Summary. This study relates the chemical composition of the polar compounds of crude oil to the wettability of rock/oil/brine systems. Adsorption properties of polar and asphaltene fractions were evaluated to determine their effects on wettability. Polar compound fractions were found to cause an oil-wet state on Berea sandstone, but the effects were not a function of the polar-fraction concentration. The concentration of nitrogen/sulfur compounds in six crude-oil polar fractions correlated with the wettability of the polar fractions on Berea sandstone. Langmuir-type adsorption on Berea sandstone was observed in adsorption studies of the asphaltene and polar fractions. Additional analysis with brine-saturated Berea sandstone resulted in adsorption values up to three times less than that for dry Berea. The amount of polar fraction adsorbed on brine-saturated Berea sandstone correlated with crude-oil wettability. Introduction Wettability as applied to an oil reservoir describes the tendency of a fluid to adhere or adsorb to a solid surface in the presence of another immiscible fluid. It can be described as a measure of the affinity of the rock surface for the oil or water phase. A major role of wettability in a reservoir is that of determining the location and distribution of reservoir fluids that influence reservoir-fluid relative permeabilities and thus recovery efficiency. Therefore. wettability is a major factor in determining the degree of oil recovery from a reservoir. This importance has been noted by a number of authors when water-driven systems were evaluated. The amount of oil recovery, as a function of water injection, was found to be greater from water-wet systems than from oil-wet systems. The evaluation of reservoir wettability is also critical in the determination of specific EOR processes. The conditions that establish a given reservoir wettability are not well known. The fluid movement through a reservoir, temperature and pressure changes, fluid production, and injection of fluids and chemicals used to enhance production are factors that must be considered as affecting wettability. Research has indicated that surface-active constituents can be isolated from a crude oil. These constituents can be important in defining reservoir wettability. The properties of reservoir rock are also factors in determining wettability. Significant variations in wettability may be related to variations in pore-surface roughness and mineralogic composition. The presence of water or previously adsorbed organic films, possibility from contact with crude oil or other organic materials, is an additional factor that influences wettability. Only a fraction of crude-oil constituents are believed to be capable of reacting with the reservoir rock surface. Several researchers have indicated that the wettability of a reservoir is strongly related to the amount of adsorption by the heavy ends found in the oil. The heavy ends contain the most polar class of compounds found in the crude oil and are principally asphaltene and resin fractions. One approach to gain insight into wettability has been adsorption studies of crude-oil and oil components on reservoir rock and minerals. A study of adsorption of petroleum heavy ends onto clay minerals has been reported. Adsorption of heavy ends onto clays, a relatively reactive constituent of the reservoir rock surface. was found to depend on the cationic form of clay and on the solvent used for heavy-ends dissolution. Subsequent work found that adsorption of asphaltenes onto clays and minerals was reduced by the presence of water. Attempts have been made to identify more specific compound classes in crude oils that affect wettability. Some researchers believe that organic acids and bases can alter wettability, but one study concluded that low-molecular-weight acids and bases did not induce wettability changes in porous media. 13 Other tractors may alter wettability for example, it has been found that transition metal ions can affect wetting on high-energy surfaces. The purpose of this research was to relate changes in reservoir wettability produced by asphaltene- and polar-compound fractions to the chemical composition of the crude oils. Adsorption properties of asphaltene and polar fractions were evaluated in terms of their effect on wettability. Improving oil production from a reservoir depends on a good, fundamental understanding of- the interaction that occurs between the reservoir fluids and the reservoir matrix. Wettability and adsorption studies are a means to increase this understanding. Experimental The individual crude-oil fractions used in this study (asphaltenes and polars) were obtained with a modified version of ASTM procedure D-2007. With this procedure. a crude oil can be separated into four fractions [saturates, aromatics, polars (may also be referred to as resins). and asphaltenes] on the basis of polarity and solubility differences of the oil constituents. The asphaltene fractions are separated on the basis of their insolubility in n-pentane. The polar fractions are retained on Attapulgus clay-packed chromatographic columns after elution with n-pentane and then removed from the clay columns by an acetone : methylene chloride (1 : 1) elution. Wettability values of the crude oils and their asphaltene and polar fractions were determined by the USBM centrifuge method, in which negative values indicate oil-wet, while positive values indicate water-wet for a given fluid/rock system. The asphaltene and polar fractions are smaller percentages of the crude oil than the saturates and aromatics. Because these materials are quite viscous, the wettability values of the asphaltenes and polars were determined on dilute solutions of these fractions dissolved in a heavy mineral oil (73 cp). The core materials were pretreated before contact with the polar or asphaltene solution and were then subjected to an initial crudeoil saturation drive, Soxhet extracted with toluene, and vacuum dried at room temperature for 48 hours. This procedure made it possible to use the same cores for a series of wettability determinations, thereby eliminating core variations. JPT P. 470^

A study was undertaken to determine why bacteria could penetrate lengths of consolidated sandstone (Berea) faster when the sandstone was sterilized by autoclaving than when dry heat (150°C, 3 h) was used. Changes in permeability, porosity, and pore entrance size of the rock as a result of autoclaving were not sufficient to explain the differences in penetration times observed, but electron dispersion spectroscopy and electron microscopy of the rock revealed changes in mineral composition and clay morphology. Autoclaved cores contained more chloride than dry-heated cores, and the clays of autoclaved cores were aggregated and irregularly shaped. Therefore, the decreases in bacterial penetration rates caused by autoclave sterilization were probably the result of a change in surface charge of the pores of the rock and of a reduction in surface area of clays available for adhesion. The results implied that dry-heat sterilization was preferable to autoclaving when examining biotic and abiotic interactions in a native-state rock model.

Water quality is an important consideration in the design of a cost-effective reservoir maintenance or secondary oil recovery project. Proper filtration equipment selection often is not based on scientific facts since knowledge of the formation may be unavailable. Rules-of-thumb that relate size of particulate in injection water to potential permeability reduction have been developed and are used for selection of proper filtration equipment. However, laboratory procedures have not been rigorously applied to the 1/3 and 1/7 rules-of-thumb currently being used to specify water filtration equipment design. This evaluation of the 1/3 and 1/7 rules-of-thumb used three different core types: Berea sandstone, Cottage Grove sandstone, and a synthetic core. The results showed that rules-of-thumb based on permeability and contaminant particle size are useful in selecting filtration equipment. Results indicated that loss of permeability (core damage) during coreflooding was more severe than expected when the 1/3 rule-of-thumb was used, but not severe enough to consider application of the more stringent 1/7 rule-of-thumb. These two competing rules appear to bracket a reasonable range for water quality. A model used to relate the amount of oil production to loss of injectivity confirmed these results by indicating reasonable oil production using the 1/3 rule-of-thumb with slightly improved production using the 1/7 rule-of-thumb.

Improvements in reservoir characterization can greatly enhance reservoir performance predictions. Heterogeneity within most reservoirs, such as the Madison Group, can be better understood from integration of results from detailed core analyses. A fractured dolomite core sample from the Upper Madison Group, near Carter Creek gas field in southwest Wyoming was studied in detail to supplement the current methodology for delineating heterogeneities in core samples. Directional permeability, fracture system orientation, and other heterogeneities related to the core sample fabric were determined and quantified by studies of: impregnated thin-sections and use of computed tomography x-ray intensity, x-ray diffraction, scanning electron microscopy, and energy dispersive spectroscopy. Computed tomography (CT) is a fast, nondestructive, qualitative and quantitative tool for the evaluation of fracture systems and associated mineralogy. The scanning procedure employed involved assigning a density range that would highlight minerals having characteristic CT densities. This procedure helped to identify variations of fracture infilling materials. The core analyses data were integrated with the regional geology, downhole logs, and production data for final evaluation.

A series of instrumental and chemical analyses was made to determine the surface chemical properties of sedimentary rocks and the physical characteristics of the pores. A scanning electron microscope (SEM) with energy dispersive X-ray analytic capability was used to study the morphology of the samples, surface mineral composition and type and location of clays. A centrifuge was used to determine the pore size distributions which are correlated with the SEM observations. An inductively coupled plasma (ICP) was used to obtain complete analyses of the rocks and effluents from ion exchange tests. The ion-exchange capacity and surface area in the Berea and Cottage Grove sandstones were found to be related to the distribution of the clays in the rock matrix. Upon comparison to conventinal methods the SEM was found to give quick positive results with regards to pore size, pore geometry and pore size distribution.