Rock wettability

In oil bearing formations, the presence of polar chemical functions of asphaltenes probably makes the rock wettable to hydrocarbons and limits their production. It also happens that during production, asphaltenes precipitate, blocking the tubing. The asphaltenes are partly responsible for the high viscosity and specific gravity of heavy crudes, leading to transport problems. 

Wettability is defined as "the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids" (145). Rock wettability can strongly affect its relative permeability to water and oil (145,172). Wettability can affect the initial distribution of fluids in a formation and their subsequent flow behavior. When rock is water-wet, water occupies most of the small flow channels and is in contact with most of the rock surfaces. The converse is true in oil-wet rock. When the rock surface does not have a strong preference for either water or oil, it is termed to be of intermediate or neutral wettability. Inadvertent alteration of rock wettability can strong alter its behavior in laboratory core floods (172). 

Care must be taken in all well treatment and injection operations not to alter rock wettability in an undesired manner. 

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. 

Jackson, D.D., Andrews, G.L., and Claridge, E.L. "Optimum WAG Ratio vs Rock Wettability in C02 Flooding," SPE Paper No. 14303, presented at the 60th Annual Technical Conference of the Society of Petroleum Engineers, Las Vegas, Sept. 1985 (being revised for publication). 

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). 

Rock wettability has a strong influence over which type of emulsion will form in the reservoir, according to Huang and Yu (2002). In an oil-wet porous medium, forming W/O emulsion is easy. In a continuous heavy oil system, due to high oil viscosity, water droplets collide less frequently than oil droplets in a less viscous water phase. For this reason, W/O is much more common than 0/W emulsion in heavy oil systems. 

Most of the research on foam sensitivity to oils in porous media, whether in microvisual or core-flood tests, has been concerned with water-wetted pore and throat surfaces. Because petroleum reservoirs are frequently of intermediate, mixed, or oil wettability, it is of considerable interest to understand how rock wettability influences foam stability. 

It is well known that flocculation of asphaltenes in petroleum reservoirs, wells and surface separation-upgrading facilities pose technical problems and increase the cost of production and processing of crudes. Field conditions conducive to precipitation of asphaltenes include natural depletion, miscible flooding, caustic flooding, acid stimulation and gas-lift operations. Asphaltene precipitation is particularly important problem in miscible flooding since it can reduce permeability, affect well injectivities and productivities, alter rock wettability characteristics and even cause plugging of producing wells. ... 

Alkaline inorganic chemicals such as sodium silicates, sodium hydroxides, sodium carbonate, and sodium phosphates have been added to injection fluids used in enhanced oil recovery systems. These chemicals can, in varying degrees, affect various rock and fluid parameters such as interfacial tension, interfacial viscosity, emulsion stability, rock wettability, hardness-ion content, ion-exchange capacity or equilibria, surfactant adsorption, phase equilibria, etc., in order to improve recovery efficiency for residual oil remaining after waterflooding. 

Surfactant slugs are frequently used in EOR processes to mobilize residual oil by changing rock wettability or by reducing oil/water interfacial tension. To increase the efficiency of such processes, polymers can be either co-injected with the surfactant slug or as a chase. In both cases, surfactant and polymer mixing is to be expected. The effects of Triton X-100 (a nonionic surfactant) and Neodol 25-3S (an anionic surfactant) on the viscosity of HPAM solutions were examined by Nasr-El-Din et al. [41]. 

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. 

Sayyouh M.H., Hemeida A.M., Al-Blehed M.S. and Desouky S.M. (1991). Role of polar compounds in crude oils on rock wettability, /. of Petroleum Science and Engineering, 6, p. 225-233. 

A problem in the WAG process is that injected water blocks contact between the injected gas phase and resident oil. This reduces displacement efficiency at the pore scale i.e., it results in a larger ROS. This effect has been found to be a strong function of rock wettability and more detrimental in water-wet rocks. 8... 

If too much water is injected, the water will move faster than the solvent, resulting in a high water saturation at the solvent/oil interface. Oil trapping is likely to be increased by the higher water saturation. The magnitude of oil trapping depends on rock wettability, as discussed in Sec. 5.10.1. 

In summary, both physical modeling and computer simulation have shown that WAG performance is dependent on rock wettability. Oil trapping in water-wet rocks is a significant negative factor. Volumetric sweep can be improved with WAG injection, but a corresponding delay in production response can adversely s ect the economies of the process. 

Huang, E.T.S. and Holm, L.W. Effect ofWAG Injection and Rock Wettability on Oil Recovery During CO2 Flooding, SPERE (Feb. 1988) 119-29. 

Lin, E.C. and Huang, E.T.S. The Effect of Rock Wettability on Water Blocking During Miscible Displacement, SPERE (May 1990) 205-12,... 

The success or failure of a polymer project depends on various parameters such as mobility ratio, recovery factor at the beginning of polymer flooding, and rock wettability. An essential parameter in this connection Is polymer loss in the reservoir during flooding, which may be due to adsorption, filtration, polymer retained in fluids not produced, polymer trapped in dead-end pores, or polymer clinging to rock material, among other factors. This paper presents a comparison of the retention values obtained in laboratory flood tests and actual polymer losses in selected field projects. 

---