A method for predicting corrosion in submarine and land oil pipelines under the coupling of CO2 and H2S

Abstract

The present application relates to the technical field of corrosion protection of oil exploitation, storage and transportation equipment, and particularly relates to a method for predicting internal corrosion of submarine and land oil pipelines under CO2 and H2S coupling, which fully absorbs a DW model, a solution electrolytic balance theory and a corrosion electrochemistry theory to form a simple CO2 corrosion rate function formula, then through high-pressure corrosion simulation experiments, an orthogonal experiment method is used to study the corrosion rate of samples in a reaction kettle at different temperatures, CO2 and H2S partial pressure ratios, and a bivariate parameter result is fitted to seek a function relationship between the corrosion rate and experimental temperature and gas partial pressure ratio, a corrosion rate function relationship formula under CO2 and H2S coupling is obtained, and a method for predicting internal corrosion of submarine and land oil pipelines under CO2 and H2S coupling is constructed, actual use condition parameters are substituted into the method, and then the corrosion rate under CO2 and H2S coupling can be calculated, the method can provide a basis for corrosion prevention material selection and corrosion allowance determination, and safety of submarine and land oil pipeline materials is ensured.

Description

TECHNICAL FIELD

[0001] The present application relates to the field of corrosion protection technology for oil exploitation, storage and transportation equipment, and particularly relates to a method for predicting internal corrosion of submarine and land oil pipelines under the coupling of CO2 and H2S. BACKGROUND

[0002] With the acceleration of oilfield development, especially the wide application of CO2 injection technology in shale oil exploitation, the content of wet CO2 and H2S in produced crude oil is increasing, and the internal corrosion problem of oil and gas pipelines caused thereby is becoming increasingly serious.

[0003] There is no clear consensus on the corrosion law under the coupling of CO2 and H2S. Foreign scholars Greco and William systematically studied the static and dynamic corrosion behavior of metals in the H2S-CO2-H2O system when the H2S partial pressure was 0.0004-550 kPa, and the experimental temperature was 30℃. The sum of CO2 and H2S pressure was 1 bar. The results showed that the H2S partial pressure had different trends of influence on the corrosion rate in different ranges. With the increase of H2S partial pressure, the corrosion rate showed a trend of first decreasing, then remaining unchanged, and then increasing. Hughes and Stromberg experiments showed that H2S was usually considered to be a harmful factor for oil and gas field corrosion, but under certain conditions, H2S could inhibit corrosion. Murata et al. believed that under some corrosion conditions (such as 60℃), the presence of H2S could inhibit uniform corrosion, while under other corrosion conditions (such as 20℃), the presence of H2S would accelerate uniform corrosion, and the corrosion rate was a function of H2S, CO2 partial pressure and temperature. Newman's research showed that when the H2S content was higher, the inhibition effect of CO2 corrosion was reduced, and sometimes it would even accelerate corrosion. Ohio University Nesic et al. used multiphase flow loop and other devices to systematically study the effect of a small amount of H2S on CO2 corrosion. The research results showed that compared with pure CO2 corrosion, the presence of a small amount of H2S would reduce the corrosion rate under both single-phase flow and multiphase flow conditions. At a temperature of 60℃, when the H2S content reached a certain critical value, the corrosion rate would decrease, but then with the increase of H2S content, the corrosion rate would change little. Through literature review, it was found that even a small amount of H2S would have a significant impact on CO2 corrosion, but whether the impact was beneficial or harmful, a unified conclusion had not been reached. SUMMARY

[0004] The technical problem solved by the present application is to provide a CO2, H2S coupling seabed and land oil pipeline internal corrosion prediction method, based on the above existing research results, the carbon dioxide corrosion function relationship is constructed, the H2S influence factor is established combined with the experimental results, the corrosion quantitative prediction problem under the coexistence of CO2 and H2S is solved, and the basis for the design, material selection and daily maintenance of oil and gas storage and transportation equipment under the related state is provided. The method belongs to the pioneering work in the field, ensures the accuracy of the prediction results, simplifies the experimental data processing process, reduces the result error, and is widely applicable to personnel and environment.

[0005] The technical solution adopted by the present application to achieve the technical purpose is: a CO2, H2S coupling seabed and land oil pipeline internal corrosion prediction method, the corrosion prediction method can be summarized as: calculating the pH value of the solution, the corrosion product film influence factor, the corrosion rate of pure CO2, then establishing the relationship between the H2S influence factor and the related factors through simulation experiment, and finally obtaining the corrosion rate calculation method under the coupling of CO2 and H2S. Specifically, the steps include:

[0006] Step 1. Calculate the H + Concentration and pH value in the solution, the specific steps are as follows:

[0007] (a) According to the basic rules of hydration and ionization equilibrium of CO2 and H2S in the solution, the relationship between C H + and CO2, H2S partial pressure, ion concentration and equilibrium constant in the medium containing NaCl and NaHCO3 is established:

[0008]

[0009] Wherein: C H + is the hydrogen ion concentration (mol / L); The bicarbonate ion concentration in the system under standard conditions (mol / L); is the carbon dioxide partial pressure in the system (bar); is the hydrogen sulfide partial pressure in the system (bar);K1~K4 are the equilibrium constants of carbon dioxide hydration and electrolysis in the system;K5~K6 are the equilibrium constants of hydrogen sulfide hydration and electrolysis in the system;K8 is the ionization reaction equilibrium constant of water itself;

[0010] (b) Under the determined environmental conditions, the Newton iteration method is used to solve the cubic equation determined by (formula-1), and C H + , and the pH value of the solution is calculated through (formula-2):

[0011]

[0012] Step 2. The CO2 corrosion rate prediction model is mainly based on the corrosion electrochemical kinetics law, and the corrosion process is controlled by the activation reaction (charge transfer) and ion mass transfer two processes. The CO2 corrosion rate prediction model is established according to the corrosion electrochemical process:

[0013] (a) According to the cathode reduction current density of the corrosion electrochemical process, the relationship between the corrosion rate and the corrosion current density is established based on the expression form of the reaction kinetics equation and the ion mass transfer current density:

[0014]

[0015] Wherein: V is the CO2 corrosion rate of the system (mm / a); V r V is the activation control corrosion rate m V is the mass transfer control corrosion rate (mm / a);

[0016] (b) According to the DW semi-empirical model [1-3] , the determination method of V r , V m :

[0017]

[0018]

[0019] Wherein: V r V is the activation control corrosion rate (mm / a); V m V is the mass transfer control corrosion rate (mm / a); T is the system temperature (℃); P is the CO2 partial pressure (bar); U is the liquid flow rate (m / s); d is the pipe diameter (mm); pH1 is calculated by (formula-2), and pH2 is calculated according to (formula-6):

[0020]

[0021] (c) The results are corrected by introducing the corrosion product film influence factor of According to the existing research results, the introduced corrosion product film influence factor is:

[0022]

[0023] According to the above semi-empirical formula, the pure CO2 corrosion rate can be calculated according to (formula-8):

[0024]

[0025] Step 3. According to actual working conditions, a high-pressure simulation corrosion environment is established in the laboratory, and orthogonal experiments are set with CO2, H2S partial pressure ratio and experimental temperature as variable factors, and the uniform corrosion rate of the sample is measured by weight loss method (the average value of 3 parallel samples is calculated each time), the corrosion rate under different conditions is determined, and the function relationship between the corrosion rate and the experimental temperature, gas partial pressure ratio is sought by fitting with double variable parameters, namely:

[0026] Determine the H2S influence factor:

[0027]

[0028] Wherein: F H2S is the H2S influence factor; T is the temperature (℃); is the CO2 partial pressure (bar); is the H2S partial pressure (bar);

[0029] Step 4. The corrosion rate model under the coupling of CO2 and H2S is established, and the corrosion rate under the coupling of CO2 and H2S can be calculated when the environmental conditions are determined:

[0030]

[0031] Preferably, the oil pipeline suitable material is carbon or low alloy pipeline steel.

[0032] Preferably, the influence of Cl - , HCO3 - and temperature factors on the corrosion rate prediction results is considered: the H + concentration in the solution and the pH value calculation involve the concentration of Cl - , HCO3 - ions in the system, the equilibrium constant in the pH value calculation process, the electrochemical kinetics equation used in the calculation of the carbon dioxide corrosion rate and the H2S influence factor all take the system temperature as a variable factor.

[0033] Compared with the prior art, the beneficial effects of the present application are:

[0034] The corrosion rate prediction method involved in the present application considers the actual working conditions of the coexistence of CO2 and H2S in oil, is closer to the actual environment, and belongs to the pioneering work in the field.

[0035] The basic idea of the present application is to fully absorb the DW model (full name: De Waard-Milliams carbon dioxide corrosion rate prediction model, a semi-empirical model), solution electrolytic equilibrium theory and corrosion electrochemistry theory to form a simple CO2 corrosion rate function, and to establish an H2S influence factor based on the experimental results, and finally form the prediction model. This process is scientific and rigorous, which guarantees the accuracy of the prediction results.

[0036] The present application introduces the concept of H2S influence factor when fitting the experimental data, and changes the relationship between the corrosion rate experimental results and the multiple factors into the relationship between the H2S influence factor and the CO2, H2S partial pressure and temperature, and further converts the multivariate parameter fitting into a bivariate parameter fitting process. The experimental data processing process is simplified, and the result error is reduced.

[0037] All steps of the present application are displayed in explicit functions, suitable for computer software operation (such as excel, mathlab, etc.), and the results can be obtained without special complex calculation by only obtaining the operating parameters, which is suitable for a wide range of personnel and environment. BRIEF DESCRIPTION OF DRAWINGS

[0038] Figure 1 The structure diagram of the corrosion rate prediction model under the coupling of CO2 and H2S. DETAILED DESCRIPTION

[0039] In order to make the purpose, technical scheme and advantages of the present application more clear and obvious, the present application is further described in detail below through the drawings and examples. However, it should be understood that the specific examples described herein are only used to explain the present application, and are not used to limit the scope of the present application. In addition, in the following description, the description of the known structure and technology is omitted to avoid unnecessary confusion of the concept of the present application.

[0040] Example 1:

[0041] Please refer to Figure 1 A CO2, H2S coupling submarine and land oil pipeline internal corrosion prediction method is provided, which is suitable for carbon or low alloy pipeline steel materials. The corrosion prediction method can be summarized as follows: calculating the solution pH value, corrosion product film influence factor, pure CO2 corrosion rate, and then establishing the relationship between the H2S influence factor and the related factors through simulation experiments, and finally obtaining the corrosion rate calculation method under the coupling of CO2 and H2S. Specifically, the following steps are included:

[0042] Step 1. Calculate the H + concentration and pH value in the solution, and the specific steps are as follows:

[0043] (a) According to the basic law of CO2, H2S hydration and ionization equilibrium in the solution, a C H + Relationship between CO2, H2S partial pressure and ion concentration and equilibrium constant:

[0044]

[0045] Wherein: C H + is the hydrogen ion concentration (mol / L); is the bicarbonate ion concentration in the system under standard conditions (mol / L); is the carbon dioxide partial pressure in the system (bar); is the hydrogen sulfide partial pressure in the system (bar); K1~K4 are the equilibrium constants of carbon dioxide hydration and electrolysis in the system; K5~K6 are the equilibrium constants of hydrogen sulfide hydration and electrolysis in the system; K8 is the ionization reaction equilibrium constant of water itself, wherein the specific values of K1~K8 refer to Table 1;

[0046] Table 1 Empirical calculation formula of equilibrium constant

[0047]

[0048]

[0049] (b) Under the determined environmental conditions, the Newton iteration method is used to solve the cubic equation determined by (Formula-1), and C H + The pH value of the solution is calculated by (Formula-2):

[0050]

[0051] Step 2. According to the corrosion rate prediction model mainly based on the law of corrosion electrochemistry kinetics, the corrosion process is controlled by two processes of activation reaction (charge transfer) and ion mass transfer, and the CO2 corrosion rate prediction model is established:

[0052] (a) According to the expression form of the cathode reduction current density based on the reaction kinetics equation and the ion mass transfer current density of the corrosion electrochemistry process, the relationship between the corrosion rate and the corrosion current density is established:

[0053]

[0054] Wherein: CR CO2 is the carbon dioxide corrosion rate of the system (mm / a); V r is the activation controlled corrosion rate V m is the mass transfer controlled corrosion rate (mm / a);

[0055] (b) Based on the DW semi-empirical model [1-3] , obtain V r V m Method for determining:

[0056]

[0057]

[0058] Where: V r To activate and control the corrosion rate (mm / a); V m To control corrosion rate through mass transfer

[0059] (mm / a); T is the system temperature (°C); Where is the partial pressure of CO2 (bar); U is the liquid flow velocity (m / s); d is the pipe diameter (mm); pH1 is calculated by (Equation-2), and pH2 is calculated according to (Equation-6):

[0060]

[0061] (c) Introducing corrosion product film influence factors on CR CO2 The results were revised, and based on existing research, the introduced corrosion product film influence factor is:

[0062]

[0063] Based on the above semi-empirical formula, the pure CO2 corrosion rate can be calculated according to (Formula-8):

[0064]

[0065] Step 3. Based on actual working conditions, establish a high-pressure simulated corrosion environment in the laboratory. Set up an orthogonal experiment with the partial pressure ratio of CO2 and H2S and the experimental temperature as variable factors. Measure the uniform corrosion rate of the samples using the weight loss method (calculate the average value of 3 parallel samples for each experiment) to determine the corrosion rate under different conditions. Use bivariate parameters to fit and seek the functional relationship between the corrosion rate and the experimental temperature and gas partial pressure ratio, i.e.:

[0066] Determine the impact factors of H2S:

[0067]

[0068] Wherein: F H2S is the H2S influencing factor; T is the temperature (°C); CO2 partial pressure (bar); For H2S partial pressure (bar);

[0069] Step 4. Establishing the corrosion rate model under the coupling of CO2 and H2S, the corrosion rate under the coupling of CO2 and H2S can be calculated when the environmental conditions are determined.

[0070]

[0071] Further, the influence of Cl - , HCO3 - and temperature factors on the corrosion rate prediction results is considered: the H + concentration in the solution and the pH value calculation involve the concentration of Cl - , HCO3 - ions in the system, and the equilibrium constant in the pH value calculation process, the electrochemical kinetics equation used in the calculation of the carbon dioxide corrosion rate and the H2S influence factor all take the system temperature as a variable factor.

[0072] Example 2:

[0073] Please refer to Figure 1 , on the basis of the above examples, an embodiment of the method for predicting the corrosion in the submarine and land oil pipeline under the coupling of CO2 and H2S:

[0074] (1) According to the requirements of Table 1, the on-site operating parameters are grabbed:

[0075] Table 1 Operating parameters required for corrosion rate calculation under the coupling of CO2 and H2S

[0076]

[0077]

[0078] (2) According to the attached Table 1, the equilibrium constants K1-K8 are calculated, the equilibrium constant calculation results and the operating parameters grabbed in Table 1 are substituted into the (Formula-1) equation, and C H+ is solved;

[0079]

[0080] (3) According to (Formula-2), C H+ is converted into pH1 value;

[0081]

[0082] (4) The working condition temperature and the carbon dioxide partial pressure are substituted into (Formula-6) to calculate pH2;

[0083]

[0084] (5) The working condition temperature, carbon dioxide partial pressure and calculated pH1, pH2 are substituted into (Formula-4) to calculate Vr ;

[0085]

[0086] (6) substituting the working condition flow rate, carbon dioxide partial pressure, and inner diameter into (Formula-5) to calculate V m ;

[0087]

[0088] (7) substituting the working condition temperature and flow rate into (Formula-7) to calculate the corrosion product film influence factor;

[0089]

[0090] (8) substituting the V r , V m , and f Scale values calculated in (5), (6), and (7) above into (Formula-8) to calculate

[0091]

[0092] (9) according to the relationship between under the working condition and 800, and calculating the H2S influence factor according to (Formula-9);

[0093]

[0094] (10) substituting the values calculated in (8) and (9) above into (Formula-10) to calculate the coupled corrosion rate CR value;

[0095]

[0096] The scheme in this embodiment can be selectively combined with the scheme in other embodiments.

[0097] It should be noted that although the above embodiments have been described in the present text, the patent protection scope of the present application is not limited thereby. Therefore, based on the innovative idea of the present application, changes and modifications to the embodiments described in the present text, or equivalent structures, equivalent processes, or equivalent function transformations made using the content of the present application specification and drawings, directly or indirectly applying the above technical solutions to other related technical fields, are all included in the protection scope of the present application patent.

Claims

1. A method for predicting internal corrosion of submarine and land oil pipelines under the coupling of CO2 and H2S, characterized in that, Specifically comprising the following steps: Step 1. Calculate the concentration of H + in solution and the pH value, in particular as follows: (a) According to the basic law of hydration and ionization equilibrium of CO2 and H2S in solution, the relationship between the ion concentration and the equilibrium constant of CO2 and H2S in the medium containing NaCl and NaHCO3 is established: and the partial pressure of CO2 and H2S. (Formula-1) wherein: is the hydrogen ion concentration; is the bicarbonate ion concentration in the system at standard conditions; is the carbon dioxide partial pressure in the system; is the hydrogen sulfide partial pressure in the system; K1~K4 are the equilibrium constants for the hydration and electrolysis of carbon dioxide in the system; K5~K6 are the equilibrium constants for the hydration and electrolysis of hydrogen sulfide in the system; K8 is the equilibrium constant for the ionization of water itself; (b) In the determination of the environmental conditions, using Newton iteration method to solve the cubic equation determined by formula-1, we can get , and then through formula-2 to calculate the solution of value: (Formula-2) Step 2. According to the corrosion rate prediction model, based on the corrosion electrochemical kinetics law, the corrosion process is controlled by the activation reaction and ion mass transfer process, the CO2 corrosion rate prediction model is established: (a) According to the cathode reduction current density of the corrosion electrochemical process, the corrosion rate and the corrosion current density relationship is established based on the reaction kinetics equation and the expression form of ion mass transfer current density: (Formula-3) wherein: VCO2is the carbon dioxide corrosion rate of the system; V r VACT is the activation controlled corrosion rate; V m Vm is the mass transfer controlled corrosion rate; (b) V is obtained according to the DW semi-empirical model r , V m determination method: (Formula-4) (Formula-5) where: V r is the activation controlled corrosion rate; V m is the mass transfer controlled corrosion rate; T is the system temperature; is the CO2 partial pressure; U is the liquid flow rate; d is the pipe diameter; pH1 is calculated from equation -2 and pH2 is calculated from equation -6: (Formula-6) (c) introducing a corrosion product film influence factor The results are corrected according to the existing research results, and the introduced corrosion product film influence factor is: (Formula-7) According to the above DW semi-empirical model, the pure CO2 corrosion rate can be calculated according to formula-8: (Formula-8) Step 3. According to the actual working condition, the high pressure simulation corrosion environment is established in the laboratory, the orthogonal experiment is set with CO2, H2S partial pressure ratio and experimental temperature as variable factors, the uniform corrosion rate of the sample is measured by weight loss method, the corrosion rate under different conditions is determined, and the function relationship between the corrosion rate and the experimental temperature, gas partial pressure ratio is sought by fitting with double variable parameters, that is: V 腐蚀速率 =V (T, / ), determining the H2S impact factor: (Formula-9) wherein: T is temperature; and is the CO2 partial pressure; is the H2S partial pressure; Step 4. The corrosion rate model under the coupling of CO2 and H2S is established, and when the environmental conditions are determined, the corrosion rate under the coupling of CO2 and H2S can be calculated: (Formula-10).

2. The method according to claim 1, wherein the method is characterized by: The oil pipeline suitable material is carbon or low alloy pipeline steel.

3. The method according to claim 1, wherein the method is characterized by: Considered and temperature factors on the corrosion rate prediction results, H + Concentration and pH value calculation involved in the system ion concentration, the equilibrium constant in the process of pH value calculation, electrochemical kinetics equation used in the calculation of carbon dioxide corrosion rate and H2S influence factor will take the system temperature as a variable factor.

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