field and 

Clarke (1979) on modern siliciclastic slopes, and by Cook 

(1979) on ancient carbonate slopes. 

In the Pennsylvanian Palo Duro basin, Crevello 

and others (1985) described allochthonous sediment 

gravity-flow carbonate rocks that occur in slope and 

basinal settings. One well produced nearly 4,000 barrels 

of oil before abandonment. Although not a commercial 

success, the discovery, as Crevello and others (1985) 

pointed out, is important as it documents the first occurrence of oil production from slope and basinal carbonate 

debris in the Palo Duro basin. The nearest oil production 

is 80 km to the south in platform-margin carbonate rocks 

(Crevello and ·others, 1985). 

New potential exploration targets exist in a frontier 

area of east-central Alaska where a 500-m-thick sequence of Carboniferous carbonate base-of-slope apron 

and (or) submarine fan-lobe facies are spectacularly 

exposed (Cook, Magoon, and others, 1987). The organic 

content of the lime mudstones interbedded with the 

allochthonous carbonate rocks averages 5 weight percent, T AI, and T max indicates that the organic matter is 

well into oil generation but not overmature. S2/S3 ratios 

suggest that the carbonate rocks contain mixed gasand-oil-prone source rocks. Such source rock data document the potential of the apron or fan facies as 

subsurface petroleum reservoirs. 

As exploration continues into deeper water carbonate slope and basinal settings, more reservoirs of the 

above types probably will be sought and found. It will be 

increasingly important to understand the nature, facies 

associations, and geologic controls responsible for the 

origin of these potential carbonate reservoirs. For exampie, a topic of active research involves the interrelations 

between carbonate platform margin collapse, eustatic 

sea-level lowering, and rapid sediment accumulation 

rates at platform margins (Mullins and others, 1986; 

Cook and Taylor, 1987; Cook, Taylor, and Magoon, 

1987; Field and Gardner, 1987; Sarg, 1988; Cook and 

others, 1989a,b; Mullins and Hine, 1989). 

Many of these coarse-grained, redeposited facies 

also have a high diagenetic potential that can enhance 

their reservoir quality within the deep marine diagenetic 

realm, particularly during shallow burial (Mullins and 

others, 1985; Dit and Mullins, 1988). Thus it becomes 

important to understand under what conditions unstable 

carbonate minerals may constitute these redeposited 

sequences. There are two principal types of redeposited 

carbonate particles: those that are platform derived and 

contain an abundance of metastable aragonite and magnesian calcite, and those that are slope derived and 

consist mainly of stable calcite. In terms of porosity 

enhancement by postdepositional solution, the former 

would have greater promise as petroleum reservoirs. 

Thus, an exploration strategy that seeks mineralogically 

unstable carbonate gravity-flow facies is likely to have a 

higher rate of success. Such an exploration strategy might 

use the following perspectives: along windward margins 

of carbonate platforms, on-bank transport of coarse 

sediment dominates, whereas along leeward margins 

coarse carbonate sediments are actively transported offbank onto adjacent slopes (Hine and Mullins, 1983). 

Accordingly, carbonate-sediment gravity-flow facies 

along leeward margins are more likely to have a higher 

percentage of redeposited unstable aragonite and magnesian calcite and are more likely to undergo porosity 

enhancement by the dissolution of unstable grains (Mullins and Cook, 1986). This concept appears' to be applicable to the Cretaceous Poza Rica trend, which Paul 

Enos (oral communication, 1985) has interpreted as a 

leeward margin. 

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Veracruz, Mexico, in Halbouty, M.T., ed., Geology of 

giant petroleum fields: American Association of Petroleum Geologists Memoir 14, p. 309-325. 

Walker, R.G., 1978, Deep-water sandstone facies and ancient 

submarine fans: Models for exploration for stratigraphic 

traps: American Association of Petroleum Geologists 

Bulletin, v. 62, no. 6, p. 932-966. 

Walker, R.G., 1984, ed., Facies models: Geoscience Canada 

Reprint Series 1, 317 p. 

Watts, K.F., 1985, Evolution of a carbonate slope facies along 

a southern Tethyan continental margin: The Mesozoic 

Sumeini Group and the Qumayrah facies of the Muti 

Formation, Oman: Santa Cruz, University of California; 

Ph.D. thesis, 475 p. 

Watts, K.F., and Garrison, R.E., 1986, Sumeini Group, Oman-Evolution of a Mesozoic carbonate slope on a south 

Tethyan continental margin: Sedimentary Geology, v. 48, 

no. 1/2, p. 107-168. 

Wilson, J.L., 1975, Carbonate facies in geologic history: New 

York, Springer-Verlag, 471 p. 

Wright, V.P., and Wilson, R.C.L., 1984, A carbonate submarine 

fan sequence from the Jurassic of Portugal: Journal of 

Sedimentary Petrology, v. 54, no. 2, p. 394-412. 

Carbonate Aprons-Their Petroleum Reservoir Potential 19 
Deep-Water Fan Systems 

By William R. Nor mark 1 

About the same time that Shepard and his peers 

had documented the widespread occurrence and types of 

submarine canyons and their importance in providing 

pathways for terrigenous sediment to reach the deep-sea 

floor (see review by Shepard and Dill, 1966), mapping of 

onshore turbidite deposits had begun to define the nature of the coarse-grained, fan-shaped deposits fed by 

ancient submarine canyons (Sullwold, 1960; Jacka and 

others, 1968). General depositional models for submarine fans began to appear shortly thereafter (Normark, 

1970; Mutti and Ricci Lucchi, 1972), and the number of 

models and model variations has blossomed, especially 

during the last decade. 

The three general types of studies used for the 

more common fan models are: (1) field (outcrop) mapping, (2) acoustic imaging of modern fans, and (3) 

seismic-stratigraphic studies. Models for "ancient" turbidite deposits are generally based on field work that in 

some cases can be augmented by analysis of borehole 

cores. The most widely used are facies models, which are 

primarily based upon interpretation of fan depositional 

environments through detailed vertical-section measurements from outcrop studies (Mutti and Ricci Lucchi, 

1972, 1975; Ricci Lucchi, 1975; Mutti, 1977, 1979). 

"Morphologic," or modern-fan, models are based on the 

knowledge of the surface-shape characteristics of the fan 

system together with some general idea of the nature 

(grain size, composition, internal structure, and stratigraphic control) of the upper few meters or tens of 

meters of the fan sediments (Normark, 1970, 1978; 

Nelson, 1976). The study of modern fans with sidelooking-sonar images and high-resolution seismicreflection profiles (1-10 kHz) in conjunction with core 

data commonly provides an acoustic-facies scheme or 

facies oombining acoustic characters and surficialsediment type. Seismic-stratigraphic models are based on 

deep-penetration, but low-resolution, seismic-reflection 

profiles (Vail and others, 1977; Vail, 1987). This technique generally results in mapping only the large-scale 

features of deep-water fan systems, such as lobes or 

major channel-levee systems, but has the advantage of 

being suitable for either modern or buried systems 

whether in deep water or within filled basins along 

continental margins. 

1U.S. Geological Sutvey, Menlo Park, Calif. 

As more data became available for the relatively 

poorly documented modern submarine fans, some sedimentation models reflected an attempt to combine characters observed from work on modern and ancient 

deposits (for example, Nelson and Nilsen, 1974; Walker, 

1978; see also review by Howell and Normark, 1982). 

Such attempts have not always met with general approval; see, for example, the discussion and reply sequence of 

the Walker paper (Nilsen, 1980; Normark, 1980; Walker, 

1980). With the recognition of the strong imprint that 

sea-level changes have on the development of deep-water 

clastic deposits, later models combine (or blend without 

specific attribution) observations from all three basic 

types of study (Vail and others, 1977; Mutti, 1985; 

Pickering and others, 1986; Vail, 1987; Shanmugam and 

Moiola, 1988). Many additional sedimentation-model 

variations of the basic themes described in the references 

above have resulted from modification of one or only a 

few components of an established general model to 

"better fit" a limited set of field observations, commonly 

from a poorly understood deposit. Such ad hoc models 

have limited use for interpretation of other turbidite 

systems. 

All three model types and some of the various 

hybrid versions have been widely used but generally 

without recognizing (or admitting) the basic differences 

in the types of observations used. During the last half 

decade, however, an ever more common theme among 

fans (friends) of submarine fans has been to express 

concern over the general applicability and usefulness of 

existing models for submarine fan deposits, whether such 

models are concerned with deciphering depositional 

processes or predicting reservoir potential for hydrocarbon exploration (Mutti, 1984; Bouma and others, 1985; 

Normark and others, 1985; Shanmugam and Moiola, 

1985; Shanmugam and others, 1985; Normark, 1986; 

Mutti and Normark, 1987). The questions raised in the 

references above were discussed in several international 

forums; reviews of most of the submarine fans and 

turbidite systems that have been studied to date are 

provided in two books covering these forums (Bouma 

and others, 1985; Weimer and Link, in press). 

The first COMFAN (COMmittee on FANs) meeting in 1982 provided a chance to compare data from 23 

modern and ancient turbidite systems. Participants at this 

workshop could not agree on common definitions for 

many of the terms used to describe fan features but did 

agree to a common set of criteria to present their 

20 The Petroleum System-Status of Research and Methods, 1990 
research. The volume resulting from this meeting reviews 

28 different turbidite systems and includes preliminary 

results from Leg 96 of the Deep Sea Drilling Program on 

the Mississippi Fan (Bouma and others, 1985). Although 

seismic-stratigraphic analyses were available for several 

turbidite systems discussed at COMF AN I, a special 

session at the 1987 Society of Economic Paleontologists 

and Mineralogists Midyear Meeting focused directly on 

the seismic stratigraphy of submarine fans. The results of 

this forum are presented in a book covering more than 15 

turbidite systems (Weimer and Link, in press). The 

groundwork laid by these two meetings provided the 

background for the COMFAN II workshop in 1988, 

where all three approaches to the study of deep-water 

fans were incorporated (Mutti and others, in press). The 

examples that follow illustrate the types of interpretational discrepancies (discussed at the COMFAN meetings) 

that arise from utilizing different techniques to study 

submarine fans. 

Fan divisions (implied depositional environments) 

based on examination of modern systems rely on morphologic characters such as the nature of the channels, 

average slope, and geographic position, but similarly 

named divisions for ancient turbidite deposits that are 

based on outcrop mapping or borehole studies are keyed 

to the nature of the sedimentary rock characters as 

determined from detailed vertical-section measurements, including bed thickness, grain size, and sedimentary structures, as well as the vertical (and in a few cases, 

horizontal) sequence(s) that may be exhibited using 

these characters. Interpretations of modern fans generally consider the basin-plain environment to be the most 

distal facies of and time-equivalent with the main fan 

body. On the other hand, at the coarser scale of observation obtained with seismic-stratigraphic data, major 

fan bodies are interpreted to prograde over basin-plain 

deposits of an earlier phase of basin development. 

The use of the term lobe or depositional lobe 

shows the greatest variation between students of submarine turbidite systems (Mutti and Normark, 1987). The 

most widely referenced application of the term is based 

on the original work of Mutti and Ricci Lucchi (1972), 

whose classic examples are from turbidite systems 

formed in elongate basins within compressional margin 

settings. Their lobe features are tabular, channel-free, 

coarsening- and thickening-upward sandstone bodies 

that can extend for tens of kilometers parallel to the basin 

axis; these general characters are supplemented by facies 

distinctions based on the details of bedding features. 

Lobe distinctions based on seismic-reflection profiles, on 

the other hand, suggest that they are mounded features 

with downlap relations of internal reflectors at their 

margins (Mutti and others, in press). The definition of 

lobe features on modem fans follows neither of the sets 

of characters noted above (see the summary in Mutti and 

Normark, 1987); instead, the term "lobe" is applied 

variously to any area of sand deposition, with or without 

channels. The thickness of the lobes from modern fans is 

generally not determined (being too thin to be resolved 

with the low-frequency reflection profiles needed to 

achieve subbottom penetration in sandy environments), 

and the nature of the sediment composing the lobes is 

based on short surficial core samples from the upper few 

meters of the deposit. 

Our understanding of modern fans is strongly tied 

to our interpretation of the shape of the deposit, even 

though for most fans we do not have precise morphologic 

control. Long-range side-looking sonar images have 

shown a remarkable variety of surficial features not 

previously known from modern fans, but most side~ 

looking systems do not provide a measure of the water 

depth; thus, only the plan shape is determined and not 

the associated relief. Without better knowledge of the 

actual vertical relief and of the type of sediment associated with the relief, it is difficult to use the side-looking 

sonar data from modern fans to help those working on 

outcrops by defining specific features to look for in 

vertical sections of ancient deposits. 

NEW APPROACHES 

Variations in the interpretation of deep-water fans 

of the kind noted above basically result from differences 

in the (1) types of observations used to map the deposits, 

(2) physical and temporal scales of features, and (3) 

characteristics of the basins containing the turbidite 

systems (Mutti and Normark, 1987, in press). Thus, it is 

not surprising that models derived from the separate 

"disciplines" lack general applicability when these differences are not taken into account. 

Figure 3 shows the range of physical scales (horizontal dimension only) of the components of turbidite 

systems and of the types of observations oommonly used 

to map turbidite systems. The key points to note are that 

the smallest features resolvable on modern deep-water 

fans and within deeply buried fan systems in continentalmargin basins using standard shipboard seismicreflection profiles could be recognized only in fairly 

impressive outcrops of ancient turbidites, where exposed 

beds could be traced over several kilometers. The limits 

on resolution obtainable with seismic-stratigraphic data 

nearly preclude the recognition of individual depositional 

lobe features unless they exceed several tens of meters in 

thickness. Thus, there are many gaps in the scale resolved 

and type of observations used to map turbidite systems. 

The vertical scale in figure 3 schematically shows 

the general increase in the complexity and volume of 

turbidite systems as the time available for deposition in 

the basin increases. Thus, techniques appropriate for the 

study of depositional processes (at the scale of individual 

beds and elements; fig. 3) are quite different from those 

Deep-Water fan Systems 21 
that might yield basin history and an evaluation of the 

potential for petroleum reserves. 

Comprehensive process or stratigraphic models for 

deep-water fans must be based on a combination of 

morphologic, sedimentologic, and structural/stratigraphic criteria; that is, they must be able to incorporate all 

types of observations. This can be done if similarly 

formed features of the same general scale are correctly 

identified. Rather than looking for general similarities 

among different fans to develop a model synthesizing sets 

of characters, Mutti and Normark (1987, in press) suggested that it is time to focus on key depositional and 

erosional features that characterize most turbidite systems. They identified a limited number of fan elements in 

terms that allow their recognition from outcrop, morphologic, or reflection-profile data; these elements are not 

strictly equivalent to the "architectural elements" of 

Miall (1985) because of the need to allow their distinction using widely varying techniques of observation (fig. 

3). The basic elements include channels and channel-fill 

sequences, overbank deposits, lobe deposits, and characteristic erosional features, for example, scours, which are 

characteristic of the channel-lobe transition zone and 

large-scale shelf-edge/upper-slope failures (Mutti and 

Normark, 1987, in press). 

The size and shape of the basin, together with the 

volume and grain-size distribution of the sediment supplied to the basin, are important factors in controlling the 

scale of the elements developed within any given turbidite system. Many comparisons of submarine fans have 

not considered the effects of the basin itself on controlling the growth pattern of the deposit. 

Most turbidite systems described through outcrop 

mapping and borehole sampling are from basins formed 

on continental crust. The best known examples are from 

active margin environments where the basin shape, size, 

and longevity are controlled by syndepositional tectonism. Many of these basins are relatively narrow, elongate 

SCALE RELATIONS 

............-.---------1 ... ~ SEISMIC STRATIGRAPHY; MULTIBEAM AND SIDESCAN SONAR 

1000 

KILOMETERS 

BASIN-FILL SEQUENCES; FAN COMPLEXES 

. -------------------- PHOTOGEOLOGIC MAPPING 

INDIVIDUAL TURBIDITE SYSTEMS OR FANS 

. ------------------------- OUTCROP MAPPING 

STAGES OF GROWTH 

...... 1-----------1 ... ~ DEEP-TOW IMAGING SYSTEMS 

BEDDING PATTERNS 

1 

KILOMETER 

ELEMENTS 

......------1 ... ~ SEA-FLOOR PHOTOGRAPHY 

1 

METER 

PHYSICAL SCALE 

MESOTOPOGRAPHV 

-----...... • CORES 

1 

MILLIMETER 

Figure 3. Relation in horizontal scale between observational techniques Oight horizontal lines with arrows) used to map turbidite 

systems and components that compose such systems (heavy lines). Arrowheads indicate that scale range can be longer in 

special circumstances; for example, core samples can provide data at much smaller scale through the use of microscopic 

examination, and outcrops of exceptional length (>50 km) are known but not common. Vertical scale (schematic only) shows 

time element related to components of a turbidite system. Adapted from figures 1 and 2 in Mutti and Normark (1987), who 

defined elements and stages of turbidite systems. 

22 The Petroleum System-Status of Research and Methods, 1990 
troughs that provide a strong control on the turbidity 

currents bringing sediment to the basin. Much of the 

available observations on modern 'fans, however, comes 

from deposits formed on oceanic crust; the largest modern fans are fed by large rivers crossing passive margins 

where there is little tectonic activity to disturb the growth 

of the fan (Bouma and others, 1985). Fans formed on 

oceanic crust are deposited from turbidity currents that 

are able to spread over large areas of the sea floor as 

deposition buries the local relief. Thus, the shape, internal structure, and distribution of coarse-grained sediment can be substantially different between t1_ubidite 

systems in active marginal basins and those on deepocean crust along passive margins. Comparison of submarine fan elements of similar size and from the same 

type of basin can be the first step in determining the main 

controls on deep-water siliciclastic turbidite deposition. 

If we understand these controls for turbidite systems 

from a sufficient range in size and basin characteristics, it 

should eventually be possible to develop depositional 

models of general applicability. 

REFERENCES CITED 

Bouma, A.H., Normark, W.R., and Barnes, N.E., 1985, Submarine fans and related turbidite systems: New York, 

Springer-Verlag, 351 p. 

Howell, D.G., and Normark, W.R., 1982, Sedimentology of 

submarine fans, in Scholle, P.A., and Spearing, D., eds., 

Sandstone depositional environments: American Association of Petroleum Geologists Memoir 31, p. 365-404. 

Jacka, A.D., Beck, R.H., St. Germain, L., and Harrison, S.C., 

1968, Permian deep-sea fans of the Delaware Mountain 

Group (Guadalupian), Delaware basin, in Guadalupian 

Facies, Apache Mountain area, west Texas Permian 

basin section: Society of Economic Paleontologists and 

Mineralogists Publication 68--11, p. 49-90. 

Miall, M.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., 1977, Distinctive thin-bedded turbidite facies and 

related depositional environments in the Eocene Hecho 

Group (south-central Pyrenees, Spain): Sedimentology, 

v. 24, p. 107-131. 

---1979, Turbidites et cones sous-marins profonds, in 

Homewood, P., ed., Sedimentation detritique (fluviatile, 

littorale et marine): Institut de Geologie, University of 

Fribourg, Switz., p. 353-419. 

---1984, Ancient turbidite systems: Models and problems: 

American Association of Petroleum Geologists Bulletin, 

v. 68, p. 1837. 

---1985, Turbidite systems and their relations to depositional sequences, in Zuffa, G.G., ed., Provenance of 

arenites (NATO-ASI Series), Dordrecht, Neth., Reidel, 

p. 65-93. 

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. 

---in ~ress, An integrated approach to the study of turbidite systems, in Weimer, P., and Link, M.H., eds., Seismic 

facies and sedimentary processes of submarine fans and 

turbidite systems: New York, Springer-Verlag. 

Mutti, E., Normark, W.R., and Posamentier, H.W., in press, 

Turbidite systems: State of the art and implications for 

exploration: American Association of Petroleum Geologists Bulletin. 

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. 

---1975, Turbidite facies and facies associations, in Mutti, 

E., and others, eds., Examples of turbidite facies and 

associations from selected formations of the northern 

Apennines: Field trip guidebook A-11, 9th International 

Association of Sedimentologists Congress, Nice, p. 

21-36. 

Nelson, C.H., 1976, Late Pleistocene and Holocene depositional trends, processes, and history of Astoria deep-sea fan, 

northeast Pacific: Marine Geology, v. 20, p. 129-173. 

Nelson, C.H., and Nilsen, T.H., 1974, Depositional trends of 

modem and ancient deep-sea fans, in Dott, A.H., and 

Shaver, R.H., eds., Modem and ancient geosynclinal 

sedimentation: Society of Economic Paleontologists and 

Mineralogists Special Publication 19, p. 69-91. 

Nilsen, T.H., 1980, Modem and ancient submarine fans: Discussion of papers by R.G. Walker and W.R. Normark: 

American Association of Petroleum Geologists Bulletin, 

v. 64, p. 1094-1101. 

Normark, W.R., 1970, Growth patterns of deep-sea fans: 

American Association of Petroleum Geologists Bulletin, 

v.54,p.2170-2195. 

---1978, Fan valleys, channels, and depositional lobes on 

modem submarine fans-Characters for recognition of 

sandy turbidite environments: American Association of 

Petroleum Geologists Bulletin, v. 62, p. 912-931. 

---1980, Modem and ancient submarine fans: Reply: 

American Association of Petroleum Geologists Bulletin, 

v. 64,p. 1108--1112. 

---1986, Modem turbidite systems: Model limitations and 

concepts for comparing fan systems: American Association of Petroleum Geologists Bulletin, v. 70, p. 

1761-1762. 

Normark, W.R., Barnes, N.E., and Bouma, A.H., 1985, Comments and new directions for deep-sea fan research, in 

Bouma, A.H., Normark, W.R., and Barnes, N.E., eds., 

Submarine fans and related turbidite systems: New York, 

Springer-Verlag, p. 341-343. 

Pickering, K., Stow, D., Watson, M., and Hiscott, R., 1986, 

Deep-water facies, processes and models: A review and 

classification scheme for modem and ancient sediments: 

Earth-Science Reviews, v. 23, p. 75-174. 

Ricci Lucchi, F., 1975, Depositional cycles in two turbidite 

formations of northern Apennines (Italy): Journal of 

Sedimentary Petrology, v. 45, p. 3-43. 

Shanmugam, G., Damuth, J.E., and Moiola, R.J., 1985, Is the 

turbidite facies association scheme valid for interpreting 

ancient submarine fan environments?: Geology, v. 13, p. 

Deep-Water Fan Systems 23 
234--237. 

Shanmugam, G., and Moiola, R.J., 1985, Submarine fan models: Problems and solutions, in Bouma, A.H., Normark, 

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

turbidite systems: New York, Springer-Verlag, p. 29--34. 

---1988, Submarine fans: Characteristics, models, classification, and resetvoir potential: Earth-Science Review, v. 

24, p. 383-428. 

Shepard, F.P., and Dill, R.F., 1966, Submarine canyons and 

other sea valleys: Chicago, Rand McNally, 381 p. 

Sullwold, H.H., Jr., 1960, Tarzana fan, deep submarine fan of 

late Miocene age, Los Angeles County, California: 

American Association of Petroleum Geologists Bulletin, 

v. 44, p. 433-457. 

Vail, P.R., 1987, Seismic stratigraphic interpretation using 

sequence stratigraphy-Part 1: Seismic stratigraphy interpretation procedure, in Bally, A.W., ed., Atlas of 

seismic stratigraphy: American Association of Petroleum 

Geologists Studies in Geology 27, p. 1-10. 

Vail, P.R., Mitchum, R.M., and Thompson, S., 1977, Seismic 

stratigraphy and global changes of sea level, part 4: 

Global cycles of relative changes of sea level, in Payton, 

C.E., ed., Seismic stratigraphy, application to hydrocarbon exploration: American Association of Petroleum 

Geologists Memoir 26, p. 83-97. 

Walker, R.G., 1978, Deep-water sandstone facies and ancient 

submarine fans: Model for stratigraphic traps: American 

Association of Petroleum Geologists Bulletin, v. 62, p. 

932-966. 

---1980, Modern and ancient submarine fans: American 

Association Petroleum of Geologists Bulletin, v. 64, p. 

1101-1108. 

Weimer, P., and Link, M.H., in press, Seismic facies and 

sedimentary processes of submarine fans and turbidite 

systems: New York, Springer-Verlag. 

24 The Petroleum System-Status of Research and Methods, 1990 
Porosity 

By James W. Schmoker and Donald L. Gautier1 

Porosity is a volumetric measure of the interstices 

(pores) through which basin fluids must migrate and in 

which hydrocarbons are reservoired and is thus an 

important element of all petroleum systems. Porosity is 

defined as the percentage of the bulk volume of a rock 

that is occupied by interstices. Primary porosity refers to 

the original porosity still remaining. Secondary porosity 

refers to porosity developed during burial by chemical 

processes and fracturing. Effective porosity includes only 

those pores that are interconnected. 

The common methods of porosity measurement 

reflect three scales of investigation: point counting describes thin sections with a thickness of 30 micrometers; 

laboratory methods involving the displacement or injection of inert fluids (typically mercury or helium) use core 

plugs with volumes of roughly 10 cm3 ; and conventional 

wire-line logs sample rock volumes on the order of 1 m3

• 

The measurement scale of porosity determinations 

is orders of magnitude smaller than that of petroleum 

systems. Furthermore, the lateral spacing of porosity 

measurements (and frequently the vertical spacing as 

well) is typically much larger than the scale of geologic 

heterogeneity. Therefore, in order to characterize the 

porosity distribution within a petroleum system, one 

must usually extrapolate from available porosity data 

according to some predictive model. 

At the time of deposition, detrital sediments have 

porosities of 40 percent or more (Schmoker and Hester, 

1986; Houseknecht, 1987; references cited therein). In 

the subsurface, however, porosities tend to be much 

lower. The dominant trend of porosity evolution in the 

subsurface is that of porosity destruction, as processes 

act to increase the thermodynamic stability of the system 

(Choquette and Pray, 1970; Baker and others, 1980). 

The inexorable decrease of porosity during burial 

is not uniform, well-ordered, or easily comprehended, 

and therein lies the impetus for research. The primary 

thrust of current research related to porosity is not 

directed at measurement techniques but rather at the 

development of models for porosity variability in the 

subsurface. 

Efforts to quantify subsurface porosity-affecting 

processes have included classical mathematical analyses 

(Durney, 1972; Elliott, 1973; de Boer, 1977; Tada and 

1

U.S.Geological Survey, Denver, Colo. 

others, 1987), laboratory experiments (Sprunt and Nur, 

1976; de Boer and others, 1977; Baker and others, 1980), 

computer modeling of subsurface chemical systems 

(summarized by Meshri, 1987), and the application of 

fractal geometry to pore systems (Krohn, 1988). Porosity 

is a particularly intractable parameter because it represents the space between minerals under investigation 

rather than the minerals themselves. The relations between matrix change and resulting porosity modification 

are complex and depend on a number of factors including 

grain shape and packing as well as on the value of 

porosity itself (Rittenhouse, 1971; Manus and Coogan, 

1974; Mitra and Beard, 1980). 

The progress being made in mathematical, experimental, and chemical studies of processes affecting subsurface porosity is substantial. Nevertheless, the 

quantitative evaluation of reservoir properties using 

these approaches is as yet beyond reach. Porosity change 

with burial must still be considered on a largely empirical 

basis. 

Processes of mechanical compaction, chemical 

compaction, cementation, and dissolution all play significant roles in the evolution of subsurface porosity. Mechanical compaction reduces porosity by reorientation 

and fracture of grains and by ductile deformation of 

grains and matrix. Chemical compaction results in closer 

grain spacing due to the dissolution of grains at points of· 

contact. Cementation occludes pores by the precipitation 

of authigenic minerals. Dissolution creates secondary 

pores by the chemical removal of framework grains or 

cement. (Dissolved material. may be reprecipitated nearby, so that the development of secondary pores does not 

necessarily increase overall porosity.) 

These four basic porosity-affecting processes are 

modified and controlled by a host of geologic factors. A 

partial list includes depositional environment, lithology, 

petrographic characteristics, patterns of meteoric-water 

circulation, chemistry of basin brines, presence of hydrocarbons, overpressuring, and proximity to fluid conduits 

such as faults and unconformities. 

A large literature has accumulated empirically 

describing processes affecting subsurface porosity evolution and the modifying effects upon these processes of 

geologic factors such as those just listed. Significant 

research along these lines is continuing, as evidenced by 

numerous recent publications (for example, McDonald 

and Surdam, 1984; Scholle and Halley, 1985; Humphrey 

and others, 1986; Porter and James, 1986; Giles, 1987; 

Porosity 25 
Houseknecht, 1987, 1988; McBride and others, 1987; 

Scherer, 1987; Tada and others, 1987; Dutton and Land, 

1988; Pittman, 1988; Shanmugam and Higgins, 1988; 

Wilson and McBride, 1988; Surdam and others, 1989). 

As suggested by the preceding discussion, any 

viable predictive model for porosity variability in the 

subsurface must take into account processes as modified 

by geologic factors. That is, predictive porosity models 

must recognize individual diagenetic facies. 

In addition, predictive models must also take rates 

of processes into account, in order to assess porosity 

change through time and burial within a given diagenetic 

facies. A common approach to this problem, and one that 

has been used repeatedly over the years, is to predict 

porosity change by correlating porosity to burial depth 

(for example, Athy, 1930; Maxwell, 1964; Baldwin and 

Butler, 1985). Depth can be accurately measured, and 

porosity-depth plots are of practical value for porosity 

prediction in some circumstances. 

Depth, however, is a position coordinate that only 

specifies present-day location. As such, depth is not a 

causal variable and can be a poor indicator of the rates of 

processes that have acted upon a formation through time. 

If a region of interest is expanded to encompass more 

than a homogeneous thermal regime or a uniform burial 

history, porosity-depth plots lose their predictive value. 

In the final analysis, processes of porosity change in 

the subsurface are influenced by time and temperature; 

time-temperature exposure (thermal maturity) is the 

relevant parameter for subsurface reaction kinetics 

(Siever, 1983). Plots of porosity versus thermal maturity 

(as opposed to depth), which typically show a powerfunction relationship, thus offer an alternative approach 

to the prediction of porosity change within a given facies 

(Schmoker, 1984; Schmoker and Gautier, 1988). 

REFERENCES CITED 

Athy, L.F., 1930, Density, porosity, and compaction of sedimentary rocks: American Association of Petroleum Geologists Bulletin, v. 14, no. 1, p. 1-24. 

Baker, P.A., Kastner, M., Byerlee, J.D., and Lockner, D.A., 

1980, Pressure solution and hydrothermal recrystallization of carbonate sediments-An experimental study: 

Marine Geology, v. 38, p. 185-203. 

Baldwin, Brewster, and Butler, C.O., 1985, Compaction curves: 

American Association of Petroleum Geologists Bulletin, 

v. 69,no. 4,p. 622-626. 

Choquette, P.W., and Pray, L.C., 1970, Geologic nomenclature 

and classification of porosity in sedimentary carbonates: 

American Association of Petroleum Geologists Bulletin, 

v.54,no. 2,p.207-250. 

de Boer, R.B., 1977, On the thermodynamics of pressure 

solution-Interaction between chemical and mechanical 

forces: Geochimica et Cosmochimica Acta, v. 41, no. 2, 

p. 249-256. 

de Boer, R.B., Nagtegaal, P J.C., and Duyvis, E.M., 1977, 

Pressure solution experiments on quartz sand: Geochimica et Cosmochimica Acta, v. 41, no. 2, p. 257-264. 

Durney, D.W., 1972, Solution transfer, an important geological 

deformation mechanism: Nature, v. 235, no. 5332, p. 

315-317. 

Dutton, S.P., and Land, L.S., 1988, Cementation and burial 

history of a low-permeability quartzarenite, Lower Cretaceous Travis Peak Formation, east Texas: Geological 

Society of America Bulletin, v. 100, no. 8, p. 1271-1282. 

Elliott, David, 1973, Diffusion flow laws in metamorphic rocks: 

Geological Society of America Bulletin, v. 84, no. 8, p. 

2645-2664. 

Giles, M.R., 1987, Mass transfer and problems of secondary 

porosity creation in deeply buried hydrocarbon reservoirs: Marine and Petroleum Geology, v. 4 (August), p. 

188-204. 

Houseknecht, D.W., 1987, Assessing the relative importance of 

compaction processes and cementation to reduction of 

porosity in sandstones: American Association of Petroleum Geologists Bulletin, v. 71, no. 6, p. 633-642. 

---1988, Intergranular pressure solution in four quartzose 

sandstones: Journal of Sedimentary Petrology, v. 58, no. 

2, p. 228-246. 

Humphrey, J.D., Ransom, K.L., and Matthews, R.K., 1986, 

Early meteoric diagenetic control of Upper Smackover 

production, Oaks Field, Louisiana: American Association of Petroleum Geologists Bulletin, v. 70, no. 1, p. 

70-85. 

Krohn, C.E., 1988, Sandstone fractal and euclidean pore volume distributions: Journal of Geophysical Research, v. 

93, no. B4, p. 3286-3296. 

Manus, R.W., and Coogan, A.H., 1974, Bulk volume reduction 

and pressure-solution derived cement: Journal of Sedimentary Petrology, v. 44, no. 2, p. 466-471. 

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, p. 697-709. 

McBride, E.F., Land, L.S., and Mack, L.E., 1987, Diagenesis of 

eolian and fluvial feldspathic sandstones, Norphlet Formation (Upper Jurassic), Rankin County, Mississippi, 

and Mobile County, Alabama: American Association of 

Petroleum Geologists Bulletin, v. 71, no. 9, p. 

1019-1034. 

McDonald, D.A., and Surdam, R.C., eds., 1984, Oastic diagenesis: American Association of Petroleum Geologists 

Memoir 37, 434 p. 

Meshri, I.D., 1987, AAPG Research Conference-Prediction 

of reservoir quality through chemical modeling: American Association of Petroleum Geologists Bulletin, v. 71, 

no. 11, p. 1436-1439. 

Mitra, Shankar, and Beard, W.C., 1980, Theoretical models of 

porosity reduction by pressure solution for well-sorted 

sandstones: Journal of Sedimentary Petrology, v. 50, no. 

4, p. 1347-1360. 

Pittman, E.D., 1988, Diagenesis of Terry Sandstone (Upper 

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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. 

26 The Petroleum System-Status of Research and Methods, 1990 
359-369. 

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Geologists Bulletin, v. 55, no. 1, p. 80-91. 

Scherer, M., 1987, Parameters influencing porosity in sandstones: A model for sandstone porosity prediction: 

American Association of Petroleum Geologists Bulletin, 

v. 71,no. 5,p.485-491. 

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. 

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1007-1010. 

Schmoker, J.W., and Hester, T.C., 1986, Porosity ofthe Miami 

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5, p. 523-535. 

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Porosity 27 
Clays 

By Richard M. Poll astra 1 

Over the past few decades there has been an 

increased interest in the study of clay and clay minerals as 

applied to petroleum geology. Much of this interest has 

been generated because clay minerals can be beneficial; 

they are useful as potential exploration tools for understanding basin, source-rock, and reservoir histories. In 

contrast, it is almost a necessity to identify the type and 

nature of the clay in a potential reservoir rock to avoid 

serious problems during the production and recovery of 

hydrocarbons. It is the purpose of this report, however, to 

address the application of clays in petroleum studies with 

particular attention to specific clay methods that aid in 

evaluating the thermal history of sedimentary basins. In 

terms of the petroleum system, these methods are extremely useful in assessing the thermal history of a 

petroleum source rock. 

Prior to about 1970, a gap existed in the clay 

science literature addressing the problems and applica- · 

tions of clays in petroleum geology. The possible role of 

clays in the sear~h for oil was first addressed by Weaver 

(1960). However, not until the 1970's and 1980's, which 

I refer to as the "decades of diagenesis," was there 

significant interest and recognition in clay minerals as 

related to petroleum geology. During the past decade, 

however, research groups, conferences, and symposia 

addressing clays and hydrocarbons have resulted in special volumes and journal issues dedicated almost exclusively to the subject. 

The earliest of these volumes containing several 

articles that described and illustrated the significance of 

clays in petroleum applications wasAspects of Diagenesis, 

edited by Scholle and Schluger (1979); a much less visible 

publication entitled Geothermal Alteration of Clay Minerals and Shales: Diagenesis, by Weaver (1979), also had 

considerable impact. Shortly thereafter, a short course 

sponsored by the Mineralogical Association of Canada 

resulted in a relatively informal publication entitled Clays 

and the Resource Geologist, edited by F.J. Longstaffe 

(1981 ). Special issues of Clays and Clay Minerals 

(1986a,b ), both the "Clays in the Petroleum Industry 

Issue" (v. 34, no. 2) and "John Hower Memorial Issue" 

(v. 34, no. 4), contain numerous method and case history 

articles. Most recently, short course notes entitled Clay 

Minerals for Petroleum Geologists and Engineers, by E. 

1

U.S. Geological Suxvey, Denver, Colo. 

Eslinger and D.R. Pevear (1988), provide an excellent 

overview of theory, interpretation, and case histories. 

The most promising clay methods used in petroleum geology are those involving the application of clay 

diagenesis to the thermal and burial history of sedimentary rocks and basins. These methods can therefore also 

be applied to studies addressing the maturation, generation, and migration of hydrocarbons. All of the applications mentioned above involve the concepts of shale 

diagenesis that were first described in detail from studies 

of buried shale sequences in the Gulf Coast (Powers, 

1957; Burst, 1959; Perry and Hower, 1970; Weaver and 

Beck, 1971; Hower and others, 1976). The most important diagenetic clay reaction in shales is the progressive 

transformation of smectite to illite by way of a series of 

mixed-layer illite/smectite (I/S) intermediates; this particular reaction series is commonly referred to as smectite diagenesis. Presently, there is a major controversy in 

clay science over the true crystallographic nature of 

material identified as 1/S by X-ray powder diffraction 

(XRD). However, whether these changes are interpreted 

by the mixed-layer (Markovian) model (MacEwan, 1956, 

1958; Reynolds, 1980) or the fundamental particle 

(Nadeau and others, 1984a,b) concepts, the reaction 

results in a progressive and irreversible increase in illite 

and corresponding decrease in expand ability (commonly 

interpreted as smectite). 

Recognition of smectite diagenesis is based mainly 

on the interpretation of XRD profiles. Interpretations of 

the changes in XRD profiles of I/S were first defined in 

detail by Reynolds and Hower (1970) who compared 

XRD profiles of natural materials to those calculated by 

computer. Their methods defined three basic, naturally 

occurring forms of 1/S ordering: random (R=O) ordering, short-range or allevardite-like (R=1) ordering, and 

long-range or Kalkberg-like (R 2:: 3) ordering. A method 

to calculate the approximate percentages of illite and 

smectite (expandable) layers in the mixed-layer phase 

also was proposed. Subsequently, numerous changes and 

updates in the modeling program have been made by 

Robert C. Reynolds Jr.; the latest version of the program, 

entitled NEWMOD, is available from Reynolds (Department of Earth Sciences, Dartmouth College, Hanover, 

NH 03755). In addition, several other methods have been 

described in the literature after the work of Reynolds and 

Hower for interpreting XRD profiles of liS (Schultz, 

1978; Srodon, 1980; Srodon and Eberl, 1984; Inoue and 

others, 1989). 

28 The Petroleum System-Status of Research and Methods, 1990 
The most useful clay method applied to petroleum 

geology studies is clay mineral geothermometry. Concepts and models of clay geothermometry in diagenetic 

settings were first proposed by Hoffman and Hower 

(1979) and Weaver (1979). Changes in the 1/S "phase" 

interpreted from XRD profiles show consistent relations 

with depth which, in fact, are related primarily to changes 

in temperature due to burial. Similar clay/temperature 

relations have been demonstrated for hydrothermal fluid 

systems and low-grade contact metamorphic situations. 

However, temperatures for changes in 1/S phase differ in 

hydrothermal systems as compared to those temperatures for similar changes in 1/S from progressive burial 

settings. These changes in 1/S, therefore, are reliable 

maximum recording geothermometers provided that the 

proper temperature model is used (Pytte and Reynolds, 

1989; Pollastro, 1989). During the last decade, numerous 

case history studies have applied and tested 1/S clay 

models in diagenetic and hydrothermal settings worldwide. Other clay minerals that have been formed, destroyed, or changed during diagenesis, as well as 1/S, also 

give reliable temperatures. No other clay minerals, however, have been studied or tested to the extent of the 1/S 

series. . 

The most important change in 1/S in relation to 

hydrocarbons is the conversion from random 1/S (R=O) 

to ordered 1/S (R=1). In samples from well profiles, the 

primary criterion for recognition of this conversion is the 

absence, or disappearance in downhole samples, of the 

17 -angstrom glycol 001 reflection on XRD patterns. The 

immediate change is recognized by the presence of a 

lesser expandable phase with smaller d-spacing (usually 

about 13 to 14 angstroms upon glycol solvation). However, the 001 glycol reflection of 1/S \_Vith R ~ 1 shifts 

between 10 and 14 angstroms, depending upon specific 

composition and degree of ordering (Reynolds and Hower, 1970). If the actual change in the 1/S reflections on 

XRD profiles cannot be recognized from random sampling or sample profiles, however, sufficient evidence 

must be established from control samples that a precursor 17 -angstrom glycol, random -ordered phase existed 

before the 1/S can be used as an absolute geothermometer. It is critical, therefore, to establish original compositions of these clays because detrital 1/S may have 

undergone extensive illitization during a previous cycle 

(Pollastro and Scholle, 1986). 

In burial diagenetic settings, this major change in 

1/S {R=O to R=1) occurs in the temperature range of 

about 100 to 110 oc (Hoffman and Hower, 1979) and is 

roughly coincident with the onset of oil generation in 

rocks of Tertiary through Cretaceous age. In relatively 

short-lived (commonly < 2 m.y.) geothermal systems, 

however, the temperature of this particular 1/S change is 

about 130 to 140 °C. I/S with R = 1 ordering, typically with 

60 to 80 percent illite layers, is thermally stable between 

100 and 175 °C. This temperature range is roughly 

coincident with the "oil window." Therefore, the simplest 

application of clays in burial diagenetic settings is to 

record the 100 to 110 oc isotherm using the R=O to R=1 

transition (Pollastro and Scholle, 1986; Pollastro and 

Schmoker, 1988), thereby providing an index of thermal 

maturity relative to hydrocarbon generation (Foscolos 

and Powell, 1980; Pollastro and Scholle, 1986). The 

method also has been used in modeling the thermal 

history of sedimentary basins (Bethke and others, 1988; 

Hagen and Surdam, 1989). This method is particularly 

valuable for samples lacking either vitrinite or other 

indicators from which the maturity level can be estimated 

directly. For example, the presence of a distinct 17-

angstrom glycol XRD peak suggests that the rock is 

immature or marginally mature with respect to oil generation. Temperatures determined for this change in I/S 

phase shows excellent agreement when compared to 

temperatures calculated from mean vitrinite reflectance 

and "Tmax" {Pevear and others, 1980; Burtner and 

Warner, 1986; Pollastro and Barker, 1986; Glassman and 

others, 1989, among others). Other studies have related 

this change in 1/S to particular stages of oil generation 

(Weaver, 1979; Pollastro and Schmoker, 1988). 

Clay geothermometry from changes in 1/S observed 

on XRD profiles is also reliable at temperatures higher 

than the change from R=O toR= 1. The conversion from 

R=1 to R~3 ordering occurs at about 175-180 oc 

(Hoffman and Hower, 1979) and can document the 

upper limit of oil generation for a particular potential 

source rock. A sample containing only R ~ 3 1/S would, 

therefore, be overmature with respect to oil generation 

and only would have potential to generate thermal methane. At temperatures exceeding those of the 1/S transformation series, a different method in clay 

geothermometry is widely used. This method involves 

measurement on XRD profiles of peak width or a 

height-to-width ratio of the illite 001 {10-angstrom) reflection. Various forms of this method are referred to as 

"illite crystallinity," "crystallinity index," "Kubler index," 

"Weaver index," and "sharpness ratio" (Weaver, 1960, 

1979; Kubler, 1964; Heroux and others, 1979). Although 

illite crystallinity correlates with vitrinite reflectance, the 

method is commonly applicable to levels of thermal 

maturity exceeding those for the generation of hydrocarbons. 

Smectite diagenesis, specifically the major I/S 

change at 100 to 110 oc in progressive burial settings, has 

several other implications in petroleum geology. However, many of these implications are unclear and will 

require further research. For example, Surdam and others (1984, 1989) and Surdam and Crossey (1985) have 

used the coincidence in time and temperature of organic 

and clay reactions for characterizing the diagenesis of 

reservoir/source rock systems. The major liS reaction at 

100 to 110 oc is coincident with temperatures of organic 

acid maxima {80-120 °C). These authors suggested that 

Clays 29 
mineral oxidants and dehydration reactions involved in 

the conversion of smectite to illite contribute to creating 

optimum diagenetic conditions for maximizing porosity 

preservation or enhancement in sandstone reservoirs. In 

contrast, many other authors have addressed smectite 

diagenesis as a contributor to reservoir cementation 

(Towe, 1962; Boles and Franks, 1979; McHargue and 

Price, 1982). Others suggest that the diagenetic transformation of smectite to illite results in increased catalytic 

activity that promotes the low-temperature transformation of organic matter into liquid and gaseous hydrocarbons (Johns, 1979; 1981; Johns and McKallip, 1989). 

Smectite diagenesis or specific changes in I/S have also 

been correlated to expulsion or migration of hydrocarbons and zones of abnormal geopressures (Powers, 1967; 

Burst, 1969; Bruce, 1984; Colton-Bradley, 1987; Shaw 

and Primmer, 1989). 

In summary, clay minerals are useful tools in 

understanding both the depositional and diagenetic settings of sedimentary rocks. In particular, the major clay 

reaction in buried sedimentary rocks, the conversion of 

smectite to illite through I/S intermediates, is an excellent 

maximum recording geothermometer. Methods of clay 

geothermometry, therefore, can greatly assist in evaluating the thermal history of a sedimentary basin. Specific 

clay geothermometers are approximately coincident with 

temperatures for hydrocarbon "windows." In a petroleum system, therefore, clays are useful in determining 

the thermal history of source rocks. 

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30 The Petroleum System-Status of Research and Methods, 1990 
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Clays 31 
Fission-Track Analysis in Petroleum Basins 

By Nancy D. Naeser1 

THE FISSION-TRACK METHOD 

Fission tracks are zones of intense damage formed 

when fission fragments travel through a solid. Several 

naturally occurring isotopes fission spontaneously, but 

only 238U has a sufficiently short fission half-life 

(9.9X 1015 yr) to produce significant numbers of tracks 

over times of geologic interest (Fleischer and others, 

1975). 

A number of common minerals contain trace 

amounts of uranium. Because 238U fissions spontaneously at a known rate, fission tracks can be used to date these 

minerals. An age can be calculated by determining the 

number of spontaneous tracks intersecting a polished 

surface of the mineral and the amount of uranium that 

produced those tracks. The two minerals most commonly 

dated by the fission-track method are apatite and zircon. 

The techniques used in dating have been developed by 

physicists and geologists since the early 1960's (Fleischer 

and others, 1975; C.W. Naeser, 1976, 1979a; N.D. 

Naeser and others, 1989b). 

If a mineral containing fission tracks is heated to a 

high enough temperature, the damage zone undergoes 

progressive shortening and ultimately disappears, leading 

to a reduction in the number of observable tracks and 

thus an anomalously young fission-track age. Different 

minerals undergo this "annealing" over different temperature ranges. The range for any given mineral depends on 

the duration of heating: the longer the mineral is heated, 

the lower the temperature required to anneal its tracks. 

More research has been devoted to determining 

the annealing kinetics of apatite than any other mineral. 

Data have been obtained both from 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; Crowley 

and Cameron, 1987, in press; Laslett and others, 1987; 

Crowley and others, 1988; Duddy and others, 1988; 

Green, 1988; Hughes and others, 1988) and by observing 

the annealing behavior of apatite in drill holes in areas 

where the thermal history of the rocks is reasonably well 

known (C.W. Naeser, 1979a, 1981; Gleadow and Duddy, 

1981; N.D. Naeser and others, 1987a, 1989a). 

Ongoing research continues to more accurately 

define apatite annealing kinetics, clarify the response of 

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

apatite track lengths to annealing (particularly in detrital 

suites derived from a number of parent rocks of different 

age and thermal history), and improve the predictive 

capabilities of apatite annealing models. One topic that 

has received considerable attention in recent years is the 

effect of chemical composition on annealing temperatures of apatite. It now appears that the annealing 

susceptibilities of F-, Sr-F-, and OH- apatite are so 

similar that all can probably be approximated by Fapatite data. Chlorapatite, however, is significantly more 

resistant to annealing; at fixed heating times in the 

laboratory, it anneals at temperatures up to 30 oc higher 

than other apatite varieties (Crowley and Cameron, 

1987; Crowley and others, 1988; Hughes and others, 

1988). Similiar variation in annealing temperatures related to Cl content is observed in drill-hole samples from 

the Otway basin, Australia (Green and others, 1985, 

1989). Available information indicates that, in contrast to 

the Otway Basin, apatite suites are typically dominated 

by fluorapatite with insignificant chlorine (for example, 

Berry and Mason, 1959; Deer and others, 1962; N.D. 

Naeser and others, 1989a) and can reasonably be interpreted using fluorapatite annealing temperatures. Nevertheless, until the effects of composition on annealing 

temperatures are fully resolved, this topic will undoubtedly continue to be investigated, and it should be considered when interpreting apatite fission-track data. 

The most complete set of empirically derived annealing temperatures presently available (C.W. Naeser, 

1981) was determined on fluorapatite (K.D. Crowley, 

written communication, 1988). These data indicate that 

apatite is effectively totally annealed (yields a zero age) at 

temperatures that range from about 105 °C for relatively 

long-term heating of about 100 million years duration to 

150 oc for about 100,000 years. 

Annealing temperatures for zircon are not as well 

known as for apatite, but limited data show that they are 

higher and are probably in the range of 160 to 250 oc for 

heating over periods of more than 1 million years (for 

example, Harrison and others, 1979; C.W. Naeser, 

1979a; Zeitler, 1985; Hurford, 1986). 

BASIN ANALYSIS 

Fission tracks in apatite and zircon are used in a 

wide range of studies in basin analysis (reviewed in N.D. 

Naeser and others, 1989b ). The annealing of fission 

32 The Petroleum System-Status of Research and Methods, 1990 
tracks, and the resulting effect on fission-track age and 

track lengths, particularly in apatite, can be used to 

reconstruct the thermal history of basins, from the deposition and burial of sediments through subsequent cooling related to uplift and erosion. Annealing can also be 

used to define more localized temperature anomalies, 

such as those related to intrusions and to the passage of 

high-temperature fluids through a basin (C.W. Naeser, 

1979b; Gleadow and others, 1983, 1986a, 1986b; Green 

and others, 1989; N.D. Naeser and others, 1989b). The 

first study using fission tracks to reconstruct the thermal 

history of a basin appeared only 10 years ago, but the 

method has now been used in basins throughout the 

world (for example, Briggs and others, 1979, 1981a, 

1981b; Duddy and Gleadow, 1982, 1985; Gleadow and 

others, 1983; Lakatos and Miller, 1983; Gleadow and 

Duddy, 1984; N.D. Naeser, 1984, 1986, in press; Johnsson, 1985, 1986; Giegengack and others, 1986; Marshallsea, 1986; Miller and others, 1986; Duddy and 

others, 1987; N.D. Naeser and others, 1987a, 1989a, 

1989b, in press; Dumitru, 1988, 1989; Feinstein and 

others, 1989; Green and others, 1989). Fission tracks in 

apatite and zircon are attractive for studying the thermal 

history of basins because they provide both temperature 

and time information over a temperature · range that 

coincides with hydrocarbon generation temperatures 

(Hood and others, 1975; Waples, 1980; N.D. Naeser and 

others, 1989b ), temperatures recorded in the 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), and temperatures associated with a 

number of other low- to moderate-temperature processes in basins such as, clay diagenesis and conodont color 

alteration. 

Typically, information on thermal history of basins 

is provided by apatite because most rocks sampled in 

basins have not been heated to temperatures sufficiently 

high to anneal zircon. The presence of unannealed zircon 

does, however, set approximate limits on maximum paleotemperatures, and the ages of individual unannealed 

zircon grains provide data on the provenance of sediments that may be difficult to obtain by other methods. 

For example, within a detrital grain suite it may be 

possible to correlate individual age populations to pro~­

able parent rocks in order to delineate sediment transport patterns in a basin (Zeitler and others, 1982, 1986; 

Hurford and others, 1984; Johnson, 1984; Yim and 

others, 1985; Baldwin and others, 1986). Changes in the 

age populations observed in a series of samples collected 

through a stratigraphic section in a basin can be used to 

reconstruct changes in sedimentation patterns, to define 

input from different source areas, and to reconstruct the 

uplift and erosion history of the parent rocks (Zeitler and 

others, 1982, 1986; N.D. Naeser and others, 1987b; 

Cerveny and others, 1988). 

Zircon has also been used extensively to date 

volcanic ashes (and their altered equivalents, bentonites 

and tonsteins) (reviewed in C.W. Naeser and N.D. 

Naeser, 1988). These units form widespread marker 

horizons that can be valuable for establishing correlation 

and chronology within sedimentary sequences. 

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Fission-Track Analysis In Petroleum Basins 33 
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34 The Petroleum System-Status of Research and Methods, 1990 
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467-468. 

Fission-Track Analysis In Petroleum Basins 35 
Geothermics Applied to the Reconstruction of 

Subsurface Temperatures 

By Charles E. Barker 1 

INTRODUCTION 

Determination of accurate subsurface temperatures is a crucial element of petroleum geology. Yet 

accurate measurement has proven to be an imprecise, 

error-prone procedure whether in the simpler case of 

present-day formation temperature, or the more difficult 

evaluation of paleotemperature. This paper overviews 

methods of determining both modern and ancient subsurface temperatures. The treatment is not comprehensive, and emphasizes the most recent literature and 

techniques that I have found useful. Only relevant summary papers are cited in the text. The methodology 

discussion is supplemented by an extended bibliography. 

If the subject of the reference is not sufficiently clear in 

the title, the citation is annotated. 

CORRECTION OF TEMPERATURE 

MEASUREMENTS 

Direct determination of accurate present-day formation temperature in wells requires thermal equilibrium before measurement. A rule of thumb is that it 

requires about the same amount of time for a well to 

recover from drilling fluid circulation effects as it took to 

driii the well (Builard, 1947). However, usually this 

length of reequilibration time is not available before a 

bottom hole temperature (BHT) is measured, usually 

within a few hours of drilling. Most BHT's do not 

represent true (equilibrium) formation temperature and 

the measurement must be corrected. 

Statistical Correction Methods 

The information necessary to calculate a correction 

to logged temperature to equilibrium formation temperature is often not included, or is inaccurate, in the wen 

logging reports (Carstens and Finstad, 1981; Catala, 

1984). Thus, accurate correction of BHT is difficult. For 

all of the uncertainty in determining the true formation 

temperature, it is reasonable to make a BHT correction 

1

U.S. Geological Sutvey, Denver, Colo. 

because we do know that equilibrium formation temperature is higher than an unequilibrated BHT. The simplest correction is to compile producing wen 

temperatures (or drill stem test information) and the 

corresponding BHT at reservoir depth for computation 

of a correction curve. The correction is made by adding 

the difference between the higher formation temperature 

and the lower BHT data calculated at the bottom hole 

depth. The quality of correction improves with the type of 

data available, with the best case being careful measurements repeated over time until temperature no longer 

changes. A widely used statistical correction is the AAPG 

method (AAPG, 1976; see also Scott, 1982). The AAPG 

correction was developed in and applied to wide geographic areas and has proved inaccurate in parts of some 

basins. The statistical approach, in general, is imprecise 

as shown by a wide data scatter about the correction 

curve generated for a single basin (for example, Chueng, 

1979). Although imprecise, the statistical method in 

many cases is the only correction possible. 

Empirical Correction Methods 

Commonly used empirical techniques are (1) the 

Horner plot (limits of application in Dowdle and Cobb, 

1975, and (2) the Middleton (1979) curve-matching 

method. Leblanc and others (1982) suggested use of the 

Horner plot when the mud equilibration time to the BHT 

measurement is known, and the curve-matching technique when it is not known. 

Present Temperature-Depth Reconstruction 

A geothermal gradient is calculated by interpolation using mean annual surface temperature to the depth 

of the corrected BHT. This linear approximation can be 

highly inaccurate because the vertical and lateral temperature profile can change with lithology (thermal conductivity), different fluids filling the pores, subsurface fluid 

flow, and so forth. This constructed geothermal gradient 

gives no information about paleotemperature. Many 

workers assume, in the absence of compeiiing information to the contrary, that present measurements can be 

extended into the past. Such an assumption often cannot 

be contradicted with other geologic information, and it is 

a useful first approximation. 

36 The Petroleum System-Status of Research and Methods, 1990 
In the absence of detailed paleotemperature evidence, the calculated geothermal gradient is often assumed to remain constant without regard to temporal 

heat-flow variation and diagenesis (primarily porosity 

loss) or change in lithology. Thus, a detailed geologic 

analysis is unfortunately reduced to time-temperature 

data by simplification of the geothermal gradient into a 

linear form and ignoring its possible temporal change. 

However, gaps in the geologic record, and the data 

quality and quantity available, often will not permit a 

more sophisticated approach. An accurate timetemperature determination is crucial to Lopatin thermal 

maturity (TTl) estimates because it is sensitive to small 

changes in subsurface temperature; an increase of just 10 

°C increases TTl by 100 percent. 

THERMAL HISTORY RECONSTRUCTION 

Paleotemperature reconstruction requires geologic 

data to document the temporal change in (1) the values 

of geothermal gradient, surface temperature, and burial 

depth history or (2) heat flow and thermal conductivity. 

These data are difficult to reconstruct because the ternperature regime has often changed, and burial history 

may be altered or obliterated by compaction, erosion, 

and structural complexities. Further, present-day measurements should be calculated to a decompacted value. 

For example, thermal conductivity is dependent in part 

on the porosity and the fluid filling it. So contemporary 

thermal conductivity measurements must be adjusted 

(lowered) to the former (higher) levels of porosity (Lewis 

and Rose, 1970) and must consider in some cases the 

displacement of pore water by oil and( or) gas. 

A paleo surface temperature is required to estimate 

subsurface temperature if only a paleogeothermal gradient is available. Surface temperature estimates can be 

made using four methods: (1) fossil evidence for paleoclimate (Savin, 1977); (2) reconstruction of paleolatitude 

by use of continental drift models (Weijermars, 1989; 

Dagger, 1989) and present models of broad latitudinal 

and elevation control of mean surface temperature2

; (3) 

contemporary measurements before apparent perturbation by the greenhouse effect (Darton, 1913); and (4) 

average near-surface water temperature (Blakey, 1966). 

l7he present surface temperature of the Earth as a function of 

north or south latitude (lat) is T=27.6-(0.04lat)-(0.006la~) (~=0.99; 

computed using data from the U.S. Weather Bureau). Note that the 

average global temperature is now 15 oc, but in the past has decreased 

to as low as 10 oc in the coldest glacial periods and has been as high 

as 22 oc, so this function must be carefully applied. Also, an elevation 

correction may have to be applied. 

Burial Depth History 

Burial depth reconstruction is usually based on a 

simple layer-cake concept of sediment accumulation. 

Another approach is to model the rate of sedimentation 

through time. Burial curves should be corrected for 

compaction (Perrier and Quiblier, 1974) to improve 

accuracy in paleodepth assessment. Paleotemperature 

history is computed using burial depth through time and 

the estimated geothermal gradients (Waples, 1985). 

Erosion Estimates 

The simplest method for determining depth of 

erosion is by stratigraphic projection of formation thickness from a related uneroded section to the eroded one, 

or measure the sediment thickness eroded from the crest 

of folded beds (see discussion in Magara, 1986). Geologic or geochemical parameters that vary regularly with 

depth and do not significantly change during exhumation 

can also indicate depth of erosion (gradient method). For 

example, using thermal maturation data, the slope and 

intercept of the vitrinite reflectance-depth profile are 

measured. A semilogarithmic plot of vitrinite reflectance 

and depth straightens the maturation curve projection to 

the vitrinite reflectance estimate at the pre-existing 

ground surface (Dow, 1977). Projecting the regression 

curve to a paleosurface vitrinite reflectance value of 0.2 

percent indicates an eroded thickness in good agreement 

with other geologic data (Nuccio and Barker, 1989). The 

gradient method must be modified to work thermal 

maturity data across with buried erosional surfaces (Katz 

and others, 1988). 

Thermal History Reconstruction 

Once surface temperature, paleodepth, and paleotemperature estimates are reconstructed, a geothermal 

gradient is calculated by a procedure similar to that used 

with BHT data. As for present-day temperature data, 

linear interpolation in a heterogeneous sediment pile 

makes many assumptions that are not very robust, but 

often it is the only method available. The thermal history 

(temperature at some point as a function of geologic 

time) is calculated by using paleogeothermal gradients 

reconstructed for each time period and calculating temperature based on surface temperature and paleodepth 

from the depth-time curve. 

Paleotemperature from Thermal Conductivity 

and Heat Flow 

Fourier's law states that the heat flow is directly 

proportional to thermal conductivity of the strata and the 

geothermal gradient. The temperature at the bottom of a 

sediment package is determined by using Fourier's law 

Geothermic& Applied to the Reconstruction of Subsurface Temperatures 37 
relating the temperature at the top of the unit (initially 

the average surface temperature), its thermal conductivity, and local terrestrial heat flo~ (Gretener, 1981; 

Buntebarth, 1984). A modification of this technique is 

the thermal resistance (Bullard) method of computing 

subsurface temperature (Andrews-Speed and others, 

1984). Contemporary terrestrial heat-flow measurements throughout the world are available from regional 

contour maps. The thermal conductivity of a rock unit is 

estimated using a weighted average proportioned to the 

abundance and thermal conductivity of each lithology 

present (as suggested by Reiter and Tovar, 1982). An 

important consideration in the thermal conductivity computation, because it is a bulk property, is the porosity and 

pore fluid composition. For example, experiments by 

Woodside and Messmer (1961) and theoretical modeling 

(Lewis and Rose, 1970; Buntebarth, 1984) show that 

filling pores with oil and( or) gas can cause major reduction of bulk-rock thermal conductivity. 

Direct Geothermometry 

Geothermometers based on inorganic materials 

(fluid inclusions, diagenetic mineral assemblages, illite 

crystallinity, isotopes, and so forth) and organic matter 

(rank indices of kerogen or coal) have been calibrated to 

burial temperature (Frey, 1987). The limitation of these 

geothermometers is that the thermal history must be 

recorded in the rocks. Thermal events can be difficult to 

record in sedimentary systems because of the slowness of 

low-temperature equilibration reactions. The short-term 

nature of some thermal events may also preclude them 

from leaving an imprint on the rock. These problems 

notwithstanding, direct geothermometry has proved to be 

a useful tool in subsurface paleotemperature studies. 

DISCUSSION 

Thermal history reconstructions are often fragile 

interpretations of geologic semi-fact, because they are 

based on many assumptions and extrapolations (the 

proverbial house of cards). The validity of these reconstructions should be evaluated on a case by case basis. 

The best check is to make both direct and indirect 

estimates of the thermal history using all possible methods and data. 

3Conversion factors: Geothermal gradient: °C/km=18.23 °F/100 

ft. Heat Flow: HFU=l microcal/cm2-s=41.8 mW/m2

• Thermal conductivity: W/m-°C=2.4 mcal/cm-s-0

C. 

SELECTED REFERENCES 

Thermal History Reconstruction 

Buntebarth, G., 1984, Geothermics: New York, SpringerVerlag, 144 p. 

Buntebarth, G., and Stegena, L., 1986, eds., Paleogeothermics: 

New York, Springer-Verlag, 234 p. 

Bustin, R.M., Cameron, A.R., Grieve, D.A., and Kalkreuth, 

W.D., 1983, Coal petrology, its principles, methods and 

applications: Geological Society of Canada, Short 

Course Notes, v. 3, 230 p. 

Frey, M., ed., 1987, Low temperature metamorphism: Glasgow, 

Blackie and Son, 351 p. 

Gretener, P.E., 1981, Geothermics: Using temperature in hydrocarbon exploration: American Association of Petroleum Geologists, Education Course Notes 17, 156 p. 

Kappelmeyer, 0. and Haenel, R., 1974, Geothermics with 

special reference to application: Berlin, Gebruder Bomtraeger, 238 p. 

North, F.K., 1985, Petroleum geology: London, Allen and 

Unwin, 607 p. 

Robert, 1988, Organic metamorphism and geothermal history: 

Dordrecht, Neth., Reidel, 311 p. 

Stach, E., Mackowsky, M.-Th., Teichmuller, M., Taylor, G.H., 

Chandra, D., and Teichmuller, R., 1982, Stach's textbook 

of coal petrology (3d ed.): Berlin, Gebriider Bomtraeger, 

535 p. 

Tissot, B.P., and Welte, D.H., 1984, Petroleum formation and 

occurrence, 2d ed.: New York, Springer-Verlag, 699 p. 

Turcotte, D. L., and Schuburt, G., 1982, Geodynamics: applications of continuum physics to geological problems: 

New York, Wiley, 450 p. 

Surface Temperature 

Berry, G.W., Grim, P.J., and lkelman, J.A., 1980, Thermal 

springs list for the United States: National Oceanic and 

Atmospheric Administration Key to Geophysical 

Records Documentation no. 12, 59 p. 

Blakey, J.F., 1966, Temperature of surface waters in the 

conterminous United States: U.S. Geological Sutvey, 

Hydrologic Investigations Atlas HA-235. 

Dagger, G.W., 1989, Driftmap-A continental drift program in 

Pascal: Computers and Geoscience, v. 15, p. 371-393. 

Darton, N.H., 1913, Geothermal data of the United States: U.S. 

Geological Sutvey Bulletin 701, 97 p. 

Savin, S.M., 1977, The history of the Earth's surface temperature during the past 100 million years: Annual Reviews 

of Earth and Planetary Sciences, v. 5, p. 319-355. 

--1984, The history of the Earth's surface temperature, in 

Durand, B., ed., Thermal phenomena in sedimentary 

basins. Paris, Editions Technip, p. 11-19. 

Waring, G.A., 1965, Thermal springs of the United States and 

other countries of the World: U.S. Geological Sutvey 

Professional Paper 492, 383 p. 

Weijermars, R., 1989, Global tectonics since the breakup of 

Pangea 180 million years ago: Evolution maps and 

lithospheric budget: Earth Science Reviews, v. 26, p. 

113-162. 

38 The Petroleum System-Status of Research and Methods, 1990 
Geothermal Gradient Data-North America 

AAPG (American Association of Petroleum Geologists), 1976, 

Basic data file from AAPG geothermal survey of North 

America: Norman, University of Oklahoma, 

Guffanti, M., and Nathenson, M., 1980, Preliminary 

temperature-gradient map of the conterminous United 

States: Geothermal Resources Council Transactions, v. 

4, p. 53-59. 

Kinney, D.M., ed., 1976, Geothermal gradient map of North 

America: American Association of Petroleum Geologists and United States Geological Survey, scale 

1:5,000,000, 2 sheets. 

Kron, A., and Stix, J., 1982, Geothermal gradient map of the 

United States: National Oceanic and Atmospheric Administration, National Geophysical Data Center, 2 

sheets, 1:2,500,000. [For many localities the heat flow 

and thermal conductivities are listed.] 

Moses, P.L., Geothermal gradients, in Drilling and production 

practice: Washington, D.C., American Petroleum Institute, p. 57-63. 

Spicer, B.C., 1964, A compilation of deep Earth temperature 

data: USA 1910-1945: U.S. Geological Survey OpenFile Report 64-14 7. 

Van Orstrand, C.E., 1935, Normal geothermal gradient in 

United States: American Association of Petroleum Geologists Bulletin, v. 19, p. 78-115. 

Geothermal Gradient Data-World 

Van Orstrand, C.E., 1961, Observed temperatures in the 

Earth's crust, in Gutenberg, B., ed., Internal constitution 

of the earth: New York, Dover, p. 107-149. 

Thermal Conductivity 

Anand, J., Somerton, W.H., and Gomaa, E., 1973, Predicting 

thermal conductivities of formations from other known 

properties: Society of Petroleum Engineers Journal, v. 

13, p. 267-273. 

Assad, Y., 1955, A study of the thermal conductivity of fluidbearing porous rocks: Berkeley, University of California, 

Ph.D. Dissertation, 71 p. 

Blackwell, D.D., and Steele, J.L., 1989, Thermal conductivity of 

sedimentary rocks, in Naeser, N.D., and McCulloh, T.H., 

eds., Thermal history of sedimentary basins: New York, 

Springer-Verlag, p. 13-36. 

Oark, S.P., 1966, Thermal conductivity, in Oark, S.P., ed., 

Handbook of physical constants: Geological Society of 

America Memoir 97, Chapter 21, p. 459-483. 

Horai, K., and Uyeda, S., 1960, Studies of the Earth. The fifth 

paper: Relation between thermal conductivity of sedimentary rocks and water content: Bulletin of the Earthquake Research Institute, v. 38, p. 199-206. 

Houbolt, JJ.H.C., and Wells, P.R.A., 1980, Estimation of heat 

flow in oil wells based on a relation between heat 

conductivity and sound velocity: Geologie en Mijnbouw, 

v. 59, p. 215-224. 

Huang, J.H., 1971, Effective thermal conductivity of porous 

rocks: Journal of Geophysical Research, v. 76, p. 

6420-6427. 

Butt, J.R., and Berg, J.W., 1968, Thermal and electrical conductivities of sandstone rocks and ocean sediments: 

Geophysics, v. 33, p. 489-500. 

Kunii, D., and Smith, J.M., 1961, Thermal conductivities of 

porous rocks filled with stagnant fluid: Society of Petroleum Engineers Journal, v. 1, p. 37-42. 

Lewis, C.R., and Rose, S.C., 1970, A theory relating high 

temperatures and overpressures: Journal of Petroleum 

Technology, v. 22, p. 11-16. 

Robertson, B.C., 1979, Thermal conductivity of rocks: U.S. 

Geological Survey Open-File Report 79-356, 31 p. 

Roy, R.F., Beck, A.E., and Touloukian, Y.S., 1981, Thermophysical properties of rocks, in Touloukian, Y.S., Judd, 

W.R., and Roy, R.F., eds., Physical properties of rockS 

and minerals, v. II-2: New York, McGraw-Hill, p .. 

409-502. 

Sass, J.H., Lachenbruch, A.B., and Munroe, R.J., 1971, Thermal conductivity of rocks from measurements on fragments and its application to heat-flow determinations: 

Journal of Geophysical Research, v. 76, p. 3391-3401. 

Sugawara, A., and Yoshizawa, Y ., 1962, An experimental 

investigation on the thermal conductivity of consolidated 

porous materials: Journal of Applied Physics, v. 33, p. 

3135-3138. 

Woodside, W., and Messmer, J.H., 1961, Thermal conductivity 

of porous media. II. Consolidated rocks: Journal of 

Applied Physics, v. 32, p. 1699-1706. 

Zierfuss, H., 1969, Heat conductivity of some carbonate rocks 

and clayey sandstones: American Association of Petroleum Geologists Bulletin, v. 53, p. 251-260. 

Paleoporosity Prediction 

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, p. 1697-1703. [See also the 

references contained within.] · 

Schmoker, J.W., and Gautier, D.L., 1988, Sandstone porosity as 

a function of thermal maturity: Geology, v. 16, p. 

1007-1010. [See also the references contained within.] 

Heat Flow Data -United States 

Blackwell, D.D., 1969, Heat flow in the northwestern United 

States: Journal of Geophysical Research, v. 74, p. 

992-1007. 

Combs, J., and Simmons, G., 1973, Terrestrial heat flow 

determinations in north-central United States: Journal of 

Geophysical Research, v. 78, p. 441-461. 

Decker, E.R., and others, 1988, Significance of past and recent 

heat-flow and radioactivity studies in the southern Rocky 

Mountains region: Geological Society of America Bulletin, v. 100, p. 1851-1885. 

Reiter, M., Mansure, AJ., and Shearer, C., 1979, Geothermal 

characteristics of the Colorado Plateau: Tectonophysics, 

v. 61, p. 183-195. 

Reiter, M., and Tovar, J.C., 1982, Estimates of terrestrial heat 

flow in northern Chihuahua, Mexico, based upon petroleum bottom-hole temperatures: Geological Society of 

America Bulletin, v. 93, p. 613-624. 

Geothermlcs Applied to the Reconstruction of Subsurface Temperatures 39 
Sass, and others, 1980, Heat flow from the crust of the United 

States, in Touloukian, Y.S., Judd, W.R., and Roy, R.F., 

eds., Physical properties of rocks and minerals, v. 11-2: 

New York, McGraw-Hill, p. 503-548. 

Sass, J.H., and Munroe, RJ., 1974, Basic heat flow data from 

the United States: U.S. Geological Survey Open-File 

Report 74-9. 

Heat Flow Data-World 

Chapman, D.S., and Pollock, H.N., 1974, Global heat flow: A 

new look: Earth and Planetary Science Letters, v. 28, p. 

28-32. [Summarizes sources of heat flow maps.] 

Cermak, V., and Rybach, L., eds., 1979, Terrestrial heat flow in 

Europe: Berlin, Springer-Verlag, 328 p. 

Danis, M., 1985, Simple evaluation of heat flow in sedimentary 

basins: Comparison and discussion: Revue de l'lnstitut 

Francais Petrole, v. 40, p. 300-320 [in French]. [Discusses a simple method of estimating heat flow from the 

water-well discharge temperature.] 

Lysak, S.V., 1987, Terrestrial heat flow of continental rifts: 

Tectonophysics, v. 143, p. 31-41. 

Vitorello, I., and Pollack, H.N., 1980, On the variation of 

continental heat flow with age and the thermal evolution 

of continents: Journal of Geophysical Research, v. 85, p. 

983-995. 

Subsurface Temperature from 

Heat-Flow Theory 

Andrews-Speed, C.P., Oxburgh, E.R., and Cooper, B.A., 1984, 

Temperatures and depth-dependent heat flow in western 

North Sea: American Association of Petroleum Geologists Bulletin, v. 68, p. 1764-1781. 

Buntebarth, G., 1984, Geothermics: New York, SpringerVerlag, 144 p. [See also the references contained within.] 

Carslaw, H.S., and Jaeger, J.C., 1959, Conduction of heat in 

solids: Oxford, Oxford University Press. 

Jaeger, J.C., 1964, Thermal effects of intrusions: Reviews of 

Geophysics, v. 2, p. 443-466. 

Nisbet, E.G., and Fowler, C.M.R., 1982, The thermal background to metamorphism-!. Simple one-dimensional 

conductive models: Geoscience Canada, v. 9, p. 161-164. 

Norton, D., and Cathles, L.M., 1979, Thermal aspects of ore 

deposition, in Barnes, H.L., ed., Geochemistry of hydrothermal ore deposits, 2d ed.: New York, Wiley, p. 

611-631. 

Correction of BHT data 

AAPG (Ame~can Association of Petroleum Geologists), 1976, 

Basic data file from AAPG geothermal survey of North 

America: Norman, University of Oklahoma. 

Albright, J., 1976, A new and more accurate method for the 

direct measurement of earth temperature gradient in 

deep boreholes: Proceedings, Second United Nations 

Symposium on the Development and Use of Geothermal 

Resources, v. 2, p. 847-851. 

Barelli, A., and Palama, A., 1981, A new method for evaluating 

formation equilibrium temperature in holes during drilling: Geothermics, v. 10, p. 95-102. 

Bullard, E.C., 1947, The time necessary for a borehole to attain 

temperature equilibrium: Monthly Notices, Royal Astronomical Society, v. 5, p. 127-130. 

Carstens, H., and Finstad, K.G., 1981, Geothermal gradients of 

the northern North Sea basin, 59-62°N, in Illing, L.V., 

and Hobson, G.D., ed., Petroleum geology of the continental shelf of north-west Europe: London, Institute of 

Petroleum, p. 152-161. [Extensive discussion of errors in 

BHT measurement and their correction.] 

Catala, G., 1984, Technical aspects of measurements of temperatures in boreholes-Some aspects of their interpretation, in Durand, B., Thermal phenomena in 

sedimentary basins: Paris, Editions Technip, p. 37-46. 

Chueng, P.K., 1979, Geothermal gradient mapping-Oklahoma: Canadian Well Logging Society, Transactions, 7th 

Formation Evaluation Symposium, p. 1-5. 

Closman, P.J., Jones, E.R., and Vogel, E.A., 1979, Effect of 

heat-conducting well casing on temperature distribution 

in an observation well: Journal of Energy Resources 

Technology, v. 101, p. 20-27. [In general, after about 

three months, error in temperature measurement due to 

this effect are negligible.] 

Cooper, L.R., and Jones, C., 1959, The determination of virgin 

strata temperatures from observations in deep survey 

boreholes: Journal of Geophysics, v. 2, p. 116-131. 

Da-Xin, L., 1986, Non-linear fitting method of finding equilibrium temperature from BHT data: Geothermics, v. 15, p. 

657-664. 

Dowdle, W.L., and Cobb, W.M., 1975, Static formation temperature from well logs-An empirical method: Journal 

of Petroleum Technology, v. 27, p. 1326-1330. 

Drury, M.J., 1984, On a possible source of error in extracting 

equilibrium formation temperatures from borehole BHT 

data: Geothermics, v. 13, p. 175-180. 

Edwardson, M.J., and others, 1962, Calculation of formation 

temperature disturbance caused by mud circulation: 

Journal of Petroleum Technology, v. 14, p. 416-426. 

Holmes, C.S., and Swift, S.C., 1970, Calculation of circulating 

mud temperatures: Journal of Petroleum Technology, v. 

22, p. 670-674. 

Kehle, R.O., Schoeppel, R.J., and Deford, R.K., 1970, The 

AAPG geothermal survey of North America: Geothermics, v. 2, p. 358-367. 

Jaeger, J.C., 1961, The effect of the drilling fluid on temperatures measured in bore holes: Journal of Geophysical 

Research, v. 66, p. 563-569. 

Lachenbruch, A.H., and Brewer, M.C., 1959, Dissipation of the 

temperature effect of drilling a well in Arctic Alaska: 

U.S. Geological Survey Bulletin 1083-C, p. 73-109. 

Leblanc, Y., Lam, H.L., Pascoe, L.J., and Jones, F.W., 1982, A 

comparison of two methods of estimating static formation temperature from well logs: Geophysical Prospecting, v. 30, p. 348-357. 

Lee, T.C., 1982, Estimation of formation temperature and 

thermal property from dissipation of heat generated by 

drilling: Geophysics, v. 47, p. 1577-1584. 

Mansure, A.J., and Reiter, M., 1979, A vertical groundwater 

movement correction for heat flow: Journal of Geophysical Research, v. 84, p. 3490-3496. 

McCulloh, T.H., and Beyer, L.A., 1979, Geothermal gradients, 

in Cook, H.E., ed., Geologic studies of the Point Con40 The Petroleum System-Status of Research and Methods, 1990 
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Middleton, M.F., 1979, A model for bottom-hole temperature 

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1716-1723. 

Oxburgh, E.R., and others, 1972, Equilibrium bore hole temperatures from observation of thermal transients during 

drilling: Earth and Planetary Science Letters, v. 14, p. 

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Raymond, L.R., 1969, Temperature distribution in a circulating 

drilling fluid: Journal of Petroleum Technology, v. 21, p. 

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Sammet, B.A., 1968, Convective flow and its effect on temperature logging in small diameter wells: Geophysics, v. 33, 

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Scott, G.N., 1982, Temperature equilibration in boreholes: A 

statistical approach: Ann Arbor, University of Michigan, 

M.S. Thesis, 63 p. 

Stegena, L., and Dovenyi, P., 1983, Procedure to correct 

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with are perturbations of the temperature by uplift, 

subsidence, climatic change, erosion, and so on.] 

Tanaka, T., and Satoh, K., 1977, Estimation of subsurface 

temperature in oil and gas producing area, northeast 

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Fluid Flow and Subsurface Temperature 

Variation 

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Drury, M.J., Jessop, A.M. and Lewis, T.J., 1984, The detection 

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Majorowicz, J.A., Jones, F.W., Lam, H.L., and Jessop, A.M., 

1985, Terrestrial heat flow and geothermal gradients in 

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Sorey, M.L., 1971, Measurement of vertical groundwater velocity from temperature profiles in wells: Water Resources 

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Direct Geothermometry 

Barker, C.E., Crysdale, B.L., and Pawlewicz, M.J., 1986, The 

relationship between vitrinite reflectance, metamorphic 

grade and temperature in the Cerro Prieto, Salton Sea, 

and East Mesa Geothermal Systems, Salton Trough, 

United States and Mexico: U.S. Geological Survey Bulletin 1578, p. 83-95. 

Barker, C.E., and Goldstein, R.H., in press, A fluid inclusion 

technique for determining maximum temperature and its 

application to establish a refined calibration for the 

vitrinite reflectance geothermometer: Geology. 

Barker, C.E., and Pawlewicz, M.J., 1986, The correlation of 

vitrinite reflectance with maximum temperature in humic 

organic matter, in Buntebarth, Gunther, and Stegena, L., 

eds., Paleogeothermics: New York, Springer-Verlag, p. 

79-93. [Proposed calibration of vitrinite reflectance and 

maximum temperature for sedimentary rocks. 

Bostick, N.H., 1971, Thermal alteration of clastic organic 

particles as an indicator of contact and burial metamorphism in sedimentary rocks: Geoscience and Man, v. 3, p. 

83-93. 

Burruss, R.C., 1987, Diagenetic palaeotemperatures from 

aqueous fluid inclusions: Re-equilibration of inclusions 

in carbonate cements by burial heating. Mineralogical 

Magazine, v. 51, p. 477-481. 

Gleadow, A.J.W., Duddy, I.R., and Lovering, J.F., 1983, Fission 

track analysis; A new tool for the evaluation of thermal 

histories and hydrocarbon potential: Australian Petroleum Exploration Association Journal, v. 23, p. 93-102. 

Goldstein, R.H., 1986, Reequilibration of fluid inclusions in 

low-temperature calcium-carbonate cement: Geology, v. 

14, p. 792-795. 

Hoffman, J., and Hower, J., 1979, Clay mineral assemblages as 

low grade metamorphic indicators: Application to the 

thrust faulted disturbed belt of Montana, U.S.A., in 

Scholle, P.A., and Schluger, P.K., eds., Aspects of diagenesis: Society of Economic Paleontologist and Mineralogist Special Publication 26, p. 55-79. [General 

correlation of burial temperature with clay mineral assemblage.] 

Hollister, L.S., and Crawford, M.L., eds., 1981, Short course in 

fluid inclusions: Applications to petrology: Mineralogical 

Association of Canada Short Course Handbook 6, 304 p. 

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

metamorphism and the generation of petroleum: American Association of Petroleum Geologists Bulletin, v. 59, 

p. 986-996. 

Hunt, J.M., 1979, Petroleum geochemistry and geology: San 

Francisco, Freeman, 617 p. 

Kharaka, Y.K. and Mariner, R.H., 1989, Chemical geothermometers and their application to formation waters from 

sedimentary basins, in Naeser, N.D., and McC~lloch, T., 

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Kisch, H. J., 1987, Correlation of between indicators of verylow-grade metamorphism, in Frey, M., ed., Low temperature metamorphism: Glasgow, Blackie and Son. 

MacKenzie, A.S., and McKenzie, D., 1983, Isomerization and 

aromatization of hydrocarbons in sedimentary basins 

Geothermics Applied to the Reconstruction of Subsurface Temperatures 41 
formed by extension: Geological Magazine, v. 120, p. 

417-528. 

Naeser, N.D., and McCulloch, T., eds., 1989, Thermal histoey of 

basins-Methods and case histories: Berlin, SpringerVerlag, 319 p. 

Prezbindowski, D.R., and Larese R.E., 1987, Experimental 

stretching of fluid inclusions in calcite-Implications for 

diagenetic studies: Geology~ v. 15, p. 333-336. 

Price, L.C., 1983, Geologic time as a parameter in organic 

metamorphism and vitrinite reflectance as an absolute 

paleogeothermometer: Journal of Petroleum Geology, v. 

6, p. 5-38. 

Roedder, E., 1984, Fluid inclusions: Mineralogical Society of 

America, Reviews in Mineralogy, v. 12, 644 p. [A source 

book for the fluid inclusion geothermometey technique.] 

Savin, S.M., and Lee, M., 1984, Estimation of subsurface 

temperatures from oxygen isotope ratios of minerals, in 

Durand, B., ed., Thermal phenomena in sedimentaey 

basins: Paris, Editions Technip, p. 65-70. 

Scholle, P A., and Schluger, P.R., eds., Aspects of diagenesis: 

Society of Economic Paleontologists and Mineralogists 

Special Publication 26, 443 p. [Contains many papers on 

geothermometric techniques used in sedimentaey basins.] 

Waples, D.W., 1984, Thermal models for oil generation, in 

Brooks, J., and Welte, D., eds., Advances in petroleum 

geochemistey, v. 1: London, Academic Press, p. 7-67. 

[Review of thermal models ~ployed in paleotemperature ;econstruction.] 

Burial Depth/Erosion Reconstruction 

Dow, W.G., 1977, Kerogen studies and geological interpretations: Journal of Geochemical Exploration, v. 7, p. 

79-99. 

England, P.C., and Richardson, S.W., 1977, The influence of 

erosion upon the mineral facies of rocks from different 

metamorphic environments: Journal of the Geological 

Society of London, v. 134, p. 201-213. 

Katz, BJ., Pheifer, R.N., and Schunk, DJ., 1988, Interpretation 

of discontinuous vitrinite reflectance profiles: American 

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

926-931. 

Magara, K., 1986, Geological models of petroleum entrapment: 

London, Elsevier, 328 p. [Useful discussion of applied 

geothermometey and burial histoey reconstruction.] 

Middleton, M.F., 1984, Seismic geohistoey analysis-A case 

histoey from the Canning basin, western Australia: Geophysics, v. 49, p. 333-343. 

Nuccio, V.F., and Barker, C.E., 1989, Application of thermal 

maturation studies to energy exploration: American Association of Petroleum Geologists, Rocky Mountain 

Section, Transactions, p. 111-120. 

Perrier, R., and Quiblier, J., 1974, Thickness change in sedimentaey layers during compaction histoey: Methods for 

quantitative evaluation: American Association of Petroleum Geologists Bulletin, v. 58, p. 507-520. 

Turcotte, D.L., and Ahem, J.L., 1977, On the thermal and 

subsidence histoey of basins: Journal of Geophysical 

Research, v. 82, p. 3762-3766. 

Vugrinovich, R., 1988, Shale compaction in the Michigan basin: 

Estimates of former depth of burial and implications for 

paleogeothermal gradients: Bulletin of Canadian Petroleum Geology, v. 36, p. 1-8. 

Waples, D.W., 1985, Geochemistey in petroleum exploration: 

Boston, International Human Resources Development 

Corporation, 232 p. 

Yamaji, A., and Takahashi, M., 1988, Estimation of relative 

depth of burial using vitrinite reflectance: Implications 

for sedimentaey basin formation by basement tilting: 

International Journal of Coal Geology, v. 10, p. 41-50. 

42 The Petroleum System-Status of Research and Methods, 1990 
Role of Kinetic Modeling in Petroleum Exploration 

By Jerry L. Clayton 1 

Although a few investigators have suggested that 

petroleum may be derived from abiological sources 

(Gold and Sofer, 1980; Porfir'ev, 1974), the present 

consensus view is that petroleum originates from thermal 

transformation of organic matter contained in sedimentary rocks. Some of the organic-solvent-soluble components (bitumen, lipids) contained in sedimentary organic 

matter may undergo only minor diagenetic alteration 

during burial heating, but most of the organic matter 

deposited in fine-grained rocks is contained in the highmolecular-weight insoluble fraction (kerogen). Kerogen 

decomposes during burial heating over geologic time to 

generate petroleum. Petroleum generated by this process 

consists mostly of products from the thermal transformation of kerogen with secondary amounts of lipid materials 

inherited directly from sedimentary organic matter without going through the kerogen intermediate step. 

The main role of kinetic modeling in exploration is 

to reduce risk by predicting how much oil or gas has been 

generated in a play where direct geochemical measurements are limited or. nonexistent because of lack of 

previous drilling or geochemical sampling. This may 

include undrilled basins or parts of basins, or may be 

deep plays in basins where only shallow wells had been 

drilled previously. The strategy used in applying kinetic 

models to exploration is to integrate the kinetics of 

hydrocarbon generation with the burial history (temperature history) of a source rock of interest to predict not 

only the type (oil or gas) and amount of hydrocarbons 

generated, but also the timing of generation and expulsion with respect to development of secondary migration 

pathways and reservoirs. 

Kinetic models of petroleum generation include 

more general considerations of organic maturation and 

are useful in other geological applications besides petroleum exploration. For example, if measured geochemical 

data from a basin are compared with kinetic models, the 

burial and thermal evolution of the basin can be inferred 

or can be constrained to fit the kinetic limitations imposed by the organic maturation model (for example, 

Brosse and others, 1986; Ungerer and others, 1986; 

Sweeney, 1989). However, modeling of kerogen decomposition may be an unnecessarily cumbersome approach 

to assessment of geologic processes such as burial histories. Several workers have proposed kinetic models for 

1

U.S. Geological Sutvey, Denver, Colo. 

specific reactions where the reactants and products are 

thought to consist only of a few chemical species rather 

than the complex kerogen-petroleum system as a whole 

(Mackenzie and McKenzie, 1983; Mackenzie, 1984; Alexander and others, 1986). In principle, this approach has 

the advantage that the specific reactions are known and 

kinetic parameters can be estimated with a greater 

degree of accuracy than for kerogen decomposition, even 

though the reactions may not be applicable directly to the 

question of petroleum generation. An understanding of 

the kinetics of kerogen decomposition is also required for 

proper design and operation of oil-shale processing 

plants and in situ retorting me.thods (Campbell and 

others, 1978; Shih and Sohn, 1980; Braun and Burnham, 

1987). 

In all of the above geologic applications, the usefulness of the kinetic modeling approach is limited by (1) 

how well the geologic and thermal history of the basin are 

known and (2) how accurately the kinetic model describes the real behavior of organic matter during burial 

heating over geologic time. The first limitation depends 

entirely on how well the geology and thermal history of 

the subject basin are known. Limitations in geologic 

methods and techniques for measuring current temperatures or estimating paleotemperatures determine the 

accuracy of geologic and thermal data. With regard to the 

second factor, the validity of kinetic models, much 

progress has been made in recent years in our understanding of the thermal evolution of organic matter. 

Nevertheless, there is enough uncertainty in our knowledge of fundamentals such as the mechanism and stoichiometry of petroleum generation to introduce 

significant uncertainty in applications of kinetic models 

when insufficient geologic data are available to properly 

constrain the models. 

A number of workers have conducted field and 

laboratory studies of the kinetics of petroleum generation with the goal of developing kinetic models that can 

be used to predict oil or gas generation for a specific 

basin or source rock horizon. Over the past 30 years, a 

number of.models have been proposed. All of the models 

currently in widespread use are based on the Arrhenius 

equation, which means that oil generation depends on 

some combination of time and temperature; that is, 

thermal transformation of kerogen during burial heating 

over geologic time. 

dPdt = e-kt where k =A exp (-E8 !R1) (1) 

Role of Kinetic Modeling In Petroleum Exploration 43 
where 

dP!dt 

k 

A 

Ea 

R 

= 

= 

= 

yield of product (oil or gas) with respect to 

time (t) for a given temperature (1) 

rate of the reaction 

Arrhenius constant 

activation energy 

gas constant 

However, the models that have been proposed vary 

considerably with respect to the values for kinetic parameters (Eu A) and the relative emphasis assigned to time 

or temperature as factors in petroleum generation (and 

thermal destruction). A historical perspective and basic 

explanations of the underlying theoretical principles of 

thermal models are given in the review by Waples (1984) 

and references therein. 

Calibration of kinetic models is often based solely 

on laboratory data, especially if the objective is to evaluate the petroleum potential of a frontier area where field 

data are unavailable. Potential problems arising from 

laboratory calibrations include the fundamental question 

of the applicability of the Arrhenius equation over the 

wide range of temperatures associated with laboratory 

studies and petroleum generation and destruction (Burnham and others, 1989), and technical problems of laboratory measurement of kinetic parameters. Laboratory 

methods of obtai~ing kinetic parameters and potential 

problems are discussed by Burnham and others (1987, 

1989). Detailed descriptions of methods for laboratory 

determination of kinetic parameters and the theoretical 

basis of these procedures are given by Braun and Burnham (1987), Burnham and Braun (1985), and Burnham 

and others (1987, 1989). 

One of the earliest petroleum -generation models 

that enjoyed wide acceptance was that of Lopatin (1976), 

which became very popular following the summary by 

Waples (1980). The Lopatin method was used routinely 

in the early 1980's by many explorationists. Recently, the 

Lopatin method has largely been supplanted by models 

using more rigorous approaches based, for example, on 

the petroleum-generation model of Tissot and Espitalie 

(1975) (for example, Ungerer, 1984; Ungerer and others, 

1986). Nevertheless, the Lopatin model is still used in 

some cases and can be a useful predictive tool if properly 

calibrated (Horvath and others, 1988). 

Many of these more recent, mathematically rigorous models, include not only the kinetics of petroleum 

generation, but also more detailed treatment of the 

burial history of the basin under investigation. These 

types of models include calculation of pressure, temperature, and physical and thermal properties of the sediments as wel1 as petroleum generation (for example, 

Welte and Yukler, 1981) and are really basin evolution 

models rather than strictly petroleum-generation models. 

Development of detailed mathematical kinetic 

models of petroleum generation is due not only to 

recognized weaknesses in simpler models, but also to the 

availability of desktop computers with sufficient capacity 

to perform the necessary calculations quickly. Future 

research in the area of kinetic modeling of petroleum 

generation must include refinements in methods for 

obtaining thermal data for basins-both paleotemperature data and accurate determinations of present ternperature conditions. The models themselves can be 

improved by increased understanding of kerogen structure and thermal behavior and by improvements in 

laboratory determination of kinetic parameters used in 

kinetic calculations. Parallel with the continued development of highly sophisticated chemical and computer 

models, training of explorationists in the applications and 

especially the limitations of these models must be addressed. Poor understanding of the theoretical basis of 

the models or the laboratory methods used to obtain 

input data can lead to serious misinterpretation of kinetic 

modeling results. 

REFERENCES CITED 

Alexander, R., Strachan, M.G., Kagi, R.I., and van Bronswijk, 

W., 1986, Heating rate effects on aromatic maturity 

indicators: Organic Geochemistry, v. 10, p. 997-1003. 

Braun, 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. 

Brosse, E., Deroo, G., Roucache, J., and Botneva, T.A., 1986, 

Organic geochemistry as a test of validity for the results 

of a modelisation in the Pripiat Basin (Bielorussia), in 

Burrus, J., ed., Thermal modeling in sedimentary basins: 

Paris, Editions Technip, p. 497-515. 

Burnham, A.K., and Braun, R.L., 1985, General kinetic model 

of oil shale pyrolysis: In Situ, v. 9, p. 1-23. 

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

1987, Comparison of methods for measuring kerogen 

pyrolysis rates and fitting kinetic parameters: Energy & 

Fuels, v. 1, p. 452-458. 

Burnham, A.K., Braun, R.L., and Samoun, A., 1989, Further 

comparisons of methods for measuring kerogen pyrolysis 

rates and fitting kinetic parameters, in Mattavelli, L., and 

Novelli, L., eds., Advances in organic geochemistry 1987: 

Organic Geochemistry, v. 13, p. 839-845. 

Campbell, J.H., Koskinas, G.H., and Stout, N.D., 1978, Kinetics 

of oil generation from Colorado oil shale: Fuel, v. 57, p. 

372-376. 

Gold, T., and Sofer, S., 1980, Scientific American, v. 242, p. 

154-162. 

Horvath, F., Dovenyi, P., Szalay, A., and Royden, L.H., 1988, 

Subsidence, thermal, and maturation history of the Great 

Hungarian Plain, in Royden, L.H. and Horvath, F., eds., 

The Pannonian basin, a study in basin evolution: American Association of Petroleum Geologists Memoir 45, p. 

355-372. 

Lopatin, N.V., 1976, Historical-genetic analysis of petroleum 

generation: Application of a model of uniform continu44 The Petroleum System-Status of Research and Methods, 1990 
ous subsidence of the oil-source bed (in Russian), Akademiya Nauk SSSR, Isvestiya Seriya Geologicheskaya, v. 

8, p. 93-101. 

Mackenzie, A.S., 1984, Applications of biological markers, in 

Brooks, J. and Welte, D., eds., Advances in petroleum 

geochemistry: London, Academic Press, v. 1, p. 115-214. 

Mackenzie, A.S. and McKenzie, D.H., 1983, Isomerization and 

aromatization of hydrocarbon in sedimentary basins 

formed by extension: Geological Magazine, v. 120, p. 

417-528. 

Porfir'ev, V.B., 1974, Inorganic origin of petroleum: American 

Association of Petroleum Geologists Bulletin, v. 58, p. 

3-33. 

Shih, S.M., and Sohn, H.Y., 1980, Nonisothermal determination of the intrinsic kinetics of oil generation from oil 

shale: Industrial Engineering Chemical Processes Design 

and Development, v. 19, p. 420-426. 

Sweeney, J.J., 1989, Application of maturation indicators and 

oil reaction kinetics to put constraints on thermal history 

models of the Unita Basin, Utah, U.S.A., in Mattavelli, 

L. and Novelli, L., eds., Advances in Organic Geochemistry 1987: Organic Geochemistry, v. 13, p. 199-205. 

Tissot, B., and Espitalie, J., 1975, L'evolution thermique de la 

matiere organique des sediments: Applications d'une 

simulation mathematique: Revue Institut Francais du 

Petrole, v. 30, p. 734-777. 

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

take into account geology and chemical kinetics, in 

Durand, B., ed., Thermal phenomena in sedimentary 

basins: Paris, Editions Technip, p. 235-246. 

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

Use of kinetic models of organic matter evolution for the 

reconstruction of paleotemperatures. Application to the 

case of the Gironville Well (France), in Burrus, J., ed., 

Thermal modeling in sedimentary basins: Paris, Editions 

Technip, p. 531-546. 

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. 

---1984, Thermal models for oil generation, in Brooks, J ., 

and Welte, D., eds., Advances in petroleum geochemistry: New York, Academic Press, v. 1, p. 7-67. 

Welte, D.H. and Yukler, M.A., 1981, Petroleum origin and 

accumulation in basin evolution-A quantitative model: 

American Association of Petroleum Geologists Bulletin, 

v. 65,p. 1387-1396. 

Role of Kinetic Modeling in Petroleum Exploration 45 
Biological Marker Chemistry as Indicator of 

Depositional Environment of Source Rocks and Crude Oils 

By Jerry L. Clayton 1 

The term "biological marker" or "biomarker" was 

first introduced in the literature by Speers and Whitehead 

(1969), although the idea of chemical "fossils" has been 

around much longer (Fox, 1944). More recently, Mackenzie(1984)defined biological markers as "any organic 

compound detected in the geosphere whose basic skeleton suggests an unambiguous link with a known, contemporary natural product." The operative word in this 

definition is "unambiguous." It is generally accepted that 

petroleum is formed from thermal transformation of 

sedimentary organic matter derived from living systems. 

During burial heating, sedimentary organic matter 

evolves from a complex mixture of a wide variety of 

molecules derived more or less directly from living 

systems to a mixture of fewer types and simpler chemical 

structures. Given sufficiently high temperatures over 

geologic time, only methane would remain. Therefore, as 

thermal maturation proceeds, the structural similarity 

between biological marker compounds in rocks or petroleum and their precursor biomolecules in living systems 

becomes increasingly more ambiguous. One of the main 

objectives of biological marker research is to recognize 

the link, or diagenetic pathway, between biomolecules in 

living systems and biological marker compounds found in 

rocks or oils that have undergone variable degrees of 

alteration during burial heating over geologic time. 

The first biomarker compounds to be identified in 

geological materials were porphyrins, which are diagenetic products of chlorophyll (Treibs, 1934a, b, .1935a, b, 

1936). Owing to the development of sensitive analytical 

tools, particularly gas chromatography-mass spectrometry, significant advances have been made over the past 20 

years in identification of biological marker compounds in 

rocks and petroleum. Many studies, particularly early 

work, have been concerned primarily with the identification of chemical structures of biological markers in 

sediments and oils (for example, Han and Calvin, 1969; 

Balogh and others, 1973; Kimble and others, 1974; 

Seifert, 1975; Seifert and others, 1978; Rowland and 

others, 1982; Schmitter and others, 1982; Trendel and 

others, 1982; Ekweozor and Straus, 1983; many others). 

In recent years, more attention has been given to applications of biological markers in petroleum geochemistry. 

1

U.S. Geological Survey, Denver, Colo. 

Comprehensive reviews of biological marker geochemistry and applications are given by Mackenzie (1984) and 

Johns (1986). 

Biological markers are important in petroleum 

systems for interpretation of oil-to-oil and oil-to-source 

rock correlations, thermal maturation, biodegradation, 

and migration. The present paper summarizes applications of biological markers in interpretation of depositional environment of source rocks. This includes 

consideration not only of source rocks themselves but 

also crude oils, because the biological marker composition of oils can be used in some cases to infer the 

depositional setting of the parent source organic matter. 

Interpretation of the depositional setting of sedimentary organic matter using biological markers can be 

approached in two ways. First, chemical conditions in the 

sedimentary environment may be inferred from which 

diagenetic reactions occur among numerous possible 

reaction pathways. For example, the ratio of pristaneto-phytane has been suggested as an indicator of the 

relative oxicity or anoxicity of sediments in which organic 

matter accumulates (Didyk and others, 1978), although 

recent evidence suggests that factors other than redox 

potential may affect the ratio (Goossens and others, 

1984; ten Haven and others, 1987). Second, biological 

markers that are characteristic of a particular organism 

or a group of organisms indicate the chemistry of the 

depositional environment because of the ecological requirements of the contributing organisms. For example, 

the presence of certain isoprenoid compounds characteristic of methanogenic bacteria indicate strongly reducing 

conditions because methanogens are strict anaerobes, 

while euxinic conditions can be inferred from the presence of aryl isoprenoids, which have been suggested as 

indicators of green photosynthetic sulfur bacteria (Summons and Powell, 1987). Many studies of biological 

marker assemblages in sediments and petroleum have 

been aimed at interpreting the specific type of environment or overlying water column in which the sediments 

were deposited, such as lacustrine freshwater, freshwater 

brackish, saline, or hypersaline (for example, Mello and 

others, 1988; Brassell and others, 1988; Fu Jiamo and 

others, 1986; ten Haven and others, 1988; Volkman, 

1988). 

Biological markers can also be used to infer the 

biological source of the organic matter. In this case, 

interpretation of the organic input is the objective, rather 

46 The Petroleum System-Status of Research and Methods, 1990 
than the actual paleoenvironment in which sediments 

were accumulating. Organic input to the sediments may 

be predominantly from organisms populating the sedimentary environment, in which case the approach used to 

interpret the paleoenvironment would lead also to an 

understanding of the main source input. However, in 

many cases nonindigenous (allochthonous) organic matter may be present in significant amounts. In this latter 

case, interpretation of the depositional environment requires differentiating between the biological marker 

components that are derived from organisms populating 

the sedimentary environments and those associated with 

allochthonous organic input. The main groups of organisms contributing organic matter to sediments are higher 

terrestrial plants, algae, and bacteria (Tissot and Welte, 

1984). Comet and Eglinton (1987), Brassell and others 

(1987), and Volkman (1988) discussed biological marker 

assemblages that are characteristic for these three groups 

of organisms. 

Future research in applications of biological markers for interpreting depositional environment will include 

continuing expansion of the inventory of biological marker compounds in living organisms, sediments, and oils. In 

addition, further work is needed to elucidate diagenetic 

and catagenetic pathways of biological marker evolution 

and factors which favor particular reaction pathways 

(such as heating rate, Eh, pH, mineral matrix, or temperature). 

REFERENCES CITED 

Balogh, B., Wilson, D.M., Christiansen, P., and Burlingame, 

A.L., 1973, 17 a (H)-Hopane identified in oil shale of the 

Green River Formation (Eocene) by carbon-13 NMR: 

Nature, v. 242, p. 603-605. 

Brassell, S.C., Eglinton, G., and Howell, V.J., 1987, Paleoenvironmental assessment for marine organic-rich sediments, 

in Brooks, J. and Fleet, A.J., eds., Marine petroleum 

source rocks: Boston, Blackwell Scientific Publications, 

p. 79-98. 

Brassell, S.C., Sheng Guoying, Fu Jiamo, and Eglinton, G., 

1988, Biological markers in lacustrine Chinese oil shales, 

in Fleet, A.J ., Kelts, K., and Talbot, M.R., eds., Lacustrine petroleum source rocks: Boston, Blackwell Scientific Publications, p. 299-308. 

Comet, P .A., and Eglin ton, G., 1987, The use of lipids as facies 

indicators, in Brooks, J., and Fleet, A.J., eds., Marine 

petroleum source rocks: Boston, Blackwell Scientific 

Publications, p. 99-117. 

Didyk, B.M., Simoneit, B.R.T., Brassell, S.C., and Eglinton, G., 

1978, Organic geochemical indicators of paleoenvironmental conditions of sedimentation: Nature, v. 272, p. 

216--222. 

Ekweozor, C.M. and Straus, O.P., 1983, 18,19-Bisnor-13 {3 (H), 

14 a (H)-cheilanthane: A novel degraded tricyclic 

sesterterpenoid-type hydrocarbon from the Athabasca 

oil sands: Tetrahedron Letters, v.23, p. 2711-2714. 

Fox, D.L., 1944, Biochemical fossils: Science, v. 100, p. 

111-113. 

Fu Jiamo, Guoying, S., and Dehan, L., 1988, Organic geochemical characteristics of major types of terrestrial petroleum 

source rocks in China, in Fleet, A.J ., Kelts, K., and 

Talbot, M.R., eds., Lacustrine petroleum source rocks: 

Boston, Blackwell Scientific Publications, p. 279-289. 

Goossens, H., de Leeuw, J.W., Schenck, P.A., and Brassell, 

S.C., 1984, Tocopherols as likely precursors of pristane 

in ancient sediments and crude oils: Nature, v. 212, p. 

440-442. 

Han, J., and Calvin, M., 1969, Occurrence of c; 5 isoprenoids in Bell Creek crude oil: Geochimica et Cosmochimica Acta, v. 33, p. 733-742. 

Johns, R.B., ed., 1986, Biological markers in the sedimentary 

record: New York, Elsevier, 364 p. 

Kimble, B.J., Maxwell, J.R., Philp, R.P., and Eglinton, G., 1974, 

Identification of steranes and triterpanes in geolipid 

extracts by high-resolution gas chromatography and mass 

spectrometry: Chemical Geology, v. 14, p. 173-198. 

Mackenzie, A.S., 1984, Applications of biological markers, in 

Brooks, J., and Welte, D., eds., Advances in petroleum 

geochemistry: New York, Academic Press, v. 1, p. 

115-214. 

Mello, M.R., Telnaes, N., Gaglianone, P.C., Chicarelli, M.l., 

Brassell, S.C., and Maxwell, J.R., 1988, Organic geochemical characterization of depositional palaeoenvironments of source rocks and oils in Brazilian marginal 

basins, in Mattavelli, L. and Novelli, L., eds., Advances in 

organic geochemistry 1987: Organic Geochemistry, v. 13, 

p. 31-45. 

Rowland, S.J., Lamb, N.A., Wilkinson, C.F., and Maxwell, J.R., 

1982, Confirmation of 2,6,10,15,19-pentamethyleicosane 

in methan-ogenic bacteria and sediments: Tetrahedron 

Letters, p. 101-104. 

Schmitter, J.M., Sucrow, W., and Arpino, P.J., 1982, Occurrence of novel tetracyclic geochemical markers: 8,14-

seco-hopanes in a Nigerian crude oil: Geochimica et 

Cosmochimica Acta, v. 46, p. 2345-2350. 

Seifert, W.K., 1975, Carboxylic acids in petroleum and sediments, in Herz, W., Grisebach, H., and Kirby, G.W., eds., 

Progress in the chemistry of organic natural products, v. 

32: New York, Springer-Verlag, p. 2-49. 

Seifert, W.K., Moldowan, J.l\.1., Smith, G.W., and Whitehead, 

E.V., 1978, First proof of structure of a C28-pentacyclic 

triterpane in petroleum: Nature, v. 271, p. 436-437. 

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, 

Springer-Verlag, p. 639-675. 

Summons, R.E., and Powell, T.G., 1987, Identification of aryl 

isoprenoids in source rocks and crude oils: Biological 

markers for the green sulfur bacteria: Geochimica et 

Cosmochimica Acta, v. 51, p. 557-566. 

ten Haven, H.L., de Leeuw, J.W., Rullkotter, J., and SinningheDamaste, J.S., 1987, Restricted utility of the pristane/ 

phytane ratio as a paleoenvironmental indicator: Nature, 

v.330,p. 2543-2548. 

ten Haven, H.L., de Leeuw, J.W., Sinnighe-Damaste, J.S., 

Schenck, P.A., Palmer, S.E., and Zumberge, J., 1988, 

Applications of biological markers in the recognition of 

Biological Marker Chemistry as Indicator of Depositional Environment of Source Rocks and Crude Oils 47 
palaeo-hypersaline environments, in Fleet, A.J., Kelts, 

K., and Talbot, M.R., eds., Lacustrine petroleum source 

rocks: Boston, Blackwell Scientific Publications, p. 

123-130. 

Tissot, B.P., and Welte, D.H., 1984, Petroleum formation and 

occurrence, 2d ed.: New York, Springer-Verlag, 699 p. 

Treibs, A., 1934a, Organic mineral substances, II-Occurrence 

of chlorophyll derivatives in an oil shale of the Upper 

Triassic: Analytical Chemistry, v. 517, p. 103-144. 

---1934b, Chlorophyll- and haemin derivatives in bituminous rocks, petroleum, mineral waxes and asphalts: 

Analytical Chemistry, v. 510, p. 42-62. 

---1935a, Organic mineral substances, IV-Chlorophyll 

and hemin derivatives in bituminous rocks, petroleums, 

coals, and phosphorites: Analytical Chemistry, v. 517, p. 

172-196. 

---1935b, Porphyrins in coal: Analytical Chemistry, v. 520, 

p. 144-151. 

---1936, Chlorophyll and hemin derivatives in organic 

mineral substances: Angewandte Chemie, v. 49, p. 

682-686. 

Trendel, J.M., Restle, A., Connan, J., and Albrecht, P., 1982, 

Identification of a novel series of tetracyclic terpane 

hydrocarbons (C24-<;7) in sediments and petroleum: 

Journal of Chemical Society, Chemical Communication, 

p. 304-305. 

Volkman, J.K., 1988, Biological marker compounds as indicators of the depositional environments of petroleum 

source rocks, in Fleet, A.J., Kelts, K., and Talbot, M.R., 

eds., Lacustrine petroleum source rocks: Boston, Blackwell Scientific Publications, p. 103-122. 

48 The Petroleum System-Status of Research and Methods, 1990 
Sulfur in Source Rocks and Petroleum 

By Jerry L. Clayton 1 

The purpose of this report is to summarize current 

understanding of the geochemistry of organic sulfur 

compounds (OSC) in crude oil and source rocks. Sulfur 

is the most abundant nonhydrocarbon component in 

crude oil; the average sulfur content of oil is about 0.65 

percent (Tissot and Welte, 1984). The range is from a 

few hundreths of 1 percent up to 8 percent and rarely up 

to 10 to 14 percent, although most crude oils contain less 

than 4 percent (Constantinides and Arich, 1967; Ho and 

others, 1974; Orr, 1978; Tissot and Welte, 1984; Bolshakov, 1986). Tissot and Welte (1984) considered 1 percent 

total sulfur to be the boundary between high- and lowsulfur oils. Most of the sulfur in crude oils is contained in 

organic compounds; secondary amounts are present as 

dissolved elemental sulfur or metal sulfides (Orr, 1978). 

OSC occur predominantly in the middle to high boiling 

point range in most crude oils (Sinnighe Damaste and 

others, 1988a). 

OSC are of considerable interest to explorationists 

and refinery chemists for several reasons. OSC in petroleum present serious refining and environmental problems that can significantly diminish the economic value of 

a given petroleum deposit. Therefore, explorationists 

need to be able to predict the occurrence of high-sulfur 

crude oil with some degree of accuracy. Furthermore, 

sulfur compounds in crude oils occur in a wide variety of 

organic structures, many of which are thought to involve 

early diagenetic reactions of sulfur with biomolecules 

derived directly from organisms contributing organic 

matter to sediments (Sinnighe Damaste and others, 

1987c) and can therefore be used for oil-source rock 

correlations and for interpretation of paleoenvironment 

of deposition of organic-rich rocks (Brassell and others, 

1989; ten Haven and others, 1985, 1988; Kohnen and 

others, 1989; Rullkotter and others, 1989). Relative 

amounts of sulfur compound classes have also been used 

to assess the thermal maturity of oils (Ho and others, 

1974), and the molecular distribution of OSC may have 

application in thermal maturity studies of oils or rocks 

(Rullkotter and Orr, 1989). Thermal requirements for 

breakdown of kerogen to generate oil depend partly on 

the distribution of sulfur bonds in the kerogen. Kerogens 

containing large amounts of sulfur bonds (type "li-S" 

1

U.S. Geological SuiVey, Denver, Colo. 

kerogen) have been observed to generate oil under 

relatively mild thermal conditions compared to lowsulfur kerogens (Orr, 1978). Therefore, studies or models of oil generation must consider the effects of sulfur on 

kinetics of kerogen breakdown. 

Figure 4 gives the chemical structures of the main 

types of OSC found in the geosphere to date. The relative 

importance of the different sulfur structural types varies 

markedly among different oils in response to a variety of 

factors such as the organic source, thermal maturity, and 

degradation (Ho and others, 1974, Bolshakov, 1986). 

Thiophenes were among the first OSC reported in oil and 

coal tar (Meyer 1882; referenced by Constantinides and 

Arich, 1967). Since that time, a large number of OSC 

have been identified in crude oil (Ho and others, 1974; 

Hughes, 1984; Bolshakov, 1986; Payzant and others, 

1985, 1986; Sinnighe Damaste and others, 1987c). Developments in research into OSC in crude oils prior to 

1967 were reviewed by Constantinides and Arich (1967). 

Much less is known about the distribution of OSC in 

sediments and source rocks, although much research 

recently has been focused on this subject (Hughes, 1984; 

Valisolalao and others, 1984; Brassell, 1986; Sinnighe 

Damaste and others, 1987a, 1987b, 1987c, 1988a, 1988b, 

1989a, 1989b; Sinnighe Damaste and de Leeuw, 1987; 

Vairavamurthy and Mopper, 1987; ten Haven and others, 

1988). 

Recently, analytical methods have been developed 

which allow more detailed characterization of OSC in 

both crude oils and rock or sediment extracts. In addition, sulfur compounds have been obtained from highmolecular-weight fractions of crude oil and from 

kerogens by pyrolysis (Giraud and Bestougeff, 1967; 

Sinnighe Damaste and others, 1988a) and by selective 

chemical degradation of kerogen or other highmolecular-weight material (asphaltenes) (Sinnghe Damaste and others, 1988b ). These analytical developments 

have led to a better understanding of the timing and 

mechanism of sulfur incorporation in sedimentary organic matter and have resulted in a rapid growth of research 

activity in this area. 

Of considerable importance is the timing and 

mechanism of sulfur incorporation in sedimentary organic materials, because the practical application of organasulfur chemistry in petroleum geochemistry depends on 

understanding the relationship between the distribution 

of OSC and source rock deposition and secondary effects 

in oils (maturation, migration, degradation). Early work 

Sulfur In Source Rocks and Petroleum 49 
ers concluded that OSC found in crude oil could not have 

been present in the organic matter initially deposited in 

source rocks because sulfur compounds in living systems 

are not present in the amounts and molecular distributions found in sedimentary organic matter and crude oils 

(Birch, 1953; Constantinides and Arich, 1967). Further, 

the present consensus view is that sulfur is not added in 

significant amounts after oil has been generated (Gransch and Posthuma, 1974; Orr, 1978). It seems likely that 

most of the OSC found in crude oils are derived from 

kerogen in the source rock and are formed during early 

diagenesis of the organic matter. Constantinides and 

Arich (1967) suggested that elemental sulfur or H2S 

could react with di-unsaturated hydrocarbons during 

early diagenesis to yield the thiophene series of OSC. 

Subsequent investigations by Sinnighe Damaste and coworkers (1987a,b, 1988b, 1989a) have provided substantial support for this hypothesis. 

Gransch and Posthuma (1974) presented a conceptual framework for incorporation of sulfur into sedimentary organic matter in which high- and low-sulfur 

kerogens (and associated crude oils) are a function of the 

chemistry of the depositional environment of the source 

rock. Their scheme depended on the oxidation-reduction 

GENERALIZED 

NAME STRUCTURAL 

FORMULA 

alkyl thiols R-SH 

cyclic thiols USH 

aromatic thiols USH 

R-S-R 

sulfides R-s-o 

disulfides R-S-S-R 

potential of the sediment (the presence or absence of 

sulfide) and whether or not reactive iron is present, which 

would effectively remove sulfide from the system before 

it could react in less kinetically favored organic reactions. 

Therefore, in depositional settings where reducing conditions coexist with small amounts of iron, sulfide could 

be present in sufficient quantities to react with organic 

matter to form high-sulfur kerogens. This reasoning is 

commonly used to explain high sulfur contents observed 

in many crude oils known to be derived from carbonate 

source rocks, and is sometimes used in the reverse 

manner as evidence that a particular oil may have been 

derived from a carbonate source rock. In contrast, depositional settings where greater quantities of reactive iron 

are present usually produce low-sulfur kerogens because 

most of the sulfur precipitates as iron sulfides before 

reactions with the organic matter can occur. This situation is typical for deposition of shale source rocks, 

although if enough sulfide is present or reactive iron 

content is relatively small, kerogens contained in shales 

may also have high sulfur contents. In general, oils 

derived from carbonate source rocks contain higher 

sulfur contents than oils derived from shale source rocks 

(Palacas, 1988). 

EXAMPLES 

/'-.../ SH 

propanethiol 

~SH thiacyclopentane 

s 

2,5-diheptylthiolane 

RMR 

cis-2,6-di-alkylthiane 

thiophenes 4-methyl-2-(3,7, 11- trimethyldodecyl)thiophene 

benzothiophenes 

dibenzothiophenes ~s~ 

~ 

~ 

~~~ S 2-methylbenzo[b]thiophene 

Figure 4. Classes of sulfur compounds reported in rock extracts and crude oils (after Ho and others, 

1974; Sinnighe Damaste and others, 1987c). S, sulfur; H, hydrogen; R, alkyl group. 

50 The Petroleum System-Status of Research and Methods, 1990 
Research in the area of sulfur geochemistry of 

sediments and oils is likely to remain quite active for the 

next several years. Besides applications in oil-source rock 

correlations, maturity studies, and kinetic models of oil 

generation, sulfur geochemistry may play an important 

role in interpretations of the diagenetic and thermal 

history of hydrocarbon compounds as well. For example, 

hydrocarbons that would otherwise be present in a rock 

extract can be incorporated into the resin, asphaltene, or 

kerogen fraction by sulfur bonding. Thermal desulfurization can later release these "trapped" hydrocarbons. The 

importance of this process is that research and applications using hydrocarbons contained in rock extracts must 

take into account the sulfur pathway as a sink or a source 

of hydrocarbons during the thermal evolution of organic 

matter and generation in petroleum. 

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Birch, S.F., 1953, Sulfur compounds in petroleum: Journal of 

the Institute of Petrology, v. 39, p. 185-201. 

Bolshakov, G.F., 1986, Organic sulfur compounds of petroleum: Sulfur Reports, v. 5, p. 103-393. 

Brassell, S.C., Guoying, S., Jimao, F., Pingan, P., Jigang, J., 

Gowar, A.P., and Eglinton, G., 1989, Organic sulphur 

compounds in Chinese hypersaline lake sediments and 

crude oils: American Chemical Society, Division of Geochemistry, 197th American Chemical Society National 

Meeting, Dallas, April 9-14, 1989. 

Constantinides, G., and Arich, G., 1967, Non-hydrocarbon 

compounds in petroleum, in Nagy, B., and Colombo, U., 

eels., Fundamental aspects of petroleum geochemistry: 

New York, Elsevier, p. 109-176. 

Giraud, A., and Bestougeff, M.A., 1967, Characterization of 

high molecular weight sulphur compounds in petroleum 

by pyrolysis and gas chromatography: Journal of Gas 

Chromatography, p. 464-470. 

Gransch, J.A., and Posthuma, J., 1974, On the origin of sulfur 

in crudes, in Tissot, B., and Bienner, F., eels., Advances in 

organic geochemistry 1973: Paris, Editions Technip, p. 

727-739. 

Ho, T.Y., Rogers, M.A., Drushel, H.V., and Koons, C.B., 1974, 

Evolution of sulfur compounds in crude oils: American 

Association of Petroleum Geologists Bulletin, v. 58, p. 

2338-2348. 

Hughes, W.B., 1984, Use of thiophenic organosulfur compounds in characterizing crude oils derived from carbonate versus siliclastic sources, in Palacas, J.G., ed., 

Petroleum geochemistry and source rock potential of 

carbonate rocks: American Association of Petroleum 

Geologists Studies in Geology 18, p. 181-196. 

Kohnen, M.E.L., Sinnighe Damaste, J.S., Eglinton, T.l., Rijpstra, W.l., and de Leeuw, J.W., 1989, Organic sulfur and 

non-sulfur compounds as selective indicators of changes 

in the paleo environment-A study of a Cretaceous oil 

shale from Jordan: American Chemical Society, Division 

of Geochemistry, 197th American Chemical Society National Meeting, Dallas, April 9-14, 1989. 

de Leeuw, J. and Sinnighe Damaste, J.S., 1989, Organic sulfur 

compounds and other biomarkers as indicators of paleosalinity and paleoproductivity: American Chemical 

Society, Division of Geochemistry, 197th American 

Chemical Society National Meeting, Dallas, April 9-14, 

1989. 

Orr, W.L., 1978, Sulphur in heavy oils, oil sands and oil shales, 

in Strausz, O.P., and Lown, E.M., eels., Oil sand and oil 

shale chemistry: New York, Springer-Verlag, p. 223-243. 

Payzant, J.D., Cyr, T.D., Montgomery, D.S., and Strausz, O.P., 

1985, The synthesis of 1-/3(H), 6-/3(Me)-2,2,6-trimethyl8-ethylbicyclo-4,3,0-7-thianone and the occurrence of 

the isomeric bicyclic terpenoid sulfides occurring in 

petroleum: Tetrahedron Letters, v. 26, p. 4175-4178. 

Payzant, J.D., Montgomery, D.S., and Strausz, O.P., 1986, 

Sulfides in petroleum, in Leythaeuser, D., and Rullkotter, J., eds., Advances in organic geochemistry 1985, 

Organic Geochemistry, v. 10, p. 357-369. 

Rullkotter, J., Littke, R., and Schaefer, R.G., 1989, Biological 

markers as facies indicators in sulfur-rich lacustrine 

sediments of Miocene age (Norglinger Ries, southern 

Germany): American Chemical Society, Division of Geochemistry, 197th American Chemical Society National 

Meeting, Dallas, April 9-14, 1989. 

Rullkotter, J., and Orr, W.L., 1989, Effects of thermal maturation on the distribution of sulfur compounds in sulfurrich Monterey crude oils: American Chemical Society, 

Division of Geochemistry, 197th American Chemical 

Society National Meeting, Dallas, April 9-14, 1989. 

Sinnighe Damaste, J.S., Kock-van Dalen, A.C., de Leeuw, J.W., 

and Schenck, PA., 1987a, The identification of 2,3-

dimethy-5-(2,6,10-trimethyl-undecane) thiophene, a 

novel sulphur containing biological marker: Tetrahedron 

Letters, v. 28, p. 957-960. 

Sinnighe Damaste, J.S., de Leeuw, J.W., Kock-van Dalen, A. C., 

de Leeuw, M.A., de Lange, F., Rijpstra, W.I.C., and 

Schenck, P.A., 1987b, The occurrence and identification 

of series of organic sulphur compounds in oils and 

sediment extracts: Geochimica et Cosmochimica Acta, v. 

51, p. 2393-2400. 

---1987c, The occurrence and identification of series of 

organic sulphur compounds in oils and sediment extracts. 

I-A study of Rozel Point Oil (USA): Geochimica 

Cosmochimica Acta, v. 51, p. 2369-2391. 

Sinnighe Damaste, J.S., Kock-van Dalen, A.C., de Leeuw, J.W., 

Schenck, P.A., 1988a, Identification of homologous series of alkylated thiophenes, thiolanes, thianes and benzothiophenes present in pyrolysates of sulphur-rich 

kerogens: Journal of Chromatography, v. 435, p. 

435-452. 

Sinnighe Damaste, J.S., Rijpstra, W.I.C., de Leeuw, J.W., and 

Schenck, P.A., 1988b, Origin of organic sulphur compounds and sulphur-containing high molecular weight 

substances in sediments and immature crude oils, in 

Novelli, L., and Mattavelli, L., eds., Advances in Organic 

Geochemistry 1987: Organic Geochemistry, v. 13, p. 

593-606. . 

Sinnighe Damaste, J.S., Rijpstra, W.I.C., Kock-van Dalen, A. C., 

de Leeuw, J.W., and Schenck, P.A., 1989a, Quenching of 

labile functionalised lipids by inorganic sulphur species: 

Evidence for the formation of sedimentary organic suiSulfur In Source Rocks and Petroleum 51 
phur compounds at the early stages of diagenesis: 

Geochimica et Cosmochimica Acta, v. 53, p. 1343-1355. 

---1989b, The occurrence and identification of series of 

organic sulphur compounds in oils and sediment extracts, 

II-Their presence in samples from hypersaline and 

non-hypersaline depositional environments and their 

possible application as molecular indicators of organic 

input, maturity and depositional environment: Geochimica et Cosmochimica Acta, v. 53, p. 1323-1341. 

ten Haven, H.L., de Leeuw, J.W., and Schenck, P.A., 1985, 

Organic geochemical studies of a Messinian evaporitic 

basin, northern Apennines (Italy) I: Hydrocarbon biological markers for a hypersaline environment: Geochimica et Cosmochimica Acta, v. 49, p. 2181-2191. 

ten Haven, H.L., de Leeuw, J.W., Sinninghe Damaste, J.S., 

Schenck, P.A., Palmer, S.E., and Zumberge, J.E., 1988, 

Application of biological markers in the recognition of 

palaeo hypersaline environments, in Kelts, K., Fleet, 

A.J., and Talbot, M., eds., Lacustrine petroleum source 

rocks: Geological Society Special Publication 40, p. 

123-130. 

Tissot, B.P., and Welte, D.H., 1984, Petroleum formation and 

occurrence: New York, Springer-Verlag, 699 p. 

Vairavamurthy, A., and Mopper, K., 1987, Geochemical formation of organosulphur compounds (thiols) by addition 

ofH2S to sedimentary organic matter: Nature, v. 329, p. 

623-625. 

Valisolalao, J., Peerakis, N., Chappe, B., and Albrecht, P., 1984, 

A novel sulfur containing C35 hopanoid in sediments: 

Tetrahedron Letters, v. 25, p. 1183-1186. 

52 The Petroleum System-Status of Research and Methods, 1990 
The Geochemistry of Evaporites and Associated Petroleum 

By Donald E. Anders and Robert J. Hite 1 

INTRODUCTION 

Nearly two-thirds of the world's known petroleum 

resources are associated with evaporites (Nehring, 1978; 

Perrodon, 1978). The most noted of these are the giant 

oil fields of the Middle East (500 billion bbl), which are 

believed derived from the Arabian Gulf evaporite facies 

and the Arabian-Persian carbonate platform. In spite of 

the fact that enormous amounts of oil are associated with 

evaporites, the exact nature of this relation remains 

unclear. Some researchers have sought to unravel this 

mystery by studying the relation between biomass production and evaporitic environment (Copeland and 

Jones, 1965; Kirkland and Evans, 1981; Warren, 1986; 

Hite and Anders, in press); others have sought to explain 

the spatiotemporal relation between evaporitic volumes 

and oil volumes (Szatmari, 1980; Kalinko, 1974; Hite and 

Anders, in press); while still others have chosen to 

address the geochemical relation between oil and associated evaporites (Palacas, 1984, 1988; Hite and Anders, 

in press). A comparison of oil volumes (Parparova and 

others, 1981) to evaporite volumes (Zharkov, 1981) by 

Hite and Anders (in press) shows a strong spatiotemporal relation between oil and evaporites of the Upper 

Devonian, Lower Cretaceous, and lower Neogene but no 

relationship with major evaporitic occurrences in the 

Lower Cambrian and Lower Permian. In basins showing 

a strong relation between petroleum and evaporite volumes, 46 percent of the oil and gas reservoirs occur 

below the evaporites, 41 percent above the evaporites, 

and 13 percent within the evaporite facies (Kalinko, 

1974). Hite and Anders (in press) offered several possible explanations for why large volumes of evaporites do 

not always have large volumes of associated hydrocarbons: (1) not all evaporite depositional environments are 

conducive to the accumulation of organic matter sufficient to generate commercial quantities of hydrocarbons 

(such as the shallow-water oxic environments of the 

midcontinent evaporites); (2) appropriate reservoirs and 

traps for evaporitic petroleum never developed or developed after migration; and (3) most occurrences of petroleum associated with evaporites are genetically related to 

evaporitic carbonate sediments which are not included in 

evaporite volume data. Whatever the reasons for this 

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

disparity, it is well documented that evaporitic environments can produce abundant biomass while providing 

excellent conditions for preservation of organic matter 

(Copeland and Jones, 1965; Neev and Emery, 1967; 

Nissenbaum and others, 1972, Cohen and others, 1977; 

Degens and others, 1978; Imhoff and others, 1979; 

Sackett and others, 1979; Sturm, 1980; Hammer, 1981; 

Kirkland and Evans, 1981; Northan and others, 1981; 

Lyons and others, 1982; Boon and others, 1983; Hite and 

others, 1984; Spencer and others, 1984; Klug and others, 

1985; Schidlowski and others, 1985; Warren, 1986; and 

many more). 

Evaporite environments and the rock types derived 

from them (carbonate, sulfate, and chloride minerals) 

cover a wide range of salinities from 35 permil (vitasaline) to over 350 permil (supersaline)(Lang, 1937; Kirkland and Evans, 1981; Hite and Anders, in press). 

Biomass production at various salinity stages in modem 

evaporitic environments generally increases with increasing salinity while the number of life-forms decreases with 

increasing salinity (Copeland and Jones, 1965; Klug and 

others, 1985). Green algae and cyanobacteria dominate 

the biomass of lower salinities while halophilic bacteria 

dominate the higher salinities (Javor, 1983; Sammy, 

1985). Preservation of organic matter is greatest in the 

anoxic environments of the higher salinities where burrowing and grazing organisms and aerobic bacteria find it 

difficult to survive (Friedman and others, 1973; Gerdes 

and Krumbein, 1984). However, high productivity and 

preservation do not necessarily mean high organic matter 

content in evaporitic rocks of higher salinities. This 

seeming contradiction is the result of high precipitation 

rates for evaporite minerals, which dilute the solid organic matter in the sediment (Hite and Anders, in press). 

Also, dissolved organic matter may be excluded from 

precipitation and never become a factor in organic matter content of evaporitic rocks unless the evaporitic 

environment is totally desiccated (Hite and Anders, in 

press). 

By far the most important evaporitic source rocks 

with respect to petroleum generation are carbonates. 

Carbonate source rocks often contain dark organic-rich 

laminated carbonate (marls) and argillaceous zones that 

can act as principal source material for petroleum generation (Hunt, 1968; Palacas and others, 1984). Carbonates can be excellent reservoirs as well (von Englehardt, 

1977). Associated evaporites (anhydrite, halite, and potash) are often the cap rocks for such reservoirs. Although 

The Geochemistry of Evaporites and Associated Petroleum 53 
organic matter productivity in brines producing only 

carbonates is generally much lower than in higher salinity 

environments, carbonate deposition rate is the slowest of 

all minerals in the evaporite depositional cycle, thus 

allowing total organic matter values to rise above values 

found in more rapidly precipitating mineral stages. 

Carbonate-halite precipitation rates can be as low as 

1:400 (Hite and Anders, in press). 

GEOCHEMISTRY OF EVAPORITE ROCKS 

Marine Carbonates 

The organic chemistry of marine carbonate rocks is 

much better known than for other evaporite minerals 

(Palacas, 1984; Palacas and others, 1984). For a review of 

pertinent literature pertaining to carbonate source rocks 

of petroleum, see Palacas (1988). Organic carbon content of carbonate rocks is highly variable, with values as 

high as 10 to 30 percent being reported (Spiro and 

others, 1983; Palacas, 1984; Palacas and others, 1984; 

Powell, 1984). However, most carbonate source rocks 

have total organic carbon values in the range 0.5 to 5.0 

percent (Palacas, 1984; Palacas and others, 1984; Sassen 

and others, 1987; Clark and Philp, in press). Bitumen 

extracts from marine evaporitic carbonates generally 

show pristane/phytane ratios below 1, however, values 

can be above 1. depending on the type of organic matter 

input and the reducing potential of the sedimentary 

environment (Didyk and others, 1978). Phytane/n-C18 

ratios are generally above 0.5 and often above 1. The 

carbon preference index (CPI) is usually equal to or less 

than 1 (nC22-nC32 ) but can show odd-carbon predominance ( CPI > 1) where there has been terrestrial organic 

matter input into the sediments. Nonhydrocarbon/hydrocarbon ratios are variable, depending on maturity, but 

generally exceed 0.35 in immature to moderately mature 

carbonate rocks. The C24 tetracyclic abundance is usually 

larger than the 6 tricyclic terpane pair. Hopanoid 

concentrations generally exceed sterane concentrations, 

and the C27/C29 sterane ratio is between 1 and 1.5. 

Methyl isomers of dibenzothiophene generally form a 

V-pattern in relative distribution in ·moderately mature 

samples but a stairstep distribution in mature samples 

(Hughes, 1984). Sulfur contents (organic and elemental) 

are generally higher in carbonate extracts than in shale 

extracts. The C23 tricyclic terpane peak is commonly the 

dominant tricyclic terpane. For further geochemical 

characteristics of organic matter in carbonates, see Palacas and others (1984, 1988), Mello and others (1988), 

and Hite and Anders (in press). 

Lacustrine Carbonates 

The hydrocarbon chemistry of bitumen extracts 

from carbonate-rich lacustrine rocks does not resemble 

that of marine carbonates in all aspects, largely due to a 

greater influx of terrestrial oxidized organic matter into 

lacustrine sediments. This terrestrial component is commonly sufficient to influence CPI values and give strong 

odd-carbon predominance in n-alkane distributions and 

to change c27 and c28 sterane dominance to c29 dominance. Other differences are seen in the dominant tricyclic terpane (frequently c20 or c21 instead of c23) and in 

relative abundance of hopanes/steranes is greater than 1 

( < 1 in thermally immature rocks). Perhaps the two most 

distinguishing biomarker characteristics of openlacustrine carbonate extracts are the great dominance of 

nC11 over other n-alkanes and the abundance of carotane 

isomers (/3-carotane dominating). /3-carotane is only minimally present in marine carbonates but is very abundant 

in lacustrine carbonate (Murphy and others, 1967; 

Anders and Robinson, 1971; Clark and Philp, in press). 

For further geochemical properties of lacustrine carbonates, see Hite and Anders (in press). 

Anhydrites 

Anhydrites are dense impermeable rocks whose 

organic matter genetically resembles the algal-rich type I 

and II kerogen, however, their organic content is usually 

too low for them to be considered viable source rocks 

( < 0.3 percent total organic content). One noted exception is the high organic carbon values (up to 30 percent 

total organic content) reported by Richardson and others 

(1988) for intrahalite beds consisting of laminated clays, 

magnesite, and anhydrite from the north Red Sea/Gulf of 

Suez Syn-Rift evaporite sequence. The authors theorized 

that these organic-rich zones are a result of algal blooms 

occurring during episodic freshening events. The importance of these thin organic-rich evaporite deposits as 

hydrocarbon source rocks remains to be seen. 

Organic geochemical data on anhydrites are limited (Connan, 1981; Palmer and Zumberge, 1981; Gardner and Bray, 1984; Connan and others, 1986; Hite and 

Anders, in press). Because of the highly reducing environment of anhydrite deposition, pristane/phytane ratios 

are less than 1, phytane/n-C18 ratios are somewhat variable but generally greater than 1, CPI is less than 1 (nC22 

to nC32); in relative concentrations, pentacyclics > steranes > tricyclics, c24 tetracyclic > c26 tricyclics, c29 

steranes > c27 or c28 steranes; and extended hopanes 

(~ -C35 ) are abundant. 

Halite and Potash 

Volumetrically, halite and potash are the most 

abundant of the evaporite minerals. One author, Szatmari (1980), suggests that via dissolution mechanisms 

halites could be the principal source rocks of the world's 

largest oil deposits. In spite of the volumetric favorability 

54 The Petroleum System-Status of Research and Methods, 1990 
of halite and potash as source rocks and the organic 

richness of halite- and potash-producing brines 

(300 + permil salinity range), the organic carbon contents 

of halite and potash seldom exceed 0.3 percent, and the 

majority has less than 0.01 percent TOC. The general 

consensus is that TOC values this low are insufficient to 

be considered a source rock (Hite and Anders, in press). 

Consequently, few studies of the organic geochemistry of 

halite and potash rocks have been reported. One report 

by Hite and Anders (in press), of Paradox and Permian 

Basin halites, gave the following general characteristics: 

pristane/phytane ratios 0.9 to 1.1, CPI generally less than 

1 (nC22 to nC32), relative concentration of hopanes 

exceeds steranes, c23 tricyclic terpane is the dominate 

tricyclic terpane, c24 tetracyclic > ~6 tricyclics, and the 

nonhydrocarbon!hydrocarbon ratio (non-HC/HC) is 

usually less than 0.3. 

GEOCHEMISTRY OF EVAPORITE SOURCED 

OILS 

Most of the geochemical information on oils derived from evaporite rocks is for oils associated with 

marine and lacustrine carbonates. For marine carbonate 

oils, see the literature survey by Palacas (1988) and 

Mello and others (1988). For lacustrine carbonate oils, 

see Tissot and others (1978), Mason (1981), Poole and 

Claypool (1984), Fleet and others (1988), and Mello and 

others (1988). Geochemical data on oil derived from 

anhydrite, halite, and potash are much more limited (see 

Hite and Anders, in press). 

Marine Carbonate Oils 

Marine carbonate oils have the following general 

geochemical characteristics: full range of API values 

from less than 20° to more than 50°, sulfur content 

usually greater than 1 percent, pristane/phytane less than 

1, CPI less than 1, non-HC/HC is 0.1 to 0.5, relative 

abundance of hopanes exceeds steranes, c27 steranes/ 

C29 steranes variable, moderate amounts of tricyclic 

terpanes (~3 maxima), abundant extended hopanes 

(C31 -~ ), 4 tetracyclic terpane > C26 tricyclic terpanes, and V -shaped distribution for methyldibenzothiophenes (Hughes, 1984 ). Additional organic 

geochemical properties are discussed by Palacas (1988) 

and Hite and Anders (in press). 

Lacustrine Carbonate Oils 

Lacustrine carbonate oils can have variable geochemical features depending on whether they are derived 

from organic matter dominated by type I kerogen (such 

as some of the Uinta basin oils) or some combination of 

types I and III kerogens (such as found in China basins). 

Generally, API values range from 20° to over 40°; sulfur 

contents less than 1 percent in oils from iron-rich sediments, pristane/phytane and CPI values are both less 

than 1 in oils derived from sediments deposited under 

anoxic, reducing, open-lacustrine evaporitic conditions 

but frequently greater than 1 in oils derived from both 

lacustrine biota and oxidized organic matter from continental sources; non-HC/HC is 0.2 to 1.7; relative abundance of steranes > hopanes > tricyclics in moderately 

mature oils, but hopanes > tricyclics > steranes in 

mature oils; c27 steranes < c29 steranes where continental input is a factor; tricyclic terpane maxima usually 

c20 or c21 but rarely c23; minimal extended hopanes; 

moderate gammacerane and abundant carotenoids. 

Anhydrite Oil 

Geochemical data for oils derived from anhydrite 

rock are limited (Hite and Anders, in press). Based on 

the work of Hite and Anders (in press), the following 

geochemical properties were observed: pristane/phytane 

less than 1; phytane/n-C18 greater than 1; non-HC/HC up 

to 30 percent; hopanes > steranes; moderate to abundant pregnane; c27 steranes < ~9 steranes, minimal to 

moderate tricyclic terpanes (maxima ); 4 tetracyclic 

terpane (abundant) > c26 tricyclic terpanes; and abundant extended hopanes (maxima ). Palacas and others 

(1984) mentioned a number of oil shows in the Punta 

Gorda Anhydrite (south Florida) but stated that these 

shows were generally associated with carbonate-rich facies in the anhydrite zone. The authors did not know 

whether these oil stains were carbonate or anhydrite 

derived. Likewise, Clark and Philp (in press) reported on 

the possible evaporite origin of some oils of the Black 

Creek Basin, Ontario. Like the Punta Gorda source 

rocks, the Black Creek oil source rocks were interbedded 

carbonates and anhydrites. 

Halite and Potash Oil 

The geochemical characteristics of halite-potash 

oils are based primarily on data from seeps in potash 

mines in the Paradox (Utah) and Permian (New Mexico) 

basins and a seep in a halite mine (Pugwash) in New 

Brunswick. Additional data were obtained from oil inclusions and stained halite core from the Paradox basin 

(Utah)( see Hite and Anders, in press). Sulfur content in 

the halite-potash oils is generally less than 0.1 percent. 

Sulfur isotopic values approach -19 permil and carbon 

isotopes -30 permit. Pristane/phytane ratios were 1 or 

greater. If low pristane/phytane ratios ( < 1) reflect depositional environment, as some have suggested (Brooks 

and others, 1969, Didyk and others,l978, ten Haven and 

others, 1987, and others), the observed values reported 

by Hite and others (1984) and Hite and Anders (in press) 

are a bit high. On the other hand, if these pristane/phyThe Geochemistry of Evaporites and Associated Petroleum 55 
tane values reflect not only the values of the depositional 

environment but possible input from organic matter 

sources outside the basin, the values could be expected to 

be higher. Hite and others {1984) offered corroborating 

data in support of transport of oxidized organic matter 

into the Paradox basin. Other geochemical properties of 

halite-potash oils are: CPI greater than 1 {C15-C17), but 

no preference for the Femaining n-alkanes, non-HC/HC 

is less than 30 percent, abundance of hopanes > steranes, c27 steranes > c29 steranes, abundant diasteranes, 

moderate amounts of tricyclic terpanes (maxima C23), 

c24 tetracyclic > ~6 tricyclics, and moderate amounts of 

extended hopanes (maxima c31). 

SUMMARY 

Evaporite depositional environments can be excellent settings for the production and preservation of 

hydrogen-rich organic matter. Evaporite rocks, though 

generally lower in organic carbon content than shales, 

have two to eight times as much extractable organic 

matter per gram of organic carbon as do shales (Tissot 

and Welte, 1984, p. 97). Under the proper conditions of 

time and temperature, much of the organic matter associated with evaporites is converted to hydrocarbons. 

Because of their low permeabilities, evaporite rocks 

make effective seals against fluid and gas migration, thus 

much of the generated hydrocarbon is kept locked in the 

evaporite sequence. However, through dissolution, bacterial reworking, and diapirism evaporates can become 

good reservoirs as well. We have only begun to understand the value of evaporites in relation to petroleum 

generation. Future work will undoubtedly challenge our 

present ideas and concepts. 

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58 The Petroleum System-Status of Research and Methods, 1990 
Effect of Biodegradation on Crude Oils 

By G. Eric Michael 1 

The use of molecular parameters and bulk properties of oil or rock extract is common practice for making 

oil-to-oil, oil-to-source rock correlations and maturity 

determinations in petroleum exploration. However, biodegradation of oils from reservoir rocks or surface seeps 

can add to the difficulty of establishing a correlation or a 

level of maturity based on bulk or molecular properties. 

The link between biodegradation and the conditions 

under which biodegradation occur are important to know 

when interpreting hydrocarbon history. Bulk oil properties, such as API gravity, sulfur content, o

13C, o34S, and 

percent saturates and aromatics, are altered with only 

low to moderate degradation (Seifert and others, 1984; 

Connan, 1984). Increased optical activity and destruction 

or alteration of sterane and terpane biomarkers result 

from more extensive biodegradation (Seifert and Moldowan, 1979). 

The status of research into crude oil biodegradation is here organized relative to increasing alteration. It 

should be stressed that severity of biodegradation is not 

absolute and exceptions are common. The exceptions to 

the general trend in degradation is the result of many 

different variables such as pH, Eh, time, temperature, 

and microbial species. In general, the smaller and simpier the structure of an organic molecule, the more likely 

it is to be biodegraded. 

A synopsis is also given toward biomarkers or 

petroleum fractions that might be of particular use in 

very extensively biodegraded oils. Porphyrins, tricyclic 

terpanes, mono-aromatic and triaromatic steroids, and 

pyrolysis-gas chromatography (py-GC) of asphaltene 

fractions appear to be good correlation tools for extensively biodegraded oils. 

Table 4 summarizes biodegradation parameters 

commonly used in oil exploration. The effects due to 

biodegradation on o

13C and o34S isotopes of whole oil 

and oil fractions are not addressed here (see Stahl, 1980, 

and Hartman and Hammond, 1981). 

The saturated hydrocarbon fraction of oil is usually 

the first affected by only light biodegradation. However, 

exceptions to the relative order of biodegradation are still 

being discovered as research progresses. The typical 

order is preferential removal of light n-alkanes followed 

by removal of iso- and anteiso-alkanes and then iso1

U.S. Geological Survey, Denver, Colo. 

prenoids (Alexander and others, 1983; Connan, 1984). 

Upon moderate to extensive degradation, polycyclic molecules are then attacked within the saturate hydrocarbon 

fraction. 

The steranes and diasteranes are preferentially 

removed in the order of C27 > C28 > C29 (Goodwin and 

others, 1983). Biodegradation of steranes shows stereoselective removal of the biological 5a,14a,17a 20R isomer (Rullkotter and Wendisch, 1982; McKirdy and 

others, 1983). The geological isomer 5a,14a,17a 20S is 

preferentially degraded over the 14,8,17.8 series (Seifert 

and others, 1984, Chosson and Connan, 1989). Diasteranes are typically attacked after the C27-C29 regular 

steranes with the 20S isomer attacked preferentially over 

the 20R isomer (Seifert and Moldowan, 1979). An exception to this order was found by Williams and others 

(1986) in south Texas crude oils, in which the steranes 

were not degraded but diasterane concentrations were 

significantly lowered. The regular steranes 1 and C20 

appear to survive even after extensive biodegradation of 

steranes and diasteranes (Connan, 1984). 

Volkman and others (1983) showed that hopane 

biodegradation immediately followed initial alteration of 

5a,14a,17a 20R steranes. In an earlier study, Seifert and 

Moldowan (1979) observed hopane demethylation to be 

concurrent with sterane degradation. Goodwin and others {1983) showed the susceptibility of hopanes to bio-. 

degradation follow the order C35 > C34 > C33 > C32 

>C31 >C30 >C29 • However, in a recent study of biodegraded tar-sand extracts, Lin and others {1989) showed 

biodegradation in the order 0 > ~1-C33 >.C34-C3s· 

The preferential removal of the biological 22R isomer 

hopane was confirmed in both studies. A number of 

studies have shown that extensive biodegradation of 

17a(H)-hopanes produces a series of ring AlB demethylated hopanes (25-norhopanes) (Seifert and Moldowan, 

1979; Rullkotter and Wendisch, 1982; Volkman and 

others, 1983). However, biodegradation of hopanes does 

not always produce ring AlB demethylated hopanes 

(Goodwin and others, 1983; Connan, 1984; Lin and 

others, 1989). Moreover, demethylated hopanes have 

been found in apparently nonbiodegraded oils (Philp, 

1983; Volkman and others, 1983; Howell and others, 

1984). The possibility that demethylated hopanes could 

originate from source rock has not yet been proved or 

disproved. Cassani and Gallango (1988) suggested that 

the presence of demethylated hopanes is related. to the 

main site of biodegradation, surface or near surface 

Effect of Biodegradation on Crude Oils 59 
Table 4. Commonly used geochemical parameters and how 

they are affected by biodegradation 

[*, not affected or highly resistant; (?), questionable as to how the 

parameter is affected or at what level; HC, hydrocarbons; E, etio 

porphyrin; D, DPEP porphyrin; PH, phenanthrene; MPH, 

methylphenanthrene; DMPH, dimethylphenanthrene] 

Parameter Effect Severity 

Bulk properties, 

often continuous change with progressive effects 

API gravity Decreases Low-very high 

Optical activity Increases Moderate-very high 

Saturated HC/aromatic HC Decreases Low-moderate 

HC/resins+asphaltenes Decreases Low-high 

Total sulfur Increases Moderate-very high 

Alkanes, 

followed by iso-,anteiso-alkanes, and isoprenoids 

Pristane/n-C17 Increases Low 

Phytane/n-C18 Increases Low 

Pristane/phytane Decreases(?) Moderate 

Steranes, 

biodegraded after n-alkanes and isoprenoids 

Sterancs/diasteranes Decreases High 

Steranes/hopanes Increases(?) High-very high 

5a(20S)/5a(20R) Increases High 

C21 +C22/C27-C29 Increases High-very high 

aaa-C27 /aaa-C29 Decreases High 

aaa-C12./aaa-C29 Decreases High 

Diasteranes, 

more resistant than C27-C22 regular steranes 

Decreases High-very high 

Decreases High-very high 

Terpanes, 

C30 -C35 hopanes degraded while regular steranes degraded 

22S/22R hopanes Increases High 

C27-C2/C30-C35 hopanes Increases High-very high 

Tm/Ts; norhopanes *(?) High-very high 

Tri+tetra/pentacyclic Increases High-very high 

Aromatics, 

some may be degraded prior to alkanes 

PH/MPH Decreases Moderate-high(?) 

MPH/DMPH Decreases Moderate-high(?) 

Mono-/tri-aromatic steroid * Very high 

Porphyrins, 

appear not affected by severe biodegradation 

DPEP/ETIO * Very high 

C'}j,E/(C28E+C32D) * Very high 

Asphaltenes-resins, 

appear not affected by severe biodegradation 

Py-GC * Very high 

versus subsurface, with demethylated hopanes being absent in surface or near-surface degraded samples. Moretanes, which appear more resistant than hopanes, show 

increased susceptibility to biodegradation with increased 

carbon number. The C29 -hopane, 17cx(H)-22,29,30-

trisnorhopane (Tm), and 18cx(H)-22,29,30-trisnorneohopane (Ts) are particularly resistant to biodegradation 

(Seifert and others, 1984; Lin and others, 1989). Brooks 

and others (1988) found that the Tstrm ratio was not 

affected among biodegraded oil sands of western Canada. Tricyclic and tetracyclic terpanes appear to be highly 

resistant to biodegradation, as confirmed by Connan and 

others (1980), Goodwin and others (1983), and Lin and 

others (1989). However, tricyclic terpanes have been 

found to be demethylated similar to hopanes in severely 

biodegraded oils of the St. Aubin Asphalt, Switzerland 

(Connan, 1984). 

The biodegradation of aromatic hydrocarbons is 

not as well understood as that of the saturated hydrocarbons. The general susceptibility of most aromatic compounds during aerobic degradation is monoaromatic> diaromatic > triaromatic (Connan, 1984). 

The best known exception to this order is the resistivity of 

monoaromatic and triaromatic steroids, which are resistant to biodegradation even after the c27-~9 steranes, 

hopanes, and C27-C29 diasteranes have been severely 

biodegraded (Volkman, 1984; Wardroper and others, 

1985). It should be noted that Jones and others (1983) 

found that low-molecular-weight aromatic compounds 

apparently are not biodegraded under anaerobic conditions, but only under aerobic conditions. 

Aromatic compounds that are alkyl-substituted 

have been shown to be biodegraded by a cooxidation 

pathway similar to that of n-alkanes (Raymond and 

others, 1971 ). In general, resistivity increases for the 

alkylaromatics as the number and length of alkyl substituents increase. Increased numbers of substituents, especially if adjacent, apparently cause steric hindrance 

effects which increase the resistance to microbes that use 

alkyl cooxidation. It should be mentioned, however, that 

oxidation of the unsubstituted ring can still take place 

aerobically, either by other microbes or under different 

environmental conditions. Different isomers of alkylsubstituted aromatics have been shown to be biodegraded at different rates (Rowland and others, 1986). An 

example of the previously mentioned factors in biodegradation of alkylaromatic compounds has been worked 

out for alkylnaphthalenes by Volkman, 1984. The order 

of susceptibility follows: naphthalene> 2-MN > 1-MN 

> 2,7-, 1,7- and 1,6-DMN > 1,3- and 2,6-DMN > 1,4-

and 1,5-DMN>1,2-DMN>2,3-DMN and 1-EN>2-E 

> 1,8-DMN (where MN is methylnaphthalene, DMN is 

dimethylnaphthalene, and EN is ethylnaphthalene ). In 

some oil samples studied, the order of degradation of 

some alkylnapthalene isomers has been found to be 

switched and has been attributed to different environmental conditions (Volkman, 1984). Trimethylnaphthalenes are more resistant to biodegradation than 

naphthalene, MN, and DMN (Rowland and others, 

1986). Biphenyl and 3-methylbiphenyl appear to both be 

at least as susceptible to biodegradation as the methylnaphthalenes (Rowland and others, 1986). Phenanthrene 

and methylphenanthrenes are more resistant to biodeg60 The Petroleum System-Status of Research and Methods, 1990 
radation than naphthalene and methylnaphthalene 

(Volkman, 1984; Rowland and others, 1986). Phenanthrene appears to be more easily biodegraded than the 

methylphenanthrenes, of which the 9-isomer appears 

most resistant (Rowland and others, 1986). Sulfur content is known to increase with biodegradation, but it is 

unclear as to when these compounds are altered relative 

to other aromatic compounds. Degradation of sulfurbearing aromatics has been reported in the literature 

(Connan, 1984), and benzothiophene appears to be degraded prior to dibenzothiophene (Connan, 1984). 

Connan (1984) has shown that extensive alteration 

of both aromatics and alkanes is generally found only at 

the surface or at shallow depth, while in deeper reservoirs, highly altered aromatics and organosulfur compounds are associated with only mildly altered alkanes. 

Preferential alteration of aromatics over alkanes has also 

been observed in the laboratory (Rowland and others, 

1986). In either case, the magnitude of unresolvable 

complex mixture in the GC-chromatograms for both the 

saturate and aromatic hydrocarbon fractions increases 

with increased biodegradation (Volkman and others, 

1983; Brooks and others, 1988). 

Considerable debate still exists among researchers 

as to whether the asphaltene and resin fractions are 

affected by biodegradation (Connan, 1984 and references therein). Teschner and Wehner (1985) demonstrated 

in laboratory experiments that py-GC products of asphaltenes are not affected by biodegradation. The resistance of asphaltenes to biodegradation has been further 

demonstrated in field studies by Rubinstein and others 

(1979), and Bonnamay and others (1987), who compared 

asphaltene pyrograms of biodegraded and nonbiodegraded oils. 

Porphyrins, which appear to be highly resistant to 

biodegradation, are a class of biomarkers present in the 

more polar aromatic and resin fractions of rock extracts 

and crude oils. Barwise and Park (1983) found no change 

in porphyrin distributions for a suite of oils derived from 

a common source and of similar maturities but at different reservoir depths and subjected to different levels of 

biodegradation. Palmer (1983) demonstrated that 

DPEP/ETIO ratios of porphyrins are good maturity 

parameters when biodegradation has already affected 

parameters such as API gravity, n-alkanes, and sterane 

and hopane distributions. Michael and others (1989), in a 

study of tar sand extracts from core, found no evidence 

for alkyl side chain cooxidation of porphyrins, cleavage of 

the isocyclic ring in D PEP porphyrins, or other alteration 

of the tetrapyrrole ring structure, despite extensive biodegradation of steranes and hopanes. 

Observed discrepancies in the order of biodegradation of compounds attests to the complication of 

studying a process which is undoubtedly subject to several variables. Further laboratory and field observations 

are required to understand how such variables as ternperature, pH, Eh, growth factors, nutrient supply, and 

microbe species influence order and rate of biodegradation. In the future, with continued research, it could 

become possible to distinguish between primarily aerobic 

or anaerobic biodegradation processes. The ability to 

distinguish aerobic versus anaerobic degradation could 

be very useful in confirming current or paleohydrodynamic conditions of an oil reservoir. 

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Effect of Biodegradation on Crude Oils 61 
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1903-1907. 

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20, p. 407-416. 

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in crude oils from the Barrow sub-basin of Western 

Australia: Organic Geochemistry, v. 6, p. 619-632. 

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et Cosmochimica Acta, v. 47, p. 785-794. 

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Rullkotter, J., eds., Advances in organic geochemistry, 

1985: Oxford, Pergamon, p. 451-461. 

62 :rhe Petroleum System-Status of Research and Methods, 1990 
Heavy Oil and Natural Bitumen 

By Richard F. Meyer1 

INTRODUCTION 

Original reserves of heavy oil in the United States 

are estimated to be 30.2 billion barrels and undiscovered 

resources are 4.3 billion barrels. In-place bitumen in the 

United States is estimated to be 22.9 billion barrels of 

demonstrated resources and 33.7 billion barrels of inferred resources (Meyer and Duford, 1989). An increasing need for new oil supplies indicates that increased 

research and exploration are necessary to make the heavy 

oil and bitumen fill at least a portion of this need. 

Research directed toward heavy oil and natural 

bitumen in the United States is at a low level, except as 

reported in the U.S. Department of Energy symposia on 

Enhanced Oil Recovery and a few joint projects of the 

Department with industry. Most heavy oil in the United 

States has been and is produced in California. In 1988, 

466,000 barrels of heavy oil per day (bbl!d) were produced in the United States by enhanced oil recovery 

methods: 97.8 percent by steam injection, 1.4 percent by 

in situ combustion, and small amounts by using chemical 

additives (Meyer and Duford, 1989). For 1979, Marchant 

and others (1981) reported five natural bitumen recovery 

projects: two by steam, two by combustion, and one 

utilizing mining. For 1985, Marchant (1988) reported 34 

in situ and nine mining projects. Today there are no 

activ~ recovery projects. Fortunately, two other Western 

Hemisphere nations, Venezuela for heavy oil and Canada for bitumen, have already made major strides in 

solving some of the research problems associated with 

the exploitation of these commodities. 

DEFINITIONS 

Definitions of heavy crude and bitumen are based 

upon either their physical or chemical properties or on a 

combination of the two. Although chemical analysis is 

rigorous, it is time consuming and the chemical composition is often reflected in the more easily measured 

physical attributes. The most readily available of these 

physical characteristics are the API gravity and the 

viscosity, and either or both of these are commonly used 

to set the limits of heavy crude and natural bitumen. The 

1

U.S. Geological Survey, Reston, Va. 

API gravity is expressed on a scale in which 10° is 

equivalent to a specific gravity of 1 and a density of 0.934 

g/cm3

• Viscosity, the resistance to flow, may be expressed 

in poises (pascal·seconds), the quotient of shearing stress 

and velocity gradient. Heavy oil (Martinez, 1984; Byramjee, 1983) is defined as that oil having API gravity of 20° 

and extra heavy oil as that below 10°, regardless of 

viscosity. Natural bitumen is any oil having a viscosity 

greater than 10,000 centipoises (cP). Briggs and others 

(1988) include bitumen with heavy oil which is then 

defined as any oil more viscous than 100 cP. Refiners 

define heavy oil as any oil which will yield 15 percent 

residuum at a temperature of 1,010 °F (National Petroleum Council, 1980; Meyer, 1987). Another type of 

classification (Hunt, 1979) is based on the fact that 

bitumens are soluble in carbon disulfide, whereas pyrobitumens are neither soluble nor fusible. Among the 

bitumens, the application of heat discriminates natural 

asphalt, which fuses, from the asphaltites-such as gilsonite-which are difficult to fuse, and the mineral waxessuch as ozocerite-which are easily fused. Natural asphalt is by far the most important quantitatively and is a 

potential source of synthetic oil. Unless specifically stated 

otherwise, the term "natural bitumen" refers to, and is 

synonymous with, "natural asphalt." Connan and van der 

Weide (1978) point out the weakness of classifications 

based on physical attributes; these physical characteris-. 

tics may result from immaturity of thermal evolution or 

postexpulsion alteration as well as from uninterrupted 

maturation. Nonetheless, a classification -based upon 

physical characteristics (Martinez, 1984) is useful for the 

compilation of statistical data. The compiler must recognize that such a classification neither necessarily indicates the origin of the oil nor distinguishes between 

immature oil and oil that which has been subjected to 

alteration. The origin bears upon the methods employed 

for resource assessment and on the recovery of the oil 

from known deposits. 

RESOURCES 

In the United States, about one-third of the original reserves of heavy oil, about 10 billion barrels, are in 

giant fields having recoverable original reserves of 500 

million barrels each; 8 of the 10 giant fields are in 

California (Meyer and Duford, 1989). Heavy oil is identified in 44 U.S. petroleum provinces, of which 5 contain 

Heavy 011 and Natural Bitumen 63 
giant fields and 4 contain offshore fields. Bitumen deposits are found in 17 petroleum provinces. Although many 

of the deposits have served as sources of direct-use 

asphalt in the past, no natural bitumen is being produced 

in 1989. Of the 56.6 billion barrels of in-place bitumen in 

the United States (Meyer and Duford, 1989), two-thirds 

is contained in four provinces: the Uinta basin (23 

percent), the Arctic Coastal Plain basin (19 percent), the 

Warrior basin (14 percent), and the Paradox basin (11 

percent). 

CHEMISTRY 

Typically, the heavy oils and natural bitumens have 

high molecular weight and viscosity, low n-alkanes, high 

asphaltenes and resins, high sulfur, and high trace metals, 

especially nickel and vanadium. The composition of 

heavy oil and bitumen is a function of source rock type, 

thermal maturation, and alteration, three processes that 

operate singly or in combination. Generally, a carbonate 

source rock expells oil that contains more nitrogensulfur-oxygen (NSO) compounds than a siliciclastic 

source rock. Low maturity is indicated by few hydrocarbons, many NSO compounds, high molecular weight, 

high sulfur to nitrogen ratio (SIN), low API gravity, and 

high viscosity (Waples, 1985). Silverman (1978) stated 

succinctly that maturation leads to an increase in 

saturate-hydrocarbon and gasoline contents and a decrease in NSO compounds, whereas degradation has the 

opposite effect, n-alkanes are reduced and the asphaltene 

and NSO contents are greatly increased. 

The alteration of an oil after it is expressed from a 

source bed can take many forms. Cracking, in which large 

molecules are reduced to smaller ones, is a part of the 

maturation process due to increase in temperature and 

pressure consequent to greater depth of burial and may 

eventually lead to thermogenic gas and ultimately to 

graphite. The effects of temperature on the maturation 

of organic matter and petroleum are well known (Hunt, 

1979; Waples, 1985), and temperature has been correlated with many indices of maturation (Heroux and 

others, 1979). Pressure effects have been both acknowledged (Tissot and others, 1974) and denied (Hunt, 1979) 

as an important factor in petroleum generation. Both 

hydrostatic and lithostatic pressure increase with depth, 

as does temperature; pressure also is basic to the cracking of oil in refineries. Pressure therefore appears to play 

a significant role in petroleum generation and, in particular, to the evolution of heavy oil and bitumen and should 

be accorded research effort. Nonthermal alteration leads 

to degradation of the oil through the processes of deasphalting, water washing, and biodegradation. Deasphalting is the precipitation of the large, heavy asphaltene 

molecules by natural gas and gravity segregation, often 

forming a tar mat at the oil-water contact. Water washing 

is a process of selective dissolution of certain lighter 

components of the oil by water, but the effects are 

generally small (Waples, 1985) and will not lead to 

development of a tar mat (Lafargue and Barker, 1988). 

Biodegradation by bacteria in the oxygenated zone is the 

most important degradation process. It may commence 

during secondary migration through the carrier bed from 

the source bed to the reservoir but most commonly takes 

place after the entrapped oil is elevated into the zone of 

oxidation. The result is a surface or near-surface natural 

bitumen deposit. Waples (1985) and Connan (1984) have 

summarized the effects of biodegradation. In order of 

preference the bacteria attack: (1) then-alkanes, (2) the 

long alkyl side-chains, (3) the single methyl branches or 

the widely spaced branches, ( 4) the isoprenoids, and ( 5) 

the polycyclic alkanes. No evidence indicates that bacteria affect porphyrins, asphaltenes, or the heavy NSO 

compounds. Thus, alkanes may be reduced from their 

normal 60 percent of the oil to 20 percent, with consequent increase in aromatics and polar compounds. Sulfur 

may be increased proportionately by hydrocarbon removal and by sulphate reduction. 

The heavy oil and bitumen are highly viscous 

because of their high content of asphaltenes. In laboratory analysis with solvents, n-pentane precipitates the 

asphaltenes. Condensate, including pentane, is also used 

as a diluent to move heavy oil and bitumen through 

pipelines (Todd, 1988). Consequently, the volume of 

solvent mixed with the oil is critical to prevent precipitating asphaltenes that would clog pipelines and disrupt 

delivery of the oil to refineries. Research is being conducted on diluents to determine the correct amount to be 

used to avoid precipitation and on the positive effects of 

adding carbon dioxide (Fuhr and others, 1989) as well. 

Excessive asphaltenes tend to foul refinery crude exchangers (Dickakian and Seay, 1988) and other equipment. Research is required on the role of asphaltenes not 

only in condensate mixtures but also on refinery feed 

stocks when two or more asphaltic crudes are to be 

combined. 

Asphaltene precipitation is manifested in another 

way by the formation of tar mats in numerous oil fields. 

Haldorsen and others (1988) describe the tar mat in the 

Prudhoe Bay field. Hirschberg (1988) discusses compositional variations in the fluid columns of reservoirs, 

citing the tar mat as the extreme example. The tar mat 

can seriously impede the flow of water in the reservoir, 

either naturally or when waterflood recovery is attempted. The presence of tar mats reduces or hampers oil 

recovery. 

CATALYSIS 

In refming crude oil, catalytic cracking is used in 

preference to thermal cracking because reaction rates 

are faster, lower temperatures are needed, less coke and 

64 The Petroleum System-Status of Research and Methods, 1990 
gas are produced, and more branched alkanes result, 

yielding a higher octane rating (Neumann and Rahimian, 

1984). The aluminum silicate catalysts which made catalytic cracking economic consisted of naturally occurring 

bentonite, later succeeded by synthetic montmorillonite. 

In nature, according to Waples (1985), the role of 

catalysis is not proved but probably varies with the 

particular clay mineral. It is generally accepted that the 

result of petroleum maturation reflects the nature of the 

original organic matter that formed the kerogen of the 

source rock, the temperatures to which the source rock 

and, later, any expelled petroleum, were exposed, and the 

geologic time involved during which the genetic process 

takes place. Goldstein (1983) makes a compelling argument for the place of geocatalytic reactions in the generation of oil. He identifies two energetically difficult 

reactions required for oil formation: shortening of alkane 

chains by cracking to produce gases and light oils, and 

fatty acid decarboxylation to yield n-alkanes. Without 

catalysts, these reactions can only take place in the 

laboratory at temperatures above 752 °C. Such reactions 

do, in fact, occur naturally. Hunt (1979) reviews the 

subject of geocatalysis, concluding that activation energies for many reactions require something other than 

straight thermal cracking, including lower energies involved in simultaneous reactions. Other explanations 

may be possible for the differences between laboratory 

experiments and extrapolations into geologic time. Milner and other·s (1977) presented views for and against 

natural catalysis but suggested that geocatalytic cracking 

may be a factor. Freund and Keleman (1989), on the 

basis of studies of low-temperature pyrolysis, believe that 

the time required for natural oil generation can be 

explained by measured high-temperature kinetics, which 

are stated to be valid at temperatures as low as 209 °C. 

They feel that geocatalysis may be possible but is not 

necessary. However, 209 oc is still at or near the upper 

limit of the oil generation zone. Additional research is 

necessary to establish whether geocatalysis is effective in 

the oil-generation process. 

OIL SEEPS 

Oil seeps are common throughout the world. They 

provided a source of bitumen in antiquity for caulk and 

cement and were one of the earliest surface indicators to 

be used in oil exploration. Lists of some of the betterknown seeps are given in Abraham (1960), Forrer 

(1986), and Meyer and Fleming (1986). Thompson 

(1934), Hunt (1979), and Forrer (1986) described the 

characteristics of oil seeps and their use for direct 

exploration and as guides to shallow buried deposits. 

Seeps may owe their origin to various causes: exhumed 

and degraded conventional oil deposits, exhumed immature deposits, or the surface manifestation of a liquid oil 

deposit whose carrier bed has been breached by erosion 

and is now exposed at the surface. Knowledge of the 

characteristics of individual seeps bears directly upon the 

proper interpretation of petroleum systems involving 

heavy oil and natural bitumen deposits. 

UNDISCOVERED RESOURCES 

There is no certain way to assess the quantity of the 

undiscovered resource of heavy oil, even more than light 

oil, in a given basin. The method used by Meyer and 

others (1984) was simply to determine the proportion of 

reserves in a basin that were heavy oils and apply that 

proportion to the total undiscovered oil, as determined 

by others (for example, Dolton and others, 1981). These 

assessments are inaccurate because conventional assessment methods do not include heavy oil, except in fields 

under production at the time of the estimate, or bitumen 

deposits (McKie, 1982), and the methods themselves 

have specific deficiencies. Procter and others (1982) 

devised a method of play analysis which they have applied 

to heavy oil in Canada. A review of heavy oil assessment 

methods by Meyer and Schenk (1986) stresses the need 

for considering material balances to account for the loss 

of as much as 80 percent of the original oil through 

various degradation processes. However, the estimation 

of possible amounts of undiscovered oil alone is not 

enough to be useful for planning. Some idea of the 

potential for recovery must also be applied. Innovative 

research on this subject is reported by Connan and 

Coustau (1987). Their studies emphasized the necessity 

for distinguishing immature oil (Petersen and Hickey, 

1987; Clayton, 1989) from mature, but degraded, oil. If 

degradation preceded accumulation or if the oil is immature, the oil will contain large molecules and will be 

highly viscous. Thus, it can saturate only the most permeable and porous zones in the reservoir, making recovery by steam flooding efficient. But if the oil was 

originally light, it could have entered the less permeable 

and less porous zones in the reservoir. After degradation, 

these zones contain very viscous oil and are very difficult 

to sweep efficiently, which may lower the recovery to or 

below the economic limit, effectively reducing the recoverable oil assessment. 

The assessment of natural bitumen resources is 

more straightforward than for heavy oil because the 

deposits are mostly at the surface or occur at shallow 

depths in proximity to surficial deposits. Historically, 

most such deposits have been located by surface geological exploration; however, means are now available to 

search for natural bitumens by remote sensing ( Cloutis, 

1989). Moore (1984) summarized the ways in which 

asphalt deposits (tar seals) can be utilized for exploration 

by indicating buried deposits either below the seals, along 

basin margins, or in stratigraphic traps. 

Heavy 011 and Natural Bitumen 65 
The role of economics is extremely important in 

determining feasibility of recovery from bitumen deposits. The deposit grade and size are of fundamental 

importance (Meyer and Schenk, 1986; Earley, 1987). 

ASSESSMENT BY PETROLEUM SYSTEM 

The concept of petroleum systems (Magoon, 1988) 

offers the best opportunity for assessment of heavy oil 

and natural bitumen resources because the development 

of such systems is based on geological fact and intuition 

rather than on simple statistical data manipulation. Evaluation factors include the level of system certainty; 

source rock age, lithology, thickness and kerogen type; 

reservoir-rock age, lithology, and thickness; and overburden age, lithology, and thickness. Information on hydrocarbon maturity, degradation, chemical attributes, and 

richness may readily be added for heavy oil and bitumen. 

The ages can be established by use of the U.S. Geological 

Survey geologic names handbook {Swanson and others, 

1981), and derived computer printout sheets can provide 

the appropriate geologic province name. The timespans 

for generation, accumulation, and degradation can be 

estimated from geologic time scales, such as contained in 

Harland and others {1982). These data, and information 

from available boreholes, will provide a data base for an 

accurate assessment of the potential volume of petrolifero us sediment. Pusey {1973) and McDowell {1975) 

outlined the general principles of basin-potential evaluation. 

Cooles and others {1986) gave formulas for calculating petroleum masses generated and expelled from 

source rocks. They concluded that rich source rocks 

having organic carbon in excess of 1.5 percent may lead 

to the expulsion of 60 to 90 percent of oil generated, 

whereas expulsion from leaner source rocks is correspondingly less efficient. Tannenbaum and others {1987) 

showed that in the conversion of light oil to heavy oil as 

much as 80 percent of the oil volume may be lost. 

Moshier and Waples {1985) demonstrated that, in addition to those present in the rock body, in which the 

Athabasca reservoir rocks are located,· additional source 

rocks are required to supply the quantity of petroleum 

present in the Athabasca deposits. Similarly, Nalivkin 

and others {1984) calculated that 65 percent of the oil 

that originally migrated into the Olenek deposit in Siberia was lost by degradation. The amounts of oil lost by 

degradation in the world are staggering. Hunt (1979) 

estimated that the asphalt deposits of the world contain 

about 2 trillion barrels of oil, a very conservative estimate. He calculated that, had these deposits originally 

been of 35° API gravity oil, their volume would have been 

9.5 trillion barrels. Use of the petroleum system approach will make possible the estimation of the age and 

span of time in years when such oil was lost. 

OTHER POTENTIAL RESOURCES 

Heavy oil and natural bitumen are rich in organometallic complexes as well as sulfur. In the United States 

in 1987, 58 percent of sulfur production was derived from 

petroleum operations, 30 percent from Frasch native 

sulfur plants, and only 12 percent as byproduct of metals 

plants. World vanadium production exclusive of the 

United States, where data are proprietary, was 34,000 

short tons in 1987 from slags, concentrates, and ores. 

Production from petroleum refineries from residues, 

ashes, and spent catalysts amounted to 925 tons in Japan 

and 2,504 tons in the United States, mainly from refineries processing imported Venezuelan heavy crudes, 

which are very high in metals. Vanadium is also recovered from petroleum residues in the Federal Republic of 

Germany and other European countries, and USSR 

(U.S. Bureau of Mines, 1989). Gribkov {1989) has made 

the point that the nonhydrocarbons may make some 

bitumen deposits economic and may, in some deposits, 

be of greater value than the bitumen. In a current study, 

C.A. Palmer (written communcation), based on analyses 

of 27 samples from 10 natural bitumen and heavy oil 

deposits, reports identifying 38 trace metals plus sulfur. 

The sulfur is most common, with a maximum determination of 69,000 parts per million .. Metals with high 

determined values include iron, potassium, sodium, vanadium, strontium, nickel, barium, and zinc. 

CONCLUSION 

Research on heavy oil and bitumen may expand 

avenues of interest to many petroleum disciplines. The 

geochemist may gain increased knowledge of the evolution of petroleum hydrocarbons, particularly the role of 

natural catalysts. The geologist may improve methods for 

the assessment of resource levels and attain characterization of the oils and reservoir rocks to assist in enhanced recovery. The chemist may achieve detailed 

analysis of the hydrocarbon's chemical composition to 

aid in planning for transportation and refining. And the 

commodity specialist may study the petroleum's nonhydrocarbon components to seek potential new sources of 

valuable commodities. 

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2-15. 

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crude and tar sands: New York, McGraw-Hill, p. 

477-488. 

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7,no.2,p. 151-162. 

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crude and tar sands, 4th, 1988, Edmonton, proceedings: 

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Meyer, R.F., Fulton, PA., and Dietzman, W.D., 1984, A 

preliminary estimate of world heavy crude oil and bituHeavy 011 and Natu1'81 Bitumen 87 
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232p. 

88 The Petroleum Syatem-Statua of Re-rch and Methoda, 1990 
Natural Gas 

By Keith A. Kvenvolden 1 

The principal hydrocarbon component in natural 

gas is methane, and a common diluent of this methane is 

nitrogen. These two components of natural gas are the 

focus of this discussion, the purpose of which is (1) to 

describe briefly the current thinking about their origins, 

(2) to redefine terms associated with the origin of methane, and (3) to suggest possible implications with regard 

to exploration strategies. 

It is now widely recognized that methane in natural 

gas has multiple origins (Schoell, 1988}. Most methane in 

natural gas has the same ultimate source, namely biologically formed organic matter. The reason that methane is 

said to have multiple origins is that a variety of processes 

act on this organic matter at varying levels of intensity. 

Methane is predominantly a product of the conversion of organic matter by both biochemical (microbial) 

and thermochemical reactions taking place in different 

temperature regions. Methane that is ultimately derived 

from organic matter should be termed biogenic as opposed to abiogenic methane, which forms by chemical 

processes that do not involve organic matter. This definition of biogenic methane is different from that which 

has been commonly used, for example, by Schoen (1980, 

1983) and Rice and Claypool (1981). In the past, the 

term biogenic described methane formed by microbial 

processes; in the future, this gas should be referred to as 

microbial (bacterial) methane (Jenden and Kaplan, 

1986; Coleman and others, 1988). That methane which 

results from the thermochemical conversion of organic 

matter is a kind of biogenic gas that should continue to be 

called thermogenic methane, and methane produced by 

this process forms about 80 percent of the commercial 

deposits of natural gas; the remaining 20 percent of 

commercial deposits contain microbial gas (Rice and 

Claypool, 1981 ). 

The various processes which lead to the formation 

of methane can often be differentiated by means of 

carbon and hydrogen isotopic compositions (fig. 5). For 

example, the formation of microbial methane follows two 

principal pathways: C02 reduction and fermentation 

(Jenden and Kaplan, 1986; Martens and others, 1986; 

Whiticar and others, 1986; Burke and others, 1988). 

Fermentation-derived methane is characterized by its 

depletion in the heavier isotope of hydrogen, that is, 

deuterium (fig. 5). The methanogenic pathways can 

1

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

operate simultaneously but are quantitatively important 

at different stages of sediment deposition. The pathways 

are generally independent of depositional environment 

but can be seasonally controlled. The fermentation processes are quantitatively more important in recently deposited sediments and swamps, whereas C02-reduction 

processes are more common in older sediments; microbial methane in commercial gas fields usually is the 

product of the C02-reduction pathway. Temperature, 

organic substrate, and age may be the major factors 

controlling the relative importance of the two pathways 

(Schoen, 1988). 

Thermogenic methane is found in a wide variety of 

geologic settings and sedimentary basins, and it has a 

wide range of isotopic compositions (fig. 5), with oilassociated methane having generally more negative isotopic values and non-associated methane having more 

positive values. These isotopic compositions seem to be 

controlled by the geologic history of the basins and 

include such factors as the extent of conversion of organic 

matter and the timing of gas expulsion, migration, and 

trapping (Schoell, 1988). Isotopic compositions of thermogenic (oil-associated) methane partially overlap the 

isotopic compositions of microbial methane. Nevertheless, the isotopic compositions of methane provide an 

invaluable tool for differentiating among various processes involved in methane formation and occurrence. 

Abiogenic methane is thought to form by inorganic 

chemical processes. Methane emanating from midoceanridge hydrothermal systems is considered to be abiogenic 

and is characterized by heavy (more positive) carbon and 

hydrogen isotopic compositions (fig. 5). Abiogenic methane is a rather exotic form of methane (Schoell, 1988) 

and has not been shown to be commercially important. 

Nitrogen is one of many nonhydrocarbon components of natural gas, ranging from trace amounts to 

concentrations approaching 100 percent (U.S. Bureau of 

Mines, 1983). The possible sources of nitrogen include 

(1) thermal degradation of organic matter in sediments, 

(2) maturation of coal beds, (3) diffusion from igneous 

and metamorphic rocks, and (4) trapped air (Hunt, 

1979). The origin of nitrogen-rich natural gas is still 

puzzling. In a recent study of this kind of gas in the 

Sacramento basin of California, J en den and others 

(1988) concluded that the gas is derived from metasedimentary rocks of the Franciscan complex thrust beneath 

the Great Valley during late Mesozoic and early Cenozoic convergence. In reaching this conclusion, they point 

Natural Gas 69 
out two factors of importance to natural gas exploration. 

First, the use of nitrogen isotopic compositions, at least in 

the Sacramento basin, is not very diagnostic and does not 

permit a satisfactory distinction between sedimentary, 

low-grade metasedimentary, and igneous sources. Second, hydrocarbon-rich and nitrogen-rich gases in this 

basin are genetically unrelated; thus the occurrence of 

nitrogen should not necessarily be used to predict the 

presence of nearby hydrocarbon accumulations, as was 

previously recommended (Getz, 1977). 

In summary, this discussion has demonstrated the 

utility of carbon and hydrogen isotopes of methane to 

help decipher the processes that produced the methane. 

This information c~ be useful in developing strategies 

for further exploration. In contrast, the nitrogen isotopic 

composition of nitrogen in natural gas does not appear to 

be particularly diagnostic, and the origin of nitrogen-rich 

natural gas is generally not well understood. 

REFERENCES CITED 

Burke, R.A., Jr., Martens, C.S., and Sackett, W.M., 1988, 

Seasonal variation of D/H and 13C/12C ratios of biogenic 

methane in surface sediments of Cape Lookout Bight, 

U.S.A.: Nature, v. 332, p. 829-831. 

Coleman, D.O., Liu, C-L., and Riley, K.M., 1988, Microbial 

methane in the shallow Paleozoic sediments and glacial 

drift deposits of Illinois, U.S.A.: Chemical Geology, v. 

71, p. 23-40. 

Getz, F.A., 1977, Molecular nitrogen: Clue in coal-derivedmethane hunt: Oil and Gas Journal, 25 April, p. 

220--221. 

Hunt, J .M., 1979, Petroleum geochemistry and geology: San 

Francisco, W.H. Freeman, 617 p. 

Jenden, P.O., and Kaplan, I.R., 1986, Comparison of microbial 

gases from the Middle America Trench and Scripps 

Submarine Canyon: Implications for the origin of natural 

gas: Applied Geochemistry, v. 1, p. 631-646. 

0 ~--------~-----------r----------,-----------.----------.----------1 

0 

-100 I 0 

0 

z 

<( 

(J) 

:::> 

0 (Nonassociated) I 

~ MICROBIAL -200 

cc (Reduction) 

w 

a.. 

(J) 

~ 

cc 

<( 

a.. 

z -300 

":.:t 

I 

u MICROBIAL 

0 EXPLANATION (Fermentation) c-o 

II Abiogenic 

-400 D Biogenic 

0 Extreme isotopic 

composition 

0 

-500 

-120 -100 -80 -60 -40 -20 0 

D13CcH

4

, IN PARTS PER THOUSAND 

Figure 5. Carbon and hydrogen (deuterium) isotopic compositions in naturally occurring methane (modified from Schoell, 

1988). 

70 The Petroleum System-Status of Research and Methods, 1990 
Jenden, P.D., Kaplan, I.R., Poreda, RJ., and Craig, H., 1988, 

Origin of nitrogen-rich natural gases in the California 

Great Valley: Evidence from helium, carbon and nitrogen isotope ratios: Geochimica et Cosmochimica Acta, v. 

52, p. 851--861. 

Martens, C.S., Blair, N.E., Green, C.D., and Des Marais, DJ., 

1986, Seasonal variations in the stable carbon isotopic 

signature of biogenic methane in a coastal sediment: 

Science, v. 233, p. 1300-1303. 

Rice, D.D., and Claypool, G.B., 1981, Generation, accumulation and resource potential of biogenic gas: American 

Association of Petroleum Geologists Bulletin, v. 65, p. 

5-25. 

Schoen, M., 1980, The hydrogen and carbon isotopic composition of methane from natural gases of various origins: 

Geochimica et Cosmochimica Acta, v. 44, p. 649-661. 

---1983, Genetic characterizations of natural gases: American Association of Petroleum Geologists Bulletin, v. 67, 

p. 2225-2238. 

---1988, Multiple origins of methane in the earth: Chemical Geology, v. 71, p. 1-10. 

U.S. Bureau of Mines, 1983, Analyses of natural gases, 

1917-1982 (magnetic tape): National Technical Information Service, Accession No. PB 83-210286. 

Whiticar, MJ., Faber, E., and Schoell, M., 1986, Biogenic 

methane formation in marine and freshwater environments: C02 reduction vs. acetate fermentation-Isotope 

evidence: Geochimica et Cosmochimica Acta, v. 50, p. 

693-709. 

Natural Gaa 71 
Natural Gas Hydrates 

By Timothy S. Collett and Keith A. Kvenvolden 1 

Gas hydrates are crystalline substances composed 

of water and gas in which a solid-water lattice accommodates gas molecules in a cagelike structure. In gas 

hydrates, water crystallizes in the cubic crystallographic 

system, forming structure I or II geometries depending 

on the composition of the gas; structure I gas hydrate is 

more commonly expected in nature (Davidson and others, 1978). Molecules of gases such as methane and 

ethane are small enough to be included in the water 

lattice of a structure I gas hydrate. At standard conditions 

(STP), one volume of structure I methane hydrate may 

contain as much as 164 volumes of methane gas (Davidson and others, 1978); because of this large volumetric 

conversion gas hydrates may represent an important 

source of natural gas. 

Gas hydrates occur in sedimentary deposits under 

conditions of pressure and temperature that are present 

in permafrost regions and beneath the sea in outer 

continental margins (reviewed by Kvenvolden and McMenamin, 1980). Geologic, geochemical, and geophysical evidence of gas hydrates in both the marine and 

permafrost environments include (1) high concentrations 

of methane in sedimentary deposits, (2) gas released 

from cores in the amounts expected for decomposing gas 

hydrate, (3) seismic anomalies that can be explained by 

the properties of sediments containing hydrates, and ( 4) 

geophysical well-log responses indicative of hydratebearing sediments. 

The presence of gas hydrates in offshore continental margins has been inferred mainly from anomalous 

seismic reflectors that coincide with the predicted transition boundary at the base of the gas-hydrate stability 

zone. This reflector is commonly called a bottomsimulating reflector or BSR. BSR's have been mapped at 

depths below the sea floor ranging from about 100 to 

about 1,100 m (Kvenvolden and McMenamin, 1980). 

The trapped free gas associated with BSR's represents a 

drilling hazard, and as such they have never been knowingly drilled; thus, BSR's are not proven to be caused by 

hydrates. However, gas hydrate samples recovered from 

wells drilled near BSR's indirectly confirm that BSR's are 

the consequence of gas hydrates. Gas hydrates have been 

recovered within 65 m of the sea floor in sediment of the 

Black Sea (Yefremova and Zhizhchenko, 1975) and the 

Gulf of Mexico (Brooks and others, 1986). Also, gas 

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

hydrates have been recovered at greater subbottom 

depths during research drilling and coring off the southeastern U.S.A. (Kvenvolden and Barnard, 1983), Mexico 

(Shipley and Didyk, 1982), Guatemala (Harrison and 

Curiale, 1982; Kvenvolden and MacDonald, 1985), and 

Peru (Kvenvolden and Kastner, 1989). 

Cold surface temperatures at high latitudes are 

conducive to the development of onshore permafrost and 

gas hydrate in the subsurface. Gas hydrates are known to 

be present in the western Siberian platform (Makogon 

and others, 1972) and are believed to occur in other 

permafrost areas of northern USSR, including the 

Timan-Pechora province, the eastern Siberian craton, 

and the northeastern Siberian and Kamchatka areas 

(Cherskiy and others, 1985). Permafrost-associated gas 

hydrates are also present in the North American Arctic. 

Well-log responses, attributed to the presence of gas 

hydrates, have been obtained in about a fifth of the wells 

drilled in the Mackenzie Delta, and in the Arctic Islands 

over half of the wells are inferred to contain gas hydrates 

(Judge, 1988). On the North Slope of Alaska gas hydrates have been identified in 34 petroleum industry 

wells using geophysical well-log responses calibrated to 

the response of an interval in one well where gas hydrates 

were recovered in a core by AR CO and Exxon (Collett 

and others, 1988). Most of the North Slope gas hydrates 

occur in a series of laterally continuous Upper Cretaceous and lower Tertiary sandstone and conglomerate 

rock units, all geographically restricted to the area overlying the eastern part of the Kuparuk River oil field and 

the western part of the Prudhoe Bay oil field. Preliminary 

resource calculations suggest that the volume of gas 

within these hydrates is approximately 8 to 10 trillion 

cubic feet. Geochemical analyses of well samples from 

the Prudhoe Bay-Kuparuk River area suggest that the 

gas hydrates consist of a mixture of microbial and thermogenic gas. It is postulated that the thermogenic gas 

migrated from deeper reservoirs along the same faults 

thought to be migration pathways for the large volumes 

· of heavy oil that occur at shallow depths in this area. The 

combined information from Arctic gas-hydrate studies 

shows that in permafrost regions, gas hydrates may exist 

at subsurface depths ranging from about 130 to about 

2,000 m. Gas hydrates may also be associated with 

permafrost in Antarctica, but few data are available 

(Hitchon, 1974; MacDonald, 1983); land-temperature 

profiles suggest that gas hydrates could exist to depths as 

great as 2,000 m. 

72 The Petroleum System-Status of Research and Methods, 1990 
Because large quantities of gas hydrates are widespread in permafrost regions and in offshore marine 

sediments, they may be a potential energy resource. 

Estimates of the amount of gas in hydrates of oceanic and 

continental settings range from 1.2X 1cf to 2.7X 108 

trillion cubic feet (adapted from Potential Gas Committee, 1981). With such a large resource potential, numerous recovery schemes have been suggested. As reviewed 

by Yousif and others (1988), the three most practical 

schemes for the production of gas from hydrates are (1) 

thermal stimulation, in which an external heat source is 

used to dissociate the hydrates, (2) depressurization, in 

which the production of associated free gas lowers reservoir pressures to cause decomposition of the hydrates, 

and (3) the use of gas hydrate inhibitors, in which a 

substance such as methanol is used to disequilibrate the 

hydrate. The Soviets have used the depressurization 

scheme to demonstrate that hydrates are an immediate, 

producible source of natural gas; their Messoyakha gas 

field in the West Siberian basin produced about 70 billion 

cubic feet of gas from hydrates over an eight-year period 

(Y.F. Makogon, Ministry of Gas Industry, Moscow, 

written communication). 

Recent drilling and geologic sampling on the North 

Slope of Alaska have revealed the presence of a gas 

hydrate/free gas contact at the predicted base of the 

methane-hydrate stability zone, and a similar contact has 

been noted at the Russian Messoyakha hydrate gas 

accumulation. Future work on the North Slope will focus 

on the relation between the gas hydrate and associated 

free-gas accumulations. An assessment will be made of 

the production characteristics and economic potential of 

both the hydrates and related free-gas occurrences. 

REFERENCES CITED 

Brooks, J .M., Cox, H.B., Bryant, W.R., Kennicutt, M.C., Mann, 

R.G., and McDonald, T.J., 1986, Association of gas 

hydrates and oil seepage in the Gulf of Mexico, in 

Advances in organic geochemistry 1985: Organic Geochemistry, v. 10, p. 221-234. 

Cherskiy, N.V., Tsarev, V.P., and Nikitin, S.P., 1985, Investigation and prediction of conditions of accumulation of gas 

resources in gas-hydrate pools: Petroleum Geology, v. 

21, p. 65-89. 

Collett, T.S., Bird, KJ., Kvenvolden, K.A., and Magoon, L.B., 

1988, Geologic interrelations relative to gas hydrates 

within the North Slope of Alaska: U.S. Geological 

Survey Open-File Report 88-389, 150 p. 

Davidson, D.W., El-Defrawy, M.K., Fuglem, M.O., and Judge, 

A.S., 1978, Natural gas hydrates in northern Canada: 

Proceedings of the 3d International Conference on Permafrost, National Research Council of Canada, v. 1, p. 

938-943. 

Harrison, W .E., and Curiale, J .A., 1982, Gas hydrates in 

sediments of Holes 497 and 498A, Deep Sea Drilling 

Project Leg 67, in Aubouin, J ., von Huene, R., and 

others, eds., Initial Report of the Deep Sea Drilling 

Project, v. 67: Washington, D.C., U.S. Government 

Printing Office, p. 591-594. 

Hitchon, B., 1974, Occurrence of natural gas hydrates in 

sedimentary basins, in Kaplan, I.R., ed., Natural gases in 

marine sediments: New York, Plenum, p. 195-225. 

Judge, A.S., 1988, Mapping the distribution and properties of 

natural gas hydrates in Canada: Proceedings of the 

American Chemical Society Third Chemical Congress of 

the North American Continent, June ~7, Toronto, 

Abstract 29. 

Kvenvolden, KA., and Barnard, L.A., 1983, Gas hydrates of 

the Blake Outer Ridge, Site 533, Deep Sea Drilling 

Project Leg 76, in Sheridan, R.E., Gradstein, F., and 

others, eds., Initial Reports of the Deep Sea Drilling 

Project, v. 76: Washington, D.C., U.S. Government 

Printing Office, p. 353-365. 

Kvenvolden, K.A., and Kastner, M., 1989, Gas hydrates of the 

Peruvian continental margin, in Suess, E., von Huene, 

R., Emeis, K.C., and others, eds., Initial Reports of the 

Ocean Drilling Program, v. 112 (Part B): Washington, 

D.C., U.S. Government Printing Office, p. (in press). 

Kvenvolden, K.A., and MacDonald, T.J., 1985, Gas hydrates of 

the Middle America Trench, Deep Sea Drilling Project 

Leg 84, in von Huene, R., Aubouin, J ., and others, eds., 

Initial Reports of the Deep Sea Drilling Project, v. 84: 

Washington, D.C., U.S. Government Printing Office, p. 

667-682. 

Kvenvolden, K.A., and McMenamin, M.A., 1980, Hydrates of 

natural gas: A review of their geologic occurrences: U.S. 

Geological Survey Circular 825, 11 p. 

MacDonald, G J ., 1983, The many origins of natural gas: 

Journal of Petroleum Geology, v. 5, p. 341-362. 

Makogon, Y.F., Trebin, FA., Trofimuk, A.A., Tsarev, V.P., and 

Cherskiy, N.V., 1972, Detection of a pool of natural gas 

in a solid (hydrate gas) state: Doklady Academy of 

Sciences U.S.S.R., Earth Science Section, v. 196, p. 

197-200. 

Potential Gas Committee, 1981, Potential supply of natural gas 

in the United States (as ofDecember31, 1980): Golden, 

Potential Gas Agency, Colorado School of Mines, 119 p. 

Shipley, T.H., and Didyk, B.M., 1982, Occurrence of methane 

hydrates offshore southern Mexico, in Watkins, J.S., 

Moore, J.C., and others, eds., Initial Reports of the Deep 

Sea Drilling Project, v. 66: Washington, D.C., U.S. 

Government Printing Office, p. 547-555. 

Yefremova, A.G., and Zhizhchenko, B.P., 1975, Occurrence of 

crystal hydrates of gas in sediments of modem marine 

basins: Doklady Academy of Sciences U.S.S.R., Earth 

Science Section, v. 214, p. 219-220. 

Yousif, M.H., Abass, H.H., Selim, M.S., and Sloan, E.D., 1988, 

Experimental and theoretical investigation of methane 

gas hydrate dissociation in porous media: Proceedings of 

the 63d Annual Technical Conference and Exhibition of 

the Society of Petroleum Engineers, October 2-5, Houston, Texas, p. 571-583. 

Natural Gas Hydrates 73 
Quantitative Petroleum Resource Assessment Methodologies 

By Robert A. Crovelli1 

INTRODUCTION 

The geologic appraisal model that is selected for 

doing a petroleum resource assessment depends upon 

the purpose of the assessment, the basic geologic assumptions of the area, the type of available data, the time 

to deadlines, the human and financial resources, the 

available computer facilities, and, most important, the 

existing quantitative methodology with corresponding 

computer software and any new quantitative methodology that would have to be developed. Therefore, different 

resource assessment projects usually require different 

geologic models. Also, more than one geologic model 

might be needed in a single project for assessing different 

regions of the study area or for crosschecking the resource estimates of the study area. Some geologic analyses used in the past for petroleum resource appraisal 

involved play analysis. The corresponding quantitative 

methodologies of these analyses usually consisted of 

Monte Carlo simulation techniques. 

The U.S. Geological SuiVey's petroleum resource 

appraisal studies have resulted in a wide variety of 

analyses, geologic models, quantitative methods, and 

computer programs. The type of analysis refers to the 

basic geologic assessment unit; for example, province, 

basin, or play. The geologic model consists of the geologic assumptions and mathematical description of the 

assessment approach; for example, resetVoir engineering, 

volumetric yield, field size, or direct assessment. The 

quantitative method is the type of probabilistic methodology that is mathematically derived from the geologic 

model; for example, Monte Carlo simulation or analytic 

probability theory. The computer software is written on 

the basis of the probabilistic methodology. 

PAST METHODOLOGIES 

Some past petroleum resource appraisal studies by 

the U.S. Geological SuiVey are as follows. 

1. The United States study (Miller and others, 

1975) assessed the petroleum provinces in the United 

States using a direct-assessment model, a volumetricyield submodel, and a Monte Carlo method for estimates 

1

U.S. Geological Survey, Denver, Colo. 

of aggregations with the computer program called MIT: 

Massachusetts Institute of Technology. 

2. The National Petroleum ReseiVe in Alaska 

(NPRA) study (U.S. Department of the Interior, 1979; 

White, 1981) assessed geologic plays in the North Slope 

of Alaska using a resetVoir-engineering model and a 

Monte Carlo method with the computer program RASP: 

Resource Appraisal Simulation for Petroleum. 

3. The Arctic National Wildlife Refuge (ANWR), 

which was formerly called the William 0. Douglas Arctic 

Wildlife Range (Mast and others, 1980), was assessed in 

a similar manner as the NPRA study. 

4. The United States study (Dolton and others, 

1981; Crovelli, 1981, 1984a) was conducted in a similar 

manner as the 1975 United States assessment; however, 

an analytic probabilistic methodology was developed for 

individual province estimates and resulted in the computer package NASP: National Appraisal System for 

Petroleum. 

5. The Devonian shale study (Charpentier and 

others, 1982) was an assessment of unconventional 

natural-gas resources in the Devonian shale of the Appalachian basin; play analysis was applied using a 

resetVoir- engineering model and a Monte Carlo method 

with the computer program MRASP, a modified version 

of RASP. 

6. The world oil study (Masters and others, 1983; 

Crovelli, 1984b, 1985a) assessed the oil basins in the 

world using basically the same approach as the 1981 

United States assessment; however, an analytic probabilistic methodology was also developed for aggregating the 

basin estimates and resulted in the computer package 

WASP: World Appraisal System for Petroleum. 

7. The Wilderness Lands in the Western United 

States study (Crovelli, 1983, 1984c, 1985b, 1986; Crovelli 

and Balay, 1984) assessed geologic clusters using a 

direct-assessment model, a richness-factor submodel, 

and an analytic probabilistic methodology for individual 

, cluster estimates and aggregations with the computer 

package WLASP: Wilderness Lands Appraisal System 

for Petroleum. 

8. The world oil and gas study (Masters and others, 

1987) assessed the oil and gas basins in the world using 

basically the same approach as the 1983 world assessment; however, a completely analytic probabilistic methodology was developed and resulted in the revised 

computer package RWASP: Revised World Appraisal 

System for Petroleum. 

74 The Petroleum System-Status of Research and Methods, 1990 
PRESENT METHODOLOGIES 

During recent years, the U.S. Geological Survey 

has made major strides to design and develop petroleum 

resource appraisal studies involving play analysis and 

analytic probabilistic methodology with a variety of geologic models. Play analysis is a general approach using 

various geologic models and probabilistic methods for 

analyzing a geologic play. In applying play analysis, a 

petroleum assessment area is first partitioned into geologic plays, and then the individual plays are analyzed. 

The individual play estimates of oil and gas are aggregated, respectively, in order to estimate the petroleum 

potential of the entire assessment area. 

A probabilistic system of petroleum resource appraisal for play analysis has been designed to meet the 

following requirements: (1) includes a variety of geologic 

models, (2) uses an analytic methodology instead of 

Monte Carlo simulation, (3) possesses the capacity to 

aggregate estimates from many areas that have been 

assessed by different geologic models, and ( 4) runs 

quickly on a microcomputer. The geologic models for 

play analysis consist of four basic types: reservoir engineering, volumetric yield, field size, and direct assessment. The order in which the models are listed reflects 

the decreasing amount of geologic information that is 

required in the model. 

The reservoir-engineering model is the most dataintensive model and was used in the three recent petroleum resource appraisal studies by the USGS given 

below. These three assessments are followed by studies 

using less data-intensive models. 

1987 Arctic National Wildlife Refuge 

Assessment 

The Arctic National Wildlife Refuge (ANWR) 

study (Crovelli and Balay, 1986; Crovelli, 1987a, 1987b, 

1988; Dolton and others, 1987) assessed in-place oil and 

gas resources of geologic plays in the North Slope of 

Alaska using a reservoir-engineering model. The model 

is similar to the reservoir-engineering model in the 1980 

ANWR assessment except that some of the parameter 

values in the reservoir-engineering equations were 

changed. 

An analytic probabilistic methodology using probability theory was developed for play analysis in the 1987 

ANWR study based upon the reservoir-engineering 

model. A computer software package consisting of six 

computer programs was created and called Fast Appraisal System for Petroleum, Reservoir Engineering 

(FASPRE). Some of the details of the analytic method 

and the computer package F ASPRE were presented by 

Crovelli and Balay (1986). 

Hungary Assessment 

The Hungary assessment of the Bekes basin involved generalizing the reservoir-engineering model and 

the aggregation model that were used in the 1987 ANWR 

study (Crovelli and Balay, in press). The modifications 

included the requirements that the system produce output in metric units and run on an IBM-PC-XT compatible computer. A user's manual was also written that 

includ~d guides for installation and operation of the 

system. 

The purpose of modifying the existing reservoirengineering model was to make the geologic model 

universal and, therefore, applicable anywhere in the 

world. This was necessary since the model in the 1987 

ANWR study was site-specific, being only applicable in 

the North Slope of Alaska. 

The analytic probabilistic methodology was derived , 

from the methodology for the 1987 ANWR study by 

replacing the site-specific reservoir-engineering equations with a new general system of equations and parameters. Therefore, through extensive modification of the 

F AS PRE package, the universal metric version of the 

play analysis computer software package was built and 

called F ASPUM. The FASPUM software is available to 

the general public through the Open-File services of the 

USGS (Crovelli and Balay, 1987). 

Tight Gas Sands Assessment 

The Tight Gas Sands study (Johnson and others, 

1987) is an assessment of low-permeability gas resources 

of the Upper Cretaceous Mesaverde Group in the 

Piceance basin of western Colorado. The resource appraisal system used in this study was derived from the 

generalized system of the universal metric study and the 

1987 ANWR study. Modifications were made that included conversion to U.S. Customary units. The computer software package F ASPUE is essentially the U.S. 

version of the metric version F ASPUM. Therefore, 

FASPUE is a universal U.S.-units, play-analysis system 

using a reservoir-engineering model and an analytic 

probabilistic methodology. The FASPUE software is 

available to the general public (Crovelli and Balay, 1988, 

1989). 

The ANWR study was designed to assess conventional oil and gas accumulations which are treated as a 

set of prospects in a play area. However, the Tight Gas 

Sands study is an assessment of unconventional lowpermeability gas reservoirs. Therefore, an entire play 

area is treated as a single gas accumulation. The hydrocarbon reservoir parameters are also assigned accordingly. The mathematical formulation of the geologic model 

is appropriate for conventional and unconventional petroleum resources. The different applications require 

different physical interpretations of the geologic model. 

Quantitative Petroleum Resource Assessment Methodologies 75 
Federal Offshore Assessments 

The Minerals Management Service (MMS), an 

agency of the U.S. Department of the Interior, made a 

systematic assessment of the undiscovered economically 

recoverable oil and gas resources for Federal offshore 

areas (Cooke, 1985). The MMS study of Federal offshore areas applied a prospect analysis using a 

volumetric-yield model and a Monte Carlo method with 

the computer program PRESTO. 

The Bureau of Land Management (BLM), an 

agency of the U.S. Department of the Interior, made the 

assessment of the undiscovered economically recoverable oil and gas resources for the 1987 ANWR study. 

The BLM assessment utilized the PRESTO program. 

The USGS was responsible for making the in-place 

assessment, while the BLM was responsible for the 

recoverable assessment in the 1987 ANWR study. 

The volumetric-yield model is not as data-intensive 

as the reservoir-engineering model; that is, not as many 

hydrocarbon-volume attributes are involved. Some of the 

hydrocarbon-volume attributes in the reservoir engineering equations are combined into a single factor, called the 

oil yield factor in the oil volume equation and the gas 

yield factor in the gas volume equation. Estimates of oil 

and gas yield factors as distributions indicate the amount 

of hydrocarbons expected per volume of reservoir rock 

(acre-foot). 

National Assessment 

The USGS recently completed its first petroleum 

resource appraisal of the entire United States using play 

analysis (Mast and others, 1989). The major geologic 

model in the play analysis is the field-size model. A 

probability model incorporating the field-size distributions of oil and gas was designed with a risk structure that 

is quite different from FASPRE and FASPUE. 

An analytic probabilistic methodology was developed for play analysis in the United States study based 

upon the field-size model and the new risk structure. A 

computer software package consisting of 11 computer 

programs was written and called Fast Appraisal System 

for Petroleum, Field Size (F ASPF). 

The field-size model is based upon an assessment 

of the size of the fields in the play and not the individual 

geologic hydrocarbon-volume attributes. The volumes of 

oil and gas accumulations are modeled as statistical 

distributions in the form of histograms or probability 

distributions. Field-size distributions are used two ways: 

(1) the distnbution is of known fields from an explored 

area, and the distribution is used to estimate the resources of the remaining fields in that area, and (2) the 

distribution is used as an analog in goologically similar 

unexplored areas (Houghton, 1988). 

A summary of the past and present petroleum 

resource appraisal studies by the USGS discussed in this 

paper is presented in table 5. 

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Table 5. Summary of some past and present petroleum resource assessments by the US. Geological Survey 

Assessment Year Anal~sis Model Method Software 

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NPRA1 1979 Play Reservoir engineering Monte Carlo RASP 

ANWR2 1980 Play Reservoir engineering Monte Carlo RASP 

United States 1981 Province Direct assessment (volumetric yield) Monte Carlo & Analytic NASP 

Devonian Shale3 1982 Play Reservoir engineering Monte Carlo MRASP 

World 1983 Basin Direct assessment (volumetric yield) Monte Carlo & Analytic WASP 

Wilderness Lands 1983 Cluster Direct assessment (richness factor) Analytic WLASP 

World 1987 Basin Direct assessment (volumetric yield) Analytic RWASP 

ANWR 1987 Play Reservoir engineering Analytic FASPRE 

Hungary 1987 Play Reservoir engineering Analytic FASPUM 

Tight gas sands 1987 Play Reservoir engineering Analytic FASPUE 

United States 1988 Pla~ 

1

National Petroleum Reserve in Alaska. 2

Arctic National Wildlife Refuge in Alaska. 3Devonian Shale of Appalachian basin. 

Field size 

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---1988, Hydrocarbon distnbution in the CretaceousTertiary Sagavanirktok Formation, North Slope, Alaska, 

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Forum on Mineral and Energy Resources: U.S. Geological Survey Circular 1025, p. 9-10. 

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1988, Geologic interrelations relative to gas hydrates 

within the North Slope of Alaska: U.S. Geological 

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--1988, U.S. Geological Survey assessment methodology 

for estimation of undiscovered petroleum resources in 

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Quantitative analysis of mineral and energy resources: 

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---1988, Multi-model approach to petroleum resource 

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Crovelli, R.A., and Balay, R.H., 1988, A microcomputer program for oil and gas resource assessment: COGS Computer Contributions, v. 4, no. 3, p. 108-122. 

---1988, A microcomputer application in oil and gas resource appraisal, in Peters, D.C., and Krajewski, S.A., 

eds., GeoTech '88 geocomputing tools-PC's workstations, and more: Colorado Section, American Institute of 

Professional Geologists, p. 31-36. 

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Assessment methodology for estimation of undiscovered 

petroleum resources in play analysis of the United States 

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1784, 45 p., 2 pl. 

---1988, Heavy oils, in National energy resource issuesGeologic perspective and the role of geologic information: U.S. Geological Survey Bulletin 1850, p. 54. 

---1988, Tar sands, in National energy resource issuesGeologic perspective and the role of geologic information: U.S. Geological Survey Bulletin 1850, p. 55. 

Cunningham, K.l., and Roberts, A.A., 1988, Helium and C1-C3 

hydrocarbon concentrations in permafrost ice, Marsh 

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U.S. Geological Survey Open-File Report 88-1, 35 p. 

Dean, W.E., Bostick, N.H., Bartel, A.J., Brandt, E.L., Daws, 

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and Chou, 1-Ming, 1988, Data on the geochemistry and 

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Geological Survey Open-File Report 88-271, 22 p. 

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Geological Survey Open-File Report 88-289, 8 p. 

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exploration of the National Petroleum Reserve in Alaska, 1974 to 1982: U.S. Geological Survey Professional 

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Dyman, T.S., Krystinik, K.B., and Takahashi, K.l., 1988, Quantitative petrographic analysis of mid-Cretaceous sandstones, southwest Montana: U.S. Geological Survey 

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Dyman, T.S., and Nichols, D.J., 1988, Stratigraphy of midCretaceous Blackleaf and lower part of Frontier Formations in parts of Beaverhead and Madison Counties, 

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Dyman, T.S., Perry, W.J., Jr., and Nichols, D.J., 1988, Stratigraphy, petrology, and provenance of the Albian Blackleaf 

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---1988, Stratigraphic cross section V-V' showing electric 

logs of Upper Cretaceous and older rocks, Powder River 

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---1988, Core porosity, permeability, and vitrinite reflec-

·tance data from the Lower Cretaceous J Sandstone in 

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foreland uplift and its influence on structure of the 

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---1988, The petroleum system-A classification scheme 

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---1988, The petroleum system-A classification scheme 

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---1988, Applying aromatic steroids to determination of 

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---1988, Thermal maturation of the eastern Anadarko 

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---1988, Overview-Carbonate reservoir facies, Wyoming 

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---1988, Phanerozoic stratigraphy of the northern Rocky 

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