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Publication numberUS3750752 A
Publication typeGrant
Publication dateAug 7, 1973
Filing dateApr 30, 1971
Priority dateApr 30, 1971
Publication numberUS 3750752 A, US 3750752A, US-A-3750752, US3750752 A, US3750752A
InventorsMott J
Original AssigneeHydril Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Completion and kill valve
US 3750752 A
Abstract
A completion and kill valve adapted to be placed immediately above a packer in the well production tubing including a tubular member having an inner bore and a circulation channel therein permitting communication between the inner bore and the well annulus area adjacent the exterior of the tubular member. A movable sleeve closes or opens communication through the circulation channel in response to various pressures and a spring bias acting on the sleeve. Provisions for locking the sleeve in the open position and subsequently unlocking the sleeve in response to inner bore pressure are provided.
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Description  (OCR text may contain errors)

United States Patent 1191 1111 3,750,752 Mott 5] Aug. 7, 1973 COMPLETION AND KILL VALVE 2,591,087" 4/1952 Millican l66/l5l [751 James D; M i'liiii 311333 2213313116: 1225552 [73] Assignee: Hydril Company, Los Angele Primary Examiner james A. pp C Att0rney--Pravel, Wilsogr & Matthews [22] Filed: Apr. 30, 1971 211 App]. N6; 138,947 [571 ABSTRACT A completion and kill valve adapted to be placed immediately above a packer in the well production tubing [52] Cl 166/224 137/383 including a tubular member having an inner bore and [51] Int Cl Ezlb 43/00 a circulation channel therein permitting communica- [58] Fieid 4 315 131 tion between the inner bore and the well annulus area 66/151 224 625 1 adjacent the exterior of the tubular member. A movable sleeve closes or opens communication through the circulation channel in response to variouspressures [56] References Cited and a spring bias acting on the sleeve. Provisions for UNITED STATES PATENTS locking the sleeve in the open position and subse- 3,583,481 6/ 1971 Vernotzy 166/184 quently unlocking the sleeve in response to inner bore 3,193,0l6 7/1965 Knox 166/224 pressure are provided, 1,684,551 9/1928 Manning 166/151 3,378,068 4/l968 Page, Jr. 166/224 25 Chums, 9 Drawing Flames r\' g /6 1 F N Jaw 20am ivy/2 widw f/fb /I /5e M] r 20$ b- /5a "/5C 27 60 A 50:? 0c ;a 50 p /-506 SZ f (z Ma G 1 /5C s y N we so)"\ v 406 4 m/ 30e- /9fi\i PAIENIEB SIEHZBFS ATTORNEYS COMPLETION AND KILL VALVE BACKGROUND OF THE INVENTION The invention relates to the field of a completion and kill valve.

One of the problems in completing a well has been removing heavy drilling mud fnom the production tubing to allow hydrocarbons within a formation to flow into the production tubing and on to the surface. A prior approach has been to use a swabbing tool in the production tubing to draw the drilling mud to the surface. Swabbing was costly, time consuming and dangerous. For example the drilling fluid brought to the surface made the working area slippery and unpleasant. Nitrogen injection has also been used to complete a well by lowering the density of the drilling mud in the production tubing and allowing the hydrocarbon pressure to overcome the hydrostatic head of drilling fluid. This method was also costly and time consuming as well as requiring special services and equipment.

Other devices to complete a well have permitted circulation of a light fluid down the production tubing with the heavy drilling fluid returning up the annulus, but these devices have required that hazardous wire line, packer or tubing work be done under pressure in either opening or closing the device.

Prior art attempts to kill a well by filling the production tubing with drilling fluid back circulated from the annulus into the tubing have also entailed wire line work under pressure or moving the well head or packer with formation pressure on the tubing in either opening or closing the device.

SUMMARY OF THE INVENTION This invention relates to a new and improved completion and kill valve, including a tubular member adapted to be mounted in a production tubing in a well and having an inner bore communicating with the inner bore of a production string/The tubular member includes a circulation channel therein for permitting communication between the inner bore of the tubular member and the well annulus and a movable member mounted with the exterior of the tubular member which moves in response to a continuous urging means in addition to differential pressures acting on various portions of the movable member to close and open the circulation channel to communication therethrough. A movable, releasable latch member moves to a locking a new and improved completion and killvalve wherein the well may be recompletedafter killing.

Yet still a further object of the'present invention is to provide a new and improvedcompletionandkill valve which maybe locked open in response to surface controlled pressure.

Yet still anotherobject of the present invention is to provide a new andimprovedcompletion and kill valve whichmay be unlocked in response to surface control pressure.

BRIEF DESCRIPTION or THE DRAWINGS FIG. I is a perspective view of the completion and kill valve of the present invention positioned in a single completion well production tubing;

FIG. 2 is a perspective view of the completion and kill valve positioned in a dual completion well production tubing;

FIG. 3 is a perspective view of the employment of a plurality of completion and kill valves in a multiple, for example, triple completion well production tubing;

FIG. 4 is a partial cross-sectional view of the completion and kill valve of the present invention;

FIG. 5 is a view similar to FIG. 2, illustrating the valve of the present invention maintained closed by outer pressure;

FIG. 6 is a view similar to FIG. 4, illustrating the valve of the present invention in the open position;

FIG. 7 is a view similar to FIG. 6, illustrating the valve of the present invention in the locked open position;

FIG. 8 is a .view similar to FIG. 7, illustrating the valve of the present invention in the locked open position prior to unlocking;

FIG. 9 is a view similar to FIG. 4, illustrating another embodiment of the present invention.

As illustrated in FIGS. 1, 2 and 3, the completion and kill valve of the present invention is generally illus trated by the numeral 10 and is connected in atubular production string or conduit T above a packer P as is well known in the art. The production string T is positioned in a well casing ll located in a subsurface formation F for recovery of hydrocarbons within. the formation F through perforations 0, as is well known in the art. I I

As illustrated in FIG. 4, the completion and kill valve 10 is illustrated in more detailand include a tubular member 15 which is connected through the usual box and pin threaded connection 16 and 17, with the production string T. I

The tubular member 15 is provided with an inner bore or channel 20 which communicates with the inner bore or channel 21 of the production tubing T. The inner bore ,20 of the tubular member l5 includes a larger diameter upper portion 200:, a shoulder 20b and a smaller diameter portion 200. I

A circulation channel .25 is formed through the wall of tubular member I5 above the' shoulder 20b for permitting communication between the inner bore 20 and the area adjacent the exterior'of tubular member 15.

A movable member 30is mounted with the tubular member 15 and adaptedto be slidably positioned in an open position, illustrated in FIGS. 6,7 and 8, permitchamber defined by a lower small diameter portion 30c, a first annular tapered shoulder 30f, a lower larger diameter portion 30g, a locking recess 30h, an upper larger diameter portion 301', a second annular tapered shoulder 30j, upper small diameter portion 30k, and sealing surface 30m.

An enlarged outer portion 150 of the tubular member 15 extends into the chamber to serve as a stop and a guide for the sleeve 30. A tapered annular surface 15b located adjacent the circulation channel 25 limits the downward movement of the sleeve 30 by engaging shoulder 30j of the sleeve 30 in the closed position, as illustrated in FIGS. 4 and 5. Outer surface 150 of the enlarged portion 15a is located closely adjacent upper surface 30i to assist in guiding the sleeve 30 in the sliding movement. The sleeve 30 further includes a flow port 30 therein having a smaller flow area than the channel 25 for permitting communication through the sleeve 30 between the area adjacent the tubular member 15 exterior surface adjacent the circulation channel 25 and the annulus l2 exterior of the sleeve 30 when the sleeve is in the open position. The flow port 31 is sealed from communicating with the circulation channel 25, blocking flow through the circulation channel 25, when the sleeve 30 is in the closed position. The sleeve 30 is slidably sealed to the exterior of tubular member 15 at the upper end by a pair of O-rings 30n. The sleeve 30 is also slidably sealed to the tubular member 15 adjacent portion 150 by a pair of O-rings 15d. The lower small diameter portion 30c is slightly larger than the tubular member 15 forming an annular passageway between the tubular member 15 and the portion 30c for communicating the annular pressure adjacent tubular member 15 to a slide member 40.

The movable sealing slide 40 is a ring-shaped member mounted with the tubular member 15 exterior surface and concentrically positioned between the sleeve 30 and the tubular member 15. The member 40 is free to slidably move with respect to both the sleeve 30 and the tubular member l5 between a lower or extended position, illustrated in FIG. 4, and an upper or retracted position, illustrated in FIGS. 5, 6, 7 and 8. The member 40 includes a first annular step shoulder 40a and a second tapered annular shoulder 40b adopted to engage shoulder 30f of the sleeve 30 for a purpose to be described more fully hereinafter. The slide 40 moves to the retracted position in response to the annulus pressure adjacent the tubular member communicated through the annular passageway between the tubular member and the portion 30a of the member 30 acting on the shoulder 40b of the member 40. A pair of 0- rings 15f seal an inner diameter surface 40c of the slide 40 to the tubular member 15. Another pair of O-rings 40: seal an outer diameter surface 40d of sealing member 40 to thesleeve 30. An O-ring 40d also seals the member 40 to the sleeve 30 when the tapered shoulder 40b engages shoulder 30flimiting the area of shoulder 30fcommunication with the annulus l2 pressure when the shoulders 40b and 30f are engaged.

As illustrated in FIGS. 4, 5, 6, 7 and 8, a means for biasing movable member 30 to the closed position is provided by spring 41. The spring is positioned within the chamber between the sleeve 30 and the tubular member 15 and is retained in such position by retainer member 41 mounted with tubular member 15 and the shoulder 40a of the sealing member 40. The engagement of the sleeve shoulder 30f by the sealing member shoulder 40b acts as a carrying means carrying the sleeve 30 to the closed position as the closing biasing of the spring 41 moves the slide 40 to the lower position.

.A sensing channel 45 is formed through the wall of tubular member 15 below the circulation channel 25 for permitting communication from the inner bore 20 of'the member 15 into a portion of the chamber above the shoulder 40a of the movable sealing member 40. The sealing member 40 is maintained in the extended position, illustrated in FIG. 4, in response to greater pressure in the inner bore 20 communicated through sensing channel 45 to the shoulder 40a. This also maintains the sleeve 30 in the closed position.

As illustrated in FIGS. 4, 5, 6, 7, 8 and 9, a means for locking the sleeve 30 in the open position includes a slidably movable ring shaped latch member positioned between the sleeve 30 and the tubular member 15 and having a locking shoulder 50a and a stepped and partially tapered unlocking shoulder 50b. The latch member 50 is movably mounted with respect to both the tubular member 15 and the sleeve 30 between a lower or locking position and an upper or free position. The latch member 50 moves downward to the latch or locking position, illustrated in FIGS. 7 and 8 in response to increased inner bore pressure urging on locking shoulder 50a and upward to the free position, illustrated in FIGS. 4, 5 and 6, in response to increased inner bore pressure urging on unlocking shoulder 50b. A pair of O-rings 50c and 50d seal the latch member 50 to the tubular member 15 exterior surface and the surface 301' of the sleeve 30, respectively. The fastening means further includes a shear pin 51 for maintaining the latch member 50 in the upper position and a split spring radially expansible detent ring 52 positioned below the latch member 50. The detent 52 is adapted to move into the recess 30!: of the sleeve 30 when the sleeve'moves into the open position and is locked in the recess 30h by latch member 50 moving downward within the radially expanded ring 52.

A locking channel 55 is formed through the wall of the tubular member 15 at a location between the sensing channel 45 and the circulation channel 25 for permitting communicating from the inner bore 20 of the tubular member 15 through the locking channel 55 into a portion of the chamber above the locking shoulder 50a of locking member 50. Shoulder 50b of the latch member 50 is positioned in the chamber above the sensing channel 45 for communicating with the inner bore 20 through the sensing channel 45. The locking channel 55 and the sensing channel 45 are blocked from communicating in the chamber by the O-rings 40d and 50d.

A plug or means for controlling communication of pressure in the inner bore 20 to the desired portion of the valve is positioned in the inner bore 20 by lowering or pumping the plug down the inner bore 20 of the production string T which will pass through the larger diameter inner bore 20a portion but will seat on and be retained by shoulder 20b below the circulation channel 25. The plug controls communication of surface controlled increased inner bore pressure above the plug with the sensing channel 45 and the locking channel 55 as desired. The use of a ball sealing the inner bore below the circulation channel is illustrated in FIG. 6 but a ball or plug sealing to and blocking the inner bore below the circulation channel 25 may be used. The

plug 60 embodiment blocks communication of the inner bore above the plug with both the, sensing channel 45 and the locking channel 55 and is used in opening the valve as will be described more fully hereinafter.

Another embodiment of the plug or means for controlling communication of pressure in the inner bore is a locking plug 61, illustrated in FIG. 7, having a shoulder 61a adapted to seat on shoulder 20b of the inner bore 20 and positioning the plug 61 in the inner bore 20. An O-ring 61b seals the plug to the inner bore 20c at a location between the locking channel 55 and the sensing channel 45 permitting the inner bore 20 above the plug 61 to communicate with the locking channel 55, but not permitting communication withthe sensing channel 45. An outer groove 61c and an annular manifold opening 61d adjacent the locking channel 55 permit communication between locking channel 55, the circulation channel 25 and the inner bore 21 of the production tubing T above the plug 61. The sensing channel 45 is blocked by the plug 61 from communicating with the locking channel 55 and circulation channel 25 in addition to the inner bore 21 of the production tubing T above the plug. The plug 61 also blocks communication through the inner bore 20. A port 6le and blocking member 61d assists in the removal of the plug 61, as is well known in the art.

An unlocking plug 62, illustrated in FIG. 8, is another embodiment of the plug or means for controlling communication of pressure in the inner bore 20 above the plug and is positioned in the inner bore 20 by the shoulimmediately adjacent the exterior of the tool the der 62a seating on the shoulder 20b of the inner bore 20 when the plug 62 is lowered in the tubing T. Plug 62 is sealed to the inner bore 20c between the circulation channel 25 and the locking channel 55 by O-ring 62b and between the locking channel 55 and the sensing channel 45 by O-ring 62c and again by O-ring 62d below the sensing channel 45. The unlocking plug 62 permits communication between the inner bore 20 above the plug 62 and the sensing channel 45, but blocks communication of the inner bore 20 above the plug with the locking channel 55. Channel 62c permits communication between the sensing channel 45, the circulation channel 25 and the inner bore 20 above the plug 62. Channel 62f permits communication from the looking channel 55 to the inner bore 20 below the sealing ring 62d of plug 62. Communication between the inner bore 20 above the plug 62 to the inner bore 20 below the plug 62 is also blocked.

In the use and operation of the present invention with the single completion well, illustrated-in FIG. 1, tubular member. is connected in the production tubingT immediately above the packer P for sealing off the annulus 12 above the production zone and. is lowered into the set perforated well casing 12 filled with drilling fluid as is well known in the art. At the desired. location the packer P is set sealing the annulus l2between the casing 11.- and the productionstring T, as is wellknown in the art.

The valve 10 is assembled inrthe production tubing 10 in the condition illustrated in FIG. 4. With equal pressure in the inner bore and the area immediately adjacentthe exterior of: the tool; the exterior pressure provides equalandoffsetting urging on the sleeve 30, while the inner bore pressure communicated through circulation channel and acting on shoulder for moving the sleeve 30 to the open position, is at least greater pressure in the inner bore 20 will act on shoulder 40a to maintain the slide 40 in the lower position and thereby the sleeve 30 in the closed position. As illustrated in FIG. 9, the bore 20 pressure responsive shoulder 40a and 30j may be provided with different size areas on which the pressure urges. By making the shoulder 40a larger than the shoulder 30j pressure in the base 20 will urge the valve closed. In this manner the valve may be pumped closed should the spring 41 malfunction or break.

Lowering the production tubing T into the well casing 11 fills the inner bores 21 and 20 with drilling fluid through the tubing T open lower end and should cause the pressure in the annulus 12 to become greater than the pressure in the inner bore 20 because of the difference in heights of columns of drilling fluid. The greater pressure in the annulus 12 will maintain the sleeve 30 in the closed position, but the slide member 40 will moveto the upper position illustrated in FIG. 5. The movable sealing member 40 has the greater pressure in the annulus 12 acting upwardly on the shoulder 40b while the pressure in the inner bore 20 is acting downwardly on shoulder 40a. Since the effective surface area of shoulders 40a and 40b on which these pressures act are equal, the slide member 40 will move upward. The upward movement of the movable sealing member 40 to a position spaced from the shoulder 30f permits the greater pressure in the annulus 12 to act on the entire shoulder 30f as a means for maintaining the sleeve 30 in the closed position in response to the greater pressure in the annulus 12. This also occurs in the embodiment illustrated in FIG. 9.

To complete the well permitting flow of hydrocarbons from the formation F, it is necessary to displace the heavy drilling fluid from the bore 21 of the production string T with a lower density fluid, as is well known in the art. As illustrated in FIG. 6, the plug or ball 60 for controlling communication in the inner bore 20 is placed in the production string inner bore 21 and .is pumped or lowered until it seats on shoulder 20b positioning the ball 60 between the circulation channel 25 and the sensing channel 45. The pressure in the inner bore 20 above the plug or ball 60 is then increased by injecting the lower density fluid into the inner bore 21' of the production tubing T at the surface by a pump P or other fluid pressure generating means, as is well known in the art. The increased pressure above the plug 60 is communicated through the circulation channel 25 to the shoulder 30c where it urges on the shoulder 302 to overcome the pressure in the annuhrs 12 urging on shoulder 30f or the urging of the movable slide 40 andmoves the sleeve 30 to the open position. This allows the heavy drilling fluid within the inner bore 2110f the production string T above the plug 60 to flow through the circulation channel 25 and the flow port 31 into the annulus 12 of the well above thepacker P. The drilling fluid in the annulus 12 is removed from the well casing 11 at the surface permitting the production string to fill with lighter fluid. When the production string T above the plug 60 is filled with lower density fluid above the blocking means 60, the pumps are stopped decreasing the pressure in the inner bore 20 above the ball or plug 60. When the pressure in the inner bore 20 decreases sufficiently to be substantially equal to the pressure in the annulus 12, the spring 41 closes the valve blocking flow from the inner bore 20 into the annulus 12. With the valve now closed, formation F pressure greater than the hydrostatic pressure within the well casing 11 at the perforations allows the hydrocarbons to flow into the casing 11 through the perforations O and on to the surface through the inner bore 21 of the production tubing T, as is well known in the art. Normally the blocking means 60 is retrieved by the formation pressure flowing the ball 60 to the surface where it is removed from the bore 21 completing the well. The ball 60 may be removed by smashing the ball 60 or by retrieving with a wire line, but the removal by formation pressure with retrieval at the surface is preferred.

To kill the single production zone well by filling the inner bore 21 of the production tubing T with a heavy fluid, the locking plug 61 is lowered down the production tubing inner bore 21 until it seats on shoulder b of the tubular member 10. The plug 61 communicates the inner bore 20 above the plug 61 with the circulation channel 25 and the locking channel 55 while blocking communication past the plug 61. Surface pumps are then used to increase the pressure in the inner bore 21 of the production string T above the plug 61. This increased pressure is communicated to the inner bore 20 above the plug 61 and communicated through the circulation channel 25 to the shoulder a for moving the sleeve 30 to the open position. The pressure in the inner bore 20 above the plug 61 is also communicated by the plug 61 through locking channel 55 to the locking shoulder 50a of the latch member 50. The increased pressure acting on shoulder 50a moves the latch member 50 downward, shearing pin 51, and moving the latch member 50 to the lower position, illustrated in FIGS. 7 and 8. In this position, the step shoulder 50b moves within'the detent52 locking it in the recess 30h of the sleeve 30 and thereby mechanically locking the sleeve 30 in the open position. The latch member 50b prevents the detent 52 from moving out of the recess 30h which would allow the valve to close. With the valve now mechanically locked open, the pumps are stopped. The surface pumps are then connected to the well casing 11 and are used to inject or introduce the heavier drilling'fluid into the annulus 12 above the packer P. The heavier drilling fluid in the annulus 12 then back circulates from the annulus 12 above the packer P through flow port 31 and circulation channel 25 into the inner bore 20 above the plug 61 filling the inner bore 21 of the production tubing T. The lighter fluid displaced by the heavier drilling fluid are removed from the inner bore 21 of the production tubing T at the surface. The heavier drilling fluid in the inner bore 21 establishes a greater hydrostatic head preventing flow of hydrocarbons from the formation through the perforations O in the casing 11 killing the well. Plug 61 may be removed at the surface when the tubing is pulled or retrieved by a wire line when the back circulation is complete nd formation pressure is no longer within the tubing T inner bore 21.

To recomplete a single production zone killed well having a locked open sleeve valve, the locking plug 61 is removed and the cross over plug 62 is lowered down the inner bore 21 of production tubing T until it seats on shoulder 20b. The crossover plug 62 positioned in the inner bore 20 by shoulder 20b permits communications of the inner bore above the plug 62 with sensing channel 45 and the circulation channel 25. The locking channel 55 communicates with the inner bore 20 below the blocking plug 62, but is blocked from communicating with the inner bore above the plug 62. The plug 62 also blocks communication through the inner bore 20. The surface pumps are used to inject the light fluid into the inner bore 21 of the production tubing T. This increases the inner bore 20 pressure above the plug 62 in the open valve 10 and displaces the heavy drilling fluid below the lighter fluid through the circulation channel 25 and the flow port 31 into the annulus 12 of the well above the packer P and back to the surface where it is removed from the casing 11. The increased pressure in the inner bore 20 is also communicated through plug channel 62e and the sensing channel 45 to shoulder 50b of the latch member 50 for moving the latch 50 upward away from the detent 52 unlocking the sleeve 30 and freeing sleeve 30 to be moved to the closed position by the spring 41. Fluid on the upper side 50a of latch member 50 is vented into the inner bore 20 below the plug 62 by channel 62f preventing any trapped fluid from blocking movement of the latch member 50 to the upper position. Light fluid is pumped into the inner bore 21 until it fills all of the inner bore 21 above the plug 62. The pressure in the inner bore 21 is then decreased closing the valve 10. When the plug 62 is retrieved the hydrocarbons are free to flow into the casing 12 through the perforation O and on to the surface through the inner bore 21 of production tubing T as is well known in the art.

FIG. 2 illustrates use of the present invention in a dual completion well. The completion and kill valve 10 is placed in the lower zone production tubing T immediately above the packer P-1 separating the upper and lower production zones. To complete the dual completion well, the plug 60 is lowered down the inner bore 21 of the lower production zone tubing string T until it seats on the shoulder 20b in the inner bore 20 of the valve 10. Surface pumps are then used to injector or introduce a lighter density fluid into the production tubing inner bore 21 above the ball 60 while also increasing the pressure in the inner bore 20 above the ball 60 to open the valve 10. The displaced heavier drilling fluid is removed from the well at the surface through the inner bore 21 of the upper zone production tubing T-1. The lighter fluid is circulated from the inner bore 21 of the production tubing T through the circulation channel 25 into the upper production zone 12a, and through the inner bore 21 of the upper zone production tubing T-1 to the surface. The pumps continue to introduce the light fluid until the inner bore 21 of the upper zone production tubing T is filled with lighter density fluid from the lower zone production tubing inner bore. When the inner bore 21 of both tubings T and T-l are filled with the light fluid, the pumps are shut down, lowering the pressure in the inner bore 20 above the plug 60 and allowing the spring 41 to move the sleeve 30 to the closed position. The pressure in the upper formation is then free to flow hydrocarbons through perforations in casing 11 into the area 12a and on to the surface through the inner bore of production tubing T-l. The plug or ball 60 must be removed from the valve before the production tubing T can flow the lower formation hydrocarbons to the surface.

Use of the valve 10 in the killing of a dual completed well by filling the inner bore 21 of both production tubings T and T-1 with a heavier fluid may be accomplished by two methods. In the first method, the step of the method of completing the dual zone well are repeated with two exceptions. The plug 60 lowered in the inner bore 21 of the production tubing T need not be removed to kill the well. The other change is that a heavy fluid is injected into the inner bore 21 of the lower zone tubing above the plug 60 and allowed to circulate through the valve 10 into the inner bore 21 of the upper zone production tubing T-l and filling both inner bores 21 with the heavy fluid while the lighter fluid is removed from the inner bore 21 of the upper zone production tubing.

In the second method to kill a dual completion well, the locking plug 61 is lowered down the inner bore 21 of the lower zone production tubing T to seat in the valve 10. The pressure in the inner bore 21 above the plug 62 is then increased to open and mechanically lock open the valve 10. Heavy drilling fluid is then injected into the inner bore 21 of the upper zone production tubing T-l while removing the displaced lighter fluid from the inner bore 21 of the lower zone production tubing above the sleeve valve 10. The injection of the heavy drilling fluid is continued until the inner bores of both the upper and lower zone production tubings are filled with heavy drilling fluid thereby killing the well.

i FIG. 3 illustrates the use of the present invention in completing a three zone production well by displacing the heavy fluid in the inner boresof the production tubings. A packer Pl separates the lower zone from the middle zone while a packer P-2 separates the middle zone from the upper zone. The packer P-3 seals the annulus 12 above the upper zone. The bottom two zones are first completed by lowering the plug 60 in the inner bore 21 of the lower zone production tubing to seat in the inner bore of valve 10a and then injecting lighter fluid in .the inner bore 21 of the lower zone production tubing T toincrease the pressure above the plug 60 to thereby open the valve 101:. The displaced heavy drilling fluid is removed from the well through the inner bore 21 of the middle zone production tubing T-l. The injection of the lighter fluid above the plug 60 continues until the inner bore 21 of the middle zone produccirculating back to the surface through the upper zone production tubing T-2, the pumps are shut down decreasing the pressure in the inner bore of the middle zone production tubing T-l, closing the valve 10b. When the plugs 60 are removed, all three zones are ready to produce and the well is completed.

- To kill the triple producing zone well, a plug 60 is lowered down the inner bore 21 of the lower zone production tubing T until it seats on the shoulder 20b within the inner bore of valve 100:. The surface pumps are then used to introduce heavy drilling fluid at increased pressure into the inner bore 21 of the production tubing T to open the valve 10a and circulate the heavy drilling fluid through the annulus 12a into the inner bore of middle zone production tubing T-l and back tothe surface. The lighter fluid is removed from the well through the inner bore 21 of the middle zone production tubing T-1. This circulation fills the inner boreof the two lower production zones tubing T and T4 with heavy drilling fluid. To kill the upper production zone, the plug 60 is lowered down the production tubing T-l until it seats on the shoulder 20b of valve 10b. Surface pumps are then used to introduce heavy drilling fluid into the inner bore 21 of the production tubing T-l at increased pressure. The increased pressure in the inner bore 20 of the middle zone production tubing T-l above the plug 60 opens the valve 10b circulating the heavier drilling fluid into the annulus 12b and back to the surface through the inner bore 21 of the upper zone production tubing T-2. The displaced lighter fluid is removed from the well through the inner bore 21 of the upper zone production tubing T-2. Filling the inner bore 21 of-the upper zone production tubing T2 with the heavy fluid kills theupper zone and completes the killing of the. well.

From the multiple zone methods set out above it is apparent that a plurality of the valves 10 connected in the production tubings may be used to complete and kill a well having any number of production strings. if a plurality of N completion and kill valves 10 are employed, a well having a plurality of N 1 production tion tubing T-l is filled with the lighter fluid. The

into the annulus 12b between packers P-2 and P-3 and up the inner bore 21 of the upper zone production string T-Z to the surface. The heavy fluid within the wellis removed through the inner bore 21 of the upper zone production tubing T-2. When the lighter fluid is strings, may be completed and killed by circulating different density fluid in the. well, through the valves 10. The foregoing disclosure and description of the invention areillustrative 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 without departing from the spirit of the invention.

What is claimed is: j

1. A valve for use in a production tubing with drilling fluids wherein the valve enables production of hydrocarbons and permits shutting off of the tubing string under certain incipient conditions, said valve comprising: t a. a tubular member having a longitudinal inner bore therein and connected at its upper and lower ends to the production tubing with said inner bore communicating with the bore of the production tubing;

b. said tubular member having a circulation channel therein for permitting communication between said inner bore and the annulus between said tubular member and the well casing;

c. a sleeve member concentrically mounted exteriorly with said tubular member for sliding movement from an open position for permitting flow through said circulation channel to a closed position for blocking flow through said circulation channel; 1

d. spring means disposed between said sleeve and said tubular member for urging said sleeve to said closed position when the pressure in said inner bore of said tubular member is substantially equal to the pressure in the annulus adjacent said tubular member wherein said sleeve is biased to said closed position by said spring means;

e. a slide member disposed between said tubular member and said sleeve, said slide member movable between an upper position and a lower position; and

f. said slide member in said lower position engaging said sleeve in the closed position and said slide member moving to the lower position in response to the pressure in said inner bore of said tubular member when the pressure in said inner bore is substantially greater than the pressure in the annulus adjacent said tubular member thereby retaining said sleeve in said closed position.

2. The structure as set forth in claim 1, including a means for maintaining said sleeve in said closed position in response to the pressure in the annulus adjacent said tubular member when such pressure is substantially greater than the pressure in said inner bore of said tubular member.

3. The structure as set forth in claim 2, wherein a. said tubular member having a sensing channel therein located below and spaced from said circulation channel, said sensing channel for permitting communication between said inner bore and the area above said slide member;

b. the space between said sensing channel and said circulation channel being sufficient to receive a plug therebetween;

c. said plug controlling communication between said inner bore above said plug and said sensing channel; and g d. said sleeve member moving to said open position in response to the pressure in said inner bore communicated to said sleeve through said circulation channel when said plug blocks communication between said inner bore above said plug and said sensing channel wherein an increased pressure developed in said inner bore above said plug moves said sleeve member to the open position permitting flow of fluid from said inner bore above said plug into the annulus through said circulation channel.

4. The structure as set forth in claim 3, including lock means in said sleeve for mechanically locking said sleeve member in the open position to prevent said spring means from thereafter moving said sleeve to said closed position.

5. The structure as set forth in claim 4, including unlocking means in said sleeve for unlocking said mechanical locking means and thereby permitting said spring means to thereafter move said sleeve to said closed position.

6. The structure as set forth in claim 4, wherein said locking means includes;

a. a movable latch member positioned between said sleeve and said tubular member for longitudinal b. a detent member positioned below said movable latch member; and

c. said sleeve including a recess in which said detent is adapted to move into when said sleeve is in the open position wherein said detent moves into said recess and is locked in said recess by said movable latch member moving downward.

7. The structure as set forth in claim 6, including:

a. said tubular member having a locking channel therein for permitting communication between said inner bore and the area above said movable latch member, said locking channel being located between said sensing channel and said circulation channel, said locking channel being spaced from said circulation channel to receive a portion of said plug therebetween, said locking channel being spaced from said sensing channel to receive a portion of said plug therebetween;

b. said plug controlling communication between said inner bo're above said plug and said locking channel; and

c. said movable latch member moving downward I when said plug permits communication between said inner bore above said plug and said locking channel wherein increased pressure in said inner bore above said plug communicates to said locking channel by said plug moves said latch' member down thereby locking the sleeve in the open positionv 8. The structure as set forth in claim 7, including unlocking means in said sleeve for moving said movable latch member upward from said detent when an increased pressure in said inner bore above said plug exerts an upward pressure thereon wherein the spring means is thereafter permitted to move said sleeve to said closed position.

9. The structure as set forth in claim 8, wherein said sensing channel communicates with the area below said latch member for exerting an upward pressure on said latch member when an increased pressure in said inner bore above said plug is communicated to said sensing channel by said plug.

10. A well tool, including:

a. a tubular member having a bore extending therethrough and adapted for connection in a production tubing to form a portion thereof with said bore communicating the bore of the production tubing to enable the flow of well fluids therethrough;

b. a circulation channel formed through said tubular member for enabling communication between said bore and an annular area formed about the production tubing; and i c. a member mounted with said tubular member movable to and from a closed position blocking communication through said circulation channel and to and from an open position enabling communication through said circulation channel, said member having means for operably moving said member to enable communication through said circulation channel in response to the urging of controlled fluid pressure in said bore greater than the pressure in the annular area wherein the well tool is operated.

11. The invention as set forth in claim 10, wherein:

fluid pressure in the annular area greater than a fluid pressure in said bore of said tubular member effects said means for operably moving said member to block communication through said circulation channel.

12. The invention as set forth in claim 10, wherein:

fluid pressure in said bore of said tubular member greater than fluid pressure in the annular area effects said means for operably moving said member to block communication through said circulation channel when the fluid pressure in said bore is not controlled.

13. The invention as set forth in claim 10, including:

biasing means for effecting movement of said member to block communication through said circulation channel when the fluid pressure in said bore of said tubular member and the fluid pressure in the annular area are substantially equal.

14. The invention as set forth in claim 10, wherein:

controlled fluid pressure is communicated to a portion of said bore of said tubular member to move said member to enable communication through said circulation channel wherein the well tool is operated.

15. The invention as set forth in claim 10, including:

a plug receivable in said bore of said tubular member to control the fluid pressure in said bore to effect movement of said member by said means for operably moving said member to the open position for enabling communication through said circulation channel in response to the controlled fluid pressure.

16. The invention as set forth in claim 10, including:

a slide member mounted with said tubular member and movable in response to the fluid pressure in said bore of said tubular member to move said member to the closed position for blocking communication through said circulation channel when the fluid pressure in said bore of said tubular member is greater than the fluid pressure in the annular area.

17. The invention asset forth inclaim 16, wherein:

said member is movable in response to the fluid pressure in the annular area to move said member to the position for blocking communication through said circulation channel when the fluid pressure in the annular area is greater than the fluid pressure in said bore of said tubularmember.

18. The invention as set forth in claim 16, including:

a sensing channelformed through said tubular member at a location spaced from said circulation channel for communication the fluid pressure in said bore of said tubular member to said slide member.

19. The invention as set forth in claim 18, including:

a plug receivable in said bore of said tubular member for controlling communication of the fluid pressure in said bore of said tubular member by blocking communication through said sensing channel while moving said member to the open position for enabling flow of fluid through said circulation channel wherein said well tool is operated.

20. The invention as set forth in claim 10, including:

means for locking said member in the open position to thereafter enable communication through said circulation channel when the controlled fluid pressures is absent.

21. The invention as set forth in claim 20, including:

means for unlocking said member from the open position to enable said member to move to the closed position.

22. The invention as set forth in claim 20, wherein said means for locking includes:

a. a latch member mounted with said tubular member and movable in response to the urging of a directional fluid pressure to and from a locking position and to and from a free position; and

b. a movable detent mounted with said tubular member for engaging said member in the open position to thereafter block movement of said member from the open position when said latch member moves to the locking position wherein said well tool is locked open.

23. The invention as set forth in claim 22, including:

a locking channel formed through said tubular member at a location spaced from said circulation channel for communicating the flluid pressure in said bore of said tubular member to said latch member.

24. The invention as set forth in claim 23, including:

a plug receivable in said bore of said tubular member controlling communication of the fluid pressure in said bore of said tubular member through said locking channel for moving said latch member to the locking position to thereafter block movement of said member from the open position wherein the well tool is locked open.

25. The invention as set forth in claim 22, wherein:

said latch member moves to the free position in response to a directional fluid pressure to thereafter enable said member to move to the closed position wherein said member is enabled to move thereafter to the closed position.

' a: ar

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US7866402 *Oct 11, 2007Jan 11, 2011Halliburton Energy Services, Inc.Circulation control valve and associated method
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Classifications
U.S. Classification166/319, 137/508, 137/383, 137/494, 166/323
International ClassificationE21B34/06, E21B34/08, E21B34/00
Cooperative ClassificationE21B34/06, E21B34/08
European ClassificationE21B34/06, E21B34/08