Corrosion of multiphase flow pipelines: the impact of crude oil

2.1.1 Classification of crude oil

Crude oil is a complex mixture of hydrocarbons that naturally occurs in reservoir rocks. It contains hydrocarbons, heterocyclic and metal organic compounds, high-molecular-weight organic compounds, and a series of nitrogen-, sulfur-, and oxygen-containing organic compounds. For different purposes, crude oil is broadly grouped by their density, geochemical parameters, live crude properties, hydrocarbon compounds, and so on. From previous literatures regarding corrosion in crude oil-containing environments, two methods of classification were generally referenced. The first one is to classify crude oils according to American Petroleum Institute (API) gravity. The API gravity is a factor inversely proportional to the density of crude oil. A heavy crude oil has an API gravity lower than 20, a medium crude oil has an intermediate API gravity of 20–34, and a light crude oil has a API gravity higher than 34. There are some crude oils with API gravity below 10 (with a density higher than 0.99 relative to pure water), which are called extreme heavy crude oils. These ranges are not absolutely defined and can be slightly varied according to different references. It has been generally accepted that heavier oils are more protective than lighter ones with regard to corrosion.

Another way to classify crude oils is based on the proportions of the organic compounds (Sokolova, Abryutina, Punanov, & Petrov, 1992), such as paraffins, aromatic compounds, and naphthenic compounds. According to a detailed identification of the roles of chemical compounds in corrosion, these compounds may present profound effect on the wettability of crude oil and the chemistry of the brine solutions (Efird, Smith, Blevins, & Davis, 2004).

Most recently, based on the ability to inhibit corrosion and the alteration of steel wettability, Richter, Babic, Tang, Robbins, and Nesic (2014) grouped crude oil into four categories. For category I, the crude oils both inhibit corrosion and alter the wettability of the steel; for category II, the crude oils inhibit corrosion but do not alter the wettability of the steel; for category III, the crude oils do not inhibit corrosion but alter the wettability of the steel; for category IV, the crude oils neither inhibit corrosion nor alter the wettability of the steel. This method can reflect the corrosion mechanisms of steels in oil-brine mixtures. However, there is no direct link between the corrosion performance and the intrinsic characteristics of crude oils.

2.1.2 Viscosity and density

The viscosity and density of crude oil are two dependent factors. They are important for corrosion prediction because the entrainment of water in crude oil is very dependent on them (Xu, 2007). A low viscosity leads to an easy separation of water from the mixtures. The oil-water mixture is usually heated to a temperature high enough to lower its viscosity, shortening the time for water separation (Arnold & Stewa, 1999). The often large difference between the density of crude oil and water is also beneficial for water separation, reducing the tendency of entrainment of water in crude oil. At a certain temperature, heavier oil is more viscous. The correlation among dynamic viscosity of crude oil, API gravity, and temperature has been well established. As suggested in a recent study (Sanchez-Minero, Sanchez-Reyna, Ancheyta, & Marroquin, 2014), the dynamic viscosity (μ_od, in centipoise) can be expressed as

where T is the absolute temperature (in kelvin) and a and b are coefficient factors as functions of API gravity and can be estimated from the following relations:

Here, API represents the gravity of crude oil (in °API).

As opposed to density, crude oil viscosity is very dependent on crude oil-brine mixtures. It is strange that the viscosity of crude oil is rarely mentioned during corrosion studies.

According to previous suggestions (De Waard, Smith, & Craig, 2003), the entrainment of water in crude oil can be estimated by API gravity. They defined the critical water break value W_break as the amount of water that can be entrained in crude oil. A linear relation has been expressed as W_break=-0.0166*API+0.83. For the water cut in an oil-brine mixture below W_break, the water phase is totally entrained in the oil phase, avoiding pipeline corrosion problems. This is an empirical formula based on field data analysis of well tubing corrosion from two oilfields (De Waard et al., 2003). The phenomenon of sharp increase in corrosion rate at a certain water cut has been experimentally verified by many laboratory tests (Carew, Al-Sayegh, & Al-Hashem, 2000; Craig, 1996; Efird & Jasinski, 1989; Papavinasam, Doiron, Panneerselvam, & Revie, 2007). This critical water cut of corrosion rate break (CRB) is defined as the critical water break value or the emulsion inversion point (EIP). Table 1 summarizes the critical water cuts for CRB in different oil-brine mixed conditions. Clearly, the CRB value for some specific crude oils has failed to comply with its correlation with API gravity. For example, some heavy and medium crude oils presented a critical break value in corrosion rate at water cut below 10%. Besides crude oil density, there must be other key factors in determining pipeline corrosion. This is a very complex issue. However, it makes little sense to directly correlate the corrosion rate value with the density and viscosity of crude oil.

2.1.3 Crude oil chemistry

Crude oil contains a variety of hydrocarbons and different types of organic compounds. The corrosion behavior of steels is very sensitive to some specific compounds in crude oil-brine solutions. A number of crude oils are selected as models to clarify the inherent roles of chemical constituents during corrosion. According to a comparison among three geochemical types of kerogen oils, the aromatic chains are more protective than paraffinic chains in crude oils (Lotz et al., 1991). A recent study also confirmed the weak influence of paraffin on corrosion of mild steel (Yang, Richter, Robbins, & Nesic, 2012). Lotz et al. (1991) also pointed out that immature hydrocarbons dispersed in the water phase can reduce the corrosion rate more markedly than mature hydrocarbons. The immature crude oil generally contains a larger amount of surface-active compounds compared with the mature one. The role of these beneficial compounds in corrosion is viewed to behave like corrosion inhibitors (Efird et al., 2004; Lotz et al., 1991; Store et al., 2011). Therefore, the influence of crude oil chemistry on corrosion has been mainly attributed to water-soluble, surface-active compounds. Further, there are experimental data supporting the direct correlation of steel corrosion rate with the nitrogen and sulfur content in crude oils (Efird & Jasinski, 1989; Hernandez, Duplat, Vera, & Baron, 2002a; Hernandez, Nesic, Weckman, & Ghai, 2006), revealing their beneficial effect on corrosion protection.

To advance the understanding of crude chemistry effect on corrosion, some specific compounds were extracted from crude oils for inhibition tests (Hernandez, Bruzual, Lopez-Linares, & Luzon, 2003; Mendez, Duplat, Hernandez, & Vera, 2001). Saturates, aromatics, resins, and asphaltene (SARA) were separated from a Venezuelan crude oil (Mendez et al., 2001), and then corrosion and adsorption behavior were measured for each extracted compound in brine solutions. During corrosion tests, a high stir rate of 500 rpm was used to generate homogeneous oil-brine mixture with addition of a small amount of crude oil or the extracted components (Mendez et al., 2001; Rincon, Hernandez, Case, & Salazar, 1999). Based on their result, the resins were found to have the highest inhibition efficiency and adsorption coverage. However, according to a qualitative characterization of the polar function groups in these compounds, it is suggested that the aromatic compounds present the best inhibition effect in resin crude oils (Mendez et al., 2001). Based on a statistical analysis of the experimental data (Hernandez et al., 2002a), the sulfur content and nitrogen content were found to be the most decisive factors affecting the corrosiveness of aqueous solutions dispersed with asphaltenic and paraffinic crude oils, respectively. This has been further confirmed by the corrosion analysis regarding other crude oils, which is related to the alteration of brine chemistry (Efird et al., 2004). In the condition of crude oil behaving as continuous phase, the polar functional groups in the resin or asphaltenes seem helpful in the formation of stable emulsions. Asphaltene extracted from Arab heavy crude oils was evaluated to be much inhibitive to corrosion (Ajmera, Robbins, Richter, & Nesic, 2011), relating to its adsorption and persistence on the steel surface.

On the basis of previous understandings, focused studies have been made regarding the influences of some subclass compounds on the corrosion inhibition and the wettability behavior of crude oil. Four classes of compounds were evaluated by Ayello, Robbins, and Richter (2011). Aromatic compounds were found to be ineffective for corrosion inhibition and presented little effect on the wettability of crude oil. However, the authors speculated that aromatics may become helpful for reducing the corrosion risk in water-in-oil (w/o) dispersion flows, possibly owning to their positive effect on the stabilization of emulsions or dispersions. Oxygen-containing compounds, especially the high-molecular-weight organic acids, were verified to be the most effective agents in reducing the corrosion rate and alternating the wettability of steel surface. This was attributed to the accumulation of surface-active compounds at the steel surface. Not all the sulfur- and nitrogen-containing compounds present significant effect on corrosion inhibition and wettability, as the effect relies on the adsorption of these active compounds on the steel surface.

2.2.1 Formation of emulsion during crude oil production

The formation of emulsion needs to meet the following three criteria (Abdel-Raouf, 2012). First, two immiscible liquids must be brought in contact; second, surface-active components must present as the emulsifying agent, which is essential for stabilizing the interface between oil and water; third, a sufficient mixing or agitating effect must be provided to disperse one liquid into another as droplets. During crude oil production, brine generally comes out together with crude oils. The solubility of water phase in crude oil is very low, from 0.1 to 2.0 mol% as a function of the production temperature (Graig, 1998). A variety of surface-active compounds can be detected in crude oil, such as SARA, especially, the asphaltenes, which act as natural emulsifiers. During crude oil production from the reservoirs, there are many possibilities for sufficiently mixing crude oil with brine, including the shear effect by stratum, pressure drop in the wellbore, rolling effect by the gas phase, and so on, which can promote the turbulence of oil-brine flows. Emulsification would be extremely enhanced in low-permeability reservoirs. Therefore, it is concluded that emulsification is a common phenomenon during crude oil production.

The emulsions produced in oilfield can be classified into three groups: (1) water-in-oil (w/o) emulsions, (2) oil-in-water (o/w) emulsions, and (3) multiple emulsions (Abdel-Raouf, 2012). In the oil industry, w/o emulsions are very common. In this condition, corrosion risk of pipeline steel is sharply reduced. For the transportation of heavy crude oils, an o/w emulsion is often helpful (Abdurahman, Rosli, Azhari, & Hayder, 2012; Ashrafizadeh & Kamran, 2010; Papavinasam et al., 2007). Corrosion of pipeline steel in o/w emulsions may be inhibited by increasing the content of crude oil in the emulsions (Becerra, Retamoso, & Macdonald, 2000; Zhang & Cheng, 2009). In some cases, the multiple emulsions (for example, water-in-oil-in-water emulsion) can be observed (Abdel-Raouf, 2012; Kokal, 2005).

The typical microstructures of the w/o and o/w emulsions are illustrated in Figure 1, which are obtained by mixing a Shengli crude oil with a brine solution at 60°C (Wang, et al., 2015; Wang, et al., 2014c). During oil production, the droplet sizes have a broad range, from 0.1 to >50 μm in diameter. Generally, the smaller the average size of the dispersed droplets, the longer the emulsion time is kept (Kokal, 2005). In this view, the emulsion was divided into three types, i.e. tight, medium, and loose emulsions. The separation of a tight emulsion requires longer time, whereas water is much easier to break from a loose emulsion. In most cases, medium and loose emulsions were encountered during crude oil production.

Figure 1:

Typical microstructures of (A) a w/o emulsion and (B) an o/w emulsion.

The w/o emulsion was prepared by mixing the crude oil (with API gravity of 29.3) with 30 wt% brine solution in a reservoir with stirring rate of 1200 rpm for 1 min. The o/w emulsion was prepared by mixing the crude oil with 90 wt% brine solution at a similar condition for emulsification. The composition of the brine solution was (0.1 mol NaCl+0.01 mol NaHCO₃+0.01 mol CaCl₂)/l to mimic the produced water in the CO₂-EOR field condition in the Shengli oilfield. The micrographs were observed by a stereomicroscope.

2.2.2 Emulsion inversion point

At low water cuts, the water droplets can be totally dispersed in the continuous oil phase if a w/o emulsion forms. With increasing water cut, a change of the emulsion structure from w/o to o/w occurs. This critical water cut is defined as the EIP (Fingas & Fieldhouse, 2004; Papavinasam et al., 2007; Xu, 2007). According to Ostwald’s model, the maximum water cut forming a w/o emulsion cannot exceed 74 vol% (De Waard et al., 2003; Xu, 2007). Actually, this critical inversion water cut is generally observed between 60 and 80 wt% (Fingas & Fieldhouse, 2004; Kokal, 2005), depending on the stability of the emulsion. A method to determine the EIP was suggested by measuring the conductivity between two close pins positioned in a flow pipe (ASTM, 2010). Alternatively, the EIP can also be determined by changes of the viscosity as a function of water cuts. It has demonstrated that the w/o emulsion presented a highest value of viscosity at the critical water cut of EIP (Fingas & Fieldhouse, 2004; Kokal, 2005). At a same crude oil-brine system, the formation of a tighter emulsion often relates to a higher EIP.

A corresponding parameter to EIP of an emulsion is the phase inversion point (PIP) of an oil-brine dispersion system. The dispersion mentioned here is not an emulsion. It is a state of water droplets entrained in the crude oil or, inversely, oil droplets entrained in the water phase. The PIP refers to the critical water cut below which the water phase can be well dispersed and entrained into the flowing oil phase as small droplets. Different from EIP, PIP is a flow-dependent parameter and can be determined in a pipe flow tests by measuring the changes in pressure drop (Nädler & Mewes, 1997; Xu, 2007). At the PIP, the continuous phase of the flow is changed from crude oil to water. The input water cut at PIP has been demonstrated to decrease with the increase of the oil viscosity (Nädler & Mewes, 1997). There are many existing models to estimate the PIP in oil-brine dispersions, which is closely correlated with the density and viscosity of crude oil (Xu, 2007). This can explain the dependence of the critical water break on API gravity, as proposed by De Waard et al. (2003). The experimentally measured PIP values are generally varied within a wide range of water cuts, depending on many testing factors, such as viscosity, flow rate, inclination, temperature, and so on (Xu, 2007). The commonly reported PIP values are from 30 to 40 wt% (Fingas & Fieldhouse, 2004; Xu, 2007), which are similar to the critical water cut for CRB in most oil-brine mixed flow conditions (Carew et al., 2000; Choi et al., 1989).

Determination of the critical water cut of CRB is a basis of understanding the corrosion phenomenon in oil-brine mixed conditions. Many attempts have been made to directly measure the corrosion rate variations of steel samples as a function of the water cuts in oil-brine mixtures (Choi et al., 1989; De Waard et al., 2003; Efird & Jasinski, 1989; Lotz et al., 1991; Papavinasam et al., 2007; Rincon et al., 1999). Most of the experiments were conducted in a high-pressure autoclave. Some of the data were collected from field conditions (De Waard et al., 2003). One assumption of these research is the formation of an emulsion during the tested periods because a high stirring rate is often used for keeping the stability of emulsions, as indicated in Table 1. However, these studies rarely characterized the state and stability of the corrosive emulsions. Investigation on the microstructures and the viscosity changes of the emulsions is very helpful in understanding the corrosion phenomenon in this complex system (Wang, et al., 2014c). Therefore, to understand the nature of steel corrosion in oil-brine mixtures, it is necessary to correlate the stability of emulsions with corrosion phenomenon.

2.2.3 Process of water separation from w/o emulsion

Emulsion is metastable in nature. Once it forms, the two immiscible liquid phases (oil and brine) are prone to separate from each other. There are three processes for water separation from the emulsion (Abdel-Raouf, 2012). The first step is the flocculation or aggregation of dispersed drops in the emulsion; the second step is the coalescence of two or more emulsion drops to form a single larger drop, which is an irreversible process; the third step is phase separation, i.e. emulsion breakdown. Many factors may affect the stability of emulsions (Abdel-Raouf, 2012; Kokal, 2005), including the content of surface-active compounds, the presence of solid particles, pH value of the brine solution, the averaged size of dispersed drops, viscosity, and temperature. Also, aging of crude oil may decrease the stability of w/o emulsions (Filho, Ramalho, Spinelli, & Lucas, 2012), thus influencing the corrosiveness (Papavinasam et al., 2007).

Even when a small amount of water is separated from the emulsion and persistently contacts with the internal pipe wall, pipelines may suffer from serious electrochemical corrosion. Therefore, determination emulsion stability is one of the most important tests for corrosion prediction (Wang, et al., 2014c; Wang et al., 2015). There are numerous methods available for determining emulsion stability (Kokal, 2005). By far, the most common method is the simple bottle test, which is directly observing the separated phase volume as a function of time at certain temperatures. Besides the experimental methods, the time of water break from w/o emulsion can be theoretically estimated according to Stokes equation and coalescence of droplets (Arnold & Stewa, 1999). Understanding emulsion stability is helpful for corrosion prediction. Corrosion can be managed by changing the transporting parameters to keep the stability of w/o emulsions (Wang et al., 2015).

2.3.1 State of oil and water in pipelines

There are several methods to identify the flow patterns in crude oil-brine mixture transportation pipelines. According to the degree of mixing, the crude oil-water two-phase flow patterns can be classified as stratified flow, semi-mixed flow, and dispersed flow (Shi, Cai, & Jepson, 1999). Owing to the discrepancy in density, water phase is prone to be transported beneath crude oil in the pipeline fluids. As proposed by Vedapuri et al. (Shi et al., 1999), oil-water flow has been treated as a three-phase stratified flow with a water layer at the bottom, an oil layer on top, and a mixed layer at the center of the pipe. Therefore, corrosion generally happens at the bottom part of the pipeline in lamellar flow conditions.

The flow patterns closely depend on the water cut and the mixing flow velocity (Arirachakaran, Oglesby, Malinowsky, Shoham, & Brill, 1989). Direct contact of water with steel surface is essential for triggering corrosion. Therefore, more details of the flow characteristics related to the contact state of water with pipe wall should be emphasized. As shown in Figure 2, there are at least five types of contacting conditions. The first type is the water phase totally entrained as droplets in the crude oil flow, avoiding direct contact with steel surface. Obviously, in this condition, corrosion is completely inhibited. The second type relates to the direct contact of some large water droplets with steel surface. However, the water droplets can move away or slip from one site to another on the steel surface. In this condition, an intermittent water/oil wetting is encountered. Therefore, corrosion may occur at certain sites, but it is also significantly inhibited by flowing crude oils. For the third type in Figure 2C, the accumulation of water droplet becomes obvious. A water layer may locally form at the bottom of pipelines, and it is not easy to remove by flowing crude oils, leading to a long-term exposure of steel surface to corrosive brine solution. In this way, corrosion may be observed at the sites contacting with the water phase. In Figure 2D, a lamellar type flow is illustrated, where corrosion will happen at the bottom part of the pipeline as mentioned above. As the water cut increases, such as for the fifth condition shown in Figure 2E, the bottom of the pipelines may partially contact with crude oil phase or droplets. This condition generally relates to a high flow velocity and a relatively high water cut. The presence of crude oil patches at the bottom of pipelines may affect the localized corrosion behavior. This classification is based on the flow pattern analysis by Charles et al. (1961), which seems helpful for the corrosion analysis in an oil-brine mixed solution contacting with the internal pipe wall. The movement of water droplets in crude oil was also previously considered for modeling corrosion in crude oil-brine mixtures (De Waard et al., 2003).

Figure 2:

Illustration of the oil-water two-phase flow patterns to highlight the contacting conditions of oil phase and water phase with the pipeline surface.This classification of flow patterns is referenced from Charles, Govier, and Hodgson (1961).

2.3.2 Water-wetting behavior on steel surfaces

Water wetting is essential for corrosion initiation on steel surfaces in an oil-brine mixed condition (Cai et al., 2012; Larsen, 2013; Smart, 1993). It should be noted that contacting and wetting are two different processes. In Figure 2, the contacting possibility of water phase (or water droplet) with steel surfaces has been illustrated. Actually, the tendency of water to displace crude oil from steel surface can be estimated by comparing the surface energies of all these interfaces. The Young’s equation (4) is generally used to express the relations between these interfacial tension forces,

where γ_so is the interfacial energy between the oil and the steel surface, γ_sw is the interfacial energy between the water and the steel surface, γ_wo is the interfacial energy between the oil and the water, and θ is the contact angle at the oil-water-steel interface measured through the water. If the contact angle is between 0° and 90°, the steel surface will be preferentially wetted by water, presenting a hydrophilic characteristic; if the contact angle is between 90° and 180°, displacement of water by crude oil should be expected, referring to a hydrophobic surface. Therefore, a number of studies have focused on the measurement of the contact angle and its relation to corrosion (Ajmera et al., 2011; Ayello, Robbins, Richter, & Nešić, 2013; Foss, 2009; Papavinasam et al., 2007). An alternative method to measure the wettability is a spreading test by examining the conductivity of a group of probes in oil-water mixtures. The merit of this wettability spreading method is that it can be conducted in higher pressure and flow conditions.

It has been recognized that a hydrophobic surface is beneficial for mitigating steel corrosion in oil-brine mixtures. According to previous understanding, wettability plays a predominant role in affecting the S-curve behavior of corrosion rate in oil-brine mixture solutions (Craig, 1996). The S-curve behavior has been observed in many crude oil-brine systems. At relatively low water cuts, corrosion rate is extremely low; at medium water cuts, corrosion rate increases sharply with water cuts, presenting a corrosion break phenomenon; at relatively high water cuts, corrosion rate gradually reaches to a higher value comparable to that observed in brine solution. According to Craig (1996), the sharp transition of corrosion rate at medium water cuts may be attributed to an intermittent water/oil wetting of the steel surface. Many factors may change the wetting behavior of oil and water contacting with steel surface, such as the surface properties (Foss, Gulbrandsen, & Sjoblom, 2010), the viscosity of crude oil, temperatures, the partial pressure of CO₂ gas (Emera & Sarma, 2007; Papavinasam et al., 2007), some chemical agents in crude oil (Ayello et al., 2013), and corrosion inhibitors (Foss et al., 2010; Li, Richter, & Nešić, 2014). Many studies also pointed out that the wettability behavior may be greatly changed under flow conditions (Efird et al., 2004; Nesic & Carroll, 2003). Clearly, a direct correlation between the corrosion rate and the wettability behavior, which is based on the typical contact angle measurements, has limited beneficial impact on the understanding of the corrosion mechanisms. It is necessary to build a method for in situ observation of the wetting behavior of water droplets and their spreading at the steel surface during corrosion in crude oil-brine mixtures.

Intermittent wetting of the steel surfaces is a common state of oil-water fluid during production. It seems that intermittent oil wetting is beneficial for mitigating corrosion compared to the complete water-wetting condition (Cai et al., 2012). However, little attention has been paid to the corrosion mechanism in oil/water intermittent wetting conditions. It is significantly important to clarify the relation of corrosion with wettability of steel surface under flow conditions.

2.3.3 Entrainment of water in crude oil fluids

The internal corrosion of pipelines is directly connected to water wetting. The area where water is settled is likely to cause corrosion problems. To entrain water droplet into crude oil fluids, a critical flow velocity is needed (with a minimal velocity of 1 m/s for most crude oils), which increases with pipe diameter (Wicks & Fraser, 1975). When the water cut is below 30%, the entrainment of water in crude oil seems easy (Fingas & Fieldhouse, 2004; Lotz et al., 1991; Nesic & Carroll, 2003; Xu, 2007). Recently, the critical velocity for the entrainment of water in crude oil has been experimentally determined in different water cut conditions by mapping the phase wetting characteristics in a horizontal pipe and a prediction model has been developed (Cai et al., 2012). Based on Cai et al. (2012), a higher flow velocity is required for the formation of dispersion in oil-brine mixtures with larger water cuts. In this case, increase of flow velocity is beneficial for reducing corrosion risks. However, continuous oil dispersion cannot be formed, and a higher flow velocity will enhance the corrosion of pipeline. This observation agrees with some previous results that in a condition with 40% water cut, an enhanced corrosion was observed with increasing the flow velocity (even up to 1.8 m/s), which has been attributed to local turbulence and the staying time of water droplets on steel surface (Choi et al., 1989). Wang et al. (2015) also measured an enhanced corrosion rate as increasing flow velocities in oil-brine mixture flows with a water cut of 95% (Wang et al., 2015). Obviously, without the formation of crude oil-based dispersions, a higher flow velocity is detrimental to pipeline corrosion, which can be referenced from corrosion mechanisms in single aqueous flow conditions (Heitz, 1991; Schmitt et al., 2000).

Besides flow velocity and water cut, the stability of water-entrained system during crude oil transportation may be dependent on such factors as viscosity and density of crude oil, temperature, and existence of surfactants, which determine the separation of water from production fluids. Therefore, heavy and viscous crude oils are prone to entrain a larger volume of water. An enhancement effect of surfactants on the mixing of oil and water has also been noted (Shi et al., 1999), which may reduce the corrosion risk of pipelines by the entrainment of water at a lower flow velocity. In flowing conditions, the water droplet size may range from tens of micrometers to several millimeters (Sarica & Zhang, 2008). The droplet size in flowing dispersions is obviously larger than that in emulsions.

2.4.1 Oil-water-gas three-phase flow patterns

Three-phase gas-oil-water flow patterns are actually a combination of gas-liquid and oil-water flow patterns. There are several methods to identify the characteristics of flow patterns in this three-phase flow. If water and crude oil are mixed well during transportation, the flow pattern can be viewed similar to the gas-liquid two-phase flow patterns (Sarica & Zhang, 2008). Based on the classification of gas-liquid two-phase flow patterns, generally, eight kinds of flow patterns were identified (Efird, 2011; Kang, Wilkens, & Jepson, 1996), i.e. bubbly, smooth stratified, wavy stratified, rolling wave, plug flow, slug flow, pseudo slug, and annular flow. When the distribution of oil and water in pipe is further considered, 12 individual three-phase flow patterns can be identified (Sarica & Zhang, 2008). During oil production, slug flow is the most common flow patterns. Therefore, the corrosion phenomenon related to slug flow were preferentially investigated in horizontal, inclined, and vertical pipes, including the effect of superficial gas velocity (Kang, Jepson, & Gopal, 1999; Maley, 1997), wall shear stress (Wang, Cai, Bosch, Jepson, & Hong, 2002; Zheng et al., 2008), slug frequency (Kang et al., 1996; Maley, 1997; Wang et al., 2015), and Froude number (Chen & Jepson, 1999; Kang et al., 1996). Owing to the similarities in flow patterns between the gas-liquid flow and the oil-water-gas three-phase flow (Sarica & Zhang, 2008), most previous efforts have been made in correlating corrosion with flow characteristics in the gas-liquid two-phase flow conditions. For a given multiphase flow that contains crude oil, visualization of the flow patterns is still a challenging issue. This may be another important reason for correlating corrosion with flow patterns in gas-liquid two-phase flow conditions without the presence of crude oil. Note that the flow pattern greatly depends on the oil content and viscosity of the mixtures. Therefore, further studies should be relevant to the conditions of crude oil production. Other methods to determine flow patterns by pressure drop (Sotgia, Tartarini, & Stalio, 2008), wetting behavior (Cai et al., 2012), or phase density distribution (Hoffmann & Johnson, 2011) are helpful for corrosion analysis in an oil-water-gas three-phase flow.

2.4.2 Influence of gas flow on liquid slug behavior

The multiphase flow patterns are decisively related to the presence of gas and the value of the gas flow rate. The flow pattern is generally described as a function of the oil-water mixing velocity and the superficial gas velocity. Obviously, there are at least two functionalities of gas flow affecting the multiphase flow patterns. The first one is its effect on the frequency of liquid slugs, which is one of the key factors in characterizing flow patterns. Experimental results indicated that a higher gas flow rate produces lower frequencies of the liquid slugs at a constant liquid velocity (Kang et al., 1999; Villarreal, Laverde, & Fuentes, 2006; Wang et al., 2015). A lower slug frequency reduces the corrosion rate of pipelines. A sharp increase in the wall shear stress has been observed when the liquid slug goes through (Yang, Brown, Nesic, Gennaro, & Molinas, 2010), which may induce the damage of corrosion products (Schmitt et al., 2000). It is also observed that a higher gas flow rate would reduce the pressure drop of a segment of pipelines (Wang et al., 2015), which is consistent with the decrease in shear stress at the flow/pipe wall interface, thus reducing the pipeline corrosion. Another reason for the mitigation of corrosion rate under low frequency of liquid slug may be attributed to a reduction of water wetting. To date, the correlation between slug frequencies and corrosion behavior was mainly investigated in the gas-brine two-phase flow conditions or the oil-brine-gas three-phase flow conditions with very high water cuts. In such multiphase flow conditions, the oil and brine phases are simply viewed as a single, well-mixed liquid phase (Sarica & Zhang, 2008).

However, in most cases, the oil phase is not completely dispersed into the brine phase and vice versa. Therefore, corrosion would be locally different around the internal pipe wall. A higher corrosion rate may be observed at the bottom of pipelines, which is prone to water-wetting. To avoid bottom-of-the-line corrosion in a multiphase flow condition, the free water must be totally entrained into crude oil. In an oil-brine two-phase flow condition, a higher mixing velocity is helpful to reduce pipeline corrosion by the entrainment of water via flow turbulence (Cai et al., 2012; Shi et al., 1999; Wicks & Fraser, 1975). However, without the presence of crude oil, a higher liquid flow rate may induce an enhancement in corrosion rate in liquid-gas flow conditions (Kang et al., 1999). Therefore, it is interesting to understand the role of gas flow in affecting the corrosion of the pipeline. Recently, it has been suggested that a higher gas-to-liquid ratio may be beneficial in reducing the multiphase flow corrosion, owing to a rolling effect of the high gas flow rate on the liquid film (Wang et al., 2015). A critical gas-to-liquid ratio was theoretically determined by resolving the Froude number (F_r), which can be expressed as

where v_t represents the velocity of the forward-facing part of a liquid slug, v_f is the velocity of liquid film at the pipe bottom, g is the acceleration of gravity, and h_eff is the effective height of liquid film. Actually, the Froude number has been suggested years ago to understand the multiphase flow corrosion behavior (Kang et al., 1999; Shi et al., 1999). The authors defined the strength of the slug proportional to the Froude number calculated in the liquid film ahead of the slug. Based on this assumption, a relationship between gas-to-liquid ratio, liquid flow rate, and the Froude number was built, from which a critical gas-to-liquid ratio can be identified as an indicator for the gas rolling effect (Wang et al., 2015). As can be seen in Figure 3, below this critical ratio, a higher corrosion risk of the pipelines may be encountered. Therefore, the Froude number is an important parameter in characterizing the gas-liquid multiphase flow patterns.

Figure 3:

Corrosion risk diagram of different Froude numbers as a function of critical gas-to-liquid ratio and liquid velocity.

This was redrawn according to the corrosion risk model of Wang et al. (2015). From the graph, the critical conditions that are prone to entraining water in crude oils can be determined. The dashed line was roughly estimated.

3.2.1 Electrochemical method

Although the limitations of electrochemical test has been noted in bad conductive solutions, this method is still used in high water cut conditions, especially for the condition of water or brine as continuous phases. Conventional electrochemical techniques, such as the linear polarization resistance (LPR) test (Foss, 2009; Gulbrandsen & Kvarekval, 2007; Mendez et al., 2001), EIS (Lotz et al., 1991; Mendez et al., 2001; Wang, et al., 2014c; Zhang & Cheng, 2009) and potentiodynamic polarization test (Jasinski & Efird, 1988; Zhang & Cheng, 2009) are all suggested to evaluate the corrosion process of pipeline steels in oil-brine mixture solutions. EIS measurement is often used to determine the electrochemical resistance or interfacial behavior, owing to its high sensitivity to the surface reactions. The electrical resistance of the testing solutions (between the working electrode and the counter-electrode) can be derived from EIS data (Lotz et al., 1991; Wang, et al., 2014c). It is also suggested that the coverage of steel surface by crude oil can be calculated by measuring the interfacial capacitance from EIS tests (Mendez et al., 2001). In most cases, EIS measurements, as well as other electrochemical testing methods, were used to evaluate the corrosion resistance of steel to corrosive oil-brine mixtures. It has been experimentally proved that EIS measurement is impossible when the crude oil phase becomes continuous (Lotz et al., 1991; Wang, et al., 2014c). In this condition, other electrochemical signals are also hard to read from the conventional three-electrode electrochemical system (Wang, et al., 2014c).

3.2.2 Weigh loss measurement

There is no doubt that weight loss measurement is generally viewed as a standard method for other corrosion tests. Nearly in all the published papers about steel corrosion in oil-brine mixed conditions, weight loss measurement was involved. In addition to composition of the solution, many other factors may decide the measurement of its corrosiveness, such as test duration, impeller type, and solution volume. These factors are closely related to the preparation and the stability of emulsions or the state of oil-brine mixtures, which may change during corrosion tests. It seems that in autoclave testing, the selection of a propeller type of stir impeller is more effective for mixing because the propeller produces mixing along the axis direction, i.e. vertical direction. Separation of water and oil may happen in a long-term immersion test in stagnant oil-brine mixtures (Wang, et al., 2014c). In contrast, in a highly stirred condition, a long-term test may produce more stable emulsion, totally changing the initial state of the mixtures. Clearly, during the measurement of corrosion rates, these factors must be carefully considered.

3.2.3 Conductivity measurement

The estimation of corrosiveness of oil-brine mixtures by measuring their conductivity was suggested in 1990s (Craig, 1996). This method is helpful for quantitatively determining the corrosiveness of a w/o emulsion. There are a number of methods to measure the solution resistance, for example, a direct measurement of the conductivity and a calculation of EIS data. By measuring the conductivity of the oil-brine mixed solutions (in flow conditions or nearly stagnant conditions) as a function of water cuts, a critical water cut of the conductivity jump can be observed (Papavinasam et al., 2007; Wang, et al., 2014c). The value of water cut has been related to EIP or PIP in different conditions (see Table 1).

Measurement of the conductivity was also used in determination of the local wettability of the oil-water two-phase flow (Cai et al., 2012; Li et al., 2006). It continuously recorded the signals from a series of tiny conductivity pins, which were mounted in the internal pipe wall. This is one of the possible methods for correlating water wetting with flow conditions (such as water cut, flow rates, oil properties, and brine composition).

3.2.4 Corrosion probes

The presence of crude oil in testing fluids brings some technical challenges for the application of corrosion probes. The most important issue is the heterogeneous coverage of the probe head (or the steel surface) by crude oil, leading to invalidity for corrosion detection. Therefore, corrosion probes used in crude oil-brine mixture fluids should be specially designed. Several types of corrosion probes have been used in corrosion measurement in oil-brine mixed conditions. The electrochemical probes are much sensitive to the presence of crude oil. To overcome this weakness, the dielectric materials between testing electrodes were modified to be ionically conductive (Jasinski & Efird, 1987). Therefore, the LPR tests can be used for corrosion tests in crude oil-containing solutions, even in the condition of w/o emulsions (Jasinski & Efird, 1988).

In recent years, a kind of corrosion probes called “wire beam electrode” or “multi-electrode array” were developed (Gui, James, & Sridhar, 2012; Tan, Bailey, & Kinsella, 2001), revealing the current maps at the steel surface. This technique has been found to be effective in detecting the localized attack behavior during corrosion of steels in oil-brine mixtures. However, for an in-depth understanding of the corrosion propagation at the steel surface in such a heterogeneous solution, the resolution needs to be greatly improved because the entrained water droplets are generally sized in the micrometer scale.

Besides, some commercial corrosion probes have also been tried in the corrosion evaluation in oil-brine mixed conditions for a variety of purposes. Detailed information can be found in related references (Wang, et al., 2014c; Wang et al., 2015).

3.2.5 Other complementary methods

Detection of the concentration of ferrous ion in aqueous solutions is an indirect method to estimate the degree of corrosion damages. This method has been widely used in the field conditions, which was also accepted in multiphase flow experiments (Li et al., 2006). However, the correlation between ferrous ion concentration and corrosion is still as straightforward as it seems. At the same time, the release of ferrous ion may induce a feedback effect on corrosion behavior in CO₂-containing environments (Bian, Wang, Han, Chen, & Zhang, 2015). Therefore, it seems to be effective only for a rough comparison of the corrosion performance.

4.1.1 Formation of stable water-in-oil emulsion

If the fluid can form a w/o emulsion during production, corrosion will not be a problem. Therefore, an investigation of the emulsion state of the oil-brine mixtures at wellheads is essential for predicting the corrosion risk of the gathering and transportation pipelines. A simple notion for the corrosion risk analysis has been suggested based on the assumption that corrosion would only occur when free water was separated from a w/o emulsion (Wang, et al., 2014c). Hence, a relation among transportation distance (L_T), transportation velocity (v_T), and time for water separation from a w/o emulsion (t_w) can be described as

According to this simple notion, corrosion could be avoided if the w/o emulsion is transported to the destinations before water separation. It is expected that a higher flow velocity is helpful in reducing the corrosion risk of pipelines. Clearly, it is important to determine the time of water separation from a w/o emulsion. As mentioned in Section 2.2.4, there are experimental and theoretical methods to estimate the stability of the emulsions.

The formation of a w/o emulsion is relied on the actual field conditions, such as the water cuts of fluids, properties of crude oil, and production environment. At some extreme conditions, the w/o emulsion can be formed at very high water cuts, for example, the experimentally measured EIP is generally reported to be as high as 70 wt% (Fingas & Fieldhouse, 2004; Wang, et al., 2014c), which means that a w/o emulsion can be formed at a relatively high water cut under sufficiently sheared or stirred conditions. However, in oil production, it is impossible to completely emulsify the oil-brine mixtures with too high water concentration. Generally, a w/o emulsion containing less than 30 wt% water can be relatively stable under field conditions (Fingas & Fieldhouse, 2004). Note also that when the water cut is higher than 30 wt%, the dynamic viscosity of the w/o emulsion increases sharply (Wang, et al., 2014c), which makes the transportation of production fluids difficult. Heating the transportation fluids may induce an easier separation of water, increasing the risk of corrosion damage of the pipelines.

Actually, at a very high flow velocity, the oil-brine mixed fluids is prone to becoming a turbulent flow. This kind of flow pattern enhances the emulsification of oil and brine phases, entraining the water droplets in crude oil more stably and persistently. However, to ensure a low-pressure drop in the onshore production pipelines, turbulent flow is not an optimum choice. Therefore, the stirring effect from turbulent flow during crude oil transportation is very weak. Things may be different for the offshore production process. As known from Table 1 and related references, the corrosion measurements in a w/o emulsion are commonly conducted in an autoclave with very high stirring rates to keep the stability of the emulsions. This probably produces both flowing and emulsifying effects. During the entire corrosion test period, the oil-brine mixture remains highly emulsified. It seems that corrosion tests under stagnant or slightly stirred conditions might be more appropriate for estimating the corrosiveness of the w/o emulsion fluids.

4.1.2 Formation of w/o dispersion

In some conditions, the water droplets are completely entrained in crude oil, but they are not fine enough to form a w/o emulsion. The main difference between an emulsion and a dispersed flow is their stability. Free water will be separated within a very short period from a w/o dispersed fluid when the flow velocity is lower than the critical one for entrainment of these large water droplets. As presented in Figure 2A and B, water cut is an important factor in analyzing the corrosion probability of pipelines. The generally observed PIP water cut is related to the possible onset of corrosion, which is dependent on the flow rates. In most cases, both w/o emulsion and w/o dispersion coexist in an oil-brine mixed fluid, i.e. the dispersion can be viewed as a destabilized emulsion. There is no clear identification of the corrosion phenomenon in these two states of crude oil-brine mixtures in previous studies. The maximum diameter of water droplet that can be sustainably entrained in the flowing crude oils can be estimated by a balance between the turbulent kinetic energy and the droplet surface energy (Barnea, 2001; Li et al., 2006).

4.2.1 Intermittent oil wetting

If crude oil is present as the continuous phase in the oil-brine mixtures, keeping the pipeline surface free from water wetting, corrosion can certainly be avoided. As illustrated in Figure 2B and C, at a relatively high water cut that the total entrainment of water droplets becomes impossible, the steel surface may be wetted intermittently or periodically by the oil and aqueous phases. The oil-water two-phase flow loop test indicated that the corrosion rate was retarded under intermittent conditions when compared with full water wetting (Li et al., 2006). However, it should be noted that the corrosion inhibitive agents in crude oil may also decisively affect the mitigation of corrosion rate measured in an intermittent wetting condition (Cai et al., 2012).

In a stagnant condition, the wettability of steel surface is dependent on the interfacial tensions of oil and water on steel surfaces. In a flow condition, the intermittent wetting behavior closely depends on the flow pattern characteristics (Nesic & Carroll, 2003). Several research have demonstrated that with increasing flow rate, the steel surface can be changed from water wetting to intermittent wetting or oil wetting (Nesic & Carroll, 2003; Cai et al., 2012). From the view of flow characteristics, the intermittent wetting behavior of steel surfaces reflects the degree of water entrainment in crude oil. A high gas-to-liquid ratio is also used to manage the wetting behavior of the bottom of pipelines, thus reducing the pipeline corrosion in multiphase flow conditions (Wang et al., 2015). This is consistent with the notion that corrosion can be mitigated in an oil-predominant oil-brine mixed flow by increasing turbulence (Wicks & Fraser, 1975).

4.2.2 Crude oil adsorption

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 longer time. For example, Wang, et al. (2014c) found that a pre-formed crude oil layer can only persist for about 15 min in a stagnant condition. Note that this observation is dependent on crude oil chemistry and experimental conditions. In their experiments, Wang, Zhang, Wang, et al. use crude oil with an API gravity of 29.3, and all the tests were conducted at 60°C. In a flow condition, the removal of crude oil layers becomes much easier. Three factors may contribute to the persistence of a crude oil layer on steel surfaces. The first one is the properties of steel surfaces. The wettability of a steel surface may be varied during corrosion owing to the formation of corrosion product layers (Papavinasam et al., 2007). If a surface is preferential to oil-wetting, an improved protectiveness of the steel surface will be expected. The second factor is the properties of crude oil. Ayello et al. (2013) pointed out that some large molecular compounds in crude oils are capable of forming a hydrophobic layer on the surface, thereby changing the wettability of the surface and producing substantial inhibition roles. According to the analysis based on SARA crude oils (Hernandez et al., 2002a), sulfur- and nitrogen-based compounds may serve as the pre-adsorbed species in the crude-oil phase. Besides crude oil chemistry, the viscosity of crude oil and environmental temperature are also viewed as important factors affecting the adsorption of crude oil on steel surface and preventing corrosion.

The heterogeneous adsorption of crude oil on the steel surface may induce localized corrosion. The degree of localized corrosion may be different from the averaged corrosion rate in oil-brine mixed conditions (Choi et al., 1989), but this phenomenon and its mechanisms have not been clearly addressed. The non-uniform corrosion phenomenon of steel surface in a crude oil-brine mixture was visualized using the wire beam electrode system (Tan et al., 2001). The adsorption of crude oil also greatly varied the erosion-corrosion mechanism maps in oil-water-sand three-phase flow conditions, depending on flow velocity and impact angle (Stack & Abdulrahman, 2012).