Methods of completing a well and apparatus therefor

A system for use with a well can include a perforating assembly with at least one perforator, the perforating assembly conveyed through a wellbore with fluid flow through the wellbore, and plugging devices spaced apart from the perforating assembly in the wellbore, the plugging devices conveyed through the wellbore with the fluid flow. A method of deploying plugging devices in a wellbore can include conveying a perforating assembly including a dispensing tool through the wellbore, the dispensing tool including a container, and then releasing the plugging devices from the container into the wellbore at a downhole location. Another method of deploying plugging devices in a wellbore can include conveying the plugging devices through the wellbore with fluid flow through the wellbore, and conveying a perforating assembly through the wellbore while the plugging devices are being conveyed through the wellbore.

BACKGROUND

This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in one example described below, more particularly provides for plugging devices and their deployment in wells.

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 formation zone. As another example, it may be desirable in some circumstances to cause fluid to flow into a particular formation zone, instead of into another formation zone. As yet another example, it may be desirable to temporarily prevent fluid from flowing through a passage of a well tool. Therefore, it will be readily appreciated that improvements are continually needed in the art of controlling fluid flow in wells.

DETAILED DESCRIPTION

Example methods described below allow existing fluid passageways to be blocked permanently or temporarily in a variety of different applications. Certain flow conveyed plugging device examples described below are made of a fibrous material and may comprise a central body, a “knot” or other enlarged geometry.

The devices may be conveyed into the passageways or leak paths using pumped fluid. Fibrous material extending outwardly from a body of a device can “find” and follow the fluid flow, pulling the enlarged geometry or fibers into a restricted portion of a flow path, causing the enlarged geometry and additional strands to become tightly wedged into the flow path, thereby sealing off fluid communication.

The devices can be made of degradable or non-degradable materials. The degradable materials can be either self-degrading, or can require degrading 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. The exposure can be performed at a desired time using a form of well intervention, such as, by spotting or circulating a fluid in the well so that the material is exposed to the fluid.

In some examples, the material can be an acid degradable material (e.g., nylon, etc.), a mix of acid degradable material (for example, nylon fibers mixed with particulate such as calcium carbonate), self-degrading material (e.g., poly-lactic acid (PLA), poly-glycolic acid (PGA), 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 the nylon could be pumped first to initiate a seal, followed by calcium carbonate to enhance the seal.

In certain examples described below, the device can be made of knotted fibrous materials. Multiple knots can be used with any number of loose ends. The ends can be frayed or un-frayed. The fibrous material can be rope, fabric, metal wool, cloth or another woven or braided structure.

The device can be used to block open sleeve valves, perforations or any leak paths in a well (such as, leaking connections in casing, corrosion holes, etc.). Any opening or passageway through which fluid flows can be blocked with a suitably configured device. For example, an intentionally or inadvertently opened rupture disk, or another opening in a well tool, could be plugged using the device.

Previously described plugging devices can be used in the methods described herein, along with several different apparatuses and methods for deploying and placing the plugging devices at desired locations within the well. Descriptions of fibrous and/or degradable plugging devices are in U.S. application Ser. No. 14/698,578 (filed 28 Apr. 2015), 62/195,078 (filed 21 Jul. 2015), 62/243,444 (filed 19 Oct. 2015) and 62/252,174 (filed 6 Nov. 2015), and in International application no. PCT/US15/38248 (filed 29 Jun. 2015). The entire disclosures of these prior applications are incorporated herein by this reference.

In one example method described below, a well with an existing perforated zone can be re-completed. Devices (either degradable or non-degradable) are conveyed by flow to plug all existing perforations.

The well can then be re-completed using any desired completion technique. If the devices are degradable, a degrading treatment can then be placed in the well to open up the plugged perforations (if desired).

In another example method described below, multiple formation zones can be perforated and fractured (or otherwise stimulated, such as, by acidizing) in a single trip of a bottom hole assembly into the well. In the method, one zone is perforated, the zone is stimulated, and then the perforated zone is plugged using one or more devices.

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

In another example, flow of fluid into previously fractured zones is blocked using flow conveyed plugging devices instead of a drillable plug. The plugging devices are carried into a wellbore via a tool in a perforating assembly. The plugging devices are then released in the wellbore. The method generally consists of the following steps:1. Establish a flow path through the wellbore (for example, by providing one or more openings at a “toe” or distal end of the wellbore, e.g., via coiled tubing perforations, a pressure operated toe valve, a wet shoe, etc.), so fluid can be pumped through the wellbore, allowing the perforating assembly to be pumped down the cased wellbore.2. Pump the perforating assembly to above (less depth along the wellbore) the topmost open perforations in the wellbore. The perforating assembly includes (from bottom to top) a plugging device dispensing tool, one or more perforators, a controller/firing head, and a connector for a conveyance used to convey the assembly into the wellbore.3. Operate an actuator of the plugging device dispensing tool to release the plugging devices into the wellbore above the topmost open perforations. The actuator may be operated using various techniques, such as, electrically, hydraulically, by pipe manipulation, by applying set down weight, by igniting a propellant, by detonating an explosive, etc.4. Move the perforating assembly up hole to one or more additional desired locations (to shallower depths along the wellbore) and operate perforators to create perforations at the one or more locations within the cased wellbore. If jointed or coiled tubing is used to convey the perforating assembly, the controller/firing head may be pressure actuated to detonate explosive shaped charges of the perforator, or an abrasive jet perforator may be used.5. Retrieve the perforating assembly from the wellbore.6. Perform fracturing operations to fracture the formation(s) penetrated by the open perforations, and deliver sand slurry (e.g., proppant) to fractured formation(s).7. Pump “flush” of sand-free fluid from surface to push any remaining sand out of the wellbore and into the fractured formation(s) via the open perforations.8. Repeat steps 2-7 until all desired zones are fractured.

The above method can also be used in conjunction with a conventional “plug and perf” technique, in which drillable bridge plugs are installed in a cased wellbore above previously fractured zone(s).

The plugging device dispensing tool used to convey the plugging devices into the wellbore can comprise a canister or other container which is loaded with plugging devices and conveyed into the well with the perforating assembly. Of course, any means of conveyance can be used to convey the perforating assembly (for example, wireline, coiled tubing, jointed pipe, slickline, etc.).

Some suitable embodiments and methods for carrying plugging devices into the wellbore are listed below. In addition, any of the methods and dispensing apparatuses described in U.S. patent application Ser. No. 15/138,968, filed 26 Apr. 2016, may be used. The entire disclosure of this prior application is incorporated herein by this reference for all purposes.1. In one example, the plugging devices are dispensed using an auger type element driven by an electric motor. In this example, the number of devices dispensed is dependent on the run time and speed of the electric motor, and a configuration of the auger.2. In another example, the plugging devices are carried in a tube with a frangible disk closing off a bottom of the tube. The disk can be broken so that fluid pumped past the dispensing tool, or upward movement of the dispensing tool, creates a pressure differential to push the plugging devices out of the tool. The disk can be broken using:a. Pyrotechnic explosive (for instance a blasting cap or detonator as used in dump bailers).b. Fluid pressure generated by the dispensing tool.c. Mechanical impact caused by the dispensing tool.d. Any other shock-inducing or cutting action.3. In another example, the plugging device dispensing tool comprises a canister or chamber having an initially closed opening or valve which can be mechanically operated to an open position. In the open position, the plugging devices are allowed to exit from the canister or chamber. The plugging devices can be forcibly discharged, or a pressure differential can be generated across the canister/chamber by pumping fluid past the tool, or the tool can be moved within the wellbore. The opening can be anywhere on the tool, such as, at the bottom, or along a side of the canister.4. In another example, the plugging devices are dispensed in a “slurry” which is pumped from the dispensing tool to the wellbore using an electrically driven pump.5. Some of the dispensing tool examples described above can be adapted to use a standard bridge plug setting tool as the motive means to operate the dispensing tool. This would allow widely used, industry standard setting tools to be used with little or no modification to operate the dispensing tool(s). In this case, the plugging device dispensing tool will have a mechanical interface which is practically identical to industry standard drillable bridge plugs.

In another method, flow of fluid into previously fractured zones is blocked using flow conveyed plugging devices, instead of a drillable bridge plug. The plugging devices are pumped from the surface into the wellbore ahead of the perforating assembly, and as the perforating assembly is being pumped through the wellbore.

The perforating assembly is stopped above open perforations that were fractured in a previous stage, or another opening that provides for flow through the wellbore. The plugging devices are pumped beyond the perforating assembly location and into the open perforations or other openings to block flow into the perforations or openings during the next fracturing step. The method generally consists of the following steps:1. Establish a flow path through the wellbore (for example, by providing one or more openings at a “toe” or distal end of the wellbore, e.g., via coiled tubing perforations, a pressure operated toe valve, a wet shoe, etc.), so fluid can be pumped through the wellbore, allowing the perforating assembly to be pumped down the cased wellbore.2. Pump plugging devices from surface into the wellbore slightly ahead of the perforating assembly.3. Pump perforating assembly to above the topmost open perforations or other openings in the wellbore, while at the same time pumping plugging devices just ahead of the perforating assembly. The perforating assembly can include (from bottom to top) one or more perforators, a controller/firing head, and a connector for a conveyance used to convey the assembly into the wellbore.4. While holding the perforating assembly in place above the open perforations or other openings, continue pumping the plugging devices further into the wellbore until they land in the open perforations or openings below the perforating assembly and block further flow into the perforations or openings.5. Move the perforating assembly up hole to one or more additional desired locations (to shallower depths along the wellbore) and operate perforators to create perforations at the one or more locations within the cased wellbore. If jointed or coiled tubing is used to convey the perforating assembly, the controller/firing head may be pressure actuated to detonate explosive shaped charges of the perforator, or an abrasive jet perforator may be used.6. Retrieve the perforating assembly from the wellbore.7. Perform fracturing operations to fracture the formation(s) penetrated by the open perforations, and deliver sand slurry (e.g., proppant) to fractured formation(s).8. Repeat steps 2-7 until all desired zones are fractured.

The above method can also be used in conjunction with a conventional “plug and perf” technique, in which drillable bridge plugs are installed in a cased wellbore above previously fractured zone(s).

After a wellbore is completed using any of the methods described herein, the plugging devices may be removed in any of a number of ways including:a. Mechanical removal with a drilling assembly including a fluid motor conveyed on tubing.b. Mechanical removal with a gauge ring conveyed on tubing.c. Mechanical removal with a drilling assembly rotated from surface.d. Chemical removal by applying a degrading treatment (such as acid) “spotted” through tubing, or pumped from the surface.e. Waiting a prescribed amount of time if self-degrading plugging devices are used.

Note that none of the methods described herein are limited to hydraulic fracturing. They can also be applied to matrix treatments, such as matrix acidizing (carbonate or sandstone formations), and damage removal (e.g., scale, mud filtrate) with acid or chelants. Any type of stimulation treatment may be performed, instead of or in addition to fracturing, in keeping with the principles of this disclosure.

Representatively illustrated inFIG. 1is a system10for use with a well, and an associated method, which can embody principles of this disclosure. However, it should be clearly understood that the system10and method are merely 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 limited at all to the details of the system10and method described herein and/or depicted in the drawings.

In theFIG. 1example, a wellbore12has been drilled so that it penetrates an earth formation14. The wellbore12is lined with casing16and cement18, although in other examples one or more sections of the wellbore may be uncased or open hole.

The wellbore12as depicted inFIG. 1is generally horizontal, and a “toe” or distal end of the wellbore is to the right of the figure. However, in other examples, the wellbore12could be generally vertical or inclined relative to vertical.

As used herein, the terms “above,” “upward” and similar terms are used to refer to a direction toward the earth's surface along the wellbore12, whether the wellbore is generally horizontal, vertical or inclined. Thus, in theFIG. 1example, the upward direction is toward the left of the figure.

As depicted inFIG. 1, a set of perforations20ahave been formed through the casing16, cement18and into a zone14aof the formation14. The perforations20aprovide for fluid communication between the zone20aand an interior of the casing16. Such fluid communication could be otherwise provided, such as, by use of a sliding sleeve valve (not shown) or other openings or ports through the casing16.

The perforations20a(or other openings) may be provided or formed in order to establish such fluid communication, so that a flow path extends longitudinally through the wellbore12and into the zone14a. In some examples, the perforations20amay be formed primarily to enable production flow from the zone14ato the earth's surface via the wellbore12.

The perforations20amay be formed using any suitable technique, such as, perforating by explosive shaped charges or by discharge of an abrasive jet, or the perforations may exist in the casing16prior to the casing being installed in the wellbore12(for example, a perforated liner could be installed as part of the casing). Thus, the scope of this disclosure is not limited to any particular timing or technique for forming the perforations20a.

In some examples, openings other than perforations may be available in the well for enabling fluid flow through the wellbore12. Tools known to those skilled in the art as a “wet shoe” or a “toe valve” can provide openings at the distal end of the wellbore12. Thus, the scope of this disclosure is not limited to any particular means of providing for fluid flow through the wellbore12.

Note that it is not necessary in keeping with the principles of this disclosure for the perforations20aor other openings to be formed at or near a distal end of the wellbore12, or for any other procedures or steps described herein to be performed at or near a distal end of a wellbore.

In theFIG. 1example, a fluid flow22is established longitudinally through the wellbore12, outward through the perforations20aand into the zone14a. This fluid flow22is used to displace or “pump” a perforating assembly24through the wellbore12. Note that the zone14amay have been treated (for example, by acidizing, fracturing, injection of conformance agents, etc.) prior to establishing the fluid flow22, or the fluid flow could be part of treating the zone14a.

As depicted inFIG. 1, the perforating assembly24includes a plugging device dispensing tool26, two perforators28, a firing head30, and a connector32. The connector32is used to connect the perforating assembly24to a conveyance34, such as, a wireline, a slickline, coiled tubing or jointed tubing.

The dispensing tool26in this example includes a container36and an actuator38. The container36contains the plugging devices (not visible inFIG. 1, seeFIG. 2), and the actuator38acts to release the plugging devices from the container in the wellbore12.

Several examples of the container36and actuator38are depicted inFIGS. 14-18and described more fully below. In addition, any of the methods and dispensing apparatuses described in the U.S. patent application Ser. No. 15/138,968 mentioned above may be used for the container36and actuator38.

The perforators28are depicted inFIG. 1as being explosive shaped charge perforating guns. Shaped charges in the perforating guns are detonated by means of the firing head30, which may be operated in response to a predetermined pressure, pressure pulse, acoustic, electric, hydraulic, optical or other type of signal.

Alternatively, the perforators28could comprise one or more abrasive jet perforators (for example, if the conveyance34is a coiled or jointed tubing). The scope of this disclosure is not limited to use of any particular type of perforator.

The fluid flow22displaces the perforating assembly24through the wellbore12to a desired location. In this example, the desired location is a position above the perforations20a. In other examples, gravity or another source of a biasing force could be used to displace the perforating assembly24through the wellbore12(e.g., if the wellbore is vertical or inclined, or if a downhole tractor is used), and/or the perforating assembly may be displaced to another desired location.

Referring additionally now toFIG. 2, the system10and method are representatively illustrated after the perforating assembly24has been displaced to the desired location above the open perforations20a, and the dispensing tool26has been operated to release the plugging devices60into the wellbore above the perforations. The fluid flow22displaces the plugging devices60through the wellbore12toward the open perforations20a.

Any number of the plugging devices60may be released from the tool26. In various examples, the number of plugging devices60released could be equal to, less than, or greater than, the number of open perforations20a.

An equal number of open perforations20aand plugging devices60may be used if it is desired to plug all of the perforations and not have excess plugging devices remaining in the wellbore12. A greater number of plugging devices60may be used if it is desired to ensure that there are more than an adequate number of plugging devices to plug all of the perforations20a. A fewer number of plugging devices60may be used if it is desired to maintain a capability for flowing fluid downward through the wellbore12after most of the perforations20ahave been plugged.

Referring additionally now toFIG. 3, the system10and method are representatively illustrated after the plugging devices60have sealingly engaged and prevent fluid flow into the perforations20a. The perforating assembly24has been raised in the wellbore12to another location where it is desired to perforate another zone14bof the formation14, and perforations20bhave been formed through the casing16and cement18by the perforating assembly.

Fluid communication is now permitted between the zone14band the interior of the casing16. Additional perforations may be formed at other locations along the wellbore12using the perforating assembly24, if desired. The perforating assembly24can then be retrieved from the wellbore12, and the zone14b(and any other perforated zone(s)) can be treated (for example, by fracturing, acidizing, injection of conformance agents, etc.).

The steps described above and depicted inFIGS. 1-3can be repeated multiple times, until all desired zones have been perforated and treated. At that point, the plugging devices60can be degraded or otherwise removed from the perforations or other openings, so that fluid communication is permitted between the various zones and the interior of the casing16.

Referring additionally now toFIG. 4A, an example of a flow conveyed plugging device60that can incorporate the principles of this disclosure is representatively illustrated. The device60may be used for any of the plugging devices in the method examples described herein, or the device may be used in other methods.

The device60example ofFIG. 4Aincludes multiple fibers62extending outwardly from an enlarged body64. As depicted inFIG. 4A, each of the fibers62has a lateral dimension (e.g., a thickness or diameter) that is substantially smaller than a size (e.g., a thickness or diameter) of the body64.

The body64can be dimensioned so that it will effectively engage and seal off a particular opening in a well. For example, if it is desired for the device60to seal off a perforation in a well, the body64can be formed so that it is somewhat larger than a diameter of the perforation. If it is desired for multiple devices60to seal off multiple openings having a variety of dimensions (such as holes caused by corrosion of the casing16), then the bodies64of the devices can be formed with a corresponding variety of sizes.

In theFIG. 4Aexample, the fibers62are joined together (e.g., by braiding, weaving, cabling, etc.) to form lines66that extend outwardly from the body64. In this example, there are two such lines66, but any number of lines (including one) may be used in other examples.

The lines66may be in the form of one or more ropes, in which case the fibers62could comprise frayed ends of the rope(s). In addition, the body64could be formed by one or more knots in the rope(s). In some examples, the body64can comprise a fabric or cloth, the body could be formed by one or more knots in the fabric or cloth, and the fibers62could extend from the fabric or cloth.

In other examples, the device60could comprise a single sheet of material, or multiple strips of sheet material. The device60could comprise one or more films. The body64and lines66may not be made of the same material, and the body and/or lines may not be made of a fibrous material.

In theFIG. 4Aexample, the body64is formed by a double overhand knot in a rope, and ends of the rope are frayed, so that the fibers62are splayed outward. In this manner, the fibers62will cause significant fluid drag when the device60is deployed into a flow stream, so that the device will be effectively “carried” by, and “follow,” the flow.

However, it should be clearly understood that other types of bodies and other types of fibers may be used in other examples. The body64could have other shapes, the body could be hollow or solid, and the body could be made up of one or multiple materials. The fibers62are not necessarily joined by lines66, and the fibers are not necessarily formed by fraying ends of ropes or other lines. The body64is not necessarily centrally located in the device60(for example, the body could be at one end of the lines66). Thus, the scope of this disclosure is not limited to the construction, configuration or other details of the device60as described herein or depicted in the drawings.

Referring additionally now toFIG. 4B, another example of the device60is representatively illustrated. In this example, the device60is formed using multiple braided lines66of the type known as “mason twine.” The multiple lines66are knotted (such as, with a double or triple overhand knot or other type of knot) to form the body64. Ends of the lines66are not necessarily frayed in these examples, although the lines do comprise fibers (such as the fibers62described above).

Referring additionally now toFIG. 5, another example of the device60is representatively illustrated. In this example, four sets of the fibers62are joined by a corresponding number of lines66to the body64. The body64is formed by one or more knots in the lines66.

FIG. 5demonstrates that a variety of different configurations are possible for the device60. Accordingly, the principles of this disclosure can be incorporated into other configurations not specifically described herein or depicted in the drawings. Such other configurations may include fibers joined to bodies without use of lines, bodies formed by techniques other than knotting, etc.

Referring additionally now toFIGS. 6A& B, an example of a use of the device60ofFIG. 4Ato seal off an opening68in a well is representatively illustrated. In this example, the opening68is a perforation formed through a sidewall70of a tubular string72(such as, a casing, liner, tubing, etc.). However, in other examples the opening68could be another type of opening, and may be formed in another type of structure.

The device60is deployed into the tubular string72and is conveyed through the tubular string by fluid flow74. The fibers62of the device60enhance fluid drag on the device, so that the device is influenced to displace with the flow74.

The fluid flow74may be the same as, or similar to, the fluid flow22described above for the example ofFIGS. 1-3. However, the fluid flow74could be another type of fluid flow, in keeping with the principles of this disclosure.

Since the flow74(or a portion thereof) exits the tubular string72via the opening68, the device60will be influenced by the fluid drag to also exit the tubular string via the opening68. As depicted inFIG. 6B, one set of the fibers62first enters the opening68, and the body64follows. However, the body64is appropriately dimensioned, so that it does not pass through the opening68, but instead is lodged or wedged into the opening. In some examples, the body64may be received only partially in the opening68, and in other examples the body may be entirely received in the opening.

The body64may completely or only partially block the flow74through the opening68. If the body64only partially blocks the flow74, any remaining fibers62exposed to the flow in the tubular string72can be carried by that flow into any gaps between the body and the opening68, so that a combination of the body and the fibers completely blocks flow through the opening.

In another example, the device60may partially block flow through the opening68, and another material (such as, calcium carbonate, poly-lactic acid (PLA) or poly-glycolic acid (PGA) particles) may be deployed and conveyed by the flow74into any gaps between the device and the opening, so that a combination of the device and the material completely blocks flow through the opening.

The device60may permanently prevent flow through the opening68, or the device may degrade to eventually permit flow through the opening. If the device60degrades, it may be self-degrading, or it may be degraded in response to any of a variety of different stimuli. Any technique or means for degrading the device60(and any other material used in conjunction with the device to block flow through the opening68) may be used in keeping with the scope of this disclosure.

In other examples, the device60may be mechanically removed from the opening68. For example, if the body64only partially enters the opening68, a mill or other cutting device may be used to cut the body from the opening. Some techniques for degrading or otherwise removing the device60are representatively illustrated inFIGS. 22-24, and are described more fully below.

Referring additionally now toFIGS. 7-9, additional examples of the device60are representatively illustrated. In these examples, the device60is surrounded by, encapsulated in, molded in, or otherwise retained by, a retainer80.

The retainer80aids in deployment of the device60, particularly in situations where multiple devices are to be deployed simultaneously. In such situations, the retainer80for each device60prevents the fibers62and/or lines66from becoming entangled with the fibers and/or lines of other devices.

The retainer80could in some examples completely enclose the device60. In other examples, the retainer80could be in the form of a binder that holds the fibers62and/or lines66together, so that they do not become entangled with those of other devices.

In some examples, the retainer80could have a cavity therein, with the device60(or only the fibers62and/or lines66) being contained in the cavity. In other examples, the retainer80could be molded about the device60(or only the fibers62and/or lines66).

During or after deployment of the device60into the well, the retainer80dissolves, melts, disperses or otherwise degrades, so that the device is capable of sealing off an opening68in the well, as described above. For example, the retainer80can be made of a material82that degrades in a wellbore environment.

The retainer material82may degrade after deployment into the well, but before arrival of the device60at the opening68to be plugged. In other examples, the retainer material82may degrade at or after arrival of the device60at the opening68to be plugged. If the device60also comprises a degradable material, then preferably the retainer material82degrades prior to the device material.

The material82could, in some examples, melt at elevated wellbore temperatures. The material82could be chosen to have a melting point that is between a temperature at the earth's surface and a temperature at the opening68, so that the material melts during transport from the surface to the downhole location of the opening.

The material82could, in some examples, dissolve when exposed to wellbore fluid. The material82could be chosen so that the material begins dissolving as soon as it is deployed into the wellbore14and contacts a certain fluid (such as, water, brine, hydrocarbon fluid, etc.) therein. In other examples, the fluid that initiates dissolving of the material82could have a certain pH range that causes the material to dissolve.

Note that it is not necessary for the material82to melt or dissolve in the well. Various other stimuli (such as, passage of time, elevated pressure, flow, turbulence, etc.) could cause the material82to disperse, degrade or otherwise cease to retain the device60. The material82could degrade in response to any one, or a combination, of: 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 to radiation in the well and exposure to a predetermined chemical composition in the well. Thus, the scope of this disclosure is not limited to any particular stimulus or technique for dispersing or degrading the material82, or to any particular type of material.

In some examples, the material82can remain on the device60, at least partially, when the device engages the opening68. For example, the material82could continue to cover the body64(at least partially) when the body engages and seals off the opening68. In such examples, the material82could advantageously comprise a relatively soft, viscous and/or resilient material, so that sealing between the device60and the opening68is enhanced.

Suitable relatively low melting point substances that may be used for the material82can include wax (e.g., paraffin wax, vegetable wax), ethylene-vinyl acetate copolymer (e.g., ELVAX™ available from DuPont), atactic polypropylene, and eutectic alloys. Suitable relatively soft substances that may be used for the material82can 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 (e.g., polyvinyl alcohol, polyethylene oxide) can be increased by incorporating a water-soluble plasticizer (e.g., glycerin), or a rapidly-dissolving salt (e.g., sodium chloride, potassium chloride), or both a plasticizer and a salt.

InFIG. 7, the retainer80is in a cylindrical form. The device60is encapsulated in, or molded in, the retainer material82. The fibers62and lines66are, thus, prevented from becoming entwined with the fibers and lines of any other devices60.

InFIG. 8, the retainer80is in a spherical form. In addition, the device60is compacted, and its compacted shape is retained by the retainer material82. A shape of the retainer80can be chosen as appropriate for a particular device60shape, in compacted or un-compacted form.

InFIG. 9, the retainer80is in a cubic form. Thus, any type of shape (polyhedron, spherical, cylindrical, etc.) may be used for the retainer80, in keeping with the principles of this disclosure.

Referring additionally now toFIG. 10, an example of a deployment apparatus90and an associated method are representatively illustrated. The apparatus90and method may be used with a system and method described herein, or they may be used with other systems and methods.

When used with an example of the system10and method representatively illustrated inFIGS. 19-21, the apparatus90can be connected between a pump and the wellbore12. However configured, an output of the apparatus90is connected to the well, although the apparatus itself may be positioned a distance away from the well.

The apparatus90is used in this example to deploy the devices60into the well. The devices60may or may not be retained by the retainer80when they are deployed. However, in theFIG. 10example, the devices60are depicted with the retainers80in the spherical shape ofFIG. 8, for convenience of deployment. The retainer material82can be at least partially dispersed during the deployment, so that the devices60are more readily conveyed by the flow74.

In certain situations, it can be advantageous to provide a certain spacing between the devices60during deployment, for example, in order to efficiently plug casing perforations. One reason for this is that the devices60will tend to first plug perforations that are receiving highest rates of flow.

In addition, if the devices60are deployed downhole too close together, some of them can become trapped between perforations, thereby wasting some of the devices. The excess “wasted” devices60might later interfere with other well operations.

To mitigate such problems, the devices60can be deployed with a selected spacing. The spacing may be, for example, on the order of the length of the perforation interval. The apparatus90is desirably capable of deploying the devices60with any selected spacing between the devices.

Each device60in this example has the retainer80in the form of a dissolvable coating material with a frangible coating88thereon, to impart a desired geometric shape (spherical in this example), and to allow for convenient deployment. The dissolvable retainer material82could be detrimental to the operation of the device60if it increases a drag coefficient of the device. A high coefficient of drag can cause the devices60to be swept to a lower end of the perforation interval, instead of sealing uppermost perforations.

The frangible coating88is used to prevent the dissolvable coating from dissolving during a queue time prior to deployment. Using the apparatus90, the frangible coating88can be desirably broken, opened or otherwise damaged during the deployment process, so that the dissolvable coating is then exposed to fluids that can cause the coating to dissolve.

Examples of suitable frangible coatings include cementitious materials (e.g., plaster of Paris) and various waxes (e.g., paraffin wax, carnauba wax, vegetable wax, machinable wax). The frangible nature of a wax coating can be optimized for particular conditions by blending a less brittle wax (e.g., paraffin wax) with a more brittle wax (e.g., carnauba wax) in a certain ratio selected for the particular conditions.

As depicted inFIG. 10, the apparatus90includes a rotary actuator92(such as, a hydraulic or electric servo motor, with or without a rotary encoder). The actuator92rotates a sequential release structure94that receives each device60in turn from a queue of the devices, and then releases each device one at a time into a conduit86that is connected to the tubular string72(or the casing16).

Note that it is not necessary for the actuator92to be a rotary actuator, since other types of actuators (such as, a linear actuator) may be used in other examples. In addition, it is not necessary for only a single device60to be deployed at a time. In other examples, the release structure94could be configured to release multiple devices at a time. Thus, the scope of this disclosure is not limited to any particular details of the apparatus90or the associated method as described herein or depicted in the drawings.

In theFIG. 10example, a rate of deployment of the devices60is determined by an actuation speed of the actuator92. As a speed of rotation of the structure94increases, a rate of release of the devices60from the structure accordingly increases. Thus, the deployment rate can be conveniently adjusted by adjusting an operational speed of the actuator92. This adjustment could be automatic, in response to well conditions, stimulation treatment parameters, flow rate variations, etc.

As depicted inFIG. 10, a liquid flow96enters the apparatus90from the left and exits on the right (for example, at about 1 barrel per minute). Note that the flow96is allowed to pass through the apparatus90at any position of the release structure94(the release structure is configured to permit flow through the structure at any of its positions).

When the release structure94rotates, one or more of the devices60received in the structure rotates with the structure. When a device60is on a downstream side of the release structure94, the flow96though the apparatus90carries the device to the right (as depicted inFIG. 10) and into a restriction98.

The restriction98in this example is smaller than the diameter of the device60. The flow96causes the device60to be forced through the restriction98, and the frangible coating88is thereby damaged, opened or fractured to allow the inner dissolvable material82of the retainer80to dissolve.

Other ways of opening, breaking or damaging a frangible coating may be used in keeping with the principles of this disclosure. For example, cutters or abrasive structures could contact an outside surface of a device60to penetrate, break, abrade or otherwise damage the frangible coating88. Thus, this disclosure is not limited to any particular technique for damaging, breaking, penetrating or otherwise compromising a frangible coating.

Referring additionally now toFIG. 11, another example of a deployment apparatus100and an associated method are representatively illustrated. The apparatus100and method may be used with a system and method described herein, or they may be used with other systems and methods.

In theFIG. 11example, the devices60are deployed using two flow rates. Flow rate A through two valves (valves A & B) is combined with Flow rate B through a pipe102depicted as being vertical inFIG. 11(the pipe may be horizontal or have any other orientation in actual practice).

The pipe102may be associated with a pump at the surface. In some examples, a separate pump (not shown) may be used to supply the flow96through the valves A & B.

Valve A is not absolutely necessary, but may be used to control a queue of the devices60. When valve B is open the flow96causes the devices60to enter the vertical pipe102. Flow104through the vertical pipe102in this example is substantially greater than the flow96through the valves A & B (that is, flow rate B>>flow rate A), although in other examples the flows may be substantially equal or otherwise related.

A spacing (dist. B) between the devices60when they are deployed into the well can be calculated as follows: dist. B=dist. A*(IDA2/IDB2)*(flow rate B/flow rate A), where dist. A is a spacing between the devices60prior to entering the pipe102, IDAis an inner diameter of a pipe106connected to the pipe102, and IDBis an inner diameter of the pipe102. This assumes circular pipes102,106. Where corresponding passages are non-circular, the term IDA2/IDB2can be replaced by an appropriate ratio of passage areas.

The spacing between the plugging devices60in the well (dist. B) can be automatically controlled by varying one or both of the flow rates A, B. For example, the spacing can be increased by increasing the flow rate B or decreasing the flow rate A. The flow rate(s) A, B can be automatically adjusted in response to changes in well conditions, stimulation treatment parameters, flow rate variations, etc.

In some examples, flow rate A can have a practical minimum of about ½ barrel per minute. In some circumstances, the desired deployment spacing (dist. B) may be greater than what can be produced using a convenient spacing dist. A of the devices60and the flow rate A in the pipe106.

The deployment spacing B may be increased by adding spacers108between the devices60in the pipe106. The spacers108effectively increase the distance A between the devices60in the pipe106(and, thus, increase the value of dist. A in the equation above).

The spacers108may be dissolvable or otherwise dispersible, so that they dissolve or degrade when they are in the pipe102or thereafter. In some examples, the spacers108may be geometrically the same as, or similar to, the devices60.

Note that the apparatus100may be used in combination with the restriction98ofFIG. 10(for example, with the restriction98connected downstream of the valve B but upstream of the pipe102). In this manner, a frangible or other protective coating on the devices60and/or spacers108can be opened, broken or otherwise damaged prior to the devices and spacers entering the pipe102.

Referring additionally now toFIG. 12, a cross-sectional view of another example of the device60is representatively illustrated. The device60may be used in any of the systems and methods described herein, or may be used in other systems and methods.

In this example, the body of the device60is made up of filaments or fibers62formed in the shape of a ball or sphere. Of course, other shapes may be used, if desired.

The filaments or fibers62may make up all, or substantially all, of the device60. The fibers62may be randomly oriented, or they may be arranged in various orientations as desired.

In theFIG. 12example, the fibers62are retained by the dissolvable, degradable or dispersible material82. In addition, a frangible coating may be provided on the device60, for example, in order to delay dissolving of the material82until the device has been deployed into a well (as in the example ofFIG. 10).

The device60ofFIG. 12can be used in a diversion fracturing operation (in which perforations receiving the most fluid are plugged to divert fluid flow to other perforations), in a re-completion operation, or in a multiple zone perforate and treat operation.

One advantage of theFIG. 12device60is that it is capable of sealing on irregularly shaped openings, perforations, leak paths or other passageways. The device60can also tend to “stick” or adhere to an opening, for example, due to engagement between the fibers62and structure surrounding (and in) the opening. In addition, there is an ability to selectively seal openings.

The fibers62could, in some examples, comprise wool fibers. The device60may be reinforced (e.g., using the material82or another material) or may be made entirely of fibrous material with a substantial portion of the fibers62randomly oriented.

The fibers62could, in some examples, comprise metal wool, or crumpled and/or compressed wire. Wool may be retained with wax or other material (such as the material82) to form a ball, sphere, cylinder or other shape.

In theFIG. 12example, the material82can comprise a wax (or eutectic metal or other material) that melts at a selected predetermined temperature. A wax device60may be reinforced with fibers62, so that the fibers and the wax (material82) act together to block a perforation or other passageway.

The selected melting point can be slightly below a static wellbore temperature. The wellbore temperature during fracturing or other stimulation treatment is typically depressed due to relatively low temperature fluids entering wellbore. After treatment, wellbore temperature will typically increase, thereby melting the wax and releasing the reinforcement fibers62.

A drag coefficient of the device60in any of the examples described herein may be modified appropriately to produce a desired result. For example, in a diversion fracturing operation, it is typically desirable to block perforations in a certain location in a wellbore. The location is usually at the perforations taking the most fluid.

Natural fractures in an earth formation penetrated by the wellbore make it so that certain perforations receive a larger portion of treatment fluids. For these situations and others, the device60shape, size, density and other characteristics can be selected, so that the device tends to be conveyed by flow to a certain corresponding section of the wellbore.

For example, devices60with a larger coefficient of drag (Cd) may tend to seat more toward a toe of a generally horizontal or lateral wellbore. Devices60with a smaller Cd may tend to seat more toward a heel of the wellbore.

Smaller devices60with long fibers62floating freely (see the example ofFIG. 13) may have a strong tendency to seat at or near the heel. A diameter of the device60and the free fiber62length can be appropriately selected, so that the device is more suited to stopping and sealingly engaging perforations anywhere along the length of the wellbore.

Acid treating operations can benefit from use of the device60examples described herein. Pumping friction causes hydraulic pressure at the heel to be considerably higher than at the toe. This means that the fluid volume pumped into a formation at the heel will be considerably higher than at the toe. Turbulent fluid flow increases this effect. Gelling additives might reduce an onset of turbulence and decrease the magnitude of the pressure drop along the length of the wellbore.

Higher initial pressure at the heel allows zones to be treated and then plugged starting at the heel, and then progressively down along the wellbore. This mitigates waste of acid from attempting to acidize all of the zones at the same time.

The free fibers62of theFIGS. 4-6B & 13examples greatly increase the ability of the device60to engage the first open perforation (or other leak path) it encounters. Thus, the devices60with low Cd and long fibers62can be used to plug from upper perforations to lower perforations, while turbulent acid with high frictional pressure drop is used so that the acid treats the unplugged perforations nearest the top of the wellbore with acid first.

In examples of the device60where a wax material (such as the material82) is used, the fibers62(including the body64, lines66, knots, etc.) may be treated with a treatment fluid that repels wax (e.g., during a molding process). This may be useful for releasing the wax from the fibrous material after fracturing or otherwise compromising the retainer80and/or a frangible coating thereon.

Suitable release agents are water-wetting surfactants (e.g., alkyl ether sulfates, high hydrophilic-lipophilic balance (HLB) nonionic surfactants, betaines, alkyarylsulfonates, alkyldiphenyl ether sulfonates, alkyl sulfates). The release fluid may also comprise a binder to maintain the knot or body64in a shape suitable for molding. One example of a binder is a polyvinyl acetate emulsion.

Broken-up or fractured devices60can have lower Cd. Broken-up or fractured devices60can have smaller cross-sections and can pass through restrictions in the well more readily.

The restriction98(seeFIG. 10) may be connected in any line or pipe that the devices60are pumped through, in order to cause the devices to fracture as they pass through the restriction. This may be used to break up and separate devices60into wax and non-wax parts. The restriction98may also be used for rupturing a frangible coating covering a soluble wax material82to allow water or other well fluids to dissolve the wax.

Fibers62may extend outwardly from the device60, whether or not the body64or other main structure of the device also comprises fibers. For example, a ball (or other shape) made of any material could have fibers62attached to and extending outwardly therefrom. Such a device60will be better able to find and cling to openings, holes, perforations or other leak paths near the heel of the wellbore, as compared to the ball (or other shape) without the fibers62.

For any of the device60examples described herein, the fibers62may not dissolve, disperse or otherwise degrade in the well. In such situations, the devices60(or at least the fibers62) may be removed from the well by swabbing, scraping, circulating, milling or other mechanical methods.

In situations where it is desired for the fibers62to 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 the device60. At relatively low well temperatures, nylon 6 may be preferred over nylon 66, because nylon 6 dissolves faster or more readily.

Self-degrading fiber devices60can be prepared from poly-lactic acid (PLA), poly-glycolic acid (PGA), or a combination of PLA and PGA fibers62. Such fibers62may be used in any of the device60examples described herein.

Fibers62can be continuous monofilament or multifilament, or chopped fiber. Chopped fibers62can be carded and twisted into yarn that can be used to prepare fibrous flow conveyed devices60.

PLA and/or PGA fibers62may be coated with a protective material, such as calcium stearate, to slow its reaction with water and thereby delay degradation of the device60. Different combinations of PLA and PGA materials may be used to achieve corresponding different degradation times or other characteristics.

PLA resin can be spun into fiber of 1-15 denier, for example. Smaller diameter fibers62will degrade faster. Fiber denier of less than 5 may be most desirable. PLA resin is commercially available with a range of melting points (e.g., 140 to 365° F.). Fibers62spun from lower melting point PLA resin can degrade faster.

PLA bi-component fiber has a core of high-melting point PLA resin and a sheath of low-melting point PLA resin (e.g., 140° F. melting point sheath on a 265° F. melting point core). The low-melting point resin can hydrolyze more rapidly and generate acid that will accelerate degradation of the high-melting point core. This may enable the preparation of a plugging device60that will have higher strength in a wellbore environment, yet still degrade in a reasonable time. In various examples, a melting point of the resin can decrease in a radially outward direction in the fiber.

Referring additionally now toFIGS. 14-18, a variety of examples of the dispensing tool26are representatively illustrated. These dispensing tool26examples may be used with the system10and method ofFIGS. 1-3, or they may be used with other systems and methods.

In theFIG. 14example, the dispensing tool26includes the container36with an auger40therein. The auger40can be rotated by a motor42of the actuator38.

When the auger40is rotated, plugging devices60are dispensed from the container36. A rate of dispensing the plugging devices60can be controlled by varying a rotational speed of the auger40, and a total number of plugging devices dispensed can be controlled by varying a duration of the auger rotation.

In theFIG. 15example, the dispensing tool26includes a detonator44or other explosive device attached to or proximate a frangible closure46of the container36.

The actuator38controls detonation of the detonator44. When the detonator44is detonated, the closure46breaks and allows the plugging devices60to displace out of the container36.

In theFIG. 16example, the actuator38includes a hydraulic pump48. The pump48is operated to increase pressure in the container36. When the pressure in the container36has increased to a predetermined level, the frangible closure46breaks and the plugging devices60are expelled from the container.

In theFIG. 17example, the actuator38displaces an elongated member50(such as a rod) when it is desired to release the plugging devices60from the container36. The member50impacts the frangible closure46, so that it breaks and releases the plugging devices60.

The actuator38could comprise any device capable of displacing the member50. For example, a linear actuator, a propellant and piston, a jack screw or any other type of displacement device may be used in the actuator38.

In theFIG. 18example, the actuator38controls operation of two valves52,54. The valves52,54provide for fluid flow through the container36, so that the plugging devices60can be displaced out of the container with the flow. The valves52,54can be located in any side or either end of the container36.

Although only release of the plugging devices60from the container36is described herein and depicted in the drawings, other plugging substances, devices or materials may also be released downhole from the container36(or another container) into the wellbore12in other examples. A material (such as, calcium carbonate, PLA or PGA particles) may be released from the container36and conveyed by the flow22into any gaps between the devices60and the perforations or other openings to be plugged, so that a combination of the devices and the materials completely blocks flow through the openings.

Referring additionally now toFIGS. 19-21, another example of the system10and method is representatively illustrated. In this example, the perforating assembly24does not include the dispensing tool26. Instead, the plugging devices60are dispensed into the wellbore12(for example, using the deployment apparatus90ofFIG. 10or the deployment apparatus100ofFIG. 11), and then displaced therein with the perforating assembly24.

InFIG. 19, the system10and method are depicted after the plugging devices60are dispensed into the wellbore12and the perforating assembly24is conveyed into the wellbore on the conveyance34. The perforating assembly24and the plugging devices60are displaced through the wellbore12by the fluid flow22.

The conveyance34can be used to stop the perforating assembly24at a desired location for forming additional perforations. Alternatively, the perforating assembly24can be displaced by the fluid flow22past the desired location, and then can be raised by the conveyance to the desired location to form the additional perforations.

InFIG. 20, the system10and method are depicted after the plugging devices60have sealingly engaged the perforations20a. Although all of the perforations20aare plugged as depicted inFIG. 20, one or more of the perforations may remain unplugged, for example, to allow continued fluid flow22through the wellbore12, if desired.

InFIG. 21, the system10and method are depicted after the conveyance34has been used to raise the perforating assembly24to a desired location for forming additional perforations20b. One of the perforators28has been used to form the perforations20bthrough the casing16and cement18, so that fluid communication is now permitted between a formation zone14band the interior of the casing.

The perforating assembly24may be displaced to other locations along the wellbore12for forming additional perforations, if desired. The perforating assembly24can then be retrieved from the wellbore12, and the zone14b(and any other perforated zone(s)) can be treated (for example, by fracturing, acidizing, injection of conformance agents, etc.).

The steps described above and depicted inFIGS. 19-21can be repeated multiple times, until all desired zones have been perforated and treated. At that point, the plugging devices60can be degraded or otherwise removed from the perforations or other openings, so that fluid communication is permitted between the various zones and the interior of the casing16.

Referring additionally now toFIGS. 22-24, various examples of techniques for degrading or removing the plugging devices60from perforations20or other openings in a well are representatively illustrated. These techniques are depicted as being performed with the system10and method, but the techniques may be performed with other systems and methods, in keeping with the principles of this disclosure.

When used with the system10and method, the plugging devices60are degraded or removed after all zones14a,bhave been perforated and treated. Only one set of perforations20are depicted inFIGS. 22-24, but it should be understood that the depicted techniques can be used to degrade or remove the plugging devices60at any number of perforations or zones.

In theFIG. 22example, a cutting device56(such as, a drill, mill, reamer, etc.) is used to cut into the plugging devices60. The cutting device56may cut the plugging devices60from the perforations20, or the cutting device may dislodge the plugging devices from the perforations.

A fluid motor58(such as, a turbine or a Moineau-type positive displacement fluid motor) may be used to rotate the cutting device56in response to fluid flow through a tubular string76extending to surface. Alternatively, or in addition, the tubular string76may be rotated from the surface. Note that it is not necessary for the cutting device56to be rotated, in keeping with the principles of this disclosure.

In theFIG. 23example, a gauge ring78is used to dislodge the plugging devices60from the perforations20. The gauge ring78is conveyed by the tubular string76in the depicted example, but a wireline or other conveyance may be used in other examples. A “junk basket”84may be included with the gauge ring78to retain the plugging devices60after they have been dislodged, for convenient retrieval to the surface.

In theFIG. 24example, a degrading fluid110is flowed into contact with the plugging devices60. The degrading fluid110could be an acid, or a fluid with a selected pH or other characteristic that causes or initiates degradation of the plugging devices60. The degrading fluid110may be introduced into the casing16, or a tubular string may be used to spot the degrading fluid110at the location(s) of the plugging devices60.

It may now be fully appreciated that the above disclosure provides significant advancements to the art of controlling flow in subterranean wells. In some examples described above, the plugging device60may be used to block flow through openings in a well, with the device being uniquely configured so that its conveyance with the flow is enhanced and/or its sealing engagement with an opening is enhanced. In some examples, the plugging device60may be dispensed from a dispensing tool26included in a perforating assembly24, or the plugging device may be displaced by fluid flow22through the wellbore12with the perforating assembly.

A well completion method, system and apparatus are described above, in which plugging devices60are released from a container36in a wellbore12. The plugging devices60may be released to plug existing perforations20a. The plugging devices60may be released prior to forming additional perforations20band fracturing through the additional perforations.

A well completion method, system and apparatus are described above, in which plugging devices60are released into a wellbore12ahead of a perforating assembly24. The plugging devices60and the perforating assembly24may be pumped simultaneously through the wellbore12.

The plugging devices60may plug perforations20aexisting before the perforating assembly24is introduced into the wellbore12. The plugging devices60may plug perforations20bmade by the perforating assembly24.

The plugging devices60may comprise a knot. The plugging devices60may comprise a fibrous material retained by a degradable retainer80.

The above disclosure provides to the art a system10for use with a subterranean well. In one example, the system10can comprise a perforating assembly24including at least one perforator28. The perforating assembly24is conveyed through a wellbore24with fluid flow22through the wellbore. Plugging devices60are spaced apart from the perforating assembly24in the wellbore12. The plugging devices60are conveyed through the wellbore12with the fluid flow22. The plugging devices60may be conveyed with the fluid flow22after being released from a container36.

The plugging devices60may or may not be released from a container36of the perforating assembly24. The perforating assembly24may include an actuator38configured to release the plugging devices60from the container36.

Each of the plugging devices60may comprise a body64and, extending outwardly from the body, at least one of lines66and fibers62. The lines66and/or fibers62may have a lateral dimension substantially less than a size of the body64. The body64of each of the plugging devices60may comprise a knot.

Each of the plugging devices60may comprise a degradable material. The degradable material may be selected from poly-vinyl alcohol, poly-vinyl acetate, poly-methacrylic acid, poly-lactic acid and poly-glycolic acid.

The plugging devices60may be deployed into the wellbore12separate from the perforating assembly24. The plugging devices60may be conveyed by the fluid flow22into sealing engagement with perforations20,20a,b.

A method of deploying plugging devices60in a wellbore12is also provided to the art by the above disclosure. In one example, the method can comprise: conveying a perforating assembly24including a dispensing tool26through the wellbore12, the dispensing tool26including a container36; and then releasing the plugging devices60from the container36into the wellbore12at a downhole location.

The releasing step can comprise operating an actuator38of the dispensing tool26.

The method can include connecting a perforator28of the perforating assembly24between a conveyance34and the dispensing tool26.

The method can include dislodging the plugging devices60from openings68(such as perforations20,20a,b), after the plugging devices60have sealingly engaged the openings.

The method can include cutting the plugging devices60, after the plugging devices60have sealingly engaged openings68(such as perforations20,20a,b).

Another method of deploying plugging devices60in a wellbore12is provided by the above disclosure. In one example, the method can comprise: conveying the plugging devices60through the wellbore12with fluid flow22through the wellbore; and conveying a perforating assembly24through the wellbore12while the plugging devices60are being conveyed through the wellbore.

The step of conveying the perforating assembly24can include conveying the perforating assembly with the fluid flow22through the wellbore12.

The method can include forming perforations20bwith the perforating assembly24, after the plugging devices60sealingly engage openings68(such as perforations20,20a,b) downhole.

The method can include dislodging the plugging devices60from openings68(such as perforations20,20a,b), after the plugging devices60have sealingly engaged the openings.

The method can include cutting the plugging devices60, after the plugging devices60have sealingly engaged openings68(such as perforations20,20a,b).

In the above description of the representative examples, directional terms (such as “above,” “below,” “upper,” “lower,” etc.) are used for convenience in referring to the accompanying drawings. However, it should be clearly understood that the scope of this disclosure is not limited to any particular directions described herein.