BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a cross-section view of a shell for completion equipment attached to tubing in a well showing one embodiment of laminate layers over the shell.
FIG. 2 is a cross-section view of a shell for completion equipment attached to tubing in a well showing another embodiment of laminate layers over the shell and a feed-through tube in the laminate layers.
FIG. 3 is a cross-section view of a tubular for completion equipment showing an embodiment of laminate layers over the tubular.
DETAILED DESCRIPTION
The description herein applies the invention primarily to a genre of well tools known as well completion tools or equipment. Generally, the invention applies to equipment in a well for which less wall thickness is needed. This would include: pressure-containing equipment in a well that must, because of its inherent design, have greater outside diameter than the tubing in a well if it is to maintain the same flow area as the tubing, and tubulars or connectors for tubulars that preferably are reduced in external diameter with the same internal diameter. This includes, but is not limited to, devices that are normally larger diameter than the tubing, such as subsurface safety valves, packers, flow control devices (e.g., sliding sleeves), tubing hangers, on-off attachments, and gas lift or instrument mandrels as well as equipment normally the same diameter as tubulars that would preferably be smaller in diameter, as least in some segments of a well, such as production tubing, liners, expansion joints and their connectors. One of ordinary skill in the art may immediately be able to apply this invention to other downhole devices, such as drilling equipment; any such uses of the present invention in wells is considered within the scope and spirit of the present invention.
FIG. 1 illustrates the invention by showing a shell for completion equipment having a diameter greater than the diameter of tubing in a well. Well 10 has been drilled in the earth, casing 12 has been placed in the well and cement 14 has been placed in the annulus outside the casing. The diameter of the hole of well 10 has been selected to allow an acceptable thickness of cement 14 and outside diameter of casing 12. The wall thickness of casing 12 has been determined by the design burst and collapse strength of the casing and the inside diameter of casing 12 has been determined by the diameter of tubing 15 that is needed in the well and the size of any pressure-containing completion equipment that may be placed in the tubing. FIG. 1 simply shows sub 16, which generically represents the shell for completion equipment that must have a larger outside diameter than the diameter of tubing 15 while maintaining a larger inside diameter for containing completion equipment. Upper flow wetted body 17 connects to lower flow wetted body 18, forming joint 19 of sub 16. Pressure seal 20 is provided. This seal may be all-metal, elastomeric, thermoplastic, spring energized, in a concentric configuration (shown) or it may be a face seal (not shown). Upper body half 17 and lower body half 18 may be separated at joint 19 to allow inclusion of the functional portion of completion equipment. The present invention may be employed when no joint 19 is required (not shown), a single joint 19 is required, or when a plurality of joints is required. Joint 19 may contain threads for connecting or be joined by welding, for examples.
After assembly of sub 16, first sleeve 22 is arranged to slide over and cover the larger outside diameter of sub 16. First sleeve 22 may be cold-worked in place. Depending on the service requirements, a preferred embodiment is pressed fit, whereby the outside diameters of upper flow wetted body 17 and lower flow wetted body 18 are larger than the inside diameter of first sleeve 22 and may be tapered. In this instance, first sleeve 22 is placed under a large axial load, which causes it to deform radially outward and expand over the larger outside diameters of upper flow wetted body 17 and lower flow wetted body 18. In an alternative procedure, first sleeve 22 is heated to cause expansion and placed over bodies 16 and 17 while hot. First sleeve 22 then acts as an elastic band, placing compressive stress on the upper flow wetted body 17 and the lower flow wetted body 18. First sleeve 22 may be a higher yield strength non-NACE material, or a material with a higher elastic modulus, such as titanium. The net effect is a higher burst pressure for the laminate body than it would be if the wall thickness were a homogenous NACE material. Sufficient internal pressure exerted inside the well tool places upper flow wetted body 17 and lower flow wetted body 18 in tension in the radial direction, which is counteracted by the compressive forces exerted by first sleeve 22. First nut 24 may be threaded onto first sleeve 22 to retain it. In this configuration, tubing tensile forces are borne by first nut 24, but if upper flow wetted body 17 and lower flow wetted body 18 are threaded together, tubing tensile forces would be primarily borne there. The additional laminate layers, if confined in the axial direction so as to assume an axial load, are intended to increase the axial strength within the tensile limits of the outer layers. If ceramic or other high-strength fibers are used in additional layers, this increase could be significant.
In the transitional section where flow area is changing, wall thickness of bodies 17 and 18 may be adjusted in response to stress analysis, which may be performed using well-known finite element procedures, and which may include the effect of outer laminate layers. Such analyses may be substantiated by well-known techniques using strain gauges.
Second sleeve 26 (or subsequent sleeves), having second nut 28, may also be used to further strengthen the assembly by adding laminate layers, each with its own beneficial material properties.
First sleeve 22 may be a series of rings arranged longitudinally along the body that would yield the same effect on burst strength of the body. Additionally, the first sleeve may take the form of a helix or helical strip wrapped around upper flow wetted body 17 and lower flow wetted body 18. These and other uses of the lamination effect by one of normal skill in the art should be considered within the scope and spirit of the present invention.
In operation, the composite wall thickness of upper flow wetted body 17 and lower flow wetted body 18, first sleeve 22 and second sleeve 26 or any subsequent sleeves is thinner than if the design engineer chose a homogenous commercially available NACE material. This allows a greater flow area in any given well (or casing) size.
FIG. 2 depicts an alternate embodiment of the invention disclosed herein. Sub 30 is attached on both upper and lower ends to production tubing 15. Sub 30 includes larger internal diameter for completion equipment, as described and shown in FIG. 1. Upper flow wetted body 34 connects to a lower flow wetted body 36, forming joint 38. Pressure is contained by seal 39. This seal may be all-metal, elastomeric, thermoplastic, spring energized, in a concentric configuration (shown) or it may be a face seal (not shown). Upper and lower body halves are depicted, so as to facilitate or incorporate the inclusion of the functional portion of completion equipment, be it a packer, subsurface safety valve, or other equipment. The present invention may be employed when no joint 38 is required (not shown), a single joint 38 is required, or if a plurality of joints such as joint 38 are required.
After assembly of sub 30, wire wraps 40 may be wound over sub 30. Depicted in FIG. 2 is round wire, but square wire may also be used, and in many instances, may be preferable. Wire may have much higher yield strength than wrought material. Higher strength material alone adds to the allowable stress the body could withstand. There is another significant advantage to the use of wire. The wire may be wrapped under tension, preferably at a tension that is close to the yield strength of the wire. Multiple wraps of wire around the upper and lower body halves of sub 30 may put a very high compressive force on sub 30. Sufficient internal pressure exerted inside the well tool may place upper flow wetted body 34 and lower flow wetted body 36 in tension in the circumferential direction, which is counteracted by the compressive forces exerted by the first sleeve. In another embodiment, a composite material may be formed. A metal matrix composite may be utilized to greatly increase burst resistance of relatively thin shells. Composite may be formed of a ceramic fiber or monofilament that is first wound over the flow wetted body to have a structure as shown in FIG. 2, where the fiber is now illustrated at 40. Molten metal 40A may then be injected into a mold to form a metal matrix over the ceramic fiber. This procedure can result in a composite material that is many times stronger than the NACE-approved material of the flow wetted body. The assembly can then be post-cast heat treated to return the body to NACE specifications. Ceramic fiber is available from 3M Company of St. Paul, Minn. and other sources,
These embodiments mean that a very high internal pressure may be applied to counteract the “pre-loaded” collapse force induced by the wire (or ceramic) wraps, to take the body to a neutrally stressed state. The result is a much higher internal pressure (or burst pressure) can be born by the well apparatus of the present invention before permanent deformation or failure due to overstress.
Second sleeve 50 (FIG. 2) (or subsequent sleeves) may also be used to further strengthen the assembly by adding laminated layers, each with its own beneficial material properties. Second nut 52 may be threaded into second sleeve 50 to retain it. In this configuration, tubing tensile forces may be borne by second nut 52, but if upper flow wetted body 34 and lower flow wetted body 36 are threaded together, tubing tensile forces would be primarily borne there.
The shell that encloses well completion equipment normally has a larger diameter than the tubing that conveys it into the well. FIG. 1 and FIG. 2 show this relationship. Annulus 60 is formed outside the shell of completion equipment and any laminate layers on the shell and inside the casing. Often in multilateral wells umbilicals or control lines (not shown) need to pass through annulus 60. As wall thickness requirements increase with pressure and temperature, annulus 60 may become too small for well umbilicals or control lines to pass, even with a laminate structure as disclosed herein. In another embodiment (FIG. 2), wherein a hollow cylinder or multiple wraps of wire or fiber are used, small diameter “feed through” tubing 62 may be adapted to the assembly and placed in a rounded groove in sub 30 or placed adjacent sub 30 prior to beginning the wrapping operation. This would allow feed through 62 to be directed through the body with minimal effect on the pressure-retaining properties of the apparatus.
When smaller outside diameter of a tubular or a connector for a tubular is needed without decreasing inside diameter, the methods described above may be employed. FIG. 3 illustrates the application of first laminate layer 72 and second laminate layer 74 to tubular 70, which is illustrated with threads for connecting to well tubing 75. Tubular 70 may be production tubing, a liner, an expansion joint and the connectors for any of these, for example. Various laminate layers as described above may be similarly applied to tubular 70 or to a connector for tubular 70. A feed-through tube such as shown in FIG. 2 may be included in a groove in tubular 70 and under first laminate layer 72.
Although the present invention has been described with reference to specific details, it is not intended that such details should be regarded as limitations on the scope of the invention, except as and to the extent that they are included in the accompanying claims.