Research Progress on Major Influencing Factors of Corrosion Behavior of Pipeline Steel in Supercritical CO₂ Environment

Abstract

Carbon capture, utilization and storage (CCUS) represents a vital technological strategy for mitigating greenhouse gas emissions and facilitating sustainable development. Supercritical CO₂ (SC-CO₂) pipeline transportation serves as an essential intermediary step towards attaining the “Dual Carbon Goals” and CCUS, representing the optimal and most cost-effective solution for ultra-long distance transport. In the CO₂ capture process, trace amounts of impurities, such as H₂O, O₂, H₂S, NO_x and SO_x, are inevitable. These gases react to form acidic compounds, thereby accelerating pipeline corrosion. With the progression of CCUS initiatives, corrosion within supercritical CO₂ pipeline transportation has become a critical challenge that significantly affects the safety and integrity of pipeline infrastructure. This review paper provides an in-depth analysis of the corrosion behavior of pipeline materials in a supercritical CO₂ environment, with particular attention to the effects of impurity, temperature, and pressure on corrosion rates, corrosion products, and corrosion morphology. Furthermore, an analysis of the corrosive behavior of welded joints in supercritical CO₂ transport pipelines is performed to provide valuable reference data for research and construction projects related to these pipelines.

1. Introduction

With the acceleration of industrialization and the ongoing expansion of human activities, greenhouse gas emissions have consistently risen, resulting in substantial modifications to the Earth’s climate system. Global warming has emerged as one of the most pressing challenges confronting our world today. To achieve sustainable development goals and tackle global climate change, 178 parties collectively adopted the Paris Agreement at the 2015 United Nations Climate Change Conference, aiming to collaboratively mitigate the accelerating trend of global warming [1,2]. In 2020, China launched the ambitious “Dual Carbon Goals”, which aim to achieve peak carbon emissions by 2030 and carbon neutrality by 2060 [3,4]. CCUS technology represents an effective approach to mitigate greenhouse gas emissions from fossil fuel usage, integrating the processes of CO₂ capture, transportation, utilization, and storage [5,6]. According to the 2024 Global Status of CCS report by the Global CCS Institute, 2024 has seen significant growth in CCS facility development. As of July 2024, the pipeline includes 628 projects, a 60% year-on-year increase. Capture capacity has seen strong growth since 2017, with an annual compound rate of 32% [7]. Efficient transportation of CO₂ is critical for integrating capture and utilization within the CCUS system. Presently, high-pressure pipeline transportation of CO₂, operating at pressures between 2 and 15 MPa, represents the most cost-effective and efficient method for ultra-long-distance transport [8]. The number of pipeline projects has seen a substantial increase. Currently, the global CO₂ pipeline network extends over 8000 km in length. Projections suggest that, by 2050 and beyond, more than 200,000 km of pipelines will be necessary to support the annual transportation of approximately 10 Gt of CO₂ [9]. In August 2022, China inaugurated its first large-scale CCUS project with the establishment of a 109-km CO₂ transport pipeline linking Qilu Petrochemical and Shengli Oilfield. The pipeline is engineered to withstand a pressure of up to 12 MPa [10,11].

To enhance cost-effectiveness and optimize transportation efficiency, CO₂ is typically compressed into its supercritical state, referred to as SC-CO₂. Pure CO₂ has a triple point at −56.6 °C and 0.518 MPa, which determines the point where CO₂ may co-exist in gas, liquid and solid state [12]. The CO₂ critical point is 7.38 MPa and 31.1 °C; below the critical temperature, the CO₂ is in the liquid dense phase, and above in the supercritical phase. There is no noticeable phase change above the critical temperature, hence, when the pressure is reduced from above to below the critical pressure, a smooth enthalpy change occurs from super critical fluid to gas [12,13]. The phase diagram for pure CO₂ as illustrated in Figure 1 [14]. In the supercritical state, neither an increase in pressure nor temperature results in a significant alteration of the state of CO₂. The unique properties of supercritical CO₂, such as low viscosity and high density, render it an energy-efficient state for transportation [14,15,16,17]. However, operating at higher pressures is associated with increased risks of corrosion and ductile running fractures of pipeline. The underground installation of supercritical CO₂ transport pipelines demands the utmost emphasis on pipeline safety. Potential leaks could lead to significant adverse outcomes, including greenhouse gas emissions, water contamination, soil acidification, and considerable economic losses [17,18]. The existing review papers address various aspects, including the design of CO₂ transportation pipelines, evaluation methods for metal corrosion in dense-phase CO₂ environments, the corrosion mechanisms of pipelines, and anti-corrosion technologies. Considering the internal corrosion of pipeline steel in a supercritical CO₂ environment, this study comprehensively examines the influence of various factors, including material composition, moisture, impurities, temperature, pressure, and flow rate, on corrosion rate, corrosion products, and corrosion morphology. Furthermore, this study reviews the current research status of welded joints under supercritical CO₂ conditions, offering valuable insights for investigating corrosion issues in supercritical CO₂ transport pipelines.

2. Corrosion Behavior of Carbon Steel in CO₂

CO₂ corrosion results from the dissolution of CO₂ in water, which subsequently forms carbonic acid (H₂CO₃). The interaction between carbon steel and CO₂ triggers a complex electrochemical corrosion process, which ultimately results in corrosion on the metal surface. The reaction mechanism responsible for this phenomenon is illustrated as follows [19,20,21,22]. The corrosion schematic is shown in Figure 2.

(1)

When CO₂ dissolves in water, it reacts chemically with water molecules to form H₂CO₃. H₂CO₃ is categorized as a weak acid, and a fraction of it further dissociates into bicarbonate ions (HCO₃⁻) and carbonate ions (CO₃²⁻).

$${CO}_2\left(g\right)\leftrightarrow {CO}_2\left(aq\right)$$

(1)

$$C{O}_2\left(g\right)+H_{2}O\left(l\right)\leftrightarrow H_{2}C{O}_3\left(aq\right)$$

(2)

$$H_{2}C{O}_3\leftrightarrow H^{+}+HC{O_3}^{-}$$

(3)

$$HC{O_3}^{-}\leftrightarrow H^{+}+{C{O}_3}^{2-}$$

(4)

(2)

Cathode reaction: The reduction of H+ ions occurs, leading to the acquisition of electrons and the formation of H₂. Additionally, this reduction process involves H₂CO₃ and CO₃²⁻.

$$2H^{+}+2e^{-}\leftrightarrow H_2$$

(5)

$$2H_{2}C{O}_3+2e^{-}\to H_2+2HC{O_3}^{-}$$

(6)

$$2HC{O_3}^{-}+2e^{-}\to H_2+2{C{O}_3}^{2-}$$

(7)

(3)

The anode reaction encompasses the dissolution of the Fe anode, the generation of Fe²⁺ ions, and the formation of carbonate compounds.

$$Fe\to {Fe}^{2+}+2e^{-}$$

(8)

$${Fe}^{2+}+{C{O}_3}^{2-}\to FeC{O}_3$$

(9)

$${Fe}^{2+}+2HC{O_3}^{-}\to {Fe\left(HC{O}_3\right)}_2$$

(10)

$${Fe\left(HC{O}_3\right)}_2\to FeC{O}_3+C{O}_2+H_{2}O$$

(11)

The substrate surface is coated with a dense film of corrosion products (FeCO₃), which effectively inhibits the diffusion of corrosive ions. This protective layer consequently safeguards the material surface and mitigates the corrosion process initiated by the corrosive medium, ultimately enhancing the overall corrosion resistance.

The corrosion of steel in CO₂ environment can be classified into localized and uniform corrosion [23]. Currently, there is no unified regulation regarding corrosion standards for CCUS supercritical CO₂ pipelines in China. However, within the petroleum industry, severe corrosion is defined as a uniform corrosion rate exceeding 0.25 mm/year for carbon steel and a maximum pitting depth greater than 0.38 mm/year [24]. The corrosion environment can be primarily categorized into two phases: the water-saturated CO₂ phase, which predominantly occurs during CO₂ transport and injection, and the CO₂-saturated water phase, which is mainly observed during CO₂ injection and subsequent oil and gas production [25,26].

3. Factors Influencing Corrosion in Supercritical CO₂ Transportation Pipelines

The corrosion issues in supercritical CO₂ pipelines primarily originate from two factors. First, in the carbon capture process, despite achieving a CO₂ purity of over 99.5%, the captured CO₂ frequently contains trace amounts of impurities, such as H₂O, O₂, NO_x, H₂S, and SO_x [7,27,28]. Internal corrosion is a significant risk to the integrity of carbon steel pipelines in case of insufficient dewatering of the CO₂ composition [14]. Once a water droplet is formed and attached to the steel surface, it strongly etches the surface and initiates localized attacks, potentially leading to leakage [15]. These impurities, such as NO_x, H₂S or SO_x, can dissolve in water, leading to a decrease in pH levels and an increase in the corrosion rate of pipeline steel. In severe cases, this may result in material failure and CO₂ leakage, posing potential safety hazards. The second factor pertains to the impact of internal conditions during transportation, such as multiphase flow (coexistence of gas and liquid phases) induced by fluctuations in temperature and pressure. These conditions can result in localized corrosion [29,30,31]. In summary, the corrosion characteristics of CO₂ are influenced by multiple factors, including material composition, impurity content, CO₂ partial pressure, temperature, pH value, and flow rate. These factors can potentially accelerate the corrosion rate of pipelines, thereby shortening their service life. American Petroleum Institute (API) specification 5L is extensively utilized in the classification and designation of pipeline steel grades. Therefore, the materials examined in the literature on the corrosion of pipeline steel in supercritical CO₂ environments primarily comprise specific grades of pipeline steel, such as X65 and X70.

3.1. Water Content

Among various impurities, H₂O is the most significant factor. H₂O not only reacts directly with Fe as a gaseous oxidizer but can also condense on the steel surface, dissolve CO₂ or other impurity gases, and form an acidic solution. This process facilitates electrochemical reactions, thereby exacerbating corrosion damage [32]. For instance, when SO₂ impurities are present, reducing the water content is more effective in mitigating corrosion issues compared to decreasing the SO₂ concentration [33]. In scientific studies, water content is typically expressed in two primary forms: absolute water content and relative humidity. The actual water content is typically quantified in parts per million by volume (PPMV), whereas relative humidity (RH) is commonly expressed as a percentage (%). RH represents the ratio of the actual water content to the saturation water content, which is influenced by both temperature and pressure [34].

Table 1. Corrosion behavior of steel under different water content conditions.

Materials	Pressures (MPa)	Temperature (°C)	Water Content	Other Impurities	Test Period (h)	Corrosion Rate (mm/y)	Local Corrosion Rate (mm/y)	Reference
X65	8	35	2029 ppm (60% RH)		336	<0.02		[35]
					72	<0.1
			2705 ppm (80% RH)
			3382 ppm (water-saturated CO2 phase)
			CO2-saturated water phase			1
X65	8	50	700 ppm, 1600 ppm		48	No measurable corrosion	No measurable corrosion	[36]
			2650 ppm			0.014	0.2
			3400 ppm (water-saturated CO2 phase)			0.024	1.4
			300 mL (CO2-saturated water phase)		96	4.1
X65	8	35	500 ppmv		72	0.0061	0.137	[37]
			1000 ppmv			0.0103	0.322
			2000 ppmv			0.0259	0.697
			3000 ppmv			0.0298	0.825
			5000 ppmv			0.0398	1.127
X70	10	50	0.95 g (50% RH)	SO2 2.0 mol%, O2 1000 ppm	120	0.0387		[38]
			1.32 g (70% RH)			0.3–0.4
			1.67 g (88% RH)			0.8–0.9
			3 g (100% RH)			1.4–1.5
X52	10	50	20 ppmv	O2 200 ppmv, H2S 200 ppmv, SO2 200 ppmv	72	0.0199		[39]
			100 ppmv			0.0234
			1000 ppmv			0.2671
			4333 ppmv (water-saturated CO2 phase)			0.2838
X65	10	50	200 ppmv	O2 200 ppmv, H2S 200 ppmv, SO2 200 ppmv	72	0.0036		[40]
			1500 ppmv			0.0224
			2000 ppmv			0.1752
			4333 ppmv (water-saturated CO2 phase)			0.5546
X60, X65, X70, X80	8	50	1600 ppm	SO2 3000 ppm, O2 1000 ppm	72	0.025–0.06	0.2–3.25	[41]
			2600 ppm, 3000 ppm			0.1–0.31
	10		1600 ppm, 2000 ppm, 2600 ppm			<0.01	0.04–6.02
			3000 ppm			0.81–0.94
X65	8	35	300 ppm, 650 ppm, 1200 ppm	O2 1000 ppm	48	No measurable corrosion	No measurable corrosion	[42]
			2800 ppm			0.010–0.014	0.8
			34,000 ppm (water-saturated CO2 phase)			0.03	3.1
			34,000 ppm (water-saturated CO2 phase)			0.10	0.9
5Cr	8	35	300 ppm, 650 ppm, 1200 ppm	O2 1000 ppm	48	No measurable corrosion	No measurable corrosion	[42]
			2800 ppm			<0.01	0.7
			34,000 ppm (water-saturated CO2 phase)			0.02	2.2
			34,000 ppm (water-saturated CO2 phase)			0.125	0.3
X70	10	50	45% RH	O2 0.1 mol%	72	0.03	0.03	[43]
			60% RH			0.1
			75% RH			0.90	~1.5
			88% RH			~1.1	~3
			100% RH			1.61	7.03
			45% RH	O2 1.0 mol%		0.03	0.03
			50% RH			0.50
			60% RH			0.63
			75% RH			0.90
			88% RH			0.90–1.0	9
			100% RH			1.6	5.23

presents a comprehensive summary of numerous authors’ results from their experiments in supercritical CO₂ environments with differing water content levels.

Jiang et al. [35] investigated the corrosion behavior of X65 steel in various CO₂ environments and discovered that the critical water content for initiating corrosion is 60% RH in both liquid and supercritical CO₂, whereas this is 80% RH in gaseous CO₂. Prior to the observation of a single water phase, the corrosion rate remains stable as relative humidity increases. When the relative humidity exceeds 60% at temperatures of 35 °C and a pressure of 8 MPa, localized corrosion and severe uniform corrosion will occur. Hua et al. [36] investigated the corrosion behavior of X65 steel exposed to supercritical CO₂ at 50 °C and 80 bar. The average corrosion rate, after immersing the sample in 300 mL of supercritical CO₂-saturated water for 96 h, was measured to be 4.1 mm/year. In the supercritical CO₂ phase saturated with water (exceeding 3400 ppm), an FeCO₃ corrosion product film gradually formed and densified on the sample surface over time, leading to a progressive reduction in the corrosion rate. The corrosion rate was measured at 0.03 mm/year, whereas local corrosion rates were observed to reach up to 1.4 mm/year for immersion times of 48 h. Reducing the water content to 2650 ppm resulted in a decrease in the corrosion rate to 0.015 mm/year and a mitigation of the local corrosion rate to 0.2 mm/year. Notably, no dissolution of the steel was observed when the water content was below 1600 ppm. Liu et al. [37] constructed a novel in situ electrochemical noise (EN) testing system for supercritical CO₂ corrosion, and the influences of water content (500–5000 ppmv) on the corrosion kinetics of X65 pipeline steel were investigated. The results revealed that the primary corrosion type was localized corrosion, characterized by the coexistence of metastable and stable pitting, with a trend toward uniform corrosion. Both the uniform corrosion rate and pitting corrosion rate were found to increase when increasing the water content, and the pitting corrosion rate was almost 20 times more than the uniform corrosion rate.

The critical relative humidity varies across different systems. Xiang et al. [38] quantified the corrosion rate of X70 steel in a CO₂-SO₂-O₂ environment using the weight loss method, and developed a thermodynamic model for pipelines to establish the upper limit of water content in supercritical CO₂ transport systems. The experimental results demonstrated that the critical relative humidity ranged from 50% to 60%. At a critical relative humidity of 50%, the corrosion rate of X70 steel was 0.0387 mm/year, with the primary corrosion products being FeSO₄ crystalline hydrate and FeSO₃ crystalline hydrate (Figure 3a). Liu et al. [39] investigated the corrosion behavior of X52 steel in a supercritical CO₂ system containing multiple impurities, including O₂, H₂S, SO₂, and NO₂. The results revealed that, as the water content increased from 20 ppmv to 4333 ppmv, the corrosion rate of X52 steel correspondingly escalated from 0.0199 mm/y to 0.2838 mm/y (Figure 3b). Moreover, as the water content increases, the corrosion product film progressively transitions from predominantly FeOOH to a mixed film of FeSO₄ and FeOOH. The critical water content that markedly alters the corrosion rate was 100 ppmv. Sun et al. [40] determined that the critical water content for X65 steel is 1500 ppmv when corroded in a supercritical CO₂-H₂O-O₂-H₂S-SO₂ environment at 10 MPa and 50 °C. When the water content was below 1500 ppmv, the corrosion effect of impurity interactions dominated the corrosion process (Figure 3c). When the water content exceeded 1500 ppmv, the corrosion rate increased significantly, and the corrosion products included FeSO₄, FeOOH, S, FeS_0.9, and FeSO₃. The corrosion process was governed by both the interactions between impurities and the corrosive effects of individual impurities.

Currently, in CO₂ transportation pipelines, API pipeline steels are predominantly utilized. Figure 4 summarizes average corrosion rates for five pipeline steels exposed to various water contents [35,36,37,39,40,41]. It is seen from the above studies that the influence of water content on the corrosion behavior of steel in a supercritical CO₂ environment exhibits a critical threshold. The critical threshold varies depending on the material and corrosion environment. As the water content exceeds the critical value, a free water phase forms, leading to the development of a water film on the steel surface and the dissolution of CO₂ and other impurities, which results in an increased rate of corrosion. Provided that the water content in supercritical CO₂ remains below the critical threshold, the corrosion rate remains relatively low, irrespective of the presence of impurities [35,40,41,42,43,44]. It is noteworthy that, as water content varies, the local corrosion rate exhibits more rapid fluctuations. Moreover, the critical threshold of water content for local corrosion is significantly lower than that corresponding to the average corrosion rate under identical conditions [36,37,41,42,43]. As per the NACE standard RP0775-2023 [45], the corrosion behavior of carbon steel can be categorized into three distinct types: low corrosion (average general corrosion rate < 0.05 mm/y, maximum pitting rate < 0.13 mm/y), moderate corrosion (average general corrosion rate: 0.05–0.2 mm/y, maximum pitting rate: 0.13–0.3 mm/y), and high corrosion (average general corrosion rate > 0.2 mm/y, maximum pitting rate > 0.3 mm/y). In accordance with this standard, to ensure that the pipe material maintains a low corrosion level, it is essential to control the water content. It is evident from the data presented in Table 1 that, under identical conditions, when the maximum pitting rate is used as the criterion for evaluation, the permitted water content is significantly lower than that associated with the average general corrosion rate. Therefore, there is no universally accepted standard for the upper limit of water content in supercritical CO₂.

3.2. O₂ Content

When O₂ is present in the corrosion system, it reacts with Fe²⁺ to progressively oxidize Fe²⁺ to Fe³⁺, leading to the formation of Fe(OH)₃ and Fe₂O_3, as indicated in Equations (12) and (13). This reaction disrupts the originally dense protective layer of FeCO₃ and accelerates the corrosion process [46,47]. The presence of O₂ can result in a localized oxygen concentration difference, which may lead to more severe localized corrosion. Under high temperature and pressure conditions, the coexistence of CO₂ and O₂ can lead to severe localized corrosion on the inner wall of the pipeline [48,49]. In supercritical CO₂ transport, O₂ can alter the solubility of H₂O in supercritical CO₂, modify the reaction pathway, and function as an oxidizer, thereby further influencing the corrosion process [50]. However, certain studies have demonstrated that, within a specific concentration range, increasing O₂ concentration can actually decrease the corrosion rate.

Table 2. Corrosion behavior of steel with various O₂ content in supercritical CO₂.

Materials	Pressures (MPa)	Temperature (°C)	Environment	O2 Content	Other Impurities	Test Period (h)	Corrosion Rate (mm/y)	Local Corrosion Rate (mm/y)	Corrosion Products	Reference
X65	8	35	water-saturated CO2 phase	0 ppm		48	0.10	0.9	FeCO3, Fe2O3, FeOOH, Fe3O4	[42]
				20 ppm			0.088	1.0–1.2
				500 ppm			0.072–0.076	1.2–1.3
				1000 ppm			0.04	3
5Cr	8	35	water-saturated CO2 phase	0 ppm		48	0.125	0.3	FeCO3, Fe2O3, Cr2O3, FeOOH, Cr(OH)3, Fe3O4	[42]
				20 ppm			0.120–0.124	0.5–0.6
				500 ppm			0.040–0.044	1.0
				1000 ppm			0.02	2.2
X70	10	50	water-saturated CO2 phase	0.1 mol%	SO2 2 mol%	72	1.61	7.03	FeO FeSO4∙xH2O	[43]
				1.0 mol%			1.6	5.23
				2.0 mol%			0.94	3.3
X70	10	50	water-saturated CO2 phase	0 ppm		120	0.014		FeCO3, Fe2O3	[47]
				1000 ppm			0.027
				10,000 ppm			0.029
N80	8	65	simulated formation water phase	0 bar		48	27.86		FeCO3, Fe2O3, FeOOH	[49]
				5 bar			13.15
X65	8	50	water-saturated CO2 phase	0 mg/L		96	0.25		FeCO3, Fe2O3	[50]
				95 mg/L			0.91
				475 mg/L			1.52
X70	10	40	water-saturated CO2 phase	0		48	0.06		FeCO3	[51]
				200 ppmv			0.09
				1000 ppmv			0.03		Fe2O3

presents a comprehensive summary of numerous authors’ results after conducing experiments in supercritical CO₂ environments with differing O₂ content levels.

$${4Fe\left(OH\right)}_2+2H_{2}O+O_2\to 4Fe{\left(OH\right)}_3$$

(12)

$$4Fe{\left(OH\right)}_3\to {Fe}_2{O}_3+3H_{2}O$$

(13)

Li et al. [32] investigated the corrosion behavior of various pipeline steels in a water-saturated supercritical CO₂ environment containing 3% and 6% O₂. The results revealed that, at pressures ≤ 9 MPa, the corrosion rates of several materials exhibited a slight increase with higher O₂ concentrations. Sun et al. [47] also found that, within an O₂ concentration range of 0–1000 ppm, the corrosion rate of X70 steel in supercritical CO₂ environments increased progressively with rising O₂ concentration. Electrochemical tests of X65 steel in supercritical CO₂ environments with varying concentrations of O₂ (95–475 mg/L) demonstrated that the addition of even small amounts of O₂ caused a negative shift in the corrosion potential, an increase in corrosion current density, and a decrease in impedance [48]. These findings indicate that O₂ significantly accelerates the corrosion of steel in these conditions. Further studies revealed that a minor amount of O₂ inhibits the formation of the FeCO₃ film, while promoting the development of porous Fe₂O₃. Additionally, as the concentration of O₂ increases, the corrosion rate also rises (Figure 5(a1–a4)) [50]. However, Hua et al. [42] discovered that the impact of O₂ content in water-saturated supercritical CO₂ on uniform corrosion differs from its effect on local corrosion. The uniform corrosion rate of X65 and 5Cr steel decreased with the increase in O₂ content, while the local corrosion rate increased. (Figure 5(b1,b2)). The presence of O₂ facilitated the formation of Fe₂O₃ along with other oxides and hydroxides. While the thin amorphous oxide layer serves to mitigate uniform corrosion, the galvanic effect arising from the film’s heterogeneity exacerbates localized corrosion. Li et al. [49] s investigated the corrosion of N80 carbon steel in supercritical CO₂ under the partial pressure of 0–10 bar O₂ and found that the corrosion rate decreased with increase in the partial pressure of O₂. In the initial stage of corrosion, O₂ facilitated the formation of iron hydroxide and oxide films on the sample surface, creating a diffusion barrier layer. This led to the accumulation of Fe²⁺ and CO₃²⁻, which subsequently resulted in the formation of a protective FeCO₃ film that inhibited further steel corrosion. Xu et al. [43] investigated the corrosion behavior of X70 steel in a supercritical CO₂-H₂O-SO₂-O₂ system at 10 MPa and 50 °C, and found that the effect of O₂ on corrosion rate varied with water content in dynamic condition. Specifically, within the relative water content range of 50–60%, the uniform corrosion of X70 steel increased as O₂ concentration rose from 0.1 mol% to 1.0 mol%, and both the local corrosion rate and severity showed a significant increase with rising O₂ concentration (from 0.1 mol% to 1.0 mol%) within the relative water content range of 50–88%. The critical relative water content was 60% when O₂ content was 0.1 mol%, while the critical relative water content dropped to 45% when O₂ content was 1.0 mol%. Wang et al. [52] found that the integrity of the FeCO₃ corrosion product film was destroyed by low concentrations of O₂, thereby accelerating corrosion in a water-saturated CO₂ system. However, when the O₂ concentration reached 1000 ppm, the steel matrix entered a passivation zone, leading to a decrease in the corrosion rate. Figure 6 summarizes average corrosion rates for three pipeline steels exposed to various O₂ contents [42,43,47,51].

As previously discussed, the results in the published literature regarding the impact of O₂ content on steel corrosion in a supercritical CO₂ environment are inconsistent [32,42,43,47,48,49,50,51]. However, as the O₂ content increases, the growth rate of the corrosion rate of steel exhibits a decreasing trend. In a supercritical CO₂ environment, the presence of O2 may lead to the formation of iron oxides, such as Fe₂O₃, Fe₃O₄ and FeOOH. The alteration of the corrosion product film could influence the uniform corrosion process of steel. When the oxide film is relatively dense, it can inhibit the penetration of corrosive media, thereby mitigating the uniform corrosion of steel. The impact of O₂ on the local corrosion rate is highly significant [42,43]. When the average corrosion rate decreases under conditions of high O₂ content, the local corrosion rate may increase even further [42]. Numerous studies have demonstrated that O₂ exhibits enhanced synergistic effects with other impurities in the system, such as H₂O and SO₂, thereby significantly influencing the corrosion process of steel [32,47,48,49]. Therefore, it is imperative to control the O₂ content in transportation systems as much as possible. According to the current specifications of the international DYNAMIS project, the O₂ concentration should be limited to no more than 1000 ppmv during enhanced oil recovery (EOR) applications [52].

3.3. H₂S Content

If a condensed water film was formed on the pipeline steel, the dissolution of H₂S in the water film and the subsequent dissociation would generate S²⁻, HS⁻ and H+, and the iron cations (Fe²⁺) could react with the anions (S²⁻) to form the iron sulfide layer on the surface of steel, as illustrated in Equations (14) [53] and (15) [54]. The deposition of these sulfides on the steel surface can exacerbate corrosion, leading to a significant reduction in the strength and toughness of the steel [53,54,55]. The presence of H₂S not only affects the solubility of other impurities but also reduces the solubility of H₂O in a CO₂-H₂S system compared to a pure CO₂ system [56].

Table 3. Corrosion behavior of steel with various H₂S content in supercritical CO₂.

Materials	Pressures (MPa)	Temperature (°C)	Environment	H2S Content	Other Impurities	Test Period (h)	Corrosion Rate (mm/y)	Local Corrosion Rate (mm/y)	Corrosion Products	Reference
P110	10	80	water-saturated CO2 phase	50 ppmv		240	<0.2	0.52	FeCO3, mackinawite, Cr(OH)3	[57]
3Cr							>0.4	0.84
316L							0	0	FeCO3, mackinawite
P110			CO2-saturated water phase				10.37	<6	FeCO3, mackinawite, pyrrhotie, Cr(OH)3
3Cr							2.71	<2
316L							<0.02	>0.024	FeCO3, Cr(OH)3, nickel sulfide, mackinawite
X65	10	80	water-saturated CO2 phase	0		240	0.17	0.29	FeCO3	[58]
				50 ppmv			0.24	0.48	FeCO3, Fe1−xS, Fe1+xS,
			CO2-saturated NaCl solution	0 ppmv			8.46	9.19	FeCO3
				50 ppmv			15.48	2.45	FeCO3, FeS, Fe1−xS
Q125	14.2	140	water-saturated CO2 phase	1.33 KPa		168	0.015		FeCO3, Fe1−xS, Cr(OH)3	[59]
				7.24 KPa			0.041
			CO2-saturated formation water phase	1.33 KPa			0.081
				7.24 KPa			0.051
X65	8	50	water-saturated CO2 phase	0.08 bar	SO2 0.08 bar, O2 0.08 bar	1.5	>20		FeS, FeSO4∙xH2O, FeCO3	[60]
						72	2.57		FeS, FeSO4∙xH2O, FeCO3, FeOOH, S

presents a comprehensive summary of numerous authors’ results after experiments in supercritical CO₂ environments with differing H₂S content levels.

$${Fe}^{2+}+S^{2-}\to FeS$$

(14)

$${Fe}^{2+}+{HS}^{-}\to FeS+H^{+}$$

(15)

Sun et al. [54] discovered that N80 steel exhibits uniform corrosion in the absence of H₂S; the corrosion rate of N80 initially increased slightly with the increase in H₂S partial pressure, and then decreased significantly in a supercritical CO₂ system containing H₂S. When the partial pressure of H₂S ranges from 0.004 bar to 4 bar, both uniform and localized corrosion occur. As the partial pressure of H₂S increases further, uniform corrosion remains predominant, while the corrosion products progressively transform from FeCO₃ to FeS (Figure 7b). They also found that the H₂S-induced phase distribution changes point to the root cause of H₂S-enhanced corrosion. Furthermore, preparing an amorphous Ni-P coating on X65 pipeline steel could prevent over 80% of localized corrosion [55]. Wei et al. [57] investigated the corrosion behavior of various steels in a dynamic supercritical CO₂ environment with a lower H₂S content (50 ppm). After 240 h of corrosion testing under dynamic conditions at 80 °C and 10 MPa, low alloy steel exhibited severe uniform and localized corrosion in an aqueous medium. In contrast, 316L stainless steel primarily experienced pitting corrosion. In supercritical CO₂ environments, low alloy steel showed predominantly localized corrosion, whereas 316L stainless steel demonstrated strong corrosion resistance with no significant signs of corrosion (Figure 7a). They found that the presence of a small amount of H₂S altered the adsorption behavior of H₂O on the steel surface in a dynamic supercritical environment, leading to more extensive H₂O adsorption across the entire surface, and accelerated both uniform and localized corrosion of X65 steel in the dynamic supercritical CO₂ environment. The small amount of H₂S played a more significant role in the dynamic CO₂-saturated water phase, which changed the microstructure and composition of the corrosion products, and changed the dominated corrosion type of X65 steel from local corrosion to uniform corrosion [58]. Wang et al. [59] found that the corrosion rate of Q125 steel in supercritical CO₂ increased significantly with the rise in H₂S partial pressure, leading to more severe localized corrosion. The corrosion products evolved from a single-layer structure into a double-layer structure, with the inner layer comprising iron sulfide, FeCO₃, and a minor amount of Cr(OH)_3, while the outer layer consisted primarily of FeCO₃. Conversely, in the formation water phase, the corrosion rate decreased with increasing H₂S partial pressure, and the corrosion products also exhibited a double-layer structure. It is evident that H₂S alters the morphological structure of corrosion products, yet its influence on the corrosion rate varies depending on the material and corrosion system.

Through the aforementioned research, it can be conclusively stated that the presence of H₂S in a supercritical CO₂ environment accelerates the corrosion rate of steel. The corrosion products exhibit a distinct double-layered structure. Moreover, the influence of H₂S on the corrosion behavior of steel in the water phase is significantly greater than that in the CO₂ phase. H₂S dissolves in water to form an acidic solution, which substantially increases the corrosion rate of steel. However, H₂S does not accelerate the localized corrosion rate of steel. Furthermore, the presence of H₂S in the water phase induces a transition in the corrosion behavior of steel from localized to general corrosion.

3.4. SO₂ Content

In supercritical CO₂ pipeline transportation, if there are H₂O and SO₂, SO₂ dissolves in water to form H⁺ and HSO₃⁻, which reduces the pH value of the system and accelerates the corrosion of the pipeline. In the CO₂-SO₂ system, the predominant corrosion product is precipitated FeSO₃, where SO₂ acts as the primary driving force [61,62]. In the CO₂-SO₂-O₂ system, the presence of O₂ causes the corrosion product FeSO₃ to undergo further oxidation, resulting in the formation of FeSO₄. If oxygen is present in sufficient quantities, FeOOH will be further oxidized, as illustrated in Equations (16)–(20) [63,64].

Table 4. Corrosion behavior of pipeline steel with various SO₂ content in supercritical CO₂.

Materials	Pressures (MPa)	Temperature (°C)	Environment	SO2 Content	Other Impurities	Test Period (h)	Corrosion Rate (mm/y)	Corrosion Products	Reference
X70	10	50	water-saturated CO2 phase	0 ppm		120	0.014	FeSO3, FeCO3,	[47]
				200 ppm			0.269
				600 ppm			0.345
				1000 ppm			0.423
				1000 ppm	O2 1000 ppm		0.842	FeSO3, FeSO4, FeCO3, FeOOH
X70	10	40	water-saturated CO2 phase	500 ppmv		48	1.1	FeSO3∙2H2O, FeCO3, FeOOH	[51]
					O2 200 ppmv		1.24	FeSO3∙2H2O, FeSO3∙3H2O, FeCO3, Fe2O3
					O2 1000 ppmv		0.6
X70	10	50	water-saturated CO2 phase	0.2 mol%	O2 1000 ppm	288	0.2	FeSO4∙7H2O,	[61]
				0.7 mol%			0.6–0.7	FeSO4∙4H2O, FeSO3∙3H2O
				1.4 mol%			0.75–0.9	FeSO4∙4H2O, α-FeOOH
				2.0 mol%			0.9	FeSO4∙4H2O
X80	8	35	CO2-saturated water phase	0		48	1.67	FeCO3, Fe2O3	[63]
				5%			3.08	FeCO3, FeSO3∙xH2O, FeS
X65	10	50	water-saturated CO2 phase	0		120	0.015	FeCO3,	[64]
				1000 ppmv			0.469	FeSO3 FeSO3∙xH2O, FeSO4∙4H2O, FeCO3, Fe2O3∙H2O
X65	8	35	water-saturated CO2 phase	0		72	0.1	FeCO3	[65]
				50 ppm			0.37	FeCO3 FeSO3∙3H2O
				100 ppm			0.72
carbon steel	9.5	60	CO2 phase	0	H2O 1000 ppm	1512	0.00352	FeCO3, α-FeOOH, Fe3O4	[66]
				0.50%			0.3375	γ-FeOOH
				1.50%			0.5–0.6
				5%			1.396	FeCO3, FeSO3∙3H2O

presents a comprehensive summary of numerous authors’ results after conducting experiments in supercritical CO₂ environments with differing SO₂ content levels.

$$H_{2}O+{SO}_2\to H^{+}+{{HSO}_3}^{2-}$$

(16)

$${{HSO}_3}^{2-}\to H^{+}+{{SO}_3}^{2-}$$

(17)

$${{SO}_3}^{2-}+{Fe}^{2+}\to {FeSO}_3$$

(18)

$${Fe}^{2+}+{{SO}_4}^{2-}\to {FeSO}_4$$

(19)

$$4{FeSO}_4+6H_{2}O+O_2\to 4FeOOH+4H_2{SO}_4$$

(20)

The corrosion rate of X70 steel was observed to increase as the SO₂ concentration rose in a dynamic supercritical environment. The primary corrosion products identified were FeSO₄ and FeSO₃·XH₂O, which formed a protective layer on the specimen surface, thereby reducing the corrosion rate [61]. Hua et al. [62] investigated the corrosion behavior of X65 steel in both water-saturated and unsaturated supercritical CO₂ environments and found that the presence of O₂ and SO₂ impurities significantly increased the corrosion rate, leading to pronounced pitting corrosion. In the absence of O₂ and SO₂, the critical water content required to maintain an overall corrosion rate below 0.1 mm/year was 3400 ppm, which was close to the solubility limit of water in CO₂ under the corresponding conditions. However, with the addition of 50 ppm SO₂ and 20 ppm O₂, the critical water content decreased to 2120 ppm. When the SO₂ concentration was increased to 100 ppm, the critical water content further reduced to 1850 ppm. Notably, the critical water content required to mitigate localized corrosion was 500 ppm, regardless of the SO₂ concentration.

Mahlobo et al. [66] investigated the corrosion behavior of pipeline steel in a supercritical CO₂ environment containing 0.5–5% SO₂ impurities over a period of 1512 h. Their results demonstrated that, as the SO₂ concentration increased to 5%, the corrosion rate markedly escalated, reaching a peak of 1.396 mm/year. Given that the solubility of SO₂ is higher than that of CO₂, the SO₂ system at high concentrations exhibits greater corrosiveness. Wang et al. [51] investigated synergistic effect of O₂ and SO₂ gas impurities on X70 steel corrosion in water-saturated supercritical CO₂ environment and found the impact of SO₂ was more pronounced than that of O₂. The synergistic effect between SO₂ and O₂ was influenced by their varying concentrations; higher concentrations of O₂ exhibited a certain inhibitory effect on the corrosion process (Figure 8). Sun et al. [60,64] found that, in water-saturated supercritical CO₂ systems, SO₂ exerted a more pronounced effect on the average corrosion rate of X65 steel compared to H₂S and O₂ when present as single impurities. The synergistic effects of multiple impurities on corrosion rates were observed in the following order: S_O2-H2S (4.88), S_O2-SO2 (35.69), S_H2S-SO2 (42.03), and S_O2-H2S-SO2 (54.88). In the presence of both H₂S and SO₂, sulfur can be produced, which subsequently reacts with water to form sulfuric acid (H₂SO₄), as shown by Equations (21) and (22):

$${2H}_{2}S+{SO}_2\to 3\mathrm{S}+2H_2\mathrm{O}$$

(21)

$$8S+8H_2\mathrm{O}\to {6H}_{2}S+2H_2\mathrm{S}{\mathrm{O}}_4$$

(22)

Similar to the effect of H₂S, the presence of SO₂ accelerates the corrosion rate of steel in supercritical CO₂ environments. The composition and morphology of corrosion products are highly complex, exhibiting a multi-layered structure. When SO₂ is present as a sole impurity gas, it does not significantly influence the localized corrosion behavior of steel in a supercritical CO₂ environment.

3.5. NO₂ Content

NO₂ is a potent oxidizing gas that readily dissolves in water to form nitric acid (HNO₃), thereby reducing the pH of the system. This has a significant impact on corrosion behavior in supercritical CO₂ environments. Corrosion products may include oxides and nitrates, such as Fe(NO₃)₃, as indicated in Equations (23)–(25) [67]. These products can dissolve the surface protective layer, thus altering corrosion behavior and potentially leading to pitting corrosion at higher concentrations [34]. Table 5 presents a summary of the experimental results obtained in a supercritical CO₂ environments contaminated with NO₂ impurities.

$$3{NO}_2+H_{2}O\to NO+2{HNO}_3$$

(23)

$${Fe}^{3+}+3{{NO}_3}^{-}\to {Fe\left({NO}_3\right)}_3$$

(24)

$$4{Fe\left({NO}_3\right)}_3\to 2{Fe}_2{O}_3+12{NO}_2+3O_2$$

(25)

Morland et al. [67] discovered that, in dense phase CO₂ at 25 °C and 10 MPa, carbon steel began to corrode when the NO₂ content was 75 ppmv and the water content reached 350 ppmv. The corrosion significantly intensified when the water content increased to 670 ppmv, with a corrosion rate of 0.57 mm/year. The corrosion products transitioned from black to brown, indicating the formation of iron oxides, though the specific type remains undetermined. Given the conditions of the corrosive medium, it is plausible that carbon steel may form FeOOH upon exposure to NO, NO₂, or HNO₃. This observation was also corroborated by other researchers [63,68]. Li et al. [63] discovered that the corrosion rate of X80 steel was 5.30 mm/y after 48 h in a supercritical CO₂ environment containing 100 ppmv of NO₂, which was significantly higher than that in an environment with O₂, SO₂, and without impurities. HNO₃ released H⁺ ions, thereby facilitating the cathodic reaction, and the corrosion products formed display inadequate adhesion to the steel matrix and insufficient protective properties, consequently accelerating the corrosion of X80 steel. (Figure 9). In dense phase CO₂ environments containing NO₂ and H₂O, the corrosion rate of X65 steel ranged from 0.06 to 1.66 mm/year, which was significantly higher than that observed in similar concentrations of SO₂ impurities [68]. Sun et al. [69] investigated the corrosion behavior of X65 steel in supercritical CO₂ saturated with water containing O₂, H₂S, SO₂, and NO₂ impurities at 10 MPa and 50 °C. Their findings indicated that NO₂ is the dominant factor controlling the corrosion behavior of X65 steel, and NO₂ and SO₂ exert the most significant influence on the corrosion of X65 steel, followed by H₂S and O₂. Local corrosion occurred in an environment containing only NO₂ impurities, where the corrosion products primarily consisted of Fe₂O₃·H₂O, with minor amounts of Fe(NO₃)₃·9H₂O.

They also found that the influence of different impurities affects stress corrosion cracking (SCC) sensitivity. Specifically, O₂ has minimal impact on enhancing SCC susceptibility of X65 steel, whereas SO₂ and NO₂ greatly enhance SCC susceptibility due to their strong corrosion effects. The SCC process of X65 steel in a supercritical CO₂ environment also varies based on the type of impurities [70]. There is a relative paucity of studies focusing on NO₂ as an individual impurity, with more research concentrating on the synergistic effects within multi-impurity systems.

There is a limited number of studies investigating the influence of NO₂ on the corrosion behavior of steel in supercritical CO₂ environments. Based on existing research findings, NO₂ has been shown to accelerate steel corrosion in such environments and induce local corrosion. When present as a single impurity gas, NO₂ exerts a greater impact on the corrosion rate of steel in supercritical CO₂ environments compared to O₂, SO₂, and H₂S.

Table 5. Corrosion behavior of steel with NO₂ impurities in supercritical CO₂.

Materials	Pressures (MPa)	Temperature (°C)	Environment	NO2 Content	Other Impurities	Corrosion Time (h)	Corrosion Rate (mm/y)	Corrosion Products	Reference
X80	8	35	CO2-saturated 1wt% NaCl solution	0		48	1.67	FeCO3, Fe2O3	[63]
				100 ppmv			5.30	FeCO3, FeOOH
X65	10	50	water-saturated CO2 phase	0		24	~0.04	FeCO3	[69]
				1000 ppmv			1.72–1.76	FeCO3, Fe(NO3)3∙9H2O, Fe2O3∙H2O
				0		120	<0.04	FeCO3
				1000 ppmv			0.44–0.48	FeCO3, Fe(NO3)3∙9H2O, Fe2O3∙H2O

Table 5. Corrosion behavior of steel with NO₂ impurities in supercritical CO₂.

Materials	Pressures (MPa)	Temperature (°C)	Environment	NO2 Content	Other Impurities	Corrosion Time (h)	Corrosion Rate (mm/y)	Corrosion Products	Reference
X80	8	35	CO2-saturated 1wt% NaCl solution	0		48	1.67	FeCO3, Fe2O3	[63]
				100 ppmv			5.30	FeCO3, FeOOH
X65	10	50	water-saturated CO2 phase	0		24	~0.04	FeCO3	[69]
				1000 ppmv			1.72–1.76	FeCO3, Fe(NO3)3∙9H2O, Fe2O3∙H2O
				0		120	<0.04	FeCO3
				1000 ppmv			0.44–0.48	FeCO3, Fe(NO3)3∙9H2O, Fe2O3∙H2O

3.6. Influence of Working Conditions (Temperature, Pressure, Flow Rate, Time)

Changes in temperature and pressure not only influence the solubility of H₂O in supercritical CO₂ and the solubility of impurity gases in CO₂ within H₂O, but also alter the morphology of corrosion products and the reaction rate [71].

Nazari et al. [72] discovered that the morphology and stability of corrosion products on X70 steel are significantly influenced by temperature in a CO₂ environment ranging from 55 °C to 85 °C. At higher temperatures, the corrosion products become denser and more resistant to disintegration or detachment, thereby effectively inhibiting further corrosion of the substrate and enhancing its protective efficacy. Sui et al. [73] investigated the corrosion behavior of X65 steel in a supercritical CO₂ environment across various temperatures and pressures. Their findings revealed that the most severe surface corrosion occurred at 8 MPa and 35 °C, with a corrosion rate of 0.190 mm/year. When the temperature increased to 50 °C, the corrosion rate decreased to 0.032 mm/year. Likewise, at a constant temperature of 35 °C, as the pressure was raised to 10 MPa, the corrosion rate reduced to 0.073 mm/year. Hua et al. [74] investigated the corrosion behavior of X65 steel in supercritical CO₂ environments at varying temperatures and water contents. Despite similar molar concentrations of water at both temperatures, the CO₂ density difference results in more than double the mass of water being dissolved into the CO₂ phase per unit volume at 35 °C compared to 50 °C. This leads to a higher corrosion rate at 35 °C relative to 50 °C under water-saturated CO₂ conditions. Additionally, the corrosion product film formed at 50 °C was denser and more protective. Wang et al. [75] investigated the corrosion behavior of N80 steel under experimental conditions involving formation water and supercritical CO₂ at pressures of 10 MPa and temperatures ranging from 40 °C to 120 °C. They discovered that increasing temperature facilitated the formation of FeCO₃. In both environments, the corrosion rate of N80 initially increased with rising temperature but subsequently decreased at higher temperatures. However, the corrosion products formed in different environments exhibit markedly distinct characteristics. In a formation water environment, the corrosion products tend to be more uniform and regular. In contrast, those formed in a supercritical CO₂ environment display a variety of morphologies, including spherical, lamellar, and needle-like structures (Figure 10).

The influence of pressure on solubility leads to a decrease in the pH of the corrosive medium, an increase in the activity of corrosive ions, and alterations in the electric double layer at the steel/liquid interface. Consequently, in both O₂-free and O₂-containing water-saturated CO₂ systems, the corrosion rates of several pipeline steels increased as pressure rose from 6.2 to 9 MPa, with a more rapid increase observed at 10 MPa [32]. Xu et al. [41] studied the corrosion behavior of supercritical CO₂ containing SO₂ and O₂ by water content on several pipeline steels at 50 °C and 8–12 MPa. The research revealed that pressure significantly influences the solubility of water in CO₂, thereby affecting the corrosion rate. Specifically, when the water content was below 2600 ppm, the corrosion rate at 10 MPa was marginally lower than that at 8 MPa. However, with a water content of 3000 ppm, the corrosion rate at 10 MPa markedly increased, surpassing the rate observed at 8 MPa. Additionally, the surface corrosion morphology of the X65 steel sample exhibited changes under these conditions. In the study of CO₂-saturated water phase, Rodrigues et al. [76] investigated the effect of pressure on CO₂ corrosion when water was the sole impurity at 50 °C and at pressures ranging from 2 to 20 MPa. FeCO₃ scales formed under supercritical pressures and, in CO₂-saturated water, exhibited significantly enhanced protective properties. Compared to the corrosion rate in subcritical wet CO₂ environments (0.05–0.09 mm/year), the corrosion rate in the CO₂-saturated water phase showed a significant increase, reaching 0.59–5.09 mm/year.

The flow rate increases the accessibility of corrosive ions (H⁺) to the surface of the metal matrix, thereby accelerating the corrosion process. Additionally, it carries Fe²⁺ ions away from the matrix surface, which hinders the formation of the protective FeCO₃ film [77]. Wei et al. [78] investigated the corrosion behavior of X70 steel in CO₂-saturated water under both static and dynamic conditions (0–2 m/s) and obtained consistent conclusions. The corrosion rate and pit depth were significantly higher under dynamic conditions compared to static conditions, suggesting that localized corrosion predominates when fluid motion is present (Figure 11). They also discovered that the variation in flow rate altered the predominant corrosion type in the supercritical CO₂-saturated water phase from uniform corrosion to localized corrosion. The number and size of FeCO₃ particles increased over time, leading to a thicker and denser FeCO₃ corrosion product layer, which in turn enhanced the protective effect on the substrate. However, under dynamic conditions during the initial stage of corrosion, the absence of corrosion products allows the corrosive medium to easily reach the substrate surface, resulting in severe localized corrosion [78]. Zeng et al. [79] discovered that, in a static supercritical CO₂ environment, uniform corrosion predominates whereas, under dynamic conditions, localized corrosion is more pronounced and the corrosion rate increased significantly. Li et al. [80] found that the increase in flow velocity (from 0 to 2 m/s) disrupts the densification of the FeCO₃ corrosion product film, thereby diminishing its protective effect on the substrate and accelerating the corrosion rate. Electrochemical test results also indicate that, as flow velocity increases, the self-corrosion current density rises while impedance decreases. Wang et al. [81] investigated the corrosion behavior of 13Cr SS in the presence of CO₂ and H₂S at flow rates ranging from 0 to 2.5 m/s. They discovered that the corrosion product film was more prone to detachment in the static water phase compared to the CO₂ phase. Consequently, after 336 h, the thickness of the corrosion product layer on the sample surface in the aqueous phase was significantly lower.

The corrosion duration in a supercritical CO₂ environment not only influences the thickness and composition of the corrosion product film but also impacts its protective properties, the initiation of localized corrosion, and changes in the corrosion rate. Mahlobo et al. [66] investigated the long-term corrosion behavior of carbon steel in supercritical CO₂ environments and found that the protective efficacy of the corrosion product film increased progressively over time, leading to a lower corrosion rate after 1512 h compared to that observed at 336 h. Wang et al. [82] proposed that, in the H₂O-rich phase, as corrosion time increased, the corrosion product layer evolved from porous to dense, ultimately forming a protective layer. In the CO₂-rich phase, corrosion products predominantly formed in water condensation regions, resulting in the formation of FeCO₃. Hua et al. [36] discovered that, in the CO₂-saturated water phase, the types and forms of corrosion products evolved over time. In comparison with the CO₂-saturated water phase, uniform corrosion is more prevalent in environments where water is less abundant. They also found that, as the exposure time of X65 and 13Cr in water-saturated supercritical CO₂ containing SO₂ and O₂ increased from 6 h to 48 h, the uniform corrosion rate and local corrosion rate decreased, but the local corrosion depth increased [83].

Compared with the influence of pressure, the conclusions drawn from various studies regarding the effects of temperature, flow rate, and time on the corrosion behavior of steel in supercritical CO₂ environments are relatively consistent. Temperature variations can significantly influence the morphology of corrosion products and modulate the rate of corrosion reactions. Overall, at higher temperatures, the corrosion products formed on steel in a supercritical CO₂ environment are denser, which enhances the protective barrier for the substrate and consequently reduces the corrosion rate. The composition and morphology of the corrosion products evolve over time. As time progresses, the corrosion products will gradually thicken and densify, consequently reducing the corrosion rate of the steel. In a supercritical CO₂ environment, the flow of fluids can erode corrosion products on the steel surface, potentially causing their detachment and thereby diminishing their protective capabilities. Additionally, the flow process enhances the transport of corrosive ions, such as H⁺, HCO₃⁻, and CO₃²⁻, thereby accelerating both the average and localized corrosion rates of steel. Pressure not only affects the solubility of CO₂ and various impurity gases in water but also influences the solubility of impurities in CO₂. Additionally, it can alter the morphology of corrosion products, thereby exerting a complex influence on the corrosion behavior of steel in supercritical CO₂ environment. For different corrosive environments and materials, the variation trend in the corrosion rate of steel with pressure does not follow a consistent pattern.

4. Corrosion of Welded Joints in Supercritical CO₂ Environments

Welded joints are among the most susceptible components in pipeline systems. During the welding process, these joints experience a welding heat cycle, with heating and cooling occurring in an extremely non-uniform manner across different regions. The microstructural changes in the weld and heat-affected zones, along with the heterogeneity of welding materials, contribute to the vulnerability of these joints to corrosion [84,85,86,87].

Ding et al. [88] investigated the corrosion mechanism in different regions of the X 65 welded joints in CO₂/SO₂ saturated aqueous solution. They found that SO₂ and its hydrates were more inclined to adsorb in the BM and generate FeS product films, while the WM exhibited the poorest adsorption. This can be attributed to the differences in microstructure between the base material (BM), heat-affected zones (HAZ), and weld metal (WM), which result in varying formation of corrosion product films on the surfaces. Bai et al. [89] argue that welds and heat-affected zones (HAZs) are the most susceptible areas to failure in welded joints within the pipeline transportation of the oil and gas industry. Given that welding is inevitable in supercritical CO₂ long-distance transportation pipelines, the corrosion behavior and protective measures for welded joints in supercritical CO₂ environments become particularly critical. Regarding the research on welded joints, Lu et al. [90] investigated the early corrosion behavior of carbon steel welded joints in water-saturated CO₂ oil fields. They discovered that the early corrosion characteristics of different regions within the welded joints were influenced by grain orientation but not by grain size, grain boundary type, or secondary phases. Yan et al. [91] investigated the corrosion behavior of X80 welded joints under conditions of 40 °C and 10 MPa water-saturated supercritical CO₂. They found that the corrosion behavior varied due to differences in microstructure among the BM, fine-grained heat-affected zone (FGHAZ), coarse-grained heat-affected zone (CGHAZ), and WM. Specifically, FGHAZ and CGHAZ exhibited higher proportions of pearlite and more severe corrosion, while BM and WM, which contained higher ferrite content, experienced relatively mild corrosion. As shown in Figure 12, the surfaces of these different regions were covered with FeCO₃ crystals, but the extent of coverage differed. The FeCO₃ islands were larger on the surface of FGHAZ, whereas they were smaller but more numerous on the surfaces of BM and WM. CGHAZ showed the most severe corrosion, forming multilayer polycrystalline FeCO₃ films that almost completely covered the specimen surface. There were numerous pores observed on both the FeCO₃ islands on the sample surface in each zone, as indicated by the red frame, which could potentially serve as initiation sites for local corrosion. Yao et al. [92] also observed that, after 120 h of corrosion at 40 °C and 10 MPa, the corrosion levels of the X80 base metal and weld area were similar, with FGHAZ experiencing the least corrosion and CGHAZ showing the most severe corrosion. Additionally, the local corrosion depth of the joint was greater. The variation in chemical composition was identified as the primary factor responsible for the differing early corrosion behaviors across various regions of the welded joints.

Although research on welded joints in CO₂ environments has reached a relatively mature stage, studies focusing on welded joints in supercritical CO₂ conditions remain limited. The existing research primarily concentrates on the differences in corrosion product forms across various regions of the X80 welded joint, but lacks a detailed examination of corrosion rates and the associated corrosion mechanisms in welded joints. Currently, there is limited research available regarding the corrosion behavior of welded joints across different steel grades, as well as the influence of various types and concentrations of impurities on the welded joints in supercritical CO₂ transmission pipelines.

5. Conclusions

The CCUS project is a large-scale system, and therefore investigating corrosion in supercritical CO₂ pipeline transportation is crucial for ensuring operational safety.

• When H₂O is present in supercritical CO₂ systems, gas impurities react with water to form corrosive products. Extensive studies have demonstrated that the corrosion rate increases significantly once the water content surpasses a specific critical threshold. However, the critical water content varies among different corrosion systems and materials. Under identical water content conditions, the localized corrosion rate can be several dozen times higher than the average corrosion rate. Controlling water content is crucial for mitigating pipeline corrosion. Compared to the average corrosion rate, taking the local corrosion rate into account is more reasonable for controlling water content in supercritical CO₂ fluids. It is crucial to emphasize the impact of water content on the localized corrosion behavior of pipeline steel in future research.
• A small amount of O₂ accelerates the corrosion of steel; however, at high concentrations, O₂ can induce passivation of the substrate, thereby significantly reducing the corrosion rate. O₂ can facilitate local corrosion of steel in supercritical CO₂ environments and significantly influence the rapid progression of localized corrosion. Acidic gases, such as H₂S, SO₂ and NO₂, can accelerate the corrosion rate of steel, and their influence on the corrosion behavior of steel in the water phase is significantly greater than that in the CO₂ phase. Among these gases, NO₂ exhibits the most significant impact, often leading to localized corrosion. H₂S and SO₂ do not accelerate the localized corrosion rate of steel. When various types of gas impurities are present, the composition of corrosion products becomes more complex, and the corrosion products form a multi-layer structure. The synergistic effects of multiple impurities are more detrimental than those of individual impurities, and water content plays a crucial role in multi-impurity systems. The influence of the synergistic effect of multiple impurities on the corrosion behavior of pipeline steel requires further investigation and merits considerable attention.
• Temperature and pressure significantly influence the formation and properties of corrosion product films. Numerous studies have demonstrated that, within a specific temperature range, elevated temperatures can promote the densification of corrosion product films, thereby enhancing the protective effect on the substrate surface. Moreover, the effects of pressure exhibit variability across different systems. The corrosion rate of steel increases with the flow velocity of supercritical CO₂ fluid, and the dynamic flow of the fluid can lead to localized corrosion of steel. The morphology and structure of the corrosion products evolve as the corrosion time increases.
• Research on welded joints of pipeline steel in the supercritical CO₂ environment remains relatively limited. Existing studies indicate that distinct morphologies of corrosion products form in the HAZ, WM, and BM of X80 welded joints under supercritical CO₂ conditions. However, a comprehensive and in-depth understanding of the corrosion mechanism remains insufficient. Specifically, there is a lack of comprehensive investigation into the influence of water content and impurity gases on the corrosion behavior of different pipeline steel welded joints.