Note: Descriptions are shown in the official language in which they were submitted.
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MITIGATION OF CABLE DAMAGE DURING PERFORATION
TECHNICAL FIELD
[0001] The present disclosure generally relates to oilfield equipment and, in
particular, to
downhole tools, drilling and related systems and techniques for completing,
servicing, and
evaluating wellbores in the earth. More particularly still, the present
disclosure relates to
systems and methods for locating cables and orienting a downhole tool in
relation to the
cables.
BACKGROUND
[0002] After drilling the various sections of a subterranean wellbore that
traverses a
formation, individual lengths of relatively large diameter metal tubulars are
typically secured
together to form a casing string that is positioned within the wellbore. This
casing string
increases the integrity of the wellbore and provides a path for producing
fluids from the
producing intervals to the surface. Conventionally, the casing string is
cemented within the
wellbore by pumping a cement slurry through the casing and into the annulus
between the
casing and the formation. To produce fluids into the casing string, hydraulic
openings or
perforations must be made through the casing string, the cement sheath, and a
short distance
into the formation.
[0003] Typically, these perforations are created by a perforating tool
connected along a tool
string that is lowered into the cased wellbore by a tubing string, wireline,
slickline, coiled
tubing, or other conveyance. Once the perforating tool is properly oriented
and positioned in
the wellbore adjacent the formation to be perforated, the perforating toot is
actuated to create
perforations through the casing and cement sheath into the formation.
[0004] It is sometimes desirable to perforate a well in a particular
direction. For example,
where one or more cables have been permanently deployed downhole adjacent the
casing, it
is desirable to avoid damaging the cables during perforating.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] Various embodiments of the present disclosure will be understood more
fully from
the detailed description given below and from the accompanying drawings of
various
embodiments of the disclosure. In the drawings, like reference numbers may
indicate
identical or flinctionally similar elements. Embodiments are described in
detail hereinafter
with reference to the accompanying figures, in which:
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[0006] Figure 1 is an elevation view in partial cross section of a land-based
well system
with a system to mitigate cable damage due to perforating according to an
embodiment;
[0007] Figure 2 is an elevation view in partial cross section of a marine-
based well system
with a system to mitigate cable damage due to perforating according to an
embodiment;
[0008] Figure 3A is an elevation view in partial cross section of a portion of
the well
system of Figure 2 utilizing an optic cable to mitigate damage to cables
during perforating;
[0009] Figure 3B is an elevation view in partial cross section of a portion of
the well
system of Figure 2 utilizing an electric cable to mitigate damage to cables
during perforating;
[00010] Figure 4 is a schematic view of the electro-acoustic transducer
package of Figure 3;
[00011] Figure 5A is a view of a cable support mechanism with an electro-
acoustic
transducer package according to an embodiment; and
[00012] Figure 5B is an exploded view of the cable support mechanism of Figure
5A.
[00013] Figure 5C is an axial view of the cable support mechanism of Figure
5A.
[00014] Figure 6 is an elevation view of a wellbore having a plurality of EAT
sensors
deployed adjacent a fiber optic cable.
[00015] Figure 7 illustrates embodiments of a method for utilizing EAT sensors
to determine
the axial location and radial position of a cable in a wellbore.
DETAILED DESCRIPTION OF THE DISCLOSURE
[00016] The disclosure may repeat reference numerals and/or letters in the
various
examples or figures. 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. Further, spatially relative terms, such as beneath, below, lower,
above, upper,
uphole, downhole, upstream, downstream, and the like, may be used herein for
ease of
description to describe one element or feature's relationship to another
element(s) or
feature(s) as illustrated, the upward direction being toward the top of the
corresponding figure
and the downward direction being toward the bottom of the corresponding
figure, the uphole
direction being toward the surface of the wellbore, the downhole direction
being toward the
toe of the wellbore. Unless otherwise stated, the spatially relative terms are
intended to
encompass different orientations of the apparatus in use or operation in
addition to the
orientation depicted in the figures. For example, if an apparatus in the
figures is turned over,
elements described as being "below" or "beneath" other elements or features
would then be
oriented "above" the other elements or features. Thus, the exemplary tem
"below" can
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encompass both an orientation of above and below. The apparatus may be
otherwise oriented
(rotated 90 degrees or at other orientations) and the spatially relative
descriptors used herein
may likewise be interpreted accordingly.
[000171 Moreover, even though a figure may depict a horizontal wellbore or a
vertical
wellbore, unless indicated otherwise, it should be understood by those skilled
in the art that
the apparatus according to the present disclosure is equally well-suited for
use in wellbores
having other orientations including, deviated wellbores, multilateral
wellbores, or the like.
Likewise, unless otherwise noted, even though a figure may depict an offshore
operation, it
should be understood by those skilled in the art that the apparatus according
to the present
disclosure is equally well-suited for use in onshore operations and vice-
versa.
1000181 Generally, a cable support mechanism for coupling a cable to a casing
section of a
downhole casing string generally includes first and second collar sections
that couple together
to form a clamp that extends around a casing section. One of the collars forms
a pathway for
receipt of a cable when installed on a casing section such that the collars
secure the cable to
the casing section. Preferably the pathway is axially aligned with the axis of
the clamp so
that when the clamp is attached to a casing section, the cable is axially
aligned with the
casing section. Mounted on the clamp adjacent the pathway are an electro-
acoustic
transducer and a set of the orientation devices, wherein the set comprises a
first orientation
device and a second orientation device orthogonally oriented with respect to
one another. A
plurality of cable support mechanisms are axially spaced apart from one
another along a
casing string thereby securing a cable to the casing string. In other
embodiments, the
plurality of electro-acoustic transducers and/or sets of orientation devices
are mounted
directly on the casing string without utilizing cable support mechanisms. In
either case, a
transmission cable is axially disposed along the casing string. At least one
transducer
generates a first wireless signal. The wireless signal may be an acoustic
signal. A second
wired signal is transmitted along the cable based on the first signal. In one
or more
embodiments, the cable is an optic cable and the second signal is an optic
signal generated
from a optic signal emitting source. In some embodiments, the second signal is
an electric
signal generated from a sensor in electrical communication with the cable. In
one or more
embodiments, the first wireless signal is utilized to generate or alter the
second wired signal
traveling along the cable in order to establish the location and position of
the electro-acoustic
transducer in the wellbore. In one or more embodiments, the first acoustic
wireless signal
causes altered backscattering or reflection of the second wired optic signal,
thereby
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influencing the second wired optic signal traveling along the cable. Where the
electro-
acoustic transducer is positioned adjacent the cable, the second signal is
utilized to establish
the location and position of the wire in the wellbore, thus permitting a
perforating tool to be
discharged in a direction so as not to damage the cable during firing.
[000191 Turning to Figures 1 and 2, shown is an elevation view in partial
cross-section of a
wellbore production system 10 utilized to produce hydrocarbons from wellbore
12 extending
through various earth strata in an oil and gas formation 14 located below the
earth's surface
16. Wellbore 12 may be formed of a single or multiple bores 12a, 12b.... 12n
(illustrated in
Figure 2), extending into the formation 14, and disposed in any orientation,
such as the
horizontal wellbore 12b illustrated in Figure 2.
[000201 Production system 10 includes a rig or derrick 20. Rig 20 may include
a hoisting
apparatus 22, a travel block 24, and a swivel 26 for raising and lowering
casing, drill pipe,
coiled tubing, production tubing, other types of pipe or tubing strings or
other types of
conveyance vehicles such as wireline, slickline, and the like 30, In Figure 1,
conveyance
vehicle 30 is a substantially tubular, axially extending drill string formed
of a plurality of pipe
joints coupled together end-to-end, while in Figure 2, conveyance vehicle 30
is completion
tubing supporting a completion assembly as described below. Rig 20 may include
a kelly 32,
a rotary table 34, and other equipment associated with rotation and/or
translation of tubing
string 30 within a wellbore 12. For some applications, rig 20 may also include
a top drive
unit 36.
[000211 Rig 20 may be located proximate to a wellhead 40 as shown in Figure 1,
or spaced
apart from wellhead 40, such as in the case of an offshore arrangement as
shown in Figure 2.
One or more pressure control devices 42, such as blowout preventers (B0Ps) and
other
equipment associated with drilling or producing a wellbore may also be
provided at wellhead
40 or elsewhere in the system 10.
[000221 For offshore operations, as shown in Figure 2, rig 20 may be mounted
on an oil or
gas platform 44, such as the offshore platform as illustrated, semi-
submersibles, drill ships,
and the like (not shown). Although system 10 of Figure 2 is illustrated as
being a marine-
based production system, system 10 of Figure 2 may be deployed on land.
Likewise,
although system 10 of Figure 1 is illustrated as being a land-based production
system, system
of Figure 1 may be deployed offshore, In any event, for marine-based systems,
one or
more subsea conduits or risers 46 extend from deck 50 of platform 44 to a
subsea wellhead
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40. Tubing string 30 extends down from rig 20, through subsea conduit 46 and
BOP 42 into
wellbore 12.
[00023] A working or service fluid source 52, such as a storage tank or
vessel, may supply
a working fluid 54 pumped to the upper end of tubing string 30 and flow
through tubing
string 30. Working fluid source 52 may supply any fluid utilized in wellbore
operations,
including without limitation, drilling fluid, cementious slurry, acidizing
fluid, liquid water,
steam or some other type of fluid.
[000241 Production system 10 may generally be characterized as having a pipe
system 58.
For purposes of this disclosure, pipe system 58 may include casing, risers,
tubing, drill
strings, completion or production strings, subs, heads or any other pipes,
tubes or equipment
that couples or attaches to the foregoing, such as string 30, conduit 46,
collars, and joints, as
well as the wellbore 12 and laterals in which the pipes, casing and strings
may be deployed.
In this regard, pipe system 58 may include one or more casing strings 60 that
may be
cemented in wellbore 12, such as the surface, intermediate and production
casings 60 shown
in Figure 1. An annulus 63 is formed between the walls of sets of adjacent
tubular
components, such as concentric casing strings 60 or the exterior of tubing
string 30 and the
inside wall of wellbore 12 or casing string 60, as the case may be.
[00025] Fluids, cuttings and other debris returning to surface 16 from
wellbore 12 are
directed by a flow line 118 to storage tanks 54 and/or processing systems 120,
such as
shakers, centrifuges and the like.
[00026] With respect to Figure 2 where subsurface equipment 56 is illustrated
as
completion equipment, disposed in a substantially horizontal portion of
wellbore 12 with
casing system 60 cemented in well bore 12, which includes casing sections 61
connected with
casing connectors or collars 62. A lower completion assembly 82 is disposed in
the casing
system 60 and includes various tools such as an orientation and alignment
subassembly 84, a
packer 86, a sand control screen assembly 88, a packer 90, a sand control
screen assembly 92,
a packer 94, a sand control screen assembly 96 and a packer 98.
[00027] Extending downhole from lower completion assembly 82 is one or more
communication cables 100, such as a sensor or electric cable, that passes
through packers 86,
90, 94 and is operably associated with one or more electrical devices 102
associated with
lower completion assembly 82, such as sensors positioned adjacent casing
collars 62, or
downhole controllers or actuators used to operate downhole tools or fluid flow
control
devices. Cable 100 may operate as communication media, to transmit power, or
data and the
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like between lower completion assembly 82 and an upper completion assembly
104. Data
and other information may be communicated using electrical signals, acoustic
signals or other
telemetry that can be converted to electrical signals at the rig 20 to, among
other things,
monitor the conditions of the environment and various tools in lower
completion assembly 82
or other tool string.
1000281 In this regard, disposed in wellbore 12 at the lower end of tubing
string 30 is an
upper completion assembly 104 that includes various tools such as a packer
106, an
expansion joint 108, a packer 110, a fluid flow control module 112 and an
anchor assembly
114.
[000291 Extending uphole from upper completion assembly 104 are one or more
communication cables 116, such as a sensor cable or an electric cable, which
extends to the
surface 16. Cable 116 may operate as communication media, to transmit power,
or data and
the like between a surface controller (not shown) and the upper and lower
completion
assemblies 104, 82, respectively.
1000301 Shown deployed in Figures 1 and 2 is a cable support system 200 to
mitigate
against damage to a cable (such as cable 100) due to perforating. Shown in
Figure 3A is an
elevation view in partial cross section of a portion of the well system of
Figures 1 and 2 with
cable support system 200 installed to mitigate against damage to a cable due
to perforation.
Also shown in Figure 3A in dashed lines to indicate it is within the interior
of casing 30 is a
perforating tool 290 supported on deployment vehicle 30. Perforating tool 290
is shown
having charges 291. Cable support system 200 comprises at least one electro-
acoustic
transducer (EAT) package 210, at least one cable support mechanism 220, a
sensing cable
250, and a control system 270. Sensing cable 250 may be the same or different
than cable
100. In cases, where they are different, the cables are co-located together in
the wellbore 12
as described herein. Sensing cable 250 may comprise multiple cables, such as a
first optic
cable and a second electric cable. In one or more embodiments, control system
270 may be
disposed at surface 16 (land-based well system) or platform 44 (marine-based),
while in other
embodiments, it may be disposed in the wellbore. As shown, cable support
system 200 is
generally mounted along the exterior of casing string 60. In such embodiments,
cement
disposed in annulus 63 may encase at least a portion of cable support system
200. In some
embodiments, cable support system 200 may include two or more cable support
mechanisms
220 axially spaced apart along casing string 60. In one or more embodiments,
an EAT
package 210 is mounted on each cable support mechanism 220. Cable 250 is
secured along
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casing 60 by cable support mechanism 220 and may be disposed to extend between
adjacent
EAT packages 210.
[00031] Referring now to Figure 4, shown is a schematic view of the EAT
package 210.
Each EAT package 210 includes a transducer 213 configured to emit a wireless
signal 211.
Signal 211 is preferably an acoustic signal or a mechanical signal, i.e.,
vibrations. Each EAT
package 210 may further include a sensor 207 and controller 216 to adjust and
customize the
wireless signal, and a power source 215 to provide power to the various
components of EAT
package 210 as necessary. Although not limited to a particular type of
transducer so long as
an acoustic or mechanical signal is generated, in one or more embodiments,
transducer 213 is
piezoelectric transducer (PZT). Electrically coupled to transducer 213 is
sensor 207. As
such, electrical responses from sensor 207 may be converted to wireless signal
211 by
transducer 213. In this regard, sensor 207 is not limited to a particular type
of sensor. In
non-limiting examples, sensor 207 may be a temperature sensor, a pressure
sensor, geophone,
chemical sensor, optical sensor (such as an integrated computational element
sensor), load
cell, strain gauge, accelerometer, piezoelectric transducer, radiation sensor
or the like. In one
or more embodiments, transducer 213 also functions as sensor 207. Power source
215 may
be local, such as a battery, or external, such as an electrical cable. More
particularly, a
condition associated with the wellbore, such as temperature, pressure, object
orientation,
cement curing, may be measured by sensor 207 and converted by transducer 213
(and
conditioned by controller 216 as desired) into a wireless signal 211 that may
be transmitted as
described herein. For example, in some embodiments, transducer 213 may be any
electro-
acoustic transducer known in the art capable of either directly measuring a
characteristic of
the wellbore or receiving an electrical signal from a sensor 207, and
thereafter generating an
acoustic or mechanical signal; controller 216 can be utilized to condition the
signal to adjust
or customize the signal as necessary. In other words, EAT package 210 is
utilized to
propagate or emit a frequency modulation (FM) acoustic or amplitude modulation
(AM)
signal 211. In the present embodiment, each transducer 213 can be configured
(such as by
controller 216) to emit the same FM signal 211 or a different FM signal 211.
In other words,
each transducer 213 may be configured to emit a unique signal 211 that is
different from the
signal 211 emitted from each of the other transducers 213. Power source 215
serves as the
energy source for the components of the EAT package 210.
[000321 As will be appreciated below, EAT sensors are particularly useful in
fiber optic
sensing in which any number of downhole sensors, electronic or fiber optic
based, can be
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utilized to make basic parameter measurements, but all of the resulting
information is
converted at the measurement location into perturbations or a strain applied
to an optical fiber
cable that is connected to an interrogator that may be located at the surface
of a downhole
well. EAT sensors can be utilized in a number of different ways depending on
the parameter
to be determined by the measurement using the EAT sensor. The parameter can
include, but
is not limited to, a chemical concentration, a pH, a temperature, a vibration,
or a pressure.
The interrogator may routinely tire optical signal pulses downhole into the
optical fiber cable.
As the pulses travel down the optical fiber cable back scattered light is
generated and is
received by the interrogator. The perturbations or strains introduced to the
optical fiber cable
at the location of the various EAT sensors can alter the back propagation of
light and those
effected light propagations can then provide data with respect to the signal
that generated the
perturbations.
[000331 Each EAT package 210 may also include one or more orientation sensors
217,
such as accelerometers, geophones or other devices capable of detecting
orientation.
Orientation sensors 217 may also be powered by power source 215. In the
present
embodiment as shown in Figure 4, two orientation devices in the form of
accelerometers
217a, 217b are shown and oriented orthogonally or 90 degrees apart from each
other along X-
, and Y- axis for determining the gravitational field and the impact to the
different sensors,
and to measure seismic signals. In an alternative embodiment, three or more
accelerometers
217 may be used. For example, an accelerometer 217 may be oriented in each of
the X-, Y-
and Z- axis directions relative to one another. In one or more embodiments,
orientation
sensors 217 may be acoustic sensors oriented to detect an acoustic signal in a
select axial
direction. For example, orientation devices 217a, 217b may be seismic sensors,
each sensor
oriented to detect a seismic signal in a direction orthogonal to one another.
Similar to
transducer 213 and/or sensor 207 response data, accelerometer 217 data may be
transmitted
by transducer 213 in the form of a first wireless signal 211. In such case,
the signal from
transducer 213 and/or sensor 207 can be modulated by controller 216 to include
accelerometer 217 data. For example, an acoustic signal 211 emanating from
transducer 213
may be modulated to include location data from accelerometers 217.
[00031 Each
EAT package 210 may also include a locking device 219, such as a cross
coupling device, configured to maintain a fixed orientation of the EAT package
210
components relative to the casing string 60 while the casing 60 is run into
the wellbore 12.
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[00035] Referring now to Figures 5A and 5B, shown is a cable support mechanism
220
with an EAT package 210 (Figure 5B in exploded view). The cable support
mechanism 220
may be any clamping device known in the art for coupling to casing, pipes, or
tubing
including, but not limited to, clamps, couplings, and collars. In the present
embodiment,
cable support mechanism 220 is a mid-joint collar and comprises a first collar
section 221, a
second collar section231, and a connecting portion 240, which, when joined
together on a
casing section 61 as described below, form a circular collar about the casing
section. In this
regard, each of sections 221 and 231, as well as connecting portion 240 may be
arcuate in
shape so as to form a circle when joined together. Thus, collar sections 221
and 231 may be
semi-circular in shape. In any event, each collar section 221, 231 has an
upper end 222, 232,
respectively, opposite a lower end 223, 233, respectively, a first side 225,
235, respectively, a
second side 226, 236, respectively, an outer semi-cylindrical surface 228,
238, respectively,
and an inner semi-cylindrical surface 229, 239, respectively. The first side
225 and second
side 226 of the first collar section 221 each have protrusions 225a, 226a,
respectively; the
protrusions 225a, 226a are spaced apart and configured to accept a pin.
Similarly, the first
side 235 and second side 236 of the second collar section 231 each have
protrusions 235a,
236a, respectively; the protrusions 235a, 236a are spaced apart and configured
to accept a
pin. The connecting portion 240 has an upper end 242 opposite a lower end 243,
a first side
245, a second side 246, an outer surface 248, and an inner surface 249. The
connecting
portion first and second sides 245, 246, respectively, each have protrusions
245a, 246a,
respectively, spaced apart and configured to accept a pin.
[000361 The first side 225 of the first semi-circular collar section 221 is
coupled to the
second side 246 of the connecting portion 240 such that the protrusions 225a
of the first semi-
circular collar section 221 interlock and align with the protrusions 246a of
the connecting
portion second side 246. A locking pin 237 inserted through the aligned
protrusions 225a,
246a retains the first semi-circular collar section 221 to the connecting
portion 240. The
second side 236 of the second semi-circular collar section 231 is coupled to
the first side 245
of the connecting portion 240 such that the protrusions 236a of the second
semi-circular
collar section 231 interlock and align with the protrusions 245a of the
connecting portion first
side 245. A locking pin 227 inserted through the aligned protrusions 236a,
245a retains the
second semi-circular collar section 231 to the connecting portion 240.
Similarly, the second
side 226 of the first semi-circular collar section 221 is coupled to the first
side 235 of the
second semi-circular collar section 231 such that the protrusions 226a of the
first semi-
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circular collar section second side 226 interlock and align with the
protrusions 235a of the
second semi-circular collar section first side 235. A locking pin 247 inserted
through the
aligned protrusions 226a, 235a retains the first semi-circular collar section
221 to the second
semi-circular collar section 231.
[000371 While EAT package 210 is shown secured to connecting portion 240, it
will be
appreciated that in other embodiments, cable support mechanism 220 may
comprise just two
collar sections 221 and 231, which, when jointed together, form a clamp around
casing
section 61. In such case, EAT package 210 may be carried on one of the collar
sections, and
that collar section may be configured as described herein, to secure a sensing
cable 250 to
casing string 60.
[00038] Also illustrated in Figure 5B is perforating tool 290. Perforating
tool 290 is
oriented so that charges 291 generally point away from cable 250.
Specifically, as shown,
charges 291 are positioned so that the discharge or blast pattern 293 of
perforating tool 290 is
oriented away from cable 250.
[00039] Referring again to Figures 1-3, sensing cable 250 extends from the
surface 16
(Figure 1) or platform 44 (Figure 2) downhole through the wellhead 40 to the
completion.
Sensing cable 250 extends through the portion of the wellbore 12 to be
perforated and may
extend to the lower end of the tubing string 60. Cable 250 may be one of the
communication
cables 100, 116 or may be an additional or alternate cable. In one or more
embodiments,
sensing cable 250 is a fiber optic cable, while in one or more other
embodiments, sensing
cable 250 is an electrical cable. As will be described herein, sensing cable
250 is utilized to
"sense" a first signal propagated from. EAT package 210 and transmit a second
signal based
on the sensed first signal. In the case where cable 250 is an electrical
cable, as illustrated in
Figure 3B, the electrical cable includes sensors 218, such as receivers,
capable of detecting
electromagnetic signals propagated or emitted by an EAT package 210. The
optical fiber
cable may be any suitable optical fiber cable known in the art; the electrical
cable may be any
suitable tube encapsulated conductor (TEC) or other electrical cable known in
the art. The
one or more optical fiber cables 250 also may be used to monitor various
devices and
operations including, but not limited to, EAT packages 210, cement curing,
perforating,
fracturing, injection, fluid inflow, production, and well integrity.
[00040] Referring still to Figures 1 and 2, a control system 270 may be
deployed to
communicate with sensing cable 250 and function as a source for a signal 209a
as described
below. In one or more embodiments, control system 270 is disposed at surface
16 or
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platform 44 at a control station 48 and is in communication with cable 250.
Where cable 250
is a fiber optic cable, control system 270 may include an interrogator unit
(not shown)
configured to send optic pulses down the fiber optical cable 250, and process
and analyze the
resulting return signals. In one or more embodiments, the control system 270
may comprise
any distributed acoustic sensing (DAS) system or time-domain interferometry
(TM) system
known in the art, although other sensing systems capable of sending pulses and
processing
and analyzing the resulting signals (optic or otherwise) may be used. In the
present
embodiment, control system 270 is a DAS system. In other embodiments such as
illustrated
in Figure 3b, cable 250 is an electrical cable and control system 270 may
transmit and receive
electrical signals along cable 250. It will be appreciated that in such
embodiments, sensors
will be distributed along electrical cable 250 which sensors 218 are capable
of receiving a
propagated signal from EAT package 210 as described herein and transmitting an
electrical
signal to control system 270 based on the received signal from the EAT package
210.
[000411 Referring now to Figures 3 and 5B and 5C, in one or more embodiments,
each
EAT package 210 is coupled or attached either directly or indirectly to casing
string 60
adjacent cable 250 extending axially along casing string 60. The EAT packages
210 are
spaced axially apart along casing string 60. In some embodiments, the cable
250 and EAT
packages 210 of system 200 are preferably deployed on the exterior of casing
string 60 in
annulus 63 between the casing string 60 and the wellbore 12. In one or more
embodiments,
each EAT package 210 is coupled or attached either directly to casing string
60, while in
other embodiments each EAT package 210 is coupled to a mid-joint collar 220,
which is
installed on casing section 61 to secure cable 250 thereto before the casing
section 61 is run
in hole to form the casing string 60. In particular, the cable 250 is secured
to the outer
diameter of casing section 61 by the mid-joint collar 220 such that cable 250
is substantially
axially aligned with the longitudinal axis of casing string 60. In this
regard, mid-joint collar
220 may include a groove, channel or similar guide 220a through which cable
250 may be
run. Guide 220a may be formed or otherwise provide on any part of the mid-
joint collar 220
so long as it is adjacent the corresponding EAT package 210. In some
embodiments, cable
250 is disposed between the inner surface 249 of the collar connecting portion
240 and the
casing section 61. The connecting portion 240 of the mid-joint collar 220 is
configured in the
form of guide 220a to provide a space or groove to accommodate the cable 250
when the
collar 220 is clamped around section 61. In particular, each mid-joint collar
220, positioned
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at approximately the middle of every casing section 61, is generally about
thirty to forty feet
away from the next adjacent collar 220 carried on the next adjacent casing
section 61.
[00042] To further protect the cable 250, Stand-offs or centralizers (not
shown) may be
used to keep the casing string 60 in the middle of the wellbore 12 and ensure
the cable 250
does not get crushed against the formation. Likewise, in addition to the
collars 220 as
described herein to secure cable 250 at points along casing string 60, cable
250 may also be
attached directly to casing collars 62 with an epoxy, clamp, or other
mechanical fastener.
Coupling the cable 250 to the casing section 61 or casing collars 62 allows
the location and
orientation of the cable 250 to be known in relation to the casing section 61
or casing collars
62.
[00043] EAT packages 210 are positioned on mid-joint collar 220 so as to be
proximate
the cable 250 and to propagate a signal in the direction of the cable 250. EAT
packages may
be carried on each collar 220 or may be spaced apart at certain increments;
for example, the
EAT packages 210 may be placed on every fifth or every tenth mid-joint collar
220. In the
present embodiment, EAT packages 210 are spaced apart approximately every
tenth to
fifteenth mid-joint collar 220 such that each EAT package 210 is approximately
300-500 feet
away from the next subsequent or previous EAT package 210. In other
embodiments, EAT
packages 210 may be spaced closer together or farther apart. In other
embodiments, the EAT
packages 210 may be secured to different portions of the casing string 60
including, but not
limited to, clamps or casing collars 62 or adhered directly on a casing
section 61 or integrally
formed as part of a casing section 61.
[00044] Referring again to Figure 5B, the EA.T package 210 is mounted to mid-
joint collar
220 by any attachment mechanism known in the art including, but not limited
to: an
adhesive, weld, clamp or other mechanical fastener. In an alternative
embodiment, the EAT
package 210 may be attached to cable 250 and casing 60 with a similar
mechanical fastener.
In a preferred embodiment, the EAT package 210 is disposed on the outer
surface of the
casing collar 62 proximate the cable 250 to be protected during the
perforating process. The
EAT package 210 may be attached to any surface of the mid-joint collar 220,
including but
not limited to outer semi-circular surface 228, 238 on the first or second
collar section,
respectively, or a surface 248, 249 of the connecting portion 240. In the
present embodiment,
EAT package 210 is disposed on outer surface 248 of connecting portion 240 at
location
210a; however, in other embodiments, the EAT package 210 may be disposed on
outer semi-
cylindrical surface 228 proximate first side 225 of first semi-cylindrical
collar section 221, or
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on outer semi-cylindrical surface 238 proximate second side 236 of second semi-
cylindrical
collar section 231. In further embodiments, the EAT package 210 may instead be
attached to
a centralizer (not shown), which is then coupled to the casing section 61
proximate the cable
250. Coupling the EAT package 210 to the mid-joint collar 220 or casing
section 61 allows
the location and orientation of the EAT package 210 components (transducer
213,
accelerometers 217a, 217b) to be known in relation to the collar 220 or
section 61, and
further allows the location and orientation of the EAT package 210 components
to be known
in relation to the cable 250. Further, by having multiple EAT packages 210
disposed along
the length of the sensing cable 250, the orientation of the cable 250 can be
determined at any
point along the casing string 60.
[00045] Further, in a preferred embodiment and regardless of the portion of
the casing
string 60 on which the EAT package 210 and cable 250 are attached, the EAT
package 210 is
adjacent or in proximity to the sensing cable 250 to minimize attenuation of
any wireless
signals 211 from the EAT package 210 transmitted in the direction of the
sensing cable 250.
In addition, the locking device 219 configured to maintain the position and
orientation of the
EA.T package 210 components relative to the mid-joint collar 220, and
consequently to the
casing section 61, while the casing string 60 is run into the wellbore 12.
Further, the mid join
collar 220 maintains the position and orientation of the sensing cable 250 as
the casing string
60 is run in.
[00046] Figure 6 illustrates a plurality of EAT packages 210 distributed in an
axial spaced
apart orientation in a wellbore 12. As shown, cable 250 extends along the
wellbore extending
from control system 270. Cable 250 is positioned to be adjacent on EAT package
210 as
described above. In operation, various data is converted by EAT package 210
into a wireless
signal 211. In one or more embodiments, the wireless signal 211 may be an
acoustic signal
transmitting data. The data may include data from sensors 213 and/or
accelerometers 217.
The wireless signal 211 is transmitted in the direction of cable 250. In one
or more
embodiments, a wired signal 209a is transmitted down wellbore 12 by control
system 270.
For example, wired signal 209a may be an optic signal. As the downgoing wired
signal 209a
encounters the wireless signal 211, wired signal 209a (or a portion thereof)
is altered (such as
altering the backscattering and/or reflected optic signal) and directed back
uphole as return
wired signal 209b. Utilizing the return wired signal 209b, control system 270
can determine
the axial location and radial orientation of EAT package cable 250, then the
radial orientation
of cable 250 at that axial location can be determined.
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[00047] In an exemplary embodiment and as illustrated in Figure 7, with
continuing
reference to Figures 1-6, a method 300 of ascertaining the location of cable
250 in a wellbore
12 is described. The method 300 may be utilized for any operation where
knowledge of the
radial position of cable 250 at a particular axial depth is required, but
method 300 is
particularly useful for perforating operations in order to ensure that cable
250 is not damaged
during discharge of a perforating gun.
[00048] In any event, in a first step 302, the casing string 60 with the EAT
packages 210
and sensing cable 250 is installed in wellbore 12. The EAT packages 210 may be
attached
directly to a casing section 61 that makes up casing string 60, or may be
secured to casing
section 61 utilizing a mechanical device, such as cable support mechanisms
220. In any case,
the EAT packages 210 are positioned adjacent to cable 250 extending axially
along a casing
section 61. To the extent a cable support mechanism 220 is utilized, the cable
support
mechanism 220 may be utilized to clamp or otherwise secure cable 250 to casing
section 61
while also supporting EAT package 210 so that it is positioned adjacent cable
250, The EAT
packages 210 include a transducer 213 and may contain one or more
accelerometers 217. In
one or more embodiments, EAT packages 210 and cable 250 are deployed along the
exterior
of a casing string 60, which casing string 60 is cemented in place within
wellbore 12.
[00049] In step 304, a wireless signal 211 is generated from one or more EAT
packages
210 and transmitted towards cable 250. Because of the proximity of the EAT
packages 210
to cable 250, the transmission need not be focused, but may be omni-
directional. The
wireless signal 211 may include transducer 213 and/or sensor 207 response data
as well as
accelerometer 217 data. The transducer 213 and/or sensor 207 response data may
reflect a
particular condition of the well bore 12, such as pressure, temperature, etc.
The accelerometer
217 data reflects a location in wellbore 12. In one or more embodiments, the
wireless signal
211 is an acoustic signal generated from transducer 213, while in other
embodiments, the
wireless signal 211 is a mechanical signal, such as vibrations, generated from
transducer 213.
In one or more embodiments, the wireless signal 211 from transducer 213 may be
altered or
conditioned by controller 216 to include location data from accelerometers
217.
[00050] In step 306, the transmitted wireless signal 211 is utilized to
generate a separate
wired signal, such as signal 209b, in cable 250. In one or more embodiments,
this separate
wired signal may be generated locally, such as by a sensor 218. In one or more
embodiments, this separate wired signal may be a signal transmitted down cable
250 that is
altered locally upon encountering the wireless signal 211. For example, with
respect to the
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latter, the backscattering of the separate wired signal 209a transmitted
downhole along cable
250 may be locally altered by the presence of a signal such as signal 211
transmitted from
adjacent transducer 213. More particularly, in embodiments utilizing a sensor
210, the sensor
210 may sense the wireless signal 211 and generate a signal 209b on cable 250
that is
transmitted back to control system 270. In embodiments utilizing a signal
originating from
control system 270, the signal may be an optic signal transmitted down cable
250; while the
return signal may be altered backscatter or reflected optic signal 209b, the
return signal 209b
being altered when the wireless acoustic signal 211 impinges upon cable 250.
With regard to
signal 209b, persons of skill in the art will appreciated that in a typical
distributed acoustic
sensing (DAS) system, normal scattering or reflection of a signal occurs at
sites along the
length of the optic fiber and changes in the distance between the scattering
or reflection sites
in the optical fiber are measured to make a particular determination. In the
system of the
disclosure, the normal scattered or reflected signal is altered by the signal
211 from the
transducer 213 because the signal 211 (in the form of acoustic energy or
mechanical
vibrations) causes small strain and vibration on the optic fiber at the
scattering or reflection
sites. The wireless signal 211 from the transducer 213 modulates vibrations
onto the fiber
and cause changes in the optical path for the back scattered or reflected
light, and this
changes the intensity and/or phase of the optical signal. This is then decoded
at the surface.
[00051] In step 308, wired return signal 209b may be utilized to determine the
axial
location and radial position of the transducer 213 that generated the wireless
signal 211.
Since the transducer 213 is co-located with or positioned adjacent cable 250,
this location and
position data of transducer 213, in turn, permits the radial position of cable
250 disposed
along casing section 61 to be determined.
[00052] In step 310, an operation in wellbore 12 can be carried out based on
the
determined radial position of the cable. Since the radial position of the
cable has been
determined, such an operation may be carried out so at to ensure that damage
to cable 250 is
minimized. In this regard, a tool may be oriented (either at the surface or
once axially
positioned) so as not to damage the cable during the operation. Likewise, a
tool that is
axially positioned may have its orientation altered to ensure the cable is not
damaged during
the operation. The disclosure is not limited to a particular operation, but
has been found to be
most useful in operations that require the casing string 60 to be breached,
such as by cutting,
perforating, milling, severing or the like. Thus, in some embodiments, the
operation may be
perforating operations, while in other embodiments the operation may be
milling operations.
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As will be appreciated, where the casing is breached, it is desirable to carry
out such
operations so as not to damage cable 250. Thus, the location of the breach may
be adjusted to
ensure that cable 250 is not damaged. For example, a perforating tool may be
operated so
that the charges discharge in a direction away from cable 250. Likewise, the
position of a
window in milling operations may be selected so as to be spaced apart from
cable 250 about
the radius of casing string 60.
[00053] Steps 302-310 are reflected in the following procedure cementing and
perforation
procedure. During deployment, initial EAT sensor responses, i.e., first
wireless signals
generated from EAT package 210, can be monitored, such as by propagating a
second,
different signal 209a along cable 250 utilizing control system 270 and
monitoring the effect
of the first wireless signal on the second wired signal 209a. Cement may be
pumped down
the inside of casing string 60 and pushed down by a wiper plug into the
annulus 63 to cement
the casing string 60 and cable 250 in place. EAT sensor responses may also be
monitored as
the cement is pumped down the casing string 60 and up the annulus 63 and, and
additionally
or alternatively, while the cement is curing. In particular, the control
system 270 can monitor
the cement while being pumped down the casing 60 by detecting the impact on
the second,
wired signal 209a transmitted along cable 250 by control system 270 of the
first wireless
signal from EAT package 210 resulting from the vibration and noise of the
cement on the
EAT package 210. In one or more embodiments, the second wired signal is an
optic signal
and the first wireless signal disrupts the second signal. Such disruption may
alter the
backscattered optical signal or have a similar impact on the second signal
209a, thus altering
the second signal and resulting in modulation of the wired return signal 209b.
EAT package
210 responses may be monitored in this way prior to, during, and after pumping
the cement
down the casing string 60. The control system 270 receives the disrupted or
backscattered
second signal 209b and interprets it to determine the gravitational field of
each EAT package
210, from which the location and orientation can be determined. Once the
cement has set, a
perforating operations may be initiated and EAT packages 210 responses can
continue to be
monitored before, during, and after the perforating operations.
[00054] More specifically, data from the second signal 209b transmitted to
control system
270 along cable 250 based on the first signal's impact on the second signal's
209a
backscattered or reflected light is utilized by control system 270 to
determine the
gravitational field and, subsequently, the position and orientation of each
EAT package 210.
Because of the proximity of the co-located cable 250 to the EAT packages 210,
the location,
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i.e., the axial depth and radial position, of the cable 250 in wellbore 12 can
be determined.
As a service tool, such as perforating tool 250, is lowered into the well, the
service tool can
then be axially positioned and radially oriented relative to the location of
cable 250. For
example, the axial position and radial orientation of the perforating tool 290
can be tracked
and correlated with the location of the EAT packages 210 to ensure that
discharge of the
perforating tool 290 is in a direction that will minimize the likelihood of
damage to cable
250. Referring again to Figure 3, in one or more embodiments where a
perforating tool 290
is deployed, an additional transducer 214 may be coupled to the perforating
tool 290 in a
similar manner as the transducer 213 are coupled to the mid-joint collars 220.
Transducer
214 may be an electro-acoustic transducer as well. As previously described,
the transducers
213, 214 may be configured to emit unique wireless signals or the same
wireless signal; the
wireless signals disrupt or trigger the wired signal in sensing cable 250,
which disruption or
triggered signal is transmitted back to the control system 270 (Figure 1 and
2). Persons of
skill in the art will appreciate that the use of unique signals (as opposed to
the same
frequency signal) would allow the depth of each EAT package 210 to determined
without the
need to count collars 62. In addition to the signal from transducer 213,
electrical signals from
the accelerometers 217 are converted to an acoustic signal and the acoustic
signal may also
be transmitted as a wireless signal towards the sensing cable 250. Signal
polarity combined
with gravity-induced sensor signals (e.g., from accelerometers 217) allows
positive
orientation identification.
[00055] Referring still to Figure 3, the control system 270 interprets data
from the return
second, wired signal resulting from the first wireless signal(s) arising from
transducer 213,
214 and accelerometers 217 in order to identify and determine the
gravitational field and,
subsequently, the orientation of EAT packages 210 and, thus, the positioning
of cable 250 in
the annulus 63. To perforate the casing string 60, a perforating tool 290
connected along a
tool string is lowered into the vvellbore 12 by a conveyance vehicle such as a
wireline 30.
During run in, active pinging of the transducer 214 disposed on the
perforating tool 290
provides an indication of the perforating tool's 290 location as it travels
down the casing
string 60. Utilizing the position of the transducers 213 outside the casing
string 60 and the
transducer 214 on the perforating tool 290 in real-time as the perforating
tool is run in, the
operator can make adjustments to change in the orientation of the perforating
tool 290 to
ensure tool 290 during deployment is oriented away from the cable 250 as tool
290 is run in,
i.e., the charges of tool 290 are positioned so that an accidental discharge
during deployment
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will not damage cable 250. Once tool 290 has been lowered to the desired axial
depth, after
any necessary adjustments are made to ensure the perforating tool 290 is
oriented so as to
have a blast patter direction away from cable 250, the perforating tool 290 is
activated and
the casing 60 is perforated. The real-time orientation information also allows
the operator to
maneuver subsequent guns in the tool string to remain correctly oriented away
from cable
250.
[00056] In some embodiments, perforating tool 290 may be tracked in the
wellbore 12
utilizing the control system 270 and cable 250 based on the acoustic signal
the perforating
tool 290 generates as it is moved down the casing 60. In some embodiments,
perforating
charges 291 (see Figure 5b) from the perforating tool 290 may be used as a
seismic source,
and the accelerometers 217 may be used to sense seismic signals returning from
the
formation 14. In particular, the transducer 213 and accelerometers 217 can
detect the
orientation of the perforations when the perforating tool 290 discharges into
the formation 14,
which results in seismic vibrations that the transducer 213 and accelerometers
217 can detect
and then convey to the control system 270 utilizing the first wireless and
second wired
signals as described above. This information may be used for seismic imaging
both in-well
and cross-well, if multiple wells are instrumented.
[00057] it should be noted that if the mid-joint collar 220 were installed
on the casing
section 61 upside down and then run into the wellbore 12, the location of the
cable 250 may
be incorrectly interpreted, which could result in damage to the cable during a
perforating
operation. For example, if one transducer 213 is orthogonally disposed at +90
degrees
relative to the axis of the cable 250, another transducer 213 is orthogonally
disposed at -90
degrees relative to the axis of the cable 250, and the mid-joint collar 220 is
installed on casing
section 61 upside down or backwards, then the identification of the cable
location would be
off by 180 degrees. To minimize the likelihood of such errors, mid-joint
collar 220 may
include a mechanical feature 247, such as a tab, shoulder, extension,
aperture, slot or similar
mechanism that engages the mid-joint collar 220 in such a way that requires
the collar to be
oriented upright. In one or more embodiments, mechanical feature 247 is a
locking pin 247
used to retain the first semi-circular collar section 221 to the second semi-
circular collar
section 231 and may be configured to only fit in aligned protrusions 226a,
235a from the
upper end 222, 232, see Figure 5B. An orientation-specific locking pin would
impede any
mid-joint collars 220 from being installed upside down and, consequently,
minimize the
likelihood of inaccurate data regarding the cable's 250 location.
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[000581 In another embodiment, transducer 213 may be utilized to determine
whether the
mid-joint collar 220, and thus the transducer 213, is installed upside down.
In particular, the
transducer 213 can be utilized to discern its own orientation relative to the
suiface 16 (i.e., the
transducer 213 can be configured to measure which way is up), and can either
store that
information or emit a signal indicating the transducer 213 is installed upside
down. Having
the additional information of each transducer's 213 orientation when
processing and
interpreting data from the transducer 213 and accelerometers 217 would allow
corrections to
be made, as necessary, and minimize inaccurate orientation determinations.
[00059] In embodiments, the transducer 213 can be turned off and on, to
conserve power
source 219. This also has the effect of reducing noise. For example, the
transducer 213 may
be configured to allow communication with a downhole tool, which instructs the
transducer
213 to power down or to a lower power state (i.e., the transducer 213 can
remain "on" but
cease transmitting an acoustic frequency). Alternatively, the transducer 213
may be
programmed to operate for a predetermined period of time (i.e., one week) and
then go
dormant for a certain period of time before it cycles back on with the
transducer 213 moving
between power states for set intervals until the power source 219 expires.
Thus, a first power
state may be "on" while a second power state may be "off'. Or alternatively, a
first power
state may be full power, while a second power state may be dormant or minimal
power. In a
further alternative, the transducer 213 may switch from one power state to
another after the
perforating tool 290 has been fired.
[00060] While the use of the EAT packages 210 to ascertain positioning and
orientation of
cable 250 has been specifically described for use in perforating operations,
it will be
appreciated that the foregoing method may be used to ascertain the positioning
and
orientation of cable 250 for any downhole operations, and as such, is not
limited to
perforating operations. Thus, in some embodiments, tool 290 can be any
downhole tool, and
is not limited to a perforating tool.
[00061] Thus, a cable support mechanism for coupling a cable to a casing
section of a
downhole casing string has been described. Embodiments of the cable support
mechanism
may generally include a first collar section; a second collar section coupled
to the first collar
section; a connecting portion coupled to the first and second halves; and a
transducer coupled
to one of the first collar section, the second collar section, and the
connecting portion. Other
embodiments of a cable support mechanism may generally include a first collar
section; a
second collar section coupled to the first collar section; a transducer
coupled to one of the
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collar sections; a set of the orientation devices coupled to one of the collar
sections adjacent
the transducer, wherein the set comprises a first orientation device and a
second orientation
device orthogonally oriented with respect to one another. Still yet other
embodiments of the
cable support mechanism may generally include a first collar section; a second
collar section
coupled to the first collar section; and a transducer coupled to one of the
first collar section or
second collar sections. Likewise, a system for perforating a casing string in
a wellbore in a
direction away from a cable deployed along the casing string has been
described.
Embodiments of the perforating system may generally include an elongated
casing string; a
first cable deployed along the casing string; a plurality of spaced apart
transducers, each
transducer coupled to the casing string adjacent the first cable; a plurality
of orientation
devices disposed proximate the plurality of transducers; and a control system
in
communication with the first cable.
[00062] For any of the foregoing embodiments, a cable support mechanism may
include any one of the following elements, alone or in combination with each
other:
At least one orientation device disposed adjacent the transducer.
The control system comprises a signal source coupled to the first cable.
At least one sensor electrically coupled to the transducer.
The transducer is an electro-acoustic transducer.
The transducer is a piezoelectric transducer.
The transducer is selected from the group consisting of an acoustic transducer
and a
mechanical transducer.
A fiber optic cable disposed adjacent the transducer; and a control system in
optical
communication with the fiber optic cable.
The cable support mechanism engages the fiber optic cable, wherein the
transducer
and the orientation device are disposed on the cable support mechanism in a
select
position and orientation proximate the fiber optic cable.
A first orientation device and a second orientation device, each orientation
device
adjacent the transducer and each orientation device oriented to measure in a
direction
orthogonal to one another.
The transducer includes an electromagnetic signal transmitter.
A power source in electrical communication with the transducer.
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A locking device securing the transducer and the at least one orientation
device to the
cable support mechanism in a fixed position and orientation relative to each
other.
A clamping device that couples the first cable and fiber optic cable to the
casing
string.
A second cable adjacent the first cable, wherein the first cable is a fiber
optic cable
and the control system is in optical communication with the fiber optic cable.
A plurality of clamping devices, wherein each clamping device comprises a
first
collar section and a second collar section secured to one another so as to
extend
completely around the casing string, each clamping device carrying one of the
transducers and a set of the orientation devices, wherein the set comprises a
first
orientation device and a second orientation device orthogonally oriented with
respect
to one another.
The clamping device further comprises a connecting portion, the connecting
portion
forming a guide along which the first and second cables run, wherein the
transducer
and set of orientation devices for the clamping device are carried on the
connecting
portion adjacent the cable.
The first cable is an electrical cable, the system further comprising a
plurality of
sensing devices, each sensing device configured to detect a signal emitted by
an
transducer and each orientation device adjacent the transducer.
A connecting portion attached to each of the first and second collar sections
so as to
form a clamping device, the connecting portion forming an axial cable guide
for
receipt of a cable, wherein the transducer and set of orientation devices are
carried on
the connecting portion adjacent the cable guide.
The orientation device is selected from the group consisting of accelerometers
and
seismic sensors.
A cable guide adjacent the transducer.
[000631 Thus, a method for detecting the orientation of a cable in a
wellbore has been
described. Embodiments of the method include coupling at least one transducer
and one
orientation device to a casing section; coupling a cable to the casing section
proximate the at
least one transducer and the at least one orientation device; deploying the
casing section in a
wellbore; transmitting a first signal from the at least one transducer towards
the cable;
propagating a second signal down the cable; altering the second signal based
on the first
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signal; and utilizing the altered signal to determine the orientation of the
cable in the wellbore
at the casing section. Other embodiments of the method include deploying a
plurality of
transducers in a wellbore, the transducers axially spaced apart from one
another along a
portion of the wellbore; utilizing a transducer to measure a condition of the
wellbore and
transmit an acoustic signal in the direction of an optic cable; propagating an
optic signal
along the optic cable; and identifying the location of the transducer in a
wellbore based on the
backscattetin.g of the propagating optic signal by the acoustic signal. Still
yet other
embodiments of the method may include propagating an optic signal along an
optic cable;
utilizing a transducer to generate an acoustic signal at an axial location in
the wellbore;
altering the optic signal with the acoustic signal at the axial location in
the wellbore; and
utilizing the altered signal to determine the axial location of the
transducer. Likewise,
embodiments of the method may include deploying a plurality of transducers in
a wellbore,
the transducers axially spaced apart from one another along a portion of the
length of a
wellbore; utilizing a transducer to measure a condition of the wellbore and
transmit a wireless
signal in the direction of a cable deployed adjacent the transducer;
influencing a wired signal
transmitted in the cable based on the wireless signal; and identifying the
location of the
transducer in a wellbore based on the influenced signal. Other embodiments of
the method
may include deploying a plurality of transducers in a wellbore, the
transducers axially spaced
apart from one another adjacent a cable extending along a length of the
wellbore; transmitting
a first signal from at least one transducer towards the cable; propagating a
second signal
down the cable; altering the second signal based on the first signal; and
utilizing the altered
signal to determine the orientation of the cable in the wellbore at the casing
section.
1000641 For the foregoing embodiments, the method may include any one of
the
following steps, alone or in combination with each other:
Sensing a condition of a wellbore and transmitting an electrical signal to a
transducer
based on the sensed condition.
Fixing the position and orientation of the at least one transducer and
orientation
device and cable to the casing section with a locking device.
The second signal is an optical signal and the first signal is an acoustic or
mechanical
signal.
The second signal is an electrical signal and the first signal is an acoustic
or
mechanical signal and the electrical signal is altered by a sensor adjacent
the
transducer.
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Orienting a perforating tool in the wellbore in based on the determined
orientation of
the cable; and discharging the perforating tool in a direction away from the
cable.
Connecting portion attached to each of the first and second collar sections so
as to
form a clamping device, the connecting portion forming an axial cable guide
for
receipt of a cable, wherein the transducer and set of orientation devices are
carried on
the connecting portion adjacent the cable guide.
Deploying comprises positioning each transducer adjacent a first cable;
identifying
the position of the first cable in the wellbore at a given point based on the
location of
the transducer; and discharging a perforating tool based on the identified
position of
the first cable.
Modulating the acoustic signal to include radial location data.
Altering comprises changing the backscattered optic signal.
Influencing comprises changing the backscattered optic signal transmitted in
the cable
based on an acoustic signal transmitted from the transducer.
The orientation device is selected from the group consisting of accelerometers
and
seismic sensors.
Utilizing the discharging from the perforating tool as a seismic source;
propagating a
seismic single into the formation; and detecting a reflected seismic signal
with the at
least one transducer, wherein the at least one transducer is an electro-
acoustic
transducer.
Propagating a seismic signal in a formation and utilizing the transducer to
detect the
seismic signal.
Propagating a seismic signal in a formation and utilizing the transducer to
detect the
seismic signal.
Generating the seismic signal from outside the wellbore.
Generating the seismic signal from within the wellbore.
Generating the seismic single from within the wet (bore by firing a
perforating tool.
[00065] Although various embodiments and methods have been shown and
described, the
disclosure is not limited to such embodiments and methods and will be
understood to include
all modifications and variations as would be apparent to one skilled in the
art. Therefore, it
should be understood that the disclosure is not intended to be limited to the
particular forms
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CA 02998330 2018-03-09
WO 2017/105434 PCT/US2015/066079
disclosed; rather, the intention is to cover all modifications, equivalents,
and alternatives
falling within the spirit and scope of the disclosure as defined by the
appended claims.
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