• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
  • 同族专利
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    • 专利摘要:
    A system may include a sensor (101; 111) for detecting a characteristic of a fluid (112) and outputting an electrical signal proportional to the characteristic; an acoustic signal generator (106) for transmitting a acoustic signal proportional to the electrical signal, and a signal detection apparatus for generating a signal proportional to the acoustic signal and transmitting the signal at a remote location.
    公开号:FR3038339A1
    申请号:FR1655006
    申请日:2016-06-02
    公开日:2017-01-06
    发明作者:John L Maida；David L Perkins
    申请人:Halliburton Energy Services Inc；
    IPC主号:
    专利说明:

    SENSOR NETWORK DISTRIBUTED CONTEXT
    In the oil and gas industry, it may be necessary to measure the characteristics and / or compositions of substances located at remote underground locations and transmit the results to the surface of the earth so that they are processed and analyzed. For example, it may be necessary to measure the chemical and / or physical properties of substances in underground oil formations and transmit the results of measurements over long distances to the earth's surface. Measurements can be made by electrical devices; on the other hand, a limited amount of electrical power is available to operate such devices and transmit measurements over long distances to the surface using electrical signals having a high signal-to-noise ratio (SNR).
    BRIEF DESCRIPTION OF THE DRAWINGS
    [0002] The following figures are included to illustrate certain aspects of the present disclosure and should not be considered as exclusive embodiments. The subject matter of this disclosure may accept substantial modifications, alterations, combinations, and equivalents, in form and function, without departing from the scope of the disclosure.
    [0003] FIG. IA illustrates an example sink system that may embody or otherwise use one or more of the principles of this disclosure.
    [0004] FIG. IB illustrates an enlarged sectional view of the well illustrated in FIG. IA.
    [0005] FIG. 2A illustrates an exemplary sensor included in a sensor system of FIG. IB.
    [0006] FIG. 2B illustrates a sectional side view of an exemplary integrated computing element (ICE) included in the sensor of FIG. 2A.
    [0007] FIG. 3 illustrates a distributed acoustic detection network (DAS) using optical fiber, given by way of example.
    [0008] FIG. 4 illustrates another distributed acoustic detection network (DAS) using the optical fiber, given by way of example.
    [0009] FIG. 5 illustrates an exemplary processing system for configuring and / or controlling the sensor system of FIG. IA and DAS networks of FIGS. 3 and 4.
    DETAILED DESCRIPTION
    The embodiments described herein relate to a distributed sensor array for measuring physical and / or chemical properties of substances located in deep underground hydrocarbon deposits. The distributed network may include a variety of well bottom sensors for detecting chemical or physical properties of substances in the hydrocarbon deposits. Embodiments may include systems and methods for converting the electrical signals sent by the sensors into acoustic signals, converting the acoustic signals into optical signals, and then transmitting the optical signals to the surface by means of optical fibers.
    The conversion of electrical signals into acoustic signals can enable the deployment of sensors over long distances to the bottom of the well, without the need to deploy long electrical conductors to the surface or to deploy consuming processing units. energy to convert and transmit an electrical signal having a high SNR on the surface.
    As used herein, the term "fluid" refers to any flowable substance, including particulate solids, liquids, gases, slurries, emulsions, powders, slurries, glasses, combinations thereof and the like. In some embodiments, the fluid may be an aqueous fluid, including water and the like. In some embodiments, the fluid may be a non-aqueous fluid, including organic compounds, more specifically hydrocarbons, oil, a refined oil component, petrochemicals, and the like. In some embodiments, the fluid may be a process fluid or a formation fluid such as those found in the oil and gas industry. The fluids can include various fluid mixtures of solids, liquids and / or gases. Examples of gases that can be considered as fluids according to the present embodiments include, for example, air, nitrogen, carbon dioxide, argon, helium, methane, ethane, butane, and other hydrocarbon gases, combinations thereof and / or the like.
    In this document, the term "characteristic" or "characteristic of interest" refers to a chemical, mechanical or physical property of the fluid or a sample of the fluid, also referred to herein as the term substance. or substance sample. The characteristic of the fluid may include a quantitative or qualitative value of one or more chemical constituents or compounds present therein or any physical property associated therewith. Such components and chemical compounds may be referred to herein as "analytes". Examples of fluid characteristics that can be detected by the sensors described herein include, for example, the chemical composition (e.g., identity and concentration of all individual components or components). , the existence of a phase (eg, gas, oil, water, etc.), impurity content, pH, alkalinity, viscosity, density, ionic strength, total dissolved solids, salt content (eg, salinity), porosity, opacity, bacterial content, total hardness, transmittance, combinations thereof, material state (solid, liquid, gas) , emulsion, mixtures thereof, etc.), and the like.
    In this document, the term "component", or variations thereof, refers to at least a portion of a substance or material of interest in the fluid to be evaluated using the sensors. described in this document. In some embodiments, the component is the characteristic of interest, as defined above, and may include any integral portion of the fluid flowing in the flow path.
    For example, the component may comprise compounds containing elements such as barium, calcium (eg, calcium carbonate), carbon (eg, resilient graphitic carbon), chlorine (e.g. chlorides), manganese, sulfur, iron, strontium, chlorine, etc., and any chemical substance that may precipitate in a flow path. The component may also refer to paraffins, waxes, asphaltenes, clays (eg smectite, illite, kaolin, etc.), aromatics, saturates, foams, salts, particles, hydrates , sand or any other solid particle (e.g., low and high density solids), combinations thereof, and the like. In other embodiments, in terms of quantization of the ionic strength, the component may comprise various ions, such as, inter alia, Ba2 +, Sr2 +, Fe +, Fe2 + (total gold Fe), Mn2 +, SO4 2-, CO32 -, Ca 2+, Mg 2 +, Na +, K +, Cl-.
    In other aspects, the component may refer to any substance or material added to the fluid as an additive or to treat the fluid or the flow path. For example, the component may comprise, inter alia, acids, acid-releasing compounds, bases, base-releasing compounds, biocides, surfactants, anti-scale agents, anti-corrosion agents, gelling agents. , crosslinking agents, anti-sludge agents, foaming agents, antifoaming agents, emulsifying agents and emulsifiers, anti-emulsifying agents, iron control agents, proppants or other particles, gravel, particle deflectors, salts, fluid loss control additives, gases, catalysts, clay control agents, clay stabilizers, anti-clay, chelating agents, anti-corrosion agents, dispersants, flocculants, base fluids (eg, water, brines, oils), scavengers (eg, H2S scavengers, CO2 scavengers or O2 scavengers) , lubricants, disrupting agents, delayed release disrupters, friction reducers, bonding agents, viscosifiers, diluents, heat-treated polymers, tar treatments, agents or weighing materials (e.g. barite, etc.), solubilizers, rheology control agents, viscosity modifiers, pH control agents (eg, buffers), hydrate inhibitors, relative permeability modifiers, deviation, consolidants, fibrous materials, bactericides, tracers, probes, nanoparticles, and the like. Combinations of these substances may also be referred to as "substance".
    As used herein, the term "flow path" refers to a path through which a fluid can be transported between two points. Exemplary flow paths include, but are not limited to, a flow line, a pipeline, a flexible pipe, a treatment plant, a storage tank, a tank, a car tank, vessel or ship, hopper, jet, sewer, subterranean field, etc., combinations thereof or the like.
    [0018] FIG. IA illustrates an exemplary well system 10 which may embody or otherwise employ one or more principles of the present disclosure, in one or more embodiments. As illustrated, the well system 10 may include a maintenance facility 12 positioned at the surface of the earth 14 and extending above and around a well 16 that penetrates one or more underground deposits 18. The installation maintenance 12 may be a drilling rig, a completion facility, a repair facility or the like. In some embodiments, the maintenance facility 12 may be omitted and replaced with a completion or a standard surface wellhead installation. In addition, if the well system 10 is described as an onshore installation, it will be appreciated that the principles of the present disclosure may be equally applicable to any marine or subsea application, the maintenance facility 12 being floating platform or an underground wellhead installation, which is already known in the art.
    The well 16 may be drilled in the underground reservoir 18 using any suitable drilling technique and may extend in a substantially vertical direction away from the surface of the earth 14. Although this is not shown on at some point, the well 16 may deviate from the vertical with respect to the surface of the earth 14 and move from a substantially vertical direction to a substantially horizontal direction.
    [0020] FIG. 1B illustrates an enlarged sectional view of the well 16 in the reservoir 18. As illustrated, the well 16 may be at least partly filled with a casing 20, which may comprise a chain of metal tubular elements connected end-to-end and secured in the well 16 to provide a protective liner to the well. The casing 20 may also be replaced by a coating or other metallic or non-metallic tubing. Thus, the scope of this disclosure is not limited to the use of a particular type of casing. A ring 22 is formed between the casing 2β and the well 16, and the casing 20 can be fixed inside the well 16 using cement 24 positioned in the ring 22, which seals the ring 22.
    As illustrated, a sensor system 100 may be positioned in the ring 22, for example, during the construction of the well 16. As illustrated, the sensor system 100 may include a plurality of sensors 101 coupled in communication with a sensor. control line 28 which can power the sensors 101 in energy from a source located on the surface 14 or a location at the bottom of the well. The control line 28 and the sensor system 100 can be fixed in the ring 22 with the cement 24. The sensors 101 can be deployed depending on the depth during the deployment of the casing 20.
    The control line 28 may also facilitate communication with remote locations, such as the surface 14 (FIG IA). Therefore, the control line 28 can be or include one or more transmission means such as, in addition, optical fibers, electrical wires, or the like, through which the output of the sensors 101 can be transmitted to the surface 14 to processing and / or control signals sent from the surface 14 may be transmitted to the sensor system 100 to control the operation thereof.
    The sensors 101 of the sensor system 100 may comprise a variety of sensors capable of detecting chemical or physical properties associated with the underground deposits 18. In one embodiment, for example, one or more of the sensors 101 may comprise sensors. electromagnetic radiation (commonly referred to as "optico-analytical devices"), quasi-distributed chemical sensors, electrochemical sensors (eg, pH sensors), or the like. In other embodiments, or in addition thereto, one or more of the sensors 101 may include optical sensors, physical property sensors, density sensors, viscosity sensors, temperature sensors, pressure sensors (eg, microphone-based sensors) and electrical sensors, for example, a thermopile opto-electronic converter. The sensors 101 may be configured to detect not only the composition and concentrations of a fluid or component thereof, but may also be configured to determine physical and other fluid characteristics and / or components present in the fluid.
    In at least one embodiment, one or more of the sensors 101 may comprise an optical computing device. As used herein, the term "optical computing device" refers to an optical device that is configured to receive an input of electromagnetic radiation from a fluid, or a substance within the fluid, and producing an electromagnetic radiation output from a processing element disposed in the optical computing device. The processing element may be, for example, an integrated computing element (ICE) used in the optical computing device. As will be described in more detail below, the electromagnetic radiation which enters into optical interaction with the processing element is modified so as to be readable by a detector, so that an output of the detector can be correlated to at least one substance measured or monitored in the fluid. The output of the electromagnetic radiation from the processing element may be reflected electromagnetic radiation, transmitted electromagnetic radiation and / or scattered electromagnetic radiation. The structural parameters of the optical computing device, as well as other considerations known to those skilled in the art, can determine whether the reflected, transmitted or scattered electromagnetic radiation is ultimately analyzed by the detector. In addition, the emission and / or diffusion of the substance, for example by fluorescence, luminescence, Raman scattering and / or Raleigh scattering, can also be monitored by the optical computing devices. Optical calculation devices are, on the other hand, only an example of a sensor 101 which can be included in the sensor system 100, which can include (as an alternative or in addition to it) any type of electrical, chemical sensor. and / or mechanical, without departing from the scope of the present disclosure.
    [0025] FIG. 2A illustrates an exemplary sensor 111, which may be included in the sensor system 100 of FIG. IB, according to one or more embodiments. The sensor 111 may be the same as or similar to any of the sensors 101 described in FIG. IB. As illustrated, the sensor 111 may comprise an optical sensor 102, a voltage-frequency converter 104 and an acoustic signal generator 106. The optical sensor 102 may be specifically configured to detect and / or measure a particular component or feature of interest a fluid present in the ring 22 or any flow line or any pipeline extending to / from the well 16.
    In some embodiments, the optical sensor 102 may include a source of electromagnetic radiation 108 configured to emit or otherwise generate electromagnetic radiation 110. Electromagnetic radiation 110 may designate radio waves, microwave radiation, and the like. , infrared and near-infrared radiation, visible light, ultraviolet light, X-rays and gamma rays. The source of electromagnetic radiation 108 may be any device capable of emitting or generating electromagnetic radiation. For example, the source of electromagnetic radiation 108 may be a light bulb, a light emitting diode (LED), a laser, a blackbody, a photonic crystal, an X-ray source, combinations thereof, or the like. In some embodiments, a lens (not shown) may be configured to collect or otherwise receive electromagnetic radiation 110 and direct a beam of electromagnetic radiation 110 to fluid 112.
    The electromagnetic radiation 110 affects and enters into optical interaction with a fluid, generally designated by the number 112, and any component present in the fluid 112. In this document, the term "optical interaction" or variations thereof is ci, can refer to the reflection, transmission, diffusion, diffraction or absorption of electromagnetic radiation. As a result, an optically interacting radiation 114 is generated by the fluid 112. The optically interacting radiation 114 may be directed or otherwise received by an ICE 118 disposed in the optical sensor 102. ICE 118 may be configured to receive the optically interacting radiation 114 and produce modified electromagnetic radiation 120 corresponding to a particular characteristic of the fluid 112. In particular, the modified electromagnetic radiation 120 is electromagnetic radiation that has optically interacted with ICE 118, which is programmed to have an optical profile mimicking a regression vector corresponding to the characteristic of the fluid 112.
    By briefly referring to FIG. 2B, a sectional side view of ICE 118 usable in the optical sensor 102 of FIG. 2A is illustrated. As illustrated, the ICE 118 may include a plurality of alternating layers 202 and 204, such as silicone (Si) and quartz (SiO2), respectively. In general, these layers 202, 204 are made of materials whose refractive index is respectively high and low. Other examples include niobia and niobium, germanium and germania, MgF, SiOx, as well as other materials known to those with a high and low index. An optical substrate 206 serves to support the layers 202, 204, according to some embodiments. In some embodiments, the optical substrate 206 is a BK-7 optical glass. In other embodiments, the optical substrate 206 may be another type of optical substrate, such as quartz, sapphire, silicone, germanium, zinc selenide, zinc sulfide, or various plastics such as polycarbonate polymethyl methacrylate (PMMA), polyvinyl chloride (PVC), diamond, ceramics, combinations thereof, and the like.
    At the opposite end (e.g., the opposing optical substrate 206 of FIG 2A), the ICE 118 may include a layer 208 that is generally exposed to the environment of the device or facility. The number of layers 202, 204 and the thickness of each layer 202, 204 are determined by the spectral attributes obtained by spectroscopic analysis of a characteristic of interest using a conventional spectroscopic instrument. The spectrum of interest of a given characteristic of interest generally comprises any number of different wavelengths. The ICE 118 of FIG. 2A, given as an example, does not represent a feature of particular interest, but is provided for illustrative purposes only. Therefore, the number of layers 202, 204 and their relative thicknesses, as shown in FIG. 2A, do not give rise to any correlation with a particular characteristic of interest. The layers 202, 204 and their relative thicknesses are not necessarily drawn to scale, and therefore should not be considered as limiting the present disclosure. In addition, those skilled in the art will readily recognize that the materials constituting each layer 202, 204 (eg, Si and SiO2) may vary, depending on the application, the cost of the materials and / or the applicability of the materials to the monitored substance.
    In some embodiments, the material of each layer 202, 204 may be doped or two or more materials may be combined to achieve the desired optical characteristic. In addition to solids, the ICE 118 may also contain liquids and / or gases, optionally in combination with solids, to obtain a desired optical characteristic. In the case of gases and liquids, ICE 118 may contain a corresponding vessel (not shown), which contains gases or liquids. Illustrative variations of ICE 118 may also include holographic optical elements, grids, piezoelectric, light path, digital light path (DLP), variable optical attenuators and / or acoustico-optical elements, for example, which can create the transmission, reflection and / or absorption properties of interest.
    The layers 202, 204 have different refractive indices. By properly selecting the materials of the layers 202, 204, their relative thicknesses and the spacing, the ICE 118 may be configured to selectively transmit / reflect / refract predetermined fractions of the electromagnetic radiation at different wavelengths. Each wavelength is associated with a predetermined weighting factor or load factor. The thickness and spacing of the layers 202, 204 can be determined using a variety of methods of approximation from the spectrograph of the characteristic of interest. These methods may include the inverse Fourier transform (IFT) of the optical transmission spectrum and the structuring of the ICE 118 as a physical representation of the IFT. The approximations convert IFT into a structure based on known materials with constant refractive indices.
    The weights applied by the layers 202, 204 of the ICE 118 at each wavelength are adjusted according to the regression weightings described with respect to a known equation, data or spectral signature. Briefly, the ICE 118 may be configured, together with the optical transducer or detector 122 described in more detail below, to effect the scalar product of the input light beam in the ICE 118 and a desired loaded regression vector. represented by each layer 202, 204 for each wavelength. As a result, the output light intensity of the ICE 118, measured by the detector 122, is associated with the characteristic of interest.
    [0033] Referring again to FIG. 2A, the modified electromagnetic radiation 120 generated by the ICE 118 may then be transmitted to a detector 122. The detector 122 may be any device capable of detecting electromagnetic radiation and may be generally referred to as an optical transducer. In some embodiments, the detector 122 may be, inter alia, a thermal detector such as a thermopile or a photoacoustic detector, a semiconductor detector, a piezoelectric detector, a CCD (charge coupler) detector, a video detector or with bars, a split detector, a photon detector (such as a photomultiplier tube), photodiodes, combinations thereof or the like, or other detectors known to those skilled in the art.
    In some embodiments, the detector 122 may be configured to produce an output signal 124 in real time or near real time in the form of a voltage (or a current) that corresponds to the characteristic of the detector. particular interest of the fluid 112. In at least one embodiment, the output signal 124 produced by the detector 122 may be directly proportional to the characteristic of the fluid 112, such as the concentration of a particular analyte of interest present in the -this. In other embodiments, the relationship may be a polynomial function, an exponential function, and / or a logarithmic function.
    In some embodiments, the optical sensor 102 may include a second detector 126, which may be similar to the first detector 122 in that it may be any device capable of detecting electromagnetic radiation. The second detector 126 may be arranged to detect the reflected light in optical interaction 115. In other embodiments, the second detector 126 may be arranged to detect the electromagnetic radiation 114 returned by the fluid. 112 or the electromagnetic radiation directed to the fluid 112 or before the latter. Without limitation, the second detector 126 may be used to detect deviations of radiation from the source of electromagnetic radiation 108. For example, the radiation deviations may include, among other things, fluctuations in intensity in the electromagnetic radiation, fluctuations interfering (e.g., dust or other interferants passing in front of the source of electromagnetic radiation), coatings on windows included in optical sensor 102, combinations thereof, or the like. As illustrated, the second detector 126 may be configured to receive a portion of the optically interacting radiation 114 through a beam splitter 130 to detect radiation deviations. To compensate for these types of undesirable effects, the second detector 126 may be configured to generate a compensation signal 128 generally indicative of the radiation deviations of the electromagnetic radiation source 108. The compensation signal 128 may be transmitted or received from any other by way of a signal processor 132 configured to provide an output signal 134. In one embodiment (not shown), the output signal 134 may be sent to the detector 122 to normalize the output signal 124 in view of any deviation radiation detected by the second detector 126.
    As indicated above, the sensor 111 is merely an example of a variety of sensors that can be used in the sensor system 100. As a result, the optical sensor 102 can be replaced by any other sensor mentioned in FIG. this document and thus the output signal 124 may come from any of these sensors.
    The output signal 124 may be an electrical signal, for example a voltage signal, and may be sent to a voltage-frequency converter (or a frequency generator) 104, which, for example, may be or may be include a voltage controlled oscillator (VCO) or a phase locked loop (PLL). In one embodiment, the output signal 124 may be a current signal, which may be converted to a voltage signal before reaching the voltage-to-frequency converter 104. As indicated above, the output signal 124 may be proportional to the characteristic of interest of the fluid 112. As the output signal 124 can determine or control a frequency (also referred to as the oscillation frequency) of a signal at an output 136 of the voltage-frequency converter 104 the signal frequency at the output 136 may be proportional to the characteristic of interest of the fluid 112. Therefore, any variation in the characteristic of interest (e.g., the concentration of a particular analyte) of the fluid 112 may proportionally vary the signal frequency at the output 136. Alternatively, the signal frequency at the output 136 may be set to a pre base frequency. determined, and an amplitude of the signal can vary proportionally based on the variation of the characteristic of interest in the fluid 112.
    The output 136 of the voltage-frequency converter 104 may be transmitted to the acoustic signal generator (e.g., an acoustic transducer) 106, which, for example, may or may comprise a piezoelectric device 107. Or, the acoustic signal generator 106 may comprise a magnetostriction device, an electrostriction device or an electro-optical device. An acoustic signal (or a wave) generated by the acoustic signal generator 106 at the output 138 thereof can be proportional to the signal frequency at the output 136 of the voltage-frequency converter 104. In one embodiment, a frequency of the acoustic signal can vary proportionally as a function of the variations of the signal frequency at the output 136. Alternatively, the frequency of the acoustic signal can be set to a desired base frequency and the amplitude of the signal. acoustics can be adapted (or modulated) according to variations in the signal frequency at the output 136.
    In one embodiment, the acoustic transducer 106 may comprise two (or more) piezoelectric devices, one of which (called primary piezoelectric device, for example, the piezoelectric device 107) may be used to generate the acoustic signal, and the other (referred to as a secondary piezoelectric device, not shown) can generate a reference signal that can be used to cancel out background noise. In this document, the second piezoelectric device is not provided on the output 136 of the voltage-frequency converter 104. A detection system (not shown) located at the surface 14 (or at any other location) measures the background vibrations. and the acoustic noises by comparing the output signals of the two co-located piezoelectric devices, the acoustic signal at the output 138 of the primary piezoelectric device 107 and the reference signal generated by the second piezoelectric device. The difference between the output signals will then be the signal of interest that is printed on the primary piezoelectric device 107, assuming that the background vibrations are very low. In another embodiment, the secondary piezoelectric device may be absent, and the primary piezoelectric device 107 may be switched between receiving the output 136 of the voltage-to-frequency converter 104 and the reference signal. The reference signal and the signal at output 138 can then be decoupled by the detection system at surface 14 (or at any other location).
    The acoustic signal generated by the acoustic signal generator 106 at the output 138 can be transmitted to the control line 28 and detected in any other way by the control line 28. For example, the acoustic signal can be transmitted to (eg, assign) one or more optical fibers included in the control line 28. In one embodiment, the at least one optical fiber may be directly coupled (eg, wound around) to the piezoelectric device 107 of the present invention. acoustic signal generator 106 for maximizing the transmission efficiency of the acoustic signal by the acoustic signal generator 106 at the control line 28.
    In an operation based on interferometric phase modulation techniques, a coherent light, eg a laser pulse, may be transmitted to the bottom of the well by the optical fiber from an interrogation unit (not shown) located at the surface 14. Faults in the optical fiber backscatter the pulse (Rayleigh scattering) as it propagates along the optical fiber and the backscattered photons are received in a photodetector on the surface 14 (FIG IA). The acoustic signal emitted by the acoustic transducer 106 may cause localized changes in the optical fiber and these changes may affect the backscattering of the pulse. Since the speed of light is constant, as a function of the delay between the moment when the pulse is transmitted to the bottom of the well and the moment when the backscattered pulse is received, the distance to the sensor 111 can be determined. This distance can then indicate the location of the component present in the fluid 112 or the characteristic of the fluid 112 at this location.
    In another embodiment, the output 136 of the voltage-frequency converter 104 may be provided with an electro-optical modulator (not expressly illustrated). In general, electrooptic modulators comprise conductive plates across a preferred crystal axis and can be prepared using titanium scattering or proton exchange techniques that create changes in the optical index along paths. defined in a crystal material, host of the electro-optical modulator. The crystal material may generally comprise lithium niobate and / or KDP (potassium dihydrogenphosphate). The variable frequency of the signal at output 136 changes the crystal refractive index of the electro-optical modulator. Indeed, the phase or amplitude of a coherent light beam transmitted to the bottom of the well is modified by the crystal of the electro-optical modulator. The modulated optical signal is detected at the surface 14 (or at any other location) by a single or looped optical fiber, included in the control line 28. The electro-optical modulator can be coupled to the optical fiber using techniques known optical cable termination, such as mats and fan kits or sink kits.
    [0043] FIG. Figure 3 illustrates an exemplary distributed sensor array (DAS) using optical fiber 300 in one or more embodiments. The DAS 300 may comprise one or more monomode optical fibers 302 (one shown) positioned in the ring 22 adjacent to the reservoir 18. As in the embodiment of FIG. 2A, the sensor system 100, including the plurality of axially spaced sensors 101, can also be positioned in the ring 22 at a predetermined distance from the optical fiber 302. The control line 28 can provide electrical power to the system In contrast, in this case, the control line 28 may not include cables or fiber optic lines. The optical fiber 302 may be positioned (or nested) in the well 16 during construction thereof and may be supported by the cement 24 used to fill the ring 22. Although FIG. 3 illustrates the optical fiber 302 diametrically opposed to the sensor system 100, it is only a simplification of the illustration and the optical fiber 302 can be positioned at the desired location in the ring 22.
    A plurality of Fiber Bragg gratings (FBG) 304, each corresponding to a sensor 101 adjacent in the circumferential direction, may be coupled to the optical fiber 302. Acoustic signals (or waves) produced by the sensors 101 can pass through the ring 22 and affect the corresponding FBG 304, resulting in a constraint in the corresponding FBG 304, which can be detected at the surface 14 (FIG IA) using a variety of interferometric phase modulation techniques. The pulse backscattered by the FBG 304 may have a higher amplitude than that of the pulse backscattered by the optical fiber without FBG. Thus, sections of the optical fiber 302 that contain the FBG 304 can produce signals of greater amplitude, which improves the spatial resolution. Backscattered signals can be detected over relatively large distances and in relatively harsh environments (eg, noisy environments), without the need for electricity at the bottom of the well. By using the nested DAS 300, the acoustic signals generated by the sensor systems 100 can be converted from an electrical domain to an optical domain and transmitted to the surface 14 (FIG IA). It will be appreciated that the conversion of the acoustic signals to the optical domain in the DAS network 300 can be performed without direct coupling of the optical fiber 302 to the sensor system 100. The nested DAS 300 may have another advantage, namely the ability to triangulate the location of the sensors 101 depending on the depth.
    In one embodiment, each sensor 101 can emit a corresponding acoustic signal (or wave) only when the characteristic of interest of the substance or material of interest in the fluid 112 (FIG. 2A) reaches or exceeds a predetermined level. For example, the optical sensor 102 of FIG. 2A may be configured to monitor or measure (continuously or intermittently) the concentration of a given analyte of interest present in the fluid 112 and provide a voltage proportional to the concentration. The acoustic signal corresponding to the voltage, on the other hand, can only be emitted if the voltage reaches or exceeds a predetermined threshold voltage that can correspond to a desired concentration of an analyte of interest. In this way, as long as the predetermined threshold voltage is not reached or exceeded, the acoustic signal can be deactivated and can be reactivated only if the predetermined threshold voltage has been reached or exceeded.
    In another embodiment comprising several sensors 101, each sensor 101 may emit an acoustic signal having a base frequency different from the basic frequencies of the acoustic signals emitted by other sensors 101. Each sensor 101 may be configured to to shift (increase or decrease) its respective base frequency proportionally to the property (e.g., a concentration of a given analyte) measured by the respective sensor 101. For example, an output of a first sensor 101 may have a frequency base of 1 kHz, an output of a second sensor 101 may have a base frequency of 2 kHz, etc. The first sensor 101 may be configured to increase its base frequency by 250 Hz or decrease it by 250 Hz in proportion to the measured property. Similarly, the second sensor 101 may be configured to increase its base frequency by 250 Hz or decrease it by 250 Hz in proportion to the measured property, etc.
    In these embodiments, the output of each sensor 101 may undergo optical multiplexing (eg, Sagnac interferometers or hybrid combinations of distributed optical fiber interferometers of Sagnac, Michelson, Mach-Zehnder, Fabry-Perot) and be transmitted to surface 14 (FIG IA) where each base frequency and each change thereof can be demodulated and monitored. The base frequency of each sensor system 100 may be a predetermined value (e.g., a predefined value by the well system operator) that may be configured during or after the installation of the DAS network 300. In addition, it may be possible to change the base frequency during operation, as needed.
    The location of each sensor 101 can be obtained depending on the time between the time required for the transmission of a light pulse at the bottom of the well by the optical fiber 302 and the time required for the corresponding backscattered pulse to reach surface 14 (FIG IA). The DAS 300 network can provide a spatial resolution of 1 meter or less for a total distance of about 10 km. Or, for the spatial location of particular sensors 101, bands or subcarrier frequency channels may be allocated to transmit the information on the local sensor. For example, each sensor 101 (or the sensor system 100) may be associated with a band or frequency channel having a bandwidth of 1 kHz. Several sensor channels to be multiplexed on the same optical fiber.
    In one embodiment, the DAS network 300 can be positioned in the housing 20 and not in the ring 22. According to another embodiment, the DAS network 300 comprising the optical fiber 302 can be directly coupled to each sensor 101, for example, by winding the optical fiber 302 around each sensor 101. The direct coupling of the DAS network 300 can reduce the number of networks in the well 16 and simplify the installation of the network or networks in the well 16.
    In an embodiment illustrated in FIG. 4, the DAS network 300 can be lowered into the housing 20 (or into a production tubing disposed in the housing 20) using tools or systems deployed by a transport means, such as a flat cable or a cable 402. another embodiment, the DAS network 300 may be replaced by an acoustic system not using an optical fiber, comprising one or more acoustic sensors 404 not using optical fibers (eg, hydrophones) and may be introduced into the housing 20 (FIG IA) using a smooth cable or cable 402.
    In both configurations, the DAS 300 and the acoustic system not using optical fiber can be introduced into the housing 20 and measurements can be made as needed. Thus, it is not necessarily necessary to have a DAS 300 network permanently installed in the well 16. It will be appreciated that these configurations also make it possible to measure the acoustic signals without direct contact with the sensor system 100. of the acoustic system not using optical fiber (eg hydrophones 404) can also be used to measure the acoustic signals generated by the sensors 101 in cases where an acoustic sensor used in conjunction with the acoustic system not using fiber optic would be dysfunctional or absent.
    [0053] FIG. 5 illustrates a processing system 500 for configuring and / or controlling the sensor system 100 and the DAS network 300 to perform the various tasks described herein. The processing system 500 may be located remotely (e.g., at surface 14).
    The system 500 may comprise a processor 510, a memory 520, a storage device 530 and an input / output device 540. Each of the components 510, 520, 530 and 540 may be interconnected, for example, using A bus system 550. The processor 510 may process instructions to be executed in the system 500. In some embodiments, the processor 510 is a single-tasking processor, a multitasking processor, or any other type of processor. The processor 510 may be able to process instructions stored in the memory 520 or on the storage device 530. The memory 520 and the storage device 530 can store information in the computer system 500.
    The input / output device 540 may provide input / output operations to the system 500. In some embodiments, the input / output device 540 may include one or more network interface devices, for example eg an Ethernet card, a serial communication device, eg an RS-232 port; and / or a wireless interface device, e.g., an 802.11 card, a wireless 3G modem, or a wireless 4G modem. In some embodiments, the input / output device may include driver devices configured to receive input data and send output data to other input / output devices, eg, a keyboard, A printer and display devices 560. In some embodiments, mobile computing devices, mobile communication devices, and other devices may be used.
    In at least some embodiments, the methods and systems described for scanning and analyzing material may be implemented in a digital electronic circuit or in software, software package or computer hardware, including structures described in this specification and their structural equivalents, or in combinations of one or more of these. The computer software may include, for example, one or more instruction modules, encoded on a computer readable storage medium for executing or controlling the operation, or a data processing apparatus. Examples of computer-readable storage medium include non-transitory support, such as random access memory (RAM) devices, read-only memory (ROM) devices, optical devices (eg, CD or DVD) and hard drives.
    The term "data processing apparatus" encompasses all types of devices, devices and machines for data processing, including for example, a programmable processor, a computer, a system on a chip or more chips or combinations of the preceding elements. The apparatus may include a dedicated-use logic circuit, eg, an FPGA (field programmable gate array) or an ASIC (application specifies integrated circuit). The apparatus may also include, in addition to the hardware, code that creates a runtime environment for the computer program in question, namely code that constitutes a processor package, a protocol stack, a base management system. of data, an operating system, a multi-platform runtime environment, a virtual machine, or a combination of one or more of these elements. The apparatus and the runtime environment can realize various different computer model infrastructures, such as web services, distributed computing, and grid computing infrastructures.
    A computer program (also called program, software, software application, script or code) can be written in any form of programming language, including compiled or interpreted languages, declarative or procedural languages. A computer program may possibly correspond to a file in a file system. A program may be stored in a part of a file that contains other programs or data (eg, one or more scripts stored in a markup language document), a single file dedicated to the program in question, or multiple coordinated files (eg, files that store one or more modules, subroutines or parts of code). A computer program may be run on one or more computers that are located on one site or distributed across multiple sites and interconnected by a communications network.
    Some of the methods and logic flows described in this specification may be realized by one or more programmable processors executing one or more computer programs to perform actions by acting on input data and generating an output. Processes and logic flows can also be performed by a dedicated-use logic circuit and an apparatus can also be implemented as a dedicated-use logic circuit, eg, an FPGA (programmable field-saver array) or an ASIC (application specifies integrated circuit).
    Among the processors adapted to the execution of a computer program, there may be mentioned, for example, microprocessors for general and specific use and processors of any type of digital computer. In general, a processor receives instructions and data from a RAM or a ROM or both. A computer includes a processor for performing actions according to the instructions and one or more memory devices for storing instructions and data. A computer may also include one or more mass storage devices for storing data, or operably coupled to receive data from one or more mass storage devices or to transfer data to one or more storage devices mass, or both, eg magnetic disks, magneto-optical disks or optical disks. On the other hand, a computer may not have such devices. Suitable devices for storing instructions and computer program data include all forms of non-volatile memory, media and memory devices, including, for example, semiconductor memory devices ( eg, EPROMs, EEPROMs, flash memory devices and others), magnetic disks (eg, internal hard disks, removable disks and the like), magneto-optical disks and CD-ROMs and DVD-ROMs. ROM. The processor and the memory may be added or incorporated into the dedicated-use logic circuit.
    To enable interaction with a user, operations may be implemented on a computer having a display device (e.g., a monitor or other type of display device) to display information to a user. user, and a keyboard and pointing device (eg, a mouse, a tracer ball, a tablet, a touch screen or other type of pointing device) by which the user can provide input to the user computer. Other types of devices may be used to also allow interaction with a user; for example, the information returned to the user may be in any form of sensory information, eg, visual information, sound information or tactile information; and the input made by the user can be received in any form, including an acoustic, voice or tactile input. In addition, a computer can interact with a user by sending documents to a device and receiving documents from a device that is used by the user; for example, sending web pages from a web browser to a user's client device in response to requests received by the web browser.
    A computer system may comprise a single computer device or several computers that operate close to each other or more generally at a distance from each other and generally communicate through a communication network. Examples of communication networks include a local area network ("LAN") and a wide area network ("WAN"), an inter-network (eg, the Internet), a network comprising a satellite link and peer entity networks (eg, ad hoc peer entity networks). A relationship between the client and the server can be created by running computer programs running on the respective computers and having a client-server relationship to each other.
    Among the embodiments described in the present document, there may be mentioned: A. A system comprising a sensor intended to detect a characteristic of a fluid and to emit an electrical signal proportional to the characteristic, a generator acoustic signal system for transmitting an acoustic signal proportional to the electrical signal and a signal detection apparatus for generating a signal proportional to the acoustic signal and transmitting the signal at a remote location.
    B. A method comprising the steps of monitoring a fluid in a well by means of a sensor, generating an electrical signal proportional to a characteristic of the fluid by means of the sensor, generating a control signal proportional to the signal using a frequency generator, generating an acoustic signal proportional to the control signal by means of an acoustic transducer, detecting the acoustic signal and generating a signal based on the acoustic signal by means of a device signal detection and transmit the signal to a remote location.
    Each of Embodiments A and B may be provided with one or more of the following additional elements in any combination: Element 1: wherein the sensor comprises one of a chemical sensor, an optical sensor, a sensor pH, a density sensor, a viscosity sensor, a thermal sensor and a pressure sensor.
    [0067] Element 2: wherein the acoustic signal generator comprises one of a piezoelectric device, a magnetostriction device, an electro-optical device and an electrostriction device. Element 3: wherein the signal detection apparatus generates an optical signal proportional to the acoustic signal by interferometric phase modulation techniques and transmits the optical signal at the remote location. Element 4: wherein the signal detection apparatus is positioned in a ring defined between a well and a housing fixed in the well. Element 5: wherein the signal detection apparatus is conveyed in a well by a smooth cable or a cable. Element 6: wherein the signal detection apparatus is an apparatus not using the optical fiber that detects the acoustic signal. Element 7: further comprising a frequency generator which receives the electrical signal and generates a control signal proportional to the electrical signal. Element 8: wherein the acoustic signal generator comprises an acoustic transducer for receiving the control signal and generating the acoustic signal proportional to the control signal. Element 9: In which the acoustic signal generator and the signal detection apparatus communicate with each other. Element 10: wherein the acoustic signal generator and the signal detection apparatus are separated from each other. Element 11: further comprising a processing unit located at the remote location and configured to process the signal output from the signal detection apparatus to determine a location of the fluid.
    [0068] Element 12: further comprising the step of generating an optical signal proportional to the acoustic signal by means of the signal detection apparatus, the optical signal being generated by the signal detection apparatus using techniques interferometric phase modulation. Element 13: further comprising the step of generating the acoustic signal when the electrical signal reaches or exceeds a predetermined threshold level, the threshold level corresponding to the characteristic of the fluid measured by the sensor. Element 14: further comprising the step of varying a frequency of the control signal proportional to the electrical signal. Element 15: further comprising the step of varying an amplitude of the control signal proportional to the electrical signal. Element 16: further comprising the step of varying a frequency of the acoustic signal proportional to the control signal. Element 17: further comprising the step of varying an amplitude of the acoustic signal proportional to the control signal. Element 18: generating the acoustic signal having a predetermined base frequency and shifting the base frequency proportional to the characteristic of the fluid measured by the sensor.
    By way of example, combinations applicable to A and B: the element 3 with the element 4; element 3 with element 5; and the element 7 with the element 8.
    Therefore, the systems and methods of the present disclosure are well suited to achieve the purposes and present the advantages mentioned, as well as those inherent in the present disclosure. The particular embodiments described above are for illustrative purposes only, the instructions of the present disclosure being able to be modified and practiced in different but equivalent ways known to those skilled in the art and having the advantages of the instructions described in the present invention. this document. In addition, the construction or design details presented herein do not have any limiting purposes other than those described in the claims below. It is therefore clear that the particular illustrative embodiments described above may be transformed, combined or modified and that all such variations are considered to fall within the scope of the present disclosure. The systems and methods described illustratively herein may be conveniently implemented in the absence of anything not specifically described herein and / or any optional feature described herein.
    In this document, the phrase "at least one of" preceding a series of elements, the terms "and" or "or" separating each of these elements, transforms the list into a set, rather than a list of different elements (ie, each element). The phrase "at least one of one" means at least one of the elements and / or at least one of any combination of these elements and / or at least one of each of the elements. For example, the phrases "at least one of A, B and C" or "at least one of A, B or C" each refer to A only, B only or C only, to any combination of A, B and C and / or at least one of each of the elements A, B and C.
    权利要求:
    Claims (19)
    [1" id="c-fr-0001]
    A well acoustic signal measurement and transmission system for a wellbore (16) comprising: a sensor (101; 111) for detecting a characteristic of a fluid (112) and emitting an electrical signal proportional to the feature ; an acoustic signal generator (106) for transmitting an acoustic signal proportional to the electrical signal; and a signal detection apparatus for generating a signal proportional to the acoustic signal and transmitting the signal at a remote location.
    [2" id="c-fr-0002]
    The system of claim 1, wherein the sensor (101; 111) comprises one of a chemical sensor (101; 111), an optical sensor (102), a pH sensor (101; 111), a sensor (101; 111), a viscosity sensor (101; 111), a thermal sensor (101; 111) and a pressure sensor (101; 111).
    [3" id="c-fr-0003]
    The system of claim 1, wherein the acoustic signal generator (106) comprises one of a piezoelectric device (107), a magnetostriction device, an electro-optical device, and an electrostriction device.
    [4" id="c-fr-0004]
    The system of claim 1, wherein the signal detection apparatus generates an optical signal proportional to the acoustic signal by interferometric phase modulation techniques and transmits the optical signal at the remote location.
    [5" id="c-fr-0005]
    The system of claim 4, wherein the signal detection apparatus is positioned in a ring (22) defined between a well (16) and a housing (20) secured in the well (16).
    [6" id="c-fr-0006]
    The system of claim 4, wherein the signal detection apparatus is conveyed in a well (16) by a smooth cable or cable.
    [7" id="c-fr-0007]
    The system of claim 1, further comprising a frequency generator which receives the electrical signal and generates a control signal proportional to the electrical signal.
    [8" id="c-fr-0008]
    The system of claim 7, wherein the acoustic signal generator (106) comprises an acoustic transducer for receiving the control signal and generating the acoustic signal proportional to the control signal.
    [9" id="c-fr-0009]
    The system of claim 1, wherein the acoustic signal generator (106) and the signal detection apparatus communicate with each other.
    [10" id="c-fr-0010]
    The system of claim 1, wherein the acoustic signal generator (106) and the signal detection apparatus are separated from each other.
    [11" id="c-fr-0011]
    The system of claim 1, further comprising a processing unit (500) located at the remote location and configured to process the signal output from the signal detection apparatus to determine a location of the fluid (112).
    [12" id="c-fr-0012]
    A method for measuring and transmitting acoustic wellbore signal data (16) comprising the steps of: monitoring a fluid (112) in a well (16) by means of a sensor (101; ni); generating an electrical signal proportional to a characteristic of the fluid (112) by means of the sensor (101; 111); generating a control signal proportional to the electrical signal by means of a frequency generator; generating an acoustic signal proportional to the control signal by means of an acoustic transducer; detecting the acoustic signal and generating a signal based on the acoustic signal by means of a signal detection apparatus; and transmit the signal to a remote location.
    [13" id="c-fr-0013]
    The method of claim 12, further comprising generating an optical signal proportional to the acoustic signal by the signal detection apparatus, the optical signal being generated by the signal detection apparatus using techniques interferometric phase modulation.
    [14" id="c-fr-0014]
    The method of claim 12, further comprising generating the acoustic signal when the electrical signal reaches or exceeds a predetermined threshold level, the threshold level corresponding to the characteristic of the fluid (112) measured by the sensor (101; ).
    [15" id="c-fr-0015]
    The method of claim 12, further comprising varying a frequency of the control signal proportional to the electrical signal.
    [16" id="c-fr-0016]
    The method of claim 12, further comprising varying an amplitude of the control signal proportional to the electrical signal.
    [17" id="c-fr-0017]
    The method of claim 12, further comprising varying a frequency of the acoustic signal proportional to the control signal.
    [18" id="c-fr-0018]
    The method of claim 12, further comprising varying an amplitude of the acoustic signal proportional to the control signal.
    [19" id="c-fr-0019]
    The method of claim 12, further comprising: generating the acoustic signal having a predetermined base frequency; and changing the base frequency proportional to the characteristic of the fluid (112) measured by the sensor (101; 111).
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    同族专利:
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    法律状态:
    2018-02-16| PLSC| Publication of the preliminary search report|Effective date: 20180216 |
    2018-03-30| ST| Notification of lapse|Effective date: 20180228 |
    优先权:
    申请号 | 申请日 | 专利标题
    PCT/US2015/039071|WO2017003485A1|2015-07-02|2015-07-02|Distributed sensor network|
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