The commercial extraction of methane from coal beds is now well established in a number of countries throughout the world, including the USA, Australia, China, India and Canada. Because coal is almost pure carbon, its reservoir character is fundamentally different to conventional gas plays. Coalbed methane (CBM) forms as either biogenically- or thermogenically-derived gas. The former occurs in ¡®under mature¡¯ (< 0.5 % vitrinite reflectance) coals and is the result of bacterial conversion of coal into CO
2 or acetate, which is then transformed by archaea into CH
4. Thermogenic gas is formed as part of the coalification process and is purely a chemical devolatilization that releases CH
4. Methane is primarily stored in coal through adsorption onto the coal surface; thus it is pore surface area that determines the maximum gas holding potential of a reservoir (as opposed to pore volume in a conventional reservoir). Although
macro-, meso-, and micropores are present in the coal matrix, it is thought that the micropores are where most methane adsorption occurs. In many of the micropores, the methane molecule may actually stretch, minutely, the pore and thus with de-gassing of the reservoir, could result in matrix
shrinkage, allowing opening of the fracture (cleat) system in the coal and thus enhancing permeability. The organic composition of the coal is paramount in determining
porosity and permeability character and thus maximum gas holding capacity. In general, the higher the vitrinite content the higher the gas holding potential (and ultimately the amount of desorbed gas) and permeability (all other factors being the same). There are other organic component/gas property relationships but these seem to be specific to individual basins, or even seams.
Characterising a CBM reservoir during an exploration programme is a challenge but the two most vital measures to determine are permeability and % gas saturation. Permeability will largely determine gas (and water) flow rate, dictating how commercial a prospect might be. Gas saturation, determined from desorption and adsorption measurements, also influences gas rate and the ultimate recoverability of gas from a reservoir. Modelling of gas flow from the reservoir is highly dependent on knowledge of these parameters. Designing a successful pilot well programme and ultimately production wells will rely mostly on the permeability and % gas saturation character. Certification of resources and reserves, which is also very important to CBM companies as they explore and develop their permits, depends heavily on accurate estimates of reservoir character; primarily seam continuity, % gas saturation and permeability.
