Material Selection and Corrosion Rate Analysis for CO2 Injection Well: A Case Study of K1 Field CO2 Sequestration Project

Abstract

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.

Study on the Influence of Supercritical CO2 with High Temperature and Pressure on Pore-Throat Structure and Minerals of Shale

“…CO 2 injection has emerged as an important method for enhancing oil recovery. Experimental tests and simulations have been undertaken to evaluate the improvement of recovery by CO 2 injections. − In the context of the shale oil and gas field, CO 2 can be used to stimulate the development of shale oil and gas via adsorption and replacement processes. Researchers have carried out experimental and dynamic simulation studies on CO 2 -enhanced recovery in shale formations. , These experimental analysis included mechanical characterization, modification in pore-throat structures, alterations in mineral content, changes in adsorption–desorption, and variations in pore and permeability levels. − Existing experimental studies conducted under conventional temperature and pressure settings have found that the interaction between CO 2 and reservoir rocks considerably influences the rock properties.…”

“…Experimental tests and simulations have been undertaken to evaluate the improvement of recovery by CO 2 injections. 1 − 3 In the context of the shale oil and gas field, CO 2 can be used to stimulate the development of shale oil and gas via adsorption and replacement processes. Researchers have carried out experimental and dynamic simulation studies on CO 2 -enhanced recovery in shale formations.…”