Abstract
Abstract
During waterfloods of a total of six outcrop chalk core plug samples prepared at various wettabilities, simultaneous local pressures and in situ fluid saturation from Magnetic Resonance Imaging (MRI) intensities were measured. Complementary use of high spatial resolution fluid saturation imaging and phase pressure measurements allowed calculations of the relative permeability to water and the dynamic capillary pressure curves for the imbibition process. One objective was to validate the theory for relative permeability calculations based on data from the fluid phase pressures measured separately using semi-permeable discs and local in situ fluid saturation measurements. A second objective was to identify fluid saturation changes due to spontaneous imbibition and viscous displacement, respectively, to determine the local recovery mechanism and allowing local recovery factors and in situ Amott-Harvey indices to be measured.
The analysis of the experimental data from three of the core samples shows that the presented theory only applies for the saturation interval when the pressures are measured in the same phase. A new and improved experimental setup is therefore introduced for the remaining three cores in order to measure each of the dynamic phase pressure gradients separately using semi-permeable discs located at fixed pressure ports. The obtained data contributes to improved description and understanding of multi-phase fluid flow in porous media, including in situ measurements of relative permeabilities, capillary pressure curves, wettability distribution and local oil recovery mechanisms.
Introduction
The dominant recovery mechanism in most chalk reservoirs is spontaneous imbibition. This is due to narrow pore throats, more or less water-wet conditions and low permeability (Baldwin, B. A., 2002, Viksund, B. G., 1996). In this study, simultaneous fluid saturation distribution and separate fluid phase pressures are measured in situ in order toincrease knowledge of dynamic phase behavior in an immiscible displacement,identify the contributions from spontaneous and viscous displacement andto calculate in situ Amott-Harvey indices, capillary pressure and relative permeabilities.
Knowledge of the relative permeabilities in multiphase flow is of vital importance to the oil industry in order to describe immiscible fluid mechanisms and to improve oil recovery during production. Several methods for calculating relative permeabilities from experimental data have been introduced, but a satisfactory method is still not developed. Most methods (Chardaire, C, 1989, Heaviside, J., 1983, Islam, M.R., 1986, Johnson, E.F., 1959, Kerig, P.D., 1986) utilize production data and total differential pressure over a core sample as measures of average saturation and pressure gradients, but this is a coarse approximation that neglects capillary pressure, wetting phase end effects and the rapid changes in the pressure around the displacement front. By measuring saturations and phase pressure gradients in situ as functions of time and position, end effects are avoided, and relative permeabilities are calculated by use of an explicit method.
The main objective with the experiments was to determine the dynamic properties of the local pressure gradient and relate this to the fluid saturation distribution to improve the understanding of oil recovery at various wettability conditions. Part of the objective was to identify the contribution from spontaneous and viscous displacement to the oil recovery at different wettabilities in chalk and to calculate in situ Amott-Harvey wettability indices, relative permeabilities and capillary pressure for the imbibition process.