Seawater injection has demonstrated a successful and a well-established procedure for reservoir pressure maintaining and sweeping oil out of the reservoir. However, in most cases seawater by itself showed low incremental oil recovery, many research studies have shown that further dilution of the injected seawater is capable of altering the carbonate formation's wettability from mixed or oil-wet to more water-wet and therefore additional oil recovery. However, dilution requires massive volume of fresh water which is an expensive commodity and therefore it will not be practical in real applications. The following study provides for the first time a novel concept for boosting oil recovery with use of halides ions in very small concentrations without the need for seawater dilution. Halides ions (iodide ions) are added to the seawater with different concentrations (1000 ppm and 2000 ppm) to formulate what we call the "Dynamic Water". The efficiencies of the different prepared Dynamic Waters (with different iodide ions concentrations) were compared to seawater by performing IFT, contact angle, spontaneous imbibition and coreflooding experiments. Although all prepared Dynamic Water mixtures have higher salinity than seawater, they had insignificant impact on lowering the IFT, but they significantly alter the rock wettability to stronger water wet, which is an important oil recovery mechanism. The performance of the Dynamic Water on oil recovery was also investigated in this study by means of spontaneous imbibition and coreflooding experiments. Six samples were utilized for these experiments, three dolostones and three limestones. Initially, the three limestone samples were considered for spontaneous imbibition where Dynamic Water proved to be efficient in recovering oil from all the samples. After sample cleaning, the same three limestone samples in addition to the three dolostone samples were used for coreflooding under reservoir conditions of high pressure and high temperature. Good oil recoveries were achieved from almost all the samples by coreflooding, with maximum additional oil recovery of 16.9% from one of the limestone samples.

Interfacial tension (IFT) between crude oil and water is one of the critical properties that governs the multiphase flow in porous media. Measuring IFT in the laboratory is time-consuming and difficult, especially with live reservoir fluids. Tools and processes are unavailable to measure it downhole. Current reservoir simulators rely on empirical models to estimate the IFT. In general, these models overpredict IFT and do not account for the role of crude oil chemistry. The surface-active naphthenic acids (NAs) present in crude oil play a crucial role in governing IFT behavior at the oil/water interface and stabilizing in situ emulsions that pose operational challenges. Additionally, the NA concentration is challenging to determine without a wet-chemistry laboratory process. In this study, we used 22 crude oil samples from different fields to develop a model that can potentially be used for downhole IFT measurements. This research will help improve saturation height function modeling, enable more informed decisions on field development planning for newly drilled wells, and develop better production strategies with the older (or preexisting) ones. Several parameters were investigated related to the Gibbs− Langmuir model. The proposed model provides average universal parameters (Γ m and K L ) related to the crude oil/water interface, enabling us to characterize the crude oil chemistry. Such a model can be used to account for the effect of acids on the crude oil interfacial tension. The acid concentration is used as an input parameter to better estimate the oil/water interfacial behavior. This model can potentially be used as a monitoring tool to avoid technical issues, such as in situ emulsification, corrosion, and scaling problems.

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Nanoparticles, through many researches, has proven its capability to be an enhance oil recovery agent. In this study, we aim to investigate the performance of natural Zeolite in nanoscale on the recovery of crude oil compared to the normal water flooding method. The natural Zeolite nanoparticles are dispersed in seawater, however nanoparticles stability in saline water have been reported to be a challenge. Therefore and in order to investigate the performance of these natural Zeolite nanoparticles on oil recovery, we first stabilize them in seawater. Natural Zeolite nanoparticles of different concentrations (i.e. 0.02, 0.03, 0.05 wt%) were dispersed in seawater, where stability tests showed nanoparticles precipitations in less than an hour. This problem, of nanoparticles precipitation in seawater, was investigated by studying the performance of the Zeolite nanoparticles in each electrolyte that exits in seawater. The study results showed good stability of the Zeolite nanoparticles in NaCl solution that has a concentration of 0.14 wt%, however Zeolite nanoparticles will destabilize at higher concentrations of NaCl. Divalent salts that exist in seawater (i.e. MgCl2 and CaCl2) were also tested. The Zeolite nanoparticles were found to be destabilized even at very low concentrations of these salts. In the current work, we added surfactants to seawater to help in stabilizing the Zeolite nanoparticles. After initial screening of several surfactants, Polyvinylpyrrolidone (PVP) showed to be the best candidate to stabilize Zeolite nanoparticles in seawater. Experiments were then carried out using Zeolite nanoparticles plus (PVP) all dispersed in seawater. The effect of this dispersant on interfacial tension (IFT) was investigated where results revealed decrease in IFT values. The dispersant was shown also to change the wettability to more water wet condition which was due to the Zeolite nanoparticles, as a dispersant of only seawater and (PVP) was tested and found to not alter the wettability.