WO2020167413A1 - Tige de pompage résistante à la corrosion et à l'abrasion - Google Patents

Tige de pompage résistante à la corrosion et à l'abrasion Download PDF

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Publication number
WO2020167413A1
WO2020167413A1 PCT/US2020/014094 US2020014094W WO2020167413A1 WO 2020167413 A1 WO2020167413 A1 WO 2020167413A1 US 2020014094 W US2020014094 W US 2020014094W WO 2020167413 A1 WO2020167413 A1 WO 2020167413A1
Authority
WO
WIPO (PCT)
Prior art keywords
resistant layer
sucker rod
abrasion resistant
corrosion resistant
particulate material
Prior art date
Application number
PCT/US2020/014094
Other languages
English (en)
Inventor
Robert P. Badrak
Original Assignee
Weatherford Technology Holdings, Llc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Weatherford Technology Holdings, Llc filed Critical Weatherford Technology Holdings, Llc
Priority to MX2021009809A priority Critical patent/MX2021009809A/es
Priority to EP20704988.3A priority patent/EP3924594A1/fr
Priority to CA3126809A priority patent/CA3126809A1/fr
Publication of WO2020167413A1 publication Critical patent/WO2020167413A1/fr
Priority to CONC2021/0009579A priority patent/CO2021009579A2/es

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/10—Wear protectors; Centralising devices, e.g. stabilisers
    • E21B17/1071—Wear protectors; Centralising devices, e.g. stabilisers specially adapted for pump rods, e.g. sucker rods
    • C—CHEMISTRY; METALLURGY
    • C23—COATING METALLIC MATERIAL; COATING MATERIAL WITH METALLIC MATERIAL; CHEMICAL SURFACE TREATMENT; DIFFUSION TREATMENT OF METALLIC MATERIAL; COATING BY VACUUM EVAPORATION, BY SPUTTERING, BY ION IMPLANTATION OR BY CHEMICAL VAPOUR DEPOSITION, IN GENERAL; INHIBITING CORROSION OF METALLIC MATERIAL OR INCRUSTATION IN GENERAL
    • C23F—NON-MECHANICAL REMOVAL OF METALLIC MATERIAL FROM SURFACE; INHIBITING CORROSION OF METALLIC MATERIAL OR INCRUSTATION IN GENERAL; MULTI-STEP PROCESSES FOR SURFACE TREATMENT OF METALLIC MATERIAL INVOLVING AT LEAST ONE PROCESS PROVIDED FOR IN CLASS C23 AND AT LEAST ONE PROCESS COVERED BY SUBCLASS C21D OR C22F OR CLASS C25
    • C23F11/00—Inhibiting corrosion of metallic material by applying inhibitors to the surface in danger of corrosion or adding them to the corrosive agent
    • C23F11/08—Inhibiting corrosion of metallic material by applying inhibitors to the surface in danger of corrosion or adding them to the corrosive agent in other liquids
    • C23F11/10—Inhibiting corrosion of metallic material by applying inhibitors to the surface in danger of corrosion or adding them to the corrosive agent in other liquids using organic inhibitors
    • C23F11/173—Macromolecular compounds
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/10—Wear protectors; Centralising devices, e.g. stabilisers
    • E21B17/1085—Wear protectors; Blast joints; Hard facing
    • C—CHEMISTRY; METALLURGY
    • C23—COATING METALLIC MATERIAL; COATING MATERIAL WITH METALLIC MATERIAL; CHEMICAL SURFACE TREATMENT; DIFFUSION TREATMENT OF METALLIC MATERIAL; COATING BY VACUUM EVAPORATION, BY SPUTTERING, BY ION IMPLANTATION OR BY CHEMICAL VAPOUR DEPOSITION, IN GENERAL; INHIBITING CORROSION OF METALLIC MATERIAL OR INCRUSTATION IN GENERAL
    • C23C—COATING METALLIC MATERIAL; COATING MATERIAL WITH METALLIC MATERIAL; SURFACE TREATMENT OF METALLIC MATERIAL BY DIFFUSION INTO THE SURFACE, BY CHEMICAL CONVERSION OR SUBSTITUTION; COATING BY VACUUM EVAPORATION, BY SPUTTERING, BY ION IMPLANTATION OR BY CHEMICAL VAPOUR DEPOSITION, IN GENERAL
    • C23C30/00—Coating with metallic material characterised only by the composition of the metallic material, i.e. not characterised by the coating process
    • C23C30/005—Coating with metallic material characterised only by the composition of the metallic material, i.e. not characterised by the coating process on hard metal substrates

Definitions

  • This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in an example described below, more particularly provides a corrosion and abrasion resistant sucker rod.
  • a sucker rod is typically used to transmit work from an actuator at surface to a downhole pump in a well.
  • the actuator may reciprocate or rotate the sucker rod (or both) to operate the downhole pump.
  • a single sucker rod may extend substantially an entire distance from the surface actuator to the downhole pump (typically thousands of meters), in which case the sucker rod is of the type known to those skilled in the art as a “continuous” sucker rod.
  • many sucker rods e.g., having lengths of ⁇ 20-30 ft. or 6-9 m may be connected together, in order to extend the distance between the surface actuator and the downhole pump.
  • FIG. 1 is a representative partially cross-sectional view of an example of a well system and associated method which can embody principles of this disclosure.
  • FIG. 2 is a representative schematic view of an example of a sucker rod surface treatment method which can embody the principles of this disclosure.
  • FIG. 3 is a representative schematic view of another example of the sucker rod surface treatment method.
  • FIG. 4 is a representative perspective view of a sucker rod treated using the FIG. 3 method.
  • FIG. 5 is a representative schematic view of another example of the sucker rod surface treatment method.
  • FIG. 6 is a representative perspective view of a sucker rod treated using the FIG. 5 method.
  • FIG. 7 is a representative schematic view of another example of the sucker rod surface treatment method.
  • FIG. 8 is a representative perspective view of a sucker rod treated using the FIG. 7 method.
  • FIG. 1 Representatively illustrated in FIG. 1 is a system 10 and associated method for use with a subterranean well, which system and method can embody principles of this disclosure.
  • a walking beam-type surface pumping unit 12 is mounted on a pad 14 adjacent a wellhead 16.
  • a rod string 18 extends into the well and is connected to a downhole pump 20 in a tubing string 22. Reciprocation of the rod string 18 by the pumping unit 12 causes the downhole pump 20 to pump fluids (such as, liquid hydrocarbons, gas, water, etc., and combinations thereof) from the well through the tubing string 22 to surface.
  • fluids such as, liquid hydrocarbons, gas, water, etc., and combinations thereof
  • the pumping unit 12 as depicted in FIG. 1 is of the type known to those skilled in the art as a“conventional” pumping unit.
  • a“conventional” pumping unit Flowever, in other examples, other types of walking beam pumping units (such as, those known to persons skilled in the art as Mark II, reverse Mark, beam-balanced and end-of-beam pumping units), hydraulic, rotary or other types of pumping units may be used.
  • the pumping unit 12 or other actuator may rotate the rod string 18 instead of, or in addition to, reciprocating the rod string.
  • the scope of this disclosure is not limited to use of any particular type or configuration of pumping unit.
  • the rod string 18 may comprise a substantially continuous rod, or may be made up of multiple connected together rods (also known as“sucker rods”).
  • a polished rod 24 extends through a stuffing box 26 on the wellhead 16.
  • An outer surface of the polished rod 24 is finely polished to avoid damage to seals in the stuffing box 26 as the polished rod reciprocates upward and downward through the seals.
  • a carrier bar 28 connects the polished rod 24 to a bridle 30.
  • the bridle 30 in this example comprises multiple cables that are secured to and wrap partially about a horsehead end of a beam of the pumping unit 12.
  • a hydraulic actuator, a motor or another type of actuator may be used to displace the polished rod 24 and the remainder of the rod string 18.
  • the rod string 18 includes the polished rod 24, the sucker rod(s) 32 and any adapters/connectors used to operatively connect the rod string to the downhole pump 20.
  • the sucker rod 32 is exposed to fluids in the tubing, which may include corrosive agents (such as, acid gases in the production stream, CO2 and/or H 2 S). This can lead to eventual failure, or the need to more frequently replace the sucker rod 32.
  • the sucker rod 32 is subject to damage due to shipping and handling, installation in the well and the pumping operation. If a corrosion resistant coating has been applied to the sucker rod 32, the coating could be breached by impacts, wear and abrasion at any point during shipping, handling, installation and operation. It would be beneficial to be able to protect a corrosion resistant layer on a sucker rod from such damage.
  • FIG. 2 an example of a sucker rod surface treatment method 34 is representatively illustrated in schematic form.
  • the sucker rod 32 depicted in FIG. 2 may be used in the system 10 and method of FIG. 1 , or it may be used in other systems and methods.
  • the sucker rod 32 traverses multiple stations 36, 38, 40, 42, 44, 46 of a surface treatment system 48 as part of, or subsequent to, manufacture of the sucker rod.
  • the surface treatment system 48 may include other stations, other numbers of stations and different
  • the method 34 may be performed prior to, or after, a base metal of the sucker rod 32 is in its final form.
  • the method 34 may be performed for sucker rod 32 that is otherwise ready for installation in a well, or as part of initial manufacture of the sucker rod.
  • the input drive 36 is used to displace the sucker rod 32 through the other stations 40, 42, 44, 46.
  • An output drive 38 may be used instead of, or in addition to, the input drive 36. If the surface treatment method 34 is part of an overall manufacturing operation, separate drives 36, 38 may not be included in the surface treatment system 48.
  • the sucker rod 32 displaces from left to right through the stations 40, 42, 44, 46 as viewed in FIG. 2. Thus, the sucker rod 32 displaces first through the surface preparation station 40 (after the input drive 36, if included), then through the heating station 42 and application stations 44, 46.
  • the surface preparation station 40 in the FIG. 2 example includes an abrader 50, a cleaner 52 and a dryer 54. In other examples, other or different elements may be used in the surface preparation station 40, or the surface preparation station may not be used or may be integrated with one or more other stations.
  • the abrader 50 removes surface debris and any rust, and provides surface roughness for enhanced adherence of coatings, extrusions, layers, bonds, etc. later applied in the method 34.
  • the cleaner 52 removes undesired chemicals or other substances from the sucker rod surface.
  • the cleaner 52 may use solvents, detergents or other cleaning agents for this purpose.
  • the dryer 54 removes any remaining cleaner and any undesired particulate matter or other debris from the surface of the sucker rod 32.
  • the dryer 54 may produce a forced air flow, whether or not the air is also heated.
  • the heating station 42 in the FIG. 2 example includes an induction heater 56.
  • other types of heaters may be used, or the heater 56 may be integrated with one or more other stations (such as, one or both of the application stations 44, 46).
  • the application station 44 applies a corrosion resistant layer to the sucker rod 32.
  • the corrosion resistant layer is applied directly to the base metal of the sucker rod 32, but in other examples a primer, an adhesive, a sealer or another type of layer may be applied to the base metal prior to the corrosion resistant layer being applied.
  • the corrosion resistant layer may be applied using a spray or powder coating technique.
  • the corrosion resistant layer may comprise a thermosetting polymer material (such as a fusion bond epoxy), in which case the heat provided by the heating station 42 is selected to cause the material to form a coating that completely encloses the base metal of the sucker rod 32.
  • the sucker rod 32 could be dipped or wrapped in a corrosion resistant material as the sucker rod passes through the application station 44.
  • the corrosion resistant layer could be extruded onto the base metal of the sucker rod 32.
  • the scope of this disclosure is not limited to any particular technique for incorporating the corrosion resistant layer into the sucker rod 32.
  • the application station 46 applies an abrasion resistant layer to the sucker rod 32.
  • the abrasion resistant layer is applied directly to the corrosion resistant layer of the sucker rod 32, but in other examples a primer, an adhesive, a sealer or another type of layer may be applied to the corrosion resistant layer prior to the abrasion resistant layer being applied.
  • the abrasion resistant layer may be applied using a spray or powder coating technique.
  • the abrasion resistant layer may comprise a thermosetting polymer material (such as, a phenolic or a phenolic and fusion bond epoxy composition), in which case the heat provided by the heating station 42 is selected to cause the material to form a coating that completely encloses the corrosion resistant layer of the sucker rod 32.
  • the sucker rod 32 could be dipped or wrapped in an abrasion resistant material as the sucker rod passes through the application station 46.
  • the abrasion resistant layer could be extruded onto the corrosion resistant layer.
  • the scope of this disclosure is not limited to any particular technique for incorporating the abrasion resistant layer into the sucker rod 32.
  • the abrasion resistant layer protects the corrosion resistant layer against damage due to impacts, wear and abrasion.
  • the abrasion resistant layer can in some examples reduce friction between the sucker rod 32 and the tubing string 22 during operation.
  • FIGS. 3 & 4 another example of the surface treatment system 48 and method 34 is representatively illustrated, along with an example sucker rod 32 produced by the system and method.
  • the stations 40, 42, 44, 46 are depicted in simplified form.
  • the input and output drive stations 36, 38 are not depicted in FIG. 3, but could be included if desired.
  • the sucker rod 32 is depicted with both of the corrosion resistant layer 58 and the abrasion resistant layer 60 on a base metal 62.
  • the corrosion resistant layer 58 is applied over the base metal 62 in the application station 44, and the abrasion resistant layer 60 is applied over the corrosion resistant layer 58 in the application station 46.
  • the base metal 62 may be any material suitable for transmitting work from the surface actuator 12 to the downhole pump 20 (see FIG. 1 ) and otherwise operating in a well environment. If the sucker rod 32 is a continuous sucker rod, the base metal 62 may have a length of 1000 meters or greater.
  • the base metal 62 should have suitable strength and toughness for transmitting torque and tensile loads, particularly fatigue strength to withstand varying loads for long periods of time, and yet be economical to obtain and process.
  • suitable materials for the base metal 62 include carbon and low alloy steels. Flowever, the scope of this disclosure is not limited to use of any particular material in the base metal 62.
  • the corrosion resistant layer 58 is suitable for preventing corrosion of the base metal 62 due to exposure to fluids in a well.
  • the corrosion resistant layer 58 comprises a corrosion resistant material 64.
  • suitable corrosion resistant materials include fusion bonded epoxy and other thermosetting polymers such as silicone, polyurethane, phenolic and polyester.
  • the corrosion resistant material 64 may mitigate corrosion by isolating the base metal 62 from well fluids, by chemically hindering a corrosive reaction, or by another means.
  • the corrosion resistant material 64 may be applied by spraying, dipping, wrapping, extruding or any other technique. The scope of this disclosure is not limited to use of any particular type of corrosion resistant material or manner of applying the corrosion resistant material.
  • the corrosion resistant layer 58 is applied directly to the base metal 62.
  • an adhesive, primer, sealer or other layer may be included between the corrosion resistant layer 58 and the base metal 62.
  • the abrasion resistant layer 60 is suitable for preventing damage to the corrosion resistant layer 58 due to various impacts, wear and abrasion
  • the abrasion resistant layer 60 comprises an abrasion resistant material 66.
  • suitable abrasion resistant materials include phenolics, fusion bonded epoxy and other thermosetting polymers, polyolefins and other thermoplastic polymers, hard particles or friction reducing particles, and combinations thereof.
  • the abrasion resistant material 66 may mitigate abrasion by reducing friction, by presenting a hard or tough surface, or by another means.
  • the abrasion resistant material 66 may be applied by spraying, dipping, wrapping, extruding or any other technique. The scope of this disclosure is not limited to use of any particular type of abrasion resistant material or manner of applying the abrasion resistant material.
  • the abrasion resistant layer 60 is applied directly to the corrosion resistant layer 58.
  • an adhesive, primer, sealer or other layer may be included between the abrasion resistant layer 60 and the corrosion resistant layer 58.
  • FIGS. 5 & 6 another example of the surface treatment method 34 and system 48, and the sucker rod 32 produced thereby, are representatively illustrated.
  • the FIGS. 5 & 6 example is similar in many respects to the FIGS. 3 & 4 example, except that a particulate material 68 is applied over the corrosion resistant layer 58.
  • the particulate material 68 is applied by an application station 70.
  • the application station 70 is positioned between the application stations 44, 46 as depicted in FIG. 5.
  • the particulate material 68 may be any material suitable to resist impact, wear or abrasion.
  • the resistance to impact, wear or abrasion may be due to a relatively high strength, hardness or toughness of the particulate material 68.
  • the particulate material 68 may comprise silicon carbide, silicon dioxide (e.g., sand), carbides, nitrides, oxides, borides, minerals, or other suitable materials.
  • the particulate material 68 may be selected from a variety of friction reducing agents, including fluorocarbons, graphite, graphene, molybdenum disulfide and other friction reducing agents. The scope of this disclosure is not limited to use of any certain particulate material.
  • the application station 70 may apply the particulate material 68 directly to the corrosion resistant layer 58, or another layer may be applied between the particulate material and the corrosion resistant layer.
  • an adhesive could be applied to the corrosion resistant layer 58 prior to applying the
  • the particulate material 68 may embed partially or fully into the corrosion resistant layer 58.
  • the abrasion resistant layer 60 includes the particulate material 68 in a matrix material 66a.
  • the matrix material 66a may be the same as the abrasion resistant material 66 in the FIGS. 3 & 4 example.
  • the abrasion resistant material 66 in the FIGS. 5 & 6 example includes both the particulate material 68 and the matrix material 66a.
  • the particulate material 68 When the matrix material 66a is applied to the corrosion resistant layer 58, the particulate material 68 is“absorbed” into the matrix material, so that the matrix and particulate materials become a single composite element. In some examples, the particulate material 68 may become dispersed or embedded in the matrix material 66a.
  • FIGS. 7 & 8 another example of the surface treatment method 34 and system 48, and the sucker rod 32 produced thereby, are representatively illustrated.
  • the FIGS. 7 & 8 example is similar in many respects to the FIGS. 5 & 6 example, except that the abrasion resistant layer 60 (including the particulate material 68 and the matrix material 66a) is applied by the application station 46.
  • the abrasion resistant material 66 in this example includes both the matrix material 66a and the particulate material 68.
  • the matrix and particulate materials 66a, 68 may be combined to form the abrasion resistant material 66, prior to the application station 46 applying the abrasion resistant material onto the corrosion resistant material 64 (or any layer applied on the corrosion resistant layer).
  • the matrix material 66a could comprise a thermoplastic material.
  • the application station 46 can be configured to extrude the
  • thermoplastic matrix material 66a along with the particulate material 68
  • the corrosion resistant material 64 comprises a thermosetting material
  • an adhesive or other tie layer may be used between the corrosion resistant layer 58 and the abrasion resistant layer 60.
  • a corrosion resistant layer 58 is applied on a base metal 62 of a sucker rod 32, and the corrosion resistant layer 58 is protected by an abrasion resistant layer 60.
  • An abrasion resistant material 66 of the abrasion resistant layer 60 may comprise a phenolic based matrix material 66a and/or a particulate material 68.
  • the sucker rod 32 may comprise a base metal 62 configured to connect a surface actuator 12 to a downhole pump 20, a corrosion resistant layer 58 on the base metal 62, and an abrasion resistant layer 60 external to the corrosion resistant layer 58.
  • the abrasion resistant layer 60 comprises a phenolic material 66a.
  • the abrasion resistant layer 60 may further comprise an epoxy material.
  • the abrasion resistant layer 60 may comprise an abrasion resistant particulate material 68. In any of the examples described herein, the abrasion resistant layer 60 may comprise a friction reducing particulate material 68.
  • the particulate material 68 may be embedded in the phenolic material 66a.
  • the particulate material 68 may be positioned between the corrosion resistant layer 58 and at least a portion of the phenolic material 66a.
  • the particulate material 68 may be selected from the group consisting of silicon carbide, silicon dioxide, oxides, borides, nitrides and carbides.
  • the particulate material 68 may be selected from a variety of friction reducing agents, including fluorocarbons, graphite, graphene, molybdenum disulfide and other friction reducing agents.
  • the corrosion resistant layer 58 may comprise an epoxy material.
  • the sucker rod 32 may be a continuous sucker rod.
  • the base metal 62 may have a length of at least 1000 meters.
  • the sucker rod 32 for use in a subterranean well is provided to the art by the above disclosure.
  • the sucker rod 32 comprises a base metal 62 configured to connect a surface actuator 12 to a downhole pump 20, a corrosion resistant layer 58 on the base metal 62, and an abrasion resistant layer 60 external to the corrosion resistant layer 58.
  • the abrasion resistant layer 60 comprises an abrasion resistant particulate material 68 and a matrix material 66a.
  • the matrix material 66a may comprise a phenolic material.
  • the particulate material 68 may be embedded in the matrix material 66a. In any of the examples described herein, the particulate material 68 may be positioned between the corrosion resistant layer 58 and at least a portion of the matrix material 66a.
  • a method 34 of producing a continuous sucker rod 32 is also provided to the art by the above method.
  • the method 34 comprises displacing the continuous sucker rod 32 through a surface treatment system 48; applying a corrosion resistant layer 58 on a base metal 62 of the continuous sucker rod 32; then applying an abrasion resistant layer 60 external to the corrosion resistant layer 58.
  • the abrasion resistant layer 60 applying step may comprise applying a phenolic material 66a.
  • the abrasion resistant layer 60 applying step may comprise applying an abrasion resistant and/or friction reducing particulate material 68.
  • the abrasion resistant layer 60 applying step may comprise applying an abrasion resistant and/or friction reducing particulate material 68 dispersed in a matrix material 66a.

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  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Mechanical Engineering (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Fluid Mechanics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Physics & Mathematics (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Chemical & Material Sciences (AREA)
  • Materials Engineering (AREA)
  • Metallurgy (AREA)
  • Organic Chemistry (AREA)
  • Laminated Bodies (AREA)
  • Other Surface Treatments For Metallic Materials (AREA)

Abstract

La présente invention concerne une tige de pompage qui peut comprendre un métal de base, une couche résistante à la corrosion sur le métal de base, et une couche résistante à l'abrasion externe à la couche résistante à la corrosion, la couche résistante à l'abrasion comprenant un matériau phénolique. Une autre tige de pompage selon l'invention peut comprendre un métal de base, une couche résistante à la corrosion sur le métal de base, et une couche résistante à l'abrasion extérieure à la couche résistante à la corrosion, la couche résistante à l'abrasion comprenant un matériau particulaire résistant à l'abrasion et un matériau de matrice. Un procédé de production d'une tige de pompage continue peut comprendre le déplacement de la tige de pompage continue à travers un système de traitement de surface, l'application d'une couche résistante à la corrosion sur un métal de base de la tige de pompage continue, puis l'application d'une couche résistante à l'abrasion extérieure à la couche résistante à la corrosion.
PCT/US2020/014094 2019-02-15 2020-01-17 Tige de pompage résistante à la corrosion et à l'abrasion WO2020167413A1 (fr)

Priority Applications (4)

Application Number Priority Date Filing Date Title
MX2021009809A MX2021009809A (es) 2019-02-15 2020-01-17 Varilla de succion resistente a la corrosion y la abrasion.
EP20704988.3A EP3924594A1 (fr) 2019-02-15 2020-01-17 Tige de pompage résistante à la corrosion et à l'abrasion
CA3126809A CA3126809A1 (fr) 2019-02-15 2020-01-17 Tige de pompage resistante a la corrosion et a l'abrasion
CONC2021/0009579A CO2021009579A2 (es) 2019-02-15 2021-07-22 Varilla de succión resistente a la corrosión y la abrasión

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US16/276,658 2019-02-15
US16/276,658 US20200263508A1 (en) 2019-02-15 2019-02-15 Corrosion and abrasion resistant sucker rod

Publications (1)

Publication Number Publication Date
WO2020167413A1 true WO2020167413A1 (fr) 2020-08-20

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Application Number Title Priority Date Filing Date
PCT/US2020/014094 WO2020167413A1 (fr) 2019-02-15 2020-01-17 Tige de pompage résistante à la corrosion et à l'abrasion

Country Status (6)

Country Link
US (1) US20200263508A1 (fr)
EP (1) EP3924594A1 (fr)
CA (1) CA3126809A1 (fr)
CO (1) CO2021009579A2 (fr)
MX (1) MX2021009809A (fr)
WO (1) WO2020167413A1 (fr)

Families Citing this family (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
RO137663A2 (ro) * 2020-09-22 2023-09-29 Oilfield Piping Systems Pty Ltd Ghidaj pentru tija de aspirare

Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4045591A (en) * 1974-07-19 1977-08-30 Rodco, Inc. Method of treating sucker rod
WO2011102820A1 (fr) * 2010-02-22 2011-08-25 Exxonmobil Research And Engineering Company Dispositifs de production revêtus et manchonnés pour puits de pétrole et de gaz
US20170029959A1 (en) * 2015-07-27 2017-02-02 Schlumberger Technology Corporation Property enhancement of surfaces by electrolytic micro arc oxidation
US20170283958A1 (en) * 2016-04-01 2017-10-05 Weatherford Technology Holdings, Llc Dual layer fusion bond epoxy coating for continuous sucker rod
US9869135B1 (en) * 2012-06-21 2018-01-16 Rfg Technology Partners Llc Sucker rod apparatus and methods for manufacture and use
AU2016247078B2 (en) * 2010-02-17 2018-12-20 Baker Hughes, A Ge Company, Llc Nano-coatings for articles

Patent Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4045591A (en) * 1974-07-19 1977-08-30 Rodco, Inc. Method of treating sucker rod
AU2016247078B2 (en) * 2010-02-17 2018-12-20 Baker Hughes, A Ge Company, Llc Nano-coatings for articles
WO2011102820A1 (fr) * 2010-02-22 2011-08-25 Exxonmobil Research And Engineering Company Dispositifs de production revêtus et manchonnés pour puits de pétrole et de gaz
US9869135B1 (en) * 2012-06-21 2018-01-16 Rfg Technology Partners Llc Sucker rod apparatus and methods for manufacture and use
US20170029959A1 (en) * 2015-07-27 2017-02-02 Schlumberger Technology Corporation Property enhancement of surfaces by electrolytic micro arc oxidation
US20170283958A1 (en) * 2016-04-01 2017-10-05 Weatherford Technology Holdings, Llc Dual layer fusion bond epoxy coating for continuous sucker rod

Also Published As

Publication number Publication date
EP3924594A1 (fr) 2021-12-22
CO2021009579A2 (es) 2021-08-09
CA3126809A1 (fr) 2020-08-20
US20200263508A1 (en) 2020-08-20
MX2021009809A (es) 2021-09-08

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