Polymer lined insulated tubing

Abstract

An insulated wellbore tubular has a metallic tubular body and a polymer liner formed to the interior of the metallic tubular body. The polymer liner has a specified thermal resistance to radial heat transfer through the polymer liner that is higher than the thermal resistance to radial heat transfer through the metallic tubular body.

Description

Attorney Docket No.50511-0085WO1 Polymer Lined Insulated Tubing CLAIM OF PRIORITY

[0001] This application claims benefit of U.S. Provisional Patent Application No. 63 / 562,000 filed on March 6, 2024, the entire contents of which are hereby incorporated by reference. TECHNICAL FIELD

[0002] The concepts herein relate to insulated drill pipe and tubulars for use in wellbores. BACKGROUND

[0003] Drilling and other well operations are typically performed with metal pipe or tubing. Metal has a high thermal conductivity, and therefore, is capable of transferring heat between the fluids within the tubing and the fluids in the annulus between the wellbore and the tubing. Drill pipe coated with thin insulative coatings have been used when needed to reduce the thermal conductivity of the pipe.Attorney Docket No.50511-0085WO1 SUMMARY

[0004] The concepts herein relate to insulated drill pipe and tubulars for use in wellbores.

[0005] Certain aspects encompass an insulated wellbore tubular having a metallic tubular body and a polymer liner formed to the interior of the metallic tubular body. The polymer liner has a specified thermal resistance to heat transfer through the polymer liner that is higher than the thermal resistance to heat transfer through the metallic tubular body.

[0006] Certain aspects encompass a method where a polymer liner is provided within a metallic tubular body configured for use in a wellbore. The polymer liner is hydroformed to the interior diameter of the metallic tubular body.

[0007] Certain aspects encompass a drilling string having a metallic drill pipe and a polymer liner formed to the interior of the metallic drill pipe. The polymer liner has a specified thermal resistance to heat transfer through the polymer liner that is higher than the thermal resistance to heat transfer through the drill pipe.

[0008] The above aspects can include some, none, or all of the following features. A wedge compression fitting can be provided on an edge of the polymer liner covering the joint between the polymer liner and the metallic tubular body. A helical metal shape can be provided for supporting the inner diameter of the polymer liner. The polymer liner can be hydroformed to the inner diameter of the metallic tubular body. The polymer liner can have a dry density of less than 2000 kg / m3. The length normalized thermal resistance of the polymer liner can be at least 0.02 m K / W. The polymer can have a melting point greater than 150°C. The polymer liner can be thermoplastic. The polymer liner can be adhered to the inner diameter of the metallic tubular body. The wellbore tubular or drill pipe can have tool joint ends configured for connection to another wellbore tubular and the tool joint ends can be coated in an insulative coating having a thermal conductivity of .9 W / mK or less.

[0009] Other aspects and features will be apparent from the following drawings and detailed description.Attorney Docket No.50511-0085WO1 DESCRIPTION OF DRAWINGS

[0010] FIG. 1A is a half cross sectional view of an example insulated wellbore tubular in accordance with the concepts herein having a coiled spring type support. FIG. 1B is a detail quarter cross sectional view of an example insulated wellbore tubular, like FIG.1A except with coating on the tubular body, in accordance with the concepts herein.

[0011] FIG.2A is a half cross-sectional view of an example insulated tubular in accordance with the concepts herein having a snap ring affixing the liner in place. FIG. 2B is a detail partial perspective view showing the snap ring.

[0012] FIG. 3 is a quarter cross-sectional view of an example insulated tubular in accordance with the concepts herein having a wedge compression fitting before hydroforming.

[0013] FIG.4 is a quarter cross-sectional view of the example insulated tubular of FIG.3 during and after hydroforming.

[0014] Like reference symbols in the various drawings indicate like elements. DETAILED DESCRIPTION

[0015] FIG. 1A shows an insulated wellbore tubular 10 configured as an insulated drill pipe joint for use in drilling a well. In other instances, the tubular 10, however, can be configured as another type of tubular for use within a wellbore. The wellbore tubular 10 has a polymer liner 12, e.g. plastic and / or another polymer, that has been placed within a tubular body 14, and formed to fit the inner contour and shape of the tubular. In the context of an insulated drill pipe joint, the tubular body 14 can be a drill pipe joint. In other instances, the tubular body 14 can be a tubing designed for use in workover, completion and production scenarios and the completed insulated wellbore tubular 10 would be suitable for such operations. Other types of tubular body 14 are contemplated herein.

[0016] The tubular body 14 is, itself, tubular having an internal bore that runs the length of the joint. The tubular body 14 can be made of metal, e.g., steel, aluminum, titanium, alloys thereof and / or another material. The tubular body 14 can be configured with tool joint ends 16, such as a box and pin, other type of threads and / or other tool jointAttorney Docket No.50511-0085WO1 connector type, to allow the tubular bodies 14 to be coupled end to end into a string of tubing. The tubular body 14 can also be coiled tubing and other types of tubulars that can be used within a wellbore. Coiled tubing is a type of wellbore tubing configured to be coiled onto a spool, and is typically provided in lengths longer than typical joints of tubing. For example, coiled tubing can be provided in lengths of hundreds of feet or more, e.g., 2,000 ft, 5,000 ft, 10,000 ft, to more than 30,000 ft. In certain instances, the tubular body 14 is a joint of drill pipe, tubing or coiled tubing that conforms to American Petroleum Institute (API) Standards.

[0017] The insulated wellbore tubular 10 is insulated in that it has a higher thermal resistance to heat transfer through the wall of the tubular 10 than the material of the tubular body 14. The primary thermal resistance comes from the polymer liner 12 itself. The liner 12 is unlike a coating in that it is cohesive and concrete enough to, itself, exist as a tubing prior to application to the tubular body 14. The liner 12 is much thicker than a coating, for example, in the order of several millimeters or centimeters wall thickness (e.g., 2mm, 3mm, 5mm, 10mm and / or another thickness). The liner 12 has a specified thermal resistance to heat transfer than the material, metal or otherwise, of the tubular body 14. Thus, the amount of heat that is able to transfer radially and / or otherwise through the wall of the insulated wellbore tubular 10 is reduced relative to that of the tubular body 14. While additional insulating material may be placed in the inner bore and / or on the outer surface of the tubular body 14, by selection of the polymer liner 12 characteristics, there may be no need for additional insulating material. By forming the polymer liner 12 to the interior of the tubular body 14, the inner diameter of the resulting bore and the hydraulic flow capacity of the tubular can be minimally affected by introducing the liner 12 because the liner 12 closely follows the shape of the tubular body’s 14 bore.

[0018] In certain instances, the polymer liner 12 has a dry density of less than 2000 kg / m3, ideally 1500 kg / m3. At this density the wet weight of the liner 12 once submerged in wellbore fluid is reduced, in some instances minimal and, in certain instances, the tubular 10 can float in the fluid. The effect is the greatest in drilling fluids, as typical drilling fluids have densities ranging from 1.0 – 2.0 Specific Gravity (althoughAttorney Docket No.50511-0085WO1 they can be higher or lower). Resultantly, the insulated wellbore tubular 10 can have an effectively lower weight to the drilling rig, once submerged in the fluids in the well, than the same length of uninsulated tubular body 14 (e.g., drill pipe).

[0019] In certain instances, the thermal resistance of the polymer liner 12 is at least 0.02 mK / W, and ideally greater than 0.05 mK / W. These values may be achieved by selecting the thermal conductivity of the polymer and the thickness of the liner 12. Typical polymer thermal conductivity range suitable for liner 12 is approximately 0.15 – 0.5 W / mK.

[0020] Therefore, this insulated wellbore tubular 10 can have excellent thermal resistance, sufficient hydraulic flow capacity, negligible impact on the wet (floating) weight of the drill string, no external abrasion issues (beyond that of typical metal tubing), and it can be handled the same as regular tubing and / or drill pipe during operations. Another advantage is this design can be applied to standard API drill pipe such as 21.9 lb / ft 5 ½” S135 pipe, and / or another type of pipe, with high torque connections.

[0021] In some instances, an insulative coating 18 can be applied to the tubular body 14 to improve thermal resistance for sections of the tubular body 14 not covered by the polymer liner 12. While the tool joint ends 16 can be left bare, in FIG.1A, an insulative coating 18 is shown applied to the outer surface of the tool joint ends 16 where there is no polymer liner 12 in the interior of the wellbore tubular 10. As shown in FIG. 1B, the coating may be applied between the polymer liner 12 and the tubular body 14 wall for further insulation and / or to protect the metal (e.g., steel) tubular body 14 from corrosion, erosion, and other wear. In certain instances, the coating 18 can also be applied to the outer surface of the tubular body 14. In certain instances, the coating 18 is an epoxy (e.g., epoxy-novolac and / or other epoxy), phenolic based coatings, and / or another type of coating. The coating 18, unlike the liner 12, is not cohesive enough to exist on its own as a tubular, and is applied as a liquid or gel to the surfaces of the tubular body 14.

[0022] Applying the insulative coating 18 over the tool joints and connections or any section that is not covered by the polymer liner 12 can have a large impact on theAttorney Docket No.50511-0085WO1 overall thermal resistance of the overall insulated wellbore tubular 10. Example thermal resistances for a(14 cm) S135 plastic formed insulated wellbore tubular 10 with a polymer thermal conductivity 0.25 W / mK: 80% length coverage by polymer liner ¼” (6mm) thick (no coating on remaining section): 0.0025 mK / W 90% length coverage by polymer liner(6mm) thick (no coating on remaining section): 0.0047 mK / W 80% length coverage by polymer liner ¼” (6mm) thick (0.9 W / mK coating on remaining section, 0.2mm thick): 0.0051 mK / W 90% length coverage by polymer liner ¼” (6mm) thick (0.9 W / mK coating on remaining section, 0.2mm thick): 0.0095 mK / W 80% length coverage by polymer liner ¼” (6mm) thick (0.2 W / mK coating on remaining section, 0.7mm thick): 0.031 mK / W 90% length coverage by polymer liner ¼” (6mm) thick (0.2 W / mK coating on remaining section, 0.7mm thick): 0.043 mK / W 100% length coverage by polymer liner ¼” (6mm) thick: 0.07 mK / W

[0023] In this example, the insulative coating over tubular body 14 which is not covered by the polymer liner 12, has a thermal conductivity < 0.4 W / mK and an average applied thickness >0.4 mm. The polymer liner 12 covers at least 80% of the length of the drill pipe joint, ideally greater than 90%.

[0024] Hydroforming

[0025] During installation of the polymer liner 12, a polymer tube is run into the tubular body 14. High pressure fluid is applied to the interior of the polymer tube, which causes the polymer to expand, deforming until it meets the larger inner diameter of the tubular body 14. This process is typically done at higher temperature when the polymer is ductile, but can also be done at ambient temperature conditions. In instances where the tool joint ends 16 have a smaller diameter than other portions of the tubular body 14, e.g., as is typical for drill pipe, the polymer liner 12 is sized, before expansion, to pass through the smaller inner diameter of the tool joint ends 16.Attorney Docket No.50511-0085WO1

[0026] The hydroforming process also secures the polymer liner 12 within the tubular body 14 as the deformed outer diameter of the polymer tube for most of the tubular body 14 length is greater than the inner diameter of the tool joints.

[0027] The hydroforming process will plastically deform the polymer, so that it maintains its deformed shape once the elevated internal pressure and temperature is removed. In ambient conditions, although it generally maintains its shape, it can thermally contract and / or relax from pressure balance relative to the hydroforming state. This process can slightly pull the polymer liner 12 away from the tubular body 14, creating a micro-annulus.

[0028] During typical operation, internal operating pressure within the wellbore tubular 10 can maintain the deformation of the polymer liner 12 and keeps it pinned against the tubular body 14. In this manner, the polymer liner 12 will flex, similar to a bladder, depending on the internal pressure and temperature conditions. In the context of drill pipe, it is typical to have high pressure fluid within which is at a much greater pressure than atmospheric that will maintain the deformation of the polymer liner 12.

[0029] Although discussed herein as “hydroforming,” the fluid used in the process need not be aqueous, and could be oil, pneumatic, and / or other fluid. Also, other manners of expanding the polymer liner 12 can be employed, such as expanding it with a die and / or bladder.

[0030] Handling thermal cycling

[0031] In operation, the wellbore tubular 10 can be exposed to high temperature, pressure, and undergo many cycles from low temperature / pressure at surface to high temperature / pressure downhole. If the wellbore tubular 10 is submerged in wellbore fluid which is at an elevated temperature (for example 150 °C), both the liner 12 and tubular body 14 will thermally expand. The linear co-efficient of thermal expansion is much higher in most polymers compared to metals. For example, the co-efficient of thermal expansion for steel may be 11 K-6, and for polymers it ranges, but may be, for example, 0.6 K-4. Therefore, polymer will expand more than steel when heated, and risks buckling as it undergoes compression.Attorney Docket No.50511-0085WO1

[0032] The polymer liner 12 may be installed in axial tension (either thermally or by mechanical stretching while hydroforming), and then secured at each end. In certain instances, the polymer liner 12 can be secured with adhesive, mechanically by crimping, a clamp, compression fitting (discussed below) or threads, and / or in another manner. Once heated, the polymer liner 12 returns to neutral or to less of a compressive state than it would have been if not installed in axial tension. The tension applied during installation is selected to prevent buckling or unwanted deformation when the wellbore tubular 10 (and thus the polymer liner 12) is heated to the maximum operating temperature.

[0033] In certain instances, the polymer of the polymer liner 12 is a thermoplastic with a melting point > 150°C, ideally > 250°C.

[0034] Sealing

[0035] Depending on the pressure and temperature of the operating environment, there may be a micro-annulus remaining between the tubular body 14 and the inner polymer liner 12. Therefore, the polymer liner 12 can be sealed at both ends so wellbore fluid cannot enter into this micro-annulus. The sealing function may be achieved by any of the below methods alone or in combination: crimping the polymer tube at the tool joint area on both ends, installing a wedged compression fitting to squeeze the polymer between the male compression wedge and the ID of the steel tube (discussed below), threaded connection, using an adhesive, and with an O-ring(s).

[0036] A small volume of liquid, gel and / or paste (e.g., oil, pipe dope, adhesive, etc.) may be placed into the micro annulus during fabrication. This has the effect of filling the contours between the polymer liner 12 and tubular body 14, and evenly counterbalancing the internal pressure during hydroforming or during operation. Therefore, the pressure differential at the sealing surfaces (between the micro annulusAttorney Docket No.50511-0085WO1 and the wellbore fluid within the wellbore tubular 10) will be lower as the expansion of the liner 12 compresses the air / liquid mixture within the micro annulus.

[0037] The polymer liner 12 may be bonded to the tubular body 14 along its entire length or just a portion of its length by adhesives (including epoxies, glues, silicones and other adhesive / bonding materials) applied between the polymer liner 12 and the inner diameter of the tubular body 14.

[0038] In certain instances, the polymer liner 12 may be thermally bonded to the metal via plastic weld. For example, the inner diameter of the tubular body 14 can be textured or a layer of textured material can be applied to its inner diameter. The polymer liner 12 is inserted into the tubular body 14, heated and pressure applied inside the liner 12 to form polymer liner 12 to the tubular body 14. The temperature to which the polymer liner 12 is heated can be selected to melt a thin layer of the polymer and bond the polymer liner 12 to the inner wall of the tubular body 14.

[0039] The adhesive bonding methods may be implemented in combination with other methods of fixating the polymer pipe to the drill wall (snap rings, threaded connection, O-ring type seal, wedged compression fitting etc.).

[0040] Wear protection of the polymer liner

[0041] As mentioned above, an internal coating on the tubular body 14 can be applied to protect it from erosion, corrosion, and abrasion. Drill pipe often has its own coating for erosion, corrosion and abrasion. In most instances, the polymer liner 12 does not require corrosion resistance. However, drilling operations may require or be conducted with a high content of solids in the drilling fluid. In some cases, wireline operations in drilling will damage the internal surface of a drill pipe, due to mechanical contact of wireline tools and cable with the drill pipe walls.

[0042] To provide longer lifespan, the interior of the polymer liner 12, after installation, can be coated with an additional layer of abrasion and erosion resistance coating 20 (FIG.1B), analogous to a drill pipe internal surface. In certain instances, the coating 20 can be an epoxy. A suitable epoxy is made by NEI Corporation and marketed under the trademark NANOMYTE.Attorney Docket No.50511-0085WO1

[0043] Alternatively, the polymer liner 12 may be a composite material with specified abrasion and erosion resistance. Some example composites include a liner 12 construction of carbon fiber and / or aramid fiber (e.g., Kevlar – a trademark of DuPont Safety & Construction, Inc.) with a wear resistant outer layer on the inner surface of the liner, abrasion resistant polyurethane as the liner 12 or an inner layer of the liner 12 (e.g., such as that produced by Industrial Screen & Maintenance), abrasion resistant polyethylene where a layer of polyester and / or aramid is provided between layers of polyethylene and / or polyvinylidene fluoride to provide the liner 12 (e.g., In-Field Liner – a trademark of Syensqo SA)

[0044] A further option may be that the coating 20 is a second liner, installed during or after the hydroforming process of the main polymer liner 12, which has higher abrasion or erosional resistance than the main polymer liner 12.

[0045] Additional support to liner

[0046] Additional mechanical support may be added to further fix the liner 12 in place during the pressure and temperature cycling.

[0047] FIG.1A shows a coiled metal shape 22, such as a spring or other helical shape, within the liner 12 or within its inner bore. The coiled shape 22 is supported to the tubular body 14 by one or more snap rings 24 that snap into groves on the inner diameter of the tubular body 14. This coiled shape 22 holds the polymer liner 12 to the tubular body 14, while simultaneously providing the ability for the polymer liner 12 to expand / contract under different temperature and pressure conditions. The coiled shape 22 is designed with a dimension that presses, into frictional contact, the polymer liner 12 with the inner diameter wall of the tubular body 14 at a desired temperature / pressure, but also enables the tubular body 14 to thermally expand without imparting a stress that would cause the tubular body 14 to buckle or undergo significant compressive forces.

[0048] FIGS.2A-2B show support applied by one or more snap rings 24 residing in a groove in the outer surface of the liner 12, which once released, spring open into corresponding grooves in the inner surface of the tubular body 14 to fix the liner 12 to the tubular body 14. The snap rings 24 can be snapped into place after or in connection with hydroforming and / or adhering the liner 12 to the tubular body 14.Attorney Docket No.50511-0085WO1

[0049] In some instances, the only mechanical support which maintains the polymer liner 12 against the inner wall of the tubular body 14 is provided by the coil spring and / or snap rings.

[0050] Wedge Compression Fittings

[0051] FIG.3 is a quarter cross-sectional view of an example insulated tubular 10, before hydroforming, having a wedge compression fitting 30. The compression fitting 30 is annular and has a wedge surface 32 on its outer diameter. The wedge surface 32 has an increasing diameter from the wedge fitting’s 30 leading end toward a shouldered end stop 34 at an opposing edge of the wedge fitting 30. The wedge surface 32 is configured to clamp the polymer liner 12 against the inner wall of the tubular body 14, and frictionally engage both the wedge fitting 30 and polymer liner 12 to the tubular body 14, when the wedge fitting 30 is driven over the interface between the polymer liner 12 and tubular body 14. The degree of wedge in the wedge surface 32 is configured to affix the polymer liner 12 to the tubular body 14 so that the two form a liquid tight seal and do not separate during operating conditions in a wellbore, despite thermal expansion and contraction of the tubular body 14. The end stop 36 is positioned to abut the tubular body 14 at the tool joint end 16, and itself be clamped between two mating tool joint ends 16 of adjacently coupled joints of wellbore tubular 10.

[0052] In construction, the wedge fittings 30 are installed at top and bottom of the tubular 10, before the polymer liner 12 has been hydroformed to the tubular body 14. FIG.4 shows pressure (P) being applied to the polymer liner 12 in connection with the hydroforming, and the soon to be final location of the polymer liner 12 (in dashed line) after the hydroforming.

[0053] The insulated wellbore tubular 10 can be useful in drilling and completing geothermal well systems, including conventional geothermal wells (where a well is drilled to access hot, subsurface water reservoirs), enhanced geothermal systems (EGS) (where an inlet and outlet wellbore are linked by factures and fluid is circulated to heat the fluid), and closed loop systems / advanced geothermal systems (AGS) (where an inlet and outlet wellbore intersect and fluid is circulated to heat the fluid). In certain instances, the wellbore tubular 10 can be used as the insulated tubing in the drilling processesAttorney Docket No.50511-0085WO1 described in WO2024 / 231758, filed April 13, 2024, and entitled “Temperature Management of Drill String Components” and can be used in drilling closed loop geothermal systems such as those disclosed in this application.

[0054] Examples

[0055] A well in the Haynesville Shale, 25,000 ft (7.6km)

[0056] Cooling:

[0057] Generic Haynesville type well (bottomhole formation temperature ~325°F (163° C), 26,000ft (7.9km) MD, 13,000 (4km) TVD, 8.5” (21.5cm) hole, OBM 1.85 SG). 5 ½” (14cm) S135 pipe with 4.78” (12mm) ID. Inlet temperature of 90°F (32° C).

[0058] Bottomhole circulating temperature at 7500 psi (52 MPa) standpipe pressure: Regular drill pipe as tubular body 14: 345°F (174°C) @ 600GPM Inner diameter coated insulated drill pipe: 300°F (149°C) @ 600 GPM Dual wall insulated drill pipe (3.5” (9cm) ID and 0.05 W / mK thermal resistance): 280°F (138°C) @ 350 GPM https: / / www.osti.gov / servlets / purl / 765147 (assumed 5.5” (14cm) OD and 3.5” (8.9cm) ID – dual wall pipe from paper is 5” (12.7cm) OD and 3.068” (7.8cm) ID) Insulated drill pipe with thermoplastic liner, similar to insulated wellbore tubular 10, ¼” (6mm) thick (0.035 mK / W thermal resistance): 240°F (115°C) @ 500 GPM

[0059] Weight:

[0060] Since the polymer liner 12 in the drill pipe has a similar density to the drilling fluid, the insulated drill pipe with polymer liner (example insulated tubular 10) weighs substantially less when submerged (wet weight) than other dual-wall pipe designs with a metallic inner tubing. The insulated drill pipe with polymer liner (example insulated tubular 10) adds <10% to the wet weight (in drilling mud between 1-2 S.G.) of the pipe relative to an equivalent standard API drill pipe, and ideally < 5%.

[0061] The additional weight of the inner tubing string in a typical dual wall insulated drill pipe design can add >30% wet weight per unit length in heavy mud (~2Attorney Docket No.50511-0085WO1 S.G.) and nearly 50% in water or balanced drilling fluid (~ 1 S.G.), which can limit the TVD / MD reach based on rig limits (and / or limit reach based on pipe strength if the inner tube is not load bearing).

[0062] For example, a dual wall drill pipe based on the specifications from https: / / www.osti.gov / servlets / purl / 765147, the specific weight is 33lb / ft (49 kg / m) vs standard equivalent drill pipe of 19.5lb / ft (19.5kg / m).

[0063] A number of embodiments of the invention have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the invention. Accordingly, other embodiments are within the scope of the following claims.

Claims

Attorney Docket No.50511-0085WO1 WHAT IS CLAIMED IS:

1. An insulated wellbore tubular, comprising: a metallic tubular body; and a polymer liner formed to the interior of the metallic tubular body, the polymer liner having a specified thermal resistance to heat transfer through the polymer liner that is higher than the thermal resistance to heat transfer through the metallic tubular body.

2. The insulated wellbore tubular of claim 1, where the metallic tubular body comprises drill pipe.

3. The insulated wellbore tubular of claims 1 or 2, comprising a wedge compression fitting on an edge of the polymer liner covering the joint between the polymer liner and the metallic tubular body.

4. The insulated wellbore tubular of any of claims 1 to 3, comprising a helical metal shape supporting the inner diameter of the polymer liner.

5. The insulated wellbore tubular of any of claims 1 to 4, where the polymer liner is hydroformed to the inner diameter of the metallic tubular body.

6. The insulated wellbore tubular of any of claims 1 to 5, where the polymer liner has a dry density of less than 2000 kg / m3.

7. The insulated wellbore tubular of any of claims 1 to 6, where the length normalized thermal resistance of the polymer liner is at least 0.02 m K / W.

8. The insulated wellbore tubular of any of claims 1 to 7, where the polymer has a melting point greater than 150°C.

9. The insulated wellbore tubular of any of claims 1 to 8, where the polymer liner comprises a thermoplastic.

10. The insulated wellbore tubular of any of claims 1 to 9, where the polymer liner is adhered to the inner diameter of the metallic tubular body.

11. The insulated wellbore tubular of any of claims 1 to 10, comprising tool joint ends configured for connection to another wellbore tubular and where the tool joint ends are coated in an insulative coating having a thermal conductivity of .9 W / mK or less.Attorney Docket No.50511-0085WO1 12. A method, comprising: providing a polymer liner within a metallic tubular body configured for use in a wellbore; and hydroforming the polymer liner to the interior diameter of the metallic tubular body.

13. The method of claim 12, where the metallic tubular body comprises drill pipe.

14. The method of claims 12 or 13, comprising driving a wedge compression fitting over an edge of the polymer liner, covering the joint between the polymer liner and the metallic tubular body.

15. The method of any of claims 12 to 14, where the polymer liner has a dry density of less than 2000 kg / m3.

16. The method of any of claims 12 to 15, where the length normalized thermal resistance of the polymer liner is at least 0.02 m K / W.

17. The method of any of claims 12 to 16, where the polymer is adhered to the inner diameter of the metallic tubular body.

18. A drilling string, comprising: a metallic drill pipe; and a polymer liner formed to the interior of the metallic drill pipe, the polymer liner having a specified thermal resistance to heat transfer through the polymer liner that is higher than the thermal resistance to heat transfer through the drill pipe.

19. The drilling string of claim 18, polymer liner has a dry density of less than 2000 kg / m3.

20. The drilling string of claim 18 or 19, where the thermal resistance through the drilling string is 0.0051 mK / W.

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