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Abstract The interfacial phenomena of spreading and adhesion of fluids on rock surfaces have serious implications because of their impact on production strategy and oil recovery. The present study reports new experimental data on the effect of brine dilution and surfactant addition on spreading and adhesion behavior of Yates crude oil on dolomite surfaces. Spreading and adhesion have been characterized through measurements of oil-water interfacial tension (IFT) and dynamic (water-advancing and receding) contact angles. The interfacial tension was measured using Computerized Axisymmetric Drop Shape Analysis (CADSA) Technique, which was calibrated against the well-known du Nuoy Ring Technique. The Dual-Drop-Dual-Crystal (DDDC) Technique has been used to measure dynamic contact angles. In order to study the effect of brine dilution, Yates reservoir brine was mixed with deionized water (DIW) in various proportions. For each diluted brine, crude oil-water IFT, water-advancing and receding contact angles were measured. The oil-water IFT initially decreased as the volume percent of brine in the mixture decreased. However, the IFT increased with further dilution of reservoir brine with DIW. A decreasing trend was observed in the behavior of water-advancing contact angle with brine dilution. This indicated that the initial oil-wet nature of the system was changed to intermediate-wettability simply by diluting the reservoir brine. However, a strange behavior of spreading of crude oil drop against brine on the dolomite surface (with large water-receding contact angles) was observed at certain brine dilutions. This spreading of crude oil appears to be related to interfacial tension in a manner similar to Zisman's observations in solid-liquid-vapor systems. The use of surfactants to enhance oil recovery through reduction in IFT is well known in the industry. However, this study examines the capability of certain surfactants to alter wettability in addition to reducing IFT. For the Yates reservoir rock-fluids system, an Ethoxy Alcohol surfactant altered the strongly oil-wet nature (advancing angle of 158ยฐ) to water-wet (advancing angle of 39ยฐ) at a concentration of 3500 ppm. While the DDDC technique yielded significant changes in wettability due to surfactant addition, the Wilhelmy Plate Technique remained insensitive throughout the range of surfactant concentrations. The practical significance of this study is that it identifies two simple modes through surfactant addition and brine dilution to alter wettability to minimize capillary trapping of oil. Introduction The primary and secondary oil recovery processes currently being practiced have been successful in recovering only about a third of the original oil in place leaving behind nearly two-thirds as residual oil. This points out the need to study and implement new and innovative methods to recover the remaining oil. This in turn requires an understanding of the interactions that take place between crude oil, brine and the rock surface, which are collectively represented by the term wettability. Reservoir wettability is affected by several factors including roughness and mineralogy of the rock surfaces and the compositions of brine and crude oil. The effect of rock mineralogy and surface roughness have been reported previously (SPE # 75211) and this paper presents the effects of fluid characteristics brine dilution and surfactant concentration) on spreading and wettability as characterized by receding and advancing contact angles, respectively. Effect of Brine Composition on Wettability Several previous studies have been reported in the literatures that describe the effect of brine composition on formation damage and waterflooding. Mungan investigated the role of pH and salinity changes on core damage. He concluded that the primary cause of permeability reduction was blocking of the pore passages by dispersed particles. A change in the salt concentration (salinity) or pH of the reservoir fluid can liberate these clay particles and cause the clay particle to swell and clog the pores thus resulting in lower permeability.
- Research Report (0.48)
- Overview > Innovation (0.34)
- Geology > Mineral (0.55)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.48)
- Geology > Geological Subdiscipline > Mineralogy (0.44)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Word Group > San Andreas Formation (0.98)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Grayburg Formation > San Andreas Formation (0.98)
Abstract Laboratory corefloods have constituted a major step in understanding many aspects of fluids flow behaviour in reservoirs. The reservoir rock samples, having been retrieved from the oil-bearing formations, have been most valuable since they represent the actual solid phase of the reservoir rock-fluids system in laboratory studies. Therefore, it is only natural that we try to maximize the information that can be extracted from these cores and corefloods. Oil-water relative permeabilities are perhaps the most widely derived parameters from such corefloods and they are the only recourse to account for all the rock-fluids interactions in the mathematical models developed to describe the reservoir flow phenomena. Thus, coring, core preservation, core analysis, core flooding, and coreflood data analysis have formed the basis of our knowledge on reservoir fluid mechanics. One of the factors that has a strong influence on reservoir fluid mechanics is rock wettability. Therefore, attempts to derive wettability from corefloods are abundant in the literature that spans several decades. On the other hand, contact angles observed in crude oil-water-solid systems have been traditionally regarded as a true or universal measure of wettability. Hence the obvious question - is there a correlation between wettability derived from corefloods and contact angles? A definitive answer does not seem to emerge from the literature for two main reasons:Craig's broad rules-of-thumb, while enabling approximate comparisons especially between extreme cases of wettability, do not allow direct deduction of rock-fluids interactions to the extent that is required to characterize wettability, and the conventional contact angle measurements have had their own share of problems in terms of reproducibility. The dual-drop-dual-crystal (DDDC) contact angle technique, recently reported in the literature, appears to resolve this long-standing reproducibility problem with contact angle measurements. This presentation aims to compare wettability derived from reproducible DDDC tests in widely differing rock-fluids systems with their corresponding oil-water relative permeabilities derived from waterflood experiments using reservoir and Berea cores. In all, a total of six different case studies are compared in which four rock-fluids systems appear to yield similar wettabilities from corefloods and contact angles while the others differ markedly. Explanations are sought for these agreements and differences in an effort to shed more light on this important aspect of correlating core analysis with distribution and flow mechanics of reservoir fluids. Introduction In spite of its well recognized importance, wettability has remained an elusive reservoir parameter to characterize with certainty. The waterflood data on reservoir cores obtained in the laboratory are used to calculate oil-water relative permeabilities, which are then analyzed through the application of Craig's broad rules-of-thumb to discern wettability. These rules are based on the values of the connate water saturation, the water saturation at the crossover point of relative permeability curves and the end-point water relative permeability at residual oil saturation. Due to the practice of using the end-point oil permeability as the base for calculating relative permeabilities, the effect of wettability on the end-point oil relative permeability at connate water saturation has been missing from these rules-of-thumb. However, it is well recognized that the end-point oil relative permeability at connate water saturation decreases as the system becomes more oil-wet. In the analysis presented in this paper, the relative position of the end point of the oil relative permeability curve (at connate water saturation) is used as the fourth rule, in addition to Craig's three rules, to infer wettability states from oil-water relative permeability data. It should be noted that relative permeability is a lumped parameter that encompasses the influence of several variables such as wettability rock pore structure, fluid-fluid interfacial tension, fluids saturations and their history etc. Therefore, it may be too simplistic an approach to attribute the observed differences in oil-water relative permeability curves to wettability alone. Anderson notes, "Because factors other than wettability can have a similar influence on relative permeability curves, it is preferable to make independent measurements of wettability rather than to rely solely on Craig's rules of thumb to evaluate wettability". P. 241^
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- Geology > Geological Subdiscipline (0.34)
- Geology > Mineral (0.31)