CO2 foam

Adipic acid is an irritant to the mucous membranes. In case of contact with the eyes, they should be flushed with water. It emits acrid smoke and fumes on heating to decomposition. It can react with oxidizing materials, and the dust can explode ia admixture with air (see Table 3). Fires may be extinguished with water, CO2, foam, or dry chemicals. 

Because of thek flash pokits, nitroparaftins are classified as flammable Hquids under DOT regulations (ha2ard class 3, PG III). Nitromethane and nitroethane tires can be extinguished with water, CO2, foam, or class ABC dry chemical extinguishers. Nitroparaftins should not be exposed to dry caustic soda, lye, or similar alkaline materials. 

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. 

Heller, J.P. CO2 Foams in Enhanced Oil Recovery in Foams, Fundamentals and Applications in the Petroleum Industry, Schramm, L.L. (Ed.), American Chemical Society Washington, DC, 1994, pp. 201-234. 

Sunset (16). CO2 foams have not been field tested at the time of this writing. 

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 ... 

In the CO2 foam process, the surfactant that is left behind, in the connate brine and adsorbed on the rock, is not entirely lost. In field processes, brine is injected following the CO2 injection. That chase brine causes surfactant desorption and displaces connate brine... 

Figure 2. Idealized saturation profile for the CO2 foam process.

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. 

To be a promising candidate for CO2 foam, the surfactant loss by adsorption, partitioning and emulsion formation must be low. In general, anionic surfactants have low adsorption on sandstones and high adsorption on carbonates, whereas the reverse is true for nonionics ( ). Cationic surfactants are not considered because of their high adsorption on many surfaces. 

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. 

Effect of CO2 Foam Fraction 0.05% Enordet X2001 (A) in 1% Brine ... 

Patton, J. T. Enhanced Oil Recovery by CO2 Foam Flooding, Final Report, U.S. DOE, DE8200905, 1982. 

DFG MAK Confirmed Animal Carcinogen with Unknown Relevance to Humans SAFETY PROFILE Suspected carcinogen. Poison by intravenous route. A powerful irritant. A dangerous fire hazard when exposed to heat or flame. To fight fire, use water, dry chemical, CO2, foam. When heated to decomposition it emits ver toxic fumes of cr, NOx, and CN . See also NITRILES. 

DOT CLASSIFICATION 6.1 Label KEEP AWAY FROM FOOD SAFETY PROFILE Poison by ingestion and intraperitoneal routes. Moderately toxic by an unspecified route. Mildly toxic by skin contact. An allergen. Flammable when exposed to heat or flame can react with oxidizing materials. To fight fire, use dry chemical, CO2, foam. Hypetgolic reaction with red fuming nitric acid. When heated to decomposition or on contact with acid or acid fumes it emits highly toxic fumes of aniline and NOx. 

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