Success of SAG-Foam Processes in Heterogeneous Reservoirs
- Dennis Denney (JPT Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- January 2008
- Document Type
- Journal Paper
- 43 - 46
- 2008. Society of Petroleum Engineers
- 1 in the last 30 days
- 138 since 2007
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This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 110408, "Success of SAG-Foam Processes in Heterogeneous Reservoirs," by W.J. Renkema and W.R. Rossen, Delft University of Technology, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November.
In 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 decrease recovery drastically. The use of foam can reduce gas mobility and the effect of heterogeneity, thereby increasing sweep efficiency. An optimal design strategy is proposed for surfactant-alternating-gas (SAG) -foam processes.
Primary- and secondary-recovery methods leave behind up to two-thirds of the oil originally in place in the reservoir. Gas injection can increase the recovery from depleted reservoirs. Injected gas tends to rise to the top of the reservoir because of its low density, then over-ride the oil-rich zone, leading to early gas breakthrough. High mobility of the gas leads to viscous instability, which enhances gravity override and makes heterogeneity much worse by forming high-mobility flow paths.
The use of foam for mobility control, proposed in 1958, traps some bubbles and reduces movement of flowing gas, thereby reducing gas mobility. Trapped gas reduces gas relative permeability because foam films (lamellae) block some of the flow channels. In flowing bubbles, the effective gas viscosity is increased because pore walls and constrictions cause significant drag. Foam does not change the water relative permeability function or liquid viscosity.
Foam can be injected into the reservoir by coinjection of gas and water or by SAG injection (alternating slugs of surfactant solution and gas). For CO2-foam projects, the SAG process also reduces corrosion in surface facilities and pipe. In low-permeability porous media, the SAG process increases gas injectivity. When gas is injected, water is displaced from the near-well region farther into the reservoir, weakening foam near the well. As a result, gas mobility in the near-well region rises, and injectivity increases.
Existing models can be divided into local-steady-state models (ranging from simple to more-complex semimechanistic models) and dynamic “population-balance” models. Population-balance models take into account the rate of change of foam texture (i.e., bubble density), which depends on creation, destruction, and trapping of lamellae.
Local-steady-state models use an algebraic relation (which could be empirical or more physically based) between gas mobility and factors determining foam texture (e.g., surfactant concentration). All these models account for foam having no effect on the relative permeability function for water.
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