WO2016149811A1 - Appareil de production d'hydrocarbures - Google Patents

Appareil de production d'hydrocarbures Download PDF

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Publication number
WO2016149811A1
WO2016149811A1 PCT/CA2016/050315 CA2016050315W WO2016149811A1 WO 2016149811 A1 WO2016149811 A1 WO 2016149811A1 CA 2016050315 W CA2016050315 W CA 2016050315W WO 2016149811 A1 WO2016149811 A1 WO 2016149811A1
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WO
WIPO (PCT)
Prior art keywords
downhole
coil
well
well casing
pipe
Prior art date
Application number
PCT/CA2016/050315
Other languages
English (en)
Inventor
Claire Yih Ping Hong
Original Assignee
Cenovus Energy Inc.
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 Cenovus Energy Inc. filed Critical Cenovus Energy Inc.
Priority to CA2980197A priority Critical patent/CA2980197A1/fr
Publication of WO2016149811A1 publication Critical patent/WO2016149811A1/fr

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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
    • E21B17/003—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings with electrically conducting or insulating means
    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • E21B43/121—Lifting well fluids
    • E21B43/128—Adaptation of pump systems with down-hole electric drives

Definitions

  • the present invention relates to the production of hydrocarbons from underground deposits by artificial lifting of the fluid including the hydrocarbons.
  • thermal techniques may be used to heat the reservoir to mobilize the hydrocarbons and produce the heated, mobilized hydrocarbons from wells.
  • One such technique for utilizing a horizontal well for injecting heated fluids and producing hydrocarbons is described in U.S. Patent No. 4,1 16,275, which also describes some of the problems associated with the production of mobilized viscous hydrocarbons from horizontal wells.
  • SAGD steam-assisted gravity drainage
  • Various embodiments of the SAGD process are described in Canadian Patent No. 1 ,304,287 and corresponding U.S. Patent No. 4,344,485.
  • steam is pumped through an upper, horizontal, injection well into a viscous hydrocarbon reservoir while hydrocarbons are produced from a lower, parallel, horizontal, production well that is vertically spaced and near the injection well.
  • the injection and production wells are located close to the bottom of the hydrocarbon deposit to collect the hydrocarbons that flow toward the bottom.
  • the SAGD process is believed to work as follows.
  • the injected steam initially mobilizes the hydrocarbons to create a steam chamber in the reservoir around and above the horizontal injection well.
  • the term steam chamber is utilized to refer to the volume of the reservoir that is saturated with injected steam and from which mobilized oil has at least partially drained.
  • viscous hydrocarbons in the reservoir are heated and mobilized, in particular, at the margins of the steam chamber where the steam condenses and heats the viscous hydrocarbons by thermal conduction.
  • the heated hydrocarbons and aqueous condensate drain, under the effects of gravity, toward the bottom of the steam chamber, where the production well is located.
  • the heated hydrocarbons and aqueous condensate are collected and produced from the production well.
  • supplemental production methods may be utilized.
  • Gas and water injection for pressure support or secondary recovery may be utilized to maintain well productivity.
  • a pump or gas lift techniques may be utilized, referred to as artificial lift. Lift processes are utilized to increase flow rates such that commercial hydrocarbon volumes are boosted or displaced to the surface. Artificial lift also improves recovery by reducing the downhole pressure at which wells become uneconomic and are abandoned. Also, the development of unconventional lift
  • resources such as viscous hydrocarbons usually include construction of complex wells, and high hydrocarbon lifting rates are desirable to produce oil quickly and efficiently at low cost.
  • Rod pump, gas lift, and electric submersible pumps are the most common artificial lift systems. Hydraulic and progressing cavity pumps are also utilized. Electric submersible systems use multiple centrifugal pump stages mounted in series within a housing, coupled to a submersible electric motor that is connected to surface controls and electric power by an armor-protected cable that extends to the surface.
  • Artificial lift may be utilized along with the SAGD process to increase the flow rate from the production well.
  • Electric submersible pumps may be utilized in the production well to facilitate the flow of the fluids to the surface.
  • electric submersible pump When utilized, electric submersible pump are typically located in or near a horizontal segment of the production well, into which fluid flows during the SAGD process, at depths of hundreds of meters. Thus, hundreds of meters of electrical cable may be utilized to power an electric submersible pump.
  • electric submersible pumps utilized in such applications are exposed to a wide range of conditions.
  • electric submersible pumps may be exposed to cold weather such as temperatures of about -40°C prior to insertion into a production well.
  • the same electric submersible pumps may be operated at reservoir temperatures near 250 °C (482 °F).
  • High-temperature motors and cables are utilized.
  • Such electric submersible pumps are also exposed to wide flow ranges and varying gas to oil ratios.
  • a downhole heater may be utilized in the injection or in the production well during start-up operations or during production to increase uniformity of expansion of the steam chamber, which typically does not expand uniformly over the length of the well pair.
  • a heater may be disposed in an electric heater string and is coupled to an armor- protected electric cable that extends to the surface.
  • a system for use in a hydrocarbon recovery process from a well.
  • the system includes a downhole electrical device for use in hydrocarbon recovery, the downhole electrical device disposed downhole in the well, an amplifier coupled to a frequency resonator which is coupled to a pipe extending downhole in the well to provide electrical energy via resonant frequency utilizing the pipe, wherein the pipe is electrically isolated from a ground, a resonator coil coupled to the pipe, and a receiver and a pickup coil coupled to the downhole electrical device.
  • the receiver receives the electrical energy transmitted through the pipe by resonant inductive coupling of the resonator coil with the receiver and the pickup coil is utilized to convert the electrical energy into current to power the downhole electrical device.
  • FIG. 1 is a sectional view through a reservoir, illustrating a SAGD well pair
  • FIG. 2 is a side view of a hydrocarbon production well of the SAGD well pair of FIG. 1 ;
  • FIG. 3 is a sectional view through a horizontal segment of a hydrocarbon production well including a part of a system for use in the well in accordance with an embodiment
  • FIG. 4 is a sectional view through a wellhead including a vertical segment of the hydrocarbon production well of FIG. 3 including a part of a system for use in the well;
  • FIG. 5 is a schematic view of a pickup coil coupled to a motor in the system of FIG. 3 and FIG. 4;
  • FIG. 6 is a flowchart illustrating a method of providing power to electrical equipment in a well for facilitating hydrocarbon recovery from a hydrocarbon-bearing formation
  • FIG. 7 is a sectional view through a horizontal segment of a hydrocarbon production well including a part of a system for use in the well in accordance with another embodiment.
  • the disclosure generally relates to a method and system for use in hydrocarbon recovery from a well.
  • the system includes a downhole electrical device for use in hydrocarbon recovery, the downhole electrical device disposed downhole in the well, an amplifier coupled to a frequency resonator which is coupled to a pipe extending downhole in the well to provide electrical energy via resonant frequency utilizing the pipe, wherein the pipe is electrically isolated from a ground, a resonator coil coupled to the pipe, and a receiver and a pickup coil coupled to the downhole electrical device.
  • the receiver receives the electrical energy transmitted through the pipe by resonant inductive coupling of the resonator coil with the receiver and the pickup coil is utilized to convert the electrical energy into current to power the downhole electrical device.
  • the injection well and the production well may be physically separate wells.
  • the production well and the injection well may be housed, at least partially, in a single physical wellbore, for example, a multilateral well.
  • the production well and the injection well may be functionally independent components that are hydraulically isolated from each other, and housed within a single physical wellbore.
  • the disclosed system is not limited to a SAGD production or injection well and may be successfully implemented in any well utilized in hydrocarbon recovery.
  • a steam assisted gravity drainage (SAGD) process may be utilized for mobilizing viscous hydrocarbons.
  • SAGD steam assisted gravity drainage
  • a well pair including hydrocarbon production well and a steam injection well are utilized.
  • the hydrocarbon production well 100 includes a generally horizontal segment 102 that extends near the base or bottom 104 of the hydrocarbon reservoir 106.
  • the steam injection well also includes a generally horizontal segment 1 10 that is disposed generally parallel to and is spaced vertically above the horizontal segment 102 of the hydrocarbon production well 100.
  • SAGD steam is injected into the injection well to mobilize the hydrocarbons and create a steam chamber 1 12 in the reservoir 106, around and above the generally horizontal segment 1 10.
  • light hydrocarbons such as the C3 through C10 alkanes, either individually or in combination, may optionally be injected with the steam such that the light hydrocarbons function as solvents in aiding the mobilization of the hydrocarbons.
  • the volume of light hydrocarbons that are injected is relatively small compared to the volume of steam injected.
  • SAP solvent- assisted process
  • various non-condensing gases such as methane or carbon dioxide
  • various non-condensing gases such as methane or carbon dioxide
  • Viscous hydrocarbons in the reservoir are heated and mobilized and the mobilized hydrocarbons drain under the effect of gravity.
  • Fluids, including the mobilized hydrocarbons along with aqueous condensate, are collected in the generally horizontal segment 102.
  • the fluids may also include gases such as steam and production gases from the SAGD process.
  • Artificial lift may be utilized to facilitate the flow of the heated hydrocarbons and aqueous condensate to the surface, for example, when the SAGD operation is carried out at sufficiently low pressure that artificial lift is required to recover mobilized hydrocarbon at the surface, or when increased rate of movement of the fluid from the well is desirable.
  • FIG. 2 An embodiment of a system 200 for use in hydrocarbon recovery utilizing a well is illustrated in FIG. 2.
  • the well is a hydrocarbon production well, as illustrated in FIG. 1 .
  • the well is not limited to the hydrocarbon production well 100, however, and may be an injection well or any other well utilized in hydrocarbon recovery.
  • the hydrocarbon production well 100 includes the generally horizontal segment 102, which is a pipe, also referred to as a slotted liner that is coupled to an intermediate well casing 202 that is coupled to a production well casing 203 by, for example, a cement to isolate the intermediate well casing 202 from the production well casing 203 and thereby inhibit grounding of the intermediate well casing 202.
  • the intermediate well casing 202 extends from the generally horizontal segment 102 to the wellhead 206.
  • the system includes a downhole electrical device 100, which in the present example is an electric submersible pump 210 for use in hydrocarbon recovery.
  • the electric submersible pump 210 is disposed downhole in the well in or near the horizontal segment 102 into which fluid flows during the SAGD process.
  • An outlet of the electric submersible pump 210 is coupled to a production conduit 212 that extends inside the production well casing 203, from a first end 214 at the outlet of the electric submersible pump 210, to a second end 216 at the wellhead 206.
  • the production conduit 212 is tubular steel pipe and may extend generally concentrically with the production well casing 203.
  • the production conduit 212 is electrically isolated from the intermediate well casing 202 to inhibit grounding of the production conduit 212.
  • a high voltage driver including an amplifier 218, coupled to a frequency resonator 220, is coupled to the intermediate well casing 202 to provide a resonating signal to the intermediate well casing 202 to thereby provide electrical energy via resonant frequency utilizing the intermediate well casing 202.
  • a resonator coil 222 is coupled to the intermediate well casing 202.
  • the resonator coil may be disposed around a reduced-diameter portion of the intermediate well casing 202 for resonant inductive coupling with a receiving coil to provide the electrical energy to the electric submersible pump 210.
  • a receiving coil receives the resonating signal that is transferred via the production conduit 212 and the resonator coil 222, by resonant inductive coupling with the resonator coil 222.
  • a pickup coil (not shown) is disposed very close to but not touching the receiving coil. The pickup coil is coupled to the motor of the electric submersible pump 210 for converting the signal received at the receiving coil by resonant inductive coupling with the resonator coil 222, to current. The pickup coil is utilized to provide the current to the electric submersible pump 210 to power the electric submersible pump 210 to facilitate hydrocarbon recovery.
  • FIG. 3 and FIG. 4 include a schematic illustration of parts of the system for use in the well.
  • the apparatus 200 includes an electric submersible pump 210.
  • the electric submersible pump 210 includes a motor 302, a seal 304 an intake 306, and a pump 308.
  • the electric submersible pump 308 is located in or near the horizontal segment 102 into which fluid flows during the SAGD process.
  • the motor 302 is disposed in the hydrocarbon production well 100 and is utilized to rotate a drive shaft 310 that drives the pump 308 that receives liquid from the intake 306.
  • the motor 302 may be a three-phase induction motor.
  • a housing of the motor 302 is made of a generally non-conductive and non-magnetic alloy.
  • the motor 302 is coupled to the seal 304 that is located between the motor 302 and the intake 306.
  • the seal 304 is utilized to balance internal motor pressure, absorb axial thrust in the drive shaft 310, and facilitate the connection of the motor 302 to the intake 304 while inhibiting or reducing the chance of wellbore fluid contaminating the motor 302.
  • the motor 302 rotates the drive shaft 310, which extends through the seal 304to drive the pump 308.
  • the intake 306 is coupled to the seal 304 and to the pump 308.
  • the intake 306 includes openings 312 through which the fluid enters to be pumped through the production conduit 302.
  • the pump 308 receives the fluid from the intake 306. As described above, the pump 308 is also driven by the drive shaft 310, which is rotated by the motor 302. In this example, the pump 308 is a multi-stage centrifugal pump that adds cumulative head to the fluid for each stage. The fluid exits the pump discharge 314 at a higher pressure than the fluid that entered the intake 306 and flows up the production conduit 212 to and through the wellhead 206.
  • a housing of the pump 308 is also made of a generally non-conductive and non-magnetic alloy.
  • An electrically insulating material 322, such as non-conductive cement, is utilized to electrically isolate the intermediate well casing 202 from the production well casing 203.
  • the insulating material 322 is disposed between the intermediate well casing 202 and the production well casing 203 to reduce the chance of contact of the intermediate well casing 202 with the production well casing 203 and thereby reduce the chance of electrically shorting out the intermediate well casing 202. Additionally, the intermediate well casing 202 is not exposed to fluid such as water or other produced fluid from the reservoir, thus, reducing the chance of electrically shorting the
  • intermediate well casing 202 and facilitating use of the intermediate well casing for the transfer of electrical energy downhole.
  • the resonator coil 222 is coupled to a portion of the intermediate well casing 202 at a location downhole.
  • the resonator coil 222 is wound around a reduced-diameter portion 330 of the intermediate well casing 202.
  • the resonator coil 222 is covered with a non-conductive ceramic such that the resonator coil 222 is disposed in the non-conductive ceramic.
  • the resonator coil 222 is hydraulically isolated by the non-conductive ceramic cover and the shroud 332.
  • the receiving coil 320 is disposed in the intermediate well casing 202, near the motor 302 and is generally aligned downhole with the resonator coil 222 on the intermediate well casing 202.
  • the receiving coil 320 is enclosed in a protective housing 324 and is insulated from the housing 324 by an insulator or is enclosed in a non- conductive housing.
  • the pickup coil 326 is disposed adjacent to the receiving coil 320 in the housing 324 in the intermediate well casing 202.
  • the receiving coil 320 and the pickup coil 326 may therefore be disposed in a single housing 324 within the intermediate well casing 202.
  • the receiving coil 320 is generally aligned with the resonator coil 222 to receive the signal from the resonator coil 326.
  • the receiving coil 320 and the pickup coil 326 may be disposed in a housing within the production conduit 212.
  • the receiving coil 320 and the pickup coil 326 are electrically insulated from the production conduit.212 and the receiving coil 320 is generally aligned downhole with the resonator coil 222 on the intermediate well casing 202.
  • the motor 302 is electrically coupled to the pickup coil 326 to receive the electrical energy transmitted through the intermediate well casing 202 by resonant inductive coupling of the receiving coil 320 with the resonator coil 222.
  • the amplifier 218 is coupled to the frequency resonator 220 which is coupled to the intermediate well casing 202 to provide the resonating signal to the intermediate well casing 202.
  • a suitable resonant frequency for the system is selected for the amplifier to provide, via the frequency resonator 220 to thereby provide electrical energy via resonant frequency utilizing the intermediate well casing 202.
  • the suitable resonant frequency may be selected by identifying an estimated frequency and then fine-tuning the frequency experimentally.
  • the estimated frequency may be calculated, for example, utilizing the following equation: a c
  • f is the frequency
  • a is an empirical constant
  • ⁇ is the wavelength, which is the length of the pipe or casing a) speed of light
  • the resonant frequency may differ from the calculated frequency when the system is completed and ready for use.
  • the resonant frequency may differ from the calculated resonant frequency because of the surrounding elements or objects.
  • the estimated frequency may be higher or lower than the actual resonant frequency depending on the application-specific surrounding objects.
  • the calculated frequency is utilized and an iterative process of adjusting the frequency based on the results achieved is utilized to identify the resonant frequency.
  • the calculated frequency is fine-tuned utilizing the iterative process.
  • the motor 302 is powered utilizing energy transmitted through the intermediate well casing 202 and the resonator coil 222, and from the resonator coil 222 to the receiving coil 320 via resonant inductive coupling.
  • FIG. 5 A schematic view of the receiving coil 320 and the pickup coil 326 coupled to the motor 302 is shown in FIG. 5.
  • the pickup coil 326 is disposed very close to without touching the receiving coil 320 and both the pickup coil 326 and receiving coil 320 are disposed within a housing in the intermediate well casing 202.
  • the pickup coil 326 is adjacent to the receiving coil 320 and is coupled to the motor 302 via a DC converter 502 and frequency switch 504.
  • the electrical energy picked up at the pickup coil 326 is converted to DC power at the DC converter 502 and, in the present example, a chopper circuit is utilized to chop the frequency at 60 Hz utilizing the switch 504, providing both positive and negative 60 Hz cycle that is utilized to power the motor 302.
  • the electrical energy transmitted via the intermediate well casing 202 is utilized to provide power to the motor 302 to drive the pump 308.
  • the schematic view of the receiving coil 320 and the pickup coil 326 coupled to the motor 302 in FIG. 5 shows a single DC converter and a single frequency switch.
  • three DC converters and three frequency switches are utilized and coupled to the motor provide power to the motor.
  • the DC converters are coupled to the pickup coil and to the three-phase induction motor via respective frequency switches.
  • the fluid including hydrocarbons along with aqueous condensate, flows into the generally horizontal segment 102 of the hydrocarbon production well 100.
  • the motor 302 drives the pump 314 and fluid that enters the intake 306 and is pumped to the wellhead through the production conduit 212.
  • the generally cylindrical intermediate well casing 202 is utilized to conduct the electrical energy.
  • FIG. 6 A flowchart illustrating a method of providing power to electrical equipment downhole for facilitating hydrocarbon recovery from a hydrocarbon-bearing formation is shown in FIG. 6. The process is carried out to facilitate hydrocarbon recovery from a reservoir, such as the reservoir 106.
  • the method may contain additional or fewer processes than shown or described, and may be performed in a different order.
  • a suitable resonant frequency is identified for the system at 602.
  • an estimated frequency is calculated.
  • the resonant frequency may differ from the estimated frequency when the system is completed and ready for use.
  • the calculated frequency is fine-tuned utilizing the iterative process to identify the resonant frequency.
  • a resonating signal is applied to a pipe or casing that extends downhole, such as the intermediate well casing 202 at 604.
  • the resonating signal may be applied by an amplifier coupled a frequency resonator.
  • the resonator coil 222 which is wrapped around a portion of the intermediate well casing 202 at a location downhole, generates a resonating signal from the voltage, which is converted downhole to current by a receiver and pickup coil and power is provided to the electrical device at 606.
  • the present application is not limited to powering an electric submersible pump. Other electrical equipment may also be powered.
  • a horizontal segment of a hydrocarbon production well including a part of a system in accordance with another embodiment is shown in FIG. 7.
  • a downhole electric heater is utilized to heat the well, which may be a production well or injection well, during start-up operations or during production to increase uniformity of expansion of the steam chamber. Alternatively, such a heater may be utilized for steam generation downhole.
  • the heater 702 may be disposed in a heater string 704 in the generally horizontal segment of the production well 100.
  • the amplifier 218 is coupled to the frequency resonator 220 which is coupled to the intermediate well casing 202 to provide the resonating signal to the intermediate well casing 202.
  • a resonator coil 720 is disposed around a reduced-diameter portion of the intermediate well casing 202 for resonant inductive coupling with a receiving coil 706, at a location downhole, from the signal applied to the intermediate well casing.
  • the receiving coil 706 is disposed in a housing 712 in the heater string 704, near the heater 702.
  • the receiving coil 706 is insulated from the housing 712, for example, by an insulator 708.
  • the pickup coil 710 is disposed in the housing 712 and adjacent to the receiving coil 706 in the heater string 704.
  • the pickup coil 710 is electrically isolated from the housing 712 by the insulator 708.
  • the heater 702 is electrically coupled to the pickup coil 710 to receive the electrical energy transmitted through the intermediate well casing 202 and to the receiving coil 706 by resonant inductive coupling of the receiving coil 706 with the resonator coil 720.
  • the heater 702 may be coupled to the pickup coil 710 by a similar DC converter and chopper circuit including the frequency switch described above with reference to FIG. 5.
  • a suitable resonant frequency for the system is identified for the amplifier to provide, via the frequency resonator 220 to thereby provide electrical energy via the intermediate well casing 202.
  • the heater is operated to heat all or a portion of the formation around the horizontal portion of the well to increase uniformity of heating across the horizontal segment of the production well.
  • fluid may be circulated in the well during heating.
  • water may be circulated and the water flashes into steam in the area of the electric heater to cause steam chamber growth.
  • tubing or casing such as an intermediate well casing, for example, is utilized to transmit electrical energy downhole.
  • electric cables that extend from the surface to the downhole electrical equipment are not utilized, reducing the chance of failure of the equipment as a result of damage to the cable.

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  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Mechanical Engineering (AREA)
  • Structures Of Non-Positive Displacement Pumps (AREA)

Abstract

L'invention concerne un système destiné à être utilisé dans la récupération d'hydrocarbures à partir d'un puits, le système comprenant un dispositif électrique de fond de trou destiné à être utilisé dans la récupération d'hydrocarbures, le dispositif électrique de fond de trou étant disposé en fond de trou dans le puits, un amplificateur couplé à un résonateur de fréquence qui est accouplé à une conduite s'étendant vers le fond de trou dans le puits pour fournir de l'énergie électrique par l'intermédiaire d'une fréquence de résonance à l'aide de la conduite, la conduite étant électriquement isolée de la terre, une bobine de résonateur couplée à la conduite et un récepteur et une bobine détectrice couplés au dispositif électrique de fond de trou. Le récepteur reçoit l'énergie électrique transmise à travers la conduite par couplage inductif résonant de la bobine de résonateur avec le récepteur et la bobine détectrice est utilisée pour convertir l'énergie électrique en courant pour alimenter le dispositif électrique de fond de trou.
PCT/CA2016/050315 2015-03-20 2016-03-18 Appareil de production d'hydrocarbures WO2016149811A1 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
CA2980197A CA2980197A1 (fr) 2015-03-20 2016-03-18 Appareil de production d'hydrocarbures

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201562135956P 2015-03-20 2015-03-20
US62/135,956 2015-03-20

Publications (1)

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Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US10605032B2 (en) 2016-07-08 2020-03-31 Ge Oil & Gas Pressure Control Lp Electrically insulated tubing hanger system
WO2021126275A1 (fr) * 2019-12-20 2021-06-24 Halliburton Energy Services, Inc. Couplage inductif pour transfert d'énergie électrique à un moteur électrique submersible

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CA2398289A1 (fr) * 2000-01-24 2001-08-02 Shell Canada Limited Inducteur de duse destine a la communication et a des operations de commande sans fil dans un puits
US6747569B2 (en) * 2001-02-02 2004-06-08 Dbi Corporation Downhole telemetry and control system
US6851481B2 (en) * 2000-03-02 2005-02-08 Shell Oil Company Electro-hydraulically pressurized downhole valve actuator and method of use
US6868040B2 (en) * 2000-03-02 2005-03-15 Shell Oil Company Wireless power and communications cross-bar switch
US6958704B2 (en) * 2000-01-24 2005-10-25 Shell Oil Company Permanent downhole, wireless, two-way telemetry backbone using redundant repeaters
US8077053B2 (en) * 2006-03-31 2011-12-13 Chevron U.S.A. Inc. Method and apparatus for sensing a borehole characteristic
US8441153B2 (en) * 2010-06-22 2013-05-14 General Electric Company Contactless power transfer system
US20140090898A1 (en) * 2012-09-24 2014-04-03 Schlumberger Technology Corporation Casing Drilling Bottom Hole Assembly Having Wireless Power And Data Connection
WO2014109754A1 (fr) * 2013-01-11 2014-07-17 Halliburton Energy Services, Inc. Réflectrométrie de suivi temporel en domaine temporel pour la surveillance des tubes de production et des formations

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Publication number Priority date Publication date Assignee Title
US4839644A (en) * 1987-06-10 1989-06-13 Schlumberger Technology Corp. System and method for communicating signals in a cased borehole having tubing
CA2398289A1 (fr) * 2000-01-24 2001-08-02 Shell Canada Limited Inducteur de duse destine a la communication et a des operations de commande sans fil dans un puits
US6958704B2 (en) * 2000-01-24 2005-10-25 Shell Oil Company Permanent downhole, wireless, two-way telemetry backbone using redundant repeaters
US6851481B2 (en) * 2000-03-02 2005-02-08 Shell Oil Company Electro-hydraulically pressurized downhole valve actuator and method of use
US6868040B2 (en) * 2000-03-02 2005-03-15 Shell Oil Company Wireless power and communications cross-bar switch
US6747569B2 (en) * 2001-02-02 2004-06-08 Dbi Corporation Downhole telemetry and control system
US8077053B2 (en) * 2006-03-31 2011-12-13 Chevron U.S.A. Inc. Method and apparatus for sensing a borehole characteristic
US8441153B2 (en) * 2010-06-22 2013-05-14 General Electric Company Contactless power transfer system
US20140090898A1 (en) * 2012-09-24 2014-04-03 Schlumberger Technology Corporation Casing Drilling Bottom Hole Assembly Having Wireless Power And Data Connection
WO2014109754A1 (fr) * 2013-01-11 2014-07-17 Halliburton Energy Services, Inc. Réflectrométrie de suivi temporel en domaine temporel pour la surveillance des tubes de production et des formations

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US10605032B2 (en) 2016-07-08 2020-03-31 Ge Oil & Gas Pressure Control Lp Electrically insulated tubing hanger system
WO2021126275A1 (fr) * 2019-12-20 2021-06-24 Halliburton Energy Services, Inc. Couplage inductif pour transfert d'énergie électrique à un moteur électrique submersible
US11391096B2 (en) 2019-12-20 2022-07-19 Halliburton Energy Services, Inc. Inductive coupling for electric power transfer to electric submersible motor

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