Stable isotope geochemistry of coal bed and shale gas and related production waters: A review

Coal bed and shale gas can be of thermogenic, microbial or of mixed origin with the distinction made primarily on the basis of the molecular and stable isotope compositions of the gases and production waters. Methane, ethane, carbon dioxide and nitrogen are the main constituents of coal bed and shale gases, with a general lack of C2+ hydrocarbon species in gases produced from shallow levels and more mature coals and shales. Evidence for the presence of microbial gas include δ13C-CH4 values less than -50‰, covariation of the isotope compositions of gases and production water, carbon and hydrogen isotope fractionations consistent with microbial processes, and positive δ13C values of dissolved inorganic carbon in production waters. The CO2-reduction pathway is distinguished from acetate/methyl-type fermentation by somewhat lower δ13C-CH4 and higher δD-CH4, but can also have overlapping values depending on the openness of the microbial system and the extent of substrate depletion. Crossplots of δ13C-CH4 versus δ13C-CO2 and δD-CH4 versus δ13C-H2O may provide a better indication of the origin of the gases and the dominant metabolic pathway than the absolute carbon and hydrogen isotope compositions of methane. In the majority of cases, microbial coal bed and shale gases have carbon and hydrogen isotope fractionations close to those expected for CO2 reduction. Primary thermogenic gases have δ13C-CH4 values greater than -50‰, and δ13C values that systematically increase from C1 to C4 and define a relatively straight line when plotted against reciprocal carbon number. Although coals and disseminated organic matter in shales represent a continuum as hydrocarbon source rocks, current data suggest a divergence between these two rock types at the high maturity end. In deep basin shale gas, reversals or rollovers in molecular and isotopic compositions are increasingly reported in what is effectively a closed shale system as opposed to the relative openness in coal measure environments. Detailed geochemical studies of coal bed and shale gas and related production waters are essential to determine not only gas origins but also the dominant methanogenic pathway in the case of microbial gases

Thermodynamic and hydrochemical controls on CH4 in a coal seam gas and overlying alluvial aquifer: new insights into CH4 origins

Using a comprehensive data set (dissolved CH(4), δ(13)C-CH(4), δ(2)H-CH(4), δ(13)C-DIC, δ(37)Cl, δ(2)H-H(2)O, δ(18)O-H(2)O, Na, K, Ca, Mg, HCO(3), Cl, Br, SO(4), NO(3) and DO), in combination with a novel application of isometric log ratios, this study describes hydrochemical and thermodynamic controls on dissolved CH(4) from a coal seam gas reservoir and an alluvial aquifer in the Condamine catchment, eastern Surat/north-western Clarence-Moreton basins, Australia. δ(13)C-CH(4) data in the gas reservoir (−58‰ to −49‰) and shallow coal measures underlying the alluvium (−80‰ to −65‰) are distinct. CO(2) reduction is the dominant methanogenic pathway in all aquifers, and it is controlled by SO(4) concentrations and competition for reactants such as H(2). At isolated, brackish sites in the shallow coal measures and alluvium, highly depleted δ(2)H-CH(4) (<310‰) indicate acetoclastic methanogenesis where SO(4) concentrations inhibit CO(2) reduction. Evidence of CH(4) migration from the deep gas reservoir (200–500 m) to the shallow coal measures (<200 m) or the alluvium was not observed. The study demonstrates the importance of understanding CH(4) at different depth profiles within and between aquifers. Further research, including culturing studies of microbial consortia, will improve our understanding of the occurrence of CH(4) within and between aquifers in these basins