Feasibility Study of Material-Balance 

Assessment of Petroleum from the 

New Albany Shale in the Illinois Basin 

U.S. GEOLOGICAL SURVEY BULLETIN 2137 

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Cover. Map showing locations of wells that penetrate Mississippian or Upper 

Devonian rocks in the Illinois Basin (heavy line). Data from Petroleum Information 

Corp. Well History Control System. 
Feasibility Study of Material-Balance Assessment of 

Petroleum from the New Albany Shale 

in the Illinois Basin 

By M.D. Lewan, J.B. Comer, T. Hamilton-Smith, N.R. Hasenmueller, 

J.M. Guthrie, J.R. Hatch, D.L. Gautier, andW.T. Frankie 

U.S. GEOLOGICAL SURVEY BULLETIN 2137 

A material-balance assessment of the petroleum expelled from 

source rocks in the New Albany Shale and accountable 

petroleum within the Illinois Basin 

UNITED STATES. GOVERNMENT PRINTING OFFICE, WASHINGTON : 1995 
U.S. DEPARTMENT OF THE INTERIOR 

BRUCE BABBITT, Secretary 

U.S. GEOLOGICAL SURVEY 

Gordon P. Eaton, Director 

For sale by U.S. Geological Survey, Information Services 

Box 25286, Federal Center 

Denver, CO 80225 

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

does not imply endorsement by the U.S. Government 

Library of Congress Cataloging-in-Publication Data 

Feasibility study of material-balance assessment of petroleum from the New Albany Shale 

in the Illinois Basin I by M.D. Lewan ... [et al.]. 

p. em. - (U.S. Geological Survey bulletin: 2137) 

Supt. of Docs. no.: I 19.3:2137 

1. Petroleum reserves-Illinois Basin. 2. Petroleum-Geology-Illinois 

Basin. 3. New Albany Shale (Ind. and Ky.) I. Lewan, M.D. (Michael D.), 1948-

II. Series. 

QE75.B9No. 2137 

[TN872.A5] 

557.3 s-dc20 95-24456 

[553.2'8'0977 CIP 
CONTENTS 

Abstract........................................................................................................................... 1 

Introduction..................................................................................................................... 1 

Methods and Results . . . .. .. . ...... ... ... . ... ... ........ .. . . .. .. ..... ......... .. .. .. . ... ... ... .. ... ..... .. ..... .... ......... 4 

Source-Rock Characterization . ... .. . . .. . . . .... .......... .. .. . ............ .. . . .. ...... .. . ...... ........ .. .. . .. 4 

Stratigraphy..................................................................................................... 4 

Thickness . . ............. .. .. . ..... .. ... . . . . ... .. ....... .. . .. ... . .. . ............ ... ..... ... . . . ..... .......... ..... 5 

Thermal Maturity . . ...... ... .. .. ... .... ... .. . . . . . . . . .. .. .... ... . . .. . .. ............ ...... .. ......... .......... 5 

Volume............................................................................................................ 5 

Organic Richness .......... ......... .. . . . . . . . . . .. ............... .. . .. ... ....... .. ......... ........ .. ......... 9 

Expulsion Factor..................................................................................................... 13 

Rock-Eval Pyrolysis........................................................................................ 14 

Hydrous Pyrolysis........................................................................................... 15 

Accountable In-Place Petroleum............................................................................. 16 

Discussion ....... ......... .. . ............ ... ... .. . . . ... . . . .. .. .............. .. . . . .. ............ .. . ..... ... . . . ..... ........... .... 20 

Petroleum Charge .................................................................................................... 20 

Petroleum Losses ............... .. .. .. . . . . . . . . . ... . .. ......... ..... .. ... ....... .. . . . . ......... .. ...... ...... .. . ...... 23 

Material Balance ......... .. ....... .. .. ......... ........ .. . . . ... .......... .. .. . ...... ...... .. ....... ....... .. ......... 24 

Future Research ....................................................................................................... 25 

Conclusions..................................................................................................................... 26 

Acknowledgments ........................................................................................................... 27 

References Cited . . . . . . ........ .. . .. ......... ... ... ................ .. . . . ......... .. . . . ................ ...... ...... ...... ...... 27 

FIGURES 

1. Map of Illinois, Indiana, and western Kentucky showing outline of the Illinois Basin based on outcrop, 

subcrop, and limit of the New Albany Shale............................................................................................................... 3 

2. Correlation of New Albany Shale in the Illinois Basin............................................................................................... 4 

3. Northwest-southeast and west-east stratigraphic cross sections of the New Albany Shale 

in the Illinois Basin...................................................................................................................................................... 6 

4. Isopach map of Blocher Member of New Albany Shale............................................................................................. 7 

5. Isopach map of Selmier Member of New Albany Shale............................................................................................. 7 

6. Isopach map of "upper shale composite" member of New Albany Shale ......... ............................. ............................ 8 

7. Isoreflectance contour map, Illinois Basin.................................................................................................................. 8 

8. Empirical relationship between mean Rock-Eval hydrogen indices and mean random vitrinite 

reflectances from core samples of New Albany Shale................................................................................................ 9 

9. Relationship between TOC per m2 and thickness of source rock................................................................................ 14 

10. Relationship between Rock-Eval expulsion factors and hydrogen index................................................................... 17 

11. Quantity of oil expelled from hydrous-pyrolysis experiments.................................................................................... 17 

12. Relationship between hydrous-pyrolysis expulsion factors and hydrogen index....................................................... 17 

13. Relationship between Fischer assay yields and heating rates..................................................................................... 20 

14. Change in measured inert organic carbon and calculated original total organic carbon from 

Rock-Eval pyrolysis with increasing maturity ..... -....................................................................................................... 21 

Ill 
IV CONTENTS 

TABLES 

1. Summary ofTOC and Rock-Eva! data on cores of New Albany Shale..................................................................... 10 

2. Surface area and volume of source rocks in members of New Albany Shale............................................................. 11 

3. Thickness and percentage of source rock in members of New Albany Shale............................................................ 12 

4. Organic richness of immature source rocks in members of New Albany Shale......................................................... 13 

5. Mass of total organic carbon in source rocks in members of New Albany Shale....................................................... 14 

6. Rock-Eva! expulsion factors....................................................................................................................................... 16 

7. Quantity of petroleum expelled from the New :Albany Shale as determined by Rock-Eva! expulsion factors.......... 18 

8. Quantity of petroleum expelled from the New Albany Shale as determined by hydrous-pyrolysis 

expulsion factors.......................................................................................................................................................... 19 

9. Calculated inert and original organic carbon from Rock-Eva! data............................................................................ 22 

10. Material balance of accountable petroleum and petroleum charge from source rocks of the 

New Albany Shale....................................................................................................................................................... 25 
FEASIBILITY STUDY OF MATERIAL-BALANCE 

ASSESSMENT OF PETROLEUM FROM THE 

NEW ALBANY SHALE IN THE ILLINOIS BASIN 

By M.D. Lewan, 1 J.B. Comer,2 T. Hamilton-Smith,3 N.R. Hasenmueller,2 J.M. Guthrie,4 

J.R. Hatch, 1 D.L. Gautier, 1 and W.T. Frankie5 

ABSTRACT 

This study examines the feasibility of assessing petroleum resources of an established petroleum basin by a material-balance method. This method involves determining the 

amount of petroleum (1) expelled from mature and overmature source rocks, (2) discovered in place, and (3) lost by 

migration, surface leakage, and erosion. The Illinois Basin 

was used for this study because of its extensive drilling history as an established petroleum basin, good estimates of discovered in-place petroleum from production data, welldeveloped geological framework based on subsurface data, 

and availability of geochemical databases on source rocks of 

the New Albany Shale and related petroleum. Although 

additional research is needed to fully develop this method, 

the results from this study indicate that a material-balance 

assessment is feasible. The amount of petroleum expelled 

from source rocks in the New Albany Shale within the Illinois Basin is estimated to be between 152 and 236 billion 

barrels. Currently, 12 billion barrels of this expelled petroleum has been discovered in place. Vertical secondary 

migration along fractures and faults appears to have been 

dominant in the Illinois Basin. However, 18 to 55 billion barrels of residual petroleum may be lost within carrier beds as 

a result of some lateral secondary migration. In-place tar 

deposits of western Kentucky represent 15 to 30 billion bar·-

rels of original undegraded petroleum, and an additional 46 

to 91 billion barrels of petroleum may have been lost due to 

erosion of the Upper Pennsylvanian through Permian 

1U.S. Geological Survey, Box 25046, Denver Federal Center, Denver, 

co 80225. 

2Indiana Geological Survey, 611 North Walnut Grove, Bloomington, 

IN 47405. 

3Kentucky Geological Survey, 228 Mining and Mineral Resources, 

University of Kentucky, Lexington, KY 40506-0107. 

4Department of Geology, Indiana University, Bloomington, IN 47405. 

5Illinois State Geological Survey, 615 East Peabody Drive, Champaign, IL 61820. 

section. Although this material balance yields reasonable 

values, the uncertainty in assumptions and variability in values make it too equivocal at this time to determine the 

amount of petroleum remaining to be discovered. This feasibility study yields a broad range of -37 to 144 billion barrels 

of petroleum from the New Albany Shale that remain to be 

discovered in conventional or unconventional accumulations 

in the Illinois Basin. The -37 billion barrels indicates that 

possibly no more undiscovered petroleum remains to be 

found and that the amounts of accountable petroleum lost to 

carrier beds or erosion are overstated. The 144 billion barrels 

indicates that possibly the expulsion factors or the steadystate model for organic richness for the source rocks in the 

mature part of the basin are overstated. Although this range 

is broad, it does encompass and does not completely exceed 

the range of accountable petroleum within the basin. Future 

research directed toward the uncertainties in petroleum 

expulsion factors and original organic richness of mature 

source rocks is attainable and will significantly enhance the 

utility of this assessment method. 

INTRODUCTION 

The increasing dependence on foreign petroleum and 

the decreasing domestic exploration effort in the United 

States are important national concerns. In order to properly 

posture domestic and foreign policies to optimize sources of 

future energy supplies, accurate and credible assessments of 

petroleum resources in the United States and the world are 

essential. Assessments of undiscovered petroleum are currently based on statistical evaluations and geological analogs 

of discovered petroleum. These types of assessments typically reflect amounts of petroleum to be found by existing 

technologies and exploration strategies and do not necessarily reflect ultimate amounts of unconventional and undiscovered conventional petroleum remaining to be found in a 

sedimentary basin. 
2 MATERIAL-BALANCE ASSESSMENT OF PETROLEUM, NEW ALBANY SHALE, ILLINOIS BASIN 

A more scientifically based method to determine the 

ultimate petroleum potential of a sedimentary basin may be 

through a material-balance assessment. This method 

requires the evaluation of petroleum charge and petroleum 

losses within a sedimentary basin. Petroleum charge is the 

amount of petroleum expelled from mature and over-mature 

source rocks. Petroleum losses are the amounts of petroleum 

lost as a result of leakage to the surface or dispersed and 

residual amounts along migration pathways. The difference 

between these two parameters gives the ultimate petroleum 

potential of a sedimentary basin. The difference between the 

ultimate petroleum potential and discovered in-place petroleum gives the amount of undiscovered petroleum remaining 

within a sedimentary basin. This amount includes both 

undiscovered conventional and unconventional petroleum. 

Determining petroleum charge requires realistic expulsion factors for identified source rocks and a thorough characterization of mature and over-mature source rocks. The 

first requirement has been problematic in the past because 

open, anhydrous laboratory pyrolysis methods (i.e., RockEva!) are unrepresentative of natural processes and grossly 

overestimate the amounts of petroleum that are expelled 

from a source rock (Lewan, 1994). This obstacle has more 

recently been alleviated in part through the development of 

a laboratory pyrolysis method (i.e., hydrous pyrolysis) that 

more closely simulates natural petroleum generation and 

expulsion (Lewan, 1993). As a result, more realistic expulsion factors for source rocks can be determined. The second 

requirement, to characterize mature and over-mature source 

rocks, has not been an obstacle in the past but has often been 

neglected or oversimplified. Two of the most common transgressions of this requirement are the inclusion of large volumes of organic-lean rocks that have no significant potential 

as source rocks and the use of only the most organic-rich 

samples to represent an entire mixed section of source and 

non-source rock. Currently, knowledge of what constitutes a 

petroleum source rock and availability of completely cored 

sections of source rocks have made the fulfillment of this 

requirement more attainable than in the past. 

Determining petroleum losses within a sedimentary 

basin remains a challenging task. Although considerable 

efforts have been made to study the expulsion of petroleum 

from source rocks and the reservoir character of entrapped 

petroleum, few studies have been made on the intermediate 

processes responsible for migration of petroleum from 

source rock to trap. Past attempts to quantify petroleum lost 

during migration have invoked enormous petroleum losses 

because of exaggerated ultimate petroleum charge values 

determined by Rock-Eva! pyrolysis. Most of these postulated petroleum losses were attributed to surface leakage, 

which typically could not be justified by the presence of 

heavy-oil or tar deposits. In addition, these studies were 

based on petroleum migration through porous rocks, with 

only minimal consideration being given to migration along 

regional fractures or faults. Determining petroleum losses 

during migration becomes a more realistic and practical. 

challenge with more realistic values of ultimate petroleum 

charge, a greater awareness of the consequences of surface 

leakage, and a new appreciation for migration along fractures and faults. 

The overall objective of this study is to determine the 

feasibility of conducting a material-balance assessment of 

petroleum within a sedimentary basin. This feasibility is 

evaluated with respect to amounts and types of data needed, 

plausibility and utility of assessment values obtained, and 

timeliness and achievability of future research required. 

Determining the feasibility of this type of assessment was 

considered to be best served by studying an established 

petroleum basin with known quantities of discovered inplace petroleum, sufficient subsurface data for a well-constrained geological framework, and available geochemical 

data for source-rock characterization. The Illinois Basin (fig. 

1) meets these prerequisites with complete assessments of 

discovered in-place petroleum (Mast and Howard, 1990), a 

well-established regional stratigraphy (Leighton and others, 

1990), and available geochemical databases on the New 

Albany Shale (Frost, 1980; Robl and others, 1983; Hasenmueller and Leininger, 1987; Comer and others, 1994). 

The Illinois Basin has almost 1, 700 named fields that 

produce from approximately 7,000 separate sandstone and 

carbonate reservoirs (Oltz and others, 1990). The established 

nature of petroleum production in this basin is reflected in its 

percentage of stripper production (96 percent), which is 

more than six times higher than the national average (Oltz 

and others, 1990). An estimate of the original petroleum in 

place for known fields in the basin is 12 billion barrels (Mast 

and Howard, 1990), with an additional 3.4 billion barrels of 

in-place tar (Noger, 1987; Crysdale and Schenk, 1988). 

Geochemical correlations and stratigraphic position of reservoirs indicate that more than 99 percent of the produced 

petroleum was sourced by the New Albany Shale (Hatch and 

others, 1990). The New Albany Shale consists of varying 

amounts of brownish-black, organic-rich shale and greenishgray, organic-lean shale. This formation is present in the 

subsurface throughout much of the basin, with thicknesses 

ranging from less than 40 m at the basin margins to more 

than 140m in the basin depocenter. 

The term petroleum as used in this study refers to naturally occurring liquids that consist predominantly of hydrocarbons (e.g., heavy oil, crude oil, and condensates). 

Although the definition of petroleum is sometimes expanded 

to include natural gas (e.g., Levorsen, 1967), natural gas is 

not considered in this feasibility study, and only the strict 

definition of petroleum (i.e., from the Latin petra, rock and 

oleum, oil) is used. It should also be emphasized that this feasibility study only addresses petroleum expelled from source 

rocks within the New Albany Shale. Other source rocks 

within the Illinois Basin have been suggested (Cluff and 

Byrnes, 1990; Bond and others, 1971), with source rocks 

within the Scales and Brainard Shales (Ordovician) being 
N 

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EXPLANATION 

0 Wells with geophysical logs 

• Wells with geophysical logs 

and cores 

D 

D 

Limit of New Albany Shale 

New Albany Shale outcrop 

or subcrop 

INTRODUCTION 3 

o 50 Miles r-1 .......... .._., 1--T'I i......,....J\1---'-----'1 

o 50 Kilometers 

A 

Figure 1. Map of Illinois, Indiana, and western Kentucky showing outline of the Illinois Basin based on outcrop, subcrop, and limit of 

the New Albany Shale (modified from Cluff and others, 1981). Map also identifies counties referred to in text and wells used in cross 

sections A-A' and B-B' shown in figure 3. 
4 MATERIAL-BALANCE ASSESSMENT OF PETROLEUM, NEW ALBANY SHALE, ILLINOIS BASIN 

CHRONOSTRATIGRAPHIC 

UNITS ROCK UNITS 

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WESTERN 

KENTUCKY 3 

SOUTHWESTERN SOUTHEASTERN WEST -CENTRAL 

INOIANA4 INDIANA4 KENTUCKY 5 

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and 

Sweetland 

Creek Shale 

Mbrs. 

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}g 

Clegg Creek 

Member 

LU ~ g; and <i: Shale <i: en Shale 

~ Grassy Creek ~ 2 cr: Sweetland g; Mbr. g; ::2: 

;:;: ~ "' Mbr. ~ Member z 

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Shale Mbr. 

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~------------~' Member extends into Ordovician rocks in 2 From Shaver and others (1985) 

.D 

<i: 

g; 

z: 

!

Unconformity beneath Sylamore Sandstone I I Modified from Cluff and others (1981) 

northwest centra\ Illinois and western Illinois 3 Modified from Schwalb and Norris (1980) 

.D 

<i: 

g; 

z: 

4 From Hasenmueller and Bassett (1981) 

5 Mod1fied from Conkin and Conkin ( 1972); 

Beard (1980); Sable and Dever (1990); 

and Ettensohn and others (1991) 

I \ 

Biostratigraphic evidence indicates that the 

basal part of the Jeffersonville Limestone 

is Emsian (Lower Devonian). See Devera and 

Fraunfelter (1988): Conkin and Conkin (1984) 

Figure 2. Correlation of New Albany Shale in the Illinois Basin (modified from Hasenmueller and others, 1994). Rock-unit thicknesses 

are not to scale. Fm., Formation; Gp., Group; J.C., Jacobs Chapel; Ls., Limestone; Mbr., Member; Sh., Shale; Slts., Siltstone; Ss., Sandstone. 

prime candidates as additional sources for petroleum (Guthrie and Pratt, 1994) that are not considered in this study. 

METHODS AND RESULTS 

SOURCE-ROCK CHARACTERIZATION 

A petroleum source rock is defined in this study as a 

rock containing oil-prone organic matter and a total organic 

carbon (TOC) content equal to or greater than 2.5 weight percent. This TOC limit is based on the petrographic study of 

Devonian and Mississippian black shales by Lewan (1987). 

This study showed that a critical quantity of organic matter 

is needed to generate sufficient bitumen to form a continuous 

organic network within the matrix of a source rock for expulsion of petroleum to occur. Rocks with oil-prone organic 

matter that is dispersed within a mineral matrix may not generate sufficient bitumen to form this continuous network if its 

original TOC is less than 2.5 weight percent. As a result, 

these organic-lean rocks may generate but not expel petroleum. Although this TOC limit of 2.5 weight percent is high 

compared to earlier proposed limits of 0.4 to 1.4 weight percent (Ronov, 1958), higher TOC limits in excess of 2.5 

weight percent are now being suggested (Bordenave and 

others, 1993). 

STRATIGRAPHY 

The New Albany Shale is a time-transgressive unit 

extending from Middle Devonian to Early Mississippian 

(Cluff and others, 1981). Figure 2 gives stratigraphic ages, 

nomenclature, and correlation of rock units within and 
METHODS AND RESULTS 5 

adjacent to the New Albany Shale in different parts of the 

Illinois Basin. The New Albany Shale overlies Middle Devonian limestones (Sellersburg Limestone, Lingle Formation, 

and North Vernon Limestone) throughout most of the basin. 

This basal contact is generally conformable in southern and 

eastern Illinois, but, farther to the north and west, the basal 

shale grades laterally into argillaceous limestone, dolostone, 

and shale of the Lingle and Alto Formations (North, 1969). 

The New Albany Shale is overlain by Early to Late Mississippian strata throughout most of the basin. However, in 

northern Illinois, the formation has been partly eroded and is 

overlain by Pennsylvanian strata. In a small area in extreme 

southern Illinois, the New Albany Shale is overlain by Upper 

Cretaceous rocks (Collinson and Atherton, 1975). As shown 

in figure 2, the New Albany Shale has been locally subdivided into as many as 13 lithologic members. 6 The regional 

relationships of these members are shown in the two cross 

sections of figure 3. Only the members containing organicrich, brownish-gray to black shales capable of generating 

petroleum are considered in this study. These members 

include the Blocher, Selmier, Sweetland Creek, Grassy 

Creek, Morgan Trail, Camp Run, and Clegg Creek Members. 

The Blocher, Grassy Creek, Morgan Trail, and Clegg Creek 

Members consist almost entirely of organic-rich, brownishblack to grayish-black, laminated, pyritic shale. The Selmier, 

Camp Run, and Sweetland Creek Members consist of varying amounts of organic-lean, greenish-gray shale and 

organic-rich, brownish-black shale. For a detailed discussion 

on the stratigraphy of the New Albany Shale, see Hasenmueller and others ( 1994 ). 

THICKNESS 

Thickness of mature and over-mature source rock 

within a sedimentary basin is a critical parameter in determining the volume of source rock for calculating petroleum 

charge. An isopach map of the New Albany Shale has been 

constructed for the Illinois Basin (Cluff and others, 1981), 

which has been useful in reconstructing paleoenvironments 

and defining depocenters. Unfortunately, a map of this type 

includes thicknesses of members that do not contain petroleum source rocks (i.e., Hannibal, Saverton, and Ellsworth 

Members) and portions of members that are not petroleum 

source rocks (i.e., Selmier and Camp Run Members). Inclusion of these non-source-rock thicknesses can significantly 

exaggerate the petroleum charge, and, therefore, an isopach 

map of only source rocks within the New Albany Shale is 

6The Illinois State Geological Survey uses lithic modifiers for the 

shale members of the New Albany Shale (Blocher Shale Member, Selmier 

Shale Member, Sweetland Creek Shale Member, Grassy Creek Shale Member, Saverton Shale Member, and Hannibal Shale Member). The Indiana 

Geological Survey and Kentucky Geological Survey do not use lithic modifiers. For simplicity, this report does not use lithic modifiers. 

needed. A map of this type currently does not exist in the 

published literature, but isopach maps of the Blocher Member (fig. 4), Selmier Member (fig. 5), and a composite of the 

Clegg Creek, Camp Run, Morgan Trail, Grassy Creek, and 

Sweetland Creek Members (fig. 6) over the entire Illinois 

Basin are available (Lineback, 1981). The latter composite 

of members is hereafter referred to informally as the "upper 

shale composite." Although the use of these maps excludes 

members consisting of non-source rocks, it does not exclude 

the thickness of non-source rocks that occur in the Selmier, 

Camp Run, and Sweetland Creek Members. Corrections to 

alleviate their inclusion are discussed later under the heading, Organic Richness. 

THERMAL MATURITY 

The levels of thermal stress experienced by the New 

Albany Shale within the Illinois Basin have been related to 

changes in the reflectivity of vitrinite dispersed within 

organic-rich shales (Barrows and others, 1979, 1980; Barrows and Cluff, 1984; Hamilton-Smith, 1993). Comer and 

others (1994) have compiled these vitrinite reflectance data 

and constructed a contour map of the mean random reflectance values. A generalized version of this map is shown in 

figure 7. Although vitrinite reflectance is a good indicator of 

thermal stress, it is not always a good indicator of petroleum 

generation because significant differences in the kinetics of 

petroleum generation are observed for different types of 

organic matter (Lewan, 1985; Hunt and others, 1991). This 

uncertainty is further complicated by the suppressed thermal 

response of vitrinite reflectance in the New Albany Shale 

(Nuccio and Hatch, 1994), which also occurs in other Devonian-Mississippian black shales (Lewan, 1985; Price and 

Barker, 1985). These difficulties were circumvented in this 

study by establishing a relationship between vitrinite reflectance and the Rock-Eval hydrogen index (mg S2 hydrocarbons/g total organic carbon) for source rocks in the New 

Albany Shale at different levels of thermal maturity. The relationship is shown in figure 8 and is based on geochemical 

data of 61 core samples from 10 wells (table 1). This relationship provides a means of equating the available vitrinitereflectance contour map (fig. 7) to Rock-Eval hydrogen 

indices, which are more indicative of petroleum generation. 

Figure 8 shows that petroleum generation based on the 

decrease in Rock-Eval hydrogen index occurs between suppressed vitrinite reflectance values of 0.6 and 1.2 percent Ro. 

VOLUME 

The volume of each source-rock-bearing member isopached by Lineback (1981) was determined for 0.1-percent 

R0 increments from 0.6 to 1.50 percent Ro. These calculations were made electronically by superimposing the 
6 MATERIAL-BALANCE ASSESSMENT OF PETROLEUM, NEW ALBANY SHALE, ILLINOIS BASIN 

A 

m ft 

30LOO 

20 

10 50 

50 mi 

0 

50 km 

B 

Chouteau Ls. 

EXPLANATION 

S Fossiliferous limestone 

Ell Bioturbated mudstone 

C Indistinctly bedded and poorly 

laminated shale 

f_--.:J Finely laminated shale 

fi:J Calcareous shale 

10 

18 

Rockford Ls. 

A' 

B' 

Figure 3. Northwest-southeast (A-A') and west-east (B-B') stratigraphic cross sections of the New Albany Shale showing regional relations 

among members (modified from Cluff and others, 1981, and Devera and Hasenmueller, 1990). Fm., Formation; Gp., Group; J.C., Jacobs 

Chapel; Ls., Limestone; Mbr., Member; Slts., Siltstone; Ss., Sandstone. Numbers indicate wells along line of section. 
METHODS AND RESULTS 7 

- - ~--'- - - ~ -- ---, r 

_ Thickness contour; 

/ 'l.l) contour interval 20 feet 

Figure 4. Isopach map showing thickness of Blocher Member of 

the New Albany Shale in the Illinois Basin (Lineback, 1981). 

digitized isoreflectance map (fig. 7) over each of the digitized isopach maps of the members of the New Albany Shale 

(figs. 4, 5, and 6). The isoreflectance map was drafted with 

AutoCAD software (release 12). The isopach maps of members (figs. 4, 5, and 6) were photocopied and then scanned 

and vectorized using CADcore Tracer software. The digital 

files of these maps were converted to digital exchange format (DXF) interchange files, using AutoCAD12, and then 

exported into PC ARC/INFO 3.4D software. In ARC/INFO, 

all truncated contours were manually joined so that each map 

consisted of sets of enclosed areas having consistent Ro and 

thickness values. These areas were assigned attributes that 

included the lowest Ro value of the two enclosing contours 

on the Ro map and the mean thickness value of the two 

enclosing contours on the thickness maps. The thickness 

maps were then electronically superimposed on the Ro map, 

causing ARC/INFO to automatically assign combined 

attributes of area, minimum Ro. and mean thickness to the 

polygons created by the intersecting Ro and thickness contours. The resulting ARC/INFO attribute table was imported 

into the relational database, Paradox 3.5, in order to format 

the final report. In Paradox 3.5, the area of each polygon was 

multiplied by the mean thickness to obtain the volume. The 

attributes of Ro, area, and volume were subsequently 

grouped in the report writer, and the areas and volumes of 

_ Arbitrary vertical EXPLANATION .-- Thickness contour; .// ~~~~~:r b~~w~~~r / 'l.l) contour interval 20 feet 

and Sweetland 

Creek Member ~ Cretaceous outcrop 

margin 

Figure 5. Isopach map showing thickness of Selmier Member of 

the New Albany Shale in the Illinois Basin (Lineback, 1981). The 

arbitrary vertical cutoff does not reflect the distribution of the Selmier in northernmost Indiana as recognized by the Indiana Geological Survey. 

polygons having the same Ro values were automatically 

summed and then printed as a report. As a check on tl)is 

method, area and volume estimates based on the total thickness of New Albany Shale were hand-calculated for 

Kentucky following the method described in Craft and 

Hawkins (1959, p. 27-29). The hand-calculated values were 

found to agree within 10 percent of those calculated using 

the digital method described above. 

The surface areas and total volumes calculated by this 

method for each member are given in table 2. The total member volumes cannot be directly equated to source-rock volumes because of the non-source-rock intervals that are 

included in the total thickness of each member. Estimates of 

source-rock percentages for each member (table 3) were 

based on total organic carbon data from available cores listed 

in table 4. Source-rock thicknesses were determined by summing the thickness of rocks containing at least 2.5 weight 

percent total organic carbon within each member represented in the core. The resulting source-rock thickness was 

divided by the total thickness of the member represented in 

the core and multiplied by 100 to obtain a source-rock 

percentage. 
8 MATERIAL-BALANCE ASSESSMENT OF PETROLEUM, NEW ALBANY SHALE, ILLINOIS BASIN 

Figure 6. Isopach map showing thickness of the ''upper shale 

composite," which consists of the thickness of the Sweetland Creek 

and Grassy Creek Members of the New Albany Shale west of the 

limit of the Selmier Member, the thickness of the Grassy Creek 

Member only where the Selmier Member is recognized in Illinois 

and Kentucky, and the combined thickness of the Morgan Trail, 

Camp Run, and Clegg Creek Members of the New Albany Shale in 

Indiana (Lineback, 1981). The arbitrary vertical cutoff does not reflect the distribution of the Selmier in northernmost Indiana as recognized by the Indiana Geological Survey. 

As shown in table 3, the composite of upper shale members has a narrow range of source-rock percentages from 92 

to 100 percent, with no systematic change between vitrinite 

reflectances of 0.44 and 0.95 percent Ro· The mean sourcerock percentage of 97.5 percent obtained from these cores 

was used for all of the upper shale composite to determine 

volume of source rock in this mapped unit as shown in table 

2. The total calculated volume of source rock in this upper 

shale composite is 1,119 km3, with more than 60 percent of 

this volume occurring in the 0.6- to 0.7-percent Ro interval 

(table 2). Inclusion of the non-source rocks of the Sweetland 

Creek Member in this upper shale composite does not influence these source-rock volumes because this member only 

occurs at vitrinite reflectance levels of less than 0.6 percent 

Ro. The Blocher Member also has a narrow range of sourcerock percentages from 98 to 100 percent from vitrinite 

reflectances of 0.44 to 0.70 percent Ro (table 3). A mean of 

in value 

Figure 7. Isoreflectance contour map based on random reflectance measurements of vitrinite in the New Albany Shale (modified 

from Comer and others, 1994). 

99.2 percent was calculated for this range of source-rock percentages and was used to determine the volume of source 

rock in the Blocher Member for the 0.6- to 0.7-percent Ro 

interval (table 2). The lower source-rock percentage in the 

cored Blocher Member of the C-174 well was used to calculate the volume of source rock at vitrinite reflectance intervals greater than 0.9 percent Ro (table 2). Source-rock 

percentages for the 0.7- to 0.8- and 0.8- to 0.9-percent Ro 

intervals were estimated by interpolating between the 99.2 

percent of the 0.6- to 0.7-percent Ro interval and the 87.2 

percent of the 0.9- to 1.0-percent Ro interval. Midpoint 

reflectance values (i.e., 0.75 and 0.8 percent Ro) for the two 

intermediate vitrinite-reflectance intervals were used in this 

linear interpolation to derive the source-rock percentages 

given in table 2. The resulting total source-rock volume for 

the Blocher Member is 360 km3 (table 2), with 56 percent of 

this total occurring in the 0.6- to 0.7-percent Ro interval. 

Estimating the source-rock percentage of the Selmier 

Member is more complicated because of the large variations 

in amount of non-source rocks and the limited data. Table 3 

shows the source-rock percentage varies from 2 to 93 

percent, and the mean value of 55 percent would not accurately represent the entire member. A more representative 

approach was used by estimating source-rock percentages 
METHODS AND RESULTS 9 

E 

~() 

><O WI700 

600 

~~ 500 ---

zti: w<!J 

<!Ja: 

ow 

a: a.. 400 

0() >-I 

ICJ) 

_J~ 

<(<( 

~ ffi 300 

()-J ~­

o::! 

a:~ 

~ 200 

100 

Petroleum generation 

and expulsion 

a~._~~~--~._~~~--~._~~~~ 

0.3 0.5 0.7 0.9 1.1 1.3 1.5 1.7 

VITRINITE REFLECTANCE, 

IN PERCENT Ro 

Figure 8. Emperical relationship between mean Rock~Eval hy~ 

drogen indices (HI) and mean random vitrinite reflectances (% Ro) 

from core samples of New Albany Shale at different levels of thermal maturity within the Illinois Basin (see table 1). The relationship 

from a vitrinite reflectance of 0.5 to 0.95 is described by the expression: H1=6,558xexp(-4.27x% Ro), and the relationship from a vitrinite reflectance of 0.95 to 1.65 is described by the expression: 

Hl=154.69(% Ro)2-472.92(% Ro)+424.36. HC, hydrocarbons; 

Tocm, total organic carbon of of mature and over-mature source 

rocks. Vertical bars indicate one standard deviation. 

for the Selmier Member in Illinois and Indiana from cores in 

the OliN, 13IL, and 1liL wells and in Kentucky from cores 

in the 01KY, C-174, and 1liL wells. In Illinois and Indiana, 

the source-rock percentage of 92.6 percent (table 2) for the 

0.6- to 0.7-percent Ro interval is based on the value derived 

from the OliN core (table 3). Source-rock percentages for the 

vitrinite reflectance intervals between 0.7 and 1.3 percent Ro 

in Illinois and Indiana are derived from a linear interpolation 

between values from cores in wells 13IL and 1liL. The 

interpolated values were determined for the midpoint vitrinite reflectance values of each interval (i.e., 0.75, 0.85, 0.95, 

1.05, 1.15, and 1.25 percent Ro), and the resulting sourcerock percentages of the vitrinite reflectance intervals higher 

than 1.3 percent Ro are kept constant at 51.8 percent on the 

basis of the 1liL core. 

The source-rock percentages for the Selmier Member 

in Kentucky are calculated in a similar manner, but with 

core data from wells 01KY, C-174, and 1liL (table 3). Values in table 3 for midpoints of vitrinite reflectance intervals 

between 0.6 and 0.9 percent Ro are derived by a linear 

interpolation between core data of wells 01KY and C-174. 

The source-rock percentage of 54.6 percent of the C-174 

core is used for the 0.9- to 1.0-percent Ro interval. The 

value of 53.8 percent for the 1.0- to 1.1-percent Ro interval 

is derived from an interpolation between values from wells 

C-174 and 1liL. The total volume of source rock in the 

Selmier Member in all three States is 599 km3 (table 2), 

with 58 percent of the total occurring in the 0.6- to 0.7-

percent Ro interval. The interpolations used to determine 

the source-rock percentage of the Selmier Member rely on 

a positive relationship between source-rock thickness and 

thermal maturity. Although a general relationship of this 

type is observed by comparing rock thickness in figure 5 

with thermal maturity in figure 7, the relationship is not a 

simple linear relationship as assumed in these interpolations. More work is needed to better constrain these sourcerock percentages, but, based on available data, these values 

represent the best estimates currently available. 

ORGANIC RICHNESS 

More than 90 volume percent of the organic matter in 

source rocks of the New Albany Shale consists of oil-prone, 

amorphous, type-II kerogen (Barrows and Cluff, 1984). The 

amount of organic matter within the source rocks is most 

readily expressed as weight percent of total organic carbon 

(TOC). Cores from six wells were used to determine a 

weighted mean TOC value for source rocks in each member. 

These cores represent complete sections and were sampled 

in sufficient detail to provide representative weighted means, 

which are given in table 4. The means were weighted with 

respect to the thickness of source rock represented by the 

sample analyzed for TOC. The low thermal maturity level 

( <0.6 percent Ro) of these cores ensures that no significant 

loss of organic carbon has occurred due to expulsion of generated petroleum or natural gas. The remaining challenge is 

how to project these weighted TOC means into the higher 

thermal maturity levels of the basin where organic carbon is 

reduced due to expulsion of petroleum and natural gas and 

where source-rock thicknesses may increase by two-fold 

(table 3). 

Two simple models for determining the original TOC 

content of the thermally mature and over-mature source 

rocks were used in this study. These two models are considered to represent end members, with the original TOC content most likely occurring somewhere between them. The 

first model assumes that the amount of organic matter 

deposited and preserved in source rocks remained constant 

during the deposition of the source rocks over the entire 
10 MATERIAL-BALANCE ASSESSMENT OF PETROLEUM, NEW ALBANY SHALE, ILLINOIS BASIN 

Table 1. Summary of TOC and Rock-Eval data on cores of New Albany Shale representing different levels of thermal maturity in the 

Illinois Basin. 

[Mean and standard deviation are given for TOC and Rock-Eval data. Ro. mean random vitrinite reflectance; TOC, total organic carbon; Rx, rock; wt. %, weight percent. See text 

under heading of Rock-Eva! Pyrolysis for definition of S1 and S2 hydrocarbons] 

Wells Number of l~ TOC S1 hydrocarbons s2 hydrocarbons Hydrogen index 

included• samples (percent) (wt. %Rx) (mg/gRx) (mg/gRx) (mgS2ffOC) 

SDH-305, SDH-308 

SDH-309, 02IL 30 0.54 7.07± 3.96 1.75±0.52 42.25±21.33 621.6±98.3 

OllN, C-219 10 0.62 4.66±2.30 1.29±0.81 24.05±9.14 528.8±81.7 

13IL 5 0.70 4.26±1.24 1.44±0.30 13.10±4.22 304.2±34.7 

C-174 9 0.95 4.16±1.46 0.30±0.17 4.76±1.72 114.7±17.6 

11IL 2 1.30 5.48±2.00 0.59±0.24 4.00±1.67 71.0±5.0 

RM 5 1.65 6.91±1.44 0.34±0.11 4.66±1.65 65.2±8.8 

• SDH-305, Indiana Geological Survey No. 305, Jackson Co., Indiana. 

SDH-308, Indiana Geological Survey No. 308, Harrison Co., Indiana. 

SDH-309, Indiana Geological Survey No. 309, Floyd Co., Indiana. 

02IL, Tristar Production No. ID, Lancaster, Effmgham Co., illinois. 

OliN, Phegley Farms No. I, Sullivan Co., Indiana. 

C-219, Canton Rock Quarry, Trigg Co., Kentucky. 

131L, Gordon T. Jenkins No. 1 Simpson, Wayne Co., illinois. 

C-174, Sheridan Target D.D.H. 66ST-4, Crittenden Co., Kentucky. 

111L, Rector & Stone No. 1 Missouri Portland Cement, Hardin Co., illinois. 

RM, Rose Mineral Exploration, Hardin Co., illinois. 

basin, and the thickening of source rocks is the result of 

increased input of inorganic components. This dilution 

model predicts that the weighted mean TOC content of a 

source rock would decrease proportionally to increases in 

thickness of a source rock. The second model assumes that 

the amount of organic matter deposited and preserved in a 

source rock maintains constant proportionality with input of 

inorganic components. This steady-state model predicts that 

the weighted mean TOC content of a source rock would 

remain constant irrespective of changes in the thickness of a 

source rock. 

The dilution model requires determining the fixed mass 

of organic carbon deposited and preserved beneath a surfacearea unit of each source-rock member. Table 4 gives the calculated mass of organic carbon per square meter of sourcerock surface area for each source-rock member in the thermally immature wells. The bulk-rock densities (PRx) needed 

for this determination were calculated from a linear relationship established between TOC values and bulk-rock densities measured on six immature samples of New Albany 

Shale, with TOC values ranging from 2.46 to 14.34 weight 

percent and bulk densities ranging from 2.15 to 2.37 Mg/m3. 

Using the relationship, PRx=-0.018(TOC)+2.40, mean bulkrock densities were determined from the weighted mean 

TOC values of each member represented in the well cores 

(table 4). Multiplying these mean bulk densities by the 

thickness of source rock yields the mass of source rock 

beneath 1 m2 of surface area for the source-rock members in 

each well. The mass of organic carbon deposited and preserved beneath 1 m2 of surface area may then be determined 

by multiplying the source-rock mass per square meter by the 

decimal fraction of the weighted mean TOC content. Large 

standard deviations (table 4) indicate that the assumption of 

this model is questionable and the use of mean values is 

difficult to justify. An alternative is to use TOC mass/area 

units from a thermally immature well that is nearest to the 

thermally maturing depocenter. The well used for this 

purpose was 01 KY, which is less than 1 km from an isoreflectance contour of 0.6 percent Ro and 72 km from an isoreflectance contour of 1.0 percent Ro. The calculated values of 

TOC mass/area for this well are 0.82, 2.38, and 4.17 Mg/m2 

for the Blocher, Selmier, and upper shale composite members, respectively (table 4). Multiplying these values by the 

surface areas given for each member at 0.1-percent Ro intervals (table 2) gives, according to this model, the original 

TOC mass of thermally mature and over-mature source 

rocks (table 5). 

The steady-state model requires determining the mean 

mass of organic carbon deposited and preserved within a 

volume unit of source rock. Figure 9 shows the relationship 

between mass of TOC/surface area and thickness of source 

rock. A lineru: regression of these data from tables 3 and 4 

gives a slope of 197.7 kg ofTOC per cubic meter of source 

rock and a near-zero intercept for all source-rock members. 
METHODS AND RESULTS 

Table 2. Surface area and volume of source rocks in members of of New Albany Shale at 0.1-percent Ro intervals. 

Ro interval Surface area Total volume Source-rock 

{Eercent2 (km22 (km32 ~ercentaGe 

Upper shale composite 

0.6-0.7 24,603.20 695.86 97.51 

0.7-0.8 5,698.14 169.75 97.51 

0.8-0.9 2,350.86 56.71 97.51 

0.9-1.0 4,193.75 149.69 97.51 

1.0-1.1 1,294.78 52.73 97.51 

1.1-1.2 179.23 6.89 97.51 

1.2-1.3 149.13 5.86 97.51 

1.3-1.4 107.75 4.40 97.51 

1.4-1.5 139.96 5.61 97.51 

>1.5 12.07 0.49 97.51 

Selmier Member 

fudianallllinois: 

0.6-0.7 14,476.81 201.08 92.62 

0.7-0.8 4,915.35 91.24 61.23 

0.8-0.9 1,484.26 17.02 59.53 

0.9-1.0 2,158.21 54.91 57.83 

1.0-1.1 814.55 38.18 56.1 3 

1.1-1.2 179.24 8.25 54.43 

1.2-1.3 149.13 6.85 52.73 

1.3-1.4 107.75 5.39 51.84 

1.4-1.5 139.95 7.05 51.84 

>1.5 12.07 0.66 51.84 

Kentucky: 

0.6-0.7 10,126.43 209.69 76.65 

0.7-0.8 782.77 31.09 69.35 

0.8-0.9 866.59 37.92 61.95 

0.9-1.0 2,035.43 105.81 54.66 

1.0-1.1 480.24 26.25 53.87 

Blocher Member 

0.6-0.7 24,603.22 203.70 99.28 

0.7-0.8 5,698.15 47.76 96.89 

0.8-0.9 2,350.85 22.12 92.09 

0.9-1.0 4,193.76 65.48 87.210 

1.0-1.1 1,294.78 28.07 87.210 

1.1-1.2 179.23 3.64 87.2 10 

1.2-1.3 149.13 2.24 87.210 

1.3-1.4 107.75 2.44 87.210 

1.4-1.5 139.96 3.01 87.210 

>1.5 12.07 0.25 87.210 

1

Mean value of upper shale composite given in table 3 for all wells. 

2Values from OliN well in table 3. 3Value from linear interpolation between 13ll.- and I liT- wells in table 3. 

4Value from I liT- well in table 3. 

5Value from linear interpolation between Ol!<.Y and C-174 wells in table 3. 

6Value from C-174 well in table 3. 7Value from linear interpolation between C-17 4 and I liT- wells in table 3. 8

Mean value of Blocher Member (excluding C-174 well) in table 3. 

Source-rock 

volume (km_3) 

678.46 

165.51 

55.29 

145.95 

51.41 

6.71 

5.72 

4.29 

5.47 

0.48 

Total= 1,119.29 

186.20 

56.63 

10.13 

31.74 

21.42 

4.49 

3.61 

2.79 

3.65 

0.34 

160.62 

21.55 

23.47 

57.77 

14.12 

Total= 598.57 

202.07 

46.23 

20.35 

57.09 

24.47 

3.17 

1.95 

2.13 

2.62 

0.22 

Total= 360.31 

9Value from linear interpolation between the mean value of99.2 percent in the 0.6- to 0.7-

percent Ro interval and 87.2 percent in the C-174 well of table 3. 10Value from C-174 well in table 3. 

11 
12 MATERIAL-BALANCE ASSESSMENT OF PETROLEUM, NEW ALBANY SHALE, ILLINOIS BASIN 

Table 3. Thickness and percentage of source rock in members of New Albany Shale determined in 

available well cores. 

[Mean value for source-rock percentage for Blocher Member does not include data for well C-174; Ro. mean random vitrinite 

reflectance] 

Well Ro Total Source-rock Source-rock Source of 

name (percent) thickness (m) thickness (m) percentage data 

Upper shale composite 

SDH-308 0.44 22.11 21.75 98.4 

SDH-273 0.46 18.03 17.96 99.6 

A-ll 0.50 16.29 15.68 96.3 2 

SDH-305 0.50 28.46 27.24 95.7 

SDH-309 0.53 26.29 26.05 99.1 

OlKY 0.56 22.17 20.47 92.3 3 

OliN 0.63 25.96 25.22 97.1 

13IL 0.70 40.66 40.66 100.0 3 

C-174 0.95 36.11 35.81 99.2 4 

Mean= 97.5 

Sebnier Member 

SDH-273 0.46 8.69 3.48 40.0 

SDH-305 0.50 4.70 0.09 1.9 

OlKY 0.56 16.41 13.66 83.2 3 

OliN 0.63 9.03 8.36 92.6 

13IL 0.70 18.85 11.71 62.1 3 

C-174 0.95 62.53 34.16 54.6 4 

lliL 1.30 53.50 27.72 51.8 3 

Mean= 55.2 

Blocher Member 

SDH-308 0.44 4.82 4.82 100.0 

SDH-273 0.46 4.97 4.94 99.4 

A-ll 0.50 3.48 3.48 100.0 2 

SDH-305 0.50 3.66 3.60 98.4 

SDH-309 0.53 5.12 5.06 98.8 

OlKY 0.56 5.82 5.75 98.8 

OliN 0.63 3.23 3.17 98.1 I 

13IL 0.70 8.78 8.78 100.0 3 

Mean= 99.2 

C-174 0.95 14.03 12.23 87.2 4 

1

Nancy Hasenmueller, Indiana Geological Survey. 2Thomas Robl, Center for Applied Energy Research, University of Kentucky. 

3Cluff and others (1981) and Frost (1980). 

4John W. Smith, Laramie Petroleum Research Center. 

This slope may be equated to a mean TOC content of 8.82 

weight percent with a bulk-rock density of 2.24 Mg/m3 for 

all the source rocks in the New Albany Shale. Multiplying 

this slope value by the source-rock volumes given for each 

member at 0.1-percent Ro intervals (table 2) gives, according 

to this model, the original TOC mass in the mature and overmature source rocks (table 5). Comparison of results from 

both models (table 5) shows the TOC mass determined by 

the steady-state model is 44 percent greater than that determined by the dilution model. 

A model predicting an increase in TOC content of the 

source rocks as the New Albany Shale thickens into the depocenter was not considered likely on the basis of available 

data and analogous studies of source rocks in other basins. A 

significant portion of this thickening is a result of an increase 

in thickness of greenish or olive-gray, organic-lean shales as 

described in cores from wells lliL and 13IL (Cluff and others, 1981). This increase in non-source rocks is especially 

obvious in the Selmier Member, as suggested by the thicknesses of indistinctly bedded and poorly laminated shales in 

the cross sections of figure 3. These rocks are typically partially bioturbated and are considered not to represent periods 

of anoxic conditions within the basin (Cluff, 1980). In addition, thickening of Devonian-Mississippian source rocks 

around the Findlay arch and in the western Appalachian 

Basin results in a decrease in their TOC contents. Robl and 
METHODS AND RESULTS 13 

Table 4. Organic richness data from complete cores of thermally immature source-rock members within the New Albany Shale. 

[Sources of data are same as those footnoted in table 3. TOC, total organic carbon; wt. %, weight percent; SRx, source rock] 

Well Weighted TOC Number Bulk-rock SRxmass/ TOCmass/ 

name1 mean TOC2 range of densitY surface area4 surface area5 

(wt. %SRx) · (wt. %SRx) analyses (Mglm3) (Mg/m2) (Mg/m2) 

Upper shale composite 

SDH-308 7.92 2.98-15.00 25 2.26 49.155 3.893 

SDH-273 8.62 5.19-11.30 13 2.24 40.230 3.468 

A-ll 10.12 5.52-15.95 27 2.22 34.810 3.523 

SDH-305 9.ll 3.80-16.10 21 2.24 61.018 5.559 

SDH-309 8.07 2.68-16.20 32 2.25 58.613 4.730 

01KY 9.10 5.81-14.03 4 2.24 45.853 4.173 

Mean 4.224 

Standard deviation ±0.732 

Selmier Member 

SDH-273 

01KY 

8.14 

7.71 

7.85-8.28 

3.40-11.95 

3 2.25. 

8 2.26 

7.830 0.637 

30.872 2.380 

Mean 1.509 

Standard deviation ±0.871 

Blocher Member 

SDH-308 9.37 5.73-11.40 6 2.23 10.749 1.007 

SDH-273 5.96 2.51-11.76 7 2.29 11.313 0.674 

A-ll 9.07 6.03-12.19 5 2.24 7.795 0.707 

SDH-305 8.21 7.32-9.70 4 2.25 8.100 0.665 

SDH-309 7.81 3.69~9.26 6 2.26 11.436 0.893 

01KY 6.25 5.67-7.71 4 2.29" 13.168 0.823 

Mean 0.795 

Standard deviation ±0.126 

1

Notations for wells SDH-305, SDH-308, and SDH-309 are the same as in the footnote for table 1. 01KY, Orbit Gas No. 1 Ray 

Clark, Christian Co., Kentucky; SDH-273, fudiana Geological Survey No. 273, Marion Co., fudiana; A-11, Nelson Co., 

Kentucky. ' 2

Weighted means are calculated by multiplying the TOC value by the thickness of source rock it represents, summing these 

products for each member, and dividing the sum by the total thickness of source rock for each member. 

3Bulk-rock densities (PRx) calculated from a linear expression (i.e., PRx=-0.0189(TOC)+2.40) based on six samples of New 

Albany Shale with TOC values ranging from 2.46 to 14.34 weight percent arid bulk-rock densities ranging from 2.15 to 2.37 

Mg/m3. 

4Source-rock mass per square meter of surface area is determined by multiplying ~e bulk-rock density by the source-rock 

thickness given in table 3. 

5TOC mass of source rocks per square meter of surface area is determined by multiplying the source-rock mass per square meter of 

surface area by the decimal fraction of the weighted mean TOC value. 

others (1983) report decreases in TOC contents for the 

Cleveland Member of the Ohio Shale around the Findlay 

arch from 15 to 9 weight percent with increases in thicknesses from 4 to 18 m, respectively. Similarly, Schmoker 

( 1980) reports decreases in TOC contents for Devonian 

organic-rich facies in the western Appalachian Basin from 

16 to 5 volume percent with increases in thicknesses from 65 

to 240 m. A similar inverse relationship between the TOC 

content and thickness of source rock was reported by Comer 

(1991, 1992) for Upper Devonian black shales in the Delaware and Anadarko Basins and by Nixon (1973) for the 

Mowry Shale (Lower Cretaceous) in the western Early Cretaceous Boreal seaway. 

EXPULSION FACTOR 

The expulsion factor is defined as the amount of petroleum that is expelled from a petroleum source rock as it thermally matures within a sedimentary basin. The unit of this 

parameter is in volume or mass of petroleum per unit mass 

of total organic carbon in a source rock. It is important that 

this parameter not be confused with hydrocarbon generation 

potential, which is a measure of hydrocarbons generated 

within rather than expelled from a source rock. Expulsion factors may be determined through evaluation of natural maturation data or laboratory pyrolysis studies. Although useful 

qualitative concepts and some constraints are obtained from 
14 MATERIAL-BALANCE ASSESSMENT OF PETROLEUM, NEW ALBANY SHALE, ILLINOIS BASIN 

Table 5. Mass of total organic carbon in New Albany Shale source 

rocks as determined by dilution and steady-state models. 

[TOC, total organic carbon. SS, TOC mass for steady-state model; D, TOC mass for 

dilution model. Mbr, Member; Fm, Formation] 

Ro interval 

(percent) 

0.6-D.7 

0.7-D.8 

0.8-D.9 

0.9-1.0 

1.0-1.1 

1.1-1.2 

1.2-1.3 

1.3-1.4 

1.4-1.5 

>1.5 

Dilution 

model 

T0Cmass1 

(Tg) 

Steady-state Percent 

model difference 

TOC mass2 {[(SS/D)xl00)-100} 

(Tg) 

Upper shale composite 

102,595 134,132 

23,761 32,721 

9,803 10,931 

17,488 28,854 

5,399 10,164 

747 1,327 

622 1,131 

449 848 

584 1,081 

50 95 

31 

38 

12 

65 

88 

78 

82 

89 

85 

90 

"Mbr" total 161,498 221,284 37 

0.6-D.7 

0.7-D.8 

0.8-D.9 

0.9-1.0 

1.0-1.1 

1.1-1.2 

1.2-1.3 

1.3-1.4 

1.4-1.5 

>1.5 

Mbrtotal 

0.6-D.7 

0.7-D.8 

0.8-D.9 

0.9-1.0 

1.0-1.1 

1.1-1.2 

1.2-1.3 

1.3-1.4 

1.4-1.5 

>1.5 

Mbr total 

Selmier Member 

58,556 

13,562 

5,595 

9,981 

3,082 

427 

355 

256 

333 

29 

92,176 

68,566 

15,456 

6,643 

17,696 

7,026 

888 

714 

552 

722 

67 

118,329 

Blocher Member 

20,175 

4,672 

1,928 

3,439 

1,062 

147 

122 

88 

115 

10 

31,758 

39,950 

9,140 

4,023 

11,288 

4,837 

627 

385 

420 

518 

44 

Fm total 285,432 

71,232 

410,845 

17 

14 

19 

77 

128 

108 

101 

116 

117 

131 

28 

98 

96 

109 

228 

355 

327 

216 

377 

350 

340 

124 

44 

1

Surface areas given in table 2 for the upper shale composite, 

Selmier, and Blocher Members are multiplied by 4.17, 

2.38, and 0.82 Mg/m2, respectively. 

2Source-rock volumes given in table 2 are multiplied by the 

197.7x106 Mglk:m3 slope derived from linear regression 

of data plotted in figure 9. 

expulsion factors derived from natural maturation data 

(Momper, 1978; Jones, 1981), the vastness of sedimentary 

basins, limited subsurface data, _and dynamics of fluid flow 

6.0 

-a: cnw 5.0 llitij 

~~(0 (.)W 0 -a: .... a: <C X 4.0 (.) ::> S2' 

:zog <(00 

(.!J a: a: a:w w 3.0 oa.. u :X::(.) a: uo=> 01-0 a:(/)(/) 2.0 

u:.~ ~ (.)a: 

~~ 

(/)_ Oz 1.0 

5 10 15 20 25 30 

SOURCE-ROCK THICKNESS, 

IN METERS 

Figure 9. Relationship between grams of total organic carbon 

(TOC) per square meter of source-rock surface area (table 4) and 

source-rock thickness, in meters (table 3), for thermally immature 

source rocks. Linear regression describes the relationship with a 

zero intercept and a slope of 197.7 kg TOC/m3 (correlation coefficient = 0.991 ). 

over geological time make it unfeasible to obtain applicable 

quantitative concepts. Therefore, it becomes essential to 

employ laboratory pyrolysis methods that simulate the natural processes to develop a quantitative determination of 

expulsion factors. The two laboratory pyrolysis methods considered in this study are Rock-Eval pyrolysis and hydrous 

pyrolysis. 

ROCK-EVAL PYROLYSIS 

This open anhydrous-pyrolysis method typically consists of heating 50 to 150 mg of powdered rock in an oven 

that is continuously swept with flowing helium at low 

pressures (<138 kPa). The powdered rock is initially 

heated at a constant temperature between 250°C and 

300°C for 3 to 5 minutes. The volatilized products that 

are released during this heating are swept with helium 

into a flame ionization detector for quantification of 

hydrocarbon content. These readily volatilized hydrocarbons are considered to be unbound to the organic matter 

within the rock and are designated as "S 1" hydrocarbons. 

Immediately following this initial isothermal heating, the 

powdered rock is heated at a rate of 25°C/min or 30°C/ 

min to a final temperature of 600°C, which is maintained 

for 1 minute. The pyrolyzed products that are generated 

during this heating are vaporized and swept with helium 

into a flame ionization detector for quantification of 

hydrocarbon content. These pyrolyzed hydrocarbons are 

considered to be bound to the organic matter within the 

rock and are designated as "S2" hydrocarbons. 
METHODS AND RESULTS 15 

Although vaporization of generated hydrocarbons by 

this pyrolysis method has no resemblance to natural conditions under which petroleum is generated and expelled in 

sedimentary basins (Lewan, 1993, 1994), it has been successfully used to provide rapid evaluations of the relative 

hydrocarbon potential and thermal maturity of source rocks 

(Bordenave and others, 1993). Cooles and others (1986) 

extended these routine screening applications of Rock-Eval 

pyrolysis to determine expulsion factors of source rocks for 

direct application in petroleum material-balance studies 

within sedimentary basins (e.g., Mackenzie and Quigley, 

1988; MacGregor and McKenzie, 1987). The central 

assumption in this algebraic scheme is that a fixed fraction 

of organic carbon cannot be vaporized as S 1 and S2 hydrocarbons by Rock-Eval pyrolysis irrespective of the thermal 

maturity of a source rock. This inactive organic carbon is 

referred to as being "inert." Another assumption in this 

approach is that gas generation is sufficiently negligible during petroleum formation to allow hydrocarbon yields to be 

equated to petroleum yields (Cooles and others, 1986). This 

approach requires determination of total, pyrolyzed, and volatilized organic carbon in immature and mature source 

rocks. The volatilized and pyrolyzed organic carbon (Ct and 

C2, respectively) are determined respectively by multiplying 

the St and S2 hydrocarbons from Rock-Eval pyrolysis by 

0.85, which is an approximation of the carbon fraction of 

petroleum (Cooles and others, 1986). Inert organic carbon 

(CI) is calculated by subtracting the sum of Ct and C2 from 

the total organic carbon (TOC) of a source rock. An "o" 

superscript is used to denote organic carbon from immature 

source rocks that have not lost organic carbon due to petroleum or natural gas expulsion. An "m" superscript is used to 

denote organic carbon from mature or over-mature source 

rocks that have lost organic carbon due to petroleum or natural gas expulsion. All of these organic carbon values are in 

units of grams of carbon per gram of source rock (g C/g Rx). 

The first step in this approach is to determine the fraction of total organic carbon that occurs as inert organic 

carbon in the immature source rock (i.e., X1°), which is 

determined by the expression: 

0 TOC0

- (C2

°+C1°) XI=-------

TOC0 

(1) 

The assumption that this fraction of inert organic carbon 

remains constant with increasing thermal maturity (i.e., 

xlo = xim) allows the calculation of the original total 

organic carbon of the immature equivalent of a mature 

source rock (TOC0m) by the expression: 

(2) 

The difference between the total organic carbon calculated 

for the original source rock (TOC0m) and measured on the 

mature source rock (TOCm) is considered the amount of 

organic carbon lost from the mature source rock as a result 

of hydrocarbon expulsion. This quantity may be divided by 

the original total organic carbon of the mature source rock 

(TOC0m) to determine the grams of expelled carbon per 

gram of original total organic carbon of the source rock. 

Dividing this quantity by the carbon fraction of petroleum 

(0.85) gives an expulsion factor in grams of petroleum 

expelled from a mature source rock per gram of original 

total organic carbon in its original immature state (g HC/g 

TOC0m). 

This approach is applied to the mean values of the natural data set given in table 1. The fraction of inert organic 

carbon (X1°) is calculated by equation 1 to be 0.4712. This 

value is used to calculate the original total organic carbon of 

the mature and over-mature source rocks using equation 2. 

The resulting Rock-Eval expulsion factors are given in table 

6. The relation between these expulsion factors and hydrogen indices may be described by a second-degree polynomial as shown in figure 10. This expression and the relation 

between percent Ro values and hydrogen indices in figure 9 

allow the calculation of expulsion factors for the midpoint 

values for each 0.1-percent Ro interval. Results of this operation and the calculated quantities of expelled hydrocarbons 

for the dilution and steady-state models are given in table 7. 

Assuming that the expelled hydrocarbons measured by 

Rock-Eval pyrolysis are similar to petroleum produced in the 

Illinois Basin, barrels of expelled petroleum are calculated 

on the basis of an API gravity of 36.8° (Mast, 1970). The 

dilution and steady-state models respectively predict 786 

and 1,172 billion barrels of petroleum were expelled from 

source rocks in the New Albany Shale. 

HYDROUS PYROLYSIS 

This closed pyrolysis method typically consists of heating 300 to 500 g of rock chips (0.5 to 2.0 em) in the presence 

of liquid water in a 1-L reactor at a constant temperature 

between 250°C and 365°C for 3 to 6 days (Lewan, 1993). 

Internal pressures are a result of water vapor and generated 

gases within the headspace of the reactor and may range 

from 10 to more than 20 MPa, depending on the experimental temperature, organic richness of sample, and heating 

duration. If the rock sample is a potential source rock and the 

experimental time and temperature conditions are sufficient, 

a free-flowing liquid oil is expelled from the rock and accumulates on the surface of the water within the reactor 

(Lewan, 1985; Huizinga and others, 1988; Peters and others, 

1990; Baskin and Peters, 1992). This expelled oil has a 

gross, molecular, and isotopic composition similar to natural 

petroleum (Lewan, 1983, 1993; Peters and others, 1990; 

Lewan and others, 1978, 1983). API gravities of these oils 
16 MATERIAL-BALANCE ASSESSMENT OF PETROLEUM, NEW ALBANY SHALE, ILLINOIS BASIN 

Table 6. Rock-Eval expulsion factors calculated from geochemical data given in table 1 using equations 1 and 2. 

[Ro, mean random vitrinite reflectance; e, carbon; Rx, rock; He, hydrocarbons; Tocm, total organic carbon in mature or overmature source rock; elm, volatilized organic carbon determined by Rock-Eval pyrolysis of mature or over-mature source rocks 

(SI x0.85); e2m, pyrolyzed organic carbon determined by Rock-Eval pyrolysis of mature or over-mature source rocks (S2x0.85); 

elm, inert carbon in mature or over-mature rock (Tocm-[e 1 m+C2mD; Toe om, original immature total organic carbon of mature 

or over-mature source rock (see eq. 1 ); (Toe om_ Toem) is equal to the amount of organic carbon expelled from mature or overmature source rock; expelled carbon is equal to (TOe om_ TOCm)rrOe0m; expelled hydrocarbons are equal to expelled carbon 

divided by 0.85] 

OliN 

C-219 

R 0 (percent) 0.62 

Tocm (g C/g Rx) 0.0466 

elm (g C/g Rx) 0.0011 

C2m (g C/g Rx) 0.0204 

cr(g C/gRx) 0.0251 

Tocom (g C/g Rx) 0.0533 

Tocom_ Tocm (g C/g Rx) 0.0067 

Expelled carbon (g C/g TOC0m) 0.1257 

Expelled HC (g HC/g TOC0m) 0.148 

Well notation given in footnote for table 1. 

may vary from 25° to 42°, depending on the type of organic 

matter within the rock and the experimental conditions. 

These close similarities between hydrous-pyrolysis oils and 

natural petroleum suggest that, despite the higher temperatures used in hydrous pyrolysis, the mechanisms responsible 

for natural petroleum generation and expulsion are being 

simulated in the experiments. 

A series of hydrous-pyrolysis experiments were conducted on aliquots of a thermally immature sample of New 

Albany Shale to determine expulsion factors at different 

maturity levels. The sample (931026-3) was collected from 

the Clegg Creek Member at a roadcut along Highway 311, 

west of Sellersburg, Ind. This sample is organic rich and 

thermally immature, with a vitrinite reflectance less than 0.5 

percent Ro, a T max of 425°C, a production index of 0.03, a 

hydrogen index of 604 mg/g TOC, and a TOC of 14.3 weight 

percent. Care was taken to collect a blocky unweathered 

sample, which was crushed to gravel size (0.5 to 2.0 em) for 

the experiments. Each of the experiments consisted of heating 300 g of crushed rock and 400 g of distilled water in 1-L 

reactors for 72 hours at constant temperatures between 

270°C and 365°C. The expelled oil was collected from the 

reactor as described by Lewan (1993). The quantities of 

expelled oil are calculated as mass of expelled oil per mass 

of original TOC (i.e., TOC0 ). These expulsion factors 

increase with increasing experimental temperature, with the 

exception of one outlying data point (fig. 11). 

Relating these hydrous-pyrolysis expulsion factors to 

the 0.1-percent Ro intervals of the source rocks is 

Wells included (see footnote) 

13IL C-174 lliL RM 

0.70 0.95 1.30 1.65 

0.0426 0.0416 0.0548 0.0691 

0.0012 0.0003 0.0005 0.0003 

0.0111 0.0040 0.0034 0.0040 

0.0303 0.0373 0.0509 0.0648 

0.0643 0.0792 0.1080 0.1375 

0.0217 0.0376 0.0532 0.0684 

0.3375 0.4747 0.4926 0.4975 

0.397 0.558 0.580 0.585 

accomplished through the relationships both of these parameters have with the hydrogen index parameter determined by 

Rock-Eval pyrolysis of natural and experimentally matured 

samples. First, the relationship established between percent 

Ro and hydrogen index for naturally matured samples (fig. 8) 

is used to determine the hydrogen index for the midpoint percentRo values for each 0.1-percent Ro interval. Secondly, 

these calculated hydrogen indices are used in the relationship 

between hydrogen indices and expulsion factors for experimentally matured samples (fig. 12) to determine the 

hydrous-pyrolysis expulsion factor for each 0.1-percent ·Ro 

interval. The results are shown in table 8 along with the 

quantities of oil expelled for mature and over-mature source 

rocks for the dilution and steady-state models. Similar to the 

volume quantities determined from the Rock-Eval expulsion 

factors in table 7, barrels of oil expelled are calculated on the 

basis of a 36.8° API-gravity oil. The total quantities of 

expelled petroleum as determined by hydrous pyrolysis are 

305 to 473 billion barrels, which represent only 39 to 40 percent of the 786 to 1,172 billion barrels determined by RockEva! expulsion factors (table 7). 

ACCOUNTABLE IN-PLACE PETROLEUM 

Mast and Howard ( 1990) estimated, on the basis of production data and a recovery factor of 35 percent that the 

original in-place petroleum for known fields in the Illinois 

Basin is 12 billion barrels. Most of this in-place petroleum 
METHODS AND RESULTS 17 

0.6 

~E 0.5 

Oo 

1-(.) 

(.)Q 

<CILL~ 0.4 Z<( 

Oa: 

(j)(!) 

...Ja: 

=>w 0.3 O...o... 

[;Su 

_.J: 

<Ccn 

>~ 0.2 

(.)(!) 

~~ 

Oz 

a:- 0.1 

0.0 

0 100 200 300 400 500 600 700 

ROCK-EVAL HYDROGEN INDEX, 

IN MILLIGRAMS HC PER GRAM Tocm 

Figure 10. Relationship between expulsion factors (EF) determined by Rock-Eval pyrolysis (table 6) and Rock-Eval hydrogen indices (HI) (table 1). The curve is defined by the expression: 

EF=0.616-43.26x1Q-5(HI)-88.68xlo-s(HI)2. HC, hydrocarbons; 

Tocom, original immature total organic carbon of mature and overmature source rocks; TOcm, total organic carbon of of mature and 

over-mature source rocks. 

0.30 

0.20 

0.10 Original 

unheated 

sample 

0.00 ~ 260 280 300 320 340 360 380 

EXPERIMENTAL TEMPERATURE FOR 72 HOURS, 

IN DEGREES CELSIUS 

Figure 11. Quantity of petroleum expelled from hydrous-pyrolysis experiments conducted isothermally at temperatures from 27\fC 

to 365°C for 72 hours with aliquots of a sample from Clegg Creek 

Member of the New Albany Shale. TOC0 , total organic carbon of 

immature source rocks. 

occurs in reservoirs of Carboniferous age, with more than 60 

percent occurring in Chesterian sandstones, 18 percent 

occurring in Valmeyeran sandstones, and 13 percent occurring in Pennsylvanian sandstones. Organic geochemical correlations indicate that more than 99 percent of the 

en 

Ci5 

~0 ou 

~ ~ 0.3 

0...~ 

cn<C :>II: 

Q(!) 

a: a: ow 

~ ~ 0.2 

~5 _.en 

-~ 0<( 

oa: 

~ (!) 0.1 ...JZ 

wo... 

>< 

w 

100 200 300 400 500 600 700 

ROCK-EVAL HYDROGEN INDEX, 

IN MILLIGRAMS HC PER GRAM TOcom 

Figure 12. Relationship between expulsion factors derived from 

hydrous pyrolysis (HPEE) and hydrogen index (HI) determined by 

Rock-Eval pyrolysis on rock recovered from the hydrous-pyrolysis 

experiments (fig. 11). The curve is described by the expression: 

HPEE=0.399-99.60xHr5(HI)+573.26xlo-9(HI) 2. HC, hydrocarbons; TOC om, original immature total organic carbon of mature and 

over-mature source rocks; TOC0 , total organic carbon of immature 

source rocks. 

discovered in-place petroleum of the basin has been sourced 

by the New Albany Shale (Hatch and others, 1990). 

In addition to free-flowing producible petroleum, tarsand deposits occur at or near the surface in various sandstones of Late Mississippian and Early Pennsylvanian age. 

These tar deposits are dispersed around the margins of the 

eastern Moorman syncline of western Kentucky and appear 

to be closely associated with faults, paleovalleys, and stratigraphic traps (Noger, 1987). Conventional oil production 

has been obtained locally from the same sandstones a few 

kilometers down-dip (Williams and others, 1982). Some of 

these deposits have local seeps that flow as much as 10 barrels per year (McGrain, 1976). Resource assessments of 

these deposits are classified as measured and speculative. 

Measured reserves are based on core analyses of tar encountered in wells, and speculative reserves are based on reported 

tar shows on drilling logs, occasional core analyses, and geological interpretations (Noger, 1987). Measured in-place tar 

has been determined to be 1. 73 billion barrels, and speculative in-place tar has been determined to be 1.68 billion barrels (Kuuslqaa, 1984; Crysdale and Schenk, 1988; Noger, 

1987). These values give a total in-place tar of 3.41 billion 

barrels, which extends over 2,500 km2 of surface area and 

from the surface to a 183-m depth (Noger, 1987). No organic 

geochemical correlations have established the source rock 

for these tars, and opinions vary: Russell (1933) suggests 

that Late Mississippian marine shales are the source, and 
18 MATERIAL-BALANCE ASSESSMENT OF PETROLEUM, NEW ALBANY SHALE, ILLINOIS BASIN 

Table 7. Quantity of petroleum expelled from the New Albany Shale as determined by Rock-Eval 

expulsion factors. 

[Ro, mean random vitrinite reflectance; HC, hydrocarbon; TOC, total organic carbon; bbl, barrel; Mbr, Member; Fm, Formation] 

Rock-Eval Dilution model Steady-state model 

Ro interval expulsion Vaporized Expelled Vaporized Expelled 

(percent) factor1 hydrocarbons2 petroleum4 hydrocarbons3 petroleum4 

(kg HC/Mg TOC) (Tg) (billion bbl) (Tg) (billion bbl) 

Upper shale composite 

0.6-0.7 290.62 29,816 223.07 38,981 291.63 

0.7-0.8 437.44 10,394 77.76 14,313 107.08 

0.8-0.9 513.91 5,038 37.69 5,617 42.03 

0.9-1.0 555.04 9,706 72.62 16,015 119.82 

1.0-1.1 565.23 3,052 22.83 5,745 42.98 

1.1-1.2 573.09 428 3.20 760 5.69 

1.2-1.3 578.95 360 2.69 655 4.90 

1.3-1.4 582.86 262 1.96 494 3.70 

1.4-1.5 585.06 341 2.55 633 4.73 

>1.5 585.55 29 0.22 56 0.42 

"Mbr" total 59,426 444.59 83,269 622.98 

Selmier Member 

0.6-0.7 290.62 17,017 127.31 19,926 149.08 

0.7-0.8 437.44 5,932 44.38 6,761 50.58 

0.8-0.9 513.91 2,875 21.51 3,414 25.54 

0.9-1.0 555.04 5,540 41.45 9,822 73.48 

1.0-1.1 565.23 1,742 13.03 3,971 29.71 

1.1-1.2 573.09 244 1.83 509 3.81 

1.2-1.3 578.95 205 1.54 413 3.09 

1.3-1.4 582.86 149 1.12 321 2.41 

1.4-1.5 585.06 195 1.46 422 3.16 

>1.5 585.55 17 0.13 39 0.29 

Mbrtotal 33,916 253.76 45,598 341.15 

Blocher Member 

0.6-0.7 290.62 5,863 43.86 11,610 86.86 

0.7-0.8 437.44 2,044 15.29 3,998 29.91 

0.8-0.9 513.91 991 7.41 2,068 15.47 

0.9-LO 555.04 1,909 14.28 6,265 46.87 

1.0-1.1 565.23 600 4.49 2,734 20.46 

1.1-1.2 573.09 84 0.63 359 2.69 

1.2-1.3 578.95 71 0.53 223 1.67 

1.3-1.4 582.86 52 0.39 245 1.83 

1.4-1.5 585.06 67 0.50 303 2.27 

>1.5 585.55 6 0.04 26 0.19 

Mbr total 11,687 87.42 27,831 208.22 

Fm total 105,029 785.77 156,698 1,172.34 

1

Hydrogen index for the midpoint of each 0.1-percent Ro interval was determined from the 

relationship in figure 8 and the resulting hydrogen index was used to determine the RockEval expulsion factor from the relationship in figure 10. 

2

Rock-Eval expulsion factor (x10-3) is multiplied by the TOC mass as determined by the 

dilution model in table 5. 

3

Rock-Eval expulsion factor (xi0-3) is multiplied by the TOC mass as determined by the 

steady-state model in table 5. 

4

A petroleum density of 840.76 kg/m3 (i.e., 36.8°API gravity) is divided into the mass of 

vaporized hydrocarbons and the quotient is multiplied by 6.29 to convert cubic meters to 

billion barrels. 
METHODS AND RESULTS 19 

Table 8. Quantity of petroleum expelled from the New Albany Shale as determined by hydrouspyrolysis expulsion factors. 

[Ro. mean random vitrinite reflectance; TOC, total organic carbon; bbl, barrel; Mbr, Member; Fm, Formation] 

Hydrous-pyrolysis Dilution model Steady-state model 

Ro interval, expulsion Expelled Expelled Expelled Expelled 

(percent) factor1 oil2 petroleum4 oil3 petroleum4 

~~ oil/M~ Toq {T~ ~illion bbQ {T~ ~illion bbQ 

Upper shale composite 

0.6-0.7 87.45 8,972 67.12 11,730 87.75 

0.7-0.8 173.94 4,133 30.92 5,691 42.58 

0.8-0.9 242.86 2,381 17.81 2,655 19.86 

0.9-1.0 292.43 5,114 38.26 8,438 63.13 

1.0-1.1 306.76 1,656 12.39 3,118 23.33 

1.1-1.2 318.52 238 1.78 423 3.16 

1.2-1.3 327.75 204 1.53 371 2.77 

1.3-1.4 334.14 150 1.12 283 2.12 

1.4-1.5 337.83 197 1.48 365 2.73 

>1.5 338.66 17 0.13 32 0.24 

"Mbr" total 23,062 172.53 33,106 247.67 

Selmier Member 

0.6-0.7 87.45 5,121 38.31 5,996 44.86 

0.7-0.8 173.94 2,359 17.65 2,688 20.11 

0.8-0.9 242.86 1,359 10.17 1,613 12.07 

0.9-1.0 292.43 2,919 21.84 5,175 38.71 

1.0-1.1 306.76 945 7.07 2,155 16.12 

1.1-1.2 318.52 136 1.02 283 2.12 

1.2-1.3 327.75 116 0.87 234 1.75 

1.3-1.4 334.14 86 0.64 184 1.38 

1.4-1.5 337.83 112 0.84 244 1.82 

>1.5 338.66 10 0.07 23 0.17 

Mbrtotal 13,163 98.48 18,595 139.11 

Blocher Member 

0.6-0.7 87.45 1,764 13.20 3,494 26.14 

0.7-0.8 173.94 813 6.08 1,590 11.89 

0.8-0.9 242.86 468 3.50 977 7.31 

0.9-1.0 292.43 1,006 7.52 3,301 24.70 

1.0-1.1 306.76 326 2.44 1,484 11.10 

1.1-1.2 318.52 47 0.35 200 1.49 

1.2-1.3 327.75 40 0.30 12£ 0.94 

1.3-1.4 334.14 29 0.22 140 1.05 

1.4-1.5 337.83 39 0.29 175 1.31 

>1.5 338.66 3 0.03 15 0.11 

Mbrtotal 4,535 33.93 11,502 86.04 

Fm total 40,760 304.94 63,203 472.82 

1

Hydrogen indices for the midpoint value of each 0.1-percent Ro interval was determined 

from the relationship in figure 8 and the resulting hydrogen indices were used to 

determine hydrous-pyrolysis expulsion factors from the relationship in figure 12. 

2Hydrous-pyrolysis expulsion factor ( x 1 o-3) is multiplied by the TOC mass as determined by 

the dilution model in table 5. 

3Hydrous-pyrolysis expulsion factor ( x 1 o-3) is multiplied by the TOC mass as determined by 

the steady-state model in table 5. 

4A petroleum density of 840.76 kg/m3 ·(i.e., 36.8°API gravity) is divided into the mass of 

expelled oil and the quotient is multiplied by 6.29 to convert cubic meters to billion 

barrels. 
20 MATERIAL-BALANCE ASSESSMENT OF PETROLEUM, NEW ALBANY SHALE, ILLINOIS BASIN 

Walters (1974) suggests that Devonian-Mississippian black 

shales (i.e., New Albany Shale) are the source. With no other 

proven source rocks younger than the New Albany Shale 

(Cluff and Byrnes, 1990), this study will tentatively consider 

the New Albany Shale as the source of these tars. 

DISCUSSION 

PETROLEUM CHARGE 

Petroleum-charge values of 786 and 1,172 billion barrels derived from Rock-Eval expulsion factors are enormous 

quantities of petroleum. These quantities are one to two 

orders of magnitude greater than the quantity of discovered 

in-place petroleum within the basin, and it is difficult to 

rationalize these quantities as undiscovered petroleum or 

petroleum lost due to migration in or leakage from the basin. 

These unrealistic petroleum charge values can be attributed 

to Rock-Eval pyrolysis not simulating natural petroleum formation (i.e., generation and expulsion) and to the assumption 

that the fraction of inert organic carbon remains constant 

throughout petroleum formation. 

High temperatures and low pressures used in RockEva! pyrolysis to vaporize generated hydrocarbons from a 

powdered rock do not occur naturally in subsiding sedimentary basins. In addition, the vaporized hydrocarbons from 

Rock-Eval pyrolysis represent a collective product with no 

distinction between high-molecular-weight hydrocarbons 

that are likely in nature to remain within the rock as bitumen, 

medium-to-low-molecular-weight hydrocarbons that are 

likely in nature to be expelled in a liquid phase as petroleum, 

and low-molecular-weight hydrocarbons that are likely in 

nature to be released as natural gas. This lack of distinction 

among natural phases broadens the predicted natural conditions for petroleum formation and exaggerates petroleum 

expulsion factors (Lewan 1993, 1994). Thermal decomposition of sedimentary organic matter may be discussed in 

terms of two opposing reaction pathways (Lewan, 1994). 

One pathway involves the cleavage of carbon-carbon bonds 

to yield medium-to-low-molecular-weight products (i.e., oil 

and gas). The other pathway involves the cross linking of 

carbon atoms to yield high-molecular-weight non-volatile 

products (i.e., pyrobitumen or inert carbon). 

Rock-Eval pyrolysis promotes the cracking pathway 

and suppresses the cross-linking pathway by vaporizing and 

removing generated products from reaction sites within a 

rock before carbon-carbon cross-linking can occur. Similarly, this suppression of the cross-linking pathway is well 

demonstrated by oil-shale retorting methods, such as Fischer 

assays, which employ similar heating rates and temperatures 

as those used in Rock-Eval pyrolysis. Although Fischer 

assays use a cold trap to remove vaporized products instead 

of a carrier gas, their yields show a one-to-one correlation 

with Rock-Eval pyrolysis yields (Madec and Espitalie, 

90 

10 

~1~0~~~-BL-~---6~~--~4~~--~2--~~0--.__+.2~ 

LOGARITHM OF HEATING RATE, 

IN DEGREES CELSIUS PER HOUR 

Figure 13. Relationship between percent hydrocarbon yield and 

heating rate of Fischer assays (Evans and Campbell, 1979) and extrapolation toward geological heating rates for sedimentary basins 

(i.e., 1 °C/m.y. to 10°C/m.y.). 

1984). The ability of these open anhydrous-pyrolysis methods to suppress the cross-linking pathway becomes apparent 

by examining the product yields at different heating rates. 

Evans and Campbell ( 1979) conducted Fischer assays over 

the same temperature range at different heating rates on aliquots of the same sample. Their results show product yields 

significantly decrease with decreasing heating rates (fig. 13). 

This relationship can be explained by slower vaporization 

and removal of generated products from reaction sites within 

the rock at lower heating rates, which results in promotion of 

the cross-linking pathway and reduced product yields. 

Extrapolation of this trend in figure 13 to lower heating rates 

results in no product yield at heating rates typically observed 

in subsiding sedimentary basins (i.e., 1 °C/m.y. to 10°C/ 

m.y.). The enormous quantities of expelled petroleum determined by Rock-Eval pyrolysis indicate the currently 

employed heating rates (25°C/min or 30°C/min) are too 

high, but, based on figure 13, it remains uncertain what heating rate is appropriate to simulate the balance between cracking and cross-linking pathways operative in natural 

petroleum formation. 

Burnham (1991) has also observed reduced product 

yields with decreasing heating rates in open anhydrous 

pyrolysis and has questioned the assumption by Cooles and 

others (1986) that the fraction of inert organic carbon as 
DISCUSSION 21 

~ 0.24 

() 

~ 0.22 

:2 

~(2 0.20 

Z<!J 

wa: 

~w 0.18 

oa... ()5 0.16 

zcc Oa: 

~<( 0.14 

<(U 

uu uz 0.12 

:zc; 

c; a: 0.10 

a:O 

~ 0.08 

<( 

a: 

" 0.06 

~ 

·•·• ···············································-Measured original TOO··· 

t 

Original 

unheated sample Measured inert organic t carbon""'- . 

260 280 300 320 340 360 

EXPERIMENTAL TEMPERATURE FOR 72 HOURS, 

IN DEGREES CELSIUS 

380 

Figure 14. Change in measured inert organic carbon and calculated original total organic carbon (TOC0m) from Rock-Eval pyrolysis 

(Cooles and others, 1986) with increasing maturity, as induced by 

hydrous pyrolysis on aliquots of an immature sample of Clegg 

Creek Member of the New Albany Shale (fig. 11). 

determined by Rock-Eval pyrolysis remains constant 

throughout petroleum formation. The rock recovered from 

the series of hydrous-pyrolysis experiments conducted on 

aliquots of shale from the Clegg Creek Member (fig. 11) provide samples at various stages of petroleum formation to further test this assumption. Rock-Eval data on the rock 

recovered from these experiments is given in table 9. The 

inert and original total organic carbon contents (C1° and 

TOC0 ) of the unheated rock are 67.5 and 143.4 mg/g of rock, 

respectively. These values give an inert organic carbon fraction of0.471 (eq. 1), which is used with the data in table 9 to 

calculate the inert (C1) and original total organic carbon contents (TOC0 m) at different maturities induced by hydrous 

pyrolysis. Calculations are made with equation 2, which 

assumes that the inert organic carbon fraction (C1) remains 

constant with increasing thermal maturity. The plotted 

results in figure 14 indicate that this assumption is not valid 

and that the amount of inert organic carbon, as determined 

by Rock-Eval pyrolysis, increases significantly with increasing thermal maturity. This increase results in significant 

overestimates of original total organic carbon (TOC0 m) by as 

much as 39 percent (fig. 14). These overestimates of original 

total organic carbon in thermally mature rocks result in 

higher calculated organic carbon losses attributed to petroleum expulsion, which explain in part the unrealistic expulsion factors and enormous quantities of expelled petroleum 

derived from Rock-Eval pyrolysis. 

These results suggest that, in addition to heating rate, 

the maturity level of a source rock can also influence the 

results from open anhydrous pyrolysis. This influence is not 

surprising when one considers the changes that occur to 

organic matter and its distribution within a source rock with 

increasing thermal maturity. Sedimentary organic matter in 

thermally immature source rocks occurs predominantly as an 

insoluble solid kerogen, which is distributed within the mineral matrix as insular domains (Lewan, 1987). In naturally 

and experimentally matured source rocks, the kerogen 

domains decompose into a viscous, high-molecular-weight 

bitumen that impregnates the microporosity and parting 

planes of the rock to form a continuous organic network 

(Lewan, 1987). These state and distribution changes of the 

organic matter with increasing thermal maturity are also 

accompanied by compositional changes in the remaining 

bitumen as saturate-enriched petroleum is expelled from the 

rock (Lewan, 1993). Therefore, it is conceivable, with all of 

these physical and chemical changes occurring to the organic 

matter with increasing maturation, that the response from 

Rock-Eval pyrolysis would be different for the same rock at 

different maturity levels. The observed increase of inert 

organic carbon with increasing thermal maturation as shown 

in figure 14 indicates an increasing preference for the crosslinking pathway with increasing maturity of a source rock. 

Although the petroleum charge determined by RockEva! pyrolysis is approximately 2.5 times greater than the 

petroleum charge determined by hydrous pyrolysis, the latter 

is still large relative to the discovered in-place petroleum 

within the basin. Hydrous pyrolysis exaggerates the natural 

processes responsible for petroleum expulsion (Lewan, 

1994) and, therefore, should not be directly applied to sedimentary basins (Lewan, 1994). Three likely causes of this 

exaggeration by hydrous pyrolysis include enhanced solubility of H20 in the bitumen network, reduced hydrostatic pressure, and enhanced thermal expansion of petroleum 

products. 

Comparison of yields from closed pyrolysis experiments under hydrous and anhydrous conditions show the 

presence of water significantly suppresses the cross-linking 

pathway and promotes generation of soluble organic products (Comet and others, 1986; Tannenbaum and others, 

1986; Lewan, 1993). Lewan (1992) suggests that the 

enhancement of yield under hydrous conditions relative to 

anhydrous closed conditions is a result of dissolved H20 in 

the bitumen network acting as a source of hydrogen. It has 

been experimentally established that the solubility of water 

in hydrocarbons is two orders of magnitude higher than the 

solubility of hydrocarbons in water (Tsonopoulos and Wilson, 1983; Heidman and others, 1985; Skripka and Boksha, 

1976; Guerrant, 1964; Griswold and Kasch, 1942). However, this high solubility of water in hydrocarbons is strongly 

dependent on temperature, with water solubilities being 

more than one order of magnitude higher at temperatures 

used in hydrous pyrolysis (300°C to 365°C) than at temperatures encountered in subsiding sedimentary basins ( 1 00°C 

to 200°C). A reduction of a possible hydrogen source by this 

magnitude is expected to promote the cross-linking pathway 

and reduce petroleum yields and expulsion factors under 
22 MATERIAL-BALANCE ASSESSMENT OF PETROLEUM, NEW ALBANY SHALE, ILLINOIS BASIN 

Table 9. Rock-Eval data and calculated inert carbon and original total organic carbon in rocks recovered from hydrous-pyrolysis experiments on aliquots of a sample from the Clegg Creek Member of the New Albany Shale. 

[See fig. 11. See text for definitions of s1 and S2. HC, hydrocarbons; Rx, rock; wt. %, weight percent; TOC, total organic carbon; C, carbon] 

Hydrous-pyrolysis 81 82 TOC Hydrogen cl c2 Inert Original 

conditions HC HC (wt.%Rx) index 81-carbon 82-carbon carbon Toc1 

(DCfor72h) (mg/gRx) (mg/gRx) (82/gTOC) (g C/gRx) (gC/gRx) (gC/g Rx) (gC/gRx) 

unheated 2.72 86.56 14.34 

269.7 1.87 85.01 14.56 

285.0 2.42 82.93 14.31 

300.2 4.53 78.28 14.09 

310.1 6.39 69.56 13.90 

320.3 8.24 57.05 13.31 

330.1 11.49 44.37 12.70 

340.2 10.67 33.71 12.04 

350.5 7.44 19.56 11.21 

355.1 6.37 12.50 10.72 

360.3 5.05 10.94 10.64 

365.0 4.70 9.32 10.58 

1

Inert organic carbon fraction= 0.471 (see eq. 1). 

natural conditions. Research is currently under way to determine the degree to which hydrous pyrolysis exaggerates 

expulsion in sedimentary basins (Lewan, 1994), but the differences in expulsion between anhydrous and hydrous pyrolysis (Lewan, 1993) suggest that exaggeration by a factor of 

2 is conceivable. 

Several experimental studies have demonstrated that 

increasing hydrostatic pressure can significantly reduce 

hydrocarbon yields from source rocks (Price and Wenger, 

1992; Freund and others, 1992, figs. 2 and 3; Michels and 

others, 1992). Hydrous pyrolysis typically operates at hydrostatic pressures slightly higher than the vapor pressure of 

water as determined by the experimental temperature and 

amount of gas generated from the pyrolyzed rock (Lewan, 

1993). The hydrous-pyrolysis experiments conducted at 

330°C for 72 hours by Michels and others (1992) showed a 

total yield (bitumen + expelled oil) reduction of 34 weight 

percent at a pressure of 70 MPa and 58 weight percent at a 

pressure of 130 MPa relative to the total yields under typical 

hydrous-pyrolysis conditions at a pressure of 13 MPa. 

According to paleoreconstructions of the Illinois Basin, the 

New Albany Shale was within peak petroleum generation at 

depths from 2.44 to 3.36 km (Cluff and Byrnes, 1990). If the 

New Albany Shale at these depths was under normal hydrostatic conditions ( 10.2 kPa/m), the water pressure would be 

24.9 to 34.3 MPa. Under overpressure conditions, approaching lithostatic pressures (20.4 kPa/m), the water pressure at 

these same depths would be 49.8 to 68.5 MPa (HamiltonSmith, 1993). This latter range of water pressures would correspond approximately to a 25 to 35 percent reduction in 

yield based on the hydrous-pyrolysis results of Michels and 

others (1992) at 330°C for 72 hours. 

603.6 0.0023 0.0736 0.0675 0.1434 

583.9 0.0016 0.0723 0.0718 0.1524 

579.5 0.0021 0.0705 0.0706 0.1499 

555.6 0.0039 0.0665 0.0705 0.1497 

500.4 0.0054 0.0591 0.0744 0.1580 

428.6 0.0070 0.0485 0.0776 0.1648 

349.4 0.0098 0.0377 0.0795 0.1688 

280.0 0.0098 0.0287 0.0827 0.1756 

174.5 0.0063 0.0166 0.0892 0.1894 

116.6 0.00~4 0.0106 0.0912 0.1936 

102.8 0.0043 0.0093 0.0928 0.1970 

88.1 0.0040 0.0079 0.0939 0.1994 

The higher temperatures used in hydrous pyrolysis relative to natural petroleum generation may also exaggerate 

expulsion factors because of greater thermal expansion of 

generated petroleum within source rocks. The specific volume of petroleum with a 29° API gravity is 1.21 cm3/g at 

100°C and 1.51 cm3/g at 315°C (GPSA, 1987). Therefore, a 

given mass of petroleum generated in a source rock by 

hydrous pyrolysis at 315°C will occupy 25 percent more volume than that generated in a source rock by natural subsidence to 1 00°C. This percent of volume increase may reflect 

an equivalent increase in petroleum expulsion during 

hydrous pyrolysis. Most petroleum expulsion models require 

the porosity of a source rock to be filled with bitumen or 

petroleum before expulsion occurs (e.g., Durand and others, 

1987; Leythaeuser and others, 1987). Lewan (1987) reports 

notable expansion of source-rock cores recovered from 

hydrous-pyrolysis experiments as a result of the opening of 

oil-filled parting fractures parallel to the bedding fabric. 

Although petroleum densities at temperatures in excess of 

320°C are not available, extrapolation of the lower temperature trends ( <320°C) suggests volume increases may exceed 

30 percent at experimental temperatures of 350°C. 

Although hydrous pyrolysis simulates natural petroleum formation, as indicated by the composition of its 

expelled oil and petrographic character of its recovered 

rock, its expulsion factors appear to be exaggerated to some 

degree compared to natural expulsion factors. Additional 

research is critical to determining the degree of exaggeration. However, the general evaluation of water solubility, 

hydrostatic pressure, and thermal expansion effects suggest 

that it would be reasonable to assume natural expulsion factors to be at least one-half of the hydrous-pyrolysis expulsion factors. This temporary estimated correction to the 
DISCUSSION 23 

hydrous-pyrolysis expulsion factors would reduce the 

petroleum charge values to 152 and 236 billion barrels for 

the dilution and steady-state models, respectively. 

PETROLEUM LOSSES 

Petroleum losses within the Illinois Basin may occur as 

residual oil in porous-rock carrier beds; surface leakage in 

the form of tar seeps; and eroded traps, carrier beds, or seeps 

in the post-Pennsylvanian section. More than 90 percent of 

the accountable produced,petroleum within the Illinois Basin 

occurs in reservoirs that are stratigraphically at least 350 m 

above the New Albany Shale. No continuous porous strata 

capable of serving as a regional carrier bed occurs within this 

intervening section between source and reservoir. As a 

result, it becomes necessary to advocate petroleum migration 

through regional fractures and faults. Secondary migration 

through fractures and faults has been advocated as effective 

pathways in other sedimentary basins (e.g., Bell, 1989; 

Price, 1980; du Rouchet, 1984). Evidence of this mode of 

secondary migration in the Illinois Basin includes the association of tar sands with faults in western Kentucky (Williams and others, 1982), lenticular reservoirs encased in 

impervious strata of the Ste. Genevieve Limestone and 

Cypress Sandstone (Seyler and Cluff, 1990), and the apparent migration of petroleum along faults to account for 

petroleum in Pennsylvanian reservoirs (Swann and Bell, 

1958; Seyler and Cluff, 1990). 

Although secondary migration through fractures and 

faults appears to be significant in the Illinois Basin, porous 

carrier beds may have been critical to lateral migration of 

petroleum away from faults and fracture conduits. The 

regional extent and good reservoir character of the Aux 

Vases Sandstone (Mississippian) make it a strong candidate 

as a regional carrier bed. This possible carrier bed varies in 

thickness from an average of 7.6 m in the central part of the 

basin to 61 m in the western part of the basin (Seyler and 

Cluff, 1990), and it is an exploration target from which 

almost 1 billion barrels of petroleum have been produced 

(Treworgy, 1990). It has a mean porosity of 18 percent and 

a mean permeability of 76 mD based on data from 179 fields 

(Mast, 1970). The Sylamore Member (Devonian), which 

occurs at the base of the New Albany Shale, has also been 

suggested as a possible carrier bed (Oltz and Crocket, 1989; 

Bethke and others, 1991 ). However, this rock unit varies in 

thickness from a few centimeters to 1.6 m and has a discontinuous distribution, as mapped by Workman and Gillette 

(1956), that make its significance as a regional carrier bed 

unlikely. 

The importance of considering porous-rock units as 

carrier beds is the ability of granular rocks to retain residual 

petroleum after they have served as carrier beds (Schowalter, 

1979). This residual petroleum in carrier beds has been 

advocated as the cause of the enormous quantities of petroleum that must have been lost, based on the enormous quantities of expelled petroleum determined by Rock-Eval 

pyrolysis (Mackenzie and Quigley, 1988). Schowalter 

( 1979) suggests that only the upper few feet of a potential 

carrier bed experiences petroleum migration, and England 

and others (1987) suggest that only 1 to 10 percent of the 

cross-sectional area of a carrier bed experiences petroleum 

migration. The amount of residual petroleum that remains in 

this portion of carrier bed that experiences petroleum migration ranges from 10 to 30 percent of the pores for water-wet 

sandstones (Schowalter and Hess, 1982). The surface area of 

the Aux Vases Sandstone that contains a sandstone-to-shale 

ratio greater than 1:8, as mapped by Swann and Bell (1958), 

is 54.5x109 m2. Assuming that 3m of this entire area acted 

as a carrier bed with a mean porosity of 18 percent, 10 to 30 

percent of this pore volume equates to 18.5 to 55.5 billion 

barrels of unrecoverable residual petroleum lost in the carrier 

bed. Currently, these quantities cannot be substantiated by 

petroleum shows from drilling reports or cores. Therefore, 

this range is treated as a maximum loss that includes residual 

petroleum that may have occurred on a more local scale in 

other sandstones younger than the Aux Vases Sandstone. 

Petroleum may also be lost from a basin as a result of 

untrapped petroleum leaking out of carrier beds, faults, or 

fractures at or near the surface. Although weathering of leaking petroleum by evaporation, water washing, microbial 

degradation, polymerization, and autp-oxidation (Hunt, 

1979, p. 411) may result in as much as 90 percent loss of the 

original petroleum, a residual tar will remain to indicate the 

occurrence of petroleum leakage. The only major tar deposits within the Illinois Basin occur in sandstones that subcrop 

at or immediately overlie the Mississippian-Pennsylvanian 

unconformity in western Kentucky. These tar-sand deposits 

comprise an in-place resource of 3.4 billion barrels, with 

1. 73 billion barrels being measured and 1.68 billion barrels 

being speculative (Kuuskraa, 1984; Noger, 1987; Crysdale 

and Schenk, 1988). The API gravity of the tar is typically 10° 

(Ward, 1983; Fedde and Zavada, 1983; Moore and others, 

1984), with a mean sulfur content of 1.66 weight percent 

(Ward, 1983; Fedde and Zavada, 1983; Hosterman and others, 1990; Thomas and others, 1983). These properties are 

significantly different than those of the produced petroleum 

of the Illinois Basin, which has a mean API gravity of 36.8° 

(Mast, 1970) and a mean sulfur content 0.22 weight percent 

(Huff, 1987). 

Subsurface degradation of produced petroleum to tar 

with these properties has been documented in the Brea 

Olinda field of the Los Angeles Basin (W.L. Orr, written 

commun., 1994). Microbial activity or water washing is the 

usual cause of this degradation (Bailey and others, 1973). 

These processes do not appear to add or remove sulfur, 

which occurs predominantly in the more aromatic and highmolecular-weight fraction of most petroleum (W.L. Orr, 

written commun., 1994). As a result, sulfur content can be 
24 MATERIAL-BALANCE ASSESSMENT OF PETROLEUM, NEW ALBANY SHALE, ILLINOIS BASIN 

used to determine the amount of petroleum lost from the tarsand deposits prior to degradation. Mass-balance calculation using the mean sulfur content of 0.22 weight percent 

for the original petroleum from which the tar was derived 

indicates that the 3.4 billion barrels of in-place tar represents only 13.3 weight percent of the original in-place petroleum. This percentage is in agreement with the study by 

Tannenbaum and others ( 1987), which determined that the 

tars in the Dead Sea area represented 10 to 20 percent of the 

original undegraded petroleum. Using 13.3 percent and correcting for density changes from 36.8° to 10° API gravity 

gives 30.4 billion barrels of original in-place petroleum 

prior to degradation. Approximately half of this total is 

measurable barrels (15.4x109 bbl) and the remaining half is 

speculative barrels (15.0x109 bbl). This total quantity is 

more than 2.5 times greater than the 12 billion barrels of 

discovered in-place petroleum and represents 27 billion barrels of petroleum lost from the basin by degradation of nearsurface leakage. 

The final petroleum loss to evaluate in the Illinois 

Basin is the amount of petroleum originally hosted in the 

eroded Upper Pennsylvanian through Permian section. 

Thermal-history models based on vitrinite reflectance and 

moisture content of Lower Pennsylvanian coal indicate 

that 0.3 to more than 2 km of Upper Pennsylvanian 

through Permian section was removed by erosion during 

the Mesozoic and Cenozoic (Damberger, 1971; Cluff and 

Byrnes, 1990). Petroleum formation from the New 

Albany Shale was well underway by the end of the Permian (Cluff and Byrnes, 1990), which makes it possible 

for petroleum to have migrated into carrier beds, traps, 

and seeps within the Upper Pennsylvanian through Permian section. The likelihood of this possibility is supported by surface tar deposits in Lower Pennsylvanian 

sandstones in western Kentucky and by shallow petroleum production from Lower Pennsylvanian sandstones at 

subsurface depths between 50 and 150 m in Illinois and 

Indiana (Ball Associates, 1965). However, the amount of 

petroleum that may have migrated into the Upper Pennsylvanian through Permian section remains uncertain. 

Petroleum production from Lower Pennsylvanian sandstones comprise 13 percent of the total basin production, 

with 88 percent of it occurring in traps associated with the 

LaSalle anticline (Seyler and Cluff, 1990). Currently, field 

studies are not available on whether these traps are filled to 

their spill points. If these traps are not filled to their spill 

points and have seals capable of maintaining petroleum columns to the spill points, it may be assumed that the petroleum charge was less than spill-point volumes and migration 

of petroleum into the overlying Upper Pennsylvanian 

through Permian section was minimal. Similar field studies 

on Mississippian traps associated with the Salem, Louden, 

and Johnsonville anticlines would also be helpful in evaluating whether a limited petroleum charge in these deeper parts 

of the basin prevented petroleum accumulations from 

occurring in overlying closures in Lower Pennsylvanian 

sandstones. Until field studies of this type are made within 

the context of migration pathways and petroleum charge in 

Illinois and Indiana, no defendable estimate can be made on 

the quantity of petroleum lost due to erosion of the Upper 

Pennsylvanian through Permian section. 

The petroleum losses associated with the eroded section 

overlying the tar deposits of western Kentucky is a more facile consideration. The 3.4 billion barrels of tar that equate to 

30.4 billion barrels of original undegraded petroleum occurs 

at subsurface depths shallower than 200m (Noger, 1987). 

Cluff and Byrnes (1990) estimate that more than 600 m of 

section have been removed from this area by erosion. These 

tar deposits are very different in size and geometry from oil 

reservoirs and appear to be truncated migration pathways 

that may have fed reservoirs in the Upper Pennsylvanian 

through Permian section prior to erosion. If it is assumed that 

the areal extent of petroleum removed by erosion was the 

same as that remaining, the original volume of undegraded 

petroleum removed by erosion would be 91.2 billion barrels. 

Approximately half of this total is derived from the measurable barrels (46.2x109 bbl), and the remaining half is derived 

from the speculative barrels (45.0x109 bbl). The sum of this 

lost petroleum with the petroleum of the remaining tar 

deposits (i.e., 30.4 billion bbl) is 121.6 billion barrels of 

undegraded petroleum, which equates to 13.6 billion barrels 

of tar prior to erosion. Although this quantity appears large 

relative to the 12 billion barrels of in-place petroleum 

discovered in the Illinois Basin, it is not excessive compared 

to the 12.5 to 16 billion barrels of tar in the Tar Sand Triangle 

of Utah (Crysdale and Schenk, 1988) or the 626 billion barrels of heavy bitumen in the Athabasca tar deposit of Canada 

(Carrigy, 1974). 

MATERIAL BALANCE 

The material balance between accountable petroleum in 

the Illinois Basin and petroleum charge from the New 

Albany Shale is given in table 10. The petroleum charge 

based on one-half of the expelled oil from hydrous-pyrolysis 

yields the most reasonable values of 152 to 236 billion barrels, compared with the 92 to 189 billion barrels of accountable petroleum in the basin. Approximately two-thirds of 

this accountable petroleum may have migrated along fault 

systems and the Mississippian-Pennsylvanian unconformity 

in western Kentucky-only 6 to 13 percent migrated into 

discovered reservoir traps. The remaining 18.5 to 55.5 billion barrels of petroleum may have been lost as residual 

petroleum along migration pathways in porous carrier beds. 

Although this material balance yields reasonable values, the uncertainty in assumptions and variability in values 

make it too equivocal to determine the amount of petroleum 

remaining to be discovered. The undiscovered quantities of 

petroleum sourced from the New Albany Shale in the Illinois 
DISCUSSION 25 

Table 10. Material balance of accountable petroleum and petroleum charge from source rocks of the New Albany Shale in the 

Illinois Basin. 

Accountable petroleum 

In-place discovered 

Residual in carrier beds 

Undegraded tar deposits 

Lost by erosion 

Total accountable petroleum 

Petroleum charge 

Yi hydrous pyrolysis 

Hydrous pyrolysis 

Rock-Eval pyrolysis · 

Undiscovered petroleum** 

Least difference 

Greatest difference 

Billions ofbarrels 

12.0 

18.5-55.5 

15.4-30.4 

46.2-91.2 

92.1-189.1 

152-236* 

305-472* 

786-1,172* 

-37 

144 

*Range based on dilution and steady-state models for organic 

richness in source rocks. 

**Based on Yi hydrous-pyrolysis expulsion factor. 

Basin show a wide range of values. Using the one-half 

hydrous-pyrolysis expulsion factors, a minimum of -37 billion barrels of undiscovered petroleum is obtained by subtracting the maximum accountable petroleum value ( 189.1) 

from the minimum petroleum charge value (152). This deficit may be interpreted as indicating that no more petroleum 

from the New Albany Shale remains to be found in the Illinois Basin or that estimates of erosional or residual losses 

are too high. Conversely, a maximum of 144 billion barrels 

of undiscovered petroleum from the New Albany Shale may 

be obtained from the same expulsion factors by subtracting 

the minimum accountable petroleum value (92.1) from the 

maximum petroleum charge value (236). However, the 

intensity of drilling in the Illinois Basin makes this maximum unlikely. Mast and others (1989) estimate that only 

0.46 billion barrels of undiscovered petroleum remains to be 

produced in this Illinois Basin, and 75 percent of this petroleum will occur in fields smaller than 1 million barrels (Oltz 

and others, 1990). This estimated amount of undiscovered 

petroleum equates to 1.3 billion barrels of in-place petroleum by using a recovery factor of 35 percent. The actual 

amount of remaining undiscovered petroleum expelled from 

the New Albany Shale is considered to be somewhere 

between these two extremes of 0 and 144 billion barrels. 

The question that emerges from this wide range of 

undiscovered petroleum is whether or not a more accurate 

material-balance assessment can be achieved through collection of new data and further research. An accurate petroleum 

charge is obviously one of the critical concerns. The amount 

of accountable petroleum will always be subject to differing 

interpretations due to uncertainties in evaluating migration 

and erosional loses, but realistic and well-constrained 

petroleum-charge values can establish an ultimate quantity 

of petroleum expelled from mature and over-mature source 

rocks within a basin. This realistic ultimate petroleum charge 

for a basin can serve as a fixed quantity from which interpretations can be evaluated, compared, and discussed. Establishing this ultimate quantity of petroleum requires accurate 

characterization of the source rock and realistic expulsion 

factors. The importance of an accurate characterization of a 

source rock is illustrated by the 84 billion barrel difference 

between the dilution and steady-state models using the same 

one-half hydrous-pyrolysis expulsion factors (table 10). 

Similarly, the importance of realistic expulsion factors is 

demonstrated by the 481. to 700 billion barrel difference 

between petroleum charges derived from Rock-Eval and 

hydrous-pyrolysis expulsion factors (table 10). In addition to 

developing a thorough understanding of the factors that 

influence laboratory pyrolysis yields, it is also essential to 

know how they relate to natural maturity intervals within a 

sedimentary basin. This feasibility study shows that 45 to 50 

percent of the petroleum charge derived from Rock-Eval 

expulsion factors and 34 to 39 percent of the petroleum 

charge derived from the hydrous-pyrolysis expulsion factors 

are from source rocks in the 0.6- to 0.7-percent Ro interval 

(tables 7 and 8). If further studies reveal that this early stage 

of maturation does not yield these quantities under natural 

conditions, the resulting petroleum-charge values may be 

significantly reduced by these percentages. As an example, 

the petroleum charge using the one-half hydrous-pyrolysis 

expulsion factors for maturity interval greater than 0. 7 percentRo is 93 to 157 billion barrels. Clearly, accurate expulsion factors and source-rock characterization are essential to 

the utility of material-balance assessments. 

. FUTURE RESEARCH 

This material-balance assessment relied solely on suppressed vitrinite reflectance in the New Albany Shale to 

determine level of thermal maturity, which was correlated to 

Rock-Eval hydrogen indices to determine degree of petroleum generation. Other parameters related more specifically 

to petroleum expulsion from a source rock need to be 

researched. Lewan (1985) demonstrated that type-II kerogens isolated from source rocks subjected to hydrous pyrolysis had a common relationship between their atomic H/C 

ratio and percent of expelled oil, irrespective of differences 

in their kinetics of petroleum formation. Stages of petroleum 

generation and the effectiveness of potential source rocks 

have also been evaluated by petrophysical log properties 

(Meissner, 1978) and petrographic studies (Lewan, 1987). 

Preferential expulsion of particular classes of biomarker 

compounds (e.g., monoaromatic steroid hydrocarbons) from 

source rocks (Lewan and others, 1986) may also provide an 

index of petroleum expulsion. Focused research efforts on 

these and other possible indicators of petroleum generation 
26 MATERIAL-BALANCE ASSESSMENT OF PETROLEUM, NEW ALBANY SHALE, ILLINOIS BASIN 

and expulsion are attainable and relevant to obtaining more 

accurate material-balance assessments in the future. 

Additional research is needed to understand the natural 

factors that control petroleum expulsion from source rocks. 

Hydrous-pyrolysis experiments have shown that the presence of water (Lewan, 1993), hydrostatic pressure (Michels 

and others, 1992), mineral matrix (Lewan and Whitney, 

1993), and amount of organic matter (Lewan, 1987) can 

have a significant effect on petroleum expulsion. These factors need to be quantified and related to chemical and physical mechanisms responsible for petroleum generation and 

expulsion for reasonable extrapolations to natural conditions. Specific to this material balance on the Illinois Basin, 

additional experimental work is needed on other members of 

the New Albany Shale. This study assumed that the experimental results on the sample from the Clegg Creek Member 

are representative of source rocks in all of the members of 

the New Albany Shale. 

Collection of source rocks and examination of their 

relationship to carrier beds in the subsurface also needs further study. Price (1994) maintains that the petroleum potential remaining in a mature source rock is underestimated 

because of significant petroleum losses to the drilling mud as 

cuttings or cores move up the borehole for collection at the 

wellhead. If this phenomenon is common, expulsion factors 

will be overestimated and a major petroleum resource 

remaining within source rocks may be unrecognized. In 

addition, the thickness of a source rock and its relationship 

to adjacent carrier beds may significantly influence expulsion factors. Leythaeuser and others ( 1988) have presented 

geochemical data on cores from the North Sea that suggest 

expulsion efficiencies are greater at the margins of thick 

source rocks where they are in contact with carrier beds. This 

interpretation can be tested in the Illinois Basin at the contact 

between the Sylamore Member and overlying organic-rich 

shales in the New Albany Shale. 

Although an accurate petroleum charge is critical to 

establishing an upper limit for a material-balance assessment, an accurate determination of petroleum losses during 

secondary migration is critical to establish the amount of 

undiscovered petroleum remaining within a basin. Detailed 

studies on migration pathways of petroleum from the mature 

source rock to convergence in traps or divergence throughout the basin are needed. Petroleum accumulations and seeps 

along migration pathways need to be evaluated in terms of 

spill points, seal integrity, and related accumulations. Secondary migration through regional or tectonic fractures, fault 

zones, or permeable porous strata need to be evaluated from 

buoyancy and fluid-flow models, compositional data on 

fluid inclusions, secondary porosity occurrences and timing, 

petroleum shows and staining, and compositional changes in 

migrated petroleum. A major assumption in this feasibility 

study is that tar deposits in western Kentucky were derived 

from petroleum expelled from the New Albany Shale. 

Although organic geochemical studies have correlated the 

petroleum in Illinois with the New Albany Shale (Hatch and 

others, 1990), no geochemical correlations have established 

the source of petroleum and tar in western Kentucky. These 

tars may account for more than two-thirds of the accountable 

petroleum within the basin. Therefore, an organic geochemical study to establish the source rock of these tars is essential 

to future material-balance assessments of the Illinois Basin. 

Although this future research represents a major scientific effort, the focusing of this basic research effort has 

immediate applications to providing more accurate and credible petroleum resource assessments. 

CONCLUSIONS 

Critical to a material-balance assessment is the petroleum charge of source rocks within a basin. The two essential components for an accurate petroleum charge are wellcharacterized source rocks and realistic petroleum expulsion 

factors. Although the thermally immature cores and outcrops 

of the New Albany Shale are well characterized, the effect of 

significant thickening of this rock unit on its organic richness 

at higher maturity levels has not been well characterized. 

The steady-state and dilution models used in this study serve 

as good end members in projecting organic richness of the 

source rocks in their depocenter, but more accurate and 

member-specific models for organic richness are needed. 

This enhanced accuracy is attainable through better characterization of source rocks in cores representing higher levels 

of thermal maturity within the basin. 

It also becomes apparent from this study that results 

from laboratory pyrolysis methods cannot be directly used to 

determine expulsion factors for naturally matured source 

rocks. The unnatural method by which a product is derived 

in Rock-Eval pyrolysis and the incorrect assumption that 

inert carbon of a source rock remains constant with increasing thermal maturity results in unrealistic petroleum-charge 

values ranging from 786 to 1, 172 billion barrels of petroleum. Although hydrous pyrolysis simulates the natural processes involved in petroleum generation and expulsion, the 

higher temperatures and lower hydrostatic pressures in these 

experiments compared with natural conditions results in 

exaggerated expulsion factors. More research is needed to 

evaluate the degree of exaggeration, but a qualitative evaluation suggests that hydrous pyrolysis may exaggerate expulsion factors by a factor of 2. Using this factor to correct 

expulsion efficiencies derived from hydrous pyrolysis gives 

more realistic petroleum-charge values ranging from 152 to 

236 billion barrels of petroleum. Thirty-four to thirty-nine 

percent of this petroleum charge is derived from source 

rocks with thermal maturities between 0.6 and 0.7 percent 

Ro. If future studies indicate that petroleum expulsion did not 

occur within this maturity interval, then the petroleum 

charge for the basin could decrease to a range of 93 to 157 

billion barrels. 
REFERENCES CITED 27 

Accounting for the amount of petroleum lost within 

or from a basin is also critical to a material-balance 

assessment. This aspect requires accurate determinations 

of residual petroleum in porous carrier beds, surface leakage because of insufficient traps along migration pathways, and removal of reservoired petroleum by erosion. 

Secondary migration in the Illinois Basin appears to have 

been dominated by vertical migration along fractures and 

faults. The significance of this style of migration is demonstrated by the fault-related tar sands of western Kentucky, which represent 15 to 30 billion barrels of 

undegraded petroleum. An additional 46 to 91 billion barrels of petroleum may have existed in overlying reservoirs before they were eroded during post-Permian time. 

These values suggest that more than two-thirds of the 

accountable petroleum expelled from the New Albany 

Shale migrated through fractures or faults into western 

Kentucky. This study also suggests that as much as 18 to 

56 billion barrels of residual petroleum may reside in the 

Aux Vases Sandstone and other porous rocks, which may 

have acted in part as a porous carrier bed for lateral 

migration. It becomes apparent from this type of assessment that additional research on delineating migration 

pathways and understanding fluid flow from source rocks 

to traps is essential. 

Petroleum material-balance assessments of established petroleum basins are feasible. Critical to this 

method is accurate determinations of petroleum charge 

from a source rock, discovered in-place petroleum, and 

petroleum losses due to migration, leakage, and erosion. 

Although this material balance yields reasonable values, 

the uncertainty in assumptions and variability in values 

make it too equivocal at this time to determine the precise 

amount of petroleum remaining to be discovered. This feasibility study yields a broad range of -37 to 144 billion 

barrels of petroleum from the New Albany Shale that 

remain to be discovered in conventional or unconventional accumulations of the Illinois Basin. The -37 billion 

barrels indicates that possibly no more undiscovered petroleum remains to be found or that the amounts of accountable petroleum loss to carrier beds or erosion are 

overstated. The 144 billion barrels indicates that possibly 

the expulsion factors or the steady-state model for organic 

richness for the source rocks in the mature part of the 

basin are overstated. Although this range is broad, it does 

encompass and does not completely exceed the range of 

accountable petroleum within the basin. As further data 

and research refine this type of assessment, this broad 

range of undiscovered petroleum is expected to narrow 

and provide a more precise upper limit to statistical-analog 

assessments currently employed. In addition, the quantitative understanding gained by material-balance assessments of established petroleum basins will provide a 

more scientific method for assessing petroleum in frontier 

basins on a global scale. 

ACKNOWLEDGMENTS 

This study was conducted as part of the 1995 National 

Assessment of United States Oil and Gas Resources by the 

U.S. Geological Survey under the direction of Donald 

Gautier. The timely completion of this study was made possible by the rapid and dedicated response of the Illinois State 

Geological Survey, Indiana Geological Survey, and Kentucky Geological Survey to the U.S. Geological Survey's 

request to conduct a material-balance feasibility study on the 

Illinois Basin. The authors appreciate the efforts of Illinois 

State Geological Survey in hosting the initial meeting that 

deliberated on the undertaking of this study in April 1994. 

The authors also appreciate the efforts of the Indiana Geological Survey in organizing field work for sample collection 

in October 1994, which was the actual start of this study. 

Lisa Pratt at Indiana University is also appreciated for 

encouraging her Ph.D. candidate, John Guthrie, to take time 

away from his dissertation to assist in the hydrous-pyrolysis 

experiments used in this study. The authors acknowledge 

and appreciate the efforts of Ted Daws in conducting RockEva! pyrolysis on the samples used in this study and Paul N. 

Irwin (Indiana Geological Survey) in computing the surface 

areas and volumes of source rocks used in this study. Barbara T. Hill and John Day in the photographic section and 

Roger Purcell and Kimberly Sowder in the technology transfer section of the Indiana Geological Survey are also 

acknowledged for their preparation of figures for this study. 

Critical reviews of this study by John M. Hunt (Woods Hole 

Oceanographic Institution), Joel Leventhal, Richard Mast, 

Leigh Price, Katherine V ames, and David Morse (Illinois 

State Geological Survey) provided helpful suggestions and 

comments that enhanced the clarity and content of the final 

manuscript. This publication, with its various data sets and 

convoluted text covering a wide range of concepts and computations, greatly benefited in clarity, organization, and 

quality from the thorough editing by Richard Scott. Lastly, 

the authors acknowledge the dedicated efforts of M.H. Barrows, R.M. Cluff, J.A. Lineback, R.F. Mast, M.C. Noger, 

and D.H. Swann in providing the geological framework that 

made this study possible. 

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Graphics prepared by the Indiana Geological Survey 

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