Sweep Improvement in CO2 Flooding by Use of Foaming Agents

Abstract

This study has two objectives:(1) to screen and select foaming agents for specific C02 floods and (2) to detennine the effectiveness of foam in improving sweep efficiency in CO 2 flooding. Foaming agents were evaluated on their ability to produce ample, lasting foam and to have low loss from adsorption on reservoir rock and decomposition at reservoir conditions. Foaming agents that perfonned well in shaking, blender, long-tenn stability, and high-pressure stability tests were selected for core-flow experiments. The stability test results demonstrated that foaming agents are reservoir-specific. The extent of the loss depends on the foaming agent, reservoir fluids, reservoir lithology, and reservoir conditions.The core-flow experiments involved the simultaneous injection of CO 2 into two waterflooded Berea cores. The cores were arranged in parallel and had different penneabilities. The test temperature and pressure were constant and above the critical conditions for CO 2 , Three types of core-flow tests, involving injection of CO 2 to displace oil, injection of alternate slugs of CO 2 and brine, and injection of foaming agents, were conducted. The foaming agents were injected before CO 2 injection and after CO 2 had displaced oil from the more penneable core.The results show that in-situ foam generation is an effective method for improving C02 displacement efficiency. Foam was most effective when the foaming agent was injected after C02 displaced the oil from the more penneable core. The improved sweep efficiency was caused by the tendency of the foam to be generated preferentially in the more penneable core. The foam increased resistance to flow in this core and caused more CO 2 to flow through the less permeable core. The second injection method is also more applicable to field implementation.

Enhanced Oil Recovery in Fractured Reservoirs

“…Diversion of gas into lower-permeable layers using foams have previously been reported (e.g. Casteel and Djabbarah, 1988, Llave et al, 1990, Zerhboub et al, 1994, Nguyen et al, 2003. This may be important for fractured systems, where a very large permeability contrast exists and cross-flow between the zones occur (Bertin et al, 1999).…”

Evaluation and Optimization Study on a Hybrid EOR Technique Named as Chemical-Alternating-Foam Floods

“…As a result of its distinct flowing and rheological properties, the foam has been widely used as drilling fluid, fracturing fluid and acidizing fluid in the petroleum industry over the past decades (Bernadiner et al, 1992;Harris, 1995;Ozbayoglu et al, 2002). Nonetheless, perhaps its most attracting application is to offer the best hope for mobility control in gas flooding suffering from poor volumetric sweep efficiency due to the displacement front instability and early breakthrough caused by the undesirable gravity segregation and viscous fingering (Casteel and Djabbarah, 1988;Chen et al, 2005;Friedmann et al, 1991;Prigiobbe et al, 2016). This Enhanced Oil Recovery (EOR) technique is defined as the foam flooding.…”

Brief Review of Numerical Simulation Applied to Solve Oil Extraction Problems

“…It affects the interfacial forces between the gas and liquid which in turn affects value of Pc*. The proper surfactant should have the following properties: be capable of generating ample, lasting foam at the reservoir conditions, should have low adsorption and decomposition losses, should increase the sweep efficiency and the oil recovery, in addition it should be commercially available and inexpensive (Casteel and Djabbarah, [72]). Foam is readily formed during a drainage process (displacing the liquid phase by the gas phase) whenever the porous medium is pre-saturated with a surfactant solution (Chou, 1991).…”

“…Adsorption of the surfactant on the reservoir rock reduces the surfactant concentration in the injected fluid. The adsorption is a function of the surfactant formulation, reservoir fluids, reservoir lithology, and reservoir conditions (Casteel and Djabbarah, [72]). For unconsolidated sand cores at temperatures ranging from 50˚C (122˚F) to 150˚C (302˚F) it was found that the surfactant adsorption decreases with increasing the temperature, and increases with the presence of clays in the core (Novosad et al, [75]).…”

“…(Rossen et al, [81]) showed that the relation between the minimum pressure gradient required for creating foam and permeability is more complex in consolidated media. Casteel and Djabbarah [72] conducted an interesting experiment to optimize oil recovery from parallel layers have different permeabilities. The result was the foam is more effective to improve oil recovery if it is conducted after the recovery by gas injection.…”