EP0332585A2 - Tragbare Vorrichtung zum Speichern von Wasser unter Druck, das in der Form eines zerstäubten Strahles verteilt wird - Google Patents

Tragbare Vorrichtung zum Speichern von Wasser unter Druck, das in der Form eines zerstäubten Strahles verteilt wird Download PDF

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Publication number
EP0332585A2
EP0332585A2 EP89830029A EP89830029A EP0332585A2 EP 0332585 A2 EP0332585 A2 EP 0332585A2 EP 89830029 A EP89830029 A EP 89830029A EP 89830029 A EP89830029 A EP 89830029A EP 0332585 A2 EP0332585 A2 EP 0332585A2
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EP
European Patent Office
Prior art keywords
waveforms
source
time
calculating
signature
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.)
Withdrawn
Application number
EP89830029A
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English (en)
French (fr)
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EP0332585A3 (de
Inventor
Giuseppe Beccaria
Enzo Fava
Giuseppe Manfredini
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Individual
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Individual
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Publication date
Priority claimed from IT8847599A external-priority patent/IT8847599A0/it
Priority claimed from IT8800602U external-priority patent/IT215841Z2/it
Application filed by Individual filed Critical Individual
Publication of EP0332585A2 publication Critical patent/EP0332585A2/de
Publication of EP0332585A3 publication Critical patent/EP0332585A3/de
Withdrawn legal-status Critical Current

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    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B05—SPRAYING OR ATOMISING IN GENERAL; APPLYING FLUENT MATERIALS TO SURFACES, IN GENERAL
    • B05B—SPRAYING APPARATUS; ATOMISING APPARATUS; NOZZLES
    • B05B9/00—Spraying apparatus for discharge of liquids or other fluent material, without essentially mixing with gas or vapour
    • B05B9/03—Spraying apparatus for discharge of liquids or other fluent material, without essentially mixing with gas or vapour characterised by means for supplying liquid or other fluent material
    • B05B9/04—Spraying apparatus for discharge of liquids or other fluent material, without essentially mixing with gas or vapour characterised by means for supplying liquid or other fluent material with pressurised or compressible container; with pump
    • B05B9/047—Spraying apparatus for discharge of liquids or other fluent material, without essentially mixing with gas or vapour characterised by means for supplying liquid or other fluent material with pressurised or compressible container; with pump supply being effected by follower in container, e.g. membrane or floating piston, or by deformation of container
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B05—SPRAYING OR ATOMISING IN GENERAL; APPLYING FLUENT MATERIALS TO SURFACES, IN GENERAL
    • B05B—SPRAYING APPARATUS; ATOMISING APPARATUS; NOZZLES
    • B05B1/00—Nozzles, spray heads or other outlets, with or without auxiliary devices such as valves, heating means
    • B05B1/14—Nozzles, spray heads or other outlets, with or without auxiliary devices such as valves, heating means with multiple outlet openings; with strainers in or outside the outlet opening
    • B05B1/18—Roses; Shower heads

Definitions

  • This invention relates to methods for processing of waveform data to profile the earth's subsurface structure in the vicinity of a borehole. More specifically, it relates to methods for estimation and removal of the effect of an unknown source signature by coherency analysis and data adaptive deconvolution filtering.
  • Reflection seismology involves profiling subsurface earth formations to aid in resource prospecting. Seismic energy, in the form of acoustic waves, is generated by a source and coupled to the earth such that the waves travel through the subsurface formations. At each interface between different subsurface layers, a part of the incident acoustic wave is reflected towards one or more receivers, where the energy is recorded for subsequent analysis.
  • the ultimate objective of seismic analysis is to determine the strengths and distribution of reflectors of seismic energy within the earth, such reflectors being intimately related to bedding geometry and differences in material properties.
  • the determination of the distribution of reflecting strength within the earth requires an estimation of the wavefield incident on each reflector, since the reflected wavefield is the result of an interaction of the reflectors with the incident wavefield. This interaction is modeled as the convolution of the reflecting distribution and strengths with the incident wavefield.
  • the sought properties of the reflectors are thus obtained by deconvolving the reflected wavefield by the incident wavefield. If the source is impulsive, the deconvolution is not necessary--if the source has an extended signature, knowledge of the signature enables the reduction to an impulsive signature.
  • VSP vertical seismic profiling
  • MWD measurement while drilling
  • An alternative to using known sources downhole is to use the noise generated by the drill bit as it is drilling as a source of acoustic waves.
  • This MWD method offers a source with uncontrolled characteristics, the signal depending on the design of the drill, the speed of rotation and on the properties of the material in the borehole. Furthermore, there is no starting time for such a signal, for the drill is continuously rotating.
  • the two main problems with using the drill bit as a seismic source are thus the unknown signature of the drill bit noise and the timing of the data.
  • the timing of the data is related to knowledge of the acoustic velocity of the subsurface formations between the drill bit and the receivers.
  • a processing technique for independent determination and deconvolution of the signature of an unknown, non-impulsive acoustic source signal for seismic profiling, and the velocity of the medium in which the source is embedded.
  • the method supposes that an array of receivers is positioned at the earth's surface to detect and record the seismic signals resulting from the interaction of such non-impulsive source with the earth's subsurface.
  • the seismic signals are recorded as data traces at each receiver in the array.
  • Moveout corrections which time-shift the data traces, correct for differences in the arrival times of a wavefront of the direct wave propagating from the source to the receivers in the array.
  • the time-shifts are determined by a coherency analysis of the seismic data, wherein the time difference between the occurrence at adjacent traces of the dominant energy in any single trace, is determined. Since the dominant energy within any single trace is due to direct waves from the source, the moveout corrections synchronize the waveforms of the direct wave across the receiver array.
  • the non-impulsive source signature is estimated as a weighted average of the signals from each time-shifted trace.
  • the weighing factor to be applied to each single trace is estimated from a priori knowledge of the location of other sources contributing to the seismic energy recorded by the traces.
  • the velocity of the medium between the source and the receiver arrays is determined from an analysis of the moveout time-shifts in relation to the geometry of the total ensemble of the source and the receivers. The velocity is used to fix the time reference of the data.
  • the effect of the extended signature of the non-impulsive source on the seismic signals measured by the receiver array is removed by an inverse amplitude deconvolution filter, obtained from the estimate of the source signature.
  • the filter in accordance with the invention, is weighted according to an analysis of the seismic data which, at any given frequency, indicates the strength of the unknown source relative to the total strength of the recorded seismic signal.
  • the present invention describes how the two problems of signature and velocity estimations can be separated and the source signature be reduced to an impulsive signature for any variations of acoustic velocity, provided the drill bit is the strongest subsurface source of acoustic energy.
  • This invention is particularly useful in seismic profiling when continuously emitting sources are used, in particular noise from the drill bit, but is also useful of other downhole acoustic sources with extended signature. Finally, it can be applied to waveform data other the seismic data, such as electromagnetic data generated from a downhole source with an extended time signature.
  • FIG. 1 of the drawings a configuration for the implementation of a reverse VSP (RVSP) technique, using the drill bit 10 as a source of acoustic wave, is shown.
  • the drill bit 10 is inserted into a borehole 12, which transverses the earth formation 18.
  • An array of receivers 14 is positioned on the earth's surface to detect and record acoustic waves resulting from the source, reflected source wavefronts and random noise.
  • the drill bit 10 acts as a source of acoustic waves while it is rotating.
  • the signature of the noise generated by the drill bit is, however, unknown and uncontrolled, depending on the design of the bit, on its speed of rotation in the borehole 12 and on the materials in the borehole 12.
  • the periodic motion of the tool generates a signal with a few strong spectral components, and the signature is by the nature of its generation non-impulsive.
  • Hammering of the drill bit 10 against the bottom of the borehole 12 during drilling operations is a source of energy that widens the frequency spectrum of the drill bit signature. Due to the difficulties involved in having electric wires between the surface and the bottom of the borehole it is not at the present seen feasible to use devices downhole that measures the drill bit noise and transmits these measurements to the surface. This means that the signature of the drill bit noise is not readily available by any standard techniques.
  • a one dimensional array of receivers 20 is shown lying on the surface of the earth 22.
  • the dimensions of the array 20 must be arranged such that its length, 1, satisfies the relationship:
  • a one dimensional array is illustrated in the drawing, a grid or two dimensional array may be utilized, in which case the array should be dimensioned in any direction in accordance with the above requirements.
  • Each vertical line 32 is called a "trace" and represents the variation with respect to time of the acoustic signal at a receiver 16 which is offset from the source 10 by the distance indicated.
  • FIG. 4 of the drawings illustrates the different arrival times resulting from the geometry relating the position of the receiver array 14 and the drill bit 10 of FIG. 1.
  • receivers 40, 42 and 44 are on the earth's surface above source 46, which is directly below receiver 42.
  • a direct acoustic wavefront from the source 46 will reach receiver 42 before reaching receiver 40 and 44 since the path 50 is shorter than paths 48 or 52.
  • the accoustic wave from source 46 will reach receiver 44 before receiver 40 because of the greater offset of receiver 40.
  • the traces 32 associated with receivers 40 and 44 must therefore be time-shifted accordingly, so that the arrival times line up.
  • the determination of the moveout corrections in accordance with the invention is done by performing local coherency analysis of the neighboring traces 32. If the direct acoustic wavefront 54 shown in FIG. 4 dominates the energy of the traces 32, i.e. is stronger than the wavefronts 56 reflected by an interface 57 of two different subsurface formation layers and noise from other sources, the coherency analysis enables the determination of the shape of the wavefront 54, and thereby the time-shifts that need to be applied to compensate for the differences in travel time from the source 46 to the individual receivers.
  • the coherency analysis is implemented in the preferred embodiment by digitizing the analog recordings of the acoustic signals by means of high speed analog to digital converter circuits 45.
  • the digital data is then multiplexed by multiplexer 46 to a standard high speed tape recorder 47 and to a processor 48.
  • the processor 48 transforms the digitized data from the time domain to the frequency domain by means of a Fourier Transform, so that the trace 32 data are described as a function of offset, x, and frequency, w.
  • the "slope", p, for a number of adjacent traces 36 is defined as the time shift 37, per unit of offset 39.
  • a local slant stack, S(xm,w,p), over the 2N + 1 traces 36 centered at offset xm, at slope p, and frequency w, is computed such that: where Sn (w) is the Fourier transform of the recorded acoustic signals at offset Xn and frequency w and e iwpix -x is the Fourier Transform of an operator that shifts the traces in time according to a constant value of p.
  • the local slant stack, S(x m ,w,p,), for each offset, x m , frequency, w, and slope, p, is determined.
  • the energy of each stack is determined such that
  • a measure of local coherency, E(xm,p) may be formed from the correlation of recorded acoustic signals from pairs of adjacent traces: where s m (w) denotes the complex conjugate of s m (w).
  • the time shift at a particular offset xm related to the dominant source is determined by the stack containing the maximum energy at a particular offset.
  • a function, p(x m ), is defined to consist of the (xm,p)-values corresponding to maximum energy E(xm,p) for each offset xm.
  • the function p( Xm ) is integrated to give the moveout, T m , to be applied to each offset:
  • the minimum value of all the calculated T m -values is found and subtracted from the Tm-values already calculated to give a new set of T m -values.
  • This new set of Tm-values are the time delays that are used in the following calculation.
  • the variation of T m with x m is illustrated in FIG. 5.
  • the average velocity of the acoustic medium between source and receivers is determined by fitting a hyperbola to the moveout curve of FIG. 5:
  • the result of applying the time shifts, as determined from the moveout curve in FIG. 5, to the recorded data is shown in FIG. 6.
  • the moveout corrected data represent a family of traces, each containing a copy of the source signature, which have been synchronized across all traces.
  • the next step in the reduction is to apply a data adaptive deconvolution to reduce the extended signature of the drill bit 10 to an impulsive signature, starting at time t m :
  • the best estimate of the signature is the spatial average of the moveout corrected traces: where s m (t + T m ) is the moveout corrected version of the trace measured at the offset xm, and M is the total number of traces.
  • weights w m can be introduced into the estimation of f(t) to reduce the relative importance of the traces measured at offsets x m where the wavefronts of energy coming from the drill bit 10 and wavefronts from other sources are tangent to each other, so that:
  • the standard deconvolution filter may be designed by taking the inverse amplitude at each frequency and multiplying by the desired impulsive signature D(w): where f(w) is the complex conjugate of f(w), and is the inverse amplitude of f(w).
  • the signature f(t) is the signature of a grinding drill bit.
  • the signature f(t) and filer F"(w), are, therefore highly frequency dependent.
  • the deconvolution filter therefore, in accordance with the present invention, includes a weighing based on the reliability of the different frequency amplitudes of the estimated signal.
  • the weighing factor in the preferred embodiment of the invention, is obtained by taking the ratio of the energy of the average trace: to the average energy of the traces:
  • the deconvolution filter then becomes:
  • Applying the filter F(w) to the moveout corrected data shown in FIG. 6 will transform the data into a dataset similar to a dataset that would have been collected if an impulsive source were used at the position of the drill bit, and the directly travelling and reflected waves were recorded at the offsets z m .
  • the result of applying the filter to moveout corrected data is illustrated in FIG. 7, wherein the source signature 90 is reduced to an impulsive type source and the data from reflections 92 is reduced to that which would result from an impulsive source.
  • This data can now be processed using standard processing techniques, such as common depth point (CDP) or migration.
  • CDP common depth point

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  • Geophysics And Detection Of Objects (AREA)
  • Jet Pumps And Other Pumps (AREA)
EP89830029A 1988-02-03 1989-01-27 Tragbare Vorrichtung zum Speichern von Wasser unter Druck, das in der Form eines zerstäubten Strahles verteilt wird Withdrawn EP0332585A3 (de)

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
IT4759988 1988-02-03
IT8847599A IT8847599A0 (it) 1988-02-03 1988-02-03 Dispositivo portatile per doccia a pressione
IT8800602U IT215841Z2 (it) 1988-12-29 1988-12-29 Dispositivo portatile perfezionato per l'accumolo d'acqua in pressione disponibile in fase di prelievo sotto forma di getto forzato frantumato
IT60288U 1988-12-29

Publications (2)

Publication Number Publication Date
EP0332585A2 true EP0332585A2 (de) 1989-09-13
EP0332585A3 EP0332585A3 (de) 1990-07-25

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EP89830029A Withdrawn EP0332585A3 (de) 1988-02-03 1989-01-27 Tragbare Vorrichtung zum Speichern von Wasser unter Druck, das in der Form eines zerstäubten Strahles verteilt wird

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Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO1992004986A3 (en) * 1990-09-15 1992-04-30 David Mitchell Liquid delivery apparatus

Family Cites Families (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB721397A (en) * 1952-08-07 1955-01-05 Anthony Pawson Smith Improvements in and relating to insecticide- and like spraying equipment
BE774544A (fr) * 1971-10-27 1972-02-14 Jadot Pierre Pulverisateur.

Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO1992004986A3 (en) * 1990-09-15 1992-04-30 David Mitchell Liquid delivery apparatus
GB2263421A (en) * 1990-09-15 1993-07-28 David Mitchell Liquid delivery apparatus
GB2263421B (en) * 1990-09-15 1994-03-16 David Mitchell Liquid delivery apparatus
US5316215A (en) * 1990-09-15 1994-05-31 David Mitchell Liquid delivery apparatus

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