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DATA FILES README AND EXAMPLES
DISTRIBUTION OF OIL, GAS, AND NON-PRODUCTIVE WELLS
·Petroleum Production in the Basin
·Distribution of Oil, Gas, and Non-productive Wells
·Estimates of Losses from Carrier Beds
·Factors That Influence/Control Estimation Of Hydrocarbon Resources
APPENDICES
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 1,343 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).
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 159 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 753 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 525 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 55 KB, and the enlarged images are 86 to 190 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 161 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).
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/DwightsWell History Control System database (1996).The large 693 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/DwightsWell History Control System database (1996).The large 574 KB 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/DwightsWell History Control System database (1996).The large 774 KB 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 122 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 143 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/DwightsWell History Control System database (1996).The large 633 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/DwightsWell History Control System database (1996).The large 345 KB 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/DwightsWell History Control System database (1996).The large 502 KB 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 493 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 1,097 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 2,937 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 .]
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.
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.
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 1,343 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).
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 159 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 753 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) 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:
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 525 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 55 KB, and the enlarged images are 86 to 190 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 161 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).
The Clark County Division field was drilled in the Illinois Basin in 1900; this is the first field that contains discovery date information in the PI/Dwights databases (1996, 1999) and Nehring database (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.
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 and15. 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/DwightsWell History Control System database (1996).The large 693 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/DwightsWell History Control System database (1996).The large 574 KB 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/DwightsWell History Control System database (1996).The large 774 KB 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 122 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 143 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/DwightsWell History Control System database (1996).The large 633 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/DwightsWell History Control System database (1996).The large 345 KB 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/DwightsWell History Control System database (1996).The large 502 KB image is named sildprod.jpg.
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 493 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 thethickness 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 SavertonMembers) 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 1,097 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 2,937 KB selmhga.jpg image.
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; and PI/Dwights, 1996, 1999). 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.]
|
BBO |
Percent of Total |
Locations of Generated and Produced Hydrocarbons |
|
140 |
100% |
Hydrocarbons generated from within the 400 HI contour |
|
54.2 |
38.5% |
Generated north of the Cottage Grove/Rough Creek fault system |
|
86.3 |
61.4% |
Generated south of the Cottage Grove/Rough Creek fault system |
|
4.002 |
100% |
Cumulative oil production across the basin |
|
4.158 |
100% |
Known petroleum volume across the basin |
|
2.727 |
65.8% |
Known petroleum volume within the generative basin (400 HI contour) |
|
1.431 |
34.2% |
Known petroleum volume outside the generative basin (400 HI contour) |
|
11.45 |
100% |
Original oil in place – calculated using a 36.22% recovery ratio |
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 .]
|
CN |
GENERATED HC |
CUM TOTAL |
K VOLWITHIN |
K VOL OUTSIDE |
K VOL TOTAL |
OOIP WITHIN |
OOIP OUTSIDE |
OOIP TOTAL |
PROD. WITHIN 400 HI |
|
1 |
201.4 |
3.939 |
0.0 |
4.205 |
4.205 |
0.0 |
11.61 |
11.61 |
100% |
|
2 |
12,350 |
1,196.0 |
846.1 |
402.0 |
1,248.1 |
2,336.0 |
1,109 |
3,446 |
68% |
|
3 |
47,290 |
1,014.0 |
739.1 |
300.1 |
1,039.3 |
2,040.6 |
828.7 |
2,869 |
71% |
|
4 |
15,540 |
40.92 |
12.42 |
29.82 |
42.25 |
33.22 |
79.75 |
112.9 |
29% |
|
5 |
34,600 |
0.0 |
0.0 |
0.0 |
0.0 |
0.0 |
0.0 |
0.0 |
0.0% |
|
6 |
21,680 |
712.0 |
553.4 |
175.1 |
728.5 |
1,528 |
483.3 |
2,011 |
76% |
|
7 |
8,779 |
1,037.0 |
572.6 |
504.6 |
1,077 |
1,581 |
1,393.0 |
2,974 |
53% |
|
Total |
140,400 |
4,002 |
2,723 |
1,415 |
4,158 |
7,518 |
3,920 |
11,450 |
66% |
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 petroROM Production Data on CD-ROM (through 1999). 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).
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 (1996) and petroROM 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 database 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.
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
2)Subsurface distribution and leakage of oil and gas
3)Field production practices
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.
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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.
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