Study Assesses Integrity, Corrosion Risks of CO2 Injection in Oil-Recovery Operations

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 224770, “Research on Carbon Capture Utilization and Storage in Drilling and Completion Engineering,” by Fei Zhao, Yan Ding, and Congyue Lv, CNPC, et al. The paper has not been peer-reviewed.

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Globally, CO2 enhanced-oil-recovery technology is widely used, leveraging subsurface CO2 storage to enhance crude oil-recovery rates. However, this process introduces significant risks, particularly casing corrosion in downhole environments. This study aims to assess systematically casing integrity and corrosion risks associated with CO2 injection in oil-recovery operations.

CO2 Oil Displacement and Storage

CO2 oil-displacement technology can reduce CO2 emissions significantly during the extraction, processing, use, and transportation of crude oil. Through continuous research on this new technology, key issues in recent years have been addressed. Currently, a supporting technology for CO2 flooding and storage has been developed, and an evaluation and verification system for the full life-cycle-safety assessment of CO2 storage production has been established. A confirmed CO22-emission-reduction system also has been established to evaluate the safety of the entire life cycle, achieving optimal conditions for both oil production and storage.

In the development process of oil fields, CO2 flooding does not require special conditions and has strong applicability. Moreover, CO2 oil-displacement technology can be applied in the early, middle, or late stages of the field. CO2 flow involves few negative factors and does not damage the reservoir, making it suitable for long-term implementation of tertiary oil-recovery technology in the process of oil extraction.

Complex Situations Related to CO2 Flooding, Drilling, and Completion Engineering

CO2 Flooding Causes Casing Failure in Oil Reservoirs.

During the process of injecting CO2 gas, the low-temperature environment causes the packer to fail to seal. The injected CO2 gas enters the oil casing through the packer and is displaced with the annulus-protection fluid, causing the gas to climb to the upper part of the annulus near the wellhead. Because of the injection of CO2 gas, the temperature at the wellhead location is the lowest, so the casing at the wellhead location is in a low-temperature environment.

As a result of the long, intermittent process of injecting CO2 into the formation during oil extraction, the casing undergoes periodic loading, resulting in cracks extending from the inner wall to the outer wall. During the major maintenance of the casing, lifting the casing string can cause rapid crack growth.

Temperature has a significant effect on the corrosion process of casing. As the temperature increases, the amount of CO2 in the corrosion medium decreases, thereby reducing the corrosion rate of the casing. Moreover, with the increase of temperature, ion activity, chemistry, electrochemistry, and corrosion rate, temperature also can affect the formation of ions and the corrosion of thin film products, indirectly affecting the corrosion process of casing. Generally speaking, with the increase of formation temperature, the corrosion rate of casing will initially increase. When the temperature reaches a certain value, as the temperature increases, a dense corrosion product film on the surface of the casing will be created. This film-product corrosion separates the casing from the medium corrosion, thereby protecting the casing to a certain extent and reducing the corrosion rate.