Coalbed Methane Reservoir
Coalbed methane and Devonian shale reservoirs are considered unconventional reservoirs in that methane gas is stored in micropores and bedding planes, as well as free gas within natural fractures or cleats (Mavor, 1997). These reservoirs act both as the source rock and storage reservoir for methane gas. Coalbed methane is peculiar in that methane and carbon dioxide are predominantly stored in a molecular adsorbed phase within micropores of the coal. High-cost natural gas produced from deep (greater than 15,000 feet) low permeability sands may also be termed unconventional, as may gas produced from geopressured (initial reservoir pressure exceeding 0.465 psi/vertical foot of depth) brines (greater than 10,000 ppm total dissolved solids). In comparison, conventional gas reservoirs contain gas molecules within interstitial porespaces, for example between sand grains in a sandstone reservoir, and in fractures. Gas trapped in a conventional reservoir generally is considered to have migrated from its place of genesis to a different geologic zone or horizon into the reservoir rock.
The ability of the coalbed reservoir to store methane is dependant upon numerous factors: reservoir pressure, composition and rank of the coal, micropore structure and its surface properties, the molecular properties of the adsorbed gas constituents, and reservoir temperature (Mavor, 1997). Coalbeds are an attractive prospect for development because of their ability to retain a higher amount of gas at shallow depths in comparison to conventional reservoirs at comparable depths and reservoir pressures. Coalbed methane (CBM) wells are drilled with techniques similar to those utilized for drilling conventional wells, but completion practices and the method of reservoir evaluation are different. The BLM has adopted COGCC order No. 112-61, which requires that the production casing of all coal-bed methane wells be cemented from producing horizon to surface by grout circulation methods. The intent of requiring this extensive primary cementing is to minimize or preclude inter-zonal flow of fluids between producing horizons and aquifers within the casing annulus. Today, coalbed gas wells are usually completed for production in one of two different manners. By altering the velocity of the gas escaping from the coal reservoir, the so-called “cavitation method” creates a cavity in the targeted coal seams, effectively enlarging the original well bore. The increased well-bore volume promotes linking the well bore with the natural fracture system of the coalbeds (Appendix C: Chart 5). The second method involves conventional completion techniques in which individual or multiple coals are hydraulically fractured by pumping water or other fracture-inducing fluids and fracture-sustaining material under high pressure through pipe perforations into the coalbeds (Appendix C: Chart 6). Since methane gas is stored (adsorbed) on micropores of the coal, and storage is a function of pressure (the higher the pressure the greater the storage potential), production of coalgas is dependent upon reduction of pressure within the coalbeds. Methane can be produced from the coalbeds by reducing overall reservoir pressure or by reducing the partial pressure of the methane alone, while sustaining reservoir pressure. Pressure reduction frees the methane molecules from the coal and allows gas migration. A reduction of reservoir pressure is most often accomplished through formation water removal by walking beam pumps, (Figure 2 following page) submersible pumps, piston lift or gas lift)
Water/gas separators used for conventional gas production were modified to accommodate copious amounts of produced water and associated coal fines. The produced water is often fresher (lower dissolved solids) than is characteristic of the relatively small amounts of produced water derived from conventional gas reservoirs. With hydrostatic pressure reduction at depth, methane gas is desorbed from the coal and is free to migrate through permeable strata, cleats and fractures to an area of lower pressure, ideally into the well bores that created the pressure reduction. In near-surface coal outcrops, hydrostatic pressure reduction may allow locally desorbed coalgas to migrate entrained with groundwater or rise vertically through porous soils to the surface.
As coalbed water is withdrawn and formation pressure declines, the volume of gas produced tends to build from a low initial rate to a maximum rate several years after the onset of production (Appendix C: Charts 7a, 7b). The progressively increased gas production rate to a maximum flow years later is in direct contrast with conventional pressure-depletion reservoirs from which gas production rates tend to be greatest at the onset, then steadily decline over the life of the well (Appendix C: Chart 8). Decreasing reservoir pressure below 150 psi is not currently considered economic. While a reduction in reservoir pressure frees the methane from the coal, greatly reduced pressure may deprive the fluids of the energy needed to migrate efficiently to the well bore and enable desorption of increasing proportions of carbon dioxide. It is estimated that less than 50 percent of the coalbed methane in place can be economically recovered by reservoir pressure depletion strategy (Puri and Yee, 1990). In areas of the San Juan Basin where reservoir factors do not allow the production of coalgas in economic quantities by pressure depletion methods, enhanced production techniques have been applied. One of these techniques introduces nitrogen under high pressure through injector wells into individual coalbeds. Methane desorption is achieved by nitrogen sorption displacement and by reducing the partial pressure of the methane rather than reducing total reservoir pressure (Amoco, 1991). Beginning in the late 1980’s, Amoco Production Company experimented with this technology and found that up to 80 percent of adsorbed methane could be recovered by introducing an inert gas, such as nitrogen, into the coal sample (Amoco, 1996). In January 1998, after receiving approval from various state and Federal agencies, Amoco began injecting nitrogen gas into the coal horizons within their Tiffany Nitrogen Injection Recovery Unit in La Plata County, Colorado. Results from this project have been encouraging. Increases in methane production have been reported at collector gas wells which have produced more methane gas in the brief time that the project has been operating than they had produced in their recorded past as normal methane gas producers (Appendix C: Chart 9). It is anticipated that injection pressures may have to be increased as reservoir pressure is raised by the nitrogen input, but the higher reservoir pressure would be expected to increase permeability by opening cleat fractures in the coal. This increase in permeability may actually enable greater production rates and offset the need for increased injection pressure (Amoco, 1991).