3D VSP Imaging Research Articles

3D VSP: A mine of information for mining exploration

The 3DVSP technique becomes more popular with the emergence of multilevel 3 component borehole tools. The value of the information derived from VSP is not always well understood. In this paper we will present a case history of a joint surface and borehole seismic acquisition, with the goal to de-risk a shaft sinking location on a platinum mine. TD was about 650m and the VSP tool was 110m long. On surface a dense grid of receivers and vibrator source points were laid out in 1.2 km radius circle centered on the well head. A12 level 3C VSP digital tool was lowered in the borehole, in three successive depth positions. The surface 3D cube was processed and interpreted independently from a the 3D VSP data. On a near target reflector, the surface data structural interpretation showed mainly a clear E/W fault, and additional subseismic lineaments of differing azimuths, difficult to identify in terms of fault. The 3D VSP image limited to a short radius around the borehole confirmed the fault/dyke nature of these lineaments, separating monocline compartments. As a consequence, the surface data was carefully re-interpreted and on the second structural images derived from two surface seismic reflectors and the near surface fault footprint from 3DVSP residual statics, a series of subtle faults were clearly assessed. last, the few faults intersecting the borehole can be clearly recognized on the logs and the borehole radar logs. This case study demonstrates the added value of a joint interpretation of surface and borehole data in a decision making process for shaft sinking.

Time-lapse 3D VSP using permanent receivers in a flowing well in the deepwater Gulf of Mexico

The vision of smart wells permanently instrumented with geophones has existed for some time. Such installations would enable opportunities for frequent reservoir monitoring, high-resolution 3D VSP imaging, and illumination of difficult areas. For many subsalt fields, 3D VSPs acquired in such wells may be the best option to illuminate and monitor reservoirs without the need to stop production or enter a well. However, this technology is not yet widely applied, nor perhaps proven.

Modern 2D and 3D VSP: reservoir imaging from downhole

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.