Innovative techniques are highly required in the O&G industry to meet the future demand of the hydrocarbon fuels, significant efforts have been exerted on the development of new innovative technologies to increase the oil recovery. Nanotechnology has provided new promising approaches to enhanced oil recovery (EOR) techniques in old and marginal fields. Nanoparticles have been developed for various applications in reservoir engineering and EOR fields. Using nanoparticles for EOR applications refers to their small size compared to the pore throat sizes; therefore, they could easily move into porous rocks without severe influence on permeability. The applications of nanoparticles to enhance the oil recovery can be summarized in three approaches; Nanocatalysts, Nanoemulsions, and Nanofluids. In this paper, the different possible displacement mechanisms of the nanofluids are discussed.
When petroleum reservoirs are depleted by primary recovery mechanisms only small fractions are produced (5-30%). Implementing a secondary recovery, water flooding, would still not produce all the recoverable oil present in the reservoir due to a poor sweep efficiency as the result of bypassed or upswept oil. Use of polymer flooding increases water viscosity which controls water mobility thus improving the sweep efficiency, thus increasing the recovery factor. Many successful polymer projects have increased recoveries of 3-10%.This paper presents a case study to investigate the effectiveness of polymer and surfactant flood in Offshore Egyptian Field. This field is located in the Gulf of Suez, and the reservoir is sandstone formation with active water aquifer and has very high permeability in the order of few Darcies. The reservoir contains medium quality crude having viscosity of 17.5 -24 cp with mobility ratio of 22 -49 which makes it a good candidate for polymer flooding especially the reservoir has high residual oil saturation.The objective of this paper is to present an extensive review of the polymer flooding literature and what constitutes a successful polymer flood project worldwide.We performed a reservoir simulation study to investigate the effect of different parameter on the polymer flooding performance using a sector model of the field. Parameters such as polymer type, polymer solution viscosity, polymer slug size, and slug concentration will be studied to come with different scenarios for evaluation and optimization of the polymer flooding pilot. This will be a key to evaluate the polymer flooding technique in the early stage of oilfield development.Results of this paper, will present the methodology needed to design a polymer and surfactant flooding project and it will provide the steps and data needed from the core lab (related to the rock qualities) and fluid lab to calibrate and have representative reservoir simulation sensitivity runs to optimize the design. This paper will focus on a case study from North Africa to implement offshore polymer flooding.
Hydraulic fracturing allows numerous, otherwise unproductive, low permeability hydrocarbon formations to be produced. The interactions between the fractures and the heterogeneous reservoir rock, however, are quite complex, which makes it quite difficult to model production from hydraulically-fractured systems. Various techniques have been applied in the simulation of hydraulically fractured wells using finite difference simulators most of these techniques are limited by the gnd dimensions and computing time and hardware restrictions. Most of the current analytical techniques assume a single rectangular shaped fracture m a single phase homogeneous reservoir, the fracture is limited to the block size and the fracture properties are adjusted using permeability multiplier. The current work demonstrates how to model these systems with a smaller grid block size which allows you to apply sensitivity to the fracture length and model the fracture with enhanced accuracy. It also allows you to study the effect of reservoir heterogeneity on the fractured well performance. It is proposed to apply amalgam LGR technique to decrease the grid size to the dimensions of the hydraulic fracture without dramatically increasing the number of gnd blocks which would cause a great increase in the computing time and the model size with no added value. This paper explains how the amalgam LGR is designed and compares between standard LGRs and the proposed design and a case study is presented from an anonymous field in Egypt to illustrate how to use this technique to model the hydraulically fractured well. The simulation model is matched to available production data by changing fracture lengths. Then the model is used to predict future response from the wells. The advantage of this technique is that it allows hydraulically fractured reservoirs to be modeled with less grid size which will lead to more realistic models and more accurate predictions: however, the most usefid application of this technique may come in the fracture modeling stage. With this tool, various fracture geometries and scenarios can be tested in the simulator, and the most economic scenarios selected and implemented. This will cause better fracture placement, and ultimately greater production.
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