Patent Publication Number: US-2021164344-A1

Title: Electromagnetic telemetry using active 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&#39;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&#39;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  600 A of the active counter electrode  83  and the high-impedance amplifier  444  according to an embodiment. The equivalent circuit diagram  600 A 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  600 B 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.