In the field of carbon capture, utilization, and storage (CCUS), maintaining the integrity of injection wells is crucial, especially for Class VI wells designed for the geologic sequestration of CO2. These wells face challenging environments where CO2 interacts with water and impurities, leading to significant corrosion risks. The presence of impurities, often from industrial sources such as power generation, chemical plants, cement plants, and ethanol plants, further complicates this situation. Rigorous corrosion assessment is essential for ensuring long-term well integrity. This blog explores how advanced corrosion modeling with OLI Systems’ software plays a pivotal role in the permitting process for CO2 storage in Class VI wells, ensuring both environmental safety and operational reliability. As will be shown, the recommendation for material selection depends on the specific compositions of the CO2 injectate and formation brine, as well as the operating conditions. Therefore, it is not feasible to make a generalized recommendation for all CO2 injection scenarios.
1. What is a Class VI Well?
Class VI wells are designed for the deep underground injection of CO2 as part of geologic sequestration (GS), a key technology in carbon capture and storage (CCS) aimed at reducing atmospheric CO2 levels. These wells enable the long-term storage of CO2 sourced from industrial emissions, power generation, and direct air capture. Understanding and mitigating the corrosion challenges in these wells is critical for maintaining their integrity over extended periods, supporting the goal of climate change mitigation. Under the EPA’s Underground Injection Control (UIC) Program, corrosion modeling is essential for Class VI wells. The UIC guidelines mandate thorough well integrity assessments to prevent leaks and environmental hazards, ensuring the long-term safety and reliability of CO2 storage in geologic formations.
2. Challenges in Material Selection for CO2 Sequestration Wells
One of the major challenges in CO2 sequestration projects is ensuring that the injection well remains intact throughout its operational life. The risks associated with CO2 gas leakage to the surface are significant, necessitating the use of materials that can endure prolonged exposure to harsh environments. For this reason, specialty tubing materials are often considered as the base case for continuous, long-term operations.
Higher Corrosion Resistant Alloys (CRAs) such as 25Cr and epoxy-lined tubulars are being considered for CO2 injection wells. While 25Cr is widely known for its robustness, it comes with high costs, which may lead to concerns about overdesign. On the other hand, epoxy-lined tubulars, though less expensive, are vulnerable to blistering under high temperatures and pressures, as well as mechanical damage from wireline operations. Thus, having a tool to determine the ideal material for specific corrosive environments is crucial.
OLI Systems’ technology is uniquely equipped to address the complex challenges of corrosion in CO2 injection wells. Its advanced thermodynamic and comprehensive corrosion models are integrated into OLI Studio: Corrosion Analyzer, a software platform that allows users to accurately simulate the interactions between CO2, water, impurities, and wellbore materials. This enables the prediction of general corrosion rates and the assessment of localized corrosion risks, thereby optimizing material selection.
For more information on the latest improvements to the corrosion model, you can visit this blog: Corrosion Modeling of Corrosion Resistant Alloys in Pure Acids and Acid Mixtures Across a Wide Concentration Range and Its Role in Predicting Corrosion in CO2 Injection.
The combination of cutting-edge modeling and user-friendly tools helps operators reduce corrosion risk, extend the lifespan of well components, and ensure the safe operation of CO2 storage wells.
3. Navigating Uncertainties and Considerations
Even with robust modeling tools, inherent uncertainties must be considered in the corrosion management process. These include variations in CO2 composition due to mixing, formation water composition, unexpected changes in wellbore conditions, and long-term material performance. OLI’s software can help identify and quantify these uncertainties, providing operators with a clearer understanding of potential risks and the confidence to make data-driven decisions during the permitting process.
4. CO2 Injection Applications Using OLI Software
The following case studies are based on a CO2 storage screening study that was seeking to connect industrial emitters with a single geological storage field. The CO2, coming from different sources, was to be transported via a 130 km (80.7 miles) pipeline to an injection wellhead platform. The plan involved injecting and storing the CO2 within a depleted carbonate reservoir until the reservoir pressure increased to its initial level of 3,000 psia. The reservoir temperature was approximately 70°C.
The tubulars used in this project were expected to be exposed to a water-rich phase both in the injection fluid and during flowback, necessitating a careful evaluation of material performance under these conditions. This study accounted for all possible conditions throughout the well’s life cycle—including CO2 injection, shut-in, and flowback— at both surface and bottom hole conditions.
To illustrate the practical applications of OLI’s corrosion modeling capabilities, this blog explores three CO2 injection fluid compositions to demonstrate the software’s effectiveness in predicting the phase behavior of the CO2 injectate, the properties of the flowback fluid, and the prediction of corrosion rates (both general and localized) during injection and shut-in scenarios.
These case studies show the corrosion results for three different sources of CO2 injection fluids: one from a natural gas source, one from an ethanol plant, and one from a post-combustion process. A summary table of the injection fluids used for this study is provided below.
Table 1. Summary table of injection fluids used for this study
| Industry | Natural Gas | Post-Combustion | Ethanol Plant | *Mixed Stream: Ethanol Plant + Post-Combustion |
|---|---|---|---|---|
| Compositions | Mole % | Mole% | Mole% | Mole% |
| Water, H₂O | 0.07 | 0.0061 | 0.0042 | 0.0422 |
| Carbon Dioxide, CO₂ | 95.26 | 98.441 | 98.7911 | 98.6274 |
| Hydrogen Sulfide, H₂S | 0.05 | 0.7795 | 0.002 | 0.3538 |
| Nitrogen, N₂ | 0.284 | 0.75 | 1.1545 | 0.9523 |
| Methane, CH₄ | 4.26 | 0.01 | 0.0001 | 0.0051 |
| Ethane, C₂H₆ | 0.063 | - | 0.0157 | 0.0078 |
| Propane, C₃H8 | 0.007 | - | ||
| Butane, C4H₁₀ | 0.001 | - | ||
| Pentane, C5H12 | - | - | ||
| Hexane, C6H14 | - | - | 0.0069 | 0.0034 |
| Heptane, C7H16 | - | - | ||
| Oxygen, O2 | 0.005 | 0.01 | 0.0256 | |
| Ammonia, NH3 | - | 0.0007 | - | 0.00035 |
| Nitrogen Dioxide, NO2 | - | 0.001 | - | |
| Sulfur Dioxide, SO2 | - | 0.001 | - | - |
| Nitrogen Monoxide, NO | - | - | - | 0.0005 |
| Sulfur, S | 0.0068 | |||
| TEG | - | 0.0007 | - | 0.0004 |
* The composition of the Mixed Stream was calculated using the OLI Studio: Corrosion Analyzer software by mixing the Ethanol Plant and Post-combustion injection fluids in a 1:1 mass ratio at the injection surface conditions of 25°C and 1,600 psia.
Two different scenarios for corrosion analysis were studied: (1) corrosion due to the drop-out of an acid-rich phase from the CO2 injection fluid during injection, and (2) corrosion due to the flowback fluid during shut-in conditions.
4.1. Scenario 1: Corrosion due to the drop out of an acid-rich phase
Although only a small amount of water was reported in all the injection fluid compositions, its presence could lead to significant corrosion if it condenses into the liquid phase, particularly in areas with temperature and pressure fluctuations. To address this risk, a conservative approach was taken by modeling scenarios with up to 5% water content to simulate worst-case conditions. The condensate composition was then used to perform corrosion rate calculations for CO2 injection at both surface and bottom hole conditions.
4.2. Scenario 2: Corrosion due to Flowback Fluid
For all the flowback fluid corrosion analyses, a single formation water analysis was used. The composition of the formation water is provided in Table 2:
Table 2. Formation Water Composition
| Property | Value | Units |
|---|---|---|
| Temperature | 24.4 | °C |
| pH | 6.98 | pH |
| Density at 20°C | 1.017 | g/cm³ |
| Total Dissolved Solids | 25,700 | mg/L |
| Chloride | 13,000 | mg/L |
| Sulfate (SO4²⁻) | 1,500 | mg/L |
| Bromide (Br⁻) | 66.1 | mg/L |
| Bicarbonate Alkalinity | 1,260 | mg CaCO₃/L |
| Sodium (Na+) | 9,140 | mg/L |
| Potassium (K+) | 100 | mg/L |
| Calcium (Ca+2) | 221 | mg/L |
| Magnesium (Mg+2) | 30.6 | mg/L |
| Strontium (Sr+2) | 16.9 | mg/L |
| Barium (Ba+2) | 0.33 | mg/L |
| Iron (Fe+2) | 0.36 | mg/L |
| Boron (B) | 108 | mg/L |
| Arsenic (As) | <0.05 | mg/L |
4.3. Corrosion Rate Analysis and Material Selection
OLI Studio Corrosion Analyzer was used to model the corrosion rates of various materials under different operational conditions. The analysis covered a broad range of temperatures (25°C to 55°C) and pressures (800 psia to 3,000 psia), simulating both surface and bottom hole conditions during the well’s shut-in and injection phases.
Table 3.Pressure and Temperature Conditions During Shut-in and Injection
| Parameters | Shut-In Case | Injection Case | ||
|---|---|---|---|---|
| Surface Condition | Bottom Hole Condition | Surface Condition | Bottom Hole Condition | |
| Pressure, psia | 800 | 2600 | 1600 | 3000 |
| Temperature, °C | 25 | 55 | 25 | 30 |
The corrosion rate analysis included six different materials commonly considered for CO2 sequestration wells, including 13Cr, Super 13Cr, Super 15Cr, Super 17Cr, 22Cr (Alloy 2205), and 25Cr (Alloy 2507). The goal was to determine which materials could maintain corrosion rates below a conservative value of 0.100 mm/year, which is crucial for ensuring long-term well integrity. Localized corrosion was also analyzed as the general corrosion rate needs to be coupled with the likelihood of localized corrosion to occur. A material might present a low general corrosion rate, but it might be susceptible to localized corrosion; hence, these two types of information must be coupled together.
5. Case Study 1: Successful Application of 13Cr Alloy
5.1. Corrosion due to drop-out of a water-rich phase
The results presented here used the CO2 injection fluid from a natural gas source. This injection fluid contained mostly CO2 (95.25 mole%) and relatively small amounts of other impurities such as N2 (0.285 mole%) and CH4 (4.26 mole%). After entering the composition of this CO2 injection fluid into the OLI Studio software, it was found that at the injection conditions (surface and bottom hole), the fluid was in the supercritical phase, not posing a significant corrosion risk. We then calculated the amount of water that this fluid can hold until a water-rich condensate forms. The resulting liquid phase composition was then used to calculate the corrosion rates. The corrosion rate results are shown in Table 4.
5.2. Corrosion due to the Flowback fluid
The second scenario within Case Study 1 focuses on the corrosion risks posed by the flowback fluid, which is a mixture of the injection fluid and formation water that returns to the well during shut-in conditions. This mixture is particularly corrosive due to its altered chemical composition and the presence of dissolved salts and minerals from the formation water. To assess the corrosion rates resulting from this interaction, the OLI Studio Corrosion Analyzer’s mixer function was used. The model incorporated the compositions of both the injection fluid and formation water, as shown in Tables 1 and 2. Only the shut-in case at bottom hole conditions was studied. The corrosion rate results are given in Table 5.
Table 4. General Corrosion Rate results for CO2 Injection at Surface and Bottom Hole Conditions
| Case | Location | Pressure, psia | Temperature, °C | pH | Type of Corrosion Attack | 13Cr | Super 13Cr | Super 15Cr | Super 17Cr | Super 22Cr | Super 25Cr |
|---|---|---|---|---|---|---|---|---|---|---|---|
| Injection | Surface | 1600 | 25 | 3.08 | General Corrosion Rates, mm/year | 0.0091 | 0.0006 | 0.0005 | 0.0004 | 0.0006 | 0.0003 |
| Localized Corrosion | No | No | No | No | No | No | |||||
| Bottom Hole | 3000 | 30 | 3.04 | General Corrosion Rates, mm/year | 0.0134 | 0.0008 | 0.0007 | 0.0006 | 0.0007 | 0.0003 | |
| Localized Corrosion | No | No | No | No | No | No |
Table 5. General Corrosion Rate results for the flowback fluid for the Shut-in case at Bottom Hole Conditions
| Case | Location | Pressure, psia | Temperature, °C | pH | Type of Corrosion Attack | 13Cr | Super 13Cr | Super 15Cr | Super 17Cr | Super 22Cr | Super 25Cr |
|---|---|---|---|---|---|---|---|---|---|---|---|
| Shut-in | Bottom Hole | 2600 | 55 | 4.2 | General Corrosion Rates, mm/year | 0.0109 | 0.0026 | 0.0022 | 0.0018 | 0.0013 | 0.0007 |
| Localized Corrosion | No | No | No | No | No | No |
For both the CO2 injection and flowback fluid scenarios, the results showed that 13Cr alloy performed well across all modeled conditions, with corrosion rates consistently below the 0.100 mm/year cut-off. These findings suggest that 13Cr could be a viable and cost-effective material for tubing in this CO2 sequestration application. Importantly, no localized corrosion (pitting) was predicted under any of the studied conditions. The results, especially for the flowback fluid scenario, suggest that despite the presence of Cl- ions from the flowback fluid, the use of 13Cr alloy remains a viable and cost-effective option, providing adequate protection against corrosion in CO2 sequestration wells under the conditions studied.
An important observation is that the pH of the flowback fluid was found to be slightly higher, ranging between 4.11 and 4.50, compared to the predicted pH of the condensed fluid that dropped out at injection conditions, which had a pH range of 3.03 to 3.19. This increase in pH is primarily attributed to the buffering effect of bicarbonates in the formation water. The OLI model predicted that 13Cr would effectively resist corrosion within the operational parameters, validating its use as a cost-effective alternative to more expensive CRA materials.
6. Case Study 2: Conditions in which 13Cr Alloy Does Not meet Specifications
The second case study examines the effect of CO2 injection fluid from a post-combustion source, where the 13Cr alloy is at risk of corrosion due to changes in operational conditions, such as increased levels of impurities like H2S (0.05 mole%) in the injection fluid. Reactions between these impurities significantly impact pH and the resulting corrosion rates. Under these conditions, Super 13Cr or higher grades were found to be more suitable.
6.1. Corrosion Due to Drop-Out of a Water-Rich Phase
This injection fluid contained mostly CO2 (95.26 mole%) with similar impurities to the natural gas source previously studied, but with a higher content of H2S (0.7795 mole%) and oxygen (0.01 mole%) and additional impurities such as NH3 (7 ppm mole), NO2 (10 ppm mole), and SO2 (10 ppm mole).
The OLI thermodynamic model accounts for the effects of various impurities that can mix with CO2 and impact its vapor-liquid equilibrium (VLE) behavior. These impurities include CH4, C2H6, N2, CO, Ar, H2, O2, H2S, and NO. Additionally, the model examines impurities known to cause the formation of solid or liquid acids—mainly sulfuric or nitric acids or ammonium-containing solids—such as H2O, NH3, O2, SO2, H2S, and NO2. This capability enables us to predict whether an acid phase will form and assess how these impurities might affect the total amount of acid that can remain in the CO2 dense phase.
After entering the composition of this CO2 injection fluid into the OLI Studio software, it was found that at the injection conditions (surface and bottom hole), the fluid remained in the supercritical phase, not posing a significant corrosion risk. The amount of water the fluid could hold until an acid phase dropped out was then calculated. The resulting liquid phase composition, with pH values between 2.93 and 2.97, was used to calculate corrosion rates. The results are shown in Table 6.
6.2. Corrosion due to Flowback Fluid
Similar to the flowback fluid scenario in Case Study 1, the injection fluid was mixed with formation water at a 1:1 mass ratio to predict the properties of the mixed CO2 injectate and formation water fluid. The only condition studied was the shut-in case at bottom hole conditions. The corrosion rate results are given in Table 7.
Table 6. General Corrosion Rate results for CO2 Injection at Surface and Bottom Hole Conditions
| Case | Pressure, psia | Temperature, °C | pH | Type of Corrosion Attack | 13Cr | Super 13Cr | Super 15Cr | Super 17Cr | Super 22Cr | Super 25Cr | |
|---|---|---|---|---|---|---|---|---|---|---|---|
| Injection | Surface | 1600 | 25 | 2.97 | General Corrosion Rates, mm/year | 0.0115 | 0.0006 | 0.0005 | 0.0004 | 0.0006 | 0.0003 |
| Localized Corrosion | No | No | No | No | No | No | |||||
| Bottom Hole | 3000 | 30 | 2.93 | General Corrosion Rates, mm/year | 0.0172 | 0.0008 | 0.0007 | 0.0006 | 0.0007 | 0.0003 | |
| Localized Corrosion | No | No | No | No | No | No |
Table 7. General Corrosion Rate results for the flowback fluid for the Shut-in case at Bottom Hole Conditions
| Case | Pressure, psia | Temperature, °C | pH | Type of Corrosion Attack | 13Cr | Super 13Cr | Super 15Cr | Super 17Cr | Super 22Cr | Super 25Cr | |
|---|---|---|---|---|---|---|---|---|---|---|---|
| Shut-in | Bottom Hole | 2600 | 55 | 4.6 | General Corrosion Rates, mm/year | 0.0108 | 0.0026 | 0.0022 | 0.0018 | 0.0014 | 0.0007 |
| Localized Corrosion | Yes | No | No | No | No | No |
For both the injection fluid and flowback fluid scenarios, the corrosion rates for 13Cr remained low, around 0.01 mm/year. However, for the shut-in bottom hole condition, localized corrosion was predicted to occur. Further analysis revealed that the main driver for localized corrosion was the high concentration of dissolved H2S in the aqueous solution—478.5 mg/L. These findings highlighted the need for alternative materials or adjustments in operational procedures to mitigate the identified corrosion risks. At a minimum, Super 13Cr would be needed for this type of injection fluid. The presence of H2S introduces additional risks such as Stress Corrosion Cracking (SCC) and Sulfide Stress Cracking (SSC), both of which can significantly compromise the integrity of the well, as predicted by the likelihood for 13Cr to suffer localized corrosion.
7. Scenario 3: Addressing Corrosion Challenges through Higher CRAs
A final case study explores alternative alloy materials to consider when the corrosion model predicted that 13Cr, Super 13Cr, Super 15Cr, and Super 17Cr were insufficient for shut-in bottom hole conditions. The CO2 injection fluid in this study comes from an ethanol plant and contains H2S (20 ppm mole) and significantly higher O2 content (0.05 mole%) compared to the previous injection fluids, as shown in Table 1. Super 22Cr and Super 25Cr were identified as the best materials due to their low general corrosion rates and no propensity for localized corrosion, ensuring well integrity under the given conditions.
7.1. Corrosion due to drop-out of a water-rich phase
A similar analysis of the CO2 injection was performed for this case. It was found that the resulting liquid phase composition that dropped out had pH values of 1.45 to 1.49. This low pH was due to the dropout of sulfuric acid, which formed due to the oxidation of H2S to H2SO4, catalyzed by the high O2 content in the CO2 injection fluid. The corrosion rate results are shown in Table 8.
7.2. Corrosion due to Flowback Fluid
Corrosion rate results for the shut-in bottom hole conditions are shown in table 8.
Table 8. General Corrosion Rate results for CO2 Injection at Surface and Bottom Hole Conditions
| Case | Pressure, psia | Temperature, °C | pH | Type of Corrosion Attack | 13Cr | Super 13Cr | Super 15Cr | Super 17Cr | Super 22Cr | Super 25Cr | |
|---|---|---|---|---|---|---|---|---|---|---|---|
| Injection | Surface | 1600 | 25 | 1.49 | General Corrosion Rates, mm/year | 0.5684 | 0.0005 | 0.0003 | 0.0002 | 0.0001 | 0.0001 |
| Localized Corrosion | No | No | No | No | No | No | |||||
| Bottom Hole | 3000 | 30 | 1.45 | General Corrosion Rates, mm/year | 0.9041 | 0.0007 | 0.0004 | 0.0003 | 0.0002 | 0.0001 | |
| Localized Corrosion | No | No | No | No | No | No |
Table 9. General Corrosion Rate results for the flowback fluid for the Shut-in case at Bottom Hole Conditions
| Case | Pressure, psia | Temperature, °C | pH | Type of Corrosion Attack | 13Cr | Super 13Cr | Super 15Cr | Super 17Cr | Super 22Cr | Super 25Cr | |
|---|---|---|---|---|---|---|---|---|---|---|---|
| Shut-in | Bottom Hole | 2600 | 55 | 4.19 | General Corrosion Rates, mm/year | 0.0109 | 0.0022 | 0.0013 | 0.001 | 0.0003 | 0.0003 |
| Localized Corrosion | Yes | Yes | Yes | Yes | No | No |
For both the injection fluid corrosion rate results, the low pH of the fluid increases the general corrosion rates of 13Cr above the cut-off value of 0.1 mm/year, making it an unsuitable material if an acid phase were to drop-put while injecting the CO2. General corrosion rates are much lower for Super 13 Cr and higher alloys.
For the flowback fluid corrosion rate predictions, the corrosion rates for 13Cr were low, one order of magnitude below the cut-off value of 0.1 mm/year. However, for the shut-in bottom hole condition, localized corrosion was predicted to occur. Further analysis revealed that the main driver for localized corrosion was the high concentration of O2 dissolved in the aqueous solution—10.2 mg/L. Other materials such as Super 13Cr, Super 15Cr, and Super 17Cr were also found to be susceptible to localized corrosion. For all these alloys, the O2 concentration drove the corrosion potential to much higher values than the localized corrosion potential, e.g., for Super 15Cr, the corrosion potential was 0.664 V vs SHE compared to the repassivation potential value of -0.0714 V vs SHE, combined with Cl– content from the formation water, leading to localized corrosion.
These findings emphasized the need for alternative materials or adjustments in operational procedures, such as decreasing the amount of O2 present in the CO2 injection fluid, to mitigate corrosion risks. For these conditions, at a minimum, 22Cr would be needed for this type of injection fluid.
8. Predicting the Composition of Mixed Injection Fluids
These case studies highlight the importance of understanding the impact of impurities and their concentrations on the corrosion rates to select the appropriate materials for the job. In some cases, the injection site will aggregate different CO2 streams coming from different emitters into a pipeline. It is important to understand how variability from emitter will change the risk profile of the pipeline and at the injection well. Variability in composition will also have an impact on the phase envelope.
OLI Studio: Corrosion Analyzer can calculate the final composition of an injection fluid when two or more CO2 streams with different compositions are mixed. Table 1 shows a mixed stream column that was calculated using OLI’s software. This capability can be used to understand how CO2 injection from different sites into a master pipeline will behave. The software can also help understand how variability from emitters can change the risk profile of the pipeline transporting the CO2 and at the injection point. The software will also allow you to understand the impact of the phase envelope, which affects the power required for transport and injection.
9. The Essential Role of Corrosion Modeling in CCUS
As the demand for CO2 storage solutions grows, ensuring the integrity of Class VI wells through comprehensive corrosion modeling becomes increasingly vital. OLI’s software offers a powerful toolset for predicting and managing corrosion risks, ultimately supporting the safe and efficient operation of CO2 injection wells. By integrating these modeling capabilities into the permitting process, operators can better safeguard both their investments and the environment.
For more information on how OLI Systems’ software can enhance your CO2 storage projects, or to request a demo, please contact our team of experts. Stay tuned for upcoming technical webinars where we will dive deeper into corrosion modeling and other critical aspects of well integrity in CCUS projects.