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WO2004001356A2 - Technique et systeme de mesure d'une caracteristique dans un puits souterrain - Google Patents

Technique et systeme de mesure d'une caracteristique dans un puits souterrain Download PDF

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Publication number
WO2004001356A2
WO2004001356A2 PCT/US2003/019395 US0319395W WO2004001356A2 WO 2004001356 A2 WO2004001356 A2 WO 2004001356A2 US 0319395 W US0319395 W US 0319395W WO 2004001356 A2 WO2004001356 A2 WO 2004001356A2
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WIPO (PCT)
Prior art keywords
sensor
optical fiber
temperature
measure
characteristic
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Ceased
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PCT/US2003/019395
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English (en)
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WO2004001356A3 (fr
Inventor
Robert J. Schroeder
Jeffrey Tarvin
Rogerio T. Ramos
George A. Brown
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Sensor Highway Ltd
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Sensor Highway Ltd
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Priority claimed from US10/176,858 external-priority patent/US20030234921A1/en
Application filed by Sensor Highway Ltd filed Critical Sensor Highway Ltd
Priority to CA2490107A priority Critical patent/CA2490107C/fr
Priority to GB0423903A priority patent/GB2406168B/en
Priority to AU2003261080A priority patent/AU2003261080A1/en
Publication of WO2004001356A2 publication Critical patent/WO2004001356A2/fr
Publication of WO2004001356A3 publication Critical patent/WO2004001356A3/fr
Priority to NO20045112A priority patent/NO20045112L/no
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01D—MEASURING NOT SPECIALLY ADAPTED FOR A SPECIFIC VARIABLE; ARRANGEMENTS FOR MEASURING TWO OR MORE VARIABLES NOT COVERED IN A SINGLE OTHER SUBCLASS; TARIFF METERING APPARATUS; MEASURING OR TESTING NOT OTHERWISE PROVIDED FOR
    • G01D5/00—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable
    • G01D5/26—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light
    • G01D5/32—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light with attenuation or whole or partial obturation of beams of light
    • G01D5/34—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light with attenuation or whole or partial obturation of beams of light the beams of light being detected by photocells
    • G01D5/353—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light with attenuation or whole or partial obturation of beams of light the beams of light being detected by photocells influencing the transmission properties of an optical fibre
    • G01D5/35383—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light with attenuation or whole or partial obturation of beams of light the beams of light being detected by photocells influencing the transmission properties of an optical fibre using multiple sensor devices using multiplexing techniques
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure
    • E21B47/07—Temperature
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01D—MEASURING NOT SPECIALLY ADAPTED FOR A SPECIFIC VARIABLE; ARRANGEMENTS FOR MEASURING TWO OR MORE VARIABLES NOT COVERED IN A SINGLE OTHER SUBCLASS; TARIFF METERING APPARATUS; MEASURING OR TESTING NOT OTHERWISE PROVIDED FOR
    • G01D5/00—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable
    • G01D5/26—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light
    • G01D5/32—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light with attenuation or whole or partial obturation of beams of light
    • G01D5/34—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light with attenuation or whole or partial obturation of beams of light the beams of light being detected by photocells
    • G01D5/353—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light with attenuation or whole or partial obturation of beams of light the beams of light being detected by photocells influencing the transmission properties of an optical fibre
    • G01D5/35306—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light with attenuation or whole or partial obturation of beams of light the beams of light being detected by photocells influencing the transmission properties of an optical fibre using an interferometer arrangement
    • G01D5/35309—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light with attenuation or whole or partial obturation of beams of light the beams of light being detected by photocells influencing the transmission properties of an optical fibre using an interferometer arrangement using multiple waves interferometer
    • G01D5/35316—Mechanical means for transferring the output of a sensing member; Means for converting the output of a sensing member to another variable where the form or nature of the sensing member does not constrain the means for converting; Transducers not specially adapted for a specific variable characterised by optical transfer means, i.e. using infrared, visible, or ultraviolet light with attenuation or whole or partial obturation of beams of light the beams of light being detected by photocells influencing the transmission properties of an optical fibre using an interferometer arrangement using multiple waves interferometer using a Bragg gratings
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01K—MEASURING TEMPERATURE; MEASURING QUANTITY OF HEAT; THERMALLY-SENSITIVE ELEMENTS NOT OTHERWISE PROVIDED FOR
    • G01K11/00—Measuring temperature based upon physical or chemical changes not covered by groups G01K3/00, G01K5/00, G01K7/00 or G01K9/00
    • G01K11/32—Measuring temperature based upon physical or chemical changes not covered by groups G01K3/00, G01K5/00, G01K7/00 or G01K9/00 using changes in transmittance, scattering or luminescence in optical fibres
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01K—MEASURING TEMPERATURE; MEASURING QUANTITY OF HEAT; THERMALLY-SENSITIVE ELEMENTS NOT OTHERWISE PROVIDED FOR
    • G01K11/00—Measuring temperature based upon physical or chemical changes not covered by groups G01K3/00, G01K5/00, G01K7/00 or G01K9/00
    • G01K11/32—Measuring temperature based upon physical or chemical changes not covered by groups G01K3/00, G01K5/00, G01K7/00 or G01K9/00 using changes in transmittance, scattering or luminescence in optical fibres
    • G01K11/3206—Measuring temperature based upon physical or chemical changes not covered by groups G01K3/00, G01K5/00, G01K7/00 or G01K9/00 using changes in transmittance, scattering or luminescence in optical fibres at discrete locations in the fibre, e.g. using Bragg scattering
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N21/00—Investigating or analysing materials by the use of optical means, i.e. using sub-millimetre waves, infrared, visible or ultraviolet light
    • G01N21/62—Systems in which the material investigated is excited whereby it emits light or causes a change in wavelength of the incident light
    • G01N21/63—Systems in which the material investigated is excited whereby it emits light or causes a change in wavelength of the incident light optically excited
    • G01N21/65—Raman scattering

Definitions

  • the invention generally relates to a technique and system for measuring temperature in a subterranean well.
  • DTS distributed temperature sensor
  • the optical fiber When used as a sensor, the optical fiber is deployed downhole so that the optical fiber extends into the region where temperature measurements are to be made.
  • the optical fiber may be deployed downhole with the well casing string or deployed downhole in a conduit that may extend through the central passageway of the casing string.
  • an optical time domain reflectometry (OTDR) technique may be used to detect the spatial distribution of temperature along the length of an optical fiber. More specifically, pursuant to the OTDR technique, temperature measurements may be made by introducing optical energy into the optical fiber by opto-electronics at the surface of the well. The optical energy that is introduced into the optical fiber produces backscattered light.
  • backscattered light refers to the optical energy that returns at various points along the optical fiber back to the opto-electronics at the surface of the well. More specifically, in accordance with OTDR, a pulse of optical energy typically is introduced to the optical fiber at the well surface, and the resultant backscattered optical energy that returns from the fiber to the surface is observed as a function of time. The time at which the backscattered light propagates from the various points along the fiber to the surface is proportional to the distance along the fiber from which the backscattered light is received.
  • the intensity of the backscattered light as observed from the surface of the well exhibits an exponential decay with time. Therefore, knowing the speed of light in the fiber yields the distances that the light has traveled along the fiber. Variations in the temperature show up as variations from a perfect exponential decay of intensity with distance. Thus, these variations are used to derive the distribution of temperature along the optical fiber.
  • the backscattered light includes the Rayleigh spectrum, the Brillouin spectrum and the Raman spectrum.
  • the Raman spectrum is the most temperature sensitive with the intensity of the spectrum varying with temperature, although all three spectrums of the backscattered light contain temperature information.
  • the Raman spectrum typically is observed to obtain a temperature distribution from the backscattered light.
  • OFDR optical frequency domain reflectometry
  • FBGs fiber Bragg gratings
  • An FBG- based temperature measurement system is described in, for example, U.S. Patent No. 5,380,995. These Bragg gratings may also measure strain.
  • Fiber Bragg gratings are manufactured by a variety of methods inside the core of standard telecommunications grade single mode fiber.
  • a standard single mode fiber 1 includes an eight micron diameter core glass material 2 that is surrounded by a 125 micron cladding glass material 3, of a different index of refraction, that gives the fiber 1 its waveguide properties.
  • a fiber Bragg grating 4 is photowritten onto the core material 2 by ultraviolet laser radiation and represents a 4-6mm long periodic modulation in the core's index of refraction by approximately 0.01%.
  • ⁇ and p e are the thermal optics (dn/dT) coefficient and the photo elastic coefficient, respectively.
  • the FBG has demonstrated linear response down to nanostrain levels and up to 500 degrees Centigrade.
  • the period of modulation in the index of refraction can be adjusted to produce multiple FBGs on a single fiber each with a unique center Bragg wavelength, ⁇ .
  • the FBG-based system is therefore suitable for a multi-sensing system with a single optical fiber line because wavelength domain multiplexing (WDM) and time domain multiplexing (TDM) can be applied.
  • Fig. 2 depicts a conventional system 5 that uses FBGs.
  • the system 5 includes an incoherent broadband light source 6 (with 50nm bandwidth) that is inserted into a fiber optic cable 7 that has several FBG's 8 written onto it at different spatial locations.
  • the system 5 also includes a detection subsystem 9.
  • Each FBG 8 reflects a narrow band fraction (typically, 0.2 nanometers) of the broadband source light with a unique wavelength (D,D ⁇ encoded tag.
  • the FBG's may be a few millimeters or kilometers apart, but they will maintain the same wavelength separation.
  • the center Bragg wavelength will move to shorter or longer wavelengths, independently of the others, and it is this wavelength change that is measured by the demodulation detection system shown. Fig.
  • FIG. 3 shows a spectral waveform 12 of a single Bragg grating as a function of wavelength. Also depicted in Fig. 3 is a waveform 10 of the source light emitting diode (LED) 12.
  • the demodulation system is attached via a fiber optic beamsplitter where a fraction of the returned light from the FBG is diverted from its return to the light source and into the demodulation system.
  • Fig. 4 depicts the reflection response of two FBG's (depicted by spectral waveforms 13 and 14) when illuminated with a broadband light emitting diode (having a spectral waveform 15) in the near infrared band centered at 1300 nanometers.
  • sensors to measure physical and chemical sensors include interferometric sensors and attenuation based sensors.
  • a technique that is usable in a subterranean well includes deploying a first sensor in a remote location to measure a distribution of a characteristic along a segment at the location.
  • the technique includes deploying a second sensor downhole to measure the characteristic at discrete points within the segment. The second sensor is separate from the first sensor.
  • FIG. 1 is a schematic diagram of a fiber Bragg grating inside a single mode optical fiber of the prior art.
  • Fig. 2 is a schematic diagram of a Bragg grating sensor system of the prior art.
  • Fig. 3 is an illustration of a wavelength spectrum of a single Bragg grating of the prior art.
  • Fig. 4 is an illustration of the reflection spectrum of two wavelength separated Bragg gratings along with an LED light source spectrum of the prior art.
  • Figs. 5, 6 and 9 are schematic diagrams of systems to measure the temperature inside a subterranean well according to different embodiments of the invention.
  • Fig. 7 is a flow diagram depicting a technique to measure temperature inside a subterranean well according to an embodiment of the invention.
  • Fig. 8 is a flow diagram depicting a technique to measure a flow velocity in a subterranean well according to an embodiment of the invention.
  • Fig. 10 is a schematic diagram of a single mode optical fiber according to an embodiment of the invention.
  • a temperature measurement system 19 for a subterranean well includes at least two types of temperature measurement subsystems, each of which is associated with a different and separate downhole temperature sensor.
  • One of these temperature measurement subsystems may be a distributed temperature sensor (DTS)-based temperature measurement system that observes the intensity of backscattered light from an optical fiber 38 that extends into a wellbore 18 of the well.
  • Another one of the temperature measurement subsystems may be a fiber Bragg grating (FBG)-based temperature measurement system that observes the spectral energy of light that is reflected from FBGs that are embedded in an optical fiber 34 that extends into the wellbore 18.
  • DTS distributed temperature sensor
  • FBG fiber Bragg grating
  • DTS-based temperature measurement systems within the oil industry has had significant acceptance. Unlike any combination of discrete electrical or fiber optic sensors, the DTS system produces a unique distributed measurement of temperature that cannot be achieved by any other technology. This application has been especially accelerated in permanent installations for vertical and deviated oil wells, where a single "snapshot" of the geothermal profile of the entire well length can be taken in a few minutes.
  • the typical geothermal gradient is 3 to 6 degrees C per 30 meters of depth.
  • DTS results In addition to measurements of the geothermal gradient, for production logging purposes, analysis of DTS results has replaced the traditional wireline temperature measurement for the location of open channels in cement behind casing, fluid entries in perforated wells and fluid front movement in steam-injected wells. These are typical production monitoring applications where the measurement precision of a typical DTS system, typically 0.5 degree C but as low as 0.1 degree C would be acceptable. Other production quantities, such as the temperature profile near an electrical submersible pump (ESP) to produce artificial lift, has had a great diagnostic benefit. Near positions where the reservoir fluid enters the wellbore, very small thermal changes can occur over extended periods of time that can indicate fluid movement at a distance away from the wellbore.
  • ESP electrical submersible pump
  • a temperature measurement with a minimum 0.1 degree C resolution and as low as millidegrees is required.
  • the resolution afforded by a fiber optic temperature sensor based on FBG sensor element can achieve this level of measurement quality.
  • the spatial resolution from the FBG sensor element placement can be as low as millimeters.
  • DTS systems typically give a true minimum spatial resolution of 1 meter.
  • an array of FBGs within a vertical or deviated well can be optimized to minimize sensor and deployment costs.
  • high precision discrete sensors may be required to measure the temperature changes induced by produced fluids.
  • cost or complexity may limit the number of discrete sensors, so that they are widely spaced or monitor only a small part of the well.
  • a DTS system can monitor the rest of the well, to detect or quantify events that can cause larger changes in temperature, such as fluid arriving from a different vertical depth or fluids of different temperature injected into the formation by another well.
  • the system 19 provides a way to measure both small and large temperature variations simultaneously.
  • the system 19 delivers the thermal profile of the entire well, along with an optimized placement of highly precise and accurate sensor arrays in a specified zone of interest in the well.
  • a distributed measurement such as temperature
  • discrete measurements i.e. temperature
  • One application for the combination of a distributed and multi -point temperature array to provide coarse and fine resolutions for the measurement of temperature is in extended reach oil wells, i.e., wells that exceed 5 kilometers in length.
  • extended reach oil wells i.e., wells that exceed 5 kilometers in length.
  • the resolution of the system decreases with the fiber distance from the DTS electronics.
  • the DTS opto-electronics has typically a dynamic range of 20dB.
  • the maximum DTS range would be 10 km. Acquiring measurements beyond some range can become difficult due to lack of sufficient signal.
  • Bragg grating technology which operates in a more favorable wavelength range where the attenuation per unit length is less than 0.5dB/km and where the power return is significantly greater than from the Raman process, can produce 0.010 degree C precision at distances to 20km or greater.
  • the most interesting location for high precision temperature measurements is at the farthest or most extended reach of the oil well.
  • DTS-like system e.g. Raman or Brillouin
  • a Bragg based temperature sensor array or arrays in one or more zones, that can provide 1) a measurement and/or 2) better resolution and accuracy.
  • the combination of a distributed and multi-point temperature array to provide coarse and fine resolutions for the measurement of temperature may be used in any application requiring a higher degree of resolution and/or accuracy than provided by a stand-alone distributed temperature measurement.
  • Another such application is the determination of fluid velocity as previously disclosed.
  • the DTS-based temperature measurement system uses an optical time domain reflectometry (OTDR) technique to measure a temperature distribution along a region (the entire length, for example) of the optical fiber 38.
  • OTDR optical time domain reflectometry
  • the DTS-based temperature measurement system is capable of providing a spatial distribution of thousands of temperatures measured in a region of the well along which the optical fiber 38 extends.
  • OTDR optical time domain reflectometry
  • a DTS-based temperature measurement system other that OTDR, such as OFDR, may be used in other embodiments of the invention.
  • a Brillouin spectrum-based DTS system may be used in some embodiments of the invention (instead of Raman).
  • a Rayleigh spectrum-based DTS system may be used, etc.
  • the DTS temperature measurement system may be limited to a temperature resolution of about 0.1° Celsius (C). This means that, in this scenario, the DTS temperature measurement system cannot be relied on to resolve temperature differences less than 0.1° C.
  • This resolution limit may affect the measurement of various well properties, such as (for example) the determination of a fluid velocity inside a particular zone in the well.
  • a tubular member 40 may be inserted into the wellbore 18, and this tubular member 40 may extend into the zone 50.
  • the tubular member 40 has ports 42 through which a temperature-altering fluid may be introduced into the zone 50 for purposes of creating a temperature pocket, or spot, in the zone 50.
  • a relatively cool fluid may be introduced into the zone 50 for purposes of creating a cool spot in the zone 50.
  • the fluid velocity may be determined by observing the movement of this spot.
  • the cool spot may be quite small, and may not be detectable due to the resolution constraints of the DTS-based temperature measurement system.
  • the tubular member 40 may alternatively include a heater coil for purposes of injecting a hot spot (instead of a cold spot) into the zone to accomplish the above-described temperature movement observation.
  • flow velocity may also be determined in a lateral, or generally horizontal, wellbore.
  • the optical fiber 34 of the FBG-based temperature measurement system includes an array of fiber Bragg gratings (FBGs) 36, such as the FBGs 36 that are depicted inside the zone 50 of Fig. 1.
  • FBGs fiber Bragg gratings
  • each FBG 36 provides one temperature measurement, and this temperature measurement has a resolution of about 10 millidegrees Celsius (m°C), a resolution that may overcome the resolution limits of the above-described DTS-based temperature measurement system.
  • m°C millidegrees Celsius
  • a method to increase the fundamental thermal resolution of a FBG is described in US Patent Number 6,246,048 by utilizing the strain response of a Bragg grating by coupling the FBG to a material with a large Coefficient of Thermal Expansion.
  • the DTS-based temperature measurement system may tend to lose resolution over greater lengths (above 7 kilometers (km), for example), whereas the FBG-based measurement system may suffer little degradation in temperature readings for lengths of 20 km or more.
  • the FBG-based temperature measurement system in some embodiments of the invention, may provide temperature measurements in the order of seconds, as compared to the temperature distribution from the DTS-based temperature measurement system that may take in the order of minutes.
  • the array may include several FBGs 36 that are spaced over a particular zone of interest, such as the zone 50. Each FBG 36 provides a temperature measurement.
  • Each FBG 36 reflects at a Bragg wavelength, l c , and the wavelengths that the FBG 36 reflects is a function of the effective core index of refraction, ri c and the period of the index modulation, L of the FBG 36 as described by Eq 1. Therefore, temperature affects the wavelength location of the spectral band of energy that is reflected by the FBG 36. Thus, a temperature may be measured via a particular FBG 36 by introducing optical energy (into the optical fiber 34) that has wavelengths that include the possible wavelengths of the reflected spectral band. The wavelengths of the reflected spectral band are then observed to derive a temperature measurement at the location of the FBG 36 as described by Eq 2.
  • each FBG may have a different grating spacing or wavelength l c for purposes of distinguishing one FBG-based measurement from another.
  • each FBG may have the same grating spacing or wavelength l c and the array of FBG 36 is distinguished via time.
  • Other FBG interrogations electronics or combinations of interrogation methods are possible and not excluded by this invention.
  • more than one FBG array 36 may be incorporated at different zones of interest along the optical fiber 34.
  • each FBG may be relatively expensive to make on a per unit length of fiber basis.
  • the FBG 36 are located only in certain zones of interest along the optical fiber 34.
  • the DTS-based measurement system may be used to obtain temperature measurements outside of regions in which the FBG arrays 36 of the optical fiber 34 are located.
  • the FBG arrays 36 may be used to obtain discrete, higher resolution measurements in a particular zone of the well, and the optical fiber 38 may be used to obtain spatially distributed, lower resolution measurements outside of these zones.
  • the measurements from both temperature measurement systems may be selectively combined to yield a spatially distributed set of temperature measurements that have high resolution where desired.
  • the FBG-based temperature system may provide more accurate temperature measurements than the measurements that are provided by the DTS-based temperature measurement system.
  • the measurements from these two temperature measurement systems may be combined for purposes of increasing the accuracy of temperature measurements from a particular zone, such as the zone 50.
  • the measurements derived from the DTS temperature measurement system along a particular region of the wellbore may be combined with the measurements derived from the FBG-based temperature measurement system along the same region.
  • the FBG measurements may be used to correct any discrepancies in the DTS measurements for the given interval.
  • the FBG system has a higher accuracy than the DTS system.
  • a processor 20 may execute a program 32 that is stored in a memory 30 for purposes of performing the FBG and DTS based temperature measurements.
  • the processor 20 may control a demodulation system (spectrum analyzer for example) 28 and two wavelength-tunable light sources 22 and 24.
  • the system 19 may also include other optical components not shown in Fig. 5.
  • the system 19 may include a directional coupler and optical filtering subsystem.
  • the system 19 may include a single light source (instead of two) that is multiplexed between the optical fibers 34 and 38.
  • the processor 20 may control the light source 22 so that the light source 22 emits pulses of light at a predefined wavelength (a Stokes wavelength, for example) into the optical fiber 38.
  • a predefined wavelength a Stokes wavelength, for example
  • the demodulation system 28 measures the intensity of the resultant backscattered light at the predefined wavelength.
  • the processor 20 processes the intensities that are detected by the optical spectrum analyzer 28 to calculate the temperature distribution along some portion (the entire length, for example) of the optical fiber 38.
  • the processor 20 also operates the light source 24 to introduce optical energy into the optical fiber 34 at the appropriate frequencies/wavelengths.
  • the processor 20, via the demodulation system 28, uses the array of FBGs 36 to obtain temperature measurements at discrete points, each of which is associated with a particular FBG 36.
  • the spatial locations of the FBGs 36 may be distinguishable, in some embodiments of the invention, by the different wavelength or time delay that is associated with each FBG 36.
  • the FBGs 36 are installed in a strain free manner, and they may be mechanically enhanced for better temperature resolution.
  • the FBGs may be interrogated in a variety and combination of ways, such as wavelength division multiplexing (WDM), time division multiplexing (TDM), or systems to interrogate a series of weak or low reflectivity Bragg gratings with a reference interferometer as described in US Patent Number 5,798,521 and developed by the US space agency NASA.
  • WDM wavelength division multiplexing
  • TDM time division multiplexing
  • both sensors 34 and 38 are deployed in control conduits that may be clamped to a tubular string (such as the tubular member 40) or located outside of the casing string 18.
  • the system 19 maybe replaced by the system 60.
  • the two systems 10 and 60 are similar, except that the single- ended optical fiber 38 of Fig. 1 is replaced by a U-shaped, double-ended optical fiber 39.
  • the U-shaped optical fiber 39 extends along the length of the wellbore 18 and returns at its bottom point 63 to the surface of the well so that the two ends of the fiber 39 are present at the surface of the well. This arrangement may be particularly desirable due to the resultant increase in accuracy.
  • the optical fiber 39 provides two sets of measurements that may be combined together to improve the accuracy of DTS measurements from the optical fiber 39. Furthermore, should one of the strands become damaged, the remaining strand may be used in a single-ended mode.
  • a technique 80 may be used for purposes of integrating the temperature measurements provided by both temperature measurement subsystems to enhance the accuracy/resolution of these measurements. More specifically, in some embodiments of the invention, in the technique 80, the DTS (i.e., the optical fiber 38) is deployed downhole, as depicted in block 82. Also, the FBG-based sensor (i.e., the optical fiber 34 having the embedded FBGs 36) is deployed downhole in the zone 50 or zones 50, as depicted in block 84. As described above, the FBG-based sensor may be used to measure temperatures at discrete points in the zone 50 or zones 50, and the DTS may be used to measure a temperature distribution inside and outside of the zone 50.
  • the DTS i.e., the optical fiber 38
  • the FBG-based sensor i.e., the optical fiber 34 having the embedded FBGs 36
  • the discrete temperature measurements provided by the FBG-based temperature measurements generally provide higher resolution and more accurate readings in the zone 50.
  • the processor 20 may combine both sets of measurements together. For purposes of resolving small temperatures (i.e., temperatures less than 0.1° C), the processor 20 may, for the zone 50, use only the measurements that are provided by the FBGs 36 and use the temperature measurements provided by the DTS outside of the zone 50. To perform the temperature measurements, averaging and selective substitution of the temperature measurements, the processor 20 may execute a program such as the program 36 (stored in the memory 30).
  • a technique 100 may be used for purposes of performing a technique 100 to determine a flow velocity inside the zone 50.
  • a thermal, or temperature, spot is injected (block 102) into a particular zone, such as the zone 50 (Fig. 5).
  • This temperature spot has a temperature that is different from the overall temperature of the zone so that the temperature spot may be detected.
  • the movement of a naturally-occurring temperature spot or an artificially-injected temperature spot may be observed in the zone 50.
  • the DTS- based temperature measurement system may be used to track the temperature spot inside and outside of the zone 50, as depicted in block 104, and the FBG-based temperature measurement system may be used to track movement of the spot inside the zone 50, as depicted in block 106. From this observed movement of the spot, the processor 20 (Fig. 5) may then calculate (block 108) the flow velocity in a particular of the well, such as in the zone 50.
  • a vertical wellbore 18 is depicted in Fig. 8, the above-described temperature measurement techniques may be used in lateral wellbores.
  • Fig. 9 depicts a system 200 for use in a lateral wellbore 202.
  • the optical fiber 38 may be used for purposes of obtaining temperature measurements outside of the zone 204; and inside the zone 204, the optical fiber 34 with its FBGs 36 may be used for purposes of obtaining higher resolution temperature measurements.
  • both optical fibers 34 and 38 may be used for purposes of obtaining temperature measurements inside and outside of the zone 204; and these measurements may be combined together.
  • the single-ended fiber 38 depicted in Fig. 5 maybe replaced by a double-ended fiber, in some embodiments of the invention. Other embodiments are within the scope of the following claims.
  • one or both of the sensors may be pumped downhole with a fluid for purposes of running the sensor 38 and/or sensor 34 downhole.
  • a conduit may be run downhole, and fluid may be pumped through the passageway of the conduit.
  • the lower end of the sensor 38 may be introduced into the fluid flow and for purposes of permitting the fluid flow to unwind the sensor 38 and/or sensor 34 from a spool at the surface of the well to carry the sensor 38 downhole.
  • the system 19 may be used in environments other than in a subterranean well.
  • the system 19 may be used to measure temperature along a segment (a pipe, for example) of a remote location.
  • the system 18 may be used in conjunction with power cables or pipelines.
  • this remote location may include chemical processing equipment of a chemical plant (for example) or food processing equipment of a food processing/preparation plant (for example). Other remote locations are possible.
  • the system 19 may measure a characteristic other than temperature.
  • the DTS-based measurement may measure a distribution of stress
  • the FBG-based measurement system may measure the stress at specific points. Characteristics other than temperature and/or stress may be measured, in other embodiments of the invention.
  • the zone 50 may include part of a formation, an entire formation, several formations, etc.
  • the DTS-based and FBG-based measurement systems may be used to obtain production as well as reservoir information from the wellbore.
  • DTS is used only to obtain production data (data from the flowing fluid).
  • FBGs which give much better resolution, can be used to obtain reservoir data (data about the fluids while they are still in the reservoir).
  • both sensors 34 and 38 may be formed from a single, single mode optical fiber 300 that is depicted in Fig. 10.
  • the FBG array 300 may be attached via an adhesive to a bottom segment 304 of the optical sensor 34.
  • the sensors 34 and 38 are deemed as being formed from a single optical fiber shared in common even if the sensors 34 and 38 are formed from different optical fiber segments that are concatenated to form the single optical fibers.

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  • Physics & Mathematics (AREA)
  • General Physics & Mathematics (AREA)
  • Geology (AREA)
  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Geophysics (AREA)
  • Measuring Temperature Or Quantity Of Heat (AREA)
  • Geophysics And Detection Of Objects (AREA)
  • Investigating Or Analyzing Materials By The Use Of Electric Means (AREA)

Abstract

Cette invention se rapporte à une technique (80, 100) utilisable dans un puits souterrain et consistant à déployer un premier capteur (38) à un emplacement distant, pour mesurer la répartition d'une caractéristique le long d'un segment (50) à cet emplacement. Cette technique (80, 100) consiste à déployer un second capteur (34) dans le trou de forage, pour mesurer ladite caractéristique en des points distincts du segment (50). Ce second capteur (34) est séparé du premier capteur (38).
PCT/US2003/019395 2002-06-21 2003-06-19 Technique et systeme de mesure d'une caracteristique dans un puits souterrain Ceased WO2004001356A2 (fr)

Priority Applications (4)

Application Number Priority Date Filing Date Title
CA2490107A CA2490107C (fr) 2002-06-21 2003-06-19 Technique et systeme de mesure d'une caracteristique dans un puits souterrain
GB0423903A GB2406168B (en) 2002-06-21 2003-06-19 Technique and system for measuring a characteristic in a subterranean well
AU2003261080A AU2003261080A1 (en) 2002-06-21 2003-06-19 Technique and system for measuring a characteristic in a subterranean well
NO20045112A NO20045112L (no) 2002-06-21 2004-11-24 Teknikk og system for maling av en egenskap i en bronn i undergrunnen

Applications Claiming Priority (4)

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US10/176,858 US20030234921A1 (en) 2002-06-21 2002-06-21 Method for measuring and calibrating measurements using optical fiber distributed sensor
US10/176,858 2002-06-21
US10/317,556 2002-12-12
US10/317,556 US6751556B2 (en) 2002-06-21 2002-12-12 Technique and system for measuring a characteristic in a subterranean well

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WO2007030427A3 (fr) * 2005-09-08 2007-06-14 Baker Hughes Inc Systeme et procede de surveillance d'un puits
CN100543498C (zh) * 2007-11-14 2009-09-23 山东大学 隧道掌子面前方探水感应装置
WO2010093920A3 (fr) * 2009-02-13 2010-10-21 Halliburton Energy Services, Inc. Flux bidirectionnel et détection d'une température répartie dans des puits souterrains
WO2011089244A3 (fr) * 2010-01-25 2011-10-20 Fraunhofer Gesellschaft zur Förderung der angewandten Forschung e.V. Élément capteur et son procédé de fabrication et son utilisation
US8505625B2 (en) 2010-06-16 2013-08-13 Halliburton Energy Services, Inc. Controlling well operations based on monitored parameters of cement health
GB2479087B (en) * 2009-01-27 2013-08-14 Tendeka Oil And Gas Services Ltd Sensing inside and outside tubing.
US8893785B2 (en) 2012-06-12 2014-11-25 Halliburton Energy Services, Inc. Location of downhole lines
WO2016100370A1 (fr) * 2014-12-15 2016-06-23 Weatherford Technology Holdings, Llc Capteur de température distribuée à deux extrémités doté d'un réseau de capteurs de température
US9388686B2 (en) 2010-01-13 2016-07-12 Halliburton Energy Services, Inc. Maximizing hydrocarbon production while controlling phase behavior or precipitation of reservoir impairing liquids or solids
US9823373B2 (en) 2012-11-08 2017-11-21 Halliburton Energy Services, Inc. Acoustic telemetry with distributed acoustic sensing system
CN109424356A (zh) * 2017-08-25 2019-03-05 中国石油化工股份有限公司 钻井液漏失位置检测系统及方法

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US7199869B2 (en) 2003-10-29 2007-04-03 Weatherford/Lamb, Inc. Combined Bragg grating wavelength interrogator and Brillouin backscattering measuring instrument

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GB2339902B (en) * 1997-05-02 2002-01-23 Baker Hughes Inc Monitoring of downhole parameters
US6274863B1 (en) * 1999-07-23 2001-08-14 Cidra Corporation Selective aperture arrays for seismic monitoring
US6279660B1 (en) * 1999-08-05 2001-08-28 Cidra Corporation Apparatus for optimizing production of multi-phase fluid
US6354734B1 (en) * 1999-11-04 2002-03-12 Kvaerner Oilfield Products, Inc. Apparatus for accurate temperature and pressure measurement
US6807324B2 (en) * 2002-05-21 2004-10-19 Weatherford/Lamb, Inc. Method and apparatus for calibrating a distributed temperature sensing system

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GB2453450B (en) * 2005-09-08 2011-02-09 Baker Hughes Inc System and method for monitoring a well
US7282698B2 (en) 2005-09-08 2007-10-16 Baker Hughes Incorporated System and method for monitoring a well
GB2453450A (en) * 2005-09-08 2009-04-08 Baker Hughes Inc System and method for monitoring a well by means of an optical fiber
WO2007030427A3 (fr) * 2005-09-08 2007-06-14 Baker Hughes Inc Systeme et procede de surveillance d'un puits
CN100543498C (zh) * 2007-11-14 2009-09-23 山东大学 隧道掌子面前方探水感应装置
GB2479087B (en) * 2009-01-27 2013-08-14 Tendeka Oil And Gas Services Ltd Sensing inside and outside tubing.
US20110232377A1 (en) * 2009-02-13 2011-09-29 Halliburton Energy Services, Inc. Bi-directional flow and distributed temperature sensing in subterranean wells
WO2010093920A3 (fr) * 2009-02-13 2010-10-21 Halliburton Energy Services, Inc. Flux bidirectionnel et détection d'une température répartie dans des puits souterrains
US9021875B2 (en) * 2009-02-13 2015-05-05 Halliburton Energy Services, Inc. Bi-directional flow and distributed temperature sensing in subterranean wells
US9388686B2 (en) 2010-01-13 2016-07-12 Halliburton Energy Services, Inc. Maximizing hydrocarbon production while controlling phase behavior or precipitation of reservoir impairing liquids or solids
CN102859332B (zh) * 2010-01-25 2016-01-06 费劳恩霍夫应用研究促进协会 传感器元件及其制造方法与用法
WO2011089244A3 (fr) * 2010-01-25 2011-10-20 Fraunhofer Gesellschaft zur Förderung der angewandten Forschung e.V. Élément capteur et son procédé de fabrication et son utilisation
CN102859332A (zh) * 2010-01-25 2013-01-02 费劳恩霍夫应用研究促进协会 传感器元件及其制造方法与用法
US8989538B2 (en) 2010-01-25 2015-03-24 Fraunhofer-Gesellschaft zur Förderung der angewandten Forschung e.V. Sensor element and method for the production thereof and use thereof
US8505625B2 (en) 2010-06-16 2013-08-13 Halliburton Energy Services, Inc. Controlling well operations based on monitored parameters of cement health
US8893785B2 (en) 2012-06-12 2014-11-25 Halliburton Energy Services, Inc. Location of downhole lines
US9823373B2 (en) 2012-11-08 2017-11-21 Halliburton Energy Services, Inc. Acoustic telemetry with distributed acoustic sensing system
WO2016100370A1 (fr) * 2014-12-15 2016-06-23 Weatherford Technology Holdings, Llc Capteur de température distribuée à deux extrémités doté d'un réseau de capteurs de température
RU2654356C1 (ru) * 2014-12-15 2018-05-17 ВЕЗЕРФОРД ТЕКНОЛОДЖИ ХОЛДИНГЗ, ЭлЭлСи Двухконечный распределенный датчик температуры с набором датчиков температуры
CN109424356A (zh) * 2017-08-25 2019-03-05 中国石油化工股份有限公司 钻井液漏失位置检测系统及方法

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GB0423903D0 (en) 2004-12-01
WO2004001356A3 (fr) 2004-07-01
AU2003261080A8 (en) 2004-01-06
CA2490107C (fr) 2010-02-16
GB2406168A (en) 2005-03-23
AU2003261080A1 (en) 2004-01-06
NO20045112L (no) 2005-03-09
CA2490107A1 (fr) 2003-12-31
GB2406168B (en) 2006-03-15

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