U.S. patent number 10,385,683 [Application Number 15/887,607] was granted by the patent office on 2019-08-20 for deepset receiver for drilling application.
This patent grant is currently assigned to Nabors Drilling Technologies USA, Inc.. The grantee listed for this patent is Nabors Drilling Technologies USA, Inc.. Invention is credited to Harmeet Kaur.
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United States Patent |
10,385,683 |
Kaur |
August 20, 2019 |
Deepset receiver for drilling application
Abstract
Drilling telemetry systems and methods include a cable antenna a
cable antenna in an auxiliary borehole in a subterranean formation
arranged to receive electromagnetic signal transmitted from an EM
tool in an adjacent wellbore in the subterranean formation. The
cable antenna may include a wireline cable having a center core, an
insulated electrical cable head in direct electrical communication
with the center core, and an uninsulated signal receiver in direct
electrical communication with electrical cable head. The
uninsulated signal receiver may have an outer surface formed of a
conductive material and configured to contact a natural
subterranean formation.
Inventors: |
Kaur; Harmeet (Houston,
TX) |
Applicant: |
Name |
City |
State |
Country |
Type |
Nabors Drilling Technologies USA, Inc. |
Houston |
TX |
US |
|
|
Assignee: |
Nabors Drilling Technologies USA,
Inc. (Houston, TX)
|
Family
ID: |
67476090 |
Appl.
No.: |
15/887,607 |
Filed: |
February 2, 2018 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B
47/13 (20200501); E21B 47/092 (20200501); E21B
47/125 (20200501); E21B 47/10 (20130101); E21B
17/023 (20130101) |
Current International
Class: |
E21B
47/12 (20120101); E21B 17/02 (20060101) |
References Cited
[Referenced By]
U.S. Patent Documents
Primary Examiner: Benlagsir; Amine
Attorney, Agent or Firm: Haynes and Boone, LLP
Claims
What is claimed is:
1. A drilling telemetry system comprising: an electromagnetic (EM)
tool sized and configured to be disposed on a drill string and
introduced into a wellbore in a subterranean formation, the EM tool
comprising a transmitter configured to transmit an electromagnetic
signal through the subterranean formation; and a cable antenna
sized and configured to be introduced into an adjacent auxiliary
borehole in the subterranean formation and arranged to receive the
electromagnetic signal transmitted from the EM tool, the cable
antenna comprising: a wireline cable having a center core; an
electrical cable head having a housing, an electrical conductor in
direct electrical communication with the center core of the
wireline cable and extending around a distal-most portion of the
center core; and an uninsulated signal receiver comprising an outer
surface formed from a rigid, conductive material, the uninsulated
signal receiver disposed at a distal-most end of the electrical
cable head, the uninsulated signal receiver in direct electrical
communication with the electrical cable head to provide
uninterrupted electrical communication between the conductive outer
surface and the electrical conductor of the electrical cable head,
the uninsulated signal receiver being exposed to engage against the
subterranean formation when the cable antenna is disposed in the
adjacent auxiliary borehole.
2. The drilling telemetry system of claim 1, wherein the
uninsulated signal receiver has a teardrop shape forming a bulbous
head.
3. The drilling telemetry system of claim 1, wherein the
uninsulated signal receiver further comprises a threaded cavity
formed therein for receiving a portion of the electrical cable
head.
4. The drilling telemetry system of claim 1, wherein the cable
antenna further comprises a polymeric jacket around the center
core, and a protective layer disposed around the polymeric
jacket.
5. The drilling telemetry system of claim 4, wherein the protective
layer is embedded within and fixedly attaches the electrical cable
head to the wireline cable.
6. The drilling telemetry system of claim 1, wherein the conductive
material of the uninsulated signal receiver comprises stainless
steel.
7. The drilling telemetry system of claim 1, wherein the EM tool
further comprises a power source.
8. The drilling telemetry system of claim 1, wherein the
uninsulated signal receiver has a diameter of 2 to 12 inches, and a
length of 3 to 18 inches.
9. A method of using a drilling telemetry system comprising:
introducing an electromagnetic (EM) tool to a wellbore, the EM tool
sized and configured to be disposed on a drill string, the EM tool
comprising a transmitter configured to transmit an electromagnetic
signal through a subterranean formation; introducing a signal
receiving system comprising an uninsulated signal receiver, an
electrical cable head, and a wireline cable to an adjacent
auxiliary borehole; transmitting the EM signal from the EM tool in
the wellbore; detecting the transmitted EM signal with the
uninsulated signal receiver disposed at a distal-most end of the
signal receiving system, the uninsulated signal receiver having a
conductive exterior surface in direct contact with walls of the
auxiliary borehole, the conductive exterior surface being in direct
electrical communication with a distal-most end of the electrical
cable head to provide uninterrupted electrical communication
between the conductive exterior surface and an electrical conductor
of the electrical cable head, the electrical cable head being in
direct electrical communication with a distal-most end of the
wireline cable; and communicating the detected EM signal to a
signal processing system in communication with the wireline
cable.
10. The method of claim 9, wherein said detecting the transmitted
EM signal with the signal receiver comprises said detecting the
transmitted EM signal only at the signal receiver.
11. The method of claim 9, further comprising performing a drilling
operation, and wherein said transmitting the EM signal from the EM
tool occurs during the drilling operation.
12. The method of claim 9, further comprising insulating or
isolating a conductive center core in the wireline cable and the
electrical conductor in the electrical cable head from contact with
the walls of the auxiliary borehole.
13. The method of claim 9, wherein said communicating the detected
EM signal comprises said communicating the detected EM signal
through the electrical conductor in the electrical cable head and
through a conductive center core of the wireline cable.
14. The method of claim 9, wherein the exterior surface of the
signal receiver is in direct conductive electrical communication
with the electrical conductor in the electrical cable head.
15. The method of claim 9, further comprising threading the signal
receiver on to the distal-most end of the electrical cable head to
place a spring-loaded contact in electrical communication with the
signal receiver.
16. The method of claim 9, wherein the signal receiver has a
teardrop shape forming a bulbous head.
17. The method of claim 9, wherein said transmitting the EM signal
comprises said transmitting the EM signal representative of one or
more detected parameters of the wellbore, an environment
surrounding the wellbore, of drilling equipment, of the
subterranean formation, or a combination thereof.
18. A drilling telemetry system comprising: an electromagnetic (EM)
tool sized and configured to be disposed on a drill string and
introduced into a wellbore in a subterranean formation, the EM tool
comprising a transmitter configured to transmit an electromagnetic
signal through the subterranean formation; and a cable antenna
sized and configured to be introduced into an adjacent auxiliary
borehole in the subterranean formation and to receive the
electromagnetic signal transmitted from the EM tool, the cable
antenna comprising: a wireline cable having a center core, a
polymeric insulative layer disposed in the center core, and an
outer protective layer disposed in the polymeric insulative layer;
an electrical cable head having a housing, an electrical conductor
in electrical communication with the center core of the wireline
cable and extending through the housing, and a cable anchor
attached to the outer protective layer and configured to secure the
electrical cable head to a distal-most end of the wireline cable,
the housing having a distal end having a spring-loaded contact; and
an uninsulated signal receiver disposed at a distal-most end of the
cable antenna and formed of a rigid, conductive material having a
diameter of 2 to 12 inches, the uninsulated signal receiver having
a conductive outer surface exposed to engage against the
subterranean formation when the cable antenna is disposed in the
adjacent auxiliary borehole, the uninsulated signal receiver being
in direct electrical communication with the spring-loaded contact
to provide uninterrupted electrical communication between the
conductive outer surface and the electrical conductor of the
electrical cable head.
19. The drilling telemetry system of claim 18, wherein the
uninsulated signal receiver has a teardrop shape forming a bulbous
head.
20. The drilling telemetry system of claim 18, wherein the
uninsulated signal receiver further comprises a threaded cavity
formed therein for receiving a portion of the electrical cable
head.
Description
BACKGROUND OF THE DISCLOSURE
The present disclosure relates in general to logging tools and
particularly to receivers used in electromagnetic logging
tools.
Measurement-while-drilling (MWD) tools and logging-while-drilling
(LWD) tools capture information during the process of drilling a
wellbore. However, the ability of current receivers to receive
signals using MWD tools typically provide drilling parameter
information such as weight on the bit, torque, temperature,
pressure, direction, and inclination. LWD tools typically provide
formation evaluation measurements such as resistivity, porosity,
and NMR distributions (e.g., T1 and T2). MWD and LWD tools often
have characteristics common to wireline tools (e.g., transmitting
and receiving antennas), but MWD and LWD tools must be constructed
to not only endure but to operate in the harsh environment of
drilling.
BRIEF DESCRIPTION OF THE DRAWINGS
The present disclosure is best understood from the following
detailed description when read with the accompanying figures. It is
emphasized that, in accordance with the standard practice in the
industry, various features are not drawn to scale. In fact, the
dimensions of the various features may be arbitrarily increased or
reduced for clarity of discussion.
FIG. 1 is an illustration of an exemplary drilling telemetry system
in a subterranean formation according to one or more aspects of the
present disclosure.
FIG. 2 is an illustration of a cross-sectional view of an exemplary
electromagnetic tool of the telemetry system of FIG. 1 according to
one or more aspects of the present disclosure.
FIG. 3 is an illustration of a cross-sectional view exemplary
signal receiving system of the telemetry system of FIG. 1 according
to one or more aspects of the present disclosure.
FIG. 4 is an illustration of a perspective view of the exemplary
signal receiver according to one or more aspects of the present
disclosure.
FIG. 5 is a flow chart diagram of at least a portion of a method
according to one or more aspects of the present disclosure.
DETAILED DESCRIPTION
It is to be understood that the following disclosure provides many
different embodiments, or examples, for implementing different
features of various embodiments. Specific examples of components
and arrangements are described below to simplify the present
disclosure. These are, of course, merely examples and are not
intended to be limiting. In addition, the present disclosure may
repeat reference numerals and/or letters in the various examples.
This repetition is for the purpose of simplicity and clarity and
does not in itself dictate a relationship between the various
embodiments and/or configurations discussed. Moreover, the
formation of a first feature over or on a second feature in the
description that follows may include embodiments in which the first
and second features are formed in direct contact, and may also
include embodiments in which additional features may be formed
interposing the first and second features, such that the first and
second features may not be in direct contact.
This disclosure is directed to an improved system and method for
obtaining downhole information during a well drilling process. In
some implementations, the system and method employ a transmitting
element on a drill string that communicates electromagnetic signals
through subterranean formations to a receiver disposed in a
separate auxiliary borehole. The receiver may be particularly
arranged to detect and receive signals, even weak signals, passed
through the subterranean formation. In this implementation, the
receiver is particularly designed without exterior material that
may insulate or dampen signals that may be received through the
subterranean formation. That is, in some exemplary implementations,
the receiver comprises a conductive material forming an external
surface of the receiver and disposed in direct contact with the
subterranean formation. In addition, the conductive material may be
in direct communication with a center core or wire forming a
portion of the wireline cable. Signal processing may occur at the
surface.
FIG. 1 shows an example of a drilling telemetry system 100 for
signaling in a subterranean formation. In this implementation, the
drilling telemetry system 100 is formed of a drilling rig system
102 and a signal receiving system 104. The drilling rig system 102
includes, among other components, a transmitter, and the signal
receiving system 104 includes, among other components, a receiver.
The drilling rig system 102 may electromagnetically communicate
information to the receiving system 104. For example, the drilling
rig system 102 may transmit information, such as information
relating to the status of the drilling rig system 102, the
wellbore, or other information to the receiving system 104. In
other examples, the drilling rig system 102 may emit
electromagnetic signals that may be captured by the receiving
system 104 that may allow the receiving system 104 to detect
geological formation characteristics or other information relating
to the geographic material through which the signals are
transmitted.
The drilling rig system 102 may be, for example, a land-based
drilling rig system--however, one or more aspects of the present
disclosure are applicable or readily adaptable to any type of
drilling rig system (e.g., a jack-up rig, a semisubmersible, a
drill ship, a coiled tubing rig, a well service rig adapted for
drilling and/or re-entry operations, and a casing drilling rig,
among others). The drilling rig system 102 includes a mast 106 that
supports lifting gear above a rig floor 108, which lifting gear may
include a crown block and a traveling block. The crown block may be
disposed at or near the top of the mast 106. The traveling block
may hang from the crown block by a drilling line. The drilling line
may extend at one end from the lifting gear to drawworks, which
drawworks are configured to reel out and reel in the drilling line
to cause the traveling block to be lowered and raised relative to
the rig floor 108.
In some implementations, the drilling rig system 102 may include a
top drive 110 suspended from the bottom of the traveling block. A
drill string 112 may be suspended from the top drive 110 and
suspended within a wellbore 113.
The drill string 112 may include interconnected sections of drill
pipe 114, a bottom-hole assembly ("BHA") 116, and a drill bit 118.
The BHA 116 may include stabilizers, drill collars, and/or
measurement-while-drilling ("MWD") or wireline conveyed
instruments, among other components. The drill bit 118 (also be
referred to herein as a tool) is connected to the bottom of the BHA
116 or is otherwise attached to the drill string 112.
The downhole MWD or wireline conveyed instruments may be configured
for the evaluation of physical properties such as pressure,
temperature, torque, weight-on-bit ("WOB"), vibration, inclination,
azimuth, toolface orientation in three-dimensional space, and/or
other downhole parameters. These measurements may be made downhole,
stored in solid-state memory for some time, and downloaded from the
instrument(s) at the surface and/or transmitted real-time to the
surface. In the implementations described herein, data may be
transmitted electromagnetic pulses. In some implementations, in
addition to transmission capability, the MWD tools and/or other
portions of the BHA 116 may have the ability to store measurements
for later retrieval via wireline and/or when the BHA 116 is tripped
out of the wellbore 113.
In the embodiment of FIG. 1, the top drive 110 is utilized to
impart rotary motion to the drill string 112. However, aspects of
the present disclosure are also applicable or readily adaptable to
implementations utilizing other drive systems, such as a power
swivel, a rotary table, a coiled tubing unit, a downhole motor,
and/or a conventional rotary rig, among others.
The drilling rig system 102 also includes a control system 120
configured to control or assist in the control of one or more
components of the drilling rig system 102--for example, the control
system 120 may be configured to transmit operational control
signals to a drawworks, the top drive 110, the BHA 116 and/or
additional equipment. In some embodiments, the control system 120
includes one or more systems located in a control room proximate
the drilling rig system 102, such as the general purpose shelter
often referred to as the "doghouse" serving as a combination tool
shed, office, communications center, and general meeting place. The
control system 120 may be configured to transmit the operational
control signals to the drawworks, the top drive 110, the BHA 116,
and/or other equipment via wired or wireless transmission (not
shown). The control system 120 may also be configured to receive
electronic signals via wired or wireless transmission (also not
shown) from a variety of sensors included in the drilling rig
system 102, where each sensor is configured to detect an
operational characteristic or parameter. Some example sensors from
which the control system 120 is configured to receive electronic
signals via wired or wireless transmission (not shown) may include
one or more of the following: a torque sensor, a speed sensor, and
a WOB sensor. In some implementations, the BHA 116 may also include
sensors disposed thereon. Some exemplary sensors include for
example, a downhole annular pressure sensor 122a, a shock/vibration
sensor 122b, a toolface sensor 122c, a WOB sensor 122d, a surface
casing annular pressure sensor 124, a mud motor delta pressure
(".DELTA.P") sensor 126a, and one or more torque sensors 126b. The
sensors are merely examples of any of a variety of sensors that may
be included on the BHA 116, the drill bit 118, and/or otherwise
disposed about the drilling rig system 102.
In this exemplary embodiment, the BHA 116 also includes an EM tool
130. The EM tool 130 may be configured to propagate an
electromagnetic signal to convey information from the BHA for
receipt and analysis by drilling rig personnel. Although identified
as a part of the BHA 116, in some implementations, the EM tool 130
is disposed elsewhere along the drill string 112 and down in the
wellbore 113. Some implementations include multiple EM tools 130
arranged to propagate a signal through the subterranean formations.
The EM tool 130 may form a part of the measurement while drilling
MWD tool. In some implementations, the EM tool 130 may form a part
of a collar or stabilizer of the drill string. Some implementations
of the EM tool 130 feature 2-way EM communication, while other
implementations include only transmission capability. In some
implementations, the power, the data rate, and the carrier wave may
be adjustable while drilling to help transmit through changing
formations. In some implementations, the EM tool may operate using
batteries or a turbine alternator. The turbine alternator may
enable longer downhole times, and higher transmitting power for
longer periods. Some implementations may include backup batteries
for operation during periods of no flow.
FIG. 2 shows an example of an EM tool 130 that may form a part of
the BHA 116. The EM tool 130 may include an electrode 131, a
downlink receiver 132, a transmitter 133, and the power source 134,
such as batteries. The electrode 131 may enable the EM tool 130 to
communicate with other downhole systems such as, for example,
sensing systems that may be carried on the BHA. The downlink
receiver 132 may be configured to receive signals and information
from the surface, from other EM tools, or other equipment that may
be in communication with the EM tool 130. The transmitter 133
transmits EM signals through geological formations. In some
implementations, the transmitter 133 is a high-voltage transmitter
configured to automatically select the necessary power usage for
the formation resistance. This may help extend the life of the
power source 134 by reducing the need to transmit at full power in
certain situations.
Returning to FIG. 1, the signal receiving system 104 may be
disposed in an auxiliary borehole 138. The signal receiving system
104 may include a cable antenna 140 and a signal processing system
142. In the implementation shown, the cable antenna 140 includes a
wireline cable 144, an electrical cable head 146, and a signal
receiver 148. In this example, the wireline cable 144 may extend or
be wound around a cable coil or reel 150 disposed on steerable
equipment, such as a working vehicle 152, such as a truck. In the
deployed configuration shown, the wireline cable 144 may extend
from the cable coil 150 through a bore head 154, and into the
auxiliary borehole 138.
FIG. 3 shows a cross-section of a portion of the signal receiving
system 104, including a portion of the wireline cable 144, the
electrical cable head 146, and the signal receiver 148. The
wireline cable 144 may include a center core 160, a polymer jacket
162 surrounding the center core 160, and a protective or armor
layer 164 disposed about the polymer jacket 162. The center core
160 may be formed of a conductive material and may extend the
length of the wireline cable 144. The center core 160 may be
configured to communicate signals from the electrical cable head
146 and the signal receiver 148 to the processing system 142. In
some examples, the polymer jacket is a polytetrafluoroethylene
(PTFE) material, and in some implementations, the polymer jacket is
or includes TEFLON.RTM. material. The polymer jacket 162 may
insulate or isolate the center core 160 from the armor layer 164.
The protective or armor layer 164 may be formed of any material
that provides protection and strength to the wireline cable 144.
For example, it may comprise a metal or metal-clad, hollow cable
that provides sufficient tensile strength to the wireline cable
144. It may be formed of a plurality of braided wires or otherwise
formed. It may be metal or some other material, including
non-conductive materials. It may be designed to carry the weight of
electrical cable head 146 and the signal receiver 148. The armor
layer 164 may form the outer surface of the wireline cable 144. In
some implementations, the armor layer is a steel armor layer.
The electrical cable head 146 may be disposed between the wireline
cable 144 and the signal receiver 148. It may electrically connect
the center core 160 to the conductive material of the signal
receiver 148. In some implementations, electrical cable head 146
may include a housing 168, an electrical conductor 170, and a cable
anchor 172. The housing 168 extends from a proximal end 174 to a
distal end 176. The proximal end 174 may include an opening 178
through which the wireline cable 144 may extend. The opening 178
may lead to an anchor cavity 180 in communication with a passage
182. The distal end 176 of the housing 168 may include a threaded
tip 184.
The electrical conductor 170 may be in electrical communication
with the center core 160 of the wireline cable 144. In some
implementations, the electrical conductor 170 may extend in the
passage 182 from the proximal end 174 to the distal end 176 and may
terminate at the threaded tip 184. In some implementations, the
electrical conductor 170 comprises a spring-loaded contact 186
projecting from the distal end 176 that contacts the signal
receiver 148.
The cable anchor 172 may be disposed within the anchor cavity 180
and may be connected to the wireline cable 144. In some
implementations, the cable anchor 172 is attached to the armor
layer 164 of the wireline cable 144. In some implementations, the
center core 160 is electrically connected with the electrical
conductor 170 through the cable anchor 172. Some implementations
include an insulative cover about the electrical conductor 170. The
insulative cover may be for example a ceramic or polymeric material
that prevents electrical communication between the electrical
conductor 170 and the housing 168.
The signal receiver 148 is connected to the distal end 176 of the
housing 168. The signal receiver 148 may be formed of a heavy,
conductive material. In some implementations, the signal receiver
148 is formed of a solid stainless steel material. In other
implementations, the signal receiver 148 is formed of copper,
silver, or other highly conductive material and with features
aiding deployment and contact with formation or casing it is
deployed in. In the implementation shown, the signal receiver 148
is formed of a solid bulbous head 190 with sides 192 that taper
toward the housing 168, forming a frustum. A threaded bore or
threaded cavity 194 is disposed in the end of the frustum and
receives the threaded tip 184 of the housing 168. The signal
receiver 148 is formed to abut in direct contact with the walls or
sides of the auxiliary borehole 138 (FIG. 1) through which it is
introduced. Accordingly, the signal receiver 148 is in contact with
the natural geological formation of the auxiliary borehole 138. In
some embodiments, signal receiver 148 may contact the hole casing
in case of cased holes. As such, the signal receiver 148 also acts
as the signal receiver from the EM tool 130. Because the signal
receiver 148 is in direct contact with the subterranean formation,
the signal receiver 148 is configured and arranged to receive EM
signals from the EM tool 130 without interference or dampening from
unnatural components about the signal receiver 148. For example,
the signal receiver 148 is free of insulative or protective
materials that may interfere or dampen reception of signals. Also,
it is deployed deeper relative to a conventional EM antenna at the
surface which is prone to signal attenuation for long reach wells
and signal loss in case of salt domes in certain basins. Because of
this, the signal receiver 148 may be particularly sensitive to even
weak signals emitted from the EM tool 130 and propagated through
the subterranean formation. Furthermore, the electrically
conductive outer surface (the exterior surface) of the signal
receiver 148 is in direct electrical communication with the
electrical conductor 170 of the cable anchor 172, and with the
center core 160 of the wireline cable 144. This electrical
connection may be free of filtering or other signal distorting
components so that the signal communicated to the ground surface is
the complete and natural signal received at the signal receiver
148.
In this implementation, the shape of the signal receiver 148 may
contribute to the receptivity of the EM signals. For example, the
bulbous head, having a diameter greater than the diameter of the
electrical cable head 146 insures that a significant portion of the
signal receiver 148 is in contact with the natural subterranean
formation. In the implementation shown, the signal receiver 148 has
the largest cross-sectional diameter of any of the wireline cable
144 or the electrical cable head 146. This may help increase the
likelihood that the signal receiver 148 will be in contact with the
subterranean formation whether disposed in a vertical auxiliary
borehole or in a curved or a horizontal auxiliary borehole.
FIG. 4 shows a perspective view of an example of a signal receiver
148. The signal receiver 148 in this implementation includes a
rounded leading end 196 and a trailing end 198. The tapering sides
192 taper toward the trailing end 198. In this implementation, the
signal receiver 148 has a substantially teardrop-shape, with the
rounded leading end 196 forming the large diameter bulbous head. A
notch 199 may be formed in a side to enable the signal receiver 148
to be grasped by a tool for threading onto the electrical cable
head 146. In some implementations, the signal receiver 148 has a
diameter in the range of about 2 to 12 inches, and has a length in
a range of about 3 to 18 inches, although larger and smaller
diameters and lengths are contemplated. In some implementations,
the signal receiver 148 has a diameter in the range of about 2 to 4
inches and has a length in the range of about 4 to 8 inches.
Furthermore, the rigidity of the bulbous signal receiver reduces
the likelihood of hang-up when the signal receiver 148 is
introduced and fed through the auxiliary borehole 138. For example,
a loose cable or other flexible component at the distal end may
interfere with advancement of the signal receiving system 104.
In some implementations, an insulative covering may isolate the
signal receiver 148 from the housing 168 of the electrical cable
head 146. In such implementations, the signal receiver 148 is still
in electrical communication with the electrical conductor 170
projecting from the threaded tip 184 of the housing 168. In some
implementations, the electrical conductor 170 is the only component
in electrical communication with the signal receiver 148.
The signal processing system 142 may be disposed at the surface
adjacent the bore hole and may be configured to receive and process
signals detected or received at the signal receiver 148. In some
implementations, the processing system 142 is in direct
communication with the center core 160 of the wireline cable 144.
Accordingly, signals detected at the signal receiver 148 may be
communicated through the electrical cable head 146 and the wireline
cable 144 to the processing system 142. In some implementations,
the processing system 142 is a computer having software configured
to interpret EM signals received from the EM tool 130.
Because the signal receiver 148 is able to directly contact the
subterranean formations, and there is no isolation or insulative
elements between the signal receiver 148 and the center core 160,
EM signals may be more easily received and captured for processing.
The cable antenna 140 implementation shown in FIG. 3 may be a
retrievable type and may be easily deployable by means of coil
tubing or wireline or the center conductor can be isolated or
connected to the polymeric material. In some implementations, this
receiver may be used for a multitude of wells being drilled across
the pad as well as nearby pads. In some implementations, the
wireline cable 144, the electrical cable head 146, and the signal
receiver 148 form a simple conductive connection having no control
feedback or logic system. It may receive and relay the signal to
the surface. In some implementations, the system does not require
electric/magnetic isolation between the center core and the
polymeric jacket. Furthermore, in some implementations, the system
does not require insulation between the signal receiver 148, the
electrical conductor 170, and the center core 160.
FIG. 5 is a flow diagram showing a process of using the drilling
telemetry system 100 according to an exemplary implementation. At
502, a user may introduce the EM tool 130 to the wellbore. The EM
tool 130 may form a part of or be disposed adjacent to a BHA during
a drilling operation carried out by the drilling rig system 102. In
some implementations, the EM tool 130 may be spaced apart from the
BHA, but may be downhole in the subterranean formation.
At 504, a user may introduce the signal receiving system to an
auxiliary borehole. Because of the size and shape of the signal
receiver 148, the signal receiver may be in direct contact with the
natural subterranean formation. That is, because the signal
receiver 148 forms the distal most tip of the signal receiving
system, and because the signal receiver 148 may, in some
implementations, have a diameter larger than other components
around the signal receiver 148, the signal receiver 148 may be in
direct contact with the natural subterranean formation. Since the
signal receiver 148 is also un-insulated, EM signals propagated
through the subterranean formation may be detected or picked up
directly from the subterranean formation without interference or
dampening from insulative or isolating materials other than the
natural subterranean formation. The signal receiving system 104 may
be introduced to the auxiliary borehole with the electrical cable
head 146 and the signal receiver 148 suspended from the wireline
cable 144. The signal receiver and the electrical cable head 146
each include direct electrical contact with each other.
At 506, the EM tool 130 may transmit EM signals through the
subterranean formation. The signals may relate to detected
parameters of the wellbore and its surrounding environment, of the
drilling equipment, or of the subterranean formation. Accordingly,
the transmitted EM signals may include MWD or LWD information. The
EM signals may be transmitted while actual drilling is occurring,
or may be transmitted during down times of the drilling process,
such as when stands are being introduced to the drill string or
during other stoppages in actual drilling.
At 508, the signal receiver 148 may detect the EM signals directly
from the subterranean formation. Since the signal receiver 148 is
particularly shaped to provide a large amount of surface contact
area, as well as have a wider diameter than other components of the
downhole signal receiving system, the signal receiver 148 may
receive signals left otherwise undetected by conventional telemetry
systems. In some implementations, the EM signals are received only
at the signal receiver. In such implementations, the electrical
cable head 146 and the wireline cable 144 may include insulative or
protective materials disposed about their respective conductive
portions that may inhibit reception of EM signals transmitted or
propagated through the subterranean formation.
At 510, the detected signals may be communicated directly from the
signal receiver through the electrical cable head 146 and the
wireline cable 144 to the processing system 142. Since the signal
receiver is in direct electrical communication with the electrical
conductor of the electrical cable head 146, and since the
electrical conductor 170 is in direct electrical communication with
the center core 160 of the wireline cable 144, signals may be
communicated directly to the processing system 142, even when the
processing system 142 is disposed above ground. At 512, the
processing system 142 may interpret the signals at the surface.
In an exemplary aspect, the present disclosure is directed to a
drilling telemetry system that may include an EM tool sized and
configured to be disposed on a drill string and introduced into a
wellbore in a subterranean formation. The EM tool may comprise a
transmitter configured to transmit an electromagnetic signal
through the subterranean formation. The drilling telemetry system
may also include a cable antenna sized and configured to be
introduced into an adjacent auxiliary borehole in the subterranean
formation and arranged to receive the electromagnetic signal
transmitted from the EM tool. The cable antenna may comprise a
wireline cable having a center core, an insulated electrical cable
head in direct electrical communication with the center core, and
an uninsulated signal receiver in direct electrical communication
with electrical cable head. The uninsulated signal receiver may
have an outer surface formed of a conductive material and
configured to engage against a natural subterranean formation.
In some aspects, the uninsulated signal receiver has a teardrop
shape forming a bulbous head. In some aspects, the uninsulated
signal receiver comprises a threaded cavity formed therein for
receiving a portion of the electrical cable head. In some aspects,
the cable antenna comprises a polymeric jacket around the center
core, and a protective layer disposed around the polymeric jacket.
In some aspects, the armor layer is embedded within and fixedly
attaches the insulated electrical cable head to the cable. In some
aspects, the conductive material of the uninsulated signal receiver
comprises stainless steel. In some aspects, the EM tool comprises a
transmitter and a power source. In some aspects, the uninsulated
signal receiver has a diameter of about 2 to about 12 inches, and a
length of about 3 to about 18 inches.
In an exemplary implementation, a method of using a drilling
telemetry system may include introducing an EM tool to a wellbore;
introducing a signal receiving system to an adjacent auxiliary
borehole; transmitting an EM signal from the EM tool in the
wellbore; detecting the transmitted EM signal with the signal
receiver having a conductive exterior surface in direct contact
with walls of the auxiliary borehole, the conductive exterior
surface being in direct electrical communication with an electrical
cable head and a wireline cable; and communicating the detected EM
signal to a signal processing system in communication with the
wireline cable.
In some aspects, detecting the transmitted EM signal with the
signal receiver comprises detecting the transmitted EM signal only
at the signal receiver. In some aspects, the method may include
performing a drilling operation, and wherein transmitting the EM
signal from the EM tool occurs during the drilling operation. In
some aspects, the method may include insulating or isolating a
conductive center core in the wireline cable and a conductor in the
electrical cable head from contact with the walls of the auxiliary
borehole. In some aspects, communicating the detected EM signal
comprises communicating the detected EM signal through a conductor
in the electrical cable head and through a conductive center core
of the wireline cable. In some aspects, the exterior surface of the
signal receiver is in direct conductive electrical communication
with the conductor in the electrical cable head. In some aspects,
the method may include threading the signal receiver on to a distal
end of the electrical cable head to place a spring-loaded contact
in electrical communication with the signal receiver. In some
aspects, the uninsulated signal receiver has a teardrop shape
forming a bulbous head. In some aspects, transmitting an EM signal
comprises transmitting an EM signal representative of one or more
detected parameters of the wellbore, an environment surrounding the
wellbore, of the drilling equipment, of the subterranean formation,
or a combination thereof.
In an exemplary aspect, the present disclosure is directed to a
drilling telemetry system that includes an EM tool sized and
configured to be disposed on a drill string and introduced into a
wellbore in a subterranean formation. The EM tool may include a
transmitter configured to transmit an electromagnetic signal
through the subterranean formation. The drilling telemetry system
may also include a cable antenna sized and configured to be
introduced into an adjacent auxiliary borehole in the subterranean
formation and to receive the electromagnetic signal transmitted
from the EM tool. The cable antenna may include a wireline cable
having a center core, a polymeric insulative layer disposed about
the center core, and an outer protective layer disposed about the
polymeric insulative layer. The cable antenna also may include an
electrical cable head having a housing, an electrical conductor in
electrical communication with the center core of the wireline and
extending through the housing, and a cable anchor attached to the
outer protective layer and configured to secure the electrical
cable head to the wireline cable. The housing may have a distal end
having a spring-loaded contact. The cable antenna also may include
an uninsulated signal receiver disposed at a distal-most end of the
cable antenna and formed of a rigid, conductive material having a
diameter of about 2 to about 12 inches. The uninsulated signal
receiver may have a conductive outer surface exposed to engage
against a natural subterranean formation when the cable antenna is
disposed in borehole. The uninsulated signal receiver may be in
direct electrical communication with the spring-loaded contact to
provide uninterrupted electrical communication between the
conductive outer surface and the electrical conductor of the
electrical cable head.
In some aspects, the uninsulated signal receiver has a teardrop
shape forming a bulbous head. In some aspects, the uninsulated
signal receiver comprises a threaded cavity formed therein for
receiving a portion of the electrical cable head.
In several exemplary embodiments, the elements and teachings of the
various illustrative exemplary embodiments may be combined in whole
or in part in some or all of the illustrative exemplary
embodiments. In addition, one or more of the elements and teachings
of the various illustrative exemplary embodiments may be omitted,
at least in part, and/or combined, at least in part, with one or
more of the other elements and teachings of the various
illustrative embodiments.
Any spatial references such as, for example, "upper," "lower,"
"above," "below," "between," "bottom," "vertical," "horizontal,"
"angular," "upwards," "downwards," "side-to-side," "left-to-right,"
"right-to-left," "top-to-bottom," "bottom-to-top," "top," "bottom,"
"bottom-up," "top-down," etc., are for the purpose of illustration
only and do not limit the specific orientation or location of the
structure described above.
In several exemplary embodiments, while different steps, processes,
and procedures are described as appearing as distinct acts, one or
more of the steps, one or more of the processes, and/or one or more
of the procedures may also be performed in different orders,
simultaneously and/or sequentially. In several exemplary
embodiments, the steps, processes and/or procedures may be merged
into one or more steps, processes and/or procedures.
In several exemplary embodiments, one or more of the operational
steps in each embodiment may be omitted. Moreover, in some
instances, some features of the present disclosure may be employed
without a corresponding use of the other features. Moreover, one or
more of the above-described embodiments and/or variations may be
combined in whole or in part with any one or more of the other
above-described embodiments and/or variations.
Although several exemplary embodiments have been described in
detail above, the embodiments described are exemplary only and are
not limiting, and those skilled in the art will readily appreciate
that many other modifications, changes and/or substitutions are
possible in the exemplary embodiments without materially departing
from the novel teachings and advantages of the present disclosure.
Accordingly, all such modifications, changes and/or substitutions
are intended to be included within the scope of this disclosure as
defined in the following claims. In the claims, any
means-plus-function clauses are intended to cover the structures
described herein as performing the recited function and not only
structural equivalents, but also equivalent structures.
The foregoing outlines features of several embodiments so that a
person of ordinary skill in the art may better understand the
aspects of the present disclosure. Such features may be replaced by
any one of numerous equivalent alternatives, only some of which are
disclosed herein. One of ordinary skill in the art should
appreciate that they may readily use the present disclosure as a
basis for designing or modifying other processes and structures for
carrying out the same purposes and/or achieving the same advantages
of the embodiments introduced herein. One of ordinary skill in the
art should also realize that such equivalent constructions do not
depart from the spirit and scope of the present disclosure, and
that they may make various changes, substitutions and alterations
herein without departing from the spirit and scope of the present
disclosure.
The Abstract at the end of this disclosure is provided to comply
with 37 C.F.R. .sctn. 1.72(b) to allow the reader to quickly
ascertain the nature of the technical disclosure. It is submitted
with the understanding that it will not be used to interpret or
limit the scope or meaning of the claims.
Moreover, it is the express intention of the applicant not to
invoke 35 U.S.C. .sctn. 112, paragraph 6 for any limitations of any
of the claims herein, except for those in which the claim expressly
uses the word "means" together with an associated function.
* * * * *