US20090277629A1 - Acoustic and Fiber Optic Network for Use in Laterals Downhole - Google Patents

Acoustic and Fiber Optic Network for Use in Laterals Downhole Download PDF

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Publication number
US20090277629A1
US20090277629A1 US12/119,089 US11908908A US2009277629A1 US 20090277629 A1 US20090277629 A1 US 20090277629A1 US 11908908 A US11908908 A US 11908908A US 2009277629 A1 US2009277629 A1 US 2009277629A1
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United States
Prior art keywords
sensor
sensors
lateral
main bore
signal
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Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Abandoned
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US12/119,089
Inventor
Luis E. Mendez
Steve Rosenblatt
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Baker Hughes Holdings LLC
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Individual
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Priority to US12/119,089 priority Critical patent/US20090277629A1/en
Assigned to BAKER HUGHES INCORPORATED reassignment BAKER HUGHES INCORPORATED ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: MENDEZ, LUIS E., ROSENBLATT, STEVE
Priority to PCT/US2009/041750 priority patent/WO2009140044A2/en
Publication of US20090277629A1 publication Critical patent/US20090277629A1/en
Abandoned legal-status Critical Current

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
    • E21B41/0085—Adaptations of electric power generating means for use in boreholes
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E21B47/13—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency
    • E21B47/135—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency using light waves, e.g. infrared or ultraviolet waves
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
    • E21B47/14—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves

Definitions

  • the field of this invention is communication of information between a lateral in a wellbore and the surface through a main bore.
  • Lateral wellbores are frequently made by using a whipstock to redirect a bit to come through a casing wall and then continuing to drill and later complete one or more laterals.
  • the mill or drill makes an elongated opening in the casing wall of the main bore through which production tubing is extended after the lateral is completed.
  • Efforts to gather data from a lateral to the surface have frequently involved a continuous communication conduit as an auxiliary conduit to the production tubing and usually connected to the outside of the production tubing and extending from the lateral to the surface.
  • the problem with this approach regardless of the nature of the information conduit from the lateral to the surface is that the conduit has to go through the elongated window that was originally made to drill the lateral.
  • This window can have sharp edges or provide a pinch point where damage to the communication conduit can occur during installation or perhaps during subsequent production operations.
  • Some illustrations of hard wire systems into laterals for communication are illustrated in U.S. Pat. Nos. 6,776,636; 6,318,457; 6,902,414 and 7,165,618.
  • WO 2005/124397 illustrates the use of transducers to transmit an acoustic signal across threaded connections.
  • Main bores of wells with laterals frequently have a communication conduit from the surface that extends to the producing zone for gathering data on well conditions and for transmission of power to downhole equipment.
  • One type of such conduit is a fiber optic cable.
  • the present invention seeks to provide communication from a lateral to a main bore and preferably to a communication conduit in the main bore such as a fiber optic.
  • the lateral can feature sensors and transmitters such as acoustic transmitters that are preferably coupled with power supplies or an ability to generate power to send a coded signal from the lateral to the main bore without a hard wire going into the window for the lateral.
  • the signals can go directly from the sensor to the main bore or can be relayed through a network of sensors to the main bore to preserve signal strength and clarity such as by using sensors as repeaters in an array that extends to provide the desired coverage in the lateral.
  • Communication between a lateral and a main bore is established wirelessly preferably using sensors that transmit sensed parameters in the lateral and transmit acoustically coded messages to the main bore preferably into a fiber optic cable that extends in the main bore.
  • the sensors have stored or/and generated power and communicate from their location to the fiber optic cable in the main bore either directly or indirectly using a network of sensors to relay the information along the lateral to the fiber optic.
  • a surface processor can then associate the data from specific sensors and alternatively communicate with certain sensors to start or stop transmitting data.
  • FIG. 1 is a schematic representation of a main wellbore and a lateral showing the array of sensors that can communicate with a fiber optic conduit in the main wellbore;
  • FIG. 2 is a detailed view of a sensor assembly illustrating schematically the power supply and generation components of the assembly.
  • FIG. 1 shows a wellbore 10 with a lateral 12 and a string 14 running into the lateral 12 .
  • the main bore 16 is closed with a packer 18 .
  • a conduit 20 which preferably is a fiber optic that had been used for data transmission between downhole and the surface is still in place in main bore 16 .
  • Conduit 20 can be a single line or a unshaped line that goes down and comes back up to the surface.
  • Fasteners 21 can secure the conduit to the string 14 in a manner where the conduit 20 does not continue into the lateral 12 or the conduit 20 can be one that remained in place before the string 14 was run into the well.
  • the main could still be open or producing and is just used for illustrative purposes.
  • the conduit 20 could be in a lateral off an original bore wherein from the lateral there have been other laterals drilled.
  • the concept is as broad as delivering information from a branch to an adjacent bore from where the branch started without hard wiring a conduit for information or power delivery through the window for the lateral.
  • the conduit 20 does not run into the lateral 12 .
  • an array of sensors 22 that can monitor different downhole conditions such as temperature, pressure, pH, water or other conditions downhole that are used to determine how the well will be produced.
  • the sensors 22 need not all be unique as far as the measured variable. Redundancy is also possible so that if a given sensor has operational difficulties or a loss of power for example, there are other sensors positioned sufficiently close to act as a backup to transmit data.
  • the sensors 22 can relay information to each other in a direction toward conduit 20 to keep the data in a recognizable format when it is transmitted to the conduit 20 where it engages the string 14 in main bore 10 .
  • the initial transmitted signal is repeated to a closer sensor that is capable of receiving and repeating a signal until it reaches the conduit 20 .
  • conduit 20 as separated from string 14 for clarity, they can be in contact when for example the sensors convey information acoustically into the string 14 and that information is transmitted into conduit 20 to go to the surface.
  • the signals that originate from any given sensor can be identified as part of the transmitted signal from any sensor 22 is encoded to identify its location and orientation on string 14 .
  • FIG. 2 illustrates the details of a particular sensor 22 .
  • the first layer 24 comprises the actual sensor components for sensing the measure variable and sending out, in the preferred embodiment a coded signal that directly or indirectly moves through the lateral 12 to reach the conduit 20 and then on to the surface for processing.
  • Layer 26 is the power supply which can be a rechargeable battery. The assembly is completed with a damper layer 28 between the battery 26 and the power generation layer 30 .
  • the power generation layer can employ piezoceramic technology to generate power.
  • An electric line or wireline supporting a sonde 32 can be run in through the string 14 to make electrical contact with a battery 26 on a particular sensor 22 and recharge the battery that may have discharged.
  • Each sensor can be powered on or off with the sonde, shown schematically as 32 in FIG. 1 .
  • sonde 32 is deployed on wireline or electric line through the string 14 to make selective electrical contact with one or more sensors 22 and/or switch them on line or off line. While acoustic signals are preferred from sensors 22 use of electromagnetic signals is an alternative.

Abstract

Communication between a lateral and a main bore is established wirelessly preferably using sensors that transmit sensed parameters in the lateral and transmit acoustically coded messages to the main bore preferably into a fiber optic cable that extends in the main bore. The sensors have stored or/and generated power and communicate from their location to the fiber optic cable in the main bore either directly or indirectly using a network of sensors to relay the information along the lateral to the fiber optic. A surface processor can then associate the data from specific sensors and alternatively communicate with certain sensors to start or stop transmitting data.

Description

    FIELD OF THE INVENTION
  • The field of this invention is communication of information between a lateral in a wellbore and the surface through a main bore.
    • BACKGROUND OF THE INVENTION
  • Lateral wellbores are frequently made by using a whipstock to redirect a bit to come through a casing wall and then continuing to drill and later complete one or more laterals. The mill or drill makes an elongated opening in the casing wall of the main bore through which production tubing is extended after the lateral is completed. Efforts to gather data from a lateral to the surface have frequently involved a continuous communication conduit as an auxiliary conduit to the production tubing and usually connected to the outside of the production tubing and extending from the lateral to the surface. The problem with this approach regardless of the nature of the information conduit from the lateral to the surface is that the conduit has to go through the elongated window that was originally made to drill the lateral. This window can have sharp edges or provide a pinch point where damage to the communication conduit can occur during installation or perhaps during subsequent production operations. Some illustrations of hard wire systems into laterals for communication are illustrated in U.S. Pat. Nos. 6,776,636; 6,318,457; 6,902,414 and 7,165,618. WO 2005/124397 illustrates the use of transducers to transmit an acoustic signal across threaded connections.
  • Main bores of wells with laterals frequently have a communication conduit from the surface that extends to the producing zone for gathering data on well conditions and for transmission of power to downhole equipment. One type of such conduit is a fiber optic cable. The present invention seeks to provide communication from a lateral to a main bore and preferably to a communication conduit in the main bore such as a fiber optic. The lateral can feature sensors and transmitters such as acoustic transmitters that are preferably coupled with power supplies or an ability to generate power to send a coded signal from the lateral to the main bore without a hard wire going into the window for the lateral. The signals can go directly from the sensor to the main bore or can be relayed through a network of sensors to the main bore to preserve signal strength and clarity such as by using sensors as repeaters in an array that extends to provide the desired coverage in the lateral. These and other aspects of the present invention will be more apparent to those skilled in the art from a review of the description of the preferred embodiment and the associated drawings while recognizing that the claims describe the full scope of the invention.
    • SUMMARY OF THE INVENTION
  • Communication between a lateral and a main bore is established wirelessly preferably using sensors that transmit sensed parameters in the lateral and transmit acoustically coded messages to the main bore preferably into a fiber optic cable that extends in the main bore. The sensors have stored or/and generated power and communicate from their location to the fiber optic cable in the main bore either directly or indirectly using a network of sensors to relay the information along the lateral to the fiber optic. A surface processor can then associate the data from specific sensors and alternatively communicate with certain sensors to start or stop transmitting data.
    • BRIEF DESCRIPTION OF THE DRAWINGS
  • FIG. 1 is a schematic representation of a main wellbore and a lateral showing the array of sensors that can communicate with a fiber optic conduit in the main wellbore;
  • FIG. 2 is a detailed view of a sensor assembly illustrating schematically the power supply and generation components of the assembly.
    •  DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
  • FIG. 1 shows a wellbore 10 with a lateral 12 and a string 14 running into the lateral 12. The main bore 16 is closed with a packer 18. A conduit 20 which preferably is a fiber optic that had been used for data transmission between downhole and the surface is still in place in main bore 16. Conduit 20 can be a single line or a unshaped line that goes down and comes back up to the surface. Fasteners 21 can secure the conduit to the string 14 in a manner where the conduit 20 does not continue into the lateral 12 or the conduit 20 can be one that remained in place before the string 14 was run into the well. Those skilled in the art will appreciate that the main could still be open or producing and is just used for illustrative purposes. The conduit 20 could be in a lateral off an original bore wherein from the lateral there have been other laterals drilled. The concept is as broad as delivering information from a branch to an adjacent bore from where the branch started without hard wiring a conduit for information or power delivery through the window for the lateral.
  • The conduit 20 does not run into the lateral 12. In the lateral 12 and supported by conduit 14 are an array of sensors 22 that can monitor different downhole conditions such as temperature, pressure, pH, water or other conditions downhole that are used to determine how the well will be produced. The sensors 22 need not all be unique as far as the measured variable. Redundancy is also possible so that if a given sensor has operational difficulties or a loss of power for example, there are other sensors positioned sufficiently close to act as a backup to transmit data. Alternatively, the sensors 22 can relay information to each other in a direction toward conduit 20 to keep the data in a recognizable format when it is transmitted to the conduit 20 where it engages the string 14 in main bore 10. In essence the initial transmitted signal is repeated to a closer sensor that is capable of receiving and repeating a signal until it reaches the conduit 20. While the drawing indicates conduit 20 as separated from string 14 for clarity, they can be in contact when for example the sensors convey information acoustically into the string 14 and that information is transmitted into conduit 20 to go to the surface. At the surface, the signals that originate from any given sensor can be identified as part of the transmitted signal from any sensor 22 is encoded to identify its location and orientation on string 14.
  • FIG. 2 illustrates the details of a particular sensor 22. The first layer 24 comprises the actual sensor components for sensing the measure variable and sending out, in the preferred embodiment a coded signal that directly or indirectly moves through the lateral 12 to reach the conduit 20 and then on to the surface for processing. Layer 26 is the power supply which can be a rechargeable battery. The assembly is completed with a damper layer 28 between the battery 26 and the power generation layer 30. The power generation layer can employ piezoceramic technology to generate power. An electric line or wireline supporting a sonde 32 can be run in through the string 14 to make electrical contact with a battery 26 on a particular sensor 22 and recharge the battery that may have discharged. Each sensor can be powered on or off with the sonde, shown schematically as 32 in FIG. 1. Those skilled in the art will recognize that sonde 32 is deployed on wireline or electric line through the string 14 to make selective electrical contact with one or more sensors 22 and/or switch them on line or off line. While acoustic signals are preferred from sensors 22 use of electromagnetic signals is an alternative.
  • The above description is illustrative of the preferred embodiment and many modifications may be made by those skilled in the art without departing from the invention whose scope is to be determined from the literal and equivalent scope of the claims below:

Claims (20)

1. A method for monitoring at least one well condition in a lateral extending from a wellbore:
placing at least one sensor on a string extending from the main bore and into the lateral;
transmitting a signal of a sensed variable in the lateral from said sensor and into said main bore without a hard wired connection.
2. The method of claim 1, comprising:
transmitting the signal received in the main bore to the surface on a conduit.
3. The method of claim 2, comprising:
providing a fiber optic cable as said conduit.
4. The method of claim 3, comprising:
transmitting an acoustic or electromagnetic signal from said sensor.
5. The method of claim 4, comprising:
providing a plurality of sensors as said at least one sensor;
relaying a given signal from one sensor to at least one other sensor in the lateral before the signal reaches the main bore.
6. The method of claim 5, comprising:
providing a power generating capability with at least one of said sensors.
7. The method of claim 6, comprising:
providing a power storage capability with at least one of said sensors.
8. The method of claim 7, comprising:
charging said power storage device through said string.
9. The method of claim 7, comprising:
providing redundant sensors to measure the same variable;
switching, via said string, power on to one sensor after power at another sensor sensing the same variable has stopped transmitting.
10. The method of claim 4, comprising:
coding a signal from a given sensor so that its location can be identified with a surface processor.
11. The method of claim 8, comprising:
delivering a sonde into said string to perform said charging.
12. The method of claim 6, comprising:
using a piezoceramic power generator with said power storage capability.
13. The method of claim 1, comprising:
receiving said signal in said main bore with a fiber optic cable.
14. The method of claim 1, comprising:
transmitting an acoustic or electromagnetic signal from said sensor.
15. The method of claim 1, comprising:
providing a plurality of sensors as said at least one sensor;
relaying a given signal from one sensor to at least one other sensor in the lateral before the signal reaches the main bore.
16. The method of claim 1, comprising:
providing a power generating capability with at least one of said sensors.
17. The method of claim 16, comprising:
providing a power storage capability with at least one of said sensors.
18. The method of claim 17, comprising:
charging said power storage device through said string.
19. The method of claim 1, comprising:
providing redundant sensors to measure the same variable;
switching, via said string, power on to one sensor after power at another sensor sensing the same variable has stopped transmitting.
20. The method of claim 1, comprising:
coding a signal from a given sensor so that its location can be identified with a surface processor.
US12/119,089 2008-05-12 2008-05-12 Acoustic and Fiber Optic Network for Use in Laterals Downhole Abandoned US20090277629A1 (en)

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PCT/US2009/041750 WO2009140044A2 (en) 2008-05-12 2009-04-27 Acoustic and fiber optic network for use in laterals downhole

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US20130076526A1 (en) * 2011-09-23 2013-03-28 Baker Hughes Incorporated System and method for correction of downhole measurements
US20140022537A1 (en) * 2010-07-19 2014-01-23 Halliburton Energy Services, Inc. Communication through an enclosure of a line
US20140126331A1 (en) * 2012-11-08 2014-05-08 Halliburton Energy Services, Inc. Acoustic telemetry with distributed acoustic sensing system
US20140144226A1 (en) * 2010-11-01 2014-05-29 David Sirda Shanks Distributed Fluid Velocity Sensor and Associated Method
WO2014085935A1 (en) * 2012-12-07 2014-06-12 Evolution Engineering Inc. Back up directional and inclination sensors and method of operating same
US8930143B2 (en) 2010-07-14 2015-01-06 Halliburton Energy Services, Inc. Resolution enhancement for subterranean well distributed optical measurements
US9541665B2 (en) 2011-09-30 2017-01-10 Zenith Oilfield Technology Limited Fluid determination in a well bore
US9541436B2 (en) 2011-11-22 2017-01-10 Lufkin Industries, Llc Distributed two dimensional fluid sensor
US20170167245A1 (en) * 2014-01-31 2017-06-15 Schlumberger Technology Corporation Monitoring of equipment associated with a borehole/conduit
US10006269B2 (en) 2013-07-11 2018-06-26 Superior Energy Services, Llc EAP actuated valve
US10107789B2 (en) 2013-03-11 2018-10-23 Zenith Oilfield Technology Limited Multi-component fluid determination in a well bore
US10329898B2 (en) 2010-11-19 2019-06-25 Zenith Oilfield Technology Limited High temperature downhole gauge system
US10386536B2 (en) 2011-09-23 2019-08-20 Baker Hughes, A Ge Company, Llc System and method for correction of downhole measurements
US20230417535A1 (en) * 2020-04-17 2023-12-28 Huvr, Inc Extended Reach Ring Interferometer with Signal Antifading Topology for Event Detection, Location and Characterization
US20240084673A1 (en) * 2022-09-08 2024-03-14 Saudi Arabian Oil Company Method for downhole installation of batteries with recharging and energy harvesting systems in dedicated compartments

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US8930143B2 (en) 2010-07-14 2015-01-06 Halliburton Energy Services, Inc. Resolution enhancement for subterranean well distributed optical measurements
US20140022537A1 (en) * 2010-07-19 2014-01-23 Halliburton Energy Services, Inc. Communication through an enclosure of a line
US9003874B2 (en) * 2010-07-19 2015-04-14 Halliburton Energy Services, Inc. Communication through an enclosure of a line
US20140144226A1 (en) * 2010-11-01 2014-05-29 David Sirda Shanks Distributed Fluid Velocity Sensor and Associated Method
US10329898B2 (en) 2010-11-19 2019-06-25 Zenith Oilfield Technology Limited High temperature downhole gauge system
US20130076526A1 (en) * 2011-09-23 2013-03-28 Baker Hughes Incorporated System and method for correction of downhole measurements
US10386536B2 (en) 2011-09-23 2019-08-20 Baker Hughes, A Ge Company, Llc System and method for correction of downhole measurements
US9541665B2 (en) 2011-09-30 2017-01-10 Zenith Oilfield Technology Limited Fluid determination in a well bore
US9541436B2 (en) 2011-11-22 2017-01-10 Lufkin Industries, Llc Distributed two dimensional fluid sensor
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US9823373B2 (en) * 2012-11-08 2017-11-21 Halliburton Energy Services, Inc. Acoustic telemetry with distributed acoustic sensing system
EA034026B1 (en) * 2012-12-07 2019-12-19 Иволюшн Енджиниринг Инк. Downhole probe assembly and elements thereof
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US10107789B2 (en) 2013-03-11 2018-10-23 Zenith Oilfield Technology Limited Multi-component fluid determination in a well bore
US10006269B2 (en) 2013-07-11 2018-06-26 Superior Energy Services, Llc EAP actuated valve
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