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A study of microemulsion viscosity with consideration of polymer and co-solvent additivesDashti, Ghazal 22 July 2014 (has links)
With the dramatic increase in the worldwide demand for the crude oil and with the fact that the oil and gas resources are depleting, the enhanced oil recovery process plays an important role to increase the production from the existing hydrocarbon reservoirs. Chemical enhanced oil recovery is one of the most important techniques to unlock significant amount of trapped oil from oil reservoirs. Surface agent materials (Surfactants) are used to lower the interfacial tension (IFT) between water and oil phases to ultralow values and mobilize the trapped oil. When surfactant, water, and oil are mixed together they form a thermodynamically stable phase called microemulsion which can be characterized by ultralow interfacial tension and the ability to solubilize both aqueous and oil compounds. Another characteristic of microemulsion solution is its viscosity which plays an important role in the creation and movement of the oil bank. The microemulsion micro-structure is complex and its viscosity is difficult to predict. Various viscosity models and correlations are presented in the literature to describe microemulsion viscosity behavior, but they fail to represent the rheological behavior of many microemulsion mixtures. Most of these models are valid in the lower and higher ranges of solute where one of the domains is discontinuous. The majority of the models fail to calculate the rheology of microemulsion phase in bicontinuous domains. In this work, we present a systematic study of the rheological behavior of microemulsion systems and the effect of additives such as polymer and co-solvent on rheological properties of microemulsions. Several laboratory experiments were conducted to determine the rheological behavior of surfactant solutions. A new empirical model for the viscosity of microemulsion phase as a function of salinity is introduced. The model consists of three different correlations one for each phase type of Windsor phase behaviors. The proposed model is validated using a number of experimental results presented in this document. The proposed viscosity model is implemented in the UTCHEM simulator and the simulator results are compared with the coreflood experiments. Excellent matches were obtained for the pressure. We further improved the proposed viscosity model to incorporate the effect of polymer and co-solvent on the microemulsion viscosity. / text
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Experimental investigation of the effect of increasing the temperature on ASP floodingWalker, Dustin Luke 20 February 2012 (has links)
Chemical EOR processes such as polymer flooding and surfactant polymer flooding must be designed and implemented in an economically attractive manner to be perceived as viable oil recovery options. The primary expenses associated with these processes are chemical costs which are predominantly controlled by the crude oil properties of a reservoir. Crude oil viscosity dictates polymer concentration requirements for mobility control and can also negatively affect the rheological properties of a microemulsion when surfactant polymer flooding. High microemulsion viscosity can be reduced with the introduction of an alcohol co-solvent into the surfactant formulation, but this increases the cost of the formulation. Experimental research done as part of this study combined the process of hot water injection with ASP flooding as a solution to reduce both crude oil viscosity and microemulsion viscosity. The results of this investigation revealed that when action was taken to reduce microemulsion viscosity, residual oil recoveries were greater than 90%. Hot water flooding lowered required polymer concentrations by reducing oil viscosity and lowered microemulsion viscosity without co-solvent. Laboratory testing of viscous microemulsions in core floods proved to compromise surfactant performance and oil recovery by causing high surfactant retention, high pressure gradients that would be unsustainable in the field, high required polymer concentrations to maintain favorable mobility during chemical flooding, reduced sweep efficiency and stagnation of microemulsions due to high viscosity from flowing at low shear rates. Rough scale-up chemical cost estimations were performed using core flood performance data. Without reducing microemulsion viscosity, field chemical costs were as high as 26.15 dollars per incremental barrel of oil. The introduction of co-solvent reduced chemical costs to as low as 22.01 dollars per incremental barrel of oil. This reduction in cost is the combined result of increasing residual oil recovery and the added cost of an alcohol co-solvent. Heating the reservoir by hot water flooding resulted in combined chemical and heating costs of 13.94 dollars per incremental barrel of oil. The significant drop in cost when using hot water is due to increased residual oil recovery, reduction in polymer concentrations from reduced oil viscosity and reduction of microemulsion viscosity at a fraction of the cost of co-solvent. / text
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