Abstract:
Embodiments of the present invention generally relate to methods and apparatuses for gripping and shearing a downhole cable. In one embodiment, a line cutter mandrel includes: a tubular mandrel; a pocket disposed along an outer surface of the mandrel and longitudinally coupled to the mandrel; a channel disposed through the pocket for receiving a cable; and a line cutter. The line cutter includes a blade, is operable to engage an outer surface of the cable in a gripping position, is operable to at least substantially sever the cable with the blade in a cutting position, and is operable from the gripping position to the cutting position by relative longitudinal movement between the cable and the pocket.

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     Embodiments of the present invention generally relate to methods and apparatuses for gripping and shearing a downhole cable. 
     2. Description of the Related Art 
       FIG. 1  is a longitudinal sectional view of a subterranean wellbore  5 . After the wellbore  5  has been drilled through a hydrocarbon-bearing formation, i.e., crude oil and/or natural gas, the wellbore  5  may be completed by running in a string of casing  10  which may be cemented  40  in place. Thereafter, the casing  10  may be perforated  45  to permit the fluid hydrocarbons  2  to flow into the interior of the casing  10 . The hydrocarbons  2  may be transported from the production zone of the wellbore  5  through a production tubing string  15  which is concentrically disposed relative to the casing. An annulus  35  defined between the casing  10  and the production tubing  15  may be isolated from the producing zone with a packer  30 . One or more blowout preventers  25  may be provided in the wellhead  20  to shut-in the wellbore  5  in an emergency. 
     An instrumentation sub  50  may be assembled with the production tubing  15  and in data communication with the surface via a cable  55  extending to the surface along an outer surface of the production tubing  15 . The instrumentation sub  50  may include pressure sensor, a temperature sensor, and/or a flow meter which provides useful data to the surface operator in producing the wellbore. The instrumentation sub  50  may be electrical or optical and the cable  55  may be correspondingly electrical or optical. Alternatively or additionally, a hydraulically operated valve (not shown) may be assembled with the production tubing and the cable may instead be or additionally include hydraulic tubing extending to the surface for control of the valve by the surface operator. 
     It may become desirable to cut the production tubing  15  at a predetermined depth in the wellbore, such as after depletion of the production zone or failure of downhole equipment. Typically a tubing cutter is lowered into the production tubing  15  until the tubing cutter reaches the predetermined depth. The tubing cutter may then be operated to cut or score the production tubing. However, the tubing cutter is unable to cut the cable  55 . Once the production tubing is cut or scored, the production tubing may be placed in tension from the surface (thereby severing the production tubing at the score if it is not already cut). Since the cable  55  has not been cut, the cable may also be broken. However, it is unlikely that the cable  55  will break at or near the predetermined depth. If the cable breaks at a substantial length above the predetermined depth, then a nest of cable will remain once a portion of the production tubing above the predetermined depth is removed from the wellbore, thereby obstructing future wellbore operations. 
     SUMMARY OF THE INVENTION 
     Embodiments of the present invention generally relate to methods and apparatuses for gripping and shearing a downhole cable. In one embodiment, a line cutter mandrel includes: a tubular mandrel; a pocket disposed along an outer surface of the mandrel and longitudinally coupled to the mandrel; a channel disposed through the pocket for receiving a cable; and a line cutter. The line cutter includes a blade, is operable to engage an outer surface of the cable in a gripping position, is operable to at least substantially sever the cable with the blade in a cutting position, and is operable from the gripping position to the cutting position by relative longitudinal movement between the cable and the pocket. 
     In another embodiment, a method of cutting a production tubing string includes running a cutting tool into the production tubing string. The production tubing string is disposed in a wellbore and includes a line cutter mandrel. The method further includes operating the cutting tool, thereby at least scoring the production tubing string; and pulling on an upper portion of the production tubing string, thereby operating a line cutter mandrel and at least substantially severing a cable or hydraulic tubing extending along an outer surface of the production tubing string. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
         FIG. 1  is a longitudinal sectional view of a subterranean wellbore. 
         FIG. 2  is an isometric view of a line cutter mandrel, according to one embodiment of the present invention.  FIG. 2A  is an internal view of the line cutter in a gripping position.  FIG. 2B  is an internal view of the line cutter in the closed or cutting position. 
         FIG. 3  is a cross section of a radial cutting torch (RCT). 
         FIG. 4  illustrates a tubing cutting operation utilizing the line cutter mandrel, according to another embodiment of the present invention.  FIG. 4A  is an enlargement of a portion of  FIG. 4 .  FIG. 4B  illustrates the RCT scoring the production tubing.  FIG. 4C  illustrates retrieval of the production tubing to the surface and operation of the line cutter mandrels. 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 2  is an isometric view of a line cutter mandrel  200 , according to one embodiment of the present invention. The line cutter mandrel  200  may include a mandrel  205 , a pocket  210 , and one or more line cutters  215 . The mandrel  205  may be tubular and have threaded longitudinal ends for assembly as part of the production tubing string  15 . The mandrel  205  may be a standard joint of production tubing. The pocket  210  may be tubular and disposed along an outer surface of the mandrel  205 . The pocket  210  may surround the outer surface and be longitudinally and rotationally coupled to the mandrel  205 , such as by welding. Alternatively, the pocket  210  may be rotatable relative to the mandrel  205  and longitudinally coupled to the mandrel. The pocket  210  may have a channel formed longitudinally through an outer surface for receiving the cable. The pocket may also have a recess  220 r formed in an outer surface for receiving the line cutter  215 . The recess  220   r  may have one or more threaded holes formed in an outer surface for receiving corresponding threaded fasteners  230 . The line cutter  215  may be configured so that an outer surface is flush, substantially flush, or slightly sub-flush with the pocket outer surface. Although only one line cutter  215  is shown, a plurality, such as two to six, of line cutters may be disposed circumferentially around the pocket  210 . 
       FIG. 2A  is an internal view of the line cutter  215  in a gripping position. The line cutter  215  may include a body  225 ; one or more blade actuators, such as cams  235 ; one or more biasing members or springs, such as coil springs  245 ; and one or more blades  250 . The body  225  may have a channel  225   c  formed longitudinally through an inner surface for receiving the cable  55 . The body may have a substantially solid outer surface for enclosing the recess  220   r , thereby retaining the cable  55 . The body  225  may also have a recess  225   r  formed in an inner surface for receiving the cams  235  and the springs  245 . The body may also have a window  225   w  formed therethrough for pressure equalization. Each cam  235  may be pivoted to the body  225  by a respective fastener, such as a pin  240 . Each pin  240  may be disposed through a respective hole formed through the body  225 , such as by a press fit. Each spring  245  may be pivoted to a respective cam  235  and the body  225 . Each spring  245  may bias a respective cam  235  into the gripping position such that a first surface  235   a  of the cam is engaged with a wall of the recess  225   r.    
     A second surface  235   b  of each cam  235  may be frictionally engaged with an outer surface of the cable  55 , thereby longitudinally coupling each cam with the cable  55 . Each blade  250  may be received by a respective opening longitudinally formed through a respective cam  235  at the second surface  235   b . Each blade  250  made be press fit into the respective opening such that a tooth or point of the blade extends from the second surface. Each blade  250  may be made from a hard metal, alloy, ceramic, or composite, such as tungsten carbide, tool steel, or a nickel alloy. Material selection may depend on factors, such as corrosiveness of the wellbore and a hardness of a jacket of the cable  55 . A hardness of the blade material may be substantially equal to, greater than, or substantially greater than a hardness of the cable jacket (or tubing wall if the cable  55  is instead hydraulic tubing as discussed above). 
       FIG. 2B  is an internal view of the line cutter  215  in the closed or cutting position. Longitudinal movement of the line cutter mandrel  200  upward, or toward the surface, relative to the cable  55  causes pivoting of the cams  235  relative to the body  225  and against the bias of the springs  245 . The cams  235  pivot until a third surface  235   c  engages a wall of the recess  225   r . As the cams  235  pivot toward the cutting position, each blade  250  engages the outer surface of the cable  55  and penetrates through a respective half of the cable until the blades are in close proximity with each other in the cutting position. Once the cutting position is reached, the cable  55  has been substantially or entirely severed. Each second cam surface  235   b  may be longitudinally curved so that each second surface remains in frictional engagement with the cable  55 . Each second cam surface  235   b  may also be curved along a thickness corresponding to the curvature of the cable  55  so that the second cam surfaces substantially surround the cable in the cutting position. Each blade may be straight or substantially straight along a thickness so as to sever or substantially sever the cable  55 . The cam thickness and/or blade thickness may be slightly greater than a diameter of the cable  55 , such as one-eighth to one-half inch. 
     When running the production string  15  in the wellbore  5  with the cable  55  (and/or hydraulic tubing), the mandrel  205  and pocket  210  may be conventionally added to the production tubing string  15 . The cable  55  may be fed from a spool along the production tubing string  15 . The cable  55  may be pressed into the channel  225   c  and between the cams  235 . The line cutter  215  may then be fastened to the pocket  210  using the fasteners  230  while placing the cable  55  in the channel  220   c . Provision of additional line cutters  215  around the pocket  210  may be beneficial as an orientation of the line cutter  215  may be unknown due to threaded makeup of the mandrel  205  with the production tubing  15 . If multiple line cutters  215  are used, then the cable  55  may be run through the line cutter in closest alignment with the existing cable path along the production tubing string  15 . Alternatively, the pocket  210  may have multiple recesses and the line cutter may be fastened into the recess closest to the cable path after the mandrel  205  is added to the production tubing string  15  or, as discussed above, the pocket may be rotatable relative to the mandrel. The process may be repeated for additional cables and/or hydraulic tubing lines being run. 
     The location of the line cutter mandrel  200  in the production tubing string  15  may be proximately or distally below the planned depth where the production tubing string  15  would later be cut or scored. For example, referring to  FIG. 1 , the line cutter mandrel  200  may be placed proximately above the instrumentation sub  50 . This placement would allow the production tubing  15  to be cut/scored at a depth almost anywhere above the instrumentation sub with the assurance that that the cable  55  would be cut below the depth of the tubing cut. If multiple tools having cables/hydraulic lines extending to the surface are deployed in the production tubing  15 , then the line cutter mandrel  200  may be placed above the tool closest to the surface. Alternatively, the line cutter mandrel  200  may be at or proximately above the planned depth where the production tubing string  15  would later be cut or scored. 
     Additionally, a second line cutter mandrel  200   b  may be assembled with the production tubing string  15 . The first line cutter mandrel  200   a  may be placed above the planned production tubing cut depth and the second line cutter mandrel below the planned depth so that the line cutter mandrels  200   a, b  straddle the planned cut depth. One of the line cutter mandrels  200   a, b  may be bladeless and the other may include the blades  250  or both of the mandrels may include the blades  250 . Further, additional line cutter mandrels  200  may be spaced along the production tubing string at regular intervals, such as every 1,000 feet. 
       FIG. 3  is a cross section of a radial cutting torch (RCT)  300 . The RCT  300  may be used to score or sever the production tubing  15  by deployment from the surface with a wireline  307 . The RCT  300  may include an igniter  301 , a combustor  302 , and an anchor  303 . Igniter  301  may include a tubular housing  305  which may include an upper portion and a lower portion. The housing upper portion may have a shoulder at its lower end. The housing lower portion and may be threadedly connected to the shoulder. A passageway may be defined in the housing lower portion and may receive a squib  306 . Squib  306  may be ignited by an electric current, which is carried through electric conductors leading from the earth&#39;s surface down through the wireline  307  into the housing  305 . The electric current may be passed from the housing  305  to squib  306  by an electrode plug  304 , a brass prong  308 , a steel conductor  309  and a spring  310 . 
     Plug  304  may be threadedly connected in the interior of upper housing with one or more O-ring seals mounted on the plug to prevent the passage of fluids between housing upper portion and lower portion. Steel conductor  309  may include a generally flat head portion facing toward squib  306  and a stem portion extending away from head portion on the side opposite of squib  306 . Spring  310  may be disposed between steel conductor  309  and a shoulder on housing lower portion to urge brass prong  308  into engagement with plug  304 . A nut  311  may be threadedly connected to conductor stem portion and an insulating washer  312  to prevent a short of the electric current is disposed around conductor stem portion between nut  311  and upper housing shoulder. 
     The combustor  302  may be threadedly connected to the lower housing. Combustor  302  may include an elongated tubular sleeve  313 . The sleeve  313  may define a chamber for receiving solid combustible pyrotechnic material  314  to provide a pipe cutting flame of sufficient duration to cut or score production tubing  15 . Internal threads may be formed along an inner surface of the sleeve  313 . The combustible, pyrotechnic material  314  may be compressed into pellets of a generally donut configuration so as to permit stacking the housing  313  chamber. The combustible material  314  may be a mixture of a metal or alloy and a metal or alloy oxide, such as thermite. The hole in each pellet  314  may be coaxially aligned with the squib  306 . Loosely packed combustible material  315 , which may be the same material used in forming pellets  314 , may be disposed within the holes of pellets  314  such that each pellet  314  becomes ignited from loosely packed combustible material  315  after ignition by squib  306 . 
     A head  317  may be from heat resistant material. The head  317  may be disposed within the sleeve  313  and have a plurality of passageways, i.e., two to eight, disposed equidistant from one another around the edge, that extend longitudinally. An inner portion of the head  317  may be conical to direct the pipe cutting flame into mouths of plurality of the shield passageways. A spindle  319  may connect head  317  to sleeve  313 . The spindle  319  may have threaded portion to connect to internal threads of sleeve  313 . The spindle  319  may include a passageway aligned with each head passageway and lined with a liner  320  made of heat resistant material. The spindle  319  may extend downwardly away from head  317  and have a second threaded portion. A retainer  321  may lock spindle  319  to sleeve  313 . Retainer  321  may be an annular member, made of heat resistant material, and define a passageway aligned with each spindle passageway. A diverter  322  may be constructed from heat resistant material to direct the pipe cutting flame from a longitudinal direction to a radial direction toward the production tubing  15 . The diverter  322  may include a truncated cone-like portion disposed adjacent the retainer body  321  to form a shoulder. The diverter  322  may further include a cylindrical portion extending downwardly away from the cone-like portion. The diverter  322  may further include a passage to receive the spindle  319 . 
     A mandrel  316  may secure the diverter  322  to retainer  321 . The mandrel  316  may include a threaded passage for engaging the spindle  319 . The mandrel  316  may include a shoulder formed in an outer surface. A cover  323  may prevent foreign matter from entering the diverter  322 . The cover  323  may extend between the mandrel  316  and the sleeve  313 . The sleeve  313  may include a recess formed in an outer surface for receiving the cover  323  so that a smooth outer surface is maintained along the RCT  300 . The cover  323  may include an inwardly extending annular shoulder to engage the mandrel shoulder. An O-ring seal may be provided in the sleeve  313  recess and an O-ring seal may be provided on the mandrel  316  facing the cover shoulder. 
     The anchor  303  may include an elongated tubular body  324 . The anchor body  324  may be threadably connected to the mandrel  316  via a threaded pin  325 . The outer diameter of anchor body  324  may be substantially equal or equal to the outer diameter of the sleeve  323  and housing  305  so that a diameter of an annulus  328   a  formed between the sleeve/housing and production tubing  15  may be substantially equal to a diameter of an annulus  328   b  formed between the anchor body  324  and the production tubing  15 . The overall length of anchor body  324  may be equal to or substantially equal to the overall length of the sleeve/housing so that a volume of the annulus  328   a  may be equal to or substantially equal to a volume of the annulus  328   b . The anchor  303  may further include a centralizer body  326  threadedly connected to the anchor body  324 . A plurality of arms  327  may radially extend from the centralizer body  326  into engagement with an inner surface of the production tubing  15 . Each of the arms may include a spring-loaded telescopic assembly. 
     In operation, RCT  300  may be lowered down into production tubing  15  with wireline  307  to the location where production tubing  15  is to be cut. Electric current may be passed from the surface of the earth through the wireline  307  to the squib  306 , thereby igniting the loosely packed material  315  which in turn ignites the pellets  314 . A pipe cutting flame is generated and directed radially against the production tubing  15 . The pipe cutting flame is directed by conical head  317  into head and spindle passageways, and onto the diverter  322 . Cover  323  may be propelled downwardly along the mandrel  316  as the pipe cutting flame generates sufficient pressure to act on the cover shoulder, thereby exposing the diverter  322  to the production tubing  15 . The pipe cutting flame passes outwardly of the diverter and contacts and cuts, substantially cuts, or scores the production tubing  15 . 
     Scoring the production tubing  15  rather than completely cutting the production tubing  15  may be beneficial to prevent damage to the casing  10 . During the cutting or scoring procedure, residual gas may be produced and flow within the annuli  328   a, b . As volumes of the annuli  328   a, b  may be equal or substantially equal, the resulting downward force of the gas above the diverter  322  may be equal or substantially equal to the upward force of gas below the diverter  322  thereby maintaining the RCT  300  in a stable condition within the production tubing  15 . 
     In another embodiment, a slickline battery firing system may be employed in lieu of the electric line firing system to energize the igniter  301  so that slickline may be used to deploy the RCT  300  instead of wireline. This alternative may include a slickline cable head which is connected to a pressure firing head. The pressure firing head may include a metal piston having a larger diameter head with a smaller diameter metal rod extending downward from the bottom of the larger diameter head. The piston may be slidably located in a hollow cylinder. A spring surrounding the rod may be employed to provide upward pressure against the under side of the larger diameter head. The spring may be adjustable to allow for hydrostatic compensation of well fluids so that the system does not fire at bottom hole pressure. When the piston is moved downward the lower end of the rod will make contact with an electrical lead from the battery pack and an electrical lead coupled to one side of the igniter to discharge current to the igniter  301 . Fluid ports may extend through the wall of the cylinder above the larger diameter piston head. When the modified RCT is in place, a pump at the surface may increase the fluid pressure in the production tubing, thereby moving the piston downward against the pressure of the spring to allow the rod to make electrical contact with the leads to energize the igniter. Alternatively, instead of a battery, a percussion cap may be used to ignite the material  315 . The percussion cap may be operated by the piston. 
     Also a coiled tubing percussion firing system may be employed in lieu of the electric line firing system to ignite the charges material  315 . This system may include coiled tubing for supporting the modified RCT connected to a connector subassembly which connects to a pressure firing head which may include a hollow cylinder which supports an interior piston by shear pins. The coiled tubing may be coupled to the interior of the cylinder at its upper end. A firing pin may extend from the lower end of the piston. When the apparatus is at the desired cutting depth, fluid pressure may be increased within the coiled tubing which shears the shear pins driving the firing pin into a percussion cap to ignite the material  315 . 
     Alternative embodiments of the RCT are discussed in U.S. Pat. Nos. 4,598,769 and 6,971,449, which are hereby incorporated by reference in their entireties. 
     Alternatively, a jet cutter or chemical cutter may be used instead of the radial cutting torch. A jet cutter may include a circular shaped explosive charge that severs the tubular radially. A chemical cutter may include a chemical (e.g., Bromine Triflouride) that may be forced through a catalyst sub containing oil/steel wool mixture. The chemical may react with the oil and ignite the steel wool, thereby increasing the pressure in the tool. The increased pressure may then push the activated chemical through one or more radially displaced orifices which direct the activated chemical toward the inner diameter of the tubular to sever or score the tubular. Such a chemical cutter is disclosed in U.S. Pat. No. 4,250,960, which is hereby incorporated by reference in its entirety. 
     Alternatively, a motorized cutting tool (MCT) may be used instead of the RCT. A motorized cutting tool may include a pump in fluid communication with hydraulically extendable anchors and one or more hydraulically extendable blades and a motor for rotating the blades. Alternatively, the anchors may be extended by an electric motor. The MCT may be deployed into the production tubing via wireline. Electric current may be delivered to the MCT, thereby operating the pump to extend the anchors and the blade into engagement with the production tubing and the motor to rotate the blade until the production tubing has been scored or cut. The MCT may be used to cut the production tubing  15  without risk of damage to the casing  10 . The MCT is discussed in more detail in U.S. patent application Ser. No. 12/132,699 , filed Jun. 4, 2008, which is herein incorporated by reference in its entirety. 
       FIG. 4  illustrates a tubing cutting operation  400  utilizing the line cutter mandrel  200 , according to another embodiment of the present invention.  FIG. 4A  is an enlargement of a portion of  FIG. 4 . A workover rig  410  may be disposed over an earth surface  412  proximate to the wellbore  5 . The workover rig  410  may include draw works having a crown block  420  mounted in an upper end of a derrick  418 . The draw works may also include a traveling block  422 . The traveling block  422  may be connected to the upper end of the production tubing  15 . Two line cutter mandrels  200   a, b  may have been assembled with the production tubing  15  during original deployment of the production tubing. 
     The RCT  300  may be deployed to the predetermined depth between the line cutter mandrels  200   a, b . The RCT  300  may be run into the production tubing string  15  on a wireline  450 . The RCT  300  and wireline  450  may be lowered into the production tubing string  415  by unspooling the line from a spool  455 . The spool  455  may be brought to the wellbore  5  by a service truck (not shown). Unspooling of the line  450  into the wellbore  5  may be aided by sheave wheels  452 . At the same time, the traveling block  422  may be used to suspend the production tubing string  415  so that the production tubing string may be in a neutral condition at the predetermined depth. Alternatively, the production tubing may still be supported from the wellhead during the cutting operation so that the production tubing string  15  may be neutral, in tension or compression at the predetermined depth. 
       FIG. 4B  illustrates the RCT  300  scoring the production tubing. Once the RCT  300  has reached the predetermined depth in the production tubing  415 , the RCT may be activated by supplying electricity from the surface to the RCT via the wireline  450 . As discussed above, the RCT  300  may then generate pipe cutting flame  475 , thereby scoring  480  or cutting the production tubing. 
       FIG. 4C  illustrates retrieval of the production tubing to the surface  412  and operation of the line cutter mandrels  200   a, b . Once the production tubing string  15  has been scored  480 , the RCT  300  may be removed from the production tubing string  15 . The workover rig  410  may then pull the production tubing string  15  so that the score  480  is placed in tension, thereby fracturing the score. The workover rig  410  may continue to pull on an upper portion of the production tubing string  15 , thereby placing the cable  55  in tension and actuating the line cutter mandrels  200   a, b . Once the line cutter mandrels  200   a, b  have cut the cable  55 , the workover rig may continue to retrieve the upper portion of the production tubing string to the surface until the production tubing string has been tripped out of the wellbore. Use of the line cutter mandrels  200   a,b  ensures that that the upper end of the lower portion of the production tubing string is free from nested cable, thereby facilitating subsequent wellbore operations, such as fishing the lower portion of the production tubing string from the wellbore, recompleting the wellbore to a higher producing zone, or drilling a lateral wellbore above the lower portion of the production tubing string to another producing formation. The higher producing zone may be located at a depth above the predetermined depth. 
     While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.