fax 01-972-952-9435. AbstractIn principle, miscible gas injection can displace nearly all of the oil from the portions of a reservoir swept by gas. However, reservoir heterogeneity, low gas density and high gas mobility reduce sweep efficiency and drastically decrease recovery. Fortunately, the use of foam can reduce gas mobility and the effect of heterogeneity and therefore increase sweep efficiency. Based on the work of Shan and Rossen, an optimal design strategy is proposed here for surfactant-alternating-gas (SAG) foam processes and tested in a homogeneous reservoir and in two layered rectangular reservoirs. Fractional-flow theory, Stone's and Jenkins' model for gravity segregation, and an idealized model developed by Shan and Rossen are used design the process and interpret the results.In the homogeneous reservoir, fixed-pressure SAG processes result in better sweep efficiency than fixed-rate SAG processes. A one-cycle SAG process, where one big slug of surfactant is followed by one big slug of gas, gives better sweep than multiple-cycle SAG processes; sweep efficiency is higher and the process proceeds faster. Adsorption can be dealt with by adjusting the size of the first surfactant slug. The optimal SAG process gives much better sweep efficiency than a WAG process without foam. Simulations reveal factors not accounted for in Shan and Rossen's idealized model for a single-cycle SAG process; nonetheless the model accurately predicts the rate of advance of the foam front at the top of the reservoir and qualitatively predicts the shape of the foam front. A ten-cycle SAG process performs somewhat better than predicted by Stone's model for continuous injection.In heterogeneous reservoirs, a maximum-fixed-pressure SAG process also gives best results. The surfactant slug sized for a homogeneous reservoir is much too large in this case, however, and much of the surfactant wasted. Again, a onecycle process SAG performs better than multiple, smaller cycles, but sweep is not as good as in a homogeneous reservoir. A high-permeability layer at the top of the reservoir leads to better sweep efficiency at gas breakthrough than when the reservoir has a low-permeability layer at the top. A lowpermeability layer at the top allows early gas breakthrough once gas in high-permeability layers below it reaches the edge of the surfactant bank above. Compared to WAG processes, the optimal SAG process shows much better sweep efficiency.
Miscible gas injection can displace nearly all of the oil from the portions of the reservoir swept by gas. However, reservoir heterogeneity, low gas density and high gas mobility reduce sweep efficiency and drastically reduce recovery. Foam can reduce gas mobility and the effects of heterogeneity and gravity, and therefore increase sweep efficiency. Here we extend a previous study (SPE 110408) on optimal design strategy for surfactant-alternating-gas (SAG) foam processes in layered reservoirs. We develop design criteria for the optimal foam strength and slug size for a given permeability contrast between layers. We reach the following conclusions: Trends of foam strength with permeability or surfactant formulation, as measured in conventional coreflood tests at fixed injected water fraction, may not correspond to behavior in a SAG process in the field. In the cases examined, foam strength in a SAG process is much less sensitive to permeability and foam parameters than is foam strength at fixed injected water fraction. Placement of surfactant into low-permeability layers is a key challenge of SAG processes in heterogeneous reservoirs. Gas breakthrough occurs via low-permeability layers that did not receive enough surfactant. For that reason, unlike gas injection without foam, having a low-permeability layer at the top of the formation is a disadvantage because it is difficult to place foam there. Using multiple surfactant and gas slugs allows foam to redistribute surfactant in later slugs. However, this strategy suffers from poor injectivity during liquid injection, which slows the process and promotes gravity segregation. Injection of both gas and surfactant slugs at the maximum allowed injection pressure, rather than at fixed rate, gives best results. Injecting gas from only the bottom of the well offers no significant advantages in the best case, where high-permeability layers lie at top and bottom of the reservoir, and performs significantly worse if low-permeability layers lie at the top (where lack of surfactant leads to override) and bottom (where low permeability restricts injectivity) of the reservoir. A surfactant slug sized for a homogeneous reservoir is too large for a heterogeneous reservoir, because little surfactant enters lower-permeability layers: much of the injected surfactant goes to waste. A surfactant slug sized to sweep high-permeability layers and a portion of low-permeability layers performs nearly as well as one sized to sweep the entire reservoir. Introduction Gases, like steam, carbon dioxide, nitrogen or reinjected field gas, have widely been used in the industry as a sweeping agent for the displacement of oil.1,2 Unfortunately, the gas is hampered in its ability to sweep due to density differences to oil and water, high gas mobility and reservoir heterogeneity. Density difference causes the gas to override the oil, leaving significant portions of the reservoir unswept. High mobility of the gas phase as compared to mobilities of water or oil causes viscous instability that significantly worsens the override and, in combination with reservoir heterogeneities, forms high-mobility channels, leading to early gas breakthrough.3 The use of foams can significantly counter these disadvantages by lowering the gas mobility and reducing the effect of layering, therefore avoiding override and increasing sweep efficiency.4,5
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