The paper discusses an approach for predicting the lateral variation of net to gross (NTG) by use of 3D probabilistic seismic inversion. The goal is to define and understand the distribution of sands and shales on the basis of seismic reflection data. The modeling and inversion are supported by the good quality of seismic data. This study underpins the benefits of seismically constrained reservoir modeling. The use of probabilistic inversion to map geological features is a new insight in the applicability of this methodology.

Introduction

The study field is located in the Carnarvon Basin offshore western Australia. The field was appraised with one well, which has added incremental volumes to existing nearby discoveries. Seismically constrained reservoir-­model building creates models that are constrained by, and matched to, geological concepts and seismic amplitudes and travel times. The complete paper shows an approach using 3D probabilistic seismic inversion to predict the lateral variation in NTG over a proven discovery. This, in turn, can be used to update the static-model properties, improving on the first-pass static-model build. Additionally, the inversion will aid in the understanding of some poorly understood seismic expressions, especially in the south of the field. In this area, the authors noticed dim amplitudes on the amplitude maps extracted from the seismic data, where the static model predicts the presence of the reservoir. Field The field is located in the Carnarvon Basin. The discovery was appraised by one well, which penetrated a thin sand layer of interdistributary bay reservoir facies (referred to as Sand 1) and a thicker distributary channel facies (referred to as Sand 2). The overburden comprises basinal shales and marls.