Material selection method for completion pipe string of gas well containing H2S and CO2

Abstract

The invention discloses a material selection method for a completion pipe string of a gas well containing H2S and CO2. The material selection method comprises the following steps that a completion pipe string pipe suitable for a research block is primarily selected; selecting one of the primarily selected pipes, performing post-corrosion strength damage characteristic evaluation and pipe column material stress analysis on the basis of the ultimate corrosion conditions of the research block, and judging the pipe which simultaneously meets the evaluation result and the stress analysis result as a completion pipe column pipe; according to the method, on the basis of predicting the corrosion rate of an H2S / CO2-containing complex working condition full-well-section oil pipe, the strength damage after corrosion is further evaluated, the limit stress is analyzed, selection of H2S / CO2-containing complex reservoir oil pipe column materials is achieved, and technical support is provided for oil pipe column optimization design and wellbore life safety evaluation.

Description

Technical Field

[0001] The present disclosure relates to the technical field of natural gas extraction, and in particular to a method for selecting materials for completion strings of H2S / CO2-containing gas wells. Background Art

[0002] With the deepening of exploration and development, more and more oil and gas fields containing various corrosive media such as H2S and CO2 are put into production, and these corrosive media have a serious adverse impact on the safe exploitation of oil and gas fields.

[0003] For tubing material selection under H2S / CO2 dual corrosion conditions, the current method is to select tubing materials that meet the requirements based on the tubing corrosion rate in the complex H2S / CO2 coupled environment. For example, CN 115950809 A discloses a method for determining a corrosion limit safety surface for downhole corrosion factors and a method for selecting downhole tubing materials using a three-dimensional material selection chart. Based on the corrosion rate control index of the well area to be selected, curve fitting, and surface fitting methods are used to create a three-dimensional material selection chart that can intuitively reflect the corrosion safety zone and danger zone of the material. The tubing material that meets the requirements is selected based on the position of the corrosion factor value relative to the safety zone and danger zone of various materials on the three-dimensional material selection chart. CN 104251812 A discloses a system and method for optimizing and evaluating wellbore tubing materials for highly sour gas fields. This system provides a wellbore tubing material optimization level evaluation system that includes a corrosion rate prediction model and a stress corrosion cracking boundary model.

[0004] Because current methods do not evaluate the mechanical safety factor of tubing after corrosion, they cannot guarantee that the selected material will meet the applicability of various harsh working conditions in the block. In other words, current methods cannot provide a more accurate method for selecting tubing materials for complex H2S / CO2 coupling environments, and therefore cannot provide effective guidance for tubing material selection in complex H2S / CO2 coupling environments. Summary of the Invention

[0005] In view of this, the present disclosure provides a method for selecting completion string materials for gas wells containing H2S and CO2, which solves the problem that current methods cannot more accurately select completion string materials for the complex coupled H2S / CO2 environment.

[0006] To achieve the above-mentioned purpose of the invention, the method for selecting materials for completion strings of H2S and CO2-containing gas wells comprises:

[0007] Preliminary selection of completion string materials suitable for the research area;

[0008] Select one of the preselected pipe materials and evaluate the strength damage characteristics after corrosion based on the extreme corrosion conditions of the research area;

[0009] If the strength damage characteristic evaluation result is unqualified, other pipes are selected from the preselected pipes and the post-corrosion strength damage characteristic evaluation is repeated; if qualified, the pipe string material stress analysis is continued;

[0010] If the stress analysis result of the tubular string material is unqualified, other tubular materials are selected from the preliminarily selected tubular materials and the post-corrosion strength damage characteristic evaluation and stress analysis are re-performed until the stress analysis result is qualified, thereby completing the selection of completion tubular string materials for the target gas well in the study block.

[0011] In the present disclosure and possible embodiments, the method for determining the extreme corrosion conditions of the study block includes:

[0012] Establishing a corrosion rate prediction model for the study area;

[0013] The extreme corrosion conditions are determined using a corrosion rate prediction model for the study area.

[0014] In the present disclosure and possible embodiments, the method of establishing the corrosion rate prediction model for the study area includes:

[0015] Orthogonal experimental design and experimental parameter combination were used to conduct coupon weight loss corrosion experiments to determine the corrosion rates under different working conditions. A multiple regression algorithm was used to determine the constant term in the corrosion rate model, and a corrosion rate prediction model for the study area was obtained; the corrosion rate model is:

[0016]

[0017] Where: Vcorr is the corrosion rate, mm / a; is the partial pressure of hydrogen sulfide, MPa; is the partial pressure of carbon dioxide, MPa; T is the temperature, °C; A, B, D, E, and C are dimensionless calculation parameters.

[0018] In the present disclosure and possible embodiments, the method for determining the extreme corrosion condition using the corrosion rate prediction model of the study block includes:

[0019] According to the corrosion rate prediction model of the study block, the maximum corrosion rate within the parameter range of the study block is calculated. Combined with the data results of the orthogonal experiment, the operating condition parameters with the highest corrosion rate of the study block are determined. The operating condition parameters are the extreme corrosion conditions.

[0020] In the present disclosure and possible embodiments, the method for evaluating strength damage characteristics after corrosion includes:

[0021] Using constant load stress corrosion experiments, the post-corrosion strength damage of the pipe to be tested is quantitatively tested under different temperatures, pressures, H2S content and CO2 content, as well as under 80% yield stress conditions. Surface damage analysis of the specimens is also performed to evaluate the stress corrosion cracking risk of the pipe to be tested under the extreme corrosion conditions.

[0022] In the present disclosure and possible embodiments, the method for analyzing the stress of a pipe string material includes:

[0023] After the constant load stress corrosion test, a tensile test is performed on the pipe string to obtain data on tensile strength, yield strength, elastic modulus and fracture toughness;

[0024] The tensile strength, yield strength, elastic modulus and fracture toughness data are used to calculate the triaxial stress of the tubular string to be tested based on the fracturing conditions to determine the residual safety factor, and to determine whether the residual safety factor meets the set safety factor.

[0025] In the present disclosure and possible embodiments, the calculation formula of the triaxial stress is as follows:

[0026]

[0027]

[0028]

[0029]

[0030] Where: r i is the inner radius of the pipe, mm; r o is the outer radius of the pipe string, mm; P i is the pressure in the column, MPa; P o is the pressure outside the string, MPa; σ r , σ o are the radial stress and circumferential stress under internal and external pressure, MPa; σ z is the axial stress, MPa; σ is the triaxial stress of the string, MPa; Q is the tension at the calculated section of the string, kN.

[0031] In the present disclosure and possible embodiments, the method for initially selecting completion string tubular materials suitable for the study block includes:

[0032] Collect temperature, pressure and gas composition parameter data of each gas well in the study block;

[0033] Based on the parameter data, through the coupon weight loss corrosion test and SEM analysis, the pipes with a corrosion rate of ≤0.125mm / a were screened and the pre-selected pipes were determined.

[0034] In the present disclosure and possible embodiments, the experimental conditions of the hanging piece weight loss corrosion experiment are selected from the temperature and pressure data at the wellhead, well and bottom of the well, and the H2S and CO2 contents are selected from the highest values ​​of the target layer in the study block.

[0035] In the present disclosure and possible embodiments, the coupon weight loss corrosion experiment uses the following formula to calculate the corrosion rate:

[0036]

[0037] Where: CR is the corrosion rate, in mm / a; W1 is the weight of the sample before the experiment, in g; W2 is the weight of the sample after the experiment, in g; A is the surface area of ​​the sample, in mm 2 ; T is the experimental time, the unit is d; D is the material density, the unit is g / cm 2 .

[0038] The present disclosure has the following beneficial effects:

[0039] The disclosed method for selecting completion string materials for CO2 and H2S gas wells first preliminarily screens string materials under different CO2 and H2S partial pressures, and then further conducts corrosion evaluation experiments on the screened pipes based on the characteristics of the block reservoir; then, based on the above corrosion test results, linear regression is used to determine the constant term in the local corrosion rate model, a corrosion model is established, the operating condition parameters with the highest corrosion rate in the block are determined, and the stress corrosion cracking risk of the pipe is evaluated; on this basis, stress analysis is performed on the operating conditions such as the running, sealing, and fracturing of the string, and finally, the completion string material suitable for the H2S and CO2 gas wells in the block is selected; that is, the disclosed method, based on the prediction of the corrosion rate of the entire well section of the oil pipe under complex working conditions containing H2S / CO2, further evaluates the strength damage after corrosion, and analyzes the ultimate stress, realizes the selection of oil pipe string materials for complex reservoirs containing H2S / CO2, and provides technical support for the optimization design of the oil pipe string and the safety assessment of the wellbore life. BRIEF DESCRIPTION OF THE DRAWINGS

[0040] The above and other objects, features and advantages of the present disclosure will become more apparent through the following description of the embodiments of the present disclosure with reference to the accompanying drawings, in which:

[0041] Figure 1 This is a flow chart of a method for selecting materials for a completion string for a gas well containing H2S and CO2 according to an embodiment of the present disclosure;

[0042] Figure 2 is the maximum triaxial stress of the tubing string under the fracturing conditions of the application example of the present disclosure;

[0043] Figure 3 is the residual safety factor of the corroded tubing string in the application example of the present disclosure. DETAILED DESCRIPTION

[0044] The present disclosure is described below based on embodiments, but it is worth noting that the present disclosure is not limited to these embodiments. In the detailed description of the present disclosure below, some specific details are described in detail. However, for the parts not described in detail, those skilled in the art can also fully understand the present disclosure.

[0045] At the same time, unless the context clearly requires otherwise, words such as "include", "comprising" and the like throughout the specification and claims should be interpreted as inclusive rather than exclusive or exhaustive; that is, as "including but not limited to".

[0046] In order to make the objectives, technical solutions and advantages of the present invention more clearly understood, the present invention is further described in detail below with reference to the accompanying drawings and by listing embodiments and application examples.

[0047] Example

[0048] Figure 1 This is a flow chart of the material selection method for the completion string of a gas well containing H2S and CO2 according to an embodiment of the present disclosure; Figure 1 As shown, the method for selecting materials for completion strings for H2S and CO2-containing gas wells in this embodiment includes the following steps:

[0049] Step S10: Preliminary selection of completion string materials suitable for the study area. The preferred preliminary selection method is as follows:

[0050] (1) Collect temperature, pressure, and gas composition data of the target layer gas wells in the study block. To ensure that the acquired data can represent the characteristics of the entire block, relevant data of all gas wells within the block are selected as much as possible. Detailed parameters include the wellbore pressure (at the wellhead, mid-well, and bottom of the well), wellbore temperature (at the wellhead, mid-well, and bottom of the well), and the content of various components such as CO2 and H2S in the produced natural gas.

[0051] (2) According to conventional techniques in this field, a weight loss corrosion test was conducted using a high-temperature autoclave. The corrosion rates of several high-sulfur-resistant carbon steels and nickel-based alloys were tested based on empirical experiments. The temperature and pressure test conditions were selected from the temperature and pressure data at the wellhead, mid-well, and bottom of the well. The H2S and CO2 contents were taken from the highest values ​​of the target layer in the study block.

[0052] Among them, the coupon weight loss corrosion test method is as follows:

[0053] Weight loss corrosion experiments were conducted in accordance with NACE SP 0775 "Preparation, Installation and Analysis of Experimental Data of Corrosion Coupons in Oilfield Production", GB10124 "Metal Materials Laboratory Uniform Corrosion Full Immersion Test Method" and SY / T 0546 "Technical Specification for Collection and Identification of Corrosion Products". The corrosion rate was calculated using the following formula:

[0054]

[0055] Where:

[0056] CR——corrosion rate, in mm / a;

[0057] W1——weight of sample before experiment, in g;

[0058] W2——weight of sample after the test, in g;

[0059] A——surface area of ​​sample, in mm 2 ;

[0060] T——experimental time, in d;

[0061] D——Material density, in g / cm 2 .

[0062] After the corrosion rate calculation is completed, SEM is used to analyze the morphology and composition of the corrosion products, clarify the corrosion characteristics, observe and screen the samples for 3D microscopic morphology test of pit size, and based on the above experimental results, preliminarily screen the pipes in the moderate corrosion range (i.e., corrosion rate ≤ 0.125 mm / a).

[0063] Step S20: Select one of the pipe materials initially selected in step 1, preferably the one with the lowest cost, and evaluate the corrosion characteristics under typical wellbore environmental conditions (temperature, pressure, and gas content) of the study block to establish a corrosion rate model for the study block. The preferred method for establishing the corrosion rate model in this embodiment is as follows:

[0064] (1) Orthogonal experimental design is used to combine experimental parameters. The orthogonal experimental factors are selected as temperature and pressure (due to the correlation with depth, they can be regarded as one factor), H2S content, and CO2 content. The design of temperature and pressure levels is selected according to the numerical range corresponding to the three depths of wellhead, well, and bottom of the well. In order to ensure the accuracy of the data, the numerical values ​​can also be appropriately encrypted, such as adding 1 group at the wellhead and well, 1 group at the well and bottom of the well, and so on. The denser the added values, the more accurate the simulation. The levels of H2S content and CO2 content are selected according to the average of the maximum parameter range interval corresponding to the block. The orthogonal experimental design with 3 factors and 5 levels is shown in Table 1:

[0065] Table 1 Orthogonal experimental design table

[0066]

[0067] (2) Based on the experimental parameters of the orthogonal experimental design, according to GB / T 19291-2003 General principles of corrosion testing of metals and alloys and GB / T 16545-2015 Removal of corrosion products from corrosion specimens of metals and alloys, a coupon weight loss corrosion experiment was conducted. The specific experimental method was the same as step 1.

[0068] Through the coupon weight loss corrosion test, the corrosion rate variation law under different H2S / CO2 partial pressure conditions was clarified, the corrosion rate under different working conditions was determined, and the multiple regression algorithm was used to determine the constant term in the corrosion rate model. The corrosion rate model of the study area was obtained; the specific corrosion rate model is as follows:

[0069]

[0070] Where: Vcorr is the corrosion rate, mm / a;

[0071] is the partial pressure of hydrogen sulfide, MPa;

[0072] is the partial pressure of carbon dioxide, MPa;

[0073] T temperature, °C;

[0074] A, B, D, E, and C are dimensionless calculation parameters.

[0075] Step S30: Select one of the preselected pipe materials, preferably the pipe with the lowest cost, calculate the extreme corrosion conditions of the study block according to the corrosion rate model of the study block, and evaluate the strength damage characteristics of the lowest cost pipe after corrosion based on the extreme corrosion conditions of the study block. The specific process is as follows:

[0076] (1) The maximum corrosion rate in the entire parameter range of the study block is calculated based on the corrosion rate model of the study block. Combined with the results of the orthogonal experimental data, the operating parameters (pressure, temperature, CO2 content, H2S content) with the highest corrosion rate in the study block are determined as the extreme corrosion conditions of the study block.

[0077] (2) According to the conventional technology in this field, the constant load stress corrosion test is carried out to quantitatively test the strength damage of the pipe under different temperatures, pressures (the selection of data can refer to step 2), H2S content and CO2 content (determined according to the corrosion characteristic evaluation experiment), and 80% σs yield stress conditions, and evaluate the stress corrosion cracking risk of the pipe in the high-pressure H2S / CO2 wellbore working condition. The strength damage of the pipe under extreme corrosion conditions is quantitatively analyzed through experiments to determine whether the strength damage of the pipe meets the safety factor requirements.

[0078] (3) The results of the strength damage characteristic evaluation are judged. If the safety factor requirements are met, the stress analysis of the pipe string material is continued for the pre-selected pipe. If the safety factor requirements are not met, the pre-selected pipe is judged as unqualified, and then other pipes are selected from the pre-selected pipes, and steps 2 and 3 are repeated to evaluate the strength damage characteristics of the newly selected pipes after corrosion.

[0079] Step S40: Performing a pipe string material stress analysis on the pipes that have passed the post-corrosion strength damage characteristic evaluation in step 3. If the pipe string material stress analysis result is unqualified, selecting other pipes from the pre-selected pipes and re-performing the post-corrosion strength damage characteristic evaluation and stress analysis until the stress analysis result is qualified, thereby completing the selection of completion string materials for the target gas well in the study block. The specific process is as follows:

[0080] (1) For pipes that have passed the strength damage characteristic evaluation in step 3, after the constant load stress corrosion test, the sample surface damage analysis is carried out, and then the tensile test is immediately carried out in accordance with the standards ISO 6892-2009 and GB / T 228-2002 "Metallic Materials Room Temperature Tensile Test Methods". The tensile strength, yield strength, elastic modulus and fracture toughness parameters are calculated based on the data results.

[0081] (2) Using the obtained tensile strength, yield strength, elastic modulus, fracture toughness and other parameter data, a stress analysis is carried out to clarify whether the qualified pipe material evaluated in step 3 meets the safety production requirements. It is known that the pipe string is subjected to the most severe stress under fracturing conditions. Therefore, this embodiment selects the fracturing conditions to perform the ultimate stress analysis of the pipe string. The specific analysis method is as follows:

[0082] (1) Parameters required for calculation

[0083] Tube string size, tubing material and steel grade, packer size, packer inner and outer diameters, formation temperature gradient, working fluid density, maximum fracturing pump pressure, well depth, tubing linear expansion coefficient, and tubing string elastic modulus.

[0084] (2) Mechanical calculation model

[0085] The axial force of the pipe string in the vertical state can be calculated by the following formula:

[0086] F=L A ·(ρ P -ρ W )ρ·A·g (3)

[0087] Where: L A is the entire string length, m;

[0088] ρ P is the column density, kg / m 3 ;

[0089] ρ W is the fluid density in the wellbore, kg / m 3 ;

[0090] A is the cross-sectional area of ​​the oil pipe, m 2 ;

[0091] g is the acceleration due to gravity, 9.8 m / s 2 ;

[0092] The calculation method of the piston effect additional force F1 is:

[0093] F1=P i (A P -A i )-P O (A P -A O ) (4)

[0094] Where: A P is the cross-sectional area of ​​the packer center tube, m 2 .

[0095] P i is the pressure in the oil pipe, MPa;

[0096] P o is the casing annulus pressure, MPa.

[0097] The deformation of the pipe string caused by the bulging effect can be calculated by the following formula:

[0098]

[0099] Where: μ P is the Poisson's ratio of the string;

[0100] △P i is the change in pressure inside the string, MPa;

[0101] △P O is the change in external pressure of the string, MPa;

[0102] E is the elastic modulus of the string, MPa;

[0103] L is the length of the upper string of the packer, m;

[0104] Then the additional force F2 caused by the bulging effect is:

[0105] F2=△L×EI (6)

[0106] Where: I is the moment of inertia of the oil pipe, m 4 .

[0107] During fracturing, the temperature change of the tubing string will also generate additional force caused by the temperature effect. The specific calculation method of the temperature effect additional force is as follows:

[0108] F3=βL△TEI (7)

[0109] Where: β is the linear expansion coefficient of the pipe, 1 / ℃;

[0110] △T is the average temperature change of the column, ℃.

[0111] Then the actual force of the string during production is:

[0112] Q=F+F1+F2+F3 (8)

[0113] The triaxial stress of the pipe string can be calculated by formula (10):

[0114]

[0115]

[0116]

[0117]

[0118] Where: r is the radius of any wall thickness of the pipe string, mm;

[0119] r i is the inner radius of the string, mm;

[0120] r o is the outer radius of the string, mm;

[0121] P i is the pressure in the string, MPa;

[0122] P o is the pressure outside the string, MPa;

[0123] σ r , σ o is the radial stress and circumferential stress under internal and external pressure, MPa;

[0124] σ zis the axial stress, MPa;

[0125] σ is the triaxial stress of the string, MPa;

[0126] Q is the force at the calculated section of the string, calculated by formula (8), kN.

[0127] (3) The residual strength of the pipe is obtained by evaluating the strength damage characteristics after corrosion in step 3. The residual strength is divided by the maximum triaxial stress of the pipe string to obtain the residual safety factor of the pipe string. The residual safety factor is required to be greater than 1.5. The stress analysis results of the pipe string material are judged to be qualified according to whether it is greater than 1.5. If it is qualified, it is used as the final pipe string material. If it is unqualified, a new pipe is selected from the remaining pipes in the initial selection, and steps 2 to 4 are repeated until the pipe string material selection is completed.

[0128] Application Examples

[0129] For example, a block in my country's Sichuan Basin has a wellbore pressure range of 16-85 MPa, a temperature of 26-133°C, an H2S content of 0.03-5.07% with a partial pressure of 0.0048-4.31 MPa, and a CO2 content of 1.13-18.5% with a partial pressure of 0.18-15.73 MPa, creating a highly corrosive environment. The average temperature gradient is 3°C / 100 m, and the average pressure coefficient is 1.54. A gas well in the block has a depth of 5,000 m, and the tubing has an outer diameter of 88.9 mm and an inner diameter of 76 mm. A permanent packer completion string is used, with a maximum outer diameter of 110 mm and an inner diameter of 55 mm. The packer is set at 3,800 m and has a maximum acid fracturing pressure of 70 MPa.

[0130] Step 1: After preliminary selection of pipe materials, the materials that meet the corrosion conditions of this block include high-sulfur-resistant carbon steel and nickel-based alloy.

[0131] Step 2: Select the highly sulfur-resistant material P110SS and conduct orthogonal corrosion tests at room temperature and pressure with CO2 partial pressures of 0 MPa, 0.5 MPa, 1 MPa, 4 MPa, 8 MPa, 12 MPa and 16 MPa, and H2S partial pressures of 0 MPa, 0.5 MPa, 1 MPa, 2 MPa, 3 MPa, 4 MPa and 5 MPa. The corrosion rates of the two pipes under different CO2 and H2S partial pressures are measured, as shown in Table 2:

[0132] Table 2 Corrosion rate of high sulfur resistant material P110SS pipe under different CO2 and H2S partial pressures at room temperature and pressure (mm / a)

[0133]

[0134] Step 3: Establish a corrosion prediction model. Based on the experimental results of step 2, the linear regression method is used. For P110SS material, the corrosion prediction model parameters A, B, C, D, and E are A=-0.18, B=-0.18, C=5.2, D=0.87, and E=1.76, respectively.

[0135] Step 4: Based on the block corrosion rate prediction function fitted in step 3 (Equation 2), the maximum corrosion rate of the gas wells in the block is predicted to be 7.18 mm / a, and the corresponding CO2 and H2S partial pressures are 8.5 MPa and 2.3 MPa, respectively.

[0136] Step 5: Evaluate the post-corrosion strength damage characteristics of the P110SS material based on parameters such as CO2 and H2S partial pressures and temperature corresponding to the maximum corrosion rate established in Step 4. The experimental results show that under these conditions, the yield strength of the P110SS material decreases by 20%. Given that the strength of an 88.9mm nickel-based alloy oil pipe is 552 MPa, the residual strength is 441.6 MPa.

[0137] Step 6: Based on the established tubing ultimate stress analysis model, the updated yield strength parameters are introduced to calculate the maximum triaxial stress of the tubing:

[0138] First, based on the string density, string length, string inner and outer diameters, and wellbore fluid density, the axial force F of the string in the vertical state is calculated according to Equation 3.

[0139] Then, based on the packer setting depth, the packer inner and outer diameters, and the wellbore fluid density, the piston force F1 due to the piston effect is calculated as -443 kN according to Equation 4;

[0140] According to equations 5 and 6, the bulging force F2 caused by the bulging effect is calculated to be 127 kN;

[0141] The additional force F3 caused by the temperature change of the tubing string during fracturing is calculated by Equation 7 to be 134 kN;

[0142] Then, the maximum force Q of the entire string is obtained from Equation 8;

[0143] Finally, the maximum triaxial stress of the string during fracturing is calculated according to Equation 9. The triaxial stress of the string is as follows: Figure 2 shown.

[0144] Step 7: Based on the information from step 5: After serving in the block, the residual strength of the P110SS material is 441.6 MPa. Divide the residual strength of the nickel-based alloy tubing by the maximum triaxial stress to which the tubing string is subjected to obtain the residual safety factor of the tubing string. The residual safety factor curve of the tubing string is as follows: Figure 3 As shown. Figure 3It can be seen that the minimum safety factor of the tubing string is approximately 1.2, which does not meet the engineering requirement of 1.5. Therefore, the P110SS tubing does not meet the requirements for use under the block's production conditions.

[0145] Step 8. From the initially selected pipe types, select nickel-based alloy oil pipes with higher strength and repeat steps 5, 6, and 7 until the conditions are met.

[0146] The above-described embodiments are merely examples of implementation methods of the present disclosure, and their descriptions are relatively specific and detailed. However, they should not be construed as limiting the scope of the present invention. It should be noted that a person skilled in the art may make various modifications, equivalent substitutions, and improvements without departing from the scope of the present disclosure, and these modifications are all within the scope of protection of the present disclosure. Therefore, the scope of protection of the present invention shall be based on the appended claims.

Claims

1. A method for selecting materials for completion strings in H2S and CO2-containing gas wells, characterized in that: include: Preliminary selection of completion string materials suitable for the research area; Select one of the preselected pipe materials and evaluate the strength damage characteristics after corrosion based on the extreme corrosion conditions of the research area; If the strength damage characteristic evaluation result is unqualified, other pipes are selected from the pre-selected pipes and the post-corrosion strength damage characteristic evaluation is repeated; If qualified, continue with the stress analysis of the string material; If the stress analysis result of the tubular string material is unqualified, other tubular materials are selected from the preliminarily selected tubular materials and the post-corrosion strength damage characteristic evaluation and stress analysis are re-performed until the stress analysis result is qualified, thereby completing the selection of completion tubular string materials for the target gas well in the study block.

2. The method for selecting a completion string according to claim 1, wherein: The method for determining the extreme corrosion conditions of the research block includes: Establishing a corrosion rate prediction model for the study area; The extreme corrosion conditions are determined using a corrosion rate prediction model for the study area.

3. The method for selecting a completion string material according to claim 2, wherein: The method for establishing the corrosion rate prediction model for the research block comprises: Orthogonal experimental design and experimental parameter combination were used to conduct coupon weight loss corrosion experiments to determine the corrosion rates under different working conditions. A multiple regression algorithm was used to determine the constant term in the corrosion rate model, and a corrosion rate prediction model for the study area was obtained; the corrosion rate model is: Where: Vcorr is the corrosion rate, mm / a; is the partial pressure of hydrogen sulfide, MPa; is the partial pressure of carbon dioxide, MPa; T is the temperature, °C; A, B, D, E, and C are dimensionless calculation parameters.

4. The method for selecting materials for completion strings according to claim 3, wherein: The method for determining the extreme corrosion condition using the corrosion rate prediction model of the research block includes: According to the corrosion rate prediction model of the study block, the maximum corrosion rate within the parameter range of the study block is calculated. Combined with the data results of the orthogonal experiment, the operating condition parameters with the highest corrosion rate of the study block are determined. The operating condition parameters are the extreme corrosion conditions.

5. The method for selecting materials for a completion string according to any one of claims 1 to 4, characterized in that: The method for evaluating strength damage characteristics after corrosion comprises: Using constant load stress corrosion experiments, the post-corrosion strength damage of the pipe to be tested is quantitatively tested under different temperatures, pressures, H2S content and CO2 content, as well as under 80% yield stress conditions. Surface damage analysis of the specimens is also performed to evaluate the stress corrosion cracking risk of the pipe to be tested under the extreme corrosion conditions.

6. The method for selecting materials for completion strings according to claim 5, characterized in that: The method for analyzing the stress of the pipe string material includes: After the constant load stress corrosion test, a tensile test is performed on the pipe string to obtain tensile strength, yield strength, elastic modulus and fracture toughness data; The tensile strength, yield strength, elastic modulus and fracture toughness data are used to calculate the triaxial stress of the tubular string to be tested based on the fracturing conditions to determine the residual safety factor, and to determine whether the residual safety factor meets the set safety factor.

7. The method for selecting materials for completion strings according to claim 6, wherein: The calculation formula of the triaxial stress is as follows: Where: r i is the inner radius of the pipe, mm; r o is the outer radius of the pipe string, mm; P i is the pressure in the column, MPa; P o is the pressure outside the string, MPa; σ r , σ o are the radial stress and circumferential stress under internal and external pressure, MPa, respectively; σ z is the axial stress, MPa; σ is the triaxial stress of the string, MPa; Q is the tension at the calculated section of the string, kN.

8. The method for selecting materials for a completion string according to any one of claims 1 to 4, 6 or 7, wherein: The method for initially selecting completion string tubing suitable for the study block includes: Collect temperature, pressure and gas composition parameter data of each gas well in the study block; Based on the parameter data, through the coupon weight loss corrosion test and SEM analysis, the pipes with a corrosion rate of ≤0.125mm / a were screened and the pre-selected pipes were determined.

9. The method for selecting materials for a completion string according to claim 8, wherein: The experimental conditions of the hanging piece weight loss corrosion experiment are selected from the temperature and pressure data at the wellhead, well and bottom of the well, and the H2S and CO2 contents are selected from the highest values ​​of the target layer in the study block.

10. The method for selecting materials for a completion string according to claim 9, wherein: The corrosion rate of the coupon weight loss corrosion experiment was calculated using the following formula: Where: CR is the corrosion rate, in mm / a; W1 is the weight of the sample before the experiment, in g; W2 is the weight of the sample after the experiment, in g; A is the surface area of ​​the sample, in mm 2 ; T is the experimental time, the unit is d; D is the material density, the unit is g / cm 2 .

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