US3606926A - Apparatus and method for installing and removing well tools in a tubing string - Google Patents

Abstract

A WELL TOOL SYSTEM FOR INSTALLING AND RETRIEVING WELL TOOLS, SUCH AS GAS LIFT VALVES, IN A TUBING STRING. A TUBULAR LATCH IS PROVIDED FOR LOCKING EACH WELL TOOL AT A LANDING NIPPLE IN THE TUBING STRING. THE LATCH HAS LOCKING KEYS WITH OPERATOR MEMBERS MANIPULATED RESPONSIVE TO A SUPPORTING PROBE FOR LOCKING AND RELEASING EACH LATCH AT A LANDING NIPPLE. ONE OR A PLURALITY OF THE LATCHES WITH CONNECTED WELL TOOLS ARE SUPPORTED ON THE PROBE IN TANDEM. THE PROBE AND SUPPORTED LATCHES AND WELL TOOLS ARE CONNECTED IN A TOOL TRAIN WHICH MAY INCLUDE WIRELINE OR PUMP DOWN HANDLING TOOLS WITH SLEEVE VALVE OPERATORS FOR OPENING AND CLOSING SLIDING SLEEVE VALVES AT THE LANDING NIPPLES WHEN INSTALLING AND REMOVING THE LATCHES AND WELL TOOLS. THE TOOL TRAIN IS RUN IN A TUBING STRING TO A DEPTH BELOW THE LOWEST LANDING NIPPLE AND IS THEN RETURNED TO THE SURFACE SEQUENTIALLY RELEASING AND LOCKING THE LATCHES AT THE LANDING NIPPLES SPACED ALONG THE TUBING STRING. THE LATCHES AND TOOLS ARE RETRIEVED BY RUNNING THE TOOL TRAIN WITH A PROBE DOWNWARDLY SEQUENTIALLY RELEASING THE LATCHES AND ENGAGING THEM ON THE PROBE IN END-TO-END ARRAY. WHEN ALL OF THE LATCHES AND WELL TOOLS ARE RELEASED AND ON THE PROBE, THE TOOL TRAIN IS RETURNED TO THE SURFACE. DURING BOTH INSTALLING AND REMOVING THE LATCHES AND TOOLS, THE SLEEVE SHIFTING UNITS IN THE TOOL TRAIN OPEN AND CLOSE THE SLEEVE VALVES AS REQUIRED.

Description

p 21, 1971 H. E. SCHWEGMAN APPARATUS AND METHOD FOR INSTALLING AND REMOVING WELL TOOLS IN A TUBING STRING Filed April 17, 1969 11 Sheets-Sheet 1 INVENTOR. Harry E Schwegmun BY \4 .WbM

ATTORNEY P 1971 H. E. SCHWEGMAN 3,606,926

APPARATUS AND METHOD FOR INSTALLING AND REMOVING WELL TOQLS IN A TUBING STRING Filed April 17, 19653 M 11 Sheets-Sheet 2 .6]? 63/ 6'84 6 c 5%. L5 53! 6'82 0 64 e53 625 a 654 624 622 m; e45

6 see 9 693 F|g.3C U. 52 INVIiN'I'UR.

Harry E.Schwegmon ATTORNEY APPARATUS AND METHOD FOR INSTALLING AND P 21, 1971 H. E. SCHWEGMAN 3,606,926

' REMOVING WELL TOOLS IN A TUBING STRING Filed April 17, 1969 ll Sheets-Sheet 5 INVENTOR. Harry E. Schwegmon AT'I 'ORNEY Sept. 21, H. E. SCH'WEGMAN -wrhmwus AND 14mm) FOR INSTALLING AND a vREMOVING WELL T001; 18 A TUBING sums Filed April 17, 1363? A 11 Sheets-Sheet 4 INVENTOR. Harry E. Schwegmon BY ATTORNEY 11 Sheets-Sheet 5 Sept. 1971 H. E. SCHWEGMAN APPARATUS AND METHOD FOR INSTALLING AND REMOVING WELL TOOLS IN A TUBING STRING Filed April 17, 1969 n .G W mmM w Tg R mm w W.n M .IC 5 5 E 0 W H m m Fig. 6

Sept.- 21, 1971 H. E. SCHWEGMAN APPARATUS AND METHOD FOR INSTALLING AND REMOVING WELL TOOLS IN A TUBING STRING ll Sheets-Sheet 6 Filed April 17', 1969 3 M mm T 9 CHHM ATTORNEY Sept. 21, 1971 H. E. scHwEGMAN 3,606,926

APPARATUS AND METHOD FOR INSTALLING AND REMOVING WELL TOOLS IN A TUBING STRING Filed April 17, I969 l1 Sheets-Sheet '7 m 67m 6' a L 68/01 6I7Q/ Fig. IO C Flg. K) B INVENTOR. l Harry E. Schwegmon BY \4 NwXsM Fig.lOA

ATTORNEY p 21, 1971 H. E. SCHWEGMAN 3,606,926

APPARATUS AND METHOD FOR INSTALLING AND REMOVING WELL TOOLS IN A TUBING STRING Filed April 17, 1969 ll Sheets-Sheet 8 I l K ,vm 753 7;; \LJ WY Fi .l 6I7J g 9 Fig.l6

v INVENTOR. 753 Harry E. Schwgman BY wW M Fig.,l8

ATTORNEY Sept. 21, 1971 H. E. 'SCHWEGMAN 3,606,926 APPARATUS AND METHOD FOR INSTALLING AND REMOVING WELL TOOLS IN A TUBING STRING 11 Sheets-Sheet 9 Filed April 17', 1969 INVENTOR. Harry E. Schwegmun BY Fig.22

A T TORNEY Sept. 21, 1971 H. E. SCHWEGMAN APPARATUS AND METHOD FOR INSTALLING AND 1 REMOVING WELL TOOLS IN A TUBING STRING Filed April 17, 1969 ll Sheets-Sheet l0 INVENTOR. Hoqry E.Schwegmon BY \6 .WNZ} M ATTORNEY Sept. 21, 1971 Filed April 17, 1969 H. E. SCHWEGMAN 3,606,926

APPARATUS AND METHOD FOR INSTALLING AND REMOVING WELL TOOLS IN A TUBING STRING ll Sheets-Sheet 11 ATTORNEY United States Patent 3,606,926 APPARATUS AND METHOD FOR INSTALLING AND REMOVING WELL TOOLS IN A TUBING STRING Harry E. Schwegman, Plano, Tex., assignor to Otis Engineering Corporation, Dallas, Tex.

Filed Apr. 17, 1969, Ser. No. 816,942

Int. Cl. E21b 23/02 US. Cl. 166315 54 Claims ABSTRACT OF THE DISCLOSURE A well tool system for installing and retrieving well tools, such as gas lift valves, in a tubing string. A tubular latch is provided for locking each well tool at a landing nipple in the tubing string. The latch has locking keys with operator members manipulated responsive to a supporting probe for locking and releasing each latch at a landing nipple. One or a plurality of the latches with connected well tools are supported on the probe in tandem. The probe and supported latches and well tools are connected in a tool train which may include wireline or pumpdown handling tools with sleeve valve operators for opening and closing sliding sleeve valves at the landing nipples when installing and removing the latches and well tools. The tool train is run in a tubing string to a depth below the lowest landing nipple and is then returned to the surface sequentially releasing and locking the latches at the landing nipples spaced along the tubing string. The latches and tools are retrieved by running the tool train with a probe downwardly sequentially releasing the latches and engaging them on the probe in end-to-end array. When all of the latches and well tools are released and on the probe, the tool train is returned to the surface. During both installing and removing the latches and too-ls, the

sleeve shifting units in the tool train open and close the sleeve valves as required.

This invention relates to well tools and more specifically to a well tool system for installing and removing tools in a well tubing.

It is a particularly important object of the invention to provide a new and improved tool system for installing and removing well tools in well tubing.

It is another object of the invention to provide a well tool system of the character described which is operable by pumping techniques.

It is another object of the invention to provide a system and method for the installation and removal of well tools in a well located remotely from a surface installation as in the case of an off-shore underwater well connected with an on-shore surface well control and servicing installation.

It is another object of the invention to provide a system which permits well tools to be pumped between a control station and locations'within the tubing of a well.

It is another object of the invention to provide a system for installing well tools in a tubing string wherein each well tool, such as a gas lift valve, is sequentially released and locked in the tubing as a string of the tools including apparatus for manipulating the tools in the tubing is pumped through the tubing.

It is another object of the invention to provide a method and apparatus for the installation of well tools in a tubing wherein a string of well tools is pumped from the surface through the tubing to a depth below that at which one or more of the well tools is to be released and locked in the tubing and the tool or tools are released and locked in the tubing during the return trip of the string of tools toward the surface.

It is another object of the invention to provide a well tool system of the character described wherein a string of tools is pumped through tubing to a collar stop in the tubing below the locations at which the tools are to be released and locked in the tubing with the impact of striking the collar stop partially releasing or arming latches in the tool string for subsequent release from the string and locking in the tubing.

It is another object of the invention to provide a Well tool. system of the character described wherein the string of tools to be installed in the tubing string is pumped only to a depth below the lowest location at which one or more of the tools is to be released and locked in the tubing.

It is a further object of the invention to provide a well tool system of the character described wherein the well tools supported in the tool string are released and locked at desired locations in the tubing string by manipulation of fluid pressure in the tubing.

It is a further object of the invention to provide a well tool system of the character described wherein a string of well tools is pumped through the well tubing to a depth below the location at which the lowermost well tool is to be installed and the tool string is returned toward the surface sequentially releasing and locking each well tool in the string with the supporting and motive means for the string of well tools being returned to the surface and removed from the well system.

It is a further object of the invention to provide a well tool system of the character described wherein the well tools are sequentially released from locking recesses in the well tubing, pumped down the tubing to stop means therein, secured on retrieving means, and pumped as a tool string unit back to the surface.

It is another object of the invention to provide a well tool system which includes a latch for releasably locking a well tool at a locking recess in well tubing, a running probe for supporting and installing the latch in well tubing, and a pulling probe for releasing and removing the latch from the well tubing.

It is another object of the invention to provide a well tool string for pumping through well tubing including a power piston, sleeve valve operating means, and probe means for supporting one or more well tools for movement through the well tubing.

It is another object of the invention to provide a well tool system of the character described including releas able latch means adapted to be pumped with a well tool coupled thereto into well tubing, locked in the tubing,

subsequently released from the tubing, and pumped back to the surface in the tubing.

It is a further object of the invention to provide a well tool system of the character described which includes a power piston for pumping a tool string through a well tubing, a sleeve valve shifter for moving sleeve valves in well tubing from an upper to a lower position, a sleeve valve shifter for moving the sleeve valves back upwardly from the lower position, a running probe for supporting one or more well tools to be released and locked in the well tubing, and one or more latches supportable on the probe to be released and locked in the well tubing for supporting a well tool connected with each of the latches.

It is a further object of the invention to provide a Well tool system of the character described including a power piston, a sleeve valve shifter for returning sleeve valves in a well tubing from a lower to an upper position, and a pulling or retrieving probe for releasing, coupling with, and retrieving well tools from the well tubing.

It is a still further object of the invention to provide a tool string for pumping well tools into well tubing and releasing and locking the tools in the tubing including a running probe adapted to release the well tools supported on the probe responsive to a mechanical impact force against a stop member in the well tubing.

It is another object of the invention to provide a well tool system of the character described including a running probe for supporting the well tools including means for hydraulically releasing the well tools supported on the probe at any desired depth in a well by manipulation of fluid pressures in the well tubing.

It is a. further object of the invention to provide a well tool system of the character described including a pulling probe for releasing and removing the well tools from well tubing and including means for release of the probe from well tools which are stuck or jammed in the well tubing and thus cannot be removed by normal forces applicable through the probe.

It is a still further object of the invention to provide a latch for releasably supporting well tools in a well tubing, the latch being supportable on a probe structure during installation and retrieval and being pumpable through the well tubing from a surface installation.

It is a further object of the invention to provide a well tool system including tool strings for both installation of and removal of well tools such as strings being articulated to permit traverse of curved tubing sections.

It is a further object of the invention to provide a well tool latch for releasably locking a well tool in a tubing including expandable and contractable locking keys movable by operator lugs and sleeve means operable responsive to positioning of a running or pulling probe inserted through a longitudinal central passage through the latch.

It is another object of the invention to provide a well tool latch for releasably locking a well tool in a tubing, such latch having a full bore opening throughout its length.

Additional objects and advantages of the invention will be readily apparent from reading the following description of a device constructed in accordance with the invention and reference to the accompanying drawings where- FIG. 1 is a schematic view of a well system in which a well tool system embodying the invention is operable and showing particularly a fragmentary longitudinal broken section of a cased well having a well tubing system for manipulating the well tool system by pumpdown techniques;

FIG. 2 is a longitudinal view in elevation of a tool string embodying the invention for running-in or installing well tools by pumpdown procedures;

FIGS. 3A-3E constitute a longitudinal view, partially in section, of the tool string including the running probe, latches, and gas lift valves shown in FIG. 2 as the tool string is run into a well tubing;

FIG. 3A shows the head of the running probe and the upper end of the upper latch of the tool string;

FIG. 3B illustrates the lower end of the upper latch and the upper gas lift valve with its upper seal assembly;

FIG. 3C shows the lower seal assembly of the upper gas lift valve and the upper portion of the lower latch in the tool string;

FIG. 3D shows the lower portion of the lower latch together with the upper seal assembly and an upper portion of the lower gas lift valve;

FIG. 3B illustrates a lower portion of the lower gas lift valve with its lower seal assembly and the lower end of the running probe together with the bottom subassembly on the lower gas lift valve for coupling the tools and latches with the running and pulling probes;

FIG. 4 is a cross-sectional view taken along the line 44 of FIG. 3D;

FIG. 5 is an enlarged cross-sectional view of the upper latch mandrel head and locking keys taken along the line 5-5 of the FIG. 3A;

FIG. 6 is an exploded perspective view partially broken away of the major parts of the upper latch;

FIG. 7 is an enlarged cross-sectional view of the upper latch mandrel head taken along the line 7--7 of FIG. 6;

FIG. 8 is a fragmentary view in longitudinal section and elevation showing the lower end of the tool train and the running probe after the train has landed on a stop in the tubing to release the latches from the running probe;

FIG. 8A is a fragmentary longitudinal view, partly in section, showing the relative positions of the running probe, the locking keys and the operating lugs of the lower latch when armed or partially released after the running probe engages the stop as represented in FIG. 8;

FIG. 9 is a view in section of the bottom stop along the line 99 of FIG. 8;

FIGS. 10A through 10D comprise a longitudinal view, partly in section, of the tool string during a return trip in a tubing with the lower latch armed for release and locking at a landing nipple;

FIG. 10A shows the head of the running probe with the upper end of the upper latch;

FIG. 10B illustrates intermediate and lower sections of the lower latch with the locking keys expanded to the tubing wall as the latch moves upwardly toward a landing nipple in the tubing string;

FIG. shows the lower gas lift valve and its upper seal assembly in elevation;

FIG. 10D shows the lower end of the lower seal assembly of the lower gas lift valve and the bottom subassembly of the tool string for coupling the string after the tool string and probe have landed at the bottom stop in the tubing and with the probe moved upwardly relative to the latches and gas lift valve;

FIG. 11 is an enlarged fragmentary view, partly in section, showing the relative positions of the running probe with the latch locking keys and operating lugs when the latch is locked at a landing nipple by its locking keys expanded into the locking recesses of the landing nipple;

FIG. 12 is a view in section along the line 12-12 of FIG. 11;

FIG. 13 is a reduced longitudinal view in elevation of a tool string including a pulling probe, a power piston unit, and a sliding sleeve downshift unit;

FIG. 14- is a fragmentary, longitudinal view partly in section of the lower end of the bottom subassembly of the lower gas lift valve and the lower end of the pulling probe as the pulling probe is initially inserted into the sub assembly;

FIG. 15 is a view similar to FIG. 14 as the pulling probe is lifted engaging the subassembly for raising the lower gas lift valve and latch in the tubing;

FIG. 16 is a fragmentary longitudinal view partly in section, of the lower end of a modified form of pulling probe when inserting the probe into the bottom of a modified form of bottom subassembly adapted for use with the modified probe;

FIG. 17 is a fragmentary longitudinal view partly in section, similar to FIG. 16 showing the pulling probe engaged in the subassembly for lifting the assembly in the tubing;

FIG. 18 is a view similar to FIG. 17 showing the functioning of the releasable feature of the modified pulling probe when the subassembly and its related tools become jammed or lodged in the tubing string;

FIG. 19 is a view similar to FIG. 18 showing a subsequent stage in the functioning of the modified pulling probe as the probe releases from the subassembly;

FIG. 20 is a view in section along the line 20--20 of FIG. 16;

FIG. 21 is a fragmentary longitudinal view in section of the head and bottom ends of a further modified form of running probe adapted to be hydraulically actuated in the tubing string at any desired depth, showing the probe as run into the tubing;

FIG. 22 is a longitudinal view similar to FIG. 21 showing the modified running probe after it has been hydraulically actuated to release the probe from the gas lift valves and latches supported on it;

FIG. 23 is a view similar to FIG. 22 showing only the upper end portion of the modified running probe after mechanically releasing the probe from the gas lift valves and latches at the bottom of a tubing;

FIG. 24 is a. longitudinal view in elevation of a coupler used for connecting together the power piston and sleeve shifting tools in the tool string;

FIG. 25 is a view of the coupler shown in FIG. 24 with its parts shifted so that they are compressed together at one end for insertion into the coupling recess of a well tool;

FIG. 26 is an enlarged exploded perspective view of the two principal parts of the coupler;

FIGS. 27 and 27a taken together illustrated in section and elevation a sliding sleeve valve for use in the well system of FIG. 1, showing the valve at its upper open position, and a sleeve valve shifting tool disposed in the sleeve valve for moving the valve downwardly to a closed position;

FIG. 27 shows upper portions of the sleeve valve and the sleeve shifting tool;

FIG. 27A shows lower portions of the sleeve valve and sleeve shifting tool and a fragment of the coupling of FIGS. 2426 connected into the lower end of the sleeve shifting tool; and

FIG. 28 is a view similar to FIGS. 27 and 27A showing a lower portion of the sliding sleeve valve at a closed position with a sleeve shifting tool for moving the sleeve valve upwardly to an open position.

Referring to FIGS. 1, 2, and 13, a preferred form of tool string 30 embodying the invention includes a pumpable power piston 31 for driving the tool string through a tubing during both well tool installation and retrieval. The piston is connected by a coupler 32 to a sleeve shifter 33 for moving sliding sleeve valves in a well tubing string from lower to upper positions. The sleeve shifter 33 is secured by another coupler 32 to a sleeve shifter 34 for moving the sliding sleeve valves from an upper to a lower position. A running probe 35 is connected by another coupler 32 to the sleeve shifter 34 for supporting well tools and latches during the installation procedure in the well tubing. An upper latch and gas lift valve 41 and a lower latch 40a and lower gas l ft valve 41a are releasably supported on the running probe for installation in a well tubing.

A well system in which the tool string 30 is useful for the installation of well tools, FIG. 1, includes a well 50a having a casing '51 provided with a well head 52 through which a pair of strings of well tubing 53 and 54 are supported in sealed relationship for conduc ing well fluids from the well and directing well servicing fluids into and out of the well. The casing may extend through and be perforated at a producing earth formation, not shown. The tubing 53 extends through a suitable conventional packer 55 downwardly to the vicinity of the producing formation for flowing well fluids to the surface. A lateral conduit connects the lower end of the tubing 54 with the tubing 53 for communicating the tubings when the tool string is to be pumped into or out of the well. A stop 61 is secured in the tubing 53 in the vicinity of the conduit 60 so that when the lower end of the tool s ring engages the stop the piston 31 is above the conduit '60. The tubings 53 and 54 communicate at spaced intervals through crossover connections 62, 63, and 64. The tubings are selectively communicated and isolated from each other by sliding sleeve valves located in the tubing string 53 at the cross-over connections -62, 63 and 64.

A surface installation 72 is connected with the surface ends of the tubings 53 and 54 for controlling the production of well fluids from the well through either of the tubings and for selectively directing fluids, such as lift gas and tool string displacing fluids, into either of the tubings while receiving fluid returns through the other of the tubings. Thus, the surface installation provides both for the control of primary well production and for effecting various well servicing and secondary recovery techniques in the well through the tubing strings and the related cross-over connections and other apparatus. The tubing 53 may include a standing valve, not shown, located below the conduit 60 to allow well fluids to rise from a producing formation into the tubings 53 and 54 while preventing the backfiow of fluids, either well fluids or well servicing fluids, into any of the well conduits below the standing valve.

A pulling tool string embodying the invention is illustrated in FIG. 13 and includes a power piston 31, a sleeve shifter 34 for moving the sliding sleeve valves and a pulling probe 81 for removal of well tools from a locked relationship in a tubing of a well system. The pulling probe comprises an elongated articulated tubular structure for releasing well tools in a tubing and withdrawing the tools from the tubing.

In operation the tool string 30 is inserted into the surface end of the tubing 53 at the surface installation 72 which is adjusted to pump displacing fluid, such as oil or water, through the tubing 53 of the well system 50 and return to the surface installation through the tubing 54. The tool string is pumped downwardly in the tubing 53 with the sleeve shifter 34 sequentially engaging and movingeach of the sliding sleeve valves 65 downwardly to their closed positions as the tool string is pumped to the lower end of the tubing against the stop 61 partially releasing the latches on the probe. When the tool string reaches the stop the direction of fluid flow in the well system is reversed from the surface installation 72 to pump the tool string 30 upwardly on a return trip in the tubing 53. The piston 31 and the sleeve shifting tool 33 pass upwardly through the lowest sleeve valve 65. The sleeve shifter 33 which engages and moves the sleeve valve upwardly to its open position. The upper latch 40 and gas lift valve 41 pass through the lower sleeve valve 65 and the lower latch 40a is then fully released from the probe and locked in the tubing at the locking recess L above the sleeve valve. Continued upward movement of the tool string withdraws the probe from the lower latch and gas lift valve and lifts the probe in the upper latch and gas lift valve shifting the upper latch keys to an intermediate armed condition. The upper latch is lifted by the probe into the next sleeve valve 65 which has been engaged by the sleeve shifter 34 and shifted open. The upper latch 40 and gas lift valve 41 are then released from the probe and locked at the sleeve valve. The tool string, after releasing all of the latch units and gas lift valves supported on its running probe, is pumped back to the surface installation 72 where it is removed from the system so that further well procedures such as gas lift production may be carried out in the well system.

When removal of the latches and gas lift valves from the well system 50 is desired, the tool string 80 with its pulling probe 81 is inserted into the tubing 53 at the surface installation and pumped through the tubing downwardly in the well. As the tool string arrives at the upper latch and gas lift valve the pulling probe is inserted downwardly through the latch and gas lift valve releasing the latch from its locking recess in the tubing. Continued pumping then forces the tool string with the upper latch and gas lift valve on the pulling probe downwardly in the tubing until the tool string reaches the next latch and gas lift valve where the procedure is repeated with the latch and gas lift valve becoming engaged on the probe and forced downwardly with the tool string. Each latch and gas lift valve assembly locked in the tubing is thus sequentially released and engaged on the pulling probe. After each latch and valve assembly is released and forced downwardly, the sleeve valve at which it had been locked is moved downwardly to a closed position by the downshifter 34. The entire tool string including all of the released latches and gas lift valves on the probe are forced downwardly until the lower end of the probe engages the collar stop 61 to cause the latches to be fully locked on the pulling probe. Fluid flow direction is then reversed in the well system pumping the tool string with the pulling probe and latches and gas lift valves engaged thereon back to the surface installation where they are removed from the tubing string.

The surface installation 72 schematically illustrated in FIG. 1 is exemplary of only one arrangement of conduits, valves, pumps, and the like for controlling the production and servicing of a well system. The installation may in the case of an offshore well be situated at a shore location perhaps as far as several miles from the actual location of the well system 50. The tubing 53 at the surface installation is connected through spaced valves 90 and 91 defining a lubricator tubing section 92 for the loading and unloading of the tool strings 30 and 80. Similarly, the tubing 54 at the surface installation includes spaced valves 93 and 94 which define a lubricator tubing section 95 in the tubing 54 which similarly may be used for the insertion and removal of a tool string such as the tool strings 30 and 80. The lubricator sections 92 and 95 communicate through a conduit 100 which connects into the lubricator sections near the valves 91 and 9-4, respectively, so that displacing fluid may be pumped into the lubricators for displacing the tool strings from the lubricators through the tubing into the well system. The conduit 100 is connected through a pair of spaced valves 101 and 102. A conduit 103 is connected into the conduit 100 between the valves 101 and 102. The conduit 103 leads to a reservoir tank 104 through a pump 105 and includes a pair of spaced valves 110 and 111 located on opposite sides of the conduit 100. A return line 112 including a valve 113 leads from the conduit 100 to the reservoir for returning fluids from the lubricator section 95 into the reservoir tank. The conduit 112 is connected into the conduit 100 between the valve 102 and the connection of the conduit 100 into the lubricator section 95. Similarly, a return line 114 including a valve 115 is connected from the reservoir tank into the conduit 100 at a location between the valve 101 and the lubricator section 92. The surface ends of the tubings 53 and 54 connected into the valves 91 and 94, respectively, may lead to well fluid treatment facilities such as separators, storage tanks, and the like and, also, may be connected with other facilities such as means for pumping lift gas into the well system when the well is to be produced by such a secondary recovery method.

The well head 52 and the supporting and sealing connections at the well head for the tubings 53 and 54, may be any suitable standard apparatus.

A preferred form of the sleeve valves 65 in the tubing 53 is illustrated in FIGS. 27 and 27A.

The sleeve valve includes an upper sub 200 which is internally threaded at its upper end for connection with a section of tubing string above it. The sub is provided with the internal spaced recess L for receiving locking keys on the latches 40 and 40a and with a reduced bore portion 203 which receives a seal on the gas lift valves and also functions in holding the lower end portions of the sleeve shifting keys of the sleeve shifter 34 pivoted outwardly while shifting the sleeve valve downwardly. The upper sub is threaded at its lower end into the upper end of a housing section 204 which is provided with a lateral port 205 for providing flow communication into the crossover conduit 63 to the tubing string 54. The lower end of the housing 204 is threaded on the upper end of a lower sub 210 which has an upper bore portion 211, a reduced middle bore or cam portion 212, an a lower bore portion 213 of a diameter intermediate that of the bore portions 211 and 212. An upwardly facing shoulder surface 214 is provided in the bore of the lower sub between the upper bore portion 211 and intermediate bore portion 212.

The sleeve valve 65 is slidably disposed in the housing section for movement between an upper open position, FIGS. 27 and 27A, and a lower closed position, FIG. 28. Upward movement of the sleeve is limited by engagement of its upper end surface 215a with the lower end surface 200a of the upper sub. The sleeve has an upper bore portion 215b which is larger in diameter than the cam bore portion 203 of the upper sub. A plurality of circumferentially spaced lateral ports 220 provided in the sleeve valve are alignable With the housing port 205 when the sleeve valve is at its upper position to provide flow communication between the interior of the valve and the cross-over conduit 60. The sleeve outside diameter is slightly reduced along the ports 220 to provide an annulus around the sleeve for improved fluid distribution. Upper ring seal 221 and lower ring seals 222 are disposed within internal annular recesses provided in the housing 204 above and below the lateral port 205 for sealing between the sleeve valve and the housing. Intermediate its ends, at the lower end of the upper bore portion 215b the sleeve is provided with an internal annular flange 230 providing an upwardly facing shoulder 231 and a downwardly facing shoulder 232 which are engageable by sleeve shifting keys on the shifting tools 33 and 34 for moving the sleeve in the housing. The sleeve valve has a lower end portion 215c of reduced external diameter below the flange 230 which telescopes into the upper bore portion 211 of the lower sub 210 when the sleeve valve is moved downwardly to its lower or closed position. When the sleeve valve is moved downwardly to its closed position the ports 220 are below the seal rings 222 so that there is no fluid flow communication between the exterior of the housing and the interior of the sleeve 215 through the port 205.

The lower end portion of the sleeve valve 215 has a plurality of longitudinally extending circumferentially spaced lands 215d which have upper shoulder surfaces 2152 effectively defining an external annular recess 224 around the sleeve valve at the upper ends of the lands. The lands are provided at their lower ends with down wardly and inwardly slope surfaces 215 An internal annular recess 232 is provided in the housing above the upper end of the lower sub 210, and an inwardly sprung detent 233 in the form of a C ring is disposed in the recess 232 to restrain the sleeve 215 against sliding movement at both its upper open position and its lower closed position so that it is not accidentally moved. The downwardly facing shoulder surfaces 215; on the sleeve lands are engageable with the detent for restraining the sliding sleeve against downward movement, but when sufficient downward force is applied to the sleeve the detent is spread and expanded outwardly into the recess 232a releasing the sleeve to move downwardly until the detent contracts inwardly into the recess 224 at the upper end of the lands for releasably restraining the sleeve at its lower position. An upward force on the sleeve engages the shoulders 215e at the upper ends of the lands with the detent to cam it outwardly to release the sleeve for movement upwardly to its open position as shown in FIG. 27A.

The form of the tool string 30 shown in FIG. 2 includes the power piston 31 Which is a pumpable seal unit movable along a flow conductor responsive to a fluid pressure differential applied across the unit. A suitable power piston which may be used for moving the tool string is illustrated and described in US. Pat. No. 3,318,605, issued to Norman F. Brown, May 9, 1967. The piston unit shown in the Brown patent is pumpable in either direction and thus may be connected into the tool string 30 by engaging the coupling 32 in the swivel cap 23 shown in FIG. 1 of the drawings of the Brown patent.

The coupler 32 is used to interconnect the several tools included in the tool string between the power piston 31 and the probe head 35 as indicated in FIG. 2 so that the tool string is a loosely coupled, fully articulated system which readily traverses curves in the tubings between the surface installation and the bottom ends of the tubings in the well. The coupler is illustrated in detail in FIGS. 24- 26 showing its parts and their relative operational relationships. The coupler comprises a male member 120 and a female member 121 supported together by a coil spring 122. The male member is basically a half tubular structure having end locking flanges 123 and 124 and spring retainer flanges 125 and 126 spaced from each other and spaced inwardly from the end flanges. A male flange section 128 is defined along each longitudinal edge of the coupler member 120 between the end cam surfaces 129 and 130. The female coupler member 121 is a half tubular member similar to the male member 120 and is provided with correspondingly positioned end locking flanges 123a and 124a and spring flanges 125a and 126a. The longitudinal edges of each female member is provided with a female recess 130 defined between sloping end cam surfaces 131 and 132 which are closer together than the cam surfaces 129 and 130 on the male flanges of the male member so that the recess 130' is shorter than the male flange portions 128. The male and female coupler members are held together by the spring 122 which encircles the members and is confined between the flanges 125 and 125a at one end of the members and the flanges 126 and 126a at the other end of the members. In the absence of forced conditions moving one of the members relative to the other, such as by opposite forces acting on the members or one of the members being held while the other is subjected to a longitudinal force, the members are held in alignment by the spring as shown in FIG. 24. When aligned the members are parallel to each other because the male flange portions 128 on the male member extend beyond the ends of the female recesses 130 in the female member so that the vertical longitudinal edges of the female member endwardly of the recesses 130 lie against or engage the longitudinal edge surfaces of the male flange portions 128 thereby supporting the members parallel to each other. A normal running condition of the coupler is as shown in FIG. 24 at which positions of the members the flanged opposite end portions of the coupler are received in well tool locking recesses coupling the well tools together. For example, the flanged end portions of one end of the coupler are received in the coupling recess 603 of the running probe head, FIG. 3A, while the other flanged end portions of the coupler are received in a similar coupling recess at the lower end of the sleeve shifting tool 34.

The end portions at either end of the coupler may be compressed together by longitudinal movement or displacement of one of the coupler members. As for example in FIG. 25, the male and female coupler members are shifted in opposite directions until the cam surfaces 129 on the male flange portions 128 of the male coupler are below the cam surfaces 131 at the upper end of the female recess 130 so that the upper end portion of the male flange portions are received within the upper end portions of the female recesses. At these relative positions of the male and female members the upper end portions of the couplers are compressed together as shown in FIG. 25 thereby reducing the effective diameter of the flanged end portions of the coupler members at the flanges 123 and 123a so that the compressed end of the coupler is insertable into the coupling recess of one of the well tools. After insertion of the compressed end of the coupler the members are released to relax allowing the members to return to the relative positions of FIG. 24 so that the flanged end of the coupling which had been compressed is connected into the coupling recess of the well tool. The other end of the coupler is similarly connected into an end locking recess in another well tool. A more detailed description of the coupler 32 is found in US. Pat. No. 3,428,346 issued Feb. 18, 1969 to John V. Fredd.

The sleeve shifting tool 34 of FIGS. 27 and 27A is symmetrical in form, only half of the tool being shown in the drawings. The tool has a mandrel 370 having an enlarged section 371 provided with a pair of laterally spaced transversely extending slots 372 each of which has an upper portion 372a extending longitudinally substantially parallel with the longitudinal axis of the mandrel and a lower downwardly and inwardly extending portion 372b. Each of the slots 372 receives a transversely extending pin 373 pivotally supporting one of the sleeve shifting keys 321 in longitudinally slidable and pivotal relationship on the body. The opposite end portions of the pivot pins'373 are each secured in a circumferentially arcuate key 321. The keys 321 fit in opposed pivotally supported relationship along opposite sides of the mandrel 370 for both pivotal and laterally expandable and retractable movement on the body. Each key has an upper internal recess 375 conforming generally to the shape of the section 371 on the body and sufficiently longer to provide for the necessary longitudinal movement of the key on the mandrel which is required when each of the keys move downwardly and inwardly on the mandrel. The keys are loosely fitted to permit pivotal and longitudinal movement, Each key has a lower internal recess 379 for receiving a lower external annular enlargement or cam member 380 on the mandrel. The lower end of the recess 379 in each key is defined by an upwardly facing cam surface 381 which is engageable with the downwardly facing cam surface 382 on the lower enlarged section 380 of the mandrel so that downward force is transmitted directly from the mandrel to the lower end portion of each of the keys. Like the upper recess 375 of each of the keys, the lower recess 379 is substantially longer than the section 380 to provide for the desired pivotal and longitudinal movement of each of the keys along the mandrel. Each of the keys has an upper external boss 384 providing an upwardly facing cam surface 385 and a downwardly facing cam surface 390, and a lower external boss 391 provided with an upper cam surface 392 and a lower cam surface 393. The cam surface 393 is engageable with the shoulder surface 231 of the sliding sleeve 215 for moving the sleeve downwardly. Additionally, the outer surface of each of the keys is relieved along a lower portion 321a to facilitate wobbling or pivoting the keys past obstructions in the tubing string and in the flow control device. Each key is somewhat thicker along an upper portion 321]) above an external shoulder 321c to provide suflicient thickness for structural rigidity of the key along the internal recess 375.

The lower end of each key is V-shaped in section as defined by an upwardly and inwardly sloping inner surface 393a and the upwardly and outwardly sloping cam surface 393.

A ring 400 is disposed on the mandrel 370= below the keys and is supported on a spring 401 which biases the ring upwardly against the lower ends of the keys. The upper face of the ring 400 is in the form of a V-shaped groove 400a which is substantially complementary to the shape of the lower ends of the keys, so that the upward force exerted by the ring on the lower ends of the keys tends to cam the lower ends of the keys inwardly toward the tool body. The slopes of the key end surfaces 393 and the corresponding outer surface portion of the groove 400a in the ring 400 is greater than the slopes of the engaging cam surface 382 and the upwardly facing inner key cam surfaces 381 so that the net effect of the upward force of the ring on the lower ends of the keys is to cam the lower end portions of the keys inwardly.

The lower end of the spring 401 is supported by an upwardly facing shoulder surface 402 on a lower connector socket 403 threaded on the lower end of the tool body 370 and locked in place by a pin 403a. The socket 403 functions to receive a coupler 32 for connecting the lower end of the sleeve shifting tool to the running probe 35. An upper connector socket 411 is threaded on the upper end of the mandrel 370 for connecting a coupler 32 to the upper end of the tool in the pump-down tool string.

When the tool 34 is moving freely through a full diameter portion of the tubing string, the spring 401 holds the ring 400 fully in contact with or seated against the lower ends of the sleeve shifting keys so that the keys are restrained at a substantially neutral position generally parallel with the longitudinal axis of the tool body. At such position the internal cam surface 381 at the lower end of the lower recess 379 in each key is biased against the downwardly facing cam surface 382 on the lower enlargement 380 of the tool mandrel 370 and the lower end surfaces 393 and 393a are seated in the key groove 400a. The pivot pin 373 of each key is located in its slot 372 substantially as shown in FIG. 27, though the keys are parallel with the body as distinguished from pivoted outwardly along their lower ends as in FIG. 27.

The tool 34 is moved downwardly in the tool string with its sleeve shifting keys 321 held at their neutral position by the ring 400, until the lower ends of the keys enter the restricted bore portion 203 at the lower end of the sub 200 of the first or uppermost sleeve valve 65. Above this restricted bore portion the internal diameter of the sub, with the exception of those portions along the locking recesses 201 and 202, is the same as the full diameter of the tubing string above the flow control device so that the sleeve shifting keys remain at their neutral position until their lower ends enter the restricted bore portion 203. The restricted bore portion cams the lower ends of the keys slightly inwardly pivoting the keys on the pins 373 so that the lower end portions of the keys pass through the restricted bore portion into the upper bore portion 215b of the sleeve valve 215. As soon as the lower key bosses 391 pass below the restricted bore portion 203, the upward force of the ring 400 against the keys returns the keys to their neutral positions until the upper external bosses 384 on the keys arrive at the restricted bore portion 203. When the upper bosses 384 enter the restricted bore portion, the upper end portions of the keys are cammed inwardly, pivoting the keys on the pins 373 and moving the lower end portions of the keys outwardly. The substantial length of the keys below the support pins compared with the length of the keys above the pins provides for a relatively small amount of inward movement of the upper end portions of the keys to effect a substantial outward movement of the lower end portions of the keys as the keys pivot. The keys and components of the sleeve valve are so relatively proportioned that the upper key bosses 384 enter the restricted bore portion 203 when the lower cam surfaces 293 on the keys are slightly above the cam surface 231 of the sliding sleeve at the upper end of the internal annular flange 215. The tool continues downward movement until the key surfaces393 engage the sleeve shoulder surface 231. Since the restricted bore portion 203 of the sub 200 holds the upper end portions of the keys inwardly, the lower end portions of the keys are held outwardly and cannot move inwardly, so that further downward movement of the tool also moves the sleeve 215 downwardly. The downward force applied at the upper end of the mandrel 370 from the piston unit 31 is transmitted directly from the lower cam surface 382 of the enlarged portion 380 of the mandrel through the lower end portion of the keys to the sliding sleeve at its shoulder surface 231, so that the pins 373 function for pivotal support of the keys but do not transmit force between the keys and the tool mandrel.

As the sleeve valve 215 is forced downwardly in the housing 204, the downwardly facing shoulder surfaces 215 on the lands 215d engage the detent 233 expanding or spreading the ring outwardly releasing the sleeve for downward movement. The sleeve shifting tool continues to force the sliding sleeve valve downwardly so long as the upper bosses 384 of the keys are engaged with the restricted camming bore portion 203 of the upper sub. At substantially the same time as the upper key bosses pass downwardly from the camming bore, the detent 233 enters the upper recess 224 on the lower end portion of the sleeve valve to hold the sleeve at its lower closed position. If the sleeve is forced downwardly slightly beyond the position of alignment of the detent ring with the recess 224 12 the lower end of the sleeve will engage the upwardly facing stop shoulder surface 214 in the bore of the lower sub 210 to prevent any further downward movement of the sleeve.

As soon as the upper bosses 384 of the keys exit from the restricted camming bore portion 203, the lower end portions of the keys are free to pivot inwardly. The upward force of the spring 401 acting on the ring 400, coupled with the camming action of the shoulder surface 231 in the sliding sleeve against the lower outer end surfaces 343 of the keys, cams the lower ends of the keys inwardly as soon as the keys are free to swing or pivot, and the keys are disengaged from the surface 231 of the sliding sleeve, releasing the shifting tool to move downwardly in the tubing string.

The lower outer bosses 391 on the keys move through the internal boss or flange 230' of the sliding sleeve leaving the sleeve at its lower position as the shifting tool moves downwardly. When the upper bosses 384 of the keys arrive at the boss 230, the lower bosses 391 are substantially below the restricted bore portion 212 of the lower sub so that the keys are free to pivot on the pins 373 and the upper end portions of the keys are cammed inwardly until the upper bosses 384 pass downwardly through the sleeve bore 230. The keys continue to wobble, swing, or pivot sufficiently as the tool moves downwardly to fully clear the flow control device, after which the keys are returned by the spring biased ring 400 to their neutral position, in which they remain as the tool moves down wardly in the tubing string until the next sleeve valve is reached.

The tool 34 is returnable to the surface through each of the sleeve valves without shifting the sleeves from their lower closed positions. As the tool passes upwardly through the sleeve valves the keys 321 wobble or pivot on the pins 373 sufliciently for the keys to pass thrOugh the various restrictions in the sleeve valve. If the keys 321 encounter an obstruction in the tubing string or in any of the sleeve valves past which the keys cannot move by normal pivotal action on the pins 373, the keys are forced downwardly and inwardly by the obstruction as the pins 373 move into the lower end portions 37% of the pivot pin slots. The inward position of the keys provides additional lateral clearance around the tool for movement past the obstruction, as already discussed.

FIG. 28 illustrates the sleeve shifting tool 33 for moving the sliding sleeve 215 upwardly from its lower closed to its upper open position, thereby returning the sleeve valve to the position of FIGS. 27 and 27A. The up-shifting tool has a mandrel 501 provided with a central annular enlargement 502 which has a pair of laterally spaced transverse slots 503 formed therein. Each slot has a central longitudinal portion 503a extending substantially parallel with the longitudinal axis of the mandrel, an upwardly and inwardly inclined upper portion 503b, and a downwardly and inwardly inclined lower portion 5030. A pair of oppositely positioned longitudinally extending sleeve shifting keys 504 are each loosely swingably or pivotally supported on the mandrel by a pivot pin 505 which passes through one of the slots 503 and is secured at its opposite ends in the arcuate key.

Each of the keys 504 has a lower internal arcuate recess 510 which receives a portion of the mandrel enlargement 502 and is somewhat longer than the enlargement to permit longitudinal movement along the mandrel. Each of the keys also has an upper internal arcuate recess 511 which receives a cam ring 512 secured by a shear pin 513 on the mandrel for transmitting force from the mandrel to the keys. The ring 512 has a downwardly and outwardly sloping shoulder upper surface 512a which is engageable with the downwardly facing sloping shoulder surface 511a of each key at the upper end of the upper key recess 511. The upper end of each of the keys has boss 524 formed with an outwardly facing upwardly and inwardly sloping upper cam surface 514 and an inner downwardly and inwardly sloping end surface 515 providing a substantially V-shape to the upper end of the key.

A ring 520 is movably disposed on the mandrel above the upper end of the keys and biased downwardly by a spring 521 confined between the ring and an upper socket connector 540 for biasing the keys to a neutral position in the same manner as the ring 400 in the downshifting tool 34. The ring 520 has a lower V-shaped face defined by an inner downwardly and inwardly sloping surface 522 and an outer downwardly and outwardly sloping surface 523. The lower face of the ring is engageable with the V- shaped upper ends of the sleeve shifting keys for releasably holding the keys at a neutral position. Each of the keys also has at its lower end a lower external boss 525. The outer surface of each of the keys is relieved along an upper portion 530 between the bosses to provide sufficient clearance for pivoting past the various restrictions encountered in the tubing string and flow control devices. Each of the keys is somewhat thickened along a lower portion 531 to provide sufiicient material strength along the lower internal recess 510.

The upper socket connector 540 is threaded on the upper end portion of the mandrel 501 for receiving a coupling 32 to connect the upper end of the up-shifting tool to the down-shifting tool 33. The socket connector 540 has a downwardly facing shoulder surface 542 engaged by the upper end of the spring 521 so that the spring for biasing the ring 520 downwardly is confined between the shoulder and the upper face of the ring 520. Similarly, a lower socket connector 543 is threaded on the lower end portion of the tool mandrel for receiving a coupler 32 for connecting the lower end of the up-shifting tool into the running probe.

As the tool 33 is moved downwardly through the tubing string, the sleeve shifting keys 504 are held by the ring 520 in a neutral position in which they are substantially parallel with the tool mandrel, so long as the tool is in normal diameter portions of the tubing string. When the tool reaches the uppermost sleeve valve and the keys enter the restricted cam bore portion 203 of the sleeve, the lower end portions of the keys are pivoted inwardly sufficiently to pass downwardly through such restricted bore into the larger bore of the housing 204 below the upper sub. When the upper bosses 524 of the keys enter the restricted cam bore portion 203 they are cammed inwardly, pivoting the lower end portions of the keys outwardly until the upper end portions of the keys pass below the restricted bore portion. If the sleeve valve'215 is at its lower position, the expanded lower end portions of the keys move freely downwardly in the housing 204 and sleeve without engaging the shoulder 231 of the sleeve. Irrespective of the sleeve valve position, the tool moves downwardly through the sleeve valve with the shifting keys wobbling, swinging, or pivoting sufficiently to clear the various restrictions within the flow control device, including the inner flange or boss 230 of the sleeve and the restricted bore portion 212 of the lower sub 210. If the keys encounter an obstruction beyond which they cannot pass by the normal pivotal or wobbling effect, the keys are forced upwardly on the tool mandrel with the pivot pins 505 moving upwardly in the slots 503 to enter the inwardly sloping slot upper portions 50312 and the keys are retracted inwardly toward each other to provide additional clearance for the keys to pass beyond the obstruction.

Thus, the up-shifting tool passes through all the sleeve valve on its downward run without affecting the valve position. During upward travel the tool moves the valve upwardly to a closed position. As the tool enters a flow control device from below, the upper end portions of the keys enter the restricted bore cam portion 212 of the lower sub 210 camming the upper ends of the keys slightly inwardly until they have moved above the restricted bore portion and enter the lower end of the bore of the sliding sleeve 215. When the lower bosses 525 of the keys enter therestricted-bore portion 212, the lower ends of the keys are cammed inwardly to swing or pivot the keys on the pins 505, swinging the upper end portions of the keys laterally outwardly so that the outer upper end surfaces 514 of the upper bosses engage the lower shoulder surface 232 of the sliding sleeve. The outward movement of the upper ends of the keys cams the ring 520 upwardly against the force of the spring 521. FIG. 28 illustrates the up-shift tool at about the position at which it initially engages the shoulder 232 of the sleeve valve for moving the valve upwardly. The force applied to the mandrel of the tool for moving the tool upwardly is transmitted from the mandrel through the shear pin 513 to the ring 512. The upper face 512a of the ring engages the inner downwardly facing surface 511a of each key, thereby applying upward force to the upper end portions of each of the keys which is then transmitted from the surface 514 of each of the keys to the internal shoulder surface 232 of the sliding sleeve. Thus, the upward force necessary to move the sleeve is not applied to the pivot pins 505.

As the sleeve valve moves upwardly the detent 233 is cammed outwardly into the recess 232 by the upper end surfaces 215e on the sleeve, releasing the sleeve for upward movement. The tool moves the valve upwardly until the bosses 525 .at the lower ends of the key emerge upwardly from the restricted bore cam portion 212, at which time the valve is at its upper closed position and the detent 233 is contracted inwardly around the sleeve below the lower cam surfaces 215 on the lower end portion of the lands 45d on the sleeve valve.

Since the lower bosses 525 on the keys have moved above the restricted bore portion 212 the lower ends of the keys are free to expand slightly, allowing the keys to pivot so the upper end portioins of the keys swing inwardly due to the combined action of the spring biased ring 520 and the shoulder surface 532 acting on the key surfaces 514. The keys are thus cammed inwardly back to their neutral positions. The sleeve is thus released at its upper closed position, with the tool continuing upwardly and the sleeve valve shifting keys wobbling or pivoting to clear the remaining restricted bore portions of the flow control device.

If, when the keysengage the sleeve valve, the valve is stuck and cannot be moved upwardly by the normal force employed with the operating tool string, the shear pin 513 holding the ring 512 on the tool mandrel is sheared. allowing the ring to move downwardly on the mandrel and thereby freeing the sleeve shifting keys for downward movement to the extent permitted by the engagement of the pivot pins 505 in the slots 503. As the keys are forced downwardly, the pins 505 enter the downwardly and inwardly sloping lower end portions 5030 of the slots, so that the keys are retracted inwardly to provide additional clearance for the keys to move upwardly through the sleeve valve, leaving it at the position at which it is stuck.

The running probe 35, which supports a string of well tools such as the latches and gas lift valves illustrated in FIG. 2 during installation of the latches and valves in a tubing, is shown in detail in FIGS. 3A3E. The probe is shown within the latches and gas lift valves supported on the probe. The probe is an articulated assembly which readily bends to traverse curved portions of a flow conduit, such portions leading to underwater wells equipped for pumpdown procedures may have curved lengths designed on radii of approximately 5 feet or greater. Referring to FIG. 3A the probe has a head 600 which includes an upper end cap 601 threaded into a housing 602. The cap has a coupling socket or upwardly opening recess 603 for connection of the coupling. 32 to provide a pivotal support for the head from the coupling. The housing 602 has a port 604 to permit free flow of liquid or gases into and out of the housing to prevent any piston effect within the housing which may interfere with proper operation of the probe. The lower end portion 605 of the probe head housing is reduced in diameter providing an internal shoulder 606 and adownwardly converging external arcuate surface 607. An articulated rod assembly 608 is loosely supported from the probe head on the shoulder surface 606. The rod assembly has a tubular head 609, having an enlarged flange portion 610 which is supported on the shoulder surface 606 in the housing 602. An internal, flexible elongated rod 615 extends throughout the length of the probe holding the rod assembly together while giving it suflicient flexibility to negotiate curve conduit portions in a pumpdown well system. The rod is a relatively slender continuous member threaded along its upper end portion into nuts 616 which support the rod from the rod head 610 as seen in FIG. 3A. A plurality of tubular sections or probe sleeves 617 are supported in end-to-end array along the entire length of the rod 615. The sleeves are generally of substantially the same length with the exception of those such as 617a, FIG. 3B, and 617b, FIG. 3C, which extend through the rigid sections of somewhat longer well tools. The lengths of the probe rod sleeves are gauged to align the joints between them at the joints between adjacent well tools in the string or swivel joints between sections of the tools. For example,;

in FIG. 3B it will be noted that the upper two sleeves 617 meet within the swivel connection between the lower end of the latch 40 and the upper end of the gas lift valve 41. A typical joint or engagement between abutting ends of the sleeves 617 is shown in the broken-away view of the probe in the upper portion of FIG. 3B. The lower end of the uppermost sleeve 617 is provided with an upwardly and inwardly convergent arcuate internal annular surface 617" which is complementary to and engages an upwardly and inwardly convergent external end surface 617' on the adjacent or next downward sleeve 617 of the probe. Each joint between abutting sleeves of the probe on the rod 615 are formed in the same manner as the one shown in FIG. 3B which permits the sleeves to conform generally to the rod 615 for supporting the various tools on the probe as it traverses a curved section of a conduit. The probe sleeve 617a, FIGS. 3B-3C, iS- substantially longer than the sleeve 617 as it extends through the valve section of the gas lift valve assembly 41. The probe sleeve 617b, FIG. 3C, is disposed during the running-in procedure through the lower latch 40a and is provided with a detent spring 618 which is welded along an upper end portion in a recess 619 formed longitudinally along the probe. The spring functions to limit upward movement of the latch on the probe after the latch has been released to its armed condition. As shown in FIG. 3D the probe sleeve 617b is reduced in diameter along a lower end portion providing a shoulder 617a and having a boss 617d spaced from the shoulder 6170. The shoulder 617a and the boss 617d serve release and locking functions during the installation of the latch in a tubing.

As shown in FIG. 3E the lower end portion of the probe rod 615 extends into a bottom probe sleeve 617a and is welded to the sleeve through a plurality of lateral hole 620. The sleeve 617e is solid along its lower end portion below its connection with the rod 615 and is provided with a lateral hole 621 for a shear pin for connection of the probe in the lower end of the string of latches and gas lift valves during the running-in procedure, as discussed in more detail below.

The upper and lower latches 40 and 40a are identical in structure and function in all respects except for the features of the heads of the mandrels of the latches. The upper latch 40 is designed at its head to engage the head of the running probe while the head of the lower latch 40a is designed to be releasably supported from the lower end of the well tool immediately above it on the running probe. The principal characteristics of the latches will be described in terms of and by reference to FIGS. 3C, 3D, and 47. The main parts of both latches are best visualized and understood by reference to FIG. 6. The latches 40 and 40a each include a tubular body or sleeve-like housing 621 an internal operator sleeve 622, operator lugs 623 and 623a, and locating and locking lkeys 624. The upper latch 40 has an internal mandrel 625 supporting the operator sleeve, lugs, keys, and housing while these parts of the lower latch 40a are mounted on a mandrel 625a which is identical to the mandrel 625 in all respects except at its head end. The mandrel 625 has a flared head 626, provided with an internal arcuate surface 630 en gaged by the arcuate surface 607 on the head of the running probe, FIG. 3A when installing a string of tools in a tubing with the probe. The mandrel 625a of the lower latch, FIG. 3C has a head 626a having an internal upwardly opening coupling recess 631 which receives a collet '632 used to secure the lower latch to the lower end of the upper gas lift valve. The head of the mandrel 625a also has a counterbore portion 6310 which receives the detent spring 618 for holding the lower latch against moving upwardly at an intermediate stage in the installation of the latches in a tubing as discussed below. In all other respects, the mandrels of the upper and lower latches are identical in structure and function. In a tool string using more than two latch-gas lift valve combinations the top latch has the mandrel 625 while all of the other latches below include the mandrel 625a since they are each connected to a well tool immediately above as distinguished from the top latch which engages the running probe head.

The latch housing 621 has an upper operating lug recess 633, an intermediate lug recess 634, and a lower lug recess 635 spaced along the body and separated by an upper internal locking surface 636 and a lower looking surface 637.

The operator sleeve 622 has a lower tubular portion 638 of uniform diameter provided with a pair of upper oppositely positioned rectangular windows 639 for the upper lugs 623 and a pair of opposite lower windows 639a for the lower lugs 623a. The illustrated positions of the windows and lugs disposed therein have been revolved in FIGS. 3D, 8A, 10B and 11 for purposes of clarity in illustration and description. The windows 639 and 639a may be located either as illustrated in FIG. 6 or revolved 90 as in the other figures. It is preferred that the FIG. 6 positioning be employed to maximize the structural strength of the operator sleeve 622. The upper portion 640 of the operator sleeve is enlarged in diameter and bifurcated to provide elongate oppositely positioned windows 641 circumferentially spaced from each other and 90 from the lug windows. Each of the windows 641 receives one of the locking keys 624 which are expandable and contractable during the locking and release of the latch in the tubing. The windows 641 extend into the lower reduced diameter portion 638 of the sleeve as best seen in FIG. 6. The sleeve is provided with two pairs of retracting and retainer flanges 642 disposed near the lower ends of and on opposite sides of each of the windows 641 for retaining the key 624 when at its expanded position relative to the sleeve and window. Each flange 642 has a tapered lower end face 642a for retracting and locking the lugs '624. Each of the retainer flanges 642 for each window extends longitudinally of the sleeve and projects circumferentially intothe window from the vertical face of the sleeve defining the longitudinal or vertical sides of the Window. The flanges 642 for each of the windows provides balanced retaining means for the locking key in the window. The lower end of each of the windows 641 is defined by an upwardly and inwardly sloping cam surface 643' which is adapted to engage a similarly inclined lower end edge surface on the key in the window during the expansion of the key to a locking position.

At the upper end of the operator sleeve 622 a pair of diagonally oppositely disposed triangular shaped slots or recesses 644 are provided adjacent the upper ends of the windows 641. One recess 644 is disposed along one side of one window 641 :while the other recess 644 is spaced l80 from the first recess and adjacent the upper end of the other side of the opposite window 641. Each of the recesses 644 receives a portion of a locking key retainer formed on the heads of the mandrels 625 and 625a. The upper end edge surface portions 645 of the operator sleeve each extend circumferentially the width of the window 641 on that side of the sleeve and slope upwardly and inwardly for performing a locking key expansion function. In actual construction practice the operator sleeve 622 is machined so that from the lower end surfaces 643 defining the lower ends of the windows 641 the sleeve is forked or bifurcated to define the two oppositely disposed windows 641 and upper and inwardly opening recess in which a ring 646 is welded providing the upper boundary surfaces of the window 641 by the lower edge surfaces of the ring. The sleeve and ring are then milled to define the two recesses 644. The inner diameter of the ring 646 is the same as the diameter of the remaining portion of the sleeve. Also, the ring is machined to provide the width of the windows 641 tapered end surfaces 645. It will be evident that other approaches to the construction of the operator sleeve may be employed to form the novel shape of the upper end of the sleeve, the windows, and retainer flanges and related features shown in FIG. 6.

The locking keys 624 are identical and each provided with spaced outer bosses 650 and 651 which are contoured to conform to the shape of the particular tubing locking recess at which it is desired the latch be released and locked. The shape of the locking bosses on the keys may be varied for several latches to be run in a particular tubing so that the keys of each latch will fit only a particular specified looking recess while passing all other recesses along the tubing. In this way it is known exactly which locking recess. the latch will release from the running probe and lock in. Each locking key has an arcuate inner surface 652 corresponding to the outer surface configuration of the portion of the mandrels 625 and 625a within the keys as best seen in FIG. 5. Each key has an internal arcuate lateral recess 653 the upper end of which is defined by a sloping cam. surface 654 which is engageable by the cam surface 645 on ring 646 of the operator sleeve 622 for expanding the key during the locking of the latch in a tubing. The portion 652a of the inner key surface 652 above the recess 653 is engaged by the ring portion 646 across the window 64-1 when the key is fully expanded for holding the key at its expanded position. Each key is provided along opposite edges or sides with an outwardly opening longitudinal recess 655 which receives the retainer flanges 642 when the key is in the window 641. The lower end of each side recess 655 is defined by a cam surface 656 which is engaged by the face 642a of the adjacent retainer flange 642 during the retraction of the locking keys and while holding the keys retracted. The positioning of the cam surfaces 656 at opposite sides of each of the keys near the lower end thereof provides balanced forces applied by the flanges 642 to the lower end of the key for smoothly and evenly retracting the keys responsive to downward movement of the operator sleeve 622. Each of the keys has oppositely disposed side retainer flanges 657 which are engaged by the inner surfaces of the retainer flanges 642 of the operator sleeve to aid in holding the keys when they are in their fully expanded positions. The inner surfaces of the flanges 642 engage the outer surfaces of the key flanges 657. The key flanges project from the side surfaces 655 of the keys as seen in FIG. 6. Each of the locking keys has an upwardly and outwardly opening upper side recess 658 along one side of the upper end portion of the key with a retainer ear 659 projecting from the side of the key near its inner surface 652 for holding the upper end of each key in alignment during its expansion and contraction and while at any given position relative to the mandrel and operator sleeve. Each of the keys has an upper inwardly facing sloping end surface 660.

Both the mandrels 625 and 625a have a tubular body portion 661 provided with oppositely disposed longitudinal windows 662 through which the inward portions of the operator lugs 623 and 623a project to engage the articulated rod sleeves of the running and pulling probes. As best seen in FIG. 4, the longitudinal side edges 663 of the windows 662 are inwardly convergent so that the operator lugs may not move into the mandrel when the pulling or running probe is not disposed through the mandrel. The window side edges 663 engage the side edges of the operator lugs loosely to limit the inward movement of the lugs while allowing them to expand outwardly for movement of the operator sleeve 622 during the various steps of locking and releasing the latch. The operator lugs must be free to move radially inwardly and outwardly from an inward position at which they are aligned with the locking surfaces 636 and 637 within the body 621 and expanding positions at which their outer portions are received in the recesses 633, 634, and 635 of the housing 621. The inward portions of the lugs must project through the windows 662 suificiently to engage the running and pulling probes disposed through the latch during installation and retrieval of the latch.

The upper portion of the mandrels 625 and 62511 aligned within the locking keys are undercut to provide arcuate longitudinal surfaces 664 along opposite sides of the mandrel spaced circumferentially from the windows 662 and corresponding in shape to the inner surfaces 652 and 652a of the locking keys so that the locking keys may be slightly thicker and also may fully retract within the operator sleeve windows to the positions illustrated in FIGS. 5 and 3C.

The mandrel surfaces 664 are cylindrical but on a larger radius than the other cylindrical surfaces of the mandrel. The head 664 of the mandrel 625 is provided with the internal annular arcuate surface 630 at its upper end and with a downwardly and inwardly convergent surface 665 which is engaged by the upper end surfaces 660 of the locking keys. A pair of oppositely disposed retainer projections 666 spaced circumferentially apart extend downwardly from the head 664 a short distance along the tubular portion of the mandrel, each provided with an upwardly and outwardly sloping recess 667 provided in the side face of the projection aligned to receive the locking ear 659 of the locking key 624 disposed along the mandrel surface 664 adjacent to the projection. It willbe noted that each of the locking keys is provided with only one locking ear 659 so that each of the projections 666 has a recess 667 only in that side of the projection facing the adjacent locking key.. The ear 659 is received in the recess 667 to hold the upper end of the locking key at any position of expansion or contraction of the key and guide the key during expansion and contraction. The lower lato'h mandrel 625a is identical other than having the coupling recess 631 instead of the arcuate end surface 630.

When the latches are assembled, the operator sleeve 622 is telescopedinto the housing 621 with the lower reduced diameter portion 638 of the sleeve disposed within the body, the relative longitudinal positions of the hous ing and sleeve depending upon the state of contraction or expansion of the looking keys. The mandrel, 625 in the case of the upper latch, 625a in the lower latch, is telescopically disposed within the operator sleeve with its retainer 666 aligned with the recesses 644 of the operator sleeve so that when the operator sleeve is forced upwardly on the mandrel the retainers enter the recesses 644 of the sleeve. The lugs 623- and 623a are disposed through the mandrel windows 663 and the operator sleeve Windows 639 and 6394: with the outside portions of the lugs extending outwardly of the sleeve to cooperate with the recesses and locking surfaces within the housing 621 while the inner portions of the operating lugs project inwardly of the mandrel windows 663 to function with the running or pulling probe. The locking keys 624 are each positioned within an operator sleeve window 641. The ears

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