Injection of carbon dioxide into unmineable coal seams is a promising technology for reducing anthropogenic gas emissions and increasing ultimate recovery of coalbed methane. The combination of incremental methane produced and possible tax incentives might compensate for the costs associated with CO2 injection.

Currently the U.S. Department of Energy (DOE) is co-funding a pilot CO2 sequestration and enhanced coalbed methane (ECBM) project in the Appalachian Basin, in a thin coal seam. Horizontal wells have been drilled in the seam to increase CO2 injectivity and methane production rate. Previously, the reservoir simulations we performed for the planned pilot pattern indicated an optimum length for the horizontal injectors to maximize methane recovery and CO2 storage. By varying operational parameters such as time of primary production, injector length, injection pressure, injection timing, and production well pressure, we can evaluate different production alternatives to determine possible tradeoffs between optimum recovery of methane and CO2 sequestration, as defined by the amounts of the gases injected or produced.

The economics of an ECMB/sequestration project using horizontal wells are sensitive to the design parameters. In commercial practice it is necessary to select a design that maximizes the economic return. In the work presented here, net present value (NPV) was used to optimize the economics of the project. The evaluation used actual design parameters, current costs to equip the field for CO2 injection, and operating costs in the actual price range of ongoing projects: coalbed methane (CBM) and CO2 enhanced oil recovery. Methane recovery and CO2 injection data were obtained from our reservoir simulations. The economic impact of tax incentives was also considered in the analysis.

The analysis demonstrates the significance of reservoir size, proper design and implementation, and tax incentives for economic viability of projects for enhanced coalbed methane production and coalseam sequestration.


Coalbed methane reservoirs are characterized as nonconventional gas resources due to the specific nature of gas storage and fluid production. Proved coalbed methane reserves have been estimated at 18.5Tcf, representing 10% of the total natural gas reserves in U.S. Coalbed methane production started in early 1980's as small, high cost operations but reached 1.6Tcf in 2002, representing more than 8% of total U.S. natural gas production1.

The large majority of CBM reservoirs are operated in primary mode, by first pumping significant volumes of water to lower reservoir pressure and to allow methane desorption2. The primary depletion process typically recovers between 20- 60% of the original gas in place, leaving a considerable amount of gas behind3. Consequently, new technologies have been proposed for enhanced coalbed methane (ECBM) production. One of these technologies is based on the injection of carbon dioxide in the reservoir. Carbon dioxide-ECBM has similarities to CO2 tertiary flooding, one of the most successful enhanced oil recovery (EOR) methods in the U.S. and worldwide4. However, the displacement and CO2 storage mechanisms are different.

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