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Modern 2D and 3D VSP: reservoir imaging from downholeGreen Open Access

Authors: B. Fuller, M. Sterling and L. Walter
Journal name: First Break
Issue: Vol 24, No 5, May 2006
Language: English
Info: Article, PDF ( 990.93Kb )

Brian Fuller and Marc Sterling, Sterling Seismic Services, and Larry Walter, Geospace Engineering Resources International (GERI), provide a guide to modern VSP and see further potential as the technology matures. Check shot surveys and VSPs have been used for decades as a way to obtain a reliable time-depth tie for seismic reflections, constrain depth migration results, and generally improve seismic interpretations. Along the way seismologists also noted that seismic data recorded in the borehole generally contains higher frequency than surface seismic data. The empirically derived rule of thumb is that VSP data contain two times the frequency content of surface seismic data. It is commonly assumed that seismic frequency attenuation is smaller for borehole seismic data because the VSP raypath is shorter than for surface seismic raypaths and because the VSP seismic wavefield passes through the nearsurface zone only once. Figure 1 shows a direct comparison between a 3D surface seismic image and a 3D VSP image. Abutting slices from the respective 3D volumes both show discontinuous sand bodies where gas production is strongly influenced by faulting and stratigraphic variations. The 3D VSP image, however, contains about twice the frequency content of the surface seismic data and shows many more details of the reservoir. The higher frequency content available in VSP data provides an opportunity to use 2D and 3D VSP as a powerful reservoir development tool. The details of reservoir fault architecture and stratigraphy are simply easier to see with 120 Hz data than 60 Hz data. The purpose of this article is to provide the reader with an overview of modern 2D and 3D VSP methods and some factors driving the current rapid growth in use of the method.

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