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Publication numberUS3831677 A
Publication typeGrant
Publication dateAug 27, 1974
Filing dateNov 24, 1972
Priority dateNov 24, 1972
Also published asCA991989A, CA991989A1, DE2357744A1
Publication numberUS 3831677 A, US 3831677A, US-A-3831677, US3831677 A, US3831677A
InventorsMullins A
Original AssigneeSchlumberger Technology Corp
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Retainer packer with improved valve system
US 3831677 A
Abstract
In accordance with the illustrative embodiments of the present invention as disclosed herein, a packer apparatus adapted for well pressuring operations such as cementing includes a mandrel having a flow passage and a valve sleeve movable vertically within the lower end portion of the mandrel for opening and closing the flow passage in response to manipulation of an operator that can be extended into the flow passage. The operator is arranged to be indexed automatically through a sequence of angular displacements in response to upward and downward movement thereof, and cooperatively arranged coupling structures on the valve sleeve and the operator function to connect the two together so that the valve can be shifted vertically between open and closed positions, and to automatically disconnect the operator from the valve sleeve so that the operator can be withdrawn from the flow passage leaving the valve closed.
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United States Patent [191 Mullins [451 Aug. 27, 1974 [5 1 RETAINER PACKER WITH IMPROVED VALVE SYSTEM Albert A. Mullins, Richmond, Tex.

[73] Assignee: Schlumberger Technology Corporation, New York, NY.

[22] Filed: Nov. 24, 1972 [21] Appl. No.: 309,313

[75] Inventor:

[56] References Cited UNITED STATES PATENTS 2/1967 Muse 166/128 10/1968 Nutter 166/226 X 9/1969 Kisling 166/128 10/197] Lewis 166/226 Primary Examiner-James R. Boler Attorney, Agent, or FirmDavid L. Moseley; Stewart F. Moore; William R. Sherman ABSTRACT In accordance with the illustrative embodiments of the present invention as disclosed herein, a packer apparatus adapted for well pressuring operations such as cementing includes a mandrel having a flow passage and a valve sleeve movable vertically within the lower end portion of the mandrel for opening and closing the flow passage in response to manipulation of an operator that can be extended into the flow passage. The operator is arranged to be indexed automatically through a sequence of angular displacements in response to upward and downward movement thereof, and cooperatively arranged coupling structures on the valve sleeve and the operator function to connect the two together so that the valve can be shifted vertically between open and closed positions, and to automatically disconnect the operator from the valve sleeve so that the operator can be withdrawn from the flow passage leaving the valve closed.

15 Claims, 7 Drawing Figures PATENIEUmczmm 831 L677 sum ear 2 FIGS RETAINER PACKER WITH IMPROVED VALVE SYSTEM This invention relates generally to well packers used in well bores, and more particularly to a cement retainer packer with improved drillability.

A cement retainer is a type of well packer that has, in addition to slips and expanders to anchor against movement and elastomeric packing rings to seal off the borehole, a fluid passage and a valve to control fluid flow therethrough. The tool is permanently set in a well casing at the desired location, and a tubing string that extends to the surface is used to pump cement slurry into the well below the packer. When the pumping is completed, the valve is closed to retain the cement at developed pressures below the tool.

Being a permanently set device, a cement retainer must be drilled up with a drill bit whenever it is desired to gain access to the well therebelow. The drilling operation can be quite expensive if much time is required, therefore it is highly desirable to construct a cement retainer in such a manner that the drill-up time is at a minimum. It is quite common to make the massive metal parts, such as the mandrel, expander cones and slips, out of readily drillable materials, so that all other factors being equal, the drill up time is a function of the amount of metal that is employed in the tool.

One quite successful well packer that is designed for cementing applications is shown and described in US Pat. No. 3,465,820, assigned to the assignee of this invention. The tool employs an indexing and movement control system for the valve operator or stinger that provides positive stops to up and down motion of the operator, which permits pressure testing the pipe string in compression, as well as assuring against accidental disengagement of the operator. The valve operator actuates a rotating valve that is indexed between open and closed positions in response to upward and downward movement of the pipe string. This type of valve, while possessing numerous advantages in terms of simplicity in function and reliability of operation, is not uniformly loaded under pressure in the closed position because the pressure differential is concentrated at regions adjacent the side openings in the valve body. Thus in order to prevent deformation or distortion of the valve element in response to such pressure concentrations, it is necessary to provide a wall thickness therefore which, due to dimensional limitations imposed by the well bore size, dictates that the valve element be housed in the valve body located below the packer mandrel where more lateral space is available. It has been found, however, that the tool can be shortened considerably to reduce the drill up time if the valve element is located at least partially within the lower end of the mandrel itself, where the abovementioned space limitations require the use of a valve element that is designed to have the pressure applied uniformly over the circumference thereof so that its wall thickness can be reduced.

On the other hand, the aforementioned US. Pat. No. 3,465,820 discloses an indexing and movement control system for the valve operator that has a number of significant advantages. lt permits the tubing string to be pressure tested for leakage with the pipe string in compression, which cannot be accomplished with other commercially available devices, and provides a positive stop against accidental disengagement of the valve operator or stingen It is the principal object of this invention to provide a new and improved well packer that has a valve element upon which pressure is uniformly applied and is located in such a manner that the tool can have minimum length for optimum drill-up time, the valve being moved between open andclosed positions by a valve operator having an indexing and movement control system that is positive and reliable in operation.

This and other objects are attained in accordance with the concepts of the present invention through the provision of a well packer having a mandrel with a flow passage that can be opened and closed by a sliding sleeve valve element disposed within the lower end por tion of the mandrel. The valve element is a relatively thin walled tubular member that can be moved between a lower open position and an upper closed position. A valve operator extends into the flow passage and has a rotational coupling to the pipe string that extends upwardly to the surface so as to move upwardly and downwardly therewith, and means are provided to cause the operator to rotate within the mandrel flow passage in a certain sequence of angular steps during such movement. The rotational motion of the operator selectively aligns lugs thereon with stop shoulders on the mandrel to provide definite limits of vertical motion. Moreover, a channel system at the lower end portion of the valve operator is caused to cooperate with a lug on the valve element in such a manner as to move the valve element between open and closed positions.

According to one embodiment of the present invention, the valve member is corotatively coupled to the packer mandrel so as to move vertically between open and closed positions, with the channel system on the lower end portion of the valve operator being cooperatively arranged to shift the valve member vertically as it undergoes vertical as well as rotational movement. In another embodiment, the valve member is free to move rotationally and vertically in response to actuation by the valve operator. In both cases, the valve member is uniformly loaded by fluid pressure differentials in the closed position so that it can have an optimum minimum wall thickness and be located within the lower portion of the packer mandrel to reduce the overall length of the tool and thereby minimize drill-up time.

The present invention has other objects and advantages that will become more clearly apparent in connection with the following detailed description of several embodiments thereof, taken in conjunction with the appended drawings in which:

FIG. 1 is a longitudinal sectional view, with portions in side elevation, of a cement retainer and releasable setting tool combination that incorporates a valve and actuator in accordance with the principles of the present invention;

FIG. 2 is a view in enlarged detail of the valve and actuator structure of FIG. 1;

F168. 3, 4 and 5 are developed plan views of the coupling channel configurations for the longitudinal stop, the index control and the valve coupling systems, respectively.

FlG. 6 is a fragmentary cross-sectional view of another embodiment of a valve member and actuator in accordance with this invention; and

FIG. 7 is a plan view of the coupling systems used in the modified form of FIG. 6.

Referring initially to FIG. 1, there is shown a well packer 10 that is dependently coupled to a mechanical setting tool 11 that is, in turn, suspended by a runningin string 12 of tubing or drill pipe that extends upwardly to the surface. The setting tool 11 includes a mandrel 13 having its upper end threaded to the lower end of the tubing 12, and carrying a control sleeve 14 and a slip retainer sleeve 15. The control sleeve 14 is slidably and corotatively secured to the mandrel 13 by splines 16 or the like, and is initially locked in an upper position thereon by one or more latch lugs 17 that engage in a mandrel detent 18. The retainer sleeve has a drag assembly 19 fixed to its upper end including a tubular cage 20 that carries typical spring biased drag blocks 21 adapted to frictionally engage the casing. An inner surface 22 of the cage 20 normally holds the lugs 17 in engagement with the detent groove 18, and the cage 20 as well as the retainer sleeve 15 are normally fixed in a lower position relative to the control sleeve 14 by meshed right hand jack threads 23.

The mandrel 13 has a swivel coupling 25 shown generally as a tubular valve operator or actuator 26 having an enlarged upper section 27 and a reduced diameter lower portion 28 adapted to be received within the bore of the well packer 10 as will be described in more detail herebelow. The swivel coupling 25 includes the usual relatively rotatable parts, and can include a safety joint clutch as disclosed and claimed in my US. Pat. No. 3,552,492, assigned to the assignee of this invention. Although the details of the swivel coupling 25 need not be described in detail here, it will be recognized that the valve operator 26 can rotate freely in at least one direction relative to the setting tool mandrel 13 in order to enable actuation of the valving in the packer 10 and to position certain control lugs for engagement and disengagement as will become more apparent hereinafter.

The well packer 10 includes a central body member or mandrel 30 having a bore 31 which provides a fluid passageway. The valve operator 26 is sealingly slidable within the passageway 31 and carries an appropriate seal assembly 32 that engages a seal surface 33 on the mandrel 30 to prevent fluid leakage. A conventional packing structure 34 is mounted around the mandrel 30 between an upper expander cone 35 and a lower expander cone 36. The lower cone 36 engages a lower slip structure 37 that can take any desired form, such,

as frangible, segmented, or integral expansible type slip. One particularly advantageous form of slip is shown in my US. Pat. No. 3,687,196, for example. In any event, the slip 37 has external wicker or teeth 38 adapted to bite into and grip the casing to prevent longitudinal movement, as well as an inner inclined surface 39 that engages the outer surface of the expander cone 36 so that relative movement will cause outward shifting of the slips. The upper expander cone 35 also has an inclined outer surface that engages the inner inclined surfaces 40 ofa plurality of slip segments 41 having external teeth 42 that can grip the casing to prevent movement. During running the slip segments 41 are retained in inner or retracted positions by virtue of the fact that the lower end portion 43 of the setting tool retainer sleeve 15 telescopes over the reduced diameter upper portions 44 of the slip segments 41. Moreover, each slip segment 41 has inwardly directed shoulders 45 and 46 that fit within external annular grooves 47 and 48 on the enlarged section 27 and the packer mandrel 30, respectively, to connect the setting tool 11 to the packer 10 in the running-in position.

Other fairly typical structure that may be utilized in this type of well packer may include anti-extrusion rings to confine the upper and lower ends of the packing 34, and shear pins or other suitable means to releasably couple the expander cones 35 and 36 to the mandrel 30 in a manner to control the relative motion sequence between parts as they are set in the casing. These elements are well known and need not be described in detail here. Moreover, a conventional split ratchet ring 50 can be arranged between the upper expander cone 35 and the mandrel 30 and have internal teeth that mesh with external teeth on the mandrel 30 to trap compression loading in the packing 34 when the well packer is set in the casing.

An abutment ring 52 is threaded onto the lower end of the mandrel 30 and provides an upwardly facing shoulder to support the lower slips 37. The abutment ring 52 can be integrally formed with a nose piece 53 having a solid bottom section 54 to close of the lower end of the bore of the mandrel 30. A plurality of ports 55 extend, however, through the wall of the mandrel 30 at the approximate level of the slips 37 in order to provide a means of communicating the mandrel bore 33 with the well annulus below the packing 34. The ports 55 are adapted to be opened and closed by a sliding valve sleeve 56 whose structural features and cooperative relationship with the valve operator 26 form the subject of this invention.

As shown in greater detail in FIG. 2, the valve sleeve 56 is sized to fit within a counterbore 57 at the lower end of the mandrel 30, and has upper and lower external seal rings 58 and 59 that slide in sealing contact with the wall surface of the counterbore 57. An elongated, vertically extending groove 61 is formed in the outer wall of the lower portion 52 of the valve sleeve 56, and receives a guide pin 63 that is mounted on the mandrel 30 and extends into the groove 61 to prevent relative rotation between the valve sleeve and the mandrel. The open bore 64 of the valve sleeve 56 is sized to receive the lower end portion 28 of the valve operator 26, and diametrically opposed drive lugs 65 extend inwardly of the bore and into a coupling system 66 on the lower portion 28 in order to couple the valve sleeve and operator during a sequence of movements as will be described in detail herebelow. It will be fully apparent at this point, however, that when the valve sleeve 56 is in the upper position the seals 58 and 59 span the flow ports 55 to block fluid flow therethrough, whereas in the lower position the valve sleeve is out of the way to enable fluid via the ports 55 and a plurality of side windows or openings 67 through the wall of the lower portion 28 of the valve operator 26.

Referring again to FIG. 1, it will be noted that the valve operator 26 has arcuate coupling lugs 70 to either side that engage within an elongated internal mandrel recess 71. The recess 71, shown in developed plan view in FIG. 3, is opened to the top of the packer mandrel 30 by vertically extending slots 72 and 73 located on circumferentially opposite sides of the bore of the mandrel. Thus the coupling lugs 70 can be inserted into the recess 71 via the slots 72 and 73, and rotation of the valve operator 26 relative to the mandrel 30 will position the lugs underneath the mandrel shoulders 74 formed between the slots. With this relationship of parts, abutment of the coupling lugs 70 with the shoulders 74 will limit upward movement of the operator 26 relative to the mandrel 30, whereas engagement of the enlarged section 27 of the operator with the upper end surface of the mandrel 30 will limit downward movement. Thus when the lugs 70 are beneath the shoulders 74, the operator 26 is coupled for limited reciprocating motion relative to the mandrel 30, and when the lugs are aligned with the slots 72 and 73, the operator can be inserted into, or withdrawn from, the bore 31 of the mandrel 30.

An intermediate section of the operator 26 is provided with a system 80 of channels or grooves that cooperate with diametrically opposed index pins 81 on the mandrel 30 to cause the operator to rotate automatically through various rotational positions as it is reciprocated vertically within the mandrel bore 31. Such rotation serves two principal functions: (1) to couple and uncouple the operator 26 with the valve sleeve 56, and (2) to couple and uncouple the operator and the mandrel 30. The slot system 80 is shown in plan or developed view in FIG. 4 and includes arcuate bosses that are spaced apart to provide vertically disposed entrance and exit slots 82 and 82 located on opposite sides of the operator 26. Inasmuch as the channel system 80 is symmetrically arranged around the circumference of the operator 26, for purposes of brevity, only one-half of the complete channel system will be described and it will be appreciated each channel portion mentioned hereinafter has an identical counterpart located on the opposite side of the operator 26. Between these entrance and exit slots 82 and 82' are upper pockets 83 and 84, the left pocket being angularly displaced from the entrance channel 82 and the right pocket 84 being angularly displaced from the exit channel 82. An intermediate lower pocket 85 is located between the upper pockets 83 and 84. The channel 82 is connected to the pocket 83 by an inclined channel 86 that extends upwardly and to the right, and the upper pocket 83 is connected to the intermediate pocket by a channel 87 that inclines downwardly and to the right. The intermediate pocket 85 is connected to the upper pocket 84 by a channel 88 that extends upwardly and to the right like channel 86, and finally the upper pocket 84 is contacted to the exit channel 82' by a channel 89 that inclines downwardly and to the right like channel 87. The intersections of the channels 86 and 87, and 87 and 88, are located somewhat to the left of the respective centers of the pockets 83 and 84 so that the index pin 81 is automatically guided to enter the channel 87 when leaving the pocket 83, and the channel 88 when leaving the pocket 85. Moreover, the intersection of channels 88 and 89 is located somewhat to the left of the upper pocket 84 so that the index pin 81 will automatically enter the channel 89 when leaving the pocket 84. As previously mentioned, the slot system 80 in which the index pins 8i engage causes a predetermined sequence of rotational movements of the operator 26 relative to the mandrel 30 in response to upward and downward movements of the operator. The sequence of movements serves to couple and uncouple the lower end portion 28 of the operator 26 with the valve sleeve 56 by appropriately positioning the valve coupling system designated at 66 with respect to the drive lugs 65 on the valve sleeve 56.

The coupling system 66, one symmetrical half of which is shown in plan view in H0. 5, is constituted by an external annular recess 90 around the circumference of the lower portion 28 of the operator 26, the recess being opened to the lower end of the operator by two vertically extending slots 91 and 92 located on diametrically opposed sides of the lower end portion. The protruding shoulder 93 between each pair of the slots provides an upwardly facing surface 94 that can engage the drive lug 65 on the valve sleeve 56 to cause upward shifting thereof to closed position. The recess 90 is also provides with upwardly extending, relatively wide slots 95 that receive the drive lugs 65 during certain portions of the vertical motion of the operator 26, and, due to their width, permit some rotation of the operator relative to the valve sleeve 56 even though the lugs are engaged therein. The slots 95 are separated by bosses providing downwardly facing shoulder surfaces 96, each of which is appropriately aligned vertically with respect to the lower slots 91 and 92 so as to be able to engage the drive lugs 65 to cause downward shifting of the valve sleeve 56 to open position.

The operation of the channel system 80 and the coupling systems 71 and 66 can best be understood by considering the F I08. 3, 4 and 5 together as follows. As the operator 26 is inserted into the bore 31 of the packer mandrel 30, regardless of the random rotational orientation of the operator, the lower inclined surfaces of the bosses 101 engage the index pins 81 on the mandrel to properly orient the operator so that the pins enter the entrance and exit channels 82 and 82'. This also orients the stop lugs 70 to enter the slots 72 and 73, as well as properly lining up the slots 91 and 92 at the bottom of the operator for reception of the drive lugs 65 on valve sleeve 56 and their entry into the annular recess 90. When the shoulders 96 engage the drive lugs 65, (assuming that the valve sleeve 56 is intially in the upper or closed position) the valve sleeve is shifted downwardly to the open position where the side windows 67 in the operator are aligned with the side ports 55 in the mandrel 30. During a final portion of downward movement of the operator 26, the index pins 81 engage the inclined sides of the channels 86 and cause the operator to rotate, thereby placing the stop lugs 70 underneath the shoulders 74 and also aligning the upwardly facing shoulders 94 with the drive lugs 65 on the valve sleeve 56. When downward movement of the operator 26 is stopped by engagement of the enlarged section 27 with the upper end of the mandrel 30, the index pins 81 are in the pockets 83, the stop lugs 70 are in the position shown in solid line in FIG. 3, and the drive lugs 65 are in the position shown similarly in FIG. 5. Then when the operator 26 is moved upwardly, the index pins engage the sides of the inclined channels 87 to cause the operator to rotate again (in the same direction), and when the index pins reach the intermediate pockets 85, the control lugs 70 abut the shoulders 74 in the position shown in dotted lines in FIG. 3 to stop upward movement. However during such upward movement the drive shoulders 94 have engaged the lugs 65 on the valve sleeve 56 to shift it upwardly to closed position where the seals 58 and 59 span the mandrel ports 55 so that the valve: is closed. Next the operator 26 can be moved downwardly and will rotate again as the pins 81 engage the sides of the inclined channels 88 prior to entry into the pockets 84, however the drive lugs 65 on the valve sleeve 56 enter the wide upper slots 95 and, not being engaged by any surface permit the valve sleeve 56 to remain in the closed position. Again the enlarged section 27 engages the upper end of the mandrel 30 to limit downward movement. Finally the operator 26 is moved upwardly again, and this time the index pins 81 engage the sides of the inclined channels 89 to rotate the operator so that they are aligned with the exit slots 82. Such rotation not only aligns the stop lugs 70 to be released through the slots 72 and 73, but also aligns the lower end slots 91 and 92 on the operator with the drive lugs 65 on the valve sleeve 56 so that the operator can be withdrawn from the bore 31 of the mandrel 30, leaving the valve sleeve in the upper or closed position.

Considering now the operation of the overall structural combination, the tools are prepared at the surface for running into the well by connecting the setting tool 11 with the well packer 10. This is accomplished by simply inserting the operator 26 into the bore of the packer mandrel 30 with the retainer sleeve 15 in its upper position on the control sleeve 14, thus enabling the upper slip assembly 41 to be positioned with the internal recess 105 overlapping the shoulders 107 and 106 on the mandrel 30 and enlarged section 27, respectively. With the slip assembly coupling these two parts, the retainer sleeve 15 is advanced downwardly by rotating the drag assembly 19 until its lower end portion telescopes over the upper portions 44 of the slips 41 to lock the parts together. The setting tool mandrel 13 is then threaded to the tubing 12 and the assembly is ready to lower into the well casing. During insertion, the valve sleeve 56 will have been pushed downwardly to the open position as previously described, so that the tubing 12 can fill with well fluids during running. The drag blocks 19 of course adapted to slide in frictional contact with the casing C and provide a resistance to rotation of the cage 20 and the retainer sleeve 15.

At setting depth, the well packer 10 and setting tool 11 are halted, and the tubing 12 is rotated to the right. Since the drag blocks 19 prevent rotation of the retainer sleeve 15, the jack threads 23 function to feed both the drag assembly 19 and the retainer sleeve 15 upwardly until the slip segments 41 are freed to be shifted outwardly. Moreover, a releasing recess 110 in the cage is positioned opposite to the latch lugs 17 to enable them to release from the mandrel detent 18, whereby the setting tool mandrel 13 can be elevated relative to both the control sleeve 14 and the drag assembly l9.

lnasmuch as the coupling lugs 70 on the operator 26 are underneath the shoulders 74, having been automatically positioned there during insertion of the operator 26 into the mandrel 30, elevation of the setting tool mandrel l3 and the packer mandrel 30 with resepct to the control sleeve 14 and the drag assembly 19 causes the upper expander cone 35 to shift the upper slips 41 outwardly into gripping contact with the casing C. The slips 41 are restrained against upward movement due to the fact that the lower end surface of the control sleeve 14 engages the upper end surfaces of the upper portions 44 of the slips. When the slips 41 set against the casing, continued upward movement of the packer mandrel 30 and the lower abutment ring 52 causes the lower slips 37 to be shifted outwardly into gripping contact with the casing, and the packing elements 34 to be compressed and expanded into sealing contact with the well casing wall to pack off the well bore. The

ratchet ring traps the mandrel 30 in the highest position to which it is moved with respect to the upper cone 35 to lock the packer in set condition. At a predetermined amount of tensile strain in the tubing 12, the well packer 20 is firmly set as shown in FIG. 2.

As the operator 26 was moved upwardly with respect to the mandrel 30 during the setting sequence described above, the index pins 81 will have moved into the intermediate pockets 85, and the shoulder surfaces 94 at the lower portion of the operator 26 will have shifted the valve sleeve 56 to the upper or closed position. Thus the weight of the tubing 12 can now be imposed on the well packer 10, moving the operator 26 downwardly until the index pins 81 are in the pockets 84, however the valve sleeve 56 remains closed as previously described. Thus the tubing 12 can be pressure tested for leaks at this point with the tubing in compression.

Subsequent to completion of testing the tubing 12, it is then picked straight up at the surface to disengage the operator 26 from the bore 31 of the packer mandrel 30. As the operator 26 moves upwardly, the index pins 81 seek the exit slots 82' and properly align both the coupling lugs 70 and the valve release slots 91 and 92 for such release. The valve sleeve 56 remains in the closed position, which is always the case when the operator is removed from the bore 31 of the packer 10 so that it completely bridges the well.

To perform a pressure operation such as squeeze cementing, a batch of cement slurry can be displaced into the tubing, and at the appropriate time the operator 26 is reinserted within the bore 31 of the mandrel 30 by lowering the tubing. The valve sleeve 56 is automatically shifted to the lower or open position so that the slurry can be pumped into the region of the well bore below the packer and then behind the casing through perforations therein. When it is desired to trap the squeeze, e.g., to retain the cement slurry at developed pressures below the packer 10, the tubing 12 is simply lifted upwardly to cause closure of the valve sleeve 56. The coupling lugs 70 will engage the stop shoulders 74 V to prevent inadvertent disengagement of the operator 26, with consequent advantages as discussed in US. Pat. No. 3,465,820, assigned to the assignee of this invention. Release of the operator 26 is accomplished by imparting a pair of vertical motions to the tubing 12, one downward and one upward.

Inasmuch as the entire external surface of the valve member 56 located between the seal rings 58 and 59 is exposed to fluid pressure via the ports 55 in the closed position, it will be apparent that the valve sleeve 56 is stressed uniformly around its curcumference by such fluid pressures. Thus the valve sleeve can be designed with the relatively small size as shown in the drawing to fit within the counterbore 57 at the lower end of the mandrel 30, eliminating any requirement for a separate valve body and thereby reducing the amount of metallic materials used in the well packer. This minimizes the drill-up time when it is desired to remove the packer 10 to clear the well casing. The coupling systems described herein retain the optimum in positive control of the valve sleeve 56 through simple surface manipulations of the tubing, namely only up and down motion.

Another embodiment of a valve and actuator system according to the principles of the present invention is shown in FIG. 6. Inasmuch as the indexing and the coupling lug systems for the valve actuator and their cooperative relationships with the packer mandrel are the same as described in connection with the previous embodiment and shown in FIGS. 4 and 3, respectively, only the modified valve and its coupling connection with the lower portion of the actuator need be described in detail here. As shown, the valve element is constituted by a tubular sleeve 150 having upper and lower external seal rings 151 and 152 and diametrically opposed coupling lugs 153 that project inwardly into the through bore 154 of the sleeve. The valve sleeve 150 is disposed for reciprocating movement within a counterborc 155 in the lower end portion of the mandrel 156 between an upper position where the seals and 152 span the side ports 157 to block fluid flow, and a lower position where the ports are open above the valve sleeve. As in the previous embodiment, a lower abutment ring 160 is threaded onto the mandrel 156 and supports the lower slip segments 170 that are adapted to be shifted outwardly by a companion expander cone 171. A nose piece 172 closes the lower end of the bore 173 of the mandrel 156 and can be connected to a junk" pusher (not shown) as previously described. An outwardly extending shoulder 175 limits downward movement of the valve sleeve 150, and a similar shoulder 176 limits upward movement.

The valve sleeve 150 has a through-bore sized to accept the lower end portion 180 of the valve actuator 181 which has a coupling system indicated generally at 182 adapted to coact with the lugs 153 to cause the valve sleeve to shift between open and closed positions in response to upward and downward movement of the pipe string. As shown in developed plan view in FIG. 7, the coupling system 182 includes arcuate bosses 183, disposed on opposite sides of the actuator 181, each having inclined lower surfaces 184 to automatically guide the valve lugs 153 and thereby properly orient the valve sleeve 150 as the lower portion 181 of the actuator is inserted thereinto. The surface 184 leads to a channel 185 that inclines upwardly and to the right and connects with a pocket 186, whereas another inclined channel 187 extends downwardly and to the right and connects with a lower pocket 188. From the lower pocket 188, a vertically extending channel 189 connects with an arcuate opening 190 through the wall of the actuator 180, the opposite side walls of the opening being spaced apart such that the actuator can index through a predetermined angle without imparting corresponding movement to the valve sleeve 150. The upper end of a channel 191 that inclines downwardly and to the right communicates with the right side of the opening 190 and leads to the space 192 between the bosses 183 to enable disconnection of the actuator from the lugs 153 on the valve sleeve 150. It should be noted that as distinguished from the structure of the previously described embodiment. the valve sleeve 150 is not splined or keyed to the mandrel 156 but is free to move rotationally as well as vertically within the counterbore 155.

In operation, assuming that the valve sleeve 150 is in the upper or closed position and the valve actuator 181 is being inserted into the bore 173 of the packer mandrel 156, the indexing system described with reference to FIG. 4 will properly orient the actuator so that the control lugs 70 at the upper end thereof will enter into the mandrel recess 71 as indicated in FIG. 3. Moreover, the lower surfaces 184 of the bosses 183 will coact with the valve sleeve lugs 153 to orient the lugs for entry into the channel systeml82. Continued insertion of the actuator 181 will cause the lugs 153 to move through the channels 185 and into the pockets 186 as the actuator is indexed by the system shown in FIG. 4, and when the lugs 153 reach the ends of the pockets 186 the valve sleeve 150 is shifted or driven downwardly to the open position shown in FIG. '6. In this position, ce-

ment slurry pumped down the tubing string and' through the actuator will flow via the side windows 190 out the mandrel ports 157 and into the well bore below the packer.

When the actuator 181 is next raised, the index system 80 causes rotation so that the valve sleeve lugs 153 pass through the channels 187 and into the lower pockets 188, whereupon continued upward movement causes the valve sleeve to be shifted or driven upwardly to the closed position where the seals 151 and '152 span the side ports 157. As previously described with reference to FIG. 3, the actuator stop lugs 70 come into engagement with the mandrel shoulders 74 to provide a positive stop to upward movement. To release the actuator 181 for withdrawal from the mandrel 156, a pair of vertical movements are imparted to the actuator, one downward and one upward. During the downward movement, the actuator 156 rotates as the index pins 81 moves from the pockets into the pockets 84 (FIG. 4), however the valve sleeve: remains stationary because the lugs 153 are free to move relatively within the side openings 190 to the position shown in dotted lines in FIG. 7. During the succeeding upward movement of the actuator, the index system 80 causes the actuator to rotate by virtue of movement of the index pins 81 into the exit slots 82 to thereby align the coupling lugs 70 with the openings 72 and 73 at the top of the mandrel recess 71, and during such movement the valve lugs 153 pass through the channels 191 and into the spaces 192 to disconnect the actuator from the valve sleeve 150. Thus the actuator is free to be withdrawn from the bore of the mandrel 156, leaving the valve sleeve 150 in the upper or closed position.

Inasmuch as the valve sleeve 150 is not splined or keyed to the mandrel 156, the construction thereof is somewhat simplified. Moreover, the valve sleeve 150 can be positioned within the counterbore at the lower end of the mandrel in any random orientation with assurance that the valve sleeve will be properly and automatically positioned for coupling to the actuator 180 whenever it is inserted into the bore of the mandrel 156.

Although the well packer 10 as disclosed herein is set with a mechanical setting tool 11, it will be appreciated that the packer can be set by the various wireline or gas setting tools which are conventional in the art. Of course in the case of wireline setting the upper slips 41 may be of the solid or frangile type, and the threads shown internally of the bottom nose piece 53 are .utilized to connect the tension member of the setting tool.

Since certain changes or modifications may be made in the disclosed embodiments without departing from the inventive concepts involved, it is the aim of the appended claims to cover all such changes or modifications falling within the true spirit and scope of the present invention.

I claim:

1. A well packer apparatus, comprising: a body member having a flow passage and carrying means to provide an anchored pack-off in a well; valve means movable vertically in said flow passage between an upper closed position and a lower open position; a valve actuator extending into said flow passage and movable upwardly and downwardly as well as rotationally therein; means for indexing said valve actuator to a plurality of angularly displaced positions with respect to said body member in response to upward and downward movement of said actuator within said flow passage; and means on said valve actuator and said valve means for connecting said valve means with said actuator in response to rotation, and for shifting said valve means be tween open and closed positions in response to upward and downward movement.

2. The well packer apparatus of claim 1 wherein said body member has a counterbore at the lower end portion thereof, said valve means being a hollow sleeve movably disposed within said counterbore.

3. The well packer apparatus of claim 2 wherein said connecting means comprises lug means extending inwardly of said sleeve, and downwardly opening channel means formed on the lower end portion of said valve actuator, said channel means being adapted to receive said lug means.

4. The well packer apparatus of claim 3 wherein said shifting means comprises opposed, transverse shoulders adapted to alternately engage said lug means, said shoulders defining wall surfaces of said channel means.

5. The well packer apparatus of claim 2 further including a slidable spline connection for preventing rotation of said sleeve relative to said body member.

6. A well packer apparatus comprising: a body member having a flow actuator; and carrying means to provide an anchored pack-off in a well conduit; valve means movable vertically in said flow passage between an upper closed position and a lower open position; a valve actuator extending into said flow passage and movable upwardly and downwardly as well as rotationally therein; means for indexing said valve actuator to a plurality of angularly displaced positions with respect to said body member in responseto upward and downward movement of said actuator within said flow passage; first means for coupling said valve actuator and valve means in response to at least one angular dis placement of said valve actuator; second means for shifting said valve means between said open and closed positions in response to upward and downward movement ofsaid valve actuator; and third means for uncoupling said valve actuator and valve means in response to at least another angular displacement of said valve actuator.

7. The well packer apparatus of claim 6 further including lug means on said valve means, and wherein said first means comprises a downwardly opening channel on said valve operator, said lug means adapted to' be received by said channel during insertion of said valve actuator into said flow passage.

8. The well packer apparatus of claim 7 wherein said second means comprises a set of spaced apart, opposed shoulder surfaces on said valve actuator angularly spaced with respect to said channel and adapted to engage said lug means, said shoulder surfaces defining wall portions of a recess on said lower portion, said channel guiding said lug means into said recess.

9. The well packer apparatus of claim 7 wherein said second means comprises a set of spaced apart, oppositely arranged pockets angularly spaced with respect to said channel and adapted to receive said lug means, reception of said lug means in one of said pockets caus ing said valve means to be shifted downwardly to open position, and in the other of said pockets causing said valve means to be shifted upwardly to closed position.

10. The well packer apparatus of claim 6 further including recess means disposed adjacent said second means and said third means for enabling vertical and rotational movement of said valve actuator within said flow passage without translating any motion to said valve means.

11. The well packer apparatus of claim 10 further including a slidable connection for preventing rotation of said valve means relative to said body member.

12. A well packer apparatus comprising: a body member having a flow passage and carrying means to provide an anchored pack-off in a well, said flow passage including a laterally directed port through the wall of said body member adjacent the lower end thereof; a valve sleeve movable vertically within said flow passage between an upper position spanning said port to close said passage and a lower position below said port to open said passage; a valve actuator extending into said flow passage and being sealingly slidable therein, said actuator being movable upwardly and downwardly as well as rotationally therein; means for indexing said valve actuator to a plurality of angularly spaced positions in response to upward and downward movement; and coupling means on the lower end portion of said valve actuator for shifting said valve sleeve between open and closed positions, said coupling means being comprised of circumferentially spaced, downwardly opening channels that are interconnected by a series of angularly spaced recesses, at least some of said recesses defining shoulder surfaces, said valve sleeve having inwardly projecting lug means thereon adapted to be received in said channels and said recesses, said channels cooperating with said lug means to connect said actuator with, and to disconnect said actuator from, said valve sleeve, said shoulder surfaces engaging said lug means to shift said valve sleeve vertically between said open and closed positions.

13. The well packer apparatus 'of claim 12 wherein one of said recesses is elongated in the vertical direction and has a circumferential dimension arranged to avoid contact with said lug means during a portion of the upward, downward and rotational movements of said actuator so that said valve sleeve can remain stationary in the closed position during such movements.

flow passage.

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Classifications
U.S. Classification166/128, 166/334.1
International ClassificationE21B23/00, E21B34/00, E21B34/12, E21B33/12, E21B33/129
Cooperative ClassificationE21B33/12, E21B23/006, E21B33/1294, E21B34/12
European ClassificationE21B33/12, E21B34/12, E21B33/129N, E21B23/00M2