3D geological model for a gas-saturated reservoir based on simultaneous deterministic partial stack inversion.

Transcription

1 first break volume 28, June 2010 special topic A New Spring for Geoscience 3D geological model for a gas-saturated reservoir based on simultaneous deterministic partial stack inversion. I. Yakovlev, Y. Stein and A. Barkov (Gazprom VNIIGAZ) with K. Filippova * and S. Fedotov (Fugro-Jason) provide a method for modelling a gas-saturated reservoir when acoustic impedance and simple seismic attributes alone fail to provide the solution. W ith the modern level of hydrocarbon exploration and production technologies, different kinds of special studies previously isolated from each other tend to merge into one unified interactive chain of procedures. It has become common practice for field development projects to be based on detailed geological models of reservoirs integrating all available data, most importantly the borehole results and on-surface geophysical survey results. In particular, a litho-stratigraphical and facies model of a field is constructed through synthesis of various approaches: core studies, sequence stratigraphical analysis of log data and interpretation of 3D seismic data (including paleo-reconstruction of depositional environments, attribute analysis and seismofacies classification). 3D seismic exploration data plays an even more significant role in the geological modelling workflow, since it is used not only to build a structural framework of productive layers and to define boundaries of different facial environments, but also to predict the lateral distribution of reservoir properties (lithology, porosity, etc.). This becomes of particular importance when dealing with offshore fields for which the lack of high quality borehole data is common. This type of prediction is usually made via inversion of the 3D seismic cube into elastic properties volumes (i.e., solution of the inverse dynamic problem) and their further transformation into reservoir properties based on petrophysical relationships established during the analysis of well log and core data. The choice of the appropriate inversion method depends on the complexity of the expected geological conditions and the range of problems to be solved. In this paper we present a case study of a geological environment that does not allow correct prediction of reservoir properties using acoustic impedance and simple seismic attributes only. The major problem is that highly saturated gas reservoirs are affecting all dynamic attributes of the seismic data. This leads to strong amplitude anomalies and hence to the distortion of the predicted petrophysical parameters. This is where deterministic simultaneous angle stack inversion may provide a reasonable solution (Mercado et al., 2002) by recovering more than one independent elastic property from the seismic data. It allows a detailed lithology model of the subsurface and subsequent evaluation of the reservoir properties separately for each lithotype (e.g., gasand water-saturated sands), thus accounting for anomalous pay zones. Geological setting The object of this study is one of the largest gas fields in Europe (Shtokman), located offshore in the Russian Barents Sea covering more than 1600 km 2. Discovered in 1988 in the northern part of the South Barents Basin, the gas field is situated in a simple dome- like structure. The productive intervals are composed of terrigenous marine shallow water deposits of middle Jurassic age, represented by three major reservoirs (from the base to the top): J2+3, J1, and J0 (Fig. 1), which were formed in various depositional environments (sequences?) of the siliciclastic shoreline zone. The lower reservoir J2+3, part of the Lower Jurassic (J1 Aalenian), is represented by a thick polyfacial succession, dominated by argillites and sandstones. These have a very complex and irregular lateral distribution. Analysis of log and core data suggests a deltaic origin of the reservoir as a whole. The upper part is interpreted as the deltaic plain incised by distributary channels which form isolated reservoir bodies. The middle reservoir J1 is of Bajocian age and displays typical coarsening and shallowing upwards sequences. It begins with silty-sandy offshore deposits overlaid by a thick barrier bar complex. The northeastern part of the field is dominated by shorefaces and foreshore deposits, while delta front sandstones with so called gravelit units have been recognized in the central part and the southeast. The uppermost reservoir J0 (Calloian age) is represented by a relatively homogenous sandy succession with a sharp base bounding it from underlying shales. Log and core analyses provide paleo-environmental reconstructions: the succession is interpreted as a shallow water mouth bar complex. However, the proximal part is shifted to the northeast compared to the reservoir J1. *Corresponding author: kfilippova@fugro-jason.com 2010 EAGE 125

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