A method of replacing a water injection well casing lift sub

Abstract

The present application relates to a method for replacing the casing lift sub of a water injection well, comprising calculating the length of the hanging tubing of the hanging packer, blocking the original well tubing, removing the components above the wellhead casing four-way junction and installing the pressure equipment and blowout preventer set, pulling out and removing the tubing hanger, hanging the first tubing using the hanging packer, and sequentially lowering the hanging packer, the second tubing and the plug valve from bottom to top, removing the pressure equipment, the blowout preventer set, the casing four-way junction, the bottom flange and the casing lift sub, replacing the casing lift sub, then installing the casing four-way junction and the bottom flange, installing the blowout preventer set and the pressure equipment, pulling out the plug valve, the second tubing and the hanging packer, installing the tubing hanger, then removing the pressure equipment and the blowout preventer set and installing the components above the casing four-way junction, unblocking the original well tubing, switching wells and resuming water injection. The present application does not require pressure relief, is basically harmless to the reservoir and reduces the number of trips for replacing the lift sub.

Description

TECHNICAL FIELD

[0001] The present application belongs to the field of oil production engineering in the oil industry, and more particularly, to a method for replacing a casing lift sub of a water injection well. BACKGROUND

[0002] During the long-term high-pressure water injection process of an oilfield water injection well, the casing lift sub thread is prone to leakage after being corroded by fluid. Meanwhile, as the injection pressure increases or for the purpose of injecting a displacement agent, acidification, etc., it is necessary to replace the wellhead (including the casing lift sub) with a higher pressure level. For this purpose, there are mainly two existing replacement technologies, as follows:

[0003] One is to stop the injection of the water injection well and release the pressure, and when the pressure of the water injection well is released to zero, the conventional workover equipment is used to remove the wellhead above the casing large four-way cross, the water injection string is pulled out, the wellhead casing large four-way cross, the bottom flange and the casing lift sub are removed, the casing lift sub is replaced, the original wellhead casing large four-way cross and the bottom flange are installed, the water injection string is lowered, and the original wellhead casing large four-way cross above is installed back.

[0004] The other is proposed by Wu Gang et al. in the article "Improvement and popularization of operation technology test in Tuha oilfield" in Inner Mongolia Petrochemical Industry, No. 16, 2014: a horn + packer (Y521 or Y211) + reverse single flow + oil pipe or fishable bridge plug + releasing tool + reverse single flow + oil pipe are used to replace the wellhead, and after releasing, the fishable bridge plug is fished out. Taking a separate injection well as an example, the replacement process of the wellhead (including the casing lift sub) involves: lowering the above bridge plug string to seal the well under pressure, pulling out the releasing string, removing the pressure equipment, removing the wellhead casing large four-way cross, the bottom flange and the casing lift sub, installing the new casing lift sub, installing the original wellhead bottom flange and casing large four-way cross, installing the pressure equipment, lowering the fishing bridge plug string under pressure, pulling out the fished bridge plug string under pressure, which involves pulling and lowering the oil pipe 4 times. If it is a general water injection well, a packer is lowered to plug the original water injection oil pipe, the wellhead casing large four-way cross above is removed, the pressure equipment is installed, the original string is pulled out under pressure, and then the above process of replacing the wellhead (including the casing lift sub) of the separate injection well is performed, and then the water injection string is lowered under pressure, the pressure equipment is removed, and the original wellhead casing large four-way cross above is installed back, which involves pulling and lowering the oil pipe 6 times.

[0005] As can be seen, the first scheme causes a large loss of formation energy and a great damage to the reservoir. Although the second scheme avoids the above problem, it involves many processes (4-6 times of pulling and lowering the oil pipe or string), occupies a long well cycle, has a high construction cost and is not conducive to the control of construction cost. SUMMARY

[0006] In view of the deficiencies of the prior art, the present application aims to provide a new method for replacing the casing lift sub of a water injection well, which can solve the problems of the above-mentioned prior solution one that the formation energy is greatly lost due to pressure relief and the reservoir is greatly damaged, and solution two that the pressurized operation process is long, the well cycle is long, the construction cost is high, and the construction cost control is not conducive.

[0007] To solve the above technical problems, the present application adopts the following technical solutions:

[0008] According to one aspect of the present application, a method for replacing the casing lift sub of a water injection well is provided, which comprises:

[0009] calculating the length of the hanging oil pipe of the hanging leather-hoof packer;

[0010] plugging the original well oil pipe;

[0011] removing the components above the wellhead casing large four-way cross and installing the pressurized equipment and blowout preventer set;

[0012] using the pressurized equipment to cooperate with the workover rig to pull out the oil pipe hanger, removing the oil pipe hanger, using the hanging leather-hoof packer to hang the first oil pipe, pressurizing and lowering the hanging leather-hoof packer, and sequentially lowering the second oil pipe and the closed plug valve above the hanging leather-hoof packer;

[0013] removing the pressurized equipment, the blowout preventer set, the casing large four-way cross, the bottom flange connected with the casing large four-way cross, and the casing lift sub, replacing the casing lift sub, and then passing the casing large four-way cross and the bottom flange from the exposed part of the second oil pipe and installing the casing large four-way cross and the bottom flange;

[0014] installing the blowout preventer set and the pressurized equipment, using the pressurized equipment to cooperate with the workover rig to pull out the closed plug valve, the second oil pipe, and the hanging leather-hoof packer, installing the oil pipe hanger, then removing the pressurized equipment and the blowout preventer set and installing the components above the casing large four-way cross; and

[0015] unplugging the original well oil pipe, switching wells, and resuming water injection.

[0016] In one embodiment of the present application, calculating the length of the hanging oil pipe of the hanging leather-hoof packer comprises:

[0017] obtaining the inner diameter d of the water injection well casing, m; the length h1 of the original well oil pipe, m; the unit length weight k of the original well oil pipe (including the coupling), kg / m; the artificial bottom depth value H, m; the oil supplement distance h2, m; the water injection density ρ L , kg / m 3 ; the steel density ρ S , kg / m 3; measuring the casing pressure value p of the injection well operation, MPa; obtaining the maximum working pressure F of the hanging leather cup packer, MPa; if p≤F is satisfied, then:

[0018] According to formula one: S=3.14 / 4*d 2 , the casing cross-sectional area S is calculated, m 2 ;

[0019] According to formula two: F 上 =980*p*S, the upward force F of the hanging leather cup packer after suspending the oil pipe is calculated, kN 上 ;

[0020] According to formula three: G-F 上 =20kN, the floating weight G of the hanging leather cup packer suspending the oil pipe is calculated, kN; and

[0021] According to formula four: G=k*h*9.8 / 1000*(1-ρ L / ρ S ), the length h of the hanging leather cup packer suspending the oil pipe is calculated, m.

[0022] In an embodiment of the present application, the method is implemented under the condition that H>h+h0+h3+h2, wherein: h0 is the length of the hanging leather cup packer, m; and h3 is the length of the second oil pipe containing the plug valve, m.

[0023] In an embodiment of the present application, the plugging original well pipe comprises:

[0024] The original well pipe is plugged by using a fishable plug or a single flow valve installed on the injection pipe string in the injection well.

[0025] In an embodiment of the present application, the blowout preventer set comprises, from top to bottom, an annular blowout preventer, a working half-ram blowout preventer, a full-ram blowout preventer, a safety slip, and a safety half-ram blowout preventer.

[0026] In an embodiment of the present application, the first oil pipe is suspended by using the hanging leather cup packer, is run in with pressure, and the second oil pipe and the plug valve in the closed state are sequentially run in above the hanging leather cup packer, comprising:

[0027] If h1>h, the first oil pipe is the original well pipe, the original well pipe is suspended by using the hanging leather cup packer, is run in with pressure, and the second oil pipe and the plug valve in the closed state are sequentially run in above the hanging leather cup packer;

[0028] If h1 < h, the length of the first tubing string is taken as the calculated length h. A hanging cup packer is used to hang a tubing string of length h. A tubing string of length h - h1 and a hanging cup packer are run in, and a second tubing string and a closed plug valve are successively run in above the hanging cup packer.

[0029] In one embodiment of the present invention, the second tubing string is a trapezoidal-thread tubing string, and the coupling of the trapezoidal-thread tubing string extends beyond the height of the casing extension joint by no more than 2 m.

[0030] In one embodiment of the present invention, unsealing the original well tubing string, delivering the well, and resuming water injection include:

[0031] Fishing out the retrievable plug, delivering the well, and resuming water injection, or opening the check valve, delivering the well, and resuming water injection.

[0032] According to another aspect of the present invention, there is provided a method for replacing the casing extension joint of an injection well, the method including:

[0033] Calculating the length of the tubing string hung by the hanging cup packer;

[0034] Using a pressure-bearing device in cooperation with a workover rig to run in a first tubing string with a total length equal to the length of the tubing string hung by the hanging cup packer and having a check valve at the end, and the hanging cup packer, and successively running in and installing a second tubing string and a closed plug valve above the hanging cup packer;

[0035] Removing the pressure-bearing device, the blowout preventer group, the casing cross joint, the bottom flange connected to the casing cross joint, and the casing extension joint, replacing the casing extension joint, and then passing the casing cross joint and the bottom flange through the exposed portion of the second tubing string and installing the casing cross joint and the bottom flange; and

[0036] Installing the blowout preventer group and the pressure-bearing device, and using the pressure-bearing device in cooperation with the workover rig to pull out the closed plug valve, the second tubing string, the hanging cup packer, and the connected first tubing string below.

[0037] In one embodiment of the present invention, calculating the length of the tubing string hung by the hanging cup packer includes:

[0038] Obtaining the inner diameter d, m of the casing of the injection well; the length h1, m of the original well tubing string; the unit length weight k (including the coupling) of the original well tubing string, kg / m; the artificial bottom hole depth value H, m; the oil pad distance h2, m; ρ L —the density of the injected water, kg / m 3 ; ρ S —the density of the steel, kg / m 3 ; Measuring the casing pressure value p, MPa during the operation of the injection well; obtaining the maximum working pressure F, MPa of the hanging cup packer; if p ≤ F, then:

[0039] According to Formula One: S = 3.14 / 4*d 2 , the casing cross-sectional area S, m, is calculated 2 ;

[0040] According to Formula Two: F 上 = 980*p*S, the upward force F, kN, that the hanging rubber bowl packer's hanging oil pipe receives is calculated 上 ;

[0041] According to Formula Three: G-F 上 = 20kN, the hanging oil pipe's buoyant weight G, kN, of the hanging rubber bowl packer is calculated; and

[0042] According to Formula Four: G = k*h*9.8 / 1000*(1-ρ L / ρ S ), the length h, m, of the hanging oil pipe of the hanging rubber bowl packer is calculated.

[0043] In an embodiment of the present application, the method is implemented when H>h+h0+h3+h2, wherein in the formula: h0 is the length of the hanging rubber bowl packer, m; and h3 is the length of the second oil pipe containing the plug valve, m.

[0044] In an embodiment of the present application, the second oil pipe is a trapezoidal buckle oil pipe, and the coupling of the trapezoidal buckle oil pipe exceeds the height of the casing lifting sub by no more than 2 m.

[0045] In an embodiment of the present application, the blowout preventer group comprises, from top to bottom, an annular blowout preventer, a working half-block blowout preventer, a full-block blowout preventer, a safety slip, and a safety half-block blowout preventer.

[0046] According to another aspect of the present application, a hanging rubber bowl packer used in the above method is provided, comprising:

[0047] an upper joint, an upper end of the upper joint being provided with an internal right-hand trapezoidal thread and a lower end of the upper joint being provided with an internal right-hand fine thread;

[0048] a steel shaft, an upper end and a lower end of the steel shaft being respectively provided with an external fine thread, an outer side of the steel shaft being provided with a left-hand sawtooth external thread, and the external fine thread of the upper end of the steel shaft being connected with the internal right-hand fine thread of the lower end of the upper joint in a matched manner;

[0049] a slip, an inner side of the slip being provided with a left-hand sawtooth internal thread, an outer side of the slip being provided with a left-hand fine thread, the left-hand sawtooth internal thread of the inner side of the slip being connected with the left-hand sawtooth external thread of the outer side of the steel shaft in a matched manner, the upper joint limiting the slip, and the left-hand fine thread of the outer side of the slip being attached to an inner wall of the casing;

[0050] A hanging groove is arranged at the lower end of the steel shaft, and the slip is rotated into the hanging groove to limit the slip;

[0051] A leather cup assembly is provided with inner right-hand fine thread at the upper end and the lower end, and the inner right-hand fine thread at the upper end of the leather cup assembly is connected with the outer fine thread at the lower end of the steel shaft; and

[0052] A lower joint is provided with outer right-hand fine thread at the upper end and the lower end, and the outer right-hand fine thread at the upper end of the lower joint is connected with the inner right-hand fine thread at the lower end of the leather cup assembly, and the outer right-hand fine thread at the lower end of the lower joint is used for connecting the oil pipe.

[0053] In an embodiment of the present application, the inner side of the steel shaft is provided with a circulating channel.

[0054] In an embodiment of the present application, four longitudinal grooves are arranged on the 360-degree circumference of the outer side of the slip, and one of the four longitudinal grooves is slotted to make the slip an elastic body.

[0055] In an embodiment of the present application, the left-hand sawtooth inner thread at the inner side of the slip and the left-hand sawtooth outer thread at the outer side of the steel shaft have a radial gap therebetween, and the outer diameter of the slip is greater than the inner diameter of the casing to make the slip have a moving amount along the steel shaft in the radial direction.

[0056] In an embodiment of the present application, the leather cup assembly is composed of at least two groups of cup-mouth-down leather cups.

[0057] By adopting the above technical solution, the present application has the following advantages compared with the prior art:

[0058] Compared with the prior scheme one, the present application does not need pressure relief and basically has no damage to the reservoir, and compared with the prior scheme two, under the premise of no pressure relief, for general water injection wells, the number of times of pulling the oil pipe under pressure involving replacement of the lifting nipple is reduced from 6 times to 2 times; for separate injection wells, the number of times of pulling the oil pipe under pressure involving replacement of the lifting nipple is reduced from 4 times to 2 times.

[0059] Different from the ordinary leather cup packer, the hanging leather cup packer in the present application realizes the hanging function, and compared with the ordinary weight-type packer which completes the hanging by the block-type slip extruding into the sleeve wall and engaging, the outer side of the slip in the present application is processed into fine thread, the steel shaft and the sawtooth thread of the slip are matched with each other during setting, the slip is compressed by the steel shaft, an external expansion force is generated, the entire circumferential outer thread of the slip is uniformly attached to the inner wall of the sleeve, the damage to the sleeve is small, and at the same time, the contact area between the slip and the inner wall of the sleeve is large, so the tensile load is high.

[0060] In the field application method of the present application, the lifting nipple of the casing is replaced for 7 well times, the average casing pressure value is 11.75 MPa, and the success rate is 100%. BRIEF DESCRIPTION OF DRAWINGS

[0061] Figure 1 A flow chart of the method for replacing the casing lift sub of the injection well provided by the embodiment of the present application is shown;

[0062] Figure 2 A flow chart of the method for replacing the casing lift sub of the injection well provided by another embodiment of the present application is shown;

[0063] Figure 3 is a longitudinal partial sectional view of the hanging leather cup packer used in the present application;

[0064] Figure 4 is a schematic diagram of the wellhead of the injection well in the embodiment of the present application.

[0065] LIST OF REFERENCE NUMERALS

[0066] 101 step, 102 step, 103 step, 104 step, 105 step, 106 step, 107 step, 201 step, 202 step, 203 step, 204 step, 31 upper joint, 32 steel shaft, 33 slip, 34 hanging groove, 35 leather cup assembly, 36 lower joint, 41 casing large four-way cross, 42 bottom flange, 43 casing lift sub, 44 casing coupling, 45 casing body, 46 casing. DETAILED DESCRIPTION

[0067] It should be understood that the embodiments of the present application shown in the exemplary embodiments are only illustrative. Although only a few embodiments of the present application are described in detail, those skilled in the art can easily appreciate that various modifications are possible without departing from the teachings of the present application subject matter. Accordingly, all such modifications should be included within the scope of the present application. Other substitutions, modifications, changes and omissions can be made to the design, operating conditions and parameters of the following exemplary embodiments without departing from the spirit of the present application.

[0068] As Figure 1 shown, for a general injection well, the present application provides a method for replacing the casing lift sub of the injection well, comprising:

[0069] Step S101: calculating the length of the hanging oil pipe of the hanging leather cup packer;

[0070] Step S102: plugging the original well oil pipe;

[0071] Step S103: removing the components above the wellhead casing large four-way cross and installing the pressure equipment and blowout preventers;

[0072] Step S104: Using a pressurized device in conjunction with a workover rig to pull out the tubing hanger, remove the tubing hanger, suspend the first tubing using a hanging cup packer, lower the hanging cup packer under pressure, and sequentially install the second tubing and a closed plug valve above the hanging cup packer.

[0073] Step S105: Remove the pressurized equipment, the blowout preventer assembly, the casing spool, the bottom flange connected to the casing spool, and the casing raising nipple, replace the casing raising nipple, and then pass the casing spool and the bottom flange through the exposed portion of the second oil pipe and install the casing spool and the bottom flange;

[0074] Step S106: Install the BOP stack and the pressurized equipment. Use the pressurized equipment in conjunction with the workover rig to pull out the closed plug valve, the second tubing, and the suspended cup packer. Install the tubing hanger. Then, remove the pressurized equipment and BOP stack and install the casing components above the large four-way.

[0075] Step S107: Unblock the original well oil pipe, hand over the well and resume water injection.

[0076] In the above step S101, the well history data of the operating well is consulted to obtain the inner diameter of the water injection well casing d, m; the length of the original well tubing h1, m; the unit length weight of the original well tubing k (including couplings), kg / m; the artificial well bottom depth H, m; the oil filling distance h2, m; ρ L —Injection water density, kg / m 3 ρ S —Steel density, kg / m 3 Measure the casing pressure p (MPa) during water injection well operation; obtain the maximum working pressure F (MPa) of the suspended cup packer; if p≤F, then:

[0077] According to formula 1: S = 3.14 / 4*d 2 , calculate the casing cross-sectional area S, m 2 ;

[0078] According to formula 2: F 上 = 980*p*S, calculate the uplift force F on the hanging cup packer after it hangs the tubing 上 , kN;

[0079] According to formula 3: GF 上 = 20kN, calculate the floating weight of the hanging tubing of the hanging cup packer G, kN; and

[0080] According to formula 4: G = k*h*9.8 / 1000*(1-ρ L / ρ S ), and the length of the hanging tubing for the hanging cup packer, h, m, is calculated accordingly.

[0081] In the above method, the calculated length h of the hanging tubing of the hanging packer, the length h0 of the hanging packer, the length h2 of the oil supplement, and the length h3 of the second tubing with the plug valve are summed up and compared with the obtained artificial well bottom depth value H. In the case of H>h+h0+h3+h2, the steps S102, S103, S104, S105, S106 and S107 are continued to be implemented.

[0082] In the above method, the step S102 comprises:

[0083] The working well is moved to the well, the well rig derrick is erected, and the tubing is blocked by the fishable plug. The tubing pressure is uniformly released, and the tubing is observed for 10 minutes. If there is no overflow, it indicates that the blocking is qualified.

[0084] In the above method, the blowout preventer group in the step S103 comprises, from top to bottom, an annular blowout preventer, a working half-blocked blowout preventer, a full-blocked blowout preventer, a safety slip, and a safety half-blocked blowout preventer. In the step S103, the blowout preventer group can be pressure tested according to the well control implementation details of the oilfield company to which the injection well belongs. After the pressure test is qualified, the safety slip is tested and qualified (the test value required by the pressurized equipment is used as the criterion), the blowout line is connected and tested, and the test is qualified according to the well control implementation details of the oilfield company to which the injection well belongs.

[0085] In the above method, the step S104 further comprises:

[0086] If h1>h, the first tubing uses the original well tubing, the original well tubing is suspended by the hanging packer, the hanging packer is lowered under pressure, and the second tubing and the plug valve in the closed state are installed above the hanging packer in sequence;

[0087] If h1<h, the length of the first tubing uses the calculated length h, the tubing with the length h is suspended by the hanging packer, the tubing with the length h-h1 and the hanging packer are lowered, and the second tubing and the plug valve in the closed state are installed above the hanging packer in sequence.

[0088] The above step S104 requires that the coupling of the second tubing exceeds the height of the casing lifting sub by not more than 2m. Then, the tubing is blocked, the well tubing is suspended, and it is observed for 10 minutes without overflow, and the seat is qualified.

[0089] In the above method, step S106 can also be the pressure test step of step S103, that is, the blowout preventer group is pressure tested according to the well control implementation rules of the oilfield company to which the injection well belongs, and after passing the pressure test, the safety slips are tested and passed (the test value required by the equipment under pressure is used as the standard), the blowout pipe line is connected, and the same is pressure tested according to the well control implementation rules of the oilfield company to which the injection well belongs.

[0090] In the above method, step S107 further includes:

[0091] fishing out the fishable plug, crossing the well and resuming water injection; or

[0092] if the original wellbore water injection string is provided with a check valve, opening the check valve, crossing the well and resuming water injection.

[0093] As shown in Figure 2 for separate injection wells, it is emphasized that replacing the casing lift sub is a procedure in the design of measures, and the equipment under pressure and the blowout preventer group have been installed and pressure tested before the procedure is performed. A method for replacing the casing lift sub of an injection well includes:

[0094] Step S201: calculating the length of the hanging tubing of the hanging rubber bowl packer;

[0095] Step S202: using the equipment under pressure to lower the first tubing with a total length of the length of the hanging tubing of the hanging rubber bowl packer and containing a check valve at the end, and the hanging rubber bowl packer into the well with the aid of the workover rig, and sequentially lowering the second tubing and the cock valve in the closed state above the hanging rubber bowl packer;

[0096] Step S203: removing the equipment under pressure, the blowout preventer group, the casing large four-way cross, the bottom flange connected with the casing large four-way cross and the casing lift sub, and replacing the casing lift sub, and then passing the casing large four-way cross and the bottom flange from the exposed part of the second tubing and installing the casing large four-way cross and the bottom flange;

[0097] Step S204: installing the blowout preventer group and the equipment under pressure, and using the equipment under pressure to lift out the cock valve in the closed state, the second tubing, the hanging rubber bowl packer and the first tubing connected thereto with the aid of the workover rig.

[0098] Similarly, in the above step S201 includes:

[0099] Referring to the well history data of the working well, the inner diameter d of the casing of the injection well, the length h1 of the tubing of the original well, the weight per unit length k of the tubing of the original well (including the coupling), the artificial bottom depth value H, the oil supplement distance h2, the density of water ρ L injected, kg / m 3 ; the density of steel ρ S , kg / m 3; measuring the casing pressure value p, MPa, during the injection well operation; obtaining the maximum working pressure F, MPa, of the hanging leather-hoof packer; if p≤F is satisfied, then:

[0100] According to Formula One: S=3.14 / 4*d 2 , the casing cross-sectional area S, m 2 , is calculated.

[0101] According to Formula Two: F 上 =980*p*S, the upward force F, kN, that the hanging leather-hoof packer receives after the hanging oil pipe is calculated. 上

[0102] According to Formula Three: G-F 上 =20kN, the floating weight G, kN, of the hanging leather-hoof packer hanging oil pipe is calculated.

[0103] According to Formula Four: G=k*h*9.8 / 1000*(1-ρ L / ρ S ), the length h, m, of the hanging leather-hoof packer hanging oil pipe is calculated.

[0104] In the above method, the length h of the hanging leather-hoof packer hanging oil pipe, the length h0 of the hanging leather-hoof packer, the oil supplement distance h2, and the length h3 of the second oil pipe with a plug valve are summed up and compared with the obtained artificial bottom hole depth value H, and in the case of H>h+h0+h3+h2, the steps S202, S203, and S204 are continued to be implemented.

[0105] In the above method, in step S202, the second oil pipe is a trapezoidal buckle oil pipe, the coupling of the trapezoidal buckle oil pipe exceeds the casing lifting nipple height by no more than 2m, the oil casing annulus is blocked, the oil pipe in the well is hung, and no overflow is observed for 10 minutes, and the setting is qualified.

[0106] In the above method, in step S204, the blowout preventer group and the pressure equipment are installed, the blowout preventer group is pressure tested according to the well control implementation details of the oilfield company to which the injection well belongs, after the pressure test is qualified, the safety slips are tested and qualified (the test value required by the pressure equipment is used as the standard), the blowout pipe line is connected and tested, and the same is pressure tested according to the well control implementation details of the oilfield company to which the injection well belongs.

[0107] As shown in Figure 3 , a hanging leather-hoof packer used in the above method of the present application comprises:

[0108] an upper joint 31, an upper end of the upper joint 31 being provided with an internal right-hand trapezoidal thread and a lower end of the upper joint being provided with an internal right-hand fine thread;

[0109] ​a steel shaft 32, the upper end and the lower end of the steel shaft 32 are respectively provided with external fine thread, the outer side of the steel shaft 32 is provided with left-handed sawtooth external thread, the external fine thread of the upper end of the steel shaft 32 is matched and connected with the internal right-handed fine thread of the lower end of the upper joint 31;

[0110] a slip 33, the inner side of the slip 33 is provided with left-handed sawtooth internal thread, the outer side of the slip 33 is provided with left-handed fine thread, the left-handed sawtooth internal thread of the inner side of the slip 33 is matched and connected with the left-handed sawtooth external thread of the outer side of the steel shaft 32, the upper joint 31 limits the slip 33, and the left-handed fine thread of the outer side of the slip 33 is attached to the inner wall of the casing;

[0111] a hanging groove 34, which is arranged at the lower end of the steel shaft 32, and the slip 33 is rotated into the hanging groove 34 to limit the slip 33;

[0112] a leather cup assembly 35, the upper end and the lower end of the leather cup assembly 35 are respectively provided with internal right-handed fine thread, the internal right-handed fine thread of the upper end of the leather cup assembly 35 is matched and connected with the external fine thread of the lower end of the steel shaft 32; and

[0113] a lower joint 36, the upper end and the lower end of the lower joint 36 are respectively provided with external right-handed fine thread, the external right-handed fine thread of the upper end of the lower joint 36 is matched and connected with the internal right-handed fine thread of the lower end of the leather cup assembly 35, and the external right-handed fine thread of the lower end of the lower joint 36 is used for connecting the oil pipe.

[0114] In the above-mentioned hanging leather cup packer, the inner side of the steel shaft 32 is provided with a circulating channel.

[0115] In the above-mentioned hanging leather cup packer, four longitudinal grooves are arranged on the 360-degree circumference of the outer side of the slip 33, and one of the four longitudinal grooves is slotted to make the slip 33 an elastic body that can expand and shrink.

[0116] In the above-mentioned hanging leather cup packer, there is a certain radial gap between the left-handed sawtooth internal thread of the inner side of the slip 33 and the left-handed sawtooth external thread of the outer side of the steel shaft 32, and the outer diameter of the slip 33 is slightly larger than the inner diameter of the casing to make the slip 33 have a certain amount of movement along the steel shaft 32 in the radial direction.

[0117] In the above-mentioned hanging leather cup packer, the leather cup assembly 35 is composed of at least two groups of cup-mouth-down leather cups, preferably, as shown in Figure 3 , two groups of cup-mouth-down leather cups are shown to constitute the leather cup assembly 35.

[0118] As shown in Figure 4 , the leather cup assembly 35 is composed of two groups of cup-mouth-down leather cups. Figure 4The schematic diagram of the wellhead of a water injection well in an embodiment of the present invention is shown. The lower end of the casing raising sub 43 is connected to the casing 46 (including the casing coupling 44 and the casing body 45). The upper end of the casing raising sub 43 is connected to the bottom flange 42. The bottom flange 42 is connected to the casing spool 41. The casing spool 41 is equipped with a tubing hanger, and the tubing hanger is connected to the water injection string. The purpose of the present invention is to eliminate the need to relieve pressure in the wellhead and adopt the present invention. Figure 3 The hanging cup packer shown is hung with a corresponding length of tubing to achieve Figure 4 The renewal or replacement of the casing raising nipple 43 shown in FIG.

[0119] The above technical solution of the present invention is described in detail below through specific embodiments.

[0120] Example 1

[0121] The injection well X47 is a general injection well. The water injection string in the well has no check valve, and the 250 wellhead casing lifting short joint is leaking and needs to be replaced. The equipment of the operation team is: 1 XJ-90Z well repair machine and 1 BYJ40 / 14FQ auxiliary skid-mounted non-sufficient well operation equipment.

[0122] Step S101: Check the history of the water injection well: the tubing in the water injection well is D73mm thickened tubing, the length of the original well tubing h1 = 3120m, the inner diameter of the casing is 0.124m, the unit length weight of the original well tubing k (including couplings) = 9.67kg / m, the oil fill distance h2 = 1.7m, the shut-in casing pressure p = 12.5MPa, the artificial well bottom H = 3610m, the maximum working pressure of the hanging cup packer F = 21MPa, the steel density ρ S =7850kg / m 3 ; Injection water density ρ L =1000kg / m 3 .

[0123] According to formula 1: S = 3.14 / 4*d 2 , calculate the casing cross-sectional area S = 1.21*10 -2 m 2 ,

[0124] According to formula 2: F 上 =980*p*S, calculate the uplift force F on the packer after it hangs the tubing 上 =148.23kN;

[0125] According to formula 3: GF 上 = 20kN and formula 4: G = k*h*9.8 / 1000*(1-ρ L / ρ S );

[0126] The length of the hanger tubing of the packer is calculated as h = 2034 m;

[0127] Obviously, H = 3610 m > h + h2+ h3+ h0= 2034 + 1.7 + 9.6 + 1.8 = 2047.1 m, wherein h0is the length of the hanger rubber cup packer, m; h3is the length of the second tubing (including the plug valve), m, and the following steps are performed;

[0128] Step S102: The work well is moved, the well servicing rig mast is erected, and the fishable plug is used to block the tubing; the tubing pressure is uniformly released, and 10 minutes are waited, and it is observed that there is no overflow of the tubing, and then the blocking is qualified;

[0129] Step S103: The wellhead casing large four-way joint above is removed, the pressure equipment and the blowout preventer set (annular blowout preventer, working half-blocked blowout preventer, full-blocked blowout preventer, safety slips and safety half-blocked blowout preventer) are installed, the annular blowout preventer is tested at 21 MPa according to the well control implementation rules of the oilfield company to which the injection well belongs, the safety half-blocked, working half-blocked and full-blocked are respectively tested at 21 MPa, after the testing is qualified, the safety slips are tested at 90 kN, the spurt pipeline is connected and released, the inner spurt pipeline (the pipeline between the casing gate and the spurt pipeline gate) is tested at 21 MPa on site, and the outer spurt pipeline (the pipeline outside the spurt pipeline gate) is tested at 10 MPa on site, and both are qualified;

[0130] Step S104: The tubing hanger is pulled out using the pressure equipment in cooperation with the well servicing rig, and the tubing hanger is removed. Obviously, h1= 3120 m > h = 2034 m, the hanger rubber cup packer is used to hang the original well tubing (i.e. the first tubing), and specifically, the hanger rubber cup packer, the second tubing (ladder-type buckling tubing) and the plug valve (in the closed state) are sequentially lowered from bottom to top; it is required that the second tubing coupling exceeds the height of the elevating nipple by not more than 2 m after the packer seat is sealed, and the packer seat sealing operation is as follows: since the slips 33 are in close contact with the lower end of the upper joint 31, it is ensured that the slips 33 will not be suspended in advance, the pipe string 8-10 is rotated in the positive direction for 8-10 turns, the hanger rubber cup packer slips 33 move downward along the left-handed external thread of the sawtooth thread on the outer surface of the steel shaft 32 to the hanger groove 34, the pipe string is lowered, the slips 33 are radially expanded by the sawtooth thread on the outer surface of the steel shaft 32, and the slips 33 are in close contact with the inner wall of the casing 46, the lower connected pipe string is heavier, and the suspension is tighter, so as to block the tubing casing annulus and suspend the tubing in the well, and it is observed for 10 minutes without overflow, and the seat sealing is qualified;

[0131] Step S105: The pressure equipment (not shown in the figure), the blowout preventer set (not shown in the figure), the casing large four-way joint 41, the bottom flange 42 connected thereto and the casing elevating nipple 43 are removed, a new elevating nipple 43 is replaced, the original wellhead casing large four-way joint 41 and the bottom flange 42 are passed through the exposed part of the second tubing, and the original wellhead casing large four-way joint 41 and the bottom flange 42 are installed;

[0132] Step S106: Install the BOP stack and pressurized equipment. According to step S103, the pressurized equipment and the blowout line are tested for qualified pressure, and the safety slips are tested for qualified lifting. Use the pressurized equipment in conjunction with the workover rig to pull out the plug valve (closed), the second tubing, and the suspended cup packer. Install the tubing hanger, seat the tubing hanger, remove the pressurized equipment and BOP stack, and install the casing above the large spool 41 of the wellhead.

[0133] Step S107: Remove the plug, return the well, and resume water injection.

[0134] Example 2

[0135] The injection well X83 is a general injection well. The water injection pipe in the well has a check valve, and the 250 wellhead casing lifting short joint is leaking and needs to be replaced. The equipment of the operation team is: 1 XJ-90Z well repair machine and 1 BYJ40 / 14FQ auxiliary skid-mounted non-sufficient well operation equipment.

[0136] Step S101: Check the history of the water injection well: the tubing in the water injection well is D73mm thickened tubing, the length of the original well tubing h1 = 3000m, the inner diameter of the casing is 0.121m, the unit length weight of the original well tubing k (including couplings) = 9.67kg / m, the oil fill distance h2 = 3.5m, the shut-in casing pressure p = 13MPa, the artificial well bottom H = 3580m, the maximum working pressure of the hanging cup packer F = 21MPa, the steel density ρ S =7850kg / m 3 ; Injection water density ρ L =1000kg / m 3 .

[0137] According to formula 1: S = 3.14 / 4*d 2 , calculate the casing cross-sectional area S = 1.149*10 -2 m 2 ,

[0138] According to formula 2: F 上 =980*p*S, calculate the uplift force F on the packer after it hangs the tubing 上 =146.42kN;

[0139] According to formula 3: GF 上 = 20kN and formula 4: G = k*h*9.8 / 1000*(1-ρ L / ρ S );

[0140] Calculate the length of the packer hanging tubing h = 2018.5m;

[0141] Obviously, H = 3580 m > h + h2+ h3+ h0= 2018.5 + 3.5 + 9.6 + 1.8 = 2033.4 m, wherein h0 is the length of the hanging rubber cup packer, m; h3 is the length of the second tubing (including the plug valve), m, the following steps are performed;

[0142] Step S102: move to the work well, erect the workover rig mast, use the single flow valve to block the tubing; evenly release the tubing pressure, wait for 10 minutes, and observe that there is no overflow of the tubing, then the blocking is qualified;

[0143] Step S103: remove the wellhead casing large four-way joint above, install the pressure equipment and blowout preventer set (annular blowout preventer, working half-blocked blowout preventer, full-blocked blowout preventer, safety slips and safety half-blocked blowout preventer), according to the well control detailed rules of the oilfield company to which the injection well belongs, test the annular blowout preventer at 21 MPa, the safety half-blocked, working half-blocked and full-blocked are respectively tested at 21 MPa, after the test is qualified, the safety slips are tested at 90 kN, the inner blowout line (the pipeline between the casing gate and the blowout line gate) is tested at 21 MPa on site, and the outer blowout line (the pipeline outside the blowout line gate) is tested at 10 MPa on site, all of which are qualified;

[0144] Step S104: use the pressure equipment to cooperate with the workover rig to pull out the tubing hanger, remove the tubing hanger, obviously, h1 = 3000 m > h = 2018.5 m, use the hanging rubber cup packer to hang the original well tubing (i.e. the first tubing), specifically, sequentially lower the hanging rubber cup packer, the second tubing (ladder-type buckling tubing) and the plug valve (closed state) from bottom to top; it is required that the second tubing coupling exceeds the height of the elevating nipple by not more than 2 m after the packer is sealed, and the packer sealing operation is as follows: since the slips 33 are in close contact with the lower end of the upper joint 31, it is ensured that the slips 33 will not be suspended in advance, the pipe string 8-10 is rotated in the positive direction for 8-10 turns, the slips 33 move downward along the left-handed external thread of the sawtooth thread of the steel shaft 32 to the suspension groove 34, the pipe string is lowered, the slips 33 are radially expanded by the sawtooth thread of the external surface of the steel shaft 32, and the slips 33 are in close contact with the inner wall of the casing 46, the lower connected pipe string is heavier, the suspension is tighter, thereby blocking the tubing casing annulus and suspending the tubing in the well, and after 10 minutes of observation, there is no overflow, and the sealing is qualified.

[0145] Step S105: remove the pressure equipment (not shown in the figure), the blowout preventer set (not shown in the figure), the casing large four-way joint 41, the bottom flange 42 connected thereto and the casing elevating nipple 43, replace the new elevating nipple 43, pass the original wellhead casing large four-way joint 41 and the bottom flange 42 from the exposed part of the second tubing, and install the original wellhead casing large four-way joint 41 and the bottom flange 42;

[0146] Step S106: Install the BOP stack and pressurized equipment. According to step S103, the pressurized equipment and the blowout line are tested for qualified pressure, and the safety slips are tested for qualified lifting. Use the pressurized equipment in conjunction with the workover rig to pull out the plug valve (closed), the second tubing, and the suspended cup packer. Install the tubing hanger, seat the tubing hanger, remove the pressurized equipment and BOP stack, and install the casing above the large spool 41 of the wellhead.

[0147] Step S107: Open the one-way valve, switch wells, and resume water injection.

[0148] Example 3

[0149] The injection well X81 is a general injection well. The water injection string in the well has no check valve. The 250 wellhead casing lifting short joint is leaking and needs to be replaced. The equipment of the operation team is: 1 XJ-90Z well repair machine and 1 BYJ40 / 14FQ auxiliary skid-mounted non-sufficient well operation equipment.

[0150] Step S101: Check the history of the water injection well: the tubing in the water injection well is D73mm thickened tubing, the length of the original well tubing h1 = 1500m, the inner diameter of the casing is 0.124m, the unit length weight of the original well tubing k (including couplings) = 9.67kg / m, the oil fill distance h2 = 2.4m, the shut-in casing pressure p = 12MPa, the artificial well bottom H = 3560m, the maximum working pressure of the hanging cup packer F = 21MPa, and the steel density ρ S =7850kg / m 3 ; Injection water density ρ L =1000kg / m 3 .

[0151] According to formula 1: S = 3.14 / 4*d 2 , calculate the casing cross-sectional area S = 1.21*10 -2 m 2 ,

[0152] According to formula 2: F 上 =980*p*S, calculate the uplift force F on the packer after it hangs the tubing 上 =142.30kN;

[0153] According to formula 3: GF 上 = 20kN and formula 4: G = k*h*9.8 / 1000*(1-ρ L / ρ S );

[0154] The calculated length of the packer hanging tubing is h = 1969m;

[0155] Obviously, H = 3560 m > h + h2+ h3+ h0= 1969 + 2.4 + 9.6 + 1.8 = 1982.8 m, wherein h0—length of the hanging rubber cup packer, m; h3—length of the second tubing (including the plug valve), m, the following steps are performed;

[0156] Step S102: move to the work well, erect the workover rig mast, and seal the tubing using the fishable packer; evenly release the tubing pressure, wait for 10 minutes, and observe that there is no overflow of the tubing, and then the sealing is qualified;

[0157] Step S103: remove the wellhead casing large four-way joint above, install the pressure equipment and blowout preventer set (annular blowout preventer, working half-blocked blowout preventer, full-blocked blowout preventer, safety slips and safety half-blocked blowout preventer), and according to the well control implementation rules of the oilfield company to which the injection well belongs, test the annular blowout preventer at 21 MPa, the safety half-blocked, working half-blocked and full-blocked blowout preventers at 21 MPa respectively, after the test is qualified, the safety slips are tested to be qualified at 90 kN, the inner blowout line (the tubing between the casing gate and the blowout line gate) is tested at 21 MPa on site, and the outer blowout line (the tubing outside the blowout line gate) is tested at 10 MPa on site, and both are qualified;

[0158] Step S104: use the pressure equipment to cooperate with the workover rig to pull out the tubing hanger, and remove the tubing hanger. Obviously, h1= 1500 m < h = 1982.8 m, the first tubing with a hanging length of h = 1982.8 m is used by using the hanging rubber cup packer, and specifically, the h-h1= 482.8 m tubing, the hanging rubber cup packer, the second tubing (ladder-type tubing) and the plug valve (closed state) are sequentially lowered from bottom to top; it is required that the second tubing coupling exceeds the height of the elevating nipple by not more than 2 m after the packer is sealed, and the packer sealing operation is as follows: since the slips 33 are in close contact with the lower end of the upper joint 31, it is ensured that the slips 33 will not be suspended in advance, the pipe string 8-10 is rotated in the positive direction for 8-10 turns, the slips 33 move downward along the left-handed external thread of the sawtooth thread of the steel shaft 32 to the suspension groove 34, the pipe string is lowered, the slips 33 are radially expanded by the sawtooth thread of the external surface of the steel shaft 32, and the slips 33 are in close contact with the inner wall of the casing 46, the lower connected pipe string is heavier, the suspension is tighter, and thus the tubing in the well is sealed, and the tubing is observed for 10 minutes without overflow, and the sealing is qualified;

[0159] Step S105: remove the pressure equipment (not shown in the figure), the blowout preventer set (not shown in the figure), the casing large four-way joint 41, the bottom flange 42 connected thereto and the casing elevating nipple 43, replace the new elevating nipple 43, pass the original wellhead casing large four-way joint 41 and the bottom flange 42 from the exposed part of the second tubing, and install the original wellhead casing large four-way joint 41 and the bottom flange 42;

[0160] Step S106: Install the BOP stack and pressurized equipment. According to step 3, the pressurized equipment and the blowout line are tested for qualified pressure, and the safety slips are tested for qualified lifting. Use the pressurized equipment in conjunction with the workover rig to pull out the plug valve (closed), the second tubing, and the suspended cup packer. Install the tubing hanger, seat the tubing hanger, remove the pressurized equipment and BOP stack, and install the casing above the large spool 41 of the wellhead.

[0161] Step S107: Remove the plug, return the well, and resume water injection.

[0162] Example 4

[0163] The injection well X73, a sub-injection well, needs acidizing construction. The original well 250 wellhead (including casing riser pup joint) is required to be replaced with a 350 wellhead (including casing riser pup joint). The equipment of the operation team is: 1 XJ-90Z well repair rig and 1 BYJ40 / 14FQ auxiliary skid-mounted non-sufficient well operation equipment.

[0164] Step S201: Check the history of the water injection well: the tubing in the water injection well is D73mm thickened tubing, the length of the original well tubing h1 = 3200m, the inner diameter of the casing is 0.124m, the unit length weight of the original well tubing k (including couplings) = 9.67kg / m, the oil fill distance h2 = 5.3m, the shut-in casing pressure p = 11MPa, the artificial well bottom H = 3360m, the maximum working pressure of the hanging cup packer F = 21MPa, the steel density ρ S =7850kg / m 3 ; Injection water density ρ L =1000kg / m 3 .

[0165] According to formula 1: S = 3.14 / 4*d 2 , calculate the casing cross-sectional area S = 1.21*10 -2 m 2 ,

[0166] According to formula 2: F 上 =980*p*S, calculate the uplift force F on the packer after it hangs the tubing 上 =130.44kN;

[0167] According to formula 3: GF 上 = 20kN and formula 4: G = k*h*9.8 / 1000*(1-ρ L / ρ S );

[0168] The calculated length of the packer hanging tubing is h = 1824.7 m;

[0169] Obviously, H = 3560 m > h + h2+ h3+ h0= 1824.7 + 5.3 + 9.6 + 1.8 = 1841.4 m, wherein h0 is the length of the hanging leather-hooped packer, m; h3 is the length of the second tubing (including the plug valve), m, and the following steps are performed;

[0170] Step S202: using the pressure equipment to cooperate with the workover rig to lower: specifically, sequentially lowering the first tubing (including the check valve, the check valve is installed on the last tubing coupling) with the total length h, the hanging leather-hooped packer, the second tubing (i.e. the ladder-type coupling tubing), the plug valve (closed) from bottom to top, the ladder-type coupling tubing coupling exceeds the casing lifting nipple height by no more than 2 m, blocking the oil-casing annulus and suspending the tubing in the well, observing for 10 minutes without overflow, and the setting is qualified;

[0171] Step S203: removing the pressure equipment (not shown in the figure), the blowout preventer group (not shown in the figure), the casing large four-way cross 41, the bottom flange 42 connected thereto and the casing lifting nipple 43, replacing the new lifting nipple 43, passing the new 350 wellhead casing large four-way cross and the bottom flange from the exposed part of the second tubing, and installing the 350 wellhead casing large four-way cross and the bottom flange;

[0172] Step S204: installing the blowout preventer group (annular blowout preventer, working half-blocked blowout preventer, full-blocked blowout preventer, safety slips and safety half-blocked blowout preventer) and the pressure equipment, performing pressure test on the blowout preventer group according to the well control implementation details of the oilfield company to which the injection well belongs, after the pressure test is qualified, the safety slips are tested and qualified (with the test value required by the pressure equipment as the standard), the blowout line is connected and tested, and the same is tested according to the well control implementation details of the oilfield company to which the injection well belongs; using the pressure equipment to cooperate with the workover rig to pull out the plug valve (in the closed state), the second tubing, the hanging leather-hooped packer and the first tubing connected thereto.

[0173] By using the methods of the above embodiments 1-4, the casing lifting nipple 7 is replaced in 7 well times on site, the average casing pressure is 11.75 MPa, and the success rate is 100%.

[0174] As can be seen, compared with the existing scheme one in the background art, the present application does not need to be depressurized and basically does not harm the reservoir, and compared with the existing scheme two, under the premise of not depressurizing, for general injection wells, the number of times of the pressure tubing tripping involving the replacement of the lifting nipple is reduced from 6 times to 2 times; for separate injection wells, the number of times of the pressure tubing tripping involving the replacement of the lifting nipple is reduced from 4 times to 2 times.

[0175] Furthermore, further, compared with the ordinary cup seal packer, the suspension cup seal packer in the application realizes the suspension function, compared with the ordinary heavy packer which realizes the suspension by the block type slip extruding into the casing wall and engaging, the slip outside of the suspension cup seal packer in the application is processed into fine thread, the steel shaft and the slip serrated thread cooperate with each other when setting, the slip is compressed by the steel shaft, the external expansion force is generated, the whole circumference of the slip is uniformly adhered to the casing inner wall, the damage to the casing is small, at the same time, since the contact area between the slip and the casing inner wall is large, the tensile load is high.

[0176] The above merely describes the preferred embodiments of the present application, and is not intended to limit the scope of the present application; if the present application is modified or replaced equivalently without departing from the spirit and scope of the present application, it should be covered in the protection scope of the claims of the present application.

Claims

1. A method of replacing a water injection well casing lift sub, characterized by, For a general injection well, comprising: calculating the length of the hanging tubing of the hanging leather-hoof packer; blocking the original well tubing; removing the components above the casing large four-way cross and installing the equipment under pressure and blowout preventer set; using the equipment under pressure to cooperate with the workover rig to pull out the tubing hanger, and removing the tubing hanger, using the hanging leather-hoof packer to hang the first tubing, lowering the hanging leather-hoof packer under pressure, and sequentially lowering the second tubing and the closed plug valve above the hanging leather-hoof packer, in the case where the length of the original well tubing is greater than the calculated length of the hanging tubing of the hanging leather-hoof packer, the first tubing uses the original well tubing, in the case where the length of the original well tubing is less than the calculated length of the hanging tubing of the hanging leather-hoof packer, the first tubing uses the tubing with a length of the calculated length of the hanging tubing of the hanging leather-hoof packer, lowering the tubing with a length of the difference between the calculated length of the hanging tubing of the hanging leather-hoof packer and the length of the original well tubing and the hanging leather-hoof packer; removing the equipment under pressure, the blowout preventer set, the casing large four-way cross, the bottom flange connected with the casing large four-way cross, and the casing lifting nipple, and replacing the casing lifting nipple, and then passing the casing large four-way cross and the bottom flange from the exposed part of the second tubing and installing the casing large four-way cross and the bottom flange; installing the blowout preventer set and the equipment under pressure, using the equipment under pressure to cooperate with the workover rig to pull out the closed plug valve, the second tubing, and the hanging leather-hoof packer, and installing the tubing hanger, and then removing the equipment under pressure and the blowout preventer set and installing the components above the casing large four-way cross; and unblocking the original well tubing, switching wells, and resuming injection.

2. The method of replacing a water injection well casing lift section of claim 1, wherein, The calculation of the length of the hanging tubing of the hanging leather-hoof packer comprises: Obtain the inner diameter of the water injection well casing d, m; the length of the original well tubing h1, m; the unit length weight of the original well tubing k, kg / m; the artificial well bottom depth H, m; the oil fill distance h2, m; the injected water density ρ L , kg / m 3 ; Steel density ρ S , kg / m 3 Measure the casing pressure p (MPa) during water injection well operation; obtain the maximum working pressure F (MPa) of the suspended cup packer; if p≤F, then: According to formula one: S = 3.14 / 4*d 2 , the casing cross-sectional area S, m 2 ; According to formula two: F 上 980 * p * S, the upward force F received by the hanging tubing behind the hanging skin bowl packer is calculated 上 , kN; According to Equation Three: G - F 上 = 20 kN, calculate the hanging oil pipe float weight G of the hanging skin bowl packer, kN; and According to formula four: G=k*h*9.8 / 1000*(1-ρ L / ρ S ), the length h of the hanging oil pipe of the hanging skin bowl packer is calculated, m.

3. The method of replacing a water injection well casing lift section of claim 2, wherein, The method is implemented in the case where H>h+h0+h3+h2, wherein the formula is: h0— the length of the hanging leather-hoof packer, m; h3— the length of the second tubing containing the plug valve, m.

4. The method of replacing a water injection well casing lift section of claim 1, wherein, The blocking of the original well tubing comprises: blocking the original well tubing using a fishable plug or using a check valve installed on the injection string in the injection well.

5. The method of replacing a water injection well casing lift section of claim 1, wherein, The second tubing is a kelly-buckle tubing, and the coupling of the kelly-buckle tubing exceeds the height of the casing lifting nipple by no more than 2 m.

6. The method of replacing a water injection well casing lift section of claim 4, wherein, The unblocking of the original well tubing, switching wells, and resuming injection comprise: fishing out the fishable plug, switching wells, and resuming injection, or opening the check valve, switching wells, and resuming injection.

7. A method of replacing a water injection well casing lift sub, characterized by, For a separate injection well, the equipment under pressure and the blowout preventer set are installed in advance, pressure testing is in place, comprising: calculating the length of the hanging tubing of the hanging leather-hoof packer; using the equipment under pressure to cooperate with the workover rig to lower the first tubing with a total length of the length of the hanging tubing of the hanging leather-hoof packer and containing a check valve at the end, and the hanging leather-hoof packer, and sequentially lowering the second tubing and the closed plug valve above the hanging leather-hoof packer; The method comprises the following steps: removing the pressure equipment, blowout preventer group, casing large four-way cross, bottom flange connected with the casing large four-way cross and casing lifting short section, replacing the casing lifting short section, then passing the casing large four-way cross and the bottom flange from the second oil pipe exposed part and installing the casing large four-way cross and the bottom flange; and installing the blowout preventer group and the pressure equipment, using the pressure equipment to cooperate with the workover rig to pull out the plug valve, the second oil pipe and the hanging leather cup packer in the closed state and the first oil pipe connected therewith.

8. The method of replacing a water injection well casing lift section of claim 7, wherein, The calculation of the hanging length of the hanging leather cup packer comprises the following steps: obtaining the inner diameter d of the casing of the injection well, m; the length h1 of the original well tubing, m; the weight per unit length k of the original well tubing, kg / m, which includes the coupling; the artificial bottom hole depth value H, m; the oil compensation distance h2, m; the density of the injected water p L , kg / m 3 ; the steel density p S , kg / m 3 ; measuring the casing pressure value p during the injection well operation, MPa; obtaining the maximum working pressure F of the suspended leather cup packer, MPa; if p≤F, then: According to formula one: S = 3.14 / 4*d 2 , the casing cross-sectional area S, m 2 ; According to formula two: F 上 980 * p * S, the upward force F received by the hanging tubing behind the hanging skin bowl packer is calculated 上 , kN; According to Equation Three: G - F 上 = 20 kN, calculate the hanging oil pipe float weight G of the hanging skin bowl packer, kN; and According to formula four: G=k*h*9.8 / 1000*(1-ρ L / ρ S ), the length h of the hanging oil pipe of the hanging skin bowl packer is calculated, m.

9. The method of replacing a water injection well casing lift section of claim 8, wherein, The method is implemented under the condition that H > h + h0 + h3 + h2, wherein, in the formula, h0 is the length of the hanging leather cup packer, m; and h3 is the length of the second oil pipe with the plug valve, m.

10. The method of replacing a water injection well casing lift section of claim 9, wherein, The second oil pipe is a trapezoidal buckle oil pipe, and the coupling of the trapezoidal buckle oil pipe exceeds the height of the casing lifting short section by no more than 2 m.

11. The method of replacing a water injection well casing lift segment of any of claims 1-10, wherein, The used hanging leather cup packer comprises: an upper joint, an upper end of the upper joint is provided with internal right-hand trapezoidal threads, and a lower end of the upper joint is provided with internal right-hand fine tooth threads; a steel shaft, upper and lower ends of the steel shaft are respectively provided with external fine tooth threads, an outer side of the steel shaft is provided with left-hand sawtooth external threads, and the external fine tooth threads of the upper end of the steel shaft are connected with the internal right-hand fine tooth threads of the lower end of the upper joint in a matched mode; a slip, an inner side of the slip is provided with left-hand sawtooth internal threads, an outer side of the slip is provided with left-hand fine tooth threads, the left-hand sawtooth internal threads of the inner side of the slip are connected with the left-hand sawtooth external threads of the outer side of the steel shaft in a matched mode, the upper joint limits the slip, and the left-hand fine tooth threads of the outer side of the slip are attached to the inner wall of a casing; a hanging groove, the hanging groove is arranged at the lower end of the steel shaft, and the slip is rotated into the hanging groove to limit the slip; a leather cup assembly, upper and lower ends of the leather cup assembly are respectively provided with internal right-hand fine tooth threads, and the internal right-hand fine tooth threads of the upper end of the leather cup assembly are connected with the external fine tooth threads of the lower end of the steel shaft in a matched mode; and a lower joint, upper and lower ends of the lower joint are respectively provided with external right-hand fine tooth threads, the external right-hand fine tooth threads of the upper end of the lower joint are connected with the internal right-hand fine tooth threads of the lower end of the leather cup assembly in a matched mode, and the external right-hand fine tooth threads of the lower end of the lower joint are used for connecting an oil pipe.

12. The method of replacing a water injection well casing lift section of claim 11, wherein, An inner side of the steel shaft is provided with a circulating channel.

13. The method of replacing a water injection well casing lift segment of claim 11, wherein, Four longitudinal grooves are arranged on the 360-degree circumference of the outer side of the slip, one of the four longitudinal grooves is slotted so that the slip is an elastic body that can expand and contract.

14. The method of replacing a water injection well casing lift section of claim 11, wherein, The left-hand sawtooth internal threads of the inner side of the slip and the left-hand sawtooth external threads of the outer side of the steel shaft have a radial gap therebetween, and the outer diameter of the slip is greater than the inner diameter of the casing so that the slip has a radial movement amount along the steel shaft.

15. The method of replacing a water injection well casing lift section of claim 11, wherein, The leather cup assembly is composed of at least two groups of bowl-down leather cups.

Images