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1
Zimmerman, Linda J., and Sen T. Chen. "Comparison of vertical seismic profiling techniques." GEOPHYSICS 58, no. 1 (January 1993): 134–40. http://dx.doi.org/10.1190/1.1443343.
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To study the imaging characteristics of various vertical seismic profiling techniques, two vertical seismic profiles (VSP) and a reversed vertical seismic profile (RVSP), where source and receiver positions are interchanged, were collected in the Loudon Oil Field in Illinois. Both VSPs were collected using a line of dynamite charges on the surface as sources. One was collected with geophones and the other with hydrophones as downhole receivers. The RVSP was collected by detonating 25 gram explosive charges in a well and detecting the seismic response with geophones at the surface. Three subsurface images (VSP with geophones, VSP with hydrophones, and RVSP) were produced using VSP-CDP transforms. For comparison, a surface seismic profile was collected along the same line with dynamite sources and vertical geophone receivers. The RVSP and hydrophone VSP stacked sections both produced higher frequency images at shallower depths than did the geophone VSP stacked section. However, the lower frequency geophone VSP stacked section produced an interpretable subsurface image at much greater depths than either the RVSP or the hydrophone VSP sections. The differences are due in part to the more powerful surface sources that were used for the VSPs than the downhole sources used for the RVSP. Furthermore, tube‐wave noise was a more severe problem for both the RVSP and the hydrophone VSP than for the geophone VSP. The results of this experiment demonstrate that if tube‐wave noise could be suppressed, hydrophone VSPs would provide attractive alternatives to geophone VSPs, because it is much easier and cheaper to deploy multilevel hydrophones downhole than geophones. Also, if a high‐powered, nondestructive source is developed, RVSP could be a practical alternative to VSP since one can easily lay out numerous receivers on the surface to record multioffset or three‐dimensional (3-D) VSP data.
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Suprajitno, M., and S. A. Greenhalgh. "Theoretical vertical seismic profiling seismograms." GEOPHYSICS 51, no. 6 (June 1986): 1252–65. http://dx.doi.org/10.1190/1.1442178.
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Offset vertical seismic profiling (VSP) theoretical seismograms which include multiples and mode conversions can be computed using a modified “reflectivity” method. In this method, the transformed displacement potentials are first calculated by multiplying the source spectrum by the composite reflectivity function. Integration over wavenumber, followed by inverse Fourier transformation over the frequency range of the signal, yields the synthetic trace. The composite reflectivity function for a buried receiver is derived from Kennett’s matrices (Kennett, 1974, 1979) which are synthesized to form phase‐related reflection and transmission coefficients from a layer stack. Both conventional fixed source‐moving receiver and fixed receiver‐walkaway source (multioffset) VSP geometries can be handled easily. The method can also readily accommodate deviated‐hole VSP. The method is general in that no ray needs to be specified. Because the order of the multiples can be controlled, wraparound problems with the discrete Fourier transform can be avoided. The normal‐incidence VSP seismograms can be rapidly generated as a special case. Several examples illustrate the method. Some classes of laterally varying structures can be approximately handled by restricting the range of ray‐angle integration and by using the principle of superposition.
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Gulati, Jitendra S., Robert R. Stewart, and John M. Parkin. "Analyzing three‐component 3D vertical seismic profiling data." GEOPHYSICS 69, no. 2 (March 2004): 386–92. http://dx.doi.org/10.1190/1.1707057.
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A three‐component 3D vertical seismic profile (VSP) was acquired over the Blackfoot oil field in Alberta, Canada. The VSP survey was recorded simultaneously with a surface seismic program. The objectives of the VSP were to develop recording logistics, data handling, and processing procedures and to determine if the 3D VSP volumes could image the glauconitic sand reservoir of the Blackfoot field. Dynamite shots from the surface seismic survey, which fell within a 2200‐m offset from the recording well, were used in the VSP analysis. The shots were recorded by a string of three‐component borehole receivers that was moved seven times, resulting in a receiver depth range of 400 to 910 m. The borehole data were processed using basic VSP processing techniques that included hodogram analysis, wavefield separation using median filters, and VSP deconvolution. The final P‐P and P‐S image volumes were obtained by VSP common‐depth point and VSP common‐conversion point stacking the upgoing wavefields followed by f‐xy deconvolution. The P‐P and P‐S images from the VSP correlate well with those from the surface seismic survey. Time slices from the VSP also indicate the trend of the sand channel of the Blackfoot field.
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Carswell, Allan, and Wooil M. Moon. "Application of multioffset vertical seismic profiling in fracture mapping." GEOPHYSICS 54, no. 6 (June 1989): 737–46. http://dx.doi.org/10.1190/1.1442701.
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Multioffset vertical seismic profiling (VSP) combines the improved vertical resolution of VSP with the lateral resolution of the conventional seismic method. In this study, the multioffset VSP technique was employed to map the fracture zones in a granite batholith in which the Atomic Energy of Canada Ltd.’s Underground Research Laboratory (URL) is located. With shotpoints along a vertical shaft and receiver arrays on the surface (cemented to outcrops), six 2-D seismic sections were obtained. The upcoming and downgoing events were separated using a Radon transform wave‐field separation method. For the given multioffset experimental configuration, the VSP-CDP transformation converted the VSP section into conventional type seismic sections. The results indicate that the multioffset configuration is an effective method for mapping deep fracture zones, in this case with respect to the URL shaft. However, the VSP-CDP transformation method used in this study tends to stretch the shallow reflection events, resulting in reduced resolution.
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Marzetta, Thomas L., Marion Orton, Alfred Krampe, Lucian K. Johnston, and Paul C. Wuenschel. "A hydrophone vertical seismic profiling experiment." GEOPHYSICS 53, no. 11 (November 1988): 1437–44. http://dx.doi.org/10.1190/1.1442423.
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To reduce the cost of VSP data acquisition, it is necessary to record the VSP signal from a vertical array of geophones for a single operation of the source. Until a vertical array of clamped three‐component geophones is available, it seems logical to evaluate the capabilities of a vertical array of hydrophones, which is much easier to fabricate. It is well known that elastic waves in the solid couple to pressure waves in the borehole fluid. It is also well known that this coupling excites in the borehole fluid energy known as tube‐wave noise that dominates the borehole pressure signal after the first arrival. (The borehole acts as a waveguide.) In this paper we test the effectiveness of velocity filtering of the borehole pressure signal to attenuate the slowly propagating tube‐wave noise and enhance the faster propagating body‐wave signals. Our initial test satisfactorily extracted from the hydrophone array data a strong reflected event that was also observed in the conventional clamped geophone VSP taken in the same borehole. We were not as successful in recovering subsequent weaker reflected signals from the hydrophone data, because of the strong incoherent ambient tube‐wave noise. This incoherency resulted from instrumental limitations that allowed us to record, for each shot, only three of the twelve hydrophone channels available in the vertical array.
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Zhou, Jun, Chun Hui Xie, and Peng Yang. "Calculate Formation Velocity from Vertical Seismic Profiling Data." Applied Mechanics and Materials 599-601 (August 2014): 639–42. http://dx.doi.org/10.4028/www.scientific.net/amm.599-601.639.
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Extracting interval velocity is one of important applications of VSP data. Also, imaging of VSP data requires accurate velocity information. Two kinds of algorithms on the assumption of straight-ray and curve-ray are employed to calculate interval velocity respectively. Comparison of the extracted velocity from the two methods above with real velocity shows that both methods are suitable for VSP data recorded in the vicinity of well, while the algorithm derived from straight-ray fails in the long-offset. Moreover, the curve-ray is more reliable when there are some random errors due to the first arrivals picking.
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Freire, Sergio L. M., and Tad J. Ulrych. "Application of singular value decomposition to vertical seismic profiling." GEOPHYSICS 53, no. 6 (June 1988): 778–85. http://dx.doi.org/10.1190/1.1442513.
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An essential part of the interpretation of vertical seismic profiles (VSP) is the separation of the upgoing and downgoing waves. This paper presents a new approach which is based on the decomposition of time‐shifted VSP sections into eigenimages, using singular value decomposition (SVD). The first few eigenimages of the time‐shifted VSP section contain the contributions of the horizontally aligned downgoing waves. The last few eigenimages contain the contribution of uncorrelated noise components. The separated upgoing waves are recovered as a partial sum of the eigenimages. Important aspects of this approach are that regular sampling of the recording levels is not required, that the first‐break times need not be measured with extreme accuracy, that noise rejection may be automatically included in the processing, and that eigenimages or sums of eigenimages which may be computed as part of the approach can provide important additional information.
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IKAWA, Takeshi. "Exploration of Subsurface Structures: Reflection Seismic Method and VSP (Vertical Seismic Profiling)." Zisin (Journal of the Seismological Society of Japan. 2nd ser.) 47, no. 1 (1994): 103–12. http://dx.doi.org/10.4294/zisin1948.47.1_103.
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Payne, Michael A. "Looking ahead with vertical seismic profiles." GEOPHYSICS 59, no. 8 (August 1994): 1182–91. http://dx.doi.org/10.1190/1.1443676.
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Several operations enhance our ability to predict the subsurface below the bottom total depth (TD) of the well when applied to zero‐offset vertical seismic profiling (VSP) data. Other key issues regarding the use of VSP data in this fashion are resolution and look‐ahead distance. An impedance log is the most useful form for presenting VSP data to look ahead of the drill bit. The VSP composite trace must first tie reliably to the surface seismic section and to the well log synthetic seismogram. The impedance log is obtained by inverting this VSP composite trace. However, before performing the inversion, we need to (1) correct the composite trace for attenuation effects below TD and (2) input velocities to provide low‐frequency information. An exponential gain function applied to the VSP data below TD adequately compensates for the loss of amplitude caused by attenuation. A calibration of the seismically derived velocities with VSP velocities yields the necessary low‐frequency information. These concepts are illustrated using a field data set and its subset truncated above TD. The output of these operations on the VSP data are compared to well log data. The question of resolution with these data was determined with a model VSP data set based on the well log data. The investigations indicate that the resolution attainable from look‐ahead data is on the order of 50–75 ft (15–23 m). This is one‐quarter seismic wavelength for the frequencies present in these data. In addition, the maximum look‐ahead distance for these data is shown to be easily 2000 ft (600) m and, perhaps, 4000 ft (1200 m5). By way of illustration, the techniques described and investigated 6were applied to an offshore VSP data set to yield an impedance log. After calibrating this curve with the well log data, the base of the target sand was correctly identified below TD. This prediction successfully yielded the thickness of the sand. Individual zones within the sand unit were identified with less confidence.
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Zhou, Hua-wei. "First-break vertical seismic profiling tomography for Vinton Salt Dome." GEOPHYSICS 71, no. 3 (May 2006): U29—U36. http://dx.doi.org/10.1190/1.2192970.
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Building laterally depth-varying velocity models for vertical seismic profiling (VSP) imaging is challenging because of the narrow ray-angle coverage of VSP data, especially if only first arrivals are used. This study explores the potential of a new deformable-layer tomography (DLT) for building velocity models with a VSP data set acquired over the Vinton salt dome in southwestern Louisiana. The DLT method uses first breaks to constrain the geometry of velocity interfaces from an initial model of flat, constant-velocity layers parameterized using a priori geologic and geophysical information. A progressive multiscale inversion loop gradually updates the interface geometry. The final solution model, containing 3D geometry, is well supported by resolution and reliability tests and closely matches the long-wavelength trends of area sonic logs. The presence of velocity anisotropy is also indicated.
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Chen, Genmeng, Janusz Peron, and Luis Canales. "Rapid VSP-CDP mapping of 3-D VSP data." GEOPHYSICS 65, no. 5 (September 2000): 1631–40. http://dx.doi.org/10.1190/1.1444851.
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Vertical seismic profiling‐common depth point (VSPCDP) mapping with rapid ray tracing in a horizontally layered velocity model is used to create 3-D image volumes using Blackfoot and Oseberg 3-D vertical seismic profiling (VSP) data. The ray‐tracing algorithm uses Fermat’s principle and is specially programmed for the layered model. The algorithm is about ten times faster than either a 3-D VSP-CDP mapping program with an eikonal traveltime computation method or a 3-D VSP Kirchhoff migration program. The mapping method automatically separates the image zone from the nonimage zone within the 3-D image volume. The Oseberg data example shows that the lateral extent of the image zone created by the 3D VSP-CDP mapping is larger than that created by 3-D VSP Kirchhoff migration. The same sample result also provides high‐frequency events at target zones. We include an analysis of the imaging error induced from using a horizontally layered model for the Oseberg data, indicating that the method is reliable in the presence of gently dipping structure.
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Hokstad, Ketil, Rune Mittet, and Martin Landrø. "Elastic reverse time migration of marine walkaway vertical seismic profiling data." GEOPHYSICS 63, no. 5 (September 1998): 1685–95. http://dx.doi.org/10.1190/1.1444464.
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Walkaway vertical seismic profiling (VSP) acquisition with three‐component geophones allows for direct measurement of compressional as well as shear energy. This makes full elastic reverse time migration an attractive alternative for imaging data. We present results from elastic reverse time migration of a marine walkaway VSP acquired offshore Norway. The reverse time migration scheme is based on a high‐order finite‐difference solution to the two‐way elastic wave equation. Depth images of the subsurface are constructed by correlation of forward‐ and back‐propagated elastic wavefields. In the walkaway VSP configuration, the number of shots is much larger than the number of geophone levels. Using processing methods operating in the shot/receiver domain, it is advantageous to use the reciprocal relationship between the walkaway VSP and the reverse VSP configurations. We do this by imaging each component of each geophone level as a reverse VSP common shot gather. The final images are constructed by stacking partial images from each level. The depth images obtained from the vertical components reveal the major characteristics of the geological structure below geophone depth. A graben in the base Cretaceous unconformity and a faulted coal layer can be identified. The horizontal components are more difficult to image. Compared to the vertical components, the horizontal component images are more corrupted by migration artifacts. This is because the horizontal component images are more sensitive to aperture effects and to the shear‐wave velocity macromodel. When converted to two‐way time, the migration results tie well with the surface seismic section. Comparison of fully elastic and acoustic reverse time migration shows that the vertical component is dominantly PP-reflected events, whereas the horizontal components get important contributions from PS-converted energy. The horizontal components also provide higher resolution because of the shorter wavelength of the shear waves.
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Wang, Yanghua. "Stable Q analysis on vertical seismic profiling data." GEOPHYSICS 79, no. 4 (July 1, 2014): D217—D225. http://dx.doi.org/10.1190/geo2013-0273.1.
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Vertical seismic profiling (VSP) provides a direct observation of seismic waveforms propagating to various depths within the earth’s subsurface. The [Formula: see text] analysis or attenuation ([Formula: see text]) analysis based on direct comparison between individual waveforms at different depths, however, suffers from the problem of instability commonly due to fluctuations inherent in the frequency spectrum of each waveform. To improve the stability, we considered frequency and time variations and conducted [Formula: see text] analysis on an integrated observation. First, we transformed the time- (or depth-) frequency-domain spectrum to a 1D attenuation measurement with respect to a single variable, the product of time and frequency. Although this 1D measurement has a higher signal-to-noise ratio than the 2D spectrum in the time-frequency domain, it can also be used to further generate a stabilized compensation function. Then, we implemented two [Formula: see text]-analysis methods by data fitting (in a least-squares sense) to either the attenuation measurement or the data-driven gain function. These two methods are theoretically consistent and practically robust for conducting [Formula: see text] analysis on field VSP data.
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Hardage, Bob, and James DiSiena. "Focusing on SEG Continuing Education: VSP Vertical Seismic Profiling." Leading Edge 4, no. 8 (August 1985): 49–51. http://dx.doi.org/10.1190/1.1439173.
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Nadri, Dariush, Milovan Urosevic, Paul Wilkes, and Mehdi Asgharzadeh. "Tube Wave removal from vertical seismic profiling (VSP) surveys." ASEG Extended Abstracts 2012, no. 1 (December 2012): 1–4. http://dx.doi.org/10.1071/aseg2012ab395.
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Bulant, Petr, and Luděk Klimeš. "Comparison of VSP and sonic-log data in nonvertical wells in a heterogeneous structure." GEOPHYSICS 73, no. 4 (July 2008): U19—U25. http://dx.doi.org/10.1190/1.2907243.
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To compare the results of sonic-log measurements and of vertical seismic profiling (VSP), sonic-log velocities are used to estimate the corresponding traveltime in the geologic structure, which is then compared with the VSP traveltime. We show how to calculate the sonic-log traveltime in the geologic structure from the sonic-log velocities while taking into account the effects of the nonvertical propagation of seismic waves, resulting from the VSP-source offset and from heterogeneous velocity in the structure, together with the effects of the well trajectory deviating from strictly vertical. Errors caused by the commonly used assumption of vertical propagation may considerably exceed the difference of the measured VSP traveltimes from the sonic-log traveltimes.
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Moon, Wooil, Allan Carswell, Roger Tang, and Chris Dilliston. "Radon transform wave field separation for vertical seismic profiling data." GEOPHYSICS 51, no. 4 (April 1986): 940–47. http://dx.doi.org/10.1190/1.1442151.
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The data obtained by the vertical seismic profiling (VSP) method require unique processing before interpretation. An important step is the separation of upgoing and downgoing signals by application of an f-k velocity filter and muting of the direct wave. Similarly, if the VSP section is transformed to the p-τ plane, the upgoing and downgoing wave fields become separable because they map to different p-τ quadrants according to their dips. This allows either wave field to be reconstructed by application of the inverse Radon transform after windowing in the p-τ plane. Results obtained by the Radon transform wave field separation (RTWS) method are similar to those obtained by f-k velocity filtering. However, by implementing an amplitude‐ratio testing filter in the forward slant stack, the quality of the reconstructed wave field is much improved. For a specific range of p-stack values in the forward transform, this filter sorts and removes the unwanted events from the desired ones by testing their consistency in stack amplitudes. Synthetic examples of separating the upgoing wave field from a full VSP wave field by both methods are presented.
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Wuenschel, Paul C. "Removal of the detector‐ground coupling effect in the vertical seismic profiling environment." GEOPHYSICS 53, no. 3 (March 1988): 359–64. http://dx.doi.org/10.1190/1.1442469.
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In a “controlled” experiment with the Gulf VSP tool, the detector‐ground coupling was measured and removed from the recorded signal using the Washburn‐Wiley algorithm. Repeat measurements were made at a common detector depth with two coupling configurations, the first to permit the true ground motion to be recorded and the second to ensure that a coupling resonance existed within the seismic frequency band. The algorithm removed the distortion of the body‐wave portion of the seismogram caused by the coupling resonance for the second configuration and recovered true ground motion. However, lowering the coupling resonance into the seismic band also caused the tool to become sensitive to tube waves. This observation is helpful in evaluating current VSP tools; it implies that any VSP tool that is sensitive to tube waves has a coupling resonance within the seismic frequency band, and that the signal recorded with such a tool does not measure true ground motion. This test also showed that a detector used to monitor source signature variations must have a bandwidth comparable to the VSP signal.
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Whitmore, N. D., and Larry R. Lines. "Vertical seismic profiling depth migration of a salt dome flank." GEOPHYSICS 51, no. 5 (May 1986): 1087–109. http://dx.doi.org/10.1190/1.1442164.
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Vertical seismic profiles (VSPs) can supply information about both velocity and subsurface interface locations. Properly designed VSPs can be used to map steeply dipping interfaces such as salt dome flanks. Mapping subsurface interfaces with VSP data requires careful survey design, appropriate data processing, interval velocity estimation, and reflector mapping. The first of these four ingredients is satisfied, in most cases, by preacquisition modeling. The second is accomplished by careful data processing. Initial velocity estimates are provided by seismic tomography. Velocity‐model refinement is accomplished by a combination of iterative modeling and iterative least‐squares inversion. Finally, the resultant interval velocities are used in depth migration of the processed VSP. These four ingredients have been combined to map a salt dome flank.
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Grech, M. Graziella Kirtland, Don C. Lawton, and Samuel H. Gray. "A multioffset vertical seismic profiling experiment for anisotropy analysis and depth imaging." GEOPHYSICS 67, no. 2 (March 2002): 348–54. http://dx.doi.org/10.1190/1.1468595.
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A multioffset vertical seismic profile (VSP) was carried out in the Rocky Mountain foothills of southern Alberta, Canada. The purpose of this experiment was to investigate whether the dipping shale strata exhibit P‐wave velocity anisotropy and, if so, to calculate the Thomsen anisotropy parameters for use in anisotropic depth migration. Traveltime inversion of first‐arrival data from the multioffset VSP revealed that the dipping Mesozoic clastics in the area exhibit seismic velocity anisotropy of about 10%. The anisotropy parameters derived from this experiment were then used in anisotropic prestack depth migration of data from a surface seismic line close to the VSP well. Comparison of the anisotropic migration with the corresponding isotropic prestack depth migration showed that the target was imaged incorrectly in the isotropic case; a lateral shift of 180 m in the updip direction of the overlying beds was observed. The image obtained with an anisotropic velocity model was also better focused than that obtained assuming isotropic velocities.
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Klokov, Alexander, Damir Irkabaev, Osareni C. Ogiesoba, and Nail Munasypov. "Correlation between seismic diffractions extracted from vertical seismic profiling data and borehole logging in a carbonate environment." Interpretation 3, no. 2 (May 1, 2015): T121—T129. http://dx.doi.org/10.1190/int-2014-0156.1.
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Seismic diffractions may play an important role in seismic interpretation because they characterize geologic objects that might not be visible for conventional seismic attribute analysis. Diffractivity may be caused by, and consequently may define, tectonic dislocations (faults and fractures), lithologic variations, and fluid saturation within rocks. We have tied seismic diffractions extracted from vertical seismic profiling (VSP) data and borehole logging, from which we recognized the reasons that were responsible for diffractivity of the strata. First, we processed a multisource multicomponent VSP data set to extract seismic diffractions and constructed diffraction images of the strata for all three of the VSP data components. Then, we performed joint analysis of well logs and diffractions to obtain petrophysical attributes associated with diffraction images. We divided the rock succession into several units, which have different diffraction properties. We identified compacted rock, alternating intervals, isolated fractured zones, and fluid-saturated layers.
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Kowalsky, Michael B., Seiji Nakagawa, and George J. Moridis. "Feasibility of Monitoring Gas-Hydrate Production With Time-Lapse Vertical Seismic Profiling." SPE Journal 15, no. 03 (March 22, 2010): 634–45. http://dx.doi.org/10.2118/132508-pa.
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Summary Many studies involving the application of geophysical methods in the field of gas hydrates have focused on determining rock-physics relationships for hydrate-bearing sediments, with the goal being to delineate the boundaries of gas-hydrate accumulations and to estimate the quantities of gas hydrate that such accumulations contain using remote-sensing techniques. However, the potential for using time-lapse geophysical methods to monitor the evolution of hydrate accumulations during production and, thus, to manage production has not been investigated. In this work, we begin to examine the feasibility of using time-lapse seismic methods—specifically, the vertical-seismic-profiling (VSP) method—for monitoring changes in hydrate accumulations that are predicted to occur during production of natural gas. A feasibility study of this nature is made possible through the coupled simulation of large-scale production in hydrate accumulations and time-lapse geophysical (seismic) surveys. We consider a hydrate accumulation in the Gulf of Mexico that may represent a promising target for production. Although the current study focuses on one seismic method (VSP), this approach can be extended easily to other geophysical methods, including other seismic methods (e.g., surface seismic or crosshole measurements) and electromagnetic surveys. In addition to examining the sensitivity of seismic attributes and parameters to the changing conditions in hydrate accumulations, our long-term goals in this work are to determine optimal sampling strategies (e.g., source frequency, time interval for data acquisition) and measurement configurations (e.g., source and receiver spacing for VSP), while taking into account uncertainties in rock-physics relationships. The numerical-modeling strategy demonstrated in this study may be used in the future to help design cost-effective geophysical surveys to track the evolution of hydrate properties. Here, we describe the modeling procedure and present some preliminary results.
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Boulfoul, M., and Doyle R. Watts. "Application of instantaneous rotations to S‐wave vertical seismic profiling." GEOPHYSICS 62, no. 5 (September 1997): 1365–68. http://dx.doi.org/10.1190/1.1444240.
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The petroleum exploration industry uses S‐wave vertical seismic profiling (VSP) to determine S‐wave velocities from downgoing direct arrivals, and S‐wave reflectivities from upgoing waves. Seismic models for quantitative calibration of amplitude variation with offset (AVO) data require S‐wave velocity profiles (Castagna et al., 1993). Vertical summations (Hardage, 1983) of the upgoing waves produce S‐wave composite traces and enable interpretation of S‐wave seismic profile sections. In the simplest application of amplitude anomalies, the coincidence of high amplitude P‐wave reflectivity and low amplitude S‐wave reflectivity is potentially a direct indicator of the presence of natural gas.
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Toverud, Tommy, and Bjørn Ursin. "Comparison of seismic attenuation models using zero-offset vertical seismic profiling (VSP) data." GEOPHYSICS 70, no. 2 (March 2005): F17—F25. http://dx.doi.org/10.1190/1.1884827.
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For seismic frequencies it is common to use an empirical equation to model attenuation. Usually the attenuation coefficient is modeled with linear frequency dependence, a model referred to as the Kolsky-Futterman model. Other models have been suggested in the geophysical literature. We compare eight of these models on a zero-offset vertical seismic profiling (VSP) data set: the Kolsky-Futterman, the power law, the Kjartansson, the Müller, the Azimi second, the Azimi third, the Cole-Cole, and the standard linear solid (SLS) models. For three separate depth zones we estimate velocities and Q-values for all eight models. A least-squares model-fitting algorithm gives almost the same normalized misfit for all models. Thus, none of the models can be preferred or rejected based on the given data set. Slightly better overall results are obtained for the Kolsky-Futterman model; for one depth zone, the SLS model gave the best result.
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Yuan, Hemin, De-hua Han, Hui Li, and Danping Cao. "Joint inversion of seismic, vertical seismic profiling, and crosswell data — A case study from China." Interpretation 5, no. 1 (February 1, 2017): T107—T119. http://dx.doi.org/10.1190/int-2015-0187.1.
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Three-dimensional poststack and prestack seismic inversion results such as P- and S-impedance are commonly used for reservoir characterization. However, the frequency bandwidth of surface-based reflection seismic surveys usually ranges from 10 to 70 Hz, and these surveys have limited vertical resolution. The frequency bandwidth of vertical seismic profiling (VSP) and crosswell data is much wider than that of surface reflection seismic data, and it can give a detailed illumination of the subsurface around the borehole. We test a joint inversion method that integrated surface reflection seismic, VSP, and crosswell data. To better constrain the inversion results, we further integrate a posteriori information on the reflectivity obtained from petrophysics data into the inversion procedure. The a posteriori distribution we use is a modified-Cauchy distribution obtained from the statistical analysis of petrophysics data. To demonstrate the effectiveness of our algorithm, we applied our inversion strategy to a 2D synthetic model and a real seismic data set, and an uncertainty assessment was also performed. The joint inversion method can detect the thin layers that surface seismic inversion fail to, demonstrating the higher resolution of the method.
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Miao, X., W. M. Moon, B. Milkereit, and C. J. Mwenifumbo. "Three component vertical seismic profiling (VSP) experiment in the Sudbury Basin." Geophysical Research Letters 21, no. 10 (May 15, 1994): 939–42. http://dx.doi.org/10.1029/93gl02246.
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Shapiro, Serguei A., and Holger Zien. "The O’Doherty‐Anstey formula and localization of seismic waves." GEOPHYSICS 58, no. 5 (May 1993): 736–40. http://dx.doi.org/10.1190/1.1443458.
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Angle (or offset) dependent effects of scattering in finely layered media can be observed and analyzed or must be compensated for in vertical seismic profiling data (VSP‐ data), crosshole observations, or seismic amplitude variation with offset (AVO) measurements. Moreover, the adequate description of multiple scattering is important for the study of seismic attenuation in sediments and for the design of inversion procedures.
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Bayer, Jacob, Bryce Jensen, Yingping Li, Tianrun Chen, and Ken Matson. "Salt/sediment proximity to delineate salt boundaries using seismic while drilling in the Gulf of Mexico." Leading Edge 38, no. 11 (November 2019): 833–42. http://dx.doi.org/10.1190/tle38110833.1.
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Between July 2018 and January 2019, Shell acquired two vertical seismic profiling (VSP) surveys in two deepwater wells in the Gulf of Mexico by using a seismic while drilling (SWD) tool. Each survey included a rig source zero-offset VSP and a boat source offset VSP. The main objective of the surveys is to delineate the salt-sediment boundary at the salt base and flank. We design and execute the complex VSP surveys with emphasis on optimization, efficiency, and integration. We develop a comprehensive analysis and processing method to integrate P-wave sediment and salt proximities with converted PS salt proximity. We use SWD-VSP surveys to demonstrate how we define the salt boundary with the integrated results. Our results show that we can delineate the salt boundary with better accuracy and with a high degree of confidence. These successful VSP surveys provide significant business and technical value.
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LeBlanc, Anne-Marie, Richard Fortier, Michel Allard, Calin Cosma, and Sylvie Buteau. "Seismic cone penetration test and seismic tomography in permafrost." Canadian Geotechnical Journal 41, no. 5 (September 1, 2004): 796–813. http://dx.doi.org/10.1139/t04-026.
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Two high-resolution multi-offset vertical seismic profile (VSP) surveys were carried out in a permafrost mound near Umiujaq in northern Quebec, Canada, while performing seismic cone penetration tests (SCPT) to study the cryostratigraphy and assess the body waves velocities and the dynamic properties of warm permafrost. Penetrometer-mounted triaxial accelerometers were used as the VSP receivers, and a swept impact seismic technique (SIST) source generating both compressional and shear waves was moved near the surface following a cross configuration of 40 seismic shot-point locations surrounding each of the two SCPTs. The inversion of travel times based on a simultaneous iterative reconstruction technique (SIRT) provided tomographic images of the distribution of seismic velocities in permafrost. The Young's and shear moduli at low strains were then calculated from the seismic velocities and the permafrost density measured on core samples. The combination of multi-offset VSP survey, SCPT, SIST, and SIRT for tomographic imaging led to new insights in the dynamic properties of permafrost at temperatures close to 0 °C. The P- and S-wave velocities in permafrost vary from 2400 to 3200 m/s and from 900 to 1750 m/s, respectively, for a temperature range between 0.2 and 2.0 °C. The Young's modulus varies from 2.15 to 13.65 GPa, and the shear modulus varies from 1.00 to 4.75 GPa over the same range of temperature.Key words: permafrost, seismic cone penetration test, vertical seismic profiling, seismic tomography, dynamic properties.
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Rich, Jamie P., and Alan J. Witten. "A theoretical and experimental comparison of three-dimensional seismic reflection and offset vertical seismic profiling (VSP)." GEOPHYSICS 70, no. 4 (July 2005): R25—R32. http://dx.doi.org/10.1190/1.1988185.
Full textAbstract:
Diffraction tomography imaging has been applied to data acquired with two different measurement geometries at a buried waste disposal site. The experimental scale is quite small, having a horizontal extent on the order of 10 m and considering features at depths (most importantly, a layer of buried waste) of less than 10 m. Both a 3D reflection and a pseudo-3D offset vertical seismic profiling (VSP) geometry were used. The use of these two different geometries allows for a comparison of the results and limitations of each method. Images derived from both techniques must be interpreted with a knowledge of the theoretical resolution and limitations imposed by each measurement geometry and imaging algorithm. The reflection algorithm leads to images that contain hollow objects, a consequence of the reflection geometry and linearized theory; this algorithm is unable to image the sides of objects because of a lack of information at oblique reflection angles. Offset VSP experiences a blurring of objects along a line between the source and receiver because information is integrated over transmission raypaths. The two techniques provide images which are consistent with each other and the expectations based on theoretical considerations.
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Owusu, John C., and Terry W. Spencer. "VSP normal moveout stretch." GEOPHYSICS 60, no. 5 (September 1995): 1579–82. http://dx.doi.org/10.1190/1.1443891.
Full textAbstract:
The vertical seismic profiling, common depth‐point (VSPCDP) transformation is a technique used to image the reflected waves in an offset VSP. This coordinate transformation procedure maps reflection amplitudes from receiver depth and reflection times to lateral offset and reflector depth (Wyatt and Wyatt, 1981). The process involves the application of moveout correction followed by stacking. This moveout correction results in a distortion of the original waveform and a smear of the reflection event that consequently degrades the lateral resolution of the transformation (Owusu, 1991). Therefore, to determine the optimum processing parameters for the transformation we need to understand the effects of the VSP moveout stretch.
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Rector III, J. W., B. P. Marion, and R. A. Hardage. "The use of an active drill bit for inverse VSP measurements." Exploration Geophysics 20, no. 2 (1989): 343. http://dx.doi.org/10.1071/eg989343.
Full textAbstract:
Vertical Seismic Profiling (VSP) is often used to provide high resolution seismic images near a wellbore. A new borehole seismic technique, the TOMEX� survey (Rector, et al., 1988), uses the vibrations produced by a drill bit as a downhole seismic energy source to produce inverse VSP data. No downhole instrumentation is required to acquire the data, and the data recording does not interfere with or delay the drilling process. Hence, there is no loss of rig time in performing the survey. These characteristics offer a method to acquire SWD (seismic-while-drilling) borehole seismic surveys. In addition, 3-D imaging around a well can be obtained at significant savings compared to conventional offset VSP imaging. The continuous signals generated by the bit during drilling are monitored with a reference sensor attached to the top of the drillstring, and the reference sensor signals are crosscorrelated with signals from surface-positioned geophones to produce inverse VSP data. Deconvolution and time shifts are then performed to remove the effects of recording the source reference trace at a location that is a considerable distance from the source. Results from tests demonstrate that these processed drill-bit source data are virtually identical to conventional forward VSP data. In using the drill bit as a downhole seismic source for inverse VSP, many of the limitations of conventional VSP are overcome. Several applications for VSP that were previously considered to be prohibitively expensive are now feasible. Furthermore, this seismic-while-drilling technique offers the potential for the explorationist to make real-time drilling decisions at the well site.
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Shi, Ying, and Yanghua Wang. "Reverse time migration of 3D vertical seismic profile data." GEOPHYSICS 81, no. 1 (January 1, 2016): S31—S38. http://dx.doi.org/10.1190/geo2015-0277.1.
Full textAbstract:
Reverse time migration (RTM) has shown increasing advantages in handling seismic images of complex subsurface media, but it has not been used widely in 3D seismic data due to the large storage and computation requirements. Our prime objective was to develop an RTM strategy that was applicable to 3D vertical seismic profiling (VSP) data. The strategy consists of two aspects: storage saving and calculation acceleration. First, we determined the use of the random boundary condition (RBC) to save the storage in wavefield simulation. An absorbing boundary such as the perfect matching layer boundary is often used in RTM, but it has a high memory demand for storing the source wavefield. RBC is a nonabsorbing boundary and only stores the source wavefield at the two maximum time steps, then repropagates the source wavefield backwards at every time step, and hence, it significantly reduces the memory requirement. Second, we examined the use of the graphic processing unit (GPU) parallelization technique to accelerate the computation. RBC needs to simulate the source wavefield twice and doubles the computation. Thus, it is very necessary to realize the RTM algorithm by GPU, especially for a 3D VSP data set. GPU and central processing unit (CPU) collaborated parallel implementation can greatly reduce the computation time, where the CPU performs serial code, and the GPU performs parallel code. Because RBC does not need the same huge amount of storage as an absorbing boundary, RTM becomes practically applicable for 3D VSP imaging.
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Ireson, R. L. "THE USE OF VSP TECHNIQUES IN FIELD EVALUATION." APPEA Journal 26, no. 1 (1986): 226. http://dx.doi.org/10.1071/aj85022.
Full textAbstract:
Vertical Seismic Profiling (VSP) techniques have been developed which have found application in the development and production of hydrocarbons as well as in exploration.A VSP is initiated by outlining the objectives of the survey and, using a model of the geology in the vicinity of the borehole, applying inversion techniques to determine the VSP method best suited to provide the required data. Reflection coverage, critical refractions, and mode conversion data (using 3-component geophones) can be used to obtain a structural, lithologic, and petrophysical interpretation.Structural interpretations using recently developed migration techniques based on the scalar wave equation can now provide images of the sub-surface which are superior to those obtained using previous ray-trace schemes.Acoustic impedance estimates from VSP surveys processed with deterministic deconvolution techniques and optimal amplitude recovery to obtain maximum temporal resolution can be more accurate than those obtained from surface seismic data. Offset VSP data can also give an estimate of reservoir porosity variations away from the borehole.
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Miao, Xiao‐Gui, Wooil M. Moon, and B. Milkereit. "A multioffset, three‐component VSP study in the Sudbury Basin." GEOPHYSICS 60, no. 2 (March 1995): 341–53. http://dx.doi.org/10.1190/1.1443770.
Full textAbstract:
A multioffset, three‐component vertical seismic profiling (VSP) experiment was carried out in the Sudbury Basin, Ontario, as a part of the LITHOPROBE Sudbury Transect. The main objectives were determination of the shallow velocity structure in the middle of the Sudbury Basin, development of an effective VSP data processing flow, correlation of the VSP survey results with the surface seismic reflection data, and demonstration of the usefulness of the VSP method in a crystalline rock environment. The VSP data processing steps included rotation of the horizontal component data, traveltime inversion for velocity analysis, Radon transform for wavefield separation, and preliminary analysis of shear‐wave data. After wavefield separation, the flattened upgoing wavefields for both P‐waves and S‐waves display consistent reflection events from three depth levels. The VSP-CDP transformed section and corridor stacked section correlate well with the high‐resolution surface reflection data. In addition to obtaining realistic velocity models for both P‐ and S‐waves through least‐square inversion and synthetic seismic modeling for the Chelmsford area, the VSP experiment provided an independent estimation for the reflector dip using three component hodogram analysis, which indicates that the dip of the contact between the Chelmsford and Onwatin formations, at an approximate depth of 380 m in the Chelmsford borehole, is approximately 10.5° southeast. This study demonstrates that multioffset, three‐component VSP experiments can provide important constraints and auxiliary information for shallow crustal seismic studies in crystalline terrain. Thus, the VSP technique bridges the gap between the surface seismic‐reflection technique and well‐log surveys.
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Chang, Chih‐Hsiung, Gerald H. F. Gardner, and John A. McDonald. "Experimental observation of surface wave propagation for a transversely isotropic medium." GEOPHYSICS 60, no. 1 (January 1995): 185–90. http://dx.doi.org/10.1190/1.1443745.
Full textAbstract:
Velocity anisotropy of surface‐wave propagation in a transversely isotropic solid has been observed in a laboratory study. In this study, Phenolite™, an electrical insulation material, was used as the transversely isotropic media (TIM), and a vertical seismic profiling (VSP) geometry was used to record seismic arrivals and to separate surface waves from shear waves. Results show that surface waves that propagate with different velocities exist at certain directions.
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Hinds, Ronald C., Richard Kuzmiski, Neil L. Anderson, and Barry R. Richards. "An integrated surface and borehole seismic case study: Fort St. John Graben area, Alberta, Canada." GEOPHYSICS 58, no. 11 (November 1993): 1662–75. http://dx.doi.org/10.1190/1.1443382.
Full textAbstract:
The deltaic sandstones of the basal Kiskatinaw Formation (Stoddard Group, upper Mississippian) were preferentially deposited within structural lows in a regime characterized by faulting and structural subsidence. In the Fort St. John Graben area, northwest Alberta, Canada, these sandstone facies can form reservoirs where they are laterally sealed against the flanks of upthrown fault blocks. Exploration for basal Kiskatinaw reservoirs generally entails the acquisition and interpretation of surface seismic data prior to drilling. These data are used to map the grabens in which these sandstones were deposited, and the horst blocks which act as lateral seals. Subsequent to drilling, vertical seismic profile (VSP) surveys can be run. These data supplement the surface seismic and well log control in that: 1) VSP data can be directly correlated to surface seismic data. As a result, the surface seismic control can be accurately tied to the subsurface geology; 2) Multiples, identified on VSP data, can be deconvolved out of the surface seismic data; and 3) The subsurface, in the vicinity of the borehole, is more clearly resolved on the VSP data than on surface seismic control. On the Fort St. John Graben data set incorporated into this paper, faults which are not well resolved on the surface seismic data, are better delineated on VSP data. The interpretive processing of these data illustrate the use of the seismic profiling technique in the search for hydrocarbons in structurally complex areas.
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Mittet, Rune, and Ketil Hokstad. "Transforming walk‐away VSP data into reverse VSP data." GEOPHYSICS 60, no. 4 (July 1995): 968–77. http://dx.doi.org/10.1190/1.1443862.
Full textAbstract:
Marine walk‐away vertical seismic profiling (VSP) data can be transformed into reverse VSP data using an elastic reciprocity transformation. A reciprocity transform is derived and tested using data generated with a 2-D high‐order, finite‐difference modeling scheme in a complex elastic model. First, 201 shots are generated with a walk‐away VSP experimental configuration. Both the x‐component and the z‐component of the displacement are measured. These data are collected in two common receiver data sets. Then two shots are generated in a reverse VSP configuration. We demonstrate that subtraction of the reverse VSP data from the walk‐away VSP data gives very small residuals. The transformation of walk‐away data into reverse VSP data makes prestack shot‐domain migration feasible for walk‐away data. Synthetic data from a multishot walk‐away experiment can be obtained from one or a few modeling operations with a RVSP experimental configuration. The required computer time is reduced by two orders of magnitude.
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Greenwood, Andrew, Christian J. Dupuis, Milovan Urosevic, and Anton Kepic. "Hydrophone VSP surveys in hard rock." GEOPHYSICS 77, no. 5 (September 1, 2012): WC223—WC234. http://dx.doi.org/10.1190/geo2011-0490.1.
Full textAbstract:
Seismic imaging in hard rock environments is gaining wider acceptance as an exploration technique and as a mine-planning tool. To date, 13 successful case studies have been acquired in Australia. The images generated from hard rock targets exhibit large levels of complexity and their interpretations remain an active area of study. To assist the imaging and better understand the source of the reflections observed, vertical seismic profiling (VSP) can be employed. This technique is not readily applied to hard rock environments because cost and operational issues often prove prohibitive. We propose the use of hydrophone arrays as a cost effective solution to VSP acquisition. We highlight the key challenges in using these receivers and propose solutions to overcome them. By careful acquisition methodologies and refined signal processing techniques, the tube waves that have up to now compromised the use of hydrophones for VSP acquisition can be effectively mitigated. We show that the data acquired with hydrophones compare favorably to that acquired with conventional 3C geophones. The data acquired with hydrophones come at a fraction of the cost and deployment time required for conventional acquisition procedures. Our results show that hydrophone vertical seismic acquisition is a viable, cost effective, and efficient solution that should be employed more routinely in hard rock environments to enhance the value of the surface data sets being acquired.
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Ahadi, A., and M. A. Riahi. "Application of Gabor deconvolution to zero-offset VSP data." GEOPHYSICS 78, no. 2 (March 1, 2013): D85—D91. http://dx.doi.org/10.1190/geo2011-0319.1.
Full textAbstract:
The aim of designing deconvolution operators is to extract the reflectivity series from seismic sections. Due to the noise, source signature inconsistency, reflection/transmission, anelastic attenuation, and multiples, the amplitude of a propagating seismic wave varies as a function of time. Because of these factors the frequency spectra of seismic signals narrow with time. Recognition of reflectors using upgoing waves is one of the notable properties of vertical seismic profiling (VSP) data. Designing a deconvolution operator for VSP data based on downgoing waves is considered to be one of the most ideal deconvolution methods intended to produce high-resolution images in routine processing of zero-offset VSP data. For such an analysis, the Gabor deconvolution operator has been designed using the downgoing wavefield and then was applied to the upgoing wavefield, and hyperbolic smoothing was used to estimate the wavelet. The final result of applying the deconvolution operator is a VSP section with superior resolution. To compare this method with customary methods of deconvolution, the Wiener deconvolution was applied to the synthetic and real data, and the results were compared with those of the Gabor deconvolution.
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Landrø, Martin. "Repeatability issues of 3-D VSP data." GEOPHYSICS 64, no. 6 (November 1999): 1673–79. http://dx.doi.org/10.1190/1.1444671.
Full textAbstract:
Increased repeatability is recognized as one major issue for improving the time‐lapse seismic technology as a reservoir management tool. A 3-D vertical seismic profiling (VSP) data set, acquired over a period of two days, is used to analyze how repeatable a permanent installed geophone array can be and how repeatability changes with inaccuracies in source positioning. It is found that for a frequency range between 3.5 and 50 Hz, the difference root‐mean‐square (rms) level between two recorded traces belonging to two different shots is about 8%. This fact shows that there is a potential for acquiring very accurate time‐lapse seismic data by using a permanently installed downhole geophone array. Repeatability variation with increasing shot separation distances is analyzed, showing a rapid decrease in repeatability as the accuracy of the positioning of the repeat survey decreases. Horizontal geophone components show approximately the same degree of repeatability compared to the vertical component, but horizontal geophone data is slightly more sensitive to positioning errors. The results show that repeated 3-D VSP surveys (preferably using permanently installed geophone arrays) might be an efficient tool for detailed and precise monitoring of fluid and pressure changes within a hydrocarbon reservoir.
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Lee, M. W. "Particle displacements on the wall of a borehole from incident plane waves." GEOPHYSICS 52, no. 9 (September 1987): 1290–96. http://dx.doi.org/10.1190/1.1442389.
Full textAbstract:
Particle displacements from incident plane waves at the wall of a fluid‐filled borehole are formulated by applying the seismic reciprocity theorem to far‐field displacement fields. Such displacement fields are due to point forces acting on a fluid‐filled borehole under the assumption of long wavelengths. The displacement fields are analyzed to examine the effect of the borehole on seismic wave propagation, particularly for vertical seismic profiling (VSP) measurements. When the shortest wavelength of interest is approximately 25 times longer than the borehole’s diameter, the scattered displacements are proportional to the first power of incident frequency and borehole diameter. The maximum scattered energy occurs when an incident P‐wave propagates perpendicular to the borehole. Borehole effects on VSP measurements, such as waveform distortion, amplitude variation, and time delay, have been analyzed using the concept of a transfer function. When the shortest wavelength of interest is about 40 times longer than the borehole’s diameter, borehole effects on VSP measurements using a wall‐locking geophone are negligible.
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Bakulin, Andrey, Marta Woodward, Dave Nichols, Konstantin Osypov, and Olga Zdraveva. "Localized anisotropic tomography with well information in VTI media." GEOPHYSICS 75, no. 5 (September 2010): D37—D45. http://dx.doi.org/10.1190/1.3481702.
Full textAbstract:
We develop a concept of localized seismic grid tomography constrained by well information and apply it to building vertically transversely isotropic (VTI) velocity models in depth. The goal is to use a highly automated migration velocity analysis to build anisotropic models that combine optimal image focusing with accurate depth positioning in one step. We localize tomography to a limited volume around the well and jointly invert the surface seismic and well data. Well information is propagated into the local volume by using the method of preconditioning, whereby model updates are shaped to follow geologic layers with spatial smoothing constraints. We analyze our concept with a synthetic data example of anisotropic tomography applied to a 1D VTI model. We demonstrate four cases of introducing additionalinformation. In the first case, vertical velocity is assumed to be known, and the tomography inverts only for Thomsen’s [Formula: see text] and [Formula: see text] profiles using surface seismic data alone. In the second case, tomography simultaneously inverts for all three VTI parameters, including vertical velocity, using a joint data set that consists of surface seismic data and vertical check-shot traveltimes. In the third and fourth cases, sparse depth markers and walkaway vertical seismic profiling (VSP) are used, respectively, to supplement the seismic data. For all four examples, tomography reliably recovers the anisotropic velocity field up to a vertical resolution comparable to that of the well data. Even though walkaway VSP has the additional dimension of angle or offset, it offers no further increase in this resolution limit. Anisotropic tomography with well constraints has multiple advantages over other approaches and deserves a place in the portfolio of model-building tools.
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Pujol, J., B. N. Fuller, and S. B. Smithson. "Interpretation of a vertical seismic profile conducted in the Columbia Plateau basalts." GEOPHYSICS 54, no. 10 (October 1989): 1258–66. http://dx.doi.org/10.1190/1.1442585.
Full textAbstract:
Seismic reflection data are often of poor quality when recorded in areas where volcanic rocks are present at or near the surface. In order to investigate this phenomenon, a vertical seismic profiling (VSP) experiment was conducted in the Columbia Plateau basalts so that the behavior of seismic energy in subsurface volcanic rocks could be observed directly, thus giving insight into data acquisition in volcanic terrains. The lithologic section at the VSP site consists of low‐velocity (400 m/s to 900 m/s) alluvium in the uppermost 50 m, beneath which are layers of high‐velocity (about 5800 m/s), high‐density basalts interbedded with clay layers with much lower velocities (about 1700 m/s) and densities. These large velocity and density contrasts dramatically influence wave generation and propagation. In spite of the small source‐borehole offset (61 m), large‐amplitude S waves are generated by the downgoing P waves when they reach a shallow (250 m) clay‐basalt boundary. These S waves, in turn, generate strong reflected P waves when they interact with another clay layer at 500 m. On the other hand, strong primary P‐wave reflections are also present in the data but are affected by various interfering effects which reduce their amplitudes. The VSP data are also characterized by large‐amplitude reverberations caused by seismic energy trapped in the upper 250 m of the lithologic section. Reverberations are also observed in surface data recorded near the VSP site. We conclude from our analysis that volcanic rocks, at least in the Columbia Plateau, do not exhibit unusual energy transmission characteristics and that the observations can be explained in terms of the large contrast in the elastic properties of interbedded clay and basalt.
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Poletto, Flavio. "A blind interpretation of drill‐bit signals." GEOPHYSICS 65, no. 3 (May 2000): 970–78. http://dx.doi.org/10.1190/1.1444793.
Full textAbstract:
The role of kurtosis in evaluating the quality of vertical seismic profiling (VSP) drill‐bit data is investigated. The calculations show how kurtosis depends on the dominant frequency, bandwidth, and phase content of a seismic signal. This analysis is applied to synthetic and real common‐offset and common‐shot drill‐bit seismograms to evaluate the prominence and quality of the first arrival and other coherent events. High values of kurtosis correspond to an isolated first arrival or to a compressed coherent noise event, while low values are typical of low S/N (distributed) ratio traces. Kurtosis analysis applied to drill‐bit VSP data while drilling proved to be successful at identifying high‐quality traces with little interpretational input.
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Byun, Joongmoo, James W. Rector III, and Tamas Nemeth. "Postmap migration of crosswell reflection seismic data." GEOPHYSICS 67, no. 1 (January 2002): 135–46. http://dx.doi.org/10.1190/1.1451423.
Full textAbstract:
Vertical seismic profiling/common depth point (VSP‐CDP) mapping is often preferred to crosswell migration when imaging crosswell seismic reflection data. The principal advantage of VSP‐CDP mapping is that it can be configured as a one‐to‐one operation between data in the acquisition domain and data in the image domain and therefore does not smear coherent noise such as tube waves, guided waves, and converted waves as crosswell migration could. However, unlike crosswell migration, VSP‐CDP mapping cannot collapse diffractions; therefore, the lateral resolution of reflection events suffers. We present a migration algorithm that is applied to the crosswell data after they have been mapped. By performing crosswell migration in two distinct steps—mapping followed by diffraction stacking—noise events can be identified and filtered in the mapped domain without smearing effects commonly associated with conventional crosswell migration operators. Tests on noise‐free synthetic crosswell data indicate that the two‐step migration yields results nearly identical with conventional crosswell migration. Our specific implementation of the two‐step migration algorithm maps the data using an estimate of the interwell velocity field and then performs diffraction stacking using a constant‐velocity assumption. The migrated results are confined to the mapped region to reduce edge effects commonly associated with conventional crosswell migration. Results from synthetic data indicate that the constant‐velocity assumption used for diffraction stacking is remarkably robust, even for models with large vertical velocity variation. It is, however, important that the data are mapped with the correct interwell velocity model. After applying postmap migration to two field data sets mapped by VSP‐CDP mapping, better fault resolution was achieved and the lateral resolution was improved significantly.
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Gao, Fuchun, Alan R. Levander, R. Gerhard Pratt, Colin A. Zelt, and Gian Luigi Fradelizio. "Waveform tomography at a groundwater contamination site: VSP-surface data set." GEOPHYSICS 71, no. 1 (January 2006): H1—H11. http://dx.doi.org/10.1190/1.2159049.
Full textAbstract:
Application of 2D frequency-domain waveform tomography to a data set from a high-resolution vertical seismic profiling (VSP) experiment at a groundwater contamination site in Hill Air Force Base (HAFB), Utah, reveals a surprisingly complicated shallow substructure with a resolution of approximately 1.5 m. Variance in the waveform misfit function is reduced 69.4% by using an initial velocity model from first-arrival traveltime tomography. The waveform tomography model suggests (1) a low-velocity layer at 1 to 4 m depth, (2) a high-vertical-velocity gradient of 80 m/s/m on average, and (3) severe lateral variations — velocity contrasts as large as about 200 m/s occur in a distance as short as 1.5 m. The model is well correlated with lithologic logs and is interpreted geologically. A Q-value of 20 is estimated for the target area. The extreme lateral and vertical variations of the subsurface compromise many standard seismic processing methods.
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Gusmeroli, Alessio, Tavi Murray, Roger A. Clark, Bernd Kulessa, and Peter Jansson. "Vertical seismic profiling of glaciers: appraising multi-phase mixing models." Annals of Glaciology 54, no. 64 (2013): 115–23. http://dx.doi.org/10.3189/2013aog64a106.
Full textAbstract:
Abstract We have investigated the speed of compressional waves in a polythermal glacier by, first, predicting them from a simple three-phase (ice, air, water) model derived from a published ground-penetrating radar study, and then comparing them with field data from four orthogonally orientated walkaway vertical seismic profiles (VSPs) acquired in an 80 m deep borehole drilled in the ablation area of Storglaciären, northern Sweden. The model predicts that the P-wave speed increases gradually with depth from 3700ms–1 at the surface to 3760ms–1 at 80m depth, and this change is almost wholly caused by a reduction in air content from 3% at the surface to <0.5% at depth. Changes in P-wave speed due to water content variations are small (<10 ms–1); the model’s seismic cold–temperate transition surface (CTS) is characterized by a 0.3% decrease downwards in P-wave speed (about ten times smaller than the radar CTS). This lack of sensitivity, and the small contrast at the CTS, makes seismically derived water content estimation very challenging. Nevertheless, for down-going direct-wave first arrivals for zero- and near-offset VSP shots, we find that the model-predicted travel times and field observations agree to within 0.2 ms, i.e. less than the observational uncertainties.
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Rusmanugroho, Herurisa, and George A. McMechan. "3D, 9C seismic modeling and inversion of Weyburn Field data." GEOPHYSICS 77, no. 4 (July 1, 2012): R161—R173. http://dx.doi.org/10.1190/geo2011-0406.1.
Full textAbstract:
Inversion of 3D, 9C wide azimuth vertical seismic profiling (VSP) data from the Weyburn Field for 21 independent elastic tensor elements was performed based on the Christoffel equation, using slowness and polarization vectors measured from field data. To check the ability of the resulting elastic tensor to account for the observed data, simulation of the 3C particle velocity seismograms was done using eighth-order, staggered-grid, finite-differencing with the elastic tensor as input. The inversion and forward modeling results were consistent with the anisotropic symmetry of the Weyburn Field being orthorhombic. It was dominated by a very strong, tranverse isotropy with a vertical symmetry axis, superimposed with minor near-vertical fractures with azimuth [Formula: see text] from the inline direction. The predicted synthetic seismograms were very similar to the field VSP data. The examples defined and provided a validation of a complete workflow to recover an elastic tensor from 9C data. The number and values of the nonzero tensor elements identified the anisotropic symmetry present in the neighborhood of a 3C borehole geophone. Computation of parameter correlation matrices allowed evaluation of solution quality through relative parameter independence.
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Noghretab, Babak Sayad, and Mohammad Kamal Ghassem-Alaskari. "Simulation of VSP data based on DSI data and estimation of shear wave velocity and elastic Moduli for a well case study." International Journal of Petrochemical Science & Engineering 4, no. 4 (August 7, 2019): 138–45. http://dx.doi.org/10.15406/ipcse.2019.04.00113.
Full textAbstract:
The purpose of this article was to generate and compare seismic modeling results with real vertical seismic profiling data (VSP data) based on Dipole Shear Imager (DSI) data in the reservoir zone (Kangan and upper Dalan Formations) of a well in South Pars gas field. Estimation of shear wave velocity (Vs) and density for layers above the reservoir zone, for which; DSI data did not exist, was also done by the applied modeling method to estimate elastic parameters of the layers. In this method, modeling for X-component of the VSP survey was run by utilizing the DSI data set of reservoir zone and the VSP survey report of the studied well with high precision. Computed results for the proposed modeling method led to achieving highly accurate, close to the reality of VSP model around the studied well. According to compression wave velocity (VP) attained from VSP survey reports of the well and Vp/Vs ratio obtained from Dipole Shear Imager (DSI), modeling was done. Afterward, shear wave velocity (Vs) for upper layers of reservoir zone estimated with high precision, then density and elastic moduli for the above layers and the reservoir zone were calculated.