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Failure analysis of carbon dioxide corrosion through wet natural gas gathering pipelines
Engineering Failure Analysis 105 (2019) 638–646
Contents lists available at ScienceDirect
Engineering Failure Analysis journal homepage: www.elsevier.com/locate/engfailanal
Failure analysis of carbon dioxide corrosion through wet natural gas gathering pipelines
T
⁎
Ammar Ali Abda,b, , Samah Zaki Najia,c, Atheer Saad Hashimb,d a
Chemical Engineering Department, Curtin University, Perth, Australia Water Resources Engineering College, Al-Qasim Green University, Babylon, Iraq. Petroleum Engineering Department, Kerbala University, Kerbala, Iraq. d Mechanical Engineering department, Nottingham University, Nottingham, United Kingdom. b c
A R T IC LE I N F O
ABS TRA CT
Keywords: CO2 corrosion HYSYS Natural gas pipelines Internal corrosion
The aggressive behavior of carbon dioxide dissolved in water considers as one of basic reasons behind corrosion failure in oil and gas processes. Simulation study using HYSYS program employed to predict CO2 corrosion in natural gas gathering pipelines system. This work examines the effect of operating pressure, temperature, pH solution, pipeline length, flow regime, and pipe inclination on the CO2 corrosion. Based on the simulation results, following highlights were identified: increasing operating pressure results in increases CO2 partial pressure and promotes corrosion rate. Temperature affects formation of protective layer, where maximum CO2 corrosion rate reached 2.96 mm/year at 40°C for this simulation conditions. After 40°C, the protective layer consists and becomes more dense and reduces corrosion rate. In addition, lower pH enhances the solubility of carbonate, reduces participation rate, and enhancing CO2 corrosion. Dissolved CO2 concentration decreases along the pipeline length and the corrosion rate reduces as result. High velocity means efficient mixing which leads to prevent the formation of the protective layer and increases CO2 corrosion. Pipeline inclination affects the velocity of flow where positive elevation change reduces fluid velocity, while minus elevation change promotes fluid velocity. Frequently, these factors depend on each other and sharing the effects on the CO2 corrosion. The prevention of CO2 corrosion in natural gas gathering pipelines starts by understanding the effects of the operation conditions.
1. Introduction Generally, energy pipelines represent pipelines that gathering and transport natural gas and liquid petroleum. Energy pipelines trade grows by 3 to 4% a year where 50% of the pipelines constructed in the period 1950 to 1970 [1]. In the end of 2013, China constructed > 62,000 km of natural gas pipelines [2]. The energy pipelines classified into gathering pipelines and transmission pipelines. Transmission pipelines are large pipes in diameter (6 to 48 in.) that transport natural gas for long distance [10]. While, gathering pipelines are small pipes transport gas from point of production to another processing facility. Oil and natural gas production processes suffer from corrosion phenomena since the early history of the industry. National Association of Corrosion Engineers (NACE) mentioned that the total corrosion cost produced by repair and replacement of corroded parts is up to 276$ billion in US [3]. Where 7 billion from this total relates to corrosion failure in transmissions pipelines of oil and natural gas industry [3]. Javidi,
⁎
Corresponding author. E-mail address: [email protected] (A.A. Abd).
https://doi.org/10.1016/j.engfailanal.2019.07.026 Received 3 March 2019; Received in revised form 6 July 2019; Accepted 7 July 2019 Available online 08 July 2019 1350-6307/ © 2019 Elsevier Ltd. All rights reserved.
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Chamanfar, & Bekhrad mentioned that one of the most earnest problems in the oil and gas processes is the corrosion that produced by presence of carbon dioxide which is called sweet corrosion [4]. First record of this kind of corrosion was in US oil and gas industry processes > 78 years ago [5]. CO2 gas is not corrosive without aqueous solution to dissolve which enhances the electrochemical reaction on the surface of the metal and cause corrosion. CO2 corrosion occurs in three variants localized corrosion which are pitting, mesa attack, and flow-induced localized corrosion [5]. Pitting corrosion takes place with laminar flow and close to the dew point temperature in gas producing wells. While mesa attack occurs in low velocities to medium velocities where the carbonate layer forms however unstable to withstand the operating regime. Flow-induced localized corrosion type starts after the formation of pits and/or sites of mesa attack above critical flow intensities with turbulent flow. Material of construction, environmental, and physical parameters are factors that have direct effects on the CO2 corrosion rate. Papavinasam et al. mentioned that 5000 is the total number of failures in Canada for the past twenty years due to corrosion of internal surface in both gathering and transmissions pipelines [6]. Therefore, internal corrosion that causes by CO2 and/or H2S considers as major threat to pipelines integrity. Typically, natural gas that comes from wells contains a small amount of water, hydrogen sulfide, and carbon dioxide. This small amount of CO2 dissolved in water to form carbonic acid (H3CO3) which increases the cathodic reaction kinetics by dissociation to bicarbonate. Some parameters have direct effect on CO2 corrosion rate such as temperature, operating pressure and partial pressure, pH, flow regime, and pipe inclination [7]. Several correlations have been modified to estimate the corrosion rate for the internal flow based on the main mentioned parameters. DeWaard and Milliams developed semi empirical correlations to calculate CO2 corrosion rate based on CO2 partial pressure with velocity up to 1 m/s at the surface of the pipelines [8]. Jepson et al. developed a fully empirical correlation to estimate the corrosion rate in horizontal pipelines with multiphase slug flow [9]. The model relates the corrosion rate with carbon dioxide partial pressure, water cut, pressure gradient across the mixing zone, and temperature which modified later to including the effects of oil type and slug frequency. Wang et al. presented correlation covering different parameters such as reactions on the pipeline surface, water chemistry, and mass change between pipeline surface and the bulk of fluid [10]. Nesic, Cai, & Lee developed a comprehensive correlation to predict corrosion rate into mild steel pipelines includes the effects of hydrogen sulfide, water entrainment in multiphase flow, and corrosion inhibition by crude oil [11]. In 2005, Norwegian petroleum industry modified new correlation to predict the CO2 corrosion based on different parameters [12]. NORSOK models consists of three empirical equations valid for range of temperature depending on many factors such as pH, CO2 partial pressure, and CO2 fugacity [12]. In the present paper, simulation study has been performed to estimate CO2 corrosion rate into natural gas gathering pipelines system. Some sensitive factors that affecting CO2 corrosion rate have been studies such as operating pressure, temperature, gradient of corrosion rate with pipeline length, pH, flow regime, and pipe inclination. 2. Process description Production wells are connected to network of small diameter pipes where these pipes gathering natural gas and send it out to larger pipelines system for longer distance transport as shown by Fig. 1. The produced gas from wells is usually called raw gas which comes with high percent of methane and contents ethane, propane, butane, isobutene, natural gasoline and some other impurities such as carbon dioxide and water. The gas gathering system works on principles of moving gas from high pressure region to low pressure region. Commonly, the pipelines material of construction is cast iron, mild steel, copper, and/or plastic where the material selection depends on the operation conditions. The CO2 corrosion considers as one of the common problems that facing gas gathering process which is known as sweet corrosion. The operation conditions use in the simulation of gathering process and the natural gas compositions of the field which is nominally free of hydrogen sulfide shown in Table 1. Two main reactions control the CO2 corrosion rate process which are i- chemical reactions, ii-electrochemical reactions. Chemical reactions represent dissolving of carbon dioxide gas in water to produce bicarbonate ions, carbonic acid which is weak but corrosive to pipeline surface, and hydrogen ions:
CO2(gas) ↔ CO2(Aqueous ) CO2(Aqueous ) + H2 O → H2 CO3
H2 CO3 ↔ H+ + HCO3− HCO3− ↔ H+ + CO32 − The electrochemical reactions can be represented in one reaction on the anode and three reactions on the cathode as below.
Fe → Fe+2 + 2e−
2H+ + 2e− → H2 2H2 CO3 + 2e− → H2 + 2HCO3− 2HCO3− + 2e− → 2CO32 − + H2 And the overall reaction in terms of mild steel can be written as:
Fe + CO2 + H2 O → Fe+2 + CO3−2 + H2 639
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Fig. 1. Gathering pipelines system design by Aspen HYSYS program.
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Table 1 Operation conditions and compositions of raw natural gas. pH chosen to be 6, because most of the gathering systems using pH stabilizer technology to bring the pH up to around 6. Temperature = 45°C Nitrogen (mol %) CO2 (mol %) Methane (mol %) Ethane (mol %) Propane (mol %) i-Butane (mol %) n-Butane (mol %) i-Pentane (mol %) n-Pentane (mol %) n-Hexane (mol %) C7 + * (mol %) H2O (mol %)
Operating pressure = 4252 kpa 0.005 0.0205 0.5664 0.2545 0.0145 0.0115 0.0146 0.0038 0.0037 0.006 0.009 0.0909
3. Simulation basis The process of natural gas gathering system simulated with Aspen HYSYS V8.8 program which is a chemical process program applied to mathematically simulate different chemical processes. HYSYS offers different types of thermodynamic property fluid packages to deal with hydrocarbons systems such as Peng-Robinson, SRK, Glycol package, and Acid Gas. The fluid package for this simulation chosen to be Acid Gas which is recommended for hydrocarbons due to their largest binary interaction parameters database. Aspen HYSYS employs different models to estimate the CO2 corrosion such as NORSOK standard M-506, and de Waard Model 1991 and 1995. In this simulation, NORSOK M-506 Standard models applied which is widely accepted model to predict the CO2 corrosion rate developed with support from Norwegian Oil Industry Association (OLF) and the Federation of Norwegian Manufacturing Industries (TBL). NORSOK correlation designed as a pure empirical model focuses on the most relevant parameters that affects CO2 corrosion process such as operating temperature and pressure, pH of solution, CO2 partial pressure, fugacity, and wall shear stress. The best temperature range that NORSOK correlation can lead to accurate results laying in between 20°C up to 150°C [12]. The geometry of natural gas pipeline that provided by Aspen HYSYS shown in Table 2. The CO2 corrosion rate at the mentioned operation conditions estimated to be 2.766 mm/year which is fair enough based on the CO2 content in the raw natural gas. 4. Results and discussion 4.1. Effects of pressure The operating pressure influences CO2 corrosion directly by accelerating the corrosion process and indirectly by affecting fluid flow, scale formation, and gas fugacity. The operating pressure is affecting CO2 partial pressure in a great extent, affecting pH of the system and changing the protective properties of the components [13]. Sui et al. studied the effects of pressure and temperature on CO2 corrosion rate and draw the conclusion that the pressure has more effect than temperature variation on corrosion rate for their test system [14]. Simulation study has been performed to examine the change in CO2 partial pressure with operating pressure, where the results show that CO2 partial pressure increases linearly as the operating pressure increases as shown by Fig. 2. Tran et al. developed a study to test the effect of CO2 partial pressure on cathodic reaction mechanisms with carbonic acid (H2CO3) [15]. The study concluded that there are two possible reaction mechanisms which are direct reaction and indirect reaction (buffering phenomena). With two mechanisms, CO2 corrosion increases by increasing carbon dioxide partial pressure however the indirect reaction (buffering) produces corrosion rate less than that for direct reaction. Elgaddaf et al. investigated the effect of partial pressure of carbon dioxide to operating pressure rate on corrosion behavior of C110 carbon steel and concluded that as pressure rate increases, corrosion rate increases [16]. Increasing operating pressure causes increasing the H2CO3 concentration which leads to increase the corrosion rate and accelerates the cathodic reactions. Zhang et al. studied the relation between partial pressure and the solubility of CO2 to summarized that CO2 solubility increases as pressure increases and the corrosion rate increases as a result [17]. Simulation study has been conducted to check the effect of operating pressure on the corrosion rate into natural gas pipelines. Table 2 Simulation pipeline geometry. Material of construction
Mild steel
Outer diameter Inner diameter Pipe thermal conductivity Roughness
88.9 mm 77.93 mm 45 W/m.K 4.572 *10−5 m
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Fig. 2. Change of CO2 partial pressure with operating pressure.
Fig. 3. Effect of operating pressure on the CO2 corrosion rate at 45°C and pH = 6.
Fig. 3 shows that corrosion rate increases as operating pressure increasing linearly and subsequently the corrosion rate starts changing with small rate. The possible reason is that buffering phenomenon shows up after 5000 kpa in which carbonic acid produced as a result of hydration of aqueous CO2, which provides more hydrogen ions in beside the dissociation of water. Then, diffusion process controls the proton ions movement to the surface of the pipelines.
4.2. Effect of temperature Temperature plays an important role in the formation rate of corrosion product layer. Corrosion product layer is porous and loose promoting the corrosion rate. Hatami et al. mentioned that temperature promotes mass transfer process by reducing the viscosity of gas mixture and accelerates both the chemical and the electrochemical reactions at the bulk and the pipeline surface [18]. High temperature feeds molecules high energy, thus enhances the collisions of the reacting elements and speed the reaction rates. Sensitivity simulation study has been conducted to examine the effect of temperature on the CO2 corrosion into natural gas gathering pipelines. Fig. 4 shows that CO2 corrosion starts increasing sharply with increasing temperature to reach maximum corrosion rate at 2.96 mm/year, subsequently the corrosion rate decreases with temperature increases to reach 1.88 mm/year at 80°C. For temperatures below 40°C, corrosion rate increases with temperature because there is no protective film formed on the surface of the pipe due to high solubility of carbonate iron layer. The corrosion product layer becomes compact and dense by increasing the temperature which adherent to the surface of the pipe and forms a protective layer. pH of solution plays a vital role in determine the range of temperature at which corrosion product layer consists, where higher pH accelerates the formation of protective films. Garnica et al. mentioned that at low pH the protective layer formed at temperature range between 70°C and 80°C [19]. This can explain why corrosion rate decreases after 40°C where the protective layer starts thin, porous and loose and with increasing temperature the layer becomes compact and the corrosion rate continuous decreases. 642
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Fig. 4. Effect of temperature on the CO2 corrosion rate at 4254 kpa and PH = 6.
4.3. Effect of pH pH is the degree of acidity or alkalinity of the solution. Moiseeva & Rashevskaya proved that pH has significant effect on CO2 corrosion by changing the corrosion environment i.e., higher pH, low corrosion rate [20]. The main reactions in the CO2 corrosion process are formation of carbonic acid and hydration with pH < 4, the hydration reaction is the dominant cathode reaction while direct reduction of carbonic acid becomes important at pH > 4 [6]. Nešić mentioned that increasing pH of solution leads to reduce the solubility of carbonate and increases the participation rate [21]. Motte et al. indicated that pH is responsible on the conditions that control the formation of iron carbonate scales and draws the way that formed film can limit the corrosion kinetics on the underlying steel [22]. Sensitivity simulation study has been performed to illustrate the effect of changing the pH solution on the corrosion rate. Fig. 5 shows that the corrosion rate decreases as the pH increases. It is noteworthy that low pH comes with high carbonate solubility and low participation rate, therefore the corrosion rate is maximum at pH 3.5 with temperature 45°C and 4252 kpa. 4.4. Effect of pipeline length Natural gas moves through pipes as a result of compressors producing pressure to push the gas from high pressure section to low pressure. The compressors work by powering with electric or natural gas fired engines. Sometimes, natural gas comes from the wells with high pressure which is enough to flow the gas and no need to compressors in this case. Gathering pipelines length depends on the design of the gathering system and the locations of the mixers. The material of construction varies with the location conditions like the soil conditions and the ambient temperature, commonly high carbon steel uses as material of construction for high pressure lines
Fig. 5. Effect of pH on the CO2 corrosion rate at 45°C and 4254 kpa. 643
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Fig. 6. Effect of pipeline length on the CO2 corrosion rate at 45°C, 4254 kpa, and pH = 6.
with 4 to 30 in. [23]. Wang & Duncan mentioned that 38,624 km out of 386,240 km pipelines gathering natural gas and transport to processing plants [23]. Sensitivity simulation study has been performed to illustrate the variation of CO2 corrosion rate along pipeline for different materials of construction. Fig. 4 shows that CO2 corrosion rate decreases as the pipeline length increases with different materials of construction. The reason is that high percent of carbon dioxide has been reacted with water to form carbonate at the first section of the pipeline while the rest flows with fluid and continuous react however with small corrosion rate, previous study also confirmed this trend [24] (Fig. 6). 4.5. Effect of flow regime Flow regime is another factor affect the process of corrosion rate in gathering of natural gas pipelines. Flow regime shows the manner in which fluid flows through a pipeline where flow type has direct impact on the wall shear stress. Sydberger presented a rational definition for the effects of flow on CO2 corrosion by introducing three different mechanisms, convective-mass transfer controlled corrosion, phase-transport controlled corrosion, and erosion-corrosion [25]. First mechanism suggested that convective mass transfer has direct effect on CO2 corrosion at the pipeline surface and fluid interface. While, second mechanism relates strongly on the multiphase flow and depends on the wetting of the metal surface by the phase containing corrosive material. Erosion-corrosion presents on the flow is turbulent and fluid flow with high velocity. Hatami et al. stated that high velocity means more turbulence flow and efficient mixing [18]. Barker indicated that for high turbulence flow with velocity > 7 m/s, the pipeline surface exposes to erosion [26]. Zhang investigated the effect of varies flow velocity on the corrosion rate of L360QS steel in H2S/CO2 environments with sulphur deposition and concluded that the corrosion rate increased by about 10 times when velocity increased from 3 to 7 m/s [27]. Sensitivity simulation study has been performed to test the effect of increasing the velocity of gas into gathering pipelines on CO2 corrosion rate. Fig. 7 shows that as the velocity increases CO2 corrosion rate increases. The reason is that high velocity leads to
Fig. 7. Effect of flowrate on the CO2 corrosion rate at 45°C, 4254 kpa, and pH = 6. 644
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Fig. 8. Pipeline positions as considered by HYSYS program.
efficient mixing which prevents the formation of the protective films on the surface of the pipeline and increases the corrosion rate as a result. 4.6. Effects of pipe elevation Pipe inclination is another factor that affecting carbon dioxide corrosion rate into natural gas gathering pipelines system. Kang, Wilkens & Jepson studied the effect of slug frequency on the corrosion rate in inclined pipes at high pressures [28]. The study highlighted that the inclination of pipe has direct effect on the velocity of flow. Hu, & Cheng stated that beside the effect of inclination of pipe on the velocity and flow regime, inclined pipes comes with fittings which consider as possible targets for corrosion [29]. Sensitivity simulation study has been performed to test the effect of pipe elevation on the CO2 corrosion rate in natural gas pipelines using HYSYS program. The program indicates that horizontal pipe section comes with elevation equal zero, positive elevation means that the pipe outlet is higher than pipe inlet, while minus elevation means that pipe inlet is lower than the pipe outlet as shown by Fig. 8. The results show that the corrosion rate increases as the pipe inclination increases as shown by Fig. 9. The reason is that the velocity of flow increases as the inclination increases which leads to efficient mixing and prevents the formation of the protective layer. 5. Conclusion In this study, extensive simulation study has been performed on the CO2 corrosion rate into natural gas gathering system. Parametric study stated to check the effects of different factors on the CO2 corrosion rate and based on the results, the following conclusions can be drawn:
• Presence of CO and water as impurities in natural gas that can causes corrosion in the gathering pipelines at different rates depends on the operational conditions. • Operating pressure affects the CO partial pressure and the type of protective scale. Where increasing operating pressure leads to increase CO partial pressure and the corrosion rate as a result. • The temperature of natural gas influences the formation of protective layer in great extent, whereas the results show at 2
2
2
Fig. 9. Effect of pipeline elevation on the CO2 corrosion rate at 45°C, 4254 kpa, and pH = 6. 645
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• • • •
temperature below 40°C, CO2 corrosion increases sharply and above the 40°C the corrosion rate started decreases because of the formation of the protective layer which becomes more compact and dense with increasing temperature and time. pH has direct effect on the solubility of carbonate and the corrosion rate as result. Maximum CO2 corrosion rate recorded at pH equals 3.5 for simulation system, where solubility of carbonate is high and low participation. CO2 corrosion rate decreases as the pipeline length increase, where internal pipe surface continuous reacted to consume CO2 along the pipeline. Three common materials of construction applied to predict the CO2 corrosion rate for each one. Mild steel shows better resistance against CO2 corrosion rate than cast iron and asphalted iron. High velocity means efficient mixing which leads to prevent the formation of protective layer and increasing corrosion rate as result. Pipe inclination relates the velocity and flow regime, from up to down means higher velocity and higher corrosion rate and vice versa.
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646
Contents lists available at ScienceDirect
Engineering Failure Analysis journal homepage: www.elsevier.com/locate/engfailanal
Failure analysis of carbon dioxide corrosion through wet natural gas gathering pipelines
T
⁎
Ammar Ali Abda,b, , Samah Zaki Najia,c, Atheer Saad Hashimb,d a
Chemical Engineering Department, Curtin University, Perth, Australia Water Resources Engineering College, Al-Qasim Green University, Babylon, Iraq. Petroleum Engineering Department, Kerbala University, Kerbala, Iraq. d Mechanical Engineering department, Nottingham University, Nottingham, United Kingdom. b c
A R T IC LE I N F O
ABS TRA CT
Keywords: CO2 corrosion HYSYS Natural gas pipelines Internal corrosion
The aggressive behavior of carbon dioxide dissolved in water considers as one of basic reasons behind corrosion failure in oil and gas processes. Simulation study using HYSYS program employed to predict CO2 corrosion in natural gas gathering pipelines system. This work examines the effect of operating pressure, temperature, pH solution, pipeline length, flow regime, and pipe inclination on the CO2 corrosion. Based on the simulation results, following highlights were identified: increasing operating pressure results in increases CO2 partial pressure and promotes corrosion rate. Temperature affects formation of protective layer, where maximum CO2 corrosion rate reached 2.96 mm/year at 40°C for this simulation conditions. After 40°C, the protective layer consists and becomes more dense and reduces corrosion rate. In addition, lower pH enhances the solubility of carbonate, reduces participation rate, and enhancing CO2 corrosion. Dissolved CO2 concentration decreases along the pipeline length and the corrosion rate reduces as result. High velocity means efficient mixing which leads to prevent the formation of the protective layer and increases CO2 corrosion. Pipeline inclination affects the velocity of flow where positive elevation change reduces fluid velocity, while minus elevation change promotes fluid velocity. Frequently, these factors depend on each other and sharing the effects on the CO2 corrosion. The prevention of CO2 corrosion in natural gas gathering pipelines starts by understanding the effects of the operation conditions.
1. Introduction Generally, energy pipelines represent pipelines that gathering and transport natural gas and liquid petroleum. Energy pipelines trade grows by 3 to 4% a year where 50% of the pipelines constructed in the period 1950 to 1970 [1]. In the end of 2013, China constructed > 62,000 km of natural gas pipelines [2]. The energy pipelines classified into gathering pipelines and transmission pipelines. Transmission pipelines are large pipes in diameter (6 to 48 in.) that transport natural gas for long distance [10]. While, gathering pipelines are small pipes transport gas from point of production to another processing facility. Oil and natural gas production processes suffer from corrosion phenomena since the early history of the industry. National Association of Corrosion Engineers (NACE) mentioned that the total corrosion cost produced by repair and replacement of corroded parts is up to 276$ billion in US [3]. Where 7 billion from this total relates to corrosion failure in transmissions pipelines of oil and natural gas industry [3]. Javidi,
⁎
Corresponding author. E-mail address: [email protected] (A.A. Abd).
https://doi.org/10.1016/j.engfailanal.2019.07.026 Received 3 March 2019; Received in revised form 6 July 2019; Accepted 7 July 2019 Available online 08 July 2019 1350-6307/ © 2019 Elsevier Ltd. All rights reserved.
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Chamanfar, & Bekhrad mentioned that one of the most earnest problems in the oil and gas processes is the corrosion that produced by presence of carbon dioxide which is called sweet corrosion [4]. First record of this kind of corrosion was in US oil and gas industry processes > 78 years ago [5]. CO2 gas is not corrosive without aqueous solution to dissolve which enhances the electrochemical reaction on the surface of the metal and cause corrosion. CO2 corrosion occurs in three variants localized corrosion which are pitting, mesa attack, and flow-induced localized corrosion [5]. Pitting corrosion takes place with laminar flow and close to the dew point temperature in gas producing wells. While mesa attack occurs in low velocities to medium velocities where the carbonate layer forms however unstable to withstand the operating regime. Flow-induced localized corrosion type starts after the formation of pits and/or sites of mesa attack above critical flow intensities with turbulent flow. Material of construction, environmental, and physical parameters are factors that have direct effects on the CO2 corrosion rate. Papavinasam et al. mentioned that 5000 is the total number of failures in Canada for the past twenty years due to corrosion of internal surface in both gathering and transmissions pipelines [6]. Therefore, internal corrosion that causes by CO2 and/or H2S considers as major threat to pipelines integrity. Typically, natural gas that comes from wells contains a small amount of water, hydrogen sulfide, and carbon dioxide. This small amount of CO2 dissolved in water to form carbonic acid (H3CO3) which increases the cathodic reaction kinetics by dissociation to bicarbonate. Some parameters have direct effect on CO2 corrosion rate such as temperature, operating pressure and partial pressure, pH, flow regime, and pipe inclination [7]. Several correlations have been modified to estimate the corrosion rate for the internal flow based on the main mentioned parameters. DeWaard and Milliams developed semi empirical correlations to calculate CO2 corrosion rate based on CO2 partial pressure with velocity up to 1 m/s at the surface of the pipelines [8]. Jepson et al. developed a fully empirical correlation to estimate the corrosion rate in horizontal pipelines with multiphase slug flow [9]. The model relates the corrosion rate with carbon dioxide partial pressure, water cut, pressure gradient across the mixing zone, and temperature which modified later to including the effects of oil type and slug frequency. Wang et al. presented correlation covering different parameters such as reactions on the pipeline surface, water chemistry, and mass change between pipeline surface and the bulk of fluid [10]. Nesic, Cai, & Lee developed a comprehensive correlation to predict corrosion rate into mild steel pipelines includes the effects of hydrogen sulfide, water entrainment in multiphase flow, and corrosion inhibition by crude oil [11]. In 2005, Norwegian petroleum industry modified new correlation to predict the CO2 corrosion based on different parameters [12]. NORSOK models consists of three empirical equations valid for range of temperature depending on many factors such as pH, CO2 partial pressure, and CO2 fugacity [12]. In the present paper, simulation study has been performed to estimate CO2 corrosion rate into natural gas gathering pipelines system. Some sensitive factors that affecting CO2 corrosion rate have been studies such as operating pressure, temperature, gradient of corrosion rate with pipeline length, pH, flow regime, and pipe inclination. 2. Process description Production wells are connected to network of small diameter pipes where these pipes gathering natural gas and send it out to larger pipelines system for longer distance transport as shown by Fig. 1. The produced gas from wells is usually called raw gas which comes with high percent of methane and contents ethane, propane, butane, isobutene, natural gasoline and some other impurities such as carbon dioxide and water. The gas gathering system works on principles of moving gas from high pressure region to low pressure region. Commonly, the pipelines material of construction is cast iron, mild steel, copper, and/or plastic where the material selection depends on the operation conditions. The CO2 corrosion considers as one of the common problems that facing gas gathering process which is known as sweet corrosion. The operation conditions use in the simulation of gathering process and the natural gas compositions of the field which is nominally free of hydrogen sulfide shown in Table 1. Two main reactions control the CO2 corrosion rate process which are i- chemical reactions, ii-electrochemical reactions. Chemical reactions represent dissolving of carbon dioxide gas in water to produce bicarbonate ions, carbonic acid which is weak but corrosive to pipeline surface, and hydrogen ions:
CO2(gas) ↔ CO2(Aqueous ) CO2(Aqueous ) + H2 O → H2 CO3
H2 CO3 ↔ H+ + HCO3− HCO3− ↔ H+ + CO32 − The electrochemical reactions can be represented in one reaction on the anode and three reactions on the cathode as below.
Fe → Fe+2 + 2e−
2H+ + 2e− → H2 2H2 CO3 + 2e− → H2 + 2HCO3− 2HCO3− + 2e− → 2CO32 − + H2 And the overall reaction in terms of mild steel can be written as:
Fe + CO2 + H2 O → Fe+2 + CO3−2 + H2 639
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Fig. 1. Gathering pipelines system design by Aspen HYSYS program.
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Table 1 Operation conditions and compositions of raw natural gas. pH chosen to be 6, because most of the gathering systems using pH stabilizer technology to bring the pH up to around 6. Temperature = 45°C Nitrogen (mol %) CO2 (mol %) Methane (mol %) Ethane (mol %) Propane (mol %) i-Butane (mol %) n-Butane (mol %) i-Pentane (mol %) n-Pentane (mol %) n-Hexane (mol %) C7 + * (mol %) H2O (mol %)
Operating pressure = 4252 kpa 0.005 0.0205 0.5664 0.2545 0.0145 0.0115 0.0146 0.0038 0.0037 0.006 0.009 0.0909
3. Simulation basis The process of natural gas gathering system simulated with Aspen HYSYS V8.8 program which is a chemical process program applied to mathematically simulate different chemical processes. HYSYS offers different types of thermodynamic property fluid packages to deal with hydrocarbons systems such as Peng-Robinson, SRK, Glycol package, and Acid Gas. The fluid package for this simulation chosen to be Acid Gas which is recommended for hydrocarbons due to their largest binary interaction parameters database. Aspen HYSYS employs different models to estimate the CO2 corrosion such as NORSOK standard M-506, and de Waard Model 1991 and 1995. In this simulation, NORSOK M-506 Standard models applied which is widely accepted model to predict the CO2 corrosion rate developed with support from Norwegian Oil Industry Association (OLF) and the Federation of Norwegian Manufacturing Industries (TBL). NORSOK correlation designed as a pure empirical model focuses on the most relevant parameters that affects CO2 corrosion process such as operating temperature and pressure, pH of solution, CO2 partial pressure, fugacity, and wall shear stress. The best temperature range that NORSOK correlation can lead to accurate results laying in between 20°C up to 150°C [12]. The geometry of natural gas pipeline that provided by Aspen HYSYS shown in Table 2. The CO2 corrosion rate at the mentioned operation conditions estimated to be 2.766 mm/year which is fair enough based on the CO2 content in the raw natural gas. 4. Results and discussion 4.1. Effects of pressure The operating pressure influences CO2 corrosion directly by accelerating the corrosion process and indirectly by affecting fluid flow, scale formation, and gas fugacity. The operating pressure is affecting CO2 partial pressure in a great extent, affecting pH of the system and changing the protective properties of the components [13]. Sui et al. studied the effects of pressure and temperature on CO2 corrosion rate and draw the conclusion that the pressure has more effect than temperature variation on corrosion rate for their test system [14]. Simulation study has been performed to examine the change in CO2 partial pressure with operating pressure, where the results show that CO2 partial pressure increases linearly as the operating pressure increases as shown by Fig. 2. Tran et al. developed a study to test the effect of CO2 partial pressure on cathodic reaction mechanisms with carbonic acid (H2CO3) [15]. The study concluded that there are two possible reaction mechanisms which are direct reaction and indirect reaction (buffering phenomena). With two mechanisms, CO2 corrosion increases by increasing carbon dioxide partial pressure however the indirect reaction (buffering) produces corrosion rate less than that for direct reaction. Elgaddaf et al. investigated the effect of partial pressure of carbon dioxide to operating pressure rate on corrosion behavior of C110 carbon steel and concluded that as pressure rate increases, corrosion rate increases [16]. Increasing operating pressure causes increasing the H2CO3 concentration which leads to increase the corrosion rate and accelerates the cathodic reactions. Zhang et al. studied the relation between partial pressure and the solubility of CO2 to summarized that CO2 solubility increases as pressure increases and the corrosion rate increases as a result [17]. Simulation study has been conducted to check the effect of operating pressure on the corrosion rate into natural gas pipelines. Table 2 Simulation pipeline geometry. Material of construction
Mild steel
Outer diameter Inner diameter Pipe thermal conductivity Roughness
88.9 mm 77.93 mm 45 W/m.K 4.572 *10−5 m
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Fig. 2. Change of CO2 partial pressure with operating pressure.
Fig. 3. Effect of operating pressure on the CO2 corrosion rate at 45°C and pH = 6.
Fig. 3 shows that corrosion rate increases as operating pressure increasing linearly and subsequently the corrosion rate starts changing with small rate. The possible reason is that buffering phenomenon shows up after 5000 kpa in which carbonic acid produced as a result of hydration of aqueous CO2, which provides more hydrogen ions in beside the dissociation of water. Then, diffusion process controls the proton ions movement to the surface of the pipelines.
4.2. Effect of temperature Temperature plays an important role in the formation rate of corrosion product layer. Corrosion product layer is porous and loose promoting the corrosion rate. Hatami et al. mentioned that temperature promotes mass transfer process by reducing the viscosity of gas mixture and accelerates both the chemical and the electrochemical reactions at the bulk and the pipeline surface [18]. High temperature feeds molecules high energy, thus enhances the collisions of the reacting elements and speed the reaction rates. Sensitivity simulation study has been conducted to examine the effect of temperature on the CO2 corrosion into natural gas gathering pipelines. Fig. 4 shows that CO2 corrosion starts increasing sharply with increasing temperature to reach maximum corrosion rate at 2.96 mm/year, subsequently the corrosion rate decreases with temperature increases to reach 1.88 mm/year at 80°C. For temperatures below 40°C, corrosion rate increases with temperature because there is no protective film formed on the surface of the pipe due to high solubility of carbonate iron layer. The corrosion product layer becomes compact and dense by increasing the temperature which adherent to the surface of the pipe and forms a protective layer. pH of solution plays a vital role in determine the range of temperature at which corrosion product layer consists, where higher pH accelerates the formation of protective films. Garnica et al. mentioned that at low pH the protective layer formed at temperature range between 70°C and 80°C [19]. This can explain why corrosion rate decreases after 40°C where the protective layer starts thin, porous and loose and with increasing temperature the layer becomes compact and the corrosion rate continuous decreases. 642
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Fig. 4. Effect of temperature on the CO2 corrosion rate at 4254 kpa and PH = 6.
4.3. Effect of pH pH is the degree of acidity or alkalinity of the solution. Moiseeva & Rashevskaya proved that pH has significant effect on CO2 corrosion by changing the corrosion environment i.e., higher pH, low corrosion rate [20]. The main reactions in the CO2 corrosion process are formation of carbonic acid and hydration with pH < 4, the hydration reaction is the dominant cathode reaction while direct reduction of carbonic acid becomes important at pH > 4 [6]. Nešić mentioned that increasing pH of solution leads to reduce the solubility of carbonate and increases the participation rate [21]. Motte et al. indicated that pH is responsible on the conditions that control the formation of iron carbonate scales and draws the way that formed film can limit the corrosion kinetics on the underlying steel [22]. Sensitivity simulation study has been performed to illustrate the effect of changing the pH solution on the corrosion rate. Fig. 5 shows that the corrosion rate decreases as the pH increases. It is noteworthy that low pH comes with high carbonate solubility and low participation rate, therefore the corrosion rate is maximum at pH 3.5 with temperature 45°C and 4252 kpa. 4.4. Effect of pipeline length Natural gas moves through pipes as a result of compressors producing pressure to push the gas from high pressure section to low pressure. The compressors work by powering with electric or natural gas fired engines. Sometimes, natural gas comes from the wells with high pressure which is enough to flow the gas and no need to compressors in this case. Gathering pipelines length depends on the design of the gathering system and the locations of the mixers. The material of construction varies with the location conditions like the soil conditions and the ambient temperature, commonly high carbon steel uses as material of construction for high pressure lines
Fig. 5. Effect of pH on the CO2 corrosion rate at 45°C and 4254 kpa. 643
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Fig. 6. Effect of pipeline length on the CO2 corrosion rate at 45°C, 4254 kpa, and pH = 6.
with 4 to 30 in. [23]. Wang & Duncan mentioned that 38,624 km out of 386,240 km pipelines gathering natural gas and transport to processing plants [23]. Sensitivity simulation study has been performed to illustrate the variation of CO2 corrosion rate along pipeline for different materials of construction. Fig. 4 shows that CO2 corrosion rate decreases as the pipeline length increases with different materials of construction. The reason is that high percent of carbon dioxide has been reacted with water to form carbonate at the first section of the pipeline while the rest flows with fluid and continuous react however with small corrosion rate, previous study also confirmed this trend [24] (Fig. 6). 4.5. Effect of flow regime Flow regime is another factor affect the process of corrosion rate in gathering of natural gas pipelines. Flow regime shows the manner in which fluid flows through a pipeline where flow type has direct impact on the wall shear stress. Sydberger presented a rational definition for the effects of flow on CO2 corrosion by introducing three different mechanisms, convective-mass transfer controlled corrosion, phase-transport controlled corrosion, and erosion-corrosion [25]. First mechanism suggested that convective mass transfer has direct effect on CO2 corrosion at the pipeline surface and fluid interface. While, second mechanism relates strongly on the multiphase flow and depends on the wetting of the metal surface by the phase containing corrosive material. Erosion-corrosion presents on the flow is turbulent and fluid flow with high velocity. Hatami et al. stated that high velocity means more turbulence flow and efficient mixing [18]. Barker indicated that for high turbulence flow with velocity > 7 m/s, the pipeline surface exposes to erosion [26]. Zhang investigated the effect of varies flow velocity on the corrosion rate of L360QS steel in H2S/CO2 environments with sulphur deposition and concluded that the corrosion rate increased by about 10 times when velocity increased from 3 to 7 m/s [27]. Sensitivity simulation study has been performed to test the effect of increasing the velocity of gas into gathering pipelines on CO2 corrosion rate. Fig. 7 shows that as the velocity increases CO2 corrosion rate increases. The reason is that high velocity leads to
Fig. 7. Effect of flowrate on the CO2 corrosion rate at 45°C, 4254 kpa, and pH = 6. 644
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Fig. 8. Pipeline positions as considered by HYSYS program.
efficient mixing which prevents the formation of the protective films on the surface of the pipeline and increases the corrosion rate as a result. 4.6. Effects of pipe elevation Pipe inclination is another factor that affecting carbon dioxide corrosion rate into natural gas gathering pipelines system. Kang, Wilkens & Jepson studied the effect of slug frequency on the corrosion rate in inclined pipes at high pressures [28]. The study highlighted that the inclination of pipe has direct effect on the velocity of flow. Hu, & Cheng stated that beside the effect of inclination of pipe on the velocity and flow regime, inclined pipes comes with fittings which consider as possible targets for corrosion [29]. Sensitivity simulation study has been performed to test the effect of pipe elevation on the CO2 corrosion rate in natural gas pipelines using HYSYS program. The program indicates that horizontal pipe section comes with elevation equal zero, positive elevation means that the pipe outlet is higher than pipe inlet, while minus elevation means that pipe inlet is lower than the pipe outlet as shown by Fig. 8. The results show that the corrosion rate increases as the pipe inclination increases as shown by Fig. 9. The reason is that the velocity of flow increases as the inclination increases which leads to efficient mixing and prevents the formation of the protective layer. 5. Conclusion In this study, extensive simulation study has been performed on the CO2 corrosion rate into natural gas gathering system. Parametric study stated to check the effects of different factors on the CO2 corrosion rate and based on the results, the following conclusions can be drawn:
• Presence of CO and water as impurities in natural gas that can causes corrosion in the gathering pipelines at different rates depends on the operational conditions. • Operating pressure affects the CO partial pressure and the type of protective scale. Where increasing operating pressure leads to increase CO partial pressure and the corrosion rate as a result. • The temperature of natural gas influences the formation of protective layer in great extent, whereas the results show at 2
2
2
Fig. 9. Effect of pipeline elevation on the CO2 corrosion rate at 45°C, 4254 kpa, and pH = 6. 645
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• • • •
temperature below 40°C, CO2 corrosion increases sharply and above the 40°C the corrosion rate started decreases because of the formation of the protective layer which becomes more compact and dense with increasing temperature and time. pH has direct effect on the solubility of carbonate and the corrosion rate as result. Maximum CO2 corrosion rate recorded at pH equals 3.5 for simulation system, where solubility of carbonate is high and low participation. CO2 corrosion rate decreases as the pipeline length increase, where internal pipe surface continuous reacted to consume CO2 along the pipeline. Three common materials of construction applied to predict the CO2 corrosion rate for each one. Mild steel shows better resistance against CO2 corrosion rate than cast iron and asphalted iron. High velocity means efficient mixing which leads to prevent the formation of protective layer and increasing corrosion rate as result. Pipe inclination relates the velocity and flow regime, from up to down means higher velocity and higher corrosion rate and vice versa.
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