Injection Strategy Optimization in Complex Reservoirs for Gas Geological Storage

Abstract Geological reservoirs have been widely applied in CO2 geological storage, strategic CH4 reserves, and emerging H2 subsurface energy storage systems. Among these applications, CO2 geological storage has become increasingly significant with the advancement of carbon-emission reduction goals. To enhance CO2 injectable mass in subsurface formations, this study investigates injection-strategy optimization in a complex thinly interbedded saline aquifer of the Zhujiang Formation in the Pearl River Mouth Basin. A three-dimensional flat-layered numerical model consisting of multiple reservoir and caprock layers was constructed, and multiphase, multicomponent numerical simulations were conducted to evaluate CO2 plume migration, bottomhole-pressure response, and storage-capacity evolution under different injection strategies and rate increments. Because direct trial-and-error optimization of variable-rate injection requires repeated full-physics simulations and is computationally expensive, an incremental injectivity index, H(t), was established from preliminary rate-increment tests to quantify the dynamic relationship between injection-rate variation and pressure response. By using H(t), the allowable injection-rate increment at a given stage can be estimated from the current pressure margin, thereby providing a computationally efficient basis for stage-wise rate adjustment. This rate–pressure relationship was further incorporated into a low-to-high stage-wise variable-rate optimization framework, which determines pressure-constrained injection rates under the coupled constraints of maximum allowable bottomhole pressure and CO2 upward migration. The results show that an excessively high initial injection rate can markedly increase the peak bottomhole pressure and exceed the maximum allowable bottomhole pressure. In contrast, the proposed H(t)-guided stage-wise variable-rate strategy mitigates early pressure buildup while improving the total injectable CO2 mass. The optimized strategy achieves a maximum injectable CO2 mass of 29.56 Mt, which is 19.56 Mt higher than that achieved by the constant 0.5 Mt/year injection-rate strategy, 1.28 Mt higher than that achieved by the annual-adjustment strategy, and 0.30 Mt higher than that achieved by the 0.25-year adjustment strategy. The proposed framework provides a practical and computationally efficient approach for injection-strategy design and single-well storage-capacity optimization in complex saline aquifers.