US3841400A

US3841400A - Selective hydrostatically set parallel string packer

Info

Publication number: US3841400A
Application number: US00338152A
Authority: US
Inventors: R Callihan; C Wainwright
Original assignee: Baker Oil Tools Inc
Current assignee: Baker Hughes Oilfield Operations LLC
Priority date: 1973-03-05
Filing date: 1973-03-05
Publication date: 1974-10-15
Anticipated expiration: 1991-10-15

Abstract

A hydraulically or hydrostatically set parallel string well packer to be used in conjunction with one or more hydraulically set well packers therebelow, all of the well packers being adapted for lowering in a well bore on a first or long tubular string to desired setting locations and selectively settable hydraulically in packed-off condition at each setting point without longitudinal movement of the long string, whereupon a second or short tubular string can be lowered in the well bore parallel to the first tubular string and appropriately related to the parallel string packer.

Description

United States Patent [1 1 Callihan et al.

[ Oct. 15, 1974 SELECTIVE HYDROSTATICALLY SET PARALLEL STRING PACKER inventors: Rudy B.Cal1ihan, Houston; Clyde S.

Wainwright, Jr., Bellaire, both of Tex.

Baker Oil Tools,'llnc., Los Angeles, Calif.

Filed: Mar. 5, 1973 Appl. No.1 338,152

[73] Assignee:

US. Cl 166/120, 166/126, 166/189 Int. Cl E2lb 23/06, E2lb 33/122 Field of Search l66/l20,-126, 189

References Cited UNITED STATES PATENTS Brown 166/120 X Cochran 166/120 Myers et al. 166/120 3,239,009 3/1966 Lcutwyler [66/120 3,252,516 5/1966 Lcutwyler 166/120 3,311,170 3/1967 Brown 166/120 3,414,058 12/1968 Rochemont 166/120 Primary Exami nerDavid H. Brown Attorney, Agent, or Firm-Bernard Kriegel 5 7 ABSTRACT A hydraulically or hydrostatically set parallel string well packer to be used in conjunction with one or more hydraulically set well packers therebelow, all of the well packers being adapted for lowering in a well bore on a first or long tubular string to desired setting locations and selectively settable hydraulically in packed-off condition at each setting point without longitudinal movement of the long string, whereupon a second or short tubular string can be lowered in the well bore parallel to the first tubular string and appropriately related to the parallel string packer.

15 Claims, 18 Drawing Figures mum- PAIENTEDBBHBW 3,841,400

sum 10F a 1&9 (\l 19a CZ- Z I u PAIENIEDUBT x 51914 sum 30F SELECTIVE HYDROSTATICALLY SET PARALLEL STRING PACKER The present invention relates to subsurface well apparatus,and more particularly to packers or anchors adapted to be set in well casings, and similar conduit strings, disposed in well bores.

In US. Pat. No. 3,414,058, a hydrostatically set dual well packer is disclosed, which is lowered to a desired setting location in the well casing on a long string cooperable with a first longitudinal passage in the packer, after which a short" string is lowered in the well casing and placed in communication with a second longitudinal passage in the well packer. The long string can be placed in a suitable sealed relation to another well packer disposed in a well bore below the dual packer. If desired, such other well packer can be lowered in the casing to its desired setting location with the upper dual packer and suitably set in packed-off condition in the well casing. Thereafter, the dual packer can be set hydraulically in the well casing by the application of pressure, such as hydrostatic pressure, exerted through the short string of the dual packer. After setting the dual packer, it can be tested. If it leaks, or is improperly set, the short string must be withdrawn, after which the dual packer is released from the casing and withdrawn from the well casing by elevating the long string.

The necessity for running the short string in the casing into appropriate relation with the dual string packer, to achieve setting and testing of the packer, is time consuming and costly in the event the packer is found to be improperly set or in a leaky condition, since withdrawal of the short string to effect release and withdrawal of the long string and packer becomes essential.

By virtue of the present invention, parallel string well packer apparatus has been provided capable of being set hydraulically by pressure imposed through the long string, thereby enabling the packer and any and all packers depending therefrom to be lowered simultaneously in the well casing to the desired setting locations, permitting setting and testing of the parallel string packer in the absence of the short string. If the test is unsatisfactory, the packer can be removed by elevating the long string. If the test is satisfactory, the short string can then be run into the casing and appro priately connected to the parallel string packer. As a result, undesired and unnecessary running and withdrawal of the short string from the well casing is avoided.

Another object of the invention is to provide a parallel string hydraulically set packer, which can be lowered in a well bore on a long string together with one or more hydraulically set well packers therebelow, such as single string well packers, the packers being selectively set and tested under the control of devices and pressure within the long string and in the absence of a short string. More specifically, by operating through the long string, the lowermost packer can be set and tested, these actions being followed sequentially in an upward direction for each succeeding upper packer. If difficulty with any packer occurs, the string of packers can be removed before the next succeeding packer or packers are set, with attendant savings in time and costs and in the absence of the short string. The latter is installed only after all packers have been tested and the tests are found to be satisfactory.

This invention possesses many other advantages, and has other objects which may be made more clearly apparent from a consideration of a form in which it may be embodied. This form is shown in the drawings accompanying and forming part of the present specification. It will now be described in detail, for the purpose of illustrating the general principles of the invention; but it is to be understood that such detailed description is not to be taken in a limiting sense.

Referring to the drawings:

FIGS. 1a and lb together constitute a side elevational view of a plurality of interconnected well packers in tandem arrangement embodying the invention, disposed in a well casing in anchored and packed-off condition, FIG. 1b being a lower continuation of FIG. la;

FIGS. 2a, 2b and 20 together constitute a vertical section through the uppermost well packer of FIG. 1a, with its parts in their initial condition for lowering the well packer in a well casing, FIGS. 2b and 2c being lower continuations of FIG. 2a and 2b, respectively;

FIG. 3 is an enlarged cross-section taken along the line 3-3 on FIG. In;

FIG. 4 is an enlarged cross-section taken along the line 44 on FIG. 1a;

FIG. 5 is an enlarged cross section taken along the line 5-5 on FIG. 2b;

FIGS. 6a and 6b together constitute a vertical section through the well packer apparatus illustrated in FIGS. 20 and 2b, after the well packer has been anchored in packed-off condition in the well casing, FIG. 6b being a lower continuation of FIG. 6a;

FIGS. 7a and 7b are views corresponding to FIGS. 2a and 2b illustrating the well packer after it has been released from its set condition in the well casing, FIG. 7b being a lower continuation of FIG.

FIG. 8 is an enlarged fragmentary longitudinal section taken along the line 8-8 on FIG. 4;

FIG. 9 is an enlarged longitudinal section through the hydraulically actuatable portion of the apparatus taken along the line 9-9 on FIG. 5;

FIG. 10 is a view similar to FIG. 9 illustrating the hydraulic actuating portion of the apparatus when the tool has been anchored in packed-off condition in the well casing;

FIG. 11 is a view similar to FIGS. 9 and 10 illustrating the hydraulic actuatable portion of the apparatus following release of the tool from the well casing;

FIG. 12 is a longitudinal section through a portion of a lower packer preparatory to its setting in the well casmg;

FIG. 13 is a view similar to FIG. 12 with the lower packer conditioned for setting in the well casing.

The apparatus illustrated in the drawings includes an upper well packer A of the retrievable dual tubular string type capable of being lowered in a well casing B disposed in a well bore and anchored in packed-off condition therein. The packer A is lowered on a first or long tubular string C extending to the top of the well bore. Thereafter, the packer is anchored in packed-off condition in the well casing. Fluid in the casing from a lower producing zone LZ can pass into a sleeve valve 500, when open, into a first tubular body 10 forming part of the well packer and into the first tubular string C to be conducted to the top of the well bore, and from an upper producing zone UZ through a second tubular body 11, which communicates with a second tubular string D FIG. 6a) extending to the top of the well bore, and which is installed in place preferably only after all of the well packers illustrated have been tested satisfactorily, as described hereinbelow.

The specific upper well packer A shown in the drawings includes an upper receptacle head or body 12 having first and second passages l3, l4 therethrough, the first passage receiving the first tubular body and the second passage being adapted to receive the lower end of the second tubular string D, installed after all well packers have been set in the well casing, that will extend to the top of the well bore. The second tubular body 11, which is parallel to the first tubular body 10, has its upper end threadedly secured to the receptacle l2 and has a passage 14a that forms a continuation of the second passage 14 of the receptacle. As described hereinbelow, the receptable or body 12 and the second tubular body 11 are movable downwardly as a unit relative to the first tubular body 10 in setting the well packer A in the well casing B.

The first tubular body 10 carries a coupling ring 15, such as a Cring, in a peripheral groove 16 which is disposed initially at the lower portion of the receptacle and which is slidable in an enlarged diameter portion or counterbore 17 of the receptacle that terminates in an upper shoulder 18 adapted to be engaged by the C- ring 15. A seal ring 19 is disposed in a circular groove 20 in the receptable and around the first tubular body 10, being in sealing engagement therewith and disposed initially immediately above the C-ring 15. This seal ring will prevent fluid from passing downwardly from the counterbore l7 surrounding the first tubular body 10. Thus, grease can be pumped through a hole 21 in the receptacle into the counterbore immediately above the seal ring 19, and such grease will pass upwardly to the receptable shoulder 18. Following filling of the counterbore space with grease, or the like, the filler hole 21 may be closed by a suitable threaded plug 22.

The first and second

tubular bodies

10, 11 extend slidably downwardly through a packing assembly or structure 23 and through an expander 24 therebelow. The first tubular body 10 passes downwardly through a passage 25 in a slip ring 26 below the expander and through a longitudinal passage 27 in the upper portion 280 of'a hydraulic housing structure 28 to a location therebelow, the tubular body 10 extending through a coupling or connector 502, the upper portion being threadedly connected to a lower portion 28b of the hydraulic housing structure 28, this coupling also being threaded within an upper portion of an elongate tubular housing member 503. The lower end of the first body 10 is threadedly secured to the upper portion of a body extension 504, the lower end of which is threadedly attached to another portion 505 of the body extension, the extension projecting through and extending below the lower end 506 of the tubular housing memher, where a suitable sub 29 may be attached thereto to threadedly receive the required length of tubing 507 that can extend downwardly into sealing relation or connection with a lower or intermediate packer F. As described hereinbelow, such length of tubing 507 may be connected to the intermediate packer F appropriately spaced from the well packer A, this packer F, in turn, being connected through suitable lengths of tubing-508 to one or more other packers G spaced therefrom and from each other by the requisite amounts, de-

pending upon the specific locations in the well casing where they are to be anchored and packed-off.

The second tubular body 11 also extends downwardly through the slip ring 26 and into a longitudinal passage 30 in the hydraulic housing structure 28, there being a suitable side seal ring 31 in the upper portion of the housing sealingly engaging the periphery of the second tubular body.

The packing assembly or structure 23 includes an upper connector 32 through which the first and second

tubular bodies

10, 11 pass, which is engaged by the lower end of the receptacle 12 and also by the lower end of the C-ring 15. The tubular bodies also pass through an upper insert 33 clamped upwardly against the upper connector by an upper gauge ring 34 threaded to the connector 32 and contacting an external flange 35 of the insert. This insert 33 also engages a split coupling ring 36 mounted in a peripheral groove 37 in the second tubular body 11 and disposed within a counterbore 38 in the upper connector. The packing assembly 23 also includes upper, lower and intermediate packing elements 39 made of a suitable elastomer material, such as natural or synthetic rubber, separated by metal spacer rings 40. The upper packing element 39 is engageable by the upper gauge ring 34 and upper insert 33; whereas, the lowermost packing element 39 is engageable by a lower insert 41 clamped to the upper end of the expander 24 by a lower gauge ring 42 threaded on the latter and the upper end of which also engages the lower packing element 39. The

tubular bodies

10, 11 extend through the packing elements 39, spacer rings 40, lower insert 41 and through

passages

43, 44 in the expander 24. The second tubular body 11 has a split coupling ring 45 mounted in a peripheral groove 46, which is engageable with the lower end of the lower insert 41, but which is slidable within a counterbore 47 in the expander.

The slip ring 26 has a plurality of circumferentially spaced T-shaped slots 48 in its upper portion in which T-shaped heads 49 of slips 50 are slidable radially into and out of engagement with the wall of the well casing B. These slips have wickers or teeth 51 facing in a downward direction to anchor the well packer against downward movement therewithin. These slips extend into circumferentially spaced grooves 52 in the expander, each groove having a base portion 53 tapering in a downward and inward direction and engaging a companion inner tapered surface 54 on the slip, such that relative downward movement of the expander 24 with respect to the slips 50 expands the latter outwardly. On the other hand, relative upward movement of the expander with respect to the slips will retract the latter by virtue of side tongues 55 on the slips being received within companion grooves 56 in the expander. Movement of the slip ring 26 toward the expander 24 and the extent of outward expansion of the slips 50 is limited by engagement of a limit sleeve 57, surrounding the first tubular body 10 and resting upon the slip ring, with the lower end of the expander 24. However, in the normal use of the apparatus, the limit sleeve 57 will not engage the lower end of the expander 24.

The packing structure 23 and slips 50 are expanded as a result of downward movement of the second tubular body 11 and upper connector 32 relative to the first tubular body 10, and as a result of upward movement of the slip ring 26 and slips 50 relative to the expander 24. A hydraulically actuatable mechanism disposed primarily in the hydraulic housing structure 28 can effect such relative movement. This hydraulic mechanism includes the hydraulic housing structure 28 into which the

tubular bodies

10, 11 extend. The upper portion of this hydraulic housing structure is connected to a ratchet sleeve 58 surrounding the second tubular body ll. The lower circumferentially continuous portion 59 of the sleeve has a split ring 60 mounted in its peripheral groove 61 and disposed in a counterbore 62 in the upper hydraulic housing 28a, the ring being clamped in the counterbore by an upper retainer 63 secured to the upper end of the upper housing member 28a by a coupling ring 64 overlying a retainer flange 65 and threadedly secured to the hydraulic housing member. The ratchet sleeve 58 is secured initially to the second tubular body ll by external tapered teeth 66 on the tubular body meshing with internal companion tapered teeth 67 formed on dogs 68 provided on the intermediate portion of flexible ratchet sleeve arms 69 formed by circumferentially spaced slots 70 in the sleeve extending between its lower circumferentially continuous portion 59 and its upper circumferentially continuous portion 71.

The external and

internal teeth

66, 67 are maintained in full mesh with one another by a ratchet sleeve retainer 72 through which the first tubular body extends, and which has a bore 73 through which the second tubular body 11 and ratchet sleeve arms 69 extend, the outwardly directed projection 74 of the dogs initially engaging the wall 75 of the bore to hold their internal teeth 67 in mesh with the external teeth 66 of the tubular body 11. Initially, the ratchet sleeve retainer 72 is releasably secured to the upper retainer 63 attached to the upper hydraulic housing member 28a by one or more shear screws 76. lt will be apparent that downward movement of the hydraulic housing assembly 28 will exert a downward pull on the ratchet sleeve 58, and because of the interengaging tapered

teeth

66, 67, the second tubular body ill will also be moved downwardly. It is only after the ratchet sleeve retainer 72 has been removed from encompassing relation with respect to the dogs 68 that the second tubular body ll can be released from the ratchet sleeve 58 by camming the dog teeth 67 out of mesh from the body teeth 66.

The ratchet sleeve 58 extends upwardly through a retainer ring 77 through which the first and second body members 10, ll also extend, this retainer ring being initially releasably secured to the slip ring 26 by one or more shear screws 78. The upper portion of the ratchet sleeve has a plurality of ratchet teeth 79 extending longitudinally along its length, which face in an upward direction and which are engageable with internal ratchet teeth 80 facing in a downward direction and formed on a split lock ring 81 mounted within the slip ring 26. This lock ring has external cam teeth 82 adapted to coact with internal cam teeth 83 in the slip ring, there being sufficient lateral clearance as to permit the split lock ring 8i to expand outwardly and permit the ratchet sleeve 58 to move downwardly with reference to the slip ring 26, but in which any tendency of the ratchet sleeve 58 to move upwardly within the slip ring will cause the

cam teeth

82, 83 to coact and shift and hold the

ratchet teeth

79, 88 coengaged. Thus, a one-way clutching arrangement is provided which will permit relative downward movement of the ratchet sleeve 58 within the slip ring 26, but which will prevent its relative movement in a reverse or upward direction.

For the purpose of preventing premature setting of the packer A in the well casing B, the

tubular body members

10, 11 are locked together initially to preclude their relative longitudinal movement. As disclosed, the upper circumferentially continuous portion 71 of the ratchet sleeve 58 has a peripheral groove 84 therein in which a split lock ring 85 is received initially, this lock ring initially being confined between the downwardly facing body shoulder 86 on the slip ring 26 and by the upper end of the retainer ring 77 to which the slip ring 66 is releasably secured by the shear screws 78. This split lock ring 85 has inner beveled corners for coaction with companion beveled sides of the groove 84 to insure subsequent outward expansion of the ring from the groove.

The lower end of the retainer ring 77 bears upon a support ring 88 surrounding the first tubular body member 10, which, in turn, bears upon a split lock ring 89 disposed in a peripheral groove 90 in the first tubular body member, this lock ring being disposed within a counterbore 91 in the ratchet sleeve retainer 72. The inner corners of this lock ring 89 are also beveled and coact with companion tapered or beveled sides of the lock ring groove 90 to insure outward expansion of the lock ring after the setting location of the well tool A in the casing has been reached.

From the foregoing relationship of parts, it is apparent that any tendency for the receptacle l2 and the second tubular body 11 to move downwardly relative to the first tubular body 10 is prevented since such downward force or thrust is transmitted from the second body 11 through the

teeth

66, 67 to the ratchet sleeve 58, and from the latter through the upper split lock ring 85 to the retainer ring 77, and from the latter through the support ring 88'to the lock ring 89, which is confined in the first body groove 90 by the encompassing counterbore 91 in the ratchet sleeve retainer 72. Similarly, any tendency of the first body member 10 to move upwardly relative to the second body member 11 is prevented by this thrust being transmitted to the second tubular body in a reverse direction; that is, through the lower lock ring 89, support ring 88, retainer ring 77, ratchet sleeve 58, coengaged

tapered teeth

66, 67 to the second tubular body 11.

After the well packer A has been anchored in packed-off condition in the well casing, and it is desired to release and retrieve it therefrom, it is necessary to first disrupt or release a shear ring 92 that releasably secures the first tubular body 10 to the retainer ring 77. This shear ring surrounds the first body and has an inwardly directed flange 93 received within a peripheral groove 94 in the first body 10. it may be made in two halves, its flange 93 being held in the groove by an encompassing sleeve 95 mounted within a counterbore 96 in the retainer ring 77, this sleeve having an upper inwardly directed flange 97 overlying the shear ring 92. Mounted in the counterbore above the sleeve 95 is a rubber shock absorber 98, the upper end of which engages the upper base portion of the counterbore 96.

The well packer A is set in the well casing B by the hydrostatic head of fluid therewithin. As shown, the upper portion of the hydraulic housing structure 28 has a plurality, such as a pair, of longitudinal cylinders 520 therein offset from the

housing passages

27, 30 receiving the first and

second body members

10, 11. Each cylinder is formed partly in the lower hydraulic housing portion 28b, the lower end of which is closed by a lower cylinder head 521. The lower end 522 of a cylinder member or cylinder extension 523 is threaded into the lower housing member 28b and extends upwardly into a cylinder portion 524 within the upper hydraulic housing member 28a, an outwardly directed flange 525 on the cylinder member or sleeve engaging the lower end 526 of the upper housing member. Suitable seal rings 527 prevent leakage of fluid between the housing members. The coupling ring 64 not only holds the upper retainer 63 in a downward direction, as described hereinabove, but it also forces the retainer against the upper end of an upper cylinder head 528 extending downwardly within each cylinder bore 529 of the upper housing member 28a, clamping the upper head flange 530 against the end of the upper hydraulic housing member.

The cylinder extensions 523 have their flanges 525 engaged by a lower retainer 102, a coupling ring 103 threaded on the lower portion of the upper housing member 28a engaging'an external retainer flange 104 and effecting a clamping action of the cylinder exten sion flanges 525 against the lower end of the upper housing member 28a. The first tubular body extends through the lower retainer 102 and into the tubular body member 503, which is also true of a lower nipple 105 extending upwardly into the second passage 30 of the hydraulic housing section 280 and secured thereto by a split ring 106 received within a nipple groove 107 and clamped between the lower end of the housing member and the lower retainer 102.

One or more suitable seal rings 535 are provided between the hydraulic housing structure 28 and the first body member 10, a seal ring being disposed in the upper portion of the lower housing member 28b immediately above an annular fluid space 536 extending between the tubular housing member 503 and the body member 10 and body extensions 504 depending therefrom, the lower portion of this annular space being closed by a suitable seal ring 537 on the tubular housing member sealingly engaging against the

body extension members

504, 505 to which the sub 29 is threadedly secured. This annular space 536 contains air initially at substantially atmospheric pressure. However, it is able to communicate with the interior of the tubular body 10 through one or a plurality of side ports 538 in the body extension 504 when such side ports'are in open condition. Initially, the side ports are closed by a sleeve valve 539 extending thereacross which has a central bore 540 extending completely therethrough and a lower inwardly directed shoulder 541. Suitable side seal rings 542 are mounted on this sleeve valve on opposite sides of the ports to initially close the latter, the sleeve valve being retained initially in such port closing position by one or a plurality of shear screws 543 threaded in the upper body extension member 504 and received within a peripheral groove 544 in the sleeve valve member.

Fluid under pressure can enter the lower ends of the cylinders 520 through the interior of the tubular body 10 and through the annular space 546 within the tubular housing member 503. Passages 550 (FIG. 5) extend from the upper portion of this annular space to the lower ends of the hydraulic cylinders adjacent to their lower heads 52], the interior of the cylinders also initially containing air at atmospheric pressure. Each cylinder contains a lower or small piston portion 116 of a piston 117. This small piston is secured to or is integral 8 with a large piston portion 118 slidable in the large cylinder 529 above the cylinder extension member 523. The piston 117 is threadedly or otherwise suitably secured to a piston rod 119 extending upwardly through the cylinder and through the upper cylinder head 528, the rod also extending slidably through the upper housing retainer 63, the ratchet sleeve retainer 72, and the retainer ring 77. Initially, the upper ends of the piston rods 119 terminate below the lower end of the slip ring 26, which is adapted to be engaged by the piston rods when the well packer A is to be set in the well casing.

The pistons 117 and rod structures 119 are retained in their lower position within the upper member 28a of the hydraulic housing 28 by one or more shear screws or pins 120 in each cylinder extension extending into a piston 117. Each small piston 116 extends within the inner smaller diameter bore 529a of a cylinder extension523, a suitable seal ring 126 preventing leakage past the small diameter piston portion. Thelarge diameter piston also has suitable seal rings 124 mounted thereon adapted to slidably seal against the inner wall of the larger diameter cylinder portion 529 in the upper housing member 28a. It is also noted that suitable seal rings 127, 125 prevent fluid leakage around each cylinder head 528 and along each rod 119.

Each small piston 116 has a diameter equal to the diameter of the piston rod 119, so that the hydrostatic head of fluid in the well bore will act initially in an upward direction over the 'area of the small piston 116, after the ports 538 have been opened by downward shifting of the sleeve valve 539, and in a downward direction over the equal area of the piston rod 119. It will not, therefore, tend to shift the piston 117 upwardly within its cylinder 520. It is only after the ports 538 have been opened that pressure in the fluid within the cylinders 520 can be increased sufficiently to shear the pins l20 and shift each piston and its small diameter portion upwardly out of the small diameter cylinder bore 529a, whereupon the hydrostatic head of fluid in the well bore can act over the entire cross-sectional area of the pistons and exert a hydraulic setting force on the packer A. It is evident that the effective area of the entire piston corresponds to the diameter of the enlarged cylinder bore 529 along which the large piston 118 is slidable. The effect of this area is reduced by the cross-sectional area of the piston rod 119.

The upper packer apparatus A is set hydraulically as a result of shifting the small pistons 116 out of their small bores 529a, so that the fluid in the well bore can enter the large diameter portions of each cylinder for action upon the full area of each piston 117. Initially, there is a sufficient distance or space between the upper end of each piston rod 119 and the lower end of the slip ring 26 to allow the piston 117 to move upwardly in the cylinder and allow the fluid on the high pressure side of the piston 117 to act over the area of the large and

small piston portions

116 and 118. Such upward movement of the pistons can occur as a result of shearing the pins 120, which require a predetermined hydraulic pressure acting over the area of each small piston 116 to effect their disruption. As disclosed in the drawings, the pressure for shearing the pins and thereby effecting hydraulic setting of the well packer is derived from the first tubular string C and the central passage 600 within the first body 10 and the body extension 504, such central passage being placed in communication with the annular fluid space 536 within the tubular housing member 503, as a result of imposing a downward force on the valve sleeve 539 to disrupt the shear screw 543 and shift the valve sleeve downwardly to a position opening the ports 538.

Several specific shifting tools are available for performing that purpose, such as the Type B Otis Positioning Tool, illustrated on page 3468 of the 1972-73 Composite Catalog of Oil Field Equipment and Services and shown partially in FIGS. 12 and 13, which is run in on a wireline through the long tubing string C and the first tubular body into appropriate engagement with the sleeve valve 539, the tool having keys that are brought into engagement with the shoulder 541, a jarring action being imposed thereon to shear the screw 543 and shift the sleeve valve downwardly. Actually, the sleeve shifting tool can pass through the sleeve valve without shifting it, for the purpose of actuating other sleeve valves positioned in the well casing in connection with lower packers F, G that are to be set at appropriate locations in the well casing B. The positioning tool not only effects opening of the ports, but closes the passage 540 through the sleeve valve 539, allowing pressure to be built up in the fluid in the first tubular string C, annular fluid space 536, and through the lateral passages 550 into the lower cylinder heads, acting upwardly on the small pistons 116 to shear the pins 120, and move the small pistons upwardly out of sealing relation to the small cylinder bores 529a. Following upward shifting of the small pistons 116 from their restricted bores 529a, the hydrostatic head of fluid in the well bore can act upwardly over the full cross-sectional area of the pistons 117 toshift them upwardly in the housing 28 and to reactively move the hydraulic housing structure 28 downwardly. It is such relative upward and downward movement that effects anchoring of the well packer A in packed-off condition in the well casing.

A typical installation of a plurality of well packers is illustrated in FIGS. 1a, 1b, the upper packer A being illustrated in conjunction with lower packers F, G, which have been located in the well casing between upper, intermediate and lower formation zones UZ, lZ, LZ, communicating with the interior of the casing through casing perforations P. A retrievable hydraulic packer F, with its parts initially in a retracted position, is connected to the upper dual packer A by a suitable length of tubing 507. tubing 508 also extending between the intermediate packer F and the lowermost packer G. The packers F and G may be the same. These packers each have a sleeve valve 539 (FIGS. 12, 13) initially closing ports 538 to prevent the build-up of pressure in the tubing string to effect its setting. The sleeve valve and port arrangement may be substantially the same as illustrated in connection with the parallel string packer A, the long string C communicating through the tubing 507 with the intermediate hydraulic packer F and through a second length of tubing 508 extending between the intermediate packer F and the lowermost packer G. The intermediate and lower packers may be of the type illustrated in US. Pat. No. Re. 26,085, being adapted to be set by the hydrostatic head of fluid in the well casing. Such patent is incorporated herein by reference, a portion of the packer illustrated in the patent being disclosed in H68. 12 and 13. As shown therein, it includes a body 900 having a port 538 initially closed by a slidable sleeve valve 539 retained in such closed position by a shear screw 543, seal rings 542 on the sleeve valve straddling the port. An inner sleeve 901 surrounds the main body, with its lower end threadedly secured to a lower cylinder head 902 which has a cylinder skirt 903 threadedly secured thereto in spaced relation to the inner sleeve 901 to form a cylinder space 904 therein, in which a release piston 905 is disposed. The upper end of this release piston engages a lower cylinder head 906 integral with a sleeve not shown) appropriately connected to upper portions of the well packer illustrated in US. Pat. No. Re. 26,085. A port 907 in the inner sleeve communicates with the body port 538 and the cylinder space 904.

When the lower packer F or G is to be set, the Type B Otis Positioning Tool PT, identified above, is lowered on a wireline 908 through the long tubing string C and into the lower packer. This tool has laterally shiftable keys 909 thereon mounted on the running too] body 910 and urged laterally outwardly by springs 911 to bring lower shoulders 912 on the key into engagement with the upwardly directed shoulder 541 on the valve sleeve. The imposition of a downward jarring force on the positioning tool PT will effect the shearing of the screw or screws 543, and will shift the valve sleeve 539 downwardly to a position opening the

ports

538, 907 in the body 900 and inner sleeve 901, allowing the hydrostatic pressure to enter through such opened ports into the cylinder space 904 and act upwardly on the piston 905 which engages the lower cylinder head 906, effecting setting of the lower packer, as described in Reissue U.S. Pat. No. 26,085. As disclosed in FIGS. 12 and 13, the keys 909 have a cam surface 913 thereon adapted to engage a companion cam surface 914 on the packer body to shift the keys inwardly and retract the key shoulders 912 from the sleeve shoulder 541.

The type B Otis Positioning Tool is shown diagrammatically in FIGS. 12 and 13, since it forms no part of the present invention. This same shifting tool is used in shifting the sleeve valve 539 illustrated in F [G 20.

The upper and lower packers A, F, G, in retracted conditions, are lowered on the long string C into the well casing to locate the intermediate packer F between the intermediate and upper perforations P, the lower packer G between the intermediate and lower perforations P, the parallel string packer A being disposed in an appropriate location above the upper casing perforations. Before lowering the packers in the well casing, the well packer A has its parts occupying the relative positions illustrated in FIGS. 2a, 2b and 2c, in which the slips 50 and packing assembly .23 are retracted. Grease can be forced into the counterbore space 17 through the filler hole 21 and such hole then closed by the plug 22, the seal ring 19 preventing the grease from moving downwardly past the C-ring 15. Similarly, the grease can be placed within a counterbore in the housing surrounding the first tubular body member 10, there being a split pick-up ring 161 slidably mounted in this counterbore and having an inwardly directed flange 162 disposed within the groove 163 in the first body member 10. The lower end or corner 164 of the ring is tapered for coaction with a companion taper in the lower side of the groove 163 to insure outward expansion of the ring from the groove, as described hereinbelow. Grease forced into the counterbore 160 is prevented from dropping downwardly therefrom by a suitable seal ring 165 mounted in the housing structure 20 and sealing against the periphery of the first tubular body below the base of the counterbore.

After the lower, intermediate and upper packers have been lowered together on the long string C to the appropriate setting locations in the well casing, as illustrated in FIGS. 1a, 1b, the positioning tool PT is lowered through the long string and through the upper sleeve valve 539, a similar sleeve valve (not shown) in the intermediate packer F, and down into appropriate relation to a similar sleve valve positioned within the lower hydrostatically set packer G. Both of these valves occupy the same initial position closing ports as the sleeve valve 82 illustrated in Us. Pat. No. Re. 26,085, replacing the latter. This sleeve valve 539 of the lower packer G is jarred downwardly to open position by the type B Otis positioning tool PT to effect setting of the lower packer in packed-off condition against the well casing B, the upper and intermediate packers still remaining in their unset conditions. The setting action is set forth in detail in US. Pat. No. Re. 26,085. The lower packer G can now be tested through use of the Otis positioning tool, or the like, to open a longitudinally slidable sleeve valve 500 in the tubing string below the lower packer G, and applying pressure to the fluid in the long string to conduct a pressure test. If desired, the fluid in the annular space above the lower packer between the

tubing

507, 508 and the well casing B can be pressurized to determine the setting and sealing effectiveness of the lower packer against the well casing.

Assuming the test on the lower packer G is successful, the Otis positioning tool can be elevated by the wireline into appropriate relation with the sleeve valve of the intermediate packer F, and an appropriate jarring action imposed on the sleeve valve to shift it to an open position, effecting setting of the intermediate packer in packed-off condition against the well casing B, in the manner described in US Pat. No. Re. 26,085. The packer F can now be tested by shifting an appropriate sleeve valve 601 in the tubing 508 to open position through use of the positioning tool, and fluid pressure imposed on the fluid through the long string of tubing C, or through the annulus between the strings of tubing C, 507 and the well casing B. if the test proves the intermediate packer F to be appropriately anchored in packed-off condition in the well casing, the Otis positioning tool PT is moved upwardly by the wireline into appropriate relation to the valve sleeve 539 of the upper packer A, an appropriate jarring action on this sleeve shifting it downwardly to a position opening the ports 538, effecting setting of the upper packer A in packed-off condition. The upper packer can then be tested by opening a sleeve valve 602 in the tubing 507 through use of the positioning tool, fluid pressure being imposed on the fluid through the long string of tubing C, or through the annulus between the long string of tubing C and the well casing B. if the test proves the upper packer A to be appropriately anchored in packed-off condition, the retrieving tool can be removed and the short string D then run in the well casing in parallel relation to the long string C and disposed within the second passage 14 of the receptacle 12. As

shown, the second tubing string D engages an inclined guide surface 175 on the head 12, which will shift it toward the passage 14. This second tubing string may have a lower latch device 180 thereon and a seal portion 181, which can enter the second passage 14 of the receptacle. In connection with such entry, the latch mechanism 180 may snap through a shoulder 182 in the receptacle to prevent inadvertent upward removal of the second tubing string D from the receptacle, and the seal ring or sleeve 181 will seal against the wall of the second passage 14.

In connection with the hydrostatic head of fluid being effective to set the upper packer A in the well bore, shifting of the sleeve valve 539 to open the ports 538 causes the hydrostatic head of fluid to exert an upward force on the large pistons 118 and rods 119 and upon the slip ring 26, shearing the screw or screws 78 securing the slip ring to the retainer ring 77 and elevating the slip ring 26 and the slips 50 along the tubular body 10 and the ratchet sleeve 58, as permitted by the freedom of the lock ring 81 to ratchet upwardly over the sleeve ratchet teeth 79. The slip ring moves the slips 50 upwardly along the expander 24 and shifts them outwardly against the wall of the well casing B upon upward movement of the slip ring 26 along the ratchet sleeve 58 by a short distance. The slip ring moves out of confining relation to the split lock ring 85, allowing the latter to expand outwardly, freeing the ratchet sleeve 58 and second body member 11 from the retainer ring 77, allowing the hydraulic housing structure 28 to be moved downwardly by the hydrostatic head of fluid, which will carry the upper retainer 63, ratchet sleeve retainer 72, ratchet sleeve 58 and second body member 11 downwardly with it. Prior to freeing of the split lock ring 85 from its groove 84, any downward force imposed by the hydraulic housing structure 28 through the split lock ring 85 on the retainer ring 77 will have very little effect on the shear ring 92 attached to the first body member 10, since it will merely pass through the support ring 88 and lock ring 89 to the body 10.

The downward movement of the hydraulic housing structure 28, ratchet sleeve 58, and second body member 11 under the action of the hydrostatic head of fluid is transmitted to the receptacle or body 12, the upper connector 32, upper insert 33, and upper gauge ring 34, shifting these parts downwardly toward the expander 24 and shortening the packing structure 23, causing the packing elements 39 to be expanded outwardly into sealing engagement with the wall of the well casing B. During such downward movement, the ratchet sleeve 58 can ratchet downwardly freely through the split lock ring 81 mounted in the slip ring 26, the downward movement and force being exerted on the expander 24 and wedging the latter within the slips 50 to embed their wickers or teeth in the wall of the well casing. During the downward movement of the parts referred to in expanding the packing structure 23 and embedding the slips 50 in the well casing, the packing assembly 23, expander 24, a second body 11, ratchet sleeve 58, ratchet sleeve retainer 72, and the hydraulic housing structure 28, and parts associated therewith, move downwardly relative to and along the first tubular body 10, the ratchet sleeve retainer 72 being shifted downwardly from encompassing relation to the lock ring 89 and allowing the latter to expand outwardly from the body groove 90. The parts are now in the relative position illustrated in FIGS. 60, 6b and 10. When in this position, it will be noted that the one-way lock device 79 to 83 has effectively coupled the second tubular body I] to the slip ring 26 and, therefore, retains the upper receptacle 12 in a fixed position relative to the slip ring 26, preventing separation between the two. Thus, the packing assembly 23 and slips 50 are held or locked in their expanded condition against the wall of the well casing.

The hydrostatic head of lfuid is constantly acting on the pistons 117 and lower cylinder heads 521, to urge the slip ring 26 upwardly and the receptacle or body 12 downwardly to hold the packer anchored in packed-off condition in the well casing. ln the event the packing elements 39 tend to extrude through adjacent clearance spaces, such extrusion will not produce any loosening of the well packer, since the constantly applied hydrostatic head of fluid will immediately move the receptacle and slip ring toward each other to take up any slack that might tend to occur, and retain the packing structure and slips firmly engaged with the well casing. Even if the hydrostatic head of fluid were to be dissipated completely in the well casing, the well packer would remain anchored in packed-off condition therewithin, since the one-way lock devices 79-83 will positively hold the tool in its set condition.

From the foregoing description, it is apparent that a plurality of hydraulically or hydrostatically set well packers A, F. G can be lowered in the well casing on the long string C, and that the packers can be selectively set, preferably by first effecting setting of the lower packer G, which can be tested before any action is taken with respect to setting the intermediate and upper packers F. A. If the test on the lower packer is unsatisfactory, it can readily be released and removed from the well casing, since the intermediate and upper packers have not as yet been set. The long string C, which is the only tubing string then in the well casing, is the only one that need be actuated to effect release of the lower packer G, whereupon all packers A, F, G, can be elevated in the well casing and removed therefrom. ln the event the lower well packer test is successful, the Otis, or similar, positioning tool can then be engage'd with the sleeve valve in the intermediate packer F, shifting it to port opening position and effecting hydraulic setting in packed-off condition of the packer F in the well casing. The intermediate packer can then be teseted, and if unsuccessful, the long string C is actuated to release the lower and intermediate packers from the well casing B, whereupon all packers are removed from the well casing. Should the intermediate packer test be successful, the positioning tool can be engaged with the sleeve valve 530 in the upper packer A, shifting it to port opening position and effecting hydraulic setting in packed-off condition of the upper packer A in the well casing. The upper packer A can then be tested. It is to be noted that a landing nipple 800 is threadedly secured to the lower end of the lower nipple 105 and that this landing nipple initially carries a blanking plug assembly 801, of any suitable type, for the purpose of closing the passage through the lower nipple 105, the second passage 30 and the second body member 11, to prevent passage of fluid therethrough in both directions. This blanking device 801 includes an upper hollow lock body 802 threadedly or otherwise secured to a blanking plug 803, the lower end of which seats upon a seating nipple shoulder 804, the blanking plug having one or more seal rings 805 sealingly engaging the wall 806 of the passage through the seating nipple 800. The lock body carries a plurality of springpressed latches 807 movable outwardly into an internal circumferential groove 808 in the seating nipple, to

prevent upper movement of the blanking assembly 801 in the seating nipple 800, its downward movement being prevented by the lower shoulder 804 in the seating nipple.

In the event the test of the upper packer A proves successful, the short string D can then be lowered into position and appropriately located within the receptacle, the parts then being in the position illustrated in FIGS. 6a, 6b. A suitable retracting tool (not shown), such as illustrated in U.S. Pat. No. 2,885,007, can be lowered through the short string D, and through the second body 11, passage 30 and nipple 105 to the blanking plug device 801. This retracting tool effecting retraction of the latches 807 from the groove 808, becoming coupled to the fishing neck 810 at the upper end of the lock body 802, which permits the entire plug assembly 801 to be elevated through the nipple 105, passage 30 and second body 11 and short string D to the derrick floor.

If the upper packer test is unsatisfactory, the blanking plug device 801 need not be removed, and the string of packers A, F, G can be released from the well casing and removed from the well bore. Since the short string D is lowered to position in the well casing only after a successful test, the long string C is the only one requiring elevation in the casing.

The upper packer A can be released and withdrawn from the well casing without the necessity for equalizing pressures on the high and low pressure sides of the pistons 117, merely as a result of taking an upwardly directed strain on the first tubing string C and first body member 10. Such upward pull will exert a force upon the shear ring 92, rubber bumper 98, retainer ring 77, lock ring and the slip ring 26, which, however, is prevented from moving upwardly by virtue of the wedging action of its companion slips 50 upon the expander 24 and the embedding of the slip teeth 51 in the wall of the well casing. When a sufficient upward force is taken on the first tubing string C and first tubular body 10, the shear ring is disrupted at its flange 93, allowing the first body 10 to move upwardly through the remainder of the well packer, the pick-up ring 161 moving upwardly within the housing counterbore 160, and through the upper retainer 63 into engagement with the lower end of the ratchet sleeve retainer 72. Exertion of a sufficient force thereon will disrupt the shear screw 76 and will allow continued upward movement of the first tubular body 10 to elevate the ratchet sleeve retainer 72 along the ratchet sleeve 58, to remove the retainer from encompassing relation to the sleeve dogs 68. The ratchet sleeve retainer 72 will move upwardly until it is brought into engagement with the lower lock ring 89, whereupon the tapered side of the first body groove 163 will expand the split lock ring 161 outwardly from the groove and thereby permit the first body member 10 to continue its upward movement within the remainder of the packing apparatus, until the C-ring 15 engages the receptacle shoulder 18. This C-ring can move from its initial position below the seal 19 to a position thereabove by shearing through such seal.

When the C-r'ing 15 engages the receptacle shoulder 18, continued upward movement of the first tubular string C and the first body 10 will elevate the receptacle or head 12 and the second tubular body 11. This second tubular body can move upwardly through the ratchet sleeve 58 as a result of the tapered

teeth

66, 67

camming the dogs 68 out of mesh therewith. As the second tubular body 11 and the receptacle 12, upper connector 32, upper insert 33, and gauge ring 34 move upwardly away from the expander 24, the packing assembly 23 inherently retracts to its initial position. Following such retraction, the split ring 46 on the second body will engage the lower insert 41 and elevate the expander 24 relative to the slip ring 26, pulling the slips 50 back to their initial retracted position. The first body 10 will move upwardly until the coupling 29 engages the lower hydraulic housing member 503, resulting in upward movement of the entire well packer apparatus below the slip ring with the first body member (FIGS. 7a, 7b).

Continued elevation of the first tubular string C will elevate the released well packer A in the well casing B to the top of the well bore, the second tubular string D having been removed from the well casing before release of the tool commences. Following release of the well packer, the hydrostatic head of fluid will shift the pistons 117 upwardly in the cylinders to their fullest extent, as disclosed in FIG. 11, which may greatly compress the air trapped on the low pressure sides 123 of the pistons. However, during elevation of the released well packer through the fluid in the well casing, the hydrostatic head of fluid progressively decreases, and as the top of the well bore fluid is approached, the compressed air can reexpand to shift the pistons 117 back downwardly so that the entrapped air is again at substantially atmospheric pressure. Accordingly, the tool can be dismantled later without fear of suddenly releasing any pressures, since there will be no pressure differential trapped within any portion of the well packer.

It is, accordingly, apparent that an upper well packer A has been provided of the hydrostatic type which can be used in conjunction with packers F or G, or both, therebelow, each packer being selectively set and tested in an appropriate sequence, such as described above. It is only necessary to run all of the packers on a single tubing string C to their appropriate setting locations in the well casing, setting being effected through the application of pressure through the long string C only, and in the absence of the short string D,

the short string only being run into position after the packers have been set and successfully tested.

We clam:

1. In apparatus adapted to conduct fluids through a plurality of tubular strings extending to the top of a well bore: a plurality of packers adapted to be disposed in the well bore; a tubing extending between and secured to said packers to hold said packers in longitudinally spaced relation, said packers including an upper packer having substantially parallel passages therethrough, a first of said parallel passages communicating through said tubing with a corresponding passage in a lower of said packers; a first tubular string secured to said upper packer for lowering all of said packers in the well bore to selected setting locations therewithin, said tubular string communicating with said first passage; said upper and lower packers each including normally retracted means and fluid operated means communicating with and responsive to the hydrostatic head of fluid in said first passage and corresponding passage, respectively, for expanding said normally retracted means of each packer outwardly into engagement with the wall of the well bore; said upper packer having first means in said first passage for preventing fluid pressure from passing from said first passage to said fluid operated means of said upper packer, said lower packer having second means in said corresponding passage for preventing fluid pressure from passing from said corresponding passage to said fluid operated means of said lower packer; and operating means movable through said first tubular string selectively into engagement with said first means and second means for selectively shifting said first means and second means separately and sequentially to positions permitting fluid pressure to pass from said first passage and corresponding passage to the fluid operated means of said upper packer and the fluid operated means of said lower packer.

2. In apparatus as defined in claim 1; said operating means being first engaged with said second means to shift the same and then engaged with said first means to shift the same.

3. In apparatus as defined in claim 1; and a second tubular string lowered in the well bore, after expansion of said upper packer normally retracted means, into engagement with a second parallel passage of said upper packer.

4. In apparatus as defined in claim 1; said operating means being first engaged with said second means to shift the same and then engaged with said first means to shift the same; and a second tubular string lowered in the well bore, after expansion of said upper packer normally retracted means, into engagement with a second parallel passage of said upper packer.

5. In apparatus as defined in claim 1; said first means closing a first port communicating said first passage with said fluid operated means of said upper packer; said second means closing a second port communicating said corresponding passage wtih said fluid operated means of said lower packer; said operating means selectively shifting said first means to a position opening said first port and said second means to a position opening said second port.

6. In apparatus as defined in claim 1; said first means comprising a first sleeve valve closing a first port communicating said first passage with said fluid operated means of said upper packer; said second means comprising a second sleeve valve closing a second port communicating said corresponding passage with said fluid operated means of said lower packer; said operating means shifting said first sleeve valve to a position opening said first port and said second sleeve valve to a position opening said second port.

7. In apparatus as defined in claim 1; said first means closing a first port communicating said first passage with said fluid operated means of said upper packer; said second means closing a second port communicating said corresponding passage with said fluid operated means of said lower packer; said operating means selectively shifting said first means to a position opening said first port and said second means to a position opening said second port.

8. In apparatus as defined in claim 1; said first means comprising a first sleeve valve closing a first port communicating said first passage with said fluid operated means of said upper packer; said second means comprising a second sleeve valve closing a second port communicating said corresponding passage with said fluid operated means of said lower packer; said operating means shifting said first sleeve valve to a position opening said first port and said second sleeve valve to a position opening said second port; said operating means being first engaged with said second sleeve valve to shift the same to a position opening said second port and then engaged with said first sleeve valve to shift the same to a position opening said first port.

9. In apparatus as defined in claim 1; said first means comprising a first sleeve valve closing a first port communicating said first passage with said fluid operated means of said upper packer; said second means comprising a second sleeve valve closing a second port communicating said corresponding passage with said fluid operated means of said lower packer; said operating means shifting said first sleeve valve to a position opening said first port and said second sleeve valve to a position opening said second port; said operating means being first engaged with said second sleeve valve to shift the same to a position opening said second port and then engaged with said first sleeve valve to shift the same to a position opening said first port; and a second tubular string lowered into the well bore, after expansion of said upper packer normally retracted means, into engagement with a second parallel passage of said upper packer.

10. In apparatus adapted to conduct fluids through a plurality of tubular strings extending to the top of a well bore: a plurality of packers adapted to be disposed in the well bore; a tubing extending between and secured to said packers to hold said packers in longitudinally spaced relation, said packers including an upper packer having substantially parallel passages therethrough, a first of said parallel passages communicating through said tubing with a corresponding passage in a lower of said packers; a first tubular string secured to said upper packer for lowering all of said packers in the well bore to selected setting locations therewithin, said tubular string communicating with said first passage; said upper and lower packers each including normally retracted means and fluid operated means communicating with and responsive to the hydrostatic head of fluid in said first passage and corresponding passage, respectively, for expanding said normally retracted means of each packer outwardly into engagement with the wall of the well bore; said normally retracted means of each packer comprising a normally retracted packing structure expandable by said fluid operated means into sealing engagement with the wall of the well bore, said normally retracted means further comprising slips and an expander engageable with said slips, said expander and slips being movable longitudinally relative to each other by said fluid operated means to expand said slips into anchoring engagement with the wall of the well bore; said upper packer having first means in said first passage for preventing fluid pressure from passing from said first passage to said fluid operated means of said upper packer; said lower packer having second means in said corresponding passage for preventing fluid pressure from passing from said corresponding passage to said fluid operated means of said lower packer; and operating means movable through said first tubular string selectively into engagement with said first means and second means for selectively shifting said first means and secondmeans separately and sequentially to positions permitting fluid pressure to pass from said first passage and corresponding passage to the fluid operated means of said upper packer and the fluid operated means of said lower packer.

11. In apparatus as defined in claim 10; said operating means being first engaged with said second means to shift the same and then engaged with said first means to shift the same.

12. In apparatus as defined in claim 10; and a second tubular string lowered into the well bore, after expansion of said upper packer normally retracted means, into engagement with a second parallel passage of said upper packer.

13. In apparatus as defined in claim 10; said first means closing a first port communicating said first passage with said fluid operated means of said upper packer; said second means closing a second port communicating said corresponding passage with said fluid operated means of said lower packer; said operating means selectively shifting said first means to a position opening said first port and said second means to a position opening said second port.

14. In apparatus as defined in claim 10; said first means comprising a first sleeve valve closing a first port communicating said first passage with said fluid operated means of said upper packer; said second means comprising a second sleeve valve closing a second port communicating said corresponding passage with said fluid operated means of said lower packer; said operating means selectively shifting said first sleeve valve to a position opening said first port and said second sleeve valve to a position opening said second port.

15. In apparatus as defined in claim 10; said first means comprising a first sleeve valve closing a first port communicating said first passage with said fluid operated means of said upper packer; said second means comprising a second sleeve valve closing a second port communicating said corresponding passage with said fluid operated means of said lower packer; said operating means selectively shifting said first sleeve valve to a position opening said first port and said second sleeve valve to a position opening said second port; said operating means being first engaged with said second sleeve valve to shift the same to a position opening said second port and then engaged with said first sleeve valve to shift the same to a position opening said first port.

$7330 v UNI rED S'iA'lES m'ljmNf f blunt;

CER'LIFICA'LE OF CORRECTION I Patcnt; Ne 3.841.409" I D 119 12211.1 I

- RUDY B. CALLIHAN. and CLYDE s. WAINWRIGHLII, JR.

Inve ntor(s) I It is certified that: error appears in the above-identified patent and that said Letters Patent are-hezjeby corrected as' s hown below:

,Column 7, fine 60 change "545"? to -536;

Colurgr 11", line 10: "slave" should read -s1eeve--.

Co1unm 13', 11ne" 5: "1fu1d s'hould read "fluid".

Signed and sealed this. 7th c iay of January- 1975.

(SE L); j Att'es't:

Z-ZcCO"- If. G BSON JR; C. I'iARSHALL DANN Attesting Officer Commissioner o'f'Patents

Claims

10. In apparatus adapted to conduct fluids through a plurality of tubular strings extending to the top of a well bore: a plurality of packers adapted to be disposed in the well bore; a tubing extending between and secured to said packers to hold said packers in longitudinally spaced relation, said packers including an upper packer having substantially parallel passages therethrough, a first of said parallel passages communicating through said tubing with a corresponding passage in a lower of said packers; a first tubular string secured to said upper packer for lowering all of said packers in the well bore to selected setting locations therewithin, said tubular string communicating with said first passage; said upper and lower packers each iNcluding normally retracted means and fluid operated means communicating with and responsive to the hydrostatic head of fluid in said first passage and corresponding passage, respectively, for expanding said normally retracted means of each packer outwardly into engagement with the wall of the well bore; said normally retracted means of each packer comprising a normally retracted packing structure expandable by said fluid operated means into sealing engagement with the wall of the well bore, said normally retracted means further comprising slips and an expander engageable with said slips, said expander and slips being movable longitudinally relative to each other by said fluid operated means to expand said slips into anchoring engagement with the wall of the well bore; said upper packer having first means in said first passage for preventing fluid pressure from passing from said first passage to said fluid operated means of said upper packer; said lower packer having second means in said corresponding passage for preventing fluid pressure from passing from said corresponding passage to said fluid operated means of said lower packer; and operating means movable through said first tubular string selectively into engagement with said first means and second means for selectively shifting said first means and second means separately and sequentially to positions permitting fluid pressure to pass from said first passage and corresponding passage to the fluid operated means of said upper packer and the fluid operated means of said lower packer.