Well repairing method for in-service salt cavern gas storage

Abstract

The invention belongs to the technical field of salt cavern gas storages, and discloses a well repairing method for an in-service salt cavern gas storage. The well repairing method provided by the embodiment of the invention comprises the following steps: when the salt cavern gas storage is put into operation, adjusting the pressure of the salt cavern, carrying out well killing operation, detecting the leakage condition of a shaft, temporarily separating a new injection and production pipe column from the salt cavern, carrying out sealing performance pressure test detection and the like. Compared with the prior art, the well repair method provided by the embodiment has the advantages that the well repair time is shorter, the operation of the gas injection and production cycle in the current year is not influenced, the additional engineering operation of reinjecting brine into the pipe column is omitted, and the well repair cost is greatly reduced; and meanwhile, the risk of tripping in a new gas injection and production pipe column in non-well-killing operation is avoided, and efficient, safe and high-economic-benefit replacement of the gas injection and production pipe column is achieved.

Description

Technical Field

[0001] The present invention relates to the technical field of salt cavern gas storage, and particularly to a well repair method for an in-service salt cavern gas storage. Background Art

[0002] Salt cavern gas storage is an important deep underground space for storing strategic resources such as natural gas, hydrogen, and petroleum. Salt rock has characteristics such as a tight structure, good sealing performance, large plastic deformation ability, good creep behavior, and damage self-healing, and is a valuable geological resource.

[0003] Due to its own characteristics, when performing well repair operations such as replacing injection and production gas pipes in a salt cavern gas storage, it is impossible to perform a kill operation in the wellbore like in the well repair of an oil and gas reservoir injection and production well. The gas in the reservoir is temporarily blocked by the gravity and viscosity of the kill fluid, so that the wellbore is in a balanced state of no blowout and no leakage for well repair operations. Currently, the conventional well repair method for salt cavern gas storage is: after filling the salt cavern with brine to displace the stored gas, then perform well repair. However, this process needs to consider the injection and production cycle problem, which restricts the normal production and operation of the salt cavern gas storage. In the existing well repair technology, it is necessary to first reduce the salt cavern pressure to the lower limit of the operating pressure, and then fill the salt cavern with brine before subsequent well repair operations can be carried out, which takes a long time and is costly. In addition, during the process of pulling out and running in the injection and production gas pipes, due to no kill operation, there is a risk of well blowout, further increasing the risk of well repair. Therefore, the current well repair technology still has problems such as high well repair safety risks, high engineering costs, and long well repair cycles that need to be solved.

[0004] Based on the above, there is an urgent need for a well repair method for an in-service salt cavern gas storage that can solve the problems existing in the existing well repair technology. Summary of the Invention

[0005] The purpose of the present invention is to provide a well repair method for an in-service salt cavern gas storage, which can shorten the well repair cycle, reduce the well repair cost, and improve the safety and reliability during well repair.

[0006] To achieve this purpose, the present invention adopts the following technical solutions:

[0007] A well repair method for an in-service salt cavern gas storage includes the following steps:

[0008] S10. Adjust the salt cavern pressure of the salt cavern gas storage to a preset pressure, temporarily block the flow channel between the old injection and production gas pipe string and the salt cavern through a first plugging device, and inject kill fluid into the old injection and production gas pipe string for kill operation;

[0009] S20. Detect the liquid level of the annulus protection fluid between the old injection and production gas pipe string and the inner wall of the wellbore, and control the liquid level of the annulus protection fluid at a preset height;

[0010] S30. Open the wellhead and remove the old injection-production gas pipe string from the wellbore.

[0011] S40. Lower the new injection-production gas pipe string to a preset depth in the wellbore, and temporarily block and seal the new injection-production gas pipe string and the wellbore with a second plug, and conduct a pressure test on the annular protection fluid located between the new injection-production gas pipe string and the wellbore.

[0012] S50. After the pressure test is qualified, remove the second plug and the first plug in sequence, and connect the flow channel between the new injection-production gas pipe string and the salt cavity.

[0013] Preferably, step S50 includes the following steps:

[0014] Step S51. When the pressure test result shows that the pressure test is qualified, connect the new injection-production gas pipe string and the salt cavity. When the pressure test result shows that the pressure test is unqualified, go to step S52.

[0015] Step S52. Re-check the sealing performance of the wellbore or the sealing performance between the wellbore and the new injection-production gas pipe string, and cycle the pressure test on the annular protection fluid until the pressure test result shows that the pressure test is qualified.

[0016] Preferably, in step S10, the pressure in the salt cavity of the salt cavern gas storage is adjusted to be below the static liquid column pressure of the kill fluid at the depth of the casing shoe in the wellbore by means of gas injection and production, and the preset pressure is set as the static liquid column pressure of the kill fluid.

[0017] Preferably, in step S10, the pressure in the salt cavity is adjusted to be 0.5 - 1 MPa lower than the static liquid column pressure of the kill fluid.

[0018] Preferably, in step S20, the annular protection fluid is a water-based annular protection fluid or an oil-based protection fluid.

[0019] Preferably, in step S30, during the process of removing the old injection-production gas pipe string from the wellbore, continuously pour the annular protection fluid into the wellbore and maintain it for a preset period of time, so that the fluid entering the wellhead inlet is the same as the fluid output from the wellhead outlet and is the annular protection fluid.

[0020] Preferably, in step S20, the liquid level of the annular protection fluid is flush with the interface of the wellhead.

[0021] Preferably, in step S50, before removing the first plug, displace part of the kill fluid in the new injection-production gas pipe string.

[0022] Preferably, a blowout preventer is provided at the wellhead.

[0023] Preferably, a cable bridge plug is arranged in the old injection-production gas pipe string, and the cable bridge plug is used for temporarily blocking the old injection-production gas pipe string and the salt cavity.

[0024] Compared with the prior art, the beneficial effects of the present invention are as follows:

[0025] The workover method for an in-service salt cavern gas storage provided by the present invention is carried out while the salt cavern gas storage is put into operation. By adjusting the salt cavity pressure, conducting a well killing operation, detecting the leakage of the wellbore, blocking the new injection-production gas pipe string from the salt cavity, and performing a sealing pressure test, etc., the replacement of the old injection-production gas pipe string with the new injection-production gas pipe string is realized. Compared with the related technology, the workover method provided in this embodiment has a shorter workover time, does not affect the annual injection and production gas cycle operation, eliminates the additional engineering operation of injecting brine back into the pipe string, and greatly reduces the workover cost; at the same time, it avoids the risk of lowering the new injection-production gas pipe string without a well killing operation, and realizes the efficient, safe and economically beneficial replacement of the injection-production gas pipe string. Description of the Drawings

[0026] Figure 1 is a flowchart of the workover method for an in-service salt cavern gas storage provided by an embodiment of the present invention;

[0027] Figure 2 is a schematic structural diagram of the workover device provided by an embodiment of the present invention when the old injection-production gas pipe string is not removed;

[0028] Figure 3 is a schematic structural diagram of the workover device provided by an embodiment of the present invention after the tubing hanger is assembled;

[0029] Figure 4 is a schematic structural diagram of the workover device provided by an embodiment of the present invention after the new injection-production gas pipe string is lowered into the wellbore.

[0030] In the figure:

[0031] 100, salt cavern gas storage; 110, salt cavity; 200, old injection-production gas pipe string; 300, well killing fluid; 400, wellhead; 500, annulus protection fluid; 600, new injection-production gas pipe string;

[0032] 1, production casing; 2, wire; 3, first landing nipple; 4, first plug; 5, Christmas tree; 6, blowout preventer; 7, tubing hanger; 8, first packer; 9, second plug; 10, second landing nipple; 11, second packer. Detailed Embodiments

[0033] The present invention will be further described in detail below with reference to the accompanying drawings and embodiments. It can be understood that the specific embodiments described herein are only used to explain the present invention, rather than limiting the present invention. In addition, it should be noted that for the convenience of description, only the parts related to the present invention are shown in the drawings, rather than all the structures.

[0034] In the description of the present invention, unless otherwise clearly defined and limited, the terms "connected", "connected", and "fixed" shall be understood in a broad sense. For example, it may be a fixed connection, a detachable connection, or integrated; it may be a mechanical connection or an electrical connection; it may be directly connected or indirectly connected through an intermediate medium, and it may be the communication inside two components or the interaction relationship between two components. For those of ordinary skill in the art, the specific meanings of the above terms in the present invention can be understood according to specific circumstances.

[0035] In the present invention, unless otherwise clearly defined and limited, the first feature being "above" or "below" the second feature may include the direct contact between the first and second features, or may include the situation where the first and second features are not in direct contact but in contact through other features therebetween. Moreover, the first feature being "above", "over", and "on" the second feature includes the first feature being directly above and obliquely above the second feature, or merely indicating that the horizontal height of the first feature is higher than that of the second feature. The first feature being "below", "under", and "beneath" the second feature includes the first feature being directly below and obliquely below the second feature, or merely indicating that the horizontal height of the first feature is lower than that of the second feature.

[0036] In the description of this embodiment, the orientation or positional relationships such as "above", "below", "right", and "left" are based on the orientation or positional relationships shown in the drawings. It is only for the convenience of description and simplifying the operation, rather than indicating or implying that the device or element referred to must have a specific orientation, be constructed and operated in a specific orientation. Therefore, it should not be construed as a limitation to the present invention. In addition, the terms "first" and "second" are only used for distinction in description and have no special meanings.

[0037] The technical solution provided by the present invention will be introduced below in combination with the accompanying drawings and specific implementation manners.

[0038] This embodiment provides a workover method for an in-service salt cavern gas storage. This method is applicable to the production and operation period of the salt cavity 110 of the salt cavern gas storage 100. In combination with the workover device, it can replace the injection-production gas pipe string while the salt cavity 110 stores gas, so as to complete the efficient workover operation. The specific steps of this method include the following operation steps:

[0039] S10. Adjust the pressure of the salt cavity 110 in the salt cavern gas storage 100 to a preset pressure, temporarily block the flow channel between the old injection-production pipe string 200 and the salt cavity 110 through the first plug 4, and inject a kill fluid 300 into the old injection-production pipe string 200 to perform a well killing operation.

[0040] In this step, the workover device includes a production casing 1. The production casing 1 extends vertically and is located within the wellhead 400. The periphery of the production casing 1 is connected to the salt cavity wall to form a hollow wellbore within the salt cavern gas storage 100. A casing shoe (not shown in the figure) is provided at the bottom of the production casing 1 and at the connection with the salt cavity wall to enhance the sealing performance and installation stability between the production casing 1 and the salt cavity 110. In addition, an old injection-production pipe string 200 is installed within the wellbore, and the bottom of the old injection-production pipe string 200 is communicated with the salt cavity 110. In this embodiment, when the pressure of the salt cavity 110 is greater than the environmental pressure during the workover operation, the pressure of the salt cavity 110 can be adjusted to be below the hydrostatic pressure of the kill fluid 300 at the depth of the casing shoe within the wellbore by means of gas production from the salt cavity 110. The hydrostatic pressure of the kill fluid 300 is set as the above-mentioned preset pressure. Through the above settings, when injecting the kill fluid 300 into the old injection-production pipe string 200 subsequently, the pressure of the salt cavity 110 can be controlled within a range lower than the pressure generated by the liquid column of the kill fluid 300, which helps to avoid blowout phenomena.

[0041] It can be understood that when the pressure of the salt cavity 110 is less than the external environmental pressure, the pressure of the salt cavity 110 can be adjusted to be below the hydrostatic pressure of the kill fluid 300 at the depth of the casing shoe within the wellbore by means of gas injection into the salt cavity 110, and in this way, the effect of controlling the pressure of the salt cavity 110 can also be achieved.

[0042] Subsequently, under pressure, lower the first plug 4 through the wire 2 at the first landing nipple 3 provided at the bottom end of the old injection-production pipe string 200, and the first plug 4 is used to block the flow channel between the old injection-production pipe string 200 and the salt cavity 110. Subsequently, inject the kill fluid 300 into the old injection-production pipe string 200 to perform a well killing operation.

[0043] It should be noted that in this embodiment, after the kill fluid 300 is injected into the old injection-production pipe string 200, the liquid level of the kill fluid 300 needs to be flush with the position of the wellhead 400. When the liquid level of the kill fluid 300 remains at the position flush with the wellhead 400 for a certain period of time, it indicates that there is no leakage risk between the old injection-production pipe string 200 and the salt cavity 110, and the pressure of the kill fluid 300 on the salt cavity 110 is at a qualified level at this time, thus laying a foundation for the subsequent steps.

[0044] Optionally, in step S10, in this embodiment, a cable bridge plug (not shown in the figure) can also be lowered into the old injection-production gas pipe string 200. The cable bridge plug can further block the old injection-production gas pipe string 200 from the salt cavity 110, thereby further reducing the probability that the kill fluid 300 sprays upward from the bottom of the old injection-production gas pipe string 200 and out of the top of the old injection-production gas pipe string 200, which helps to ensure the sealing and safety during the kill operation. In one implementation manner of this embodiment, the cable bridge plug is 2 m higher than the first setting nipple 3.

[0045] Optionally, in this embodiment, when the pressure of the salt cavity 110 is reduced to 0.5 - 1 MPa below the hydrostatic pressure of the kill fluid 300 at the casing shoe in the wellbore, the gas surging phenomenon that occurs when the pressure of the salt cavity 110 is higher than the wellbore pressure can be avoided.

[0046] S20. Detect the liquid level of the annulus protection fluid 500 located between the old injection-production gas pipe string 200 and the inner wall of the wellbore, and control the liquid level of the annulus protection fluid 500 at a preset height.

[0047] The annulus protection fluid 500 is a fluid provided in the wellbore together with the old injection-production gas pipe string 200. The annulus protection fluid 500 can provide certain support pressures for the old injection-production gas pipe string 200 and the inner wall of the wellbore respectively, prevent the inner wall of the wellbore from collapsing, and also prevent the old injection-production gas pipe string 200 from rupturing due to excessive pressure difference between the inner and outer wall surfaces of the old injection-production gas pipe string 200, thereby maintaining the stability of the internal environment of the wellbore.

[0048] In this embodiment, the liquid level of the annulus protection fluid 500 is detected by a liquid level monitor. If it is detected that the liquid level position is not flush with the interface of the wellhead 400, the annulus protection fluid 500 needs to be continuously injected into the annulus area between the old injection-production gas pipe string 200 and the inner wall of the wellbore to lift the liquid level of the annulus protection fluid 500 to a position flush with the interface of the wellhead 400. After stabilizing for a period of time, observe the leakage amount of the annulus protection fluid 500 in the annulus area, and the liquid level drop rate of the annulus protection fluid 500 in the wellbore can also be monitored by the liquid level monitor.

[0049] Optionally, in this embodiment, the ground liquid supply equipment needs to have a liquid supply capacity that provides 1.5 - 2 times the leakage amount.

[0050] Optionally, in this embodiment, in order to reduce costs, the annulus protection fluid 500 can be a conventional and lower-cost water-based or oil-based annulus protection fluid such as brine or polyacrylamide.

[0051] Optionally, in other parallel embodiments, if the leakage volume of the annulus protection fluid 500 is greater than 2 cubic meters per hour, an annulus protection fluid 500 with a plugging function can be selected for well killing operations to plug the leakage points on the inner wall of the wellbore through the annulus protection fluid 500. For example, an annulus protection fluid 500 of types such as high-viscosity gel fluid, cement slurry, etc. that can thicken and solidify at the leakage point position can be selected. This application is not limited thereto, and it can be continuously filled by an automatic filling machine at any time to keep the liquid level of the annulus protection fluid 500 flush with the interface of the wellhead 400, and then the next operation can be performed.

[0052] S30. Open the wellhead 400 and remove the old injection-production gas pipe string 200 from the wellbore.

[0053] In this embodiment, continuously and automatically fill the annulus protection fluid 500 to keep the liquid level of the annulus protection fluid 500 in the wellbore flush with the interface of the wellhead 400. Subsequently, remove the Christmas tree 5 located at the wellhead 400 and install the blowout preventer 6.

[0054] Lift the old injection-production gas pipe string 200 upward out of the wellbore to separate the old injection-production gas pipe string 200 from the fixed pipe on the first packer 8. In this embodiment, the annulus protection fluid 500 and the well killing fluid 300 are different fluids, that is, the well killing fluid 300 uses brine, and the annulus protection fluid 500 is selected as a fluid with a plugging function. During the process of separating the old injection-production gas pipe string 200 from the fixed pipe on the first packer 8, continuously fill the annulus protection fluid 500 into the wellbore and maintain it for a preset period of time so that the fluid entering the inlet of the wellhead 400 and the fluid output from the outlet of the wellhead 400 are both the annulus protection fluid 500.

[0055] Exemplarily, in this embodiment, continuously fill the annulus protection fluid 500 into the wellbore for more than one week, so that the continuously flowing annulus protection fluid 500 can discharge the well killing fluid 300 leaking from the old injection-production gas pipe string 200 out of the wellbore, which is beneficial to maintaining the density of the annulus protection fluid 500 in the wellbore during the workover operation, and further can ensure a better well killing effect and prevent a blowout phenomenon caused by the pressure in the salt cavity 110 being greater than the pressure in the wellbore.

[0056] It should be additionally noted that the dimensions of the new injection-production gas pipe string 600 are the same as those of the old injection-production gas pipe string 200, which helps to match the space in the wellbore.

[0057] S40. Lower the new injection-production gas pipe string 600 into the wellbore to a preset depth, and temporarily block the new injection-production gas pipe string 600 and the wellbore through the second plug 9, and conduct a pressure test on the annulus protection fluid 500 located between the new injection-production gas pipe string 600 and the wellbore.

[0058] During specific implementation, in combination with Figure 3 、 Figure 4As shown, when the new injection-production gas pipe string 600 is installed in the well, it is necessary to continuously inject the annulus protection fluid 500, keep the liquid level of the annulus protection fluid 500 at a position flush with the interface of the wellhead 400, and continue to lower the new injection-production gas pipe string 600 to a preset depth position about 5 - 10 m away from the first packer 8. The specific lowering position of the new injection-production gas pipe string 600 can be determined according to the actual working conditions, so that the bottom depth of the new injection-production gas pipe string 600 is less than the bottom depth of the old injection-production gas pipe string 200 when it is not detached. Subsequently, a tubing hanger 7 is set at the top of the new injection-production gas pipe string 600. The tubing hanger 7 is used to hang the new injection-production gas pipe string 600 in the wellbore and seal the top opening of the new injection-production gas pipe string 600. Subsequently, the blowout preventer 6 is removed and installed into the Christmas tree 5.

[0059] In this embodiment, the workover device further includes a second plug 9. After the Christmas tree 5 is installed in place, the second plug 9 is dropped into the new injection-production gas pipe string 600 and sits in the second setting nipple 10 located at the bottom of the new injection-production gas pipe string 600 to temporarily isolate the new injection-production gas pipe string 600 from the wellbore through the second plug 9, and pressure is applied to set the second packer 11 above the second setting nipple 10 to isolate the wellbore from the bottom salt cavity 110 through the second packer 11. Subsequently, the annulus protection fluid 500 in the annulus area is pressure tested at 10 MPa for 10 min.

[0060] S50. After the pressure test is qualified, the second plug 9 and the first plug 4 are removed in sequence to connect the flow channel between the new injection-production gas pipe string 600 and the salt cavity 110.

[0061] In this embodiment, the bottom end of the new injection-production gas pipe string 600 is connected to the first plug 4 to cut off the flow channel between the new injection-production gas pipe string 600 and the salt cavity 110 through the first plug 4. A coiled tubing is lowered into the new injection-production gas pipe string 600, and nitrogen is continuously injected inward to displace the kill fluid 300 for 50 - 100 m. It should be noted that before the first plug 4 is removed, that is, before the flow channel is opened, part of the kill fluid 300 in the new injection-production gas pipe string 600 can be pumped out, so as to avoid the situation that the pressure difference between the kill fluid 300 in the new injection-production gas pipe string 600 and the annulus protection fluid 500 in the wellbore annulus is too large, resulting in great difficulty in removing the first plug 4.

[0062] When the first plug 4 and the second plug 9 are removed, the flow channel between the new injection-production gas pipe string 600 and the salt cavity 110 is connected, so that the kill fluid 300 in the new injection-production gas pipe string 600 falls into the salt cavity 110, and the wellhead 400 opens the Christmas tree 5 to carry out normal injection-production gas production.

[0063] In this embodiment, the method S50 specifically includes the following operation steps:

[0064] S51. When the pressure test result shows that the pressure test is qualified, it indicates that the new injection-production gas pipe string 600 has good sealing performance. Subsequently, the second plug 9 and the first plug 4 are retrieved, and the salt cavity 110 is connected to the new injection-production gas pipe string 600. When the pressure test result shows that the pressure test is unqualified, proceed to the following step S52;

[0065] S52. Re-check the sealing performance of the wellbore or the sealing performance between the wellbore and the new injection-production gas pipe string 600, and cycle the pressure test on the annulus protection fluid 500 until the pressure test result shows that the pressure test is qualified.

[0066] Optionally, to further prevent out-of-control blowout, whether it is to lower the first plug 4, the second plug 9 or the coiled tubing, a blowout preventer can be additionally configured at the wellhead 400. Thus, before retrieving the first plug 4, the first plug 4 can be fully utilized. Even if the first plug 4 fails, the blowout preventer can prevent blowout, thereby further increasing the safety and reliability of this workover method.

[0067] In summary, the workover method provided in this embodiment is to, while the salt cavity gas storage reservoir is put into operation, replace the old injection-production gas pipe string 200 with the new injection-production gas pipe string 600 under the gas storage condition of the salt cavity 110 through steps such as adjusting the pressure of the salt cavity 110, conducting a kill operation, detecting the leakage of the wellbore, temporarily blocking the new injection-production gas pipe string from the salt cavity 110, and conducting a sealing pressure test. Compared with the related technology, the workover method provided in this embodiment has a shorter workover time (about 1 month), does not affect the annual injection-production gas cycle operation, eliminates the additional engineering operation of injecting brine back into the pipe string, and greatly reduces the workover cost; at the same time, it avoids the risk of lowering the new injection-production gas pipe string 600 without a kill operation, and realizes the efficient, safe and cost-effective replacement of the injection-production gas pipe string.

[0068] In the description of this specification, the descriptions referring to terms such as "some embodiments", "other embodiments", etc. mean that the specific features, structures, materials or characteristics described in connection with the embodiment or example are included in at least one embodiment or example of the present invention. In this specification, the schematic representations of the above terms do not necessarily refer to the same embodiment or example. Moreover, the specific features, structures, materials or characteristics described can be combined in a suitable manner in any one or more embodiments or examples.

[0069] Obviously, the above embodiments of the present invention are merely examples for clearly illustrating the present invention, rather than limitations on the implementation manners of the present invention. For those of ordinary skill in the art, various obvious changes, re-adjustments and substitutions can be made without departing from the protection scope of the present invention. It is not necessary and impossible to enumerate all the implementation manners here. Any modifications, equivalent substitutions and improvements made within the spirit and principle of the present invention shall be included in the protection scope of the claims of the present invention.

Claims

1. A workover method for an in-service salt cavern gas storage reservoir, characterized in that, It includes the following steps: S10. Adjust the pressure of the salt cavity (110) of the salt cavern gas storage (100) to a preset pressure, temporarily block the flow channel between the old injection-production pipe string (200) and the salt cavity (110) through a first plugging device (4), and inject a well-killing fluid (300) into the old injection-production pipe string (200) to perform a well-killing operation; S20. Detect the liquid level of the annulus protection fluid (500) between the old injection-production pipe string (200) and the inner wall of the wellbore, and control the liquid level of the annulus protection fluid (500) at a preset height; S30. Open the wellhead (400) and remove the old injection-production pipe string (200) from the wellbore; S40. Lower a new injection-production pipe string (600) to a preset depth in the wellbore, temporarily block the annulus protection fluid (5) between the new injection-production pipe string (600) and the wellbore through a second plugging device (9), and perform a pressure test on the annulus protection fluid (500) between the new injection-production pipe string (600) and the wellbore; S50. After the pressure test is qualified, remove the second plugging device (9) and the first plugging device (4) in sequence, and connect the flow channel between the new injection-production pipe string (600) and the salt cavity (110).

2. The workover method for an in-service salt cavern gas storage reservoir according to claim 1, characterized in that, Step S50 includes the following steps: Step S51. When the pressure test result shows that the pressure test is qualified, connect the new injection-production pipe string (600) to the salt cavity (110). When the pressure test result shows that the pressure test is unqualified, go to step S52; Step S52. Re-check the tightness of the wellbore or the tightness between the wellbore and the new injection-production pipe string (600), and cycle the pressure test on the annulus protection fluid (500) until the pressure test result shows that the pressure test is qualified.

3. The workover method for an in-service salt cavern gas storage reservoir according to claim 1, characterized in that, In step S10, the pressure of the salt cavity (110) of the salt cavern gas storage (100) is adjusted to be below the hydrostatic pressure of the well-killing fluid (300) at the depth of the casing shoe in the wellbore through the injection and production of gas, and the preset pressure is set to the hydrostatic pressure of the well-killing fluid (300).

4. The workover method for an in-service salt cavern gas storage reservoir according to claim 3, wherein In step S10, adjust the pressure of the salt cavity (110) to be 0.5 - 1 MPa lower than the hydrostatic pressure of the well-killing fluid (300).

5. The workover method for an in-service salt cavern gas storage reservoir according to claim 1, wherein In step S20, the annulus protection fluid (500) is a water-based annulus protection fluid or an oil-based protection fluid.

6. The workover method for an in-service salt cavern gas storage reservoir according to claim 5, characterized in that In step S30, during the process of removing the old injection-production pipe string (200) from the wellbore, continuously pour the annulus protection fluid (500) into the wellbore and maintain it for a preset period of time, so that the fluid entering the inlet of the wellhead (400) is the same as the fluid output from the outlet of the wellhead (400) and is the annulus protection fluid (500).

7. The workover method for an in-service salt cavern gas storage reservoir according to claim 1, wherein In step S20, the liquid level of the annulus protection fluid (500) is flush with the interface of the wellhead (400).

8. The workover method for an in-service salt cavern gas storage described in claim 1, characterized in that, In step S50, before removing the first plugging device (4), displace part of the well-killing fluid (300) in the new injection-production pipe string (600).

9. The workover method for an in-service salt cavern gas storage reservoir according to claim 1, characterized in that, A blowout preventer is provided at the wellhead (400).

10. The workover method for an in-service salt cavern gas storage reservoir according to claim 1, characterized in that, A cable bridge plug is arranged in the old injection-production gas pipe string (200), and the cable bridge plug is used to temporarily block the old injection-production gas pipe string (200) and the salt cavity (110).

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