Patent Publication Number: US-11655684-B2

Title: System for dislodging and extracting tubing from a wellbore

Description:
SUMMARY 
     The present invention is directed to a system comprising a wellbore formed within the ground and having a casing installed therein. The system also comprises a tubular string having no opening between its ends and having a first portion situated within the casing and a second portion wound around an above-ground reel. The system further comprises a tool carrying an explosive charge and positioned within the second portion of the tubular string. 
     The present invention is also directed to a method of using a kit in an environment. The kit comprises a tool comprising an explosive charge, a funnel element, and at least one deformable ball. The funnel element has opposed first and second surfaces joined by a fluid passage. The funnel element also has an enlarged bowl that opens at the first surface and connects with a narrow neck that opens at the second surface. The at least one deformable ball is sized, in its undeformed state, to be seated within the bowl of the funnel element. The environment comprises a wellbore formed within the ground and having a casing installed therein, and a tubular string having a first portion situated within the casing and a second portion wound around an above-ground reel and terminating in an open end. 
     The method of using the kit in the environment first comprises the step of inserting the funnel element through an open end of the second portion of the tubular string. Thereafter, fluid pressure within the tubular string is increased until the funnel element is situated within the first portion of the tubular string. Thereafter, the at least one ball is positioned within the first portion of the tubular string. Thereafter, the tool is inserted through the open end of the second portion of the tubular string, and thereafter, fluid pressure is increased within the tubular string until the tool is situated within the first portion of the tubular string. 
     The present invention is also directed to a method of recovering at least a portion of a tubular string from a subterranean wellbore having a casing installed therein. The method first comprises the step of positioning a funnel element within the tubular string, the funnel element having a fluid passage extending therethrough. Thereafter, the fluid passage is blocked with the first deformable ball. Thereafter, fluid pressure within the tubular string is increased until the first deformable ball is expelled through the fluid passage in a downhole direction. Thereafter, the fluid passage is blocked with a second deformable ball, and thereafter, a tool comprising an explosive charge is positioned within an underground portion of the tubular string such that the tool is uphole from the funnel element. 
     The present invention is further directed to a method of using a tubular string installed within a subterranean wellbore and having an above-ground open end. The method comprises the step of inserting a tool carrying an explosive charge into the open end of the tubular string. The method further comprises the step of causing fluid flow within the tubular string to carry the tool to an underground position within the tubular string. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG.  1    is an illustration of a pipe recovery system used to dislodge or sever a tubular string that is stuck within a cased wellbore. 
         FIG.  2    is an enlarged view of area A shown in  FIG.  1    and shows a jar. A deformable ball is seated within the funnel element of the jar. The ball and portions of the tubular string and bottom hole assembly are shown in cross-section. 
         FIG.  3    is an enlarged view of area B from  FIG.  1    and shows a tubular severance device. The tubular string is shown in cross-section. 
         FIG.  4    is an enlarged view of area C from  FIG.  1    showing a plurality of plugs seated against perforations formed within the casing. Some of the plugs are shown with the sleeve partially cut away, in order to reveal the plug&#39;s insert element. 
         FIG.  5    shows the wellbore and pipe recovery system of  FIG.  1   , after the tubular string has been severed. 
         FIG.  6    is an exploded perspective view of the jar shown in  FIG.  2   . 
         FIG.  7    is a perspective view of the jar shown in  FIG.  6   , in an assembled configuration. Portions of the funnel element and collar element have been cut away. An undeformed ball is shown above the funnel element and a deformed ball is shown below the funnel element. 
         FIG.  8    is a cross-sectional view of the jar shown in  FIG.  7   . The cross-section is taken along a plane that includes the axis D-D shown in  FIG.  6   . An undeformed ball is shown seated within the funnel element and a deformed ball is shown below the funnel element. 
         FIG.  9    is a perspective view of one of plugs shown in  FIG.  4   . 
         FIG.  10    shows the plug of  FIG.  9    and its insert element. A portion of the sleeve has been cut away. 
         FIG.  11    is an enlarged front elevation view of the tubular severance device shown in  FIG.  3   . 
         FIG.  12    is a perspective view of the device shown in  FIG.  11   . 
         FIG.  13    is a cross-sectional view of the device shown in  FIG.  11   . The device is sectioned by a plane that extends through the axis E-E shown in  FIG.  11   . 
         FIG.  14    is a perspective view of the device shown in  FIG.  13   . 
         FIG.  15    is an exploded perspective view of the device shown in  FIG.  11   . 
         FIG.  16    shows the device of  FIG.  13    after the firing pin has impacted the detonator. 
         FIG.  17    shows the wellbore and pipe recovery system of  FIG.  1    while the tubular severance device is above-ground. 
         FIG.  18    is an enlarged view of area F shown in  FIG.  17   . A portion of the tubular string has been cut away in order to show an installed tubular severance device. 
         FIG.  19    is a perspective view of an alternative embodiment of a tubular severance device. 
         FIG.  20    is an exploded perspective view of the device shown in  FIG.  19   . 
         FIG.  21    is a cross-sectional view of the device shown in  FIG.  19   . The device is sectioned by a plane that extends through the axis G-G shown in  FIG.  19   . 
         FIG.  22    is an enlarged view of area H shown in  FIG.  21   . 
         FIG.  23    is an enlarged view of area I shown in  FIG.  21   . 
     
    
    
     DETAILED DESCRIPTION 
     Turning to  FIG.  1   , during oil and gas drilling operations, a wellbore  10  is drilled beneath a ground surface  12  and a casing  14  is installed within the wellbore  10 . The wellbore  10  may extend vertically and transition into a horizontal section  16 . A plurality of perforations  18  may be formed in the walls of the casing  14  within the horizontal section  16 . The perforations  18  serve as an opening for oil and gas to flow from the surrounding subsurface and into the casing  14 . 
     A tubular work string  20  is shown installed within the casing  14  in  FIG.  1   . The tubular string  20  is known in the art as “coiled tubing”. Coiled tubing is typically used in well completion or workover operations to lower tools into the wellbore  10 . The tools are typically included in a bottom hole assembly (BHA)  22  attached to a first end  24  of the string  20 . The BHA  22  shown in  FIG.  1   , for example, includes a milling tool  26 . Milling tools are used to grind up tools, such as large composite plugs, abandoned within the wellbore  10  during drilling and fracturing operations. 
     The tubular work string  20  is a long metal pipe that is typically between one and four inches in diameter. A first portion  28  of the string  20  is situated within the casing  14  and a second portion  30  is wound around an above-ground reel  32 . A second end  34  of the string  20  is supported on the reel  32 . No opening is formed within the string  20  between its opposed first and second ends  24  and  34 . 
     In operation, the string  20  is unwound from the reel  32  and lowered into the casing  14  to the desired depth. An injector head  36  positioned at the ground surface  12  grips and thrusts the string  20  into the wellbore  10 . As the string  20  advances through the wellbore  10 , the string  20  or BHA  22  may become stuck. The string  20  or BHA  22  may become caught on well debris or lodged against the interior wall of the casing  14 . For example, the string  20  is shown lodged against an interior wall of the casing  14  at a stuck point  38  in  FIG.  1   . The process of dislodging or recovering the stuck string  20  may be referred to as a pipe recovery operation. 
     One method of dislodging the string  20  from its stuck point  38  is to jar the string  20 . One method of jarring the string  20  uses a jar  100  included in the BHA  22 , as shown in  FIG.  2   . 
     If the string  20  is caught on debris at the stuck point  38 , one method of dislodging the string  20  is to pump fluid into the annulus  40  between the casing  14  and the string  20 . The fluid washes debris away from the stuck point  38 . If the casing  14  has been perforated during an earlier fracturing operation, fluid may flow through those perforations  18 , instead of flowing toward or around the stuck point  38 . To prevent such diversion, a plurality of plugs  200  may be used to fill the perforations  18 , as shown in  FIG.  4   . 
     If the string  20  cannot be dislodged or freed from debris, it may be necessary to sever the string  20  above its stuck point  38 . The string  20  may be severed using a tubular severance device  300 , shown in  FIG.  3   . The portion of the string  20  above the point of severance  39  may be recovered from the wellbore  10  and salvaged, as shown in  FIG.  5   . The portion of the string  20  below the point of severance  39  may be fished out of the wellbore  10  or milled into small pieces. The milled pieces may be flushed from the wellbore  10  with fluid. 
     Tubular severance devices known in the art are typically lowered into a tubular work string on a wireline. In order to insert the wireline into the string, the string must first be cut near the injector head at the ground surface. The cutting operation produces an opening into which the wireline may be lowered. However, cutting the string at the injector head exposes the string to atmospheric pressure. Such exposure can cause pressure changes within the wellbore and resulting damage to the string. Such damage may impair the string&#39;s salvageability. 
     As will be discussed in more detail herein, the tubular severance device  300  may be lowered into the wellbore  10  without opening the tubular string  20  at the ground surface  12 . The device  300  may be carried in fluid to the desired severance point. The device  300  works in combination with the jar  100  to position the device  300  at the desired severance point. 
     Turning to  FIGS.  2  and  6 - 8   , the jar  100  comprises a funnel sub  102  that is installed within a collar element  104 . The string  20  and the BHA  22  are attached to opposite ends of the collar element  104 , as shown in  FIG.  2   . The collar element  104  has an elongate body  106  having a longitudinal internal passage  108  extending therethrough, as shown in  FIGS.  7  and  8   . The passage  108  opens at a first end  110  and an opposed second end  112  of the body  106 . The passage  108  has an enlarged first portion  114  joined to a narrowed second portion  116 . An annular shoulder  118  formed in the walls of the body  106  surrounding the passage  108  defines the boundary between the first and second portions  114  and  116 . The passage  108  tapers inwardly below the annular shoulder  118  so that the second portion  116  is narrower than the first portion  114 , as shown in  FIGS.  7  and  8   . 
     The first portion  114  of the passage  108  is configured to receive the first end  24  of the string  20 . The first end  24  of the string  20  is inserted within the collar element  104  until it abuts the annular shoulder  118 . The string  20  and collar element  104  may be joined by welds or slips. The collar element  104  is joined to the BHA  22  by a threaded connection. External threads  120 , formed on the second end  112  of the collar element  104 , mate with internal threads formed on the end of the BHA  22 . 
     Continuing with  FIGS.  6 - 8   , the funnel sub  102  comprises an elongate body  122  having a funnel element  124  formed therein. The funnel element  124  is characterized by a longitudinal internal passage  126  that opens at a first surface  128  and an opposed second surface  130  of the funnel sub  102 . An outer surface  132  of the funnel sub  102  is smooth and tapers inwardly from the first surface  128  to the second surface  130 , as shown in  FIG.  6   . The outer surface  132  of the funnel sub  102  is configured to lodge into the second portion  116  of the passage  108  formed in the collar element  104 , as shown in  FIGS.  7  and  8   . 
     The internal passage  126  of the funnel element  124  has an enlarged bowl  134  that tapers inwardly and connects with a narrow neck  136 . A seat  140  is formed at the connection between the bowl  134  and the narrow neck  136 . The bowl  134  opens at the first surface  128  of the funnel sub  102  and the narrow neck  136  opens at the second surface  130  of the funnel sub  102 . The bowl  134  has the shape of a frustum of a right circular cone having a slant angle of between 15 and about 20 degrees. Preferably this angle is 17.5 degrees. 
     The collar element  104  is interposed between the string  20  and the BHA  22  prior to lowering the string  20  into the wellbore  10 . The funnel sub  102  is held at the ground surface  12  while the string  20  is lowered downhole. If the string  20  or BHA  22  becomes stuck during operation, the jar  100  may be assembled. 
     To assemble the jar  100 , the funnel sub  102  is inserted into the open second end  34  of the string  20  at the ground surface  12 , shown in  FIG.  1   . Fluid pumped into the open second end  34  of the string  20  carries the funnel sub  102  through the string  20 . The funnel sub  102  first travels through the above-ground second portion  30 , at least part of which is wound upon the reel  32 , and next travels underground within the first portion  28 . The funnel sub  102  moves down the first portion  28  of the string  20  until it lodges within the collar element  104 . 
     The assembled jar  100  is activated by lowering a deformable ball  138 , shown in  FIGS.  2 ,  7  and  8   , into a seated position within the funnel element  124 . The ball  138 , in an undeformed state, is inserted into the open second end  34  of the string  20 . Fluid carries the ball  138  through the string  20  until the ball  138  reaches the funnel sub  102 . The ball  138  will engage the seat  140  formed in the funnel element  124  and block fluid from flowing through the funnel sub  102 . 
     Fluid pressure is increased until the ball  138  deforms and is forced from the narrow neck  136  of the funnel element  124 , as shown in  FIGS.  7  and  8   . The deformed ball  138  may be expelled through the funnel element  124  at a speed as high as 22,000-23,000 feet/second. 
     As the deformed ball  138  is expelled through the funnel sub  102 , fluid within the string  20  and above the ball  138  will rapidly flow through the narrow neck  136  of the funnel element  124 . This rapid release of fluid will cause a dynamic event within the wellbore  10 . The dynamic event is characterized by a shock wave throughout the string  20  that causes a powerful jarring or jolting of the string  20  within the wellbore  10 . The jarring or jolting of the string  20  works to dislodge the string  20  or BHA  22  from its stuck point within the wellbore  10 . 
     If the first dynamic event does not dislodge the string  20  or BHA  22  from its stuck point, a second deformable ball  138  may be carried down the string  20  to the funnel element  124 . Fluid pressure above the ball  138  is again increased until the ball  138  is deformed and forced through the narrow neck  136  of the funnel element  124 . This process may be repeated as many times as needed until the string  20  is dislodged from its stuck point within the wellbore  10 . 
     After each ball  138  is expelled through the funnel element  124 , the balls may be retained within the BHA  22 . A screen (not shown) may be incorporated into the BHA to retain the deformed balls but allow fluid to pass through. Alternatively, the deformed balls may pass through the bottom hole assembly and come to rest within the wellbore. 
     The balls  138  used to activate the jar  100  may have varying diameters. The greater the diameter of the ball  138 , the greater the hydraulic pressure needed to deform the ball. The balls  138  are preferably solid and made of nylon, but can be made out of any material that is capable of deforming under hydraulic pressure and withstanding high temperatures within the wellbore  10 . 
     The balls  138  may be porous and coated in a nano-particulate matter. Such a coating enhances frictional forces between the ball  138  and the funnel element  124 . The greater the friction between the ball  138  and the funnel element  124 , the greater hydraulic pressure required to extrude the ball  138  through the funnel element  124 . Thus, the nano-particulate matter may help increase the speed at which the deformed balls  138  are extruded through the funnel element  124 . 
     In operation, an operator in charge of activating the jar  100  is typically provided with a set of balls  138 , each ball having a different diameter. The operator may start by sending a control ball down the string  20 , thereby activating the jar  100 . The operator may use any size ball  138  as a control ball. The control ball is used to gain information about the conditions within the wellbore  10 . Such information is important because each wellbore may vary in depth, and the depth of the jar  100  within the wellbore at the time a tubular work string becomes stuck may vary. Due to these varying factors, the same size balls  138  may extrude at different pressures within each wellbore. 
     Once the control ball has been extruded through the funnel element  124  and the jarring event takes place, the operator may try to move the string  20  within the wellbore  10 . Resulting movement of the string  20  may show that the control ball alone has caused the string  20  or BHA  22  to dislodge from the stuck point. If the string  20  does not move as desired, another ball  138  may be used to once again activate the jar  100 . The size of this ball  128  may be chosen based on how much the string  20  moved, if at all, following the previous jarring cycle. 
     A pressure gauge at the surface  12  allows an operator to monitor the jarring process. Pressure builds within the string  20  until a ball  138  is extruded through the funnel element  124 . After extrusion occurs, pressure within the string  20  drops precipitously. By noting the pressure drop points associated with balls  138  of different sizes, an operator can estimate what string pressure, and what size of ball  138 , will be required for a particular jarring action. 
     The jar  100  may be made of steel, aluminum, plastic, carbon fiber or other materials suitable for use in oil and gas operations. Preferably the jar  100  is made of steel. The jar  100  may be coated with tungsten nitrate in order to harden its outer surface and reduce rusting. 
     The jar  100  may be assembled from a kit. Such a kit should include at least one funnel element  124  and at least one, and preferably a plurality of deformable balls  138 . The kit may further include the collar element  104 . 
     Turning to  FIGS.  9  and  10   , each of the plugs  200  comprises an insert element  202  and a deformable sleeve  204 . The insert element  202  is received and retained within a medial section  206  of the sleeve  204 . The sleeve  204  has sections  208  joined to opposite sides of the medial section  206 . Each section  208  has an open end  210 . The medial section  206  has a larger maximum cross-sectional diameter than the sections  208  when the insert element  202  is installed within the sleeve  204 . The plug  200  is sized to seal a single perforation  18  formed in the casing  14 , as shown in  FIG.  4   . 
     The insert element  202  has the shape of a sphere and is preferably made of plastic, such as a thermoplastic or thermoset. However, the insert element  202  may be made of any material capable of withstanding high pressure. For example, the insert element  202  may be made of the same material as the sleeve  204 . In some embodiments, the insert element  202  may be harder than the sleeve  204 . The insert elements  202  may have a different shape than that disclosed herein, such as a shape having an oval or hexagonal profile. However, the insert element must be shaped such that it can seal a single perforation  18  when installed within the sleeve  204 . The insert element  202  may be solid or hollow. 
     The sleeve  204  is preferably made of an elastic material, such as silicon, rubber, or neoprene. However, the sleeve  204  may be made out of any material that has elastic and viscous qualities such that it can block fluid from passing through a perforation  18 . The plugs  200  may vary in size in accordance with the size of the perforations  18  formed in the casing  14 . 
     As discussed above, plugging of the perforations  18  helps direct fluid towards the stuck point, where it can wash away debris. The plugs  200  may remain seated within the perforations  18  while the string  20  is being removed from the casing  14 . If the string  20  extends within the perforated zone of the string  20 , the seated plugs  200  serve as bearings that engage the string  20  and ease its removal from the casing  14 . 
     Turning to  FIGS.  3  and  11 - 16   , the tubular severance device  300  comprises a first section  302  joined to a second section  304 . A longitudinal axis E-E extends through each section  302  and  304 . The sections  302  and  304  are preferably made of metal. The first section  302  has an internal bore  308  formed therein and extending longitudinally therethrough, as shown in  FIGS.  13  and  14   . The bore  308  opens at a bottom surface  310  of the first section  302 . A series of internal threads  312  are formed in the walls of the bore  308  adjacent the bottom surface  310 . 
     The second section  304  has an upper section  314  joined to a lower section  316 . The upper section  314  has a maximum cross-sectional dimension that is larger than that of the lower section  316 . An internal bore  318  is formed in the lower section  316 . The bore  318  opens at a bottom surface  320  of the second section  304  and extends longitudinally through the lower section  316  until it reaches a face  322 . The face  322  defines the boundary between the upper and lower sections  314  and  316  of the second section  304 . 
     The upper section  314  includes a threaded portion  324  that projects from a top surface  326 . A series of external threads  328  are formed on the threaded portion  324 . The maximum cross-sectional dimension of the threaded portion  324  is less than that of the remainder of the upper section  314 . An annular shoulder  330  joins the threaded portion  324  to the rest of the upper section  314 . An internal passage  332  extends through the upper section  314  and interconnects the face  322  and a top surface  334  of the threaded portion  324 . 
     The device  300  is assembled by mating the external threads  328  within the internal threads  312 , thereby joining the first and second sections  302  and  304 . When so assembled, the bottom surface  310  of the first section  302  abuts the annular shoulder  330  formed on the second section  304 , as shown in  FIGS.  13  and  14   . 
     Continuing with  FIGS.  13 - 16   , an explosive charge  336  is placed within the internal bore  308  of the first section  302 . The charge  336  is preferably a shaped charge. A central passage  338  is formed in the center of the charge  336 . The passage  338  aligns with the passage  332  in the upper section  314  of the second section  304 . 
     A detonator  340  is installed within the bore  318  formed in the second section  304 , such that the detonator  340  abuts the face  322 . The detonator  340  is cylindrical and has a thin outer housing that holds a dense flammable composite mixture. For example, the composite mixture may comprise titanium, potassium, and phosphorus mixed with glass. At the open bottom surface  342  of the detonator  340 , the composite mixture is exposed to the environment. 
     An energy-transmitting cord  344  interconnects the charge  336  and the detonator  340 . The cord  344  extends through the internal passage  332  and into the passage  338 . A bottom surface  346  of the cord  344  abuts a top surface  348  of the detonator  340 . The cord  344  may be in the form of a fuse comprising black powder wrapped in a tough textile or plastic. 
     A firing system  350  is configured to actuate the detonator  340 , and comprises a firing pin  352  and a control system  354 . The firing system  350  is housed in the second section  304 , and more preferably within the internal bore  318  formed in the lower section  316 . 
     The firing pin  352 , which is solid and preferably made of metal, features a cylindrical upper portion  355  that is joined to a cone-shaped lower portion  356 . A plurality of annular grooves  358  are formed in the upper portion  354  of the firing pin  352 , as shown in  FIG.  15   . 
     The control system  354  selectively maintains the firing pin  352  and the detonator  340  in an axially-spaced relationship. In addition, the control system  354  can selectively release one or both of the firing pin  352  and the detonator  340  from that axially-spaced relationship. The control system  354  comprises a collar  360  and a plurality of pins  362 . The collar  360  is an annular ring that is preferably made of metal. The collar  360  has two pairs of diametrically opposed holes  364  formed in its periphery, as shown in  FIG.  15   . In alternative embodiments, the collar may have fewer than four holes or more than four holes formed in its periphery. 
     When the firing pin  352  is installed within the collar  360 , the grooves  358  formed in the pin  352  align with the holes  364 . The firing pin  352  and the collar  360  are held together by pins  362 . Specifically, a pin  362  is inserted into each of the holes  364 , such that the end of the pin engages the base of the underlying aligned groove  358 . Once assembled, the firing pin  352  and collar  360  are installed within the bore  318 . When installed, the collar  360  abuts an annular shoulder  368  formed in the inner walls surrounding the bore  318 , as shown in  FIGS.  13  and  14   . The shoulder  368  prevents axial movement of the collar  360  within the bore  318 . 
     The collar  360  is press fit into the walls surrounding the bore  318 . In alternative embodiments, the collar may be threaded or welded into the walls surrounding the bore. When the control system  354  is installed within the second section  304  of the device  300 , a bottom surface  370  of the firing pin  352  is exposed to the surrounding environment within the wellbore  10 . When the control system  354  is installed within the second section  304 , the space between the detonator  340  and the firing pin  352  is sealed and maintained at or around the surrounding atmospheric pressure. 
     With reference to  FIG.  16   , the control system  354  operates in response to fluid pressure within the string  20 . Increased fluid pressure against the pins  362  causes them to shear, thereby releasing the firing pin  352  from the collar  360 . After release, fluid pressure within the string  20  causes the firing pin  352  to move rapidly through the bore  318  and strike the detonator  340 . The impact will cause the detonator  340  to ignite. Ignition of the detonator  340  ignites the cord  344 , which in turn ignites the charge  336 . The ignited charge  336  explodes and severs the surrounding tubular string  20 , as shown in  FIG.  5   . 
     Turning back to  FIGS.  3 ,  11  and  12   , a series of notches  372  are formed in the bottom surface  320  of the second section  304 . The notches  372  provide side openings through which fluid may enter the device  300 , even when its open base is clogged by debris. A wire or rod  376  may be threaded through a diametrically opposed pair of holes  374 , such that the ends of the wire or rod  376  form a nonzero and acute angle relative to the lower section  316 . Additional wires or rods  376  may be installed in other diametrically opposed pair of holes  374 . The wires or rods  376  help center the device  300  within the string  20  as it is delivered to its desired position, as shown in  FIG.  3   . 
     With reference to  FIGS.  17  and  18   , the device  300  is installed within the tubular string  20  by inserting the device  300 , second section  304  first, through the open second end  34  of the string  20  at the ground surface  12 . Fluid carries the device  300  through the second portion  30  of the string  20 , shown in  FIG.  18   , and into the first portion  28  of the string  20 , shown in  FIGS.  1  and  3   . 
     Turning back to  FIGS.  1 - 3   , the device  300  is positioned by shutting off fluid flow through the string  20 , such as with the jar  100  and a ball  138 . Fluid is then pumped into the string  20  and allowed to at least partially fill the string  20 . The device  300  is lowered into the fluid within the string  20 , and permitted to float at the desired point of severance. 
     For example, the string  20  within the wellbore  10  may be 1,000 feet long when measured from the ground surface  12  to the first end  24  of the string  20 . The jar  100  may be positioned on the 1,000 th  foot of the string  20 . The operator may want to sever the string  20  at 900 feet, allowing 900 feet of string  20  to be removed from the wellbore  10  and 100 feet of string  20  to be abandoned in the wellbore  10 , as shown in  FIG.  5   . 
     In operation, the ball  138  is inserted into the open second end  34  of the string  20 . Once fluid has carried the ball  138  100 feet through the string  20 , the device  300  is inserted into the open second end  34  of the string  20 . Pumping of fluid into the string  20  continues, and the ball  138  and device  300  are carried downward with the fluid. The 100-foot spacing between the ball  138  and the device  300  is maintained. 
     Pumping continues until the ball  138  seats within the funnel element  124  of the jar  100 , thereby blocking fluid flow. Once pumping is stopped, the device  300  floats about 100 feet above the ball  138  and the funnel element  124 . Thus, when the ball  138  seats within the jar  100  positioned at the 1,000 th  foot of the string  20 , the device  300  is positioned at or near the 900 th  foot of the string  20 . 
     Once the device  300  is at the desired severance position, fluid pressure within the wellbore  10  will be increased until the pins  362  are sheared. Once the pins  362  are sheared, the firing pin  352  is released and strikes the detonator  340 . Detonation of the charge  336  will sever the string  20 , as shown in  FIG.  5   . The remains of the device  300 , together with the severed portion of the string  20 , will be deposited in the wellbore  10 . 
     Turning to  FIGS.  19 - 23   , an alternative embodiment of the tubular severance device  400  is shown. The device  400  is similar to the device  300 , except that the device  400  uses a much longer cord  402 , as shown in  FIGS.  20  and  21   . The device  400 , which has a longitudinal axis G-G, comprises a first section  404 , a second section  406 , and a cord  402 . 
     With reference to  FIGS.  21  and  22   , the first section  404  is identical to the first section  302  of the device  300 , with one exception. In the device  400 , a centralizer  408  is used to center the device with the string  20 , rather than the rods  376  used in the device  300 . The centralizer  408  is an X-shaped metal piece that engages the top surface  410  of the first section  404 . The centralizer  408  is concentric with the first section  404 , and attached to its top surface  410  with a pair of socket head screws  412 . Like the first section  302 , an explosive charge  414  is positioned within a bore  415  formed in the first section  404 . The charge  414  is identical to the charge  336 . 
     Unlike the device  300 , the first and second sections  404  and  406  of the device  400  are not attached directly. Instead, each section  404  and  406  is joined to a cross-over sub  416  and  444  which is in turn joined to an end of the cord.  402 . The first cross-over sub  416 , which is preferably formed from metal, is attached to the first section  404 . The first cross-over sub  416  comprises a body  418  having a first end  424  and an opposed second end  426 . Threads  420  are formed at the first end  422 , and a tubular section  424  projects from the second end  426 . An internal passage  432  extends through the sub  416 . The passage  432  is aligned with a passage  434  formed in the charge  414 . The passages  432  and  434  are configured to receive the cord  402 . 
     With reference to  FIGS.  21  and  23   , the second section  406  comprises a body, preferably formed from metal, having opposed top and bottom surfaces  438  and  440 . An internal passage  436  extends longitudinally through the body and between the surfaces  438  and  440 . Adjacent the top surface  438 , internal threads  442  are formed in the walls defining the passage  436 . 
     The second cross-over sub  444 , which is preferably identical to the first cross-over sub  416 , is attached to the second section  406 . An externally threaded portion  446  of the sub  444  mates with the internal threads  442  of the second section  406 . When mated, a bottom surface  448  of the sub  444  is exposed to the passage  436 , as shown in  FIG.  23   . A passage  450  formed within the second cross-over sub  444  is configured to receive the cord  402 . 
     A firing system  452  is positioned within the second section  406 . The firing system  452  is identical to the firing system  350 , described with reference to  FIGS.  16 - 19   . A detonator  454  included in the firing system  452  abuts the bottom surface  448  of the sub  444 . When the cord  402  is installed within the passage  450  formed in the second cross-over sub  444 , a bottom surface  458  of the cord  402  abuts a top surface  460  of the detonator  454 . 
     When the device  400  is assembled, the cord  402  interconnects the detonator  454  and the charge  414 . The cord  402  is made from the same material as the cord  344 . The portion of the cord  402  that extends between the subs  416  and  444  is surrounded by a flexible seal  462 . The seal  462  shown in the figures is a water-resistant tape formed from synthetic rubber. The tape is wrapped multiple times around the cord  402  so as to form a thick layer. In alternative embodiments, the seal may comprise any material that is flexible and water-resistant, such as rubber, nylon, or plastic. The seal  462  is preferably both flexible and water-resistant. It is flexible so that it may easily bend as the device  400  passes through the string  20  wound around the reel  32 , shown in  FIG.  21   . It is water-resistant so that it can protect the cord  402  from fluid contained within the string  20 . 
     In operation, the device  400  is delivered to the desired point of severance in the same manner as the device  300 . The device  400  is likewise detonated in the same manner as the device  300 . 
     In further alternative embodiments of the device  300  or  400 , the cord may transfer energy electrically or hydraulically from the firing pin to the charge. In such embodiments, a detonator may not be used and the firing pin alone may be used to initiate the transfer of energy from the cord to the charge. 
     When performing pipe recovery operations, an operator may first attempt to jar the string  20  using the jar  100 . If jarring is unsuccessful, an operator may next try to flush away debris by pumping fluid into the annulus  40 . Before this step can be carried out, plugs  200  are first deployed into the annulus  40  and seated in the perforations  18 . Deployment of plugs  200  can occur either before or after jarring is complete. If fluid flushing is unsuccessful, an operator may next deploy one of the tubular severance devices  300  and  400 . After the device  300  or  400  detonates, a portion of the first portion of the string  20  may be removed from the wellbore  10 . 
     One or more kits may be useful for performing pipe recovering operations. The kits may comprise the jar  100 , at least one deformable ball  138 , a plurality of the plugs  200 , and the tubular severance device  300  or  400 . 
     Changes may be made in the construction, operation and arrangement of the various parts, elements, steps and procedures described herein without departing from the spirit and scope of the invention as described in the following claims.