U.S. patent application number 16/645113 was filed with the patent office on 2021-06-03 for electromagnetic telemetry using active electrodes.
The applicant listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Scott Urquhart, Glenn Andrew Wilson.
Application Number | 20210164344 16/645113 |
Document ID | / |
Family ID | 1000005403933 |
Filed Date | 2021-06-03 |
United States Patent
Application |
20210164344 |
Kind Code |
A1 |
Wilson; Glenn Andrew ; et
al. |
June 3, 2021 |
ELECTROMAGNETIC TELEMETRY USING ACTIVE ELECTRODES
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.
Inventors: |
Wilson; Glenn Andrew;
(Houston, TX) ; Urquhart; Scott; (Tuscon,
AZ) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Family ID: |
1000005403933 |
Appl. No.: |
16/645113 |
Filed: |
December 29, 2017 |
PCT Filed: |
December 29, 2017 |
PCT NO: |
PCT/US2017/068940 |
371 Date: |
March 6, 2020 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 47/13 20200501 |
International
Class: |
E21B 47/13 20060101
E21B047/13 |
Claims
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.
Description
BACKGROUND
[0001] 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.
[0002] 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
[0003] 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:
[0004] 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;
[0005] 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;
[0006] FIG. 3 is a schematic view of a downhole transceiver of an
EM telemetry system, in accordance with an embodiment of the
disclosure;
[0007] 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;
[0008] 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;
[0009] 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;
[0010] 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;
[0011] FIG. 7 is a flowchart of a method of EM telemetry, in
accordance with an embodiment of the disclosure; and
[0012] FIG. 8 is a block diagram of a computer of an EM telemetry
system, in accordance with an embodiment of the disclosure.
[0013] 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
[0014] 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.
[0015] 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.
[0016] 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.
[0017] 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.
[0018] 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.
[0019] 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.
[0020] 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 12a, 12b . . . 12n (illustrated in
FIG. 2), extending into the formation 14, and disposed in any
orientation, such as the horizontal wellbore 12b illustrated in
FIG. 2.
[0021] 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.
[0022] 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.
[0023] 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.
[0024] 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.
[0025] 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.
[0026] 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.
[0027] 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.
[0028] 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.
[0029] 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.
[0030] 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.
[0031] 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.
[0032] 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.
[0033] 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.
[0034] 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 .mu.V. 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.
[0035] 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.
[0036] 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.
[0037] 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.
[0038] 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.
[0039] 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.
[0040] 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.
[0041] 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.
[0042] 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.
[0043] 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.
[0044] 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, 83b, . . . 83n is depicted according to an
embodiment. As illustrated, one or more of the active counter
electrodes 83, 83b, . . . 83n 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, 83b, . . .
83n 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, 83b, . . . 83n and the wellhead 40 may be measured
or applied by the controller 510. In an embodiment, the active
counter electrodes 83, 83b, . . . 83n 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, 83b, . . . 83n as an array of electrodes is the
ability to orient and/or arrange the active counter electrodes
83-83n to improve a signal-to-noise ratio of the EM telemetry
system 80.
[0045] Additionally, as discussed above with respect to FIG. 4, the
active counter electrodes 83, 83b, . . . 83n each include
high-impedance amplifiers 444 to minimize any effects of contact
resistance on the voltage received by the active counter electrodes
83, 83b, . . . 83n. 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.
[0046] 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.
[0047] 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.
[0048] 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.
[0049] 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.
[0050] 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.
[0051] 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.
[0052] 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.
[0053] 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.
[0054] 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.
[0055] 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.
[0056] 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.
[0057] 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.
[0058] 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.
[0059] 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.
[0060] 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.
[0061] 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.
[0062] 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.
[0063] 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.
[0064] 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.RTM. 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.
[0065] 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.
[0066] 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.
[0067] 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).
[0068] 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.
[0069] 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.
[0070] 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.
[0071] 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:
[0072] 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.
[0073] Clause 2, the system of clause 1, wherein the downhole
sensor is communicatively coupled to the transceiver.
[0074] 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.
[0075] 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.
[0076] 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.
[0077] Clause 6, the system of clause 5, wherein the galvanic
electrode comprises a metal-metal salt porous pot.
[0078] 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.
[0079] Clause 8, the system of at least one of clauses 5-7, wherein
the amplifier comprises a negative feedback loop.
[0080] 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.
[0081] 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.
[0082] 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.
[0083] 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.
[0084] 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.
[0085] 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.
[0086] 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.
[0087] 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.
[0088] 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.
[0089] 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.
[0090] Clause 19, the method of clause 18, wherein the amplifier
comprises a negative feedback loop.
[0091] Clause 20, the method of clause 18 or 19, wherein the
amplifier comprises an input impedance of between 500 kOhm and 10
MOhm.
[0092] 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.
[0093] 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.
* * * * *