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The rheological behavior of a polymer solution is very important for its application in enhanced oil recovery. An experimental study was conducted to examine the effects of salts, alkali, and surfactants on the rheological properties of partially hydrolyzed polyacrylamide (PHPAM) over a wide range of parameters. The experimental results show that addition of ionic species significantly reduces the polymer viscosity by reducing the hydrodynamic size of the polymer. The power-law model was used to describe the rheological properties of the solutions. The flow behavior index, n, of the samples was in the range from 0.232 to 0.275, while the consistency index, K, ranged from (1.45 to 5.76) Pa • s n . The variation of viscosity with temperature was also studied and found to satisfy the Arrhenius equation.

In order to reduce the permeability to water or brine, there is a possibility of polymer injection into the reservoir. In the present work, special focus has been paid in polymer [partially hydrolyzed polyacrylamide (PHPA)] injection as a part of chemical method. Tests were conducted in the laboratory at the ambient temperature to examine the reduction in permeability to water or brine in the well-prepared sand packed after the polymer injection. The experiments were performed to study the effect of polymer adsorption on permeability reduction by analyzing residual resistance factor values with different concentrations of polymer solutions. The rheological behavior of the polymer has also been examined. The experimental results also indicate that the adsorption behavior of polymer is strongly affected by salinity, solution pH, and polymer concentration. To investigate the effect of polymer adsorption and mobility control on additional oil recovery, polymer flooding experiments were conducted with different polymer concentrations. It has been obtained that with the increase in polymer concentrations, oil recovery increases.

The merits of CO 2 capture and storage to the environmental stability of our world should not be underestimated as emissions of greenhouse gases cause serious problems. It represents the only technology that might rid our atmosphere of the main anthropogenic gas while allowing for the continuous use of the fossil fuels which still power today's world. Underground storage of CO 2 involves the injection of CO 2 into suitable geological formations and the monitoring of the injected plume over time, to ensure containment. Over the last two or three decades, attention has been paid to technology developments of carbon capture and sequestration. Therefore, it is high time to look at the research done so far. In this regard, a high-level review article is required to provide an overview of the status of carbon capture and sequestration research. This article presents a review of CO 2 storage technologies which includes a background of essential concepts in storage, the physical processes involved, modeling procedures and simulators used, capacity estimation, measuring monitoring and verification techniques, risks and challenges involved and field-/pilot-scale projects. It is expected that the present review paper will help the researchers to gain a quick knowledge of CO 2 sequestration for future research in this field. Keywords CO 2 storage • Geological formation • Modeling for CO 2 storage • Mechanism of CO 2 storage • CO 2 storage projects Edited by Yan-Hua Sun

In the present paper the effect of salinity and different surfactants on interfacial tension (IFT) between crude oil and water has been investigated. Three different types of surfactants like anionic (sodium lauryl sulfate [SLS]), cationic (hexadecyltrimethylammonium bromide [HTAB]), and nonionic surfactants such as Tergitol 15-S-7, Tergitol 15-S-9, and Tergitol 15-S-12, respectively, have been used in this study. Improved efficiency of IFT reduction using a salt and surfactant mixture has been verified by measuring the IFT between oil and water. The synergism of salt and surfactant mixture on the reduction of IFT has been observed. A series of flooding experiments have been conducted to justify the effects of lowering interfacial tension and adsorption behavior of surfactants on additional oil recovery. It has been found that the additional oil recovery increases up to 24 % of the original oil in place (OOIP) when a surfactant and salt mixture has been used as the displacing fluid.

The trend of growing interest in alternative source of energy focuses on renewable products worldwide. However, the situation of petroleum industries in many countries needs much concern in improving the oil recovery technique. Chemical method, especially microemulsion flooding, plays an important role in enhanced oil recovery technique due to its ability to reduce interfacial tension between oil and water to a large extent as well as alter wettability of reservoir rocks. Surfactant-based chemical systems have been reported in many academic studies and their technological implementations are potential candidates in enhanced oil recovery activities. This paper reviews the role of different types of surfactants in enhanced oil recovery, structure of microemulsion, phase behavior of oil-brine-surfactant/cosurfactant systems with variation of different parameters such as salinity, temperature, pressure and physicochemical properties of microemulsions including solubilization capacity, interfacial tension, viscosity and density under reservoir conditions. The enhanced oil productivity by microemulsion flooding with different surfactant/cosurfactant systems has also been discussed in this paper. This review introduces a new opening in enhanced oil recovery by microemulsion flooding with some new aspects.

Foam and surface tension behaviors of different ionic/nonionic surfactant solutions along with their different combinations have been investigated. Among different surfactants, sodium dodecyl sulfate showed the highest foamability over other surfactants. Mixed surfactant systems were always found to have higher foamability than the individual surfactant. It was also noticeable that nonionic surfactants show good foamability when they combine with anionic and cationic surfactants. In the case of mixed surfactant systems, nonionic/cationic surfactant mixtures showed lower surface tension than nonionic/anionic surfactant mixture due to a synergistic effect.