Validation of Gravity-dominated Relative Permeability and Residual Oil Saturation in a Giant Oil Reservoir

Gravity drainage is normally characterized as a slow but efficient process, leading to a low remaining oil saturation. If the reservoir has a large oil column and a high vertical permeability, then efficient recovery may be achieved through the gravity drainage process that accompanies a stable gas cap expansion. An extensive experimental program was conducted to characterize the flow properties of the gravity drainage process where oil is displaced by gas in the presence of an initial water saturation. The experiments described here were designed to give endpoint saturations, oil relative permeabilities, and gas relative permeabilities for the gas-displacing-oil gravity drainage situation. No single test provides all of these parameters required for performance prediction. Long core gravity drainage tests, as well as porous plate and centrifuge tests, were performed at simulated reservoir conditions. The long core drainage tests were conducted in a vertical coreflood apparatus in which in-situ oil and water distributions were monitored regularly using both x-ray and microwave scanning systems. The experimental results support the following conclusions with regard to high permeability, unconsolidated sands: • Residual oil saturation to the gravity drainage process (S org) is low, 3-10% and is somewhat insensitive to rock properties. This level of saturation is achieved through film drainage and may require considerable time and suitable conditions (oil column height and fluid density differences). • Sorg is not sensitive to fluid properties such as viscosity, interfacial tensions, and spreading coefficient for the limited systems studied. • Sorg does not depend on initial water saturation within a reasonable range. • kro and krg depend on rock properties. • Conventional gas flood tests give higher Sorg (average 30%), even at high volume (1000 PV) and/or low rate gas injection, and do not represent the gravity drainage process. These laboratory findings were validated by a subsequent coring operation, using a low invasion water-based mud, in the secondary gas cap of the Ubit field, offshore Nigeria, that had been in production for twenty-five years. The residual oil saturations to gravity drainage found in the secondary gas cap agreed well with laboratory results. However, the observed S org was not achieved in the simulation of the field history when detailed geological description and the lab measured k ro was used. Adjustment of kro by an order of magnitude near the Sorg was necessary to match the Sorg distribution observed in the secondary gas cap. It was found that the low kro close to Sorg was an artifact due to capillary end effects, not fully accounted for in initial modeling. Subsequent lab tests were designed to generate appropriate data for reservoir management. Adjustment of kro was justified when data were reanalyzed, taking P c into consideration, and bringing laboratory measurements, field observations, and reservoir simulation into complete agreement.