Plugging device deployment in subterranean wells.

(54) Title: DEPLOYMENT OF PLUGGING DEVICE IN UNDERGROUND WELLS.

(54) Title: PLUGGING DEVICE DEPLOYMENT IN SUBTERRANEAN WELLS.

(57) Summary

One method of releasing plugging devices within a well may include transporting a dispensing tool to a desired location within the well within the well, the dispensing tool includes a container, and then releasing the plugging devices from the container into the well. well at the location inside the well. A plugging device dispensing system for use with an underground well may include a dispensing tool having a container configured to contain multiple plugging devices, and an actuator operable to release the plugging devices from the container at a location in inside the well.

(57) Abstract

A method of releasing plugging devices into a wellbore can include conveying a dispensing tool to a desired downhole location in the wellbore, the dispensing tool including a container, and then releasing the plugging devices from the container into the wellbore at the downhole location. A plugging device dispensing system for use with a subterranean well can include a dispensing tool having a container configured for containing multiple plugging devices, and an actuator operable to release the plugging devices from the container at a downhole location in the well.

DEPLOYMENT OF PLUGGING DEVICE IN WELLS

UNDERGROUND

FIELD OF THE INVENTION

This disclosure generally refers to equipment used and operations carried out in conjunction with an underground well and, in an example described below, more particularly provides what is needed for plugging devices and their deployment in wells.

BACKGROUND OF THE INVENTION

It can be beneficial to be able to control how and where fluid flows in a well. For example, it may be desirable in some circumstances to be able to prevent fluid from flowing into a particular area of ​​the formation. As another example, it may be desirable in some circumstances to cause fluid to flow to a particular area of ​​the formation, rather than another area of ​​the formation. As yet another example, it may be desirable to temporarily prevent fluid from flowing through a borehole tool passage. Therefore, it will be readily appreciated that improvements are continually needed in the art of controlling fluid flow in wells.

BRIEF DESCRIPTION OF THE DRAWINGS

Figure 1 is a representative partially cross-sectional view of an example of a well system and associated method that may incorporate the principles of this disclosure.

Figures 2A-2D are representative enlarged scale partially cross-sectional views of steps in an example of a re-termination method that can be practiced with the system of Figure 1.

Figures 3A-3D are representative partially cross-sectional views of steps in another example of a method that can be practiced with the system of Figure 1.

Figures 4A and 4B are representative enlarged scale elevation views of examples of a flow-borne device that can be used in the system and methods of Figures 1-3D, and which may incorporate the principles of this disclosure.

Figure 5 is a representative elevation view of another example of the flow-conveyed device.

Figures 6A and 6B are representative partially cross-sectional views of the flow-transported device in a well, the device being flow-transported in Figure 6A, and engaging an opening in the liner in Figure 6B.

Figures 7-9 are representative elevation views of examples of the flow-conveyed device with a retainer.

Figure 10 is a representative cross-sectional view of an example of a deployment apparatus and method that may incorporate the principles of this disclosure.

Figure 11 is a representative schematic view of another example of a deployment apparatus and method that may incorporate the principles of this disclosure.

Figures 12 and 13 are representative cross-sectional views of additional examples of the flow-borne device.

Figure 14 is a representative cross-sectional view of a well tool that can be operated using the flow-carried device.

Figure 15 is a representative partially cross-sectional view of a plugging device delivery system that may incorporate the principles of this disclosure.

Figures 16A-42B are representative views of examples of dispensing tools that can be used with the dispensing system of Figure 15.

DETAILED DESCRIPTION OF THE INVENTION

A system 10 for use with a well, and associated method, is representatively illustrated in Figure 1, which may incorporate the principles of this disclosure. However, it should be clearly understood that the system 10 and method are only one example of an application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not entirely limited to the details of the system 10 and method described in this document and / or represented in the drawings.

In the example of Figure 1, a tubular chain 12 is transported into a well 14 lined with liner 16 and cement 18. Although multiple casing chains would generally be used in actual practice, for clarity of illustration only one is depicted coating chain 16 in the drawings.

Although the well 14 is illustrated as being vertical, the sections of the well could instead be horizontal or otherwise inclined relative to the vertical. Although well 14 is fully cased and cemented as shown in Figure 1, any section of the well, in which the operations described in greater detail below are carried out, could be cased or uncoated.

Therefore, the scope of this disclosure is not limited to any particular details of the system 10 and method.

The tubular chain 12 of Figure 1 comprises coiled tubing 20 and a downhole assembly 22. As used herein, the term coiled tubing is. refers to a substantially continuous pipe that is stored on a spool or cylinder 24. The spool 24 could be mounted, for example, on an unloading ramp, trailer, floating vessel, vehicle, etc., to transport 10 to a well site. Although not shown in Figure 1, a control room or cabin with instrumentation, computers, controllers, recorders, etc. would generally be provided to control equipment such as an injector 26 and a burst preventer stack 28.

As used herein, the term "downhole assembly" refers to an assembly connected to a distal end of a tubular chain in a well. It is not necessary for a downhole assembly to be positioned or used in a downhole or well.

When the tubular chain 12 is positioned in the well

14, a ring 30 is formed radially between them. Fluid, slurries, etc., can be caused to flow from the surface into the ring 30 through, for example, a liner valve 32. One or more pumps 34 can be used for this purpose. Fluid can also be flowed to the surface from well 14 through ring 30 and valve 32.

Fluid, slurries, etc., can also be flowed from the surface to well 14 through tubing 20, for example, using one or more pumps 36. Fluid can also be flowed to the surface from well 14 through pipe 20.

In the further description of the examples in Figures 2A-14 below, one or more flow-borne devices are used to block or plug openings in the system 10 of Figure 1. However, it should be clearly understood that these methods and the flow-through device can be used with other systems, and the flow-through device can be used in other methods in accordance with the principles of this disclosure.

The exemplary methods described below allow existing fluid passages to be permanently or temporarily blocked in a variety of different applications. Certain examples of the flow-borne device described below are made of a fibrous material and may comprise a central body, a knot geometry, or other enlarged geometry.

Ί

Devices are transported to leak passages or paths using pumped fluid. Fibrous material extending outward from a body of a device can meet and follow fluid flow, pulling the enlarged geometry or fibers into a restricted portion of a flow path, causing the enlarged geometry and additional strands to wedge tightly. in the flow path, thereby sealing the fluid communication.

The devices can be made of degradable or non-degradable materials. Degradable materials may be self-degrading, or may require degradation treatments, such as, by exposing the materials to certain acids, certain base compositions, certain chemicals, certain types of radiation (e.g., electromagnetic or nuclear), or elevated temperature. Exposure can be accomplished at a desired time using a form of well intervention, such as, placing or circulating a fluid in the well such that the material is exposed to the fluid.

In some examples, the material may be an acid-degradable material (eg, nylon, etc.), a mixture of acid-degradable material (eg, nylon chips mixed with particles such as calcium cardonate), self-degrading (eg, polylactic acid (PLA,

Poly-Lactic Acid), poly-glycolic acid (PGA, Poly-Glycolic Acid), etc.), material that degrades by galvanic action (such as, magnesium alloys, aluminum alloys, etc.), a combination of different self-degrading materials, or a combination of self-degrading and non-self-degrading materials.

Multiple materials can be pumped together or separately. For example, nylon and calcium carbonate could be pumped as a mixture, or nylon could be pumped first to initiate a seal, followed by calcium carbonate to improve the seal.

In certain examples described below, the device may be made of knotted fibrous materials. Multiple knots can be used with any number of loose ends. The ends can be frayed or not frayed. The fibrous material can be rope, cloth, metallic wool, cloth, or other woven or braided structure.

The device can be used to block open sleeve valves, boreholes, or any leakage path in a well (such as leaky casing connections, corrosion holes, etc.). Any opening or passage through which fluid flows can be blocked with a suitably configured device. For example, an intentionally or unintentionally opened rupture disc, or other opening in a well tool, could be plugged using the device.

In an exemplary method described below, a well with an existing drilled zone can be re-completed. Devices (either degraded or non-degradable) are transported by flow to plug all existing perforations.

The well can then be re-terminated using any desired completion technique. If the devices are degradable, then a degradation treatment can be placed in the wellbore to adsorb the plugged holes (if desired).

In another exemplary method described below, multiple zones of the formation can be drilled and fractured (or otherwise stimulated, such as, by acidification) in a single journey from the bottomhole shaft 22 into the hole. In the method, an area is drilled, the area is fractured and / or otherwise stimulated, and the pierced area is then capped using one or more devices.

These steps are repeated for each additional zone, except that a last zone may not be covered; All plugged areas are eventually uncovered by waiting a certain period of time (if the devices are self-degrading), by applying an appropriate degradation treatment, or by mechanically removing the devices.

Referring now specifically to Figures 2A-2D, the steps are representatively illustrated in an example of a method in which the downhole assembly 5 22 of Figure 1 can be used in the completion of a well. In this method (see Figure 2A), the well has existing boreholes 38 that provide the necessary for fluid communication between the land formation zone 40 and an interior of the casing 16. However, it is desired to re-terminate zone 40, in order to improve fluid communication.

Referring now further to Figure 2B, the perforations 38 are plugged, thereby preventing flow through the perforations into the zone 15 40. The plugs 42 in the perforations may be flow-borne devices, as described more fully later. In that case, plugs 42 can be transported through liner 16 and into engagement with perforations 38 by means of fluid flow 44.

Referring now further to Figure 2C, new perforations 46 are formed through casing 16 and cement 18 through the use of an abrasive blast perforator 48. In this example, the downhole assembly 22 includes perforator 48 and a circulation valve assembly 50. Although the new perforations 46 are depicted as being formed on top of the existing perforations 38, the new perforations could be formed at any location in accordance with the principles of this disclosure.

Note that other means can be used to provide the perforations 46 in other examples. Explosive drills, drill bits, etc. can be used if desired. The scope of this disclosure is not limited to any particular piercing medium, or piercing use at all.

Circulation valve assembly 50 controls flow between flexible tubing 20 and perforator 48, and controls flow between ring 30 and an interior of tubular chain 12. Rather than transporting plugs 42 into the well by flow 44 through the interior of liner 16 (see Figure 2B), in other examples the plugs could be deployed within tubular chain 12 and transported by fluid flow 52 to through the tubular chain before the drilling operation. In that case, a valve 54 of the circulation valve assembly 50 could be opened to allow the plugs 42 to exit the tubular chain 12 and flow into the liner external to the tubular chain.

Referring now further to Figure 2D, the zone 40 has been fractured by applying increased pressure to the zone after the drilling operation. Improved fluid communication is now allowed between zone 40 and the interior of liner 16.

Note that fracturing is not necessary in accordance with the principles of this disclosure. A zone could be stimulated (eg by acidification) with or without fracturing. Therefore, although fracturing is described for certain examples, it should be understood that other types of stimulation treatments could be performed in addition to or in place of fracturing.

In the example of Figure 2D, plugs 42 prevent pressure applied to fracture zone 40 via perforations 46 from leaking into the zone through perforations 38. Caps 42 can remain in perforations 38 and continue preventing flow through the perforations, or the plugs can be degraded, if desired, such that flow through the perforations is eventually allowed.

In other examples, fractures may be formed by existing perforations 38, and new perforations may not be formed. In one technique, pressure can be applied to liner 16 (eg, using pump 34), thereby initially fracturing zone 40 via some of the perforations 38 that receive most of the fluid flow 44 . After initial fracturing of zone 40, and while fluid is flowing through liner 16, plugs 42 within the liner can be released so that the plugs seal those perforations 38 that are receiving most of the flow of fluid.

In this way, fluid 44 will be diverted to other perforations 38, such that zone 40 will also fracture via those other perforations 38. Plugs 42 can be released into liner 16 continuously or periodically as the sealing operation progresses. fracturing, such that the plugs will gradually seal all, or most, of the perforations 38 as the zone 40 is fractured by the perforations. That is, at each point in the fracturing operation, plugs 42 will seal those perforations 38 through which most of the fluid flow 44 passes, which are the perforations through which zone 40 has fractured. .

Referring now further to Figures 3A-3D, the steps in another example of a method in which the downhole assembly 22 of Figure 1 can be used in the completion of multiple zones 40a-c of a well. Each of the multiple zones 40a-c is drilled and fractured during a single trip of the tubular chain 12 into the wellbore.

In Figure 3A, tubular chain 12 has been deployed within liner 16, and has been positioned such that perforator 48 is in the first zone 40a to be terminated. Perforator 48 is then used to form perforations 46a through liner 16 and cement 18, and in zone 40a.

In Figure 3B, the zone 40a has been fractured by applying increased pressure to the zone via the perforations 46a. The fracturing pressure can be applied, for example, by means of ring 30 from the surface (e.g., using pump 34 of Figure 1), or by means of tubular chain 12 (e.g., using pump 36 of Figure 1). The scope of this disclosure is not limited to any particular fracturing means or technique, or the use of fracturing at all.

After the zone 40a is fractured, the perforations 46a are plugged by deploying the plugs 42a into the well and transporting them by fluid flow to the sealing engagement with the perforations. Plugs 42a can be conveyed by flow 44 through liner 16 (eg, as in Figure 2B), or by flow 52 through tubular chain 12 (eg, as in Figure 2C).

Tubular chain 12 is repositioned in liner 16 such that perforator 48 is now located in the next zone 40b to be terminated. The perforator 48 is then used to form the perforations 46b through the liner 16 and the cement 18, and in the zone 40b. Tubular chain 12 can be repositioned before or after plugs 42a are deployed into the well.

In Figure 3C, the zone 40b has been fractured by applying increased pressure to the zone via the perforations 46b. The fracturing pressure can be applied, for example, by means of ring 30 from the surface (e.g., using pump 34 of Figure 1), or by means of tubular chain 12 (e.g., using pump 36 of Figure 1).

After the zone 40b is fractured, the perforations 46b are plugged by deploying the plugs 42b into the well and transporting them by fluid flow to the sealing engagement with the perforations. Plugs 42b can be conveyed by flow 44 through liner 16, or by flow 52 through tubular chain

12.

Tubular chain 12 is repositioned in liner 16 such that perforator 48 is now located in the next zone 40c to be terminated. The perforator 48 is then used to form the perforations 46c through the liner 16 and the cement 18, and in the zone 40c. Tubular chain 12 can be repositioned before or after plugs 42b are deployed into the well.

In Figure 3D, the zone 40c has been fractured by applying increased pressure to the zone via the perforations 46c. The fracturing pressure can be applied, for example, by means of ring 30 from the surface (e.g., using pump 34 of Figure 1), or by means of tubular chain 12 (e.g., using pump 36 of Figure 1).

The plugs 42a, b then degrade and no longer prevent flow through the perforations 46a, b. Therefore, as depicted in Figure 3D, flow is allowed between the interior of liner 16 and each of the zones 40ac.

The plugs 42a, b can degrade in any way. The plugs 42a, b can degrade in response to application of a degradation treatment, in response to the passage of a certain period of time, or in response to exposure to elevated temperature inside the well.

The degradation treatment could include exposing the plugs 42a, b to a particular type of radiation, such as electromagnetic radiation (eg, light having a certain wavelength or range of wavelengths, gamma rays, etc.) or nuclear particles (eg, gamma, beta, alpha, or neutrons).

The plugs 42a, b can degrade by galvanic action or by dissolution. Plugs 42a, b can degrade in response to exposure to a particular fluid, either occurring naturally in the well (such as water or hydrocarbon fluid), or introduced into the well (such as a fluid having a pH particular).

Note that any number of zones can be completed in accordance with the principles of this disclosure. The 15 zones 40a-c can be sections of a single land formation, or they can be sections of separate formations. Although perforations 46c were not previously described as being plugged in the method, perforations 46c could be plugged after zone 40c is fractured or otherwise stimulated (e.g., to verify that the plugs are in place. done by preventing flow from cladding 16 to zones 40a-c).

In other examples, plugs 42 may not degrade. The plugs 42 could rather be removed mechanically, for example by milling or otherwise cutting the plugs 42 out of the perforations. In any of the method examples described above, after the fracturing operation (s) is completed, the plugs 42 can be milled or removed from the perforations 38, 46, 46a, b sin. dissolve, melt, disperse, or otherwise degrade a plug material.

In some examples, the plugs 42 can be mechanically removed without necessarily cutting the plugs. A tool with appropriate gripping structures (such as a bur or other cutting or gripping device) could grasp the plugs 42 and pull them out of the perforations.

Referring now further to FIG. 4A, an example of a flow-borne device 60 is representatively illustrated that may incorporate the principles of this disclosure. Device 60 can be used for any of the plugs 42, 42a, b in the method examples described above, or the device can be used in other methods.

The example device 60 of Figure 4A includes multiple fibers 62 that extend outward from an enlarged body 64. As depicted in Figure 4A, each of the fibers 62 has a lateral dimension (eg, a thickness or diameter) that is substantially smaller than a size (eg, thickness or diameter) of body 64.

Body 64 can be dimensioned such that it will effectively engage and seal a particular opening in a well. For example, if device 60 is desired to seal a bore in a well, body 64 can be formed such that it is somewhat larger than a diameter of the bore. If it is desired that multiple devices 60 seal multiple openings having a variety of dimensions (such as holes caused by corrosion of the coating 16), then the bodies 64 of the devices can be formed in a corresponding variety of sizes.

In the example of Figure 4A, the fibers 62 are joined (eg, by braiding, weaving, wiring, etc.) to form lines 66 that extend outward from the body 64. In this example, there are two lines 66 such, but any number of lines (including one) can be used in other examples.

Lines 66 may be in the form of one or more strings, in which case fibers 62 could comprise frayed ends of string (s). Additionally, the body 64 could be formed by one or more knots in the rope (s). In some examples, the body 64 may comprise a cloth or cloth, the body could be formed by means of one or more knots in the cloth or cloth, and the fibers 62 could extend from the cloth or cloth.

In other examples, device 60 could comprise a single sheet of material, or multiple strips of sheet material. Device 60 could comprise one or more films. Body 64 and lines 66 may not be made of the same material, and the body and / or lines may not be made of fibrous material.

In the example of Figure 4A, the body 64 is formed by a single double knot in a rope, and the ends of the rope are frayed such that the fibers 62 flare outward. In this manner, the fibers 62 will cause significant fluid drag when the device 60 is deployed in a flow stream, such that the device will be effectively carried by, and will follow, the flow.

However, it should be clearly understood that other types of bodies and other types of fibers can be used in other examples. Body 64 could have other shapes, the body could be hollow or solid, and the body could be made of one or more materials. The fibers 62 are not necessarily joined by lines 66, and the fibers are not necessarily formed by frayed ends of ropes or other lines. Body 64 is not necessarily centrally located in device 60 (for example, the body could be at one end of lines 66). Therefore, the scope of this disclosure is not limited to the construction, configuration, or other details of device 60 as described herein or depicted in the drawings.

Referring now further to Figure 4B, another example of device 60 is representatively illustrated. In this example, device 60 is formed using multiple braided lines 66 of the type known as a mason knot. The multiple lines 66 are knotted (such as, with a simple double or triple or other type of knot) to form the body 64. The ends of lines 66 are not necessarily frayed in these examples, although the lines do comprise fibers (such as fibers 62 described above).

Referring now further to Figure 5, another example of device 60 is representatively illustrated. In this example, four sets of fibers 62 are attached via a corresponding number of lines 66 to body 64. Body 64 is formed by means of of one or more nodes on lines 66.

Figure 5 demonstrates that a variety of different configurations are possible for the device 60. Accordingly, the principles of this disclosure may be incorporated in other configurations not specifically described herein or represented in the drawings. Such other configurations may include fibers bonded to bodies without the use of lines, bodies formed by techniques other than knotting, etc.

Referring now further to Figures 6A and 6B, an example of a use of the device 60 of Figures 4A and 4B to seal an opening 68 in a well is representatively illustrated. In this example, opening 68 is a hole formed through 'a side wall 70 of a tubular chain 72 (such as a liner, sleeve, pipe, etc.). However, in other examples the opening 68 could be another type of opening, and could be formed in another type of structure.

Device 60 deploys onto tubular chain 72 and is transported through tubular chain by fluid flow 74. Fibers 62 from device 60 enhance fluid entrainment over the device so that the device is visible influenced to move with flow 74. '

Since flow 74 (or a portion thereof) exits tubular chain 72 through aperture 68, device 60 will be influenced by fluid entrainment to also exit tubular chain through aperture 68. As depicted in Figure 6B, a set of fibers 62 first enters opening 68, and body 64 follows. However, body 64 is appropriately sized such that it does not pass through aperture 68, but rather is fixed or wedged within the aperture. In some examples, the body 64 can be only partially received in the opening 68, and in other examples, the body can be completely received in the opening.

Body 64 may completely or only partially block flow 74 through aperture 68. If body 64 only partially blocks flow 74, any remaining fiber 62 exposed to flow in tubular chain 72 can be carried by flow to any space between the body and the opening 68, such that a combination of the body and the fibers completely blocks the flow through the opening.

In another example, device 60 can partially block flow through opening 68, and other material (such as calcium carbonate, PLA, or PGA particles) can be deployed and transported via flow 74 to any space between the device and aperture, such that a combination of device and material

4 completely blocks flow through opening.

Device 60 can permanently prevent flow through opening 68, or device can degrade to eventually allow flow through the opening. If device 60 degrades, it may be self-degrading, or it may degrade in response to any of a variety of different stimuli. Any technique or means to degrade device 60 (and any other material used in conjunction with device to block flow through opening 68) can be used within the scope of this disclosure.

In other examples, device 60 can be mechanically removed from opening 68. For example, if body 64 only partially enters opening 68, a milling cutter or other cutting device can be used to cut the body from the opening.

Referring now further to Figures 7-9, additional examples of device 60 are representatively illustrated. In these examples, device 60 is surrounded by, encapsulated in, molded in, or otherwise retained by, a retainer 80.

The retainer 80 assists in the deployment of the device 60, particularly in situations where multiple devices are to be deployed simultaneously. In such situations, the retainer 80 for each device 60 prevents the fibers 62 and / or lines 66 from entangling with the fibers and / or lines of other devices.

Retainer 80 could, in some examples, completely enclose device 60. In other examples, retainer 80 could be in the form of a binder that holds fibers 62 and / or lines 66 together so that they do not tangle. with those of other devices.

In some examples, retainer 80 could have a cavity therein, with device 60 (or only fibers 62 and / or lines 66) contained in the cavity. In other examples, retainer 80 could be molded around device 60 (or just fibers 62 and / or lines 66).

During or after deployment of the device 60 into the well, the retainer 80 dissolves, melts, disperses, or otherwise degrades, such that the device is capable of sealing an opening 68 in the well, as described above. For example, the retainer 80 can be made of a material 82 that degrades in the environment of a well.

Retainer material 82 may degrade after deployment within the well, but prior to arrival of device 60 in opening 68 to be plugged. In other examples, the retainer material 82 may degrade on or after the arrival of the device 60 in the opening 68 to be plugged. If device 60 also comprises a degradable material, then preferably, the retainer material 82 degrades prior to the device material.

Material 82 could, in some examples, melt at the elevated well temperatures. The material 82 could be chosen to have a melting point that is between a temperature at the surface of the earth and a temperature at the opening 68, such that the material melts during transportation from the surface to the location of the opening inside the well.

Material 82 could, in some examples, dissolve when exposed to well fluid. The material 82 could be chosen such that the material begins to dissolve as soon as it unfolds into the well 14 and contacts a certain fluid (such as water, brine, hydrocarbon fluid, etc.) within it. In other examples, the fluid that initiates dissolution of the material 82 could have a certain pH range that causes the material to dissolve.

Note that the material 82 need not melt or dissolve in the well. Other different stimuli (such as passage of time, high pressure, flow, turbulence, etc.) could cause the material 82 to disperse, degrade, or stop retaining the device 60. Material 82 could degrade in response to any, or a combination, of: the passage of a predetermined period of time in the well, exposure to a predetermined temperature in the well, exposure to a predetermined fluid in the well, exposure radiation in the wellbore and exposure to a predetermined chemical composition in the wellbore. Therefore, the scope of this disclosure is not limited to any particular stimulus or technique to disperse or degrade material 82, or to any particular type of material.

In some examples, material 82 may remain in device 60, at least partially, when the device engages opening 68. For example, material 82 could continue to cover body 64 (at least partially) when the body engages. and seals the opening 68. In such examples, the material 82 could conveniently comprise a relatively soft, viscous and / or elastic material, such that the seal between the device 60 and the opening 68 is improved.

Suitable relatively low melting point substances that can be used for material 82 may include wax (eg, paraffin wax, vegetable wax), ELVAX ™ ethylene vinyl acetate copolymer available from DuPont), atactic polypropylene, and eutectic alloys.

Suitable relatively soft substances that can be used for the material 82 may include a soft silicone composition or a viscous liquid or gel.

Suitable dissolvable materials can include PLA, PGA, anhydrous boron compounds (such as anhydrous boric oxide and anhydrous sodium borate), polyvinyl alcohol, polyethylene oxide, salts, and carbonates. The dissolution rate of a water soluble polymer (eg, polyvinyl alcohol, polyethylene oxide) can be increased by incorporating a water soluble plasticizer (eg, glycerin), or a fast dissolving salt ( eg, sodium chloride, potassium chloride), or both a plasticizer and a salt.

In Figure 7, the retainer 80 is in a cylindrical shape. Device 60 is encapsulated in, or molded into, retainer material 82. Fibers 62 and lines 66 are therefore prevented from entangling with fibers and lines of any other device 60.

In Figure 8, the retainer 80 is in a spherical shape. Additionally, the device 60 is compacted, and its compacted shape is retained by means of the retainer material 82. A shape of the retainer 80 may be chosen as appropriate for the shape of a particular device 60, in compacted or non-compacted form.

In Figure 9, the retainer 80 is in a cubic shape. Therefore, any type of shape (polyhedron, spherical, cylindrical, etc.) can be used for the retainer 80, in accordance with the principles of this disclosure.

Referring now further to Figure 10, an example of a deployment apparatus 90 and associated method is representatively illustrated. The apparatus 90 and method can be used with the system 10 and method described above, or can be used with other systems and methods.

Leads used with system 10, apparatus 90 can be connected between pump 34 and liner valve 32 (see Figure 1). Alternatively, the apparatus 90 may be supported in a tube associated with the pump 34 and the liner valve 32, or in a tube associated with the pump 36 (for example, if the devices 60 are to be deployed via the tubular chain 12). However configured, an outlet of apparatus 90 is connected to the well, although the apparatus itself can be positioned at a distance away from the well. ·

Apparatus 90 is used in this example to deploy devices 60 into the well. Devices 60 may or may not be retained by retainer 80 when deployed. However, in the example of Figure 10, the devices 60 are depicted with the retainers 80 in the spherical shape of Figure 8, for display convenience. Retainer material 82 may be at least partially dispersed during deployment, such that devices 60 are more easily transported via flow 74.

In certain situations, it may be desirable to provide some spacing between devices 60 during deployment, for example, in order to efficiently plug perforations in the liner. One reason for this is that the devices 60 will tend to plug the perforations that are receiving the highest flow rates first.

Additionally, if the devices 60 are deployed into the well closely together, some of them may get caught between the bores, thereby wasting some of the devices. Excessive wasted devices 60 may later interfere with other well operations.

To mitigate such problems, devices 60 can be deployed with a selected spacing. The spacing can be, for example, in the order of the length of the perforation interval. Apparatus 90 is

Desirably capable of deploying devices 60 with any selected spacing between devices.

Each device 60 in this example has the retainer 80 in the form of a dissolvable coating material with a brittle coating 88 thereon, to impart a desired geometric shape (spherical in this example), and to allow for convenient deployment. The dissolvable retainer material 82 could be detrimental to the operation of the device 60 if a drag coefficient of the device increases. A high coefficient of drag can cause the devices 60 to sweep a lower end of the piercing range, rather than sealing the uppermost piercings. '

The brittle coating 88 is used to prevent the dissolvable coating from dissolving during a glue time prior to deployment. Using apparatus 90, the brittle coating 88 can desirably break, open, or otherwise damage during the unfolding process, such that the dissolvable coating is then exposed to fluids that can cause the coating to dissolve.

Examples of suitable brittle coatings include cementitious materials (eg, plaster of Paris) and different waxes (eg, paraffin wax, carnauba wax, vegetable wax, machinel wax). The brittle nature of a wax coating can be optimized for particular conditions by mixing a less brittle wax (eg, paraffin wax) with a more brittle wax (eg, carnauba wax) 5 in a certain ratio selected for particular conditions.

As depicted in Figure 10, apparatus 90 includes a rotary actuator 92 (such as a hydraulic or electric servo motor, with or without a rotary encoder). The actuator 92 rotates a sequential release structure 94 that receives each device 60 in turn from a tail of the devices, and then releases each device one at a time into a conduit 8 6 that is connected to the tubular chain 72 ( or liner 16 15 or pipe 20 of Figure 1).

Note that the actuator 92 need not be a rotary actuator, as other types of actuators (such as, a linear actuator) can be used in other examples. Additionally, it is not necessary for only one device 60 to be deployed 20 at a time. In other examples, release structure 94 could be configured to release multiple devices at the same time. Therefore, the scope of this disclosure is not limited to any particular detail of apparatus 90 or associated method as described herein or depicted in the drawings.

In the example of Figure 10, a deployment rate of the devices 60 is determined by an actuation speed of the actuator 92. As a rotational speed of the structure 94 increases, a release rate of the devices increases accordingly. 60 from the structure. Therefore, the deployment rate can be conveniently adjusted by adjusting an operational speed of the actuator 92. This adjustment could be automatic, in response to well conditions, stimulation treatment parameters, flow variations, etc.

As depicted in Figure 10, a flow of liquid 96 enters apparatus 90 from the left and exits from the right (eg, at about 1 barrel per minute). Note that flow 96 is allowed to pass through apparatus 90 at any position on release structure 94 (release structure is configured to allow flow through structure at any of its positions).

When the release frame 94 rotates, one or more of the devices 60 received in the frame rotate with the frame. When a device 60 is on a downstream side of release structure 94, flow 96 through apparatus 90 carries the device to the right (as depicted in Figure 10) and into a restriction 98.

The restriction 98 in this example is smaller than the diameter of the device 60. The flow 96 causes the device 60 to be forced through the restriction 98, thereby damaging the brittle liner 88, opening or fracturing to allow dissolvable material 82 in retainer 80 dissolves.

Other ways to open, break, or damage a brittle coating can be used in accordance with the principles of this disclosure. For example, cutters or abrasive structures could contact an exterior surface of a device 60 to penetrate, break, wear, or otherwise damage the brittle coating 88. Therefore, this disclosure is not limited to any particular technique to damage, break, penetrate or otherwise compromise a brittle coating.

Referring now further to Figure 11, another example of a display apparatus 100 and associated method is representatively illustrated. The apparatus 100 and method can be used with the system 10 and method described above, or can be used with other systems and methods.

In the example of Figure 11, devices 60 are deployed using two flow rates. The flow rate A through two valves (valves A and B) is combined with the flow rate B through a tube 102 depicted as vertical in Figure 11 (the tube can be horizontal or have any other orientation in actual practice).

Tube 102 may be associated with pump 34 and liner valve 32, or tube may be associated with pump 36 if devices 60 are to be deployed through tubular chain 12. In some examples, it may be used a separate pump (not shown) to supply flow 96 through valves A and B.

Valve A is not absolutely necessary, but can be used to control a tail of devices 60. When valve B is open, flow 96 causes devices 60 to enter vertical tube 102. Flow 104 through tube Vertical 102 in this example is substantially greater than flow 96 through valves A and B (ie, flow B »flow A), although in other examples the flows may be substantially the same or related in another way.

A spacing (dist. B) between devices 60 when deployed downhole can be calculated as follows: dist. B = dist. A * (ID_TO²/ ID_B²) * (flow B / flow A), where dist. A is a spacing between devices 60 before entering tube 102, ID_TO is an inside diameter of a tube 106 connected to tube 102, and ID_B is an inner diameter of tube 102. This assumes circular tubes 102, 104. When the corresponding passages are not circular, the ID term_TO²/ ID_B² it can be replaced by an appropriate ratio of the passage or passage areas.

The spacing between plugging devices 60 in the well (dist. B) can be controlled automatically by varying one or both of the flow rates A, B. For example, the spacing can be increased by increasing flow B or decreasing flow A The flow rate (s) A, B can be adjusted automatically in response to changes in well conditions, stimulation treatment parameters, flow variations, etc.

In some examples, the flow rate A may have a practical minimum of about a barrel per minute. In some circumstances, the desired deployment spacing (dist. B) may be greater than what can be produced using a suitable spacing distance. A from devices 60 and flow A in tube 106.

Deployment spacing B can be increased by adding spacers 108 between devices 60 on tube 106. Spacers 108 effectively increase the distance A between devices 60 on tube 106 (and thus' increase the value of dist. A in the above equation).

The spacers 108 can be dissolvable or otherwise dispersible, such that they dissolve or degrade when in tube 102 or later. In some examples, spacers 108 can be geometrically the same, or similar, to devices 60.

Note that apparatus 100 can be used in combination with restriction 98 of Figure 10 (for example, when restriction 98 is connected downstream of valve B but upstream of tube 102). In this manner, a brittle coating or other protective coating on devices 60 and / or spacers 108 can be opened, broken, or otherwise damaged before the devices and spacers enter tube 102.

Referring now further to Figure 12, a cross-sectional view of another example of device 60 is representatively illustrated. Device 60 can be used in any of the systems and methods described herein, or can be used in other systems and methods.

In this example, the body of the device 60 is made of filaments or fibers 62 formed as a ball or sphere.

Of course, other shapes can be used, if desired.

The filaments or fibers 62 can make up all, or substantially all, of the device 60. The fibers 62 can be randomly oriented, or they can be arranged in different orientations as desired.

In the example of Figure 12, fibers 62 are retained by dissolvable, degradable, or dispersed material 82. Additionally, a brittle coating may be provided in device 60, for example, in order to delay dissolution of material 82 until the device has deployed into a well (as in the example of Figure 10).

The device 60 of Figure 12 can be used in a diversion fracturing operation (in which perforations receiving most of the fluid are plugged to divert fluid flow to other perforations), in a re-completion operation. (eg, as in the example in Figures 2A-2D), or in a multi-zone drilling and fracturing operation (eg, as in the example in Figures 3A-3D).

An advantage of the device 60 of Figure 12 is that it is capable of sealing irregularly shaped openings, perforations, leak paths, or other passages. Device 60 may also tend to stick or adhere to an opening, for example, due to coupling between fibers 62 and the structure surrounding (and in) the opening. Additionally, there is an ability to selectively seal the openings.

Fibers 62 could comprise, in some examples, wool fibers. Device 60 could be reinforced (eg, using material 82 or other material) or could be made entirely of fibrous material with a substantial portion of the fibers 62 randomly oriented.

Fibers 62 could comprise, in some examples, metallic wool, or crimped and / or compressed wire. The wool can be retained with wax or other material (such as Material 82) to form a ball, sphere, cylinder, or other shape.

In the example of Figure 12, the material 82 may comprise a wax (or eutectic metal or other material) that melts at the selected predetermined temperature. A wax device 60 can be reinforced with fibers 62 such that the fibers and wax (material 82) work together to block a perforation or other passage.

The selected melting point may be slightly below a static well temperature. The well temperature during fracturing is generally depressed due to relatively low temperature fluids entering the well. After fracturing, the temperature of the well will generally increase, thus melting the wax and releasing the reinforcing fibers 62.

This type of device 60 in the shape of a ball or other shapes can be used to operate the tools inside the well in a similar manner. In Figure 14, a well tool 110 is depicted with a passage 112 extending longitudinally through the well tool. The tool of the. Well 110 could be connected, for example, to liner 16 of Figure 1, or it could be connected to another tubular chain (such as tubing chain, tubular chain 12, etc.).

Device 60 is depicted in Figure 14 as being hermetically engaged with a seat 114 formed in a sliding sleeve 116 of well tool 110. When device 60 is coupled in this manner to well tool 110 (for example, after well tool is deployed into a well and is properly positioned), a pressure differential can occur across the device and the sliding sleeve 116, in order to cut the brittle members 118 and move the sleeve down (as seen in Figure 14), thereby allowing flow between passage 112 and an exterior of well tool 110 through openings 120 formed through an exterior housing 122.

Material 82 from device 60 can then be dissolved, dispersed, or otherwise degraded to thereby allow flow through passage 112. Of course, other types of well tools (such as placement tools can be operated or actuated). plugs, fracturing plugs, testing tools, etc.) using device 60 within the scope of this disclosure.

A drag coefficient of device 60 in any of the examples described herein can be appropriately modified to produce a desired result. For example, in a diversion fracturing operation, it is generally desirable to block the perforations at a certain location in the wellbore. The location is generally in the boreholes that take up the most fluid.

Natural fractures in a well-penetrated earth formation cause certain boreholes to receive a greater portion of fracturing fluids. For these situations and others, the shape, size, density, and other characteristics of the device 60 can be selected, such that the device tends to be transported by flow to a certain corresponding section of the well.

For example, devices 60 with a higher coefficient of drag (Cd) may tend to settle more toward a generally horizontal or lateral well tip (toe). Devices 60 with a lower Cd may tend to seat more toward a heel of the well. For example, if the well 14 depicted in Figure 2B is horizontal or highly deviated, the heel would be at an upper end of the well illustrated, and the tip would be at the lower end of the well illustrated (e.g. ., the direction of fluid flow 44 is from heel to toe).

Smaller devices 60 with long, free-floating fibers 62 (see example in Figure 13) may have a strong tendency to settle on or near the bead. A diameter of the device 60 and the free length of the fiber 62 can be appropriately selected, as such. so that the device is best suited to stop and tightly engage boreholes anywhere along the length of the well.

Acid treatment operations can benefit from the use of the device 60 examples described herein. Pumping friction causes hydraulic pressure at the heel to be considerably higher than at the toe. This means that the volume of fluid pumped into a formation at the heel will be considerably greater than at the tip. Turbulent fluid flow increases this effect. Gelling additives could reduce an onset of turbulence and decrease the magnitude of the pressure drop along the length of the wellbore.

The higher initial pressure on the heel allows the areas to acidify and then plug starting at the heel, and then progressively down the hole. This mitigates acid waste by attempting to acidify all areas at the same time.

The free fibers 62 of the examples in Figures 4A6B and 13 greatly increase the ability of the device 60 to engage the first open hole (or other leak path) it encounters. Therefore, low-Cd, long-fiber 62 devices 60 can be used to plug from top to bottom holes, while turbulent acid with high frictional pressure drop is used in such a way that the acid treats uncapped holes first. closer to the top of the well with acid.

In examples of device 60 where a wax material (such as material 82) is used, the fibers 62 (including body 64, lines 66, knots, etc.) can be treated with a treatment fluid that repels wax (e.g. during a molding process). This can be useful in releasing wax from fibrous material after fracturing or otherwise compromising the retainer 80 and / or a brittle coating thereon. ,

Suitable release agents are water-wetting surfactants (e.g., alkyl ether sulfates, high hydrophilic-lipophilic balance (HLB) surfactants, betaines, alkylaryl sulfonates, hydrophilic-lipophilic balance sulfonates diphenyl. 10 alkyl, alkyl sulfates). The release fluid may also comprise a binder to maintain the knot or body 64 in a shape suitable for molding. An example of a binder is a polyvinyl acetate emulsion.

Broken or fractured devices 60 may have lower Cd. Broken or fractured devices 60 can have smaller cross sections and can pass through ring 30 between pipe 20 and liner 16 more easily.

The restriction 98 (see Figure 10) can be connected to any line or tube through which the devices 60 are pumped, in order to cause the devices to fracture as they pass through the restriction. This can be used to break apart the devices 60 into wax and non-wax parts. Restriction 98 can also be used to break a brittle coating covering a soluble wax material 82 to allow water or other fluids in the well to dissolve the wax.

Fibers 62 may extend outward from device 60, whether or not body 64 or other main structure of the device also comprises fibers. For example, a ball (or other shape) made of any material could have fibers 62 attached to and extending outwardly from it. Such a device 60 will be better able to find and adhere to openings, holes, perforations, or other leak paths near the heel of the well, compared to the ball (or other shape) without the fibers 62.

For any of the examples of device 60 described herein, fibers 62 may not dissolve, disperse, or otherwise degrade in the well. In such situations, the devices 60 (or at least the fibers 62) can be removed from the wellbore by piston, scraping, circulation, milling, or other mechanical methods.

In situations where it is desired that the fibers 62 dissolve, disperse, or otherwise degrade in the well, nylon is a suitable acid soluble material for the fibers. Nylon 6 and Nylon 66 are acid soluble and suitable for use in device 60. At relatively low well temperatures, Nylon 6 may be preferred over Nylon 66 since Nylon 6 dissolves faster and more easily.

Self-degrading fiber devices 60 can be prepared from polylactic acid (PLA), polyglycolic acid (PGA), or a combination of PLA and PGA fibers 62. Such fibers 62 can be used in any of the examples of device 60 described herein.

Fibers 62 can be continuous monofilament or multifilament, or staple fiber. The staple fibers 62 can be carded or twisted into a yarn that can be used to prepare fibrous flow-borne devices 60.

The PLA and / or PGA fibers 62 can be coated with a protective material, such as calcium stearate, to slow their reaction with water and thus delay the degradation of the device 60. Different combinations of PLA materials can be used and PGA to achieve the different degradation times or other corresponding characteristics.

PLA resin can be spun into 1-15 denier fiber, for example. Smaller diameter fibers 62 degrade faster. Fiber denier of less than 5 may be more desirable. PLA resin is commercially available with a range of melting points (e.g., 60 to 185 ° C (140 to

7

365 ° F)). Fibers 62 spun from lower melting PLA resin can degrade faster.

The bi-component PLA fiber has a high melting point PLA resin core and a low melting point PLA resin sheath (e.g., 60 ° C (140 ° C) melting point sheath. F) over a core with a melting point of 129 ° C (265 ° F)). The low melting point resin can hydrolyze faster and generate acid which will accelerate the degradation of the high melting point core. This can enable the preparation of a fibrous device 60 that will have greater strength in a well environment, still degrading in a reasonable time. In different examples, a melting point of the resin may decrease in a radially outward direction in the fiber.

Referring now further to Figure 15, a system 200 and associated method for dispersing plugging devices 60 within well 14 is representatively illustrated. In this system 200, plugging devices 60 are not discharged into well 14 on the surface and are transported to a desired plugging location (such as perforations 38, 46a-c, 46 in the examples of Figures 2A-3D or aperture 68 in the example of Figures 6A and 6B) via fluid flow 44, 74, 96, 104. Instead, plugging devices 60 are contained in a container 202, the container is transported via transport 204 to a desired location within the well, and the plugging devices are released from the container at the location where inside the well.

A variety of different containers 202 for the devices 60 are described below. plugging and are depicted in Figures 16A-42B. However, it should be clearly understood that the scope of this disclosure is not limited to any particular type or configuration of container 202.

An actuator 206 may be provided to forcibly release or discharge the plugging devices 60 from the container 202 when desired. Container 202 and actuator 206 can be combined into a dispensing tool 300 to dispense plugging devices 60 into the well at a location within the well. A variety of different actuators 206 are described below and depicted in the drawings, however, it is not necessary that an actuator be provided, or that any particular type or configuration of actuator be provided.

Transport 204 could be of any type suitable for transporting container 202 to the desired location within the well. Examples of transports include conductive cable, transportable wire, flexible pipe, articulated pipe, autonomous or wire tractor, etc.

In some examples, container 202 could be moved by fluid flow 208 through well 14. Fluid flow 208 could be any of the fluid flows 44, 74, 96, 104 described above. Fluid flow 208 could comprise a treatment fluid, such as a stimulation fluid (eg, fracturing and / or acidification fluid), an inhibitor (eg, to inhibit paraffin formation, asphaltenes, corrosion, etc. .) and / or remedial treatment (for example, to remedy damage due to corrosion, clays, polymer, etc., accumulated in the wellbore).

In the example of Figure 15, the plugging devices 60 are released from container 202 over a plug, bridge plug, cleaning plug, or other type of plug 210 previously placed in well 14. In other examples, the devices Plugging 60 could be released above a previously plugged valve, such as the example of valve 110 in Figure 14.

Note that it is not necessary within the scope of this disclosure that plugging devices 60 are released into well 14 above any plug, plug 210 or other flow blockage in the well.

As depicted in Figure 15, the plugging devices 60 will be carried by the flow 208 in sealing engagement with the perforations 46 above the plug 210. In other examples, the plugging devices 60 could block the flow through other types of openings (eg, openings in tubulars in addition to liner 16, flow passages in well tools such as valve 110, etc.). Therefore, the scope of this disclosure is not limited to the use of the container 202 to release the plugging devices 60 to plug the perforations 46.

The plugging devices 60 shown in Figure 15 are similar to those of the example in Figure 12, and are spherical in shape. These plugging devices 60 are well depicted in other examples of the system 200 and container 202 of Figures 16A-42B for convenience. However, any of the plugging devices 60 described herein may be used with any of the examples of the system 200 and container 202, and the scope of this disclosure is not limited to the use of any particular configuration, type, or shape of the tamponade devices.

Although only the release of plugging devices 60 from container 202 is described herein and depicted in the drawings, other plugging substances, devices or materials may also be released into the well from container 202 (or other container) into well 14 in other examples. A material (such as calcium carbonate, PLA, or PGA particles) can be released from container 202 and transported by flow 208 to any space between devices 60 and the openings to be plugged, such that a combination of devices and materials completely blocks flow through the openings.

Referring now further to Figures 16A-18B, an example of the dispensing tool 300 is representatively illustrated in different stages of actuation. Dispensing tool 300 can be used with system 200 and the method of Figure 15, or can be used with other systems and methods within the scope of this disclosure.

In this example, tool 300 is operated using a linear actuator 206 connected to an upper end of container 202. A portion of actuator 206 is depicted in Figures 16A and 16B, but is not depicted in Figures 17A-18B for convenience.

Any linear actuator 206 having sufficient feed length and force can be used. Suitable examples include standard lead wire plug setting tools (such as, those operated using a fired propellant (e.g., the common setting tool sold by Baker Oil Tools of Houston, Texas, USA), an electric actuator, or an electro-hydraulic actuator, etc.), hydraulic hose plug setting tools, or any hydraulic actuator (for example, using differential pressure or hydrostatic pressure to generate a force, etc.).

Plugging devices 60 are contained within a chamber 212 container 202. A rod 214 is retained by a safety pin 216. The rod 214 connects an end closure 218 to a mandrel 220. The mandrel 220 connects to the linear actuator 206.

When actuator 206 is operated as shown in Figures 17A and 17B, shear pin 206 is sheared, and rod 214 experiences a tension load. When sufficient tension load is exerted on rod 214 by means of actuator 206, a reduced cross-sectional portion 214a separates from the rod, thereby releasing end closure 218 from chamber 212.

As shown in Figures 18A and 18B, the end closure 218 can be detached from the container 202 and thus allow the plugging devices 60 to be released from the chamber 212. The end closure 218 can be made of a brittle material or dissolvable, in such a way that it does not interfere with subsequent well operations.

Additionally, when mandrel 220 is moved upward by actuator 206, a flow path 222 opens in the top of container 202. Fluid flow 208 may enter flow path 222, and assist in separation of the fluid. end closure 218 of container 202 and displace capping devices 60 from chamber 212. Alternatively, tool 300 can be moved upward in well 14, thereby creating a differential pressure from the top of chamber 212 to the bottom of the chamber.

Plugging devices 60 and any fluid and / or other material in chamber 212 will be expelled from container 202. A rate at which the contents of chamber 212 are expelled depends on the flow rate and other properties of fluid flow 208, or the rate of travel of tool 30 through well 14. Therefore, these rates can be conveniently varied to thereby achieve a desired spacing of plugging devices 60 along the well 14.

Referring now further to Figures 19A-21B, another example of the dispensing tool 300 is representatively illustrated at different stages. This example is similar in many respects to the example of Figures 16A-18B. However, instead of the bar 214 pulling apart in response to the stress applied by the actuator 206, the end closure 218 breaks and thus allows the plugging devices 60 to be released from the chamber 212.

In Figures 19A and 19B, tool 300 is in a run configuration. End closure 218, which is made of a brittle material, closes a lower end of chamber 212.

In Figures 20A and 20B, actuator 206 has moved mandrel 220 and rod 214 upward. This upward movement of bar 214 causes end closure 218 to break.

In Figures 21A and 21B, fluid flow 208 in open flow path 222 (or upward movement of tool 300 in well 14) acts to discharge plugging devices 60, and any fluid or other material, from container 202.

Referring now further to Figures 22A-23B, another example of the dispensing tool 300 is representatively illustrated. In this example, the plugging devices 60 are initially contained in a separate cartridge 224 that is alternately received in the container 202. Cartridge 224 may be pre-loaded with plugging devices 60, thus making it convenient to prepare tool 300 for use in a well.

Bar 214 is connected to an upper end of cartridge 224, and end closure 218 closes a lower end of cartridge. In Figures 22A and 22B, tool 300 is in a run configuration. End closure 218 is secured to cartridge 224 and abuts against a lower end of container 202.

In Figures 23A and 23B, actuator 206 has moved mandrel 220, rod 214, and cartridge 224 upward. The tension force exerted by actuator 206 has severed end seal 218 from cartridge 224, thereby opening the lower end of cartridge and container 202. Flow path 222 is also open, such that fluid flow 208 (or upward movement of tool 300 in well 14) can displace plugging devices 60, and any associated fluid and material, out of the container. 202 and the interior of well 14.

Referring now further to Figures 24A-25B, another example of tool 300 is representatively illustrated. In this example, end closure 218 is not necessarily brittle, but rather flexible in a manner that allows the lower end of the container 202 opens in response to the upward movement of rod 214 by actuator 206.

In Figures 24A and 24B, tool 300 is in a run configuration. A radially enlarged gap 226 at a lower end of bar 214 receives the inwardly extending projections 218a from closure end 218, which is separated into multiple, elongated, elastic clips 218b. Therefore, the clamps 218b are held in an inwardly bent condition by the bar 214.

In Figures 25A and 25B, bar 214 has been moved upward by actuator 206, thereby releasing projections 218a from gap 226, and allowing clips 218b to flex outward. This opens the lower end of container 202 and allows the flow of fluid 208 through the now open flow path 222 (or upward movement of tool 300 into the well

14) to move plugging devices 60, and any associated fluids and materials, out of container 202 and into well 14.

Referring now further to Figures 26A-27B, another example of tool 300 is representatively illustrated. In this example, actuator 206 is not a linear actuator, but rather is a rotary actuator that includes a motor 228.

The motor 228 rotates a bore 230 in the container 202. The plugging devices 60 are contained in the chamber 212, which extends helically between blades of the bore 230. The bore 230 is shown separately in Figures 27A and 27B.

When the bore 230 rotates by means of the motor 228, the plugging devices 60 are gradually discharged from the lower end of the container 202. A discharge rate of the plugging devices 60 can be controlled by varying the rotational speed of the motor 228 and the drill 230. Tool 300 can travel in well 14 at a selected speed while rotating hole 230 at a specific speed to thereby achieve a desired spacing of plugging devices 60 in well 14.

Suitable examples of rotary motors or actuators for use as the 228 motor include: a) an electric motor or motor and motor and drive train operated by conductive wire or transportable wire, b) an electric or hydraulic rotary actuator operated by conductive cable or transportable wire, c) a mud motor (a turbine or fluid motor positive displacement) operated in flexible tubing or articulated tube, d) a battery-operated rotary source transported by any suitable means, and e) tube rotation from the surface with a drag block or other friction element within the well to provide relative rotational movement in tool 300.

Referring now further to Figures 28A-30B, another example of the tool 300 is representatively illustrated. This example is similar in many respects to the example of Figures 26A-27B, in that the rotation of the bore 230 is used to discharge the devices. 60 plugging from container 202. However, the example of Figures 28A-30B also includes a barrier 232 displaceable through rotation of bore 230, thereby to positively discharge plugging devices 60 from chamber 212.

9

In Figures 28A and 28B, tool 300 is in a run configuration. Barrier 232 is positioned at an upper end of chamber 212, which is loaded with coupling devices 60. Barrier 232 has a helical groove 232a formed therein for engagement with blades of bore 230.

Top and side views of barrier 232 are representatively illustrated in respective Figures 29A and 29B. In these views, it can be seen that barrier 232 also has splines 232b formed longitudinally therein for sliding engagement with longitudinal grooves 212a formed in chamber 212.

The engagement between the splines 232b and the slots 212a prevents the barrier 232 from rotating with the bore 230, while also allowing the barrier to move longitudinally in the chamber 212 due to the rotation of the bore 230 and the engagement between the blades of the bore and helical groove 232a.

In Figures 30A and 30B, bore 230 has been rotated by motor 228 of actuator 206, thereby moving barrier 232 longitudinally through container 202 and discharging plugging devices 60 from chamber 212.

Referring now further to Figures 31A-32B, another example of tool 300 is representatively illustrated. In this example, multiple barriers 232 are longitudinally spaced along bar 214, which is externally threaded (see Figures 32A and 32B).

The externally threaded rod 214 is similar in some respects to the bore 230 of the examples of Figures 26A30B, in that rotation of the rod by means of the motor 228 causes longitudinal displacement of the barriers 232 through the chamber 212. The barriers 232 of the example of Figures 31A-32B include helical groove 232a, which is internally threaded. External grooves 232b could be provided on barriers 232 for engagement with longitudinal grooves 212a in chamber 212 (as in the example of Figures 28A-30B), if desired, to prevent rotation of barriers 232 with rod 214 threaded.

In Figures 31A and 31B, tool 300 is depicted in a run configuration. When motor 228 is operated to rotate rod 214, barriers 232 will gradually move downward, thereby releasing plugging devices 60 from the lower end of container 202. The barriers 232 can also be moved out of chamber 212 and into the well 14, and thus the barriers can be made of brittle or dissolvable material so that they will not interfere with subsequent operations of the well.

Referring further now to Figures 33A-34B, another example of tool 300 is representatively illustrated. In this example, tool 300 includes cartridge 224 similar to the example of Figures 22A-23B, but the cartridge rotates to release the devices. 60 plugging, rather than being longitudinally displaced.

In Figures 33A and 33B, tool 300 is depicted in a run configuration. Plugging devices 60 are received in cartridge 224, which is rotatably received in container 202, and is connected to motor 228. A longitudinally extending passage 234 through end closure 218 is blocked by an end closure. 218 from cartridge 224.

In Figures 34A and 34B, tool 300 is depicted in a driven configuration, in which cartridge 224 has been rotated by motor 228. As a result, a passage 236 in cartridge end seal 218 is now aligned with the passage 234 in the end closure 218 of the container.

Another passage 240 in an upper end closure of cartridge 224 is now aligned with flow path 222.

Plugging devices 60 can now be released into well 14 by fluid flow 208 (or by upward movement of tool 300 through well).

Referring now further to Figures 35A-35C, the example of Figures 26A-27B of tool 300 in combination with piercer 48 is representatively illustrated. Piercer 48 is connected above tool 300, with a line 242 for operating motor 228 extending through the perforator. Line 242 may be an electrical, hydraulic, fiber optic, or other line for transmitting power and / or control signals to actuator 206 and motor 228.

Piercer 48, in this example, is an explosive piercer of the type that includes shaped charges 48a within an outer tubular housing 48b. However, other types of perforators (such as, fluid jet perforators, etc.) can be used in other examples.

The perforator 48 is connected above the tool 300, when the perforator is connected between the transport 204 (see Figure 15) and the dispensing tool. However, other relative positions of piercer 48, transport 204, and tool 300 may be utilized within the scope of this disclosure.

Referring now further to Figures 36A-36C, another example of the perforator 48 and dispensing tool 300 combined is representatively illustrated. In this example, tool 300 is connected above piercer 48, such that tool 300 will be connected between transport 204 (see Figure 15) and piercer.

Line 242 in this example can include multiple lines, and different types of lines can be included (such as, electric, hydraulic, fiber optic, detonation cord, etc.). At least one of the lines 242 can be used to operate the actuator 206, and - another of the lines can be used to operate the perforator 48 (such as, to detonate a perforator detonator or explosive cap to explode the shaped charges 48a, etc.). For the operation of perforator 48, at least one of lines 242 extends longitudinally through dispensing tool 300, from transport 204 to the perforator.

In this configuration, the dispensing tool 300 can dispense the plugging devices 60 into the well 14 above the perforations formed by the perforator 48, such that the fluid flow 208 can conveniently transport the plugging devices into mating coupling. sealed with the perforations, such as, after a treatment operation has been carried out. In other configurations in which the dispensing tool 300 is positioned below the perforator 48, the transport 204 can be used to raise the dispensing tool relative to the perforations formed by the perforator (such as, after it has been brought into perform a treatment operation), in order to dispense the plugging devices 60 above the perforations. However, it is not necessary within the scope of this disclosure that the plugging devices 60 be dispensed above, below, or in any other particular position relative to the perforations.

Note that, since dispensing tool 30 is positioned above piercer 48, dispensing tool is configured to discharge plugging devices 60 laterally from tool into well 14. Specifically, tool 300 includes a port for side discharge 244 that is initially blogged by a barrier 24 6, as depicted in Figure 36B.

Barrier 246 is internally threaded and positioned on an externally threaded lower portion of rod 214. When rod 214 is rotated by motor 228, barrier 246 travels down into container 202, until port 244 is fully opened . Rotation of rod 214 also operates bore 230 such that plugging devices 60 discharge from side port 244 after it is opened.

Referring now further to Figures 37A-38C, another example of the perforator 48 and dispensing tool 300 combined is representatively illustrated. In this example, the dispensing tool 300 is connected between two piercers 48. Consequently, the tool 300 includes the side port 244 and the barrier 246 to control the release of the plugging devices 60 laterally from the chamber 212 into the well. 14.

In Figures 37A-37C, the dispensing tool 300 is depicted in an execution configuration. In Figures 38A-38C, dispensing tool 300 is depicted in a powered configuration, with side port 244 open, such that plugging devices 60 are released from container 202.

Referring now further to Figures 39A and 39B, another example of the dispensing tool 300 is representatively illustrated. In this example, the actuator for releasing the plugging devices 60 is in the form of detonators 248 and brittle discs 250 that initially lock flow path 222 and passage 244 at opposite ends of chamber 212.

When an appropriate electrical signal is transmitted to detonators 248 through lines 242, the detonators detonate, thereby breaking brittle discs 250. Fluid flow 208 can then pass into chamber 212 through the pathway. flow 222, and the plugging devices 60 may move out of the chamber through the open passage 244.

In the example of Figures 39A and 39B, the dispensing tool 300 is connected above a perforator 48, that is, between the transport 204 and the perforator. Thus, passage 244 discharges plugging devices 60 laterally into well 14. At least one of lines 242 extends longitudinally through dispensing tool 300 to piercer 48 for actuation of piercer.

Referring further now to Figures 40A and 40B, another example of the dispensing tool 300 is representatively illustrated. This example is similar in some respects to the example of Figures 39A and 39B, in that the two tape detonators 48 are used to open opposite ends of chamber 212 and release plugging devices 60.

However, in the example of Figures 40A and 40B, the lower detonator 248 is received in the brittle end closure 218. When the detonators 248 are detonated, the end seal 218 will break, thereby opening the lower end of the chamber 212, and the brittle disk 250 that initially blocks the flow path 222 will break, thereby opening the flow path. flow. Fluid flow 208 (or upward movement of tool 300 in well 14) can then displace plugging devices 60, and any associated fluid and material in chamber 212, into the well through the open lower end of the well. the camera.

A sealed enclosure 252 with electrical power can be used to isolate chamber 212 from transport 204 or a piercer 48 connected above dispensing tool 300. In different exemplary configurations, tool 300 of Figures 40A and 40B could be positioned by above, below or between one or more perforators 48.

Referring now further to Figures 41A-41C, another example of the dispensing tool 300 is representatively illustrated, connected between two piercers 48. The dispensing tool 300 in this example is similar, and opera similar, the example of the Figures 39A and 39B.

Referring now further to Figures 42A and 42B, still another example of the dispensing tool 300 is representatively illustrated. In this example, a gas generating charge or propellant 254 is used to release and eject the plugging devices 60 upon release. well interior 14.

To operate tool 300, propellant 254 is ignited via lines 242, causing pressure build-up. When the pressure reaches a predetermined level, a rupture disc 256 ruptures, suddenly introducing relatively high pressure gas into chamber 212. The sudden increase in pressure in chamber 212 causes the end seal 218 to rupture, releasing it way the plugging devices 60 from the chamber into the well 14.

The exemplary dispensing tool 300 of Figures 42A and 42B could be configured for connection above a piercer, or between piercers, by providing a laterally directed passageway (such as passageway 244 described above) with a brittle closure. Any of the examples of dispensing tool 300 described above could be positioned above or between piercers 48, or otherwise positioned relative to other well tools, within the scope of this disclosure.

It can now be fully appreciated that the above disclosure provides significant advancements to the art of controlling flow in underground wells. In some examples described above, the plugging device 60 can be used to block flow through openings in a well, with the device being uniquely configured such that its transport with flow is enhanced and / or improved. its sealing coupling with an opening. A dispensing tool 300 can be used to deploy the devices 60 into the well, such that a desired location and spacing between the devices is achieved.

Some advantages of the examples of the dispensing tool 300 and method described above may include (but are not limited to): a) plugging devices 60 can be precisely positioned in a desired location within well 14 for selective plugging of specific boreholes 46, b) plugging devices 60 do not have to be compatible with surface pumping equipment, c ) a possibility of accidentally plugging the pumping equipment at the surface is eliminated, d) very large plugging devices 60 can be deployed, making it possible to plug very large openings in the wellbore, e) the plugging devices 60 can be distributed in a specific desired spacing or density within the well 14, f) no special or additional equipment is needed at the surface beyond that required to standard plugging and drilling operations, and g) there is no possibility of presetting a plug.

The above disclosure provides the art with a method of releasing devices 60 from a hole within a well 14. In one example, the method may include transporting a dispensing tool 300 to a desired location within the well in well 14, the dispensing tool 300 includes a container 202, and then releasing the plugging devices 60 from the container 202 into the well 14 at the location within the well.

The release step may comprise operating an actuator 206 of the dispensing tool 300. The operating step may comprise detonating at least one detonator 248, operating a motor 228, rotating a bore 230, moving a barrier 232 through a chamber 212 in container 202, operating a linear actuator 206, and / or firing a propellant 254.

The method may include connecting the dispensing tool 300 between perforators 48. The method may include connecting the dispensing tool 300 between a perforator 48 and a transport 204. The method may include connecting a perforator 48 between a transport 204 and the dispensing tool. 300.

Each of the plugging devices 60 may comprise a body 64 and, extending outward from the body, at least one of the group consisting of lines 66 and fibers 62. Said at least one of the group consisting of lines 66 and fibers 62 it may have a lateral dimension substantially less than a body size 64.

The body 64 of each of the plugging devices 60 may comprise a knot.

Each of the plugging devices 60 may include a degradable material. The degradable material can be selected from the group consisting of polyvinyl alcohol, polyvinyl acetate, polymethacrylic acid, polylactic acid and polyglycolic acid.

A plugging device dispensing system 200 for use with an underground well is also provided to the art by the above disclosure. In one example, the dispensing system 200 may comprise a dispensing tool 300 that includes a container 202 configured to contain multiple plugging devices 60, and an actuator 206 operable to release the plugging devices 60 from the container 202 at a location in inside the well.

Although different examples have been described in the foregoing, with each example having certain characteristics, it should be understood that it is not necessary that a particular characteristic of an example be used exclusively with that example. Instead, any of the features described above and / or depicted in the drawings can be combined with any of the examples, in addition to or in place of any of the other features of those examples. Features in one example are not mutually exclusive to features in another example. Instead, the scope of this disclosure encompasses any combination of any of the characteristics.

Although each example described above includes a certain combination of features, it should be understood that it is not necessary that all features of an example be used. Instead, any of the features described above can be used, without also using any other particular features or features. '

It should be understood that the different modalities described in this document can be used in different orientations, such as tilted, inverted, horizontal, vertical, etc., and in different configurations, without departing from the principles of this disclosure. The modalities are described only as examples of useful applications of the principles of the disclosure, which are not limited to any specific details of these modalities.

In the foregoing description of representative examples, directional terms (such as over, under, over, under, etc.) are used for convenience when referring to the accompanying drawings. However, it should be clearly understood that the scope of this disclosure is not limited to any particular address described in this document.

The terms including, includes, comprising, comprises, and like terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc., is described as

4 that includes a certain feature or item, the system, method, apparatus, device, etc., may include that feature or item, and may also include other features or items. Similarly, the term "comprise" is taken to mean "comprises," but is not limited to.

Of course, a person skilled in the art would readily appreciate, with careful consideration of the above description of representative modalities of disclosure, that many modifications, additions, substitutions, omissions, and other changes can be made to the specific modalities, and such changes are contemplated by the principles of this disclosure. For example, the structures that are disclosed as being separately formed may, in other examples, be formed integrally and vice versa. Accordingly, the above detailed description is to be clearly understood as provided by way of illustration and examples only, the spirit and scope of the invention being limited only by the appended claims and their equivalents.

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