US20100013663A1 - Downhole Telemetry System Using an Optically Transmissive Fluid Media and Method for Use of Same - Google Patents

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).

Description

TECHNICAL FIELD OF THE INVENTION
• 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
• Without limiting the scope of the present invention, its background is described with reference to sand control completions, as an example.
• 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.
• 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.
• 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.
• 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.
• 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
• 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.
• 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.
• 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.
• 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.
• 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.
• 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.
• 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.
• 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.
• 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.
• 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
• 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:
• 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;
• 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;
• FIG. 3 is a block diagram of a sensor for operation in the downhole telemetry system of the present invention;
• FIG. 4 is a side view of a flat pack wire bundle for use the downhole telemetry system of the present invention;
• FIG. 5 is a cross sectional view taken along line5-5 ofFIG. 4 of a flat pack wire bundle for use the downhole telemetry system of the present invention;
• 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;
• 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
• 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
• 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.
• Referring initially toFIG. 1, a downhole telemetry system including a series of optical communication components in use in a well is schematically illustrated and generally designated10. Asemi-submergible platform12 is centered over a submerged oil andgas formation14 located belowsea floor16. Asubsea conduit18 extends fromdeck20 ofplatform12 towellhead installation22 includingblowout preventers24.Platform12 has aderrick26 and ahoisting apparatus28 for raising and lowering pipe strings including awork string30.Work string30 is positioned within well32 havingcasing34 that has been secured within well32 bycement36. In the illustrated embodiment,work string30 includes a sump packer38, a gravel packing apparatus orsand screen40 including a plurality ofsensors42 and acrossover assembly44 including agravel packer46.Work string30 also includes a plurality ofoptical communication components48,50,52,54,56 and58. A wiredcommunication link60 that passes throughgravel packer46 provides a communication medium for communication betweensensors42 andoptical communication component48. Similarly, a wired communication link disposed withinpipe segment62 provides a communication medium for communication betweenoptical communication component52 andoptical communication component54 acrossblowout preventers24. Optical transmission between various optical communication components is achieved via an optically transmissive fluid medium64 disposed withinannulus66, the interior ofwork string30 or both.
• A typical completion process usinggravel packing apparatus40 having integratedsensors42 will now be described. First, theproduction interval68 adjacent toformation14 is isolated.Packer46 seals the upper end ofproduction interval68 and packer38 seals the lower end ofproduction interval68.Crossover assembly44 is located adjacent togravel packing apparatus40, traversingpacker46 with portions ofcrossover assembly44 on either side ofpacker46. When the gravel packing operation commences, the objective is to uniformly and completely fill theproduction interval68 with gravel. To help achieve this result, a wash pipe is disposed withingravel packing apparatus40. The wash pipe extends intocrossover assembly44 such that return fluid passing throughgravel packing apparatus40 may travel through the wash pipe and intoannulus66 for return to the surface.
• The fluid slurry containing gravel is pumped downwork string30 intocrossover assembly44. The fluid slurry containing gravel exitscrossover assembly44 through a series of crossover ports and is discharged intoannular interval68, such that the gravel drops out of the slurry and builds up fromformation14, filling the perforations andannular interval68 aroundgravel packing apparatus40 forming the gravel pack. Some of the carrier fluid in the slurry may leak off through the perforations intoformation14 while the remainder of the carrier fluid passes throughgravel packing apparatus40, that is sized to prevent gravel from flowing therethrough. The fluid flowing back throughgravel packing apparatus40, as explained above, flows back to the surface. This process progresses along the entire length ofgravel packing apparatus40 such thatannular interval68 becomes completely packed with the gravel. Onceannular interval68 is completely packed with gravel, the gravel pack operation may cease.
• Throughout the gravel placement process,sensors42 that are operably associated withgravel packing apparatus40 and wiredcommunication link60 are used to monitor the entire gravel packing operation and provide substantially real time data relating to the gravel placement.Sensors42 are position in a variety of circumferential, axial and radial locations relative togravel packing apparatus40. For example, as seen inFIG. 2,gravel packing apparatus40 includessensors42 positioned on the outer and inner surfaces ofbase pipe70, the outer and inner surfaces ofscreen wire72 and on the outer and inner surfaces ofwash pipe74.Sensors42 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.
• As illustrated inFIG. 3, asensor42 can be powered by abattery80. In the illustrated embodiment,sensor42 is coupled totransceiver82 that is used to transmit data and receive instructions betweensensor42 and the surface or betweensensor42 and another downhole system.Sensor42 has amicroprocessor84 associated therewith to allow for manipulation and interpretation of the sensor data and for processing the received instructions. Likewise,sensor42 is coupled to amemory86 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 anactuator88 which may be a flow control device, such as a sliding sleeve, associated withgravel packing apparatus40 to selectively permit and prevent fluid flow therethrough or which may be a safety device or other actuatable downhole device.
• Referring again toFIG. 1,sensors42 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 collectedsensors42 is encoded into electrical signals utilizing, for example, “1” and “0” for information transmission. The encoded electrical signal is then transmitted tooptical communication component48 via wiredcommunication link60.
• Optical communication component48 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 component48 emits coherent light radiation in a narrow, low-divergence monochromatic beam with a well-defined wavelength.Optical communication component48 includes a transmitter that transmits the optical data stream tooptical communication component50 that includes a receiver. The optical data stream is sent inannulus66 which contains an opticallytransmissive fluid medium64. 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 medium64 may alternatively or additionally include other suspended particles including engineered particles of glass or polymers preferably having flat surfaces or other desirable refraction surfaces.
• 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 transmissivefluid medium64. As the suspended particles in optically transmissive fluid medium64 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 theentire annulus66 with light radiation.
• In the illustrated embodiment,optical communication component50 is positioned betweenoptical communication component48 andoptical communication component52 to provide amplification and repeater functionality. Specifically,optical communication component50 is positioned relative tooptical communication component48 such that the light radiation intensity is sufficient atoptical communication component50 to read the data digitally encoded within the optical data stream. Preferably,optical communication component50 optically or electrically processes the data stream and retransmits the data stream as another digitally encoded optical data stream tooptical communication component52.
• Even thoughFIG. 1 depicts three optical communication components disposed withinwellbore32 belowsea floor16, 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.
• In the illustrated embodiment,optical communication component52 includes a transducer that converts the digitally encoded optical data stream to an electrical signal such that the data stream may be passed throughblowout preventers24. Specifically, asblowout preventers24 create a discontinuity in the optically transmissive fluid medium64, another communication mode is used. In this embodiment, a wired communication link disposed withinpipe segment62 provides a communication medium for communication betweenoptical communication component52 andoptical communication component54 acrossblowout preventers24. Specifically, as best seen inFIGS. 4 and 5, a flat packumbilical line90 may be used to provide the wired communication link. In the illustrated embodiment,umbilical line90 includes aninstrument line92, 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 ahydraulic line94. In addition,umbilical line90 includes a pair of bumper bars96,98 such as braided wire, which provides added rigidity toumbilical line90. Alternatively, instead of includinghydraulic line94, certain embodiments ofumbilical line90 could utilize a pair of instrument lines. Also, instead of being disposed withinpipe segment62, a wired communication link could alternatively be disposed exteriorly ofpipe segment62 or could be embedded or integrated withinpipe segment62.
• Continuing on the communication path depicted inFIG. 1, the encoded electrical signal is transmitted tooptical communication component54 from the wired communication link associated withpipe segment62.Optical communication component54 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 fromoptical communication component54 tooptical communication component56 inannulus100 which contains optically transmissivefluid medium64.Optical communication component56 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 tooptical communication component58.Optical communication component58 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.
• 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 withingravel packing apparatus40 such that the return path for fluids is altered. In this case, such a command can be sent to theappropriate sensor42 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 tooptical communication component58 that converts the digitally encoded electrical command into a digitally encoded optical command which is sent via optically transmissive fluid medium64 tooptical communication component56 which in turn retransmits the digitally encoded optical command for receipt byoptical communication component54. The command is then send fromoptical communication component54 tooptical communication component52 via the wired communication link disposed withinpipe segment62. The optical retransmission continues fromoptical communication component52 tooptical communication component50 and finally tooptical communication component48 which converts the digitally encoded optical command to a digitally encoded electrical command that is sent to theappropriate sensor42 via wiredcommunication link60.Actuator88 ofsensor42 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.
• 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 downwork string30, throughcrossover assembly44 intoannular interval68, through the perforations and intoformation14 without taking return fluids. During this process,sensors42 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 bysensors42 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 bysensors42 may be sent to the surface viaoptical communication components48,50,52,54,56,58 and the wired communication link associated withpipe segment62. This substantially real time information can then be used to alter or refine the planned frac pack treatment operation.
• Even thoughFIG. 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 thoughFIG. 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.
• As described above with reference to the wired communication link disposed withinpipe segment62, 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 inFIG. 6, a plurality ofoptical communication components48,50,52 provide bidirectional optical communications via optically transmissive fluid medium64 disposed withinannulus66 in the portion of the well belowsea floor16. As noted above, asblowout preventers24 create a discontinuity in the optically transmissive fluid medium64, use of another data transmission modes therethrough is desirable. As with the embodiment ofFIG. 1, a wired communication link disposed withinpipe segment62 enables data transmission throughblowout preventers24. In this embodiment, however, theentire pipe string102 fromblowout preventers24 toplatform12 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.
• Referring next toFIG. 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 ofoptical communication components54,56,58 provide bidirectional optical communications via optically transmissive fluid medium64 disposed withinannulus66 in the portion of the well abovesea floor16. Belowsea floor16, the illustrated telemetry system utilizes a plurality ofacoustic communication components104,106,108. For example,acoustic communication components104,106,108 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.
• Upon electrical excitation, these transducers generate vibrations, i.e. acoustic waves, thework string30 which provide a means of telemetering information. Specifically, aftersensors42 collect data, this data is encoded into an electrical waveform which drives the electromechanical transducer ofacoustic communication component104 which generates acoustic waves inwork string30 which travel upwork string30 and are received byacoustic communication component106 this serves as an intermediate repeater.Acoustic communication component106 retransmits the data by again generating acoustic waves inwork string30 which travel upwork string30 and are received byacoustic communication component108. The received acoustic signals are converted back to electrical signals by each of the receiving transducer and decoded to recover the data obtained bysensors42.
• Acoustic communication component108 feeds a digitally encoded electrical signal to the wired communication link disposed withinpipe segment62 which forwards the data carried in the electrical signal tooptical communication component54 for transmission to the surface viaoptical communication components56,58 and optically transmissive fluid medium64 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 insubsea conduit18.
• Referring next toFIG. 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 ofoptical communication components48,50 provide bidirectional optical communications via optically transmissive fluid medium64 disposed withinannulus66 in the portion of the well belowsea floor16. In addition,communication component110 not only has optical communication capabilities, but is also operable to retransmit a digital data stream via electromagnetic waves. Specifically,communication component110 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
• 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 generateelectromagnetic waves112 that are radiated into the earth carrying the information obtained bysensors42. 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 generateselectromagnetic waves112.
• Electromagnetic waves112 travel through the earth and are received bysubsea repeater114 located onsea floor16.Subsea repeater114 may detect either the electrical field (E-field) component ofelectromagnetic waves112, the magnetic field (H-field) component ofelectromagnetic waves112 or both. Aselectromagnetic waves112 reachsubsea repeater114, a current is induced insubsea repeater114 that carries the information originally obtained bysensors42. The current is fed to an electronics package withinsubsea repeater114 for processing.
• After the electrical signal has been processed, it is forwarded to ansonar modem116 that will transform the electrical signal intosound waves118. The information may be encoded intosound waves118 bysonar modem116 using, for example, frequency shift keying (FSK) or multiple frequency shift keying (MFSK).Sound waves118 are transmitted through the sea carrying the information originally obtained bysensors42.Sound waves118 are then picked up bysonar modem120 and forwarded to the surface viaelectric wire122. As with each of the above described telemetry systems, the telemetry system described with reference toFIG. 8 may also be used as a downlink to communicate information from the surface to a downhole device.
• 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.

Claims (25)

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 inclaim 1 further comprising a tubular string that supports the downhole transmitter and the downhole receiver.

3. The downhole telemetry system as recited inclaim 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 inclaim 1 wherein the downhole transmitter is positioned uphole of the downhole receiver.

5. The downhole telemetry system as recited inclaim 1 wherein the downhole transmitter is positioned downhole of the downhole receiver.

6. The downhole telemetry system as recited inclaim 1 wherein the data stream further comprises at least one of surface commands and downhole data.

7. The downhole telemetry system as recited inclaim 1 wherein the optically transmitted data stream further comprises at least one of light and laser.

8. The downhole telemetry system as recited inclaim 1 wherein the optically transmissive fluid further comprises a brine.

9. The downhole telemetry system as recited inclaim 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 inclaim 10 further comprising suspending particles in the optically transmissive fluid.

12. The method as recited inclaim 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 inclaim 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 inclaim 14 wherein the optically transmissive fluid further comprises a brine.

16. The downhole telemetry system as recited inclaim 14 wherein the optically transmissive fluid further comprises suspended solids.

17. The downhole telemetry system as recited inclaim 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 inclaim 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 inclaim 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 inclaim 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 inclaim 19 wherein the optically transmissive fluid further comprises a brine.

23. The downhole telemetry system as recited inclaim 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 inclaim 24 wherein the other of the first and the second transmission modes is selected from acoustic transmission, electromagnetic transmission, electrical transmission and sonar transmission.

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