US20110088891A1

US20110088891A1 - Ultra-short slip and packing element system

Info

Publication number: US20110088891A1
Application number: US12/925,141
Authority: US
Inventors: Gregg W. Stout
Original assignee: Individual
Current assignee: OILTOOL ENGINEERING SERVICES Inc
Priority date: 2009-10-15
Filing date: 2010-10-14
Publication date: 2011-04-21

Abstract

A packer device, with a commercial name called “Frac Disc” includes an interior packer mandrel and radially surrounding cone, slip and seal system that seals and engages the surrounding casing or other tubular member. The cones expand the slip system and the slips compress and expand the seal system, simultaneously. The slip system provides a means for supporting the seal system when pressure is applied from above or below the packer. The close proximity of the seal and slip system in combination with a separating packer body provides for a very short packer, or a “minimum material packer”, that offers lower cost, higher performance, and if required, faster mill-out.

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application is related in subject matter to application Ser. No. 12/653,155 filed Dec. 9, 2009 entitled “Subterranean Well Ultra-Short Slip and Packing Element System”, Gregg W. Stout, inventor.

BACKGROUND OF THE INVENTION

1. Field of the Invention
This invention relates to downhole tools for oil and gas wells and similar applications and more particularly to improved well packers.
2. Description of Prior Art
Well packers are used to form an annular barrier between well tubing or casing, to create fluid barriers, or plugs, within tubing or casing, or the control or direct fluid within tubing or casing. Packers may be used to protect tubulars' from well pressures, protect tubulars' from corrosive fluids or gases, provide zonal isolation, or direct acid and frac slurries into formations.
Typical well packers consist of a packer mandrel. Radially mounted on the packer mandrel is a locking or release mechanism, a packing element system with gage rings, and a slip/cone system. These packers tend to be 2 feet or longer depending on the packer design. The packing system is typically an elastomeric packing element with various types of backup devices such as gage rings. The packing system is typically expanded outward, between the gage rings to contact the I.D. of the casing by a longitudinal compression force generated by a setting tool or hydraulic piston. This force expands the elastomer and any backup material to create a seal between the packer mandrel and casing I.D. This same longitudinal force acts through the sealing system and acts on the slip system. The slip system is typically an upper and lower cone that slides under slip segments and expands the slip segments outwardly until teeth on the O.D. of a series of slip segments engage the I.D. of the casing. Teeth or buttons on the O.D. of the slip segments penetrate the I.D. of the casing, to secure the packer in the casing, so the packer will not move up or down as pressure above or below the packer is applied. A locking system typically secures the seal and slip systems in there outward engaged position in order to maintain compression force in the elastomer and, in turn, compression force on the slip system. Certain part configurations allow the locking mechanism to disengage to allow retrieval of the packer. The presence of the release mechanism usually classifies the packer as a “retrievable packer” and the absence of the release mechanism classifies the packer as a “permanent packer”.
Problems with prior art packers, in some cases, can be the excessive length of the packers since all of the above combined systems require length. It would advantageous to have a packer that is much shorter in that reduced material would certainly lower material and manufacturing costs. It would be advantageous to have a very short packer, so if packer removal is required, milling time would be greatly reduced. Some of the drillable frac plugs on the market are the Halliburton “Obsidian Frac Plug”, the Smith Services “D2 Bridge Plug”, the Owen Type “A” Frac Plug, the Weatherford “FracGuard”, and the BJ Services “Phython”. By comparison, all of these plug designs are very long in comparison to the current invention. Also, a very short packer would reduce cost and simplify the task of creating a “Pass-through” packer. “Pass-through” packers are used for intelligent well completions and allow the passage of, for example and not limited to, hydraulic control lines, fiber optic lines, and electrical lines.
Both retrievable and permanent packers are sometimes drilled or milled out of the casing. If the packer is being used as a “Frac Plug”, a Halliburton trademark, it is commonly milled out after the frac is completed. Typical packers, as described above, tend to have mill-out problems because the packer parts tend to spin within the engaged slips. The mill operation becomes very inefficient because the packer parts spin with the rotation of the milling tool. Some packer designs exist, for example the BJ Services U.S. Pat. No. 6,708,770, to reduce this spinning tendency. It would be advantageous to have a packer design that would offer alternative features to prevent spinning of parts while milling out. It would also be advantageous if this same design feature would provide a means to equally distribute the slip segments around the packer body to evenly distribute the load on the I.D. of the casing
Another problem is that the slip system is loaded through the packing element system without a fully supported packing element to prevent extrusion. Extrusion of the packing element system reduces stored energy in the slip system thus allowing the slip system to disengage, especially during pressure reversals, the casing and in turn cause packer slippage and seal failure. Typical packers have a seal system that has elastomers backed up by anti-extrusion devices and the anti-extrusion devices are backed up by gage rings. The gage rings typically have a built-in extrusion gap between the O.D. of the gage ring and the I.D. of the casing to provide running clearance for the packer. The built-in extrusion gap can be a problem and is commonly the primary mode of seal system failure at higher temperatures and pressures. This is because the elastomers and backup devices tend to move into the extrusion gaps. When this movement occurs, the stored energy is lost in the seal system and the seal engagement is jeopardized to the point of seal failure. It would be an advantage to remove the majority of the extrusion gap to prevent the seal from extruding or moving. Attempts have been made to reduce the extrusion gap by use of expandable-metal packers, for example, the Baker expandable packer U.S. Pat. No. 7,134,504 B2, US 2005/0217869, and U.S. Pat. No. 6,959,759 B2, or the Weatherford Lamb metal sealing element patent # US 2005/023100 A1.
Typical retrievable packers have slip systems that, when expanded, contact the I.D. of the casing at 45 degree or 60 degree increments around the I.D. of the casing. Each slip segment has a width and there is typically a space between each slip segment. The space between each slip segment creates a surface area where no slip tooth engagement occurs. The total slip contact with the I.D. of the casing may, for example, only be 50% of the surface area on the inside of the casing. If pressure is applied across the packer, the slips are driven outward into the casing. It is a problem in that due to the incremental contact on the I.D. of the casing, high non-uniform stresses in the casing wall can cause deformation or even failure of the casing wall. It would be very desirable to have a slip system that approaches a full 360 degree contact in the I.D. of the casing to minimize damage to the casing. Also, with slip engagement approaching 360 degrees, there is more slip tooth engagement due to increased radial surface contact area, thereby providing the opportunity to reduce length of the slip. Reduced length of the slip then reduces the overall length of the packer.
Typical permanent packers have slip systems that “break”. Slips that “break” approach the 360 degrees of contact. These slips are usually made by manufacturing a ring, cutting slots in the ring to create break points, and then treating the teeth on the O.D. of the ring for hardness purposes. When longitudinal load is applied to a cone, the cone moves under the slip ring and the ring tends to break at the slots to create slip segments. History has shown that the slip segments, break unevenly or don't break at all, break at different forces, and engage the I.D. of the casing in irregular patterns. These breaking problems can reduce the performance and reliability of the packer. It would be advantageous to have slips that approach the 360 degrees of contact and are not required to break, don't require a variable force to break, and evenly distribute themselves around the I.D. of the casing.

SUMMARY OF THE INVENTION

This invention provides an improved packer for cased wells or for a tubular member positioned inside of casing. The invention includes a number of features that overcome the above mentioned problems. A very short and simple packer design, with features that increase overall packer reliability, is created by effectively combining synergies of the cone, slip and seal elements to work in unison.
This packer can be set on standard electric wireline or with hydraulic setting tools conveyed on jointed pipe or coiled tubing.
The packer can be ready modified to serve several applications: 1) A hydraulic setting cylinder can be added so the packer can be run as part of the casing or tubing; 2) the packer can utilize a fixed frangible disc or a flapper device to serve as a bridge plug, frac plug, or a preferred title, a “Frac Disc”. The materials of the packer can be optimized to reduce mill-out time. Mill-out time is greatly reduced due to the very short length of the packer, around 4″, so expensive composite materials aren't necessarily required, 3) a seal bore can easily be attached to the packer body, 4) since the slip system creates a metal-to-metal interface with the I.D. of the casing, the packer can readily be adapted to a high pressure and temperature well environment, 5) the packer can address applications as simple as low cost plug and abandonment to highly complex applications in hostile environment wells, and 6) the packer, due to it's short length, is ideal for incorporating “control line pass-thru” for intelligent well completions.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic view of the present invention in the “running position”.

FIG. 2 is a schematic view of the present invention in the “set position”.

FIG. 3 is a cross-sectional end view of the packer mandrel and slip segments of the present invention in the fully expanded “set position”.

FIG. 4 shows three views of a slip segment that demonstrates an alternate to teeth.

FIG. 5 is a schematic view of the present invention, less the upper slip segments, in the “set position”.

FIG. 6 is a schematic of the present invention in the set position, further simplified with use of a packer cup rather than a compressed packing element.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

With reference to FIG. 1, a schematic of the present invention shows a 180 degree lengthwise cross-section of the packer. A mandrel 1 has a running thread 16 with a tension or shear parting point, or connection, 17 located below the running thread. The mandrel 1 may be shortened by more than one means at point 17, i.e., any type of shear, tension, or locking device that can be separated in a fashion to shorten the mandrel. A setting tool (not shown) is made up to running thread 16 in order to convey the packer into the well. A millable, frangible or disintegrable disc 14 is a fluid barrier and is part of mandrel 1 or can be attached and sealed to mandrel 1 in some fashion. Cone surface 3 is shown of the O.D. of mandrel 1. Slip segments 4 are expandable by sliding up coned surfaces at 2 and 3. Seal 5, commonly known as a packing element, is located between slip segments 4 and extrusion barriers 6. Seal 5 is compressed and expanded between slip segments 4.
The slip segments 4 have gaps between them that increase in size as the slip segments travel up the cones 2 and 3. The extrusion barriers 6 are segmented and attached to the slip segments 4 so that the gaps between the slip segments 4 are always bridged to prevent extrusion of Seal 5 as the slip segments 4 travel outward to meet the I.D. of the casing. As an alternative, the extrusion barriers 6 may be manufactured as part of the slip segments 4 so that the slip segments 4 themselves bridge the gaps between the slip segments as the slip segments expand outward. Shear pins 7 secure the slip segments 4 in the retracted position while the packer is run into the well.
The slip segments 4 have dovetail shaped runners 12 that slide in dovetail grooves 11 at cone surfaces 3 and 2. The runners 12 and grooves 11 may be of any profile and serve to retain the slip segments to both mandrel 1 and cone 8. Furthermore, the runners and grooves provide a means to equally space the slip segments 4 around the perimeter of the plug. Additionally, the runners and grooves provide a means to rotationally lock the slip segments 4, the mandrel 1, the cone 8, and the lock ring 9 together during milling operations. When the slip segments engage the inner casing wall, all components become rotationally locked together to help prevent spinning of the packer parts. The lock ring 9 threads are arranged in a manner so if right-hand rotation during milling rotates lock ring 9 to the right, the lock ring 9 rotates down thread 10, until it bottoms out at the end of thread 10. Once bottomed out, it 9 becomes rotationally locked to the mandrel 1, rotationally locked to the cone 8, which is rotationally locked to slip segment 4, while the teeth 19 of slip segment 4 are penetrated into the inner casing wall.
The slip segments 4 are positioned almost 360 degrees around the O.D. of the mandrel 1. Each slip segment has a series of teeth 19, or some other casing penetrating profiles such as hard inserts positioned on the O.D. of the slip segments as shown in FIG. 4.
In FIG. 4 the slip segment 4 is shown without teeth 19, but instead inserts or coating 25. Inserts or coating 25 may be ceramic balls, carbide balls, other geometries made of carbide or ceramic, proppant or sand, or other materials. Inserts or coatings 25 may be of any pattern on the O.D. of slip segment 4 and can be either a structured or random pattern. Sand or proppant, for example 20-40 or larger sizes, gravel pack sand or fracturing proppant made by Santrol or Hexion, or Carboceramics, can be used in or on the surface of slip segment 4 and can be attached to the surface with bonding materials or imbedded into the base material. Those in the gravel pack or frac pack business know that sand or proppant can stick downhole tools in the well, so it would be obvious that sand or proppant can be used on packer slips to hold tools in place relative to pipe or casing. The objective of using inserts or coatings 25 is to improve millability of the slip segments whereby the base material of the slip segments are easily machined and the inserts or coating 25 are hard enough to penetrate the casing I.D. Another objective to inserts or coating 25 is to minimize casing damage on the I.D. of the casing. Teeth marks from slips can increase susceptibility of the casing to corrosion and other failure mechanisms, especially in chrome based materials. The teeth, inserts, or coatings are sufficiently hard to penetrate the inside of the casing wall in order to grip the wall and prevent the packer from moving relative to the casing.
The slip segments have an O.D. that is machined to be almost equal to the I.D. of the casing. The slip segments are machined to minimize any gaps between the O.D. of the slip segments and the I.D. of the casing. Similarly, the angles on the I.D. of the slip segments are machined to almost match the O.D. of the cone surfaces 2 and 3 when the slip is fully expanded, in order to minimize gaps between the parts.
The cone 8 has a surface 2. The setting tool (not shown) pushes against surface 18 while pulling on threads 16 during the setting operation. The cone 8 has an internal thread that engages body lock ring 9. Body lock ring 9 can ratchet freely toward the slip segments 4 but engages and prevents movement away from the slip segments 4 by engaging the threads 10 on the top O.D. of the mandrel 1. Lugs 13 engage slots 15 if plugs stack during milling so the relative plugs don't spin during milling.
FIG. 2 shows the packer in the “set position”. In operation, also see FIG. 1, the setting tool (not shown) pushes on cone 8, at or near surface 18, and simultaneously pulls on thread 16 of mandrel 1. Cone 8 moves toward the slip segments 4 and seal 5 and in the process expands the slip segments 4 up cones 2 and 3 and compresses Seal 5 between slip segments 4 and extrusion barriers 6. Expansion of slip segments 4 and seal 5 continues until sufficient contact is made with the I.D. of the casing to achieve slip tooth 19 penetration in the inner wall of the casing.
At this point the teeth of the slip segments have nearly closed any seal 5 extrusion gaps between the O.D. of the slip segments 4 and the I.D. of the casing. Extrusion gaps have been minimized nearly 360 degrees around the packer. Additionally, slip load has been nearly evenly distributed around the I.D. of the casing to minimize distortion of the casing. Slip segment 4 distribution around the O.D. of the mandrel 1 is more uniform due to the rails 12 and grooves 11 keeping the slip segments equally spaced around the packer. Also, extrusion gaps have been closed where the I.D. of the slip segments contact the surfaces of the cones at 20 and 21. At this point, the extrusion gaps between the slip segments 4 are bridged with the extrusion barriers 6.
In the set position, FIG. 2, the lock ring 9 has traveled over thread 10. Thread 10 is designed to prevent reverse movement of lock ring 9, so that lock ring 9 holds cone 8 in a firm position under slip segment 4 while maintaining compression on seal 5 and keeping the slip segments 4 expanded into the I.D. of the casing. Once sufficient load is applied to cone 8 and thread 16 of mandrel 1, in order the drive teeth 19 into the I.D. of the casing and create an adequate seal with seal 5, the upper portion of mandrel 1 with thread 16, disconnects at point 17. The upper portion 22 of mandrel 1 comes out of the hole with the setting tool (not shown) and leaves a short section of mandrel 1 in the well.
Obviously, with the outer packer components 4,5, and 8 compressed closely together in combination with the short section of mandrel 1, the remaining portion of the plug is not only very short, but requires less material and length to mill out. The amount of material to mill out is minimized by taking as much material out of the packer components as possible, while still maintaining enough strength to hold well pressure differentials. For example, notice on mandrel 1 that the I.D. is bored out and at the lower end of mandrel 1 below the angled surface 3, material has been removed at location 23. As a result, the packer becomes a minimum material packer by removing material that is not needed to structurally maintain a pressure differential in the well bore. Also, to enhance millability of the packer, highly millable materials may be used, such as cast iron, or some other easily machinable material.
FIG. 3 shows a cross-sectional end view of the slip segments 4 in the expanded position. In the expanded and set position, gaps exist between each slip segment 4. An extrusion barrier 6 is attached to the slip segment 4 by an attachment means, such as drive-loc pins 24. The extrusion barriers 6 cover the gaps between each slip segment 4 to form a seal 5 backup surface to prevent seal 5 extrusion past the slip segments 4. Since the teeth 19 of the slip segments penetrate the inside of the casing wall, any extrusion gaps are closed off on the outside of the slip segments 4. Since the I.D. of the slip segments 4 closely matched the O.D. of the tapered surfaces 2 and 3, the extrusion gaps on the inside of the slip segments 4 are reduced to a minimum. This described geometry forms a near metal-to-metal seal backup system in the packer which is very desirable for high pressure and temperature well conditions.
FIG. 5 shows a similar packer, or Frac Disc, to FIG. 1. The FIG. 5 packer has the same features mentioned above except it does not have an upper set of slip segments 4, therefore, it would normally be used in situations where the packer is only required to hold pressure from above. This version would be a lower cost version than the one shown in FIG. 1 and cone 8 could be replaced with lock ring housing 26. In order to further simplify the packer design, the extrusion rings 6 could be eliminated and the packing element, or seal 5, could have a backup built into the seal system 5. In low pressure applications, or in cases where a positive seal with the I.D. of the casing is not needed, extrusion backup 6 and other backups in the packing element could be eliminated.
FIG. 6 shows a similar packer, or Frac Disc, to FIG. 1. The FIG. 6 packer has many of the same features mentioned above except it does not have the upper set of slip segments 4, or the packing element 5, or the anti-extrusion devices 6. The cone 8 is replaced with cup retainer 27 and the packing element 5 is replaced with the packing cup 28. Obviously the packing cup 28 only holds pressure from above generated from pressure operations occurring above the cup. This design allows opportunities to further minimize the material left in the well for milling out, for example, by eliminating the upper slip segments 4 and leaving a shorter mandrel 1 by moving separation point 17 downward.

Claims

1) A tool for sealing along a section of a wall of a subterranean well and carriable into said well on a conduit, and moveable from a run-in position to a set position by a setting tool manipulatable on said conduit, said well tool comprising:

(1) a plurality of anchoring elements shiftable from a first retracted position when said well tool is in a run-in position to a second expanded position after manipulation of said setting tool;

(2) seal means contained within said anchoring elements for sealing engagement along the wall of the well; and

(3) cone means activatably receiving said anchoring elements in a retracted position during the run-in position and, upon manipulation of said setting tool, urging said anchoring elements in a direction toward the wall of the subterranean well, said anchoring elements being shiftable to said second expanded position, said seal means sealingly engaging said well wall, and said cone means urging said anchoring means in a direction toward the wall of said well, all in concert and substantially concurrently with one another.