A method for predicting the internal corrosion rate of natural gas pipelines based on the CO2 corrosion mechanism

Abstract

The present invention provides a method for predicting the internal corrosion rate of natural gas pipelines based on the CO2 corrosion mechanism. First, corrosion environment data obtained from actual detection is acquired; the corrosion environment data is input into a validated CO2 corrosion rate prediction mechanism model to obtain the predicted corrosion rate. The construction method of the CO2 corrosion rate prediction mechanism model is as follows: corrosion experiments are respectively carried out on the rigid body to be measured under the flowing condition in a pure CO2 saturated solution and under the online top corrosion condition to obtain corrosion data; the adsorption and charge transfer parameters of carbonic acid and H + on the iron surface are calculated and analyzed based on the first principles of density functional theory to obtain the corrosion mechanism of CO2; an initial model is constructed according to the corrosion mechanism and the corrosion process; the accuracy of the initial model is calibrated according to the corrosion data to obtain the CO2 corrosion rate prediction mechanism model. The internal corrosion rate prediction model established according to the CO2 corrosion mechanism of the present invention has higher prediction accuracy and can provide a theoretical basis for the safe operation of natural gas pipelines.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas corrosion protection, and particularly to a method for predicting the internal corrosion rate of natural gas pipelines based on the CO2 corrosion mechanism. Background Art

[0002] In recent years, the global demand for oil and gas energy has been increasing continuously. The oil and gas transportation system is the key to connecting the production end and the consumption end. Among them, pipeline transportation is regarded as the preferred method for long-distance oil and gas transportation due to its safety and economy. However, during the operation of pipelines, pipeline steel will inevitably fail. Therefore, predicting the pipeline corrosion rate is of great significance for the safe operation of pipelines.

[0003] It is very important to clarify the corrosion medium when establishing a corrosion rate prediction model. Corrosion in oil and gas production and transmission facilities is usually caused by the co-existing aqueous phase, acidic gases, and dissolved acidic compounds. During the exploitation of natural gas, CO2 almost always exists as a by-product, and carbonic acid, the hydrate of CO2, is also the most common corrosion medium in pipelines. The uniform CO2 corrosion of high-strength steel is also one of the most studied and theoretically well-understood corrosion systems. Therefore, most of the current corrosion rate prediction models are based on CO2 corrosion.

[0004] In recent years, relevant scholars have conducted a large number of studies on CO2 corrosion in different environments and proposed many corrosion rate prediction models. However, with the continuous in-depth study of CO2 corrosion, some scholars have found that the existing CO2 corrosion theory can no longer explain some experimental phenomena. Especially when the medium flow rate is relatively fast, the CO2 corrosion rate is higher. And due to the effect of environmental temperature difference, part of the water vapor condenses on the inner wall of the top of the pipeline, causing corrosion at the top of the line. These two common corrosion conditions cannot directly apply the traditional CO2 corrosion rate prediction model. Therefore, it is necessary to study the CO2 corrosion behavior and mechanism under flowing and top-of-line corrosion conditions, so as to establish a CO2 corrosion rate prediction model to ensure the safe operation of natural gas pipelines. Summary of the Invention

[0005] In order to overcome the deficiencies of the prior art, the purpose of the present invention is to provide a method for predicting the internal corrosion rate of natural gas pipelines based on the CO2 corrosion mechanism.

[0006] To achieve the above purpose, the present invention provides the following solutions:

[0007] A method for predicting the internal corrosion rate of natural gas pipelines based on the CO2 corrosion mechanism, comprising:

[0008] Obtaining the actually detected corrosion environment data;

[0009] Input the corrosion environment data into the verified CO2 corrosion rate prediction mechanism model to obtain the predicted corrosion rate;

[0010] The construction method of the CO2 corrosion rate prediction mechanism model is as follows:

[0011] Perform corrosion experiments on the rigid body to be measured under flowing conditions in a pure CO2 saturated solution and under online top corrosion conditions respectively to obtain corrosion data;

[0012] Based on the first-principles calculation of density functional theory for the adsorption and charge transfer parameters of carbonic acid and H + on the iron surface, and analyze the charge transfer law to obtain the corrosion mechanism of CO2;

[0013] Construct an initial model according to the corrosion mechanism and corrosion process;

[0014] Calibrate the accuracy of the initial model according to the corrosion data to obtain the CO2 corrosion rate prediction mechanism model.

[0015] Preferably, the corrosion process includes:

[0016] Chemical process, electrochemical process and mass transfer process.

[0017] Preferably, the corrosion experiments on the rigid body to be measured under flowing conditions in a pure CO2 saturated solution and under online top corrosion conditions respectively to obtain corrosion data include:

[0018] Use electrochemical tests and microscopic characterization means to determine the corrosion behavior of the rigid body to be measured under flowing and liquid accumulation conditions in a pure CO2 saturated solution to obtain the first experimental result;

[0019] Compare and analyze the corrosion behavior laws under flowing and liquid accumulation conditions according to the first experimental result.

[0020] Preferably, the corrosion experiments on the rigid body to be measured under flowing conditions in a pure CO2 saturated solution and under online top corrosion conditions respectively to obtain corrosion data include:

[0021] Use electrochemical tests and microscopic characterization means to determine the CO2 corrosion behavior of the rigid body to be measured under online top corrosion conditions to obtain the second experimental result;

[0022] Analyze the structure and composition of the corrosion products according to the second experimental result.

[0023] Preferably, the first-principles calculation of density functional theory for the adsorption and charge transfer parameters of carbonic acid and H + on the iron surface, and analyze the charge transfer law to obtain the corrosion mechanism of CO2, including:

[0024] Calculating the adsorption situation and charge transfer parameters of carbonic acid and H + on the Fe surface;

[0025] Determining the transfer law according to the adsorption situation and charge transfer parameters;

[0026] Analyzing and summarizing according to the transfer law to obtain the corrosion mechanism.

[0027] Preferably, the modeling method of the chemical process includes:

[0028] Determining the dynamic phase equilibrium process in the CO2 - mixed salt - H2O system;

[0029] Obtaining the equilibrium constant for calculating the dynamic phase equilibrium process according to thermodynamic concepts;

[0030] Constructing the chemical process according to the equilibrium constants of the thermodynamic equilibrium processes of carbonic acid dissociation and water dissociation, the equilibrium constant of the dynamic phase equilibrium process, and the dynamic phase equilibrium process.

[0031] Preferably, the modeling method of the electrochemical process includes:

[0032] Determining the anodic reaction, cathodic reaction, and equilibrium potential according to the Nernst equation;

[0033] Determining that the anodic reaction is the dissolution of Fe and the cathodic reaction is H + and the reduction of H2O according to the corrosion mechanism;

[0034] Determining the current densities of the anodic reaction and the cathodic reaction according to the Tafel equation;

[0035] Constructing the electrochemical process according to the current density.

[0036] Preferably, the modeling method of the mass transfer process includes:

[0037] Determining the flux expression and mass transfer formula of substances according to molecular diffusion caused by convection and the electro - migration of various ions;

[0038] Simplifying and condition - constraining the flux expression and the mass transfer formula to obtain the metal surface flux formula;

[0039] Constructing the mass transfer process according to the metal surface flux formula.

[0040] Preferably, the rigid body to be measured is X80 steel.

[0041] According to the specific embodiments provided by the present invention, the present invention discloses the following technical effects:

[0042] The present invention provides a method for predicting the internal corrosion rate of natural gas pipelines based on the CO2 corrosion mechanism. First, corrosion environment data obtained from actual detection is acquired; the corrosion environment data is input into a verified CO2 corrosion rate prediction mechanism model to obtain the predicted corrosion rate. The construction method of the CO2 corrosion rate prediction mechanism model is as follows: corrosion experiments of the rigid body to be measured are respectively carried out under flowing conditions in a pure CO2 saturated solution and under online top corrosion conditions to obtain corrosion data; the adsorption and charge transfer parameters of carbonic acid and H + on the iron surface are calculated based on the first principles of density functional theory, and the charge transfer law is analyzed to obtain the corrosion mechanism of CO2; an initial model is constructed according to the corrosion mechanism and the corrosion process; the accuracy of the initial model is calibrated according to the corrosion data to obtain the CO2 corrosion rate prediction mechanism model. The internal corrosion rate prediction model established according to the CO2 corrosion mechanism in the present invention has higher prediction accuracy and can provide a theoretical basis for the safe operation of natural gas pipelines. BRIEF DESCRIPTION OF THE DRAWINGS

[0043] In order to more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the following will briefly introduce the drawings required for use in the embodiments. Obviously, the drawings in the following description are only some embodiments of the present invention, and those of ordinary skill in the art can also obtain other drawings without creative efforts based on these drawings.

[0044] Figure 1 It is a flowchart of the method provided by the embodiment of the present invention;

[0045] Figure 2 It is a flowchart of the corrosion rate prediction model provided by the embodiment of the present invention;

[0046] Figure 3 It is a schematic diagram of the corrosion mechanism under dynamic conditions provided by the embodiment of the present invention;

[0047] Figure 4 It is a schematic diagram of the corrosion mechanism under the condition of a thin liquid layer provided by the embodiment of the present invention

[0048] Figure 5 It is a schematic diagram of the comparison between the corrosion rate obtained by testing in a CO2 environment and the calculation result of the prediction model provided by the embodiment of the present invention. DETAILED DESCRIPTION OF THE EMBODIMENTS

[0049] The following will clearly and completely describe the technical solutions in the embodiments of the present invention with reference to the accompanying drawings in the embodiments of the present invention. Obviously, the described embodiments are only a part of the embodiments of the present invention, rather than all the embodiments. All other embodiments obtained by those of ordinary skill in the art based on the embodiments of the present invention without creative efforts shall fall within the protection scope of the present invention.

[0050] Reference to "embodiment" herein means that a particular feature, structure, or characteristic described in connection with the embodiment can be included in at least one embodiment of the present application. The phrase appears in various places in the specification and does not necessarily refer to the same embodiment, nor is it an independent or alternative embodiment mutually exclusive with other embodiments. Those skilled in the art will explicitly and implicitly understand that the embodiments described herein can be combined with other embodiments.

[0051] The terms "first", "second", "third", "fourth", etc. in the specification and claims of the present application and the accompanying drawings are used to distinguish different objects, rather than to describe a specific order. In addition, the terms "comprising" and "having" and any variations thereof are intended to cover non-exclusive inclusion. For example, a series of steps, processes, methods, etc. included do not limit to the listed steps, but optionally further include steps not listed, or optionally further include other step elements inherent to these processes, methods, products, or devices.

[0052] The object of the present invention is to provide a method for predicting the internal corrosion rate of a natural gas pipeline based on the CO2 corrosion mechanism. The internal corrosion rate prediction model established according to the CO2 corrosion mechanism has higher prediction accuracy and can provide a theoretical basis for the safe operation of natural gas pipelines.

[0053] To make the above objects, features, and advantages of the present invention more obvious and understandable, the present invention will be further described in detail below with reference to the accompanying drawings and specific embodiments.

[0054] Figure 1 For the method flow chart provided by the embodiments of the present invention, as Figure 1 shown, the present invention provides a method for predicting the internal corrosion rate of a natural gas pipeline based on the CO2 corrosion mechanism, including:

[0055] Step 100: Obtain the actually detected corrosion environment data;

[0056] Step 200: Input the corrosion environment data into the verified CO2 corrosion rate prediction mechanism model to obtain the predicted corrosion rate;

[0057] The step 200 further includes:

[0058] Step 201: Conduct corrosion experiments on the rigid body to be measured under the conditions of flowing in a pure CO2 saturated solution and under the condition of on-line top corrosion, and obtain corrosion data;

[0059] Step 202: Calculate the adsorption and charge transfer parameters of carbonic acid and H + on the iron surface based on the first principles of density functional theory, analyze the charge transfer law, and obtain the corrosion mechanism of CO2;

[0060] Step 203: Construct an initial model according to the corrosion mechanism and the corrosion process;

[0061] Step 204: Calibrate the accuracy of the initial model according to the corrosion data to obtain the CO2 corrosion rate prediction mechanism model.

[0062] Among them, the rigid body to be measured can be X80 steel.

[0063] Figure 2 This is the flow chart of the corrosion rate prediction model provided by the embodiment of the present invention. As Figure 2 shown, in this embodiment, the corrosion behavior of X80 steel under the conditions of liquid accumulation and flow in a pure CO2 saturated solution is first studied by means of electrochemical tests and microscopic characterization, and the corrosion behavior laws under the conditions of liquid accumulation and flow are compared and analyzed. The corrosion mechanism diagram under dynamic conditions is as Figure 3 shown; similarly, the CO2 corrosion behavior of X80 steel under the condition of on-line top corrosion is studied by means of electrochemical tests and microscopic characterization. The on-line top corrosion environment is similar to a thin liquid layer, so the structure and composition of the corrosion products are analyzed under the condition of a thin liquid layer, so as to clarify the CO2 corrosion behavior law under the condition of on-line top corrosion. The corrosion mechanism diagram under the condition of a thin liquid layer is as Figure 4 shown; by calculating the adsorption and charge transfer parameters of carbonic acid and H + on the iron surface based on the first principles of density functional theory, analyze the charge transfer law to clarify the CO2 corrosion mechanism. Preferably, the corrosion process includes:

[0064] Chemical process, electrochemical process and mass transfer process.

[0065] Preferably, the corrosion experiments on the rigid body to be measured under the conditions of flowing in a pure CO2 saturated solution and under the condition of on-line top corrosion to obtain corrosion data include:

[0066] Use electrochemical tests and microscopic characterization means to determine the corrosion behavior of the rigid body to be measured under the conditions of flowing and liquid accumulation in a pure CO2 saturated solution, and obtain the first experimental result;

[0067] According to the first experimental result, compare and analyze the corrosion behavior laws under the conditions of flow and liquid accumulation.

[0068] Preferably, corrosion experiments of the rigid body to be tested are respectively carried out under flowing conditions in a pure CO2 saturated solution and under online top corrosion conditions to obtain corrosion data, including:

[0069] Determine the CO2 corrosion behavior of the rigid body to be tested under online top corrosion conditions through electrochemical tests and microscopic characterization means to obtain the second experimental result;

[0070] Analyze the structure and composition of the corrosion products according to the second experimental result.

[0071] Specifically, corrosion kinetic parameters are obtained through experiments to provide data support for establishing a CO2 corrosion rate prediction mechanism model.

[0072] Preferably, the first-principles calculation based on density functional theory calculates the adsorption and charge transfer parameters of carbonic acid and H + on the iron surface and analyzes the charge transfer law to obtain the corrosion mechanism of CO2, including:

[0073] Use first-principles calculation to calculate the adsorption situation and charge transfer parameters of carbonic acid and H + on the Fe surface;

[0074] Determine the transfer law according to the adsorption situation and charge transfer parameters;

[0075] Analyze and summarize according to the transfer law to obtain the corrosion mechanism.

[0076] Optionally, in order to further clarify the carbonic acid corrosion mechanism, first-principles calculation is used to calculate the adsorption and charge transfer ability of carbonic acid and H + on the Fe surface, and integrate the mathematical relationship of the corrosion mechanism into the corrosion rate prediction model to provide a theoretical basis for the remaining life prediction of pipelines. The calculation results are shown in Tables 1, 2 and 3.

[0077] Table 1 Adsorption energy and bond length before and after adsorption of H2CO3 at different positions Bond angle Change situation

[0078]

[0079] Table 2 Adsorption energy and bond length before and after adsorption of H + at different positions Bond angle Change situation

[0080]

[0081] Table 3 Charge population

[0082]

[0083] This embodiment determines the cathodic reaction mechanism of carbonic acid in pipeline corrosion and finds that the reduction of H + dominates the cathodic reaction of carbonic acid, and the direct reduction of carbonic acid is not important and can even be ignored. The main conclusions are as follows:

[0084] (1) The two O atoms in the carbonic acid molecule are negatively charged, with the lowest Mulliken charge and the strongest reactivity, so they are more likely to bond with Fe. On the most stable Fe(110) surface, the optimal adsorption position of carbonic acid is the TH position, and the adsorption energy of H + is much smaller than that of carbonic acid, so H + is more likely to adsorb on the Fe surface and then react.

[0085] (2) In the prediction of pipeline corrosion rate, it is very important to determine the cathodic reaction substances. The theoretical calculation results show that the direct reduction of carbonic acid can be ignored, and the reduction rate of H + determines the magnitude of the corrosion rate.

[0086] Preferably, the modeling method of the chemical process includes:

[0087] Determine the dynamic phase equilibrium process in the CO2 - mixed salt - H2O system;

[0088] According to the thermodynamic concept, obtain the equilibrium constant for calculating the dynamic phase equilibrium process;

[0089] Construct the chemical process according to the equilibrium constants of the thermodynamic equilibrium processes of carbonic acid dissociation and water dissociation, the equilibrium constant of the dynamic phase equilibrium process, and the dynamic phase equilibrium process.

[0090] Specifically, the chemical process steps based on the CO2 corrosion process are as follows:

[0091] (1) In the CO2 - mixed salt - H2O system, CO2 molecules in the CO2 - rich phase and H2O molecules in the H2O - rich phase will dissolve into each other's phases, and finally reach dynamic phase equilibrium under given temperature and pressure conditions. At the equilibrium state, the dynamic phase equilibrium process can be written as:

[0092]

[0093]

[0094] (2) In this work, according to the basic thermodynamic concept, the equilibrium constant (K) is used to calculate the dynamic phase equilibrium process:

[0095]

[0096]

[0097] where f i is the fugacity of gaseous H2O and CO2, which can be calculated by the following expression:

[0098]

[0099] where, P i is the partial pressure of component i, P is the pressure, is the fugacity coefficient of gaseous component i.

[0100] (3) In addition, in natural gas pipelines, the transportation temperature is generally not higher than 50 °C, so there is no need to consider the activity model of H2O to represent the non-ideality of electrolytes.

[0101] Carbonic acid dissociation:

[0102]

[0103]

[0104] Water dissociation:

[0105]

[0106] (4) The equilibrium constants (K) of these thermodynamic equilibrium processes can be calculated:

[0107]

[0108]

[0109]

[0110]

[0111] where, K is the reaction equilibrium constant, a i is the ion activity.

[0112] Preferably, the modeling method of the electrochemical process includes:

[0113] Determining the anodic reaction, cathodic reaction and equilibrium potential according to the Nernst equation;

[0114] Determining that the anodic reaction is the dissolution of Fe and the cathodic reaction is the reduction of H + and H2O according to the corrosion mechanism;

[0115] Determining the current densities of the anodic reaction and the cathodic reaction according to the Tafel equation;

[0116] Constructing the electrochemical process according to the current density.

[0117] Specifically, the electrochemical process steps based on the CO2 corrosion process are as follows:

[0118] (1) In the presence of an electrolyte, the essence of metal corrosion is an electrochemical corrosion reaction occurring on the metal surface. For the corrosion of carbon steel in a CO2-containing environment, the anodic process is the dissolution of iron. For the cathodic process, the direct reduction of carbonic acid can be ignored. According to the Nernst equation, the possible anodic and cathodic reactions and their equilibrium potentials are summarized as follows:

[0119] Anodic reaction:

[0120]

[0121]

[0122] Cathodic reaction:

[0123]

[0124] (2) According to the results of the study on the CO2 corrosion mechanism, the anodic and cathodic reactions considered in this model are the dissolution of Fe and the reduction of H + , H2O. The current density of the anodic reaction, i.e., the corrosion rate or corrosion current density, is controlled by the charge transfer process. However, the current density of each electrochemical cathodic reaction is controlled by the charge transfer process and mass transfer process of the active species involved in these cathodic reactions:

[0125] i corr = i a = i c,tot ;

[0126]

[0127] where I r is the current density of the electrode reaction controlled by charge transfer, and I L is the limiting diffusion current density controlled by mass transfer. For the current density of the electrode reaction controlled by charge transfer, it can be calculated using the Tafel equation:

[0128]

[0129]

[0130] where, i corr is the corrosion current density, i0 is the exchange current density, T is the temperature, T R is the reference temperature, and R is the gas constant.

[0131] Preferably, the modeling method of the mass transfer process includes:

[0132] Determine the flux expression and mass transfer formula of substances based on molecular diffusion caused by convection and the electro-migration of various ions;

[0133] Simplify and impose conditional constraints on the flux expression and the mass transfer formula to obtain the metal surface flux formula;

[0134] Construct the mass transfer process according to the metal surface flux formula.

[0135] Specifically, the steps of the mass transfer process based on the CO2 corrosion process are as follows:

[0136] (1) The rate of the electrochemical reaction is determined by the concentration of the reactants, and the concentration of the reactants is determined by the mass transfer process. The mass transfer process includes molecular diffusion caused by convection and the electro-migration of various ions. Describe the mass transfer process of species in the diffusion layer using a mass balance equation covering chemical reactions and electrochemical reactions:

[0137] The flux of substances can be described by the following formula:

[0138]

[0139] From the Nernst - Plank equation:

[0140]

[0141] where N i is the flux of species i, and R i is the net reaction rate of species i.

[0142] (2) Since the prediction object is uniform corrosion, there is only a concentration gradient in the direction perpendicular to the electrode surface. Therefore, the above formula can be simplified to

[0143]

[0144]

[0145] (3) Since the formula is a partial differential equation, specific initial conditions and boundary conditions are required. At the initial time (T = 0), assuming the solution is uniform, the concentration of the solution on the metal surface is a known value, and throughout the reaction process, the total concentration of species remains unchanged. Therefore, for electroactive species, the mass flux at the boundary between the metal surface and the solution is the rate of the electrochemical reaction. The metal surface flux is as follows:

[0146]

[0147] (4) For non - electroactive species, since they do not participate in the electrochemical reaction, the flux is 0:

[0148]

[0149] (5) Meanwhile, there is also an "electroneutrality" constraint condition in the electrochemical process:

[0150]

[0151]

[0152] Finally, in this embodiment, a prediction mechanism model for CO2 corrosion rate is established based on the chemical process, electrochemical process, and mass transfer process of the CO2 corrosion process, and the prediction accuracy of the model is calibrated through experimental data. By assuming uniform corrosion on the metal surface, a simple one-dimensional structure from the solution to the metal surface is constructed, which is also a typical corrosion situation. When the temperature, pressure, solution properties, and CO2 partial pressure are constant, the corrosion rate can be calculated through the above formula. The corrosion rate calculated by the prediction model is compared with the experimental data to verify the accuracy of the model. The results are as Figure 5 shown, where Figure 5 the dotted line represents twice the error. It can be seen that almost all the data are within the range representing twice the error limit, which proves that the model can accurately calculate the corrosion rate under normal conditions, and the consistency between the prediction and test results further supports the corrosion mechanism proposed in this embodiment.

[0153] The various embodiments in this specification are described in a progressive manner. Each embodiment focuses on the differences from other embodiments. For the same or similar parts among the embodiments, reference can be made to each other.

[0154] Specific examples are used in this article to elaborate on the principles and implementation manners of the present invention. The descriptions of the above embodiments are only used to help understand the method and its core idea of the present invention; at the same time, for those of ordinary skill in the art, based on the idea of the present invention, there will be changes in the specific implementation manners and application scopes. In summary, the content of this specification should not be construed as a limitation to the present invention.

Claims

1. A method for predicting the internal corrosion rate of natural gas pipelines based on the CO2 corrosion mechanism, characterized in that, Including: Obtain the actually detected corrosion environment data; Input the corrosion environment data into the verified CO2 corrosion rate prediction mechanism model to obtain the predicted corrosion rate; The construction method of the CO2 corrosion rate prediction mechanism model is as follows: Conduct corrosion experiments on the rigid body to be tested under flowing conditions in a pure CO2 saturated solution and under on-line top corrosion conditions respectively to obtain corrosion data; First-principles calculations based on density functional theory for the adsorption and charge transfer parameters of carbonic acid and H + on the iron surface, and analyze the charge transfer law to obtain the corrosion mechanism of CO2; Construct an initial model according to the corrosion mechanism and corrosion process; Calibrate the accuracy of the initial model according to the corrosion data to obtain the CO2 corrosion rate prediction mechanism model.

2. The method for predicting the internal corrosion rate of a natural gas pipeline based on the CO2 corrosion mechanism according to claim 1, characterized in that The corrosion process includes: Chemical process, electrochemical process and mass transfer process.

3. A method for predicting the internal corrosion rate of a natural gas pipeline based on the CO2 corrosion mechanism according to claim 1, characterized in that The corrosion experiments on the rigid body to be tested under flowing conditions in a pure CO2 saturated solution and under on-line top corrosion conditions respectively to obtain corrosion data include: Use electrochemical tests and microscopic characterization means to determine the corrosion behavior of the rigid body to be tested under flowing and liquid accumulation conditions in a pure CO2 saturated solution to obtain the first experimental result; Compare and analyze the corrosion behavior laws under flowing and liquid accumulation conditions according to the first experimental result.

4. A method for predicting the internal corrosion rate of a natural gas pipeline based on the CO2 corrosion mechanism according to claim 1, characterized in that, The corrosion experiments on the rigid body to be tested under flowing conditions in a pure CO2 saturated solution and under on-line top corrosion conditions respectively to obtain corrosion data include: Determine the CO2 corrosion behavior of the rigid body to be tested under on-line top corrosion conditions through electrochemical tests and microscopic characterization means to obtain the second experimental result; Analyze the structure and composition of the corrosion products according to the second experimental result.

5. A method for predicting the internal corrosion rate of a natural gas pipeline based on the CO2 corrosion mechanism according to claim 1, characterized in that, The first-principles calculation of carbonic acid and H based on density functional theory + The adsorption and charge transfer parameters on the iron surface, and analyze the charge transfer law to obtain the corrosion mechanism of CO2, including: Using first-principles calculations for the adsorption of carbonic acid and H + on the Fe surface and the charge transfer parameters; Determine the transfer law according to the adsorption situation and charge transfer parameters; Analyze and summarize according to the transfer law to obtain the corrosion mechanism.

6. The method for predicting the internal corrosion rate of a natural gas pipeline based on the CO2 corrosion mechanism according to claim 2, wherein, The modeling method of the chemical process includes: Determine the dynamic phase equilibrium process in the CO2 - mixed salt - H2O system; According to thermodynamic concepts, obtain the equilibrium constant for calculating the dynamic phase equilibrium process; Construct the chemical process according to the equilibrium constants of the thermodynamic equilibrium processes of carbonic acid dissociation and water dissociation, the equilibrium constant of the dynamic phase equilibrium process and the dynamic phase equilibrium process.

7. A method for predicting the internal corrosion rate of a natural gas pipeline based on the CO2 corrosion mechanism according to claim 2, characterized in that The modeling method of the electrochemical process includes: According to the Nernst equation, determine the anodic reaction, cathodic reaction and equilibrium potential; Based on the corrosion mechanism, it is determined that the anodic reaction is the dissolution of Fe and the cathodic reaction is the reduction of H + and H2O; Determine the current densities of the anodic reaction and the cathodic reaction according to the Tafel equation; Construct the electrochemical process according to the current densities.

8. A method for predicting the internal corrosion rate of a natural gas pipeline based on the CO2 corrosion mechanism according to claim 2, characterized in that, The modeling method of the mass transfer process includes: Determine the flux expression and mass transfer formula of substances according to molecular diffusion caused by convection and the electro-migration of various ions; Simplify and conditionally constrain the flux expression and the mass transfer formula to obtain the metal surface flux formula; Construct the mass transfer process according to the metal surface flux formula.

9. A method for predicting the internal corrosion rate of a natural gas pipeline based on the CO2 corrosion mechanism according to claim 1, characterized in that The rigid body to be tested is X80 steel.

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