Abstract
Depleted gas reservoirs are important potential sites for CO2 geological sequestration due to their proven integrity and safety, well-known geological characteristics, and existing infrastructures and wells built for natural gas production. The Sichuan Basin has a large number of gas fields in which approximately 5.89×109 tons of CO2 can be stored. The Huangcaoxia gas field has the best opportunity in the eastern Sichuan Basin for a pilot project of CO2 sequestration due to its relatively large storage capacity and the nearly depleted state. A coupled thermal-hydrodynamic model including faults is built based on the geological and hydrogeological conditions in the Huangcaoxia gas field. The results of the numerical simulations show that the downhole temperature is above 80°C at a downhole pressure of 14 MPa under the constraint of temperature drop in the reservoir due to the strong Joule-Thomson effect. The corresponding injection pressure and temperature at the wellhead are 10.5 MPa and 60°C, respectively. The sizes of the pressure and CO2 plumes after an injection of 10 years are 18 km and 5 km, respectively. The zone affected by temperature change is very small, being about 1-2 km away from the injection well. The injection rate in the injection well Cao 31 averages 6.89 kg/s (21.73×104 tons/a). For a commercial-scale injection, another four wells (Cao 9, Cao 30, Cao 6, and Cao 22) can be combined with the Cao 31 well for injection, approaching an injection rate of 35 kg/s (1.10×106 tons/a). Both the pressure and temperature of CO2 injection decrease with the increasing depleted pressure in the gas reservoir when the latter is below 6 MPa. With the technique of CO2-enhanced gas recovery (CO2-EGR), the CO2 injection rate is improved and approximately 1.58×107 kg of gas can be produced during a studied time period of 10 years.
Highlights
The application of CCS in deep saline aquifers is hindered by some uncertainties and challenges, such as significant variation of storage capacity, limited information on geological characteristics, high costs associated with infrastructure construction, and the risk of CO2 and brine leakage [2]
Depleted gas reservoirs are regarded as alternative candidates for CO2 storage due to the integrity and safety proved by the accumulation and entrapment of natural gas, known geological characteristics from past natural gas production, and the fact that the preexisting in situ infrastructure and wells may be reused for CO2 transport and injection [3]
To maximize the injection rate, a downhole pressure of 14 MPa and a downhole temperature of 80°C are suggested for CO2 injection
Summary
The application of CCS in deep saline aquifers is hindered by some uncertainties and challenges, such as significant variation of storage capacity, limited information on geological characteristics, high costs associated with infrastructure construction, and the risk of CO2 and brine leakage [2]. Depleted gas reservoirs are regarded as alternative candidates for CO2 storage due to the integrity and safety proved by the accumulation and entrapment of natural gas, known geological characteristics from past natural gas production, and the fact that the preexisting in situ infrastructure and wells may be reused for CO2 transport and injection [3]. The other type is strictly for storing CO2 when the gas reservoir is depleted or CO2-EGR is completed. There are a few pilot projects testing the feasibility of CO2 storage in depleted gas reservoirs: the K12-B CO2 Injection Project in the Netherlands, the Lacq CCS Pilot Project in
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