Anisotropic Prestack Depth Migration Research Articles

Optimization of seismic-guided 3-D marine magnetotelluric imaging in a complex fold-thrust belt setting in NW Borneo, Malaysia

SUMMARY The use of seismic-derived structure tensor to guide the inversion of non-seismic data has been gaining increasing attention because of its ability to constrain the inversion result to honour structural information from seismic reflectivity. While the cross-gradient method has been recently adapted to this problem, there is a need to further examine how the choice of the various regularization weighting factors and the design of the starting model impact the image-guided results. In this paper focused on marine magnetotellurics (MT), we study several practical aspects of seismic-guided electromagnetic (EM) inversion to see on what can be improved from the current practice. We then show practical examples of how the cross-gradient method can be applied to get a more geologically pleasing model that fits the data. We also show that there are subjective choices in how to effectively apply the method. First, using a field-realistic synthetic model, we established what would be the suitable regularization weights in the vertical and horizontal directions. Secondly, for the actual 3-D survey data, we compared the use of structure tensors derived from anisotropic pre-stack depth migration (APSDM) reflectivity, high-fidelity full-waveform inversion (FWI) velocity and acoustic impedance inversion volumes to guide cross-gradient anisotropic resistivity inversion with initial half-space resistivity starting models. We determined post-facto the optimum structure tensor weights using well logs as the ground truth. We found that the initial model built using horizon-based interpolated resistivity logs from multiple wells in the anisotropic inversion guided with seismic FWI velocity gave the best match to well logs as compared to the other options. However, given that resistivity logs from multiple wells may not always be available for a robust initial model construction in frontier exploration, we suggest that the structure tensor from APSDM reflectivity data is still preferred since the APSDM reflectivity data have well-defined structural information.

Applying integrated seismic technology to complex foothill areas of foreland basins in China

Due to complicated near-surface conditions, including large elevation changes and complex geologic structures, accurate imaging of subsurface structures for hydrocarbon exploration in the foreland basins of western China has been challenging for many years. After decades of research and fieldwork, we developed an effective seismic exploration workflow that uses the latest technologies from acquisition to imaging. They include 3D high-density and wide-azimuth (WAZ) acquisition, 3D true-surface tilted transverse isotropy (TTI) anisotropic prestack depth migration, and dual-detachment structural modeling and interpretation. To further reduce uncertainty in velocity model building and improve imaging quality, our geologists, geophysicists, and reservoir engineers worked closely through the exploration cycle (seismic acquisition, processing, and interpretation). This exploration model has been used successfully in hydrocarbon exploration of many complex foothill areas in western China. Three-dimensional WAZ high-density seismic surveys have been conducted over 40,000 km2of the foreland basins, greatly improving the field seismic data quality. After application of 3D true-surface TTI anisotropic depth model building and imaging with integrated structural interpretation, new discoveries of hydrocarbon reservoirs have increased. The application of new technologies not only increased drilling success but also reduced depth well-tie errors between seismic data and wells.

Anisotropic Depth Imaging Case Studies from Australia's North West Shelf

This paper demonstrates the increase in confidence of depth prediction and structural imaging achieved using anisotropic pre-stack depth migration of 3D surface seismic data. Using examples of anisotropic travel time derived models updated with hybrid grid-based reflection tomography, this paper provides evidence of improved imaging from two data examples in Australia?s North West Shelf. The data examples described contain various imaging challenges, including short scale lateral velocity heterogeneity, carbonates, gas affected overburden zones, HRDZ?s (Hydrocarbon Related Diagenetic Zones) and reservoir level fault shadows. This paper will describe the work flow approach used and the geological considerations given to derive an appropriate earth model for each dataset. Evidence is presented to show how the velocity models converge to minimal residual moveout with each iteration of reflection tomography. Comparisons between data formed with time domain imaging and anisotropic depth imaging are made for the two surveys considered.

Constraining a 3D anisotropic tomography inversion with 800 wells – A Canadian oil sands case history

This Canadian oil-sands case history is a very shallow play with a complex geology that includes Quaternary thrusting at surface, sinkholes, and highly karsted Devonian carbonates at the base of the notoriously complex McMurray reservoir. Despite this challenging environment, we were able to demonstrate that Depth Imaging brought significant improvements as compared to the routinely used time imaging. Recent developments in Anisotropic Pre-Stack Depth Imaging technologies provided a better focused and better positioned 3D subsurface image that accurately tied several hundreds of wells. These results were achieved using steering filters, solver bounds and simultaneous multi-parameter tomography inversion while constraining the tomography updates with the well top picks from over 800 wells. Surveys of different vintages, geometries, orientations and shooting directions were regularized using 5D interpolation and merged together. Besides a better imaging of the subsurface, one of main objective of the project was the characterization of the McMurray reservoir. To that aim, the Anisotropic Pre-Stack Depth Migration (APSDM) generated better conditioned Offset Vector Tile gathers for subsequent pre-stack inversion work. The Alberta oil sands are one of the largest bituminous hydrocarbon reserves in the world (Alberta Energy Regulator, 2015). At reservoir temperature, the bitumen is so viscous that it can almost be considered as a solid. In situ thermal recovery processes such as steam-assisted gravity drainage (SAGD) that lower viscosity and increase mobility are required to extract the bitumen from the reservoir. SAGD operations consist of horizontal well pairs that are drilled into the base of the reservoir. In each pair, one well is drilled about 5 m directly above the other well. The top well is injected with steam to melt the bitumen. The bitumen seeps down towards the bottom producing well, which pumps the bitumen to the surface. The well pairs are generally configured to about ten parallel horizontal well pairs that are around 100 m apart horizontally and are 1000 m long, which constitute a 1-km2 pad.

Key seismic exploration techniques for foreland thrust belt: A case from the complex deep subsalt structure of Kuqa, Tarim Basin, Western China

The Kuqa area of the Tarim Basin is a typical foreland thrust belt. Abundant petroleum resources are stored in the complex subsalt structures at depths greater than 6500 m. The extremely rugged surface, the severely deformed gypsum-salt cap above the reservoir, and the large burial depth of the overthrust target make it difficult to accurately delineate the target structures. Those geologic challenges translate into geophysical difficulties of complex seismic wavefields, low signal-to-noise ratio (S/N), and poor imaging accuracy, which compound the exploration challenge in the Kuqa area. To meet the exploration challenge, a research campaign has been conducted since 2005 to integrate seismic acquisition, processing, and interpretation. After almost a decade of research effort and pilot applications, a set of techniques, comprised of wide-line large-array acquisition, anisotropic prestack depth migration under rugged topography, complex structure modeling, and structure mapping with varying velocities, was developed. The use of these techniques has much improved the S/N, imaging accuracy, subsequent interpretation, and well placement. As a result, the success ratio of exploration drilling has increased from less than 25% to more than 64% in the Kuqa area of the Tarim Basin.

Broadband Seismic Acquisition: Implications for Interpretation and Reservoir Models

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18075, “The Impact of Broadband Seismic Acquisition and Implications for Interpretation and Reservoir-Model Building,” by Carter Gehman and Andrew Spedding, Hess, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed. This paper addresses the impact of acquiring a new 3D broadband seismic survey over an amplitude-supported, discovered gas field containing legacy 3D conventional towed-streamer seismic data. The new seismic data were acquired in shallow water depths by use of a dual-level streamer technique and were processed through prestack depth migration (PSDM). Five gas discovery/ appraisal wells existed before broadband acquisition, and two wells were drilled after acquisition was completed. These seven wells serve as control points that provide a valuable link between the seismic and reservoir properties. Introduction and Background Seismic imaging of hydrocarbon reservoirs with small impedance contrasts relative to bounding lithologies is challenging. Ideally, an infinite bandwidth wavelet would detect and resolve subsurface geology as observed in the resolution of a typical wireline log. Improvements in seismic acquisition and processing continue to strive toward this ideal condition, and recent advancements in seismic acquisition— namely, the broadband acquisition technique—have attempted an approximation of the infinite bandwidth wavelet through the removal of the receiver or source ghosts. This advancement is of particular interest in oil and gas development areas where known thin or poor-quality reservoirs that are difficult to detect on conventional seismic records have been penetrated by previous wells. The study area is located in the shallow (less than 200 ft) waters off peninsular Malaysia. Seven exploration and appraisal wells have targeted shallow and deep reservoirs, although only three wells have been drilled to deep targets. Generally speaking, seismic imaging of shallow reservoirs is good, while deep targets are more challenging to image. The primary motivation for acquiring a new broadband seismic survey stemmed from imaging difficulties of thin (less than 15 ft) deep gas reservoirs on conventional seismic data. Many of these reservoirs are vertically juxtaposed by coals, which tend to mask the acoustic response of the reservoir. Even after later reprocessing of legacy data through anisotropic PSDM, imaging difficulties remained.

Innovation and prospect of geophysical technology in the exploration of deep oil and gas

Abstract The global situation of distribution, reserves and production of deep oil and gas are examined systematically, the progress and exploration achievement of onshore China deep geophysical technology are summarized, and the challenges and developing direction of deep geophysical technology are pointed out. Aiming at the exploration of deep onshore strata in China, the article analyzes the key geophysical problems, such as low signal-to-noise ratio, low resolution, low imaging accuracy and low amplitude-preservation, in the exploration of deep clastic, carbonate, and volcanic reservoirs, and presents the corresponding technical countermeasures such as wide-line large-array 2-D acquisition, wide-azimuth and high-density 3-D acquisition, anisotropic pre-stack depth migration (PSDM), reverse-time migration (RTM), complex structure modeling, and quantitative reservoir prediction. The analysis from two aspects, imaging of deep complicated structures and prediction of deep complicated reservoirs, shows that wide-frequency, amplitude-preservation, high-accuracy and information integration are the challenges to and key issues in the geophysical technology. It is pointed out that wide-frequency seismic acquisition, rock physical modeling of complex reservoirs, high-accuracy prestack amplitude-preservation imaging, comprehensive evaluation of complex reservoirs, non-seismic techniques, and drilling steering with seismic data are the key geophysical techniques needed to be developed in the future.

Gaussian beam prestack depth migration in heterogeneous transversely isotropic media

The transversely isotropic (TI) media approximation is commonly applied to assist in the processing of seismic data acquired in sedimentary environments. Based on anisotropic kinematic and dynamic ray tracing systems, a P-wave Gaussian beam prestack depth migration (GB-PSDM) method for TI media is introduced in this paper. The imaging principle of anisotropic GB-PSDM and the corresponding migration parameters are presented on the basis of the GB-PSDM method in isotropic media. Tests of synthetic and field seismic data show that the method is an accurate and efficient anisotropic prestack depth migration method in TI media.

Reducing seismic positioning uncertainty with “simple” tilted transverse isotropy earth models — Gulf of Mexico Lobster field case study

The remaining potential in many mature fields in the Gulf of Mexico consists of smaller long-reach targets that require ever-more-accurate vertical and horizontal location for drilling precision. This is particularly true at the Lobster field in Ewing Bank, where, during the previous platform drilling campaigns, some midreach prospects were interpreted to have been missed due to mispositioning. Potential future drilling at the Lobster field would target primarily long-reach prospects in areas of significant geologic dip — increasing the risk of missing the prospects. This mispositioning risk could sometimes exceed the geologic risk, and it could have significant impact on the risked reserves and on the economics. Achieving the desired positioning accuracy requires the use of 3D seismic and anisotropic prestack depth migration with accurate velocity and anisotropy models. We have developed a case study of using a long offset walkaway checkshot and a geologic frame of reference to build a tilted transverse isotropy velocity model sufficiently accurate to support potential future drilling campaigns at the Lobster field.

Imaging deepwater carbonates offshore Brazil: Methodology and uncertainties

An anisotropic prestack depth-migration sequence was used in the imaging of a carbonate accumulation in deep water offshore Brazil. The reservoir is overlain by a complex sequence of evaporites, carbonates, and clastics. Although the latter display a modest magnitude of anisotropy, this parameter has to be taken into account for the depth accuracy required in reservoir evaluation. The seismic data input to the processing consist of two narrow-azimuth streamer surveys, acquired with distinct azimuths that overlap approximately at the center of the reservoir structure. The resulting velocity model is geologically plausible, exhibiting good accuracy when compared with average velocities calculated from check shots and vertical seismic profiles acquired at nearby wells. Such accuracy holds true to the base of the evaporitic sequence, which corresponds roughly to the top of reservoir, and makes this model adequate for depth positioning and hydrocarbon volume calculations. However, deep layers in the velocity models present larger errors and a spatial behavior that does not match geologic expectations. This is attributed to the lack of proper illumination that these conventional seismic acquisitions provide and arguably makes the case for a more modern full-azimuth seismic acquisition over the structure. This limitation is quantified by an illumination map simulated at the top of the reservoir from a waveform-modeling exercise that took into consideration the seismic-acquisition parameters over the field.

Advances in velocity modelling and imaging techniques in the Taranaki Basin

SUMMARY This paper demonstrates recent advances in grid-based reflection tomography model building in conjunction with anisotropic pre-stack depth migration. These advances significantly benefit the imaging and resolution of 3D seismic data in a number of structurally complex basins. Using 3D seismic imaging examples from Petroleum Exploration Permit PEP 51558 in New Zealand’s Taranaki Basin, this paper demonstrate how reflection tomography techniques can utilize implicit geological constraints to resolve complex velocity variations and, thereby, reduce structural and imaging uncertainty. One challenge associated with velocity modelling in the Taranaki Basin is to adequately resolve the large lateral velocity contrasts across major faults. This work shows how the use of steering filters during the reflection tomography process significantly improves the resolution and delineation of these fault-constrained velocity contrasts. This approach is compared with the conventional gridded tomography approach of velocity model building. Using a detailed velocity model from the Taranaki Basin, comparisons were made between time and depth migration, as well as alternate depth migration techniques.

Anisotropic Depth Imaging Case Studies from Australia’s North West Shelf

SummaryThis paper demonstrates the increase in confidence of depth prediction and structural imaging achieved using anisotropic pre-stack depth migration of 3D surface seismic data. Using examples of anisotropic travel time derived models updated with hybrid grid-based reflection tomography, this paper provides evidence of improved imaging from two data examples in Australia’s North West Shelf.The data examples described contain various imaging challenges, including short scale lateral velocity heterogeneity, carbonates, gas affected overburden zones, HRDZ’s (Hydrocarbon Related Diagenetic Zones) and reservoir level fault shadows. This paper will describe the work flow approach used and the geological considerations given to derive an appropriate earth model for each dataset. Evidence is presented to show how the velocity models converge to minimal residual moveout with each iteration of reflection tomography.Comparisons between data formed with time domain imaging and anisotropic depth imaging are made for the two surveys considered.

A case study for azimuthally anisotropic prestack depth imaging of an onshore Alaska prospect

In a study of the Sterling-Triangle area of Alaska, U.S.A., we initiated prestack depth migration (PSDM) to improve imaging on a prospect initially identified on a prestack time-migrated (PSTM) volume. Under the isotropic media assumption, the first few iterations of the reflection tomography had difficulty in converging to the proper velocity model. Upon further investigation, a very-high-velocity conglomerate layer was identified in the middle of the section across the whole survey area. We adopted the salt-flood practice, routine in depth-imaging salt provinces such as the Gulf of Mexico. The strategy was to focus on the shallow section above the conglomerate first, followed by a constant-velocity flood for picking the conglomerate base. The finalisotropic PSDM result showed that significant residual moveout differences existed on gathers along different azimuths. The net anisotropic effect on the isotropic PSDM was a degraded final PSDM volume. In the subsequent anisotropic PSDM work, azimuthally variant horizontal velocities were allowed in the model building. Common-image-point (CIP) gathers were created along different azimuths using sectored input gathers. Residuals picked on the sectored CIP gathers were used in joint tomography to invert different horizontal velocities. Incorporating significant well information, we built an anisotropic velocity model such that the azimuthal moveout on the butterfly gathers was essentially flat. The resulting anisotropic PSDM was consistent with well data and could be interpreted with much higher confidence.

Anisotropic PP and PSv prestack depth migration of 4C seismic data; Pamberi, Trinidad

SummaryIn November 2004, EOG Resources contracted WesternGeco to acquire an ocean-bottom cable (OBC) 4C swath survey across the Pamberi-1 well in the Lower Reverse L block of the Columbus basin, eastern offshore Trinidad. The purpose of the 4C survey was to evaluate the potential of long-offset multicomponent technology for resolving lithology and stratigraphic detail in an area perturbed by shallow gas, overpressure and illumination shadows from normal regional faults and major anticlinal ridge trends acting as pressure seals. A key motivation for EOG was the realization that a conventional 3D towed-streamer survey acquired the previous year failed to adequately image the target reflectors comprising the reservoir under the main fault.Details of the P- and PSv-wave processing of this dataset through anisotropic prestack time migration were previously described (Johns et al., 2006) in which it was demonstrated that there existed a qualitative correlation between derived parameters and attributes from P and Sv anisotropic migration velocities and known regional geology. This observation was quite remarkable considering only a limited effort to constrain or validate parameters (in this case, velocities to the Pamberi-1 well checkshots) was performed. Under the “Future work” section of the previous publication, it was suggested that further data quality enhancement in preparation for more quantitative rock property classification could only be achieved after prestack depth imaging.In this paper, we present precisely that next phase in the 4C processing, advancing the P- and PSv-wave data through anisotropic prestack depth migration, using cellbased tomography with a top-down approach. The Pamberi-1 well was used to constrain the anisotropy in the shallow section, with the deeper, spatial trend away from the proximity of the well determined from the anisotropy derived previously in the time processing.Prior to proceeding with the anisotropic depth imaging, the magnitude of shear splitting from the presence of azimuthal anisotropy (HTI) was first examined to assess its potential impact on the radial rotated P-S signal. The shear wave splitting analysis revealed a principal angle of polarization that was closely aligned with the regional stress direction delineated by the normal major faults blocks acting as pressure seals.

A comparison between anisotropic reverse time and phase-shift plus interpolation prestack migrations for tilted anisotropic media

Two 2D anisotropic prestack depth migration algorithms that use wavefield extrapolation are evaluated for tilted transversely isotropic media (TTI). The first method is anisotropic phase-shift-plus-interpolation (A-PSPI) that is based on an analytical solution of frequency-dispersion enabling the use of an arbitrary distribution of velocities and anisotropic parameters. The second method is anisotropic reverse-time (A-RT) that uses the full wave equation. we evaluate the accuracy and efficiency of there algorithms. Examples are presented that use numerica and physically modelled data along with a structurally complex real data example. Both A-PSPI and A-RT have excellent performance with A-RT maintaining the advantage of using the full wave equation.

VTI anisotropic corrections and effective parameter estimation after isotropic prestack depth migration

In the method for applying anisotropic corrections after isotropic prestack depth migration (PSDM), the correction, which is calculated and implemented in the depth domain, is defined as a time difference between isotropic and anisotropic traveltimes, under the assumption that the vertical velocity is known. The definition of this correction uses a special postmigration common-image-gather (CIG) ordering, which collects the migrated data according to the input-trace’s source and receiver distance from the surface CIG location. In this postmigration domain, the dip of the events can be directly related to their horizontal position in the CIG, called the imaging offset, and the separation of flat and dipping reflectors becomes easy to perform. The dependency of the seismic anisotropic effect on the subsurface dip angle is well pronounced in these CIGs. After application of an isotropic PSDM, effective anisotropic-parameter estimation is performed at selected CIG locations by using a simple two-parameter scan procedure. The optimal anisotropic parameters can be used to perform a final anisotropic PSDM or to apply a residual correction to the isotropically migrated data. We demonstrate the method for P-wave data in 2D media with vertical transverse isotropy (VTI) symmetry by using both synthetic and real data. We also present a strategy for handling the ambiguity between the vertical velocity and the anisotropic parameters.

Reducing structural uncertainties through anisotropic pre-stack depth imaging: examples from the Elgin/Franklin/Glenelg HP/HT fields area, Central North Sea

This paper highlights how a global approach to quantifying structural uncertainties has ultimately reduced overall structural uncertainty through improved seismic imaging, notably anisotropic pre-stack depth migration, in a structurally complex area. The Elgin/Franklin high pressure/high temperature (HP/HT) fields lie in the Central Graben area of the North Sea UK sector, c . 240 km east of Aberdeen. The fields are the deepest production in the North Sea and represent the largest gas condensate development in the world, with recoverable reserves estimated at over 700 × 10 6 BBL equivalent. The reservoirs produce from the Jurassic Fulmar shallow-marine and Pentland fluvial reservoirs at depths of 5100–5600 m subsea. Production from these HP/HT reservoirs (1100 bar/200°C) started in March 2001 and flows over 200 000 BOE per day from 12 wells. For this type of producing environment, the stakes are high for understanding uncertainties related to imaging. Improved fault imaging translates not only to reduced uncertainties in bulk rock volumes, and ultimately in-place hydrocarbon volumes but also to an increased understanding of the static/dynamic behaviour of the fields through better imaging of internal faulting. The application of various proprietary and contractor-based seismic depth processing since 1997 has allowed for a better understanding of structural configuration of the deep reservoirs. This rich processing history has provided the interpretation team with various processing volumes (isotropic Post-SDM, anisotropic Post-SDM and, most recently, anisotropic Pre-SDM) to allow a more complete understanding of the uncertainties related to different imaging approaches. Historically, the effects of anisotropy on vertical and lateral positioning were realized and a number of internal proprietary software tools were developed to quality control depth imaging processing. The 1998 Glenelg discovery southwest of Elgin Field was the focus for the initial anisotropic Pre-SDM study, which was later expanded to include the Elgin/Franklin fields area. This processing benefited from Total’s internal QC tools and a combination of additional data (e.g. walk-away VSP profiles with different orientations, long-offset 2D seismic data) which provided an optimum mix to derive and verify the anisotropic parameters for the velocity model. Overall, the new seismic data shown significant improvement over the previous time- and depth-migrated datasets, reduced uncertainty on internal and bounding-fault positions and allowed the observation of the vertical and spatial uncertainties attached to different migration approaches. This understanding of the variability in seismic imaging and its effects on the reservoir parameters and structural configurations in depth is used as an input to understand ranges of in-place hydrocarbon volumes, the potential of near-field exploration and future infill-drilling strategies.

Integrated prestack depth migration of vertical seismic profile and surface seismic data from the Rocky Mountain Foothills of southern Alberta, Canada

We have developed an anisotropic prestack depth migration code that can migrate either vertical seismic profile (VSP) or surface seismic data. We use this migration code in a new method for integrated VSP and surface seismic depth imaging. Instead of splicing the VSP image into the section derived from surface seismic data, we use the same migration algorithm and a single velocity model to migrate both data sets to a common output grid. We then scale and sum the two images to yield one integrated depth‐migrated section. After testing this method on synthetic surface seismic and VSP data, we applied it to field data from a 2D surface seismic line and a multioffset VSP from the Rocky Mountain Foothills of southern Alberta, Canada. Our results show that the resulting integrated image exhibits significant improvement over that obtained from (a) the migration of either data set alone or (b) the conventional splicing approach. The integrated image uses the broader frequency bandwidth of the VSP data to provide higher vertical resolution than the migration of the surface seismic data. The integrated image also shows enhanced structural detail, since no part of the surface seismic section is eliminated, and good event continuity through the use of a single migration–velocity model, obtained by an integrated interpretation of borehole and surface seismic data. This enhanced migrated image enabled us to perform a more robust interpretation with good well ties.

On Structural Integrity in Seismic Data

The industrialist Peter Scotese once said, ``Integrity is not a 90 percent thing, not a 95 percent thing; either you have it or you don't.' In the case of seismic data, structural integrity derives from the combined accuracy of the migration algorithm and velocities used. Indeed, these two components are complimentary. For example, even the most accurate migration method cannot provide reliable structural images if the velocities used are obtained by simply scaling stacking velocities by 90 percent or 95 percent! The nature of the velocity field is, of course, a major factor in determining the detail, sophistication and intensity required for velocity analysis. However, it also influences the accuracy of the structural image in other, subtler ways. In particular, although the range of velocity variations dictates the complexity of the imaging method that should be used, it can also influence what parts of the earth can be imaged, and, by implication, even place constraints on the data acquisition. Finally, because the focusing aspect of migration is relatively insensitive to certain (anisotropic) aspects of the velocity field, this limits the accuracy with which migration velocities alone can be used to convert directly to depth, and can even introduce lateral mispositioning in the final image. Indeed, this is one of the major reasons why migrated data often do not tie wells correctly. In this paper, we consider the impact and interaction of velocity variations and migration algorithms on structural imaging. Specifically, we review different migration algorithms, and show how more detailed and accurate consideration of the velocity behaviour on the underlying physics can lead to more reliable images and improved velocity determination. We also show that fundamental limitations in data-derived velocities can be overcome using well information, and that, when this is done, anisotropic prestack depth migration can provide exceptionally accurate images in depth. As General Norman Schwartzkopf once said about integrity, ``The truth of the matter is that you always know the right thing to do. The hard part is doing it.'

Anisotropic prestack depth migration in practice

Conventional prestack depth migration involves building a velocity model for the subsurface using velocities that are assumed to be isotropic. When the earth is anisotropic, it is impossible for this conventional earth model to correctly predict the seismic raypaths and hence to accurately migrate the recorded data.Common problems with conventional prestack depth migration are overcorrected common-image point gathers and depth misties with available well data.Applying anisotropic prestack depth migration involves making some assumptions about the symmetry of the anisotropy and then determining the vertical velocity and the anisotropic parameters, delta and epsilon. These parameters were determined using a combination of well information, higher moveout analysis and migration scans.The results of a successful anisotropic prestack depth migration tie the available well information, have flat common-image point gathers and have higher resolution and improved focussing.