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Due to capillary pressure, reservoir heterogeneity, oil mobility, and lack of reservoir energy, typically more than 50 % of the original oil in place is left in the reservoir after primary and secondary recovery oil production. With relatively easy-to-get conventional oil resources diminishing and the price of oil hovering around triple digits, enhanced oil recovery methods, such as polymer flooding, have become very attractive ways to recover oil effectively from existing reservoirs. Enhanced oil recovery methods can be categorized into three categories: water or chemical based, gas based, and thermal based. This thesis will focus on the chemical injection of surfactants, alkali, and polymer of the water based methods. Surfactants are used to alter the interfacial tension of the aqueous and oleic phases in order to facility oil production. Alkali chemicals are used to create surfactants by reacting with acidic oil. And polymer is used to reduce injection water mobility to effectively displace the contacted oil in heterogeneous reservoirs by improving the volumetric and displacement sweep efficiencies. This research presents several laboratory results of polymer and alkali/surfactant/polymer core floods performed in the Center for Petroleum and Geosystems Engineering laboratories. Properties of polymer and surfactant phase behavior were measured and modeled and each coreflood was history matched with UTCHEM, a three-dimensional chemical flooding simulator. The coreflood results and the history matched model parameters were then upscaled to a pilot case for viscous oil in offshore environment with four wells in a line drive pattern. The potential of polymer flooding was investigated and several sensitivity cases were performed to evaluate the effect of various physical property parameters on oil recovery. Water salinity and hardness (i.e. amount of calcium and magnesium) has detrimental effects on polymer viscosity and its stability. The potential benefits of low salinity water injection by desalinization of seawater for polymer flood projects have been discussed in recent publications. The effect of low salinity polymer flood was also investigated. A series of sensitivity studies on well pattern and well spacing is carried out to investigate the impact on recovery factor and recovery time. / text

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No description available.

CO2 has been widely used as a displacement fluid in both immiscible and miscible displacement processes to obtain tertiary recovery from the field. There are several problems associated with the application of CO2 flooding, especially when there is a significant presence of heterogeneous elements, such as fractures, channels and high permeability streaks within the reservoir. With flooding, CO2 will finger through the target zone while leaving most of the residual/trapped oil untouched. As a result, early gas breakthrough has been a very common problem in CO2-related projects, reducing the overall sweep efficiency of CO2 flooding. This research aims at improving the CO2 flood efficiency using cross-linked gel conformance control and CO2 viscosifier technique. A series of coreflood experiment studies have been performed to investigate the possibility of applying CO2 mobility control techniques. Corresponding simulation works have also been carried out to predict the benefits of applying CO2 mobility control techniques in the field. In the laboratory study, the CO2 coreflood system was integrated with the CT (Computed Tomography)-scanner and obtained real-time coreflood images of the CO2 saturation distributions in the core. This system was applied to the research of both cross-linked polymer gel treatment and CO2 viscosifier study and produced images with sharp phase contrasts. For the gel conformance study, promising results were obtained by applying cross-linked gel to eliminate permeability contrast and diverting CO2 into low permeability regions to obtain incremental oil recovery; also studied were the gel strength in terms of leak-off extent with the aid of CT (Computed Tomography) images. For the CO2 viscosifier research, we tested several potential viscosifier chemicals and found out PVAc (Polyvinylacetate)/toluene combination to be the most promising. The follow-up study clearly demonstrates the superiority of viscosified CO2 over neat CO2 in terms of sweep efficiency. This research serves as a preliminary study in understanding advanced CO2 mobility control techniques and will provide insights to future studies on this topic.

Thesis (Ph. D.)--University of Texas at Austin, 2002. / Vita. Includes bibliographical references. Available also from UMI Company.

Polymer flooding is a commercially proven technology to enhance oil recovery from mature reservoirs. The main mechanism for improving oil recovery is to increase the viscosity of injection water by adding polymer, thereby creating a favorable mobility ratio for improved volumetric sweep efficiency. However, polymer injection brings on several potential problems: a) a high injection pressure with associated pumping cost; b) creation of unwanted injection well fractures; and c) mechanical degradation of polymers due to high shear near wellbore. The high viscosity of polymer solutions and permeability reduction by polymer retention reduce mobility, and simultaneously increase the pressure drop required for the propagation of the polymer bank. The objective of this dissertation is to develop an improved polymer injection process that can minimize the impact of those potential problems in the polymer flooding process, and to extend this application to conformance control. This objective is accomplished by utilizing the pH sensitivity of partially hydrolyzed polyacrylamide (HPAM), which is the most commonly used EOR polymer. The idea of the “low-pH polymer process” is to inject HPAM solution at low-pH conditions into the reservoir. The polymer viscosity is low in that condition, which enables the polymer solution to pass through the near wellbore region with a relatively low pressure drop. This process can save a considerable amount of pump horse power required during injection, and also enables the use of large-molecular-weight polymers without danger of mechanical degradation while injecting below the fracture gradient. Away from the near wellbore region, the polymer solution becomes thickened with an increase in pH, which occurs naturally by a spontaneous reaction between the acid solution and rock minerals. The viscosity increase lowers the brine mobility and increases oil displacement efficiency, as intended. Another potential application of the low-pH polymer injection process is conformance control in a highly heterogeneous reservoir. As a secondary recovery method, water flooding can sweep most oil from the high-permeability zones, but not from the low-permeability zones. The polymer solution under low-pH conditions can be placed deep into such high-permeability sands preferentially, because of its low viscosity. It is then viscosified by a pH increase, caused by geochemical reactions with the rock minerals in the reservoir. With the thickened polymer solution in the high permeability sands, the subsequently injected water is diverted to the low permeability zone, so that the bypassed oil trapped in that zone can be efficiently recovered. To evaluate the low-pH polymer process, extensive laboratory experiments were systematically conducted. As the first step, the rheological properties of HPAM solutions, such as steady-shear viscosity and viscoelastic behavior, were measured as functions of pH. The effects of various process variables, such as polymer concentrations, salinity, polymer molecular weight, and degree of hydrolysis on rheological properties, were investigated for a wide range of pH. A comprehensive rheological model for HPAM solutions was also developed in order to provide polymer viscosity in terms of the above process variables. As the second step, weak acid (citric acid) and strong acid (hydrochloric acid) were evaluated as pH control agents. Citric acid was shown to clearly perform better than hydrochloric acid. A series of acid coreflood experiments for different process variables (injection pH, core length, flow rate, and the presence of shut-ins) were carried out. The effluent pH and five cations (total Ca, Mg, Fe, Al, and K) were measured for qualitative evaluation of the geochemical reactions between the injected acid and the rock minerals; these measurements also provide data for future history matching simulations to accurately characterize these geochemical reactions. Finally, polymer coreflood experiments were carried out with different process variables: injection pH, polymer concentration, polymer molecular weight, salinity, degree of hydrolysis, and flow rate. The transport characteristics of HPAM solutions in Berea sandstone cores were evaluated in terms of permeability reduction and mobility reduction. Adsorption and inaccessible/excluded pore volume were also measured in order to accurately characterize the transport of HPAM solutions under low-pH conditions. The results show that the proposed “low-pH polymer process” can substantially increase injectivity (lower injection pressures) and allow deeper transport of polymer solutions in the reservoir due to the low solution viscosity. The peak pH’s observed in several shut-ins guarantee that spontaneous geochemical reactions can return the polymer solution to its original high viscosity. However, low-pH conditions increase adsorption (polymer-loss) and require additional chemical cost (for citric acid). The optimum injection formulation (polymer concentration, injection pH) will depend on the specific reservoir mineralogy, permeability, salinity and injection conditions. / text

Thesis (Ph. D.)--University of Texas at Austin, 2008. / Vita. Includes bibliographical references.

acase@tulane.edu / The objective of this research is to study the surface/interfacial phenomena via video-microscopic observation and quantification inside a micro-channel or microcapillary, which can mimic the operating conditions of practical problems, such as ink-jet, lubricant oil neutralization and enhanced oil recovery. In the second chapter, a micropipette-in-microcapillary method is described for the surface tension measurement at high temperatures, which mimics the dimension and working environment of ink-jet print head. Temperature control within the confined space of a capillary was achieved by coating the outer surface of the housing microcapillary with an electrically conductive, transparent, tin-doped indium oxide (ITO) thin film as a heating jacket. The precision of this technique was discussed according to the comparisons of our results with published reference data for water, n-hexadecane, and n-decane at both room and elevated temperatures. Traditionally, the neutralization of sulfuric acid by engine oils has been the major focus, however, due to the introduce of biofuel or ethanol the acetic acid has become an important concern. In the third chapter, based on micropipette-in-square-channel video-microscopy setup, the neutralization reaction mechanism and reaction kinetics of acetic acid by fully formulated lubricant oil is discussed. It was found that the neutralization exists simultaneously on the oil-acid-interface and bulk-oil phase during the droplet shrinkage. Besides, FTIR and NMR analysis show the neutralization of acetic acid as an instantaneous process, and almost all of the dissolved acetic acid in the bulk is eventually neutralized. Due to the minor role of acetic acid dissolution compared to the interfacial reaction, an interface-reaction-rate-controlled kinetic mechanism is proposed as approximation to describe the neutralization process at different conditions. When glacial and diluted acetic acid droplets were neutralized in fully formulated lubricant oil, the experimentally measured shrinking radius agreed very well with the mathematical model. According to Arrhenius equation, the activation energy of neutralization reaction was determined to be constant and its range (Ea>21 kJ/mol) further validated the assumption of interface-controlled reaction kinetics. In the final chapter, an oil-soluble surfactant prepared by Eni S.p.A. was studied to enhance crude oil mobilization in cryolite-packed miniature bed, which provided a transparent porous media at the microscopic level. When the porous media was imbued with crude oil, the presence of the surfactant in the oil phase was able to improve the mobilization performance of crude oil by flushing. In order to deliver the oil-soluble surfactant and apply it to the removal of crude from porous media, an SDS solution was used to solubilize the surfactant, and the formation of SDS/Eni-Surfactant micellar solution was confirmed by Cryo-SEM images. Using the prepared micellar solutions in oil-removal tests on the packed bed, a very high effectiveness was demonstrated by image binarization, thus confirming the possibility to deliver liposoluble surfactants to the porous-media-trapped crude oil by means of hydrosoluble carriers. / 1 / Yufei Duan

Current oil production technologies recover only about one‐third to one‐half of the oil originally present in an oil reservoir. Given current oil prices, even a modest increase in oil recovery efficiency is fiscally attractive. One novel approach to increase oil recovery efficiency is a process called microbial enhanced oil recovery (MEOR), where microorganisms are either used as a clogging agent to redirect flow or to produce biosurfactant that reduces interfacial tension. This dissertation aims to understand the MEOR pore‐scale mechanisms relevant to oil recovery by taking a two‐fold approach where transparent 2‐dimensional micromodel experiments imaged with stereo microscopy and 3‐dimensional column experiments imaged with x‐ray computed microtomography (CMT) are utilized. Micromodel experiments allow for direct visualization of the biological phase (i.e. biofilm), however, only 2‐dimensional information is provided. Conversely, CMT experiments provide 3‐dimensional pore‐scale information, but lack the ability to image the biological phase. With this two‐fold approach, it is possible to distinguish multiple fluid interfaces, quantify fluid phase saturations, measure oil blob size distributions, and visualize the biological phase. Furthermore, a method to measure interfacial curvature from 3‐dimensional images is developed, providing researchers a new perspective from which to study multiphase flow experiments. Overall, the presented research utilizes pore‐scale imaging techniques to study the interfacial interactions occurring during MEOR in an effort to better explain the physics, and thus, increase the efficacy of MEOR. / Graduation date: 2012