Key points are not available for this paper at this time.
ABSTRACT: This paper presents a reference stress-strain solution for a thermo-hydro-mechanical one-way coupled problem related to CO2 storage. The benchmark problem is solved with a semi-analytical model based on the equivalent cuboid inclusion method. This case is then extended to assess the modelling capability of two finite element codes (GEOS and VISAGE) in predicting thermo-poro-elastic stresses and assessing the occurrences of thermo-hydraulically induced fractures. In the defined CO2 injection problem, there are two different fronts, pressure front constraining in the near wellbore and cooling front moving to the far field. To account for this, different meshes and methodologies are chosen for two numerical models. Comparison with numerical results confirms that the thermo-poro-elastic effects are accurately captured by the semi-analytical solution, which correlates well with the numerical results. Although differences between the two numerical simulators are sometimes larger than those between a numerical solution and the semi-analytical solution, similar conclusion regarding the formation of thermo-hydraulically induced fractures can be provided. The agreement in stress and strain solutions provides a common foundation for future work on two-way coupling and fracture propagation. The documented benchmark example and simulation results could be used to validate the modelling capabilities of other similar tools in the future. 1. INTRODUCTION Multidisciplinary studies related to CO2 storage in depleted sandstone reservoirs raised many questions and hence gained substantial focus. During long term CO2 injection with low temperature and high rates, one major operationally risk is the formation of thermally and hydraulically induced fractures (THIF), which could lead to a sustained injectivity increase, and may introduce unexpected leakage pathways in the caprock or through the fault. As for our specific case study and desired operating envelopes, temperature typically ranges from 10 to 20°C at fluid inlets, which locate at depth of 3500 m. Injection of cold CO2 may cause a temperature drop of about 100°C for the surrounding rock in the contact of migrated CO2 plume. Considering such magnitude of cooling and thermo-poro-elastic coupling effect, potential stress change may be boosted up to several hundred bars for a sandstone reservoir with porosity about 10 to 15%. Besides that, the injection pressure at bottomhole will increase from 20 bars initially to 200 to 350 bars after several years injection. The combination of decreasing temperature and increasing reservoir pore pressure could induce a significant variation in both the total and effective in-situ stresses, due to thermo-poro-elastic or thermo-hydro-mechanical (THM) coupling. Furthermore, the highest pressure gradient is always around the injectors, whereas the highest temperature gradient, or cooling front, is formed inside the reservoir and advances with time. The advance of such thermal front moving away from the injector makes the prediction of the occurrence of THIF a complex numerical problem.
Su et al. (Sun,) studied this question.