Guidelines Assist Selection of Corrosion-Resistant Alloys for CCS and CCUS Injection Wells
Authors: Carpenter Chris 
Published: December 2024

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 217664, “Selection of Corrosion-Resistant Alloys for CCS and CCUS Injection Wells,” by Adam C. Rowe, SPE, Stress Engineering Services, and Bruce D. Craig, SPE, MetCorr. The paper has not been peer reviewed.

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Currently, few test data are available for determining the most suitable corrosion-resistant alloys (CRAs) for downhole injection equipment in carbon capture and storage (CCS) and carbon capture, use, and storage (CCUS) wells. The complete paper provides a guideline for such selections based on the composition of the CO2 stream, including impurities and the composition of the saline formation into which the CO2 will be injected.

Introduction

For those CCS and CCUS systems where water is expected to be present at some point, such as injection into a saline formation or by virtue of incomplete dehydration, carbon steel will corrode and CRAs must be considered. Because carbon steel pipelines are standard practice for transport of supercritical CO2 and have a long, successful history, this paper is strictly focused on the selection of CRAs for injection wells.

While the selection of CRA material can be, and often is, based on common practices, each application requires an in-depth review of the complete system to determine the best materials for the job. In the case of storage, service life is ostensibly forever, so even otherwise minor pitting rates may not be tolerable in permanent equipment. The most important factors to consider for CRA corrosion are temperature, pH of the water phase, formation-water composition (typically chloride content), and stream impurities. With respect to temperature, this paper is focused on corrosion within CCS and CCUS wells and, therefore, considers only elevated temperature resulting from downhole geothermal gradients.

Stream impurities have a significant effect on potential CRA selection, especially when certain species such as oxygen are present. However, hydrogen sulfide (H2S) and nitrogen and sulfur oxides also can be important to this selection.

Technical Review of CCS and CCUS Injection Conditions

Much of the CRA experience from the oil patch cannot be applied directly to CCS and CCUS well design. Multiple sources are susceptible to significant residual H2S in the injectate. Currently, no standards or guidelines exist relating to the effect of H2S in supercritical CO2 on materials. Therefore, the industry default at the time of writing is to apply the industry standard NACE MR0175/ISO 15156-3, though it is important to note that environmentally assisted cracking resistance has not been established for many CRAs at pH 3 and lower. It also is important to recognize that this standard is specifically applicable to production of oil and gas, and it remains to be determined whether CCS and CCUS operations are similar enough to apply this guide, or if supercritical CO2 warrants different limits, particularly when O2 is present.

The presence of O2 in supercritical-CO2 streams presents a significant problem for the selection of CRAs. The corrosivity from O2 is defined by the dissolved oxygen concentration in the water phase, which is difficult to model in complex systems. Currently, these data are not readily available for supercritical-CO2 streams commingled with formation brines. As a guide, albeit a qualitative one, use of the pitting resistance equivalent number (PREN) is helpful for ranking resistance to pitting and crevice corrosion in aerated brine.