Two 126 level 3-component 3D-VSP's (Vertical Seismic Profiles) were acquired coincident with a high-resolution surface seismic survey. Figure 1 shows the location of the first 3D-VSP on the crest of the field and the second 3D-VSP on the flank of the field. Using the surface seismic sources, 11712 shot points were used per VSP to collect 4.5 million traces per VSP, which produced a 6–9 km2 final 3D-VSP image around each of the two wells. Due to the large offsets and high density of traces available it was possible to experiment with acquisition and processing methodologies to produce images that resolve thinner beds, see more structural definition and improve reservoir characterization. Results from the first phase of processing are very encouraging and show the 3D-VSP images to be able to resolve subtle faults that were not seen in older surface seismic data and have higher frequency content than the new 640 fold, high resolution surface seismic data. Source and receiver decimation tests are aiding in efforts to better understand how to acquire high quality 3D-VSP's in the future with minimal effort and cost. Efforts to expand the size of the 3D-VSP volumes around the wells have been successful. The largest image produced so far has been able to image more than 1.5 km away from the wellbore. The high quality VSP images and the fact that VSP's can be repeated at much lower cost than surface seismic makes this technology very attractive for future time-lapse reservoir monitoring studies.
We conducted laboratory measurements of Vp (compressional waves), Vs (shear waves), porosity and permeability on forty nine dry carbonate core plug samples at ambient pressure and temperature. We also, performed an initial lithological description, based on Dunham's carbonate rock classification to fully characterize the samples. The study results were analyzed to search for potential correlations between the different rock properties and lithological characteristics. We used cross plots of porosity-permeability, Vp - porosity, Vs - porosity, Vp - permeability, Vs – permeability, and Vp-Vs, for all samples and each rock type. The preliminary results from our analysis suggest that the acoustic velocities are highly affected by heterogeneity. The study also confirms an inverse relation between porosity and acoustic velocities, where pore size and pore type can be the main factors controlling the acoustic response at a given porosity. In addition, a general inverse tendency between permeability and acoustic velocities is found. The results also show that carbonate mudstones follow consistent trends of porosity-permeability, Vp - porosity, Vs - porosity, Vp - permeability, and Vs - permeability. This result can probably be attributed to the relativlely more uniform internal structure of carbonate mudstones compared with the other carbonate rock types. Wackestones and packestones present relationships that are less consistent and more dispersed than the ones found for mudstones for instance. The rest of the rock types display a great scatter and non apparent relationships. Finally, we find an empirical correlation between Vp and Vs that can be used to identify gas zones. This study has a great significance in the process of a better understanding of how acoustic velocities from different types of carbonate rocks relate to each other and to their rock properties. This knowledge can potentially be used to diagnose gas zones, predict Vs values, identify different types of carbonate rocks using well log data, and improve seismic interpretation and inversion.
The 3D VSP method is being increasingly employed as a tool to produce high-resolution images for detailed reservoir characterization and to address reservoir challenges. These challenges include thin layer reservoirs, thief zones and stratigraphic features that affect recovery. The main challenges in processing VSP datasets are twofold: First to ensure that the high frequency and better vector fidelity is being used and carried through to the final image. This requires special care and appropriately adapted processing techniques to the smaller scale and high frequency contained in the VSP data. Second, is dealing with the unique geometry of a 3D VSP, which has laterally varying fold coverage and aperture that has to be accounted for in order to minimize any footprint on the final image. In this project VSP processing advances have been made using data from the largest 3D VSP recorded to date, which was acquired in an Abu Dhabi oil field. Different types of static corrections were tested and optimized to recover the high frequencies required for optimum event delineation. A combination of static corrections that takes full advantage of the 3D VSP geometry and includes surface seismic data results that helped achieve optimal coherency of events. A careful analysis of the irregular fold geometry resulted in good target imaging using a detailed illumination analysis. Such an analysis aids in the correct treatment of the high resolution events and helps to interpret their character along the area illuminated. This analysis provides critical information about the velocity model and the corresponding kinematics. The ability of VSP's to recover high frequencies is demonstrated in this processing flow, by showing the difference in resolution between new high resolution surface seismic and the final 3D VSP image. Introduction The availability of 3D VSP data has resulted in more detailed characterizations of the reservoir because of the high resolution given by the VSP data compared to surface seismic techniques. Its usage includes detailed stratigraphic analysis of thin and often deep targets that the surface seismic cannot adequately image. In addition the VSP technology has been used in areas within complex near surface environments or areas where there is limited surface access. The use of receivers within the well has led to seismic images in the vicinity of the well that have high resolution and high signal to noise ratio. More importantly receivers in the borehole environment have led to high frequency data because of shorter travel paths. In the VSP case less energy is attenuated as it only travels once through the near surface weathering layer or complex overburdens. The high frequency recorded by the borehole array (Figure 1) consequently results in smaller Fresnel zones at the target in the vicinity of the well, therefore enhancing its lateral characterization.
An azimuth dependant processing pilot study was carried out in a large Middle East Field to evaluate if this technology has the potential to successfully identify fracture permeability pathways. The field is heavily faulted and fractured with good well control and therefore is a good candidate to perform this study. The success criteria for the Azimuthal processing are:• Improved fault imaging relative to the available conventional processed seismic volume; • Obtain information about seismic anisotropy in the reservoir zones.This anisotropy will be linked in a full evaluation to fault & fracture density and orientation. The anisotropy can be measured via differences in seismic travel times or amplitudes / seismic attributes measured in the different azimuth seismic cubes. Azimuthal anisotropy from a 3D land seismic dataset acquired in the U.A.E. has been analyzed using wide azimuth processing. Two different processing methods and flows were tested to derive optimum processed volumes. In both methods raw CMP gathers, after convolution, residual statics, and inter-bed multiple elimination were used as input data for the azimuth stack processing sequence. The two methods are • Azimuth Sectoring • Common Cartesian Offset Bins (CCOB)Both processing methods have their benefits, one big advantage of CCOB is that you can stack very fast different individual azimuths together and get a sharper image, which results in better interpretation. Azimuth sectors both parallel and perpendicular to the three major fault system orientations, were imaged separately to produce the six final azimuth volumes. Comparisons between the different azimuth sectors were used to detect azimuthal differences in velocities and amplitudes that could be correlated with fault and fracture orientation and magnitude.The interpretation and validation of the results suggest that value is maximized by integrating multiple attributes that include horizon mapping for time differences, amplitude extractions for reflectivity differences and result validations with available well calibration. The azimuth sector results have aided in the quantification of fault presence, magnitude of throw and suggests that fractured zones can be identified which may indicate higher permeability pathways within the reservoir. Another important learning from this case study is to use an integrated approach during processing and interpretation and don't look only at one single part, e.g. velocity cube.Overall the results of this carbonate Azimuthal Pilot for fault and fracture characterization has produced encouraging results and valuable lessons learned to aid future studies.
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