RELATED APPLICATIONS

[001] The present application claims the benefit of Unites States Provisional Patent Application Serial No. 63/112,588 filed November 11, 2020, entitled, “Advanced Insulation and Jacketing for Downhole Power and Motor Lead Cables,” the disclosure of which is herein incorporated by reference.

FIELD OF THE INVENTION

[002] The present invention relates generally to electric submersible pumping systems and more particularly to the insulation of electric conductors used in downhole electric submersible pumping systems.

BACKGROUND

[003] Submersible pumping systems are often deployed into wells to recover petroleum fluids from subterranean reservoirs. Typically, a submersible pumping system includes a number of components, including an electric motor coupled to one or more high performance pump assemblies. Production tubing is connected to the pump assemblies to deliver the petroleum fluids from the subterranean reservoir to a storage facility on the surface.

[004] The motor is typically an oil-filled, high capacity electric motor that can vary in length from a few feet to nearly one hundred feet, and may be rated up to hundreds of horsepower. Typically, electricity is generated on the surface and supplied to the motor through a heavy-duty power cable. The power cable typically includes several separate conductors that are individually insulated within the power cable. Power cables are often constructed in round or flat configurations.

[005] In many applications, power is conducted from the power cable to the motor via a

“motor lead cable.” The motor lead cable typically includes one or more “leads” that are configured for connection to a mating receptacle on the motor. The leads from the motor lead cable are often retained within a motor-connector that is commonly referred to as a "pothead." The pothead relieves the stress or strain realized between the motor and the leads from the motor lead cable. Motor lead cable is often constructed in a “flat” configuration for use in the limited space between downhole equipment and the well casing.

[006] Because the power and motor lead cables are positioned in the annulus between the production string and well casing, these cables must be designed to withstand the inhospitable downhole environment. Prior art cables often fail over time as corrosive well fluids degrade the various layers of insulation placed around the electrical conductors. Without sufficient insulation, the high-capacity power and motor lead cables become susceptible to electrical malfunctions that cause irreparable damage to the cable and downhole equipment.

[007] Power and motor lead cables typically include a conductor, insulation surrounding the conductor, a lead jacket encasing the insulator, and a durable external armor that surrounds the jacket. Although covered by several layers of protection, the insulation remains a common source of failure in power and motor lead cables. In the past, manufacturers have used EPDM rubber, polypropylene or polyethylene as the dielectric insulation layer that surrounds the conductive material. [008] In certain applications, the presence of hydrogen sulfide (H2S) in the wellbore can accelerate corrosion and other attacks on the conductor (carcass) of the cable. In the past, extruded lead has been used as a barrier to protect the copper conductor from H2S attack. Lead can be toxic to humans and animals and carries certain health and safety concerns. Additionally, lead is heavy and increases the costs associated with manufacturing, packaging, shipping, and handling. Furthermore, lead is a soft metal that can be mechanically damaged, which may compromise its ability to provide a barrier function. Accordingly, there is a need for an improved cable design for use in power and motor lead cables that provides adequate resistance from H2S and other corrosive compounds in downhole environments. It is to these and other deficiencies in the prior art that exemplary embodiments of the present invention are directed.

SUMMARY OF THE INVENTION

[009] In one aspect, embodiments of the present invention include an electric submersible pumping system configured for operation in downhole applications. The electric submersible pumping system includes a motor, a pump driven by the motor, and a cable that provides electrical power to the motor. The cable includes a conductor and an insulator surrounding the conductor. The insulator includes a first layer surrounding the conductor and a second layer surrounding the first layer. The second layer comprises an H2S scavenger. The first layer may also include an H2S reactant.

[010] In another aspect, embodiments of the present invention include an electric submersible pumping system configured for operation in downhole applications. The electric submersible pumping system includes a motor, a pump driven by the motor, and a cable that provides electrical power to the motor. The cable includes a conductor and an insulator surrounding the conductor. The insulator includes a first layer and a second layer surrounding the first layer. The cable further includes a sub-insulator layer between the conductor and the insulator. The sub-insulator layer comprises a coating applied directly to the conductor. In some embodiments, the coating is a metal coating. In other embodiments, the coating is a nitride coating.

[OH] In another aspect, the present disclosure is directed to a cable for use in an electric submersible pumping system configured for operation in downhole applications. The cable has a conductor, an insulator surrounding the conductor, and a sub-insulator layer between the insulator and the conductor. The insulator includes a first layer and a second layer surrounding the first layer. The insulator has an H2S scavenger in the first or second layer of the insulator and an H2S reactant in the first or second layer of the insulator. The sub-insulator layer is applied directly to the conductor and may include metal and nitride-based coatings.

BRIEF DESCRIPTION OF THE DRAWINGS

[012] FIG. 1 is a back view of a downhole pumping system constructed in accordance with an embodiment of the present invention.

[013] FIG. 2 is a perspective view of the power cable of the downhole pumping system of FIG. 1.

[014] FIG. 3 is a perspective view of the motor lead cable of the downhole pumping system of FIG. 1.

[015] FIG. 4 is a cross-sectional view of the conductor and two-layer insulator of one or both of the power cable and motor lead cable of FIG. 1. [016] FIG. 5 is a cross-sectional view of the conductor and three-layer insulator of one or both of the power cable and motor lead cable of FIG. 1.

[017] FIG. 6 is a cross-sectional view of the conductor and one-layer insulator of one or both of the power cable and motor lead cable of FIG. 1.

[018] FIG. 7 is a cross-sectional view of an embodiment in which a sub-insulator layer is located between the conductor and a two-layer insulator.

[019] FIG. 8 is a cross-sectional view of an embodiment in which a sub-insulator layer is located between the conductor and a three-layer insulator.

[020] FIG. 9 is a cross-sectional view of an embodiment in which a sub-insulator layer is located between the conductor and a one-layer insulator.

WRITTEN DESCRIPTION

[021] In accordance with an exemplary embodiment of the present invention, FIG. 1 shows a front perspective view of a downhole pumping system 100 attached to production tubing 102. The downhole pumping system 100 and production tubing 102 are disposed in a wellbore 104, which is drilled to produce a fluid such as water or petroleum. The downhole pumping system 100 is shown in a non-vertical well. This type of well is often referred to as a “horizontal” well. Although the downhole pumping system 100 is depicted in a horizontal well, it will be appreciated that the downhole pumping system 100 can also be used in vertical wells.

[022] As used herein, the term "petroleum" refers broadly to all mineral hydrocarbons, such as crude oil, gas and combinations of oil and gas. The production tubing 102 connects the pumping system 100 to a wellhead 106 located on the surface. Although the pumping system 100 is primarily designed to pump petroleum products, it will be understood that the present invention can also be used to move other fluids. It will also be understood that, although each of the components of the pumping system 100 are primarily disclosed in a submersible application, some or all of these components can also be used in surface pumping operations. It will be further understood that the pumping system 100 is well-suited for use in high-temperature applications, including steam-assisted gravity drainage (SAGD) and geothermal applications, where downhole temperatures may exceed 250 °C, or where the concentration of hydrogen sulfide (H2S) gas is high.

[023] The pumping system 100 includes a pump 108, a motor 110 and a seal section 112. The motor 110 is an electric motor that receives its power from a surface-based supply through a power cable 114 and motor lead cable 116. In many embodiments, the power cable 114 and motor lead cable 116 are each configured to supply the motor 110 with three-phase power from a surface-based variable speed (or variable frequency) drive 118. As used herein, the generic reference to “cable” refers to both the power cable 114 and the motor lead cable 116.

[024] The motor 110 converts the electrical energy into mechanical energy, which is transmitted to the pump 108 by one or more shafts. The pump 108 then transfers a portion of this mechanical energy to fluids within the wellbore, causing the wellbore fluids to move through the production tubing 102 to the surface. In some embodiments, the pump 108 is a turbomachine that uses one or more impellers and diffusers to convert mechanical energy into pressure head. In other embodiments, the pump 108 is a progressive cavity (PC) or positive displacement pump that moves wellbore fluids with one or more screws or pistons. [025] The seal section 112 shields the motor 110 from mechanical thrust produced by the pump 108. The seal section 112 is also configured to prevent the introduction of contaminants from the wellbore 104 into the motor 110. Although only one pump 108, seal section 112 and motor 110 are shown, it will be understood that the downhole pumping system 100 could include additional pumps 108, seal sections 112 or motors 110.

[026] Referring now to FIGS. 2 and 3, shown therein are perspective views of a round power cable 114 and a flat motor lead cable 116, respectively. It will be understood that the geometric configuration of the power cable 114 and motor lead cable 116 can be selected on an application specific basis. Generally, flat cable configurations, as shown in FIG. 3, are used in applications where there is a limited amount of annular space around the pumping system 100 in the wellbore 104. In the exemplary embodiments depicted in FIGS. 2 and 3, the power cable 114 and motor lead cable 116 each include one or more conductors 120, one or more insulators 122, a jacket 124 and external armor 126.

[027] In exemplary embodiments, the conductors 120 are manufactured from copper and may include a solid core (as shown in FIG. 2), a stranded core, or a stranded exterior surrounding a solid core (as shown in FIG. 3). The jacket 124 is protected from external contact by the armor 126. The armor 126 can be manufactured from galvanized steel, stainless steel, Monel or other suitable metal or composite material.

[028] The insulators 122 are configured to electrically isolate the conductors 120, while providing increased resistance to H2S and other corrosive or oxidative compounds potentially present in the wellbore 104. Turning to FIGS. 4-6, shown therein are cross- sectional views of various embodiments of the conductor 120 and insulator 122. In the embodiment depicted in FIG. 4, the insulator 122 includes an interior first layer 128 and an exterior second layer 130. In the embodiment depicted in FIG. 5, the insulator includes an intermediate third layer 132 in addition to the first and second layers 128, 130. In the embodiment depicted in FIG. 6, the insulator 122 includes only the first layer 128. It will be appreciated that the jacket 124 and armor 126 have been removed from the cross-sectional depictions in FIGS. 4-6. As explained below, various embodiments include improved insulators 122 that improve the resistance of the cables 114, 116 to attack by H2S and other corrosive compounds.

[029] In a first embodiment, the insulator 122 includes a polymer-based reactive barrier configured to neutralize or mitigate H2S and CO2 to prevent contamination or corrosion of the conductor 120. In this first embodiment, the insulator 122 includes at least two layers of insulation. The first (inner) layer 128 is a polymer layer that has been compounded with an H2S reactant. Suitable H2S reactive compounds (reactants) include zinc oxide (ZnO), ferric oxide (Fe2O3), and zirconium oxide (ZrCE). Suitable polymers include EPDM, PP/EPDM, fluoroplastics, including PEEK, PEKK, PAEK, polyimide, PF A, PTFE, PSU, cross-linked fluoropolymers, and other high-temperature polymers. Upon contact with EES, the EES reactive compounds within the first layer 128 convert the EES to metallic sulfide, which acts as an inert, non-corrosive filler on the conductor 120, within the first layer 128 or between the conductor 120 and the first layer 128.

[030] The second (outer) layer 130 includes a polymer layer that has been compounded with EES scavengers. Suitable polymers include EPDM, PPZEPDM, fluoroplastics, including PEEK, PEKK, PAEK, polyimide, PFA, PTFE, PSU, cross-linked fluoropolymers, and other high-temperature polymers. Suitable H2S scavengers include triazines, ammonium -bi sulphite, ferrous gluconate, zinc, lead oxide, tin oxide, iron oxide, and zirconium oxide. In some embodiments, the H2S scavengers include the sodium salts of triazoles, which can be water soluble and incorporated into a polymer matrix. Suitable sodium salts of triazoles include benzotri azole, tolyltri azole, tetrahydrobenzotriazole, and butylbenzotri azole. The H2S scavengers are optionally configured to provide a delayed release from the high-temperature polymer selected for the second layer 130. The extended, controlled release of the H2S scavenger will prolong the life of the conductor 120. If H2S passes through the H2S scavenger layer, the remaining H2S is converted to metallic sulfide by the H2S reactive layer, as discussed above.

[031] It will be appreciated that the same chemicals can be used for both the H2S reactants and H2S scavengers. In some embodiments, the H2S reactants and H2S scavengers. Suitable formulations for one or both of the first layer 128 and the second layer 130 include, but are not limited to, the following formulations (expressed on a “by weight” percentage):

[032] Thus, in this first embodiment, the insulator 122 includes an outer polymer layer

130 that includes one or more H2S scavenger components, and an inner polymer layer 128 that includes one or more H2S reactive components. It will be appreciated that the first and second layers 128, 130 can each constitute multiple extruded layers, multiple layers of film arranged in cross-ply or stacked configurations, or combinations of extruded and wrapped layers. The use of cross-ply wrapped layers may increase the mechanical strength of the power or motor lead cable 114, 116. The use of multiple barrier layers within insulator 122 with H2S scavengers and H2S reactants presents a cost- effective and safer alternative to the conventional use of lead-based insulation.

[033] In a second embodiment, the insulator 122 includes multiple layers of inert and reactive polymers that provide electrical insulation and chemical resistance for the conductor 120. The first (inner) layer 128 is manufactured from a polyarylether ketone (PAEK) polymer. The first layer 128 can be between about 0.1 mm and 2.0 mm in thickness. A thickness of the first layer 128 of about 0.9 mm works well for several embodiments. Suitable polymers for the first layer 128 include poly ether ether ketone (PEEK) polymers and polyether ketone ketone (PEKK) polymers, which are widely available from a variety of sources.

[034] The insulator 122 includes a second (outer) layer 130 manufactured from a polymer that has been compounded with H2S scavengers. Suitable polymers include perfluoroalkoxy polymer (PFA) and suitable H2S scavengers include triazines, ammonium -bi sulphite, ferrous gluconate, and other H2S scavengers disclosed herein. The H2S scavengers are optionally configured to provide a delayed release from the high- temperature polymer selected for the second layer 130. The extended, controlled release of the H2S scavenger will prolong the life of the conductor 120. The second (outer) layer 130 can have a thickness of about 0.5 mm to about 2.0 mm. A second layer 130 with a thickness of about 1.0 mm works well for many embodiments of the insulator 122.

[035] The insulator 122 includes a third (intermediate) layer 132 that is manufactured from a chemically inert polymer. The third layer 132 can be manufactured from a fluoroplastic polymer and can have a thickness of between about 0.5 mm and about 2.0 mm. A third layer 132 with a thickness of about 0.8 mm works well for many embodiments of the insulator 122. Suitable polymers for the second layer 130 include commercially available PFA polymers, which are then treated with zinc oxides either by compounding (impregnation) or layered coating processing.

[036] Thus, in this second embodiment, the insulator 122 includes an inner layer, an intermediate layer, and an outer layer that has been compounded with one or more H2S scavengers to mitigate the impact of sour gas and other corrosive downhole chemicals.

[037] In a third embodiment, the insulator 122 includes a combination of polymer layers that defends the conductor 120 against attack from corrosive chemicals like H2S, CO2, water, and methane. In this embodiment, the first layer 128 is manufactured from polyether ether ketone (PEEK) polymer. The second layer 130 is manufactured from an extruded layer of high-temperature crystallized fluoroplastics. In some embodiments, the second insulation layer 130 is manufactured from a perfluoropolymer resin that undergoes a positive melt point shift upon crystallization.

[038] The second layer 130 provides favorable electrical insulating properties, chemical resistance properties and resistance to permeation by methane, oxygen, and carbon dioxide gases at temperatures around about 300 °C. Suitable perfluoropolymers are available from a variety of sources. [039] In a fourth embodiment, the jacket 124 is manufactured from zinc or zinc alloys. The use of a zinc-based jacket 124 presents a significant advantage over traditional leadbased jackets and sheathes, which are heavy and present health and safety concerns during manufacture and handling. The zinc-based jacket 124 can be used in combination with any of the embodiments of the insulator 122 disclosed above.

[040] Turning to FIGS. 7-9, shown therein are cross-sectional views of additional embodiments in which an additional sub-insulator layer 134 has been placed over the conductor 120 and beneath the insulator 122. The sub-insulator layer 134 (or “fourth layer 134”) is located between the metal conductor 120 and the first layer 128. It will be appreciated that the sub-insulator layer 134 is not shown to scale in FIGS. 7-9.

[041] In one embodiment, the sub-insulator layer 134 is formed by electroplating the copper conductor 120 with a substantially continuous metal coating. In other embodiments, the sub-insulator layer 134 is produced by wrapping metal tape, foil or cladding around the copper conductor 120. In each case, the sub-insulator layer 134 is formed from a corrosion-resistant material. Suitable metals for the sub-insulator layer 134 include tin, tin/nickel alloys, tin/lead alloys, tin/indium alloys, silver, aluminum, tungsten, molybdenum, tantalum, Inconel, and other nickel-chromium based alloys.

[042] In other embodiments, the sub-insulator layer 134 is prepared by coating the conductor 120 with a nitride compound, such as boron nitride, carbon nitride, aluminum nitride, tin nitride, and silicon nitride. The additional sub-insulator layer 134 will further mitigate corrosion and breakdown caused by an interaction between wellbore contaminants (like H2S) and the copper conductor 120. [043] Several embodiments have been disclosed for improving the construction of power cables 114 and motor lead cables 116. Although various features have been disclosed as independent embodiments, it will be understood that features from different embodiments can be used together in new combinations. For example, the various first, second and third layers 128, 130, 132 of the insulator 122 can be interchanged between embodiments, such that the prescribed first layer 128 from one embodiment can be used in concert with the second layer 130 from another embodiment. The optional subinsulator layer 134 can be incorporated into any of the embodiments disclosed herein to further improve the corrosion resistance of the power cables 114 and motor lead cables 116.

[044] It is to be understood that even though numerous characteristics and advantages of various embodiments of the present invention have been set forth in the foregoing description, together with details of the structure and functions of various embodiments of the invention, this disclosure is illustrative only, and changes may be made in detail, especially in matters of structure and arrangement of parts within the principles of the present invention to the full extent indicated by the broad general meaning of the terms in which the appended claims are expressed. It will be appreciated by those skilled in the art that the teachings of the present invention can be applied to other systems without departing from the scope and spirit of the present invention.