U.S. patent application number 12/173851 was filed with the patent office on 2010-01-21 for downhole telemetry system using an optically transmissive fluid media and method for use of same.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Travis Cavender, Kevin Fink, Roger Schultz, Vince Zeller.
Application Number | 20100013663 12/173851 |
Document ID | / |
Family ID | 41529849 |
Filed Date | 2010-01-21 |
United States Patent
Application |
20100013663 |
Kind Code |
A1 |
Cavender; Travis ; et
al. |
January 21, 2010 |
Downhole Telemetry System Using an Optically Transmissive Fluid
Media and Method for Use of Same
Abstract
A downhole telemetry system (10) disposed within a wellbore
(32). The downhole telemetry system (10) includes a downhole
transmitter (48) operable to optically transmit a data stream and a
downhole receiver (52) operable to receive the optically
transmitted data stream. An optically transmissive fluid (64) is
disposed in the wellbore (32) and provides a medium for the optical
transmission of the data stream between the downhole transmitter
(48) and the downhole receiver (52).
Inventors: |
Cavender; Travis; (Angleton,
TX) ; Fink; Kevin; (Frisco, TX) ; Zeller;
Vince; (Flower Mound, TX) ; Schultz; Roger;
(Ninnekah, OK) |
Correspondence
Address: |
LAWRENCE R. YOUST;Lawrence Youst PLLC
2900 McKinnon, Suite 2208
DALLAS
TX
75201
US
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
Carrollton
TX
|
Family ID: |
41529849 |
Appl. No.: |
12/173851 |
Filed: |
July 16, 2008 |
Current U.S.
Class: |
340/854.3 ;
340/854.6 |
Current CPC
Class: |
G01V 11/002
20130101 |
Class at
Publication: |
340/854.3 ;
340/854.6 |
International
Class: |
G01V 3/00 20060101
G01V003/00 |
Claims
1. A downhole telemetry system disposed within a wellbore, the
downhole telemetry system comprising: a downhole transmitter
operable to optically transmit a data stream; a downhole receiver
operable to receive the optically transmitted data stream; and an
optically transmissive fluid disposed in the wellbore that provides
a medium for the optical transmission of the data stream between
the downhole transmitter and the downhole receiver.
2. The downhole telemetry system as recited in claim 1 further
comprising a tubular string that supports the downhole transmitter
and the downhole receiver.
3. The downhole telemetry system as recited in claim 2 wherein the
optically transmissive fluid is disposed in at least one of an
annulus between the tubular string and the wellbore and an interior
of the tubular string.
4. The downhole telemetry system as recited in claim 1 wherein the
downhole transmitter is positioned uphole of the downhole
receiver.
5. The downhole telemetry system as recited in claim 1 wherein the
downhole transmitter is positioned downhole of the downhole
receiver.
6. The downhole telemetry system as recited in claim 1 wherein the
data stream further comprises at least one of surface commands and
downhole data.
7. The downhole telemetry system as recited in claim 1 wherein the
optically transmitted data stream further comprises at least one of
light and laser.
8. The downhole telemetry system as recited in claim 1 wherein the
optically transmissive fluid further comprises a brine.
9. The downhole telemetry system as recited in claim 1 wherein the
optically transmissive fluid further comprises suspended
solids.
10. A method for transmitting data with a wellbore, the method
comprising: disposing an optically transmissive fluid within the
wellbore to provide a medium for optical transmission of data; and
optically transmitting a data stream through the optically
transmissive fluid.
11. The method as recited in claim 10 further comprising suspending
particles in the optically transmissive fluid.
12. The method as recited in claim 10 wherein optically
transmitting a data stream through the optically transmissive fluid
further comprises transmitting light through the optically
transmissive fluid.
13. The method as recited in claim 10 wherein optically
transmitting a data stream through the optically transmissive fluid
further comprises transmitting laser through the optically
transmissive fluid.
14. A downhole telemetry system disposed within a wellbore, the
downhole telemetry system comprising: a downhole transmitter
operable to optically transmit a data stream; a downhole repeater
operable to receive the optically transmitted data stream from the
downhole transmitter and to optically retransmit the data stream; a
downhole receiver operable to receive the optically retransmitted
data stream; and an optically transmissive fluid disposed in the
wellbore that provides a medium for the optical transmission of the
data stream between the downhole transmitter and the downhole
repeater and for the optical retransmission of the data stream
between the downhole repeater and the downhole receiver.
15. The downhole telemetry system as recited in claim 14 wherein
the optically transmissive fluid further comprises a brine.
16. The downhole telemetry system as recited in claim 14 wherein
the optically transmissive fluid further comprises suspended
solids.
17. The downhole telemetry system as recited in claim 14 further
comprising a tubular string that supports the downhole transmitter,
the downhole repeater and the downhole receiver and wherein the
optically transmissive fluid is disposed in at least one of an
annulus between the tubular string and the wellbore and an interior
of the tubular string.
18. The downhole telemetry system as recited in claim 14 further
comprising a plurality of downhole repeaters disposed with the
wellbore between the downhole transmitter and the downhole
receiver, each of the downhole repeaters operable to receive the
optically transmitted data stream and to optically retransmit the
data stream.
19. A downhole telemetry system disposed within a wellbore, the
downhole telemetry system comprising: a first downhole transmitter
operable to transmit a data stream via a first transmission mode; a
first downhole receiver operable to receive the data stream
transmitted via the first transmission mode; a second downhole
transmitter communicably associated with the first downhole
receiver operable to retransmit the data stream via a second
transmission mode; and a second downhole receiver operable to
receive the data stream retransmitted via the second transmission
mode; wherein one of the first and the second transmission modes is
optical transmission; and wherein an optically transmissive fluid
disposed in the wellbore provides a medium for the optical
transmission of the data stream.
20. The downhole telemetry system as recited in claim 19 wherein
the other of the first and the second transmission modes is
selected from acoustic transmission, electromagnetic transmission,
electrical transmission and sonar transmission.
21. The downhole telemetry system as recited in claim 19 further
comprising a tubular string that supports the first and second
downhole transmitters and the first and second downhole receivers
and wherein the optically transmissive fluid is disposed in at
least one of an annulus between the tubular string and the wellbore
and an interior of the tubular string.
22. The downhole telemetry system as recited in claim 19 wherein
the optically transmissive fluid further comprises a brine.
23. The downhole telemetry system as recited in claim 19 wherein
the optically transmissive fluid further comprises suspended
solids.
24. A method for transmitting data with a wellbore, the method
comprising: transmitting a data stream via a first transmission
mode; receiving the data stream transmitted via the first
transmission mode; retransmitting the data stream via a second
transmission mode; and receiving the data stream retransmitted via
the second transmission mode; wherein one of the first and the
second transmission modes is optical transmission; and wherein an
optically transmissive fluid disposed in the wellbore provides a
medium for the optical transmission of the data stream.
25. The method as recited in claim 24 wherein the other of the
first and the second transmission modes is selected from acoustic
transmission, electromagnetic transmission, electrical transmission
and sonar transmission.
Description
TECHNICAL FIELD OF THE INVENTION
[0001] This invention relates, in general, to communication systems
for transmitting data between downhole equipment and surface
equipment and, in particular, to a downhole telemetry system that
transmits optical signals via an optically transmissive fluid media
disposed in a wellbore.
BACKGROUND OF THE INVENTION
[0002] Without limiting the scope of the present invention, its
background is described with reference to sand control completions,
as an example.
[0003] It is well known in the subterranean well drilling and
completion art that relatively fine particulate materials may be
produced during the production of hydrocarbons from a well that
traverses an unconsolidated or loosely consolidated formation.
Numerous problems may occur as a result of the production of such
particulate. For example, the particulate causes abrasive wear to
components within the well, such as tubing, flow control devices,
safety devices and the like. In addition, the particulate may
partially or fully clog the well creating the need for an expensive
workover. Also, if the particulate matter is produced to the
surface, it must be removed from the hydrocarbon fluids using
surface processing equipment.
[0004] One method for preventing the production of such particulate
material is to gravel pack the well adjacent to the unconsolidated
or loosely consolidated production interval. In a typical gravel
pack completion, a sand control screen is lowered into the wellbore
on a work string to a position proximate the desired production
interval. A fluid slurry including a liquid carrier and a
relatively coarse particulate material, such as sand, gravel or
proppants, which are typically sized and graded and which are
typically referred to herein as gravel, is then pumped down the
work string and into the well annulus formed between the sand
control screen and the perforated well casing or open hole
production zone.
[0005] The liquid carrier either flows into the formation or
returns to the surface by flowing through a wash pipe or both. In
either case, the gravel is deposited around the sand control screen
to form the gravel pack, which is highly permeable to the flow of
hydrocarbon fluids but blocks the flow of the fine particulate
materials carried in the hydrocarbon fluids. As such, gravel packs
can successfully prevent the problems associated with the
production of these particulate materials from the formation.
[0006] In other cases, it may be desirable to stimulate the
formation by, for example, performing a formation fracturing and
propping operation prior to or simultaneously with the gravel
packing operation. This type of treatment process is commonly
referred to as a frac pack. During this treatment process,
hydraulic fractures are created in the hydrocarbon bearing
formation, which increase the permeability of the formation
adjacent the wellbore. According to conventional practice, a
fracture fluid such as water, oil, oil/water emulsion, gelled water
or gelled oil is pumped down the work string with sufficient volume
and pressure to open multiple fractures in the production interval.
The fracture fluid may carry a suitable propping agent, such as
sand, gravel or proppants, which are typically referred to herein
as proppants, into the fractures for the purpose of holding the
fractures open following the fracturing operation. In addition,
these proppants are deposited around the sand control screen to
form the gravel pack as described above. As such, frac packs can
successfully enhance fluid production from the formation while also
preventing the production of particulate materials from the
formation.
[0007] Typically, downhole parameters such as pressure and
temperature are obtained and recorded during such treatment
processes with one or more downhole sensors. The information
obtained by the sensors is later downloaded into surface or remote
computers once the treatment operation is complete and the sensors
have been tripped out of the wellbore. It has been found, however,
that the quality of the treatment operation is evaluated only after
such downhole sensors are brought to the surface. As such, the
information obtained by the sensors is not supplied in a manner
timely enough to allow modifications to the treatment operation.
Accordingly, a need has arisen for a communication system for
transmitting data between downhole equipment and surface equipment
that is operable to provide real-time information relating to
parameters and conditions downhole such that modifications to a
treatment operation may occur, if desired.
SUMMARY OF THE INVENTION
[0008] The present invention disclosed herein provides a
communication system for transmitting data between downhole
equipment and surface equipment. The system of the present
invention is operable to provide real-time information relating to
parameters and conditions downhole such that modifications to a
treatment operation may occur, if desired.
[0009] In one aspect, the present invention is directed to a
downhole telemetry system that is disposed within a wellbore. The
downhole telemetry system includes a downhole transmitter operable
to optically transmit a data stream and a downhole receiver
operable to receive the optically transmitted data stream. An
optically transmissive fluid is disposed in the wellbore and
provides a medium for the optical transmission of the data stream
between the downhole transmitter and the downhole receiver.
[0010] In one embodiment, a tubular string supports the downhole
transmitter and the downhole receiver. In this embodiment, the
optically transmissive fluid may be disposed in an annulus between
the tubular string and the wellbore, in an interior of the tubular
string or both. In some embodiments, the downhole transmitter may
be positioned uphole of a downhole receiver, downhole of a downhole
receiver or both to enable communication of surface commands
downhole, downhole data uphole or both. In certain embodiments, the
optical transmission of the data stream may be accomplished using a
light beam such as a laser. The optically transmissive fluid may be
a brine and may include suspended solids.
[0011] In another aspect, the present invention is directed to a
method for transmitting data within a wellbore. The method includes
disposing an optically transmissive fluid within the wellbore to
provide a medium for optical transmission of data and optically
transmitting a data stream through the optically transmissive fluid
between a downhole transmitter and a downhole receiver.
[0012] The method may also include disposing suspending particles
in the optically transmissive fluid, transmitting light through the
optically transmissive fluid or transmitting laser through the
optically transmissive fluid.
[0013] In a further aspect, the present invention is directed to a
downhole telemetry system disposed within a wellbore. The downhole
telemetry system includes a downhole transmitter operable to
optically transmit a data stream, a downhole repeater operable to
receive the optically transmitted data stream from the downhole
transmitter and to optically retransmit the data stream and a
downhole receiver operable to receive the optically retransmitted
data stream. An optically transmissive fluid is disposed in the
wellbore and provides a medium for the optical transmission of the
data stream between the downhole transmitter and the downhole
repeater and for the optical retransmission of the data stream
between the downhole repeater and the downhole receiver.
[0014] In one embodiment, a tubular string supports the downhole
transmitter, the downhole repeater and the downhole receiver. In
this embodiment, the optically transmissive fluid may be disposed
in an annulus between the tubular string and the wellbore, an
interior of the tubular string or both. In certain embodiments, a
plurality of downhole repeaters may be disposed within the wellbore
between the original downhole transmitter and the final downhole
receiver. In this embodiment, each of the downhole repeaters is
operable to receive the optically transmitted data stream and to
optically retransmit the data stream such that the data stream may
be sent over a long distance.
[0015] In yet another aspect, the present invention is directed to
a downhole telemetry system disposed within a wellbore. The
downhole telemetry system includes a first downhole transmitter
operable to transmit a data stream via a first transmission mode, a
first downhole receiver operable to receive the data stream
transmitted via the first transmission mode, a second downhole
transmitter communicably associated with the first downhole
receiver and operable to retransmit the data stream via a second
transmission mode and a second downhole receiver operable to
receive the data stream retransmitted via the second transmission
mode. In this system, one of the first and the second transmission
modes is optical transmission and an optically transmissive fluid
that is disposed in the wellbore provides a medium for the optical
transmission of the data stream.
[0016] In one embodiment, the other of the first and the second
transmission modes is selected from acoustic transmission,
electromagnetic transmission, electrical transmission and sonar
transmission.
[0017] In an additional aspect, the present invention is directed
to a method for transmitting data within a wellbore. The method
includes transmitting a data stream via a first transmission mode,
receiving the data stream transmitted via the first transmission
mode, retransmitting the data stream via a second transmission mode
and receiving the data stream retransmitted via the second
transmission mode, wherein one of the first and the second
transmission modes is optical transmission and wherein an optically
transmissive fluid disposed in the wellbore provides a medium for
the optical transmission of the data stream.
BRIEF DESCRIPTION OF THE DRAWINGS
[0018] For a more complete understanding of the features and
advantages of the present invention, reference is now made to the
detailed description of the invention along with the accompanying
figures in which corresponding numerals in the different figures
refer to corresponding parts and in which:
[0019] FIG. 1 is a schematic illustration of a offshore oil and gas
platform positioned over a well that traverses a hydrocarbon
bearing subterranean formation in which an embodiment of a downhole
telemetry system of the present invention is operating;
[0020] FIG. 2 is a cross sectional view taken of a gravel packing
apparatus having integrated sensors for operation in the downhole
telemetry system of the present invention;
[0021] FIG. 3 is a block diagram of a sensor for operation in the
downhole telemetry system of the present invention;
[0022] FIG. 4 is a side view of a flat pack wire bundle for use the
downhole telemetry system of the present invention;
[0023] FIG. 5 is a cross sectional view taken along line 5-5 of
FIG. 4 of a flat pack wire bundle for use the downhole telemetry
system of the present invention;
[0024] FIG. 6 is a schematic illustration of a offshore oil and gas
platform positioned over a well that traverses a hydrocarbon
bearing subterranean formation in which another embodiment of a
downhole telemetry system of the present invention is
operating;
[0025] FIG. 7 is a schematic illustration of a offshore oil and gas
platform positioned over a well that traverses a hydrocarbon
bearing subterranean formation in which another embodiment of a
downhole telemetry system of the present invention is operating;
and
[0026] FIG. 8 is a schematic illustration of a offshore oil and gas
platform positioned over a well that traverses a hydrocarbon
bearing subterranean formation in which another embodiment of a
downhole telemetry system of the present invention is
operating.
DETAILED DESCRIPTION OF THE INVENTION
[0027] While the making and using of various embodiments of the
present invention are discussed in detail below, it should be
appreciated that the present invention provides many applicable
inventive concepts which can be embodied in a wide variety of
specific contexts. The specific embodiments discussed herein are
merely illustrative of specific ways to make and use the invention,
and do not delimit the scope of the invention.
[0028] Referring initially to FIG. 1, a downhole telemetry system
including a series of optical communication components in use in a
well is schematically illustrated and generally designated 10. A
semi-submergible platform 12 is centered over a submerged oil and
gas formation 14 located below sea floor 16. A subsea conduit 18
extends from deck 20 of platform 12 to wellhead installation 22
including blowout preventers 24. Platform 12 has a derrick 26 and a
hoisting apparatus 28 for raising and lowering pipe strings
including a work string 30. Work string 30 is positioned within
well 32 having casing 34 that has been secured within well 32 by
cement 36. In the illustrated embodiment, work string 30 includes a
sump packer 38, a gravel packing apparatus or sand screen 40
including a plurality of sensors 42 and a crossover assembly 44
including a gravel packer 46. Work string 30 also includes a
plurality of optical communication components 48, 50, 52, 54, 56
and 58. A wired communication link 60 that passes through gravel
packer 46 provides a communication medium for communication between
sensors 42 and optical communication component 48. Similarly, a
wired communication link disposed within pipe segment 62 provides a
communication medium for communication between optical
communication component 52 and optical communication component 54
across blowout preventers 24. Optical transmission between various
optical communication components is achieved via an optically
transmissive fluid medium 64 disposed within annulus 66, the
interior of work string 30 or both.
[0029] A typical completion process using gravel packing apparatus
40 having integrated sensors 42 will now be described. First, the
production interval 68 adjacent to formation 14 is isolated. Packer
46 seals the upper end of production interval 68 and packer 38
seals the lower end of production interval 68. Crossover assembly
44 is located adjacent to gravel packing apparatus 40, traversing
packer 46 with portions of crossover assembly 44 on either side of
packer 46. When the gravel packing operation commences, the
objective is to uniformly and completely fill the production
interval 68 with gravel. To help achieve this result, a wash pipe
is disposed within gravel packing apparatus 40. The wash pipe
extends into crossover assembly 44 such that return fluid passing
through gravel packing apparatus 40 may travel through the wash
pipe and into annulus 66 for return to the surface.
[0030] The fluid slurry containing gravel is pumped down work
string 30 into crossover assembly 44. The fluid slurry containing
gravel exits crossover assembly 44 through a series of crossover
ports and is discharged into annular interval 68, such that the
gravel drops out of the slurry and builds up from formation 14,
filling the perforations and annular interval 68 around gravel
packing apparatus 40 forming the gravel pack. Some of the carrier
fluid in the slurry may leak off through the perforations into
formation 14 while the remainder of the carrier fluid passes
through gravel packing apparatus 40, that is sized to prevent
gravel from flowing therethrough. The fluid flowing back through
gravel packing apparatus 40, as explained above, flows back to the
surface. This process progresses along the entire length of gravel
packing apparatus 40 such that annular interval 68 becomes
completely packed with the gravel. Once annular interval 68 is
completely packed with gravel, the gravel pack operation may
cease.
[0031] Throughout the gravel placement process, sensors 42 that are
operably associated with gravel packing apparatus 40 and wired
communication link 60 are used to monitor the entire gravel packing
operation and provide substantially real time data relating to the
gravel placement. Sensors 42 are position in a variety of
circumferential, axial and radial locations relative to gravel
packing apparatus 40. For example, as seen in FIG. 2, gravel
packing apparatus 40 includes sensors 42 positioned on the outer
and inner surfaces of base pipe 70, the outer and inner surfaces of
screen wire 72 and on the outer and inner surfaces of wash pipe 74.
Sensors 42 may be any one or more of the following types of
sensors, including pressure sensors, temperature sensors,
piezoelectric acoustic sensors, flow meters for determining flow
rate, accelerometers, resistivity sensors for determining water
content, velocity sensors, weight sensors or any other sensor that
measures a fluid property or physical parameter downhole. As used
herein, the term sensor shall include any of these sensors as well
as any other types of sensors, such as fiber optic distributed
temperature sensors, that are used in downhole environments and the
equivalents to these sensors.
[0032] As illustrated in FIG. 3, a sensor 42 can be powered by a
battery 80. In the illustrated embodiment, sensor 42 is coupled to
transceiver 82 that is used to transmit data and receive
instructions between sensor 42 and the surface or between sensor 42
and another downhole system. Sensor 42 has a microprocessor 84
associated therewith to allow for manipulation and interpretation
of the sensor data and for processing the received instructions.
Likewise, sensor 42 is coupled to a memory 86 which provides for
storing information for later batch processing or batch
transmission, if desired. Importantly, this combination of
components provides for localized control and operation of an
actuator 88 which may be a flow control device, such as a sliding
sleeve, associated with gravel packing apparatus 40 to selectively
permit and prevent fluid flow therethrough or which may be a safety
device or other actuatable downhole device.
[0033] Referring again to FIG. 1, sensors 42 provide substantially
real time data on the effectiveness of the treatment operation. For
example, during a gravel packing operation, voids may be identified
during the gravel placement process that allow the operator to
adjust treatment parameters such as pump rate, gravel
concentration, fluid viscosity and the like to overcome
deficiencies in the gravel pack. This real time data is then sent
to the surface via the downhole telemetry system of the present
invention. As a first step, the data collected sensors 42 is
encoded into electrical signals utilizing, for example, "1" and "0"
for information transmission. The encoded electrical signal is then
transmitted to optical communication component 48 via wired
communication link 60.
[0034] Optical communication component 48 operates as a transducer
to convert the digitally encoded electrical signal into a digitally
encoded optical data stream in the form of light radiation such as
a laser. In a preferred embodiment, optical communication component
48 emits coherent light radiation in a narrow, low-divergence
monochromatic beam with a well-defined wavelength. Optical
communication component 48 includes a transmitter that transmits
the optical data stream to optical communication component 50 that
includes a receiver. The optical data stream is sent in annulus 66
which contains an optically transmissive fluid medium 64. Suitable
optically transmissive fluids include clear fluids such as water as
well as fluids containing various suspended particles such as
brines that may includes salts such as sodium chloride, sodium
formate, calcium chloride, calcium bromide, zinc chloride, zinc
bromide, potassium chloride, potassium bromide, potassium formate,
caesium formate and the like. Optically transmissive fluid medium
64 may alternatively or additionally include other suspended
particles including engineered particles of glass or polymers
preferably having flat surfaces or other desirable refraction
surfaces.
[0035] In a highly optically transmissive medium, the digitally
encoded optical data stream will tend to travel in the straight
path maintaining its narrow beam format. As most wellbores do not
provide a straight path, the optically transmissive fluid medium of
the present invention uses the suspended particles to scatter the
light beam, thus allowing the information carried in the digitally
encoded optical data stream to travel between the optical
communication components of the present invention. Specifically,
scattering allows the digitally encoded optical data stream to
deviate from a straight trajectory due to the localized
non-uniformities created by the suspended particles in optically
transmissive fluid medium 64. As the suspended particles in
optically transmissive fluid medium 64 cause a large number of
scattering events of the digitally encoded optical data stream, the
path of the digitally encoded optical data stream diffuses to fill
the entire annulus 66 with light radiation.
[0036] In the illustrated embodiment, optical communication
component 50 is positioned between optical communication component
48 and optical communication component 52 to provide amplification
and repeater functionality. Specifically, optical communication
component 50 is positioned relative to optical communication
component 48 such that the light radiation intensity is sufficient
at optical communication component 50 to read the data digitally
encoded within the optical data stream. Preferably, optical
communication component 50 optically or electrically processes the
data stream and retransmits the data stream as another digitally
encoded optical data stream to optical communication component
52.
[0037] Even though FIG. 1 depicts three optical communication
components disposed within wellbore 32 below sea floor 16, those
skilled in the art will recognize that the number of optical
communication components needed in a given installation will depend
on factors including the length of the wellbore, the optical
transmissivity of the fluid medium, the concentration of suspended
particles, the strength and type of light radiation used and the
like. Accordingly, any number of optical communication components,
each having a transmitter and a receiver, may serve as repeaters
without departing from the principles of the present invention.
[0038] In the illustrated embodiment, optical communication
component 52 includes a transducer that converts the digitally
encoded optical data stream to an electrical signal such that the
data stream may be passed through blowout preventers 24.
Specifically, as blowout preventers 24 create a discontinuity in
the optically transmissive fluid medium 64, another communication
mode is used. In this embodiment, a wired communication link
disposed within pipe segment 62 provides a communication medium for
communication between optical communication component 52 and
optical communication component 54 across blowout preventers 24.
Specifically, as best seen in FIGS. 4 and 5, a flat pack umbilical
line 90 may be used to provide the wired communication link. In the
illustrated embodiment, umbilical line 90 includes an instrument
line 92, such as a copper wire, a coaxial cable, a fiber optic
bundle, a twisted pair or other line suitable for transmitting
signals, data and the like, and a hydraulic line 94. In addition,
umbilical line 90 includes a pair of bumper bars 96, 98 such as
braided wire, which provides added rigidity to umbilical line 90.
Alternatively, instead of including hydraulic line 94, certain
embodiments of umbilical line 90 could utilize a pair of instrument
lines. Also, instead of being disposed within pipe segment 62, a
wired communication link could alternatively be disposed exteriorly
of pipe segment 62 or could be embedded or integrated within pipe
segment 62.
[0039] Continuing on the communication path depicted in FIG. 1, the
encoded electrical signal is transmitted to optical communication
component 54 from the wired communication link associated with pipe
segment 62. Optical communication component 54 operates as a
transducer to convert the digitally encoded electrical signal into
a digitally encoded optical data stream. As illustrated, the
optical data stream is transmitted from optical communication
component 54 to optical communication component 56 in annulus 100
which contains optically transmissive fluid medium 64. Optical
communication component 56 provides amplification and repeater
functionality by optically or electrically processing the data
stream and retransmitting the data stream as another digitally
encoded optical data stream to optical communication component 58.
Optical communication component 58 preferably includes a transducer
that converts the digitally encoded optical data stream to an
electrical signal such that the data stream may be passed to a
surface computer for further processing and analysis.
[0040] As large amounts of information can be transmitted optically
in substantially real time using the present invention, the
information may be used to make changes in the treatment process
that enhance the quality of the treatment process. As one example,
it may desirable to open certain sliding sleeves or valves
associated with the wash pipe disposed within gravel packing
apparatus 40 such that the return path for fluids is altered. In
this case, such a command can be sent to the appropriate sensor 42
that can actuate such a sliding sleeve or valve. The command can be
sent using the telemetry system described above as a downlink.
Specifically, a digitally encoded electrical command may be sent to
optical communication component 58 that converts the digitally
encoded electrical command into a digitally encoded optical command
which is sent via optically transmissive fluid medium 64 to optical
communication component 56 which in turn retransmits the digitally
encoded optical command for receipt by optical communication
component 54. The command is then send from optical communication
component 54 to optical communication component 52 via the wired
communication link disposed within pipe segment 62. The optical
retransmission continues from optical communication component 52 to
optical communication component 50 and finally to optical
communication component 48 which converts the digitally encoded
optical command to a digitally encoded electrical command that is
sent to the appropriate sensor 42 via wired communication link 60.
Actuator 88 of sensor 42 then causes the actuation of the desired
sliding sleeve or valve. In using the telemetry system of the
present invention as a downlink, it may be desirable to use a beam
of coherent light radiation in a narrow, low-divergence
monochromatic beam with a different well-defined wavelength than
that used for data communication in the uphole direction. Likewise,
multiple beams of coherent light radiation in a narrow,
low-divergence monochromatic beam with different well-defined
wavelengths can be used simultaneously to provide multiple channels
of communication in either the uphole direction, the downhole
direction or both.
[0041] The telemetry system of the present invention may also be
used to enhance a frac pack operation. In certain frac pack
completions, it is desirable to perform a mini frac prior to
performing the full fracture stimulation and gravel packing
treatment. Typically, the mini frac is performed using a relative
small volume of frac fluid to test the formation response to the
proposed treatment regime. In such a treatment scenario, the frac
fluid is pumped down work string 30, through crossover assembly 44
into annular interval 68, through the perforations and into
formation 14 without taking return fluids. During this process,
sensors 42 are used to monitor various aspects of the mini frac,
such as temperature and pressure at various locations and
particularly temperature during the bleed-off period. As the mini
frac is relatively short in duration, the data obtained during the
mini frac is preferably stored by sensors 42 until the mini frac is
complete. At this point, it may be desirable to circulate an
optically transmissive fluid into the well through which the
digitally encoded optical data stream generated by the optical
communication components may be transmitted. Following the
communication path described above, the data obtained by sensors 42
may be sent to the surface via optical communication components 48,
50, 52, 54, 56, 58 and the wired communication link associated with
pipe segment 62. This substantially real time information can then
be used to alter or refine the planned frac pack treatment
operation.
[0042] Even though FIG. 1 depicts a vertical well, it should be
noted by one skilled in the art that the telemetry system of the
present invention are equally well-suited for use in wells having
other directional orientations such as deviated wells, inclined
wells or horizontal wells. Accordingly, it should be apparent to
those skilled in the art that the use of directional terms such as
above, below, upper, lower, upward, downward and the like are used
in relation to the illustrative embodiments as they are depicted in
the figures, the upward direction being toward the top of the
corresponding figure and the downward direction being toward the
bottom of the corresponding figure. Also, even though FIG. 1
depicts an offshore operation, it should be noted by one skilled in
the art that the telemetry system of the present invention are
equally well-suited for use in onshore operations or other dry tree
installations.
[0043] As described above with reference to the wired communication
link disposed within pipe segment 62, the optical communication
components of the present invention can be integrated into a
telemetry system the utilizes one or more other data transmission
modes. As best seen in FIG. 6, a plurality of optical communication
components 48, 50, 52 provide bidirectional optical communications
via optically transmissive fluid medium 64 disposed within annulus
66 in the portion of the well below sea floor 16. As noted above,
as blowout preventers 24 create a discontinuity in the optically
transmissive fluid medium 64, use of another data transmission
modes therethrough is desirable. As with the embodiment of FIG. 1,
a wired communication link disposed within pipe segment 62 enables
data transmission through blowout preventers 24. In this
embodiment, however, the entire pipe string 102 from blowout
preventers 24 to platform 12 supports a wired communication link.
Use of this embodiment provides for a more a economical telemetry
system as compared to an entirely wired system by using optical
communications in the wellbore below the sea floor while only using
the wired system above the sea floor.
[0044] Referring next to FIG. 7, therein is depicted another
embodiment of a downhole telemetry system of the present invention
that integrates optical communication components with other
communication components that use different data transmission
modes. In the illustrated embodiment, a plurality of optical
communication components 54, 56, 58 provide bidirectional optical
communications via optically transmissive fluid medium 64 disposed
within annulus 66 in the portion of the well above sea floor 16.
Below sea floor 16, the illustrated telemetry system utilizes a
plurality of acoustic communication components 104, 106, 108. For
example, acoustic communication components 104, 106, 108 may be
electromechanical transducers which produce mechanical motion or
force in response to a driving electrical signal and respond to
mechanical force or motion applied to their mechanical connection
by generating an electric field which produces a voltage on its
electrical connection, such as a stack of piezoelectric disks. The
piezoelectric disks may be formed from various crystalline
materials, such as quartz, ceramic materials, PZT
(lead-zirconate-titanate), ferroelectric, relaxor ferroelectric,
electrostrictor, PMN and the like.
[0045] Upon electrical excitation, these transducers generate
vibrations, i.e. acoustic waves, the work string 30 which provide a
means of telemetering information. Specifically, after sensors 42
collect data, this data is encoded into an electrical waveform
which drives the electromechanical transducer of acoustic
communication component 104 which generates acoustic waves in work
string 30 which travel up work string 30 and are received by
acoustic communication component 106 this serves as an intermediate
repeater. Acoustic communication component 106 retransmits the data
by again generating acoustic waves in work string 30 which travel
up work string 30 and are received by acoustic communication
component 108. The received acoustic signals are converted back to
electrical signals by each of the receiving transducer and decoded
to recover the data obtained by sensors 42.
[0046] Acoustic communication component 108 feeds a digitally
encoded electrical signal to the wired communication link disposed
within pipe segment 62 which forwards the data carried in the
electrical signal to optical communication component 54 for
transmission to the surface via optical communication components
56, 58 and optically transmissive fluid medium 64 as described
above. In this manner, an acoustic telemetry system can be used for
data transmission downhole with the aid of the optical transmission
mode of the present invention to overcome the problems associates
with acoustic transmissions in the noisy environment provided in
subsea conduit 18.
[0047] Referring next to FIG. 8, therein is depicted another
embodiment of a downhole telemetry system of the present invention
that integrates optical communication components with other
communication components using multiple data transmission modes. A
plurality of optical communication components 48, 50 provide
bidirectional optical communications via optically transmissive
fluid medium 64 disposed within annulus 66 in the portion of the
well below sea floor 16. In addition, communication component 110
not only has optical communication capabilities, but is also
operable to retransmit a digital data stream via electromagnetic
waves. Specifically, communication component 110 has a transducer
for converting the digitally encoded optical data stream into an
electrical signal that is processed to establish the frequency,
power and phase output that is fed to an electromagnetic
transmitter
[0048] The electromagnetic transmitter may be a direct connect type
transmitter that utilizes an output voltage applied between two
electrical terminals that are electrically isolated from one
another to generate electromagnetic waves 112 that are radiated
into the earth carrying the information obtained by sensors 42.
Alternatively, the transmitter may include a magnetically permeable
annular core, a plurality of primary electrical conductor windings
and a plurality of secondary electrical conductor windings which
are wrapped around the annular core. Collectively, the annular
core, the primary windings and the secondary windings serve to
approximate an electrical transformer which generates
electromagnetic waves 112.
[0049] Electromagnetic waves 112 travel through the earth and are
received by subsea repeater 114 located on sea floor 16. Subsea
repeater 114 may detect either the electrical field (E-field)
component of electromagnetic waves 112, the magnetic field
(H-field) component of electromagnetic waves 112 or both. As
electromagnetic waves 112 reach subsea repeater 114, a current is
induced in subsea repeater 114 that carries the information
originally obtained by sensors 42. The current is fed to an
electronics package within subsea repeater 114 for processing.
[0050] After the electrical signal has been processed, it is
forwarded to an sonar modem 116 that will transform the electrical
signal into sound waves 118. The information may be encoded into
sound waves 118 by sonar modem 116 using, for example, frequency
shift keying (FSK) or multiple frequency shift keying (MFSK). Sound
waves 118 are transmitted through the sea carrying the information
originally obtained by sensors 42. Sound waves 118 are then picked
up by sonar modem 120 and forwarded to the surface via electric
wire 122. As with each of the above described telemetry systems,
the telemetry system described with reference to FIG. 8 may also be
used as a downlink to communicate information from the surface to a
downhole device.
[0051] While this invention has been described with a reference to
illustrative embodiments, this description is not intended to be
construed in a limiting sense. Various modifications and
combinations of the illustrative embodiments as well as other
embodiments of the invention, will be apparent to persons skilled
in the art upon reference to the description. It is, therefore,
intended that the appended claims encompass any such modifications
or embodiments.
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