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The CO2 sequestration project is becoming increasingly attractive due to tax exemption benefits and as an initiative to reduce the global warming effect (D'Alesio, P., Poloni, R., Valente, P., & Magarini, P. A.2010). One of the major challenges in CO2 sequestration project is to ensure that the injection well integrity is intact throughout the well operating life. CO2 gas leakage to the surface or sea is unacceptable. Therefore, the considerations of using exotic/premium tubing materials are usually considered as the base case for continuous long-term operations (Baklid, A., Korbol, R., & Owren, G.1996). Typical materials used for CO2 injector wells are either Corrosion Resistant Alloy (CRA) or epoxy lined tubulars. The most widely adopted CRA material is 25 Cr (L. Smith, M.A. Billingham, C.-H. Lee, D. Milanovic, 2011). Selection of 25 Cr material is considered as conservative and may well be overdesigning. The main drawback is the high well cost associated with the application of 25 Cr tubing. Meanwhile, alternative materials such as epoxy lined tubulars are exposed to high temperature and pressure blistering effects and prone to mechanical damage caused by wireline activities, hauling, running, and pulling off the tubing (Newton, L. E., & McClay, R. A, 1977). Application of materials other than 25 Cr for CO2 injector wells, such as 22 Cr, Super 17 Cr, Super 15 Cr, Super 13 Cr, 13 Cr and carbon steel are uncommon but may be fit for purpose. Detailed studies using analytical method and physical tests are required to further qualify these materials for application in CO2 injector wells. These studies should cover all possible conditions throughout the well life such as injection, shut-in, flowback and by considering surface and bottom hole conditions which may contribute to increase in the corrosion rates for different types of materials. Other tests warranted before selecting the suitable material for field application include physical coupon, Sulfide Stress Cracking (SSC) and Stress Corrosion Cracking (SCC) tests. This paper describes the material selection methodology and corrosion studies performed in the K1 field CO2 sequestration project using the other materials mentioned above as an effort to optimize well costs and improve overall project economics without jeopardizing the CO2 injector well integrity.

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Exploration well with carbonate reservoir is a challenging well to plan for due to risk of total losses because of karst presence. It became even more challenging for a subsea well with high bottom hole temperature (BHT) and prospect of well testing. Flow of HT reservoir fluids (BHT up to 175 deg C) to surface will resulted in significant heat transfer to adjacent casing & its annulus fluids, and lead to annular pressure build-up (APB). High APB will lead to loss of well integrity via 13-3/8" intermediate casing burst and 9-7/8" production casing collapse if left unmitigated. As per The Company technical standards, two APB mitigations were required in a subsea well. The first selected mitigation is an open casing shoe. The exposed shoe will act as a natural relief valve whenever APB exceeding its fracture pressure (FP), therefore, limit the APB to its FP. However, it is challenging to keep the 9-7/8" casing top of cement (TOC) below the 13-3/8" casing shoe and fulfil the open shoe barrier requirement for this well where the open hole interval is relatively short and subject to be plugged off by barite sagging, insufficient open shoe length for safety margin of excess cement and requirement of minimum annulus cement length for shoe integrity. Extra mitigations were addressed through extensive lab tested solids-free annulus fluid to mitigate barite sagging. Open shoe interval also designed with multiple weak sands exposure and higher FP were considered for worst-case APB simulation. The second barrier is the 13-3/8" intermediate casing and 9-7/8" production casing itself. Based on WellCAT simulation, the intermediate casing unable to meet The Company standards of burst (safety factor, SF < 1.1) in the worst-case scenario whereby APB is unmitigated. The casing burst pressure rating was recalculated using API Bulletin 5C3 equation with the inputs taken from minimum actual casing wall thickness measurement and internal yield pressure from its mill certificate. Technical derogations were raised and approved once the casing passed all the load cases using the revised burst rating by minimum SF of 1.0. The well was delivered successfully with the open hole barrier for both casing was executed flawlessly despite the complex fluid train while cementing.

K field is a green field in East Malaysia with prolific gas reserves that is being developed with six high rate gas producing wells from high temperature (190 °C) carbonate reservoir. Tubular material feasibility study is one of the key subjects of scrutiny when it comes to completing wells in high temperature environment coupled with existence of significant level of H2S and CO2 contents. Material testing was conducted at the specified test environments (102 bar CO2 + 120ppm H2S) and load cases to assess susceptibility of Martensitic Stainless Steel to Stress Corrosion Cracking (SCC), corrosion rate and compatibility with completion brine. The aim was to optimize the material selection that is fit for purpose (lower completion and flow-wetted area of production casing) and reduce well cost up to USD 2.5 million. The base case of material selection for flow-wetted section is 17CR110 ksi, which meets the design requirements of these wells based on fit for purpose test conducted in the data base. Flow-wetted section in this case is production liner and flow-wetted section of production casing below production packer. Super 13CR -110 ksi and 15CR125 ksi material grades were considered for design optimization for this section of interest. Four Point Bend Method was used for SCC test sets while weight loss method for corrosion rate measurement. For brine compatibility test, calcium bromide (without additive) was used as test solution for 17CR 110 ksi, 15CR 125 ksi and Super 13CR -110 ksi with elevated temperature of 190 °C. Post-test assessment was conducted by visual examination by stereomicroscope to check for surface indication and dye-penetrant examination to determine any indication of cracks. It was observed that the Super 13CR -110 ksi and 15CR 125 ksi test specimens survived the test with no pitting observed. Meanwhile, test specimens were weighed to determine corrosion rates, resulted to Super 13CR -110 ksi sample having an average corrosion rate of 0.2195 mm/year. This translates to less than 30% weight loss throughout well production life and therefore accepted for open-hole production liner and production casing flow-wetted section. Key enabler in this design optimization effort is the understanding of the Stress Corrosion Cracking for martensitic stainless steel in high temperature sour environment where commonly, martensitic stainless steel (Super 13Cr / Modified Super 13Cr) working temperature is 165 °C. The test manages to extend the working temperature up to 190 °C.