Extensive Laboratory Test to Validate Material Selection for CO2 Injector in Depleted Carbonate Field - A Case Study of Carbon Capture and Storage Development Project in Offshore Malaysia

Abstract

Abstract As part of decarbonization initiatives, the K1 field CCS project plans to capture the CO2 produced from the nearby gas field development and store it in the depleted carbonate reservoir. One of the challenges in CCS project is to choose the optimum material for the well design. This paper presents the case study of CO2 injection well material selection of K1 field CCS project development. The injection fluid contains more than 90-98% CO2 and about 500-711 ppm of H2S. This condition and presence of free water might create high risk environment for Stress Corrosion Cracking (SCC) and Sulfide Stress Cracking (SSC). Materials were initially screened based on Oil Company Tubular Good (OCTG) charts. Further qualification was deemed required through fit for purpose tests which represent the most likely and worst-case conditions. Test matrix has been developed based on NACE TM 0177 and NACE TM 0136 guidelines. Initial material selection using the OCTG chart suggested 25 Cr as a suitable material. No verification through the lab test is required for this material. As an alternative material, 22 Cr and enhanced 13 Cr were considered, subject to further verification on Sulfide Stress Cracking (SSC) and Stress Corrosion Cracking (SCC). The test matrix had been developed to simulate two scenarios where the injected gas mixes with condensed water during injection and flowback of formation water. For enhanced 13 Cr material, SSC test is performed at 24°C and 34°C. The temperature of 24°C is chosen as the temperature of highest susceptibility of SSC expected to occur for martensitic material. For temperature of 34°C, it is performed to investigate the effect of supercritical CO2 fluid phase on the corrosion and cracking if any. For 22 Cr which is duplex material, the test is performed at temperature of 90°C, which is the temperature of the highest SSC susceptibility of duplex material expected to occur. The corrosion and cracking test result show that the material suitable for more than 90% CO2 with about 711 ppm of H2S in condensed water condition and flowback fluid condition is 22 Cr and above grade. As part of material selection process, extensive lab tests to qualify tubing material has been performed by both OCTG manufacturer and independent lab. The result enables further optimization on well cost while giving assurance on K1 CCS injector well's integrity