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Kun Sang Lee - One of the best experts on this subject based on the ideXlab platform.
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assessment of npv uncertainty on heterogeneous reservoirs during Polymer Flood
Applied Mechanics and Materials, 2013Co-Authors: Byung In Choi, Kun Sang LeeAbstract:This study shows net present value (NPV) distribution by considering uncertainties in porosity, oil viscosity, water saturation, and permeability for Polymer Flood with Monte Carlo simulation. For high and low average permeability conditions, differences of NPV between Polymer Flooding and water Flooding have been investigated. According to results both average NPV and range of NPV distribution tend to increase with porosity and permeability in all cases. Although water saturation and oil viscosity affect NPV, they are not important parameters that conclude uncertainty of NPV under the conditions considered in this study. For high permeability model which has Dykstra-Parsons coefficient (DP) as 0.72 and porosity as 0.3088, Monte Carol simulations for Polymer Flood show that 50th percentile (P50) of NPV is 352.81 M$. If porosity is decreased from 0.3088 to 0.1912, the P50 is also decreased 63.8 %. The reduction of NPV during Polymer Flooding in low permeability reservoirs are almost 40 % higher than that of water Flood. These differences come from Polymer adsorption and permeability reduction that easily occurs in low permeability zone. The procedure has proven to be useful tool to generate probability distribution of NPV when Polymer Flood is selected as a tertiary Flood process.
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The Effects of the Shear-thinning Property of Injection Fluid on the Performance of Polymer Flood
Energy Sources Part A-recovery Utilization and Environmental Effects, 2013Co-Authors: Kun Sang LeeAbstract:Assessment of the potential of a Polymer Flood process for mobility control requires an accurate model on the viscosities of displacement fluids. Because most Polymers used in enhanced oil recovery exhibit shear-thinning behavior, effective viscosity of Polymer solution is a highly nonlinear function of shear rate. A reservoir simulator, including the model for the shear-rate dependence of viscosity, was used to investigate the shear-thinning effects of Polymer solution on the performance of the reservoir in a five-spot pattern operating under Polymer Flood followed by waterFlood. The model can be used as a quantitative tool to evaluate the comparative studies of different Polymer Flooding scenarios with respect to shear-rate dependence of fluids' viscosities. Results of cumulative oil recovery, injectivity, and distributions of Polymer concentration and aqueous phase viscosity are presented for parameters of shear-rate dependencies, permeability, and injection rate. The results of this work have proven t...
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application of horizontal wells to improve injectivity during Polymer Flood processes
Petroleum Science and Technology, 2011Co-Authors: Kun Sang LeeAbstract:Abstract This numerical study was undertaken to investigate and compare the performances of Polymer Flood processes through horizontal or vertical wells. To achieve the objective, the author performed an extensive numerical simulation for 3 different well configurations under Polymer Flood followed by waterFlood. The potential for a horizontal well application was assessed through different scenarios in combinations of injection and production wells and reservoir geometry. Other parameters included the length and spacing of horizontal injectors and horizontal or vertical producers. For different parameters of the system, performances were compared in terms of cumulative recovery and water-oil ratio at the production well and pressure drop or injectivity at the injection well. Results demonstrate that additional oil can be recovered and injectivity was significantly improved by utilizing a combination of horizontal wells when the same volume of fluid is injected into the reservoir. The improvement of injec...
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performance of a Polymer Flood with shear thinning fluid in heterogeneous layered systems with crossflow
Energies, 2011Co-Authors: Kun Sang LeeAbstract:Assessment of the potential of a Polymer Flood for mobility control requires an accurate model on the viscosities of displacement fluids involved in the process. Because most Polymers used in EOR exhibit shear-thinning behavior, the effective viscosity of a Polymer solution is a highly nonlinear function of shear rate. A reservoir simulator including the model for the shear-rate dependence of viscosity was used to investigate shear-thinning effects of Polymer solution on the performance of the layered reservoir in a five-spot pattern operating under Polymer Flood followed by waterFlood. The model can be used as a quantitative tool to evaluate the comparative studies of different Polymer Flooding scenarios with respect to shear-rate dependence of fluids’ viscosities. Results of cumulative oil recovery and water-oil ratio are presented for parameters of shear-rate dependencies, permeability heterogeneity, and crossflow. The results of this work have proven the importance of taking non-Newtonian behavior of Polymer solution into account for the successful evaluation of Polymer Flood processes. Horizontal and vertical permeabilities of each layer are shown to impact the predicted performance substantially. In reservoirs with a severe permeability contrast between horizontal layers, decrease in oil recovery and sudden increase in WOR are obtained by the low sweep efficiency and early water breakthrough through highly permeable layer, especially for shear-thinning fluids. An increase in the degree of crossflow resulting from sufficient vertical permeability is responsible for the enhanced sweep of the low permeability layers, which results in increased oil recovery. It was observed that a thinning fluid coefficient would increase injectivity significantly from simulations with various injection rates. A thorough understanding of Polymer rheology in the reservoir and accurate numerical modeling are of fundamental importance for the exact estimation on the performance of Polymer Flood.
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the effects of temperature dependent fluids viscosity on the performance of a Polymer Flood in reservoir systems with an elevated temperature
Energy Sources Part A-recovery Utilization and Environmental Effects, 2011Co-Authors: Kun Sang LeeAbstract:Abstract Accurate assessment of the potential of a nonisothermal Polymer Flood process requires a model on the viscosities of reservoir fluids as a function of temperature. A three-dimensional numerical model for fluid flow, mass transport, and energy balance is used to analyze the performance of the reservoir in a five-spot pattern operating under Polymer Flood followed by waterFlood. The nonisothermal scheme can be used as a quantitative tool to evaluate the comparative studies of different Polymer Flooding scenarios with respect to temperature dependence of fluids' viscosities. Results of cumulative recovery and water-oil ratio at the production well are presented for various types of temperature dependencies, reservoir temperatures, and oil viscosities. Significant improvement in predicted oil recovery and reduction in water-oil ratio is obtained for the case of including temperature dependencies of both water and oil because the reduction of oil viscosity is larger than that of brine viscosity. The i...
Knut Taugbol - One of the best experts on this subject based on the ideXlab platform.
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chemical Flooding of oil reservoirs 1 low tension Polymer Flood using a Polymer gradient in the three phase region
Colloids and Surfaces A: Physicochemical and Engineering Aspects, 1995Co-Authors: Tor Austad, Knut TaugbolAbstract:Abstract This paper discusses the possibility of using a Polymer gradient at constant salinity in a three-phase low-tension Polymer Flood process. Six core Floods at 50°C have been conducted using Berea as the sandstone core, alkyl- o -xylene sulfonate as the surfactant, xanthan as the Polymer, n -heptane as the oil, and NaCl solution as the injection fluid. The oil recovery is compared by using a traditional salinity gradient to optimize the Flooding process. The Flooding mechanism is discussed in terms of the following two phenomena: (a) chromatographic separation of the Polymer and surfactant in the front of the chemical slug to prevent dispersion of the surfactant; (b) the decrease in the Polymer concentration at the rear of the surfactant slug to promote a III/II(−) phase transition in order to prevent trapping of surfactant.
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physicochemical principles of low tension Polymer Flood
Journal of Petroleum Science and Engineering, 1994Co-Authors: Tor Austad, Ingebret Fjelde, K Veggeland, Knut TaugbolAbstract:Abstract Co-injection of low-concentration surfactant and a bioPolymer, followed by a Polymer buffer for mobility control, leads to reduced chemical consumption and high oil recovery. The method has been termed Low Tension Polymer Flood, LTPF, by BP. The present paper gives a critical discussion of the physicochemical phenomena behind LTPF. Surfactant-Polymer interaction in solution and chromatographic separation of surfactant and Polymer during the Flooding process are believed to be important factors in performing a LTPF. The criteria with regard to chemicals and porous media are discussed in order to obtain LTPF performance. Flooding mechanisms are suggested based on an oil-in-water, II(−), and a multiphase, III, Flood behavior. It is suggested to use a Polymer gradient when implementing LTPF at constant salinity in the multiphase state to minimize the loss of surfactant. The HPLC method to study surfactant-Polymer complex formation, applying the gel filtration technique, is presented.
Kishore K. Mohanty - One of the best experts on this subject based on the ideXlab platform.
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a triblock coPolymer for Polymer Flood in porous media
Journal of Petroleum Science and Engineering, 2014Co-Authors: Krishna Panthi, Kishore K. MohantyAbstract:Abstract High molecular weight Polymers are used in petroleum reservoir Polymer Floods to enhance oil recovery. The objective of this work is to evaluate small Polymeric surfactants for their viscosifying capacity in reservoir brines and oil displacement ability. The phase behavior and viscosity of a triblock coPolymer (P123) are studied as a function of brine salinity and temperature. Its flow through a porous rock and oil displacement is evaluated and compared with that of a Newtonian fluid (glycerol) and a non-Newtonian fluid with a high molecular weight Polymer (HPAM) of similar viscosity. P123 forms cylindrical micelles in brine to give high viscosity. The viscosity increases with salinity at a low salinity, but decreases at a higher salinity. In the secondary mode, both the Polymers (P123 and HPAM) and glycerol solutions increase the oil recovery significantly over the water Flood. The oil recovery is similar for the three viscous fluids. In the tertiary mode, none of the viscous fluids increased oil recovery over the waterFlood at typical field rates. Pressure drop during P123 Flood is significantly lower than the pressure drop during HPAM and glycerol Floods of similar initial viscosity. Viscosity of the aqueous P123 solution decreases when it is equilibrated with oil. Some of the cylindrical micelles are converted to spherical micelles in the presence of solubilized oil. P123 is not as cost effective as HPAM because it is slightly more expensive and needs a higher concentration for a similar viscosity.
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Effect of Alkaline Preflush in an Alkaline-Surfactant-Polymer Flood
Energy & Fuels, 2013Co-Authors: Krishna Panthi, Kishore K. MohantyAbstract:An ultralow interfacial tension alkali-surfactant-Polymer formulation was developed for a sandstone reservoir. Phase behavior was studied with the reservoir oil at different water–oil ratios and varying salt/alkali concentrations. The rheology of the resulting microemulsion phases was measured with and without Polymers. The surfactant formulation was tested with a field core and an out-crop core, with and without an alkaline preflush. WaterFlood recovered about 48% of the oil in place and reduced the oil saturation to 35% for the field core. The tertiary ASP injection in the field core without alkaline preflush yielded 80% cumulative oil recovery; the recovery increased to 85% in the same core (and the same surfactant formulation) if the alkaline preflush was used. The oil recovery in the out-crop core with the alkaline preflush was 94%. Alkaline preflush increases the core salinity to the optimum salinity of the surfactant formulation before the surfactant slug.
Tor Austad - One of the best experts on this subject based on the ideXlab platform.
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chemical Flooding of oil reservoirs 1 low tension Polymer Flood using a Polymer gradient in the three phase region
Colloids and Surfaces A: Physicochemical and Engineering Aspects, 1995Co-Authors: Tor Austad, Knut TaugbolAbstract:Abstract This paper discusses the possibility of using a Polymer gradient at constant salinity in a three-phase low-tension Polymer Flood process. Six core Floods at 50°C have been conducted using Berea as the sandstone core, alkyl- o -xylene sulfonate as the surfactant, xanthan as the Polymer, n -heptane as the oil, and NaCl solution as the injection fluid. The oil recovery is compared by using a traditional salinity gradient to optimize the Flooding process. The Flooding mechanism is discussed in terms of the following two phenomena: (a) chromatographic separation of the Polymer and surfactant in the front of the chemical slug to prevent dispersion of the surfactant; (b) the decrease in the Polymer concentration at the rear of the surfactant slug to promote a III/II(−) phase transition in order to prevent trapping of surfactant.
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physicochemical principles of low tension Polymer Flood
Journal of Petroleum Science and Engineering, 1994Co-Authors: Tor Austad, Ingebret Fjelde, K Veggeland, Knut TaugbolAbstract:Abstract Co-injection of low-concentration surfactant and a bioPolymer, followed by a Polymer buffer for mobility control, leads to reduced chemical consumption and high oil recovery. The method has been termed Low Tension Polymer Flood, LTPF, by BP. The present paper gives a critical discussion of the physicochemical phenomena behind LTPF. Surfactant-Polymer interaction in solution and chromatographic separation of surfactant and Polymer during the Flooding process are believed to be important factors in performing a LTPF. The criteria with regard to chemicals and porous media are discussed in order to obtain LTPF performance. Flooding mechanisms are suggested based on an oil-in-water, II(−), and a multiphase, III, Flood behavior. It is suggested to use a Polymer gradient when implementing LTPF at constant salinity in the multiphase state to minimize the loss of surfactant. The HPLC method to study surfactant-Polymer complex formation, applying the gel filtration technique, is presented.
Tahi Muhammad - One of the best experts on this subject based on the ideXlab platform.
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Experimental investigation of sulfate-modified water and Polymer Flooding for enhanced oil recovery
2020Co-Authors: Tahi MuhammadAbstract:Modified/smart water Flooding is a low-cost enhanced oil recovery (EOR) technique that works through the manipulation of injected water chemistry to disturb the established ionic equilibrium in a reservoir system. Chemical manipulation is achieved by the addition/removal of active/non-active ions, respectively. Added active ions are known as potential determining ions (PDI) while removed non-active ions are known as non-potential determining ions (non-PDI). The focus of this study is to investigate the role of sulfate ions as PDI to select an optimum injection scheme and initiation time. This work investigates the combination of two EOR methods (also known as the hybrid method)—modified water Flooding in the secondary mode and low-concentration Polymer Flooding in the tertiary mode—to enhance the capability of the Flooding process. Modified water triggered fluid-fluid and rock-fluid interactions, and follow-up Polymer Flood improved the macroscopic sweep efficiency due to a favourable displacement mobility ratio. Hence, the hybrid EOR method is expected to be low-cost (as low Polymer concentrations are required) and to provide the combined benefits of both EOR processes. This research work is focusing on experimental work. Evaluations were performed through comprehensive laboratory evaluations that included measurements of rheological behaviour, contact angle, interfacial tension, oil drop snap-off volume, and wettability alteration. Furthermore, the synergetic effects of modified water and Polymer Flooding were defined by Flooding experiments using two types of micromodels with modified-wettability and complemented with core Flooding in Bentheimer outcrops. The objective of the study is to investigate whether the main recovery mechanism should be rock-fluid interaction, fluid-fluid interaction, or a combination of both as a potential lead. Synthetic seawater (SSW) was used as the benchmark. Brine optimization was performed by tuning the brine salinity and concentration of the sulfate, by either diluting the brine to achieve total dissolved solids of around 5g/L or maintaining the salinity of the SSW. Further, two types of formation brine (SSW, 2*SSW) were used to compare the impact and significance of the presence of divalent cations (the hardness contrast between the injection and formation brine). Subsequently, to investigate wettability alteration, Bentheimer core plugs and glass-silicon-glass micromodels were used as porous media for Flooding experiments and to cross-validate the results. Three-week and six-week aging of core plugs were considered to establish the attachment of oil polar compounds resulting in mixed-wet and oil-wet core plugs. Similarly, oil-wet, complex/mix-wet, and water-wet micromodels were used for oil recovery comparison. Brine Floods were performed as the secondary mode and Polymer Flooding as the tertiary mode to optimize the synergies and benefits of the hybrid EOR techniques. In addition, single-phase core-Flooding experiments were performed to investigate the role of sulfates, salinity, and hardness for the Polymer viscoelastic properties. Oil recovery from core plugs was mainly obtained by alteration of the local wettability to water-wet, which resulted from strong rock-fluid interaction as well as fluid-fluid interaction at the fluid interface. However, the recovery factor from the oil-wet/mixed-wet micromodel was achieved only through fluid-fluid interaction. The main reason for this is that the oil-wetting condition in the micromodel was achieved by the chemisorption of fluorinated silane at the matrix structure, which made it impossible for the modified water to promote a change of the micromodel’s wettability to a water-wet state. Oil recovered from the two porous media approaches support the finding that wettability and fluid-fluid interactions result in more oil recovery when the injected brine is spiked with sulfate than SSW alone. Oil recovery comparison of oil-wet/mixed-wet with water-wet micromodels demonstrates that an initial oil-wetting condition is a basic requirement for the success of modified water Flooding. Moreover, comparing data on the wettability alteration of core plugs and micromodels shows this recovery mechanism dominates over fluid-fluid interfacial interaction. Further, Polymer Flooding after modified water injection produced significantly higher recovery compared to the seawater base brine combined with Polymer Flooding. According to the single-phase Polymer Flooding data, the presence of sulfate increased Polymer sensitivity to mechanical degradation. Further, Polymer spiked with sulfate had higher pressure in two-phase Polymer Flooding due to the interfacial ionic layer developed between the pre-flushed brine and dead oil. Finally, a brief exercise evaluating the economic scenario of the project showed that sulfate-modified brine is a cost-effective process based on oil recovery.Wasserfluten gehört zu den Standardverfahren bei der Ölgewinnung. Hierbei wird produziertes Lagerstättenwasser genutzt welches hohe Salzkonzentrationen besitzt. Der Einfluss der im Wasser gelösten Ionen auf den Verdrängungsprozess ist Gegenstand der aktuellen Forschung. Wasserfluten mit chemisch modifiziertem Wasser ist eine verhältnismassig kosteneffektive EOR-Methode bei der die chemische Zusammensetzung des injizierten Salzwassers verändert wird. Hierdurch wird das Gleichgewicht der Ionen im Reservoir verändert. Bei der chemischen Manipulation werden die Konzentrationen von aktiven und passiven Ionen verändert. Aktive Ionen werden als potentialbestimmende Ionen bezeichnet (PDI). Diese Arbeit untersucht den Einfluss von Sulfat-Ionen um den optimalen Injektionszeitpunkt und ein passendes Injektionsschema zu ermitteln. Es wird eine Kombination aus zwei EOR-Methoden (Hybridmethode) genutzt. (1) Wasserfluten mit modifizierter Ionenkonzentration im sekundären Modus und (2) Polymerfluten mit geringer Konzentration im tertiären Modus. Das modifizierte Injektionswasser verändert die Wechselwirkungen zwischen den Fluiden sowie zwischen Fluid und Gestein. Anschließendes Polymerfluten optimiert die makroskopische Verdrängung von Öl durch eine stabilisierte Verdrängungsfront. Es wird erwartet, dass eine Hybridmethode kosteneffektiv ist (geringe Polymerkonzentration) und die mikroskopischen und makroskopischen Effekte beider Methoden kombiniert werden. Der Fokus dieser Forschungsarbeit liegt auf experimentellen Untersuchungen. Die Laboruntersuchungen beinhalten rheologische Messungen, Kontaktwinkel-Messungen, Grenzflächenspannung, dynamische Grenzflächenspannung sowie die Veränderung der Benetzbarkeit. Des Weiteren wurden Synergieeffekte zwischen modifiziertem Wasserfluten und Polymerfluten untersucht. Hierfür wurden Flutversuche in Mikromodellen mit zwei unterschiedlichen porösen Strukturen sowie unterschiedlicher Benetzbarkeit durchgeführt. Abschließend wurden Kernflutversuche in Bentheimer Sandstein durchgeführt. Das Ziel dieser Untersuchung ist die Klärung ob der Verdrängungsmechanismus auf Wechselwirkung zwischen den Fluiden, zwischen Fluid und Gestein oder auf einer Kombination basiert. Als Standard dienen Flutversuche mit synthetischem Meerwasser (SSW). Durch Veränderung der Salinität und durch Zugabe von Sulfat-Ionen wurde die Zusammensetzung der Salzlösung modifiziert. Zwei Salzlösungen mit unterschiedlicher Salinität wurden eingesetzt (SSW, 2*SSW) um den Einfluss divalenter Ionen auf den Gewinnungsprozess zu untersuchen (unterschiedliche Härte zwischen Injektionslösung und Reservoir-Lösung). Anschließend wurde die Benetzbarkeitsänderung untersucht. Hierfür wurden Flutversuche in Bentheimer Sandsteinkernen und Glass-Silizium-Glass Mikromodellen durchgeführt. Die Gesteinskerne wurden für drei bzw. sechs Wochen gealtert, um die Adsorption polarer Ölkomponenten auf der Gesteinsoberfläche sicherzustellen. Die Gesteinskerne besaßen somit gemischte Benetzbarkeit bzw. waren ölbenetzend. Zum Vergleich wurden die Mikrodelle modifiziert um ölbenetzende, gemischt benetzende und wasserbenetzende Oberflächen zu erhalten. Salzwasserfluten im sekundären- und Polymerfluten im tertiären Modus wurden durchgeführt. Zusätzlich wurden Einphasen-Versuche vorgenommen um den Einfluss von Salinität, Härtegrad und Sulfat-Gehalt zu untersuchen. Die zusätzliche Ölausbeute war Folge der Änderung der lokalen Benetzbarkeit von ölbenetzend hin zu wasserbenetzend. Dies war eine Folge starker Gestein-Fluid Wechselwirkungen, sowie Fluid-Fluid Wechselwirkungen. Jedoch, im Mikromodell war die Ölgewinnung eine Folge von Fluid-Fluid Wechselwirkungen. Dieser Unterschied rührt aus der Tatsache, dass die ölbenetzende Eigenschaft des Mikromodells durch Chemisorption flourinierter Silane erzeugt wurde und somit keine Änderung der Benetzbarkeit während des Experiments möglich war. Die Ergebnisse unterstützen die Annahme, dass die Injektion einer mit Sulfaten versetzter Salzlösung zu einer Änderung der Benetzbarkeit sowie Fluid-Fluid Wechselwirkungen führt. Als Folge wird eine zusätzliche Ölgewinnung beobachtet. Ölbenetzende Eigenschaften des porösen Mediums sind hierfür eine grundlegende Voraussetzung. Der Vergleich von Gesteinskernen und Mikromodellen macht deutlich, dass die Änderung der Benetzbarkeit der dominierende Mechanismus ist. Des Weiteren führte das Polymerfluten im Anschluss an das Wasserfluten mit Sulfat dotierter Salzlösung zu einer deutlich höheren Ausbeute im Vergleich zum Benchmark. Einphasenversuche zeigten, dass die Präsenz von Sulfat-Ionen mechanische Degradation des Polymers verstärkt. Des Weiteren führte der Einsatz von Sulfat-Ionen zu einem erhöhten Differenzialdruck beim anschließenden Polymerfluten. Diese Beobachtung wird auf Ionen-Wechselwirkungen an der Grenzfläche zwischen der Salzlösung und dem Öl zurückgeführt. Abschließend zeigte eine vereinfachte ökonomische Bewertung, dass Wasserfluten eine kosteneffektive EOR Methode ist
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Unlocking the effects of fluid optimization on remaining oil saturation for the combined sulfate-modified water and Polymer Flooding
'MDPI AG', 2020Co-Authors: Tahi Muhammad, Hincapie, Rafael E., Ganze L.Abstract:Interfacial interactions and wettability alteration remain as the main recovery mechanism when modified water is applied seeking to obtain higher oil recoveries. Fluid-fluid interaction could lead to the development of the called viscoelastic layer at the interface in oil-brine systems. This interfacial layer stabilizes thanks to the slow chemical interaction between oil polar compounds and salts in the brine. This study investigates the role of sulfate presence in injection brine that could possible lead to develop the interfacial viscoelastic layer and hence to contribute to the higher oil recovery. Furthermore, Polymer Flooding is performed in tertiary mode after brine Flood to investigate/unlock the synergies and potential benefits of the hybrid enhanced oil recovery. Brine optimization is performed using the composition of two formation brines and four injection brines. Moreover, interfacial tension measurements and oil drop snap-off volume measurements are performed in parallel with the core Flooding experiments to define the role of interfacial viscoelasticity as the recovery mechanism other than wettability alteration. Synthetic seawater spiked with double amount of sulfate depicted potential results of interfacial viscoelastic layer development and hence to contribute the higher oil recovery. Total oil recovery after secondary-mode using sulfate-modified water and tertiary-mode Polymer Flood was higher than the combination of seawater brine in secondary-mode and Polymer Flood in tertiary-mode. Nevertheless, experiments helped us concluding that the amount of sulfate added is a critical factor to obtain maximum oil recovery and to avoid pore-plugging problems. We, therefore, demonstrate that executing a detailed fluid optimization leads to promising laboratory results, potentially linked with an improvement in the economics of the field applications
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Coupling microfluidics data with core Flooding experiments to understand sulfonated/Polymer water injection
'MDPI AG', 2020Co-Authors: Tahi Muhammad, Hincapie, Rafael E., Ganze L., Langanke Nils, Jaeger, Philip T.Abstract:The injection of sulfonated-modified water could be an attractive application as it results in the formation of a mechanically rigid oil-water interface, and hence, possible higher oil recovery in combination with Polymer. Therefore, detailed experimental investigation and fluid-flow analysis into porous media are required to understand the possible recovery mechanisms taking place. This paper evaluates the potential influence of low-salt/sulfate-modified water injection in oil recovery using a cross-analyzed approach of coupled microfluidics data and core Flooding experiments. Fluid characterization was achieved by detailed rheological characterization focusing on steady shear and in-situ viscosity. Moreover, single and two-phase micromodels and core Floods experiments helped to define the behavior of different fluids. Overall, coupling microfluidics, with core Flooding experiments, confirmed that fluid-fluid interfacial interaction and wettability alteration are both the key recovery mechanisms for modified-water/low-salt. Finally, a combination of sulfate-modified/low-salinity water, with Polymer Flood can lead to ~6% extra oil, compared to the combination of Polymer Flood with synthetic seawater (SSW). The results present an excellent way to make use of micromodels and core experiments as a supporting tool for EOR processes evaluations, assessing fluid-fluid and rock-fluid interactions
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Influence of sulfate ions on the combined application of modified water and Polymer Flooding: rheology and oil recovery
'MDPI AG', 2020Co-Authors: Tahi Muhammad, Hincapie, Rafael E., Ganze L.Abstract:Oil recovery using modified/smart water technology can be maximized by optimizing the composition of the injected water. Brine optimization is also believed to improve Polymer Flooding performance. This chapter assesses and defines the potential impact of combining low-salt-modified waterwith Polymer Flooding, based on the presence of sulfate in the injectionwater. Hence,we evaluated the influence of sodium sulfate on (1) Polymer viscoelasticity, under the assumption that the phenomena exists, and (2) oil recovery and pressure response. Mainly, a comprehensive rheological evaluation and two-phase core Flood experiments are the focus of this work. Composition of injection brine is optimized after having synthetic seawater as a base brine. Core-Flood experiments were performed in a secondary, tertiary and a sort of post-tertiary (quaternary) mode to evaluate the feasibility of applying both processes (modified water and Polymer Flood). Obtained data was subsequently cross-analyzed and as an overall observation, sodium sulfate helped with improving Polymer viscosity compared to sodium chloride or divalent cation presence. Moreover, optimized modified water, with the higher amount of sulfate ions, showed an additional oil recovery in both secondary and tertiary mode of about 5.0%. Additionally, Polymer injection in tertiary mode, after modified-water injection, showed significant additional oil recover