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Publication numberUS3789923 A
Publication typeGrant
Publication dateFeb 5, 1974
Filing dateDec 17, 1971
Priority dateDec 17, 1971
Publication numberUS 3789923 A, US 3789923A, US-A-3789923, US3789923 A, US3789923A
InventorsGarrett H
Original AssigneeBrown Oil Tools
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Method and apparatus for modifying a well to provide gas lift production
US 3789923 A
Abstract
In the method, a perforating device equipped with perforation forming means is lowered through a conventional tubing string and locked with a collar recess at a predetermined subsurface location. On a second trip, a remotely operable actuating device is lowered into engagement with the perforating device and operated to actuate the perforating device which in turn forms perforations through the wall of the surrounding tubing string. On the return leg of the second trip, the perforating device is unlocked and removed from the tubing string along with the attached actuating device. On a third trip, a gas lift valve is lowered through the tubing and anchored with the same collar recess to provide regulated valving of fluids flowing through the perforations.
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Description  (OCR text may contain errors)

United States Patent Garrett Feb. 5, 1974 METHOD AND APPARATUS FOR MODIFYING A WELL TO PROVIDE GAS LIFT PRODUCTION Primary Examiner-David H. Brown Attorney, Agent, or FirmCarlos A. Torres et a1.

[57] ABSTRACT In themethod, a perforating device equipped with perforation forming means is lowered through a conventional tubing string and locked with a collar recess at a predetermined subsurface location. On a second trip, a remotely operable actuating device is lowered into engagement with the perforating device and operated to actuate the perforating device which in turn forms perforations through the wall of the surrounding tubing string. On the return leg of the second trip, the perforating device is unlocked and removed from the tubing string along with the attached actuating device. On a third trip, a gas lift valve is lowered through the tubing and anchored with the same collar recess to provide regulated valving of fluids flowing through the perforations.

The apparatus includes a perforating device and a separate actuating device. The actuating device is lowered into engagement with the perforating device following locking of the perforating device with a subsurface collar recess. The actuating device is surface operated to ignite a charge carried in the perforating device which produces a cutting jet stream to form perforations in the surrounding tubing string. The perforating and actuating devices are locked together for removal as a unit. The apparatus includes a gas lift valve provided with radially movable collar recess anchoring members and axially spaced, self expanding seal members for respectively anchoring the valve with the collar recess and providing a seal above and below the perforations whereby the valve regulates the flow of fluids through the perforations.

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A TTOR/VE/ S PAIENTED FEB 5874 SHEET 3 BF 4 ATTORNEYS METHOD AND APPARATUS FOR MODIFYING A WELL TO PROVIDE GAS LIFT PRODUCTION BACKGROUND OF THE INVENTION 1. Field of the Invention The present invention relates to methods and means for equipping a well with gas lift apparatus for artificial production of the fluids contained within the well. More specifically, the present invention relates to methods and means for equipping a conventional production tubing string with gas lift valves.

2. Brief Description of the Prior Art When the subsurface pressure within a petroleum bearing formation drops below the point required to naturally elevate the petroleum effluents through the well structure at an efficient rate, artificial lifting of the fluids is usually required. Such artificial production is normally effected by simple mechanical pumping or by the use of gas lift techniques. In the latter method of artificial production, pressurized gas is injected into the well from the wellhead and gaslift valves in the well structure are employed to regulate the flow of the gas into the conduit through which the well fluids flow. Normally, the fluid containing conduit is the production tubing string and gas is inserted into the annular area between the production string and the surrounding casing where it is injected into the tubing string by means of gas lift valves secured to the tubing string.

In converting a conventional, naturally produced well to gas lift production, it is not uncommon to remove the conventional tubing string and replace it with a modified string equipped with the required tubing perforations and valves. Often, the modified string includes specially designed landing nipples equipped with perforations and inside pockets which permit placement and retrieval of the gas lift valves after the tubing string is in place.

When the future need for gas lifting of a newly completed well is anticipated before the production tubing is installed, special landing nipples may be included in the tubing string as the string is inserted into the well. In this prior art technique, following decline in the natural formation pressure, a perforating device is employed to form openings through the landing nipple and specially designed gas lift valves are then lowered through the tubing string and landed in the nipple.

The replacement of an entire string is undesirable because of the expense and lost production time associated with removing the original tubing string and replacing it with a gas lift equipped string. While the sec ond prior art method of pre-equipping the string with special landing nipples overcomes this objection, many of the older wells are equipped only with conventional tubing. If the future need for gas lifting any newly completed well is questionable, the extra expense required for the use of special pre-installed landing nipples may be prohibitive. Moreover, subsequent changes in formation conditions may require the positioning of the gas lift valves at points other than those where the landing nipples are located.

Prior art processes and equipment employed to convert a conventional tubing string for gas lift operation may require as many as five separate trips to install each gas lift valve. As used herein, the term trip is employed to define a procedure in which a running tool or other equipment is lowered through the well and thereafter returned to the wells surface. A single lowering and subsequent raising to the surface is considered to be a trip.

The perforating equipment employed in prior art systems is often subject to dangerous prefiring since the perforating means and the actuating or firing mechanisms are handled as a unit in a single trip. Moreover, conventional devices intended for use as gas lift valves in a converted conventional tubing string normally require a mechanism for anchoring the assembly in place and a second separate mechanism intended to provide the valving function. Because of the need for separate components, the complexity of the system is increased and there is a corresponding decline in reliability.

SUMMARY OF THE INVENTION In the method of the present invention, only three trips are required to install a gas lift valve in a conventional production tubing string. On the first trip, a per forating device is lowered through the tubing string to the desired subsurface location and locked with a collar recess formed between two connecting tubing sections. On the second trip, an actuating or firing device is lowered into locking engagement with the perforating device. Surface manipulation of the actuating device ignites a shaped charge in the perforating device which in turn produces a cutting jet stream to form a perforation in the tubing string. On the return portion of the second trip, the perforating device and actuating device are removed to the surface as a unit and on a third trip, a gas lift valve equipped with self-expanding seals is lowered into the tubing string and locked into the collar recess to provide the desired valving of fluids flowing through the perforations.

In the method of the present invention, only three strips are required to install each gas lift valve. Since the perforating device and the activating means are moved downwardly through the tubing string in separate trips, there is no danger of prefiring. Additional safety is provided by forming the perforations below the point where the perforating device is anchored with the tubing string. In addition, anchoring the perforating device and the gas lift valve from the same collar recess ensures precise placement of the valve assembly about the perforation.

The apparatus of the present invention includes a perforating device which is surface operated and may be anchored with any subsurface collar recess in the tubing string. A running tool is employed to position and lock the perforating device in the tubing string. Premature release is prevented by safety members which hold the running tool with the perforating device until radially movable locking dogs have been expanded into a collar recess.

The perforating device is equipped with a charge which when ignited produces a cutting jet action which forms a perforation in the tubing string. An impact responsive ignition or discharge control is carried by the perforating device and when struck, ignites the cutting charge. The ignition control is protected from inadvertent impact and the required discharging impact may be provided only by a separate actuating or firing device which is designed to engage the perforating device after the latter has been securely anchored at the desired subsurface location. Surface manipulation of the actuating device provides the desired discharge impact and locks the actuating device and perforating device together for removal from the tubing string as a unit.

The gas lift valve of the present invention is designed to anchor with the same collar recess previously holding the perforating device so that the valve is precisely positioned with respect to the perforations. The valve assembly is equipped with self-expanding seals which provide a leakproof flow passage between the perforation and the valve. The anchoring means, seal and valve form a single assembly which is positioned within and retrieved from the tubing string as a unit.

From the foregoing, it may be appreciated that the present invention permits a conventional tubing string to be equipped with gas lift valves without the need for removing the tubing string and without the use of preinstalled, specially designed landing nipples. Because of the cooperating design of the perforating device, activating device and gas lift means, only three trips are required to perforate the tubing string and equip it with a gas lift valve. The equipment and method of the present invention permit separate handling of the perforating device and the actuating mechanism required to effect operation of the perforating device. The gas lift valve is self anchoring and sealing to eliminate the need for separate components.

The foregoing as well as other features and advantages of the present invention will be more fully appreciated from the following specification, drawings and related claims.

BRIEF DESCRIPTION OF THE DRAWINGS FIG. 1 is a vertical quarter-section illustrating the perforating device of the present invention being lowered through a tubing string to a subsurface collar recess;

FIG. 2 is a view similar to FIG. I illustrating the perforating device being locked into engagement with a collar recess;

1 FIG. 3 is a vertical elevation in quarter section illustrating an actuating device landed within the perforating device;

FIG. 4 is a quarter sectional elevation illustrating the actuating device of FIG. 3 locked into engagement with the perforating device;

FIG. 5 is a view similar to FIG. 4 illustrating the actuating device delivering an impact to the discharge control means in the perforating device;

FIG. 6 is a view similar to FIG. 5 illustrating the perforating device released from the tubing string prior to removal of the perforating device and the actuating mechanism from the tubing string;

FIG. 7 is a view similar to FIG. 6 illustrating the perforating device and actuating mechanism being moved upwardly through the tubing string;

FIG. 8 is a vertical elevation, in quarter-section, illustrating the gas lift valve assembly of the present invention being lowered into the tubing string;

FIG. 9 is a view similar to FIG. 8 illustrating the valve assembly just before being anchored into the collar recess;

FIG. It) is a view similar to FIG. 9 illustrating the valve assembly locked into engagement with the collar recess with' the running tool released;

FIG. I I is a vertical elevation in quarter-section illustrating the gas lift valve assembly being removed from the tubing string;

FIG. 12 is a horizontal section taken along the line 12-12 of FIG. 2;

FIG. 13 is a horizontal cross-section taken along the line 13-43 of FIG. 2;

FIG. 14 is a horizontal cross-section taken along the line l414 of FIG. 3; and

FIG. I5 is a horizontal cross-section taken along the line 15-15 of FIG. 8.

DESCRIPTION OF THE PREFERRED EMBODIMENT AND METHOD PERFORATING DEVICE FIG. I of the drawings illustrates the perforating device of the present invention, indicated generally at 10. The perforator I0 is illustrated being lowered through a conventional tubing string T by means of a wireline running tool, indicated generally at R, suspended from a wireline W. While the present invention is described as being employed with wireline apparatus, it will be appreciated that other conventional methods or equipment may be employed to position, actuate and retrieve equipment of the present invention. In general, the perforating device 10 is designed to be locked into a tubing collar recess C, released from the running tool R and subsequently engaged and actuated by a separate actuating mechanism to form a perforation in the tubing string T.

The perforating device 10 is equipped with one or more jet perforation forming means 11 designed to be ignited by a primer cord 12 to cut openings through the tubing T. The primer cord is ignited by an impact responsive discharge control 13. The control 13 is a replaceable powder filled cartridge connected to a dynamite cap and is discharged by an impact delivered through an axially movable firing pin 14 mounted in a pin housing 140. A hammer 15 carried above the pin 14 is fixed against movement by a shear pin 15a until actuated by a separate device to be described.

The outer housing of the perforator 10 is formed from threadedly engaged cooperating components which include a lower shoe section 16, an intermediate pin mounting section 17, a body section 18, a latch cage section 19 and an upper retaining collar 20. The lower shoe section 16 mounts and supports the control 13. The jet perforation forming means 111 is threadedly mounted within the tubular wall of the shoe section 16 and an O-ring seal 22 is positioned between the means 11 and the shoe to form a leakproof connection between the two components.

As may best be seen by joint reference to FIGS. 1, 2 and 13, the upper end of the perforating device 10 includes a plurality of dogs 25 which are designed to be moved radially outwardly by axial movement of a setting sleeve 26. The dogs 25 include upper and lower tapered heads 25a and 25b respectively which cooperate with upper and lower tapered recesses 26a and 26b, respectively to control anchoring and release of the perforating device within the tubing string T. It will be appreciated that relative movement between the dogs 25 and sleeve 26 acts through the engaged tapered surfaces to tend to move the dogs out of the recesses. A shear pin 27 extends between the setting sleeve 26 and an inner, loading sleeve 28. A short control sleeve 29 is carried between the setting sleeve 26 and loading sleeve 28 and a plurality of axially developed, resilient collet fingers extend downwardly from a shoulder formed at the upper end of the control sleeve 29. While only a single collet 30 is seen in FIG. 1, it will be appreciated that a plurality of circumferentially spaced, axially extending collets similar to the collet 30 depend from the upper end of the sleeve 29. The lower end of each of the collets is provided with an enlarged head 30. When the componsnets of the perforator are in the position illustrated in FIG. 1, the collet heads a are biased inwardly into an annular recess 28a formed on sleeve 28. A recess 26c formed along the internal wall of the sleeve 26 is adapted to receive the collet heads 30a when the various perforator components have been moved relative to each other into the positions illustrated in FIG. 2. A shoulder 26d formed on the outer wall of the sleeve 26 is employed to prevent relative movement between the anchoring components in a manner to be hereinafter described.

A coil spring 31 is positioned between the base of the sleeve 28 and the top of a pin keeper sleeve 32a which in turn is slidably carried over a safety lock sleeve 32. A rod 33 extends coaxially through the sleeve 32 and the compressed spring 31. The rod 33 is provided with a slot 33a which receives a shear pin 34 carried by the sleeve 32 and held in place by the keeper sleeve 32a. Flanged locking dogs extend through radial openings formed through the base of the sleeve 32 and project into a recess 18a formed in the housing member 18. In the position illustrated in FIG. 1, a circumferential ridge 33b formed about the rod 33 maintains the dogs 35 extended radially outwardly through the openings formed in the sleeve 32 to prevent separation of the perforator 10 and running tool R.

Referring jointly to FIGS. 1, 2 and 12, several holding dogs 36 are mounted for radial movement through the control sleeve 26 and when extended, move into a recess 20a in the collar 20 during the procedure used to anchor the perforator to the tubing string. The loading sleeve 28 is movable with respect to the rod 33 to permit preliminary positioning of the dogs 35 and positioning of the collet heads 30a in the recess 28a. The spring 31 remains compressed until the perforator is anchored.

AN Cl-IORING TI-IE PERFORATOR FIG. 1 illustrates the perforating device 10 and running tool R and they appear when the assembly is being lowered through the tubing string. During the lowering procedure, the spring 31 pushes the sleeves 28 and 32 apart. The base of sleeve 32 engages the base of recess 18a in the housing section 18 and tends to move the attached housing section 19 away from the sleeve 26 which is pinned to the sleeve 28. The opposing movement between section 19 and sleeve 26 urges the dogs 25 outwardly so that the heads 25b are dragged against the internal tubing string wall as the perforator is lowered. When the heads 25a register with a collar recess, additional outward radial movement of the dogs is permitted and the dogs move into the recess. The lower ends of the heads 25b are tapered so that the dogs are moved inwardly when they engage the base of the collar recess so that the assembly may continue to move down through the tubing string with a ratchet-like action.

When the desired subsurface location has been reached, the running tool R is stopped and the perforator 10 is raised upwardly through the tubing string T. As the dogs 25 encounter the first collar recess C in the upward movement, they are moved radially outwardly into the recess. Continued upward movement of the setting tool R is resisted by engagement of the dog heads 25b with the upper end of the collar recess. The tapered surfaces on the setting sleeve 26 and on the dogs 25 tend to urge the dogs further outwardly as greater lift force is exerted to thereby prevent upward movement of perforator 10. This additional lift further compresses the spring 31 and engages the top of keeper sleeve 32a with the base of loading sleeve 28. When sufficient lift is exerted by the running tool R, the pin 27 shears so that the perforator components move into the anchored position illustrated in FIG. 2 of the drawings. Thus, once the pin 27 has been severed, the force of the compressed spring 31 is suddenly released to move the sleeve 28 upwardly with respect to the anchored perforator 10. This upward movement acts through the collets 30 to lift the control sleeve 29, dogs 36 and setting sleeve 26 upwardly relative to the housing section 19 which causes the dogs 36 to move outwardly. The collet heads 30a spring into the recess 26c to maintain the control sleeve 29 in an upper position which in turn retains the dogs 36 at their outermost radial position in the recess 20a.

In the anchored position illustrated in FIG. 2, the upper and lower dog heads, 25a and 25b, respectively, have been moved out of the setting sleeve recesses 26a and 26b. In the anchored position, heads 25b extend radially into the collar recess to the extent required to prevent movement of the perforating device 10 axially above or below the recess. The engagement of dogs 36 with the base of the recess 26a prevents the control sleeve 26 from being moved downwardly with respect to the dogs 25 and the engagement between the base of the collar 20 and the shoulder 26d on the control sleeve 26 prevents the control sleeve from moving upwardly with respect to the dogs 25. Continued upward movement of the rod 33 severs the pin 34 permitting the rod to move into the position illustrated in FIG. 2 which frees the dogs 35 and permits the running too] to separate from the anchored perforating device.

The dogs 35 and ridge 33b cooperate to form a safety mechanism which prevents separation of the perforating device 10 and setting tool R before the dogs 25 have been moved into and locked in their radially outer position. Thus, until the dogs 25 have been expanded radially outwardly into the position shown in FIG. 2, upward movement of the sleeve 32 and control rod 33 draws the dogs 35 into engagement with the top of recess 18a preventing separation of the running tool R and perforator 10. Since the dogs 25 are not extended into the recess C, the upward movement draws both the running tool R and perforator 10 upwardly.

THE ACTUATING MECHANISM (FIGS. 3-7) Once the perforating device 10 has been anchored to the collar recess C, the running tool R and attached set ting assembly are removed from the tubing to complete the first trip of the method. On the first leg of the second trip, an actuating mechanism indicated generally at A is lowered through the tubing string T and into engagement with the anchored perforating device 10. The mechanism A includes a tubular running head 40 which is suspended from the wireline W. A mandrel 41 extends centrally through the member 40 and is held in axial position within the member 40 by a shear pin 42. A coil spring 43 is positioned over the mandrel 41 between the base of the member 40 and the upper end of a keeper sleeve 44a set over a locking sleeve 44. A laterally extending shear pin 45, held in position by the sleeve 44a, extends through the sleeve 44 and through an axially developed slot 46 formed in the mandrel 41. The lower end of the mandrel 41 is threadedly engaged to a shoe portion 47 and an annular ridge 48 is formed along the lower portion of the mandrel. Referring jointly to FIGS. 3 and 14, a plurality of locking dogs 49 are disposed between the mandrel 41 and the surrounding sleeve 44 and are designed to be moved radially through a slot formed in the sleeve 44. The dogs 49 project into the recess 18a to lock the actuating and perforating mechanisms together. The lower end of the sleeve 44 is equipped with an end member 50 which surrounds the mandrel 41 and acts as a guide for axial movement of the mandrel.

OPERATION OF THE ACTUATING MECHANISM AND PERFORATOR As the actuating mechanism A is being lowered through the tubing string T and before it engages the perforating device 10, the components of the mechaism are in the relative positions indicated in FIG. 4. When the lower end of the actuating mechanism A engages the upper end of the anchored perforating device 10, the mechanism telescopes downwardly into the perforating device until the dogs 49 engage the upper end of collar 26. At this point, further downward movement of the actuating mechanism is prevented because of the radial extension of the dogs 49. Weighting means M carried by the wireline W are permitted to rest on the firing mechanism to compress the spring 43 which in turn permits the mandrel 41 to be lowered into the position illustrated in FIG. 3 thereby permitting the dogs 49 to retract by moving off the ridge 48. With the dogs 49 retracted, the actuating device may be moved into the position illustrated in FIG. 4 where the spring 43 moves the sleeve 44 downwardly over the mandrel 41 which in turn moves the dogs 49 radially outwardly into locking engagement with the recess 18a. After the dogs 49 are moved into the recess 18a, the actuating mechanism A and perforating device P are securely locked together.

When the cutting charge 11 in the perforating device 10 is to be ignited or discharged, a downward blow is imparted to the mandrel 41. This blow may be effected by the use of jars or any other suitable means. The impact force is transmitted through the running head 40, through the shear pin 42 and to the mandrel 41 which in turn strikes the hammer severing the pin 15a. The sharp movement of the hammer 15 following severance of the pin 15a discharges the control 13 which ignites the cutting jet charge 11 to form the desired perforation P. It will be appreciated that the perforation forming means described herein are exemplary and that any suitable means carried by the device 10 may be employed for forming a perforation in the tubing T. In the preferred embodiment, the member 13 is a powder charged cartridge employed to ignite a dynamite cap. The element 12 is a primer cord ignited by the dynamite cap and 11 is a shaped charge which produces a torch-like cutting jet to form an opening through the tubing.

After the perforation has been formed, a second, stronger downwardly directed blow is imparted to the head 4% by the jarring mechanism connected to the wireline W. The mandrel 41 engages the hammer 14 which in turn engages the housing section 17 to prevent further downward movement of the mandrel so that the second blow severs the shear pin 41 and permits the head 40 to be moved downwardly over the mandrel 41. Downward movement of the head 40 brings it into engagement with the control sleeve 26 which in turn moves the sleeve 26 down and permits the dogs 36 to be moved radially inwardly. This permits setting sleeve 26 to be moved downwardly with respect to the dogs 25. Once the sleeve 26 has been shifted downwardly as illustrated in FIG. 6, the dogs 25 are free to move radially into and out of the recesses 26a and 26b and the dogs 49 remain atop the ridge 48 so that the actuating mechanism and perforating device remain locked together and may be removed from the tubing string as a unit as illustrated in FIG. 7.

VALVE ASSEMBLY Following formation of the perforation P and removal of the perforating and actuating devices, the valving assembly of the present invention indicated generally at 60 in FIGS. 8-10, is lowered into the tubing string by a running tool indicated generally at R-l. As with the perforating device and actuating mechanism, the valving assembly 60 may be moved downwardly through the tubing string by conventional wireline equipment. FIG. 8 illustrates the assembly as it appears during the first leg or lowering portion of the third strip. The assembly 60 is equipped with a releasable anchoring means similar to that employed to anchor the perforating device 10. The valve anchoring components employed in the valving assembly 60 are identified by reference characters which are higher by than the corresponding components employed in the perforating device. The anchoring assembly includes: a cage member 119; top collar 120 with an internal recess 120a; anchoring dogs with upper and lower head portions 125a and 1251;, respectively; a setting and release sleeve 126; a shear pin 127; loading sleeve 128; control sleeve 129 equipped with collets 130; coil spring 131; safety sleeve 132; a setting rod 133; shear pin 134; dogs 135 and dogs 136.

Anchoring of the valve assembly 60 proceeds in the manner described previously with respect to anchoring of the perforating device 10. As the assembly 60 is lowered through the well bore, upper and lower normally expanded seals and 171 are maintained retracted to prevent formation of a seal with the surrounding tubing string. When the desired subsurface location has been reached, the wireline is pulled upwardly to move the anchoring membersinto positions illustrated in FIG. 9 with subsequent upward pulling bringing the dogs 125 into the collar recess C and permitting the shear pin 127 to sever as illustrated in FIG. 10. It will be appreciated that the movement of the various components during the anchoring action is similar to that previously described with respect to similar components in the perforating device 10.

The seals 170 and 171 are mounted between axially movable end structures which may move toward each other to permit the seals to expand radially outwardly into sealing engagement with the surrounding tubing string T. To this end, the upper seal 170 is mounted over a tubular seal support member 173 which is threadedly engaged at its upper end with the lower end of housing section 119. An upper seal mount member 174 holds the upper end of the seal 170 in place and a lower seal mount member 175 is positioned over the support member 173. The lower mount member 175 is threadedly engaged to a coupling 176 which supports a tubular housing section 178 and a valve mounting section 179. As illustrated in FIGS. 3-10 and 15, a conventional gas lift valve V is threadedly mounted within a recess formed in the section 179.

The lower end of the valve mounting section 179 is threadedly engaged to a second tubular coupling mem ber 1811 which in turn is threadedly engaged to an upper seal mount member 181 holding the upper end of the seal 171 in position. A tubular seal support member 182 extends centrally within the seal 171 and provides a support for a lower seal mount member 183. The upper end of the support 182 is threadedly engaged to a headed bushing 184 and its lower end is tapered to assist in guiding the assembly downwardly through the tubing string.

Resilient O-ring seals are provided between the various components making up the valve assembly to ensure a leakproof seal above and below the perforation P when the seals 170 and 171 are moved outwardly into sealing engagement with the tubing string T. During placement of the assembly 60 within the tubing string, the seals 170 and 171 are retained in radially retracted position by a spacer bar 185 secured to the lower end of the sleeve 132 and extending to the top of bushing 184. The spacer bar maintains the end structures for each of the seals at their greatest axial separation. The normal resiliency of seal 170 tends to draw the tubular sleeve 176 upwardly along the supporting sleeve 173 which in turn tends to permit the seal to expand radially outwardly. A continuous sliding seal between the support member 173 and surrounding coupling sleeve 176 is provided by an annular O-ring seal 186. Similarly, the natural resiliency of seal 171 tends to draw the support member 182 upwardly through the surrounding sleeve 180 to permit the seal 171 to expand radially outwardly. A continuous sliding seal is maintained between the support member 182 and the surrounding coupling 180 by an annular O-ring seal 187. When the running mechanism R-l is latched into the valve assembly 60 in the manner illustrated in FIGS. 8 and 9, the spacer bar 185 maintains the relatively slidable components at their extended position so that the seals 170 and 171 remain retracted radially to prevent formation of a seal between the assembly 60 and the surrounding tubing string T. The headed bushing 184 engages either an internal shoulder formed in the coupling 80 or the base of mounting section 171 to limit axial travel of the support 182. Axial movement of the support 173 is limited by engagement of a shoulder 1730 with the top of section 178 and an internal shoulder in section 176.

OPERATION OF THE VALVE ASSEMBLY Once the dogs 125 in the assembly 60 have been expanded into the recess as illustrated in FIG. 10, the running assembly R-l may be removed from the tubing. In the anchored, sealing position illustrated in FIG. 10, the valve assembly 60 provides a fluid-tight seal above and below the perforation P so that injection gas in the area external to the tubing string T may enter the annular area between the tubing string and the outer housing of assembly 60 where it may be injected into the tubing string T by the valve V. The valve V carried by the assembly 60 is conventional and functions to regulate the flow of injection gas into the tubing string T as a function of the pressure of the injection gas and/or the pressure of the fluids within the tubing string.

The seals and 171 are similar and are selfexpanding once the spacer rod is released and removed from the assembly 60. The seals are preferably of the design illustrated and function to provide a leakproof seal against pressures developed either above or below the seal. For this purpose, the seals are equipped with an annular groove such as the groove 17021 in the seal 170. A plurality of radially directed openings 17Gb extend through the seal and open into a void annular area 170d formed behind the seal. When the assembly is in the position illustrated in FIG. 10, the higher gas pressure entering the annular area between the seals 170 and 171 is communicated through the openings 170a into the upper portion of the annular opening 170d behind the seal 170. This pressure is higher than the pressure in the tubing string T and tends to expand the upper portion of the seal 170 radially outwardly into tight sealing engagement with the surrounding tubing string wall. It will be appreciated that the seal 171 operates in the same manner with the exception that the gas pressure tends to extend the lower portion of the seal radially outwardly into sealing engagement with the surrounding tubing string.

VALVE RETRIEVING APPARATUS In FIG. 11, a retrieving apparatus indicated generally at R-2 is illustrated locked into position with the valve assembly 60. The assembly R-2 includes a tubing control member 211 extending over a central control rod 212. The upper end of the member 211 is threadedly engaged to a sleeve 213 which extends upwardly through the center of a coil spring 214. The rod 212 is provided with an axially extending slot 215 and the member 211 supports a laterally extending shear pin 216 which passes through the slot 215. The upper end of the rod 212 is threadedly engaged to a retaining member 217 which is suspended from a running tool (not illustrated). The external surface of the member 211 is equipped with upper and lower shoulders 211a and 211b, respectively. The lower end of rod 212 is equipped with a circumferential ridge 212a which is adapted to move under locking dogs 218 projecting through openings formed in the lower portion of the member 211.

RETRIEVING THE VALVING ASSEMBLY When the valving assembly 60 is to be removed from anchoring engagement with the tubing T, the retrieving apparatus R-2 is lowered through the tubing string and into engagement with the assembly 60 so that the shoulder 21 1b engages the top of collet 129. Continued lowering compresses the spring 214 and moves the collet 129 downwardly through the surrounding sleeve 126 freeing the dogs 136. Subsequent lowering of the apparatus R-2 brings the shoulder 211a into engagement with the top of sleeve 126 to move the sleeve downwardly. Once the dogs 136 are retracted, the spring 214 snaps the pin 216 to the base of slot 215 so that the ridge 2120 is moved below the dogs 218 causing the dogs to project radially outwardly and engage the base of the sleeve 173 to prevent separation of the retrieving mechanism and the valve assembly 60. With the sleeve 126 moved to its lower position, the dogs 125 are free to retract radially into the position illustrated in FIG. 11 which permits the entire assembly to be withdrawn from the tubing string T.

Although not specifically illustrated, it will be appreciated that the retrieving mechanism R-2 may be equipped with a suitable spacer rod to push the bushing 184 downwardly thereby causing retraction of the seals 170 and 171 to facilitate retraction of the assembly from the tubing string. In the event the assembly 60 should become wedged in the tubing string T, the running mechanism R-2 may be separated from the assembly 60 by pulling upwardly sufficiently to sever the shear pin 216. With the pin 216 severed, the rod 212 and ridge 212a may be raised to the point necessary to permit retraction of dogs 218.

The foregoing disclosure and description of the invention is illustrative and explanatory thereof, and various changes in the size, shape and materials as well as in the details of the illustrated construction may be made within the scope of the appended claims without departing from the spirit of the invention.

1 claim:

1. A system for performing subsurface operations in a tubing string comprising:

a. a perforating device configured for axial movement through said tubing string;

b. perforating means included in said perforating device and operable by an actuating means for forming one or more perforations in said tubing string;

c. locking means included in said perforating device for locking said perforating device at a subsurface location within said tubing string;

d. actuating means for operating said perforating means; and

e. releasable engagement means included in said actuating means for engaging said actuating means with said perforating device after said perforating device is locked to said tubing string and for releasing said perforating device from said tubing string after said one or more perforations have been formed.

2. A system as defined in claim I wherein:

a. said perforating means includes ignitable charge means for discharging to form one or more radial openings through said tubing string;

b. said perforating means includes impact responsive discharge control means for discharging said ignitable charge means; and

c. said actuating means includes remotely operable impact means for delivering an impact to said dis charge control means.

3. A system as defined in claim 1 wherein said locking means includes remotely operable radially movable locking members movable between outer and inner radial positions to respectively anchor to and release from said tubing string whereby said perforating device may be selectively engaged with and disengaged from said tubing string.

4. A system as defined in claim 1 for use in a tubing string of the type formed from a plurality of tubular sections connected to each other at their ends by collars wherein said locking means includes radially movable collar locking means remotely operable to be moved radially outwardly for locking said perforating device with a collar recess formed at the unction of two sections of said tubing string.

5. A system as defined in claim 4 wherein:

a. said perforating means includes ignitable charge means for forming a radial opening in said tubing;

b. said perforating means includes impact responsive discharge control means for discharging said ignitable charge means; and

c. said actuating means includes remotely operable impact means for delivering an impact to said discharge control means.

6. A system as defined in claim 4 wherein:

a. said collar locking means includes a plurality of radially movable locking dogs; and

b. said locking means includes axially movable setting sleeve means movable to a first axial position for retaining said locking dogs in a radially outward position in engagement with a collar recess.

7. A system as defined in claim 6 wherein said setting sleeve means is movable to a second axial position for permitting radial retraction of said locking dogs from said radially outward position and further including remotely releasable holding means for temporarily retaining said setting sleeve means in said first position and, when released, for releasing said setting sleeve means for movement to said second position have been inserted after position.

8. A system for performing subsurface operations in a tubing string comprising:

a. a perforating device configured for axial movement through said tubing string.

b. perforating means included in said perforating device and operable by an actuating means for forming one or more perforations in said tubing string;

c. locking means included in said perforating device for locking said perforating device at a subsurface location within said tubing string, said locking means including remotely operable radially movable locking members movable between outer and inner radial positions to respectively anchor to and release from said tubing string whereby said perforating device may be selectively engaged with and disengaged from said tubing string;

d. a setting mechanism releasably connected with said perforating means, said mechanism including biasing means for urging said locking members to their other radial position before said perforating device is locked to said tubing string and release means for releasing said setting mechanism from said perforating device after said device is locked to said tubing string; and

e. ratcheting means connected with said setting mechanism permitting said locking members to withdraw radially from a collar recess to their inner radial position when said perforating device is moved downwardly through said tubing string while preventing such withdrawal when said perforating device is moved upwardly through said string.

9. A system as defined in claim 8 for use in a tubing string of the type formed from a plurality of tubular sections connected to each other at their ends by collars wherein said locking means includes radially movable collar locking means remotely operable to be moved radially outwardly for locking said perforating device with a collar recess formed at the junction of two sections of said tubing string.

10. A system as defined in claim 8 wherein:

a. said perforating means includes ignitable charge means for discharging to form one or more radial openings through said tubing string; and

b. said perforating means includes impact responsive discharge control means for discharging said ignitable charge means.

11. A system as defined in claim 8 wherein said engagement means includes safety members for preventing separation of said perforating device and said setting means until after said locking members have been moved to their radially outer position.

12. A system as defined in claim 8 further including releasable engagement means in said perforating means for engaging an actuating means with said perforating two sections of said tubing string.

UNITED STATES PATENT OFFICE CERTIFICATE OF CORRECTION Patent No. 3,789 ,923 Dated February 5, i97

lnventor(s) Henry U. Garrett I It is certified that error appears in the above-identified patent and that said Letters Patent are hereby corrected as shown below:

Column 2, line 36: change "strips" to -trip-.

Column 5, line l; change "componsnets" to --components-.

Column 12, line 2 1 after "position" insert lines 2 4 and 25 delete: "have been inserted after "position.".

Signed and sealed this 17th day of September 1974.

(SEAL) Attest:

MCCOY M. GIBSON JR. C. MARSHALL DANN Commissioner of Patents Arresting Officer USCOMM'DC 6O376-P6S US GOVERNMENT PRINTING OFFICE: I959 0-366-334

Patent Citations
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Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US4237976 *Aug 13, 1979Dec 9, 1980Kobe, Inc.Hydraulic well pumping method
US4716970 *Sep 22, 1986Jan 5, 1988Henning Freddie LOil or gas well workover technique
US5101900 *Dec 27, 1990Apr 7, 1992Oryx Energy CompanySand control in wells with gas generator and resin
US5154230 *Dec 17, 1991Oct 13, 1992Oryx Energy CompanyPolymerizing resin to form colsolidate matrix that prevents fl ow of sand
US5360062 *Nov 18, 1991Nov 1, 1994H. Wade WhiteWell tubing and tubing collar therefor
US5361843 *Sep 24, 1992Nov 8, 1994Halliburton CompanyMethod for completing a well
US5390742 *Mar 30, 1993Feb 21, 1995Halliburton CompanyInternally sealable perforable nipple for downhole well applications
EP0575114A1 *Jun 11, 1993Dec 22, 1993Donna K. TerrellLarge head downhole chemical cutting tool
Classifications
U.S. Classification166/55.1, 166/297, 175/4.56
International ClassificationE21B29/02, E21B43/12, E21B29/00
Cooperative ClassificationE21B43/122, E21B29/02
European ClassificationE21B43/12B2, E21B29/02
Legal Events
DateCodeEventDescription
Apr 5, 1982ASAssignment
Owner name: HUGHES TOOL COMPANY A CORP. OF DE
Free format text: MERGER;ASSIGNOR:BROWN OIL TOOLS, INC. A TX CORP.;REEL/FRAME:003967/0348
Effective date: 19811214