6751. NORTHERN APPALACHIAN BASIN–Syncline Play (HYPOTHETICAL)
This target area for potential coalbed gas reserves is subdivided into two plays based on structure: (1) anticline (Northern Appalachian Basin–Anticline Play 6750), and (2) syncline (Northern Appalachian Basin–Syncline Play 6751). The anticline play is located on the crests and shallow flanks of the tightly folded northeast-southwest trending anticlines. Although the gas contents are generally lower because of the shallower depths and partial degassing, the permeability may be tectonically enhanced. In addition, the gas production from both desorption and from the cleats will probably be water free. All the past production of coalbed gas in the basin has come from this play. In the Big Run field, the only field where production records are available, gas was produced from generally unstimulated wells with no water. The undiscovered potential for this play is rated as good. Limiting factors are long desorption times that may affect production rates and low gas contents.
The syncline play, which covers more area, is located in the broad structural lows of the basin and below the gas-water contact. The gas contents in this play, as compared to the anticline play, will undoubtedly be higher because of the greater depth; however the gas production will be accompanied by water. In addition, the permeability values may be lower because of greater depth of burial and lack of enhancement by tight folding. Although no production has been established and the play is hypothetical, its potential for undiscovered resources is considered to be good. Possible limiting factors are long desorption times that may affect production rates and low gas contents.
Central Appalachian Basin
The Central Appalachian Basin contains one coalbed gas play, the Central Appalachian Basin Basin–Central Basin Play (6752).
Adams (1984) and Kelafant and Boyer (1988) described the geologic controls of coalbed gas potential of the Central Appalachian Basin. Summaries of reservoir characteristics and development of technology for coalbed gas in the entire Appalachian Basin are provided by Zebrowitz and others (1991) and Hunt and Steele (1992). Recovery and utilization of coalbed gas from underground mining operations in the Central Appalachian Basin is characterized by von Schonfeldt and others (1982).
The coal-bearing rocks of the Central Appalachian Basin are of Pennsylvanian age, but they are older (Lower and Middle Pennsylvanian) and thicker ( as much as 5,000 ft) than those of the Northern Appalachian Basin. The coals are assigned to formations of the Pottsville Group; the formation names and individual coal bed names commonly change across State borders. In southwestern Virginia, where commercial production of coalbed gas is taking place, the main coal-bearing interval is assigned to the Pocahontas, Lee, and Norton Formations. The Pocahontas No. 3 is the deepest (as much as 3,000 ft deep), thickest (as much as 7 ft), and most extensive seam, and the seam is the main target for both underground mining and coalbed gas development. Younger target coal beds for gas are Pocahontas No. 4, Lower Horsepen/Firecreek, War Creek/Beckley, Lower Seaboard/Sewell, and Jawbone/Iaeger (Virginia name followed by West Virginia name). The target coal beds commonly occur in the depth range of 1,500 to 2,500 ft which is considerably deeper than the Northern Appalachian Basin.
The rank of the prospective coals for gas increases to the east from medium- to low-volatile bituminous, considerably higher than the Northern Appalachian Basin. As in the Northern Appalachian Basin, the coalification pattern was probably controlled by maximum depth of burial in late Paleozoic time, which increased to the east toward the terrigenous source area. Uplift and erosion of a considerable amount of rock probably took place in early Mesozoic time.
Produced coalbed gases in the Virginia portion of the Central Appalachian Basin are composed mainly of methane with as much as 4 percent heavier hydrocarbons and as much as 2 percent CO2. Isotopic analyses indicate that the gases are of thermogenic origin.
Pennsylvanian strata dip gently to the northwest, whereas Mississippi and older strata dip to the southeast. Structural features of the Central Appalachian Basin are mainly the result of thin-skin tectonics of the Pine Mountain Overthrust Block that moved along dŽcollement zones of shale and coal generally below the Pennsylvanian coal zone. The overthrust block was transported as much as 5 mi to the northwest, which might have resulted in enhanced permeability in the overlying coals. Broad northeast-southwest folds formed prior to thrusting and close to time of deposition. Thin-skin thrusting and strike-slip faulting, which are at high angles to the thrusting, occurred during the Allegheny Orogeny (late Pennsylvanian to Permian time). The Russell Fork Fault is a prominent example of a strike-slip fault with as much as 4 mi of lateral displacement. Permeability has probably been enhanced along these faults, which might have resulted in some natural degassing of the coal beds.
In contrast to the Northern Appalachian Basin, cleat-and-joint patterns display two dominant trends that reflect two periods of structural deformation. A northeast-southwest set probably formed first and the second set (north-south) was superimposed on it during later deformation associated with movement of the Pine Mountain Overthrust Block. Some relaxation of the cleats might have occurred during Tertiary time.
Within the area of potential additions to reserves, gas contents are reported to be as high as 700 Scf/ton in the Pocahontas No. 3 coal seam, which is extensively mined underground. At equivalent depths and ranks, gas contents in the Central Appalachian Basin are much higher than those in the Northern Appalachian Basin. The variation in gas content between the two basins might be attributed to different maximum burial depths, and burial and tectonic histories. An additional factor is that the Central Appalachian coals desorb in a time period of a few days (1 to 3) as compared to the Northern Appalachian coals that commonly take a few hundred days. These shorter desorption times indicate that gas production rates from individual wells will be higher.
Reservoir pressures measured in the Pocahontas No. 3 seam are close to hydrostatic (0.35 to 0.43 psi/ft) and are higher than those reported from the Northern Appalachian Basin. The pressures may be locally lowered by underground mining activities.
Only minor amounts of water are produced from wells in the Central Appalachian Basin (several bbl/D per well). The total dissolved solids (TDS) of this water are commonly very high (greater than 30,000 ppm) and injection is required. Although precipitation is relatively abundant and some coal beds are thick and continuous, ground-water flow is restricted because the area with potential reserves is fault-bounded and the coal beds do not crop out for possible recharge.
The latest estimate for in-place coalbed gas resources of the Central Appalachian Basin for the six major coal beds (Pocahontas No.’s 3 and 4, Lower Horsepen, War Creek, Lower Seaboard, and Jawbone) is 5 TCF. Additional in-place resources are undoubtedly present in other coal seams. This resource figure is considerably lower than a range of 10 to 48 TCF, which was reported at an earlier date. The earlier large number resulted mainly from having no depth cutoff, which is critical in this area of high relief where coal beds commonly crop out on hill sides and have probably degassed.
Major quantities of coal are mined in the Central Appalachian Basin, both underground and on the surface. Five counties (Pike, Kentucky; Mingo, Boone, and Logan, West Virginia;, and Buchanan, Virginia) are in the top ten mining counties in the United States based on 1991 statistics, and Buchanan County, Kentucky, was fourth in the country in terms of total tonnage from underground mining. The majority of the underground mining is in the Pocahontas No’s. 3, and 4, and Beckley seams. West Virginia and Virginia ranked number. 1 and 3, respectively, in the United States in 1988 for methane emissions from underground mines. However, parts of West Virginia are located in both the Northern and Central Appalachian Basin.
As is the case with the Northern Appalachian Basin, there have been several cooperative projects between mines and Federal agencies during the past 20 years to produce coalbed gas, most of which were marginally successful and information is not readily available. The cooperative projects were a result of the need to degasify the underground coal mines. Much of the early technology (horizontal and gob wells) to degas underground mines was actually developed in the Virginia part of the basin.
In the Central Appalachian Basin, the State of Virginia and the Federal government in 1990 adopted a version of “forced pooling” to reduce the obstacle created by uncertainty of gas ownership. This “forced pooling” procedure in Virginia resulted in a dramatic increase in the development and production of coalbed gas during the period of 1990 to 1993. In 1992, southwest Virginia had more than 280 coalbed wells that produced about 10 BCF. These wells were completed mostly in the Nora and Oakwood fields and were drilled both in association with and away from underground coal mines. As of 1993, the coalbed gas reserves in Virginia are estimated to be about 220 BCF. West Virginia has recently passed legislation regulating, and perhaps encouraging, the development of coalbed gas.
The prospective area for coalbed gas in the Central Appalachian Basin is underlain by oil and gas fields and an infrastructure for these hydrocarbons is in place. Over the past couple of years, many miles of pipeline have been constructed in southwestern Virginia for the collection of coalbed gas from many wells, which have been drilled and are producing in association with and away from underground coal mining.
The topography of the Central Appalachian Basin is characterized by considerable relief (as much as 1,500 ft), and many of the coal seams crop out along hillsides or are less than 500 ft below drainage. This condition severely limits the coalbed gas potential to about 20 percent (5,000 sq mi in West Virginia and Virginia) of the total area. One play is identified in the Central Appalachian Basin, and it is confined to that area where coal beds have gas contents of at least 86 Scf/t and reservoir pressures of at least 215 psi. These values correspond to depths of burial greater than 500 ft. The play area (5,000 sq mi) represents approximately 22 percent of the total coal-bearing part of the Central Appalachian Basin and the gas is contained in about 15 percent of the coal reserves.
6752. CENTRAL APPALACHIAN BASIN–central Basin Play
The play can be divided into two areas based on the total gas in place per section, which is the result of coal thickness, depth, and gas content. In the central area, the coal beds are thick and occur at depths greater than 1,000 ft deep indicating higher gas content. In this area, gas in-place is as much as 5 BCF per sq mi. The Nora and Oakwood fields of southwest Virginia are located within this area.
The other area surrounds this central part, and the major seams, such as the Pocahontas No. 3 and 4 and War Creek, are thinner and shallower. The gas in-place volume is less than 1 BCF per sq mi. Only a few wells, which are in Roaring Fork field, have been drilled in this play, and it is essentially undeveloped. The undiscovered potential for this play is considered to be good, although the production rates for individual wells will probably be lower than for the central area. The potential for additions to reserves for this entire play is considered to be very good.
The fourth coalbed gas play in the Appalachian Basin province (067) is the Cahaba Coal Field play (6753) in the Cahaba Basin.
Coalbed gas potential of the Cahaba Basin is described by Telle and Thompson (1987) and Pashin and Carroll (1993). Production information for the basin’s only field, Gurnee, is commonly reported with the Black Warrior Basin.
The Cahaba Basin contains one of the principal coal fields within the Appalachian Thrust Belt, a foreland thrust system. To date, most development of coalbed gas has taken place in gently deformed foreland basins, such as the adjacent Black Warrior Basin. The Cahaba coal field, although small in size, provides an example from another tectonic setting where the potential for coalbed gas exists, but its controls reflect an interaction between sedimentation, tectonism, and coalification.
The coal field is situated along the southeast side of the northeast-southwest trending Cahaba Basin which is part of an Alleghenian Thrust Sheet. Thrusting probably occurred near the margin of a relict rift basin. The basin is bound on the northwest by the Birmingham Anticlinorium and on the southeast by the Helena Thrust Fault. The basin was an actively subsiding depression behind an uplifting thrust ridge during deposition of Lower Pennsylvanian Pottsville Formation.
The Lower Pennsylvanian Pottsville Formation is the principal coal-bearing interval in the Cahaba coal field. A comparison of the Pottsville section in the adjacent Black Warrior Basin with that in the Cahaba coal field indicates a different depositional history in the Cahaba area, which is related to syndepositional tectonism (subsidence and thrusting). In the Cahaba, the Pottsville is as much as 9,000 ft thick and can be divided into a lower quartz-arenite measures, middle mudstone measures, and an upper conglomerate measures. It contains 20 informal coal zones and as many as 60 individual beds. About 25 beds are thick enough to be of economic importance, and they are primarily in the mudstone measures. Individual beds are as much as 7 ft thick and the net coal thickness can be more than 45 ft thick. Some of the economically important coal zones, in ascending order, are the Gould, Harkness, Wadsworth, Coke, Gholson, Thompson, Montavello, and Maylene.
Coals at the surface in the Cahaba field are high-volatile A bituminous rank, and the rank increases to the southeast. Rank also increases with depth; in the southeast part of the basin the rank of the coal is low-volatile bituminous at 9,000 ft. The rank of these deeper coals increases to the northwest. The diverse relation between rank patterns and structure indicates a complicated burial and thermal history. The main coalification phase occurred during time of maximum burial and thrusting. However, this regional coalification pattern is overlain by a significant post-tectonic component. This post-tectonic coalification resulted from meteoric recharge in the shallow coal beds and from expulsion of warm orogenic fluids during thrusting in the deeper coalbeds.
Although biogenic gas was probably generated in the shallower coal beds, thermogenic gas was generated in deeper coal beds (greater than 2,500 ft) in the structurally deeper parts of the basin. The best potential for thermogenic gas probably occurs in the coal beds of the mudstone measures.
Strata in the Cahaba Basin dip gently to the southeast. The southwest part of the coal field contains numerous folds. The field narrows to the northeast where en echelon folds and thrust faults occur in the center of the synclinorium.
In most foreland basins, rectilinear face-butt cleat systems are dominant. These cleats form in a tensile stress field and gas and water are able to flow through them. However, inclined fractures, which result from shearing by structural slip, are abundant in the folded coal beds of the Cahaba coal field. These fractures strike roughly parallel to bedding and dip approximately 60¡ to bedding. The fractures are best developed where the bedding is dipping steeper than 15¡. Thrust faults and associated folds are also common in the dipping coal beds, but, as is the case with the inclined fractures, they do not penetrate the bounding sandstone and mudstone. The ability of gas and water to flow through compressional fractures in thrust belts, such as the Cahaba coal field, is not well understood. However, similar inclined fractures do produce coalbed gas in the Black Warrior Basin along the Blue Creek Anticline.
The desorbed gas contents measured in a core hole in the southeast part of the Cahaba coal field were as much as 380 Scf/t and show a relation between rank and depth. Because of the complex burial and thermal history of the basin, more measurements and modeling of gas contents will be required for basin-wide evaluation. On the basis of the measured gas content values and the estimated coal resources by depth, rank, and location, about 2 TCF of in-place coalbed gas resources have been estimated for the basin with the highest resource potential occurring in the southeast part of the basin.
Although some coal is being mined on the surface, no underground mining has taken place in the Cahaba coal field for a number of years. Most of the underground mining was in the southeast part of the basin where the coal rank is higher.
Coalbed gas production was established in the Gurnee field in 1990, the only degasification field in the coal field. In 1993, 64 wells produced about 432 MMCF of coalbed gas. In comparison, 140 wells produced about 542 MMCF of coal gas in 1992.
6753. Cahaba Coal Field play
Only one coalbed gas play is identified in the Cahaba Basin, the Cahaba Coal Field play, and it coincides with the areal extent of the Pottsville Formation. On the basis of the structural complexity of the coal field and the production histories of the existing wells to date, the play is estimated to have fair potential for additional reserves of coalbed gas. However, more detailed studies are needed on foreland thrust systems, such as the Cahaba, to understand the geologic factors controlling the development of potentially large resources of recoverable coalbed gas.
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