A distributed optical fiber horizontal well fluid production profile testing device and method

Abstract

The present application belongs to the technical field of oil well testing, and particularly relates to a distributed optical fiber horizontal well liquid production profile testing device and method, which comprises a logging vehicle erected at a wellhead, a winch system and an injection head system sequentially arranged on the logging vehicle, a coiled tubing wound on a drum of the winch system, a special optical cable arranged in the coiled tubing, and a distributed optical fiber sensor unit arranged at an end of the coiled tubing and protected by a slotted screen pipe; wherein the coiled tubing is driven by the injection head system to enter the well from a side pipe opening of a double-pipe wellhead of a pumping unit Christmas tree, so that the distributed optical fiber sensor unit is transported to a predetermined depth in the well in the oil production well to obtain distributed temperature sensing and distributed acoustic wave sensing monitoring data of the whole well section of the heavy oil horizontal well; the present application can quantify the wellbore flow characteristics and reservoir response, locate high-yield sections, low-efficiency sections or ineffective sections, and effectively find potential layers in production wells.

Description

Technical Field

[0001] This invention belongs to the field of oilfield well testing technology, and in particular relates to a distributed optical fiber horizontal well production profile testing device and method. Background Technology

[0002] Heavy oil (crude oil) is an important component of global oil and gas resources. It has high viscosity and extremely poor fluidity, resulting in low extraction efficiency from traditional vertical wells. With the widespread application of horizontal well technology, heavy oil extraction is gradually shifting towards long horizontal wells to increase drainage area and single-well production capacity. However, the complex wellbore structure of horizontal wells and the special fluid properties of heavy oil make production profile testing technology a key challenge for optimizing development plans and improving recovery rates.

[0003] However, existing production profile testing methods for heavy oil horizontal wells face numerous limitations due to the high viscosity and poor fluidity of heavy oil, which easily lead to gas-liquid stratification and heterogeneous flow. These limitations are as follows: First, traditional testing techniques have limitations. Conventional production logging instruments are difficult to effectively lower and center in horizontal well sections, and the instruments are prone to adhesion and blockage in heavy oil wells, which may affect normal production during the testing process.

[0004] Secondly, the spatial resolution of point measurements is limited. Traditional methods can only provide fixed-point measurement data, making it difficult to obtain continuous flow characteristics of the entire horizontal well section, and have limited ability to identify non-uniform flow of heavy oil.

[0005] Third, the challenge of high temperature and high pressure environment. Heavy oil reservoirs are usually in high temperature and high pressure conditions. The accuracy of conventional electronic sensors decreases in high temperature environment, and the long-term stability of the testing system is difficult to guarantee. Summary of the Invention

[0006] This invention provides a distributed fiber optic horizontal well production profile testing device and method, which can effectively discover potential layers in production wells, guide segmented water control, water shut-off, or repeated fracturing, reduce ineffective cycles, and provide a reliable basis for formulating potential tapping and efficiency enhancement measures.

[0007] This invention is achieved through the following technical solution: This invention relates to a distributed fiber optic horizontal well production profile testing device, comprising a logging rig erected at the wellhead, a winch system and an injection head system sequentially mounted on the logging rig, a coiled tubing wound around the drum of the winch system, a special optical cable installed inside the coiled tubing, and a distributed fiber optic sensor unit installed at the end of the coiled tubing and protected by a slotted screen. The coiled tubing, driven by the injection head system, enters the well from the auxiliary pipe opening of the wellhead of the pumping unit's production tree, allowing the distributed fiber optic sensor unit to be transported to a predetermined depth within the well to acquire distributed temperature sensing and distributed acoustic wave sensing monitoring data for the entire section of the heavy oil horizontal well.

[0008] As a preferred embodiment of the present invention, the continuous tubing is made of stainless steel with an outer diameter of 13-26 mm and a wall thickness of 2 mm. The distributed optical fiber sensor unit includes a distributed optical fiber temperature sensor with a single-core multimode optical fiber and a distributed optical fiber acoustic wave sensor with a single-core single-mode optical fiber.

[0009] As a preferred embodiment of the present invention, the auxiliary port of the dual-tube wellhead is sequentially equipped with a test valve, a wellhead sub, a quick connector, a blowout preventer, and a grease-sealed packing box from the wellhead upwards.

[0010] As a preferred embodiment of the present invention, the grease-filled sealing packing box includes a lower box body, a sealing packing component installed in the lower box body, an upper box body threadedly connected to the lower box body, a grease injection nozzle installed on the upper box body, and a toggle plate installed on the upper box body; wherein, the grease-filled sealing packing box is equipped with an adjustable support assembly for supporting the separated upper box body.

[0011] As a preferred embodiment of the present invention, the adjustable support assembly includes a connecting block installed on the side of the toggle plate, the connecting block having a threaded blind hole; the adjustable support assembly also includes a threaded support block fixedly installed to the outer ring surface of the lower box by a connecting rod, the threaded support block having a through threaded hole; the adjustable support assembly also includes a threaded support rod with a smooth middle section and threaded grooves at both ends, the threaded support rod being threadedly connected to the threaded blind hole and the through threaded hole.

[0012] As a preferred embodiment of the present invention, the grease-filled sealing packing box further includes a packing bracket installed in the lower box body for installing the sealing packing component, and the adjustable support assembly is equipped with a push-removal assembly for disassembling or installing the packing bracket.

[0013] As a preferred embodiment of the present invention, the packing support includes a connecting ring embedded in the bottom of the lower box body, a plurality of bottom support blocks installed on the inner ring surface of the connecting ring, and a plurality of vertical support rods installed on the outer ring surface of the connecting ring in a vertical state; wherein, the bottom of the lower box body is provided with a plurality of embedding grooves to facilitate the embedding of the bottom support blocks, and the inner wall of the lower box body is provided with a plurality of embedding vertical grooves to facilitate the embedding of the vertical support rods.

[0014] As a preferred embodiment of the present invention, the push-disassembly assembly includes a support ring movably sleeved on a threaded support rod, a block installed on one side of the support ring, a nut installed on the block, a horizontal insertion rod threadedly connected to the nut, a locking bolt threadedly connected to the support ring for locking the support ring, and a push-slip ring movably sleeved on the threaded support rod; wherein, a radial guide groove is provided at the upper opening of the lower box for the horizontal insertion rod to move, and a mating insertion hole is provided at the top of the vertical support rod and aligned with the radial guide groove for the horizontal insertion rod to be inserted.

[0015] A method for testing the production profile of a distributed fiber optic horizontal well, applicable to the aforementioned distributed fiber optic horizontal well production profile testing equipment, includes the following steps: S1: Logging Instrument Deployment: The winch system and injection head system of the logging truck for horizontal wells deliver the coiled tubing, special optical cable, and distributed fiber optic sensor unit at the end to the predetermined depth in the well. S2: Well logging equipment connection: Insert the special optical cable connector into the ground acquisition system and connect the ground acquisition system to the computer power supply; S3: Well logging process: Well logging design scheme is formulated as follows: first system background test → second system production period test → third system shut-in test; S4: Data monitoring: Monitor the well status data during the shut-in phase and the production phase respectively; S5: Logging Instruments and Equipment Reset: The coiled tubing, special optical cable, and distributed fiber optic sensor unit at the end are lifted to the wellhead via the winch system and injection head system, and then the logging truck, winch system, and injection head system are reset. S6: Data Preservation: Verify and save the original logging data. Use a seismic-resistant box to store the field data hard drive to avoid data loss or damage. Hand over and preserve the data in accordance with the requirements for electronic data archiving.

[0016] The present invention has the following beneficial effects: This invention utilizes a dedicated logging rig, winch system, and injection head system for horizontal wells to deliver special optical cables and distributed fiber optic sensor units protected by coiled tubing into the well. This allows the distributed fiber optic sensor units of the logging instrument to be accurately and effectively lowered and centered in the horizontal well section, without causing adhesion or blockage in heavy oil wells.

[0017] The distributed optical fiber sensor unit of this invention uses a distributed optical fiber temperature sensor with a single-core multimode optical fiber and a distributed optical fiber acoustic sensor with a single-core single-mode optical fiber. It can acquire distributed temperature sensing and distributed acoustic sensing monitoring data of the entire well section of heavy oil horizontal wells, quantify wellbore flow characteristics and reservoir response, locate high-yield sections, low-efficiency sections or ineffective sections, and effectively discover potential layers in production wells.

[0018] This invention uses 316L stainless steel for the continuous oil tubing protecting the special optical cable, making it suitable for use in environments ranging from 0℃ to 375℃. It can effectively protect the distributed optical fiber sensor unit and the special optical cable from high temperature and pressure. Furthermore, each sensor is coated with a high temperature and pressure resistant material, ensuring that its accuracy will not decrease in high-temperature environments, thereby guaranteeing the long-term stable operation of the testing system.

[0019] Of course, any product implementing this invention does not necessarily need to achieve all of the advantages described above at the same time. Attached Figure Description

[0020] To more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0021] Figure 1 This is a simplified structural diagram of the testing equipment according to an embodiment of the present invention; Figure 2 This is a schematic diagram of the internal structure of the slotted screen tube according to an embodiment of the present invention; Figure 3 This is a connection diagram of the blowout preventer and the grease-sealed packing box according to an embodiment of the present invention. Figure 4 This is an exploded view of the assembly of the upper and lower box bodies according to an embodiment of the present invention; Figure 5 This is an assembly diagram of the packing support and sealing packing component according to an embodiment of the present invention; Figure 6 This is an exploded view of the packing support and lower housing according to an embodiment of the present invention.

[0022] In the diagram: 1. Logging rig; 2. Winch system; 3. Injection head system; 4. Coiled tubing; 41. Special optical cable; 42. Slotted screen pipe; 43. Distributed fiber optic sensor unit; 5. Blowout preventer; 6. Grease-sealed packing box; 61. Lower box body; 611. Radial guide groove; 62. Sealing packing component; 63. Upper box body; 64. Grease nozzle; 65. Actuating plate; 7. Adjustable support assembly; 71. Connecting block; 72. Threaded support block; 73. Threaded support rod; 8. Packing support; 81. Connecting ring; 82. Bottom support block; 83. Vertical support rod; 84. Butt socket; 9. Push-off disassembly assembly; 91. Support ring; 92. Square block; 93. Horizontal insertion rod; 94. Locking bolt; 95. Push-off slip ring. Detailed Implementation

[0023] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0024] In the description of this invention, it should be understood that the terms "opening", "upper", "lower", "thickness", "top", "middle", "length", "inner", "around", etc., which indicate orientation or positional relationship, are only for the convenience of describing this invention and simplifying the description, and do not indicate or imply that the components or elements referred to must have a specific orientation, or be constructed and operated in a specific orientation, and therefore should not be construed as limiting this invention.

[0025] Example 1: Please refer to Figures 1-6 As shown, the present invention is a distributed fiber optic horizontal well production profile testing device, including a logging rig 1 erected at the wellhead, a winch system 2 and an injection head system 3 sequentially mounted on the logging rig 1, a coiled tubing 4 wound on the drum of the winch system 2, a special optical cable 41 installed inside the coiled tubing 4, and a distributed fiber optic sensor unit 43 installed at the end of the coiled tubing 4 and protected by a slotted screen pipe 42; wherein, the coiled tubing 4 enters the well from the auxiliary pipe opening of the double-tube wellhead of the pumping unit's production tree under the drive of the injection head system 3, so that the distributed fiber optic sensor unit 43 is transported to a predetermined depth in the well to obtain distributed temperature sensing and distributed acoustic wave sensing monitoring data of the entire section of the heavy oil horizontal well; As the optimal implementation of this solution, the continuous tubing 4 is made of stainless steel with an outer diameter of 13-26 mm and a wall thickness of 2 mm. The distributed optical fiber sensor unit 43 includes a distributed optical fiber temperature sensor with a single-core multimode optical fiber and a distributed optical fiber acoustic wave sensor with a single-core single-mode optical fiber. Specifically, the distributed fiber optic temperature sensor uses a 62.5 / 125μm single-core multimode fiber coated with aluminum foil and other metal materials, and measures temperatures from -40℃ to 400℃. It is used to acquire distributed temperature signals (DTS) throughout the entire well section of heavy oil horizontal wells. The distributed fiber optic acoustic sensor uses a 9 / 125μm single-core single-mode fiber coated with aluminum foil and other metal materials, and is used to acquire distributed acoustic signals (DAS) throughout the entire well section of heavy oil horizontal wells. The coiled tubing 4 is preferably made of 316L stainless steel with an outer diameter of 13–26m. The tubing has a diameter of 1.5m, a wall thickness of 2mm, and is corrosion-resistant and pressure-resistant. Its surface is free of obvious dents and scratches, making it suitable for use in environments ranging from 0℃ to 375℃. Based on the manufacturing process of Φ19 continuous tubing with built-in distributed optical fiber, its minimum bending radius is 1.5m. During the well run, the bending radius must be maintained above 1.5m throughout the entire process. When selecting a well, the wellbore trajectory data should be used to determine whether the logging conditions can be met. If other specifications of miniature continuous tubing (such as φ14, φ25, etc.) are selected, their minimum bending radius should meet the transmission requirements of the horizontal well testing channel.

[0026] As the optimal implementation of this solution, the auxiliary pipe port of the dual-pipe wellhead is sequentially installed from the wellhead upwards with a test valve, a wellhead short section, a quick connector, a blowout preventer 5, and a grease-sealed packing box 6; Specifically, the test valve is used to test whether the wellhead pressure is balanced. For example, after the equipment is in place and the logging control software is started, the wellhead safety needs to be checked and confirmed before slowly opening the wellhead test valve to observe the pressure change of the blowout preventer 5. When the fluid in the well enters the blowout preventer 5, the operation should be stopped. When the pressure in the blowout preventer 5 is balanced with the pressure in the well, the test valve is fully opened. The side of the wellhead short section is the oil discharge nozzle, which is used to release pressure and guide oil after the test is completed. The grease-filled sealing packing box 6, which allows the coiled tubing 4 to pass through, is different from the ordinary pumping unit polished rod packing box. Its core function is to seal, protect, fix and ensure signal transmission of the special optical cable 41 for monitoring in the auxiliary pipe port. The sealing packing component 62 installed in the grease-filled sealing packing box 6 is filled with sealing grease to fill the gap and seal under pressure, which is used to isolate the leakage of crude oil, natural gas and formation pressure in the well, so as to adapt it to the pressure-bearing conditions of the oil wellhead.

[0027] Example 2: Compared to the existing method of installing a hanger on the sucker rod to suspend and fix the disassembled upper housing 63, and then disassembling the long-term damaged sealing packing 62, this Example 2 makes the following improvements: For the optimal implementation of this solution, please refer to Figures 4-6As shown, the grease-filled sealing packing box 6 includes a lower box body 61, a sealing packing member 62 installed in the lower box body 61, an upper box body 63 threadedly connected to the lower box body 61, a grease injection nozzle 64 installed on the upper box body 63, and a toggle plate 65 installed on the upper box body 63; wherein, the grease-filled sealing packing box 6 is equipped with an adjustable support assembly 7 for supporting the separated upper box body 63; Specifically, although a grease nipple 64 is installed on the upper housing 63, grease can be injected into the upper housing 63 and the lower housing 61 after connection, so that the special sealing packing 62 and the special sealing grease can achieve a flexible seal, without forcibly compressing the special optical cable 41, without generating additional stress and strain on the optical fiber, and without affecting the measurement accuracy of optical fiber sensing and monitoring, there is at least one toggle plate 65. If it is to facilitate driving the upper housing 63 to rotate, two plates can also be set and welded symmetrically to the outside of the upper housing 63. When the sealing packing 62 is used for a long time, impurities adhering to the coiled tubing 4 will inevitably come into contact with the sealing packing 62, causing wear and damage. Therefore, it is necessary to remove the upper housing 63 from the lower housing 61 to replace the internal sealing packing 62. When it is necessary to remove the long-used sealing packing 62 from the lower housing 61 online, it is necessary to ensure that the entire pumping well equipment is in a safe, non-operating state. Then, move the actuating plate 65 to rotate the upper housing 63, making it easy to remove the threaded upper housing 63 from the lower housing 61 (since the lower housing 61 is fixed to the blowout preventer 5). Because the coiled tubing 4 that penetrates into the grease-filled sealing packing box 6 has a small diameter and a certain degree of flexibility, if it is still used... The existing method of installing a hanger on the sucker rod to suspend and fix the disassembled upper housing 63 makes it difficult to quickly install the hanger onto the coiled tubing 4, thus hindering the suspension and fixation of the disassembled upper housing 63. However, when the upper housing 63 is disassembled from the lower housing 61, the operator can use the adjustable support assembly 7 to suspend and support the disassembled upper housing 63 above the lower housing 61, facilitating the quick removal of the sealing packing 62 from the lower housing 61. Then, the new sealing packing 62 can be installed into the lower housing 61. Furthermore, some components of the adjustable support assembly 7 can be disassembled, allowing for a quick connection of the upper housing 63 to the lower housing 61. The adjustable support assembly 7 does not interfere with the normal movement of the coiled tubing 4 within the grease-filled sealing packing box 6.

[0028] In the preferred embodiment of this solution, the adjustable support assembly 7 includes a connecting block 71 mounted on the side of the toggle plate 65, and the connecting block 71 has a threaded blind hole; the adjustable support assembly 7 also includes a threaded support block 72 fixedly mounted to the outer ring surface of the lower housing 61 by a connecting rod, and the threaded support block 72 has a through threaded hole; the adjustable support assembly 7 also includes a threaded support rod 73 with a smooth middle section and threaded grooves at both ends, and the threaded support rod 73 is threadedly connected to the threaded blind hole and the through threaded hole; Specifically, if the toggle plate 65 is set to two sets, the adjustable support assembly 7 is also set to two sets accordingly. The bottom of the threaded support rod 73 is equipped with a rotating handle, and the two ends of the threaded support rod 73 are formed with threaded grooves that cooperate with the threaded blind hole and the through threaded hole. Therefore, after the upper box 63 is rotated and disassembled from the lower box 61, the top of the threaded support rod 73 can be twisted through the threaded support block 72. After the upper part of the threaded groove of the threaded support rod 73 passes through the threaded support block 72, the threaded support rod 73 is pushed so that it slides into the threaded blind hole of the connecting block 71. Then the threaded support rod 73 is rotated or pushed. If the threaded support rod 73 is pushed, the upper box 63 will be pushed upward through the connecting block 71 and the actuating plate 65. After the lower part of the threaded groove of the threaded support rod 73 contacts the through threaded hole, the threaded support rod 73 is twisted. At this time, the two parts of the threaded groove on the threaded support rod 73 will be connected to the threaded blind hole and the through threaded hole respectively. Then the upper box 63 can be suspended and supported by the threaded support rod 73, the connecting block 71 and the threaded support block 72. The threaded support rod 73 can be twisted to adjust the distance between the upper box 63 and the lower box 61 so as not to interfere with the disassembly and replacement of the sealing packing 62 inside the lower box 61. If the threaded support rod 73 is rotated first, the top of the threaded support rod 73 will be threaded into the threaded blind hole of the connecting block 71. Then, the operator pushes the threaded support rod 73 upward, so that it can push the threadedly connected actuating plate 65 and upper box 63 upward. Since the upper box 63 has been fixed by the threaded support rod 73, the upper box 63 will not wobble when pushed upward. When the lower part of the threaded groove of the threaded support rod 73 contacts the through threaded hole, if the threaded support rod 73 is rotated again, the threaded support rod 73 will not only push the upper box 63 to continue to move upward, but also make the lower part of the threaded groove threaded into the through threaded hole, so as to fix and support the separated upper box 63.

[0029] Example 3: Compared to Example 2, where the sealing packing 62 is manually removed from the lower housing 61, Example 3 makes the following improvements: For the optimal implementation of this solution, please refer to Figures 4-6As shown, the grease-filled sealing packing box 6 also includes a packing bracket 8 installed in the lower box body 61 for installing the sealing packing component 62, and the adjustable support assembly 7 is equipped with a push-removal assembly 9 for disassembling or installing the packing bracket 8. Further specified, the packing support 8 includes a connecting ring 81 embedded in the bottom of the lower box 61, a plurality of bottom support blocks 82 installed on the inner ring surface of the connecting ring 81, and a plurality of vertical support rods 83 installed on the outer ring surface of the connecting ring 81 in a vertical state; wherein, the bottom of the lower box 61 is provided with a plurality of embedding grooves to facilitate the embedding of the bottom support blocks 82, and the inner wall of the lower box 61 is provided with a plurality of embedding vertical grooves to facilitate the embedding of the vertical support rods 83; Specifically, since the existing sealing packing 62 is basically directly installed into the lower housing 61, when it is necessary to disassemble and replace the sealing packing 62 that has been used for a long time, the operator can only use tweezers or other hand tools to remove the used sealing packing 62 from the lower housing 61. Since the sealing packing 62 has impurities such as grease or oil production fluid adhering to it, the removal of the sealing packing 62 will cause the impurities adhering to its surface to splash and have other effects. Since the new sealing packing 62 is basically in a spiral state, if the new sealing packing 62 is directly placed into the lower housing 61, firstly, the friction between the sealing packing 62 and the inner wall of the lower housing 61 will make it difficult for the sealing packing 62 to be installed downwards in sequence, requiring the use of auxiliary tools. Secondly, if the spiral sealing packing 62 is not installed tightly in the lower housing 61, it will affect the sealing and protection effect of the grease-filled sealing packing box 6 on the reciprocating sliding continuous oil tubing 4. Therefore, in this embodiment, a packing support 8 is installed inside the lower housing 61. When the packing support 8 is installed inside the lower housing 61, the connecting ring 81 is embedded in the annular groove at the bottom of the lower housing 61, while the at least four bottom support blocks 82 arranged in a circular array are embedded in the recessed grooves, and the four vertical support rods 83 arranged in a circular array are also embedded in the vertical grooves. Thus, the connecting ring 81, bottom support blocks 82, and vertical support rods 83 are all flush with the inner wall of the lower housing 61, and will not interfere with the installation of the sealing packing 62. The lower housing 61 has a good sealing effect on its inner wall and will not interfere with the threaded connection of the upper housing 63 to the lower housing 61. When it is necessary to remove the long-used sealing packing 62 from the lower housing 61, the push-release assembly 9 needs to be installed on the threaded support rod 73 first, and then the push-release assembly 9 is connected to the packing bracket 8. Then, by the upward pulling force of the push-release assembly 9, the packing bracket 8 can be pulled vertically out of the lower housing 61, and the sealing packing 62 located on the packing bracket 8 can be removed as a whole without causing any damage. To prevent the packing gland 62 from becoming scattered and to avoid excessive splashing of impurities adhering to its surface, when installing a new packing gland 62 into the lower housing 61, the spiral-shaped packing gland 62s are first stacked sequentially on the packing gland support 8, with the bottom of the packing gland 62 in contact with the bottom support block 82. Then, the spiral-shaped packing gland 62s are adjusted sequentially so that they are stacked on top of each other on the packing gland support 8. The multiple vertical support rods 83 of the packing gland support 8 can radially limit the stacked packing gland 62s, preventing them from scattering. The component 62 expands due to the extrusion force, and then the packing support 8 is pushed down by the push-disassembly assembly 9, which causes the stacked sealing packing components 62 to be quickly and stably inserted into the lower housing 61. Since the sealing packing components 62 are already stacked and attached to each other on the packing support 8, the sealing packing components 62 installed in the lower housing 61 will be tightly attached to the inner wall of the lower housing 61. This ensures that the installed sealing packing components 62 will not be excessively scattered, thus affecting the sealing effect on the moving continuous oil pipe 4.

[0030] As the preferred embodiment of this solution, the push-disassembly assembly 9 includes a support ring 91 movably sleeved on the threaded support rod 73, a block 92 installed on one side of the support ring 91, a nut installed on the block 92, a horizontal insertion rod 93 threadedly connected to the nut, a locking bolt 94 threadedly connected to the support ring 91 for locking the support ring 91, and a push-slip ring 95 movably sleeved on the threaded support rod 73; wherein, a radial guide groove 611 for moving the horizontal insertion rod 93 is provided at the upper opening of the lower box 61, and a mating insertion hole 84 for inserting the horizontal insertion rod 93 is provided at the top of the vertical support rod 83 and aligned with the radial guide groove 611; Specifically, after the upper housing 63 and lower housing 61 are disengaged from the threaded connection, the top end of the threaded support rod 73 will pass through the threaded support block 72. Then, the operator will sequentially put the push-slip ring 95 and the support ring 91 onto the threaded support rod 73 (the push-slip ring 95 is located below the support ring 91), and then push or twist the threaded support rod 73 upwards to separate the upper housing 63 from the lower housing 61. At this point, the packing support 8 can be removed from the lower housing 61 in two ways, as needed. The specific operations are as follows: Method 1: After the upper box 63 and lower box 61 are separated by a small distance, the operator first threads the horizontal insertion rod 93 onto the block 92, and moves the end of the horizontal insertion rod 93 radially to the outer surface of the lower box 61. Then, the operator pushes the support ring 91 upwards to align the end of the horizontal insertion rod 93 with the radial guide groove 611 and the mating hole 84. Then, the operator readjusts the radial movement distance of the horizontal insertion rod 93 so that it can be inserted into the mating hole 84. Finally, the operator twists the locking bolt 94 on the side of the support ring 91 to fix the support ring 91 to the threaded support rod 73. Then, when the operator pushes the threaded support rod 73 upward to further separate the upper housing 63 from the lower housing 61, the threaded support rod 73 will also drive the packing support 8 located in the lower housing 61 to be removed through the fixedly connected support ring 91 and horizontal insert rod 93, thus facilitating the replacement of the long-used sealing packing 62; then, if the operator finds that the packing support 8 cannot be quickly removed from the lower housing 61 due to long-term installation and internal impurities when pushing the threaded support rod 73 upward, a second method can be used, as follows: Method Two: After the threaded support rod 73 contacts or is threadedly connected to the connecting block 71, the operator first pushes the threaded support rod 73 upward to separate the upper box 63 and the lower box 61 to their maximum distance. Then, the threaded support rod 73 is threadedly connected to the connecting block 71 and the threaded support block 72, fixing the threaded support rod 73 in a fixed state. Next, the support ring 91 is pushed upward to align the horizontal insertion rod 93 with the mating hole 84. At this point, the horizontal insertion rod 93 is radially adjusted to insert into the aligned mating hole 84. The horizontal insertion rod 93 will then provide gravity support for the support ring 91. Finally, the operator pushes the push-slip ring 95 (similar to the sliding hammer of a pin puller) upward to allow the push-slip ring 95 to support the support ring. 91 generates an upward thrust, which allows the support ring 91 to move upward along the fixed threaded support rod 73. This facilitates the removal of the packing support 8 embedded in the lower housing 61 from the lower housing 61 by a certain distance. Then, the operator can manually push the support ring 91 upward as needed, so that it can drive the packing support 8 to be quickly and stably removed from the lower housing 61 via the horizontal insertion rod 93. When the packing support 8 is completely removed from the lower housing 61, the operator can then turn the locking bolt 94 to fix the support ring 91 on the threaded support rod 73. This makes it easier to fix the removed packing support 8 and allows the operator to quickly remove the sealing packing part 62 from the packing support 8. When the new spiral-shaped sealing packing components 62 are sequentially spirally stacked on the packing support 8, the operator can insert the pressure block into the mating hole 84 opened on the other vertical support rods 83 through the side pin, so that the pressure block can press the stacked sealing packing components 62 tightly. Then the operator loosens the locking bolt 94, so that the support ring 91 can slide down on the threaded support rod 73, thereby facilitating the quick insertion of the packing support 8 with the sealing packing components 62 installed into the lower box 61 through the horizontal insertion rod 93. Since the sealing packing components 62 stacked on the packing support 8 are pressed by the pressure block, the sealing packing components 62 will not become loose or fail to accurately descend to make precise contact with the inner bottom wall of the lower box 61 due to the friction between them when they come into contact with the inner wall of the lower box 61. When the packing support 8 After being fully installed into the lower box 61, the operator first removes the horizontal insert rod 93 from the mating hole 84, then removes the pressure block and corresponding pin from the mating hole 84, and then rotates the threaded support rod 73 in the opposite direction to make the upper box 63 descend vertically. When the upper box 63 is in contact with the lower box 61, the operator continues to rotate the threaded support rod 73 in the opposite direction to remove it from the connecting block 71. Then the support ring 91 and the push-slip ring 95 are removed from the threaded support rod 73 (because the gap between the top of the threaded support rod 73 and the connecting block 71 is large after separation). Then the threaded support rod 73 is rotated again to remove it from the threaded support block 72. This prevents the threaded support rod 73, support ring 91, and push-slip ring 95 from remaining on the grease-sealed packing box 6 for a long time. They are only used when the sealing packing part 62 needs to be disassembled and replaced. It should be noted that, in order to avoid a situation where a set of horizontal inserts 93 are only inserted into one of the vertical support rods 83, causing the upward pulling force of the horizontal inserts 93 to only act on a part of the packing bracket 8 when the support ring 91 moves upward, which would result in the packing bracket 8 being subjected to a tilted pulling force and unable to be quickly removed from the lower box 61, it is preferable to weld two toggle plates 65 to the outer ring surface of the upper box 63. Consequently, there are also two sets of the adjustable support assembly 7 and the push-disassembly assembly 9. This ensures that the packing bracket 8 is subjected to a uniform pulling force and downward pushing force when it is removed from or placed into the lower box 61, allowing the packing bracket 8 to drive the sealing packing 62 to be quickly and accurately removed and installed from the lower box 61.

[0031] A method for testing the production profile of a distributed fiber optic horizontal well, applicable to the aforementioned distributed fiber optic horizontal well production profile testing equipment, includes the following steps: S1: Logging Instrument Deployment: The winch system 2 and injection head system 3 of the horizontal well-specific logging vehicle 1 transport the coiled tubing 4, special optical cable 41, and the distributed fiber optic sensor unit 43 at the end to the predetermined depth in the well. Specifically, during the deployment process, to prevent the distributed fiber optic sensor unit 43 from being subjected to excessive bending, stretching, or compression, the following operations need to be performed: First, measure the speed, with the following requirements: Step 1: When measuring in the vertical well section, the speed should not exceed 350 m / h; Step 2: When measuring from the start of the inclined section to point A in the horizontal section (i.e., the starting point of the horizontal section), the speed should not exceed 300 m / h; Step 3: When measuring from point A in the horizontal section to point B (i.e., the ending point of the horizontal section), the speed should not exceed 200 m / h. Second, the predetermined logging depth must meet the following requirements: Step 1: The logging depth shall be performed according to the construction design plan. Under normal circumstances, the top of the coiled tubing 4 (including the guide cone) should pass through point B of the horizontal section of the horizontal well and be as close as possible to the bottom of the artificial well. Step 2: If the instrument gets stuck before reaching the predetermined depth, the emergency stop button should be pressed, and the control knob of the winch system 2 and the push pressure control knob of the injection head system 3 should be returned to zero. Step 3: When the predetermined depth is reached, the motor oil circuit switch should be turned off, and the control knob of the winch system 2 and the push pressure control knob of the injection head system 3 should be returned to zero. It should be noted that during the instrument lowering process: the logging truck 1 drives the coiled tubing 4 into the well from the auxiliary pipe opening of the double-tube wellhead of the pumping unit's tree; during the lowering process, the coiled tubing 4 at the lower end of the injection head system 3 remains vertical to the wellhead, and the angle difference between it and the tree's vertical axis is less than 5°. S2: Well logging equipment connection: Insert the special optical cable 41 connector into the ground acquisition system and connect the ground acquisition system to the computer power supply; specifically, the ground acquisition system includes a distributed fiber optic temperature measurement system, a distributed fiber optic acoustic wave sensing system, and various control systems. S3: Logging Process: The logging design scheme is formulated as follows: First system background test → Second system production period test → Third system shut-in test; Specifically, by changing the operating system of the production well, the production capacity of the producing section in the well changes, while continuously monitoring the changes in the fluid supply capacity of the production section under different operating conditions and the changes in the flow regime of the entire wellbore, ultimately improving the consistency rate between the interpretation results and the actual production, with the following requirements: First, the working principle of an oil pumping unit can be changed by adjusting the stroke or the number of strokes. Second, the opening and closing times of the well during the logging process should be recorded in detail; Under each work system, the monitoring cycle for DTS and DAS should be no less than 4.0 hours; S4: Data Monitoring: Monitor the well status data during the shut-in phase and the production phase respectively; specific operational requirements are as follows: First, the well shut-in status data monitoring is as follows: The preparation phase requires the following: Step 1: Close the wellhead production gate and keep the pumping unit in a stopped state; Step 2: Use distributed fiber optic temperature sensors and distributed fiber optic acoustic sensors to monitor the bottom hole background data; Second, the technical requirements for the data monitoring phase are as follows (including data quality control indicators): Step 1: Strictly follow the logging notification requirements to complete the monitoring work for the entire well section from the wellhead to the point where the instrument encounters obstruction. Step 2: The direct reading monitoring time for DTS background data should not be less than 2.0 hours, and the direct reading monitoring time for DAS background data should not be less than 1.0 hour. Step 3: The well reservoir coefficient in the previous unstable well test interpretation report can be used as a reference for the monitoring time of this logging background data. Step 4: After shutting in the well, if the average sound intensity fluctuation rate of the horizontal section DAS data within the 10Hz-100Hz frequency band is less than 5% within 15 minutes, it can be determined as DAS background data; if the temperature change of the horizontal section DTS data within each meter interval is less than 1℃ within 30 minutes, it can be determined as DTS background data. Secondly, data monitoring during the production phase should comply with the following procedures: During the preparation phase, the procedures are as follows: Step 1: Check the distance between the injection head system 3 and blowout preventer 5 of the logging truck 1 and the sucker rod of the pumping unit to ensure it meets the requirements for pumping operations; Step 2: Notify the on-site monitoring personnel to open the wellhead production gate; Step 3: Release the brake until the pumping unit head reaches the bottom dead center; Step 4: Operate the power distribution cabinet to start the pumping unit for production stage monitoring. Second, the data monitoring phase, the operation is as follows: Step 1: As required by the logging notification, monitor the entire well section from the wellhead to the point where the instrument encounters resistance at the bottom of the well; for pumping units with variable speed adjustment, full-section monitoring should be conducted under different stroke conditions; Step 2: Based on the direct reading monitoring results, continuously measure and record the response values ​​of different wavebands; Step 3: The direct reading monitoring time should not be less than 3 hours, and the specific monitoring time should be based on repeating the horizontal section produced fluid response curve more than 3 times; S5: Logging Instruments and Equipment Reset: The coiled tubing 4, special optical cable 41, and the distributed fiber optic sensor unit 43 at the end are pulled to the wellhead via the winch system 2 and injection head system 3. Then, the logging rig 1, winch system 2, and injection head system 3 are reset. Specific operations are as follows: After logging is completed, the coiled tubing 4 is pulled up. During the retrieval process, the distributed fiber optic sensor unit 43 is protected from excessive bending, stretching, or compression. The following operations are performed: Step 1: From point B in the horizontal section to point A, the lifting speed should not exceed 200 m / h; Step 2: From point A in the horizontal section to the end of the directional drilling section, the lifting speed should not exceed 300 m / h; Step 3: When in the vertical section, the lifting speed should not exceed 350 m / h; Step 4: When gradually decelerating to 50 m from the wellhead, the lifting speed should not exceed 100 m / h. Second, the tension gauge should be monitored in real time throughout the entire process of raising the coiled tubing 4, with the following requirements: Step 1: When the tension data curve rises rapidly, the hydraulic valve should be adjusted immediately or the system should be stopped. Step 2: When the tension data curve gradually rises to the upper limit of the permissible tension of the coiled tubing, the lifting speed should be slowed down or the lifting should be stopped. The instrument should be lowered and then lifted again to restore normal operation. S6: Data Preservation: Verify and save the original logging data. Use a seismic protection box to protect the field data hard drive to prevent data loss or damage. Hand over and preserve the data in accordance with electronic data archiving requirements.

[0032] In the description of this specification, references to terms such as "an embodiment," "example," "specific example," etc., indicate that a specific feature, structure, material, or characteristic described in connection with that embodiment or example is included in at least one embodiment or example of the invention. In this specification, illustrative expressions of the above terms do not necessarily refer to the same embodiment or example. Furthermore, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in one or more embodiments or examples.

[0033] The preferred embodiments of the present invention disclosed above are merely illustrative of the invention. These preferred embodiments do not exhaustively describe all details, nor do they limit the invention to the specific implementations described. Clearly, many modifications and variations can be made based on the content of this specification. This specification selects and specifically describes these embodiments to better explain the principles and practical applications of the invention, thereby enabling those skilled in the art to better understand and utilize the invention. The invention is limited only by the claims and their full scope and equivalents.

Claims

1. A distributed fiber optic horizontal well production profile testing device, comprising a logging rig erected at the wellhead and a winch system and an injection head system sequentially mounted on the logging rig, characterized in that, It also includes a continuous tubing wound around the drum of the winch system, a special optical cable installed inside the continuous tubing, and a distributed optical fiber sensor unit installed at the end of the continuous tubing and protected by a slotted screen. The coiled tubing, driven by the injection head system, enters the well from the auxiliary pipe opening of the double-tube wellhead of the pumping unit's production tree, allowing the distributed fiber optic sensor unit to be delivered to a predetermined depth within the well to obtain distributed temperature sensing and distributed acoustic wave sensing monitoring data for the entire section of the heavy oil horizontal well. The auxiliary port of the dual-tube wellhead is equipped with a test valve, a wellhead short section, a quick connector, a blowout preventer, and a grease-sealed packing box in sequence from the wellhead upwards; the grease-sealed packing box includes a lower box body, a sealing packing component installed in the lower box body, an upper box body threadedly connected to the lower box body, a grease injection nozzle installed on the upper box body, and an actuating plate installed on the upper box body. The grease-sealed packing box is equipped with an adjustable support assembly for supporting the separated upper box body. The adjustable support assembly includes a connecting block installed on the side of the actuating plate, and the connecting block has a threaded blind hole. The adjustable support assembly also includes a threaded support block fixedly installed to the outer ring surface of the lower box body by a connecting rod, and the threaded support block has a through threaded hole. The adjustable support assembly also includes a threaded support rod with a smooth middle section and threaded grooves at both ends, and the threaded support rod is threadedly connected to the threaded blind hole and the through threaded hole. The grease-sealed packing box also includes a packing bracket installed in the lower box for installing the sealing packing components, and the adjustable support assembly is equipped with a push-release assembly for disassembling or installing the packing bracket. The packing support includes a connecting ring embedded in the bottom of the lower box, multiple bottom support blocks installed on the inner ring surface of the connecting ring, and multiple vertical support rods installed on the outer ring surface of the connecting ring in a vertical position. The push-disassembly assembly includes a support ring movably sleeved on a threaded support rod, a block installed on one side of the support ring, a nut installed on the block, a horizontal insert rod threadedly connected to the nut, a locking bolt threadedly connected to the support ring for locking the support ring, and a push-slip ring movably sleeved on the threaded support rod. The lower box has a radial guide groove at the upper opening for the horizontal insertion rod to move, and the top of the vertical support rod, aligned with the radial guide groove, has a mating hole for the horizontal insertion rod to be inserted.

2. The distributed optical fiber horizontal well production profile testing equipment according to claim 1, characterized in that, The continuous tubing is made of stainless steel, with an outer diameter of 13-26 mm and a wall thickness of 2 mm. The distributed optical fiber sensor unit includes a distributed optical fiber temperature sensor with a single-core multimode optical fiber and a distributed optical fiber acoustic wave sensor with a single-core single-mode optical fiber.

3. The distributed optical fiber horizontal well production profile testing equipment according to claim 1, characterized in that, The bottom of the lower box body has multiple embedding grooves to facilitate the insertion of the bottom support block, and the inner wall of the lower box body has multiple embedding vertical slots to facilitate the insertion of the vertical support rod.

4. A method for testing the production profile of a distributed fiber optic horizontal well, the method being applicable to the distributed fiber optic horizontal well production profile testing equipment described in any one of claims 1-3, characterized in that, Includes the following steps: S1: Logging Instrument Deployment: The winch system and injection head system of the logging truck for horizontal wells deliver the coiled tubing, special optical cable, and distributed fiber optic sensor unit at the end to the predetermined depth in the well. S2: Well logging equipment connection: Insert the special optical cable connector into the ground acquisition system and connect the ground acquisition system to the computer power supply; S3: Well logging process: Well logging design scheme is formulated as follows: first system background test → second system production period test → third system shut-in test; S4: Data monitoring: Monitor the well status data during the shut-in phase and the production phase respectively; S5: Logging Instruments and Equipment Reset: The coiled tubing, special optical cable, and distributed fiber optic sensor unit at the end are lifted to the wellhead via the winch system and injection head system, and then the logging truck, winch system, and injection head system are reset. S6: Data Preservation: Verify and save the original logging data. Use a seismic-resistant box to store the field data hard drive to avoid data loss or damage. Hand over and preserve the data in accordance with the requirements for electronic data archiving.

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