A method for predicting the remaining life of oil well casing in a changing corrosive environment

Abstract

The present invention discloses a method for predicting the remaining service life of oil well casing in a changing corrosion environment. By combining experiments with mathematical modeling, an equation for the variation of casing corrosion rate with service time and a curve equation for the variation of corrosion depth with service time, i.e., a dynamic corrosion rate evolution equation, are established. A downhole casing bending stress model is established. By utilizing finite element model simulation technology and combining coupled calculations of the dynamic development of corrosion with the downhole stress conditions of the casing, the remaining service life of the casing is predicted more scientifically and accurately, thereby reducing the safety and environmental risks caused by casing failure.

Description

Technical Field

[0001] The invention relates to the technical field of oilfield corrosion and protection, and in particular to a method for predicting the remaining service life of an oil well casing in a changing corrosion environment. Background Art

[0002] With the development of oil and gas fields, most wells currently experience a corrosive environment characterized by high mineralization and the coexistence of multiple acidic gases. With increasing water content in oil wells, water injection development, and the extension of well production life, the downhole corrosion environment undergoes corresponding changes. The increasingly demanding service conditions of reservoir casing accelerate casing corrosion, leading to increasingly severe corrosion conditions. This seriously threatens wellbore safety and normal oil and gas production, and may even lead to well scrapping and shutdown, posing risks to oilfield safety and effective well development. Casing damage caused by corrosion is primarily due to thinning of the casing wall due to corrosion, which leads to collapse failure or material yield failure under various downhole stresses. Therefore, developing a method to effectively assess the evolution of casing corrosion patterns throughout the life cycle of an oil well, and establishing a casing strength mechanical failure model and a casing remaining life prediction method that better reflects actual downhole operating conditions, is of great significance for the selection of casing materials and the safe management of casing service.

[0003] Current methods for predicting the remaining life of casing only consider a single downhole corrosion environment, failing to account for the fact that this environment can change over time as the well is produced, leading to variations in the corrosion rate of the casing during different production stages. Furthermore, since casing is typically several thousand meters long, the corrosion environment of other pipelines differs significantly, while the forces acting on different casing layers vary. Existing methods for predicting the remaining life of casing generally do not make this distinction or only perform predictions for the casing in the most corroded reservoir layer. The methods currently reported in the literature primarily consider loads such as principal formation stress, geothermal gradient, internal pressure, and extrusion loads, failing to consider the bending loads borne by the downhole casing as the wellbore trajectory changes. Summary of the Invention

[0004] In order to overcome the above technical deficiencies, the present invention provides a method for predicting the remaining service life of oil well casing in a changing corrosive environment, thereby achieving a more scientific, effective and accurate prediction of the remaining service life of oil well casing in a changing corrosive environment, and providing a basis for the rational selection of materials for oil well casing and the formulation of anti-corrosion technical measures for different production stages of oil wells.

[0005] In order to achieve the above objectives, the present invention adopts the following technical solutions:

[0006] A method for predicting the remaining life of oil well casing in a changing corrosive environment comprises the following steps:

[0007] According to the corrosive environment of the oil well, the corrosion weight loss test of casing steel with different experimental time was carried out to obtain the corrosion rate of different experimental time.

[0008] Using the relationship between the corrosion rate and the experimental duration for different experimental durations, a regression curve equation of the annual corrosion rate under the corrosive environment is obtained by fitting;

[0009] Based on the specific corrosion environment corresponding to the different service times of oil wells, short-term corrosion weight loss tests were conducted on casing steel to obtain the short-term corrosion rate of casing steel at different service times. This series of short-term corrosion rate data was regressed with the service time data to obtain the relationship between short-term corrosion rate and service time. Combined with the annual corrosion rate regression curve equation, the relationship between annual corrosion rate and service time was converted.

[0010] Integrating the relationship between the annual corrosion rate and the service time with respect to the service time to obtain a relationship between the corrosion depth of the casing and the service time;

[0011] A finite element model of downhole casing was established. Based on the actual stress conditions of the casing, relevant constraints and loads were set on the finite element model of the casing. The critical failure wall thickness for uniform corrosion of the casing was analyzed and solved. The corresponding corrosion margin was calculated based on the critical failure wall thickness.

[0012] The corrosion allowance is substituted as the corrosion depth into the relationship between the corrosion depth and the service time, and the corresponding service time is calculated. The service time is the remaining life of the casing.

[0013] The following is a detailed description of each step:

[0014] Step "Based on the corrosion environment downhole in the oil well, corrosion weight loss experiments are carried out on the casing steel for different experimental durations to obtain the corrosion rates for different experimental durations."

[0015] Preferably, the different experimental durations include 7 days, 14 days, 21 days and 28 days.

[0016] Preferably, the corrosion weight loss experiment is carried out in a high-temperature and high-pressure autoclave.

[0017] Preferably, the calculation formula for the corrosion rate of the different experimental durations is as follows:

[0018] CR=87600·Δm / (tρs)

[0019] Where CR is the corrosion rate, mm / year (mm / a); Δm is the mass change before and after the experiment, g; t is the experimental time, h; ρ is the density of the casing steel, g / cm 3 ; s is the corrosion surface area, cm 2 .

[0020] Step "using the relationship between the corrosion rate and the experimental duration of the different experimental durations to fit the regression curve equation of the annual corrosion rate under the corrosion environment".

[0021] The regression curve equation of the annual corrosion rate can be expressed as:

[0022] CR year =f1(t1)

[0023] Among them, t1 is time, days; when time t1 is 365 days, CR year is the annual corrosion rate, mm / year.

[0024] Taking the downhole corrosion environment at any service time of the oil well as the benchmark, a short-term (for example, 3 days) corrosion weight loss test is conducted on the casing steel in this environment using a high-temperature autoclave to obtain its short-term corrosion rate CR0. The short-term corrosion rate (CR0) of the casing material at any other service time is x,y ) can be converted into annual corrosion rate according to the following formula:

[0025] CR year,x,y =(CR x,y / CR0)×f1(t1)

[0026] Among them, CR0 is the short-term corrosion rate of casing material measured by corrosion coupon test based on a certain corrosive environment of oil well, CR x，y The short-term corrosion rate of the casing material is measured by the corrosion coupon test in any other corrosive environment of the oil well. year，x，y CR x，y The corresponding annual corrosion rate, t1, is 365 days.

[0027] The steps are: "Based on the specific corrosion environment corresponding to the different service times of the oil well, short-term corrosion weight loss tests are conducted on the casing steel to obtain the short-term corrosion rate of the casing steel at different service times; this series of short-term corrosion rate data is regressed with the service time data to obtain the relationship between short-term corrosion rate and service time, and the relationship between annual corrosion rate and service time is converted by combining the annual corrosion rate regression curve equation."

[0028] Preferably, the different service times include the 1st, 4th, 7th, ..., 1+3n years, where n is an integer greater than 2.

[0029] Preferably, the regression curve equation of the annual corrosion rate is:

[0030] CR x,y =f2(t2)

[0031] Among them, t1 is time, day; when the conversion time t1 is 365 days, CR year is the annual corrosion rate in mm / year;

[0032] Substituting the regression curve equation of the annual corrosion rate into the relationship between short-term corrosion rate and service time to obtain the relationship between the annual corrosion rate and service time;

[0033] The annual corrosion rate of casing material in any corrosive environment of oil well is expressed as:

[0034] CR year,x,y =(f2(t2) / CR0)×f1(t1)

[0035] Among them, CR0 is the short-term corrosion rate of casing material measured by corrosion coupon test based on a certain corrosive environment of oil well, CR x，y The short-term corrosion rate of the casing material is measured by the corrosion coupon test in any other corrosive environment of the oil well. year，x，y CR x，y The corresponding annual corrosion rate, t1 is 365 days;

[0036] Since the relationship between short-term corrosion rate and service time is:

[0037] CR x,y =f2(t2)

[0038] Therefore, the relationship between the annual corrosion rate and service time is:

[0039] CR year,x,y =(f2(t2) / CR0)×f1(t1)

[0040] Among them, t1, t1 is 365 days, and t2 is the casing service time, years.

[0041] Preferably, the test duration of the short-term corrosion weight loss test is 3 days.

[0042] The step of "integrating the relationship between the annual corrosion rate and the service time with respect to the service time to obtain the relationship between the corrosion depth of the casing and the service time".

[0043] The relationship between corrosion depth and service time is:

[0044]

[0045] The steps include: "establishing a finite element model of the downhole casing, setting relevant constraints and loads on the finite element model of the casing according to the actual stress conditions of the casing, analyzing and solving the critical failure wall thickness for uniform corrosion of the casing; and calculating the corresponding corrosion allowance based on the critical failure wall thickness."

[0046] Preferably, the maximum critical failure wall thickness and the minimum critical failure wall thickness are calculated for the maximum and minimum stress conditions of the downhole casing respectively, and the corresponding minimum corrosion allowance and maximum corrosion allowance are calculated corresponding to the maximum critical failure wall thickness and the minimum critical failure wall thickness.

[0047] Preferably, the calculation formula of the corrosion allowance is as follows:

[0048] D y =D0–D n

[0049] Where D0 is the original casing wall thickness, D n is the critical failure wall thickness of the casing.

[0050] The step of "substituting the corrosion allowance as the corrosion depth into the relationship between the corrosion depth and the service time, and calculating the corresponding service time, where the service time is the remaining life of the casing".

[0051] Preferably, two remaining lives are calculated respectively according to the minimum corrosion allowance and the maximum corrosion allowance, and the remaining life of the casing is within the two remaining life ranges according to changes in actual environmental conditions.

[0052] Preferably, the steps of establishing a finite element model of downhole casing to calculate the casing wall thickness corrosion allowance are as follows:

[0053] Parameters such as wellbore trajectory, wellbore structure, casing size, casing temperature at different depths, hydrostatic column pressure, formation pressure, and cementing quality are obtained based on on-site well design plans, cementing and completion data, and logging data;

[0054] A 3D solid model of the casing is established based on the casing size and wellbore trajectory, and then meshing is performed. At the same time, the boundary conditions of the finite element model are determined based on the on-site casing detection parameters. Considering the temperature, bending load, hydrostatic column pressure, formation pressure, and axial tension of the oil well casing, the relevant load parameters are input into the finite element model. Among them, the bending load F borne by the casing is calculated based on the wellbore trajectory. The calculation formula is:

[0055] I=π(D 4 -d 4 ) / 64

[0056] F=2EIθ / L 2

[0057] Where, I: moment of inertia of the casing end face, m 4 ; L: sleeve length, m; D: sleeve outer diameter, m; d: sleeve inner diameter, m; F: bending load applied to the end face, N; E: elastic modulus of sleeve material, Pa; θ: end face rotation angle, rad;

[0058] The steps for analyzing and solving the model and calculating the critical failure wall thickness and corrosion allowance of the casing are as follows:

[0059] First, the original casing wall thickness (D0) was substituted into the simulation, and the stress distribution contours of the casing under a certain load condition and the local maximum stress (δ0) of the original casing were obtained. During the simulation, the stress distribution contours of the casing were calculated for four typical operating conditions based on the wellbore structure and the stress conditions of each casing section, and the local maximum stresses of the casing were obtained for each of the four conditions. These four operating conditions cover all the most extreme downhole conditions: 1) the maximum internal and external pressure differential of the casing is equal to the internal pressure (external pressure is zero) and the cementing quality is good (the casing outer wall cannot expand freely in the simulation); 2) the maximum internal and external pressure differential of the casing is equal to the internal pressure (external pressure is zero) and the cementing quality is poor (the casing outer wall can expand freely in the simulation); 3) the maximum internal and external pressure differential of the casing is equal to the external pressure (internal pressure is zero) and the cementing quality is good; and 4) the maximum internal and external pressure differential of the casing is equal to the external pressure (internal pressure is zero) and the cementing quality is poor. According to the simulation results, the most demanding working condition (i.e., the working condition corresponding to the maximum local stress with the largest value) and the least demanding working condition (i.e., the working condition corresponding to the minimum maximum local stress) among the four working conditions are selected to perform iterative calculations on the critical failure wall thickness of the casing.

[0060] The critical failure wall thickness of the casing that causes collapse failure can be obtained through iterative calculation. The calculation formula for the casing wall thickness calculated by the nth iteration (n≥1) is D n =λD n-1 ·δ n-1 / δ MAX , where D n-1 and δ n-1 are the casing wall thickness and the maximum stress calculated at the n-1th iteration, respectively, where δ MAX is the smaller value between the yield strength and tensile strength of the casing material in the casing service temperature environment, and λ is the safety factor, which is 1.15 according to the SYT5724-2008 standard. n When the simulation calculation obtains the corresponding local maximum equivalent stress of the casing, it is δ n ;

[0061] When |δ n -δ MAX When / λ|≤5MPa, the iteration stops. At this time, D n It is the critical failure wall thickness of the casing;

[0062] The difference between the original wall thickness and the critical failure wall thickness is the casing wall corrosion allowance (allowable corrosion depth, D0-D n), based on the calculation results under the most demanding and least demanding working conditions, the minimum corrosion allowance and maximum corrosion allowance of the casing wall thickness are obtained respectively.

[0063] The present invention uses a method that combines experiments with mathematical modeling to establish the relationship between the casing corrosion rate and service time, as well as the relationship between the corrosion depth and service time, namely the dynamic corrosion rate evolution equation; a downhole casing bending stress model is established, and finite element model simulation technology is used to combine the coupled calculation of the dynamic development of corrosion and the downhole stress conditions of the casing to more scientifically and accurately predict the remaining service life of the casing, thereby reducing the safety and environmental risks caused by casing failure.

[0064] The beneficial effects of the present invention include:

[0065] 1) Existing methods for predicting the remaining life of casing only consider a single corrosive environment and fail to account for variations in the casing's service environment over time. Specifically, the casing corrosion rate varies with the corrosive environment, resulting in a certain degree of deviation in the predicted remaining life. This new method integrates the continuous equation "corrosion rate - service time" to derive the relationship "corrosion depth - service time."

[0066] 2) At the same time, the present invention takes into account the influence of the wellbore trajectory on the downhole stress of the casing, establishes a more reasonable curved casing model, and also considers that different pipe sections face different corrosion environments and stress environments. Therefore, different service lives are predicted for different pipelines, and the prediction results are more accurate and the prediction method is more scientific.

[0067] 3) The present invention considers a variety of extreme working conditions for simulation calculations and provides a time interval for the remaining life, which is more in line with the actual situation of complex and changeable working conditions faced by oil well casing during service.

[0068] The prediction method of the present invention can calculate the expected service life (i.e., remaining life) of the casing during the oil well design stage, the initial stage of production, and different service stages. When the trend of the corrosion environment changes or the downhole stress conditions change, the remaining life of the casing can be quickly predicted in a timely manner based on the latest situation. Therefore, it can provide a basis and guidance for the selection of oil well casing materials and the adoption of targeted anti-corrosion technical measures for oil layer casing in different oil well production stages. BRIEF DESCRIPTION OF THE DRAWINGS

[0069] Figure 1 The present invention is a flow chart of a method for predicting the remaining life of oil well casing in a changing corrosive environment downhole.

[0070] Figure 2 The figure shows the change of water content of an oil well with service time under different development plans in the embodiment.

[0071] Figure 3 Graph showing the relationship between the annual corrosion rate of the casing and the service time of the casing under different development plans for a certain oil well in the embodiment.

[0072] Figure 4 1 is a graph showing the relationship between the theoretical corrosion depth of the casing and the service time of the casing under different development plans for a certain oil well in the embodiment.

[0073] Figure 5 2 is a schematic diagram of a sleeve model in an embodiment (the left diagram is a side view, and the right diagram is a circular cross-sectional view).

[0074] Figure 6a-6d The finite element stress simulation calculation results (MPa) of the casing of an oil well with a depth of 0-1800 m in the embodiment are as follows: Figure 6a The corresponding working condition is that the maximum pressure difference is equal to the internal pressure (when the external pressure is 0) and the cementing quality is good; Figure 6b The corresponding working condition is that the maximum pressure difference is equal to the internal pressure (when the external pressure is 0) and the cementing quality is poor; Figure 6c The corresponding working condition is that the maximum pressure difference is equal to the external pressure (when the internal pressure is 0) and the cementing quality is good; Figure 6d The corresponding working condition is that the maximum pressure difference is equal to the external pressure (when the internal pressure is 0) and the cementing quality is poor.

[0075] Figure 7a-7d The finite element stress simulation calculation results (MPa) of the casing of an oil well with a depth of 1800m-2360m in the embodiment are as follows: Figure 7a The corresponding working condition is that the maximum pressure difference is equal to the internal pressure (when the external pressure is 0) and the cementing quality is good; Figure 7b The corresponding working condition is that the maximum pressure difference is equal to the internal pressure (when the external pressure is 0) and the cementing quality is poor; Figure 7c The corresponding working condition is that the maximum pressure difference is equal to the external pressure (when the internal pressure is 0) and the cementing quality is good; Figure 7d The corresponding working condition is that the maximum pressure difference is equal to the external pressure (when the internal pressure is 0) and the cementing quality is poor.

[0076] Figure 8a-8d The finite element stress simulation calculation results (MPa) of the casing of an oil well with a depth of 2360m-3632m in the embodiment are as follows: Figure 8a The corresponding working condition is that the maximum pressure difference is equal to the internal pressure (when the external pressure is 0) and the cementing quality is good; Figure 8b The corresponding working condition is that the maximum pressure difference is equal to the internal pressure (when the external pressure is 0) and the cementing quality is poor; Figure 8c The corresponding working condition is that the maximum pressure difference is equal to the external pressure (when the internal pressure is 0) and the cementing quality is good; Figure 8d The corresponding working condition is that the maximum pressure difference is equal to the external pressure (when the internal pressure is 0) and the cementing quality is poor.

[0077] Figure 9a-9dThe finite element stress simulation calculation results (MPa) of the casing of a certain oil well 3632m-3758.5m in the embodiment are as follows: Figure 9a The corresponding working condition is that the maximum pressure difference is equal to the internal pressure (when the external pressure is 0) and the cementing quality is good; Figure 9b The corresponding working condition is that the maximum pressure difference is equal to the internal pressure (when the external pressure is 0) and the cementing quality is poor; Figure 9c The corresponding working condition is that the maximum pressure difference is equal to the external pressure (when the internal pressure is 0) and the cementing quality is good; Figure 9d The corresponding working condition is that the maximum pressure difference is equal to the external pressure (when the internal pressure is 0) and the cementing quality is poor.

[0078] Figure 10a-Figure 10d The finite element stress simulation calculation results of each pipe section calculation point when the critical failure wall thickness of a certain oil well casing in the embodiment is taken to be the maximum value: Figure 10a The critical failure wall thickness of the 0-1800m pipe section is 6.38mm; Figure 10b The critical failure wall thickness of the pipe section from 1800m to 2360m is 8.30mm; Figure 10c The critical failure wall thickness of the pipe section from 2360m to 3632m is 8.50mm; Figure 10d The critical failure wall thickness of the pipe section from 3632m to 3758.5m is 9.05mm.

[0079] Figure 11a-Figure 11d The finite element stress simulation calculation results of each pipe section calculation point when the critical failure wall thickness of a certain oil well casing in the embodiment is taken as the minimum value: Figure 11a The critical failure wall thickness of the 0-1800m pipe section is 6.05mm; Figure 11b The critical failure wall thickness of the pipe section from 1800m to 2360m is 4.90mm; Figure 11c The critical failure wall thickness of the pipe section from 2360m to 3632m is 6.50mm; Figure 11d The critical failure wall thickness of the pipe section from 3632m to 3758.5m is 4.22mm. DETAILED DESCRIPTION

[0080] In order to explain the present invention more clearly, the present invention is further described below in conjunction with preferred embodiments. Those skilled in the art should understand that the following specific description is illustrative rather than restrictive and should not be used to limit the scope of protection of the present invention.

[0081] The present invention predicts the remaining life of oil well casing under downhole corrosion changing environment according to Figure 1 The present invention is further illustrated and described below with reference to the accompanying drawings, using the calculation of the remaining life of a casing made of L80-1 material in an oil field in the Middle East as an example.

[0082] (1) Corrosion test conditions:

[0083] Based on the downhole corrosion environment of the oil field, under the experimental conditions of temperature of 90°C, 1000ppm H2S, 0.5MPa CO2, 10% chloride ion, and 90% water content, the casing steel L80-1 was subjected to corrosion weight loss tests for 7, 14, 21, and 28 days to obtain the corresponding corrosion rates (Table 1). The calculation formula is as follows:

[0084] CR=87600·Δm / (tρs)

[0085] Where CR is the corrosion rate, mm / year (mm / a); Δm is the mass change before and after the experiment, g; t is the time, h; ρ is the material density, g / cm 3 ; s is the corrosion surface area, cm 2 .

[0086] Table 1 Corrosion rate of L80-1 steel after different immersion times

[0087]

[0088] Then, using the experimental values ​​of the corrosion rate above, regression analysis was performed to obtain the annual corrosion rate regression curve equation of L80-1 in an environment of 90°C, 0.5MPa CO2, 1000ppm H2S, and 90% water content:

[0089] CR year =2.1779t -0.319

[0090] Where t is time (days), and the conversion period is usually one year.

[0091] The short-term corrosion rate (1.429 mm / a) obtained from the corrosion weight loss test of L80-1 after 3 days of immersion in the late service environment of 95°C, 10% chloride ion, 0.5 MPa CO2, 1000 ppm H2S, and 90% water content is used as the calculation basis. The short-term corrosion rate in other similar environments is converted into an annual corrosion rate. The annual corrosion rate calculation formula is as follows:

[0092] CR year,x,y =CR x,y / 1.429×2.1779t -0.319 , t = 365 days

[0093] (2) According to different development plans on site, we can know the changing trend of water content in oil wells under different plans and during the production cycle, such as Figure 2 .

[0094] according to Figure 2The moisture content and corrosion environment data at 1 (the first year of service), 4, 7, ..., 1+3n years are used. A corrosion weight loss experiment with a duration of 3 days is carried out in the laboratory to calculate the short-term corrosion rate in the corrosion environment corresponding to the service time of 1, 4, 7, ..., 1+3n years. The short-term corrosion rate is substituted into the annual corrosion rate calculation formula in step (1) to obtain the annual corrosion rate. The curves of annual corrosion rate and service time corresponding to different development plans can be obtained, such as Figure 3 , the fitted relationship is as follows:

[0095] Development Plan 1:

[0096]

[0097] Development Plan 2:

[0098]

[0099] Development Plan 3:

[0100]

[0101] (3) According to the service time and annual corrosion rate relationship curve ( Figure 3 ) is integrated to obtain the curve diagram of the corrosion depth and service time of the casing after different service times, as shown in Figure 4 , and the relationship is as follows:

[0102] Development Plan 1:

[0103]

[0104] Development Plan 2:

[0105]

[0106] Development Plan 3:

[0107]

[0108] Where t is the casing service time.

[0109] (4) Establish a finite element model of the casing and perform simulation calculations.

[0110] Based on the casing's wellbore structure, wellbore trajectory, actual stress conditions (casing deadweight tension, formation pressure, internal medium pressure, circumferential constraint force, and bending load on the casing), and reservoir temperature, corresponding external loads were applied to the oil well casing on a finite element model to analyze and solve the critical failure wall thickness when the casing undergoes uniform corrosion failure.

[0111] The casing of an oil well was selected for analysis. Based on the wellbore structure, wellbore trajectory, downhole temperature, and pressure, it was divided into four sections for calculation. Section A has the highest casing deadweight tension; Section B is a straight section with high internal and external pressures; Section C has a high wellbore trajectory inclination (high casing curvature); and Section D is located below the packer, where the fluid inside the casing is an oil-water mixture. Based on field data, the loads for different casing sections can be determined, as shown in Table 2:

[0112] Table 2 Loads of various sections of casing in an oil well

[0113]

[0114] Note: Curvature: 2360-3632m: 3.66° / 30m; 3632-3758.5m: 0.645° / 30m.

[0115] At the same time, the bending load needs to be applied to the curved section of the casing. The bending load is first calculated based on the casing curvature and then evenly distributed to each node of the casing section in the finite element model. From the mechanics of materials, it is known that the formula for calculating the bending load of the casing curvature is as follows:

[0116] I=π(D 4 -d 4 ) / 64

[0117] F=2EIθ / L 2

[0118] Where, F: bending load applied to the end face, N; E: elastic modulus of the sleeve material, Pa; I: moment of inertia of the sleeve end face, m 4 ;θ: end face rotation angle, rad; L: sleeve length, m; D: sleeve outer diameter, m; d: sleeve inner diameter, m.

[0119] The established three-dimensional model of the casing is shown in Figure 5 The length L of each casing section is 12m, the inner diameter d of the casing is 6.180in, the outer diameter D of the casing is 7in, the casing material is L80-1, and the original wall thickness is 0.408in (10.363mm).

[0120] The steps for iterative calculation to obtain the critical failure wall thickness and corrosion allowance are as follows:

[0121] 1) The wall thickness of the L80-1 casing in the initial finite element model is set to 10.363 mm (D0), and four typical working conditions are set. These four working conditions cover all the most extreme cases, namely: the maximum internal and external pressure difference of the casing is equal to the internal pressure (the external pressure is 0) and the cementing quality is good (the outer wall of the casing cannot expand freely in the simulation calculation); the maximum internal and external pressure difference of the casing is equal to the internal pressure (the external pressure is 0) and the cementing quality is poor (the outer wall of the casing can expand freely in the simulation calculation); the maximum internal and external pressure difference of the casing is equal to the external pressure (the internal pressure is 0) and the cementing quality is good; the maximum internal and external pressure difference of the casing is equal to the external pressure (the internal pressure is 0) and the cementing quality is poor.

[0122] 2) According to the comprehensive stress conditions of the wellbore structure and each section of the casing, the stress distribution cloud diagram and the maximum local stress (δ0) of each section of the casing under four different well conditions were calculated through finite element simulation when the wall thickness was 10.363 mm (D0). Figure 6a-6d The finite element stress simulation results of the casing in the 0-1800m section are shown. The maximum local stress values ​​of the casing under the four working conditions are 312.735, 350.067, 304.531, and 326.806 MPa respectively. Figure 7a-7d The finite element stress simulation results of the casing in the 1800m-2360m section are shown. The maximum local stress values ​​of the casing under the four working conditions are 262.966, 426.235, 259.124, and 304.457 MPa respectively. Figure 8a-8d The finite element stress simulation results of the casing in the 2360m-3632m section are shown. The maximum local stress values ​​of the casing under the four working conditions are 363.924, 443.165, 361.216, and 411.024 MPa respectively. Figure 9a-9d These are the finite element stress simulation calculation results of the casing in the 3632m-3758.5m section. The maximum local stress values ​​of the casing under the four working conditions are 278.46, 217.573, 290.302, and 404.94MPa, respectively.

[0123] 3) The larger the value of the maximum local stress of the casing, the more severe the working condition of the casing. Therefore, the most severe working condition among the four working conditions is selected (the working condition when the maximum local stress (δ0) is obtained), and different wall thickness parameters are brought into its finite element model for iterative calculation to obtain the value of the critical failure wall thickness. The finite element model is repeatedly run for simulation calculation. When |δ n -δ MAX When / λ|≤5MPa, stop the iteration. Figure 10a-Figure 10d The stress distribution cloud diagram of the finite element iterative calculation results of each pipe segment. At this time, the wall thickness parameter D in the model nThis is the maximum critical failure wall thickness of the casing; after obtaining the maximum critical failure wall thickness of the casing, the minimum corrosion allowance of the casing wall thickness can be calculated by subtracting the maximum critical failure wall thickness from the original wall thickness. The smaller the maximum local stress of the original wall thickness casing, the less demanding the working condition of the casing. Therefore, the least demanding working condition among the four working conditions is selected (the working condition when the minimum maximum local stress (δ0) is obtained), and different wall thickness parameters are brought into its finite element model for iterative calculation to obtain the value of the critical failure wall thickness. Repeatedly run the finite element model for simulation calculation. When |δ n -δ MAX When / λ|≤5MPa, stop the iteration. Figure 11a-Figure 11d The stress distribution cloud diagram of the finite element iterative calculation results of each pipe segment. At this time, the wall thickness parameter D in the model n This is the minimum critical failure wall thickness of the casing. After obtaining the minimum critical failure wall thickness of the casing, the maximum corrosion allowance of the casing wall thickness can be calculated by subtracting the minimum critical failure wall thickness from the original wall thickness.

[0124] Table 3 lists the material mechanical parameters, structural parameters, and stress magnitudes of the L80-1 casing, as well as the strength reserve ranges of each section of the casing when the original wall thickness is 10.363 mm (D0) obtained through finite element model simulation. The ranges are: 1.542-1.773 (0-1800 m), 1.267-2.084 (1800 m-2300 m), 1.218-1.495 (2360 m-3632 m), and 1.309-2.482 (3632 m-3758.5 ​​m). At the same time, Table 3 shows the maximum critical failure wall thickness (mm) of the casing of each section obtained by iterative calculation under the most demanding and least demanding working conditions: 6.38 (0-1800m), 8.30 (1800m-2300m), 8.50 (2360m-3632m), 9.05 (3632m-3758.5m); the minimum critical failure wall thickness (mm): 6.05 (0-1800m), 4.90 (1800m-2300m), 6.50 (2360m-3632m), 4.22 ( 3632m-3758.5m); Minimum corrosion allowance (mm): 3.983 (0-1800m), 2.063 (1800m-2300m), 1.863 (2360m-3632m), 1.313 (3632m-3758.5m); Maximum corrosion allowance (mm): 4.313 (0-1800m), 5.463 (1800m-2300m), 3.863 (2360m-3632m), 6.143 (3632m-3758.5m).

[0125] Table 3 Strength reserve and corrosion allowance of an oil well casing

[0126]

[0127] (5) Calculate the remaining life of the oil well casing.

[0128] The corrosive environment for the section above the packer is the annular protective fluid (corrosion coupon testing indicates a uniform corrosion rate of 0.0289 mm / a for L80-1 under this fixed environment). The remaining life of this section of casing is calculated by dividing the casing's corrosion allowance by the fixed corrosion rate. For the casing below the packer, where the corrosive medium is an oil-water mixture, the remaining life of the casing is calculated by substituting the corrosion allowance for the casing wall thickness, i.e., the allowable corrosion depth, into the equation between corrosion depth and service time to obtain the service time, which is the remaining life of the casing section. For the casing above the packer, if the corrosive medium (oil-water mixture) enters the annulus, the remaining life of the casing is calculated by substituting the corrosion allowance for the casing wall thickness into the equation between corrosion depth and service time to obtain the service time, which is the remaining life of the casing section.

[0129] Table 4 provides detailed numerical results for the remaining life assessment of the casing section above the packer under different development scenarios, while Table 5 provides detailed numerical results for the remaining life assessment of the casing section below the packer under different development scenarios. The actual remaining life of the casing lies between the minimum and maximum remaining life. When the corrosive environment for the casing above the packer is an annular protection fluid, the remaining life (in years) of the casing for each section is: 137.82-149.24 (0-1800 m), 71.38-189.03 (1800 m-2360 m), and 64.46-133.67 (2360 m-3632 m). If the corrosive medium enters the annular protection fluid of the casing above the packer, the remaining service life (years) of the casing in each section under development plan 1 are: 44.6-46.3 (0-1800m), 33.9-52.2 (1800m-2360m), 32.7-44.0 (2360m-3632m); the remaining service life (years) of the casing in each section under development plan 2 are: 49.8-51.6 (0- The remaining life (years) of the casing below the packer (3632m-3758.5m) under different development plans range from 29.0-55.6 (Development Plan 1), 32.8-61.2 (Development Plan 2), and 33.5-65.6 (Development Plan 3). The results show that the remaining life of each pipe section is a time interval. The remaining life in years can be predicted based on the on-site corrosion environment and stress conditions. The prediction results reflect the actual impact of changes in casing stress and corrosion environment on casing life, thereby improving the scientificity and applicability of casing remaining life prediction.

[0130] Table 4 Remaining life assessment results of the casing section above the packer under different development plans

[0131]

[0132] Table 5 Remaining life assessment results of the casing section below the packer under different development plans

[0133]

[0134]

[0135] Obviously, the above embodiments of the present invention are merely examples for clearly illustrating the present invention, and are not limitations on the implementation methods of the present invention. For ordinary technicians in the relevant field, other different forms of changes or modifications can be made based on the above description. It is impossible to list all the implementation methods here. All obvious changes or modifications derived from the technical solution of the present invention are still within the scope of protection of the present invention.

Claims

1. A method for predicting the remaining life of oil well casing in a changing corrosive environment, characterized in that: The method comprises the following steps: According to the downhole corrosion environment of oil wells, corrosion weight loss experiments of casing steel with different experimental durations were carried out to obtain the corrosion rates of different experimental durations. Using the relationship between the corrosion rate and the experimental duration for different experimental durations, a regression curve equation of the annual corrosion rate under the corrosive environment is obtained by fitting; Based on the specific corrosion environment corresponding to the different service times of oil wells, short-term corrosion weight loss tests were conducted on casing steel to obtain the short-term corrosion rate of casing steel at different service times. This series of short-term corrosion rate data was regressed with the service time data to obtain the relationship between short-term corrosion rate and service time. Combined with the annual corrosion rate regression curve equation, the relationship between annual corrosion rate and service time was converted. Integrating the relationship between the annual corrosion rate and the service time with respect to the service time to obtain a relationship between the corrosion depth of the casing and the service time; A finite element model of downhole casing was established. Based on the actual stress conditions of the casing, constraints and loads were set on the finite element model to analyze and solve the critical failure wall thickness for uniform corrosion of the casing. The corresponding corrosion margin was calculated based on the critical failure wall thickness. Substituting the corrosion allowance as the corrosion depth into the relationship between the corrosion depth and the service time, and calculating the corresponding service time, which is the remaining life of the casing; The regression curve equation of the annual corrosion rate is: CR year =f1(t1) Among them, t1 is time, days; when time t1 is 365 days, CR year is the annual corrosion rate, mm / year; Substituting the regression curve equation of the annual corrosion rate into the relationship between short-term corrosion rate and service time to obtain the relationship between the annual corrosion rate and service time; The annual corrosion rate of casing material in any corrosive environment of oil well is expressed as: CR year,x,y =(CR x,y / CR0)×f1(t1) Among them, CR0 is the short-term corrosion rate of casing material measured by corrosion coupon test based on a certain corrosive environment of oil well, CR x，y The short-term corrosion rate of the casing material is measured by the corrosion coupon test in any other corrosive environment of the oil well. year,x,y CR x,y The corresponding annual corrosion rate, t1 is 365 days; The relationship between short-term corrosion rate and service time is: CR x,y =f2(t2) The relationship between the annual corrosion rate and service time is: <h2 style=";text-align:left;direction:ltr">CR<h2 style=";text-align:left;direction:ltr"> year,x,y <h2 style=";text-align:left;direction:ltr"> =(f2(t2) / CR0)×f1(t1) Among them, t1 is 365 days, t2 is the casing service time, years; By integrating the relationship between the annual corrosion rate and the service time with the service time, the relationship between the corrosion depth of the casing and the service time can be obtained:

2. The method according to claim 1, characterized in that The corrosion weight loss experiment is carried out in a high-temperature autoclave.

3. The method according to claim 1, characterized in that The calculation formula for the corrosion rate of different experimental durations is as follows: CR=87600·Δm / (tρs) Where CR is the corrosion rate, mm / year; Δm is the mass change of casing steel before and after the experiment, g; t is the experimental time, h; ρ is the density of casing steel, g / cm 3 ; s is the corrosion surface area, cm 2 .

4. The method according to claim 1, wherein The different service times include the 1st, 4th, 7th, ..., 1+3n years, where n is an integer greater than 2.

5. The method according to claim 1, wherein The experimental duration of the short-term corrosion weight loss experiment is 3 days.

6. The method according to claim 1, characterized in that For the maximum and minimum stress conditions of the downhole casing, the maximum critical failure wall thickness and the minimum critical failure wall thickness are calculated respectively, and the corresponding minimum corrosion allowance and maximum corrosion allowance are calculated corresponding to the maximum critical failure wall thickness and the minimum critical failure wall thickness.

7. The method according to claim 6, characterized in that Two remaining lives are calculated respectively according to the minimum corrosion margin and the maximum corrosion margin, and the remaining life of the casing is within the two remaining life ranges according to changes in actual environmental conditions.

8. The method according to any one of claims 1, 6-7, characterized in that The calculation formula of the corrosion allowance is as follows: D y =D0–D n Where D0 is the original casing wall thickness, D n is the critical failure wall thickness of the casing.

9. The method according to claim 1, characterized in that The steps to establish a finite element model of downhole casing and calculate the corrosion allowance include: Parameters such as wellbore structure, wellbore trajectory, casing size, casing temperature at different depths, hydrostatic column pressure, formation pressure, and cementing quality are obtained based on on-site well design plans, cementing and completion data, and logging data. A three-dimensional solid model of the casing is established based on the casing size and wellbore trajectory, and then meshing is performed. At the same time, the boundary conditions of the finite element model are determined based on the on-site casing detection parameters. Considering the temperature, bending load, hydrostatic column pressure, formation pressure, and axial tension of the oil well casing, the relevant load parameters are input into the finite element model. The bending load F borne by the casing is calculated based on the wellbore trajectory. The calculation formula is: I⼝π(D 4 -d 4 ) / 64 F=2EIθ / L 2 Where, I is the moment of inertia of the casing end face, m 4 ; L is the length of the casing, m; D is the outer diameter of the casing, m; d is the inner diameter of the casing, m; F is the bending load applied to the end face, N; E is the elastic modulus of the casing material, Pa; θ is the end face rotation angle, rad; Analyze and solve the model to calculate the critical failure wall thickness and corrosion allowance: First, the original casing wall thickness D0 is substituted, and a simulation calculation is performed to obtain the casing stress distribution cloud map and the local maximum stress of the original wall thickness casing under a certain load condition. During the simulation calculation, the casing stress distribution cloud map under four typical working conditions is calculated based on the wellbore structure and the stress conditions of each section of the casing, and the local maximum stress of the casing under the four working conditions is obtained respectively. The four working conditions include: 1) the casing is subjected to a maximum internal and external pressure difference equal to the internal pressure and the cementing quality is good; 2) the casing is subjected to a maximum internal and external pressure difference equal to the internal pressure and the cementing quality is poor; 3) the casing is subjected to a maximum internal and external pressure difference equal to the external pressure and the cementing quality is good; 4) the casing is subjected to a maximum internal and external pressure difference equal to the external pressure and the cementing quality is poor. According to the simulation results, the most demanding and least demanding working conditions among the four working conditions are selected to perform iterative calculations on the critical failure wall thickness of the casing. The critical failure wall thickness of the casing that causes collapse failure is obtained through iterative calculation. The calculation formula of the casing wall thickness calculated in the nth iteration is D n =λD n-1 ·δ n-1 / δ MAX , n≥1, where D n-1 and δ n-1 are the casing wall thickness and the maximum stress calculated at the n-1th iteration, respectively, where δ MAX is the smaller value between the yield strength and tensile strength of the casing material in the casing service temperature environment, λ is the safety factor, which is 1.15; when the casing wall thickness is D n When the simulation calculation obtains the corresponding local maximum equivalent stress of the casing, it is δ n ; When |δ n -δ MAX When / λ|≤5MPa, the iteration stops. At this time, D n It is the critical failure wall thickness of the casing; The difference between the original wall thickness and the critical failure wall thickness is the casing wall corrosion allowance. Based on the calculation results under the most demanding and least demanding working conditions, the minimum corrosion allowance and maximum corrosion allowance of the casing wall thickness are obtained respectively.

Images