CO₂ enhanced oil recovery (CO₂-EOR) in residual oil zones has emerged as a viable technique to maximize both the oil production and carbon storage. Most CO₂ field projects suffer from inadequate sweep because of high mobility of CO₂ compared to the oil. Gas conformance techniques have the potential to further improve the effectiveness of CO₂-EOR projects. The choice of mobility control to improve the sweep efficiency is critical and simulation studies with hysteretic relative permeability and mechanistic foam model can assist in the choice of technique and optimization of the process for each reservoir. Two promising mobility control practices of Water Alternating Gas (WAG) and foam are evaluated using the in-house compositional gas reservoir simulator (DOE-CO₂). The effect of hysteresis and cycle dependent relative permeability on WAG and foam injections incorporating a new three-phase hysteresis model has been investigated. Simulations are performed with and without hysteresis to assess the impact of the saturation history and saturation path on gas entrapment, fluid injectivity and oil recovery. The foam assisted technique in CO₂-EOR processes has also been investigated. Here foam is generated in-situ by injecting surfactant solution with CO₂ rather than directly injecting foam. A simplified yet mechanistic population-balance model implemented in the in-house simulator has been applied to test the impact of foam. The results have been compared with an empirical foam model which is the standard model in commercial simulators. Simulations have been performed on actual field models for selection and optimization of the CO₂ injection scheme, quantifying the impact of hysteresis, depicting the effectiveness of CO₂-EOR process as against a surfactant flood, the effectiveness of foam assisted floods and insights into low tension gas flooding process. All the above analyses have also been performed on layer cake models with properties replicating the Permian Basin carbonate reservoirs and Gulf Coast sandstone reservoirs. Hysteresis shows an improvement in oil recovery of gas injection schemes where flow reversal takes place. Foam has been found to be effective and the models show lower CO₂ utilizations factors compared to the case without foam. / text

The petroleum industry has been utilizing surfactant stabilized foams for mobility control and enhanced oil recovery applications. However, if surface-treated nanoparticles were utilized instead of surfactants, the foams could have a number of important advantages. The solid-stabilized foams are known to have a much better stability than the surfactant-stabilized foams, because the energy required to bring nanoparticles to, and detach from the foam bubble surface is much larger than that of surfactants, and thus the resulting foam will be more stable. Since nanoparticles are the stabilizing component of the foam and are solid, they have potential to stabilize foam at high temperature conditions for extended periods of time. Since they are inherently small, nanoparticles, as well as the foam that they stabilize, can be transported through rocks without causing plugging in pore throats. Stable supercritical carbon dioxide-in-water foams were created using 5 nm silica-core nanoparticles whose surface had short polyethylene-glycol chains covalently bonded to it. The foams were made by injecting CO2 and an dispersion of with surface-treated nanoparticles simultaneously through a glass-bead pack. The fluids flowing through this permeable media created shear rates of about 1350 sec-1. Nanoparticle concentration, nanoparticle coating, water salinity, volume ratios between CO2 and water, temperature and shear rates were systematically varied in order to define the range of conditions for foam generation. Using de-ionized water to dilute the nanoparticle concentration, we were able to generate stable foams were at nanoparticle concentrations as low as 0.05 weight percent. Among the different surface coatings that we tested PEG coatings were the only type that was able to stabilize foam. As the salinity of the aqueous phase increased, the nanoparticle concentration required to maintain foam also increased; for example, 0.5 weight percent nanoparticles were required for 4 weight percent NaCl brine. Foam stability was weakly correlated with volume ratios as foams were made across ratios from two to fourteen, and the normalized viscosity ratio increased with the increase of the phase ratio. Foams were created at temperatures up to 95 degrees Celsius. Foam generation was also determined to require a critical shear rate, which increased with temperature. When foam was stabilized by the nanoparticles, the foam exhibited an increase of between two and twenty times in the resistance of flow compared to the two fluids flowing without nanoparticles. / text

Alkali-Surfactant-Polymer (ASP) or Surfactant-Polymer (SP) flooding are attractive chemical enhanced oil recovery (EOR) methods. However, some reservoir conditions are not favorable for the use of polymers or their use would not be economically attractive due to low permeability, high salinity, or some other unfavorable factors. In such conditions, gas can be an alternative to polymer for improving displacement efficiency in chemical-EOR processes. The co-injection or alternate injection of gas and chemical slug results in the formation of foam. Foam reduces the relative permeability of injected chemical solutions that form microemulsion at ultra-low interfacial tension (IFT) conditions and generates sufficient viscous pressure gradient to drive the foamed chemical slug. We have named this technique of foam assisted enhanced oil recovery as Alkali/Surfactant/Gas (ASG) process. The concept of ASG flooding as an enhanced oil recovery technique is relatively new, with very little experimental and theoretical work available on the subject. This dissertation presents a systematic study of ASG process and its potential as an EOR method. We performed a series of high performance surfactant-gas tertiary recovery corefloods on different core samples, under different rock, fluid, and process conditions. In each coreflood, foamed chemical slug was chased by foamed chemical drive. The level of mobility control in corefloods was evaluated on the basis of pressure, oil recovery, and effluent data. Several promising surfactants, with dual properties of foaming and emulsification, were identified and used in the coreflood experiments. We observed a strong synergic effect of foam and ultra-low IFT conditions on oil recovery in ASG corefloods. Oil recoveries in ASG corefloods compared reasonably well with oil recoveries in ASP corefloods, when both were conducted under similar conditions. We found that the negative salinity gradient concept, generally applied to chemical floods, compliments ASG process by increasing foam strength in displacing fluids (slug and drive). A characteristic increase in foam strength was observed, in nearly all ASG corefloods conducted in this study, as the salinity first changed from Type II(+) to Type III environment and then from Type III to Type II(-) environment. We performed foaming and gas-microemulsion flow experiments to study foam stability in different microemulsion environments encountered in chemical flooding. Results showed that foam in oil/water microemulsion (Type II(-)) is the most stable, followed by foam in Type III microemulsion. Foam stability is extremely poor (or non-existent) in water/oil microemulsion (Type II (+)). We investigated the effects of permeability, gas and liquid injection rates (injection foam quality), chemical slug size, and surfactant type on ASG process. The level of mobility control in ASG process increased with the increase in permeability; high permeability ASG corefloods resulting in higher oil recovery due to stronger foam propagation than low permeability corefloods. The displacement efficiency was found to decrease with the increase in injection foam quality. We studied the effect of pressure on ASG process by conducting corefloods at an elevated pressure of 400 psi. Pressure affects ASG process by influencing factors that control foam stability, surfactant phase behavior, and rock-fluid interactions. High solubility of carbon dioxide (CO₂) in the aqueous phase and accompanying alkali consumption by carbonic acid, which is formed when dissolved CO₂ reacts with water, reduces the displacement efficiency of the process. Due to their low solubility and less reactivity in aqueous phase, Nitrogen (N₂) forms stronger foam than CO₂. Finally, we implemented a simple model for foam flow in low-IFT microemulsion environment. The model takes into account the effect of solubilized oil on gas mobility in the presence of foam in low-IFT microemulsion environment. / text

Cars have become necessities of our daily life and are especially important to people with disability because they extend their range of activity and allow participation in a social life. Sometimes driving a normal car is impossible for individuals with severe disability and they require additional driving aide. However, it is dangerous to send these individuals on the road without giving them special training on driving vehicles using an adaptive aide. Nowadays there are a number of driving simulators that train disabled persons but none of them have joystick-enabled training that controls both steering, gas and break pedal. This necessitates the design of a method and a system which helps a person with disabilities learn how to operate a joystick-enabled vehicle, by using a combination of an advanced vehicle interface system, which is a driving aide known as Advanced Electronic Vehicle Interface Technology (AVEIT) and virtual reality driving simulator known as Simulator Systems International (SSI). This thesis focuses on the mechanism that synchronizes both AVEIT and SSI systems. This was achieved by designing a mechanical and electrical system that serves as a means of transferring the action between the AVEIT and SSI system. The mechanical system used for this purpose consists of two coupler units attached to AVEIT and SSI each combined together by the electrical system. As the user operates the joystick, the action of AVEIT is transferred to the SSI system by the help of the electromechanical system. The design provides compatibility between the AVEIT and SSI system which makes them convenient for training persons with disability.

The focus of this thesis was conducting experiments which would help in understanding mechanisms and in design of surfactant enhanced oil recovery (EOR) processes in various scenarios close to reservoir conditions such as heterogeneity, effects of crude oil, wettability, etc. Foam generated in situ by surfactant alternating gas injection was demonstrated as a substitute for polymer drive in a 1-D FOR process. It was effective in a similar process for a 266 cp crude oil even though the system did not have favorable mobility control. Foam enhanced sweep efficiency in a layered sandpack with a 19:1 permeability ratio. Foam diverted surfactant from the high- to the low-permeability layer. Ahead of the foam front, liquid in the low-permeability layer crossflowed into the high-permeability layer. Foam completely swept the system in 1.3 TPV (total pore volume) fluid injection while waterflood required 8 TPV. When the same 2-D system was oil-wet, the recovery by watertlood was only 49.1% of original oil-in-place (OOIP) due to injected water flowing through high-permeability zone leaving low-permeability zone unswept. To improve recovery, an anionic surfactant blend (NI) was injected that altered the wettability and lowered the interfacial tension (IFT) and consequently enabled gravity and capillary pressure driven vertical counter-current flow to occur and exchange fluids between layers during a 42-day system shut-in. Cumulative recovery after a subsequent foamflood was 94.6% OOIP. The addition of lauryl betaine to NI at a weight ratio of 2:1 made the new NIB a good IFT-reducing and foaming agent with crude oil present. It showed effectiveness in water-wet homogeneous and oil-wet heterogeneous sandpacks. The unique attribute of foam with higher apparent viscosity in high- than in low-permeability regions makes it a better mobility control agent than polymer in heterogeneous systems. One single surfactant formulation such as NIB in this study that can simultaneously reduce IFT and generate foam will improve the microscopic displacement and sweep efficiency from the beginning of a chemical flooding process. Foam generation mechanisms, alkaline/surfactant processes, and foam stability in presence of crude oil were investigated in a glass micro model. Total acid number measurement with spiking method was discussed.

The use of foam-forming surfactants offers promise to improve sweep efficiency and mobility control for enhanced oil recovery (EOR). This thesis provides an in depth understanding of transport of surfactant and foam through porous media using a combination of laboratory experiments and numerical simulations. In particular, there are several issues in foam EOR processes that are examined. These include screening of surfactant adsorption onto representative rock surfaces, modeling of foam flow through porous media, and studying the effects of surface wettability and porous media heterogeneity. Surfactant adsorption onto rock surfaces is a main cause of foam chromatographic retardation as well as increased process cost. Successful foam application requires low surfactant adsorption on reservoir rock. The focus of this thesis is natural carbonate rock surfaces, such as dolomite. Surfactant adsorption was found to be highly dependent on electrostatic interactions between surfactants and rock surface. For example, the nonionic surfactant Tergitol 15-S-30 exhibits low adsorption on dolomite under alkaline conditions. In contrast, high adsorption of cationic surfactants was observed on some natural carbonate surfaces. XPS analysis reveals silicon and aluminum impurities exist in natural carbonates, but not in synthetic calcite. The high adsorption is due to the strong electrostatic interactions between the cationic surfactants and negative binding sites in silica and/or clay. There are a number of commercial foam simulators, but an approach to estimate foam modeling parameters from laboratory experiments is needed to simulate foam transport. A one-dimensional foam simulator is developed to simulate foam flow. Chromatographic retardation of surfactants caused by adsorption and by partition between phases is investigated. The parameters in the foam model are estimated with an approach utilizing both steady-state and transient experiments. By superimposing contour plots of the transition foam quality and the foam apparent viscosity, one can estimate the reference mobility reduction factor (fmmob) and the critical water saturation (fmdry) using the STARS foam model. The parameter epdry, which regulates the abruptness of the foam dry-out effect, can be estimated by a transient foam experiment in which 100% gas displaces surfactant solution at 100% water saturation. Micromodel experiments allow for pore-level visualization of foam transport. We have developed model porous media systems using polydimethylsiloxane. We developed a simple method to tune and pattern the wettability of polydimethylsiloxane (PDMS) to generate porous media models with specific structure and wettability. The effect of wettability on flow patterns is observed in gas-liquid flow. The use of foam to divert flow from high permeable to low permeable regions is demonstrated in a heterogeneous porous micromodel. Compared with 100% gas injection, surfactant-stabilized foam effectively improves the sweep of the aqueous fluid in both high and low permeability regions of the micromodel. The best performance of foam on fluid diversion is observed in the lamella-separated foam regime, where the presence of foam can enhance gas saturation in the low permeable region up to 45.1% at the time of gas breakthrough. In conclusion, this thesis provides new findings in surfactant adsorption onto mineral surfaces, in the methodology of estimating foam parameters for reservoir simulation, and in micromodel observations of foam flow through porous media. These findings will be useful to design foam flooding in EOR processes.

Carbon dioxide (CO₂) flooding is the second most common tertiary recovery technique implemented in the United States. Yet, there is huge potential to advance the process by improving the volumetric sweep efficiency of injected CO₂. Delivering CO₂ into the reservoir as a foam is one way to do this. Surfactants have traditionally been used to generate CO₂ foams for mobility control; however, the use of nanoparticles as a foam stabilizing agent provides several advantages. Surfactant-stabilized foams require constant regeneration to be effective, and the surfactant is adsorbed onto reservoir rocks and is prone to chemical degradation at harsh reservoir conditions. Nanoparticle-stabilized foams have been found to be tolerant of high temperature and high salinity environments. Their nano size also allows them to be transported through reservoir rocks without blocking pore throats. Stable CO₂-in-water foams were generated using 5 nm silica nanoparticles with a short chain polyethylene glycol surface coating. These foams were generated by the co-injection of CO₂ and a nanoparticle dispersion through both rock matrix and fractures. A threshold shear rate was found to exist for foam generation in both fractured and non-fractured Boise sandstone cores. The ability of nanoparticles to generate foams only above a threshold shear rate is advantageous; in field applications, high shear rates are associated with high permeability zones, where the presence of foam is desired. Reducing CO₂ mobility in these high permeability zones diverts CO₂ into lower permeability regions containing not yet swept oil. Nanoparticles were also found to be able to stabilize CO₂ foams by co-injection through rough-walled fractures in cement cores, demonstrating their ability to stabilize foams without matrix flow. Experiments were conducted on the ability of fly ash, a waste product from burning coal in power plants, to stabilize oil-in-water emulsions and CO₂ foams. The use of fly ash particles as a foam stabilizing agent would significantly reduce material costs for potential tertiary oil recovery and CO₂ sequestration applications. Nano-milled fly ash particles without surface treatment were able to generate stable oil-in-water emulsions when high frequency, high energy vibrations were applied to a mixture of fly ash dispersion and dodecane. Oil-in-water emulsions were also generated by co-injecting fly ash and dodecane, a low pressure analog to CO₂, through a beadpack. Emulsions generated by co-injection, however, were unstable and coalesced within an hour. A threshold shear rate was required for the emulsion generation. Fly ash particles were found to be able to stabilize CO₂ foam in a high pressure batch mixing cell, but not by co-injection through a beadpack. Dispersions of fly ash particles were found to be stable only at low salinities (<1 wt% NaCl). / text

More and more Swedish municipalities are adopting approaches that target ‘vulnerable EU citizens’ and the ‘passive collection of money’. This thesis analyses begging permits, bans, and other approaches, motivated by the positions supported in Eskilstuna, Katrineholm and Norrköping. The approaches analysed are irrespective of the municipalitiesthat implemented them. This thesis follows a ‘problem’ questioning approach, taking into consideration the context and the system under which the ‘problems’ are constructed and aims to find the implicit and explicit aims of the various approaches.

Foam reduces gas mobility in porous media by trapping substantial amount of gas and applying a viscous resistance of flowing lamellas to gas flow. In mechanistic foam modeling, gas relative permeability is significantly modified by gas trapping, while an effective gas viscosity, which is a function of flowing lamella density, is assigned to flowing gas. A complete understanding of foam mobility in porous media requires being able to predict the effects of pressure gradient, foam texture, rock and fluid properties on gas trapping, and therefore gas relative permeability, and effective gas viscosity. In the foam literature, separating the contributions of gas trapping and effective gas viscosity on foam mobility has not been achieved because the dynamics of gas trapping and its effects on the effective gas viscosity have been neglected. In this study, dynamics of foam mobility in porous media is investigated with a special focus on gas trapping and its effects on gas relative permeability and effective gas viscosity. Three-dimensional pore-network models representative of real porous media coupled with fluid models characterizing a lamella flow through a pore throat are used to predict flow paths, threshold pressure gradient and Darcy velocity of foam. It is found that the threshold path and the pore volume open above the threshold pressure are independent of the fluid model used in this study. Furthermore, analytical correlations of flowing gas fraction as functions of pressure gradient, lamella density, rock and fluid properties are obtained. At a constant pressure gradient, flowing gas fraction increases as overall lamella density decreases. In the discontinuous-gas foam flow regime, there exists a threshold pressure gradient, which increases with overall lamella density. One of the important findings of this study is that gas relative permeability is a strong non-linear function of flowing gas fraction, opposing most of the existing theoretical models. However, the shape of the relative gas permeability curve is poorly sensitive to overall lamella density. Flowing and trapped lamella densities change with pressure gradient. Moreover, analytical correlations of effective gas viscosity as functions of capillary number, lamella density and rock properties are obtained by up-scaling a commonly used pore-scale apparent gas (lamella) viscosity model. Effective gas viscosity increases nonlinearly with flowing lamella density, which opposes to the existing linear foam viscosity models. In addition, the individual contributions of gas trapping and effective gas viscosity on foam mobility are quantified for the first time. The functional relationship between effective gas viscosity and flowing lamella density in the presence of dynamic trapped gas is verified. A mechanistic foam model is developed by using the analytical correlations of flowing gas fraction and effective gas viscosity generated from the pore-network study and a modified population balance model. The developed model is successful in simulating unsteady-state and steady state flow of foam through porous media. Moreover, the flow behaviors in high- and low-quality flow regimes are verified by the experimental studies in the literature. Finally, the simulation results are successfully history matched with two different core-flood data. / text

[pt] O aumento do fator de recuperação e o uso de métodos de recuperação avançada no atual cenário de novos patamares de preços representam um enorme desafio para a indústria do petróleo. Neste contexto, o uso de emulsões óleo-água como um método de recuperação avançada torna-se bastante atrativo. Diversos trabalhos mostraram um aumento no volume de óleo produzido através da injeção de emulsões óleo-água. Resultados de pesquisas experimentais indicam que a injeção de emulsões pode ser utilizada como agente de controle de mobilidade, bem como reduzindo a saturação residual de óleo. A aplicação do método de injeção alternada água-emulsão-água (WAE) requer o entendimento do escoamento de emulsões no meio poroso e dos mecanismos responsáveis pela melhora na recuperação. Este entendimento tanto na escala de poros como na escala de reservatórios permite incorporação destes mecanismos na modelagem para simulação de fluxo de reservatórios. No presente trabalho foi feita a incorporação dos efeitos gravitacionais no modelo desenvolvido para o escoamento de emulsões em meios porosos através da parametrização das curvas de permeabilidade relativa em função da concentração de gotas e do Número de Capilaridade. O processo WAE foi avaliado através de simulações em duas e três dimensões (2D/3D) utilizando um conjunto de camadas do segundo modelo comparativo do SPE10. Com simulações 2D e 3D foi possível realizar um estudo de sensibilidade do processo em relação ao momento da injeção de emulsão, o tamanho do banco, e as faixas de vazão e respectivos números de capilaridades de atuação da emulsão. / [en] In the current crude oil price scenario, the increase in oil recovery factor and the use of enhanced recovery methods represent a major challenge for the Oil Industry. In this context, the use of oil-water emulsion flooding as an enhanced recovery method becomes very attractive. Several studies have shown a significant potential to increase oil volume recovery by the injection of oil-water emulsions. Experimental results indicate that the emulsions injection can be used as a mobility control agent, resulting in a more uniform fluid displacement in the reservoir and lower residual oil saturation. Based on these experimental results, the most relevant parameters for emulsion injection performance effectiveness are droplet size, the local concentration of the dispersed phase of the emulsion and the local capillary number. The application of water alternating emulsion injection (WAE) method requires understanding of the flow of emulsions in porous media and the mechanisms responsible for the improved recovery. The understanding of this process in both porous scale and reservoir scale is fundamental to model emulsion injection effects in reservoir flow simulation. In this work, the gravitational effects was incorporated in the macroscopic model to represent flow of emulsions in porous media by relative permeability curves parametrization as function of emulsion concentration and of the local capillary number. The WAE process was evaluated in two and three dimensional simulations (2D / 3D) using a set of layers of the second SPE 10 comparative model. With 2D and 3D simulations, it was possible to explore a WAE injection performance sensitivity analysis considering the time at which the emulsion injection is started, the size of emulsion bank, and the injection flow rates and consequently the flow their capillary number.