3:00 PM - 3:15 PM
[AGE34-06] Numerical Simulation of CO2 Hydration and Diffusion Behavior in Geological Formations Using PFLOTRAN
Keywords:CCS, CO2 Hydrate, Numerical Simulation
The large-scale deployment of CCS (Carbon dioxide Capture and Storage) projects, which separate and recover CO2 from the atmosphere and store it in geological formations, is expected to be crucial in mitigating climate change. However, significant uncertainties remain regarding CO2 storage in underground reservoirs. Recently, a technology gaining attention involves injecting CO2 into submarine sand reservoirs beneath the seafloor and storing it as CO2 hydrate. In this study, we conduct numerical simulations of CO2 hydrate formation and diffusion behavior in submarine reservoirs off the coast of Japan using PFLOTRAN, the large-scale parallel multiphase flow and reactive transport simulator.
CO2 hydrate is a crystalline structure in which CO2 molecules are trapped inside cage-like structures formed by water molecules. It forms only under low-temperature and high-pressure conditions. When assuming a marine environment at a depth of 1,000 m in the Nankai Trough region, the stable zone of CO2 hydrate is estimated to range from 0 mbsf (seafloor) to 263 mbsf. In this study, we conducted CO2 injection simulations in a submarine reservoir at a depth of 1,000 m in the Nankai Trough region. The CO2 injection temperature and injection rate were set as parameters, and the simulation considered CO2 concentration and pore water salinity within the reservoir.
For the CO2 injection simulation, we used PFLOTRAN, which solves the partial differential equations describing fluid behavior and reactive transport in reservoirs using an implicit method, outputting results at each timestep. The simulation employed a 2D reservoir model extracted from a cylindrical 3D model. The geological structure consists of a two-layered system, with a mudstone seal layer from 0 to 200 mbsf and a sandstone reservoir layer from 200 to 220 mbsf. The porosity was set to 0.1 for the seal layer and 0.35 for the reservoir layer, while absolute permeability was set to 1.0×10-16 m2 for the seal layer and 1.0×10-12 m2 for the reservoir layer. We designed eight scenarios by varying the CO2 injection rate (1.0×108 kg/year, 1.0×107 kg/year, 1.0×106 kg/year, 1.0×105 kg/year) and injection temperature (20°C (liquid phase), 40°C (supercritical phase)). The same simulation model was used across all scenarios.
The simulation results showed that higher injection rates led to greater CO2 hydrate growth, while lower injection temperatures promoted more active CO2 hydrate formation near the injection well. Over time, CO2 hydrate grew horizontally from the middle of the reservoir outward, forming a self-sealing layer. At an injection rate of 1.0×108 kg/year, CO2 hydrate formation was observed not only in the reservoir but also in the seal layer near the injection well. At 1.0×107 kg/year, widespread CO2 storage was possible within the reservoir alone. At 1.0×105 kg/year, although the CO2 hydrate formation area was small, its volume fraction was the highest. Regarding injection temperature, apart from hydrate formation near the injection well, its overall effect was minimal. In all scenarios except for 20°C-1.0×106 kg/year, a three-phase coexisting region (pore water - fluid-phase CO2 - CO2 hydrate) remained even at 100 years.
Parameter analysis revealed a positive correlation between injection rate and total CO2 hydrate formation and a negative correlation between injection rate and hydrate phase mass fraction. Under these simulation conditions, CO2 injection at 20°C and 1.0×108 kg/year was the most favorable in terms of both storage volume and storage efficiency for geological CO2 sequestration.
CO2 hydrate is a crystalline structure in which CO2 molecules are trapped inside cage-like structures formed by water molecules. It forms only under low-temperature and high-pressure conditions. When assuming a marine environment at a depth of 1,000 m in the Nankai Trough region, the stable zone of CO2 hydrate is estimated to range from 0 mbsf (seafloor) to 263 mbsf. In this study, we conducted CO2 injection simulations in a submarine reservoir at a depth of 1,000 m in the Nankai Trough region. The CO2 injection temperature and injection rate were set as parameters, and the simulation considered CO2 concentration and pore water salinity within the reservoir.
For the CO2 injection simulation, we used PFLOTRAN, which solves the partial differential equations describing fluid behavior and reactive transport in reservoirs using an implicit method, outputting results at each timestep. The simulation employed a 2D reservoir model extracted from a cylindrical 3D model. The geological structure consists of a two-layered system, with a mudstone seal layer from 0 to 200 mbsf and a sandstone reservoir layer from 200 to 220 mbsf. The porosity was set to 0.1 for the seal layer and 0.35 for the reservoir layer, while absolute permeability was set to 1.0×10-16 m2 for the seal layer and 1.0×10-12 m2 for the reservoir layer. We designed eight scenarios by varying the CO2 injection rate (1.0×108 kg/year, 1.0×107 kg/year, 1.0×106 kg/year, 1.0×105 kg/year) and injection temperature (20°C (liquid phase), 40°C (supercritical phase)). The same simulation model was used across all scenarios.
The simulation results showed that higher injection rates led to greater CO2 hydrate growth, while lower injection temperatures promoted more active CO2 hydrate formation near the injection well. Over time, CO2 hydrate grew horizontally from the middle of the reservoir outward, forming a self-sealing layer. At an injection rate of 1.0×108 kg/year, CO2 hydrate formation was observed not only in the reservoir but also in the seal layer near the injection well. At 1.0×107 kg/year, widespread CO2 storage was possible within the reservoir alone. At 1.0×105 kg/year, although the CO2 hydrate formation area was small, its volume fraction was the highest. Regarding injection temperature, apart from hydrate formation near the injection well, its overall effect was minimal. In all scenarios except for 20°C-1.0×106 kg/year, a three-phase coexisting region (pore water - fluid-phase CO2 - CO2 hydrate) remained even at 100 years.
Parameter analysis revealed a positive correlation between injection rate and total CO2 hydrate formation and a negative correlation between injection rate and hydrate phase mass fraction. Under these simulation conditions, CO2 injection at 20°C and 1.0×108 kg/year was the most favorable in terms of both storage volume and storage efficiency for geological CO2 sequestration.