US20210164344A1

US20210164344A1 - Electromagnetic telemetry using active electrodes

Info

Publication number: US20210164344A1
Application number: US16/645,113
Authority: US
Inventors: Glenn Andrew WILSON; Scott Urquhart
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2017-12-29
Filing date: 2017-12-29
Publication date: 2021-06-03
Also published as: WO2019132977A1; WO2019132977A8; CA3075297A1; CA3075297C

Abstract

An electromagnetic (EM) telemetry system of a wellbore drilling and production environment includes at least one downhole sensor. The system also includes a downhole transceiver including an encoded signal transmitter. The encoded signal transmitter transmits data collected by the at least one downhole sensor. Further, the system includes an encoded signal receiver, which includes one or more active counter electrodes.

Description

BACKGROUND

The disclosure generally relates to systems and methods for electromagnetic (EM) telemetry. More specifically, the disclosure relates to EM telemetry using active electrodes during drilling, measurement-while-drilling (MWD), and/or logging-while-drilling (LWD) operations.
EM telemetry is a method of communicating between a bottom-hole assembly (BHA) and the surface of a wellbore during drilling applications. EM telemetry systems typically operate at low frequencies and data rates from a limited number of communication channels. The communications signals used in EM telemetry systems may be characterized by a signal-to-noise ratio (SNR) given by the ratio between the strength of the communication signal and the strength of the noise signal. In general, the SNR of EM telemetry systems provides a significant challenge to effective EM telemetry communication. A lowered SNR of an EM telemetry system may be due to high electrode contact resistance (ECR) of an electrode of the EM telemetry system.

BRIEF DESCRIPTION OF THE DRAWINGS

Illustrative embodiments of the present disclosure are described in detail below with reference to the attached drawing figures, which are incorporated by reference herein, and wherein:

FIG. 1 is a schematic view of a land based drilling system incorporating an electromagnetic (EM) telemetry system, in accordance with an embodiment of the disclosure;

FIG. 2 is a schematic view of a marine based production system having an EM telemetry system, in accordance with an embodiment of the disclosure;

FIG. 3 is a schematic view of a downhole transceiver of an EM telemetry system, in accordance with an embodiment of the disclosure;

FIG. 4 is a schematic view of a surface assembly of an EM telemetry system including an active galvanic counter electrode, in accordance with an embodiment of the disclosure;

FIG. 5 is a schematic view of a surface assembly of an EM telemetry system using a plurality of active counter electrodes, in accordance with an embodiment of the disclosure;

FIG. 6A is an equivalent circuit diagram of an active counter electrode and a high-impedance amplifier, in accordance with an embodiment of the disclosure;

FIG. 6B is an equivalent circuit diagram of an active counter electrode and a high-impedance amplifier, in accordance with an embodiment of the disclosure;

FIG. 7 is a flowchart of a method of EM telemetry, in accordance with an embodiment of the disclosure; and

FIG. 8 is a block diagram of a computer of an EM telemetry system, in accordance with an embodiment of the disclosure.

The illustrated figures are only exemplary and are not intended to assert or imply any limitation with regard to the environment, architecture, design, or process in which different embodiments may be implemented.

DETAILED DESCRIPTION

In the following detailed description of the illustrative embodiments, reference is made to the accompanying drawings that form a part hereof. These embodiments are described in sufficient detail to enable those skilled in the art to practice the disclosed subject matter, and it is understood that other embodiments may be utilized and that logical structural, mechanical, electrical, and chemical changes may be made without departing from the spirit or scope of the disclosure. To avoid detail not necessary to enable those skilled in the art to practice the embodiments described herein, the description may omit certain information known to those skilled in the art. The following detailed description is, therefore, not to be taken in a limiting sense, and the scope of the illustrative embodiments is defined only by the appended claims.
As used herein, the singular forms “a”, “an,” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms “comprise” and/or “comprising,” when used in this specification and/or the claims, specify the presence of stated features, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, steps, operations, elements, components, and/or groups thereof. In addition, the steps and components described in the embodiments and figures are merely illustrative and do not imply that any particular step or component is a requirement of a claimed embodiment.
Unless otherwise specified, any use of any form of the terms “connect,” “engage,” “couple,” “attach,” or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to”. Unless otherwise indicated, as used throughout this document, “or” does not require mutual exclusivity.
Further, spatially relative terms, such as beneath, below, lower, above, upper, uphole, downhole, upstream, downstream, and the like, may be used herein for ease of description to describe one element or feature's relationship to another element(s) or feature(s) as illustrated, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the wellbore along the wellbore, the downhole direction being toward the toe of the wellbore along the wellbore. Unless otherwise stated, the spatially relative terms are intended to encompass different orientations of the apparatus in use or operation in addition to the orientation depicted in the figures. For example, if an apparatus in the figures is turned over, elements described as being “below” or “beneath” other elements or features would then be oriented “above” the other elements or features. Thus, the exemplary term “below” can encompass both an orientation of above and below. The apparatus may be otherwise oriented (rotated 90 degrees or at other orientations) and the spatially relative descriptors used herein may likewise be interpreted accordingly.
Moreover, even though a figure may depict a horizontal wellbore or a vertical wellbore, unless indicated otherwise, it should be understood by those skilled in the art that the apparatus according to the present disclosure is equally well suited for use in wellbores having other orientations including vertical wellbores, slanted wellbores, multilateral wellbores or the like. Likewise, unless otherwise noted, even though a figure may depict an onshore operation, it should be understood by those skilled in the art that the apparatus according to the present disclosure is equally well suited for use in offshore operations and vice-versa. Further, unless otherwise noted, even though a figure may depict a cased hole, it should be understood by those skilled in the art that the apparatus according to the present disclosure is equally well suited for use in open hole operations and vice versa.
In one or more embodiments, an EM telemetry system is provided wherein active electrodes are used to improve the detection of encoded signals transmitted and received using EM telemetry during drilling, logging-while-drilling (LWD), measurement-while-drilling (MWD) operations, production operations, and/or other downhole operations. The use of active electrodes in an EM telemetry system offers numerous advantages over conventional EM telemetry systems and/or purely capacitive electrode EM telemetry systems, including limited electrode-formation contact resistance, long operational lifetime, low temperature drift, no electrochemical noise, short stabilization times, and ease of deployment.
Turning to FIGS. 1 and 2, a schematic illustration of a partial cross-section of a wellbore drilling and production system 10 utilized to produce hydrocarbons from wellbore 12 extending through various earth strata in an oil and gas formation 14 located below the earth's surface 16 is depicted. Wellbore 12 may be formed of a single or multiple bores 12 a, 12 b . . . 12 n (illustrated in FIG. 2), extending into the formation 14, and disposed in any orientation, such as the horizontal wellbore 12 b illustrated in FIG. 2.
The drilling and production system 10 includes a drilling rig or derrick 20. The drilling rig 20 may include a hoisting apparatus 22, a travel block 24, and a swivel 26 for raising and lowering casing, drill pipe, coiled tubing, production tubing, other types of pipe or tubing strings or other types of conveyance vehicles, such as wireline, slickline, and the like 30. In FIG. 1, the conveyance vehicle 30 is a substantially tubular, axially extending drill string formed of a plurality of drill pipe joints coupled together end-to-end. In FIG. 2, the conveyance vehicle 30 is completion tubing supporting a completion assembly as described below. The drilling rig 20 may include a kelly 32, a rotary table 34, and other equipment associated with rotation and/or translation of tubing string 30 within the wellbore 12. For some applications, the drilling rig 20 may also include a top drive unit 36.
The drilling rig 20 may be located proximate to a wellhead 40 as shown in FIG. 1, or spaced apart from wellhead 40, such as in the case of an offshore arrangement as shown in FIG. 2. One or more pressure control devices 42, such as blowout preventers (BOPS) and other equipment associated with drilling or producing the wellbore 12 may also be provided at the wellhead 40 or elsewhere in the system 10.
For offshore operations, as shown in FIG. 2, whether drilling or production, the drilling rig 20 may be mounted on an oil or gas platform 44, such as the offshore platform as illustrated, semi-submersibles, drill ships, and the like (not shown). Although the system 10 of FIG. 2 is illustrated as being a marine-based production system, the system 10 of FIG. 2 may be deployed on land. Likewise, although the system 10 of FIG. 1 is illustrated as being a land-based drilling system, the system 10 of FIG. 1 may be deployed offshore. In any event, for marine-based systems, one or more subsea conduits or risers 46 extend from deck 50 of the platform 44 to a subsea wellhead 40. The tubing string 30 extends down from drilling rig 20, through the subsea conduit 46 and BOP 42 into the wellbore 12.
A working or service fluid source 52 may supply a working fluid 58 pumped to the upper end of the tubing string 30 and flow through tubing string 30. The working fluid source 52 may supply any fluid utilized in wellbore operations, including without limitation, drilling fluid, cementitious slurry, acidizing fluid, liquid water, steam or some other type of fluid.
The wellbore 12 may include subsurface equipment 54 disposed therein, such as, for example, a drill bit and bottom hole assembly (BHA), a completion assembly or some other type of wellbore tool.
The wellbore drilling and production system 10 may generally be characterized as having a pipe system 56. For purposes of this disclosure, the pipe system 56 may include casing, risers, tubing, drill strings, completion or production strings, subs, heads or any other pipes, tubes or equipment that attaches to the foregoing, such as the string 30 and the conduit 46, as well as the wellbore and laterals in which the pipes, casing and strings may be deployed. In this regard, the pipe system 56 may include one or more casing strings 60 cemented in the wellbore 12, such as the surface, intermediate and production casing 60 shown in FIG. 1. An annulus 62 is formed between the walls of sets of adjacent tubular components, such as the concentric casing strings 60 or the exterior of tubing string 30 and the inside wall of the wellbore 12 or the casing string 60.
Where the subsurface equipment 54 is used when the drilling and conveyance vehicle 30 is a drill string, the lower end of the drill string 30 may include a bottom hole assembly (BHA) 64, which may carry a drill bit 66 at a downhole end of the BHA 64. During drilling operations, weigh-on-bit (WOB) is applied as the drill bit 66 is rotated, thereby enabling the drill bit 66 to engage the formation 14 and drill the wellbore 12 along a predetermined path toward a target zone. In general, the drill bit 66 may be rotated with the drill string 30 from the rig 20 with the top drive 36 or the rotary table 34, and/or with a downhole mud motor 68 within the BHA 64. The working fluid 58 may be pumped to the upper end of the drill string 30 and flow through a longitudinal interior 70 of the drill string 30, through the bottom hole assembly 64, and exit from nozzles formed in the drill bit 66. At a downhole end 72 of the wellbore 12, the drilling fluid 58 may mix with formation cuttings, formation fluids and other downhole fluids and debris. The drilling fluid mixture may then flow in an uphole direction through the annulus 62 to return formation cuttings and other downhole debris to the surface 16.
The bottom hole assembly 64 and/or the drill string 30 may include various other tools, including a power source 69, mechanical subs 71 such as directional drilling subs, and measurement equipment 73, such as measurement while drilling (MWD) and/or logging while drilling (LWD) instruments, sensors, circuits, or other equipment to provide information about the wellbore 12 and/or the formation 14. Measurement data and other information from the tools may be communicated using electrical signals, acoustic signals or other telemetry that can be converted to electrical signals at the rig 20 to monitor the performance of the drilling string 30, the bottom hole assembly 64, and the associated drill bit 66, as well as monitor the conditions of the environment to which the bottom hole assembly 64 is subjected.
With respect to FIG. 2 where the subsurface equipment 54 is illustrated as completion equipment, disposed in a substantially horizontal portion of the wellbore 12 is a lower completion assembly 74 that includes various tools such as an orientation and alignment subassembly 76, a packer 78, a sand control screen assembly 110, a packer 112, a sand control screen assembly 114, a packer 116, a sand control screen assembly 118 and a packer 120.
Extending downhole from lower completion assembly 74 is one or more communication cables 122. The communication cables 122 may include sensor or electric cables that pass through packers 78, 112, and 116 and are operably associated with one or more electrical devices 124 associated with lower completion assembly 74. The communication cables 122 may also be coupled to sensors positioned adjacent to sand control screen assemblies 110, 114, 118 or at the sand face of the formation 14, and/or the communication cables 122 may couple to downhole controllers or actuators used to operate downhole tools or fluid flow control devices. The cable 122 may operate as communication media and/or as power transmission cables. In an embodiment, the cable 122 transmits data and the like between the lower completion assembly 74 and an upper completion assembly 125.
In this regard, an upper completion assembly 125 is disposed in the wellbore 12 at the lower end of the tubing string 30. The upper completion assembly 125 includes various tools such as a packer 126, an expansion joint 128, a packer 100, a fluid flow control module 102, and an anchor assembly 104. Extending uphole from the upper completion assembly 125 are one or more communication cables 106, such as sensor cables or electric cables, which pass through packers 126 and 100 and extend to the surface 16. The cables 106 may operate as communication media and/or as power transmission cables. In an embodiment, the cables 106 transmit data and the like between a surface controller (not pictured) and the upper and lower completion assemblies 125, 74.
Shown deployed in FIGS. 1 and 2 is an electromagnetic (EM) telemetry system 80. In an embodiment, the EM telemetry system 80 includes a surface assembly 81 having a counter electrode 83 and a downhole transceiver 89. The EM telemetry system 80 allows for communication between the surface assembly 81 and the downhole transceiver 89. For example, the EM telemetry system 80 may allow communication between a control and/or data acquisition module (not shown) coupled to surface the assembly 81 and downhole equipment and/or sensor(s) coupled to the downhole transceiver 89. In one or more embodiments, the EM telemetry system 80 may be bidirectional; that is, one or both of the surface assembly 81 and the downhole transceiver 89 may be configured as a transmitter and/or receiver of the EM telemetry system 80 either sequentially or at a given time. In furtherance of such embodiments, any suitable simple duplexing or duplexing technique may be utilized, such as time division duplexing, frequency division duplexing, or the like. In one or more embodiments, the EM telemetry system 80 may be unidirectional.
Encoded signal 90, as depicted in FIGS. 1 and 2, is a time-varying electromagnetic field that carries information between the surface assembly 81 and the downhole transceiver 89. For example, the encoded signal 90 may carry the measurement and/or logging data acquired by the downhole equipment and/or the downhole sensors (e.g., at the BHA 64), the data being transmitted to the surface for further processing and control of the drilling operation. Because encoded signal 90 may be transmitted and received during a drilling operation, the EM telemetry system 80 is suitable for measurement-while-drilling (MWD) and/or logging-while-drilling applications. For example, the encoded signal 90 may carry measurement data, logging data, and/or instructions for drilling tools, such as directions used for directional drilling applications. In one or more embodiments, the information carried by the encoded signal 90 may be in a digital and/or analog format. Accordingly, any suitable digital or analog encoding or modulation scheme may be employed to achieve reliable, secure, and/or high speed communication between the downhole transceiver 89 and the surface assembly 81. In one or more embodiments, the encoding and modulation scheme may include pulse width modulation, pulse position modulation, on-off keying, amplitude modulation, frequency modulation, single-side-band modulation, frequency shift keying, phase shift keying (e.g., binary phase shift keying and/or M-ary phase shift keying), discrete multi-tone, orthogonal frequency division multiplexing, and/or the like. In one or more embodiments, encoded signal 90 may have a nominal frequency range between 1 Hz and 50 Hz and a nominal physical data rate of between 3 and 12 bits per second.
When the EM telemetry system 80 operates with the downhole transceiver 89 as the transmitter and the surface assembly 81 as the receiver, the encoded signal 90 is generated by applying a voltage signal across a gap in the downhole transceiver 89. For example, the gap may electrically insulate the drill bit 66 from the drill string 30. More generally, the gap electrically insulates a portion of the system 10 that is electrically coupled to the wellhead 40 from a portion of the system 10 that is electrically coupled to the formation 14. In one or more embodiments, the applied voltage signal may have a strength of approximately 3 V (e.g., nominally between 0.5 and 5 V). The encoded signal 90 propagates through the earth and the drill string 30 to the surface assembly 81. At the surface, the counter electrode 83 measures a voltage signal corresponding to the encoded signal 90, the voltage signal being determined based on a differential voltage between the counter electrode 83 and the wellhead 40. In other embodiments, the differential voltage is measured between two surface deployed counter electrodes 83. The measured voltage signal is demodulated and/or decoded to recover the information carried by the encoded signal 90. In one or more embodiments, the measured voltage signal may have a strength of approximately 10 μV. Similarly, when the EM telemetry system 80 operates with the surface assembly 81 as the transmitter and the downhole transceiver 89 as the receiver of the encoded signal 90, the encoded signal 90 is transmitted by applying a voltage signal between the counter electrode 83 and the wellhead 40. In other embodiments, the voltage signal is transmitted between two surface deployed counter electrodes 83. A corresponding voltage signal across the gap in downhole transceiver is measured, demodulated, and/or decoded to recover the information carried by the encoded signal 90.
Although the downhole transceiver 89 is not limited to a particular type or configuration, FIG. 3 illustrates an embodiment of the downhole transceiver 89. In one or more embodiments, the downhole transceiver 89 may be configured as an encoded signal transmitter of the EM telemetry system 80. In furtherance of such embodiments, the downhole transceiver 89 may include a controller 310 that includes an encoder 311, a modulator 312, and a transmitter 313. In one or more embodiments, the downhole transceiver 89 may be additionally and/or alternatively configured as a receiver of the EM telemetry system 80. In furtherance of such embodiments, the controller 310 may include a decoder 314, a demodulator 315, and a receiver 316. In one or more embodiments, the encoder 311 may be communicatively coupled to one or more downhole data sources, such as downhole equipment 330 and/or a downhole sensor 340, and the encoder 311 may receive analog and/or digital data from the data sources over an input interface 322. The encoder 311 may convert the received data into a stream of bits, the modulator 312 may convert the stream of bits into analog and/or digital symbols, and the transmitter 313 may convert the symbols into a voltage signal corresponding to encoded signal. The encoder 311 may perform various operations on the incoming data including source encoding, interleaving, encryption, channel encoding, convolutional encoding, and/or the like. In one or more embodiments, the modulator 312 may modulate the incoming stream of bits according to a variety of modulation schemes including pulse width modulation, pulse position modulation, on-off keying, amplitude modulation, frequency modulation, single-side-band modulation, frequency shift keying, phase shift keying (e.g., binary phase shift keying and/or M-ary phase shift keying), discrete multi-tone, orthogonal frequency division multiplexing, and the like.
The voltage signal from the transmitter 313 is applied between a gap 332 in the downhole transceiver 89. As depicted in FIG. 3, the gap 332 electrically insulates the drill bit 66 from drill string 30 in accordance with FIG. 1. However, it is to be understood that the gap 332 may separate other downhole components, such as the wireline 30 from the upper completion assembly 125 as depicted in FIG. 2. Analogously, where the downhole transceiver 89 is configured as an encoded signal receiver of the EM telemetry system 80, the decoder 314, the demodulator 315, and the receiver 316 may operate to measure a voltage signal across the gap 332 and demodulate/decode the measured voltage signal to provide output analog and/or digital data to one or more downhole tools over an output interface 324.
In one or more embodiments, the downhole sensor 340 may be associated with, coupled to, and/or otherwise disposed to monitor the downhole equipment 330 and may transmit information (e.g., measurement and/or logging data) associated with the downhole equipment 330 to the surface assembly 81 through the controller 310. In one or more embodiments, the downhole equipment 330 may receive instructions from the surface assembly 81 through the controller 310. In some embodiments, the downhole equipment 330 may include drilling equipment, logging-while-drilling (LWD) equipment, measurement-while-drilling (MWD) equipment, production equipment, and the like. In an embodiment, the downhole sensor 340 may include one or more temperature sensors, pressure sensors, strain sensors, pH sensors, density sensors, viscosity sensors, chemical composition sensors, radioactive sensors, resistivity sensors, acoustic sensors, potential sensors, mechanical sensors, nuclear magnetic resonance logging sensors, gravity sensor, a pressure sensor, a fixed length line sensor, optical tracking sensor, a fluid metering sensor, an acceleration integration sensor, a velocity timing sensor, an odometer, a magnetic feature tracking sensor, an optical feature tracking sensor, an electrical feature tracking sensor, an acoustic feature tracking sensor, a dead reckoning sensor, a formation sensor, an orientation sensor, an impedance type sensor, a diameter sensor, and the like.
Although the surface assembly 81 is not limited to a particular type or configuration, FIG. 4 illustrates an embodiment of the surface assembly 81. In one or more embodiments, the surface assembly 81 may be configured as an encoded signal transmitter of the EM telemetry system 80. In furtherance of such embodiments, the surface assembly 81 may include a controller 410 that includes an encoder 411, a modulator 412, and a transmitter 413, as described above with respect to FIG. 3. In one or more embodiments, the surface assembly 81 may be additionally or alternatively configured as an encoded signal receiver of the EM telemetry system 80. In furtherance of such embodiments, the controller 410 may include a decoder 414, a demodulator 415, and/or a receiver 416. The functions performed by the decoder 414, the demodulator 415, and the receiver 416 on the received data generally mirror the functions performed by the encoder 311, the modulator 312, and the transmitter 313 depicted in FIG. 3. For example, the decoder 414 may perform source decoding, de-interleaving, channel decoding, convolutional decoding, and the like. The controller 410 may further include an input interface 422 and an output interface 424 for communicating transmitted or received data, respectively, to and from various data sources and/or sinks, such as a control and/or data collection module, a user interface, and the like.
As illustrated in FIG. 4, the surface assembly 81 includes at least one active counter electrode 83. The active counter electrode 83 is used by the receiver 416 to measure a voltage signal between the active counter electrode 83 and the wellhead 40 shown in FIGS. 1 and 2. A shielded wire 440 couples the controller 410 to the wellhead 40 such that a potential difference between the active counter electrode 83 and the wellhead 40 may be measured and/or applied by the controller 410. In some embodiments, the active counter electrode 83 is placed ten or more meters from the wellhead 40. Further, in an embodiment, the potential difference in voltage signals may be measured between multiple active counter electrodes 83 instead of between an active counter electrode 83 and the wellhead 40.
As illustrated, the active counter electrode 83 is electrically coupled to the earth. For example, the active counter electrode 83 may include a metal stake, a porous pot, an abandoned or active well head or oil rig, a wellbore casing, and/or the like. Additionally, the active counter electrode 83 may be positioned at the surface 16 of the formation 14, or the active counter electrode 83 may also be positioned beneath the surface 16 of the formation 14, for example, in an adjacent wellbore. In an embodiment, the active counter electrode 83 include the wellhead 40 of the wellbore drilling and production system 10 in combination with active circuitry, such as a high-impedance amplifier 444, such that the wellhead 40 appears to be an active counter electrode 83 by the receiver 416.
In an embodiment, the active counter electrode 83 includes a metal stake or plate 442 that electrically couples to the earth, although other electrochemical electrodes (e.g., porous pots) that electrically couple to the earth may be used in place of the metal stake or plate 442. The electrical coupling of the active counter electrodes 83 to the earth is predominantly galvanic. Galvanic electrodes operate as electro-chemical transducers that convert electrical conduction from ionic conduction in the formation 434 (i.e., the earth) to electronic conduction in the metal electrode. The electrochemical reactions at the electrodes, involving gain or loss of electrons, are oxidation-reduction reactions.
The active galvanic counter electrodes 83 tend to have a high electrode-formation contact resistance (i.e., the resistance between the counter electrode and the earth). Furthermore, the electrode-formation contact resistance may vary significantly in time and location. Galvanic counter electrodes may be implemented using a solid metal (e.g., stainless steel, titanium, etc.) or a metal-metal salt porous pot (e.g., Ag/AgCl) in contact with formation and formation fluids. In these and similar implementations, the contact resistance of the counter electrode is primarily determined by a transition layer at the surface of the electrodes where electronic conduction in the metal portion of the electrode is converted to and from ionic conduction in the formation. Such a transition layer typically includes two sub-layers of differing electrochemistry. The electrochemistry of this so-called “double layer” is complex and results in a high resistance for current to flow from the electrode into the formation or from the formation into the electrode. Further, concentrations of different ionic species in the formation fluids vary in time and space. The variability of the formation fluids, which interact with the double layer, causes the contact resistance to be variable in time and/or location.
To combat the high electrode contact resistance of the active counter electrode 83, a high-impedance amplifier 444 is positioned in close physical proximity and in series with the metal stake or plate 442 or other galvanic counter electrode to make up the active counter electrode 83. As used herein, the term close physical proximity is intended to mean within 0.5 meters. An input impedance of the high-impedance amplifier 444 may be approximately 1 MOhm (e.g., between 500 kOhm and 10 MOhm) or greater. Any effect of the contact resistance on a voltage measured at the active counter electrode 83 is limited by the high impedance of the amplifier 444. Especially in locales that increase the electrode contact resistance, such as on frozen ground, ice, or dry sand, the effects of the electrode contact resistance are avoided using the amplifier 444 such that an adequate signal is received by the active counter electrode 83. Further, wire-to-ground capacitance in wires from the active counter electrode 83 to the receiver 416 is avoided by using a shielded wire or cable from the impedance amplifier 444 to the receiver 416. In an embodiment, the amplifier 444 may include a negative feedback loop 448. The negative feedback loop 448 may reduce fluctuations at an output of the amplifier 444 and promote settling of a signal output from the amplifier 444.
Although a single active counter electrode 83 is depicted in FIG. 4, it is to be understood that the surface assembly 81 may include a plurality of active counter electrodes 83. In FIG. 5, an example of the surface assembly 81 including a plurality of active counter electrodes 83, 83 b, . . . 83 n is depicted according to an embodiment. As illustrated, one or more of the active counter electrodes 83, 83 b, . . . 83 n may be galvanically coupled to the earth using a metal stake or plate 442, as depicted in FIG. 4, or using any other electrode that galvanically couples to the earth (e.g., a porous pot, an adjacent well casing, or an abandoned or active wellhead). A controller 510 measures and/or applies a voltage signal from the active counter electrodes 83, 83 b, . . . 83 n to receive and/or transmit information on input and output interfaces 522 and 524, respectively. A wire 540 couples the controller 510 to the wellhead 40 (as illustrated in FIGS. 1 and 2) such that a potential difference between the active counter electrodes 83, 83 b, . . . 83 n and the wellhead 40 may be measured or applied by the controller 510. In an embodiment, the active counter electrodes 83, 83 b, . . . 83 n may be configured relative to one another as a grid, ring, line, and/or any other suitable array configuration. An advantage of configuring active counter electrodes 83, 83 b, . . . 83 n as an array of electrodes is the ability to orient and/or arrange the active counter electrodes 83-83 n to improve a signal-to-noise ratio of the EM telemetry system 80.
Additionally, as discussed above with respect to FIG. 4, the active counter electrodes 83, 83 b, . . . 83 n each include high-impedance amplifiers 444 to minimize any effects of contact resistance on the voltage received by the active counter electrodes 83, 83 b, . . . 83 n. An output of the amplifiers 444 is provided to the shielded cable or wire 446 to avoid wire-to-ground capacitance. Optionally, negative feedback loops 448 are provided at the amplifiers 444 to provide stability to the output of the amplifiers 444.
FIG. 6A is an equivalent circuit diagram 600A of the active counter electrode 83 and the high-impedance amplifier 444 according to an embodiment. The equivalent circuit diagram 600A includes a voltage source 601 received from the formation 14 and measured by the active counter electrode 83. The active counter electrode 83 includes an electrode resistance 602 and an electrode capacitance 604. The electrode resistance 602 and the electrode capacitance 604 collectively form an electrode contact impedance between the active counter electrode 83 and the formation 14.
Also illustrated in FIG. 6A is a wire resistance 606, a wire inductance 608, and a wire capacitance 610. The adverse effects of the wire resistance 606, the wire inductance 608, and the wire capacitance 610 on the voltage signal provided by the voltage source 601 are heightened as a length 612 of a wire 614 between the active counter electrode 83 and the amplifier 444 increases. As the length 612 increases, the wire resistance 606, the wire inductance 608, and the wire capacitance 610 may all increase, which may result in a diminished signal provided to the amplifier 444.
Turning to FIG. 6B, an equivalent circuit diagram 600B is provided with a smaller length 620 of the wire 614 in comparison to the length 612 of FIG. 6A. By reducing the length 620 of the wire 614 to less than 0.5 meters, the effects of the wire resistance 606, the wire inductance 608, and the wire capacitance 610 may be minimized. Further, because the input impedance of the amplifier 444 (e.g., approximately 1 MOhm) is much larger than the contact impedance created by the electrode resistance 602 and the electrode capacitance 604, the signal at an output 622 of the amplifier 444 is effectively equal to the signal of the voltage source 601.
For a wire running from the output 622 at the amplifier 444 to the receiver 416, as illustrated in FIG. 4, the amplifier 444 acts as an ideal voltage source. That is, the output 622 of the amplifier 444 has a negligible output impedance. Accordingly, the receiver 416 receives only the voltage signal output by the amplifier 444, which is equal to the voltage signal from the voltage source 601, without effects of the electrode resistance 602 and the electrode capacitance 604 that generate the contact impedance at the active counter electrode 83.
FIG. 7 is a simplified diagram of a method 700 of EM telemetry using active counter electrodes 83 according to an embodiment. The EM telemetry system 80 may perform the method 700 to achieve reliable and accurate communication between a surface assembly (such as the surface assembly 81) and a downhole transceiver (such as the downhole transceiver 89). More specifically, a controller of the surface assembly, such as the controller 410 and/or 510 depicted in FIGS. 4 and 5, respectively, may perform the method 700 when communicating with the downhole transceiver 89.
At step 710, a first encoded signal is received using one or more active counter electrodes, such as the active electrode 83. In one or more embodiments, the received encoded signal corresponds to a voltage vm measured between the counter electrode 83 and the wellhead 40. The measured voltage signal vm may be represented in analog and/or digital format. The measured voltage signal vm is characterized by a signal-to-noise ratio (SNR) measured by dividing the strength of the encoded signal 90 by the strength of various noise signals. According to some embodiments, the first encoded signal may be transmitted by a downhole transceiver and may carry information from one or more downhole tools to the surface. For example, the first encoded signal 90 may carry data including measurement-while-drilling data and logging-while-drilling data. In one or more embodiments, the voltage difference between the counter electrode 83 and the wellhead 40 may be measured using a high input impedance receiver 416. For example, the receiver may have an input impedance of 1 MOhm or greater.
At step 720, the first encoded signal 90 is demodulated and decoded to recover the information carried in the first encoded signal. Owing to the advantages of the active electrodes discussed above, in one or more embodiments the demodulator 415 and decoder 414 operated in accordance with the method 700 may generate output data more reliable and/or faster than conventional EM telemetry systems. The demodulation and decoding processes generally mirror the processing steps applied by the downhole transceiver 89 to generate the first encoded signal 90. In one or more embodiments, the encoding and modulation scheme (and corresponding decoding and demodulation scheme) may include pulse width modulation, pulse position modulation, on-off keying, amplitude modulation, frequency modulation, single-side-band modulation, frequency shift keying, phase shift keying (e.g., binary phase shift keying and/or M-ary phase shift keying), discrete multi-tone, orthogonal frequency division multiplexing, and the like.
At step 730, a second encoded signal 90 is encoded and modulated. According to some embodiments, the second encoded signal may carry information from the surface 16 to one or more downhole tools. For example, the second encoded signal 90 may carry instructions for the downhole tools, such as directions for directional drilling applications. In one or more embodiments, the encoding and modulation scheme (and corresponding decoding and demodulation scheme) may include pulse width modulation, pulse position modulation, on-off keying, amplitude modulation, frequency modulation, single-side-band modulation, frequency shift keying, phase shift keying (e.g., binary phase shift keying and/or M-ary phase shift keying), discrete multi-tone, orthogonal frequency division multiplexing, and the like.
At step 740, the second encoded signal 90 is transmitted using the one or more active counter electrodes. In one or more embodiments, the second encoded signal is transmitted by applying a time-varying differential voltage va between the one or more active counter electrodes 83 and the wellhead 40. According to some embodiments, the second encoded signal may be received by a downhole transceiver 89 coupled to the downhole tools 330. In one or more embodiments, the voltage between the counter electrode 83 and the wellhead 40 may be applied using a low output impedance transmitter, such as transmitter 413. For example, the transmitter may have an output impedance of 10 Ohms or less.
Any one of the foregoing methods may be particularly useful during various procedures in a wellbore. Thus, in one or more embodiments, a wellbore may be drilled, and during drilling or during a suspension in drilling, information about downhole equipment disposed in the wellbore may be generated. The downhole equipment may be selected from the group consisting of drilling equipment, logging-while-drilling (LWD) equipment, measurement-while-drilling (MWD) equipment, and production equipment. Likewise, in one or more embodiments, downhole production equipment may be disposed in a wellbore, and during production operations, information about downhole equipment disposed in the wellbore may be generated. The information may be generated utilizing one or more sensors disposed in the wellbore and selected from the group consisting of temperature sensors, pressure sensors, strain sensors, pH sensors, density sensors, viscosity sensors, chemical composition sensors, radioactive sensors, resistivity sensors, acoustic sensors, potential sensors, mechanical sensors, nuclear magnetic resonance logging sensors, gravity sensor, a pressure sensor, a fixed length line sensor, optical tracking sensor, a fluid metering sensor, an acceleration integration sensor, a velocity timing sensor, an odometer, a magnetic feature tracking sensor, an optical feature tracking sensor, an electrical feature tracking sensor, an acoustic feature tracking sensor, a dead reckoning sensor, a formation sensor, an orientation sensor, an impedance type sensor, and a diameter sensor.
FIG. 8 is a block diagram of an exemplary computer system 800 in which embodiments of the present disclosure may be adapted for performing EM telemetry. For example, the steps of the operations of the method 700 of FIG. 7 and/or the components of the controller 310 of FIG. 3, the controller 410 of FIG. 4, and/or the controller 510 of FIG. 5, as described above, may be implemented using the system 800. The system 800 may be a computer, phone, personal digital assistant (PDA), or any other type of electronic device. Such an electronic device includes various types of computer readable media and interfaces for various other types of computer readable media. As shown in FIG. 8, the system 800 includes a permanent storage device 802, a system memory 804, an output device interface 806, a system communications bus 808, a read-only memory (ROM) 810, processing unit(s) 812, an input device interface 814, and a network interface 816.
The bus 808 collectively represents all system, peripheral, and chipset buses that communicatively connect the numerous internal devices of the system 800. For instance, the bus 808 communicatively connects the processing unit(s) 812 with the ROM 810, the system memory 804, and the permanent storage device 802.
From these various memory units, the processing unit(s) 812 retrieve instructions to execute and data to process in order to execute the processes of the presently disclosed subject matter. The processing unit(s) may be a single processor or a multi-core processor in different implementations.
The ROM 810 stores static data and instructions that are needed by the processing unit(s) 812 and other modules of the system 800. The permanent storage device 802, on the other hand, is a read-and-write memory device. This device is a non-volatile memory unit that stores instructions and data even when the system 800 is in a powered off state. Some implementations of the subject disclosure use a mass-storage device (such as a magnetic or optical disk and its corresponding disk drive) as the permanent storage device 802.
Other implementations use a removable storage device (such as a floppy disk, flash drive, and its corresponding disk drive) as the permanent storage device 802. Like the permanent storage device 802, the system memory 804 is a read-and-write memory device. However, unlike the storage device 802, the system memory 804 is a volatile read-and-write memory, such as random access memory (RAM). The system memory 804 stores some of the instructions and data that the processor needs at runtime. In some implementations, the processes of the subject disclosure are stored in the system memory 804, the permanent storage device 802, and/or the ROM 810. For example, the various memory units include instructions for computer aided pipe string design based on existing string designs in accordance with some implementations. From these various memory units, the processing unit(s) 812 retrieve instructions to execute and data to process in order to execute the processes of some implementations.
The bus 808 also connects to the input and output device interfaces 814 and 806, respectively. The input device interface 814 enables the user to communicate information and select commands to the system 800. Input devices used with the input device interface 814 include, for example, alphanumeric, QWERTY, or T9 keyboards, microphones, and pointing devices (also called “cursor control devices”). The output device interfaces 806 enable, for example, the display of images generated by the system 800. Output devices used with the output device interface 806 include, for example, printers and display devices, such as cathode ray tubes (CRT), liquid crystal displays (LCD), and/or light emitting diode (LED) displays. Some implementations include devices such as a touchscreen that functions as both input and output devices. It should be appreciated that embodiments of the present disclosure may be implemented using a computer including any of various types of input and output devices for enabling interaction with a user. Such interaction may include feedback to or from the user in different forms of sensory feedback including, but not limited to, visual feedback, auditory feedback, or tactile feedback. Further, input from the user can be received in any form including, but not limited to, acoustic, speech, or tactile input. Additionally, interaction with the user may include transmitting and receiving different types of information, e.g., in the form of documents, to and from the user via the above-described interfaces.
Also, as shown in FIG. 8, the bus 808 couples the system 800 to a public or private network (not shown) or combination of networks through a network interface 816. Such a network may include, for example, a local area network (LAN), such as an intranet, or a wide area network (WAN), such as the internet. Any or all components of the system 800 may be used in conjunction with the subject disclosure.
The functions described above can be implemented in digital electronic circuitry, in computer software, firmware, or hardware. The techniques can be implemented using one or more computer program products. Programmable processors and computers can be included in or packaged as mobile devices. The processes and logic flows can be performed by one or more programmable processors and by one or more programmable logic circuitry. General and special purpose computing devices and storage devices can be interconnected through communication networks.
Some implementations include electronic components, such as microprocessors, storage, and memory that store computer program instructions in a machine-readable or computer-readable medium (alternatively referred to as computer-readable storage media, machine-readable media, or machine-readable storage media). Some examples of such computer-readable media include RAM, ROM, read-only compact discs (CD-ROM), recordable compact discs (CD-R), rewritable compact discs (CD-RW), read-only digital versatile discs (e.g., DVD-ROM, dual-layer DVD-ROM), a variety of recordable/rewritable DVDs (e.g., DVD-RAM, DVD-RW, DVD+RW, etc.), flash memory (e.g., SD cards, mini-SD cards, micro-SD cards, etc.), magnetic and/or solid state hard drives, read-only and recordable Blu-Ray® discs, ultra density optical discs, any other optical or magnetic media, and floppy disks. The computer-readable media can store a computer program that is executable by at least one processing unit and includes sets of instructions for performing various operations. Examples of computer programs or computer code include machine code, such as is produced by a compiler, and files including higher-level code that are executed by a computer, an electronic component, or a microprocessor using an interpreter.
While the above discussion primarily refers to microprocessor or multi-core processors that execute software, some implementations are performed by one or more integrated circuits, such as application specific integrated circuits (ASICs) or field programmable gate arrays (FPGAs). In some implementations, such integrated circuits execute instructions that are stored on the circuit itself. Accordingly, the steps of the operations of method 700 of FIG. 7, as described above, may be implemented using the system 800 or any computer system having processing circuitry or a computer program product including instructions stored therein, which, when executed by at least one processor, causes the processor to perform functions relating to these methods.
As used in this specification and any claims of this application, the terms “computer,” “server,” “processor,” and “memory” all refer to electronic or other technological devices. These terms exclude people or groups of people. As used herein, the terms “computer readable medium” and “computer readable media” refer generally to tangible, physical, and non-transitory electronic storage mediums that store information in a form that is readable by a computer.
Embodiments of the subject matter described in this specification can be implemented in a computing system that includes a back end component, e.g., a data server; a middleware component, e.g., an application server; a front end component, e.g., a client computer having a graphical user interface or a Web browser through which a user can interact with an implementation of the subject matter described in this specification; or any combination of one or more such back end, middleware, or front end components. The components of the system can be interconnected by any form or medium of digital data communication, e.g., a communication network. Examples of communication networks include a local area network (LAN) and a wide area network (WAN), an inter-network (e.g., the Internet), and peer-to-peer networks (e.g., ad hoc peer-to-peer networks).
The computing system can include clients and servers. A client and server are generally remote from each other and typically interact through a communication network. The relationship of client and server arises by virtue of computer programs running on the respective computers and having a client-server relationship to each other. In some embodiments, a server transmits data (e.g., a web page) to a client device (e.g., for purposes of displaying data to and receiving user input from a user interacting with the client device). Data generated at the client device (e.g., a result of the user interaction) can be received from the client device at the server.
It is understood that any specific order or hierarchy of steps in the processes disclosed is an illustration of exemplary approaches. Based upon design preferences, it is understood that the specific order or hierarchy of steps in the processes may be rearranged, or that all illustrated steps be performed. Some of the steps may be performed simultaneously. For example, in certain circumstances, multitasking and parallel processing may be advantageous. Moreover, the separation of various system components in the embodiments described above should not be understood as requiring such separation in all embodiments, and it should be understood that the described program components and systems can generally be integrated together in a single software product or packaged into multiple software products.
Furthermore, the exemplary methodologies described herein may be implemented by a system including processing circuitry or a computer program product including instructions which, when executed by at least one processor, causes the processor to perform any of the methodology described herein.
The above-disclosed embodiments have been presented for purposes of illustration and to enable one of ordinary skill in the art to practice the disclosure, but the disclosure is not intended to be exhaustive or limited to the forms disclosed. Many insubstantial modifications and variations will be apparent to those of ordinary skill in the art without departing from the scope and spirit of the disclosure. For instance, although the flowchart depicts a serial process, some of the steps/processes may be performed in parallel or out of sequence, or combined into a single step/process. The scope of the claims is intended to broadly cover the disclosed embodiments and any such modification. Further, the following clauses represent additional embodiments of the disclosure and should be considered within the scope of the disclosure:
Clause 1, an electromagnetic (EM) telemetry system of a wellbore drilling and production environment, the system comprising: at least one downhole sensor; a downhole transceiver comprising an encoded signal transmitter, the encoded signal transmitter configured to transmit data collected by the at least one downhole sensor; and an encoded signal receiver comprising one or more active counter electrodes.
Clause 2, the system of clause 1, wherein the downhole sensor is communicatively coupled to the transceiver.
Clause 3, the system of clause 1 or 2, wherein the encoded signal receiver is disposed at a surface of the wellbore drilling and production environment.
Clause 4, the system of at least one of clauses 1-3, wherein the encoded signal transmitter transmits an encoded signal comprising the data collected by the at least one downhole sensor.
Clause 5, the system of at least one of clauses 1-4, wherein the one or more active counter electrodes each comprise a galvanic electrode in series with an amplifier.
Clause 6, the system of clause 5, wherein the galvanic electrode comprises a metal-metal salt porous pot.
Clause 7, the system of clause 5, wherein the galvanic electrode comprises a metal rod, a metal plate, an adjacent well casing, or an abandoned wellhead.
Clause 8, the system of at least one of clauses 5-7, wherein the amplifier comprises a negative feedback loop.
Clause 9, the system of at least one of clauses 1-8, wherein the one or more active counter electrodes are positioned beneath a surface of a formation.
Clause 10, the system of at least one of clauses 1-9, wherein the one or more active counter electrodes comprise at least two active counter electrodes, and the encoded signal receiver is configured to measure a potential difference between two of the at least two active counter electrodes.
Clause 11, the system of at least one of clauses 1-10, wherein one of the one or more active counter electrodes comprises an active wellhead of the wellbore drilling and production environment.
Clause 12, the system of at least one of clauses 1-11, wherein the one or more active counter electrodes are arranged in an array configuration.
Clause 13, a method for communicating with a downhole transceiver, the method comprising: receiving a first encoded signal using an active counter electrode; decoding the first encoded signal; encoding a second encoded signal; and transmitting the second encoded signal using the active counter electrode.
Clause 14, the method of clause 13, wherein the first encoded signal carries data including one or more of measurement-while-drilling data and logging-while drilling data.
Clause 15, the method of clause 13 or 14, wherein the second encoded signal carries data including instructions for downhole equipment coupled to the downhole transceiver.
Clause 16, the method of at least one of clauses 13-15, wherein receiving the first encoded signal comprises: receiving a first voltage signal at the active counter electrode; receiving a second voltage signal at a wellhead; and measuring a voltage difference between the first voltage signal and the second voltage signal.
Clause 17, the method of at least one of clauses 13-16, wherein the active counter electrode comprises a galvanic electrode in series with an amplifier.
Clause 18, an electromagnetic (EM) telemetry system, comprising: at least one downhole sensor; a downhole transceiver comprising an encoded signal transmitter, the encoded signal transmitter configured to transmit data collected by the at least one downhole sensor into a formation; and an encoded signal receiver comprising one or more active counter electrodes, the one or more active counter electrodes comprising a galvanic electrode in series with an amplifier.
Clause 19, the method of clause 18, wherein the amplifier comprises a negative feedback loop.
Clause 20, the method of clause 18 or 19, wherein the amplifier comprises an input impedance of between 500 kOhm and 10 MOhm.
While this specification provides specific details related to electromagnetic telemetry using active counter electrodes, it may be appreciated that the list of components is illustrative only and is not intended to be exhaustive or limited to the forms disclosed. Other components related to the multi-frequency communications will be apparent to those of ordinary skill in the art without departing from the scope and spirit of the disclosure. Further, the scope of the claims is intended to broadly cover the disclosed components and any such components that are apparent to those of ordinary skill in the art.
It should be apparent from the foregoing disclosure of illustrative embodiments that significant advantages have been provided. The illustrative embodiments are not limited solely to the descriptions and illustrations included herein and are instead capable of various changes and modifications without departing from the spirit of the disclosure.

Claims

What is claimed is:

1. An electromagnetic (EM) telemetry system of a wellbore drilling and production environment, the system comprising:

at least one downhole sensor;

a downhole transceiver comprising an encoded signal transmitter, the encoded signal transmitter configured to transmit data collected by the at least one downhole sensor; and

an encoded signal receiver comprising one or more active counter electrodes.

2. The system of claim 1, wherein the downhole sensor is communicatively coupled to the transceiver.

3. The system of claim 1, wherein the encoded signal receiver is disposed at a surface of the wellbore drilling and production environment.

4. The system of claim 1, wherein the encoded signal transmitter transmits an encoded signal comprising the data collected by the at least one downhole sensor.

5. The system of claim 1, wherein the one or more active counter electrodes each comprise a galvanic electrode in series with an amplifier.

6. The system of claim 5, wherein the galvanic electrode comprises a metal-metal salt porous pot.

7. The system of claim 5, wherein the galvanic electrode comprises a metal rod, a metal plate, an adjacent well casing, or an abandoned wellhead.

8. The system of claim 5, wherein the amplifier includes a negative feedback loop.

9. The system of claim 1, wherein the one or more active counter electrodes are positioned beneath a surface of a formation.

10. The system of claim 1, wherein the one or more active counter electrodes comprise at least two active counter electrodes, and the encoded signal receiver is configured to measure a potential difference between two of the at least two active counter electrodes.

11. The system of claim 1, wherein one of the one or more active counter electrodes comprises an active wellhead of the wellbore drilling and production environment.

12. The system of claim 1, wherein the one or more active counter electrodes are arranged in an array configuration.

13. A method for communicating with a downhole transceiver, the method comprising:

receiving a first encoded signal using an active counter electrode;

decoding the first encoded signal;

encoding a second encoded signal; and

transmitting the second encoded signal using the active counter electrode.

14. The method of claim 13, wherein the first encoded signal carries data including one or more of measurement-while-drilling data and logging-while drilling data.

15. The method of claim 13, wherein the second encoded signal carries data including instructions for downhole equipment coupled to the downhole transceiver.

16. The method of claim 13, wherein receiving the first encoded signal comprises:

receiving a first voltage signal at the active counter electrode;

receiving a second voltage signal at a wellhead; and

measuring a voltage difference between the first voltage signal and the second voltage signal.

17. The method of claim 13, wherein the active counter electrode comprises a galvanic electrode in series with an amplifier.

18. An electromagnetic (EM) telemetry system, comprising:

at least one downhole sensor;

a downhole transceiver comprising an encoded signal transmitter, the encoded signal transmitter configured to transmit data collected by the at least one downhole sensor as an encoded signal into a formation; and

an encoded signal receiver comprising one or more active counter electrodes, the one or more active counter electrodes comprising a galvanic electrode in series with an amplifier and configured to receive the encoded signal from the formation.

19. The system of claim 18, wherein the amplifier comprises a negative feedback loop.

20. The system of claim 18, wherein the amplifier comprises an input impedance of between 500 kOhm and 10 MOhm.