Academic literature on the topic 'Oil and water displacementsi'
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Journal articles on the topic "Oil and water displacementsi"
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Campbell, Bruce T., and Franklin M. Orr. "Flow Visualization for CO2/Crude-Oil Displacements." Society of Petroleum Engineers Journal 25, no. 05 (October 1, 1985): 665–78. http://dx.doi.org/10.2118/11958-pa.
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Abstract Results of visual observations of high-pressure CO2 floods are reported. The displacements were performed in two-dimensional (2D) pore networks etched in glass plates. Results of secondary and tertiary first-contact miscible displacements and secondary and tertiary multiple-contact miscible displacements are compared. Three displacements with no water present were performed in each of three pore networks:displacement of a refined oil by the same oil dyed a different color;displacement of a refined oil by CO2 (first-contact miscible); anddisplacement of a crude oil at a pressure above the minimum miscibility pressure. In addition, three tertiary displacements were performed in the same pore networks;displacement of the refined oil by water, followed by displacement by the same refined oil dyed to distinguish it from the original oil;tertiary displacement of the refined oil by CO2; andtertiary displacement of crude oil by CO2. In addition, recovery of oil from dead-end pores, with and without water barriers shielding the oil, was investigated. Visual observations of pore-level displacement events indicate that CO2 displaced oil much more efficiently in both first-contact and multiple-contact miscible displacements when water was absent. In tertiary displacements of a refined oil, CO2 effectively displaced the oil it contacted, but high water saturations restricted access of CO2 to the oil. The low viscosity of CO2 aggravated effects of high water saturations because the CO2 did not displace water efficiently. CO2 did, however, contact trapped oil by diffusing through water to reach, to swell, and to reconnect isolated droplets. Finally, CO2 displaced crude oil more efficiently than it did the refined oil in tertiary displacements. Differences in wetting behavior between the refined and crude oils appear to account for the different flow behavior. Introduction If high-pressure CO2 displaces oil in a one-dimensional (1D), uniform porous medium (in which the effects of viscous fingering are necessarily absent), the displacement efficiency is controlled by the phase behavior of the CO2/crude-oil mixtures. The conventional description of the effects of phase behavior was given by Hutchinson and Braun1 for vaporizing gas drives and was extended to CO2 systems by Rathmell et al.2 In a rigorous mathematical treatment of the flow of three-component mixtures. Helfferich3 proved that the displacement will develop miscibility if the oil composition lies outside the region of tie-line extensions on a ternary diagram. Helfferich's analysis was for 1D flows in which fluids are mixed well locally, and the effects of dispersion are absent. Sigmund et al.,4 Gardner et al.,5 and Orr et al.6 showed that results of slim-tube displacements, which are nearly 1D and come close to eliminating the effects of viscous instability, can be predicted quantitatively by 1D process simulations based on independent measurements of the phase behavior and fluid properties of the CO2/crude-oil mixtures. Thus there is good experimental confirmation that the simple theory of the effects of phase behavior on displacement performance describes accurately the behavior of flow in an ideal displacement, such as a slim tube. In a CO2 flood in reservoir rock, however, a variety of other factors will influence process performance. Because the viscosity CO2 is much lower than that of most oils, viscous instability will limit the sweep efficiency of the injected CO2. In addition, Gardner and Ypma7 predicted, based on 2D simulations of the growth of a viscous finger, that an interaction between viscous instability and phase behavior would lead to higher residual oil saturation in regions penetrated by a viscous finger. Pore-structure heterogeneity may also influence displacement efficiency. Spence and Watkins8 found that residual oil saturations after CO2 waterfloods increased as the heterogeneity of the core increased. Several investigators have reported that high water saturations can alter mixing between oil and injected solvent. Raimondi and Torcaso9 found, in displacements in Berea sandstone cores, that significant fractions of the oil phase could not be contacted by injected solvent when the water saturation was high. Thomas et al.10 reported that a portion of the nonwetting phase can exist in "dendritic" pores whose shapes were determined by the surrounding wetting phase. They argued that material in the dendritic pores mixed with fluid in the flowing fraction only by diffusion. Stalkup11 and Shelton and Schneider12 also investigated effects of mobile water saturations in miscible displacements. Stalkup found that the flowing fraction decreased as the water saturation increased. Shelton and Schneider reported that the presence of a second mobile phase slowed recovery of either phase, but the nonwetting phase was affected more strongly. In their tests, all of the wetting phase was recovered by a miscible displacement, but significant amounts of nonwetting phase remained unrecovered.
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Kamali, Fatemeh, Furqan Hussain, and Yildiray Cinar. "An Experimental and Numerical Analysis of Water-Alternating-Gas and Simultaneous-Water-and-Gas Displacements for Carbon Dioxide Enhanced Oil Recovery and Storage." SPE Journal 22, no. 02 (August 30, 2016): 521–38. http://dx.doi.org/10.2118/183633-pa.
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Summary This paper presents an experimental and numerical study that delineates the co-optimization of carbon dioxide (CO2) storage and enhanced oil recovery (EOR) in water-alternating-gas (WAG) and simultaneous-water-and-gas (SWAG) injection schemes. Various miscibility conditions and injection schemes are investigated. Experiments are conducted on a homogeneous, outcrop Bentheimer sandstone sample. A mixture of hexane (C6) and decane (C10) is used for the oil phase. Experiments are run at 70°C and three different pressures (1,300, 1,700, and 2,100 psi) to represent immiscible, near-miscible, and miscible displacements, respectively. WAG displacements are performed at a WAG ratio of 1:1, and a fractional gas injection (FGI) of 0.5 is used for SWAG displacements. The effect of varying FGI is also examined for the near-miscible SWAG displacement. Oil recovery, differential pressure, and compositions are recorded during experiments. A co-optimization function for CO2 storage and incremental oil production is defined and calculated by use of the measured data for each experiment. The results of SWAG and WAG displacements are compared with the experimental data of continuous-gas-injection (CGI) displacements. A compositional commercial reservoir simulator is used to examine the recovery mechanisms and the effect of mobile water on gas mobility. Experimental observations demonstrate that the WAG displacements generally yield higher co-optimization function than CGI and SWAG with FGI = 0.5 displacements. Numerical simulations show a remarkable reduction in gas relative permeability for the WAG and SWAG displacements compared with CGI displacements, as a result of which the vertical-sweep efficiency of CO2 is improved. More reduction of gas relative permeability is observed in the miscible and near-miscible displacements than in the immiscible displacement. The reduced gas relative permeability lowers the water-shielding effect, thereby enhancing oil recovery and CO2-storage efficiency. More water-shielding effect is observed in SWAG with FGI = 0.5 than in WAG. However, increasing FGI from 0.5 to 0.75 in the near-miscible SWAG displacement shows a significant increase in oil recovery, which is attributed to reduced water-shielding effect. So, an optimal FGI needs to be determined to minimize the water-shielding effect for efficient SWAG displacements.
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Bera, Bijoyendra, Ines Hauner, Mohsin Qazi, Daniel Bonn, and Noushine Shahidzadeh. "Oil-water displacements in rough microchannels." Physics of Fluids 30, no. 11 (November 2018): 112101. http://dx.doi.org/10.1063/1.5053625.
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Brailovsky, I., A. Babchin, M. Frankel, and G. Sivashinsky. "Fingering Instability in Water-Oil Displacement." Transport in Porous Media 63, no. 3 (June 2006): 363–80. http://dx.doi.org/10.1007/s11242-005-8430-z.
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Namdar Zanganeh, M., S. I. I. Kam, T. C. C. LaForce, and W. R. R. Rossen. "The Method of Characteristics Applied to Oil Displacement by Foam." SPE Journal 16, no. 01 (August 19, 2010): 8–23. http://dx.doi.org/10.2118/121580-pa.
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Summary Solutions obtained by the method of characteristics (MOC) provide key insights into complex foam enhanced-oil-recovery (EOR) displacements and the simulators that represent them. Most applications of the MOC to foam have excluded oil. We extend the MOC to foam flow with oil, where foam is weakened or destroyed by oil saturations above a critical oil saturation and/or weakened or destroyed at low water saturations, as seen in experiments and represented in foam simulators. Simulators account for the effects of oil and capillary pressure on foam using algorithms that bring foam strength to zero as a function of oil or water saturation, respectively. Different simulators use different algorithms to accomplish this. We examine SAG (surfactant-alternating-gas) and continuous foam-flood (coinjection of gas and surfactant solution) processes in one dimension, using both the MOC and numerical simulation. We find that the way simulators express the negative effect of oil or water saturation on foam can have a large effect on the calculated nature of the displacement. For instance, for gas injection in a SAG process, if foam collapses at the injection point because of infinite capillary pressure, foam has almost no effect on the displacement in the cases examined here. On the other hand, if foam maintains finite strength at the injection point in the gas-injection cycle of a SAG process, displacement leads to implied success in several cases. However, successful mobility control is always possible with continuous foam flood if the initial oil saturation in the reservoir is below the critical oil saturation above which foam collapses. The resulting displacements can be complex. One may observe, for instance, foam propagation predicted at residual water saturation, with zero flow of water. In other cases, the displacement jumps in a shock past the entire range of conditions in which foam forms. We examine the sensitivity of the displacement to initial oil and water saturations in the reservoir, the foam quality, the functional forms used to express foam sensitivity to oil and water saturations, and linear and nonlinear relative permeability models.
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Zhou, Wen Sheng, Xiao Ru He, Zhan Li Geng, and Ji Cheng Zhang. "Water Displacement Rule at Extra-High Water Cut Stage." Advanced Materials Research 1073-1076 (December 2014): 2239–43. http://dx.doi.org/10.4028/www.scientific.net/amr.1073-1076.2239.
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During the development of the oilfield, the water cut of the water controlled field is an aggregative indicator which is affected by various factors. It can reflect the restriction of liquid flowing rules from the oil layer and crude oil physical property, and the effect of serious technical measures during the exploitation. Water cut increasing rate is closely related with water cut. The level of water-cut increasing rate of various well network was evaluated during oil producing with extra-high water cut in Xingnan development area, compared the differences among various well networks, and analyzed the geology causes and development causes.
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Zhao, Jin, Guice Yao, and Dongsheng Wen. "Pore-scale simulation of water/oil displacement in a water-wet channel." Frontiers of Chemical Science and Engineering 13, no. 4 (October 1, 2019): 803–14. http://dx.doi.org/10.1007/s11705-019-1835-y.
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Abstract Water/oil flow characteristics in a water-wet capillary were simulated at the pore scale to increase our understanding on immiscible flow and enhanced oil recovery. Volume of fluid method was used to capture the interface between oil and water and a pore-throat connecting structure was established to investigate the effects of viscosity, interfacial tension (IFT) and capillary number (Ca). The results show that during a water displacement process, an initial continuous oil phase can be snapped off in the water-wet pore due to the capillary effect. By altering the viscosity of the displacing fluid and the IFT between the wetting and non-wetting phases, the snapped-off phenomenon can be eliminated or reduced during the displacement. A stable displacement can be obtained under high Ca number conditions. Different displacement effects can be obtained at the same Ca number due to its significant influence on the flow state, i.e., snapped-off flow, transient flow and stable flow, and ultralow IFT alone would not ensure a very high recovery rate due to the fingering flow occurrence. A flow chart relating flow states and the corresponding oil recovery factor is established.
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Suleimanov, B. A., F. S. Ismayilov, O. A. Dyshin, and N. I. Huseynova. "Fractal analysis of oil - water displacement front." "Proceedings" of "OilGasScientificResearchProjects" Institute, SOCAR, no. 4 (December 30, 2011): 36–43. http://dx.doi.org/10.5510/ogp20110400091.
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Liu, Haohan. "New Water-Oil Displacement Efficiency Prediction Method." Open Petroleum Engineering Journal 7, no. 1 (January 9, 2015): 88–91. http://dx.doi.org/10.2174/1874834101407010088.
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Abbasov, É. M., and T. S. Kengerli. "Integral Simulation of Oil Displacement by Water." Journal of Engineering Physics and Thermophysics 92, no. 2 (March 2019): 441–49. http://dx.doi.org/10.1007/s10891-019-01949-z.
Full textDissertations / Theses on the topic "Oil and water displacementsi"
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Agharazi-Dormani, Nader. "Modeling of radial water/oil displacement in water-wet porous media." Thesis, University of Ottawa (Canada), 1991. http://hdl.handle.net/10393/5706.
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The effects of five operating variables and four dimensionless groups on oil recovery and finger formation during the immiscible radial displacement of oil by water in a consolidated water-wet porous medium were investigated using statistical model building techniques. Two different approaches were used. In the first approach, experiments were carried out according to a central composite design with partial replication over the following operating region: (UNFORMATTED TABLE OR EQUATION FOLLOWS)$$\vbox{\halign{#\hfil&&\quad#\hfil\cr &Flow rate of injection fluid&0.65 $\le$ Q $\le$ 510.00 (mL/h)\cr &Radius of breakthrough&2.5 $\le$ R $\le$ 7.0 (cm)\cr &Viscosity difference&15 $\le\mu\sb{\rm o}$-$\mu\sb{\rm w} \le 152$ (mPa.s)\cr &Permeability&13.33 $\le$ K $\le$ 77.41 ($\mu$m$\sp2$)\cr&Interfacial tension (IFT)&0.3 $\le \gamma \le$ 30.0 (mN/m)\cr}}$$(TABLE/EQUATION ENDS) A second-order polynomial of the general form $$\rm Y = \beta\sb{o} + \sum\sbsp{i=1}{5} \beta\sb{i}X\sb{i} + \sum\sbsp{i=1}{5} \sum\sbsp{j=1}{5} \beta\sb{ij}X\sb{i}X\sb{j}$$was fitted to the data. It was found that for water-wet systems, the recovery decreased as the viscosity difference increased and this effect became more significant as the flow rate increased. Conversely, as the breakthrough radius or permeability of the cell increased, the recovery increased. The effect of IFT was negative and depended on the level of viscosity difference and permeability. In addition, an increase in flow rate, breakthrough radius or the viscosity difference resulted in an increase in the number of fingers, while high permeability reduced the number of fingers. The operating variables were grouped together in dimensionless terms such as the capillary number and the viscosity ratio, and the parameters ($\beta\sbsp{\rm i}{\prime}$s) were estimated for these terms. The recovery was found to be enhanced with an increase in the ratio of breakthrough radius to the cell thickness (R/h). It was reduced as the viscosity ratio increased and this attenuating effect became more significant as the flow rate increased. The effect of ratio of the cell thickness to the square root of the permeability (h/$\sqrt{K})$ and capillary number depended on the value of other variables. The number of fingers increased as any of the above ratios was increased with the exception of (h/$\sqrt{K})$ where the effect was more complex. (Abstract shortened by UMI.)
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VARGAS, KELLY MARGARITA COLMENARES. "OIL DISPLACEMENT IN MICRO MODELS OF POROUS MEDIA BY INJECTION OF OIL IN WATER EMULSION." PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO, 2014. http://www.maxwell.vrac.puc-rio.br/Busca_etds.php?strSecao=resultado&nrSeq=35523@1.
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PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIROCOORDENAÇÃO DE APERFEIÇOAMENTO DO PESSOAL DE ENSINO SUPERIOR
PROGRAMA DE EXCELENCIA ACADEMICA
O processo de recuperação de óleo pelo deslocamento com água é o método mais utilizado na indústria de petróleo. No entanto, as altas razões de mobilidade e baixas eficiências de varrido tornam o processo menos eficiente. Uma alternativa usada para minimizar este efeito é a aplicação de tecnologias que atuam como agentes de controle de mobilidade. Dentre eles, e em particular a injeção de emulsões de óleo em água tem sido estudada com relativo sucesso como um método de recuperação avançada de óleo. Alguns estudos indicam melhor varredura do reservatório devido a uma redução da mobilidade da água em regiões do reservatório já varridas por água, mediante a aglomeração e bloqueio parcial dos poros mais permeáveis com gotas da fase dispersa da emulsão. Contudo, ainda não há compreensão plena dos mecanismos associados ao escoamento de emulsões em meios porosos, assim, uma análise e visualização na escala microscópica dos fenômenos envolvidos se faz essencial para a melhora do entendimento do escoamento de emulsões em um reservatório. Neste trabalho, experimentos de escoamento de emulsões foram conduzidos em um micromodelo de vidro, estrutura artificial que busca representar alguns aspectos principais de um meio poroso e proporciona uma adequada visualização do comportamento das faces ao longo do escoamento. Nos experimentos foram realizadas alterações na molhabilidade e variou-se a vazão volumétrica a fim de avaliar diferentes números de capilaridade no meio poroso. Dentro dos resultados mais significativos, foi evidenciado como a fase dispersa da emulsão é capaz de bloquear os poros e gargantas de poro alterando a distribuição dos fluidos no meio poroso, melhorando a eficiência de deslocamento na escala de poro e com isso o fator de recuperação final. Os resultados mostram que, a altos números de capilaridade as forças interfaciais são menos importantes ao reduzir o efeito de bloqueio pelas gotas da fase dispersa nos poros do micromodelo. Estes resultados fornecem um grande aprendizado ao permitir conhecer características do escoamento de emulsões no meio poroso para uma futura aplicação no campo.
The oil recovery process by water-flooding is the most used method in the oil industry. However, the high mobility ratios and low sweep efficiencies make the process less effective. A common alternative to minimize this effect is the application of technologies that act as mobility control agents. Among them and in particular the injection of oil in water emulsions has been studied with relative success as an Enhanced Oil Recovery (EOR) method. Several studies indicate a better reservoir sweep due to the water mobility reduction in regions already swept by water. This reduction can be associated with partial blockage of porous media throats by droplets of emulsion dispersed phase. Nevertheless, there is still no full understanding of the mechanisms associated to the flow of emulsions in porous media, thus, an analysis and visualization at the microscopic scale of the involved phenomena is essential for the improvement of the comprehension of the flow of emulsions in a reservoir. In this work, experimental tests related to the flow of emulsions in a glass micro-model were performed, artificial device that represents some principal features of a porous medium and provides a proper visualization of the phase behavior. In the experiments, the effect of the capillary number on the oil recovery factor and the relative influence of the wettability of the porous medium on the oil displacement process were studied. The results evidence how the oil droplets in the emulsion are capable of block the pores and the pore throats modifying the fluids distribution in the porous medium, improving the displacement efficiency at pore scale and consequently the final oil recovery factor. It was also observed that at high capillary numbers, the blocking caused by the capillary pressure needed to deform the droplet becomes less intense. These results provide a great learning by allowing to know the characteristics of the flow of emulsions in porous media for a future field application.
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Thirunavu, Subramanian. "Effects of buoyancy forces on immiscible oil/water displacements in porous media." Thesis, University of Ottawa (Canada), 1994. http://hdl.handle.net/10393/10231.
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The effects of buoyancy forces on liquid-liquid displacement processes occurring in porous media are important in a variety of practical situations, in particular during the displacement of oil from partially-depleted underground reservoirs by means of aqueous solutions. Most previous studies involving the visualization of water/oil displacements in porous media have been undertaken in horizontal two-dimensional porous medium cells. The objective of this work was to determine the effects of buoyancy forces on the fingering pattern and oil recovery by conducting immiscible displacement experiments in two-dimensional porous medium cells aligned in the vertical plane. A consolidated porous medium cell was utilized to perform the displacements, which permitted a wide range of experiments to be carried out within an identical porous medium. In order to obtain a clear understanding of the effects of buoyancy forces (both favourable and unfavourable) experiments were carried out in three different modes, namely horizontal, vertical upward, and vertical downward. As the effects of buoyancy forces are almost negligible, in the horizontal mode, recoveries obtained in this mode are used as a reference and compared to those obtained in the other two modes. For the system studied in this work, as the displacing liquid in all cases had a higher density than the displaced liquid, buoyancy forces were always favourable in the vertical upward mode and always unfavourable in the vertical downward mode. The immiscible system employed consisted of heavy paraffin oil and glycerol solution as the displaced and displacing phases respectively. The viscosity ratio was varied by changing the concentration of the glycerol solution. Displacements with five different viscosity ratios were studied. Breakthrough time was measured and fractional oil recovery was calculated. The effects of buoyancy, viscous and capillary forces as well as the injection flow rate were also observed. The results obtained indicate that the buoyancy forces are highly effective at very low flow rates and low viscosity ratios (or high density ratios), and even with a slight increase in the flow rate, buoyancy forces lose their importance quickly.
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NUNEZ, VICTOR RAUL GUILLEN. "OIL DISPLACEMENT IN A POROUS MEDIA THROUGH INJECTION OF OIL-IN-WATER EMULSION: ANALYSIS OF LINEAR FLOW." PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO, 2007. http://www.maxwell.vrac.puc-rio.br/Busca_etds.php?strSecao=resultado&nrSeq=10663@1.
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COORDENAÇÃO DE APERFEIÇOAMENTO DO PESSOAL DE ENSINO SUPERIORAGÊNCIA NACIONAL DE PETRÓLEO
A injeção de emulsão é um método comum para melhorar o varrido do reservatório e manter-lo pressurizado. A eficiência de recuperação de óleo no caso de óleos pesados é limitada pela alta razão de mobilidade entre a água injetada e o óleo. Um método de reduzir o problema relativo µa alta razão de viscosidade é por injeção de soluções poliméricas. Porem, a interação líquido- rocha, os grandes volumes e o preço associado dos polímeros podem fazer esta técnica não aplicável em caso de campos gigantes. Diferentes métodos de recuperação avançada de óleo estão sendo desenvolvidos como alternativas µa injeção de polímeros. A injeção de dispersões, em particular a injeção de emulsões, têm sido tratadas com relativo sucesso como um método de recuperação avançada de óleo, mas as técnicas não são totalmente desenvolvidas ou compreendidas. O uso de cada método requer uma completa análise dos diferentes regimes de fluxo de emulsões dentro do espaço poroso de um reservatório. A maioria das análises de fluxo de emulsões em um meio poroso utiliza uma descrição macroscópica. Esta aproximãção é só valida para emulsões com o tamanho da fase dispersa muito menor do que o tamanho do poro. Se o tamanho de gota da fase dispersa é da mesma ordem de magnitude do tamanho de poro, as gotas podem aglomera-se e particularmente podem bloquear o fluxo através dos poros. Este regime de fluxo pode ser utilizado para controlar a mobilidade do líquido injetado, conduzindo a um fator de recuperação maior. Neste trabalho, experimentos de deslocamento de óleo foram executados em um corpo de prova de arenito. Os resultados mostram que a injeção de uma emulsão mudou o fator de recuperação de óleo, elevando este desde 40%, obtido só por injeção de água, ate um valor aproximado de 75%, seja em modo primario ou depois do influxo da água.
Water injection is a common method to improve the reservoir sweep and maintain its pressure. The e±ciency of oil recovery in the case of heavy oils is limited by the high mobility ratio between the injected water and oil. A method of reducing the problem related to the high viscosity ratio is by polymer solution injection. However, the liquid-rock interaction, the large volume and the associated cost of polymer may make this technique not applicable in the case of giant fields. Different enhanced oil recovery methods are being developed and studied as alternatives to polymer injection. Dispersion injection, in particular oil-water emulsion injection, has been tried with relative success as an enhanced oil recovery method, but the techniques are not fully developed or understood. The use of such methods requires a complete analysis of the different flow regimes of emulsions inside the porous space of a reservoir. Most analyses of flow of emulsion in a porous media use a macroscopic description. This approach is only valid for dilute emulsion which the size of the disperse phase is much smaller of the pore throat. If the drop size of the disperse phase is of the same order of magnitude of the pore size, the drops may agglomerate and partially block the flow through pores. This flow regime may be used to control the mobility of the injected liquid, leading to higher recovery factor. In this work, experiments of oil displacement were performed in a sandstone plug. The results show that injection of an emulsion changed the oil recovery factor, raising it from approximately 40%, obtained with water injection alone, to approximately 75%, whether in primary mode or after water flooding.
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Bristow, Robert Philip. "Micromodels of immiscible two-phase flow in porous media." Thesis, University of Cambridge, 1987. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.235763.
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The research is a study on the microscopic scale of the immiscible displacement of oil by water in a porous medium such as sandstone. Of particular interest (with application to the oil industry) are the residual saturation of oil, the permeability to water at residual oil saturation and the maximum trapped blob size. Initially the effects of gravity, surface tension and distribution of pore sizes were studied in a computer simulation of a buoyancy driven, quasi-static invasion. The rock was modelled as a three-dimensional lattice of spherical pores connected by narrow cylindrical throats. With the rock water-wet, the tendency of the surface tension to favour the invasion of smaller pores led to a larger residual oil saturation by pore volume than by pore numbers. Also bourne out were some scaling arguments based on percolation theory for the maximum trapped blob size as a function of the relative strength of buoyancy and surface tension forces. The second part of the research investigated the interaction of viscous and surface tension forces. As this is a much more complicated problem, involving the solution of flow equations, the invasion process was first simulated with exact equations of motion on small networks (up to 10x10), where surface tension effects dominate. From these simulations a simplified set of rules was developed to determine which pore in a locality on the oil-water interface is invaded and how long the invasion takes. These rules include a viscous correction to the dominant surface tension forces. Finally, some theory has been developed for the inclusion of the small-scale analysis into a larger model, allowing a full simulation of the viscous dominated invasion to be performed.
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Gholamhosseini, Masoud. "Visualization of water/oil displacement in porous media in the presence of chemical reaction." Thesis, University of Ottawa (Canada), 1991. http://hdl.handle.net/10393/7838.
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In enhanced oil recovery, low interfacial tension, optimum wettability condition, high pH value, and the electric charge density at the interface can improve the oil recovery percentage appreciably. However, the addition of sodium hydroxide changes the interfacial tension to an ultra-low value. Interfacial tension decreases as a result of the interfacial reaction between the surface active species in the oleic phase and the caustic in the aqueous phase. The surface active species also provide favorable wettability conditions and interfacial activity which improves the recovery percentage. This study has investigated the effects of caustic concentration in the aqueous phase on the recovery percentage, and on the displacement pattern in a radial cell. The caustic solutions were employed as the displacing phase being brought into contact with the acidic oil in the cell. The displacing aqueous phase contained different concentrations of sodium hydroxide ranging from 0.0 mM to 25 mM, and the displaced phase was a light paraffin oil containing 10 mM linoleic acid. In this research, the effect of flowrate on oil recovery percentage was also examined. (Abstract shortened by UMI.)
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Al-Zaidi, Ebraheam Saheb Azeaz. "Experimental studies on displacements of CO₂ in sandstone core samples." Thesis, University of Edinburgh, 2018. http://hdl.handle.net/1842/33183.
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CO2 sequestration is a promising strategy to reduce the emissions of CO2 concentration in the atmosphere, to enhance hydrocarbon production, and/or to extract geothermal heat. The target formations can be deep saline aquifers, abandoned or depleted hydrocarbon reservoirs, and/or coal bed seams or even deep oceanic waters. Thus, the potential formations for CO2 sequestration and EOR (enhanced oil recovery) projects can vary broadly in pressure and temperature conditions from deep and cold where CO2 can exist in a liquid state to shallow and warm where CO2 can exist in a gaseous state, and to deep and hot where CO2 can exist in a supercritical state. The injection, transport and displacement of CO2 in these formations involves the flow of CO2 in subsurface rocks which already contain water and/or oil, i.e. multiphase flow occurs. Deepening our understanding about multiphase flow characteristics will help us building models that can predict multiphase flow behaviour, designing sequestration and EOR programmes, and selecting appropriate formations for CO2 sequestration more accurately. However, multiphase flow in porous media is a complex process and mainly governed by the interfacial interactions between the injected CO2, formation water, and formation rock in host formation (e.g. interfacial tension, wettability, capillarity, and mass transfer across the interface), and by the capillary , viscous, buoyant, gravity, diffusive, and inertial forces; some of these forces can be neglected based on the rock-fluid properties and the configuration of the model investigated. The most influential forces are the capillary ones as they are responsible for the entrapment of about 70% of the total oil in place, which is left behind primary and secondary production processes. During CO2 injection in subsurface formations, at early stages, most of the injected CO2 (as a non-wetting phase) will displace the formation water/oil (as a wetting phase) in a drainage immiscible displacement. Later, the formation water/oil will push back the injected CO2 in an imbibition displacement. Generally, the main concern for most of the CO2 sequestration projects is the storage capacity and the security of the target formations, which directly influenced by the dynamic of CO2 flow within these formations. Any change in the state of the injected CO2 as well as the subsurface conditions (e.g. pressure, temperature, injection rate and its duration), properties of the injected and present fluids (e.g. brine composition and concentration, and viscosity and density), and properties of the rock formation (e.g. mineral composition, pore size distribution, porosity, permeability, and wettability) will have a direct impact on the interfacial interactions, capillary forces and viscous forces, which, in turn, will have a direct influence on the injection, displacement, migration, storage capacity and integrity of CO2. Nevertheless, despite their high importance, investigations have widely overlooked the impact of CO2 the phase as well as the operational conditions on multiphase characteristics during CO2 geo-sequestration and CO2 enhanced oil recovery processes. In this PhD project, unsteady-state drainage and imbibition investigations have been performed under a gaseous, liquid, or supercritical CO2 condition to evaluate the significance of the effects that a number of important parameters (namely CO2 phase, fluid pressure, temperature, salinity, and CO2 injection rate) can have on the multiphase flow characteristics (such as differential pressure profile, production profile, displacement efficiency, and endpoint CO2 effective (relative) permeability). The study sheds more light on the impact of capillary and viscous forces on multiphase flow characteristics and shows the conditions when capillary or viscous forces dominate the flow. Up to date, there has been no such experimental data presented in the literature on the potential effects of these parameters on the multiphase flow characteristics when CO2 is injected into a gaseous, liquid, or supercritical state. The first main part of this research deals with gaseous, liquid, and supercritical CO2- water/brine drainage displacements. These displacements have been conducted by injecting CO2 into a water or brine-saturated sandstone core sample under either a gaseous, liquid or supercritical state. The results reveal a moderate to considerable impact of the fluid pressure, temperature, salinity and injection rate on the differential pressure profile, production profile, displacement efficiency, and endpoint CO2 effective (relative) permeability). The results show that the extent and the trend of the impact depend significantly on the state of the injected CO2. For gaseous CO2-water drainage displacements, the results showed that the extent of the impact of the experimental temperature and CO2 injection rate on multiphase flow characteristics, i.e. the differential pressure profile, production profile (i.e. cumulative produced volumes), endpoint relative permeability of CO2 (KrCO2) and residual water saturation (Swr) is a function of the associated fluid pressure. This indicates that for formations where CO2 can exist in a gaseous state, fluid pressure has more influence on multiphase flow characteristics in comparison to other parameters investigated. Overall, the increase in fluid pressure (40-70 bar), temperature (29-45 °C), and CO2 injection rate (0.1-2 ml/min) caused an increase in the differential pressure. The increase in differential pressure with increasing fluid pressure and injection rate indicate that viscous forces dominate the multi-phase flow. Nevertheless, increasing the differential pressure with temperature indicates that capillary forces dominate the multi-phase flow as viscous forces are expected to decrease with this increasing temperature. Capillary forces have a direct impact on the entry pressure and capillary number. Therefore, reducing the impact of capillary forces with increasing pressure and injection rate can ease the upward migration of CO2 (thereby, affecting the storage capacity and integrity of the sequestered CO2) and enhance displacement efficiency. On the other hand, increasing the impact of the capillary force with increasing temperature can result in a more secure storage of CO2 and a reduction in the displacement efficiency. Nevertheless, the change in pressure and temperature can also have a direct impact on storage capacity and security of CO2 due to their impact on density and hence on buoyancy forces. Thus, in order to decide the extent of change in storage capacity and security of CO2 with the change in the above-investigated parameters, a qualitative study is required to determine the size of the change in both capillary forces and buoyancy forces. The data showed a significant influence of the capillary forces on the pressure and production profiles. The capillary forces produced high oscillations in the pressure and production profiles while the increase in viscous forces impeded the appearance of these oscillations. The appearance and frequency of these oscillations depend on the fluid pressure, temperature, and CO2 injection rate but to different extents. The appearance of the oscillations can increase CO2 residual saturation due to the re-imbibition process accompanied with these oscillations, thereby increasing storage capacity and integrity of the injected CO2. The differential pressure required to open the blocked flow channels during these oscillations can be useful in calculating the largest effective pore diameters and hence the sealing efficiency of the rock. Swr was in ranges of 0.38-0.42 while KrCO2 was found to be less than 0.25 under our experimental conditions. Increasing fluid pressure, temperature, and CO2 injection rate resulted in an increase in the KrCO2, displacement efficiency (i.e. a reduction in the Swr), and cumulative produced volumes. For liquid CO2-water drainage displacements, the increase in fluid pressure (60-70 bar), CO2 injection rate (0.4-1ml/min) and salinity (1% NaCl, 5% NaCl, and 1% CaCl2) generated an increase in the differential pressure; the highest increase occurred with increasing the injection rate and the lowest with increasing the salinity. On the other hand, on the whole, increasing temperature (20-29 °C) led to a reduction in the differential pressure apart from the gradual increase occurred at the end of flooding.
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Fannir, Jamal. "Stability of the two-phase displacement in porous media studied by MRI techniques." Electronic Thesis or Diss., Université de Lorraine, 2019. http://www.theses.fr/2019LORR0330.
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Il est important de comprendre les forces motrices qui contrôlent l'écoulement de deux fluides immiscibles dans un milieu poreux. En effet, il existe une large gamme d'applications des écoulements diphasiques en milieux poreux, notamment ceux qui concernent la récupération assistée du pétrole (EOR). Le développement des techniques quantitatives d'imagerie par résonance magnétique (IRM) ouvre de nouvelles possibilités pour étudier et caractériser les flux multiphasiques en milieu poreux. Ce travail s’intéresse précisément à décrire le déplacement de deux fluides immiscibles (eau-huile) au sein d’un milieu poreux en utilisant les techniques d’IRM. Le milieu poreux est initialement saturé d’huile qu’on vient déplacer en injectant de l’eau par le bas, l’huile et l’eau pouvant s’évacuer par le haut. L’objectif général de l’étude est de déterminer le déplacement et la déformation du front (eau-huile) au cours du temps, et de préciser les mécanismes de piégeage des phases. Des expériences sont menées sur deux modèles poreux. L’un mouillant à l’huile consiste en un empilement de petites billes en polystyrène (0,4 mm < dp < 0,6 mm), l’autre mouillant à l’eau est un sable légèrement compacté (0,02 mm < dp < 0,50 mm). Nous avons utilisé un dispositif de micro-imagerie RMN fonctionnant à 14 T (résonance 1H à 600 MHz) pour acquérir des images à haute résolution (0.2 mm) à l’intérieur des milieux poreux au cours du déplacement des deux fluides. Les résultats obtenus ont montré que le profil de saturation en huile est fortement influencé par les propriétés du matériau poreux, telles que la porosité et la perméabilité de l'échantillon, le mouillage des phases, le débit d'injection de l’eau ou encore l’hétérogénéité de la matrice solide. L'influence du débit d’injection d’eau sur la saturation résiduelle en huile a été plus particulièrement étudiée. Les résultats expérimentaux permettent une compréhension fine du déplacement de deux fluides non miscibles pour deux types de milieux poreux, qui se différencient principalement par les effets de la mouillabilité. Dans le même temps, une simulation numérique du déplacement vertical ascendant de l’huile poussée par de l’eau dans une colonne poreuse a été réalisée et les résultats ont été comparés à nos expériences sous IRMIt is important to understand the driving forces that control the flow of two immiscible fluids in a porous medium. Indeed, there is a wide range of applications of two-phase flows in porous media, especially those relating to enhanced oil recovery (EOR). The development of quantitative magnetic resonance imaging (MRI) techniques opens up new possibilities for studying and characterizing multiphase flows in porous media. This work is specifically concerned with describing the displacement of two immiscible fluids (water-oil) in a porous medium using MRI techniques. The porous medium is initially saturated with oil which is displaced by injecting water from below, oil and water can be evacuated from above. The general objective of the study is to determine the displacement and the deformation of the front (water-oil) over time, and to specify the trapping mechanisms of the phases. Experiments are conducted on two porous models. One oil wetting consists of a stack of small polystyrene beads (0.4 mm < dp < 0.6 mm), the other wetting with water is a slightly compacted sand (0.02 mm < dp <0.50 mm). We used a 14 T NMR micro-imaging device (1H resonance at 600 MHz) to acquire high resolution images (0.2 mm) inside the porous media during the movement of the two fluids. The results obtained showed that the oil saturation profile is strongly influenced by the properties of the porous material, such as the porosity and the permeability of the sample, the wetting of the phases, the injection rate of the water or even the heterogeneity of the solid matrix. The influence of the water injection flow rate on the residual saturation of oil has been studied more particularly. The experimental results allow a fine understanding of the displacement of two immiscible fluids for two types of porous media, which mainly differ by the effects of wettability. At the same time, a numerical simulation of the upward vertical displacement of oil pushed by water in a porous column was performed and the results compared to our MRI experiments
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SOUZA, Márcio Rodrigo de Araújo. "Simulação Numérica de Escoamento Bifásico em reservatório de Petróleo Heterogêneos e Anisotrópicos utilizando um Método de Volumes Finitos “Verdadeiramente” Multidimensional com Aproximação de Alta Ordem." Universidade Federal de Pernambuco, 2015. https://repositorio.ufpe.br/handle/123456789/17248.
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Sob certas hipóteses simplificadoras, o modelo matemático que descreve o escoamento de água e óleo em reservatórios de petróleo pode ser representado por um sistema não linear de Equações Diferenciais Parciais composto por uma equação elíptica de pressão (fluxo) e uma equação hiperbólica de saturação (transporte). Devido a complexidades na modelagem de ambientes deposicionais, nos quais são incluídos camadas inclinadas, canais, falhas e poços inclinados, há uma dificuldade de se construir um modelo que represente adequadamente certas características dos reservatórios, especialmente quando malhas estruturadas são usadas (cartesianas ou corner point). Além disso, a modelagem do escoamento multifásico nessas estruturas geológicas incluem descontinuidades na variável e instabilidades no escoamento, associadas à elevadas razões de mobilidade e efeitos de orientação de malha. Isso representa um grande desafio do ponto de vista numérico. No presente trabalho, uma formulação fundamentada no Método de Volumes Finitos é estudada e proposta para discretizar as equações elíptica de pressão e hiperbólica de saturação. Para resolver a equação de pressão três formulações robustas, com aproximação dos fluxos por múltiplos pontos são estudadas. Essas formulações são abeis para lidar com tensores de permeabilidade completos e malhas poligonais arbitrárias, sendo portanto uma generalização de métodos mais tradicionais com aproximação do fluxo por apenas dois pontos. A discretização da equação de saturação é feita com duas abordagens com característica multidimensional. Em uma abordagem mais convencional, os fluxos numéricos são extrapolados diretamente nas superfícies de controle por uma aproximação de alta resolução no espaço (2ª a 4ª ordem) usando uma estratégia do tipo MUSCL. Uma estratégia baseada na Técnica de Mínimos Quadrados é usada para a reconstrução polinomial. Em uma segunda abordagem, uma variação de uma esquema numérico Verdadeiramente Multidimensional é proposto. Esse esquema diminui o efeito de orientação de malha, especialmente para malhas ortogonais, mesmo embora alguma falta de robustez possa ser observada pra malhas excessivamente distorcidas. Nesse tipo de formulação, os fluxos numéricos são calculados de uma forma multidimensional. Consiste em uma combinação convexa de valores de saturação ou fluxo fracionário, seguindo a orientação do escoamento através do domínio computacional. No entanto, a maioria dos esquemas numéricos achados na literatura tem aproximação apenas de primeira ordem no espaço e requer uma solução implícita de sistemas algébricos locais. Adicionalmente, no presente texto, uma forma modificada desses esquemas “Verdadeiramente” Multidimensionais é proposta em um contexto centrado na célula. Nesse caso, os fluxos numéricos multidimensionais são calculados explicitamente usando aproximações de alta ordem no espaço. Para o esquema proposto, a robustez e o caráter multidimensional também leva em conta a distorção da malha por meio de uma ponderação adaptativa. Essa ponderação regula a característica multidimensional da formulação de acordo com a distorção da malha. Claramente, os efeitos de orientação de malha são reduzidos. A supressão de oscilações espúrias, típicas de aproximações de alta ordem, são obtidas usando, pela primeira vez no contexto de simulação de reservatórios, uma estratégia de limitação multidimensional ou Multidimensional Limiting Process (MLP). Essa estratégia garante soluções monótonas e podem ser usadas em qualquer malha poligonal, sendo naturalmente aplicada em aproximações de ordem arbitrária. Por fim, de modo a garantir soluções convergentes, mesmo para problemas tipicamente não convexos, associados ao modelo de Buckley-Leverett, uma estratégia robusta de correção de entropia é empregada. O desempenho dessas formulações é verificado com a solução de problemas relevantes achados na literatura.
Under certain simplifying assumptions, the problem that describes the fluid flow of oil and water in heterogeneous and anisotropic petroleum reservoir can be described by a system of non-linear partial differential equations that comprises an elliptic pressure equation (flow) and a hyperbolic saturation equation (transport). Due to the modeling of complex depositional environments, including inclined laminated layers, channels, fractures, faults and the geometrical modeling of deviated wells, it is difficult to properly build and handle the Reservoir Characterization Process (RCM), particularly by using structured meshes (cartesian or corner point), which is the current standard in petroleum reservoir simulators. Besides, the multiphase flow in such geological structures includes the proper modeling of water saturation shocks and flow instabilities associated to high mobility ratios and Grid Orientation Effects (GOE), posing a great challenge from a numerical point of view. In this work, a Full Finite Volume Formulation is studied and proposed to discretize both, the elliptic pressure and the hyperbolic saturation equations. To solve the pressure equation, we study and use three robust Multipoint Flux Approximation Methods (MPFA) that are able to deal with full permeability tensors and arbitrary polygonal meshes, making it relatively easy to handle complex geological structures, inclined wells and mesh adaptivity in a natural way. To discretize the saturation equation, two different multidimensional approaches are employed. In a more conventional approach, the numerical fluxes are extrapolated directly on the control surfaces for a higher resolution approximation in space (2nd to 4th order) by a MUSCL (Monotone Upstream Centered Scheme for Conservation Laws) procedure. A least squares based strategy is employed for the polynomial reconstruction. In a second approach, a variation of a “Truly” Multidimensional Finite Volume method is proposed. This scheme diminishes GOE, especially for orthogonal grids, even though some lack of robustness can be observed for extremely distorted meshes. In this type of scheme, the numerical flux is computed in each control surface in a multidimensional way, by a convex combination of the saturation or the fractional flow values, following the approximate wave orientation throughout the computational domain. However, the majority of the schemes found in literature is only first order accurate in space and demand the implicit solution of local conservation problems. In the present text, a Modified Truly Multidimensional Finite Volume Method (MTM-FVM) is proposed in a cell centered context. The truly multidimensional numerical fluxes are explicitly computed using higher order accuracy in space. For the proposed scheme, the robustness and the multidimensional character of the aforementioned MTM-FVM explicitly takes into account the angular distortion of the computational mesh by means of an adaptive weight, that tunes the multidimensional character of the formulation according to the grid distortion, clearly diminishing GOE. The suppression of the spurious oscillations, typical from higher order schemes, is achieved by using for the first time in the context of reservoir simulation a Multidimensional Limiting Process (MLP). The MLP strategy formally guarantees monotone solutions and can be used with any polygonal mesh and arbitrary orders of approximation. Finally, in order to guarantee physically meaningful solutions, a robust “entropy fix” strategy is employed. This produces convergent solutions even for the typical non-convex flux functions that are associated to the Buckley-Leverett problem. The performance of the proposed full finite volume formulation is verified by solving some relevant benchmark problems.
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Ligiero, Leticia. "Crude oil/water interface characterization and its relation to water-in-oil emulsion stability." Thesis, Pau, 2017. http://www.theses.fr/2017PAUU3048/document.
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La formation d’émulsions stables eau/huile lors des processus de récupération et de raffinage du pétrole peut impacter défavorablement l’efficacité de ces opérations. Bien que résines et asphaltènes soient généralement tenus pour responsables de la stabilité des émulsions, la composition exacte des molécules présentes à l’interface eau/huile est en réalité assez mal connue. L’identification de ces molécules et la connaissance de leur influence sur la propriété des interfaces est une étape nécessaire pour mieux prédire les problèmes de stabilité des émulsions dans l’industrie pétrolière. Cette thèse présente des résultats de caractérisation analytique par GPC-ICP-HRMS et FTMS du matériel interfacial (IM) extrait de quatre bruts différents et des espèces transférées dans la phase aqueuse lorsque ces bruts contactent l’eau, ainsi que des propriétés rhéologiques en cisaillement et en dilatation des interfaces eau/huile en présence de ces composés. Les bruts ont été choisis en raison de leur capacité à former des émulsions eau-dans-huile de stabilités différentes. Les mesures d’élasticité de cisaillement ont montré que la majorité des interfaces eau/huile étudiées formaient une structure élastique susceptible de fausser la mesure du module dilatationnel de Gibbs par la méthode d’analyse du profil de goutte. Néanmoins, nous montrons à l’aide de simulations numériques que le module apparent Eapp mesuré dans un tel cas est proche de la somme du module de Gibbs et du module de cisaillement (G) multiplié par 2 du réseau interfacial dès lors que G reste petit (G < 10 mN/m), ce qui est très souvent le cas puisque nous observons que le réseau interfacial formé se rompt lors des expériences de dilatation. Une équation phénoménologique a été développée permettant d’attribuer un temps de relaxation unique aux processus de relaxation qui ont lieu aux interfaces eau/huile, ce qui nous permet de classer les différents systèmes entre eux. Nous avons également étudié les IM extraits des bruts selon la technique chromatographique dite « wet silica method » récemment développée par Jarvis et al. (Energy Fuels, 2015). Les expériences de rhéologie interfaciale confirment que cette méthode permet d’extraire les composés les plus tensioactifs présents aux interfaces eau-brut. Les analyses chimiques montrent que les IM sont partiellement composés d’asphaltènes et suggèrent que les composés contenant du soufre jouent un rôle important dans la stabilité des émulsions. Enfin, nous avons trouvé que les composés hydrosolubles transférés du brut à l’eau ont un comportement bénéfique, dans le sens où leur présence rend les émulsions eau-dans-brut moins stables. L’analyse FTMS de ces composés montre qu’ils appartiennent aux classes d’hétéroatomes suivant : O2, O3, S1, OS et O2S2 et qu’une partie de ces composés appartient à la classe des asphaltènesCrude oil recovery and refining operations rely on high consumption water processes, which may induce the formation of stable water-in-oil emulsions. Although asphaltenes and resins are known to influence the stability of crude oil emulsions, much is still unknown about the real composition of the w/o interfacial layer. Therefore, identifying these molecules and understanding their impact on the w/o interfacial properties are key points for better predicting emulsion problems in the petroleum industry. This thesis presents results on water/oil (w/o) interface characterization using shear and dilatational interfacial rheology as well as results on molecular characterization (GPC-ICP-HRMS and FTMS) of the crude oil interfacial material (IM) and of the amphiphilic crude oil species, which are transferred to the aqueous phase during the emulsification process. Four crude oils forming w/o emulsions of different stability were used in this study. Shear interfacial rheology experiments showed that most of the studied w/o interfaces were capable of forming an elastic interfacial network exhibiting shear elasticity G. A non-null G value interferes on drop deformation and thus on drop shape analysis (DSA) results. Nevertheless, the dilatational elasticity modulus measured by DSA (Eapp) was found to be representative of the sum of the Gibbs modulus plus 2 times G, as long as G 10 mN/m. This condition is generally satisfied since the asphaltene network is broken during dilatational experiments. Consequently, Eapp gives a good approximation of the real Gibbs modulus of the interface. A new phenomenological equation was proposed to fit the dilatational Eapp experimental data, allowing the assignment of a unique characteristic time to describe the w/o interfacial relaxation process and thus sample comparison. The IM of the crude oils was extracted using the “wet silica method” recently developed by Jarvis et al. (Energy Fuels, 2015). Results showed that this method collects the most-surface active compounds that adsorb in the time frame of the extraction procedure. Successive extractions collected species that were larger and less concentrated in the crude oil, but with higher adsorption energies. Molecular characterization revealed that the IM was partially composed of asphaltene compounds, and suggested that sulfur-containing compounds may play a major role in emulsion stability. Lastly, the oil-to-water transferred species were proven to impact the w/o interfacial properties and emulsion stability. Interestingly, concentrating these water-soluble species led to more efficient crude oil dehydration. FTMS analysis of the transferred species revealed that part of the compounds belonged to O2, O3, S1, OS and O2S2 heteroatom classes, and some of them have an asphaltene-type of molecules classification
Books on the topic "Oil and water displacementsi"
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B, Scott P. J., ed. Oilfield water technology. Houston, Tex: NACE International, 2006.
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Yale Center for British Art., ed. Oil on water: Oil sketches by British watercolorists. New Haven, Conn: Yale Center for British Art, 1986.
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Bhushan, Bharat. Bioinspired Water Harvesting, Purification, and Oil-Water Separation. Cham: Springer International Publishing, 2020. http://dx.doi.org/10.1007/978-3-030-42132-8.
Full textBook chapters on the topic "Oil and water displacementsi"
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Li, Dang, and Junbin Chen. "Foundation of Water/Oil Displacement Theory." In Mechanics of Oil and Gas Flow in Porous Media, 183–237. Singapore: Springer Singapore, 2020. http://dx.doi.org/10.1007/978-981-15-7313-2_6.
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Barenblatt, G. I., V. M. Entov, and V. M. Ryzhik. "Two-Phase Flow and Water-Oil Displacement." In Theory of Fluid Flows Through Natural Rocks, 230–319. Dordrecht: Springer Netherlands, 1990. http://dx.doi.org/10.1007/978-94-015-7899-8_5.
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Bedrikovetsky, Pavel, and Gren Rowan. "Displacement of Oil by a Chemical Slug with Water Drive." In Mathematical Theory of Oil and Gas Recovery, 138–73. Dordrecht: Springer Netherlands, 1993. http://dx.doi.org/10.1007/978-94-017-2205-6_7.
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Bedrikovetsky, Pavel, and Gren Rowan. "Displacement of Non-Newtonian Oil by Hot Water with Heat Losses to Adjacent Layers." In Mathematical Theory of Oil and Gas Recovery, 244–56. Dordrecht: Springer Netherlands, 1993. http://dx.doi.org/10.1007/978-94-017-2205-6_14.
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Zhang, Xiangzhong, Lun Zhao, Jincai Wang, Li Chen, and Xiangan Yue. "Effect of WaterFlooding Speed on Water–Oil Displacement Efficiency of Homogeneous Core." In Proceedings of the International Field Exploration and Development Conference 2018, 932–37. Singapore: Springer Singapore, 2019. http://dx.doi.org/10.1007/978-981-13-7127-1_86.
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Qadeer, S., K. Dehghani, D. O. Ogbe, and R. D. Ostermann. "Correcting Oil-Water Relative Permeability Data for Capillary End Effect in Displacement Experiments." In Particle Technology and Surface Phenomena in Minerals and Petroleum, 81–104. Boston, MA: Springer US, 1991. http://dx.doi.org/10.1007/978-1-4899-0617-5_8.
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Bieber, M. T., B. Bourbiaux, and B. Legait. "Oil Displacement by Water in Porous Media and Determination of the Laws of Flow." In Optimization of the Production and Utilization of Hydrocarbons, 250–64. Dordrecht: Springer Netherlands, 1992. http://dx.doi.org/10.1007/978-94-011-2256-6_15.
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Schuchmann, Heike P., Karsten Köhler, Freddy Aguilar, and Andreas Hensel. "Oil-in-Water and Water-in-Oil Emulsions." In Micro Process Engineering, 325–43. Weinheim, Germany: Wiley-VCH Verlag GmbH & Co. KGaA, 2013. http://dx.doi.org/10.1002/9783527631445.ch37.
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Li, Na. "Oil-Water Emulsion." In Encyclopedia of Membranes, 1–2. Berlin, Heidelberg: Springer Berlin Heidelberg, 2013. http://dx.doi.org/10.1007/978-3-642-40872-4_730-4.
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Li, Na. "Oil-Water Emulsion." In Encyclopedia of Membranes, 1424–25. Berlin, Heidelberg: Springer Berlin Heidelberg, 2016. http://dx.doi.org/10.1007/978-3-662-44324-8_730.
Full textConference papers on the topic "Oil and water displacementsi"
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Lepski, B., Z. Bassiouni, and J. Wolcott. "Second-Contact Water Displacement Oil Recovery Process." In SPE/DOE Improved Oil Recovery Symposium. Society of Petroleum Engineers, 1996. http://dx.doi.org/10.2118/35360-ms.
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Xu, Guangli, Liangxue Cai, Amos Ullmann, and Neima Brauner. "Trapped Water Flushed by Flowing Oil in Upward-Inclined Oil Pipelines." In 2012 9th International Pipeline Conference. American Society of Mechanical Engineers, 2012. http://dx.doi.org/10.1115/ipc2012-90680.
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Pipe-line corrosion is of a major concern in the transportation of crude oil and natural gas. The corrosion is caused by the presence of water in contact with the walls. Following water-tests and/or shut-down, small amounts of water tend to accumulate at low sections along the pipe line. Flushing out of the water from the pipe by the oil flow is required to avoid damages in the pipeline. From a practical point of view, the minimal oil flow rate required for displacement and flush-out of the accumulated water by the oil flow has to be determined. Experimental study, mechanistic models and numerical simulations are used to investigate the characteristics of water displacement by oil flow in hilly terrain pipelines. Various mechanisms for the onset of water displacement from a lower (horizontal) section into an upward inclined section are considered and the associated minimal (critical) oil-flow rate for the water displacement is evaluated. For oil-flow rates exceeding the critical value, the possible patterns of water movement in the inclined pipe are examined.
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Vittoratos Inc., E. S., C. C. West Inc., and C. J. Black. "Flow Regimes of Heavy Oils under Water Displacement." In IOR 2007 - 14th European Symposium on Improved Oil Recovery. European Association of Geoscientists & Engineers, 2007. http://dx.doi.org/10.3997/2214-4609-pdb.24.b12.
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Dietrich, James K. "The Displacement of Heavy Oil From Diatomite Using Hot Water and Steam." In SPE Improved Oil Recovery Symposium. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/129705-ms.
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Xie, J., and M. Pooladi-Darvish. "Upscaling of Oil-Water Displacement in Naturally Fractured Reservoirs." In Canadian International Petroleum Conference. Petroleum Society of Canada, 2004. http://dx.doi.org/10.2118/2004-146.
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Cruz-Hernandez, J., R. Islas-Juarez, C. Perez-Rosales, S. Rivas-Gomez, A. Pineda-Munoz, and J. A. Gonzalez-Guevara. "Oil Displacement by Water in Vuggy Fractured Porous Media." In SPE Latin American and Caribbean Petroleum Engineering Conference. Society of Petroleum Engineers, 2001. http://dx.doi.org/10.2118/69637-ms.
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Barenblatt, G. I., T. W. Patzek, and D. B. Silin. "The Mathematical Model of Non-Equilibrium Effects in Water-Oil Displacement." In SPE/DOE Improved Oil Recovery Symposium. Society of Petroleum Engineers, 2002. http://dx.doi.org/10.2118/75169-ms.
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Riazi, M., M. Riazi, M. Jamiolahmady, S. Ireland, and C. Brown. "Direct Observation of CO2 Transport and Oil Displacement Mechanisms in CO2/Water/Oil Systems." In IOR 2009 - 15th European Symposium on Improved Oil Recovery. European Association of Geoscientists & Engineers, 2009. http://dx.doi.org/10.3997/2214-4609.201404841.
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Gorell, S. B. "Modeling the Effects of Trapping and Water Alternate Gas (WAG) Injection on Tertiary Miscible Displacements." In SPE Enhanced Oil Recovery Symposium. Society of Petroleum Engineers, 1988. http://dx.doi.org/10.2118/17340-ms.
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Sincock, K. J., and C. J. J. Black. "Validation of Water/Oil Displacement Scaling Criteria Using Microvisualization Techniques." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 1988. http://dx.doi.org/10.2118/18294-ms.
Full textReports on the topic "Oil and water displacementsi"
1
Evans, D., H. Baum, B. McCaffrey, G. Mulholland, M. Harkleroad, and W. Menders. Combustion of oil on water. Gaithersburg, MD: National Bureau of Standards, 1987. http://dx.doi.org/10.6028/nbs.ir.86-3420.
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2
Skone, Timothy J. Oilfield Gas, Water, and Oil Separation. Office of Scientific and Technical Information (OSTI), October 2012. http://dx.doi.org/10.2172/1509428.
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3
Swanson, C. Development of the oil-water monitor. Office of Scientific and Technical Information (OSTI), April 1990. http://dx.doi.org/10.2172/6856927.
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Dwyer, Brian P. Treatment of Oil & Gas Produced Water. Office of Scientific and Technical Information (OSTI), February 2016. http://dx.doi.org/10.2172/1238102.
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Heller, A., and J. R. Brock. Photoassisted oxidation of oil films on water. Office of Scientific and Technical Information (OSTI), October 1990. http://dx.doi.org/10.2172/6470338.
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Heller, A., and J. R. Brock. Photoassisted oxidation of oil films on water. Office of Scientific and Technical Information (OSTI), August 1991. http://dx.doi.org/10.2172/5117156.
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Veil, J. A., and J. J. Quinn. Water issues associated with heavy oil production. Office of Scientific and Technical Information (OSTI), November 2008. http://dx.doi.org/10.2172/943431.
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Klara, Paul C. Coalescing Tubes Test for Oil/Water Separators (OWSs). Fort Belvoir, VA: Defense Technical Information Center, September 1998. http://dx.doi.org/10.21236/ada354868.
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Coulombe, S., B. A. Farnand, and H. Sawatzky. Characterization of surfactants isolated by ultrafiltration from enhanced oil recovery oil-in-water emulsions. Natural Resources Canada/ESS/Scientific and Technical Publishing Services, 1986. http://dx.doi.org/10.4095/302671.
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Veil, J. A., B. G. Langhus, and S. Belieu. Feasibility evaluation of downhole oil/water separator (DOWS) technology. Office of Scientific and Technical Information (OSTI), January 1999. http://dx.doi.org/10.2172/917614.
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