Detailed Special Core Analysis Program Key to Aggressive Field Development Planning - Rajasthan, India

Abstract

Abstract In 2004, several large oil discoveries were made in high-permeability multi-layered Fatehgarh sandstone reservoirs in Rajasthan, India. The fields contain light but viscous paraffinic oils with wax appearance temperatures very close to reservoir temperature. As these were the first Fatehgarh discoveries in the region, no special core analysis (SCAL) information existed for the unusual oil-bearing rocks. A fast-track comprehensive SCAL program to determine wettability, relative permeabilities, capillary pressures, and initial and residual oil saturation was implemented within weeks of the first discovery. This data was critical to the design of waterflood patterns and facilities for these intermediate- to weakly oil-wet reservoirs. The value of a comprehensive up-front SCAL program is clearly demonstrated. Although acquisition of the SCAL data cost ~US$5million, it played a crucial role in justifying a change in field development plans involving closer well spacing, higher injection volumes and larger surface facilities. A statistically significant number of SCAL measurements were made on representative Fatehgarh samples. In general, reservoir rocks have the low initial water saturations (Swi~5%), long oil drainage tails and low residual oil saturations (Sorw<15%) typical of intermediate- to weakly oil-wet reservoirs (Amott-Harvey wettability index -0.33 ± 0.27). Early quantification of these characteristics by facies and their implementation into stochastic static and dynamic reservoir models were critical to development of a technically sound field development plan. The 2004 discoveries in an industrially less-developed part of India are projected to be on production by 2009. Large fast-tracked investments in infrastructure and oilfield development were significantly shaped by the early acquisition of a comprehensive SCAL dataset. The data helped to optimize the different waterflood designs chosen for the different fields (pattern floods vs. edge line drives, well spacings, vertical vs. horizontal wells, etc.) and to quantify the expected oil and water production profiles from these very high-quality intermediate- to weakly oil-wet reservoirs. Background The Mangala field was discovered in January 2004 (Reference 1) by the drilling of Mangala-1, which encountered a gross oil column of ~150m in the late-Palaeocene Fatehgarh sandstones of the rifted Tertiary Barmer Basin (Figure 1) of northwestern India. The Mangala oil is a paraffinic sweet crude averaging 27ºAPI gravity with viscosity of ~13cp. It also contains a thin biodegraded oil zone just above the oil-water contact (OWC) where the crude quality is lower at ~22ºAPI and ~50cp. Figure 1: Location of the Barmer Basin, India. Well test rates of more than 5,000 bopd from limited intervals with less than 200psi of drawdown confirmed the very high quality nature of the reservoir that was inferred from logs and cuttings. To date, Cairn has made twenty oil and gas discoveries in the basin, including the large Bhagyam and Aishwariya oilfields, with a total estimated 2P STOIIP of 3.6 billion BOE. A critical part of the ongoing field development planning was the acquisition of a comprehensive special core analyses (SCAL) data-set.