Corrosion and Material Degradation in Geological CO2 Storage: A Critical Review

Xin Fan; Qing Hu; Y. Frank Cheng

doi:10.1016/j.eng.2025.02.021

Engineering ›› 2025, Vol. 48 ›› Issue (5) :45 -63. DOI: 10.1016/j.eng.2025.02.021

Research Carbon Capture, Utilization, and Storage—Review

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Corrosion and Material Degradation in Geological CO₂ Storage: A Critical Review

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Abstract

At present, carbon capture and storage (CCS) is the only mature and commercialized technology capable of effectively and economically reducing greenhouse gas emissions to achieve a significant and immediate impact on the CO₂ level on Earth. Notably, long-term geological storage of captured CO₂ has emerged as a primary storage method, given its minimal impact on surface ecological environments and high level of safety. The integrity of CO₂ storage wellbores can be compromised by the corrosion of steel casings and degradation of cement in supercritical CO₂ storage environments, potentially leading to the leakage of stored CO₂ from the sites. This critical review endeavors to establish a knowledge foundation for the corrosion and materials degradation associated with geological CO₂ storage through an in-depth examination and analysis of the environments, operation, and the state-of-the-art progress in research pertaining to the topic. This article discusses the physical and chemical properties of CO₂ in its supercritical phase during injection and storage. It then introduces the principle of geological CO₂ storage, considerations in the construction of storage systems, and the unique geo–bio–chemical environment involving aqueous media and microbial communities in CO₂ storage. After a comprehensive analysis of existing knowledge on corrosion in CO₂ storage, including corrosion mechanisms, parametric effects, and corrosion rate measurements, this review identifies technical gaps and puts forward potential avenues for further research in steel corrosion within geological CO₂ storage systems.

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Geological CO₂ storage / Supercritical CO₂ / Geo–bio–chemical environments / Corrosion / Cement degradation

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Xin Fan, Qing Hu, Y. Frank Cheng. Corrosion and Material Degradation in Geological CO₂ Storage: A Critical Review. Engineering, 2025, 48(5): 45-63 DOI:10.1016/j.eng.2025.02.021

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1. Introduction

Despite the significant challenges posed by climate change, it is apparent that fossil fuels—especially natural gas—may continue to play a significant role in meeting the demands of both industry and civilians for the foreseeable future. The Paris Agreement Article 6 states that multiple pathways should be provided as much as possible to incentivize carbon capture and storage (CCS) [1]. At present, CCS is the only mature and commercialized technology capable of effectively and economically reducing greenhouse gas (GHG) emissions to achieve a significant and immediate impact on the CO₂ level on Earth [2], [3]. CCS technology comprises several essential steps: ① CO₂ is captured from industrial sources (i.e., anthropogenic CO₂) or natural wells; ② the captured CO₂ is compressed into a supercritical state for transportation; and ③ the CO₂ is injected into formations or the ocean for long-term storage, effectively isolating it from the atmosphere [4]. The capture of CO₂ mostly occurs in fossil-fuel-burning power generation and industrial sectors emitting large amounts of CO₂, such as the chemical industry, oil/gas production, steelmaking, and manufacturing [5]. The captured CO₂ is transported to storage locations by various methods, ranging from traditional tankers and ships to pipeline transportation. CO₂ storage methods include geological storage in certain geological structures (e.g., depleted oil and gas fields, deep saline water layers, and non-exploitable coal seams), marine storage by directly injecting CO₂ into seawater or into storage below 1500 m in the deep sea, and solidification in inorganic carbonates through industrial processes [6], [7], [8]. To provide a comprehensive overview of the CO₂ storage landscape, Fig. 1 [9] schematically illustrates the various CO₂ geological storage methods, both offshore and onshore, along with their relevant depth distributions. It includes a detailed illustration of geological CO₂ storage in depleted oil and gas fields, deep saline water layers, and non-exploitable coal seams, as well as CO₂ injection for enhanced oil recovery (EOR).

Geological storage stands out among the various methods for CO₂ storage due to its minimal impact on the surface ecological environment and its high level of safety. Underground formations characterized by porous rock structures, such as abandoned oil and gas reservoirs, are promising CO₂ storage sites, possessing the necessary attributes of good gas distribution and appropriate chemical properties, permeability, and porosity required for long-term CO₂ storage [10], [11]. For example, abandoned natural gas fields are a typical type of geological reservoir with significant CO₂ storage potential [12]. Almost the entire volume of an abandoned gas field can be used for CO₂ storage. Furthermore, abandoned natural gas fields are widely distributed, with an estimated total carbon storage potential ranging from 98 to 133 Gt [13], [14], [15], [16]. According to the Global Status of CCS 2023 report [17], there were 41 large-scale CCS and carbon capture, utilization, and storage (CCUS) projects in operation worldwide as of September 2023, with most being located in North America and Europe. The CO₂ captured in 29 of these projects is utilized for EOR, whereas the remaining projects focus on direct geological storage [17].

One major concern for safe and efficient CO₂ storage is the potential leakage of CO₂ from underground storage sites, which would have extremely adverse effects on the ecological balance of animals and plants and on human health [18]. Corrosion and cement degradation of underground storage wellbore facilities is one of the primary reasons leading to CO₂ leakage [2], [19], [20]. In geological storage technology, CO₂ flows into the formation through perforations in steel pipes and casing. CO₂ is usually compressed into a supercritical fluid state and then injected into underground rock structures, as it thus has a lower density than the residual liquid in the reservoir [21]. The injection well is considered the most vulnerable component in CO₂ storage systems and is highly likely to become a potential leakage pathway for CO₂ [22]. This vulnerability arises from both localized corrosion and uniform corrosion of steel pipes in the injection well. It was reported that the corrosion rates of 1018 carbon steel in CO₂ storage within the Weyburn-Midale reservoir system reached up to 18.1 and 11.0 mm per year at 60 °C and CO₂ partial pressures of 30 and 80 bar, respectively (1 bar = 10⁵ Pa) [23].

The conditions that induce steel corrosion in CO₂ storage systems primarily stem from two sources. The captured CO₂ contains corrosive impurities such as SO_x and NO_x. CO₂ with these impurities can dissolve in water to form strong acids, thereby reducing the pH of the solution and creating acidic, corrosive environments [20], [24]. The complex geological setting, coupled with biological and chemical factors, can also lead to severe corrosion of underground facilities [25]. Multiple factors within injection wells can compromise the long-term integrity of CO₂ storage systems, thereby contributing to CO₂ leakages [18]. For example, improper control or fluctuations in pressure during CO₂ injection can lead to rupture of the wellbore or the reservoir structure. The casing within the wellbore may fracture or deform under high pressures, especially after prolonged use. This could result in a loss of seal integrity between the wellbore and the underground reservoir, allowing CO₂ to leak through fractures [12], [26]. Seismic and other geological activities can cause shifts or fractures in the reservoir. Additionally, the heterogeneous geological properties of the reservoir, such as variations in porosity and permeability, may lead to uneven CO₂ distribution during injection. This can result in localized pressure buildup, potentially causing the wellbore to fracture or the cement layer to fail, which in turn leads to CO₂ leakage [13], [14], [15].

Studies have been conducted to explore solutions aimed at maintaining wellbore integrity for the long-term storage of CO₂ [27], [28], [29]. In particular, corrosion of the injected wellbore has been identified as a crucial factor in degrading the integrity of CO₂ storage [28]. Such corrosion is primarily affected by acidic gases and formation water, which lead to the generation of strong acids and, consequently, severe corrosion of steel components [30]. Moreover, cement degradation in CO₂ storage environments is a critical concern, as the interactions between CO₂, water, and cement materials can lead to the formation of detrimental byproducts, causing leakage of CO₂ to the ground or adjacent permeable layers [31]. The use of a recently developed cement with a novel composition and structure can not only prevent cement degradation but also protect casings from corrosion attack [32]. Both mechanistic and empirical models have been developed to evaluate and predict steel corrosion under CO₂ storage conditions [19], [33]. In addition to corrosion, stress corrosion cracking (SCC) and sulfide stress cracking (SSC) can pose great threats to the integrity of the wellbore, leading to CO₂ leakage. It is thus apparent that the long-term safety and effectiveness of underground CO₂ storage depends on maintaining the integrity of the wellbore, which requires thorough research on corrosion control [34], [35], [36], [37], [38], [39].

This critical review endeavors to establish a knowledge foundation for the corrosion and materials degradation associated with geological CO₂ storage. This is achieved through an in-depth examination and analysis of the environment, operation, and state-of-the-art progress in research pertaining to corrosion of steel facilities in CO₂ storage. This review article starts with a concise introduction of the advantages and status of CCS projects, CO₂ storage, and corrosion problems occurring in geological CO₂ storage. Subsequently, it describes the physical and chemical properties of CO₂ in its supercritical phase during injection and storage. Next, the article introduces the principle of underground CO₂ storage, along with considerations for the construction of storage systems. After reviewing the unique geo–bio–chemical environment in CO₂ storage, which involves aqueous media and microbial communities, the main types of corrosion encountered in this environment and their mechanisms are discussed. Through a comprehensive analysis of existing knowledge on corrosion in CO₂ storage, this review puts forward potential avenues for further research on steel corrosion within geological CO₂ storage systems, along with proactive and feasible measures aimed at ensuring effective corrosion control in CO₂ storage facilities. Given the growing importance of CO₂ storage in combating climate change, it is essential to understand and manage corrosion risks in order to ensure the long-term safety and integrity of CO₂ storage systems. This review provides crucial guidance for this endeavor, as it consolidates the current understanding of corrosion in CO₂ storage and provides a foundation for future research and practical solutions.

2. Supercritical CO₂ and its physicochemical properties

2.1. Physical properties of supercritical CO₂

As stated earlier, CO₂ is typically compressed into a supercritical fluid state and stored underground to effectively utilize geological storage capacity and prevent CO₂ from leaking into the atmosphere or escaping into groundwater [40]. Fig. 2 shows the phase diagram of CO₂ fluid, where BD, BC, and AB refer to the melting curve, vaporization curve, and sublimation curve, respectively. Point B is the triple point (−56.57 °C, 216.58 K, and 5.11 atm; 1 atm = 101 325 Pa), and Point C is the critical point (30.98 °C, 304.13 K, and 72.79 atm). The critical point represents the maximum pressure and temperature beyond which the liquid and gaseous phases become indistinguishable. Beyond the critical point, CO₂ becomes a supercritical fluid. Supercritical CO₂ has a high density close to that of liquid CO₂ and several hundred times greater than the density of CO₂ gas. The range of the density of supercritical CO₂ is approximately 1.08–2.75 g·cm⁻³ [41], [42]. The viscosity of supercritical CO₂, depending on the temperature and pressure, is low, close to that of a gas and two orders of magnitude lower than that of gaseous CO₂. Under common experimental conditions, for example, at 40 °C and 7 MPa, the viscosity of supercritical CO₂ typically ranges from approximately 0.1 to 0.2 mPa·s. This range can change depending on the specific temperature and pressure conditions. Generally, the viscosity decreases as the temperature increases and slightly increases with higher pressure. The flow and mass transfer performance of CO₂ in its supercritical state is good, with a surface tension of 0. Supercritical CO₂ is also compressible, as compressing supercritical CO₂ does not lead to the formation of a liquid phase but only results in an increase in density [43].

Notably, the physical properties of CO₂ depend on its composition. Various impurities are inevitably included in captured CO₂ gas, causing the physical properties of the captured CO₂ to differ from those of pure CO₂. Changes in the phase characteristics of CO₂, such as alterations in pressure and temperature approaching the critical point, can affect the phase state of CO₂ in underground storage. Consequently, these changes influence the corrosive environment within the system. Phase equilibrium calculation models have been proposed to analyze the phase changes of CO₂ containing the impurities found in captured CO₂. These models provide insights for corrosion management of the underground storage of supercritical CO₂ and appropriate specifications for processing equipment [44], [45].

2.2. Chemical properties of supercritical CO₂

Supercritical CO₂ exhibits a high diffusion coefficient similar to that of a gas and surpassing that of a liquid by 10–100 times; this property accelerates the reaction kinetics, resulting in faster reaction rates [46]. Supercritical CO₂ possesses high solubility, enabling effective dissolution in many organic compounds such as fatty acids, esters, and alcohols. This solubility facilitates the substitution of many organic solvents in processes such as extraction, monomer separation, and compound purification. Finally, supercritical CO₂ can facilitate chemical reactions under high-pressure and high-temperature conditions. Alterations in system pressure can modulate both the rate and selectivity of the reaction [47].

Captured CO₂ invariably contains specific types and quantities of impurities, which vary according to the capture technology employed and the sources of CO₂. For example, the CO₂ captured after combustion contains pollutants such as N₂, O₂, H₂, CO, Ar, H₂O, SO_x, and NO_x, whereas the CO₂ obtained through pre-combustion capture technology usually contains impurities such as N₂, H₂, CH₄, CO, and H₂S [48]. These impurities—particularly SO_x and NO_x—dissolve in water during the storage process, which leads to the formation of acidic environments characterized by strong corrosivity. If impurities are not efficiently removed from the CO₂ fluid, severe corrosion occurs in the wellbore and other steel components within the CO₂ storage system [49]. This will compromise the integrity and safety of the CO₂ injection and storage system [50]. At present, widespread attention is directed toward understanding the effect of impurities on the accelerated and localized corrosion of steels in supercritical CO₂ fluids. Details on the corrosion reactions of supercritical CO₂ with steel, along with the corrosion mechanisms, are provided in Section 5.1.

3. CO₂ storage: Principle, construction considerations, and current status

There are four distinct phases of CO₂ sequestration and storage, as follows [51]: ① site selection and development (3–10 years) for CO₂ sequestration; ② operation (>10 years), which starts when CO₂ is injected underground; ③ closure of the injection wells and monitoring of the reservoirs to ensure successful implementation of the sequestration project; and ④ post closure, which establishes the permanence of the CO₂ reservoir. Three essential elements are required for feasible geological storage, namely, sufficient pore volume to store the gas, a sealing layer to ensure containment, and high injectivity.

3.1. The principle of geological CO₂ storage

During injection into the sealing formation, supercritical CO₂ diffuses horizontally and upward because of its gas buoyancy. However, the CO₂ is unlikely to leak upward into the upper aquifer. Compared with aquifers, cap rocks in the upper part of the reservoir have higher capillary pressure, allowing the continuous accumulation of supercritical CO₂ at the bottom of the cap rocks. Once the accumulated CO₂ reaches a certain thickness, it can overcome the constraint of capillary pressure and quickly diffuse upward through the low-permeability cap rocks into the upper aquifer. At the same time, the CO₂ gathered at the bottom of the cap rocks undergoes continuous diffusion along the groundwater flow direction. As a result, the thickness of the CO₂ accumulation decreases, preventing the CO₂ from spreading upward and thereby enabling its long-term storage. This process is schematically illustrated in Fig. 3 [52].

After injection, the CO₂ fluid permeating into the rock pores generates a certain tension, and a fraction of the CO₂ remains trapped within the pores for a long time. This trapped CO₂ is known as residual gas saturation. A higher saturation of residual gas implies that more CO₂ is retained within the rock pores, preventing further diffusion to the surrounding area. The residual CO₂ can dissolve in water and react with rock minerals, forming carbonate mineral precipitation. This process contributes to the storage of a portion of the CO₂ within the reservoir [53].

3.2. Considerations for the construction of CO₂ storage systems

When selecting a site for geological CO₂ storage, it is essential to ensure that the site’s geographical location is characterized by stable geological structures. Three elements are crucial for the technical feasibility of CO₂ storage:

•Capacity. The porosity and permeability of the reservoir must be adequate to achieve the necessary storage capacity.

•Injectivity. The formation characteristics must allow near-wellbore injectivity.

•Containment. An overlying sealing package must ensure the containment of appropriate fluids [45].

The geological environment suitable for storing captured CO₂ must not only possess the necessary characteristics but also effectively prevent CO₂ from migrating laterally or leaking vertically to other strata, shallow drinking water, soil, or the atmosphere [54].

3.2.1. Safety

Safety stands as the foremost priority in geological CO₂ storage, serving as the key consideration in the construction and operation of CO₂ storage projects. Risks to the safety of CO₂ storage systems include high concentrations of CO₂ leakage, resulting in adverse effects on plants, animals, humans, and local ecological environments. In addition, pressure accumulation during the injection of large volumes of CO₂ into sedimentary layers may trigger earthquakes [55], [56]. Measures that can be taken to minimize these risks include the following:

•Proper design. During the design stage of underground CO₂ storage construction, it is necessary to collect historical data to assess the potential for fluid leakage related to CCS projects. This information is crucial for ensuring the long-term maintenance of wellbore integrity [57].

•Leakage monitoring. As it typically takes a relatively lengthy period for leaked CO₂ to reach the ground, early detection of leakage is effective in minimizing the potential for disasters associated with leakage.

•Timely remediation. In the event of leakage at the storage location, prompt remedial actions are imperative to prevent the spread of leakage. Remediation methods may include employing standard well remediation techniques, applying suitable sealants to address CO₂ leakage pathways, or intercepting and extracting CO₂ before it infiltrates the shallow groundwater layer above [58].

•Long-term monitoring. Considering the long-term nature of geological CO₂ storage, continuous monitoring of storage locations for potential leakage is essential.

At present, research demonstrating the practical efficacy of available leakage risk-management methods is needed. In addition, these methods must be continually updated based on real-world operation experiences in CO₂ underground storage projects [59].

3.2.2. Storage capacity

Estimating the CO₂ storage capacity of particular geological sites, such as non-exploitable coal seams, abandoned oil/gas reservoirs, and deep saline water layers, is a key step in identifying suitable locations. A site with a good CO₂ storage capacity typically features ample underground space and favorable porosity, where the latter is essential to provide sufficient pore volume to accommodate a large amount of CO₂. The geological structure and lithology also significantly affect the success of CO₂ storage projects [60], [61]. Among various types of underground storage sites, evaluating the CO₂ storage capacity of oil and gas reservoirs is relatively easy. It is also well known that deep saltwater layers feature extensive storage capacity [62].

The evaluation of CO₂ storage capacity at certain sites is usually conducted using numerical modeling techniques. Modeling methods can predict the amount of residual CO₂ dissolved or retained near the pore space and the movement of CO₂ within geological formations, thereby guiding appropriate positioning of the injection equipment to ensure efficient use of underground storage capacity and minimize the risk of CO₂ escape into the atmosphere [63]. Efforts are made to identify suitable geological locations based on factors such as porosity, permeability, thickness, and depth. These considerations are used to pinpoint sites with ample storage space, confining formations, and the capability to securely retain injected CO₂ for hundreds of years [64], [65].

3.3. Global status of geological CO₂ storage projects

While the majority of operational CCS projects utilize the captured CO₂ for EOR purposes, there are 12 projects dedicated to geological storage as of 2023. These projects are distributed across Australia, Canada, China, Iceland, Norway, Qatar, and the United States. The Global CCS projects dedicated to geological CO₂ storage as of 2023 are outlined in Table 1 [17].

In addition, there are 20 new CCS projects with dedicated geological CO₂ storage projects under construction, as compared with only five new projects utilizing CO₂ for EOR purposes [17]. These numbers suggest a significant shift toward long-term carbon sequestration, rather than the short-term economic benefits realized through EOR. This shift reflects growing concerns over climate change and increased efforts to reduce GHG emissions. The new geological CO₂ storage sites extend to countries including Malaysia (1), Netherlands (1), and Oman (1), as well as Australia (1), China (2), Iceland (2), Norway (3), Qatar (1), and the United States (8).

4. Typical geo–bio–chemical environments in geological CO₂ storage

4.1. Geochemical environments

Exploring the geochemical environment of underground CO₂ storage involves investigating the interactions between CO₂ and rock formations. These interactions include various chemical and biological reactions that occur in the underground geological environment. Such research helps to assess the integrity of the wellbore system and estimate the efficiency of CO₂ storage. Suitable reservoir rocks generally have high porosity and permeability; examples include sandstone, limestone, dolomite, basalt, or their mixtures. The cap rocks are typically composed of shale, anhydrite, or low-permeability carbonate rocks [66]. For example, the Sleipner CCS Project—the first commercial-scale CO₂ storage project injecting captured CO₂ into an offshore saline aquifer located in the Norwegian North Sea [67]—is characterized by a geological environment composed of permeable sandstone layers beneath a low-permeability shale cap layer [68]. Deep geological reservoirs used for CO₂ storage are typically composed of limestone (primarily calcite, CaCO₃) and dolomite (CaMg[CO₃]₂). Storage reservoirs with quartz and metal (aluminum) silicates also exist. The brine contained in such reservoirs is primarily composed of Na⁺, Cl⁻, Ca²⁺, and SO₄²⁻ [28].

To assess the impact of sedimentary environments on CO₂ storage efficiency, a more detailed approach is needed to classify salt-bearing strata based on specific sedimentary environments, instead of broad rock types like sandstone, limestone, and dolomite [69]. It has been accepted that acidic environments formed by the dissolution of CO₂ into formation brine can promote ion exchange and induce geochemical interactions [70], [71], [72]. Impurities and acidic gases contained in the captured CO₂ also undergo chemical reactions with rocks [29]. For example, SO_x compounds react with rocks to produce sedimentary sulfates, thereby reducing rock porosity and consequently lowering injection capacity. The interaction between CO₂ and rocks may dissolve certain minerals (e.g., carbonate, feldspar, kaolinite, calcite, chlorite, and barite) or lead to clay precipitation [70].

Chemical reactions between CO₂ and components of the underground geological environment lead to the formation of acidic H₂CO₃ when CO₂ dissolves in saline water. This acidic environment is the primary mechanism responsible for the corrosion of steel facilities. Moreover, as the water pH decreases, the interactions among the CO₂, water, and rocks can shift from rock-dominated reactions into fluid-dominated reactions. This transition often leads to the acidic erosion of minerals in both the cement and the host rocks [70]. The reactions involving carbonate and sulfate minerals are rapid and can reach equilibrium within a few hours at ambient temperature. Therefore, the occurrence of these reactions during the injection phase will have a significant impact on the well environment, such as the porosity and permeability of the reservoir. All these processes significantly affect the reservoir environment and the storage of CO₂ within it. The geochemical reactions involved are closely linked to challenges such as CO₂ leakage and the integrity of wellbores [73], especially in carbonate-containing rocks under low-temperature conditions [74].

4.2. Impact of microorganisms on the integrity of CO₂ storage wellbores

Microorganisms and their activities are widely acknowledged as significant factors affecting the successful implementation of geological hydrogen storage [75], [76], [77]. Microbial influence also plays an important role in geological CO₂ storage. Moreover, microbial activity can cause corrosion of metallic facilities, posing a threat to the integrity of wellbores intended for CO₂ storage. Among the various types of microorganisms found underground, sulfate-reducing bacteria (SRB) are notable as the primary bacteria responsible for causing and accelerating metallic corrosion in CO₂ storage environments [78]. SRB can electrochemically reduce underground sulfates, generating HS⁻ and H₂S through their metabolic processes. In combination with other environmental factors, such as formation water containing a substantial amount of dissolved Cl⁻, the steel casing suffers from corrosion in CO₂/H₂S/Cl⁻ environments. Microbiologically influenced corrosion (MIC) manifests on steel surfaces within the wellbore, typically under a biofilm. In the presence of SRB, steel undergoes accelerated corrosion and pitting corrosion, which lead to perforation and—in some cases—premature stress cracking of steel components [79], [80], [81], [82]. In addition, other microorganisms such as acid-producing bacteria (APB) and iron-reducing bacteria (IRB) may contribute to the generation of methane, acetyl acetic acid, and reduced iron, resulting in steel corrosion and degradation of the wellbore integrity [83], [84].

Over the past decade, progress has been made in both research and practical applications of the management of MIC in the oil and gas industry. More specifically, operators have adopted MIC threat-assessment models that use both qualitative and quantitative methods to evaluate the corrosion degradation rate in applications including CO₂ storage. A field case study in North Sea storage highlighted the differences between traditional microbiological methods and quantitative polymerase chain reaction (qPCR) technology for microbial characterization upon the implementation of a corrosion-control strategy. The results showed that the data obtained through qPCR changed the way in which MIC was monitored and managed. This practice has improved the accuracy and efficiency of MIC control in CO₂ storage [85].

Supercritical CO₂ has the potential to affect the microbial community in deep non-exploitable aquifers. It was found that, upon the injection of supercritical CO₂, some bacterial cells within a reservoir underwent rupture and loss of activity, leading to a decrease in their relative abundance [86]. The application of microbial-induced carbonate precipitation (MICP) technology has been proposed for geological CO₂ storage to enhance storage performance [87]. This approach involves the formation of mineral structures and biofilms that obstruct pores. Consequently, potential CO₂ leakage channels are reduced, limiting CO₂ migration and facilitating stable storage. Moreover, MICP can effectively convert CO₂ into minerals, thereby enabling extended storage.

5. Corrosion and materials degradation in geological CO₂ storage

The steel casing used for CO₂ geological storage is usually stabilized with cement. After CO₂ injection, the wellbore is sealed with a cement plug. During long-term underground service, both the steel and the cement may experience corrosion and degradation, resulting in loss of integrity of the storage system and leakage of the stored CO₂. Fig. 4 illustrates the potential pathways of CO₂ leakage resulting from corrosion and cement degradation through the excavation damage zone and the cement, casing, or fractures, as well as between the cement and the formation or casing [31], [88]. It is crucial to investigate steel corrosion, cement degradation, and parametric effects under CO₂ geological storage conditions in order to ensure the long-term integrity of wellbores for CO₂ storage.

5.1. Corrosion of steel casings: Mechanistic aspects

The corrosion of steels in supercritical CO₂ environments shares mechanistic similarities with the corrosion encountered in CO₂ environments under normal pressures [89]. When CO₂ dissolves in water, it undergoes hydration to produce carbonic acid (H₂CO₃), as follows:

(1) $\mathrm{CO}_{2(\mathrm{~g})}+\mathrm{H}_{2} \mathrm{O}_{(\mathrm{l})} \leftrightarrow \mathrm{H}_{2} \mathrm{CO}_{3(\mathrm{aq})}$

The H₂CO₃ then partially dissociates in two stages to form bicarbonate (HCO₃^–) and carbonate (CH₃^2–) ions:

(2) $\mathrm{H}_{2} \mathrm{CO}_{3} \leftrightarrow \mathrm{H}^{+}+\mathrm{HCO}_{3}^{-} \text {and } \mathrm{HCO}_{3}^{-} \leftrightarrow \mathrm{H}^{+}+\mathrm{CO}_{3}^{2-}$

5.1.1. Cathodic reactions

The dominant cathodic reaction during steel corrosion in a CO₂ environment varies, depending on the solution pH [90]. At a low pH of less than 4, which is typical for pure CO₂-saturated water at the pressures associated with supercritical CO₂ transport, the dominant process is the electrochemical reduction of H⁺ ions to produce H₂ molecules, as follows:

(3) $2 \mathrm{H}^{+}+2 \mathrm{e}^{-} \rightarrow \mathrm{H}_{2}$

At intermediate pH ranges (i.e., 4 < pH < 6), the diffusion rate of H⁺ ions is limited due to their low concentration. This pH range is usually observed in water condensates containing Fe²⁺ ions resulting from corrosion, which elevates the alkalinity of the electrolyte. In addition to hydrogen evolution, the cathodic reaction involving the electrochemical reduction of H₂CO₃ to generate HCO₃⁻ ions becomes significant:

(4) $2 \mathrm{H}_{2} \mathrm{CO}_{3}+2 \mathrm{e}^{-} \rightarrow \mathrm{H}_{2}+2 \mathrm{HCO}_{3}^{-}$

This reaction can potentially play a substantial role in the acceleration of corrosion in supercritical CO₂ systems [91]. However, there is ongoing debate regarding the extent to which this reaction actually occurs to any significant degree [92]. As the solution pH further increases toward the neutral and alkaline ranges, the concentration of HCO₃⁻ can surpass that of H₂CO₃. Consequently, the direct reduction of HCO₃⁻ becomes significant, leading to the production of CO₃²⁻ by the following reaction:

(5) $2 \mathrm{HCO}_{3}^{-}+2 \mathrm{e}^{-} \rightarrow \mathrm{H}_{2}+2 \mathrm{CO}_{3}^{2-}$

This reaction is typically disregarded in oil and gas and in CO₂ environments where achieving an alkaline pH is rare [89]. Finally, although the cathodic reduction of H₂O molecules is thermodynamically feasible, this reaction is much slower and generally does not significantly contribute toward the total cathodic reaction under typical CO₂ service conditions [89]. Therefore, the primary cathodic reactions during corrosion in CO₂ environments—including supercritical CO₂ transport service—are the reduction of H⁺ ions and H₂CO₃.

5.1.2. Anodic reaction and scale deposit

The anodic reaction during the CO₂ corrosion of steel is usually simplified as the oxidization of iron, as shown in Eq. (6). The actual process is much more complicated than this reaction [93].

(6) $\mathrm{Fe} \rightarrow \mathrm{Fe}^{2+}+2 \mathrm{e}^{-}$

Another crucial aspect of CO₂ corrosion involves the deposition of iron carbonate (FeCO₃) scale on the steel surface. When the concentration of Fe²⁺ and CO₃²⁻ ions exceed the solubility product, it becomes thermodynamically favorable for FeCO₃ to form as a corrosion product:

(7) $\mathrm{Fe}^{2+}+\mathrm{CO}_{3}{ }^{2-} \rightarrow \mathrm{FeCO}_{3}$

FeCO₃ scale can decrease the corrosion reaction kinetics, both by acting as a diffusion barrier to electrochemically active species and through a surface-coverage effect when adhering to the substrate. However, localized corrosion can occur under the scale if it has a porous structure [79]. The precipitation kinetics of FeCO₃ are typically influenced by the CO₂ concentration and pH. A high concentration of CO₂ promotes a decrease in the pH value (i.e., an acidic environment), which favors the precipitation of FeCO₃ by producing more Fe²⁺. When the dissolved oxygen concentration is low, the oxidation of iron (Fe) is weaker, which is more favorable for the formation of FeCO₃ from Fe²⁺ and CO₃^2⁻. At lower flow velocities, FeCO₃ is more likely to accumulate on the steel surface, forming a relatively stable deposition layer.

5.1.3. Other types of corrosion

In addition to uniform corrosion in a supercritical CO₂ environment, steel components may undergo other types of corrosion when subjected to various operating conditions. Galvanic corrosion may occur due to the cracking and peeling of the cement that separates the tubing and casing made of different metals. As a result, the tubing and casing come into electrical contact, with trapped fluid acting as an electrolyte. Corrosion then manifests on the equipment made of the more active metal, as illustrated in Fig. 5(a) [28]. For example, it was found that, when the cement between an N80 steel casing and a 13Cr stainless steel tubing was compromised in a supercritical CO₂ environment, the corrosion rate of the N80 steel increased upon coupling with the 13Cr stainless steel. This enhancement in corrosion was attributed to a galvanic effect, contrasting with the corrosion rate of N80 steel in the same environment [94].

SCC can occur on steel casings, causing devastating failures due to the synergism of stress and electrochemical corrosion under supercritical injection conditions, as shown in Fig. 5(b) [95]. Steel structures become more prone to SCC occurrence when CO₂ and H₂S coexist in the downhole environment [97]. The hoop stress exerted on the casing body, which results from internal pressure, is the primary stress. The weight of the steel casing generates significant tensile stress as well, contributing to SCC occurrence. Porous FeCO₃ scale on the steel surface will initiate localized corrosion under the scale. The corrosion defects (i.e., pits) transit toward cracks under appropriate chemical/electrochemical and geometrical conditions. It is thus expected that SCC will happen on steel casings in geological CO₂ storage systems.

Furthermore, MIC should not be ignored, considering the extensive microorganism population existing in geological CO₂ storage reservoirs [98]. The primary microorganisms that cause or accelerate steel corrosion include SRB, IRB, and APB, and many other types of bacteria may also be present. MIC typically occurs beneath a biofilm, which acts as a barrier, restricting the free exchange of solution chemistry between the bulk environment and the environment underneath the film [99]. Fig. 5(c) schematically illustrates a stratified multispecies biofilm at different stages of development on a corroding metal surface, explaining the involvement of the bacteria in the corrosion reaction [96]. This situation creates a unique solution chemistry and pH beneath the film, facilitating MIC. During the MIC process, microorganisms affect the concentration of dissolved oxygen, the pH, and other dissolved substances through metabolism, thereby affecting the precipitation behavior of FeCO₃ scale.

In CO₂ storage environments, the biofilm and CO₂ corrosion products—primarily FeCO₃ scale—frequently overlap, affecting microbial activity and further corroding the steel [100], [101], [102]. For example, high CO₂ concentrations in the fluid harm microbial cell viability, but factors such as mineral presence and biofilm formation help microbes adapt and grow under these harsh conditions [100]. The dynamics of microbial activity within different geological storage sites are influenced by a variety of factors, including specific microbial communities, physical conditions (e.g., temperature and pressure), and chemical parameters (e.g., salinity, carbon sources, electron acceptors, and donors). When CO₂ is dissolved in water, it creates conditions that promote increased corrosion of steels through a synergistic effect with SRB [103]. This enhances the growth of SRB and facilitates the formation of biofilms.

5.2. Progression of research on corrosion under geological CO₂ storage conditions

Investigations of CO₂ corrosion in high-pressure environments started from the CO₂ EOR process in the early 1990s [104]. In recent decades, significant progress has been made in understanding the mechanistic aspects of supercritical CO₂ corrosion, along with the study of CO₂ corrosion in oil and gas facilities. Parametric effects determined both qualitatively and quantitatively help in the development of techniques for efficient corrosion control and models for long-term corrosion prediction.

5.2.1. Effect of alloying composition and microstructure

Carbon and low-alloy steels are extensively used in CCS systems, including geological CO₂ storage, due to their availability and favorable performance–price ratio. It is widely accepted that, although carbon steels are prone to corrosion in CO₂ environments, the corrosion rate of these steels is affected by their chromium (Cr) content [105], [106]. In corrosion testing, steel samples are exposed to specific gas mixtures (e.g., CO₂ and/or H₂S) and water environments in an autoclave under set temperature and pressure conditions for a certain period. After the test, the samples are removed, cleaned, dried, and weighed. The weight loss of the samples before and after testing is used to calculate the corrosion rates. Table 2 [23], [107], [108], [109] summarizes the uniform corrosion rate of carbon steels containing various Cr contents in supercritical CO₂ environments. As the Cr content in the steels increases, there is typically a decrease in the uniform corrosion rate. This is generally observed over relatively short testing periods, such as 48 h. It is believed that the formation of a protective layer of corrosion product film on the steel surface contributes to this reduction in corrosion rate. Initially, a Cr-rich film comprising Cr(OH)₃ and a certain amount of FeCO₃ is formed to mitigate steel corrosion [107], [108]. However, as the exposure time progresses, the thickness of the corrosion products remains relatively unchanged. The Cr enrichment affects the nucleation and growth of FeCO₃ scale, thereby promoting the continuous expansion of pitting corrosion, which results in a decrease in corrosion protection effectiveness [107].

It can thus be seen that an alloying treatment of carbon steels with the addition of Cr can enhance their corrosion resistance in supercritical CO₂ environments, albeit primarily over short-exposure durations. During the long-term geological storage of supercritical CO₂, Cr alloying may not benefit the corrosion resistance of steel casings. This is primarily attributed to the mutual interference between Cr and Cr oxides with FeCO₃ scale formed on the steel surface [107].

The microstructure of the steel is also important for the CO₂ corrosion resistance of carbon steels. It is generally believed that martensite is more susceptible to localized corrosion than a ferrite-pearlite microstructure. This is related to the poor adhesion and crystallinity of the FeCO₃ scale formed on the surface of a martensite structure [111], [112]. However, new martensite structures may have better corrosion resistance than ferrite-pearlite microstructures in some cases [26]. Two types of martensitic stainless steel have been developed, both offering excellent weldability and enhanced corrosion resistance. The first type, designed for sweet environments, demonstrated superior resistance to CO₂ corrosion compared with 13Cr martensitic stainless steel. This improvement in corrosion resistance is attributed to the reduction of carbon content and the addition of nickel, which collectively lowers the general corrosion rate in CO₂ environments. Moreover, the addition of copper enhances the steel’s resistance to pitting corrosion. The second type, intended for light sweet environments, exhibited strong SSC resistance in welded joints, primarily due to the increased pitting resistance from the addition of molybdenum. Given that the casings employed for geological CO₂ storage predominantly consist of ferritic steels and ferrite-pearlite steels, there is currently limited research focusing on microstructural innovations to enhance corrosion resistance.

5.2.2. Effect of water content in supercritical CO₂ fluid

The water (or moisture) content present in supercritical CO₂ fluid is the paramount factor affecting steel corrosion. Water (or moisture) is essential for forming water condensate on the steel surface within a supercritical CO₂ environment, which subsequently becomes corrosive upon CO₂ dissolution [20]. When the water content is lower than the solubility limit of H₂O in CO₂, it is difficult for an acidic water film to form on the steel surface. Thus, the corrosion reaction becomes less favorable, resulting in a lower corrosion rate. However, field experiences have shown that corrosion can occur even within the recommended H₂O content limit in a supercritical CO₂ fluid. A critical moisture content exists (∼500 parts per million (ppm)) above which the corrosion rate increases significantly [113]. The corrosion rates of 1010 carbon steel in supercritical CO₂ containing various water contents at 7580 kPa and 40 °C were measured [114], and it was found that, even with a water content of 100 ppm in the CO₂ fluid, the corrosion rate of the steel reached 1.2 mm·a⁻¹. Upon an increase in water content to 1000 ppm, the corrosion rate escalated to 2.3 mm·a⁻¹.

Table 3 [113], [114], [115], [116], [117], [118] lists the uniform corrosion rates of carbon steels in supercritical CO₂ environments with varying water contents, where RH refers to the relative humidity, which is the ratio of the current water vapor pressure to the saturation vapor pressure at a given temperature, expressed as a percentage. It can be seen that, under specific pressure, temperature, and time combinations, the steel corrosion increases with increased water content in the CO₂ fluid. Therefore, stringent control and limitation of water or moisture in supercritical CO₂ fluid will be effective in preventing the occurrence of corrosion.

5.2.3. Effect of impurity gases

Various impurity gases, such as SO₂, NO_x, O₂, and N₂, always exist in captured CO₂ fluid. Depending on the sources of CO₂ capture, the range and level of impurities in CO₂ streams vary widely [119]. Impurity gases can change the CO₂ phase state under pipeline operating conditions. Fig. 6 shows the phase diagram of CO₂ fluid with 10% (mol/mol) single impurity gases (N₂, CH₄, H₂, H₂S, SO₂, Ar, CO, NH₃, and O₂) [120]. Obviously, all impurity gases change the physical parameters of the CO₂ fluid. For example, H₂ and H₂S gases form the widest and narrowest two-phase regions, respectively. Impurity gases can shift the critical point of the CO₂, potentially leading to the coexistence of liquid and vapor phases in the fluid. This results in the formation of an aqueous environment within the steel casing, causing corrosion of the steel.

In addition, the impurity gases, once dissolved in water condensate, change the solution chemistry and corrosivity. The effect of impurity gases on supercritical CO₂ corrosion is quite complex. Their concentration, interactions, and the specific environmental conditions (e.g., temperature and pressure) can influence the extent and type of corrosion observed. First, the effect of impurity gases on corrosion enhancement or inhibition is difficult to predict. As shown in Fig. 7(a) [121], the presence of O₂ gas in supercritical CO₂ fluid increases the corrosion of X65 steel over low and high content ranges. However, a super-high O₂ content causes a decrease in the corrosion rate. This phenomenon is primarily attributed to an increase in the cathodic reaction to produce OH^– ions, which elevates the solution pH. In contrast, the corrosion rate of 13Cr steel decreases with an increase in O₂ content, due to the effect of the Cr element on the corrosion resistance of the steel. Second, the role played by impurity gas in steel corrosion is affected by other factors related to components in the supercritical CO₂ fluid. For example, as the NO₂ concentration in the CO₂ fluid increases, the corrosion rate of the steel increases, but this is only observed in fluid with a high water content, such as 1220 ppmv water, as shown in Fig. 7(b) [49]. When the water content is 488 ppmv, the effect of NO₂ on the corrosion rate is marginal. Finally, some impurity gases can react with each other when dissolved in water, producing new chemicals that can affect the corrosion reaction [122]. This is particularly applicable for the impurity gases SO_x, NO_x, and O₂. Table 4 [109], [116], [123], [124], [125], [126], [127], [128], [129] summarizes recent work investigating the effects of various impurity gases on the corrosion of carbon and low-alloy steels in supercritical CO₂ fluid. The scattered results reflect the complexity of corrosion in supercritical CO₂ when multiple types of impurity gases are present.

Due to the significant and complex effects of impurity gases on the corrosion of steels in supercritical CO₂, strict concentration limits for impurities are implemented for corrosion control. While purification can achieve these limits, it substantially increases the cost of the entire CCS process. Moreover, no widely accepted standard specifying the impurity limits in CO₂ fluid exists. Instead, individual CCS projects implement their own CO₂ quality management plans. It is important to note that impurity restrictions may vary from site to site, depending on factors such as local geology, regulatory requirements, and operational conditions. Table 5 [89] lists the CO₂ quality recommendations and quality tolerance in Dynamis and Alstom CCS projects, respectively.

5.2.4. Effects of service temperature and pressure

The CO₂ stored underground exists in a supercritical phase, generally at pressures ranging from 8 to 15 MPa and temperatures between 30 and 40 °C. Over time, fluctuations in temperature and pressure may occur, affecting the corrosion of steels in supercritical CO₂ environments. Figs. 8(a) and (b) [129] show the corrosion rates of X65 steel exposed to water-saturated supercritical CO₂ containing 1000 ppm H₂S impurity at various temperatures and pressures. The experimental setup consisted of a CO₂/H₂S gas mixture cylinder, a booster pump, a 3 L capacity autoclave, a controller, and a waste gas treatment device. The controller was used to monitor and control the temperature and pressure during testing. The water concentration, when it reached saturation, ranged from 1711 to 3946 ppm. This corresponded to the dissolved water in the CO₂ within the 3 L autoclave, which varied between 0.334 and 3.663 g. To achieve water-saturated conditions, 10 g of water was introduced into the autoclave. After completing the test, the specimens were rinsed with deionized water, thoroughly dried, and photographed. Three specimens underwent chemical cleaning to remove the corrosion products. The uniform corrosion rate was calculated using the weight loss testing. It is clear that, at a pressure of 8 MPa, the corrosion rate increases from 0.095 to 0.190 mm·a⁻¹ when the temperature increases from 27 to 35 °C. With a further increase in temperature to 50 °C, the corrosion rate decreases to 0.032 mm·a⁻¹. This phenomenon is attributed to structural changes in the corrosion scale formed on the steel surface at different temperatures. Similarly, at a temperature of 35 °C, the corrosion rates are 0.017, 0.190, and 0.073 mm·a⁻¹ at pressures of 6, 8, and 10 MPa, respectively. Changes in temperature and pressure have also been found to affect the composition of H₂CO₃ in the liquid phase. As illustrated in Fig. 8(c) [130], with an increase in pressure, the solubility of CO₂ in H₂O increases, which increases the concentration of H₂CO₃. Consequently, the solution pH decreases and the acidity increases, leading to an increased corrosion rate.

An elevated temperature generally increases the reaction kinetics, including the corrosion reaction. Simultaneously, temperature affects the nucleation of corrosion scales on the steel surface. As the temperature increases, the nucleation rate of FeCO₃ scale increases, which favors the formation of more protective scale. Thus, temperature plays a dual role in supercritical CO₂ corrosion.

Pressure affects the growth process of the corrosion scale. It was found that, under supercritical CO₂ conditions, a non-crystalline layer was preferentially formed on the steel surface, which gradually evolved into a dense inner layer of FeCO₃ scale. Eventually, a relatively porous outer layer of FeCO₃ scale was generated above the inner layer. However, under low CO₂ pressure conditions, a dense outer layer of FeCO₃ was formed first, followed by the formation of a porous but thick inner layer. The inner layer of the corrosion scale plays a primary protective role, especially under supercritical CO₂ conditions [131].

5.3. Degradation of cement in geological CO₂ storage environments

Cement is used to stabilize the steel casing for CO₂ storage, in what is known as wellbore completion. When the CO₂ injection is finished, the wellbore is sealed with a cement plug and left abandoned. The designed service life of a CO₂ storage system is over 100 years, and the stored CO₂ is not expected to leak back to the atmosphere or near-surface resources. In reality, the cement between the steel tubing and rocks is inherently incomplete. Under vigorous acidic conditions, the cement degrades over time. It has been reported that stress cracking can occur on the cement, causing direct exposure of the steel casing to corrosive environments.

Cement degradation is closely tied to its carbonation process, wherein CO₂ reacts with the calcium compounds in the cement, lowering the pH and subsequent weakening the cement structure. For example, the widely used Portland cement includes tricalcium silicate (Ca₃O₅Si), dicalcium silicate (Ca₂SiO₄), tricalcium aluminate (Al₂Ca₃O₆), and tetracalcium aluminoferrite (Ca₄Al₂Fe₂O) [132]. These compounds can react at a relatively high rate with HCO₃^– and CO₃^2– ions, which are produced when CO₂ dissolves in H₂O [132], [133], [134], [135]:

(8)

{C a}_{(l)}^{2 +} + H C O_{3 (l)}^{-} + {O H}_{(l)}^{-} \to {C a C O}_{3 (s)} + H_{2} O

(9)

{C a}_{(l)}^{2 +} + {C O}_{3 (l)}^{2 -} \to {C a C O}_{3 (s)}

Deposition of CaCO₃ can cause volume expansion and cracking within the cement matrix. Additionally, leaching of Ca²⁺ ions from the cement leads to increased porosity. These combined processes ultimately result in cement degradation.

6. Perspectives for further research in steel corrosion and its control in geological CO₂ storage

6.1. Standardized methods for replicating the corrosive environments encountered in supercritical CO₂ storage

In its dry state, CO₂ gas is not corrosive toward steel. However, corrosion manifests on steel casings within supercritical CO₂ fluid when water condensate forms on the internal surface of the casings and the CO₂ dissolves in the water. This process leads to the creation of an acidic electrolyte, which in turn corrodes the steel. Field experiences have shown that corrosion may occur even within the recommended water content limits in supercritical CO₂ fluids. When the water content exceeds 500 ppm, the corrosion rate increases significantly. Internal corrosion of steel casings in geological supercritical CO₂ storage primarily occurs within water films, typically characterized by limited thickness. The limited volume of the corrosive electrolyte plays a critical role in steel corrosion, affecting the formation of corrosion scale, accelerating the mass transfer of corrosive species toward the steel surface, and changing the solution chemistry.

Reproducing the corrosive conditions encountered within supercritical CO₂ storage casings presents a considerable challenge. In laboratory settings, researchers have resorted to advanced high-pressure autoclave systems, as depicted in Fig. 9 [136], to study corrosion in supercritical CO₂ fluid. These systems incorporate sophisticated pumping, gassing, and operating controllers, enabling the injection of supercritical CO₂ fluid at controlled temperatures and pressures into the autoclave. The testing systems also enable adjusting the types and concentrations of impurity gases, placing multiple specimens in a specimen holder within the autoclave, and conveniently monitoring the testing conditions throughout the experiment [126], [129], [137]. The ability of these systems to replicate the corrosive environments found in supercritical CO₂ storage casings is uncertain. Immersing steel specimens in electrolytes may not accurately reflect the realistic corrosive environment CO₂ storage casings are exposed to. Casing corrosion typically occurs due to a water film on the steel surface. It is widely accepted that the solution thickness is crucial to corrosion processes and corrosion reaction kinetics [138]. Unlike a bulk solution, the thin-layer electrolyte is associated with unique features or properties, such as a rapid mass transfer process [139], [103], accumulation of corrosion products [138], [140], and initiation of localized corrosion [141]. Moreover, the solution chemistry in thin-solution films may undergo major changes over time due to the limited volume, further increasing the difficulty of environmental reproduction. These alterations can sometimes lead to testing results that are neither reproducible nor directly comparable with each other. At present, there is no standardized method available to generate inter-comparable and industrially relevant data for supercritical CO₂ corrosion testing. This is a significant gap that merits further attention and concerted effort.

6.2. Quantitative assessment of the impact of impurity gases on supercritical CO₂ corrosion

As stated above, the presence of various types of impurity gases in supercritical CO₂ fluid significantly affects the corrosion of steel facilities. Impurity gases such as SO₂, NO_x, O₂, and N₂ are commonly present in captured CO₂ streams. The concentration and variety of these impurities can vary significantly depending on the CO₂ capture source. Although strict concentration limits for specific impurities can be achieved through purification, this requires additional energy, chemical treatments, and specialized equipment, all of which contribute to elevated operational and capital costs. The need for continuous purification and maintenance of corrosion-protection systems can significantly increase the overall costs of CO₂ storage. This elevates the cost per ton of stored CO₂, directly impacting the economic viability of CCS projects. In cases where the impurities cannot be effectively removed to a cost-efficient level, it may be necessary to explore alternative corrosion-mitigation methods, further complicating the economics of the project. Moreover, technical maturity limits the level of removal of these impurities. Field experiences have shown that, even though the CO₂ fluid quality is tightly regulated, internal corrosion still occurs even within the recommended H₂O content limit [142]. Obviously, developing an effective management strategy for controlling steel corrosion in supercritical CO₂ storage necessitates a thorough understanding and quantitative assessment of the impact of various impurity gases present in the CO₂ fluid.

First, the combined effect of multiple impurity gases on the phase state and physiochemical properties of supercritical CO₂ remains unknown. Substantial efforts are currently underway to investigate the phase behavior and critical points of CO₂ fluid containing specific impurity gases such as N₂, CH₄, H₂, H₂S, SO₂, Ar, CO, NH₃, NO₂, O₂, and H₂O [120], [143], [144]. Nevertheless, there is a scarcity of data concerning CO₂ phase diagrams in the presence of two or more types of impurity gases. Fig. 10 [144] illustrates the phase diagrams of CO₂ fluid containing 5% N₂ + 5% CH₄ and 5% N₂ + 5% NO₂, in comparison with the phase diagrams of pure CO₂ gas and CO₂ gas containing either 5% N₂, 5% NO₂, or both. It is obvious that the presence of multiple impurity gases alters the phase state and critical point of CO₂. In reality, the coexistence of two or more types of impurity gases—especially those affecting and accelerating corrosion reactions (e.g., SO₂, H₂S, and O₂) within the supercritical CO₂ fluid—will indeed change the phase state and physiochemical properties of CO₂. Consequently, it will also affect the CO₂ corrosion process. However, current understanding of this aspect is quite limited, and many essential pieces of knowledge are lacking.

Second, although the effects of specific single impurity gases (e.g., O₂, H₂O, and NO₂) on supercritical CO₂ corrosion have been extensively investigated, the interactions between these impurity gases and their synergistic effects on steel corrosion are not yet fully understood. In supercritical CO₂ fluid, numerous impurity gases can interact with each other when dissolved in water, leading to the formation of new chemicals and altering the solution chemistry. Typical examples include CO₂ + H₂S + SO₂ and CO₂ + H₂S + O₂ in water. Their reactions will affect both the anodic and cathodic reactions during steel corrosion. Moreover, the formation of new corrosion products may occur, causing the deposition of layers on the steel surface. The effects also depend on the concentration of individual impurities. Thus, in order to gain a comprehensive understanding of supercritical CO₂ corrosion under storage conditions, it is necessary to establish the chemical and electrochemical reactions that occur in the presence of multiple impurity gases when dissolved in water. Given the large number of impurity gases that may be present in CO₂ fluid, prioritization is necessary to rank the importance of individual gases in corrosion.

Finally, as mentioned earlier, there is as yet no widely accepted standard specifying the impurity limits in CO₂ fluid. Such a standard, once developed, will enable the evaluation of corrosion risk and the estimation of corrosion rates through appropriate modeling based on measurements of CO₂ fluid quality. This standard will also aid in mitigating the corrosion of steel facilities in supercritical CO₂ storage systems.

6.3. Modeling for long-term corrosion prediction

Ensuring accurate prediction of long-term corrosion progression on steel facilities is essential for effective asset integrity management within geological CO₂ storage systems. Modeling has emerged as a useful alternative enabling the prediction of metallic corrosion. While CO₂ corrosion models have been extensively pursued in both academic and industry communities [79], [91], those developed under low-pressure and low-temperature conditions are not applicable for CO₂ corrosion under supercritical conditions. As mentioned earlier, CO₂ in underground storage exists in a supercritical phase at pressures of 8–15 MPa and temperatures of 30–40 °C. Fluctuations in temperature and pressure over time can affect steel corrosion in supercritical CO₂ environments. Under high CO₂ pressures, Henry’s law, which governs the amount of gas (e.g., CO₂) that will dissolve in water under low-pressure conditions, does not apply [146]. Efforts have been made to model supercritical CO₂ processes. However, their applicability in CO₂ storage environments has yet to be validated.

Thus far, the available models for predicting supercritical CO₂ corrosion suffer from three major limitations. First, the corrosive environment modeled does not represent the reality in supercritical CO₂ storage. For example, a model was proposed to predict the uniform corrosion rate of CO₂ pipelines in supercritical CO₂/SO₂/O₂/H₂O environments [145]. Although the model provided a good prediction of steel corrosion compared with the testing results, the corrosive fluid used was not representative of that present in CO₂ storage. Moreover, the model treated CO₂ as a solvent, while the gaseous components SO₂ and O₂ were regarded as corrosive species. Second, the role of the corrosion scale that forms on the steel surface in further corrosion of the steel is either underestimated or completely ignored [146]. This type of model typically yields predictive results that are relatively conservative. Finally, while some models have been developed for corrosion in CO₂ storage systems, they primarily focus on predicting the uniform corrosion rate of the steel casings and yield results consistent with the testing data [19]. This applies to situations where the cement supporting the casings is absent, exposing the steel directly to corrosive environments over a sufficiently large area. Fig. 11 [19] illustrates the physical block of a mechanistic model that integrates three interrelated sub-models: water chemistry, electrochemical corrosion, and mass transfer in solution and solid scale phases [19]. It also compares the modeling results with experimentally measured uniform corrosion rates. However, a common corrosion scenario involves the generation of micro-annuluses or crevices in the cement, resulting in localized pitting corrosion occurring on the casings [147]. Developing mechanistic models that are applicable for geological CO₂ storage under supercritical conditions—especially for quantitatively predicting the localized corrosion rate of the steels—is a priority for the long-term integrity management of steel facilities in CO₂ storage.

6.4. Solutions for effective corrosion control

Given the harsh environment within a supercritical CO₂ storage environment, the development of effective corrosion control technologies is urgent to maintain the integrity of steel facilities.

6.4.1. Drying and purification

Adequate drying and purification of supercritical CO₂ fluids to reduce corrosion risks is widely recognized as an essential step in managing the integrity of steel facilities in CO₂ storage environments. Removing moisture from the CO₂ fluid can significantly prevent the generation of condensed water. However, this approach presents several limitations and challenges. The first issue is the economic burden associated with achieving sufficiently dry and pure supercritical CO₂. The energy-intensive processes required for efficient CO₂ dehydration and impurity removal, such as adsorption, condensation, and cryogenic distillation, can cause a substantial increase in operational costs. These processes are not only expensive but also difficult to carry out in large-scale CO₂ storage operations, especially when considering the vast quantities of CO₂ involved in CCS.

Furthermore, while sufficient drying is effective at mitigating the corrosion caused by condensed water, it does not address other complex corrosion mechanisms that may arise in CO₂ storage environments. For instance, supercritical CO₂—even in its dry form—may still contain trace levels of acidic impurities, which can cause corrosion under stress. The removal of such impurities is technically challenging and, in many cases, may not be completely achievable. Moreover, the practice of drying supercritical CO₂ alone fails to address other fundamental corrosion drivers, such as microbial activity and chloride-induced corrosion, which can still occur even in environments where moisture is minimized. These types of corrosion are not always mitigated through drying techniques. The practical approach to managing the quality of CO₂ fluid involves setting reasonable standards and controlling the levels of water and impurity gases within specific ranges. However, this is insufficient for corrosion control in CO₂ storage systems.

6.4.2. Corrosion-resistant alloys (CRAs)

CRAs are typically employed in aggressive underground environments. In general, the CRAs are covered with a layer of stable and compact oxide film, which serves as a protective barrier against corrosion attack. Cr is a common alloy element added to carbon steels to enhance their corrosion resistance [148]. It has been reported that 1 wt% Cr-modified carbon steels can effectively mitigate CO₂ corrosion under normal pressures [149]. Although Cr-modified carbon steels have exhibited promising corrosion resistance, this approach suffers from some limitations, especially regarding its long-term performance. One of the primary concerns is the incomplete and potentially unstable oxide film that forms on the steel surface under realistic environmental conditions. Even if a protective Cr oxide layer forms, it can be compromised under certain conditions, particularly in the presence of chloride ions or microbial activity. For example, in environments containing chlorides or exposed to SRB, the Cr-induced oxide layer can become vulnerable to localized corrosion [150]. Chloride ions can cause breakage of oxide films, leading to pitting corrosion. Similarly, SRB can induce microbial corrosion, further exacerbating localized damage and undermining the effectiveness of Cr in mitigating corrosion.

Another limitation is the cost-effectiveness of adding Cr to carbon steels in large-scale applications. Although stainless steels and nickel alloys are used in extreme downhole environments due to their excellent pressure-bearing and corrosion resistances [151], the economic feasibility of employing such materials for CO₂ storage systems is questionable. CO₂ storage reservoirs are typically located several kilometers underground, making the cost of using these types of alloys as casings economically unfeasible.

Furthermore, the long-term durability of Cr-modified steels remains a subject of concern. Although Cr can improve resistance to uniform corrosion, it may not effectively protect against other degradation mechanisms, such as SCC and hydrogen embrittlement. These types of damage can also potentially occur on steel casings in CO₂ storage environments.

6.4.3. Innovation in corrosion inhibitors

When considering long-distance piping or pipelines such as supercritical CO₂ storage casings, corrosion inhibitors often prove to be a more suitable internal corrosion mitigation technique compared with internal coatings. However, most relevant studies have focused on CO₂ corrosion inhibition in oil and gas pipelines, where the corrosion occurs at a low partial pressure of CO₂ and under considerably different conditions of pressure and temperature from those in geological CO₂ storage [152]. Inhibitor selection, inhibiting mechanism and performance, and applicability in supercritical CO₂ storage environments are being studied and defined. At present, studies on supercritical CO₂ corrosion inhibitors are conducted using imidazoline-based molecules as organic inhibitors, as these compounds generally exhibit a high solubility in supercritical CO₂. As illustrated in Fig. 12 [152], the structural properties of the inhibitor molecules, such as functional groups, alkyl chains, heteroatoms, phenyl rings, and π-bond conjugation, have a considerable influence on the overall adsorption and protection performance. Beyond imidazolines, other heterocyclic organic molecules, such as pyrazoles, imidazoles, benzotriazoles, and pyridines, are also being explored for their potential to act as effective inhibitors in supercritical CO₂ environments. These molecules might offer promising avenues for corrosion protection, but their long-term stability, their cost-effectiveness, and the need for novel formulations that function well under supercritical conditions are critical aspects that have yet to be thoroughly addressed. Moreover, the inhibitors should overcome the drawbacks of high cost, tedious synthetic procedure, toxicity, and effectiveness at high concentrations.

7. Concluding remarks

While CCS stands as the sole process currently capable of yielding a significant and immediate reduction in CO₂ levels on Earth, corrosion presents a formidable challenge to the structural integrity of steel facilities exposed to supercritical CO₂ fluid. The CO₂ stored underground is in a supercritical phase, at pressures of 8–15 MPa and temperatures of 30–40 °C. Corrosion of steels in supercritical CO₂ environments occurs when water (or moisture) contained in the fluid condenses on the pipe wall surface and CO₂ becomes dissolved in the water, generating an acidic electrolyte. The dominant cathodic reaction is hydrogen evolution when the electrolyte pH is below 4. At intermediate pH ranges (i.e., 4 < pH < 6), the cathodic reaction involving the electrochemical reduction of H₂CO₃ to generate HCO₃^– ions becomes significant. The anodic reaction is usually simplified as the oxidization of iron, although the actual process is much more complicated than this reaction, accompanying the deposition of FeCO₃ scale on the steel surface.

In addition to uniform corrosion in the supercritical CO₂ environment, steel components may experience other types of corrosion when subjected to various operating conditions. Galvanic corrosion may occur due to cracking and peeling of the cement that separates casings made of different metals. SCC can occur on steel casings due to the synergism of stress and electrochemical corrosion under supercritical CO₂ injection conditions. Microbial corrosion also occurs, considering the extensive microorganism population existing in geological CO₂ storage reservoirs.

Supercritical CO₂ corrosion in storage environments is affected by multiple factors. The alloying treatment of carbon steels by the addition of Cr can improve their corrosion resistance: As the Cr content in the steels increases, there is typically a decrease in the corrosion rate. This is attributed to the formation of a protective layer of corrosion product film on the steel surface. However, during the long-term geological storage of supercritical CO₂, Cr alloying may not benefit the corrosion resistance of steel casings due to mutual interference between Cr and Cr oxides with FeCO₃ scale formed on the steel surface.

When the water (moisture) content in CO₂ fluid is lower than the solubility limit of H₂O in CO₂, it is difficult for an acidic water film to form on the steel surface. Thus, the corrosion reaction becomes less favorable, resulting in a lower corrosion rate. Therefore, stringent control and limitation of water or moisture in the supercritical CO₂ fluid will be effective in preventing corrosion occurrence.

The presence of impurity gases in the fluid can change the CO₂ phase state under pipeline operating conditions. In addition, once they have dissolved in water condensate, these impurities alter the solution chemistry and corrosivity. The effect of impurity gases on supercritical CO₂ corrosion is complex, as evidenced by the varied corrosion rates observed in relevant investigations. There is no widely accepted standard specifying the impurity limits in CO₂ fluid as yet.

Temperature plays a dual role in supercritical CO₂ corrosion. Elevated temperature increases corrosion reaction kinetics and accelerates the nucleation of corrosion scale on the steel surface, promoting the formation of more protective scale. Pressure affects the growth process of the corrosion scale.

The cement between the steel casing and rocks is inherently incomplete. Under vigorous acidic conditions, the cement degrades over time. The degradation of cement is closely linked to its carbonation process, wherein CO₂ reacts with the calcium compounds in the cement, leading to a reduction in pH and subsequent weakening of the cement structure.

Currently, effective corrosion management and control in geological CO₂ storage is the focus of ongoing research in four key areas: ① developing standardized methods for replicating the corrosive environments encountered in supercritical CO₂ storage, ② quantitatively assessing the impact of impurity gases on supercritical CO₂ corrosion, ③ modeling long-term corrosion growth on steel casings, and ④ developing high-performance corrosion-control solutions, with a primary emphasis on corrosion inhibitors.

CRediT authorship contribution statement

Xin Fan: Writing – original draft, Resources, Investigation, Formal analysis. Qing Hu: Validation, Investigation, Formal analysis. Y. Frank Cheng: Writing – review & editing, Writing – original draft, Validation, Supervision, Project administration, Methodology, Funding acquisition, Formal analysis, Conceptualization.

Declaration of competing interest

The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.

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