Coalbed methane potential in the Appalachian states of Pennsylvania,West Virginia, Maryland, Ohio, Virginia, Kentucky, and Tennessee--An overview

Paul C. Lyons
Open-File Report 96-735

Legal, economic, and environmental constraints

Coal is both the source and reservoir of CBM. Thus, because methane could be considered in the terms ìcoalî and ìgasî, legal conflicts have arisen among surface owners, owners of coal rights, and owners of oil and gas rights. Ownership of coalbed methane has been a source of legal contention in several states (see ìWho owns the gas in coal?--A legal updateî, Farrell, 1987).

In 1977, Virginia enacted a statue that all migratory gases are the property of the coal owner rather than that of the gas lessee or surface owner. In Pennsylvania, in U.S. Steel v. Hoge, methane ownership was considered passed with the coal rights, but the landowner retained rights on the methane that migrated from the coal bed. As noted later in this paper, this migrated CBM may not be a small matter because most of the thermogenic methane generated in coal has probably migrated out of the coal and may be partly trapped in surrounding strata in tight sands or has escaped to the surface.

In 1991 with the passage of the Gas and Oil Act in Virginia, ownership rights and regulation has spurred development of CBM in Virginia (see Table 1). This act states: ìWhen there are conflicting claims to the ownership of coalbed methane gas, the Board, upon application from any claimant, shall enter an order pooling all interests or estates in the coalbed methane gas drilling unit for the development and operation thereof.î In April 1995, about 650 wells in Virginia were producing CBM (Jack Nolde, Virginia Division of Mineral Resources, Department of Natural Resources, personal commun., May, 1995). Similar laws in West Virginia and probably other Appalachian states are expected to be enacted in order to foster CBM exploration and development.

The Energy Policy Act of 1992 requires the Interior Secretary to administer a federal program to regulate coalbed methane in states where ownership disputes have impeded development (Petroleum Research Institute, 1995, p. 11). These states in 1995 included Kentucky, Pennsylvania, and Tennessee; Ohio was recently removed from the list of affected states (Petroleum Information Corporation, 1995). In the northern Appalachian basin, gas ownership and environmental problems (mainly disposal of water) have hindered CBM development (Rice, 1995).

The economic parameters for CBM development are outlined in Kuuskraa and Boyer (1993). The economics of CBM recovery is discussed at length by Rogers (1994). According to Rogers (1994), the critical factors for CBM development of Appalachian coals are gas content, permeability, and reservoir pressure. Hunt and Steele (1991b) suggested that a minimum gas content of coals of 125-150 Mcf/ton was necessary for profitable development in the Appalachian and Warrior basins. In addition, permeability of at least 0.1-0.5 millidarcies (md) are necessary to be economically attractive, but hydraulic and other types of fracturing can greatly enhance the permeability, which is particularly true for the Pittsburgh coal bed (Rogers, 1994). An additional factor in CBM recovery is the cost of water disposal.

In the Appalachian basin, lower rock pressures and shallower depths of CBM recovery, as compared with the San Juan and Warrior basins, should help keep the drilling costs down. Also, a substitution of state-of-the-art technology for stimulation treatments (see Hunt, 1991) may also enhance future CBM production in the central and northern Appalachian basin. In addition, gas prices, existing pipeline infrastructure, and proximity of the Northeastern U.S. gas markets should favor continued development of CBM in the central and northern Appalachian basin (Hunt and Steele, 1991c). Also, it is likely the demand for gas in the Northeast will increase and cost-effective CBM recoverability technology could keep CBM competitive with conventional gas prices (Steele, 1990).

Attanasi and Rice (1995) predicted on the basis of economic analysis that CBM will continue to contribute to the future gas supply of the United States. For the Appalachian basin, they suggested costs (based on 1993 prices) of about $2-6 per thousand cubic ft (Mcf) for confirmed CBM resources and about $6-9 per Mcf for hypothetical resources. In 1994 in Virginia, the average price for CBM was $2.16 Mcf, as compared with $2.29 Mcf in 1993, a slight drop in prices (Jack Nolde, Virginia Division of Mineral Resources, personal commun., March, 1996). Flaim et al. (1987, p. 153) estimated that the cost of ìCoalbed methane appears to be substantially less than exploration for conventional resources. Federal tax credits under Section 29 of the Windfall Profit Act of 1980 spurred exploration and development of CBM in the United States, particularly in the San Juan and Warrior basins (Rogers, 1994). On December 31 1992, when this tax credit end for new CBM wells drilled, major production of CBM was accomplished in the San Juan and Warrior basins, and 6,000 wells were producing CBM in the United States (Kuuskraa and Boyer, 1993). For 1981-1992, these tax credits for CBM increased with inflation from $0.25 to $0.95/Mcf. The tax credit program will continue until the end of 2002 for CBM wells drilled near the end of 1992 (Rogers, 1994).

In the central Appalachian basin, low well costs and attractive wellhead gas prices spurred development without tax supports after 1992 (Stevens et al., 1996). In the northern Appalachian basin, extremely low costs of CBM production historically have been due to shallow wells (less than 1000 ft) in an anticlinal structure (Patchen et al., 1991).

Water is an important economic and environmental factor in CBM projects. Water must be removed from the coal to lower the pressure for CBM desorption (Rogers, 1994). This is the bulk moisture that is in the cleat system of coal. In some cases, underground mining such as in the Pittsburgh coal bed, may have greatly reduced water saturation. Water disposal techniques may include well injection and discharge into surface streams. Injection wells, which require suitable formations for disposal, are the preferred method of disposal in the San Juan Basin and central Appalachian basin (Rice, 1995), whereas discharge into surface streams, after treatment in ponds to meet water-quality regulations, occurs in the Black Warrior basin (Rogers, 1994). Total dissolved solids in water in CBM wells from the central Appalachian basin have been reported at 30,000 ppm as compared with 3,000 ppm for the Black Warrior Basin (Rice, 1995).

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