Source rocks: Stratigraphically, the source rocks of these autogenic shales are the same as the reservoirs. In general, the greatest amount of organic carbon in the shale sequence (2 percent or more) extends in a broad band northward from eastern Kentucky and adjacent West Virginia into central Ohio (Schmoker, 1993). On the western side of the Appalachian Basin, kerogen types I and II predominate, indicating that their principal sources were algae or marine biota (Zeilinski and McIver, 1982). On the eastern side of the basin, woody and coaly types predominate (type III), and by using carbon isotopes Maynard (1981) showed that the only likely source of this land-derived carbon was to the east. In general, Ro values of vitrinite increase from about 0.5 to 2.0 percent eastward across the Appalachian Basin (Maynard, 1981; Schmoker, 1993). In the productive areas in Virginia, Kentucky, and West Virginia, Ro values range from about 0.6 to 1.5 percent.
Timing and migration of hydrocarbons: Depending on location within the Appalachian Basin, generation of hydrocarbons probably occurred during maximum burial late in the Pennsylvanian, and westward migration of hydrocarbons probably occurred during thrust loading of the eastern side of the basin during the Alleghenian deformation.
Traps: The Devonian gas shales are best described as regional accumulations having variable production characteristics. Production depths may range from several tens of feet to several hundreds of feet in some areas, such as in the Lake Shore fields, to 5,000 feet or more in the deeper parts of the play in southwestern Virginia. Evidence from drilling indicates that zones of decollement and associated extensional and contractional fractures are much more likely to be present within the kerogen-bearing black shales rather than in the interbedded gray shale and siltstone (Young, 1957; Milici, 1993). Productive horizons thus are separated from one another and sealed by less fractured fine-grained siliciclastic units having relatively low carbon content.
Exploration status: The Devonian Black Shale Gas plays are the oldest gas plays in the United States. The first well drilled for gas in the United States was drilled in Fredonia, New York, in 1821, in shale beds overlying the black Dunkirk Shale (deWitt and others, 1993). Since then, Devonian shales have yielded about 3.0 TCFG, and it is estimated that recoverable reserves are about 20 TCFG (Charpentier and others, 1993).
At present, gas is produced from Devonian and Mississippian black shales from three general regions, as well as from numerous scattered localities in the Appalachian basin. A major producing area in southernmost Ohio, eastern Kentucky, southwestern West Virginia, and southwestern Virginia includes the Big Sandy gas field and several nearby smaller fields. This area constitutes the Greater Big Sandy Gas Play (Play 6470), the most productive shale-gas play in the Appalachian Basin. In this area, the cumulative thickness and organic richness of the black gas shales within the Devonian shale sequence is relatively great. Although the kerogen is generally oil prone in this part of the Appalachian Basin, natural gas is commonly produced instead of oil because of the relatively low thermal maturity of the source beds in this area. Abundant decollement-related fracture porosity is an essential characteristic of the reservoir, and these fractures provide the permeability necessary for the gas to migrate to the well bore. More than 10,000 wells were drilled and produced more than 2.5 TCFG from the Big Sandy gas field between 1921 and 1985 (Hunter and Young, 1953; Brown, 1976; Charpentier and others, 1993).
An extension of the Big Sandy producing area is present to the north, in West Virginia, and is called "the emerging area" by Patchen and Hohn (1993). The "emerging area" of Patchen and Hohn (1993) in western West Virginia extends into nearby counties in southeastern Ohio. For the purposes of this assessment, this shale-gas play is characterized by its greater siltstone content (play 6741). It is of considerable economic interest for exploration, however, primarily because it produces oil as well as gas from the Devonian shale sequence. The occurrence of both liquid and gaseous hydrocarbons in the Devonian shale sequence in this region is a result of the almost unique coincidence of suitable source rock composition, thermal maturity, matrix porosity in fine-grained siliciclastics, and abundant fracture porosity (Zielinski and McIver, 1982). In general, the Upper and Middle Devonian stratigraphic sequence in this area contains a significant stratigraphic component that has a relatively low organic content. The black and gray shale formations, rich in organic matter, are interstratified (diluted) with gray and greenish-gray shales and siltstones, and in places, with very fine-grained sandstones, all relatively lean in organic matter. As a result of this overall low content of organic matter, this play may ultimately prove marginal or non-commercial.
Low-pressure fields have been producing gas from fractured Devonian shales in the Lake Shore fields for than 100 years in an area of relatively low thermal maturity (play 6742). Almost all of northern Ohio and adjacent parts of Pennsylvania and nearby New York were subjected to several episodes of continental glaciation within the last 1,000,000 years during the Pleistocene Epoch. White (1992) suggests that ice as thick as 4,000 to 6,500 ft effectively produced a decollement in Silurian salt measures that resulted in the formation of southeastward verging salt-cored anticlines around the periphery of the Laurentide ice lobe. Indeed, glacial loading and post-glacial isostatic rebound in the gas-producing regions to the south of the Great Lakes appears to have created the fractured pathways for gas to have migrated from black shale source rocks into intercalated brittle silty and sandy reservoirs, as well as to have fractured and enhanced the storage capacity of these reservoirs. Drilling commenced in Pennsylvania in the 1850's and was extended into Ohio a decade later (Janssens and deWitt, 1976). Hundreds of wells have been drilled, chiefly for domestic production. In general, initial production ranges from 1 to 50 MCF/D. The wells decline slowly and may produce gas for 50 years or more. Production is probably from silty and sandy zones within the shale sequence, and fracture porosity is of secondary importance (Broadhead, 1993).
Resource potential: The Devonian Black Shale Gas plays are a regional accumulation that has produced moderate quantities of natural gas over many years. Reserves previously estimated are large, and their future production depends primarily on the economics of the natural gas industry and on improved technology for production of the gas. Most favorable areas are those having relatively high amounts of organic matter, suitable thermal maturation, and naturally enhanced fracture porosity. A dozen or more shale-gas wells were drilled in western Pennsylvania to the south of the Lake Shore fields during the late 1970's and early 1980's. Although most of these wells either produced natural gas or have the potential to produce gas from the Devonian shale and siltstone sequence, the area is relatively untested (play 6473). In addition, Milici (1993) identified two relatively large, untested areas in northeastern Ohio and western Pennsylvania that initially, at least, may be favorable for exploration.
6725. Mississippian and Pennsylvanian sandstone/carbonate play
The Mississippian and Pennsylvanian Sandstone/Carbonate Play is defined by oil and gas trapped in shallow-marine sandstone and shelf limestone by facies-change stratigraphic traps, combination traps, unconformity traps, and local anticlinal traps. Stratigraphically, the play involves numerous formal and informal sandstone units and several limestone units. Among the important reservoirs are the Lower Mississippian (recently changed to Upper Devonian) Berea Sandstone (Ohio, West Virginia, Kentucky, Virginia), Lower Mississippian (recently changed to Upper Devonian) Murrysville Sandstone (Pennsylvania), bioherms in the Lower Mississippian Fort Payne Formation (Tennessee), Lower Mississippian Big Injun, Squaw, and Weir sandstones (West Virginia, Ohio, Kentucky), Upper Mississippian Greenbrier and Newman Limestones (West Virginia, Kentucky), Upper Mississippian Monteagle Limestone (Tennessee), Upper Mississippian Mauch Chunk and Pennington Formations (Kentucky, Pennsylvania, West Virginia), Upper Mississippian Ravencliff Sandstone Member of the Hinton Formation (West Virginia, Virginia), Lower and Middle Pennsylvanian Salt sands of the Lee Formation (Kentucky, West Virginia), Lower and Middle Pennsylvanian sandstone of the Pottsville Formation (Pennsylvania), Upper Pennsylvanian Cow Run Sandstone (Pennsylvania, Ohio, West Virginia, Kentucky), The previously named sandstone and limestone reservoirs are combined into a single play because they occupy the uppermost part of the sedimentary section in the basin that has been penetrated by hundreds of thousands of drill holes. Subdividing this highly explored sedimentary sequence into numerous plays seems unnecessary in view of the small number of undiscovered oil and gas fields, greater than 1 MMBO and 6 BCFG in size, that remain.
The play covers parts of Pennsylvania, Ohio, West Virginia, Maryland, Kentucky, Virginia, Tennessee, Georgia, and Alabama. The eastern and northern boundary is defined by the erosional limit of Mississippian strata. Several isolated coal basins, east of the erosional limit, in northeastern and south-central Pennsylvania and east-central Alabama, are included in the play. The western boundary of the play is marked by the western boundary of the Appalachian Basin Province (067), except in Ohio where it is marked by the erosional limit of Mississippian strata. The play is confirmed and the sandstone and limestone reservoirs are conventional.
Reservoirs: Very fine to medium grained sandstone and pebbly coarse-grained sandstone, classified as litharenite, sublitharenite, and quartzarenite, constitute the sandstone reservoirs in the play. Primary intergranular porosity, although reduced somewhat by silica, dolomite, and calcite cement and authigenic clay minerals, is the dominant porosity type in the play; however, secondary intergranular porosity, created by the dissolution of cements and detrital grains such as feldspar and metamorphic rock fragments, is also important. Porosity for sandstone reservoirs in the play ranges from 3 to 25 percent and averages between 6 and 18 percent, depending on the age, composition, and drilling depth of the reservoir. Permeability ranges from <0.1 mD to several hundreds of millidarcies and averages between 6 and 10 mD. The average thickness of the producing part of the sandstone reservoir is between 10 and 15 ft. Drilling depths to the sandstone reservoirs range from 1,500 to 3,000 ft but are as great as 5,000 ft in the eastern parts of the play area.
Carbonate reservoirs in the play consist of oosparite, crinoidal bioherms, vuggy dolomite, and crystalline dolomite. Commonly, the limestone and dolomite reservoirs in the Greenbrier/Newman Limestone (Big Lime) contain 20–30 percent of very fine to fine grained quartz sand. Vuggy, intercrystalline, oomoldic, and intergranular (oolitic) porosity are the common porosity types in the limestone and dolomite reservoirs. Locally, fracture porosity has been identified. Porosity for carbonate reservoirs in the play ranges from 2 to 24 percent and averages between 6 and 14 percent, depending on the rock type, porosity type, and drilling depth of the reservoir. Permeability ranges from 0.1 to about 50 mD and averages between 1 and 4 mD. The average thickness of the producing part of the carbonate reservoir is between 9 and 18 ft. Drilling depths to the carbonate reservoirs range from about 1,500 to 2,000 ft.
Source rocks: The sources of oil and gas in the play are the Middle Devonian Marcellus Shale, Upper Devonian black shales and the Lower Mississippian Sunbury Shale. The Middle and Upper Devonian black shale sequence in the northern part of the play is between 50 and 500 ft thick and has TOC values between 3 and 5 percent. In the Tennessee and Alabama part of the play the Upper Devonian and Lower Mississippian black shale sequence is between 25 and 50 ft thick and has TOC values between 5 and 10 percent.
Vitrinite reflectance data indicate that Middle and Upper Devonian and Lower Mississippian source rocks in the play have achieved several levels of thermal maturity. Devonian and Mississippian source rocks in northwesternmost Pennsylvania, east-central Ohio, western West Virginia, southeastern Kentucky, east-central Tennessee, northwesternmost Georgia, and northeastern Alabama are in the zone of oil generation. Devonian and Mississippian source rocks in the zone of oil generation are flanked on the east by Devonian and Mississippian source rocks in the zone of gas generation that extends from northwestern Pennsylvania, through northern and central West Virginia, to southwestern Virginia. In southwestern Pennsylvania, western Maryland, and eastern West Virginia, Devonian and Mississippian source rocks are overmature with respect to the generation of oil and gas, whereas, in central Ohio and northern Kentucky, Devonian and Mississippian source rocks are immature with respect to the generation of oil and gas. Oil and wet thermal gas are the expected hydrocarbon types in the play.
Timing: Peak oil and gas generation from the Middle Devonian, Upper Devonian, and Lower Mississippian black shale sequences occurred between Late Pennsylvanian and Early Triassic time when the sequences were buried under an eastward-thickening wedge of orogenic sediments. Oil and gas migrated short distances laterally and upsection to the sandstone and carbonate reservoirs. A variety of facies-change stratigraphic traps, combination traps, diagenetic traps, truncation traps, and local high-amplitude anticlines were available to trap the oil and gas.
Traps: Facies-change stratigraphic traps, commonly in combination with subtle anticlinal flanks, anticlinal noses, and diagenetic traps, are the most important traps in the play. Locally important traps are anticlinal closure and truncation traps situated above and below unconformities. Seals for the traps are shale, siltstone, and micrite in the Mississippian and Pennsylvanian sequence.
Exploration status: Oil and gas in the play were first discovered in Beaver County, Pennsylvania, in 1859, the same year that the Drake well was completed. In the 1860's, most of the exploration drilling was concentrated in southwestern Pennsylvania (Beaver, Greene, and Lawrence Counties), southeastern Ohio (Gallia, Meigs, Morgan, and Washington Counties), and northern West Virginia (Hancock, Marion, Monongalia, Pleasant, Ritchie, and Wirt Counties). Most of the fields discovered in the 1860's produced oil and gas from a variety of sandstone reservoirs of Pennsylvanian age and a few sandstones of Mississippian age. The first field in the Kentucky part of the play was discovered in Knott County in 1892. By the turn of the century, approximately 125 fields had been discovered in the play.
Lower Mississippian sandstone reservoirs and Upper Mississippian carbonate reservoirs were the chief exploration objectives in the play in the early 1900's. Most oil fields in the trend were identified by the early 1930's and many of the larger fields were exploited using secondary recovery techniques, mainly water flooding, in the 1930's and 1940's. Nonassociated gas fields and a few oil fields continued to be discovered in the play in the 1950's and 1960's. Exploration in the play was rejuvenated in 1969 with the discovery of oil in bioherms of the Lower Mississippian Fort Payne Formation, Scott County, Tennessee. About 7 or 8 Fort Payne Formation oil fields greater than 1 MMBO were discovered in east-central Tennessee in the 1970's and early 1980's.
Approximately 900 to 1,000 oil and (or) gas fields have been discovered in the play since 1859. Many of these fields have commingled oil and (or) gas production from Upper Devonian sandstone and Upper Devonian black shale, but production from Mississippian and (or) Pennsylvanian reservoirs is dominant. Parts or all of about 35 fields in the play have been converted to gas storage facilities. The exploration phase of the play is almost complete, and most of the current drilling consists of infill wells that add small amounts of oil and gas to existing fields. Many of the sandstone and carbonate reservoirs in the play have tight formation status.
Among the largest oil fields in the play are Fairview-Statler Run-Mt. Morris (Monongalia and Marion Cos., W.Va.), discovery date 1890, ultimate recovery ~23 MMBO; Blue Creek (Kanawha Co., W.Va.), discovery date 1911, ultimate recovery ~19 MMBO; and Sistersville (Tyler Co., W.Va.), discovery date 1890, ultimate recovery ~15 MMBO.
Resource potential: This play has potential for a small number of oil and gas fields greater than 1 MMBO or 6 BCFG; however, the shallow drilling depths of the reservoirs and the high drilling density in the play area suggest that the play is almost exhausted. Most undiscovered fields greater than 1 MMBO or 6 BCFG are probably located along the eastern margin of the play where drilling has been less intense.
Coalbed Gas Plays
By Dudley D. Rice and Thomas M. Finn
For the purposes of coal geology, the Appalachian Basin province is divided into three northeast-southwest trending basins: Northern, Central, and Cahaba (plays 6750 through 6753). The Northern Appalachian Coal Basin covers an area of approximately 30,000 sq mi and is located in parts of five States–Pennsylvania, West Virginia, Ohio, Kentucky, and Maryland. The Central Appalachian Coal Basin is smaller (about 23,000 sq mi) and occupies parts of Tennessee, Kentucky, Virginia, and West Virginia. The Cahaba Basin is a small, tectonically complex area located within the Appalachian Thrust Belt of Alabama.
Northern Appalachian Basin
The Northern Appalachian Basin is divided into 2 coalbed gas plays, the Northern Appalachian Basin Anticline Play (6750) and the Northern Appalachian Basin Syncline Play (6751).
A geologic overview of the coalbed gas potential of the Northern Appalachian Basin is given by Kelafant and others (1988), Patchen and others (1991), and Schwietering and others (1992). Zebrowitz and others (1991) and Hunt and Steele (1992) provide summaries of reservoir characteristics and technology development for coalbed gas in the entire Appalachian Basin. Diamond and others (1993) described production of coalbed gas associated with underground coal mining.
The coal-bearing interval of the Northern Appalachian Basin is the Pennsylvanian Allegheny, Conemaugh, and Monongahela Groups and the Permian Dunkard Group. The main targets for coalbed gas are seams assigned to, in ascending order, the Clarion/Brookville, Kittanning, Freeport, Mahoning, Pittsburgh, Sewickly, and Waynesburg Coal Groups. Each of these coal groups may contain several individual coal seams that were deposited mainly in a fluvial environment. Data from oil and gas wells indicate that the cumulative coal thickness of all the groups ranges from 10 to 19 ft. The Pittsburgh seam is the thickest (as much as 12 ft), most widespread, and has been mined extensively underground. Many of the coal groups show a eastward trend of increasing number and thickness of individual coal seams. In comparison, data from some proprietary coreholes in West Virginia indicate that the average thickness of the coals more than 2 ft thick over this same interval is greater than 25 ft. Although the coal beds are as deep as 2,000 ft in the basin, the target coal beds for coalbed gas are generally in the depth range of 500 to 1,200 ft.
Coal rank in the basin increases in an eastward direction from high-volatile B bituminous to low-volatile bituminous; a large portion of the coal is actually high-volatile A bituminous in rank. In general, coalification probably resulted from maximum burial during late Paleozoic and early Mesozoic at which time thermogenic gases were generated. However, along the Allegheny Structural Front localized areas of higher rank may have been controlled by advective heating due to fluid flow. As much as 9,000 to 10,000 ft of Permian and Pennsylvanian strata have probably been eroded starting in early Permian time. This uplift and erosion resulted in degassing of some of the original coalbed gas, particularly at shallow depths.
The coalbed gases, as determined from desorbed samples, are composed mostly of methane with variable amounts of CO2 (as much as 10 percent). The gases are probably of thermogenic origin, although some mixing of relatively recent biogenic gas may have occurred.
Coal-bearing Pennsylvanian strata were folded into many northeast-southwest trending anticlines, which are parallel to the trend of the basin, during the main phase of the Allegheny Orogeny (Permian through Triassic time). Face cleats are oriented perpendicular or at high angles to the axes of the anticlines (NW-SE). Because the cleats are perpendicular to bedding, even on steeply dipping limbs of folds, they probably formed prior to the main phase of the Allegheny Orogeny.
Gas contents in the Northern Appalachian Basin generally vary according to rank and depth. Although gas contents as high as 400 Scf/ton have been reported, the values are generally less than 200 Scf/ton because of the low rank (high-volatile A bituminous) and relatively shallow depths (generally less than 1,200 ft). In addition to having relatively low gas contents, coals from the Northern Appalachian Basin have longer desorption times (as much as 600 days) as compared to those from other productive basins.
Coalbed gas and conventional oil and gas reservoirs are usually underpressured as compared to hydrostatic pressure (average 0.3 psi/ft). This underpressuring is probably the result of extensive underground coal mining and/or partial degassing of original thermogenic gas.
Information on coalbed hydrology is limited. However, in Indiana County, Pennsylvania, several wells produce water at rates up to 200 barrels per day. The water is supposedly potable, and a permit has been issued for surface discharge.
The in-place coalbed gas resources of the Northern Appalachian Basin in coal beds greater than 1 ft thick and deeper than 300 ft are estimated to be about 61 TCF. The majority of this resource is concentrated in the deeper Brookville/Clarion, Kittanning, and Freeport coal groups. This represents, by far, the largest in-place coalbed gas resource in the Paleozoic coal-bearing provinces of Central and Eastern United States (Eastern Interior and Midcontinent regions). However, the economic recoverability of the resource may be adversely affected in this basin by the long desorption time which will probably result in lower production rates.
Major quantities of Pennsylvanian coal are mined underground in the Northern Appalachian Basin and large amounts of methane are emitted in the process. Greene County of Pennsylvania and Monongalia County of West Virginia are two of the top five underground mining counties in the U.S. based on 1991 tonnage statistics. Large mined-out areas occur in the Kittanning, Freeport, and Pittsburgh Coal Groups, particularly in the Pittsburgh, which is the shallowest of these three groups. Some of the largest coal mine emissions rates in the United States have been documented from the Pittsburgh mines in north-central West Virginia. In 1988, West Virginia and Pennsylvania were ranked first and fourth, respectively, in terms of methane emissions from underground mines. In West Virginia, emissions were from both the Northern and Central Appalachian Basins.
The history of coalbed gas production in the Northern Appalachian Basin goes back at least 50 years. Gas was produced from the Pittsburgh coal bed in the Big Run field in Wetzel County, West Virginia starting in 1932. More than 2 BCF of coalbed gas was produced from the field until 1988. Four other gas fields and pools are also reported to have produced coalbed gas: Oakford, Gump, and Waynesburg in Pennsylvania and Pine Grove in West Virginia. During the 1970’s and 1980’s, the Bureau of Mines and Department of Energy, in association with mining companies, undertook a variety of projects directed toward development of the coalbed gas resource. These projects were only marginally successful because of low production rates (generally <100 MCFGPD) and technical problems, including attempted production from only a single coal seam and inadequate reservoir stimulation. Current activity is limited to one project in Indiana County, Pennsylvania, where 20 wells were drilled in 1992. Six wells were put on production, which was characterized by high water rates initially (as much as 200 bbl/D per well). In addition to technical problems, the development of coalbed gas in the Northern Appalachian Basin has been hindered by questions of gas ownership (coal versus gas rights) and environmental problems, mainly disposal of water.
Much of the Northern Appalachian Basin is underlain by shallow gas fields, with reservoirs of Mississippian and Pennsylvanian age that have been producing for many years. Therefore, an infrastructure is in place for the development of the shallow coalbed gas resource.
The area of potential Pennsylvanian coalbed gas reserves in the northern Appalachian coal basin corresponds with the area where the Kittanning Coal Group has more than 0.5 BCF/sq mi in-place which generally corresponds to depths of burial greater than 300 ft. The Kittanning has the largest in-place resources of coalbed gas in the basin, and the areas of potential reserves for other coal zones are generally within this same Kittanning area.