Abstract:
A borehole plug or packer for treating is designed to be flowed back to a surface location after use. When the treatment is concluded pressure from above is relieved or lowered, and well fluid is flowed back, so that the plug or plugs disengages at slips designed to resist differential pressure from above. The application of differential pressure from below causes the lower slips to release one or more of such plugs in the hole into specialized sub surface or surface capture equipment so that well pressure is relieved before removal of the plugs from specialized subsurface or surface capture equipment. Sensors to obtain and store data can be incorporated into the plugs or into objects landed on the plugs so that when brought to the surface the data can be processed and used in aid of production.

Description:
PRIORITY INFORMATION 
       [0001]    This application is a continuation-in-part of U.S. patent application Ser. No. 15/605,716 filed on May 25, 2017, and a continuation-in-part of U.S. patent application Ser. No. 15/168,658 filed on May 31, 2016 
     
    
     FIELD OF THE INVENTION 
       [0002]    The field of the invention is borehole barriers and more particularly designs that see pressure from above and are retrieved to a surface or subsurface location by lowering pressure from above and bringing up stored well data in the plug or a ball used to close a plug passage. 
       BACKGROUND OF THE INVENTION 
       [0003]    Borehole plugs are used in a variety of applications for zone isolation. In some applications the differential pressure experienced in the set position can come from opposed directions. These plug typically have a sealing element with mirror image slips above and below the sealing element. The plug is set with a setting tool that creates relative movement between a setting sleeve that is outside the mandrel and the plug mandrel. The slips have wickers oriented in opposed directions and ride out on cones to the surrounding tubular. The sealing element is axially compressed after the first set of slips bite followed by setting of the other set of slips on the opposite side of the sealing element from the first slip set to set. The set position of these elements is maintained by a body lock ring assembly. Body lock ring assemblies are in essence a ratchet device that allows relative movement in one direction and prevents relative movement in the opposite direction. The relative movement that compresses the sealing element and drives the opposed slips out on respective cones is locked by a body lock ring. Body lock rings are threaded inside and out and sit between two relatively movable components. The thread forms are such that ratcheting in one direction only is enabled. A good view of such a design is shown in  FIG. 13  of U.S. Pat. No. 7,080,693. The trouble with such a design in applications where the plug needs to be quickly milled out after use such as in treating or fracturing is that the shear loading on the ratcheting patterns is so high that the ratchet teeth break at loads that are well within the needed operating pressure range for the plug. With fracturing pressures going up and the use of readily milled components such as composites a new approach to locking was needed. The goal during treating is to hold the differential pressure from above while keeping the design simple so as not to prolong the milling time for ultimate removal. A typical zone treatment can involve multiple plugs that need to be removed. Elimination of upper slips when using the lock ring also shortens milling time. Better yet, milling of the plugs can be avoided by lowering pressure from above to induce flow back from the stage below the targeted plug, until the slips of the plug or series of plugs to disengage and come up to a surface location such as into specialized surface or subsurface equipment where the pressure can be relieved and the plug or plugs safely removed. In some situations the casing or tubular string gets larger as it gets closer to the surface and if the plug or plugs are being flowed to the surface they can slow down or fail to finish the travel to be captured either below or above the wellhead. In those situations at least one wiper is used to facilitate not only pumping the plug into position but to also aid the movement of the plug back uphole in wells where the string size increases on the way toward the surface. The capture equipment can be a lubricator located above a wellhead and configured to allow reduction of pressure above the packer or plug to allow it to flow to the surface for capture in the lubricator. A piping and valve array at the lubricator allows production to continue with a single plug or multiple plugs captured in the lubricator for later removal. Alternatively the capture device below the wellhead can be a slotted liner or the like with a tapered inlet that is also perforated to guide flowed plugs into the liner that has a closed top. A counter counts how many plugs are captured while a trap such as flexible fingers holds the captured plugs in the slotted liner as production continues. At some later time the slotted liner is fished out with the well otherwise shut in with one or more barrier valves below. A counter for the plugs and a flexible finger trap is contemplated for the slotted liner to give surface personnel confirmation that the plugs have all been flowed up and retained for later removal. In yet another aspect the plug or an object destined for the plug to block a passage through the plug can include sensors to gather and store different types of data from the formation in the vicinity of the set plug such that when the object or plug are flowed to the surface the stored data can be processed and analyzed for production purposes. The sensors can be in the plug body or a passage therethrough or in a ball or other object landed on each plug. The plugs can be flowed to the surface together with the associated objects landed on them or the objects can be flowed up after treatment against a specific plug before the next plug is set in place. 
         [0004]    The lock ring is preferably split to ease its movement when axial opposed forces are applied to set the plug. The ring is tapered in cross section to allow it to act as a wedge against reaction force tending to relax the components from the set position. The side of the ring facing the mandrel has a surface treatment that provides minimal resistance in the setting direction and digs into the mandrel to resist reaction forces from the compressed sealing element in the set position. Preferably the surface treatment is a series of extending members oriented downhole with sharp ends that can dig into the mandrel for a firm grip. These and other aspects of the present invention can be better understood by those skilled in the art from a review of the description of the preferred embodiment and the associated drawings while recognizing that the full scope of the invention is to be determined from the appended claims. 
         [0005]    Multicomponent body lock rings have been made of easily milled materials such as composites as illustrated in US 2014/0190685; U.S. Pat. Nos. 8,191,633; 6,167,963; 7,036,602; 8,002,030 and 7,389,823. The present invention presents a way to avoid milling altogether so that the use of composites that aid milling become an optional feature. This can reduce the cost of each plug in treatments that frequently involve multiple plugs. U.S. Pat. No. 8,240,390 is relevant to packer releasing methods. Wiper plugs typically used in cementing operations are well known and described in the following references: U.S. Pat. Nos. 9,080,422; 7,861,781 and 8,127,846. These plugs typically stay downhole and none are used to aid in plug recovery to the surface using formation pressure. Lubricators used in oil and gas production are illustrated in U.S. Pat. No. 6,755,244; WO2008/060891 and U.S. Pat. No. 6,250,383. 
       SUMMARY OF THE INVENTION 
       [0006]    A borehole plug or packer for treating is designed to be flowed back to a subsurface or surface location after use. The plug handles differential pressure from above using a lower slip assembly under a sealing element. A setting tool creates relative axial movement of a setting sleeve and a plug mandrel to compress the seal against the surrounding tubular and set the slips moving up a cone against the surrounding tubular to define the set position for the plug. The set position is held by a split lock ring having a wedge or triangular sectional shape and a surface treatment facing the mandrel that slides along the mandrel during setting movement but resists opposed reaction force from the compressed sealing element. The surface treatment can be a series of downhole oriented ridges such as a buttress thread that preferably penetrate the mandrel when holding the set position. When the treatment is concluded pressure from above is relieved or lowered so that the plug or plugs disengage at slips designed to resist differential pressure from above. The application of flow from below causes the slips to release one or more of such plugs in the hole in order to flow uphole into specialized surface or subsurface equipment so that well pressure is relieved before removal of the plugs from the well. To aid the plugs on the way up the borehole in situations where the tubular size increases on the way out of the borehole an apparatus is employed that can enlarge to bridge a growing gap on the way out of the borehole so that the plug velocity with formation pressure can continue to move the flowed plug back to capture equipment above or below the wellhead. Packers or plugs are captured above, below or at a wellhead in a receptacle. Production ensues without milling with the captured plugs or packers in place or removed. Sensors to obtain and store data can be incorporated into the plugs or into objects landed on the plugs so that when brought to the surface the data can be processed and used in aid of production. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0007]      FIG. 1  is a section view of the plug in the run in position; 
           [0008]      FIG. 2  is a close up view of the lock ring shown in  FIG. 1  and 
           [0009]      FIG. 3  is an exterior view of the plug; 
           [0010]      FIG. 4  is a schematic view of recovery of packers or plugs with net differential pressure; 
           [0011]      FIG. 5  illustrates the use of wipers to bring up plugs where the tubular size increases up the hole; 
           [0012]      FIG. 6  illustrates the use of a single wiper to move multiple plugs up the hole; 
           [0013]      FIG. 7  illustrates using a dedicated wiper for each plug to bring the plugs up the hole; 
           [0014]      FIG. 8  shows a wiper fin design with fins oriented in opposed directions; 
           [0015]      FIG. 9  is the view of  FIG. 8  with the fins in a parallel orientation; 
           [0016]      FIG. 10  is a section view of a wiper peripheral member with a quadrilateral section shape; 
           [0017]      FIG. 11  is an alternative to the view of  FIG. 10  where the cross-sectional shape is circular; 
           [0018]      FIG. 12  illustrates a plug catcher above a wellhead with a bypass line to allow pressure reduction around the plugs in the catcher to obtain the remaining plugs in the catcher; 
           [0019]      FIG. 13  shows an alternative catcher configuration to  FIG. 12  that enables the captured plugs to be isolated and the well to continue to be produced; 
           [0020]      FIG. 14  shows a slotted liner as a capture device located below a wellhead; 
           [0021]      FIG. 15  shows a series of plugs with data collection sensors in the plug; 
           [0022]      FIG. 16  shows a series of plugs with data sensors in the objects landed on the plugs; 
           [0023]      FIG. 17  is a detailed view showing placement of data sensors in a ball that lands on a respective plug. 
       
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
       [0024]    Referring to  FIG. 1  the plug or packer  10  has a mandrel  12  preferably made of a readily milled material such as a composite. Mandrel  12  can optionally have a passage  13  that can be optionally closed with a ball landed on a seat or with a valve (not shown). Shoulder  14  supports sealing element  16 . A cone  18  has individualized tapered surfaces  20  on which a slip, drag block or other retainer, collectively referred to as slip  22  is guided between opposed surfaces  24  and  26 . The slips  22  are each connected to a slip ring  28  that has a triangular undercut  30  when viewed in section in  FIG. 1  that extends for 360 degrees, preferably. The undercut is defined by surfaces  32  and  34  as better seen in  FIG. 2 . The undercut  30  and lock ring  36  may be inverted from the  FIG. 2  position in which case the ribs  56  will be oriented uphole to resist differential pressure in an uphole direction. Lock ring  36  has an outer surface  38  that is preferably parallel to surface  32  of undercut  30 . Bottom surface  40  of ring  36  is contacted by surface  34  of undercut  30  during the setting process. A shear pin or some other breakable member  42  allows the sealing element  16  to be compressed against a surrounding tubular that is not shown before the slips  22  are released to move up ramp surfaces  20  by the breaking of the shear pin  42 . Movement of ring  28  relative to mandrel  12  brings together surfaces  34  and  40  to push the lock ring  36  in tandem with ring  28  during setting with a setting tool that is well known and is not shown and which serves as the force to brace the mandrel  12  while applying compressive force to the sealing element  16  and then extending the slips  22  against the surrounding tubular. The slips  22  have a surface treatment such as wickers  44  that resist reaction force from the compressed sealing element  16  as well as applied pressure loads from uphole applied in the direction of arrow  46 . Because the wickers  44  are designed to hold pressure differential from above they are oriented downhole so that when the flow back rate is significantly increased the wickers  44  will disengage from the surrounding borehole wall, usually a tubular and the plug  10  will come loose. If there is a ball landed on a seat in the plug it may lift off and come uphole or lift and come uphole to seat on the next borehole plug. The flow through the plug will be sufficient to propel that plug into the plug above it, if any, and then further up the hole into specialized surface or subsurface equipment for isolation and depressurization so that the plug or plugs can be removed. 
         [0025]    The lock ring  36  has a surface treatment  48  on bottom surface  50  that faces the mandrel  12 . During setting when the ring  28  takes lock ring  36  with it the surface treatment  48  rides along surface  54  of mandrel  12  without penetration of surface  54 . However, after the set and release from the plug by the setting tool the reaction force from the sealing element  16  causes the downhole oriented ribs  56  to penetrate the surface of the mandrel  12  to brace the lock ring  36  so that it can act as a wedge using surface  38  to prevent motion of ring  28  in the direction of arrow  46 . 
         [0026]    Lock ring  36  can run continuously for nearly  360  with a single split to facilitate assembly to the mandrel  12 . Alternatively, there can be discrete spaced segments for the majority of the  360  degree extent of the undercut  30 . Undercut  30  can be continuous or discontinuous for  360  degrees to retain lock ring  36  when lock ring  36  is formed of discrete segments. The wedging action between surfaces  32  and  38  reduces the stress in an axial direction parallel to surface  54  to discourage shear failure of the ribs  56  while the preferred composite construction of the mandrel  12  encourages penetration through surface  54 . The wedging action creates a radial and axial component forces to the ribs  56  to increase the penetration into the mandrel  12  and to decrease the axial shear force component acting on the ribs  56  at the outer surface of said mandrel  12 . The ribs  56  can be parallel or one or more spiral patterns or a thread form such as a buttress thread. The rib spacing can be equal or variable. The lock ring  36  can preferably be made of composite material or a soft metallic that can be easily drilled. Optionally, if lock ring  36  is a continuous split ring the faces  58  and  60  that define the split can be placed on opposed sides of a tab  62  on mandrel  12  to rotationally lock the two together to prevent lock ring relative rotation with respect to the mandrel  12  when milling out. When segments are used for the lock ring  36  each segment can be rotationally retained in a dedicated undercut  30  in ring  28  to rotationally secure the components when milling out. Alternatively, some or all of the above described plug  10  apart from sealing element  16  can be made of a disintegrating controlled electrolytic material to forgo the milling out altogether. 
         [0027]    Optionally the ribs  56  can be omitted so that bottom surface  50  can make frictional contact with surface  54  with no or minimal penetration so that the retaining force is principally or entirely a frictional contact. Surface  50  can have surface roughening or it can even be smooth. While the ability to hold reaction force may be somewhat decreased without the ribs  50  there is still enough resistance to reaction force to hold the set position for some applications. Wedging action creates the frictional retention force. 
         [0028]      FIG. 4  shows packers  10  still in position and others already displaced by a new uphole force shown schematically as arrow  70 . This condition is normally accomplished by reducing pressure above the set packers  10  from a surface location. When a net uphole force is developed against any of the packers  10  the wickers at some level of net uphole force will no longer be able to retain the grip to the surrounding tubular and the packer  10  will move uphole. It wall pass lower valve  74  of surface or subsurface capture equipment  72  and will be stopped by the upper valve  76 . Once one or more of the packers  10  are in the specialized surface or subsurface capture equipment  72 , the bottom valve  74  is closed and a vent valve  78  is opened and the packers are removed out the top of the specialized surface or subsurface capture equipment  72  through valve  76 . Milling is only needed if one of the packers  10  fails to come to the surface under a net uphole flow from the formation schematically represented by arrow  70 . The specialized surface or subsurface capture equipment  72  can also feature a counter to give a local signal of how many packers  10  have passed into the specialized surface or subsurface capture equipment  72 . As previously stated the orientation of wickers  44  in a downhole direction allows them to function to hold the set of each packer  10  with a net force applied from uphole in a downhole direction such as when performing a treatment. Care must be taken to keep a constant net force in a downhole direction to keep the packer or packers  10  in position. When the treatment ends for the zone the surface pressure is reduced and the grip of the wickers  44  is overcome. The wickers need no radial retraction, they simply give up their grip in the uphole direction as wickers  44  are not oriented to dig in in the uphole direction. This makes the design suitable for treatment where the net pressure is in a downhole direction and later retrieval where the net force on the packer is reversed in direction to bring the packer or packers to the surface. With that the sealing element  16  cannot hold the packer  10  in position and the motion starts uphole into the specialized surface or subsurface capture equipment  72 . The one way oriented wickers  44  allow fixation under a net downhole pressure and retrieval under a net uphole flow. If the packers  10  have a landed object on a seat that closes a passage through the mandrel of a packer  10  it is possible for the object to lift off the seat and then flow through the packer  10  passage as well as the net uphole flow on the mandrel will bring that packer uphole. Bringing up one or more packers can also wipe the borehole of proppant or other solids that may have accumulated in the borehole. Optionally if the borehole has sliding sleeves for zone access, the recovery of the packers  10  with flow from below can also act to close sliding sleeves on the way out of the borehole. One such sliding sleeve  80  is shown adjacent treated formation  82  although multiple such sliding sleeves can be used and operated to close or to open by the passing packers  10  depending on the application. 
         [0029]      FIG. 5  illustrates a horizontal borehole  100  that has a smaller dimension than an upper section  102  with a transition  104  in between. Section  100  can be a liner with a top at transition  104  and the upper section can be casing. Two plugs  106  and  108  are illustrated although more can be used. The plug  106  is backed by wiper  110  and the plug  108  is backed by wiper  112 . Arrow  114  represents a net uphole force on the plugs  106  and  108  sufficient to dislodge their grip to the horizontal borehole after a treatment such as fracturing for example. This condition is typically accomplished by lowering the pressure above the plugs  106  and  108  such as by lowering the pressure above them from the surface for one example. The wipers  110  and  112  move with their respected plugs  106  and  108  out of section  100  and past transition  104  into casing  102 . As that happens the fins  116  oriented uphole and the fins  118  oriented downhole flex to a relaxed position as shown for plug  110  that has passed the transition  104 . The plugs  110  and  112  each have a mandrel  120  with an open passage  122 . The lowermost wiper is preferably positioned uphole from tow perforations  124 . The plugs  110  and  112  can be delivered with their associated plug so that for example wiper  112  is delivered with plug  108  on a variety of conveyances such as coiled tubing, wireline or slickline. As an alternative to the arrangement in  FIG. 6  a single wiper or multiple stacked wipers  126  can be delivered first ahead of plugs  128 ,  130  and  132  as shown in  FIG. 6  so that a net uphole force represented by arrow  134  can bring up the wiper or wipers  126  with all the plugs above such as  128 ,  130  and  132  although a greater or lesser number of plugs can be retrieved in this manner. The opposed orientation of fins  116  and  118  allows pumping the associated wiper into the hole as well as recovering the associated wiper with a net uphole force from the formation with there being at least some fins in either direction of movement that engage the surrounding borehole wall to aid in the movement of the wiper in question. Note that sealing against the borehole walls of various dimensions on the way up the hole is not critical as long as flow is deterred sufficiently to allow the wiper in question to take up the hole however many plugs are used and that need recovery without a need to drill them out. 
         [0030]    Accordingly, as in  FIG. 7  a wiper  136  can be associated with a plug  138 . A wiper  140  can be associated with plug  142  and a wiper  144  can be associated with plug  146 . Typically the plugs illustrated in  FIG. 7  are identical and can be of the type that receive progressively larger balls in an uphole direction to close off a passage through them or depending on the treatment they can be straight plugs with no passage through them. Either way whether one wiper per plug is used or one wiper for a plurality of plugs, the goal is to be bring the plugs with the wiper or wipers to a capturing device above or below the wellhead as previously described. 
         [0031]      FIGS. 8-11  illustrate some alternative wiper designs.  FIG. 8  has been previously described and  FIG. 9  varies in that the fins, typically made of a resilient material such as rubber are extending radially perpendicular to the mandrel of the illustrated wiper. The wiper design can simply be a ring around a mandrel that may have a passage through the mandrel. The ring can have a quadrilateral shape as shown in  FIG. 10  or a round shape as shown in  FIG. 11  or triangular to name a few options. The ring may be flexible foam or some other material that can compress without undue resistance when going into a smaller dimension in the borehole and have some shape memory to expand on the way up the hole as the size of the hole increases one or more times. The rings need not be continuous because, as stated before, enough resistance to flow around the wiper is needed to keep the plug or plugs moving uphole at a reasonable speed. 
         [0032]    Typically the well is allowed to come in by opening a valve or valves at the surface to release the plugs so that the plugs with the associated wiper or wipers can come up the hole. The plugs may engage each other on the way up the hole after they are broken loose and start the trip up the hole. As long as there is a perforation for formation access below the lowest wiper, all the plugs and wiper(s) should come up to the capture device as the path of least resistance is toward the surface. 
         [0033]    With regard to  FIGS. 12-14 , alternative arrangements for retaining or capturing packers or plugs  200  and  202  are illustrated with the understanding that the number of such packers or plugs can vary. The construction that is preferred for each plug has been described above although other designs that will release with a net uphole differential pressure are also contemplated. Preferably the plugs have slips arranged below the sealing element and not above the sealing element making them amenable to release with a lowering of the pressure above so that formation fluid can flow them toward the surface. 
         [0034]      FIG. 12  illustrates a receptacle  204  above a wellhead  206  that includes isolation valve(s) of a type typically used in wellheads. The receptacle is in a position typically used for lubricators but lubricators are typically used for insertion of assemblies into the borehole whereas receptacle  204  is used to catch packers or plugs such as  202  and  204  that are flowed to the surface with induced differential pressure that makes them lose grip when the differential is in the direction of the surface. Receptacle  204  has a closed top  208  that leads to a valve  210 . Valve  212  is connected to receptacle  204  near a lower end  214 . Line  216  can be oriented to a tank or flare that is not shown. Line  218  connects the receptacle  204  to valve  210  and line  220  connects the receptacle  204  to valve  212 . The two positions of valve  212  are to close off line  220  or to open line  220  into line  222 . Valve  210  aligns line  218  to line  216  or in another position aligns line  222  to line  216 . Arrows  224  schematically illustrate packers or plugs  200  and  202  moving to the surface when a passage from receptacle  214  is open to line  216 . Initially, pressure above plugs or packers  220  and  202  is reduced sending plugs or packers that can be above them but are not shown into receptacle  204 . The presence of such plugs or packers in receptacle  204  can slow the uphole fluid velocity if the access to line  216  is through valve  210  and one or more plugs or packers are covering line  218 . In those circumstances valve  212  can align line  220  to line  222  with valve  210  positioned to communicate line  222  to line  216 . Alternatively both lines  218  and  220  can be lined up at the same time to line  216  as this will keep any plugs or packers in receptacle  214  away from line  220  so it can operate as an unrestricted vent. Since the fluid coming up with the packers or plugs such as  200  and  202  is treatment fluid for the earlier treatment there is a very low risk of flammability. Line  216  can be connected to separation equipment to remove hydrocarbons that can either be captured or flared. Arced line  224  is intended to schematically illustrate a multifunctional device or multiple devices that count the number of packers or plugs that enter the receptacle  204  and provides a trap for those entering packers or plugs to prevent their exit. This can be in the form of spring loaded spaced fingers that flex up toward closed top  208  to allow entry of plugs or packers into receptacle  204  but the spring return that pushes the finger array down prevents exit of such plugs or packers, effectively trapping them. Other one way devices to trap plugs or packers in receptacle  204  are also contemplated. 
         [0035]      FIG. 13  is slightly different than  FIG. 12  and where the components are the same similar numbers will be used. The main differences are that receptacle  204 ′ has valve  226  at the top that opens wide enough to pass packers or plugs. An adequately secured hose  228  is directed to a tank  230 . Instead of capture inside the receptacle  204 ′ the plugs or packers  200 ′ or  202 ′ continue their movement into hose  228  and tank  230  displacing mostly treatment fluids ahead of them. The plugs or packers  200 ′ and  202 ′ and others that may have been further uphole can be recovered from the tank  230 . Tank  230  can be an open pit or an enclosed vessel with a remote vent to separation equipment and ultimately a flare. Once the counter  224 ′ confirms to surface personnel that all the plugs and packers are out of the hole valve  226  can be closed. Valve  232  is an alternate outlet out of receptacle  204 ′ in case there is a blockage with a packer or plug in hose  228 . Valve  232  is an alternative fluid outlet out of receptacle  204 ′ into line  216 ′. Wellhead  206 ′ has several inline valves that are not shown and between such valves there are side outlet valves one of which is valve  234  connected to line  236  that communicates with line  216 ′. Line  216 ′ can function as a production line. After all the packers or plugs are in receptacle  204 ′ or in the tank  230  through hose  228 , valves  226  and an inline valve in wellhead  206 ′ can be closed and valve  234  opened to communicate through lines  236  and  216 ′ to tank  230  or another location for storage of produced fluid that is not shown. In essence there is no or minimal delay between flowing the plugs or packers to the surface and clearing the borehole to the next step in getting production. The captured plugs or packers can be dealt with at a later time without delaying production and, of course avoiding the need to mill anything. It should be noted that the wellhead  206  in  FIG. 12  can be equipped in a similar way as in  FIG. 13  so that trapped packers or plugs in receptacle  204  can be isolated and the next step toward production initiated without delay or any milling. The captured plugs in receptacle  204  can be removed at a later time while production is on the way. The entire receptacle with the captured plugs or packers can be removed with a hoist or crane off of closed inline valves in wellhead  206 . 
         [0036]      FIG. 14  illustrates a capture assembly that can be located between a wellhead  206 ″ and one or more remotely actuated formation isolation valves such as  238 . Valves(s)  238  are typically full opening ball valves that can be remotely actuated in a number of known ways. A slotted liner  204 ″ has a closed top  208 ′. The slotted liner  204 ″ serves as a receptacle for the plugs or packers  200 ″ and  202 ″ and can be located in the blowout prevented in part or supported at another location below. An inlet guide cone  240  has openings  242  to allow flow to go into receptacle  204 ″ and out through its slots or to go in an annular space  244  around the outside of receptacle  204 ″ and onto the surface. While it is conceivable that production can begin with receptacle  204 ″ still in the hole, it will be clear that it is preferred to remove receptacle  204 ″ after closing formation isolation valve(s)  238  before production begins. Other enclosures different from a slotted liner are also contemplated. Basically cylindrically shaped enclosures big enough to accept the plug or packer without getting the plug or packer cocked inside are acceptable. There needs to be openings for sufficient flow to get the plugs or packers to releases in the first place and that condition needs to continue after some of the plugs or packers are captured. 
         [0037]      FIGS. 15-17  describe options for collecting borehole data from locations where plugs  300  are set. In  FIG. 15  there is a passage  302  through each plug which can be a location for data sensing and collecting module  304  placed there in a manner that still allows flow through passage  302  for rapid deployment of each plug  300 . Alternatively, module  304  can be incorporated into the body of each plug. As another alternative there may not even be a passage  302  or a seat  306  on which an object such as a ball  308  lands on. Instead, the plug body itself would contain the module  304  and when pressure is reduced above the plugs as described in detail above they are made to release and travel uphole where they can be recovered as also described above and the module  304  can then be connected to a processor that is not shown to collect the data in a format for analysis in aid of production which follows after a treatment as defined herein is completed. A host of properties can be sensed and collected over time such as temperature, formation properties such as porosity, pressure or viscosity to name a few examples. Alternatively module  304  can be in a recess  310  and held by a retainer  312  that is flush with the outer surface  314  of the object which is preferably a sphere. The same sensors could be used regardless of the location of the module  304  in the plugs  300  or the objects  308  landed on the plugs  300 , if used. 
         [0038]    There are alternative procedures for the data recovery from the modules  304 . In one option a plug  300  as described above, is set and an object  308  is landed on seat  306  for performance of a treatment. Subsequently another plug  300  is located further uphole and another object  308  is landed on that plug followed by a treatment further uphole. This process repeats until the entire interval is treated. After that the pressure uphole of all the plugs  300  is reduced and they release their grip as described above and flow toward the surface taking all the objects  308  with them. Regardless of whether the modules  304  are in the plugs  300  or the objects  308  they are all readily identifiable as to which plug  300  or object  308  they correlate to either by external markings or through stored data in module  304 . The data from each module can be correlated to a well depth in that manner. The plugs  300  and the associated objects  308  would typically come out and be collected in the reverse order from which they were introduced into the borehole but an opportunity for losing that order can occur at the surface so that they are tagged so that order can be recreated if necessary. 
         [0039]    As mentioned before the plugs  300  may be configured without passages but can still contain a module  304  in which case when all the plugs  300  are caused to release and flow to the surface the modules  304  will be recovered with the plugs  300 . 
         [0040]    In another possible method one plug  300  can be run in with a module  304  in it or alternatively with an object  308  preferably a ball with a module  304  delivered to the plug  300 . After treatment against a first plug  300  it can be caused to release to come to the surface, with a ball  308  if used, and a second plug  300  can be set further uphole and the process repeated. Alternatively, if a ball  308  is used with a plug  300  and the module  304  is in the ball  308  the ball can be recovered after treatment against first plug  300  without the first plug  300  by reducing pressure above ball  308  enough to bring up the ball but not so much as to release the plug  300 . 
         [0041]    The teachings of the present disclosure may be used in a variety of well operations. These operations may involve using one or more treatment agents to treat a formation, the fluids resident in a formation, a wellbore, and/or equipment in the wellbore, such as production tubing. The treatment agents may be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Illustrative treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, flow improvers etc. Illustrative well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding, cementing, etc. 
         [0042]    The above description is illustrative of the preferred embodiment and many modifications may be made by those skilled in the art without departing from the invention whose scope is to be determined from the literal and equivalent scope of the claims below: