Downhole laser tool and method
By using laser tools to generate annular collimated laser beams during drilling to clear the annulus between downhole equipment and the wellbore wall, the stuck drill problem was solved, enabling efficient release of stuck drill bits and recovery of fish, reducing the complexity of drilling operations and equipment damage.
Patent Information
- Authority / Receiving Office
- CN · China
- Patent Type
- Patents(China)
- Current Assignee / Owner
- SAUDI ARABIAN OIL CO
- Filing Date
- 2022-02-23
- Publication Date
- 2026-05-12
AI Technical Summary
During drilling, the drill string may get stuck, causing a stuck drill. Existing tools are not effective at releasing stuck drill bits and recovering stuck drill bits, especially in complex downhole environments, where traditional methods may damage downhole equipment.
A circular collimated laser beam is generated using a laser tool and lowered through the working string to the vicinity of the downhole equipment. This clears the annulus between the downhole equipment and the wellbore wall, releases the stuck drill bit, and retrieves the fallen fish using a retrieval tool.
Effectively clearing stuck drill bits prevents damage to downhole equipment, improves the success rate of stuck drill bit release and fish recovery, and reduces the complexity and cost of drilling operations.
Smart Images
Figure CN116888342B_ABST
Abstract
Description
Background Technology
[0001] Hydrocarbon fluids are typically found in hydrocarbon reservoirs located in porous rock formations below the surface. Hydrocarbon wells can be drilled to extract hydrocarbon fluids from these reservoirs. Hydrocarbon wells are drilled by running a drill string, consisting of a drill bit and a bottomspan assembly, into the wellbore to break up the rock and extend the wellbore's depth. Fluids can be pumped through the drill bit to help cool and lubricate it, provide bottomhole pressure, and carry drill cuttings to the surface. During drilling operations, the drill string can get stuck. A stuck drill string (commonly referred to as "stuck") occurs when the drill string cannot move up or down in the wellbore without applying excessive force. Often, when attempting to release the stuck string, a portion of the drill string may break off and remain in the wellbore. This portion of the drill string is called the "fish" and may require a retrieval operation to remove it from the wellbore.
[0002] Various types of tools (such as slappers and retrieval tools) are used to attempt to release stuck drill strings and retrieve fish. A slapper is a mechanical device that transfers an impact load to the stuck section of the drill string. A retrieval tool is typically tandemly driven with a rough drill surface that allows the retrieval tool to slightly drill through the stuck section, grabbing the fish so that it can be pulled out of the wellbore. Summary of the Invention
[0003] This summary is provided to introduce a series of concepts that will be further described in the following detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to help limit the scope of the claimed subject matter.
[0004] In one or more embodiments, this disclosure provides a laser system for releasing downhole equipment and a method of operating the system. Generally, in one or more embodiments, the laser system includes a laser tool with an inner diameter larger than the outer diameter of the downhole equipment, the laser tool having means for generating an annular collimated laser beam. The laser system also includes a working string with an inner diameter larger than the outer diameter of the downhole equipment. The laser tool is mounted on the working string, which descends around the downhole equipment. When the working string descends to a position where the laser tool is near an obstacle on the downhole equipment, the laser tool emits the annular collimated laser beam to clear the annulus between the downhole equipment and the wellbore wall, thereby releasing the downhole equipment.
[0005] In one or more embodiments, a method of operating the laser system includes mounting a laser tool onto a working string, the laser tool having means for generating an annular collimated laser beam. The inner diameter of the laser tool and the working string is larger than the outer diameter of the downhole equipment. The working string and the laser tool are lowered outside the downhole equipment to a position near an obstruction on the downhole equipment. The annular collimated laser beam is generated and emitted into the annulus between the downhole equipment and the wellbore wall to clear the obstruction, and the working string and the laser tool are pulled out of the wellbore.
[0006] Other aspects and advantages of the claimed subject matter will become apparent from the following description and the appended claims. Attached Figure Description
[0007] Figure 1 This is a schematic diagram of an exemplary well site according to one or more embodiments.
[0008] Figure 2 This is a schematic diagram of a downhole laser tool according to one or more embodiments.
[0009] Figure 3 This is a schematic diagram of a laser system according to one or more embodiments.
[0010] Figure 4 This is a schematic diagram of a laser system according to one or more embodiments.
[0011] Figure 5 This is a schematic diagram of a laser system according to one or more embodiments.
[0012] Figure 6 A flowchart according to one or more embodiments is shown.
[0013] Figure 7 A flowchart according to one or more embodiments is shown.
[0014] Figure 8 A flowchart according to one or more embodiments is shown. Detailed Implementation
[0015] Numerous specific details are set forth in the following detailed description of embodiments of the present disclosure in order to provide a more thorough understanding of the present disclosure. However, it will be apparent to those skilled in the art that the present disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.
[0016] Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as adjectives for elements (i.e., any noun in this application). Unless explicitly disclosed, such as by using the terms “before,” “after,” “single,” and other such terms, the use of ordinal numbers does not imply or create any particular order of elements, nor does it limit any element to a single element. Rather, the use of ordinal numbers is intended to distinguish between elements. As an example, a first element is distinct from a second element, and a first element may contain more than one element and be placed after (or before) the second element in the order of elements.
[0017] Figure 1 An exemplary well site 100 is shown. Generally, well sites can be configured in a variety of ways. Therefore, well site 100 is not intended to limit a specific configuration of drilling equipment. Well site 100 is described as being on land. In other examples, well site 100 may be located offshore and drilling may be carried out with or without a riser. Drilling operations at well site 100 may include drilling a wellbore 102 into the subsurface, including various formations 104, 106. To drill new sections of wellbore 102, a drill string 108 is suspended within wellbore 102. Drill string 108 may include one or more drill pipes 109 connected to form a conduit and a bottom drill assembly (BHA) 110 disposed at the distal end of the conduit. BHA 110 may include a drill bit 112 to cut into subsurface rock. BHA 110 may include measurement tools such as measurement-while-drilling (MWD) tools 114 and logging-while-drilling (LWD) tools 116. Measurement tools 114 and 116 may include sensors and hardware to measure downhole drilling parameters, and these measurements may be transmitted to the surface using any suitable telemetry system known in the art. BHA 110 and drill string 108 may include other drilling tools known in the art but not specifically shown.
[0018] The drill string 108 can be suspended in the wellbore 102 via a derrick 118. A crane 120 can be mounted on top of the derrick 118, and a traveling block 122 can be lowered from the crane 120 via a cable or drill rope 124. One end of the cable 124 can be connected to a winch 126, which is a winding device for adjusting the length of the cable 124 to allow the traveling block 122 to move up or down along the derrick 118. The traveling block 122 may include a hook 128, on which a top drive 130 is supported. The top drive 130 is coupled to the top of the drill string 108 and is operable to rotate the drill string 108. Alternatively, the drill string 108 can be rotated via a rotary table (not shown) on the drill rig 131. Drilling fluid (commonly referred to as mud) can be stored in a mud pit 132, and at least one pump 134 can pump mud from the mud pit 132 into the drill string 108. The mud can flow into the drill string 108 through the appropriate flow path in the top drive 130 (or by rotating the tap if a rotary table is used instead of the top drive to rotate the drill string 108).
[0019] In one embodiment, system 200 may be positioned at or in communication with well site 100. System 200 can control at least a portion of the drilling operation by providing control over various components of the drilling operation at well site 100. In one or more embodiments, system 200 may receive data from one or more sensors 160 arranged to measure controllable parameters of the drilling operation. As a non-limiting example, sensor 160 may be arranged to measure WOB (weight on bit), RPM (rotational speed of drill string), GPM (glued flow rate of mud pump), and ROP (mechanical rate of penetration of drilling operation). Sensor 160 may be positioned to measure parameters related to the rotation of drill string 108, parameters related to the travel of traveling block 122 (which can be used to determine the ROP of the drilling operation), and parameters related to the flow rate of pump 134. For illustrative purposes, sensor 160 is shown on drill string 108 and near mud pump 134. The shown location of sensor 160 is not intended to be limiting, and sensor 160 may be positioned wherever drilling parameters need to be measured. In addition, there can be a ratio Figure 1 More sensors 160 are shown to measure various other parameters of the drilling operation. Each sensor 160 can be configured to measure the desired physical stimulus.
[0020] During drilling operations at well site 100, drill string 108 rotates relative to wellbore 102, and weight is applied to drill bit 112 to enable it to break rock as drill string 108 rotates. In some cases, drill bit 112 can be rotated independently using a drilling motor. In another embodiment, drill bit 112 can be rotated using a combination of drilling motor and top drive 130 (or, if a rotary table is used instead of a top drive to rotate drill string 108, a rotary tap is used). While cutting rock with drill bit 112, mud is pumped into drill string 108. The mud flows downward along drill string 108 and is discharged through nozzles in drill bit 112 to the bottom of wellbore 102. The mud in wellbore 102 then flows upward back to the surface in the annulus between drill string 108 and wellbore 102 along with entrained drill cuttings. The mud with drill cuttings is returned to pool 132 for recirculation back into drill string 108. Typically, drill cuttings are removed from the mud before it is pumped back into the drill string 108, and the mud is repaired as needed. In one or more embodiments, drilling operations may be controlled by system 200.
[0021] In one or more embodiments, Figure 2 The configuration of the proposed laser tool 202 is depicted, comprising a laser head housing 204, an optical fiber cable 206, a first lens 208, a second lens 210, and a cover lens 212. The laser head housing 204 houses and protects the optical fiber cable 206, the first lens 208, the second lens 210, and the cover lens 212. The cover lens 212 protects the first lens 208 and the second lens 210 from spatter and debris during laser processing. The optical fiber cable 206 generates a raw laser beam 214, which enters the first lens 208, which focuses and controls the shape of the beam. The raw laser beam 214 enters the second lens 210 to generate a ring-collimated laser beam 216.
[0022] The first lens 208 and the second lens 210 can be conical lenses with specific interior angles 218, diameters 220, edge thicknesses 222, and center thicknesses 224. The first lens 208 and the second lens 210 have specific aspect ratios, which are the ratios of the center thicknesses 224 to the diameters 220 of the lenses 208 and 210. The aspect ratios and interior angles 218 of the first lens 208 and the second lens 210 determine the inner diameter 226, the outer diameter 228, and the eccentricity of the annular collimated laser beam 216.
[0023] The eccentricity of the annular collimated laser beam 216 can be a circular, parabolic, or elliptical transverse beam profile. The diameter 220 of lenses 208 and 210 should be a value between 1.1 times the outer diameter 228 of the annular collimated laser beam 216 and 1.9 times the inner diameter of the laser tool 202. The outer diameter 228 of the annular collimated laser beam 216 is given by Equation 1 (hereinafter), where D... OD beam = Outer diameter 228 of the annular collimated laser beam 216; L = Distance between the tips of the two lenses 208 and 210, where R = radius of lens 208, 210; θ = interior angle 218°; n = effective refractive index of lens 208°, 210°
[0024]
[0025] To achieve collimation of the original laser beam 214, the interior angles 218 of the first lens 208 and the second lens 210 must be the same. Additionally, lenses 208 and 210 can be images, for example... Figure 2 As shown, lenses 208 and 210 can also be interchanged in the opposite direction to the direction shown. The edge thickness can be any thickness, but it is usually between 1 mm and 10 mm. Equation 2 (hereinafter) shows the relationship between the center thickness 224 = CT, the edge thickness 222 = ET, the diameter 220 = D, and the interior angle 218 = θ of lenses 208 and 210.
[0026]
[0027] The thickness of the annular collimated laser beam 216 is the lateral distance between the outer diameter 228 and the inner diameter 226 of the annular collimated laser beam 216. The thickness is determined using Equation 3 (hereinafter), where BT = thickness of the annular collimated laser beam 216; n = the effective refractive index of lenses 208 and 210; θ = interior angle 218.
[0028]
[0029] In another embodiment, an aspherical or spherical lens may be positioned between the first lens 208 and the second lens 210 or after the second lens 210 to reduce the thickness of the annular collimated laser beam 216. When the aspherical or spherical lens is positioned between the first lens 208 and the second lens 210, the annular collimated laser beam is reduced to at most the diffraction limit of the aspherical or spherical lens. When the aspherical or spherical lens is positioned after the second lens 210, the annular collimated laser beam is refined and focused and is independent of the diffraction limit of the aspherical or spherical lens.
[0030] The second lens 210 can be transformed into a switchable mirror or glass using electro-optic glass, electrochromic materials, or non-Hermitian materials to produce perfect transparency or reflectivity. A conical switchable mirror / glass with a flat surface can also be placed after the second lens 210 to reflect the annular collimated laser beam 216 radially outward away from the laser tool 202; however, the energy density of the annular collimated laser beam 216 will be reduced. A conical switchable mirror / glass with a hyperboloidal surface will maintain a higher energy density while still reflecting the annular collimated laser beam 216 radially outward away from the laser tool 202.
[0031] Those skilled in the art will understand that the method described above for generating the annular collimated laser beam 216 does not limit the scope of this disclosure. Any suitable method for generating the annular collimated laser beam (e.g., using static / dynamic refractive / diffractive elements, transforming optics, or micro / macro patterned windows / mirrors) can be used without departing from the scope of this disclosure.
[0032] Figure 3 A laser tool 302 deployed in wellbore 336 to release stuck drill bit. In one or more embodiments, downhole equipment 330 is stuck at multiple sticking points 334. Figure 3 As shown, downhole equipment 330 can be drill string 108, or it can be any equipment that can be used for any operation performed in wellbore 336, such as completion string, production string, casing, or any type of fitting or tool. A choke point 334 is shown as the bottom drill string assembly 110 surrounding drill string 108; however, a choke point 334 can appear anywhere along downhole equipment 330. Figure 3 A jamming point 334 caused by material 342 is shown. Material 342 that may cause jamming point 334 may include drill cuttings, wellbore debris, or tools that have broken or been lost in the wellbore 336. However, in another embodiment, jamming point 334 may be caused by irregularities in the wellbore wall 338. Irregularities in the wellbore wall 338 may be inconsistent inner diameters or portions of the wellbore wall 338 protruding or extending into the wellbore 336.
[0033] The laser tool 302 travels within the wellbore 336 via the working string 332. The inner diameters of the working string 332 and the laser tool 302 are larger than the outer diameter of the downhole equipment 330, causing them to descend around the downhole equipment 330. The laser tool 302 emits annular collimated laser beam 316 to remove material 342 or irregularities from the annulus 340 between the downhole equipment 330 and the wellbore wall 338, thereby removing obstacles and releasing the downhole equipment 330. The inner diameter 226 of the annular collimated laser beam 316 is larger than the outer diameter of the downhole equipment 330, allowing it to travel parallel to the downhole equipment 330 without damaging it.
[0034] Figure 4 A laser tool 402 is shown deployed in a wellbore 436 to release a stuck downhole device 430. In one or more embodiments, the downhole device 430 is stuck at multiple jamming points 434, and the downhole device 430 has broken or twisted. The laser tool 402 travels within the wellbore 436 via a retrieval tube tool 446. The retrieval tube tool 446 is used to retrieve the stuck device from the wellbore 436 and is typically configured with an upper connector 448, a bowl 450, grippers 452, and a packer 454. The upper connector 448 is the uppermost component of the retrieval tube tool 446 and is equipped with a box connection for connecting to a conduit 444 for lowering the retrieval tube tool 446 into the wellbore 436. The bowl 450 is the main working component of the retrieval tube tool 446. The inner diameter of the bowl 450 has a threaded portion that matches the external thread of the gripper 452.
[0035] Slip 452 is the clamping mechanism of the retrieval tool 446, and slip 452 can be a basket slip 452 or a spiral slip 452. A basket slip 452 is a grooved, expandable cylinder with wicked interior for engaging the fish. The basket slip 452 engages the fish by passing outside it, and when a tensile load is applied, slip 452 uses its wicker to bite into the fish. A spiral slip 452 is similar to a left-handed helical spring. Its outer diameter has a tapered shape that mates with a left-handed spiral cone in the barrel 450. Left-handed helical serrations in the bore provide catch wickers. A spiral slip 452 engages the fish by rotating in a specific direction outside it, and when a tensile load is applied, slip 452 bites into the fish to form a clamping portion that can pull the fish out of the wellbore 436.
[0036] Type A packer 454 is used in conjunction with spiral slips 452 to seal the interior of barrel 450 and the exterior periphery of the fish. Milling-controlled packer 454 is used in conjunction with basket slips 452 to provide a reliable seal around the fish and remove small burrs. Burrs are raised edges or small pieces of material that remain attached to the workpiece after the modification process. In one or more embodiments, fishing barrel tool 446 and laser tool 402 can be lowered into wellbore 436 by passing through from outside downhole equipment 430. Laser tool 402 can emit annular collimated laser beam 416 to remove material 442 from the annulus 440 between downhole equipment 430 and wellbore wall 436, thereby removing obstructions. Fishing barrel tool 446 can be engaged, and the fish can be pulled out of wellbore 436.
[0037] In one or more embodiments, Figure 5A laser tool 502 configured to cut downhole equipment 530 is shown. The laser tool 502 is lowered into the wellbore 536 via a working string 532. In this figure, the downhole equipment 530 is stuck in the wellbore 536 at multiple jamming points 534. Material 542 in the wellbore 536 has blocked the downhole equipment 530, creating the jamming points 534. The working string 532 and the laser tool 502 can be lowered into the wellbore 536 by passing through and surrounding the downhole equipment 530. The laser tool 502 can emit a conical annular collimated laser beam 517 and guide the laser beam 516 onto the downhole equipment 530. The conical annular collimated laser beam 517 can cut the downhole equipment 530 above the jamming points 534 to pull the detached portion of the downhole equipment 530 out of the wellbore 536.
[0038] When removing the cut downhole equipment 530, the remaining downhole equipment 530 or the fish that fell into the well can be retrieved using traditional salvage methods or by operating... Figure 3 or Figure 4 The laser system is released. The fish can remain in wellbore 536, and the well can be abandoned. Wellbore 536 can be plugged, and drilling operations can generate a sidetracked well from the original wellbore 536. For example... Figure 5 The laser system shown can be used Figure 4 The retrieval tool 446 introduced in the process was lowered into the wellbore 536. Figure 5 The laser system can collimate ring-type laser beams 216, 316, and 416 with... Figure 5 The laser tool 502 shown travels in series, thereby removing material 542 from the annulus 540 between the downhole device 530 and the wellbore wall 538 before or after the separated portion of the downhole device 530 has been removed from the wellbore 536.
[0039] Figure 6 A flowchart illustrating a laser system according to one or more embodiments is shown. Although Figure 6 The boxes in the document are presented and described in sequence, but those skilled in the art will understand that some or all of these boxes may be executed in a different order, may be combined or omitted, and may be executed in parallel. Furthermore, these boxes may be executed actively or passively.
[0040] Laser tools 202, 302, 402, and 502, equipped with means for generating annular collimated laser beams 216, 316, and 416, are mounted in working strings 332 and 532 (S656). Working strings 332 and 532 may include any conduit 444 capable of operating under downhole conditions, such as drill pipe 444. The means for generating the annular collimated laser beams 216, 316, and 416 may include a method using fiber optic cable 206, a first conical lens 208, and a second conical lens 210.
[0041] Fiber optic cable 206 transmits the original laser beam 214 into a first conical lens 208, which focuses and controls the shape of the beam. The diverging laser beam enters a second lens 210 to generate annular collimated laser beams 216, 316, 416. The inner diameter 226, outer diameter 228, and eccentricity of the annular collimated laser beams 216, 316, 416 can be varied according to the interior angle 218 and aspect ratio of the conical lenses 210, 212. Any means for generating the annular collimated laser beams 216, 316, 416 can be used in this disclosure without departing from the scope of this disclosure.
[0042] for Figure 6 In the method shown, the inner diameter 226 of the annular collimated laser beams 216, 316, and 416 is larger than the outer diameter of the downhole equipment 330, 430, and 530. Therefore, when the annular collimated laser beams 216, 316, and 416 are emitted, the downhole equipment 330, 430, and 530 will not be damaged. The inner diameters of the working tubing 332 and 532 and the laser tools 202, 302, 402, and 502 are larger than the outer diameters of the downhole equipment 330, 430, and 530, allowing the top drive 130 to lower the working tubing 332 and 532 and the laser tools 202, 302, 402, and 502 from outside the downhole equipment 330, 430, and 530 until the depth of the jamming points 334 and 434 inside the wellbore (S658).
[0043] Annular collimated laser beams 216, 316, and 416 are generated by laser tools 202, 302, 402, and 502 and emitted into the annulus 340, 440, and 540 between the downhole equipment 330, 430, and 530 and the wellbore walls 338, 438, and 538 (S660). The annular collimated laser beams 216, 316, and 416 drill out of the annulus 340, 440, and 540 and remove the material 342, 442, and 542 that caused the sticking points 334 and 434, in order to release the downhole equipment 330, 430, and 530 (S662). The material 342, 442, and 542 that may have caused the sticking points 334 and 434 may include drill cuttings, wellbore debris, or tools that have broken or been lost in the wellbore 336, 436, and 536.
[0044] The top drive 130 is used to pull the working tubing 332, 532 and laser tools 202, 302, 402, 502 out of the wellbore 336, 436, 536 (S664). After successfully releasing the downhole equipment 330, 430, 530, operations in the wellbore 336, 436, 536, such as drilling, workover, or completion operations, can continue (S668). If the downhole equipment 330, 430, 530 cannot be successfully released, other salvage operations can be performed; the wellbore 336, 436, 536 can be plugged and abandoned; or, the fish can remain downhole and sidetracking can be performed on the wellbore 336, 436, 536.
[0045] Figure 7 A flowchart illustrating a laser system according to one or more embodiments is shown. Although Figure 7 The boxes in the document are presented and described in sequence, but those skilled in the art will understand that some or all of these boxes may be executed in a different order, may be combined or omitted, and may be executed in parallel. Furthermore, these boxes may be executed actively or passively.
[0046] Laser tools 202, 302, 402, and 502, equipped with devices for generating annular collimated laser beams 216, 316, and 416, are mounted into the retrieval tube tool 446 (S770). The devices for generating the annular collimated laser beams 216, 316, and 416 may include a method using an optical fiber cable 206, a first conical lens 208, and a second conical lens 210.
[0047] Fiber optic cable 206 transmits the original laser beam 214 into a first conical lens 208, which focuses and controls the shape of the beam. The diverging laser beam enters a second lens 210 to generate annular collimated laser beams 216, 316, 416. The inner diameter 226, outer diameter 228, and eccentricity of the annular collimated laser beams 216, 316, 416 can be varied according to the interior angle 218 and aspect ratio of the conical lenses 210, 212. Any means for generating the annular collimated laser beams 216, 316, 416 can be used in this disclosure without departing from the scope of this disclosure.
[0048] for Figure 7In the method shown, the inner diameter 226 of the annular collimated laser beams 216, 316, and 416 is larger than the outer diameter of the downhole equipment 330, 430, and 530. Therefore, when the annular collimated laser beams 216, 316, and 416 are emitted, the downhole equipment 330, 430, and 530 will not be damaged. The retrieval tool 446 is a tool capable of catching and pulling a fallen fish out of the wellbore 336, 436, and 536. The retrieval tool 446 may include an upper connector 448, a cylinder 450, slips 452, and a packer 454. The retrieval tool 446 and the laser tools 202, 302, 402, and 502 are lowered into the wellbore 336, 436, and 536 by a top drive 130 to contact any broken or twisted components of the downhole equipment 330, 430, and 530 remaining in the wellbore 336, 436, and 536 (S772).
[0049] The retrieval tool 446 and laser tools 202, 302, 402, and 502 descend around the downhole equipment 330, 430, and 530. Annular collimated laser beams 216, 316, and 416 are generated by the laser tools 202, 302, 402, and 502 and emitted into the annulus 340, 440, and 540 between the downhole equipment 330, 430, and 530 and the wellbore walls 338, 438, and 538 (S774). The annular collimated laser beams 216, 316, and 416 clear material 342, 442, and 542 from the annulus 340, 440, and 540 that is blocking the downhole equipment 330, 430, and 530 and causing sticking points 334 and 434 (S776). The retrieval tool 446 engages by an upward force provided by the top drive 130. Kava 452 grabs downhole equipment 330, 430, and 530 (S778), and downhole equipment 330, 430, and 530 are pulled out of wellbore 336, 436, and 536 (S780).
[0050] After successfully releasing downhole equipment 330, 430, and 530, operations in wellbore 336, 436, and 536 can continue, such as drilling, workover, or completion operations (S782). If downhole equipment 330, 430, and 530 cannot be successfully released, other salvage operations can be performed; wellbore 336, 436, and 536 can be plugged and abandoned; or, the fish can remain downhole, and sidetracking can be performed on wellbore 336, 436, and 536.
[0051] Figure 8 A flowchart illustrating a laser system according to one or more embodiments is shown. Although Figure 8 The boxes in the document are presented and described in sequence, but those skilled in the art will understand that some or all of these boxes may be executed in a different order, may be combined or omitted, and may be executed in parallel. Furthermore, these boxes may be executed actively or passively.
[0052] Laser tools 202, 302, 402, and 502, equipped with means for generating annular collimated laser beams 216, 316, 416 and a conical annular collimated laser beam 517, are mounted into the retrieval tube tool 446 (S884). The means for generating the annular collimated laser beams 216, 316, and 416 may include a method using an optical fiber cable 206, a first conical lens 208, and a second conical lens 210.
[0053] Fiber optic cable 206 transmits the original laser beam 214 into a first conical lens 208, which focuses and controls the shape of the beam. The diverging laser beam enters a second lens 210 to generate annular collimated laser beams 216, 316, 416. The inner diameter 226, outer diameter 228, and eccentricity of the annular collimated laser beams 216, 316, 416 can be varied according to the interior angle 218 and aspect ratio of the conical lenses 210, 212. Any means for generating the annular collimated laser beams 216, 316, 416 can be used in this disclosure without departing from the scope of this disclosure.
[0054] for Figure 8 The method shown has an inner diameter 226 of the annular collimated laser beams 216, 316, and 416 that is larger than the outer diameter of the downhole equipment 330, 430, and 530. Therefore, when the annular collimated laser beams 216, 316, and 416 are emitted, the downhole equipment 330, 430, and 530 will not be damaged. The inner and outer diameters of the conical annular collimated laser beam 517 are reduced to be smaller than the dimensions of the downhole equipment 330, 430, and 530, allowing the conical annular collimated laser beam 517 to cut through the downhole equipment 330, 430, and 530.
[0055] The retrieval tool 446 is a tool capable of catching and pulling a fallen fish out of the wellbore 336, 436, and 536. The retrieval tool 446 may include an upper connector 448, a barrel 450, slips 452, and a packer 454. The retrieval tool 446 and laser tools 202, 302, 402, and 502 are lowered from outside the downhole equipment 330, 430, and 530 into the wellbore 336, 436, and 536 via a top drive 130, reaching the depth of the choke point 334, 434 within the wellbore 336, 436, and 536 (S886). A conical annular collimated laser beam 517 is generated by the laser tools 202, 302, 402, and 502 and emitted to cut the downhole equipment 330, 430, and 530 at a point above the choke point 334, 434 (S888).
[0056] The slip is placed on drill rig 131 and surrounds the fishing tube tool 446 to support its weight (S890). The top drive 130 is screwed into the top post of downhole equipment 330, 430, 530 to pull the separated downhole equipment 330, 430, 530 out of wellbore 336, 436, 536 (S892). The top drive 130 is screwed back into the fishing tube tool 446, and the slip is removed (S893). Annular collimated laser beams 216, 316, 416 are generated by laser tools 202, 302, 402, 502 and emitted into the annulus 340, 440, 540 between the remaining downhole equipment 330, 430, 530 and the wellbore walls 338, 438, 538 (S894).
[0057] Using annular collimated laser beams 216, 316, and 416, material 342, 442, and 542 causing sticking points 334 and 434 is removed from the annulus 340, 440, and 540 to release downhole equipment 330, 430, and 530 (S896). The retrieval tool 446 engages by an upward force provided by the top drive 130. The slip 452 grips the remaining downhole equipment 330, 430, and 530 (S778), and the remaining downhole equipment 330, 430, and 530 are pulled out of the wellbore 336, 436, and 536 (S898).
[0058] After successfully releasing downhole equipment 330, 430, and 530, operations in wellbore 336, 436, and 536 can continue, such as drilling, workover, or completion operations (S899). If downhole equipment 330, 430, and 530 cannot be successfully released, other salvage operations can be performed; wellbore 336, 436, and 536 can be plugged and abandoned; or, the fish can remain downhole, and sidetracking can be performed on wellbore 336, 436, and 536.
[0059] Although only a few exemplary examples have been described in detail above, those skilled in the art will readily understand that many modifications can be made to the exemplary examples without substantially departing from the invention. Therefore, all such modifications are intended to be included within the scope of this disclosure as defined by the appended claims. In the claims, functional definitions are intended to cover structures described herein as performing the enumerated functions, encompassing not only structural equivalents but also equivalent structures. Thus, although nails and screws may not be structural equivalents, as nails employ a cylindrical surface to hold wooden parts together and screws employ a helical surface, nails and screws can be equivalent structures in the context of fastening wooden parts. The applicant’s explicit intent is not to invoke Section 112, Paragraph 6 of the U.S. Patent Act to impose any limitation on any claim in this specification, except for those claims that expressly use the phrase “means for…” in conjunction with the associated function.
Claims
1. A laser system for releasing downhole equipment from a wellbore, the laser system comprising: A laser tool, the inner diameter of which is larger than the outer diameter of the downhole equipment, the laser tool including means for generating an annular collimated laser beam; as well as A working tubing string, the inner diameter of which is larger than the outer diameter of the downhole equipment. The laser tool is mounted on the working column. The working tubing descends around the downhole equipment, and When the working string is lowered to a position where the laser tool is near an obstacle in the downhole equipment, the laser tool emits the annular collimated laser beam to clear the annulus between the downhole equipment and the wellbore wall, thereby releasing the downhole equipment.
2. The laser system according to claim 1, in, The annular collimated laser beam can be positioned to cut the downhole equipment.
3. The laser system according to claim 1, in, The laser tool also includes: optical fiber; Laser head housing; Cover the lens; The first lens; and Second lens, The original laser beam emitted from the optical fiber passes through the first lens and the second lens to generate a collimated laser beam, thereby the laser head housing and the cover lens together protect the first lens and the second lens.
4. The laser system according to claim 3, in, The apparatus for generating the annular collimated laser beam further includes: The first lens is a conical lens having a specific interior angle and a specific aspect ratio; and The second lens is a conical lens having the specific interior angle and the specific aspect ratio, wherein the original laser beam passes through the first lens to generate a diverging ring beam, and The diverging annular beam passes through the second lens to generate the annular collimated laser beam.
5. The laser system according to claim 4, in, The specific interior angle and the specific aspect ratio determine the inner diameter of the annular collimated laser beam, the outer diameter of the annular collimated laser beam, and the eccentricity of the annular collimated laser beam.
6. The laser system according to any one of claims 1 to 5, in, The working string is a retrieval tool used to grab the downhole equipment to be pulled out of the wellbore.
7. A method for operating a laser system in a wellbore to release downhole equipment used in wellbore operations, the method comprising: A laser tool is mounted onto a work column, the laser tool including means for generating a ring-shaped collimated laser beam. Wherein, the inner diameter of the laser tool and the working string is larger than the outer diameter of the downhole equipment; The working string and the laser tool are lowered outside the downhole equipment until they are located near an obstacle of the downhole equipment; The annular collimated laser beam is generated and emitted into the annulus between the downhole equipment and the wellbore wall to clear the obstruction; and Pull the working string and the laser tool out of the wellbore.
8. The method according to claim 7, in, The annular collimated laser beam can be positioned to cut the downhole equipment.
9. The method according to claim 7, in, The laser tool also includes: optical fiber; Laser head housing; Cover the lens; The first lens; and Second lens, The original laser beam emitted from the optical fiber passes through the first lens and the second lens to generate a collimated laser beam, thereby the laser head housing and the cover lens together protect the first lens and the second lens.
10. The method according to claim 9, in, The apparatus for generating the annular collimated laser beam further includes: The first lens is a conical lens having a specific interior angle and a specific aspect ratio; and The second lens is a conical lens having the specific interior angle and the specific aspect ratio, wherein the original laser beam passes through the first lens to generate a diverging ring beam, and The diverging ring beam passes through the second lens to generate a ring-collimated laser beam.
11. The method according to claim 10, in, The specific interior angle and the specific aspect ratio determine the inner diameter of the annular collimated laser beam, the outer diameter of the annular collimated laser beam, and the eccentricity of the annular collimated laser beam.
12. The method according to any one of claims 7 to 11, in, The working string is a retrieval tube tool, and the method further includes: The retrieval tool grips the downhole equipment; and The retrieval tool, the laser tool, and the downhole equipment are pulled out of the wellbore.