Completion and kill valve

[57] 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.

Claims, 9 Drawing Figures

<img file="US3750752A_D0001.tif" />

PATINIEOAUG Mi

3,750.752

SHEET 1 OF 5

<img file="US3750752A_D0002.tif" />

<img file="US3750752A_D0003.tif" />

<img file="US3750752A_D0004.tif" />

<img file="US3750752A_D0005.tif" />

cfa/nej 2) Moff inventor

BY

Rtauef WilCrU

ATTORNEYS

PAWEO*ug τβη

SHEET 2 OF 5

3,750,752

<img file="US3750752A_D0006.tif" />

<img file="US3750752A_D0007.tif" />

<img file="US3750752A_D0008.tif" />

(Ja'/nes J). Afa/f

INVENTOR

BY million ir Aloft 1( etui

ATTORNEYS

PAWEDMIB 71973

SHEET 3 OF 5

3,750,752

<img file="US3750752A_D0009.tif" />

PATENTED^ 7β73

SHEET U Of 5

3,750,752

<img file="US3750752A_D0010.tif" />

c/dsnej d). /Woff

INVENTOR

BY

Rauef U/tZs.&amp;» £ MatflteuM

ATTORNEYS

PATENTED AUG 7»w

SHEET 5 OF 5

3.750,752

<img file="US3750752A_D0011.tif" />

<img file="US3750752A_D0012.tif" />

cTcr/7?ej ^}. /L/ofF

INVENTOR

BY

Ruwef UA/iο* i XaHletuA

ATTORNEYS

3,750,752

COMPLETION AND KILL VALVE which may be unlocked in response to surface control

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 fitom 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 position in response to inner bore pressure communicated through a locking channel for fastening the movable member or sleeve in the open position and moves to a free position in response to inner bore pressure communicated through a sensing channel for releasing the sleeve to thereby enable the sleeve to return to pressure responsive operation.

An object of the present invention is to provide a new and improved completion and kill valve for tubing.

A further object of the present invention is to provide a new and improved completion and kill valve wherein the well may be recompleted after killing.

Yet still a further object of the present invention is to provide a new and improved completion and kill valve which may be locked open in response to surface controlled pressure.

Yet still another object of the present invention is to provide a new and improved completion and kill valve pressure.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 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 produc10 tion 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 comple15 tion 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 20 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 25 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.

DESCRIPTION OF THE PREFERRED EMBODIMENT

As illustrated in FIGS. 1,2 and 3, the completion and kill valve of the present invention is generally illustrated by the numeral 10 and is connected in a tubular ³⁵ 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 11 located in a subsurface formation F for recovery of hydrocarbons within the formation F through perforations O, as is well known in the art.

As illustrated in FIG. 4, the completion and kill valve 10 is illustrated in more detail and include a tubular member 15 which is connected through the usual box and pin threaded connection 16 and 17, with the pro⁴³ duction string T.

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 15 includes a ⁰ larger diameter upper portion 20α, a shoulder 20b and a smaller diameter portion 20c.

A circulation channel 25 is formed through the wall of tubular member 15 above the shoulder 20b for per₅₅ mining communication between the inner bore 20 and the area adjacent the exterior of tubular member 15.

A movable member 30 is mounted with the tubular member 15 and adapted to be slidably positioned in an open position, illustrated in FIGS. 6, 7 and 8, permit6θ ting flow through the circulation channel 25 and a closed position, illustrated in FIGS, 4 and 5, blocking flow through circulation channel 25. The movable member 30 includes an upper portion 30a and a lower portion 30b forming a sleeve concentrically mounted ₆₅ with the tubular member 15 exterior adjacent the channel 25. The portions 30α and 30b are secured together by engagement of thread portions 30c and 30d, respectively. The inner surface of sleeve 30 forms a

3,750,752 chamber defined by a lower small diameter portion 30e, a first annular tapered shoulder 30/, a lower larger diameter portion 30g, a locking recess 306, an upper larger diameter portion 30i, a second annular tapered shoulder 30/ upper small diameter portion 306, and sealing surface 30m.

An enlarged outer portion 15α 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 ISb 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 15c of the enlarged portion 15α is located closely adjacent upper surface 30» 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 12 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 15α by a pair of O-rings ISd. The lower small diameter portion 30e is slightly larger than the tubular member 15 forming an annular passageway between the tubular member 15 and the portion 30e 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 15 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 40α and a second tapered annular shoulder 406 adopted to engage shoulder 30/ 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 15 and the portion 30e of the member 30 acting on the shoulder 406 of the member 40. A pair of firings 15/seal an inner diameter surface 40c of the slide 40 to the tubular member 15. Another pair of O-rings 40e seal an outer diameter surface 40d of sealing member 40 to the sleeve 30. An Ο-ring 40d also seals the member 40 to the sleeve 30 when the tapered shoulder 406 engages shoulder 30/limiting the area of shoulder 30/communication with the annulus 12 pressure when the shoulders 406 and 30/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 40α of the sealing member 40. The engagement of the sleeve shoulder 30/by the sealing member shoulder 406 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 40α 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 40α. 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 50 positioned between the sleeve 30 and the tubular member 15 and having a locking shoulder 50α and a stepped and partially tapered unlocking shoulder 506. 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 50α and upward to the free position, illustrated in FIGS. 4, 5 and 6, in response to increased inner bore pressure urging on unlocking shoulder 506. A pair of O-rings 50c and 50d seal the latch member 50 to the tubular member 15 exterior surface and the surface 30i 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 306 of the sleeve 30 when the sleeve moves into the open position and is locked in the recess 306 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 50α of locking member 50. Shoulder 506 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 20α portion but will seat on and be retained by shoulder 206 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 60 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

3,750,752 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 206 of the inner bore 20 and positioning the plug 61 in the inner bore 20. An O-ring 616 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 with.the 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 61e 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 shoulder 62α seating on the shoulder 206 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 626 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 62e permits communication between the sensing channel 45, the circulation channel 25 and the inner bore 20 above the plug 62. Channel 62/ permits communication from the locking 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 15 is connected in the production tubing T 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 12 between the casing 11 and the production string T, as is well known in the art.

The valve 10 is assembled in the production tubing 10 in the condition illustrated in FIG. 4; With equal pressure in the inner bore 20 and the area immediately adjacent the exterior of the tool; the exterior pressure provides equal and offsetting urging on the sleeve 30, while the inner bore pressure communicated through circulation channel 25 and acting on shoulder 30/for moving the sleeve 30 to the open position, is at least balanced by the same inner bore pressure communicated through sensing channel 45 to the shoulder 40α of the movable sealing member 40. This allows the spring 41 to bias the sleeve to the closed position by the 5 slide 40 engaging shoulder 30/ of the sleeve 30 and moving the sleeve 30 to the closed position as the slide 40 moves to the lower position. This position blocks all communication of the inner bore 20 with the annulus 12 of the well through the valve. Should the pressure 10 in the inner bore 20 become greater than the pressure immediately adjacent the exterior of the tool the greater pressure in the inner bore 20 will act on shoulder 40α to maintain the slide 40 in the lower position and thereby the sleeve 30 in the closed position. As il15 lustrated in FIG. 9, the bore 20 pressure responsive shoulder 40α and 30j may be provided with different size areas on which the pressure urges. By making the shoulder 40α larger than the shoulder 30/ pressure in the base 20 will urge the valve closed. In this manner 20 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 25 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 ³⁰ move to 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 406 while the pressure in the inner bore 20 is acting downwardly on shoulder 40α. Since the effective surface area of shoulders 40α and 406 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 30/permits the greater pressure in the annulus 12 to act on the en⁴⁰ tire shoulder 30/ 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 hydrocar⁵ bons 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 5θ for controlling communication in the inner bore 20 is ^υ placed in the production string inner bore 21 and is pumped or lowered until it seats on shoulder 206 positioning the ball 60 between the circulation channel 25 and the sensing channel 45. The pressure in the 55 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 ₆₀ above the plug 60 is communicated through the circulation channel 25 to the shoulder 30e where it urges on the shoulder 30e to overcome the pressure in the annulus 12 urging on shoulder 30/or the urging of the movable slide 40 and moves the sleeve 30 to the open posi₆₅ tion. This allows the heavy drilling fluid within the inner bore 20 of 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 the

3,750,752 packer 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 O 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 20b 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 30e 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 50α of the latch member 50. The increased pressure acting on shoulder 50α 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 detent 52 locking it in the recess 30b 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 30A 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 50α of latch member 50 is vented into the inner bore 20 below the plug 62 by channel 62/ 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-l. 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 12α, and through the inner bore 21 of the upper zone production tubing T-l 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 forma

3.750.752 tion is then free to flow hydrocarbons through perforations O in casing 11 into the area 12α 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 10 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-l 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.

FIG. 3 illustrates the use of the present invention in completing a three zone production well by displacing the heavy fluid in the inner bores of the production tubings. A packer P-1 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 10α and then injecting lighter fluid in the inner bore 21 of the lower zone production tubing T to increase the pressure above the plug 60 to thereby open the valve 10α. 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 production tubing T-l is filled with the lighter fluid. The pumps are shut down decreasing the pressure in the inner bore 21 of the lower zone production tubing closing valve 10α. A plug 60 is then lowered down the inner bore 21 of the middle zone production tubing T-l until it seats in the valve 10ft. Lighter fluid is then injected at increased pressure into the inner bore 21 of the middle zone production tubing T-l above the plug 60. This opens the valve 10ft and permits flow of fluid from the inner bore 21 of the middle zone production tubing T-l into the annulus 12ft between packers P-2 and P-3 and up the inner bore 21 of the upper zone production string T-2 to the surface. The heavy fluid within the well is removed through the inner bore 21 of the upper zone production tubing T-2; When the lighter fluid is circulating 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 10ft. 5 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 20ft 10 within the inner bore of valve 10α. 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 10α and circulate the heavy drilling fluid through the annulus 12α into the 15 inner bore of middle zone production tubing T-l and back to the surface. The lighter fluid is removed from the well through the inner bore 21 of the middle zone production tubing T-l. This circulation fills the inner bore of the two lower production zones tubing T and 20 T-l 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 20ft of valve 10ft. Surface pumps are then used to introduce heavy drilling fluid into the inner bore 21 of the production 25 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 10ft circulating the heavier drilling fluid into the annulus 12ft and back to the surface through the inner bore 21 ³⁰ 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 T-2 with the heavy fluid kills the upper zone and ³³ 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 ⁴⁰ a plurality of N completion and kill valves 10 are employed, a well having a plurality of N + 1 production 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 in⁴⁵ vention are illustrative and explanatory thereof, and various changes in the size, shape and materials as well as in the details of the illustrated construction may be made without departing from the spirit of the invention.