There has been a long history of the trial application of CO₂-EOR technique in oil and gas industry. However, the combination of this technique with CCS was recently adopted. As illustrated in Figure 1, the whole chain can be divided into carbon capture, CO₂ transportation, CO₂ injection, and oil production, during which a great portion of CO₂ are permanently stored underground and the other is reutilized in the recycling process. In this whole chain process, CO₂ can be viewed as a feedstock and crude oil is the product. When the net emission of CO₂ is less than zero, i.e., the amount of CO₂ stored underground is larger than that produced after burning the CO₂-EOR crude oil, the crude oil will become “carbon negative.”

Currently, corrosion is one of the big concerns for wide application of the CCS-EOR technique, as water may be acidified in a CO₂-containing environment. The presence of crude oil could vastly change the corrosion performance of steel materials, implying that the fluid structure may significantly affect corrosion. Therefore, the state of water and the fluid properties will be highlighted in this paper.

In the temperature range of oil production, completely dry CO₂ is not corrosive to steel. Direct carbonation of steel materials by CO₂ can only occur at a high temperature (Cao et al., 2012). As mentioned above, CO₂ is generally transported and injected into wells in a dense phase state, for example, the supercritical state. The presence of a trace amount of water in the dense phase CO₂ is the origin of corrosion; the formation of CO₂ saturated water layer on steel surface triggers corrosion. In this case, corrosion will be very slight, since this water layer can quickly become saturated with ferrous ion and an iron carbonate layer can be easily formed on the steel surface. The variation of local temperature and pressure is believed to be the primary cause of forming droplets or a water layer on steel surfaces (Choi and Nešić, 2011), just like that in a wet natural gas pipeline. However, CO₂ fluids can have a very high density, vastly different from natural gas. As seen from Figure 3, the density of CO₂ can be higher than 800 kg/m³ in a certain depth in the injection well. Therefore, in a flow condition, such a dense-phase CO₂ may behave more like an oil phase rather than a natural gas phase.

Recently, it was found that the corrosion morphology was highly relied on the flow rate and the degree of water saturation (Liu et al., 2018); a higher flow rate and a higher degree of water saturation produced larger corrosion product particles and patches, implying a possible corrosion mechanism related to the direct bombardment of water droplets on steel surfaces and these droplets are likely entrained in the dense CO₂ phase, rather than directly nucleated on steel surfaces. In SC CO₂ fluids, the entrainment of these water-rich clusters (or droplets) is possible and the presence of such water-rich heterogeneities in wet SC CO₂ has been identified by near-infrared spectroscopy (Wang et al., 2013) and radial distribution function method (Glezakou et al., 2010). Above the solubility limit of water in SC CO₂, the water-CO₂ mixture may form stable water-in-SC CO₂ micro-emulsions (Lee et al., 1999). Below the saturation limit, the formation of a weak Lewis acid-base H₂O:CO₂ complex (Thanthiriwatte et al., 2012; Wang et al., 2013) has been reported in SC CO₂ media. As illustrated in Figure 3, depending on the flow rate in transportation and injection, the velocity of a CO₂ fluid can be in a wide range from <0.1 to 0.5 m/s or higher. Obviously, decreasing the velocity of CO₂ can reduce the impact of water droplets on steel surface, thus reducing the corrosion risk (Bian et al., 2015). Therefore, to get a high transportation efficiency, pressurizing the CO₂ fluid is better than improving its flow velocity from a corrosion view.

Besides the influence of flow rate and water concentration, it has been reported that some impurity gases may also significantly change the corrosion morphology and increase the corrosion rate. To date, the corrosion performance of steel in presence of trace amounts of O₂ (Xiang et al., 2013; Hua et al., 2014b), SO_x, NO_x (Ayello et al., 2010; Dugstad et al., 2013a), H₂S (Choi et al., 2015; Sun et al., 2016b), and their mixtures (Choi et al., 2010; Dugstad et al., 2013b; Ruhl and Kranzmann, 2013; Xiang et al., 2013) have been extensively investigated. The results show that these impurity gases may greatly change the water limit for triggering corrosion, as they exacerbates corrosion by influencing corrosion products and participating in corrosion processes. However, it should be noticed that the presence of impurities may also change the stability of the water-CO₂ mixture in a supercritical state (Mohitpour et al., 2012). Visualization tests should be conducted to further explore the initial corrosion and water settlement in SC CO₂ environments. This may finally lead to a better management of the corrosion risk in CO₂ transportation and injection pipelines.

Although CO₂ is dried prior to transportation, water ingress may happen in some occasional conditions. It has been reported that the corrosion rate of mild steel in a dense-phase CO₂-water flowing conditions can be as high as several to tens of mm/y depending on their fluid parameters (Dugstad et al., 2011a; Barker et al., 2017), because the aqueous solution was saturated with high pressure CO₂. There are many experimental results on the corrosion rates and corrosion morphologies of steel materials in high-pressure CO₂ environments (Cui et al., 2006; Cao et al., 2012; Zhang Y. et al., 2012; Hua et al., 2015), from which it can be deduced that the steel materials suffer from severe corrosion attack and the flow can vastly accelerate corrosion (Dugstad et al., 2011a; Wei et al., 2018) in the presence of a bulk volume of water during the transportation of dense-phase CO₂.

In practice, CO₂ and water may also be alternatively injected into wells (Rogers and Grigg, 2001; Lv et al., 2015; Dang et al., 2016). For example, in Shengli oilfield, the water alternating gas (WAG) injection technique is planned to be adopted after a further verification in the pilot-scale CO₂-EOR project (Lv et al., 2015). This WAG injection process can to some extent retard gas-migration under reservoir conditions (Dugstad et al., 2011b). By adjusting the WAG ratio, a maximum ratio of the oil production to CO₂ injection could be reached (Dai et al., 2014). However, the alternating exposure of the pipe inner wall to water and CO₂ fluids can result in severe corrosion damage. According to field experiences, the water phase may linger for a long time in crevices or dead spots after dry conditions were restored (IEAGHG, 2010), leading to a corrosion problem in aggressive well environments. Temperature and pressure are believed to be the critical factors in corrosion (De Waard et al., 1991), since they directly determine the solubility of water in CO₂ and the pH-value of the water layer (Choi and Nešić, 2011). During the WAG injection process, corrosion occurs when the CO₂ slug begins to drive down the previous water slug, leaving a water layer on the pipe inner wall being acidified by flowing CO₂. Recently, Wang and Song theoretically evaluated the corrosion risk of steel materials in such WAG conditions by assuming that the steel surfaces were periodically exposed to the wet/dry cycles in CO₂ fluids and the corrosion was dependent on the dissolution of CO₂ in the water layer (Wang and Song, 2018). In their simulation work, the time of forming a CO₂ saturated water layer was simiply determined by the diffusion rate of CO₂ through the layer, which was assumed to be very fast and genrally less than several minutes (Grogan et al., 1988; Farajzadeh et al., 2009), having little influence on the overall corrosion performace. Therefore, the long-term corrosion behavior relied on the time for drying the steel surface by flowing “dry” CO₂, and the amount of water absorbed by the “dry” CO₂ fluid was critical for determing corrosion risk, where the “dry” CO₂ meant that the water concentration in CO₂ phase was far below its saturation limit, a shorter drying time meant a less exposure of steel surface to the CO₂ saturated corrosive water, and corrosion was supposed to cease when the water layer was completely absorbed into the CO₂ fluid. In this way, they concluded that the alternate period determined the long-term corrosion performance. The injection rate of CO₂ fluid is another critical factor influencing the distributions of temperature and pressure in well (Lindeberg, 2011; Ruan et al., 2013) and it also affects the drying time of the water layer along the pipe internal wall.

The presence of crude oil may reduce the corrosion risk of CO₂-EOR pipelines. The corrosion performance of pipeline may be influenced by crude oil's physical properties, such as its density (Lotz et al., 1991; De Waard et al., 2003; Papavinasam et al., 2007), viscosity (Kanwar, 1994; Jepson and Menezes, 1995; Papavinasam et al., 2007), conductivity (Craig, 1998), and wettability (Craig, 1996; Smart, 2001; Efird et al., 2004). Recently, Wang and Zhang (2016) summarized four different mechanisms for the inhibition effect of crude oil on corrosion: (1) water entrainment, (2) crude oil wetting, (3) soluble chemical partitioning, and (4) corrosion product layer modification. De Waard et al. (2003) found that heavy oil was less corrosive than light one in an oil-water two-phase flow condition, which could be attributed to the formation of w/o dispersions (Xu, 2007). A simple notion for corrosion risk analysis has been proposed based on the assumption that corrosion would occur only when free water was separated from w/o emulsion during transportation (Wang Z. L. et al., 2014). At some extremely high water cuts, w/o emulsion can also be formed. For example, the experimentally measured emulsion inversion point (EIP) is generally reported to be as high as 70 wt.% (Fingas and Fieldhouse, 2004; Wang Z. L. et al., 2014), which means that a w/o emulsion can be formed at a relatively high water cut under sufficiently stirred conditions. Free water will be separated within a very short period from a w/o dispersed fluid when the flow is slower than a critical velocity (Xu, 2007). In practical oil production, it is hard to completely emulsify the oil-brine mixtures with a very high water concentration. Generally, a w/o emulsion containing <30 wt.% water is relatively stable under flow conditions (Fingas and Fieldhouse, 2004).

The occurrence of corrosion may be related to the droplet behavior in a w/o emulsion or dispersion, and the droplets may grow to larger ones during transportation, leading to the settlement on pipeline bottom. According to Stokes equation, the settlement rate (V_t) of water droplets in a w/o emulsion can be expressed as (Frising et al., 2006),

where d_t is the mean diameter of droplets at a test condition, g is the gravitational acceleration, ρ_w and ρ_o are the densities of water and oil phases, and μ is the viscosity of oil-water mixtures. It is clear that a larger water droplet is easier to settle down in a lighter oil-water mixture. It should also be noticed that the formation of a stable emulsion may significantly increase the fluid viscosity (Xu, 2007; Wang Z. L. et al., 2014), thus retarding the settlement of water droplets. In practical uses, the theoretical analysis must be verified by the stability of emulsion samples in field conditions. Recently, Paolinelli et al. (2018) examined the correlation of water droplet size distribution with different fluid parameters (flow rate, pressure drop, oil types, and fraction of water) after a globe valve on a pipe flow loop and compared with theoretical analysis, and gave some reasonable hints for the control of water droplets in flow conditions. In this way, before the settlement of water droplets or the formation of water layer at pipeline bottom, corrosion could be totally retarded during the long-distance transportation of oil-water emulsion and a fast transportation could shorten the time from wellhead to treatment station (Wang Z. L. et al., 2014), beneficial for reducing the corrosion risk.

At a higher water cut, where total entrainment of water droplets becomes impossible, the steel surface will be intermittently wetted by water. Flow loop tests indicated that the corrosion rate was retarded under intermittent water wetting conditions compared to continuous water wetting (Li et al., 2006). In a flow condition, the intermittent wetting behavior closely depends on the flow pattern characteristics (Nesic and Carroll, 2003). Several studies have demonstrated that with increasing flow rate, the steel surface can be changed from continuous water wetting to intermittent wetting or even continuous oil wetting (Nesic and Carroll, 2003; Cai et al., 2012), hence reducing the corrosion risk at the pipeline bottom. The intermittent wetting by oil and water at steel surface has been verified by various sensors in flow loop tests (Fordham et al., 1999; Zong et al., 2010; Luo et al., 2017). Efforts have been made to monitor the wetting and corrosion phenomena by electrochemical noise method in oil-water mixtures (Bouazaze et al., 2005). However, the electrochemical noise signals are much complicated. A quantitative and controllable method is urgently needed for analyzing the dynamic wetting and corrosion phenomena in one test. To further reveal the corrosion phenomena in oil-water intermittent conditions, Wang et al. (2019a) recently proposed an “alternate wetting cell” to record the current signals under anodic polarization with a rotating electrode. With a controllable movement of the oil/water interface relative to electrode, it can simplify the intermittent flow pattern as the alternate wetting of the electrode surface by oil and water, as illustrated in Figure 4. The actual wetting state could be presented as a series of oil and water slugs (see Figure 4A). Interestingly, there is a delay in the actual oil wetting time (t_ao) and the actual water wetting time (t_aw), which can be confirmed by the anodic current peaks in Figure 4B. The height and width of the current peaks could reflect the corrosion and water wetting on the electrode surface, respectively. Their results indicate that a slow flow and a short alternate period can generate high corrosion mitigation efficiency. The “alternate wetting cell” method provides a possible way to describe the correlation between corrosion and wetting under a controllable manner and a new insight into the corrosion phenomena in a complicated system. It can be used for the evaluation of corrosion inhibitors in an oil-water system (Wang et al., 2019b).

The covering effect of crude oil at the steel surface is widely accepted as the origin for corrosion inhibition. However, a thin layer of crude oil at the steel surface is unstable to prevent corrosion for a long time. For example, Wang Z. L. et al. (2014) observed that a crude oil layer could only persist for about 15 min on a vertically placed steel surface in a stagnant condition. The heterogeneous adsorption of crude oil on steel surface may induce localized corrosion (Sun et al., 2016a). The degree of localized corrosion may be vastly different from the averaged corrosion rate in oil-brine mixed conditions (Choi et al., 1989; Sun et al., 2016a), but this phenomenon and its mechanisms have not been clearly addressed. Some soluble organic compounds in crude oil can also decisively reduce the corrosion rate in a manner like corrosion inhibitors (Efird and Jasinski, 1989; Castillo et al., 2000; Ayello et al., 2013) and they may produce a possible hybrid effect on corrosion products (Mendez et al., 2001; Yang et al., 2014; Taleb et al., 2017).

The multiphase fluids are commonly encountered in CO₂-EOR production, in which a large fraction of CO₂ in the gas phase is involved. Previous efforts were mainly focused on the relationship between corrosion and the flow characteristics of a gas-liquid two-phase flow. Although very limited number of studies have been focused on the corrosion phenomena in CO₂-EOR multiphase flow conditions, the results regarding corrosion in conventional oil production can be employed for reference. For instance, in a slug flow, the corrosion risk of pipelines can be closely related to the superficial gas velocity (Maley, 1997; Kang et al., 1999), slug frequency (Kang et al., 1996; Maley, 1997; Wang et al., 2015), and Froude number (Kang et al., 1996; Chen and Jepson, 1999). Generally, direct visualization is used to determine the flow patterns. Other methods are also widely accepted, for examples, pressure drop (Sotgia et al., 2008), wetting behavior (Cai et al., 2012), and phase density distribution (Hoffmann and Johnson, 2011). Currently, many research institutes have developed multiphase flow loops for corrosion tests (Kouba and Jepson, 1990; Nyborg, 1998; Li et al., 2006; Zheng et al., 2008; Wang et al., 2015). Based on the flow loop tests, the relationship between corrosion and flow characteristics has been built. It was found that a higher slug frequency may increase the corrosion rate of pipelines, owing to a sharp increase in the local wall shear stress (Yang et al., 2010), which was viewed as an important parameter in corrosion (Wang et al., 2002; Zheng et al., 2008). A higher shear stress may enhance the local corrosion kinetics or damage the corrosion products (Schmitt et al., 2000; Li et al., 2016). It was also observed that a higher gas flow rate could reduce the pressure drop and lower the frequency of liquid slugs at a constant liquid velocity (Kang et al., 1999; Villarreal et al., 2006; Wang et al., 2015), thus reducing the corrosion risk.

In conducting a flow loop experiment, oil and water may be emulsified during a long-term cyclic test if crude oil was used. The heavier the crude oil is, the easier it can be emulsified. At a fixed pump input fraction of oil and water, the entrainment of water in oil phase may increase the actual water fraction of input fluids. It has been reported that a significantly large amount of water can be entrained into the crude oil phase after 3 days of the cycle test in a closed flow loop (Wang and Zhang, 2016). No free water can be separated from the oil-water mixture within a short period after the cyclic test. Emulsification is the main reason for the use of white oil, instead of crude oil, in most multiphase flow loop tests. To overcome the emulsification problem, a multiphase flow loop was built in a treatment station of Shengli oilfield, where the oil, water and gases were separately introduced into the test loop from the production pipelines and then went back to the production system via the output pipeline after corrosion test. The input of oil, water and gas was also driven by pumps and the process was similar to that of a laboratory-scale setup reported previously (Wang et al., 2015). The only difference is that the mixed fluids after going through the corrosion test section directly flows into the oil production system and never goes back to the pipe section for corrosion tests. Using this “open” flow loop system, field corrosion was monitored at the steel pipe bottom. The corrosion rate can be automatically converted from the galvanic current of a commercial corrosion probe, which has been previously used for corrosion monitoring in an oil-water system (Wang Z. L. et al., 2014). A flat sheet of 20# steel was used as the corrosion probe and the diameter of the pipeline was 80 mm. With changing water cut, a series of field conditions can be simulated.

One may notice that CO₂-EOR production fluids generally contain an extremely high fraction of gas phase with a gas-to-liquid ratio over 200, in which CO₂ gas can reach a volume fraction of 70% in the gas phase (Wang et al., 2015). Under such a high gas-to-liquid ratio, oil and water may be strongly stirred during transportation, and corrosion can be reduced once the oil phase reaches the bottom of pipeline. In Figure 5, the influence of gas-to-liquid ratio on corrosion was further verified at different water cuts in filed conditions. The corrosion rate initially increased and then decreased after the gas-to-liquid ratio increased to a critical value, depending on the water cuts. A higher water cut generally leads to a transition point at a higher gas-to-liquid ratio. However, when the gas-to-liquid ratio is higher than 20, corrosion will be obviously reduced. The result agrees with the theoretical analysis of corrosion mitigation in oil-water-gas three-phase flow conditions (Wang et al., 2015). This is also consistent with the notion that corrosion can be mitigated in an oil-brine mixed flow by increasing turbulence to generate oil wetting (Wicks and Fraser, 1975; Cai et al., 2012). Under a high pressure, the dissolved gas may reduce the viscosity of crude oil, thus changing the flow pattern and the wetting behavior in pipeline (Luo et al., 2017).

Sand or solid particles in CO₂-EOR fluids may induce erosion or localized corrosion problem. Generally, in the CO₂ injection and water treatment processes, no sand or solid particle is involved. The influence of sand or solid particle on corrosion is usually considered in presence of crude oil. The simulation work from Landry et al. (2012) suggested that the settlement of solid particles is much easier onto the pipeline bottom and water may also be accumulated around such solid particles forming a locally water-rich environment. In this condition, corrosion may be preferentially initiated around the solid particle (Han et al., 2013). Tang et al. (2008) observed severe erosion-corrosion damage on steel surface and the contribution of erosion was measured to be around 70% in the oil-sand slurry with different sand concentrations. However, Stack and Abdulrahman (2012) reported the movement behavior of sand particles sealed by an oil layer, which produces a weaker impact on steel surface, and thus reduce the mechanical and electrochemical attacks. A further analysis is essential for understanding the corrosion behavior associated with sand particles and crude oils, which will be helpful to the field corrosion management in CO₂-EOR well and deep-sea conditions.

The authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.