Method for replacing annulus well completion fluid of bare hole packer segmented reconstruction pipe column and killing method

Abstract

This invention provides a method for replacing completion fluid in the annulus of an open-hole packer segmented modification tubing string and a well-killing method. The replacement method includes: injecting well-killing fluid into the tubing, with the hydraulic anchor's claws engaging with the casing; removing the production tree and installing a backpressure valve on the tubing hanger; installing a blowout preventer (BOP) assembly; lifting the tubing hanger away from the tubing head sealing surface; closing the annular BOP in the BOP assembly; applying casing pressure to balance the tubing pressure and release the hydraulic anchor; lifting the reinserted sealing tube and suspending the packer to connect the tubing and casing; and injecting well-killing fluid into the tubing to replace the completion fluid between the production tubing and casing. The well-killing method may include replacing the completion fluid between the production tubing and casing using the above-described replacement method, and then circulating the well-killing fluid evenly within the well. This invention saves on operation time and cost; avoids various engineering risks caused by recirculating well-killing fluid after perforating curved tubing in highly deviated well sections; and has a high success rate and wide applicability.

Description

Technical Field

[0001] This invention relates to the field of petroleum exploration and development, and in particular, to a method for replacing completion fluid in the annulus of an open-hole packer segment modification string and a well-killing method. Background Technology

[0002] Open-hole packer staged completion is a key completion technology for highly deviated and horizontal wells. It saves well construction time and costs, has good production enhancement effects, and significant economic benefits, making it widely used in oil and gas exploration and development. The open-hole packer staged completion string includes the open-hole packer string and the return tubing string. A typical open-hole packer string includes a guide shoe + back pressure valve + setting ball seat + differential pressure sleeve + open-hole packer + ball-dropping sleeve + open-hole packer + ... + ball-dropping sleeve + open-hole packer + suspended packer, which is usually completed in the deviated section. A typical return tubing string includes a back-insertion sealing tube + hydraulic anchor + tubing + tubing hanger.

[0003] The process for running open-hole packer segment modification tubing is as follows: The open-hole packer tubing is fed into the drilling fluid using drill pipe; water or KCl solution (approximately 3% KCl aqueous solution) is added to replace the mud in the tubing and open-hole section with water or KCl solution; a ball is dropped to pressurize and set the open-hole packer and the suspended packer. After setting, the formation is isolated by the suspended packer and backpressure valve, preventing formation fluid from flowing into the packer tubing and casing; pressure is continued to disengage the suspended packer from the drill pipe tubing; the drilling fluid is replaced with water and the well is flushed to verify that the open-hole packer tubing and the suspended packer are properly sealed. After confirming well stability, the drill string is retrieved; the reconnecting tubing string is run in, and the reconnecting sealing tube is inserted into the suspended packer. After the reconnecting sealing tube is fully inserted, the tubing string continues to be lowered, with part of the tubing weight pressing down on the suspended packer, while the tubing is simultaneously seated in the tubing head four-way valve. After the open-hole packer segment modification string is run in, the oil and gas wellhead equipment and fracturing wellhead are installed, and fracturing (acidizing) modification construction is carried out; after the modification construction is completed, a fluid drainage test is conducted.

[0004] During open-hole packer staged completion operations, the wellbore contains water or KCl solution during the processes of pulling out the open-hole packer string, sending in the casing string, and running in the return string. If the formation pressure in the oil and gas well is high, water alone cannot control the well. It is essential to rely on downhole suspended packers and backpressure valves to prevent formation fluids from entering the packer string and casing, ensuring well control safety. Therefore, open-hole packer staged completion technology is typically used in low-pressure or atmospheric-pressure oil and gas wells.

[0005] Open-hole packer-modified tubing strings typically do not have circulating sleeves. The tubing and casing are separated by the suspended packer, with no circulation channel, as seen in open-hole packer-modified tubing strings published in patent applications CN201210587438.5, CN201210587439.X, CN201310021213.8, and CN201120264146.9. In wells where open-hole packer-modified tubing has been completed, the annulus between the tubing and casing is filled with clear water. After the modification work is completed, both the differential pressure sleeve and the ball-drop sleeve are in the open position.

[0006] For production needs, such as testing the upper reservoir, replacing the return pipe string, or using the original wellbore for sidetracking, it is necessary to retrieve the return pipe string for well control. For oil and gas wells with low reservoir pressure where clean water can meet the well control requirements, since the tubing and casing are already filled with clean water, well control can be completed simply by filling the tubing with clean water. For oil and gas wells with high reservoir pressure that require a well control fluid with a density higher than clean water, it is necessary to connect the tubing and casing and replace the entire tubing with the well control fluid to achieve well control. Only after well control can the return pipe string be retrieved and other well workover operations be carried out.

[0007] For wells completed with open-hole packer segmented tubing, if a kill fluid with a density higher than that of fresh water is required, the existing solution is to perforate the tubing to connect the tubing and casing, and then circulate the kill fluid for well control. To meet the requirements of circulation kill and prevent solid precipitation of the kill fluid from burying the tubing string, the perforation needs to be as close as possible to the lower end of the tubing string.

[0008] The tubing string is typically run down to highly deviated sections of the well, and the lower tubing is often bent under pressure, posing significant engineering risks for tubing perforation: the perforating gun may deform and become stuck after firing, which is difficult to resolve; the perforating gun is difficult to run to the target well depth, and high perforation positions increase the difficulty of well control and the risk of solidification and sticking of the control fluid; the tubing may bend and adhere to the casing wall, making it susceptible to casing damage during perforation. Existing technologies not only increase the perforation operation steps but also increase engineering risks. Summary of the Invention

[0009] In view of the shortcomings of the prior art, the purpose of this invention is to solve one or more problems existing in the prior art. For example, one objective of this invention is to solve the technical problem of the lack of a circulation kill channel in wells with open-hole packer segmented modification tubing.

[0010] To achieve the above objectives, the present invention provides a method for replacing the annular completion fluid in a segmented modification of an open-hole packer tubing.

[0011] The replacement method may include the following steps: injecting kill fluid into the tubing, with the hydraulic anchor's claws engaging with the casing; removing the production tree and installing a backpressure valve on the tubing hanger; installing a blowout preventer (BOP) assembly; lifting the tubing hanger away from the tubing head sealing surface; closing the annular BOP in the BOP assembly; applying casing pressure to release the hydraulic anchor; removing the backfill sealing tube from the hanging packer to connect the tubing and casing; and injecting kill fluid into the tubing to replace the completion fluid between the production tubing and casing.

[0012] Furthermore, the open-hole packer segment modification string may include: a guide shoe, a backpressure valve, a setting ball seat, a differential pressure sliding sleeve, an open-hole packer, a ball-dropping sliding sleeve, a suspended packer, a back-insertion sealing tube, a hydraulic anchor and tubing, and a tubing hanger, etc. After the modification construction is completed, both the differential pressure sliding sleeve and the ball-dropping sliding sleeve are in the open state; the suspended packer seals the tubing and casing, and the annular space between the tubing and casing is filled with completion fluid.

[0013] Furthermore, the completion fluid is usually water.

[0014] Furthermore, in the step of injecting kill fluid into the tubing, the kill fluid is used to fill the open-hole packer section of the modified tubing and the open-hole section.

[0015] Furthermore, after injecting hydraulic pressure into the tubing to kill the well, the pressure of the liquid column inside the hydraulic anchor is higher than the pressure of the liquid column outside the hydraulic anchor, and the pressure difference between the inside and outside of the hydraulic anchor is less than 14 MPa.

[0016] Furthermore, the blowout preventer assembly may include a switching four-way valve, a double-gate blowout preventer, a single-gate blowout preventer, a shear blowout preventer, and an annular blowout preventer.

[0017] Furthermore, after installing the blowout preventer assembly, the drill pipe is connected to the back pressure valve for blowout preventer pressure testing, wherein the drill pipe is connected to the back pressure valve.

[0018] Furthermore, the blowout preventer pressure test includes: pressure testing of a pipe gate blowout preventer and an annular blowout preventer that match the drill pipe outer diameter. The pipe gate blowout preventer may include the aforementioned double gate blowout preventer or single gate blowout preventer.

[0019] Furthermore, the step of lifting the tubing hook away from the tubing head sealing surface may include: opening the tubing head four-way gate, loosening the tubing hook top screw, activating the annular blowout preventer, slowly lifting the tubing hook, and stopping the lifting when the tubing hook leaves the tubing head sealing surface.

[0020] Furthermore, after the tubing is lifted away from the tubing head sealing surface and before the sleeve pressure is applied, the annular blowout preventer is closed and the tubing head four-way gate is closed.

[0021] Furthermore, applying sleeve pressure to balance the tubing pressure means making the external pressure of the hydraulic anchor greater than the internal pressure. The step of applying sleeve pressure may include: applying pressure to the annulus of the sleeve to cause the hydraulic anchor claws to retract.

[0022] Furthermore, the pressure applied to the casing is 20 MPa to 30 MPa; after the hydraulic anchor is released, the replacement method may also include a depressurization step, depressurizing to a predetermined pressure, such as 14 MPa.

[0023] Furthermore, during or after the installation of the blowout preventer, the replacement method may further include the step of: adjusting the distance between the top surface of the tubing hanger and the annular blowout preventer core to satisfy the following formula: H > H 上提 +H4+H5, where H is the distance between the top surface of the tubing hanger and the rubber core of the annular blowout preventer. 上提 The required lifting height for removing the reinsertion sealing pipe from the suspension packer is the height from the top of the tubing to the point where the reinsertion sealing pipe is lifted from the suspension packer to the wellhead. H4 is the length of the drill pipe back pressure valve, and H5 is the total length of the drill pipe joint and the thickened part of the drill pipe.

[0024] Furthermore, in the step of lifting the drill pipe to remove the reinsertion sealing tube from the suspension packer, the lifting distance of the reinsertion sealing tube can be determined according to the following formula: H 上提 =H1+H2+H3, where H1 is the length of the re-insertion sealing tube inserted into the suspension packer, H2 is the compression distance of the re-insertion tube, and H3 is the tensile length of the tube caused by the clamping force.

[0025] Furthermore, in the step of removing the reinserted sealing tube from the suspended packer, the drill pipe joint does not pass over the annular blowout preventer core.

[0026] Another aspect of the present invention provides a method for completing well control by segmenting the open-hole packer tubing.

[0027] The well control method includes: replacing the completion fluid between the production tubing and the casing by using the open-hole packer segment modification tubing annulus completion fluid replacement method as described above, and then circulating the well control fluid evenly in the well.

[0028] Compared with the prior art, the beneficial effects of the present invention may include at least one of the following:

[0029] (1) This invention can solve the problem of no circulation kill channel in wells completed by open-hole packer segment modification tubing, and avoid the engineering risks of existing technical solutions, such as perforation gun jamming, insufficient perforation depth increasing the difficulty of kill, drilling fluid solid phase precipitation causing stuck drill and damage to perforated casing.

[0030] (2) The present invention can save perforation operation steps, save operation cycle and cost.

[0031] (3) The present invention can avoid various engineering risks caused by recirculation well control after perforating curved tubing in a highly deviated well section.

[0032] (4) During well control operations, the tubing and casing annulus are filled with clean completion fluid (usually water), so the hydraulic anchor and insertion resistance are small. This invention has a high success rate and a wide range of applications. Attached Figure Description

[0033] The above and other objects and features of the present invention will become clearer from the following description taken in conjunction with the accompanying drawings, in which:

[0034] Figure 1 A schematic diagram of the open-hole packer segment modification tubing string and wellhead device of the present invention is shown;

[0035] Figure 2 A schematic diagram of the wellhead device of the present invention is shown.

[0036] Explanation of key figure labels:

[0037] 1-Guiding shoe; 2-Back pressure valve; 3-Setting ball seat; 4-Differential pressure sleeve; 5-Open hole packer; 6-Pitching sleeve; 7-Suspended packer; 8-Return sealing pipe; 9-Hydraulic anchor; 10-Tubing; 11-Casing; 12-Tubing hanger; 13-Tubing head four-way; 131-Casing gate valve; 132-Tubing hanger top screw; 14-Oil and gas tree; 15-Converter four-way; 16-Double gate blowout preventer; 17-Single gate blowout preventer; 18-Shear gate blowout preventer; 19-Annular blowout preventer; 191-Annular blowout preventer rubber core; 20-Rising flange; 21-Back pressure valve; 22-Drill pipe; 221-Drill pipe joint; 222-Thickened part of drill pipe. Detailed Implementation

[0038] The following description, in conjunction with the accompanying drawings and exemplary embodiments, details the present invention's method for replacing completion fluid in the annulus of a segmented modified open-hole packer string and its method for killing the well.

[0039] Exemplary Example 1

[0040] Figure 1 A schematic diagram of the open-hole packer segment modification string and wellhead device of the present invention is shown. Figure 2 A schematic diagram of the wellhead device of the present invention is shown. The following is in conjunction with... Figure 1 and Figure 2 This invention describes a method for replacing the annular completion fluid in a segmented modification of an open-hole packer tubing.

[0041] The method includes the following steps:

[0042] S01: Hydraulic well for well control, where hydraulic anchors are injected into the tubing and the anchor claws engage with the casing.

[0043] In this embodiment, the kill fluid density can be selected according to the formation pressure, and kill fluid can be injected into the tubing 10 to fill the open hole packer 5 section of the modified tubing string and the open hole section. Because the kill fluid density is higher than the completion fluid density, the fluid column pressure inside the hydraulic anchor 9 is higher than the fluid column pressure outside the hydraulic anchor 9, and the anchor claws of the hydraulic anchor 9 engage with the casing 11.

[0044] In this embodiment, because open-hole packer staged completion technology is commonly used in low-pressure or atmospheric-pressure oil and gas wells, the kill fluid density is usually low, but higher than the completion fluid density. Therefore, after the kill fluid is injected from the tubing 10, the internal fluid column pressure of the hydraulic anchor 9 is higher than the external fluid column pressure, and the pressure difference is usually less than 14 MPa. For example, in a certain open-hole packer staged completion, the return tubing is completed to a depth of 5000m (vertical depth), and the density inside the tubing is 1.25 g / cm³. 3 In a hydraulic well kill operation, the pressure difference between the internal and external hydraulic columns of the hydraulic anchor 9 is 12.3 MPa (the internal hydraulic column pressure is 12.3 MPa higher than the external hydraulic column pressure). Applying 14 MPa to the casing can release the hydraulic anchor constraint.

[0045] S02: Remove the tree and install a back pressure valve on the tubing.

[0046] In this embodiment, after the well-killing fluid is injected into the tubing, the production tree 14 is removed, and a back pressure valve (also known as a drill string back pressure valve or drill pipe back pressure valve) 21 is installed on the tubing hanger 12. The back pressure valve 21 prevents the kill fluid from flowing out of the tubing 10. The suspended packer seals the annular space between the tubing and the casing, preventing formation fluid from entering the casing above the suspended packer. Furthermore, the tubing hanger 12 and the casing gate valve (also known as a casing gate valve) 131 control the completion fluid (such as water) to flow out of the casing 11, ensuring well control safety.

[0047] S03: Install the blowout preventer assembly.

[0048] In this embodiment, the blowout preventer (BOP) assembly may include a four-way valve 15, a double-gate BOP 16, a single-gate BOP 17, a shear gate BOP 18, and an annular BOP 19. The BOP assembly can be selected according to well control requirements.

[0049] S04: Adjust the distance between the top surface of the oil pipe hanger and the rubber core of the annular blowout preventer.

[0050] In the subsequent step of lifting the reinserted sealing tube 8 out of the suspended packer 7, the required lifting height needs to be determined according to formula (1).

[0051] H 上提 =H1+H2+H3(1)

[0052] In the formula: H 上提H1 is the required upward elevation of the reinforcing sealing tube 8 to support the suspended packer 7, in meters; H2 is the length of the reinforcing sealing tube 8 inserted into the suspended packer 7, in meters; H3 is the compression distance of the reinforcing tube, in meters; and H4 is the tensile length of the tube caused by the clamping force, in meters.

[0053]

[0054] Where F is the resistance force on the hydraulic anchor 9 and the reinserted sealing pipe 8, and its value is 100×10. 3 N~150×10 3 N;L i The length of the i-th specification tubing in the return tubing string, in meters; A i Let m be the cross-sectional area of ​​the i-th specification of tubing in the return tubing string. 2 E is the elastic modulus of steel, 206 × 10⁻⁶. 9 Pa.

[0055] In order to lift the drill pipe and remove the back-insertion sealing tube 8 from the suspended packer 7 without the drill pipe joint passing over the annular blowout preventer rubber core 191, the distance H between the top surface of the tubing hanger 12 and the annular blowout preventer rubber core 191 needs to be adjusted to meet the following requirements:

[0056] H > H 上提 +H4+H5 (2)

[0057] H is the height of the annular blowout preventer core 191 on the top surface of the tubing hanger 12, in meters; H4 is the length of the drill pipe backpressure valve 21, in meters; H5 is the total length of the drill pipe joint 221 and the thickened part of the drill pipe 222, in meters.

[0058] Normally, if the distance H between the annular blowout preventer rubber core 191 on the top surface of the oil pipe hanger 12 does not meet the requirements of equation (2), then the lifting flange 20 is used to increase the distance H between the annular blowout preventer rubber core 191 on the top surface of the oil pipe hanger 12 so that it meets the requirements of equation (2).

[0059] S05: Connect drill pipe 22 to back pressure valve 21 and perform blowout preventer pressure test. The drill pipe is connected to the back pressure valve.

[0060] In this embodiment, the blowout preventer pressure test includes testing the corresponding pipe gate blowout preventer and the annular blowout preventer to ensure they pass the pressure test.

[0061] S06: Lift the oil pipe away from the sealing surface of the oil pipe head.

[0062] In this embodiment, the step may specifically include: opening the tubing head four-way gate valve (i.e., casing gate valve 131), loosening the tubing hanger top screw 132, opening the annular blowout preventer 19, slowly lifting the drill pipe 22, and stopping the lifting of the drill pipe 22 when the tubing hanger 12 leaves the sealing surface of the tubing head four-way valve 13.

[0063] S07: Close the annular blowout preventer in the blowout preventer assembly; apply sleeve pressure to make the external pressure of the hydraulic anchor greater than the internal pressure, and release the hydraulic anchor anchoring.

[0064] In this embodiment, the step may specifically include: closing the annular blowout preventer 19, closing the casing gate 131, applying a pressure of 20MPa to 30MPa to the casing annulus 11 to cause the hydraulic anchor 9 to retract its claws, and then depressurizing (i.e. depressurizing the casing) to a predetermined pressure, such as 14MPa.

[0065] S08: Pull out the reinserted sealing tube and hang the packer to connect the tubing and casing.

[0066] In this embodiment, the step may specifically include: maintaining the casing pressure at a predetermined pressure (e.g., 14 MPa), slowly raising the drill pipe 22 with the annular blowout preventer 19 closed, causing the re-insertion sealing tube 8 to disengage from the suspension packer 7, connecting the tubing 10 to the casing 11, at which point the pointers of the string weight gauge and the casing pressure gauge show significant fluctuations; if the raising distance reaches H... 上提 If the reinserted sealing tube 8 does not disengage from the suspension packer 7, then the lifting stops, and a higher pressure, such as 25 MPa, is applied to the sleeve to release the hydraulic anchor 9 constraint and cause the reinserted sealing tube 8 to disengage from the suspension packer 7 and reconnect to the sleeve.

[0067] S09: Inject kill fluid into the tubing to replace the completion fluid between the production tubing and the casing.

[0068] In this embodiment, the step may specifically include: after the tubing 10 is connected to the casing 11, inject kill fluid into the tubing 10 to replace the completion fluid between the tubing 10 and the casing 11, such as water.

[0069] Exemplary Example 2

[0070] This exemplary embodiment provides a method for completing well control using a segmented modification string with an open-hole packer.

[0071] The well control method may include the steps in Exemplary Example 1, and after displacing the completion fluid between the tubing 10 and the casing 11, the well control operation is completed by circulating the well control fluid evenly in the well.

[0072] Exemplary Example 3

[0073] This exemplary embodiment provides a method for completing well control using a segmented modification string with an open-hole packer.

[0074] The method involves injecting kill fluid into the tubing, then raising the tubing string under pressure, and pulling out the reinserted sealing pipe to suspend the packer to connect the tubing and casing for circulating kill.

[0075] Specifically, the method may include the following steps: injecting hydraulic fluid into the tubing for well control; removing the production tree, installing a backpressure valve on the tubing hanger, and installing a blowout preventer (BOP) assembly. Based on data such as the insertion length of the back-insertion seal, the compression distance of the back-insertion tubing string, and the expected tubing string stretching length caused by the hydraulic anchor and back-insertion seal clamping force, adjust the distance between the annular BOP core and the tubing hanger to meet the following conditions: close the annular BOP and ensure the drill pipe joint does not pass over the annular BOP core; lift the drill pipe to remove the back-insertion seal from the suspension packer. Connect the drill pipe to the tubing hanger, slowly lift the drill pipe to lift the tubing hanger away from the tubing head sealing surface, and close the annular BOP; apply casing pressure to make the external pressure of the hydraulic anchor greater than the internal pressure to release the hydraulic anchor anchoring; slowly lift the drill pipe to disengage the back-insertion tubing string from the suspension packer back-in sleeve, connecting the tubing and casing; start the pump for circulation, using kill fluid to replace the completion fluid in the tubing and casing annulus, and circulate to vent air to complete the well control.

[0076] This invention conforms to SY / T5964-2019 "Specifications for the Assembly, Installation, Commissioning and Use of Drilling Well Control Devices" 5.1.3 "Under special circumstances, when only the annular blowout preventer is closed and the casing pressure does not exceed 14MPa, the drill string is allowed to move up and down at a speed not exceeding 0.2m / s, but the drill string is not allowed to rotate or pass through the drill string joint via the rubber core" and Q / SY 02552-2018 "Technical Specifications for Drilling Well Control" 5.3.2 "After the annular blowout preventer or the gate blowout preventer is closed, when the casing pressure does not exceed 14MPa, the drill string is allowed to move up and down at a speed not exceeding 0.2m / s, but rotation or passing through the drill string joint is not allowed."

[0077] This invention is particularly applicable to oil and gas wells where the internal hydraulic column pressure of the hydraulic anchor after a well undergoing injection-pressurization in tubing is higher than the external hydraulic column pressure, but the pressure difference does not exceed 14 MPa; this invention is also applicable to oil and gas wells where the internal hydraulic column pressure of the hydraulic anchor after a well undergoing injection-pressurization in tubing is higher than the external hydraulic column pressure, but the pressure difference exceeds 14 MPa. For example, in a well where the open-hole packer has been completed in sections, the tubing has been reconnected to a depth of 5000 m (vertical depth), and the density inside the tubing is 1.35 g / cm³. 3 In a hydraulic well kill operation, the hydraulic column pressure differential is 17.2 MPa, the casing pressure is 14 MPa, and the distance to pull back the tubing string reaches H. 上提 Afterwards, applying a higher pressure, such as 25 MPa, to the casing can release the hydraulic anchor constraint, allowing the reinserted sealing pipe to detach from the suspended packer reconnecting sleeve, thus connecting the tubing and casing to achieve circulating well control.

[0078] In recent years, this invention has been experimentally applied in three wells in the Anyue Gas Field: Moxi 123, Moxi 122, and Moxi 146. The pipe string was reconnected to a depth of approximately 5000m (vertical depth), and the mud density for well control was 1.25g / cm³. 3 ~1.28g / cm 3 All experiments were successful on the first attempt.

[0079] The open-hole packer segmentation modification process is usually applied to low-pressure or atmospheric-pressure oil and gas wells, therefore, the present invention has a wide range of applications.

[0080] Although the invention has been described above in conjunction with exemplary embodiments, those skilled in the art will understand that various modifications and changes can be made to the exemplary embodiments of the invention without departing from the spirit and scope defined by the claims.

Claims

1. A method for replacing completion fluid in the annulus of a segmented modified open-hole packer tubing string, characterized in that, The replacement method includes the following steps: Hydraulic wells are injected into the tubing to kill the well, and the anchor claws of the hydraulic anchor engage with the casing. Remove the tree gas production line and install a back pressure valve on the tubing. Install blowout preventer assemblies; Lift the oil pipe away from the sealing surface of the oil pipe head; Close the annular blowout preventer in the blowout preventer assembly; Apply pressure to release the hydraulic anchor; Pull out the reinserted sealing tube and hang the packer to connect the tubing to the casing; Inject kill fluid into the tubing to replace the completion fluid between the production tubing and the casing; The open-hole packer segmented modification string includes: a guide shoe, a backpressure valve, a setting ball seat, a differential pressure sleeve, an open-hole packer, a ball-dropping sleeve, a suspended packer, a back-insertion sealing tube, a hydraulic anchor, tubing, and a tubing hanger; after the modification construction is completed, both the differential pressure sleeve and the ball-dropping sleeve are in the open state; the suspended packer seals the tubing and casing, and the annular space between the tubing and casing is filled with completion fluid.

2. The method for replacing the completion fluid in the annulus of the open-hole packer segmented modification string according to claim 1, characterized in that, In the step of injecting kill fluid into the tubing, the kill fluid is used to fill the open hole packer section of the modified tubing string and the open hole section.

3. The method for replacing the completion fluid in the annulus of the open-hole packer segmented modification string according to claim 2, characterized in that, After injecting hydraulic pressure into the tubing to kill the well, the pressure of the liquid column inside the hydraulic anchor is higher than the pressure of the liquid column outside the hydraulic anchor, and the pressure difference between the inside and outside of the hydraulic anchor is less than 14 MPa.

4. The method for replacing the completion fluid in the annulus of the open-hole packer segmented modification string according to claim 1, characterized in that, The blowout preventer assembly includes a four-way converter, a double-gate blowout preventer, a single-gate blowout preventer, a shear blowout preventer, and a ring blowout preventer.

5. The method for replacing the completion fluid in the annulus of the open-hole packer segmented modification string according to claim 1, characterized in that, After installing the blowout preventer assembly, connect the drill pipe to the back pressure valve and perform a blowout preventer pressure test, wherein the drill pipe is connected to the back pressure valve.

6. The method for replacing the completion fluid in the annulus of the open-hole packer segmented modification string according to claim 1, characterized in that, The step of lifting the oil pipe away from the sealing surface of the oil pipe head includes: Open the four-way gate valve of the oil pipe head, loosen the oil pipe hanger top screw, activate the annular blowout preventer, and slowly lift the oil pipe hanger. Stop lifting when the oil pipe hanger leaves the sealing surface of the oil pipe head.

7. The method for replacing the annular completion fluid in the open-hole packer segmented modification string according to claim 6, characterized in that, After the tubing is lifted away from the tubing head sealing surface and before the sleeve pressure is applied, the annular blowout preventer is closed and the tubing head four-way gate is closed.

8. The method for replacing the completion fluid in the annulus of the open-hole packer segmented modification string according to claim 1, characterized in that, The step of applying sleeve pressure includes: applying pressure to the annulus of the sleeve so that the external pressure of the hydraulic anchor is greater than the internal pressure, causing the hydraulic anchor claws to retract.

9. The method for replacing the annular completion fluid in the open-hole packer segmented modification string according to claim 8, characterized in that, After releasing the hydraulic anchor, the replacement method further includes a depressurization step, depressurizing to a predetermined pressure.

10. The method for replacing the completion fluid in the annulus of the open-hole packer segmented modification string according to claim 1, characterized in that, During or after the installation of the blowout preventer, the replacement method further includes the step of adjusting the distance between the top surface of the tubing hanger and the annular blowout preventer core to satisfy the following formula: H>H 上提 +H4+H5, Where H is the distance between the top surface of the tubing hanger and the rubber core of the annular blowout preventer. 上提 To determine the required upward elevation of the reinforcing sealing tube from the suspended packer, H4 is the length of the drill pipe back pressure valve, and H5 is the total length of the drill pipe joint and the thickened part of the drill pipe.

11. The method for replacing the annular completion fluid in the open-hole packer segmented modification string according to claim 10, characterized in that, The required upward elevation for lifting the reinsertion sealing tube out of the suspended packer is determined according to the following formula: H 上提 (H1+H2+H3) Where H1 is the length of the re-insertion sealing tube inserted into the suspension packer, H2 is the compression distance of the re-insertion tube, and H3 is the tensile length of the tube caused by the clamping force.

12. The method for replacing the completion fluid in the annulus of the open-hole packer segmented modification string according to claim 1, characterized in that, During the step of removing the reinsertion sealing tube from the suspended packer, the drill pipe joint does not pass over the annular blowout preventer core.

13. A method for achieving well control through segmented modification of an open-hole packer tubing string, characterized in that, The well control method includes: replacing the completion fluid between the production tubing and the casing using the open-hole packer segment modification tubing annulus completion fluid replacement method as described in any one of claims 1 to 12, and then circulating the well control fluid in the well evenly.

Images