Effects of Foam Quality and Flow Rate on CO2-Foam Behavior at Reservoir Temperature and Pressure
- Shih-Hsien Chang (New Mexico Petroleum Recovery Research Center) | R.B. Grigg (New Mexico Petroleum Recovery Research Center)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- June 1999
- Document Type
- Journal Paper
- 248 - 254
- 1999. Society of Petroleum Engineers
- 4.3.1 Hydrates, 1.6.9 Coring, Fishing, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.5 Reservoir Simulation, 5.7.2 Recovery Factors, 5.4 Enhanced Recovery, 5.2.1 Phase Behavior and PVT Measurements, 5.1.1 Exploration, Development, Structural Geology, 5.3.1 Flow in Porous Media, 5.4.2 Gas Injection Methods, 5.4.6 Thermal Methods
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This paper reports a series of steady-state CO2-foam flow experiments performed at reservoir conditions of 101°F and 2100 psig. Three flow rates (total injection rates), 4.2, 8.4, and 16.8 cm3/h, and five foam qualities, 20%, 33.3%, 50%, 66.7%, and 80%, were used to study how flow rate and foam quality affect foam mobility.
Results from these experiments show that foam mobility (total mobility of CO2/surfactant solution) increases with increasing flow rate and foam resistance factor decreases with increasing flow rate. Results also show that foam mobility decreases with increasing foam quality. Foam resistance factor increases with increasing foam quality ranging from 33.3% to 80%; there appears to be a minimum foam resistance factor between foam qualities of 20% and 33.3%.
Carbon dioxide CO2 flooding processes frequently experience poor sweep efficiency despite the favorable characteristics CO2 has for achieving dynamic miscibility with oil under most reservoir conditions. Because the mobility of CO2 is high compared to that of oil, channeling that initially results from reservoir heterogeneity can be further increased. This problem is also inevitable in other types of gas flooding processes (e.g., immiscible or miscible gas drive or steam drive). A need for mobility control during gas flooding has led to the study of foam processes that consist of the injection of gas with a surfactant solution (an aqueous solution of a surfactant). The basic idea is that the mobility of gas flowing through a porous medium is lowered when gas is dispersed within a surfactant solution forming foam.1 The term "foam" is defined as a dispersion of gas in a liquid such that the water phase is continuous and part of the gas phase is made discontinuous by lamellae.2 The concept of using foam for mobility control was first patented by Bond and Holbrook3 in 1958. The first research on the mechanisms of the foam drive process conducted by Fried4 was reported in 1961. Fried reported a sharp pressure drop across the foam bank and reduced gas mobility through porous media. Since then, the mechanisms of foam flow through porous media in gas flooding have been studied extensively. Much of the early research has been reviewed by Heller and Taber,5 Heller et al.,6 Marsden,7 and Hirasaki.8,9
Studies of foam mechanisms can be generally divided into two major groups: studies10-17 conducted in most cases with nitrogen or steam at low and moderate pressures (below 1500 psia) and studies18-26 conducted with CO2 at higher pressures. To avoid confusing CO2 foam with nitrogen foam, we would like to point out that nitrogen is a gas-like fluid while CO2 is a dense, liquid-like fluid over much of the range of pressures and temperatures found in many oil reservoirs. The density of CO2 lies within the range from 0.5 to 0.9 g/cm3 . Even though CO2 is actually a supercritical fluid with a liquid-like density under most reservoir conditions, CO2 is still referred to as a gas. Note that the critical temperature and pressure for pure CO2 is 88°F and 1071 psia, respectively. It is also important to note that both the density and the compressibility of CO2 are close to those of crude oil and they do not differ greatly from those of water. Therefore, the characteristics of CO2 foam cannot be assumed to be the same as those of air or nitrogen foam at near ambient conditions.
Laboratory foam tests are usually performed by simultaneously injecting CO2 and surfactant solution into a core saturated with either surfactant solution or brine at a specified flow rate (total injection rate) and an imposed foam quality (CO2 fraction). Note that a foam quality of 80% (a CO2 fraction of 0.8) corresponds to a foam test where the CO2-liquid volumetric injection ratio is 4:1. In this work, the term "liquid" designates the aqueous phase, with or without surfactant. The surfactant solution is prepared by mixing a surfactant with brine at a specified surfactant concentration. When a steady-state pressure drop across the core is achieved, the total mobility of CO2/surfactant solution can be calculated for the corresponding foam quality (CO2 fraction), flow rate (total injection rate), and surfactant concentration. The foam resistance factor25,27 is an expression commonly used to assess the magnitude of the mobility reduction in laboratory foam tests. The foam resistance factor is defined as the total mobility of CO2 /brine divided by the foam mobility (total mobility of CO2 /surfactant solution), where both mobility measurements are conducted at the same CO2-liquid volumetric injection ratio. If foam is not generated, the total mobility of CO2/surfactant solution is about the same as the total mobility of CO2/brine, and the resistance factor is unity. If foam is generated, the value of the resistance factor quantifies the effect of the foam. It is important to note that the total mobility of CO2/surfactant solution, which is often referred to as the foam mobility,23,26-28 is different from the mobility of CO2 in the presence of foam. The total mobility of CO2 /surfactant solution is calculated as a single fluid and is defined as the ratio of the total injection rate per unit superficial area to the pressure gradient required for simultaneous flow of CO2 and brine/surfactant through the core.23
Recent field tests29,30 using high-pressure CO2 foam indicate that field application of CO2 foam is a technically viable process for improved oil recovery (IOR). An efficient evaluation of candidate reservoirs for possible CO2-foam application requires a fundamental understanding of information on CO2-foam behavior under various foam test conditions. Many parameters (e.g., foam texture, surfactant concentration, permeability, foam quality, and flow rate) have been evaluated to study their effects on foam flow behavior. However, some of the information available in the literature is inconclusive and incomplete. It is difficult to compare the results obtained by the various authors because their experimental conditions varied and because foam properties are dependent upon these conditions. Two important parameters, foam quality and flow rate, are investigated in this study.
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