Influence of H₂S and CO₂ Partial Pressures and Temperature on the Corrosion of Superduplex S32750 Stainless Steel

Abstract

This study analyzes the effects of varying H₂S and CO₂ concentrations and temperature on the pH of geothermal fluids flowing through superduplex S32750 stainless-steel pipelines, classified as corrosion-resistant alloys (CRAs). Corrosive decay is evaluated by comparing OLI Studio software simulations with experimental data from the literature. The results indicate that an increase in the partial pressure of either gas lowers pH levels, with temperature exerting a more pronounced exponential effect on corrosion than gas partial pressure. When both gases are present, the dominant gas dictates the corrosion behavior. In cases where CO₂ and H₂S are in equal proportions, FeS₂ forms as the primary corrosive product due to the higher potential corrosivity of H₂S. The H₂S/CO₂ ratio influences the formation of passive films containing chromium oxides or hydroxides (Cr₂O₃, Cr(OH)₃), iron oxides (Fe₂O₃, Fe₃O₄), or iron sulfides (FeS).

1. Introduction

Offshore oil and gas production platforms are typically dismantled and brought ashore for recycling at the end of their operational lifespan. However, a more sustainable alternative involves repurposing these structures for geothermal energy extraction. One advantage of platforms in the North Sea is the low working temperature of piping immersed in cold seawater, which remains lower than that of land-based air-cooling towers used to condense working fluids from geothermal wells after they have passed through a turbine [1].

Due to their offshore locations, these structures are exposed to various environmental factors that contribute to surface corrosion and potential structural degradation. Early offshore platforms were fixed to the seabed, but floating platforms have become increasingly common. Stress corrosion cracking (SCC) arises from the combination of mechanical stress and a corrosive environment, influenced by factors such as temperature, H₂S, CO₂, pH, chloride concentration, and water-wetting effects. SCC is a common failure mode in pipelines made from corrosion-resistant alloys (CRAs) [2,3,4,5,6,7,8].

To ensure the durability of deep-water pipelines, high-strength materials such as duplex (S32205/S31803) and superduplex (S32750) stainless steels, carbon steels, and nickel–iron–chromium alloys (N08825 or N08800) are commonly used [9,10]. Internal corrosion mechanisms are significantly influenced by the working fluid, particularly the combined effects of CO₂ and H₂S, which are more detrimental than the presence of either gas alone. Additionally, dissolved oxygen in seawater plays a crucial role in passivation and the formation of a protective oxide layer [11]. However, when this passive layer is altered or destroyed by factors such as salinity, the presence of microorganisms, and the electrochemical conditions of seawater, both internal and external corrosion of the pipes can accelerate, compromising the integrity of the metallic material over time.

Numerous studies have developed theoretical correlations to predict corrosivity based on CO₂ and H₂S interactions [12,13]. The ISO 15156-3:2020 standard [14] defines four exposure regions, depending on the partial pressure of H₂S and in-situ pH [10]. The effect of temperature on corrosion rates is complex; while corrosion rates generally increase with temperature, they can decrease at higher temperatures due to lower gas solubility. Additionally, the wetting effect, particularly the dew point temperature at which condensation occurs, plays a key role in the electrochemical reactions that lead to corrosion [9].

pH significantly influences the corrosion behavior of steel materials, with lower pH values generally accelerating corrosion. Acidic environments hinder the formation of a protective oxide film, leading to localized corrosion, including pitting, SCC, and crevice corrosion. The interactions between H₂S and CO₂ present conflicting corrosion scenarios. While H₂S has been found to accelerate corrosion by forming a less protective FeS layer, other studies suggest it can contribute to passivation through the formation of FeS and FeCO₃ layers [15]. Additionally, research has identified both generalized and pitting corrosion in environments containing both gases [16].

Several investigations indicate that corrosion product layers in aggressive environments may consist of iron carbonate (FeCO₃), iron sulfide (Fe_xS_y), iron carbide (Fe₃C), and possibly iron oxides (Fe_xO_y) [13,15]. The formation of FeS polymorphs, including mackinawite (FeS), pyrite (FeS₂), pyrrhotite (Fe_(1−x)S), and greigite (Fe₃S₄), depends on environmental conditions such as temperature and H₂S pressure [15,16,17,18,19].

Iron carbide (Fe₃C) is a steel microstructural component that remains as a residue after ferrite dissolution, while corrosion products such as FeCO₃, Fe_xS_y, and Fe_xO_y can precipitate [20].

This study aims to investigate the effects of CO₂ and H₂S partial pressures, temperature, and pH on corrosion mechanisms in oil and gas environments within CRA pipelines. Particular emphasis is placed on S32750 superduplex stainless steel due to the complexity and ambiguity of its corrosion behavior in such systems. Carbon steel, being the least corrosion-resistant, is rarely used in marine structures, whereas nickel–iron–chromium alloys exhibit reduced passive film stability in the presence of dissolved CO₂ due to carbonic acid-induced dehydration [20].

The study compares experimental findings from the literature with simulations conducted using OLI Studio software, providing valuable insights into corrosion processes in energy applications.

2. Materials and Methods

OLI Platform V11.5 Studio simulation software (Parsippany, NJ, USA) incorporates Stream Analyzer, (Parsippany, NJ, USA) a core component used for simulating aqueous systems. In this interface, one or more streams, called “Add Stream”, are created for all calculations. These streams have a defined chemical composition, temperature, and pressure. The software allows for various types of calculations, including: single-point calculations (determining pH, volume, speciation, and other properties at a specific equilibrium state); topographical calculations (evaluating changes in stream parameters as a function of temperature, pressure, or composition); water analysis; mixing simulations; and chemical diagrams (generating stability maps for species as a function of concentration and other parameters, such as pH).

The software provides three thermodynamic models:

1. Aqueous Model (AQ): Used when more than 70% of the system is in the aqueous phase (dilute solution). This model employs an electrolyte activity coefficient approach to predict solution properties up to an ionic molal strength of 30 [21]. However, it has limited available data and a pressure restriction between 1000 and 1500 bar. This pressure limitation was later corrected in the next model, as some systems exceeded 4000 bar (AQSim. OLI electrolyte solutions, s. f.).

2. Mixed-Solvent Electrolyte Model (MSE): Considers both long- and short-range interactions, including ionic interactions. It is applicable when water or other solvents, such as ethanol, are present. Despite offering significant advantages over the AQ model, it has certain limitations, such as the inability to accurately reproduce the critical behavior of non-electrolytic mixtures.

3. MSE-SRK Model: A variation of the MSE model designed for electrolyte systems, incorporating the Soave–Redlich–Kwong (SRK) equation of state. The MSE-SRK model is specifically designed for applications in the oil and gas industry and related chemical processes that involve light hydrocarbons and CO₂, requiring high-pressure conditions (P > 80 atm). This model addresses the limitations that previously restricted the use of the MSE model for these applications.

Based on the Mixed-Solvent Electrolyte (MSE) framework, it provides an accurate representation of electrolyte systems in both aqueous and mixed-solvent environments (MSE-SRK, s. f.).

The software database includes various thermodynamic models, such as the MSE and MSE-SRK models (selected by default), as well as models for corrosion, geochemistry, urea, and surface-complex double-layer systems. The way the software handles systems capable of forming two liquid phases is particularly relevant for mixtures containing light organic and inorganic components, such as CO₂ and H₂S.

The MSE-SRK model has been primarily designed for:

• Upstream oil and gas systems
• Electrolytes in water
• Mixtures involving water, salts, and hydrocarbons
• Hydrocarbons mixed with water, salts, acid gases, and other light components (e.g., light hydrocarbons, CO₂, H₂S, and N₂)

This model is especially advantageous when dealing with wide pressure ranges, making it the most suitable choice for this study.

In this study, the molarity of CO₂ and H₂S was varied, as did their respective partial pressures. The simulation results obtained with the MSE-SRK model were then compared with experimental data retrieved from the Web of Science database.

3. Effect of CO₂, H₂S, and Temperature

3.1. Influence of CO₂

In this section, the effects of varying the partial pressure of CO₂ were evaluated within the range of 0–12 MPa, corresponding to the addition of 0–3.5 moles of CO₂ in the OLI Studio simulation software package. This pressure range is typically encountered in corrosive geothermal environments where corrosion-resistant alloys (CRAs), such as superduplex S32750 stainless steel, are used [22].

Although dry CO₂ is not inherently corrosive, it undergoes a series of chemical reactions when dissolved in water, making the resulting solution highly corrosive to steel. In an aqueous system, CO₂ hydrates to form carbonic acid (H₂CO₃), which subsequently dissociates into bicarbonate ions (HCO₃⁻) and carbonate ions (CO₃²⁻). The equilibrium of CO₂ in solution can therefore be described by the following expression:

$$\left[{\mathrm{C}\mathrm{O}}_{2 \left(\mathrm{a}\mathrm{q}\right)}\right]=\left[{\mathrm{H}}_2{\mathrm{C}\mathrm{O}}_{3 \left(\mathrm{a}\mathrm{q}\right)}\right]+\left[{\mathrm{H}\mathrm{C}\mathrm{O}}_{3 \left(\mathrm{a}\mathrm{q}\right)}^{-}\right]+\left[{\mathrm{C}\mathrm{O}}_{3 \left(\mathrm{a}\mathrm{q}\right)}^{2-}\right]$$

(1)

In Figure 1, the green curve illustrates that the ionization constant values for the dissociation of carbonic acid and bicarbonate ions are significantly greater than 1. The dissociation occurs at pH₁ = 6.4 and pH₂ = 10.2, corresponding to the equivalence points where acid and base concentrations reach balance. CO₂ is therefore classified as a weak acid, leading to what is commonly known as “sweet” corrosion, as opposed to “sour” corrosion [23].

In a CO_2–H₂O system, when the pH drops below 4, the corrosion rate increases progressively as acidity rises. However, within a pH range of 4 to 10, corrosion remains largely unaffected by pH variations due to the formation of a protective layer of iron carbonate (FeCO₃), also known as siderite. This passive layer acts as a barrier, preventing further corrosion [23].

Generally, the corrosion rate shows no significant variation at temperatures above 70 °C. Beyond that value, corrosion decreases due to the film created by the decrease in solubility [24].

A literature review was conducted to gather data on the effects of CO₂ partial pressure and temperature on pH, allowing for a comparison with the software simulation results. Haghi et al. [25] and Peng et al. [26] investigated the behavior of a CO_2–H₂O system over a temperature range of 35–280 °C for a stainless steel. Both studies found that as the temperature increased, the pH values also increased, leading to greater alkalinity. However, despite this pH rise, the medium could still become more aggressive, as higher temperatures accelerate reaction kinetics.

Figure 2 compares the experimental data reported in the literature [24,25,26] with the pH variations generated by the OLI Studio simulation software. The solid line represents experimental values, while symbols indicate the OLI simulation results. At lower temperatures, both datasets show good agreement. However, as temperature increases, the deviation between the experimental and simulated data becomes more pronounced, particularly at high temperatures and low partial pressures. Above 150 °C, there was no convergence with the simulation software. This may be due to the limitations of existing models for high temperatures and to the fact that low-temperature simulations are much simpler than high-temperature ones.

Despite the increase in pH with temperature, the system tends to become more aggressive due to enhanced reaction kinetics. For instance, when the temperature rises from 160 °C to 280 °C at a constant pressure of 10 MPa, the pH increases from 3.5 to 4.2. This behavior is directly linked to chemical kinetics, as reaction rate constants exhibit an exponential dependence on temperature, as described by the Arrhenius Equation [27].

In contrast, an increase in CO₂ partial pressure leads to a decrease in pH. Figure 2 shows that at a temperature of 200 °C and a CO₂ partial pressure of 4 MPa, the pH is 3.9. However, when the pressure increases to 14 MPa, the pH decreases to 3.6. In other words, a 10 MPa increase in CO₂ partial pressure results in a pH drop of 0.3.

As the CO₂ partial pressure increases, the formation of carbonic acid is favored, leading to a higher concentration of hydrogen ions and a subsequent decrease in pH. In general, the solubility of CO₂ in water decreases with increasing temperature [28]. At higher temperatures, CO₂ is released from the solution, which may reduce the concentration of carbonic acid and, consequently, affect pH.

Additionally, carbonic acid and hydrogen ions can accelerate the corrosion of metals and superduplex stainless-steel alloys, as hydrogen ions actively participate in corrosive reactions [29]. Furukawa et al. [30] investigated the corrosion resistance of supercritical CO₂ pressurized at 20 MPa in the temperature range of 400–600 °C. The authors reported no significant effect of CO₂ pressure on the corrosion behavior of high-chromium and austenitic steels [31].

As highlighted by Costa et al. [32] superduplex stainless steels exhibit excellent corrosion resistance and mechanical strength due to the presence of a Cr₂O₃ protective layer. This layer is solid, self-repairing, and consistent, but it is affected by temperature and gas exposure, which can lead to larger cracks or surface defects.

The presence of CO₂ increases defects in the passive steel layer, making it more heterogeneous. Moreover, this detrimental effect intensifies at higher temperatures, meaning that the combined influence of CO₂ and elevated temperatures further compromises the protective properties of the passive film. Electrochemical impedance spectroscopy, adjusted by constant phase element circuits, has confirmed this reduction in film integrity. It was therefore concluded that, in superduplex S32750 stainless steel, the effect of varying CO₂ partial pressure was not as significant as the exponential effect of temperature [28].

The results were validated by comparing both the pH values and the predicted corrosion products with published experimental data. Comparing the simulated pH values with those measured by Haghi et al. [25] and Peng et al. [26] for CO_2–H₂O systems shows good agreement up to 125 °C. At higher temperatures, discrepancies can be attributed to the limited accuracy of thermodynamic models under subcritical conditions.

Regarding corrosion products, the prediction of FeCO₃ and FeS as stable solid phases under specific conditions was consistent with studies by Liu et al. [33], who identified thin FeS layers on duplex steels exposed to H₂S. The partial inhibitory effect of FeCO₃ in CO₂-rich environments, as described by De Waard and Lotz [34], was also reproduced.

The agreement between simulation and experimental results supports the validity of the findings and provides insights into the relationship between pH and the partial pressures of H₂S and CO₂, as well as the potential formation of corrosion products in H₂S/CO₂ environments, such as those found in geothermal and oil and gas settings.

3.2. Influence of H₂S

In an aqueous solution, H₂S undergoes partial dissociation into bisulfide (HS⁻) and sulfide (S²⁻) ions, without requiring a prior hydration phase [26]. The equilibrium of H₂S in solution can be expressed by the following equation:

$$\left[{{\mathrm{H}}_2\mathrm{S}}_{\left(\mathrm{g}\mathrm{a}\mathrm{s}\right)}\right]=\left[{{\mathrm{H}}_2\mathrm{S} }_{\left(\mathrm{a}\mathrm{q}\right)}\right]+\left[{\mathrm{H}\mathrm{S}}_{\left(\mathrm{a}\mathrm{q}\right)}^{-}\right]+\left[{\mathrm{S}}_{\left(\mathrm{a}\mathrm{q}\right)}^{2-}\right]$$

(2)

As explained for CO₂, the concentration of sulfur species in an aqueous medium circulating through a superduplex stainless-steel pipeline must be analyzed as a function of pH to determine the ionization constant values (Figure 1, blue curve).

In Figure 1 (blue), the ionization constant values are significantly greater than 1 during the dissociation process, when acid and base concentrations reach their equivalence point. This indicates that, like CO₂, H₂S is also a weak acid. In an H₂S–H₂O system, as the concentration of H₂S increases, the protective iron sulfide (FeS) layer becomes less stable within a pH range of 3–5 and ceases to contribute to corrosion inhibition [35]. Additionally, other researchers [36] have affirmed that corrosivity could be more effectively prevented at temperatures below 90 °C.

The available results were those obtained using the OLI Studio simulation software (Figure 3). This figure shows that an increase in temperature leads to a rise in pH, whereas an increase in H₂S partial pressure results in a decrease in pH. This behavior is similar to that observed for CO₂, as described in the previous section.

H₂S is a weak acid and reacts with water to form hydrogen ions (H⁺) and sulfide ions (S²⁻), acidifying the medium and lowering the pH. The solubility of H₂S in water can vary with temperature. At higher temperatures, chemical reactions tend to accelerate [35]. More H₂S is released in gaseous form, which affects the concentration of H₂S in the environment and, consequently, its potential to corrode superduplex stainless steel. Moreover, the formation of corrosion products, such as sulfides, becomes more significant in the presence of H₂S, further contributing to corrosion of the superduplex steel [29,35,36].

A simulation was conducted at three different temperatures to study the evolution of pH with variations in both CO₂ and H₂S partial pressures. In Figure 4, the fundamental difference in the relationship between pH readings at high temperatures (125 °C and 250 °C) and at low temperatures (25 °C) is evident. At higher temperatures, the pH for CO₂ showed higher values (indicating more alkaline and less acidic conditions) compared to H₂S. However, at lower temperatures, any differences were nearly negligible.

It can therefore be concluded that an increase in temperature in a geothermal fluid system circulating through a superduplex steel pipe with a specific partial pressure of H₂S will lead to an increase in pH, though not as significantly as with CO₂. On the other hand, an increase in the partial pressure of either H₂S or CO₂ will result in a decrease in pH, as the pKa value for H₂S is higher.

Several studies [35,36,37] have evaluated the behavior of superduplex stainless-steel S32750 in environments with H₂S presence, detecting FeS₂ compounds, among others. These studies found that the corrosion resistance of the material decreases, and the ferritic phase of the material undergoes selective dissolution. Additionally, other studies [35] have shown that, at 60 °C, porosity develops in the protective film due to sulfide absorption, leading to corrosion of the film.

3.3. Influence of CO₂ and H₂S

The behavior of CO_2–H₂S–H₂O systems typically found in geothermal fluids was analyzed in the context of their interaction with superduplex stainless-steel tubing used in geothermal applications. It should be noted that the key difference between CO₂ and H₂S, as noted in previous sections, is that aqueous CO₂ undergoes a prior hydration process to form H₂CO₃, allowing for subsequent dissociation. As such, CO₂ has a stronger dissociation process compared to H₂S.

Thus, it is important to understand the relationship between both gases before dissociation. The first step is to obtain the concentration of H₂CO₃ and H₂S (Equations (5) and (7)). Starting with the equilibrium expressions for each of them:

$${\mathrm{K}}_{{\mathrm{s}\mathrm{o}\mathrm{l} \mathrm{C}\mathrm{O}}_2}={\displaystyle \frac{{\mathrm{C}}_{{\mathrm{C}\mathrm{O}}_2}}{{\mathrm{P}}_{{\mathrm{C}\mathrm{O}}_2}}}$$

(3)

where K_solCO2 is the equilibrium constant for the dissolution reaction of CO₂, C_CO2 represents the concentration of CO₂, and P_CO2 is the partial pressure of CO₂ in the system.

$${\mathrm{K}}_{\mathrm{h}\mathrm{y}\mathrm{d}}={\displaystyle \frac{{\mathrm{C}}_{{\mathrm{H}}_2{\mathrm{C}\mathrm{O}}_3}}{{\mathrm{C}}_{{\mathrm{C}\mathrm{O}}_2}}}$$

(4)

In Equation (4), K_hyd is the equilibrium expression for the hydration process of CO₂, and $C_{H_2{CO}_3}$ represents the concentration of carbonic acid.

$${\mathrm{C}}_{{\mathrm{H}}_2{\mathrm{C}\mathrm{O}}_3}={\mathrm{K}}_{\mathrm{h}\mathrm{y}\mathrm{d}}·{\mathrm{K}}_{{\mathrm{s}\mathrm{o}\mathrm{l} \mathrm{C}\mathrm{O}}_2}·{\mathrm{P}}_{{\mathrm{C}\mathrm{O}}_2}$$

(5)

$${\mathrm{K}}_{{\mathrm{s}\mathrm{o}\mathrm{l} \mathrm{H}}_2\mathrm{S}}={\displaystyle \frac{{\mathrm{C}}_{{\mathrm{H}}_2\mathrm{S}}}{{\mathrm{P}}_{{\mathrm{H}}_2\mathrm{S}}}}$$

(6)

Equation (6) represents the equilibrium expression for the dissolution reaction of H₂S, where ${\mathrm{C}}_{{\mathrm{H}}_2\mathrm{S}}$ is the concentration of H₂S and ${\mathrm{P}}_{{\mathrm{H}}_2\mathrm{S}}$ is the partial pressure of H₂S.

$${\mathrm{C}}_{{\mathrm{H}}_2\mathrm{S}}={\mathrm{K}}_{{\mathrm{s}\mathrm{o}\mathrm{l} \mathrm{H}}_2\mathrm{S}}·{\mathrm{P}}_{{\mathrm{H}}_2\mathrm{S}}$$

(7)

The relevant ionization constants can be calculated using expressions (8)–(10).

$${\mathrm{K}}_{{\mathrm{s}\mathrm{o}\mathrm{l} \mathrm{C}\mathrm{O}}_2}={\displaystyle \frac{14.5}{1.00258}}\times {10}^{-(2.27+5.65\times {10}^{-3}·{\mathrm{T}}_{\mathrm{f}}-8.06\times {10}^{-6}·{\mathrm{T}}_{\mathrm{f}}^2+0.075\mathrm{I}}\left({\displaystyle \frac{\mathrm{m}\mathrm{o}\mathrm{l}}{\mathrm{b}\mathrm{a}\mathrm{r}}}\right)$$

(8)

$${\mathrm{K}}_{\mathrm{h}\mathrm{y}\mathrm{d}}=2.58\times {10}^{-3}$$

(9)

$${\mathrm{K}}_{{\mathrm{s}\mathrm{o}\mathrm{l} \mathrm{H}}_2\mathrm{S}}={10}^{-(634.27+0.2709·{\mathrm{T}}_{\mathrm{k}}-0.00011132·{\mathrm{T}}_{\mathrm{k}}^2-{\displaystyle \frac{\mathrm{16,719}}{·{\mathrm{T}}_{\mathrm{k}}}}-261.9{\log }_{10}{\mathrm{T}}_{\mathrm{k}}}$$

(10)

In $K_{{sol CO}_2}$ and $K_{{sol H}_{2}S}$ [37], temperature is the varying parameter. Using the above equations, we can determine the values of the constants and the relationship between H₂S and CO₂ at different temperatures (30 °C, 50 °C, 70 °C, and 90 °C). The results are presented in

Table 1. Equilibrium constant calculations for both aqueous H₂CO₃ and aqueous H₂S.

Temperature (°C)	30	50	70	90
${\mathrm{K}}_{{\mathrm{s}\mathrm{o}\mathrm{l} \mathrm{C}\mathrm{O}}_2}$ · ${\mathrm{K}}_{\mathrm{h}\mathrm{y}\mathrm{d}}$	6.7 × 10−5	4.9 × 10−6	3.8 × 10−7	3.1 × 10−8
${\mathrm{K}}_{{\mathrm{s}\mathrm{o}\mathrm{l} \mathrm{H}}_2\mathrm{S}}$	6.9 × 10−2	5.0 × 10−3	4.0 × 10−4	3.4 × 10−5
H2S/CO2 ratio	1.04 × 10−3	1.01 × 10−3	1.04 × 10−3	1.08 × 10−3

.

It can be seen in Table 1 that the H₂S/CO₂ ratio remains on the order of 10³ across different temperatures, given the same partial pressure of H₂S and CO₂. Consequently, the following expression holds:

$$\mathrm{R}\mathrm{a}\mathrm{t}\mathrm{i}\mathrm{o}={\displaystyle \frac{{\mathrm{C}}_{{\mathrm{H}}_2\mathrm{S}}}{{\mathrm{C}}_{{\mathrm{H}}_2{\mathrm{C}\mathrm{O}}_3}}}={\displaystyle \frac{{\mathrm{K}}_{{\mathrm{s}\mathrm{o}\mathrm{l} \mathrm{H}}_2\mathrm{S}}·{\mathrm{P}}_{{\mathrm{H}}_2\mathrm{S}}}{{\mathrm{K}}_{\mathrm{h}\mathrm{y}\mathrm{d}}·{\mathrm{K}}_{{\mathrm{s}\mathrm{o}\mathrm{l} \mathrm{C}\mathrm{O}}_2}·{\mathrm{P}}_{{\mathrm{C}\mathrm{O}}_2}}}=1000·{\displaystyle \frac{{\mathrm{P}}_{{\mathrm{H}}_2\mathrm{S}}}{{\mathrm{P}}_{{\mathrm{C}\mathrm{O}}_2}}}$$

(11)

In a geothermal fluid flowing through a superduplex S32750 steel pipe, with the same partial pressure or concentration of CO₂ and H₂S, the partial pressure of CO₂ will be 1 bar, while that of H₂S will reach 1000 bar [38,39]. This indicates a higher corrosive potential of H₂S in superduplex stainless steel compared to CO₂.

H₂S dissociates into H⁺ (protons) and HS⁻, with the latter being responsible for material corrosion. In his research, Zhang et al. [37] observed that small amounts of H₂S accelerated the corrosion rate by a factor of 4 to 6 compared to a system containing only CO₂. Furthermore, FeS was identified as the dominant corrosion product. It was also found that in an H₂S–CO₂ system with low H₂S concentrations, the first layer to form consisted of FeS, which affected the subsequent formation of the FeCO₃ layer. Unlike FeS, the FeCO₃ layer was unable to dissolve into the superduplex steel pipe wall. In the case of CO₂, the main corrosive species was HCO₃⁻.

Several researchers have proposed corrosion models (corrosion regimes) for systems containing H₂S and CO₂, highlighting the predominant corrosion mechanisms [9,34]. Askari et al. [9] developed a model that has been refined in this study and is presented in Figure 5, improving upon the models previously proposed by De Waard et al. [34]. When both gases are present in ratios between 20 and 500, a passive layer of FeS₂ and FeCO₃ may form on the steel pipe walls, acting as competing layers (Figure 5). The FeS₂ layer may only be formed locally, where galvanic and pitting corrosion may also occur. According to the model, when the partial pressure of H₂S predominates over that of CO₂, acidic conditions prevail, and the primary corrosion product formed on superduplex steel is mainly determined by the H₂S content. Conversely, if the partial pressure of CO₂ is higher, “sweet corrosion” (CO₂ corrosion) will occur.

As mentioned by Wang et al. [39] when comparing a system with the same duplex stainless steel in a CO₂ environment to one with H₂S, the steel is more susceptible to pitting corrosion in the presence of H₂S. A change has been detected in the composition of the passive film, which consists of chromium oxides or hydroxides (Cr₂O₃, Cr(OH)₃), iron oxides (Fe₂O₃ and Fe₃O₄), or iron sulfides (FeS).

On the other hand, Zhang et al. [37] found that when carbon steel is exposed to 40 ppm H₂S, the most severe pitting occurs, with the formation of a very thin (100–200 nm) porous Fe_xS_y and Fe_xO_y layer on the steel surface. This layer is significantly thinner than the FeCO₃ layer typically observed in mild corrosion (micron level) but much thicker than the stainless-steel passive layer (up to 5 nm).

3.4. Prediction of Corrosion Products and Rates Using OLI Study

To complement the pH prediction, additional simulations were conducted in the OLI study using the chemical equilibrium module with solid-phase output, with the goal of identifying potentially stable corrosion products in CO_2–H₂O and H₂S–H₂O systems under representative geothermal operating conditions (25–250 °C, 0–20 MPa).

In the presence of CO₂, the simulations predicted the precipitation of ferrous carbonate (FeCO₃), known for forming passivating layers on carbon steels and stainless steels. At temperatures above 120 °C and pH > 4, FeCO₃ appeared as the predominant solid phase, which is consistent with the findings of Dugstad et al. [40] regarding the stabilization of this compound in “sweet” environments.

In contrast, in atmospheres containing H₂S, the formation of sulfide phases such as FeS and FeS₂ (pyrite) was observed, with the latter predominating at pH values between 3 and 5 and temperatures above 150 °C. These compounds are in agreement with corrosion products experimentally identified in duplex steels exposed to H₂S, according to Zhang et al. [37] and Liu et al. [33].

Additionally, species concentration data, redox potential, and temperature were used to estimate theoretical corrosion rates using the rate prediction module in OLI. The predicted rates ranged from 0.1 to 1.2 mm/year, depending on the temperature, dominant gas, and stability of the passive layer. These values align with the results reported by Zhu et al. [38], who observed corrosion rate increases of up to sixfold in the presence of small amounts of H₂S.

4. Conclusions

This study analyzed the impact of the simultaneous presence of CO₂ and H₂S on the corrosion of superduplex stainless steels under conditions representative of hydrocarbon production environments. The results confirm that the corrosivity of H₂S is significantly higher than that of CO₂ due to its ability to dissociate into H⁺ and HS⁻, generating highly reactive sulfur compounds with steel.

Experiments and analyses revealed that in the presence of H₂S, FeS formation as a corrosion product dominates over FeCO₃ formation. It was observed that small concentrations of H₂S can increase the corrosion rate by a factor of 4 to 6 compared to an environment exclusively based on CO₂. Additionally, it is important to consider the chemical composition of the passive layer and the sequence of deposition of corrosion products, as these are more relevant parameters when analyzing the protective properties and stability of passive films. This is consistent with previous findings indicating that even small changes in alloying elements (such as Mo, Cr, or N) can significantly affect localized corrosion resistance.

The evaluated corrosion models indicate that the competition between the formation of FeS₂ and FeCO₃ layers plays a fundamental role in the evolution of the corrosion process. Under conditions where H₂S predominates, FeS₂ formation promotes localized degradation, whereas in environments where CO₂ is dominant, sweet corrosion occurs, with the formation of FeCO₃ protective layers that are less effective in superduplex steels.

These findings highlight the need to carefully consider the chemical composition of the environment and the relative proportion of gases when designing corrosion mitigation strategies for industrial applications. Additionally, future research should focus on developing more accurate predictive models and evaluating new alloys with greater corrosion resistance in mixed H₂S and CO₂ environments.