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Waterflood recoveries of a Prudhoe Bay crude oil from Berea Sandstone were determined for two brine compositions used previously in a study of the effect of brine composition on the recovery of Moutray crude oil. These brines will be termed Brine 1 and Brine 2. For standard waterfloods (no difference between the initial and injected brine composition) Brine 1 (4 wt% NaCl + 0.5 wt% CaCl2) gave 16% higher recovery (% original oil in place) than Brine 2 (0 wt% NaCl + 2 wt% CaCl2). Recovery by injection of Brine 1, with Brine 2 as the initial brine, or vice versa, gave recoveries, even at breakthrough, that were intermediate to the results of standard waterfloods (no change in brine composition). Standard waterflood recoveries for synthetic reservoir brine were comparable to those obtained with Brine 1. The results demonstrate that brine composition can have a large effect on oil recovery and that displacement efficiency is not necessarily dominated by the composition of the initial (connate) brine. Introduction Reservoir wettability is a dominant factor in determining waterflood recoveries and their economic limits. In the laboratory, different wettability states can be induced by exposing outcrop core samples to crude oil. This process is referred to as aging or marination. Crude oil type, aging conditions, and initial water saturation (Swi) have a considerable impact on both wettability and oil recovery by waterflood(1–3). The effects on oil recovery of extreme changes in pH and interfacial tension have been investigated, but there is surprisingly little information available on the effect of brine composition. For waterfloods that are about to be implemented, judicious choice of injected brine when more than one source is available, or modification of the brine through addition of salts, could result in higher ultimate oil recoveries. Favourable adjustment of the injected brine composition for a mature waterflood offers a possible approach to reducing the water/oil production ratio and extending the productive life of the reservoir. A major part of this work concerns two somewhat arbitrary brine compositions: 4% NaCl + 0.5% CaCl2 and 0% NaCl + 2% CaCl2, referred to as Brine 1 and Brine 2, respectively. The effect of these brines on oil recovery by waterflooding and spontaneous imbibition from Berea Sandstone has been investigated in detail for Moutray crude oil(4). Special attention was given to the effect of differences in the initial (connate) brine and the injected brine, and the effect of changing brine composition during the course of a waterflood. This paper reports a companion study using the same core material and brines and a crude oil sample from Prudhoe Bay, designated A'92. In addition to Brines 1 and 2, waterfloods with synthetic reservoir brine and 4% NaCl brine were also tested. Experimental Materials Fluids Approximately 0.02% NaN3 was added to the brines to prevent bacterial growth. A'92 was a stock tank crude oil. Asphaltene content was measured using a 9:1 ratio of precipitant (pentane or hexane) to crude oil, following the procedure described by Jadhunandan(5).

Wettability has a significant impact on the flow of oil during enhanced oil recovery (EOR) and profound effect on fluid distribution in oil fields. Mechanisms that influence the interaction between the injected water and the components of crude oil in the presence of carbonate rock samples were investigated. The main objectives of this study were to investigate the role of both rock mineralogy and the compositions of various oils as a function of asphaltene content on the destabilization of the aqueous film separating the oil from the substrate rock surface of carbonates using aqueous phases such as brine and carbonated water. The contact angles as a function of time were measured using brine and carbonated water and two types of crude oil on four types of rock samples. Once the exact contact angle has been determined, the compositions of various oils, based on asphaltene contents, were characterized to investigate the role of oil composition on the destabilization of the aqueous film separating the oil from the rock surface. Interfacial tensions (IFTs) of brine and two types of crude oil were also measured. Four types of rock samples from carbonate reservoirs, with different compositions, selected based on X-ray diffraction results were as follows: (1) 100% dolomite D(100), (2) 100% calcite C(100), (3) 67% dolomite + 33% calcite (D67 + C33), and (4) 37% dolomite + 63% calcite (D37 + C63). Two types of crude oil were used based on the asphaltene content obtained using the saturate, aromatic, resin, and asphaltene analysis. The contents of asphaltenes for crude-1 and crude-2 were 11.6 and 6.4 wt % and represented as (I-11.6) and (II-6.4), respectively. In this study, crude oil/brine/carbonate systems showed that (D37 + C63) gave the lowest contact angle value of 67° with 6.4 wt % of asphaltene content (II-6.4) and that D(100) gave the highest contact angle of 136° with 11.6 wt % of asphaltene content (I-11.6). Brine was used as the external phase on both tests. On the other hand, using carbonated water as the external phase, the contact angle decreased from 97.6° (D67 + C33) to 75.5° (D37 + C63) for mixed dolomite/calcite systems. Decreasing the dolomite content in mixed dolomite/calcite systems caused a shift in contact angle from the oil negative intermediate wet to weakly water wet regardless of the saturating fluid phase. Also, using the adhesion tension approach, in defining surface wettability, shows that with the decrease in the contact angle values, adhesion tension shifted to positive directions with an increase in the degree of water wetness. This behavior was mainly due to the effect of type-II crude oil. The novelty of this study stems from studying the effect of rock mineralogy based on dolomite and calcite distribution and oil composition based on the asphaltene content in wettability alteration using aqueous phases such as brine and carbonated water. The results of both contact angle and IFT were implemented in adhesion tension using the Thomas Young equation as an alternative approach in defining s...

The present study was an attempt to investigate the possibility of contact angle determination of two immiscible fluids in contact with the solid surface of a porous material with heterogeneous mineralogical composition. Since the contact angles are measured on a single mineral’s crystal, the question of how representative the results of wettability of the rock containing many different constituents arise. Due to the roughness, heterogeneity, and absorption ability of porous surfaces of reservoir core, the direct measurement of contact angle is not applicable. When contact angles cannot be directly measured, the measurement of capillary rise in a bed of particles can be used to quantify wetting characteristics of the solid. The main objective of this study was to investigate the determination of rock wettability by Thin Layer Wicking approach. The application of the Washburn equation for dynamic measurement of contact angle and the method of Thin Layer Wicking were described. Experiments were conducted on the powdered samples of different sandstone and limestone rock samples and also their representative pure minerals such as quartz and calcite, respectively. As a wicking test liquid, distilled water, 2% NaCl brine, kerosene, and mineral oil were used, and their contact angles with respect to the sample’s solid surface were calculated. Powdered sample of quartz mineral was proved to be more water-wet than powdered sample of calcite mineral. Furthermore; the contact angle values of carbonates are closer to that of calcite while the contact angle values of Berea and Bentheim sandstone are closer to that of quartz. This study is the first Thin Layer Wicking study in Petroleum and Natural Gas Engineering Field, and it can be a leading survey to attempt new investigations in this subject.