Thermal Fracture Simulation in Depleted Gas Field Carbon Capture and Storage: Implications for Injectivity and Flow Assurance

Abstract

CO2 injection into depleted gas fields causes long-term cooling of the reservoir. Therefore, even if injection pressure stays below the fracture initiation pressure, the cooled volume still creates an extensive stress disturbance that can induce the propagation of large fractures over time. The enhanced injectivity after the onset of this thermal fracturing might jeopardize injection operations due to the risk of hydrate plugging in the injection well caused by the combination of low pressure and low temperature, and large fractures may also increase the risk of loss of containment. Modeling the fracture evolution provides an estimate of the magnitude and timing of these effects. In this study, commercial compositional reservoir simulation software capable of modeling the physical phenomena associated with CO2 injection into depleted natural gas reservoirs has been used. These encompass CO2 mixing with natural gas, water vaporization, thermal effects, and geomechanics. The finite-element geomechanics module used “two-way” coupling, which computes pressure and temperature in the flow simulation module, transmits this information to the geomechanics module to update stress and strain parameters, and uses these parameters to adjust porosity and permeability, thereby enhancing the accuracy and reliability of the overall simulation results. The thermal fracture opening is simulated as increased permeability in the fracture domain by using a fracturing criterion based on the effective stress. The fracture simulations were developed in close relation with flow assurance modeling to determine the operational windows that avoid hydrate formation while maintaining the required injection target. Unlike matrix injection, thermal fracturing shows a substantial reduction in injection bottomhole pressure (BHP), reaching 26 000 kPa (260 bar) in a specific scenario. These findings underscore the crucial consideration of cooling effects and thermal fracturing in carbon capture and storage (CCS) operations, particularly in flow assurance studies where well injectivity significantly influences overall outcomes. Due to the intense cooling-induced stress reduction, thermal fractures may propagate uncontrollably, potentially reaching faults within the reservoir. Temperature distributions along boundary faults may differ markedly from matrix flow conditions, highlighting the need to incorporate these effects into geomechanical studies to mitigate risks associated with fault stability during cooling processes.