CO2-foam mobility

High pressure equipment has been designed to measure foam mobilities in porous rocks. Simultaneous flow of dense C02 and surfactant solution was established in core samples. The experimental condition of dense CO2 was above critical pressure but below critical temperature. Steady-state CC -foam mobility measurements were carried out with three core samples. Rock Creek sandstone was initially used to measure CO2-foam mobility. Thereafter, extensive further studies have been made with Baker dolomite and Berea sandstone to study the effect of rock permeability. 

Also, other dependent variables associated with CO2-foam mobility measurements, such as surfactant concentrations and C02 foam fractions have been investigated as well. The surfactants incorporated in this experiment were carefully chosen from the information obtained during the surfactant screening test which was developed in the laboratory. In addition to the mobility measurements, the dynamic adsorption experiment was performed with Baker dolomite. The amount of surfactant adsorbed per gram of rock and the chromatographic time delay factor were studied as a function of surfactant concentration at different flow rates. 

Figure 10. CO2-foam mobility using CD 1050 in different permeability rocks. (Reproduced with permission from reference 29. Copyright 1992 Society of Petroleum Engineers.)...

Computerized Tomography (CT) was used to study mobility control with CO2 foam during tertiary horizontal corefloods at reservoir pressures and temperatures. CO2 foam provided effective mobility control under first-contact miscible conditions. However, mobility control was not observed when the pressure was substantially reduced so -that the oil and CO2 were immiscible. If the beneficial effects of foam can be extended to developed-miscibility conditions, CO2 foam will be an outstanding EOR process. 

The surfactant has two important roles in CO2 foam. First, it increases the apparent viscosity of CO2 so that brine and oil are displaced in a stable manner. Second, the surfactant lowers the interfacial tension between CO2 and brine which promotes brine displacement. Reducing the brine saturation below S c allows bulk-phase CO2 to completely access the oil-filled pore network. A high-saturation brine bank also retards CO2 mobility by relative permeability effects. The brine bank carries surfactant and allows oil reconnection and mobilization ahead of the bulk CO2 phase because of the favorable partitioning of CO2 from brine into oil. 

The differences between the miscible CO2 foam process and a stable tertiary miscible solvent process are shown in Figures 2 and 3. In the miscible CO2 foam process, oil mobilization occurs as CO2 partitions into and swells the trapped oil above Sorw allowing it to be displaced by the mobile brine. The carbonated brine in turn is displaced by CO2 foam. In comparison, miscible N2 and LPG do not transfer to oil through solution in the water phase, as CO2 does. Instead of a brine bank, the solvent and oil are separated by a miscible dispersion zone. The brine saturation is not reduced below Swc ... 

A fundamental concern in CO2 foam applications is how far foams can be transported at reservoir temperatures and salinities in the presence of crude oil. Oils that spread at gas/brine interfaces are known to have severe debilitating effects on foam stability. Another concern is that surfactants may retard oil droplet coalescence and therefore reduce tertiary oil reconnection and mobilization efficiency. 

Many surfactants have been suggested as candidates for CO2 foam. However, at high salinity and temperature in the presence of oil, most surfactants foam poorly due to partitioning and emulsion formation and fail to control mobility during CO2 injection. This behavior is analogous to that observed in chemical (microemulsion) oil recovery (5-1). As the salinity, hardness and temperature increase, surfactants form water/oil emulsions, precipitate surfactant-rich coacervate phases, and partition into the oleic phase. CO2 decreases further the solubility of surfactant in the aqueous phase. 

Final laboratory testing of CO2 foam was performed in Shell s CT facility (11-12L Tertiary miscible and immiscible CO2 corefloods, with and without foam mobility control, were scanned during flow at reservoir conditions. The cores were horizontally mounted continuous cylinders of Berea sandstone. Table I lists pertinent core and fluid data. 

One important and as yet not fully understood feature of CO2 foam concerns delineation of the length of the foam bank. Multiple pressure tap measurements indicated that the largest pressure drop occurred within 3 to 6 inches around the bulk CO2 phase front. These and additional studies suggest that the foam bank can be relatively short compared to the length of the core. The pressure drop decreased to very low values as brine approaches its irreducible saturation. This is reasonable, since aqueous surfactant lamella cannot form or propagate when there is no mobile brine present. 

The important question is whether mobility control can be obtained in developed-miscibility CO2 flooding. Further research is required to define CO2 foam behavior under developed-miscibility conditions. 

But such a lower limit of attainable mobility, as is shown on the Figure, has also been observed with one other surfactant. If it proves to be a general feature of all surfactants that are effective in stabilizing CO2 foams, it will be of great economic interest, since it will fix the maximum concentrations of particular surfactants that could be useful in the field. 

In most applications of CO2 as an oil recovery agent, the CO2 exists as a supercritical fluid above its critical pressure (7.4 MPa) and temperature (32°C), while its solutions in oil are liquids (5). Hence, the dispersion types of most direct interest are supercritical-fluid-in-a-liquid (for which no specific name yet exists) and emulsions of oleic-in-aqueous liquids (which may be encountered at low CO2 saturations). However, for historical reasons (described below), all dispersions used in research on gas-flood mobility control are sometimes called "foams," even when they are known to be of another type. 

Heller, J. P. "Reservoir Application of Mobility Control Foams in CO2 Floods, paper SPE/DOE 12644 presented at the SPE/DOE Fourth Joint Symposium on Enhanced Oil Recovery, Tulsa, Oklahoma, April 15-18, 1984. 

In recent years there has been considerable interest in the use of foams in chemical steam flood, CO2, and low tension processes. To date, principal applications have been as diverting agents where the foam has been used to block high permeability, low oil saturation zones and hence force drive fluids through lower permeability, higher oil saturation zones. The utility of foams in more general mobility control roles has not been extensively... 

Two sets, i.e., four experiments, of core flow studies are compared. Sets No. 1 and No. 2 were tertiary miscible and immiscible CO2 floods without mobility control. The same core from each set, after plain CO2 injection, was restored to waterflood residual oil saturation and flooded with 0.05% AEGS 25-12 surfactant in brine. There was almost no difference between the oil saturation distributions in the cores between experiments, with the average Sorw values of 37 1 saturation percent in both sets of experiments. CO2 was injected continuously in all experiments at a nominal rate of 1 ft/day. No attempt was made to preform a foam, or to inject alternate slugs of surfactant solution and CO2. 

It is also interesting to observe that the slope of the fitted lines (that is, the dependence of mobility on overall flow rate) decreases as the surfactant fraction increases. A possible explanation is that the lamellae formed in the pore space between the CO2 and surfactant mixture become more durable as the aqueous fraction is increased. From a macroscopic viewpoint, more uniform displacement would be expected as a result of the decreased mobility. Furthermore, greater scattering of data is observed for the CO2 fraction of 81.1 1.0%. It is possible that this particular mixture may be more thermodynamically unstable than "foams of different quality. 

Tertiary oil was increased up to 41% over conventional CO2 recovery by means of mobility control where a carefully selected surfactant structure was used to form an in situ foam. Linear flow oil displacement tests were performed for both miscible and immiscible floods. Mobility control was achieved without detracting from the C02-oil interaction that enhances recovery. Surfactant selection is critical in maximizing performance. Several tests were combined for surfactant screening, included were foam tests, dynamic flow tests through a porous bed pack and oil displacement tests. Ethoxylated aliphatic alcohols, their sulfate derivatives and ethylene oxide - propylene oxide copolymers were the best performers in oil reservoir brines. One sulfonate surfactant also proved to be effective especially in low salinity injection fluid. 

Steam is also used as a foaming fluid. The problem in this case is similar to that of the CO2 system, i.e. a high mobility of the steam. Once again, surfactants with or without non-condensable gas are used to increase the foam stability. Since the operating temperatures involved are high, the surfactant system must be... 

Foams have been tested as diverting agents in waterfloods, 39 as steam-diverting agents to reduce gravity override or steam channeling in steamfloods, and as mobility-control fluids in CO2 displacements. 4 ... 

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