U.S. patent application number 17/203803 was filed with the patent office on 2021-07-01 for downhole electromagnetic sensing techniques.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Sameer Bhoite, Jung Kee Chung, Jaroslav Dobos, Dean Homan, Edward Michael Tollefsen.
Application Number | 20210199836 17/203803 |
Document ID | / |
Family ID | 1000005462551 |
Filed Date | 2021-07-01 |
United States Patent
Application |
20210199836 |
Kind Code |
A1 |
Chung; Jung Kee ; et
al. |
July 1, 2021 |
DOWNHOLE ELECTROMAGNETIC SENSING TECHNIQUES
Abstract
An electromagnetic (EM) telemetry system includes an EM
transmitter configured to transmit EM signals downhole and multiple
sensors each configured to communicate with the EM transmitter and
with another of the multiple sensors. Each sensor is placed a
distance from another sensor along a length of a wellbore in the EM
telemetry system. The EM telemetry system also includes a processor
configured to select two or more sensors of the multiple sensors
based on a signal to noise ratio (SNR) of an EM signal received
from the two or more selected sensors, a depth of the EM
transmitter, or both.
Inventors: |
Chung; Jung Kee; (Katy,
TX) ; Bhoite; Sameer; (Fulshear, TX) ; Homan;
Dean; (Damon, TX) ; Tollefsen; Edward Michael;
(Katy, TX) ; Dobos; Jaroslav; (Calgary,
CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Family ID: |
1000005462551 |
Appl. No.: |
17/203803 |
Filed: |
March 17, 2021 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
16806636 |
Mar 2, 2020 |
10962673 |
|
|
17203803 |
|
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|
15622197 |
Jun 14, 2017 |
10598809 |
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16806636 |
|
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62357094 |
Jun 30, 2016 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
G01V 3/38 20130101; G01V
3/20 20130101; G01V 3/02 20130101 |
International
Class: |
G01V 3/20 20060101
G01V003/20; G01V 3/02 20060101 G01V003/02; G01V 3/38 20060101
G01V003/38 |
Claims
1. An electromagnetic (EM) telemetry system, comprising: a
measuring while drilling (MWD) display computer; an EM transmitter
in a first wellbore; an EM receiver in a second wellbore remote
from the first wellbore, the EM receiver being configured to
receive signals from the EM transmitter in the first wellbore; and
a wireless transmitter configured to transmit signals received at
the EM receiver in the second wellbore to the MWD display
computer.
2. The system of claim 1, wherein the EM transmitter is a first EM
transmitter and the signals are first signals, and further
comprising a second EM transmitter in a third wellbore, and wherein
the EM receiver is configured to receive second signals from the
second EM transmitter.
3. The system of claim 1, wherein the second wellbore is offset
from the first wellbore by between 1,000 meters and 3,000
meters.
4. The system of claim 1, wherein the wireless transmitter is
configured to transmit a downlink EM signal to the EM receiver.
5. The system of claim 1, wherein the wireless transmitter is
configured to transmit the signals to a remote data network.
6. The system of claim 1, further comprising a downhole decoder
connected to the EM receiver in the second wellbore, wherein the
downhole decoder is configured to reduce noise of the received
signals.
7. The system of claim 1, wherein the EM receiver is configured to
transmit a downhole signal to the EM transmitter.
8. The system of claim 1, further comprising an insulated cable to
transmit the signals received at the EM receiver to the wireless
transmitter.
9. The system of claim 1, wherein a depth of the EM receiver is
greater than or equal to a depth of the EM transmitter.
10. A method for downhole electromagnetic (EM) telemetry,
comprising: transmitting an EM signal from an EM transmitter
located in a first wellbore; receiving the EM signal at an EM
receiver located in a second wellbore remote from the first
wellbore; and wirelessly transmitting the EM signal to an MWD
display computer from a surface wireless transmitter.
11. The method of claim 10, wherein the EM signal is a first EM
signal, and further comprising receiving a second EM signal from a
third wellbore remote from the first wellbore and the second
wellbore.
12. The method of claim 10, further comprising wirelessly
transmitting an EM downlink signal from the surface wireless
transmitter to the EM receiver.
13. The method of claim 10, wherein the EM signal is a first EM
signal, and further comprising transmitting a second EM signal from
the EM receiver to the EM transmitter.
14. The method of claim 10, further comprising at least partially
decoding the EM signal at a downhole decoder in the second
wellbore.
15. The method of claim 10, further comprising transmitting the EM
signal from the EM receiver to the surface wireless transmitter
with a wired connection.
16. The method of claim 10, further comprising wirelessly
transmitting the EM signal to a remote data processor.
17. The method of claim 10, further comprising at least partially
decoding the EM signal at the MWD display computer.
18. A method for downhole electromagnetic (EM) telemetry,
comprising: at an MWD display computer, receiving a signal from a
wireless transmitter located at a surface location of a first
wellbore, wherein: the wireless transmitter receives the signal
from an EM receiver in the first wellbore; and the EM receiver
receives the signal from an EM transmitter located in a second
wellbore remote from the first wellbore.
19. The method of claim 18, wherein the signal includes survey
information from the second wellbore.
20. The method of claim 18, wherein the MWD display computer is a
remote data processor.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application is a continuation application of U.S.
patent application Ser. No. 16/806,636, filed on Mar. 2, 2020,
which is a divisional application of U.S. Pat. No. 10,598,809,
filed on Jun. 14, 2017, which claims priority to and the benefit of
U.S. Provisional Patent Application No. 62/357,094, filed on Jun.
30, 2016, the entirety of both of which are incorporated herein by
reference.
BACKGROUND
[0002] Conventional electromagnetic ("EM") telemetry employs two or
more stakes (i.e., electrodes) placed in the ground to detect a
signal. The signal may include an electrical current, and the
current may cause a voltage differential between the stakes due to
the resistivity of the ground. The signal includes an EM telemetry
portion that is transmitted from a downhole tool in a wellbore. The
EM telemetry portion includes encoded measurement data captured by
the downhole tool. The signal also includes an electrical noise
portion due to equipment (e.g., motors, generators, pumps, etc.) at
the surface. It is oftentimes difficult to distinguish the EM
telemetry portion of the signal from the electrical noise portion
of the signal. To make matters more difficult, the EM telemetry
portion of the signal is largely attenuated by the subterranean
formation between the downhole tool and the stakes at surface.
Furthermore, there may be other EM telemetry tools interfering with
the desired signal.
SUMMARY
[0003] This summary is provided to introduce a selection of
concepts that are further described in the detailed description.
This summary is not intended to identify key or essential features
of the claimed subject matter, nor is it intended to be used as an
aid in limiting the scope of the claimed subject matter.
[0004] An electromagnetic (EM) telemetry system includes an EM
transmitter configured to transmit EM signals downhole and multiple
sensors each configured to communicate with the EM transmitter and
with another of the multiple sensors. Each sensor is placed a
distance from another sensor along a length of a wellbore in the EM
telemetry system. The EM telemetry system also includes a processor
configured to select two or more sensors of the multiple sensors
based on a signal to noise ratio (SNR) of an EM signal received
from the two or more selected sensors, a depth of the EM
transmitter, or both.
[0005] In another embodiment, an insulating device configured to
electrically insulate sensors in an electromagnetic (EM) telemetry
system includes a first conductive sub and a second conductive sub,
each comprising a threaded surface configured to fit with the
other. The device includes an insulation structure between the
first and second conductive subs and a conductor channel disposed
across the insulation structure and between a first electronic
pocket in the first conductive sub and a second electronic pocket
in the second conductive sub. The conductor channel is configured
to alter the electrical potential of the first sub.
[0006] Another embodiment of an insulating device configured to
electrically insulate sensors in an electromagnetic (EM) telemetry
system is disclosed. The device includes a first conductive sub and
a second conductive sub, each comprising a threaded surface
configured to fit with the other. The device also includes an
insulation structure between the first and second conductive subs
and a conductor channel disposed through the second conductive sub
and through the insulation structure and between the first
conductive sub and the second conductive sub. The conductor channel
is configured to alter the electrical potential of the first
conductive sub.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] The accompanying drawings, which are incorporated in and
constitute a part of this specification, illustrate embodiments of
the present teachings and together with the description, serve to
explain the principles of the present teachings. In the
figures:
[0008] FIG. 1 illustrates a schematic side view of first and second
wellbores in a subterranean formation, according to an
embodiment.
[0009] FIG. 2 illustrates a schematic view of an amplifier that
receives signals from the first and second sensors, according to an
embodiment.
[0010] FIG. 3 illustrates a schematic side view of the second
wellbore having three sensors, according to an embodiment.
[0011] FIG. 4 illustrates a schematic side view of a wellsite
showing an EM telemetry tool having dipoles, according to an
embodiment.
[0012] FIG. 5 illustrates a schematic side view of a wellsite
showing an EM telemetry tool having dipoles, mapped to a schematic
diagram of sensors and gaps, according to an embodiment.
[0013] FIG. 6 illustrates a schematic view of an EM sensor,
according to an embodiment.
[0014] FIG. 7 illustrates a schematic side view of a connection for
an EM sensor, according to an embodiment.
[0015] FIG. 8 illustrates a schematic side view of a connection for
multiple EM sensors, according to an embodiment.
[0016] FIG. 9 illustrates a schematic side view of a cantilever arm
for an EM sensor, according to an embodiment.
[0017] FIG. 10 illustrates a schematic side view of a wellsite
showing an EM telemetry tool having dipoles, mapped to a schematic
diagram of sensors and gaps and a downhole decoder, according to an
embodiment.
[0018] FIG. 11 illustrates a top schematic view of a wellsite
having multiple selectable wells, according to an embodiment.
[0019] FIGS. 12-16 and 17A-D illustrate different configurations of
insulation gaps in a gap sub for electrically isolating sensors in
an EM telemetry system, according to an embodiment.
[0020] FIG. 18 illustrates a schematic view of a computing system
for performing at least a portion of the methods, according to an
embodiment.
DETAILED DESCRIPTION
[0021] Reference will now be made in detail to specific embodiments
illustrated in the accompanying drawings and figures. In the
following detailed description, numerous specific details are set
forth in order to provide a thorough understanding of the
disclosure. However, it will be apparent to one of ordinary skill
in the art that the disclosure may be practiced without these
specific details. In other instances, well-known methods,
procedures, components, circuits, and networks have not been
described in detail so as not to obscure aspects of the
embodiments.
[0022] The terminology used in the description herein is for the
purpose of describing particular embodiments and is not intended to
be limiting. As used in the description and the appended claims,
the singular forms "a," "an" and "the" are intended to include the
plural forms as well, unless the context clearly indicates
otherwise. It will also be understood that the term "and/or" as
used herein refers to and encompasses any possible combinations of
one or more of the associated listed items. It will be further
understood that the terms "includes," "including," "comprises"
and/or "comprising," when used in this specification, specify the
presence of stated features, integers, operations, elements, and/or
components, but do not preclude the presence or addition of one or
more other features, integers, operations, elements, components,
and/or groups thereof. Further, as used herein, the term "if" may
be construed to mean "when" or "upon" or "in response to
determining" or "in response to detecting," depending on the
context.
[0023] FIG. 1 illustrates a schematic view of an EM telemetry
system 100 in a wellsite having a first wellbore 110 and a second
wellbore 160 formed in a subterranean formation 104, according to
an embodiment. The first wellbore 110 may have a downhole tool 120
positioned therein. The downhole tool 120 may be or include a
rotary steerable system ("RSS") 122, a motor 124, one or more
logging-while-drilling ("LWD") tools 126, one or more
measurement-while-drilling ("MWD") tools 128, or a combination
thereof. The LWD tool 126 may be configured to measure one or more
formation properties and/or physical properties as the first
wellbore 110 is being drilled or at any time thereafter. The MWD
tool 128 may be configured to measure one or more physical
properties as the first wellbore 110 is being drilled or at any
time thereafter. The formation properties may include resistivity,
density, porosity, sonic velocity, gamma rays, and the like. The
physical properties may include pressure, temperature, wellbore
caliper, wellbore trajectory, a weight-on-bit, torque-on-bit,
vibration, shock, stick slip, and the like. The measurements from
the LWD tool 126 may be sent to the MWD tool 128. The MWD tool 128
may then group the sets of data from the LWD tool 126 and the MWD
tool 128 and prepare the data for transmission to the surface
102.
[0024] The data may be transmitted to the surface via
electromagnetic ("EM") telemetry, mud pulse telemetry, or the like.
When using EM telemetry to transmit the data from the downhole tool
120 in the first wellbore 110 to the surface 102, a coding method
is used. For example, a predetermined carrier frequency may be
selected and any suitable modulation method, e.g., phase shift
keying ("PSK"), frequency shift keying ("FSK"), continuous phase
modulation ("CPM"), quadrature amplitude modulation ("QAM"), or
orthogonal frequency division multiplexing ("OFDM"), may be used to
superpose the bit pattern onto the carrier wave. In another
embodiment, a baseband line code, e.g., pulse position modulation,
Manchester coding, biphase coding, or runlength limited codes such
as 4b/5b or 8b/10b coding, may be used to superpose the bit pattern
onto a waveform suitable for transmission across the MWD channel.
This coded signal is applied as a voltage differential across an
electrical insulation layer (e.g., ceramic, peek, hard plastic) 130
positioned between upper and lower portions of the downhole tool
120. Due to the voltage differential, an EM telemetry signal (e.g.,
electrical current) 132 is generated that travels through the
subterranean formation 104. More particularly, the EM telemetry
current density signal 132 travels from the lower portion of the
downhole tool 120, out into the subterranean formation 104, and
bends back toward the upper portion of the downhole tool 120, in an
almost semi-elliptical like-shape as determined by the boundary
conditions of the subterranean formation 104. The EM telemetry
signal 132 from the downhole tool 120 may become attenuated
proceeding away from the downhole tool 120 (e.g., upward toward the
surface 102) due to the resistivity of the subterranean formation
104. More particularly, the EM telemetry signal 132 may be
attenuated in highly conductive portions of the subterranean
formation 104, which may shunt the EM telemetry signal 132, and/or
the EM telemetry signal 132 may be attenuated by highly resistive
portions of the subterranean formation 104, which may restrict the
flow of the EM telemetry signal 132 to the surface 102.
[0025] Surface equipment may 140 be positioned at the surface 102.
The surface equipment 140 may be or include a motor, a generator, a
pump, or the like. The surface equipment 140 may be poorly grounded
to one-another, which may introduce noise signals (e.g., electrical
current) 142 into the subterranean formation 104 near the surface
102. The noise signals 142 from the surface equipment 140 may
become attenuated proceeding away from the surface equipment 140
due to the resistivity of the subterranean formation 104. Thus, in
one example, the noise signals 142 from the surface equipment 140
may become more and more attenuated proceeding downward, deeper
into the subterranean formation 104.
[0026] In one embodiment, one or more surface sensors (two are
shown: 144, 146) may be positioned at the surface 102. The surface
sensors 144, 146 may be or include metallic stakes driven into the
surface 102. Although not shown, one of the surface sensors (e.g.,
sensor 144) may be coupled to a blow-out preventer ("BOP") of the
first wellbore 110. The surface sensors 144, 146 may measure the EM
telemetry signal 132 and the noise signal 142 in the subterranean
formation 104. The signals 132, 142 measured by the surface sensors
144, 146 may have an EM telemetry portion (e.g., from the EM
telemetry signal 132 transmitted from the downhole tool 120), and
an electrical noise portion (e.g., from the noise signal 142
generated by the noise-generating equipment 140 at the surface
102).
[0027] The surface sensors 144, 146 may detect/measure the signals
132, 142 in the subterranean formation 104. A voltage differential
may then be determined between the surface sensors 144, 146 using
the signals 132, 142 and the resistance between the surface sensors
144, 146. The resistance may be due to the resistivity of the
subterranean formation 104. The resistance between the surface
sensors 144, 146 is oftentimes from about 25 ohms to about 100 ohms
(e.g., about 50 ohms).
[0028] The signals 132, 142 (e.g., current or voltage differential)
may be transmitted from the surface sensors 144, 146 to a computer
system 1000. The signals 132, 142 (e.g., current or voltage
differential) received by the computer system 1000 may include an
EM telemetry portion from the downhole tool 120 and an electrical
noise portion from the surface equipment 140. The computer system
1000 may identify and decode the EM telemetry portion to recover
the properties measured by the downhole tool 120. Both signals 132,
142 may be travelling in a substantially-horizontal direction
proximate to the surface 102 when detected by the surface sensors
144, 146, causing the electrical noise portion to be
"electrically-coupled" to the EM telemetry portion. This may make
it difficult to distinguish the EM telemetry portion from the
electrical noise portion.
[0029] To improve the signal-to-noise ratio ("SNR") between the EM
telemetry portion and the electrical noise portion, a first sensor
162 may be positioned in the second wellbore 160. The second
wellbore 160 may be laterally-offset from the first wellbore 110
from about 10 m to about 100 m, about 100 m to about 500 m, about
500 m to about 1000 m, about 1000 m to about 3000 m, or more. The
first sensor 162 may be or include an electrode, a magnetometer, a
capacitive sensor, a current sensor, a Hall-effect sensor, a
toroid, a solenoid, a resistive gap, or a combination thereof. The
first sensor 162 may be placed in a substantially vertical portion
of the second wellbore 160, a lateral portion of the second
wellbore 160, or in the heel therebetween. In one example, the
first sensor 162 may be placed in a lateral portion of the second
wellbore 160 that is extending toward the first wellbore 110. The
depth of the first sensor 162 may be greater than or equal to the
depth of the downhole tool 120, as measured vertically from the
surface 102; however, in other embodiments, the depth of the first
sensor 162 may be less than the depth of the downhole tool 120. A
first insulated cable 164 may be coupled the first sensor 162. The
first cable 164 may be configured to transmit the measurements
captured by the first sensor 162 to the surface 102.
[0030] The second wellbore 160 may be "open-hole" or have a casing
166 positioned therein. When the second wellbore 160 has the casing
166 (or other metallic tubular member) positioned therein, the
first sensor 162 may be in contact with the casing 166. In other
embodiments, the first sensor 162 may not be in direct contact with
the casing 166 and may instead sense the EM telemetry signal 132
through a liquid (e.g. brine) or through other means such as a
magnetometer, capacitive coupling, etc. at a point in the second
wellbore 160.
[0031] At least a portion of the EM telemetry signal 132 from the
downhole tool 120 in the first wellbore 110 may be measured by the
first sensor 162 in the second wellbore 160. For example, the EM
telemetry signal 132 may flow into the casing 166 in the second
wellbore 160, and the first sensor 162 may measure the EM telemetry
signal 132 in the casing 166 proximate to the first sensor 162. The
measurement data from the first sensor 162 may be transmitted up to
the surface 102 through the cable 164 in the second wellbore
160.
[0032] Once the EM telemetry signal 132 reaches the casing 166 in
the second wellbore 160, at least a portion of the EM telemetry
signal 132 may flow up the casing 166 in the second wellbore 160
toward the surface 102, which is the path of least resistance. A
second sensor 168 may be configured to measure the EM telemetry
signal 132 at a different location than the first sensor 162. As
shown, the second sensor 168 is positioned within the second
wellbore 160 and above the first sensor 162. In another embodiment,
the second sensor 168 may be positioned at the surface 102
proximate to the top of the second wellbore 160 (e.g., coupled to a
wellhead or BOP of the second wellbore 160). The second sensor 168
may also be or include an electrode, a magnetometer, a capacitive
sensor, a current sensor, a Hall-effect sensor, a toroid, a
solenoid, a resistive gap, or a combination thereof. The second
sensor 168 may be in contact with the casing 166 in the second
wellbore 160 or in contact with an intermediate conductive member
that is in contact with the casing 166 in the second wellbore 160,
to enable the second sensor 168 to detect the EM telemetry signal
132 at that location. A second insulated cable 170 may be coupled
the second sensor 168. The second cable 170 may be configured to
transmit the measurements captured by the second sensor 168 to the
surface 102.
[0033] As will be appreciated, the EM telemetry signal 132 flowing
through the casing 166 at the location of the first and second
sensors 162, 168 may be different. For example, the EM telemetry
signal 132 measured by the second sensor 168 may be smaller than
the EM telemetry signal 132 measured by the first sensor 162
because a portion of the EM telemetry signal 132 "leaks" back to
the downhole tool 120 through the subterranean formation 104 before
reaching the second sensor 168. This leaking effect may be more
pronounced for casing materials that are less conductive or where a
joint between two casing joints introduces a series resistance. In
addition, the first and second sensors 162, 168 may also be
affected differently by the noise signals 142 produced by the
surface equipment 140. For example, the noise signals 142 that
reach the first sensor 162 may be smaller than the noise signals
142 circulating in proximity to the second sensor 168 due to the
additional distance (and corresponding resistance) that the noise
signal 142 travels to reach the first sensor 162. Said another way,
as depth of the downhole tool 120 increases, the amplitude of the
noise signals 142 from the surface 102 may be reduced due to
shunting of the noise current loops in the conductive formations
and attenuation due to interleaved resistive layers.
[0034] As the downhole tool 120 drills deeper into the subterranean
formation 104, the EM telemetry signal 132 transmitted by the
downhole tool 120 may be attenuated on its path to the surface 102.
This attenuation is greater in highly-conductive formations that
shunt the EM telemetry signal 132 and can be worsened by the
presence of highly resistive layers which restrict the flow of the
EM telemetry signal 132 to the surface 102.
[0035] A distance between the first and second sensors 162, 168 may
be known. The distance may be, for example, from about 10 m to
about 50 m, about 50 m to about 100 m, about 100 m to about 250 m,
about 250 m to about 500 m, about 500 m to about 1000 m, or more.
While it was previously assumed that the resistance between two
points on the casing 166 was zero or close to zero, over larger
distances, the resistance is no longer nominal. As a result, with
the distance known, the resistance of the casing 166 between the
first and second sensors 162, 168 may be determined. The resistance
may be, for example, from about 0.1 ohms per 1000 m to about 5 ohms
per 1000 m, from about 0.2 ohms per 1000 m to about 2 ohms per 1000
m, or from about 0.3 ohms per 1000 m to about 1 ohm per 1000 m. In
one specific example, the resistance may be about 0.5 ohms per 1000
m. Thus, in one example, if there is 10,000 m of casing 166 between
the first and second sensors 162, 168, the resistance may be about
5 ohms. At least a portion of the casing 166 may be substantially
vertical, which may cause the EM telemetry signal 132 to flow in a
substantially vertical direction. As a result, the EM telemetry
signal 132 from the downhole tool 120 (e.g., the EM telemetry
portion) may be substantially perpendicular to the noise signal 142
from the surface equipment 140 at the surface 102 (e.g., the
electrical noise portion), which may reduce the electrical coupling
between the two portions.
[0036] The first and/or second sensor 162, 168 may be positioned to
maximize the EM telemetry signal 132 (e.g., current) that is
measured. In addition, the first and/or second sensor 162, 168 may
be positioned to maximize the resistive path that the EM telemetry
signal 132 travels through. When the subterranean formation 104 is
highly resistive, the first and/or second sensor 162, 168 may be
positioned in a conductive layer of the subterranean formation 104
below a highly resistive layer.
[0037] The sensors 144, 146, 162, 168 may be positioned in and/or
configured to detect signals from a single downhole tool 120 in a
signal wellbore 110 or multiple downhole tools 120 in multiple
wellbores 110, 160, etc. The sensors 144, 146, 162, 168 may operate
on land or in marine environments. The sensors 144, 146, 162, 168
may communicate unidirectionally or bi-directionally. In some
embodiments, the sensors 144, 146, 162, 168 may communicate with
each other and/or with other components of the downhole tools 120
or EM telemetry system 100 to communicate in a full or partial
duplex manner. For example, in some embodiments, the communication
channels between the sensors 144, 146, 162, 168 may be used for
full duplex operation and may communicate bi-directionally and
simultaneously. The sensors 144, 146, 162, 168 may use automation,
downlinking, noise cancellation, etc., and may operate with
acquisition software and/or human operators.
[0038] FIG. 2 illustrates a schematic view of a differential
amplifier 200 that measures the voltage difference across the
sensors 162, 168, which can be electrodes in contact with the
casing 166, according to an embodiment. The signals 132, 142
measured by the first and second sensors 162, 168 may be introduced
into the differential amplifier 200 to generate the voltage
differential. This embodiment reduces the noise that couples both
the sensors 162, 168 (e.g., common mode noise). As shown, the
impedance from the sensors 162, 168 to the input of the
differential amplifier may be very low (e.g., equal to the casing
resistance for that section of casing 166 for the example in which
the sensors 162, 168 contact the casing 166). In this embodiment,
the low source impedance provides high noise immunity as compared
to a different embodiment that measures the differential signal
between the sensor 162 and a stake placed at the surface 102. The
latter embodiment may have higher impedance and also may couple the
noise signals 142 from the surface equipment 140. In at least one
embodiment, the impedance of the front end may be varied to match
the resistance of the casing 166, which may be roughly known per
unit of distance (e.g., meter).
[0039] The amplifier 200 may have a high common mode rejection
ratio, which removes common mode noise. In addition to the common
mode rejection benefit of multiple sensors 162, 168 in the second
wellbore 160, the multiple sensors 162, 168 may provide the ability
to capture the EM telemetry signal 132 from the downhole tool 120
throughout the full interval.
[0040] FIG. 3 illustrates a schematic side view of the second
wellbore 160 having three sensors 162, 168, 172, according to an
embodiment. The third sensor 172 may be positioned proximate to the
top of the second wellbore 160 (e.g., coupled to the casing 166,
wellhead, or BOP). The second and third sensors 168, 172 may be
used to measure the EM telemetry signal 132 from the downhole tool
120 when the downhole tool 120 is in a first, upper interval in the
first wellbore 110 (e.g., when the depth of the downhole tool 120
is less than the depth of the second sensor 168). The first and
second sensors 162, 168 may then be used to measure the EM
telemetry signal 132 from the downhole tool 120 when the downhole
tool 120 is in a second, lower interval in the first wellbore 110
(e.g., when the depth of the downhole tool 120 is greater than the
depth of the second sensor 168). In one embodiment, the computer
system 1000 may be or include a multi-channel acquisition system
that uses the signals from the sensors 162, 168, 172 to remove
noise with a noise-cancelation algorithm to maximize the SNR.
[0041] FIG. 4 illustrates a schematic side view of a wellbore
having an EM telemetry tool with downhole dipoles separated by
electrical gaps. The transmitter to the gap is one pole, while the
gap to the wellhead is another pole. The EM signal may be injected
in the formation using this dipole. The EM signal may be sensed on
the surface using surface antenna or stakes. The surface antenna or
stakes are inserted into the ground, such that the EM signal
traveling through the drill pipe constitutes high potential and the
surface antenna constitutes low potential such that the surface
bipole gets the signal. The process of transmitting an EM signal
from downhole to the surface is referred to as EM uplink, while the
transmission of EM signals from the surface to the downhole tool is
referred to as downlink.
[0042] The demodulation of an EM signal is affected by the signal
to noise ratio (SNR) in the EM signal frequency band. Rig activity
generates unwanted electrical noise at the surface, and as drilling
depth increases, EM signal amplitudes received at the surface
weakens due to attenuation, whereas surface noise amplitude remains
the same. This leads to reduced SNR as the drilling depth
increases. Once SNR drops below a certain level, demodulating the
EM signal at the surface may become very difficult.
[0043] In some embodiments, the arrangement of one or more downhole
sensors, and the configuration of each downhole sensor, may reduce
the effects of surface noise on the EM signals. For example, in
some embodiments, multiple downhole sensors (i.e., receivers,
electrodes, toroids, etc.) may be available for making multiple
electrical contact points downhole. These multiple sensors may be
configured such that during operation of the system, certain sensor
pairs may be selected based on its impedance. For example, the
sensors may be configured such that two downhole sensors having a
signal with the highest SNR may be selected, thereby providing for
more simplified and accurate decoding and demodulation.
[0044] FIG. 5 illustrates a schematic side view of a wellbore
having an EM telemetry tool, as well as a schematic representation
of the downhole sensors and electrically insulated gaps which
isolate the sensors. Such a multi-contact EM telemetry system may
include multiple conductors and may be deployed using wireline,
with a MWD or LWD tool, or in any other suitable logging
conveyance. The multi-contact EM telemetry system may have multiple
sensors, each spaced a distance apart from another. For example,
each sensors may be 500 ft to 3000 ft apart, or 1000 ft to 2000 ft
apart, etc. The sensors may be different distances apart, and the
distances between each sensor may further be adjustable, either
before or after it is deployed downhole. In some embodiments, a
suitable processor controller, such as surface acquisition
software, may monitor the performance of the electrode pairs and
dynamically choose one or more electrode pairs based a location of
the transmitter (e.g., at the bit), and based on the signal
obtained at the sensors.
[0045] In accordance with the present techniques, the multi-contact
EM telemetry system may include spring loaded contact points which
have continuous contact with the casing or open hole during its
downhole deployment and operation. If an sensor pair separation is
selected, the two sensors connected by a single conductor cable may
be utilized as a standalone installation. At the rig site, the top
electrode may be wired to the two wireline conductors, reducing the
overall rig setup time.
[0046] Each sensor may include mechanical wire clamp parts,
electrical connection with pressure sealing parts, insulated gap
joints parts, electrical connection to centralizer, centralizer
that contacts formation/casing mechanically and electrically,
electrical connection with pressure sealing parts, and other
mechanical wires clamp parts, as illustrated in FIG. 6. As
illustrated in FIG. 7, mechanical wire clamp parts may include
cable head housing, clamps for mechanical connections, and
electrical sockets with covered with rubber boot for pressure
sealing. In some embodiments, by mating electrical connections,
multi-conductor cable without armor may pass through the insulated
gap joint and centralizer and connected to the other electrical
connector which has same structure and pressure sealing function. A
wire may be connected to the insulated gap joint to contact with
the centralizer. Other wires may pass through the inside diameter
for use in other electrode. As illustrated in the schematic
sideview of FIG. 8, multiple sensor connections are possible by
repeating the connections and configurations illustrated in FIGS. 6
and 7.
[0047] In some embodiments, surface power may be delivered (e.g.,
via wireline) to activate a motor downhole. This motor may use
linear actuation mechanisms to energize a cantilever arm to make
electrical contact with the casing or formation. To retrieve the
electrode, mechanical springs may be used to retract the arm. The
cantilever arm, as illustrated in FIG. 9, may be actuated by
multiple linear to radial actuation mechanisms (e.g., cam, radial
outward grooves to push the arm out, etc.).
[0048] Furthermore, to further reduce the effects of surface noise,
and as illustrated in FIG. 10, a downhole decoder and/or wireless
transmitter may be used in some embodiments. The downhole decoder
may reduce or remove noise for different deep electrode pairs and
wirelessly transmit an electrode pair wellpair to the MWD computer
for display. By decoding electrical signals downhole, potential
noise may be reduced or removed. The wireless transmitter may be
used to select wells for deployment of sensor arrays. For example,
as illustrated in FIG. 11 representing a well pad with two
observation wells, multiple sensor pairs may be installed in both
observation wells. Depending on the drill bit depth, an electrode
(and wellpair) may be selected for having a downlink or uplink
signal with a suitable SNR.
[0049] In some embodiments, the electrically insulating gap sub
used in the EM system may be configured to create a voltage
difference across two electrically insulated elements of the sub.
The gap sub may be conveyed using wireline, slickline, or coiled
tubing, such that these conveyances may be passed through the gap
sub and a repeater may be located in the piping string. In some
embodiments, an electrical conductor may pass through a dielectric
thermoplastic material. The voltage difference between the two
electrically insulated elements of the sub may be controlled by
applying a voltage to this electrical conductor from a cavity
within the gap sub. The design may be used for short range EM
communication in an EM system.
[0050] As illustrated in FIG. 12, a gap sub may include a male sub
and a female sub which are electrically conductive, and an
insulation between the male and female subs. The insulation gap may
be filled with nonconductive plastic material (e.g., by injection).
A probe may be configured in the gap sub to create a voltage
difference across the gap sub through the metal centralizers in
contact with the inner bore of the gap sub. A conductor channel may
be created across the electrical insulation structure, as shown in
FIG. 13, between an electronic pocket on one side of the insulation
and the other side of the insulation. An insulated conductor inside
the conductor channel may control the electrical potential of the
male sub from the electronic cartridge. As there may be limited
space between the male and female threads of the male and female
subs, the relative positions of the two threads may not be
controlled precisely. In some embodiments, a groove may be cut in
the female thread in which the channel may terminate. As
illustrated in FIG. 14, this may prevent the conductor from
contacting both male and female subs at the same time, which would
create a short between the two elements of the gap sub.
[0051] Once the male and female subs are assembled together,
similarly to the current dry assembly process, an insulated
electrical conductor may be run through the conductor channel until
it contacts the male sub. The insulated electrical conductor may
then be secured before the injection of the dielectric
thermoplastic. Once the injection is complete, the electrical
potential of the male sub may be controlled from the electronic
pocket through an insulated conductor termination, as illustrated
in FIG. 15. As illustrated in FIG. 16, several conductor channels
may be created radially, if high currents are required to be passed
through.
[0052] In accordance with the present techniques, variations of the
conductor channel are possible by changing the location of the
channel, in particular the distance to the center line and the
angle from the center line anywhere from 0 to 180 degrees. The
channel can be created before injection or after injection. For
example, FIG. 17A shows a conductor channel created along the outer
diameter of the sub, creating a groove parallel to the axis of the
sub. The electrically insulated conductor may be positioned in the
groove, such that it can be accessed and secured by potting or
welding. FIG. 17B illustrates a configuration where the radial
conductor channel is drilled through the female sub to go through
the insulating structure and connect to the male sub. This
embodiment may protect the structural integrity of the insulating
structure on the outer diameter that is exposed to abrasion and
shock while drilling. FIG. 17C illustrates another embodiment where
an angular hole is drilled through the insulating structure.
Additionally, FIG. 17D illustrates an embodiment drilling a
conductor channel after thermoplastic injection.
[0053] In some embodiments, the methods of the present disclosure
may be executed by a computing system. FIG. 10 illustrates an
example of such a computing system 1000, in accordance with some
embodiments. The computing system 1000 may include a computer or
computer system 1001A, which may be an individual computer system
1001A or an arrangement of distributed computer systems. The
computer system 1001A includes one or more analysis modules 1002
that are configured to perform various tasks according to some
embodiments, such as one or more methods disclosed herein. To
perform these various tasks, the analysis module 1002 executes
independently, or in coordination with, one or more processors
1004, which is (or are) connected to one or more storage media
1006. The processor(s) 1004 is (or are) also connected to a network
interface 1007 to allow the computer system 1001A to communicate
over a data network 1009 with one or more additional computer
systems and/or computing systems, such as 1001B, 1001C, and/or
1001D (note that computer systems 1001B, 1001C and/or 1001D may or
may not share the same architecture as computer system 1001A, and
may be located in different physical locations, e.g., computer
systems 1001A and 1001B may be located in a processing facility,
while in communication with one or more computer systems such as
1001C and/or 1001D that are located in one or more data centers,
and/or located in varying countries on different continents).
[0054] A processor may include a microprocessor, microcontroller,
processor module or subsystem, programmable integrated circuit,
programmable gate array, or another control or computing
device.
[0055] The storage media 1006 may be implemented as one or more
computer-readable or machine-readable storage media. Note that
while in the example embodiment of FIG. 18 storage media 1006 is
depicted as within computer system 1001A, in some embodiments,
storage media 1006 may be distributed within and/or across multiple
internal and/or external enclosures of computing system 1001A
and/or additional computing systems. Storage media 1006 may include
one or more different forms of memory including semiconductor
memory devices such as dynamic or static random access memories
(DRAMs or SRAMs), erasable and programmable read-only memories
(EPROMs), electrically erasable and programmable read-only memories
(EEPROMs) and flash memories, magnetic disks such as fixed, floppy
and removable disks, other magnetic media including tape, optical
media such as compact disks (CDs) or digital video disks (DVDs),
BLUERAY.RTM. disks, or other types of optical storage, or other
types of storage devices. Note that the instructions discussed
above may be provided on one computer-readable or machine-readable
storage medium, or may be provided on multiple computer-readable or
machine-readable storage media distributed in a large system having
possibly plural nodes. Such computer-readable or machine-readable
storage medium or media is (are) considered to be part of an
article (or article of manufacture). An article or article of
manufacture may refer to any manufactured single component or
multiple components. The storage medium or media may be located
either in the machine running the machine-readable instructions, or
located at a remote site from which machine-readable instructions
may be downloaded over a network for execution.
[0056] In some embodiments, the computing system 1000 contains one
or more telemetry module(s) 1008. The telemetry module(s) 1008 may
be used to perform at least a portion of one or more embodiments of
the methods disclosed herein (e.g., method 900).
[0057] It should be appreciated that computing system 1000 is one
example of a computing system, and that computing system 1000 may
have more or fewer components than shown, may combine additional
components not depicted in the example embodiment of FIG. 10,
and/or computing system 1000 may have a different configuration or
arrangement of the components depicted in FIG. 10. The various
components shown in FIG. 10 may be implemented in hardware,
software, or a combination of both hardware and software, including
one or more signal processing and/or application specific
integrated circuits.
[0058] Further, the methods described herein may be implemented by
running one or more functional modules in information processing
apparatus such as general purpose processors or application
specific chips, such as ASICs, FPGAs, PLDs, or other appropriate
devices. These modules, combinations of these modules, and/or their
combination with general hardware are included within the scope of
protection of the disclosure.
[0059] As used herein, the terms "inner" and "outer"; "up" and
"down"; "upper" and "lower"; "upward" and "downward"; "above" and
"below"; "inward" and "outward"; "uphole" and "downhole"; and other
like terms as used herein refer to relative positions to one
another and are not intended to denote a particular direction or
spatial orientation. The terms "couple," "coupled," "connect,"
"connection," "connected," "in connection with," and "connecting"
refer to "in direct connection with" or "in connection with via one
or more intermediate elements or members." Similarly, the term "in
contact with" refers to "in direct contact with" or "in contact
with via one or more intermediate elements or members."
[0060] The foregoing description, for purpose of explanation, has
been described with reference to specific embodiments. However, the
illustrative discussions above are not intended to be exhaustive or
to limit the disclosure to the precise forms disclosed. Many
modifications and variations are possible in view of the above
teachings. Moreover, the order in which the elements of the methods
described herein are illustrate and described may be re-arranged,
and/or two or more elements may occur simultaneously. The
embodiments were chosen and described in order to explain the
principals of the disclosure and its practical applications, to
thereby enable others skilled in the art to utilize the disclosure
and various embodiments with various modifications as are suited to
the particular use contemplated. Additional information supporting
the disclosure is contained in the appendix attached hereto.
* * * * *