A method and system for safety assessment of internal corrosion in CO2-EOR crude oil pipelines

Abstract

The present invention relates to a method and system for safety assessment of internal corrosion of a CO2-EOR crude oil pipeline, the method comprising: segmenting the CO2-EOR crude oil pipeline to obtain a plurality of segmented pipelines; calculating the key corrosion influencing factors of each segmented pipeline according to the parameters of each segmented pipeline; calculating the chemical reaction rate and mass transfer rate of each segmented pipeline according to the key corrosion influencing factors of each segmented pipeline; calculating the corrosion rate of each segmented pipeline according to the chemical reaction rate and mass transfer rate of each segmented pipeline; calculating the remaining wall thickness of each segmented pipeline according to the corrosion rate of each segmented pipeline; and evaluating the internal corrosion defects of each segmented pipeline according to the remaining wall thickness of each segmented pipeline. The present invention performs applicability evaluation on the safety status of pipeline service, can effectively identify unacceptable pipelines, and thus take targeted repair measures in a timely manner to ensure the safe and reliable operation of the pipeline.

Description

Technical Field

[0001] The present invention relates to the technical field of safety assessment of petroleum pipes, and in particular to a method and system for safety assessment of internal corrosion of a CO2-EOR crude oil pipeline. Background Art

[0002] Global climate change has garnered widespread international attention, and reducing greenhouse gas CO2 emissions to address climate change challenges has gradually become an international consensus. To achieve this goal, a series of measures are needed to reduce carbon emissions, such as vigorously developing low-carbon energy sources, developing energy-saving technologies, and employing carbon capture, utilization, and storage (CCUS). Because the conditions required for oil and gas accumulation and CO2 accumulation are very similar, CO2 capture, enhanced oil recovery (CO2-EOR), and storage, as a technology that can both enhance oil recovery and reduce CO2 emissions, offers both social and economic benefits and holds great promise for development.

[0003] However, artificial CO2 injection inevitably affects the quality of produced water, lowering its pH. Produced crude oil also carries significant amounts of CO2, exacerbating the internal corrosion environment for surface oil and gas gathering and transportation. When metal loss from the inner wall of a pipeline exceeds the designed corrosion allowance, it directly jeopardizes the pipeline's safe service life. This can affect normal oilfield production, reduce production, and lead to serious consequences such as pipeline scrapping and accidents. Furthermore, the annual maintenance investment in oilfield pipelines is substantial, reducing the economic benefits of the field. Therefore, safety assessments of pipeline corrosion are crucial. Summary of the Invention

[0004] The technical problem to be solved by the present invention is to provide a CO2-EOR crude oil pipeline internal corrosion safety assessment method and system, which can evaluate the applicability of the safety status of the pipeline in service to ensure the safe and reliable operation of the pipeline.

[0005] The present invention solves the above-mentioned technical problem with the following technical solution: A method for safety assessment of internal corrosion of a CO2-EOR crude oil pipeline comprises the following steps:

[0006] S1, segmenting the CO2-EOR crude oil pipeline to obtain multiple segmented pipelines;

[0007] S2, based on the parameters of each segmented pipeline, calculate the key corrosion influencing factors of each segmented pipeline;

[0008] S3, based on the key corrosion influencing factors of each segmented pipeline, the chemical reaction rate and mass transfer rate of each segmented pipeline are calculated;

[0009] S4, based on the chemical reaction rate and mass transfer rate of each segmented pipeline, the corrosion rate of each segmented pipeline is calculated;

[0010] S5, calculating the remaining wall thickness of each segmented pipeline according to the corrosion rate of each segmented pipeline;

[0011] S6. Evaluate the internal corrosion defects of each segmented pipeline according to the remaining wall thickness of each segmented pipeline.

[0012] On the basis of the above technical solution, the present invention can also be improved as follows.

[0013] Furthermore, the S1 is specifically:

[0014] The CO2-EOR crude oil pipeline is segmented based on the region to obtain well site process pipelines, off-site gathering pipelines, and processing station process pipelines;

[0015] The well site process pipeline is segmented using the throttle valve as a segmentation point to obtain a pipeline section from the crude oil production well to the throttle valve and a pipeline section from the throttle valve to the well site outlet;

[0016] The off-site gathering and transportation pipeline is segmented using the oil transfer station and the metering room as segmentation points to obtain a pipeline section from the well site to the oil transfer station, a pipeline section from the oil transfer station to the metering room, and a pipeline section from the metering room to the processing station;

[0017] The process pipeline of the treatment station is segmented with the decarbonization device area as the segmentation point to obtain a pipeline section from the station valve group area to the decarbonization device area, a pipeline section from the decarbonization device area to the dehydration device area, and a pipeline section from the decarbonization device area to the CO2 compression device area;

[0018] Among them, the pipeline from the crude oil production well to the throttle valve section, the pipeline from the throttle valve to the well site outlet section, the pipeline from the well site outlet to the oil transfer station section, the pipeline from the oil transfer station to the metering room section, the pipeline from the metering room to the processing station section, the pipeline from the station valve group area to the decarbonization device section, the pipeline from the decarbonization device area to the dehydration device section, and the pipeline from the decarbonization device area to the CO2 compression device section are all the said segmented pipelines.

[0019] Furthermore, if a segmented pipeline cannot simultaneously meet multiple preset conditions, the segmented pipeline is further segmented at the corresponding preset condition change point as the segmentation point; wherein the multiple preset conditions include:

[0020] The first precondition: the material of the segmented pipeline is carbon steel;

[0021] Second precondition: the inner diameter of the segmented pipeline does not change;

[0022] The third precondition: there is no heating device along the segmented pipeline;

[0023] Fourth precondition: there is no throttling device along the segmented pipeline;

[0024] Fifth prerequisite: There are no containers, storage tanks or compressors along the segmented pipeline.

[0025] Furthermore, in S2, the key corrosion influencing factors include the CO2 partial pressure in the segmented pipeline, the pH value of the medium in the segmented pipeline under standard conditions, the operating temperature of the segmented pipeline, and the flow rate of the medium in the segmented pipeline;

[0026] The formula for calculating the CO2 partial pressure in the segmented pipeline is:

[0027]

[0028] in, is the CO2 partial pressure in the segmented pipeline, P is the operating pressure of the segmented pipeline, and κ is the volume percentage of CO2;

[0029] The formula for calculating the pH value of the medium in the segmented pipeline under standard conditions is:

[0030]

[0031] Wherein, PH is the pH value of the medium in the segmented pipeline under standard conditions, and T is the operating temperature of the segmented pipeline;

[0032] The formula for calculating the flow rate of the medium in the segmented pipeline is:

[0033] f=max(f1,f2);

[0034] in,

[0035] Specifically, f is the flow rate of the medium in the segmented pipeline, f1 is the flow rate of crude oil and water, f2 is the gas phase flow rate, Q 液 is the flow rate of crude oil and water, S is the cross-sectional area of ​​the segmented pipeline, d is the inner diameter of the segmented pipeline, q s is the flow rate of the gas phase in the segmented pipeline under actual working conditions.

[0036] Furthermore, the key corrosion influencing factors include the CO2 partial pressure in the segmented pipeline, the pH value of the medium in the segmented pipeline under standard conditions, the operating temperature of the segmented pipeline and the flow rate of the medium in the segmented pipeline; in S3,

[0037] The formula for calculating the chemical reaction rate in a segmented pipeline is:

[0038]

[0039] Among them, ξ r is the chemical reaction rate of the segmented pipeline, T is the operating temperature of the segmented pipeline, is the CO2 partial pressure in the segmented pipeline, PH ais the pH value of the medium in the segmented pipeline at normal temperature and pressure, and PH is the pH value of the medium in the segmented pipeline under standard conditions;

[0040] The formula for calculating the mass transfer rate of a segmented pipeline is:

[0041]

[0042] Among them, ξ m is the mass transfer rate of the segmented pipeline, f is the flow rate of the medium in the segmented pipeline, and d is the inner diameter of the segmented pipeline.

[0043] Furthermore, in S4, the formula for calculating the corrosion rate of the segmented pipeline is:

[0044]

[0045] Among them, ξ c is the corrosion rate of the segmented pipeline, ξ m is the mass transfer rate of the segmented pipeline, ξ r is the chemical reaction rate in the segmented pipeline.

[0046] Furthermore, in S5, the formula for calculating the remaining wall thickness of the segmented pipeline is:

[0047] δ mm =δ-nξ c ;

[0048] Among them, δ mm is the remaining wall thickness of the segmented pipeline, δ is the nominal wall thickness of the segmented pipeline, n is the service life of the segmented pipeline, ξ c is the corrosion rate of the segmented pipeline.

[0049] Furthermore, the S6 is specifically as follows:

[0050] Determine the minimum allowable wall thickness of each segmented pipeline;

[0051] Based on the minimum allowable wall thickness and remaining wall thickness of each segmented pipeline, the internal corrosion defect evaluation criteria of each segmented pipeline are constructed; the internal corrosion defect evaluation criteria of the segmented pipeline are specifically as follows:

[0052]

[0053] Specifically, δ mm is the remaining wall thickness of the segmented pipeline, μ is the corrosion allowance of the segmented pipeline, η is the allowable residual strength factor, and η=0.9, δ min is the minimum allowable wall thickness of the segmented pipeline, δ l is the limit wall thickness of the segmented pipe, and δ l =max(0.2δ,2.5), δ is the nominal wall thickness of the segmented pipe;

[0054] By judging whether the internal corrosion defect evaluation criteria of each segmented pipeline are established, the internal corrosion defects of each segmented pipeline are evaluated accordingly; specifically, if the internal corrosion defect evaluation criteria of a segmented pipeline are established, it is determined that the internal corrosion defects of the segmented pipeline are acceptable under the current working pressure; if the internal corrosion defect evaluation criteria of a segmented pipeline are not established, it is determined that the internal corrosion defects of the segmented pipeline are unacceptable under the current working pressure.

[0055] Furthermore, the formula for determining the minimum allowable wall thickness of each segmented pipeline is:

[0056]

[0057] Where P is the operating pressure of the segmented pipeline, d is the inner diameter of the segmented pipeline, ε is the yield strength of the segmented pipeline material, F is the segmented pipeline design coefficient, λ is the weld coefficient, and λ=1.

[0058] Based on the above-mentioned CO2-EOR crude oil pipeline internal corrosion safety assessment method, the present invention also provides a CO2-EOR crude oil pipeline internal corrosion safety assessment system.

[0059] A CO2-EOR crude oil pipeline internal corrosion safety assessment system includes the following modules:

[0060] A segmentation module, which is used to segment the CO2-EOR crude oil pipeline into multiple segmented pipelines;

[0061] The key corrosion influencing factor calculation module is used to calculate the key corrosion influencing factors of each segmented pipeline according to the parameters of each segmented pipeline;

[0062] Chemical reaction rate and mass transfer rate calculation module, which is used to calculate the chemical reaction rate and mass transfer rate of each segmented pipeline according to the key corrosion influencing factors of each segmented pipeline;

[0063] A corrosion rate calculation module is used to calculate the corrosion rate of each segmented pipeline according to the chemical reaction rate and mass transfer rate of each segmented pipeline;

[0064] The remaining wall thickness calculation module is used to calculate the remaining wall thickness of each segmented pipeline according to the corrosion rate of each segmented pipeline;

[0065] The evaluation module is used to evaluate the internal corrosion defects of each segmented pipeline according to the remaining wall thickness of each segmented pipeline.

[0066] The beneficial effects of the present invention are as follows: a CO2-EOR crude oil pipeline internal corrosion safety assessment method and system of the present invention, through pipeline segmentation, solving key corrosion influencing factors, chemical reaction rate calculation, mass transfer rate calculation, corrosion rate calculation, remaining wall thickness calculation and internal corrosion evaluation, performs applicability evaluation on the safety status of pipeline service, can effectively identify unacceptable pipelines, so that targeted repair measures can be taken in a timely manner to ensure safe and reliable operation of the pipeline. BRIEF DESCRIPTION OF THE DRAWINGS

[0067] Figure 1 This is a flow chart of a safety assessment method for internal corrosion of a CO2-EOR crude oil pipeline according to the present invention;

[0068] Figure 2 This is a schematic diagram of the well site process pipeline segmentation;

[0069] Figure 3 This is a schematic diagram of the off-site gathering and transportation pipeline sections;

[0070] Figure 4 This is a schematic diagram of the process pipeline sections of the treatment station;

[0071] Figure 5 This is a schematic diagram of the segmented process pipelines in the well site of the example;

[0072] Figure 6 This is a schematic diagram of the segmented gathering and transportation pipeline outside the station in the example;

[0073] Figure 7 This is a schematic diagram of the process pipeline sections of the processing station in the example;

[0074] Figure 8 This is a schematic diagram of re-segmenting the process pipeline of the treatment station in the example;

[0075] Figure 9 This is a structural block diagram of a CO2-EOR crude oil pipeline internal corrosion safety assessment system according to the present invention. DETAILED DESCRIPTION

[0076] The principles and features of the present invention are described below with reference to the accompanying drawings. The examples given are only used to explain the present invention and are not used to limit the scope of the present invention.

[0077] like Figure 1 As shown, a safety assessment method for internal corrosion of a CO2-EOR crude oil pipeline includes the following steps S1-S6:

[0078] S1, segmenting the CO2-EOR crude oil pipeline to obtain multiple segmented pipelines.

[0079] Crude oil production pipelines (referred to as crude oil pipelines) are complex, with significant differences in operating conditions and fluid media. During transportation, there are often changes in diameter, throttling, pressure, and temperature. Furthermore, the CO2 content also changes before and after decarbonization. Therefore, in order to accurately determine the corrosion level of CO2-EOR crude oil production pipelines, it is necessary to calculate the pipelines in sections. Using regions as the segmentation points, the pipelines are generally divided into wellsite process pipelines, off-site gathering pipelines, and processing station process pipelines. The wellsite process pipelines, off-site gathering pipelines, and processing station process pipelines are then segmented. The specific segments are as follows:

[0080] (1) Wellsite process pipeline segmentation

[0081] Considering the different pressures and temperatures before and after the throttle valve, the throttle valve is used as the segmentation point to divide the well site process pipeline into two sections: the pipeline from the crude oil production well to the throttle valve section, and the pipeline from the throttle valve to the well site outlet section. Figure 2 shown.

[0082] (2) Off-site gathering and transportation pipeline segmentation

[0083] Pipelines from different crude oil production well sites converge at the oil transfer station after leaving the station. The medium composition changes and then is transported to the metering room through larger diameter pipelines. After the crude oil is metered, it is transported to the processing station. Therefore, the oil transfer station and the metering room are used as segmentation points to divide the off-site gathering and transportation pipeline into three sections: the pipeline from the well site to the oil transfer station, the pipeline from the oil transfer station to the metering room, and the pipeline from the metering room to the processing station. Figure 3 shown.

[0084] (3) Segmentation of process pipelines at treatment stations

[0085] After entering the station from different manifolds, it enters the valve group area in the station, and after pressure regulation, it is transported to the decarbonization device area for CO2 capture. The water phase enters the dehydration device area, and the gas phase enters the CO2 compression device area for compression, drying and injection into the formation. Therefore, the decarbonization device area is used as the segmentation point to divide the process pipeline of the treatment station into three sections: the pipeline from the station valve group area to the decarbonization device area, the pipeline from the decarbonization device area to the dehydration device area, and the pipeline from the decarbonization device area to the CO2 compression device area. Figure 4 shown.

[0086] Among them, the pipeline from the crude oil production well to the throttle valve section, the pipeline from the throttle valve to the well site outlet section, the pipeline from the well site outlet to the oil transfer station section, the pipeline from the oil transfer station to the metering room section, the pipeline from the metering room to the processing station section, the pipeline from the station valve group area to the decarbonization device section, the pipeline from the decarbonization device area to the dehydration device section, and the pipeline from the decarbonization device area to the CO2 compression device section are all the said segmented pipelines.

[0087] On the basis of the above pipeline segmentation, the following preset conditions must be met to be divided into the same section. Otherwise, they must be considered separately (that is, the segmented pipeline is further segmented at the corresponding preset condition change point as the segmentation point):

[0088] The first precondition: the material is carbon steel, such as 20#, 20G, L245, L360, L415, etc.

[0089] Second precondition: the inner diameter of the pipe does not change;

[0090] The third precondition: there is no heating device along the pipeline;

[0091] Fourth precondition: there is no throttling device along the pipeline;

[0092] Fifth prerequisite: There are no containers, storage tanks, compressors or other equipment along the pipeline.

[0093] S2, based on the parameters of each segmented pipeline, calculate the key corrosion influencing factors of each segmented pipeline.

[0094] When CO2-containing crude oil pipelines contain water, they provide the basic conditions for electrochemical corrosion. The dissolved CO2 gas in the water increases the acidity of the water, causing the pH value to drop, and the pipeline will undergo electrochemical hydrogen absorption corrosion. As the operating pressure increases, the CO2 partial pressure will also be higher, which will further promote the electrochemical corrosion process. Moreover, temperature is a sign of the intensity of the molecules of an object at the microscopic level. The increase in temperature can increase the driving force of the reaction, increase the reaction rate, and the corrosion rate will also accelerate with the increase in temperature. In addition, the corrosion process of metal materials is controlled by diffusion or mixing. Therefore, corrosion is related to the transport of reactants to the surface of the material and the transport of corrosion products to the bulk of the solution. The flow rate is an important mechanical parameter that controls the mass transfer process. Generally, as the flow rate increases, the erosion corrosion rate increases. Therefore, for CO2 corrosion, the key corrosion influencing factors to be considered include: CO2 partial pressure in the segmented pipeline, the pH value of the medium in the segmented pipeline under standard conditions, the operating temperature of the segmented pipeline, and the flow rate of the medium in the segmented pipeline. The specific solution process for the key corrosion influencing factors is as follows:

[0095] (1) Calculate the CO2 partial pressure in the segmented pipeline

[0096]

[0097] in, is the CO2 partial pressure in the segmented pipeline, unit: MPa; P is the operating pressure of the segmented pipeline, unit: MPa; κ is the volume percentage of CO2, unit: %;

[0098] (2) Calculate the pH value of the medium in the segmented pipeline under standard conditions

[0099]

[0100] Wherein, PH is the pH value of the medium in the segmented pipeline under standard conditions, unit: dimensionless; T is the operating temperature of the segmented pipeline, unit: K.

[0101] (3) Calculate the flow rate of the medium in the segmented pipeline:

[0102]

[0103]

[0104]

[0105]

[0106] f=max(f1,f2); (7)

[0107] From formula (6), we can deduce:

[0108] Where, f is the flow rate of the medium in the segmented pipeline, unit: m / s; f1 is the flow rate of crude oil and water, unit: m / s; f2 is the gas phase flow rate, unit: m / s; Q 液 is the flow rate of crude oil and water, unit: m 3 / d; S is the cross-sectional area of ​​the segmented pipeline, unit: m 2 ; d is the inner diameter of the segmented pipe, unit: m; q s The flow rate of the gas phase in the segmented pipeline under actual working conditions, unit: m 3 / s;Q 气 The flow rate of the gas phase in the segmented pipeline under standard conditions, unit: m 3 / d; P0 is the pressure under standard conditions, which is 0.1MPa; Z is the gas compressibility coefficient, which is 0.85; T0 is the temperature under standard conditions, which is 298K.

[0109] S3, based on the key corrosion influencing factors of each segmented pipeline, the chemical reaction rate and mass transfer rate of each segmented pipeline are calculated accordingly.

[0110] The electrochemical reaction process caused by corrosion is closely related to the medium temperature, CO2 partial pressure and pH value. The chemical reaction rate of the segmented pipeline is calculated using the following formula:

[0111]

[0112] Among them, ξ r is the chemical reaction rate of the segmented pipeline, unit: mm / a; T is the operating temperature of the segmented pipeline (i.e., medium temperature); is the CO2 partial pressure in the segmented pipeline; PH ais the pH value of the medium in the segmented pipeline at normal temperature and pressure; PH is the pH value of the medium in the segmented pipeline under standard conditions;

[0113] The mass transfer process is closely related to the flow rate and the inner diameter of the pipe. The formula for calculating the mass transfer rate of a segmented pipe is:

[0114]

[0115] Among them, ξ m is the mass transfer rate of the segmented pipeline; f is the flow rate of the medium in the segmented pipeline; d is the inner diameter of the segmented pipeline.

[0116] S4, according to the chemical reaction rate and mass transfer rate of each segmented pipeline, the corrosion rate of each segmented pipeline is calculated accordingly.

[0117] The chemical reaction rate and mass transfer rate are superimposed to form the final corrosion rate. The formula for calculating the corrosion rate of the segmented pipeline is:

[0118]

[0119] Among them, ξ c is the corrosion rate of the segmented pipeline, unit: mm / a; ξ m is the mass transfer rate of the segmented pipeline, ξ r is the chemical reaction rate in the segmented pipeline.

[0120] S5, according to the corrosion rate of each segmented pipeline, the remaining wall thickness of each segmented pipeline is calculated accordingly.

[0121] The formula for calculating the remaining wall thickness of a segmented pipe is:

[0122] δ mm =δ-nξ c ; (12)

[0123] Among them, δ mm is the remaining wall thickness of the segmented pipeline, unit: mm; δ is the nominal wall thickness of the segmented pipeline, unit: mm; n is the service life of the segmented pipeline, unit: a; ξ c is the corrosion rate of the segmented pipeline.

[0124] S6, evaluate the internal corrosion defects of each segmented pipeline according to the remaining wall thickness of each segmented pipeline. Specifically:

[0125] First determine the minimum allowable wall thickness of each segmented pipe:

[0126]

[0127] Among them, δ mmis the remaining wall thickness of the segmented pipeline, unit: mm; P is the operating pressure of the segmented pipeline; d is the inner diameter of the segmented pipeline; ε is the yield strength of the segmented pipeline material, unit: MPa; F is the segmented pipeline design coefficient, its value is 0.7; λ is the weld coefficient, its value is 1;

[0128] Then, based on the minimum allowable wall thickness and remaining wall thickness of each segmented pipeline, the internal corrosion defect evaluation criterion of each segmented pipeline is constructed; wherein, the internal corrosion defect evaluation criterion of the segmented pipeline is specifically as follows:

[0129]

[0130] Specifically, δ mm is the remaining wall thickness of the segmented pipeline; μ is the corrosion allowance of the segmented pipeline, unit: mm; η is the allowable residual strength factor, its value is 0.9; δ min is the minimum allowable wall thickness of the segmented pipeline; δ l is the limit wall thickness of the segmented pipe, unit: mm, and δ l =max(0.2δ,2.5), δ is the nominal wall thickness of the segmented pipe;

[0131] Finally, by judging whether the internal corrosion defect evaluation criteria of each segmented pipeline are established, the internal corrosion defects of each segmented pipeline are evaluated accordingly; specifically, if the internal corrosion defect evaluation criteria of a segmented pipeline are established, it is determined that the internal corrosion defects of the segmented pipeline are acceptable under the current working pressure; if the internal corrosion defect evaluation criteria of a segmented pipeline are not established, it is determined that the internal corrosion defects of the segmented pipeline are unacceptable under the current working pressure.

[0132] The method of the present invention is described in detail below using a CO2 flooding process in a certain oil field block as an example.

[0133] An oil field has three oil wells, one oil transfer station, one metering room, and one processing station. The processing station contains a valve group, a decarbonization device, a dehydration device, and a CO2 compression device. According to the present invention, a safety assessment of internal pipeline corrosion is conducted. The specific steps are as follows:

[0134] Step 1: Pipeline Segmentation

[0135] (1) Wellsite process pipeline segmentation

[0136] Since there are 3 oil wells, they are divided into 6 sections, such as Figure 5 shown.

[0137] (2) Off-site gathering and transportation pipeline segmentation

[0138] The second, fourth and sixth sections of the pipeline coming out of the three well sites enter the oil transfer station and are then divided into two sections, namely the seventh and eighth sections. Figure 6 shown.

[0139] (3) Segmentation of the gathering and transportation pipelines at the treatment station

[0140] After the crude oil enters the station, it is divided into three sections, namely the 9th, 10th and 11th sections. Figure 7 shown.

[0141] In addition, since there is a pressure regulating valve between the inlet valve group area and the decarbonization device area for pressure boosting, the 9th section of the processing station gathering pipeline is divided into 2 sections, and the 10th and 11th sections are made of stainless steel 316L. Therefore, the re-divided pipeline is as follows Figure 8 shown.

[0142] Step 2: Solve the key factors affecting pipeline corrosion

[0143] (1) CO2 partial pressure in segmented pipelines

[0144] The CO2 partial pressure in each segmented pipeline is calculated using formula (1). Table 1 records the CO2 partial pressure in each segmented pipeline:

[0145] Table 1

[0146]

[0147] (2) pH value of the medium in the segmented pipeline under standard conditions

[0148] The pH value of the medium in each segmented pipeline under standard conditions is calculated using formula (2). Table 2 records the pH value of the medium in each segmented pipeline under standard conditions:

[0149] Table 2

[0150]

[0151] (3) Medium flow rate in segmented pipelines

[0152] The medium flow rate in each segmented pipeline is calculated using equations (3) to (8). Table 3 records the medium flow rate in each segmented pipeline:

[0153] Table 3

[0154]

[0155]

[0156] Step 3: Chemical reaction rate calculation

[0157] The chemical reaction rate of each segmented pipeline is calculated using formula (9). Table 4 records the chemical reaction rate of each segmented pipeline:

[0158] Table 4

[0159]

[0160] Step 4: Mass transfer rate calculation

[0161] The mass transfer rate of each segmented pipeline is calculated using formula (10). Table 5 records the mass transfer rate of each segmented pipeline:

[0162] Table 5

[0163]

[0164] Step 5: Corrosion Rate Calculation

[0165] The corrosion rate of each segmented pipeline is calculated using formula (11). Table 6 records the corrosion rate of each segmented pipeline:

[0166] Table 6

[0167]

[0168]

[0169] Step 6: Calculation of remaining wall thickness

[0170] The remaining wall thickness of each segmented pipeline is calculated using formula (12). Table 7 records the remaining wall thickness of each segmented pipeline:

[0171] Table 7

[0172] Pipeline Name δ, mm n,a <![CDATA[ξ c ,mm / a]]> <![CDATA[δ mm ,mm]]> Paragraph 1 7 2 0.64 5.72 Paragraph 2 7 2 0.78 5.45 Paragraph 3 7 2 0.44 6.13 Paragraph 4 7 2 0.53 5.95 Paragraph 5 7 2 0.68 5.65 Paragraph 6 7 2 0.83 5.34 Paragraph 7 8 2 0.73 6.54 Paragraph 8 8 2 1.91 4.19 Paragraph 9 8 2 1.76 4.48 Paragraph 10 6 2 0.73 4.54

[0173] Step 7: Internal Corrosion Evaluation

[0174] The minimum allowable wall thickness of each segmented pipeline is calculated using formula (13). Table 7 records the minimum allowable wall thickness of each segmented pipeline:

[0175] The internal corrosion defect evaluation criterion (14) of each segmented pipeline is judged to be valid, thereby correspondingly evaluating the internal corrosion defects of each segmented pipeline. The evaluation results of the internal corrosion defects of each segmented pipeline are shown in Table 8:

[0176] Table 8

[0177]

[0178] Based on the above-mentioned CO2-EOR crude oil pipeline internal corrosion safety assessment method, the present invention also provides a CO2-EOR crude oil pipeline internal corrosion safety assessment system.

[0179] like Figure 9 As shown in the figure, a CO2-EOR crude oil pipeline internal corrosion safety assessment system includes the following modules:

[0180] A segmentation module, which is used to segment the CO2-EOR crude oil pipeline into multiple segmented pipelines;

[0181] The key corrosion influencing factor calculation module is used to calculate the key corrosion influencing factors of each segmented pipeline according to the parameters of each segmented pipeline;

[0182] Chemical reaction rate and mass transfer rate calculation module, which is used to calculate the chemical reaction rate and mass transfer rate of each segmented pipeline according to the key corrosion influencing factors of each segmented pipeline;

[0183] A corrosion rate calculation module is used to calculate the corrosion rate of each segmented pipeline according to the chemical reaction rate and mass transfer rate of each segmented pipeline;

[0184] The remaining wall thickness calculation module is used to calculate the remaining wall thickness of each segmented pipeline according to the corrosion rate of each segmented pipeline;

[0185] The evaluation module is used to evaluate the internal corrosion defects of each segmented pipeline according to the remaining wall thickness of each segmented pipeline.

[0186] The specific functions of each module in the CO2-EOR crude oil pipeline internal corrosion safety assessment system of the present invention can be found in the steps of the CO2-EOR crude oil pipeline internal corrosion safety assessment method of the present invention, which will not be repeated here.

[0187] The present invention provides a CO2-EOR crude oil pipeline internal corrosion safety assessment method and system. By segmenting the pipeline, solving key corrosion influencing factors, calculating chemical reaction rates, mass transfer rates, corrosion rates, remaining wall thickness, and internal corrosion, the system conducts a suitability assessment of the pipeline's service safety status. Unacceptable pipelines can be effectively identified, allowing targeted repair measures to be taken in a timely manner to ensure safe and reliable operation of the pipeline.

[0188] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the scope of protection of the present invention.

Claims

1. A safety assessment method for internal corrosion of CO2-EOR crude oil pipeline, characterized by: The following steps are involved: S1, segmenting the CO2-EOR crude oil pipeline to obtain multiple segmented pipelines; S2, based on the parameters of each segmented pipeline, calculate the key corrosion influencing factors of each segmented pipeline; S3, based on the key corrosion influencing factors of each segmented pipeline, the chemical reaction rate and mass transfer rate of each segmented pipeline are calculated; S4, based on the chemical reaction rate and mass transfer rate of each segmented pipeline, the corrosion rate of each segmented pipeline is calculated; S5, calculating the remaining wall thickness of each segmented pipeline according to the corrosion rate of each segmented pipeline; S6, evaluating the internal corrosion defects of each segmented pipeline according to the remaining wall thickness of each segmented pipeline; In said S2, said key corrosion influencing factors include CO2 partial pressure in the segmented pipeline, pH value of the medium in the segmented pipeline under standard conditions, operating temperature of the segmented pipeline and flow rate of the medium in the segmented pipeline; The formula for calculating the CO2 partial pressure in the segmented pipeline is: ； in, is the CO2 partial pressure in the segmented pipeline, is the operating pressure of the segmented pipeline, is the volume percentage of CO2; The formula for calculating the pH value of the medium in the segmented pipeline under standard conditions is: ； in, is the pH value of the medium in the segmented pipeline under standard conditions, is the operating temperature of the segmented pipeline; The formula for calculating the flow rate of the medium in the segmented pipeline is: ； in, , ; Specifically, is the flow velocity of the medium in the segmented pipeline, are the flow rates of crude oil and water, is the gas phase flow rate, is the flow rate of crude oil and water, is the cross-sectional area of ​​the segmented pipe, is the inner diameter of the segmented pipe, is the flow rate of the gas phase in the segmented pipeline under actual working conditions; The key corrosion influencing factors include the CO2 partial pressure in the segmented pipeline, the pH value of the medium in the segmented pipeline under standard conditions, the operating temperature of the segmented pipeline and the flow rate of the medium in the segmented pipeline; in S3, The formula for calculating the chemical reaction rate in a segmented pipeline is: ； in, is the chemical reaction rate in the segmented pipeline, is the operating temperature of the segmented pipeline, is the CO2 partial pressure in the segmented pipeline, is the pH value of the medium in the segmented pipeline at normal temperature and pressure, is the pH value of the medium in the segmented pipeline under standard conditions; The formula for calculating the mass transfer rate of a segmented pipeline is: ； in, is the mass transfer rate in the segmented pipeline, is the flow velocity of the medium in the segmented pipeline, is the inner diameter of the segmented pipe; In S4, the formula for calculating the corrosion rate of the segmented pipeline is: ； in, is the corrosion rate of the segmented pipeline, is the mass transfer rate in the segmented pipeline, is the chemical reaction rate of the segmented pipeline; In S5, the formula for calculating the remaining wall thickness of the segmented pipeline is: ； in, is the remaining wall thickness of the segmented pipe, is the nominal wall thickness of the segmented pipe, is the service life of the segmented pipeline, is the corrosion rate of the segmented pipeline; The S6 is specifically: Determine the minimum allowable wall thickness of each segmented pipeline; Based on the minimum allowable wall thickness and remaining wall thickness of each segmented pipeline, the internal corrosion defect evaluation criteria of each segmented pipeline are constructed; the internal corrosion defect evaluation criteria of the segmented pipeline are specifically as follows: ； Specifically, is the remaining wall thickness of the segmented pipe, is the corrosion allowance of the segmented pipeline, is the allowable residual strength factor, and , is the minimum allowable wall thickness of the segmented pipe, is the limit wall thickness of the segmented pipe, and , is the nominal wall thickness of the segmented pipe; By judging whether the internal corrosion defect evaluation criteria of each segmented pipeline are established, the internal corrosion defects of each segmented pipeline are evaluated accordingly; specifically, if the internal corrosion defect evaluation criteria of a segmented pipeline are established, it is determined that the internal corrosion defects of the segmented pipeline are acceptable under the current working pressure; if the internal corrosion defect evaluation criteria of a segmented pipeline are not established, it is determined that the internal corrosion defects of the segmented pipeline are unacceptable under the current working pressure.

2. The CO2-EOR crude oil pipeline internal corrosion safety assessment method according to claim 1, characterized in that: The S1 is specifically: The CO2-EOR crude oil pipeline is segmented based on the region to obtain well site process pipelines, off-site gathering pipelines, and processing station process pipelines; The well site process pipeline is segmented using the throttle valve as a segmentation point to obtain a pipeline section from the crude oil production well to the throttle valve and a pipeline section from the throttle valve to the well site outlet; The off-site gathering and transportation pipeline is segmented using the oil transfer station and the metering room as segmentation points to obtain a pipeline section from the well site to the oil transfer station, a pipeline section from the oil transfer station to the metering room, and a pipeline section from the metering room to the processing station; The process pipeline of the treatment station is segmented with the decarbonization device area as the segmentation point to obtain a pipeline section from the station valve group area to the decarbonization device area, a pipeline section from the decarbonization device area to the dehydration device area, and a pipeline section from the decarbonization device area to the CO2 compression device area; Among them, the pipeline from the crude oil production well to the throttle valve section, the pipeline from the throttle valve to the well site outlet section, the pipeline from the well site outlet to the oil transfer station section, the pipeline from the oil transfer station to the metering room section, the pipeline from the metering room to the processing station section, the pipeline from the station valve group area to the decarbonization device section, the pipeline from the decarbonization device area to the dehydration device section, and the pipeline from the decarbonization device area to the CO2 compression device section are all the said segmented pipelines.

3. The CO2-EOR crude oil pipeline internal corrosion safety assessment method according to claim 2, characterized in that: If a segmented pipeline cannot simultaneously meet multiple preset conditions, the segmented pipeline is further segmented at the corresponding preset condition change point as the segmentation point; wherein the multiple preset conditions include: The first precondition: the material of the segmented pipeline is carbon steel; The second precondition: the inner diameter of the segmented pipeline does not change; The third precondition: there is no heating device along the segmented pipeline; Fourth precondition: there is no throttling device along the segmented pipeline; Fifth precondition: There are no containers, storage tanks or compressors along the segmented pipeline.

4. The CO2-EOR crude oil pipeline internal corrosion safety assessment method according to claim 1, characterized in that: The formula for determining the minimum allowable wall thickness of each segmented pipe is: ； in, is the operating pressure of the segmented pipeline, is the inner diameter of the segmented pipe, is the yield strength of the segmented pipeline material, is the segmented pipeline design coefficient, is the weld coefficient, and .

5. A CO2-EOR crude oil pipeline internal corrosion safety assessment system, characterized by: The method for safety assessment of internal corrosion of a CO2-EOR crude oil pipeline as claimed in any one of claims 1 to 4 comprises the following modules: A segmentation module, which is used to segment the CO2-EOR crude oil pipeline into multiple segmented pipelines; The key corrosion influencing factor calculation module is used to calculate the key corrosion influencing factors of each segmented pipeline according to the parameters of each segmented pipeline; Chemical reaction rate and mass transfer rate calculation module, which is used to calculate the chemical reaction rate and mass transfer rate of each segmented pipeline according to the key corrosion influencing factors of each segmented pipeline; A corrosion rate calculation module is used to calculate the corrosion rate of each segmented pipeline according to the chemical reaction rate and mass transfer rate of each segmented pipeline; The remaining wall thickness calculation module is used to calculate the remaining wall thickness of each segmented pipeline according to the corrosion rate of each segmented pipeline; The evaluation module is used to evaluate the internal corrosion defects of each segmented pipeline according to the remaining wall thickness of each segmented pipeline.

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