Enhanced oil recovery (EOR) processes have a great potential to maximize oil recovery factor of the existing reservoirs, where a significant volume of the unrecovered oil after conventional methods is targeted. Application of chemical EOR techniques includes the process of injecting different types of chemicals into a reservoir to improve the overall sweep efficiency. Surfactant flooding is one of the chemical EOR used to reduce the oil–water interfacial tension and to mobilize residual oil toward producing wells. Throughout the process of surfactant flooding, selecting a suitable surfactant for the reservoir conditions is quite challenging. Surfactants tend to be the major factor associated with the cost of an EOR process, and losing surfactants leads to substantial economic losses. This process could encounter a significant loss of surfactant due to adsorption into the porous media. Surfactant concentration, salinity, temperature, and pH were found to be as the main factors that influence the surfactant adsorption on reservoir rocks. Most of the research has been conducted in low-temperature and low-salinity conditions. Only limited studies were conducted in high-temperature and high-salinity (HT/HS) conditions due to the challenging for implementation of surfactant flooding in these conditions. This paper, therefore, focuses on the reviews of the studies conducted on surfactant adsorption for different surfactant types on different reservoir rocks under different reservoir conditions, and the influence of surfactant concentration, salinity, temperature, and pH on surfactant adsorption.

Introduction: Fluid transport through reservoir rocks is complex and cannot be described by theory alone. Darcy's law, an empirical equation describing the laminar flow of incompressible fluids, is largely used for calculation of fluid flow through porous media. It relates the macroscopic velocity (flux) of a fluid of known viscosity to the pressure gradient by a proportionality factor called absolute permeability, expressed in darcies. Permeability is a measure of the ability of porous materials to Permeability is a measure of the ability of porous materials to conduct flow and is dictated by the geometry of the pore network. Generally, the fluid flow in hydrocarbon reservoirs involves more than one fluid, in which case the ability of each fluid to flow is reduced by the presence of other fluids. Darcy's equation has been extended to such situations using the concept of effective permeability, which is the apparent permeability of a fluid at a given saturation. The sum of the permeability of a fluid at a given saturation. The sum of the effective permeabilities for all phases is less than the absolute permeability because of the interference between fluids that permeability because of the interference between fluids that share the same channels. The effective permeability to a fluid becomes zero while its saturation is finite because the fluids become discontinuous at low saturations. Another useful concept in describing the flow of multiphase systems is relative permeability, which is defined as the ratio of the effective permeability of a fluid to the absolute permeability of the rock. Relative permeability has a first-order permeability of the rock. Relative permeability has a first-order dependency on saturation level. However, many interstitial fluid distributions are possible for each level of saturation, depending on the direction of saturation changes. Thus, values of relative permeability vs. saturation obtained for drainage (reduction of wetting-phase saturation) may be different from those for imbibition (increase in wetting-phase saturation). This phenomenon is called hysteresis. phenomenon is called hysteresis. Fig. 1 shows a typical plot of two-phase relative permeability vs. saturation. It is also helpful to present such permeability vs. saturation. It is also helpful to present such plots on a semilog scale to expand the relative-permeability plots on a semilog scale to expand the relative-permeability characteristics near the endpoint saturations. Relative-permeability data are essential for almost all calculations of fluid flow in hydrocarbon reservoirs. The data are used in making engineering estimates of productivity, injectivity, and ultimate recovery from reservoirs for evaluation and planning of production operations and also can be used to diagnose formation damage expected under various operational conditions. These data are unquestionably one of the most important data sets required in reservoir simulation studies. Laboratory Determination of Effective Permeability and Relative Permeability Permeability and Relative Permeability Steady-state methods for determining permeabilities have the widest application and greatest reliability because the capillary equilibrium prevails, the saturation is measured directly, and the calculation scheme is based on Darcy's law. Unsteady-state techniques present many uncertainties in calculation schemes. Operational constraints connected with use of viscous ohs and high injection rates diminish the role of capillarity such that the influence of wettability cannot always be manifested. Following is a description of both methods. Steady-State Techniques.: The most reliable relative-permeability data are obtained by steady-state methods in which two or three fluids are injected simultaneously at constant rates or pressure for extended durations to reach equilibrium. The saturations, flow rates, and pressure gradients are measured and used in Darcy's law to obtain the effective permeability for each phase. Conventionally, curves of relative permeability for each phase. Conventionally, curves of relative permeability vs. saturation are obtained, in a stepwise fashion, permeability vs. saturation are obtained, in a stepwise fashion, by changing the ratio of injection rates and repeating the measurements as equilibrium is attained. Saturation changes are controlled to be unidirectional (i.e., imbibition or drainage) to avoid hysteresis. The steady-state methods are inherently time-consuming because equilibrium attainment may require several hours or days at each saturation level. In addition, these methods require independent measurement of fluid saturations in the core. Their advantages are greater reliability and the ability to determine relative permeability for a wider range of saturation levels. The steady-state methods include the Hassler method, single-sample dynamic, stationary phase, Penn State, and modified Penn State. They vary in the method of establishing capillary equilibrium between fluids and reducing or eliminating end effects. Further details of these methods are provided in subsequent sections. provided in subsequent sections. Unsteady-State Techniques. The quickest laboratory methods of obtaining relative-permeability data are unsteady-state techniques. In these techniques, saturation equilibrium is not attained; thus, an entire set of relative-permeability vs. saturation curves can be obtained in a few hours. A typical run involves displacing in-situ fluids by constant-rate (or constant-pressure) injection of a driving fluid while monitoring the effluent volumes continuously. The production data are analyzed, and a set of relative-permeability curves is obtained using various mathematical methods. The Buckley-Leverett equation for linear displacement of immiscible and incompressible fluids is the basis for all analyses. This equation relates the saturation levels, at each point and time, to capillary...

Polymer flooding is an important enhanced oil recovery technology introduced in field projects since the late 1960s. The key to a successful polymer flood project depends upon proper estimation of polymer retention. The aims of this paper are twofold. First, to show the mechanism of polymer flooding and how this mechanism is affected by polymer retention. Based on the literature, the mobility ratio significantly increases as a result of the interactions between the injected polymer molecules and the reservoir rock. Secondly, to provide a better understanding of the polymer retention, we discussed polymer retention types, mechanisms, factors promoting or inhibiting polymer retention, methods and modeling techniques used for estimating polymer retention.

Surfactants have been successfully used for enhanced or improved oil recovery in reservoirs having mild conditions (low temperature, low salinity). Reservoirs having harsh conditions, however, offer unique challenges in that most surfactants precipitate and chemically degrade due to a combined effect of high temperature and hardness salinity. Industry’s efforts are continuing to develop or formulate surfactants for oil recovery applications to high temperature and salinity. The aim of this study was to evaluate several modified anionic surfactants/formulations that were claimed to be able to overcome the unfavorably high-salinity brine (sea water) and high temperature and to understand the impact of high temperature to surfactant adsorption. A series of experiments were conducted to characterize and quantify the effects of aging time in high temperature (106 °C) and seawater salinity (32,000 ppm with 1600 hardness) on surfactant performance. Results for both sulfate- and sulfonate-based surfactants were deemed not to be satisfactory. Sulfate-based surfactants encountered hydrolysis problem at high temperature, whereas sulfonate-based surfactants precipitated in the presence of divalent ions. This study then focused on alkyl ether carboxylate (AEC) as the main surfactant, and blends of AEC with alkyl polyglucoside (APG). To find the optimum conditions, phase behavior tests were performed with a fixed seawater salinity but with different blending ratios of surfactant and co-surfactant, as well as overall surfactant concentrations, similar to the salinity scan. Type III microemulsion was observed for both surfactant solutions of AEC and AEC–APG blend with IFT of 10⁻³ mN/m (millinewton/meter). Surfactant adsorption resulted in lower adsorption in the high-temperature region. The results of this project are urgently needed by the industry for future screening in order to find suitable surfactants for applying to reservoirs with harsh conditions. The study also intends to provide an understanding of adsorption relationship to high temperature, as a guideline in addressing surfactant losses due to adsorption at high-temperature field application.