Method and system for predicting service life of water injection tubular column in corrosive environment

Abstract

The invention discloses a method and system for predicting the service life of a water injection tubular column in a corrosive environment, and belongs to the technical field of oilfield water injection. The prediction method comprises the following steps of: firstly, measuring and calculating resultant force (total amount of a tubular column and unblocking force of a packer) borne by the water injection tubular column during well lifting through a simple method; then, measuring and calculating the axial tension limit load of the water injection tubular column in the corrosive environment, and finally, finding out the minimum positive value obtained by subtracting the axial tension limit load of the water injection tubular column from the resultant force during well lifting by comparing the resultant force and the axial tension limit load when the water injection tubular column lifts the well. The time corresponding to the axial tension limit load is the optimal service life of the water injection tubular column. The prediction method can predict the optimal service life of the water injection tubular column in the corrosion environment, reduce the overhaul risk when the water injection well tubular column is lifted for different oilfield water injection development blocks, and provide a theoretical basis for selecting the optimal service life of the water injection well tubular column, saving the replacement of the tubular column and reducing the production and maintenance cost.

Description

Technical Field

[0001] The invention belongs to the technical field of oilfield development, and relates to a method and a system for predicting the service life of a water injection pipe string in a corrosive environment. Background Art

[0002] At present, most oil fields use water injection to supplement the formation energy for oil production. During the water injection development process, the water injection process string that meets the development needs will be designed according to the depth, temperature, water injection medium and other factors of the development block. During the service process, the process string is often lifted and lowered according to the production needs of the oil field, and the oil pipe is replaced according to the corrosion of the pipe string to ensure that the performance of the pipe string meets the water injection needs. In low permeability oil fields, due to the high mineralization of formation water, the deep burial depth of the development layer system, and the high temperature, the water injection pipe string is severely corroded, affecting the efficient development of the oil field. Replacing the oil pipe too early will increase the one-time investment in oil field development; replacing the oil pipe too late will increase the risk of pipe string breaking and causing major overhaul of the water injection well, and will also increase the investment in overhaul costs.

[0003] At the production site, it is usually judged whether the tubing can continue to be used by directly pulling the water injection string and then observing it. If it can continue to be used, the string will continue to be lowered, and the service time will be determined when the string is pulled next time; if it cannot continue to be used, the service time of the tubing will end now. This method usually relies on the observer to judge whether to replace the tubing. The accuracy of the observer's qualitative judgment is difficult to meet the needs of efficient development of the oil field. A method for quantitatively predicting the optimal service life of the string is needed to assist the production site in the efficient water injection development of the oil field, so as to reduce the water injection development cost during the entire production cycle of the oil field. Summary of the invention

[0004] The purpose of the present invention is to solve the problem that the existing methods for judging whether an oil pipe can continue to be used in the prior art have low accuracy and are difficult to meet the needs of efficient development of oil fields, and to provide a method and system for predicting the service life of a water injection pipe string in a corrosive environment.

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

[0006] The present invention proposes a method for predicting the service life of a water injection string in a corrosive environment, comprising the following steps:

[0007] Obtain the combined force on the water injection string when it is pulled out of the well and the axial tensile limit load of the water injection string in a corrosive environment;

[0008] By comparing the combined force on the water injection string when it is pulled out of the well and the axial tensile limit load of the water injection string under the corrosive environment, the minimum positive value of the force on the water injection pipe is obtained;

[0009] The time corresponding to the minimum positive value of the force on the water injection string is obtained according to the minimum positive value of the force on the water injection string, so as to realize the prediction of the service life of the water injection string.

[0010] Preferably, the resultant force on the water injection string when it is pulled out of the well is obtained as the power F that the operating equipment needs to provide when pulling out the string. 总 ;

[0011] F 总 =F g +F f ;

[0012] Among them, F g is the load generated by the weight of the pipe itself, N; F f is the unsealing force of the packer when it is lifted out of the well, N; the load generated by the weight of the tubing string itself is realized as follows:

[0013] F g =H×L×g

[0014] Wherein, H is the length of the pipe, m; L is the average mass of the pipe per meter, Kg / m; g is the gravity constant.

[0015] Preferably, the axial tensile limit load F of the water injection string in the corrosive environment is n as follows:

[0016] F n =P×A=P×π(Dt)×(tn×K)

[0017] The initial axial tensile limit load of the pipe body is as follows:

[0018]

[0019] Where n is the service life (corrosion time); K is the corrosion rate of the oil field development block, mm / year; P is the specified axial tensile strength of the pipe body, MPa; A is the cross-sectional area of ​​the pipe body, mm 2 ; D is the nominal outer diameter of the tube, mm; t is the nominal wall thickness of the tube, mm; π is the circumference of the tube.

[0020] Preferably, the corrosion rate of the oilfield development block is measured as follows:

[0021] First, among the injection wells in the same reservoir layer, several injection wells in the same batch of production were selected to carry out corrosion rate tests, and the depth, production time, and injection water quality conditions of the test wells were selected to be consistent;

[0022] Secondly, carry out water injection tubing parameter testing, including tubing inner diameter and wall thickness. After the test is completed, obtain the logging results;

[0023] Finally, the average corrosion thickness of the corroded sections of each well was calculated, and the annual average corrosion rate of the same batch of injection wells in this block was obtained based on the average corrosion thickness.

[0024] Preferably, the calculation method of the average corrosion thickness m is as follows:

[0025]

[0026] Among them, d is the inner diameter of the oil pipe after service; r is the wall thickness of the oil pipe after service.

[0027] Preferably, the method for obtaining the annual average corrosion rate of the same batch of water injection wells in this block according to the average corrosion thickness is as follows:

[0028] The average corrosion thickness of each well is summarized and the arithmetic mean is calculated. The arithmetic mean is then divided by the service life of the oil pipes of the batch of water injection wells at the time of testing to obtain the annual average corrosion rate of the same batch of water injection wells in this block.

[0029] Preferably, the inner diameter of the oil pipe is tested by a multi-arm caliper logging method, and the wall thickness of the oil pipe is tested by a magnetic wall thickness logging method.

[0030] The present invention proposes a prediction system for the service life of a water injection pipe string in a corrosive environment, comprising:

[0031] A parameter acquisition module, which is used to obtain the combined force on the water injection string when it is pulled out of the well and the axial tensile limit load of the water injection string in a corrosive environment;

[0032] A parameter calculation module, wherein the parameter calculation module is used to obtain the minimum positive value of the force on the water injection pipe by comparing the resultant force on the water injection pipe when it is pulled out of the well with the axial tensile limit load of the water injection pipe under a corrosive environment;

[0033] A parameter comparison module is used to obtain the time corresponding to the minimum positive value of the force on the water injection string according to the minimum positive value of the force on the water injection string, so as to realize the service life prediction of the water injection string.

[0034] A computer device comprises a memory and a processor, wherein the memory stores a computer program and the processor implements the steps of a method for predicting the service life of a water injection pipe string in a corrosive environment when executing the computer program.

[0035] A computer-readable storage medium stores a computer program, which, when executed by a processor, implements the steps of a method for predicting the service life of a water injection string in a corrosive environment.

[0036] Compared with the prior art, the present invention has the following beneficial effects:

[0037] The present invention proposes a method for predicting the service life of a water injection string in a corrosive environment. First, the resultant force on the water injection string when starting the well is calculated; then, the axial tensile limit load of the water injection string in the corrosive environment is calculated. Finally, by comparing the numerical values ​​of the first two, the minimum positive value of the axial tensile limit load of the water injection string and the resultant force on the well is found. At this time, the time corresponding to the axial tensile limit load is the optimal service life of the water injection string. The prediction method can predict the reasonable use time of the production string of the water injection well in the water injection development block of the oil field with high accuracy, which is conducive to formulating a reasonable service life plan for the water injection string, extending the service life of the water injection string as much as possible, and reducing the cost of replacing the string and checking the string during the whole life cycle of the water injection well; at the same time, it avoids the overhaul problem caused by the corrosion and breakage of the string after the string exceeds the service time plan, reduces the risk of overhaul of the water injection well, and provides a theoretical basis for selecting the optimal service life of the water injection well string, saving string replacement, and reducing production and maintenance costs.

[0038] Furthermore, the depth, production time and injection water quality conditions of the screening test wells are consistent to ensure that the selected test wells are representative of the same batch of production wells in the block.

[0039] The present invention proposes a prediction system for the service life of a water injection string in a corrosive environment, which realizes the prediction of the service life of the water injection string by dividing the system into a parameter acquisition module, a parameter calculation module and a parameter comparison module. The modularization concept is adopted to make each module independent of each other, which is convenient for unified management of each module. BRIEF DESCRIPTION OF THE DRAWINGS

[0040] In order to more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings required for use in the embodiments are briefly introduced below. It should be understood that the following drawings only show certain embodiments of the present invention and therefore should not be regarded as limiting the scope. For ordinary technicians in this field, other related drawings can be obtained based on these drawings without creative work.

[0041] Figure 1 This is a flow chart of the method for predicting the service life of a water injection pipe string in a corrosive environment according to the present invention.

[0042] Figure 2 It is a schematic diagram of the principle of the method for predicting the service life of a water injection pipe string in a corrosive environment according to the present invention.

[0043] Figure 3 This is a system diagram for predicting the service life of the water injection pipe string in a corrosive environment of the present invention. DETAILED DESCRIPTION

[0044] In order to make the purpose, technical solutions and advantages of the embodiments of the present invention clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below in conjunction with the drawings in the embodiments of the present invention. Obviously, the described embodiments are part of the embodiments of the present invention, not all of the embodiments. Generally, the components of the embodiments of the present invention described and shown in the drawings here can be arranged and designed in various different configurations.

[0045] Therefore, the following detailed description of the embodiments of the present invention provided in the accompanying drawings is not intended to limit the scope of the invention claimed for protection, but merely represents selected embodiments of the present invention. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0046] It should be noted that similar reference numerals and letters denote similar items in the following drawings, and therefore, once an item is defined in one drawing, further definition and explanation thereof is not required in subsequent drawings.

[0047] In the description of the embodiments of the present invention, it should be noted that if the terms "upper", "lower", "horizontal", "inner", etc. indicate an orientation or positional relationship based on the orientation or positional relationship shown in the drawings, or the orientation or positional relationship in which the product of the invention is usually placed when in use, it is only for the convenience of describing the present invention and simplifying the description, and does not indicate or imply that the device or element referred to must have a specific orientation, be constructed and operated in a specific orientation, and therefore cannot be understood as a limitation on the present invention. In addition, the terms "first", "second", etc. are only used to distinguish the description, and cannot be understood as indicating or implying relative importance.

[0048] In addition, if the term "horizontal" appears, it does not mean that the component must be absolutely horizontal, but can be slightly tilted. For example, "horizontal" only means that its direction is more horizontal than "vertical", which does not mean that the structure must be completely horizontal, but can be slightly tilted.

[0049] In the description of the embodiments of the present invention, it is also necessary to explain that, unless otherwise clearly specified and limited, the terms "set", "install", "connect", and "connect" should be understood in a broad sense, for example, it can be a fixed connection, a detachable connection, or an integral connection; it can be a mechanical connection or an electrical connection; it can be a direct connection, or it can be indirectly connected through an intermediate medium, or it can be the internal connection of two components. For ordinary technicians in this field, the specific meanings of the above terms in the present invention can be understood according to specific circumstances.

[0050] The present invention is further described in detail below in conjunction with the accompanying drawings:

[0051] The present invention proposes a method for predicting the service life of a water injection string in a corrosive environment. Figure 1 As shown, the following steps are included:

[0052] S1. Obtain the combined force on the water injection string when it is pulled out of the well and the axial tensile limit load of the water injection string in a corrosive environment;

[0053] The resultant force on the water injection string when it is pulled out of the well is obtained as the power F that the operating equipment needs to provide when pulling out the string. 总 ;

[0054] F 总 =F g +F f ;

[0055] Among them, F g is the load generated by the weight of the pipe itself, N; F f is the unsealing force of the packer when it is lifted out of the well, N; the load generated by the weight of the tubing string itself is realized as follows:

[0056] F g =H×L×g

[0057] Wherein, H is the length of the pipe, m; L is the average mass of the pipe per meter, Kg / m; g is the gravity constant.

[0058] Axial tensile limit load F of water injection string in corrosive environment n as follows:

[0059] F n =P×A=P×π(Dt)×(tn×K)

[0060] Among them, n is the service life (corrosion time); K is the corrosion rate of the oil field development block, mm / year. In the newly developed block, refer to the standard of "Water Quality Index and Analysis Method for Water Injection in Clastic Reservoirs" and take 0.076mm / year for prediction; the corrosion rate of the old oil field block is calculated by actual production, testing, etc. to obtain the total amount of corrosion and take the annual average value, and then participate in the calculation; P is the specified axial tensile strength of the pipe body, generally the axial tensile yield strength specified by ISO / API, MPa; A is the cross-sectional area of ​​the pipe body, mm 2 ; D is the nominal outer diameter of the tube, mm; t is the nominal wall thickness of the tube, mm; π is the circumference of the tube.

[0061] The initial axial tensile limit load of the pipe body is as follows:

[0062]

[0063] The corrosion rate of the oilfield development block is measured as follows:

[0064] First, among the injection wells in the same reservoir layer, several injection wells in the same batch of production were selected to carry out corrosion rate tests, and the depth, production time, and injection water quality conditions of the test wells were selected to be consistent;

[0065] Secondly, carry out water injection tubing parameter testing, including tubing inner diameter and wall thickness. After the test is completed, obtain the logging results;

[0066] The inner diameter of the tubing is tested by the multi-arm caliper logging method, and the wall thickness of the tubing is tested by the magnetic wall thickness logging method.

[0067] Finally, the average corrosion thickness of the corroded sections of each well was calculated, and the annual average corrosion rate of the same batch of injection wells in this block was obtained based on the average corrosion thickness.

[0068] The calculation method of average corrosion thickness m is as follows:

[0069]

[0070] Among them, d is the inner diameter of the oil pipe after service; r is the wall thickness of the oil pipe after service; n is the number of sampling points involved in calculating the average corrosion thickness.

[0071] The method for obtaining the annual average corrosion rate of the same batch of injection wells in this block based on the average corrosion thickness is as follows:

[0072] The average corrosion thickness of each well is summarized and the arithmetic mean is calculated. The arithmetic mean is then divided by the service life of the oil pipes of the batch of water injection wells at the time of testing to obtain the annual average corrosion rate of the same batch of water injection wells in this block, that is, K = m / t.

[0073] S2. By comparing the resultant force on the water injection string when it is pulled out of the well with the axial tensile limit load of the water injection string under the corrosive environment, the minimum positive value of the force on the water injection pipe is obtained;

[0074] By comparing the values ​​of the first two, the minimum positive value of the axial tensile limit load of the water injection string minus the resultant force when the well is pulled out is found.

[0075] S3. According to the minimum positive value of the force on the water injection string, the time corresponding to the minimum positive value of the force on the water injection string is obtained to realize the prediction of the service life of the water injection string.

[0076] The following is a detailed analysis with examples:

[0077] Example 1: (Newly developed block)

[0078] Take the water injection pipe string of a newly developed block of a low permeability oil field as an example. The average well depth in this block is between 1500-1900m. The water injection pipe is made of J55 steel grade 2 7 / 8in oil pipe.

[0079] According to the conventional practice in the oil industry, a joint injection well requires one casing packer, and a two-layer injection well requires two packers; the packer uses the Y341 washable well packer, and the release force is generally around 60,000 N. There is no previous corrosion data for this newly developed block, and the corrosion rate is predicted to be 0.076 mm / year with reference to the standard "Water Quality Indicators and Analysis Methods for Water Injection in Clastic Reservoirs".

[0080] like Figure 2 As shown in the figure, the first step is to calculate the main stress conditions of the pipe string:

[0081] By analyzing the stress of the pipe string in the wellbore (buoyancy and friction resistance are negligible), the main stress conditions are as follows:

[0082] F 总 =F g +F f

[0083] Among them, F 总 The power required by the operating equipment when lifting the pipe string, N; F g is the load generated by the weight of the pipe itself, N; F f is the packer release force, N.

[0084] First calculate the tube weight F g Value: The average value of the well depth data of this block is (1500+1900) / 2=1700m, so the length of the pipe string is 1700m. 7 The parameters of the / 8in oil pipe are outer diameter 73.02mm, wall thickness 5.51mm, and unit mass 9.52Kg / m.

[0085] F g =H×L×g=1700×9.52×9.8N=158603N

[0086] Among them, F g is the load generated by the weight of the pipe itself, N; H is the length of the pipe, m; L is the average mass of the pipe per meter, Kg / m; g is the gravity constant, which is 9.8N / Kg.

[0087] Then calculate the main force of the pipe string:

[0088] Combined injection well (1 casing packer):

[0089] F 总合 =F g +F f =158603N+60000N=218603N

[0090] Separate injection well (two-layer separate injection, 2 casing packers):

[0091] F总分 =F g +F f =158603N+2×60000N=278603N

[0092] The second step is to calculate the axial tensile load of the tube:

[0093] After checking API Spec 5CT / ISO 11960, J55 steel grade 2 7 The yield strength of the 8-inch oil pipe is 379-552 MPa, and 379 MPa is used here for calculation; the outer diameter of the oil pipe is 73.02 mm and the wall thickness is 5.51 mm. In the newly developed blocks, the corrosion rate is referenced to the standard of "Water Quality Indicators and Analysis Methods for Water Injection in Clastic Reservoirs", and 0.076 mm / year is used for prediction;

[0094] Axial tensile limit load of the pipe body after n years of service (after corrosion):

[0095] F n =P×A=P×π×[(D-2n×K-(tn×K)]×(tn×K)

[0096] F n =P×A=P×π×(Dtn×K)×(tn×K)

[0097] F n =379×3.1416×(73.02-5.51-n×0.076)×(5.51-n×0.076)

[0098] Among them, F n is the axial tensile limit load of the pipe body after n years of service, N; P is the specified axial tensile strength of the pipe body, generally the axial tensile yield strength specified by ISO / API, MPa; A is the cross-sectional area of ​​the pipe body, mm 2 ; D is the nominal outer diameter of the pipe body, mm; t is the nominal wall thickness of the pipe body, mm; π is the circumference of a circle, which is 3.1416. n is the service life (corrosion time), which is a positive integer, years; K is the corrosion rate of the oilfield development block, mm / year; in the newly developed blocks, refer to the standard "Water Quality Indicators and Analysis Methods for Water Injection in Clastic Reservoirs", and take 0.076mm / year for prediction; the corrosion rate of the old oilfield blocks is calculated by taking the annual average value after obtaining the total amount of corrosion through actual production, testing, etc., and then participating in the calculation.

[0099] In the above formula, if n is a positive integer, then:

[0100] F1=430605.78N F2=418307.35N F3=406008.92N F4=393710.49N

[0101] F5=381412.06N F6=369113.63N F7=356815.20N F8=344516.77N

[0102] F9=332218.35NF 10 =319919.92NF 11 =307621.49NF 12 =295323.06N

[0103] F 13 =283024.63NF 14 =270726.20NF 15 =258427.77NF 16 =246129.34N

[0104] F 17 =233830.91NF 18 =221532.49NF 19 =209234.06NF 20 =196935.63N

[0105] The third step is to determine the optimal service life:

[0106] By comparison, F 18 =221532.49N>F 总合 =218603N>F 19 =209234.06N, indicating that in the newly built block (corrosion rate 0.076mm / year), the optimal service life of the injection string of the combined injection well of about 1700m is 18 years, and the injection string can be successfully pulled out; if it continues to serve for 19 years or even longer, the string is very likely to break when it is pulled up, resulting in a major overhaul of the injection well.

[0107] By comparison, F 13 =283024.63N>F 总分 =278603N>F 14 =270726.20N, indicating that in this newly built block (corrosion rate 0.076mm / year), the optimal service life of the injection string of the injection well of about 1700m is 13 years, at which time the injection string can be successfully pulled out; if it continues to serve for 14 years or even longer, the string is very likely to break when it is pulled up, resulting in a major overhaul of the injection well.

[0108] Example 2: (Old Oil Field)

[0109] Take the water injection pipe string of a low permeability old oil field block as an example. The average well depth in this block is between 2200-2600m. The water injection pipe is made of N80 steel grade 2 7 / 8in oil pipe.

[0110] According to the conventional practice in the oil industry, a joint injection well requires one casing packer, and a two-layer injection well requires two packers; the packer uses the Y341 washable well packer, and the release force is generally around 60,000 N. The corrosion rate of the old oil field block is calculated by obtaining the total amount of corrosion through actual production and testing, and then taking the annual average value for calculation.

[0111] like Figure 2 As shown in the figure, the first step is to calculate the main stress conditions of the pipe string:

[0112] By analyzing the stress of the pipe string in the wellbore (buoyancy and friction resistance are negligible), the main stress conditions are as follows:

[0113] F 总 =F g +F f

[0114] Among them, F 总 The power required by the operating equipment when lifting the pipe string, N; F g is the load generated by the weight of the pipe itself, N; F f is the packer release force, N.

[0115] First calculate the tube weight F g Value: The average value of the well depth data of this block is (2200+2600) / 2=2400m, so the length of the pipe string is 2400m. 7 The parameters of the / 8in oil pipe are outer diameter 73.02mm, wall thickness 5.51mm, and unit mass 9.52Kg / m.

[0116] F g =H×L×g=2400×9.52×9.8N=223910N

[0117] Among them, F g is the load generated by the weight of the pipe itself, N; H is the length of the pipe, m; L is the average mass of the pipe per meter, Kg / m; g is the gravity constant, which is 9.8N / Kg.

[0118] Then calculate the main force of the pipe string:

[0119] Combined injection well (1 casing packer):

[0120] F 总合 =F g +F f =223910N+60000N=283910N

[0121] Separate injection well (two-layer separate injection, 2 casing packers):

[0122] F 总分 =F g +F f =223910N+2×60000N=343910N

[0123] The second step is to calculate the axial tensile load of the tube:

[0124] According to API Spec 5CT / ISO 11960, N80 steel grade 2 7 The yield strength of the 8-in oil pipe is 552-758 MPa, and 552 MPa is taken here for calculation; the outer diameter of the oil pipe is 73.02 mm and the wall thickness is 5.51 mm.

[0125] The corrosion rate was determined as follows:

[0126] Step 1: Determine the service time t of the well pipe in years;

[0127] Step 2: Arrange a logging vehicle to use the "Multi-arm Well Caliber (MIT) + Magnetic Well Logging (MTT) technology" to test the inner diameter d and wall thickness r of the well tubing after service. And record all test point data through logging software.

[0128] Step 3: Compare the inner diameter d and wall thickness r data of each point obtained from the test with the original outer diameter of the oil pipe 73.02mm and wall thickness 5.51mm, and calculate the average corrosion thickness m during the service time t. The specific calculation method is as follows.

[0129]

[0130] Step 4: Calculate the average corrosion rate, K = m / t.

[0131] After testing, the average corrosion rate of the block was found to be 0.1364 mm / year.

[0132] Axial tensile limit load of the pipe body after n years of service (after corrosion):

[0133] F n =P×A=P×π×[(D-2n×K-(tn×K)]×(tn×K)

[0134] F n =P×A=P×π×(Dtn×K)×(tn×K)

[0135] F n =552×3.1416×(73.02-5.51-n×0.076)×(5.51-n×0.076)

[0136] Among them, Fn is the axial tensile limit load of the pipe body after n years of service, N; P is the specified axial tensile strength of the pipe body, generally the axial tensile yield strength specified by ISO / API, MPa; A is the cross-sectional area of ​​the pipe body, mm 2 ; D is the nominal outer diameter of the pipe body, mm; t is the nominal wall thickness of the pipe body, mm; π is the ratio of pi, which is 3.1416. n is the service life (corrosion time), which is a positive integer, years; K is the corrosion rate of the oil field development block, mm / year; the corrosion rate of the old oil field block is calculated by calculating the total amount of corrosion through actual production, testing, etc., and then taking the annual average value, and then participating in the calculation.

[0137] The corrosion rate of old oilfield blocks was measured as follows.

[0138] First, among the injection wells in the same reservoir layer, select 3-5 injection wells from the same batch of production to carry out corrosion rate testing. The depth, production time, injection water quality and other conditions of the screening test wells should be basically the same to ensure that the selected test wells are representative of the same batch of production wells in the block.

[0139] Secondly, the water injection tubing parameter test was carried out, and the test items mainly included the tubing inner diameter and wall thickness. The tubing inner diameter test adopted the multi-arm well caliper logging (MIT) technology series, and the tubing wall thickness adopted the magnetic wall thickness logging (MTT) technology series.

[0140] Finally, after the field test is completed, the well logging results report is completed through the supporting software. According to the well logging report, the maximum corrosion thickness and average corrosion thickness of the main corrosion sections of each well are counted, and then the average corrosion thickness of each well is summarized to calculate the arithmetic mean, and then the arithmetic mean is divided by the service life of the oil pipes of the batch of water injection wells at the time of the test to obtain the annual average corrosion rate of the same batch of water injection wells in this block.

[0141] In the above formula, if n is a positive integer, then:

[0142] F1=613117.07N F2=581180.48N F3=549243.88N F4=517307.29N

[0143] F5=485370.69N F6=453434.10N F7=421497.50N F8=389560.90N

[0144] F9=357624.31NF 10 =325687.71NF 11 =293751.12NF 12 =261814.52N

[0145] The third step is to determine the optimal service life:

[0146] By comparison, F 11 =293751.12N>F 总合 =283910N>F 12 =261814.52N, indicating that in the old oil field block (corrosion rate 0.1364mm / year), the optimal service life of the water injection string of the combined injection well of about 2400m is 11 years, and the water injection string can be successfully pulled out; if it continues to serve for 12 years or even longer, the lifting string is very likely to break, resulting in a major overhaul of the water injection well.

[0147] By comparison, F9=357624.31N>F 总分 =343910N>F 10 =325687.71N, indicating that in the old oilfield block (corrosion rate 0.1364mm / year), the optimal service life of the water injection string of the combined injection well of about 2400m is 9 years, at which time the water injection string can be successfully pulled out; if it continues to serve for 10 years or even longer, the string is very likely to break when it is pulled up, resulting in a major overhaul of the water injection well.

[0148] The present invention proposes a prediction system for the service life of a water injection pipe string in a corrosive environment, such as Figure 3 As shown, it includes a parameter acquisition module, a parameter calculation module and a parameter comparison module;

[0149] The parameter acquisition module is used to obtain the combined force on the water injection string when it is pulled out of the well and the axial tensile limit load of the water injection string in a corrosive environment;

[0150] The parameter calculation module is used to obtain the minimum positive value of the force on the water injection pipe by comparing the combined force on the water injection pipe when it is pulled out of the well with the axial tensile limit load of the water injection pipe under the corrosive environment;

[0151] The parameter comparison module is used to obtain the time corresponding to the minimum positive value of the stress on the water injection string according to the minimum positive value of the stress on the water injection string, so as to realize the service life prediction of the water injection string.

[0152] The terminal device provided in an embodiment of the present invention comprises: a processor, a memory, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, the steps in the above-mentioned method embodiments are implemented. Alternatively, when the processor executes the computer program, the functions of the modules / units in the above-mentioned device embodiments are implemented.

[0153] The computer program may be divided into one or more modules / units, and the one or more modules / units are stored in the memory and executed by the processor to accomplish the present invention.

[0154] The terminal device may be a computing device such as a desktop computer, a notebook, a PDA, a cloud server, etc. The terminal device may include, but is not limited to, a processor and a memory.

[0155] The processor may be a central processing unit (CPU), or other general-purpose processors, digital signal processors (DSP), application-specific integrated circuits (ASIC), field-programmable gate arrays (FPGA) or other programmable logic devices, discrete gate or transistor logic devices, discrete hardware components, etc.

[0156] The memory may be used to store the computer programs and / or modules, and the processor implements various functions of the terminal device by running or executing the computer programs and / or modules stored in the memory and calling the data stored in the memory.

[0157] If the module / unit integrated in the terminal device is implemented in the form of a software functional unit and sold or used as an independent product, it can be stored in a computer-readable storage medium. Based on this understanding, the present invention implements all or part of the processes in the above-mentioned embodiment method, and can also be completed by instructing the relevant hardware through a computer program. The computer program can be stored in a computer-readable storage medium, and the computer program can implement the steps of the above-mentioned various method embodiments when executed by the processor. Among them, the computer program includes computer program code, and the computer program code can be in source code form, object code form, executable file or some intermediate form. The computer-readable medium may include: any entity or device capable of carrying the computer program code, recording medium, U disk, mobile hard disk, disk, optical disk, computer memory, read-only memory (ROM, Read-Only Memory), random access memory (RAM, Random Access Memory), electric carrier signal, telecommunication signal and software distribution medium. It should be noted that the content contained in the computer-readable medium can be appropriately increased or decreased according to the requirements of legislation and patent practice in the jurisdiction. For example, in some jurisdictions, according to legislation and patent practice, computer-readable media do not include electric carrier signals and telecommunication signals.

[0158] The present invention proposes a method for predicting the service life of a water injection string in a corrosive environment. First, a simple method is used to calculate the resultant force on the water injection string when it is pulled out of the well; then, the axial tensile limit load of the water injection string in a corrosive environment is calculated; finally, by comparing the values ​​of the first two, the minimum positive value of the axial tensile limit load of the water injection string minus the resultant force on it when it is pulled out of the well is found. At this time, the time corresponding to the axial tensile limit load is the optimal service life of the water injection string. The service life of the water injection string in a corrosive environment can be predicted, the risk of overhaul when the water injection well string is pulled out of the well is reduced, the success rate of the operation is further improved, and the production and maintenance costs of water injection development oil fields are reduced.

[0159] The above are only preferred embodiments of the present invention and are not intended to limit the present invention. For those skilled in the art, the present invention may have various modifications and variations. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present invention shall be included in the protection scope of the present invention.

Claims

1. A method for predicting the service life of a water injection string in a corrosive environment, characterized in that: The steps include: Obtain the combined force on the water injection string when it is pulled out of the well and the axial tensile limit load of the water injection string in a corrosive environment; By comparing the combined force on the water injection string when it is pulled out of the well with the axial tensile limit load of the water injection string under the corrosive environment, the minimum positive value of the force on the water injection pipe is obtained. The time corresponding to the minimum positive value of the force on the water injection string is obtained according to the minimum positive value of the force on the water injection string, so as to realize the prediction of the service life of the water injection string.

2. The method for predicting the service life of a water injection string in a corrosive environment according to claim 1, characterized in that: The resultant force on the water injection string when it is pulled out of the well is obtained as the power F that the operating equipment needs to provide when pulling out the string. 总 ; F 总 =F g +F f ; Among them, F g is the load generated by the weight of the pipe itself, N; F f is the unsealing force of the packer when it is lifted out of the well, N; the load generated by the weight of the tubing string itself is realized as follows: F g =H×L×g Wherein, H is the length of the pipe, m; L is the average mass of the pipe per meter, Kg / m; g is the gravity constant.

3. The method for predicting the service life of a water injection string in a corrosive environment according to claim 1, characterized in that: The axial tensile limit load F of the water injection string under the corrosive environment n as follows: F n =P×A=P×π(D-t)×(t-n×K) The initial axial tensile limit load of the pipe body is as follows: Where n is the service life (corrosion time); K is the corrosion rate of the oil field development block, mm / year; P is the specified axial tensile strength of the pipe body, MPa; A is the cross-sectional area of ​​the pipe body, mm 2 ; D is the nominal outer diameter of the tube, mm; t is the nominal wall thickness of the tube, mm; π is the circumference of the tube.

4. The method for predicting the service life of a water injection pipe string in a corrosive environment according to claim 3, characterized in that: The corrosion rate of the oilfield development block is measured as follows: First, among the injection wells in the same reservoir layer, several injection wells in the same batch of production were selected to carry out corrosion rate tests, and the depth, production time, and injection water quality conditions of the test wells were selected to be consistent; Secondly, carry out water injection tubing parameter testing, including tubing inner diameter and wall thickness. After the test is completed, obtain the logging results; Finally, the average corrosion thickness of the corroded sections of each well was calculated, and the annual average corrosion rate of the same batch of injection wells in this block was obtained based on the average corrosion thickness.

5. The method for predicting the service life of a water injection string in a corrosive environment according to claim 4, characterized in that: The calculation method of average corrosion thickness m is as follows: Among them, d is the inner diameter of the oil pipe after service; r is the wall thickness of the oil pipe after service.

6. The method for predicting the service life of a water injection string in a corrosive environment according to claim 4, characterized in that: The method for obtaining the annual average corrosion rate of the same batch of injection wells in this block based on the average corrosion thickness is as follows: The average corrosion thickness of each well is summarized and the arithmetic mean is calculated. The arithmetic mean is then divided by the service life of the oil pipes of the batch of water injection wells at the time of testing to obtain the annual average corrosion rate of the same batch of water injection wells in this block.

7. The method for predicting the service life of a water injection string in a corrosive environment according to claim 4, characterized in that: The inner diameter of the tubing is tested by the multi-arm caliper logging method, and the wall thickness of the tubing is tested by the magnetic wall thickness logging method.

8. A prediction system for the service life of a water injection string in a corrosive environment, characterized in that: include: A parameter acquisition module, which is used to obtain the combined force on the water injection string when it is pulled out of the well and the axial tensile limit load of the water injection string in a corrosive environment; A parameter calculation module, wherein the parameter calculation module is used to obtain the minimum positive value of the force on the water injection pipe by comparing the resultant force on the water injection pipe when it is pulled out of the well with the axial tensile limit load of the water injection pipe under a corrosive environment; A parameter comparison module is used to obtain the time corresponding to the minimum positive value of the force on the water injection string according to the minimum positive value of the force on the water injection string, so as to realize the service life prediction of the water injection string.

9. A computer device comprising a memory and a processor, wherein the memory stores a computer program, wherein: When the processor executes the computer program, the steps of the method for predicting the service life of a water injection string in a corrosive environment as described in any one of claims 1 to 7 are implemented.

10. A computer-readable storage medium storing a computer program, characterized in that: When the computer program is executed by a processor, the steps of the method for predicting the service life of a water injection string in a corrosive environment as described in any one of claims 1 to 7 are implemented.

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