Three-phase flow configurations occur in many situations in petroleum engineering, gravity assisted gas displacement, tertiary waterflood, water alternating gas process (W.A.G.). Therefore residual saturations (oil and gas) knowledge during three-phase flow is a crucial point for reservoir engineers. In this paper we present experimental results dealing with the influence of wettability on two and three-phase flow in porous media in short (0.25m) and long (1m) cores. Forced displacement of gas by water and oil have been performed on the short cores while gas/oil gravity drainage in presence of irreducible water (Swi) followed by a tertiary waterflood have been performed on the long cores. For all the experiments the saturation profiles are measured using a dual-energy gamma-ray attenuation technique. Originality of the experiments lies on the fact that gas/oil gravity drainage and tertiary waterflood are performed on the same core during the same experiment. Two phase flow is obtained at the bottom of the core (in the capillary head region) while three-phase flow is observed in the upper part of the core. Local measurement of saturation profiles show that residual oil saturation at the end of gravity drainage depends on wettability. However we do not observe a wettability effect on three-phase residual gas saturation. Behaviour of three-phase residual oil saturation is much more complicated because its value and saturation profile depends strongly on wettability. Introduction Recovery techniques involving gas injection, water-alternating-gas (W.A.G.) process or gravity drainage in oil reservoirs in presence of connate water are widely used to improve oil recovery. Development of these techniques, among others, illustrates the growing interest devoted three-phase studies. In this paper we focus our attention on the effect of wettability and flow type (two- and three-phase flow) on gas and oil residual saturations. Literature results dealing with that topic can be can be summarized, in a non exhaustive way as follows. Kortekaas et al.1 showed during a waterflood following pressure depletion on water-wet core, residual saturation in three-phase configuration (Sor3?) was lower than residual oil saturation obtained by waterflooding (Sorw). Ma et al.2 confirmed this behaviour for W.A.G. experiments. In the same way, but using different wettability cores Skauge et al.3 showed that residual oil saturation in three-phase flow condition (Sor3?) is significantly lower than residual oil obtained after water (Sorw) or gas (Sorg) flooding. Moreover, for water-wet system they compared the residual saturations with the trapped gas saturation and found that Sorw= Sor3?+Sgt4. Nevertheless data are in contradiction with the results from Fayers5, who provided empirical relationships dealing with Sor3? for different wettability, Sor3?=Sorw-0.5.Sgt for water-wet core and Sor3?=Sorw for intermediate-wettability which is in good agreement with the results of Kyte et al.6 and Holmgren et al.7. Dealing with three-phase residual gas saturation (Sgr3?) different results are published in the literature. Kralik et al.8 and Skauge et al.9 showed experimentally that three-phase residual gas saturation is lower than two-phase residual gas saturation (Sgr3?< Sgr2?). On the other hand Maloney et al.10 and Jerauld11, presenting different imbibition experiments for two and three-phase flow showed that Sgr3?= Sgr2?. Our experimental study deals with the influence of wettability on two and three-phase flow on short core (0.25m) and long (1m) cores of the same origin. Short cores were used for forced displacement of gas by water and oil while long cores were used to perform gas-oil gravity drainage in presence of irreducible water (Swi) followed by tertiary waterflood. Final and transient saturation profiles are measured using dual energy attention gamma ray attenuation technique. We focused our attention on residual (gas and oil) saturations deduced from the final profiles.

When an active aquifer encroaches into a gas bearing reservoir or when an oil rim sweeps gas during late depletion of the gas cap, gas displacement by liquid is important for estimating the gas recovery. In the water displacing gas condition, the viscosity ratio is extremely favorable, resulting in a sharp waterfront in the reservoir matrix: it results that changing the relative permeability Kr shape has negligible effect, while endpoints water relative permeability Krw Max and residual gas saturation Sgr are much more important to understand gas flow performance for estimation of gas recovery with active aquifer or productivity decline after water breakthrough. Three main methods are used to determine water/gas relative permeability curves: imbibition unsteady-state, imbibition steady-state or indirect approaches such as co-current spontaneous imbibition if transient data are available. One of the other popular indirect methods is called Brooks-Corey approach: by measuring the drainage Pc curve using centrifuge or porous plate methods, it is possible to calculate a pore size distribution index c. This coefficient is used in a Brooks-Corey model to determine the drainage Kr curve. It is also required to measure and determine the relationship between the residual gas saturation Sgr and the initial gas saturation Sgi relationship. Finally, it is accepted that there is no hysteresis on the water relative permeability Krw curve, as water is always the wetting phase in the gas/water couple. As non-wetting phase, gas exhibits strong hysteresis between drainage and imbibition curves: it is therefore necessary to apply a correction on the drainage Krg curve to build the imbibition one using correcting models. The aim of this paper is to compare gas/water relative permeability of clastic rocks using direct waterflooding information and indirect approach using Brooks-Corey model. It is shown that using the indirect approach leads to results like those experimentally obtained. Also, additional numerical simulations are proposed to discuss the relevance of measuring the entire water-gas imbibition relative permeability curve using the steady-state approach.

Relative permeability and capillary pressure are essential parameters for understanding multiphase flow in porous media and scenarios of production in oil or gas reservoirs. There are several experimental methods for determining the relative permeability curves: unsteady-state (USS), steady-state (SS), and semi-dynamic (SD) methods. Each method has advantages and weaknesses. Although the USS approach leads to fast data results, the interpretation neglects the capillary pressure effects and provides a limited amount of data points obtained after breakthrough. The SS method is time consuming but enables covering a wider range of saturation with data points if the test is well designed. The SD method may be more time consuming than the SS method but provides both relative permeability to the injected phase and capillary pressure. The relative permeability to the produced phase is then determined by numerical means. The main objective of this study was to compare the water-oil relative permeability curves obtained from the steady-state and semi-dynamic methods performed at reservoir conditions with live fluids. Carbonate core plugs of same rock type and same properties were selected for this experimental program. The samples were brought to the same irreducible water saturation at a constant brine-oil capillary pressure using a centrifuge before being dynamically aged with live oil. In addition to monitoring the average saturation using material balance (MB), a linear X-ray scanner was used for in-situ saturation monitoring (ISSM) along the core samples. The oil relative permeability from the SD method was simulated with fixed water relative permeability and capillary pressure by history-matching the oil production and the differential pressure signal. Two additional centrifuge tests on twin plug were performed in order to measure imbibition capillary pressure and oil relative permeability at pseudo-reservoir conditions. This comparative study shows that the SD method provides similar capillary pressure and oil relative permeability curves to those obtained by centrifuge methods. Even if all Kr curves are in an acceptable envelop, some differences are observed between SD and SS Kr curves: several investigative leads are given to explain this discrepancy. It is also shown that a better saturation method needs to be implemented, especially when dealing with heterogeneous rocks. While a more robust ISSM method is being tested at TOTAL, the results presented in this paper are very encouraging.

Relative permeability and capillary pressure are important parameters in reservoir simulations because it helps in understanding and anticipating oil and/or gas production scenarios over the years. They are both obtained in a laboratory after establishing the required initial conditions. As a matter of fact, before measuring imbibition relative permeability and capillary pressure, it is recommended to set initial rock reservoir conditions by establishing appropriate initial water saturation (Swi) and by aging the core to restore the reservoir wettability. There are several conventional techniques to establish Swi. Viscous flooding is a fast technique, but it may create a non-uniform saturation profile and, in some cases, be inefficient in reaching low Swi targets. Centrifugation is a capillary-driven technique that is also very fast; however, the possibility of not desaturating the outlet face is a significant constraint. In both cases, reversing flow direction is generally performed to flatten the saturation profile; however, this phenomenon is poorly controlled. The application of capillary pressure by porous plate allows targeting a specific value of Swi and generates a uniform saturation profile; however, it is a very time-consuming method. In this paper, we present the Hybrid Drainage Technique (HDT), which couples viscous flooding and porous plate approaches, significantly reducing the experimental duration when setting Swi. Another advantage of the method is the possibility of setting a uniform saturation profile at the targeted Swi. A specific core holder, adapted to nuclear magnetic resonance (NMR) imaging and capable of performing both viscous flooding and porous plate testing without unloading the rock, was designed. Using this core holder enables performing aging and imbibition coreflood testing with no further manipulation of the core sample. Monitoring saturation profiles was made possible by using an NMR imaging setup. The method has been tested and validated on two outcrop samples from Bentheimer (sandstone) and Richemont (limestone), drastically reducing the experimental time of the primary drainage step in comparison to classical porous plate drainage but also leading to uniform water saturation profiles. The experiment duration is reduced, and it enables the realization of coreflooding; therefore, this technique may be used for larger samples classically used in relative permeability experiments. This approach is preferred as it provides faster and more reliable measurements of saturation.

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