Water-alternating-gas (WAG) injection, both miscible and immiscible, is a widely used enhanced oil recovery method with over 80 field cases. Despite its prevalence, the numerical modeling of the physical processes involved remains poorly understood, and existing models often lack predictability. Part of the complexity stems from the component exchange between gas and oil and the hysteretic relative permeability effects. Thus, improving the reliability of numerical models requires the calibration of the equation of state (EOS) against phase behavior data from swelling/extraction and slim-tube tests, and the calibration of the three-phase relative permeability model against WAG coreflood experiments. This paper presents the results and interpretation of a complete set of two-phase and thee-phase displacement experiments on mixed-wet carbonate rocks. The three-phase WAG experiments were conducted on the same composite core at near-miscible reservoir condition; experiments differ in the injection order and length of their injection cycles. First, the two-phase water/oil and gas/oil displacement experiments and first cycles of WAG were used to estimate the two-phase relative permeabilities. Then, a synchronized history-matching procedure over the full set of WAG experiments and cycles was carried out to tune Larsen ans Skauge WAG hysteresis model—namely the Land gas traping parameter, the gas reduction exponent, the residual oil reduction factor and three-phase water relative permeability. The second part of this paper deals with the multiphase upscaling of microscopic displacement properties from plug to coarse grid reservoir scale. The two-phase relative permeability curves and three-phase WAG parameters were upscaled using a sector model to preserve the displacement process and reservoir performance. The result of the coreflood calibration indicate that the two-phase displacement and first cycles of WAG yield a consistent set of two-phase relative permeabilities. Including the full set of WAG experiments allowed a robust calibration of the hysteresis model.
In offshore wells, the pressure fluctuations caused by the ocean tide can be used to inform on the mechanical properties of the reservoir, in particular its compressibility. Such phenomena is not associated with water movement, except at the microscopic level. In heterogeneous reservoirs, these pressure oscillations can cause macroscopic movement of water, which can serve as the basis for the estimation of reservoir flow properties. The purpose of this study is to develop a set of analytical solutions that describe the pressure variations in a heterogeneous reservoir, in terms of amplitude ratio and phase shift. The solutions were developed using the coupled fluid flow-geomechanics equation for a reservoir under uniaxial tidal loading. This study looks in particular at three geometries of inhomogeous diffusion—radial composite, linear composite and composite slab.
Summary Offshore reservoirs are subjected to pressure loading from the ocean tide. The resulting pressure fluctuation, notably its amplitude and phase, provides valuable information regarding the formation compressibility and heterogeneity. The purpose of the present study is twofold: First, to propose a method for calculating tidal efficiency from harmonic analysis of regional tide stations and detrended bottomhole pressure (BHP), and second, to compare the compressibility from tidal analysis with that obtained from rock-mechanics measurements and material balance. This case study is on a fractured oil field for which matrix laboratory measurements alone cannot capture the large-scale formation compressibility that is driven by the fracture distribution. This paper will show how, in the absence of seabed-pressure measurements, a synthetic diurnal tide can be simulated by interpolating the harmonic constituents of neighboring tide stations. The validity of this method was confirmed on two offshore fields. A new procedure that combines a Savitzky and Golay (1964) (SG) filter and cubic splines gave satisfactory results to filter out the tidal signal residual from the reservoir-transient response for both buildup and interference tests. In addition, this paper found that wells in fractured areas of the field have higher rock compressibility and exhibit a higher tidal efficiency. The same effect is observed in flank wells with higher water saturation. Conversely, the tidal efficiency is dramatically reduced in wells experiencing gas breakthrough.
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