Success of SAG Foam Processes in Heterogeneous Reservoirs

Abstract

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.

Understanding aqueous foam with novel CO2-soluble surfactants for controlling CO2 vertical sweep in sandstone reservoirs

“…In our current work, the surfactant concentration and dry-out effects are considered and some typical values are chosen, as shown in Table 1. Here, we chose 100 for fmmob, which is less than these employed by earlier researchers, such as 1000 (Rossen et al 2006), 3000 (Rossen and Shen 2007;Jamshidnezhad et al 2008a), or 5000 (Cheng et al 2000;Rossen and Renkema 2007;Kloet et al 2009), because we believe too strong foam used previously masked some details in the foam process, which is crucial for the novel foam. Meanwhile, it is also much less than the result of coreflood matching (Ma et al 2013) because the foam in 3D is much weaker than in 1D, which has been demonstrated by Li et al (2006).…”

“…Meanwhile, it is also much less than the result of coreflood matching (Ma et al 2013) because the foam in 3D is much weaker than in 1D, which has been demonstrated by Li et al (2006). In simulations, we made fmsurf equal to the injected surfactant concentration (3.34 9 10 -5 , molar fraction) (Hanssen et al 1994;Rossen and Renkema 2007). A linear dependence between foam strength and surfactant concentration was chosen (epsurf = 1) (Rossen and Renkema 2007).…”

“…In simulations, we made fmsurf equal to the injected surfactant concentration (3.34 9 10 -5 , molar fraction) (Hanssen et al 1994;Rossen and Renkema 2007). A linear dependence between foam strength and surfactant concentration was chosen (epsurf = 1) (Rossen and Renkema 2007). Here, we set the fmdry as 0.15, which is more than irreducible water saturation.…”

“…However, this process frequently experiences viscous fingering, gravity override, and gas channeling because of reservoir heterogeneity as well as low density and viscosity of CO 2 , which results in a decreased oil recovery (Rossen and Renkema 2007). Fortunately, the use of foam can reduce gas mobility and effects of heterogeneity and therefore increase sweep efficiency (Rossen 1995).…”

“…Shan and Rossen (2004) proposed an optimal injection strategy for overcoming gravity override with foam in a homogeneous reservoir. Kloet et al (2009) extended the study of Rossen and Renkema (2007) and developed design criteria for the optimal foam strength and slug size for a given permeability contrast between layers. SAG injection also minimizes contact between water and gas in surface facilities and piping (Heller 1994).…”