Processing, inversion, and interpretation of a 2D seismic data set from the North Viking Graben, North Sea

Abstract

Simultaneous elastic impedance inversion is performed on the 2D North Viking Graben seismic data set used at the 1994 SEG workshop on amplitude variation with offset and inversion. P‐velocity (Vp), S‐velocity (Vs), density logs, and seismic data are input to the inversion. The inverted P‐impedance and S‐impedance sections are used to generate an approximate compressional‐to‐shear velocity ratio (Vp/Vs) section which, in turn, is used along with water‐filled porosity (Swv) derived from the logs from two wells, to generate fluid estimate sections. This is possible as the reservoir sands have fairly constant total porosity of approximately 28 ± 4%, so the hydrocarbon filled porosity is the total porosity minus the water‐filled porosity.To enhance the separation of lithologies and of fluid content, we map Vp/Vsinto Swvusing an empirical crossplot‐derived relation. This mapping expands the dynamic range of the low end of the Vp/Vsvalues. The different lithologies and fluids are generally well separated in the Vp/Vs–Swvdomain.Potential hydrocarbon reservoirs (as calibrated by the well data) are identified throughout the seismic section and are consistent with the fluid content estimations obtained from alternative computations.The Vp/Vs–Swvplane still does not produce unique interpretation in many situations. However, the critical distinction, which is between hydrocarbon‐bearing sands and all other geologic/reservoir configurations, is defined. Swv≤ 0.17 and Vp/Vs≤ 1.8 are the criteria that delineate potential reservoirs in this area, with decreasing Swvindicating a higher gas/oil ratio, and decreasing Vp/Vsindicating a higher sand/shale ratio. As these criteria are locally calibrated, they appear to be valid locally; they should not be applied to other data sets, which may exhibit significantly different relationships. However, the overall procedure should be generally applicable.