Balancing Surface Facilities & Well Design to Comply with Cap-Rock Integrity in CO2 Storage Projects: Experience from UAE

Abstract CO2 injection is different than oil and gas injection, where CO2 phase changes are very likely to occur inside tubing at various operating conditions, especially in depleted gas reservoirs during early stages where reservoir pressure is low, and CO2 can change from supercritical to gas phases at various depths inside tubing when flow approaches perforation intervals. This is a dynamic and transient behavior, and modelling wellbore pressure and temperature during the life of the well (early, mid and late) is essential and can provide better understanding of the potential risks that are associated with CO2 injection and the appropriate actions and mitigation plans. Severe cooling due to phase changes and Joule Thomson effects inside tubing, as well as cycling of cooling and heating conditions, can negatively impact well and reservoir integrity including cap rock. This paper presents a case history of a CCUS project in the Middle East where wellbore pressure and temperature modelling showed a significant impact on surface facility design, and a geomechanical model was constructed to investigate cap rock integrity as well as the safe operating envelope for CO2 injection. The workflow included modelling of seven time-steps to represent CO2 injectivity performance and pressure/temperature profiles inside tubing from start to the end of the project. In addition, sensitivity analysis was considered for CO2 impurities at each time step. The results feed the geomechanical study to ensure reservoir and caprock integrity during injection as well as surface facility design and mitigation plans. The results showed that high purity CO2 can yield significantly higher injection rates compared to a low purity scenario. During early stages of injection, low bottomhole injection temperature was observed. Injection under low temperature may jeopardize reservoir and caprock integrity. Potential solutions to mitigate such issues are to consider heating CO2 at surface at early stage or to use smaller tubing size which may impact the injection capacity. Early stage during injection is the most critical period and may impact completion design and reservoir/cap-rock integrity. Hydrate risk assessment was conducted and showed that surface conditions are close to the hydrate risk zone. The operational philosophy has been modified to consider a surface heating unit to be used during the early stage of injection until reservoir pressure builds up. This paper presents the importance of detailed wellbore pressure and temperature modelling during CO2 injection and how this can impact the integrity of the project as well as the operational philosophy. Workflow and risk assessment are also presented.