The Experts below are selected from a list of 360 Experts worldwide ranked by ideXlab platform
Yining Wu - One of the best experts on this subject based on the ideXlab platform.
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study on the synergy between silica nanoparticles and surfactants for enhanced Oil Recovery during spontaneous imbibition
Journal of Molecular Liquids, 2018Co-Authors: Mingwei Zhao, Wenjiao Lv, Yuyang Li, Xinke Wang, Hongda Zhou, Yue Zhang, Yining WuAbstract:Abstract Silica nanofluid with silica nanoparticles and surfactants was prepared and used to enhance Oil Recovery through spontaneous imbibition. Nonionic surfactant (TX-100) as dispersant and synergistic enhancement agent was used to disperse silica nanoparticles into water. The silica nanofluid showed excellent anti-temperature and anti-salinity property. Because of synergistic effect, silica nanofluid has much better ability of Oil detachment and wettability alteration than surfactant. The imbibition tests showed that silica nanofluid can improve Oil Recovery to about 16%, comparing with about 8% Oil Recovery of TX-100 solution, which improved the synergistic effect mechanism. The silica nanofluid has good application foreground for EOR.
Omid Karoussi - One of the best experts on this subject based on the ideXlab platform.
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effect of temperature wettability and relative permeability on Oil Recovery from Oil wet chalk
Energies, 2008Co-Authors: A A Hamouda, Omid KaroussiAbstract:It is customary, for convenience, to use relative permeability data produced at room temperature. This paper shows that this practice underestimates Oil Recovery rates and ultimate Recovery from chalk rocks for high temperature reservoirs. Above a certain temperature (80°C in this work) a reduction of Oil Recovery was observed. The reduction in Oil Recovery is reflected by the shift of relative permeability data towards more Oil-wet at high temperature (tested here 130°C). However, both IFT and contact angle measurements indicate an increase in water wetness as temperature increases, which contradict the results obtained by relative permeability experiments. This phenomenon may be explained based on the total interaction potential, which basically consists of van der Waals attractive and short-range Born repulsive and double layer electrostatic forces. The fluid/rock interactions is shown to be dominated by the repulsive forces above 80°C, hence increase fine detachment enhancing Oil trapping. In other words the indicated Oil wetness by relative permeability is misleading.
Quoc P. Nguyen - One of the best experts on this subject based on the ideXlab platform.
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Low tension gas flooding for secondary Oil Recovery in low-permeability, high-salinity reservoirs
Fuel, 2020Co-Authors: Alolika Das, Nhut M. Nguyen, Quoc P. NguyenAbstract:Abstract Low Tension Gas (LTG) flooding has been established as a successful tertiary Oil Recovery method for low-permeability carbonate reservoirs with high salinity and hard formation brine (~200,000 ppm and hardness 19,000 ppm). LTG flooding recovers Oil using two integral mechanisms: ultra-low interfacial tension (IFT) between Oil and water, and mobility control using in-situ foam generated by injected gas. In the present work, the scope of applicability of LTG flooding has been extended to secondary Oil Recovery under the same reservoir conditions. Secondary Recovery using LTG flooding has been compared to conventional secondary Recovery methods such as waterflooding. Oil Recovery was observed to increase by 16% OOIP (Original Oil in Place) as compared to waterflooding, even in case of micellar flooding without gas. On introducing mobility control during LTG flooding in the form of injected gas, the secondary Oil Recovery was observed to increase steadily up to 81% OOIP. Co-injecting gas and surfactant also exhibited lower pressure drop than waterflood, thus underlining the importance and efficiency of mobility control using foam in secondary Recovery. Gas injection strategy was improved in terms of injected foam quality and onset of gas injection. When gas was injected only during drive, ultimate Oil Recovery was reduced to 70% OOIP. Chemical injection strategy was also modified to test the impact of different in-situ salinity profiles on Oil Recovery.
Mohammad Ali Emadi - One of the best experts on this subject based on the ideXlab platform.
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enhanced Oil Recovery in high temperature carbonates using microemulsions formulated with a new hydrophobic component
Journal of Industrial and Engineering Chemistry, 2016Co-Authors: Mohammad Saber Karambeigi, Masoud Nasiri, Ali Haghighi Asl, Mohammad Ali EmadiAbstract:Abstract The positive feedback from previous studies has confirmed the high performance of microemulsion flooding. However, there are few researches assessing this efficient method in carbonates reservoirs, particularly at high temperature. This paper attempts to fill the gap. Furthermore, biodiesel is introduced and evaluated as a new hydrocarbon source of mixture. For this purpose, phase behavior of surfactant/brine/biodiesel/co-solvent was systematically studied using response surface methodology to find the optimum formulation. Thereafter, optimized microemulsion was characterized in terms of particle size distribution, zeta potential, electrical conductivity, polarized light microscopy, surface tension, interfacial tension, and viscosity. Finally, Oil Recovery tests comprising spontaneous imbibition, contact angle, core-flood and microvisual experiments were conducted to examine the potential of optimum formulation for chemical enhanced Oil Recovery (CEOR) purpose in carbonates. Experiments of different stages were carried out at elevated temperature (75 °C). Employing optimal microemulsion, 20.0% original Oil in place (OOIP) in spontaneous imbibition and 6.4% OOIP in core-flood tests were tertiary added to Oil Recovery. The results of this study illustrate the efficacy of proposed formulation to increase Oil Recovery factor of carbonate formations.
Kevin John Webb - One of the best experts on this subject based on the ideXlab platform.
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Recovery rates enhanced Oil Recovery and technological limits
Philosophical Transactions of the Royal Society A, 2014Co-Authors: A H Muggeridge, Kevin John Webb, Andrew Cockin, Harry Frampton, Ian Ralph Collins, Tim Moulds, Salino Peter AnthonyAbstract:Enhanced Oil Recovery (EOR) techniques can significantly extend global Oil reserves once Oil prices are high enough to make these techniques economic. Given a broad consensus that we have entered a period of supply constraints, operators can at last plan on the assumption that the Oil price is likely to remain relatively high. This, coupled with the realization that new giant fields are becoming increasingly difficult to find, is creating the conditions for extensive deployment of EOR. This paper provides a comprehensive overview of the nature, status and prospects for EOR technologies. It explains why the average Oil Recovery factor worldwide is only between 20% and 40%, describes the factors that contribute to these low recoveries and indicates which of those factors EOR techniques can affect. The paper then summarizes the breadth of EOR processes, the history of their application and their current status. It introduces two new EOR technologies that are beginning to be deployed and which look set to enter mainstream application. Examples of existing EOR projects in the mature Oil province of the North Sea are discussed. It concludes by summarizing the future opportunities for the development and deployment of EOR.
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conditions for a low salinity enhanced Oil Recovery eor effect in carbonate Oil reservoirs
Energy & Fuels, 2012Co-Authors: T Austad, C J J Black, S F Shariatpanahi, Skule Strand, Kevin John WebbAbstract:Low-salinity enhanced Oil Recovery (EOR) effects have for a long time been associated with sandstone reservoirs containing clay minerals. Recently, a laboratory study showing low-salinity EOR effects from composite carbonate core material was reported. In the present paper, the results of Oil Recovery by low-salinity water flooding from core material sampled from the aqueous zone of a limestone reservoir are reported. Tertiary low-salinity effects, 2–5% of original Oil in place (OOIP), were observed by first flooding the cores with high-saline formation water (208 940 ppm) and then with 100× diluted formation water or 10× diluted Gulf seawater at 110 °C. It was verified by flooding the core material with distilled water that the core samples contained small amounts of anhydrite, CaSO4(s). The Oil Recovery was tested under forced displacement using different injection brines and Oils with different acid numbers, 0.08, 0.34, and 0.70 mg of KOH/g. The low-salinity effect depended upon mixed wet conditions, a...
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low salinity Oil Recovery an experimental investigation
Petrophysics, 2008Co-Authors: Arnaud Lager, Kevin John Webb, C J J Black, Michael Singleton, Kenneth Stuart SorbieAbstract:The idea of injecting low salinity water into a petroleum reservoir is not novel and was often used in the 70s prior to the injection of surfactant. Recently it was shown that simply injecting sufficiently low salinity water improves Oil Recovery. Many possible mechanisms concerning low-salinity waterflood have been proposed in the literature. This paper describes an experimental investigation into some of the factors controlling the increased Oil Recovery observed when low salinity brine is injected into Oil saturated reservoir core samples. Extensive chemical analyses were performed on the effluent showing the extent of interaction between the injected brine, the Oil and the rock matrix.
