Wettability, change rock surface

Several alkaline chemicals have been employed for various aspects of enhanced oil recovery. Two of the most favorable alkaline chemicals tested and used in tertiary oil recovery are sodium orthosilicate and sodium hydroxide. Comparing their characteristics, both chemicals react with acids in crude oil to form surfactants, precipitate hardness ions and change rock surface wettability. One difference between the two chemicals is that the interfacial properties for sodium orthosilicate systems are less affected by hardness ions (13), hence slightly lower interfacial tensions would occur. Lower Interfacial tensions can aid in in-situ emulsion formation. 

The observed increase in waterflood recovery indicated that rock surface wettability might be changed as a result of cyclic waterflooding—from Flood 1 (TlFl) to Flood 3 (T1F3). 

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. 

Since surfactant adsorption can alter rock surface wettability, it is possible that a surfactant could change a water-wet surface to oil-wet and break the foam. Such foam effects on porous media surfaces must be considered in the design of the foam. 

Conventional scale inhibitors are hydrophilic, that is, they dissolve in water. In the case of down-hole squeezing, it is desirable that the scale inhibitor is adsorbed on the rock to avoid washing out the chemical before it can act as desired. However, adsorption on the rock may change the surface tension and the wettability of the system. To overcome these disadvantages, oil-soluble scale inhibitors have been developed. Coated inhibitors are also available. Often, scale inhibitors are not applied as such, but rather in combination with corrosion inhibitors. 

TFSA molecules have been extensively and successfully used as steam additives in cyclic steam operations(27-32). Recently, results of a TFSA-waterflood which was conducted in West Texas were reported(33). The purpose of the work described in this paper was to further evaluate the feasibility of recovering incremental oil in a mature waterflood by injection of surfactants which change the wettability of reservoir rock surfaces. In this paper, we present the results of laboratory studies with Thin Film Spreading Agents and the results of a carefully conducted TFSA-waterflood pilot in the Torrance Field located in the Los Angeles Basin of California. 

RECOVERY MECHANISMS. Being surface active, TFSAs lower oil-water inter facial tension, but not by the three orders of magnitude needed to increase the capillary number sufficiently to recover a substantial amount of incremental oil. Instead, TFSAs enhance the recovery of oil by changing the wettability of reservoir rock surfaces from oil-wet and intermediate wettability to strongly water-wet, and by coalescing emulsions in the near-wellbore region of the production wells. 

Changing the wettability of reservoir rock surfaces from oil-wet to water-wet, increases the permeability of the formation to oil, decreases the permeability to water, decreases mobility ratio, increases sweep efficiency, increases the flowing fraction of oil at every saturation, and increases oil recovery at the economic limit of the waterflood. 

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

In an attempt to understand how nature is able to achieve such low residual oil saturations without help of engineers or laboratory specialists, Salathiel in 1973 (34) described a method for changing the wettability of rock surfaces in an unusual way. By treating cores which were saturated with typical values of oil and water, he was able to generate a mixed-wettability condition in the laboratory wherein surfaces in the larger pores were primarily oil-wet and rock surfaces in the smaller pores remained water-wet. 

Reduces surfactant adsorption on rock surfaces Changes oil wettability Hydrolyzes over time to orthophosphate... 

In chemical flooding processes for enhanced oil recovery, alkaline chemicals can be useful for hardness ion suppression or removal, reaction with acidic crude oils to generate surface-active species, reduction in surfactant adsorption on reservoir rock surfaces, changes in interfacial phase properties, mobility control and increased sweep efficiency, oil wettability reversal and increased emulsification. 

Some clay minerals can also coat a pore rock surface and change its wettability behavior. Trantham et al. [56] noted that the oil-wet character of the North Burbank reservoir was due to a coating of... 

Amott method, to be preferentially oil-wet, RDI= —0.82. Laboratory work was undertaken to determine the feasibility of injecting alkaline solutions to improve oil recovery. These experiments were designed to produce surfactants in-situ. The surfactants would both lower the interfacial tension and react with the reservoir rock surface to modify the wettability of the porous media. The experimental work considered the injection of seawater and sodium hydroxide mixtures into cores. The experimental results show that the oil recovery was higher than 50% when the alkaline solution was injected. The conclusion was that surfactant produced by alkaline injection altered the rock wettability from oil-wet to intermediate-wet, increasing oU recovery. One precaution with alkaline flooding is that the range of reactions and the change in pH can cause unexpected variation in oil recovery if the reservoir and fluids are not well characterized. 

The wettability must also be accounted for. This is explained if one considers that oil, water, and gas are accommodated in a rock reservoir. It is expected that water preferably wets the solid surfaces, as depicted in Figure 15.18a. Since gas is the least likely fluid to wet the solid surface, it is stored in the cores of the pores, with oil occupying intermediary positions. This is the case in the majority of oil reservoirs, but in some cases, where the formation characteristics are changed during prospection, the rock surface is coated with oil, as shown in Figure 15.18b. This situation requires more attention from engineers and operation personnel in the extraction activities [29,30]. 

Deposits may occur in reservoir rock and source rock for oil. This imp>airs the production of the well by causing the blocking of pores of the rock and by changing a very important property of the reservoir rock, its wettability, which is the tendency of a fluid to spread or adhere to a solid surface in the presence of non-miscible fluids, and can be modified by adsorption of polar compoimds and/or deposition of organic material and thus affect the migration of oil. This is an extremely serious problem, since it can lead to the loss of the well (Faria, 2003 Menechini, 2006). 

The wettability of reservoir rocks can be altered by the adsorption of polar compounds or the deposition of organic material such as asphaltenes in the crude oil. Wettability alteration is determined by the interaction of oil constituents, mineral surface, and brine chemistry including ionic composition and pH. Any extraneous substance such as artificial surfactants that changes the mineral surface will change the wettability of the rock and consequently the flow of fluids inside the reservoir. 

Changes in the surface properties and wettability of the system petroleum-watcr-rocks explain the increase that occurs in the oil yield with temperature during the process of water soaking of the capillaries. 

---