Surfactant relative permeabilities

Blends of sodium hypochlorite with 15% HC1 and with 12% HCl/3% HF have been used to stimulate aqueous fluid injection wells(143). Waterflood injection wells have also been stimulated by injecting linear alcohol propoxyethoxysulfate salts in the absence of any acid (144). The oil near the well bore is mobilized thus increasing the relative permeability of the rock to water (145). Temperature effects on interfacial tension and on surfactant solubility can be a critical factor in surfactant selection for this application (146). 

Use of carefully selected surfactants in well treatment fluids is a way to accomplish this. Rock wettability can be altered by adsorption of polar materials such as surfactants and corrosion inhibitors, or by the deposition of polar crude oil components (173). Pressure appears to have little influence on rock wettability (174). The two techniques used to study wettability, contact and and relative permeability measurements, show qualitative agreement (175-177). Deposition of polar asphaltenes can be particularly significant in carbon dioxide enhanced oil recovery. 

More recently well treatments that do not interrupt normal water injection operations have increased in frequency. Addition of surfactant to the injection water (144,146) can displace the oil remaining near the production well. The lower oil saturation results in an increase in the water relative permeability (145). Consequently a greater water injection rate may be maintained at a given injection pressure or a lower injection pressure. Thus smaller and cheaper injection pumps may be used to maintain a given injection rate. While the concentration of surfactant in the injection water is relatively high, the total amount of surfactant used is not great since it is necessary only to displace the oil from a 6-10 foot radius around the injection well. 

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 emulsification properties of the crude oil must be determined. Some crude oils can be emulsified with surfactant mixtures, others with caustic. Some crudes, such as Hasley Canyon (Table III), are difficult to emulsify. Experiments can be performed to determine if in situ emulsification is feasible, or if an emulsion must be injected. If in situ emulsification is feasible, loss of chemicals to reservoir rock is a problem to be addressed. If in situ emulsification is employed in conjunction with steam, it must be determined if chemicals are most effective when injected with the flowing steam or when chemical/steam injections are alternated. Relative permeabilities of the injected fluids should be determined. All of this information is needed to calculate the economics of scale-up to a specific field situation. 

Once a drug aerosol has made its way through the conducting airways to deposit in the deep lung, the major barriers to entering the body are the 0.15 pm layer of type I alveolar cells that are covered by a very thin layer of epithelial lining fluid consisting mainly of surfactant and the relatively permeable endothelium of the alveolar capillaries. Alveolar cells have so called... 

This chapter covers the fundamentals of surfactant flooding, which include microemulsion properties, phase behavior, interfacial tension, capillary desaturation, surfactant adsorption and retention, and relative permeabilities in surfactant flooding. It provides the basic theories for surfactant flooding and presents new concepts and views about capillary number (trapping number), relative permeabilities, two-phase approximation of the microemulsion phase behavior, and interfacial tension. This chapter also presents an experimental study of surfactant flooding in a low-permeability reservoir. 

Relative permeability is probably one of the least-defined parameters in chemical flooding processes. The classical relative permeability curves represent a situation in which the fluid distribution in the system is controlled by capillary forces. When capillary forces become small compared to viscous forces, the whole concept of relative permeability becomes weak. This area has not been adequately researched, and theoretical understanding is rather inadequate (Brij Maini, University of Calgary in Canada, personal communication, 2007). This section discusses relative permeability models related to surfactant flooding and the IFT effect on relative permeabilities. 

In surfactant-related processes, the interfacial tension is reduced. As IFT is reduced, the capillary number is increased, leading to reduced residual saturations. Obviously, residual saturation reduction directly changes relative permeabilities. A number of authors reported their research results, as reviewed by Amaefule and Handy (1982) and Cinar et al. (2007). The general observations were that the relative permeabilities tend to increase and have less curvature as the IFT decreases or the capillary number increases. However, Delshad et al. (1985) observed that even at IFT of 10 mN/m, k, curves showed significant curvature. 

When investigating low IFT relative permeabilities, most of the researchers treated the surfactant solution as the low IFT water phase (type I microemulsion). However, depending on the salinity, the surfactant solution could be a type I, type II, or type III microemulsion. When it is a type III microemulsion, the system becomes a three-phase system (aqueous, oleic, and microemulsion phases). A... 

TABLE 7.11 Effect of Surfactant Injection on Relative Permeabilities ... 

A 0.1% selected surfactant was then added to the injection water. The core flood experiments showed that injection pressure was reduced by 26.6%, and that the oil recovery was increased by 6.7%. This effect was a result of wettability alteration to more water-wet, reduced immobile water and oil saturations, and increased oil and water relative permeabilities. The data are shown in Table 7.11. 

Effect of Relative Permeabilities (kr Curves) in Continuous Injection of Surfactant... 

Effect of Relative Permeabilities (K Curves) in a Finite Surfactant Slug... 

In ASP flooding, alkaline, surfactant, and polymer have different effects on relative permeabilities. Table 13.2 shows our attempt to summarize these effects compared with waterflood. From Table 13.2, we can see that the effect of alkaline flood in terms of emulsification is similar to the polymer effect, whereas its effect in terms of IFT is similar to the surfactant effect. Less rigorously, we may say that only polymer reduces k, and only surfactant reduces IFT. In ASP flooding, the viscosity of the aqueous phase that contains the polymer is multiplied by the polymer permeability reduction factor in polymer flooding and the residual permeability reduction factor in postpolymer water-flooding to consider the polymer-reduced k effect. Then we can use the k curves (water, oil, and microemulsion) from surfactant flooding or alkaline-surfactant flooding experiments without polymer. 

Nevertheless, it is important to point out that a lamella cannot be created directly at a pore-throat. Rather, a lens forms first with lamella creation occurring upon expansion into the adjacent pore-body, provided surfactant is available (see the discussion of foam-generation mechanisms). During two-phase flow without stabilizing surfactant present, lenses are still created by snap-off in Roof sites (54, 60) followed by expansion and rapid coalescence in the downstream pore-body, once the lens thins to a film. If stabilized lamellae are pictured to rupture before exiting the immediate downstream pore-body, they are not much longer lived than unstable lenses. Such processes are accounted for in measurements of continuum relative permeabilities. 

Thus, the units of this effective viscosity are centipoises (Pa-s). The effective viscosity is not the actual viscosity of any real fluid, it is the viscosity of a virtual fluid simulating the combined flow of C02 and surfactant—brine through reservoir rock. The effective viscosity is a number that can be used in Darcy s law, along with the absolute permeability of the rock, to give the ratio of pressure gradient to superficial flow rate. In particular, the effective viscosity defined previously is not to be used with any assumed value of the relative permeability of dense C02 in the rock. As will be seen, experiments show that this effective viscosity is not constant, but changes in value as a number of other parameters of the flow are varied. 

Steam-based processes in heavy oil reservoirs that are not stabilized by gravity have poor vertical and areal conformance, because gases are more mobile within the pore space than liquids, and steam tends to override or channel through oil in a formation. The steam-foam process, which consists of adding surfactant with or without noncondensible gas to the injected steam, was developed to improve the sweep efficiency of steam drive and cyclic steam processes. The foam-forming components that are injected with the steam stabilize the liquid lamellae and cause some of the steam to exist as a discontinuous phase. The steam mobility (gas relative permeability) is thereby reduced, and the result is in an increased pressure gradient in the steam-swept region, to divert steam to the unheated interval and displace the heated oil better. This chapter discusses the laboratory and field considerations that affect the efficient application of foam. 

Surfactant propagation in the reservoirs has been modeled (44, 45) by allowing for surfactant adsorption, oil partitioning, and first-order surfactant decomposition all of these variables are functions of temperature. The foam mobility reduction is taken into account by reducing the gas relative permeability as follows ... 

The gas-phase relative permeability is an empirically determined function of superficial gas-phase velocity, superficial water-phase velocity, and surfactant concentration in the water phase. 

Shell (48) used a simple foam model (49) for their Bishop Fee pilot. The foam generation rate was matched by using an effective surfactant partition coefficient that took into account surfactant losses and foam generation inefficiencies. The value of this coefficient was selected so that the numerical surfactant propagation rate was equal to the actual growth rate. Foam was considered to exist in grid blocks where steam was present and the surfactant concentration was at least 0.1 wt%. The foam mobility was assumed to be the gas-phase relative permeability divided by the steam viscosity and the MRF. The MRF increased with increasing surfactant concentration. The predicted incremental oil production [5.5% of the... 

Cationic surfactants adsorb strongly on clay surfaces by cation exchange. The fatty tails of these adsorbed surfactants impart oil-wetness to the clay surfaces and shield the clays from direct contact with water. This shielding has an obvious stabilizing effect however, this change in wettability often results in undesirable side effects, such as a decrease in oil relative permeability. Moreover, because of the possibility of multilayered adsorption (formation of surface micelles), a high surfactant concentration is required to satisfy the cation exchange capacity of the clays, which can make such treatments rather expensive. 

Alcohol-free chemical floods using an equimolar blend of an olefin sulfonate and a petroleum sulfonate were reported to give a final oU recovery of 94% with a 13% of PV slug size using 3 vol.% surfactant concentration. When the slug size was reduced to 3% of PV, the oil recovery was still 80% [J7]. The mobility was controlled by adding polymer so the minimum slug viseosity, Hs, was at least equal to the reciproeal value of the water mobility at residual oil saturation, Sor Rw is viseosity of water and fcrw is relative permeability of water, i.e. ... 

In order to differentiate between foam effects, the effects of surfactant transport, and multiphase flow, a number of peripheral experiments were eonducted. Through additional corefloods the surfactant adsorption level was measured and the relative permeabilities between the different phases gas/oil/water were determined, as outlined in the Appendix. 

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