Abstract

Staatsolie conducted several screening studies in the past decade to explore the potential of enhanced oil recovery (EOR) for its heavy oil fields in Suriname. The latest screening study was performed in 2011. It indicated that combined gas and water injection could be a highly efficient method to extend the life of the fields beyond primary recovery. To validate this conclusion further, an area of the Tambaredjo heavy oil field was selected for a feasibility study comprising laboratory tests and field scale reservoir simulation studies. This paper presents a series of core-flood tests done to evaluate the potential of several CO2 and N2 injection schemes and to gather data for the further numerical simulations. CO2, N2, and brine were injected either (1) on continuous mode or (2) in a water-alternating-gas (WAG) mode into Bentheimer sandstone cores previously saturated with Tambaredjo heavy oil, having a viscosity in the range of 650 to 1,100 cP and a density ranging from 16 to 17 °API. The injection strategies tested resulted in substantial incremental oil recovery (relative to OIIP), but values hereof varied from strategy to strategy. The core-flood test with continuous CO2 injection following extensive water flooding resulted in an incremental recovery of 31.1% over tertiary CO2 flooding stage. Continuous N2 and CO2 injection in a secondary mode resulted in incremental recoveries of respectively 14.8% and 24.5% over secondary drainage stage. Subsequent long water slugs resulted in both cases in further increase of the recovery by 48.1% and 29.2%. N2 and CO2 WAG with WAG ratios and slug sizes chosen based on optimized reservoir simulations resulted in similar recovery factors. Overall recoveries for five schemes used in core-floods were in the range of 49.6 to 65.9%. The paper discusses the mechanism responsible for the oil displacement for each injection strategy and presents how the core-flood tests can be used to model gas injection for a sector of the heavy oil reservoirs of Suriname.

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