The use of adjusted/optimized saline water categorized into two different classes namely smart water (SW) and low salinity (LoSal) water injection has been proposed for more oil recovery from specific types of oil reservoirs. There are possible mechanisms concerning SW flooding that have been proposed in the literature, some of them are still subject to more examination. In this study, an experimental investigation is performed to determine the influence of type and amount of salt to the surface properties including interfacial tension (IFT) and contact angle (CA) of aqueous solution + acidic and asphaltenic crude oil + carbonate rock systems. For this purpose, the concentration of different salts including NaCl, KCl, Na2SO4, MgSO4, CaSO4, CaCl2, and MgCl2 are examined in a wide range of concentrations. The measurements revealed that salinity has dual impacts on the CA of water wet surfaces of carbonate rock. That is, CA could remain unchanged or increase as a function of brine salinity, though the increase was still within the strongly water-wet region of wettability with high film stability. The results of IFT measurements show that using ions especially divalent cations in the presence of chloride anion could substantially decrease the IFT values. The results show that the lowest IFT values are obtained at high salinity conditions (above 0.053 mol·kg–1) especially if divalent ions of MgCl2 are utilized. High values of IFT are obtained if monovalent salts such as NaCl and KCl are used.

It has been already well established that adjusting the salinity of displacing fluid critically affects the oil recovery efficiency during secondary and tertiary oil recovery processes. In this investigation, systematic experiments are designed and conducted to find the effects of both low and high salinity water on the surface properties of crude oil−brine/solid surfaces. In this respect, the effects of the major salts including NaCl, CaCl 2 , and MgCl 2 are tested in the concentration range of 0−45 000 ppm on fluid/solid and fluid/fluid interactions for a crude oil/water/rock system. Two main surface properties including contact angle and interfacial tension (IFT) are measured using a pendant drop apparatus. The obtained results demonstrate the critical effects of heavy oil components on the interfacial properties. High film stability in some cases resulted in small contact angle changes, mostly in the range of the strongly water wet condition, for different brine salinity.

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On the basis of an artificial neural network (ANN), a model is proposed to predict the thermal conductivity of pure ionic liquids. A total of 209 data points from 21 different ionic liquids was used to train and test the proposed network. The optimum number of hidden layers was determined to be 1, with 13 neurons in the hidden layer and logarithmic−sigmoid and purelin functions as the transfer functions in the hidden and output layers, respectively. The results obtained reveal that the proposed network is able to correlate and predict the thermal conductivity of all of the pure ionic liquids with an overall absolute mean relative deviation percent (MARD %) of 0.5% and mean square error (MSE) of 1.2 × 10 −6 . The optimized network was also compared with literature correlations and a predictive group contribution method. The results indicate the rather good accuracy of the proposed neural network compared to the previously proposed literature methods.

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The main objective of this study was to determine the effect of temperature difference between the oil and the pipe wall on deposition thickness and wax and asphaltene þ resin contents on the pipe wall surface of a single-phase crude oil. All of the tests were performed under laminar flow conditions (Reynolds number is ∼450) with a wax appearance temperature (WAT) of 31 °C and a 13°API crude oil from the Kermanshah oil field (Paydar-East Reservoir). A new experimental apparatus was designed and constructed to simulate the deposition thickness in flow lines. The heat-transfer method was used to measure the deposition thickness during the tests, and the chemical analysis method was additionally used to determine wax and asphaltene þ resin contents at the end of the each test. It was found that the deposition thickness increased by increasing the temperature difference between the oil and pipe wall. In addition, the chemical analysis method showed that wax content on the deposit was increased by increasing the deposition thickness and temperature difference.