Petroleum Systems 

of the United States 

U.S. GEOLOGICAL SURVEY BULLETIN 1870 

.S .Su 

. ~g 
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Petroleum Systems 

of the United States 

LESLIE B. MAGOON, Editor 

U.S. GEOLOGICAL SURVEY BULLETIN 1870 
DEPARTMENT OF THE INTERIOR 

DONALD PAUL HODEL, Secretary 

U.S. GEOLOGICAL SURVEY 

Dallas L. Peck, Director 

Any use of trade names and trademarks 

in this publication is for descriptive 

purposes only and does not constitute 

endorsement by the U.S. Geological Survey 

UNITED STATES GOVERNMENT PRINTING OFFICE, WASHINGTON : 1988 

For sale by the 

Books and Open-File Reports Section 

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library of Congress Cataloging-in-Publication Data 

Petroleum systems of the United States. 

(U.S. Geological Survey bulletin ; 1870) 

Includes bibliographies. 

Supt. of Docs. no.: I 19.3:1870 

1. Petroleum-Geology-United States. 2. PetroleumUnited States-Reserves. I. Magoon, Leslie B. II. Series. 

QE75.89 no. 1870 . 557.3 s 88-600313 

[TN872.A5] [553 .2182] 
CONTENTS 

Abstract 

Leslie B. Magoon 1 j 

The petroleum system-A classification scheme for esearch, exploration, and resource assessment 2 

Leslie B. Magoon 

Role of amount and type of organic matter in recoJition of petroleum source rocks 16 

Jerry L. Clayton 

I 

I 

Characteristics of carbonate source rocks of petroleuin 20 

James G. Palacas I 

I 

Geothermics of petroleum systems: Implications ofjhe stabilization of kerogen thermal 

maturation after a geologically brief heating dura ion at peak temperature 26 

Charles E. Barker 

Thermal maturity 30 1 

I

I 

Primary and secondary hydrocarbon migration 33 

J. David King and Mark J. Pawlewicz 

Charles W. Spencer 

Structure 36 

William J. Perry, Jr. 

Types of seals as related to migration and entrapme t of hydrocarbons 39 

Gregory F. Ulmishek I 

Sand stone reservoirs 41 

Christopher J. Schenk 

Natural gas 44 

Keith A. K venvolden 

Natural gas hydrate 46 

Timothy S. Collett and Keith A. Kvenvolden 

Tight gas reseiVoirs 48 

Ben E. Law and Charles W. Spencer 

Natural gas in fractured shale-The Appalachian Deronian black shale gas system 50 

John B. Roen 

Coal-bed methane 52 

Ben E. Law 

III 
Classification and composition of crude oil 54 

Jerry L. Clayton 

Heavy oil and natural bitumen 57 

Richard F. Meyer 

Geochemical correlations in petroleum systems 60 

Donald E. Anders 

Computer applications 65 

Kenneth I. Takahashi, Thaddeus S. Dyman, and Leslie B. Magoon 

FIGURES 

1. Cross section showing essential elements of petroleum system 4 

2. Map showing extent of petroleum system 6 

3. Geologic cross section showing elements of the Beluga-Sterling(.) petroleum system 7 

4. Geologic cross section showing elements of the Torok-Nanushuk(.) petroleum system 8 

5. Geologic cross section showing elements of the Ellesmerian(!) petroleum system 8 

6. Geologic cross section showing elements of the Tuxedni-Hemlock(.) petroleum system 9 

7. Van Krevelen diagram showing three evolution paths for kerogen 18 

8. Biomarker distributions that show the origin of gilsonite and tar sand oil 63 

TABLES 

1. Summary of models that incorporate geologic process to explain the distribution of petroleum 

in nature 3 

2. Definitions for level of certainty 6 

3. Classification scheme for the petroleum system 7 

4. One petroleum system in each class and the number of similar systems identified in the United 

States 7 

5. Formal meetings that were required to implement the petroleum system classification scheme 11 

6. Petroleum systems within the United States 12 

7. Recent publications in English referring to carbonate and carbonate-evaporite rocks as potential 

source beds of petroleum 20 

8. Characteristics of low- to medium-maturity oils derived from carbonate versus shale source rocks 22 

9. Typical composition of a 35° API gravity crude oil 54 

10. Classification of oils according to scheme of Tissot and Welte (1984) 55 

11. The most commonly used correlation parameters and their general application in 

gas-oil-source studies 61 

12. Some commonly used correlation parameters to show the origin of gilsonite and tar sand oil 64 

13. Computer systems specifications and software, Branch of Petroleum Geology 67 

14. File structure for an 80-column card-image format for the petroleum system data base 68 

IV 
PETROLEUM SYSTEMS 

Abstract 

Leslie B. Magoon, Editor 

I 

~F I 

I 

This publication in 18 individually authore~l summaries by U.S. Geological Survey scientists (1 

explains and classifies the petroleum system, (2) present 

a preliminary listing of petroleum systems within th 

United States, and. (3) describes current research on th9 

essential elements of these systems. J 

The petroleum system is proposed as a unique 

approach to research, exploration, and resourc~ assessment. A petroleum system includes all thos~ 

elements that are essential for an oil and gas deposit tq 

exist in nature. The basic elements include a petroleum! 

source rock, migration path, reservoir rock, seal, anl 

trap. All elements must be placed correctly in time an 

space for a petroleum system to occur. A petroleum 

deposit includes high concentrations of any of the 

following substances: thermal and microbial natural gas] 

condensate, oil, and solid bitumen. The. description of ~I petroleum system includes its stratigraphic limits 

geographic extent, and geologic timespan. The system i 

named using the stratigraphic nomenclature for th 

source rock and the most important reservoir rock; thes~ 

two names are then separated by a hyphen. Th~ 

confidence that a particular source · rock generate 

hydrocarbons that are trapped in a certain reservoir i 

expressed in the level of certainty: known (!) 

Manuscript approved for publication, July 29, 1988. 

THE UNITED STATES 

hypothetical (.), or speculative (?). The symbol for the 

level of certainty is placed at the end of the petroleum 

system name, for example, Phosphoria-Weber(!), a 

known system. Petroleum systems can be classified by 

using criteria such as source and reservoir rock type and 

complexity of its geologic history. 

A list of most of the petroleum systems within 

the United States was developed by USGS geologists 

who are specialists in the petroleum geology for different 

parts of the United States. In a series of meetings, these 

specialists identified and named the petroleum systems in 

their respective areas and provided other information on 

source and reservoir type, so that the systems could be 

classified. The results from this exercise are included in 

the petroleum system chapter as a table. 

Most chapters in this bulletin are devoted to 

current research on the essential elements of the 

petroleum system. Topics included are siliciclastic and 

carbonate source rocks, geothermal gradient, thermal 

maturity. hydrocarbon migration, seals, structure, 

reservoirs, computer file structure, and the different types 

of petroleum deposits. Each author defines the essential 

element, discusses the current research for that element, 

and provides supporting references. 

Abstract 1 
The Petroleum System-A Classification Scheme 

for Research, Exploration, and Resource Assessment 

By Leslie B. Magoon 

INTRODUCTION 

Geologists are continually looking for new ways 

to organize information or data into arrays to be 

interpreted in innovative ways to answer a specific 

question. One of the oldest ways, but still a very useful 

one, is to organize information into a geologic map. 

Over the last four decades, many new maps have been 

invented by petroleum geologists that relate to the 

reservoir rocks, structure, stratigraphy, and source rocks. 

With the advent of the computer, a plethora of ways to 

organize geologic information is available; in fact, 

finding the proper way to organize is sometimes a 

problem. As more geological, geophysical, and 

geochemical information about petroleum occurrence 

accrues, there is a need to organize and categorize our 

ideas into conceptual models based on geologic 

processes. These models must then be classified so that 

comparative studies can be carried out. 

Various papers have added significantly to our 

understanding of petroleum occurrence, some of which 

are identified in table 1. The papers included on this 

table were chosen because the subject is closest to the 

petroleum system. Papers relating to basin studies 

(Zieglar and Spotts, 1978; Welte and Yukler, 1984; 

Klemme, 1986) and play or prospect analysis (Sluijk and 

Nederlof, 1984; Bird, 1986) were purposely left out 

because of emphasis. The petroleum system emphasizes 

the genetic relation between a particular source rock and 

the resulting petroleum accumulation; basin studies 

emphasize structural depressions and the included 

sedimentary rocks regardless of the relation to any 

petroleum deposits; and the play or prospect approach 

emphasizes whether the present -day trap is detectable 

with available technology or tools. 

Seven items are identified on table 1 that can be 

divided into two broad categories: geologic parameters 

and evaluation criteria. On this table, all papers 

discussed at least one geologic parameter in considerable 

detail or at least acknowledged their importance. For 

example, all papers acknowledged the importance of 

migration but did not discuss this process in detail. The 

evaluation criteria were discussed in only three papers. 

The naming nomenclature using stratigraphic units was 

used in Dow (1974) and discussed in detail by Magoon 

(1987); the level of certainty in one paper (Magoon, 

1987); and the classification schemes in two papers (Bois 

2 Petroleum Systems of the United States 

and others, 1982; Magoon, 1987). This table is by no 

means exhaustive, but is shown to put the petroleum 

system into historical perspective. 

Remember that the petroleum system implies a 

genetic relation between the source rock and a series of 

accumulations, but it is not proof of the relation. The 

level of confidence in this genetic relation is indicated 

with the level of certainty, and can be improved using 

various geological, geophysical, and geochemical 

techniques. In addition, when defining a system, scale is 

as important to the petroleum system as it is to the 

geologic map. A small-scale geologic map includes 

more regional or general information on a large area 

when compared to a large-scale map that includes more 

detailed information on a small area. Similarity, any one 

petroleum system identified on a regional scale, such as 

in this study, may on closer examination be subdivided 

into smaller systems. The purpose of this paper is to 

define a petroleum system, to name the system, to 

determine its level of certainty, and then to classify the 

system. 

PETROLEUM SYSTEM 

A petroleum system includes all those geologic 

elements and processes that are essential for an oil and 

gas deposit to exist in nature. These basic 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 suspected to occur. 

CHARACTERISTICS AND LIMITS 

The stratigraphic, areal, and temporal extent of 

the petroleum system is specific. Stratigraphically, the 

system is limited to the following rock units: a petroleum 

source rock, rocks through which migration has occurred, 

reservoir rock (trap), and rock overburden required for 

maturity (fig. 1). The areal extent of the petroleum 

system is defined by a line that circumscribes the mature 
I 

Table 1. Summary of models that incorporate geologictocess to explain the distribution of petroleum in nature 

[Origin, includes richness, type, and thennal maturity of petroleum source rock; migration, includes the movement of oil, gas, or any other 

hydrocarbon through the country rock; accumulation, includes the pres ce of a reservoir rock, seal, trap, and a high concentration of hydrocarbons; 

timing, traps fonned before the hydrocarbons migrated;++, discussed · detail;+, discussed in general tenns; -,did not discuss] 

Geolo ic arameters Evaluation criteria 

Reference Descriptive phrase Origin Migra- Accumu- Tim- Nomen- Level of Classification 

tion lation in clature certain scheme 

Dow (1974) Oil system ++ + ++ + + 

Bois (1975) Petroleum-zone + + ++ 

White (1980) Facies-cycle wedges + + ++ + 

Bois and others (1982) Petroleum-zone ++ + ++ + + 

Demaison (1984) Generative basin ++ + + + 

Meissner and others (1984) Hydrocarbon machines ++ + + + 

Ulmishek (1986) Independent petroliferous system ++ + ++ + 

Ma oon (1987) Petroleum s stem + + + + ++ ++ ++ 

source rock and all oil and gas deposits, convention at three levels of certainty: known, hypothetical, and 

and unconventional, originating from that source (fig. 2). speculative (table 2). In a known petroleum system, in 

On the cross section (fig. 1), there are tw the case of oil, a good geochemical match must exist 

sedimentary basins, three plays, and one petroleu between the source rock and oil accumulations; or, in the 

system. The literature includes numerous ways t case of natural gas, the gas is produced from a gas 

classify or identify a sedimentary basin, but in simpl source rock. In a hypothetical petroleum system, 

terms it is a depression into which sediments ar geochemical information is sufficient to identify a source 

deposited and is usually expressed as a lenticular body o rock, but no geochemical match exists between source 

prism of sedimentary rock. As expressed from th and petroleum deposits. In a speculative petroleum 

interface between the sedimentary rock and basemen system, the existence of source rocks and petroleum 

complex, there are two lenticular bodies of sedimen accumulations is postulated entirely on the basis of 

rock or two basins on the cross section. Knowledge o geologic or geophysical evidence. At the end of the 

the detailed stratigraphy within these two basins migh system's name, the level of certainty is indicated by (!) 

reveal even more sedimentary basins. Hence, b for known, (.) for hypothetical, and (?) for speculative. 

studying a sedimentary basin, a geologist may or rna I propose that the petroleum system designation include 

not study the elements essential to petroleu the name of the source rock followed by the name of the 

accumulations. The three plays shown on the eros major reservoir rock and a symbol expressing the level 

section are (1) a series of suspected traps along of certainty. For example, the Torok-Nanushuk(.) is a 

anticlinal trend, (2) a series of suspected traps along hypothetical system on the North Slope of Alaska 

stratigraphic pinch-out trend, and (3) any suspected tra comprising the Cretaceous Torok Formation source rock 

within a stratigraphic interval. A prospect is a drillabl and Nanushuk Group sandstone as the major reservoir 

trap within a play. This play definition is much narrowe (Magoon and Claypool, 1985). 

than that of Dolton and others (1987) and is felt to b After a petroleum system is identified and 

more relevant to industry's approach to exploration named and its level of certainty established, it must be 

Hence, the definition of a play need not include all th classified (table 3). An identified petroleum system is 

essential elements of a petroleum system. classified into one of 12 categories, based on the type of 

A petroleum system represents sufficien source rock (I, II, or III), composition of reservoir rock 

geologic time to assemble all of the basic elements, fro (siliciclastic or carbonate), and whether the system is 

the source rock to the last unit, required to for purebred or hybrid. A purebred petroleum system was 

petroleum deposits. A petroleum deposit includes higj deposited in a geologic setting in which the structural 

concentrations of any of the following substances framework did not change significantly during the 

thermal and microbial natural gas found in conventiona geologic life of the system; in contrast, a hybrid system 

reservoirs as well as in gas hydrates, tight sands includes a major structural reorientation, without which a 

fractured shales, and coal beds; condensates, crude oils petroleum system would not have formed. The 

heavy oils and solid bitumen reservoired in siliciclasti1 composition of the reservoir refers to the lithology, either 

and carbonate rocks. 1 siliciclastic or carbonate, of the largest petroleum 

A petroleum system can be identified in termi deposit. The organic matter type, either I, II, or III, is 

of geochemical correlation of petroleum and source rockj distinguished on the basis of the hydrogen and oxygen 

A Classificatir Scheme for Research, Exploration, and Resource Assessment 3 
indices of the kerogen when plotted on the van Krevelen 

diagram (Tissot and Welte, 1984). The organic matter 

type that produced the petroleum reservoired in the 

largest petroleum deposit is used to classify the system. 

The largest petroleum deposit refers to a single pool that 

contains the most inplace hydrocarbons or a series of 

pools that cumulatively contain the most inplace 

hydrocarbons in the system at the time of discovery. 

By classifying petroleum systems, groupings of 

similar systems may be revealed, and these groups may 

serve as analogs for research, exploration, or resource 

assessment (table 4). For example, the most common 

type of system has a purebred geologic setting, 

siliciclastic reservoirs, and type II kerogen, and the 

Monterey(!) petroleum system is one example of 26 

other systems. There were no petroleum systems 

identified in a hybrid geologic setting, carbonate 

reservoirs, and type I or type III kerogens. To date, the 

total number of petroleum systems identified and 

classified in the 48 conterminous states and Alaska is 

119. If important information about each system is 

collected and categorized, many comparisons and 

contrasts become apparent and can then be subject for 

further investigation. To explain further the petroleum 

system, four examples from Alaska follow. Two of the 

examples are classified as purebred, and two are hybrid. 

EXAMPLES OF PETROLEUM SYSTEMS 

Beluga-Sterling(.) 

In Cook Inlet, Alaska, a significant amount of 

dry gas is reservoired and produced from Tertiary rocks 

deposited in a forearc basin (Magoon and Egbert, 1986; 

fig. 3). At least two stratigraphic units are involved, the 

Beluga and Sterling Formations, and this geologic setting 

is classified as a purebred system. Most of the gas is in 

the Sterling Formation and is reservoired in a mediumgrained, well to fairly well sorted, and slightly 

conglomeratic sandstone (Crick, 1971; Boss and others, 

1976; Hayes and others, 1976). The source for the gas is 

unclear, but the Beluga and Sterling Formations have 

considerable coal and type III kerogen (Claypool and 

others, 1980). The coal and type III kerogen is below or 

associated with the Sterling Formation, so this source is 

in a good position to charge overlying reservoirs with 

microbial gas (Claypool and others, 1980). Because the 

source of the microbial gas cannot be directly tied to the 

Beluga Formation, the level of certainty for the BelugaSterling(.) petroleum system is hypothetical, and the 

system is classified as purebred with siliciclastic 

reservoirs and type III kerogen source rocks. 

Torok-Nanushuk(.) 

On the North Slope of Alaska significant 

quantities of petroleum are associated with the Nanushuk 

Group (fig. 4). Oil and gas accumulations are located in 

anticlines and in combination traps (Collins and 

Robinson, 1967; Bird, 1985). The geologic setting, a 

foreland basin, has remained the same during deposition 

of all the essential elements, and thus the petroleum 

system is classified as a purebred system. The reservoir 

rock is feldspar- and lithic-rich sandstone derived from 

the Brooks Range orogen (Ahlbrandt, 1979; Molenaar, 

1983; Molenaar and others, 1987; Huffman, 1985). The 

source rocks for the hydrocarbons are most likely in the 

lower part of the Torok Formation, containing a type III 

14----------- PETROLEUM SYSTEM---------~ 

/ 

--- - Thrust belt-Arrows indicate direction 

of relative movement 

Figure 1. Hypothetical geologic cross section (see fig. 2 for location) of a basin showing the essential elements of a 

petroleum system. The expanded explanation is appropriate for figures 1-6. 

4 Petroleum Systems of the United States 
kerogen, and possibly the underlying pebble shale unit, 

containing a type III/II kerogen (Magoon and Claypool, 

1985). There is considerable geochemical data available 

on both the oils and source rocks, but a convmcmg 

geochemical correlation has not been demonstrated 

(Magoon and Bird, 1985; Claypool and Magoon, 1985). 

The level of certainty for the Torok-Nanushuk(.) 

petroleum system is hypothetical, and the system is 

classified as a purebred with siliciclastic reservoirs and 

type III kerogen source rocks (table 4). 

PETROLEUM SYSTEM EXPLANATION 

Source rock 

0 Type I kerogen 

<:g> Type II kerogen 

<@> Type Ill kerogen 

Reservoir rock 

® Siliciclastic 

© Carbonate 

Seal rock 

L[J Shale 

0 Anhydrite 

@ Gypsum 

Lithology 

0 Shale 

D Siliciclastic 

~ Carbonate mudstone 

~ Carbonate 

Stages of organic metamorohism 

Diagenesis 

Catagenesis 

Metagenesis 

Figure 1. Continued. 

Petroleum accumulation 

.a All types 

lliJ Natural bitumens, asphaltites, and 

asphaltic pyrobitumens 

[I] Oil, extra heavy gravity (<10° API) 

[8] Oil, heavy gravity (10° < 20° API) 

@] Oil, medium gravity (20° < 45° API) 

[QJ Condensate (>45° API) 

@] Thermal gas 

@] Microbial methane gas 

[]] Gas originating from coal beds 

ITJ Gas reservoired in low-porosity and 

permeable rock 

~ Natural gas hydrate 

Migration 

- Indicates direction petroleum migrated 

Petroleum products Definition 

Microbial gas 

••••••••••••• Onset of catagenesis 

Oil/condensate 

0000000000000 Onset of metagenesis 

Thermal gas 

A Classification Scheme for Research, Exploration, and Resource Assessment 5 
Ellesmerian( !) 

On the North Slope of Alaska, the largest oil 

field in North America, Prudhoe Bay, is one of several 

fields reservoired in the Ellesmerian sequence (fig. 5). 

The oil accumulations are reservoired mostly in 

siliciclastic rocks that range in age from Late Devonian 

through Tertiary and also in Carboniferous age 

carbonates (Bird, 1981; Bird and Magoon, 1987; Alaska 

Oil and Gas Conservation Commission, 1985). 

Two different depositional settings separated by 

continental rifting were required to complete this 

petroleum system, thus making it a hybrid system. The 

first setting, the Arctic platform, includes rocks, 

deposited on a broad shelf, that range in age from Late 

Devonian through Early Cretaceous, contains siliciclastic 

and carbonate rocks, and is designated the Ellesmerian 

sequence (Lerand, 1973; Bird, 1981). The Ellesmerian 

system includes three source rocks with mostly type II 

Table 2. Definitions for level of certainty 

Level of certainty Criteria Symbol 

Known Oil/source-rock correlation, (!) 

or gas reservoired in documented 

gas source-rock 

Hypothetical No oil/source-rock correlation, (.) 

or gas reservoired near postulated 

source rock 

Speculative Geological and geophysical evidence (?) 

BASINWARD EXTENT 

OF RESERVOIR ROCK 

\/ 

I 

n • •• ,;----- •./ 

• I •, 

I ', 

I •, 

• I • • l : 

I : 

' I ,• I ,.___ • ___ _ 

PfTROLt.\J~ 

u ..... ~ 

l 

ZERO EDGE 

OF 

RESERVOIR 

ROCK 

EXPLANATION 

Line of cross section 

(\ (\ 

Thrust belt-Sawteeth on upper plate 

Fault-Hachures on downthrown block 

Plunging anticline 

Plunging syncline-Dashed where approximately 

located 

Figure 2. Plan map of the hypothetical basin in figure 1 showing the areal extent of the petroleum system. The 

boundary circumscribes all petroleum deposits and the mature pod of source rock that generated the hydrocarbons in 

those deposits. See figure 1 for explanation. 

6 Petroleum Systems of the United States 
Table 3. Classification scheme for the petroleum system 

Geologic setting 

Reservoir rock 

Source rock type I 

Petroleum system classification scheme 

Purebred 

Siliciclastic Carbonate 

IT Ill I II III I 

Hybrid 

Siliciclastic Carbonate 

II ITI I IT Ill 

Table 4. One petroleum system in each class and the number of similar systems identified in the United States 

Petroleum system classification scheme 

Geologic 

setting (number) 

Purebred (85) 

Hybrid (34) 

(f) 2 w 

_j 

2 

West 

Reservoir 

rock type (number) 

Siliclastic (56) 

Carbonate (29) 

Siliciclastic (27) 

Carbonate (7) 

~ 3 [ _______ _ 

I 

f8J 4 

o Hemlock 

5 

6 

Source Nomenclature 

rock type Source-reservoir (certainty) 

I Green River-Wasatch(.) 

II Monterey(!) 

Ill Torok-Nanushuk(.) 

I Utica-Trenton(!) 

II Smackover(!) 

III Chattanooga-Fort Payne(.) 

I Sheep Pass-Garrett Ranch(.) 

II Ellesmerian(!) 

Ill Tuxedni-Hemlock(.) 

I None 

II Winnipeg-Red River(.) 

Ill None 

Kenai 

EXPLANATION 

Fault, normal-Arrows indicate d1rection 

of relat1ve movemP.nt 

Unconformity 

East 

Number of 

systems 

7 

26 

23 

8 

14 

7 

1 

12 

14 

0 

7 

0 

Total 119 

8 

9 

Figure 3. Geologic cross section showing the Beluga-Sterling(.), a purebred petroleum system, in Cook Inlet, Alaska. 

Section, modified from Boss and others (1976), trends northwest-southeast just north of the Kenai gas field. See figure 

1 for explanation. 

A Classification Scheme for Research, Exploration, and Resource Assessment 7 
0 

l ') 

UJ 

:=! 

2 

~ 

::[ 

1-

Q... 

w 

0 

2 

West East 

@] @] 

Barrow Simpson Shoreline 

r-~~~------------------------------------------------------------~~-------------,Sea 

~~--.::r-__,~ 

Sagavanirktok Formation 

EXPLANATION 

D Shale, deltaic foresets C Simpson Paleocanyon 

D Siliciclastic rock Unconformity 

CZJ Nearshore facies transition 

le ve I 

2 

3 

U) 

a: 

w 

1-

w 

2 

0 

_J 

~ 

z 

I 

1--

Q... 

w 

0 

Figure 4. Geologic cross section showing the Torok-Nanushuk(.), a purebred petroleum system on the North Slope of 

Alaska at end of Cretaceous time. Reservoir rock above the Barrow gas field is a sandstone lens within the pebble 

shale unit that contained oil (Magoon and Claypool, 1985). Section modified from Bird (1985). See figure 1 for 

explanation. 

U) 

w 

_J 

2 

~ 

I 

1-

0 

:t 2 0 

3 

West 

@] 

Barrow 

Shublik Formation and 

Sag River Sandstone 

EXPLANATION 

[I] 

Dalton 

C2J Nearshore fac1es trans1t1on 

Unconformity 

[E] 

Fish 

Creek 

[ill @] @] 

Kuparuk Prudhoe 

West Sak 

Sadlerochit Group 

Lisburne Group 

East 

@] 

Bay 

Lisburne 

65 Ma 

Sea 

I eve I 

U) 

a: 

w 

1-

w 

2 

2 g 

~ 

z 

3 ~ 

4 

Q... 

w 

0 

Figure 5. Geologic cross section showing the Ellesmerian(!), a hybrid petroleum system on the North Slope of Alaska 

at end of Cretaceous time. Section modified from Bird (1985). See figure 1 for explanation. 

8 Petroleum Systems of the United States 
organic matter: the Shublik Formation, Kingak Shale, 

and to a lesser extent the pebble shale unit (Magoon and 

Bird, 1985); and three siliciclastic reservoir rocks: the 

Endicott Group, Sadlerochit Group (Ivishak Formation), 

and Kuparuk Formation; and a carbonate reservoir, the 

Lisburne Group (Bird, 1981, 1985). The second setting, 

a foreland basin, includes rocks deposited by a 

prograding deltaic deposit that ranges in age from late 

Early Cretaceous to Holocene and whose primary role in 

terms of the petroleum system is to provide the 

overburden necessary to mature the organic matter of the 

Ellesmerian source rocks. These rock units, derived 

from the Brooks Range orogen, are designated the 

Brookian sequence (Lerand, 1973). 

This petroleum system is named the Ellesmerian 

system because the petroleum accumulations originated 

from at least three source rocks and occurs in four 

different reservoir rocks; to avoid the cumbersome use of 

all these stratigraphic units in the name, the single name 

Ellesmerian is used. The level of certainty is known for 

the Ellesmerian(!) because an oil-to-source rock 

correlation has been demonstrated (Seifert and others, 

1980; Sedivy and others, 1987). Because two distinctly 

different depositional sequences are required to form oil 

in this system, the Ellesmerian(!) is classified as a hybrid 

petroleum system with siliciclastic reservoirs and type II 

kerogens (table 4). Even though the Lisburne Group is 

an important carbonate reservoir, the Ivishak and 

Kuparuk Formations, siliciclastic reservoirs, are 

volumetrically the more important reservoirs. The 

pebble shale unit contains type II/III kerogen, but the 

West 

two most important oil source rocks, the Shublik 

Formation and Kingak Shale, contain mostly type II 

kerogen. 

Tuxedni-Hemlock(.) 

In the Cook Inlet, Alaska, several large oil fields 

occur in reservoirs of Tertiary age (fig. 6). 

Approximately 80 percent of the oil is reservoired in the 

Hemlock Conglomerate, a conglomeratic sandstone of 

Oligocene age (Wolfe, 1981). Two different depositional 

settings, separated by a major unconformity, were 

required to complete this petroleum system. The first 

setting, a marine environment, includes rocks deposited 

in a forearc basin associated with volcanic and plutonic 

rocks that range in age from Early Jurassic through Late 

Cretaceous, and includes both volcaniclastic and 

siliciclastic rocks. The Middle Jurassic Tuxedni Group, 

containing a type III kerogen, is considered the source 

rock for the oil. The second setting, a fluvial 

environment, includes siliciclastic rocks deposited in a 

narrow forearc basin trough. These Tertiary rocks 

include not only the reservoir rock but the overburden 

necessary to mature the Middle Jurassic source rock. 

The level of certainty for the Tuxedni-Hemlock(.) 

petroleum system is hypothetical because geochemical 

information on the oils and rocks have not demonstrated 

a correlation (Magoon and Claypool, 1981). This system 

is classified as a hybrid with siliciclastic reservoirs and 

type III kerogens. 

East 

Trading 

Bay 

McArthur Middle 

[J) 

ll.! 

~ 

~ 3 

I 

f--

~ 4 0 

6 

EXPLANATION 

River Ground Shoal 

Lower Jurassic r 0 Cfrs 

~ Fault-Arrows indicate direction of relat1ve 

movement 

Unconformity 

2 [J) 

a: 

w --------'::f 3 ~ 

~~~~----~---, 

::2: 

4 5 

::.::: 

5 ~ 

I 

6 5:: 

8 

9 

w 

0 

Figure 6. Geologic cross section showing the Tuxedni-Hemlock(.), a hybrid petroleum system in Cook Inlet, Alaska. 

Section, modified from Boss and others (1976), trends northwest-southeast through the largest oil fields. See figure 1 

for explanation. 

A Classification Scheme for Research, Exploration, and Resource Assessment 9 
SUMMARY 

U.S. Geological Survey geologists recently 

identified, named, and classified the petroleum systems in 

the United States during four formal meetings (table 5) 

and several informal meetings with certain individuals 

from October 1987 to early February 1988. The results 

of this initial effort are summarized in tables 4 and 6. 

There are 119 petroleum systems, of which 85 

are purebred and 34 are hybrid systems. The most 

common system is the hybrid, siliciclastic, type II 

systems, of which there are 26; there are no hybrid, 

carbonate with either a type I or type III source. 

Siliciclastic reservoirs (83) occur more than twice as 

often as carbonate (36) reservoirs. The most common 

source rock is type II (59), followed by type III (44), 

with the least common type I (16). In actual practice, 

the name for each petroleum shown on table 6 was 

coined from either stratigraphic or time-stratigraphic 

nomenclature. When more than one name was needed to 

designate either the source or the reservoir rock, the 

names were separated with a slash. The predominant 

petroleum type, either oil or gas, is designated unless the 

geologist felt that both types were equally important; if 

one type precedes another, it is felt to be slightly more 

important. The geographic distribution for each 

petroleum system is shown as the States covered; if the 

system is restricted to a basin or area in a large State, the 

general location is designated. 

By classifying the Nation's petroleum systems 

using the criteria outlined above, the various elements of 

each system may be scrutinized and compared to 

determine the mechanism and capacity to generate, 

migrate, and trap hydrocarbons. Plans call for research 

projects on selected petroleum systems; the 

Ellesmerian(!) petroleum system on the North Slope of 

Alaska will be among the first studied. 

REFERENCES CITED 

Ahlbrandt, T.S., ed., 1979, Preliminary geologic, 

petrologic, and paleontologic results of the study 

of Nanushuk Group rocks, North Slope, Alaska: 

U.S. Geological Survey Circular 794, 163 p. 

Alaska Oil and Gas Conservation Commission, 1985, 

1984 Statistical Report: Anchorage, Alaska Oil 

and Gas Conservation Commission, 187 p. 

Bird, K.J., 1981, Petroleum exploration of the North 

Slope, Alaska, in Mason, J .F., ed., Petroleum 

geology in China-Principal lectures presented 

to the United Nations: Tulsa, Penn Well 

Publishing, p. 233-248. 

-- 1985, The framework geology of the North Slope 

of Alaska as related to oil-source rock 

correlations, in Magoon, L.B. and Claypool, 

G.E., eds., Alaska North Slope oil/rock 

10 Petroleum Systems of the United States 

correlation study: American Association of 

Petroleum Geologists Studies in Geology 20, p. 

3-29. 

1986, A comparison of the play analysis 

technique as applied in hydrocarbon resource 

assessments of the National Petroleum Reserve 

in Alaska and the Arctic National Wildlife 

Refuge, in Rice, D.D., ed., Oil and gas 

assessment-Methods and applications: 

American Association of Petroleum Geologists 

Studies in Geology 21, p. 133-142. 

Bird, K.J., and Magoon, L.B., eds., 1987, Petroleum 

geology of the northern part of the Arctic 

National Wildlife Refuge, northeastern Alaska: 

U.S. Geological Survey Bulletin 1778, 324 p. 

Bois, C., 1975, Petroleum-zone concept and the 

similarity analysis contribution to resource 

appraisal, in Haun, J.D., ed., Methods of 

estimating the volume of undiscovered oil and 

gas resources: American Association of 

Petroleum Geologists Studies in Geology 1, p. 

87-89. 

Bois, C., Bouche, P., and Pelet, R., 1982, Global 

geologic history and distribution of hydrocarbon 

reserves: American Association of Petroleum 

Geologists Bulletin, v. 66, no. 9, p. 1248-1270. 

Boss, R.F., Lennon, R.B., and Wilson, B.W., 1976, 

Middle Ground Shoal oil field, Alaska, in 

Braunstein, Jules, ed., North Amercian oil and 

gas fields: American Association of Petroleum 

Geologists Memoir 24, p. 1-22. 

Claypool, G.E., and Magoon, L.B., 1985, Comparison of 

oil-source rock correlation data for Alaskan 

North Slope: Techniques, results, and 

conclusions, in Magoon, L.B. and Claypool, 

G.E., eds., Alaska North Slope oil/rock 

correlation study: American Association of 

Petroleum Geologists Special Studies in 

Geology 20, p. 49--81. 

Claypool, G.E., Threlkeld, C.N. and Magoon, L.B., 1980, 

Biogenic and thermogenic origins of natural gas 

in Cook Inlet basin, Alaska: American 

Association of Petroleum Geologists Bulletin, v. 

64, p. 1131-1139. 

Collins, F.R., and Robinson, R.M., 1967, Subsurface 

stratigraphic, structural, and economic geology, 

northern Alaska: U.S. Geological Survey OpenFile report, 171 p. 

Crick, R.W., 1971, Potential Petroleum Reserves, Cook 

Inlet, Alaska, in Cram, I.H., ed., Future 

petroleum provinces of the United States-Their 

geology and potential: American Association of 

Petroleum Geologists Memoir 15, v. 1, p. 

109-119. 

Demaison, G., 1984, The generative basin concept, in 

Demaison, G. and Murris, R.J., eds., Petroleum 
Table 5. Formal meetings that were required to implement the petroleum system classification scheme 

[*, chaired meetings] 

Meeting 

location 

Reston, Virginia 

Denver, Colorado 

Denver, Colorado 

Corpus Christi, Texas 

Denver, Colorado 

Menlo Park, California 

Menlo Park, California 

Date Time Geoscientist present 

mo/day/yr Name Position 

Province: Atlantic Coast; Arpalachians; Eastern Interior; Michigan 

10/30/87 8:30am-1:30pm Bayer, Kenneth C. 

Gautier, Donald L. 

Magoon, Leslie B.• 

Meyer, Richard F. 

Roen, John B. 

Ryder, Robert T. 

deWitt, Wallace 

Province: Rocky Mountains; Northern Great Plains; Colorado Plateau; Basin and Range 

11!2/87 8:30 am-2:00 pm Anders, Donald E. 

Butler, William C. 

Clayton, Jerry L. 

Dolton, Gordon L. 

Dyman, Thaddeus S. 

Grow, John A. 

Magoon, Leslie B." 

Perry, William J. Jr. 

Powers, Richard B. 

Rice, Dudley D. 

Spencer, Charles W. 

Province: Atlantic Coast; Gulf Coast; West Texas and eastern New Mexico 

1113/87 8:30 am-11:30 am Barker, Charles E. 

Province: Gulf Coast 

2/5/88 8:30 am-4:30 pm 

Province: Michigan; Mid-continent 

11/4/87 8:30am-3:00pm 

Province: Alaska 

11/10/87 1:00pm-3:30pm 

Province: Pacific Coast 

11/13/87 10:00 am-11:30 am 

Grow, John A. 

Magoon, Leslie B." 

Palacas, James G. 

Foote, Richard Q. 

Magoon, Leslie B." 

Massingill, Linda M. 

Wells, Ronnie H. 

Charpentier, Ronald R. 

Clayton, Jerry L. 

Dyman. Thaddeus S. 

Grow, John A. 

Hatch, Joseph R. 

Higley, Debra K. 

Law, Benjamin E. 

Magoon, Leslie B." 

Mast, Richard F. 

Schenk, Christopher J. 

Schmoker, James W. 

Taylor, David J. 

Ulmichek, Gregory f. 

Bader, Jeffrey W. 

Beyer, Larry A. 

Bird, Kenneth J. 

Collett, Timothy S. 

Gautier, Donald L. 

Magoon, Leslie B.• 

Bird, Kenneth J. 

Cook, Harry E. 

Isaacs, Caroline M. 

Magoon, Leslie B.* 

McLean, Hugh 

Stanley, Richard G. 

Wagner, Holly 

Geophysicist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

Chemist 

Geologist 

Geologist 

Geologist 

Geologist 

Geophysicist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

Geophysicist 

Geologist 

Geologist 

Geophysicist 

Geologist 

Geologist 

Geophysicist 

Geologist 

Geologist 

Geologist 

Geophysicist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

Geophysicist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

Geologist 

A Classification Scheme for Research, Exploration, and Resource Assessment 11 
Table 6. Petroleum systems within the United States 

[AK, Alaska; AL, Alabama; AR, Arkansas; AZ, Arizona; CA, California; CO, Colorado; Cf, Connecticut; FL, Florida; GA, Georgia; IA, Iowa; ID, 

Idaho; IL, Illinois; IN, Indiana; KS, Kansas; KY, Kentucky; LA, Louisiana; MA; Massachusetts; MI; Michigan; MN, Minnesota; MO, Missouri; MS, 

Mississippi; MT, Montana; NC, North Carolina; ND, North Dakota; NE, Nebraska; NJ, New Jersey; NM, New Mexico; NV, Nevada; NY, New 

York; OH, Ohio; OK, Oklahoma; OR, Oregon; PA, Pennsylvania; RI, Rhode Island; SD, South Dakota; TN, Tennessee; TX, Texas; UT, Utah; VA, 

Virginia; VT, Vermont; WA, Washington; WI, Wisconsin; WV, West Virginia; WY, Wyoming] 

Source-reservoir( certainty) 

PUREBRED, siliciclastic reservoir 

Cabot Head-Medina(.) 

Green River-Wasatch(.) 

Pennsylvanian cannel coals-sandstone(.) 

Austin Chalk/Eagleford-Woodbine(?) 

Glenwood-Rose Run(?) 

Neogene-Salt Lake(?) 

Rose Hill-Keefer(?) 

Heath-Tyler(!) 

Hue-Sagavanirktok/Canning(!) 

Monterey-Puente(!) 

Tyler(!) 

Conasauga-Rome(.) 

Michigan-Stray(.) 

Monterey-Repetto/Pico(.) 

Monterey-Sisquoc(.) 

Monterey-Stevens/Kern River(.) 

New Albany(.) 

Tuscaloosa(.) 

Woodford-Silurian/Devonian(.) 

Aneth/Elbert-McCracken(?) 

Curtis-Entrada/Morrison(?) 

Devonian-Berea(?) 

Eel River-Rio Dell(?) 

Kreyenhagen-Gatchell(?) 

Lower Cretaceous-Paluxy(?) 

Miocene(?) 

Monterey(?) 

Moreno(?) 

Nonesuch-Keweenawan(?) 

Triassic-Newark(?) 

Unkown-Eocene(?) 

Unknown-Eutaw/Selma(?) 

Unknown-San Miguel/Olmos(?) 

Cretaceous(!) 

Devonian Black Shales-Venango(!) 

Ohio Shale(!) 

Pennsylvanian coals(!) 

Pennsylvania-Late Paleozoic(!) 

Sunbury-Berea(!) 

Antrim(.) 

Beluga-Sterling(.) 

Cenozoic(.) 

Cretaceous(.) 

Forbes(.) 

Marcellus-Oriskany(.) 

12 Petroleum Systems of the United States 

Oil/gas 

Type I source 

Oil 

Oil 

Oil 

Oil 

Oil 

Oil 

Gas 

Type ll source 

Oil 

Oil 

Oil 

Oil 

Oil 

OiVgas 

Oil 

Oil 

Oil 

Gas 

Gas 

Oil 

Oil 

Oil 

Oil 

Gas 

Oil 

Oil/gas 

Oil 

Oil 

Oil 

Gas 

Oil 

Oil 

Oil 

Oil 

TyPe III source 

Gas 

Gas/oil 

Gas 

Gas 

Gas 

OiVgas 

Gas 

Gas 

Oil/gas 

Gas/oil 

Gas 

Gas 

State(s) 

VA,KY,WV,MD,OH,PA,NY 

UT 

TN,KY,VA,WV,OH 

TX,LA,MS 

PA,OH,VA,WV 

UT 

KY,WV,VA 

MT 

AK 

Los Angeles basin, CA 

ND 

TN,KY,WV,MD,PA 

MI 

Ventura basin, CA 

Santa Maria basin, CA 

San Joaquin basin, CA 

IN,IL,KY,TN,MO 

TX,LA,AL 

NM,TX 

AR,CO,NM,UT 

co 

MI 

CA 

San Joaquin, CA 

TX,LO,MS,AL,FL,AR,Offshore 

Offshore CA 

Point Arena, CA 

San Joaquin, CA 

WI,MN,IA,NE,MO,KS 

MA,CT,NY,NJ,PA 

TX 

TX,LA,AL,MS 

TX 

MT,ND,SD,WY,NE,CO,KS 

WV,PA,OH,NY 

AL,GA,TN,KY, V A,WV,MD,PA,NY,OH 

AL,GA,TN,KY, V A,WV,MD,OH,PA 

OK,KS,CO,AR,TX,MO 

KY,OH,WV,VA 

IN,MI 

AK 

TX,LA,MS,AL,FL 

Green River basin WY,CO 

CA 

VA,WV,MD,PA,NY,OH 
Table 6. Petroleum systems within the United States-Continued 

Source-reservoir( certainty) 

PUREBRED, siliciclastic reservoir 

Miocene(.) 

Mississippian coals-sandstones(.) 

Starkey-Winters(.) 

Stepovak-Bear Lake(.) 

Sunbury-Murrysville(.) 

Ohio-Big Injun(.) 

Chester(?) 

Cotton Valley(?) 

Hornbrook(?) 

Jurassic-Cretaceous(?) 

Ohio-Weir(?) 

PUREBRED, carbonate reservoir 

Austin Chalk(!) 

Simpson-Viola(!) 

Trenton(!) 

Utica-Trenton(!) 

Simpson-Viola/Hunton(.) 

Athens-Trenton/Knox(?) 

Glenwood-Trempealeau(?) 

Salina-Newburg(?) 

Smackover(!) 

S unniland(!) 

Dollar Bay(.) 

Pennsylvanian(.) 

Pennsylvanian(.) 

Permian(.) 

Permian(.) 

Salina-Niagaran(.) 

S impson-Ellenberger/Simpson(.) 

Woodford/Chattanooga-Paleozoic(.) 

Conasauga-Knox(?) 

Devonian-Detroit River/Traverse(?) 

EauClair-Knox(?) 

Ordovician-Prairie du Chien/Black River!frenton(?) 

Chattganooga-Fort Payne(.) 

Marcellus-Bass Islands(.) 

Marcellus-Onondaga(.) 

Monroe(?) 

Ohio/Chattanoo ga-Comiferous(?) 

Ohio/Sunbury-Greenbriar/Newman(?) 

Sligo(?) 

HYBRID, siliciclastic reservoir 

Sheep Pass-Garrett Ranch(.) 

Ellesmerian(!) 

Minnelusa(!) 

Phosphoria-Weber(!) 

Utica-Beekmantown(!) 

Oil/gas 

Type ID source-Continued 

Gas 

Gas 

Gas 

Gas 

Gas 

Gas/oil 

Gas 

Gas 

Gas 

Gas 

Gas 

Type I source 

Oil/gas 

Oil 

Oil 

Gas 

Oil 

Oil 

Gas 

Oil 

Type II source 

Oil 

Oil 

Oil 

Oil 

Oil 

Oil 

Oil 

Oil 

Gas/oil 

Oil 

Oil 

Oil 

Gas 

Oil 

Type Ill source 

Oil/gas 

Gas 

Gas 

Gas 

Oil/gas 

Gas 

Gas 

Type I source 

Oil 

Type ll source 

Oil 

Oil 

Oil 

Gas 

MS,AL,FL 

VA 

CA 

AK 

PA,WV,OH 

WV,PA,OH 

MS,AL 

State(s) 

TX,LA,MS,FL,AL,AR 

CA,NV 

Atlantic offshore 

OH,WV,VA,KY 

TX,LA,MS 

OK,MO,KS 

IN,KY,IL,MO 

VT,NY,PA,VA, WV,MD,OH,IN 

KS,MO,NE,IA 

TN,NC,VA,WV,KY 

OH 

WV,OH 

TX,LO,MS,AL,FL,AR,Offshore 

FL 

FL 

TX,NM 

Midland basin,TX 

TX,NM 

TX 

MI,IN,OH 

TX,NM 

OK,TX,AR,MO,KS,NE,CO 

MS,AL 

MI 

IL,IN,KY,MO 

WI,MN,IL,IN, OH 

KY,TN 

NY,PA 

NY,PA 

LA 

KY 

VA,KY,WV,OH,PA 

TX,LA,AL,MS 

NV 

AK 

WY,NE,SD,CO 

ID,WY,UT,MT,CO 

VT 

A Classification Scheme for Research, Exploration, and Resource Assessment 13 
Table 6. Petroleum systems within the United States-Continued 

HYBRID, siliciclastic resetvoir 

Type TI source-Continued 

Greenhorn-Dakota(.) 

Mancos-Mesaverde(.) 

Mancos-Tocito(.) 

Todilto-Entrada(.) 

Aspen/Bear River-Nugget/Madison(?) 

Chainman-White Rim(?) 

Domengine-Cierbo/Briones(?) 

Jurassic/Cretaceous(?) 

Oil 

Gas 

Oil 

Oil 

Oil 

Oil 

Oil/gas 

Oil 

NM,CO 

NM,CO 

NM,CO 

NM 

UT,WY 

UT 

CA 

MT,ID 

Type III source 

Cretacous-Tertiary(!) 

Lewis-Picture Cliffs(.) 

Mesaverde(.) 

Mesaverde(.) 

Torok-Nanushuk(.) 

Tuxedni-Hemlock(.) 

Cretaceous(?) 

Cretaceous(?) 

Cretaceous(?) 

Cretaceous(?) 

Cretaceous-Tertiary(?) 

Cretaceous(?) 

Cretaceous(?) 

Poul Creek-Katalla(?) 

HYBRID, carbonate resetvoir 

Gas 

Gas 

Gas 

Gas 

Oil 

Oil 

Oil/gas 

Oil 

Oil/gas 

Oil 

Gas 

Gas 

Gas 

Oil 

Wind River basin WY 

NM,CO 

Uinta basin UT,CO 

Piceance basin CO 

AK 

AK 

Big Hom basin WY,MT 

Wind River basin WY 

Denver basin CO,WY,NE 

Powder River basin WY,MT 

Bighorn basin WY 

Laramie basin WY 

North Park basin CO 

AK 

Type II source 

Bakken-Madison(!) 

Winnipeg-Red River(!) 

Bakken-Madison(.) 

Paradox-Hermosa(.) 

Chainman-Simonson(?) 

Conasauga-Knox(?) 

Favret(?) 

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Contrasts between braided and meandering 

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14 Petroleum Systems of the United States 

Oil 

Oil 

Oil 

Oil 

Oil 

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MT,SD,ND 

ND,MT,SD 

Sweetgrass arch MT 

NM,AR,UT,CO 

NV,UT 

V A,TN,NC,GA 

NV 

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Geologists Studies in Geology 21, p. 59-68. 

Welte, D.H., and Yukler, M.A., 1984, Petroleum origin 

and accumulation in basin evolution-A 

quantitative model, in Demaison, G., and 

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

basin evaluation: American Association of 

Petroleum Geologists Memoir 35, p. 27-39. 

White, D.A., 1980, Assessing oil and gas plays in 

facies-cycle wedges: American Association of 

Petroleum Geologists Bulletin, v. 64, no. 8, p. 

1158-1178. 

Wolfe, J .A., 1981, A chronologie framework for 

Cenozoic megafossil floras of northwestern 

North America and its relation to marine 

geochronology: Geological Society of America 

Special Paper 184, p. 39-42. 

Zieglar, D.L., and Spotts, J.H., 1978, Reservoir and 

source-bed history of Great Valley, California: 

American Association of Petroleum Geologists 

Bulletin, v. 62, no. 5, p. 813-826. 

A Classification Scheme for Research, Exploration, and Resource Assessment 15 
Role of Amount and Type of Organic Matter in 

Recognition of Petroleum Source Rocks 

By Jerry L. Clayton 

Source rocks are an essential element of any 

petroleum system. The purpose of this report is to 

summarize the current understanding of the roles of 

amount and type of organic matter in forming source 

rocks. Concepts of organic maturation are discussed 

elsewhere in this volume. 

Various definitions for petroleum source rock 

have been proposed (Dow, 1978; Hunt, 1979; Tissot and 

Welte, 1984; Brooks and others, 1987). In the most 

general sense, a source rock is any volume of rock that 

is capable of generating and expelling commercial 

quantities of oil or gas under proper conditions of 

heating over geologic time. Hunt (1979) emphasized the 

need to include "commercial" amounts of hydrocarbons 

in any source rock definition because nearly all 

sedimentary rocks can generate small quantities of 

hydrocarbons. Therefore, as noted by Brooks and others 

(1987), some ambiguity is inherent in defining a source 

rock because the criteria include economic 

considerations, not solely geological criteria. Further, the 

term "source rock" includes (1) rocks which have not 

generated hydrocarbons because they have not undergone 

sufficient heating over geologic time; (2) rocks which are 

actively generating and expelling hydrocarbons; and (3) 

rocks which already generated and expelled hydrocarbons 

during earlier heating and no longer contain residual 

capacity for further generation on a commercial scale. 

Source rocks of the first type are often referred to as 

"potential" source rocks. Rocks of the second and third 

type are called "effective" source rocks, and the term 

"spent" source rock (Dow, 1978) is sometimes used to 

describe the type of effective source rock in the third 

category. Recognition of source rocks requires 

characterization of the following criteria: (1) amount of 

organic matter, (2) type of organic matter, (3) maturity 

of organic matter, and (4) amount of hydrocarbons 

generated and expelled. 

The amount of organic matter is critical for 

recognition of a source rock, not only because a 

minimum total mass of organic matter must be present to 

generate commercial quantities of hydrocarbons, but also 

because a minimum threshold concentration of liquid or 

gaseous organic matter must be present before expulsion 

(primary migration) of the generated hydrocarbons can 

occur (Momper, 1978). Ronov (1958) studied a large 

number of shale samples from petroleum-producing and 

nonproducing regions and observed that the lower limit 

16 Petroleum Systems of the United States 

for organic carbon content is 0.5 percent (by weight) for 

shales adjacent to oil-producing fields of part of the 

Russian Platform. Gehman (1962) investigated carbonate 

rocks and arrived at an empirically determined minimum 

value of 0.3 percent for carbonate rocks to be considered 

as source rocks. Currently, most investigators consider 

0.5-1.0 percent as the minimum amount of organic 

carbon needed for a source rock. For "spent" source 

rocks, these criteria of minimum organic carbon contents 

are difficult to apply because much of the original 

organic carbon may have been lost during generation and 

expulsion of hydrocarbons, and the residual carbon 

remaining in the rock may represent only a fraction of 

the original carbon present. To a large extent, the mass 

balance approach to source rock evaluation, which is 

discussed later, avoids the issue of minimum requirement 

for organic carbon content, because actual amounts of 

hydrocarbons generated and expelled are calculated. 

The type of organic matter present in a source 

rock is important because different types of organic 

matter have different potentials for generating 

hydrocarbons and because the composition of 

hydrocarbons generated depends on organic matter type. 

Reservoir rock type usually refers to the depositional site 

of the rock material, such as nearshore marine; in 

contrast, source rock type frequently refers to the 

provenance of the material. For example, a terrestrial 

source rock, which contains abundant pollen and spores 

derived from land plants, may be deposited in a marine 

environment off the mouth of a delta. Source rocks are 

commonly categorized into marine and nonmarine types. 

The distinction between marine rock and marine organic 

matter is important to remember and often tends to be 

overlooked in discussions of source rock types. A true 

marine source rock only includes organic matter that 

originated in a marine environment. However, rocks 

younger than Ordovician usually contain a mixture of 

organic matter derived from marine and terrigenous 

organisms including bacterially reworked material. 

Nonmarine source rocks contain organic matter derived 

from terrigenous organisms (higher land plant) or 

freshwater algae and bacteria. Other environments, such 

as hypersaline lacustrine and nearshore brackish settings, 

are also important depositional sites for source rocks. 

Coals have also been thought to be source rocks for gas, 

and more recently have been shown to be possible 

sources of liquid hydrocarbons (Durand and Oudin, 1979; 
Durand and Paratte, 1983; Thompson and others, 1985). 

The main organisms contributing to organic 

matter in source rocks are higher plants, algae, 

zooplankton, and bacteria. The relative contribution 

from each of these organisms to a given source rock is 

important because the chemical composition, and 

therefore the ultimate hydrocarbon potential, varies 

among organic components derived from these groups of 

organisms. In general, higher plant tissue contains 

biomolecules with more oxygen (cellulose, 

hemicellulose) and relatively nonbiodegradable 

components such as lignin. These higher plant 

biomolecules have a relatively low HJC ratio and high 

0/C ratio. Lipids are a minor component of higher 

plants which reside in leaf cuticles, seeds, and fruits, for 

example. In contrast, algae and bacteria contain more 

hydrogen and less oxygen and have a higher lipid 

content than higher plants. Sedimentary organic matter 

derived from algae and bacteria has a higher H/C ratio 

and lower 0/C ratio than higher plant material and, 

therefore, greater relative capacity for generating liquid 

hydrocarbons during burial heating. 

Lipids, commonly referred to as bitumen in 

sedimentary rocks, are usually present in secondary 

amounts in source rocks. Kerogen constitutes most of 

the organic matter in such rocks. Kerogen is defined by 

most authors as the organic component of sedimentary 

rocks that is insoluble in aqueous alkaline and organic 

solvents. The process by which kerogen is formed from 

precursor biological materials is not well understood. 

Although some petroleum hydrocarbons and 

nonhydrocarbons are derived directly from lipids of 

living systems having undergone diagenetic alteration, 

most petroleum constituents are derived from thermal 

alteration of kerogen. Therefore, the type of organic 

matter contained in a source rock applies mainly to the 

kerogen composition. 

Kerogen type is classified using organic 

petrographic and organic geochemical methods. Organic 

geochemical methods, used widely, can quickly and 

easily characterize the bulk organic matter (kerogen) in a 

source rock on a routine basis. Most laboratories use a 

combination of petrographic and geochemical methods 

(Magoon and Claypool, 1985). The petrographic 

approach involves visual identification of individual 

organic constituents, or macerals, in the organic fraction 

of a rock. The most common geochemical methods 

include elemental analysis (C, H, 0) and pyrolysis. 

Pyrolysis is the more widely used of the two methods 

because it is inexpensive on a per-sample cost basis and 

can be done quickly using only milligram quantities of 

sample. Figure 7, adapted from Brooks and others 

(1987), shows a standard van Krevelen diagram with H/C 

and 0/C ratios determined from elemental analysis and 

the equivalent Hydrogen Index and Oxygen Index 

determined by pyrolysis. Shown also in figure 7 are the 

different names for kerogen types and the predominant 

types of products from each kerogen type during 

catagenesis (petroleum generation). 

Another method of characterizing kerogen type 

is by pyrolysis-gas chromatography (Giraud, 1970; 

Leventhal, 1976; Larter and Douglas, 1980; Dembicki 

and others, 1983; Larter, 1984, 1985). This approach to 

kerogen characterization has some advantages over the 

visual description and either elemental analysis or 

pyrolysis estimate of elemental composition because it 

provides a direct measure of the molecular distribution of 

hydrocarbons that can be produced by heating a kerogen. 

Assessment of the fourth source rock criterion, 

amount of hydrocarbons generated and expelled, is a 

goal of the mass balance approach to source rock studies. 

For example, Larter (1985) defined an "actual" source 

rock as one "in which hydrocarbon expulsion has 

occurred to a measurable degree." Mass balance 

calculations in source rock studies are not new, but have 

become more popular in recent years and are used 

increasingly in integrated basin studies. Mass balance 

calculations using pyrolysis and extraction data were 

described by Cooles and others (1986) and Mackenzie 

and Quigley (1988). The method of Cooles and others 

(1986) is basically the same approach as that used by 

Merewether and Claypool (1980) with some 

modifications, most notable of those being consideration 

of the quantities of free hydrocarbons present in the 

source rock at both the mature and immature stages of 

thermal evolution. The principal difficulties with the 

mass balance approach are (1) the assumption that the 

mature source rock contains the same type of organic 

matter (kerogen type) as immature samples of the same 

rock at other locations in the basin; (2) failure to 

adequately consider vertical variations in source rock 

character within the section; (3) errors in measurement of 

bitumen concentration, either by pyrolysis or solvent 

extraction (Larter, 1988); and (4) insufficient control on 

the thickness of the source rock over a broad area under 

investigation. 

Research in source-rock geochemistry in recent 

years has been directed toward improved understanding 

of the conditions during sedimentation and early 

diagenesis that control formation of potential source 

rocks. The objective of this type of research is to be 

able to better predict the occurrence of petroleum source 

rocks. The main factors controlling the accumulation of 

organic-rich sediments are primary productivity, 

sedimentation rate, and preservation after burial. 

However, the various factors influencing each of these 

stages and the relative importance of each are not yet 

fully understood. A second area of potentially fruitful 

research is the application of molecular geochemistry to 

assess the paleoenvironment of organic-rich rocks. The 

Role of Amount and Type of Organic Matter in Recognition of Petroleum Source Rocks 17 
objectives of these types of studies are to understand the REFERENCES CITED 

specific sources and to follow the diagenetic fate of 

organic materials in depositional environments (for 

example, see Brassell and others, 1987). Finally, as 

pointed out by Larter (1988), additional work is needed 

to allow better characterization of the molecular 

composition of organic fractions, especially kerogen and 

asphaltenes, contained in sedimentary organic matter. 

Brassell, S.C., Eglinton, C., and Howell, V.J., 1987, 

Paleoenvironmental assessment of marine 

organic-rich sediments using molecular organic 

geochemistry, in Brooks, J., and Fleet, A.J., eds., 

Marine petroleum source rocks: Boston, 

Blackwell, p. 79-98. 

X 0 w i= 1.5 

0 

z <{ 

a: 

z Q w 

(!) ~ 

0 0 

a: I0 <{ 

>- 0 1.0 

I I 

-

0.05 

LIPTINITE 

(''Type I") 

INERTINITE 

(''Type IV") 

0.10 0.15 

0/C ATOMIC RATIO 

OXYGEN INDEX 

ZONES OF GENERATION 

r~ C02 + H20 rz; . ({\J Oil 

EXINITE 

(''Type II'') 

VITRINITE 

(''Type Ill ") 

0.20 0.25 

Gas 

Figure 7. Van Krevelen diagram showing elemental H/C and 0/C for kerogens, and Hydrogen Index and Oxygen 

Index from Rock-Eval pyrolysis (Espitalie and others, 1985). Arrows show evolution paths for kerogen types during 

burial heating (modified from Brooks and others, 1987). 

18 Petroleum Systems of the United States 
Brooks, J., Cornford, C., and Archer, R., 1987, The role 

of hydrocarbon source rocks in petroleum 

exploration, in Brooks, J., and Fleet, A.J., eds., 

Marine petroleum source rocks: Boston, 

Blackwell, p. 17-46. 

Cooles, G.P., Mackenzie, A.S., and Quigley, T.M., 1986, 

Calculation of petroleum masses generated and 

expelled from source rocks, in Leythaeuser, D. 

and Rullkotter, J., eds., Advances in Organic 

Geochemistry 1985: Organic Geochemistry, v. 

10, p. 235-245. 

Dembicki, H., Horsfield, B., and Ho, T.Y., 1983, Source 

rock evaluation by pyrolysis-gas 

chromatography: American Association of 

Petroleum Geologists Bulletin, v. 67, p. 

1094-1103. 

Dow, W.G., 1978, Petroleum source-beds on continental 

slopes and rises: American Association of 

Petroleum Geologists Bulletin, v. 62, 

1584-1606. 

Durand, B., and Oudin, J.L., 1979, Exemple de migration 

des hydrocarbures dans une Sirie deltaoque: Le 

delta de Ia Mahakam, Indonisie: 1Oth World 

Petroleum Congress Proceedings, v. 2, p. 3-11. 

Durand, B., and Paratte, N., 1983, Oil potential of coals: 

A geochemical approach, in Brooks, J., ed., 

Petroleum geochemistry and exploration of 

Europe: Boston, Blackwell, p. 255-265. 

Espitalie, J., Deroo, G., and Marquis, F., 1985, Rock-eval 

pyrolysis and its applications [preprint]: Institut 

Francais du Petrole, Rueil, France. 

Gehman, H.M., Jr., 1962, Organic matter in limestones: 

Geochimica et Cosmochimica Acta, v. 26, p. 

885-897. 

Giraud, A., 1970, Application of pyrolysis and gas 

chromatography to geochemical characterization 

of kerogen in sedimentary rocks: American 

Association of Petroleum Geologists Bulletin, v. 

54, p. 439-451. 

Hunt, J .M., 1979, Petroleum geochemistry and geology: 

San Francisco, W.H. Freeman, 617 p. 

Larter, S.R., 1984, Application of analytical pyrolysis 

techniques to kerogen characterization and fossil 

fuel exploration/utilization, in Voorhees, K. ed., 

Analytical pyrolysis-Methods and applications: London, Butterworths, p. 212-275. 

1985, Improved kerogen typing for petroleum 

source rock evaluation: Nature, v. 318, p. 

277-280. 

in press, Pragmatic perspectives in petroleum 

geochemistry: Marine and Petroleum Geology. 

Larter, S.R., and Douglas, A.G., 1980, A pyrolysis-gas 

chromatography method for kerogen typing, in 

Douglas, A.G. and Maxwell, J.R., eds., 

Advances in organic geochemistry 1979: New 

York, Pergamon, p. 579-584. 

Leventhal, J.S., 1976, Stepwise pyrolysis-gas 

chromatography of kerogen in sedimentary 

rocks: Chemical Geology, v. 18, p. 5-20. 

Mackenzie, A.S., and Quigley, T.M., 1988, Principles of 

geochemical prospect appraisal: American 

Association of Petroleum Geologists Bulletin, v. 

72, p. 399-415. 

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

North Slope oiVrock correlation study: 

American Association of Petroleum Geologists 

Studies in Geology 20, 682 p. 

Merewether, E.A., and Claypool, G.E., 1980, Organic 

composition of some upper Cretaceous shale, 

Powder River basin, Wyoming: American 

Association of Petroleum Geologists Bulletin, v. 

64, p. 488-500. 

Momper, J.A., 1978, Oil migration limitations suggested 

by geological and geochemical considerations, 

in Physical and chemical controls on petroleum 

migration: Tulsa, American Association of 

Petroleum Geologists Continuing Education 

Course Note Series, No.8, p. B1-B60. 

Ronov, A.B., 1958, Organic carbon in sedimentary rocks 

(in relation to presence of petroleum): 

Translation in Geochemistry, No. 5, p. 

510-536. 

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

and occurrence: A new approach to oil and gas 

exploration: Berlin, Springer-Verlag, 538 p. 

Thompson, S., Cooper, B.S., Morley, R.J., and Barnard, 

P.C., 1985, Oil-generating coals, in Thomas, 

B.M. and others, eds., Petroleum geochemistry 

in exploration of the Norwegian shelf: London, 

Graham and Trotman, p. 59-73. 

Van de Meent, D., Brown, S.C., Philp, R.P., and 

Simoneit, B.R.T., 1980, Pyrolysis-high 

resolution gas chromatography and pyrolysis gas 

chromatography-mass spectrometry of kerogens 

and kerogen precursors: Geochemica et 

Cosmochimica Acta, v. 44, p. 999-1014. 

Role of Amount and Type of Organic Matter in Recognition of Petroleum Source Rocks 19 
Characteristics of Carbonate Source Rocks of Petroleum 

By James G. Palacas 

Carbonate rocks are unique in that they 

commonly play a dual role in petroleum systems. Not 

only can they make good to excellent source rocks but 

they also make excellent reservoir rocks. Their 

importance as reservoirs is underscored by the fact that 

they are host to about 46 percent of the oils in the 509 

giant oil fields in the world (Carmalt and St. John, 1986). 

Another unique feature of carbonate rocks is that in 

many geologic habitats, contiguous carbonate strata serve 

both as source and reservoir rock. This synergistic 

relation is a key factor that distinguishes many carbonate 

petroleum systems (characterized by inplace oil) in 

contrast to shale-sandstone systems. 

Early workers generally assumed that carbonate 

rocks were not suitable as source beds of petroleum (von 

Hettinga Tromp, 1938; Owen, 1964; Hunt, 1967). In 

contrast, shales were regarded as the primary or perhaps 

even the only viable petroleum source rock (Andreev and 

others, 1968; Dott and Reynolds, 1969). Because of this 

bias, most geologic and geochemical research focused on 

the role that shale plays in the formation of petroleum. 

Only limited attention was given to carbonate rocks. 

However, in the past decade, mounting geologic and 

geochemical evidence, supported in many cases by oilto-source rock correlations, has proved the efficacy of 

carbonate and carbonate-evaporite rock types as effective 

source beds of petroleum. Documentation for such 

evidence is presented in table 7. 

Table 7. Recent publications in English referring to carbonate and carbonate-evaporite rocks as potential source 

beds of petroleum 

Authors Year 

Milner and others 1977 

Renard and others 1977 

Palacas 1978 

Tissot and others 1978 

Hunt 1979 

Murris and deGroot 1979 

Malek-Aslani 1980 

Murris 1980 

Ross 1980 

Connan 1981 

Palmer and Zumberge 1981 

20 Petroleum Systems of the United States 

Table 7. Recent publications in English referring to carbonate and carbonate-evaporite rocks as potential source 

beds of petroleum-Continued 

Authors Year 

Tis sot 1981 

Ayres and others 1982 

Connan and others 1983 

The and others 1983 

McK.irdy and others 1983 

Rohrback 1983 

Breger 1984 

Burwood 1984 

Connan and others 1984 

Demaison and Bourgeois 1984 

Fu and others 1984 

Gardner and Bray 1984 

Grabowski 1984 

Hughes 1984 

Hunt and McNichol 1984 

Hussler and others 1984 

Jones 1984 

McKirdy and others 1984 

Oehler 1984 

Palacas 1984 

Palacas and others 1984a 

Palacas and others 1984b 

Patton and others 1984 

Powell 1984 

Rice 1984 

Shinn and others 1984 

Tissot and others 1984 

Tissot and Welte 1984 

Zumberge 1984 

Jones 1985 

Rullkotter and others 1985 

Tannenbaum and Aizenshtat 1985 

Albaiges and others 1986 

Brukner-Wein and Veto 1986 

Connan and others 1986 

Riva and others 1986 

Rullkotter and others 1986 

Talukdar and others 1986 

Chowdhary and Taha 1987 

Sass en and others 1987 

Claypool and Mancini In press 
Before proceeding, pertinent source-rock terms 

need to be defined or clarified. In this report, as gleaned 

from the literature, carbonate source rocks refer chiefly 

to fine-grained sedimentary rocks that contain 50 percent 

or more of carbonate minerals, often associated with 

variable amounts of argillaceous, siliceous, and 

evaporitic constituents. Fine-grained limestones such as 

micrites and lime mudstones are the most prevalent 

carbonate source rocks, but equivalent dolomite facies 

also apply. Some lacustrine source deposits designated 

as "oil shales," such as in the Green River Formation, 

Uinta basin, are in fact carbonate source beds (Tissot and 

Welte, 1984, p. 255). Some, if not many, marlstones are 

also classified as carbonate source beds, especially those 

that contain more than or close to 50 percent carbonate 

minerals such as the Alcanar Formation marls of offshore 

Spain (Demaison and Bourgeois, 1984) and the LaLuna 

Formation marlstones of Colombia (Zumbcrge, 1984). 

In terms of what constitutes a carbonate or shale 

source rock, most of the critical factors, such as amounts, 

type, and maturity of organic matter, are discussed by 

Clayton (this volume). In general, the amount of organic 

matter in carbonate rock as well as shale is quite variable 

and is dependent largely upon the depositional and early 

diagenetic environment. Jones and Demaison (1982) and 

Jones (1984) assessed the variability of organic matter 

content or source potential of sedimentary rocks in terms 

of the "organic facies" concept. Organic facies is 

defined as "a mappable rock unit, distinguishable *** by 

the character of its organic matter without regard to the 

inorganic aspects of the sediment" (Jones, 1984, p. 163). 

Jones and Demaison suggested that organic-rich, oilprone organic facies develop in highly anoxic, 

unbioturbated environments, irrespective of carbonate or 

clay mineral matrices. Conversely, organic-lean, gasprone organic facies form in oxic, commonly bioturbated 

environments. 

Although Jones (1984) did point out some 

differences between carbonate and shale source facies, 

his main focus was on the similarity of characteristics of 

the source rocks. In this present report, the emphasis is 

on the uniqueness of many carbonate source rocks in the 

sense that they commonly generate petroleums with 

distinctive compositional characteristics. Such carbonate 

and particularly carbonate-evaporite facies accumulate in 

saline to hypersaline depositional environments such as 

lagoons, restricted marine basins, sabkhas, and lacustrine 

basins. These environments or subenvironments are 

characterized by low influx of terrigenous debris, high 

organic productivity in the upper water column, usually 

anoxic conditions in the lower water column, and always 

highly reducing conditions beneath the sediment-water 

interface. 

In such highly reducing environments, 

carbonate-evaporite source facies commonly contain 1-5 

percent total organic carbon (TOC) and sometimes as 

much as 10--30 percent (Palacas, 1984; Powell, 1984; 

Spiro and others, 1983). Significantly, these same facies, 

in their thermally immature state (Ro = 0.3-0.5 percent), 

are characterized by extremely high yields (10--25 

percent) of lipid-like extractable organic matter relative 

to total organic carbon. Moreover, even higher yields 

(30--80 percent) have been observed in interbeds of these 

same immature carbonate-evaporite facies (Palacas, 

1984; Palmer and Zumberge, 1981, Powell, 1984; 

Tannenbaum and Aizenshtat, 1985). In sharp contrast, 

immature shales generally show extract yields of less 

than 5 percent (Tissot and Welte, 1984, p. 180). 

This unusual phenomenon of significant volumes 

of lipid-like extractable organic matter produced at low 

levels of thermal maturity runs counter to conventional 

interpretations that call for maximum generation of liquid 

petroleum at a much more mature stage of catagenesis. 

One explanation (Orr, 1986) is that during early 

diagenesis, in the highly reducing environment where 

abundant H2S is generated and iron content is low, sulfur 

becomes incorporated into the kerogen structure 

(designated as Type II-S kerogen). Cleavage of 

relatively weak sulfur-carbon bonds results in generation 

of resin- and asphaltene-rich petroleum at low levels of 

thermal maturation. Another explanation is that the 

extreme reducing conditions in the depositional 

environment cause retardation of the condensation or 

polymerization of kerogen precursor molecules, resulting 

in abnormally high ratios of lipid-like soluble organic 

matter (predominantly resins and asphaltenes) to 

insolubles (kerogen) (Powell, 1984). Should this latter 

hypothesis be true, then the resins and asphaltenes, in 

addition to kerogen, may also serve as major precursors 

of hydrocarbons generated later under higher thermal 

stress (Powell and others, 1975; Palacas, 1984). 

Whatever mechanisms are invoked, the above 

geological-geochemical phenomena have important 

implications for petroleum exploration, especially for 

heavy-oil resources in carbonate regimes. 

In order to establish a well-defined petroleum 

system by correlating oils to oils and oils to source 

rocks, a comparison of some of the common chemical 

characteristics of oils believed by various workers to be 

derived from carbonate (evaporite) and shale source 

rocks is presented (table 8). The data in the table apply 

only to oils of comparable maturity and are especially 

applicable to immature and moderately mature oils. In 

very mature oils, many of the discrete biomarker 

components are destroyed or structurally altered. 

Assumptions are that oils have undergone little or no 

alteration due to biodegradation, migration, and inreservoir maturation. Obviously, caution should be 

exercised in using this table because on a worldwide 

basis there are oils that contain combinations of the two 

categories of geochemical characteristics listed. Also, 

some oils may be mixtures of oils derived from two or 

Characteristics of Carbonate Source Rocks of Petroleum 21 
Table 8. Characteristics of low- to medium-maturity oils derived from carbonate versus shale source rocks 

[HC, hydrocarbons; Sat, saturated; Arom, aromatic; CPI, carbon preference index; #, oils derived from lacustrine carbonate rocks are commonly low 

in sulfur] 

Parameter 

API gravity 

Total sulfur 

HC/(resins+asphaltenes) 

N aphthenes/paraffins 

Sat HC/Arom HC 

CPI, C22-C32 n-alkanes 

Pristane/phytane 

Phytane/n-C 18 

S teranes+triterpanes/n-alkanes 

Steranes 

Diasteranes 

Hopane/C27-C29 steranes 

C3sfC34 extended hopanes 

Diterpanes: 

C24 tetracyclic/C26 tricyclic 

V pattern in four isomeric 

methyldibenzothiophenes 

Thiophenic sulfur 

Carbonate rocks 

Low-medium 

High (>1 percent)# 

Low-medium 

High-medium 

Low-medium 

~1 

~1 

High (0.3-1.5+) 

High-medium 

High aquatic to mixed 

aquatic/terrestrial 

(Cz.j>C29) 

Low (-medium) 

>20 

~1 

High-medium 

Common 

High in benzothiophenes 

Shales 

Medium-high 

Low (<1 percent) 

Medium-high 

Medium-low 

Medium-high 

~1 

~1 

Low (~0.3-0.4) 

Low-medium 

High terrestrial to mixed 

aquatic/terrestrial 

(Cz7<Cz9) 

Medium-high 

<20 

~1 

Medium-low 

Absent or rare 

Low in benzothiophenes 

References 

6,10,16 

1,6,10,12,16 

1,4,9,10,11,12 

6,13,16 

6,11,12,16 

1,6,10,11, 12,17 

1,3,6,10, 12,13 

1,10,11,12 

1,11,12 

5,6 

6,8,14,15 

2 

8 

2,10,11 

6 

6 

References: (1) Connan, 1981; (2) Connan and others, 1986; (3) Didyk and others, 1978; (4) Grabowski, 1984; (5) Huang and 

Meinschein, 1979; (6) Hughes, 1984; (7) Hunt and McNicol, 1984; (8) McKirdy and others, 1983; (9) Murris and DeGroot, 1979; 

(10) Palacas, 1984; (11) Palacas and others, 1984a; (12) Powell, 1984; (13) Renard and others, 1977; (14) Rubenstein and others, 

1975; (15) Rullkotter and others, 1985; (16) Tissot and Welte, 1984; (17) Welte and Waples, 1973. 

more sources, sometimes of different lithologies. Also, 

secondary processes may selectively alter the parameters. 

Therefore, no single parameter can be used to pinpoint 

the origin of an oil. Rather, interpretation of multiple 

bulk and molecular parameters is needed to determine 

oil-source bed relations with some degree of confidence. 

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1986, Petroleum geochemistry of the Tarragona 

Basin (Spanish Mediterranean offshore), in 

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

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Organic Geochemistry, v. 10, p. 441-450. 

Andreev, P.F., Bogomolov, A.I., Dobryanskii, A.F., and 

Kartsev, A.F., 1968, Transformation of 

petroleum in nature (English translation): 

Oxford, Pergamon, International Series 

Monographs in Earth Sciences, v. 29, 466 p. 

22 Petroleum Systems of the United States 

Ayres, M.G., Bilal, M., Jones, R.W., Slentz, L.W., Tartir, 

M., and Wilson, A.O., 1982, Hydrocarbon 

habitat in main producing areas, Saudi Arabia: 

American Association of Petroleum Geologists 

Bulletin, v. 66, p. 1-9. 

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Characteristics of Carbonate Source Rocks of Petroleum 25 
Geothermics of Petroleum Systems: 

Implications of the stabilization of Kerogen Thermal Maturation 

after a Geologically Brief Heating Duration at Peak Temperature 

By Charles E. Barker 

INTRODUCTION 

Although the degree of interplay between 

temperature and time in the thermal maturation of 

source rocks is controversial, it is now established that 

heating of kerogen, usually by burial, is crucial to 

generate petroleum (Naeser and McCulloch, 1988). 

Evidence is also accumulating that kerogen thermal 

maturation stabilizes (terminates) after a geologically 

short reaction time at maximum temperature (Robert, 

1980; Barker, 1983; Price, 1983; Kisch, 1987; and 

others). Geologic time at peak temperature is almost 

always sufficient to allow stabilization of the maturation 

process (Suggate, 1982), requiring 1 to 10 million years 

(m.y.) during burial diagenesis (Kisch, 1987; Barker, 

1988). The stabilization of kerogen thermal maturation 

implies some important new concepts that apply to 

petroleum systems. 

Firstly, it should be possible to assess sourcerock thermal maturity by considering temperature alone 

rather than temperature and time together. Most 

petroleum generation occurs during catagenesis, 

commencing at about 50 °C and finishing at the 

threshold of dry gas generation at about 200 oc (Hunt, 

1979, p. 102; Ammosov, 1981; and others). Secondly, 

petroleum generation may cease after a geologically brief 

time at peak temperature. Lastly, overpressured or 

hydrothermal fluids associated with increasing 

temperature during burial are a crucial element in a 

petroleum system. Migration of petroleum in these hot, 

reactive fluids may cause enhanced porosity in the 

reservoir rock, or interact with rocks just above the path 

to form reservoir seals. This last point extends from the 

influence of increasing temperature on the petroleum 

system, inducing forced convection with simultaneous 

petroleum migration, along with diagenetic changes 

caused by the turnover of pore fluids (Wood and Hewett, 

1985), and influencing the porosity (Schmoker, 1984) 

remaining in the potential reservoir rocks and seals. 

Because diagenetic reactions and the rate of convection 

are enhanced by increased temperature, the most 

profound changes are likely at near peak temperature. 

These factors make the timing and magnitude of peak 

temperature (the thermal history) important in 

determining the hydrocarbon volume, where and when 

26 Petroleum Systems of the United States 

traps form, the proportion of oil to gas, and apparently, 

when petroleum ceases to be generated in the system. 

As a consequence of the stabilization of thermal 

maturation, vitrinite reflectance (R ), an index of thermal 0 

maturity, can be calibrated empirically to the peak 

temperature. A series of R measurements taken at 0 

various levels in sedimentary sections can be used to 

compute a profile consisting of peak temperature points, 

within some constraints (Dembicki, 1984; Barker and 

Pawlewicz, 1986). The peak temperature profile is a 

crucial reference line for thermal history reconstruction 

by comparative geothermometry. The thermal history of 

the sedimentary section, within some limitations, can be 

inferred by comparing mineral-based geothermometric 

data and the present-day temperature profile (Gretener, 

1981, p. 13) to the peak temperature profile. Application 

of this technique by the U.S. Geological Survey to 

selected petroleum systems illustrates how peak 

temperature and thermal history are interpreted. 

PEAK TEMPERATURE 

Delaware basin, Texas 

Barker and Halley (1986) studied 

paleotemperatures indicated by fluid inclusion, R , and 0 

oxygen isotope data from fracture-filling calcite and host 

rock in the Bone Spring Limestone (Leonardian), 

Delaware basin, Texas. Although the cements have 

petrographically distinct multiple zones, homogenization 

temperatures (Th) of oil inclusions, o180 data, and in 

some samples crosscutting relationships, divide these 

cements into the early and late groups. Early cements 

have 0180 near zero permil and contain blue fluorescent 

oil inclusions whose mean This 70 oc (160 °F}. The late 

cements have o180 of about -9 permil and contain sparse 

oil inclusions with blue fluorescence similar to those in 

the early cement. Crosscutting both these cements is a 

later generation of oil fluid inclusions with a yellow 

fluorescence. Primary fluid inclusions in the late cements 

have a mean Th of 110 oc (230 °F}. The mean Th of 

these inclusions is comparable to the 110 oc calculated 

from a R0 of 0.7 percent with the Barker and Pawlewicz 
( 1986; modified as noted below) empirical calibration 

and the 45 oc (80 °F) temperature change from the early 

to late cement interpreted from a B180 difference of 

about 9 permil. These thermal data and burial history 

reconstruction suggest that both the late cements and R 0 

record the maximum temperature attained in the rock. 

These temperatures suggest a geothermal gradient of at 

least 40 °C/km (2.2 °F/100 ft) higher than previously 

reported for the western Delaware basin (Kinney, 1976)*. 

Barker and Pawlewicz (1987) extended Barker 

and Halley's study to Leonardian rocks throughout the 

Delaware basin. Their R0 data suggested that the 

Leonardian petroleum system in the western portion of 

the basin was hotter than that in the eastern portion. This 

heating is attributed to igneous intrusions and increased 

heat flow related to the mid-Tertiary development of the 

Basin and Range Province in the western Delaware 

basin. Burial history reconstruction indicates that oil was 

generated during near-maximum burial in Permian time 

with a geothermal gradient of about 25 °C/km (1.4 

°F/100 ft). Peak temperatures computed from R -depth 

0 

relationships and Barker and Pawlewicz's (1986) 

modified empirical geothermometer imply that 

paleogeothermal gradients exceeded 40 °C/km (2.2 

°F/100 ft) in Tertiary time. This reheating produced 

thermally mature rocks as young as Guadalupian in the 

western Delaware basin and caused a second episode of 

petroleum generation in the Leonardian petroleum 

system. Evidence that each thermal event caused 

renewed petroleum migration includes distinct fracture 

sets that have trapped at least two oils with different 

fluorescence colors. 

Green River basin, Wyoming 

Pollastro and Barker (1986) used comparative 

geothermometry to study the Cretaceous(.) petroleum 

system penetrated by a deep borehole through the 

Pinedale anticline, northern Green River basin, 

Wyoming. Using the modified Barker and Pawlewicz 

(1986) empirical calibration, they computed peak 

temperature in the petroleum system of about 200 °C 

(390°F), close to the temperature calculated from claymineral data at about 190 oc (370 °F). Uncorrected 

borehole temperature is now about 130 oc (270 °F). The 

* We now think it is better to use a regression method that allows error to be present in both the independent and dependent variable. 

The major axis regression method (fill, 1974) calculates the following 

equation from the same set of R0 and temperature data: ln (R) = 

0.0096 (fmax) - 1.4. This equation produces peak temperature predictions (fmax) from R0 that are more compatible with other geothermometers and burial history reconstruction. 

slope of the present-day borehole temperature 

measurements and the slope of temperatures interpreted 

from R are about 25 °C/km (1.4 °F/100 ft). Fluid 0 

inclusion homogenization temperatures in quartz-filled 

fractures formed by late Tertiary deformation are equal 

to present-day temperature. An extrapolated R0 surface 

intercept of 0.33 percent indicates that about 1,700 m 

(5,600 ft) of section has been removed. Decreasing the 

burial depth by 1, 700 m in a geothermal gradient of 25 

°C/km would decrease borehole temperatures by about 

40 °C (70 °F), making it consistent with the other 

geothermometric data. These data were interpreted to 

indicate that the temperature decrease of about 40 oc (70 0F) was caused by uplift and erosion rather than by 

decline in geothermal gradient, which occurred before 

the fractures were filled with quartz. A subsequent 

fission-track annealing study in this same borehole 

confirmed a temperature decline of at least 20 oc ( 40 °F) 

at approximately 3 Ma (Naeser, 1984). 

Piceance basin, Colorado 

Law and others (in press) studied the 

Mesaverde(.) petroleum system in the Piceance basin, 

Colorado. Here segmented R0 profiles are interpreted to 

result from heating caused by relatively warm fluids 

displaced upward when gas filled the pores of 

overpressured rocks. Barker (in press) used their vitrinite 

reflectance data to compute peak temperature of at least 

200 °C (390 °F) in the Cameo coal zone. This peak 

temperature iS higher than that expected (175 °C; 350°F) 

from extrapolating the present-day temperature profile 

(heat flow has not changed since the Paleozoic) to the 

reconstructed maximum burial depth of the Cameo coal 

zone. Barker (in press) suggested that the decrease of 

thermal conductivity caused by gas (rather than water) 

filling the pores of a rock can temporarily increase 

geothermal gradients to twice the ambient geothermal 

gradient, without changing the heat flow in the rock 

section. The decreased thermal conductivity suggests a 

peak temperature (using the method of Gretener, 1981) 

similar to that computed from R using the modified 0 

Barker and Pawlewicz (1986) equation. 

SUMMARY 

New evidence that thermal maturation stabilizes 

after a geologically brief time at peak temperature has 

important implications in the study of petroleum systems. 

Thermal maturation and petroleum generation may cease 

soon after peak temperature is reached. Consequently, 

the peak temperature is most influential in determining 

R, a measure of thermal maturity. The comparative 0 

Geothermics of Petroleum Systems 27 
geothermometry technique, which utilizes R0 as a 

maximum recording geothermometer, together with 

supporting geological evidence, can produce a thermal 

history reconstruction of a petroleum system. 

Application of this technique shows that many petroleum 

systems are buried quickly and rapidly reach 

temperatures sufficient for petroleum generation. Many 

also remain near maximum burial for extended periods 

of geologic time. In some cases, heating events at or 

after maximum burial have produced another episode of 

petroleum generation. In conclusion, these studies 

suggest the strong influence of temperature on petroleum 

systems. 

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Petroleum Geologists and U.S. Geological 

Survey, scale 1:5,000,000, 2 sheets. 

Kisch, HJ ., 1987, Correlation between indicators of 

very-low-grade metamorphism, in Frey, M., ed., 

Low temperature metamorphism: Glasgow, 

Blackie and Son, p. 228-300. 

Law, B.E., Nuccio, V.F., and Barker, C.E., in press, 

Kinky vitrinite reflectance profiles: Evidence of 

paleopore pressure in low-permeability gasbearing sequences in Rocky Mountain foreland 

basins: American Association of Petroleum 

Geologists Bulletin. 

Naeser, N.D., 1984, Fission-track ages from the Wagon 

Wheel no. 1 well, northern Green River basin, 

Wyoming; Evidence for recent cooling, in Law, 

B.E., ed., Geological characteristics of lowpermeability Upper Cretaceous and lower 

Tertiary rocks in the Pinedale area, Sublette 

County, Wyoming: U.S. Geological Survey 

Open-File Report 84-753, p. 66--77. 

Naeser, N.D., and McCulloch, Thane, 1988, Introduction 

and overview, in Naeser, N.D., and McCulloch, 

Thane, eds., Thermal history of basins: Methods 

and case histories: Berlin, Springer-Verlag, p. 

1-11. 

Pollastro, R.M., and Barker, C.E., 1986, Application of 

clay-mineral, vitrinite reflectance, and fluid 

inclusion studies to the thermal and burial 

history of the Pinedale anticline, Green River 

basin, Wyoming, in Gautier, D.L., ed., 1986, 

Roles of organic matter in sediment diagenesis: 

Society of Economic Paleontologists and 

Mineralogists Special Publication 38, p. 73-83. 

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. 

Robert, P., 1980, The optical evolution of kerogen and 

geothermal histories applied to oil and gas 

exploration, in Durand, B., ed., Kerogen: Paris, 

Editions Technip, p. 385-414. 

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. 

Suggate, R.P., 1982, Low rank sequences and scales of 

organic metamorphism: Journal of Petroleum 

Geology, v. 4, p. 377-392. 

Till, R., 1974, Statistical methods for the Earth 

scientist-An introduction: London, Macmillan, 

154 p. 

Wood, J.R., and Hewett, T.A., 1985, Reservoir 

diagenesis and convective fluid flow, in 

Mcdonald, D.A., and Surdam, R.C., eds., Clastic 

diagenesis: Tulsa, American Association of 

Petroleum Geologists, p. 99-110. 

Geothermics of Petroleum Systems 29 
Thermal Maturity 

By J. David King and Mark J. Pawlewicz 

INTRODUCTION 

Substantial evidence indicates that much of the 

observed petroleum and natural gas in the world derives 

from thermal alteration of organic compounds found in 

sedimentary rocks. These organic compounds are 

diagenetic products of material originating in the 

biosphere at the time of deposition of the sedimentary 

rocks (Ourisson and others, 1984). The key word here is 

thermal. This implies that organic-rich rocks that have 

not been heated to some degree will not have produced 

commercially significant quantities of oil or gas. 

Possible heat sources include heat flow from radioactive 

decay within the Earth's crust, tectonically controlled 

events that change heat flow locally, volcanism and 

intrusions, and heat flow by fluid transport. 

The ultimate goal of thermal maturity 

assessment is to determine as accurately as possible the 

temperature history of sedimentary rocks. Once the 

temperature history is defined, it can be used to predict 

the time at which expulsion of oil and gas occurred and 

thus constrain migration pathways and entrapment 

mechanisms (Waples, 1985). In practice, a study of the 

temperature history of any petroleum system consists of 

estimation of rock temperature through geologic time, 

refinement of the initial estimate based on various kinds 

of measurements of rock properties, and construction of 

a "model" of source rock maturity. It is important to note 

that the actual values obtained from measurement of rock 

properties are not in themselves the thermal maturity of 

the rock, but merely indicative of the temperature history 

of the rock. 

INITIAL ESTIMATE 

Basic to any thermal maturity study is a complete 

geologic history of the rocks in question. In the case of a 

typical sedimentary basin, this includes burial history and 

tectonics as well as temperature and heat-flow 

measurements (for example, see Chapman and others, 

1984; Mackenzie and McKenzie, 1983; Pitman and 

others, 1987). The only way to get an accurate picture 

of an entire basin is to construct separate burial-thermal 

history diagrams for many locations within the basin 

(Beaumont and others, 1985). Thus, as a minimum, the 

initial temperature history estimate must be based upon 

rock thicknesses, ages, and postulated heat flows (or 

30 Petroleum Systems of the United States 

geothermal gradients)-usually derived from stratigraphic 

and bottom-hole temperature data. 

MEASUREMENT OF ROCK PROPERTIES 

Physical and chemical analyses of rock properties 

influenced by heating can be divided into two basic 

groups. 

Properties of inorganic material include silica 

phase changes (Isaacs, 1982), clay mineral diagenesis, 

fission-track annealing (Gleadow and others, 1983; 

Naeser and Naeser, 1985), and isotope measurement 

(Harrison and Be, 1983). 

Properties of organic material include vitrinite 

reflectance (R ), spore/pollen translucency and thermal m 

alteration index (T AI), conodont alteration index (CAl; 

Epstein and others, 1977), gas chromatographic odd-even 

predominance (OEP; Scalan and Smith, 1970), 

temperature of maximum pyrolysis products (Tmax)' 

molecular reactions (Mackenzie, 1984), and fluid 

inclusions (Burruss, 1985). 

Since these analyses measure properties of the 

rock or organic material that respond differently to 

temperature and time, measurement of more than one of 

the parameters can significantly improve the initial timetemperature estimate. A complete assessment of 

basinwide thermal maturity requires that different kinds 

of analyses be performed on many samples from 

locations throughout the basin. 

REFINEMENT OF THE INITIAL ESTIMATE 

A link must be established between the 

estimated thermal history and each of the rock properties 

that have been determined quantitatively. This is 

accomplished by thermal maturity modeling. If 

discrepancies arise from this procedure, it can be 

assumed that either the estimated thermal history is in 

error or the thermal maturity model invoked is 

unacceptable. 

One widely used thermal maturity model is 

time-temperature index (TTl). TTl values can be 

"correlated" with properties such as Rm' TAl, Tmax 

(Waples, 1985) and extent of completion of certain 

molecular reactions (King and Claypool, 1983). The 

validity of this model may be in question, however 

(Schmoker, 1986). 
Recently, individual kinetic maturity models 

have come into favor, mainly because of their specificity 

toward measured quantities; that is, different 

mathematical procedures are used for each of the 

different measured properties. Kinetic models have been 

applied with considerable success to molecular reaction 

parameters (Alexander and others, 1986; Beaumont and 

others, 1985), although they are not restricted solely to 

these maturity measures (Antia, 1986). Armed with the 

predictions of the thermal maturity model and 

geochemical analyses, one should be able to find an 

acceptable thermal history by appropriate manipulation 

of the initial time-temperature estimate (Lerche, 1988). 

THERMAL RELEASE OF ORGANICS AS OIL 

AND GAS 

An assessment of thermal maturity alone does 

not provide sufficient information to accurately determine 

temporal and spatial occurrence of petroleum and natural 

gas. The only link between the thermal maturity study 

and release of oil and gas is a well-defined paleothermal 

history and its use to model kerogen breakdown, 

compaction, fluid flow, fluid pressure, pore geometry, 

and other considerations that are crucial to understanding 

the release of oil and gas from their point of origin. 

Modeling of kerogen breakdown to oil or gas 

can be as simple as defining a TTl oil or gas "window" 

(Waples, 1985) or as complex as kinetic modeling 

(Burnham and others, 1987; Ungerer and Pelet, 1987). 

The technique used and the validity of the assessment 

depend upon the availability of good geological and 

geochemical data. 

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. 

Antia, D.D.J., 1986, Kinetic method for modeling 

vitrinite reflectance: Geology, v. 14, p. 606-608. 

Beaumont, C., Boutilier, R., Mackenzie, A., and 

Rulkotter, J., 1985, Isomerization and 

aromatization of hydrocarbons and the 

paleothermometry and burial history of Alberta 

Foreland Basin: American Association of 

Petroleum Geologists Bulletin, v. 69, no. 4, p. 

546-566. 

Burnham, A.K., Braun, R.L., Gregg, H., and Samoun, A., 

1987, Comparison of methods for measuring 

kerogen pyrolysis rates and fitting kinetic 

parameters: 193d Meeting of the American 

Chemical Society, April 6, 1987, Denver, Colo., 

p. 1-27. 

Burruss, R.C., 1985, Paleotemperatures from fluid 

inclusions-Advances in theory and technique 

[abs.]: American Association of Petroleum 

Geologists Bulletin, v. 69, no. 2, p. 241. 

Chapman, D., Keho, T., Bauer, M., and Picard, D., 1984, 

Heat flow in the Uinta Basin determined from 

bottom hole temperature (BHT) data: 

Geophysics, v. 49, no. 4, p. 453-466. 

Epstein, A., Epstein, J., and Harris, L., 1977, Conodont 

color alteration-An index to organic 

metamorphism: U.S. Geological Survey 

Professional Paper 995, 27 p. 

Gleadow, A.J.W., Duddy, 1., and Lovering, J.F., 1983, 

Fission track analysis: A new tool for the 

evaluation of thermal histories and hydrocarbon 

potential: APEA Journal, p. 93-102. 

Harrison, M.T., and Be, K., 1983, 40ArP9 Ar age spectrum 

analysis of detrital microclines from the 

southern San Joaquin basin, California: An 

approach to determine the thermal evolution of 

sedimentary basins: Earth and Planetary 

Science Letters, v. 64, p. 244-256. 

Isaacs, C.M., 1982, Influence of rock composition on 

kinetics of silica phase changes in the Monterey 

Formation, Santa Barbara area, California: 

Geology, v. 10, p. 304-308. 

King, J.D., and Claypool, G.E., 1983, Biological marker 

compounds and implications for generation and 

migration of petroleum in rocks of the Point 

Conception deep-stratigraphic test well, OCSCAL 78-164 no. 1, offshore California, in 

Isaacs, C., and Garrison, R., eds., Petroleum 

generation and occurrence in the Miocene 

Monterey Formation, California: Bakersfield, 

Pacific Section, Society of Economic 

Paleontologists and Mineralogists, p. 191-200. 

Lerche, I., in press, Inversion of multiple thermal 

indicators: Quantitative methods of determining 

paleoheat flux and geological parameters I. The 

theoretical development: Mathematical 

Geology. 

Mackenzie, A.S., 1984, Applications of biological 

markers, in Brooks, J., and Welte, D., eds., 

Advances in petroleum geochemistry, v. 1: p. 

115-214. 

Mackenzie, A.S., and McKenzie, D.H., 1983, 

Isomerization and aromatization of hydrocarbons 

in sedimentary basins formed by extension: 

Geological Magazine, v. 120, no. 5, p. 417-528. 

Naeser, N.D., and Naeser, C.W., 1985, Fission-track 

dating and its application to the thermal history 

of sedimentary basins [abs.]: American 

Association of Petroleum Geologists Bulletin, v. 

69, no. 2, p. 191. 

Thermal Maturity 31 
Ourisson, G., Albrecht, P., and Rohmer, M., 1984, The 

microbial origin of fossil fuels: Scientific 

American, v. 251, no. 2, p. 44-51. 

Pitman, J.K., Franczyk, KJ., and Anders, D.E., 1987, 

Marine and nonmarine gas-bearing rocks in 

upper Cretaceous Blackhawk and Neslen 

Formations, Eastern Uinta Basin, Utah: 

Sedimentology, diagenesis and source rock 

potential: American Association of Petroleum 

Geologists Bulletin, v. 71, no. 1, p. 76-94. 

Scalan, R.S., and Smith, J.E., 1970, An improved 

measure of the odd-even predominance in the 

normal alkanes of sediment extracts and 

petroleum: Geochimica et Cosmochimica Acta, 

V. 34, p. 611-620. 

32 Petroleum Systems of the United States 

Schmoker, J.W., 1986, Oil generation in the Anadarko 

Basin, Oklahoma and Texas: Modeling using 

Lopatin's method: Oklahoma Geological 

Survey Special Publication 86-3, 40 p. 

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

kinetics of oil and gas formation from laboratory 

experiments to sedimentary basins: Nature, v. 

327' p. 52-54. 

Waples, D.W., 1985, Geochemistry in petroleum 

exploration: Boston, International Human 

Resources Development Corp., Geological 

science series, 232 p. 
Primary and Secondary Hydrocarbon Migration 

By Charles W. Spencer 

Hydrocarbon migration is a critical element of 

any petroleum system. Migration takes place through a 

simple to sometimes complex "plumbing" system that 

starts with source-bed expulsion and continues through to 

the ultimate site of entrapment. Primary migration 

involves the movement of hydrocarbons from the site of 

generation in a source bed to expulsion into a reservoir 

rock or carrier bed. Secondary migration is the 

movement of hydrocarbons within the carrier beds of the 

petroleum system. Under ideal conditions, secondary 

migration results in an economically recoverable 

accumulation of hydrocarbons in a trap. The term 

tertiary migration is sometimes applied to the subsequent 

remigration of a previous accumulation of oil or gas. 

In spite of many years of petroleum research 

and exploration, there is still a wide diversity of opinion 

on exactly how primary migration occurs (Roberts and 

Cordell, 1980; Durand, 1983; Tissot, 1984). Methods of 

secondary migration are less controversial. In the 1960's 

and 1970's primary migration by water-driven 

hydrocarbon expulsion became a popular explanation. 

The source of water was generally believed to be water 

released as a result of the alteration of smectite to illite, 

or water released as sediments compact and consequently 

expel water incorporated in argillaceous sediments at the 

time of deposition (Powers, 1967; Burst, 1969; Magara, 

1976). Primary migration related to water expulsion may 

involve hydrocarbons dissolved in water (Price, 1976), 

free hydrocarbons, or oily compounds as emulsions or 

dissolved by natural soaps (micellar migration) (Baker, 

1962; Cordell, 1973). All require some method to 

recombine the dispersed hydrocarbons into a discrete oil 

or gas phase. These types of primary migration are not a 

likely explanation for many giant oil and gas 

accumulations. Also, several recent authors have pointed 

out that most rocks are fairly well compacted when 

buried to sufficient depths (and heat) to generate 

significant volumes of oil and gas (Cordell, 1972; Jones, 

1980; Durand, 1983). Furthermore, whereas rapidly 

filled young basins have slightly undercompacted 

water-bearing rock sequences, basins characterized by 

slow deposition contain rocks that are usually well 

compacted and lithified when peak hydrocarbon 

generation takes place. Finally, many major source beds 

worldwide do not contain smectitic clay, hence water is 

unavailable from this source. 

Diffusion of light hydrocarbons through source 

beds and seals has been suggested as a primary migration 

mechanism (Pandey and others, 1974; Leythaeuser and 

others, 1982). Rates of diffusion are influenced by 

molecule size, concentration, temperature, and other 

factors. Diffusion is a mechanism by which gases can 

migrate out of source beds and traps but it is generally a 

dispersive process and not a means to effectively 

concentrate hydrocarbons. 

Migration of oil and gas as continuous-phase 

hydrocarbons is the most plausible mechanism for 

primary expulsion from source beds (Meissner, 1976, 

1978, 1985; Jones, 1980; Durand, 1983). Naturally, 

sufficient concentrations of liquid or gaseous 

hydrocarbons have to be present in the source bed to 

saturate the pore fluids and pore space, after which 

differential pressures caused by hydrocarbon generation, 

compaction of kerogen, and other factors act to expel the 

oil and gas into available reservoir rocks. The mobility 

of heavier organic molecules is likely facilitated by the 

generation of methane and carbon dioxide from thermal 

maturation of kerogen. The volume increase from gas 

generation plus the compaction of kerogen can cause 

elevated pressures in the source rock even to the point of 

microfracturing (Cordell, 1972; Hedberg, 1974, 1980; 

Meissner, 1978). 

As noted earlier, secondary migration is 

moderately well understood. Many studies tying oils to 

source beds, and geologic and engineering studies of the 

behavior of oil- and gas-phase migration, strongly 

support the concept of continuous-phase oil and gas 

migration in reservoir (carrier) beds. This mode of 

migration explains most major oil and gas accumulations 

(Aschenbrenner and Achauer, 1960; Schowalter, 1979; 

Jones, 1980; McAuliffe, 1980; Durand, 1983). However, 

in special cases, secondary migration may take place by 

hydrocarbons in solution or as micelles. 

The oil globules or gas bubbles coalesce after 

primary migration out of the source bed. When they 

form continuous phase stringers or columns of oil or gas, 

the hydrocarbons are buoyant in water-filled reservoir 

pore spaces. Under hydrostatic conditions, the 

hydrocarbon continuous phase must exceed the capillary 

(or entry) pressure of the largest pore throats of the 

carrier bed in order to migrate updip. Migration is 

generally believed to occur in thin continuous 

hydrocarbon layers or stringers in the uppermost part of 

the carrier beds. Migration can be assisted by a pressure 

differential in hydrocarbon-saturated reservoirs, or 

buoyancy migration can be assisted by hydrodynamic 

Primary and Secondary Hydrocarbon Migration 33 
updip movement of reservoir water. Oil and gas will 

begin to accumulate in the top of structural closures or 

against the updip edges of stratigraphic traps. When the 

pressure caused by the buoyant, continuous column of 

hydrocarbons exceeds the entry pressure of the largest 

pore throats in the seal or updip barrier, the 

hydrocarbons will penetrate the barrier and a significant 

volume of the hydrocarbons may leak updip to the next 

obstruction along the migration route (Berg, 1975; 

Schowalter, 1979; Downey, 1984). However, updip 

hydrodynamic flow will cause stratigraphic traps to 

become less effective as barriers whereas downdip water 

flow will enhance the trapping ability of capillary traps 

(Berg, 1975). Abnormally high regional pore pressures 

may force hydrocarbons into or through seals or along 

nonsealing faults and fractures. Under certain conditions, 

strong downdip flow of water may physically displace oil 

downdip (Hubbert, 1953), but such conditions are not 

common. 

REFERENCES CITED 

Aschenbrenner, B.C., and Achauer, C.W., 1960, 

Minimum conditions for migration of oil in 

water-wet carbonate rocks: American 

Association of Petroleum Geologists Bulletin, v. 

44,no. 2,p. 235-243. 

Baker, E.G., 1962, Distribution of hydrocarbons in 

petroleum: American Association of Petroleum 

Geologists Bulletin, v. 46, no. 1, p. 76-84. 

Berg, R.R., 1975, Capillary pressures in stratigraphic 

traps: American Association of Petroleum 

Geologists Bulletin, v. 59, no. 6, p. 939-956. 

Burst, J.F., 1969, Diagenesis of Gulf Coast clayey 

sediments and its possible relation to petroleum 

migration: American Association of Petroleum 

Geologists Bulletin, v. 53, no. 1, p. 73-93. 

Cordell, R.J ., 1972, Depths of oil migration and primary 

migration-A review and critique: American 

Association of Petroleum Geologists Bulletin, v. 

56, no. 10,p. 2029-2067. 

1973, Colloidal soap as proposed primary 

migration medium for hydrocarbons: American 

Association of Petroleum Geologists Bulletin, v. 

57,no.9,p. 1618-1643. 

Downey, M.W., 1984, Evaluating seals for hydrocarbon 

accumulations: American Association of 

Petroleum Geologists Bulletin, v. 68, no. 11, p. 

1752-1763. 

Durand, B., 1983, Present trends in organic geochemistry 

in research on migration of hydrocarbons, in 

Bjoroy, M., ed., Advances in organic 

geochemistry 1981: New York, John Wiley & 

Sons, p. 117-128. 

Hedberg, H.D., 1974, Relation of methane generation to 

34 Petroleum Systems of the United States 

undercompacted shales, shale diapirs, and mud 

volcanoes: American Association of Petroleum 

Geologists Bulletin, v. 58, no. 4, p. 661--673. 

1980, Methane generation and petroleum 

migration, in Roberts, W.H., III, and Cordell, 

R.J., eds., Problems of petroleum migration: 

American Association of Petroleum Geologists 

Studies in Geology 10, p. 179-206. 

Hubbert, M.K., 1953, Entrapment of petroleum under 

hydrodynamic conditions: American Association 

of Petroleum Geologists Bulletin, v. 37, no. 9, 

p. 1954-2026. 

Jones, R.W., 1980, Some mass balance and geological 

constraints on migration mechanisms, in 

Roberts, W.H., III, and Cordell, R.J., eds., 

Problems of petroleum migration: American 

Association of Petroleum Geologists Studies in 

Geology 10, p. 47--68. 

Leythaeuser, Detlev, Schaefer, R.G., and Yukler, Arif, 

1982, Role of diffusion in primary migration of 

hydrocarbons: American Association of 

Petroleum Geologists Bulletin, v. 66, no. 4, p. 

408-429. 

Magara, Kinji, 1976, Water expulsion from clastic 

sediments during compaction-Directions and 

volumes: American Association of Petroleum 

Geologists Bulletin, v. 60, no. 4, p. 543-553. 

McAuliffe, C.D., 1980, Oil and gas migration-Chemical 

and physical constraints, in Roberts, W.H., III, 

and Cordell, R.J., eds., Problems of petroleum 

migration: American Association of Petroleum 

Geologists Studies in Geology 10, p. 89-107. 

Meissner, F.F., 1976, Abnormal electric resistivity and 

fluid pressure in Bakken Formation, Williston 

basin and its relation to petroleum generation, 

migration and accumulation [abs.]: American 

Association of Petroleum Geologists Bulletin, v. 

60, no. 8,p. 1403-1404. 

1978, Petroleum geology of the Bakken 

Formation, Williston basin, North Dakota and 

Montana, in 24th Annual Conference, Williston 

Basin Symposium: Billings, Montana 

Geological Society, p. 207-227. 

1985, Regional hydrocarbon generation, 

migration, and accumulation pattern of 

Cretaceous strata, Powder River basin [abs.]: 

American Association of Petroleum Geologists 

Bulletin, v. 69, p. 856. 

Pandey, G.N., Tek, M.R., and Katz, D.L., 1974, 

Diffusion of fluids through porous media with 

implications in petroleum geology: American 

Association of Petroleum Geologists Bulletin, v. 

58, no. 2,p. 291-303. 

Powers, M.C., 1967, Fluid release mechanisms in 

compacting marine mudrocks and their 
importance in oil exploration: American 

Association of Petroleum Geologists Bulletin, v. 

51, no. 7,p. 1240-1254. 

Price, L.C., 1976, Aqueous solubility of petroleum as 

applied to its origin and primary migration: 

American Association of Petroleum Geologists 

Bulletin, v. 60, no. 2, p. 213-244. 

Roberts, W.H., Ill, and Cordell, R.J., 1980, eds., 

Problems of petroleum migration: American 

Association of Petroleum Geologists Studies in 

Geology 10, 273 p. 

Schowalter, T.T., 1979, Mechanics of secondary 

hydrocarbon migration and entrapment: 

American Association of Petroleum Geologists 

Bulletin, v. 63, p. 723-760. 

Tissot, B.P., 1984, Recent advances in petroleum 

geochemistry applied to hydrocarbon 

exploration: American Association of Petroleum 

Geologists Bulletin, v. 68, no. 5, p. 545-563. 

Primary and Secondary Hydrocarbon Migration 35 
Structure 

By William J. Perry, Jr. 

In its most limited sense, structure is the threedimensional shape of a body of rock, whether we are 

dealing with a single bed, a sedimentary basin, a 

mountain belt, or the Earth. Structure also concerns the 

internal morphology of rocks, whether we are discussing 

the structure of pore throats, other microscopic fabrics, or 

the internal morphology of mountain belts. Both shape 

and internal morphology are necessary ingredients of 

petroleum systems. 

So-called structure maps (as used in the 

petroleum industry) are simply contour maps of the 

present elevations of a reference horizon, commonly 

bedding, contoured in feet or meters above or below sea 

level. These maps are used to define structural closures 

such as four-way closures, in which beds dip away on all 

sides, or fault-bounded closures, in which beds dip away 

from a bounding fault(s). Hydrocarbons will migrate 

updip along permeable layers into such closures, if 

closures are present, unless trapped by a permeability 

barrier. Structural closures may then become traps for 

hydrocarbons if vertical migration is prevented by the 

presence of a seal, generally an impermeable layer or 

sequence of layers above the permeable zone. The 

paleostructure (preexisting structure) of a region is 

becoming recognized to be of great importance to 

petroleum systems: the closures that were present during 

peak hydrocarbon generation and migration are those 

most likely to contain significant quantities of 

hydrocarbons. 

Structures may be broadly subdivided into (1) 

folds, which are continuous, caused by buckling or 

flowage or a combination of both, and (2) faults, which 

disrupt the continuity of rock layers and along which 

movement has occurred. Faults belong to a larger family 

of structures formed by brittle deformation known as 

fractures, planar features across which a loss of cohesion 

has occurred. In the parlance of rock mechanics, faults 

are shear fractures. The second major family of fractures 

are commonly called joints or rock joints. These are 

extension fractures, characterized by lack of 

displacement along their surfaces; they have extended or 

dilated the rock body in which they occur. These are of 

particular importance to petroleum systems in that they 

create secondary porosity. Of equal importance, they 

form part of what is called a "dual permeability" system: 

permeability pathways along an interconnected fracture 

and interstitial pore-space network. The direction of 

extension fracture alignment is normally the direction in 

36 Petroleum Systems of the United States 

which fluids will move most readily, unless such 

fractures are sealed by calcite or other minerals. Such 

mineral-filled fractures are commonly termed veins. 

Fracture development and propagation has been the 

subject of intensive laboratory and theoretical analysis, 

summarized with respect to rocks by Ramsay (1967) and 

Suppe (1985). 

Structural styles include those of extensional, 

compressional, and wrench-fault tectonics, each with its 

family of characteristic structures, structural processes, 

and structural relationships, and each with a different 

history of petroleum generation, migration, and trapping 

based in part on these different processes and 

relationships (Harding and Lowell, 1979). 

Extensional tectonics is a rapidly growing field 

of investigation. Principal examples of extensional 

terranes, those in which the Earth's crust has undergone 

extension, are the Basin and Range Province of the 

western United States, the Aegean Sea, and the North 

Sea petroleum province (Armstrong, 1972; Wernicke and 

Burchfiel, 1982; Mayer, 1986; Coward and others, 1987). 

Passive continental margins, such as the Gulf Coast 

offshore petroleum province, the Niger delta, and the 

Baltimore Canyon trough offshore from the U.S. east 

coast, form another class of extensional terranes. Such 

regions are characterized by crustal thinning and 

relatively high heat flow during extension. Rifts, such as 

the Midcontinent rift, Red Sea rift, and southern 

Oklahoma aulacogen, are also examples of extensional 

terranes (Hoffman and others, 1974; Keller and others, 

1983; Burke, 1980; Feinstein, 1981; Suppe, 1985). 

Hydrocarbon traps are commonly bounded by extension 

(normal) faults in such terranes; traps in rift settings were 

summarized by Harding (1984). 

Compressional tectonics, the study of fold and 

thrust belts, was put on a firm theoretical basis by 

Chapple (1978) and is a rapidly expanding field of 

research (McClay and Price, 1981; Perry and others, 

1984). Compressional terranes, generally known as 

orogenic belts, are characterized by crustal thickening 

and variable heat flow. Principal examples are the 

Alpine-Himalayan, Appalachian, and Cordilleran 

orogenic belts. Compressional tectonism is the tectonic 

style characteristic also of accretionary wedges 

developed along active convergent plate margins (Boyer, 

1985; Moore and Byrne, 1987). The association of 

hydrocarbons with foreland margins of fold and thrust 

belts has spurred research by the petroleum industry, 
particularly during the 1970's and early 1980's (Perry 

and others, 1984). Hydrocarbon trap styles in 

compressional terranes are summarized by Boyer (1985). 

Wrench-fault tectonics, the study of structures 

associated with major strike-slip faults, is receiving 

increasing attention (for example Biddle and ChristieBlick, 1985). The San Andreas fault system of central 

and southern California (Sylvester, 1984) is a primary 

example of wrench-fault tectonism. Hybrid structural 

styles, such as transpression and transtension, briefly 

discussed below, are not necessarily the result of largescale wrench faulting, and are considered separately. 

Hydrocarbon trap styles associated with wrench-fault 

systems were summarized by Harding (1974) and 

Harding and Lowell (1979). 

Hybrid styles, such as those of transtensional 

and transpressional tectonism, are now being recognized 

and studied (Harland, 1971; Schmidt and Garihan, 1983; 

Sanderson and Marchini, 1984; McCoss, 1986). These 

hybrid styles are found where rocks or basins or orogenic 

belts have been compressed or extended oblique to 

earlier formed planes or directions of weakness, where 

such planes or directions have controlled subsequent 

patterns. Primary examples are the Rocky Mountain 

foreland province, Anadarko basin, Spitzbergen, and the 

Gulf of California (Harland, 1971; Sales, 1968; Schmidt 

and Garihan, 1983; Lorenz, 1984; Harding, 1985; Perry, 

1987 and in press). 

Each style of tectonism represents a different 

structural environment of deformation in terms of basin 

development, heat flow, and plate-tectonic setting. 

Therefore, each will require a different treatment in 

terms of petroleum systems; early identification of 

structurally complex petroleum systems in terms of 

tectonic style is necessary for understanding and 

development of each such system. 

REFERENCES CITED 

Armstrong, R.L., 1972, Low-angle (denudation) faults, 

hinterland of the Sevier orogenic belt, eastern 

Nevada and western Utah: Geological Society of 

America Bulletin, v. 83, p. 1729-1754. 

Biddle, K.T., and Christie-Blick, N., eds., 1985, Strikeslip deformation, basin formation and 

sedimentation: Society of Economic 

Paleontologists and Mineralogists Special 

Publication 37, 386 p. 

Boyer, S.E., 1985, Hydrocarbon trap styles in fold-andthrust belts and related terranes: Proceedings 

1985 Offshore Technology Conference, contrib. 

OTC 4873, p. 297-305. 

Burke, K., 1980, Intracontinental rifts and aulacogens, in 

Continental tectonics: Washington, D.C., 

National Academy of Science, p. 42-49. 

Chapple, W.M., 1978, Mechanics of thin-skinned fold 

and thrust belt: Geological Society of America 

Bulletin, v. 89, p. 1189-1198. 

Coward, M.P., Dewey, J.F., and Hancock, P.L., eds., 

1987, Continental extensional tectonics: 

Geological Society of London Special 

Publication 28, 637 p. 

Feinstein, S., 1981, Subsidence and thermal history of 

the southern Oklahoma aulacogen: Implications 

for petroleum exploration: American Association 

of Petroleum Geologists Bulletin, v. 65, p. 

2521-2533. 

Harding, T.P., 1974, Petroleum traps associated with 

wrench faults: American Association of 

Petroleum Geologists Bulletin, v. 58, p. 

1290-1304. 

--- 1984, Graben hydrocarbon occurrences and 

structural style: American Association of 

Petroleum Goologists Bulletin, v. 68, p. 

333-362. 

--- 1985, Seismic characteristics and identification of 

negative flower structures, positive flower 

structures, and positive structural inversion: 

American Association of Petroleum Geologists 

Bulletin, v. 69, p. 582-600. 

Harding, T.P., and Lowell, J.D., 1979, Structural styles, 

their plate-tectonic habitats and hydrocarbon 

traps in petroleum provinces: American 

Association of Petroleum Geologists Bulletin, v. 

63, p. 1016-1058. 

Harland, W.B., 1971, Tectonic transpression in 

Caledonian Spitzbergen: Geological Magazine, 

v. 108, p. 27-42. 

Hoffman, P., Dewey, J.F., and Burke, K., 1974, 

Aulacogens and their genetic relations to 

geosynclines, with a Proterozoic example from 

Great Slave Lake, Canada, in Dott, R.H., Jr., 

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

geosynclinal sedimentation: Society of 

Economic Paleontologists and Mineralogists 

Special Publication 19, p. 38-55. 

Keller, G.R., Lidiak, E.G., Hinze, W.J., and Braile, L.W., 

1983, The role of rifting in the tectonic 

development of the midcontinent, USA, in 

Morgan, P., and Baker, B.H., eds., Processes of 

continental rifting: Tectonophysics, v. 94, p. 

391-412. 

Lorenz, J.C., 1984, The role of the Lewis and Clark fault 

system during the Laramide orogeny, in 

Northwest Montana and adjacent Canada: 

Montana Geological Society 1984 Field 

Conference and Symposium Guidebook, p. 

221-230. 

McClay, K.R., and Price, N.J., eds., 1981, Thrust and 

nappe tectonics: Geological Society of London 

Special Publication 9, 539 p. 

Structure 37 
McCoss, A.M., 1986, Simple constructions for 

deformation in transpression/transtension zones: 

Journal of Structural Geology, v. 8, 715-718. 

Mayer, L., ed., 1986, Extensional tectonics of the 

southwestern United States: A perspective on 

processes and kinematics: Geological Society of 

America Special Paper 208, 130 p. 

Moore, J.C., and Byrne, T., 1987, Thickening of fault 

zones: A mechanism of melange formation in 

accreting sediments: Geology, v. 15, p. 

1040--1043. 

Perry, WJ., Jr., 1987, Structural development of the 

southeastern margin of the Anadarko basin 

[abs]: Geological Society of America Abstracts 

with Programs, v. 19, p. 176. 

Perry, WJ., Jr., in press, Tectonic evolution of the 

Anadarko basin region, Oklahoma, in Stoesser, 

J., ed., Evolution of sedimentary basinsAnadarko basin: U.S. Geological Survey 

Bulletin 1866A. 

Perry, W.J., Jr., Roeder, D.H., and Lageson, D.R., 

compilers, 1984, North American thrust-faulted 

terranes: American Association of Petroleum 

Geologists Reprint Series 27, 466 p. 

38 Petroleum Systems of the United States 

Ramsay, J.G., 1967, Folding and fracturing of rocks: 

New York, McGraw-Hill, 568 p. 

Sales, J.K., 1968, Crustal mechanics of Cordilleran 

foreland deformation: A regional and scale 

model approach: American Association of 

Petroleum Geologists Bulletin, v. 52, p. 

2016-2044. 

Sanderson, DJ., and Marchini, W.R.D., 1984, 

Transpression: Journal of Structural Geology, v. 

6, p. 449-458. 

Schmidt, CJ., and Garihan, J.M., 1983, Laramide 

tectonic development of the Rocky Mountain 

foreland of southwestern Montana, in Lowell, 

J.D., ed., Rocky Mountain foreland basins and 

uplifts: Denver, Rocky Mountain Association of 

Geologists, p. 271-294. 

Suppe, J., 1985, Principles of structural geology: 

Englewood Cliffs, New Jersey, Prentice-Hall, 

537 p. 

Sylvester, A.G., compiler, 1984, Wrench fault tectonics: 

American Association of Petroleum Geologists 

Reprint Series 28, 374 p. 

Wernicke, B.P., and Burchfiel, B.C., 1982, Modes of 

extensional tectonics: Journal of Structural 

Geology, v. 4, p. 105-115. 
Types of Seals as Related to 

Migration and Entrapment of Hydrocarbons 

By Gregory F. Ulmishek 

The importance of seals as a decisive factor in 

controlling migration of hydrocarbons and their 

entrapment and preservation through geologic time is 

often underestimated by petroleum geologists, especially 

in a regional geologic analysis. 

Theoretically, the properties of rocks that 

control their seal capacity are well understood on the 

basis of laboratory experiments (Prozorovich, 1972; 

Schowalter, 1979; Downey, 1984). The capacity of a 

seal is defined by the capillary entry (or hydrocarbonwater displacement) pressure, which depends on the 

fluid's interfacial tension, wettability of rocks, and the 

radius of pore throats. A bed may be considered a seal 

if the constituting rock is characterized by a capillary 

pressure that exceeds the buoyancy force of the 

underlying continuous hydrocarbon phase (pool or 

filaments in oil-stained rock). Theoretically, the seal 

capacity of a bed does not depend on its thickness and 

ductility, but mainly on the size of the connected pore 

throats. A bed remains impermeable to oil and gas as 

long as the buoyancy force does not exceed the capillary 

entry pressure in largest pores. When this happens, a 

breakthrough occurs, and once a continuous oil (or gas) 

phase is established through the seal, a large part of the 

hydrocarbons escapes upward until the capillary pressure 

causes the seal to reestablish itself (Schowalter, 1979). 

Hydrodynamic forces can significantly enhance or reduce 

the seal capacity of a bed depending on the direction of 

the water movement. Downward-directed hydrodynamic 

gradients enhance seals, whereas upward flow will 

decrease sealing capacity of rocks. 

Diffusion of hydrocarbon molecules through a 

seal is a much less effective mechanism for transport of 

oil and gas than continuous phase migration. The rate of 

diffusion for a particular compound depends on its 

molecular size and the volume of water-filled connected 

pore space in a seal. Most probably, diffusion does not 

affect secondary migration and preservation of oil pools, 

but in some cases may be significant for preservation of 

gas accumulations through extended periods of geologic 

time (Leythaeuser and others, 1982). 

In a geologic environment, however, other 

large-scale qualities of a seal that cannot be described 

from physical analyses of cores are more important. The 

most significant of these qualities are resistance to brittle 

fracturing, lateral continuity and areal extent, pore 

overpressure, thickness, and homogeneity. Migration of 

hydrocarbons in geologic conditions, especially vertical 

migration, occurs through fracture systems, because even 

the smallest fracture represents an extraordinary conduit 

for migrating fluids (Schowalter, 1979). On the basis of 

ability of a rock to resist fracturing and to quickly seal 

fault planes, the seals can be subdivided into brittle and 

plastic. Other classifications based on the lithologic 

composition (such as evaporite, shale, or carbonate seals; 

Nalivkin, 1983) chiefly emphasize the same quality. 

Plastic seals (evaporites, uncompacted shales) are the 

best barriers to hydrocarbon migration. Brittle seals are, 

as a rule, only locally impermeable. Regionally, they 

can be fairly good seals only if their quality is enhanced 

by a downward hydrodynamic flow as is known, for 

example, for the Devonian Kynov Shale in the TimanPechora province of the USSR (Chemikov and 

Sverchkov, 1974). 

According to their lateral continuity and areal 

extent, seals can be separated into regional and local. 

Although both groups can control oil and gas pools, the 

effect of regional seals on the productivity of a region is 

much more significant. Regional seals control the entire 

hydrodynamic regime in underlying permeable 

formations and, hence, strongly affect the migration and 

accumulation of hydrocarbons and preserve oil and gas 

pools from destruction. Over large areas, good regional 

seals prevent hydrocarbons from escaping upward and 

thus create a natural boundary for a petroleum system (or 

independent petroliferous system, IPS, according to 

Ulmishek, 1986). Local seals of small extent are 

effective only in the presence of a regional seal higher in 

the section. Significant hydrocarbon reserves in pools 

controlled only by local seals are uncommon and usually 

indicate strong predominance of vertical over lateral 

migration in formation of these pools. 

Overpressured shale formations (undercompacted shales) are excellent seals owing to the 

hydrodynamic gradient directed downward into 

underlying permeable rocks that usually have lower 

reservoir pressure. This hydrodynamic gradient 

effectively prevents hydrocarbons from escaping from 

rocks beneath the overpressured shale into overlying 

formations. On this basis, the overpressured shales are 

sometimes classified as the hydrodynamic class of seals 

versus other seals that are not characterized by abnormal 

pressure and whose sealing quality is controlled only by 

the structure of the pore space (Beka and Vysotskiy, 

Types of Seals as Related to Migration and Entrapment of Hydrocarbons 39 
1976). Additionally, overpressured shale formations are 

usually thick and ductile due to a high amount of pore 

water. 

The thickness is evidently an important quality 

of a seal, especially of a regional seal. Greater thickness 

terminates minor defects, such as occasional pore 

channels and fractures, inside the seal, and decreases 

chances for the appearance of windows of permeability 

that can be created by local facies changes, erosion, or 

faulting. In the case of faulting, thick seals are 

especially important because even small-scale faulting 

can place the bottom of a relatively thin seal against 

permeable rocks and thus cut the migration paths or 

allow traps to leak. The vertical homogeneity of a seal 

is, to a significant degree, analogous to its thickness. 

Nonhomogeneous seals that include interbeds of 

permeable rocks, such as sandstone and siltstone, are 

essentially less reliable due to the small thickness of 

individual shale beds. Measurements of the 

concentration and composition of dispersed bitumen in 

shale and siltstone over a number of oil pools in the 

USSR showed that the height of penetration of migrated 

oil into the seals varied from 30 to 50 m. The content of 

vertically migrated oil in poor seals (for example, in 

siltstone interbeds) is only an order of magnitude less 

than in the underlying productive strata (Larskaya and 

Polyanskaya, 1987). Thus, for example, a shale 50 m 

thick is generally a better seal than a 100-m-thick 

alternation of shale and siltstone layers in which the 

thickness of shale totals the same 50 m. 

In discussing petroleum systems, it seems 

appropriate to classify seals by their extent into regional 

and local, and by their quality into perfect and imperfect. 

Regional seals are those that are continuous over all or 

most of the area occupied by a petroleum system, while 

local seals are developed only in separate zones of the 

system. Perfect seals are represented by formations that 

are characterized by plasticity at in-situ conditions or 

downward-directed hydrodynamic gradient (Ulmishek, 

1986). These formations are composed of salt, 

anhydrite, undercompacted overpressured shale, and 

plastic shale usually having a high percentage of smectite 

minerals or plastic kerogen. Possibly permafrost (with 

associated gas hydrates) also fits the perfect type, 

although recent data call into question its essentially 

absolute impermeability (Starobinets and Murogova, 

1985; Shershukov and Khudyakov, 1986). Seals of the 

imperfect type are composed of dense but brittle rocks 

such as well-compacted shale (often intercalated with 

siltstone), marl, and dense carbonate. These seals lose 

their impermeability in zones of faulting and fracturing. 

Only locally can they control hydrocarbon pools in quiet 

tectonic regimes. The lifespan of many perfect seals 

(probably except only anhydrite) is usually restricted to a 

certain period of geologic time. After burial to 

40 Petroleum Systems of the United States 

significant depths, most perfect seals lose their quality 

owing to dehydration and compaction, in the case of 

plastic shale, and salt doming with complete squeezing 

of salt from the rim synclines, in the case of thick salt 

beds. Regional perfect seals control the vertical extent 

of petroleum systems; other types of seals of this 

classification affect the distribution of oil and gas pools 

inside the systems. 

REFERENCES CITED 

Beka, K., and Vysotskiy, I., 1976, Geology of oil and 

gas (Geologiya nefti i gaza): Moscow, Nedra, 

591 p. 

Chemikov, K.A., and Sverchkov, G.P., eds., 1974, 

Criteria of the separate assessment of oil and 

gas potential: Trudy VNIGNI, v. 334, 

Leningrad, Nedra, 184 p. 

Downey, M.W., 1984, Evaluating seals for hydrocarbon 

accumulation: American Association of 

Petroleum Geologists Bulletin, v. 68, no. 11, p. 

1752-1763. 

Larskaya, E.S., and Polyanskaya, V.S., 1987, Evaluation 

of the quality of seals controlling oil and gas 

pools: Geologiya Nefti i Gaza, no. 1, p. 22-25. 

Leythaeuser, D., Schaefer, R.G., and Yukler, A., 1982, 

Role of diffusion in primary migration of 

hydrocarbons: American Association of 

Petroleum Geologists Bulletin, v. 66, no. 4, p. 

408-429. 

Nalivkin, V.D., ed., 1983, Genesis and forecast of oil, 

gas, and bitumen accumulations 

(Proiskhozhdenie i prognozirovanie skopleniy 

gaza, nefti i bitumov): Leningrad, Nedra, 272 p. 

Prozorovich, G.E., 1972, Seals for oil and gas pools: 

Moscow, Nedra, 216 p. 

Schowalter, T.T., 1979, Mechanics of secondary 

hydrocarbon migration and entrapment: 

American Association of Petroleum Geologists 

Bulletin, v. 63, no. 5, p. 723-760. 

Shershukov, V.V., and Khudyakov, V.N., 1986, 

Migration of coal gases in conditions of 

permafrost: Sovetskaya Geologiya, no. 5, p. 

30--32. 

Starobinets, I.S., and Murogova, R.N., 1985, Sealing and 

conducting role of rocks of the cryogenic zone 

in relation to migrating hydrocarbons: 

Geologiya Nefti i Gaza, no. 1, p. 24-27. 

Ulmishek, G., 1986, Stratigraphic aspects of petroleum 

resource assessment, in Rice, D.D., ed., Oil and 

gas assessment, methods and applications: 

American Association of Petroleum Geologists 

Studies in Geology 21, p. 59-68. 
Sandstone Reservoirs 

By Christopher J. Schenk 

Sandstone bodies are an important part of 

petroleum systems for two reasons; first, they act as 

conduits for migrating fluids, and second, sandstones 

serve as reservoirs. Current research efforts on 

sandstones generally focus on determining the types and 

causes of sandstone heterogeneity, which is the spatial 

variation of physical and chemical properties in a 

sandstone that generally exerts a deleterious effect on 

fluid flow. Heterogeneity controls the efficacy of a 

sandstone to act as a conduit or a reservoir for 

petroleum. An understanding of fluid-flow pathways in 

sandstone and their evolution is critical for predictive 

models of fluid migration and associated diagenetic 

modifications. From a pragmatic viewpoint, successful 

secondary and tertiary recovery of petroleum is 

dependent on a detailed understanding of fluid-flow 

pathways within sandstone reservoirs. 

Heterogeneity is largely a function of 

sedimentologic characteristics and diagenetic 

modifications of the sandstone (Weber, 1986). A 

heirarchy of heterogeneities, outlined by Weber (1986), 

is modified for the following discussion. The largest 

scale of heterogeneity is sandstone bodies and their 

boundaries. The geometry (length, width, thickness) of a 

sandstone body is controlled by tectonic, sedimentsupply, sea-level, and depositional environment factors 

(Miall, 1984). Knowledge of regional sandstone-body 

geometry (ribbon or sheet) is critical for predicting 

possible routes of petroleum migration. Sandstone 

bodies can be defined as simple (single genetic unit) or 

complex (multiple, stacked genetic units), but most 

appear to be complex deposits (Friend, 1983; Tyler and 

Ambrose, 1985; Galloway and Cheng, 1985; Tyler and 

others, 1986; Ebanks and Weber, 1987). Boundaries can 

be enclosing fine-grained clastics, evaporites, fault 

contacts, or unconformities. These boundaries are 

important to characterize because they commonly define 

the continuity of fluid-flow pathways in a regional 

context (Galloway, 1984). 

The second scale of heterogeneity is what are 

termed "baffles" to fluid flow within a sandstone. Baffles 

are manifest mainly by mudstone layers that may range 

from continuous to discontinuous across the sandstone 

body (Weber, 1982; Haldorsen and Chang, 1986). These 

finer grained interbeds are considered by some workers 

to be the most important form of heterogeneity affecting 

fluid flow either vertically or horizontally through a 

sandstone body (Haldorsen and Chang, 1986). Baffles 

could also be formed by diastems or unconformities 

within the sandstone body, such as the erosional surfaces 

between fluvial-channel sandstones in a multistory 

sandstone body. Baffles of this type could be even more 

detrimental to fluid flow if they were the focus of 

subsequent diagenetic alterations that reduce 

permeability. 

Facies represent the third scale of heterogeneity. 

A facies represents an aspect of a sand body that is 

sufficiently unique to be described separately from the 

rest of the sandstone; examples include cosets of ripplelaminated sandstones, cosets of large-scale cross-strata 

and channel sandstones (Walker, 1984; Reading, 1978). 

One sandstone may contain numerous facies. Facies 

form what are now being recognized as "flow units" 

within sandstone bodies; each flow unit exhibits some 

common range of porosity and permeability values 

(Hearn and others, 1986). 

Individual sedimentary structures compose the 

fourth scale of heterogeneity. The geometry of a 

sedimentary structure dictates the degree of anisotropy of 

fluid flow at this scale. A structure can be classified as 

small-scale or large-scale (Allen, 1984); strata within a 

sedimentary structure can be planar, low-angle, or highangle (cross-strata); the shape of the bounding surfaces 

can be tabular-planar, wedge-planar, or trough-shaped in 

cross sections normal to the paleocurrent direction. The 

orientation and shape of a set of strata or cross-strata can 

constrain the continuity of fluid flow. Types of 

stratification exert a profound influence on directional 

permeabilities. Goggin and others (1986) reported that 

interdune, eolian ripple, and eolian sandflow cross-strata 

exhibited significant differences in permeability within an 

eolian sandstone. These three elements form the basic 

building blocks for most eolian deposits, and thus can 

generally be expected to influence permeabilities in 

eolian sand bodies. In a similar analysis, Hearn and 

others (1986) concluded that flow units differentiated 

mainly by sedimentary structures in a shelf sandstone 

exhibited significant differences in permeabilities. 

Sedimentary structures are composed of bundles 

of similar strata or laminae: each stratum has a unique 

grain size distribution, and possible vertical or horizontal 

grain-size grading (Hunter, 1977; Sallenger, 1979; 

Schenk, 1983, 1987). These characteristics can result in 

a fifth scale of heterogeneity, as these textural 

characteristics may influence subsequent diagenetic 

alterations on a stratum-by-stratum basis (Evans, 1983). 

Sandstone Reservoirs 41 
Diagenetic alterations are the sixth type of 

heterogeneity. Unlike the several scales of heterogeneity 

formed at the time of deposition, diagenetic alterations 

can evolve with time (Pollastro, 1985), they can form at 

any time in the burial history of a sandstone, and the 

magnitude of an alteration can change, enhancing or 

decreasing reservoir quality (through secondary porosity 

or compaction; Bjorlykke, 1984; Houseknecht, 1987). 

Phases of sandstone diagenesis are best studied in a 

burial history context, as a function of both the timetemperature exposure of the sandstone (Schmoker and 

Gautier, 1988) and the evolving fluid chemistry of the 

pore-water system (Surdam and others, 1984; Wood and 

Hewett, 1984 ). 

Fracture systems represent the final type of 

heterogeneity that affects fluid flow. Unlike most other 

forms of heterogeneity, fractures serve to enhance 

permeability and flow continuity (DoRozario and Baird, 

1987). However, fractures can have a detrimental effect 

in that they may cause premature water influx into the 

reservoir or decrease the effectiveness of secondary or 

tertiary recovery projects. Timing of fracturing, fracture 

orientation, and fracture openness are all important to 

consider (Weber, 1986). 

Predicting types of sandstone heterogeneity 

appears to become more difficult as the scale of 

heterogeneity decreases (Weber, 1986). In particular, 

diagenetic and fracture patterns are quite variable in a 

regional sense, and are especially difficult to predict in 

areas of limited data. 

REFERENCES CITED 

Allen, J.R.L., 1984, Sedimentary structures: Their 

character and physical basis: Developments in 

Sedimentology, v. 30, 663 p. 

Bjorlykke, K., 1984, Formation of secondary porosity: 

How important is it?, in McDonald, D.A., and 

Surdam, R.C., eds., Clastic diagenesis: American 

Association of Petroleum Geologists Memoir 37, 

p. 277-288. 

DoRozario, R.F., and Baird, B.W., 1987, The detection 

and significance of fractures in the Palm Valley 

gas field: Australian Petroleum Exploration 

Association Journal, v. 27, part 1, p. 264-280. 

Ebanks, W.J., and Weber, J.P., 1987, Shallow heavy oil 

deposit in a Pennsylvanian fluvial sandstone 

reservoir, Eastburn field, Missouri, in Meyer, 

R.F., ed., Exploration for heavy crude oil and 

natural bitumen: American Association of 

Petroleum Geologists Studies in Geology 25, p. 

327-339. 

Evans, C.C., 1983, Aspects of depositional and 

diagenetic history of the Miami; LimestoneControl of primary sediment fabric over early 

42 Petroleum Systems of the United States 

cementation and porosity development: Coral 

Gables, Fla., University of Miami, M.S. thesis, 

130 p. 

Friend, P.F., 1983, Toward the field classification of 

alluvial architecture or sequence, in Collinson, 

J.D., and Lewin, J., eds., Modern and ancient 

fluvial systems: International Association of 

Sedimentologists Special Publication 6, p. 

345-354. 

Galloway, W.E., 1984, Hydrologic regimes of sandstone 

diagenesis, in McDonald, D.A., and Surdam, 

R.C., eds., Clastic diagenesis: American 

Association of Petroleum Geologists Memoir 37, 

p. 3-14. 

Galloway, W.E., and Cheng, E.S., 1985, Reservoir facies 

architecture in a microtidal barrier system-Frio 

Formation, Texas Gulf coast: Texas Bureau of 

Economic Geology Report of Investigations 144, 

36 p. 

Goggin, D.J., Chandler, M.A., Kocurek, G., and Lake, 

L.W., 1986, Patterns of permeability in eolian 

deposits: Society of Petroleum Engineers/U.S. 

Department of Energy Preprint 14893, p. 

181-188. 

Haldorsen, H.H., and Chang, D.M., 1986, Notes on 

stochastic shales; from outcrop to simulation 

model, in Lake, L.W., and Carroll, H.B., Jr., 

eds., Reservoir characterization: New York, 

Academic Press, p. 445-483. 

Hearn, C.L., Hobson, J.P., and Fowler, M.L., 1986, 

Reservoir characterization for simulation, 

Hartzog Draw field, Wyoming, in Lake, L.W., 

and Carroll, H.B., Jr., eds., Reservoir 

characterization: New York, Academic Press, p. 

341-371. 

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, p. 633-642. 

Hunter, R.E., 1977, Basic types of stratification in small 

eolian dunes: Sedimentology, v. 24, p. 361-387. 

Miall, A.D., 1984, Principles of sedimentary basin 

analysis: New York, Springer-Verlag, 490 p. 

Pollastro, R.M., 1985, Mineralogical and morphological 

evidence for the formation of illite at the 

expense of illite/smectite: Clays and Clay 

Minerals, v. 33, p. 265-274. 

Reading, H.G., 1978, Facies, in Reading, H.G., ed., 

Sedimentary environments and facies: London, 

Blackwell, p. 4-15. 

Sallenger, A.H., 1979, Inverse grading and hydraulic 

equivalence in grain-flow deposits: Journal of 

Sedimentary Petrology, v. 49, p. 553-562. 

Schenk, C.J., 1983, Textural and structural characteristics 
of some experimentally formed eolian strata, in 

Brookfield, M.E., and Ahlbrandt, T.S., eds., 

Eolian sediments and processes: Developments 

in Sedimentology, v. 38, p. 41-49. 

--- 1987, Primary textures in experimentally formed 

oolite cross-strata: U.S. Geological Swvey 

Bulletin 1670, 11 p. 

Schmoker, J.W., and Gautier, D.L., 1988, Dependence of 

sandstone porosity upon thermal maturity-An 

approach to prediction and interbasinal 

comparison of porosity: U.S. Geological Swvey 

Circular 1025, 56 p. 

Surdam, R.C., Boese, S.W., and Crossey, L.J., 1984, The 

chemistry of secondary porosity, in McDonald, 

D.A., and Surdam, R.C., eds., Clastic diagenesis: 

American Association of Petroleum Geologists 

Memoir 37, p. 127-150. 

Tyler, N., and Ambrose, W.A., 1985, Facies architecture 

and production characteristics of strandplain 

reservoirs in the Frio Formation, Texas: Texas 

Bureau of Economic Geology Report of 

Investigations 146, 42 p. 

Tyler, N., Gholston, J.C., and Ambrose, W.A., 1986, 

Genetic stratigraphy and oil recovery in an 

Upper Cretaceous wave-dominated deltaic 

reservoir, Big Wells (San Miguel) field, South 

Texas: Texas Bureau of Economic Geology 

Report of Investigations 153, 38 p. 

Walker, R.G., 1984, General introduction: Facies, facies 

sequences and facies models, in Walker, R.G ., 

ed., Facies models, 2d ed.: Geoscience Canada 

Reprint Series 1, p. 1-9. 

Weber, K.J., 1982, Influence of common sedimentary 

structures on fluid flow in reservoir models: 

Journal of Petroleum Technology, v. 34, p. 

665-672. 

--- 1986, How heterogeneity affects oil recovery, in 

Lake, L.W., and Carroll, H.B., Jr., eds., 

Reservoir characterization: New York, 

Academic Press, p. 487-544. 

Wood, J.R., and Hewett, T.A., 1984, Reservoir 

diagenesis and convective fluid flow, in 

McDonald, D.A., and Surdam, R.C., eds., 

Clastic diagenesis: American Association of 

Petroleum Geologists Memoir 37, p. 99-110. 

Sandstone Reservoirs 43 
Natural Gas 

By Keith A. Kvenvolden 

Natural gas is commonly defined as the gaseous 

phase of petroleum, but microbial gas, which has no 

direct connection with petroleum, is also referred to as 

natural gas. The components of natural gas are mainly 

hydrocarbons of very low molecular weights 

accompanied by gaseous nonhydrocarbons such as 

carbon dioxide, nitrogen, hydrogen sulfide, helium, and 

hydrogen. In a typical reservoir, natural gas contains 70 

to 100 percent methane, 1 to 10 percent ethane, and 

lower percentages to trace amounts of higher molecular 

weight hydrocarbons up to about nonane (Hunt, 1979). 

Natural gas composed almost entirely of methane is 

called a dry gas; if the proportion of ethane and larger 

hydrocarbons exceeds about 4 percent, the mixture is 

called a wet gas. The terms sweet and sour refer to the 

low or high content of hydrogen sulfide. Wherever 

natural gas accompanies oil, the gas is called an 

associated gas; if the gas no longer accompanies oil, the 

gas is called a nonassociated gas. 

The components of natural gas have multiple 

sources, but the dominant hydrocarbon components result 

from the alteration or degradation of organic matter in 

fine-grained sediment or sedimentary rocks by a series of 

complex chemical reactions (Rice and Claypool, 1981). 

The extent of these reactions is controlled primarily by 

temperature and duration of heating during geologic 

time. The processes of formation of natural gas take 

place during three stages of increasing chemical 

alteration (maturity) called diagenesis, catagenesis, and 

metagenesis (Tissot and Welte, 1984). 

During diagenesis, both biochemical and 

thermochemical processes take place, but because of the 

low temperatures involved (<50 °C), only biochemical 

processes are geologically significant, generating 

extensive volumes of microbial methane through 

methanogenesis. More than 20 percent of the world's 

discovered gas reserves are of microbial origin (Rice and 

Claypool, 1981). 

With increasing temperatures and advancing 

geologic time, a full range of hydrocarbons in natural gas 

is produced from the thermal alteration of organic matter 

during the maturation stage of catagenesis. This stage is 

the principal one for oil generation, during which 

significant amounts of wet natural gas are produced from 

the alteration of organic matter (kerogen) as well as from 

the· alteration of previously formed oil. 

At the end of the catagenesis stage, kerogen 

becomes highly polymerized and stable. With increasing 

44 Petroleum Systems of the United States 

temperatures and time during the metagenesis stage, 

methane alone results from the high-temperature cracking 

of remaining hydrocarbons, because hydrocarbons larger 

than methane are destroyed much more rapidly than they 

are formed (Rice and Claypool, 1981). 

Thus dry natural gas (mainly methane) is 

generated during the maturity stages of diagenesis and 

metagenesis whereas wet natural gas (methane plus 

larger molecules) is formed during catagenesis. Methane 

resulting from various processes can be distinguished by 

measurements of its carbon and often its hydrogen 

isotopic compositions. The range of carbon isotopic 

compositions of methane in commercial natural gas 

deposits range from about -75 to -25 permit relative to 

the Peedee Belemnite Standard (Fuex, 1977). The limits 

on this range are not fixed. Within this range, methane 

at various maturity stages has specific isotopic signatures. 

When methane is formed microbially, two 

primary methanogenic pathways can be distinguished 

using carbon and hydrogen isotopic compositions of this 

gas (Whiticar and others, 1986). Although both 

pathways may occur in both marine and freshwater 

sediment, carbon dioxide reduction to form methane is 

the dominant pathway in the sulfate-free zone of marine 

sediment, whereas acetate-type fermentation is the 

principal pathway in freshwater sediment. Methane in 

marine sediment has isotopic compositions ranging from 

-110 to -60 permit for carbon and from -250 to -170 

permil for hydrogen. (Hydrogen isotopic compositions 

are reported relative to standard mean ocean water, 

SMOW). In contrast, methane from freshwater sediment 

ranges from -65 to -50 permit for carbon and from -400 

to -250 permit for hydrogen. Methane in shallow dry 

gas deposits worldwide has carbon isotopic compositions 

ranging from about -85 to -55 permit (Rice and 

Claypool, 1981). 

Methane formed during catagenesis is 

commonly referred to as thermogenic gas. The carbon 

isotopic composition of this methane ranges between 

about -60 and -40 permil (Fuex, 1977) and the hydrogen 

isotopic composition from about -300 to -140 permit 

(Schoen, 1983). Most natural wet gas deposits in the 

world contain thermogenic methane (Hunt, 1979). 

Metagenic gas is dry gas formed at temperatures 

in excess of about 150 °C. The isotopic compositions of 

methane formed during metagenesis ranges from about 

-40 to -20 permil for carbon and from -150 to -130 

permil for hydrogen (Tissot and Welte, 1984). The 
isotopic signatures of methane and other hydrocarbons in 

natural gas along with molecular compositions of the gas 

mixtures provide means by which natural gases can be 

characterized genetically (Schoen, 1983). Such 

characterization is valuable in petroleum exploration, 

allowing an assessment of source, origin, and migration 

of natural gas. 

Proved and currently recoverable world 

resources of conventional natural gas have been 

estimated to be 2,329 to 2,594 trillion cubic feet (tcf) or 

6.6x1013 to 7.3x1013 m3, and the estimated total 

remaining recoverable resources are 7,900 to 9,200 tcf or 

2.2x1014 to 2.6x1014 m3 (Parent, 1980). Besides these 

conventional natural gas deposits, a large potential 

natural gas resource exists within reservoirs that are not 

producible with conventional drilling and production 

techniques. These reservoirs of nonconventional natural 

gas include geopressured aquifers, coal seams, organicrich shales, tight sands, and gas hydrates. In recent 

years, interest in the potential supply of natural gas from 

nonconventional sources has increased as has information 

about them through studies supported by the Department 

of Energy. Improvements in drilling and production 

technology accompanied by a more favorable economic 

climate will likely make it possible in the future to 

recover significant volumes of natural gas from some of 

these sources (Potential Gas Committee, 1981). 

REFERENCES CITED 

Fuex, A.N., 1977, The use of stable carbon isotopes in 

hydrocarbon exploration: Journal of 

Geochemical Exploration, v. 7, p. 155-188. 

Hunt, J .M., 1979, Petroleum geochemistry and geology: 

San Francisco, W.H. Freeman, 617 p. 

Parent, J.D., 1980, A survey of the United States and 

total world production, proved reserves, and 

remaining recoverable resources of fossil fuels 

and uranium: Chicago, The Institute of Gas 

Technology, 140 p. 

Potential Gas Committee, 1981, Potential supply of 

natural gas in the United. States (as of December 

31, 1980): Potential Gas Agency, Golden, 

Colorado, Colorado School of Mines, 119 p. 

Rice, D.D., and Claypool, G.E., 1981, Generation, 

accumulation, and resource potential of biogenic 

gas: American Association of Petroleum 

Geologists Bulletin, v. 65, p. 5-25. 

Schoen, M., 1983, Genetic characterization of natural 

gases: American Association of Petroleum 

Geologists Bulletin, v. 67, p. 2225-2238. 

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

and occurrence-A new approach to oil and gas 

exploration: Berlin, Springer-Verlag, 538 p. 

Whiticar, M.J., Faber, E., and Schoell, M., 1986, 

Biogenic methane formation in marine and 

freshwater environments: C02 reduction vs. 

acetate fermentation-Isotopic evidence: 

Geochimica et Cosmochimica Acta, v. 50, p. 

693-709. 

Natural Gas 45 
Natural Gas Hydrate 

By Timothy S. Collett and Keith A. Kvenvolden 

Gas hydrates are a type of inclusion compound 

or clathrate formed as icelike mixtures of gas and water 

in which gas molecules are contained within a solid cage 

framework of water molecules. Large quantities of 

natural gas, mainly methane, can be trapped in sediments 

in the form of gas hydrates. The necessary pressure and 

temperature conditions for the formation of gas hydrates 

are found at high latitudes in permafrost regions and at 

low and high latitudes in oceanic sediment of outer 

continental margins and ocean basins (reviewed by 

Kvenvolden and McMenamin, 1980). Gas hydrates can 

be expected to occur in these two regions wherever the 

supply of methane from microbial and thermogenic 

sources is sufficient to stabilize the gas hydrate structure. 

In practical terms, gas hydrates of permafrost regions can 

occur at subsurface depths ranging from about 130 to 

2,000 m, depending on subsurface temperatures. In 

sediment of outer continental margins, at water depths 

exceeding 300 to 500 m, gas hydrates can occur near the 

bottom to sub-bottom depths of about 1,000 m; these 

limits depend on bottom-water temperatures and 

geothermal gradients. 

An attractive aspect of gas hydrates as a 

potential energy resource is that they may contain or trap 

enormous volumes of methane at shallow subsurface 

depths. One volume of gas hydrate may hold about 164 

volumes of methane (Davidson and others, 1978). At 

depths less than about 1,300 m, gas hydrates contain 

more gas than can be trapped in an equal volume of free 

space. At greater depths there is no volumetric advantage 

to gas hydrates (reviewed by Hunt, 1979). An important 

asset of gas hydrates may be their impermeability, which 

provides a barrier or seal under which free gas can 

accumulate (Hedberg, 1980). 

Although the greatest volume of methane occurs 

in gas hydrates of outer continental margins, it is the gas 

hydrates of permafrost regions that are of greatest 

exploration interest because these potential gas deposits 

occur on land and not beneath great water depths. 

During the 1940's, the pressure and temperature 

conditions in permafrost regions were recognized as 

appropriate for gas-hydrate occurrence (Katz, 1971). By 

1970, well logging and formation tests in the 

Messoyakha gas field of western Siberia conclusively 

showed the presence of gas hydrates (Makogon and 

others, 1972); in fact, this was the first gas hydrate field 

where an attempt was made to produce gas from the 

hydrate commercially. Besides the western Siberia 

46 Petroleum Systems of the United States 

platform, where the Messoyakha gas field is located, 

other permafrost areas of the northern USSR, including 

the Timan-Pechora province, the eastern Siberian craton, 

and the northeastern USSR and Kamchatka areas, are 

believed to have gas hydrate deposits (Cherskiy and 

others, 1985). 

The occurrences of permafrost-associated gas 

hydrates in the North American Arctic have been 

reviewed by Kvenvolden and Grantz (in press). Well-log 

responses consistent with the presence of gas hydrates 

were obtained in the Mackenzie Delta, Sverdrup Basin, 

Arctic Platform and Islands, and the North Slope of 

Alaska. The only known confirmation of the presence of 

inplace natural gas hydrates on the North Slope of 

Alaska was obtained in 1972, when Arco and Exxon 

were successful in recovering samples of gas hydrates in 

pressure-core barrels (reviewed by Collett and 

K venvolden, 1987). These samples came from a well 

located about 10 km west of the giant Prudhoe Bay oil 

field. 

A study of wire-line logs from 134 wells from 

the North Slope of Alaska indicates possible gas hydrates 

in 39 of these wells (Collett, 1983; Collett and others, 

1988). The depths between which the occurrence of gas 

hydrate is inferred from well logs range from 130 to 

1,100 m. Most of the gas hydrates appear to be 

geographically restricted to the Kuparuk River area. Gas 

hydrates there occur in about four to six laterally 

continuous units. The gas hydrates are restricted to a 

series of sandstones and conglomerates that are 

interbedded with multiple thick siltstone units. The gashydrate-bearing sandstones and conglomerates represent a 

nonmarine delta-front to delta-plain depositional package. 

Resource estimates for gas hydrates are variable 

and highly speculative owing to incomplete knowledge 

of gas hydrate occurrences and poor methods for 

estimating reserves in known occurrences; the Potential 

Gas Committee (1981) summarized such estimates. For 

continental Alaska, estimates of the volume of natural 

gas in gas hydrates ranges from 11 to 25,000 trillion 

cubic feet (tcf) or 3.1x1011 to 7,100x1011 m3• The actual 

value is probably nearer the lower limit of this range. 

Although the amount of methane in gas hydrates 

is undoubtedly large, current technology cannot extract 

hydrated gas economically even if production wells are 

able to drill into the gas hydrates (Franklin, 1980). 

Penetration of gas hydrates during drilling may be 

hazardous; however, special procedures including slow 
drilling rates and carefully controlled mud weights and 

temperatures have proved to be successful in wells 

located in the Canadian Beaufort Sea (Weaver and 

Stewart, 1982). 

Current research on gas hydrates in Alaska is 

directed toward detailing the geologic setting and 

formational characteristics of these deposits through 

temperature and borehole gravity surveys, analyses of 

pore fluids, field mapping and sampling, and seismic 

modeling. Goals of the work are to verify the presence 

of gas hydrates in this region through core recovery, to 

develop a model for gas hydrate formation and 

occurrence on the North Slope, to determine the amount 

of methane that is associated with these gas hydrates, 

and to establish the potential for these gas hydrate 

deposits as unconventional energy resources. 

REFERENCES CITED 

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., 1983, Detection and evaluation of natural 

gas hydrates from well logs, Prudhoe Bay, 

Alaska: Fairbanks, University of Alaska, M.S. 

thesis, 78 p. 

Collett, T.S., Bird, K.J., 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. 

Collett, T.S., and Kvenvolden, K.A., 1987, Evidence of 

naturally occurring gas hydrates on the North 

Slope of Alaska: U.S. Geological Survey OpenFile Report 87-255, 8 p. 

Davidson, D.W., El-Defrawy, M.K., Fuglem, M.O., and 

Judge, A.S., 1987, Natural gas hydrates in 

northern Canada: Proceedings Third 

International Conference on Permafrost, v. 1, p. 

937-943. 

Franklin, L.J., 1980, In-situ hydrates-A potential gas 

source: Petroleum Engineering International, v. 

52, no. 13, p. 112-122. 

Hedberg, H.D., 1980, Methane generation and petroleum 

migration, in Roberts, W.H., III, and Cordell, 

R.J., eds., Problems of petroleum migration: 

American Association of Petroleum Geologists 

Studies in Geology 10, p. 179-206. 

Hunt, J .M., 1979, Methane hydrates, in Hunt, J .M., 

Petroleum geochemistry and geology: San 

Francisco, W.H. Freeman, p. 156-162. 

Katz, D.L., 1971, Depths to which frozen gas fields (gas 

hydrates) may be expected: Journal of Petroleum 

Technology, v. 23, p. 419-423. 

K venvolden, K.A., and Grantz, Arthur, in press, Gas 

hydrates of the Arctic Ocean region, in Grantz, 

A., Johnson, L., and Sweeney, J.F., eds., The 

Arctic Ocean region: Boulder, Geological 

Society of America, Geology of North America 

series, v. 50. 

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. 

Makogon, Yu.F., Trebin, F.A., 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-Earth Science Section 196, p. 197-200. 

Potential Gas Committee, 1981, Potential supply of 

natural gas in the United States (as of December 

31, 1980): Golden, Colorado, Potential Gas 

Agency, Colorado School of Mines, 119 p. 

Weaver, J.S., and Stewart, J.M., 1982, In-situ hydrates 

under the Beaufort Sea Shelf, in French, M.H., 

ed., Proceedings 4th Canadian Permafrost 

Conference, 1981 (Roger J .E. Brown Memorial 

Volume): National Research Council of Canada, 

p. 312-319. 

Natural Gas Hydrate 47 
Tight Gas Reservoirs 

By Ben E. Law and Charles W. Spencer 

Low-permeability (tight) gas reservoirs are 

considered to have an estimated inplace gas permeability 

of 0.1 millidarcy (md) or less. Tight reseiVoirs contain 

major resources of gas; about 1 trillion cubic feet (tcf) of 

gas per year is produced from these reservoirs. The 

National Petroleum Council (1980) estimated the gas-inplace resource for tight reservoirs in the United States at 

about 924 tcf and a maximum recoverable resource of 

about 608 tcf. This estimate is considered to be 

relatively conservative because reservoirs deeper than 

4,600 m (15,000 ft) were not included in the assessment. 

Tight-gas reservoirs are highly variable in terms 

of age, lithology, environments of deposition, depth, 

thickness, and continuity. They occur in nearly all 

petroleum provinces but are particularly notable in the 

eastern, south-central, and western regions of the United 

States. 

In the eastern region, tight-gas reservoirs occur 

in the Appalachian and Black Warrior basins. The 

principal reservoirs are Devonian and Silurian shale, 

siltstone, and sandstone. The Devonian gas-bearing 

shales, which have been extensively studied (deWitt, 

1986}, are organic-rich, dark rocks that were deposited in 

a marine environment as the distal part of the Catskill 

delta system. The gas-bearing shales range in thickness 

from a few inches to more than 400 ft and contain 0.5 to 

20 weight percent organic carbon. Permeability ranges 

from 0.1 to 10 microdarcies (Jld), and porosity ranges 

from 1 to 3 percent. Most of the gas is adsorbed on 

organic matter, and a lesser amount occurs as free gas in 

fractures. Economic production from these reservoirs is 

highly dependent on the occurrence of natural fractures. 

The gas is generated from the shale and ranges from a 

biogenic origin in the western part of the Appalachian 

basin to a thermogenic origin in the eastern part of the 

basin. 

The more important tight-gas sandstone 

reservoirs in the eastern region are the Lower Silurian 

Medina Group and Tuscarora Sandstone; the Devonian 

Oriskany Sandstone and Venango, Bradford, and Elk oil 

sand groups; and Mississippian Berea and Hartselle 

Sandstones (Laughrey and Harper, 1986; Finley, 1984, 

1986). These sandstones were deposited in marine to 

marginal marine environments and are lithologically 

variable, ranging in composition from quartzose to 

feldspathic. Permeability is generally less than 0.1 md, 

and porosity ranges from 4 to 12 percent. As a result of 

a complex diagenetic history, most of the porosity is 

-'8 Petroleum Systems of the United States 

secondary. The pores are poorly connected, thus 

fractures, either natural or induced, are necessary for 

sustained flow rates. 

In the south-central region, the tight-gas 

reservoirs occur in the Anadarko, Arkoma, East Texas, 

and North Louisiana basins. Reservoirs in these basins 

include sandstone and carbonate rocks of Pennsylvanian 

through Cretaceous age that were deposited in a wide 

range of marine to nonmarine environments. The more 

important tight-gas reservoirs in this region are the 

Lower Pennsylvanian (Morrowan) sandstones in the 

Anadarko basin, the Upper Jurassic Cotton Valley 

Formation in the East Texas and North Louisiana basins, 

and the Lower Cretaceous Travis Peak Formation in the 

East Texas basin. Reservoir characteristics of these and 

other units have been described by Finley (1984, 1986). 

All of the units in the south-central region 

contain conventional as well as unconventional 

reservoirs. Permeability in the tighter portion of these 

reservoirs is well below 0.1 md, and porosity varies from 

2 to 10 percent. Dissolution porosity is the primary type 

of porosity. Pressure conditions vary from normal to 

overpressured. Drilling depths to the tight Morrowan 

sandstone reservoirs in the Anadarko basin are generally 

greater than 4,600 m (15,000 ft) while depths to the 

Travis Peak and Cotton Valley in the East Texas and 

North Louisiana basins range from 900 to 3,350 m 

(3,000--11,000 ft). The source of the gas in these 

reservoirs is unknown. 

In the western region, tight-gas reservoirs occur 

in several Rocky Mountain foreland basins and in the 

Great Plains east of the Rocky Mountains. The 

reservoirs include Lower Cretaceous to lower Tertiary 

sandstone, siltstone, shale, and chalk that were deposited 

in marine to nonmarine environments. In the foreland 

basins, most of the reservoirs are Upper Cretaceous 

sandstone interbedded with siltstone, mudstone, and coal 

beds that were deposited in deltaic and ft uvial systems 

that are as much as 3,000 m (10,000 ft) thick. The gas 

reservoirs are commonly overpressured or underpressured 

(Meissner, 1978; Law and Dickinson, 1985; Spencer, 

1987), produce little or no water, and occur in basincenter positions, downdip from normal-pressured waterbearing reseiVoirs. The occurrence of these 

accumulations is largely determined by relationships 

between permeability, thermal maturation, temperature, 

pressure, and organic content; structural and stratigraphic 

trapping aspects are of secondary importance. The gas 
contained in these reservoirs is of thermogenic origin and 

was generated primarily from humic-type organic matter 

contained in the interbedded nonmarine organic-rich 

mudstone and coal beds and from adjacent marine shale 

(Law, 1984). 

In the Great Plains region of eastern Colorado, 

northwestern Kansas, Nebraska, North and South Dakota, 

and eastern Montana, more than 100 tcf of recoverable 

gas resources is believed to be present (Rice and Shurr, 

1980) in tight-gas reservoirs. Here, the reservoirs are 

composed of sandstone, siltstone, shale, and chalk. They 

were deposited in a shallow marine-shelf environment as 

blanketlike reservoirs and presently occur at depths 

generally less than 1,200 m (4,000 ft). Because of the 

generally small grain size, these reservoirs are 

characterized by relatively high porosity (15 to more 

than 20 percent) but with a low permeability to gas 

(Spencer, 1985). Gas in these reservoirs is of a biogenic 

origin and was generated from the adjacent shales (Rice 

and Shurr, 1980). 

The U.S. Department of Energy and the Gas 

Research Institute have been sponsoring geologic and 

engineering research on tight-gas reservoirs for several 

years. Gas from tight reservoirs probably has the best 

potential for making a major near-term contribution to 

the Nation's energy needs. However, significant 

advancements in recovery technology are needed in order 

to maximize profitability and ultimate recovery. 

REFERENCES CITED 

deWitt, Wallace, Jr., 1986, Devonian gas-bearing shales 

in the Appalachian basin, in Spencer, C.W., and 

Mast, R.F., eds., Geology of tight gas reservoirs: 

American Association of Petroleum Geologists 

Studies in Geology 24, p. 1-8. 

Finley, R.J., 1984, Geology and engineering 

characteristics of selected low-permeability gas 

sandstones-A national survey: University of 

Texas at Austin, Bureau of Economic Geology 

Report of Investigations 138, 220 p. 

--- 1986, An overview of selected blanket-geometry, 

low-permeability gas sandstones in Texas, in 

Spencer, C.W., and Mast, R.F., eds., Geology of 

tight gas reservoirs: American Association of 

Petroleum Geologists Studies in Geology 24, p. 

69-85. 

Laughrey, C.D., and Harper, J.A., 1986, Comparisons of 

Upper Devonian and Lower Silurian tight 

formations in Pennsylvania-Geological and 

engineering characteristics, in Spencer, C.W., 

and Mast, R.F., eds., Geology of tight gas 

reservoirs: American Association of Petroleum 

Geologists Studies in Geology 24, p. 9-43. 

Law, B.E., 1984, Relationships of source-rock, thermal 

maturity, and overpressuring to gas generation 

and occurrence in low-permeability Upper 

Cretaceous and lower Tertiary rocks, Greater 

Green River basin, Wyoming, Colorado, and 

Utah, in Woodward, J., Meissner, F.F., and 

Clayton, J.L., eds., Hydrocarbon source rocks of 

the greater Rocky Mountain region: Denver, 

Rocky Mountain Association of Geologists, p. 

469-490. 

Law, B.E., and Dickinson, W.W., · 1985, Conceptual 

model for origin of abnormally pressured gas 

accumulations in low-permeability reservoirs: 

American Association of Petroleum Geologists 

Bulletin, v. 69, p. 1295-1304. 

Meissner, F.F., 1978, Patterns of source-rock maturity in 

nonmarine source-rocks of some typical Western 

Interior basins, in Nonmarine Tertiary and 

Upper Cretaceous source rocks and the 

occurrence of oil and basins west-central U.S.: 

Denver, Rocky Mountain Association of 

Geologists Continuing Education Lecture Series, 

p. 1-37. 

National Petroleum Council, 1980, Tight gas 

reservoirs-Part I, in National Petroleum 

Council unconventional gas resources: 

Washington, D.C., National Petroleum Council, 

222 p. with appendices. 

Rice, D.D., and Shurr, G.W., 1980, Shallow lowpermeability reservoirs of the northern Great 

Plains-An assessment of their natural 

resources: American Association of Petroleum 

Geologists Bulletin, v. 64, no. 7, p. 969-987. 

Spencer, C.W., 1985, Geologic aspects of tight gas 

reservoirs in the Rocky Mountain region: 

Journal of Petroleum Technology, v. 37, p. 

1308-1314. 

1987, Hydrocarbon generation as a mechanism 

for overpressuring in Rocky Mountain region: 

American Association of Petroleum Geologists 

Bulletin, v. 71, p. 368-388. 

Tight Gas Reservoirs 49 
Natural Gas in Fractured Shale-The Appalachian 

Devonian Black Shale Gas System 

By John B. Roen 

Fractured shale-gas systems are unconventional 

hydrocarbon accumulations in which the source and 

reservoir are the same tight shale beds. Such 

unconventional resources will increase in value as 

conventional resources decline and exploration and 

recovery techniques advance. For example, the recent 

energy shortage of the early 1970's prompted increased 

efforts in the exploitation of the gas contained in the 

fractured Devonian shale reservoirs in the Appalachian 

basin. The increased interest in the recovery of 

Devonian shale gas resulted in research that provided an 

excellent characterization and resource assessment of a 

fractured shale-gas system. Resource estimates suggest 

that 149 trillion cubic feet (tcf) (Wallace deWitt, oral 

commun., 1977) to 867 tcf (Smith, 1978) of gas may be 

present in the black Devonian shales of the Appalachian 

area. 

The Devonian gas shales are brownish black, 

grayish black, and black in color and are rich in organic 

matter. The average amount of organic carbon for the 

dark organic-rich shale ranges from about 10 weight 

percent in the western part of the basin to about 3 weight 

percent in the east. The average content of organic 

carbon in the fractured shale reservoir rock that produces 

gas is about 5 weight percent. The shales are 

concentrated in the western and central parts of the 

basin, although some crop out along the northern and 

eastern margins of the basin. The shales are very tight, 

having negligible porosity and extremely poor 

permeability. 

Production decline curve characteristics from 

Devonian shale-gas wells substantiated by geochemical 

correlations indicate that the gas contained in the 

fractured Devonian black shale reservoirs was derived 

from the same black shale. The proven correlation of 

gas to source rock identifies a petroleum system: the 

Appalachian Devonian black shale gas system. The 

system is composed of several stratigraphic shale units, 

each of which could be identified as source and reservoir 

rock and hence each a discrete petroleum system with a 

known level of certainty. Because each of these systems 

is lithologically and geochemically identical to the others 

in the Devonian black shale sequence, it is reasonable to 

describe the sequence in its entirety as the Appalachian 

Devonian black shale gas systems(!); the exclamation 

point indicating a known level of certainty. As 

described, the system is purebred because its source 

50 Petroleum Systems of the United States 

rocks, migration paths, reservoir rocks, and trapping 

mechanisms are in the same basin. 

Data from pyrolysis and elemental analysis 

plotted on van Krevelen diagrams indicate that the 

organic matter in the shales was derived from marine 

algae material (type I) and from terrestrial plants (type 

nn. Limited data from 13C nuclear magnetic resonance 

(NMR) analyses confirms the existence of both marine 

and terrestrial organic matter. The areal distribution of 

the NMR data suggests that the organic matter becomes 

increasingly terrestrial in character toward the east. 

Thermal maturation ranges from marginally mature in 

the western areas of shallow burial to postmature in the 

more deeply buried, eastern parts of the basin. Thermal 

alteration of the kerogen in the Devonian black shale 

generated oil in addition to substantial quantities of gas. 

Minor amounts of indigenous oil are being economically 

produced from the matrix and fractures of the Devonian 

black shale gas system in north-central West Virginia 

and adjacent southeastern Ohio. The presence of oil, 

however, is thought to inhibit the slow migration of the 

gas molecules through the shale matrix to fractures and 

permeability paths to the well bore (Soeder and others, 

1986). Oil trapped in sandstone reservoirs 

stratigraphically above the Devonian black shale is 

believed to have been derived from the black shale 

(George Claypool, written commun., 1984). The oil was 

probably derived from source beds with comparatively 

higher concentrations of oil-prone, type I kerogens. Its 

generation and migration probably occurred early relative 

to the shale gas. The relative amount and type of 

recovered hydrocarbons generated from the shales and 

the amount and type of hydrocarbons estimated to be 

remaining in place, supported by the aforementured 

geochemical and pyrolytic analyses, suggest that the 

shales are predominantly gas prone. 

Production of gas from Devonian shale 

reservoirs is dependent on the existence of naturally 

occurring fracture systems. Without extensive natural 

fractures, the shale gas molecules cannot desorb from the 

very low permeability shale matrix, move to the fracture 

system and ultimately to the well bore in quantities 

sufficient for economic exploitation. Shale sequences 

lacking extensive natural fracture systems generally will 

not yield gas economically, even with stimulation by 

existing fracturing techniques. Natural fracturing of the 

Devonian shale gas system is the result of tensional 
tectonic features of the Appalachian basin. Faulting 

associated with the Rome trough, a portion of a 

basement aulacogen (Harris, 1978), and the Kentucky 

River-Paint Creek fault zone has created an extensive 

fracture reservoir system in the shale. Glacial retreat and 

subsequent crustal rebound due to weight removal have 

produced fractures in gas-rich shales to a depth of about 

450 m (1,500 ft). Tensional fractures resulting from 

compressional tectonics in folding also produce the 

necessary fracture porosity and permeability. However, 

shear fractures from horizontal compressional stress 

apparently do not produce the required extensive fracture 

porosity and permeability necessary for economic 

concentration of shale gas. This is evidenced by very 

short duration blowouts and the lack of sustained steady 

production from an extremely fractured decollement zone 

in the Devonian black shale sequence along the Pine 

Mountain thrust fault. 

Studies of the Devonian black shale gas system 

indicate that several of its features are probably common 

to other fractured shale gas systems. It is apparent that 

the existence of an extensive natural fracture system with 

enhancement is a prerequisite for economic exploitation. 

The natural fractures in a fractured shale system should 

be tensional in nature. In fractured shale gas systems, 

the hydrocarbons that are produced are generally 

indigenous to the fractured shale reservoir rock. 

Production decline curves of wells in fractured shale 

systems display similar characteristics of initial flush 

production declining at a rapid rate before reaching a 

relatively much longer period of steady-state flow. 

Finally, fractured gas shale reservoirs are not easily 

located by the more conventional exploration techniques; 

in fact, most discoveries were the results of random 

drilling. 

In regard to exploration, new and successful 

techniques must be developed to fully utilize the gas 

resource contained in the Devonian as well as other 

fractured shale gas systems. Recently, research efforts 

have concentrated on various surface techniques to locate 

prospective areas. Efforts have been directed to locating 

areas with a high density of penetrative fractures and 

joints that might be indicative of a similar concentration 

of fractures in a Devonian shale reservoir at depth. 

Delineation of major stress systems, field mapping of 

joints and fractures, and the use of various remote 

sensing methods have been used with moderate success. 

Further development in the application of remote sensing 

techniques is needed. In addition, research is needed in 

the application and utility of direct and indirect 

geochemical detection to delineate extensive fracture 

systems. 

Improvement of Devonian shale development 

techniques have also been under investigation. Various 

downhole diagnostic methods, including borehole 

television examination and wire-line geophysical 

characterization, have been developed along with 

application of stratigraphic, geochemical, and production 

data to define closely the stratigraphic shale intervals for 

completion and stimulation. Research on stimulation 

techniques to increase yield and flow rate has been 

carried out looking for improvement and new methods. 

Early stimulation methods with explosives commonly 

created good gas flow but required extensive clean-up 

periods. Shooting shale-gas wells has been largely 

replaced by hydraulic fracturing techniques developed in 

the 1950's. Hydraulic fracturing, with subsequent 

improvements and modifications, has been most widely 

and successfully used. However, the use of water as the 

fracturing fluid causes swelling of some mixed-layer 

clays in the shale, which reduces permeability and blocks 

gas migration to the well bore. Difficulties from the 

excessive volume of water in the fracturing treatment 

have been largely overcome by more recently developed 

foam fracturing methods that use nitrogen and 

considerably less water than the hydraulic method. 

Current research is principally confined to 

developing downhole diagnostic techniques and relating 

stratigraphic characteristics to production in order to 

enhance the selection and development of the most 

productive shale interval. 

REFERENCES CITED 

Harris, L.D., 1978, The Eastern interior aulacogen and its 

relation to Devonian shale gas production: 

Second Eastern Gas Shales Symposium, U.S. 

Department of Energy, Morgantown Energy 

Technology Center, Preprint, METC/SP-78/6, v. 

2, p. 55-73. 

Smith, E.C., 1978, A practical approach to evaluating 

shale hydrocarbon potential: Second Eastern Gas 

Shales Symposium, U.S. Department of Energy, 

Morgantown Energy Technology Center, 

Preprint, METC/SP-78/6, v. 2, p. 73-87. 

Soeder, D.J., Randolph, P.L., and Matthews, R.D., 1986, 

Porosity and permeability of Eastern Devonian 

gas shales: U.S. Department of Energy, 

Morgantown Energy Technology Center, Report 

DOE/MC/20343-8, p. 52-54. 

Natural Gas in Fractured Shale-The Appalachian Devonian Black Shale Gas System 51 
Coal-Bed Methane 

By Ben E. Law 

Coal beds have been known or assumed to be 

excellent sources of gas for many years. There is a 

growing awareness, however, that coal beds are also 

good gas reservoirs; gas generated and stored in coal 

beds can be recovered with standard petroleum drilling 

and production techniques. In Europe and in the eastern 

United States, coal-bed gas has been produced and 

utilized in limited quantities for many years, and, 

recently, coal-bed gas has been produced from coal beds 

in the western United States. Several areas in the United 

States, most notably the Black Warrior basin in Alabama 

and the San Juan basin in New Mexico and Colorado, 

are now producing commercial quantities of gas from 

coal beds. Coal-bed methane resources in the United 

States are estimated at 72 to 860 trillion cubic feet (tct), 

and most estimates are between 300 and 500 tcf 

(Rightmire, 1984). 

Coal is a lithified organic sediment derived from 

various types of plant material that form under a wide 

variety of physical and chemical conditions. Most coal 

is composed of woody plant debris and is generally 

thought to be capable of generating mainly gas with 

lesser amounts of oil (Tissot and Welte, 1984; Hunt, 

1979), although some work has suggested that a 

significant amount of coal-derived hydrocarbons consist 

of oil-type components (Durand and Parratte, 1983). 

During early stages of coalification (diagenesis), coal 

beds are affected by microorganisms in predominantly 

low-temperature environments. Methane, carbon dioxide, 

and traces of other gases are released, as well as large 

amounts of water. With increasing burial, coal beds are 

subjected to higher temperature and pressure 

environments (catagenesis). Under these conditions, 

large amounts of methane and carbon dioxide and 

smaller amounts of nitrogen, oxygen, hydrogen, and 

heavier hydrocarbons, such as ethane, propane, and 

butane, are generated. During catagenesis, it has been 

estimated that more than 200 m3 (7,000 ft3

) of gas may 

be generated from 1 ton (900 kg) of coal (J untgen and 

Karweil, 1966). Although some of this gas either is lost 

to the atmosphere or migrates from the coal into adjacent 

rocks, large quantities are retained in the coal as free gas 

within joints or fractures in the coal or as adsorbed gas 

within the fine micropore coal structure (Stach and 

others, 1982). Gas contained in joints and fractures is 

more easily removed from the coal than is the more 

abundant adsorbed gas. At constant temperature and 

pressure, high-rank coals contain larger amounts of gas 

52 Petroleum Systems of the United States 

than low-rank coals. The gas adsorption capability of 

coal increases with increasing pressure and decreases 

with increasing temperature (Kim, 1977). Coal-bed gas 

contains 90 to 99 percent methane and has a heat of 

combustion of 950 to 1,035 Btu per cubic foot. 

At the present time, coal-bed gas is produced 

from deep, unminable seams, from drainage of gas in 

advance of coal mining, and from drainage of gas from 

mined-out areas. Production rates are highly variable. 

Initial daily rates from some of the better producing 

wells are more than 1 million cubic feet (28,000 m3

) per 

day, but rates in most wells are less than 250,000 ft3 /d 

(7 ,000 m3

). Physicochemical factors affecting the 

amount and recoverability of coal-bed gas include coal 

rank, moisture content, gas adsorption capability, 

macro pore and micropore structure, cleat (or fracture) 

development, type of organic matter, temperature, and 

pressure. 

Although there is a large base of know ledge 

concerning many aspects of coal, most of that 

information is applicable to the mining industry and the 

direct utilization of coal. From a petroleum geology 

perspective, relatively little information is directly 

applicable. Some of the more important geologic 

uncertainties that need additional work include: (1) 

determining the factors controlling the amount of water 

in coal-bed reservoirs; (2) refining the relations between 

reservoir pressure, temperature, thermal maturity, and gas 

production; (3) determining the importance of cleat 

development to gas production; ( 4) determining the 

importance of coal-bed composition to coal gassiness; 

and (5) conducting basin-wide burial and thermal history 

reconstructions of coal beds. 

Coal beds have some advantages over 

conventional gas reservoirs. Geographic and 

stratigraphic occurrences of coal beds in the United 

States and elsewhere are relatively well known, and, 

because the coal beds are both the gas source and the gas 

reservoir, problems of gas generation and migration are 

less complex. These factors, in conjunction with drilling 

depths of generally less than 900 m (3,000 ft), reduce 

exploration and exploitation costs. 

The commonly employed methods of gas 

recovery from coal beds are vertical drilling using 

standard petroleum techniques and directional drilling. 

Vertically drilled holes drain the gas from the area 

immediately adjacent to the borehole. This type of 

completion often requires additional stimulation 
treatment to increase production to economic levels. 

Fracturing the coal bed by injection of fluids under 

pressure is a common practice. These hydraulic fractures 

generally increase the effective drainage area and 

significantly increase production levels. Directional 

drilling is a technique used to drill a hole within and 

parallel to a coal bed. The coal bed may be horizontal 

or steeply dipping. This technique maximizes the coal 

surface area exposed to the borehole, intersecting the 

joint system of the coal and thereby exposing a large 

area of gas drainage. 

REFERENCES CITED 

Durand, B., and Parratte, M., 1983, Oil potential of 

coals-A geochemical approach, in Brooks, V ., 

ed., Petroleum geochemistry and exploration of 

Europe: Geological Society Special Publication 

12, p. 255-265. 

Hunt, J .M., 1979, Petroleum geochemistry and geology: 

San Francisco, W.H. Freeman, 617 p. 

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

gasspeicherung in steinkohlenflozen, Part I and 

II: Erdol and Koble, Erdgas, Petrochemie, v. 

19, p. 251-258 and p. 339-344. 

Kim, A.G., 1977, Estimating methane content of 

bituminous coalbeds from adsorption data: U.S. 

Bureau of Mines Report of Investigations 8245, 

22p. 

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

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

Coalbed methane resources of the United States: 

American Association of Petroleum Geologists 

Studies in Geology 17, p. 1-13. 

Stach, C., Chamdra, D., Mackowsky, M-Th., Taylor, 

G.H., Teichmueller, M., and Teichmueller, R., 

1982, Stach's text book of coal petrology: 

Stuttgart, Bomtraeger, 428 p. 

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

and occurrence: New York, Springer-Verlag, 

699 p. 

Coal-Bed Methane 53 
Classification and Composition of Crude Oil 

By Jerry L. Clayton 

Several methods for classification of crude oils 

have been proposed by geochemists and refining 

chemists using physical characteristics or chemical 

composition of oils. The various schemes that have been 

developed have different purposes and are based on 

different physical and chemical parameters. The reader 

is referred to Tissot and Welte (1984) for a historical 

review of various petroleum classification methods. 

Geologists and geochemists view classification as a 

means to relate oils to their source rocks and to 

determine their level of thermal maturation. Such an 

understanding is critical for determining relationships 

between oils and source beds, for determining the 

generation and migration history of hydrocarbons, and 

for prediction of recoverable reserves within the 

petroleum system. Unfortunately, in many cases the 

source rocks are unknown and only crude oils are 

available for analysis. This paper is a summary of the 

most common approaches to classification of oils for the 

purpose of interpreting the nature of the source rock. 

The most basic level of classification of oils with respect 

to source is to distinguish carbonate- and shale-derived 

oils and to separate marine from nonmarine oils. 

Distinctions can be made between marine and nonmarine 

oils as well as including more specific depositional 

settings within these two broad categories. Palacas (this 

volume) summarizes the classification parameters for oils 

derived from carbonate versus shale sources. 

Crude oil ranges from heavy oil to condensate. 

It is a complex mixture of predominantly hydrocarbons 

with secondary amounts of nonhydrocarbons 

(heteroatomic molecules) containing N, S, or 0. 

Hydrocarbons typically constitute greater than 75 to 80 

percent by weight of medium-gravity crude oil. 

Medium-gravity oils are defined for the purpose of this 

discussion as those with API gravity between 20° to 45°. 

Condensates are included in this paper and are defined as 

oils that are gases at the pressure and temperature of the 

reservoir, but are liquids at surface temperature and 

pressure. Condensates have API gravities of 

approximately 45° or higher. Unfortunately, some 

ambiguity is introduced by this definition because it 

depends on reservoir conditions rather than actual 

composition of the reservoir fluids. Changes in reservoir 

pressure during the geologic or development history of a 

reservoir can change a gaseous condensate into a liquid 

accumulation. Oils with API gravities between 10° and 

20° are generally classified as heavy oils, and those with 

54 Petroleum Systems of the United States 

gravities less than 10° are called extra-heavy (Connan, 

1984). Heavy and extra-heavy oils are discussed in a 

separate report (Meyer, this volume) and are not 

specifically addressed here. 

Generally, a classification based on density or 

boiling-point distribution may be useful for refinery 

applications, but has limited application for exploration 

geologists or geochemists who need to know something 

about the specific source beds and conditions of 

formation for petroleum accumulations. Although 

normal oils (20°--45°+ API gravity) are composed 

predominantly of saturated and aromatic hydrocarbons 

with secondary amounts of nonhydrocarbons (resins and 

asphaltenes), the actual abundances of various structural 

types, indicated in table 9, can vary considerably. More 

importantly, the molecular distribution within the various 

structural types of compounds can vary widely in 

response to differences in the thermal maturities of 

various oils and, particularly, the parent-source organic 

matter from which the oils were derived. Because 

explorationists are interested in the source of an oil, 

compounds which provide source-specific information 

about the oil are important in the classification, even 

though they may be present only in small amounts in the 

oil. Recently, Tissot and Welte (1984) proposed a 

Table 9. Typical composition of a 35° API gravity 

crude oil (from Hunt, 1979) 

Common Molecular Volume 

name weight percent 

range 

Gasoline CS-ClO 27 

Kerosene Cu-C13 13 

Diesel fuel cl4-Cls 12 

Heavy gas oil cl9-C2S 10 

Lubricating oil C26-C4o 20 

Residuum >C4o 18 

Total100 

Molecular Weight 

types ~rcent 

Paraffins 25 

Naphthenes 50 

Aromatics 17 

Asphaltenes + resins 8 

TotallOO 
Table 10. Classification of oils according to scheme of Tissot and Welte (1984) 

[S, saturates; AA, aromatics+ resins + asphaltenes; P, paraffins; N, naphthenes; >210 °C, concentration in crude oil topped at 210 oq 

Sulfur content Number of 

Concentration in crude oil Crude oil in crude oil samples per class 

>210 oc type (approximate) (total no. 514) 

S>50%, AA<50% P>N and P>40% Paraffinic <1% 100 

S>50%, AA<50% PS40% and NS40% Paraffinic-naphthenic <1% 217 

S>50%, AA<50% N>P and N>40% Naphthenic <1% 21 

SSS0%.~0% P>10% Aromatic-intermediate >1% 126 

SsS0%.~0% PSlO%, NS25% Aromatic-asphaltic >1% 41 

SSS0%.~0% PS10%, N~5% Aromatic-naEhthenic General!,>:: S< 1% 36 

classification scheme based on the content of normal + 

isoalkanes, cycloalkanes, and aromatic compounds, 

including resins and asphaltenes. Table 10 shows the 

main classes of oils according to their scheme. Some 

genetic information is included in this scheme. 

"Aromatic-intermediate" oils are generally associated 

with marine sediments and reducing conditions, and 

"paraffinic-naphthenic" or "paraffinic" oils are usually 

associated with deltaic sediments of continental margins 

or nonmarine source rocks. 

Silverman and Epstein (1958) suggested that 

stable carbon isotope ratios could be used to separate 

marine from nonmarine oils. More recently, So fer 

(1984) determined carbon isotope ratios of saturated and 

aromatic hydrocarbons for 339 oils and concluded that 

oils derived from marine and nonmarine organic matter 

could be distinguished not by carbon isotope composition 

of a particular fraction but by the difference in isotope 

ratios between the saturated and aromatic hydrocarbons. 

Schoell (1983; 1984) used carbon and hydrogen isotopes 

to differentiate carbonate- and shale-derived oils. Peters 

and others (1986) argued that carbon isotopes cannot be 

used to unequivocally separate marine and nonmarine 

oils. They suggested that multivariate analysis of a 

combination of biological marker and isotope data 

provides a better method for distinguishing depositional 

settings of source rocks based on oil analyses, and 

presented data showing classification of oils from marine 

shale, nonmarine shale, and marine carbonates. 

With continuing development of analytical 

capabilities and computerized handling of data, various 

classification methods using the multivariate approach 

are becoming more popular, and, in some cases, more 

details about the source-rock geochemistry may be 

inferred from oil analyses. For example, Moldowan and 

others (1985) were able to differentiate marine from· 

nonmarine oils in a sample set of 40 oils using C30 

steranes and monoaromatic steroid distributions and were 

able to estimate the relative proportion of higher plant 

input for a given crude. Mello and others (1988) used a 

combination of geochemical methods (carbon isotope 

ratios, API gravity, NiN, percent sulfur, biological 

markers) to classify oils from offshore Brazil as to 

depositional settings of the source rocks-lacustrine 

freshwater, lacustrine saline, marine evaporites, marine 

carbonate, or marine deltaic. Zumberge (1987) used 

statistical analysis of geochemical data (16 biological 

marker compounds) to classify 216 oils located 

worldwide for the purpose of predicting source-rock 

features or depositional environments. He identified five 

categories of oil (source-rock depositional setting): 

nearshore marine (paralic/deltaic); deeper-water marine; 

lacustrine; phosphatic-rich source beds; and Ordovician 

age source beds. 

For very mature oils, particularly condensates, 

classification according to type of source rock is more 

difficult than for normal-gravity oils because severe 

thermal alteration of source-specific parameters may have 

occurred. The overall trend of increasing maturity is to 

reduce the chemical complexity of an oil and produce 

oils with fewer and simpler chemical structures. Given 

sufficient temperature over geologic time, only methane 

would be present in significant quantities. 

Future methods of classification of oils will 

undoubtedly use a multiparameter approach and will 

depend heavily on the use of individual biomarker 

compounds or associations of several biomarkers and 

bulk properties for inferring detailed information about 

the source environment of the parent organic matter of 

the oils. 

REFERENCES CITED 

Connan, J., 1984, Biodegradation of crude oils in 

reservoirs, in Brooks, J., and Welte, D., eds., 

Advances in petroleum geochemistry, v. 1: 

New York, Academic Press, p. 299-335. 

Hunt, J.M., 1979, Petroleum geochemistry and geology: 

San Francisco, W. H. Freeman, 617 p. 

Classification and Composition of Crude Oil 55 
Mello, M.R., Gaglianone, P.O., Brassell, S.C., and 

Maxwell, J .R., in press, Geochemical and 

biological marker assessment of depositional 

environments using Brazilian offshore oils, in 

Mattavelli, L., and Novelli, L., eds., Advances 

in organic geochemistry 1987: Organic 

Geochemistry. 

Moldowan, J.M., Seifert, W.K., and Gallegos, E.J., 1985, 

Relationship between petroleum composition 

and depositional environment of petroleum 

source rocks: American Association of 

Petroleum Geologists Bulletin, v. 69, p. 

1255-1268. 

Peters, K.E., Moldowan, J.M., Scholle, M., and 

Hempkins, W. B., 1986, Petroleum isotopic and 

biomarker composition related to source rock 

organic matter and depositional environment, in 

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

Advances in organic geochemistry 1985: 

Organic Geochemistry, v. 10, p. 17-27. 

Schoen, M., 1983, Wasserstoff- and kohlenstoff 

isotopenvariationen in organischen substanzen, 

ErdOlen und Erdgasen, Geologisches Jahrbuch, 

Reihe D, v. 67, 164 p. 

56 Petroleum Systems of the United States 

1984, Recent advances in petroleum isotope 

geochemistry, in Schenck, P.A., DeLeeuw, J.W., 

and Lijmbach, G.W.M., eds. Advances in 

organic geochemistry 1983: Organic 

Geochemistry, v. 6, p. 645--663. 

Silverman, S.R., and Epstein, S., 1958, Carbon isotopic 

composition of petroleums and other 

sedimentary organic materials: American 

Association of Petroleum Geologists Bulletin, v. 

42, p. 998-1012. 

Sofer, Z., 1984, Stable carbon isotope composition of 

crude oils: Application to source depositional 

environments and petroleum alteration: 

American Association of Petroleum Geologists 

Bulletin, v. 68, p. 31-49. 

Tissot, B., and Welte, D., 1984, Petroleum fonnation and 

occurrence-A new approach to oil and gas 

exploration: Berlin, Springer-Verlag, 538 p. 

Zumberge, J.E., 1987, Prediction of source rock 

characteristics based on terpane biomarkers in 

crude oils: A multivariate statistical approach: 

Geochimica et Cosmochimica Acta, v. 51, p. 

1625-1637. 
Heavy Oil and Natural Bitumen 

By Richard F. Meyer 

Heavy crude oil and the natural bitumens are 

petroleum hydrocarbons distinguished from conventional 

crude oils by their high density and high viscosity. 

Because of these characteristics, their recovery from the 

reservoir and consequent transportation and refining is 

rendered difficult and costly. Most heavy oil requires the 

application of heat to be producible from a well. In the 

United States, two types of natural bitumen deposits are 

found, vein deposits and natural asphalt. Vein deposits, 

such as gilsonite, are rare and of little consequence as a 

source of liquid hydrocarbons. Most natural bitumens 

occur as natural asphalt (oil sands, tar sands) and are 

usually mined. In some places they can be produced by 

thermal enhancement; in mining, the bitumen must be 

physically separated from the mineral matrix and then 

upgraded to a liquid hydrocarbon before being processed 

at a refinery. Most deposits of heavy oil and natural 

bitumen are either gas free or have extremely low gasto-oil ratios. 

Heavy oil and natural bitumen may be defined 

on several different bases: density and viscosity of the 

whole crude, percentage of whole crude that is a refinery 

residuum at approximately 540 oc (1,000 °F), or the 

ability to recover the crude oil by primary and secondary 

methods only. Using oil density and viscosity, the 

United Nations Information Centre for Heavy Crude and 

Tar Sands (Martinez, 1984) has set limits as follows: 

Hydrocarbons more viscous than 10,000 cp are defined 

as bitumen, whereas those less viscous than 10,000 cp 

are considered to be crude oil. Crude oil with a density 

range of 10°-20° API is defined as heavy oil. Extraheavy oil is more dense than 10° API. Ordinarii y, if an 

oil can be produced through a well and is less than 10° 

API, it is assumed to be extra-heavy oil and not bitumen. 

A good example is the extra-heavy oil in the Venezuelan 

Orinoco Oil Belt. The API gravity of oil is the most 

commonly available physical attribute. Its viscosity is 

seldom reported. Heavy oil may also be distinguished 

(Oil and Gas Journal, 1983) on the basis of the 

proportion of residuum remaining when the whole crude 

is distilled to approximately 540 oc (1 ,000 °F). A 

residuum of 15 volume percent is commonly accepted as 

the criterion of a heavy oil even though the unrefined 

crude may have a high API gravity. Using this criterion, 

Brent crude from the North Sea is conventional, with a 

gravity of 38° API and a residuum yield of only 10.3 

percent. On the other hand, Ekofisk crude, also from the 

North Sea, might be called heavy conventional because it 

yields 25.2 percent residuum even though the whole 

crude gravity is 43.4° API. A heavy crude oil such as 

Venezuelan Bachaquero (16.8° API), yields 70.3 percent 

residuum. The California Oxnard natural bitumen has a 

gravity of 3.9° API and a residuum yield of 51 percent. 

Lastly, an upper limit to the density for heavy oil may be 

based on recoverability by primary and secondary 

methods (Chapman Cronquist, written common., 1984), 

without resorting to enhanced (tertiary) recovery. Most 

heavy oil deposits are relatively free of gas. 

Waterflooding, a secondary method that may be used to 

enhance the original reservoir pressure, is only effective 

to about 18° API. Thus, the upper limit for heavy oil 

needs to be set above 18° API, and a gravity of 20° API 

is the most widely accepted definitional limit even 

though it has no precise chemical basis. 

The physical attributes of the heavy oils and 

natural bitumens are directly related to the chemical 

constituency, characterized by large molecules of 

asphaltenes and resins. In such organometallic 

complexes are found most of the nonhydrocarbon 

elements that make the heavy oils difficult to refine. 

With an increase in density to and beyond 20° gravity 

API (Speight, 1980), the Conradson carbon greatly 

increases, the proportion of asphaltics increases notably, 

there is a decided increase in viscosity, and ordinarily the 

content of sulfur, oxygen, nitrogen, and such trace metals 

as nickel and vanadium rises significantly. Because 

these factors cause severe problems in recovery, 

transportation, and refining, they lead to a lower value 

for the crude. However, viscosity is notably sensitive to 

temperature, so that anything leading to higher reservoir 

temperature, such as high heat flow in the Earth or 

application of exogenous heat, simplifies recovery from 

the reservoir. After the heavy crude oil reaches the 

surface, the high-viscosity problem returns. There is no 

direct correlation between density and viscosity, except 

for each individual deposit. However, sufficiently 

accurate generalities may be drawn to permit use of 

density as a proxy for viscosity for most crudes, because 

of the general absence of any viscosity data. 

The United States has four important areas of 

heavy oil production: California, 345 million barrels in 

1986 in the Los Angeles, San Joaquin, Santa Maria, and 

Ventura basins; Rocky Mountains, 28 million barrels in 

1986, in the Big Horn, Green River, and Powder River 

basins; Southwest, 40 million barrels in 1986, in the 

Arkla, East Texas, Gulf Coast, Mid-Gulf, and Permian 

Heavy Oil and Natural Bitumen 57 
basins; and the Alaskan North Slope, with no 1986 

production. The three areas in the lower 48 United 

States yielded 413 million of the U.S. total of 423 

million barrels. In terms of Original Reserves (proved 

reserves plus cumulative production), the same three 

areas contain 29.8 billion of a lower 48 States total of 

30.5 billion barrels, with an additional 34.3-36.8 billion 

barrels on the North Slope. Of the 30.5 billion barrels, 

18 percent is offshore; in depth, 10 percent is found at 

less than 150 m (500 ft), 33 percent between 150 and 

600 m (500 and 2,000 ft), 45 percent between 600 and 

1,500 m (2,000 and 5,000 ft), and 12 percent below 

1,500 m (5,000 ft); 87 percent is heavy oil, and 13 

percent extra-heavy. Of the extra-heavy oil, 80.5 percent 

occurs at depths between 600 and 1,500 m (2,000 and 

5,000 ft), which suggests that much of this oil is 

immature rather than degraded light oil. About one-third 

of the heavy oil is located in giant fields (more than 500 

million barrels of original reserves); these include South 

Belridge, Coalinga, Huntington Beach, Kern River, 

Midway-Sunset, San Ardo, and Wilmington in California 

and Hawkins and Smackover in the Southwest. When 

developed, the West Sak deposit on the North Slope will 

be a giant. 

In the United States, most heavy oil is produced 

with the assistance of thermal enhancement recovery to 

reduce viscosity. Of 224 enhanced oil recovery (EOR) 

projects active in 1986, 182 utilized steam, 3 utilized hot 

water, and 17 utilized underground combustion 

(fireflood). The other 22 involved polymer, alkaline, and 

carbon dioxide floods. Overall, recovery of heavy oil in 

place averages about 28 percent but varies greatly; 

California recovery is about average. 

The importance of understanding whether a 

heavy crude oil is an immature oil or a degraded 

conventional light oil is directly pertinent to oil recovery 

(Connan and Coustau, 1987). The entrapment of oil 

depends upon its buoyancy, the capillary pressures 

involved, and the hydrodynamics of the basin system. 

With a heavy oil, buoyancy is low, because an API 

gravity of 10° equals a specific gravity of unity. 

Consequently, if its buoyancy is low, an oil will only 

saturate the most permeable zones in the reservoir, and 

these will be the ones preferentially swept by a steam 

drive. If a mature light oil is entrapped in a zone of low 

porosity and permeability, which might easily be the 

case, and subsequently degraded by bacteria and water 

washing, recovery will be very difficult because the 

steam will preferentially enter the zones of high 

permeability and porosity. If water washing increases, 

partially sweeping the reservoir, then recovery becomes 

nearly impossible, particularly when the reservoir rock 

itself is diagenetically altered by the water. A mature 

light oil degraded during migration will behave much 

like an immature oil. possessing low buoyancy and 

saturating only the most highly porous and permeable 

58 Petroleum Systems of the United States 

zones, where steam drive will be efficient. Before 

attempting enhanced recovery of heavy oil, therefore, it 

is exceedingly important to conduct studies of the 

porosity and permeability of the reservoir rock itself as 

well as of the oil, in order to predict recovery 

possibilities. 

Of the natural bitumens, the asphaltites and 

asphaltic pyrobitumens (Abraham, 1960) are the least 

important quantitatively and economically but perhaps 

the most intriguing of the hydrocarbons scientifically. 

The asphaltites are asphalt-like, with fusing points 

greater than 110 °C. The best known example is 

gilsonite, characterized by a specific gravity of 1.03 to 

1.10 and fixed carbon content of 10-20 percent. 

Gilsonite occurs in a large vein in the Uinta basin, and 

its origin is still in question. A second variety is glance 

pitch, found in Emery County, Utah, with a specific 

gravity of 1.10 to 1.15 and a fixed carbon content of 

20-35 percent. The third variety of asphaltite is 

grahamite, found in West Virginia, Oklahoma, and 

Colorado. It has a specific gravity of 1.15 to 7.20 and 

fixed carbon content of 35-55 percent. 

The asphaltic pyrobitumens are infusible and 

have extremely low oxygen-to-carbon ratios. All are 

minor in occurrence and of little economic significance. 

Wurtzilite, found in Uintah County, Utah has a specific 

gravity of 1.05 to 1.07 and a fixed carbon content of 

5-25 percent; albertite, in the same area, has a slightly 

higher specific gravity (1.07-1.10) and greater fixed 

carbon (25-50 percent); and impsonite, occurring in 

small veins in Oklahoma, Arkansas, Nevada, and 

Michigan, has a specific gravity of 1.10-1.25 and fixed 

carbon content of 50-90 percent. 

Natural asphalt is of far greater significance 

worldwide, both scientifically and economically. It is a 

natural bitumen that may occur in a relatively pure state, 

as in the pitch lake of Trinidad, or contained in clastic or 

carbonate reservoir rocks. The clastic reservoirs are 

commonly either sand or sandstone. Except for the 

Alberta Athabasca and related deposits, natural asphalts 

have historically been used solely as sources of road 

paving, mastic, and roofing material. These uses have 

largely been displaced by manufactured asphalt. Future 

use of large natural asphalt deposits will be mainly as a 

source of liquid hydrocarbons. At present, only the 

Alberta oil-sand bitumen is so used. It yields about 

160,000 barrels per day of synthetic crude oil. In the 

United States, the original natural asphalt reserves are 

estimated to be about 43 billion barrels in the lower 48 

States and 11 billion barrels on the North Slope of 

Alaska. The North Slope deposit, which occurs in the 

upper and lower parts of Ugnu sands, may be as large as 

19 billion barrels. Most of the resources in the lower 48 

States are contained in 11 deposits, each of which 

contains bitumen amounting to more than 1,000 million 

barrels. The two largest, each exceeding 6 billion 
barrels, are Northwest Alabama and Sunnyside, Utah. 

Others include Asphalt Ridge, Circle Cliffs, PR Spring, 

and Tar Sand Triangle, Utah, the Tri-State area of 

Missouri, Kansas, and Oklahoma, the San Miguel 'D' in 

Texas, the Big Clifty Sandstone in Kentucky, and Cat 

Canyon and the deposit of Foxen Sandstone, California. 

Exploitation of natural asphalts for recovery of 

their included bitumen as a source of liquid hydrocarbons 

depends more upon economics than technology. With 

respect to mineability (Resnick and others, 1981), certain 

factors are fixed and others are flexible. The fixed 

factors include the structural characteristics of the ore 

body and surrounding strata; the geological 

characteristics of the deposit; topography; and location, 

areal extent, variability, and richness (grade) of the 

deposit. Factors allowing some flexibility are availability 

of water; transportation; labor and community 

infrastructures; and power resources. Finally, factors of 

environmental concern, socioeconomic status, the 

political environment, and ownership patterns may 

ultimately limit mining. 

The Discounted Cash Flow Rate of Return 

(DCFROR) (Earley, 1987) is quite insensitive to the 

stripping ratio at shallow depths. However, the 

DCFROR is very sensitive to the richness (grade) of the 

deposit and to the size of the plant. In general, a grade 

of 8-10 weight percent bitumen is required with a plant 

size of at least 10,000 barrels per day. A smaller plant 

size implies a very rich, local ore source. Similarly, if 

the grade remains fixed, as net pay thickness diminishes, 

the area of the deposit must increase for a given plant 

size. Increased richness will lower the thickness/area 

requirement. Consequently, a resource equivalent to 250 

million barrels of oil of 20° API, covering 3,000 acres, 

would require thicknesses of about 13 m (42 ft) at grade 

of 11.6 weight percent, 18 m (58 ft) at 8.7 weight 

percent and 26 m (84 ft) at 5.8 weight percent 

(Herkenhoff, 1972). 

Such data indicate that additional problems will 

be entailed in the transportation and upgrading of heavy 

oil and bitumen. These can most easily be visualized by 

equating the heavy oil and bitul{len to the highest boiling 

temperature fraction of the refinery barrel, in which 

through the distillation process is concentrated most of 

the least desirable crude oil components: the large, 

complex molecules of hydrocarbons; the trace metals, 

nitrogen, and oxygen through organic complexes; and the 

sulfur. 

The preceding review indicates that 

discrimination of the oil or bitumen in the various 

deposits with respect to their fundamental nature, 

whether immature or mature and degraded, is essential to 

an understanding of the petroleum systems to which the 

deposits belong. These data are also basic to an 

understanding of the most economical recovery methods 

to be employed. It is necessary, at the same time, to 

have a detailed knowledge of the reservoir rock itself, 

particularly the porosity and permeability characteristics. 

Research on the source beds which contributed 

hydrocarbons to the deposits will materially assist in 

understanding the nature of the occurrences. 

With regard to the heavy oil fields, assumptions 

can be made as to the source and carrier beds in the 

same way as with conventional oil fields. To gain any 

degree of certainty, however, will require chemical 

analyses of the trapped oil and the oil in the assumed 

source beds. For bitumens, little attempt has been made 

to relate the deposits to source beds and avenues of 

migration. Because both the heavy oil fields and the 

bitumen deposits generally contain more or less severely 

degraded oils, positive identifications in order to 

assemble the petroleum system involved will require the 

attention of organic geochemists. Lack of understanding 

of the petroleum systems renders the location of new 

deposits and the effective exploitation of those already 

identified a very chancy business, one no longer 

acceptable in its inefficiency. 

REFERENCES CITED 

Abraham, Herbert, 1960, Asphalts and allied substances, 

6th ed.: New York, Van Nostrand, v. 1,370 p. 

Connan, J.M., and Coustau, Henri, 1987, Influence of the 

geological and geochemical characteristics of 

heavy oils on their recovery, in Meyer, R.F., ed., 

Exploration for heavy crude oil and natural 

bitumen: American Association of Petroleum 

Geologists Studies in Geology 25, p. 261-280. 

Earley, J.W., 1987, Economic factors in near-surface 

heavy-oil/tar sand mining, in Meyer, R.F., ed., 

Exploration for heavy crude oil and natural 

bitumen: American Association of Petroleum 

Geologists Studies in Geology 25, p. 669--671. 

Herkenhoff, E.C., 1972, When are we going to mine 

oil?: Engineering and Mining Journal, v. 173, 

no. 6, p. 132-138. 

Martinez, A.R., 1984, Report of working group on 

definitions, in Meyer, R.F., Wynn, J.C., and 

Olson, J.C., The future of heavy crude and tar 

sands: New York, McGraw-Hill, p. xvii-xviii. 

Oil and Gas Journal, 1983, U.S. crude oil imports shift to 

heavier category: v. 81, no. 25, p. 78. 

Resnick, B.S., Dike, D.H., English, L.M., III, and Lewis, 

A.G., 1981, Evaluation of tar sand mining; v. 1. 

An assessment of resources amenable to mine 

production: U.S. Department of Energy 

DOE/ET/30201-1 (DE82010249), 214 p. 

Speight, J.G., 1980, The chemistry and technology of 

petroleum: New York, Marcel Dekker, 498 p. 

Heavy Oil and Natural Bitumen 59 
Geochemical Correlations in Petroleum Systems 

By Donald E. Anders 

Hydrocarbons in conventional petroleum and gas 

accumulations (nonbacterial) are degradation products of 

macromolecular organic structures (known as kerogen) 

disseminated in fine-grained sedimentary rocks. Kerogen 

breakdown occurs by a succession of physical and 

chemical transformations (diagenesis, catagenesis, and 

metagenesis) in response to burial heating over geologic 

time. The kerogen structures and the type of 

hydrocarbons (gas and liquid) produced from them 

during thermal evolution are related to the principal 

sources of the organic matter (algal, microbial, higher 

plants, and so on) and chemical conditions during 

deposition of the organic matter. 

The existence and recognition of distinct 

physical and chemical similarities between hydrocarbons 

in a reservoir and the insoluble (kerogen) and soluble 

(bitumen) organic constituents still retained in the source 

rock is the basis for geochemical correlation. 

Conversely, establishing that pairs of oils or oil-source 

rocks are not genetically related is based on the 

supposition that unrelated samples have geochemical 

dissimilarities. The ability to establish oil-to-oil, oil-tosource, gas-to-gas, gas-to-oil and gas-to-source genetic 

relationships are based on the assumption that the 

processes acting on the separated hydrocarbons, such as 

migration, thermal maturation, biodegradation, and water 

washing, do not adversely affect all of the composition 

parameters necessary for correlation. 

Before geochemical correlations are performed, 

the petroleum geologist needs to make sure that the 

combined geologic setting of the pooled hydrocarbons, 

proposed migrational pathways, and presumed source 

rocks are in harmony with the stratigraphic, structural, 

tectonic, and hydrodynamic constraints within the basin. 

Once the geologic setting has been worked out, 

geochemistry can establish the resource potential of 

probable source rocks, and correlation studies can 

determine the number of genetically related (families) 

oils, gases, and condensates in the basin and in 

identifying the source rocks from which the pooled 

hydrocarbons are derived. Correlation studies are also 

helpful in establishing possible communication between 

different pay zones (producing horizons) and fault blocks 

(Tissot and Welte, 1984, p. 549). 

Two kinds of chemical properties are used for 

correlation purposes: (1) bulk parameters which describe 

properties of the whole sample; and (2) specific 

parameters which measure in detail the chemical 

60 Petroleum Systems of the United States 

characteristics of a fraction of the sample. The most 

commonly employed correlation parameters in use today 

are listed in table 11. 

The choice of compositional parameter for 

correlation depends upon the type of hydrocarbon deposit 

to be correlated (gas, oil, condensate, biodegraded heavy 

oil, or tar sand) and the availability of methods to the 

explorationist. In conventional oil-to-oil and oil-tosource rock correlation studies, a large number of 

parameters can be used (see table 11 and Koons and 

others, 1974; Williams, 1974; Seifert and Moldowan, 

1978; Seifert and others, 1980; Welte and others, 1975, 

1982; Poole and Claypool, 1984) In other cases, such as 

the correlation of gases to one another or to oils or to 

their source rocks, only a limited number of parameters 

are useful: C/C1

-C4 (wetness), C5-C7 hydrocarbon 

distribution, and o13C and oD (Schoell, 1981, 1983, 

1984). In overmature rocks and oils or in biodegraded 

heavy oil seeps and tar sands, the choice of correlation 

parameters is again limited: naphthenoaromatics, 

aromatics, thiophenes, polycyclic naphthenes, and o13C 

(Tissot and others, 1974; Rullkotter and Welte, 1980; 

Moldowan and Seifert, 1980, Claret and others, 1977; 

Palacas and others, 1986; Anders and Magoon, 1986). A 

problem sometimes encountered in oil-to-source rock 

correlation is the occurrence of migrated hydrocarbons in 

the presumed source rock. A relatively new technique of 

pyrolyzing the kerogen or asphaltenes in the rock and 

then comparing the hydrocarbons of the pyrolyzate with 

the hydrocarbons in the oil has been extremely helpful in 

this regard (Rubinstein and others, 1979; Behar and 

others, 1984; Durand, 1983; Lewan and others, 1979). 

One of the most useful tools for correlations that 

has been developed in the past 20 years is in the area of 

high-resolution gas chromatography-mass spectrometry. 

This technique allows the fingerprinting of any number 

of classes of chemical compounds in the oil and bitumen 

or pyrolyzate for direct comparison. The compound 

types most useful for correlation, because of their 

ubiquitous nature and their stability over a wide range of 

geologic conditions, are the polycyclic naphthenes and 

naphthenoaromatics. These compounds, often referred to 

as "geochemical fossils" or "biological markers," are so 

called because they often retain enough of their original 

chemical character and skeletal structure so as to be able 

to relate them unambiguously to known biochemical 

molecules in living organisms (Anderson and others, 

1969; Hills and others, 1966; Anders, 1970; Kimble and 
Table 11. The most commonly used correlation parameters and their general application in gas-oil-source studies 

[y, application used; n, application not used; -,poor or not useful; +, sometimes useful; ++, often useful; +++,very useful; parameters can be affected 

by: 1, migration; 2, maturation; 3, biodgradation; *,useful in comparing very mature and degraded oils; C, carbon; D, deuterium; N, nitrogen; Ni, 

nickel; 0, oxygen; S, sulfur; V, vanadium; C#, number of carbon atoms per molecule] 

Analyses 

DescriEtion Bulk Specific Oil-oil 

b13C 

Kerogen y y +++ 

Bitumen y y +++ 

Crude oil y y +++ 

Saturated hydrocarbons y y +++ 

Aromatic hydrocarbons y y +++ 

NSO nonhydrocarbons y y +++ 

Asphaltenes y y +++ 

Methane gas n y 

Ethane gas n y 

bD 

Methane gas y n +++ 

b34S 

Crude oil y n +++ 

Bitumen y n +++ 

Ratios of: 

Saturated-/aromatic hydrocarbons y n +++ 

Hydrocarbons/nonhydrocarbons y n +++ 

Molecular distribution of: 

C/J:.C1-C4 (wetness) n y 

Cs-C1 n y +++ 

n-paraffins n y +++ 

Naphthenes n y +++ 

Aromatics .. n y ++ 

Thiophenes .. n y + 

Isoprenoids n y +++ 

Diterpenoids n y +++ 

Triterpenoids n y ++ 

Steranes n y ++ 

Aromatic steroids'" n y ++ 

Porphyrins n y ++ 

API gravity y n ++ 

V/Ni ratio n y +++ 

PercentS y n +++ 

Percent N y n +++ 

Optical activity y n ++ 

Infrared spectra y n ++ 

Hydrous pyrolysis on kerogen y n 

H~drous E~ol~sis on asEhaltenes ~ n 

others, 1974). If enough molecular information is 

retained on the "chemical fossil," it is possible to 

interpret the biological processes leading to its formation 

and perhaps even infer something about the chemical 

conditions during deposition and specific types of 

chemical reactions that occurred (for example: oxic, 

euxinic, thermal, hydrolyzing, decarboxylating) between 

Application 

Comments 

Oil-source Gas-gas Gas-oil Gas-source 

+++ 2 

+++ 1,2,3 

+++ 1,2,3 

+++ 1,2,3 

+++ 1,2 

+++ 1,2 

+++ 1,2 

+++ +++ +++ 

+++ +++ +++ 

+++ +++ +++ +++ 

+++ 

+++ 

+ 1,2,3 

+ 1,2,3 

++ 

+ + 3 

+++ 3 

+++ 

++ 

+ 

+++ 

+++ 

++ 1,2,3 

++ 1,2,3 

++ 2 

+ 2 

3 

++ 1 

+++ 1,2 

+++ 1,2 

+ 2,3 

++ 

++ 

++ 

the time of the organism's death and its discovery eons 

later. 

Although many biomarker hydrocarbons such as 

acyclic isoprenoids, steranes, and tri- and pentacyclic 

terpanes are ubiquitous in sedimentary organic matter 

and petroleum resources, their relative distributions are 

not. Of particular value in correlation studies are 

Geochemical Correlations in Petroleum Systems 61 
biomarker compounds which occur in a limited number 

of organisms. For comprehensive literature reviews on 

the use of biomarkers for correlation, see Connan (1981), 

Philp (1982), MacKenzie (1984), Tissot and Welte 

(1984), Waples (1985), and Johns (1986). 

When making correlation studies, as many 

different parameters should be used as economically 

feasible because from a chemical standpoint, it is far 

easier to prove that unrelated samples are different than 

it is to prove that similar samples are genetically related. 

The best correlations are those where both bulk and 

specific chemical properties are in agreement with one 

another and with the geologic constraints placed on the 

samples being compared. 

An example of a correlation study done in the 

Uinta basin of Utah to answer one of the questions 

frequently asked by petroleum explorationists (are the tar 

sand oils and gilsonite deposits derived from shallow 

immature, marginally mature, or deep mature sources?) 

is shown in figure 8 and table 12. In this example, both 

bulk properties and specific biomarker traces (m/z 217 = 

steranes, m/z 191 = tri- and pentacyclic terpanes, and m/z 

231 and 253 = tri- and monoaromatic steroids) are used 

for correlation. The degree of similarity in the bulk 

properties (carbon and sulfur isotopes) and biomarker 

distributions for all of the samples except the deepest oil 

suggests that the gilsonite, tar sand, and shallowest oil 

are all derived from the bitumen extracted from the 

organic matter in the Green River Formation. This 

proposed relationship is in agreement with geologic 

evidence as the accumulations are in stratigraphic 

communication with the source. The level of thermal 

maturity for various hydrocarbon compounds (based on 

certain isomeric and molecular ratios) in this comparison 

study also suggests that all of the hydrocarbons but the 

deepest oil are derived from rocks at similar levels of 

thermal stress (vitrinite reflectance equivalence = 0.4 to 

0.6 percent R0 ). This is further supported by vitrinite 

reflectance measurements: reservoir rocks of the 2,750 

m (9,000 ft) oil have a R = 0.8 percent whereas the 0 

reservoir rocks of the 1,435 m (4,700 ft) oil and the 

rocks from which the bitumen was extracted have a R = 0 

0.5 percent. The geochemical and geologic evidence 

strongly suggests that the gilsonite and tar sand are 

derived from immature to marginally mature organic 

matter in rocks of the Green River Formation. 

REFERENCES CITED 

Anders, D.E., 1970, Cycloalkanes from Green River oil 

shale and their relationship to living organisms: 

Laramie, University of Wyoming, M.S. Thesis, 

36 p. 

Anders, D.E., and Magoon, L.B., 1986, Oil-source 

correlation study in northeastern Alaska, in 

62 Petroleum Systems of the United States 

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

Advances in organic geochemistry 1985: 

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

Anderson, P.C., Gardner, P.M., Whitehead, E.V., Anders, 

D.E., and Robinson, W.E., 1969, The isolation 

of steranes from Green River oil shale: 

Geochimica et Cosmochimica Acta, v. 33, p. 

1304-1307. 

Behar, F., Pelet, R., and Roucache, J., 1984, 

Geochemistry of asphaltenes, in Schenk, P.A., 

ed., Advances in organic geochemistry 1983: 

Organic Geochemistry, v. 6, p. 587-595. 

Claret, J., Tchikaya, J.B., Tissot, B., Deroo, G., and 

vanDorsselaer, A., 1977, Un exemple d'huile 

biodegradee a basse teneur en soufre: le 

gisement d'Emeraude (Congo), in Campos, R., 

and Goni, J ., eds., Advances in organic 

geochemistry 1975: Madrid, ENADIMSA, p. 

509-522 (in French). 

Connan, J., 1981, Biological markers in crude oils, in 

Mason, J .F., ed., Petroleum geology in China 

1980: Tulsa, Penn Well, p. 48-70. 

Durand, B., 1983, Present trends in organic geochemistry 

in research on migration of hydrocarbons, in 

Bjoroy, M., ed., Advances in organic 

geochemistry 1981: Chichester, Wiley, p. 

117-128. 

Hills, I.R., Whitehead, E.V., Anders, D.E., Cummings, 

J.J., and Robinson, W.E., 1966, An optically 

active triterpane, gammacerane in Green River 

oil-shale bitumen: Chemical Communications, 

v. 20,p. 752-754. 

Johns, R.B., 1986, Biological markers in the sedimentary 

record: Amsterdam, Elsevier, 364 p. 

Kimble, B.J., Maxwell, J.R., Philip, R.P., and Eglinton, 

G., 1974, Identification of steranes and 

triterpanes in geolipid extracts by highresolution gas chromatography and mass 

spectrometry: Chemical Geology, v. 14, p. 

173-198. 

Koons, C.B., Bond, J.G., and Peirce, F.L., 1974, Effects 

of depositional environment and postdepositional 

history on chemical composition of lower 

Tuscaloosa oils: American Association of 

Petroleum Geologists Bulletin, v. 58, p. 

1272-1280. 

Lewan, M.D., Winters, J.C., and MacDonald, J.H., 1979, 

Generation of oil-like pyrolyzates from organicrich shales: Science, v. 203, p. 897-899. 

MacKenzie, A.S., 1984, Application of biological 

markers in petrogeochemistry, in Brooks, J., and 

Welte, D., eds., Advances in petroleum 

geochemistry, v. 1: London, Academic Press, p. 

115-214. 

Moldowan, J.M., and Seifert, W.K., 1980, First discovery 

of botryococane in petroleum: Journal of the 
~ Ci5 

z 

w 

1-

~ 

w 

> 

w 

~ a: 

mlz 191 mlz 217 

Eureka gilsonite (surface) 

Asphalt Ridge tar sand (surface) 

Parachute Creek bitumen (2480 ft) 

Red Wash oil (4042-4082 ft) 

Bluebell oil (9230-9898 ft) 

TIME --.. 

mlz 231. 253 

L 

=:::: 

.A 

-A 

T .al J~LIL_ 

Figure 8. Comparison of biomarker distributions in these gas chromatograms show that gilsonite and tar sand oil at 

the surface are related to immature, shallow bitumen (756 m; 2,480 ft) or oil (1,397 m; 4,682 ft) rather than to the deep 

mature oil (2,743 m; 9,000 ft). Data are summarized in table 12. 

Geochemical Correlations in Petroleum Systems 63 
Table 12. Some commonly used correlation parameters to show the origin of gilsonite and tar sand oil 

Sample name Burial depth 

Eureka Gilsonite 

Asphalt Ridge tar sand 

Parachute Creek bitumen 

Red Wash oil 

Bluebell oil 

m 

Surface 

Surface 

756 

1,397 

2,743 

ft 

Surface 

Surface 

2,480 

4,682 

9,000 

Chemical Society Chemical Communications, v. 

34, p. 912-914. 

Patacas, J.G., Monopolis, D., Nocolaou, C.A., and 

Anders, D.E., 1986, Geochemical correlation of 

surface and subsurface oils, western Greece, in 

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

Advances in organic geochemistry 1985: 

Organic Geochemistry, v. 10, p. 417-423. 

Philp, R.P., 1982, Application of computerized gas 

chromatography-mass spectrometry to fossil fuel 

research: Spectra, v. 8, p. 6-31. 

Poole, F.G., and Claypool, G.E., 1984, Petroleum 

source-rock potential and crude-oil correlation in 

the Great Basin, in Woodward, J., Meissner, 

F.F., and Clayton, J .L., eds., Hydrocarbon source 

rocks of the greater Rocky Mountain Region: 

Denver, Rocky Mountain Association of 

Geologists, p. 179-229. 

Rubinstein, I., Spyckerelle, C., and Strausz, O.P., 1979, 

Pyrolysis of asphaltenes: A source of 

geochemical information: Geochimica et 

Cosmochimica Acta, v. 43, p. 1-6. 

Rullkotter, J., and Welte, D.H., 1980, Oil-oil and oilcondensate correlation by low e V GC-MS 

measurements of aromatic hydrocarbons, in 

Douglas, A.G ., and Maxwell, J .R., eds., 

Advances in organic geochemistry 1979: 

Oxford, Pergamon Press, p. 93-102. 

Schoell, M., 1981, Application of isotopic analyses in oil 

and natural-gas research: Erdol und Koble, 

Erdgas, Petrochemie, v. 34, p. 537-544 (in 

German). 

1983, Genetic characterization of natural gases: 

American Association of Petroleum Geologists 

Bulletin, v. 67, p. 2225-2238. 

1984, Stable isotopes in petroleum research, in 

64 Petroleum Systems of the United States 

o34s 

Elemental 

sulfur 

+27.9 

+30.0 

+30.8 

+28.4 

+16.6 

Saturated 

hydrocarbons 

-32.7 

-31.9 

-32.2 

-32.2 

-31.6 

Aromatic 

hydrocarbons 

-31.8 

-30.7 

-31.8 

-31.2 

-30.4 

Brooks, J., and Welte, D.H., eds., Advances in 

petroleum geochemistry v. 1: London, Academic 

Press, p. 215-245. 

Seifert, W.K., and Moldowan, J.M., 1978, Application of 

steranes, terpanes and monoaromatics to the 

maturation, migration and source of crude oils: 

Geochimica et Cosmochimica Acta, v. 42, p. 

77-95. 

Seifert, W.K., Moldowan, J.M., and Jones, R.W., 1980, 

Application of biological marker chemistry to 

petroleum exploration: 1Oth World Petroleum 

Congress Proceedings, v. 2, p. 425-438. 

Tissot, B.P., Durand, B., Espitalii, J., and Combaz, A., 

1974, Influence of nature and diagenesis of 

organic matter in formation of petroleum: 

American Association of Petroleum Geologists 

Bulletin, v. 58, p. 499-506. 

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

and occurrence: Berlin, Springer-Verlag, 699 p. 

Waples, D.W., 1985, Geochemistry in petroleum 

exploration: Boston, International Human 

Resources Development Corporation, 232 p. 

Welte, D.H., Hagemann, H.W., Hollerbach, A., 

Leythaeuser, D., and Stahl, W., 1975, 

Correlation between petroleum and source rock: 

9Lh World Petroleum Congress Proceedings, v. 

2, p. 179-191. 

Welte, D.H., Kratochvil, H., Rullkotter, J., Ladwein, H., 

and Schaefer, R.G., 1982, Organic geochemistry 

of crude oils from the Vienna Basin and an 

assessment of their origin: Chemcal Geology, v. 

35, p. 33-68. 

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

Williston Basin: American Association of 

Petroleum Geolgoists Bulletin, v. 58, p. 

1243-1252. 
Computer Applications 

By Kenneth I. Takahashi, Thaddeus S. Dyman, and Leslie B. Magoon 

INTRODUCTION 

The Branch of Petroleum Geology conducts 

topical and regional research on geological, geochemical, 

and geophysical aspects on the origin, migration, 

accumulation, and distribution of petroleum resources. 

Computerized information and data systems are accessed 

continually during these research activities. In addition, 

data generated within the branch as part of the research 

effort are integrated with existing data systems and 

computer software. The computerized data acquired 

through this research are valuable for defining, 

illustrating, and describing a petroleum system. 

The purpose of this paper is to describe ( 1) the 

computer and data systems available to the Branch of 

Petroleum Geology and (2) how these data systems can 

be integrated to facilitate petroleum system research. 

COMPUTER APPLICATIONS 

Computer support for the petroleum system 

research includes computer programming, data bases and 

data management, and applications software. Computer 

programming support includes writing new computer 

programs or modifying existing programs for research 

applications. Data systems support includes accessing 

available data bases, developing new data bases, and 

integrating data from computerized files using data 

management software. Existing computer software 

applications include spread sheets, word processing, 

statistical and numerical analyses, data summary and 

tabulation, and mapping and contouring. Computer 

systems support includes dissemination of geological 

information for all phases of petroleum system research. 

Computer Systems 

In Denver, Colorado, the Branch of Petroleum 

Geology facilities include a 200-m2 (2,200 ft2

) computer 

room and two user rooms with terminals and plotters 

accessable to the user. A VAX 11/780 is used by the 

geologic research staff and includes considerable 

software; a Micro VAX is used for word-processing. For 

geophysical processing, a DISCO VAX 11/780 system is 

in a separate computer room. In Menlo Park, California, 

a VAX 11nso is used by the research staff and has the 

same software that is available in Denver. Table 13 lists 

the computer systems and software packages. 

In Denver, a Micro VAX II is used for wordprocessing; WPS-plus software is used by clerical and 

geologic staff and can be accessed from terminals in 

offices, in the centrally located user rooms, or by dialup 

telephones from remote facilities. Printers are located in 

several easily accessible locations. Using WPS-plus, 

documents can be exchanged between technical and 

clerical staff for editing and review and transmitted to 

other U.S. Geological Survey offices. The DISCO VAX 

11/780 is located in a separate facility maintained by the 

Geophysics research group. This system is used mainly 

for seismic data processing and reprocessing and seismic 

interpretation. Several computers dedicated to petroleum 

geochemical and well log analysis are also available to 

research scientists. In addition, personal computers and 

Macintoshs are being used for graphics, desk-top 

publishing, and statistical analyses. 

Communications and networking options on 

branch computers are flexible. The VAX systems can be 

accessed from throughout the United States using the 

wide-area networks Geonet and Tymenet, maintained by 

the U.S. Geological Survey. Interactive user sessions 

and file transfers are possible within the network. The 

v AX 11n8o, Microvax II, and the DISCO VAX are also 

linked together locally using DECnet, allowing users on 

any of our systems to transfer files, messages, or 

documents to other users on any other VAX system 

linked to either the local or wide-area networks. 

Data Management 

The Branch of Petroleum Geology uses 

TECH/SYS and Datatrieve for storage and retrieval of 

large data files on the VAX 11n8o. TECH/SYS, a file 

management and data retrieval system designed by 

Petroleum Information Corporation (PI) of Denver, 

Colorado, uses a command file of data and format 

specifications to retrieve data from up to four data bases 

at one time (Petroleum Information Corporation, 1984). 

TECH/SYS was originally designed to retrieve wellhistory data from PI's Well History Control System 

(WHCS); it is also used to access the Petroleum Data 

System (PDS), the NRG Associates Significant Oil and 

Gas Fields File for field and reservoir data, and the North 

Slope geochemistry file. TECH/SYS will also be used to 

retrieve data from the Petroleum System Data Base 

(PSDB), where data will be stored by individual 

petroleum systems. 

Datatrieve is a database program developed by 

Digital Equipment Corporation which has data base 

Computer Applications 65 
updating and file management capabilities that are tied to 

the VAX VMS operating system. Datatrieve is used to 

retrieve bibliographic data and data from small project 

files developed for petroleum system applications. 

Applications Software 

Applications software includes programs for 

digital mapping, statistical and numerical analyses, and 

graphical data display. Most digital maps are produced 

using Dynamic Graphics Corporation's Interactive 

Surface Modeling (ISM) system. Special ISM features 

are menu-driven parameter selection, file management, 

graphic editing, zooming and panning of graphic data, 

and grid and data manipulation (Dynamic Graphics 

Corporation, 1986). ISM is used with the Well History 

Control System (WHCS) data to produce isopach, 

structure, and total-sediment thickness maps. Petrologic, 

geochemical, and geophysical data can also be mapped. 

The Geologic Analysis System (GAS) was 

developed by PI and contains computer software for 

graphic display and statistical analyses of geologic and 

lithologic data. GAS includes TECH/SYS, discussed 

above; Petroleum Information Contouring System 

(PICS); Petroleum Geochemical System (PGS); TimeTemperature Index (TTl); Stratigraphic Report Graphic 

(SRG); and Sample Data System (SDS). 

PICS is a general-purpose contouring software 

package that can post wells from the WHCS file. Each 

posted well symbol can be annotated with up to four 

values; any one well can be represented by up to ten 

status symbols. For most uses, this software package has 

been supplanted by ISM. 

PGS includes data files and applications 

programs for commonly available petroleum geochemical 

analyses. The analyses are of the type that an 

exploration geologist would use to evaluate the richness, 

organic type, and thermal history of important sourcerock intervals from the perspective of the drilling well or 

the entire basin. Data files include geochemistry, 

WHCS, wireline logs, lithology, and temperature. 

Til is a burial history software package based 

on the Lopatin method of Waples (1980, 1981). Burial 

history profiles, past and present temperature gradients, 

and indicators of thermal history are used in concert to 

calculate the time-temperature indices, which are then 

mapped to show hydrocarbon generating zones 

throughout geologic time. 

SRG is a stratigraphic applications program that 

accepts sedimentologic, paleontologic, lithologic, 

paleoecologic, and nomenclatural data for outcrop 

sections and cores, and displays these data in a scalevariant format (Petroleum Information Corporation, 1984; 

Dyman and others, 1985). 

SDS is a statistical and graphic module that 

includes correspondence, factor, and cluster analysis; the 

graphic module generates triangular and cross plots 

66 Petroleum Systems of the United States 

(Petroleum Information Corporation, 1984). 

Additional software includes the Statistical 

Package for the Social Sciences (SPSS), Minitab, and 

TELL-A-GRAF. Resource assessment computer 

programs such as F ASP have also been developed by the 

Branch. F ASP is a fast appraisal system for petroleum 

play analysis using a reservoir-engineering geologic 

model and an analytic probabilistic methodology 

(Crovelli and Balay, 1986). 

Data Systems 

The Branch of Petroleum Geology accesses PI's 

Well History Control System (WHCS), the Petroleum 

Data System (PDS), the NRG Associates Significant Oil 

and Gas Field File (NRG), and the Petroleum 

Geochemistry file (PGF)(table 13). 

WHCS contains information on geologic, 

engineering, production, and formation tests, and 

descriptive location for more than 1. 7 million wells 

drilled in the United States. Parts of the WHCS data 

base are stored either online on disk or offline on 

magnetic tape depending on the level and variety of 

usage within the branch. A WHCS extract file 

containing basic location, completion, and identification 

information for all wells in the WHCS file is available 

using Datatrieve. This file is used for a variety of basin 

analysis and resource assessment applications. 

PDS is a historical file containing geologic, 

engineering, and production data for more than 80,000 

oil and gas fields and reservoirs in the United States 

(Dyman, 1978). PDS annual production figures are 

presently acquired from PI, but no system is presently 

available to update geologic data for existing fields and 

reservoirs. 

The NRG Associates Significant Oil and Gas 

Fields File (NRG) is similar to PDS but only includes 

data for fields with ultimate recoverable resources larger 

than 1 million barrels (NRG Associates, 1985). This file 

also contains reserve data and is updated annually. 

A petroleum geochemistry data base (PGF) is 

now being developed. Data will include standard organic 

geochemical analyses such as vitrinite reflectance, 

pyrolysis, thermal alteration index (TAl), total organic 

carbon (TOC), and chromatographic data. This data base 

expands on the Alaska North Slope geochemistry file, 

and will include both new and historic data from the 

branch's organic geochemical laboratory. 

PETROLEUM SYSTEM DATA BASE (PSDB) 

In order to quantitatively define and analyze a 

petroleum system, a Petroleum System Data Base 

(PSDB) is now being developed by the Branch of 

Petroleum Geology. Table 14 contains the preliminary 

file structure for the PSDB. Data from the PSDB can be 
Table 13. Computer systems specifications and software, Branch of Petroleum Geology 

[SPSS, Statistical Package for the Social Sciences; ISM, Interactive Surface Modeling; RGSL, Regional Geophysical software library; GAS, Geologic 

analysis system which includes TECH/SYS (Petroleum Information data base management system, now called PI Base), PICS (Petroleum Information 

contouring system), PGS (Petroleum geochemical system), m (Time-temperature index), SRG (Stratigraphic report graphic), and SDS (Sample data 

system); WHCS, Well history control system; PDS, Petroleum data system; NRG, NRG Associates oil and gas field file; PGF, Petroleum geochemical 

file; PC, Personal computer] 

System Location Hardware specifications Software packages 

VAX 11nso Denver 8 megabytes memory, 

7 gigabytes disk storage; 

color graphics terminals; 

plotters, digitizers; 

VMS operating system; 

DECNet communications 

Data and applications software: 

Minitab, SPSS, ISM, RGSL, GAS 

WHCS, PDS, NRG, PGF 

MicroVAX II Denver 16 megabytes memory; 

456 megabytes disk storage 

laser text printers; 

DECNet communications 

WPS-plus 

VAX 11nso Denver 24 megabytes memory; 

1.2 gigabytes disk storage; 

VMS operating system 

DISCO seismic processing; 

Explorer 

VAX unso Menlo Park 4 megabytes memory; 

1.1 gigabytes disk; 

VMS operating system 

ISM, GAS 

IBM PC's and 

Macintoshes 

Denver 

Menlo Park 

integrated with other computerized files for a wide 

variety of research applications. 

Magoon (this report) defines petroleum system 

categories based on type of reservoir rock (siliciclastic or 

carbonate), type of source rock (1, II, or lll), and whether 

a petroleum system is purebred or hybrid. A system's 

level of certainty is indicated by (!) for known, (.) for 

hypothetical, and (?) for speculative. Additional data 

elements include the age and formation code for each 

petroleum system source rock and reservoir rock. These 

codes are derived from PI's age and fonnation code list 

(Petroleum Information Corporation, 1979) and can be 

expanded as needed. The full petroleum system name is 

also identified. 

The file structure for the petroleum system data 

base is an 80~column card~image format (table 14). The 

first character is 9 which indicates the 14-digit API 

number format follows. The State and county code 

numbers from the API Bulletin D12A are placed in 

Columns 2 through 6 (American Association of 

Petroleum Geologists Committee on Statistics and 

Drilling, 1966; American Petroleum Institute, 1979). A 

right-justified unique number for each petroleum system 

is entered into columns 7 through 11. A 3-digit API 

province code is placed in columns 12 through 15 

(Meyer, 1974). The county~distribution is that portion of 

a county, in percent from 1-100, that the petroleum 

system covers; this number is placed in columns 16 

through 18. The remainder of the format includes: the 

Variable Graphics, technical word 

processing, and administrative 

ap lications 

name of the petroleum system in columns 19 through 35; 

its level of certainty in column 36; information to 

classify the system in columns 37 through 45; and the 

petroleum system name written out in the last 35 

columns. The codes for the source rock and reservoir 

rock are from PI's WHCS file documentation. 

Since most petroleum systems will occupy 

several counties, a county-distribution parameter has 

been included in the data base. For example, the 

Phosphoria-Weber petroleum system may occupy all or 

parts of many counties in the Rocky Mountain region. 

Thus, the county distribution parameter may equal 100 

percent for many counties or less than 100 percent for 

others. Based on this file structure, a single petroleum 

system (a unique petroleum sequence number) may have 

many unique state and county identification numbers, and 

many county-distribution parameters. In this way, 

petroleum systems can be subdivided into geographic and 

geologic units; the data from these units can also be 

integrated with data from other data files. 

The PSDB can be integrated with the WHCS 

well data base by unique API sequence numbers 

(American Petroleum Institute, 1979), province codes, 

age and formation codes, and gross lithology. WHCS 

data can be retrieved by any of these parameters, edited 

for accuracy, and integrated with other petroleum system 

data. Distributions such as total drilled feet, drilling 

completions through time, drilling by location, and 

undrilled thicknesses can be generated for each 

Computer Applications 67 
Table 14. File structure for an 80-column card-image format for the petroleum system data base 

l A, alpha characters; X, numeric characters; API, American Petroleum Institute; PI, Petroleum Information Corporation; see Magoon (this report) for 

definition of petroleum system data elements] 

Data element 

Number "9", indicates API number format 

API State (XX) and county (XXX) number 

Unique petroleum system number 

API Province code 

County-distribution in percent (~100) 

Source rock: geologic age and rock unit name (PI code) 

Hyphen separating source and reservoir rock unit codes 

Reservoir rock: geologic age and rock unit name (PI code) 

Level of certainty: known (K), hypothetical (H), or speculative (H) 

Geologic setting: purebred (pur) or hybrid (hyb) 

Reservoir rock type: siliciclastic (silic) or carbonate (carbo) 

Source rock type: I (1), II (2), or lli (3) 

Complete petroleum system name 

petroleum system. Reservoir data from the PDS and 

NRG field files can be retrieved by reservoir or 

formation name, province, county, State, and latitudelongitude location and can be integrated with PSDB data. 

Production histories, geologic and engineering parameter 

summaries, and resource assessments can be easily 

produced for each petroleum system. 

Additional applications include PSDB 

integration with the Branch of Petroleum Geology 

petroleum geochemistry file, published bibliographic 

files, and a host of published data generated by formation 

and geographic location. 

The PSDB will be an effective mechanism to 

store, retrieve, and analyze information gathered through 

petroleum system research. 

REFERENCES CITED 

American Association of Petroleum Geologists 

Committee on Statistics and Drilling, 1966, 

Standard state, county, operator, and 

stratigraphic codes: Tulsa, American Association 

of Petroleum Geologists, 60 p. 

American Petroleum Institute, 1979, The API well 

number and standard state and county numeric 

codes including offshore waters: API Bulletin 

D12A, Washington, D.C., American Petroleum 

Institute, 136 p. 

Crovelli, R.A., and Balay, R.H., 1987, FASP, an 

analytical resource appraisal system for 

petroleum play analysis: Computers and 

Geosciences, v. 12, no. 4B, p. 423-475. 

Dyman, T.S., 1978, Data on 80,000 fields available to 

industry: World Oil, v. 186, no. 1, p. 109-116. 

68 Petroleum Systems of the United States 

Columns 

1 

2-6 

7-11 

12-15 

16-18 

19-26 

27 

28-35 

36 

37-39 

40-44 

45 

46-80 

Character type 

X 

xxxxx 

X XXX X 

xxxx 

XXX 

XXXAAAAA 

XXXAAAAA 

A 

AAA 

AAAAA 

X 

alpha 

Total characters 

1 

5 

5 

4 

3 

8 

1 

8 

1 

3 

5 

1 

35 

Total 80 

Dyman, T.S., Materna, W.L., and Wilcox, L.A., 1985, 

Stratigraphic applications of the Geologic 

Analysis System (GAS)-A case study [abs.]: 

American Association of Petroleum Geologists 

Bulletin, v. 69, no. 2, p. 251. 

Dynamic Graphics Corporation, 1986, Interactive Surface 

Modeling (ISM) users guide: Berkeley, Dynamic 

Graphics Corporation, 104 p. 

Meyer, R.F., ed., 1974, Geologic provinces of the United 

States: Tulsa, Oklahoma, American Association 

of Petroleum Geologists, scale 1:5,000,000. 

NRG Associates, 1985, The field/reservoir clusters of the 

United States: Colorado Springs, NRG 

Associates. 

Petroleum Information Corporation, 1979 (with annual 

updates), Well History Control System (WHCS) 

manual: Denver, Petroleum Information 

Corporation. 

1984, Geologic Analysis System (GAS}-

Technical services training manual: Denver, 

Petroleum Information Corporation, 195 p. 

Waples, D.W., 1980, Time-temperature relation in 

petroleum exploration: Application of Lopatin's 

method to petroleum exploration: American 

Association of Petroleum Geologists Bulletin, v. 

64, p. 916-926. 

1981, Organic geochemistry for exploration 

geologists: Minneapolis, Burgess, 151 p. 

Wilcox, L.A., Coit, T.A., and Magoon, L.B., in press, 

The National Petroleum Reserve in Alaska 

computer data and graphics system-An aid to 

geologic interpretation, in Gryc, George, ed., 

Geology of the National Petroleum Reserve in 

Alaska: U.S. Geological Survey Professional 

Paper 1399. 

GPO 585-045/9764 
SELECTED SERIES OF U.S. GEOLOGICAL SURVEY PUBLICATIONS 

Periodicals 

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Professional Papers are mainly comprehensive scientific reports of 

wide and lasting interest and importance to professional scientists and engineers. Included are reports on the results of resource studies and of 

topographic, hydrologic, and geologic investigations. They also include 

collections of related papers addressing different aspects of a single scientific topic. 

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geographic coverage than Professional Papers. They include the results 

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to professional geologists, hydrologists, and engineers. The series covers 

investigations in all phases of hydrology, including hydrogeology, 

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and columnar sections only. 

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is 1:24,000 and regional studies are at 1:250,000 scale or smaller. 

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