US20160215613A1

US20160215613A1 - Optically-controlled switching of power to downhole devices

Info

Publication number: US20160215613A1
Application number: US15/025,637
Authority: US
Inventors: Glenn A. Wilson; Burkay Donderici
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2014-05-21
Filing date: 2014-05-21
Publication date: 2016-07-28
Also published as: WO2015178906A1; AU2014395165A1; GB201617641D0; CA2946379A1; AU2014395165B2; NO20161663A1; BR112016024531A2; GB2540078A

Abstract

A well having optically controlled switching, the well including a power cable run along a tubular string in a borehole, one or more downhole devices attached to the tubular string, one or more optically-controlled switches arranged downhole, where each switch is coupled between the power cable and one of the one or more downhole devices to enable or disable a flow of power to the downhole device, and a switch controller coupled to the one or more optically-controlled switches via an optical fiber, where each of the one or more optically-controlled switches are independently controllable.

Description

BACKGROUND

Oilfield operators are faced with the challenge of maximizing hydrocarbon recovery within a given budget and timeframe. While they perform as much logging and surveying as feasible before and during the drilling and completion of production wells and, in some cases, injection wells, the information gathering process does not end there. It is desirable for the operators to track the movement of fluids in and around the reservoirs, as this information enables them to adjust the distribution and rates of production among the producing and/or injection wells to avoid premature water breakthroughs and other obstacles to efficient and profitable operation. Moreover, such information gathering further enables the operators to better evaluate treatment and secondary recovery strategies for enhanced hydrocarbon recoveries.
To obtain such information, a permanent electromagnetic (EM) monitoring system may be attached to the casing string as it is run into the borehole. Example monitoring devices may include electrodes and electromagnetic antennas. Power to the monitoring devices may be independently controlled to enable maximum power delivery and easier monitoring of individual device power consumption or, for example, to determine independent device current leakage. If not properly determined, such leakage may be incorrectly interpreted as formation resistivity, thus resulting in inaccurate measurement determinations.
The independent power control may be accomplished by having a single power source and a switching unit at the Earth's surface and running independent power lines downhole to each of the monitoring devices. However, this consumes a great amount of limited space within the borehole, thus limiting the number of independent lines that may be run. This method also inherently increases cost due to the additional wire required to run each power source. Moreover, the increased hardware represents additional points of failure within the system, may introduce additional unwanted currents and/or voltage noise, and adds additional hardware that must be accounted for so as not to be damaged when performing further downhole operations (e.g., perforating, hydraulic fracturing, or stimulation activities).

BRIEF DESCRIPTION OF THE DRAWINGS

Accordingly, there are disclosed herein systems and methods for controlling power to downhole devices via optical switching. In the drawings:

FIG. 1 shows an illustrative permanent EM monitoring system for a reservoir.

FIG. 2 is an enlarged schematic view of an illustrative optically controlled well monitoring system.

FIG. 3 is a flow diagram of an illustrative method for controlling a permanent EM monitoring system.

It should be understood, however, that the specific embodiments given in the drawings and detailed description thereto do not limit the disclosure. On the contrary, they provide the foundation for one of ordinary skill to discern the alternative forms, equivalents, and modifications that are encompassed together with one or more of the given embodiments in the scope of the appended claims.

DETAILED DESCRIPTION

Certain disclosed system and method embodiments provide an optically controlled switching system for downhole devices. The system may include a tubular string having a power cable and one or more downhole devices attached thereto and arranged within a borehole. One or more optically-controlled switches are arranged downhole, each of which is coupled between one of the downhole devices and the power cable to enable or disable a flow of power to the downhole device. Additionally, a switch controller is optically coupled to the switches via an optical fiber and independently controls each of the switches.
In some embodiments, exemplary downhole devices may include capacitive electrodes, galvanic electrodes, multi-loop antennas, and electric motors (e.g., gauges, valves, and the like). The system may further include additional sensors, such as current and voltage sensors coupled to the switches and capable of measuring a current or voltage of the corresponding downhole device. In further embodiments, the tubular string may be a casing string, wherein the tubular string, power cable, and downhole devices are cemented within the borehole.
To provide some context for the disclosure, FIG. 1 shows an illustrative permanent EM monitoring system 100 (hereinafter “system 100”). As depicted, the system 100 includes a well 102 having a casing string 106 set within a borehole 104 of a formation 101 and secured in place by a cement sheath 108. In alternative embodiments, the casing string 106 may be a general tubular string. Moreover, the tubular string may be electrically insulated.
Inside the casing string 106, a production tubing string 110 defines an annular flow path (between the walls of the casing string and the production tubing string) and an inner flow path (along the bore of the production tubing string). Wellhead valves 112 and 114 provide fluid communication with the bottom-hole region via the annular and inner flow paths, respectively. Well 102 may function as a production well, an injection well, or simply as a formation monitoring well.
The well 102 includes downhole devices 116 a-c (illustrated as a first, second, and third downhole device 116 a, 116 b, and 116 c, respectively) attached to the casing string 106 and cemented within the borehole 104. Example downhole devices may include, but are not limited to, capacitive electrodes, galvanic electrodes, multi-loop antennas, and electric motors (e.g., gauges, valves, and the like). The downhole devices 116 a-c receive power from a power source 118 via a power cable 120 strapped to the outside of the casing string 106. The power cable 120 may include a mono-conductor or multi-conductor core.
Interposed between the power cable 120 and each downhole device 116 a-c is an optically-controlled switch 122 a-c (depicted as a first, second, and third switch, 122 a, 122 b, and 122 c, accordingly) which enables or disables the flow of power to the corresponding downhole device 116 a-c.
The switches 122 a-c are independently controllable via an optical fiber 124 coupled to a switch controller 126. Advantageously, only a single power cable 120 and a single optical fiber 124 are required, thus substantially saving space within the borehole and reducing or eliminating the problems of the prior art which may use individual power cables for each downhole device 116 a-c.
The switch controller 126 is coupled to and controlled by a processing unit 128 which may be, for example, a computer in tablet, notebook, laptop, or portable form, a desktop computer, a server or virtual computer on a network, a mobile phone, or some combination of like elements that couple software-configured processing capacity to a user interface 130. The processing unit 128 may perform processing including compiling a time series of measurements to enable monitoring of the time evolution, and may further include the use of a geometrical model of the reservoir that takes into account the relative positions and configurations of the downhole devices 116 a-c to obtain one or more parameters or formation characteristics. For example, if one of the downhole devices 116 a-c is a dielectric measurement tool, those parameters may include a resistivity distribution and an estimated water saturation.
The processing unit 128 may further enable the user to adjust the configuration of the system, for example, modifying such parameters as acquisition or generation rate of the downhole devices 116 a-c, firing sequence, transmit amplitudes, transmit waveforms, transmit frequencies, receive filters, and demodulation techniques. In some contemplated system embodiments, the processing unit 128 further enables the user to adjust injection and/or production rates to optimize production from the reservoir.
FIG. 2 illustrates an enlarged schematic view of an optically controlled well monitoring system 200 (hereinafter “system 200”). The system 200 may be similar to the system 100 of FIG. 1 and therefore may be best understood with reference thereto, where like numerals represent like elements that will not be described again in detail. In particular, as depicted, the system 200 includes three downhole devices 116 a-c attached to the casing string 106. The downhole devices 116 a-c receive power from the power source 118 via the power cables 120 a-b (wherein power cable 120 a is a source cable and power cable 120 b is a return cable). The three switches 122 a-c are interposed between each of the downhole devices 116 a-c and the power cables 120 a-b, thereby enabling or disabling a flow of power to the associated downhole device 116 a-c.
The switches 122 a-c are controlled by the switch controller 126 and coupled thereto via the optical fiber 124. One exemplary protocol that may be implemented over the optical fiber 124 enabling the switch controller 126 to independently control each switch 122 a-c is radio-over-fiber. When implementing such a protocol, the system 200 may further include an optical modulator 202 for modulating the signal sent via the optical cable to the switches 122 a-c. The modulated signal may be received by a demodulator 204 a-c coupled to or integrated with the switches 122 a-c for demodulating the optical signal and operating only the desired switch 122 a-c, thus enabling independent control of each switch 122 a-c.
As depicted, the downhole devices 116 a-c are electrodes which inject and receive current flowing through the formation 101. The first switch 122 a has both contacts open, therefore the first electrode 116 neither injects nor receives current. The second switch 122 b has the contact associated with the source power cable 120 a closed, thereby enabling injection of current from the second electrode 116 b. The third switch 122 c has one contact associated with the return power cable 120 b closed, thereby enabling a return path for the current.
Advantageously, only a single power cable 120 is required (even though a source and return power cable 120 a and 120 b are depicted). This is a significant reduction in cables, and thus space, required downhole. Moreover, the system requires less power than prior systems due to the switches being optically operated rather than electrically operated.
In some embodiments, the optical fiber 124 may further serve to transmit data from one or more sensors 206 (one shown) coupled to or integrated with the switches 122 a-c to help monitor the system 200. As depicted, the sensor 206 is coupled to the second switch 122 b for measurements of the corresponding downhole device 116 a-c. For example, such sensors 206 may include a current or voltage sensor that measures the current or voltage of the downhole device 116 b. Alternatively, the sensor 206 may take temperature or vibration measurements in proximity to the downhole device 116 a-c. Advantageously, such a configuration may enable more precise measurements due to measuring individual downhole devices 116 a-c, as compared to taking a single measurement near the power source 118 and only obtaining overall system information.
FIG. 3 is a flow diagram of an illustrative permanent EM monitoring method 300. The method begins at block 302 with a crew coupling one or more EM monitoring downhole devices and a power cable to a tubular string. The power cable is coupled to a power source at or near the Earth's surface. Downhole devices may be, for example, electrodes or a multi-turn loop antenna. The crew further couples an optically-controlled switch between each of the downhole devices and the power cable. Of course, those skilled in the art will appreciate that the optically-controlled switch may alternatively be embedded with or part of the downhole device circuitry and need not be a physically separate attachment or hardware. The tubular string and equipment attached thereto may then be run into a borehole and cemented therein for permanent monitoring.
At block 304, a well operator may control the flow of power to each of the downhole devices via the switches coupled between the downhole devices and the power cable. Moreover, as at block 306, the operator may individually control each of the switches with a switch controller coupled thereto via an optical cable. Advantageously, only a single power cable and a single optical fiber are required, thus substantially saving space within the borehole and reducing or eliminating the problems of the prior art which may use individual power cables for each downhole device 116 a-c.
The method 300 may further monitor characteristics of the downhole devices. For example, the method 300 may employ a current sensor coupled to the device to monitor the current generated or received by the device. Alternatively, voltage of the downhole device may be measured using voltage sensors. Advantageously, taking such measurements at each device individually may provide the operator with more accurate and detailed data as compared to merely monitoring the overall system near the power source. Additional measurements that may be taken are, for example and without limitation, downhole temperature and vibrations. Such measurements may be conveyed to the surface via the optical fiber. The method 300 may utilize such measurements to determine a formation characteristic with a processor, such as formation resistivity.
Numerous other modifications, equivalents, and alternatives, will become apparent to those skilled in the art once the above disclosure is fully appreciated. For example, similar application can be applied to wireline resistivity logging, logging-while-drilling (LWD), electromagnetic ranging, and telemetry applications without departing from the scope of the present disclosure. It is intended that the following claims be interpreted to embrace all such modifications, equivalents, and alternatives where applicable.
Embodiments disclosed herein include:
A: A well having optically controlled switching, the well including a power cable run along a tubular string in a borehole, one or more downhole devices attached to the tubular string, one or more optically-controlled switches arranged downhole, where each switch is coupled between the power cable and one of the one or more downhole devices to enable or disable a flow of power to the downhole device, and a switch controller coupled to the one or more optically-controlled switches via an optical fiber, where each of the one or more optically-controlled switches are independently controllable.
B: A permanent electromagnetic (EM) monitoring method that includes positioning a tubular string having a power cable and one or more downhole devices attached thereto in a borehole, controlling the flow of power to each of the downhole devices via one or more optically-controlled switches arranged downhole, wherein each switch is coupled between one of the one or more downhole devices and the power cable, and controlling the one or more optically-controlled switches with a switch controller, the switch controller being coupled to the one or more optically-controlled switches via an optical fiber, and wherein each of the one or more optically-controlled switches are independently controllable
Each of embodiments A and B may have one or more of the following additional elements in any combination:
Element 1: At least one of the downhole devices includes a capacitive electrode. Element 2: At least one of the downhole devices includes a galvanic electrode. Element 3: At least one of the downhole devices includes a multi-turn loop antenna. Element 4: At least one of the downhole devices is an electric motor. Element 5: The switch controller is arranged at the surface. Element 6: An optical fiber current sensor coupled to at least one of the optically-controlled switches that measures a current of the corresponding downhole device. Element 7: An optical fiber voltage sensor coupled to at least one of the optically-controlled switch that measures a voltage of the corresponding downhole device. Element 8: Where the power cable is a multi-conductor cable. Element 9: Wherein the tubular string is electrically insulated. Element 10: Where the tubular string is a casing string cemented within the borehole. Element 11: A processing unit which determines a formation characteristic.
Element 12: Cementing the tubular string and downhole devices in the borehole. Element 13: Monitoring characteristics of the downhole devices. Element 14: Where the characteristic includes one of the group of an electrical current, an electrical voltage, a temperature, or a vibration. Element 15: Where the monitoring the electrical current is performed by an optical fiber current sensor coupled to one of the optically-controlled switches. Element 16: Where the monitoring the electrical voltage is performed by an optical fiber voltage sensor coupled to one of the optically-controlled switches. Element 17: Controlling one of a voltage, current, or waveform of the downhole devices with the corresponding optically-controlled switch. Element 18: Where one of the downhole devices is a multi-turn loop antenna, the method further comprising measuring an electromagnetic signal with the multi-turn loop antenna. Element 19: Where one of the downhole devices includes an electric motor, the method further comprising controlling the electric motor. Element 20: Further comprising determining a formation characteristic with a processing unit.

Claims

What is claimed is:

1. A well having optically-controlled switching, the well comprising:

a power cable run along a tubular string in a borehole;

one or more downhole devices attached to the tubular string;

one or more optically-controlled switches arranged downhole, wherein each switch is coupled between the power cable and one of the one or more downhole devices to enable or disable a flow of power to the downhole device; and

a switch controller coupled to the one or more optically-controlled switches via an optical fiber, wherein each of the one or more optically-controlled switches are independently controllable.

2. The well of claim 1, wherein at least one of the downhole devices includes a capacitive electrode.

3. The well of claim 1, wherein at least one of the downhole devices includes a galvanic electrode.

4. The well of claim 1, wherein at least one of the downhole devices includes a multi-turn loop antenna.

5. The well of claim 1, wherein at least one of the downhole devices is an electric motor.

6. The well of claim 1, wherein the switch controller is arranged at the surface.

7. The well of claim 1, further comprising an optical fiber current sensor coupled to at least one of the optically-controlled switches that measures a current of the corresponding downhole device.

8. The well of claim 1, further comprising optical fiber voltage sensor coupled to at least one of the optically-controlled switch that measures a voltage of the corresponding downhole device.

9. The well of claim 1, wherein the power cable is a multi-conductor cable.

10. The well of claim 1, wherein the tubular string is electrically insulated.

11. The well of claim 1, wherein the tubular string is a casing string cemented within the borehole.

12. The well of claim 1, further comprising a processing unit which determines a formation characteristic.

13. A permanent electromagnetic (EM) monitoring method, comprising:

positioning a tubular string having a power cable and one or more downhole devices attached thereto in a borehole;

controlling the flow of power to each of the downhole devices via one or more optically-controlled switches arranged downhole, wherein each switch is coupled between one of the one or more downhole devices and the power cable; and

controlling the one or more optically-controlled switches with a switch controller, the switch controller being coupled to the one or more optically-controlled switches via an optical fiber, and wherein each of the one or more optically-controlled switches are independently controllable.

14. The method of claim 13, further comprising cementing the tubular string and downhole devices in the borehole.

15. The method of claim 13, further comprising monitoring characteristics of the downhole devices.

16. The method of claim 15, wherein the characteristic includes one of the group of an electrical current, an electrical voltage, a temperature, or a vibration.

17. The method of claim 16, wherein the monitoring the electrical current is performed by an optical fiber current sensor coupled to one of the optically-controlled switches.

18. The method of claim 16, wherein the monitoring the electrical voltage is performed by an optical fiber voltage sensor coupled to one of the optically-controlled switches.

19. The method of claim 13, further comprising controlling one of a voltage, current, or waveform of the downhole devices with the corresponding optically-controlled switch.

20. The method of claim 13, wherein one of the downhole devices includes a multi-turn loop antenna, the method further comprising measuring an electromagnetic signal with the multi-turn loop antenna.

21. The method of claim 13, wherein one of the downhole devices includes an electric motor, the method further comprising controlling the electric motor.

22. The method of claim 13, further comprising determining a formation characteristic with a processing unit.