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Picture for Formation of strong acids in dense phase CO2
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51318-11429-Formation of strong acids in dense phase CO2

Product Number: 51318-11429-SG
Author: Bjørn Helge Morland / Morten Tjelta / Arne Dugstad / Gaute Svenningsen
Publication Date: 2018
$20.00

Results from novel transparent autoclave experiments. Carbon steel corrosion coupons were exposed to impurities levels within established specifications at simulated transport conditions (25 °C and 10 MPa of CO2).
Picture for Applicability of Martensite-Based Stainless Steels for CO2 Injection Tubing
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Applicability of Martensite-Based Stainless Steels for CO2 Injection Tubing

Product Number: 51324-20636-SG
Author: Yuichi Kamo; Kenichiro Eguchi; Hiroyasu Ebina; Hiroyuki Takai; Takamasa Kawai
Publication Date: 2024
$40.00
This paper discusses the risks to the integrity of tubing material used in Carbon Capture and Storage (CCS). One risk is the formation of condensed water at the wellhead, which can lead to corrosion. FEM analysis of the waterlcontaining CO2 flux in the well indicated that the risk of corrosion due to condensed water was very low. Another risk is cooling of the tubing by cold CO2 when the temperature of CO2 is drastically decreased by the JoulelThomson effect. A cooling experiment in which cold nitrogen gas was applied to a steel pipe showed that the temperature of the steel did not decrease to the temperature of the cold gas, indicating that the cooled area was limited to the surface of the steel. The Charpy impact test demonstrated that martensitelbased stainless steels have good lowltemperature toughness. Corrosion of the steel pipe at the bottom hole, where it comes into contact with formation water, is also a risk to the material integrity. Corrosion tests of the steels in SO2 and NO2 contaminated conditions showed that not only S25CR but also modified 13CR (Mod. 13CR), 15CR, 17CR steels have good corrosion resistance in terms of the corrosion rate, resistance to localized corrosion and resistance to SCC under the SO2 and NO2 contaminated conditions.
Picture for Corrosion Behavior of Martensite-Based Stainless Steels in Chloride Solutions Saturated with CO2 Containing Impurity Gases
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Corrosion Behavior of Martensite-Based Stainless Steels in Chloride Solutions Saturated with CO2 Containing Impurity Gases

Product Number: 51323-18908-SG
Author: Yuichi Kamo, Kenichiro Eguchi, Hiroyuki Takai
Publication Date: 2023
$20.00

Carbon Capture and Storage (CCS) is a countermeasure for the global warming issue, and the number of CCS projects has increased. One type of CCS is Enhanced Oil Recovery (EOR), in which CO2 is injected into oil or natural gas reservoirs. Because formation water, which usually has a high concentration of chloride, exists at the bottom of these reservoirs, the injection tubing will suffer corrosion when the formation water flows back to the tubing. Stainless steels have been applied as tubing materials for Oil Country Tubular Goods (OCTG), and showed excellent corrosion resistance under high temperature and high CO2 pressure conditions. Martensite-based stainless steels bearing 13 mass% Cr to 17 mass% Cr are one of these tubing materials and are also expected to be used in CO2 injection tubing.
Picture for Corrosion of Cr-Alloyed Steels in Supercritical CO2-Saturated Brine Water
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Corrosion of Cr-Alloyed Steels in Supercritical CO2-Saturated Brine Water

Product Number: 51324-20809-SG
Author: Alexander Gross; Haofei Sun; Jing Liu
Publication Date: 2024
$40.00
In the context of urgent efforts to reduce global carbon emissions, carbon capture, utilization, and storage (CCUS) has gained prominence. Tubing and casing steels are vital materials of construction (MOC) in CCUS systems, especially in supercritical CO2 (s-CO2) environments. However, the understanding of the corrosion behavior of these steels under s-CO2 conditions is limited, which presents integrity challenges. Immersion experiments were conducted with steels containing varying chromium (Cr) levels (0.5 wt% to 16.5 wt%), including P110, P91, and SS 316. These steels were exposed to s-CO2-saturated brine water (3.5 wt% NaCl) at 50 °C and 10 MPa for durations of 10 and 100 hours. Corrosion rates were determined via weight loss measurements, and corrosion products were analyzed with SEM and XRD. P110 displayed the highest corrosion rates (15.7 mm/y at 10 hours, 2.9 mm/y at 100 hours) but developed a thick FeCO3 layer after 100 hours. In contrast, P91 and SS 316 exhibited lower corrosion rates after 100 hours (0.04 mm/y and < 0.01 mm/y, respectively). The influence of Cr content and exposure duration on the corrosion behavior of these steels were discussed. All steels exhibited decreasing corrosion rates over time, primarily due to oxide formation, enhancing the understanding of casing and tubing steel corrosion in s-CO2 environments.
Picture for Corrosion Resistance Evaluation Of Super Duplex Stainless Steel In Supercritical CO2 Saturated Liquid Phase Containing Impurities O2 Or SO2
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Corrosion Resistance Evaluation Of Super Duplex Stainless Steel In Supercritical CO2 Saturated Liquid Phase Containing Impurities O2 Or SO2

Product Number: 51322-17602-SG
Author: Daisuke Matsuo, Masayuki Sagara, Yuji Arai, Hisashi Amaya, Kyohei Kanki
Publication Date: 2022
$20.00

Carbon capture, utilization and storage (CCUS) is one of the key technologies to achieve the net-zero emission. One of the CCUS method is CO2 injection to depleted oil and gas wells or aquifers and storage (CCS). The CO2 emitted from fossil fuel-based powers and industrial plants are captured and transported to the injection point by ships or pipe line. Following that, the dense phase or supercritical phase CO2 will be injected to depleted oil and gas wells or aquifers through oil country tubular goods, for examples, seamless pipe.
Picture for Corrosion Resistance of Duplex Stainless Steels for CCS Application under the Liquid Phase in Equilibrium with Supercritical CO2 Containing Slight Amount of O2
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Corrosion Resistance of Duplex Stainless Steels for CCS Application under the Liquid Phase in Equilibrium with Supercritical CO2 Containing Slight Amount of O2

Product Number: 51324-20598-SG
Author: Kyohei Kanki; Daisuke Matsuo; Yuji Arai; Hisashi Amaya
Publication Date: 2024
$40.00
In carbon dioxide capture and storage, CO2 emitted from various industries containing impurities is captured and injected underground in dense or supercritical phase through tubings. In order to evaluate corrosion resistances of materials in the supercritical CO2 with a slight amount of O2, corrosion tests were performed under the conditions of 5 mass% NaCl equilibrium with CO2, containing with the various amount of O2 at total pressure of 130 bar and 100 °C. Super Martensitic Stainless Steel (UNS S41426), Duplex Stainless Steel (UNS S82551), and Super Duplex Stainless Steel (UNS S39274) were evaluated. Localized corrosion was observed in S41426 at conditions higher than 200ppm O2 (0.026 bar O2 partial pressure) condition. On the other hand, S82551 and S39274 showed good corrosion resistance in the same condition. As for S82551, it suffered from localized corrosion at 1000ppm O2 (0.13 bar O2) condition. However, in the actual O2 concentrations, it is considered that S82551 and S39274 are suitable materials even if formation water flow back has occurred.
Picture for Pitfalls And Artefacts In Corrosion Experiments With Dense Phase CO2
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Pitfalls And Artefacts In Corrosion Experiments With Dense Phase CO2

Product Number: 51321-16667-SG
Author: Bjørn Helge Morland; Gaute Svenningsen
Publication Date: 2021
$20.00
Picture for Predicting Corrosion Severity of Pipeline Steels in Supercritical CO2 Environments Using Supervised Machine Learning
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Predicting Corrosion Severity of Pipeline Steels in Supercritical CO2 Environments Using Supervised Machine Learning

Product Number: 51324-20803-SG
Author: Emily Seto; Meifeng Li; Jing Liu
Publication Date: 2024
$40.00
The importance of effective corrosion management in carbon capture, utilization, and storage (CCUS) networks has significantly increased. Captured CO2 is often transported in the supercritical state (s-CO2) and can contain impurities like H2O, O2, SOx, or NOx. While repurposing existing oil and gas pipelines for s-CO2 transport has been suggested, further testing and risk assessment is required to validate this strategy and its associated risks. Given the substantial amount of corrosion data available from recent corrosion studies, machine learning (ML) has emerged as a promising tool for corrosion prediction and management. This study aims to utilize supervised ML techniques to predict the corrosion severity of pipeline steels operating in s-CO2 systems. The selected algorithms, random forest (RF), K-nearest neighbor (KNN), and support vector machine (SVM) were trained on a comprehensive data set of X-series pipeline steels which includes corrosion rates, impurity levels, temperatures, pressures, and exposure times. Additional testing data set and error and accuracy scores were used to determine the most accurate algorithm. An additional experimental testing was performed to verify the predictions of the model. It was found that the RF model had the best accuracy of 65.3% out of the three tested models and KNN had the worst accuracy of 59.2%. In multiple impurity environments the RF model was able to accurately predict corrosion severity but overestimated corrosion severity in environments with short exposure times.
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