Technical Field

[0001] The present invention relates to the production of hydrocarbons from underground deposits by artificial lifting of the fluid including the hydrocarbons.

Background

[0002] Extensive deposits of viscous hydrocarbons exist around the world, including large deposits in the Northern Alberta oil sands that are not susceptible to standard oil well production technologies. One problem associated with producing hydrocarbons from such deposits is that the hydrocarbons are too viscous to flow at commercially relevant rates at the temperatures and pressures present in the reservoir. In some cases, such deposits are mined using open-pit mining techniques to extract hydrocarbon-bearing material for later processing to extract the hydrocarbons.

Alternatively, 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.

[0003] One thermal method of recovering viscous hydrocarbons using spaced horizontal wells is known as steam-assisted gravity drainage (SAGD). Various embodiments of the SAGD process are described in Canadian Patent No. 1 ,304,287 and corresponding U.S. Patent No. 4,344,485. In the SAGD process, 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.

[0004] 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. As the steam chamber expands upwardly and laterally from the injection well, 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.

[0005] When a hydrocarbon reservoir lacks sufficient energy for oil, gas, and water to flow from wells at desired rates, supplemental production methods may be utilized. Gas and water injection for pressure support or secondary recovery may be utilized to maintain well productivity. When fluids do not naturally flow to the surface or do not naturally flow at a sufficient rate, 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

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.

[0006] 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.

[0007] 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. 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.

[0008] The electric submersible pumps utilized in such applications are exposed to a wide range of conditions. For example, 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.

[0009] Failure rates in electric submersible pumps related to electrical shorting are high and are primarily attributable to failure of the electrical cable system, which may occur at a connection point or anywhere along the length of the electrical cable, for example, as a result of damage during installation or extraction, wear, abrasion, or any combination of factors. Even armoured, insulated, electrical cable is frequently damaged.

[0010] Other electrical equipment and combinations of electrical equipment may also be utilized downhole in the hydrocarbon recovery process. For example, 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. Such a heater may be disposed in an electric heater string and is coupled to an armor- protected electric cable that extends to the surface.

[0011] As with electric submersible pumps, electric cables utilized for downhole heaters are also susceptible to damage and failure.

[0012] Reduction in failure rates in downhole electrical equipment as a result of failure of the electrical cables is desirable.

Summary

[0013] According to one aspect, a system is provided 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.

Brief Description of the Drawings

[0014] Embodiments of the present invention will be described, by way of example, with reference to the drawings and to the following description, in which:

[0015] FIG. 1 is a sectional view through a reservoir, illustrating a SAGD well pair;

[0016] FIG. 2 is a side view of a hydrocarbon production well of the SAGD well pair of FIG. 1 ;

[0017] 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;

[0018] 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;

[0019] FIG. 5 is a schematic view of a pickup coil coupled to a motor in the system of FIG. 3 and FIG. 4;

[0020] 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;

[0021] 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. Detailed Description

[0022] For simplicity and clarity of illustration, reference numerals may be repeated among the figures to indicate corresponding or analogous elements.

Numerous details are set forth to provide an understanding of the examples described herein. The examples may be practiced without these details. In other instances, well- known methods, procedures, and components are not described in detail to avoid obscuring the examples described. The description is not to be considered as limited to the scope of the examples described herein.

[0023] 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.

[0024] Throughout the description, reference is made to an injection well and a production well. The injection well and the production well may be physically separate wells. Alternatively, 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. Furthermore, 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.

[0025] As described above, a steam assisted gravity drainage (SAGD) process may be utilized for mobilizing viscous hydrocarbons. In the SAGD process, a well pair, including hydrocarbon production well and a steam injection well are utilized. One example of a well pair is illustrated in FIG. 1 . 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.

[0026] During 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. In addition to steam injection into the steam injection well, 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. The addition of light hydrocarbons is referred to as a solvent- assisted process (SAP). Alternatively, or in addition to the light hydrocarbons, various non-condensing gases, such as methane or carbon dioxide, may be injected. 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.

[0027] 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.

[0028] An embodiment of a system 200 for use in hydrocarbon recovery utilizing a well is illustrated in FIG. 2. For the purpose of the present example, 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.

[0029] 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.

[0030] 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.

[0031] 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.

[0032] A resonator coil 222 is coupled to the intermediate well casing 202. For example, 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.

[0033] A receiving coil (not shown in FIG. 2) 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. [0034] Reference is made to FIG. 3 and FIG. 4 which show sectional view through a generally horizontal segment of the hydrocarbon production well 100 and through a wellhead including a vertical segment of the hydrocarbon production well 100, drawn to a larger scale by comparison with FIG. 2. FIG. 3 and FIG. 4 include a schematic illustration of parts of the system for use in the well.

[0035] As described above, 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.

[0036] 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. For example, 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.

[0037] 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.

[0038] 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.

[0039] 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. [0040] 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. Thus, 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.

[0041] The resonator coil 222 is coupled to a portion of the intermediate well casing 202 at a location downhole. In the present example, 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. Thus, the resonator coil 222 is hydraulically isolated by the non-conductive ceramic cover and the shroud 332. By hydraulically isolating the resonator coil 222, the chance of electrically shorting the resonator coil 222 as a result of water or other fluid contact is reduced.

[0042] 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.

[0043] 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.

[0044] Alternatively, the receiving coil 320 and the pickup coil 326 may be disposed in a housing within the production conduit 212. In this alternative, 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.

[0045] 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.

[0046] As illustrated in FIG. 4, 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.

[0047] 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.

[0048] The estimated frequency may be calculated, for example, utilizing the following equation: a c

f ⁼ IX '

where f is the frequency;

a is an empirical constant;

c is the speed of light; and

λ is the wavelength, which is the length of the pipe or casing a) speed of light

4 (estimated length of intermediate well casing)

[0049] The resonant frequency may differ from the calculated frequency when the system is completed and ready for use. For example, the resonant frequency may differ from the calculated resonant frequency because of the surrounding elements or objects. Thus, 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. Thus, the calculated frequency is fine-tuned utilizing the iterative process.

[0050] Thus, 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.

[0051] 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. Thus, 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. Thus, the electrical energy transmitted via the intermediate well casing 202 is utilized to provide power to the motor 302 to drive the pump 308.

[0052] 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. In the case of a three-phase induction motor, however, three DC converters and three frequency switches are utilized and coupled to the motor provide power to the motor. Thus, the DC converters are coupled to the pickup coil and to the three-phase induction motor via respective frequency switches.

[0053] During the production of hydrocarbons, 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.

[0054] The generally cylindrical intermediate well casing 202 is utilized to conduct the electrical energy.

[0055] 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.

[0056] Thus, as described hereinabove, a suitable resonant frequency is identified for the system at 602. As described above, 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. Based on the identified resonant frequency, a resonating signal is applied to a pipe or casing that extends downhole, such as the intermediate well casing 202 at 604. As set forth above, 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.

[0057] 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. In the present example, 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.

[0058] The heater 702 may be disposed in a heater string 704 in the generally horizontal segment of the production well 100.

[0059] As described above with reference to FIG. 4, 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.

[0060] 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. [0061] 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.

[0062] 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.

[0063] 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.

[0064] 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.

[0065] 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. Optionally, fluid may be circulated in the well during heating. For example, water may be circulated and the water flashes into steam in the area of the electric heater to cause steam chamber growth.

[0066] Advantageously, tubing or casing, such as an intermediate well casing, for example, is utilized to transmit electrical energy downhole. Thus, 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.

[0067] The described embodiments are to be considered in all respects only as illustrative and not restrictive. The scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole. All changes that come with meaning and range of equivalency of the claims are to be embraced within their scope.