Abstract
The objective of this paper was to investigate the THM-coupled responses of the storage formation and caprock, induced by gas production, CO2-EGR (enhanced gas recovery), and CO2-storage. A generic 3D planer model (20,000 × 3,000 × 100 m, consisting of 1,200 m overburden, 100 m caprock, 200 m gas reservoir, and 1,500 m base rock) is adopted for the simulation process using the integrated code TOUGH2/EOS7C-FLAC3D and the multi-purpose simulator OpenGeoSys. Both simulators agree that the CO2-EGR phase under a balanced injection rate (31,500 tons/year) will cause almost no change in the reservoir pressure. The gas recovery rate increases 1.4 % in the 5-year CO2-EGR phase, and a better EGR effect could be achieved by increasing the distance between injection and production wells (e.g., 5.83 % for 5 km distance, instead of 1.2 km in this study). Under the considered conditions there is no evidence of plastic deformation and both reservoir and caprock behave elastically at all operation stages. The stress path could be predicted analytically and the results show that the isotropic and extensional stress regime will switch to the compressional stress regime, when the pore pressure rises to a specific level. Both simulators agree regarding modification of the reservoir stress state. With further CO2-injection tension failure in reservoir could occur, but shear failure will never happen under these conditions. Using TOUGH-FLAC, a scenario case is also analyzed with the assumption that the reservoir is naturally fractured. The specific analysis shows that the maximal storage pressure is 13.6 MPa which is determined by the penetration criterion of the caprock.
Highlights
The stress path could be predicted analytically and the results show that the isotropic and extensional stress regime will switch to the compressional stress regime, when the pore pressure rises to a specific level
Temperature decrease and the corresponding cooling effects are limited in the near field of injection wells, fault slip may occur when the reservoir pressure rises to a critical level
TOUGH2 is fully upwinded with respect to mass transport, while for these simulations OGS utilizes a standard Galerkin finite element (FEM) procedure (Park et al 2011), with dispersion introduced via coefficients of dispersion designed to maintain the Peclet number near 2.0, and produce dispersive characteristics similar to an upwinded scheme
Summary
Temperature decrease and the corresponding cooling effects are limited in the near field of injection wells, fault slip may occur when the reservoir pressure rises to a critical level This could lead to CO2 leakage to drinking water source or even land surface and bring out significant environmental issues. The objective of this paper was to study the THM-coupled responses of the storage formation and caprock, resulting from the reservoir pressure changes in the gas production, CO2-EGR and CO2-storage phase. We utilize a Biot formulation to represent the solid density time derivative (in Eq 5) as in (Rutqvist et al.2001; Khalili and Selvadurai 2003) and substitute Eq 5 and the density compressibility derivatives into Eq 4 to obtain the final form of fluid mass balance, aÀ/ /qCp þ q Kg oP ot þ ð/qCxÞ oX ot þ. 1⁄4 ÀFi ð9Þ for the shear modulus G, and Lameconstant k
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