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CO2 capture and storage (CCS) is expected to reduce CO2 emissions into the atmosphere. Various underground reservoirs and layers exist where CO2 may be stored such as aquifers, depleted oil and gas reservoirs as well as unmined coal seams. Coal seams are feasible for CCS because coal can adsorb CO2 gas with roughly twice volume compared with CH4 gas originaly stored (Yee et al., 1993). However, the coal matrix is swelling with adsorbing CO2 and its permeability is reduced. Supercritical CO2 has a higher injection rate of CO2 into coal seams than liquid CO2 because its viscosity is 40% lower than the liquid CO2 (see Harpalani and Chen, 1993). The Japanese consortium carried out the test project on Enhanced Coal Bed Methane Recovery by CO2 injection (CO2–ECBMR) at Yubari City, Hokkaido, Japan during 2004 to 2007 [Yamaguchi et al. (2007), Fujioka et al.(2010)]. The target coal seam at Yubari was located about 890 to 900 m below the surface (Yasunami et al., 2010). However, liquid CO2 was injected from the bottom holes because of heat loss along the deep injection tubing. The absolute pressure and temperature at the bottom hole was approximately 15.5MPa and 28°C. The regular tubing was replaced with thermally insulated tubing that included an argon gas layer but the temperature at the bottom was still lower than the critical temperature of CO2. This chapter provides a numerical model of heat transfer and calculation procedure for the prediction of CO2 temperature and pressure that includes a phase change (supercritical or liquid) by considering the heat loss from the injector to surrounding casing pipes and rock formation. Furthermore, this study provides numerical simulation results of the temperature distribution of the coal seam after the injection of CO2.

Heat Transfer and Phase Change in Deep CO2 Injector for CO2 Geological Storage