WO2021003120A1 - Procédé et appareil pour déterminer une épaisseur tubulaire à l'aide d'un signal de forme d'onde d'écho d'impulsion - Google Patents

Procédé et appareil pour déterminer une épaisseur tubulaire à l'aide d'un signal de forme d'onde d'écho d'impulsion Download PDF

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Publication number
WO2021003120A1
WO2021003120A1 PCT/US2020/040231 US2020040231W WO2021003120A1 WO 2021003120 A1 WO2021003120 A1 WO 2021003120A1 US 2020040231 W US2020040231 W US 2020040231W WO 2021003120 A1 WO2021003120 A1 WO 2021003120A1
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WIPO (PCT)
Prior art keywords
frequency
function
acoustic
delay function
peak
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PCT/US2020/040231
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English (en)
Inventor
John F. Priest
Original Assignee
Baker Hughes Oilfield Operations Llc
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
Application filed by Baker Hughes Oilfield Operations Llc filed Critical Baker Hughes Oilfield Operations Llc
Priority to GB2200489.9A priority Critical patent/GB2599878B/en
Publication of WO2021003120A1 publication Critical patent/WO2021003120A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/005—Monitoring or checking of cementation quality or level
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/08—Measuring diameters or related dimensions at the borehole
    • E21B47/085—Measuring diameters or related dimensions at the borehole using radiant means, e.g. acoustic, radioactive or electromagnetic
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
    • G01V1/44—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators and receivers in the same well
    • G01V1/48—Processing data
    • G01V1/50—Analysing data

Definitions

  • Downhole production boreholes utilized in subterranean operations typically utilize casings disposed therein to protect the borehole from downhole pressures, chemical reactions and other conditions and prevent failures such as borehole collapse, burst and tensile failures. Casings can also be used to define production zones in various portions of the borehole.
  • Casing monitoring and evaluation techniques are important tools in maintaining the integrity of the casing, and in turn maintaining the integrity of the borehole.
  • Typical evaluation and maintenance procedures involve interrogating the casing and cement that is used to bond the casing to a borehole wall.
  • the thickness of the casing is an important factor in testing for casing integrity and for well abandonment.
  • the method includes: obtaining acoustic waveform data in a time domain using an acoustic transducer configured to emit an acoustic signal and receive a return acoustic signal; transforming, by a processor, the acoustic waveform data into a frequency domain using a frequency domain transform to provide frequency domain acoustic waveform data; determining, by a processor, a complex group delay function G k derived from the frequency domain acoustic waveform data to provide a phase delay function as a function of frequency, wherein the complex group delay function G k represents a first derivative of phase in the frequency domain with respect to frequency; determining, by the processor, an imaginary component function of the complex group delay function G k to provide a phase delay function as a function of frequency; and characterizing, by the processor, the tubular using the phase delay function.
  • the apparatus includes: an acoustic transducer configured to emit and receive an acoustic signal to provide to provide acoustic waveform data in a time domain and a processor.
  • the processor is configured to: transform the acoustic waveform data in the time domain into a frequency domain using a frequency domain transform to provide frequency domain acoustic waveform data; determine a complex group delay function G k derived from the frequency domain acoustic waveform data to provide a phase delay function as a function of frequency, wherein the complex group delay function G k represents a first derivative of phase in the frequency domain with respect to frequency; determine an imaginary component function of the complex group delay function G k to provide a phase delay function as a function of frequency; and characterize the tubular using the phase delay function.
  • FIG. l is a cross-sectional view of an embodiment of an acoustic tool disposed in a wellbore penetrating a subsurface formation
  • FIG. 2 is a cross-sectional view of the acoustic tool
  • FIG. 3 depicts aspects of acoustic energy travel paths from the acoustic tool to the wellbore wall and associated reflections
  • FIGS. 4a and 4b depict aspects of time-varying voltage for an acoustic pulse echo return signal with a casing resonance waveform
  • FIG. 5 depicts aspects of results of processing the acoustic pulse echo resonance waveform using three different methods
  • FIG. 6 depicts aspects of a resonance tail spectrum, a real component group delay function, and an imaginary component phase delay function
  • FIG. 7 is a flow chart for a method for characterizing a tubular disposed in a wellbore penetrating a subsurface formation.
  • FIG. 8 depicts aspects of equipment for performing a borehole-related operation.
  • a non-limiting embodiment of the tubular can be a casing that may be cemented or bonded to the subsurface formation.
  • a characterizing process includes transmitting an acoustic signal and receiving an acoustic return signal in response to the transmitted acoustic signal. Characterization of the tubular may include determining the thickness of the tubular. Characterization may also include determining a condition of the bond, such as the bond being completely present, partially present, and/or absent. Other types of tubular and/or bond characterization may also be obtained.
  • the disclosed methods and apparatuses may also be used for other types of tubulars such as tubulars disposed at or above the surface of the earth and for purposes other than producing hydrocarbons.
  • Various techniques are disclosed for processing the acoustic return signal to provide a characterization having more accuracy than prior art techniques also using acoustic signals.
  • Each of the techniques makes use of the imaginary part of a complex group delay waveform that is discussed further below.
  • FIG. 1 shows an acoustic pulse-echo imaging tool 10 as it is used in a wellbore or borehole 2.
  • the acoustic pulse-echo imaging tool 10 called the tool for brevity, is lowered to a desired depth in the wellbore 2 by means of a carrier such an electric wireline or cable 6.
  • Power to operate the tool 10 is supplied by a surface logging unit 8 connected to the other end of the cable 6.
  • Signals acquired by the tool 10 are transmitted through the cable 6 to the surface logging unit 8 for processing and presentation.
  • the carrier include a drill string and coiled tubing, e.g. for pipe conveyed logging and for logging while drilling.
  • a casing 4 is set in the wellbore 2 and may or may not be cemented in place with concrete in the annulus 32 between the casing and formation.
  • a casing shoe 11 At the bottom of the casing 4 is a casing shoe 11.
  • Drilling the wellbore 2 continues after cementing of the casing 4 until a desired depth is reached.
  • the tool 10 is generally run in an open-hole 13, which is a portion of the wellbore 2 deeper than the casing shoe 11.
  • the tool 10 is usually run in the open-hole 13 for evaluating a subsurface formation 16 penetrated by the wellbore 2.
  • the casing 4 can be representative of any tubular disposed within the well bore and may be bonded or cemented in the wellbore 2, or the annulus 32 may be filled with a fluid, more specifically liquid or gas.
  • the tool 10 has a transducer section 14 from which an acoustic pulse 12 is emitted.
  • the acoustic pulse 12 travels through a liquid 18 which fills the wellbore 2.
  • the liquid 18 may be water, water-based solution of appropriate chemicals, or drilling mud.
  • the acoustic pulse 12 strikes the wall of the wellbore 2, or the casing 4, at least part of the energy in the acoustic pulse 12 is reflected back toward the tool 10 as a reflection (or return signal) 15.
  • the transducer section 14 is then switched to receive the reflection 15 of the acoustic pulse 12 from the wall of the wellbore 2, or from the casing 4.
  • the reflection 15 contains data which are useful in evaluating the earth formation 16 and the casing 2.
  • FIG. 2 shows the tool 10 in more detail.
  • the tool 10 is connected to one end of the cable 6 and includes a housing 20 which contains a transducer head 24 rotated by an electric motor 22 or by whole tool rotation using another conveyance method, e.g. a rotating drill string.
  • Rotation of the transducer head 24 enables evaluation of substantially all the circumference of the wellbore 2 and casing 4 by enabling acoustic pulses 12 to be aimed at and reflections 15 received from various angular positions around the axis of the wellbore 2 or casing 4.
  • the transducer head 24 is located within an acoustically transparent cell 28. The acoustic pulses 12 and the reflections 15 can easily pass through the cell 28.
  • the acoustic pulses 12 are generated, and the reflections 15 are received by a piezoelectric element 26 contained within the transducer head.
  • the piezoelectric element 26 may be constructed with an internal focusing feature so that the emitted acoustic pulses 12 have an extremely narrow beam width, generally about 1/3 of an inch in a non-limiting embodiment. Narrow beam width enables high resolution of small features in the wellbore 2.
  • the piezoelectric element 26 emits the acoustic pulses 12 upon being energized by electrical impulses from a transceiver circuit 21. The electrical impulses are conducted through an electromagnetic coupling 23 which enables rotation of the transducer head 26.
  • the transceiver circuit 21 After transmitting the acoustic pulse 12, the transceiver circuit 21 is programmed to receive a time-varying electrical voltage 27 generated by the piezoelectric element 26 as a result of the reflections 15 striking the piezoelectric element 26.
  • the transceiver circuit 21 also comprises an analog-to-digital converter 21 A which converts the resulting time-varying electrical voltage 27 into a plurality of numbers, which may also be known as samples, representing the magnitude of the time- varying electrical voltage 27 sampled at spaced-apart time intervals.
  • the plurality of numbers is transmitted to the surface logging unit 8 through the cable 6.
  • the tool 10 may include downhole electronics 9 for processing data such as the time-varying electrical voltage 27 downhole.
  • the downhole electronics may also be configured to act as a telemetry interface for transmitting data to and/or receiving commands from the surface.
  • FIG. 3 shows one principle of operation of the tool 10 in more detail as it relates to determining the thickness of the casing 4.
  • the tool 10 is suspended substantially in the center of the wellbore 2.
  • the acoustic pulses 12 emitted by the tool 10 travel through the fluid 18 filling the wellbore until they contact the casing. Because the acoustic velocity of the casing 4 and the fluid 18 are generally quite different, an acoustic impedance boundary is created at the interface between the casing 4 and the fluid 18. Some of the energy in the acoustic pulse 12 will be reflected back toward the tool 10.
  • Some of the energy of the acoustic pulse 12 will travel through the casing 4 until it reaches the interface between the casing 4 and cement 34 in the annular space between the borehole 2 and the casing 4.
  • the acoustic velocity of the cement 34 and the acoustic velocity of the casing 4 are generally different, so another acoustic impedance boundary is created.
  • some of the energy of the acoustic pulse 12 is reflected back towards the tool 10, and some of the energy travels through the cement 34. Energy reflected back towards the tool 10 from the exterior surface of the casing 4 will undergo a further partial reflection 35 when it reaches the interface between the fluid 18 in the wellbore 2 and the casing 4.
  • the acoustic energy absorbed by the casing 4 will be greatest at the resonant frequency of the casing 4 because the wavelength of the energy at the resonance frequency is such that the partial reflections tend to become trapped in the casing.
  • the acoustic energy detected by the tool 10 within the reflection 15 will show evidence of energy captured or trapped at the resonant frequency of the casing 4.
  • the resonant frequency of the casing 4 is a function of the thickness of the casing 4 and the velocity of sound in the casing 4.
  • the velocity of sound in the casing 4 can be determined by measurement at the earth's surface, or inferred from knowledge of the material composition of the casing 4. Thickness of the casing 4 can be determined by determining the resonant frequency of the casing as indicated by analysis of the acoustic energy contained in the reflection 15.
  • a Fourier transform is applied to the acoustic time-varying waveform data obtained downhole to compute an amplitude spectrum and phase (not shown] transforming the waveform data into the frequency domain.
  • time-varying acoustic waveform data is illustrated in FIG. 4a.
  • One example of the amplitude spectrum in the frequency domain is illustrated as curve 50 in FIG. 5.
  • a notch 51 in the amplitude spectrum curve 50 is indicative of the resonant frequency due to the energy captured at the resonant frequency.
  • the acoustic energy slowly bleeds off, creating a time domain tail in the amplitude spectrum, illustrated at 23 in FIG 4a.
  • the frequency of this resonance tail is a function of casing thickness and the speed of sound in the casing.
  • a second method (method 2) is used in which a positive peak in a broad tail end of the waveform data in the frequency domain may be used to identify the resonant frequency.
  • the short transducer acoustic pulse In the time domain plot of the pulse echo resonance waveform, FIG. 4a, the short transducer acoustic pulse can be distinguished from the resonance tail. In the absence of a casing resonance, the transducer acoustic pulse has a short time span, as indicated by the oval 22 enclosing the transducer pulse.
  • the resonance as indicated by the oval 23, can be clearly distinguished from the transducer acoustic pulse. If the waveform data is split at the intersection of the two ovals 24, the left half will contain the transducer acoustic pulse 22, and the right half will contain the resonance tail 23. When split into two separate waveforms, each can be processed independently. The resonance tail always occurs after the transducer acoustic pulse; however, depending of the shape of the transducer acoustic signal there will be varying degrees of overlapping. This overlapping if severe enough may make this method challenging as illustrated at 24 in FIG. 4b. This waveform also contains multiple reflections between the transducer and the casing. These multiple reflections make the spectral analysis more complicated as the multiple reflections modify the entire spectrum. FIG.
  • the broad resonance tail peak limits accuracy of peak position, and thickness and the resonance tail is susceptible to interference from transducer lateral modes 64.
  • transducer lateral modes can shift peak position and/or cause false peaks leading to erroneous results.
  • the broad resonance tail peak and susceptibility make this second method less reliable than is desired.
  • a peak in a real component waveform of a complex group delay function determined in the frequency domain as discussed below is used to identify the resonant frequency.
  • the real component waveform of the complex group delay determined in the frequency domain from the time domain waveform data is determined as follows. Each reflection is digitized into a first plurality of numbers. Each number of the first plurality of numbers has an index value which represents the ordinal position of each number in the first plurality of numbers. The first plurality of numbers is used to calculate a first Fast Fourier transform. The output of the first Fast Fourier transform is a first plurality of coefficient pairs representing real coefficients and imaginary coefficients of the first Fast Fourier transform. The real coefficients and the imaginary coefficients are computed by the relationships:
  • f is a number in the first plurality of numbers
  • k is the wave number
  • N is the total quantity of numbers in the first plurality of numbers
  • Ak and Bk are, respectively the real and imaginary Fourier coefficients
  • i is the index value and the ordinal position of each sample in the plurality of numbers.
  • the Fourier transform as a function of the wavenumber F k is calculated by: is the discrete Fourier transform as a function of frequency. [0029]
  • the phase f as a function of wavenumber, can be calculated by the relationship:
  • phase and wavenumber bypasses the step of explicitly calculating the phase.
  • the relationship between phase and wavenumber is shown in order to demonstrate the relationship of the phase to the desired value, which is the real component of the group delay.
  • the group delay is defined as the first derivative of the phase as a function of frequency.
  • the group delay is defined as the derivative of phase with respect to the wave number k. Therefore the group delay function can be defined as:
  • the expression for group delay in equation 6 has terms for the first derivative with respect to the wavenumber of the real coefficients and the imaginary coefficients calculated as a result of the first Fast Fourier transform.
  • the first derivative functions of the first plurality of coefficient pairs can be calculated by the following relationships:
  • Equation 13 can be rewritten more simply as:
  • Equation 14 contains summation terms similar in form to the Fourier coefficient term definitions from equations 1 and 2. Using the definition of the Fourier coefficients defined in equations 1 and 2, it is then possible to calculate a second plurality of coefficient pairs representing the result of a second Fast Fourier transform on a second plurality of numbers. The second plurality of numbers is calculated by multiplying each number in the first plurality of numbers by the index value corresponding to each number.
  • the real coefficients and the imaginary coefficients calculated as a result of the second Fast Fourier transform are defined as:
  • the second discrete Fourier transform can be calculated in a manner similar to that shown in equation 3 :
  • Equation 14 the expression for group delay, can therefore be rewritten as:
  • W WT k A k C k + B k D k + j(A k D - B k C k ) (21)
  • equation 18 can be rewritten as: -2 n %(fi) k WfiYk
  • Calculation of the group delay can be performed by simultaneous Fast Fourier transforms of the first plurality of numbers and the second plurality of numbers to save calculation time.
  • the relative amplitudes of the reflection energy at various frequencies is evaluated to determine a frequency range in which there is sufficient energy in the reflection to evaluate the group delay curve.
  • a third plurality of numbers is calculated from the first plurality of coefficient pairs, by calculating the square root of the sum of the squares of each of the first plurality of coefficient pairs.
  • the third plurality of numbers represents the relative amplitudes of the component frequencies of the acoustic energy in the reflection.
  • the third plurality of numbers is scanned over its entire range of frequencies, and a frequency at which a peak value of relative amplitude occurs is selected.
  • the third plurality of numbers is then scanned for a lowest frequency and a highest frequency between which the relative amplitude remains greater than a preselected portion of the peak value.
  • the portion selected in one or more embodiments is 4 percent of the peak value.
  • the subjective criterion used to pick the 4 percent discrimination level was an appearance in the amplitude plot of a smooth roll-off of amplitude away from the transmitter center frequency of about 250 kHz. Below 4 percent of the peak amplitude, the plots had a "noisy" character or jagged appearance. Other selection criterion may also be used.
  • the real component of the complex group delay function is then scanned between the lowest frequency and the highest frequency.
  • the maximum value found in the scan occurs at the resonant frequency of the casing, since there is a slight delay in the reflection time of energy at the resonant frequency of the casing, in particular because of the internal multiple reflections within the casing of energy at the resonant frequency of the casing.
  • the group delay curve represents the first derivative of phase with respect to frequency, the slope of which derivative represents the time delay from the emission of the acoustic pulse to reception of the reflection.
  • the group delay curve (i.e., real component) will tend to peak at disturbances in reflection time.
  • An example of the real component of the group delay function is shown as number 52 in FIG. 5 with a real component peak at 53.
  • Another example of a peak of the real component of the group delay function is illustrated at 63 in FIG. 6.
  • the factor of 2 is present because the energy has to cross the casing twice in order to return to the transducer.
  • G g + j p (26)
  • the group delay is the real part of G, namely g
  • the phase delay is the imaginary part of G , namely p.
  • FIG. 5 One example of the curve of p with respect to frequency is illustrated in FIG. 5 at 54. As seen in FIG. 5, the phase delay curve p includes a bipolar peak pair at 55.
  • the resonant frequency is identified in the phase delay curve p at the inflection point or zero-crossing point 56.
  • FIG. 6 also illustrates an inflection point or zero-crossing point at 66.
  • each of the methods discussed above may have issues that result in the resonant frequency being difficult to identify or being askew from the actual resonant frequency.
  • the notch in method 1 may not be readily detectable algorithmically and it may become difficult to detect with increasing signal noise.
  • the broad resonance tail peak may limit accuracy of peak position, such as at 60 in FIG. 6, and thus thickness.
  • the resonance tail may be susceptible to interference from transducer lateral modes, which can result in shifts of peak position and/or cause false peaks, such as at 65 in FIG. 6.
  • the group delay peak may sometimes have inverted polarity or may have an abnormal local resonance peak with proper polarity.
  • resonant frequencies as determined by multiple methods may be averaged or used together to increase the accuracy of the determination of the resonant frequency.
  • Averaging may include weighted averaging with weight for each method being determined by the quality of the acoustic data. Other averaging methods may also be used.
  • accuracy may be increased by interpolating between bins.
  • FIG. 7 is a flow chart for a method 70 for characterizing a tubular disposed in a borehole penetrating a subsurface formation.
  • Block 71 calls for obtaining acoustic waveform data in a time domain using an acoustic transducer configured to emit an acoustic signal and receive a return acoustic signal.
  • Block 72 calls for determining, by a processor, an imaginary component function of a complex group delay function that represents a first derivative of phase with respect to frequency using the acoustic waveform data, the imaginary component function comprising an inflection or zero-crossing point between adjacent bipolar peaks.
  • the slope of the first derivative represents a time delay from the emission of the acoustic signal to reception of the return acoustic signal to provide a phase delay curve or function.
  • Block 72 may include identifying a frequency at the inflection point as a resonant frequency that represents a thickness of the tubular.
  • Block 73 calls for determining, with the processor, a real component function of the complex group delay function, the real component function comprising a peak.
  • Block 73 may also include identifying a frequency at the peak as a resonant frequency that represents a thickness of the tubular.
  • Block 74 calls for transforming, with the processor, the acoustic waveform data into a frequency domain to provide frequency domain acoustic waveform data, the frequency domain acoustic waveform data comprising at least one of (i) a notch and (ii) a peak in a resonance tail spectrum.
  • Block 74 may also include identifying at least one of a frequency at the notch and a frequency at the peak as a resonant frequency that represents a thickness of the tubular.
  • Block 75 calls for averaging frequencies corresponding to the inflection point, the peak of the a real component curve, and at least one of the notch and the peak in the resonant tail spectrum to provide an average resonant frequency.
  • Block 75 may also include determining a thickness of the tubular using the average resonant frequency.
  • the method 70 may also include performing a borehole-related physical operation using the characterization of the tubular.
  • the borehole-related physical action may include (1) perforating the tubular or casing with the proper amount charge for perforating that thickness or (2) cutting the tubular or casing with a cutter configured to cut that thickness as non-limiting embodiments.
  • Other remedial actions may be performed to preserve casing and/or well integrity.
  • FIG. 8 illustrates an embodiment of borehole-related equipment or tool 80 disposed in the borehole 2 and configured to perform a borehole-related physical operation.
  • the tool 80 may be conveyed by a carrier 81 such as a wireline, cable, drill string, or coiled tubing in non-limiting embodiments.
  • the tool 80 may be operated by topside equipment 82 based on the characterization of the tubular or casing 4.
  • the method may include normalization of data to put the inflection point on or near the zero axis of the phase delay curve.
  • Stage 1 Within a predefined window, find the peak of the resonance tail, within a narrower window search the phase delay for a negative to positive zero crossing, if a negative to positive zero crossing is found, then skip to stage 5.
  • Stage 2 Then if a negative to positive zero crossing is not found, find the positive peak of the group delay and repeat the search for a negative to positive zero crossing. If a negative to positive zero crossing is found, skip to stage 5.
  • Stage 3 Then if a negative to positive zero crossing is not found, find the negative peak of the group delay and repeat the search for a negative to positive zero crossing. If a negative to positive zero crossing is found, skip to stage 5.
  • Stage 4 Then if a negative to positive zero crossing is not found, find the negative and positive peaks of the phase delay and repeat the search for a negative to positive zero crossing. Start with a few samples before negative peak and end with a few samples after the positive peak.
  • Stage 5 By linear interpolation of the phase delay, compute the frequency at the zero crossing (i.e., the inflection point).
  • the processing window for the phase delay is narrower than the initial scan windows.
  • CTHKMIN selected minimum value
  • CTHKMAX selected maximum value
  • CTHKMIN and CTHKMAX Within the window defined by CTHKMIN and CTHKMAX, represented as dashed line 61 and dashed line 62, respectively, find group delay peak index (see black line 63) and phase delay zero crossing index (see black line 66).
  • FIG. 6 illustrates some potential problems.
  • the resonance tail peak is not at correct frequency
  • competing transducer lateral mode resonances can be larger than resonance tail and cause tail center frequency to shift.
  • One method includes the following aspects referring to FIG. 6:
  • Window should include NRI such that, CTHKMIN ⁇ NRI ⁇ CHTKMAX.
  • Resonance tail scan between R pos ⁇ 10 for example (+/- refers to number of sample bins).
  • the teachings of the present disclosure may be used in a variety of well operations. These operations may involve using one or more treatment agents to treat a formation, the fluids resident in a formation, a wellbore, and/or equipment in the wellbore, such as production tubing.
  • the treatment agents may be in the form of liquids, gases, solids, semi-solids, and mixtures thereof.
  • Illustrative treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, flow improvers etc.
  • Illustrative well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding, cementing, etc.
  • various analysis components may be used, including a digital and/or an analog system.
  • the surface logging unit 8 and/or downhole electronics 9 may include digital and/or analog systems.
  • the system may have components such as a processor, storage media, memory, input, output, communications link (wired, wireless, optical or other), user interfaces (e.g., a display or printer), software programs, signal processors (digital or analog) and other such components (such as resistors, capacitors, inductors and others) to provide for operation and analyses of the apparatus and methods disclosed herein in any of several manners well-appreciated in the art.
  • a power supply, magnet, electromagnet, sensor, electrode, transmitter, receiver, transceiver, antenna, controller, optical unit or components, electrical unit or electromechanical unit may be included in support of the various aspects discussed herein or in support of other functions beyond this disclosure.
  • Elements of the embodiments have been introduced with either the articles“a” or“an.” The articles are intended to mean that there are one or more of the elements.
  • the terms“including” and“having” and the like are intended to be inclusive such that there may be additional elements other than the elements listed.
  • the conjunction“or” when used with a list of at least two terms is intended to mean any term or combination of terms.
  • the term “configured” relates one or more structural limitations of a device that are required for the device to perform the function or operation for which the device is configured.

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Abstract

L'invention concerne un procédé de caractérisation d'un élément tubulaire, qui consiste à obtenir des données de forme d'onde acoustique dans un domaine temporel à l'aide d'un transducteur acoustique configuré pour émettre un signal acoustique et recevoir un signal acoustique de retour et transformer les données de forme d'onde acoustique vers un domaine fréquentiel pour fournir des données de forme d'onde acoustique de domaine fréquentiel. Le procédé consiste également à déterminer une fonction de retard de groupe complexe.... dérivée des données de forme d'onde acoustique de domaine fréquentiel pour fournir une fonction de retard de phase en fonction de la fréquence, la fonction de retard de groupe complexe.... représentant une dérivée première de la phase dans le domaine fréquentiel par rapport à la fréquence. Le procédé consiste en outre à déterminer une fonction de composante imaginaire de la fonction de retard de groupe complexe.... pour fournir une fonction de retard de phase en fonction de la fréquence et caractériser l'élément tubulaire à l'aide de la fonction de retard de phase.
PCT/US2020/040231 2019-07-02 2020-06-30 Procédé et appareil pour déterminer une épaisseur tubulaire à l'aide d'un signal de forme d'onde d'écho d'impulsion WO2021003120A1 (fr)

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Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US11397081B2 (en) * 2019-07-02 2022-07-26 Baker Hughes Oilfield Operations Llc Method and apparatus for determining a tubular thickness using a pulse echo waveform signal

Citations (5)

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US4912683A (en) * 1988-12-29 1990-03-27 Atlantic Richfield Company Method for acoustically measuring wall thickness of tubular goods
US5491668A (en) * 1994-05-13 1996-02-13 Western Atlas International, Inc. Method for determining the thickness of a casing in a wellbore by signal processing pulse-echo data from an acoustic pulse-echo imaging tool
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