Geological sequestration sites for CO2 include depleted oil and gas reservoirs, deep aquifers, coal seams and deep-sea strata, etc. Among them, near-depleted oil and gas reservoirs are ideal sites for long-term CO2 storage due to complete and safe trap closure and clear understanding. As the production of typical edge-bottom water reservoirs entered the high water cut stage, it becomed more difficult to further increase the recovery rate in conventional water drive development. We investigated the control factors of the CO2 enhanced oil recovery and storage. Firstly, the typical characteristics of the reservoir were extracted to establish a conceptual model for numerical simulation and fit the reservoir production dynamics. We have studied the modes of CO2 enhanced oil recovery (EOR), including water drive, gas drive, gas-top drive, water alternating gas (WAG) and bi-directional drive. The highest recovery was obtained with 39.04% for the bi-directional drive. Different injection pressures were then tested, combined with recovery and storage, we controlled the injection pressure close to the initial reservoir pressure at 14,000 kPa. Secondly, we have analysed the characteristics of the storage stage, including reservoir pressure maintenance and injection rates. It was assumed that the reservoir fracture pressure was 1.4 times the initial pressure, beyond which the CO2 would leak. The maximum storage weight obtained in this case is 25.683 million tonnes. Meanwhile, the slower the injection rate, the more CO2 can be stored. We proposed a production scheme for near-depleted edge-bottom water reservoirs and analyzed the main parameters for CO2 storage, providing some guidance for the siting and development of similar reservoirs.
As the problem of global warming becomes more serious, more efforts are needed to reduce CO2 emissions, and CO2 sequestration is considered to be one of the most effective ways to reduce greenhouse gases. The study of natural gas hydrates has become more innovative, with huge hydrate-forming zone (HFZ) that can be effectively used to sequester CO2. In order to accurately characterize the formation and dissociation of CO2 hydrate, we have fitted the hydrate phase equilibrium to precisely control the chemical reaction by temperature and pressure. By injecting CO2 into the HFZ for 30 years, the permeability and porosity around the wellbore dropped to 1.55 × 10-3 mD and 0.056. Plugging occurred which prevented gas injection. Then we proposed thermal stimulation, increasing injection pressure and hydraulic fracturing to enhance sequestration. Thermal stimulation can restore stratigraphy conditions to initial conditions. The CO2 was injected into the reservoir successfully with a sequestration volume of 5.50 × 107 m3. Also, the injection rate decreased slowly, allowing for long-term sequestration. In contrast, the physical methods, such as increasing injection pressure and hydraulic fracturing, can only increase the rate for a short time, and the sequestration increased from 4.23 × 107 m3 to 4.42 × 107 m3 and 4.34 × 107 m3, respectively. These results demonstrate that the most important measures to enhance sequestration by mitigating hydrate plugging are destabilizing hydrate and restoring injection loss.