US20030164038A1 - Acoustic sensor for fluid characterization - Google Patents

Acoustic sensor for fluid characterization Download PDF

Info

Publication number
US20030164038A1
US20030164038A1 US10384221 US38422103A US2003164038A1 US 20030164038 A1 US20030164038 A1 US 20030164038A1 US 10384221 US10384221 US 10384221 US 38422103 A US38422103 A US 38422103A US 2003164038 A1 US2003164038 A1 US 2003164038A1
Authority
US
Grant status
Application
Patent type
Prior art keywords
fluid
attenuation
acoustic
method
speed
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Abandoned
Application number
US10384221
Inventor
Wei Han
James R. Birchak
Bruce H. Storm
Thomas E. Ritter
Original Assignee
Wei Han
James R. Birchak
Bruce H. Storm
Thomas E. Ritter
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date

Links

Images

Classifications

    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00Survey of boreholes or wells
    • E21B47/10Locating fluid leaks, intrusions or movements
    • E21B47/101Locating fluid leaks, intrusions or movements using acoustic energy
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E21B49/08Obtaining fluid samples or testing fluids, in boreholes or wells
    • GPHYSICS
    • G01MEASURING; TESTING
    • G01NINVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N29/00Investigating or analysing materials by the use of ultrasonic, sonic or infrasonic waves; Visualisation of the interior of objects by transmitting ultrasonic or sonic waves through the object
    • G01N29/02Analysing fluids
    • G01N29/024Analysing fluids by measuring propagation velocity or propagation time of acoustic waves
    • GPHYSICS
    • G01MEASURING; TESTING
    • G01NINVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N29/00Investigating or analysing materials by the use of ultrasonic, sonic or infrasonic waves; Visualisation of the interior of objects by transmitting ultrasonic or sonic waves through the object
    • G01N29/34Generating the ultrasonic, sonic or infrasonic waves, e.g. electronic circuits specially adapted therefor
    • G01N29/348Generating the ultrasonic, sonic or infrasonic waves, e.g. electronic circuits specially adapted therefor with frequency characteristics, e.g. single frequency signals, chirp signals
    • GPHYSICS
    • G01MEASURING; TESTING
    • G01NINVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N2291/00Indexing codes associated with group G01N29/00
    • G01N2291/01Indexing codes associated with the measuring variable
    • G01N2291/015Attenuation, scattering
    • GPHYSICS
    • G01MEASURING; TESTING
    • G01NINVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N2291/00Indexing codes associated with group G01N29/00
    • G01N2291/02Indexing codes associated with the analysed material
    • G01N2291/022Liquids
    • G01N2291/0222Binary liquids
    • GPHYSICS
    • G01MEASURING; TESTING
    • G01NINVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N2291/00Indexing codes associated with group G01N29/00
    • G01N2291/02Indexing codes associated with the analysed material
    • G01N2291/024Mixtures
    • G01N2291/02416Solids in liquids
    • GPHYSICS
    • G01MEASURING; TESTING
    • G01NINVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N2291/00Indexing codes associated with group G01N29/00
    • G01N2291/02Indexing codes associated with the analysed material
    • G01N2291/024Mixtures
    • G01N2291/02433Gases in liquids, e.g. bubbles, foams
    • GPHYSICS
    • G01MEASURING; TESTING
    • G01NINVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N2291/00Indexing codes associated with group G01N29/00
    • G01N2291/02Indexing codes associated with the analysed material
    • G01N2291/028Material parameters
    • G01N2291/02818Density, viscosity
    • GPHYSICS
    • G01MEASURING; TESTING
    • G01NINVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N2291/00Indexing codes associated with group G01N29/00
    • G01N2291/02Indexing codes associated with the analysed material
    • G01N2291/028Material parameters
    • G01N2291/02836Flow rate, liquid level
    • GPHYSICS
    • G01MEASURING; TESTING
    • G01NINVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N2291/00Indexing codes associated with group G01N29/00
    • G01N2291/10Number of transducers
    • G01N2291/105Number of transducers two or more emitters, two or more receivers

Abstract

A method and apparatus for in-situ characterization of downhole fluids in a wellbore using ultrasonic acoustic signals. Measurements of the speed of sound, attenuation of the signal, and acoustic back-scattering are used to provide qualitative and quantitative data as to the composition, nature of solid particulates, compressibility, bubble point, and the oil/water ratio of the fluid. The tool generally comprises three sets of acoustic transducers mounted perpendicular to the direction of the flow. These transducers are capable of operating at different frequencies so that the spectrum of the acoustic signal can be optimized. The apparatus is capable of operating downhole to provide real time information as to conditions in the well.

Description

    CROSS-REFERENCE TO RELATED APPLICATIONS
  • [0001]
    This is a divisional of co-pending U.S. patent application Ser. No. 09/803,850, filed Mar. 12, 2001, which application claims the benefit of U.S. Provisional Application Serial No. 60/189,254, filed Mar. 14, 2000, entitled Acoustic Sensor For Fluid Characterization, which is incorporated herein by reference.
  • FIELD OF THE INVENTION
  • [0002]
    The present invention relates generally to downhole measurements of fluid properties in a borehole, and more particularly to a tool for characterizing fluids at the bottom of the hole, including fluid flowing into the hole from the formation. Still more particularly, the present invention relates to a tool that uses acoustic measurements, including multi-frequency acoustic measurements, to obtain qualitative and quantitative measurements of the composition and phases of the liquid, its compressibility and its bubble point.
  • BACKGROUND OF THE INVENTION
  • [0003]
    During the development and useful life of a hydrocarbon well it is often desirable to evaluate the fluids present in the surrounding formations to determine the quality of hydrocarbons present and the status of the well. Useful information about the formation fluid includes the composition and volume fraction of oil and water, the amount of solids contained in the fluid, compressibility of the fluid, and the pressure at which any entrained gases will bubble out of the fluid (bubble point). This information is helpful in determining the proper procedures to use for drilling and producing the well.
  • [0004]
    Historically, subterranean reservoir fluids were brought to the surface for analysis. There are many advantages to being able to analyze reservoir fluids while still in the well but downhole sampling and analysis of reservoir fluids presents a number of problems. One problem encountered in data acquisition downhole is the need to obtain a representative sample of reservoir fluid with minimum level of drilling fluid contamination. In the course of drilling, filtrate (drilling-mud based fluid) typically invades the formation in the vicinity of the wellbore. The process of conducting a formation test commonly involves acquiring a sample of reservoir fluid by running a conduit into the wellbore and providing a pressure drop so that fluid will flow into the conduit. The first fluid to reach the tool will comprise mainly the drilling fluid filtrate coming back out of the formation. Over time reservoir fluids displace this filtrate. Since the objective is to sample and analyze the reservoir fluids, rather than the filtrate, it is necessary to wait until the reservoir fluid has substantially displaced the filtrate from the sampling device. Thus, it is desirable to monitor the drilling fluid level in the fluid stream and to determine when an acceptable maximum level of contamination is reached so that a representative fluid sample can be obtained. A maximum level of one hundred parts per million of contaminant is acceptable for all known applications. Even samples with 70% contaminant can sometimes be useful with accurate knowledge of contaminant fraction.
  • [0005]
    Accordingly, there has been a continuing need to develop a fluid analysis system capable of accurately assessing the quality of the wellbore fluid and measuring the composition of the reservoir fluid. In particular, there has been a need to provide a method and system for measuring level of drilling fluid contamination in fluid sample, and for performing in-situ quantitative fluid analysis to determine gas bubble point, water-oil ratio, fluid composition, and compressibility of the reservoir fluid. Some prior art has disclosed methods of measuring fluid properties downhole but these methods are limited in the amount of information available.
  • [0006]
    U.S. Pat. No. 3,914,984, issued to Wade, discloses a method of measuring solid and liquid droplets in a liquid using ultrasonic tone-burst transmission in a sample cell. U.S. Pat. No. 4,381,674, issued to Abts, describes a method of detecting and identifying scattering media in an oil recovery system by counting the number of ultrasonic pulses reflected from the scattering media and comparison with the ultrasonic energy attenuation. U.S. Pat. No. 4,527,420, issued to Foote, describes a method and apparatus of using scattered ultrasound to identify solid particles and liquid droplets, specifically for semiconductor and chemical process monitoring applications. International Application Publication No. WO 98/34105, invented by Nyhavn, describes a method and apparatus for inspecting a fluid flow in a hydrocarbon production well using a method of qualitatively analyzing scattering media using acoustic signals scattered or reflected in the fluid flow. U.S. Pat. No. 4,571,693, issued to Birchak et al., describes a device for downhole measurement of multiple parameters such as attenuation, speed of sound, and density of fluids. The device consists of a gap to be filled with the fluids and a void to provide reference echo for attenuation measurement calibration but does not utilize a conduit to enable the flow of fluids through the tool. Other prior art devices have employed optical sensors and utilized a visible and near-infrared absorption spectrometer to identify the type of formation fluid, i.e. to differentiate between oil, drilling mud, water and gas present in the formation fluid. However, the windows of the optical devices may become coated with hydrocarbons (asphaltene, paraffin) that may distort their results. The devices also suffer from small depth of penetration for opaque fluids, which reduces their accuracy.
  • [0007]
    Despite the teachings of the foregoing references, it is still desired to provide a method for determining drilling fluid contamination and characterizing fluid media in situ. It is further desired to provide a downhole device that can detect and analyze gas bubbles and fine sand particles. Such a device would greatly improve reservoir fluid sampling and testing.
  • SUMMARY OF THE INVENTION
  • [0008]
    The present invention relates generally to fluid characterization in downhole reservoir fluid sampling and description applications. More specifically, this disclosure provides a method and apparatus for using acoustic transducers to detect and identify gas bubbles, solid particles, and/or liquid droplets in fluids. In one embodiment, the method comprises transmitting an acoustic signal through the fluid and using the received acoustic signal to determine the speed of sound in the fluid and the attenuation of the signal in the fluid. These measurements, along with a measurement of the density of the fluid can be used to calculate the compressibility of the fluid, fluid composition, solids content, and bubble-point of the fluid.
  • [0009]
    The present invention measures the fluid speed of sound and acoustic attenuation as a function of frequency and/or pressure. From the speed of sound, the fluid type and presence of mixtures can be determined. From speed of sound data combined with density, the compressibility of the fluid can be determined. Attenuation as a function of pressure is used to determine the bubble point pressure. In turn, these values can be used qualitatively and/or quantitatively to obtain information about the presence and size of solids in the fluid stream, contamination by solids or immiscible liquids, compressibility and the bubble point of the fluid stream.
  • [0010]
    Capabilities of the present method and apparatus may include, but are not limited to:
  • [0011]
    providing a qualitative indication of the extent of drilling fluid contamination in formation fluid;
  • [0012]
    providing a qualitative distinction between gas and liquid, water and oil, and crude oil and drilling mud fluid;
  • [0013]
    detecting gas vapor and gas bubbles in formation fluids;
  • [0014]
    providing a way to determine compressibility of the fluid;
  • [0015]
    providing a quantitative indication of oil/water ratio; and
  • [0016]
    providing a quantitative indication of solid particle size and concentration.
  • BRIEF DESCRIPTION OF THE DRAWINGS
  • [0017]
    For a detailed understanding of a preferred embodiment of the invention, reference will be made to the attached Figures, wherein:
  • [0018]
    [0018]FIG. 1 is a longitudinal cross-section of a tool constructed in accordance with a preferred embodiment of the present invention;
  • [0019]
    [0019]FIG. 2 is a cross-sectional view taken along lines 2-2 of FIG. 1;
  • [0020]
    [0020]FIG. 3 is a schematic view of a tool constructed in accordance with a preferred embodiment; and
  • [0021]
    [0021]FIG. 4 is a schematic view of the system.
  • [0022]
    While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and will herein be described in detail. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims.
  • DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
  • [0023]
    The present invention provides a method and apparatus for analyzing downhole fluids in a wellbore, such as in a formation testing application or in a pipeline, by determining the bubble point of entrained gas, water-oil ratio, fluid composition, and compressibility. Measurements of speed of sound, acoustic back-scattering, density, frequency-dependent attenuation, and pressure-dependent attenuation are collected and used as the basis for a characterization of the wellbore fluids. These measurements are made difficult by the fact that formation fluids generally contain particulates dispersed in a continuous liquid medium. The particulate can be in the form of solid particles (e.g., fine sand), liquid droplets, or gas bubbles.
  • [0024]
    To assess or characterize the fluid and the dispersed particulate(s), the present system uses at least one ultrasonic acoustic wave that is transmitted into the fluid flow. The transmitted acoustic wave may have finite cycles and may have fixed or variable frequencies. One or more receivers then receive the transmitted signals. The received signal can then be used to determine the speed of sound in the liquid, the acoustic back-scattering caused by impurities in the liquid, and the attenuation, or acoustic energy losses, resulting from traveling through the fluid.
  • [0025]
    The preferred method of measuring the speed of sound in the liquid is to transmit an acoustic signal over a known distance between a transmitter and a receiver. The speed of sound in the fluid can be measured from the time-of-flight of transmitted signal, as given by c=D/Δt, where D is the path length (equal in this case to the conduit diameter), and Δt is the time-of-flight for the pulse traveling across the fluid. For a fluid consisting of water and oil of known type and temperature, the ratio of water/oil can be determined from speed of sound measurement in the two-phase mixture by comparing the measured speed of sound to known data for speed of sound for the individual components.
  • [0026]
    Determination of the acoustic energy loss (attenuation) can be used to assess sample contamination in more complex environments. Each transmitting acoustic transducer emits a tone-burst or pulsed signal having a distinct frequency into the fluid. After passing through the fluid sample, the wave is detected by a receiving transducer. The received acoustic signal is controlled by the amount of acoustic energy loss (attenuation) in the fluid sample, as characterized by the attenuation coefficient of the fluid. To evaluate fluid mixtures of solid particles or liquid droplets suspended in a liquid medium, the excess attenuation coefficient is evaluated. The excess attenuation coefficient is the total attenuation in the liquid medium minus losses of the signal that would occur in a liquid without particles or droplets. The extent of acoustic energy loss in the fluid sample results from the combined effect of absorption in the particulate and liquid media, visco-inertial attenuation, thermal attenuation, and acoustic back-scattering loss.
  • [0027]
    The preferred method of measurement of the compensated attenuation coefficient requires two receivers and two transmitters. Two split element transducers give four elements. In reference to FIG. 4, the transmitters are labeled T1 and T2, and the receivers are R1 and R2, then the attenuation is given by the equation:
  • α=[(V 12*V 21)/(V 11*V 22)]1/2,
  • [0028]
    where V12 is the signal produced by transmitter T1 in receiver R2, V21 is the signal produced by T2 in R1, V11 is the signal produced by T1 in R1, and V22 is the signal produced by T2 in R2. A microprocessor 21 controls the transmitters and receivers via interface 23 to obtain signal voltage measurements, processes the signal measurements to determine sound attenuation and speed, and transmits the results to the surface via telemetry module 22. Because the measured voltage is proportional to signal strength, the above equation can be used to convert measured voltages into attenuation data.
  • [0029]
    The preferred fluid analysis method also includes measuring the attenuation coefficient at different frequencies so that the frequency dependence of the attenuation can be determined. In general, the frequency/attenuation relationship can be given as α=Aƒn, where:
  • [0030]
    α is the attenuation coefficient;
  • [0031]
    A is a calibration constant representing the absorption of the liquid, for water A=25 and for castor oil A=10000;
  • [0032]
    ƒ is the frequency of the transmitted signal;
  • [0033]
    and n is a power factor that correlates to the solids associated with damping (e.g., for visco-elastic damping n=2 and for visco-inertial n=1). In a pure liquid, attenuation is proportional to frequency squared (n=2). As the amount of solids in the fluid increase, n approaches unity.
  • [0034]
    From the frequency dependence of the attenuation coefficient, the fluid can be compared to fluids with known attenuation coefficients. The frequency dependence of the attenuation coefficient can therefore form the basis for a qualitative indication of the nature of the fluid stream, and more importantly, the extent of drilling mud fluid contamination in the formation fluid sample.
  • [0035]
    As an alternative embodiment of this invention, acoustic attenuation as function of frequency or at a constant frequency, can be used to monitor the variation of the solid concentration and thus help determine the relative level of the mud (and mud filtrate) contamination in the formation fluid sampled. For example, water-based drilling mud normally consists of 10-20 wt % of solid particles (i.e., clay, a few microns in size) suspended in a liquid medium (i.e., water). At the start of pumping, the fluid sample would mainly be the mud with known solid concentration. As the portion of the mud (or mud filtrate) decreases and more formation fluid is collected, the solid concentration in the fluid sample would proportionally decrease. Monitoring the solid concentration in the fluid sampled can provide a quantitative measurement of the mud (or mud filtrate) fraction in the fluid sampled. For suspensions of micrometer-sized clay particles suspended in water, previous experimental studies on acoustic attenuation were reported at finite frequencies, 0.1 MHz, 1.0 MHz, 5.0 MHz, and at discrete frequencies from 3-100 MHz. The experimental studies on clay-water dispersions indicate that: 1) at solid weight fraction <22%, the attenuation coefficient is linearly proportional to the frequency up to f=30 MHz; and 2) at constant frequency, the attenuation coefficient is approximately linear, increasing with the solid concentration up to 22 wt %, beyond which point the observed attenuation starts to decrease, due the increased particle-particle interaction. Experimental study of acoustic attenuation in clay-water dispersions indicates that the frequency dependence of the visco-inertial attenuation coefficient is linear to the frequency, that is, α∝Bf, below f<35 MHz. Here B is a factor primarily dependent on the solid concentration and particle size.
  • [0036]
    The visco-inertial acoustic energy loss results from the relative motion of the suspended particle phase relative to the suspending fluid medium. The loss is dependent on the relative density contrast of the suspended particulate and surrounding fluid medium. Visco-inertial attenuation is the dominant mechanism for acoustic signal loss in suspensions of sub-micron or micron-sized clay or sand particles in water. At high frequency or high concentrations, the visco-inertial attenuation dominates the total attenuation so that the absorption in water may be neglected. At low frequency and low solid concentrations, to get the excess attenuation and evaluate the solid properties more accurately, knowledge of the absorption in the liquid medium is needed. This information can be determined by experimental analysis of known fluids in a controlled environment.
  • [0037]
    In contrast to visco-inertial losses in suspensions of solids in liquids, for dispersions of oil droplets in water, thermal loss is the dominant loss mechanism. Thermal attenuation is the acoustic energy loss in the form of heat transfer between suspending particle and fluid medium phases. The thermal loss is strongly dependent on the difference in the thermodynamic factor [thermal expansion coefficient/(density×specific heat)] for suspended particulate and fluid phases. The attenuation coefficient for either the visco-inertial or thermal attenuation loss is an approximately linear function of the frequency, that is, α∝Bƒ.
  • [0038]
    Scattering loss is a non-absorption process in which an acoustic wave beam is reflected or re-directed from the surface of a particulate, thereby reducing the acoustic transmission. The extent of scattering loss strongly depends on frequency ƒ and size of the scattering particles. More particularly, the scattering loss is approximately related to the scattering particulate size and frequency as α∝ƒ4a3 where a is particle diameter, for particulates smaller than the signal wavelength.
  • [0039]
    For particles comparable to or larger than the wavelength, specular reflection occurs. Specular loss is relatively independent of frequency. Fine particle size originated from the drilling fluid or from the formation may also be measured using the attenuation spectrum. For an emulsion containing a small amount of one liquid as highly dispersed droplets, the attenuation vs. fourth power of frequency may be most suitable.
  • [0040]
    The preferred embodiment of the present invention also provides a method for determining the compressibility of the fluid using the measured speed of sound in fluid stream and density. Compressibility helps to determine the relative concentrations of solids, liquids and gases in multi-phase systems. Density can be measured using a standard densitometer (not shown). For a fluid medium with a known density, the compressibility of the fluid β is determined by β=1/(c2ρ).
  • [0041]
    In turn, measurement of the sound speed and calculation of the fluid compressibility, in conjunction with attenuation measurement discussed above, can give a qualitative indication of the presence of a gas phase in the fluid stream. Gas volume fraction relates linearly to incremental compressibility.
  • [0042]
    The preferred embodiment also seeks to determine the pressure at which gas entrained in the liquid will begin to bubble out, known as the bubble point. Monitoring for gas bubbles and for the bubble-point can also help optimize pumping control of sample fluid and representative sample collection. Gas evolution from the formation fluid must be avoided during sampling, which requires that the sampling pressure be above the bubble-point pressure of the fluid. When the fluid is determined to consist primarily of reservoir fluid, or equilibrium conditions in the test tool have been achieved, the bubble point of the reservoir fluid can be determined. This can be accomplished by monitoring the pressure and testing for the evolution of gas bubbles with acoustic attenuation and/or scattering measurements as the pressure of the system is lowered from an initial pressure above the bubble point. As the pressure reaches the bubble point, free gas vapor appears and the acoustic attenuation and scattering increase abruptly. By detecting the formation of gas bubbles and hence determining the bubble point pressure, the pumping operation can be monitored and adjusted to maintain the sampling pressure above the bubble point pressure. Thus sampling conditions at which no gas evolves in the formation fluid can be determined, allowing representative formation fluid sample to be collected.
  • [0043]
    If the sampling pressure is above bubble-point pressure, as is required by the requirement of collecting representative formation fluid, no gas phase exists and the mixture will comprise one or more liquid phases in addition to a solids phase. If the solids concentration is very small, then the fluid essentially becomes a water and oil two-phase mixture. As discussed above, for water and oil of known type at temperature T, the ratio of water/oil can be determined from speed of sound measurement in the two-phase mixture by comparing the measured speed of sound to known data for a speed of sound for the individual components.
  • [0044]
    The disclosed methods for measuring the speed of sound of the fluid and the acoustic attenuation coefficient as function of frequency allow for characterization of the particulate and the fluid streams. In particular, the method disclosed makes it possible to distinguish between gas and liquid, oil and water, and crude oil and drilling mud filtrate. For example, when a fluid stream is introduced into a formation-testing tool, the character of the fluid entering the tool changes as a function of time: from drilling mud to drilling fluid filtrate, and then to reservoir fluid as the dominant component. The solids content of the flow stream also changes, decreasing over time. The compressibility of the system increases as more gas is present in the reservoir fluid. Each of these features affects the transmission, and speed of incident acoustic radiation, providing signatures whereby changes in the fluid may be monitored.
  • [0045]
    In addition, using the measured fluid density and the measured speed of sound, the acoustic impedance can be calculated as (z=ρc) as the product of the density (ρ) and the speed of sound (c). Attenuation measurements are preferably compensated for transmission losses due to changing impedance mismatch between transducer and fluid. The transmission loss associated with the impedance mismatch can be calculated once the fluid acoustic impedance is known and used to calculate a true attenuation that is compensated for transmission loss associated with the impedance mismatch. An alternate method of measuring acoustic impedance is using a medium of known acoustic impedance between the piezoelectric element and the fluid. The reflection amplitude from the medium/fluid interface can be used knowing the known acoustic impedance of the medium to calculate acoustic impedance of the fluid. The medium is called a delay line. The product of the acoustic impedance measured with a delay line and the speed of sound equals the inverse of the compressibility. Hence, compressibility can be derived without a separate density measurement if a delay line is used.
  • [0046]
    The present method and system are particularly advantageous when the formation is one that produces a gas condensate. Specifically, the attenuation measurements described above can be performed over a range of pressures. This present technique provides a sensitive way to determine the presence of gas in the sample, because as the attenuation is measured as a function of pressure, it will rise sharply when the dissolved gas begins to form bubbles. In some instances, it may be possible to measure the speed of sound of the gas, using the lowest signal frequencies of the tool. If it can be obtained, this speed of sound data can be used to help identify the molecular weight of the gas.
  • [0047]
    As shown in FIG. 1, a preferred embodiment of a tool adapted to carry out the measurements required by the present method comprises three transmitting transducers 2, 4, 6 and three receiving transducers 8, 18, and 20 arranged at various positions along a conduit 10. Receiving transducer 8 is mounted opposite to the transducer 2 to measure the signals from the transducer 2 transmitted through the fluid. Transducers 18 and 20 receive signals transmitted from transmitters 4 and 6 respectively. The flowing fluid in conduit 10 contains particles 12 and a liquid medium 14 (FIG. 3). Transmitter 2 emits several cycles of tone-burst signals having a acoustic frequency ƒ at a repetitive time interval T. Under turbulent flow or well-mixed conditions, the fluid in the volume of interrogation can be considered representative of the bulk fluids in the conduit.
  • [0048]
    A fluid characterization device generally in accordance with FIG. 1 is configured as follows. A preferred fluid path 10 is at least five wavelengths (wavelength=speed of sound/frequency). The speed of sound for gas is about 0.3 mm/μs, while the speed of sound for liquids varies from about 0.8 mm/μs to 2 mm/μs. The preferred operating frequency varies from 2 MHz to 20 MHz. As a result, the fluid path 10 is preferably at least 0.5 mm to enable any meaningful measurement in fastest fluids. A preferred fluid path is approximately 3.2 mm. This value is good for all conditions except possibly below 3 MHz, where fast liquids may have resolution problems.
  • [0049]
    In order to ensure that the received signal contains only the desired signal and does not contain extraneous energy, the path from the transmitting transducer to the receiving transducer through the housing should be slower than the fluid path. Hence, a preferred housing 24 is designed so that the estimated path through housing 24 is expected to be longer than the fluid path for liquids. For gas, however, the fluid path may be slower than the housing path and the signals may be weak. A preferred housing material is a tetrafluoroethylene polymer, such as TEFLON®, manufactured by DuPont. The speed of sound in the preferred polymer is about 1.4 mm/μs, which is slower than the speed of sound in water. In addition, the shape of the housing gives a housing path that is longer than the fluid path length.
  • [0050]
    The transducers are held in the housing 24 by a clamshell housing 25. Either end of the clamshell housing 25 is contained by a flange 26 that allows for attachment to a conduit for running into a wellbore. A series of bolts 27 span between the two flanges 26 and hold the apparatus together.
  • [0051]
    According to the preferred embodiment, a first opposed pair of transducers, for example 20, 6, with one serving as transmitter and the other as receiver, is used for attenuation and speed of sound measurement at a low frequency. The second pair of transducers 2, 8 and the third pair 4, 18 measure the speed of sound and attenuation at intermediate and high frequencies. These three sets of transducers are preferably broad band in frequency and have different center resonance frequencies. One major advantage of having a wide frequency band is that the attenuation coefficient can be measured over a wide range of frequencies, and thus provide more distinct characterization of the fluid properties. Depending on the fluid systems and attenuation properties, it may be also necessary to use more pairs than the disclosed three-pair transducers, so as to provide a sufficiently wide frequency band. Lower frequencies than 2 MHz may be useful for high mud weight. Higher frequencies than 15 MHz may be needed to distinguish among single-phase liquids.
  • [0052]
    Alternatively, in another embodiment, the frequency range for one or more of the transducers can be extended by using its third harmonic frequency response. For example, a single piezoelectric transducer element can be excited at its fundamental and third harmonic. By using electronic filtering of the transmitter and received signals, the element can be operated at either frequency, thereby helping to determine the frequency dependence from a fixed configuration comprising a limited number of transducers. The ratio of the two measurements will be relatively stable because transducer variations with environmental conditions have little effect on the sensitivity of the ratio. By operating each transducer at multiple frequencies, fewer transducers are needed to generate the frequency dependence data. For example, a system might include a I MHz transducer operated at 1 MHz and 3 MHz and a 9 MHz transducer operated at 9 MHz and 27 MHz.
  • [0053]
    Speed of sound in the fluid can be calculated by measuring the time of flight of the pulse over the known distance between transmitter 2 and receiver 8. Once the speed of sound is determined, scattered signals measured by transducers 4 and 6 can be identified and gated for analysis. The receiver 8 is also used to determine the attenuation coefficient of the fluid, preferably at multiple frequencies (including third harmonics), by measuring the decay of multiple reflected signals, or comparing the transmitted signals to those of a fluid with known attenuation coefficient.
  • [0054]
    The tool illustrated in FIG. 1 would be attached to a conduit and lowered into a wellbore. A pump at the surface would be activated drawing liquid from the wellbore up through the tool. Monitoring of data acquired by the tool and method discussed above would show the gradual change of the fluid in the tool from primarily drilling mud to primarily formation fluids. This change would likely be evidenced by a decrease of solids and an increase of hydrocarbons in the form of oil droplets or entrained gas. Therefore, the present method and apparatus allow a meaningful qualitative and quantitative assessment, of the formation fluid, to be made downhole. Hence, the present invention removes the delay normally associated with transit of the fluid sample to the surface and thus makes operations more efficient. Also, by providing essentially real-time fluid information, it is possible to react much more quickly to changes in the formation fluid and therefore enhance safe operation of the well.
  • [0055]
    In addition to the foregoing, the following U.S. Patents are incorporated herein in their entireties: U.S. Pat. No. 5,924,499, 5,763,773, and 5,841,734.
  • [0056]
    While a preferred embodiment has been shown and described, it will be understood that various modifications can be made thereto without departing from the scope of the invention. For example, the measurements and calculations described herein can be made alone or in combination, the number, frequency and arrangement of the transducers can be varied, and the number of measurements and the number of frequencies used can be varied. Furthermore, while a preferred embodiment uses a clamshell housing as shown in FIGS. 1 and 2, so as to achieve a compressive force on the transducers and maintain a fluid seal, other housings and configurations can likewise be used.

Claims (20)

    What is claimed is:
  1. 1. A method comprising the steps of:
    attaching an acoustic tool to a conduit;
    lowering said tool into a wellbore;
    circulating wellbore fluid through said tool;
    transmitting an acoustic signal through said fluid;
    receiving the transmitted signal; and
    using the received signal to assess the solids content, fluid composition and bubble point of the fluid.
  2. 2. The method of claim 1 further comprising:
    transmitting an acoustic signal a known distance through a medium of known acoustic impedance before the acoustic signal travels through said fluid.
  3. 3. The method of claim 2, wherein said using step includes:
    using the received signal to calculate the speed of sound in the fluid and the acoustic impedance of the fluid;
    using the speed of sound in the fluid and acoustic impedance of the fluid to calculate the compressibility of the fluid; and
    measuring the attenuation of the signal in the fluid.
  4. 4. The method of claim 3, further comprising: repeating said transmitting and measuring steps with acoustic signals of different frequencies.
  5. 5. The method of claim 4, further comprising: calculating the frequency dependence of the attenuation.
  6. 6. The method of claim 3, further comprising: repeating said transmitting and measuring steps at multiple pressures.
  7. 7. The method of claim 6, further comprising: calculating the pressure dependence of the attenuation.
  8. 8. The method of claim 4 wherein the attenuation is calculated using at least one transducer operated at multiple frequencies.
  9. 9. The method of claim 3 further comprising: correcting the attenuation value for transmission loss associated with impedance mismatch.
  10. 10. A method comprising the steps of:
    lowering an acoustic tool into a wellbore;
    circulating wellbore fluid through said tool;
    transmitting an acoustic signal into said fluid;
    measuring an acoustic signal received from said fluid; and
    calculating a speed of sound in said fluid.
  11. 11. The method of claim 1, further comprising: calculating an attenuation coefficient of the fluid.
  12. 12. The method of claim 10, further comprising:
    measuring the density of the fluid; and
    using the speed of sound in the fluid and the density of the fluid to calculate the compressibility of the fluid.
  13. 13. The method of claim 12, further comprising: using the speed of sound and density values obtained to assess the solids content of the fluid.
  14. 14. The method of claim 12, further comprising:
    calculating an attenuation coefficient of the fluid; and
    using speed of sound, attenuation, and density characteristics to assess the fluid composition.
  15. 15. The method of claim 12, further comprising:
    calculating an attenuation coefficient of the fluid; and
    using speed of sound, attenuation, and density characteristics to assess the bubble point of the fluid.
  16. 16. A method comprising the steps of:
    lowering an acoustic tool into a wellbore;
    circulating wellbore fluid through said tool;
    transmitting an acoustic signal into said fluid;
    measuring an acoustic signal received from said fluid; and
    calculating an attenuation coefficient of the fluid.
  17. 17. The method of claim 16, further comprising:
    determining a frequency dependence of the attenuation coefficient.
  18. 18. The method of claim 16, further comprising:
    determining a pressure dependence of the attenuation coefficient.
  19. 19. The method of claim 17, wherein the frequency dependence is determined using at least one transducer operated at multiple frequencies.
  20. 20. The method of claim 16, wherein the calculating step includes correcting for transmission loss associated with an impedance mismatch.
US10384221 2000-03-14 2003-03-07 Acoustic sensor for fluid characterization Abandoned US20030164038A1 (en)

Priority Applications (3)

Application Number Priority Date Filing Date Title
US18925400 true 2000-03-14 2000-03-14
US09803850 US6672163B2 (en) 2000-03-14 2001-03-12 Acoustic sensor for fluid characterization
US10384221 US20030164038A1 (en) 2000-03-14 2003-03-07 Acoustic sensor for fluid characterization

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
US10384221 US20030164038A1 (en) 2000-03-14 2003-03-07 Acoustic sensor for fluid characterization

Related Parent Applications (1)

Application Number Title Priority Date Filing Date
US09803850 Division US6672163B2 (en) 2000-03-14 2001-03-12 Acoustic sensor for fluid characterization

Publications (1)

Publication Number Publication Date
US20030164038A1 true true US20030164038A1 (en) 2003-09-04

Family

ID=26884941

Family Applications (3)

Application Number Title Priority Date Filing Date
US09803850 Active 2021-08-10 US6672163B2 (en) 2000-03-14 2001-03-12 Acoustic sensor for fluid characterization
US10384221 Abandoned US20030164038A1 (en) 2000-03-14 2003-03-07 Acoustic sensor for fluid characterization
US10384030 Active US6817229B2 (en) 2000-03-14 2003-03-07 Acoustic sensor for fluid characterization

Family Applications Before (1)

Application Number Title Priority Date Filing Date
US09803850 Active 2021-08-10 US6672163B2 (en) 2000-03-14 2001-03-12 Acoustic sensor for fluid characterization

Family Applications After (1)

Application Number Title Priority Date Filing Date
US10384030 Active US6817229B2 (en) 2000-03-14 2003-03-07 Acoustic sensor for fluid characterization

Country Status (2)

Country Link
US (3) US6672163B2 (en)
WO (1) WO2001069040A1 (en)

Cited By (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20070227241A1 (en) * 2006-03-30 2007-10-04 Difoggio Rocco Downhole fluid characterization based on changes in acoustic properties with pressure
US20080163680A1 (en) * 2006-03-30 2008-07-10 Baker Hughes Incorporated Downhole fluid characterization based on changes in acoustic properties
US20090157329A1 (en) * 2007-12-14 2009-06-18 Glenn Weightman Determining Solid Content Concentration in a Fluid Stream
US7628202B2 (en) 2007-06-28 2009-12-08 Xerox Corporation Enhanced oil recovery using multiple sonic sources
US20100010750A1 (en) * 2007-01-26 2010-01-14 Daniel Baron Method for measuring the pressure and/or molar mass of a gas in a housing, and corresponding measurement assembly
US8910514B2 (en) * 2012-02-24 2014-12-16 Schlumberger Technology Corporation Systems and methods of determining fluid properties
WO2014165833A3 (en) * 2013-04-04 2014-12-31 Los Alamos National Security, Llc Methods for measuring properties of multiphase oil-water-gas mixtures
US20150354343A1 (en) * 2013-01-29 2015-12-10 Statoil Petroleum As Measuring settling in fluid mixtures

Families Citing this family (80)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
JP2004520570A (en) * 2000-11-13 2004-07-08 インダストリアル リサーチ リミテッド System and method for determining the particle size of the particulate solid
US7162918B2 (en) * 2001-05-15 2007-01-16 Baker Hughes Incorporated Method and apparatus for downhole fluid characterization using flexural mechanical resonators
US7328624B2 (en) * 2002-01-23 2008-02-12 Cidra Corporation Probe for measuring parameters of a flowing fluid and/or multiphase mixture
CA2485974A1 (en) * 2002-05-15 2003-11-27 Halliburton Energy Services, Inc. Acoustic doppler downhole fluid flow measurement
US8555968B2 (en) * 2002-06-28 2013-10-15 Schlumberger Technology Corporation Formation evaluation system and method
US8899323B2 (en) 2002-06-28 2014-12-02 Schlumberger Technology Corporation Modular pumpouts and flowline architecture
US7178591B2 (en) 2004-08-31 2007-02-20 Schlumberger Technology Corporation Apparatus and method for formation evaluation
US8210260B2 (en) 2002-06-28 2012-07-03 Schlumberger Technology Corporation Single pump focused sampling
US7096719B2 (en) * 2003-01-13 2006-08-29 Cidra Corporation Apparatus for measuring parameters of a flowing multiphase mixture
CA2513248C (en) * 2003-01-13 2013-01-08 Cidra Corporation Apparatus and method using an array of ultrasonic sensors for determining the velocity of a fluid within a pipe
US6945095B2 (en) * 2003-01-21 2005-09-20 Weatherford/Lamb, Inc. Non-intrusive multiphase flow meter
US6956204B2 (en) * 2003-03-27 2005-10-18 Schlumberger Technology Corporation Determining fluid properties from fluid analyzer
US7036363B2 (en) * 2003-07-03 2006-05-02 Pathfinder Energy Services, Inc. Acoustic sensor for downhole measurement tool
US7075215B2 (en) * 2003-07-03 2006-07-11 Pathfinder Energy Services, Inc. Matching layer assembly for a downhole acoustic sensor
US6995500B2 (en) * 2003-07-03 2006-02-07 Pathfinder Energy Services, Inc. Composite backing layer for a downhole acoustic sensor
US7513147B2 (en) * 2003-07-03 2009-04-07 Pathfinder Energy Services, Inc. Piezocomposite transducer for a downhole measurement tool
US7134320B2 (en) * 2003-07-15 2006-11-14 Cidra Corporation Apparatus and method for providing a density measurement augmented for entrained gas
EP1646849B1 (en) * 2003-07-15 2008-11-12 Expro Meters, Inc. An apparatus and method for compensating a coriolis meter
US7299705B2 (en) * 2003-07-15 2007-11-27 Cidra Corporation Apparatus and method for augmenting a Coriolis meter
US7207397B2 (en) * 2003-09-30 2007-04-24 Schlumberger Technology Corporation Multi-pole transmitter source
US7237440B2 (en) * 2003-10-10 2007-07-03 Cidra Corporation Flow measurement apparatus having strain-based sensors and ultrasonic sensors
CA2545492C (en) * 2003-11-21 2009-03-10 Baker Hughes Incorporated Method and apparatus for downhole fluid analysis using molecularly imprinted polymers
US7024917B2 (en) * 2004-03-16 2006-04-11 Baker Hughes Incorporated Method and apparatus for an acoustic pulse decay density determination
US20050205301A1 (en) * 2004-03-19 2005-09-22 Halliburton Energy Services, Inc. Testing of bottomhole samplers using acoustics
US7426852B1 (en) * 2004-04-26 2008-09-23 Expro Meters, Inc. Submersible meter for measuring a parameter of gas hold-up of a fluid
US7318471B2 (en) * 2004-06-28 2008-01-15 Halliburton Energy Services, Inc. System and method for monitoring and removing blockage in a downhole oil and gas recovery operation
US7380438B2 (en) 2004-09-16 2008-06-03 Cidra Corporation Apparatus and method for providing a fluid cut measurement of a multi-liquid mixture compensated for entrained gas
US7389687B2 (en) * 2004-11-05 2008-06-24 Cidra Corporation System for measuring a parameter of an aerated multi-phase mixture flowing in a pipe
US7526966B2 (en) 2005-05-27 2009-05-05 Expro Meters, Inc. Apparatus and method for measuring a parameter of a multiphase flow
US7437946B2 (en) 2005-05-27 2008-10-21 Cidra Corporation Apparatus and method for measuring a parameter of a multiphase flow
US7263874B2 (en) * 2005-06-08 2007-09-04 Bioscale, Inc. Methods and apparatus for determining properties of a fluid
WO2007003058A1 (en) * 2005-07-06 2007-01-11 National Research Council Of Canada Method and system for determining material properties using ultrasonic attenuation
US7353709B2 (en) * 2005-07-06 2008-04-08 National Research Council Of Canada Method and system for determining material properties using ultrasonic attenuation
US7418877B2 (en) * 2005-07-07 2008-09-02 Expro Meters, Inc. Wet gas metering using a differential pressure based flow meter with a sonar based flow meter
US20070017672A1 (en) * 2005-07-22 2007-01-25 Schlumberger Technology Corporation Automatic Detection of Resonance Frequency of a Downhole System
US7523640B2 (en) * 2005-08-01 2009-04-28 Baker Hughes Incorporated Acoustic fluid analyzer
US7614302B2 (en) * 2005-08-01 2009-11-10 Baker Hughes Incorporated Acoustic fluid analysis method
US9366133B2 (en) 2012-02-21 2016-06-14 Baker Hughes Incorporated Acoustic standoff and mud velocity using a stepped transmitter
US9109433B2 (en) 2005-08-01 2015-08-18 Baker Hughes Incorporated Early kick detection in an oil and gas well
US8794062B2 (en) * 2005-08-01 2014-08-05 Baker Hughes Incorporated Early kick detection in an oil and gas well
US20070055464A1 (en) * 2005-08-17 2007-03-08 Gysling Daniel L System and method for providing a compositional measurement of a mixture having entrained gas
US20070137287A1 (en) * 2005-12-16 2007-06-21 Honeywell International Inc. Acoustic wave particulate sensor
EP1982169B1 (en) 2006-01-11 2012-11-07 Expro Meters, Inc. Apparatus and method for measuring parameters of a multiphase fluid flow
US7880133B2 (en) * 2006-06-01 2011-02-01 Weatherford/Lamb, Inc. Optical multiphase flowmeter
US7624650B2 (en) 2006-07-27 2009-12-01 Expro Meters, Inc. Apparatus and method for attenuating acoustic waves propagating within a pipe wall
US20080065362A1 (en) * 2006-09-08 2008-03-13 Lee Jim H Well completion modeling and management of well completion
US7624651B2 (en) * 2006-10-30 2009-12-01 Expro Meters, Inc. Apparatus and method for attenuating acoustic waves in pipe walls for clamp-on ultrasonic flow meter
US7673526B2 (en) * 2006-11-01 2010-03-09 Expro Meters, Inc. Apparatus and method of lensing an ultrasonic beam for an ultrasonic flow meter
EP2092278A2 (en) 2006-11-09 2009-08-26 Expro Meters, Inc. Apparatus and method for measuring a fluid flow parameter within an internal passage of an elongated body
US7587936B2 (en) * 2007-02-01 2009-09-15 Smith International Inc. Apparatus and method for determining drilling fluid acoustic properties
US8321133B2 (en) * 2007-10-23 2012-11-27 Schlumberger Technology Corporation Measurement of sound speed of downhole fluid utilizing tube waves
CA2643261A1 (en) * 2007-11-06 2009-05-06 Queen's University At Kingston Method and system for identifying and quantifing particles in flow systems
US20090201764A1 (en) * 2008-02-13 2009-08-13 Baker Hughes Incorporated Down hole mud sound speed measurement by using acoustic sensors with differentiated standoff
EP2286189A1 (en) 2008-05-01 2011-02-23 Micro Motion, Inc. Vibratory flow meter for determining one or more flow fluid characteristics of a multi-phase flow fluid
GB2465505B (en) 2008-06-27 2010-12-08 Wajid Rasheed Electronically activated underreamer and calliper tool
US7784538B2 (en) * 2008-10-27 2010-08-31 Baker Hughes Incorporated Using an acoustic ping and sonic velocity to control an artificial lift device
US8117907B2 (en) * 2008-12-19 2012-02-21 Pathfinder Energy Services, Inc. Caliper logging using circumferentially spaced and/or angled transducer elements
US8622128B2 (en) * 2009-04-10 2014-01-07 Schlumberger Technology Corporation In-situ evaluation of reservoir sanding and fines migration and related completion, lift and surface facilities design
US7950451B2 (en) 2009-04-10 2011-05-31 Bp Corporation North America Inc. Annulus mud flow rate measurement while drilling and use thereof to detect well dysfunction
US8467050B2 (en) * 2009-06-11 2013-06-18 M-I Llc Apparatus and method for metering flare gas
US8567269B1 (en) 2009-07-27 2013-10-29 M-I Llc Sensor mounting apparatus and method
US8335650B2 (en) * 2009-10-20 2012-12-18 Schlumberger Technology Corporation Methods and apparatus to determine phase-change pressures
EP2372330B1 (en) * 2010-03-31 2013-01-16 LIFEBRIDGE Medizintechnik AG Air bubble sensor
US8701461B2 (en) * 2011-02-22 2014-04-22 Southern Methodist University Calibration tube for multiphase flowmeters
US8525986B2 (en) 2011-04-06 2013-09-03 M-I Llc Method for hydrocarbon well completion
DE102011050957A1 (en) 2011-06-09 2012-12-13 OCé PRINTING SYSTEMS GMBH A method for determining the mass concentration of particles in a particle and liquid dispersion comprising
US8773948B2 (en) 2011-09-27 2014-07-08 Schlumberger Technology Corporation Methods and apparatus to determine slowness of drilling fluid in an annulus
US9097641B2 (en) 2012-05-31 2015-08-04 OCé PRINTING SYSTEMS GMBH Method to determine the mass concentration of particles in a dispersion including particles and fluid
CA2875532A1 (en) 2012-06-07 2013-12-12 California Institute Of Technology Communication in pipes using acoustic modems that provide minimal obstruction to fluid flow
US9383476B2 (en) 2012-07-09 2016-07-05 Weatherford Technology Holdings, Llc In-well full-bore multiphase flowmeter for horizontal wellbores
US9599505B2 (en) * 2012-12-10 2017-03-21 The Government Of The United States Of America, As Represented By The Secretary Of The Navy Fiber optic directional acoustic sensor
CN104142366A (en) * 2013-05-09 2014-11-12 中科隆声(北京)科技有限责任公司 Moisture content online detection method of oil pipelines by acoustic detection technology
US9617850B2 (en) 2013-08-07 2017-04-11 Halliburton Energy Services, Inc. High-speed, wireless data communication through a column of wellbore fluid
US20160177708A1 (en) * 2013-11-19 2016-06-23 Halliburton Energy Services, Inc. Acoustic measurement of wellbore conditions
US9618446B2 (en) 2014-01-28 2017-04-11 Schlumberger Technology Corporation Fluidic speed of sound measurement using photoacoustics
DE102014213216A1 (en) * 2014-07-08 2016-01-28 Continental Automotive Gmbh Method and apparatus for determining a concentration of a constituent of a fluid mixture in a fluid chamber
US9739904B2 (en) * 2014-10-21 2017-08-22 Baker Hughes Incorporated Three-phase flow identification and rate detection
US9719965B2 (en) * 2015-03-16 2017-08-01 Halliburton Energy Services, Inc. Mud settlement detection technique by non-destructive ultrasonic measurements
GB201601643D0 (en) * 2016-01-29 2016-03-16 Yta B V Downhole tool
US20170315098A1 (en) * 2016-04-29 2017-11-02 David F. Beers Ultrasonic contaminant detection system

Citations (13)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3914984A (en) * 1972-05-08 1975-10-28 Richard A Wade System for measuring solids and/or immiscible liquids in liquids
US4381674A (en) * 1981-06-22 1983-05-03 Micro Pure Systems, Inc. Ultrasonic detecting and identifying of particulates
US4527420A (en) * 1982-06-11 1985-07-09 Micro Pure Systems, Inc. Ultrasonic particulate sensing
US4571693A (en) * 1983-03-09 1986-02-18 Nl Industries, Inc. Acoustic device for measuring fluid properties
US4580444A (en) * 1984-02-10 1986-04-08 Micro Pure Systems, Inc. Ultrasonic determination of component concentrations in multi-component fluids
US4665511A (en) * 1984-03-30 1987-05-12 Nl Industries, Inc. System for acoustic caliper measurements
US5159578A (en) * 1992-01-23 1992-10-27 Mobil Oil Corporation Apparatus for rotating a transducer assembly of a borehole logging tool in a deviated borehole
US5276656A (en) * 1990-04-27 1994-01-04 Chevron Research And Technology Company Method for fluid identification and evaluation within wellbores using ultrasonic scanning
US5367911A (en) * 1991-03-21 1994-11-29 Halliburton Logging Services, Inc. Device for sensing fluid behavior
US5741962A (en) * 1996-04-05 1998-04-21 Halliburton Energy Services, Inc. Apparatus and method for analyzing a retrieving formation fluid utilizing acoustic measurements
US5924499A (en) * 1997-04-21 1999-07-20 Halliburton Energy Services, Inc. Acoustic data link and formation property sensor for downhole MWD system
US6354146B1 (en) * 1999-06-17 2002-03-12 Halliburton Energy Services, Inc. Acoustic transducer system for monitoring well production
US6401538B1 (en) * 2000-09-06 2002-06-11 Halliburton Energy Services, Inc. Method and apparatus for acoustic fluid analysis

Family Cites Families (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3906791A (en) * 1973-10-01 1975-09-23 Panametrics Area averaging ultrasonic flowmeters
US3981176A (en) * 1974-09-16 1976-09-21 The United States Of America As Represented By The Secretary Of The Department Of Health, Education And Welfare Dual frequency acoustic gas composition analyzer
US5060506A (en) * 1989-10-23 1991-10-29 Douglas David W Method and apparatus for monitoring the content of binary gas mixtures
US5060514A (en) * 1989-11-30 1991-10-29 Puritan-Bennett Corporate Ultrasonic gas measuring device
US5437194A (en) * 1991-03-18 1995-08-01 Panametrics, Inc. Ultrasonic transducer system with temporal crosstalk isolation
US5639972A (en) * 1995-03-31 1997-06-17 Caldon, Inc. Apparatus for determining fluid flow
WO1998034105A1 (en) 1997-01-13 1998-08-06 Maritime Well Service As Method and system for inspecting a fluid flow

Patent Citations (13)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3914984A (en) * 1972-05-08 1975-10-28 Richard A Wade System for measuring solids and/or immiscible liquids in liquids
US4381674A (en) * 1981-06-22 1983-05-03 Micro Pure Systems, Inc. Ultrasonic detecting and identifying of particulates
US4527420A (en) * 1982-06-11 1985-07-09 Micro Pure Systems, Inc. Ultrasonic particulate sensing
US4571693A (en) * 1983-03-09 1986-02-18 Nl Industries, Inc. Acoustic device for measuring fluid properties
US4580444A (en) * 1984-02-10 1986-04-08 Micro Pure Systems, Inc. Ultrasonic determination of component concentrations in multi-component fluids
US4665511A (en) * 1984-03-30 1987-05-12 Nl Industries, Inc. System for acoustic caliper measurements
US5276656A (en) * 1990-04-27 1994-01-04 Chevron Research And Technology Company Method for fluid identification and evaluation within wellbores using ultrasonic scanning
US5367911A (en) * 1991-03-21 1994-11-29 Halliburton Logging Services, Inc. Device for sensing fluid behavior
US5159578A (en) * 1992-01-23 1992-10-27 Mobil Oil Corporation Apparatus for rotating a transducer assembly of a borehole logging tool in a deviated borehole
US5741962A (en) * 1996-04-05 1998-04-21 Halliburton Energy Services, Inc. Apparatus and method for analyzing a retrieving formation fluid utilizing acoustic measurements
US5924499A (en) * 1997-04-21 1999-07-20 Halliburton Energy Services, Inc. Acoustic data link and formation property sensor for downhole MWD system
US6354146B1 (en) * 1999-06-17 2002-03-12 Halliburton Energy Services, Inc. Acoustic transducer system for monitoring well production
US6401538B1 (en) * 2000-09-06 2002-06-11 Halliburton Energy Services, Inc. Method and apparatus for acoustic fluid analysis

Cited By (12)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20070227241A1 (en) * 2006-03-30 2007-10-04 Difoggio Rocco Downhole fluid characterization based on changes in acoustic properties with pressure
US20080163680A1 (en) * 2006-03-30 2008-07-10 Baker Hughes Incorporated Downhole fluid characterization based on changes in acoustic properties
US7516655B2 (en) * 2006-03-30 2009-04-14 Baker Hughes Incorporated Downhole fluid characterization based on changes in acoustic properties with pressure
US8037747B2 (en) 2006-03-30 2011-10-18 Baker Hughes Incorporated Downhole fluid characterization based on changes in acoustic properties
US20100010750A1 (en) * 2007-01-26 2010-01-14 Daniel Baron Method for measuring the pressure and/or molar mass of a gas in a housing, and corresponding measurement assembly
US8175822B2 (en) * 2007-01-26 2012-05-08 Electricite De France Method for measuring the pressure and/or molar mass of a gas in a housing, and corresponding measurement assembly
US7628202B2 (en) 2007-06-28 2009-12-08 Xerox Corporation Enhanced oil recovery using multiple sonic sources
US20090157329A1 (en) * 2007-12-14 2009-06-18 Glenn Weightman Determining Solid Content Concentration in a Fluid Stream
US8910514B2 (en) * 2012-02-24 2014-12-16 Schlumberger Technology Corporation Systems and methods of determining fluid properties
US20150354343A1 (en) * 2013-01-29 2015-12-10 Statoil Petroleum As Measuring settling in fluid mixtures
WO2014165833A3 (en) * 2013-04-04 2014-12-31 Los Alamos National Security, Llc Methods for measuring properties of multiphase oil-water-gas mixtures
GB2527236A (en) * 2013-04-04 2015-12-16 Los Alamos Nat Security Llc Methods for measuring properties of multiphase oil-water-gas mixtures

Also Published As

Publication number Publication date Type
US6672163B2 (en) 2004-01-06 grant
US20010035312A1 (en) 2001-11-01 application
US20030150262A1 (en) 2003-08-14 application
WO2001069040A1 (en) 2001-09-20 application
US6817229B2 (en) 2004-11-16 grant

Similar Documents

Publication Publication Date Title
US4546649A (en) Instrumentation and control system and method for fluid transport and processing
US5714691A (en) Method and system for analyzing a two phase flow
US6644119B1 (en) Noninvasive characterization of a flowing multiphase fluid using ultrasonic interferometry
US7461547B2 (en) Methods and apparatus of downhole fluid analysis
US5622223A (en) Apparatus and method for retrieving formation fluid samples utilizing differential pressure measurements
US5576974A (en) Method and apparatus for determining watercut fraction and gas fraction in three phase mixtures of oil, water and gas
US5969237A (en) Measurement and control of asphaltene agglomeration in hydrocarbon Liquids
US5306909A (en) Analysis of drilling fluids
US20070114372A1 (en) Water detection and 3-phase fraction measurement systems
US6343507B1 (en) Method to improve the quality of a formation fluid sample
US5473934A (en) Ultrasonic fluid composition monitor
US20040095847A1 (en) Acoustic devices to measure ultrasound velocity in drilling mud
US6748815B2 (en) Method for determining particle size
US20040199340A1 (en) Apparatus and method using an array of ultrasonic sensors for determining the velocity of a fluid within a pipe
US5049823A (en) Method and device for measuring the qualities of a multiphase fluid
US6176323B1 (en) Drilling systems with sensors for determining properties of drilling fluid downhole
US5365778A (en) Method for measuring liquid viscosity and ultrasonic viscometer
US6178815B1 (en) Method to improve the quality of a formation fluid sample
US5763773A (en) Rotating multi-parameter bond tool
US5266800A (en) Method of distinguishing between crude oils
US5331156A (en) Method of analyzing oil and water fractions in a flow stream
US4947683A (en) Pulsed ultrasonic doppler borehole fluid measuring apparatus
US5549000A (en) Passive acoustic detection of pipeline pigs
US6568271B2 (en) Guided acoustic wave sensor for pipeline build-up monitoring and characterization
US20090078036A1 (en) Method of downhole characterization of formation fluids, measurement controller for downhole characterization of formation fluids, and apparatus for downhole characterization of formation fluids