Mohammed Abdul Rahman, John Shirokoff
Hydrogen sulphide (H2S) corrosion has become a significant concern in the oil and gas industry and one the most commonly used corrosion resistant alloy, 13% chromium stainless steel, has been experimentally investigated in the study. The corrosion behaviour, including corrosion rates, the effect of environmental conditions and the formation of protective films, were examined during the study. A series of experiments was performed using the conventional electrochemical method to study the effects of temperature, pH and exposure time 13% chromium stainless steel in the H2S environment. Electrochemical behaviour was monitored using the polarisation resistance technique, a scanning electron microscope (SEM) equipped with energy dispersive X-ray spectroscopy (EDS) was used to conduct morphological characterization and X-ray diffraction (XRD) was used to study the crystal structure of corrosion products. This study shows that each environmental parameter has a significant impact on corrosion rates and types of corrosion products formed in the H2S environment.
Because you are not logged-in to the journal, it is now our policy to display a 'text-only' version of the preprint. This version is obtained by extracting the text from the PDF or HTML file, and it is not guaranteed that the text will be a true image of the text of the paper. The text-only version is intended to act as a reference for search engines when they index the site, and it is not designed to be read by humans!
If you wish to view the human-readable version of the preprint, then please Register (if you have not already done so) and Login. Registration is completely free.Electrochemical analysis of H2S Corrosion on 13% Chromium Stainless Steel Mohammed Abdul Rahman1and John Shirokoff 2 1 Department of Mechanical Engineering, Faculty of Engineering and Applied Science, Memorial University of Newfoundland. St. John’s, NL, Canada. A1B 3X5 2 Department of Process Engineering, Faculty of Engineering and Applied Science, Memorial University of Newfoundland. St. John’s, NL, Canada. A1B 3X5 Correspondence should be addressed to John Shirokoff; (firstname.lastname@example.org) Abstract Hydrogen sulphide (H2S) corrosion has become a significant concern in the oil and gas industry and one the most commonly used corrosion resistant alloy, 13% chromium stainless steel, has been experimentally investigated in the study. The corrosion behaviour, including corrosion rates, the effect of environmental conditions and the formation of protective films, were examined during the study. A series of experiments was performed using the conventional electrochemical method to study the effects of temperature, pH and exposure time 13% chromium stainless steel in the H2S environment. Electrochemical behaviour was monitored using the polarisation resistance technique, a scanning electron microscope (SEM) equipped with energy dispersive X-ray spectroscopy (EDS) was used to conduct morphological characterization and X-ray diffraction (XRD) was used to study the crystal structure of corrosion products. This study shows that each environmental parameter has a significant impact on corrosion rates and types of corrosion products formed in the H2S environment. 1. Introduction Oil and gas exploration in highly corrosive environments has significantly increased in recent years, making hydrogen sulphide (H2S) corrosion an important topic of research after several pipeline failures and the safety risks associated with this dangerous gas. Corrosion resistance alloys (CRA) are used in the H2S environment, due to the passive film formation along with the selfrepair nature of passive films, but these CRA started corroding once these passive layers stopped forming efficiently . The internal corrosion of the corrosion resistant alloys is controlled by environmental parameters such as temperature, pH value, the concentration of H2S in the environment and its exposure time. A minute change in any of these parameters can cause severe corrosion, causing catastrophic damages leading to the shutdown of the oilfields. The formation and growth of corrosive films on the steel surface are directly dependent on the environmental parameters. In some extreme conditions, the formed corrosion film is not sufficient to protect the underlying steel, which initiates localized corrosion with high corrosion rates, and very little research has been done related to H2S corrosion in the oil industry ,. Another corrosion concern in the industry is the transportation of oil and gas. Traditionally, supply in huge volumes is being done by pipelines for many decades, as a reliable and economical method. To achieve the demand for oil and gas, these pipelines run hundreds of kilometers and corrosion 1 causes the difficulty to maintain the integrity of such large networks. This transportation is commonly in multiphase form, which contains gases such as CO2, H2S, and a few other particles in the transmission pipelines have accelerated the corrosion rate . The corrosion cost has increased to by millions of dollars in recent years . Compared to the number of studies on carbon dioxide (CO2) corrosion, there is a limited amount of experimental work available on hydrogen sulphide (H2S) corrosion, given the safety concerns and protocols necessary for working with hydrogen sulphide gas . In this study different environmental parameters have been used to conduct the experimental work and to study the behaviour of the corrosion resistant alloy. 2. Chemical bath preparation Due to safety concerns associated with H2S gas, an alternative approach which mimics H2S gas was used. The chemical bath used in this alternative approach deposits thin films of iron sulphide, exactly as occurs with real H2S gas,. The reagents listed in Table 1 were mixed with specified concentrations to make the chemical bath. Each reagent has to be mixed with de-ionized water, making three different solutions, and each solution has to be stirred at a speed of 350 rpm for approximately 30 minutes. These three different solutions were mixed and stirred for 2 hours at a speed of 350 rpm so that a homogenous electrolyte solution was achieved. The reaction mechanism involves the release of iron and sulphur ions, which help in the deposition of the iron sulphide (FeS) layer on the working electrode. Table 1 Bath compositions to prepare a chemical bath Serial No. Chemical reagents Chemical formula Concentrations 1 Iron Chloride (Tetra-hydrate) FeCl2.4H2O 0.15M 2 Thioacetamide CH3CSNH2 2M 3 Urea CH4N2O 1M 3. Experimental procedure A conventional three-electrode glass cell setup was used for measuring corrosion rates at different parameters using the polarisation resistance technique, for which a small specimen of steel was used as the working electrode (WE), a graphite rod was used as a counter electrode (CE) and Ag/AgCl/4MKClsat was used as a reference electrode (RE). The working electrode was prepared by machining the 13% chromium steel sample to an approximate dimension of 1cm length and 1cm diameter. Prior to placing the working electrode into the chemical bath, the working electrode specimen was polished using sandpaper of grit sizes P220, P320, P400, P600 and micron 6 after which the specimen was immediately cleaned using de-ionized water and dried. Electrochemical measurements were performed using a potentiostat (Ivium Compactact Potentiostat) monitoring system connected to a computer for data acquisition and also connected to a three-electrode glass cell set up by applying potential to record the generated readings. 2 After the completion of the electrochemical investigation, samples were taken for morphological and crystal structure characterization. Morphological characterization was done using an FEI MLA 650F Scanning Electron Microscope (SEM) for the high-resolution surface, the Scanning Electron Microscope (SEM) was running at 15 kV, low vacuum mode and images were acquired using a Back-scattered Electron detector (BSED). Bruker Xflash SSD X-ray detectors (EDS) were used for the elementary chemical analysis of the corrosion products. The crystal structure of the corrosion products was characterized by X-ray diffraction (XRD) using a Rigaku Ultima IV X-ray diffractometer with a copper X-ray source (Cu-K-α radiation) operating at 40kV and 44mA. The experimental paremeters selected for this study are listed in Table 2. Table 2 Experimental parameters Steel substrate Temperature pH Immersion time 13% Chromium stainless steel 40ᴼC to 80ᴼC 2 to 5 24 Hrs. to 48 Hrs. 4. Results and Discussion 4.1 Effect of temperature on the corrosion behaviour of 13% chromium stainless steel. The polarisation curves of 13% chromium stainless steel at 50ᴼC and 70ᴼC at pH 2 are shown in Figure 1. The corrosion current density (Icorr) at 70ᴼC is 5.711 x 10-5 A/cm2 whereas, the Icorr of the sample corroded at 50ᴼC is 3.34 x 10-5 A/cm2. Figure 1 Polarisation curves of 13% Chromium Stainless steel at temperatures 50ᴼC & 70ᴼC at pH2. The sample corroded at 70ᴼC possesses more ICorr value than the sample at 50ᴼC. The formation of FeS films acts as a protective barrier, forming faster at a lower temperature, the growth of corrosion product hinders the steel from further corrosion. 3 At a higher temperature, the diffusion of ions takes places more quickly and generates weak passive layer on the metals. Furthermore, there is an increase in the flow of the positive charge from the anodic (oxidation) site toward the cathodic (reduction) site, affecting the dissolution of the steel surface, indicating that the 13% Cr. stainless steel corrodes faster at a higher temperature. The corrosion rates of samples at varying temperatures are listed in Table 3. Table 3 The rate of corrosion with respect to a change in temperature S.No. 1 2 Experimental parameters pH2, 50ᴼC pH2, 70ᴼC Corrosion rate (mm/year) 0.3616 0.6014 4.2 Effect of pH on the corrosion behaviour of 13% chromium stainless steel. The pH value of the solution has an enormous impact on the composition of the corrosion products and their passive nature. At a lower pH, the solubility of the solution is very high, which makes the precipitation of iron sulphide (FeS) difficult on the steel surfaces . Due to this, the passive layer formation is minimal and weak, which increases the corrosion rate. This can also be explained by the increased Icorr value. Figure 2 Polarisation curves of 13% Chromium Stainless steel at different pH: 4 and 5 at 80ᴼC. The Icorr recorded at pH 4 is 7.431 x 10-4 A/cm2 and Icorr at pH 5 is 3.543 x 10-4 A/cm2. This demonstrates that the corrosion rate of the steel sample at pH 4 is higher than for the sample at pH 5 also seen in Figure 2. The inhibitive effect due to the formation of iron sulphide layers occurs mostly between pH 3 to pH 5  which explains the corrosion behaviour more precisely at these pH values. Table 4 shows the corrosion rate with repect to change in pH value. 4 Table 4 The rate of corrosion with respect to a change in pH value S.No. 1 2 Experimental parameters pH4, 80ᴼC pH5, 80ᴼC Corrosion rate (mm/year) 7.81 3.73 4.3 Effect of exposure time on the corrosion behaviour of 13% chromium stainless steel. In this case, the experimental parameters are the temperature of 40ᴼC and pH 2 with a change in the immersion time from 0 to 24 hours and 24 to 48 hours. Figure 3 shows that the corrosion rate of an immersion time of 24 hours is higher than the rate at 48 hours. Figure 3 Polarisation curves of 13% Chromium Stainless steel at different immersion times: 24 hours and 48 hours at pH2, 40ᴼC. The Icorr is 1.092 x 10-4 A/cm2 at 24 hours, which is lower than the Icorr of 3.339 x 10-5 A/cm2 at 48 hours.The corrosion rates are different for both immersion times, which can be explained by the weakly formed passive layer . Change in corrosion rates at varying immersion times is explained in Table 5. Table 5 The rate of corrosion with respect to a change in immersion time (or exposure time) S.No. 1 2 Experimental parameters pH2, 40ᴼC, 24 hours pH2, 40ᴼC, 48 hours Corrosion rate (mm/year) 1.217 0.361 4.4 XRD Analysis Figure 4 shows the crystal structure of corrosion products formed on the samples at different conditions, the peaks of the sample corroded at pH2, 50ᴼC shown in Figure 4(a) are matched to be 5 iron, pyrite and iron sulphide with PDF #[98-001-1732], [98-002-0637],[98-001-1763] respectively. Identifying iron (Fe) and pyrite (FeS2) as the cubic crystal structure and iron sulphide (FeS) as orthorhombic crystal structure. In Figure 4(b) the sample was corroded at pH2, 70ᴼC, corrosion products formed on the steel surface are identified as iron (Fe) [00-006-0696], iron sulphide (FeS) [98-001-1763], pyrite (FeS2) [98-002-0637] and greigite [98-000-1180]. These corrosion products are minerals of iron sulphide (FeS) which have been precipitated on the steel surface after an increase in temperature in the H2S environmental parameters ,. The crystal structure of corrosion products formed on the samples at different conditions, the peaks of the sample corroded at pH4, 80ᴼC shown in figure 4(c) are matched to be iron and greigite with PDF #[98-001-9699] and [98-001-1768]. S.N. Smith (2002) reported that the sequential resistance of corrosion products, mainly FeS, formed in the H2S environment are as follows: Mackinawite < Troilite < Pyrrohotite < Pyrite . In Figure 4(d) the sample was corroded at pH5, 80ᴼC, corrosion products formed on the steel surface are identified as iron (Fe) [98-001-9692, and pyrite (FeS2) [98-002-0637]. These corrosion products are precipitated on the steel surface after a change in pH value in the chemical bath solution. 98-001-1732 > Iron (Fe) 98-001-1763 > Iron Sulphide (FeS) 98-002-0637 > Pyrite (FeS2) 98-001-1732 > Iron (Fe) 98-001-1763 > Iron Sulphide (FeS) 98-002-0637 > Pyrite (FeS2) 98-000-1180 > Greigite (Fe3S4) (b) (a) 98-001-9699 > Iron (Fe) 98-001-1762 > Iron Sulphide (FeS) 98-00-1180 > Greigite (Fe3S4) (c) 98-001-9692 > Iron (Fe) 98-002-0637 > Pyrite (FeS2) (d) 6 00-006-0696 > Iron (Fe) 00-006-0696 > Iron (Fe) 00-016-0713 > Greigite (F3eS4) (f) (e) Figure 4 XRD analysis of the corrosion product formed on the steel surface at: (a) 50ᴼC, pH2, (b) 70°C, pH2, (c) 80ᴼC, pH4, (d) 80°C, pH5 (e) 40ᴼC, pH2,24 hours, (f) 40°C, pH2, 48hours. In Figure 4(e) the peaks are matched by the PDF #[00-006-0696], identifying the iron (Fe) as a body centred cubic (BCC) structure, XRD peaks in Figure 4(f)) match the PDF # [00-016-0713] identifying the corrosion product as Greigite (Fe3S4) with a cubic crystal structure; this suggests that the corroded sample after an increase in the immersion time, formed a corrosion product on the steel surface. 4.5 SEM Analysis The SEM analysis was conducted to study the morphological characterization of the corrosion products in different H2S environmental conditions. The corroded sample at pH 2, 50ᴼC have been shown in Figure 5(a). The magnified SEM image shows the layer of pyrite,iron sulphide (FeS) films on the steel surface. The thick corrosion layer observed in the SEM image is cracked, due to the diffusion of the electrochemical reaction at a high temperature. The EDS analysis shows that a high amount of sulphur has lead to the formation of a corrosion layer. In Figure 5(b) the sample was corroded at a higher temperature of 70ᴼC at pH 2. The SEM images show the loose and rough formation of corrosion film due to the increased reactivity in the chemical bath at a significantly higher temperature and lower pH. The EDS analysis shows a higher amount of sulphur. The SEM image is shown in Figure 5(c) is of the sample corroded at a temperature of 80ᴼC at pH 4. The SEM images show a fragile layer of corrosion film, due to the increased reactivity in the chemical bath at high temperature. The EDS analysis shows higher amounts of sulphur. Figure 5(d) shows the SEM image of a corroded sample at pH 5, 80ᴼC. The SEM image shows a high volume of precipitation of the corrosion layer on the steel surface. As the pH values increase, the corrosion product becomes insoluble in the chemical bath, which also increases the rate of precipitation on the passive layer observed on the steel surface, which limits the corrosion reactivity. 7 The past research reports that when the pH value is decreased, the corrosive film becomes depassivated, which results in an unprotected steel surface ,,, in the H2S environment, which rapidly changes the corrosion reactivity In this sample, the immersion time is increased from 24 hours to 48 hours. Figure 5(e) shows the SEM image of sample corroded at a temperature of 40ᴼC at pH 2 and 48 hours. The SEM image shows that a thin layer of corrosion film has formed on the surface. Increase in immersion time decreases the chemical reactivity between the corrosive film and the chemical bath. It allows further precipitation and formation of the passive layer. The EDS analysis is shown in Figure 5(e) shows the chemical composition of the corrosion products, which have a significant amount of iron. SEM image of sample a corroded at an immersion time of 48 hours is shown in Figure 5(f), it is observed that when there is an increase in the immersion time, the volume of precipitation of the corrosion product on the steel surface also increases, forming a thick corrosion layer. (a) (b) 8 (c) (d) (e) 9 (f) Figure 5 SEM images(left side) and EDS analysis images(right side) of the corrosion products formed on the steel surface for (a) pH 2, 50ᴼC (b) pH 2, 70ᴼC, (c) pH 4, 80ᴼC (d) pH 5, 80ᴼC, (e) pH 2, 40ᴼC, 24 hours (f) pH 2, 40ᴼC,48 hours. 5 CONCLUSION The results of this work are important findings with respect to the corrosion behaviour in sour environments. • In an H2S environment, the corrosion rate increases with the increase in temperature but after a significantly higher temperature the effect of temperature lessens. • The corrosion rates decrease with an increase in the pH value and the pH of the environment has a huge impact on the corrosion rate and the formation of protective films on the steel surface. • For a short period of time the corrosion rates decrease with an increase in exposure time, but over an extended period the protective layer becomes weak and starts to corrode the steel beneath the protective film • • The formation of a film on a steel surface is dependent on the pH and temperature of the environment. Lower temperature and higher pH form thick and uniform protective films which eventually decrease the corrosion rate and protect the steel from exposure to the corrosive media. Different types of oxides formed on the surface have different effects on the corrosive resistivity of the steel and the formation of stable oxides lowers the rate of corrosion. ACKNOWLEDGMENT Authors acknowledge the support provided by the Suncor Reservoir Souring Initiative at Memorial University of Newfoundland, Canada. DATA AVAILIBILITY STATEMENT This research work was performed under a ‘Memorial University Disclosure Agreement’. No additional data will be available to public unless it is approved by the university and the funding organisation(s). 10 REFERENCES  J. Fritz and D. H. Russ, “H2S Multiphase Flow Loop: CO2 Corrosion in the Presence of Trace Amounts of Hydrogen Sulfide,” Eng. Technol., November, 2004.  W. Yan, P. Zhu, and J. Deng, “Corrosion behaviors of SMSS 13Cr and DSS 22Cr in H2S/CO2-oil-water environment,” Int. J. Electrochem. Sci., vol. 11, no. 11, pp. 9542–9558, 2016.  A. F. Goncharov et al., “Hydrogen sulfide at high pressure: Change in stoichiometry,” Phys. Rev. B, vol. 93, no. 17, p. 174105, 2016.  G. Xian Zhao, X. Hong Lu, J. Min Xiang, and Y. Han, “Formation Characteristic of CO 2 Corrosion Product Layer of P110 Steel Investigated by SEM and Electrochemical Techniques,” J. Iron Steel Res. Int., vol. 16, no. 4, pp. 89–94, 2009.  S.D. Kapusta, B.F.M. Pots and R.A. Connell, “Corrosion Management of Wet Gas Pipelines,” in Proc. Corrosion, 1999.  R. Heidersbach, “Metallurgy and Corrosion Control in Oil and Gas Production.,” John Wiley and Sons, 2011.  L. Khaksar, G. Whelan and J. Shirokoff, “Electrochemical and microstructural analysis of FeS films from acidic chemical bath at varying temperatures, pH, and Immersion Time,” Int. J. Corros., 2016.  M. Saeed Akhtar, A. Alenad, and M. Azad Malik, “Synthesis of mackinawite FeS thin films from acidic chemical baths,” Mater. Sci. Semicond. Process., vol. 32, pp. 1–5, 2015.  S. N. Smith, “A proposed mechanism for corrosion in slightly sour oil and gas production,” NACE, September, 1993, pp. 2695–2706, 1993.  D. Brondel, R. Edwards, A. Hayman, D. Hill, and T. Semerad, “Corrosion in the Oil Industry,” Oilf. Rev., pp. 4–18, 1994.  H. Ma et al., “The influence of hydrogen sulfide on corrosion of iron under different conditions,” Corros. Sci., vol. 42, no. 10, pp. 1669–1683, 2000.  L. Khaksar and J. Shirokoff, “Effect of elemental sulfur and sulfide on the corrosion behavior of Cr-Mo low alloy steel for tubing and tubular components in oil and gas industry,” Materials (Basel)., vol. 10, no. 4, 2017.  Wei Sun and Srdjan Nesic., “Kinetics of Iron sulphide and Mixed Iron Sulphide / Carbonate scale precipitation in CO2/H2S Corrosion.”  J. Han, Y. Yang, S. Nesic, and B. N. Brown, “Roles of Passivation and Galvanic Effects in,” Corros. 2008, Paper no. 08332, pp. 1–19, 2008.  Hemmingsen T, Hilbert L, and Nielsen L.V, “Assessment of sulphur and H2S corrosion by use of simultaneous ER, galvanic and optical measurements.,” Eurocorr, 2003.  David R.B, “Sodium Sulfides,” Kirk-Othmer Encycl. Chem. Technol., 1997. 11  D. G. Enos and L. L. Scribner, “The Potentiodynamic Polarization Scan" Technical Report 33,” Cent. Electrochem. Sci. Eng., pp. 1–13, 1997.  M. Koteeswaran, “CO2 and H2S Corrosion in Oil Pipelines,” M.S. Thesis, Faculty of Mathematics and Natural Science, University of Stavanger, Norway, June, 2010. 12