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1 Paper No Corrosion Rate Measurement of a Downhole Tubular Steel at Different CO 2 Partial Pressures and Temperatures and Calculation of the Activation Energy of the Corrosion Process Arshad Bajvani Gavanluei Cameron International Inc. Subsea Systems Houston TX USA David L. Olson Colorado School of Mines 1500 Illinois Street Golden, CO USA Brajendra Mishra Colorado School of Mines 1500 Illinois Street Golden, CO USA ABSTRACT Corrosion rate of a low alloy tempered martensite downhole tubular steel was studied at different temperatures and CO 2 partial pressures using direct weight loss measurement. Experiments were carried out in a high pressure high temperature autoclave. CO 2 partial pressures of 40 (276), 80 (552), 160 (1103), and 320 (2206) psi (kpa) were examined at temperatures 25, 40, 50, and 75 C. A linear trend between corrosion rate and CO 2 partial pressure was observed at different temperatures and increasing CO 2 partial pressure increased the slope of the lines. In addition, at constant CO 2 partial pressure, increasing temperature increased the corrosion rate. X-ray diffraction (XRD) and scanning electron microscopy (SEM) were used to study the corrosion products formed on the surface. At 50 C and below, only iron and iron carbide were detected using XRD analysis, but, at 75 C, in addition to iron carbide, iron carbonate was also detected. Formation of scattered iron carbonate crystals was studied using SEM. Finally, having the corrosion rate at different temperatures and CO 2 partial pressures, the activation energy of the corrosion process was calculated using the de Waard Equation. Key words: downhole tubular steels, CO 2 corrosion, corrosion rate, autoclave INTRODUCTION Extraction of oil and gas from geological formations is accompanied with impurities such as water, carbon dioxide and hydrogen sulfide, as well as various salts and organic acids. The combination of water and carbon dioxide provides a corrosive environment, which degrades materials and influences the integrity of the facilities. Dissolved carbon dioxide in water forms weak but corrosive carbonic acid. The presence of carbonic acid causes the corrosion of steel in downhole environments, hydrocarbon storage, transportation pipeline, and processing facilities. Even though corrosion resistance alloys which resist these corrosive environments can be used, carbon and low alloy steels are still the most 1

2 cost effective structural materials used in the oil and gas industry. Carbon and low alloy steels are widely used in the oil and gas industry due to their availability, fabricability and low cost despite their low corrosion resistance. 1, 2 Carbon and low alloy steels may have different microstructures depending on their chemical composition and heat treatment, which affect their mechanical properties and corrosion resistance. 3-7 It has been reported that chemical and electrochemical reactions are responsible for the CO 2 corrosion of steel. 8 Chemical reactions take place in the solution, while possible cathodic reactions, depending on the ph of the solution, and the anodic reaction take place on the surface of steel. Occurrence of these reactions release bicarbonate, carbonate and iron ions into the solution, and exceeding the concentration of the ions beyond their solubility limits leads to the precipitation of iron carbonate on the surface of steel as: Formation of the FeCO 3 layer on the surface is one of the most important factors which determines the corrosion rate of steel in these environments. The corrosion rate of steel in CO 2 containing environments depends on the governing reactions being either in activation controlled or diffusion controlled states. The activation controlled state is the condition in which formation of a dense and protective corrosion product layer doesn t occur and the corrosion rate is greater than the precipitation rate of the corrosion products. In other words, the corrosion process is under the control of chemical reactions. On the other hand, the diffusion controlled state is the condition in which a protective and dense iron carbonate layer forms on the steel surface and the formed iron carbonate layer acts as a diffusion barrier for the species involved in the corrosion process of steel and can retard the dissolution of steel. Formation and the protectiveness of the scale depends on the environmental factors (e.g., temperature, ph, CO 2 partial pressure), physical factors (e.g., water wetting, crude oil, flow and erosion, corrosion inhibitors) and metallurgical factors such as the steel chemical composition and its microstructure Principally, kinetics of the precipitation reaction govern the formation of the iron carbonate layer. Precipitation of iron carbonate is a form of heterogeneous crystallization from an aqueous solution. Crystallization of iron carbonate from the solution can be divided into two separate stages: nucleation and growth, and every step has its own distinctive kinetics. Nucleation has been determined to be of primary importance in homogeneous crystallization processes, whereas in heterogeneous crystallization processes such as precipitation of iron carbonate in the CO 2 containing environments, the crystal growth governs the overall kinetics of the process. 10, 13 It has been reported that the growth of an iron carbonate layer primarily depends on the precipitation rate. When the rate of precipitation equals or exceeds the corrosion rate, a protective film forms. Thickness of the corrosion product film as 10, 15 well as its density increases over time as the corrosion process continues. Numerous research and field studies have been performed on CO 2 corrosion of carbon steels in hydrocarbon production and transportation environments. Corrosion mechanisms are now very wellknown and are included in corrosion prediction models. 1, 9, 12, 16 This work has focused on the direct corrosion rate measurement of a low alloy tempered martensite tubular steel used in downhole environments under the assumption that the corrosion process is in the activation controlled state. EXPERIMENTAL PROCEDURE Initially, the microstructure, chemical composition and mechanical properties of the as-received tubular steel were characterized. Tempered martensite microstructure of the steel is shown in Figure 1. Prior austenite grain boundaries were delineated using saturated picric acid etchant. (1) 2

3 Figure 1: Optical microscopy image of as-received tubular steel showing tempered martensite microstructure. Prior austenite grain boundaries were delineated using saturated picric acid etchant, 50X. Chemical composition and mechanical properties of the as-received tubular steel for this study are listed in Table 1. Table 1 Mechanical properties and chemical composition (wt. pct.) of as-received tubular steel YS UTS e (MPa) (MPa) C Mn Si Ni Cr Mo P S Fe (%) Min Max Min Steel General corrosion rate measurements using the weight loss method were carried out. The experiments were conducted inside the autoclave, which was made from a nickel base superalloy. The effects of temperature and CO 2 partial pressure on the corrosion rate of the steel were studied using rectangular specimens cut from the longitudinal direction of tubular steel. Figure 2 shows the geometry and dimensions of the weight loss specimens. Figure 2: Geometry and dimensions (in mm) of weight loss specimens. Specimens were ground with 600 SiC grit paper, washed with de-ionized (DI) water, rinsed with ethanol and dried with warm blowing air and stored in a desiccator. Before exposure, dimensions were measured to the hundredths of a millimeter using a digital caliper and the mass of the specimens were 3

4 weighed to the thousandths of a gram using a Scientech SA 310 balance. 850 ml DI water was poured inside the autoclave and after tightening the autoclave, CO 2 was purged for one hour to deaerate and saturate the solution. After saturation, ph of the solution was measured which was varied between Then, the autoclave was heated to the desired test temperature using a proportional integral derivative temperature controller. Temperature was controlled within ±2 C of the test temperature. Finally, CO 2 partial pressure was adjusted to the desired pressure and experiment time was recorded. After 24 hours, specimens were removed from the autoclave, rinsed with acetone, and dried with hot blowing air. After XRD and SEM studies of the specimens, corrosion products were cleaned chemically using Clarke solution according to ASTM (1) G standard. RESULTS AND DISCUSSION Corrosion Rate Measurements Weight Loss Method Corrosion rate of the steel was measured using the weight loss method. The corrosion rate was evaluated at four different temperatures (25, 40, 50 and 75 C) and four different CO 2 partial pressures (40 (276), 80 (552), 160 (1103) and 320 (2206) psi (kpa)). These experimental conditions were chosen to investigate the corrosion rate in the active corrosion state where reactions are activation controlled. Since, in this condition, protective corrosion products are not formed, mass transfer of species to the metal surface does not play any role. The exposure duration for all the experiments was 24 hours. Figure 3 shows the corrosion rate in millimeters per year (mm/y) for the steel at different temperatures and CO 2 partial pressures. It has been reported that 12, 16 in the activation controlled state, the corrosion rate is proportional to CO 2 partial pressure and temperature. The results of this study showed that the corrosion rate increased as temperature increased. Also, the corrosion rate increased with increasing CO 2 partial pressure. A linear trend between corrosion rate and CO 2 partial pressure has been observed at different temperatures, confirming the direct relation of these two factors. Increasing partial pressure of CO 2 increased the slope of these lines. Solution corrosiveness partially related to its dissolved CO 2 content 18, 19 or aqueous CO 2 concentration, [CO 2(aq) ]. According to Henry s Law: where K s is solubility constant (Henry s constant); p CO2 is the partial pressure of CO 2 gas and [CO 2(aq) ] is the concentration of dissolved CO 2 in water. [CO 2(aq) ] is dependent on the CO 2 partial pressure in the gas phase, which is in equilibrium with the aqueous phase. In the case of activation controlled corrosion processes, increase in CO 2 partial pressure will lead to higher corrosion rates. 1, 12, 16, 20, 21 A higher corrosion rate was observed as the CO 2 partial pressure increased, which is shown in Figure 3. Increase in the corrosion rate at higher CO 2 partial pressure is attributed to the increase in carbonic acid concentration and, consequently, acceleration of cathodic reaction of carbonic acid reduction according to Equation 3. (2) (3) Trade name (1) ASTM International, 100 Barr Harbor Dr., West Conshohocken, PA

5 Corrosion Rate (mm/y) C 40 C 50 C 75 C P CO2 (psi) Figure 3: Corrosion rate vs. CO 2 partial pressure at different temperatures. Experiments showed that at constant CO 2 partial pressure, increasing temperature increased the corrosion rate. Temperature strongly influences the corrosion process of steel in CO 2 -containing environments, as it accelerates all the chemical, electrochemical and transport reactions involved in the corrosion process. It has been mentioned that at temperatures above 80 C, the solubility of iron carbonate decreases in the solution, creating high supersaturation which leads to precipitation of iron carbonate film on the surface. However, at lower temperatures, corrosion rates gradually increase with temperature because supersaturation of ions does not occur. 1, 13, 21 In these temperatures, precipitation of FeCO 3 does not occur, or its formation is very slow, such that a protective and dense film is not formed. Figure 4 shows the SEM image of the steel specimens tested at 50 and 75 C before cleaning the corrosion products. XRD analysis of these specimens showed the presence of only iron carbide and iron at 50 C, but at 75 C, in addition to iron carbide, iron carbonate was also detected. Scattered crystals of iron carbonate are seen on the surface of the specimen tested at 75 C. XRD analysis of the specimens tested at 50 and 75 C and 160 psi (1103 kpa) CO 2 partial pressure are shown in Figure 5. 5

6 Figure 4: SEM Images of weight loss specimens tested at 50 and 75 C for 24 hours at 160 psi CO 2 partial pressure. Only iron carbide was detected as the corrosion product at 50 C, but at 75 C, in addition to iron carbide, scattered crystals of iron carbonate formed on the surface. Figure 5: XRD pattern of weight loss specimens of the tubular steel tested at 50 and 75 C in solution with CO 2 partial pressure of 160 psi. At 50 C, iron peaks plus iiron carbide peaks were observed, but at 75 C, in addition to iron carbide, iron carbonate as a corrosion product were also observed. 6

7 14, 19 It has been mentioned that CO 2 dissolution and its hydration, chemical reactions, are slower reactions while dissociation of carbonic acid and bicarbonate ions, electrochemical reactions, are faster reactions in this process. Chemical reactions occurring in the solution can change the rate of electrochemical reactions on the surface of steel and, subsequently, the rate of corrosion. Inequality in reactions rates can lead to a local non-equilibrium in the solution. Local non-equilibrium in the solution causes the solubility limits of species to be exceeded in some regions. Exceeding the concentration of species beyond their solubility limits leads to precipitation of a layer on the surface. Figure 6 shows an example of local supersaturation and precipitation of iron carbonate formed on the surface of the specimen tested at 75 C and 80 psi (552 kpa) CO 2 partial pressure. Figure 6: Backscattered SEM image of the tubular steel specimen tested at 75 C and 80 psi CO 2 partial pressure showing local supersaturation and formation of local compact iron carbonate on the surface. Increase in CO 2 partial pressure increased the corrosion rate, as shown in Figure 3. Higher CO 2 partial pressure leads to higher carbonic acid concentration and acceleration of the cathodic reaction and, finally, corrosion rate. However, increase in CO 2 partial pressure can have a beneficial effect when a favorable condition for formation of iron carbonate is created. 22 An increase in CO 2 partial pressure leads to an increase in the corrosion rate, generating more ferrous ions, as well as increases in the concentration of bicarbonate and carbonate ions and higher supersaturation. Higher supersaturation of ions results in faster precipitation of iron carbonate on the surface. Figure 7 shows no precipitates of FeCO 3 formed on the surface of the specimen tested at 75 C and 40 psi (276 kpa) CO 2 partial pressure. Increasing CO 2 partial pressure to 80 psi (552 kpa) scattered precipitates of FeCO 3 formed on the surface and density of precipitates increased at 160 psi (1103 kpa). Although precipitates are formed on the surface, the film requires a longer exposure time to be fully protective. XRD analyses of the specimens tested at 75 C and different CO 2 partial pressures are shown in Figure 8. The intensity of iron carbonate peaks in Figure 8 confirms the relative amount of this species is formed on the surface. As shown in Figure 7, the specimen tested in 80 psi (552 kpa) contains scattered amounts of FeCO 3 and this is indicated in Figure 8 by the appearance of only the strongest peak of FeCO 3. The appearance of the other peaks of iron carbonate precipitates at 2θ equal 25, 32 and 53 degrees indicates an increase in density of FeCO 3 at higher CO 2 partial pressures. The corrosion rate prediction of steel as a function of temperature and CO 2 partial pressure developed by de Waard et al. is the most widely accepted model in the oil and gas industry. They assumed that the overall corrosion process is activation controlled and obtained an Arrhenius-type relation between corrosion rate, temperature and CO 2 partial pressure. 16 7

8 where A is a constant; Q is the activation energy; R is the gas constant; T is temperature in Kelvin; and P is CO 2 partial pressure in bar. (4) Figure 7: SEM images of corrosion products formed on the surface of the weight loss specimens of the tubular steel at 75 C at different CO 2 partial pressures. 40 (1 st row), 80 (2 nd row) and 160 psi (3 rd row). Magnification is increased from left to right. 8

9 Figure 8: XRD pattern analyses of the specimens tested at 75 C showing the effect of different CO 2 partial pressures on the formation of corrosion products. The logarithmic form of Equation 4 is: where Q is the activation energy; T is temperature in Kelvin; and P is CO 2 partial pressure in bar. Mishra et al. added the effect of ph to the de Waard equation and proposed Equation (5) (6) Considering Equation 5 and plotting the corrosion rate of the tubular steel as a function of 1/T, (Figures 9-12) approximately a straight line is obtained. Slope of the line in each CO 2 partial pressure gives the activation energy of the corrosion process, Q. Having corrosion rate results for the steel at different temperatures and CO 2 partial pressures, activation energy of the corrosion process was obtained using Equation 5, which is shown in Table 2. 9

10 Log (CR)-0.67*Log(P CO2 ) Log (CR)-0.67*Log(P CO2 ) P (CO2) 40 psi Equation y = a + b*x Adj. R-Square Value Standard Error B Intercept B Slope /T (K -1 ) Figure 9: Arrhenius plot of corrosion rate as a function of 1/T at 40 psi CO 2 partial pressure P (CO2) 80 psi Equation y = a + b*x Adj. R-Square Value Standard Error B Intercept B Slope /T (K -1 ) Figure 10: Arrhenius plot of corrosion rate as a function of 1/T at 80 psi CO 2 partial pressure. 10

11 Log (CR)-0.67*Log(P CO2 ) Log (CR)-0.67*Log(P CO2 ) P (CO2) 160 Equation y = a + b*x Adj. R-Square Value Standard Error B Intercept B Slope /T (K -1 ) Figure 11: Arrhenius plot of corrosion rate as a function of 1/T at 160 psi CO 2 partial pressure P (CO2) 320 psi Equation y = a + b*x Adj. R-Square Value Standard Error B Intercept B Slope /T (K -1 ) Figure 12: Arrhenius plot of corrosion rate as a function of 1/T at 320 psi CO 2 partial pressure. 11

12 Table 2 Activation energy and intercept A of corrosion process of the steel for different CO 2 partial pressure P CO2, psi (kpa) Q (J/mol) A 40 (276) (552) (1103) (2206) XRD analysis of corrosion products formed on the surface indicated only presence of iron carbide on the surface at 25 and 50 C, but at 75 C, besides iron carbide, iron carbonate (siderite) is also formed on the surface. The iron carbonate (siderite) formed on the surface did not cover the entire surface, as shown in Figure 7, to slow down the corrosion rate. Activation energy increased with increasing CO 2 partial pressure. Since corrosion rate increases with CO 2 partial pressure, the increase in activation energy can be attributed to the formation of scale on the surface, even though the scale is nonprotective. CONCLUSIONS This work confirmed the proportionality of the corrosion rate with temperature and CO 2 partial pressure under the activation controlled conditions of the corrosion process. At temperatures of 25, 40, 50 C, no iron carbonate formed on the surface of the steel, but at 75 C, scattered crystals of FeCO 3 formed on the surface at CO 2 partial pressures of 80 psi (552 kpa) and above. Increasing CO 2 partial pressures increased the density of FeCO 3 crystals. Formation of local compact and protective film at 75 C was observed due to the local nonequilibrium in solution which originated from inequality in reactions rate in CO 2 corrosion process of steel. Although increase in CO 2 partial pressure increased the density of iron carbonate crystals on the surface of steel, corrosion rate also increased because the formed FeCO 3 film was not dense and compact and the film requires a longer exposure time to be fully protective. Activation energy increased with increasing CO 2 partial pressure. Since corrosion rate increases with CO 2 partial pressure, the i ncrease in activation energy can be attributed to the formation of a scale on the s ur face even though the scale is non-protective. ACKNOWLEDGEMENTS The authors would like to express their acknowled g ments and appreciation of the support of Petroleum Ins t itute Abu Dhabi, UAE. Also they are thankful to DEVASCO International Inc. (Welding Products) for their help and support. The first author is grateful to Subsea Systems of Cameron International Incorporation for their support and encouragement. REFERENCES 1. M. B. Kermani and A. Morshed, Carbon Dioxide Corrosion in Oil and Gas Production A Compendium, Corrosion, Vol. 59, No. 8, 2003, pp M. R. Bonis and J. L. Crolet, Basics of the Prediction of the Risks of CO 2 Corrosion in Oil and Gas Wells, Paper No , Houston, TX: NACE,

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