Note: Descriptions are shown in the official language in which they were submitted.
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APPARATUS AND MEHTOD FOR COMMUNICATION DATA BETWEEN WELL
AND THE SURFACE USING PRESSURE PULSES
B.ACKGROUND OF THE DISCLOSURE
1. Field of tbe 1)isctosure
(00011 This disclosure relates to apparatus and methods for communicati.ng
data between
a well and the surface.
2. Bac ronnd Information
[0002] Wells (also referred to as "wellbores" or "boreholes") are drilled and
completed to
produce hydrocarbons: (oil and gas) from one or more production zones
penetrated by a
wellbore. A typical completed well may include a metallic casing that lines
the well.
Cement is generally placed between the casing and the well to provide a seal
between the
formation surrounding the well and the casing. Perforations made in the
formation
through the casing at selected locations across from the producing formations
(also
referred to as the "production zones" or "reservoirs") allow the formation
fluid
containing the hydrocarbons to flow into the cased well. The formation fluid
flows to the
surface via a production tubing placed inside the casing because the pressure
in the
production zone is generally higher than the pressure caused by the weight of
the fluid
column in the well. An artificial lift mechanism, such as an electrical
submersible pump
("ESP") or a gas-lift mechanism is often employed when the formation pressure
is not
adequate to push the fliaid in the well to the surface.
[0003] A variety of dev:ices are used in the well to control the flow of the
fluid from the
production zones to optimize the oil and gas production over the life of the
well.
Remotely-controlled flow control valves and chokes are often used to control
the flow of
the fluid. Chemicals are injected at certain locations in the well via one or
more tubes
that run from the surface to the production zones to inhibit the forrnation of
harmful
chemicals, such as corrosion, hydrate, scale, hydrogen sulfide, methane,
asphaltene, etc.
A number of sensors are typically placed in the well to provide information
about a
variety of downhole parameters, including the position of the valves and
chokes,
pressure, temperature, fluid flow rate, acoustic signals responsive to water
front and
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surface or downhole induced signals in the subsurface formations, resistivity,
porosity,
permeability, water-cut, etc. The measurement data is typically transmitted to
the surface
via conductors, such as electrical wires, that run from the surface to
selected locations in
the well. Signals are also sent from the surface to the downhole sensors and
devices via
such conductors to control their operations. Such conductors can degrade over
time or
become non-functional. It is therefore desirable to have a data communication
system
that may be less prone to degradation.
[0004] The present disclosure provides improved apparatus, systems and methods
for
communicating data between a well and the surface.
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SUMMARY
[0005] In one aspect, a method is disclosed that includes: placing a conduit
containing
non-circulating liquid therein in a well; and generating pressure pulses
through the liquid
in the tubing to transnait information between a location in the well and the
surface. The
system may further include one or more repeaters that detect pressure pulses
in the
conduit and transmit pressure pulses through the liquid in the conduit that
correspond to
the detected pressure pulses.
{0005] In another aspect, a well data communication system is disclosed that
includes: a
conduit which extends, from a downhole location to an uphole location and a
transducer
that is configured to send information through the liquid medium in the form
of pressure
pulses. A detector spaced from the transducer detects the pulses in the
conduit.
{0006] In another aspect, an apparatus is disclosed for use in a well that
includes: a
conduit that has a liquid medium therein, which conduit is configured to be
deployed in
the well; and a transducer that is configured to generate pressure pulses
through the liquid
medium in the conduit to transmit data signals.
[0007] Examples of ttie more important features of a well data communication
system
and methods have been summarized rather broadly in order that the detailed
description
thereof that follows may be better understood, and in order that the
contributions to the
art may be appreciated. There are, of course, additional features that will be
described
hereinafter and which vvill form the subject of the claims. The summary is
provided to
provide the reader with broad information and is not intended to be used in
any way to
limit the scope of the claims.
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BItIEF DESCRIPTION OF THE DRAWINGS
[0008] For a detailed understanding of the apparatus, systems and methods for
communicating infonnation between a well and the surface, reference should be
made to
the following detailed description, taken in conjunction with the accompanying
drawings,
in which like elements generally have been given Iike numerals, wherein:
FIG IA shows a schematic diagram of an exemplary well configured to provide
data communication between devices in the well and a surface controller
according to
one embodiment of the disclosure;
FIG, 1B shows a schematic diagram of certain controllers and devices at the
surface that may be utilized to establish data communication between the well
and the
surface;and
FIG, 2 shows a functional block diagram of a transducer that may be utilized
to
generate pressure pulses in a well system to establish data communication
between a well
and the surface, such as shown in FIGS.1 and 2.
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DETAILED DESCRIPTION
(0009) FIGS.IA and 1B (collectively referred to herein as "FIG 1")
collectively show
schematic diagrams of an exemplary embodiment of a well system 100 that
includes a
data communication system between a completed well 50 and the surface 112
according
to one embodiment of the disclosure. FIG 1A shows the schematic diagram of the
equipment of the well system 100 that is below the surface 112, while FIG IB
shows the
functional block diagram of exemplary equipment of the well system 100 that
may be
deployed at the surface 112 to manage the operations of the system 100. The
system 100
shows the wel150 formed in a formation 55 that produces formation fluids 56a
and 56b
(such as hydrocarbons) from two exemplary production zones 52a (upper
production
zone) and 52b (lower production zone) respectively. The wel150 is shown lined
with a
casing 57 containing perforations 54a, adjacent the upper production zone 52a
and
perforations 54b adjacent the lower production zone 52b. A packer 64, which
may be a
retrievable packer, positioned above or uphole of the lower production zone
perforations
54a isolates the lower production zone 52b from the upper production zone 52a.
A
screen 59b adjacent to ihe perforations 54b may be installed to prevent or
inhibit solids,
such as sand, from entering into the wellbore from the lower production zone
54b.
Similarly, a screen 59a may be used adjacent the upper production zone
perforations 59a
to prevent or inhibit solids from entering into the well 50 from the upper
production zone
52a.
(00010] Formation fluid 56b from the lower production zone 52b enters the
annulus
51a of the we1150 through the perforations 54a and into a tubing 53 via a flow
control
valve 67. The flow contrrol valve 67 may be a remotely controlled sliding
sleeve valve or
any other suitable valve or choke that is configured to regulate the flow of
the fluid from
the annulus 51a into the production tubing 53. An adjustable choke 40 in the
tubing 53
may be used to regulate the fluid flow from the lower production zone 52b to
the surface
112. The formation fluid 56a from the upper production zone 52a enters the
annulus 51 b
(the annulus portion above the packer 64) via perforations 54a. The formation
fluid 56a
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enters production tubing or line 45 via inlets 42. An adjustable valve or
choke 44
regulates the fluid flow into the tubing 45. Each valve, choke and other such
device in
the well may be operated electrically, hydraulically, mechanically and/or
pneumatically
by a surface control unit, such as controller 150 and/or by a downhole control
unit or
controller, such as controller 60. The fluid from the upper production zone
52a and the
lower production zone 52b enter the line 46.
100011j When the formation pressure is not sufficient to push the fluid 56a
and/or fluid
56b to the surface, an artificial lift mechanism, such as an electrical
submersible pump
(ESP), gas lift system or other desired systems may be utilized to lift the
fluids from the
well 50 to the surface 112. In the system 100, an ESP 30 in a manifold 31 is
shown as the
artificial lift mechanism, which receives the forrnation fluids 56a and 56b
and pumps
such fluids via tubing 47 to the surface 112. A cable 134 provides power to
the ESP 30
from a surface power source 132. The cable 134 also may include two-way data
communication links 134a and 134b (FIG 1B), which may include one or more
electrical conductors or fiber optic links to provide two-way signals and data
communication between the ESP 30, ESP sensors SE and an ESP control unit 130
(FIG.
1B).
(00012] Still referring to FIGS. 1A and IB, in one aspect, a variety of
sensors are
placed at suitable locations in the well 50 to provide measurements or
information
relating to a number of downhole parameters of interest. In one aspect, one or
more
gauge or sensor carriers, such as a carrier 15, may be placed in the
production tubing to
house any number of suitable sensors. The carrier 15 may include one or more
temperature sensors, pressure sensors, flow measurement sensors, resistivity
sensors,
sensors that may provide information about density, viscosity, water content
or water cut,
etc., and chemical sensors that provide information about scale, corrosion,
hydrate,
paraffin, hydrogen sulfide, emulsion, asphaltene, etc. Density sensors may
provide fluid
density measurements for fluid produced from each production zone and that of
the
combined fluid from two or more production zones. The resistivity sensor or
another
suitable sensor may provide measurements relating to the water content or the
water-cut
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of the fluid mixture :received from each production zones and/or the combined
fluid.
Other sensors may be used to estimate the oil/water ratio and gas/oil ratio
for each
production zone and for the combined fluid. The ternperature, pressure and
flow sensors
provide measurements for the pressure, temperature and flow rate of the fluid
in the line
53. Additional gauge carriers may be used to obtain one or more of the above-
noted and
other measurements relating to the formation fluid received from the upper
production
zone 52a. Additional downhole sensors may be used at other desired locations
to provide
measurements relating to the presence and extent of chemicals downhole.
Additionally,
sensors Si-Sõ may be permanently installed in the wellbore 50 to provide
acoustic,
seismic or microseismic measurements, fonmation pressure and temperature
measurements, resistivity measurements and measurements relating to the
properties of
the casing 51 and fonnation 55. Such sensors may be installed in the casing 57
or
between the casing 57 and the formation 55. Microseismic and other sensors may
be used
to detect water fronts, which may aid in making adjustments to the flow rates
fro each
zone, chemical injection rate, ESP frequency, etc. Pressure and temperature
changes or
expected changes may provide early warning of changes in the chemical
composition of
the production fluid. Additionally, the screen 59a and/or screen 59b may be
coated with
tracers that are released due to the presence of water, which tracers may be
detected at the
surface or downhole to determine or predict the occurrence of water
breakthrough. ESP
sensors SE may include sensors that provide information about temperature,
pressure and
flow rate of the ESP, differential pressure across the ESP, ESP frequency,
power, etc.
Sensors also may be provided at the surface, such as a sensor for measuring
the water
content in the received fluid, total flow rate for the received fluid, fluid
pressure at the
wellhead, temperature, etc. Other devices may be used to estimate the
production ofsand
for each zone.
1000131 In general, suflficient sensors may be suitably placed in the well 50
to obtain
measurements relating to each desired parameter of interest. Such sensors may
include,
but are not limited to: sensors for measuring pressures corresponding to each
production
zone, pressure along the wellbore, pressure inside the tubing carrying the
formation fluid,
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pressure in the annulus; sensors for measuring temperatures at selected places
along the
wellbore; sensors for rneasuring fluid flow rates con=esponding to each of the
production
zones, total flow rate, :llow through the ESP; sensors for measuring ESP
temperature and
pressure; chemical sensors for providing signals relating to the presence and
extent of
chemicals, such as scale, corrosion, hydrates, paraffin, emulsion, hydrogen
sulfide and
asphaltene; acoustic ot= seismic sensors that measure signals generated at the
surface or in
offset wells and signals due to the fluid travel from injection wells or due
to a fracturing
operation; optical sensors for measuring chemical compositions and other
parameters;
sensors for measuring various characteristics of the formations surrounding
the well,
such as resistivity, porosity, permeability, fluid density, etc. The sensors
may be installed
in the tubing in the well or in any device or may be pennanently installed in
the well. For
example, sensors may be installed in the wellbore casing, in the wellbore wall
or between
the casing and the wall. The sensors may be of any suitable type, including
electrical
sensors, mechanical sensors, piezoelectric sensors, fiber optic sensors,
optical sensors,
etc. The signals from the downhole sensors may be par6ally or fully processed
downhole,
such as by a controller 60 that includes a microprocessor and associated
electronic
circuitry that is in signal. or data communication with the downhole sensors
and devices,
and then communicated to the surface controller 150 (FIG. 1B) via a
signal/data link,
such as link 101. The signals from downhole sensors may also be sent directly
to the
surface controller 150.
[000141 A variety of hydraulic, electrical and data communication lines
(collectively
designated by numeral 20 (FIG. lA) are run inside the well 50 to operate the
various
devices in the wel150 to obtain measurements and other data from the various
sensors in
the well 50 and to provide power and data communication between the surface
and
downhole equipment. As an example, a tube or tubing 21 may supply or inject a
particular chemical from the surface into the fluid 56b via a mandrel 36.
Similarly, a
tubing 22 may supply or injeci a particular chemical to the fluid 56a in the
production
tubing via a mandrel 37. Separate lines may be used to supply the additives at
different
locations in the well 50 or to supply different types of additives. Lines 23
and 24 may
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operate the chokes 40 and 44 and may be used to operate any other device, such
as the
valve 67. Lines 25 niay provide electrical power to certain devices downhole
from a
suitable surface power source. Two-way data communication between downhole
sensors,
devices located at any one or more suitable downhole locations and a downhole
controller, such as a controller 60 and/or one or more transducers, such as a
transducer
110, may be established by any desired method, including, but not limited to,
wires,
optical fibers, acoustic telemetry using a fluid line, electromagnetic
telemetry, optical
fibers, wirelessly, etc.
j000151 In one aspect, one or more conduits ortubings, such as tubings 101 and
102 are
placed or run between a suitable location in the well 50 and the surface 112
to establish
data communication using pressure pulses through a liquid medium in the
tubings 101
and/or 102 through. The tubings may be enclosed at a downhole end and may also
be
enclosed at the uphole or surface end. Additionally, the tubings include a
suitable non-
circulating liquid, such as water, oil, etc., which is suitable for sending
pressure pulses
therethrough. The tubings 101, 102 may be made from any suitable material,
such as an
alloy or a composite material capable of withstanding the downhole environment
for an
extended time period. Tubing 102 may be same or similar to the tubing 101. In
FIG 1,
tubing 101 is shown in fluid communication with a downhole transducer 110,
which may
include any device that is configured to generate pressure pulses in the
liquid medium in
the tubing 101. The transducer 110 may include a receiver that receives
signals or data
from one or more sensors, such a sensors Sl-Sm in the wel150 and other
devices, such as
a sensors that provide signals relating to the position of the sleeve 53, ESP
operating
parameters, such a flow rate through the ESP, and pump speed, etc. Such data
or signals
may be provided to the transducer 110 via any suitable data link, such as
electrical
conductors, optical fibers or wireless links. The transducer may be an active
device that
include a processor, mernory and other circuitry that are configured to
receive signals
from one or more sensors and devices, process the received signals and
transmit the
processed signals as pressure signals through the liquid medium in the tubing
101. The
processor may use any telemetry scheme, including but not limited to,
amplitude,
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frequency, phase, pulse duration, pulse shape, time between the pulses or any
combination thereof. A second transducer 120 spaced from the transducer 110
detects or
receives the pressure pulses and sends the received signals to a surface
controller or
control unit, such as the central controller 150. The second transducer may
include any
suitable detector for detecting pressure pulses, such as a pressure sensor.
The surface
controller 150 decodes the signals received from the receiver 120 (FIG 1 B)
and uses the
signals to manage one or more operations of the well system 10. The surface
controller
may send data signals to the transducer 120, which transmits the received
signals via the
liquid media in the tubing 101 in the form of pressure pulses. Alternatively,
a separate
transducer 122 and tubing 102 may be used to send pressure pulses from the
surface 112
to a downhole controller 60 via the liquid medium in the tubing 102. Each of
the
transducers 110 and 120 may be configured to generate the pressure pulses at
multiple
frequencies. The pressure pulses may be coded signals and may use any desired
signals
modulation technique, such as amplitude, phase, frequency, shape, pulse
duration, time
between pulses modulation or any combination thereof. Any suitable device may
be used
to generate pressure pulses, including but not limited to, a piezoelectric
device, a poppet-
type pulser, an oscillating-type or shear-wave pulser, a rotary-type pulser,
or another
suitable pulser.
[00016] Wells can be very long and can extend to several thousand meters. In
some
such wells, the pressure pulses transmitted by a transducer, such a transducer
110 may
attenuate and may not be detectable by the receiver 120. In other cases, it
may be
desirable to transmit pressure pulses between branch wellbores and the surface
or a
branch wellbore and a main wellbore via the fluid-filled conduit and the
signals may
attenuate to an undesirable extent. Also, the transducer 110 over time may not
be able to
send signals that are strong enough to reach the receiver 120. In any such
case, one or
more additional transducers 110 or repeaters, such as Rl - R. (generally
designated by
numeral 114), may be deployed in the well 50 and configured to detect signals
from the
conduit medium and retransmit the detected signals to the next repeater and/or
the
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receiver 120. Similar transducers and repeaters may be deployed in the second
conduit
102.
[000171 Each of the transducers, such as transducer 110, 120 and/or the
repeaters R, -
Ro, may be an autononnous device. FIG 2 shows a functional diagratn of an
autonomous
transducer or repeater 200 according to one embodiment of the disclosure. The
device
200 may include: a processor 210, such as a micro-controller, microprocessor
or another
suitable circuit combuiation; a data storage device or memory device 212, such
a solid
state memory device (Read-only-memory "ROM," random access memory ("RAM",
flash memory, etc.) that is suitable for downhole application; and one or more
computer
programs or sets of instructions 214 that may be stored in the memory 212 and
are
accessible to the processor 210. The processor 210 communicates with the
memory 212
and the programs 214 via links 211 and 213 respectively. A power source 220
provides
power to the processor 210 as shown by link 221 and to the other components of
the
device 200 via link 223. In operation, signals Tl - TP from sensors and other
devices may
be received by an interface 230. The interface 230 may be configured to
condition the
received signals, such as by amplifying and digitizing the signals. The
processor 210
processes the signals from the interface 230, such as by sequencing the
signals, putting
the signals in appropriate data packets, assigning addresses of the sensors or
the devices
from which such sigmils were received by the interface 230, etc. and sends
such
processed signals via linLk 241 to a pulser (transmitter) 240 that sends the
signals via the
medium in the conduit as pressure pulses. The pressure pulses sent from the
surface via
the conduits 101 andlor 102 are received by a receiver or detector 245, which
may
condition the received signals and provide them to the processor 210. The
processor 210
processes the surface-sent signals and may control one or more downhole
devices 260 or
send these signals to the downhole controller 60. The processor 210 may store
any
information in the memciry device 212 and/or programs 214 to perform one or
more of
the functions described herein. The processor 210 is shown to communicate with
the
receiver 245 via link 243 and with downhole devices 260 via link 261. Thus in
operation,
the downhole transducer 110 receives signals from one or more devices or
sensors in the
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well and transmits signals representative of the received signals as pressure
pulses
through a liquid-filled conduit placed in the well. A receiver spaced from the
downhole
transducer detects the pressure pulses and retransmits them to a surface
controller for
further use. The surface controller may send signals in the form of pressure
pulses or by
any other method to a downhole receiver via the same or a separate liquid-
filled conduit.
One or more repeaters may be provided along the liquid-filled tubing's to
retransmit the
pressure pulses.
[000181 Referring back to FIG 1B, in one aspect, the exemplary equipment shown
in
FIG.1B may be utilized to manage and control the various operations of the
well system
in response to the signals received from the downhole transducer 110. In one
aspect,
the controller 150 may manage injection of additives from a chemical injection
unit 120
into the well 50 to enhance production from one or more zones in response to
the signals
received from a chemical sensor that may provide information about the
presence of
certain chemicals, such as scale, hydrate, corrosion, asphaltene, hydrogen
sulfide, etc. or
in response to a water-cut sensor, resistivity sensor, etc.
[00019] In another aspect, the central controller 150 may control the
operation of one or
more downhole devices directly or via a downhole device control unit 160 by
sending
commands via a link 161. The commands may be instructions to alter the
position of a
choke or a sliding sleeve, etc and such commands may be in response to signals
received
from one or more dowiihole devices or sensors and/or signals received from a
remote
controller, such as controller 185 that may communicate with the controller
150 via a
suitable link 189, such as Ethernet, the Internet, etc. The downhole device
controller 160
may control the downhole devices via links 21-25. In another aspect, the
central
controller 150 may control the operation of the ESP 30 directly or via an ESP
controller
130. The ESP controller may control power to the ESP from a power source 132
in
response to the signals received from the ESP sensors and/or signals received
from the
central controller 150.
[000201 Thus, in one aspect, a system for communicating information between at
least
one location in a well ancl the surface is disclosed, wherein the system
includes: a conduit
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that filled with a non-circulating liquid and a transducer that generates
pressure pulses
representative of signals to be transmitted through the conduit. A detector
spaced from
the transducer detects the pressure pulses in the conduit and generates
electrical signals
representative of the detected pressure pulses.
1000211 The transducer may include a pulser that generates the pressure pulses
in the
liquid in the conduit. The pulser may be any suitable device that is
configured to generate
the pressure pulses downhole, including but not limited to: a piezoelectric
device that
generates acoustic signals to generate the pressure pulses; a poppet-type
pulser that
includes a reciprocatii:ig piston or valve that obstructs fluid flow to
generate pressure
pulses; a shear-wave pulser that generates pressure pulses when a disc
oscillates
proximate a stationary disc to obstruct fluid flow; a rotary pulser that
generates pressure
pulses when a disc rotates proximate a stationary to obstruct a fluid flow.
[00022] In another aspect, the system may include one or more repeaters uphole
of the
transducer that detects the pressure pulses generated by the transducer. The
repeater may
condition the detected pressure pulses and generate the conditioned pulses
through the
liquid medium in the conduit. The uphole location may be in the well or at the
surface.
The system may further include a surface transducer that generates pressure
pulses in a
liquid-filled conduit to a downhole location and a detector downhole that
detects the
pressure pulses sent fi-om the surface. The downhole detector may provide
signals
corresponding to the detected pulses to a downhole controller or processor. In
one
aspect, the transducer and /or any of the repeaters may be an autonomous
device, which
may include: a receiver that receives signals from at least one sensor; a
processor that
converts the signals received from the at least one sensor into coded signals;
and a pulser
that generates pressure pulses in the liquid corresponding to the coded
signals. The
system, in another aspect, may further include an interface that receives
signals from at
least one senor or device in the well. The sensor or device may be one or more
of: (i) a
pressure sensor; (ii) a temperature sensor; (iii) an acoustic sensor; (iv) a
flow cate
measuring device; (v) oi water-cut measurement device; (vi) a resistivity
measuring
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device; (vii) a chemical detection sensor; (viii) a fiber optic sensor; (ix) a
piezoelectric
sensor; and (x) a density sensor.
[00023] The uphole location in the system may be a location in a branch
wellbore, a
main wellbore, a location at the surface of the earth, a location at the sea
bed, a location
on a land rig or a location on an offshore vessel or platform. The downhole
sensors or
devices may send signals to the transducer or a downhole controller via any
suitable
connection, including, but not limited to, electrical conductors, optical
fibers and wireless
links.
[00024] A suitable power source in the well or at the surface may provide
power to the
downhole transducers and repeaters, which may include: a battery; (ii) a power
generation unit that gen.erates electrical power in the wellbore; and (iii) a
power unit at
the surface that supplies electrical power via an electrical conductor
disposed in or along
the conduit. The conduit may conduit may be placed: (i).inside a production
tubing
carrying fluid to thee surface; (ii) between a production tubing and a casing;
or (iii)
between a casing and formation surrounding the wellbore.
(00025] In another aspect, the system may include a plurality of sensors
distributed in
the well, and wherein the system may include a plurality of transducers, each
of which
receives signals from an associated sensor or device and transmits coded
signals as
pressure pulses through the liquid in the conduit that are representative of
the received
signals.
[00026] In another aspect, the system may include an additional liquid-filled
conduit
that is used to transmit pressure pulses from the surface to a downhole
location.
Alternatively, the system may include another telemetry system for
transmitting signals
from the surface, such an electro-magnet telemetry system, an acoustic
telemetry system,
wire in a tubing, etc. Additionally, each transducer and/or repeater may be an
autonomous device and may include: an electronics module; and an energy
source. The
electronic module may fiuther include a processor that acts according to
programmed
instructions for controlling an operation of the transducer. The energy source
may be: (i)
a battery; (ii) a thermoelectric generator; (iii) a combination of a battery
and a
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thermoelectric generator; or (iv) a source at the surface. The transducers and
repeaters
may transmit signals at different frequencies and at more than one frequency.
Additionally, the one or more sensors associated with the transducer or
repeater may
detect at least one parameter of interest related to: (i) a health of the
transducer; or (ii) a
downhole condition. The sensors downhole may include any suitable sensor or
device,
including, but not l'united to, sensors for providing a measurement relating
to: (i)
pressure; (ii) temperature; (iii) resistivity; (iv) fluid flow rate; (v)
capacitance; (v)
viscosity; (vi) density; (vii) presence of a chemical in the wellbore; (viii)
paraffin; (ix)
scale; (x) hydrate; (xi) hydrogen sulfide; ( xii) asphaltene; (xiii)
corrosion; (xiv) water
content; (xv) presence of gas; (xvi) water cut.
[00027] In another aspect, a method is disclosed that includes: placing a
liquid-filled
conduit in the wellbore; receiving from at least one sensor in the wellbore
signals relating
to a parameter of interest; transmitting pressure pulses in the liquid in the
conduit at a
downhole location that: are representative of the signals received from the at
least one
sensor; and detecting the pressure pulses at an uphole location; processing
the detected
signals to estimate the parameter of interest; and recording the estimated
parameter of
interest in a suitable medium. The method may further include at last one
repeater device
at a downhole location that detects the pressure pulses, conditions the
detected pressure
pulses and transmits the conditioned pressure pulses through the liquid in the
conduit.
The parameter of interest may by any suitable parameter, including, but not
limited to: (i)
pressure; (ii) temperattae; (iii) resistivity; (iv) fluid flow rate; (v)
capacitance; (v)
viscosity; (vi) density; (vii) presence of a chemical in the wellbore; (viii)
paraffin; (ix)
scale; (x) hydrate; (xi) hydrogen sulfide; ( xii) asphaltene; (xiii)
corrosion; (xiv) water
content; and (xv) presence of gas.
[00028] In another aspect the method may include: placing a conduit in the
well that
contains a non-circulatuig liquid medium therein; and transmitting information
in the
form of pressure pulses through the medium, while the apparatus may include: a
conduit
in a well that contains a non-circulating liquid medium therein and a
transmitter
16
CA 02693485 2010-01-18
WO 2009ro18420 PCT/US2008/071720
configured to transmit pressure pulses through the inedium that are
representative of
signals to be transmitted between a downhole location and an uphole location
of a well.
[00029] While the foregoing disclosure is directed to certain disclosed
embodiments
and methods, various modifications will be apparent to those skilled in the
art. It is
intended that, all modifications that fall within the scopes of the claims
relating to this
disclosure be deemed as part of the foregoing disclosure. Also, an abstract is
provided in
this application with the understanding that it will not be used to interpret
or limit the
scope or meaning of the claims.
17
