CN111335888A - Method for determining properties of well bore in geological formation - Google Patents
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- 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
- E21B49/00—Testing 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
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- 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
- E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
- E21B47/14—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves
- E21B47/16—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves through the drill string or casing, e.g. by torsional acoustic waves
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- 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
- E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
- E21B47/14—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves
- E21B47/18—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves through the well fluid, e.g. mud pressure pulse telemetry
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Abstract
The invention provides a method for determining the properties of a well bore in a geological formation, comprising the following steps: acquiring acoustic waveform data, standardizing acoustic waveforms, carrying out workflow inversion processing and outputting parameters. The invention has the beneficial effects that: the method for determining the properties of the shaft in the geological formation is suitable for the sound attenuation of larger and thicker casing in the drilling mud which is more commonly used at present; the acoustic wave performance cannot be influenced by the shaft environment, and the evaluation accuracy is improved; accurate data such as the thickness of the casing, the acoustic impedance of the annular filling material, the acoustic impedance of the slurry and the like can be determined and output.
Description
Technical Field
The invention belongs to the technical field of shaft operation, relates to a technology for determining underground stratum characteristics by using sound wave shaft data, and particularly relates to a method for determining the shaft properties in a geological stratum by using resonance inversion of annular acoustic impedance behind a casing.
Background
The shaft refers to a channel which is cut when mining and building long tunnels and underground railways and is connected with ground and underground roadways. In completing a well, a casing or tubing string is typically placed in the wellbore and an annular packing material (e.g., cement) is placed in the annular space between the casing and the formation, one of the purposes of which is to separate the producing and gas producing zones from each other and from the water-bearing formation. If the cement does not provide isolation of one area from another, fluid under pressure may migrate from one area to another, thereby reducing production efficiency, and hydrocarbons migrating toward the aquifer are both environmentally and economically undesirable. Therefore, reliable evaluation of the annular content is of great significance for determining zonal isolation of different formations.
Sonic evaluation is commonly used to determine whether cement provides zonal isolation between formations penetrated by a borehole. Certain acoustic measurements, such as ultrasonic pulse echo measurements, find widespread use in cement evaluation by providing high azimuthal and axial resolution of the effective acoustic impedance of the annular material near the casing to evaluate cement properties and zonal isolation. For example, an ultrasonic pulse echo tool may transmit a broadband pulse (typically between 200-700 kHz) to the casing wall to excite thickness resonance modes in the casing, and modeling techniques may be used to estimate the annular acoustic impedance to process the acquired signal. However, these conventional methods are more suitable for thinner casing (e.g., casing thinner than 12 mm), but are not suitable for larger, thicker casing acoustic attenuation in the more commonly used drilling muds today, because such wellbore conditions can affect acoustic performance, thereby reducing the accuracy of cement evaluation.
It is therefore desirable to develop a method of determining the properties of a wellbore in a geological formation that is suitable for the detection of the larger, thicker casing that is currently commonly used in drilling muds, and that provides accurate and reliable annulus content evaluation data.
Disclosure of Invention
The invention provides a method for determining the properties of a well casing in a geological formation, which is realized by utilizing a mode of inversion of annular acoustic impedance resonance behind a casing, and teaches and improves the research on annular materials in a well by utilizing information in a sound wave form resonance trail. A workflow relating to the specification of acoustic waveforms to make normalized waveforms have clear resonance traps in their spectra and to match reference waveforms with normalized waveforms; before identifying the matching reference waveform, processing the matching waveform by using an iterative inversion method so as to more accurately estimate the parameters of the well bore, such as the acoustic impedance of the annular filling material, the acoustic impedance of mud, the thickness of a casing and the like.
A method of determining a property of a wellbore in a geological formation, comprising the steps of:
(1) acquiring acoustic waveform data: acquiring acoustic data from an acoustic logging tool, in particular inputting one or more acoustic waveform data consisting of reflected acoustic waves from an acoustic logging tool deployed in a wellbore of mud, casing and annular packing material; wherein the acoustic logging tool is a pulse echo logging tool;
(2) normalized acoustic waveform: normalizing the sound wave data by using a normalization working process to obtain a normalized wave;
(3) and (3) workflow reversal processing: looking up a reference wave database by looking up a table according to known wellbore parameters, and forming a reference waveform by using a reference wave generator, a model, a waveform synthesizer or a combination thereof; then, fitting the normalized waveform and the reference waveform in the same way to ensure that the two waveforms have practical significance; then, comparing the fitted normalized waveform with the fitted reference waveform, and outputting a best-fit reference wave if the waveforms are matched; if not, generating a new fitting reference wave by adopting an iterative inverse demonstration method on the basis of comparison, and iteratively comparing the fitting normalized wave with the new fitting reference wave until the best fitting reference wave is determined;
(4) and (3) parameter output: and determining and outputting wellbore parameters according to the best fit reference wave.
Further, the normalization workflow in step (2) is as follows: converting the acoustic waveform data into a frequency domain to generate a spectrum; estimating a specular spectrum from the spectrum; normalizing the spectrum by using the mirror spectrum to obtain a normalized spectrum; normalizing the normalized frequency spectrum again by using the plastic frequency spectrum to obtain a plastic waveform; converting the plastic waveform into a time domain to obtain a normalized waveform; wherein said estimating a mirror spectrum from the spectrum comprises using a priori knowledge about the wellbore; the wellbore includes a casing, an annular packing material between the casing and the formation, and a mud between the casing and the sonic logging tool.
Further, the reference waveform of step (3) comprises a reference waveform generated according to an initial casing thickness estimation.
Further, the new fitted reference wave parameters in the step (3) include a reference waveform estimated after iteratively adjusting the thickness of the casing, a reference waveform estimated after iteratively adjusting the acoustic impedance of the slurry, a reference waveform estimated after iteratively adjusting the acoustic impedance of the annular filling material, and a reference waveform estimated after iteratively adjusting the acoustic impedance of the slurry and the acoustic impedance of the annular filling material.
Further, the fitting manner in step (3) includes using log-Hilbert transform, frequency conversion.
Further, the frequency conversion is performed by applying a first window to the reference waveform and the normalized waveform to generate a first windowed reference waveform and a first windowed normalized waveform; applying a second window to the reference waveform and the normalized waveform, thereby generating a second windowed reference waveform and a second windowed normalized waveform; converting the first windowed reference waveform, the second windowed reference waveform, and the first windowed normalized waveform, the second windowed normalized waveform to the frequency domain, thereby generating a first reference spectrum, a second reference spectrum, a first normalized spectrum, and a second normalized spectrum; matching the first reference spectrum to a first normalized spectrum to determine a first best fit reference spectrum; matching the second reference spectrum to the second normalized spectrum to determine a second best fit reference spectrum; and determining the acoustic impedance of the annular filler material and the acoustic impedance of the mud based on the intersection of the first reference spectrum and the second reference spectrum.
Further, the output parameters in the step (4) include casing thickness T, annular filling material acoustic impedance Za and mud acoustic impedance Zm.
Further, the method may be accomplished using a non-transitory computer readable medium storing computer executable instructions, the entire process requiring at least one processor to perform.
Further, the step (2) may be accomplished by at least one non-transitory computer-readable medium storing computer-executable instructions; said step (3) may be accomplished by at least one non-transitory computer-readable medium storing computer-executable instructions; the step (4) may be accomplished by at least one non-transitory computer-readable medium storing computer-executable instructions.
Further, the annular filler material may be cement, resin, or the like.
The invention has the beneficial effects that:
① the present invention provides a method of determining wellbore properties in geological formations that is suitable for the greater, thicker casing acoustic attenuation in the more commonly used drilling muds today.
② the method for determining the property of the well bore in the geological formation provided by the invention is not influenced by the well bore environment to the acoustic performance, and the evaluation accuracy is improved.
③ the method of determining the properties of the wellbore in the geological formation of the present invention shows greater accuracy than the prior art in estimating the casing thickness, acoustic impedance of the annular packing material and acoustic impedance of the mud.
④ the method for determining the borehole properties in geological formations of the present invention can determine and output accurate data of casing thickness, acoustic impedance of annular packing material and acoustic impedance of mud.
Drawings
FIG. 1 is a schematic diagram of a system for evaluating cement installation and zonal isolation of a wellbore in comparative example 1;
FIG. 2 is a schematic diagram of the acoustic tool workflow for obtaining pulsed-echo acoustic cement evaluation data according to comparative example 1;
FIG. 3 is a schematic flow chart of the acoustic tool operation for obtaining asphalt-captured acoustic cement evaluation data according to comparative example 1;
FIG. 4 is a schematic representation of a cross-sectional representation of the sonic logging instrument of comparative example 1 in a cased wellbore under filled and free pipe conditions and a corresponding representation of the attenuation of the sonic response;
FIG. 5 is a schematic flow chart of a method of determining a property of a wellbore in a geological formation according to the present invention;
FIG. 6 is a detailed workflow diagram of the step of normalizing the acoustic waveform of FIG. 5;
FIG. 7 is a schematic workflow diagram of the normalization process of FIG. 6;
FIG. 8 is a schematic workflow of a method of determining a property of a wellbore in a geological formation for estimating casing thickness according to example 1 of the present invention;
FIG. 9 is a schematic view of the workflow reversal process of FIG. 8;
FIG. 10 is a schematic workflow diagram of a method of determining a property of a wellbore in a geological formation to estimate acoustic impedance according to embodiment 2 of the present invention;
FIG. 11 is a schematic diagram of the workflow reversal process of FIG. 10 in use; 11-1 in FIG. 11 represents the result of comparing the normalized waveform with the reference waveform; 11-2 represents the comparison result of the normalized waveform after log-Hilbert transformation and the reference waveform after log-Hilbert transformation; 11-3 shows the comparison result of the normalized waveform after log-Hilbert transformation and the reference waveform after log-Hilbert transformation when the acoustic impedance Zm of the mud is increased; 11-4 shows the comparison result of the normalized waveform after log-Hilbert transformation and the reference waveform after log-Hilbert transformation when the annular acoustic impedance Za is increased;
FIG. 12 is a schematic workflow diagram of a method of determining a property of a wellbore in a geological formation to estimate acoustic impedance according to embodiment 3 of the present invention;
FIG. 13 is a schematic diagram of the workflow reversal process of FIG. 12 in use;
FIG. 14 is a schematic diagram comparing the method of the present invention with a conventional inversion; in the graph 51 represents Zm output, 52 represents Za output, both processed by prior art resonance inversion, and 53 represents output processed by conventional techniques;
FIG. 15 is a schematic representation of a comparison of data from the method of the present invention and a conventional inversion; in the figure 54 represents Za plotted from conventional pulse-echo processing techniques, 55 represents Za plotted using the present technique, 56 represents Zm plotted using the present technique, 57 represents estimated casing thickness using both conventional and prior art techniques, and 58 shows an image obtained by bend attenuation.
FIG. 16 is a data comparison of the method of the present invention with a conventional processing method; where well 59 represents Za processed using conventional techniques, well 60 represents Za processed using the present technique, well 61 represents Zm processed using the present technique, well 62 represents casing thickness processed using the present technique, and well 63 represents a comparison of thickness estimates between conventional techniques and processes using the present technique.
The meaning of the reference symbols in the figures: 1-surface equipment, 2-geological formation, 3-wellbore, 4-annular packing material, 5-annulus, 6-casing, 7-casing collar, 8-drilling fluid, 9-sonic logging instrument, 10-cable, 11-vehicle, 12-drilling rig, 13-acoustic data, 14-data processing system, 15-processor, 16-memory, 17-memory, 18-display, 19-general solid character, 20-general liquid or gas character, 21-transducer, 22-sound wave, 23-reflected wave, 24-reflected wave, 25-reflected wave, 26-transmitter, 27-receiver transducer, 28-transmitted sound energy, 29-reflected wave, 30-reflection number five, 31-reflection number six, 32-relatively fast decay rate, 33-relatively slow decay rate, 34-acoustic waveform data, 35-normalized waveform, 36-reference waveform, 37-spectrum, 38-mirror spectrum, 39-normalized spectrum, 40-modeled spectrum, 41-modeled waveform, 42-new reference waveform, 43-notch number one, 44-notch number two, 45-time window number one, 46-time window number two, 47-windowed waveform number one, 48-windowed waveform number two, 49-windowed spectrum number one, and 50-windowed spectrum number two.
Detailed Description
In order to make the objects, technical solutions and advantages of the embodiments of the present invention clearer, the technical solutions in the embodiments of the present invention are clearly and completely described, and it is obvious that the described embodiments are a part of the embodiments of the present invention, but not all of the embodiments. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.
Comparative example 1
In one drilling operation one wellbore 3 is drilled and the annulus 5, i.e. the space between the wellbore 3, the casing 6 and the casing collar 7, is sealed by cementing operations using an annular packing material 4.
As shown in fig. 1, the casing 6 represents the length of casing string joined together by casing collar 7 to form a stable wellbore, and the casing 6 and casing collar 7 may be made of carbon steel, stainless steel, or other suitable material to withstand various pressures, such as collapse, burst, and tensile failure, as well as chemical fluid erosion. The surface equipment 1 may perform various logging operations to detect the condition of the wellbore 3; logging operations may measure parameters of the geological formation 2 (e.g., resistivity or porosity) and the wellbore 3 (e.g., temperature, pressure, fluid type, or fluid flow rate); the sonic logging instrument 9 may provide sonic cement evaluation and wellbore integrity data (e.g., casing thickness, optoacoustic impedance, drilling fluid impedance, etc.) that are used to verify cement installation and zonal isolation of the wellbore 3.
The acoustic tool 9 is conveyed through the wellbore 3 by a cable 10, which cable 10 may be a mechanical or electro-optical cable containing optical fiber lines protected from the harsh wellbore environment. Of course, the sonic tool 9 may be conveyed using other suitable conveyance means, such as coiled tubing. There may be drilling fluid 8 around the acoustic tool 9 as it is conveyed in the wellbore 3.
The sonic tool 9 may be deployed within the wellbore 3 by a surface facility 1, which surface facility 1 may include a vehicle 11 (the vehicle 11 may be equipped with a computer or software communication for data collection and analysis) and a rig 12 or like deployment system; data relating to the geological formation 2 or the wellbore 3 collected by the sonic tool 9 may be transmitted to the surface or stored in the sonic tool 9 for later data processing and analysis.
Fig. 1 also schematically shows an enlarged view of a portion of the cased wellbore 3. As described above, the sonic tool 9 may obtain acoustic data 13 (e.g., sonic waveforms) for assessing the integrity of the cased wellbore 3. When the sonic tool 9 provides measurements to the surface equipment 1 (via the cable 10), the surface equipment 1 may communicate the measurements as acoustic data 13 to a data processing system 14 (e.g., a cement evaluation system), the data processing system 14 including a processor 15, a memory device 16, a memory 17, and a display 18.
The data processing system 14 may collect acoustic data 13, which acoustic data 13 may evaluate characteristics related to the integrity of the wellbore 3, such as the thickness of the casing 6, the apparent acoustic impedance of the annular filler material 4, and the apparent acoustic impedance of the drilling fluid 8. Processor 15 may execute instructions that are stored in memory 16 and memory 17. The memory means 16, 17 may be a ROM memory, a Random Access Memory (RAM), a flash memory, an optical storage medium or a hard disk drive, etc. The display 18 may be any suitable electronic display that can display other information about the classification of the material in the annulus 5 behind the casing 6 in the wellbore 3. The processor 15 may be a computer, may be a processor including one or more application specific processors (e.g., ASICs), may be one or more field programmable logic arrays (FPGAs), or a combination thereof. The data processing system 14 may include a Graphical User Interface (GUI) so that a user may interact with the processor 15. Processor 15 may also include other types of processors (e.g., a microprocessor, a microcontroller, a digital signal processor, or a general purpose computer) for performing the processes herein.
The sonic tool 9 may be an ultrasonic imager (usi.tm) or an isolated scanner, and may obtain pulse-echo measurements using thickness mode (in the manner of an ultrasonic imaging tool), or may capture measurements using the pitch of the casing in bending mode. The ultrasonic pitch capture technique may be based on excitation and detection of casing quasimmer modes, often referred to as the lowest order anti-symmetric mode (AO) of the flexural mode. The casing bend mode also radiates elastic energy into the annulus between the casing and the formation (or between the primary and secondary casings in the case of multiple strings). When the annulus is filled with cement, either shear or longitudinal waves may radiate to the cement layer, depending on the mechanical properties of the cement or annulus material.
With this in mind, FIG. 2 provides a general example of the operation of the sonic tool 9 in the wellbore 3, and in particular, the transducer 21 in the sonic tool 9 may emit a first acoustic wave 22 toward the casing 6 and form a first reflected wave 23, a second reflected wave 24, and a third reflected wave 25 corresponding to the casing 6, annular fill 4, and geological formation 2 interfaces, respectively. The first reflected wave 23, the second reflected wave 24, and the third reflected wave 25 depend on whether the annular filler material 4 is a generally solid feature 19 or a generally liquid or gas feature 20. The reflected waves 23, 24, and 25 may be received at the same transducer 21 for cement evaluation. The sonic tool 9 may use any number of different techniques, including measurements of acoustic impedance from sonic, ultrasonic, or flexural attenuation. When one or more of these acoustic cement evaluation data are obtained, they may be processed integrally to determine the characteristics of the annular packing 4.
FIG. 3 provides another example of an acoustic tool 9 having a transmitter 26 and a pair of receiver transducers 27. A transmitter 26 in the sonic logging instrument 9 may transmit acoustic energy 28 into the wellbore 3, thereby generating a reflected wave number four 29, a reflected wave number five 30, and a reflected wave number six 31. In fig. 2, the emitted energy excites predominantly zero-order asymmetric modes (also called bending modes); in fig. 3, acoustic energy 28 propagates by transmission to both sides of the casing 6. The transmission in the annulus of the casing is dependent on the material outside the casing wall, with varying degrees of energy leakage in the annulus. The acoustic tool 9 depicted in FIG. 3 may use acoustic impedance measurements from flexural attenuation because different distances of the transmitter 26 and a pair of receiver transducers 27 and energy leakage may result in different amplitudes for the measured acoustic pressure.
The present technique is applicable to thickness mode, pulse-echo measurements (as shown in FIG. 2), and bending mode, pitch capture measurements (as shown in FIG. 3). The acoustic data 13 may include acoustic or reflected waves from the casing 6, the annular packing material 4, the geological formation 2, the drilling fluid 8, and the casing 6, or any interface thereof. The acoustic data 13 may also be referred to as acoustic waveforms or measurement waveforms.
Various acoustic processing techniques have been used to estimate model-based annular acoustic impedance, where the thickness resonance depends on the reflection coefficients of the casing inner and outer walls. The reflection coefficient may be defined as the acoustic impedance of the medium at these interfaces (e.g., the interface between the drilling fluid and the casing material, the interface between the casing and the annulus material, etc.). As shown in FIG. 4, different conditions behind the casing 6 may result in significantly different resonance tail decay behavior of the received waveform, with the resonance tail possibly having a relatively fast decay rate 32 when the annular packing material 4 behind the casing 6 is a generally solid feature 19, and a relatively slow decay rate 33 when a generally liquid or gas feature 20 is present behind the casing 6.
In some conventional acoustic processing techniques, a loop parameter such as loop acoustic impedance may be obtained by matching an observed acoustic waveform to a synthesized acoustic waveform predicted using one-dimensional modeling of estimated parameters. From this, the impedance of the casing and mud can be assumed. This type of model can suitably approximate the following situation: the energy is mainly compressed and normally propagates to the casing wall where it is assumed to be planar and the shear mode conversion is insignificant in the region where the sensor beam contacts the casing wall. However, when the casing is relatively thick (e.g., greater than 1 millimeter thick), heavy drilling fluids are used, wellbore inclination, or tool eccentricities, three-dimensional propagation effects and shear mode conversion can affect the accuracy and stability of conventional acoustic inversion processing techniques. Furthermore, conventional processing techniques using known or assumed mud impedances may also be inaccurate because many weighted muds and specially formulated muds may not have known mud resistances. The use of such assumptions in conventional processing techniques can result in poor accuracy of the estimate of the acoustic impedance of the annulus for the above reasons.
Example 1
Referring to fig. 5, a method of determining a property of a wellbore in a geological formation, comprises the steps of:
(1) acquiring acoustic waveform data: acquiring acoustic data from an acoustic logging tool, namely inputting acoustic waveform data consisting of one or more reflected acoustic waves from the acoustic logging tool deployed in a wellbore of a casing; acoustic data herein refers to casing thickness.
(2) Normalized acoustic waveform: normalizing the sound wave data by using a normalization working process to obtain a normalized wave; the normalization workflow, referring to fig. 6 and 7, converts acoustic waveform data 34 from the time domain to the frequency domain using a fourier transform, thereby producing a spectrum 37; the spectrum 37 can be used to estimate a specular spectrum 38 (the specular spectrum 38 can be a waveform generated from a priori knowledge that is similar in shape to the spectrum 37 but without notches; can be a first echo from the first interface of the casing that approximates the first sound wave 54); normalizing spectrum 37 with a mirror spectrum to obtain normalized spectrum 39, (where normalized spectrum 39 may be an approximation of the system response spectrum of an infinite short pulse); normalizing the normalized spectrum 39 again using a molding spectrum 40 (such as the gaussian curve described) to produce a molding waveform 41 for removing other echoes from other interfaces in the wellbore or other disturbances or noise in the wellbore; the modeled waveform 41 is converted from the frequency domain to the time domain to produce the normalized waveform 35.
(3) And (3) workflow reversal processing: referring to fig. 8, the reference waveform 36 is estimated based on the estimated casing thickness, specifically, the reference waveform 36 based on the thickness is obtained by looking up a table or referring to a reference wave database according to the known casing thickness. Referring to fig. 8 and 9, comparing the normalized waveform 35 with the reference waveform 36 shows that the notches of the normalized waveform 35 and the reference waveform 36 are respectively characterized by the notch one number 43 and the notch two number 44, and the frequency difference Δ f between the notch one number 43 and the notch two number 44 is significant (fig. 9-1), which indicates that the normalized waveform 35 does not match the reference waveform 36, and at this time, the previous thickness estimate needs to be adjusted to obtain a new thickness estimate Tnew, and the formula for calculating the new thickness estimate Tnew is as follows:
where T0 is the initial or previous thickness, Δ f is the frequency difference between the two waveforms of normalized waveform 35 and reference waveform 36, and c is the speed of sound;
a new reference waveform 42 is then generated based on the new thickness estimate Tnew, and the normalized waveform 35 is iteratively compared with the new reference waveform 42 until the resonance notch of the normalized waveform 35 and the resonance notch of the new reference waveform 42 match, i.e., the notch one 43 and the notch two 44 substantially match (fig. 9-2), and the waveform at this time is the best-fit reference wave. In the above process, Δ f lower than a certain threshold may be used as a basis for determining matching according to actual conditions.
(4) And (3) parameter output: and determining and outputting a casing thickness parameter T according to the best fit reference wave.
Example 2
A method of determining a property of a wellbore in a geological formation, comprising the steps of:
(1) acquiring acoustic waveform data: acquiring acoustic data from an acoustic logging tool, namely inputting acoustic waveform data consisting of one or more reflected acoustic waves from the acoustic logging tool deployed in a wellbore of mud, casing and annular packing material; the acoustic waveform data is a resonance tail which is generated by the mixed sound in the casing and is similar to exponential attenuation, and the resonance tail has different reactions and sensitivities to the acoustic impedance changes of the mud and the annular filler, and is respectively expressed as the acoustic impedance Za of the annular filling material and the acoustic impedance Zm of the mud;
(2) normalized acoustic waveform: the obtained acoustic waveform data is normalized by the normalization workflow, and a normalized waveform 35 is obtained.
(3) And (3) workflow reversal processing: forming a reference waveform 36 by looking up a reference wave database from known wellbore parameters using a reference wave generator, model, waveform synthesizer or combination thereof; comparing the normalized waveform 35 with the reference waveform 36 results in the two waveforms plotted in the time domain as shown at 11-1 in FIG. 11 being substantially matched, but to better utilize the attenuation of the normalized waveform 35 and the reference waveform 36The tails to estimate acoustic impedance require a comparison of normalized waveform 35 and reference waveform 36 in a comparable manner, i.e., Hilbert transform f of normalized waveform 35 and reference waveform 36 inputs and taking the logarithm of their absolute values, expressed as log (| H (f) |), then the log-Hilbert of normalized waveform 35 and reference waveform 36 can linearly represent the exponential decay of the resonance tail. As shown at 11-2 in fig. 11, the log-Hilbert transformed normalized waveform 35 can be compared to the log-Hilbert transformed reference waveform 36. If the log-Hilbert transformed normalized waveform 35 does not match the log-Hilbert transformed reference waveform 36, then the mud acoustic impedance Zm and the annulus acoustic impedance Za of the model need to be adjusted (11-3 in FIG. 11, increasing the mud acoustic impedance Zm changes the amplitude of the tail and slightly decreases its slope; 11-4 in FIG. 11, increasing the ring acoustic impedance Za increases the slope of the tail while substantially maintaining the absolute offset), iteratively generating a new reference waveform 42; and the normalized waveform 35 after the log-Hilbert transformation is iteratively compared with the new reference waveform 42 after the log-Hilbert transformation until the normalized waveform and the new reference waveform are matched, wherein the waveform at the moment is the best fitting reference wave. Wherein the parameterization for describing the attenuation tail of the received waveform comprises a straight line drawn through the attenuation tail in log-Hilbert space, denoted y-kx + b, a bijection
The relationships corresponding to:
[k，b]＝f(Zmud，Zcem)
the explicit form of f may not allow direct determination of the inverse function f-1 such that
[Zmud，Zcem]＝f-1(k，b)
However, by representing the reference waveform in the same log-Hilbert space, it can be for each [ Z [ ]mud， Zcem]Determine a pair [ k ]syn，bsyn]. Can determine [ ksyn，bsyn]For the initial parameters [ k, b]Z corresponding to the matching normalized waveform 35, new reference waveform 42mud，Zcem]。
(4) And (3) parameter output: and determining and outputting the acoustic impedance Za of the annular filling material and the acoustic impedance Zm of the mud according to the best-fit reference wave.
Example 3
A method of determining a property of a wellbore in a geological formation, comprising the steps of:
(1) acquiring acoustic waveform data: acquiring acoustic data from an acoustic logging tool, in particular inputting acoustic waveform data consisting of one or more reflected acoustic waves from the acoustic logging tool deployed in a wellbore of mud, casing and annular packing material; wherein the acoustic logging tool is a pulse echo logging tool;
(2) normalized acoustic waveform: normalizing the obtained acoustic waveform data by using a normalization workflow to obtain a normalized waveform 35;
(3) and (3) workflow reversal processing: forming a reference waveform 36 by looking up a reference wave database from known wellbore parameters using a reference wave generator, model, waveform synthesizer or combination thereof; comparing the normalized waveform 35 with the reference waveform 36 shows that the two waveforms substantially match, but to better compare the resonant frequencies of the normalized waveform 35 and the reference waveform 36, a time window may be applied to the initial waveform in the time domain to limit the length of the resonant tail.
As in fig. 13, two time windows, time window number one 45 and time window number two 46, are depicted around normalized waveform 35 and reference waveform 36 to produce corresponding windowed waveform number one 47 and windowed waveform number two 48, which windowed waveform number one 47 and windowed waveform number two 48 are then converted by frequency conversion to the frequency domain where the windowed spectra of windowed waveform number one 47 and windowed waveform number two 48, i.e., windowed spectrum number one 49 and windowed spectrum number two 50, are plotted, respectively.
The above method may be applied to normalized waveform 35 and reference waveform 36 to effect frequency translation of normalized waveform 35 and reference waveform 36 (converting the windowed waveform of each normalized waveform 35 and reference waveform 36) and comparing separately, and the windowed spectrum 49 of windowed waveform number one 47 generated by applying normalized waveform 35 to time window number one 45 may be compared to the spectrum of the waveform of reference waveform 36 applied to time window number one 45. The second windowed spectrum 50 of second windowed waveform 48 resulting from application of second time window 46 by normalized waveform 35 may be compared to the spectrum of the waveform applied to second time window 46 by reference waveform 36. The windowed spectrum is then fitted around the resonant frequency to determine if the spectra sufficiently match. If each normalized waveform 35 does not match the windowed spectrum of reference waveform 36, the mud acoustic impedance Zm and the ring acoustic impedance Za of the model may be adjusted to generate a new reference waveform 42, and a new reference waveform 42 may be selected from a lookup table or database based on the different Zm and Za.
The best fit spectrum belongs to a curve proportional to the relationship Za ═ f (Zm, Win _ Length), where Win _ Length is the same window Length applied to the normalized waveform 35 and the reference waveform 36. By varying the second parameter of the window length, a different set of solutions may be obtained for each different value. The best matching reference spectrum of a first window may be identified relative to the corresponding normalized spectrum of the same window, and the other best matching reference spectrum of a second window may be identified relative to the corresponding normalized spectrum of the same window.
Since point (Za, 0, Zm, 0) corresponds to a real-world understanding belonging to all curves, Zm and Za may be determined at the intersection of curves corresponding to two or more different window-length values. The following relationship indicates how Zm and Za are searched using the system of equations:
accordingly, identifying the intersection of the best-fit curves over two or more windows may output Zm and Za.
(4) And (3) parameter output: and determining and outputting the acoustic impedance Za of the annular filling material and the acoustic impedance Zm of the mud according to the intersection of the best fitting curves.
Example 4
FIG. 14 provides example test results obtained with a 12 mm thick casing immersed in 4.54Kg of oil-based mud. The Zm output is shown at 51, the Za output is shown at 52, both processed by prior art resonance inversion, and the output processed by conventional techniques is shown at 53. Each of the figures is expressed in terms of eccentricity. As can be seen from the figure, the resonance-based inversion technique is largely independent of the borehole fluid. In fact, Zm is the output of current resonance-based inversion techniques, rather than the output of conventional techniques. Furthermore, resonance inversion processes 51 and 52 exhibit better stability in terms of standoff distance than conventional art process output 53. In the Za output 52 of the resonance inversion process, the effect of eccentricity is visible, but in some embodiments the tool eccentricity may be adjusted by taking the eccentricity as an input variable and matching the measured property (e.g., the attenuation line) to a reference line.
FIG. 15 is a comparison of results using the resonance-based inversion technique of the present invention with those obtained using other types of processing or acoustic measurements. Specifically, 54 in the figure represents Za delineated from conventional pulse-echo processing techniques, 55 in the figure represents Za delineated using the present technique, 56 in the figure represents Zm delineated using the present technique, 57 in the figure represents estimated casing thickness (within 3% similarity) using conventional and prior art techniques, and 58 in the figure is an image obtained by bend attenuation. Generally, logs 55 and 56 show a high similarity to logs 54 and 58, and in particular, log 55 has a greater similarity to log 58 than log 55, probably because current techniques are less sensitive to the third interface.
FIG. 16 shows a portion of a log 54 located in a deviated casing, where log 59 represents Za processed using conventional techniques, log 60 represents Za processed using the present techniques, log 61 represents Zm processed using the present techniques, log 62 represents casing thickness processed by the present techniques, and log 63 represents a comparison of thickness estimates between conventional techniques and processes of the present techniques. The log 59 shows a clear narrow channel of low impedance, which is a false channel, which disappears in the log 60 and is replaced by a stripe of high impedance. These log images on the log 60 are consistent with expectations, suggesting that mud particles may be deposited at the bottom of the casing, resulting in a slight increase in its acoustic impedance. The inversion technique provided in the present invention allows for the presence of mud deposits, as shown by logs 59 and 60. Furthermore, the new result of outputting Zm is the same as in the log 61.
It should be understood that the above-described specific embodiments are merely illustrative of the present invention and are not intended to limit the present invention. Obvious variations or modifications which are within the spirit of the invention are possible within the scope of the invention.
Claims (10)
1. A method of determining a property of a wellbore in a geological formation, the method comprising the steps of:
(1) acquiring acoustic waveform data: acquiring acoustic data from an acoustic logging tool, in particular inputting one or more acoustic waveform data consisting of reflected acoustic waves from an acoustic logging tool deployed in a wellbore of mud, casing and annular packing material; wherein the acoustic logging tool is a pulse echo logging tool;
(2) normalized acoustic waveform: normalizing the sound wave data by using a normalization working process to obtain a normalized wave;
(3) and (3) workflow reversal processing: looking up a reference wave database by looking up a table according to known wellbore parameters, and forming a reference waveform by using a reference wave generator, a model, a waveform synthesizer or a combination thereof; then, fitting the normalized waveform and the reference waveform in the same way to ensure that the two waveforms have practical significance; then, comparing the fitted normalized waveform with the fitted reference waveform, and outputting a best-fit reference wave if the waveforms are matched; if not, generating a new fitting reference wave by adopting an iterative inverse demonstration method on the basis of comparison, and iteratively comparing the fitting normalized wave with the new fitting reference wave until the best fitting reference wave is determined;
(4) and (3) parameter output: and determining and outputting wellbore parameters according to the best fit reference wave.
2. A method of determining a property of a wellbore in a geological formation according to claim 1, characterized by: the normalization work flow in the step (2) is as follows: converting the acoustic waveform data into a frequency domain to generate a spectrum; estimating a specular spectrum from the spectrum; normalizing the spectrum by using the mirror spectrum to obtain a normalized spectrum; normalizing the normalized frequency spectrum again by using the plastic frequency spectrum to obtain a plastic waveform; converting the plastic waveform into a time domain to obtain a normalized waveform; wherein said estimating a mirror spectrum from the spectrum comprises using a priori knowledge about the wellbore; the wellbore includes a casing, an annular packing material between the casing and the formation, and a mud between the casing and the sonic logging tool.
3. A method of determining a property of a wellbore in a geological formation according to claim 1, characterized by: the reference waveform of step (3) comprises a reference waveform generated from an initial casing thickness estimate.
4. A method of determining a property of a wellbore in a geological formation according to claim 1, characterized by: the new fitted reference wave parameters in the step (3) comprise a reference waveform estimated after the thickness of the sleeve is iteratively adjusted, a reference waveform estimated after the acoustic impedance of the slurry is iteratively adjusted, a reference waveform estimated after the acoustic impedance of the annular filling material is iteratively adjusted, and a reference waveform estimated after the acoustic impedance of the slurry and the acoustic impedance of the annular filling material are iteratively adjusted.
5. A method of determining a property of a wellbore in a geological formation according to claim 1, characterized by: the fitting manner of the step (3) comprises the use of log-Hilbert transform and frequency conversion.
6. A method of determining a property of a wellbore in a geological formation according to claim 1, characterized by: the frequency conversion is performed by applying a first window to the reference waveform and the normalized waveform to produce a first windowed reference waveform and a first windowed normalized waveform; applying a second window to the reference waveform and the normalized waveform, thereby generating a second windowed reference waveform and a second windowed normalized waveform; converting the first windowed reference waveform, the second windowed reference waveform, and the first windowed normalized waveform, the second windowed normalized waveform to the frequency domain, thereby generating a first reference spectrum, a second reference spectrum, a first normalized spectrum, and a second normalized spectrum; matching the first reference spectrum to a first normalized spectrum to determine a first best fit reference spectrum; matching the second reference spectrum to the second normalized spectrum to determine a second best fit reference spectrum; and determining the acoustic impedance of the annular filler material and the acoustic impedance of the mud based on the intersection of the first reference spectrum and the second reference spectrum.
7. A method of determining a property of a wellbore in a geological formation according to claim 1, characterized by: and (4) the output parameters comprise the thickness T of the casing pipe, the acoustic impedance Za of the annular filling material and the acoustic impedance Zm of the slurry.
8. A method of determining a property of a wellbore in a geological formation according to claim 1, characterized by: the method may be performed using a non-transitory computer readable medium storing computer executable instructions, the entire process requiring at least one processor to perform.
9. A method of determining a property of a wellbore in a geological formation according to claim 1, characterized by: said step (2) may be accomplished by at least one non-transitory computer-readable medium storing computer-executable instructions; said step (3) may be accomplished by at least one non-transitory computer-readable medium storing computer-executable instructions; the step (4) may be accomplished by at least one non-transitory computer-readable medium storing computer-executable instructions.
10. A method of determining a property of a wellbore in a geological formation according to claim 1, characterized by: the annular filler material may be cement, resin, or the like.
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| CN116660997A (en) * | 2023-08-02 | 2023-08-29 | 中海油田服务股份有限公司 | Inversion method and device for acoustic impedance of medium inside and outside sleeve and electronic equipment |
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