Fractional Flow Theory of Foam Displacements With Oil
- Elham Ashoori (Delft U. of Technology) | Thom van der Heijden (Delft U. of Technology) | William Richard Rossen (Delft U. of Technology)
- Document ID
- Society of Petroleum Engineers
- SPE International Symposium on Oilfield Chemistry, 20-22 April, The Woodlands. Texas
- Publication Date
- Document Type
- Conference Paper
- 2009. Society of Petroleum Engineers
- 5.4 Enhanced Recovery, 4.1.5 Processing Equipment, 4.2.3 Materials and Corrosion, 3.2.4 Acidising, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.3.2 Multiphase Flow, 5.2.1 Phase Behavior and PVT Measurements, 5.4.9 Miscible Methods, 4.1.2 Separation and Treating, 5.4.2 Gas Injection Methods, 1.2.3 Rock properties, 5.3.1 Flow in Porous Media, 5.4.1 Waterflooding, 4.3.4 Scale, 1.8 Formation Damage, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.3.4 Reduction of Residual Oil Saturation, 5.7.2 Recovery Factors
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Fractional-flow theory provides key insights into complex foam EOR displacements and acts as a benchmark for foam simulators. In some cases with mobile oil present the process can be represented as a two-phase displacement. We examine three such cases.
A first-contact-miscible gas flood with foam injection includes a chemical shock defining the surfactant front and a miscible shock defining the gas front. The optimal water fraction for the foam, that gives the fastest oil recovery, maintains the gas front slightly ahead of the foam (surfactant) front.
The success of a foam process with first-contact-miscible CO2 and surfactant dissolved in the (supercritical) CO2 depends on the strength of foam at very low water fractional flow, as for a surfactant-alternating-gas (SAG) process with surfactant dissolved in water. The speed of propagation of the foam front depends on surfactant adsorption on rock and also on the partitioning of surfactant between water and CO2, but is always less than the velocity of the foam front in a SAG flood with surfactant ahead of the gas. A foam with surfactant that is much more soluble in water than in CO2 would propagate slowly, regardless of surfactant's absolute solubility or the level of adsorption on rock. An aqueous surfactant preflush can speed the advance of foam, however.
An idealized model of a surfactant flood pushed by foam suggests that it is best to inject a relatively high water content in the foam to ensure that the gas front remains behind the surfactant front as the flood proceeds. Any gas that passes ahead of the surfactant front would finger through the oil and be wasted.
We present simulations to verify the solutions obtained with fractional flow methods and illustrate the challenges of accurate simulation of these processes.
Miscible flooding is an attractive method to displace the residual oil in a reservoir after primary and secondary recovery methods. It can in principle recover all oil in the reservoir. But the low viscosity and density of the gas phase causes instability and inefficiency in the displacement front because of gravity override, gas channeling, and viscous fingering (Lake, 1989). Gas displacement could be improved by water-alternating-gas (WAG) injection. However, gravity segregation and low injectivity tends to impair the advantages of this injection strategy (Le et al., 2008). This has inspired the application of foam as an effective way to increase the sweep efficiency of CO2 flooding.
Foam can improve sweep efficiency in gas-injection enhanced oil recovery (EOR) (Schramm, 1994; Rossen, 1996) and surfactant EOR (Li et al., 2008), redirect acid flow in matrix acid stimulation (Gdanski, 1993; Nguyen et al., 2003), and increase the efficiency of remediation of aquifers (Hirasaki et al., 2000; Mamun et al., 2002). Foam in porous media can be defined as a dispersion of gas phase in liquid phase such that the liquid phase is connected and at least some gas paths are blocked by thin liquid films (Rossen, 1996).
The fractional-flow method, or the method of characteristics (MOC), is useful in analyzing foam and other EOR processes (Zhou and Rossen, 1994, 1995; Rossen et al., 1999; Shrivastava et al., 1999; Shan and Rossen, 2004; Mayberry and Kam, 2006; Namdar-Zanganeh et al., 2009) and better understanding foam simulation models and their artifacts (Rossen et al., 1999; Dong and Rossen, 2007). Most applications of MOC to foam have been limited to two-phase flow of gas and water; in some cases it is assumed that oil is present but immobile, at its residual saturation. Application of MOC for three-phase flow for foam is limited to a few recent works. Mayberry and Kam (2006) apply this method to an immiscible displacement of gas and oil, where foam strength does not depend on oil or water saturation. Namdar-Zanganeh et al. (2009) extend this approach to cases where foam strength is a function of water or oil saturation or both.
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