US 20070012461 A1
A packer assembly requires only forces applied axially along an actuating means such as production tubing (either pushing down or pulling up) to actuate it between its operational states, such as a set state, a bypassed state, and a released state. The packer includes a tubular member that has a lug guide formed substantially within its inner surface. The packer further includes a mandrel that can be coupled to an actuating means and disposed within the tubular member, the mandrel further comprising a lug ring having at least one lug disposed in the lug guide. The tubular member is held in a substantially fixed position relative to the mandrel once the packer is initially set within a well-bore. The lug ring is free to rotate in response to forces applied to the tubing once the packer tool assembly is initially set.
1. A packer apparatus comprising:
a tubular member comprising a lug guide formed substantially within its inner surface;
a mandrel operative to be coupled to an actuating means and disposed within the tubular member, the mandrel further comprising a lug ring having at least one lug disposed in the lug guide;
means for maintaining the tubular member in a substantially fixed position relative to the mandrel once said packer is initially set within a well-bore; and
wherein the lug ring is operative to rotate in response to forces applied to the actuating means once the packer tool assembly is initially set.
2. The packer apparatus of
3. The packer apparatus of
4. The packer apparatus of
5. The packer apparatus of
a first of the state positions of the lug guide corresponds to a set state wherein said packer is sealably anchored within the well-bore; and
a second of the state positions of the lug guide corresponds to a released state wherein said packer can be repositioned within the well-bore.
6. The packer apparatus of
7. The packer apparatus of
8. The packer apparatus of
9. The packer apparatus of
10. The packer apparatus of
11. The packer apparatus of
12. The packer apparatus of
13. The packer apparatus of
14. A method of actuating a packer, said packer comprising a mandrel, the mandrel comprising a rotatable lug ring, the lug ring comprising at least one lug, the mandrel being disposed within a tubular member, the at least one lug being disposed within a lug guide formed substantially within the inner surface of the tubular member and having a plurality of state positions and a plurality of intermediate positions there between, each of the state and intermediate positions sequentially interconnected through a guide segment, said method comprising:
setting the packer within a well bore, said setting further comprising maintaining the tubular member in a fixed position relative to the mandrel;
applying a downward axial force on the mandrel to urge the at least one lug through a declining one of the guide segments into a next intermediate position of the lug; and
applying an upward axial force on the mandrel to urge the at least one lug through an inclining one of the guide segments into a next state position of the lug guide.
15. The method of
a first of the state positions of the lug guide corresponds to a set state wherein the packer is sealably anchored within the well-bore; and
a second of the state positions of the lug guide corresponds to a released state wherein the packer can be repositioned within the well-bore.
16. The method of
17. The method of
18. The method of
deploying the armed packer within a well-bore; and
wherein said setting further comprises providing a triggering force to the packer that exceeds the predetermined threshold.
19. The method of
20. The method of
When oil and gas wells are first drilled, sections of pipe are threadably secured together and the segmented pipe is lowered into the well-bore created by the drilling process. Cement is then typically introduced between the well-bore and the outside surface of the pipe to rigidly secure the pipe in place within the well-bore. This length of cemented pipe is called a casing and provides a rigid support that prevents the well-bore from collapsing in on itself Because the casing is expensive, it is desirable for the casing to be relatively permanent. Thus, it is important to protect the casing from the corrosive properties of the fluids that are typically produced from the well (e.g. oil, gas and other fluids from formations tapped by the well), as well as fluids that may be pumped down into the well for purposes of acidizing, formation fracturing, squeeze cementing, or other similar operations known to those of skill in the art.
One common technique for protecting the casing as previously described is through the use of a tool generally referred to as a packer. Packers are typically deployed within the annulus or bore of the casing and include sealing elements that, when forced against the annular surface of the casing, prevent the flow of fluids into the casing that are being produced just below it. The packer ensures that corrosive fluids are only produced through the packer and a second pipe to which the packer is attached rather than through the casing itself
A packer is deployed by first lowering the packer into the casing attached to, for example, a length of production tubing or a wireline as is known to those of skill in the art. While being lowered into the well, the packer is initially configured in a mode whereby it is able to move freely within the bore of the casing until it reaches the zone of a formation from which the well is to produce. The packer is designed such that upon reaching the appropriate depth in an “armed” mode, it can be triggered or actuated through the application of forces from above to anchor itself against the annular surface of the casing while also disposing its sealing elements against the annular surface of the casing. This process is known as “setting” the packer.
In the case of packers run into the hole already attached to tubing through which the well is to be produced, the setting of the packer is typically triggered by introducing fluid into the packer through the tubing. The bore of the packer is initially plugged on its down-hole end and as a result hydraulic forces develop inside of the packer and are used to trigger the setting process. Packers run into the hole by wireline are set by actuating a wireline device that uses gravity to trigger the setting process. Once set, the wireline and wireline device are removed and production tubing is then introduced and coupled to the packer. In either case, once the packer is set, a pump out plug is blown out of the down-hole end of the packer to enable production from a perforated portion of the casing just below it. Regardless of the manner in which the triggering or actuating force is generated and applied, most commercially available packers operate in a similar fashion internally to achieve the desired “set” configuration.
Once production from a well (or at least from a particular zone within the well) has been completed, a packer is typically removed from that location in the well-bore. Some packer designs permit the packer to be released from the set position through the application of forces to the production pipe or tubing to which the packer is attached. These forces are typically axial (i.e. along the axis of the pipe or tubing), or some may require rotational forces applied to the pipe or tubing that are translated into a torque at the packer. Other designs are permanently set and the only way they can be removed is by their destruction, such as drilling them out of the casing. Some retrievable packers can be released through application of axial force, raised or lowered to another zone, and then reset at the new depth without having to be pulled from the hole and re-armed. In the case of a reset, force applied up-hole is used to reset the packer rather than hydraulic forces or a wireline. Resetting these packers typically requires the ability to administer a rotational force to the packer from above the ground in addition to applying pulling and pushing (i.e. axial) forces.
The ever-increasing demand for oil and gas and the increasing price in response thereto, has motivated the drilling of wells to access formations that are not easily reached with a primarily vertical well-bore. Rather, access to many formations requires directional and even horizontal drilling that may involve abrupt changes in direction (referred to as “doglegs”). As a result, the pipe used for the casing and especially for producing such wells has necessitated the use of more flexible materials such as tubing that can be more easily run through horizontal and doglegged bores. The use of flexible tubing has made it virtually impossible to use packer designs that require rotational forces to manipulate the packer. This is because it is very difficult to achieve sufficient rotational force on a packer that is coupled at the end of what may be several thousand feet of flexible tubing. While a packer deployed under such conditions may initially be set using hydraulic forces, current packer designs still require the application of rotational forces if the packer is to be easily released and reset at another depth to avoid being removed from the well.
For a detailed description of embodiments of the invention, reference will now be made to the accompanying drawings in which:
FIGS. 2A-B form two parts of continuous drawing that illustrates a cross-sectional view of the top and bottom sections, respectively, of an embodiment of a hydraulically actuated packer incorporating aspects of the invention.
Certain terms are used throughout the following description and in the claims to refer to particular features, apparatus, procedures, processes and actions resulting therefrom. Those skilled in the art may refer to an apparatus, procedure, process, result or a feature thereof by different names. This document does not intend to distinguish between components, procedures or results that differ in name but not function. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”
The following discussion is directed to various embodiments of the invention. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted as, or otherwise be used for limiting the scope of the disclosure, including the claims, unless otherwise expressly specified herein. For example, an embodiment may be hydraulically actuated (i.e. set) if run into the hole coupled to tubing, yet various aspects of the invention can also be incorporated into embodiments using other known setting techniques, such as using a wireline device. In addition, one skilled in the art will understand that the following description has broad application, and the discussion of any particular embodiment is meant only to be exemplary of that embodiment, and not intended to intimate that the scope of the disclosure, including the claims, is limited to that embodiment. For example, while the various embodiments may employ one type of technique for initially setting the packer, packers employing other known techniques are considered within the scope of the present invention.
With reference to
As previously described, packers have been designed that can be released, re-positioned within the well bore, and then re-set without having to be removed from the well-bore. One such packer design is disclosed in U.S. Pat. No. 5,197,547 (hereinafter the '547 patent), which is incorporated herein in its entirety by this reference. The packer design disclosed in the '547 patent requires a rotational force, along with axially applied forces, to be applied at the up-hole end of the production medium to release the packer from the “set” mode and reset the packer while disposed within the well-bore. The application of torque to actuate the packer in this manner becomes exceedingly difficult when disposed in a directionally drilled well-bore such as that illustrated in
Some packer designs employed under the drilling conditions described in
Moreover, aspects of the present invention also permits an additional “bypassed” state, between the “set” and “released” modes, where fluids are permitted to bypass the seals into the casing for purposes of performing circulation while the packer remains in a “set” state. Thus, while in this bypass state, the packer remains anchored within the casing and the sealing elements remain deployed until circulation is complete. During circulation, fluid is forced down through the production tubing causing fluids resting at the bottom of the well to be lifted up from the bottom of the well. These fluids are then forced into interstitial areas of the packer outside of the packer bore, around the sealing elements and ultimately into the annulus of the casing. This serves to avoid contact between the fluids being produced during circulation and the sealing elements, which would otherwise degrade the sealing elements and quickly render them ineffectual. Moreover, it is an added benefit that the packer remains anchored within the casing during circulation.
The mandrel sub 31 is telescopically received through the upper end of a body B, which is releasably connected to mandrel sub 31 by suitable frangible means such as shear pins 32 as is well known to those of skill in the art. In an embodiment, shear pins 32 may extend through body B and into sub 31. An annular cap 33 is threadedly engaged in the upper end of body B at threads 134 and the cap 33 terminates in the shoulder 34 internally of body B as shown. Mandrel sub 31 has shoulder 35 extending outwardly between mandrel sub 31 and body B which engages shoulder 34 when the packer is being unset so that mandrel sub 31 may be moved up by the tubing T.
As shown in
The spring element 55 is typically collapsed when the tool is assembled as the body B is moved up on the packer mandrel to be secured to the mandrel sub 31 by the frangible means 32. It remains collapsed or partially collapsed as the body B is moved down along the packer mandrel by hydraulic forces created during the setting process as will be described in more detail below. Those of skill in the art will recognize that other known embodiments of packers may not make use of a resilient element 55. For example, an alternate embodiment of a packer that does not make use of a resilient element 55 is disclosed in the above-referenced '547 patent.
The packer mandrel may be formed of any suitable number of tubular portions, in addition to mandrel sub 31, as is known to those of skill in the art. In an embodiment, this may include an upper tubular portion or sub 14 (which is threadedly connected to mandrel sub 31 at 16) and a lower tubular portion or sub 15, which are threadedly connected together through a rotatable lug assembly 500. A more detailed description of an embodiment of the rotatable lug assembly will be presented later in the description.
In an embodiment, a member referred to generally at 26 (and is sometimes referred to as a packer support or a rubber mandrel), provides a support for the rubber sealing elements P that are used to seal the casing C when the packer is set. The packer support 26 includes a support sleeve 27 and upper 102 and lower 104 slip and cone assemblies. It serves to extend or move the packer or seal elements referred to generally at P, along with the upper and lower slip and cone anchor assemblies 102, 104, into sealing and securing relation with the inner surface or annular wall of the casing C.
In an embodiment, the upper assembly 102 includes upper slips 57 supported at the lower end of the body B in a manner well known to those skilled in the art and are adjacent to (and while in the “armed” state, preferably not in contact with) an annular, tapered surface 58 a forming a conical surface or cone supported on the upper end of the packer support 26. The lower assembly 104 includes a movable end portion 60 on the lower end of packer support 26, which has an annular tapered surface 61 forming a conical surface or cones for engagement with adjacent lower slips 62 on member 25 when the packer is set. Those of skill in the art will recognize that the structure and relationship of the cones 58 a, 61 and slips 57, 62 may be accomplished in any manner suitable for setting the packer.
In an embodiment, the upper end of packer support 26 is secured by suitable means such as threads 56 c to support sleeve 27 as shown in
In an embodiment, the support sleeve 27 extends longitudinally of the packer mandrel as shown in the drawings and terminates in end cap 69, which may be threadedly engaged thereon and assists in supporting the partially surrounding member 25 on the sleeve 27. The member 25 may be formed of any desired number of tubular subs or portions, and may include an upper tubular sub 72 and a lower tubular sub 25 a, which may be threadedly coupled as shown at 25 b or coupled in any appropriate manner as the packer is assembled. The member 25 includes a groove 606 formed within its internal surface into which rotating lugs 514 a and 514 b (
In an embodiment, drag blocks referred to generally at 70 and springs 71 are supported in the tubular sub 72. Member 25 may be formed by the upper tubular sub or member 72 and the lower tubular sub or member 25 a, which are connected together to form the member 25 as previously discussed. When the drag blocks 70 are engaged during the initial setting of the packer, they are urged outwardly by spring means 71 for engagement with the casing C to enable the packer mandrel to be vertically manipulated relative to the member 25. Vertically manipulating the mandrel causes lugs 514 a, 514 b to be advanced within groove 606 to achieve various operational states of the packer, including the “bypassed” and “released” states, and then back to the “set” state if desired. A more detailed description of the rotatable lug assembly 500,
In an embodiment, the springs 71 will be initially collapsed and secured to the support sleeve 27 and member 25 prior to deployment and while in the “armed” state prior to triggering the setting of the packer. Shear pins 72 a may be employed to maintain the drag blocks in this inoperative or non-engaged state. Shear pins 72 a may also be used to secure the member 25 so that slips 62 are supported in a non-engaging position adjacent the tapered surface (i.e. cone) 61 while the packer is deployed within the well bore casing C. Those of skill in the art will recognize that other equivalent means may be employed to provide the necessary anchoring of the tubular member 25 to render it stationary with respect to the packer mandrel without consequence to the patentability of the invention as disclosed.
In an embodiment, rotatable lug assembly 500,
In an embodiment, the groove or guide patterns 606 of
In an embodiment of the guide 606,
In an embodiment, a pump out plug referred to generally at 36 is shown adjacent the lower end 29 of the mandrel sub 15. The pump out plug may include a tubular housing 37 threadedly connected to the mandrel sub 15, and a plug portion 38 releasably secured in the housing by any suitable means such as a frangible member, or shear pins 39. After the packer is set, sufficient hydraulic pressure can be applied to the bore of the mandrel to shear the pin(s) 39 and release the plug 38 to enable fluid flow through the mandrel bore 26 a and the packer as desired.
In assembling a packer for deployment that includes features of the present invention, virtually all of the components except for the rotating lug assembly 500 and lower tubular sub 25 a, may be assembled using any number of well-known designs in any well-known manner to place such a design in a “preset” or “armed” state. With reference to the example embodiment of
In an embodiment, shear pins 72 a are introduced as shown in
In an embodiment, the packer is threadedly secured with the tubing T as shown and is lowered into a well-bore casing C. Once the packer has been lowered to the desired position within casing C, the packer is hydraulically triggered to become “set” in a manner well known in the art. Fluid is pumped down through the tubing T and into the bore 26 a of the packer. Internal pressure begins building within the packer, including inside the spring housing 55 a of body B as the fluid flows into the housing 55 a through channels 5,
Body B continues to press downwardly and the top slips 57 are pressed downward and make initial contact with top cones (not shown) of the upper slip and cone arrangement 102. Continued movement of the packer support or rubber mandrel 26 (including support sleeve 27) shears pins 72 a to release the member 25 and the drag block springs 71 of drag block assembly 70. These forces are also translated to the rubber mandrel 26, causing the top cones (not shown) of lower slip and cone arrangements 104 to initially contact the bottom slips 62. This results because second end portion 60 of the packer support 26 contacts lower slips 62 to force the lower slips 62 and tapered surface 61 out into securing engagement with the surface defining the opening in which the present invention is positioned. This stops the downward movement of movable portion 60 of the packer support 26.
Continued downward hydraulic force on body B and packer support 26 forces packer support 26, packer P and support sleeve 27 downward. Packer P is thus forced against packer support second end portion 60 which forces or extends the packer or seal elements P out into sealing engagement with the annular surface of the casing C. The above action continues until the packer P and the upper slip 57 of upper slip and cone assembly 102 is firmly engaged with the annular surface of the casing C. Finally, the hydraulic forces cause the shear pins 512 in the rotatable lug assembly to sheer, which frees the packer mandrel (e.g. subs 31, 14 and 15) to move freely with respect to tubular member 25, including subs 25 a and 72. This causes the packer mandrel to move downwardly and causes rotatable lug 510, (
Once set, pump-out plug 38 can be blown out by shearing pins 39. With plug 38 removed, the well may begin producing through the lower end 29 of the packer. Those of skill in the art will recognize that the packer is designed to “avalanche” into the “set” state by sequencing the failure of the various shear pins in the manner described above. This can be accomplished by designing the shear pins to fail at increasing thresholds of force to effectuate the sequential nature of the setting process.
An illustration of the embodiment of
In addition, while the embodiment illustrated in
Once production from a current zone has been completed, or circulation is desired, an operator at the surface can apply a force axially along the tubing that causes the lugs 514 to move away from the “set” rest point 602 in guide 606 and to contact declined surface 609 of guide 606. The axially applied pushing force will cause the rotatable lug ring 510 to rotate, causing the lugs 514 to travel down the guide 606 and to reach vertical segment 630. There, the internal components of the packer can become substantially compressed and begin resisting any further travel of the packer mandrel in the down-hole direction such as at position 607. This is because the packer is still set and all of the anchoring and sealing components are maximally disposed against the inside surface of the casing C. A pulling force applied to the tubing T then causes the packer mandrel to pull up and causes the lugs 514 to travel to the top of vertical groove segment 630 until it contacts inclined surface 632. At this point, the lug ring 510 rotates and causes the lugs 514 to travel into position 604. This position places the packer into the “bypassed” state as will be described in more detail below. In the bypassed state, the mandrel has been pulled up, but not to the level at which the anchoring and sealing components will be released. The packer can therefore be bypassed during, for example, circulation can be advantageously conducted while the packer is still in a sealed and anchored state.
Once circulation is complete, the packer can be actuated again, as previously described, first with a force directed axially along the tubing T and down-hole in direction. This will bring the lugs 514 into the vertical segment 636 of guide 606. Pulling up-hole on the tubing T will cause the lugs 514 to move up and into the highest state position in the guide 606 at position 608. At this point, the body B will be completely extended toward the upper mandrel 31 and the spring element 55 will be substantially uncompressed. The force will be just sufficient to begin lifting the upper slips 57 from the top cones (not shown) and the internal upper and lower anchoring components, as well as the sealing elements will begin to release from their position against the inner wall of the casing C. The mechanisms by which the slips and sealing elements can be made to release are well-known to those of skill in the art. Once released, the packer can be lifted by the tubing T either completely from the hole, or to a new location that is higher than the previous location in the well-bore.
In the embodiment of guide 606 disclosed in
In the embodiment of guide 606 as illustrated in
When the packer is placed into the “bypassed” mode (i.e. the lugs 514 are actuated into position 604), the position of the rubber mandrel 26 is raised just enough to leave the packer in the set mode, but enough to cause bypass channels 410 to be raised and to come into communication with upper bypass channels 412. The proximate relationship of the bypass channels 410, 412 is illustrated in
Various embodiments of the rotating lug assembly (500,
Thus, a packer may be bypassed while still being set, may be released from its set position for repositioning movement or complete removal from the well-bore, and may be reset at a different position within the well-bore without the need to remove the packer and to rearm the packer for redeployment. Further, movement between these states of operation does not require any rotational forces to be applied and translated down the tubing, which is extremely difficult to accomplish reliably.
The foregoing is by way of example only, and changes can be made without departing from the scope of the invention which is more properly encompassed by the following claims.