Numerical Simulation Study on Mitigation of the Pressure Build-up in the Geological Formation During Injection of CO2

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The injection of supercritical CO2 into the deep underground increases the pore pressure in the geologic formation, first locally around the injection point, later spreads radially throughout the formation. The range of pressure increase depends on the injection rate, injectivity and reservoir volume. The increase of pressure in the reservoir may cause several problems, including fracturing of sealing layer, fault reactivation and changes in other hydrogeological conditions. In order to reduce the pressure buildup in the reservoir during CO2 injection, two methods were studied in this paper by numerical simulations using the TOUGH2 code. One describes production of formation water as proposed by Buscheck et al. in 2014 (dual-mode well), and the second method describes production of formation water via a second well during CO2 injection. We employed a simple reservoir model based on available data of the CCS demonstration project at the Tomakomai area in Hokkaido, Japan. The efficiency and influence of two reservoir volumes, and a hypothetical placed production well, on pressure build-up in the storage formation were tested. Two models with different volumes, and an injection rate of 1 Mt/yr were applied and three cases were simulated for each model. The first case only considered injection of CO2 for 100 years without production. The second case examined the dual-mode well, in which formation water was produced for 5 years prior to the start of CO2 injection for 100 years. The last (third) case assumed utilization of an observation well for producing water in parallel with CO2 injection. Judging from the results, the following conclusion can be drawn: 1) The dual-mode well with short duration of water production (5 years) was not so effective to maintain the reservoir pressure in the large reservoir volume considered here. The method would be better suited for smaller reservoir, otherwise a very long-term production would be necessary. 2) Water production in parallel with injection was very effective in order to maintain the reservoir pressure and to avoid harmful effects on the overlying seal layers and other hydrogeological conditions. The methods can be applied to make CCS technology much more sufficient through increasing the effective capacity of injectable CO2. It may also lead to more opportunities related to site selection. However, it has to be emphasized, that the effectiveness of the production strategies investigated here may highly depend on site conditions. Therefore, the results obtained in this study should be regarded as a preliminary evaluation for the Tomakomai site specifications. Further investigations would be necessary, when more data become available through the site investigation and even operations.