A knowledge of the preferential wetting characteristics of a reservoir can frequently be of assistance to the field or reservoir engineer, particularly in such areas as (1) assessing the particularly in such areas as (1) assessing the applicability of restored state data; (2) interpreting electric logs; (3) selecting well workover fluids; (4) applying laboratory capillary pressure data; and (5) applying special fluid injection processes. Because of this broad usefulness, wettability information was gathered on more than 50 oil-producing reservoirs from many areas of the world. One-half of the reservoirs studied, however, were located in West Texas and Wyoming. The reservoirs studied ranged in depth from 1,700 to 13,000 ft, in temperature from 80 deg. to 240 deg. F; the reservoir oils ranged from 14 deg. to 50 deg. APl gravity. Contact angle measurements in a glass-teflon cell using uncontaminated samples of the reservoir crudes provided a quantitative indication of the ability of the various crudes to wet reservoir rock minerals in the presence of water. The minerals used were selected from petrographic studies of cores fro the reservoirs of interest. For many of the reservoirs studied, flow data on native-state or fresh cores were available to provide a qualitative comparison of the reservoir wetting preference. The results obtained in the contact angle cell tests indicated that for approximately 27 percent of the reservoirs studied, water wets the rock mineral surfaces more strongly than oil; for about 66 percent of the reservoirs, oil wets the rock mineral surfaces more strongly than water; and in the remaining 7 percent of the reservoirs, the mineral surfaces were percent of the reservoirs, the mineral surfaces were not wet strongly by either water or oil. Excellent agreement was found between these results and the qualitative indication of rock wettability obtained from native-state or fresh core relative permeability tests. The tests further showed that contamination by air and certain metallic ions can seriously alter the wetting properties of many reservoir crude oils.
The relative preference of reservoir rock pore surfaces to be wet by water or oil has long been of concern, and perhaps some bewilderment to the oil industry. Several early investigator of the relative wetting tendencies of solids by water and various hydrocarbons found that some solid surfaces exhibited a definite affinity to be wet preferentially by hydrocarbons. Other early research demonstrated that many crude oils contain natural surface-active agents that are readily adsorbed at solid-liquid interfaces to render the solid surface oil-wet. numerous subsequent studies of flow in porous media have demonstrated the porous media have demonstrated the significant effect of rock wetting preference on oil displacement by water. Some of the more recent studies would appear to provide rather conclusive evidence that reservoir rock wetting preference may cove a broad spectrum. however, preference may cove a broad spectrum. however, there is still a strong tendency by some in the industry to accept the implications of research conducted by Leverett and others that all reservoirs are preferentially water-wet. If reservoir rock wetting preference were not an important factor in many aspects of oil production, further elucidation on the subject would be on little practical importance. its real significance, however, practical importance. its real significance, however, can perhaps best be demonstrated by a few examples.1. The quantitative interpretation of water saturation from electric log response by Archie's method requires a numerical value of the saturation exponent, n, which is directly related to wettability.2. In well completions or workovers, it is desirable that the kill fluid or wellbore fluid itself not have a prolonged adverse effect on the well productivity. If a formation is oil-wet, microscopic productivity. If a formation is oil-wet, microscopic trapping of water (as a nonwetting phase), which may have invaded the formation furring its use as a well control fluid, could result in serious, prolonged reduction in formation oil flow rates after putting the well on production.