Water-wetting surfactant

Surfactants. Surfactants (qv) perform a variety of functions in a drilling fluid. Depending on the type of fluid, a surfactant may be added to emulsify oil in water (o/w) or water in a nonaqueous Hquid (w/o), to water-wet mud soHds or to maintain the soHds in a nonwater-wet state, to defoam muds, or to act as a foaming agent. 

Wettabihty is defined as the tendency of one fluid to spread on or adhere to a soHd surface (rock) in the presence of other immiscible fluids (5). As many as 50% of all sandstone reservoirs and 80% of all carbonate reservoirs are oil-wet (10). Strongly water-wet reservoirs are quite rare (11). Rock wettabihty can affect fluid injection rates, flow patterns of fluids within the reservoir, and oil displacement efficiency (11). Rock wettabihty can strongly affect its relative permeabihty to water and oil (5,12). When rock is water-wet, water occupies most of the small flow channels and is in contact with most of the rock surfaces as a film. Cmde oil does the same in oil-wet rock. Alteration of rock wettabihty by adsorption of polar materials, such as surfactants and corrosion inhibitors, or by the deposition of polar cmde oil components (13), can strongly alter the behavior of the rock (12). 

Most mineral fillers can be easily incorporated into solvent-borne and water-borne (adding adequate surfactants and wetting agents) adhesives. 

Uintaite is not easily water wet with most surfactants. Thus, stable dispersions of uintaite are often difficult to achieve, particularly in the presence of salts, calcium, solids and other drilling fluid contaminants and/or in the presence of diesel oil. The uintaite must be readily dispersible and must remain water wet otherwise it will coalesce and be separated from the drilling fluid, along with cuttings at the shale shaker or in the circulating pits. Surfactants and emulsifiers are often used with uintaite drilling mud additives. 

Sandstone rock surfaces are normally highly water-wet. These surfaces can be altered by treatment with solutions of chemical surfactants or by asphaltenes. Increasing the pH of the chemical treating solution decreases the water wettability of the sandstone surface and, in some cases, makes the surface medium oil-wet [1644]. Thus the chemical treatment of sandstone cores can increase the oil production when flooded with carbon dioxide. 

Surfactants Nonemulsifiers Prevent water-wetting of formation... 

T. Austad, B. Matre, J. Milter, A. Saevareid, and L. Oyno. Chemical flooding of oil reservoirs Pt 8 Spontaneous oil expulsion from oil-and water-wet low permeable chalk material by imbibition of aqueous surfactant solutions. Colloids Surfaces, Sect A, 137(1-3) 117-129, 1998. 

Interpretation of NMR well logs is usually made with the assumption that the formation is water-wet such that water occupies the smaller pores and oil relaxes as the bulk fluid. Examination of crude oil, brine, rock systems show that a mixed-wet condition is more common than a water-wet condition, but the NMR interpretation may not be adversely affected [47]. Surfactants used in oil-based drilling fluids have a significant effect on wettability and the NMR response can be correlated with the Amott-Harvey wettability index [46]. These surfactants can have an effect on the estimation of the irreducible water saturation unless compensated by adjusting the T2 cut-off [48]. 

Increasing the water-wet surface area of a petroleum reservoir is one mechanism by which alkaline floods recover incremental oil(19). Under basic pH conditions, organic acids in acidic crudes produce natural surfactants which can alter the wettability of pore surfaces. Recovery of incremental oil by alkaline flooding is dependent on the pH and salinity of the brine (20), the acidity of the crude and the wettability of the porous medium(1,19,21,22). Thus, alkaline flooding is an oil and reservoir specific recovery process which can not be used in all reservoirs. The usefulness of alkaline flooding is also limited by the large volumes of caustic required to satisfy rock reactions(23). 

Thin Film Spreading Agents are synthetic surfactants which change the wettability of reservoir rock surfaces from oil-wet and intermediate wettability to water-wet. 

Petro-Green, Inc., ADP-7 is a biodegradable, water-soluble, nonionic/anionic liquid surfactant concentrate that emulsifies hydrocarbons, makes them water-wet, and allows natural processes to biodegrade them in situ. Once it is an emulsion, the hydrocarbons are no longer flammable or odoriferous. ADP-7 promotes the natural biodegradation processes. 

Another potential area of use for HIPEs is in the recovery of oil from tar and oil sands, suggested by Sebba [19,24]. In this process, an oil-in-water HIPE, e.g. of kerosene, is added to the solid material, and the mixture is agitated. The oil quickly dissolves in the kerosene, and the aqueous surfactant solution wets the surface of the solid particles, preventing readhesion of oil. Addition of a small amount of water causes the oil/kerosene mixture to form a separate layer, which can easily be removed. 

Recently, use of a surfactant in the injected water such that a foam or emulsion is formed with carbon dioxide has been proposed (20.21) and research is proceeding on finding appropriate surfactants (22-24). The use of such a foam or emulsion offers the possibility of providing mobility control combined with amelioration of the density difference, a combination which should yield improved oil recovery. Laboratory studies at the University of Houston (25) with the same five-spot bead-pack model as used before show that this is so, for both the relatively water-wet and relatively oil-wet condition. We have now simulated, with a finite-difference reservoir process computer program, the laboratory model results under non-WA3, WAG, and foam displacement conditions for both secondary and tertiary recovery processes. This paper presents the results of that work. 

The surfactant adsorbs on water-wet glass beads. Experiments reported in Ref. 27 show that about 0.5 HCPV of surfactant solution is required to satisfy the adsorption capacity of the bead pack. Hence, when a slug size of 0.2 HCPV of carbon dioxide and an equal slug of surfactant solution are injected together, the surfactant is all adsorbed when about 40% of the volume of the bead pack has been contacted. This is apparently sufficient to obtain the benefits of... 

A plot showing the ratio of gas mobility to liquid mobility for air flow in the presence of brine and some surfactant solutions in brine is shown in Figure 4. The results indicate that these surfactants should be effective agents for reducing gas mobility, particularly in water-wetted sandstone reservoirs. A list of the surfactants used axe given in Table I. 

Soo and Radke (11) also studied the effect of average droplet size of emulsion on the flow behavior in porous media. The droplet size distribution of the emulsions that were prepared with surfactants and NaOH in a blender are shown in Figure 12. These droplet size distributions were found to be log-normal distributions. Others (9, 27) have also observed that the size of emulsion droplets was log-normally distributed. Soo and Radke (11) conducted experiments with emulsions having different average mean diameter in fine Ottawa water-wet sand packs. Their results of the reduced permeability, k/ko, and reduced effluent volume concentration as a function of the pore volume of oil (in the emulsion) injected are shown in Figure 13. All emulsions were of 0.5% quality, and the initial permeability, ko, was 1170 mD (millidarcies). The lines in the figure represent results of flow theory (12,13) based on deep-bed filtration principles. 

Hydrophilic solids can be suspended easily in water without the aid of a water-dispersible surfactant or wetting agent, and conversely hydrophobic solids can be suspended in oils and non-polar vehicles without the use of lipid-soluble surfactants. The crystal density of hydrophilic solids usually ranges from 1.5 to 6.9g/cm, whereas the crystal density of hydrophobic solids usually ranges from 0.9 to 2.2g/cm. ... 

By addition of a surfactant, the wetting of the wall by oil droplets is avoided and the heat transfer characteristic can be well described by the equation (7.44) incorporating the values fe, h and for water, see Fig. 7.11. 

In dilnte surfactant flooding a water-wet reservoir, when surfactant solution contacts residnal oil droplets, the oil droplets are emulsified because of low IFT and entrained in snrfactant solution. These entrained oil droplets are carried forward and are pnlled to become long oil threads so that they can deform and pass throngh pore throats. When the salinity is low, oil-in-water (OAV) emnlsions are formed. When the salinity is high, water-in-oil (W/0) emulsions are formed. These oil droplets are coalesced to form an oil bank ahead of the snrfactant sing. As snrfactant contacts rock surfaces, wettability may be changed. 

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. 

A number of papers (e.g., Standnes and Austad, 2000 Hirasaki and Zhang, 2004 Adibhatla and Mohanty, 2008) report that alkaline and/or surfactant solutions can change rock wettability and favorably change from more oil-wet to water-wet. However, there are also reports that ASP solutions increase the contact angle— for example, an ASP solution of 3530S polymer + ADF-4 surfactant + NaaCOs alkali (Yang et al., 2002b). 

---