System for dislodging and extracting tubing from a wellbore

A system used to dislodge and, if necessary, sever a tubular string that is stuck within a cased wellbore. The system utilizes a jar, a plurality of plugs, and a tubular severance device. Components of the system are carried to their respective desired downhole positions by downward fluid flow within the wellbore. The jar is configured to jar the string in an effort to dislodge the string from its stuck point. The plugs are configured to fill open perforations formed in the casing in order to direct the fluid toward the stuck point and away from the perforations. If the string cannot be freed by the jar, the tubular severance device is deployed within the string above the stuck point. Detonation of the device severs the string above the stuck point.

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.

DETAILED DESCRIPTION

Turning toFIG. 1, during oil and gas drilling operations, a wellbore10is drilled beneath a ground surface12and a casing14is installed within the wellbore10. The wellbore10may extend vertically and transition into a horizontal section16. A plurality of perforations18may be formed in the walls of the casing14within the horizontal section16. The perforations18serve as an opening for oil and gas to flow from the surrounding subsurface and into the casing14.

A tubular work string20is shown installed within the casing14inFIG. 1. The tubular string20is known in the art as “coiled tubing”. Coiled tubing is typically used in well completion or workover operations to lower tools into the wellbore10. The tools are typically included in a bottom hole assembly (BHA)22attached to a first end24of the string20. The BHA22shown inFIG. 1, for example, includes a milling tool26. Milling tools are used to grind up tools, such as large composite plugs, abandoned within the wellbore10during drilling and fracturing operations.

The tubular work string20is a long metal pipe that is typically between one and four inches in diameter. A first portion28of the string20is situated within the casing14and a second portion30is wound around an above-ground reel32. A second end34of the string20is supported on the reel32. No opening is formed within the string20between its opposed first and second ends24and34.

In operation, the string20is unwound from the reel32and lowered into the casing14to the desired depth. An injector head36positioned at the ground surface12grips and thrusts the string20into the wellbore10. As the string20advances through the wellbore10, the string20or BHA22may become stuck. The string20or BHA22may become caught on well debris or lodged against the interior wall of the casing14. For example, the string20is shown lodged against an interior wall of the casing14at a stuck point38inFIG. 1. The process of dislodging or recovering the stuck string20may be referred to as a pipe recovery operation.

One method of dislodging the string20from its stuck point38is to jar the string20. One method of jarring the string20uses a jar100included in the BHA22, as shown inFIG. 2.

If the string20is caught on debris at the stuck point38, one method of dislodging the string20is to pump fluid into the annulus40between the casing14and the string20. The fluid washes debris away from the stuck point38. If the casing14has been perforated during an earlier fracturing operation, fluid may flow through those perforations18, instead of flowing toward or around the stuck point38. To prevent such diversion, a plurality of plugs200may be used to fill the perforations18, as shown inFIG. 4.

If the string20cannot be dislodged or freed from debris, it may be necessary to sever the string20above its stuck point38. The string20may be severed using a tubular severance device300, shown inFIG. 3. The portion of the string20above the point of severance39may be recovered from the wellbore10and salvaged, as shown inFIG. 5. The portion of the string20below the point of severance39may be fished out of the wellbore10or milled into small pieces. The milled pieces may be flushed from the wellbore10with 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's salvage ability.

As will be discussed in more detail herein, the tubular severance device300may be lowered into the wellbore10without opening the tubular string20at the ground surface12. The device300may be carried in fluid to the desired severance point. The device300works in combination with the jar100to position the device300at the desired severance point.

Turning toFIGS. 2 and 6-8, the jar100comprises a funnel sub102that is installed within a collar element104. The string20and the BHA22are attached to opposite ends of the collar element104, as shown inFIG. 2. The collar element104has an elongate body106having a longitudinal internal passage108extending therethrough, as shown inFIGS. 7 and 8. The passage108opens at a first end110and an opposed second end112of the body106. The passage108has an enlarged first portion114joined to a narrowed second portion116. An annular shoulder118formed in the walls of the body106surrounding the passage108defines the boundary between the first and second portions114and116. The passage108tapers inwardly below the annular shoulder118so that the second portion116is narrower than the first portion114, as shown inFIGS. 7 and 8.

The first portion114of the passage108is configured to receive the first end24of the string20. The first end24of the string20is inserted within the collar element104until it abuts the annular shoulder118. The string20and collar element104may be joined by welds or slips. The collar element104is joined to the BHA22by a threaded connection. External threads120, formed on the second end112of the collar element104, mate with internal threads formed on the end of the BHA22.

Continuing withFIGS. 6-8, the funnel sub102comprises an elongate body122having a funnel element124formed therein. The funnel element124is characterized by a longitudinal internal passage126that opens at a first surface128and an opposed second surface130of the funnel sub102. An outer surface132of the funnel sub102is smooth and tapers inwardly from the first surface128to the second surface130, as shown inFIG. 6. The outer surface132of the funnel sub102is configured to lodge into the second portion116of the passage108formed in the collar element104, as shown inFIGS. 7 and 8.

The internal passage126of the funnel element124has an enlarged bowl134that tapers inwardly and connects with a narrow neck136. A seat140is formed at the connection between the bowl134and the narrow neck136. The bowl134opens at the first surface128of the funnel sub102and the narrow neck136opens at the second surface130of the funnel sub102. The bowl134has 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 element104is interposed between the string20and the BHA22prior to lowering the string20into the wellbore10. The funnel sub102is held at the ground surface12while the string20is lowered downhole. If the string20or BHA22becomes stuck during operation, the jar100may be assembled.

To assemble the jar100, the funnel sub102is inserted into the open second end34of the string20at the ground surface12, shown inFIG. 1. Fluid pumped into the open second end34of the string20carries the funnel sub102through the string20. The funnel sub102first travels through the above-ground second portion30, at least part of which is wound upon the reel32, and next travels underground within the first portion28. The funnel sub102moves down the first portion28of the string20until it lodges within the collar element104.

The assembled jar100is activated by lowering a deformable ball138, shown inFIGS. 2, 7 and 8, into a seated position within the funnel element124. The ball138, in an undeformed state, is inserted into the open second end34of the string20. Fluid carries the ball138through the string20until the ball138reaches the funnel sub102. The ball138will engage the seat140formed in the funnel element124and block fluid from flowing through the funnel sub102.

Fluid pressure is increased until the ball138deforms and is forced from the narrow neck136of the funnel element124, as shown inFIGS. 7 and 8. The deformed ball138may be expelled through the funnel element124at a speed as high as 22,000-23,000 feet/second.

As the deformed ball138is expelled through the funnel sub102, fluid within the string20and above the ball138will rapidly flow through the narrow neck136of the funnel element124. This rapid release of fluid will cause a dynamic event within the wellbore10. The dynamic event is characterized by a shock wave throughout the string20that causes a powerful jarring or jolting of the string20within the wellbore10. The jarring or jolting of the string20works to dislodge the string20or BHA22from its stuck point within the wellbore10.

If the first dynamic event does not dislodge the string20or BHA22from its stuck point, a second deformable ball138may be carried down the string20to the funnel element124. Fluid pressure above the ball138is again increased until the ball138is deformed and forced through the narrow neck136of the funnel element124. This process may be repeated as many times as needed until the string20is dislodged from its stuck point within the wellbore10.

After each ball138is expelled through the funnel element124, the balls may be retained within the BHA22. 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 balls138used to activate the jar100may have varying diameters. The greater the diameter of the ball138, the greater the hydraulic pressure needed to deform the ball. The balls138are 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 wellbore10.

The balls138may be porous and coated in a nano-particulate matter. Such a coating enhances frictional forces between the ball138and the funnel element124. The greater the friction between the ball138and the funnel element124, the greater hydraulic pressure required to extrude the ball138through the funnel element124. Thus, the nano-particulate matter may help increase the speed at which the deformed balls138are extruded through the funnel element124.

In operation, an operator in charge of activating the jar100is typically provided with a set of balls138, each ball having a different diameter. The operator may start by sending a control ball down the string20, thereby activating the jar100. The operator may use any size ball138as a control ball. The control ball is used to gain information about the conditions within the wellbore10. Such information is important because each wellbore may vary in depth, and the depth of the jar100within the wellbore at the time a tubular work string becomes stuck may vary. Due to these varying factors, the same size balls138may extrude at different pressures within each wellbore.

Once the control ball has been extruded through the funnel element124and the jarring event takes place, the operator may try to move the string20within the wellbore10. Resulting movement of the string20may show that the control ball alone has caused the string20or BHA22to dislodge from the stuck point. If the string20does not move as desired, another ball138may be used to once again activate the jar100. The size of this ball128may be chosen based on how much the string20moved, if at all, following the previous jarring cycle.

A pressure gauge at the surface12allows an operator to monitor the jarring process. Pressure builds within the string20until a ball138is extruded through the funnel element124. After extrusion occurs, pressure within the string20drops precipitously. By noting the pressure drop points associated with balls138of different sizes, an operator can estimate what string pressure, and what size of ball138, will be required for a particular jarring action.

The jar100may be made of steel, aluminum, plastic, carbon fiber or other materials suitable for use in oil and gas operations. Preferably the jar100is made of steel. The jar100may be coated with tungsten nitrate in order to harden its outer surface and reduce rusting.

The jar100may be assembled from a kit. Such a kit should include at least one funnel element124and at least one, and preferably a plurality of deformable balls138. The kit may further include the collar element104.

Turning toFIGS. 9 and 10, each of the plugs200comprises an insert element202and a deformable sleeve204. The insert element202is received and retained within a medial section206of the sleeve204. The sleeve204has sections208joined to opposite sides of the medial section206. Each section208has an open end210. The medial section206has a larger maximum cross-sectional diameter than the sections208when the insert element202is installed within the sleeve204. The plug200is sized to seal a single perforation18formed in the casing14, as shown inFIG. 4.

The insert element202has the shape of a sphere and is preferably made of plastic, such as a thermoplastic or thermoset. However, the insert element202may be made of any material capable of withstanding high pressure. For example, the insert element202may be made of the same material as the sleeve204. In some embodiments, the insert element202may be harder than the sleeve204. The insert elements202may 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 perforation18when installed within the sleeve204. The insert element202may be solid or hollow.

The sleeve204is preferably made of an elastic material, such as silicon, rubber, or neoprene. However, the sleeve204may be made out of any material that has elastic and viscous qualities such that it can block fluid from passing through a perforation18. The plugs200may vary in size in accordance with the size of the perforations18formed in the casing14.

As discussed above, plugging of the perforations18helps direct fluid towards the stuck point, where it can wash away debris. The plugs200may remain seated within the perforations18while the string20is being removed from the casing14. If the string20extends within the perforated zone of the string20, the seated plugs200serve as bearings that engage the string20and ease its removal from the casing14.

Turning toFIGS. 3 and 11-16, the tubular severance device300comprises a first section302joined to a second section304. A longitudinal axis E-E extends through each section302and304. The sections302and304are preferably made of metal. The first section302has an internal bore308formed therein and extending longitudinally therethrough, as shown inFIGS. 13 and 14. The bore308opens at a bottom surface310of the first section302. A series of internal threads312are formed in the walls of the bore308adjacent the bottom surface310.

The second section304has an upper section314joined to a lower section316. The upper section314has a maximum cross-sectional dimension that is larger than that of the lower section316. An internal bore318is formed in the lower section316. The bore318opens at a bottom surface320of the second section304and extends longitudinally through the lower section316until it reaches a face322. The face322defines the boundary between the upper and lower sections314and316of the second section304.

The upper section314includes a threaded portion324that projects from a top surface326. A series of external threads328are formed on the threaded portion324. The maximum cross-sectional dimension of the threaded portion324is less than that of the remainder of the upper section314. An annular shoulder330joins the threaded portion324to the rest of the upper section314. An internal passage332extends through the upper section314and interconnects the face322and a top surface334of the threaded portion324.

The device300is assembled by mating the external threads328within the internal threads312, thereby joining the first and second sections302and304. When so assembled, the bottom surface310of the first section302abuts the annular shoulder330formed on the second section304, as shown inFIGS. 13 and 14.

Continuing withFIGS. 13-16, an explosive charge336is placed within the internal bore308of the first section302. The charge336is preferably a shaped charge. A central passage338is formed in the center of the charge336. The passage338aligns with the passage332in the upper section314of the second section304.

A detonator340is installed within the bore318formed in the second section304, such that the detonator340abuts the face322. The detonator340is 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 surface342of the detonator340, the composite mixture is exposed to the environment.

An energy-transmitting cord344interconnects the charge336and the detonator340. The cord344extends through the internal passage332and into the passage338. A bottom surface346of the cord344abuts a top surface348of the detonator340. The cord344may be in the form of a fuse comprising black powder wrapped in a tough textile or plastic.

A firing system350is configured to actuate the detonator340, and comprises a firing pin352and a control system354. The firing system350is housed in the second section304, and more preferably within the internal bore318formed in the lower section316.

The firing pin352, which is solid and preferably made of metal, features a cylindrical upper portion355that is joined to a cone-shaped lower portion356. A plurality of annular grooves358are formed in the upper portion354of the firing pin352, as shown inFIG. 15.

The control system354selectively maintains the firing pin352and the detonator340in an axially-spaced relationship. In addition, the control system354can selectively release one or both of the firing pin352and the detonator340from that axially-spaced relationship. The control system354comprises a collar360and a plurality of pins362. The collar360is an annular ring that is preferably made of metal. The collar360has two pairs of diametrically opposed holes364formed in its periphery, as shown inFIG. 15. In alternative embodiments, the collar may have fewer than four holes or more than four holes formed in its periphery.

When the firing pin352is installed within the collar360, the grooves358formed in the pin352align with the holes364. The firing pin352and the collar360are held together by pins362. Specifically, a pin362is inserted into each of the holes364, such that the end of the pin engages the base of the underlying aligned groove358. Once assembled, the firing pin352and collar360are installed within the bore318. When installed, the collar360abuts an annular shoulder368formed in the inner walls surrounding the bore318, as shown inFIGS. 13 and 14. The shoulder368prevents axial movement of the collar360within the bore318.

The collar360is press fit into the walls surrounding the bore318. In alternative embodiments, the collar may be threaded or welded into the walls surrounding the bore. When the control system354is installed within the second section304of the device300, a bottom surface370of the firing pin352is exposed to the surrounding environment within the wellbore10. When the control system354is installed within the second section304, the space between the detonator340and the firing pin352is sealed and maintained at or around the surrounding atmospheric pressure.

With reference toFIG. 16, the control system354operates in response to fluid pressure within the string20. Increased fluid pressure against the pins362causes them to shear, thereby releasing the firing pin352from the collar360. After release, fluid pressure within the string20causes the firing pin352to move rapidly through the bore318and strike the detonator340. The impact will cause the detonator340to ignite. Ignition of the detonator340ignites the cord344, which in turn ignites the charge336. The ignited charge336explodes and severs the surrounding tubular string20, as shown inFIG. 5.

Turning back toFIGS. 3, 11 and 12, a series of notches372are formed in the bottom surface320of the second section304. The notches372provide side openings through which fluid may enter the device300, even when its open base is clogged by debris. A wire or rod376may be threaded through a diametrically opposed pair of holes374, such that the ends of the wire or rod376form a nonzero and acute angle relative to the lower section316. Additional wires or rods376may be installed in other diametrically opposed pair of holes374. The wires or rods376help center the device300within the string20as it is delivered to its desired position, as shown inFIG. 3.

With reference toFIGS. 17 and 18, the device300is installed within the tubular string20by inserting the device300, second section304first, through the open second end34of the string20at the ground surface12. Fluid carries the device300through the second portion30of the string20, shown inFIG. 18, and into the first portion28of the string20, shown inFIGS. 1 and 3.

Turning back toFIGS. 1-3, the device300is positioned by shutting off fluid flow through the string20, such as with the jar100and a ball138. Fluid is then pumped into the string20and allowed to at least partially fill the string20. The device300is lowered into the fluid within the string20, and permitted to float at the desired point of severance.

For example, the string20within the wellbore10may be 1,000 feet long when measured from the ground surface12to the first end24of the string20. The jar100may be positioned on the 1,000thfoot of the string20. The operator may want to sever the string20at 900 feet, allowing 900 feet of string20to be removed from the wellbore10and 100 feet of string20to be abandoned in the wellbore10, as shown inFIG. 5.

In operation, the ball138is inserted into the open second end34of the string20. Once fluid has carried the ball138100 feet through the string20, the device300is inserted into the open second end34of the string20. Pumping of fluid into the string20continues, and the ball138and device300are carried downward with the fluid. The 100-foot spacing between the ball138and the device300is maintained.

Pumping continues until the ball138seats within the funnel element124of the jar100, thereby blocking fluid flow. Once pumping is stopped, the device300floats about 100 feet above the ball138and the funnel element124. Thus, when the ball138seats within the jar100positioned at the 1,000thfoot of the string20, the device300is positioned at or near the 900thfoot of the string20.

Once the device300is at the desired severance position, fluid pressure within the wellbore10will be increased until the pins362are sheared. Once the pins362are sheared, the firing pin352is released and strikes the detonator340. Detonation of the charge336will sever the string20, as shown inFIG. 5. The remains of the device300, together with the severed portion of the string20, will be deposited in the wellbore10.

Turning toFIGS. 19-23, an alternative embodiment of the tubular severance device400is shown. The device400is similar to the device300, except that the device400uses a much longer cord402, as shown inFIGS. 20 and 21. The device400, which has a longitudinal axis G-G, comprises a first section404, a second section406, and a cord402.

With reference toFIGS. 21 and 22, the first section404is identical to the first section302of the device300, with one exception. In the device400, a centralizer408is used to center the device with the string20, rather than the rods376used in the device300. The centralizer408is an X-shaped metal piece that engages the top surface410of the first section404. The centralizer408is concentric with the first section404, and attached to its top surface410with a pair of socket head screws412. Like the first section302, an explosive charge414is positioned within a bore415formed in the first section404. The charge414is identical to the charge336.

Unlike the device300, the first and second sections404and406of the device400are not attached directly. Instead, each section404and406is joined to a cross-over sub416and444which is in turn joined to an end of the cord.402. The first cross-over sub416, which is preferably formed from metal, is attached to the first section404. The first cross-over sub416comprises a body418having a first end424and an opposed second end426. Threads420are formed at the first end422, and a tubular section424projects from the second end426. An internal passage432extends through the sub416. The passage432is aligned with a passage434formed in the charge414. The passages432and434are configured to receive the cord402.

With reference toFIGS. 21 and 23, the second section406comprises a body, preferably formed from metal, having opposed top and bottom surfaces438and440. An internal passage436extends longitudinally through the body and between the surfaces438and440. Adjacent the top surface438, internal threads442are formed in the walls defining the passage436.

The second cross-over sub444, which is preferably identical to the first cross-over sub416, is attached to the second section406. An externally threaded portion446of the sub444mates with the internal threads442of the second section406. When mated, a bottom surface448of the sub444is exposed to the passage436, as shown inFIG. 23. A passage450formed within the second cross-over sub444is configured to receive the cord402.

A firing system452is positioned within the second section406. The firing system452is identical to the firing system350, described with reference toFIGS. 16-19. A detonator454included in the firing system452abuts the bottom surface448of the sub444. When the cord402is installed within the passage450formed in the second cross-over sub444, a bottom surface458of the cord402abuts a top surface460of the detonator454.

When the device400is assembled, the cord402interconnects the detonator454and the charge414. The cord402is made from the same material as the cord344. The portion of the cord402that extends between the subs416and444is surrounded by a flexible seal462. The seal462shown in the figures is a water-resistant tape formed from synthetic rubber. The tape is wrapped multiple times around the cord402so 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 seal462is preferably both flexible and water-resistant. It is flexible so that it may easily bend as the device400passes through the string20wound around the reel32, shown inFIG. 21. It is water-resistant so that it can protect the cord402from fluid contained within the string20.

In operation, the device400is delivered to the desired point of severance in the same manner as the device300. The device400is likewise detonated in the same manner as the device300.

In further alternative embodiments of the device300or400, 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 string20using the jar100. If jarring is unsuccessful, an operator may next try to flush away debris by pumping fluid into the annulus40. Before this step can be carried out, plugs200are first deployed into the annulus40and seated in the perforations18. Deployment of plugs200can occur either before or after jarring is complete. If fluid flushing is unsuccessful, an operator may next deploy one of the tubular severance devices300and400. After the device300or400detonates, a portion of the first portion of the string20may be removed from the wellbore10.

One or more kits may be useful for performing pipe recovering operations. The kits may comprise the jar100, at least one deformable ball138, a plurality of the plugs200, and the tubular severance device300or400.

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.