Material Selection and Corrosion Rate Analyzed for CO2 Injection Well

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21818, “Material Selection and Corrosion-Rate Analysis for CO2 Injection Well: A Case Study of K1 Field CO2 Sequestration Project,” by Mohd A. Abu Bakar, Wan Amni Wan Mohamad, and M. Wahidullah M. Wahi, Petronas, et al. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission. _ Typical materials used for CO2 injector wells are either corrosion-resistant alloys (CRA) or epoxy-lined tubulars. The most widely adopted CRA material is 25Cr, which features a high well-application cost. Application of materials other than 25Cr for CO2 injector wells are uncommon but may be fit for purpose. The complete paper describes material-selection methodology and corrosion studies performed in the K1 field CO2 sequestration project using materials other than 25Cr in an effort to optimize well costs and improve overall project economics without jeopardizing CO2 injector-well integrity. Introduction K1 field is in the Sarawak Basin at a water depth of 453 ft. It was discovered by an exploration well in 1972 and appraised by a dedicated well in 1992. The field features a gas column of 324 ft from the free water level at 4,990 ft true vertical depth subsea. Gas initially in place for this field is estimated at approximately 2,800 Bscf. CO2 storage screening studies had identified an opportunity to use the K1 field as a storage site. The source of CO2 gas is a nearby field, from which separated CO2 gas will be transported through a 130-km pipeline to the K1 field’s new injection-wellhead platform. The current plan is to inject and store the CO2 inside one of the depleted carbonate reservoirs until an increase in reservoir pressure to the initial pressure of 3,440 psi is observed. The reservoir temperature is approximately 120°C. Injection-Fluid Composition and Presence of Water Injection fluid contains a high mol% of CO2, methane, and other impurities such as nitrogen and hydrogen sulfide (H2S) gases. Injection fluid will be injected above the CO2 supercritical condition. Based on the injection fluid’s composition, CO2 will be the main source of corrosion in the presence of water when exposed to unprotected tubulars in the wells. The presence of H2S denotes the effect of stress corrosion cracking (SCC) and sulfide stress cracking (SSC), which must be considered in selecting tubing material for the injector wells. A small percentage of water (approximately 0.0086 mol%) also exists in the injection fluid. This will be detrimental to the injection wells in terms of corrosion if it is in the aqueous phase. To study this, the well’s shut-in and injection pressures and temperatures were plotted against the water-phase diagram. During these conditions, water in the injection fluid exists as vapor phase. Considering the possible risks of a higher percentage of water in the injection fluid, a more- conservative approach was taken in the selection of tubing material for the injector wells.