TUBING FOR TRANSPORTING A FLUID, AND METHODS OF USING THE SAME

Abstract

This invention relates generally to tubing for transporting a fluid, for downhole applications, connected to a production packer and/or a downhole anchor and more particularly to tubing 10 for transporting a fluid, connected to a coupling member, a production or injection installation, a method of placing production and/or injection tubing in a subsurface well, a method of manufacturing tubing, and a method of retrieving a subsurface fluid, such as oil or gas, from a well

Claims

1. Tubing for transporting a fluid, the tubing comprising; an inner liner; and an outer wall, wherein the tubing is connected to a production packer and/or a downhole anchor.

2. The tubing according to claim 1, wherein the inner liner comprises an isotropic material.

3. The tubing according to any of the preceding claims, wherein the inner liner has a rupture strain rate of more than about 0.5%, preferably of more than about 5%, more preferably of more than about 20%.

4. The tubing according to any of the preceding claims, wherein the inner liner comprises metal and/or metal alloys.

5. The tubing according to claim 4, wherein the inner liner comprises one or more of steel, nickel alloys, nickel chrome, nickel copper alloys, titanium, titanium alloys, preferably wherein said steel is selected from the group consisting of non-sour service carbon steel, sour service carbon steel, martensitic stainless steel, martensitic ferritic stainless steel, and duplex stainless steel.

6. The tubing according to any of the preceding claims, wherein the inner liner comprises a polymer material, preferably wherein the inner liner comprises one or more of polyether ether ketone, polyetherketoneketone, polyvinylidene fluoride, ethylene chlorotrifluoroethylene, Polyamide 11, and polycaprolactam.

7. The tubing according to claim 6, wherein the polymer material has a glass transition temperature of at least about 120° C., preferably of at least about 160° C., more preferably of at least about 180° C., still more preferably of at least about 200° C., most preferably of at least about 220° C., measured by differential scanning calorimetry (DSC).

8. The tubing according to any preceding claim, wherein the tubing has a density that of lower than about 3000 kg/m.sup.3 at 25° C., preferably lower than about 2000 kg/m.sup.3 at 25° C., more preferably lower than about 1500 kg/m.sup.3 at 25° C., still more preferably lower than about 1200 kg/m.sup.3 at 25° C.

9. The tubing according to any preceding claim, wherein the outer wall comprises a fiber-reinforced material.

10. The tubing according to claim 9, wherein the outer wall comprises fibers within a thermoset polymer matrix.

11. The tubing according to claim 10, wherein the thermoset polymer matrix material has a glass transition temperature of at least about 120° C., preferably of at least about 160° C., more preferably of at least about 180° C., still more preferably of at least about 200° C., most preferably of at least about 220° C.

12. The tubing according to any of claims 9 to 11, wherein the fibers of the fiber-reinforced material comprise one or more of carbon fiber, glass fiber, aramid fiber, and/or basalt fiber.

13. The tubing according to any of claims 9 to 12, wherein the fiber-reinforced material comprises pitch based carbon fiber and/or pan based carbon fiber.

14. The tubing according to any of claims 9 to 13, wherein the fiber-reinforced material has an ultimate tensile strength of between 2500 and 8000 MPa, preferably of between 5000 and 8000 MPa, more preferably of between 7000 and 8000 MPa.

15. The tubing according to any of claims 9 to 14, wherein the fiber-reinforced material has a modulus of elasticity of between 60 and 590 GPa, preferably of between 200 and 400 GPa, more preferably of between 200 and 250 GPa.

16. The tubing according to any of claims 9 to 15, wherein the fiber-reinforced material comprises PX35 and/or T700 carbon fiber.

17. The tubing according to any of claims 10 to 16, wherein the thermoset polymer matrix comprises at least an epoxy resin.

18. The tubing according to any of claims 10 to 17, wherein the thermoset polymer matrix comprises one or more of polyester, epoxy, dicyclopentadiene, polyurethane, phenolic polymers, bismaleimide resin, and/or phthalonitrile.

19. The tubing according to any of the preceding claims, wherein the tubing has an uninterrupted length of greater than 15 meters, preferably of greater than 30 meters, more preferably of greater than 50 meters, still more preferably of greater than 100 meters.

20. The tubing according to any of the preceding claims, wherein the tubing has an outer diameter of less than about 200 millimeters, preferably of less than about 160 millimeters, more preferably of less than about 140 millimeters.

21. The tubing according to any of the preceding claims, wherein the tubing has an inner diameter of more than about 45 millimeters, preferably of more than about 80 millimeters, more preferably of more than about 125 millimeters, still more preferably of more than about 150 millimeters.

22. The tubing according to any of the preceding claims, wherein the tubing has a wall thickness of less than about 60 millimeters, preferably of less than about 40 millimeters, more preferably of less than about 30 millimeters, still more preferably less than about 20 millimeters, and most preferably of less than about 10 millimeters.

23. The tubing according to any of the preceding claims, wherein the tubing comprises a terminal coupling member, wherein the outer wall comprises a fiber-reinforced material; and wherein the fiber-reinforced material binds to the coupling member, thereby joining the coupling member to the tubing.

24. The tubing according to any of the preceding claims, wherein the tubing comprises a tubing opening, wherein the tubing opening is coupled to an assembly of valves, and/or spools, and/or fittings, such as a Christmas tree.

25. A system comprising the tubing according to any of claims 1-24 and connected to a production packer and/or a downhole anchor.

26. Tubing for transporting a fluid at a production and/or injection well, wherein the tubing comprises: an outer wall comprising fibers; and an inner liner, wherein the tubing comprises a terminal coupling member, and wherein the fibers extend over the coupling member, thereby joining said tubing to said coupling member.

27. The tubing according to claim 26, wherein outer, radially extending projections are provided on the coupling member, wherein the fibers are disposed between the projections.

28. The tubing according to claim 27, wherein the projections are conical or rounded.

29. The tubing according to claims 27 or 28, wherein the projections comprise a cylindrical stem.

30. The tubing according to any of claims 26 to 29, wherein the projections have a maximum diameter of between 1 mm and 15 mm, preferably between 2 mm and 10 mm, more preferably between 3 mm and 8 mm, most preferably between 4 and 6 mm.

31. The tubing according to any of claims 26 to 30, wherein the projections are distributed over the coupling member, in the form of a regular pattern and/or with a density gradient and/or with a constant density.

32. The tubing according to any of claims 26 to 31, wherein the ratio of the distance between two projections to the diameter of the projections is greater than 1, preferably greater than 3.

33. The tubing according to any of claims 31 to 32, wherein the density of the projections is at most 1 projection per square centimeter, preferably per 2 square centimeter, more preferably per 5 square centimeter.

34. The tubing according to any of claims 26 to 33, wherein the inner liner comprises an isotropic material.

35. The tubing according to any of claims 26 to 34, wherein the inner liner has a rupture strain rate of more than about 0.5%, preferably of more than about 5%, more preferably of more than about 20%.

36. The tubing according to any of claims 26 to 35, wherein the inner liner comprises metal and/or metal alloys.

37. The tubing according to claim 36, wherein the inner liner comprises one or more of steel, nickel alloys, nickel chrome, nickel copper alloys, titanium, titanium alloys, preferably wherein said steel is selected from the group consisting of non-sour service carbon steel, sour service carbon steel, martensitic stainless steel, martensitic ferritic stainless steel, and duplex stainless.

38. The tubing according to claim 36 or 37, wherein the inner liner is welded to the coupling member.

39. A production or injection installation comprising a subsurface well and tubing according to any one of claims 1 to 38, said tubing being located in the subsurface well.

40. Method of placing production and/or injection tubing in a subsurface well, the method comprising the steps of: providing tubing according to any one of claims 1 to 38 on a spool having a diameter of less than 20 meters, preferably less than 15 meters; and unspooling and inserting the tubing into the well.

41. Method of manufacturing tubing, the method comprising the steps of: providing an inner liner; winding a fibrous material around the inner liner; providing a thermosetting polymer material to the fibrous material; curing the thermosetting polymer material, preferably by heating the thermosetting polymer.

42. The method of claim 41, wherein the inner liner comprises a metal, wherein preferably the inner liner is welded to a coupling member.

43. The method of claims 41 or 42, wherein the thermosetting polymer is heated via induction heating.

44. The method of any of claims 41 to 43, wherein an electrically conducting additive is provided in the thermosetting polymer.

45. The method of any of claims 41 to 44, wherein the inner liner is manufactured with pre-preg tapes.

46. Method of producing mineral oil or natural gas from a subsurface reservoir, comprising the steps of; providing tubing according to any one of claims 1 to 38 in a subsurface reservoir; and extracting subsurface oil or gas through the tubing to provide said mineral oil or natural gas.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0081] The features and advantages of the invention will be appreciated upon reference to the following drawings, in which:

[0082] FIG. 1 is a cross-sectional view of the tubing of an embodiment of the present invention provided in the casing of the well;

[0083] FIG. 1A is a blow-out view of one side of the tubing according to an embodiment of the present invention;

[0084] FIG. 1B is a cross-sectional view taken at B-B of FIG. 1, of an embodiment of the present invention provided in the casing of the well;

[0085] FIG. 2 is a cross-sectional view of the tubing of an embodiment of the present invention provided in the casing and attached to a coupling member and a production packer;

[0086] FIG. 3 is a cut-out view of a coupling member connected to the tubing according to an embodiment of the present invention;

[0087] FIG. 4 is a front view of the coupling member, connected to the inner liner according to an embodiment of the present invention;

[0088] FIG. 5 is a flow chart illustrating a method for placing production and/or injection tubing in a subsurface well;

[0089] FIG. 6 is a flow chart illustrating a method of manufacturing tubing; and

[0090] FIG. 7 is a flow chart illustrating a method of producing mineral oil or natural gas from a subsurface reservoir.

DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

[0091] The following is a description of certain embodiments of the invention, given by way of example only and with reference to the drawings.

[0092] Referring to FIG. 1, a cross-sectional view of the tubing 10 of an embodiment of the present invention is shown, provided in the casing 3 of the well. The tubing 10 comprises an inner liner 1 and an outer wall 2. In the shown embodiment, the outer wall 2 of the tubing 10 expands as it extends downwardly towards the coupling member 7. The coupling member 7 receives the material of the outer wall 2 to bind the outer wall 2 of the tubing 10 to the coupling member 7. The dimensions of the tubing 10, including the inner liner 1 and the outer wall 2, are choses so that a coupling member 7 can be attached to the tubing, without having the tubing 10 reach a size that can no longer fit in the casing 3 of the well.

[0093] Referring to FIG. 1A, a blow-out view of one side of the tubing according to an embodiment of the present invention is shown. In the shown embodiment, the outer wall 2 is shown to have a higher thickness than the inner liner 1 of the tubing 10. The outer wall 2 provides a high degree of structural integrity to the tubing 10, while the inner liner 1 preferably comprises an isotropic impermeable material which mitigates the effects of potential microcracks in the surface of the outer wall 2 of the tubing 10.

[0094] Referring to FIG. 1B, a cross-sectional view taken at B-B of FIG. 1, of an embodiment of the present invention provided in the casing of the well is shown. The cross-sectional view shows the tubing 10, comprising of an inner liner 1 and an outer wall 2. The tubing 10 is provided in the casing 3 of the well.

[0095] Referring to FIG. 2, a cross-sectional view of the tubing 10 of an embodiment of the present invention is shown, provided in the casing 3 and attached to a coupling member 7 and a production packer 9. The tubing 10 is attached to the coupling member 7 through binding the fibers of the outer wall 2 to the coupling member 7. As can be seen in the figure, the thickened section of the outer wall 2 at the interface region between the tubing 10 and the coupling member 7, runs over the coupling member. The fibers of the outer wall 2 extend between the projections 71 of the coupling member 7, thereby creating an integral connection between the outer wall 2 and the coupling member 7.

[0096] In addition, in the shown embodiment, there is provided a bi-metal ring 6, which is provided between the coupling member 7 and the inner lining 1 of the tubing 10. In particular, this bi-metal ring 6 comprises a first end 4 which comprises a metal corresponding to the material of the inner liner 1. This first end 4 of the bi-metal ring 6 is connected to the inner liner 1 of the tubing 10, preferably via welding. The bi-metal ring 6 further comprises a second end 5, which comprises a metal corresponding to the material of the coupling member 7. This second end 5 of the bi-metal ring 6 is connected to the coupling member 7, also preferably via welding. In this manner, the inner liner 1 and the coupling member 7 may be connected to one another via welding, regardless of the fact that they can be made of different materials. As eluded to in the above section, regular welding techniques may not be sufficient to connect two components of different metals. The bi-metal ring 6 is manufactured via e.g. explosion welding or friction stir welding.

[0097] To the coupling member 7, a pub joint 8 may be connected. Pub joints are known standard components in oil and gas industry, designed to provide the final component to a completion string. The pub joint 8 may be connected to the coupling member 7 with any known coupling mechanisms. In the shown embodiment, the pub joint 8 is connected to the coupling member 7 with a threaded connection. To the pub joint 8, a production packer 9 is connected. The production packer 9 provides a seal between the formation 11, e.g. the zone from which a fluid is produced, and the production annulus 91, the region between the tubing and the casing, above the production packer 9. The production packer 9 thus provides a seal between the pub joint 8 and the casing 3, to separate the production annulus 91 and the formation 11.

[0098] Referring to FIG. 3 a cut-out view of a coupling member 7 connected to the tubing 10 according to an embodiment of the present invention is shown. The figure shows the tubing 10 comprising an inner liner 1 and an outer wall 2, connected to a coupling member 7. As discussed, in this embodiment, the inner liner 1 is connected to the first end 4 of the bi-metal ring 6, preferably by welding. On the other side, the second end 5 of the bi-metal ring 6 is connected to the coupling member 7. As can be seen, the coupling member 7 comprises a plurality of projections 71, which extend radially outward, and are provided across the coupling member 7. These projections 71 are arranged to receive the fibers of the outer wall 2 of the tubing 10. These fibers extend between the projections 71 of the coupling member 7, thereby creating an integral connection between the tubing 10 and the coupling member 7.

[0099] Referring to FIG. 4, a front view of the coupling member 7, connected to the inner liner 1 of the tubing 10, according to an embodiment of the present invention is shown. The inner liner 1 is connected to the coupling member 7 via a bi-metal ring 6, comprised of a first end 4 and a second end 5, composed of the materials corresponding to the materials of the inner liner 1 and the coupling member 7, respectively. On the coupling member 7, a number of projections 71 are disposed, between which the fibers 21 of the outer wall 2 may be guided. As shown in the figure, one such fiber 21 is directed over the inner liner 1 of the tubing 10 between the projections 71. The projections 71 allow for a gradual directional change of the fiber 21 to ensure the fiber does not encounter disadvantageous amounts of local stress.

[0100] Different layers of fibers 21 may be wound around the inner liner 1 of the tubing 10 at different winding angles relative to a central tubing axis. The low angle fibers 21 are mainly responsible for carrying the axial loads and providing the connection to the coupling member 7. Therefore, particular attention must be given to the winding pattern of the low angle fibers 21 when transitioning to the coupling member 7 and to the path they follow between the projections 71. To provide a smooth and distributed transfer of axial loads from the fibers 21 to the coupling member 7, a gradual change of fiber direction is desired. This translates into so called wide turns, e.g. turns with a large radius. This is shown e.g. in FIG. 4. An even distribution of loads onto the projections 71 is also achieved by ensuring that the turns of each new low angle fiber 21 is placed at a different location along the coupling member 7 than the previous one. The high angle fibers, provided in the outer wall 2 are mainly responsible for carrying the circumferential loads i.e. pressure and collapse loads. When transitioning onto the coupling member 7, these high angle fibers maintain their path and angle. This method will sandwich the low angle fibers 21 into a stable laminate, thereby increasing the integrity and stability of the low angle fibers 21.

[0101] The transition of fibers from the inner liner 1 onto the coupling member 7 may be a weak point of the tubing 10. To design a fiber transition that is as strong or stronger than the tubing itself, additional local fibers 21 may be added. This leads to the creation of the tubing connection upset, e.g. the increased thickness of the outer wall 2, closer to the coupling member 7. The maximum outer diameter of the pipe body as well as the maximum outer diameter of the coupling member 7 may be determined by industry standards, such as the maximum inner diameter of the BOP, and/or the casing. Additional local fibers may be added to increase the strength at the transition point while not exceeding the maximum connection upset diameter.

[0102] Referring to FIG. 5, a flow chart illustrating a method for placing production and/or injection tubing in a subsurface well is shown. It shows the steps of providing tubing 10 according to any of the abovementioned embodiments on a spool having a diameter of less than 20 meters. In a preferred embodiment, the spool has a diameter of less than 15 meters. The figure further shows the step of unspooling and inserting the tubing 10 into the well. Since the tubing 10 may be in accordance with the industry standard requirements, the tubing 10 will readily fit inside the casing 3 of the well, thereby greatly improving operational efficiency.

[0103] Referring to FIG. 6, a flow chart illustrating a method of manufacturing tubing 10 is shown. The figure shows the steps of providing an inner liner 1 according to any of the abovementioned embodiments. A fibrous material is then wound around the inner liner 2. To this fibrous material, a thermosetting polymer material is provided. Further, the thermosetting polymer material is cured, thereby forming the outer wall 2 of the tubing 10. In a preferred embodiment, this curing is done by heating the thermosetting polymer.

[0104] Referring to FIG. 7, a flow chart illustrating a method of producing mineral oil or natural gas from a subsurface reservoir is shown. The figure shows the steps of providing tubing 10 according to any of the embodiments described hereinabove in a subsurface reservoir. The subsurface oil or gas is then extracted through the tubing 10 to provide said mineral oil or natural gas.

[0105] The invention has been described by reference to certain embodiments discussed above. It will be recognized that these embodiments are susceptible to various modifications and alternative forms well known to those of skill in the art.

[0106] Further modifications in addition to those described above may be made to the structures and techniques described herein without departing from the spirit and scope of the invention. Accordingly, although specific embodiments have been described, these are examples only and are not limiting upon the scope of the invention.