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Journal articles on the topic 'Fluid recovery'
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1
Lê, Hồng Nguyên, Thị Tuyết Mai Đặng, Thị Bích Phương Đặng, and Thị Ánh Trinh Lưu. "Recovering heat of flue gas from heat recovery steam generator system at Nhon Trach 1 and Nhon Trach 2 gas power plants by organic Rankine cycle to produce power." Petrovietnam Journal 5 (July 4, 2022): 38–42. http://dx.doi.org/10.47800/pvj.2022.05-05.
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Flue gas from gas turbines at Nhon Trach 1 and Nhon Trach 2 gas power plant are in the temperature range of 100 - 113oC after heat has been recovered at the heat recovery steam generator. These heat flows are not recovered by conventional methods since they are not effective. Meanwhile, the organic Rankine cycle (ORC) uses organic fluids with low boiling point, that is why it can recover heat from low-temperature flue gas streams. Results of the ORC investigation reveal that with R245fa as a fluid, the Nhon Trach 1’s capacity will increase by 2.0 MW, and the Nhon Trach 2’s capacity will see an increase of 3.6 MW with R113 as a fluid.
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Hanshi, Zhang, Jiang Guancheng, Bi Hongxun, and Zhu Kuanliang. "Research on Protecting Formation Low-Damage Workover Fluid in Low Permeability Reservoir." International Journal of Nanoscience 18, no. 06 (2019): 1850049. http://dx.doi.org/10.1142/s0219581x18500497.
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During the workover treatment process, poorly compatible workover fluids infiltrating into reservoir could cause serious formation damage. To tackle the aformentioned issues, in this work, low-damage workover fluid was systematically studied. By investigating reservoir damage mechanisms, chemical property study, compatibility evaluation test and core flow test, we obtain three kinds of workover fluids suitable for different blocks in Nanpu oilfield. Attractively, JRYL workover fluid which contains antiswelling agents can effectively prevent water sensitivity, and the permeability recovery values of JRYL workover fluid to NP1-5 and PG2 core are 95.3% and 86.9%, respectively. JRYD workover fluid which contains antiswelling agents and anti-waterblocking agent can prevent both water sensitivity and water blocking damage, and the permeability recovery value of JRYD workover fluid to NP403X1 core is 89.4%. JRYJ workover fluid suitable for high pressure formation can prevent water sensitivity and water blocking damage, and the permeability recovery value of the JRYJ workover fluid to NP403X1 core is 95.1%. The actual field application in Nanpu oilfield indicates that these workover fluids can not only reduce the oil well recovery time after workover treatment, but also increase production recovery rate. These results display great potential to efficiently develop low permeability reservoirs.
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Bui, Khoa, and I. Yucel Akkutlu. "Hydrocarbons Recovery From Model-Kerogen Nanopores." SPE Journal 22, no. 03 (2016): 854–62. http://dx.doi.org/10.2118/185162-pa.
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Summary Existing strategies for oil and gas recovery are designed on the basis of macroscopic properties of the produced hydrocarbon fluids. However, recent studies on source rocks revealed that properties of fluids stored in nanopores of the organic constituent material kerogen deviate from the bulk behavior. Hence, the traditional equation-of-state (EOS) and fluid-properties correlations are no longer applicable. This, in turn, leads to added uncertainties in hydrocarbon-in-place and recovery calculations for the source rocks that are rich in kerogen. In this paper, we seek to address the question at a fundamental level from the thermodynamics standpoint by simulating isothermal expansion of a quinary hydrocarbon mixture in a model nanopore under typical subsurface conditions, and measuring the fluid composition and amount. Molecular Monte Carlo simulations are used to investigate the equilibrium relationship between the bulk fluid at the outside of the pore and the remaining mixture inside during the stages of pressure depletion. The fluid stored in nanopores shows a composition that varies significantly with the pore size. The smaller the pore is, the heavier becomes the mixture that is in equilibrium with the bulk fluid. During the depletion, the small hydrocarbon molecules escape readily from the pores. The composition of the remaining fluid inside the pore thus becomes progressively heavier and viscous. We show that nanopore confinement significantly limits the release of hydrocarbon molecules from the pores with sizes smaller than 10 nm. For each hydrocarbon component, a strong correlation exists between molar fractions of the component in the produced fluid with that which remained inside the pore. This correlation can serve in future studies as the basis for establishing alternative methods for reservoir-engineering calculations, such as the ultimate recovery.
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Fan, Pingtian, Yuetian Liu, Ziyu Lin, Haojing Guo, and Ping Li. "Experimental Study on the Efficiency of Fracturing Integrated with Flooding by Slickwater in Tight Sandstone Reservoirs." Processes 12, no. 11 (2024): 2529. http://dx.doi.org/10.3390/pr12112529.
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Tight reservoirs, with their nanoscale pore structures and limited permeability, present significant challenges for oil recovery. Composite fracturing fluids that combine both fracturing and oil recovery capabilities show great potential to address these challenges. This study investigates the performance of a slickwater-based fracturing fluid, combined with a high-efficiency biological oil displacement agent (HE-BIO), which offers both production enhancement and environmental compatibility. Key experiments included tests on single-phase flow, core damage assessments, interfacial tension measurements, and oil recovery evaluations. The results showed that (1) the slickwater fracturing fluid effectively penetrates the rock matrix, enhancing oil recovery while minimizing environmental impact; (2) it causes substantially less damage to the reservoir compared to traditional guar gum fracturing fluid, especially in cores with little higher initial permeability; and that (3) oil recovery improves as HE-BIO concentration increases from 0.5% to 2.5%, with 2.0% as the optimal concentration for maximizing recovery rates. These findings provide a foundation for optimizing fracturing oil displacement fluids in tight sandstone reservoirs, highlighting the potential of the integrated fracturing fluid to enhance sustainable oil recovery.
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Tian, Jie, Wende Yan, Zhilin Qi, Shiwen Huang, Yingzhong Yuan, and Mingda Dong. "Cyclic Supercritical Multi-Thermal Fluid Stimulation Process: A Novel Improved-Oil-Recovery Technique for Offshore Heavy Oil Reservoir." Energies 15, no. 23 (2022): 9189. http://dx.doi.org/10.3390/en15239189.
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Cyclic supercritical multi-thermal fluid stimulation (CSMTFS) is a novel technology that can efficiently recover heavy oil, while the heating effect, production and heat loss characteristics of CSMTFS have not been discussed. In this study, a physical simulation experiment of CSMTFS is conducted with a three-dimensional experimental system. The results of the study indicate that the whole process of CSMTFS can be divided into four stages, namely, the preheating stage, production increase stage, production stable stage and production decline stage, of which the production stable stage is the main oil production stage, and the production decline stage is the secondary oil production stage. In the first two stages of the CSMTFS process, there is no supercritical multi-thermal fluid chamber, and only a relatively small supercritical multi-thermal fluid chamber is formed in the last stage of the CSMTFS process. Out of the supercritical multi-thermal fluid chamber, supercritical water in the thermal fluids condensates to hot water and flows downward to heat the subjacent oil layer. At the same time, the non-condensate gas in the thermal fluids accumulates to the upper part of the oil layer and reduces heat loss. The analysis of heat loss shows that the heat loss rate gradually increases at first and then tends to be stable. Compared with conventional thermal fluid, the CSMTFS can more effectively reduce heat loss. The enthalpy value of supercritical multi-thermal fluid is significantly increased compared with that of multi-thermal fluid, which effectively solves the problem of insufficient heat carrying capacity of multi-thermal fluid. Overall, cyclic supercritical multi-thermal fluid stimulation can effectively solve the problems of conventional heavy oil thermal recovery technology in offshore heavy oil recovery; it is indeed a new improved-oil-recovery technique for offshore heavy oil. The findings of this study can help in better understanding the cyclic supercritical multi-thermal fluid stimulation process. This study is significant and helpful for application of CSMTFS technology in heavy oil recovery.
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Soundararajan, Srinath, and Mahalingam Selvaraj. "Investigations of protracted finned double pipe heat exchanger system for waste heat recovery from diesel engine exhaust." Thermal Science, no. 00 (2023): 143. http://dx.doi.org/10.2298/tsci230212143s.
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The need for energy and material savings, as well as environmental concerns, have helped to increase the demand for high-efficiency heat exchangers in the modern era. In practice, a heat exchanger or the direct ejection of the hot working fluid is used to recover the waste heat from a heat engine or thermal power plant into the environment. Waste heat of a heat engine or power plant is recovered to the environment via a heat exchanger or by direct ejection from the hot working fluid. In many situations, waste heat recovery removes or greatly reduces the necessity for additional fuel energy input to achieve this goal. The double pipe heat exchanger equipment is taken in this research, heat from engine exhaust recovers due to its superior qualities. The design characteristics of the heat pipe will be changed in order to increase overall efficiency by studying the concepts of various authors. Different design parameters for a double pipe heat exchange system as well as different working fluid flow rates are tested with the suggested device. Additionally, ANSYS performs computational fluid dynamics for the proposed heat exchanger system in order for the results to support the experimental findings.
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Kingsley Onyedikachi Omomo, Andrew Emuobosa Esiri, and Henry Chukwuemeka Olisakwe. "Advanced fluid recovery and recycling systems for offshore drilling: A conceptual approach." Engineering Science & Technology Journal 5, no. 10 (2024): 2884–96. http://dx.doi.org/10.51594/estj.v5i10.1626.
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Offshore drilling is a crucial component of global energy production, but it poses significant environmental challenges, particularly in managing drilling fluids. This paper presents a conceptual approach to advanced fluid recovery and recycling systems, focusing on the integration of innovative filtration and separation technologies to reduce waste and enhance sustainability. The review explores current challenges in traditional drilling fluid management, highlighting waste disposal's environmental and operational drawbacks. A detailed conceptual framework is provided, outlining the design principles of the proposed system and its potential to increase fluid recovery rates while minimizing environmental impact. The paper also examines the sustainability and economic benefits of fluid recycling, including cost savings and long-term contributions to more responsible drilling practices. Finally, the future outlook discusses advancements in recovery technologies, integration with broader sustainability initiatives, and the policy and regulatory considerations necessary for widespread adoption. This review underscores the importance of fluid recovery systems in driving sustainable offshore drilling and aligning the industry with global environmental goals. Keywords: Offshore Drilling, Fluid Recovery, Waste Management, Sustainability, Advanced Filtration, Environmental Impact.
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Elliott, M. L., and M. Prevatte. "Comparison of Damage to `Tifgreen' Bermudagrass by Petroleum and Vegetable Oil Hydraulic Fluids." HortTechnology 5, no. 1 (1995): 50–51. http://dx.doi.org/10.21273/horttech.5.1.50.
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Petroleum and vegetable oil hydraulic fluids were spread on `Tifgreen' bermudagrass at three volumes (125, 250, and 500 ml) and three temperatures (27, 49, and 94C) to simulate a turfgrass equipment leak. Initial damage, recovery, and effects for a 1-year period were compared among treatments. All hydraulic fluid treatments resulted in 100% leaf necrosis within 10 days of application. Turfgrass recovery was influenced primarily by the fluid volume. After recovery, only plots treated with petroleum hydraulic fluid were periodically chlorotic, resulting in lower turfgrass quality. Long-term negative effects of hydraulic leaks from golf course equipment may be reduced by using vegetable oil hydraulic fluid.
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Villero-Mandon, Jose, Peyman Pourafshary, and Masoud Riazi. "Oil/Brine Screening for Improved Fluid/Fluid Interactions during Low-Salinity Water Flooding." Colloids and Interfaces 8, no. 2 (2024): 23. http://dx.doi.org/10.3390/colloids8020023.
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Low-salinity water flooding/smart water flooding (LSWF/SWF) are used for enhanced oil recovery (EOR) because of the improved extraction efficiency. These methods are more environmentally friendly and in many scenarios more economical for oil recovery. They are proven to increase recovery factors (RFs) by between 6 and 20%, making LSWF/SWF technologies that should be further evaluated to replace conventional water flooding or other EOR methods. Fluid/fluid interaction improvements include interfacial tension (IFT) reduction, viscoelastic behavior (elastic properties modification), and microemulsion generation, which could complement the main mechanisms, such as wettability alteration. In this research, we evaluate the importance of fluid/fluid mechanisms during LSWF/SWF operations. Our study showed that a substantial decrease in IFT occurs when the oil asphaltene content is in the range of 0% to 3 wt.%. An IFT reduction was observed at low salinity (0–10,000 ppm) and a specific oil composition condition. Optimal IFT occurs at higher divalent ion concentrations when oil has low asphaltene content. For the oil with high asphaltene content, the sulfates concentration controls the IFT alteration. At high asphaltene concentrations, the formation of micro-dispersion is not effective to recover oil, and only a 5% recovery factor improvement was observed. The presence of asphaltene at the oil/low-salinity brine interface increases the energy required to disrupt it, inducing significant changes in the elastic moduli. In cases of low asphaltene content, the storage modulus demonstrates optimal performance at higher divalent concentrations. Conversely, at high asphaltene concentrations, the dominant factors to control the interface are paraffin content and temperature.
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Akramov, B. Sh ,., Sh Kh Umedov, and Zh F. Nuritdinov. "Influence of Fluid Recovery and Flushing Frequency on Oil Recovery." Oil and Gas Technologies 134, no. 3 (2021): 47–49. http://dx.doi.org/10.32935/1815-2600-221-134-3-47-49.
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The article deals with the influence of intensive fluid withdrawal on the oil production process and on the amount of anhydrous current and final oil recovery. The beneficial effect of high rates of fluid recovery on the rate of oil recovery ant the current oil recovery in the water period is the technological basis of the method of forced fluid recovery from the reservoir. It is shown that forced withdrawal allows to reduce the duration of the late stage and extend the period of profitable oil production.
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Kates, Robin, Dennis Atkinson, and Michael Brant-Zawadzki. "Fluid-attenuated Inversion Recovery (FLAIR)." Topics in Magnetic Resonance Imaging 8, no. 6 (1996): 389???396. http://dx.doi.org/10.1097/00002142-199612000-00005.
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Shang, Jianping, Zhengliang Dong, Wenyuan Tan, et al. "A Review of Fracturing and Enhanced Recovery Integration Working Fluids in Tight Reservoirs." Processes 12, no. 6 (2024): 1241. http://dx.doi.org/10.3390/pr12061241.
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Tight reservoirs, characterized by low porosity, low permeability, and difficulty in fluid flow, rely on horizontal wells and large-scale hydraulic fracturing for development. During fracturing, a significant volume of fracturing fluid is injected into the reservoir at a rate far exceeding its absorption capacity. This not only serves to create fractures but also impacts the recovery efficiency of tight reservoirs. Therefore, achieving the integration of fracturing and enhanced recovery functions within the working fluid (fracturing-enhanced recovery integration) becomes particularly crucial. This study describes the concept and characteristics of fracturing-enhanced recovery integration and analyzes the types and features of working fluids. We also discuss the challenges and prospects faced by these fluids. Working fluids for fracturing-enhanced recovery integration need to consider the synergistic effects of fracturing and recovery; meet the performance requirements during fracturing stages such as fracture creation, proppant suspension, and flowback; and also address the demand for increased recovery. The main mechanisms include (1) enlarging the effective pore radius, (2) super-hydrophobic effects, and (3) anti-swelling properties. Fracturing fluids are pumped into fractures through pipelines, where they undergo complex flow in multi-scale fractures, ultimately seeping through capillary bundles. Flow resistance is influenced by the external environment, and the sources of flow resistance in fractures of different scales vary. Surfactants with polymerization capabilities, biodegradable and environmentally friendly bio-based surfactants, crosslinking agents, and amino acid-based green surfactants with outstanding properties will unleash their application potential, providing crucial support for the effectiveness of fracturing-enhanced recovery integration working fluids. This article provides important references for the green, efficient, and sustainable development of tight oil reservoirs.
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Zhu, Qidi, Zhiqiang Sun, and Jiemin Zhou. "Performance analysis of organic Rankine cycles using different working fluids." Thermal Science 19, no. 1 (2015): 179–91. http://dx.doi.org/10.2298/tsci120318014z.
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Low-grade heat from renewable or waste energy sources can be effectively recovered to generate power by an organic Rankine cycle (ORC) in which the working fluid has an important impact on its performance. The thermodynamic processes of ORCs using different types of organic fluids were analyzed in this paper. The relationships between the ORC?s performance parameters (including evaporation pressure, condensing pressure, outlet temperature of hot fluid, net power, thermal efficiency, exergy efficiency, total cycle irreversible loss, and total heat-recovery efficiency) and the critical temperatures of organic fluids were established based on the property of the hot fluid through the evaporator in a specific working condition, and then were verified at varied evaporation temperatures and inlet temperatures of the hot fluid. Here we find that the performance parameters vary monotonically with the critical temperatures of organic fluids. The values of the performance parameters of the ORC using wet fluids are distributed more dispersedly with the critical temperatures, compared with those of using dry/isentropic fluids. The inlet temperature of the hot fluid affects the relative distribution of the exergy efficiency, whereas the evaporation temperature only has an impact on the performance parameters using wet fluid.
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Agustina, Fitriani, Ainil Yusra, and Said Taufiq. "Compliance of Patients Undergoing Hemodialisis with Recovery Time Post-Dialysis." JKEP 9, no. 2 (2024): 172–86. http://dx.doi.org/10.32668/jkep.v9i2.1485.
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Post-hemodialysis, patients frequently experience symptoms that disrupt their comfort during daily activities, ranging from simple to strenuous tasks. Many hemodialysis patients do not feel well after dialysis sessions and require time to recover before resuming their usual activities at home or work. This study aims to determine the influence of fluid compliance, dietary compliance, and hemodialysis dose compliance on post-dialysis recovery time. A cross-sectional design with consecutive sampling was employed, involving 76 respondents. Data were collected by distributing questionnaires to patients undergoing hemodialysis during each session. Data analysis was conducted using the Mann-Whitney test with a 95% confidence interval. Post-dialysis recovery time ranged from a minimum of 15 minutes to a maximum of 1,800 minutes, with the majority of patients recovering within 240 minutes. There was a significant difference between post-dialysis recovery time and fluid restriction adherence (p-value = 0.000, p-value < 0.05), with respondents who adhered to fluid restrictions having a predominantly 45-minute recovery time. Similarly, a significant difference was observed between post-dialysis recovery time and dietary compliance (p-value = 0.000, p-value < 0.05), with respondents who adhered to their diet also having a 45-minute recovery time. Additionally, a significant difference was found between post-dialysis recovery time and hemodialysis dose compliance (p-value = 0.007, p-value < 0.05), with the majority of respondents adhering to the hemodialysis dose exhibiting a 120-minute recovery time. Post-dialysis recovery time is influenced by compliance to fluid restrictions, dietary management, and hemodialysis dosing in hemodialysis patients. Maintaining compliance to fluid restrictions, diet, and hemodialysis dosing can shorten post-dialysis recovery time.
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Dianita, Cindy, Muhammad Faturahman, and Andi Mardianza. "PORE-SCALE 3D MODELING OF VISCOUS FINGERING FOR NON-NEWTONIAN HEAVY OIL RECOVERY." Scientific Contributions Oil and Gas 48, no. 1 (2025): 77–90. https://doi.org/10.29017/scog.v48i1.1690.
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Heavy oil recovery faces significant challenges due to the unstable displacement of oil by water, known as viscous fingering (VF). This occurs when low-viscosity fluids displace high-viscosity fluids, leading to inefficient oil recovery and increased water production. These issues reduce efficiency and increase environmental and economic costs, highlighting the need for improved simulation techniques to better understand and manage VF dynamics. This study examines the use of non-Newtonian Carreau fluids in modeling VF phenomena, offering more realistic simulations than Newtonian fluids. The shear-thinning behavior of Carreau fluids allows injected fluids to penetrate smaller pores effectively, influencing finger formation and growth. Current work, which incorporates non-Newtonian fluid characteristics, provides a more accurate representation of viscous fingering, including key features such as finger formation, merging, coalescence, blocking, tip-splitting, and expansion. Three porosity values (0.29, 0.5, and 0.7) are simulated to represent diverse reservoir conditions. A 3D computational fluid dynamics (CFD) model is utilized, employing the volume of fluid (VOF) approach to capture immiscible displacement processes. The model is validated using experimental data from coreflood studies. The results demonstrate that porosity significantly influences VF behavior, with lower porosities resulting in more pronounced finger formation, splitting, and coalescence. Non-Newtonian fluids decrease instability by moderating VF growth dynamics, enhancing displacement efficiency. These findings emphasize the importance of incorporating non-Newtonian fluid properties and porosity variations into VF simulations to optimize oil recovery processes. This study provides insights into VF dynamics, advancing the development of sustainable and efficient heavy oil recovery technologies.
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Tahir, Muhammad, Rafael E. Hincapie, Nils Langanke, Leonhard Ganzer, and Philip Jaeger. "Coupling Microfluidics Data with Core Flooding Experiments to Understand Sulfonated/Polymer Water Injection." Polymers 12, no. 6 (2020): 1227. http://dx.doi.org/10.3390/polym12061227.
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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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Tuo, Han Fei. "Energetic Based Organic Fluid Selection for a Solid Oxide Fuel Cell-Organic Rankine Cycle Combined System." Advanced Materials Research 622-623 (December 2012): 1162–67. http://dx.doi.org/10.4028/www.scientific.net/amr.622-623.1162.
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In this study, energetic based fluid selection for a solid oxide fuel cell-organic rankine combined power system is investigated. 9 dry organic fluids with varied critical temperatures are chosen and their corresponding ORC cycle performances are evaluated at different turbine inlet temperatures and exhaust gas temperature (waste heat source) from the upper cycle. It is found that actual ORC cycle efficiency for each fluid strongly depends on the waste heat recovery performance of the heat recovery vapor generator. Exhaust gas temperature determines the optimal fluid which yields the highest efficiency.
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Cheng, Qiuyang, Lijun You, Na Jia, Yili Kang, Cheng Chang, and Weiyang Xie. "New Insight into Enhancing Organic-Rich Shale Gas Recovery: Shut-in Performance Increased through Oxidative Fluids." Energies 16, no. 11 (2023): 4325. http://dx.doi.org/10.3390/en16114325.
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Oxidizing stimulation of organic-rich shale reservoirs, as a supplement of hydraulic fracturing, was proposed to enhance shale gas recovery. Previous publications revealed that the interaction between organic-rich shale and oxidative fluids causes the components’ dissolution, which induces lots of pores and microfractures, resulting in rock microfracturing without confined pressure and associated increments of the matrix permeability, and improving unpropped fracture conductivity. However, the enhancement of shale gas recovery with oxidative fluids still lacks an implementation clue targeted for specific engineering problems. In recent years, water–rock interaction inducing microfractures indicates a positive effect of retained fracturing fluid on the stimulation after the fracturing operation, which sheds light in the enhancement of shale gas production by shut-in. The objectives of this study are to provide a new perspective whereby the shut-in performance to enhance shale gas recovery could be increased by the injection of oxidative fluids into the formation during the fracturing operation. Firstly, the mechanisms of shut-in performance increased by oxidative dissolution, which illustrate the increment of the density of fracture networks, the improvement of fracture network conductivity, and the promotion of gas desorption and diffusivity, are demonstrated. Then, the feasibility of using oxidative fluids to increase shut-in performance, which follows the geological and engineering characteristics of organic-rich shale reservoirs, is evaluated. Finally, according to the analysis of production performance for two typical types of shale gas wells, in which one is a low gas production and a high fracturing fluid recovery (LGP-HFR) and the other is a high gas production and a low fracturing fluid recovery (HGP-LFR), a shut-in strategy with oxidative fluids to enhance shale gas recovery is developed. This indicates that the injection of oxidative fluids during the fracturing operation may become a promising and cost-effective approach to enhance shale gas recovery.
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Villero-Mandon, Jose, Nurzhan Askar, Peyman Pourafshary, and Masoud Riazi. "Importance of Fluid/Fluid Interactions in Enhancing Oil Recovery by Optimizing Low-Salinity Waterflooding in Sandstones." Energies 17, no. 13 (2024): 3315. http://dx.doi.org/10.3390/en17133315.
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Low-salinity waterflooding/smart waterflooding (LSWF/SWF) is a technique involving the injection of water with a modified composition to alter the equilibrium between rock and fluids within porous media to enhance oil recovery. This approach offers significant advantages, including environmental friendliness and economic efficiency. Rock/fluid mechanisms such as wettability alteration and fines migration and fluid/fluid mechanisms such as a change in interfacial tension and viscoelasticity are considered active mechanisms during LSWF/SWF. In this study, we evaluated the effect of these mechanisms, by LSWF/SWF, on sandstones. To investigate the dominant mechanisms, coreflooding studies were performed using different injected fluid composition/salinity and wettability states. A comparative analysis of the recovery and mobility reduction factor was performed to clarify the conditions at which fluid/fluid mechanisms are also effective. Our studies showed that wettability alteration is the most dominant mechanism during LSWF/SWF, but, for weak oil-wet cases, optimizing brine compositions may activate fluid/fluid mechanisms. Brine composition significantly influences interface stability and performance, with sulfate content playing a crucial role in enhancing interface properties. This was observed via mobility behavior. A comparative analysis of pressure differentials showed that fines migration may act as a secondary mechanism and not a dominant one. This study highlights the importance of tailored brine compositions in maximizing oil recovery and emphasizes the complex interplay between rock and fluid properties in enhanced oil recovery strategies.
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Zhu, Jian, Fei Wang, Shicheng Zhang, and Xinfang Ma. "Experimental Research on Behavior of Spontaneous Imbibition and Displacement After Fracturing in Terrestrial Shale Oil Based on Nuclear Magnetic Resonance Measurements." Processes 12, no. 12 (2024): 2685. http://dx.doi.org/10.3390/pr12122685.
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Spontaneous imbibition (SI) effectively enhances oil recovery in shale reservoirs, significantly changing well shut-in and flowback design. This study conducted SI and displacement experiments to simulate the well shut-in and flowback stages so that the mechanism of imbibition and displacement between crude oil and fracture fluid can be discussed. In addition, the relative contribution to oil recovery of different types of pores in various stages and the effect of wettability were determined with low-field nuclear magnetic resonance (LF-NMR) via each sample’s T2 transverse relaxation time at each time. The experimental results show that shale has multiscale pore structure characteristics combined with micropores, small mesopores, and mesopores. During the SI process, crude oil is displaced from micropores by fracture fluid at first, and then a large amount of oil production comes from small mesopores. Oil recovery of water-wet core samples is approximately 40.7%. Oil recovery of oil-wet core samples is about 26%. The wettability significantly affects the imbibition and displacement oil recovery of samples. For the process of SI, oil recovered from small mesopores takes the lead in the complete sample recovery. For the displacement process, oil recovered from small mesopores and mesopores take the lead in the complete sample recovery. After displacement, only 12% of fracture fluid flooded from the samples. This research, demonstrating the imbibition and displacement characteristics of terrestrial shale and several relevant affecting factors, contributes to understanding the fracturing fluid retention mechanism in shale reservoirs and provides crucial theoretical foundations for the development of shale oil reservoirs.
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Gounley, John, and Yan Peng. "Shape Recovery of Elastic Capsules from Shear Flow Induced Deformation." Communications in Computational Physics 16, no. 1 (2014): 56–74. http://dx.doi.org/10.4208/cicp.220513.151113a.
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AbstractRed blood cells undergo substantial shape changes in vivo. Modeled as a viscoelastic capsule, their deformation and equilibrium behavior has been extensively studied. We consider how 2D capsules recover their shape, after having been deformed to ‘equilibrium’ behavior by shear flow. The fluid-structure interaction is modeled using the multiple-relaxation time lattice Boltzmann (LBM) and immersed boundary (IBM) methods. Characterizing the capsule’s shape recovery with the Taylor deformation parameter, we find that a single exponential decay model suffices to describe the recovery of a circular capsule. However, for biconcave capsules whose equilibrium behaviors are tank-treading and tumbling, we posit a two-part recovery, modeled with a pair of exponential decay functions. We consider how these two recovery modes depend on the capsule’s shear elasticity, membrane viscosity, and bending stiffness, along with the ratio of the viscosity of the fluid inside the capsule to the ambient fluid viscosity. We find that the initial recovery mode for a tank-treading biconcave capsule is dominated by shear elasticity and membrane viscosity. On the other hand, the latter recovery mode for both tumbling and tank-treading capsules, depends clearly on shear elasticity, bending stiffness, and the viscosity ratio.
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Baek, Seunghwan, and I. Yucel Akkutlu. "CO2 Stripping of Kerogen Condensates in Source Rocks." SPE Journal 24, no. 03 (2019): 1415–34. http://dx.doi.org/10.2118/190821-pa.
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Summary Significant research has been conducted on hydrocarbon fluids in the organic materials of source rocks, such as kerogen and bitumen. However, these studies were limited in scope to simple fluids confined in nanopores, while ignoring the multicomponent effects. Recent studies using hydrocarbon mixtures revealed that compositional variation caused by selective adsorption and nanoconfinement significantly alters the phase equilibrium properties of fluids. One important consequence of this behavior is capillary condensation and the trapping of hydrocarbons in organic nanopores. Pressure depletion produces lighter components, which make up a small fraction of the in-situ fluid. Equilibrium molecular simulation of hydrocarbon mixtures was carried out to show the impact of CO2 injection on the hydrocarbon recovery from organic nanopores. CO2 molecules introduced into the nanopore led to an exchange of molecules and a shift in the phase equilibrium properties of the confined fluid. This exchange had a stripping effect and, in turn, enhanced the hydrocarbon recovery. The CO2 injection, however, was not as effective for heavy hydrocarbons as it was for light components in the mixture. The large molecules left behind after the CO2 injection made up the majority of the residual (trapped) hydrocarbon amount. High injection pressure led to a significant increase in recovery from the organic nanopores, but was not critical for the recovery of the bulk fluid in large pores. Diffusing CO2 into the nanopores and the consequential exchange of molecules were the primary drivers that promoted the recovery, whereas pressure depletion was not effective on the recovery. The results for N2 injection were also recorded for comparison.
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El-Khatib, Noaman A. F. "Immiscible Displacement of Non-Newtonian Fluids in Communicating Stratified Reservoirs." SPE Reservoir Evaluation & Engineering 9, no. 04 (2006): 356–65. http://dx.doi.org/10.2118/93394-pa.
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Summary The displacement of non-Newtonian power-law fluids in communicating stratified reservoirs with a log-normal permeability distribution is studied. Equations are derived for fractional oil recovery, water cut, injectivity ratio, and pseudorelative permeability functions, and the performance is compared with that for Newtonian fluids. Constant-injection-rate and constant-total-pressure-drop cases are studied. The effects of the following factors on performance are investigated: the flow-behavior indices, the apparent mobility ratio, the Dykstra-Parsons variation coefficient, and the flow rate. It was found that fractional oil recovery increases for nw &gt; no and decreases for nw &lt; no, as compared with Newtonian fluids. For the same ratio of nw /no, oil recovery increases as the apparent mobility ratio decreases. The effect of reservoir heterogeneity in decreasing oil recovery is more apparent for the case of nw &gt; no . Increasing the total injection rate increases the recovery for nw &gt; no, and the opposite is true for nw &lt; no . It also was found that the fractional oil recovery for the displacement at constant total pressure drop is lower than that for the displacement at constant injection rate, with the effect being more significant when nw &lt; no. Introduction Many of the fluids injected into the reservoir in enhanced-oil-recovery (EOR)/improved-oil-recovery (IOR) processes such as polymer, surfactant, and alkaline solutions may be non-Newtonian; in addition, some heavy oils exhibit non-Newtonian behavior. Flow of non-Newtonian fluids in porous media has been studied mainly for single-phase flow. Savins (1969) presented a comprehensive review of the rheological behavior of non-Newtonian fluids and their flow behavior through porous media. van Poollen and Jargon (1969) presented a finite-difference solution for transient-pressure behavior, while Odeh and Yang (1979) derived an approximate closed-form analytical solution of the problem. Chakrabarty et al. (1993) presented Laplace-space solutions for transient pressure in fractal reservoirs. For multiphase flow of non-Newtonian fluids in porous media, the problem was considered only for single-layer cases. Salman et al. (1990) presented the modifications for the Buckley-Leverett frontal-advance method and for the JBN relative permeability method for non-Newtonian power-law fluid displacing a Newtonian fluid. Wu et al. (1992) studied the displacement of a Bingham non-Newtonian fluid (oil) by a Newtonian fluid (water). Wu and Pruess (1998) introduced a numerical finite-difference solution for displacement of non-Newtonian fluids in linear systems and in a five-spot pattern. Yi (2004) developed a Buckley-Leverett model for displacement by a Newtonian fluid of a fracturing fluid having a Herschel-Bulkley rheological behavior. An iterative procedure was used to obtain a solution of the model. The methods available in the literature to predict linear waterflooding performance in stratified reservoirs are grouped into two categories depending on the assumption of communication or no communication between the different layers. In the case of noncommunicating systems, no vertical crossflow is permitted between the adjacent layers. The Dykstra-Parsons (1950) method is the basis for performance prediction in noncommunicating stratified reservoirs.
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Karadeli, Hasan Hüseyin, and Muhammed Emin Özcan. "Fluid-Attenuated Inversion Recovery Vascular Hyperintensity." Turkish Journal of Cerebrovascular Diseases 22, no. 2 (2016): 45–48. http://dx.doi.org/10.5505/tbdhd.2016.19870.
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Tatemichi, Nobuhiro, Hiroshi Tanizaki, Syouji Makabe, and Kazumasa Yagi. "164. Fluid Attenuated Inversion Recovery Imaging." Japanese Journal of Radiological Technology 49, no. 8 (1993): 1189. http://dx.doi.org/10.6009/jjrt.kj00003324752.
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O’Rourke, Katy, Ben Morrison, Soumen Sen, and Chris Jones. "Fluid management for enhanced recovery surgery." Digestive Medicine Research 2 (December 2019): 37. http://dx.doi.org/10.21037/dmr.2019.09.05.
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Davidson, Brett. "Fluid-Pulse Technology Boosts Oil Recovery." Journal of Petroleum Technology 65, no. 12 (2013): 34–35. http://dx.doi.org/10.2118/1213-0034-jpt.
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WILSON, CLYDE R., WALLACE H. ANDREWS, PAUL L. POELMA, and VERNEAL R. BRUCE. "Recovery of Salmonella from Fluid Milk." Journal of Food Protection 51, no. 5 (1988): 409–11. http://dx.doi.org/10.4315/0362-028x-51.5.409.
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Methodology was developed for isolation of Salmonella from skim milk, 2% fat milk, whole milk and buttermilk. Lactose broth, lactose broth plus brilliant green dye, buffered peptone water and each milk type plus brilliant green dye were evaluated as preenrichment broths. Incubation temperatures of 35 and 43°C were compared for use at the preenrichment stage. The recovery of Salmonella was determined after selective enrichment in selenite cystine, tetrathionate and Rappaport-Vassiliadis broths. Results indicated that fluid milk should be examined for Salmonella by being preenriched in lactose broth, subcultured to selenite cystine and tetrathionate broths and streaked to selective agars, with 35°C as the incubation temperature throughout the analysis.
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Olindo, Stephane, Nicolas Chausson, Julien Joux, et al. "Fluid-Attenuated Inversion Recovery Vascular Hyperintensity." Archives of Neurology 69, no. 11 (2012): 1462. http://dx.doi.org/10.1001/archneurol.2012.1310.
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Bangerter, Neal K., Brian A. Hargreaves, Garry E. Gold, Daniel T. Stucker, and Dwight G. Nishimura. "Fluid-attenuated inversion-recovery SSFP imaging." Journal of Magnetic Resonance Imaging 24, no. 6 (2006): 1426–31. http://dx.doi.org/10.1002/jmri.20743.
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Lenci, Alessandro, Farhad Zeighami, Irene Daprà, and Vittorio Di Federico. "Slip Backflow of Polymers in Elastic Fractures for Subsurface Heat Recovery." Energies 16, no. 24 (2023): 7999. http://dx.doi.org/10.3390/en16247999.
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This research delves into the complexities of backflow phenomena in finite-length and flat-walled fractures with elastic walls, specifically focusing on power-law fluids, whose shear-thinning behavior distinguishes them from Newtonian fluids. We model the backflow process under the lubrication approximation and by incorporating the linear Navier slip law. We numerically examine the influence of parameters such as slip length, fluid rheology, and external pressure on the backflow propagation of the carrier fluid. Our findings underscore the significant role played by the rheological index in determining the fracture closure rate. Additionally, our investigations highlight the marked effect of external pressure variations on pressure distribution within the fracture. Notably, the friction coefficient at the fracture walls, as denoted by a dimensionless slip number, exhibits limited influence on the fundamental dynamics of the problem. These insights advance our understanding of power-law fluid backflow and have wide-ranging applications across various engineering disciplines.
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Liu, Yin Qing, Shi Jun Guo, and Hai Qing Cui. "The Research of Vertical Pipe Flow Rules of Polymer Drive Pump Wells Recovery Liquid." Advanced Materials Research 807-809 (September 2013): 2612–15. http://dx.doi.org/10.4028/www.scientific.net/amr.807-809.2612.
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As polymer flooding in Daqing oil field with the further exploitation,the polymer content in the flooding produced fluids and the produced fluid flow characteristics of polymer are all constant change. The rheology of produced fluids is changed too, it obviously shows non-newtonian fluid properties. About the concentric axis of non-newtonian fluid flow rules of the air the ring,it is becoming more and more important for producted crude oil in Daqing polymer flooding oilfield. This paper built a indoor device that used for the research of Polymer flooding pumping Wells recovery liquid vertical pipe flow rules,had a deep research on flow rules and rheology of Polymer flooding pumping Wells recovery liquid that was coming from Xingbei development zone of Daqing oilfield in the tubing wellbore.
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Wang, Zhijian, Hua Tian, Lingfeng Shi, Gequn Shu, Xianghua Kong, and Ligeng Li. "Fluid Selection of Transcritical Rankine Cycle for Engine Waste Heat Recovery Based on Temperature Match Method." Energies 13, no. 7 (2020): 1830. http://dx.doi.org/10.3390/en13071830.
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Engines waste a major part of their fuel energy in the jacket water and exhaust gas. Transcritical Rankine cycles are a promising technology to recover the waste heat efficiently. The working fluid selection seems to be a key factor that determines the system performances. However, most of the studies are mainly devoted to compare their thermodynamic performances of various fluids and to decide what kind of properties the best-working fluid shows. In this work, an active working fluid selection instruction is proposed to deal with the temperature match between the bottoming system and cold source. The characters of ideal working fluids are summarized firstly when the temperature match method of a pinch analysis is combined. Various selected fluids are compared in thermodynamic and economic performances to verify the fluid selection instruction. It is found that when the ratio of the average specific heat in the heat transfer zone of exhaust gas to the average specific heat in the heat transfer zone of jacket water becomes higher, the irreversibility loss between the working fluid and cold source is improved. The ethanol shows the highest net power output of 25.52 kW and lowest electricity production cost of $1.97/(kWh) among candidate working fluids.
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Federau, Christian, Soren Christensen, Michael Mlynash, et al. "Comparison of stroke volume evolution on diffusion-weighted imaging and fluid-attenuated inversion recovery following endovascular thrombectomy." International Journal of Stroke 12, no. 5 (2016): 510–18. http://dx.doi.org/10.1177/1747493016677985.
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Background To compare the evolution of the infarct lesion volume on both diffusion-weighted imaging and fluid-attenuated inversion recovery in the first five days after endovascular thrombectomy. Methods We included 109 patients from the CRISP and DEFUSE 2 studies. Stroke lesion volumes obtained on diffusion-weighted imaging and fluid-attenuated inversion recovery images both early post-procedure (median 18 h after symptom onset) and day 5, were compared using median, interquartile range, and correlation plots. Patients were dichotomized based on the time after symptom onset of their post procedure images (≥18 h vs. <18 h), and the degree of reperfusion (on Tmax>6 s; ≥ 90% vs. < 90%). Results Early post-procedure, median infarct lesion volume was 19 ml [(IQR) 7–43] on fluid-attenuated inversion recovery, and 23 ml [11–64] on diffusion-weighted imaging. On day 5, median infarct lesion volume was 52 ml [20–118] on fluid-attenuated inversion recovery, and 37 ml [16–91] on diffusion-weighted imaging. Infarct lesion volume on early post-procedure diffusion-weighted imaging, compared to fluid-attenuated inversion recovery, correlated better with day 5 diffusion-weighted imaging and fluid-attenuated inversion recovery lesions (r = 0.88 and 0.88 vs. 0.78 and 0.77; p < 0.0001). Median lesion growth was significantly smaller on diffusion-weighted imaging when the early post-procedure scan was obtained ≥18 h post stroke onset (5 ml [−1–13]), compared to <18 h (13 ml [2–47]; p = 0.03), but was not significantly different on fluid-attenuated inversion recovery (≥18 h: 26 ml [12–57]; <18 h: 21 ml [5–57]; p = 0.65). In the <90% reperfused group, the median infarct growth was significantly larger for diffusion-weighted imaging and fluid-attenuated inversion recovery (diffusion-weighted imaging: 23 ml [8–57], fluid-attenuated inversion recovery: 41 ml [13–104]) compared to ≥90% (diffusion-weighted imaging: 6 ml [2–24]; p = 0.003, fluid-attenuated inversion recovery: 19 ml [8–46]; p = 0.001). Conclusions Early post-procedure lesion volume on diffusion-weighted imaging is a better estimate of day 5 infarct volume than fluid-attenuated inversion recovery. However, both early post-procedure diffusion-weighted imaging and fluid-attenuated inversion recovery underestimate day 5 diffusion-weighted imaging and fluid-attenuated inversion recovery lesion volumes, especially in patients who do not reperfuse.
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Dupras, R., L. Mills, C. Meunier, and Y. Chorfi. "90 Effects of treatment with the nonsteroidal anti-inflammatory drug Anafen prior to embryo recovery and the number of embryo flush procedures performed on prostaglandin levels in uterine fluid and pregnancy rate following embryo transfer." Reproduction, Fertility and Development 31, no. 1 (2019): 171. http://dx.doi.org/10.1071/rdv31n1ab90.
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Some studies have shown that performing a second flush during embryo collection can increase the number of embryos recovered. However, this technique results in greater uterine manipulation that may increase PGF2α in the uterine fluid of donor cows and affect pregnancy rate in recipient females. Two experiments were conducted (1) to determine whether PGF2α concentration in uterine fluid was affected by treatment with a non-steroidal anti-inflammatory drug (NSAID) before embryo recovery and (2) to determine whether the percent of recipients becoming pregnant following embryo transfer (P/ET) was affected by flush number. In both experiments, lactating Holstein cows were used as donors (n=18 and 34, respectively) and subjected to a standard superovulation protocol (Baracaldo et al. 2000 Theriogenology 53, 1239-1250, DOI: 10.1016/S0093-691X(00)00268-5). Embryo recovery was performed using 2 catheters that were inserted simultaneously into the uterus, 1 into each horn. During the first flush, a volume of 300mL of flush medium was used in each horn. At the end of the first flush approximately 75mL of fluid was left and, after 1h, a second flush was performed to recover the remaining fluid. Samples were taken from each horn at the first and second flush to determine PGF2α concentration using a bovine PGFM ELISA kit. Data for PGF2α concentrations in uterine fluid were presented as the average of both uterine horns. In Exp. 1, donors were randomly assigned to be treated with or without 1.2g of the NSAID Anafen (ketoprofen) IM 20min before embryo recovery. In Exp. 2, recovered grade-1 embryos from the first and second flush procedures were frozen in ethylene glycol and subsequently transferred to synchronized Holstein heifers (n=106 and 49 for the first and second flushes, respectively). Pregnancy was diagnosed by rectal palpation at Day 60. All data were analysed using t-test. In Exp. 1, Anafen treatment 20min before embryo recovery reduced PGF2α in uterine fluid during the second flush procedure (105.9±11.4v. 43.6±5.7 pg/mL; P&lt;0.001), but not during the first (54.7±7.3v. 44.2±5.6 pg/mL; P=0.34). In Exp. 2, PGF2α in uterine fluid was greater for the second flush as compared to the first flush (95.9±7.4v. 56.3±5.5 pg/mL; P&lt;0.001). A total of 345 viable embryos were recovered from the 34 donors in Exp. 2 (n=276 and 69 for the first and second flushes, respectively). The P/ET at Day 60 was greater (P&lt;0.05) for recipients that received embryos from the first flush as compared to recipients that received embryos from the second flush (64.2v. 49.0%). Taken together, the results of the present study indicate that the second flush procedure results in greater PGF2α levels in uterine fluid and that embryos recovered during the second flush are less likely to establish pregnancy following transfer. Moreover, pretreatment of donors with the NSAID Anafen reduced PGF2α levels in uterine fluid during the second flush. Further research is needed to determine whether treatment of donors with NSAID can improve the P/ET achieved following the transfer of embryos recovered following a second flush procedure.
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Barth, Madison, Japan Trivedi, Benedicta Nwani, and Yosamin Esanullah. "Optimal Zwitterionic Surfactant Slug for an Improved Oil Recovery in Oil Wet Carbonate Rocks." Alberta Academic Review 2, no. 2 (2019): 7–8. http://dx.doi.org/10.29173/aar45.
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Of recent, there has been research and development in the technologies/techniques required to meet the ever-growing energy demand in the world. Oil is a major source of energy which is contained in over 50% of carbonate reservoirs. The oil/mixed wettability of carbonate rocks makes it technically challenging to recover the needed oil. The process of crude oil recovery has three different stages primary, secondary and tertiary recovery. Tertiary recovery is also known as enhanced oil recovery or EOR. EOR includes the use of surfactants to reduce the interfacial tension between a hydrocarbon and brine, thus suspending them both in a microemulsion. Surfactant performance can be affected by multiple variables, including brine salinity, surfactant concentration, and type of hydrocarbon. A petroleum engineer must take all variables into consideration when selecting a surfactant to make sure that its efficiency is as high as possible, especially because the use of surfactants is costly.
 In this work, a chembetaine zwitter ionic surfactant of two different concentrations are evaluated at various synthetic formation brine salinities for their favourable wettability alteration and interfacial tension reduction in oil-wet carbonate- Silurian Dolomite. For the evaluation, fluid-fluid and rock-fluid analysis are carried out to select the optimal surfactant concentration and brine salinity with the greatest improved oil recovery potential.
 Results are indicative that the surfactant at the two concentrations studied is compatible at the ranges of salinities evaluated. However, from the fluid-fluid analysis, there was no ultra-low interfacial tension that is needed for oil mobilization. More so, the rock-fluid analysis shows that the surfactant is not able to alter the wettability of oil-wet rocks favourably. The optimal surfactant slug for the greatest oil recovery, in this case, would be expected at 0.5% surfactant concentration in 10,000 ppm synthetic formation brine salinity. This study, therefore, serves as a guide for the design of optimal surfactant slug in oil-wet carbonate cores requires to reduce non-productive time, prevent reservoir damage and therefore improve recovery.
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Muhammad, Edward Hamid, Hadziqul Abror, Eriska Eklezia Dwi Saputri, Riska Laksmita Sari, and Welayaturromadhona Welayaturromadhona. "Analisa Unjuk Kerja Sucker Rod Pump C-228 D – 213 – 86-7466 Sebagai Metode Pengangkatan Buatan Produksi Minyak Bumi untuk API 15° dan 45°." Jurnal Teknik Mesin 15, no. 2 (2022): 96–102. http://dx.doi.org/10.30630/jtm.15.2.945.
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The oil production process is the process of extracting oil from the reservoir using the wells that have been made. In the production process there are three stages, namely primary recovery, secondary recovery and tertiary recovery. At the primary recovery stage there are two methods, namely production using natural reservoir energy (natural flow) and production using artificial lift methods (artificial lift). There are two basic principles of artificial lift, namely gas lift and pumps. The principle of the gas lift is to inject gas into the bottom of the well thereby reducing the density and pressure gradient of the reservoir fluid so that the fluid flows more easily. While the principle of the pump is to provide additional energy (head) to lift the fluid. The type of pump that is often used for shallow wells is Sucker Rod Pump. The performance of the sucker rod pump is influenced by the characteristics of the well and reservoir such as pressure, well productivity, physical properties of the fluid, as well as the depth of the well and the dimensions of the sucker rod pump. In this study, the factors studied were the physical properties of the fluid, namely the API of the fluid with variations of API 15o and API 45o, as well as the pump volumetric efficiency (Ev) of 90% and 70%. From the analysis carried out, the results obtained a). For API 15° and Ev 90% fluids: 759 stb/day and 39 hp prime mover power; and for API 15° and Ev 70%: 591 stb/day and prime mover power of 32.2 hp. b). For API 45° and Ev 90% fluids: 783 stb/day and prime mover power of 34.3 hp; and for API 45° and Ev 70%: 609 stb/day and prime mover power of 28.6 hp.
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Marhaendrajana, Taufan, Indah Widiyaningsih, Ivan Kurnia, and Harry Budiharjo Sulistyarso. "FLUID-TO-FLUID AND FLUID-TO-ROCK INTERACTION ON SOPHOROLIPIDS BIOSURFACTANT FOR ENHANCED OIL RECOVERY: A LITERATURE REVIEW." Scientific Contributions Oil and Gas 48, no. 1 (2025): 63–76. https://doi.org/10.29017/scog.v48i1.1688.
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The promising glycolipids produced by non-pathogenic yeast as biosurfactants are called sophorolipids. Their advantages over chemical surfactants are smaller environmental impact, lower toxicity, and biodegradable. They can reduce interfacial tension (IFT), form microemulsions, and alter wettability in enhanced oil recovery applications. The potential as biosurfactants is due to the resistance to high salinity and high temperature in reservoir conditions.Laboratory experiments for enhanced oil recovery (EOR) applications require to test fluid-to-fluid and fluid-to-rock interactions in the complex crude oil–rock–brine (CORB) system. This review discusses the sophorolipids mechanisms of fluid-to-fluid and fluid-to-rock interactions.Sophorolipids’ potential in EOR processes can be determined from core flooding experiments, in which some researches reported the incremental oil recovery up to obtained up to 20%. The review and discussion in this article are intended to have a broad impact on science and the petroleum industry, particularly in EOR applications.
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Gerutu, Gerutu B., and Yossapong Laoonual. "Comparison Study of Cascaded Organic Rankine Cycles with Single and Dual Working Fluids for Waste Heat Recovery." Journal of Advanced Thermal Science Research 11 (May 24, 2024): 1–21. http://dx.doi.org/10.15377/2409-5826.2024.11.1.
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This study compares thermodynamics, economics, and environmental performance of cascaded ORCs operated under a single and dual fluids. In the single fluid cascaded ORC, toluene, benzene, acetone and cyclopentane are run in high and low temperature cycles, whereas in dual fluid cascaded ORC, toluene, benzene, acetone and cyclopentane are run in high temperature cycle and R601a in the low temperature cycle. The analysis compares variations in expander inlet temperature and condensation temperature. Thermodynamic performance involved net power output (Pnet) and thermal efficiency (ηth), while economic indicators included net present value (NPV) and levelized cost of electricity (LCOE). In environmental performance, the annual reduction in carbon dioxide emission (CO2-eq) is assessed. The findings revealed that dual fluid cascaded ORC generated the highest Pnet of 1245.11 kW while single fluid cascaded ORC reached 1170.27 kW. The dual fluid cascaded ORC showed the significant increase in Pnet (%DPnet) for about 43% at the lowest expander inlet temperature (500 K). In terms of ηth, dual fluid cascaded ORC attained 37.23 % while single fluid cascaded ORC reached 33.25%. It is further found that acetone+R601a performed well in dual fluid cascaded ORC, resulting in the highest Pnet and allowing system’s NPV to turn positive sooner than other fluids. Furthermore, cyclopentane+R601a had the lowest LCOE of 0.0158 US$/kWh, which is 1.1% lower compared to the single fluid cascaded ORC and competitive in the Thai electricity market. In environmental saving, dual fluid cascaded ORC reduced about 144.96 tCO2-eq/year, and outperformed single fluid cascaded ORC by roughly 6.39%.
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Medina-Rodriguez, Bryan X., Teresa M. Reilly, Teresa E. Lehmann, and Vladimir Alvarado. "The Impact of Naphthenic Acids on Dynamic Fluid–Fluid Interactions: Implication for Enhanced Oil Recovery." Energies 18, no. 9 (2025): 2231. https://doi.org/10.3390/en18092231.
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Previous coreflooding results and wettability analyses in our group show that injection of naphthenic-acid-enriched water can improve oil recovery over traditional waterflooding. This observation is still a subject of research efforts without a definitive explanation. Naphthenic acids (NA) have been reported to drive wettability alteration and increase the water–oil interface elasticity. These alterations depend on the NA carbon number and aqueous-phase salinity, among other conditions, as reported in the literature. Smart-water flooding (SWF) research often links recovery to the initial wettability condition, being higher for initially oil-wet rock. SWF refers to a technique in which the aqueous-phase ion composition or/and salinity are changed to maximize oil recovery. Given NAs’ complex solution behavior, selecting acid combinations that prompt oil recovery is a difficult objective. The aim of this research is to determine the effects of select naphthenic acids on the oil–water interfacial rheology and wettability alteration and how these interfacial effects are associated with oil recovery under spontaneous imbibition. NAs were selected based on their carbon number, molecular structure, and solubility in the saline solution used in this research. We aimed at exploring which NAs should be used to regulate interfacial properties so as to either increase oil recovery or accelerate production. Time-domain nuclear magnetic resonance, interfacial dilatational rheology, and liquid-bridge experiments, i.e., proxy of snap-off, were conducted. A baseline was established using results obtained with a previously tested sulfate-rich aqueous phase, shown to be effective in recovering oil. Results show that NA14 and N18 increase the water–oil interfacial viscoelasticity and induce interfacial healing but led to different recovery factors. N10, while effective at inducing water wetness in oil-wet rock, is ineffective at increasing the recovery factor. We concluded that wettability and oil–water interfacial rheology are not exclusive, and instead they can synergistically favor EOR benefits. Moreover, oil recovery benefits under spontaneous imbibition are shown to depend strongly on the initial wettability conditions.
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Song, Jinhyeuk, Jaekyeong Jang, Taehoon Kim, and Younghak Cho. "Particle Separation in a Microchannel with a T-Shaped Cross-Section Using Co-Flow of Newtonian and Viscoelastic Fluids." Micromachines 14, no. 10 (2023): 1863. http://dx.doi.org/10.3390/mi14101863.
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In this study, we investigated the particle separation phenomenon in a microchannel with a T-shaped cross-section, a unique design detailed in our previous study. Utilizing a co-flow system within this T-shaped microchannel, we examined two types of flow configuration: one where a Newtonian fluid served as the inner fluid and a viscoelastic fluid as the outer fluid (Newtonian/viscoelastic), and another where both the inner and outer fluids were Newtonian fluids (Newtonian/Newtonian). We introduced a mixture of three differently sized particles into the microchannel through the outer fluid and observed that the co-flow of Newtonian/viscoelastic fluids effectively separated particles based on their size compared with Newtonian/Newtonian fluids. In this context, we evaluated and compared the particle separation efficiency, recovery rate, and enrichment factor across both co-flow configurations. The Newtonian/viscoelastic co-flow system demonstrated a superior efficiency and recovery ratio when compared with the Newtonian/Newtonian system. Additionally, we assessed the influence of the flow rate ratio between the inner and outer fluids on particle separation within each co-flow system. Our results indicated that increasing the flow rate ratio enhanced the separation efficiency, particularly in the Newtonian/viscoelastic co-flow configuration. Consequently, this study substantiates the potential of utilizing a Newtonian/viscoelastic co-flow system in a T-shaped straight microchannel for the simultaneous separation of three differently sized particles.
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Jin, Yan, and Kang Ping Chen. "Fundamental equations for primary fluid recovery from porous media." Journal of Fluid Mechanics 860 (December 4, 2018): 300–317. http://dx.doi.org/10.1017/jfm.2018.874.
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Primary fluid recovery from a porous medium is driven by the volumetric expansion of thein situfluid. For production from a petroleum reservoir, primary recovery accounts for more than half of the total amount of recovered hydrocarbon. The primary recovery process is studied here at the pore scale and the macroscopic scale. The pore-scale flow is first analysed using the compressible Navier–Stokes equations and the mathematical theory for low-Mach-number flow developed by Klainerman & Majda (Commun. Pure Appl. Maths, vol. 34 (4), 1981, pp. 481–524; vol. 35 (5), 1982, pp. 629–651). An asymptotic analysis shows that the pore-scale flow is governed by the self-diffusion of the fluid and it exhibits a slip-like mass flow rate, even though the velocity satisfies the no-slip condition on the pore wall. The pore-scale density equation is then upscaled to a macroscopic diffusion equation for the density which possesses a diffusion coefficient proportional to the fluid’s kinematic viscosity. Darcy’s law is shown to be inapplicable to primary fluid recovery and it should be replaced by a new mass flux equation which depends on the porosity but not on the permeability. This is in stark contrast to the classical result and it can have important implications for hydrocarbon recovery as well as other applications.
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Esanullah, Yosamin, Japan Trivedi, Benedicta Nwani, and Madison Barth. "Optimal Zwitterionic Surfactant Slug for an Improved Oil Recovery in Oil Wet Carbonate Rocks - Silurian Dolomite." Alberta Academic Review 2, no. 2 (2019): 27–28. http://dx.doi.org/10.29173/aar40.
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The increase in energy demand has led to extensive research and development on economically, environmentally and technically feasible ways of improving the ever-growing energy demand. A common derivative of energy is from hydrocarbons, specifically oil. The process of oil recovery can be divided into primary, secondary, and tertiary recovery (also known as enhanced oil recovery). Once the internal pressure of a reservoir has depleted enough during primary and secondary recovery, more advanced techniques in enhanced oil recovery mechanisms are used to recover 50-80% of oil in the reservoir. Tertiary recovery includes the use of surfactants to reduce interfacial tension (IFT) or alter wettability. In this work, a zwitter ionic surfactant at two different concentrations is evaluated for its ability to reduce the interfacial tension between oil and water, as well as altering wettability in silurian dolomite. To achieve this, fluid-fluid analysis was done by a compatibility test, phase behavior test and interfacial tension measurements. Rock-fluid analysis was also completed by means of floatation test, carried out with carbonate rock particles to analyze the surfactant’s ability to alter wettability. Solution pH measurements were taken to validate the qualitative floatation test results. Results show that the surfactant, chembetaine C surfactant, is compatible with all ranges of salinities investigated, though was not able to produce a winsor type III micro-emulsion. The results of the interfacial tension measurements are in line with the phase behavior test, as none of the measurements were at ultra-low values. Surfactant retention is likely to occur with the analyzed zwitterionic surfactant based on the fluid-fluid analysis. Qualitative results from the floatation test show that the wettability of the carbonate rock particles cannot be significantly altered to more water-wet conditions. The pH of the solution remains at alkaline values, which can be beneficial in enhanced oil recovery in producing soap in situ, also known as saponification. Overall, tests conclude that this zwitterionic surfactant at 1% concentration would be most effective at 10,000 ppm salinity brine, though overall is not suitable for chemically enhanced oil recovery.
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Gómez-Izquierdo, Juan C., Alessandro Trainito, David Mirzakandov, et al. "Goal-directed Fluid Therapy Does Not Reduce Primary Postoperative Ileus after Elective Laparoscopic Colorectal Surgery." Anesthesiology 127, no. 1 (2017): 36–49. http://dx.doi.org/10.1097/aln.0000000000001663.
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Abstract Background Inadequate perioperative fluid therapy impairs gastrointestinal function. Studies primarily evaluating the impact of goal-directed fluid therapy on primary postoperative ileus are missing. The objective of this study was to determine whether goal-directed fluid therapy reduces the incidence of primary postoperative ileus after laparoscopic colorectal surgery within an Enhanced Recovery After Surgery program. Methods Randomized patient and assessor-blind controlled trial conducted in adult patients undergoing laparoscopic colorectal surgery within an Enhanced Recovery After Surgery program. Patients were assigned randomly to receive intraoperative goal-directed fluid therapy (goal-directed fluid therapy group) or fluid therapy based on traditional principles (control group). Primary postoperative ileus was the primary outcome. Results One hundred twenty-eight patients were included and analyzed (goal-directed fluid therapy group: n = 64; control group: n = 64). The incidence of primary postoperative ileus was 22% in the goal-directed fluid therapy and 22% in the control group (relative risk, 1; 95% CI, 0.5 to 1.9; P = 1.00). Intraoperatively, patients in the goal-directed fluid therapy group received less intravenous fluids (mainly less crystalloids) but a greater volume of colloids. The increase of stroke volume and cardiac output was more pronounced and sustained in the goal-directed fluid therapy group. Length of hospital stay, 30-day postoperative morbidity, and mortality were not different. Conclusions Intraoperative goal-directed fluid therapy compared with fluid therapy based on traditional principles does not reduce primary postoperative ileus in patients undergoing laparoscopic colorectal surgery in the context of an Enhanced Recovery After Surgery program. Its previously demonstrated benefits might have been offset by advancements in perioperative care.
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MUHAMMAD, Muhammad Aminu, Usman HASSAN, Mohammed Bello ADAMU, Ibrahim AYUBA, and Yahaya Yakubu ADAMU. "Performance Evaluation of Rankiya (Grewia venusta) as a Polymer for Enhanced Oil Recovery-Polymer Flooding." ABUAD Journal of Engineering and Applied Sciences 2, no. 1 (2024): 20–27. http://dx.doi.org/10.53982/ajeas.2024.0202.03-j.
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Polymer Flooding is an enhanced oil recovery method where high-molecular-weight polymers are added into the injected water, in order to increase the viscosity of injection fluid, improve volumetric sweep efficiency, and finally increase the oil recovery factor. Most research studies focused on the use of partially hydrolysed polyacrylamide (HPAM), xanthan gum, SPG, HEC as flooding fluid. This work focused on investigating the potential of natural polymer - Grewia venusta plant tree in formulating flooding fluid for polymer flooding operation. The polymer was prepared from the mucilage extracted from the inner stem bark of Grewia venusta. Rheological characterization shows that the formulated Grewia venusta mucilage (GVM)-based flooding fluid maintained high viscosity under very high salinity, also exhibits shear thinning behaviour which obeys power law model with fluid behaviour index n = 0.32 and consistency index K= 6.3 at highest GVM concentration of 3000 ppm, similarly revealed that GVM-based flooding fluid was stable when subjected to high salinity of 130,000 ppm and temperature, up to 90 oC an inconsequential decrease in viscosity was experienced. These indicate its potential in enhancing oil recovery process. Core flooding analysis was carried out on an outcrop core sample with porosity and permeability of 26.1% and 218 mD respectively. Core flooding analysis revealed that: with increase in GVM concentration of 500, 750, 1000 and 2000 ppm oil recovered against time were 55.1%, 62.6%, 69.2% and 72.9% respectively, beyond 2000 ppm GVM concentration (optimum concentration), increase in polymer concentration did not bring about an increase in oil recovery, this finally resulted to an incremental recovery of 29% original oil in place (OOIP).
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Tong, D. H., X. H. Kong, M. Li, X. Liu, G. L. Huang, and X. P. Wang. "Thermodynamic Analysis of Space Regenerative Orc (Srorc) System for Automotive Waste Heat Recovery." Journal of Physics: Conference Series 2186, no. 1 (2022): 012018. http://dx.doi.org/10.1088/1742-6596/2186/1/012018.
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Abstract In this paper, the space regenerative ORC (SRORC) system is proposed. In SRORC system, the superheated working fluid is divided into two parts after it works completely in the expander. The performance of SRORC system is studied, the performance of ORC system and SRORC system under different conditions are compared and analyzed. From the perspective of latent and sensible heat, the mechanism of using space regeneration to improve the performance of SRORC system is explored. The models of ORC system and SRORC system are built by Aspen plus software. R245fa is chosen as the working fluid because of its excellent performance. The simulation results show that compared with the evaporation temperature, the evaporation pressure has greater influence on the performance of SRORC system under B75 condition. Under C25, B50, A75, B75, and B100 conditions, compared with ORC system, the net output power of SRORC system is increased by 30.7%, 30.3%, 34.4%, 33.2% and 34%, the thermal efficiency is increased by 4.3%, 4.36%, 4.97%, 4.79% and 4.89%, the exergy efficiency is increased by 11.13%, 10.28%, 10.36%, 10.69% and 10.02%, the recovery efficiency of engine power is increased by 3.92%, 2.55%, 2.9%, 2.91% and 3.36%, respectively. The heat recovery rate of IHE-ORC system and SRORC system are 13.7kW and 24.8kW under B75 condition. In SRORC system, liquid working fluid can recover sensible and latent heat of superheated working fluid, and the latent heat accounts for most of the heat recovered.
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Yang, Shenyao, Zhilin Qi, Jie Tian, Mingda Dong, Wei Zhang, and Wende Yan. "Composition and Injection Rate Co-Optimization Method of Supercritical Multicomponent Thermal Fluid Used for Offshore Heavy Oil Thermal Recovery." Energies 17, no. 21 (2024): 5239. http://dx.doi.org/10.3390/en17215239.
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Supercritical multicomponent thermal fluid injection is a new technology with great potential for offshore heavy oil thermal recovery. In the process of thermal fluid generation, the reaction conditions including temperature, pressure, and the organic mass concentration in the reaction material will significantly affect its composition and injection rate and will further affect the thermal recovery and development quality of heavy oil. However, there is a lack of relevant research on the variation rules and control methods of the composition and injection rate of supercritical multicomponent thermal fluids, resulting in a lack of technical mechanisms for effective optimization. To fill this gap, a reaction molecular dynamics simulation method was used to simulate thermal fluid generation under different temperatures, pressures, and organic mass concentrations. The changes in thermal fluid composition and yield with reaction conditions were studied, and a control model of thermal fluid composition and yield was established. The proportional relationship between the thermal fluid generation scale of an offshore heavy oil platform and the simulated thermal fluid generation scale is analyzed, and a collaborative optimization method of thermal fluid composition and injection rate in field applications is proposed. The results show the following: (1) The higher the mass concentration of organic matter, the higher the content of supercritical carbon dioxide and supercritical nitrogen in thermal fluids, and the lower the content of supercritical water. (2) The higher the temperature and pressure, the higher the thermal fluid yield, and the higher the organic mass concentration, the lower the thermal fluid yield. (3) The component fitting model conforms to the power function relationship, and the coefficient of determination R2 is greater than 0.9; the yield fitting model conforms to the modified inverse linear logarithmic function relationship, the determination coefficient R2 is greater than 0.8, and the fitting degree is high. (4) The ratio between the actual injection rate of thermal fluids in the mine field and the molecular simulated thermal fluid yield is the ratio of organic matter mass in the platform thermal fluid generator and organic matter mass in the simulated box. (5) Based on the composition and yield control model, combined with the simulation of the ratio relationship between yield and injection rate in the field, a collaborative optimization method of thermal fluid composition and injection rate was established. The research results can provide an effective technical method for predicting, controlling, and optimizing the composition and injection rate of supercritical multicomponent thermal fluids.
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Fu, Qiang, Jie Tian, Yongfei Liu, Zhilin Qi, Hongmei Jiao, and Shenyao Yang. "Comparison of the Reaction Characteristics of Different Fuels in the Supercritical Multicomponent Thermal Fluid Generation Process." Energies 17, no. 21 (2024): 5376. http://dx.doi.org/10.3390/en17215376.
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Supercritical multicomponent thermal fluid technology is a new technology with obvious advantages in offshore heavy oil recovery. However, there is currently insufficient understanding of the generation characteristics of the supercritical multicomponent thermal fluid, which is not conducive to the promotion and application of this technology. In order to improve the economic benefits and applicability of the supercritical multicomponent thermal fluid thermal recovery technology, this article reports on indoor supercritical multicomponent thermal fluid generation experiments and compares the reaction characteristics of different fuels in the supercritical multicomponent thermal fluid generation process. The research results indicate that the main components of the products obtained from the supercritical water–crude oil/diesel reaction are similar. Compared to the supercritical water–crude oil reaction, the total enthalpy value of the supercritical multicomponent thermal fluid generated by the supercritical water–diesel reaction is higher, and the specific enthalpy is lower. When the thermal efficiency of the boiler is the same, the energy equilibrium concentration of crude oil is lower than that of diesel. The feasibility of using crude oil instead of diesel to prepare supercritical multicomponent thermal fluids is analyzed from three aspects: reaction mechanism, economic benefits, and technical conditions. It is believed that using crude oil instead of diesel to prepare supercritical multicomponent thermal fluids has good feasibility.
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TSUCHIHASHI, TOSHIO, TOSHIO MAKI, and TAKESHI SUZUKI. "Study of the Fast Inversion Recovery Pulse Sequence: : With Reference to Fast Fluid Attenuated Inversion Recovery and Fast Short TI Inversion Recovery Pulse Sequence." Japanese Journal of Radiological Technology 53, no. 2 (1997): 291–98. http://dx.doi.org/10.6009/jjrt.kj00003109749.
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Alwassiti, Asawer A., Mayssaa Ali AL-Bidry, and Khalid Mohammed. "Experimental study of Zubair shale stability of east Baghdad oil field using different additives in water based mud." Journal of Petroleum Exploration and Production Technology 10, no. 3 (2019): 1215–25. http://dx.doi.org/10.1007/s13202-019-00820-4.
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AbstractShale formation is represented as one of the challenge formations during drilling wells because it is a strong potential for wellbore instability. Zubair formation in Iraqi oil fields (East Baghdad) is located at a depth from 3044.3 to 3444 m. It is considered as one of the most problematic formations through drilling wells in East Baghdad. Most problems of Zubair shale are swelling, sloughing, caving, cementing problem and casing landing problem caused by the interaction of drilling fluid with the formation. An attempt to solve the cause of these problems has been adapted in this paper by enhancing the shale stability through adding additives to the drilling fluid. The study includes experiments by using two types of drilling fluids, API and polymer type, with five types of additives (KCl, NaCl, CaCl2, Na2SiO3 and Flodrill PAM 1040) in different concentrations (0.5, 1, 5 and 10) wt% and different immersion period (1, 24 and 72 h) hours. The effect of drilling fluids and additive salts on shale has been studied by using different techniques: (XRD, XRF, reflected and transmitted microscope) as well shale recovery. The results show that adding 10 wt% of Na2SiO3 to API drilling fluid results in a high percentage of shale recovery (78.22%), while the maximum shale recovery was (80.57%) in polymer drilling fluid type gained by adding 10 wt% of Na2SiO3.