High resolution 3D seismic imaging using 3C data from large downhole seismic arrays

Bjorn Paulsson, Martin Karrenbach, Paul Milligan, Alex Goertz, and Alan Hardin of Paulsson Geophysical Services, with John O'Brien and Don McGuire of Anadarko Petroleum Corporation explain why recording multi-component seismic data using receivers positioned deep in the earth, and closer to the target-zone, can overcome many of the limitations experienced by surface 3D seismic methods. Borehole seismic surveys, commonly known as Vertical Seismic Profiling (VSP), have been an industry standard technique for several decades. In the past, however, these data have been used primarily for check-shot type velocity surveys and for reflection mapping at the well location in a one-dimensional fashion. This 1D measurement can be extended to 2D by using one or more walk-away lines of surface source points. The 2D method works well enough for imaging simple layered stratigraphy, but in a complex reservoir a full 3D data acquisition and imaging solution needs to be pursued. Inserting seismic sensors deep into oil and gas wells, as shown in Figure 1, allows the recording of much higher frequencies as compared to placing sensors at the Earth’s surface. The reason for this is simple: seismic waves have to propagate only once through the weathered layer in a confined zone near the source. In contrast, during surface seismic surveys, waves must travel through the weathered layer twice. Each traversal of the weathered layer attenuates high frequencies much more than the low frequencies, thus reducing the image resolution. The frequency content of borehole seismic data is typically more than twice that of surface seismic data, which provides an increase in subsurface resolution. In addition to recording higher frequency data, borehole seismic sensors provide a number of other advantages: borehole seismic data typically achieve a much higher signal-tonoise ratio than surface seismic data. The combination of a quiet borehole environment and strong sensor coupling to the borehole wall enables such high signal-to-noise ratio. Surface geophones, on the other hand, are generally poorly coupled in weathered rock and exposed to cultural and environmental noise at the surface. Good sensor coupling in the borehole enables three-component (3C) seismic data to be recorded with high vector fidelity. This ultimately allows shear and converted-wave imaging as well as the determination of anisotropy by shear wave splitting analysis (see, e.g., Maultzsch, 2003). Combining P and S wave images allows for attribute inversions of rock properties, such as fluid content, pore pressure, stress direction and fracture patterns. O’Brien et al. (2004b) use time lapse borehole seismic to map changes in such critical attributes for production monitoring purposes. Another advantage of borehole seismic surveys is a favourable geometry to illuminate complex structures such as sub-salt targets, salt flanks or steeply dipping faults. The 3D image volume that can be generated from a large downhole seismic array data is shown in Figure 1. The typical 3D borehole seismic image volume is cone shaped with the top of the cone coincident with the top receiver in the borehole array. The size of the base of the cone is determined by the depth of the image volume and the offset of the sources.