Patent Publication Number: US-2022235622-A1

Title: Methods of completing a well and apparatus therefor

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This application claims the benefit of the filing date of U.S. provisional application No. 62/433,459 filed on 13 Dec. 2016. The entire disclosure of this prior application is incorporated herein by this reference. 
    
    
     BACKGROUND 
     This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in examples described below, more particularly provides methods and apparatus for completing a well. 
     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. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a representative partially cross-sectional view of an example of a well system and associated method which can embody principles of this disclosure, wherein a perforating assembly is being displaced into a well. 
         FIG. 2  is a representative partially cross-sectional view of the system and method of  FIG. 1 , wherein flow conveyed plugging devices are being released from a container of the perforating assembly. 
         FIG. 3  is a representative partially cross-sectional view of the system and method, wherein a formation zone is perforated. 
         FIGS. 4A  &amp; B are enlarged scale representative elevational views of examples of a flow conveyed plugging device that may be used in the system and method of  FIGS. 1-3 , and which can embody the principles of this disclosure. 
         FIG. 5  is a representative elevational view of another example of the flow conveyed plugging device. 
         FIGS. 6A  &amp; B are representative partially cross-sectional views of the flow conveyed plugging device in a well, the device being conveyed by flow in  FIG. 6A , and engaging a casing opening in  FIG. 6B . 
         FIGS. 7-9  are representative elevational views of examples of the flow conveyed plugging device with a retainer. 
         FIGS. 10 &amp; 11  are representative cross-sectional views of additional examples of the flow conveyed plugging device. 
         FIGS. 12A  &amp; B are representative cross-sectional views of an example of the dispensing tool in respective run-in and actuated configurations. 
         FIG. 13  is a representative perspective view of an example of an enclosure of the dispensing tool. 
         FIG. 14  is a representative cross-sectional view of an attachment between the enclosure and a valve closure member of the dispensing tool. 
     
    
    
     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 can be 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 US publication nos. 2016/0319628, 2016/0319630 and 2016/0319631, and in International application nos. PCT/US15/38248 (filed 29 Jun. 2015) and PCT/US16/29357 (filed 26 Apr. 2016). 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 US patent application publication no. 2016/0348467 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 dispensing tool  26 ).   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. In another example, the plugging devices are initially contained in a sack or bag, which is mechanically opened downhole in response to applied pressure. 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.   6. 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 in  FIG. 1  is a system  10  for use with a well, and an associated method, which can embody principles of this disclosure. However, it should be clearly understood that the system  10  and 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 system  10  and method described herein and/or depicted in the drawings. 
     In the  FIG. 1  example, a wellbore  12  has been drilled so that it penetrates an earth formation  14 . The wellbore  12  is lined with casing  16  and cement  18 , although in other examples one or more sections of the wellbore may be uncased or open hole. 
     The wellbore  12  as depicted in  FIG. 1  is generally horizontal, and a “toe” or distal end of the wellbore is to the right of the figure. However, in other examples, the wellbore  12  could 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&#39;s surface along the wellbore  12 , whether the wellbore is generally horizontal, vertical or inclined. Thus, in the  FIG. 1  example, the upward direction is toward the left of the figure. 
     As depicted in  FIG. 1 , a set of perforations  20   a  have been formed through the casing  16 , cement  18  and into a zone  14   a  of the formation  14 . The perforations  20   a  provide for fluid communication between the zone  20   a  and an interior of the casing  16 . 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 casing  16 . 
     The perforations  20   a  (or other openings) may be provided or formed in order to establish such fluid communication, so that a flow path extends longitudinally through the wellbore  12  and into the zone  14   a . In some examples, the perforations  20   a  may be formed primarily to enable production flow from the zone  14   a  to the earth&#39;s surface via the wellbore  12 . 
     The perforations  20   a  may 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 casing  16  prior to the casing being installed in the wellbore  12  (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 perforations  20   a.    
     In some examples, openings other than perforations may be available in the well for enabling fluid flow through the wellbore  12 . 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 wellbore  12 . Thus, the scope of this disclosure is not limited to any particular means of providing for fluid flow through the wellbore  12 . 
     Note that it is not necessary in keeping with the principles of this disclosure for the perforations  20   a  or other openings to be formed at or near a distal end of the wellbore  12 , or for any other procedures or steps described herein to be performed at or near a distal end of a wellbore. 
     In the  FIG. 1  example, a fluid flow  22  is established longitudinally through the wellbore  12 , outward through the perforations  20   a  and into the zone  14   a . This fluid flow  22  is used to displace or “pump” a perforating assembly  24  through the wellbore  12 . Note that the zone  14   a  may have been treated (for example, by acidizing, fracturing, injection of conformance agents, etc.) prior to establishing the fluid flow  22 , or the fluid flow could be part of treating the zone  14   a.    
     As depicted in  FIG. 1 , the perforating assembly  24  includes a plugging device dispensing tool  26 , two perforators  28 , a firing head  30 , and a connector  32 . The connector  32  is used to connect the perforating assembly  24  to a conveyance  34 , such as, a wireline, a slickline, coiled tubing or jointed tubing. 
     The dispensing tool  26  in this example includes a container  36  and an actuator  38 . The container  36  contains the plugging devices (not visible in  FIG. 1 , see  FIG. 2 ), and the actuator  38  acts to release the plugging devices from the container in the wellbore  12 . Any of the methods and dispensing apparatuses described in the US patent application publication no. 2016/0348467 mentioned above may be used for the container  36  and actuator  38 . 
     The perforators  28  are depicted in  FIG. 1  as being explosive shaped charge perforating guns. Shaped charges in the perforating guns are detonated by means of the firing head  30 , which may be operated in response to a predetermined pressure, pressure pulse, acoustic, electric, hydraulic, optical or other type of signal. 
     Alternatively, the perforators  28  could comprise one or more abrasive jet perforators (for example, if the conveyance  34  is a coiled or jointed tubing). The scope of this disclosure is not limited to use of any particular type of perforator. 
     The fluid flow  22  displaces the perforating assembly  24  through the wellbore  12  to a desired location. In this example, the desired location is a position above the perforations  20   a . In other examples, gravity or another source of a biasing force could be used to displace the perforating assembly  24  through the wellbore  12  (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 to  FIG. 2 , the system  10  and method are representatively illustrated after the perforating assembly  24  has been displaced to the desired location above the open perforations  20   a , and the dispensing tool  26  has been operated to release the plugging devices  60  into the wellbore  12  above the perforations. The fluid flow  22  displaces the plugging devices  60  through the wellbore  12  toward the open perforations  20   a.    
     Any number of the plugging devices  60  may be released from the tool  26 . In various examples, the number of plugging devices  60  released could be equal to, less than, or greater than, the number of open perforations  20   a.    
     An equal number of open perforations  20   a  and plugging devices  60  may be used if it is desired to plug all of the perforations and not have excess plugging devices remaining in the wellbore  12 . A greater number of plugging devices  60  may be used if it is desired to ensure that there are more than an adequate number of plugging devices to plug all of the perforations  20   a . A fewer number of plugging devices  60  may be used if it is desired to maintain a capability for flowing fluid downward through the wellbore  12  after most of the perforations  20   a  have been plugged. 
     Referring additionally now to  FIG. 3 , the system  10  and method are representatively illustrated after the plugging devices  60  have sealingly engaged and prevent fluid flow into the perforations  20   a . The perforating assembly  24  has been raised in the wellbore  12  to another location where it is desired to perforate another zone  14   b  of the formation  14 , and perforations  20   b  have been formed through the casing  16  and cement  18  by the perforating assembly. 
     Fluid communication is now permitted between the zone  14   b  and the interior of the casing  16 . Additional perforations may be formed at other locations along the wellbore  12  using the perforating assembly  24 , if desired. The perforating assembly  24  can then be retrieved from the wellbore  12 , and the zone  14   b  (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 in  FIGS. 1-3  can be repeated multiple times, until all desired zones have been perforated and treated. At that point, the plugging devices  60  can 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 casing  16 . 
     Referring additionally now to  FIG. 4A , an example of a flow conveyed plugging device  60  that can incorporate the principles of this disclosure is representatively illustrated. The device  60  may be used for any of the plugging devices in the method examples described herein, or the device may be used in other methods. 
     The device  60  example of  FIG. 4A  includes multiple fibers  62  extending outwardly from an enlarged body  64 . As depicted in  FIG. 4A , each of the fibers  62  has a lateral dimension (e.g., a thickness or diameter) that is substantially smaller than a size (e.g., a thickness or diameter) of the body  64 . 
     The body  64  can 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 device  60  to seal off a perforation in a well, the body  64  can be formed so that it is somewhat larger than a diameter of the perforation. If it is desired for multiple devices  60  to seal off multiple openings having a variety of dimensions (such as holes caused by corrosion of the casing  16 ), then the bodies  64  of the devices can be formed with a corresponding variety of sizes. 
     In the  FIG. 4A  example, the fibers  62  are joined together (e.g., by braiding, weaving, cabling, etc.) to form lines  66  that extend outwardly from the body  64 . In this example, there are two such lines  66 , but any number of lines (including one) may be used in other examples. 
     The lines  66  may be in the form of one or more ropes, in which case the fibers  62  could comprise frayed ends of the rope(s). In addition, the body  64  could be formed by one or more knots in the rope(s). In some examples, the body  64  can comprise a fabric or cloth, the body could be formed by one or more knots in the fabric or cloth, and the fibers  62  could extend from the fabric or cloth. 
     In other examples, the device  60  could comprise a single sheet of material, or multiple strips of sheet material. The device  60  could comprise one or more films. The body  64  and lines  66  may not be made of the same material, and the body and/or lines may not be made of a fibrous material. 
     In the  FIG. 4A  example, the body  64  is formed by a double overhand knot in a rope, and ends of the rope are frayed, so that the fibers  62  are splayed outward. In this manner, the fibers  62  will cause significant fluid drag when the device  60  is 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 body  64  could have other shapes, the body could be hollow or solid, and the body could be made up of one or multiple materials. The fibers  62  are not necessarily joined by lines  66 , and the fibers are not necessarily formed by fraying ends of ropes or other lines. The body  64  is not necessarily centrally located in the device  60  (for example, the body could be at one end of the lines  66 ). Thus, the scope of this disclosure is not limited to the construction, configuration or other details of the device  60  as described herein or depicted in the drawings. 
     Referring additionally now to  FIG. 4B , another example of the device  60  is representatively illustrated. In this example, the device  60  is formed using multiple braided lines  66  of the type known as “mason twine.” The multiple lines  66  are knotted (such as, with a double or triple overhand knot or other type of knot) to form the body  64 . Ends of the lines  66  are not necessarily frayed in these examples, although the lines do comprise fibers (such as the fibers  62  described above). 
     Referring additionally now to  FIG. 5 , another example of the device  60  is representatively illustrated. In this example, four sets of the fibers  62  are joined by a corresponding number of lines  66  to the body  64 . The body  64  is formed by one or more knots in the lines  66 . 
       FIG. 5  demonstrates that a variety of different configurations are possible for the device  60 . 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 to  FIGS. 6A  &amp; B, an example of a use of the device  60  of  FIG. 4A  to seal off an opening  68  in a well is representatively illustrated. In this example, the opening  68  is a perforation formed through a sidewall  70  of a tubular string  72  (such as, a casing, liner, tubing, etc.). However, in other examples the opening  68  could be another type of opening, and may be formed in another type of structure. 
     The device  60  is deployed into the tubular string  72  and is conveyed through the tubular string by fluid flow  74 . The fibers  62  of the device  60  enhance fluid drag on the device, so that the device is influenced to displace with the flow  74 . 
     The fluid flow  74  may be the same as, or similar to, the fluid flow  22  described above for the example of  FIGS. 1-3 . However, the fluid flow  74  could be another type of fluid flow, in keeping with the principles of this disclosure. 
     Since the flow  74  (or a portion thereof) exits the tubular string  72  via the opening  68 , the device  60  will be influenced by the fluid drag to also exit the tubular string via the opening  68 . As depicted in  FIG. 6B , one set of the fibers  62  first enters the opening  68 , and the body  64  follows. However, the body  64  is appropriately dimensioned, so that it does not pass through the opening  68 , but instead is lodged or wedged into the opening. In some examples, the body  64  may be received only partially in the opening  68 , and in other examples the body may be entirely received in the opening. 
     The body  64  may completely or only partially block the flow  74  through the opening  68 . If the body  64  only partially blocks the flow  74 , any remaining fibers  62  exposed to the flow in the tubular string  72  can be carried by that flow into any gaps between the body and the opening  68 , so that a combination of the body and the fibers completely blocks flow through the opening. 
     In another example, the device  60  may partially block flow through the opening  68 , and another material (such as, calcium carbonate, poly-lactic acid (PLA) or poly-glycolic acid (PGA) particles) may be deployed and conveyed by the flow  74  into 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 device  60  may permanently prevent flow through the opening  68 , or the device may degrade to eventually permit flow through the opening. If the device  60  degrades, 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 device  60  (and any other material used in conjunction with the device to block flow through the opening  68 ) may be used in keeping with the scope of this disclosure. 
     In other examples, the device  60  may be mechanically removed from the opening  68 . For example, if the body  64  only partially enters the opening  68 , a mill or other cutting device may be used to cut the body from the opening. 
     Referring additionally now to  FIGS. 7-9 , additional examples of the device  60  are representatively illustrated. In these examples, the device  60  is surrounded by, encapsulated in, molded in, or otherwise retained by, a retainer  80 . 
     The retainer  80  aids in 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 becoming entangled with the fibers and/or lines of other devices. 
     The retainer  80  could in some examples completely enclose the device  60 . In other examples, the retainer  80  could be in the form of a binder that holds the fibers  62  and/or lines  66  together, so that they do not become entangled with those of other devices. 
     In some examples, the retainer  80  could have a cavity therein, with the device  60  (or only the fibers  62  and/or lines  66 ) being contained in the cavity. In other examples, the retainer  80  could be molded about the device  60  (or only the 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, so that the device is capable of sealing off an opening  68  in the well, as described above. For example, the retainer  80  can be made of a material  82  that degrades in a wellbore environment. 
     The retainer material  82  may degrade after deployment into the well, but before arrival of the device  60  at the opening  68  to be plugged. In other examples, the retainer material  82  may degrade at or after arrival of the device  60  at the opening  68  to be plugged. If the device  60  also comprises a degradable material, then preferably the retainer material  82  degrades prior to the device material. 
     The material  82  could, in some examples, melt at elevated wellbore temperatures. The material  82  could be chosen to have a melting point that is between a temperature at the earth&#39;s surface and a temperature at the opening  68 , so that the material melts during transport from the surface to the downhole location of the opening. 
     The material  82  could, in some examples, dissolve when exposed to wellbore fluid. The material  82  could be chosen so that the material begins dissolving as soon as it is deployed into the wellbore  14  and contacts a certain fluid (such as, water, brine, hydrocarbon fluid, etc.) therein. In other examples, the fluid that initiates dissolving of the material  82  could have a certain pH range that causes the material to dissolve. 
     Note that it is not necessary for the material  82  to melt or dissolve in the well. Various other stimuli (such as, passage of time, elevated pressure, flow, turbulence, etc.) could cause the material  82  to disperse, degrade or otherwise cease to retain the device  60 . The material  82  could 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 material  82 , or to any particular type of material. 
     In some examples, the material  82  can remain on the device  60 , at least partially, when the device engages the opening  68 . For example, the material  82  could continue to cover the body  64  (at least partially) when the body engages and seals off the opening  68 . In such examples, the material  82  could advantageously comprise a relatively soft, viscous and/or resilient material, so that sealing between the device  60  and the opening  68  is enhanced. 
     Suitable relatively low melting point substances that may be used for the material  82  can 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 material  82  can 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. 
     In  FIG. 7 , the retainer  80  is in a cylindrical form. The device  60  is encapsulated in, or molded in, the retainer material  82 . The fibers  62  and lines  66  are, thus, prevented from becoming entwined with the fibers and lines of any other devices  60 . 
     In  FIG. 8 , the retainer  80  is in a spherical form. In addition, the device  60  is compacted, and its compacted shape is retained by the retainer material  82 . A shape of the retainer  80  can be chosen as appropriate for a particular device  60  shape, in compacted or un-compacted form. 
     In  FIG. 9 , the retainer  80  is in a cubic form. Thus, any type of shape (polyhedron, spherical, cylindrical, etc.) may be used for the retainer  80 , in keeping with the principles of this disclosure. 
     Referring additionally now to  FIG. 10 , a cross-sectional view of another example of the device  60  is representatively illustrated. The device  60  may 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 device  60  is made up of filaments or fibers  62  formed in the shape of a ball or sphere. Of course, other shapes may be used, if desired. 
     The filaments or fibers  62  may make up all, or substantially all, of the device  60 . The fibers  62  may be randomly oriented, or they may be arranged in various orientations as desired. 
     In the  FIG. 10  example, the fibers  62  are retained by the dissolvable, degradable or dispersible material  82 . In addition, a frangible coating may be provided on the device  60 , for example, in order to delay dissolving of the material  82  until the device has been deployed into a well. 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. 
     The device  60  of  FIG. 10  can 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 the  FIG. 10  device  60  is that it is capable of sealing on irregularly shaped openings, perforations, leak paths or other passageways. The device  60  can also tend to “stick” or adhere to an opening, for example, due to engagement between the fibers  62  and structure surrounding (and in) the opening. In addition, there is an ability to selectively seal openings. 
     The fibers  62  could, in some examples, comprise wool fibers. The device  60  may be reinforced (e.g., using the material  82  or another material) or may be made entirely of fibrous material with a substantial portion of the fibers  62  randomly oriented. 
     The fibers  62  could, in some examples, comprise metal wool, or crumpled and/or compressed wire. Wool may be retained with wax or other material (such as the material  82 ) to form a ball, sphere, cylinder or other shape. 
     In the  FIG. 10  example, the material  82  can comprise a wax (or eutectic metal or other material) that melts at a selected predetermined temperature. A wax device  60  may be reinforced with fibers  62 , so that the fibers and the wax (material  82 ) 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 fibers  62 . 
     A drag coefficient of the device  60  in 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 device  60  shape, 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, devices  60  with a larger coefficient of drag (Cd) may tend to seat more toward a toe of a generally horizontal or lateral wellbore. Devices  60  with a smaller Cd may tend to seat more toward a heel of the wellbore. 
     Smaller devices  60  with long fibers  62  floating freely (see the example of  FIG. 11 ) may have a strong tendency to seat at or near the heel. A diameter of the device  60  and the free fiber  62  length 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 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 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 fibers  62  of the  FIGS. 4-6B &amp; 11  examples greatly increase the ability of the device  60  to engage the first open perforation (or other leak path) it encounters. Thus, the devices  60  with low Cd and long fibers  62  can 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 device  60  where a wax material (such as the material  82 ) is used, the fibers  62  (including the body  64 , lines  66 , 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 retainer  80  and/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 body  64  in a shape suitable for molding. One example of a binder is a polyvinyl acetate emulsion. 
     Broken-up or fractured devices  60  can have lower Cd. Broken-up or fractured devices  60  can have smaller cross-sections and can pass through restrictions in the well more readily. 
     A restriction may be connected in any line or pipe that the devices  60  are 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 devices  60  into wax and non-wax parts. The restriction may also be used for rupturing a frangible coating covering a soluble wax material  82  to allow water or other well fluids to dissolve the wax. 
     Fibers  62  may extend outwardly from the device  60 , whether or not the 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 therefrom. Such a device  60  will 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 fibers  62 . 
     For any of the device  60  examples described herein, the fibers  62  may not dissolve, disperse or otherwise degrade in the well. In such situations, the devices  60  (or at least the fibers  62 ) may be removed from the well by swabbing, scraping, circulating, milling or other mechanical methods. 
     In situations where it is desired for the fibers  62  to 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 device  60 . At relatively low well temperatures, nylon 6 may be preferred over nylon 66, because nylon 6 dissolves faster or more readily. 
     Self-degrading fiber devices  60  can be prepared from poly-lactic acid (PLA), poly-glycolic acid (PGA), or a combination of PLA and PGA fibers  62 . Such fibers  62  may be used in any of the device  60  examples described herein. 
     Fibers  62  can be continuous monofilament or multifilament, or chopped fiber. Chopped fibers  62  can be carded and twisted into yarn that can be used to prepare fibrous flow conveyed devices  60 . 
     PLA and/or PGA fibers  62  may be coated with a protective material, such as calcium stearate, to slow its reaction with water and thereby delay degradation of the device  60 . 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 fibers  62  will 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.). Fibers  62  spun 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 device  60  that 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 to  FIGS. 12A-14 , another example of the dispensing tool  26  is representatively illustrated. This dispensing tool  26  example may be used with the system  10  and method of  FIGS. 1-3 , or it may be used with other systems and methods. 
     The dispensing tool  26  of  FIGS. 12A-14  may be conveyed by a variety of different conveyances, such as, wireline, coiled tubing, etc. In the following description of the  FIGS. 12A-14  dispensing tool  26  example, the dispensing tool is used to place plugging devices  60  in a wellbore. The dispensing tool  26  can also be used to place other materials or chemicals. 
     In one operational example, the dispensing tool  26  may be run with and below wireline or coiled tubing-conveyed perforating guns or perforators  28  as a part of a perforating assembly  24  in a fracturing operation. After a stage is fractured, the perforators  28  and the dispensing tool  26  are run downhole just above the fractured zone. The plugging devices  60  are dumped prior to firing the perforators  28 . When fracturing begins again, the plugging devices  60  shut off the perforations  20   a  that have just been fractured to force the fracturing fluid into the newly formed perforations  20   b.    
     The dispensing tool  26  example is shown in an initial run-in configuration in  FIG. 12A . Plugging devices  60  are located in an enclosure  84  (such as, a flexible sack or bag) in a lower part of the tool  26 . 
     A viscous substance  86  may be placed in the enclosure  84  with the plugging devices  60  to help keep the plugging devices  60  from settling or entangling during storage, shipment, and displacement in the wellbore  12 . A lower end of the enclosure  84  is secured to the container  36 , for example, using a fastener  78 . 
     There is a radially enlarged boss  88  located below ports  90  of a sliding sleeve valve  92 . The boss  88  is used to restrict flow through an annulus formed radially between the casing  16  and the tool  26 , to allow the tool to be pumped down with the wireline, coiled tubing or other conveyance  34 . The boss  88  restricts flow through the casing  16 , and also helps direct fluid flow  74  into the sliding sleeve valve ports  90  and through the tool  26  when the tool is operated to dispense the plugging devices  60 . 
     The dispensing tool  26  can be operated with the actuator  38  described above, or with a conventional packer setting tool, such as a Baker number  10  setting tool. A packer setting tool (not shown) typically operates by retracting a mandrel several inches while restricting displacement of an outer housing. 
     A mandrel of the setting tool can be threaded to a mandrel  94  of the tool  26 . A setting tool adapter  96  can be threaded to the body or outer housing of the setting tool. When the setting tool is actuated, the dispensing tool mandrel  94  is pulled upward (to the left as depicted in  FIG. 12A ) relative to the setting tool adapter  96 . 
     The setting tool mandrel is typically free to float upward prior to actuation of the setting tool. To prevent accidental operation of the dispensing tool  26 , shear pins  100  lock the mandrel  94  in an extended position relative to the setting tool. When the setting tool is actuated, the shear pins  100  shear to allow the dispensing tool mandrel  94  to displace upward. 
     The upward movement of the mandrel  94  causes a closure member or inner sleeve  98  of the sliding sleeve valve  92  to shift upward. This upward displacement of the sleeve  98  shears pins  100  and opens a lower end of the enclosure  84 . 
     In  FIG. 12B , the dispensing tool  26  is representatively illustrated in an open configuration. Ports  90  are opened when the sleeve  98  shifts upward. The open ports  90  provide for fluid communication between an exterior of the dispensing tool  26  (e.g., the annulus between the tool  26  and the casing  16 ) and an interior flow passage  102  extending through a lower end of the sleeve  98  and into the enclosure  84 . 
     An upper end of the enclosure  84  is attached to the sleeve  98 . Thus, when the sleeve  98  displaces upward, the upper end of the enclosure  84  also displaces upward, thereby tearing open the lower end of the enclosure. The lower end of the enclosure  84  is, thus, pierced, cut or opened, allowing the plugging devices  60  to displace out of the enclosure  84 . A cutter  104  may be mounted in the container  36  for facilitating opening of the enclosure  84  lower end. 
     As used herein, the term “pierce” is used in the sense of forming an opening through a material, such as, by cutting, tearing, penetrating or perforating. 
     Only a portion of the flow  74  passes though the flow passage  102  after the valve  92  has been opened. Part of the flow  74  passes around the boss  88 . This split flow  74  helps separate the plugging devices  60 , which is beneficial to conveying the plugging devices  60  to the perforations  20   a,b  or other openings  68  to be plugged. 
       FIG. 13  shows details of an example of the plugging device enclosure  84 . The enclosure  84  includes a flexible material  106  that can be conveniently opened downhole, and is compatible with well environments. TYVEK™, available from E.I. DuPont de Nemours of Wilmington, Del. USA, is suitable for use as the material  106 , but any wellbore compatible material may be used instead, or in addition. 
     As mentioned above, a screw or other fastener  78  (see  FIGS. 12A  &amp; B) can be used to fasten the lower end of the enclosure  84  to the container  36 , the boss  88  or another component of the tool  26 . The lower end of the enclosure  84  can be folded and retained closed with a grommet  108 . The fastener  78  can extend through the grommet  108  to secure the lower end of the enclosure  84 . 
     The lower end of the enclosure  84  may have perforations or other weakening means to cause it to be torn or pierced in an appropriate place. The perforations may not be necessary, since the folded end can be inherently weaker and will tear off at an upper end of the folds. 
     The upper end of the enclosure  84  is attached to the valve inner sleeve  98 . When the inner sleeve  98  moves up, tension in the enclosure  84  causes the lower end of the enclosure to tear off, thereby opening the lower end. 
     In the  FIG. 13  example, there is an o-ring or other ring-shaped element  110  located at the upper end of the enclosure  84 . The material  106  is wrapped about the element  110  and secured with stitches  112 . This creates an enlarged thickness at the upper end of the enclosure  84 . This enlarged thickness and the ring-shaped element  110  therein can be captured and attached to the lower end of the sliding sleeve valve inner sleeve  98 , as described more fully below. 
     In this example, an elastomeric o-ring is used for the ring-shaped element  110 . Depending on their composition, o-rings are usually relatively inexpensive, stiff (resistant to deflection), and resilient (having elasticity). In other examples, the enclosure material  106  could be folded and sewn to accomplish a similar enlarged thickness at the upper end of the enclosure  84  (without use of the separate element  110 ). 
       FIG. 14  depicts an example of the attachment of the upper end of the enclosure  84  to the lower end of the inner sleeve  98 . The enlarged thickness upper end of the enclosure  84  is positioned in a recess  116  formed on the lower end of the inner sleeve  98 . 
     A split ring  114  secures the upper end of the enclosure  84  against longitudinal displacement relative to the sleeve  98  and recess  116 . A retainer ring  118  prevents displacement of the upper end of the enclosure  84  radially out of the recess  116 . A spiral lock ring  120  secures the retainer ring  118  (and, thereby, the split ring  114  and the upper end of the enclosure  84 ) on the inner sleeve  98 . 
     An example operation of the dispensing tool  26  of  FIGS. 12A-14  may be as follows when used with the system  10  of  FIGS. 1-3 :
         Stop pumping fracturing fluids after a first zone  20   a  is fractured;   Run tool  26  downhole below perforators  28  in the perforating assembly  24 ;   Locate tool  26  above previously fractured zone  20   a;      Actuate packer setting tool or actuator  38 ;   Pump fluid to displace plugging devices  60  out of dispensing tool  26  with fluid flow  22 ;   Pull up to next zone  20   b  position;   Fire perforators  28 ;   Retrieve perforating assembly  24  from wellbore.       

     It may be desirable to prevent plugging devices  60  from entangling in the enclosure  84  prior to operation of the dispensing tool  26 . To prevent the plugging devices  60  from forming a dense pack and/or tangling with each other, they can be suspended in the substance  86  (such as, a gel) within the enclosure  84 . Suitable gelling agents include crosslinked polyacrylate powder (e.g., Carbopol 941), xanthan gum, polyvinyl alcohol, and mixtures of locust bean gum and guar gum. 
     The plugging devices  60  may comprise a covering of a dry gelling agent that hydrates due to contact with well fluid after the dispensing tool  26  is introduced into the well. 
     In any of the examples described herein, appropriate materials can be selected to construct plugging devices  60  with controllable lifetimes in various downhole environments. Plugging device diversion can be used in a variety of well stimulation and remedial treatments to control the placement of fluid along a length of a perforated zone. 
     For a typical new well completion with “plug and perf” techniques, plugging devices  60  that do not self-degrade can be used, because the plugging devices  60  can be removed during a plug-milling operation after the fracturing operation. However, if dissolvable or otherwise degradable plugs are used, self-degrading plugging devices  60  can be desired, so that no subsequent coiled-tubing run or other intervention is necessary to remove the plugging devices. 
     Self-degrading plugging devices  60  are also beneficial for re-fracturing of older wells, where a coiled-tubing run may not be made after the treatment. For damage removal in older wells, acid-resistant plugging devices  60  may be needed, due to long contact times with hydrochloric acid. High-temperature wells may utilize plugging devices  60  made from fiber that will withstand elevated temperature longer that common fibers, such as nylon 6 or polyester. 
     All of the materials for making plugging devices  60  described in this disclosure can be in the form of staple fiber or filament that is formed into yarn. The yarn can be then twisted or braided into cord or rope, or twisted into a larger yarn that can be used directly to make plugging devices  60 . 
     Use of staple fiber (e.g., chopped fiber) typically involves additional preliminary steps of carding and one or more drawing steps before spinning into yarn. Open end spinning, ring spinning, and air jet spinning can be used to form the basic yarn from staple fiber. Open end spinning may be preferable, because it typically uses fewer drawing steps than the other spinning techniques, and a heavier yarn (e.g., thread count &lt;4) can be made. 
     Multiple yarns can be twisted together to prepare plied yarn (e.g., 10 ply or 12 ply) that can be used to make plugging devices  60 . As an alternative to plied yarns, DREF spinning (friction spinning), can be used to make a large-diameter yarn without a subsequent plying step. DREF spinning typically uses a monofilament as a base for the staple fiber to form around. 
     Staple fiber of thermoplastic polymers (e.g., nylon, polyester, polylactic acid, etc.) can be prepared by melt spinning. Polymers not amenable to melt spinning (e.g., rayon, polyaramid, acrylic, polybenzimidazole) may be dissolved in solvent and spun in either a wet or dry process for solvent removal. After spinning, drawing, crimping, and chopping steps produce a staple fiber that can be used in the yarn-spinning process. 
     Multiple different polymers can be spun into a single, multi-component fiber. Various core-sheath cross sections are possible (e.g., single core, concentric or eccentric cross section; multiple core, “islands in the sea” cross section; segmented pie cross section). Multi-component fiber in this application can be used to prepare a fiber that has sufficient strength, while degrading in a reasonable time in downhole environments. A single component fiber that rapidly degrades may not have sufficient mechanical properties on the time scale of the well treatment. Conversely, a mono-component fiber with adequate mechanical properties may degrade too slowly to be useful. 
     Polylactic acid (PLA) degradability is related to the degree of crystallinity and melting point of the polymer. For example, poly(L-lactic acid) is more crystalline and degrades slower than poly(D-lactic acid-co-L-lactic acid). In one example, these two types of PLA can be used together in a bi-component fiber to adjust the degradation rate over a wide temperature range. 
     In addition to the lower crystallinity PLA degrading faster, acid produced by the hydrolysis will accelerate the degradation of the higher-crystallinity PLA. The lower crystallinity PLA can be used as the sheath (as in fiber made for nonwoven cloth applications), or as the core. 
     To further expand the usable temperature range available with PLA, other combinations of polymers can be used. Potentially useful polymers include poly(glycolic acid), poly(lactic acid-co-glycolic acid), poly(paradioxanone), poly(ε-caprolactone), poly(L-lactic acid-co-ϑ-caprolactone), poly(L-lactic acid-co-trimethylene carbonate), poly(ε-caprolactone-co-glycolic acid-co-trimethylene carbonate), polybutylene succinate, poly(3-hydroxybutyrate-co-3-hydroxyvalerate), poly(L-lactic acid-block-ethylene glycol), and polyethylene terephthalate. In all of these examples, the acid produced by the faster-degrading polymer can accelerate the degradation of the more stable polymer. 
     Polyester hydrolysis is catalyzed by both acids and bases, but base-catalyzed hydrolysis is much faster. For low temperature wells where the desired degradation rate cannot be achieved by the spontaneous hydrolysis of the polyester, the degradation rate can be increased by adding a base or base precursor to the polymer before spinning the fiber, or by coating the fiber. Alkaline earth oxides and hydroxides, (e.g., calcium oxide, magnesium oxide, calcium hydroxide, magnesium hydroxide), zinc oxide, sodium tetraborate, calcium carbonate, hexamethylenetetramine, and urea could be used for this purpose. 
     Combinations of water-soluble polymer and degradable polymer can be used to make bi-component fibers with higher degradation rates than single-component fibers made from a degradable polymer. The degradable polymers listed above can be used in combination with various water-soluble polymers, including polyethylene oxide, polyvinyl acetate, polyvinyl alcohol, methacrylic acid copolymers, copolymers of 2-ethylhexyl acrylate and dimethylaminoethyl methacrylate, and sulfopolyesters. 
     For sealing perforations in high-temperature wells (e.g., &gt;300° F.), fibers made from common polymers, such as nylon-6 and polyethylene terephthalate, may degrade too rapidly. In high-temperature wells, plugging devices  60  made with fibers comprising hydrolysis-resistant materials could be used. 
     Potentially suitable materials for use in high-temperature wells include carbon fiber, glass fiber, mineral fiber, ceramic fiber, meta-aramid fiber (e.g., Nomex), para-aramid fiber (e.g., Kevlar), polyacrylonitrile fiber (e.g., Orlon, acrylic, modacrylic), polyparaphenylene sulfide fiber (e.g., Ryton), polybenzanilide, polybenzimidazole fiber (e.g., PBI), polyethylene terephthalate, and fibers made from copolymers and blends. Natural fibers suitable for high temperature include cotton, flax, hemp, sisal, jute, kenaf and coir. 
     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 devices  60  may be dispensed from a dispensing tool  26  (in some cases included in a perforating assembly  24 ). The dispensing tool  26  can include an enclosure  84  that is cut or torn open to release the plugging devices  60 . 
     A well completion method, system and apparatus are described above, in which plugging devices  60  are released from a container  36  in a wellbore  12 . The plugging devices  60  may be released to plug existing perforations  20   a . The plugging devices  60  may be released prior to forming additional perforations  20   b  and fracturing through the additional perforations. 
     A well completion method, system and apparatus are described above, in which plugging devices  60  are released into a wellbore  12  ahead of a perforating assembly  24 . The plugging devices  60  and the perforating assembly  24  may be pumped simultaneously through the wellbore  12 . 
     The plugging devices  60  may plug perforations  20   a  existing before the perforating assembly  24  is introduced into the wellbore  12 . The plugging devices  60  may plug perforations  20   b  made by the perforating assembly  24 . 
     The plugging devices  60  may comprise a fibrous material, a degradable material, and/or a material selected from nylon, poly-lactic acid, poly-glycolic acid, poly-vinyl alcohol, poly-vinyl acetate and poly-methacrylic acid. 
     The plugging devices  60  may comprise a knot. The plugging devices  60  may comprise a fibrous material retained by a degradable retainer  80 . 
     A plugging device dispensing tool  26  and method are described above and depicted in the drawings. The plugging devices  60  are disposed within an enclosure  84  of the dispensing tool  26 . The enclosure  84  is torn open downhole to release the plugging devices  60  into the wellbore  12 . 
     The enclosure  84  may be torn open in response to actuation of a valve  92 . Actuation of the valve  92  may open a flow passage  102  for fluid flow  74  through the dispensing tool  26 . 
     The enclosure  84  may be torn open by actuation of a setting tool or other actuator  38  connected to the dispensing tool  26 . The setting tool/actuator  38  may displace an inner mandrel  94  of the dispensing tool  26 . 
     A staple fiber or filament  62  may be formed into yarn. The yarn may be twisted or braided into cord or rope, or twisted into a larger yarn that is used to make the plugging device  60 . 
     Multiple different polymers may be spun into a single, multi-component fiber  62 . The different polymers may have different degrees of crystallinity and melting points. 
     The polymers may comprise poly(L-lactic acid), poly(D-lactic acid-co-L-lactic acid), poly(glycolic acid), poly(lactic acid-co-glycolic acid), poly(paradioxanone), poly(ε-caprolactone), poly(L-lactic acid-co-ε-caprolactone), poly(L-lactic acid-co-trimethylene carbonate), poly(ε-caprolactone-co-glycolic acid-co-trimethylene carbonate), polybutylene succinate, poly(3-hydroxybutyrate-co-3-hydroxyvalerate), poly(L-lactic acid-block-ethylene glycol), and/or polyethylene terephthalate. In all of these examples, an acid produced by the faster-degrading polymer can accelerate the degradation of the more stable polymer. 
     A degradation rate of a polymer may be increased by adding a base or base precursor to the polymer before spinning the fiber, or by coating the fiber. Alkaline earth oxides and hydroxides, (e.g., calcium oxide, magnesium oxide, calcium hydroxide, magnesium hydroxide), zinc oxide, sodium tetraborate, calcium carbonate, hexamethylenetetramine, and urea are optionally used for this purpose. 
     The plugging device  60  and method can include combinations of water-soluble polymer and degradable polymer used to make bi-component fibers  62  with higher degradation rates than single-component fibers made from a degradable polymer. The degradable polymers listed above can be used in combination with various water-soluble polymers, including polyethylene oxide, polyvinyl acetate, polyvinyl alcohol, methacrylic acid copolymers, copolymers of 2-ethylhexyl acrylate and dimethylaminoethyl methacrylate, and sulfopolyesters. 
     The plugging device  60  and method can include use of hydrolysis-resistant materials. Potentially suitable materials for use in high-temperature wells include carbon fiber, glass fiber, mineral fiber, ceramic fiber, meta-aramid fiber (e.g., Nomex™), para-aramid fiber (e.g., Kevlar™), polyacrylonitrile fiber (e.g., Orlon™, acrylic, modacrylic), polyparaphenylene sulfide fiber (e.g., Ryton™), polybenzanilide, polybenzimidazole fiber (e.g., PBI), polyethylene terephthalate, and fibers made from copolymers and blends. Natural fibers suitable for high temperature include cotton, flax, hemp, sisal, jute, kenaf and coir. 
     A method of deploying plugging devices  60  in a wellbore  12  is provided to the art by the above disclosure. In one example, the method can comprise: conveying a dispensing tool  26  through the wellbore  12 , the dispensing tool  26  including an enclosure  84  containing the plugging devices  60 ; and then opening the enclosure  84  by piercing a material  106  of the enclosure  84 , thereby releasing the plugging devices  60  from the enclosure  84  into the wellbore  12  at a downhole location. 
     The piercing step may include tearing, opening and/or cutting the material  106  of the enclosure  84 . 
     The opening step may include displacing one end of the enclosure  84  relative to an opposite end of the enclosure  84 . The displacing step may include displacing a member of a valve  92 . The valve  92  member may comprise an inner sleeve  98  that selectively blocks flow through at least one port  90  of the valve  92 . 
     The releasing step may include producing fluid flow  74  through a flow passage  102  in communication with an interior of the enclosure  84 . The opening step may include opening a valve  92 , thereby permitting the fluid flow  74  from an exterior of the dispensing tool  26  to the flow passage  102 . 
     The opening step may include operating an actuator  38  of the dispensing tool  26 . 
     The method may include connecting the dispensing tool  26  and a perforator  28  in a perforating assembly  24 . 
     A dispensing tool  26  for dispensing plugging devices  60  into a subterranean well is also provided by the above disclosure. In one example, the dispensing tool  26  can comprise a container  36  having an enclosure  84  therein, the enclosure  84  including a flexible material  106  that contains the plugging devices  60 , and an end of the enclosure  84  being secured to a member (such as the inner sleeve  98 ) displaceable by an actuator  38 , and in which the enclosure material  106  is opened in response to displacement of the member by the actuator  38 . 
     An opposite end of the enclosure  84  may be secured against displacement relative to the container  36 . A fastener  78  may extend through folds of the flexible material  106  at the opposite end of the enclosure  84 . 
     The member may comprise a closure member of a valve  92 . The closure member may comprise an inner sleeve  98 , and the valve  92  may comprise a sliding sleeve valve. 
     The closure member  98  may have a closed position that prevents fluid communication between an exterior of the dispensing tool  26  and an interior flow passage  102  of the dispensing tool  26 . The closure member  98  may have an open position in which fluid communication is permitted between the exterior of the dispensing tool  26  and the interior flow passage  102 . The flow passage  102  may be in fluid communication with an interior of the enclosure  84 . 
     The above disclosure also provides to the art a plugging device  60  for use in a subterranean well. In one example, the plugging device  60  can include at least one body  64  configured to engage an opening  68  in the well and block fluid flow  74  through the opening  68 ; and multiple fibers  62 , the fibers  62  comprising staple fibers or filaments formed into yarn. 
     The yarn may be twisted or braided and form cord or rope. The yarn may be twisted or braided to form a larger yarn. 
     Each of the multiple fibers  62  may comprise multiple different polymers spun into an individual multi-component fiber  62 . The different polymers may have respective different degrees of crystallinity and/or respective different melting points. 
     The polymers may be selected from the group consisting of poly(L-lactic acid), poly(D-lactic acid-co-L-lactic acid), poly(glycolic acid), poly(lactic acid-co-glycolic acid), poly(paradioxanone), poly(ε-caprolactone), poly(L-lactic acid-co-ε-caprolactone), poly(L-lactic acid-co-trimethylene carbonate), poly(ε-caprolactone-co-glycolic acid-co-trimethylene carbonate), polybutylene succinate, poly(3-hydroxybutyrate-co-3-hydroxyvalerate), poly(L-lactic acid-block-ethylene glycol) and polyethylene terephthalate. 
     An acid produced by a faster-degrading one of the polymers may accelerate degradation of a more stable one of the polymers. A degradation rate of at least one of the polymers may be increased by addition of a base or base precursor to the at least one of the polymers before spinning the fiber  62 , or by inclusion of the base or base precursor in a coating on the fiber  62 . 
     The base or base precursor may be selected from the group consisting of alkaline earth oxides, alkaline earth hydroxides, calcium oxide, magnesium oxide, calcium hydroxide, magnesium hydroxide, zinc oxide, sodium tetraborate, calcium carbonate, hexamethylenetetramine and urea. 
     The polymers may comprise a combination of a water-soluble polymer and a degradable polymer. The water-soluble polymer may be selected from the group consisting of polyethylene oxide, polyvinyl acetate, polyvinyl alcohol, methacrylic acid copolymers, copolymers of 2-ethylhexyl acrylate and dimethylaminoethyl methacrylate and sulfopolyesters. 
     The multiple fibers  62  may comprise a hydrolysis-resistant material. The hydrolysis-resistant material may be selected from the group consisting of carbon fiber, glass fiber, mineral fiber, ceramic fiber, meta-aramid fiber, para-aramid fiber, polyacrylonitrile fiber, polyparaphenylene sulfide fiber, polybenzanilide, polybenzimidazole fiber, polyethylene terephthalate and fibers made from copolymers and blends. The hydrolysis-resistant material may be selected from the group consisting of cotton, flax, hemp, sisal, jute, kenaf and coir. 
     Although various examples have been described above, with each example having certain features, it should be understood that it is not necessary for a particular feature of one example to 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 substitution for any of the other features of those examples. One example&#39;s features are not mutually exclusive to another example&#39;s features. Instead, the scope of this disclosure encompasses any combination of any of the features. 
     Although each example described above includes a certain combination of features, it should be understood that it is not necessary for all features of an example to be used. Instead, any of the features described above can be used, without any other particular feature or features also being used. 
     It should be understood that the various embodiments described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments. 
     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. 
     The terms “including,” “includes,” “comprising,” “comprises,” and similar terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc., is described as “including” a certain feature or element, the system, method, apparatus, device, etc., can include that feature or element, and can also include other features or elements. Similarly, the term “comprises” is considered to mean “comprises, but is not limited to.” 
     Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. For example, structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the invention being limited solely by the appended claims and their equivalents.