Old oil pipe evaluation and regeneration method

Abstract

An old oil pipe evaluation and regeneration method comprises the following steps that firstly, oil pipes to be repaired are cleaned and subjected to full-length drift diameter test, and the oil pipes to be repaired with unqualified drift diameter tests serve as scrapped oil pipes; 2, appearance detection and preliminary judgment are conducted on the qualified oil pipes in the step 1; 3, thread repairing and coupling replacement are conducted on the first-stage oil pipe and the second-stage oil pipe; 4, pressure testing is conducted on the first-stage oil pipe and the second-stage oil pipe; 5, coatings and protection devices are arranged on the first-stage oil pipe and the second-stage oil pipe; and 6, the first-stage oil pipe and the second-stage oil pipe are put into use again, and oil pipe regeneration is completed. According to the method, the problem of high abnormal waste judgment rate of old oil pipe repair can be solved, the oilfield development cost is remarkably reduced, and the potential popularization value is achieved.

Description

Technical Field

[0001] This invention relates to the field of used oil pipe treatment in the petroleum industry, and specifically to a method for evaluating and regenerating used oil pipes. Background Technology

[0002] Oil tubing is a widely used metal component in the petroleum industry. The technical specifications for new oil tubing deliveries are typically API Spec 5CT. API Spec 5CT requires a smooth tubing surface, prohibiting pits deeper than 12.5%t or having a remaining wall thickness less than the minimum requirement (87.5%t). Even tubing meeting API Spec 5CT requirements will develop rust pits on its surface after a period of operation in the well due to corrosion and rust.

[0003] To reduce tubing procurement costs and improve economic efficiency, oilfield development necessitates the recycling and repair of old tubing. Currently, the API SPEC 5CT standard is used to inspect and evaluate repaired old tubing to ensure safe use in wells. However, while using the API SPEC 5CT standard as the criterion for judging repaired old tubing ensures safety, it results in an excessively high rejection rate, reducing the economic viability of reusing old tubing. In reality, many rejected tubing units can still meet usage requirements depending on the specific environmental conditions. Therefore, the evaluation criteria for new tubing are not suitable for the recycling and reuse of repaired old tubing.

[0004] Regarding the criteria for assessing the usability and repair methods of used oil pipes, no widely recognized and applied standard or specification has been promulgated at home and abroad. The main reasons are: (1) The criteria for assessing used oil pipes involve complex factors, including not only the production standards of the product itself, but also the impact of various defects (corrosion, cracks, thread damage, deformation, etc.) on the performance of the oil pipes, and are also closely related to the different service conditions of the oil field; (2) Different oil fields, different blocks, and different well conditions have different requirements for the safety and economy of oil pipe applications; (3) Sufficient data accumulation is needed to formulate the assessment method in order to better ensure the organic unity of the economy and safety in assessing used oil pipes. Summary of the Invention

[0005] To address the lack of a unified and applicable method for the repair and usability assessment of old oil pipes in existing technologies, this invention provides a method for evaluating and regenerating old oil pipes.

[0006] A method for evaluating and regenerating used oil pipes, characterized by comprising the following steps:

[0007] Step 1: Clean and test the full length of the tubing to be repaired, and discard any tubing that fails the test.

[0008] Step 2 involves visual inspection and preliminary assessment of the qualified oil pipes from Step 1, specifically including:

[0009] Step 2.1: Conduct a preliminary visual inspection of the qualified oil pipes from Step 1, and designate any oil pipes that are bent or deformed as scrapped oil pipes.

[0010] Step 2.2: Measure the corrosion defects that cause wall thickness loss in the qualified oil pipes from Step 2.1, and preliminarily classify them into undetermined first-level oil pipes and undetermined second-level oil pipes according to the depth of corrosion pits and the degree of linear axial wear defects.

[0011] Step 2.3 involves using an ultrasonic flaw detector to perform flaw detection and assessment on the undetermined primary and secondary oil pipes, specifically including:

[0012] Step 2.3.1, Inspection of the pending primary oil pipe;

[0013] Perform flaw detection on the undetermined first-level tubing identified in step 2.2 to determine whether it meets the flaw detection requirements for L2 acceptance level specified in Table C.43 of Clause 10.15 of API SPEC 5CT. If it does, it is determined to be a first-level tubing and proceeds to step 3; otherwise, it is determined to be an undetermined second-level tubing and proceeds to step 2.3.2.

[0014] Step 2.3.2, pending secondary oil pipe inspection, specifically includes:

[0015] Step 2.3.2.1: Inspect the undetermined secondary tubing identified in Steps 2.2 and 2.3.1. Use a new tubing with the same diameter, wall thickness and material as the original secondary tubing as a sample tubing. Process artificial defects on the sample tubing and use an ultrasonic flaw detector to test the artificial defects on the sample tubing to obtain the reference sensitivity. Increase the reference sensitivity by 5-7 dB to obtain the scanning sensitivity.

[0016] Step 2.3.2.2: Based on the scanning sensitivity, use an ultrasonic flaw detector to inspect the undetermined secondary oil pipe and determine whether the undetermined secondary oil pipe meets the requirement that the depth of the corrosion pits is less than 30% of the standard wall thickness. If it meets the requirement, it is determined to be a secondary oil pipe and step 3 is executed; otherwise, it is determined to be a scrapped oil pipe.

[0017] Step 3: Repair the threads and replace the couplings of the primary and secondary oil pipes;

[0018] Step 4: Perform pressure tests on the primary and secondary oil pipes;

[0019] Step 5: Apply coatings and protective devices to the primary and secondary oil pipes;

[0020] Step 6: Put the primary and secondary oil pipes back into use, thus completing the oil pipe regeneration.

[0021] Preferably, the preliminary classification determination in step 2.2 is as follows: if the depth of the corrosion pits does not exceed 12.5% ​​of the standard wall thickness and there are no linear axial wear defects on the inner wall of the pipe, it is determined to be a first-class undetermined oil pipe; if the depth of the corrosion pits exceeds 12.5% ​​of the standard wall thickness, but the depth of the corrosion pits is less than 30% of the standard wall thickness, and the linear axial wear defects on the inner wall of the pipe are less than 12.5% ​​of the standard wall thickness, it is determined to be a second-class undetermined oil pipe; the rest are determined to be scrapped oil pipes.

[0022] Preferably, in step 2.3.2.1, the sample tube is processed. The vertical through hole was used as an artificial defect. An ultrasonic flaw detector was used to test the artificial defect on the sample tube. The sensitivity value displayed by the ultrasonic flaw detector when the intensity of the reflected wave of the artificial defect was equal to 80 ± 0.5% of its peak value was used as the reference sensitivity.

[0023] Preferably, step 3 specifically comprises:

[0024] Step 3.1: Thread inspection and judgment;

[0025] Inspect the corrosion of the factory end threads and field end threads of the primary and secondary oil pipes, as well as the corrosion of the inner and outer surfaces within 300mm of the pipe end. Determine whether there are defects such as rust, sticking, loss of thread continuity, and corrosion pits in the male end threads. If so, cut off the end and re-thread; otherwise, proceed to step 3.2.

[0026] Step 3.2, Inspection and judgment of couplings;

[0027] Determine whether the primary and secondary oil pipes have defects such as rust, sticking, or disruption of thread continuity in the coupling threads, or whether there are corrosion defects or end face damage exceeding the specified depth on the outer surface of the coupling. If so, it is determined that the coupling needs to be replaced; otherwise, proceed to step 3.3.

[0028] Step 3.3: Repair the primary and secondary oil pipes and replace the couplings according to the judgment results in Step 3.2.

[0029] More preferably, step 4 specifically involves: conducting hydrostatic pressure tests on the primary and secondary oil pipes using a hydrostatic pressure test production line and supporting facilities. The test pressure is the hydrostatic pressure test pressure specified by API SPEC 5CT, and the full pressure test state must be maintained for no less than 10 seconds. It is then determined whether the oil pipe has passed the hydrostatic pressure test. If it has, step 5 is executed; otherwise, it is determined to be a scrapped oil pipe.

[0030] More preferably, step 5 further includes: before applying coatings and protective devices to the primary and secondary oil pipes, inspecting the appearance of the threads to determine whether the thread damage was caused by pressure testing. If so, repair the threads and return to step 4; otherwise, continue to step 5.

[0031] Preferably, step 5 further includes: marking the primary and secondary oil pipes that have been coated and protected, and marking the marking content includes the name or trademark of the processing plant, steel grade, wall thickness, outer diameter, thread type, hydrostatic test pressure, whether the coupling has been replaced, and oil pipe grade.

[0032] More preferably, in step 2.3, the ultrasonic flaw detector has a coverage rate of 120% or more over the workpiece, and the signal-to-noise ratio of the ultrasonic flaw detector is greater than 8dB.

[0033] More preferably, in step 2.1, the preliminary visual inspection items include: the presence or absence of cracks, fissures, pits, dents, corrosion damage on the inner and outer surfaces, damage to the steel wire rope on the inner and outer surfaces, damage to the slips and pliers on the outer surface, wear of the sucker rod on the inner surface, pipe bending, appearance and threads of the coupling, and damage to the male end threads.

[0034] Preferably, in step 6, the primary tubing is used according to the usage method of new tubing; the secondary tubing is used for mechanical pumping wells and electric pump wells, and the strength of the secondary tubing is checked according to 80% of the connection strength of the new tubing body.

[0035] The beneficial effects of this invention are as follows:

[0036] The purpose of this invention is to address the problem that the current use of API Spec 5CT to inspect old tubing results in an excessively high rate of abnormal rejection during the repair process of a large number of old tubing, which prevents the full utilization of old tubing that can be used under certain conditions.

[0037] This invention discloses a method for evaluating and regenerating used oil tubing. The method involves sequentially cleaning and inspecting the entire length of the tubing, visually inspecting it, performing ultrasonic testing, repairing threads and replacing couplings, pressure testing, and installing coatings and protective devices. Ultimately, it regenerates usable primary and secondary oil tubing. This invention repairs used oil tubing based on the impact of various defects on tubing performance, considering the safety and economic requirements of different oilfields, blocks, and well conditions. It rates the repaired tubing according to actual needs and effectively regenerates it based on these ratings. This invention solves the problem of high failure rates in repairing used oil tubing and significantly reduces oilfield development costs, demonstrating potential for widespread application. Attached Figure Description

[0038] Figure 1 This is a schematic flowchart of a method for regenerating used oil pipes according to the present invention;

[0039] Figure 2 This is a flowchart illustrating step 2.2 in Embodiment 1 of the present invention;

[0040] Figure 3 This is a schematic diagram showing the relationship between the tensile strength of the old oil pipe with spherical, conical, and cylindrical corrosion pits and the diameter of the corrosion pit in step 2.2.2.2.4 of Embodiment 1 of the present invention.

[0041] Figure 4 This is a schematic diagram showing the relationship between the internal pressure resistance of the old oil pipe with spherical, conical, and cylindrical corrosion pits and the diameter of the corrosion pit in step 2.2.2.2.4 of Embodiment 1 of the present invention.

[0042] Figure 5 This is a schematic diagram showing the relationship between the extrusion resistance strength of the old oil pipe with spherical, conical, and cylindrical corrosion pits and the diameter of the corrosion pit in step 2.2.2.2.4 of Embodiment 1 of the present invention.

[0043] Figure 6 This is a schematic diagram comparing the theoretical calculation results and the actual test calculation results of the remaining tensile strength of the old oil pipe with multi-point corrosion / uniform corrosion pits in step 2.2.2.3.1 of Embodiment 1 of the present invention;

[0044] Figure 7 This is a schematic diagram comparing the theoretical calculation results and the actual test calculation results of the remaining internal pressure resistance of the old oil pipe with multi-point corrosion / uniform corrosion pits in step 2.2.2.3.2 of Embodiment 1 of the present invention;

[0045] Figure 8 This is a schematic diagram comparing the theoretical calculation results and the actual test calculation results of the remaining extrusion resistance of the old oil pipe with multi-point corrosion / uniform corrosion pits in step 2.2.2.3.3 of Embodiment 1 of the present invention.

[0046] Figure 9 This is a schematic diagram comparing the theoretical calculation results and the actual test calculation results of the remaining tensile strength of the old oil pipe in step 2.2.2.4 of Embodiment 1 of the present invention;

[0047] Figure 10 This is a schematic diagram comparing the theoretical calculation results and the actual test calculation results of the remaining internal compressive strength in step 2.2.2.4 of Embodiment 1 of the present invention;

[0048] Figure 11 This is a schematic diagram comparing the theoretical calculation results and the actual test calculation results of the remaining extrusion strength in step 2.2.2.4 of Embodiment 1 of the present invention. Detailed Implementation

[0049] The present invention will be further described below with reference to the accompanying drawings and exemplary embodiments.

[0050] Example 1

[0051] Reference Figure 1 A method for evaluating and regenerating used oil pipelines includes the following steps:

[0052] Step 1: Clean and inspect the entire length of the tubing to be repaired;

[0053] Step 1.1 After cleaning the tubing to be repaired, the tubing to be repaired should be free of obvious oil stains, wax and scale on the inner and outer walls, and free of rust, chips or other residual substances that may cause the downhole tools to get stuck on the inner wall.

[0054] Step 1.2: Perform a full-length bore test on the tubing to be repaired. The bore test gauge size should meet the technical requirements in the API SPEC 5CT casing and tubing specifications. Tubing to be repaired that fails the bore test should be scrapped.

[0055] Step 2: Perform a visual inspection of the oil pipe to be repaired;

[0056] Step 2.1: Conduct a preliminary visual inspection of the tubing to be repaired, and designate any tubing with bending or deformation as scrap tubing.

[0057] The preliminary visual inspection items include: whether there are cracks, fissures, pits, dents, corrosion damage on the inner and outer surfaces, damage to the steel wire rope on the inner and outer surfaces, damage to the slips and pliers on the outer surface, wear of the sucker rod on the inner surface, pipe bending, appearance of the coupling and threads, and damage to the male end threads.

[0058] Step 2.2: Measure the corrosion defects causing wall thickness loss and classify the tubing to be repaired, such as... Figure 2 As shown;

[0059] If the depth of the corrosion pits does not exceed 12.5% ​​of the standard wall thickness and there are no linear axial wear defects on the inner wall of the pipe, it is determined to be a first-class undetermined oil pipe.

[0060] If the depth of the corrosion pits exceeds 12.5% ​​of the standard wall thickness, but the depth of all corrosion pits is less than 30% of the standard wall thickness, and the linear axial wear defects on the inner wall of the pipe are less than 12.5% ​​of the standard wall thickness, then it is determined to be a secondary oil pipe pending determination.

[0061] The rest were all determined to be scrapped oil pipes;

[0062] Step 2.3: Use an ultrasonic flaw detector to perform flaw detection on the oil pipe to be repaired;

[0063] When the ultrasonic flaw detector is working, the coverage of the workpiece must be greater than or equal to 120%, and the signal-to-noise ratio of the ultrasonic flaw detector must be greater than 8dB.

[0064] Step 2.3.1, Inspection of the pending primary oil pipe;

[0065] Perform flaw detection on the undetermined first-level tubing identified in step 2.2 to determine whether the undetermined first-level tubing meets the flaw detection requirements of L2 acceptance level as described in Table C.43 of Clause 10.15 of API SPEC 5CT. If it does, proceed to step 3; otherwise, determine it as a second-level tubing and proceed to step 2.3.2.

[0066] Step 2.3.2: Inspection of the pending secondary oil pipe;

[0067] Step 2.3.2.1 Inspect the undetermined secondary tubing identified in Steps 2.2 and 2.3.1. Use a new tubing with the same diameter, wall thickness, and material as the secondary tubing as a sample tubing, and process the tubing on the sample tubing. The vertical through hole is used as an artificial defect. An ultrasonic flaw detector is used to test the artificial defect on the sample tube. The sensitivity value displayed by the ultrasonic flaw detector when the intensity of the reflected wave of the artificial defect is equal to 80% of its peak value is used as the reference sensitivity. The reference sensitivity is increased by 6 dB as the scanning sensitivity.

[0068] Step 2.3.2.2 Based on the scanning sensitivity, an ultrasonic flaw detector is used to inspect the undetermined secondary oil pipe;

[0069] Determine whether the corrosion pit depth of the undetermined secondary oil pipe is less than 30% of the standard wall thickness. If it is, proceed to step 3; otherwise, determine it as a scrapped oil pipe.

[0070] Step 3: Repair the threads and replace the couplings of the primary and secondary oil pipes;

[0071] Step 3.1: Thread inspection and judgment;

[0072] Inspect the corrosion of the factory end threads and field end threads of the primary and secondary oil pipes, as well as the corrosion of the inner and outer surfaces within 300mm of the pipe end. Determine whether there are defects such as rust, sticking, loss of thread continuity, and corrosion pits in the male end threads. If so, cut off the end and re-thread; otherwise, proceed to step 3.2.

[0073] Step 3.2, Inspection and judgment of couplings;

[0074] Determine whether the primary and secondary oil pipes have rust, sticking, or thread continuity defects in the coupling threads, or whether there are corrosion defects or end face damage defects on the outer surface of the coupling that exceed the specified depth. If so, the coupling needs to be replaced; otherwise, proceed to step 3.3.

[0075] The corrosion defects and end-face damage defects existing on the outer surface of the primary tubing coupling shall be determined according to the depth specified in API 5CT Table C.36, and the corrosion defects and end-face damage defects existing on the outer surface of the secondary tubing coupling shall be determined according to Table 1.

[0076] Table 1

[0077]

[0078] Step 3.3: Repair the primary and secondary oil pipes and replace the couplings according to the judgment results in Step 3.2;

[0079] Step 4: Perform pressure tests on the primary and secondary oil pipes;

[0080] The hydrostatic pressure test production line and supporting facilities are used to conduct hydrostatic pressure tests on the primary and secondary oil pipes. The test pressure is the hydrostatic pressure test pressure specified by API SPEC 5CT, and the full pressure test state must be maintained for no less than 10 seconds. Determine whether the oil pipe passes the hydrostatic pressure test. If it passes, proceed to step 5; otherwise, it is determined to be a scrapped oil pipe.

[0081] Step 5: Apply coatings and protective devices to the primary and secondary oil pipes;

[0082] Step 5.1: Inspect the appearance of the thread to determine if the thread was damaged by the pressure test. If so, repair the thread and return to step 4; otherwise, continue to step 5.2.

[0083] Step 5.2: Apply an outer coating to the tubing body and couplings to prevent rusting during transportation and storage. The outer coating surface should be smooth and dense. Apply external and internal thread protectors to the threads on the tubing body to prevent damage during normal loading, unloading and transportation.

[0084] Step 5.3: Mark the primary and secondary oil pipes that have been coated and protected. The marking content includes the name or trademark of the processing plant, steel grade, wall thickness, outer diameter, thread type, hydrostatic test pressure, whether the coupling has been replaced, and oil pipe grade, so as to facilitate traceability and identification.

[0085] Step 6: Put the primary and secondary oil pipes back into use, thus completing the oil pipe regeneration.

[0086] The primary tubing shall be used in accordance with the usage instructions for new tubing without any changes.

[0087] Secondary tubing is used in mechanically pumped wells and electric pump wells, and its strength is checked against 80% of the original tubing connection strength. For example, a secondary tubing of Φ88.90×6.45mm P110 can be used in mechanically pumped wells and electric pump wells with a tubing depth of less than 4000m and a wellhead pressure of less than 15MPa in oilfields in Northwest China. According to tests and simulations, the tensile strength of tubing with pitting corrosion at a depth of 30%t on the outer surface can reach more than 80% of the tensile strength of the original tubing (for actual Φ88.9×6.45mm P110 tubing, the tensile strength can reach 91% of the rated tensile strength of the original tubing), and its internal pressure resistance can reach 100% of the internal pressure resistance of the original tubing (for actual Φ88.9×6.45mm P110 tubing). P110 tubing has an internal pressure resistance that can reach 102% of the rated internal pressure resistance of the original tubing body, but its external extrusion resistance can only reach 60% of the external pressure resistance of the original tubing body (for actual Ф88.9×6.45mm P110 tubing, the external extrusion resistance of the tubing can only reach 60% of the rated tensile strength of the original tubing body). Secondary tubing is not recommended for use in wells subjected to external extrusion pressure.

[0088] The scrapped oil pipes were used for other purposes.

[0089] The basis for the grading determination in step 2.2 of this embodiment is as follows:

[0090] Step 2.2.1: Detection and statistical analysis of quality defects in old oil pipes;

[0091] Step 2.2.1.1: Statistical analysis of defect types in old oil pipes;

[0092] According to statistics, of the 295,858 old oil pipes in Northwest China, totaling 2.663 million meters, 44,940 pipes, totaling 404,000 meters, were determined to be scrapped by API Spec 5CT. The main reason for scrapping was corrosion (91%), with other reasons (mechanical damage, bending, insufficient diameter, etc.) accounting for 9%. The corrosion distribution was mainly pitting corrosion, supplemented by surface corrosion, with pitting corrosion accounting for 81%. Corrosion was present on both the inner and outer walls, and there were also a few corrosion perforations.

[0093] A macroscopic statistical analysis was conducted on randomly selected old oil pipes. The corrosion distribution was mainly pitting corrosion, accounting for 72%, surface corrosion, accounting for 20%, and other types, accounting for 8%.

[0094] Step 2.2.1.2: Statistical analysis of typical corrosion defects in old oil pipes;

[0095] The depth of typical corrosion defects in the sampled used oil pipes was precisely measured. Statistical analysis revealed that the maximum percentage of corrosion pit depth to the specified wall thickness was 57%, and the average was 18.7%. Corrosion pits with a depth exceeding 20% ​​of the specified wall thickness accounted for 39.2% of the total number of corrosion pits; those exceeding 25% of the specified wall thickness accounted for 15.9%; and those exceeding 30% of the specified wall thickness accounted for 3.9%.

[0096] Step 2.2.1.3: C-scan analysis of typical corrosion defects in old oil pipes;

[0097] Samples of equal length were cut from the old oil pipe and subjected to C-scan analysis to observe the degree of corrosion on the inner and outer walls.

[0098] Step 2.2.2: Finite element analysis of the remaining strength of old oil pipes with typical defects;

[0099] The corrosion pit detection and statistical analysis obtained in step 2.2.1.2 show that the number of corrosion pits with a depth exceeding 30% of the specified wall thickness is relatively small. The criterion of corrosion pit depth not exceeding 30% of the specified wall thickness can cover more than 95% of old oil pipes. Sinopec's enterprise standard "Quality Standard for Repaired Oil Pipes" Q / SH0180-2008 proposes that a defect depth greater than 12.5% ​​and less than 25% of the standard wall thickness is used as the judgment standard for secondary oil pipes. Therefore, in this embodiment of the invention, taking a corrosion pit depth of 30% of the specified wall thickness as an example in the finite element analysis of a single corrosion pit, the influence of corrosion pits of different shapes, such as spherical, conical and cylindrical corrosion pits, on the strength of old oil pipes is analyzed to determine whether the residual strength when the depth of a single corrosion pit is 30% of the specified wall thickness meets the requirements.

[0100] For corrosion pits with a depth less than 30% of the specified wall thickness, or for uniform corrosion, the uniform corrosion method, probability distribution method, and uniform corrosion pit distribution method can be used for analysis and calculation. At the same time, the appropriate method for calculating the strength of old oil pipes can be determined based on actual experimental values, and then the calculation model can be determined.

[0101] Step 2.2.2.1, Finite element analysis model;

[0102] Type: Taking a used oil pipe body as an example, specifications: Φ88.9×6.45mm; Software: ANSYS; Material model: steel grade 110, elastic modulus 212739Mpa, Poisson's ratio 0.3, yield strength 758Mpa, tensile strength 862Mpa, engineering stress-strain curve adopted the converted real stress-strain curve; Model: A three-dimensional model of defects in the used oil pipe and an elastoplastic analysis model were established;

[0103] Step 2.2.2.2: Finite element analysis of the remaining strength of old oil pipes with single corrosion pits;

[0104] Step 2.2.2.2.1: Finite element analysis of the remaining tensile strength of old oil pipes with single corrosion pits;

[0105] (1) Analysis of the failure law of old oil pipes with single corrosion pits under tensile conditions;

[0106] The tensile failure mode of old oil pipes is the fracture of a certain section of the pipe body; the fracture criteria are: if necking occurs, fracture occurs; if no necking occurs, no fracture occurs.

[0107] Taking a spherical corrosion pit as an example, the pit depth is 1.935 mm, which is 30% of the specified wall thickness. A defect model containing the spherical corrosion pit is established. An axial load is applied to one end. As the axial load increases, the overall stress of the old oil pipe and the local stress level at the corrosion pit increase. As the load further increases, the load-bearing capacity of the old oil pipe containing the spherical corrosion pit reaches its maximum value when the applied load reaches 1418 kN. Subsequently, even if the axial load decreases, the axial displacement can still increase, and the necking phenomenon occurs. From the above analysis, it can be seen that the failure load of the old oil pipe containing the spherical corrosion pit is 1418 kN.

[0108] (2) Finite element analysis of tensile strength of old oil pipes with spherical corrosion pits

[0109] Taking a spherical corrosion pit as an example, with a pit depth of 1.935 mm (30% of the specified wall thickness), and pit diameters of 5.76 mm, 8.70 mm, 10.62 mm, 12.06 mm, 13.21 mm, 14.17 mm, 14.98 mm, 15.67 mm, 16.28 mm, 16.81 mm, 17.29 mm, 17.73 mm, 18.10 mm, and 18.40 mm, calculations and analyses were performed. As the pit diameter increases, the tensile strength of the old tubing gradually decreases, though the decrease is not significant. The tensile strength of the largest pit diameter (18.40 mm) is approximately 1.8% lower than that of the smallest pit diameter (5.76 mm), but both meet the standard values ​​required by API 5C1.

[0110] (3) Finite element analysis of tensile strength of old oil pipes with conical corrosion pits

[0111] Taking a conical corrosion pit as an example, with a pit depth of 1.935 mm, which is 30% of the specified wall thickness, and using pit diameters of 1.90 mm, 3.73 mm, 5.47 mm, 8.52 mm, 10.99 mm, 13.78 mm, 16.29 mm, and 17.22 mm as examples, the tensile strength of the old oil pipe gradually decreases as the pit diameter increases, although the decrease is not significant. The tensile strength of the largest pit diameter of 17.22 mm is about 1.0% lower than that of the smallest pit diameter of 1.90 mm. The tensile strength of all of them can meet the standard value required by API 5C1.

[0112] (4) Finite element analysis of tensile strength of old oil pipe with cylindrical corrosion pits

[0113] Taking a cylindrical corrosion pit as an example, with a pit depth of 1.935 mm, which is 30% of the specified wall thickness, and using pit diameters of 5.08 mm, 7.62 mm, 10.16 mm, 12.70 mm, 15.24 mm, 17.78 mm, and 20.32 mm as examples, the tensile strength of the old oil pipe gradually decreases as the pit diameter increases, although the decrease is not significant. The tensile strength of the largest pit diameter of 20.32 mm is about 1.9% lower than that of the smallest pit diameter of 5.08 mm. The tensile strength of all of them can meet the standard value required by API 5C1.

[0114] Step 2.2.2.2.2 Finite element analysis of the remaining internal pressure resistance of old oil pipes with single corrosion pits.

[0115] (1) Analysis of the failure law of old oil pipes with single corrosion pits under internal pressure conditions;

[0116] The failure mode that causes internal pressure to the old oil pipe is corrosion pit leakage. The judgment of corrosion pit leakage is that the corrosion pit is completely yielded.

[0117] Taking a spherical corrosion pit as an example, the pit depth is 3.68 mm and the pit diameter is 11.54 mm. A defect model containing the spherical corrosion pit is established. Internal pressure is applied to the inner wall. As the internal pressure increases, the overall stress of the old oil pipe and the local stress at the pit increase. As the internal pressure further increases, when the internal pressure reaches 108 MPa, the entire cross-section of the corrosion pit yields, and the internal pressure reaches its maximum value. From the above analysis, it can be seen that the internal pressure resistance of the old oil pipe containing the spherical corrosion pit is 108 MPa.

[0118] (2) Finite element analysis of the internal pressure resistance of old oil pipes with spherical corrosion pits;

[0119] Taking a spherical corrosion pit as an example, with a pit depth of 1.935 mm, which is 30% of the specified wall thickness, and using pit diameters of 5.76 mm, 10.62 mm, 13.21 mm, 14.98 mm, 16.28 mm, 17.29 mm, and 18.10 mm as examples, the internal pressure resistance of the old oil pipe gradually decreases as the pit diameter increases, although the decrease is not significant. The internal pressure resistance of the largest pit diameter of 18.10 mm is about 6.7% lower than that of the smallest pit diameter of 5.76 mm. However, the internal pressure resistance of all pits still meets the standard value required by API 5C1.

[0120] (3) Finite element analysis of the internal pressure resistance of old oil pipes with conical corrosion pits;

[0121] Taking a conical corrosion pit as an example, with a pit depth of 1.935 mm, which is 30% of the specified wall thickness, and with pit diameters of 1.90 mm, 3.73 mm, 5.47 mm, 8.52 mm, 10.99 mm, 13.78 mm, 16.29 mm, and 17.22 mm, the internal pressure resistance of the old oil pipe gradually decreases as the pit diameter increases, although the decrease is not significant. The internal pressure resistance of the largest pit diameter of 17.22 mm is about 4.9% lower than that of the smallest pit diameter of 1.90 mm. However, the internal pressure resistance of all pits still meets the standard value required by API 5C1.

[0122] (4) Finite element analysis of the internal pressure resistance of old oil pipes with cylindrical corrosion pits;

[0123] Taking a cylindrical corrosion pit as an example, with a pit depth of 1.935 mm, which is 30% of the specified wall thickness, and using pit diameters of 5.08 mm, 7.62 mm, 10.16 mm, 12.70 mm, 15.24 mm, 17.78 mm, and 20.32 mm as examples, the internal pressure resistance of the old oil pipe gradually decreases as the pit diameter increases, although the decrease is not significant. The internal pressure resistance of the largest pit diameter of 20.32 mm is approximately 13.3% lower than that of the smallest pit diameter of 5.08 mm. However, the internal pressure resistance of all pits still meets the standard value required by API 5C1.

[0124] Step 2.2.2.2.3: Finite element analysis of the remaining crush resistance of old oil pipes with single corrosion pits;

[0125] (1) Analysis of the failure law of old oil pipes with single corrosion pits under external pressure;

[0126] The failure modes that cause old oil pipes to collapse are instability or corrosion pit leakage. Casing collapse is also called casing crushing, which is the failure process of casing becoming unstable, deformed or flattened under external pressure. The critical collapse pressure is defined as the casing's crush resistance strength. Corrosion pit leakage is judged by the complete yielding of the corrosion pit.

[0127] Taking a spherical corrosion pit as an example, the pit depth is 1.935 mm, which is 30% of the specified wall thickness. A defect model containing the spherical corrosion pit is established. External pressure is applied to the outer wall. As the external pressure increases, the overall stress of the old oil pipe and the local stress at the corrosion pit increase. As the external pressure further increases, when the applied external pressure reaches 106 MPa, the entire cross-section of the corrosion pit yields, and the external pressure reaches its maximum value. From the above analysis, it can be seen that the internal pressure resistance of the old oil pipe containing the spherical corrosion pit is 106 MPa.

[0128] (2) Finite element analysis of the extrusion resistance of old oil pipes with spherical corrosion pits;

[0129] Taking a spherical corrosion pit as an example, with a pit depth of 1.935 mm, which is 30% of the specified wall thickness, and using pit diameters of 5.76 mm, 8.70 mm, 10.62 mm, 13.21 mm, 14.98 mm, 16.28 mm, 17.29 mm, and 18.10 mm as examples, the analysis shows that as the pit diameter increases, the extrusion strength of the old oil pipe gradually decreases, but the decrease is not significant. The extrusion strength of the largest pit diameter of 18.10 mm is about 7.4% lower than that of the smallest pit diameter of 5.76 mm. The extrusion strength of all of them can meet the standard value required by API 5C1.

[0130] (3) Finite element analysis of the extrusion resistance of old oil pipes with conical corrosion pits;

[0131] Taking a conical corrosion pit as an example, with a pit depth of 1.935 mm, which is 30% of the specified wall thickness, and with pit diameters of 1.90 mm, 3.73 mm, 5.47 mm, 8.52 mm, 10.99 mm, 13.78 mm, 16.29 mm, and 17.22 mm, the analysis shows that as the pit diameter increases, the extrusion strength of the old tubing gradually decreases, but the decrease is not significant. The extrusion strength of the largest pit diameter of 17.22 mm is about 5.6% lower than that of the smallest pit diameter of 1.90 mm. The extrusion strength of all pits meets the standard value required by API 5C1.

[0132] (4) Finite element analysis of the extrusion resistance of old oil pipes with cylindrical corrosion pits;

[0133] Taking a cylindrical corrosion pit as an example, with a pit depth of 1.935 mm, which is 30% of the specified wall thickness, and using pit diameters of 5.08 mm, 7.62 mm, 10.16 mm, 12.70 mm, 15.24 mm, 17.78 mm, and 20.32 mm as examples, the analysis shows that as the pit diameter increases, the extrusion strength of the old oil pipe gradually decreases, but the decrease is not significant. The extrusion strength of the largest pit diameter of 20.32 mm is about 11.3% lower than that of the smallest pit diameter of 5.08 mm. The extrusion strength of all of them can meet the standard value required by API 5C1.

[0134] Step 2.2.2.2.4, Summary;

[0135] When the depth of the corrosion pit is 30% of the wall thickness, the relationship between the tensile strength, internal pressure strength, and extrusion strength of the old oil pipe with spherical, conical, and cylindrical corrosion pits and the diameter of the corrosion pit is shown in the figure. Figures 3 to 5 As shown in the figure, the residual strength of old oil pipes with cylindrical corrosion pits has a significant impact; as the diameter of spherical, conical, and cylindrical corrosion pits increases, their load-bearing capacity decreases to a certain extent, but their residual strength can still meet the standard value required by API 5C1.

[0136] Step 2.2.2.3: Theoretical analysis of the remaining strength of old oil pipes with multi-point corrosion / uniform corrosion pits;

[0137] For corrosion pits with a depth less than 30% of the specified wall thickness, or for uniform corrosion, the uniform wall thickness corrosion method, probability distribution method, and uniform distribution of corrosion pits can be used for analysis and calculation. The calculation methods are as follows:

[0138] (1) Uniform wall thickness corrosion method;

[0139] Uniform corrosion, also known as general corrosion, is corrosion that is distributed across the entire metal surface. In terms of weight, uniform corrosion represents the maximum damage caused by corrosion to old oil pipes. For corrosion pits with a depth less than 30% of the specified wall thickness, or for uniform corrosion, if the uniform wall thickness corrosion method is used to calculate the strength of the old oil pipe, then the oil pipe wall thickness is uniformly corroded away by 30%. For example, if 30% of the wall thickness of an 88.90×6.45mm oil pipe is uniformly corroded away, the remaining wall thickness is 4.52mm. The strength calculation is based on this wall thickness.

[0140] (2) Probability distribution method;

[0141] By detecting and statistically analyzing corrosion pit defects in oil pipe samples, the average value of the corrosion pit depth relative to the specified wall thickness was calculated using a probability method. Strength calculation was then performed based on the average wall thickness according to the probability distribution. For example, if the average percentage of corrosion pit depth relative to the specified wall thickness in old oil pipes is 18.7%, the remaining wall thickness is 5.24 mm. Strength calculation was performed based on this wall thickness.

[0142] (3) Uniform distribution of corrosion pits;

[0143] The oil pipe strength is calculated by evenly distributing corrosion pits of a certain fixed size on the surface of the oil pipe.

[0144] (4) Statistical prediction method for experimental values ​​(3 sigma)

[0145] The probability method is used to calculate the three sigma of the standard normal function, which is the probability of being 3 standard deviations to the left and right of the central axis; the experimental mean and standard deviation are calculated based on the experimental results, and then the possible outcomes are predicted.

[0146] Step 2.2.2.3.1 Theoretical analysis of the remaining tensile strength of old oil pipes with multi-point corrosion / uniform corrosion pits;

[0147] The tensile strength of old oil pipes was calculated using the uniform wall thickness corrosion method, the probability distribution method, and the uniform pit distribution method. Table 2 summarizes the theoretical results for the tensile strength of oil pipes under multi-point corrosion / uniform pit conditions. The table shows that the uniform wall thickness corrosion method yields the lowest value, while the probability distribution method's result falls between that of the uniform pit distribution method. A comparison between the theoretical calculation results and the actual experimental calculation results is shown below. Figure 6 As shown in the figure, the calculation results of the uniform wall thickness corrosion method and the experimental value statistical prediction method (3 sigma) are conservative, while the calculation results of the uniform corrosion pit distribution method are in good agreement with the actual experiment. Therefore, it is recommended to use the uniform corrosion pit distribution method to calculate the remaining tensile strength of the old oil pipe.

[0148] The corrosion pit depth is less than 30% of the specified wall thickness. There are multiple corrosion pits or uniform corrosion. Although the load-bearing capacity of the old oil pipe has decreased to a certain extent, the tensile strength has decreased by 21%, reaching 91% of the rated value.

[0149] Table 2

[0150]

[0151] Step 2.2.2.3.2: Theoretical analysis of the remaining internal pressure resistance of old oil pipes with multi-point corrosion / uniform corrosion pits;

[0152] The internal pressure resistance of old oil pipes was calculated using the uniform wall thickness corrosion method, probability distribution method, and uniform pit distribution method. Table 3 summarizes the theoretical results of the internal pressure resistance of oil pipes under multi-point corrosion / uniform pit distribution. The table shows that the uniform wall thickness corrosion method yields the lowest value, while the probability distribution method's result falls between that of the uniform pit distribution method. A comparison between the theoretical calculation results and the actual experimental calculation results is shown below. Figure 7As shown in the figure, the calculation results of the uniform wall thickness corrosion method and the experimental value statistical prediction method (3 sigma) are conservative, while the calculation results of the uniform corrosion pit distribution method are in agreement with the actual experiment. Therefore, it is recommended to use the uniform corrosion pit distribution method to calculate the remaining internal pressure resistance of the old oil pipe.

[0153] The corrosion pit depth is less than 30% of the specified wall thickness. There are multiple corrosion pits or uniform corrosion. Although the load-bearing capacity of the old oil pipe has decreased to a certain extent, the internal pressure resistance has decreased by 22%, reaching 102% of the rated value.

[0154] Table 3

[0155]

[0156] Step 2.2.2.3.3: Theoretical analysis of the remaining crush resistance of old oil pipes with multi-point corrosion / uniform corrosion pits;

[0157] The extrusion strength of old oil tubing was calculated using the uniform wall thickness corrosion method, probability distribution method, and uniform corrosion pit distribution method. Table 4 summarizes the theoretical results of multi-point corrosion / uniform corrosion pit impact on the extrusion strength of the tubing. The table shows that the uniform wall thickness corrosion method yields the lowest value, while the probability distribution method's result falls between that of the uniform corrosion pit distribution method. A comparison between the theoretical calculation results and the actual experimental calculation results is shown below. Figure 8 As shown in the figure, the calculation results of the uniform wall thickness corrosion method and the experimental value statistical prediction method (3 sigma) are conservative, while the calculation results of the uniform corrosion pit distribution method are in agreement with the actual experiment. Therefore, it is recommended to use the uniform corrosion pit distribution method to calculate the remaining extrusion strength of the old oil pipe.

[0158] The corrosion pit depth is less than 30% of the specified wall thickness. There are multiple corrosion pits or uniform corrosion. Although the load-bearing capacity of the old oil pipe has decreased to a certain extent, the extrusion strength has decreased by 43%, reaching 60% of the rated value.

[0159] Table 4

[0160]

[0161] Step 2.2.2.4, Comprehensive Analysis and Discussion;

[0162] Due to the complexity of establishing corrosion defect models, the analytical conclusions obtained by different methods vary considerably. The distribution chart of the remaining strength test values ​​and calculated values ​​of the old oil pipe is shown below. Figures 9 to 11 The experimental value statistical prediction method is the most conservative (it can be considered as the limit value), and the uniform distribution method of corrosion pits is in good agreement with the actual experimental values; in this embodiment, the depth of corrosion pits does not exceed 30% of the specified wall thickness. The theoretical analysis and prediction of the remaining strength of the old oil pipe is based on the uniform distribution method of corrosion pits, and the prediction results of the remaining strength are shown in Table 5.

[0163] Table 5

[0164]

[0165] Theoretical analysis results of the residual strength of corroded tubing show that:

[0166] (1) Tensile strength decreased by 21%, reaching 91% of the rated value;

[0167] (2) The internal compressive strength decreased by 22%, reaching 102% of the rated value;

[0168] (3) The crush resistance decreased by 43%, reaching 60% of the rated value;

[0169] Step 2.2.2.5, Conclusions and Recommendations;

[0170] (1) Due to the complexity of the corrosion defect model, the analytical conclusions obtained by different methods are quite different. The uniform distribution method of corrosion pits is in good agreement with the actual experimental values. Therefore, it is recommended to use the uniform distribution method of corrosion pits to predict the remaining strength of old oil pipes in theoretical analysis.

[0171] (2) Theoretical analysis of the remaining strength of old oil pipes with corrosion pit defects shows that if the depth of the corrosion pit does not exceed 30% of the specified wall thickness, it still has a high load-bearing capacity.

[0172] (3) The theoretical analysis results of the residual strength of the corroded oil pipe show that: the corrosion pit depth does not exceed 30% of the specified wall thickness. The tensile strength of the old oil pipe decreases by 21%, reaching 91% of the rated value; the internal pressure strength decreases by 22%, reaching 102% of the rated value; and the extrusion strength decreases by 43%, reaching 60% of the rated value.

[0173] According to an embodiment of the present invention, 1,913 old tubings that were deemed unusable by API Spec 5CT were regenerated to obtain 1,500 secondary tubings. Subsequently, 590 secondary tubings were installed in wells TK677 and TH12204. The installation process was successful and production is currently normal.

[0174] The 590 secondary tubing sections already installed in the well have saved approximately 472,000 yuan in costs, calculated as follows:

[0175] Savings = (New oil pipe 1353 yuan / pipe - Repair cost and residual value 553 yuan / pipe) * 590 pipes = 472,000 yuan.

[0176] According to statistics, 150,000 old oil pipes identified as scrap by API Spec 5CT can be recycled into more than 120,000 secondary oil pipes through the regeneration of this invention, saving 96 million yuan in procurement funds.

[0177] Example 2

[0178] In this embodiment, step 2.3.2, the detection of the undetermined secondary oil pipe, specifically refers to:

[0179] The undetermined secondary tubing identified in steps 2.2 and 2.3.1 is inspected. A new tubing with the same diameter, wall thickness, and material as the secondary tubing is used as a sample tubing, and the process is carried out on the sample tubing. The vertical through hole is used as an artificial defect. An ultrasonic flaw detector is used to test the artificial defect on the sample tube. The sensitivity value displayed by the ultrasonic flaw detector when the intensity of the reflected wave of the artificial defect is equal to 80.5% of its peak value is used as the reference sensitivity. The reference sensitivity is increased by 7dB as the scanning sensitivity.

[0180] Based on the scanning sensitivity, an ultrasonic flaw detector was used to inspect the secondary oil pipe;

[0181] Determine whether the secondary oil pipe meets the requirement that the depth of the corrosion pits is less than 30% of the standard wall thickness. If it does, proceed to step 3; otherwise, it is determined to be a scrapped oil pipe.

[0182] All other settings are the same as in Example 1.

[0183] Example 3

[0184] In this embodiment, the secondary oil pipe inspection in step 2.3.2 specifically refers to:

[0185] The secondary tubing identified in steps 2.2 and 2.3.1 is inspected. A new tubing with the same diameter, wall thickness, and material as the secondary tubing is used as a sample tubing, and the tubing is machined on the sample tubing. The vertical through hole is used as an artificial defect. An ultrasonic flaw detector is used to test the artificial defect on the sample tube. The sensitivity value displayed by the ultrasonic flaw detector when the intensity of the reflected wave of the artificial defect is equal to 79.5% of its peak value is used as the reference sensitivity. The reference sensitivity is increased by 5 dB as the scanning sensitivity.

[0186] Based on the scanning sensitivity, an ultrasonic flaw detector was used to inspect the secondary oil pipe;

[0187] Determine whether the secondary oil pipe meets the requirement that the depth of the corrosion pits is less than 30% of the standard wall thickness. If it does, proceed to step 3; otherwise, it is determined to be a scrapped oil pipe.

[0188] All other settings are the same as in Example 1.

[0189] The above embodiments are only used to illustrate the technical solutions of the present invention, and are not intended to limit them. For those skilled in the art, modifications can be made to the specific technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features. However, these modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the scope of the technical solutions protected by the present invention.

Claims

1. A method for evaluating and regenerating used oil pipes, characterized in that, Includes the following steps: Step 1: Clean and test the full length of the tubing to be repaired, and discard any tubing that fails the test. Step 2 involves visual inspection and preliminary assessment of the qualified oil pipes from Step 1, specifically including: Step 2.1: Conduct a preliminary visual inspection of the qualified oil pipes from Step 1, and designate any oil pipes that are bent or deformed as scrapped oil pipes. Step 2.2: Measure the corrosion defects that cause wall thickness loss in the qualified oil pipes from Step 2.1, and preliminarily classify them into undetermined first-level oil pipes and undetermined second-level oil pipes according to the depth of corrosion pits and the degree of linear axial wear defects. Step 2.3 involves using an ultrasonic flaw detector to perform flaw detection and assessment on the undetermined primary and secondary oil pipes, specifically including: Step 2.3.1, Inspection of the pending primary oil pipe; Perform flaw detection on the undetermined first-level tubing identified in step 2.2 to determine whether the undetermined first-level tubing meets the flaw detection requirements of L2 acceptance level specified in Table C.43 of Clause 10.15 of APISPEC 5CT. If it meets the requirements, it is determined to be a first-level tubing and step 3 is executed. Otherwise, it is determined to be an undetermined second-level tubing and step 2.3.2 is executed. Step 2.3.2, pending secondary oil pipe inspection, specifically includes: Step 2.3.2.1: Inspect the undetermined secondary oil pipes identified in Steps 2.2 and 2.3.

1. Use a new oil pipe with the same diameter, wall thickness and material as the secondary oil pipe as a sample pipe. Process artificial defects on the sample pipe and use an ultrasonic flaw detector to test the artificial defects on the sample pipe to obtain the reference sensitivity. Increase the reference sensitivity by 5-7 dB as the scanning sensitivity. Step 2.3.2.2: Based on the scanning sensitivity, use an ultrasonic flaw detector to inspect the undetermined secondary oil pipe and determine whether the undetermined secondary oil pipe meets the requirement that the depth of the corrosion pits is less than 30% of the standard wall thickness. If it meets the requirement, it is determined to be a secondary oil pipe and step 3 is executed; otherwise, it is determined to be a scrapped oil pipe. Step 3: Repair the threads and replace the couplings of the primary and secondary oil pipes; Step 4: Perform pressure tests on the primary and secondary oil pipes; Step 5: Apply coatings and protective devices to the primary and secondary oil pipes; Step 6: Put the primary and secondary oil pipes back into use, thus completing the oil pipe regeneration.

2. The method according to claim 1, characterized in that, The preliminary classification determination in step 2.2 is as follows: if the depth of the corrosion pits does not exceed 12.5% ​​of the standard wall thickness and there are no linear axial wear defects on the inner wall of the pipe, it is determined to be a first-class pipe pending classification; if the depth of the corrosion pits exceeds 12.5% ​​of the standard wall thickness, but the depth of the corrosion pits is less than 30% of the standard wall thickness, and the linear axial wear defects on the inner wall of the pipe are less than 12.5% ​​of the standard wall thickness, it is determined to be a second-class pipe pending classification; all others are determined to be scrapped pipes.

3. The method according to claim 1, characterized in that, In step 2.3.2.1, the sample tube is machined. The vertical through hole was used as an artificial defect. An ultrasonic flaw detector was used to test the artificial defect on the sample tube. The sensitivity value displayed by the ultrasonic flaw detector when the intensity of the reflected wave of the artificial defect was equal to 80 ± 0.5% of its peak value was used as the reference sensitivity.

4. The method according to claim 1, characterized in that, Step 3 specifically involves: Step 3.1: Thread inspection and judgment; Inspect the corrosion of the factory end threads and field end threads of the primary and secondary oil pipes, as well as the corrosion of the inner and outer surfaces within 300mm of the pipe end. Determine whether there are defects such as rust, sticking, loss of thread continuity, and corrosion pits in the male end threads. If so, cut off the end and re-thread; otherwise, proceed to step 3.

2. Step 3.2, Inspection and judgment of couplings; Determine whether the primary and secondary oil pipes have defects such as rust, sticking, or disruption of thread continuity in the coupling threads, or whether there are corrosion defects or end face damage exceeding the specified depth on the outer surface of the coupling. If so, it is determined that the coupling needs to be replaced; otherwise, proceed to step 3.

3. Step 3.3: Repair the primary and secondary oil pipes and replace the couplings according to the judgment results in Step 3.

2.

5. The method according to claim 4, characterized in that, Step 4 specifically involves: conducting hydrostatic tests on the primary and secondary oil pipes using a hydrostatic test production line and supporting facilities. The test pressure is the hydrostatic test pressure specified in API SPEC 5CT, and the full pressure test state must be maintained for no less than 10 seconds. Determine whether the oil pipe passes the hydrostatic test. If it passes, proceed to step 5; otherwise, it is determined to be a scrapped oil pipe.

6. The method according to claim 5, characterized in that, Step 5 further includes: before applying coatings and protective devices to the primary and secondary oil pipes, inspecting the appearance of the threads to determine whether the pressure test caused thread damage. If so, repair the threads and return to step 4; otherwise, continue with step 5.

7. The method according to any one of claims 1 to 6, characterized in that, Step 5 further includes: marking the primary and secondary oil pipes that have been coated and protected, and marking the marking content includes the name or trademark of the processing plant, steel grade, wall thickness, outer diameter, thread type, hydrostatic test pressure, whether the coupling has been replaced, and oil pipe grade.

8. The method according to claim 1, characterized in that: In step 2.3, the ultrasonic flaw detector has a coverage rate of 120% or higher over the workpiece when it is working, and the signal-to-noise ratio of the ultrasonic flaw detector is greater than 8dB.

9. The method according to claim 1, characterized in that: In step 2.1, the preliminary visual inspection items include: the presence or absence of cracks, fissures, pits, dents, corrosion damage on the inner and outer surfaces, damage to the steel wire rope on the inner and outer surfaces, damage to the slips and pliers on the outer surface, wear on the sucker rod on the inner surface, pipe bending, appearance and threads of the coupling, and damage to the male end threads.

10. The method according to claim 1, characterized in that, In step 6, the primary tubing is used according to the usage method of new tubing; the secondary tubing is used for mechanical pumping wells and electric pump wells, and the strength of the secondary tubing is checked according to 80% of the connection strength of the new tubing body.

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