Patent Publication Number: US-11377926-B2

Title: Plugging device deployment

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation of prior U.S. application Ser. No. 15/745,608 filed on 17 Jan. 2018, which is a national stage under 35 USC 371 of International Application No. PCT/US16/29357, filed on 26 Apr. 2016, which claims the benefit of the filing date of U.S. provisional application Ser. No. 62/195,078 filed 21 Jul. 2015. The entire disclosures of these prior applications are incorporated herein in their entireties by this reference. 
    
    
     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 deployment of plugging devices 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. 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. 
         FIGS. 2A-D  are enlarged scale representative partially cross-sectional views of steps in an example of a re-completion method that may be practiced with the system of  FIG. 1 . 
         FIGS. 3A-D  are representative partially cross-sectional views of steps in another example of a method that may be practiced with the system of  FIG. 1 . 
         FIGS. 4A  &amp; B are enlarged scale representative elevational views of examples of a flow conveyed device that may be used in the system and methods of  FIGS. 1-3D , and which can embody the principles of this disclosure. 
         FIG. 5  is a representative elevational view of another example of the flow conveyed device. 
         FIGS. 6A  &amp; B are representative partially cross-sectional views of the flow conveyed 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 device with a retainer. 
         FIG. 10  is a representative cross-sectional view of an example of a deployment apparatus and method that can embody the principles of this disclosure. 
         FIG. 11  is a representative schematic view of another example of a deployment apparatus and method that can embody the principles of this disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     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 tubular string  12  is conveyed into a wellbore  14  lined with casing  16  and cement  18 . Although multiple casing strings would typically be used in actual practice, for clarity of illustration only one casing string  16  is depicted in the drawings. 
     Although the wellbore  14  is illustrated as being vertical, sections of the wellbore could instead be horizontal or otherwise inclined relative to vertical. Although the wellbore  14  is completely cased and cemented as depicted in  FIG. 1 , any sections of the wellbore in which operations described in more detail below are performed could be uncased or open hole. Thus, the scope of this disclosure is not limited to any particular details of the system  10  and method. 
     The tubular string  12  of  FIG. 1  comprises coiled tubing  20  and a bottom hole assembly  22 . As used herein, the term “coiled tubing” refers to a substantially continuous tubing that is stored on a spool or reel  24 . The reel  24  could be mounted, for example, on a skid, a trailer, a floating vessel, a vehicle, etc., for transport to a wellsite. Although not shown in  FIG. 1 , a control room or cab would typically be provided with instrumentation, computers, controllers, recorders, etc., for controlling equipment such as an injector  26  and a blowout preventer stack  28 . 
     As used herein, the term “bottom hole assembly” refers to an assembly connected at a distal end of a tubular string in a well. It is not necessary for a bottom hole assembly to be positioned or used at a “bottom” of a hole or well. 
     When the tubular string  12  is positioned in the wellbore  14 , an annulus  30  is formed radially between them. Fluid, slurries, etc., can be flowed from surface into the annulus  30  via, for example, a casing valve  32 . One or more pumps  34  may be used for this purpose. Fluid can also be flowed to surface from the wellbore  14  via the annulus  30  and valve  32 . 
     Fluid, slurries, etc., can also be flowed from surface into the wellbore  14  via the tubing  20 , for example, using one or more pumps  36 . Fluid can also be flowed to surface from the wellbore  14  via the tubing  20 . 
     In the further description below of the examples of  FIGS. 2A-9 , one or more flow conveyed devices are used to block or plug openings in the system  10  of  FIG. 1 . However, it should be clearly understood that these methods and the flow conveyed device may be used with other systems, and the flow conveyed device may be used in other methods in keeping with the principles of this disclosure. 
     The example methods described below allow existing fluid passageways to be blocked permanently or temporarily in a variety of different applications. Certain flow conveyed device examples described below are made of a fibrous material and comprise a “knot” or other enlarged geometry. 
     The devices are conveyed into leak paths using pumped fluid. The fibrous material “finds” and follows the fluid flow, pulling the enlarged geometry 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, 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 through which fluid flows can be blocked with a suitably configured device. 
     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 the bottom hole assembly  22  into the well. In the method, one zone is perforated, the zone is fractured or otherwise 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. 
     Referring specifically now to  FIGS. 2A-D , steps in an example of a method in which the bottom hole assembly  22  of  FIG. 1  can be used in re-completing a well are representatively illustrated. In this method (see  FIG. 2A ), the well has existing perforations  38  that provide for fluid communication between an earth formation zone  40  and an interior of the casing  16 . However, it is desired to re-complete the zone  40 , in order to enhance the fluid communication. 
     Referring additionally now to  FIG. 2B , the perforations  38  are plugged, thereby preventing flow through the perforations into the zone  40 . Plugs  42  in the perforations can be flow conveyed devices, as described more fully below. In that case, the plugs  42  can be conveyed through the casing  16  and into engagement with the perforations  38  by fluid flow  44 . 
     Referring additionally now to  FIG. 2C , new perforations  46  are formed through the casing  16  and cement  18  by use of an abrasive jet perforator  48 . In this example, the bottom hole assembly  22  includes the perforator  48  and a circulating valve assembly  50 . Although the new perforations  46  are depicted as being formed above the existing perforations  38 , the new perforations could be formed in any location in keeping with the principles of this disclosure. 
     Note that other means of providing perforations  46  may be used in other examples. Explosive perforators, drills, etc., may be used if desired. The scope of this disclosure is not limited to any particular perforating means, or to use with perforating at all. 
     The circulating valve assembly  50  controls flow between the coiled tubing  20  and the perforator  48 , and controls flow between the annulus  30  and an interior of the tubular string  12 . Instead of conveying the plugs  42  into the well via flow  44  through the interior of the casing  16  (see  FIG. 2B ), in other examples the plugs could be deployed into the tubular string  12  and conveyed by fluid flow  52  through the tubular string prior to the perforating operation. In that case, a valve  54  of the circulating valve assembly  50  could be opened to allow the plugs  42  to exit the tubular string  12  and flow into the interior of the casing  16  external to the tubular string. 
     Referring additionally now to  FIG. 2D , the zone  40  has been fractured or otherwise stimulated by applying increased pressure to the zone after the perforating operation. Enhanced fluid communication is now permitted between the zone  40  and the interior of the casing  16 . Note that fracturing is not necessary in keeping with the principles of this disclosure. 
     In the  FIG. 2D  example, the plugs  42  prevent the pressure applied to stimulate the zone  40  via the perforations  46  from leaking into the zone via the perforations  38 . The plugs  42  may remain in the perforations  38  and continue to prevent flow through the perforations, or the plugs may degrade, if desired, so that flow is eventually permitted through the perforations. 
     Referring additionally now to  FIGS. 3A-D , steps in another example of a method in which the bottom hole assembly  22  of  FIG. 1  can be used in completing multiple zones  40   a - c  of a well are representatively illustrated. The multiple zones  40   a - c  are each perforated and fractured during a single trip of the tubular string  12  into the well. 
     In  FIG. 3A , the tubular string  12  has been deployed into the casing  16 , and has been positioned so that the perforator  48  is at the first zone  40   a  to be completed. The perforator  48  is then used to form perforations  46   a  through the casing  16  and cement  18 , and into the zone  40   a.    
     In  FIG. 3B , the zone  40   a  has been fractured by applying increased pressure to the zone via the perforations  46   a . The fracturing pressure may be applied, for example, via the annulus  30  from the surface (e.g., using the pump  34  of  FIG. 1 ), or via the tubular string  12  (e.g., using the pump  36  of  FIG. 1 ). The scope of this disclosure is not limited to any particular fracturing means or technique, or to the use of fracturing at all. 
     After fracturing of the zone  40   a , the perforations  46   a  are plugged by deploying plugs  42   a  into the well and conveying them by fluid flow into sealing engagement with the perforations. The plugs  42   a  may be conveyed by flow  44  through the casing  16  (e.g., as in  FIG. 2B ), or by flow  52  through the tubular string  12  (e.g., as in  FIG. 2C ). 
     The tubular string  12  is repositioned in the casing  16 , so that the perforator  48  is now located at the next zone  40   b  to be completed. The perforator  48  is then used to form perforations  46   b  through the casing  16  and cement  18 , and into the zone  40   b . The tubular string  12  may be repositioned before or after the plugs  42   a  are deployed into the well. 
     In  FIG. 3C , the zone  40   b  has been fractured or otherwise stimulated by applying increased pressure to the zone via the perforations  46   b . The pressure may be applied, for example, via the annulus  30  from the surface (e.g., using the pump  34  of  FIG. 1 ), or via the tubular string  12  (e.g., using the pump  36  of  FIG. 1 ). 
     After stimulation of the zone  40   b , the perforations  46   b  are plugged by deploying plugs  42   b  into the well and conveying them by fluid flow into sealing engagement with the perforations. The plugs  42   b  may be conveyed by flow  44  through the casing  16 , or by flow  52  through the tubular string  12 . 
     The tubular string  12  is repositioned in the casing  16 , so that the perforator  48  is now located at the next zone  40   c  to be completed. The perforator  48  is then used to form perforations  46   c  through the casing  16  and cement  18 , and into the zone  40   c . The tubular string  12  may be repositioned before or after the plugs  42   b  are deployed into the well. 
     In  FIG. 3D , the zone  40   c  has been fractured or otherwise stimulated by applying increased pressure to the zone via the perforations  46   c . The pressure may be applied, for example, via the annulus  30  from the surface (e.g., using the pump  34  of  FIG. 1 ), or via the tubular string  12  (e.g., using the pump  36  of  FIG. 1 ). 
     After stimulation of the zone  40   c , the perforations  46   c  could be plugged, if desired. For example, the perforations  46   c  could be plugged in order to verify that the plugs are properly blocking flow from the casing  16  to the zones  40   a - c.    
     As depicted in  FIG. 3D , the plugs  42   a,b  are degraded and no longer prevent flow through the perforations  46   a,b . Thus, as depicted in  FIG. 3D , flow is permitted between the interior of the casing  16  and each of the zones  40   a - c.    
     The plugs  42   a,b  may be degraded in any manner. The plugs  42   a,b  may degrade in response to application of a degrading treatment, in response to passage of a certain period of time, or in response to exposure to elevated downhole temperature. The degrading treatment could include exposing the plugs  42   a,b  to a particular type of radiation, such as electromagnetic radiation (e.g., light having a certain wavelength or range of wavelengths, gamma rays, etc.) or “nuclear” particles (e.g., gamma, beta, alpha or neutron). 
     The plugs  42   a,b  may degrade by galvanic action or by dissolving. The plugs  42   a,b  may degrade in response to exposure to a particular fluid, either naturally occurring in the well (such as water or hydrocarbon fluid), or introduced therein. 
     The plugs  42   a,b  may be mechanically removed, instead of being degraded. The plugs  42   a,b  may be cut using a cutting tool (such as a mill or overshot), or an appropriately configured tool may be used to grab and pull the plugs from the perforations. 
     Note that any number of zones may be completed in any order in keeping with the principles of this disclosure. The zones  40   a - c  may be sections of a single earth formation, or they may be sections of separate formations. 
     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 plugs  42 ,  42   a,b  described above in the method examples of  FIGS. 2A-3D , 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. The body  64  could be formed from a single sheet of material or from multiple strips of sheet 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 formed from the same material as the lines  66 . The body  64  could comprise a relatively large solid object, with the lines  66  (such as, fibers, ropes, fabric, sheets, cloths, tubes, films, twine, strings, etc.) attached thereto. 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 be 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. 4  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 lines  66  and fibers  62  of the device  60  enhance fluid drag on the device, so that the device is influenced to displace with the flow  74 . 
     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 /lines  66  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 /lines  66  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, PLA or 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. 
     If the device  60  is present in a well during or after an acidizing treatment, then at least the body  64  could be somewhat acid resistant. For example, a coating material on the body  64  could initially delay degradation of the body, but allow the body to degrade after a predetermined period of time. Alternatively, the device  60  could be mechanically removed after the acidizing treatment. 
     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, 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 , an example of a deployment apparatus  90  and an associated method are representatively illustrated. The apparatus  90  and method may be used with the system  10  and method described above, or they may be used with other systems and methods. 
     When used with the system  10 , the apparatus  90  can be connected between the pump  34  and the casing valve  32  (see  FIG. 1 ). Alternatively, the apparatus  90  can be “teed” into a pipe associated with the pump  34  and casing valve  32 , or into a pipe associated with the pump  36  (for example, if the devices  60  are to be deployed via the tubular string  12 ). However configured, an output of the apparatus  90  is connected to the well, although the apparatus itself may be positioned a distance away from the well. 
     The apparatus  90  is used in this example to deploy the devices  60  into the well. The devices  60  may or may not be retained by the retainer  80  when they are deployed. However, in the  FIG. 10  example, the devices  60  are depicted with the retainers  80 , for convenience of deployment. The retainer material  82  is at least partially dispersed during the deployment method, so that the devices  60  are more readily conveyed by the flow  74 . 
     In certain situations, it can be advantageous to provide spacing between the devices  60  during deployment, for example, in order to efficiently plug casing perforations. One reason for this is that the devices  60  will tend to first plug perforations that are receiving highest rates of flow. 
     In addition, if the devices  60  are deployed downhole too close together, some of them can become trapped between perforations, thereby wasting some of the devices. The excess “wasted” devices  60  can later interfere with other well operations. 
     To mitigate such problems, the devices  60  can be deployed with a selected spacing. The spacing may be, for example, on the order of the length of the perforation interval. The apparatus  90  is desirably capable of deploying the devices  60  with any selected spacing between the devices. 
     Each device  60  in this example has the retainer  80  in the form of a dissolvable coating material with a frangible coating  88  (see  FIG. 8 ) thereon, to impart a desired geometric shape (spherical in this example), and to allow for convenient deployment. The dissolvable retainer material  82  could be detrimental to the operation of the device  60  if it increases a drag coefficient of the device. A high coefficient of drag can cause the devices  60  to be swept to a lower end of the perforation interval, instead of sealing uppermost perforations. 
     The frangible coating  88  is used to prevent the dissolvable coating from dissolving during a queue time prior to deployment. Using the apparatus  90 , the frangible coating  88  can 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 in  FIG. 10 , the apparatus  90  includes a rotary actuator  92  (such as, a hydraulic or electric servo motor, with or without a rotary encoder). The actuator  92  rotates a sequential release structure  94  that receives each device  60  in turn from a queue of the devices, and then releases each device one at a time into a conduit  86  that is connected to the tubular string  72  (or the casing  16  or tubing  20  of  FIG. 1 ). 
     Note that it is not necessary for the actuator  92  to 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 device  60  to be deployed at a time. In other examples, the release structure  94  could be configured to release multiple devices at a time. Thus, the scope of this disclosure is not limited to any particular details of the apparatus  90  or the associated method as described herein or depicted in the drawings. 
     In the  FIG. 10  example, a rate of deployment of the devices  60  is determined by an actuation speed of the actuator  92 . As a speed of rotation of the structure  94  increases, a rate of release of the devices  60  from the structure accordingly increases. Thus, the deployment rate can be conveniently adjusted by adjusting an operational speed of the actuator  92 . This adjustment could be automatic, in response to well conditions, stimulation treatment parameters, flow rate variations, etc. 
     As depicted in  FIG. 10 , a liquid flow  96  enters the apparatus  90  from the left and exits on the right (for example, at about 1 barrel per minute). Note that the flow  96  is allowed to pass through the apparatus  90  at any position of the release structure  94  (the release structure is configured to permit flow through the structure at any of its positions). 
     When the release structure  94  rotates, one or more of the devices  60  received in the structure rotates with the structure. When a device  60  is on a downstream side of the release structure  94 , the flow  96  though the apparatus  90  carries the device to the right (as depicted in  FIG. 10 ) and into a restriction  98 . 
     The restriction  98  in this example is smaller than the diameter of the retainer  80 . The flow  96  causes the device  60  to be forced through the restriction  98 , and the frangible coating  88  is thereby damaged, opened or fractured to allow the inner dissolvable material of the retainer  80  to 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 retainer  80  to penetrate, break or otherwise damage the frangible coating  88 . Thus, this disclosure is not limited to any particular technique for damaging, breaking, penetrating or otherwise compromising a frangible coating. 
     Note that it is not necessary for the restriction  98  to open, break or damage a frangible coating. In some examples, a frangible coating may not be provided on the device  60 . In those examples, the restriction  98  could initiate degradation of the retainer  80  (e.g., when the retainer material comprises paraffin wax). The restriction  98  could mechanically compress, damage, fracture, open, penetrate, cut, compromise or break the retainer  80 , and thereby expose additional surface area of the retainer to degradation by exposure to heat, fluids, etc. in the well. 
     In some examples, the restriction  98  could be used to initiate degradation of the device  60 . For example, the retainer  80  may not be used, or the retainer may be incorporated into the device. In those examples, the restriction  98  could have an interior dimension that is smaller than an external dimension of the device  60 , or could have cutters or abrasive structures to contact an outside surface of the device and thereby damage, break, penetrate or otherwise compromise the device, so that it more readily degrades in the well. 
     Referring additionally now to  FIG. 11 , another example of a deployment apparatus  100  and an associated method are representatively illustrated. The apparatus  100  and method may be used with the system  10  and method described above, or they may be used with other systems and methods. 
     In the  FIG. 11  example, the devices  60  are deployed using two flow rates. Flow rate A through two valves (valves A &amp; B) is combined with Flow rate B through a pipe  102  (such as casing  16  or tubular string  72 ) depicted as being vertical in  FIG. 11  (the pipe may be horizontal or have any other orientation in actual practice). 
     The pipe  102  may receive flow via the pump  34  and casing valve  32 , or the pipe may receive flow via the pump  36  if the devices  60  are to be deployed via the tubular string  12 . In some examples, a separate pump (not shown) may be used to supply the flow  96  through the valves A &amp; B. 
     Valve A is not absolutely necessary. When valve B is open the flow  96  causes the devices  60  to enter the vertical pipe  102 . Flow  104  through the vertical pipe  102  in this example is substantially greater than the flow  96  through the valves A &amp; B (that is, flow rate B&gt;&gt;flow rate A), although in other examples the flows may be substantially equal or otherwise related. 
     A spacing (dist. B) between the devices  60  when they are deployed into the well can be calculated as follows: dist. B=dist. A*(ID A   2 /ID B   2 )*(flow rate B/flow rate A), where dist. A is a spacing between the devices  60  prior to entering the pipe  102 , ID A  is an inner diameter of a pipe  106  connected to the pipe  102 , and ID B  is an inner diameter of the pipe  102  (such as, the casing  16  or tubular string  72 ). This assumes circular pipes  102 ,  106 . Where corresponding passages are non-circular, the term ID A   2 /ID B   2  can be replaced by an appropriate ratio of passage areas. 
     The spacing between the plugging devices  60  in the well (dist. B) can be automatically controlled by varying at least one of the flow rates. For example, the spacing can be increased by increasing the flow rate B or decreasing the flow rate A. The flow rate(s) 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 of the devices  60  and the flow rate A in the pipe  106 . 
     The deployment spacing B may be increased by adding spacers  108  between the devices  60  in the pipe  106 . The spacers  108  effectively increase the distance A between the devices  60  in the pipe  106  (and, thus, increase the value of dist. A in the equation above). 
     The spacers  108  may be dissolvable or otherwise dispersible, so that they dissolve or degrade when they are in the pipe  102  or thereafter. In some examples, the spacers  108  may be geometrically the same as, or similar to, the devices  60 . 
     Note that the apparatus  100  may be used in combination with the restriction  98  of  FIG. 10  (for example, with the restriction  98  connected downstream of the valve B but upstream of the pipe  102 ). In this manner, a frangible or other protective coating  88  on the devices  60  and/or spacers  108  can be opened, broken or otherwise damaged prior to the devices and spacers entering the pipe  102 . 
     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 device  60  may 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. A deployment apparatus  100  can be used to deploy the devices  60  into the well, so that a desired spacing between the devices is achieved. 
     The above disclosure provides to the art a method of deploying plugging devices  60  in a well. In one example, the method can include operating an actuator  92 , thereby displacing a release structure  94 . The release structure  94  releases the plugging devices  60  into the well in response to the operating step. 
     The method may include controlling a rate of release of the plugging devices  60 . The controlling step can be performed by controlling an operational speed of the actuator  92 . The controlling step may be performed by automatically controlling the actuator  92 , thereby automatically controlling the rate of release of the plugging devices  60 . 
     The actuator  92  may rotate the release structure  94 . The releasing step may include passing a fluid flow  96  through the release structure  94 . 
     The method can include initiating degradation of the plugging devices  60  or a retainer  80  that retains of each of the plugging devices  60 . The initiating step may be performed by opening a frangible coating  88  on each of the retainers  80 . The initiating step may be performed by forcing the plugging devices  60  through a restriction  98 . The initiating may be performed by damaging, breaking or opening the retainer  80 . 
     A deployment apparatus  90  for deploying plugging devices  60  in a well is also provided to the art by the above disclosure. In one example, the deployment apparatus  90  can comprise an actuator  92  and a release structure  94  that releases the plugging devices  60  into a conduit  86  connected to a tubular string  72  in the well. 
     A rate of release of the plugging devices  60  may be proportional to an operational speed of the actuator  92 . 
     The deployment apparatus  90  can include a restriction  98  that initiates degradation of the plugging devices  60  or a retainer  80  that retains each of the plugging devices  60 . 
     The restriction  98  may open a frangible coating  88  on each of the retainers  80 . 
     Another method of deploying plugging devices  60  in a well can comprise: selectively displacing the plugging devices  60  through a first pipe  106  that intersects a second pipe  102 ; controlling a first fluid flow rate through the first pipe  106 ; and controlling a second fluid flow rate through the second pipe  102 . A spacing between the plugging devices  60  deployed into the well is proportional to a ratio of the first and second flow rates. 
     The method may include varying the spacing by varying at least one of the first and second flow rates. 
     The method may include automatically varying the spacing by automatically varying at least one of the first and second flow rates. 
     The spacing between the plugging devices  60  in the well may be determined by the following equation: dist. B=dist. A*(ID A   2 /ID B   2 )*(flow rate B/flow rate A), where dist. B is the spacing between the plugging devices in the well, dist. A is a spacing between the plugging devices in the first pipe  106 , ID A  is an inner dimension of the first pipe  106 , ID B  is an inner dimension of the second pipe  102 , flow rate A is the first flow rate through the first pipe  106 , and flow rate B is the second flow rate through the second pipe  102 . 
     The method may include interposing spacers  108  between the plugging devices  60 . 
     Another deployment apparatus  100  for deploying plugging devices  60  in a well is described above. In one example, the deployment apparatus  100  comprises intersecting first and second pipes  106 ,  102  and a valve B that selectively permits and prevents displacement of the plugging devices  60  through the first pipe  106 . A spacing between the plugging devices  60  deployed into the well is proportional to a ratio of first and second flow rates through the respective first and second intersecting pipes  106 ,  102 . 
     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.