CA2714872C - Downhole oilfield tubulars having liners with diffusion barrier layer - Google Patents
Downhole oilfield tubulars having liners with diffusion barrier layer Download PDFInfo
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- CA2714872C CA2714872C CA2714872A CA2714872A CA2714872C CA 2714872 C CA2714872 C CA 2714872C CA 2714872 A CA2714872 A CA 2714872A CA 2714872 A CA2714872 A CA 2714872A CA 2714872 C CA2714872 C CA 2714872C
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- liner
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Abstract
A well completion method and a tubing assembly for oilfield well completion is disclosed, which includes: (a) a rigid metal tubular member having a metallic outer surface and a metallic inner surface, wherein the metallic inner surface of the rigid tubular member defines a metal tubular borehole; and (b) a liner disposed inside the metal tubular borehole adjacent to and against the metallic inner surface; wherein the liner includes at least one layer comprising a polymer and at least one diffusion barrier layer.
Description
DOWNHOLE OILFIELD TUBULARS HAVING LINERS
WITH DIFFUSION BARRIER LAYER
BACKGROUND
Tubular goods, such as oil country tubular goods ("OCTG's") (e.g., well casing, tubing, diillpipe, drill collars, and line pipe) and flowline tubular goods, are often used for transportation of gases, liquids, and mechanical equipment, including various applications related to extraction of petroleum and natural gas from underground reservoirs, transportation of petroleum, natural gas, and other materials, such as solution mining and slurry transport lines in the mining industry. OCTG's may be used to transport the product from the underground reservoir, and also to house mechanical equipment (e.g., artificial lift devices, rod couplings, plungers, reciprocating rod pumping units, rotating progressive cavity pumps, and plunger lift units), electrical equipment (e.g., well monitoring equipment), and/or transport gases or liquids for disposal operations or secondary removal operations. These gases and liquids may contain corrosive materials such as, by way of example only, salt water, dissolved oxygen, CO2, or H2S. In addition, flowline tubular goods may be used to transport petroleum, petroleum products, natural gas, or other gases or liquids from one point to another. The gases and liquids which flow within flowlines may, comprise corrosive and/or abrasive components. In addition, flowline tubular goods may also occasionally require the use of mechanical equipment, such as pigs, to clean or service the tubular good.
With respect to moving mechanical equipment and abrasive fluids, such as reciprocating or rotating rods or pumps or drilling or mining slurries (e.g., drilling mud), friction and abrasion may cause wear, fatigue, and even failure of the pipe and/or the equipment. In addition, this wear, fatigue, or failure may be accelerated due to the presence of corrosive or abrasive materials, such as, for example CO2, or by deviations in the direction of the well bore. One method of combatting this wear in oil well production equipment is disclosed in U.S. Patent No. RE36,362 to Jackson In addition to the possible acceleration of mechanical wear, fatigue, and failure, the presence of corrosive material, in and of itself, may cause chemical damage to the OCTG' s and flowline tubular goods. By way of example only, the presence of CO2, when contacted with metal or other materials may cause corrosion, dusting, rusting, or pitting, which may lead to failure of the material. In addition, the presence of microbiological active agents, such as bacteria, may produce chemicals which influence or accelerate corrosion.
It would therefore be desirable to create tubular goods which decrease or eliminate the mechanical and/or chemical wear, fatigue, or failure caused by the conditions surrounding the extraction of materials such as petroleum or natural gas and transportation of materials, thereby potentially increasing the life and productivity of the tubular good.
SUMMARY
Disclosed herein are methods and apparatus for reducing or eliminating the mechanical and/or chemical wear, fatigue, and failure on tubular goods. The methods comprise disposing a liner along at least a portion of the tubular good. The liner may decrease friction, thereby decreasing mechanical wear as well as reducing the amount of energy necessary to operate the mechanical tool or pump the abrasive fluid. In addition, the liner may also comprise a material which is resistant to particular chemicals or a barrier to particular chemicals, thereby decreasing or eliminating contact between the chemicals and the tubular good and decreasing or eliminating the wear or corrosion caused by those chemicals.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure I is a schematic drawing of a tubular good in accordance with embodiments of the present invention.
WITH DIFFUSION BARRIER LAYER
BACKGROUND
Tubular goods, such as oil country tubular goods ("OCTG's") (e.g., well casing, tubing, diillpipe, drill collars, and line pipe) and flowline tubular goods, are often used for transportation of gases, liquids, and mechanical equipment, including various applications related to extraction of petroleum and natural gas from underground reservoirs, transportation of petroleum, natural gas, and other materials, such as solution mining and slurry transport lines in the mining industry. OCTG's may be used to transport the product from the underground reservoir, and also to house mechanical equipment (e.g., artificial lift devices, rod couplings, plungers, reciprocating rod pumping units, rotating progressive cavity pumps, and plunger lift units), electrical equipment (e.g., well monitoring equipment), and/or transport gases or liquids for disposal operations or secondary removal operations. These gases and liquids may contain corrosive materials such as, by way of example only, salt water, dissolved oxygen, CO2, or H2S. In addition, flowline tubular goods may be used to transport petroleum, petroleum products, natural gas, or other gases or liquids from one point to another. The gases and liquids which flow within flowlines may, comprise corrosive and/or abrasive components. In addition, flowline tubular goods may also occasionally require the use of mechanical equipment, such as pigs, to clean or service the tubular good.
With respect to moving mechanical equipment and abrasive fluids, such as reciprocating or rotating rods or pumps or drilling or mining slurries (e.g., drilling mud), friction and abrasion may cause wear, fatigue, and even failure of the pipe and/or the equipment. In addition, this wear, fatigue, or failure may be accelerated due to the presence of corrosive or abrasive materials, such as, for example CO2, or by deviations in the direction of the well bore. One method of combatting this wear in oil well production equipment is disclosed in U.S. Patent No. RE36,362 to Jackson In addition to the possible acceleration of mechanical wear, fatigue, and failure, the presence of corrosive material, in and of itself, may cause chemical damage to the OCTG' s and flowline tubular goods. By way of example only, the presence of CO2, when contacted with metal or other materials may cause corrosion, dusting, rusting, or pitting, which may lead to failure of the material. In addition, the presence of microbiological active agents, such as bacteria, may produce chemicals which influence or accelerate corrosion.
It would therefore be desirable to create tubular goods which decrease or eliminate the mechanical and/or chemical wear, fatigue, or failure caused by the conditions surrounding the extraction of materials such as petroleum or natural gas and transportation of materials, thereby potentially increasing the life and productivity of the tubular good.
SUMMARY
Disclosed herein are methods and apparatus for reducing or eliminating the mechanical and/or chemical wear, fatigue, and failure on tubular goods. The methods comprise disposing a liner along at least a portion of the tubular good. The liner may decrease friction, thereby decreasing mechanical wear as well as reducing the amount of energy necessary to operate the mechanical tool or pump the abrasive fluid. In addition, the liner may also comprise a material which is resistant to particular chemicals or a barrier to particular chemicals, thereby decreasing or eliminating contact between the chemicals and the tubular good and decreasing or eliminating the wear or corrosion caused by those chemicals.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure I is a schematic drawing of a tubular good in accordance with embodiments of the present invention.
Figure 2 is a cross section of a tubular good in accordance with embodiments of the present invention.
Figure 3 is a rotating rod pumping system in accordance with embodiments of the present invention.
DETAILED DESCRIPTION
Referring now to Figure 1, there is shown metal tubing 30, coupling 36, and liner 40. Two joints of metal tubing 30, having an inner diameter 32 and outer diameter 34, are connected together by coupling 36. Disposed within each tubing joint 30 adjacent to its inner surface 38 is a liner 40 (an embodiment of which is shown in detail in Figure 2). Liner 40 may be a multilayer system comprising both a wear resistant material and a diffusion barrier. In some embodiments, where gas diffusion is of minimal or no concern, liner 40 may comprise a layer comprising only a wear barrier such as polypropylene with no diffusion barrier being present.
The liner 40 may be disposed within the tubing 30 by any one of several methods known in the art. One method of disposing the liner within the tubing bore is to provide a polymer liner having an outside diameter which is slightly greater than or equal to the inner diameter of the tubing section pipe having an outside diameter larger than the internal diameter of the tubing.
Reduce the outside of the liner and insert the reduced diameter liner within the tubing. After the liner is in place, it will attempt to substantially return to its original shape and will become secured within the tubing section via process called plastic deformation. There may be numerous methods of reducing the outside diameter of the liner for insertion into a tubing section are available. For example, rollers may be used to mechanically reduce the outside diameter of the liner by the desired amount and to push the liner into the tubing joint. Other methods include pulling the liner through a sizing sleeve or orifice and pushing the reduced diameter liner into place in the tubing.
One method of disposing the polymer liners within the tubing sections includes providing a liner having an initial outside diameter similar to or larger than the inner diameter of the tubing, reducing the outer diameter of the liner by mechanical means and inserting the liner into the tubing bore. The ends of the polymer liner may then be softened using a heat source and formed around the end of the external pipe thread on the metal pipe. In some cases, the ends may be reinforced for additional structural integrity. The ends may then be joined onto a coupling (with or without an internal coating or corrosion resistant insert) used to join each stick of lined pipe. The process ultimately provides a one-piece seamless liner in each joint that is mechanically bonded to the metal pipe ID. The wall thickness of the claimed liners is preferably between about 2 and 10 millimeters. The diameter of the claimed liners may be between about 20 and 700 millimeters or greater. In the embodiments shown in Fig. 1, the thickness "t" of the liner 40 is about 4 millimeters.
Referring now to Figure 2 (not to scale), there is shown lined tubular good comprising outer layer 110, diffusion barrier 120, adhesive layers 130 and 160 (optional), and friction and wear reducing layers 140 and 150. outer layer 110 may be a metal tubular good such as an OCTG, a flowline tubular good, or a solution mining or slurry transport line. The tubular good liner is preferably comprised of elements 120, 130, 140, 150, and 160. Friction and wear reducing layers 140 and 150 may comprise, by way of example only, polyethylene or polypropylene. Layers 140 and 150 may or may not consist of the same material.
Diffusion reducing layer may comprise, by way of example only, a vinyl alcohol such as polyvinyl alcohol. Layer 140 may be bonded to diffusion barrier 120 by any method as would be appreciated by one of skill in the art. By way of example only, layers 120 and 140 may be bonded by adhesive layer 130 and layers 150 and 120 may be bonded by adhesive layer 160. Adhesive layers 130 and 160 may be, but are not necessarily, the same adhesive.
Adhesive layers 130 and 160 may comprise, any acceptable polymer adhesive as is known in the art, such as copolymers.
Figure 3 is a rotating rod pumping system in accordance with embodiments of the present invention.
DETAILED DESCRIPTION
Referring now to Figure 1, there is shown metal tubing 30, coupling 36, and liner 40. Two joints of metal tubing 30, having an inner diameter 32 and outer diameter 34, are connected together by coupling 36. Disposed within each tubing joint 30 adjacent to its inner surface 38 is a liner 40 (an embodiment of which is shown in detail in Figure 2). Liner 40 may be a multilayer system comprising both a wear resistant material and a diffusion barrier. In some embodiments, where gas diffusion is of minimal or no concern, liner 40 may comprise a layer comprising only a wear barrier such as polypropylene with no diffusion barrier being present.
The liner 40 may be disposed within the tubing 30 by any one of several methods known in the art. One method of disposing the liner within the tubing bore is to provide a polymer liner having an outside diameter which is slightly greater than or equal to the inner diameter of the tubing section pipe having an outside diameter larger than the internal diameter of the tubing.
Reduce the outside of the liner and insert the reduced diameter liner within the tubing. After the liner is in place, it will attempt to substantially return to its original shape and will become secured within the tubing section via process called plastic deformation. There may be numerous methods of reducing the outside diameter of the liner for insertion into a tubing section are available. For example, rollers may be used to mechanically reduce the outside diameter of the liner by the desired amount and to push the liner into the tubing joint. Other methods include pulling the liner through a sizing sleeve or orifice and pushing the reduced diameter liner into place in the tubing.
One method of disposing the polymer liners within the tubing sections includes providing a liner having an initial outside diameter similar to or larger than the inner diameter of the tubing, reducing the outer diameter of the liner by mechanical means and inserting the liner into the tubing bore. The ends of the polymer liner may then be softened using a heat source and formed around the end of the external pipe thread on the metal pipe. In some cases, the ends may be reinforced for additional structural integrity. The ends may then be joined onto a coupling (with or without an internal coating or corrosion resistant insert) used to join each stick of lined pipe. The process ultimately provides a one-piece seamless liner in each joint that is mechanically bonded to the metal pipe ID. The wall thickness of the claimed liners is preferably between about 2 and 10 millimeters. The diameter of the claimed liners may be between about 20 and 700 millimeters or greater. In the embodiments shown in Fig. 1, the thickness "t" of the liner 40 is about 4 millimeters.
Referring now to Figure 2 (not to scale), there is shown lined tubular good comprising outer layer 110, diffusion barrier 120, adhesive layers 130 and 160 (optional), and friction and wear reducing layers 140 and 150. outer layer 110 may be a metal tubular good such as an OCTG, a flowline tubular good, or a solution mining or slurry transport line. The tubular good liner is preferably comprised of elements 120, 130, 140, 150, and 160. Friction and wear reducing layers 140 and 150 may comprise, by way of example only, polyethylene or polypropylene. Layers 140 and 150 may or may not consist of the same material.
Diffusion reducing layer may comprise, by way of example only, a vinyl alcohol such as polyvinyl alcohol. Layer 140 may be bonded to diffusion barrier 120 by any method as would be appreciated by one of skill in the art. By way of example only, layers 120 and 140 may be bonded by adhesive layer 130 and layers 150 and 120 may be bonded by adhesive layer 160. Adhesive layers 130 and 160 may be, but are not necessarily, the same adhesive.
Adhesive layers 130 and 160 may comprise, any acceptable polymer adhesive as is known in the art, such as copolymers.
In addition, layers 120 and 140 may be bonded by the addition of additives to the layers, by way of example only, 2,5-furandione, the chemical structure of which is set forth as Formula 1 below:
0 0 (1), when added to the layers may cause the layers to become bonded together without the need for additional adhesives.
The layers are typically coextruded through a specially designed extrusion die head using multiple extruders. The melted polymer layers are then cooled into one continuous seemless tube.
For a rod pumping system 10 (see FIG. 3) commonly referred to as a beam pumping well, using a plurality of sucker rods 20 (see FIG. 3) disposed within a string of tubing 24 which extends into said well, said string of tubing comprising a plurality of tubing sections each having a bore and an inside diameter; a down hole pump 28 operably connected to said sucker rods 20; and means for reciprocating said sucker rods wherein the improved method comprises using tubing sections having polyolefin liners disposed within said bore of said tubing sections to eliminate contact between said sucker rods and said tubing string when said sucker rods are being reciprocated.
For a rotating rod pumping system 10 (see FIG. 3) commonly referred to as a progressive cavity pumping system, using a plurality of sucker rods 20 (see FIG. 3) disposed within a string of tubing 24 which extends into said well, said string of tubing comprising a plurality of tubing sections each having a bore and an inside diameter; a down hole pump 28 operably connected to said sucker rods 20; and means for rotating said sucker rods wherein the improved method comprises using tubing sections having polyolefin liners disposed within said bore of said tubing sections to eliminate contact between said sucker rods and said tubing string when said sucker rods are being rotated.
The scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest purposive construction consistent with the description as a whole. By way of example only, the friction and wear reducing layer may comprise nucleated polypropylene; polyolefins containing nanocomposites or other additives to control diffusion rates;
impact copolymer grade polypropylene; homopolymer grade polypropylene;
heterophasic copolymers;
fractional melt grade polypropylene; other thermoplastics coextruded with polypropylene; reactor made thermoplastic polyolefins; metallocene catalyzed polypropylenes; random copolymer polypropylenes; blends, alloys, filled or reinforced polypropylene or polyethylene containing other polyolefins and structural reinforcement. In addition, additives may be included in the polymer to increase the lubricity of the liner material and decrease the coefficient of friction of the product.
The gas diffusion barrier may comprise other polymers, organic or inorganic materials, or metals. In some embodiments, this barrier is chosen to reduce or eliminate the permeation of carbon dioxide through liners utilized in CO2 floods and WAG (water-alternating-gas) injection systems for oil production enhanced recovery operations.
In embodiments in which the friction wear reducing layer and the diffusion barrier are chemically bonded 2,5-furandione or other similar additives may be used. The layers may also be bound by any acceptable adhesive as is known in the art. For example, an acceptable adhesive may comprise a copolymer. It is also envisioned that the friction wear reducing layer and the diffusion barrier need not be directly bonded together. There may be intermediate layers between the two.
Additionally, there may be layers radially outward or inward of the diffusion barrier. By way of example only, the diffusion barrier may be sandwiched between the friction and wear reducing layer and a third layer. The third layer may be of the same or different material as the friction and wear reducing layer.
0 0 (1), when added to the layers may cause the layers to become bonded together without the need for additional adhesives.
The layers are typically coextruded through a specially designed extrusion die head using multiple extruders. The melted polymer layers are then cooled into one continuous seemless tube.
For a rod pumping system 10 (see FIG. 3) commonly referred to as a beam pumping well, using a plurality of sucker rods 20 (see FIG. 3) disposed within a string of tubing 24 which extends into said well, said string of tubing comprising a plurality of tubing sections each having a bore and an inside diameter; a down hole pump 28 operably connected to said sucker rods 20; and means for reciprocating said sucker rods wherein the improved method comprises using tubing sections having polyolefin liners disposed within said bore of said tubing sections to eliminate contact between said sucker rods and said tubing string when said sucker rods are being reciprocated.
For a rotating rod pumping system 10 (see FIG. 3) commonly referred to as a progressive cavity pumping system, using a plurality of sucker rods 20 (see FIG. 3) disposed within a string of tubing 24 which extends into said well, said string of tubing comprising a plurality of tubing sections each having a bore and an inside diameter; a down hole pump 28 operably connected to said sucker rods 20; and means for rotating said sucker rods wherein the improved method comprises using tubing sections having polyolefin liners disposed within said bore of said tubing sections to eliminate contact between said sucker rods and said tubing string when said sucker rods are being rotated.
The scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest purposive construction consistent with the description as a whole. By way of example only, the friction and wear reducing layer may comprise nucleated polypropylene; polyolefins containing nanocomposites or other additives to control diffusion rates;
impact copolymer grade polypropylene; homopolymer grade polypropylene;
heterophasic copolymers;
fractional melt grade polypropylene; other thermoplastics coextruded with polypropylene; reactor made thermoplastic polyolefins; metallocene catalyzed polypropylenes; random copolymer polypropylenes; blends, alloys, filled or reinforced polypropylene or polyethylene containing other polyolefins and structural reinforcement. In addition, additives may be included in the polymer to increase the lubricity of the liner material and decrease the coefficient of friction of the product.
The gas diffusion barrier may comprise other polymers, organic or inorganic materials, or metals. In some embodiments, this barrier is chosen to reduce or eliminate the permeation of carbon dioxide through liners utilized in CO2 floods and WAG (water-alternating-gas) injection systems for oil production enhanced recovery operations.
In embodiments in which the friction wear reducing layer and the diffusion barrier are chemically bonded 2,5-furandione or other similar additives may be used. The layers may also be bound by any acceptable adhesive as is known in the art. For example, an acceptable adhesive may comprise a copolymer. It is also envisioned that the friction wear reducing layer and the diffusion barrier need not be directly bonded together. There may be intermediate layers between the two.
Additionally, there may be layers radially outward or inward of the diffusion barrier. By way of example only, the diffusion barrier may be sandwiched between the friction and wear reducing layer and a third layer. The third layer may be of the same or different material as the friction and wear reducing layer.
Claims (20)
1. A method of completing a well for production or injection of fluids from an underground formation, which method comprises: installing within the wellbore a string of tubing, wherein: (a) the string of tubing includes a rigid metal tubular member having a metallic outer surface and a metallic inner surface; (b) the metallic inner surface of the rigid metal tubular member defines a metal tubular borehole; (c) a liner is disposed inside the metal tubular borehole adjacent to and against the metallic inner surface; and (d) the liner includes at least one layer comprising a polymer and at least one gas diffusion barrier layer.
2. The method of claim 1 wherein the polymer includes a polyolefin.
3. The method of claim 1 wherein the polymer includes a thermoplastic.
4. The method of claim 1 wherein the polymer includes a polypropylene.
5. The method of claim 1 wherein the polymer includes a polyethylene.
6. The method of claim 1 wherein the gas diffusion barrier layer includes vinyl alcohol.
7. The method of claim 6 wherein the vinyl alcohol includes polyvinyl alcohol.
8. The method of any one of the claims 1 to 7 wherein the one layer that comprises the polymer is an outer layer, and the gas diffusion barrier layer is positioned circumferentially inside the outer layer, such that the outer layer is closer than the gas diffusion barrier layer to the metallic inner surface of the rigid metal tubular member, and the gas diffusion barrier layer is closer than the outer layer to the longitudinal axis of the metal tubular borehole.
9. The method of claim 8 wherein the liner further includes an adhesive layer between the outer layer and the gas diffusion barrier layer.
10. The method of claim 8 wherein the gas diffusion barrier layer prevents substantial diffusion of carbon dioxide through the layer.
11. The method of claim 8 wherein the liner further includes a friction-reducing layer positioned inside the gas diffusion barrier layer, such that the friction-reducing layer is closer than the gas diffusion layer to the longitudinal axis of the metal tubular borehole.
12. The method of any one of the claims 1 to 11 wherein the liner further includes a friction-reducing layer and also an adhesive layer, such that the adhesive layer is positioned between the gas diffusion barrier layer and the friction-reducing layer or between the outer layer and the gas diffusion barrier layer.
13. The method of claim 1 wherein the layer comprising the polymer, or the diffusion barrier layer, or both, includes an additive that promotes adhesion between the layer comprising the polymer and the gas diffusion barrier layer.
14. The method of claim 13 wherein the additive that promotes adhesion comprises 2,5-furandione.
15. The method of claim 13 wherein the liner additionally includes an adhesive layer.
16. The method of any one of the claims 1 to 15, wherein the string of tubing includes a string of injection well tubing and the wellbore is part of an enhanced oil recovery well or a disposal well.
17. The method of claim 1, wherein the layer that includes the polymer is in direct physical contact with the metallic inner surface, such that no other layer is interposed between the metallic inner surface and the layer that includes the polymer.
18. The method of claim 1, wherein the gas diffusion barrier layer is the innermost layer of the liner such that any fluids being produced or injected through the wellbore are capable of being in direct contact with the innermost layer of the liner.
19. A method of completing a well for production or injection of fluids from an underground formation, which method comprises installing a tubular member within the wellbore, wherein:
(a) the tubular member has an outer surface and an inner surface; (b) the tubular member defines a tubular borehole configured to provide for the flow of production or injection fluids; (c) a liner is disposed inside the tubular borehole adjacent to the inner surface; (d) the liner includes at least one layer comprising a polymer and at least one gas diffusion barrier layer; and (e) the layer that includes the polymer is an outer layer, and the gas diffusion barrier layer is positioned circumferentially inside the outer layer, such that the outer layer is closer than the gas diffusion barrier layer to the inner surface of the tubular member, and the gas diffusion barrier layer is closer than the outer layer to the longitudinal axis of the tubular borehole.
(a) the tubular member has an outer surface and an inner surface; (b) the tubular member defines a tubular borehole configured to provide for the flow of production or injection fluids; (c) a liner is disposed inside the tubular borehole adjacent to the inner surface; (d) the liner includes at least one layer comprising a polymer and at least one gas diffusion barrier layer; and (e) the layer that includes the polymer is an outer layer, and the gas diffusion barrier layer is positioned circumferentially inside the outer layer, such that the outer layer is closer than the gas diffusion barrier layer to the inner surface of the tubular member, and the gas diffusion barrier layer is closer than the outer layer to the longitudinal axis of the tubular borehole.
20. A method of completing a well for production or injection of fluids from an underground formation, which method comprises installing a tubular member within the wellbore, wherein:
(a) the tubular member has an outer surface and an inner surface;
(b) the tubular member defines a tubular borehole configured to provide for the flow of production or injection fluids;
(c) a liner is disposed inside the tubular borehole adjacent to the inner surface;
(d) the liner includes a first polymer layer, which comprises a first polymer; at least one diffusion barrier layer and a second polymer layer, which comprises a second polymer;
(e) the first polymer layer is an outer layer, and the diffusion barrier layer is positioned circumferentially inside the outer layer, such that the outer layer is closer than the diffusion barrier layer to the inner surface of the tubular member, and the diffusion barrier layer is closer than the outer layer to the longitudinal axis of the tubular borehole;
(f) the second polymer layer is positioned circumferentially inside the diffusion barrier layer such that the second polymer layer is closer than the diffusion barrier layer to the longitudinal axis of the tubular borehole; and (g) the layer comprising the polymer, or the diffusion barrier layer, or both, includes an additive that promotes adhesion between the layer comprising the polymer and the diffusion barrier layer.
(a) the tubular member has an outer surface and an inner surface;
(b) the tubular member defines a tubular borehole configured to provide for the flow of production or injection fluids;
(c) a liner is disposed inside the tubular borehole adjacent to the inner surface;
(d) the liner includes a first polymer layer, which comprises a first polymer; at least one diffusion barrier layer and a second polymer layer, which comprises a second polymer;
(e) the first polymer layer is an outer layer, and the diffusion barrier layer is positioned circumferentially inside the outer layer, such that the outer layer is closer than the diffusion barrier layer to the inner surface of the tubular member, and the diffusion barrier layer is closer than the outer layer to the longitudinal axis of the tubular borehole;
(f) the second polymer layer is positioned circumferentially inside the diffusion barrier layer such that the second polymer layer is closer than the diffusion barrier layer to the longitudinal axis of the tubular borehole; and (g) the layer comprising the polymer, or the diffusion barrier layer, or both, includes an additive that promotes adhesion between the layer comprising the polymer and the diffusion barrier layer.
Applications Claiming Priority (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US36713202P | 2002-05-16 | 2002-05-16 | |
| US60/367,132 | 2002-05-16 | ||
| CA2486177A CA2486177C (en) | 2002-05-16 | 2003-02-14 | Tubular goods and liners |
Related Parent Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2486177A Division CA2486177C (en) | 2002-05-16 | 2003-02-14 | Tubular goods and liners |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CA2714872A1 CA2714872A1 (en) | 2003-11-27 |
| CA2714872C true CA2714872C (en) | 2013-11-19 |
Family
ID=43064692
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2714872A Expired - Lifetime CA2714872C (en) | 2002-05-16 | 2003-02-14 | Downhole oilfield tubulars having liners with diffusion barrier layer |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA2714872C (en) |
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2003
- 2003-02-14 CA CA2714872A patent/CA2714872C/en not_active Expired - Lifetime
Also Published As
| Publication number | Publication date |
|---|---|
| CA2714872A1 (en) | 2003-11-27 |
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| EEER | Examination request | ||
| MKEX | Expiry |
Effective date: 20230214 |