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| Open-File Series 03-037: 508 Document |
The New
Albany Shale Petroleum System, Illinois Basin - Data and Map
Image
Archive from the Material-Balance Assessment
D.K.
Higley, M.E. Henry, M.D. Lewan, and J.K. Pitman
2003
. .
This
report is preliminary and has not been reviewed for conformity
with
U.S. Geological Survey editorial standards or with the North
American
Stratigraphic Code.
Any use
of trade, firm, or product names is for descriptive purposes
only
and does not imply endorsement by the U.S. Government
Open-File
Report 2003-03-037
U.S.
Department of the Interior
U.S.
Geological Survey
++++++++++++++++++++++++++++++++++++++++++++++
U.S.
Department of the Interior
U.S.
Geological Survey Open-File 03-037
THE NEW
ALBANY SHALE PETROLEUM SYSTEM, ILLINOIS BASIN - DATA AND MAP
IMAGE
ARCHIVE FROM THE MATERIAL-BALANCE ASSESSMENT
D.K.
Higley, M.E. Henry, M.D. Lewan, and J.K. Pitman
TABLE
OF CONTENTS
README
FILE
DATA
FILES README AND EXAMPLES
ABSTRACT
INTRODUCTION
DISTRIBUTION
OF OIL, GAS, AND NON-PRODUCTIVE WELLS
*
Petroleum Production in the Basin
*
Distribution of Oil, Gas, and Non-productive Wells
METHODS
AND RESULTS
*
Source-Rock Characterization
*
Estimated Amounts of Generated and Produced Oil, Known Petroleum
Volume
of Oil, and Original-Oil-In-Place
*
Estimates of Losses from Carrier Beds
*
Factors That Influence/Control Estimation Of Hydrocarbon Resources
CONCLUSIONS
SELECTED
REFERENCES
ACKNOWLEDGEMENTS
GLOSSARY
APPENDICES
*
Appendix 1, A database that contains median porosity and permeability
information
from core samples (Appendix 1, located in data/
fileform/porperm.xls)
that was created from analyses supplied by the
Illinois
State and Indiana Geological Surveys. File names are
porperm.xls,
porperm.csv, and porperm.prn.
*
Appendix 2. Maps in this report are
based primarily on results from
Rock-Eval
pyrolysis of 475 samples from 262 locations across the
Illinois
Basin. Multiple samples from the same location were averaged.
Data
files that list HI, TOC, well location, and other information are
located
in the data subdirectory. The files are stored in Microsoft
EXCEL
(HI_TOC.xls), comma-delimited (HI_TOC.csv), and space-delimited
(HI_TOC.prn)
formats. Fileform.htm contains an
example and explanation
of data
and methods.
LIST OF
FIGURES
Figure
1. Index map of major structural features in the eastern mid-
continent
of the United States (Modified from Buschbach and Kolata,
1991,
reprinted by permission of the American Association of Petroleum
Geologists
and AAPG Data Systems (Datapages, Inc.), whose permission is
required
for further use). Green dashed line is generalized outline of
the
Illinois Basin. The large 31 KB image is named indexmp.jpg .
Figure
2. Major structural features of the Illinois Basin and bounding
areas.
Shown are major fault systems, anticlines, synclines,
monoclines,
and crypto explosive or impact structures in the region
(modified
from Buschbach and Kolata, 1991; Treworgy, 1981, reprinted by
permission
of The American Association of Petroleum Geologists and AAPG
Data
Systems (Datapages, Inc.), whose permission is required for
further
use). The large 90KB image is named bstruct.jpg .
Figure
3. Chart showing times of structural activity in the Illinois
Basin
area. Illustrated are major structural events in the region and
plate
tectonic movement across the world. These are plotted on a
numerical
time scale from the COSUNA chart that was modified by Shaver
and others
(1985). Diagram is modified from Kolata and Nelson (1991,
reprinted
by permission of The American Association of Petroleum
Geologists
and AAPG Data Systems (Datapages, Inc.), whose permission is
required
for further use). The large 30 KB image is named agestru.jpg .
Figure
4. Distribution of oil and gas wells from Silurian- through
Pennsylvanian-
age reservoirs in the Illinois Basin; approximate basin
outline
is marked by a thick orange line. The thin red line shows
region
of thermally mature source rocks. Major structural features are
labeled;
fault names are black text while blue text marks arches,
monoclines,
synclines, and domes. Catchment 1 is labeled and catchments
2
through 7 are located clockwise and sequentially from 1. Faint purple
lines
segregate each catchment. The irregular
blue line outlines
maximum
subsurface and surface extent of Chesterian-age formations. The
large
151 KB image is named oilstruc.jpg . The small-scale image
without
the labeled structures is named allprod.jpg .
Figure
5. Decreasing hydrogen index (HI) contours show regions of
increasing
thermal maturity of New Albany Shale source rocks within the
Illinois
Basin. Contour interval is 50 HI. The 400 HI contour (red
line)
outlines the area of source rocks that are thermally mature for
oil
generation. Catchments are labeled clockwise from 1 to 7. Irregular
dark-green
line outlines the maximum extent of the New Albany Shale
(modified
from Lewan and others, 1995, 2002). Large scale 112 KB image
is
named contorhi.jpg .
Figure
6 a through g. Below are a series of 3-D images of hydrogen
indices
(HI) values cut by structure on the top of the New Albany
Shale.
HI contours show location of the generative basin as outlined by
a HI of
400. Major fault traces are shown in red on some views.
Vertical
displacement by the faults is illustrated in shades of gray.
Vertical
exaggeration is 20 times. "LS" marks the La Salle anticlinal
belt
and "RC" labels the Rough Creek fault zone on some images.
Included
are north arrows and azimuth relative to north (degrees), and
inclination
relative to a horizontal plane (degrees). Small-size images
are 28
to 53 KB, and the enlarged images are 91 to 224 KB.
Figure
7. Generalized stratigraphic column of Devonian and
Mississippian
strata in the southern part of the Illinois Basin.
Horizontal
red lines to the right of the column indicate the primary
oil and
gas productive intervals. Shown are names and vertical and
lateral
associations of strata from Late Devonian to Late Mississippian
time.
The New Albany Shale hydrocarbon source rock is also labeled
(Modified
from Bell and others, 1961; Buschbach and Kolata, 1991,
reprinted
by permission of The American Association of Petroleum
Geologists
and AAPG Data Systems (Datapages, Inc.), whose permission is
required
for further use). The large 19 KB image is named stratsec.jpg.
Figure
8. This generalized southwest-northeast stratigraphic cross
section
of the Middle Devonian through Mississippian Kaskaskia sequence
shows
vertical and lateral extent of primary hydrocarbon source rock
and
reservoir rocks in the Illinois Basin (modified from Treworgy and
Devera,
1991, reprinted by permission of The American Association of
Petroleum
Geologists and AAPG Data Systems (Datapages, Inc.), whose
permission
is required for further use). This is a 20 KB image named
devmisxs.jpg
.
Figure
9. Distribution of more than 4,700 wells with petroleum
production
from Pennsylvanian-age reservoirs in the Illinois Basin.
Catchment
1 is labeled and catchments 2 through 7 are located clockwise
and
sequentially from 1. Purple lines segregate each catchment. An
irregular
dark-reddish-brown line outlines the maximum extent of
Pennsylvanian-age
formations. Well location data were derived from
PI/Dwights
Well History Control System database (1996).
The large 104
KB
image is named pennprod.jpg.
Figure
10. Shown are greater than 2,000 dry holes that reach total
depth
within Pennsylvanian-age formations. Catchment 1 is labeled and
catchments
2 through 7 are located clockwise and sequentially from 1.
Purple
lines segregate each catchment. An
irregular dark-reddish-brown
line
outlines the maximum extent of Pennsylvanian-age formations. Well
location
data were derived from PI/Dwights Well History Control System
database
(1996). The large 104KB image is called
penndry.jpg.
Figure
11. Shown are more than 38,000 dry holes that reach total depth
within
Mississippian-age or older formations. Catchment 1 is labeled
and
catchments 2 through 7 are located clockwise and sequentially from
1.
Purple lines segregate each catchment.
Subsurface or surface extent
of
Chesterian-age formations is outlined by the irregular blue line.
Well
location data were derived from PI/Dwights Well History Control
System
database (1996). The large 104KB image
is called missdry.jpg .
Figure
12. Chesterian regressive depositional cycle is modified from
Pryor
and others (1991, reprinted by permission of The American
Association
of Petroleum Geologists and AAPG Data Systems (Datapages,
Inc.),
whose permission is required for further use). Shown are
spontaneous
potential (SP) and resistivity well-log signatures,
lithology,
and depositional systems for an idealized shoaling-upward
regressive
system; most cycles are bounded by disconformities (shown by
wavy
horizontal lines). The large 16 KB image is named chesdep.jpg.
Figure
13. This Valmeyeran regressive depositional cycle is modified
from
Pryor and others (1991, reprinted by permission of The American
Association
of Petroleum Geologists and AAPG Data Systems (Datapages,
Inc.),
whose permission is required for further use). Shown are
spontaneous
potential (SP) and resistivity well-log signatures,
lithology,
and depositional systems for an idealized upward-shoaling
regressive
carbonate cycle. The large 36 KB image is named valmdep.jpg.
Figure
14. Distribution of petroleum production from Chesterian-age
reservoirs
in the Illinois Basin. Shown are more than 13,000 oil and
600 gas
wells. Catchment 1 is labeled and catchments 2 through 7 are
located
clockwise and sequentially from 1. Purple lines segregate each
catchment. The irregular blue line outlines the maximum
extent of
Chesterian-age
formations. Well location data were derived from
PI/Dwights
Well History Control System database (1996).
The large 112
KB
image is named chesprod.jpg.
Figure
15. This map shows wells that produce
from units within the
Mississippian
Valmeyeran Series. The catchments 1 through 7 are
labeled.
Purple lines segregate each catchment.
The irregular dark-
green
line outlines the maximum extent of Valmeyeran-age formations.
Primary
producing formations are Ste. Genevieve, Salem, and Aux Vases.
There
are more than 12,000 oil wells (green) and 400 gas wells (red).
Well
location data were derived from PI/Dwights Well History Control
System
database (1996). The large 107KB image
is named valmprod.jpg .
Figure
16. Distribution of oil and gas wells from Silurian- and
Devonian-age
formations. Shown are more than 2,700 oil and 100 gas
wells.
Catchment 1 is labeled and catchments 2 through 7 are located
clockwise
and sequentially from 1. Purple lines segregate each
catchment. Well location data were derived from
PI/Dwights Well
History
Control System database (1996). The
large 93KB image is named
sildprod.jpg.
Figure
17. Thickness of source-rock-quality New Albany Shale across the
generative
basin, Illinois Basin. Isopach interval is 20 ft (6 m).
Greatest
thickness of source rocks is the red "bulls eye" located near
the
intersection of Illinois, Indiana, and Kentucky. This area is east
of the
basin axis, and directly east of the "bulls eye" of greatest
maturation
level. Catchment 1 is labeled and catchments 2 through 7 are
located
clockwise and sequentially from 1. Purple lines segregate each
catchment. Maximum extent of the New Albany Shale is
shown by the dark
green
line (modified from Lewan and others, 1995). Large-scale 122 KB
image
is named srthick.jpg.
Figure
18. Isopach map of the Selmier Member of the New Albany Shale.
Contour
interval is 10 ft. (3.0 m). Catchment 1 is labeled and
catchments
2 through 7 are located clockwise and sequentially from 1.
Purple
lines segregate each catchment. Maximum
extent of the New
Albany
Shale is shown by the dark green line (modified from Lewan and
others,
1995). The large 141 KB image is named selmiso.jpg.
Figure
19. Percent thickness of the Selmier Member of the New Albany
Shale
that exhibits gamma signatures of 120 API units or greater.
Contour
interval is 20%. Red line outlines the generative basin.
Catchment
1 is labeled and catchments 2 through 7 are located clockwise
and
sequentially from 1. Purple lines segregate each catchment. Basin
axis is
the purple line that separates catchments a) 2 and 7, b) 3 and
6, and
c) 4 and 5. Greatest percentage of source-rock quality shales
(thickest
intervals of high gamma signature) are along the basin axis.
Maximum
extent of the New Albany Shale is the dark green line (modified
from
Lewan and others, 1995). Sample
locations are small inverted
triangles.
These are more readily viewed on the large 131 KB
selmhga.jpg
image.
TABLES
Table
1. Estimated amounts of hydrocarbons that have been generated and
produced
from the New Albany Shale petroleum system in the Illinois
Basin.
Shown are estimated volumes of hydrocarbons both within the area
of
mature source rocks and outside this boundary. The thermally mature
region
is defined by a hydrogen index (HI) value of 400. Included are
estimates
of cumulative production and known petroleum volume of oil,
and
original-oil-in-place (OOIP). The known
petroleum volume of oil is
36.22%
of the OOIP of 11.45 BBO (billion barrels of oil). [If your view
does
not read the HTML v. 3 format, the file is also saved as comma-
delimited
( ooipnum.csv), text ( ooipnum.txt), and EXCEL v 4.0 (
ooipnum.xls)
formats.]
Table
2. Catchment number (CN), cumulative production (CUM) and known
petroleum
volume of oil (K VOL), and original oil in place (OOIP)
values
for the New Albany Shale petroleum system.
Volumes are millions
of
barrels of oil (MMBO).
"Within" and "outside" refer to location of
produced,
in-place, and (or) recoverable oil within or outside the 400
HI
contour that encloses thermally mature source rocks. The final
column
shows the percent of oil production within the hydrocarbon
generative
area of the Illinois Basin. [If your Web browser cannot view
the
below table, it is also saved as comma-delimited ( oilprod.csv) and
Microsoft
EXCEL v. 5.0 ( oilprod.xls) files. The external HTML table is
named
oilprod.htm .]
ABSTRACT
The
data files and explanations presented in this report were used to
generate
published material-balance approach estimates of amounts of
petroleum
1) expelled from a source rock, and the sum of 2) petroleum
discovered
in-place plus that lost due to 3) secondary migration
within,
or leakage or erosion from a petroleum system. This study
includes
assessment of cumulative production, known petroleum volume,
and
original oil in place for hydrocarbons that were generated from the
New
Albany Shale source rocks. More than
4.00 billion barrels of oil
(BBO)
have been produced from Pennsylvanian-, Mississippian-, Devonian-
, and
Silurian-age reservoirs in the New Albany Shale petroleum system.
Known
petroleum volume is 4.16 BBO; the average recovery factor is
103.9%
of the current cumulative production. Known petroleum volume of
oil is
36.22% of the total original oil in place of 11.45 BBO. More
than
140.4 BBO have been generated from the Upper Devonian and Lower
Mississippian
New Albany Shale in the Illinois Basin. Approximately
86.29
billion barrels of oil that was trapped south of the Cottage
Grove
fault system were lost by erosion of reservoir intervals. The
remaining
54.15 BBO are 21% of the hydrocarbons that were generated in
the
basin and are accounted for using production data.
Included
in this publication are 2D maps that show the distribution of
production
for different formations versus the Rock-Eval pyrolysis
hydrogen-indices
(HI) contours, and 3D images that show the close
association
between burial depth and HI values. The
primary vertical
migration
pathway of oil and gas was through faults and fractures into
overlying
reservoir strata. About 66% of the produced oil is located
within
the generative basin, which is outlined by an HI contour of 400.
The
remaining production is concentrated within 30 miles (50 km)
outside
the 400 HI contour. The generative basin is subdivided by
contours
of progressively lower hydrogen indices that represent
increased
levels of thermal maturity and generative capacity of New
Albany
Shale source rocks. The generative basin was also divided into
seven
oil-migration catchments. The catchments were determined using a
surface-flow
hydrologic model with contoured HI values as input to the
model.
INTRODUCTION
In the
1990's the material-balance approach to assessing petroleum
resources
was tested with a study of the New Albany Shale petroleum
system
in the Illinois Basin. An initial
publication entitled
"Feasibility
Study of Material-Balance Assessment of Petroleum from the
New
Albany Shale in the Illinois Basin" by Lewan and others, USGS
Bulletin
2137, 1995, indicated that this was a promising method of
assessing
oil and gas resources, and outlined the methodology. A
second,
"Material-balance assessment of the New Albany Shale-Chesterian
petroleum
system of the Illinois Basin" by Lewan and others, 2002, was
published
in the AAPG bulletin series and details the geology, methods
of
geochemical analysis, and results of the study. This open file
report
details the evaluation of the distribution and volumes of
produced
oil and gas, and includes maps and raw geochemical and other
data
that were used to generate but were not included in previous
papers. The New Albany is assigned group rank in
Illinois; in Indiana
and
western Kentucky the New Albany is a formation-rank unit. In this
report,
the name "New Albany Shale" will be used throughout the
Illinois
Basin. Highlighted text and graphics
are links to figures and
large-size
images in which the sizes are approximately 16 by 16 inches
and
scales are 1:1,000,000. They may also
be links to the glossary;
most of
the definitions are derived from the Dictionary of Geological
Terms,
1984, Higley and others, 1997, and Klett and others, 2000.
The
Illinois Basin is located in southwestern Indiana, western
Kentucky,
and all but northernmost Illinois. Major structural features
in the
basin and bounding areas are shown on figures 1 and 2. Times of
structural
activity are illustrated on figure 3. Petroleum production
is
concentrated along many of the major faults and other structures.
About
42% of the almost 90,000 holes drilled are oil and (or) gas
productive.
Mississippian reservoirs provide 70% of the producing wells
in the
basin, which are equally split between Chesterian- and
Valmeyeran-age
formations. Approximately 60% of oil produced from the
basin
is from Chesterian reservoirs (Howard, 1991). Additional
production
is primarily from Valmeyeran (greater than 20%),
Pennsylvanian
(13%), and Silurian and Devonian (7%) reservoirs (Howard,
1991).
A simplifying aspect of the New Albany Shale petroleum system is
that
almost all reported production is oil. Average gas to oil ratio
for the
Mississippian and Pennsylvanian producing formations is 750
cubic
feet of gas per barrel (CFG/BBL) (Macke, 1996).
About
66% of the produced oil occurs within the area of thermally-
mature
New Albany Shale source rocks, which suggests the primary
hydrocarbon
migration direction was upwards through faults and
fractures
into overlying reservoir strata. Geochemical analyses of oil-
field
brines across the Illinois Basin indicate short migration
distances
(Abrams 1995) for these hydrocarbons that are probably
sourced
from the New Albany Shale; brines typically exhibit ionic
composition
of the (probable in-situ) seawater with ionic
concentrations
of as much as 5 times seawater. Long-range migration of
formation
fluids generally dilutes connate water. Abrams further
postulates
that density drive due to buoyancy was the primary mechanism
of oil
migration. The influence of lateral migration through porous
carrier
beds may be important in large oil fields such as Louden and
Main
Consolidated that lie near or outside the limit of mature source
rocks
in the Illinois Basin. The Fairfield Subbasin (Figure 1), within
the
Illinois Basin, contains most of the oil produced in the New Albany
Shale
petroleum system. Bordering the Fairfield Subbasin are the
primary
barriers and conduits to lateral migration of hydrocarbons
(Figure
2); structures listed below also define some of the boundaries
of
catchments in the basin that influence hydrocarbon migration
pathways
and traps.
1. The
Rough Creek -Shawneetown fault system, near the southern
boundary
of the basin, is the northern boundary of the Rough Creek
graben.
This east-west trending fault system is a probable barrier to
migration
of hydrocarbons and is located just east of the Cottage Grove
fault
system.
2. The
Cottage Grove fault system is a series of right-lateral wrench
faults
(Nelson and Lumm, 1985) that mark the southern limit of
significant
oil and gas production in the western half of the basin.
Approximately
98% of reported oil and gas production is located north
of this
fault system, based on analysis of production data from Nehring
(1996),
and PI/Dwights Production Data on CD-ROM (1996).
3. The
La Salle anticlinal belt is a primary barrier to eastward
migration
of hydrocarbons. This belt forms the northeast boundary of
the
Fairfield Subbasin and consists of sub-parallel north-south
trending
anticlines.
4. The
Wabash Valley fault system is located south of the La Salle
anticlinal
belt, along the Illinois/Indiana state line. This system was
an
important vertical and north-south oil migration corridor.
Hydrocarbons
accumulated in reservoir rocks adjacent to or between
faults,
and in upthrown blocks. In Indiana, oil commonly occurs within
the
fault system. Figure 4 and the
detailed allprod.jpg map show oil
and gas
wells near this and the other structural features that outline
the
hydrocarbon generative area of the basin.
5.
Westward migration of hydrocarbons was slowed by the Louden and
Salem
anticlines and by the Du Quoin monocline. This monocline dips
steeply
to the east and forms the western edge of the Fairfield
Subbasin.
The faulted monocline near the western terminus of the
Cottage
Grove system appears to have focused oil migration northward.
The two
largest fields in the basin are located on the Salem and Louden
anticlines,
which are north of and approximately on strike with the Du
Quoin
monocline. Seismic data revealed that the Louden anticline is
faulted
on both flanks and that these faults may extend to the basement
(Nelson,
1991). Only minor amounts of oil exist in Mississippian
reservoirs
west of the monocline suggesting that faults and other
structural
features served as barriers to westward migration.
Figure
1. Index map of major structural features in the eastern mid-
continent
of the United States (Modified from Buschbach and Kolata,
1991,
reprinted by permission of the American Association of Petroleum
Geologists
and AAPG Data Systems (Datapages, Inc.), whose permission is
required
for further use). Green dashed line is generalized outline of
the
Illinois Basin. The large 31 KB image is named indexmp.jpg .
Figure
2. Major structural features of the Illinois Basin and bounding
areas.
Shown are major fault systems, anticlines, synclines,
monoclines,
and crypto explosive or impact structures in the region
(modified
from Buschbach and Kolata, 1991; Treworgy, 1981, reprinted by
permission
of The American Association of Petroleum Geologists and AAPG
Data
Systems (Datapages, Inc.), whose permission is required for
further
use). The large 90KB image is named bstruct.jpg .
Figure
3. Chart showing times of structural activity in the Illinois
Basin
area. Illustrated are major structural events in the region and
plate
tectonic movement across the world. These are plotted on a
numerical
time scale from the COSUNA chart that was modified by Shaver
and
others (1985). Diagram is modified from Kolata and Nelson (1991,
reprinted
by permission of The American Association of Petroleum
Geologists
and AAPG Data Systems (Datapages, Inc.), whose permission is
required
for further use). The large 30 KB image is named agestru.jpg .
Figure
4. Distribution of oil and gas wells from Silurian- through
Pennsylvanian-
age reservoirs in the Illinois Basin; approximate basin
outline
is marked by a thick orange line. The thin red line shows
region
of thermally mature source rocks. Major structural features are
labeled;
fault names are black text while blue text marks arches,
monoclines,
synclines, and domes. Catchment 1 is labeled and catchments
2
through 7 are located clockwise and sequentially from 1. Faint purple
lines
segregate each catchment. The irregular
blue line outlines
maximum
subsurface and surface extent of Chesterian-age formations. The
large
151 KB image is named oilstruc.jpg . The small-scale image
without
the labeled structures is named allprod.jpg .
The New
Albany Shale was deposited as brownish-black laminated shales
in a
marine, stratified anoxic basin; primary environments were
transitional
shelf, slope, and basin (Cluff and others, 1981). Time
span of
New Albany Shale deposition to possible completion of
hydrocarbon
migration is Late Devonian through Late Jurassic, about 225
m.y.
Hydrocarbon expulsion in southern Illinois began during the Middle
Pennsylvanian
and reached its peak in Late Pennsylvanian to Early
Permian
time (Cluff and Byrnes, 1991). Extensive folding and faulting
coincident
with this event created many of the major structural traps
in the
basin (Figure 3). A late stage of
hydrocarbon migration
probably
occurred during tectonic activity after maximum burial depth
(post-Early
Permian) (Figure 3) (Lewan and others, 2002); however this
was
minimal as indicated by the fact that about 66% of petroleum
production
is from within the generative basin, and only 2% of
hydrocarbon
production is from south of the Cottage Grove and Rough
Creek-Shawneetown
fault systems.
Bethke
and others (1991) state that migration of hydrocarbons into
traps
began during Early Cretaceous time (100 Ma).
Bethke and others
(1991)
suggest that long-range, northward, migration of hydrocarbons
(100 km
(62 mi.) or more) resulted from uplift during Mesozoic time of
the
Pascola Arch, located along the southern boundary of the Illinois
Basin.
They further postulate that oil generated from the Devonian and
Mississippian
New Albany Shale migrated through underlying Devonian and
Silurian
carbonates along a karstified surface of a regional
unconformity.
They doubt the oil migrated over long distances along
faults;
they indicate the central basin contains few fault systems, and
none
are believed oriented along their inferred migration routes.
Primary
migration mechanisms were attributed to hydrodynamic flow and
buoyancy.
Fluid expulsion is also associated with sediment compaction.
Emplacement
of hydrocarbons was influenced by their vertical migration
along
fault systems, combined with potential sealing effects of some
faults
and associated structures. Results of this migration include
vertical
expansion of the petroleum system into overlying younger
formations,
and limiting the lateral migration and extent of oil and
gas by
sealing faults and low-permeability formations. Erosional
removal
of potential reservoir units was particularly widespread south
of the
Cottage Grove fault system (Figure 4). During this time an
estimated
1-3 km (0.6 to 2 mi.) of section in southern Illinois was
removed
(Cluff and Byrnes, 1991; Damberger, 1971). This was determined
based
on extrapolation of trends in thicknesses of Paleozoic strata
across
the basin, and by anomalous values of thermal maturity in near-
surface
coal beds.
The New
Albany Shale petroleum system was divided into seven migration
drainage
areas, or catchments. Petroleum charge, losses, and in-place
resources
were evaluated separately for each catchment, both within and
outside
the generative basin. Catchments and hydrocarbon migration
pathways
were determined using surface hydrologic modeling utilities in
the
Arc/Info geographic information systems (GIS) software mapping
program
(Environmental System Research Institute, Inc., 1997). Because
decrease
in hydrogen index (HI) values is associated with an increase
in
thermal maturity, the HI contour map resembles a depression. In
order
to model movement of hydrocarbons under buoyant forces by using
hydrologic
flow modeling software, the model must be inverted. The HI
values
for each of the 262 locations were multiplied by minus one.
These
negative HI values were then used as input to the watershed
modeling
utility in the Arc/Info program. Regions of source rocks that
are
thermally mature for oil generation are defined by a 400 HI contour
(Figure
5); this is also the limiting polygon for calculation of
amounts
of generated hydrocarbons. HI values within the thermally
mature
portion of the basin range from 10 to 400 mg/g TOC (Appendix 2,
HI_TOC.xls). The study area was initially divided into 21
drainage
regions,
or catchments. These were condensed into seven catchments by
combining
drainage areas that had ambiguous boundaries. Petroleum
production
data was calculated using these 21 catchments, and the data
were
merged into the final 7 catchments. Boundaries between catchments
were
extended to the New Albany Shale subcrop/outcrop by drawing
perpendicular
lines outward from the 400 HI contour.
The 400
HI contour generally follows the structure of the Fairfield
Subbasin.
The 100 HI contour outlines an area of higher thermal
maturity
in southern Illinois. Maximum lateral
movement along the
Cottage
Grove fault systems is less than one mile (Nelson and Krausse,
1981)
and is not associated with noticeable displacement of HI
contours.
The
regions of the Illinois Basin that are thermally mature for oil and
gas
that was sourced from the New Albany Shale are shown on figures 5
and 6
a-g. Figures 6a through 6g are 3-D images of hydrogen indices
contoured
across the basin; these HI contours are draped on the top of
the New
Albany Shale to better show the association between HI and the
basin
structure. Surfaces are offset by movement along major fault
systems.
Maps are based primarily on results from Rock-Eval pyrolysis
of 475
samples from 262 locations across the Illinois Basin. Multiple
samples
from the same location were averaged. The thermally mature area
includes
the Fairfield Subbasin (400 HI red contour) (Figure 4).
Contoured
values greater than 400 HI are not displayed; these areas are
thermally
immature for oil generation. Data files that list HI, TOC,
well
location, and other information are located in the data
subdirectory.
The files are stored in Microsoft EXCEL ( HI_TOC.xls),
comma-delimited
( HI_TOC.csv), and space-delimited (HI_TOC.prn, .txt)
formats. Fileform.htm contains an example and
explanation of data and
methods.
The
following are factors that influenced the generation and migration
of
hydrocarbons from the New Albany Shale and were used in our
analyses:
1.
Thermal maturity is primarily a measure of burial depth at the time
of
hydrocarbon generation and expulsion.
2.
Petroleum migrates vertically under buoyant forces. Permeability
barriers
mainly deflect the movement laterally, but in an up-dip
direction.
3.
General features of petroleum migration were modeled using a
structure
contour map of elevation of the top of the New Albany Shale.
This
structure was used as input to a hydrologic flow modeling computer
program
that was modified to account for flow behavior of hydrocarbons.
4. The
basin configuration is such that impermeable layers that are
encountered
by migrating hydrocarbons will have similar geometry to the
top of
the New Albany Shale.
5.
Existing pathways, such as faults and fractures, allowed for mostly
vertical
migration of hydrocarbons from the New Albany Shale into
overlying
porous and permeable reservoirs. Vertical barriers were
hundreds
of feet of generally dense limestone and lesser amounts of
shales
of the Chesterian and Valmeyeran Series (Figures 7, 8).
Vertical
relationship of New Albany Shale to primary reservoir
intervals
is shown on the stratigraphic column of Devonian and
Mississippian
strata in the southern part of the Illinois Basin (Figure
7).
Formations that are oil productive are marked by horizontal red
lines. Figure 8 is a generalized stratigraphic
cross section of this
time
interval. Also shown is the extent of Chesterian and Valmeyeran
Series
across the basin. Regressive depositional cycles for the
Chesterian
and Valmeyeran Series were tied to well-log signatures and
lithologic
descriptions (Treworgy and Devera, 1991).
Figure 5. Decreasing hydrogen index (HI)
contours show regions of
increasing
thermal maturity of New Albany Shale source rocks within the
Illinois
Basin. Contour interval is 50 HI. The 400 HI contour (red
line)
outlines the area of source rocks that are thermally mature for
oil
generation. Catchments are labeled clockwise from 1 to 7. Irregular
dark-green
line outlines the maximum extent of the New Albany Shale
(modified
from Lewan and others, 1995, 2002). Large scale 112 KB image
is
named contorhi.jpg .
Figure
6 a through g. Below are a series of 3-D images of hydrogen
indices
(HI) values cut by structure on the top of the New Albany
Shale.
HI contours show location of the generative basin as outlined by
a HI of
400. Major fault traces are shown in red on some views.
Vertical
displacement by the faults is illustrated in shades of gray.
Vertical
exaggeration is 20 times. "LS" marks the La Salle anticlinal
belt
and "RC" labels the Rough Creek fault zone on some images.
Included
are north arrows and azimuth relative to north (degrees), and
inclination
relative to a horizontal plane (degrees). Small-size images
are 28
to 53 KB, and the enlarged images are 91 to 224 KB.
Figure
6a. nalb115.jpg
Figure
6b. nalb111.jpg
Figure
6c. nalb110.jpg
Figure
6d. nalb112.jpg
Figure
6e. nalb116.jpg
Figure
6f. nalb114.jpg
Figure
6g. nalb113.jpg
Figure
7. Generalized stratigraphic column of Devonian and
Mississippian
strata in the southern part of the Illinois Basin.
Horizontal
red lines to the right of the column indicate the primary
oil and
gas productive intervals. Shown are names and vertical and
lateral
associations of strata from Late Devonian to Late Mississippian
time.
The New Albany Shale hydrocarbon source rock is also labeled
(Modified
from Bell and others, 1961; Buschbach and Kolata, 1991,
reprinted
by permission of The American Association of Petroleum
Geologists
and AAPG Data Systems (Datapages, Inc.), whose permission is
required
for further use). The large 19 KB image is named stratsec.jpg.
Figure
8. This generalized southwest-northeast stratigraphic cross
section
of the Middle Devonian through Mississippian Kaskaskia sequence
shows
vertical and lateral extent of primary hydrocarbon source rock
and
reservoir rocks in the Illinois Basin (modified from Treworgy and
Devera,
1991, reprinted by permission of The American Association of
Petroleum
Geologists and AAPG Data Systems (Datapages, Inc.), whose
permission
is required for further use). This is a 20 KB image named
devmisxs.jpg
.
DISTRIBUTION
OF OIL, GAS, AND NON-PRODUCTIVE WELLS
Petroleum
Production in the Basin
The
Clark County Division field was drilled in the Illinois Basin in
1900;
this is the first field that contains discovery date information
for the
PI/Dwights WHCS (1996) and Production Data on CD-ROM (1999) and
Nehring
databases (1996). Average discovery
date is 1946 for 320
fields
in the databases that contain this information. The Illinois
Basin
has a mature exploration status. Macke (1996) estimated that 10
or
fewer oil accumulations of 1 million barrels or greater remain to be
discovered
in Mississippian and Pennsylvanian formations in the basin
and
that remaining reserve growth will mainly result from secondary and
tertiary
methods of petroleum production from existing fields. The
basin
contains more than sixty different petroleum pay intervals that
range
in age from Ordovician to Pennsylvanian; production is primarily
from
structural traps at depths of less than 5,500 ft (1,675 m) (Howard
and
Whitaker, 1990). "A number of hydrocarbon occurrences are closely
related
to the tops of three major carbonate intervals"; these are
listed
by Howard (1991) as being the Upper Ordovician Ottowa
Supergroup,
the Silurian and Devonian Hunton Supergroup, and the
Mississippian
Valmeyeran Series. Most hydrocarbon production in the
basin
has been from siliciclastic intervals in Chesterian and
Pennsylvanian
rocks (Howard, 1991). Oltz and others (1991) determined
that
the Illinois Basin has almost 1,700 fields; these produce mainly
oil
from about 7,000 separate sandstone and carbonate reservoirs.
Ninety-six
percent of this production is stripper, or less than 10
BO/day per
well; this percentage is six times greater than the national
average
for stripper production (Oltz and others, 1991). Organic
geochemical
correlations indicate that more than 99% of discovered
petroleum
in the basin was derived from the New Albany Shale (Hatch and
others,
1991).
Almost
90,000 wells have been drilled in the Illinois Basin; 42%, or
about
38,000 wells, are currently listed as oil and (or) gas productive
(PI/Dwights
WHCS data through Dec, 1996). Total number of dry holes
across
the basin is 47,800 (PI/Dwights WHCS database through 1996).
Figure
4 shows distribution of oil and gas wells across the basin.
Production
is from Silurian-through Pennsylvanian-age reservoirs.
Distribution
of Oil, Gas, and Non-Productive Wells
The
following maps show areal distribution of oil and gas wells and dry
holes
(non-productive wells) in the Illinois Basin. The primary source
of well
data for the well distribution figures is the PI/Dwights Well
History
Control System data through 1996. The smooth solid red line on
figures
is the 400 HI contour; this outlines the hydrocarbon generative
area of
the New Albany Shale as defined by a hydrocarbon index value of
400.
Purple lines within the generative basin segment the seven
catchments;
perpendiculars are extended to the boundaries of the
formation
or basin. Labeled outcrop/subcrop extents are generalized in
areas,
particularly south of the Rough Creek and Cottage Grove fault
systems
and along the southwestern border of the basin.
Numerous
wells produce from several different age and (or) formation
intervals
and production is commingled; allocation of percentages of
total
production can therefore be somewhat misleading. This can result
in
over- or under-reporting of production data. Production from
Pennsylvanian-age
formations is illustrated on figure 9.
Approximately
13% of
basin production is from Pennsylvanian-age reservoirs according
to
Howard (1991). More than 4,700 mostly
oil wells produce from
Pennsylvanian
formations; this is 7.8% of total oil and gas wells in
the
basin (PI/Dwights WHCS data, 1996).
Seventy-five percent of
Pennsylvanian
production is concentrated along the north-south trending
La
Salle anticlinal belt (Swann and Bell, 1958).
The largest field is
Main
Consolidated, which is the large crescent-shaped field that
overlies
the anticlinal belt and the 400 HI contour in catchment 2
(fig.
9). Dry hole maps are useful to show
the concentration of
drilling
across the basin. 2,000 dry holes that
reach total depth
within
Pennsylvanian-age formations are concentrated in the area of
Main
Consolidated field (crescent shape in catchment 2 on Figure 10)
and
west of the area of thermally-mature source rocks. Almost 39,000
dry
holes across the basin reach total depth in Mississippian-through-
Devonian-age
formations (Figure 11). This is about 60% of all wells
drilled,
an approximate percentage because some wells are reclassified
as dry
after they are shut in, others are misreported or underreported,
and
other factors tend to skew the data.
More
than 13,800 wells are listed as productive from Chesterian
reservoirs.
This comprises 37% of all producing oil and (or) gas wells
in the
basin; almost 100% are oil wells. More than 33% of oil and gas
wells
in the basin produce from Valmeyeran age reservoirs; about 97%,
or
12,600, are oil wells (PI/Dwights WHCS data, 1996). Sandstone
reservoirs
from the Chesterian and Valmeyeran are commonly interpreted
as
being from fluvial, deltaic, shoreline, or tidal depositional
environments
(Pryor and others, 1991). A typical Chesterian regressive
depositional
cycle ( Figure 12) begins at the base with a marine shelf-
carbonate
unit, followed by marine, shelf, or prodelta shale, and
topped
by a sequence of sandstone and shale from shoreline, tidal-bar,
tidal-channel,
delta or fluvial distributary, and lower delta-plain
environments
(Pryor and others, 1991). There are seven primary
sandstone,
shale, and carbonate lithofacies for Valmeyeran cycles
(Pryor
and others, 1991). A Valmeyeran regressive depositional cycle is
shown
on figure 13. Oil and gas wells from the Chesterian and the
Valmeyeran
Series are shown on figures 14 and 15.
Chesterian
reservoirs
account for about 60% of the oil produced from the basin
(Howard,
1991). About 18% of basin oil production is from the Ste
Genevieve
Limestone and 2% from sandstones of the Salem Formation
(Cluff
and Lineback, 1981); these are the primary Valmeyeran
reservoirs.
Distribution
of production from Silurian and Devonian-age formations
across
the basin is illustrated on figure 16. These account for 2% and
5%,
respectively, of oil reserves (Howard, 1991). There are about 3,000
oil and
gas wells that produce from Silurian and Devonian reservoirs;
which
is about 12% of the total (PI/Dwights WHCS data, 1996). The
scattered
Silurian production is primarily in western and west-central
Illinois.
Devonian production is widely scattered; primary reservoirs
are
vuggy porous Geneva Dolomite. Minor amounts of natural gas may be
present
in the deep part of the basin as an untapped resource
(Lineback,
1981).
Figure
9. Distribution of more than 4,700 wells with petroleum
production
from Pennsylvanian-age reservoirs in the Illinois Basin.
Catchment
1 is labeled and catchments 2 through 7 are located clockwise
and
sequentially from 1. Purple lines segregate each catchment. An
irregular
dark-reddish-brown line outlines the maximum extent of
Pennsylvanian-age
formations. Well location data were derived from
PI/Dwights
Well History Control System database (1996).
The large 104
KB
image is named pennprod.jpg.
Figure
10. Shown are greater than 2,000 dry holes that reach total
depth within
Pennsylvanian-age formations. Catchment 1 is labeled and
catchments
2 through 7 are located clockwise and sequentially from 1.
Purple
lines segregate each catchment. An
irregular dark-reddish-brown
line
outlines the maximum extent of Pennsylvanian-age formations. Well
location
data were derived from PI/Dwights Well History Control System
database
(1996). The large 104KB image is called
penndry.jpg .
Figure
11. Shown are more than 38,000 dry holes that reach total depth
within
Mississippian-age or older formations. Catchment 1 is labeled
and
catchments 2 through 7 are located clockwise and sequentially from
1.
Purple lines segregate each catchment.
Subsurface or surface extent
of
Chesterian-age formations is outlined by the irregular blue line.
Well
location data were derived from PI/Dwights Well History Control
System
database (1996). The large 104KB image
is called missdry.jpg .
Figure
12. Chesterian regressive depositional cycle is modified from
Pryor
and others (1991, reprinted by permission of The American
Association
of Petroleum Geologists and AAPG Data Systems (Datapages,
Inc.),
whose permission is required for further use). Shown are
spontaneous
potential (SP) and resistivity well-log signatures,
lithology,
and depositional systems for an idealized shoaling-upward
regressive
system; most cycles are bounded by disconformities (shown by
wavy
horizontal lines). The large 16 KB image is named chesdep.jpg.
Figure
13. This Valmeyeran regressive depositional cycle is modified
from
Pryor and others (1991, reprinted by permission of The American
Association
of Petroleum Geologists and AAPG Data Systems (Datapages,
Inc.),
whose permission is required for further use). Shown are
spontaneous
potential (SP) and resistivity well-log signatures,
lithology,
and depositional systems for an idealized upward-shoaling
regressive
carbonate cycle. The large 36 KB image is named valmdep.jpg
.
Figure
14. Distribution of petroleum production from Chesterian-age
reservoirs
in the Illinois Basin. Shown are more than 13,000 oil and
600 gas
wells. Catchment 1 is labeled and catchments 2 through 7 are
located
clockwise and sequentially from 1. Purple lines segregate each
catchment. The irregular blue line outlines the maximum
extent of
Chesterian-age
formations. Well location data were derived from
PI/Dwights
Well History Control System database (1996).
The large 112
KB
image is named chesprod.jpg.
Figure
15. This map shows wells that produce
from units within the
Mississippian
Valmeyeran Series. The catchments 1 through 7 are
labeled.
Purple lines segregate each catchment.
The irregular dark-
green
line outlines the maximum extent of Valmeyeran-age formations.
Primary
producing formations are Ste. Genevieve, Salem, and Aux Vases.
There
are more than 12,000 oil wells (green) and 400 gas wells (red).
Well
location data were derived from PI/Dwights Well History Control
System
database (1996). The large 107KB image
is named valmprod.jpg .
Figure
16. Distribution of oil and gas wells from Silurian- and
Devonian-age
formations. Shown are more than 2,700 oil and 100 gas
wells.
Catchment 1 is labeled and catchments 2 through 7 are located
clockwise
and sequentially from 1. Purple lines segregate each
catchment. Well location data were derived from
PI/Dwights Well
History
Control System database (1996). The
large 93KB image is named
sildprod.jpg.
METHODS
AND RESULTS
Source
Rock Characterization
Characteristics
of the source rocks and of the method of analysis used
in this
study are detailed in Lewan and others (1995, 2002). The New
Albany
Shale (Figure 7) is composed of the following members. In
ascending
order these are 1) Blocher, 2) Sylamore Sandstone, 3)
Selmier,
4) Grassy Creek, 5) Saverton, 6) Louisiana Limestone, 7)
Horton
Creek, and 8) Hannibal (Atherton, Collinson, and Lineback, 1975;
Collinson
and Atherton, 1975; Conkin and Conkin, 1973). An upper shale
composite
of the New Albany Shale is sometimes called the Sweetland
Creek,
Grassy Creek, Morgan Trail, Camp Run, and Clegg Creek Members.
To some
extent, members grade laterally into others; because of erosion
and
non-deposition there is no location in the basin that has all
members
(Cluff and others, 1981). Isopach maps of source rock thickness
for
wells across the basin comprised these members of the New Albany
Shale. Figure 17 shows thickness of
source-rock-quality New Albany
Shale
across the generative basin.
Figure
17. Thickness of source-rock-quality New Albany Shale across the
generative
basin, Illinois Basin. Isopach interval is 20 ft (6 m).
Greatest
thickness of source rocks is the red "bulls eye" located near
the
intersection of Illinois, Indiana, and Kentucky. This area is east
of the
basin axis, and directly east of the "bulls eye" of greatest
maturation
level. Catchment 1 is labeled and catchments 2 through 7 are
located
clockwise and sequentially from 1. Purple lines segregate each
catchment. Maximum extent of the New Albany Shale is
shown by the dark
green
line (modified from Lewan and others, 1995). Large-scale 122 KB
image
is named srthick.jpg .
Initial
thickness of the New Albany Shale, and of individual members,
was
determined from published sources, and also by examination of well-
logs
for the Selmier Member. Intervals assigned to source rocks are
characterized
by API of 120 and greater on gamma ray logs.
Maps that
show
total thickness of the Blocher and Selmier Members and of the
upper
shale composite were traced and scanned (Cluff and Reibold, 1981;
Lineback,
1981; Lewan and others, 1985); scales were about 1 to 2.5
million.
Resulting TIF-format graphics files were converted to Arc/Info
(Environmental
System Research Institute, Inc., 1997) coverages and
saved
as Lambert geographic projections. Map
polygons were assigned
average
thicknesses for each member based on thickness values of
original
contours. These polygon Arc/Info coverages were then converted
to
grids to calculate thickness of member source rocks, and for the
total
New Albany Shale.
Three
Arc/Info coverages (map layers) that describe 1) HI contours, 2)
the
source rock thickness, and 3) catchment boundaries were combined
into
one file by using the intersection function in Arc/Info. The
spreadsheet
that contained the combined attributes for each polygon was
then
used to calculate amounts of expelled hydrocarbons. Greatest
thickness
of source rocks is located in catchments 3 and 4, east of the
present-day
axis of the basin. This is slightly east of the region
where
the source rocks are the most-thermally-mature (Figure 5).
TOC
determinations for eight cores at various maturity levels for the
Blocher
Member show that 98% to 100% of this lower member is
hydrocarbon
source rock. The effective thickness of the Blocher Member
was
calculated by multiplying the total thickness by 0.99, a number
that
approximates the percent that is source-rock quality. Effective
thickness
of the Blocher Member upper composite was determined by
multiplying
the total thickness by 0.97. Selmier Member effective
thickness
was calculated by multiplying total thickness of this
interval
by a grid that was created from point locations across the
basin.
The three grids were added to derive contours for total
thickness
of source-rock-quality of New Albany Shale.
Percent
of source rock for the Selmier Member was variable; average for
61
wells that contained source-rock intervals was 58% of the total
member
thickness. Figure 18 shows the thickness of the member across
the
basin; figure 19 shows the percent of the member that exhibits high
levels
of gamma radiation as indicated by API units of generally
greater
than 120. Excluded from the source rock calculations were
intervals
of the Selmier Member from 87 wells that exhibited low gamma
signatures
characteristic of poor source rock potential; other members
in
these wells were used in the analyses (well logs; Cluff and
Reinbold,
1981). Isopach thickness values for upper members of the New
Albany
Shale (Hannibal and Saverton Members)
were further corrected to
account
for source rock quality, based largely on TOC values. HI values
in the
generative basin were assigned in Arc/Info to individual x-y
grid
cells.
Thickness
of the New Albany Shale, and of its individual members,
increases
towards the basin depocenter in southern Illinois and Indiana
(Cluff
and others, 1981; Devera and Hasenmueller, 1990) (Figures 18,
19). A
second depocenter is located in northwestern Illinois in
catchment
7, just northwest of the saddle of 0 to 20 ft (0 to 6 m)
thick
shale of the Selmier Member. The Selmier Member is about 200 ft
(61)
thick in Hardin County, Illinois (Devera and Hasenmueller, 1990).
This is
within the red contour fill in the southern tip of Illinois
(Figure
18). Percentages of source rock thickness that exhibit 120 API
units
or greater gamma is highest along the basin axis (Figure 19).
Outlying
high gamma percentages are commonly associated with thinner
intervals
of Selmier, or may represent extrapolation outside the areas
of data
control.
Figure
18. Isopach map of the Selmier Member of the New Albany Shale.
Contour
interval is 10 ft. (3.0 m). Catchment 1 is labeled and
catchments
2 through 7 are located clockwise and sequentially from 1.
Purple
lines segregate each catchment. Maximum
extent of the New
Albany
Shale is shown by the dark green line (modified from Lewan and
others,
1995). The large 141 KB image is named selmiso.jpg.
Figure
19. Percent thickness of the Selmier Member of the New Albany
Shale
that exhibits gamma signatures of 120 API units or greater.
Contour
interval is 20%. Red line outlines the generative basin.
Catchment
1 is labeled and catchments 2 through 7 are located clockwise
and
sequentially from 1. Purple lines segregate each catchment. Basin
axis is
the purple line that separates catchments a) 2 and 7, b) 3 and
6, and
c) 4 and 5. Greatest percentage of source-rock quality shales
(thickest
intervals of high gamma signature) are along the basin axis.
Maximum
extent of the New Albany Shale is the dark green line (modified
from
Lewan and others, 1995). Sample
locations are small inverted
triangles.
These are more readily viewed on the large 131 KB
selmhga.jpg
image.
Estimated
Amounts of Generated and Produced Oil, Known Petroleum Volume
of Oil,
and Original-Oil-In-Place
Cumulative
production from Silurian through Pennsylvanian formations
across
the basin through 1996 is 4.002 BBO; 2.624 BBO is from within
the
generative basin. Half of the oil in the system, 49.6%, is produced
from
only six fields; these are Clay City Consolidated, Lawrence,
Louden,
Main Consolidated, New Harmony Consolidated, and Salem
Consolidated.
Macke (1996) details an Illinois Basin-Post-New Albany
hydrocarbon
play that includes Mississippian- through Pennsylvanian -
age
formations across the basin. He lists cumulative production of 2.56
BBO for
these formations, and 2.67 BBO cumulative for Silurian through
Pennsylvanian-age
formations. This 2.67 BBO is considerably less than
the
current 4.0 BBO cumulative production and may result primarily from
differences
in the area of his basin and play boundaries. Macke's
(1996)
Post-New Albany play covers an area of more than 34,000 sq. mi.;
API
gravity of oil ranges from 22 to 42 degrees and averages 38
degrees.
Oil contains about 0.3 percent sulfur.
Reported
and calculated known petroleum volume in the basin for all
formations
ranges from 3.57 to 4.30 BBO (Mast and Howard, 1991; Nehring
and
Associates, 1995; PI/Dwights Corp., 1996). Our calculations, based
on
these proprietary databases and published sources, result in a known
petroleum
volume of 4.158 BBO; values of recoverable oil were available
for 210
of the 721 fields used in this analysis. There were originally
more
than 1,700 fields across the basin but are now about 721, largely
because
of consolidation of fields and under-recording of fields
completed
early in the history of the basin and of small fields.
Reported
and proprietary known petroleum volumes ranged from 100% to
192%
over current cumulative oil production. Respective average and
median
values for the scatter of data were 104.9% and 103.2%. The
103.2%
recovery was used in the calculations because it better fit the
production
histories of the remaining mostly smaller fields.
Mast
and Howard (1991) indicate known petroleum volume of oil (their
"estimated
ultimate recovery") from existing fields in the Illinois
Basin
is 4.30 BBO, and that 7.7 BBO remains in place, some of which may
be
produced through tertiary recovery methods. Gas production numbers
are not
included because during the early history of drilling in the
basin
huge quantities of associated dissolved gas were flared, and gas
production
records were poorly kept. Bell and Cohee (1940) stated as
much as
1 MCF of associated-dissolved gas has been produced for each
barrel
of oil recovered from fields in the Illinois Basin. Based on
this
number, Mast and Howard (1991) suggest as much as 4 TCF of gas has
been
flared and lost in the basin, or 667 MMBOE. Volume of produced
non-associated
gas is about 250 BCFG (41.7 MMBOE); Bell and Cohee
(1940)
indicated that lease condensate volumes are about 30 bbls for
each
MMCFG produced.
The
4.158 BBO total known petroleum volume excludes oil from west of
the
Sagamon arch, gas, and oil from Ordovician age formations. Also not
included
are the in-place tar deposits of an estimated 3.4 billion
barrels
of hydrocarbons (Noger, 1987; Crysdale and Schenk, 1988). These
were
excluded because chemical analyses of the tar, particularly the
nickel
and vanadium concentrations, indicated that the tar is derived
from a
different source rock than the New Albany Shale (M. Lewan,
personal
communication, 1998). Tar deposits within the Illinois Basin
are
restricted to catchments Nos. 3 and 4. Tar occurs in sandstones of
Chesterian
age in Crawford Co., Indiana (within catchment number 3,
Figure
14) (J. Rupp, personal communication 1998) and of Chesterian
through
Pennsylvanian age in catchment 4 (Breckinridge, Hardin, McLean,
and
Grayson counties, Kentucky)(Ball Associates, 1965). Tar deposits in
catchments
3 and 4 indicate that leakage of petroleum has occurred in
these
catchments.
About
66% of the 4.158 BBO known petroleum volume, or 2.723 BBO, is
located
within the generative part of the basin (Table 1). The
remaining
34% is concentrated within about 30 mi. (50 km) of the
generative
area. Table 2 lists cumulative production, known petroleum
volume
of oil, and original oil in place for the seven catchments in
the
Illinois Basin. Also shown is production within and outside the
generative
basin. Seventy to seventy-five percent of the production is
from
shallow (less than 3,000 ft, 915 m) Chesterian and Pennsylvanian
reservoirs,
20% from Valmeyeran reservoirs, and much of the remaining
7% from
Silurian- and Devonian-age formations (Howard, 1991; Mast and
Howard,
1991).
Table
1. Estimated amounts of hydrocarbons that have been generated and
produced
from the New Albany Shale petroleum system in the Illinois
Basin.
Shown are estimated volumes of hydrocarbons both within the area
of
mature source rocks and outside this boundary. The thermally mature
region
is defined by a hydrogen index (HI) value of 400. Included are
estimates
of cumulative production, known petroleum volume of oil, and
original-oil-in-place
(OOIP). The known petroleum volume of
oil is
36.22%
of the OOIP of 11.45 BBO (billion barrels of oil). [If your view
does
not read the HTML v. 3 format, the file is also saved as comma-
delimited
( ooipnum.csv), text ( ooipnum.txt), and EXCEL v 4.0 (
ooipnum.xls)
formats.]
Table
2. Catchment number (CN), cumulative
production (CUM), known
petroleum
volume (K VOL), and original oil in place (OOIP) values for
the New
Albany Shale petroleum system. Volumes
are millions of barrels
of oil
(MMBO). "Within" and
"outside" refer to location of produced,
in-place,
and (or) recoverable oil within or outside the 400 HI contour
that
encloses thermally mature source rocks.
The final column shows
the
percent of oil production within the hydrocarbon generative area of
the
Illinois Basin. [If your Web browser cannot view the below table,
it is
also saved as comma-delimited ( oilprod.csv) and Microsoft EXCEL
v. 5.0
( oilprod.xls) files. The external HTML table is named
oilprod.htm
.]
Estimated
original oil in place (OOIP) is 11.45 BBO; this is based on a
36.22%
recovery ratio of the 4.158 BB known petroleum volume of oil.
The
Mast and Howard (1991) estimate of OOIP for the basin is 12 BBO.
Their
greater estimated volume results from incorporating both a larger
area
and Ordovician production. We excluded production from Ordovician
formations
and from wells west of the Sagamon Arch, because they are
not
part of the New Albany Shale petroleum system. Neither Mast and
Howard
(1991) nor our estimate includes hydrocarbons from tar deposits.
Mast
and Howard (1991) included in their calculations the suggested 4
TCF of
associated gas and 250 BCF of non-associated gas. The non-
associated
gas fields they included are outside the boundaries of the
New
Albany Shale petroleum system. We did not include their suggested 4
TCF of
flared associated gas in our calculations. Our original-oil-in-
place
(OOIP) percentages were determined primarily on Nehring and
Associates
data on oil and gas fields (through 1995), Illinois State
Geological
Survey reservoir studies, Department of Energy data, and
PI/Dwights
production data on CD-ROM (through 1996). Cumulative
production
of oil was derived from the above sources. OOIP numbers from
these
sources for 38 oil fields across the study area range from 1.782
to
1,200 MMBO.
Mast
and Howard (1991) assigned an overall recovery efficiency of about
34.3%
for all fields inside, and some outside the Illinois Basin. They
indicated
this percentage is probably too small for the Illinois Basin
alone
for two reasons. The first is that recovery efficiency is greater
for
Illinois Basin fields than for all fields in their study area,
which
included all of Illinois, Indiana, and Kentucky. Second, use of
secondary
recovery and other methods has increased production
efficiency
in stripper and other wells. "By the end of 1983,
approximately
one-third of cumulative oil production was attributable
to
secondary recovery methods" (Mast and Howard, 1991). Their
recommendation
of 36% recovery of OOIP agrees with our estimated
recovery
percentage. Estimated recovery efficiency for all onshore U.S.
oil
fields in 1980 was about 32.1% (American Petroleum Institute,
1980).
Estimates
of Losses from Carrier Beds
Oil and
gas can be lost during secondary migration of hydrocarbons. In
this
study, estimates of residual losses and the analytical methods are
documented
in Lewan and others (2002). Maps were created that showed
all wells
in the Illinois Basin that contained reports of petroleum
production
from or hydrocarbon shows in the principal reservoir rocks.
Information
for these maps was collected from the PI/Dwights Well
History
Control System (WHCS, 1996) and Production Data on CD-ROM
(1999)
databases, and the Nehring database (1996). Included rock units
are the
Valmeyeran Ste Genevieve Limestone and Aux Vases Sandstone, the
Chesterian
Bethel and Cypress Sandstones, and three 'generic' units
consisting
of Silurian, Devonian, and Pennsylvanian rocks. The
Pennsylvanian
reservoir units were not divided into individual
formations
because the areal extent of many of the named units in the
basin
is limited. Silurian and Devonian well data were lumped at the
system
level because these reservoirs make only a small contribution to
total
basin petroleum production. Polygons of the maximum extent of
production
and shows were plotted on these show maps. Arc/Info
coverages
were then generated from the data and surfaces. The polygons
were
taken as representative of the minimum areas through which
petroleum
had migrated.
A data
base that contains median porosity and permeability information
from
core samples (Appendix 1, located in data/ fileform/porperm.xls)
was
created from analyses supplied by the Illinois State and Indiana
Geological
Surveys. From these point data, generalized basin porosity
contour
maps were generated for the three Mississippian-age units. The
extent
of these contours was limited by the polygons that represent the
extent
of shows for the respective-age reservoir units. The 'generic'
units
were assigned the following average porosities; 18% for
Pennsylvanian,
14% for Devonian, and 13% for Silurian (Howard, 1990).
The
intersection function in Arc/Info was then used to combine the
attributes
of the show map with those of the porosity contour maps for
each
rock unit. A value of 1.5 ft (0.5 m) was used for the minimum
thickness
of the carrier bed that was subjected to hydrocarbon
migration
(Schowalter, 1979). Values of 1) porosity, 2) estimated
residual
oil saturations, and 3) volume of carrier bed through which
petroleum
moved were used to determine the residual loss of petroleum
for
each polygon within the show area. These amounts were summed for a
total
residual loss for each of the seven possible carrier units.
Factors
That Influence/Control Estimation of Hydrocarbon Resources
The
ultimate petroleum potential of a sedimentary basin is based on the
following
equation from Lewan and others (1995, 2002). PC is petroleum
charge,
which is the quantity of oil expelled from a mature source
rock,
also referred to as a kitchen area (Lewan and others, 1995,
2002),
or pod of active source rock (Magoon and Dow, 1994). PL is
leakage
of hydrocarbons due to eroded section, surface leakage of oil,
or
secondary migration residual (Lewan and others, 2002). Ultimate in-
place
petroleum is the amount of petroleum that has been generated from
the
source rocks, minus the amount lost (PL).
This is different from
OOIP,
which is a measure of the original oil volume present in known
reservoirs;
Lewan and others (2002) also refer to OOIP as "accountable
in-place
oil".
PC - PL = Ultimate In-Place
Petroleum
A
generalized list of factors that influence resource estimates
follows:
1)
Economics - petroleum is present but in sub-economic or lesser
volumes
due to
a.
Price of oil and/or gas,
b.
Distribution of oil and gas; scattered wells were sub-economic,
c.
Mixing of oil and water. Much of the
oil around field margins is
located
in thin units or admixed with other fluids and would not be
economic.
d. Loss
of associated gas during production as a result of flaring.
How
much gas has been lost is unknown but the practice was common in
the
Illinois Basin. Mast and Howard (1991) suggest as much as 4 TCF of
gas has
been flared and lost in the basin.
e.
Reporting. Most of the fields in the basin are older and reporting
practices
were less rigorous in the past; this would be especially true
for
infill wells, for smaller fields, and for those owned by smaller
operators.
Older production is probably both under-reported and under-
compiled.
f.
Non-discovery. While the basin center is extensively drilled for
Pennsylvanian
through Mississippian formations, some of the fringe
areas
are not. Some of the reasons for lack of discovery are sparse
drilling,
non-detection of hydrocarbons in underpressured reservoirs or
within
compartments, or not recognizing oil outside of the target
formations.
2) Subsurface distribution and leakage of oil
and gas
a. Loss
of hydrocarbons updip or up fracture networks.
b. Loss
of hydrocarbons from erosion following emplacement. This is
particularly
important south of the Cottage Grove and Rough Creek-
Shawneetown
fault systems.
c. Oil
trapped within clays, in isolated shale stringers, and other
thin
discontinuous units may not be factored into OOIP numbers because
they
are based on production. In theory, the OOIP numbers take into
account
these non-recoverable hydrocarbons.
3) Field production practices
a.
Formation was damaged during the drilling process and well had to be
abandoned
(D & A).
b. Oil
was produced but the reservoir was shut-in due to economics or
to
technology. That is, the hydraulic fracturing or other process used
to
complete the wells was inefficient at recovering hydrocarbons from
these
heterogeneous reservoirs.
c. The
field was shut in before the advent of secondary and tertiary
recovery
processes. This would have resulted in an overall decrease in
production
efficiency, perhaps to 28-30% of OOIP versus the 36.22% we
used in
our calculations.
CONCLUSIONS
This paper documents the analytical methods
used in assessing oil and
gas
reserves and resources for the material balance assessment by Lewan
and
others (2002) of the New Albany-Chesterian petroleum system in the
Illinois
Basin. Included maps show the
distribution of oil and gas and
non-productive
wells for formations in the basin that are sourced from
the
Upper Devonian and Lower Mississippian New Albany Shale, and tables
show
data and results of the analyses.
Included on the 2D production
maps
and the 3D images are the 7 hydrocarbon catchments of the basin
and the
distribution of oil, gas, and non-productive wells for Silurian
through
Pennsylvanian formations in the Illinois Basin.
The New
Albany Shale in the Illinois Basin is the primary source for
oil and
gas produced from the basin. The generative area of the
Illinois
Basin is outlined by a hydrocarbon index value of 400; HI
values
within the thermally mature portion of the basin range from 10
to 400
mg/g TOC (Appendix 2, HI_TOC.xls). About 66% of the produced oil
occurs
within the generative basin, which suggests that oil primarily
migrated
upwards through faults and fractures into overlying reservoir
strata.
Remaining production is concentrated within about 30 mi. (50
km) of
the generative area, suggesting limited lateral migration. The
influence
of lateral migration through porous carrier beds may be
important
in large oil fields such as Louden and Main Consolidated, all
or
parts of which lie outside the generative basin.
Silurian
through Pennsylvanian rocks in the Illinois Basin contain
4.158
BB known petroleum volume of oil, and have produced 4.002 BBO.
Estimated
original oil in place (OOIP) is 11.45 BBO.
Known petroleum
volume
is 36.22% of the OOIP. Excluded from the calculations were areas
west of
the Sagamon arch, which are outside the generative basin, may
have a
different migration history, and may contain petroleum
production
from Ordovician rocks, which have a different source. Also
excluded
was associated dissolved gas; which is mainly located outside
the
assessment area, was primarily flared across the basin, and of
which
few records were kept.
SELECTED
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K., Seyler, B., and Udegbunam, E.O., 1994, An integrated
geologic
and engineering study of the Plumfield Lease Aux Vases
reservoirs,
Zeigler field, Franklin County, Illinois; Illinois State
Geologic
Survey, IP 146, 29 p.
Swann,
D.H., and Bell, A.H., 1958, Habitat of oil in the Illinois
Basin,
in Weeks, L.G., ed., Habitat of oil: American Association of
Petroleum
Geologists, p. 447-472.
Treworgy,
J.D., 1981, Structural features in Illinois- a compendium:
Illinois
State Geological Survey Circular 519, 22p.
Treworgy,
J.D. and Devera, J.A., 1991, Kaskaskia sequence overview:
Middle
Devonian Series through Chesterian Series, in Leighton, M.W.,
Kolata,
D.R., Oltz, D.F. and Eidel, J.J., eds., Interior Cratonic
Basins:
American Association of Petroleum Geologists Memoir 51, p. 109-
112.
Whitaker,
S.T., and Finley, A. K., 1992, Reservoir heterogeneity and
potential
for improved oil recovery within the Cypress Formation at
Bartelso
field. Clinton County, Illinois; Illinois State Geologic
Survey,
IP 137, 40 p.
Willman,
H.B., Frye, J.C., Simon, J.A., Clegg, K.E., Swann, D.H.,
Atherton,
E., Collinson, C., Lineback, J.A., and Buschbach, T.C., 1967,
Geologic
Map of Illinois: Illinois State Geological Survey, 615 E.
Peabody,
Champaign, IL, 1 plate, Scale 1:500,000.
Xu, J.,
and Huff, B.G., 1995, The Cypress Sandstone (Mississippian)
reservoir
and its recovery potential at Xenia East oil field, Clay
County,
Illinois; Illinois State Geologic Survey, IP 147, 47 p.
ACKNOWLEDGEMENTS
Keith
Kirk, previously of the Office of Surface Mining, and other
Office
of Surface Mining personnel, Denver, Colorado, were kind enough
to
allow us access to their 3-D EarthVision computer software. The
publication
benefited from reviews by Tom Judkins, Joe Hatch, Mike
Pantea,
and Kathy Varnes of the U.S. Geological Survey.
++++++++++++++++++++++++++++++++++++++++++++++
U.S.
Department of the Interior
U.S.
Geological Survey
THE NEW
ALBANY SHALE PETROLEUM SYSTEM, ILLINOIS BASIN - DATA AND MAP
IMAGE
ARCHIVE FROM THE MATERIAL-BALANCE ASSESSMENT
The two
sets of data that are located in the "data" sub-directory are
porperm.xls
and HI_TOC.xls. All data files are saved in Microsoft EXCEL
version
5.0 as v97 and 5.0/95 Workbooks, as space-delimited files
(*.txt),
and comma-delimited data (*.csv). File contents and examples
are
shown and explained below.
Table
3. Below is a sample from the porperm.xls file. The data are also
saved
as comma-delimited ( porperm.csv ) and space-delimited (
porperm.txt
) formats. Files are located in the "data" sub-directory.
Three-hundred
and seventy-seven core reports were used to determine
median
values of porosity, permeability, and the percent oil and water
saturation
for cored intervals of the following Mississippian-age
formations:
Aux Vases, Bethel, Cypress, and the McCloskey unit of the
Saint
Genevieve. Figure 7 is a stratigraphic column of these
formations.
Percents of oil and water saturation are generally
inaccurate
due to water washing and/or contamination of the core during
drilling
and recovery.
VARIABLES
FOR PORPERM FILES ARE:
* ID = Identification
code for that cored interval
*
Longitude = Geographic reference point, values are degrees of arc.
Data
are derived primarily from State sources.
*
Latitude = Geographic reference point, values are degrees of arc.
Data
are derived primarily from State sources.
* Form
= Cored stratigraphic interval. AXVS = Aux Vases, BTHL = Bethel,
CPRS =
Cypress, MCLK = McCloskey
*
Depthft = Median depth in feet of the core
* Hperm
= Median horizontal permeability, in millidarcies
*
Porosity = Median porosity of the cored interval, in percent
* %Oil
= Median percent of oil saturation in the cored formation
*
%Water = Median percent of water saturation in the core.
* Well
Name = Name of the well on the core report
* Field
Name = Name of the oil field, or "wildcat" is entered if there
is no
field
* TRS =
Township, range, and section location of the well from the core
report.
This is written in several formats and can include quarter
sections.
Table
4. The below sample from the HI_TOC files shows geochemical
statistics
for samples from the New Albany Shale. HI_TOC.xls file is
saved
in Microsoft EXCEL version 5.0 as v97 and 5.0/95 Workbook. The
file is
also saved in space-delimited (HI_TOC.txt) and comma-delimited
formats
(HI_TOC.cvs). Analytical methods are detailed and assessed in
Lewan
et al. (1995, 2002), and very briefly summarized here. Total
organic
carbon content (TOC) of hydrocarbon source rocks is primarily
determined
using Rock-Eval pyrolysis. This technique involves heating
about
50 to 150 mg of powdered rock in a crucible under anhydrous
conditions.
The oven is continuously swept by flowing helium at low
pressures,
and the sample is heated isothermally, followed by a
programmed
rate of heating. Pyrolysis of the sample at a constant
temperature
of about 250 degrees C for 3 to 5 minutes distills organic
compounds
from C1 (one carbon atom and attached hydrogen atoms) to
about
C32. Volatilized products are swept with helium into a flame
ionization
detector (FID) for quantification of contained hydrocarbons.
These
pyrolyzed hydrocarbons are considered to be bound to the organic
matter
in the sample and are designated as "S1" (S subscript 1)
hydrocarbons.
Programmed heating from 250 to 600 degrees C at a rate of
25
degrees C/minute cracks the kerogen and heavy bitumen. This yields
organic
compounds, water, carbon dioxide, and other gases. Half of the
flow of
produced molecules is sent to the FID to measure hydrocarbon
compounds;
these are designated "S2" (S subscript 2), generated
hydrocarbons.
The other half of the flow is sent to a carbon dioxide
trap
that is heated at 250 to 390 degrees C. Compounds in the carbon
dioxide
trap are heated and resulting gas is measured by a thermal
conductivity
detector (TCD); these hydrocarbons are designated as "S3"
(S
subscript 3). Evolved carbon monoxide (CO) is not measured. The
crucible
is then moved to another furnace where it is heated to about
590
degrees C in air (oxidizing atmosphere). The evolved carbon dioxide
is
measured by the TCD.
VARIABLES
FOR HI_TOC FILES OF THE NEW ALBANY SHALE ARE:
* State
= The State in the United States from which the sample
originated
(IL=Illinois, IN=Indiana, KY=Kentucky)
*
Latitude = Geographic reference point, values are degrees of arc.
Data
are primarily from State records.
*
Longitude = Geographic reference point, values are degrees of arc.
Data
are primarily from State records.
* Tmax
= Tmax results (degrees C) from Rock Eval or hydrous pyrolysis
* PI =
Production index (Lewan et al., 2002)
* TOC =
Total organic carbon content (weight percent) of the New Albany
Shale
source rocks
* HI =
Hydrogen index values determined from Rock Eval or hydrous
pyrolysis
((mg S2 hydrocarbons)/TOC).
*
Sample_No = Sequential numbers assigned to each sample. Numbers for
the 262
samples in the file range up to 318. Not all results are
included,
some were for different formations or were outside the study
area.
*
Sample_ID = Identification code for that sample location. Some
Kentucky
wells instead have the well name.
++++++++++++++++++++++++++++++++++++++++++++++
Glossary
- THE NEW ALBANY SHALE PETROLEUM SYSTEM, ILLINOIS BASIN;
RESOURCE
ESTIMATES BY CATCHMENT
Authigenic
Generated
or formed in place. Specifically used with rock minerals and
other
constituents that were derived locally, and of minerals that
precipitated
at the same time, or subsequent, to the rock in which they
are
found.
ASCII
(American
Standard Code for Information Interchange) A standard format
for
storing and transmitting data. A set of binary numbers that
represent
the alphabet, punctuation, numbers, and symbols that are used
for
text and communication protocols.
Binary
A file
format consisting of machine-readable executable code or binary
data,
as opposed to ASCII text files.
BinHex
A file
conversion format that converts binary files to ASCII text
files.
Biostratigraphy
Ages,
differentiation, and correlation of rock intervals based on the
study
of contained fossils.
Bioturbated
Sediment
that has been extensively reworked by worms, crustaceans, or
other
organisms. Burrows and other evidence of reworking are commonly
minor
due to the biologic activity.
Bug
Commonly
indicates a software or other computer-based error.
Case
sensitive
Refers
to upper and lower case letters. UNIX is case sensitive, meaning
that
names of document links and file names must be identical. A
program
accessing "Cat.GIF" would not find the same file were it named
"cat.GIF."
Concretions
Hard
round, oval, or other-shaped mass of mineral or aggregate matter
of
varied sizes. Commonly forms by chemical precipitation around a
nucleus
or center, or replacement of precursor organic or inorganic
material.
An example is siderite (iron, calcium carbonate) concretions.
Detrital
Formed
from detritus of preexisting rock. This is particularly for
rocks,
minerals, and sediments composed of precursor components.
Diachronous
A
single rock unit that exhibits various ages in different areas. A
sedimentary
formation, such as marine sands, that formed during
transgression
or regression of the shoreline, being progressively
younger
in the direction that the sea level is moving.
Diagenesis
Changes
that influence sediments after deposition. These include
compaction,
cementation, chemical alteration, dissolution, and
precipitation
of constituents. Excluded are surficial weathering, and
metamorphism
of preexisting sediments.
Dissolution
A void
space or cavity in or between rocks that resulted from solution
of part
of the rock material.
Document
window
Scrollable
WWW browser window in which documents, slide shows, and
movies
are viewed.
File
Transfer Protocol (FTP)
File
Transfer Protocol is commonly used to transfer files from one
computer
platform to another.
Flow
unit
In
petroleum geology, reservoir zones that exhibit similar fluid flow,
porosity/permeability,
reservoir potential, and production
characteristics.
The flow-unit definition includes a "volume of rock
subdivided
according to geological and petrophysical properties that
influence
the flow of fluids through it" (Ebanks, 1987).
Folder
Directory,
sub-directory, and folder are used interchangeably to show
addresses
of files on this CD-ROM.
FTP
(File Transfer Protocol)
File
Transfer Protocol is commonly used to transfer files from one
computer
platform to another.
GIF
(Graphics Interchange Format)
GIF is
a graphics file, commonly with the .gif or .GIF ending. The
acronym
refers to the Graphics Interchange format developed by
CompuServe,
Inc. This graphics format is used on numerous computer
platforms
and systems. GIF files can be for inline and movie images.
Heterogeneity
The
state or quality of being nonuniform, having dissimilar elements,
not
homogeneous. For example, a unit composed of interbedded thin- and
thick-bedded
sandstones and mudstones is heterogeneous.
Home page
The
initial screen or graphic image in which links to related
information
are listed. A document that the user specifies for network
browsing
software to display, commonly when the software program is
started.
HTML
(Hypertext Markup Language)
Acronym
for Hypertext Markup Language. HTML files on this CD-ROM follow
the 8.3
PC/DOS format. One version of this file, for example, is named
glossary.htm.
Hydrogen
index (HI=S2/TOC (mg hydrocarbons/g organic carbon))
The
hydrocarbon generative potential of a rock normalized to TOC is
correlative
with the H/C ratio of the kerogen. HI is an indicator of
kerogen
type and whether the source rock is oil or gas prone. Values
generally
range from 0 to 900.
Image
Refers
to still image data. Subtypes recognized by graphics programs
include
JPEG, GIF, RGB, TAR, TIFF, X-PICT (PICT), X-XBM (X bitmap
image),
and other formats.
JPEG
(Joint Photographic Experts Group)
Acronym
for Joint Photographic Experts Group, an image-compression
format
used to transfer color images over computer networks.
Known
Petroleum Volume
The sum
of cumulative production and remaining reserves. Also called
estimated
total recoverable volume (sometimes called "ultimate
recoverable
reserves" or "estimated ultimate recovery"). Commonly
reported
as millions of barrels of oil (MMBO), or million barrels of
oil
equivalent (MMBOE) when both oil and gas production and reserves
are
evaluated; the equivalent refers to conversion of gas to oil
volume. Modified from Klett and others (2000).
Laminar
bedding
1)
Finest stratification of shale or fine-grained sandstone bedding, 2)
thin
alternating layers of differing composition, and 3) laminae, such
as in
shale, that can be split into thin layers.
Meniscus
The
curved upper surface of a nonturbulent liquid in a container. A
crescent-shaped
body. A concavo-convex lens.
Minus-cement
porosity
The
percent volume of void space in a rock, added with volume of
cements
and other post-depositional pore-filling compounds. This is
used as
an estimate of porosity during the time of deposition of the
rock.
MOV
File
type of a single-forked stand-alone QuickTime movie.
MPG,
MPEG, CMPEG
Moving
Pictures Expert Group movie file type used primarily for PC/DOS
and
UNIX platforms. Special viewing applications are required to run
MPG
movies on your computer.
Overgrowth
Secondary
material precipitated around a crystal grain of the same
composition.
Both grain and cement are in optical and crystallographic
continuity.
Paragenesis
A
sequential order of rock alteration, such as, compaction,
precipitation
of minerals, dissolution of grains and cements, and
similar
processes.
Permeability
The
capacity or ability of a porous medium, such as rock or soil, to
transmit
fluid; an indication of the rate of diffusion of a fluid under
unequal
pressure. The common unit of measure is the millidarcy (mD).
Petroleum
System
The
basic geologic unit used to assess oil and gas reserves and
resources
and includes all genetically related petroleum that occurs in
shows
and accumulations that (1) has been generated by a pod or by
closely
related pods of mature source rock, and (2) exists within a
limited
mappable geologic space, along with the other essential
mappable
geologic/geochemical elements (source, reservoir, seal, and
overburden
rocks) that control the fundamental processes of generation,
expulsion,
migration, entrapment, and preservation of petroleum
(modified
from Magoon and Dow, 1994).
Production
Index (PI= S1/(S1+S2))
During
thermal maturation of a source rock the S1 hydrocarbons increase
at the
expense of S2 hydrocarbons, with an associated increase in PI.
PI is
an indicator of the level of thermal maturity of source rocks. A
rock
sample that is oil-stained or has organic contamination will
exhibit
an anomalously high PI. Values range from 0.0 to generally less
than
0.4.
Planar
bedded
Lying
or arranged in approximately parallel planes. Bedding in which
the
lower surface is a beveled erosional contact; cross bedding is
characterized
by planar foreset beds.
Porosity
The
percentage of bulk volume of a rock or other object that is
occupied
by void space, whether isolated or connected. Porosity is
further
subdivided into effective (or connected) pores, primary,
secondary,
and minus-cement categories. Primary porosity includes all
depositional
pore spaces; secondary porosity records the volume of void
space
resulting from dissolution and (or) fracturing of the rock or
sediment.
Minus-cement porosity category combines intergranular primary
porosity
and secondary porosity, in addition to authigenic cements and
clays,
as an estimate of the amount of porosity at the time of
lithification;
porosity resulting from intragranular dissolution is
excluded
QuickTime
A
digital video standard developed by Apple Computer for PC/Windows and
Apple
computers. The QuickTime extension file is inserted into the
Apple
System Folder, and special viewing applications are required to
view
QuickTime "movies."
Range
1) Any
series of contiguous townships of the U.S. Public Land Survey
system.
These are aligned parallel to a principal meridian and numbered
consecutively
in an east-west direction from the meridian. 2) mountain
range.
3) The numerical difference between a series highest and lowest
values.
4) stratigraphic range. 5) A geographic area over which an
organism
or group of organisms is located.
Ravinement
A break
in sedimentation resulting primarily from erosion. An example
is a
disconformity resulting from marine transgression and erosion of
precursor
sediments. Formation of a gully or ravine.
Radiometry
Methods
of calculating an age for geologic materials by measuring the
amounts
of short-half-life radioactive elements, such as carbon-14, or
of
long-half-life radioactive elements plus their decay products, such
as
potassium-40/argon-40.
Regression
(Simply)
The local or widespread retreat of seas from land surfaces and
resulting
changes in erosion and depositional patterns of strata.
Rock-Eval
Pyrolysis
An
open-system method of heating 10-20 milligrams of powdered rock at
300 to
600 degrees C over 15 to 30 minutes.
Vaporized S1 and S2
products
(below) that are generated from the sample during the heating
are
swept from the oven with a carrier gas over a flame ionization
detector;
the purpose is to quantify yields of generated hydrocarbons
(Espitalie
and others, 1977a, b).
S1
Free
hydrocarbons (HC, hydrogen plus carbon molecules) in the rock.
Measured
as mg HC/g rock (milligrams of hydrocarbons per gram of rock
sample).
This approximates the gas, oil, and bitumen content of the
rock,
up to about C33 (thirty-three carbon atoms with attached hydrogen
atoms).
S2
Hydrocarbons
that are generated by pyrolytic degradation (cracking
under
high heat) of the kerogen and any remaining free hydrocarbon
chains
greater than C33 (thirty-three carbon atoms with attached
hydrogen
atoms) (heavy bitumen) in the sample (mg HC/g rock). Common
values
range from 0 to 40 mg/g.
SEA
(Self-Extracting Archive)
Self-extracting
archive (SEA). These compressed files contain one or
more
files and (or) programs. SEA s are generally decompressed by
double
clicking on the name or icon. Further instructions are given
during
the decompression process.
Secondary
porosity
Porosity
developed in a rock subsequent to its emplacement or
deposition.
Processes are mostly dissolution of grains, cements, and
other
constituents due to changes in pressure and (or) pore-fluid
composition.
Section
1) One
of the 36 units that make up a township, and are generally one
mile
square. 2) An exposed vertical or inclined surface, such as a
cliff
or quarry face. 3) geologic term used for a columnar section,
type
section or thin section.
TGA
(TARGA)
TARGA
image file format; this commonly has a .tga or .TGA ending.
TIFF
(Tagged Image File Format)
Acronym
for Tagged Image File Format, a graphic file format developed
by
Aldus and Microsoft. TIFF is used as an image transfer format on
computer
networks.
Tmax
Temperature
(degrees C) during which the maximum amount of S2
hydrocarbons
is generated from a rock sample. Tmax values are functions
of
kerogen type and levels of thermal maturity. This is a measure of
the
degree of thermal maturity of potential hydrocarbon source rocks.
Total
organic carbon (TOC = RC + PC = Wt % organic C in the rock)
The TOC
is the sum of the residual carbon (RC) and the pyrolyzable
carbon
(PC). Residual Carbon (RC=0.1*S4) is determined from the amount
of
carbon dioxide that is evolved during combustion of the rock sample.
This
assumes complete combustion with no contamination by carbonate
carbon.
The organic carbon represented by the carbon dioxide from
pyrolysis
(S3) is fairly small and is excluded from the TOC
calculation.
Transgression
(Simply)
The advance or spread of seas over land surfaces which cause
changes
in erosion and depositional patterns of marine and non-marine
strata.
Tabular
cross bedding
Cross-bedded
units that are bounded by planar, essentially parallel,
surfaces
to form tabular sandstone bodies.
Township
A unit
of survey of the U.S. Public Land Survey. It is an area bounded
on the
east and west by meridians located about 6 miles apart. A
township
is normally a square that is subdivided into 36 sections, each
of
which is approximately 1 mile square. Township, range, and section
locations
are shown on most topographic maps, for example.
Trough
cross bedding
Cross-bedding
in which the lower surfaces are curved erosional contacts
which
result from scour and subsequent deposition.
URL
(Uniform Resource Locator)
The
acronym stands for Uniform Resource Locator, the addressing
standard
on the WWW. The URL contains information about the location,
method
of access, and path of files to be viewed.
World
Wide Web (WWW)
The
hypermedia document network system, abbreviated as WWW. WWW can be
accessed
over the Internet using Web browser software.
