US3465820A

US3465820A - Retainer packers having a rotating valve

Info

Publication number: US3465820A
Application number: US673190A
Authority: US
Inventors: James W Kisling
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 1967-10-05
Filing date: 1967-10-05
Publication date: 1969-09-09
Anticipated expiration: 1986-09-09
Also published as: DE1801038A1; JPS4916321B1; GB1195156A

Description

P 9, 1959 J. w. KISLING m 3,465,820

RETAINER PACKERS HAVING A ROTATING VALVE Filed Oct. 5. 1967 3 Sheets-Sheet 2 & l

i 54 52a r 1 f LTJ 55 I /QV P 1969 J. w. KISLING m 3,465,820

RETAINER PACKERS HAVING A ROTATING VALVE United States Patent 3,465,820 RETAINER PACKERS HAVING A ROTATING VALVE James W. Kisling HI, Houston, Tex., assignor to Schlumberger Technology Corporation, Houston, Tex., a corporation of Texas Filed Oct. 5, 1967, Ser. No. 673,190 Int. Cl. E2111 33/12 US. Cl. 166-128 13 Claims ABSTRACT OF THE DISCLOSURE The particular embodiment described herein as illustrative of one form of the invention is a well packer having a body with anchor and packing means to provide an anchored pack oif in a well bore. The body has a flow passage which can be selectively opened and closed by a valve sleeve which is mounted for rotational movement in the flow passage between positions opening and closing same, Valve actuating means coupled to a running-in string is extendible into the flow passage and is coupled to valve sleeve for rotating it. Coengageable means between the actuating means and body is arranged to rotate the actuating means and thus the valve sleeve between open and closed positions in response to upward and downward movement of the running-in string.

This invention relates generally to well packers, and more specifically to a new and improved well packer apparatus having a valve system for providing controlled fluid communication through the well packer apparatus.

It is often desirable in connection with wells to seal off the Well bore while providing controlled fluid communication to a well zone below the sealing point. For example, it may be desirable to squeeze cement below a packer through a pipe string at a predetermined point behind liner or casing. Such on operation is advantageous in preventing communication with other zones, closing channels, etc., before a particular zone is put on production. Or, it may be desirable to reperforate a well zone, and cement is squeezed to close old perforations. Further, it might be desirable to abandon a well zone and cement may be used to squeeze off the zone.

In any event, an apparatus commonly known as a cement or squeeze retainer packer may be used to isolate the zone which is to be pressurized from well fluids in the remainder of the well bore. Such packers have valving which can be closed after squeezing is completed in order to retain the cement below the packer at developed pressures. Commonly, such valving has taken the form of check valve type systems which readily permit fluid flow into the isolated zone from the pipe string but which prevent reverse flow. Check type valves, however, while functioning to hold the back pressure of the squeeze, are disadvantageous because such systems do not prevent loss of mud to the formation when low break-down pressures are encountered, do not keep annulus fluids off weak formations when the pipe string is removed, and do not permit the use of batch squeeze operations. Moreover, in order to completely bridge the well bore against fluid flow in either directions after a cementing operation has been completed, a shut-off plug or the like must be placed in the packer bore.

In view of the foregoing disadvantages in using check type valve systems in cement retainer packers, various so called pressure balanced valve systems have come into usage. Such valve systems, usually being constituted by a reciprocating sleeve which is opened and closed mechanically, will hold fluid pressure from above or below and thus alleviate most of the foregoing problems. How- Too ever, prior systems have not been reliable and simple to operate and have been subject to malfunctions due to failures in closing when it is desired to hold back pressure, or due to inability to subsequently reopen the valve for additional displacement. In view of the great depths at which such packers and valve systems may be used, and the extremely high pressures which are sometimes developed, it is important that the structure utilized be as sturdy, foolproof and simple in operation as is possible in view of the circumstances.

The present invention provides a new and improved well packer and valve system which has all the advantages of pressure balanced systems. The valve system comprises a rotating sleeve which will hold pressure from either direction when closed and which is mechanically actuated in a positive manner in response to simple upward and downward motion of the pipe string. Moreover, the valve system of the present invention is structurally arranged to be unaffected by well environments which have contributed to malfunctions in prior systems, and is thus highly reliable in operation in a well bore.

The present invention may be summarized to further point out the various concepts involved, as a well packer apparatus having normally retracted slips and packing which can be expanded to provide an anchored pack off in a well bore. When set, the packer isolates the well bore therebelow. The mandrel of the packer apparatus has a flow passage which is ported to the side of the mandrel below the packing. Valve means is provided for opening and closing the flow passage, the valve means comprising a sleeve which is mounted adjacent the side ports for rotation between positions opening and closing the flow passage. To rotate the valve sleeve, actuating means coupled to the pipe string extends into the flow passage and is co-rotatively coupled to the valve sleeve. Coengageable means between the mandrel and actuating means is arranged to cause predetermined rotational movement of the valve sleeve between open and closed positions in response to upward and downward motion of the pipe string at the top of the well bore. Thus it will be apparent that the present invention provides a new and improved retainer packer apparatus having a valve system which is mechanically operated in a simple manner, and the valve system is arranged to be unresponsive to fluid pressure from above or below.

The present invention has other concepts and advantages which will become more clearly apparent in connection with the following detailed description. A preferred embodiment is shown in the accompanying drawings, in which:

FIGURES 1A and LB are longitudinal sectional views, with portions on side elevation, of the present invention with parts in relative positions for lowering into a well bore, FIGURE 1B forming a lower continuation of FIG- URE 1A;

FIGURE 2 is an isometric view of the rotary valve element;

FIGURE 3 is a fragmentary developed view of a coupling mechanism in accordance with the present invention;

FIGURE 4 is a fragmentary developed view to illustrate the torque transmission structure between the extension and valve sleeve;

FIGURE 5 is a fragmentary developed view of the extension slot system in accordance with the present invention;

FIGURE 6 is a cross section on line 6-6 of FIGURE 1A; and

FIGURES 7A and 7B are views similar to FIGURES 1A and 1B except with parts of the present invention in their cooperative positions when set in a well bore.

With initial reference to FIGURES 1A and 1B, apparatus which will illustrate the principles of the present invention includes a mechanical setting tool A and a well packer B having a valve system C. The setting tool A is utilized in setting the packer B in a well bore so that the packer B can function to pack off the well bore. The valve system C controls fluid communication to the well bore below the packer B. The entire apparatus can be lowered into the well on a running-in string of tubing or drill pipe which provides a fluid conduit extending to the top of the well, as well as a mechanical member which can be manipulated at the top of the well bore to effect operation of the setting tool A and the valve assembly C.

As shown in FIGURE 1B, the packer B has a central body or mandrel 11 having a bore 12 which provides a fluid passageway and further has a lower guide portion 13 which supports lower slips 14. The slips 14 can take any desired form, such as frangible, segmented, or integral expansible type slips. A lower expander cone 15 is arranged to shift the lower slips 14 outwardly and conventional packing structure 16 surrounds the mandrel 11 between the lower expander cone and an upper expander cone 17. Typical anti-extrusion rings 18, 18a can confine the end portions of the packing 16, and

shear pins

19, 19a or other suitable means can releasably couple the

expander cones

15 and 17 to the mandrel 11 to control the relative motion sequence between parts in any desired manner. A conventional split ratchet ring 20 is arranged between the upper expander cone 17 and the lmandrel 11 and cooperates with external teeth 21 on the mandrel to trap compression loading in the packing structure 16 when the well packer B is set.

The lower guide portion 13 of the mandrel 11 is constituted as a valve body having a central flow passage 24 which is closed in a fluid tight manner at its lower end by a plug 25. Diametrically opposed side ports 26 in the valve body 23 are provided to communicate with the well annulus below the packing element 16. A valve sleeve 27 is located within the passage 24 adjacent to the side ports 26 and is arranged for movement between various rotational positions about the longitudinal axis of the mandrel 11 to control fluid flow from the passage 24 through the side ports 26. In one rotational position, lateral ports 28 in the valve sleeve 27 are aligned with the side ports 26 in the valve body 23 to permit fluid flow. In other rotational positions of the valve sleeve 27, the

ports

26 and 28 are not in registry and the passage 24 is closed to fluid flow in either direction.

As shown in FIGURE 2, the valve sleeve 27 is generally tubular in form and has appropriate external grooves for a seal structure which can include upper and lower

annular seals

29 and 30 which are connected by vertically extending

seals

31 and 32 located on either side of the ports 28. With this type of seal configuration, the

side seals

31 and 32 together with the

seal portions

33 and 34 above and below the ports 28 prevent fluid flow through the ports, while the entirety of the upper and

lower seals

29 and 30 precludes flow through the body ports 26. In the alternative, it will be appreciated that the seal arrangement could include face seals which surround the sleeve ports 28 to prevent flow in either direction through the sleeve ports, along with upper and lower annular sleeve seals above and below the face seals to prevent flow in either direction through the body ports 26. Radially inwardly extending pins 35 on the valve sleeve 27 provide a means for applying rotation force or torque to the valve sleeve 27 to rotate it between its various positions.

With particular reference to FIGURE 1A, the setting tool assembly A includes a central operating mandrel 38 having an open bore 39 and which can be connected to the lower end of the tubing string 10 by a threaded collar 40 or the like. The lower end portion of the operating mandrel 38 is provided with a swivel connection 41 to a tubular extension assembly which includes an enlarged sub 42 arranged to engage the upper end of the packer mandrel 11 and a tubular extension which telescopes within the bore 13 of the packer mandrel. The sub 42 and extension 45 are threaded together at 43 in a fluid tight manner. A swivel sleeve 44 is coupled to the upper portion of the sub 42 and has an inwardly extending shoulder section 46 forming an annular space 47 which rotatably received an outwardly extending section 48 on the operating mandrel 38. Accordingly, it will be apparent that the extension 45 and sub 42 can turn or rotate relative to both the operating mandrel 38 and the tubing 10. Appropriate seals such as O-

rings

49 and 50 can be provided, the lower seal 50 preventing fluid leakage from the bore of the mandrel 38 at the swivel connection 41, and the upper seal 49 protecting the swivel connection from ambient well fluids and debris.

The extension 45 is telescoped within the bore of the packer mandrel 11 and has arcuate coupling lugs 52 which can engage within an elongate internal mandrel recess 53. The recess 53, shown in an inside developed view in FIGURE 3, is open to the top of the packer mandrel 11 by vertically extending slots 54 and located on circumferentially opposite side of the bore of the mandrel. Thus, the coupling lugs 52 can be inserted into the recess 53 via the

slots

54 and 55 and rotation of the extension 45 relative to the mandrel 11 will position the lugs 52 underneath mandrel shoulders 56 formed between the slots. With this relationship of parts, engagement of the coupling lugs 52 with the shoulders 56 will limit upward movement of the extension 45 relative to the mandrel 11, and engagement of the sub 42 with the upper end surface of the mandrel 11 will limit downward movement. Accordingly, when the lugs 52 are underneath the shoulders 56, the extension 45 is coupled for limited reciprocating motion relative to the mandrel 11, and when the lugs are aligned with the

slots

54, 55, the extension can be inserted within, or withdrawn from, the bore 12 of the mandrel 11.

The lower end of the extension 45 is open at 57 and side ports 58 are provided for fluid flow. When the extension 45 is telescoped within the packer mandrel 11 as shown in FIGURE 1B the lower end portion 59 of the extension 45 is located within the valve sleeve 27. A torque sleeve 60 is threaded onto the lower end portion 59, and properly positioned thereon as by a screw 61 or the like, and has upwardly extending side guide slots 62 which are flared and open at the lower end of the sleeve 60. The slots 62 receive the valve sleeve pins 35 so that rotation of the extension 45 will impart corresponding rotation to the valve sleeve 27. Each of the side slots 62, one of which is shown in developed view in FIGURE 4, has a longitudinal portion 63 of suificient vertical extent whereby the extension 45 can be moved upwardly and downwardly a predetermined amount and still be co-rotatively coupled to the valve sleeve 27. Moreover, the slots 60 each have an upper circumferentially enlarged portion 64 to permit the valve sleeve 27 to be rotated to a certain extent relative to the extension 45 and in a diretcion which is opposite to its normal direction of rotation for purposes which will be hereaf er explained. The upper end of the torque sleeve 60 can be made to terminate below an outwardly extending shoulder 65 on the extension 45 to provide an annular recess in which a seal structure 66 is located. The seal structure 66, which can take many forms, is shown as one or more metallic rings 67 having inner and outer grooves which receive

suitable seals

68 and 69. Thus arranged, the seal structure 66 prevents fluid leakage between the packer mandrel 11 and the extension 45 when the latter is telescoped within the former.

Upper slip segments 72 are mounted at the upper end portion of the packer mandrel 11 adjacent to the upper expander cone 17. The segments 72 have upwardly facing wickers or teeth 73 on their outer peripheries, as well as inner inclined surfaces 74 which are engageable with outer inclinded surfaces 75 on the expander cone 17 for shifting the segments outwardly into gripping engagement with well casing. The extension sub 42 and the packer mandrel 11 are respectively provided with

annular grooves

76 and 77 and the slip segments 72 can have

corresponding shoulders

78 and 79 which engage within the grooves to limit movement of th slip segments in their retracted positions. A retainer sleeve 80, which forms a part of the setting tool A, extends downwardly in encompassing relation over upper portions 81 of the slip segments to retain them inwardly as long as the retainer sleeve occupies the relative position shown in FIGURE 1A and 1B. It will be appreciated that due to the engaging conditions of the

shoulders

78 and 79 within the

grooves

76 and 77, and to the holding action of the retainer sleeve 80, the slip segments 72 are quite rigidly held inwardly in retracted positions to prevent any likelihood of premature setting during lowering into a well.

Further to the setting tool assembly A, a control sleeve 88 (FIGURE 1A) is slidably and co-rotatively secured to the operating mandrel 38 by splines 89 or the like. The control sleeve 88 is initially locked in an upper position on the mandrel 38 by several latch lugs 90 which engage in a mandrel detent 91. A drag mechanism 92 including a tubular cage 93 is initially secured in a lower position on the control sleeve by coengaging right-hand threads 94. Typical drag blocks 95 are carried by the cage 93 and urged outwardly by coil springs 96 to frictionally engage casing and resist motion in a conventional manner. An inner surface 97 on the cage 93 holds the latch lugs 90 inwardly in engagement with the mandrel detent 19 while the parts are in the relative positions for lowering into a well bore.

The slip retainer sleeve 80 extends downwardly from the cage 93 to encompass the upper end portions 81 of the upper slip segments 72 as was previously described. When desired, it will be appreciated that right-hand rotation of the operating mandrel 38 by the running-in string will rotate the control sleeve 88 relative to the drag mechanism 92, and, due to the interengagement of the threads 94, cause the drag mechanism and the retainer sleeve 80 to feed upwardly along the control sleeve 88, thereby removing the retainer sleeve from encompassing reation to the upper portions of the slips 72. Upward feeding of the drag mechanism 92 will also position an internal cage recess 100 opposite the latch lugs 90 and permit them to move outwardly and release from the mandrel detent 91, thereby permitting upward movement of the operating mandrel 38 relative to the control sleeve 88 and the drag mechanism 92.

A slip setting sleeve 101 extends downwardly from the control sleeve 88 and terminates in spaced relation to the upper portions 81 of the slips 72. When the retainer sleeve 80 is removed upwardly, the slips 72 are not restrained and can move outwardly to engage the well casing. Outward movement of the slips will, of course, remove the

shoulders

78 and 79 from engagement with the mandrel and

sub grooves

76 and 77 and thereby uncouple the packer mandrel 11 from the extension assembly. With this condition of parts, the extension 45 can telescope upwardly relative to the packer mandrel 11 until the coupling lugs 52 engage the recess shoulders 56. Then upward extension movement will shift the packer mandrel 11 upwardly relative to the setting sleeve 101, the latter part not moving upward by virtue of the engagement of the friction drag blocks 95 with the well casing. Accordingly, it will be appreciated that the slip segments 72 cannot move upwardly due to the holding action of the setting sleeve 101, and that the expander cone 17 can be moved upwardly and behind the slips 72 to shift them outwardly into firm anchoring engagement with the well casing. Once the upper slips 72 are set, the expander cone 17 cannot move any further upwardly and continued upward movement of the mandrel 11 will 6 advance the lower cone toward the upper cone to expand the packing 16. The lower slips 14 are shifted over the lower expander cone 15 and outwardly into gripping engagement with the well casing. The ratchet ring 20 will lock the parts in expanded position in conventional manner.

In response to upward and downward motions of the extension 45 relative to the packer mandrel 11 occasioned by like motions imparted to the running-in string 10 once the packer B is set, the extension 45 is caused to rotate through various rotational positions due to interengagement of index pins 104, extending inwardly within the bore of the mandrel 11, with an extension slot system 105 to be described below. Rotation of the extension 45 within the packer mandrel 11 serves the primary function of selectively rotating the value sleeve 27 between open and closed positions. As shown in plain view in FIGURE 5, the slot system 105 is formed about the periphery of extension 45 and includes vertically disposed entrance and

exit slots

106 and 107 located on opposite sides of the extension. Inasmuch as the slot system is symetrically arranged around the circumference of the extension 45, for purposes of brevity, only one-half of the total slot system structure will be described and it will be appreciated that each slot portion mentioned hereafter has an identical counterpart location on the opposite side of the extension. Between these entrance and

exit slots

106 and 107 are

upper pockets

108 and 109, the left upper pocket 108 being located, for example, about 50 degrees from entrance and exit slot 106 and the right upper pocket 109 being located, for example, about 40 degrees from entrance and exit slot 107. An intermediate pocket 110 is located between the

upper pockets

108 and 109 and can be located about 50 degrees from the left upper pocket 108. The entrance and exit slot 106 is connected to the upper pocket 108 by a channel 111 which extends upwardly and to the right, and the upper pocket 108 is connected to the intermediate pocket 110 by a channel 112 which extends downwardly and to the right. The intermediate pocket 110 is connected to the upper pocket 109 by a channel 113 which extends upwardly and to the right like channel 111, and the upper pocket 109 is connected to the enentrance and exit slot 107 by a channel 114 which extends downwardly and to the right like channel 112. The intersections of the

channels

111 and 112, and 113 and 114, are located somewhat to the left of the respective centers of the

upper pockets

108 and 109 so that the index pin 104 is constrained to enter the channel 112 when leaving pocket 108, and channel 114 when leaving pocket 109. Moreover, the intersection of

channels

112 and 113 is located somewhat to the left of the intermediate pocket 110 so that the index pin 104 will enter the channel 113 when leaving the pocket 110.

It will be apparent that the slot system 105 provides a guideway in which the pins 104 engage to cause a predetermined sequence of rotational movements of the extension 45 relative to the mandrel 11 in response to upward and downward motions of the extension. Thus, movement of the index pin 104 from entrance and exit slot 106 to the left upper pocket 108 will cause the extension 45 to rotate about 50 degrees in a clockwise direction (viewed from above) within the packer mandrel 11, such rotation being occasioned by engagement of the upper inclined wall 115 of channel 111 with the index pin. Movement of the index pin 104 from the upper pocket 108 to the pocket 110 will cause another 50 degrees rotation of the extension 45 when the lower inclined wall 116 of the channel 112 engages the index pin 104, and further movement from the pocket 110 to the right upper pocket 109 will cause an additional 40 degrees relative rotation when the index pin engages the upper inclined wall 117 of the channel 113. Finally, movement of the index pin 104 from the right upper pocket 109 down through the channel 114 with inclined lower wall 118 and out of the entrance and exit slot 107 will effect another degrees relative rotation of the extension for a total of 180 degrees. Each increment of extension rotation will cause a corresponding amount of rotation of the valve sleeve 27 by virtue of engagement of the valve sleeve pins 35 with the walls 63a of the slots 62 in the torque sleeve 60. Of course the direction of rotation of the extension 45 and the valve sleeve 27 is a function of the slot system 105 and, although the arrangement shown is preferred, it will be appreciated that the slot system 105 could be arranged in reverse manner so that the extension and valve will rotate in the lefthand direction.

The coupling lugs 52 on the extension 45 are vertically aligned relative to the entrance and

exit slots

106 and 107, and the mandrel recess openings 54 and 55 (FIGURE 3) aligned relative to the index pins 104, such that when the index pins 104 engage within the entrance and exit slots, the coupling lugs 52 are vertically aligned with the mandrel recess openings and can readily pass into, and out of, the mandrel recess 53. When the index pins 104 engage the upper wall surfaces 115 of the channels 111 which are inclined upwardly and to the-right, the extension 45 is caused to rotate or swivel in the clockwise direction to position the coupling lugs 52 underneath the mandrel shoulders 56. The lugs 52 will remain in positions underneath the mandrel shoulders 56 as long as the entrance and

exit slots

106, 107 are not aligned with the index pins 104. The entrance and

exit slots

106 and 107 are also circumferentially located relative to the torque sleeve slots 60 so that when the index pins 104 are within the

slots

106 and 107, and thus when the coupling lugs 52 can pass through the

recess openings

54 and 55, the valve sleeve 27 is always in a closed rotational position. The bosses 120 formed between the entrance and

exit slots

106 and 107 can have lower converging

cam surfaces

121 and 122 to insure that the mandrel index pins 104 will enter one or the other of the

slots

106 and 107 regardless of the initial rotational position of the extension 45 relative to the packer mandrel 11 when the extension is inserted. Moreover, the pins 104 can have flattened peripheral portions to reduce bearing loads as the pins work within the slot system 105.

Should it ever be desirable to disconnect the setting tool A from the well packer B, leaving the extension 45 within the bore of the packer mandrel 11, for example, where the extension 45 has become lodged within the mandrel by sedimentation or junk in the well, a safety feature is provided for this purpose. With particular reference to FIGURES 1A and 6, the swivel section 48 has a reduced diameter portion 125 which is externally threaded with buttress type teeth 126 facing upwardly. A clutch ring 127 is cut through at 129 and is capable of sufiicient lateral expansion and contraction for ratcheting action over the teeth 126 in an upward direction.

A longitudinally extending key 130 on the swivel sleeve 44 engages within the cut 129 to co-rotatively secure the ring to the sleeve. The swivel section 48 further has an upper outwardly extending annular shoulder 131 having an inwardly and upwardly inclined lower face 132 which is shaped in complimentary manner to the upper end surface 133 of the clutch ring 127.

It will be appreciated that due to the configuration of the slot system 105 and its coaction with the indexing pins 104, the extension 45 will always rotate relative to operating mandrel 35 in the same direction, for example, with the slot arrangement shown in FIGURE 5, in the clockwise or right-hand direction viewed from above. Accordingly, the threads 126 and 128 on the section 125 and clutch ring 127 respectively can be formed as right-hand threads. Thus, clockwise rotation of the swivel sleeve 44 and the clutch ring 127 relative to the operating mandrel 38 will cause downward feeding of the clutch ring until it abuts the sub shoulder 134 as shown in FIGURE 1A whereupon the clutch ring will remain stationary and merely ratchet over the threads 126 in response to continued rotation of extension assembly relative to the operating mandrel during normal operation of the tool. However, if the operating mandrel 38 is rotated in a clockwise or right-hand direction relative to the extension assembly by right-hand rotation of the running-in string 10 at the top of the well bore, the clutch ring 127 will feed upwardly along the threads 126 until the

inclined surfaces

132 and 133 engage, thereby exerting inward force on the clutch ring and clutching the operating mandrel 38 to the swivel sleeve 44 since the clutch ring cannot ratchet downwardly along the threads 126. Then, continued rotation of the running-in string 10 will effect unscrewing of the threads 43 between the swivel sub 42 and the extension 45, which threads are formed as left-hand threads, so that the entire setting tool A except for the extension 45 can be withdrawn from the well.

Operation In operation, the parts are assembled as shown in the drawings with the extension 45 telescoped within the packer mandrel 11. The

slips

15 and 72 and the packing 16 are in normally retracted positions, the upper slips 72 being retained inwardly by the retainer sleeve 80. The drag blocks 95 can slide along in frictional engagement with the well casing as the tool is lowered into a well bore to setting depth. If it is desired to lower the packer with the valve sleeve 27 in open condition so that the running-in string 10 can fill with well fluid during lowering, the extension 45 is merely inserted into the packer mandrel 11 during assembly and the index pins 104 will properly index the extension until the pins are in the left upper pockets 108, or positions D, FIGURE 5. This rotational position of the extension 45 will properly align the sleeve and

body ports

28 and 26 in registry with one another. On the other hand, to run the tool in the well with the valve sleeve 27 in closed condition, the plug 25 at the lower end of the mandrel 11 can be conveniently removed to gain access to the valve sleeve 27 to position the pins 35 within the enlarged slot portions 64 on the torque sleeve 60. This will orient the valve sleeve 27 in a rotationally closed position. Inasmuch as the valve sleeve 27 is always rotated in the same direction by the extension 45, the enlarged portions 64 have no effect on the operation of the valve sleeve 27 after the well packer is set. In other words, the straight sides 63a of the longitudinal slot portion 63 always engage the sleeve pins 35 to rotate the valve sleeve.

When it is desired to set the packer B, the running-in string 10 is first rotated a number of turns to the right. Since the drag mechanism 92 cannot rotate due to engagement of the drag blocks 95 with the casing, the control sleeve 88' will be rotated relative to the drag mechanism 92 with resultant upward feeding of the retainer sleeve out of encompassing relation to the upper portions 81 of the upper slips 72. In actuality, the entire apparatus in the well except for the drag mechanism 92 and retainer sleeve 80 will be rotated by the running-in string 10. When the retainer sleeve 80 moves sufiiciently upwardly, the slips 77 are free to move outwardly and the lower end of the setting sleeve 101 is cleared for engagement with upper end surfaces of the slips 72. The cage recess 100 is now positioned adjacent to the latch lugs so that the lugs can move outwardly and release from the mandrel detent 91. The operating mandrel 38 is thus free to be moved upwardly relativeto the control sleeve 88, the drag mechanism 92 and the the setting sleeve 101.

The running-in string 10 is then elevated to set the packer B. When the slips 72 are released, as previously described, the extension 45 can move upwardly to a limited extent relative to the packer mandrel 11. As this relative movement occurs, the extension 45 is rotated as the index pins 104 move within the intermediat pockets 110, or positions E, FIGURE 5. This rotation of the extension also positions the coupling lugs 52 underneath and in engagement with the mandrel recess shoulders 56, the lugs moving from positions G to positions H as shown in FIGURE 3. If the valve is initially open, rotation of the extension 45 will also cause corresponding rotation of the valve sleeve 27 to closed position. On the other hand, if the valve sleeve 27 is initially closed during lowering, rotation of the extension 45 will have no effect on the valve sleeve because the enlarged slot portions 64 in the torque sleeve 60 will permit this extension rotation to occur without imparting corresponding rotation to the valve sleeve. Thus, the valve sleeve 27 will remain in closed position.

Inasmuch as the coupling lugs 52 are engaging the mandrel shoulders 56, continued upward movement of the extension 45 will elevate the packer mandrel 11, and thus the upper expander cone 17, toward the lower end surface of the setting sleeve 101. The slips 72 will thus be shifted outwardly into gripping engagement with the casing, the holding force of the drag blocks 95 being transmitted through the cage 93, threads 94, control sleeve 88 to the setting sleeve 101 to prevent its upward movement. The slips 72 will accordingly be held against upward movement by the setting sleeve 101 and suflicient upward movement of the packer mandrel 11 will bring the expander cone 17 behind the slips 72 to shift them outwardly into gripping engagement with the casing as shown in FIGURE 7B. When the upper slips 72 grip the casing, the upper expander cone 17 cannot move any further upwardly, and continued upward movement of the packer mandrel 11 will cause expansion of the packing element 16 and then shifting of the lower slips 14 over the lower expander cone 15. The external body teeth 21 will ratchet through the ratchet ring 20 and the ring will trap the mandrel 11 in the highest position to which it is moved. Accordingly, the packing and slips are locked in expanded positions and when a predetermined upward strain is taken on the running-in string, the packer B will be firmly set.

After thus setting the packer B, the weight of the running-in string 10 is slacked off. This will occasion downward movement of the extension 45 within the packer mandrel 11 with consequent rotation of the extension and the valve sleeve 27 until the index pins 104 are within the right upper pockets 109 of the slot system, posi tions E in FIGURE 5. The valve sleeve 27 is still in on of its closed rotational positions. Accordingly, the running-in string 10 is closed-off at its lower end and can be pressure tested for leakage at this time. The weight of the running-in string 10 can be conveniently imposed upon the packer B so that pressurizing the string 10 will not cause the extension as to be lifted upwardly by the pressure. The feature of being able to impose tubing weight on the tool when testing tubing is an important advantage over packers of this type having reciprocating sleeve valves because the imposition of tubing weight may open the valve systems of these packers.

After such testing, the running-in string 10 is simply picked up at the surface to disengage the extension 45 from within the bore of the packer mandrel 11. As the extension 45 is moved upwardly, the index pins 104 will cause the extension and the valve sleeve 27 to rotate again as the index pins move within the entrance and exit slots 107. The valve sleeve 27 is still closed. In this relative rotational position of parts the coupling lugs 52 are moved from positions K, FIGURE 3, into vertical alignment with the

mandrel recess openings

54, 55. Accordingly, the extension 45 is conditioned to be withdrawn from the bore of the packer mandrel 11. It will be noted that whenever the extension 45 is withdrawn, the valve sleeve 27 is always left in a closed rotational position, whereby the well packer B completely bridges the well bore to prevent fluid flow in either longitudinal direction.

To perform a pressure operation such as squeeze ce- Inenting, the extension 45 is reinserted within the bore 12 of the packer mandrel 11 by downward movement of the running-in string 10. Regardless of the initial random rotational position of the extension 45, the bosses 120 and the lower cam surfaces 121 and 122 will cooperate with the index pins 104 to properly orient the extension 45 such that the index pins are vertically aligned within the entrance and

exit slots

106 and 107. With the

slots

106 and 107 thus aligned, the coupling lugs 52. are also aligned with the

mandrel recess openings

54, 55, and the side slots 62 in the valve torque sleeve 60 are properly positioned with respect to the valve sleeve pins 35 so that the lower end portion 59 of the extension can be lowered inside the valve sleeve 27. When the extension 45 has moved sufficiently downwardly within the bore of the packer mandrel 11, the index pins 104 will engage the upper inclined surfaces of the channels 111 and cause the extension and the valve sleeve 27 to rotate during further downward movement until the index pins are within the left upper pockets 108. As this rotation occurs, the valve sleeve ports 28 will become radially aligned with the valve body ports 26 to open the valve. The coupling lugs 52 are also rotated to positions within the mandrel recess 53 such that the lugs are underneath the recess shoulders 56. With the valve open, cement slurry can be displaced through the running-in string 10 and out into the well bore below the packer.

When suflicient displacement has occurred and it is desired to trap the squeeze, e.g., to retain the cement slurry at developed pressures below the packer B, the valve sleeve 27 can be moved to a rotationally closed position by simply picking the running-in string 10 upwardly to index the extension 45 until the index pins 104 are within the intermediate pockets 110, thereby rotating the valve sleeve 27 to closed position. The coupling lugs 52 will engage the mandrel shoulders 56 to positively prevent separation of the extension 45 from the mandrel 11, thereby enabling complete control of tubing and annulus pressures. Thus it will be appreciated that adequate annulus pressures can be maintained to prevent dumping cement into well bore when the extension 45 is purposely disengaged. The extension 45 can be withdrawn from the packer mandrel 11, leaving the valve sleeve 27 in closed position, by imparting a pair of vertical motions to the running-in string 10, one downward, and one upward. The corresponding reciprocation of the extension 45 will cause the index pins 104 to traverse the

channels

113 and 114 and into the entrance and exit slots 106, whereupon the coupling lugs 52 are vertically aligned with the

mandrel recess openings

54, 55 and the extension 45 is free for upward movement, leaving the valve sleeve 27 in closed condition. The setting tool A can be withdrawn from the well, or conventional circulation or reverse circulation procedures can be undertaken. Of course, the extension 45 can be reinserted within the packer mandrel 11 for further operations as desired.

Although the packer B is disclosed as settable on the mechanical setting tool A, it will be appreciated that the packer can be set by the various wireline or other setting tools which are conventional in the art. In case of wireline setting, of course other upper slips such as conventional frangible or solid type slips can be utilized, and the plug 25 at the lower end of the mandrel 11 is provided with internal threads for connecting to the tension member of the setting tool. Thus it will be apparent that apparatus of the present invention is quite versatile and can be used for a variety of down hole applications as will be appreciated by those skilled in this art.

A new and improved well packer and valve system have been disclosed for use in a well bore. The valve system comprises a rotating sleeve which is arranged to be unaffected fluid pressure acting in either direction. The packer can be set and the valve system operated in a convenient, positive, and reliable manner by a minimum number of manipulations of the running-in string at the top of the well bore. Since certain changes or modifications may be made in the present invention by those skilled in the art without departing from the concepts involved, it is intended that the appended claims cover all such changes or modifications falling within the true spirit and scope of the present invention.

I claim:

1. A well packer comprising: a body having a flow passage; anchor and packing means for providing an anchored pack-off about said body in a well bore; a valve sleeve rotatably mounted in said flow passage and arranged for rotational movement about the longitudinal axis of said body between positions opening and closing said flow passage; and means on said valve sleeve to enable rotation of said valve sleeve between said open and closed positions by an actuating means extendable into said flow passage.

2. A squeeze retainer packer having a body member with a passage therethrough; packing means on said body member; anchoring means on said body member; valve means mounted in said passage for rotation about the longitudinal axis of said body member, and operable in response to rotational movement to open or close said passage; and means for setting said packing and anchoring means in response to longitudinal motion, said setting means including means extending into said passage for operating said valve means.

3. A squeeze retainer packer having a body member with a flow passage therethrough; anchor and packing means on said body member to provide an anchored packoff in a Well bore; valve means mounted in said passage and operable in response to rotational movement to open or close said passage; and setting tool means including means for releasing said anchor means in response to relative rotation, means for setting said anchor and packing means in response to longitudinal motion, and means for operating said valve means, said setting tool means being releasably coupled to said body member.

4. A well packer apparatus comprising: a mandrel having a flow passage; packing means and anchoring means on said mandrel for respectively packing off a well bore and anchoring against movement in the well bore; valve means for controlling fluid flow through said passage, said valve means including a valve sleeve arranged for rotational movement in said passage between positions opening and closing same; and actuating means for rotating said valve sleeve, said actuating means extending into said passage and being operatively coupled to said valve sleeve.

5. The apparatus of claim 4 wherein said actuating means is adapted for movement by a running-in string extending to the top of the well bore; and further including coengageable means between said actuating means and said mandrel for ellecting rotational movement of said actuating means and valve sleeve in response to longitudinal movement of the running-in string.

6. The apparatus of claim 5 further including means coupling said actuating means for rotation relative to the running-in string.

7. The apparatus of claim 5 further including means for co-rotatively and slidably coupling said actuating means and valve sleeve whereby said actuating means can move longitudinally relative to said valve sleeve while imparting rotational movement thereto.

8. The apparatus of claim 5 wherein said actuating means has a central flow path in communication with said flow passage; and further including seal means for preventing fluid leakage between said actuating means and said mandrel.

9. In a well packer apparatus having a mandrel providing a flow passage, packing means on said mandrel for packing off the annulus between said mandrel and a surrounding well bore wall, and anchoring means for securing said mandrel and packing means in a well bore, the combination comprising: valve body means at the lower end of said mandrel, said valve body means having laterally extending port means in communication with the well bore below said packing means; a valve sleeve in said valve body and rotatable therein about the longitudinal axis of said valve body means between positions opening and closing said port means; actuator means extending in said flow passage and operatively coupled to said valve sleeve for rotating said valve sleeve, said actuator means being adapted for movement by a running-in string extending to the top of a well bore; and means cooperable between said actuator means and mandrel for rotating said actuator means and valve sleeve in response to upward and downward movement of the running-in string at the top of the well bore.

10. The apparatus of claim 9 further including means for co-rotatively and slidably coupling said actuator means to said valve sleeve.

11. The apparatus of claim 9 wherein said actuator means comprises a generally tubular member telescopically and rotatably received within the flow passage of said mandrel and further including seal means between said tubular member and said mandrel for preventing fluid leakage between said tubular member and said mandrel.

12. The apparatus of claim 11 wherein said rotating means includes slot means about the periphery of said tubular member and index means on said mandrel cooperable with said slot means in a manner whereby longitudinal motion of said tubular member relative to said mandrel will effect rotation of said tubular member in a predetermined manner.

13. In a well packer apparatus having a mandrel with a flow passage, anchor and packing means on said mandrel for providing an anchored seal in a well bore, and valve body means at the lower end portion of said mandrel, the combination comprising: rotary valve means mounted in said body means for rotation about the axis of said mandrel between open and closed positions to control fluid flow through said passage; actuator means extendable into said passage for imparting rotary motion to said valve means, said actuator means forming the lower end portion of a running-in string extending to the top of a well bore; seal means between said actuator means and said mandrel for preventing fluid leakage therebetween; first coengageable means between said actuator means and said mandrel for guiding said actuator means relative to said mandrel; and second coengageable means between said actuator means and said valve means for imparting rotational movement to said valve means.

References Cited UNITED STATES PATENTS 2,785,755 3/1957 En Dean l6672 3,306,366 2/1967 Muse 166l28 X 3,332,495 7/1967 Young 166l52 X 3,334,691 8/1967 Parker l66l52 3,347,318 10/1967 Barrington 166226 3,351,133 11/1967 Clark et al. 166-72 X DAVID H. BROWN, Primary Examiner U.S. Cl. X.R. l66-124