Water alternate gas (WAG) injection technology is a method which may improve oil recovery efficiency by combining effects from two traditional technologies -water and gas flooding. Both microscopic oil displacement and sweep efficiency can be improved by WAG implementation. This paper describes a method of designing an effective waterlgas flooding in stratified reservoirs.The analytical approach taking into account effects of three phase flow, gravity and viscous forces in anisotropic media, allows the determination of optimum parameters of waterlgas injection. A three-phase extended black oil simulator with relative permeability and capillary pressure hysteresis, was used to validate the optimum WAG injection parameters obtained by the analytical method. In this work, the efficiency of different injection schemes was compared. Simulation results which demonstrate the influence of WAG injection parameters, as water-gas ratio, injection rates and cycle periods, on the recovery process, are discussed.

Summary. The Frigg field is a major North Sea gas reservoir composed of turbiditic sediments. This paper describes the detailed geologic modeling and three-dimensional (3D) reservoir simulation of the field.A geologic model containing sand lobes and intercalating shales has been defined from seismic and well data. Special attention was paid to the realistic modeling of the shales. The more continuous (deterministic) shales between the turbiditic sand lobes of the reservoir were directly implemented in the model as horizontal flow barriers. The more discontinuous shales within the lobes were modeled with the method of Haldorsen and Lake and Begg and King. This method uses statistical geologic information and well data to calculate effective vertical permeability. The simulator was built as a 3D, two-phase (gas/water) model. Field data for 8 years of production were matched. A good match of both fluid levels and pressures was obtained. This reservoir study demonstrates that the impact of the shales on the reservoir behavior in general and the movement of the gas/liquid contact (GLC) in particular is essential. Introduction The Frigg field straddles the Norway/U.K. boundary in the northern North Sea (Figs. 1 and 2). Discovered in 1971 and brought on stream in 1977, the field is unitized and jointly owned by the Frig-U.K. Assn. (Elf U.K. and Total Oil Marine and the Frigg-Norwegian Assn. [Elf-Aquitaine Norge (operator), Norsk Hydro, Total Oil Marine Norsk, and Statoil]. Top reservoir is at about 1790 m [5.875 ft] mean sea level (MSL). The gas has a maximum column of 160 m [525 ft] overlying an ∼ 2- to 10-m [∼ 6.6- to 32.8-ft] -thick oil rim. Gas initially in place was illustrated at 265 × 10(9) std m3 [9,360 × 10(9)scf] before unitization in 1976. Initial model studies assumed a homogeneous sand reservoir with local occurrences of shale and limestone (Fig. 3) A tuff and shale layer separating the Frigg from the Cod formation, well below the GLC, was considered the only barrier for flow in the reservoir model. That this barrier had to contain permeability windows could be deduced from the active aquifer response during the production phase.GLC movements in the first observation well, Well 25/1-A22, did not give rise initially to drastic changes in the basic concept of the reservoir. However, results of the second observation well, Well 10/1-A25, which was deepened in Aug. 1984. demonstrated an ∼40-m [∼130-ft] -higher rise in GLC than observed in Well 25/1-A22. Furthermore, repeat formation tester (RFT) data of this well showed a pressure step over shales above the assumed tuff and shale barrier and no pressure step across the "tuff zone" itself (Fig. 4). This indicated a more complex, dynamic behavior of the reservoir than originally anticipated. An intensive appraisal involving the drilling of three remote appraisal wells (Wells 1011–5, 25/1–7, and 25/1–8) and the deepening of two platform wells was consequently undertaken. The planning of a 3D seismic survey was also initiated. The presence of shales in the Frigg formation that varied in lateral extent, forming horizontal flow barriers, appeared to be the main cause for the complex behavior of the reservoir. At the end of 1984, Norsk Hydro initiated the independent study described here to model and to simulate the effect of these shales in the Frigg reservoir. This 3D simulation study was concluded in Sept. 1985 and incorporates the results of all recently drilled remote appraisals and the deepening of Well 25/1A 14. A combination of direct and statistical methods was selected for the modeling to reflect the impact of the shales. Note that the geologic complexity combined with relatively sparse well spacing gives room for many uncertainties. For this reason, the interpretation presented here should also be seen as Norsk Hydro's own. among others. Note also that the field operator and the other Frigg partners are still conducting substantial studies. Theoretical Concept The basic philosophy behind the theoretical concept of this study is defined as follows. The complete incorporation of the effects of contrasting lithologic units is essential for reservoir simulation. Consequently, realistic estimations of occurrence and geometry of these units have to be made when data are not sufficient to define all units separately. Application of this philosophy will improve consistent incorporation of reservoir heterogeneity, which is often neglected when only the correlatable events/units are represented in the model. It will consequently yield a more realistic production forecast on a field scale. The situation in the Frigg field was typical for the application of the stated philosophy because insufficient data were available to define all contrasting lithologic units (sands and shales) separately at the time the study was initiated.A combination of direct and statistical methods has been selected for the modeling. The more continuous shales at the boundaries of the reservoir units (lobes) were modeled directly as vertical transmissibility barriers. They are classified here as deterministion shales. Their mapping, involved much postulation, however, because of a lack of data. The less continuous and uncorrelatable shales within the reservoir units (lobes) were handled statistically and are classified as stochastic shales (Fig. 5). Concepts based on the ideas of Haldorsen and Laker and Begg and King' were used for the statistical handling of the stochastic shales. In fact, a modified version of the Begg-King streamline method was applied. SPEFE P. 493^

Microscopic oil displacement and sweep efficiency of waterflooding and continuous gas injection can be improved by water alternated gas (WAG) injection. Reservoir and fluid properties are determining factors in screening WAG injection strategies. Evaluation of miscibility condition is an important step in the process design. Different correlations used for miscibility evaluation are compared on the Brent reservoir example. The effect of injection parameters on injectivity and recovery in the layers of a stratified reservoir is shown through the simulation results. Methods improving WAG efficiency like non-stationary injection are discussed. Main parameters of cyclic injection with variation of flow directions are considered in relation with non-stationary WAG. Numerical modelling with respect to three phase effects showed the advantages of non-stationary WAG in a stratified reservoir.

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Water alternate gas (WAG) injection technology is a method which may improve oil recovery efficiency by combining effects from two traditional technologieswater and gas flooding. Both microscopic oil displacement and sweep efficiency can be improved by WAG implementation. This paper describes a method of designing an effective waterlgas flooding in stratified reservoirs.The analytical approach taking into account effects of three phase flow, gravity and viscous forces in anisotropic media, allows the determination of optimum parameters of waterlgas injection. A three-phase extended black oil simulator with relative permeability and capillary pressure hysteresis, was used to validate the optimum WAG injection parameters obtained by the analytical method. In this work, the efficiency of different injection schemes was compared. Simulation results which demonstrate the influence of WAG injection parameters, as water-gas ratio, injection rates and cycle periods, on the recovery process, are discussed.