Offset Vertical Seismic Profiling Research Articles

High-Precision Iterative VSP Wavefield Separation

Conventional vertical seismic profiling (VSP) wavefield separation method (CSM) focuses on the wavefield separation result, not the residual. Usually, it cannot obtain desirable high-precision results. Iterative zero-offset VSP (ZVSP). However, IZSM only can be used for ZVSP data, which limits its application. The scalar wavefield separation algorithm used in IZSM is based on the SVD filtering, which limits its precision. The objective function threshold of IZSM is varied with the input ZVSP data, which limits its result precision and efficiency. To improve the wavefield separation precision and efficiency, we propose a high-precision iterative VSP wavefield separation method (HISM). HISM is suitable for both ZVSP and offset VSP (OVSP) data, and also applicable for any possible scalar wavefield separation algorithm The objective function threshold of HISM can be a fixed number. Therefore, HISM can obtain high precision and efficiency results. Actual ZVSP and OVSP data application demonstrates the performance of HISM.

Monitoring subsurface changes by tracking direct-wave amplitudes and traveltimes in continuous distributed acoustic sensor VSP data

Instrumenting wells with distributed acoustic sensors (DASs) and illuminating them with passive or active seismic sources allows precise tracking of temporal variations of direct-wave traveltimes and amplitudes, which can be used to monitor variations in formation stiffness and density. This approach has been tested by tracking direct-wave amplitudes and traveltimes as part of a carbon capture and storage project where a 15 kt supercritical CO2 injection has been monitored with continuous offset vertical seismic profiling using nine permanently mounted surface orbital vibrators acting as seismic sources and several wells instrumented with DAS cables cemented behind the casing. The results indicate a significant (from 15% to 30%) increase of strain amplitudes within the CO2 injection interval, and traveltime shifts of 0.3–0.4 ms below this interval, consistent with full-wave 1.5D numerical simulations and theoretical predictions. The results give independent estimates of the CO2 plume thickness and the associated P-wave velocity reduction.

Processing of multi‐well offset vertical seismic profile data acquired with distributed acoustic sensors and surface orbital vibrators: Stage 3 of the CO2CRC Otway Project case study

ABSTRACTTime‐lapse seismic reservoir monitoring is used as a way to gain insight into subsurface processes. Yet, the application of standard 4D technology onshore faces challenges, such as high cost, significant environmental footprint and, consequently, relatively infrequent surveys. As part of the Otway Project Stage 3 CO2 injection study, continuous automated borehole‐based monitoring using distributed acoustic sensing has been paired with permanently deployed surface sources, referred to as surface orbital vibrators, as a way to monitor the spreading CO2 plume. The injection of 15,000 tonnes of CO2 in a saline reservoir at a depth of 1550 m is monitored using five boreholes instrumented with enhanced sensitivity fibre optic cables and nine surface orbital vibrators, creating an array of 45 well–source pairs. The data are processed with an offset vertical seismic profiling processing workflow developed to address key challenges of the continuous distributed acoustic sensing acquisition using surface orbital vibrators. The processing flow includes deconvolution with a source sweep recorded by a pilot geophone installed below the surface orbital vibrators. A second deconvolution with a wavelet estimated from direct arrivals compensates for the difference between distributed acoustic sensing measurements and the pilot geophone as well as near‐surface variations. Image quality is noted to be best for short offsets and decreases with increasing offsets and well deviations. As surface orbital vibrators generate unique sweeps in two rotation directions, further processing is applied to stack these rotation signals together, which further improves the images. The resulting 2D transects of each well–source pair visually provide good illumination of the subsurface, suggesting continuous monitoring of the spreading CO2 plume should be possible with some further tuning of the processing workflow for time‐lapse repeatability.

Integration of VSP in the process of surface seismic data inversion

The measurements of vertical seismic profiles (VSP) used in the petroleum industry are often limited to direct arrivals to establish time-depth laws. Many other measurements such as PP and PS corridor stacks, offset vertical seismic profiles (OVSP) and walkaway can help to predict P and S wave impedances estimated by inversion of surface seismic data. This article shows the use of all available VSP records to constrain the inversion of surface seismic data and predict matrix properties of Carboniferous and Devonian intervals in the Machukhske gas field in the Ukrainian Dnieper-Donetsk basin. The use of PS corridor stack, in addition to PP corridor stack, allows a better optimization of the S impedance at the well. Moreover, corridor stacks allow a better estimate of the P and S impedance below the well TD than surface seismic data alone, and therefore an enhanced characterization of the Devonian sands, which has been drilled by only a few wells. OVSPs help to build a more reliable a priori model by confirming or discarding the faults identified on the 3D seismic data. Results of reservoir characterization show a clear impact of the VSP integration on lithology prediction from surface seismic data.

Land VSP seismic sources evaluation: CO2CRC Otway project case study

It is widely accepted that, depending on acquisition technique, vertical seismic profiling (VSP) can provide us with extremely valuable information on seismic velocities (both P and S), attenuation and anisotropy of s eismic properties of the earth. Subsurface images, obtained with offset or 3D VSP could demonstrate superior resolution, signal-to-noise ratio and repeatability of surveys in comparison to standard surface seismic. These potential benefits are of great importance for both reservoir characterisation and time-lapse seismic monitoring. However in order to achieve them VSP surveys should be acquired with proper survey design and optimal source and receiver characteristics.

Multi-Azimuthal Walkway VSP for Full Azimuth Seismic Calibration

Comprehensive borehole seismic surveys hold the key to unlocking the knowledge contained within the long-offset full-azimuth surface seismic surveys that are fast becoming common in land exploration. This paper presents a case study of acquisition, processing and use of such survey for validation and calibration of processing parameters and inversion results of a recent point-source/point-receiver 3D surface seismic dataset acquired in the Cooper Basin. The 3D surface seismic data have been initially processed without significant borehole seismic data input. However, as the processing revealed gaps in knowledge, the need for borehole calibration was realised. This led to acquisition of a complex borehole seismic survey in a gas-discovery well comprising Multi-Azimuthal Walkaway (MAZ WVSP), Walkaround and Zero Offset Vertical Seismic Profiles (ZVSP). The acquired dataset shed light into the peg-leg multiple mechanisms as well as the VTI and azimuthal anisotropy. Advanced processing techniques such as calibrated piece-wise VTI inversion and azimuthal travel time fitting were applied to the MAZ WVSP data to validate the processing steps of the 3D surface seismic data and calibrate the results of its AVOaz inversion. Apart from showing some of the results of this study, this paper documents the various contact points between VSP and surface seismic datasets and how the results of processing complement each other. The final result comprised a calibrated seismic map of drilling targets.

Reliability of the slowness and slowness-polarization methods for anisotropy estimation in VTI media from 3C walkaway VSP data

We studied the validity of qP-wave slowness and slowness-polarization methods for estimating local anisotropy parameters in transversely isotropic (TI) media by quantifying the estimation errors in a numerical exercise. We generated numerical slownesses and polarizations over two aperture ranges corresponding to a short offset walkaway vertical seismic profiling (VSP) and a long offset walkaway VSP for a range of TI models with vertical axis of symmetry (VTI). Synthetic data are equisampled over the phase angle range and contaminated with Gaussian noise. We inverted the data and compared the anisotropy parameters of the optimal model with the true model. We found that the selection of a proper methodology for VTI parameter estimation based on walkaway VSP measurements was mostly dependent on our ability to accurately estimate either horizontal components of qP-wave slowness vector or the polarization vector. With data contaminated with noise, methods that include the horizontal component of the slowness vector had greater accuracy than the methods that replace this information with polarization measurements. The estimations are particularly accurate when a wide range of propagation angle was available. For short offsets, only parameter [Formula: see text] could be reliably estimated. In the absence of long offsets, depending on the accuracy of polarization measurements, the method based on the weak anisotropy approximation for qP-wave velocity in VTI media or the method based on slowness and polarization vectors could be used to estimate [Formula: see text] and [Formula: see text]. If the horizontal components of the slowness vector were not available (a heterogeneous overburden), we used methods that were based on local measurements of the polarization vector. We found that, with accurate measurements of the polarization vector, the method based on exact relationship between vertical slowness and polarization dip could be used to estimate VTI parameters even for the cases in which the wide offset range was not available.

Optimal designs of time-lapse seismic surveys for monitoring CO2 leakage through fault zones

Cost-effective time-lapse seismic surveys are crucial for long-term monitoring of geologic carbon sequestration. In this paper, we numerically model time-lapse seismic surveys for monitoring CO2 leakage through fault zones, and design optimal surveys for time-lapse seismic data acquisition using elastic-wave sensitivity analysis. Two stages of CO2 leakage through fault zones are simulated. In the early stage of leakage, when CO2 is confined in a relatively deep region, and our results show that the most desired location for receivers at the surface is at the hanging-wall side of the fault zone, of normal faults (with large dip angles) or reverse faults. The most sensitive places at the surface to the change of different elastic parameters (e.g. P- and S-wave velocity and density) are similar to one another, and are often not sensitive to the source location. In a late stage of leakage, in which CO2 migrates close to the surface, our modeling demonstrates that the best region at the surface for time-lapse seismic surveys is very sensitive to the source location and the elastic parameter to be monitored. For time-lapse vertical seismic profiling (VSP) surveys, our modeling suggests that it is important to account for the effect of free-surface reflections, especially for large offset VSP surveys.

Local vertical seismic profiling (VSP) elastic reverse-time migration and migration resolution: Salt-flank imaging with transmitted P-to-S waves

To avoid the defocusing effects of propagating waves through salt and overburden with an inaccurate overburden velocity model, we introduce a vertical seismic profiling (VSP) local elastic reverse-time-migration (RTM) method for salt-flank imaging by transmitted P-to-S waves. This method back-projects the transmitted PS waves using a local velocity model around the well until they are in phase with the back-projected PP waves at the salt boundaries. The merits of this method are that it does not require the complex overburden and salt-body velocities and it automatically accounts for source-side statics. In addition, the method accounts for kinematic and dynamic effects, including anisotropy, absorption, and all other unknown rock effects outside of this lo-cal subsalt velocity model. Numerical tests on an elastic salt model and offset 2D VSP data in the Gulf of Mexico, using a finite-difference time-domain staggered-grid RTM scheme, partly demonstrate the effectiveness of this method over interferometry PS-PP transmission migration and local acoustic RTM. Our method separates elastic wavefields to vector P- and S-wave velocity components at the trial image point and achieves better resolution than local acoustic RTM and interferometric transmission migration. The analytical formulas of migration resolution for local acoustic and elastic RTM show that the migration illumination is limited by data frequency and receiver aperture, and the spatial resolution is lower than standard poststack and prestack migration. This new method can image salt flanks as well as subsalt reflectors.

Imaging of offset VSP data acquired in complex areas with modified reverse‐time migration

ABSTRACTA modified reverse‐time migration algorithm for offset vertical seismic profiling data is proposed. This algorithm performs depth imaging of target areas in the borehole vicinity without taking into account the overburden. Originally recorded seismograms are used; reliable results can be obtained using only the velocity profile obtained along the well. The downgoing wavefield emitted from a surface source is approximated in the target area using the transmitted P‐wave, recorded by the receivers deployed in the well. This is achieved through a reverse‐time extrapolation of the direct transmitted P‐wave into the target area after its separation in offset vertical seismic profiling seismograms generated using a finite‐difference scheme for the solution of the scalar wave equation.The proposed approach produces ‘kinematically’ reliable images from reflected PP‐ and PS‐waves and, furthermore, can be applied as a salt proximity tool for salt body flank imaging based on the transmitted PS‐waves. Our experiments on synthetic data demonstrate that the modified reverse‐time migration provides reliable depth images based on offset vertical seismic profiling data even if only the velocity profile obtained along the borehole is used.

Inversion of seismic data: sensitivity and stability via SVD analysis

AbstractThe problem of recovery of seismic parameters of the media via wavefield produced by array of sources and recorded by array of receivers is considered in this work. In order to invert these data and recover elastic parameters one can use the optimization technique based on the gradient–like or Newton–like methods. In seismic applications this approach is known as “Full waveform inversion”. According to it we search for solution which minimizes mean–square deviation of the observed wavefield from the computed one for current values of elastic parameters. Surely convergence is governed by the properties of the Frechet derivative of nonlinear operator that maps medium parameters to the observed data. Thus studying these properties is an important step before development the numerical methods and algorithms of this inversion.For a simple case it can be shown that this derivative is a compact operator so implementation of any Newton–like approach is connected with necessity to resolve ill–posed problem of resolution of the first–order linear integral operational equation. In order to study the main peculiarities of this operator Singular Value Decomposition is applied. Two acquisition systems are dealt with – the offset vertical seismic profiling and cross–well tomography. Numerical results for realistic media are presented and the main differences of inverse problems for these two acquisition are shown. (© 2008 WILEY‐VCH Verlag GmbH & Co. KGaA, Weinheim)

Seismic attenuation in Faroe Islands basalts

ABSTRACTWe analysed vertical seismic profiling (VSP) data from two boreholes at Glyvursnes and Vestmanna on the island of Streymoy, Faroe Islands, to determine the magnitude and causes of seismic attenuation in sequences of basalt flows. The work is part of SeiFaBa, a major project integrating data from vertical and offset VSP, surface seismic surveys, core samples and wireline log data from the two boreholes. Values of effective seismic quality factor (Q) obtained at Glyvursnes and Vestmanna are sufficiently low to significantly degrade the quality of a surface reflection seismic image. This observation is consistent with results from other VSP experiments in the North Atlantic region. We demonstrate that the most likely cause of the low values of effective Q at Glyvursnes and Vestmanna is a combination of 1D scattering and intrinsic attenuation due to seismic wave‐induced fluid flow within pores and micro‐cracks. Tests involving 3D elastic wave numerical modelling with a hypothetical basalt model based on field observations, indicate that little scattering attenuation is caused by lateral variations in basalt structure.

Pure S-waves in land P-wave source VSP data

Conventional land vertical seismic profiling (VSP) exploration usually uses P-wave sources and three-component geophones for receivers, emphasizing P-and converted S-waves. Previous studies show that both dynamite borehole shots and vertical vibrations from controllable seismic sources at the surface will produce relatively strong pure P-waves and weaker pure S-waves. Interfaces with a large Poisson’s ratio difference have a positive influence on the formation of strong transmitted converted S-waves. By a comparative analysis of pure S-waves from sources and converted downgoing S-waves, we believe that the main frequency of pure S-waves is usually lower than pure P-waves while the main frequency of downgoing converted S-waves is close to that of P-waves. We have studied zero-offset and offset VSP data from land P-wave sources. Results show that pure S-waves commonly exist in these data with differences in wave intensity. S-wave velocity can be obtained from the P-wave source zero-offset VSP data. Finally, we discuss the bright future of joint application of VSP P-and S-waves and the full use of S-waves in P-wave source VSP data.

Imaging reflection-blind areas using transmitted PS-waves

We illustrate the use of mode-converted transmitted (e.g., PS- or SP-) waves in vertical seismic profiling (VSP) data for imaging areas above receivers where reflected waves cannot illuminate. Three depth-domain imaging techniques — move-out correction, common-depth-point (CDP) mapping, and prestack migration — are described and used for imag-ing the transmitted waves. Moveout correction converts an offset VSP trace into a zero-offset trace. CDP mapping maps each sample on an input trace to the location where the mode conversion occurs. For complex media, prestack migration (e.g., reverse-time migration) is used. By using both synthetic and field VSP data, we demonstrate that images derived from transmissions complement those from reflections. As an important application, we show that transmitted waves can illuminate zones above highly de-viated or horizontal wells, a region not imaged by reflection data. Because all of these benefits are obtained without extra data acquisition cost, we believe transmission imag-ing techniques will become widely adopted by the oil in-dustry.

A theoretical and experimental comparison of three-dimensional seismic reflection and offset vertical seismic profiling (VSP)

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.

When 4D seismic is not applicable: Alternative monitoring scenarios for the Arab‐D reservoir in the Ghawar Field

ABSTRACTGhawar, the largest oilfield in the world, produces oil from the Upper Jurassic Arab‐D carbonate reservoir. The high rigidity of the limestone–dolomite reservoir rock matrix and the small contrast between the elastic properties of the pore fluids, i.e. oil and water, are responsible for the weak 4D seismic effect due to oil production. A feasibility study was recently completed to quantify the 4D seismic response of reservoir saturation changes as brine replaced oil. The study consisted of analysing reservoir rock physics, petro‐acoustic data and seismic modelling. A seismic model of flow simulation using fluid substitution concluded that time‐lapse surface seismic or conventional 4D seismic is unlikely to detect the floodfront within the repeatability of surface seismic measurements. Thus, an alternative approach to 4D seismic for reservoir fluid monitoring is proposed. Permanent seismic sensors could be installed in a borehole and on the surface for passive monitoring of microseismic activity from reservoir pore‐pressure perturbations. Reservoir production and injection operations create these pressure or stress perturbations. Reservoir heterogeneities affecting the fluid flow could be mapped by recording the distribution of epicentre locations of these microseisms or small earthquakes. The permanent borehole sensors could also record repeated offset vertical seismic profiling surveys using a surface source at a fixed location to ensure repeatability. The repeated vertical seismic profiling could image the change in reservoir properties with production.

Clarion system calls for new approach to downhole seismic in reservoir management

Seismic technology traditionally has played a role in exploration, rather than production, of hydrocarbons. Weatherford, one of the big oil services companies, believes that its new optical seismic sensing system is changing the way the industry applies the technology. After four years of development and field testing, its permanent, in-well Clarion system is now being commercially deployed on a worldwide basis and integrated with other permanent optical sensing products and in-well flow controls for production optimization and reservoir management. Tad Bostick, vice president of business development for Weatherford's Intelligent Completions group, describes the background to the development. In the late 1970s and early 1980s, the industry began to recognize the potential of in-well seismic methods for improving exploration success, reducing drilling costs, controlling uncertainties and improving productivity. These years witnessed an explosive growth of interest in, and use of, vertical seismic profiling (VSP). The conventional seismic check shot survey was transformed to VSP when more well positions were occupied and the entire wavefield sampled by downhole geophones was processed. The acquired seismic signature of the earth was used for independently checking and correlating the surface seismic response. Placement of subsurface sensors, direct measurement of velocities and time versus depth, and the ability to link between the different scales of the various data, enabled comprehensive calibration of surface seismic with well information. Offsetting the source from the receiver (offset vertical seismic profiling, or OVSP) provided higher-resolution structural and stratigraphic images than did surface seismic profiling, despite a spatially limited investigation; but singlelevel tools were costly in terms of rig time, and rudimentary processing restricted widespread adoption of OVSP technology. The popularity of surveys using multi-source positions at surface with fewer well stations, together with the introduction of multilevel three-component (3C) tools, renewed interest in borehole seismic techniques in the late 1980s. In the following decade, the focus of research turned to further integration of surface seismic data, core data, and well logs. Borehole seismic profiling was the natural link; but the geophysical data extracted from this technique were not reliable enough, and acquisition costs were prohibitive. Unfortunately, the price of oil dropped at this time and oil companies restructured to meet increased pressure on nearterm financial targets, significantly curtailing further research. However, the perseverance of a few and some advances in acquisition and processing techniques ultimately made possible the provision of cost-effective borehole seismic data of the required quality. The most significant technical breakthrough was the introduction of more reliable, higher-capacity, multilevel 3C tools, which allowed rapid, simultaneous data acquisition from many levels. Better understanding of seismic wave theory yielded comprehensive 3C processing, resulting in more complete P- and S-wave images. Newer seismic techniques, such as hydraulic fracture mapping and micro-seismic monitoring, were also emerging as viable. By the end of the 1990s, improved desktop processing capability allowed rapid interpretation of borehole seismic data using optimized 3C processing sequences. Three-dimensional (3D) VSP became feasible and is now being vigorously pursued. The borehole seismic image was transformed again into even more useful volumetric information. The next step in the evolution of the technology is permanent sensing. Development of smaller, more rugged, fit-forpurpose optical sensors and state-of-the-art optical multichannel instrumentation has enabled the implementation of reliable seismic arrays for long-term deployment within the tight constraints found in well-bores.

Multifarious VSP methods for imaging of complex structures with three component data

Yingping Li, Baker Atlas, Dorothea Faw, Ocean Energy, James Jackson, David Dushman, Fran Doherty, Baker Atlas provide a case study of the benefits of modern borehole seismic technology in the Gulf of Mexico In the US Gulf of Mexico, petroleum reserves are often trapped underneath overhangs of diapiric salt domes. Although the top of salt and sediment structures can be well imaged using current surface seismic migration techniques, the interpretation of the salt flank with irregularly shaped overhangs and the position of updip sands is often ambiguous. Therefore, vertical seismic pro-filing (VSP) surveys are usually requested for additional, independent information (Sparlin and Deri, 1989; Millahn and Manzur, 1990; Nosal et al, 1991; Barker and Guzman, 1992; Burch and Johnson, 1993). The area under study is located in Eugene Island Block 126. There was a deviated well drilled to 11 794 ft SS in the vicinity of a salt dome. A comprehensive borehole seismic survey was designed and acquired in this well in order to obtain a better image of the updip sands and the salt flank. The multifarious three component (3C) VSP data consisted of a rig-source velocity survey (VS), an offset VSP (OVSP), and a refraction salt proximity survey (SP). A map view of the VSP survey configuration is shown in Figure 3. The blue circles are source locations and the pink triangles represent the well trajectory. The survey source was a 500 in, 3 fourgun tuned airgun array. A DGPS navigation system was used to ensure that all sources were in the correct position. To reliably estimate arrival directions for the SP, a gyro tool was attached to the 3C geophone and was used to monitor the orientation of the horizontal geophone components. The rig-source VS was acquired to accurately measure the sediment velocities needed for processing the OVSP and SP data. The data were also subsequently used for ray-trace modelling. The 3C OVSP was shot at an offset of 5571 ft from the wellhead. Presurvey modelling indicated the optimal position of the source to produce reflection images for both the salt face and the updip reservoir sands flanking the salt. The source location of the SP was positioned over the salt top at an offset of 5404 ft from the wellhead. The SP source was positioned in order to utilize the refracted waves to define a salt face position by calculating salt exit points in 3D space. In this paper, we present VSP imaging results from the multifarious VSP survey in the Eugene Island field. The OVSP reflection image of the salt face closely matches the salt exit points calculated from the 3D SP. The determined salt boundary is also consistent with existing well control data. The sedimentary reflectors from the OVSP data terminate as they approach the salt face. Post-survey travel time modelling of the SP data and the salt lead from the VS data provided a further constraint on the shape of the salt flank. Both the refraction and reflection images can be integrated with other available information such as well control data, results from ray-trace modelling, and surface-seismic data, to produce a consistent image of the salt face and the target sand beds. Careful processing and interpretation of the various VSP data result in the precise definition of a diapiric salt dome and updip sands in the Eugene Island field.

Transmission mode time-reversal super-resolution imaging.

The theory of time-reversal super-resolution imaging of point targets embedded in a reciprocal background medium [A. J. Devaney, "Super-resolution imaging using time-reversal and MUSIC," J. Acoust. Soc. Am. (to be published)] is generalized to the case where the transmitter and receiver sensor arrays need not be coincident and for cases where the background medium can be nonreciprocal. The new theory developed herein is based on the singular value decomposition of the generalized multistatic data matrix of the sensor system rather than the standard eigenvector/eigenvalue decomposition of the time-reversal matrix as was employed in the above-mentioned work and other treatments of time-reversal imaging [Prada, Thomas, and Fink, "The iterative time reversal process: Analysis of the convergence," J. Acoust. Soc. Am. 97, 62 (1995); Prada et al., "Decomposition of the time reversal operator: Detection and selective focusing on two scatterers," J. Acoust. Soc. Am. 99, 2067 (1996)]. A generalized multiple signal classification (MUSIC) algorithm is derived that allows super-resolution imaging of both well-resolved and non-well-resolved point targets from arbitrary sensor array geometries. MUSIC exploits the orthogonal nature of the scatterer and noise subspaces defined by the singular vectors of the multistatic data matrix to form scatterer images. The time-reversal/MUSIC algorithm is tested and validated in two computer simulations of offset vertical seismic profiling where the sensor sources are aligned along the earth's surface and the receiver array is aligned along a subsurface borehole. All results demonstrate the high contrast, high resolution imaging capabilities of this new algorithm combination when compared with "classical" backpropagation or field focusing. Above and beyond the application of seismo-acoustic imaging, the time-reversal super-resolution theory has applications in ocean acoustics for target location, and ultrasonic nondestructive evaluation of parts.

Acoustic wave diffraction tomography

The classical theory of Diffraction Tomography (DT) is formulated within the context of the acoustic and elastic wave equations. A number of applications for the generalized theory are reviewed including ultrasound tomography in variable density and elastic wave media and cross-well geophysical tomography and offset vertical seismic profiling (VSP). The general theory of DT is compared and contrasted with classical focus-on-transmit and focus-on-receive confocal acoustic imaging as well as with various standard ad-hoc imaging methods often employed in applications. The use of slant stacking for converting point source to plane wave insonification is reviewed as is the theory of acoustic tomography in known layered background media. A number of computer simulations and results from experimental data are presented.