CO₂ / H₂S Corrosion

General Information

CO₂ corrosion in oil and gas production and transmission systems has been extensively studied over the last decades. The effects of various key parameters, such as temperature, pH, CO2 partial pressure and the presence of H₂S etc., have also been examined and, in many cases, these findings are used to assess and predict system corrosivity. The following chapter provides a general overview of CO₂/H₂S corrosion, the impact of these parameters and corrosion modelling approach.

Mechanism

Anhydrous CO₂ (dry gas) is considered non-corrosive. However, in the presence of water, it dissolves and forms weak carbonic acid, which leads to a reduction in pH and subsequent corrosion of carbon steel. The fundamental mechanism of CO₂ corrosion is relatively well understood and has been described by many researchers, including the seminal work of De Waard and Milliams, Crolet, Dugstad and others. ^{1 2 3 4}

Simplified anodic and cathodic reactions describing principles of CO₂ corrosion is presented below:

\(\ce{Fe -> Fe^2+ + 2e-}\) Reaction 1

\(\ce{H2CO3 + e- -> HCO3- + 2H+}\) Reaction 2

\(\ce{H+ + H+ -> H2}\) Reaction 3

Which can be presented in summary reaction:

\(\ce{Fe + 2H2CO3 -> Fe^2+ + 2HCO3- + H2}\) Reaction 4

During the progression of CO₂ corrosion, the bicarbonate ion concentration in the solution increases, which in turn raises the pH level. Once this concentration exceeds the saturation equilibrium, iron carbonate precipitates, as illustrated schematically in Reaction 5.

\(\ce{Fe + 2HCO3- -> FeCO3 + H2O + CO2}\) Reaction 5

Depending on the impact of various process parameters such as temperature, flow rate, and the CO₂/H₂S ratio, the FeCO₃ layer will exhibit varying properties, including density and porosity. However, regardless of these variations, the presence of an FeCO₃ deposit on the metal surface consistently leads to a reduction in the corrosion rate, which may be more or less significant depending on the specific conditions.

Key Variables

It is widely agreed that CO₂ corrosion is influenced by a combination of several parameters, including temperature, pH, CO₂ concentration, the presence of H₂S, flow, and other ionic species, particularly chlorides. Additional factors that may also affect the final CO₂ corrosion rate include the presence of oxygen, elemental sulfur, and the oil wetting effect, among others.^{5 6}

CO₂ Partial Pressure and Temperature

CO₂ partial pressure and temperature are the two critical, influential factors governing CO₂ corrosion in oil and gas production and transmission systems. In general, higher CO₂ partial pressure increases carbonic acid formation, lowers pH, and accelerates the corrosion rate. Temperature, on the other hand, influences corrosion in multiple ways: corrosion increases with temperature due to faster corrosion process; at higher temperature, conditions increasingly favor the formation of protective iron carbonate (FeCO₃) films; affecting solubility and equilibrium constants, thereby impacting the pH. There is a general consensus that in an ideal, pure CO₂ system, the corrosion rate increases with temperature, reaching its peak within the range of 60–80°C (140–176°F). Beyond this point, the corrosion rate begins to decrease, and at temperatures above approximately 120°C (248°F), it becomes almost independent of CO₂ partial pressure.² The reduction in corrosion is primarily attributed to the formation of protective corrosion products, such as FeCO₃ (iron carbonate). These behaviors are commonly modeled using the well-known De-Waard-Milliams equation:

log (Vcor) = 5.8 - 1710/T + 0.67 log (pCO₂) (Equation 1)

pH

The pH is closely related to the previously discussed parameters, such as CO₂ partial pressure and temperature. Generally, an increase in pH is associated with a decrease in the corrosion rate. This is primarily due to the slowing of the cathodic reduction of H+ ions, which, according to Le Chatelier’s Principle, causes the anodic reaction to counteract, thereby slowing the dissolution of the metal. Additionally, as the pH increases, the solubility of FeCO₃ decreases, leading to the precipitation of iron carbonate. This precipitated layer acts as a protective barrier on the metal surface, further reducing the corrosion rate. This dual effect - slowing the cathodic reaction and promoting protective film formation -underscores the importance of pH in controlling corrosion processes in CO₂-containing environments.⁴ Therefore, accurate determination of pH is a critical component in all CO₂ corrosion models. It is widely agreed that utilizing ionic modeling, based on known ionic speciation, is the preferred method for estimating field pH. This approach offers several advantages over direct water sampling and pH measurement under high operating pressures, which can be complex, costly, and prone to errors due to the challenges of maintaining gas-liquid equilibrium during sampling and measurement. By using ionic modeling, it is possible to achieve more reliable and consistent pH estimates that better reflect the in-situ conditions of the system, thereby enhancing the accuracy of corrosion predictions.

H₂S

H₂S is also widely encountered in most oil and gas production systems. Even in small amounts, H₂S may significantly influence corrosion behavior. As the H₂S concentration (or partial pressure) increases in the process stream, the corrosion dynamics shift, largely depending on the CO₂/H₂S ratio. When H₂S concentrations are negligible (less than 68 Pa or 0.01 psia), CO₂-driven corrosion remains the primary mechanism, with a reduction in the corrosion rate observed above 60-80°C, as previously discussed. However, as the CO₂ partial pressure to H₂S partial pressure ratio (CO2pp/H₂Spp) exceeds 200, H₂S begins to react with iron to form iron sulfides (Fe_xS_y), which can decrease the overall corrosion rate. The scale formed under these conditions is typically a mixture of (Fe_xS_y) and FeCO₃, which acts as a protective barrier against further corrosion.⁷ At higher H₂S concentrations, where the CO₂pp/H₂Spp ratio falls below 200, the dominant scale compound between approximately 60°C and 240°C becomes Fe_xS_y. This iron sulfide scale is generally protective; however, once the temperature surpasses the 230-240°C range, the corrosion rate may increase again due to the scale becoming porous, which compromises its protective properties and allows H₂S corrosion to progress.⁷

Oxygen

Ingress of oxygen, typically resulting from inadequately de-aerated injection water or brine, can significantly accelerate corrosion in sweet environments, where carbon dioxide (CO₂) is the primary corrosive agent. Several studies have shown that the rate of CO₂-induced corrosion can increase by approximately 0.5 mm/year for every 1 ppm of oxygen contamination.⁸ However, it is crucial to recognize that under actual field conditions, this rate may vary due to the complex interaction of multiple factors, including flow velocity, temperature, pressure, and the specific chemistry of the water or brine being injected.

The presence of oxygen is believed to degrade the protective FeCO₃ (iron carbonate) layer that typically forms on metal surfaces, making it porous and more susceptible to penetration by corrosive species. Consequently, the corrosion process is exacerbated. In oxygenated conditions, the composition of surface deposits on the metal will include not only FeCO₃ but also iron oxide phases such as magnetite (Fe₃O₄), hematite (α-Fe₂O₃), and goethite (α-FeOOH).⁹

Flow, Oil Type and GOR

In oil and gas production and transmission systems, oil, water, and gas typically exist as a mixture. These phases flow together in complex patterns within pipelines, which can impact pipeline integrity. Therefore, characterizing multiphase flow is crucial for understanding how hydrodynamic factors affect corrosivity and integrity of a system. A multiphase flow modeling tool is available in the Tool section for further analysis.

There is a general agreement that in oil wells with a Gas/Oil Ratio (GOR) below 890 m³/m³ or 5000 scf/bbl, crude oil forms a stable hydrophobic layer on metal surfaces. This layer prevents water from contacting the metal, thereby reducing both sweet and sour corrosion rates. ^{7 10 11 12 13}

However, the relationship between “oil wetting” and corrosion is more complex, involving the interplay of factors such as oil type (including API gravity), water cut, water-in-oil emulsion stability, and the flow regime within the well. Oil’s protective tendency is typically most evident when the water cut (WC) is around 30-40% and linear flow velocities exceed approximately 1 m/s.^{2 7} The specified water-cut boundary is not fixed and may vary depending on the specific properties of the crude oil. For instance, heavier crude oils, particularly those rich in asphaltenes and resins (with an API gravity of approximately 20 or lower) and capable of forming stable emulsions, may offer sufficient protection even at water cuts exceeding 50%.^{11 14 15 16}

Inhibitors

The application of corrosion inhibitors is a widely used and effective method for controlling corrosion in oil and gas (O&G) production systems, both in sweet (CO₂) and sour (H₂S) environments. Over the last few decades, a significant number of compounds have been developed, tested, and successfully implemented as corrosion inhibitors in the O&G industry. The majority of these compounds are film-forming inhibitors, which create protective mono- or multi-layer films on the metal surface. These films act as a barrier, significantly retarding the ingress of water and other corrosive species, and thus reducing the rate of electrochemical reactions that lead to both sweet and sour corrosion.

Among the most popular and widely used corrosion inhibitors in the industry are fatty imidazoline derivatives, amide-imidazolines, or quaternary amine salts. These compounds are often used either individually or in mixtures to optimize their performance and provide comprehensive protection against corrosion. Fatty acids imidazoline derivatives are particularly valued for their strong film-forming properties and stability, while quaternary amine salts are known for their effectiveness in inhibiting corrosion in acidic environments. The combination of different inhibitors often results in synergistic effects, providing enhanced corrosion protection in complex and harsh conditions commonly encountered in O&G production systems. ^{17 18 19 20}

Due to the wide variety of commercial inhibitors available, each with different compositions and varying concentrations of active components, it is challenging to develop a generalized guideline that correlates dosage, inhibitor type, and the resulting corrosion rate reduction. However, it is possible to provide some general estimations for one of the most widely used groups of inhibitors—fatty acid imidazolines. These inhibitors have been extensively evaluated over the past several decades under a range of conditions, including varying levels of CO2 partial pressure, flow, and other environmental factors.

Typically, a continuous dosage of 3-10 ppm of fatty acid imidazolines (measured as the active component) is expected to reduce the rate of sweet corrosion by approximately 80% to over 90%.^{21 22 23 24} Of course, the final inhibition effectiveness will also be influenced by several other factors, including water cut, oil type (light vs. heavy), flow conditions (such as wall shear stress and flow type), and the partitioning behavior of the inhibitor between the water and oil phases.²⁵

O&G-Corrology

A semi-mechanistic corrosion prediction model has been developed for multiphase CO₂/H₂S environments in oil and gas production and transportation systems to support corrosion assessment. The model integrates water chemistry, multiphase flow, and corrosion modules to enable engineers to quickly assess corrosion risk and system aggressiveness.

The model foundation is based on the “resistance model” ²⁷ , as shown in Equation 2:

1/Vcor = 1/Vr + 1/Vm (Equation 2)

The base corrosion rate component Vr is adapted from the well-established de Waard equation (1993)² , with modifications to incorporate the effect of H₂S. An equivalent CO₂ partial pressure (CO₂eqv), adjusted based on system pH, is used in place of the actual CO₂ partial pressure in the Vr equation, as shown below:

log Vr = 5.8 – 1710/T + 0.67 log (CO₂eqv) (Equation 3)

The Vm term accounts for limiting factors due to various species.

The model also incorporates correction factors for additional influences, including FeCO₃ / FeS scale formation, saturation pH, H₂S concentration, chloride content, gas fugacity, flow behavior, water cut & oil wetting, and inhibition. A high-level flowchart of the model is presented in Figure 1.

Model Validation

pH Model Evaluation

The pH prediction component of the model was validated using measured data reported by A.Miyasaka.²⁶ The validation dataset includes pH measured at two temperature levels -298 K (25 °C) and 333 K (60 °C) – under a range of CO₂ and H₂S gas compositions and bicarbonate (HCO₃⁻) concentrations. As shown in Figure 2, the predicted pH values demonstrate excellent agreement with the measured values, with a coefficient of determination (R²) of 0.9958. This good correlation confirms the model’s capability to accurately estimate in-situ pH, thereby enhancing its reliability for corrosion rate predictions.

Corrosion Model Evaluation

The corrosion prediction model was validated using a combination of field and laboratory data representative of upstream oil and gas conditions. These validation cases were drawn from multiple published studies, covering a wide range of operational environments including variations in temperature, pressure, gas composition, water chemistry, and flow.^{27 ,28 ,29 ,30} Corrosion rates measured from wells and production systems across different fields were compared with model predictions. Table 1 summarizes a selection of these field datasets used for evaluation.

Table 1 Summary of selected field data used for corrosion model validation.

References

This Article has 30 references.

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• ^{1 - A constant amount of 100 ppm of bicarbonate was added, as specified in the source paper}
• ^{2 - A constant fluid velocity of 20 ft/s (6.1 m/s) was used, as specified in the source paper}
• ^{3 - With no oil protection, as specified in the source paper}