US20080035328A1 - Laminate pressure containing body for a well tool - Google Patents
Laminate pressure containing body for a well tool Download PDFInfo
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- US20080035328A1 US20080035328A1 US11/501,414 US50141406A US2008035328A1 US 20080035328 A1 US20080035328 A1 US 20080035328A1 US 50141406 A US50141406 A US 50141406A US 2008035328 A1 US2008035328 A1 US 2008035328A1
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- laminate layer
- pressure
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- 238000000034 method Methods 0.000 claims description 25
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- 239000011156 metal matrix composite Substances 0.000 claims description 8
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- 239000002184 metal Substances 0.000 claims description 6
- 229910010293 ceramic material Inorganic materials 0.000 claims 2
- 238000010438 heat treatment Methods 0.000 claims 1
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- 239000002131 composite material Substances 0.000 description 4
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- 230000009286 beneficial effect Effects 0.000 description 2
- 229910002092 carbon dioxide Inorganic materials 0.000 description 2
- 239000001569 carbon dioxide Substances 0.000 description 2
- 239000004568 cement Substances 0.000 description 2
- -1 elastomeric Substances 0.000 description 2
- 239000003208 petroleum Substances 0.000 description 2
- 229920001169 thermoplastic Polymers 0.000 description 2
- 239000004416 thermosoftening plastic Substances 0.000 description 2
- 230000035899 viability Effects 0.000 description 2
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 description 1
- RTAQQCXQSZGOHL-UHFFFAOYSA-N Titanium Chemical compound [Ti] RTAQQCXQSZGOHL-UHFFFAOYSA-N 0.000 description 1
- 230000002411 adverse Effects 0.000 description 1
- 230000015572 biosynthetic process Effects 0.000 description 1
- 238000005336 cracking Methods 0.000 description 1
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- 229930195733 hydrocarbon Natural products 0.000 description 1
- 150000002430 hydrocarbons Chemical class 0.000 description 1
- 238000003475 lamination Methods 0.000 description 1
- 239000011159 matrix material Substances 0.000 description 1
- 230000003938 response to stress Effects 0.000 description 1
- 238000005728 strengthening Methods 0.000 description 1
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- 238000010618 wire wrap Methods 0.000 description 1
Images
Classifications
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/006—Accessories for drilling pipes, e.g. cleaners
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/02—Couplings; joints
- E21B17/04—Couplings; joints between rod or the like and bit or between rod and rod or the like
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y10—TECHNICAL SUBJECTS COVERED BY FORMER USPC
- Y10T—TECHNICAL SUBJECTS COVERED BY FORMER US CLASSIFICATION
- Y10T29/00—Metal working
- Y10T29/49—Method of mechanical manufacture
- Y10T29/49826—Assembling or joining
- Y10T29/49885—Assembling or joining with coating before or during assembling
Definitions
- This invention pertains to apparatus for use in wells. More particularly, pressure-containing apparatus is provided for use in high-pressure, high-temperature wells where wall thickness of apparatus is to be minimized and material selection is limited by well conditions.
- HPHT High-Pressure and High-Temperature wells
- Well completion equipment 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.
- 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.
- NACE National Association of Corrosion Engineers
- Apparatus for allowing greater flow area in wells by strengthening pressure-containing shells or tubulars that are a part of completion equipment in the wells.
- Laminate layers made of materials having higher yield value than equipment that comes in contact with well fluids are added to completion equipment.
- the layers may be formed of cylinders, wound wire or other forms of materials.
- Metal matrix composite materials may be used.
- 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.
- the description herein applies the invention primarily to a genre of well tools known as well completion tools or equipment.
- 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.
- 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.
- 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
- 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 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
- 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.
- 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.
- 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.
- 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 .
- 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.
- 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.
- 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.
- 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.
- 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.
- 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 .
- 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 40 A may then be injected into a mold to form a metal matrix over the ceramic fiber.
- 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.
- 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.
- 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.
- 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 .
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- Engineering & Computer Science (AREA)
- Geology (AREA)
- Life Sciences & Earth Sciences (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Mechanical Engineering (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Laminated Bodies (AREA)
- Physical Or Chemical Processes And Apparatus (AREA)
- Rigid Pipes And Flexible Pipes (AREA)
Abstract
Description
- 1. Field of the Invention
- This invention pertains to apparatus for use in wells. More particularly, pressure-containing apparatus is provided for use in high-pressure, high-temperature wells where wall thickness of apparatus is to be minimized and material selection is limited by well conditions.
- 2. Description of Related Art
- With energy prices at all time highs, companies involved in the discovery and production of hydrocarbons are pursuing deeper offshore oil and gas plays. As well depths increase, well architecture becomes more challenging. Geologists, geophysicists and petroleum engineers understand that as well depths increase, so does formation pressure and temperature. It is estimated that pressures of 30,000 psi and 500 deg F. and beyond may become commonplace in future wells. The industry acronym for High-Pressure and High-Temperature wells is HPHT. As HPHT conditions present themselves in deep wells, the equipment needed to safely complete and produce HPHT wells must be developed to withstand safely the rigors of these extreme conditions.
- Industry is developing methods and materials to drill the HPHT wells safely, but technology gaps in equipment placed in the wells for producing the wells, called “well completion equipment,” also must be addressed. 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. Several papers have been published recently addressing and discussing “gaps” in current technology (for examples, “Ultra Deep HPHT Completions: Classification, Design Methodologies and Technical Challenges, OTC 17927, Offshore Technology Conference, Houston, Tex., May. 2006; “HPHT Completion Challenges,” SPE 97589, Society of Pet. Engrs., May, 2005).
- Substances present in fluids produced from HPHT wells are often detrimental to materials that form tubulars and well completion equipment. One of the worst substances is hydrogen sulfide (H2S), which can cause stress corrosion cracking, especially of materials that have high yield strength. Another substance that is often present in HPHT wells is carbon dioxide (CO2), which can cause weight loss corrosion. The National Association of Corrosion Engineers (NACE) has developed guidelines for selecting materials that can be used in the presence of adverse wellbore chemistry. Most often these “NACE materials” fall in the mid-range of material hardness and yield strength.
- Additionally, there is recognition among mechanical engineers that guidelines and practices for the safe design of equipment at 15,000 psi and 300° F. are vastly different for the requirements of 30,000 psi and 500° F. As an outgrowth of this knowledge, The American Petroleum Institute (API) is in the process of adopting the requirements of ASME Section VIII Division III into the design requirements of downhole equipment. Section VIII Division III practice requires that Ultra High Pressure Vessels have the allowable stress on materials de-rated as a result of temperature and that a fracture analysis be performed as a part of the design realization process. The simply stated result is that the wall thickness of pressure-containing devices must be very thick if homogeneous NACE materials are used in downhole pressure-containing vessels.
- When drilling a well, costs are much higher as depth increases. A similar relationship exists with the diameter of the hole being drilled. Larger diameter, deeper holes become prohibitively expensive unless production flow area (inside diameter of the production tubing) is maximized. Operators want the largest possible flow area in the smallest possible hole. The economic viability of a project is determined by the flow rate from the well. For deep, expensive wells, the production flow area (diameter of the tubing) must often be 5½-in, 7-in, or in some cases 9⅝-in. The design of the well must have its genesis at the inside diameter of the production tubing and work outward to determine what diameter hole must be drilled.
- These factors serve to work against each other in the following summarized manner. Wellbores must be deeper to reach pay zones. Production flow areas must be maximized and the hole diameter must be minimized for the well to be economic. The cost of drilling a well is much more expensive as the diameter and depth each increase. Materials must be tailored to the environment, but use of the strongest materials may be inadvisable or prohibited due to NACE requirements to avoid chemical attack. Design practices require thicker and thicker walls to accommodate these factors. Smaller drilled holes, bigger flowing bores, and thicker wall requirements are conflicting requirements.
- What is needed is the development of a pressure-containing body that minimizes wall thickness, uses NACE materials where exposed to production fluids, fits in the smallest possible drilled and cased hole, and yields the largest possible flow area for the well. Use of such a body or device can significantly improve the economic viability of new wells.
- Apparatus is provided for allowing greater flow area in wells by strengthening pressure-containing shells or tubulars that are a part of completion equipment in the wells. Laminate layers made of materials having higher yield value than equipment that comes in contact with well fluids are added to completion equipment. The layers may be formed of cylinders, wound wire or other forms of materials. Metal matrix composite materials may be used.
-
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. - 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 andcement 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 ofcement 14 and outside diameter ofcasing 12. The wall thickness ofcasing 12 has been determined by the design burst and collapse strength of the casing and the inside diameter ofcasing 12 has been determined by the diameter oftubing 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 showssub 16, which generically represents the shell for completion equipment that must have a larger outside diameter than the diameter oftubing 15 while maintaining a larger inside diameter for containing completion equipment. Upper flow wettedbody 17 connects to lower flow wettedbody 18, formingjoint 19 ofsub 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 andlower 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 ofsub 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 wettedbody 17 and lower flow wettedbody 18 are larger than the inside diameter offirst 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 wettedbody 17 and lower flow wettedbody 18. In an alternative procedure,first sleeve 22 is heated to cause expansion and placed overbodies First sleeve 22 then acts as an elastic band, placing compressive stress on the upper flow wettedbody 17 and the lower flow wettedbody 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 wettedbody 17 and lower flow wettedbody 18 in tension in the radial direction, which is counteracted by the compressive forces exerted byfirst sleeve 22.First nut 24 may be threaded ontofirst sleeve 22 to retain it. In this configuration, tubing tensile forces are borne byfirst nut 24, but if upper flow wettedbody 17 and lower flow wettedbody 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 - 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 wettedbody 17 and lower flow wettedbody 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 wettedbody 18,first sleeve 22 andsecond 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 toproduction tubing 15.Sub 30 includes larger internal diameter for completion equipment, as described and shown inFIG. 1 . Upper flow wettedbody 34 connects to a lower flow wettedbody 36, forming joint 38. Pressure is contained byseal 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 oversub 30. Depicted inFIG. 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 ofsub 30 may put a very high compressive force onsub 30. Sufficient internal pressure exerted inside the well tool may place upper flow wettedbody 34 and lower flow wettedbody 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 inFIG. 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 intosecond sleeve 50 to retain it. In this configuration, tubing tensile forces may be borne bysecond nut 52, but if upper flow wettedbody 34 and lower flow wettedbody 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 andFIG. 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 throughannulus 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 insub 30 or placedadjacent 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 offirst laminate layer 72 andsecond laminate layer 74 to tubular 70, which is illustrated with threads for connecting towell 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 fortubular 70. A feed-through tube such as shown inFIG. 2 may be included in a groove intubular 70 and underfirst 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.
Claims (37)
Priority Applications (8)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US11/501,414 US20080035328A1 (en) | 2006-08-09 | 2006-08-09 | Laminate pressure containing body for a well tool |
EP07800038A EP2049761A2 (en) | 2006-08-09 | 2007-08-07 | Laminate pressure-containing body for a well tool |
AU2007284107A AU2007284107A1 (en) | 2006-08-09 | 2007-08-07 | Laminate pressure-containing body for a well tool |
MX2009001401A MX2009001401A (en) | 2006-08-09 | 2007-08-07 | Laminate pressure-containing body for a well tool. |
PCT/US2007/075354 WO2008021826A2 (en) | 2006-08-09 | 2007-08-07 | Laminate pressure-containing body for a well tool |
CA2660306A CA2660306C (en) | 2006-08-09 | 2007-08-07 | Laminate pressure-containing body for a well tool |
NO20090408A NO20090408L (en) | 2006-08-09 | 2009-01-28 | Laminated pressure-containing body for a well tool |
US12/572,653 US7980303B2 (en) | 2006-08-09 | 2009-10-02 | Laminate pressure containing body for a well tool |
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US11/501,414 US20080035328A1 (en) | 2006-08-09 | 2006-08-09 | Laminate pressure containing body for a well tool |
Related Child Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US12/572,653 Continuation US7980303B2 (en) | 2006-08-09 | 2009-10-02 | Laminate pressure containing body for a well tool |
Publications (1)
Publication Number | Publication Date |
---|---|
US20080035328A1 true US20080035328A1 (en) | 2008-02-14 |
Family
ID=39049471
Family Applications (2)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US11/501,414 Abandoned US20080035328A1 (en) | 2006-08-09 | 2006-08-09 | Laminate pressure containing body for a well tool |
US12/572,653 Active US7980303B2 (en) | 2006-08-09 | 2009-10-02 | Laminate pressure containing body for a well tool |
Family Applications After (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US12/572,653 Active US7980303B2 (en) | 2006-08-09 | 2009-10-02 | Laminate pressure containing body for a well tool |
Country Status (7)
Country | Link |
---|---|
US (2) | US20080035328A1 (en) |
EP (1) | EP2049761A2 (en) |
AU (1) | AU2007284107A1 (en) |
CA (1) | CA2660306C (en) |
MX (1) | MX2009001401A (en) |
NO (1) | NO20090408L (en) |
WO (1) | WO2008021826A2 (en) |
Cited By (8)
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US20120031624A1 (en) * | 2010-08-06 | 2012-02-09 | Schlumberger Technology Corporation | Flow tube for use in subsurface valves |
US20130098687A1 (en) * | 2011-10-21 | 2013-04-25 | Ghazi J. Hashem | Wear and buckling resistant drill pipe |
WO2014140618A1 (en) * | 2013-03-15 | 2014-09-18 | Petrowell Limited | Heat treat production fixture |
US20150047856A1 (en) * | 2013-08-17 | 2015-02-19 | Antelope Oil Tool & Mfg. Co., Llc | Wrap-around stop collar and method of forming |
US9085942B2 (en) | 2011-10-21 | 2015-07-21 | Weatherford Technology Holdings, Llc | Repaired wear and buckle resistant drill pipe and related methods |
WO2015156772A1 (en) * | 2014-04-08 | 2015-10-15 | Halliburton Energy Services, Inc. | Flexible tool housing |
US20160215574A1 (en) * | 2014-07-16 | 2016-07-28 | Daqing First Technology Development Limited Company | A downhole-started self-locking casing centralizer |
CN106593315A (en) * | 2016-12-28 | 2017-04-26 | 中国石油天然气集团公司 | Combined sleeve with sleeve-deformation-resistant function |
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US9623479B2 (en) | 2010-10-15 | 2017-04-18 | Baker Hughes Incorporated | Apparatus including metal foam and methods for using same downhole |
US10704361B2 (en) | 2012-04-27 | 2020-07-07 | Tejas Research & Engineering, Llc | Method and apparatus for injecting fluid into spaced injection zones in an oil/gas well |
US9523260B2 (en) | 2012-04-27 | 2016-12-20 | Tejas Research & Engineering, Llc | Dual barrier injection valve |
US9334709B2 (en) | 2012-04-27 | 2016-05-10 | Tejas Research & Engineering, Llc | Tubing retrievable injection valve assembly |
WO2016065235A1 (en) * | 2014-10-24 | 2016-04-28 | Schlumberger Canada Limited | Eutectic feedthrough mandrel |
CA2997177C (en) * | 2015-11-02 | 2020-01-07 | Halliburton Energy Services, Inc. | High-resolution-molded mandrel |
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US1959367A (en) * | 1932-09-24 | 1934-05-22 | Charles B Kennedye | Well casing |
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US7082998B2 (en) * | 2003-07-30 | 2006-08-01 | Halliburton Energy Services, Inc. | Systems and methods for placing a braided, tubular sleeve in a well bore |
US20080115931A1 (en) * | 2004-08-13 | 2008-05-22 | Enventure Global Technology, Llc | Expandable Tubular |
-
2006
- 2006-08-09 US US11/501,414 patent/US20080035328A1/en not_active Abandoned
-
2007
- 2007-08-07 CA CA2660306A patent/CA2660306C/en not_active Expired - Fee Related
- 2007-08-07 AU AU2007284107A patent/AU2007284107A1/en not_active Abandoned
- 2007-08-07 EP EP07800038A patent/EP2049761A2/en not_active Withdrawn
- 2007-08-07 MX MX2009001401A patent/MX2009001401A/en active IP Right Grant
- 2007-08-07 WO PCT/US2007/075354 patent/WO2008021826A2/en active Application Filing
-
2009
- 2009-01-28 NO NO20090408A patent/NO20090408L/en not_active Application Discontinuation
- 2009-10-02 US US12/572,653 patent/US7980303B2/en active Active
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US1959367A (en) * | 1932-09-24 | 1934-05-22 | Charles B Kennedye | Well casing |
US2592854A (en) * | 1946-02-08 | 1952-04-15 | Reed Roller Bit Co | Tool joint wear sleeve |
US3220437A (en) * | 1963-03-28 | 1965-11-30 | Zapata Lining Corp | Blast coating and method of applying the same to tubing |
US3208530A (en) * | 1964-09-14 | 1965-09-28 | Exxon Production Research Co | Apparatus for setting bridge plugs |
US4648444A (en) * | 1985-04-17 | 1987-03-10 | Halliburton Company | Tensile ring cable head assembly |
US5988300A (en) * | 1995-12-05 | 1999-11-23 | Lwt Instruments, Inc. | Composite material structures having reduced signal attenuation |
US6065540A (en) * | 1996-01-29 | 2000-05-23 | Schlumberger Technology Corporation | Composite coiled tubing apparatus and methods |
US6594608B1 (en) * | 1999-10-25 | 2003-07-15 | Institut Francais Du Petrole | Method for determining a flexible pipe structure |
US20060124308A1 (en) * | 2002-05-16 | 2006-06-15 | Wagon Trail Ventures, Inc. | Downhole oilfield tubulars |
US7080686B2 (en) * | 2002-11-13 | 2006-07-25 | David Beckhardt | Devices and methods for extraction, transportation and/or release of material |
US7082998B2 (en) * | 2003-07-30 | 2006-08-01 | Halliburton Energy Services, Inc. | Systems and methods for placing a braided, tubular sleeve in a well bore |
US20050173121A1 (en) * | 2004-02-06 | 2005-08-11 | Steele David J. | Multi-layered wellbore junction |
US20080115931A1 (en) * | 2004-08-13 | 2008-05-22 | Enventure Global Technology, Llc | Expandable Tubular |
Cited By (14)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20120031624A1 (en) * | 2010-08-06 | 2012-02-09 | Schlumberger Technology Corporation | Flow tube for use in subsurface valves |
US20130098687A1 (en) * | 2011-10-21 | 2013-04-25 | Ghazi J. Hashem | Wear and buckling resistant drill pipe |
US9085942B2 (en) | 2011-10-21 | 2015-07-21 | Weatherford Technology Holdings, Llc | Repaired wear and buckle resistant drill pipe and related methods |
US9091124B2 (en) * | 2011-10-21 | 2015-07-28 | Weatherford Technology Holdings, Llc | Wear and buckling resistant drill pipe |
WO2014140618A1 (en) * | 2013-03-15 | 2014-09-18 | Petrowell Limited | Heat treat production fixture |
US10155999B2 (en) | 2013-03-15 | 2018-12-18 | Weatherford Technology Holdings, Llc | Heat treat production fixture |
US9765576B2 (en) * | 2013-08-17 | 2017-09-19 | Antelope Oil Tool & Mfg. Co. | Wrap-around stop collar and method of forming |
US20150047856A1 (en) * | 2013-08-17 | 2015-02-19 | Antelope Oil Tool & Mfg. Co., Llc | Wrap-around stop collar and method of forming |
WO2015156772A1 (en) * | 2014-04-08 | 2015-10-15 | Halliburton Energy Services, Inc. | Flexible tool housing |
GB2538436A (en) * | 2014-04-08 | 2016-11-16 | Halliburton Energy Services Inc | Flexible tool housing |
CN106062302A (en) * | 2014-04-08 | 2016-10-26 | 哈利伯顿能源服务公司 | Flexible tool housing |
US10151154B2 (en) | 2014-04-08 | 2018-12-11 | Halliburton Energy Services, Inc. | Flexible tool housing |
US20160215574A1 (en) * | 2014-07-16 | 2016-07-28 | Daqing First Technology Development Limited Company | A downhole-started self-locking casing centralizer |
CN106593315A (en) * | 2016-12-28 | 2017-04-26 | 中国石油天然气集团公司 | Combined sleeve with sleeve-deformation-resistant function |
Also Published As
Publication number | Publication date |
---|---|
MX2009001401A (en) | 2009-06-26 |
CA2660306A1 (en) | 2008-02-21 |
WO2008021826A3 (en) | 2008-12-18 |
EP2049761A2 (en) | 2009-04-22 |
NO20090408L (en) | 2009-03-03 |
AU2007284107A1 (en) | 2008-02-21 |
US20100018700A1 (en) | 2010-01-28 |
WO2008021826A2 (en) | 2008-02-21 |
US7980303B2 (en) | 2011-07-19 |
CA2660306C (en) | 2012-07-17 |
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