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A considerable portion of current world oil production comes from mature fields and the rate of replacement of the produced reserves by new discoveries has been declining steadily over the last few decades. To meet the growing need for economical energy throughout the world, the recoverable oil resources in known reservoirs that can be produced economically by applying advanced IOR and EOR technologies will play a key role in meeting the energy demand in years to come. This paper presents a comprehensive review of EOR projects. Specifically, the paper presents an overview of EOR field projects by reservoir lithology (sandstone, carbonate, and turbidite formations) and offshore versus onshore fields. More than 1,500 field projects are reviewed and summarized to evaluate feasibility of EOR technologies. Another area of growing interest is the combination of near-well-bore and in-depth conformance technologies with chemical EOR technologies such as SP and ASP. However, these are in early stages of evaluation. Examples of numerical simulations combining chemical conformance and EOR technologies are presented showing the potential of this recovery strategy in waterflooded reservoirs. Impacts of carbon capture cost and volatility of oil and carbon-credit markets on CO2-EOR projects based on anthropogenic sources is also addressed. Based on this review, it is evident that thermal and chemical EOR projects dominate in sandstone formations while gas and water-based recovery methods dominate carbonate, turbidite, and offshore fields. The review also shows the growing trend of CO2 (from natural sources), high-pressure air injection (HPAI), and chemical flooding including in-depth conformance field projects in the U.S. and abroad. CO2-EOR / sequestration in offshore fields and chemical EOR processes offshore (e.g., polymer-based methods) and onshore, including heavy crude oil reservoirs, are some of the opportunities identified for the next decade based on preliminary evaluations and proposed or ongoing pilot projects. The critical review will help to identify the next challenges and opportunities in EOR. Hybrid schemes combining IOR/EOR as well as CO2-EOR/sequestration can be ranked on the basis of adequate simulation procedures.

Surfactant-polymer (SP) flooding is an enhanced oil recovery (EOR) technique used to mobilize residual oil by lowering the oil-water interfacial tension, micellar solubilization, and lowering the displacing phase mobility to improve sweep efficiency. Surfactant-polymer flooding, also known as micellar flooding, has been studied both in the laboratory and field pilot tests for several decades. Surfactant polymer flooding is believed to be a major enhanced oil recovery technique based on laboratory experiments; however, its applications to field has not met the expectations of laboratory results. Successful field applications of SP flooding have been limited because of a number of obstacles, which include the large number of laboratory experiments required to design an appropriate SP system, high sensitivity to reservoir rock and fluid characteristics, complexity of reservoirs, infrastructure required for field implementation, and lack of reliable statistics on successes of field applications. In other words, there are many variables that affect reservoir performance. Traditionally, in SP flooding, a tapered polymer solution follows the injected surfactant slug. However, in recent years co-injection of surfactant and a relatively high concentration of polymer solution have been used in several field trials. Despite significant increase in oil recovery at early times in several surfactant-polymer floods, the increase in oil production period has had short duration followed by significant reduction in oil production. Thus, this research primarily relied on field test data to understand the problem, hoping that an improved solution strategy can be developed for new field applications. Second, current numerical models do not correctly predict the performance of surfactant-polymer floods and tend to over predict. Thus the second objective of this research was to develop a methodology to use combined field and laboratory data in commercial simulators to improve their predictive capability. iv TABLE OF CONTENTS

Enhanced-Oil Recovery (EOR) for asset acquisition or rejuvenation involves intertwined decisions. In this sense, EOR operations are tied to a perception of high investments that demand EOR workflows with screening procedures, simulation and detailed economic evaluations. Procedures have been developed over the years to execute EOR evaluation workflows.We propose strategies for EOR evaluation workflows that account for different levels of available information. These procedures have been successfully applied to oil property evaluations and EOR applicability in a variety of oil reservoirs. The methodology relies on conventional and unconventional screening methods, emphasizing identification of analogues to support decision making. The screening phase is combined with analytical or simplified numerical simulations to estimate full-field performance while maintaining rational reservoir segmentation procedures. This paper fully describes the EOR decision-making procedures using field case examples from Asia, Canada, Mexico, South America and the United States. The type of assets evaluated includes a spectrum of reservoir types, from oil sands to light oil reservoirs. Different stages of development and information availability are discussed. Results show the advantage of flexible decision-making frameworks that adapt to the volume and quality of information by formulating the correct decision problem and concentrate on projects and/or properties with apparent economic merit.Our EOR decision-making approaches integrate several evaluation tools, publicly or commercially available, whose combination depends on availability and quality of data. The decision is laid out using decision-analysis tools coupled with economic models and numerical simulation. This allows integrated teams to collaborate in the decision making process without over-analyzing the available data. One interesting aspect is the combination of geologic and engineering data, minimizing experts' bias and combining technical and financial figures of merit rationally. The proposed methodology has proved useful to screen and evaluate projects/properties very rapidly, identifying whether or not upside potential exists.

This paper presents an analytical study of transient flow into multiple vertical wells producing from a porous media containing randomly distributed discrete fractures. The model may be used to analyze the production and well test data from tight gas sands and Austin chalk type reservoirs. Both vertical openholes and hydraulically fractured vertical wells are considered. Wells and fractures are randomly distributed. The model dynamically couples the multiple fracture flow models with an analytical reservoir flow model. The analytical model simulates pressure and pressure derivative characteristics of wells and flow distribution along and through both the natural and hydraulic fractures. The study shows that single or multiple isolated fractures yield negative pseudoskin factors in vertical wells near isolated fractures. The negative pseudoskin factor in un-stimulated wells has also been observed in field tests. The negative pseudoskin factor is a function of fracture conductivity, fracture density, length, distance from the wellbore, and azimuth. Using the model, we demonstrate that the shape of pressure derivative is related to fracture distribution. However, the wellbore pressure derivative response is controlled by the fractures in the near wellbore region. The result of this study indicate that the conventional analysis, based on the double porosity model such as the Warren and Root model, to predict the storativity ratio of a naturally fractured system is not reliable. Also, the displacement between two semilog straight lines is not necessarily a good indicator of the storativity ratio. Introduction Naturally fractured reservoirs may be classified as extremely heterogeneous porous media. Modeling the fluid flow in naturally fractured reservoirs has been one of the most challenging topics in the petroleum industry throughout years. There are many naturally fractured reservoirs all around the world. A significant part of the known hydrocarbon reserves are in naturally fractured porous rocks. Therefore, building realistic models representing naturally fractured reservoirs are of vital importance to maximize hydrocarbon recovery from such reservoirs. The main focus of this study is to develop an analytical model to simulate the flow inside a homogenous porous media containing randomly distributed and unconnected fractures. Once such a model is available, the effect of isolated fractures on the pressure transient behavior of producing wells may be investigated. In the current literature, only a few analytical studies focus on the effect of stochastically distributed natural fractures on well performance. To the best of our knowledge, the literature lacks a model to simulate the transient flow towards a system of vertical openholes and hydraulically fractured wells producing from a porous media dissected by randomly distributed but disjointed natural fractures. This study offers such a model to investigate the effect of multiple isolated fractures on wellbore pressure. Literature Review The model presented in this study could be used to simulate the flow behavior in an infinite reservoir that contains naturally fractures, hydraulically fractured wells, and vertical openholes. Therefore, a summary of the current literature on each subject is presented. The literature review is divided into five different sections; multiple vertical well models, dual porosity models, hydraulic fracture models, single isolated natural fracture model, and discreet fracture network models. Multiple Vertical Well Models. The available literature on this subject is too extensive; hence, we just refer to only a few studies. Several researchers have presented flow models for multiple vertical wells producing from a common reservoir. The researchers have investigated the pressure response and inflow performance of a multiple well system in infinite and finite homogenous formations.1–7 The interference between wells in closed and infinite reservoirs have also been examined. Most of the publications concentrate on the calculation of the productivity of a multi-well system, the drainage area for each well, and the analysis of transient pressure data.3–7 Rodriguez and Cinco-Ley 1 presented a two-dimensional analytical solution for multiple vertical wells producing from closed-boundary reservoirs. Their model predicts the production performance of multiple wells producing at constant bottomhole pressure.

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