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1 3D VSP acquisition and 3C processing on a deep subsalt prospect in the Gulf of Mexico John Graves, Steve Checkles, Jacques Leveille, Hess Corporation, Houston; Allan Campbell*, Scott Leaney, C. Peter Deri, Schlumberger, Houston Summary Good quality seismic images can be difficult to achieve in the deepwater, sub-salt sediments of the Gulf of Mexico. 3D vertical seismic profiles (3D VSP), with the receivers placed below the salt, can be a useful technique in improving sub-salt image quality. This paper describes how a 3D VSP was used to prove the existence of reservoir horizons, confirm reservoir dip and generally confirm seismic correlations. Success was achieved by way of several innovations in acquisition and processing. We deployed 40 downhole receivers, the largest array deployed in the Gulf of Mexico at the time of recording. Previously, a survey of this magnitude required several tool settings and several times the rig time. Noise in the data prompted development of station consistent deconvolution, a new casing ringing reduction technique. We also adapted surface seismic techniques for reducing random noise and source noise from a nearby surface seismic shoot. Common image point gathers (CIP) were introduced as a means of verifying the migration velocity model and as quality control tool for the final image stacking. The 3D VSP image volume produced an excellent tie to the existing surface seismic and well data, and confirmed presurvey interpretations and correlations. Introduction data available in the area. We feel that this is a result of reducing the travel through the salt boundaries by half (because of the VSP geometry), and by careful treatment of the amplitudes recorded in the VSP. Other issues such as imaging holes beneath salt are resolved with VSP geometry (Hornby et al, 2006). Survey Design We used 3D ray tracing in a fully 3D model to determine the best shot pattern to achieve the desired subsurface illumination. The illumination needed to extend to a nearby well where more borehole seismic data existed. We did not follow the traditional spiral survey design, as there was fear of weather causing a premature end to data acquisition. The final design of 55 parallel source lines shown in Figure 1 would guarantee at least 2D coverage with sufficient lateral offset from the wellhead to meet the imaging goals of the project should the weather turn bad. \ Figure 1 3D survey design to optimize sub-surface coverage Acquisition The central Gulf of Mexico (Planning Areas Green Canyon, Garden Banks, etc.) is characterized by water depths in excess of 1000 feet, and salt sheets that vary in thickness from 0 feet more than 15,000 feet. These salt sheets can have irregular (non-planar) top surfaces and basal surfaces, which together with the high contrast in seismic impedance with the bounding sediments, results in complex, high-amplitude bounding reflections. These surfaces generate strong multiples on seismic images. These effects, taken together, can severely degrade seismic data quality in many areas. To attempt to solve these problems, Hess partnered with Schlumberger to conduct a 3D VSP in a recently drilled well in the area. Results of the VSP showed significantly improved signal-to-noise, and coherency of the data, versus even the newest 3D surface Figure 2 First use of a 40 level downhole tool in the Gulf of Mexico The downhole tool used in survey acquisition was the VSI- 40, a 40 level downhole array (Figure 2). 50 ft level spacing makes the downhole array 1950 ft long. At the time 3340 Downloaded 20 Jul 2009 to Redistribution subject to SEG license or copyright; see Terms of Use at

2 of acquisition this was the longest arra, with the most receivers that had been deployed in the Gulf of Mexico. Maximizing the array length has been proven to be a critical part for a successful 3D VSP survey (Van Gestel et al, 2003). There are three significant noise types in the data. The data are affected by casing ringing due to poor cement bond between the casing and the formation. Random noise bursts can be seen in the data, and a nearby surface seismic shoot contributed coherent noise to parts of the survey. Noise Reduction Two main processes were used to reduce noise in the data. Station consistent deconvolution was developed to reduce casing ringing, and f-xy filtering was used to remove random noise and source noise from the nearby survey. The well known process of surface-consistent deconvolution has been adapted to the multi-source VSP geometry where a multi-component downhole array remains stationary (Leaney et al, 2008). The offset and CMP terms of surface-consistent deconvolution for surface seismic data are replaced by a distance indexed average term, estimated using a novel re-indexing of shot-receiver pairs (or stations). Additionally, a frequency-independent scale factor is optionally included to handle the inevitable rotation of horizontal components. The source and receiver terms are estimated using a median or trimmed mean with Gauss-Seidel iteration. An input shot gather and estimated residual receiver spectra are shown in Figure 3. An amplitude-preserving minimum phase operator is then constructed and applied to the data to remove the receiver coupling variations. Station consistent deconvolution (SCD) was applied to the complete survey and successfully reduced the casing ringing noise (Figure 4). Figure 4 Removing casing ringing with station consistent decon. Before filtering on top, after filtering on bottom. After application of the station consistent decon, f-xy noise reduction was applied to remove noise bursts, and further attenuate boat noise (see Figures 5 and 6). Both these noise types appear random in either the shot or receiver domain and can be attenuated with little damage to the desired data. Figure 5 Raw X, Y, Z axes showing noise bursts and casing ringing from a representative shot. Figure 3 Receivers with casing ringing on left, residual spectra on the right. Figure 6 EW, NS, Vertical after SCD, f-xy filter, and orientation (bottom). Same shot as in Figure Downloaded 20 Jul 2009 to Redistribution subject to SEG license or copyright; see Terms of Use at

3 Processing The processing flow uses a 3C vector separation technique which uses all three oriented components of data to produce scalar compressional and shear wavefields. The 3 component data is first oriented to a fixed reference frame which uses the direct arrival polarizations and an optimal bearing inversion technique. We output data oriented to an EW, NS and true vertical frame. An anisotropic vector plane wave 3D, 3C elastic wavefield decomposition technique (Wavesip) was used to derive scalar P, Sv and Sh wavefields from the oriented data. Wavesip decomposes downhole vector array recordings using a comparatively rich plane wave spectrum and hence takes advantage of acquisition with longer array tools such as the 40 receiver array used here. For any given wave type (down P, up P, down Sv, up Sv, down Sh, up Sh), plane waves with propagation angles within an aperture are estimated in the data, then summed and stored (Leaney, 2002). Figure 8 Starting model supplied by Hess. For the full 3D migration, the 3D starting model was calibrated using the VSP direct arrival travel times. Model calibration uses a tomographic updating of the model velocities to minimize the difference between the observed direct arrival times in the VSP data and the direct arrival times estimated by ray tracing through the velocity model while using the survey geometry. A measure of the success of the model calibration is the minimization of residual travel times (Figure 9). Figure 7 Scalar downgoing P, upgoing P, downgoing Sv, upgoing Sv from same shot as in Figures 5 and 6. Trace-by-trace waveshaping deconvolution was applied to the upgoing P wavefields with the goal of producing a zerophase upgoing P wavefield. The deconvolved scalar upgoing p waves are then input to migration. Migration Reliable images of the sub-salt sediments required a 3D migration, using a fully 3D, borehole calibrated velocity model. The starting model (Figure 8) was a PSDM surface seismic velocity model supplied by Hess. Figure 9 Residual times for uncalibrated model (top) and model after VSP calibration (bottom). We left the Hess supplied velocities untouched below the receivers to provide a better tie with the surface seismic. After borehole calibration of the velocity model, we use a fully 3D version of the GRT migration technique described in Miller et al, We migrate shot by shot but have the option to save an image volume for each receiver. This allows various qc techniques, such as CIP gathers, to be used. Common image point (CIP) gathers have been used in this study to validate the velocity model. CIP gathers are 3342 Downloaded 20 Jul 2009 to Redistribution subject to SEG license or copyright; see Terms of Use at

4 generated by collecting all migrated traces from the same image location. Each image X, Y location will have a 40- trace CIP gather if a 40-receiver 3D VSP has been migrated. As we are sampling the same image points, the reflectors in a CIP gather should be flat if the velocity field used in the migration is correct. As we have shown, the 3D VSP that was conducted in this area was successful in recording high-quality (low-noise) seismic reflections, from an area where previous surface seismic acquisition efforts had been unable to obtain records of this quality. We feel that this was a result of careful survey planning; and careful processing efforts. Because of these good results, Hess hopes to conduct more VSPs in the central Gulf of Mexico. Figure 10 Two example CIP gathers from migrated receiver volumes. We migrated 40 receivers so each common image point gather will have 40 traces. Figure 10 shows the reflectors to be generally flat, giving confidence in the velocity model. The CIP gathers also show that the deeper receivers (the right side of the panels) are not coherent with the shallower receivers, so only the shallowest 21 receiver volumes were stacked to produce the final image volume (Figure 11). Starting with 40 downhole receivers provides a large amount of data redundancy, giving the opportunity to remove data from the final stack if there is any doubt about the quality of the data. Figure 12 3D VSP on top of surface seismic on left, 3DVSP extracted line on right. Conclusions This 3D VSP was shot to provide confidence in the interpretation of sub-salt reservoir horizons. This goal was met due to several innovations in the acquisition and processing of the data. At the time of shooting, this was the largest 3D VSP survey acquired in the Gulf of Mexico utilizing 40 downhole receivers. A new noise reduction technique, station consistent decon, was developed to remove casing ringing from VSP data. F- XY filtering was adapted from surface seismic to reduce random noise and shot noise from another survey. We also adapted CIP gathers from surface seismic to verify the accuracy of our migration model. Figure 11 Two lines extracted from the final image volume Results The 3D VSP images show an excellent tie to the well log data recorded in the survey well. Lateral continuity of the deeper reflections in the image shown in Figure 12 is improved over the surface seismic. The final image volume provides an excellent tie to the surface seismic. This gives confidence in the location of the reservoir horizons and supports later sidetrack drilling decisions. Acknowledgements The authors thank Hess Corporation for the permission to publish this paper. We would also like to thank Dave Patten and Rogelio Rufino at Schlumberger for their work in processing the 3D VSP Downloaded 20 Jul 2009 to Redistribution subject to SEG license or copyright; see Terms of Use at

5 EDITED REFERENCES Note: This reference list is a copy-edited version of the reference list submitted by the author. Reference lists for the 2008 SEG Technical Program Expanded Abstracts have been copy edited so that references provided with the online metadata for each paper will achieve a high degree of linking to cited sources that appear on the Web. REFERENCES Gestel, J. P., B. Hornby, J. Sharp, C. Regone, and D. Ebrom, 2003, Effects of changing the receiver array settings on VSP images: 73rd Annual International Meeting, SEG, Expanded Abstracts, Hornby, B., J. Yu, J. A. Sharp, A. Ray, Y. Quist, and C. Regone, 2006, VSP: Beyond time-to-depth: The Leading Edge, 25, Leaney, W. S., 2002, Anisotropic vector plane wave decomposition for 3D VSP data: 72nd Annual International Meeting, SEG, Expanded Abstracts, Leaney, W. S., M. Sacchi, and T. J. Ulrych, 2008, Station-consistent deconvolution for multisource VSP data: in preparation. Miller, D., M. Oristaglio, and G. Beylkin, 1987, A new slant on seismic imaging: Migration and integral geometry: Geophysics, 52, Downloaded 20 Jul 2009 to Redistribution subject to SEG license or copyright; see Terms of Use at