Abstract
The electrochemical and sulfide stress corrosion cracking (SSCC) behaviors of 13Cr stainless steel and P110 steel were investigated in a simulated acidic annular environment with low-temperature and high-pressure H2S/CO2 using electrochemical methods, U-bend immersion tests, and scanning electron microscopy. In the solution containing high pressure CO2, 13Cr, and P110 steels exhibited general corrosion and severe pitting, respectively. Compared with sweet corrosion, additional H2S in the solution enhanced the corrosion of 13Cr steel but inhibited the corrosion of P110 steel. By contrast, in a solution containing 4 MPa CO2 and different \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) (0-0.3 MPa), the susceptibility of both 13Cr stainless steel and P110 steel toward SSCC was significantly promoted by increases in H2S partial pressure. The 13Cr stainless steel exhibited higher susceptibility toward SSCC than P110 steel under a H2S/CO2 environment but lower susceptibility under a pure CO2 environment.
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Introduction
During oil and gas exploitation, complex work conditions cause serious corrosion in tubular steel in sour oil and gas wells. Considerable effort has been exerted to study the effects of environmental aspects, material characteristics, and corrosion scales on sulfide stress corrosion cracking (SSCC) in oil and gas wells, where CO2 and H2S coexist (Ref 1–6). However, most reports focus on the internal corrosion (Ref 7, 8) of tubular and pipeline steels during the exploitation and transportation of oil and gas, and limited attention has been directed toward studies on H2S/CO2 corrosion under an annular environment (Ref 9–12) between tubing steel and casing steel. Several tubing steel failure accidents recently occurred in some oil fields in China, and investigations have been conducted to determine the most probable causes of these failures. Results showed that the chemical composition, metallographic structure, and mechanical properties of the tubing steels are in accordance with the relevant technical requirements of API Spec 5CT standards (Ref 13). Based on analyses of macroscopic fracture characteristics, fractographs, microscopic cracks, and x-ray diffractograms of surface films and deposits at the fracture position, SSCC induced by cracks originating outside the tubing steel appear to be responsible for the accidents.
SSCC failures occurring under an annular environment between tubing and casing steels are a new type of corrosion phenomenon in CO2 injection wells. Our investigation on the annular medium showed the complexity of this annular environment with low temperature (0-30 °C), high-pressure H2S/CO2, and low pH (~4). Compared with corrosion under a high-temperature/high-pressure environment in down-hole wells, corrosion under a low-temperature/high-pressure environment promotes higher susceptibility to stress corrosion cracking (SCC). The design of control methods and selection of suitable materials are difficult because of the lack of data on tubing steel corrosion under an annular environment, especially under high partial pressures of H2S (\( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) = 0.05 to 0.3 MPa). Thus, studies on H2S/CO2 corrosion and SSCC of tubular steels under acidic annular environments are of great importance.
Two types of steels, namely, 13Cr stainless steel and P110 steel, both of which are widely used as tubing materials for oil and gas wells (Ref 14, 15), were chosen as experimental materials in this study, and the corrosion behaviors of these steels under a specific annular environment were compared. The results of this study provide support for the selection of materials used in oil and gas wells.
This study aims to compare the electrochemical corrosion and SSCC behaviors of 13Cr and P110 steels under an acidic, low-temperature, high-pressure H2S/CO2 annular environment. This study also evaluates the effect of \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) on the corrosion behavior of tubing steels using static load U-bend immersion tests, electrochemical measurements, and scanning electron microscopy (SEM).
Experimental
Materials and Test Solution
13Cr and P110 steels, the chemical compositions and mechanical properties of which are shown in Table 1, were used in this experiment. Based on a survey on the chemical composition of the solution medium in a real tubing annular environment, the test solution was composed of NaHCO3 (2.71 g/L), NaCl (6.15 g/L), and Na2SO4 (0.33 g/L) to simulate actual working conditions. The solution pH was then adjusted to 4 with 5% acetic acid. Given that an inhibitor is widely used in actual operational activities to control the corrosion of steels (Ref 16, 17), a 1000 ppm inhibitor (a commercial imidazoline-based product) was added to the solution under several test conditions to insure that test results are as close to real conditions as possible.
Electrochemical Measurements
All the samples used for electrochemical tests were coated with epoxy, and an exposure area of 10 × 10 mm2 served as the working surface. The working surface was ground using 1200 grit sandpaper, degreased with acetone, and rinsed with deionized water. High-pressure tests were performed using an autoclave with a capacity of 1 L. After the specimens and test solution were placed in the autoclave, the solution was de-aerated by purging nitrogen for 1 h. The autoclave was then pressured with H2S to the required levels, which ranged from 0 to 0.3 MPa. CO2 and N2 were pressured to 4 and 9 MPa, respectively. The test conditions are shown in Table 2.
An EG&G M2273 electrochemical test system was used for electrochemical measurements. A three-electrode test cell was used with a platinum plate as the counter electrode, a Ag/AgCl electrode as the reference electrode, and the steel specimen as the working electrode. Potentiodynamic polarization curves were obtained by changing the electrode potential automatically from the cathodic branch to the anodic branch at a scan rate of 0.5 mV/s. Electrochemical impedance spectroscopy (EIS) was measured at open circuit potential with a sinusoidal potential excitation of 10 mV amplitude in the frequency range of 100 kHz to 10 mHz. The impedance data were fitted with ZsimpWin software using equivalent circuits. Experiments for each H2S concentration were conducted at least thrice to insure that the results were reproducible and reliable.
Static Load U-bend Immersion Tests
U-bend immersion tests are useful in studying the SCC mechanism and propagation mode of materials under static load and static strain in a specific environment (Ref 18). Therefore, this study used U-bend immersion tests to investigate the effect of H2S on SSCC susceptibility under a high-pressure CO2/H2S environment. Immersion tests were performed in a high-pressure autoclave with a capacity of 3 L. The working conditions (such as the test solution, order for pressured gases, and specific partial pressure parameters of the gases) for static load U-bend immersion tests were identical to those used for the electrochemical test. Three parallel specimens for each type of material were placed in the test solution for every test, which lasted for 720 h at room temperature.
Surface Analysis
After the corrosion tests, the immersed U-bend specimens used for surfacing analysis were removed and rinsed with deionized water. A wire cutter was used to cut the top parts of two parallel specimens. A heavy stress was applied to these parts, which were then immersed in descaling solution (500 mL of HCl + 500 mL of H2O + 3.5 g of (CH2)6N4) in an ultrasonic container for 3 min. Another specimen was retained for backup. The specimens were then degreased with acetone and dried with cool air, and their surface morphologies were observed by SEM.
Results
Effect of H2S on the Electrochemical Behavior of 13Cr and P110 Steels
Figure 1 shows the polarization curves of 13Cr stainless steel and P110 steel in solutions containing 4 MPa CO2 with/without 0.05 MPa H2S. Two curves for 13Cr stainless steel showed obvious passive characteristics; by contrast, the curves of P110 steel showed active dissolution characteristics. Compared with the H2S-free condition, addition of 0.05 MPa H2S significantly increased the passive current density (i pass) of 13Cr stainless steel but slightly decreased the i corr of P110 steel. For 13Cr stainless steel, the increase in i pass implies that both anodic iron dissolution and cathode reduction were accelerated because of the presence of H2S. For P110 steel, the decrease in i corr demonstrates that the corrosion process was, to some extent, inhibited by the presence of H2S. Compared with sweet corrosion, the presence of H2S moved the corrosion potentials strongly toward the negative direction in both 13Cr and P110 steels.
The EIS curves of 13Cr stainless steel and P110 steel measured at open-circuit potential mode in solutions containing 4 MPa CO2 with/without 0.05 MPa H2S are shown in Fig. 2. The Nyquist plots exhibited characteristic capacitive semicircles, and the diameter of the capacitive semicircle of 13Cr stainless steel was significantly larger than that for P110 steel. Compared with the H2S-free condition, addition of 0.05 MPa H2S slightly decreased the diameter of the capacitive semicircle of 13Cr stainless steel but significantly increased the diameter of the capacitive semicircle of P110 steel. This result demonstrates that the presence of H2S degrades the corrosion resistance of 13Cr stainless steel but improves that of P110 steel under the test conditions. The results so far are consistent with the results obtained from the polarization curves. Moreover, the shape of the Nyquist plots (capacitive loop) of each steel did not change with/without H2S, which indicates the same mechanism for steel corrosion throughout the entire test.
Effect of Different \( {P}_{{{\text{H}}_{{2}} {\text{S}}}}\) on the Corrosion Behavior of 13Cr and P110 Steels
Figure 3 shows the polarization and EIS curves of 13Cr and P110 steels under different \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\). An equivalent circuit shown in Fig. 4 was used to fit the EIS data to quantify the electrochemical parameters. In this equivalent circuit, R s represents the solution resistance, Q f represents the capacitance of the corrosion product film, R f represents the resistance of the corrosion product film, Q dl represents the double layer capacitance, and R ct represents the charge transfer resistance. As both R f and R ct represent the resistances of the corrosion process of carbon steel, a parameter named polarization resistance, R p (R p = R f + R ct), was used to evaluate the corrosion rate of carbon steel in a H2S/CO2 environment (Ref 19).
Figure 5 shows the relationships of the EIS fitting results R p, the corrosion current density i corr of P110, and the passive current density i pass of 13Cr with different H2S partial pressures. The parameters i pass (i corr) and 1/R p are in good agreement with each other. In Fig. 5(a), the R p of 13Cr stainless steel without H2S and 0.05 MPa \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) exhibited significantly higher values than those obtained at higher H2S partial pressures (0.1 to 0.3 MPa \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\)), and the i pass increased greatly in the presence of H2S. However, i pass remained stable as the H2S partial pressure increased from 0.05 to 0.3 MPa. In Fig. 5(b), the regularity of the change in 1/R p of P110 steel was consistent with that of i corr; both 1/R p and i corr significantly decreased with increasing H2S partial pressure. The lowest R p and largest i corr both occurred during sweet corrosion, and the presence of H2S significantly decreased the i corr of the steel.
After the high-pressure immersion tests, the U-bend specimens were subjected to surface analysis after the removal of corrosion scales. Figure 6 shows micrographs of the surfaces of 13Cr stainless steel. Uniform corrosion was observed during sweet corrosion, while cracks on the surface of the sample could be observed during sour corrosion. Figure 6(b-d) shows that the width and depth of the cracks on the surface of 13Cr steel increased with increasing partial pressure of H2S, which indicates that increases in H2S enhance susceptibility toward SSCC. Moreover, the U-bend samples subjected to 0.2 and 0.3 MPa H2S partial pressures were fractured (no failure specimen was observed at 0 and 0.1 MPa H2S partial pressure). The fracture cross-sections of the specimens are shown in Fig. 6(e) and (f). SSCC cracks were initiated on the steel surface and continued to propagate until the ligament of the specimen could no longer bear the applied load.
SEM morphology of U-bend specimens of 13Cr stainless steel under various H2S partial pressures of (a) \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) = 0 MPa, (b) \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) = 0.1 MPa, (c) \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) = 0.2 MPa, and (d) \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) = 0.3 MPa and the fractography at (e) \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) = 0.2 MPa and (f) \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) = 0.3 MPa. All of the test solutions contained 1000 ppm corrosion inhibitor
Figure 7 shows the morphology of the surface of P110 tubing steel obtained under various \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) after the removal of corrosion products. Corrosion pits with diameters of ~25 μm and small-sized cracks were observed without H2S. At 0.1 MPa \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\), slight corrosion and a few small cracks were observed on the matrix. These generated cracks are related to hydrogen evolution during the cathodic process in the presence of H2S. Hydrogen atoms that penetrate into the substrate facilitate the nucleation of cracks. As the H2S partial pressure increased to 0.2 and 0.3 MPa, the depth and number of cracks significantly increased, which indicates that the cathodic process was significantly accelerated and that hydrogen ingress into the matrix was enhanced.
SEM morphology of U-bent specimens of P110 steel under various H2S partial pressures: (a) \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) = 0 MPa, (b) \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) = 0.1 MPa, (c) \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) = 0.2 MPa, and (d) \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) = 0.3 MPa. All of the test solutions contained 1000 ppm corrosion inhibitor
Effect of Corrosion Inhibitor on the Corrosion Behavior of 13Cr and P110 Steels
Figure 8 shows the SEM morphology of U-bent specimens of 13Cr stainless steel and P110 steel obtained without corrosion inhibitor after the removal of corrosion products. In corrosive medium without inhibitor, the metal comes into direct contact with anions and subsequent dissolution of the matrix occurs at the metal-solution interface. Therefore, severe corrosion occurs in metals in acidic solution without inhibitor. Upon addition of 1000 ppm inhibitor to the test solution, inhibitors function by adsorption of ions or molecules onto metal surface. The inhibitor prevents direct contact between the matrix and the corrosive medium and can thus reduce the corrosion rate by decreasing the anodic and/or cathodic reaction (Ref 17). Thus, compared with that in the solution without inhibitor, the corrosion process decreased greatly in the solution with inhibitor, as shown in Figs. 6(a) and (c) and 7(a) and (c). These results indicate that the inhibitor decreases the corrosion rate of the matrix significantly.
SEM morphology of U-bent specimens: (a) 13Cr steel, PCO2 = 4 MPa, without inhibitor; (b)13Cr steel, \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) = 0.2 MPa, PCO2 = 4 MPa, without inhibitor; (c) P110 steel, PCO2 = 4 MPa, without inhibitor; and (d) P110 steel, \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) = 0.2 MPa, PCO2 = 4 MPa, without inhibitor
Discussion
Analysis of the Formation of the Annular Environment of CO2 Injection Wells
CO2 oil displacement technology, a type of technology for enhanced oil recovery that requires the injection of CO2 into underground reservoirs, has attracted worldwide attention for its many advantages, which include low cost, non-toxicity, environmental protection, and good miscibility with crude oil (Ref 20, 21). In natural gas and oil wells, packers are used to insure that the exterior of the tubing steel and the interior of the casing steel do not touch the corrosion medium. However, some defects may exist in the tubular steel, and these defects could cause widespread leakage of production steel. Corrosion at defect sites during service worsens the leakage problem. In CO2 injection wells, the high pressure of CO2 injected into the underground natural gas reservoirs may result in the following:
-
(1)
High pressure (4-20 MPa) at the wellhead;
-
(2)
A relatively low-temperature (0-30 °C) environment at a certain depth; and
-
(3)
Partial CO2 leakage into the annular environment from defects of the tubular steel.
CO2 then dissociates into the annular environment protective liquid:
The chemical dissociation of CO2 behaves similar to a weak acid and decreases the solution pH (the solution pH was ~4). This reaction accelerates the dissolution of steel during the anodic process, and the hydrogen evolution reaction in the cathodic process occurs as follows:
Promotion of the cathodic hydrogen evolution process will increase the susceptibility of the tubular steel toward SCC because hydrogen atoms generated in the cathodic process could penetrate into the steel substrate.
The annular environment between the tubing steel and the casing steel is full of protection liquids. This stationary, enclosed, de-aerated environment should not contain H2S. However, our investigation on the solution medium extracted from the actual annular environment showed that the protective liquid contains a high concentration of H2S. Thus, the outer face of the tubing steel suffered from sulfate-reducing bacteria (SRB) corrosion. SRBs are anaerobic bacteria that reduce sulfate to sulfide. The presence of SRBs in the annular environment can consume sulfate radicals though cathodic depolarization, thereby converting sulfate to sulfide and promoting H2S formation in an acid environment (Ref 22, 23):
The synergistic effects of leakage and presence of SRB promote the formation of a complex annular environment in CO2 injection wells featuring low temperature, high pressure CO2/H2S, and low pH (~4), as shown in Fig. 9.
Effect of H2S on Corrosion Behavior of Tubular Steel
In a high-pressure CO2/H2S environment, a significant difference exists between the effects of varying \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) on the corrosion behaviors of tubular steels (Ref 24, 25). Pots et al. (Ref 26) claimed that the effects of H2S on the corrosion behavior of steel in a CO2/H2S environment depend on the CO2/H2S ratio, which determines the nature of the scales and the corrosion mechanism. Although no specific critical H2S concentration provides inhibition, the inhibitory effect may be related to the formation of a corrosion product film (Ref 15, 27). Choi (Ref 28) suggested that the precipitation of an iron sulfide and iron carbonate film is possible in acidic solutions (pH = 3 or 4) because of local supersaturation in regions immediately above the steel surface. Corrosion product films form on the steel surface during the corrosion of the steel under a CO2/H2S environment:
During sweet corrosion, the corrosion product film is composed of FeCO3, which is a typical product of CO2 corrosion. However, with increases in the partial pressure ratio of H2S/CO2, the corrosion process gradually switches to H2S and CO2 mix control, and the corrosion product film of Fe x S is dominant under these conditions (Ref 15).
In 13Cr stainless steel, CO2 corrosion dominates the corrosion process in conditions without H2S, and a layer of passive corrosion product film consisting of Cr(OH)3 and FeCO3 covers the steel surface (Ref 15). However, this layer of corrosion product film is not tightly adhered to the matrix and can be easily removed from the steel surface without the protection of the inhibitor. Some particles, such as carbides, act as cathodic sites, while the rest of the metal acts as an anode, and then many micro galvanic cells were formed (Ref 14). These heterogeneities sites disrupt the corrosion product film, such that severe pitting occurs without the inhibitor, as shown in Fig. 8(a) and (b). As the inhibitor is added to the solution medium, the metal matrix becomes well protected under the combined effects of the corrosion product film and the inhibitor. Thus, uniform corrosion with no cracks is observed in Fig. 6(a). In the presence of H2S, chemically dissociated ions, such as HS− and S2−, from the additional H2S are strongly adsorbed on the surface of the steel. On one hand, these HS− and S2− ions react with the passive film to form soluble corrosion products that promote the dissolution of the original passivity film. On the other hand, the FeS x film generated by the Sx− and Fe2+ cannot protect the matrix since this Fe x S film competes with the inhibitor covering the surface of steel (Ref 29–31). Thus, the passive surface film is severely damaged, which would explain why the polarization resistance R p significantly decreases, as shown in Fig. 5(a). The part of the matrix without film or inhibitor protection will come into contact with the corrosive medium directly and become greatly corroded.
A layer of thin corrosion product film FeCO3 covers the P110 steel surface under CO2 corrosion. The severe pitting shown in Fig. 7(a) occurs during sweet corrosion because of the uneven distribution of the corrosion product film formed on the surface of the steel (Ref 14). During sour corrosion, the presence of H2S dissociates in solution and facilitates the formation of a layer of Fe x S, which is more compact than the FeCO3 film and inhibits ion migration (Ref 2). Compared with sweet corrosion, i corr greatly decreases during sour corrosion because of the protection endowed by the Fe x S film, which is reflected by the significantly increased R p shown in Fig. 5(b). In contrast to the 13Cr stainless steel, the layer of Fe x S film on the P100 steel does not compete with the inhibitor, and the matrix is well protected under the combined effects of the corrosion product film and the inhibitor. The different performances of the corrosion product film Fe x S and the inhibitor cause 13Cr stainless steel and P110 steel to exhibit different corrosion behaviors in a sweet corrosion environment, i.e., the presence of H2S accelerates the corrosion of 13Cr stainless steel but inhibits the corrosion of P110 steel.
The reduction of hydrogen ions is one of the main cathodic reduction reactions (Ref 3–5) in a solution of pH 4. Hydrogen atoms generated from the cathodic process can penetrate into the steel matrix, which results in hydrogen-induced cracking (HIC) and contributes to the increased HIC susceptibility of steels. Thus, SSCC of the steels in a CO2/H2S environment may be expected to be based on hydrogen, i.e., HIC. As shown in Figs. 6 and 7, for the 13Cr stainless steel surface shows no cracks during sweet corrosion, whereas the P110 steel surface exhibits several small cracks. These cracks reveal that P110 steel has higher susceptibility toward SSCC than 13Cr stainless steel in a high-pressure CO2 environment. SSCC cracks prevail under conditions with H2S, and the 13Cr stainless steel specimen fails under 0.2 and 0.3 MPa H2S. This result is attributed to high-pressure H2S enhancing hydrogen ingress into the steel as well as HIC susceptibility, which is related to the increase in absorbed hydrogen content with increasing partial pressure of H2S (Ref 25). The regularity of change in morphology (SSCC susceptibility) of the 13Cr stainless steel, as revealed by the immersion test, is consistent with that observed in the electrochemical test results (i pass). Both SSCC susceptibility and i pass were promoted by increasing \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\). For P110 carbon steel, however, the increase in SSCC susceptibility seems to be in conflict with the decrease in i corr as the \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\) increases from H2S-free to 0.3 MPa. As previously stated, the decrease in i corr may be attributed to the FeS x film covering the steel surface; this layer of film provides protection to the steel. However, hydrogen atoms can still penetrate into the matrix because of their size, regardless of the presence or absence of a film layer. As the H2S partial pressure increases from 0.1 to 0.3 MPa, more cracks appear on the specimen surface and susceptibility toward SSCC is enhanced with increasing \( {P}_{{{\text{H}}_{ 2} {\text{S}}}}\).
Overall, 13Cr stainless steel exhibited general corrosion while the P110 steel exhibited severe pitting under a high-pressure CO2 environment. Such results may be due to differences in the protective performance of corrosion product scales on each surface. The presence of H2S in CO2-containing environments can promote corrosion risk by facilitating corrosion in the 13Cr steel (increase i pass) at a rate greater than that induced by pure CO2 corrosion. By contrast, the corrosion risk of P110 (decrease i corr) can be decreased by preferentially forming a layer of FeS x on the film surface; this type of film is more compact than FeCO3. H2S also increases SSCC risk by promoting hydrogen atom ingress into the substrate in for 13Cr stainless steel and P110 steel. Development of SSCC is of particular concern because it degrades steel and results in cracking.
Conclusions
The results of this study suggest that 13Cr stainless steel and P110 steel exhibit different corrosion behaviors and susceptibility toward SSCC under a simulated acidic annular environment with low temperature and H2S/CO2. In a solution of 4 MPa CO2, 13Cr stainless steel exhibited general corrosion whereas P110 steel exhibited severe pitting. P110 steel showed higher susceptibility toward SSCC than 13Cr stainless steel under the experimental condition. Compared with sweet corrosion, additional H2S accelerated the corrosion of 13Cr stainless steel but decreased the corrosion of P110 steel. The susceptibility of both 13Cr and P110 toward SSCC was significantly promoted in the presence of H2S. 13Cr showed higher susceptibility toward SSCC than P110 steel in a H2S/CO2 environment. Moreover, a higher H2S partial pressure in the solution allowed more hydrogen atoms to penetrate into the matrix, thereby increasing SSCC susceptibility.
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Acknowledgments
This work was supported by the National Key Technology Research and Development Program of the Ministry of Science and Technology of China (No. 2011BAK06B01-01) and National Natural Science Foundation of China (No. 51131001).
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Liu, Z.Y., Wang, X.Z., Liu, R.K. et al. Electrochemical and Sulfide Stress Corrosion Cracking Behaviors of Tubing Steels in a H2S/CO2 Annular Environment. J. of Materi Eng and Perform 23, 1279–1287 (2014). https://doi.org/10.1007/s11665-013-0855-x
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DOI: https://doi.org/10.1007/s11665-013-0855-x