liang wei, yucheng zhang, xiaolu pang and kewei gao

Corros Rev 2015; 33(3-4): 151–174

*Corresponding author: Kewei Gao, Department of Materials Physics and Chemistry, University of Science and Technology Beijing, Beijing 100083, China, e-mail: [email protected] Wei and Xiaolu Pang: Department of Materials Physics and Chemistry, University of Science and Technology Beijing, Beijing 100083, ChinaYucheng Zhang: Test and Analysis Center, ShouGang Research Institute of Technology, Beijing 100043, China

Liang Wei, Yucheng Zhang, Xiaolu Pang and Kewei Gao*

Corrosion behaviors of steels under supercritical CO2 conditions

DOI 10.1515/corrrev-2014-0067Received December 28, 2014; accepted April 14, 2015

Abstract: Carbon dioxide (CO2) corrosion at low partial pressure has been widely recognized, but research on supercritical CO2 (SC CO2) corrosion is very limited. By far, investigations on steel corrosion under SC CO2 conditions have mainly focused on the corrosion rate, structure, mor-phology, and composition of the corrosion scales as well as the electrochemical behaviors. It was found in aqueous SC CO2 environment, that the corrosion rate of carbon steel was very high, and even stainless steels (13Cr and high-alloy CrNi steels) were subjected to some corrosion. Inhibitor could reduce the corrosion rate of carbon steels and stain-less steels, but none of the tested inhibitors could reduce the corrosion rate of carbon steel to an acceptable value. Impurities such as O2, SO2, and NO2 and their mixtures in SC CO2 increased the corrosion rate of carbon steel. How-ever, the existing studies so far were very limited on the cor-rosion mechanism of steels in SC CO2 conditions. Thus, this paper first reviews the finding on the corrosion behaviors of steels under SC CO2 conditions, points out the shortcom-ings in the present investigations and finally looks forward to the research prospects on SC CO2 corrosion.

Keywords: carbon steel; corrosion; inhibitor; stainless steel; supercritical CO2.

1 IntroductionCorrosion is an important damage factor in modern industry. In current oil production, the losses caused by corrosion are huge. There are many types of corrosion

existing in the exploitation of oilfields, of which carbon dioxide (CO2) corrosion is a very common type and a very prominent problem hindering the development of the oil and gas industry (Kermani & Smith, 1997; Schmitt, Gudde, & Strobel-Effertz, 1996). CO2 often exists as components of natural gas or oil-associated gas, which has a strong corrosivity on metal materials when dissolved in water. At a certain temperature and pressure, wet CO2 could cause serious corrosion of metal materials, cause pipes and equipment failure, and even cause the fracture of oil tubing steels. Consequently, it can significantly reduce the productive lifetime of oil and gas wells and result in huge economic losses (Kermani & Morshed, 2003; Lopez, Simison, & Sanchez, 2003; Schmitt, 1984).

The term “CO2 corrosion” was first put forward by the American Petroleum Institute (API) in 1925, and until 1943, pipeline corrosion in the Texas oilfield was identified as CO2 corrosion. Since then, a half century later, great progress has been made in understanding the CO2 corrosion rules, and the CO2 corrosion mechanisms under different conditions have also been widely studied (Dugstad, 2006; Gulbrand-sen & Bilkova, 2006; Schmitt & Hoerstemeier, 2006; Smith & Joosten, 2006). However, investigations on CO2 corrosion thus far were mainly performed at low CO2 partial pressures (Nesic, 2007; Nesic & Lee, 2003; Nesic, Postlethwaite, & Olsen, 1996; Palacios & Shadley, 1991; Smart, 1990).

During transportation, CO2 is often compressed to a high pressure state (supercritical conditions) in order to increase density, which makes transportation convenient and brings lower costs (Gale & Davison, 2004; Kruse & Tekiela, 1996). In addition, in some deep oil and gas fields, CO2 pressure and temperature are usually higher than 100 MPa and 120°C, where CO2 is also in its supercritical condition (Wu et al., 2004). Supercritical CO2 (SC CO2) has properties such as low viscosity, high diffusivity, and high compressibility. The solubility of CO2 in water under supercritical conditions is much higher than that under low pressures (King, Mubarak, Kim, & Bott, 1992), so it can cause serious corrosion on metal materials, especially free water existing in the system (Choi & Nesic, 2009; Zhang, Gao, & Schmitt, 2011a).

However, few articles reported steel corrosion under the conditions when CO2 is compressed into high- temperature and high-pressure liquid or supercritical states. The research results published so far on the

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152 L. Wei et al.: Corrosion behaviors of steels under supercritical CO2 conditions

corrosion behaviors of steels under SC CO2 conditions are very limited. Therefore, this paper aims to introduce the present research progress on CO2 corrosion under super-critical conditions and look forward to future research prospects in this field.

2 Review of research progress on SC CO2 corrosion

2.1 Definition, properties, and application of SC CO2

Gaseous CO2 is easily liquefied by compressing it at room temperature. If CO2 is heated and compressed over its critical values (31.1°C and 7.38 MPa), as shown in Figure 1 (Ziomek-Moroz et al., 2012), it will change from gas into the supercritical fluid state. CO2 in the supercritical state has many unique properties, for example, when it is over its critical temperature, CO2 cannot change into gas, no matter how much it is heated; similarly, CO2 cannot change into liquid or solid when it is over its critical pres-sure, even if more pressure is applied. Since CO2 in this condition is different from gas, liquid, and solid, it is called SC CO2.

SC CO2 behaves like gas and can distribute evenly throughout the container. By controlling the pressure, it can achieve the same density as liquid CO2. SC CO2 has a strong ability to penetrate objects, and its capacity to dis-solve objects is much greater than gas, even greater than liquid. Its density is several hundred times higher than

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Figure 1: CO2 phase diagram (Ziomek-Moroz, O’Connor, & Bullard, 2012). Reproduced with permission from NACE International, Houston, TX. All rights reserved.

gas, close to liquid. Its viscosity is equal to gas, but its dif-fusion coefficient is only about 1% of gas and a hundred times higher than liquid. As a result, SC CO2 has strong penetration ability, and the material dissolved in the SC CO2 fluid spreads easily.

As SC CO2 has strong permeability and is capable of dissolving materials, it is often used for extraction. Supercritical fluid extraction technology (SFET) is a kind of chemical separation technology that was developed around the world since the 1970s. It extracts and separates certain components from materials by means of the special physical and chemical properties of supercritical fluid. Compared with traditional extraction techniques, SFET has many advantages, such as extraction of products without or with little organic solvent, lower extraction temperature, better preservation of the biological activity of products, etc. Therefore, SFET is in alignment with today’s pursuit of “return to nature” and is considered as a “green, sustaina-ble technology”. As CO2 is an inert gas, it will not react with other components in the process of extraction. Moreover, its critical temperature is relatively low (31.1°C), and its critical pressure is not high (7.38 MPa), and it is non-toxic, odorless, and non-polluting; therefore, CO2 is often used as a supercritical fluid in the supercritical extraction industry. Environmental pollution-free SC CO2 extraction has become more and more popular and has been widely applied in oil, pharmaceutical, food, cosmetics, flavors and fragrances, biology, environmental, and chemical industries.

2.2 Research progress in the field of SC CO2 corrosion

Although extraction by SC CO2 has been applied for many years, there are few reports about the corrosion caused by SC CO2 on the equipment during the extraction. This could be accounted for the fact that SC CO2 extraction is performed in the absence of water, and extraction usually takes a very short time. In addition, CO2 injection has been used in the oil and gas industry for decades for enhanced oil recovery (EOR) and enhanced gas recovery to increase the lifetime of oil and gas wells, but few investigations have been done on the corrosion of steels under SC CO2 conditions.

2.2.1 The corrosion behaviors of steels under SC CO2 conditions

2.2.1.1 The corrosivity of dry SC CO2

Many experiment results have shown that dry SC CO2 is essentially non-corrosive. In dry SC CO2, the corrosion rate



L. Wei et al.: Corrosion behaviors of steels under supercritical CO2 conditions 153

of carbon steel is very low, especially when the exposure time is very short, and carbon steel shows no corrosion. Beck et al. (2011) used electrochemical impedance spec-troscopy (EIS) technology to study the conductivity of metals in a dry SC CO2 environment and found that the conductivity for dry SC CO2 was 3 × 10-5 S/m, two orders of magnitude lower than SC CO2 saturated with water (7 × 10-3 S/m). This low conductivity indicated that corro-sion in dry and pure SC CO2 was low or nonexistent. Zhang et al. (2011a) found that no corrosion occurred on carbon steels after 96 h in dry SC CO2 at 80°C and 12.5 MPa. The investigation of Russick, Poulter, Adkins, and Sorensen (1996) indicated that there was no trace of any corrosion when C1018 carbon steel was exposed to dry SC CO2 for 24 h at 50°C and 24 MPa. Schremp and Roberson (1973, 1975) and West (1974) also confirmed that in the short-term exposure to dry SC CO2 the corrosion rate of carbon steel was zero. During 200-day experiments at 9–12 MPa and 160–180°C, the corrosion rate of AISI 1080 carbon steel was only in the order of 0.01 mm/year (Propp et al., 1996). A similar result was also observed during 12 years of pipeline service with high pressure dry CO2, and the cor-rosion rate of carbon steels encountered 0.5–2.5 μm/year (Gill, 1985; Newton Jr., 1984). Collier et al. (2013) performed experiments in dry SC CO2 conditions at about 8 MPa and 35°C with a flow velocity of 100 rpm. They revealed that the corrosion rates of 304L and 316L stainless steels were 0.0008 and 0.0012 mm/year, while the corrosion rates of X42 and X60 carbon steels were up to 0.02 mm/year. There-fore, it could be concluded that in dry SC CO2, carbon steels experience little or no corrosion.

2.2.1.2 The corrosivity of SC CO2 with little waterWhen SC CO2 contains a small amount of water, the cor-rosion rate of carbon steel is still very small as long as the water content is less than its solubility limit in SC CO2 at a given temperature. Long-distance CO2 pipelines have been widely used for CO2 EOR projects in the USA alone (∼2400 km in 2001 and ∼5000 km in 2011). From 1990 to 2001, there were only 10 accidents, of which only two associated with corrosion occurred in the CO2 pipelines (Gale & Davison, 2004). The corrosion rate of these pipe-lines for transporting CO2 in the US was 0.00025–0.0025 mm/year (Cole, Corrigan, Sim, & Birbilis, 2011), a very low corrosion rate. Such CO2 pipelines in the USA oper-ated under strict limitations on contaminants such as no free water, i.e. water content ≤ 600 ppm (Connell, 2005), which was demonstrated as the critical value of water content to induce significant corrosion (McGrail, Schaef, Glezakou, Dang, & Owen, 2009). In addition, in Alberta,

Canada, the pipelines (20–200 km) that transported CO2 and H2S to injection sites had no significant corrosion for two decades of operation (Bachu & Gunter, 2005). The study of Schremp and Roberson (1973, 1975) showed that X60 pipeline steel was found to be corroded in a rate of < 0.001 mm/year at 14 MPa with 800–1000 ppm H2O. Zhang et al. (2011a) also found that when 600 g SC CO2 contained 1.5 g H2O, the corrosion rates of carbon steels at 80°C after 96 h were 0.0036 mm/year (C75) and 0.0053 mm/year (X65), respectively. Furthermore, the investigations of Choi and Nesic (2011b), Farelas, Choi, and Nesic (2012), Dugstad, Morland, and Clausen (2010), Dugstad, Clausen, and Morland (2011a), Dugstad, Halseid, Morland, and Clausen (2011b) and Hua, Barker, and Neville (2014) also indicated that when water content was kept below its solubility limit in the SC CO2 phase, no corrosion has taken place. However, Ayello, Evans, Thodla, and Sridhar (2010b) used the corrosion current from the polarization curves to calculate the corrosion rates, and found that when water content was 100 ppm the corrosion rate was 1.2 mm/year, but it was ascribed to the residual water on the carbon steel surface. Field experiences and laboratory experiments indicated that as long as the water content contained in the SC CO2/H2O system was below the solubility limit at the correspond-ing pressure and temperature, carbon steels were not corroded during the transporting CO2 process.

However, when the water content rises and exceeds its solubility limit in SC CO2, the corrosion rate of carbon steel will rapidly increase. As a comparison, a further study was made by Zhang et al. (2011a) on the corrosion behavior of carbon steel in SC CO2 containing more H2O. When 600 g SC CO2 contained 100 g H2O, the corrosion rates of carbon steel at a temperature range of 50–130°C after 96 h were 0.014–0.043 mm/year, which were nearly 10 times higher than those containing 1.5 g H2O. Russick et al. (1996) also reported that significant corrosion attack occurred at 24 MPa CO2 and 50°C as soon as the water content exceeded the solubility limit. In addition, there was a case in the study of Newton Jr. and Mcclay (1977) that due to insufficient drying of liquid CO2, H2O accumu-lated in the low-lying parts of the pipelines and resulted in the corrosion of steels and subsequently the leakage accident.

This is because, when the water content is less than its solubility in SC CO2, all water dissolves in SC CO2; consequently, there is no free liquid water phase in the CO2/H2O system, and hence the corrosion rate is low. Inversely, when the water content exceeds its solubil-ity in SC CO2, except for a small part of H2O dissolving in SC CO2, most of the water presents as a free liquid phase




in the CO2/H2O system, which is saturated with SC CO2, and the corrosion rate of carbon steel can increase dra-matically. Corrosion rate data from different researchers (Ayello, Evans, Sridhar, & Thodla, 2010a; Ayello et al., 2010b; Cabrini, Lorenzi, Pastore, & Radaelli, 2014; Choi & Nesic, 2010, 2011b; Choi, Nesic, & Young, 2010; Collier et al., 2013; Dugstad, Morland, & Clausen, 2011c; Dugstad, Halseid, & Morland, 2013; Hua et al., 2014; Russick et al., 1996; Sim, Bocher, Cole, Chen, & Birbilis, 2014a; Thodla, Francois, & Sridhar, 2009; Zhang et al., 2011a) summa-rized in Table 1 show the corrosion extent of steels with various water contents in SC CO2 or aqueous CO2 environ-ments. Based on the comparison between these corrosion data, the following conclusions could be drawn:

– Cr-containing carbon steels and stainless steels were corroded slightly (normally < 0.001 mm/year), or there were no signs of corrosion on them.

– When the water content in SC CO2 was less than its solubility limit (undersaturated), carbon steels were corroded slightly, general below 0.1 mm/year.

– When at water-saturated SC CO2 conditions, the general corrosion rates of carbon steels dramatically increased, normally above 0.1 mm/year, and even up to 1 mm/year.

– No matter if saturated or undersaturated with water in an SC CO2-rich environment, pitting corrosion rates were all much higher than general corrosion rates, indicating that pitting corrosion was the main corro-sion type in an SC CO2-rich environment.

– Traditional electrochemical techniques could not exactly reflect the actual corrosion rates of carbon steels in an SC CO2-rich environment. The corrosion rates calculated by electrochemical techniques were much larger than those calculated by weight loss measurement.

2.2.1.3 The corrosivity of water phase saturated with SC CO2

As the water content in SC CO2 rises further, the phase structure of the CO2/H2O system will gradually change from “CO2-rich phase” to “H2O-rich phase”. When the water content is high in SC CO2, the main phase in the CO2/H2O system is H2O, SC CO2 dissolved in H2O.

To compare the difference in corrosion rates of carbon steels in SC CO2 environment between “CO2-rich” and “H2O-rich” phases, Choi and Nesic (2009) investi-gated the corrosion behaviors of carbon steel exposed in water-saturated SC CO2 and SC CO2-saturated water for 24 h at 50°C and 4, 6, and 8 MPa. They found that in both corrosive medias the corrosion rates were not

significantly dependent on the CO2 pressure. In the water-saturated SC CO2 (CO2-rich phase), the corrosion rate was about 0.4 mm/year, while in the SC CO2-satu-rated water (H2O-rich phase), the corrosion rate was about 20 mm/year.

It can be interpreted that the solubility of H2O in SC CO2 was very small (King et al., 1992), when no water phase is available to dissolve iron ions or iron com-pounds (like iron carbonate), the acid reactions stop (or retard significantly) as soon as the surface is covered with a barrier film consisting of metal compound; therefore, in “CO2-rich” system, the corrosion rate of carbon steel was very small. However, the solubility of SC CO2 in H2O was much higher than that at low CO2 pressure (Choi & Nesic, 2009; King et al., 1992); as a result, carbon steel suffered serious corrosion in the “H2O-rich” system. The corrosion rates of carbon steels in water- saturated SC CO2 system and CO2-saturated water system have been recorded by many researchers, as shown in Figure 2 (Cabrini et al., 2014; Choi & Nesic, 2010, 2011b; Choi et al., 2010; Seiersten, 2001; Zhang et al., 2011a). It can be found that the corrosion rate in “H2O-rich” systems was almost 100 orders of magnitude higher than that in “CO2-rich” systems.

Moreover, in the water saturated with SC CO2 environ-ment, not only did carbon steel experience severe cor-rosion, but also Cr-containing steels or stainless steels showed more serious corrosion than that under low CO2 pressure condition. The experimental results of Zhang et al. (2011a) showed that the corrosion rates of carbon steels at 50–130°C in water saturated with SC CO2 after 96 h of exposure were 5–15 mm/year and encountered localized corrosion with a maximum pit depth of 95 μm. Under the same conditions, the corrosion rates of 13Cr stainless steel were 0.3–0.8 mm/year, and even duplex steel and 904L stainless steel showed more than 0.1 mm/year of corrosion rate at 110°C. Seiersten (2001) found that the corrosion rate of 0.5Cr steel in 1% NaCl solution was higher than X65 carbon steel at 9.5 MPa and 40°C after 150–300 h exposure.

Under SC CO2 conditions, the NORSOK (2005) and KSC models (Nesic, Nordsveen, Nyborg, & Stangeland, 2001), which are often used to predict the corrosion rate of steel in CO2 environment, are no longer applicable. For example, in the study of Seiersten (2001), the corrosion rates of X65 and 0.5Cr carbon steels in water saturated with SC CO2 at 7.5–9 MPa and 40°C ranged from 1 to 6 mm/year; however, the calculated corrosion rates according to the NORSOK and KSC models were 17 and 10 mm/year, respectively. The predicted values by means of the two models are signifi-cantly higher than the measured ones.




Table 1: Summary of corrosion rate data of steels under SC CO2 conditions.

No. P (bar) T (°C) H2O (ppmv) Type of steel t (h) Flow Corrosion rate (mm/year)

Refs.

1 80 40 244 C-steel 168 Static 0.08 Sim et al., 2014a2 488 0.07 3 732 0.06 4 976 0.08 5 1220 0.08 6 3660 0.08 7 14,640 0.11 8 61,000 0.17 9 1,22,000 0.11 10 80 40 244–1,22,000 C-steel 168 Static Pit Cor. rate:∼0.62 11 80 50 Sat(34,000 ppm) X65 14, 24, 48 Static 0.024–∼0.1 Hua et al., 201412 80 35 Sat(34,000 ppm) X65 14, 24, 48 Static ∼0.1 13 80 50 700 ppm X65 48 Static No corrosion 14 1600 ppm No corrosion 15 2650 ppm 0.014 16 3400 ppm ∼0.024 17 80 35 300 ppm X65 48 Static 0.004 18 700 ppm 0.005 19 1200 ppm 0.012 20 1770 ppm 0.028 21 2800 ppm 0.068 22 3437 ppm ∼0.1 23 80 50 2650 ppm X65 48 Static Pit Cor. Rate: 0.2 24 80 50 3400 ppm X65 48 Static Pit cor. Rate: 1.4 25 80 35 700–3437 ppm X65 Static Pit Cor Rate: 0.3–0.9 26 79.6–82 35 10 g SS: 304L, 316L

C-Steel: X42,X60 120 100 rpm SS: 0.0005–0.0008

C Steel: 0.007 Collier et al., 2013

27 79.6–82 35 100 g Saturated 120 100 rpm SS: 0.0005–0.002C-Steel:0.01

28 76.9 35 100 g Saturated 110 Static SS: 0.002C-steel: 0.02

29 80 50 650 (undersat) X65 24 Static No corrosion Choi & Nesic, 2011b30 80 50 3310 (sat) X65 24 Static 0.38 Choi & Nesic, 2010,

2011b; Choi, Nesic, & Young, 2010

31 80 50 10 g (Saturated) X65 24 Static 0.4–1 Choi & Nesic, 2010; Choi, Nesic, & Young, 2010

32 75.8 40 244 C steel 5 Static 1.2 Ayello et al., 2010a, b; Thodla et al., 2009

33 2440 2.3 34 4880 2.5 35 79 31 244 C steel 5 Static 1.1 Thodla et al., 200936 2440 2.5 37 95–182 50–130 100 g (saturated) C steel 96 995 0.014–0.043 Zhang et al., 2011a38 Cr containing steel < 0.001 39 100 20 1220 X65 720 Static No corrosion Dugstad et al., 2011c40 100 10 50v% X65 312 Static 0.5 41 20 336 0.8 42 50 336 0.5 43 50 336 2.7 44 20 72 1.1 45 100 25 488, 1222 X65 336 3 rpm 0 Dugstad et al., 201346 125 80 1.5 g 38Mn6/C75 96 995 0.0036 Zhang et al., 2011a47 X65 0.0053 48 Cr containing steel No corrosion 49 123–146 25–60 Saturated X65 48–400 180 rpm 0.01–0.1 Cabrini et al., 201450 240 50 40 g (Saturated) 24 Static Not given Russick et al., 1996




2.2.2 The influence factors on corrosion behaviors of steels under SC CO2 conditions

2.2.2.1 Effect of temperatureAt low CO2 partial pressure, the main effects of temperature on the CO2 corrosion of steels are changing the solubility of CO2 and subsequently the process of cathodic corrosion reaction rate and mass transfer rate, and are altering the structure and characteristics of the corrosion scale (Gao et al., 2008; Nazari, Allahkaram, & Kermani, 2010; Waard, Lotz, & Milliams, 1991; Yin, Feng, Zhao, Bai, & Lin, 2009; Yu et al., 2005). This is because at low temperatures the activity of the reactants is low, which results in a small reaction rate constant. As the temperature increases, the activity of the reactants increases, and thereby the corro-sion rate increases. But when the temperature continues to increase, a dense and protective corrosion scale can form on the substrate surface, which hinders the transmission of media. As a consequence, the corrosion rate decreases. Overall, CO2 corrosion rate, as a function of temperature, first increases and then decreases, with a maximum value in the middle temperatures (Ikeda, Ueda, & Mukai, 1984).

However, under SC CO2 conditions, the variation rule for corrosion rate as a function of temperature is still in dispute. By studying the corrosion behaviors of carbon steels and stainless steels in water saturated with SC CO2 at 50, 80, 110, and 130°C, Zhang et al. (2011a) and Zhang, Pang, Qu, Li, and Gao (2012) found that the variation ten-dency of corrosion rate with temperature in SC CO2 envi-ronment was similar with that at low CO2 pressures. As the temperature increased, the corrosion rate of carbon steels

Figure 2: Comparison of corrosion rates of carbon steels between water-saturated SC CO2 phase and CO2-saturated water phase (Cabrini et al., 2014; Choi & Nesic, 2010, 2011b; Choi et al., 2010; Seiersten, 2001; Zhang et al., 2011a).

firstly increased and then decreased, and the maximum corrosion rates in SC CO2 and low CO2 pressure environ-ments were both obtained at 80°C. However, the maximum corrosion rates for stainless steels were obtained at 110°C. Zhang, Pang, Qu, Li, and Gao (2011c) also investigated the relationship between the corrosion rate of X65 steel and the fracture toughness (KIC) of CO2 corrosion product scale with the variation of temperature in an SC CO2 environ-ment, and found that the lowest fracture toughness was obtained at 80°C, consisting of the highest corrosion rate. They established a liner relationship between the corro-sion rate of X65 steel and 1/KIC

3/2, as presented in Equation (1). Figure 3 shows the comparison between the measured corrosion rate by weight loss measurement and the calcu-lated corrosion rate according to Equation (1); these two kinds of corrosion rates had good consistency.

-3/ 2

IC

3.25 0.908CRK

=

(1)

The study of Cui, Wu, Zhu, and Yang (2006), however, indicated that in water saturated with SC CO2 environ-ment, the corrosion rates of carbon steels (P110, N80, and J55) decreased with temperature increasing from 60 to 150°C, and even up to 150°C, there was still no peak appearing. The corrosion rate decreased rapidly with increasing temperature from 60 to 90°C and slowly from 90 to 150°C. Corrosion rates were from 2–3 mm/year at 60°C down to 0.5–1.0 mm/year at 150°C. Wu et al. (2004) used EIS to investigate the properties of surface scale on carbon steel exposed in water saturated with SC CO2 at 8.274 MPa from 60 to 150°C and found that the diameter of the high-frequency capacitance semicircle increased dramatically with the increase of temperature (as shown in Figure 4) and demonstrated that the protectiveness

Figure 3: Comparison between the measured and calculated cor-rosion rates of X65 steel according to Equation (1) (Zhang et al., 2011c). Copyright permission from Elsevier.




it showed a linear increase relationship by log-log. The investigation of Li, Zhou, and Xue (2012) also indicated that the average corrosion rate of 110S steel presented an increasing trend with the increasing CO2 partial pressure in CO2/H2S mixture environments at 130°C and 9 MPa H2S partial pressure. The corrosion rate at 8 or 10 MPa CO2 partial pressure (SC CO2) was nearly two times higher than that at below 4 MPa, which also demonstrated that the corrosion rate in SC CO2 condition was higher than that at low CO2 partial pressure.

However, Choi and Nesic (2011a) found that the increase of CO2 partial pressure did not significantly increase the corrosion rate of carbon steel. The results showed that the corrosion rates of carbon steel exposed in CO2-saturated water with different CO2 partial pressures

of surface scale improved significantly with increasing temperature, so the corrosion rate decreased.

Azuma, Kato, Yamashita, Miyashiro, and Saito (2013) studied the corrosion of J55 and N80 steel in water satu-rated with SC CO2 at 50 and 70°C. They reported that the corrosion weight loss of J55 steel at 50°C was larger than that at 70°C between 100 and 1000 h of immersion, while the weight loss of N80 steel at 50°C was lower than that at 70°C for 100 h of immersion and then was similar up to 1000 h of immersion.

2.2.2.2 Effect of pressureThe mutual solubility of water and CO2 has been widely investigated by numerous researchers (Bamberger, Sieder, & Maurer, 2000; Bruusgaard, Beltran, & Servio, 2010; Fu, Liu, & Yang, 2009; Mohamed, Nor, & Suhor, 2011; Pappa, Perakis, Tsimpanogiannis, & Boutsas, 2009), and the solubility of CO2 in water with CO2 partial pressure calcu-lated by Spycher, Pruess, and Ennis-King (2003) and Choi and Nesic (2009, 2011a) is shown in Figure 5. It revealed that the solubility of CO2 and H2CO3 increased with the increase of CO2 partial pressure. According to the study of Zhang et al. (2012), the corrosion mechanism of carbon steel between low CO2 partial pressure and SC CO2 was basically the same, while the corrosion rate in SC CO2 con-dition was much higher than that at low CO2 partial pres-sure (Zhang et al., 2011c), especially at the initial period of corrosion (Zhang et al., 2012). This is because with the increase of CO2 partial pressure, the concentration of H2CO3 increased, which accelerated the cathodic reactions and then increased the corrosion rate. DeBerry and Clark (1979) studied the relationship between corrosion rate and CO2 pressure in the context of EOR and found that

11,00010,000

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00

- Im

ag (

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.cm

2 )

5000 10,000 20,00015,000

Real (ohm.cm2)

60°C

90°C

120°C

150°C

Figure 4: EIS spectra of surface scales on carbon steel formed at 60, 90, 120, and 150°C in static simulated produced water saturated with SC CO2 at 8.274 MPa (Wu et al., 2004). Copyright permission from Elsevier.

0.035

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45°C

65°C

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Mol

e fr

actio

n of

CO

2H

2CO

3 co

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/l)

Figure 5: Solubility of CO2 and H2CO3 in water as functions of pressure and temperature (Choi & Nesic, 2009). Reproduced with permission from NACE International, Houston, TX. All rights reserved.




(4, 6, and 8 MPa) at 50°C after 24 h were all in the range of 18–20 mm/year. Seiersten and Kongshaug (2005) used the linear polarization resistance (LPR) technique to measure the corrosion rate of X65 carbon steel with CO2 partial pressure at 50°C, as presented in Figure 6. With or without inhibitor (monoethylene glycol [MEG]), the maximum value of corrosion rates was reached at gaseous CO2 condition. The corrosion rate reached the maximum value at 4 MPa (gaseous CO2 condition) without MEG and was much larger than that at 8 MPa (SC CO2 condition). Lin, Zheng, Bai, and Zhao (2006) studied the effect of CO2 partial pressure on the corrosion rate of three steels in CO2-saturated solution at 90°C and found that the corrosion rates at subcritical condition (6.89 MPa) were larger than at supercritical condition (10.34 MPa). They proposed that this is ascribed to the inhibiting function of SC CO2 during CO2 corrosion.

The investigation by Azuma et al. (2013) showed that the weight loss of J55 steel exposed in 0.5 m NaCl solu-tion at 50°C after 100 h at 18 MPa was larger than that at 8 MPa, while the weight loss at 5 MPa was larger than that at 18 MPa at 70°C. Choi, Magalhaes, Farelas, Petrobras, and Nesic (2013) investigated the corrosion rate of carbon steel with CO2 partial pressure (4, 8, and 12 MPa) at 65 and 90°C by weight loss measurement and electrochemical technique. The corrosion rates at three different CO2 partial pressures at 65°C were all about 5.5 mm/year at the initial stage and increased up to 24 h and then stayed constant. As shown in Figure 7A, after 43 h of immersion, the corro-sion rate showed a larger value at higher pressure. At 90°C (Figure 7B), however, the corrosion rates for three different pressures all increased before 7 h of exposure, and higher pressure resulted in higher corrosion rate. Subsequently,

Figure 6: Corrosion rates of X65 carbons steel in CO2-saturated water with/without 50 wt% MEG at 50°C (for the data see Seiersten & Kongshaug, 2005).

14

12

4 MPa8 MPa12 MPa

4 MPa8 MPa12 MPa

10

Cor

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ate

(mm

/yea

r)C

orro

sion

rat

e (m

m/y

ear)

8

6

4

2

0 100

30

25

15

20

10

5

0

20 30 40 50

Time (h)

0 10 20 30 40 50

Time (h)

A

B

Figure 7: Variations of corrosion rate (A, 65°C; B, 90°C) of carbon steel with immersion time at different CO2 partial pressures (Choi et al., 2013). Reproduced with permission from NACE International, Houston, TX. All rights reserved.

the corrosion rates all rapidly decreased and were lower than 1 mm/year; however, it showed a higher value at lower pressure, which was contrary to the results at 65°C. The decrease of corrosion rate for three different pressures at 90°C was attributed to the formation of protective FeCO3 scale after 7 h. Meanwhile, it is worth noting that localized corrosion occurred at 90°C. Similar results were also found in the study of Suhor, Mohamed, Muhammad Nor, Singer, and Nesic (2012), in which the corrosion rates decreased with the increase of CO2 partial pressure. They claimed that due to the formation of the protective FeCO3 scale above 7 MPa the corrosion rate decreased. On the other hand, although FeCO3 was observed on the steel surface below 4 MPa, the corrosion rate stayed constant with increasing time.




A similar phenomenon could also be observed from the studies of Cui et al. (2006) and Li et al. (2006). Cui et al. (2006) studied the corrosion behaviors of low-alloy

2.2.2.3 Effect of immersion timeIn general, the CO2 corrosion rate is relatively high in the initial corrosion process because the metal surface directly contacts with the corrosive medium. As corro-sion progresses, a corrosion scale can gradually form on the metal surface. Under the protection of the corrosion scale, the corrosion rate slows down. The same rule is also observed in SC CO2 corrosion.

By studying the corrosion behaviors of carbon steels under SC CO2 conditions between 24 and 120 h of immersion, Choi and Nesic (2009, 2010) found that when the immersion time was 24 h, the corrosion rate was only the initial corro-sion rate. With the increase of immersion time, the sample surface gradually formed a layer of corrosion scale, which induced the corrosion rates to decrease significantly. The initial scale formed on steel had high internal stress and a poor cohesion with the metal substrate; therefore, it was prone to cracking or spalling off (as shown in Figure 8).

Zhang et al. (2011c) investigated the variation for cor-rosion rate of X65 steel with the extent of immersion time in water saturated with CO2 at 80°C and 9.5 MPa. As shown in Figure 9, before the first 2 h of immersion, the corro-sion rate of X65 slightly decreased, no scale was observed on the steel surface, and corrosion rate was kept at a rela-tively high level (about 28 mm/year). From 2 to 50 h, the corrosion rate decreased dramatically. Correspondingly, a FeCO3 corrosion scale formed at this stage (Figure 10A) and became denser with the increase of immersion time. After 96 h, the corrosion rate was constant, and a dense corrosion scale was observed on the steel surface, which protected the steel effectively, as shown in Figure 10B.

Figure 8: SEM image of the corroded surface of X65 steel exposed in water saturated with SC CO2 for 24 h at 50°C and 8 MPa (Choi & Nesic, 2009). Reproduced with permission from NACE International, Houston, TX. All rights reserved.

A

B

Figure 10: Surface morphology of corrosion scale formed on X65 steel immersed in CO2-saturated water at 80°C and 9.5 MPa: (A) 7 h; (B) 168 h (Zhang et al., 2011c). Copyright permission from Elsevier.

Figure 9: Corrosion rate of X65 steel immersed in CO2-saturated water at 80°C and 9.5 MPa for various immersion time (Zhang et al., 2011c). Copyright permission from Elsevier.




carbon steels (J55, N80, and P110 steel) in CaCl2 solution at 90°C and 8.274 MPa with different immersion times and found that the corrosion rate decreased with the increase of immersion time. During the first 50 h, the cor-rosion rate decreased sharply and then declined slowly. After 100 h, the corrosion rate was basically constant. With the increase of immersion time, the protective cor-rosion scale gradually formed on the steel surface, which mainly consisted of (Fe, Ca) CO3 and a certain amount of α-FeOOH. The study of Li et al. (2006) indicated that in the initial 4 h, the corrosion rate was very high (19.4 mm/year) and rapidly decreased to 4.83 mm/year at 8 h. The cor-rosion rate increased again between 8 and 24 h and was up to 7.22 mm/year at 24 h and subsequently decreased to 0.446 mm/year at 144 h. The corrosion scale rapidly formed between 4 and 8 h of immersion, but this scale was very loose. From 48 to 144 h, the FeCO3 scale gradu-ally changed into a fine compound scale consisting of (Fe, Ca) CO3, Fe2Ca2O5, and CaCO3, which covered the steel substrate well and had good protectiveness.

Choi et al. (2013) used an electrochemical technique to calculate the corrosion rate of carbon steel with the increase of immersion time in the SC CO2 environment. They found that the corrosion rate at 65°C firstly increased and then was kept constant after 43 h, and no FeCO3 scale but a Fe3C layer with no protectiveness was observed on the steel surface, which resulted in the increase of cor-rosion rate. A similar phenomenon was also observed in the study of Hassani et al. (2014). The corrosion rates of carbon steel and 5Cr steel were all high (about 20 mm/year for carbon steel and about 7 mm/year for 5Cr steel), which increased at the initial corrosion period and then kept constant after 6 h. These high corrosion rates are ascribed to the presence of Fe3C on carbon steel and the crack of corrosion scale on 5Cr steel. However, the corrosion rate of 13Cr steel decreased firstly and then was kept at a lower value (about 0.1 mm/year). Choi et al. (2013) found that the variation of the corrosion rate of carbon steel with time at 90°C was different with that at 65°C, as shown in Figure 7. Due to the formation of protective FeCO3 at 7 h, the corro-sion rate rapidly decreased; this was in alignment with the observation of Suhor et al. (2012).

Pfennig and Kranzmann (2012) and Pfennig, Wiegand, Wolf, and Bork (2013) compared the corrosion rate of 42CrMo4 and X46Cr13 steels after 8000 h of exposure in aquifer brine water and SC CO2 phase at 60°C and 10 MPa; the average corrosion rates with the increase of exposure time as well as the depth of pits on these two kinds of steels are shown in Figure 11A. The corrosion rates of two steels slightly decreased with the increase of exposure time, which were about 0.1–0.2 mm/year after 700 h exposure

1.0

X46Cr13_supercritical

X46Cr13_liquid

42CrMo4_supercritical

42CrMo4_liquid

X46Cr13_vapor

X46Cr13_liquid

42CrMo4_vapor

42CrMo4_liquid

0.8

A

B

0.6

0.4

0.2

0.0

800

700

600

500

400

300

200

100

0

0 2000

20001000

Max

imum

pen

etra

tion

dept

h (µ

m)

Cor

rosi

on r

ate

(mm

/yea

r)

4000

4000

6000

Exposure time in h

Exposure time in h

8000

8000

Figure 11: Comparison of corrosion rates (A) and penetration depths of pits (B) of 42CrMo4 and X46Cr13 steels after exposed in aquifer brine water at 60°C and 10 MPa for 8000 h (Pfennig & Kranzmann, 2012; Pfennig et al., 2013). Copyright permission from Elsevier.

and decreased to 0.01–0.02 mm/year after 8000 h expo-sure. However, as shown in Figure 11B, the penetration depth of two steels overall increased with exposure time.

These findings indicated that the short-term corrosion test can only give very limited information on the corro-sion behaviors of steels in SC CO2 environments, because as the corrosion progresses, the protective scale can form on the metal surface, which induces the corrosion rate to significantly decrease.

2.2.2.4 Effect of crude oilCrude oil is hard to dissolve in water; therefore, in a crude oil/water/CO2-mixed emulsion system, water usually dis-perses in an oil phase emulsion. Moreover, crude oil can prevent the steel surface from infiltrating by water and thus greatly reduces the corrosion rate. The greater the vis-cosity of the emulsion, the more stable its property is, and its ionic conductivity is thus worse and results in lower average corrosion rate. As the water content in oil-water medium increases, emulsion becomes unstable. The water




corrosion rate of J55 steel increased rapidly with the water cut between 30% and 75%, and during this immersion period the emulsion was changing from water-in-oil to oil-in-water emulsion; when water cut was between 75% and 100%, stable oil-in-water emulsion formed and the corro-sion rate of J55 steel increased significantly, while localized corrosion expended to mesa corrosion; when the water cut was 100%, J55 steel suffered serious uniform corrosion due to the completely and homogeneous coverage of the strong corrosive solution. The corrosion rate of J55 steel in SC CO2/water system reached up to 2.03 mm/year.

Overall, the critical point of water cut from water-in-oil to oil-in-water is between 30% and 75% in SC CO2/oil/water system. Below this area, the system is in a stable water-in-oil state, oil covers the steel surface, and the cor-rosion rate slightly increased. When the water cut exceeds 75%, the system is in a stable oil-in-water state, water saturated with SC CO2 completely covers the steel surface, and the lower pH value results in the higher corrosion rate, which increases significantly with the increasing water cut. Between 30% and 75% water cut, the emul-sion is unstable, and oil and water intermittent wets steel surface; therefore, localized corrosion occurs.

2.2.2.5 Effect of inhibitorBased on the results of Choi and Nesic (2009), Zhang et al. (2011a), and Cui et al. (2004), it was obvious that water phases saturated with SC CO2 were very corrosive to carbon steels, as well as stainless steels. The corrosion rates of carbon steels could be more than 10 mm/year, and localized corrosion occurred, and even the corrosion rates

droplets dispersed in the oil phase start to polymerize and infiltrate the metal surface. As a result, the corrosion rate increases rapidly (Craig, 1996). The crude oil/water ratio in CO2 corrosive system significantly influenced the corrosion rate of steels. The study of Carew, Al-Sayegh, and Al-Hashem (2000) indicated that the corrosion rate of carbon steel gradually increased with the increasing water cut in CO2/oil/brine solution containing 80% CO2 and 20% H2S (total pressure ∼20 MPa and temperature at 70 and 90°C). The corrosion rate was nearly constant between 20% and 30% water cut, increased rapidly from 30% to 40% water cut, and then slowly increased until 100% water cut.

Cui, Wu, Li, Zhu, and Yang (2004) investigated the relationship between corrosion rate and water cut in the water/oil mixture saturated with SC CO2 at 80°C and 8.274 MPa and found that the corrosion rates of all tested carbon steels (J55, N80, and P110) increased smoothly from 1 to 2 mm/year between 30% and 50% but increased sharply when the water cut increased from 50% to 70% (from 2 to about 7 mm/year). When the water cut in the mixture was 100% (without crude oil), the corrosion rate exceeded 12 mm/year. A water cut of 50% in the mixed system was considered as the critical point of CO2 cor-rosion under the applied conditions, because a 50% water cut was the switch point of the flow structure from water-in-oil to oil-in-water. The flow structure completely changed into oil-in-water state while the water cut in the mixture was over 50%. Farelas, Choi, Nesic, Magalhaes, and Andrade (2013b) also argued with this view that the transition point from water-in-oil state changing to oil-in-water state was 50%. There was no corrosion attack observed with 0% water cut, and below 50% water cut, the corrosion rate of carbon steel slightly increased with the increase of water cut, while once the water cut exceeded 50%, the corrosion rate increased significantly. However, no localized corrosion was observed in the study of Farelas et al. (2013b) for different water cuts.

Sun, Sun, Wang, Wang, and Liu (2014) studied the corrosion rate and corrosion types of carbon steel J55 with different water cuts at 10.2 MPa and 76°C in SC CO2/oil/water system and also found that after 480 h of immer-sion the average corrosion rate increased with the water cut (Figure 12). The corrosion mechanism of J55 steel in SC CO2/oil/water system can divide into five types: J55 steel was barely corroded under pure crude oil conditions, and its average corrosion rate was only 0.0003 mm/year; the corrosion rate of J55 steel smoothly increased with water cut from 0% to 30% (but was below 0.1 mm/year), and uniform corrosion was observed during this process due to the formation of stable water-in-oil emulsion; while local

2.4

2.0

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1.2

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0.0-10 10 20 30 40 50 60 70 80 90 100 110

Water cuts (%)

0

Ave

rage

cor

rosi

on r

ate

(mm

/yea

r)

I II III IV V

Figure 12: Partition graph of the average corrosion rate of J55 steel with the change of water cut in SC CO2/oil/water system (Sun et al., 2014). Copyright permission from Acta Metallurgica Sinca.




of 13Cr steel could reach up to 0.8 mm/year. Furthermore, as summarized in Table 1, when SC CO2 was saturated with water, the corrosion rates of carbon steels were all above 0.1 mm/year. Such a high corrosion rate is not acceptable in the practical industrial production or CCS process, so the application of inhibitor is very necessary when steels are served in SC CO2 environments.

The effect of corrosion inhibitors has been widely studied in the oil and gas production, and these experi-ments were normally conducted at low CO2 partial pressure or other corrosive environments, which were summarized by Sim, Cole, Choi, and Birbilis (2014b) and Li et al. (2014). However, investigations so far focusing on the effect of inhibitor on the corrosion behavior of steels under SC CO2 conditions are very sparse. Seiersten and Kongshaug (2005) found that the corrosion rate of X65 could be reduced two to three times in the presence of 50% MEG, which was because MEG could prevent the formation of CO2 hydrates. With the help of a film formed by inhibitor, the corrosion rates could be reduced. Thodla et al. (2009) also confirmed that a mono ethanol amine (MEA) inhibitor could reduce the corrosion rate of carbon steel at 31°C and 7.8 MPa.

Nevertheless, it is obvious that the experimental tem-perature and pressure in the studies of Seiersten et al. (2004) and Thodla et al. (2009) were very close to the CO2 critical temperature 31.1°C and critical pressure 7.38 MPa (Seiersten: 50°C, 8 MPa; Thodla: 31°C, 7.8 MPa). Precisely speaking, these temperatures and pressures were near the boundary between supercritical state and gas or liquid state (or in the transition zone where liquid or gas CO2 changes into the supercritical state). When the tempera-ture and pressure of CO2 are much higher than its critical temperature and pressure (namely, a wide range of SC CO2 states), whether MEG and MEA still behave, inhibition corrosion and inhibitor efficiency are better than that at low CO2 partial pressures, need to be further investigated.

In order to further study the inhibitor effect at a wide range of temperatures and pressures of CO2 (supercritical conditions), Zhang, Gao, and Schmitt (2011b) studied the corrosion behaviors of carbon steels and stainless steels under SC CO2 conditions at 50–130°C and 9.5–21.5 MPa in the presence of different inhibitors (two types of oleic acid-based imidazolines 18-OH and 18-NH, hexadecenyl succinic anhydride, and hexadecyltrimethylammonium bromide [HTA Bromide]). It was observed that the corro-sion inhibitors were effective not only for the carbon steels but also for the stainless steels. However, the inhibitor efficiency of every inhibitor for stainless steels was higher than that for carbon steels. Moreover, the inhibitor effi-ciency of different inhibitors was different, and the best efficiency was found for hexadecyltrimethylammonium

20

16

A

12

8

4

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C75 X65

Materials

Without inhibitor100 ppm 18-OH100 ppm 18-NH100 ppm HSA100 ppm HTA Bromide

0.7

0.6

0.5

0.4

0.3

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0.0

B

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ate

(mm

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13Cr steel Duplex steel 904 L steelMaterials

Without inhibitor100 ppm 18-OH100 ppm 18-NH100 ppm HSA100 ppm HTA Bromide

Figure 13: Corrosion rates of steels in SC CO2-saturated water with different inhibitors at 80°C and 9.5 MPa (Zhang et al., 2011b).

bromide, as shown in Figure 13. In the presence of HTA Bromide inhibitor, the corrosion rates of all stainless steels were below 0.1 mm/year in the whole range of temperatures 50 to -130°C.

2.2.2.6 The effect of impurities in SC CO2

In the CCS process, CO2 is normally transported by pipelines. Due to the difference of emission sources, the captured CO2 may contain impurities, such as O2, SO2, NO2, and H2S. Moreover, in the exploitation of oil and gas fields, except for the common CO2-associated gas, there are also some H2S, O2, hydrocarbons, and other gases or their mix-tures existing, and sometimes even a small amount of NO2 and SO2. These corrosive associated gases can promote the CO2 corrosion of steels not only at low partial pressures but also at supercritical conditions. Dugstad and Halseid (2012) have reviewed public data about the tolerances for various impurities with respect to EOR as well as some specifications in the CCS process. However, up to now,




there are still lacking data for deeper understanding of the limits for the contained impurities in CO2 and how they influence the corrosion of steels once they are mixed.

2.2.2.6.1 Effect of O2

The effect of O2 on corrosion rates of steels under SC CO2 conditions (Alami, Augustin, Orlans, & Servier, 2011; Ayello et al., 2010b; Choi & Nesic, 2010, 2011b; Choi et al., 2010; Collier et al., 2013; Dugstad et al., 2011c; Hashizume, Kobayashi, & Trillo, 2013; Ruhl & Kranzmann, 2012) are listed in Table 2. Overall, the corrosion rates of carbon steels in a water-saturated SC CO2 environment were above 0.1 mm/year when O2 is present. Ayello et al. (2010b) con-ducted experiments at 7.58 MPa and 40°C with 1000 ppm of water in SC CO2 (undersaturated) and found that a small amount of O2 (100 ppm) basically had no effect on the corrosion of steel. Similar results were also presented in the studies of Choi and Nesic (2011b) and Dugstad et al. (2011c), when the content of water was below its solubility limit in SC CO2, and even if O2 was present, there was no or little corrosion in steels.

However, in a water-saturated SC CO2 environment, the addition of O2 could result in serious corrosion. Choi and Nesic (2010) and Choi, Nesic, and Young (2010) inves-tigated the effect of O2 content (0%, 2%, 4%, and 6%) on the corrosion of X65 steel in a water- saturated SC CO2 envi-ronment at 8 MPa and 50°C after 24 h of exposure. The presence of O2 enhanced the corrosion rate of X65 steel in an SC CO2 environment, while the corrosion rate did not increase with the increase of O2 content. The corrosion rate of X65 steel reached a maximum value of 1 mm/year with the addition of 4% O2. When no O2 existed, the steel surface was covered with a dense and protective FeCO3. Once O2 is present in this system, it could inhibit the formation of pro-tective FeCO3 film and induce the formation of porous iron oxides with less protectiveness, resulting in the increase of corrosion rate. The investigation conducted by Collier et al. (2013), in which stainless steels (304L and 316L) and carbon steels (X42 and X60) were exposed in a water-saturated SC CO2 environment with O2, indicated that stainless steels performed good corrosion resistance when O2 was present in an SC CO2 system, while carbon steels were more sus-ceptible to corrosion in this system. The corrosion rates of carbon steels in the presence of 3v% O2 were much higher than that without O2. The effect of O2 on the corrosion rate of carbon steels in water-saturated SC CO2 environment was greater than in a subcritical environment. A series of experiments were conducted by Dugstad et al. (2011c) in dense CO2 phase and 50v% water environment at 10 MPa and various temperature with various concentration of O2

(0, 100, and 200 ppm). They found that the addition of O2 increased the corrosion rate of X65 carbon steel 50–120%. At 50°C, the Fe2+ reacted with O2 and formed iron oxides, resulting in a low Fe2+ content in dense CO2 phase than that without O2. The lower Fe2+ content destabilized the protec-tive FeCO3 film and led to the local failure of FeCO3 film. Therefore, serious localized corrosion was generated, and the localized corrosion rate was even up to 17 mm/year.

Choi and Nesic (2010) and Choi, Nesic, and Young (2010) studied the effects of O2 on the corrosion behaviors of carbon steel and 13Cr stainless steel exposed in water-saturated SC CO2 at 50°C and 8 MPa, and found that in the initial corrosion period, the addition of 4% O2 nearly had no effect on the corrosion rate of carbon steel (19.2 mm/year without O2 and 19.3 mm/year with 4% O2) and 13Cr steel (0.01 mm/year). When the immersion time was extended to 120 h, the corrosion rate of carbon steel in the presence of 4% O2 (14.1 mm/year) was higher than that without O2 (10.6 mm/year). Hashizume et al. (2013) studied the effect of O2 on the corrosion of two 13% Cr steels in SC CO2-saturated 5% NaCl solution at 15 and 30 MPa and 100°C with 0.0045 and 0.045 MPa O2 partial pressures. Lower O2 content (0.0045 MPa) nearly had no effect on the corrosion rates of two 13% Cr steels, while high O2 content (0.045 MPa) increased the corrosion rates of two kinds of 13% Cr steels. Meanwhile, high O2 content accelerated the formation of localized corrosion.

2.2.2.6.2 Effect of SO2

Compared with O2, the acid gas SO2 can greatly promote the corrosion rate of steels. Table 3 lists the corrosion data about the effect of SO2 on steels under SC CO2 condi-tions (Ayello et al., 2010b; Choi & Nesic, 2010, 2011b; Choi et al., 2010; Dugstad et al., 2011c, 2013; Farelas et al., 2012; Farelas, Choi, & Nesic, 2013a; Xiang et al., 2012a,b, 2013). The corrosion rates of steels were even up to 7 mm/year due to the presence of SO2, which were much higher than that in the presence of O2. Researchers have discovered that corrosion did not take place in pure CO2 or CO2 with O2 when the water content was far below the water solubility limit in CO2, while corrosion could occur in water under saturated SC CO2 environments with SO2 (Ayello et al., 2010b; Choi & Nesic, 2011b; Farelas et al., 2012, 2013a).

Farelas et al. (2012, 2013a) studied the effect of SO2 content on the corrosion rate of X65 carbon steel exposed to CO2/SO2/H2O (650 ppmv H2O, undersaturated) system at 8 MPa and 50°C with 24 h of exposure. The corro-sion rate was high (3.48 mm/year) with 1% SO2, and it decreased rapidly to 0.025 mm/year when SO2 concentra-tion decreased to 0.1%, and when the SO2 concentration




Table 2: Summary of the effect of O2 on corrosion rate of steels under SC CO2 condition.

No. P (bar) T (°C) H2O (ppmv) O2 (ppmv) Type of steel t (h) Flow (rpm) Corrosion rate (mm/year) Refs.

1 75.8 40 2440 100 5 Static Ayello et al., 2010b

2 80 50 Saturated (10 g) 02%(1.6 bar)4%(3.3 bar)6%(5.1 bar)

X65 24 Static 0.380.610.9

Choi & Nesic, 2010, 2011b; Choi, Nesic, & Young, 2010

3 80 50 65020003000

3.3 bar(4%)

X65 24 Static No corrosionNo corrosion < 0.01

Choi & Nesic, 2011b

4 79.6–82 35 Saturated (100 g) 0 304L,316LX42,X60

120 100 0.0020.0010.0140.011

Collier et al., 2013

5 94.8–103 49 Saturated (100 g) 3v% 304L,316LX42,X60

120 100 0.0030.0040.0990.093

Collier et al., 2013

6 100 60 Saturated(1 ml 55.6 mmol)

Yes(∼1000 ppm)

X42 120 Static 0.008(∼1 mg)

Ruhl & Kranzmann, 2012

7 100 20 1220 488 X65 720 Static No corrosion Dugstad et al., 2011c

8 100 10205050102050

50v%(Saturated)

0000200100200

X65 312336336336312336432

Static 0.50.80.52.71.21.30.6 (pit corrosion rate 17)

Dugstad et al., 2011c

9 150 80 Saturated 1000 ppm 288 120 0.2–0.9 Alami et al., 201110 150 100 5% NaCl 0.045 bar

0.45 bar Type 420 720 Static 0.08 Localized cor.

0.25 Localized cor. Hashizume et al.,

201311 300 100 5% NaCl 0.045 bar

0.45 bar Type 420 720 Static 0.07 Negligible localized cor.


201312 150 100 5% NaCl 0.045 bar

0.45 bar M-SS 720 Static 0.01 Localized cor.


201313 300 100 5% NaCl 0.045 bar

0.45 bar M-SS 720 Static 0.02 No Localized cor.


201314 100 12

13 Water phase 1000

0 X65 48–96 0–3 m/s 5–10

3–5 Dugstad et al.,

2011c15 80 50 400 ml

Water phase 4%; 0 X65 24

120 Static 19.3; 19.2

14.1; 10.6 Choi & Nesic,

2010; Choi, Nesic, & Young, 2010

16 80 50 400 mlWater phase

4%0

13Cr 24 Static 0.01 Choi & Nesic, 2010; Choi, Nesic, & Young, 2010

was further decreased to 0.05%, the corrosion rate basically remained the same value. The effect of SO2 on the corro-sion of carbon steel in aqueous CO2 was also investigated in CO2/SO2/H2O (650 ppmv H2O, undersaturated) system at 8 MPa and 25°C. The corrosion rates in aqueous CO2 phase were lower than that in SC CO2 phase. However, the corro-sion type of carbon steel in SC CO2 phase was general cor-rosion, while serious localized corrosion was observed on

carbon steel in aqueous CO2 phase (0.1% SO2 6.8 mm/year, 0.05% SO2 2.4 mm/year). Xiang et al. (2012a, b, 2013) con-ducted a series of experiments to investigate the effect of SO2 concentration, exposure time, and water content on the corrosion of X70 carbon steel in SC CO2/SO2/H2O system at 10 MPa and 50°C with 120 rpm of flow velocity. When the SO2 concentration was 2 mol%, the corrosion rate of X70 carbon steel increased with increasing water content




and reached a maximum value of about 1.5 mm/year (Xiang et al., 2012b), while the corrosion rate decreased with the increase of exposure time (Xiang et al., 2012a). In the water-saturated SC CO2 system, the corrosion rate of X70 carbon steel gradually increased from 0.2 to 0.8 mm/year with the increase of SO2 concentration (Xiang et al., 2013).

As reported by Choi and Nesic (2010, 2011b) and Choi, Nesic, and Young (2010), 1% SO2 can significantly improve the corrosion rate of carbon steel in both water-saturated and undersaturated SC CO2 environments. The corrosion rate could be increased from 0.38 to 6 mm/year in water-saturated SC CO2 environment and from 0 to 3.48 mm/year in water-undersaturated SC CO2 environment by increas-ing SO2 from 0% to 1%. The corrosion rate of carbon steel could even exceed 7 mm/year in the presence of O2 and SO2 mixture, as shown in Figure 14. This is because SO2 promotes the formation of FeSO4 film, which supplies worse protection to the metal substrate than FeCO3 film.

When O2 and SO2 existed simultaneously, FeSO4 could be oxidized to FeOOH, and H2SO4 was released; therefore, the corrosion rate of carbon steel increased rapidly. In the presence of SO2, the corrosion resistance of 13Cr steel was even as low as that of carbon steel.

2.2.2.6.3 Effect of NO2

Ayello et al. (2010b) compared the effect of the same con-centrations of O2, SO2, and NO2 on the corrosion of carbon steel in SC CO2/H2O system at 40°C and 7.58 MPa (the data listed in Table 4), and found that 100 ppm O2 had no effect on the corrosion rate of carbon steel, but it increased from 2.3 to 4.6 mm/year in the presence of 100 ppm SO2. However, when 100 ppm NO2 was present, the maximum corrosion rate of carbon steel could increase to 11.6 mm/year. Dugstad et al. (2013) also proposed that NO2 could result in much higher corrosion rate of carbon steel

Table 3: Summary of effect of SO2 on carbon steel corrosion under SC CO2 conditions.

No. P (bar) T (°C) H2O (ppmv) O2 (ppmv) SO2 (ppmv) Type of steel

t (h) Flow (rpm) Corrosion rate (mm/year)

Refs.

1 75.8 40 2440 1000 ppm

0 ppm100

C steel(1010)

5 Static No corrosion4.6

Ayello et al., 2010b

2 80 50 650 03.3 bar03.3 bar

000.8 bar (1%)0.8 bar

X65 24 Static No corrosionNo corrosion3.483.7

Choi & Nesic, 2011b

3 80 50 3310 (Saturated)

03.3 bar03.3 bar

000.8 bar (1%)0.8 bar

X65 24 Static 0.3815.57

Choi & Nesic, 2010, 2011b; Choi, Nesic, & Young, 2010

4 80 25 650 0 0.1%0.05%

X65 24 Static 0.1≈0

Farelas et al., 2012; Farelas, Choi, & Nesic, 2013a

5 80 50 650 0 1%0.8 bar0.1%0.080.05%0.04

X65 24 Static 3.480.030.05

Farelas et al., 2012, 2013a

6 80 50 10 g (Saturated)

03.3 bar

0.8 bar 13Cr 24 Static > 7 Choi & Nesic, 2010; Choi, Nesic, & Young, 2010

7 100 20 488 100 ppmw 1000200 ppmw

X65 168 Static 0.01 < 0.01

Dugstad et al., 2011c

8 100 25 488 0 100344

X65 336 3 < 0.005 Dugstad et al., 2013

9 100 25 1220 0 344 X65 336 3 0.02 Dugstad et al., 201310 100 50 0.17 g (9RH%)

-3 g (100RH%) 1000

ppm 2.0 mol%

(0.2 MPa) X70 120 120 0.0387-∼1.5 Xiang, Wang, Yang, Li,

& Ni, 2012b11 100 50 6 g (Saturated) 1000 ppm 0.2

0.71.42 (mol%)

X70Iron

288 120 0.2–0.80.3–1.3

Xiang et al., 2012a

12 100 50 3 g 1100 2 mol% X70 24–192 120 0.7–2.1 Xiang, Wang, Li, & Ni, 2013




(0.06–1.6 mm/year as shown in Table 4) than the same concentration of SO2 ( ≤ 0.02 mm/year). They found that the corrosion rate decreased with the decrease of NO2 content. The higher corrosion rate in the SC CO2/NO2/H2O environment could mean that NO2 dissolved in water to form HNO3, resulting in the pH value of solution declin-ing sharply. Moreover, HNO3 has a strong oxidation effect and oxidized Fe2+, which led to the formation of a rust-like dusty product. This corrosion product film was fluffy and had less protectiveness. As a result, the corrosion rate of carbon steel increased significantly in the presence of NO2.

Based on the above discussion, it could be concluded that in the water-containing SC CO2 system:

– O2, SO2, and NO2 could accelerate the corrosion of car-bon steels in SC CO2/H2O environments. Among three kinds of impurities with the same concentration, NO2 had the largest effect on the corrosion rate of carbon steel, followed by SO2 and O2.

Table 4: Summary of effect of NO2 on the corrosion of carbon steels under SC CO2 conditions.

No. P (bar) T (°C) H2O (ppmv) O2 (ppmv) SO2 (ppmv) NO2 (ppmv) Type of steel

t (h) Flow (rpm) Corrosion rate (mm/year)

Refs.

1 75.8 40 2440 1000 ppm0

0 ppm1000

0 ppm0100

C steel(1010)

5 Static No Corrosion4.611.6

Ayello et al., 2010b

2 100 25 1220 0 0 478191

X65 240 3 1.60.67

Dugstad et al., 2013

3 100 25 488 0 0 191 X65 380 3 0.06 4 100 25 488 0 0 96 X65 72 3 0.17 5 100 25 488 0 138 191 X65 168 3 0.017

7

6

5

4

3

2

1

0CO2

Cor

rosi

on r

ate

(mm

yea

r-1)

CO2+O2 CO2+SO2 CO2+O2+SO2

8650 ppm water (under-saturated)3310 ppm water (saturated)

Figure 14: Effects of O2, SO2, and their mixtures on the corrosion rates of carbon steel in SC CO2 phase with different amounts of water (Choi & Nesic, 2011b). Reproduced with permission from NACE International, Houston, TX. All rights reserved.

– For O2, when the water content was far below the water solubility limit in the pure SC CO2 system, O2 had no effect on the corrosion of carbon steels. When the water content was near or above the water solubil-ity in the pure SC CO2 system, the addition of O2 could accelerate the corrosion rate of carbon steel, while the increase of O2 concentration nearly had no effect on the corrosion rate of carbon steel. Stainless steel had more corrosion resistance than carbon steel in the water-saturated SC CO2/O2 system.

– For SO2, corrosion could occur in the SC CO2/SO2/H2O system even if the water content was far below the water solubility limit in SC CO2. The corrosion rate of carbon steel increased with increasing SO2 concen-tration. Higher concentration of SO2 had significant effect on the corrosion of carbon steels, while very low concentration of SO2 had little effect on the corrosion of carbon steels. In the SC CO2/SO2/H2O system, the corrosion resistance of high Cr-containing alloy steel (such as 13Cr steel) was as low as carbon steel.

However, in the actual CO2 transportation process and oil and gas production, impurities such as O2, SO2, and NO2 coexisted and mixed with CO2. Meanwhile, due to the difference of emission sources, there are normally many other impurities. Yevtushenko, Bäßler, and Salgado (2013), Yevtushenko and Bäßler (2014a), and Yevtushenko et al. (2014b) investigated the corrosion resistance of carbon steels, Cr-containing steels, and high-alloyed steels under SC CO2 conditions. To simulate the real con-ditions in pipelines, small amounts of impurities such as O2 (8100 ppmv), SO2 (70 ppmv), NO2 (100 ppmv), and CO (750 ppmv) were added to this environment. The general corrosion rates of both carbon steel (X52) and CrMo alloy (UNS G41400) decreased with exposure time at 10 MPa and 60°C in circulating SC CO2 environment with 1000 ppmv H2O (flow velocity 4 l/h) as well as with the decrease of water concentration (from 1000 to 500 ppmv,




undersaturated) (Yevtushenko & Bäßler, 2014a). The cor-rosion resistance of CrMo alloy was better than carbon steel, while pitting corrosion was observed on CrMo alloy. They found that in the circulating (4 l/min) SC CO2 with impurities (as mentioned above) condition (Yevtushenko et al., 2013), after 168 h of exposure, the carbon steel and iron were mainly general corrosion with a corrosion rate of about 0.00003 mm/year, slight pitting corrosion occurred on 13% Cr alloy steels, while alloy 31 had no corrosion. They also found that in CO2-saturated aquifer water with impu-rities mentioned above (Yevtushenko et al., 2014b), 13% Cr steels all suffered pitting corrosion, while heat treatment could increase their pitting corrosion resistance.

Paschke and Kather (2012) investigated the corrosion of L360NB and L485MB carbon steels under SC CO2 condi-tions (11 MPa and 60°C) and agreed that the addition of O2 could increase the corrosion rate of carbon steel. The corro-sion rate of L485MB steel significantly decreased with the decrease of O2 content, while the variation of O2 content had no effect on the corrosion of L360NB steel. However, the corrosion rates of the two kinds of carbon steels were all lower and below 0.1 mm/year, indicating that with a small amount of H2O in SC CO2 (undersaturated), the trace of impurities had little effect on the corrosion of carbon steels. It is noted that the author proposed that with the addition of a small amount of CO (50 ppmv) or SO2 (70 ppmv) no corrosion was observed, while corrosion occurred with the addition of 100 ppmv NO.

2.2.2.6.4 Effect of other impuritiesOverall, the effect of concentration variation of a certain impurity on corrosion of steels in water-containing SC CO2, mixed with other impurities such as O2, SO2, and NO2, was similar to it as the only impurity (excluding H2O) in SC CO2 environment. Some authors (Alami et al., 2011; Dugstad, Halseid, & Morland, 2014; Li et al., 2012; McGrail et al., 2009; Schremp & Roberson, 1975) investigated the effect of H2S on the corrosion of steels in SC CO2 environments and found that when the water content was below the water solubility limit in SC CO2, corrosion was very slight in SC CO2/H2O/H2S system ( < 0.0005 mm/year) (Schremp & Roberson, 1975). However, the corrosion rate of steels was higher than 0.3 mm/year in water-saturated SC CO2 phase (Alami et al., 2011) and CO2-saturated water phase (Li et al., 2012) environments, in which H2S was also contained.

Ayello et al. (2010a) used electrochemical imped-ance spectroscopy (EIS) and OLI software to investigate the effects of single impurity (1000 ppm of 1 mm NaOH, 100 ppm water + 100 and 1000 ppm of amine, 1000 ppm of 1 mm HCl and 1000 ppm of 1 mm HNO3) on the solubility

limit of water in SC CO2 and the pH value of the condensed aqueous water phase, as well as the corrosion rate of carbon steels. A small amount of NaOH could increase the pH value of the condensed water and caused a low corro-sion rate of carbon steel (1.4 mm/year) than in SC CO2/H2O system. HCl and HNO3 had similar effect on the pH value of condensed water, which decreased with the addition of HCl or HNO3; this resulted in higher corrosion rate (5.6 mm/year for HCl and 4.5 mm/year for HNO3) than that in SC CO2 phase with 1000 ppm water. However, amine significantly increased the pH value of the condensed water; as a result, the corrosion rate of carbon steel was 0.1 mm/year for 100 ppm and 0.01 mm/year for 1000 ppm amine. Sim et al. (2013) studied the effect of different concentrations of salt and acid impurities (listed in Table 5 No. 2) on carbon steel corrosion in SC CO2 environment and suggested that the general corrosion rates of carbon steel under different test conditions were similar (about 0.03 mm/year); however, the pitting corrosion rates of carbon steel were much larger than its general corrosion rates, and HNO3 significantly increased the pitting corrosion rate of carbon steel ( > 3 mm/year). The study of Ruhl and Kranzmann (2012) also confirmed that when SC CO2 contained H2O, the addition of HNO3 could result in localized corrosion. They investi-gated the effect of various flue gas acids (listed in Table 5 No. 21, 22, and 23) on the corrosion of X42 carbon steel in SC CO2 environment at 10 MPa and 60°C. Due to H2SO4 not migrating through SC CO2, no corrosion was observed in the SC CO2 environment with different concentrations of H2SO4 and water. However, HCl and HNO3 significantly accelerated the corrosion of X42 steel. Choi, Nesic, and Young (2010) also confirmed that the addition of H2SO3 could increase the corrosion rate of X65 steel in SC CO2 environment.

In addition, Thodla et al. (2009) investigated the variation of amine concentration on the effect of corro-sion of carbon steel in SC CO2 with 100 ppmv water at 7.9 MPa and 31°C, and found that with the increase of amine concentration (from 0 to 1000 ppm), the corrosion rate of carbon steel decreased. Kongshaug and Seiersten (2005) found that the addition of 50 wt% MEG in SC CO2- saturated 1 wt% NaCl solution at 8 MPa and 50°C decreased the corrosion rate of X65 carbon steel from 4.6 to 1.7 mm/year. As mentioned above, the following could be concluded:

– Acid impurities, except for H2SO4, could accelerate the corrosion of carbon steels in SC CO2 environment, especially when water existed. The addition of HNO3 in SC CO2/H2O can result in pitting corrosion.

– Amines and NaOH could decrease the corrosion rate of carbon steels.




Tabl

e 5:

Sum

mar

y of

effe

ct o

f im

purit

ies

on th

e co

rros

ion

of ca

rbon

ste

els

unde

r SC

CO2 co

nditi

ons.

No.

P (b

ar)

T (°

C) H

2O (p

pmv)

O2 (p

pmv)

SO 2 (p

pmv)

NO 2 (p

pmv)

H2S

(ppm

v)

CO (p

pmv)

Oth

er Im

purit

y

t (h)

Flo

w C

orro

sion

rate

(m

m/y

ear)

Typ

e of

ste

el R

efs.

1

75.8

40

1 m

m N

aOH1

000

ppm

Amin

e 10

0 pp

mAm

ine

1000

ppm

1 m

m H

Cl 1

000

ppm

1 m

m H

NO3 1

000

ppm

5

Stat

ic 1

.4 0.1

0.01

5.6

4.5

A

yello

et a

l.,

2010

a

2

76

50 2

4400

1

g/l

NaC

l1

g/l N

a 2SO4

1 g/

l NaN

O 3

3 g/

l Na 2SO

4

3 g/

l NaN

O 3

10 g

/LHN

O 3

3 g/

l NaN

O 3

16

8 0

0.0

30.

030.

030.

030.

028

0.02

20.

03

C s

teel

Sim

et a

l.,

2013

3

79

31 1

00

0 100

ppm

am

ine

1000

ppm

am

ine

S

tatic

1.1 0.11

0.01

1

T

hodl

a et

al.,

20

09

4

80

50

0 0 3.3

bar

650

ppm

(6%

H2SO

3)

24 120

120 S

tatic

0.0

320.

019

0.02

5

C

hoi &

Nes

ic,

2011

b

5

80

50 1

wt%

NaC

l

50

wt%

MEG

0 1

20–1

68 S

tatic

1.7 4.6

X65

Kon

gsha

ug

and

Seie

rste

n 20

046

80,

100

130

15%

NaC

l

9 M

Pa

240

Stat

ic 0

.4 1

10 S

ste

el L

i et a

l., 2

012

7

82

24 9

96

321

ppm

w

1176

Sta

tic N

ot g

iven

M

cGra

il et

al.,

20

098

10

0 25

122

275

69

96

130

24

0 Ro

tate

d

540°

/min

0.0

34

Dug

stad

et a

l.,

2014

9

100

60 1

000

810

0

70

100

75

0

7 4

l/h

0.0

25 X

52 Y

evtu

shen

ko &

Bä

ßler

, 201

4a10

10

0 60

100

0 8

100

70

10

0

750

30

4 l/

h 0

.013

11

100

60 1

000

810

0

70

100

75

0

186

4 l/

h 0

.003

12

100

60 6

00 8

100

70

10

0

750

30

4 l/

h 0

.006

13

100

60 5

00 8

100

70

10

0

750

30

4 l/

h 0

.004

14

100

60 1

000

810

0

70

100

75

0

7 4

l/h

0.0

24 C

rMo-

allo

y(U

NS G

4140

0) Y

evtu

shen

ko &

Bä

ßler

, 201

4a,

Yevt

ushe

nkoe

t al

., 20

14b

15

100

60 1

000

810

0

70

100

75

0

30 4

l/h

0.0

05

Yev

tush

enko

&

Bäßl

er, 2

014a

16

100

60 6

00 8

100

70

10

0

750

30

4 l/

h 0

.002

5




No.

P (b

ar)

T (°

C) H

2O (p

pmv)

O2 (p

pmv)

SO 2 (p

pmv)

NO 2 (p

pmv)

H2S

(ppm

v)

CO (p

pmv)

Oth

er Im

purit

y

t (h)

Flo

w C

orro

sion

rate

(m

m/y

ear)

Typ

e of

ste

el R

efs.

17

100

60 5

00 8

100

70

10

0

750

30

4 l/

h 0

.001

18

100

60 L

iqui

d w

ater

ph

ase

810

0

70

100

75

0

7992

P

it Co

rros

ion

Y

evtu

shen

ko

et a

l., 2

014b

19

100

60 1

000

810

0

70

100

75

0

168

4 l/

min

0.0

0003

0.00

004

C-s

teel

Iron

Yev

tush

enko

et

al.,

201

320

10

0 60

100

0 8

100

70

10

0

750

16

8 4

l/m

in P

ittin

g Co

r.Sl

ight

Pit

Cor.

Initi

atio

n Pi

tNo

corr

osio

n

X20

Cr13

X46C

r13

X2Cr

MoN

i22-

5-2

Allo

y 31

Yev

tush

enko

&

Bäßl

er, 2

014a

21

100

60 0

, 0.5

, 0.8

m

l N

ot g

iven

H2SO

4 (96

wt.%

):1,

0.5

, 0.2

ml

12

0 St

atic

No

corr

osio

n X

42 R

uhl &

Kr

anzm

ann,

20

1222

10

0 60

0, 0

.5, 0

.8

ml

Not

giv

en

H

NO3 (6

5 w

t.%):

1, 0

.5, 0

.2

120

Stat

ic ∼

0.39

-∼3.

88 X

42

23

100

60 0

ml

Not

giv

en

H

Cl(3

7 w

t%)1

ml

12

0 St

atic

∼0.

77 X

42

24

110

60 0

–100

0 pp

m 4

.7v%

70

50

Ar+

N 2:10.

37v%

NO: 1

00

168

Stat

ic 0

.008

–0.0

72 C

-ste

el P

asch

ke &

Ka

ther

, 201

225

11

0 60

100

ppm

4.7

v%0.

67v

100

ppm

70

10

0

50

16

8 St

atic

L48

5MB:

20,5

,3L3

60NB

:2,3

,2

C-s

teel

26

138

3 24

40

800

67

2 St

atic

< 0.

0005

S

chre

mp

and

Robe

rson

19

7527

13

8 22

244

0

800

10

08 S

tatic

< 0.

0005

28

150

80 S

atur

ated

3

v%

336

Stat

ic >

0.3

A

lam

i et a

l.,

2011

29

240

50 0

4

% TH

FA

24 S

tatic

No

corr

osio

n

Rus

sick

et a

l.,

1996

30

240

50

4

wt%

Met

hano

l

24 S

tatic

Not

giv

en

Tabl

e 5

(con

tinue

d)




– Corrosion rates significantly increased in SC CO2 envi-ronment with salt impurities (such as Cl-, NO3

-, SO42-),

and localized corrosion also occurred.

In summary, investigations so far on the corrosion behav-iors of steels under SC CO2 conditions mainly focused on the corrosion rate, structure, morphology, and composi-tion of corrosion scales as well as the electrochemical behaviors. The main conclusions are that in water satu-rated with an SC CO2 environment, the corrosion rate of carbon steel was very high (more than 10 mm/year), and localized corrosion was encountered. Under these condi-tions, even 13Cr and high alloy CrNi stainless steels were also subjected to a bit of corrosion. Inhibitor could reduce the corrosion rate of carbon steels and stainless steels, but none of the tested inhibitors could reduce the corro-sion rate of carbon steel to an acceptable value. Impuri-ties such as O2, SO2, and NO2 and their mixtures in SC CO2 increased the corrosion rate of carbon steel.

3 Discussion and outlookAs summarized above, in water saturated with an SC CO2 environment, the corrosion rate of carbon steel is very high. For stainless steel, the corrosion has been observed in varying degrees on 13Cr, duplex, and 904L stainless steels (Zhang et al., 2011a). The corrosion rates for 13Cr steel are 0.3–0.8 mm/year, and even duplex and 904L stainless steels encounter corrosion by more than 0.1 mm/year at 110°C. The corrosion resistance of 13Cr steel is even as low as that of carbon steel in the presence of SO2 (Ayello et al., 2010b; Dugstad et al., 2013). Therefore, further studies are needed on the research for corrosion behaviors of differ-ent stainless steels in environments of water saturated with SC CO2 in order to develop new corrosion resistance stainless steels that are applicable in aqueous SC CO2 conditions.

On the other hand, although stainless steel can effectively prevent or reduce CO2 corrosion rate, they are very expensive, so carbon steel (such as X65, X70 pipe-line steels) is still preferred for long-distance oil and gas pipelines. However, as reported by Zhang et al. (2011b), even with hexadecyltrimethylammonium bromide, which is proven to be the best inhibitor in these condi-tions by far, the corrosion rate of carbon steel is still up to 3 mm/year at 80°C. Therefore, more inhibitors should be further tested to find a new corrosion inhibitor that can exhibit good corrosion inhibition effect under SC CO2 conditions.

4 ConclusionThis paper reviews the research results on corrosion behav-iors of steels under SC CO2 conditions, points out the short-comings in the present investigations, and finally looks forward to the prospects on SC CO2 corrosion research. In order to understand the controlling factors on steel corrosion in SC CO2, the corrosion mechanism and corrosion properties of steels under SC CO2 conditions are necessary to be investi-gated further. Finally, a standard for selecting steels applied in the SC CO2 environment as well as a life and integrity assessment system of pipelines should be established for the expectation that it would be used for the materials selection in the future of CO2 capture, transport, and storage.

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BionotesLiang WeiDepartment of Materials Physics and Chemistry, University of Science and Technology Beijing, Beijing 100083, China

Liang Wei is a PhD student at the University of Science and Technology Beijing. His research mainly focuses on the corrosion behaviors of steels under CO2 and SC CO2 conditions.

Yucheng ZhangTest and Analysis Center, ShouGang Research Institute of Technology, Beijing 100043, China

Yucheng Zhang received his PhD degree from the University of Science and Technology Beijing. Currently, he is a Researcher with ShouGang Research Institute of Technology.

Xiaolu Pang Department of Materials Physics and Chemistry, University of Science and Technology Beijing, Beijing 100083, China

Xiaolu Pang is an Associate Professor with the University of Science and Technology Beijing. His research primarily focuses on the preparation of nano-film and property characterization, material surface modification, and biological friction corrosion.




Kewei GaoDepartment of Materials Physics and Chemistry, University of Science and Technology Beijing, Beijing 100083, China, [email protected]

Kewei Gao is a Professor with the University of Science and Technology Beijing. Her research focuses on corrosion and corrosion protection, materials service performance evaluation, materials surface technology, stress corrosion cracking, and hydrogen-induced cracking. Her current research mainly focuses on the corrosion of steels under SC CO2 conditions.



liang wei, yucheng zhang, xiaolu pang and kewei gao

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