Abstract:
In order to overcome the need to remove each fracturing plug after a plug and perforate operation it is desirable to utilize a profile latch in conjunction with a coupling profile. By having a profile in each coupling or at least in predetermined couplings a tool such as a perforating assembly including a fracturing plug may be precisely placed. A profile in the couplings also provides a means to latch the perforating assembly or other tool securely to the casing without using slips. Such profiles typically provide for securing the tool or perforating assembly in one direction although a particular profile may secure the assembly in place in two directions. By securing the tool or perforating assembly in one direction only the tool may be easily relocated or removed from the casing.

Description:
BACKGROUND 
     In the course of producing oil and gas wells, typically after the well is drilled, the well may be completed. In many instances, in order to complete the well the well may be cased. In certain instances the process of installing casing into the wellbore may begin with a cement float shoe threaded to a coupling and the coupling is threaded onto the first joint of casing. Typically, each joint of casing is about thirty feet long with a pin connection on each end. A coupling typically has a box connection on both ends. As the casing is lowered into the well a coupling is attached between each joint of casing to allow the joints of casing to be threaded together. 
     Once the casing is located at the appropriate position in the wellbore cement may be pumped into and down the interior of the casing. The cement may both anchor the casing into position as well as isolate the hydrocarbon bearing formation from another section of the same formation or from other formations that are penetrated by the same wellbore. Once the cement reaches the cement float shoe the cement flows out of the casing and then into the annular area outside of the casing between the casing and the wellbore. The cement is forced into the annular area generally until the annular area is filled with cement. Once an appropriate amount of cement is pumped into the casing a wiper plug may then be used push the cement out of the casing and to eliminate as much of the remaining cement as possible from the interior of the casing. 
     Generally the next step in completing the well, after the cement is allowed to set or cure is to form ports in the casing to allow the fluids from the formation into the interior of the casing. One of the current methods of forming the ports in the casing is known as plug and perforate. Typically, fracturing operations in oil and gas wells today involve fracturing plugs. Fracturing plugs are typically deployed on electric line in combination with perforating guns and a plug setting tool. The operator uses the weight of the fracturing plug, perforating guns, and plug setting tool to lower the assembly to the desired location in the well. For highly deviated and horizontal wells, gravity will not provide the assistance to move the assembly out in the horizontal lateral section, therefore many operators use a ‘pump-down’ technique where fluid is pumped into the well above the assembly thereby forcing the assembly into the well and while allowing the electric line to unspool. The operator monitors the length of electric line deployed to determine where the assembly and in particular the fracturing plug is located in the well. Once the assembly reaches the desired setting location, the surface pumps are stopped and the fracturing plug is set by sending an electric signal down the electric line which fires the setting tool. The setting process also releases the plug from the setting tool. 
     Once the fracturing plug is set within the wellbore, the operator may then perform a second operation to perforate the casing allowing access the adjacent formation. The perforating guns utilize specially designed explosives to perforate the casing allowing access to the adjacent formation above the fracturing plug&#39;s pre-determined location. After firing the perforating gun, the operator may move the perforating gun and setting tool up the casing and the perforating gun is again activated. The process may be repeated until all of the perforating gun&#39;s sections have been utilized. 
     After firing all of the desired sections of the perforating gun the operator typically retrieves the electric line and spent perforating guns. Once the electric line and spent perforating guns are removed from the wellbore the operator may then rig up the surface piping to conduct pressure fracturing operations through the new perforations and into the formation with the fracturing plug that was placed into the casing isolating that portion of the casing below the fracturing plug and allowing only the portion of the formation that was accessed by the perforating gun to be fractured 
     Formation fracturing occurs when the fracturing fluid, pressurized from surface using high-pressure pumps, creates a pressure greater than the natural reservoir pressure contained in the formation. This process is commonly known as ‘fracturing the well.’ The pressurized fluid will be diverted by the fracturing plug through the perforations in the casing, therefore the fracturing fluids will be forced out into the formation of interest. Fracturing the reservoir causes cracks and fissures to occur in the rock containing the hydrocarbon, and thus releases the oil or gas to flow into the well bore for easier production. 
     After fracturing the formation a new perforation assembly is run into the casing where the new fracturing plug is set above the section previously perforated and the entire process is repeated until the desired number of perforations has been completed and the associated portions of the formations have been fractured and treated. 
     Once the process is complete the fracturing plugs must be removed, typically by milling or drilling out each fracturing plug. It is not unusual for there to be ten or more fracturing plugs that must be removed before the well may be produced. Removing each fracturing plug by milling it out takes a substantial amount of rig time incurring substantial cost. Typically this is accomplished by running a motor and mill assembly on the bottom of either coil tubing or on threaded pipe. Each previously installed fracturing plug may be completely milled up, or removed, from the wellbore. The milling operation may be expensive and can sometimes cost hundreds of thousands of dollars to remove all of the plugs so the well can be placed into production. 
     SUMMARY 
     It may be desirable to be able to remove the fracturing plugs from the casing without milling out each fracturing plug. It is also desirable to anchor a fracturing plug or other wellbore device in the casing without slips that may damage the interior surface of the casing. 
     By having a coupling with a particular profile in the internal diameter the fracturing plug may be precisely located during the initial fracturing process. Additionally, in the event the operator desires to re-fracture the well the same profile may be used, again precisely locating the fracturing plug. Each desired coupling profile could be an individual profile allowing only a particular fracturing plug to locate at into the particular coupling profile. 
     In another embodiment using multiple couplings, each having the same profile but located along the tubing string at each desired location would allow each fracturing plug to be located at a different location without requiring a particular coupling with a particular profile to be located consuming undue costs or time. Thereby allowing the operator to have only a single type of profiled coupling and a single type of fracturing plug at the wellsite. 
     In certain instances the operator may not locate a coupling profile in each coupling but may spread those couplings with a profile over the length of the tubing string interspersing non-profiled couplings in between. 
     The coupling profiles are preferably used for both locating the fracturing plug but also as a means for securing the fracturing plug in the casing or tubing. While the preferred embodiment utilizes a fracturing plug the profiles could be used to secure any equipment that the operator desires in the casing or tubing assembly. Additionally while the preferred embodiment utilizes a profile in a coupling it would also be possible to locate a profile in any or all of the casing joints. 
     In one embodiment of the present invention profile latch for locking into a casing coupling may be provided where a casing assembly may have at least two casing joints and at least one casing coupling. The casing coupling may have at least one profile where the profile latch may have at least one dog corresponding to the profile to lock into the profile. The dog is locked into the profile by a cam. The profile may be at least partially circumferential or it may include at least one longitudinal slot. The profile may have a lower surface perpendicular to the longitudinal axis of the coupling. The dog may have a lower surface and the profile may have a lower surface each having an angle that cooperate to apply a radially outward force to the dog when a down force may be applied to the dog. The dog may have an upper surface and the profile may have upper surfaces each having angles that cooperate to apply a radially inward force to the dog when an upward force may be applied to the dog. 
     In another embodiment of the present invention a method may be provide to lock a profile latch into a coupling. The method provides for assembling a casing assembly, where the casing assembly may have at least two casing joints and at least one casing coupling. The casing coupling may have at least a first and a second profile and the second profile may be located above the first profile. The casing assembly may be run into a wellbore and then cemented into the wellbore. Next a profile latch may be run into the casing assembly. The profile latch may have at least one dog corresponding to the profile to lock into the first and the second profile. The profile latch may be then located adjacent the first profile after which the profile latch may be locked into the first profile. An upwards force may be applied to the profile latch to release the profile latch from the first profile after which the profile latch may be moved from the first profile to the second profile. The profile latch may then be locked into the second profile. An upwards force may be applied to the profile latch to release the profile latch from the second profile after which the profile latch may be retrieved from the casing assembly. The first and the second profiles may be at least partially circumferential and may include at least one longitudinal slot. The first profile and the second profile correspond to the same profile latch. The first and the second profiles may have a lower surface perpendicular to the longitudinal axis of the coupling. The dog may have a lower surface and the first and the second profiles each may have a lower surface having an angle that cooperate to apply a radially outward force to the dog when a down force is applied to the dog. The dog may have an upper surface and the first and the second profiles each may have an upper surface having an angle that cooperate to apply a radially inward force to the dog when an upward force is applied to the dog. 
     In another embodiment of the present invention a method is provided to lock a profile latch into a coupling. The method provides for assembling a casing assembly, where the casing assembly may have at least three casing joints and at least a first casing coupling and a second casing coupling. The first casing coupling may have a first profile and the second casing coupling may have a second profile. The second profile may be located above the first profile. The casing assembly may be run into a wellbore and then cemented into the wellbore. A first profile latch may be run into the casing assembly where the first profile latch may have at least one first dog corresponding to the first profile to lock into the first profile. The first profile latch may be located adjacent the first profile and then locked into the first profile. A second profile latch may be run into the casing assembly where the second profile latch may have at least one second dog corresponding to the second profile to lock into the second profile. The second profile latch may be located adjacent the second profile and then locked into the second profile. The first profile may be at least partially circumferential. The second profile may be at least partially circumferential. The first profile or the second profile include at least one longitudinal slot. The first profile may have a lower surface perpendicular to the longitudinal axis of the casing assembly. The second profile may have a lower surface perpendicular to the longitudinal axis of the casing assembly. The first dog and the second dog each may have a lower surface and the first profile and the second profile each may have a lower surface having an angle that cooperate to apply a radially outward force to the first dog or the second dog when a down force is applied to the first dog or the second dog. The first dog and second dog each may have an upper surface and the first profile and second profile each may have an upper surface each having an angle that cooperate to apply a radially inward force to the first dog or the second dog when an upward force is applied to the first dog or the second dog. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  depicts a cemented wellbore with couplings connecting the casings joints and a perforating gun, a setting tool, and a fracturing plug located in the casing. 
         FIG. 2  depicts a coupling profile located on the couplings interior surface. 
         FIG. 3  depicts a first coupling and a second coupling each having an interior surface. 
         FIG. 4  depicts a perforating assembly located adjacent to a coupling profile but not yet actuated. 
         FIG. 5  depicts a close up of the coupling profile and profile latch, not yet actuated. 
         FIG. 6  depicts a perforating assembly located adjacent to a coupling profile but not yet actuated. 
         FIG. 7  depicts a close up of the coupling profile and profile latch, not yet actuated. 
     
    
    
     DETAILED DESCRIPTION 
     The description that follows includes exemplary apparatus, methods, techniques, and instruction sequences that embody techniques of the inventive subject matter. However, it is understood that the described embodiments may be practiced without these specific details. 
       FIG. 1  depicts a completion where a wellbore  10  has been drilled through one or more formation zones  18 . A casing assembly  12 , consisting of casing joints  16  and couplings  14  may be run into the wellbore  10 . Typically the casing assembly  12  is made up on the surface  20  with a cement float shoe  22  on the lower end of the casing assembly  12 . The casing assembly  12  is then lowered into the wellbore  10  by the rig  30  until the desired depth is reached. 
     Upon reaching the desired depth, cement  24  is pumped from the surface  20  through the interior of the casing assembly  12 , out of the cement float shoe  22 , and into the annular area  26  formed between the casing assembly  12  and the wellbore  10 . Once a predetermined amount of cement  24  is pumped into the casing assembly  12  at the surface  20  a wiper plug may be pumped down through the casing assembly  12  to push the cement out of the casing assembly  12  and into the annular area  26 . Upon setting or curing the cement  24  may anchor the casing assembly  12  into position. The cement may also longitudinally isolate various formations  18  or portions of a formation  18  from one another. 
     Typically after the casing assembly  12  has been cemented into place a perforating assembly  40  may be run into the casing assembly  12  on e-line  50 . The perforating assembly  40 , typically has a fracturing plug  42  on the lower end, a setting tool  44  just above the fracturing plug  42 , and a multi-stage perforating gun  46  just above the setting tool  44 . Once the perforating assembly  40  is properly located power is supplied via the e-line  50  to the setting tool  44  to set the fracturing plug  42 . 
     Provided that the perforating assembly  40  is properly located, when the setting tool  44  is actuated the setting tool  44  causes dogs in the fracturing plug  42  to move outwards to engage the appropriate profile in the interior of the appropriate coupling  14  locking the fracturing plug  42  to the coupling  14 . At the same time the setting tool causes the fracturing plug  42  to longitudinally compress sealing the interior of the casing assembly  12  against fluid flow past the fracturing plug  42 . The dogs may be any type of device that may transition between a radially outward position to lock the fracturing plug or profile latch in place thereby preventing further downward travel of the fracturing plug or profile latch and a radially inward position unlocking the fracturing plug or profile latch to allow either upwards or downwards movement. Such dogs include collets, snap rings, cams, and fingers. 
     As shown the setting tool  44  may then be disconnected from the fracturing plug  42  so that the remainder of the bottom hole assembly  40 , the setting tool  44  and the multi-stage perforating gun  46  may be raised to the desired location and power supplied to the first stage of the multi-stage perforating gun  46  so that the first stage may be discharged to form ports through the casing  16  and the cement  24  providing access to formation  18 . The multi-stage perforating gun  46  may then be moved some distance and the next stage of the multi-stage perforating gun  46  is discharged. The process may be repeated until all of the stages of the multi-stage perforating gun  46  have been discharged. 
     Typically, once the desired stages of the multi-stage perforating gun  46  have been discharged, the setting tool  42  and the now discharged multi-stage perforating gun  46  are raised to the surface  20 . A second or a reloaded multi-stage perforating gun  46  and a second or a reloaded setting tool  44  may then be lowered or pumped back down through the casing assembly  14  until the second setting tool lands on the fracturing plug  42 . Upon landing on the fracturing plug  42  the setting tool  44  locks to the fracturing plug allowing the operator to exert upward force on the fracturing plug  42  causing the dogs in the fracturing plug  42  to release and allowing the entire perforating assembly  40  to be raised to the next location to be fractured or treated. Upon reaching the next location to be fractured or treated the now recharged or replaced setting tool  44  is actuated. The setting tool  44  causes dogs in the fracturing plug  42  to move outwards to engage the appropriate profile in the interior of the appropriate coupling  14  locking the fracturing plug  42  to the coupling  14 . At the same time the setting tool  44  causes the fracturing plug  42  to longitudinally compress sealing the interior of the casing assembly  12  against fluid flow past the fracturing plug  42 . The process is then repeated until each desired formation zone  18  has been fractured or treated. 
     In another embodiment the setting tool  44  may remain attached to fracturing plug  42 . The perforating gun  46  and the setting tool  44  may be spaced apart so that upon power being supplied to the perforating gun  46  the perforating gun  46  may be discharged to form ports through the casing  16  and the cement  24  providing access to formation  18 . The formation may then be fractured while leaving the perforating gun  46 , the setting tool  44 , and the fracturing plug  42  in place. After the fracturing or treating operation is complete the perforating assembly may be raised causing the dogs in the fracturing plugs to release and allowing the entire assembly to be raised. 
     In another embodiment after the treating or fracturing operation is complete a fracturing plug  42  may remain in place at certain locations in the wellbore  10 . With a fracturing plug  42  the well cannot be produced from any formation below the fracturing plug  42  as the inflow of fluids, including hydrocarbons, from the formation  18  is blocked by the fracturing plugs  42  that remain locked to the coupling profiles thereby blocking fluid flow in both directions. The operator will typically run back into the casing assembly  14  with retrieving tool to lock into the upper end of the fracturing plug  42 . Once the retrieving tool is locked into the fracturing plug  42  upward force may be applied to release the dogs and the sealing element thereby allowing the fracturing plug  42  free movement through the casing assembly  12 . 
     Typically, each fracturing plug has a latch profile on its upper end to allow a setting tool or any other tool with the appropriate profile to lock in to the fracturing tool  42 . Additionally each fracturing tool  42  may also have the appropriate latch profile on its lower end to allow a fracturing plug  42  higher in the well to be lowered to the next lower fracturing plug  42  and lock in to the next lower fracturing plug  42 . When upward force is exerted on the next lower fracturing plug said fracturing plug will be released to move through the casing assembly with the higher fracturing plug. In this manner all of the remaining fracturing plugs may be released from the well in a single trip. 
       FIG. 2  depicts a coupling  51  having a profile  52  located on the interior surface  54  of coupling  51 . The coupling has a first box end  56  and a second box end  60  so that a first casing joint  62  having a first pin end  64  and a second casing joint  68  having a second pin end  66  may be threadedly attached to the coupling  51  where the first pin end  64  is threaded in to the first box end  56  and the second pin end  66  is threaded in to the second box end  60 . In this case the profile consists of three grooves  52 A,  52 B, and  52 C. 
       FIG. 3  depicts a first coupling  100  and a second coupling  102  each having an interior surface  104  and  106  respectively. At least one joint of casing  108  separates the couplings  100  and  102  although any number of casing joints could be between the couplings  100  and  102 . In the instance that multiple casing joints are used a coupling would be needed between each casing joint, although each coupling would not necessarily have a profile in its interior. As depicted couplings  100  and  102  have different internal coupling profiles. Coupling  100  has a profile with two circumferential grooves  110  and  112  while coupling  102  has a profile with three circumferential grooves  114 ,  116 , and  118 . By utilizing couplings  100  and  102 , each having a different profile, a fracturing plug or other tool may be set at a particular point in the casing assembly so long as the fracturing plug or other tool is provided with a locking profile or set of dogs that correspond to the particular coupling profile where the tool is to be latched. In this case a fracturing plug having a three dog locking profile would pass by coupling  100  without latching into the circumferential grooves  110  and  112  but would continue downhole to coupling  102  where the fracturing plug would be able to lock in to the corresponding circumferential grooves  114 ,  116 , and  118 . A following fracturing plug or other tool may then utilize the coupling  100  and latch into grooves  110  and  112 . While the profiles depicted are circumferential grooves, any type or combination of profiles may be utilized, including but not limited to one or more circumferential grooves, partially circumferential grooves, offset partially circumferential grooves, slots, or any combination thereof. 
       FIGS. 4 ,  5 ,  6 , and  7  depict a perforating assembly  200  in its run in condition and in its set condition.  FIG. 4  depicts a fracturing plug  210 , a setting tool  212 , a multi-stage perforating gun  214 , and a profile latch  216  run into a casing assembly  220  on an electric line  218 . The casing assembly  220  has at least one casing joint  222 , a profile coupling  224 , and an interior passage  226 . The profile latch  216  has a male retrieving latch  221  on its lower end so that upon being released from the profile coupling  224 , it may be lowered to latch into a matching female retrieving latch on the upper end of a second profile latch that may remain lower in the wellbore. Typically, each profile latch will be retrieved by the setting tool  212  that is run into the wellbore with the profile latch  216 . Typically each setting tool  212  has a male retrieving latch on its lower end that mates with the female retrieving latch in each profile latch to allow the setting tool  212  to actuate and retrieve each profile latch  216 . 
     As can be seen more readily in  FIG. 5 , which is area A of  FIG. 5 , the profile coupling  224  has three circumferential grooves  230 ,  232 , and  234 . In this instance the profile latch  216  has three dogs  240 ,  242 , and  244  that are located adjacent to circumferential grooves  230 ,  232 , and  234 . Upon a signal from the operator the setting tool  212  will fire to actuate the sealing assembly in the fracturing plug  210 , the dogs  240 ,  242 , and  244  in the profile latch  216 , and to disconnect the setting tool  212  from the fracturing plug  210  and the profile latch  216 . 
       FIG. 6  depicts the perforating assembly  200  after the setting tool  212  has been actuated. The setting tool  212  is disconnected from the fracturing plug  210 , the fracturing plug  210  is sealing the interior  70  of the casing assembly  10 , and the profile latch  216  is engaged with the matching profile coupling  224 . 
     As can be more readily seen in  FIG. 7 , which is area B from  FIG. 6 , with the fracturing plug  210  set the sealing element  250  is forced radially outward as the sealing element  250  is longitudinally compressed. The sealing element  250  is extruded radially outward until it contacts the casing assembly  10  to seal the interior of the casing assembly against fluid flow past the sealing element  250 . Additionally the dogs  240 ,  242 , and  244  in the profile latch  216  are moved outward to engage the circumferential grooves  230 ,  232 , and  234  in the profile coupling  224 . Rod  252  is attached to each dog  240 ,  242 , and  244 . As the rod  252  moves downwards each dog  240 ,  242 , and  244  is rotated about a pivot point  254 ,  256 , and  258  such that the outer surface of each dog  240 ,  242 , and  244  engages each circumferential groove  230 ,  232 , and  234 . The lower surface  260 ,  262 , and  264  of each circumferential groove  230 ,  232 , and  234  is generally perpendicular to the longitudinal axis of the casing assembly  10  so that the matching surface  270 ,  272 , and  274  on the lower end of each dog  240 ,  242 , and  244  will resist further downward movement of the fracturing plug  210  and profile latch  216  when pressure is applied against the fracturing plug. 
     In some instances the lower surface  260 ,  262 , and  264  of the grooves  230 ,  232 , and  234 , respectively, may have an angle such as angle  310  that is an acute angle. Each lower surface  312 ,  314 , and  316  of dogs  240 ,  242 , or  244 , respectively, corresponding to each groove  230 ,  232 , and  234  may have an angle  310  that is acute to the longitudinal axis of the casing assembly. With at least one groove  230 ,  232 , and  234  having an angle  310 , such that as a corresponding dog  240 ,  242 , and  244  is forced downward by pressure applied from above, such as hydraulic fracturing pressure, the dogs  240 ,  242 , and  244  will be forced radially outward further locking the fracturing plug  210  and the profile latch  216  in position. 
     In the embodiment depicted the upper surface  280 ,  282 , and  284  of each circumferential groove  230 ,  232 , and  234  is generally angled so that when force is applied in the upwards direction the angled upper surfaces  280 ,  282 , and  284  will tend to force the dogs  240 ,  242 , and  244  to move inwards releasing the profile latch  216  as well as the fracturing plug  210  so that both the fracturing plug  210  and the profile latch  216  may be moved upwards to the next location or removed from the well. 
     Bottom, lower, or downward denotes the end of the well or device away from the surface, including movement away from the surface. Top, upwards, raised, or higher denotes the end of the well or the device towards the surface, including movement towards the surface. While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible. 
     Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.