The CO2 flooding is a proven enhanced oil recovery technique to obtain high oil recovery from complicated formations and can be applied to various types of oil reservoirs. It can be injected as immiscible or miscible flooding but immiscible flooding is less effective than miscible flooding. Two types of miscibility can occur: first contact miscibility and multiple contact miscibility. First contact miscibility happens when a single phase is formed when CO2 is mixed with the crude oil. Multiple contact miscibility occurs when miscible conditions are developed in situ, through composition alteration of the CO2 or crude oil as CO2 moves through the reservoir. The miscible flooding process involves complex phase behavior, which depends on the temperature, pressure and fluid properties of the oil reservoir. The CO2 increases oil recovery by oil swelling, reduction of oil viscosity and density, the acidization of carbonate formations and miscibility effects. Multiple-contact miscibility between the injected CO2 and oil can be achieved at pressures above the minimum miscibility pressure (MMP). MMP is the pressure at which the reservoir fluid develops miscibility with CO2 and is a very important parameter in a well-designed CO2 flood project. Some reservoirs are considered tight because of poor rock or fluid characteristics. The main objective of this study is to investigate the performance of CO2 miscible flooding in tight oil reservoirs. This includes determination of minimum miscibility pressure (MMP) involving carbon dioxide and crude oil and miscible CO2 core flooding. This paper addresses the results of CO2 miscible flooding applied to a known reservoir. Several CO2 miscible flooding experiments were conducted using live oil at reservoir temperature and pressure above the MMP on composite cores of known reservoir. The MMP was determined experimentally using the slim tube. High oil recovery from these experiments indicates that the MMP determined from slim tube studies was correct and such a high recovery is only possible if full miscibility occurs during the displacement. The analytical correlation also gave a MMP consistent with MMP determined from slim tube experiments. Introduction Certain reservoirs have been classified "tight" at the time of their discovery, simply because of poor reservoir characteristics. The exploitation of these reservoirs was judged uneconomical at that time because of their low production rate. In fact, the decision whether to produce or not from a reservoir that has been judged "tight" depends not only on the economical context at the time this decision is taken but also on the state of technology prevalent at the time of this decision. It is natural that any change in the price of oil, or any breakthrough in technology especially in drilling, production engineering and enhanced oil recovery can affect significantly the feasibility of developing these tight reservoirs. Reservoirs that have been judged tight on the basis of thirty year old technology may become economical when modern recovery techniques are applied. Both the economical context and the state of new technologies in the domain of enhanced oil recovery, drilling and production engineering have a significant effect on the feasibility of developing these reservoirs.

Formation damage due to fines migration is a threshold type process in that there exists a critical condition at which a petroleum reservoir is susceptible to formation damage. This paper presents a physical model for predicting the critical condition for particle deposition based on experimental data and trajectory analysis. Suspensions (bentonite, kaolinite) were passed through a capillary (100 m) at a controlled flow rate and at the same time, pressure drop across the capillary was monitored. Based on the log jam effect a criterion is proposed to predict the critical condition for particle deposition in porous media. Introduction Petroleum reservoirs contain particles of loose solid materials in the pore surfaces. These particles, often called fines, are not held physically in place by natural cementing material that binds larger sand grains together, instead they are individual particles located at the interior surfaces of the porous matrix. Thus, these particles are free to migrate through the pores along with the fluids that flow in the reservoir. The migration or movement of fines in a sandstone reservoir is usually triggered by the contact of the formation with an incompatible fluid. During migration, these fines are not carried all the way through the formation by the fluids, instead they concentrate at pore restrictions. If certain conditions are met, these particles bridge pore restrictions which leads to pore plugging and a large reduction in permeability. Numerous experimental studies have been conducted on core plugs to understand the factors controlling the migration of the fines in a porous medium (Muecke, 1979; Gruesbeck and Collins, 1982; Egbogah, 1984; Sarkar and Sharma, 1988; O'melia and Stum, 1967, Gabriel and Inamdar, 1983, Rahman et al., 1994). Although a quantitative assessment cannot be made based on core analysis, it is, however, recognised that deposition of fines at pore restrictions largely depends on: particle to pore size ratio, concentration of particles, fluid flow rate, ionic activity of pore fluids and fluid phases present in pores. P. 181^

Carbon dioxide flooding process has been a proven valuable tertiary enhanced oil recovery technique. Although the petroleum industry has been applying the technique to produce heavy oil, it can be an effective tool to yield appreciable recoveries from complicated formations to produce comparatively lighter oil. The focus of experimental studies has been on the production of heavy oil and Carbon dioxide application to a wide range of other geological conditions and for wide range of petroleum fluids has been a less traversed path. Especially the process can be applied to tight formations where normal production procedures are not economically viable. This unviability may be due to rock or rock-fluid interactive properties. A research program for evaluation of the feasibility of development of such tight formations in the Middle East has been initiated. The research work included determination of minimum miscibility pressure (MMP), CO2 Core flooding and phase behavior investigation. Since both these processes are governed by the phase behavior; an investigation of phase behavior and PVT properties of reservoir fluids when combined with carbon dioxide are an integral part for a complete evaluation of crude oil extraction process. This paper presents the experimental and simulated phase behavior data for various mixtures of a live crude oil and carbon dioxide. The data helped in designing of the slim tube investigations and core flooding experiments. The phase behavior during a CO2 flooding is a very complex process. Three mechanisms; oil swelling, reduction of oil viscosity, and the acidization of carbonate help obtaining better recovery in a CO2 flooding process. First two are the mechanisms boosting the miscibility between CO2 and reservoir oil. The other parameters which effect phase behavior during a CO2 flooding are the temperature, pressure and rock-fluid interactive properties of the reservoir. Carbon dioxide can be first contact miscible with crude oils, but usually at very high pressure. Attaining and operating a flooding process at these pressures is not financially desirable. Multi contact miscible process is preferred as the economical process for the carbon dioxide flooding. The phase behavior of the original oil and after addition of different amounts of CO2 was studied by performing Constant Composition Expansion (CCE) tests. The bubble point pressure determined for the original oil sample and with increasing carbon dioxide. The phase behavior properties like bubble point pressure amount of liquid for the mixture with carbon dioxide range matched well with Equation of State (EOS) simulations. A comparison of the average density of the crude oil CO2 mixtures confirmed the swelling process. A material balance study between the injected and produced material from the core was also done for verification.

A model is proposed to predict the increase in pressure drop in a micro‐capillary due to the particle deposition. Collection efficiency was estimated from three‐dimensional (3D) trajectory analysis which is based on mass balance and considers dispersion forces (London‐van der Waals), hydrodynamic forces (gravity and drag), and electrical force (electrical double layer). An exponential function introduced to 3D trajectory analysis accounts for the effects of fluid velocity on the particle capture probability. Validity of the model is tested experimentally by circulating a 1000 ppm bentonite suspension at different flow rates through a micro‐capillary of diameter 100 μM. Experimental evidence indicates that the 3D trajectory analysis is limited to a few conditions of particle deposition in a micro‐capillary.

Super-Critical CO 2 flooding combined with surfactants is one of the latest methods being used for Enhanced Oil Recovery. This overcomes the shortcomings associated with CO 2 gas injection like gravity override and viscous fingering to an appreciable extent. It restricts the mobility of the injected fluid leading to higher contact with the resident crude resulting in better sweep efficiency. A number of surfactants have been tested with CO 2 to appraise performance in different scenarios. However there have been problems of surfactant instability at real reservoir conditions i.e. at high temperature and high salinity. Adsorption of surfactants on the rock surface is another issue that usually decreases the effectiveness of the system.In the core-flood experiments performed in this work, an amine oxide-based amphoteric fluorosurfactant has been injected with super critical CO 2 for the first time on foot long carbonate cores saturated with high saline formation water (Total Dissolved Solids > 200,000 ppm). High temperature (90°C) and pressure (2500 psi) were applied coupled with 5 days of aging time with reservoir crude to recreate actual reservoir environment. Different injection strategies were studied including coinjection of super-critical CO 2 and surfactant solution, and alternating injection of super-critical CO 2 and surfactant solution in different ratios, and then compared to find out the optimum injection strategy.Results from the study exhibit a significant increase in the oil recovery due to this CO 2 -surfactant system as well as foam generation in high saline environment for the co-injection scheme.This research provides a new and viable option for CO 2 -Surfactant flooding especially for high salinity carbonate reservoirs. It displays the usefulness of the surfactant even at very low concentrations, thus mitigating the high cost of this type of surfactants. Furthermore, this surfactant does not contain environment harmful substances making it a greener substitute to conventional hydrocarbon surfactants.