Corrosion, defined as the detrimental degradation of a material through interactions with its environment [1], is a significant challenge in the upstream oil and gas sector, often leading to unforeseen costs and environmental repercussions. Aqueous phases in production fluids amplify the risk and severity of corrosion, impacting the industry’s equipment and materials. Traditionally, carbon steels (CS), favored for their affordability and accessibility, have been extensively used in hydrocarbon extraction infrastructure, despite their susceptibility to corrosion due to their high electrochemical activity [2].

The annual corrosion cost in oil and gas production, estimated at $1.372 billion, notably includes $463 million attributed to downhole tubing expenses [3]. As exploration extends into harsher downhole environments, characterized by high temperatures/ pressures (HT/HP), corrosive gases, and acids, the corrosion challenge intensifies. The evolving conditions demand ongoing operational adaptations, tool redesigns, and material revisions to combat corrosion effectively. Figure 1 encapsulates the common corrosion root causes and types prevalent in downhole settings, illustrating a breakdown of failure types and their associated frequencies, derived from a limited industry-wide survey in the 1980s [4]. CO₂ and H₂S-related failures account for 46 % of the total failures observed, underscoring their corrosive nature in industrial settings. Each type of corrosion observed in a downhole setting will be discussed in later sections.

Figure 1 Corrosion-related issues and failure instances encountered in the oil and gas industry [4].

A recent and refined data pulled out from PHMSA (Pipeline and Hazardous Materials Safety Administration) and Government Canada related to corrosion failures and incidents in pipelines is presented in Figure 2 for the period from 2008 to 2024 [5,6]. The data indicates that corrosion is a major cause of pipeline failures, accounting for an average of 11.5 and 18.7 % of the total failures in Canada and the USA, respectively.

Figure 2 Data for corrosion-related failures in pipelines for the period from 2008 to 2024 in Canada and USA [5,6].

In downhole environments, where aqueous phases mingle with corrosive gases, acids, and brines, corrosion susceptibility escalates under HT/HP conditions. The operating temperatures typically range between 130 (266) and 250 °C (482 °F), coupled with pressures often exceeding 2 MPa (approximately 290 psi) [7,8]. These extreme conditions not only exacerbate corrosion severity but also modify the corrosion mechanisms experienced. Notably, downhole failures stem from the interplay of multiple corrosion and wear processes and their synergistic effects [9]. The presence of CO₂ and H₂S in condensed water phases exacerbates corrosion challenges across oil and gas operations, from production to stages [10]. CO₂, dissolved in water, forms corrosive carbonic acid, while H₂S, acting as a weak acid, releases hydrogen ions, furthering corrosive effects. Oxygen, though not typically present in producing formations, infiltrates during drilling, intensifying corrosion in conjunction with CO₂ and H₂S [11].

Apart from natural downhole aggressors, introduced chemicals like acids and brines during well completion and production significantly influence steel corrosion. Chloride ions, commonly found in brines, are notorious for localized corrosion and stress corrosion cracking (SCC) of downhole facilities [12]. Various oil recovery techniques, involving corrosive species injection, further exacerbate steel corrosion [13-15]. However, oil and gas products can act as organic corrosion inhibitors, mitigating steel corrosion [16,17]. The interplay of these factors, alongside HT/HP and stresses during drilling or production, complicates downhole corrosion analysis and prevention and hinders accurate prediction of corrosion type and rate in lab tests. To mitigate failures, understanding and controlling critical parameters such as reactive gas partial pressures, system pressures, temperatures, chloride content, oxygen levels, aqueous phase properties, and synthetic brine compositions are paramount.

Controlling corrosion rates can often be more cost-effective than attempting complete prevention, given the near-impossibility of eradicating corrosion. The initial step in managing corrosion-related failures is identifying the specific corrosion type. Downhole environments commonly experience pitting corrosion, stress corrosion cracking, crevice corrosion, corrosion under deposits and scales, and erosion-corrosion [18]. Corrosion in these settings often coincides with the formation of iron sulfide (FeS) scale, especially in the presence of H₂S, leading to decreased production and tubing plugging [19]. This FeS scale, originating from the corrosion of carbon steel, lacks the protective properties of a passive film and can even foster localized corrosion, hastening structural failure [20,21]. Furthermore, downhole structures are susceptible to erosion-corrosion due to the continuous impact of multi-phase fluids containing solid particles [22]. This erosion-corrosion issue costs the oil and gas industry millions annually in efforts to prevent and rectify downhole sand control failures [23].

To combat downhole corrosion, various techniques are employed, including corrosion inhibitors [24], coatings [25], corrosion-resistant alloys (CRAs) [26], and non-metallic composites [27]. Despite the prevailing trend of combating and minimizing corrosion, there exists a niche where controlled and favorable corrosion is harnessed. This approach diverges from the conventional norm of corrosion prevention, showcasing how intentional and strategic corrosion can serve as a valuable tool in advanced technologies, such as dissolvable downhole tools. These dissolvable tools, such as balls and frac plugs, dissolve entirely under downhole conditions after their operational lifespan, eliminating the need for retrieval and enhancing operational efficiency [28]. A dedicated section in this paper will delve further into the principles and applications of this technology, providing a detailed discussion.

Over the past decade, the publication trends reflect a consistent and significant focus on downhole corrosion research. From 2014 to 2024, an average of 67 publications annually addressed downhole corrosion, 60 focused on sour corrosion, and 36 explored sweet corrosion, as depicted in Figure 3. These numbers highlight the sustained efforts to advance understanding and address challenges in this critical field. The higher focus on sour corrosion research may be attributed to its more aggressive nature, leading to severe material degradation, particularly in HT/HP environments. Additionally, sour environments often require specialized materials and mitigation strategies due to the presence of H₂S, which poses safety and operational challenges. In contrast, sweet corrosion, while still significant, generally results in less severe damage, possibly explaining the relatively lower number of studies. These trends suggest a prioritization of research efforts based on industry needs and the severity of corrosion related risks.

Figure 3 Recent publication records on corrosion issues in downhole environments over the past decade. Data obtained from Scopus (2014 - 2024) searching for downhole corrosion, sour corrosion, and sweet corrosion.

Previous studies have extensively addressed corrosion challenges in oil and gas environments, focusing on a wide range of themes, including corrosion monitoring and controls, i.e., well integrity, [29-35], sour corrosion challenges [36-39], sweet corrosion [35,40-46], and microbial-induced corrosion [47-55]. Thus far, the findings emphasize the importance of continued research and improvement specifically targeting corrosion issues in the oil and gas industry. Choi et al. [56] emphasized the critical role of wellbore integrity, highlighting the risks of casing steel corrosion under CO₂ sequestration conditions and the importance of cement quality in mitigating leakage. Solovyeva et al. [29] provided insights into the advancement in corrosion protection, discussing the potential of smart coatings, nanomaterial-based solutions, and environmentally friendly inhibitors to address harsh operational demands. Olorundaisi et al. [57] explored the application of High Strength Low Alloy Steels (HSLAs) in pipelines, showcasing the benefits of alloying with chromium and surface treatments to enhance corrosion and wear resistance in petrochemical settings. Additionally, Askari et al. [46] examined internal corrosion and cracking in oilfield pipelines, categorizing risks in both sweet and sour service environments and discussing specific corrosion mechanisms and case studies, while Khan et al. [58] reviewed various electrochemical techniques for corrosion monitoring in surface and downhole applications, highlighting ongoing challenges and prospects.

Our work stands apart by synthesizing these perspectives and extending the scope to address HT/HP downhole environments, where the effects of CO₂, H₂S, and O₂ pose unique challenges on metallic structures. The discussion extends to various forms of corrosion encountered in downhole environments, offering insights into their implications on pipeline failure. Moreover, we evaluate the countermeasures of current corrosion control strategies identifying their strength and limitations. Uniquely, our work also touches on favorably controlled corrosion through advanced dissolvable alloys, exploring their potential in downhole operations, particularly in enhancing efficiency and reducing post-fracture clean-up in unconventional oil and gas wells. By synthesizing these themes, our review bridges existing knowledge gaps and provides insights to advance corrosion management in challenging operational settings.

Corrosive gases in downhole environments

CO₂ corrosion

CO₂, often referred to as “sweet gas,” is a common component in downhole environments. The concentration of CO₂ in wells can vary from 0.5 to 7.5 % depending on geographical factors [2,27,59]. It plays a dual role in oilfield operations: While naturally occurring, CO₂ contributes to corrosion challenges, injected CO₂ is a critical component of Enhanced Oil Recovery (EOR) and Carbon Capture, Utilization, and Storage (CCUS) processes. CO₂-EOR, which increases oil extraction by 15 - 20 %, involves injecting CO₂ into the subsurface to reduce the viscosity and interfacial tension of crude oil, enhancing mobility and recovery [60]. While CO₂-EOR supports sustainability goals by utilizing captured CO₂, its net sequestration potential varies depending on operational practices. Studies indicated that approximately 40 - 60 % of the injected CO₂ is produced with the oil, whereas standalone CCUS processes are designed for permanent storage, aiming for near-total sequestration [61-64]. This distinction highlights that while CO₂-EOR contributes to carbon sequestration, its effectiveness in long-term CO₂ reduction depends on retention rates and project-specific parameters. Both techniques support environmental efforts by utilizing captured CO₂, aligning with global sustainability goals.

Despite its operational benefits, CO₂ poses significant risks to downhole equipment. In the presence of water, CO₂ dissolves to form carbonic acid (H₂CO₃) which initiates “sweet corrosion.” This type of corrosion affects materials like CS commonly used in oilfield infrastructure, resulting in degradation that can compromise the integrity of wells and pipelines. Effective management of CO₂-induced corrosion is essential to ensure the longevity and safety of oilfield operations.

Mechanism of CO₂ corrosion

When CO₂ dissolves into formation water, it initiates the corrosion of metals, particularly CS. Dissolved CO₂ undergoes hydration and ionization, releasing hydrogen ions and leading to a decrease in pH. This process, illustrated in Reactions (1) - (3), forms carbonic acid (H₂CO₃), a key driver of CO₂ corrosion. The anodic and cathodic reactions, outlined in Reactions (4) - (6), involve the reduction of hydrogen ions and carbonate to hydrogen gas, further facilitating the corrosion process [42,65,66]. The mechanism is illustrated in Figure 4.

One critical component of CO₂ corrosion is iron carbonate (FeCO₃), which forms a protective layer on steel surfaces as illustrated in Reactions (7) [42,67]. FeCO₃ precipitates due to its low solubility and can significantly reduce the corrosion rate if the layer is dense and adherent. This primary corrosion product forms a protective film on the metal surface, which can mitigate further corrosion and reduce the overall corrosion rate [68,69]. The formation of FeCO₃ was also proposed to take place in a 2-stage reaction, Reactions (8 and 9), where iron bicarbonate (Fe(HCO₃)₂) is formed from ferrous ions and bicarbonate ions. The formed Fe(HCO₃)₂ decomposes to FeCO₃ that precipitates on the metal surface.

Figure 4 Mechanism of CO₂-induced corrosion.

Figure 5 shows the influence of chloride concentration and temperature. In Figure 5(a), a parabolic trend was observed when the corrosion rate of N80 carbon steel was studied under varying Cl⁻ concentrations from (0 to 150) g/L [70]. A slight increase in Cl⁻ concentration significantly influenced the corrosion rate, peaking at 25 g/L after which it drops as Cl⁻ concentration increases. Figure 5 (b) shows the corrosion rate as a function of the temperature of T95, C110, and Q125 carbon steels [71]. The highest corrosion rate was observed at 38 °C, while at 71 and 107 °C, the corrosion rate decreased as protective layers became more stable. The chloride concentration and temperature have similar effects, where the corrosion rate generally decreases as their values increase. This results in reducing the solubility of CO₂ and FeCO₃, which promotes the formation of the protective layer. It is important to note that at elevated temperatures localized corrosion and pitting become more prominent due to the possible formation of porous and non-uniform corrosion scales.

Figure 5 Influence of chloride concentration and temperature on the corrosion rate of carbon steels. (a) The impact of chloride concentration on the corrosion rate of N80 at 20 MPa pCO₂ and 100 °C after 72 h exposure [70], and (b) the impact of temperature on the corrosion rate of T95, C110, and Q125 carbon steels at 20.7 MPa pCO₂ and 2 % NaCl after exposure for 168 h [71].

The protectiveness of this scale depends on multiple factors, including the steel’s composition and microstructure, as well as environmental parameters such as CO₂ partial pressure and pH. Controlled formation conditions promote a dense and adherent FeCO₃ scale, effectively mitigating further corrosion. Conversely, rapid precipitation can lead to porous and loosely adherent films, which are less protective [69,72]. While the influence of these factors is reviewed elsewhere [73,74]. Table 1 summarizes their effects on the corrosion behavior and protective layer in CO₂ environments.

Table 1 Summary of factors influencing corrosion behavior and protective layer formation in CO₂ environments.

Role of CO₂ solubility in corrosion

A key factor in CO₂-induced corrosion is its solubility in brine. CO₂ solubility is influenced by temperature and pressure, which significantly impact the corrosion environment. It decreases with increasing temperatures, leading to a less aggressive corrosion environment due to reduced carbonic acid formation (Reactions (1) - (3)) [42]. Conversely, increasing pressure enhances CO₂ solubility, intensifying the corrosion environment. Figure 6 illustrates an example of CO₂ solubility in deionized and brine water at pressures of 1 - 2 MPa across various temperatures [64]. The balance of these effects underlies operational decisions in oilfield production to minimize corrosion risks.

Figure 6 Mole fraction of gaseous CO₂ (1 and 2 MPa) dissolved in DI and brine water at different temperatures [106].

Finally, it is important to note that in the absence of water, no hydration of CO₂ or metal ions occurs, effectively halting the electrochemical corrosion process. Dry CO₂, whether under low pressures or supercritical conditions, does not provide the necessary water molecules to support corrosion reactions [99,107]. This highlights the critical role of water presence in governing CO₂-induced corrosion in downhole environments.

CO₂ corrosion in downhole environments

In downhole environments, CO₂ can occur as a gas or supercritical phase. Supercritical CO₂ is a unique phase of carbon dioxide, occurring above its critical temperature of 31.1 °C and critical pressure of 7.38 MPa. In this state, CO₂ behaves as both a gas and a liquid, having high density and diffusivity. This environment is particularly relevant in applications such as CCUS and EOR.

Al-Hashem et al. [108] studied the corrosion of L80 steel in simulated oil well conditions at various temperatures and pressures with saturated pure CO₂. They reported a maximum corrosion rate of 1.8 mm/y at 6.89 MPa (1,000 psi) CO₂ pressure and 90 °C. Similar trends were observed for N80 steel in CO₂-saturated formation water for 168 h, with the corrosion rate increasing as temperature increased up to 60 °C and 5 MPa, achieving a maximum weight-loss corrosion rate of 10 mm/y [92]. Whittaker et al. [109] also observed a maximum corrosion rate of 1.75 mm/y for CS in a steam-assisted gravity drainage (SAGD) brackish water system at 90 °C.

Various alloys have been investigated under supercritical CO₂ conditions, further illustrating the influence of CO₂ partial pressure (pCO₂), pressure, and temperature on the corrosion rate. Elgaddafi et al. [91] studied the corrosion behavior of C110 carbon steel under varying pCO₂ and at 38 °C and different total pressures (20.68, 41.37 and 62.05 MPa). At low overall pressure, the corrosion rate of C110 increased with increasing pCO₂, owing to the enhanced dissolution of CO₂ in the brine, which raised the acidity and lowered the pH. At 38 °C and 100 % pure pCO₂, the corrosion rate reached its maximum of 14.21 mm/y at 20.68 MPa and the corrosion was uniform. The corrosion rate was notably reduced with increasing pressure. A behavior described by the formation of a protective scale, inhibiting the corrosion process. In another study, they reported the average corrosion rates of T95, C110, and Q125 carbon steels at 38 °C and 41.37 total pressure, with ~50 % pCO₂ [110]. The obtained values were 14.6, 12.8 and 3.0 mm/y for T95, C110, and Q125 carbon steel, respectively. Q125 carbon steel exhibited high corrosion resistance, owing to the presence of manganese, nickel, and chromium.

The effect of CO₂ corrosion on chromium-containing steels was investigated by Trasatti et al. [111]. A similar behavior was observed when pCO₂ was increased from 1.0 to 1.4 MPa at 100 °C. The average corrosion rate of 9.78Cr and 8.53Cr increased from 0.13 to 0.32 and from 0.6 to 0.59 mm/y, respectively, when CO₂ partial pressure increased. In addition, they reported the corrosion rate of 8.95Cr, 8.93Cr, and AISI 410, having values of 0.17, 0.16, and 0.013 mm/y, respectively, at 150 °C and 1.4 pCO₂.

Hassani et al. [112] assessed the CO₂ corrosion behavior of AISI 1018, 13Cr (S41000), and 5Cr (A182) in the gas phase (3 MPa) and supercritical phase (8 MPa) at 60 °C. Regarding corrosion resistance, 13Cr steel exhibited excellent corrosion resistance (~0.1 mm/y) followed by 5Cr steel (~6 mm/y) and carbon steel (~20 mm/y) at 3 and 8 MPa pCO₂. This observed behavior is in agreement with the previously discussed formation of the Cr-containing corrosion product layer, which acts as a diffusion barrier, blocking corrosion species from reaching the metal surface and reducing the corrosion rate. The decrease in the corrosion rate of chromium steels was also observed when the pCO₂ increased from 3 to 8 MPa, while the opposite was observed for carbon steel, which was explained by the higher solubility of CO₂ leading to lower pH.

A similar observation was found in Kermani et al. [113] study of the corrosion performance of 3Cr steels and L80 steel in 10 % NaCl at 0.1 MPa CO₂ and 50, 80 and 120 °C. At 50 °C the corrosion rates for 3Cr-A and 3Cr-B (see Appendix A for their respective compositions) are lower (2.9 and 4.0 mm/y, respectively) compared to L80 steel (8.5 mm/y). The trend continues at 80 and 120 °C, with both 3Cr-A and 3Cr-B demonstrating lower corrosion rates, owing to the formation of Cr-enriched protective layers on 3Cr steel samples. It is worth mentioning that at 120 °C, the corrosion rate of 3Cr steels decreased to 0.32 and 0.41 mm/y for 3Cr-A and 3Cr-B, respectively, compared to the continuous increase of corrosion rate for L80 carbon steel from 8.5 mm/y at 50 °C to 13 mm/y at 120 °C. This behavior is in agreement with Hassani et al. [112] findings. Table 2 summarizes the performance of various alloys in sweet corrosion at different conditions.

The Cr-enriched protective layers formed on Cr-containing steels play a crucial role in mitigating corrosion, primarily by acting as a diffusion barrier that limits the penetration of aggressive species. These layers are typically composed of chromium oxides and mixed with iron carbonate phases, which enhance the overall stability of the steel surface. In CO₂ corrosion, an additional anodic reaction takes place, relating to the formation of Cr(OH)₃ when the steel matrix contains Cr [114]. The amorphous Cr(OH)₃ possesses a dense structure, reducing the diffusion channels and porosity in the corrosion film. Under downhole conditions of 50 °C, 8 MPa, and 1 MPa pCO₂, the corrosion product of 2Cr steels has a dense morphology, with corrosion film thickness of 41.4 and 13.1 µm for static and dynamic conditions [115]. The Cr-enriched inner layer acts as a barrier, limiting the penetration of Cl⁻ ions to the metal matrix. This reduction in anion concentration at the film-metal interface helps suppress the metal corrosion.

Environmental and operational factors play a critical role in corrosion behavior, influencing the formation and stability of protective layers on carbon steel surfaces. While a summary of these factors was presented in Table 1, this section focuses exclusively on the influence of corrosive gases encountered in downhole environments. The following subsections will discuss the roles of H₂S and O₂, providing a detailed examination of their impact on corrosion mechanisms.

Table 2 Performance summary of various alloys under sweet corrosion conditions.

Influence of H₂S presence on CO₂ corrosion

H₂S, known as “sour gas,” is present in various stages of oil and gas processes, including extraction, transportation, and refining, typically at concentrations ranging from 0 to 10 % [2,19]. Driven by the activity of sulfate-reducing bacteria (SRB), the risks of H₂S corrosion and microbiologically induced corrosion in oil and gas systems are significantly amplified [118]. These bacteria contribute to the increased presence of H₂S gas in production lines, even in fields previously considered sweet. SRB activity is particularly pronounced at the interfaces where produced water, seawater, and steel surfaces meet, creating favorable conditions for the formation and growth of biofilms. The chemical environment at these interfaces, enriched with volatile fatty acids, further promotes SRB proliferation [119].

SRB are anaerobic microorganism that utilizes sulfate (SO₄^-) as an electron acceptor, reducing it to H₂S while metabolizing organic compounds or hydrogen. This biological process not only increases H₂S concentration in production systems but also promotes the formation of biofilms on metal surfaces, altering local electrochemical conditions and facilitating corrosion [120]. These bacterial biofilms create microenvironments with distinct pH and ion concentration gradients, leading to localized corrosion such as pitting and under-deposit corrosion. Different SRB strains exhibit varying levels of aggressiveness depending on their metabolic pathways and environmental conditions. A detailed review of the characteristics and habitats of thermophilic SRB can be found in [55]

Additionally, the formation of FeS layers due to SRB activity can have both protective and damaging effects on carbon steel. While dense FeS layers may reduce further corrosion under certain conditions, porous or loosely adherent FeS films can act as conductive pathways, facilitating electron transfer and accelerating localized attack [121]. The structural integrity and adhesion properties of FeS films depend on multiple factors, including H₂S concentration, bacterial activity, and alloy composition.

When H₂S dissolves into water and ionizes, it generates H⁺ ions and creates a low pH environment, leading to the corrosion of metals. The H⁺ ions readily capture electrons, accelerating both anodic iron dissolution and cathodic hydrogen evolution. Due to its corrosive nature, H₂S production often necessitates specialized production equipment, such as stainless-steel tubing, which can be costly. Similar to CO₂, H₂S is usually non-corrosive in the absence of water.

The corrosion products formed in downhole environments due to H₂S include polymorphous iron sulfides such as amorphous FeS, mackinawite FeS, cubic ferrous sulfide FeS, troilite FeS, pyrrhotite Fe_1−xS, pyrite FeS₂. The formation of these corrosion products is influenced by factors such as pH, temperature, and duration of exposure [122-124]. Bai et al. [125] characterized the crystal structure and morphology of these corrosion products in an aqueous H₂S environment.

Different corrosion products have varying effects on steel corrosion in H₂S environments. Under specific conditions, Ma et al. [126] observed the formation of metastable mackinawite, which subsequently converted into troilite and pyrite, exhibiting an inhibiting effect on iron corrosion. Mackinawite, being porous, offers limited protection and can result in high corrosion rates [18]. Pehlke reported a maximum corrosion rate of 1.8 mm/y for 1018 CS in environments of SAGD wells containing H₂S, with the corrosion products identified as pyrrhotite [127]. Due to its very low solubility, FeS is easier to identify as the main corrosion product [128,129], and its formation can be described by Reactions (10) - (14). H₂S dissociates, as shown in Reaction (13), to form hydrogen (H⁺) and hydrogen sulfide ions (HS⁻. The HS^- ions dissociate further to sulfide ions (S²⁻) and H⁺, Reaction 11. The cathodic reactions involve the reduction of H⁺ to form hydrogen gas, as well as the formation of FeS, as shown in Reactions (13) - (14).

The main corrosion product, FeS, has very low solubility in water or water-based muds, where H₂S, HS^-, and S^2- ions are in dynamic equilibrium with water, H⁺, and OH^- ions, depending on pH [42,69]. At low pH, H₂S is dominant, while the HS^- ion becomes dominant at mid-range pH, and S₂ ions dominate at high pH. This equilibrium dictates that sulfide ions revert to H₂S if pH decreases.

A comparative analysis of the impact of varying H₂S on CO₂ corrosion is discussed by Rida Elgaddafi et al., where they provided valuable insights into the corrosion behavior of 3 carbon steels - T95, C110, and Q125 - in CO₂ and H₂S environments [110]. Their study highlights the significant influence of H₂S on both corrosion rates and the characteristics of corrosion scales formed on these materials. The corrosion tests were conducted at 38 °C and 41.37 MPa total pressure, with pCO₂ of approximately 50 % and varying H₂S concentrations of 0, 10, 50, and 150 ppm. Generally, the addition of H₂S to CO₂ environments in small quantities accelerates the corrosion, while higher concentrations can lead to the formation of protective scales that inhibit the corrosion.

For T95 carbon steel, the corrosion rate increased from 14.62 mm/y, in CO₂ only environment, to 19.67 mm/y when 10 ppm H₂S was introduced. Interestingly, as the H₂S concentration increased to 50 ppm H₂S, the corrosion rate decreased to 16.17 mm/y, likely due to the formation of a partially protective scale. However, at 150 ppm H₂S, the rate rose slightly to 17.16 mm/y, attributed to the breakdown of the protective layer. Similarly, for C110, an initial rise in the corrosion rate from 12.79 mm/y in CO₂ only environment to 13.97 mm/y when 10 ppm H₂S was introduced. This was followed by a significant reduction to 9.36 mm/y at 50 ppm H₂S, suggesting the formation of a more stable protective layer.

In contrast, the corrosion rate of Q125 in CO₂ only environment was initially 2.99 mm/y, and increased to 9.26 mm/y when 10 ppm H₂S was introduced. The alloy exhibited a steady increase in corrosion rates from 9.26 mm/y at 10 ppm H₂S to 9.94 at 50 and 10.05 mm/y at 150 ppm. This behavior was attributed to the nature of the corrosion scales: Denser and more effective at lower H₂S concentrations but becoming more porous and scattered at higher concentrations, reducing their protective effectiveness.

In addition to carbon steels, the corrosion performance of martensitic and low-alloy steels in downhole environments was studied by S. Trasatti et al. [111]. They investigated the corrosion behavior of 9Cr-1Mo steel grades and martensitic steels, including AISI 410 and Super 13Cr, at 2 temperatures of 100 and 150 °C, 2 CO₂ partial pressures of 1.0 and 1.4 MPa, and H₂S partial pressures of 10 kPa. The study reported moderate corrosion rates for 8.95Cr and 8.93Cr steels, ranging from 0.08 to 0.44 mm/y, depending on the temperature and partial pressures of CO₂ and H₂S. AISI 410 exhibited excellent corrosion resistance, with a corrosion rate as low as 0.001 mm/y at 100 °C, with pCO₂ and pH₂S of 1.0 MPa and 10 kPa, respectively, and 0.07 mm/y at 150 °C, with pCO₂ and pH₂S of 1.4 MPa and 10 kPa, respectively. Similarly, Super 13Cr showed strong performance, with a corrosion rate of 0.02 mm/y at 150 °C, 1.0 MPa pCO₂, and 10 kPa pH₂S. A slight increase in corrosion rate to 0.04 mm/y was observed when pCO₂ was increased to 1.4 MPa.

Liu et al. [130] further contributed to the understanding of alloy performance in downhole environments by investigating the corrosion behavior of HS110S steel at temperatures ranging from 150 to 350 °C, 0.25 MPa pCO₂, and 0.17 kPa pH₂S. Their findings revealed pronounced effects of temperature on the corrosion rate. Under static conditions, the corrosion rate increased with increasing temperature. At 150 °C, the corrosion rate was 0.11 mm/y which increased to 0.97 mm/y at 350 °C. The tests were also conducted under dynamic conditions, at which corrosion rates were reported higher due to the enhanced mass transfer of corrosion species and the fluid shear stresses that could disturb the protective corrosion product layer.

Similarly, Kermani et al. [113] examined the corrosion performance of 3Cr steels and L80 steel in 10 % NaCl at 50 °C, 0.095 MPa pCO₂, and 5 kPa pH₂S. Their results showed that L80 steel exhibited a higher corrosion rate of 2.9 mm/y, whereas 3Cr steel demonstrated better corrosion resistance with a rate of 0.56 mm/y. A similar behavior was observed in their study for sweet corrosion, where the Cr-enriched protective layer acts as a diffusion barrier and inhibits the corrosion.

Ren et al. [116] studied the relationship between corrosion rates and pH₂S for N80, investigating the influence of H₂S partial pressure at 100 °C and 1.7 MPa pCO₂. For N80 steel, introducing H₂S at 2 kPa resulted in a high corrosion rate of 3.08 mm/y. However, as pH₂S increased to 10 kPa, the corrosion rate decreased sharply to 0.96 mm/y, and further increases to 14 and 20 kPa reduced the corrosion rate to 0.69 and 0.54 mm/y, respectively. This behavior was attributed to the formation of protective iron sulfide films at higher pH₂S.

Yan et al. [117] studied the pH₂S influence on 3Cr80 steel at 90 °C and 0.4 pCO₂, under dynamic conditions, by varying pH₂S from 0.2 to 400 kPa. Their study revealed that as pH₂S increased from 0.2 to 4 kPa, the corrosion rate steadily decreased, with the minimum corrosion rate of 0.72 and 0.71 mm/y occurring at 0.8 and 4 kPa. Beyond this range, a different trend was observed, as pH₂S increased to 80 kPa the corrosion rate rose to 1.52 mm/y, and at 400 kPa, it doubled to 2.1 mm/y compared to pure pCO₂ conditions. The findings highlighted a dual effect of H₂S, where at low levels, protective layers effectively reduced the corrosion rate, while at higher levels, these layers became unstable, leading to increased general and localized corrosion.

These findings collectively emphasize the complex interactions between environmental factors - such as temperature, fluid dynamics, presence of H₂S - and alloy composition. They also underscore the critical role of protective scale formation and stability in mitigating corrosion in CO₂-H₂S environments. Table 3 summarizes the performance of various alloys under sour corrosion conditions across different conditions

Table 3 Performance summary of various alloys under sour corrosion conditions.

Influence of O₂ presence on CO₂ corrosion

In oilfield operations, oxygen-induced corrosion poses a significant challenge, particularly for the internal surfaces of production equipment. Oxygen is typically absent at depths below 100 m (330 feet); however, contamination can occur in facilities where processing and handling of produced fluids take place near atmospheric pressure. Common sources of oxygen ingress include leaking seals in pumps, venting through casing or process systems, open hatches, and exposure during operations such as drilling and mud pit handling [131].

Oxygen is a potent oxidizing agent with rapid reduction kinetics, shown by Reaction (15):

Its solubility in water and brines is relatively low, making the rate of oxygen transport a limiting factor in the corrosion processes of carbon and low-alloy steels, especially in non-acidic conditions. This limited transport also contributes to localized corrosion, such as crevice corrosion and under-deposit attacks arising from restricted oxygen flow in certain areas [132,133].

The presence of O₂ in CO₂-dominated environments can significantly elevate the corrosion rate of steels. Zhang et al. [66] demonstrated that O₂ reacts with FeCO₃, promoting CO₂ hydration and increasing H⁺ concentrations, as shown in Reaction (16):

This reaction undermines the formation of compact and protective FeCO₃ scales on steel surfaces, increasing their susceptibility to corrosion. Lin et al. [134] studied 3Cr steel in O₂-CO₂ environments under HT/HP, observing the formation of porous iron hydroxides rather than protective Cr(OH)₃ scales. Similarly, Zhang et al. [135] reported that O₂ exacerbates N80 steel corrosion, varying its effects on temperature and O₂ concentration.

Oxygen contamination in downhole environments can result from processes such as the reinjection of produced water, CO₂, and inhibitors [136,137]. Air-assisted steam injection for secondary oil recovery, for instance, introduces O₂ concentrations of 5 to 20 % under HT/HP conditions [137]. Additionally, trace amounts of O₂ are introduced during thermal exploitation methods [138,139]. Even at low concentrations, O₂ strongly enhances corrosion at elevated temperatures due to its depolarizing nature [140].

In O₂-containing environments, the cathodic reaction shifts to O₂ reduction, as shown in Reaction (18). The ferrous ions produced in the anodic reaction (Reaction (17)) combine with hydroxide ions to form iron hydroxide (Reaction (19)), which further oxidizes and dehydrates at higher temperatures to form iron oxides (Reactions (20) and (21)) [66]:

Xiang et al. [93] studied X70 steel in CO₂/SO₂/O₂/H₂O environments and found that the corrosion rate rises with temperature, peaks, and then declines. This behavior is attributed to reduced O₂ solubility at high temperatures and the protective nature of the corrosion product layer. The presence of SO₂ in CO₂ corrosive environments can influence the corrosion mechanism. SO₂ ionizes when dissolved in water to form hydrogen sulfite (HSO₃^-) and sulfite (SO₃^-) ions, Reactions (22) and (23). The sulfite ions then react with Fe²⁺ to precipitate FeSO₃, Reaction (24), which competes with FeCO₃ formation, affecting the protectiveness of the corrosion scale.

The presence of O₂ further modifies the corrosion process by oxidizing sulfite ions to sulfate ions, leading to the formation of FeSO₄ instead, as per Reaction (25). However, Hua et al. [141] study did not report the formation of FeSO₄, when carbon steel was exposed to static water-saturated CO₂ in the presence of 20 ppm O₂ and (2, 50 and 100) ppm SO₂ at 35 °C and 8 MPa for 48 h exposure. In contrast, Xiang et al. [105]; Choi et al. [142] observed FeSO₄ on the steel surface under different test conditions. Xiang et al. [105] performed tests at 10 MPa and 50 °C, exposing the steel to water-saturated CO₂ with 0.02 - 0.2 MPa SO₂ and a significantly higher O₂ concentration of 1,000 ppm. Similarly, Choi et al. [142] conducted experiments with 0.08 MPa SO₂ and 0.33 MPa O₂ in water-saturated CO₂ conditions at 8 MPa and 50 °C. The formation of FeSO₄ in these studies indicates that both the SO₂ and O₂ concentrations influence its precipitation. A higher O₂ level enhances oxidation reactions, converting sulfite (SO₃²⁻) to sulfate (SO₄²⁻), which subsequently reacts with Fe²⁺ to form FeSO₄, as shown in Reactions (25) and (26). The lack of FeSO₄ detection in Hua et al. [141]’s study was explained by the lower O₂ concentration (20 ppm), which might not have been sufficient to drive the oxidation of sulfite to sulfate, preventing FeSO₄ formation under their experimental conditions.

Carbon steels are particularly vulnerable to O₂-induced corrosion at high temperatures. Zhang et al. [137] observed that in an O₂-Cl⁻-H₂O environment under HT/HP conditions, the corrosion rate of P110 steel reached 73 mm/y at 20 MPa air pressure. High Cl⁻ concentrations can mitigate O₂ corrosion by reducing dissolved O₂ levels in high-salinity fluids.

Water containing both dissolved O₂ and CO₂ is more corrosive than water with only 1 corrosive component. For instance, type 304 stainless steel showed significantly higher corrosion currents in CO₂-O₂ environments compared to CO₂ alone [143]. However, the combined effects of CO₂ and varying dissolved O₂ concentrations on erosion-corrosion under HT/HP conditions require further investigation. Table 4 summarizes the performance of various alloys under CO₂- O₂ across different conditions.

Table 4 Performance Summary of various alloys under CO₂ – O₂ conditions.

Types of corrosion

The integrity and longevity of equipment and tools in the oil and gas industry depend heavily on understanding the various types of corrosion prevalent in downhole environments. Common types that frequently affect downhole structures include pitting corrosion, crevice corrosion, under-deposit corrosion (UDC), SCC, and erosion-corrosion. Extensive efforts, both in laboratory and industrial settings, have been devoted to comprehending these forms of corrosion. Research related to these corrosion types is summarized in Table 5. Notably, all these forms of corrosion are localized, indicating a high risk for metal structures in downhole environments.

Table 5 Summary of corrosion types in downhole environments.

This section addresses these significant forms of corrosion encountered in downhole operations. Each type presents unique challenges that impact reliability and operational safety. Numerous studies have focused on understanding the general mechanisms of each type of corrosion in the oil and gas industry [190-196]. It aims to examine the impact of various downhole operational factors on different types of corrosion, including corrosive gases, temperature, stress, and flow conditions. It also reports the corrosion behavior of various oilfield construction materials.

Pitting corrosion

Among all types of corrosion attacks, pitting corrosion is one of the main causes of failures in oilfield production, posing a significant threat due to the harsh environments encountered during extraction [146]. Pitting corrosion compromises the integrity of downhole equipment, such as tubular and casing, which are essential for efficient and safe operations. Pits formed can act as stress concentrators, potentially leading to catastrophic failures and costly downtime [197]. Understanding the factors that predict pitting corrosion is crucial for developing sound mitigation strategies.

The characteristics of pits vary depending on the dissolved gas present, whether it is CO₂, H₂S, O₂, or a mixture of these gases. The shape of the corrosion pit sides and bottoms often provides crucial clues in diagnosing corrosion failures. Martin et al. [198] discussed the pits’ characteristics under dissolved gas corrosion. In a dissolved CO₂ environment with H₂S content below 10 ppm, 3 to 6 mm straight-sided pits form at gas breakout areas of iron carbonate products, as illustrated in Figure 7(a) [199]. When the H₂S concentration increases, the corrosion morphology changes due to the formation of FeS on the surface. In such cases, pits ranging from 3 to 10 mm in diameter are characterized by sloping edges with a nested pit at the bottom. A mixture of straight-sided and sloping-sided pits occurs in environments containing CO₂ and 10 to 20 ppm H₂S. Figure 7(b) shows the straight-sided and sloping-sided pits for a corroded X65 sample [200]. The presence of O₂ along with H₂S and CO₂, as is common in oil and gas production, intensifies the corrosion of steel. Pits formed in such an environment, with 20 ppm or greater H₂S, tend to have broad, smooth sides and bottoms that are usually found in crevices [198,201]. When small amounts of O₂ enter a sweet environment, the morphology of pits changes minimally, but with faster growth.

Figure 7 Morphology of corrosion pits under different corrosive gases: (a) corrosion of L415N in a CO₂ environment for 30 days at 25 °C and 5.8 MPa [199]; (b) Corrosion of X65 in an H₂S environment at 20 ppm H₂S, 0.097 MPa CO₂, 20 ppb_(w) [O₂], 7 days exposure time at 30 °C [200]. Reprinted with permission from [199,200].

Pitting morphology influences the severity and progression of material degradation. Deep pitting compromises the mechanical integrity by reducing the thickness and creating stress concentration points. As pitting depth and/or its frequency increases, the fracture pressure of casing materials decreases markedly [202]. Pitting depth was also linked to a reduction in ultimate tensile strength [203,204]. The localized stress at the pit base could exceed the material’s yield strength leading to crack formation. In H₂S environments, pits can be initiation sites for stress corrosion cracking [205]. Additionally, pitting alters the internal surface topology of casings and pipelines, leading to increased turbulence and flow resistance. These irregularities act as favorable factors for erosion-corrosion processes, where turbulence flow around pits leads to localized removal of protective films, accelerating material loss and deepening the pits [206].

The influence of various parameters on localized/pitting corrosion has been investigated by Zhang et al. [200]. Figures 8(a) - 8(e) highlights the complex interactions between environmental factors and corrosion behavior. The experimental findings indicate that pitting initiates only in the presence of H₂S and propagates when CO₂ is also present, highlighting the synergistic role of these gases in localized attacks. Specifically, pitting was observed within narrow ranges of H₂S (0.02 - 0.09 mbar) and CO₂ (0.53 - 0.97 bar) partial pressures, at pH levels 4 and 5, and at 30 °C but not higher temperatures. The presence of NaCl was not necessary for pit initiation, but increased chloride concentrations correlated with higher pitting density, suggesting a galvanic coupling effect. Pit formation is closely linked to the integrity of the thin FeS layer, where localized breakdown exposes steel surfaces to the aggressive buffering effect of H₂CO₃, driving further propagation. The pitting penetration rate represents the depth at which corrosion progresses into the metal over time and is typically derived from the deepest pit observed on the surface after a given exposure. The penetration ratio provides a comparative measure of localized versus general corrosion by relating the maximum pit depth to the average general corrosion. It is calculated as the ratio of the deepest pit depth to the uniform corrosion rate obtained from weight loss measurements. The findings clearly illustrate the relationship between these parameters and localized corrosion behavior, emphasizing the importance of controlling operational conditions to mitigate pitting risks.

Figure 8 Influence of various environmental conditions on the pitting corrosion occurrence of X65 carbon steel for 168 h exposure [200]. (a) experimental conditions: 30 °C, pH 5, 0.04 mbar pH₂S, 1 wt.% NaCl, 300 rpm, 20 ppb_w[O₂], (b) experimental conditions: 30 °C, pH 5, 0.97 bar pCO₂, 1 wt.% NaCl, 300 rpm, 20 ppb_w[O₂], (c) experimental conditions: PH 5, 0.97/0.82/0.53 bar pCO₂, 0.04 mbar pH₂S, 1 wt.% NaCl, 300 rpm, 20 ppb_w[O₂], (d) experimental conditions: 30 °C, 0.97 bar pCO₂, 0.04 mbar pH₂S, 1 wt.% NaCl, 300 rpm, 20 ppb_w[O2], (e) experimental conditions: 30 °C, pH 5, 0.97 bar pCO₂, 0.04 mbar pH₂S, 300 rpm, 20 ppb_w[O₂].