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Abstract A new method of coalbed methane (CBM) recovery is proposed wherein hot carbon dioxide at or near supercritical condition is injected into a CBM reservoir to take advantage of enhanced desorption of methane at elevated temperatures and the preferential adsorption of CO2 on coal surfaces compared to methane. The feasibility of this concept was studied by reservoir simulations using one quarter of an inverted five spot pattern using CO2 and CH4 adsorption isotherms published in the literature. The study compared CBM recovery by pressure depletion, CO2 injection and injection of CO2 that is 10°C hotter than the reservoir temperature. Results show that hot CO2 injection can significantly increase the production rate and recovery factor over and above that achievable by reservoir heating or CO2 injection alone. This new method holds promise for enhanced CBM recovery and also CO2 sequestration, especially for high-rank coals where swelling of coal by CO2 injection is minimized. Preliminary considerations suggest that this method can be economic over a range of CO2 and natural gas price if the CO2 comes from natural sources and the CBM field is located near an existing CO2 pipeline. Alternatively, if the source of CO2 is industrial, this method can be profitable if the cost of CO2 capture is offset by the trading price of CO2 and if the CBM project is located near the CO2 source. Introduction Coalbed methane, also known as coal seam gas, is a significant source of natural gas worldwide, with sizable reserves in the United States, Australia, Russia, Canada and China. In 2015, CBM production in the US was 1.27 Tcf (35.97 Bcm), accounting for 3.9% of all US natural gas production (EIA, 2017). Commercial production of CBM occurs in ten US basins with major production coming from the San Juan, Black Warrior and the Central Appalachian. In 2015, CBM production in Australia was 270 Bcf (7.65 Bcm) accounting for 18% of Australia's total natural gas production (Australian Government, 2016).

This paper presents a detailed case study of using surface to in-seam wells to develop a major coalbed methane (CBM) field in the Bowen Basin of Australia. This study was novel in that special emphasis was given to quantification of subsurface property uncertainty and modeling of dynamic uncertainty. The result was the generation of recovery factor versus depth correlations which can be used to calculate the estimated ultimate recoverable.In this work, a 3D box model around three pilot wells was extracted from the regional static model. To quantify key subsurface uncertainties such as permeability, both the Percentile and Confidence Interval Methods were used. Trends of laboratory-measured parameters like gas content, ash, Langmuir volume, permeability were established. Reservoir properties without measurements such as cleat porosity, desorption time and relative permeability were estimated based on rules-of-thumb, basin-wide analogue or educated guesses. A reservoir simulation model was built and production data from pilot wells were manually history matched. Parametric analysis was conducted to determine key parameters that significantly affect model history matching and forecasting results. Given the complexities of the coal reservoir and the non-uniqueness of the history match, Experimental Design was used to generate a population of simulation models that sampled the uncertainty range of key reservoir properties. This ensemble was reduced to include only those that matched the pilot wells’ production. With different combinations of reservoir properties thus obtained, recovery factor versus depth correlations were generated.This study is a good example of early resource assessment critical to the field development planning of a major CBM field. It presents a systematic method to handle uneven distribution of often sparse subsurface data over a large geographic area which often confounds the CBM industry. Furthermore, this method may be extended to assess other well architectures like vertical, slant, horizontal, multi-branch, multi-lateral and hydraulically fractured vertical and horizontal wells.