Delineating thin sand connectivity in a complex fluvial system in Mangala field, India, using high resolution seismic data

The Mangala field is located in the northern part of the onshore Barmer Basin in India. The primary reservoir in the field is the Fatehgarh Formation, deposited during the rifting phase that created the Barmer Basin during the Late Cretaceous to Early Paleocene period. The majority of reservoired oil is con¬tained within the Upper FM1 member of the Fatehgarh Formation, composed of single storey and multi-storey stacked, meandering channel sands. The average gross thickness of FM1 is 80 m, and individual sands vary in thickness from 3 to 7 m, with net-to-gross ratio ranging from 18% to 78% due to inherent heterogeneity within FM1 as evident from core data. For such a heterogeneous fluvial system, correlation of fluvial channel sands and flood plain shales poses a major challenge for reservoir characterization when based on well data alone. Detecting or mapping the lateral continuity of these thin fluvial channel sands is difficult because they are below seismic resolution in conventional seismic data. We applied sparse-layer reflectivity inversion (Zhang and Castagna, 2011) to the 3D stack PSTM data, which resulted in a data¬set with improved detectability and resolution. The 7-50 Hz bandwidth of the input seismic data increased to 7-100 Hz through the inversion process. Results were validated using well log and production data. The new data contributed to greater understanding of the lateral connectivity of the FM1 fluvial channel sands, and enabled geobody extraction for reservoir static modelling.