Pressurized top seal drag temporary plugging fracturing device and fracturing method

Abstract

This invention relates to the field of fracturing string technology, specifically a fracturing device and method with a pressure-driven top seal and temporary plugging mechanism. The device comprises, sequentially connected from the well bottom to the wellhead, a guide shoe, a coupling locator, a sliding sleeve jetting device, a bottom packer, a hydraulic anchor, tubing, a top packer, and a screen pipe. The screen pipe includes a body and a lower conversion joint, connected together. The body has several through-flow channels. The screen pipe connects the tubing to the annulus, allowing for simultaneous injection of fracturing fluid into the tubing and casing, increasing the fracturing fluid flow rate for high-volume fracturing operations. This invention features a reasonable and compact structure, is easy to use, and employs an annulus-based or simultaneous injection method. The fracturing fluid is redirected through the screen pipe before entering the tubing string for targeted fracturing operations, effectively increasing the fracturing fluid flow rate and enabling applications in high-volume fracturing operations. The absence of a packer behind the sliding sleeve jetting device fundamentally reduces the risk of packer sand jamming.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of fracturing pipe string, and is a top sealing drag temporary plugging fracturing device and a fracturing method. BACKGROUND

[0002] Under the background of oil and gas resource exploration and development into deep and complex reservoirs, efficient development of multi-layer oil and gas wells has become a key field to ensure energy production. However, technical bottlenecks in the process of reservoir reconstruction are increasingly prominent, mainly in two dimensions of reservoir geological condition limitation and development efficiency deficiency.

[0003] From the perspective of reservoir geological endowment, a large number of oil and gas reservoirs are affected by sedimentary environment and diagenesis, showing the characteristics of "double low" of low porosity and low permeability. The rock of such reservoirs is dense, the pore space is small and the connectivity is poor, and the natural fracture development is insufficient, which limits the flow channel of oil and gas in the reservoir. More importantly, the crack propagation pressure of some reservoirs is relatively high. In the initial fracturing operation, the conventional fracturing fluid injection pressure is difficult to break through the rock fracture pressure threshold of the reservoir, which cannot effectively open the new crack network, and even can only form short and narrow artificial cracks in the near wellbore zone of the reservoir, which is difficult to realize large-scale reconstruction of the reservoir, directly leading to the failure to release the potential of the reservoir.

[0004] In the development and production process, another problem also restricts the utilization rate of the reservoir: although some reservoirs form a certain scale of cracks in the initial fracturing, due to the elastic shrinkage of the reservoir rock, the migration of the formation fluid and the settlement loss of the proppant, the phenomenon of premature closure of the cracks is widespread. The closed cracks lose the flow conductivity, and the oil and gas cannot flow continuously to the wellbore, so the reservoir with development value falls into the "inefficient or even ineffective" dilemma, and the overall utilization rate of the reservoir is greatly reduced, which not only wastes valuable oil and gas resources, but also increases the cost and risk of oil and gas field development.

[0005] Cross-sealing fracturing technology uses packers to isolate the target layer to be reconstructed from other layers, and the fracturing fluid enters the target layer for pinpoint and fine fracturing without affecting other layers, which is an effective means to maintain and increase the yield of old wells. The current top sealing drag temporary plugging fracturing usually uses three packers, and the packer behind the sliding sleeve sand blaster is prone to sand sticking when the pipe string is pulled out.

[0006] The sliding sleeve blasting nozzle is a key component for the directional delivery of fracturing fluid to the target formation. Its central tube needs to withstand the long-term erosion of high-pressure, high-velocity fracturing fluid. Because the fracturing fluid contains proppant (such as silica sand and ceramsite), these solid particles exert a strong erosive effect on the inner wall of the central tube (especially the area near the nozzle) during high-speed flow. After prolonged operation, the inner wall of the central tube will experience wear, thinning, and even perforation, leading to uncontrolled fracturing fluid flow. Some fracturing fluid may directly erode the wellbore wall, not only reducing the utilization efficiency of the fracturing fluid but also potentially damaging the wellbore casing and increasing wellbore maintenance costs.

[0007] During fracturing operations, proppant-carrying fracturing fluid is injected into the target formation at high velocity through a sandblasting nozzle. Some proppant (especially smaller particles like quartz sand or crushed ceramsite) may detach from the main fracturing fluid system and migrate towards the annulus region where the hydraulic anchor is located due to factors such as velocity fluctuations, flow channel deflection, or wellbore irregularities. Because the hydraulic anchor has a certain clearance between its prongs and body to achieve its anchoring function, and some hydraulic anchors lack effective sand-proofing structures in their unlocking channels (such as hydraulic oil passages and mechanical transmission gaps), these free proppant particles can enter the gaps between the moving parts of the hydraulic anchor with the annulus fluid. For example, when the hydraulic anchor extends its prongs hydraulically, proppant may become embedded between the sealing surfaces of the prongs and the cylinder, or block the hydraulic channels for prong retraction, preventing the prongs from retracting smoothly during unlocking. If the pumping rate drops suddenly or stops during fracturing, the annulus fluid velocity slows down, making it easier for proppant to settle and accumulate near the hydraulic anchor, forming localized sand bridges that directly obstruct the movement of the prongs. This causes the hydraulic anchor to be unable to reset and release itself without hydraulic pressure.

[0008] During fracturing, the fracturing fluid displacement is a key parameter affecting the scale of fracture extension and conductivity. A higher displacement can drive fractures deeper into the reservoir, forming a more complex fracture network. However, in existing trans-district fracturing technologies, fracturing fluid is usually injected from the top connecting pipe. Due to pipe diameter limitations, the displacement often needs to be restricted in actual operations. This, to some extent, limits the stimulation effect on low-permeability, tight reservoirs and makes it difficult to form a large-scale fracture network that meets high-production requirements.

[0009] Therefore, existing cross-bar fracturing methods have problems such as the inability to smoothly remove the downhole tool string after fracturing operations, the packer behind the sliding sleeve sandblaster being prone to sand jamming, the central tube of the sandblaster being prone to erosion damage, the hydraulic anchor being blocked by proppant particles and unable to be unlocked, and the fracturing discharge rate being limited. Summary of the Invention

[0010] This invention provides a fracturing device and method with a pressure-sealed drag-and-pump fracturing device, which overcomes the shortcomings of the prior art. It can effectively solve the problems of easy sand blockage of the packer behind the sliding sleeve sandblaster after fracturing in existing cross-diaphragm fracturing, easy erosion damage to the central tube of the sandblaster, inability to unlock the hydraulic anchor due to blockage by proppant particles, and limited fracturing discharge.

[0011] One of the technical solutions of this invention is achieved through the following measures: a pressure-sealed drag-type fracturing device, comprising a guide shoe, a coupling locator, a sliding sleeve sandblaster, a bottom packer, a hydraulic anchor, tubing, a top packer, and a screen pipe connected sequentially from the bottom of the well to the wellhead. The screen pipe includes a body and a lower conversion joint, with the body and the lower conversion joint connected together. The body is provided with several through-flow channels. The screen pipe connects the tubing to the annulus, allowing for simultaneous injection of fracturing fluid into the tubing and casing, increasing the fracturing fluid discharge rate for high-volume fracturing operations. The top packer and the bottom packer are combined to isolate the upper modified production section, and the bottom packer is seated on top of the lowest section to be modified. Fracturing modification is performed through the sliding sleeve sandblaster at the rear of the bottom packer.

[0012] The following are further optimizations and / or improvements to the above-mentioned technical solution:

[0013] Preferably, the hydraulic anchor includes a central tube, anchor claw assemblies, telescopic tubes, and an outer cylinder. The telescopic tube is connected to the left end of the outer cylinder. Several anchor claw assemblies are installed along the circumference of the outer cylinder. The anchor claw assemblies can extend and anchor under hydraulic pressure. The outer cylinder contains a central tube with several liquid outlet holes. Each liquid outlet hole is equipped with a high-pressure multilayer metal felt filter screen.

[0014] Preferably, the hydraulic anchor also includes a connector, a slider sleeve, an arc-shaped push block, and a shear pin. Two slider sleeves are symmetrically arranged on the outer side of the central tube at intervals. The slider sleeves have at least three sloping dovetail grooves evenly distributed along the circumference. At least three arc-shaped push blocks are provided between the two symmetrically arranged slider sleeves. The left and right ends of the arc-shaped push blocks are respectively located in the sloping dovetail grooves on the two slider sleeves. The outer side of the arc-shaped push block corresponding to the installation position of the anchor claw assembly has a dovetail groove. The inner end of the connector is connected to the dovetail groove and can slide in the dovetail groove. The outer end of the connector is threaded to the anchor claw assembly. The slider sleeve located on the left is fixedly installed to the outer cylinder by the shear pin.

[0015] Preferably, the anchor claw assembly includes a base and an anchor claw installed together. The outer cylinder has a stepped hole that runs through the inside and outside. The inner end of the stepped hole is a small hole and the outer end is a large hole. A sand settling groove is provided at the junction of the large hole and the small hole. The base and the anchor claw are installed in the large hole, and the outer end of the connector is threaded to the base.

[0016] Preferably, a metal felt filter screen is installed inside the small holes.

[0017] Preferably, the sliding sleeve sandblasting device includes an upper connector, a lower connector, a limiting bushing, a plunger, and a return spring. The upper connector is threaded to the outer left end of the limiting bushing, and the lower connector is threaded to the outer right end of the limiting bushing. A sandblasting hole is provided in the middle of the limiting bushing. A first limiting ring platform is provided on the inner right side of the limiting bushing, and a second limiting ring platform is provided on the inner right side of the lower connector. An outer ring platform is provided on the outer side of the middle of the plunger. The outer ring platform is located between the first and second limiting ring platforms. A return spring is installed on the outer side of the plunger at the position between the outer ring platform and the second limiting ring platform.

[0018] Preferably, the sliding sleeve sandblaster also includes a guide head, a conical guide head is installed on the left end of the plunger, a first hard alloy jacket is provided on both the inner and outer sides of the sandblasting hole, an inner liner is provided on the left side of the first hard alloy jacket located on the inner side, and the right end of the inner liner can be sealed with the conical surface of the guide head.

[0019] Preferably, the limiting bushing is fixed with anti-rotation pins at the installation positions of the upper and lower connectors.

[0020] Preferably, the bottom packer is a Y341 packer and the top packer is a suspended Y211 packer.

[0021] Preferably, a second hard alloy jacket is installed on the outside of the flow channel opening of the screen tube. The second hard alloy jacket has a flow port that communicates with the flow channel opening. The inner diameter of the flow port is smaller than that of the flow channel opening. A safety pin is installed between the body and the lower conversion joint.

[0022] The second technical solution of the present invention is achieved through the following measures: a fracturing method, performed according to the following method:

[0023] Step 1: Measure the actual dimensions of the tool before it is lowered into the well;

[0024] Step 2: Use a wellbore gauge and scraper of the specified size to clean the well and scrape to a depth below the target formation.

[0025] Step 3: Lower the pressure-sealed top seal and drag the temporary plugging fracturing device to the predetermined depth; isolate the lowest modified section from the modified sections; and also isolate the upper unmodified sections from the modified sections.

[0026] Step 4: Use the casing coupling locator to drag the pressurized top seal temporary plugging fracturing device to the design depth;

[0027] Step 5: Lift and lower the tubing string, and set the top packer;

[0028] Step 6: Start the pump to inject fracturing fluid into the annulus. The fracturing fluid enters the 3.5-inch tool string cavity through the screen tube from the annulus (or the oil casing is injected at the same time), and the bottom packer is set.

[0029] Step 7: Pump fracturing fluid according to the fracturing pump injection procedure, observe the changes in wellhead pressure and annular pressure, and determine the packer setting status;

[0030] Step 8: Start the pump and pump fracturing fluid according to the pumping procedure. In the later stage of the proppant addition stage, add a mixed fracturing fluid containing a certain proportion of water-soluble temporary plugging agent and proppant to temporarily plug the fracturing section in a targeted manner.

[0031] Step 9: Stop the pump, observe the changes in wellhead pressure and annular pressure, and determine the packer setting status and temporary plugging effect;

[0032] Step 10: Raise the tubing string and align the sandblasting nozzle with the next layer to be modified. Repeat steps 5-9 until fracturing operations are completed for all layers.

[0033] If there is an already modified section with the next level section to be modified, temporary plugging agent shall be used to temporarily plug the section according to the specific circumstances.

[0034] Step 11: Stop the pump and observe the wellhead pressure and annular pressure;

[0035] Step 12: Use pressurized equipment to remove the downhole tool string;

[0036] Step 13 involves performing continuous tubing flushing to restore reservoir production.

[0037] The present invention has a reasonable and compact structure and is easy to use. It adopts the method of fluid injection from the annulus or simultaneous injection of oil and casing. The fracturing fluid enters the tubing after being reversed through the screen tube for targeted fracturing operation, which effectively improves the fracturing fluid discharge rate and can be applied to large-displacement operation. There is no packer at the rear of the sliding sleeve sandblaster, which fundamentally reduces the risk of packer sand jamming. Attached Figure Description

[0038] Appendix Figure 1 This is a schematic diagram of the string structure according to an embodiment of the present invention.

[0039] Appendix Figure 2 This is a cross-sectional structural diagram of a hydraulic anchor.

[0040] Appendix Figure 3 For the appendix Figure 2 A three-dimensional structural diagram of the middle slider sleeve.

[0041] Appendix Figure 4 For the appendix Figure 2 A schematic diagram of the main structure of the arc-shaped pusher block.

[0042] Appendix Figure 5 For the appendix Figure 4 A schematic diagram of the structure viewed from below.

[0043] Appendix Figure 6 For the appendix Figure 2 Enlarged structural diagram of the middle anchor claw assembly.

[0044] Appendix Figure 7 For the appendix Figure 2 A schematic diagram of the main structure of the connector.

[0045] Appendix Figure 8 This is a schematic diagram of the cross-sectional structure of the sieve tube.

[0046] Appendix Figure 9 For the appendix Figure 8 A schematic diagram of the main structure.

[0047] Appendix Figure 10 This is a cross-sectional view of the sandblasting hole of the sliding sleeve sandblaster when it is closed.

[0048] Appendix Figure 11 This is a cross-sectional view of the sandblasting hole of the sliding sleeve sandblaster when it is open.

[0049] The codes in the attached diagram are as follows: 1 for guide shoe, 2 for coupling locator, 3 for sliding sleeve sandblasting device, 4 for bottom packer, 5 for hydraulic anchor, 6 for top packer, 7 for screen pipe, 8 for body, 9 for lower conversion joint, 10 for flow channel opening, 11 for central pipe, 12 for anchor claw assembly, 13 for telescopic pipe, 14 for outer cylinder, 15 for liquid outlet, 16 for connector, 17 for sliding sleeve, 18 for arc-shaped push block, 19 for shear pin, 20 for inclined dovetail groove, and 21 for dovetail. 22 is the base, 23 is the anchor claw, 24 is the metal felt filter screen, 25 is the upper connector, 26 is the lower connector, 27 is the inner bushing, 28 is the limiting bushing, 29 is the plunger, 30 is the return spring, 31 is the sandblasting hole, 32 is the first limiting ring platform, 33 is the second limiting ring platform, 34 is the outer ring platform, 35 is the guide head, 36 is the first hard alloy outer sleeve, 37 is the anti-rotation pin, 38 is the second hard alloy outer sleeve, 39 is the flow port, 40 is the safety pin, and 41 is the sedimentation tank. Detailed Implementation

[0050] The present invention is not limited to the following embodiments, and the specific implementation can be determined according to the technical solution of the present invention and the actual situation.

[0051] In this invention, for ease of description, the description of the relative positions of the components is based on the appendix to the specification. Figure 1 The layout is described using a diagrammatic method, such as front, back, top, bottom, left, right, etc. The positional relationships are determined based on the layout direction of the attached diagram in the instruction manual.

[0052] The present invention will be further described below with reference to embodiments and accompanying drawings:

[0053] Example 1: As shown in the attached document Figures 1-11As shown, the pressure-sealed temporary plugging fracturing device includes a guide shoe 1, a coupling locator 2, a sliding sleeve sandblaster 3, a bottom packer 4, a hydraulic anchor 5, tubing, a top packer 6, and a screen pipe 7 connected sequentially from the bottom of the well to the wellhead. The screen pipe 7 includes a body 8 and a lower conversion joint 9. The body 8 and the lower conversion joint 9 are connected together. The body 8 is provided with several through-flow channels 10. The screen pipe 7 connects the tubing to the annulus, allowing for simultaneous injection of fracturing fluid into the tubing and casing, increasing the fracturing fluid discharge rate for high-volume fracturing operations. The top packer 6 and the bottom packer 4 are combined to isolate the upper modified production section. The bottom packer 4 is seated on the top of the lowest section to be modified. Fracturing modification is carried out through the sliding sleeve sandblaster 3 at the rear of the bottom packer 4.

[0054] This invention uses a combination of a top packer 6 and a bottom packer 4 to isolate the upper, modified production section. The bottom packer 4 is seated on top of the lowest section to be modified, and fracturing is performed through a sliding sleeve sandblasting device 3 at the rear of the bottom packer 4. Using a simultaneous oil-casing injection method, the fracturing fluid injected from the annulus passes through the screen pipe 7 and then enters the fracturing string below the packer for fracturing operations. The large annulus void effectively increases the fracturing fluid discharge rate, solving the problem of limited discharge rate in cross-section fracturing operations.

[0055] In the later stages of sand addition, a mixed fracturing fluid containing a certain proportion of water-soluble temporary plugging agent (50-140 mesh) and proppant (40-100 mesh) is added to the fracturing section under construction for targeted temporary plugging (technical sand plugging). Then, the tubing string is lifted and the tool string is dragged to the next stage to be modified for further modification. The sliding sleeve sandblaster 3 has no packer at the rear. The fracture is sealed by injecting water-soluble temporary plugging agent, which fundamentally reduces the risk of packer sand jamming, shortens the tubing string length, reduces the friction between the liquid and the tubing string, and minimizes hydraulic loss.

[0056] The above-mentioned pressurized top-sealed drag-type temporary plugging fracturing device can be further optimized and / or improved according to actual needs:

[0057] Example 2: As shown in the attached document Figures 2-7 As shown, the hydraulic anchor 5 includes a central tube 11, anchor claw assembly 12, telescopic tube 13, and outer cylinder 14. The telescopic tube 13 is connected to the left end of the outer cylinder 14. Several anchor claw assemblies 12 are installed along the circumference of the outer cylinder 14. The anchor claw assembly 12 can extend and anchor under hydraulic push. The central tube 11 is provided inside the outer cylinder 14. Several liquid outlet holes 15 are provided on the central tube 11. High-pressure filter multilayer metal felt filter sand mesh is installed at the position of each liquid outlet hole 15.

[0058] After high-pressure liquid is injected into the central tube 11, it flows out from the outlet hole 15, pushing the anchor claw assembly 12 to extend and anchor with the casing. After anchoring, it can counteract the high-pressure thrust, prevent the downhole tool string from moving upward as a whole, and avoid the packer "moving". It stabilizes the sealing state of the packer, ensures the interlayer isolation effect, and reduces rubber wear. By installing a high-pressure filter multilayer metal felt filter screen at the outlet hole 15, it can block sand particles with a diameter of 0.044mm or larger, prevent large particles from entering the anchor claw assembly 12 and causing the anchor claw 23 to get stuck, and reduce the risk of jamming.

[0059] As required, three pre-fabricated liquid outlet holes 15 are designed on the central tube 11. The three liquid outlet holes 15 have a phase angle of 120 degrees, a diameter of 10 mm, and an axial distance of 50 mm between two holes. The staggered design of the liquid outlet holes 15 provides a reliable hydraulic power flow channel for the anchor claw assembly 12, preventing accidental blockage of the fluid flow channel from causing the hydraulic anchor 5 to fail to anchor properly. It also avoids the problem of stress concentration caused by concentrated openings, which leads to a decrease in the tool's ability to unblock.

[0060] Example 3: As shown in the attached document Figures 2-7 As shown, the hydraulic anchor 5 also includes a connector 16, a slider sleeve 17, an arc-shaped push block 18, and a shear pin 19. Two slider sleeves 17 are symmetrically arranged on the left and right sides of the outer side of the central tube 11. The slider sleeves 17 have at least three sloping dovetail grooves 20 evenly distributed around their circumference. At least three arc-shaped push blocks 18 are provided between the two symmetrically arranged slider sleeves 17. The left and right ends of the arc-shaped push blocks 18 are located in the sloping dovetail grooves 20 on the two slider sleeves 17, respectively. The arc-shaped push blocks 18 corresponding to the installation position of the anchor claw assembly 12 have dovetail grooves 21 on their outer sides. The inner end of the connector 16 is connected to the dovetail groove 21 and can slide within the dovetail groove 21. The outer end of the connector 16 is threadedly connected to the anchor claw assembly 12. The slider sleeve 17 located on the left side is fixedly installed to the outer cylinder 14 by the shear pin 19.

[0061] The arc-shaped pusher 18 has a narrow strip structure. After high-pressure liquid is injected into the central tube 11, it flows out from the outlet hole 15 and passes around the arc-shaped pusher 18 to push the anchor claw assembly 12 out. The anchor claw assembly 12 pulls the arc-shaped pusher 18 to move radially outward. When the anchoring assembly is stuck and cannot be released, the sliding block sleeve 17 located on the left is pulled to the left with sufficient pressure to cut the shear pin 19. When the sliding block sleeve 17 moves to the left, under the limit of the slope dovetail groove 20, the arc-shaped pusher 18 retracts inward along the slope dovetail groove 20, thereby pulling the anchor claw assembly 12 to move inward, thereby forcibly releasing the jam and reducing the operational risk caused by the hydraulic anchor 5 not being able to be effectively released.

[0062] Example 4: As shown in the appendix Figure 6As shown, the anchor claw assembly 12 includes a base 22 and an anchor claw 23 mounted together. The outer cylinder 14 has a stepped hole that extends through both the inner and outer sides. The inner end of the stepped hole is a small hole, and the outer end is a large hole. A sand settling groove 41 is provided at the junction of the large and small holes. The base 22 and the anchor claw 23 are installed in the large hole, and the outer end of the connector 16 is threaded onto the base 22. By setting the sand settling groove 41, particles in the fracturing fluid can be contained, reducing the number of particles in the movable position and ensuring that the anchor claw 23 can extend and retract normally to anchor and release anchor.

[0063] Example 5: As shown in the attached document Figure 6 As shown, a metal felt filter screen 24 is installed inside the small hole. This further filters the liquid and reduces the impact of particulate matter on the anchor claw assembly 12. The hydraulic anchor 5 is equipped with a triple sand control system. The primary sand control system is the sand control device in the central tube 11, and the liquid outlet 15 is equipped with a multi-layer metal felt filter screen. The secondary sand control system is the metal felt filter screen installed inside the small hole. The tertiary sand control system is the sand settling tank 41. This triple sand control design can effectively prevent formation sand, fracturing proppant, and other impurities from entering the anchor body cavity, and promptly remove sand particles that accidentally enter the base 22, reducing the risk of sand getting stuck in the hydraulic anchor 5 during construction operations and improving the safety performance of the tool.

[0064] Example 6: As attached Figure 10 , 11 As shown, the sliding sleeve sandblaster 3 includes an upper connector 25, a lower connector 26, a limiting bushing 28, a plunger 29, and a return spring 30. The upper connector 25 is threaded to the outer left end of the limiting bushing 28, and the lower connector 26 is threaded to the outer right end of the limiting bushing 28. A sandblasting hole 31 is provided in the middle of the limiting bushing 28. A first limiting ring platform 32 is provided on the inner right side of the limiting bushing 28. A second limiting ring platform 33 is provided on the inner right side of the lower connector 26. An outer ring platform 34 is provided on the outer side of the middle of the plunger 29. The outer ring platform 34 is located between the first limiting ring platform 32 and the second limiting ring platform 33. A return spring 30 is installed on the outer side of the plunger 29 at the position between the outer ring platform 34 and the second limiting ring platform 33.

[0065] During well insertion, the pressure inside the tubing is low. Under the action of the well pressure and the return spring 30, the plunger 29's sandblasting hole 31 is closed, isolating the oil-casing space, allowing the tool to be inserted into the well under pressure. After the high-pressure liquid is injected, it pushes the plunger 29 to the right, compressing the return spring 30, opening the sandblasting hole 31, allowing sandblasting operations. After the operation is completed and the pump is stopped, the pressure inside the tubing decreases again. Under the action of the well pressure and the return spring 30, the plunger 29 returns to its original position, and the sandblasting hole 31 is closed, effectively isolating the oil-casing pressure. The outer ring platform 34, the first limiting ring platform 32, and the second limiting ring platform 33 restrict the movement path of the plunger 29. Sealing rings are set in the tubing string as needed to reduce liquid loss. Compared with the ball-throwing sliding sleeve sandblaster 3, which requires subsequent processing of the ball after throwing, making continuous operation difficult, the sliding sleeve sandblaster 3 of this invention can perform continuous operation without ball processing.

[0066] Example 7: As attached Figure 10 , 11 As shown, the sliding sleeve blasting device 3 also includes a guide head 35. A conical guide head 35 is installed on the left end of the plunger 29. A first hard alloy jacket 36 is provided on both the inner and outer sides of the blasting hole 31. An inner liner 27 is provided on the left side of the inner first hard alloy jacket 36, and the right end of the inner liner 27 can seal with the conical surface of the guide head 35. The guide head 35 effectively guides the liquid flow, reducing fluid hydraulic loss.

[0067] Example 8: As attached Figure 10 , 11 As shown, the limiting bushing 28 is fixed with anti-rotation pins 37 at the installation positions of the upper connector 25 and the lower connector 26. The anti-rotation pins 37 form a rigid mechanical constraint, directly blocking the relative rotation tendency between the components, ensuring that the tool always maintains a complete connection state under complex working conditions, and avoiding connection failure caused by rotation.

[0068] Example 9: As attached Figure 1 As shown, the bottom packer 4 is a Y341 packer, and the top packer 6 is a suspended Y211 packer. During the tool string insertion process, the bypass valve is open during low-volume circulation to prevent accidental setting of the packer during insertion. During fracturing operations, during high-volume circulation, the internal sliding sleeve moves downward under the action of the throttling pressure differential, closing the bypass valve, allowing the packer to quickly set. After fracturing is completed, the sliding sleeve sandblaster 3 isolates the oil and casing pressure, and the Y341 packer quickly releases under the action of the return spring. At the same time, the bypass valve opens to balance the oil and casing pressure. The suspended Y211 packer features one-way slips, lifting and lowering for setting and releasing, and has sand-proof function. Its inner diameter is not less than 40mm, and its sand discharge capacity is not less than 6 m³ / h. 3 / min, total sand throughput not less than 1000 m³ 3 The tensile strength is not less than 60T.

[0069] Example 10: As attached Figure 8 , 9 As shown, a second hard alloy jacket 38 is installed on the outside of the flow channel opening 10 of the screen tube 7. The second hard alloy jacket 38 has a flow port 39 communicating with the flow channel opening 10. The inner diameter of the flow port 39 is smaller than that of the flow channel opening 10. A safety pin 40 is installed between the body 8 and the lower conversion joint 9. The addition of the second hard alloy jacket 38 to the outside of the screen tube 7 effectively prevents damage caused by sand and gravel erosion, and at the same time allows the screen tube 7 to maintain sufficient strength under the sand flow rate required by the design. The total flow area of ​​the flow channel opening 10 can be determined according to the specific operation requirements, which can ensure that no excessive pressure drop occurs under the liquid flow rate required by the design, so that the construction pressure can be controlled within a reasonable range.

[0070] Example 11: The fracturing method is as follows:

[0071] Step 1: Measure the actual dimensions of the tool before it is lowered into the well;

[0072] Step 2: Use a wellbore gauge and scraper of the specified size to clean the well and scrape to a depth below the target formation.

[0073] Step 3: Lower the pressure-sealed top seal and drag the temporary plugging fracturing device to the predetermined depth; isolate the lowest modified section from the modified sections; and also isolate the upper unmodified sections from the modified sections.

[0074] Step 4: Use the casing coupling locator 2 to drag the pressurized top seal temporary plugging fracturing device to the design depth;

[0075] Step 5: Lift and lower the tubing string, and set the top packer 6;

[0076] Step 6: Start the pump to inject fracturing fluid into the annulus. The fracturing fluid enters the 3.5-inch tool string cavity through the screen pipe 7 from the annulus (or the oil casing is injected at the same time). The bottom packer 4 is set.

[0077] Step 7: Pump fracturing fluid according to the fracturing pump injection procedure, observe the changes in wellhead pressure and annular pressure, and determine the packer setting status;

[0078] Step 8: Start the pump and pump fracturing fluid according to the pumping procedure. In the later stage of the proppant addition stage, add a mixed fracturing fluid containing a certain proportion of water-soluble temporary plugging agent (50-140 mesh) and proppant (40-100 mesh) to temporarily plug the fracturing section in a targeted manner.

[0079] Step 9: Stop the pump, observe the changes in wellhead pressure and annular pressure, and determine the packer setting status and temporary plugging effect;

[0080] Step 10: Raise the tubing string and align the sandblasting nozzle with the next layer to be modified. Repeat steps 5-9 until fracturing operations are completed for all layers.

[0081] If there is an already modified section with the next level section to be modified, temporary plugging agent shall be used to temporarily plug the section according to the specific circumstances.

[0082] Step 11: Stop the pump and observe the wellhead pressure and annular pressure;

[0083] Step 12: Use pressurized equipment to remove the downhole tool string;

[0084] Step 13 involves performing continuous tubing flushing to restore reservoir production.

[0085] This invention uses pressurized equipment for haul-down operations, effectively solving the problem that the equipment cannot smoothly pull out a long tool string from the wellhead after fracturing operations.

[0086] The above technical features constitute various embodiments of the present invention, which have strong adaptability and implementation effect. Unnecessary technical features can be added or removed according to actual needs to meet the needs of different situations.

Claims

1. A temporary plugging fracturing device with a pressure-sealed top seal, characterized in that... The system comprises, sequentially connected from the bottom of the well to the wellhead, a guide shoe, a coupling locator, a sliding sleeve blasting device, a bottom packer, a hydraulic anchor, tubing, a top packer, and a screen pipe. The screen pipe includes a main body and a lower conversion joint, connected together. The main body has several through-flow channels. The screen pipe connects the tubing to the annulus, allowing for simultaneous injection of fracturing fluid into the tubing and casing, increasing the fracturing fluid flow rate for high-volume fracturing operations. The top and bottom packers isolate the upper, modified production zone. The bottom packer is seated on top of the lowest zone to be modified, and fracturing is achieved through the sliding sleeve blasting device behind the bottom packer. The hydraulic anchor includes a central tube, anchor claw assemblies, a telescopic tube, and an outer cylinder. The telescopic tube is connected to the left end of the outer cylinder, and several anchor claw assemblies are installed along the circumference of the outer cylinder. The component can extend and anchor under hydraulic pressure. The outer cylinder has a central tube with several liquid outlet holes. Each liquid outlet hole is equipped with a high-pressure filter multilayer metal felt filter screen. The hydraulic anchor also includes a connector, a slider sleeve, an arc-shaped push block, and a shear pin. Two symmetrically arranged slider sleeves are fitted on the outer side of the central tube at intervals. The slider sleeves have at least three sloping dovetail grooves evenly distributed along their circumference. At least three arc-shaped push blocks are provided between the two symmetrically arranged slider sleeves. The left and right ends of the arc-shaped push blocks are located in the sloping dovetail grooves on the two slider sleeves, respectively. The arc-shaped push blocks corresponding to the installation positions of the anchor claw components have dovetail grooves on their outer sides. The inner end of the connector is connected to the dovetail groove and can slide within it. The outer end of the connector is threaded to the anchor claw component. The slider sleeve located on the left is fixedly installed to the outer cylinder by a shear pin.

2. The pressure-sealed, dragged, temporary plugging fracturing device according to claim 1, characterized in that... The anchor claw assembly includes a base and anchor claw installed together. The outer cylinder has a stepped hole that runs through the inside and outside. The inner end of the stepped hole is a small hole and the outer end is a large hole. A sand settling groove is provided at the junction of the large hole and the small hole. The base and anchor claw are installed in the large hole, and the outer end of the connector is threaded to the base.

3. The pressure-sealed drag-type temporary plugging fracturing device according to claim 2, characterized in that... A metal felt filter screen is installed inside the small hole.

4. The pressurized top-sealed drag-type temporary plugging fracturing device according to claim 1, 2, or 3, characterized in that... The sliding sleeve sandblasting device includes an upper connector, a lower connector, a limiting bushing, a plunger, and a return spring. The upper connector is threaded to the outer left end of the limiting bushing, and the lower connector is threaded to the outer right end of the limiting bushing. A sandblasting hole is provided in the middle of the limiting bushing. A first limiting ring platform is provided on the inner right side of the limiting bushing, and a second limiting ring platform is provided on the inner right side of the lower connector. An outer ring platform is provided on the outer side of the middle of the plunger. The outer ring platform is located between the first and second limiting ring platforms. A return spring is installed on the outer side of the plunger at the position between the outer ring platform and the second limiting ring platform.

5. The pressure-sealed drag-type temporary plugging fracturing device according to claim 4, characterized in that... The sliding sleeve sandblaster also includes a guide head. A conical guide head is installed on the left end of the plunger. A first carbide jacket is provided on both the inner and outer sides of the sandblasting hole. An inner liner is provided on the left side of the first carbide jacket located on the inner side. The right end of the inner liner can be sealed with the conical surface of the guide head.

6. The pressure-sealed drag-type temporary plugging fracturing device according to claim 5, characterized in that... The limiting bushing is fixed with anti-rotation pins at the installation positions of the upper and lower connectors.

7. The pressure-sealed, dragged, temporary plugging fracturing device according to claim 1, 2, 3, 5, or 6, characterized in that... The bottom packer is a Y341 packer, and the top packer is a suspended Y211 packer; a second hard alloy jacket is installed on the outside of the flow channel opening of the screen tube. The second hard alloy jacket has a flow port that communicates with the flow channel opening. The inner diameter of the flow port is smaller than that of the flow channel opening. A safety pin is installed between the body and the lower conversion joint.

8. A fracturing method using the pressure-sealed drag-and-plug fracturing device according to any one of claims 4-7, characterized in that... Perform the following steps: Step 1: Measure the actual dimensions of the tool before it is lowered into the well; Step 2: Use a wellbore gauge and scraper of the specified size to clean the well and scrape to a depth below the target formation. Step 3: Lower the pressurized top seal and drag the temporary plugging fracturing device to the predetermined depth; isolate the lowest layer to be modified from the modified layers; and also isolate the upper unmodified layers from the modified layers. Step 4: Use the casing coupling locator to drag the pressurized top seal temporary plugging fracturing device to the design depth; Step 5: Lift and lower the tubing string, and set the top packer; Step 6: Start the pump to inject fracturing fluid into the annulus. The fracturing fluid enters the 3.5-inch tool string cavity from the annulus through the screen tube, and the bottom packer is set. Step 7: Pump fracturing fluid according to the fracturing pump injection procedure, observe the changes in wellhead pressure and annular pressure, and determine the packer setting status; Step 8: Start the pump and pump fracturing fluid according to the pumping procedure. In the later stage of the proppant addition stage, add a mixed fracturing fluid containing a certain proportion of water-soluble temporary plugging agent and proppant to temporarily plug the fracturing section in a targeted manner. Step 9: Stop the pump, observe the changes in wellhead pressure and annular pressure, and determine the packer setting status and temporary plugging effect; Step 10: Raise the tubing string and align the sandblasting nozzle with the next layer to be modified. Repeat steps 5-9 until fracturing operations are completed for all layers. If the next level of the layer to be modified already has a modified section, temporary plugging agent shall be used to temporarily plug it according to the specific circumstances. Step 11: Stop the pump and observe the wellhead pressure and annular pressure; Step 12: Use pressurized equipment to remove the downhole tool string; Step 13 involves performing continuous tubing flushing to restore reservoir production.

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