The Experts below are selected from a list of 49866 Experts worldwide ranked by ideXlab platform
Moon Sik Jeong - One of the best experts on this subject based on the ideXlab platform.
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Development of Coupled Biokinetic and Thermal Model to Optimize Cold-Water Microbial Enhanced Oil Recovery (MEOR) in Homogenous Reservoir
MDPI AG, 2019Co-Authors: Eunji Hong, Moon Sik Jeong, Tae Hong Kim, Ji Ho Lee, Jin Hyung Cho, Kun Sang LeeAbstract:By incorporating a Temperature-dependent biokinetic and thermal model, the novel method, cold-water microbial enhanced oil recovery (MEOR), was developed under nonisothermal conditions. The suggested model characterized the growth for Bacillus subtilis (microbe) and Surfactin (biosurfactant) that were calibrated and confirmed against the experimental results. Several biokinetic parameters were obtained within approximately a 2% error using the cardinal Temperature model and experimental results. According to the obtained parameters, the examination was conducted with several injection scenarios for a high-Temperature Reservoir of 71 °C. The results proposed the influences of injection factors including nutrient concentration, rate, and Temperature. Higher nutrient concentrations resulted in decreased interfacial tension by producing Surfactin. On the other hand, injection rate and Temperature changed growth condition for Bacillus subtilis. An optimal value of injection rate suggested that it affected not only heat transfer but also nutrient residence time. Injection Temperature led to optimum Reservoir condition for Surfactin production, thereby reducing interfacial tension. Through the optimization process, the determined optimal injection design improved oil recovery up to 53% which is 8% higher than waterflooding. The proposed optimal injection design was an injection sucrose concentration of 100 g/L, a rate of 7 m3/d, and a Temperature of 19 °C
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Estimation of Critical Temperatures Based on New Viscosity Model for HPAM Polymer Flooding in High-Temperature Reservoir
IOR 2015 - 18th European Symposium on Improved Oil Recovery, 2015Co-Authors: B. Choi, Moon Sik Jeong, J. Choi, K.s. LeeAbstract:Polymer flooding in high Temperature Reservoirs usually has shown poor performance due to severe thermal degradation, leading to and ineffective in-situ sweep behavior. Even though the thermal degradation is important characteristic of polymer, accurate viscosity models have not been implemented in the conventional Reservoir simulation. This paper presents new viscosity model as a function of Temperature and time which can describe the thermal decomposition as an irreversible process. The Temperature-dependent viscosity model is developed by using half-life decomposition of synthetic polymer. The new viscosity model can reflect well-characterized chemical degradation sequence for transported polymer. Having established the viscosity model, comparison to the conventional Flory-Huggins' equation. The results that Temperature and initial injected concentration have more massive impact on viscosity, long-term stability, compared to conventional Flory-Huggins' model were obtained. The new viscosity model helps to evaluate accurately the application of polymer flooding in high-Temperature Reservoirs. From simulations including heat transfer within Reservoir by adopting new viscosity model, Temperature limitation was deduced in terms of various parameters such as Reservoir Temperature, polymer concentration, and oil viscosity. Even the hottest Reservoir with 200C can be exploited by low-Temperature fluid injection which provokes heat loss by convection and conduction. This heat loss occurring during polymer injection with 120C into the hot Reservoir can make reaction rate of thermal decomposition slow down and long-term stability can be maintained. According to the acquired results, high Reservoir Temperature causes low oil recovery efficiency without guarantying long-term stability. The critical Temperature for application of polymer flooding was calculated as about 160C. Above the critical range, polymer flooding is expected to show poor performance. Also, the viscous oil lowers the effectiveness of polymer flooding not only at high-Temperature, but also at low-Temperature Reservoirs. Effects of injection fluid Temperature showed even at the hottest Reservoir (200C), severe thermal degradation can be avoided by injecting lower-Temperature fluid, which leads to slow down decomposition rate. Heat loss from cooling water injection is able to increase oil recovery in high-Temperature Reservoirs. Therefore, the critical Reservoir Temperature estimated previously as abandonment condition can be taken into accounts and extended.
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Temperature-dependent viscosity model of HPAM polymer through high-Temperature Reservoirs
Polymer Degradation and Stability, 2014Co-Authors: Byung-in Choi, Moon Sik JeongAbstract:Abstract Polymer flooding in high Temperature Reservoirs usually has shown poor performance because the injected polymeric solution tends to experience severe thermal degradation and ineffective in-situ sweep behavior. For the simulation results under such Reservoirs, the real observation is likely to be out of estimation due to the absence of accurate viscosity model. The aim of this study was therefore to modify an existing numerical Reservoir simulator to model HPAM hydrolysis, which is caused by thermal degradation in high Temperature Reservoirs, by employing the concept of half-life decomposition. The term ‘half-life’ has been proposed in numerical simulations to describe the kinetics of thermal decomposition of unstable polymers. This work analyzed rheological properties considering thermal hydrolysis with the goal of establishing an in-situ viscosity calculation for high Temperature Reservoirs. Comparison of the conventional Flory–Huggins’ model to the proposed viscosity model allowed us to evaluate hydrolysis and the long-term stability of the polymer according to Temperature. The results obtained using the new viscosity model indicated that polymer concentration loss was proportional to the initial concentration. However, viscosity reduction was more severe than concentration loss at higher initial polymer injection concentrations and was exaggerated as the initial concentration increased. Due to polymer decomposition at high Temperatures, application of polymer flooding is limited at high-Temperature Reservoir.
Yuehua Chen - One of the best experts on this subject based on the ideXlab platform.
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dynamic processes of indigenous microorganisms from a low Temperature petroleum Reservoir during nutrient stimulation
Journal of Bioscience and Bioengineering, 2014Co-Authors: Peike Gao, Lingxia Zhao, Huimei Tian, Xuecheng Dai, Liubing Dai, Hongbo Wang, Haidong Huang, Yuehua ChenAbstract:Compared to medium–high Temperature petroleum Reservoirs (30°C–73°C), little is known about microbial regulation by nutrients in low-Temperature Reservoirs. In this study, we report the performance (oil emulsification and biogas production) and community structure of indigenous microorganisms from a low-Temperature (22.6°C) petroleum Reservoir during nutrient stimulation. Culture-dependent approaches indicated that the number of hydrocarbon-oxidizing bacteria (HOB), nitrate-reducing bacteria (NRB) and methane-producing bacteria (MPB) increased by between 10- and 1000-fold, while sulfate-reducing bacteria (SRB) were observed at low levels during stimulation. Phylogenetic analysis of the 16S rRNA gene indicated that Pseudomonas, Ochrobactrum, Acinetobacter, Halomonas and Marinobacter, which have the capability to produce surfactants, were selectively enriched. Methanoculleus, Methanosaeta, Methanocorpusculum and Methanocalculus showed the largest increase in relative abundance among archaea. Micro-emulsion formed with an average oil droplet diameter of 14.3 μm (ranging between 4.1 μm and 84.2 μm) during stimulation. Gas chromatographic analysis of gas production (186 mL gas/200 mL medium) showed the levels of CO2 and CH4 increased 8.97% and 6.21%, respectively. Similar to medium–high Temperature Reservoirs, HOB, NRB, SRB and MPB were ubiquitous in the low-Temperature Reservoir, and oil emulsification and gas production were the main phenomena observed during stimulation. Oil emulsification required a longer duration of time to occur in the low-Temperature Reservoir.
Jinzhou Zhao - One of the best experts on this subject based on the ideXlab platform.
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Tertiary cross-linked and weighted fracturing fluid enables fracture stimulations in ultra high pressure and Temperature Reservoir
Fuel, 2020Co-Authors: Xiaojiang Yang, Jincheng Mao, Wenlong Zhang, Zhang Heng, Yang Zhang, Chong Zhang, Dong Ouyang, Qiang Chen, Chong Lin, Jinzhou ZhaoAbstract:Abstract Advancement of exploration and drilling extended the depth of oil and gas Reservoir development, while it is accompanied by great challenges of abnormally high pressure and ultra-high Temperature. Weighted fracturing fluid was considered as one of the key technologies to deal with this challenge in the case of existing fracturing equipment. In this work, a super guar gum with good solubility was modified from guar gum for potassium formate (CHKO2) weighted fracturing fluid and tertiary cross-linking strategy was employed to cope with ultra-high Reservoir Temperature. In addition, a novel gel breaker which was completely different from the conventional oxidized breaker was designed to achieve the complete gel breaking under strong reducing conditions caused by concentrated CHKO2. The CHKO2 weighted fracturing fluid proposed in this study performed very well in static leak-off and formation damage. The density of fracturing fluid weighted by CHKO2 here was up to 1.33 g/cm3. The applicable Temperature of the fluid can reach 180 °C and the fracturing fluid can be completely broken, almost with no residue left after the operation. This is a very useful and practical technology for abnormally high-pressure and ultra-high Temperature Reservoir stimulation.
Erling Halfdan Stenby - One of the best experts on this subject based on the ideXlab platform.
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Density, compressibility and phase equilibrium of high pressure-high Temperature Reservoir fluids up to 473 K and 140 MPa
The Journal of Supercritical Fluids, 2020Co-Authors: Teresa Regueira, Erling Halfdan Stenby, Maria-lito Glykioti, Nomiki Kottaki, Wei YanAbstract:Abstract Experimental measurement of volumetric and phase equilibrium properties of two high pressure - high Temperature Reservoir fluids was performed in this work. One fluid is volatile oil and the other is gas condensate. The density, isothermal compressibility, saturation pressure, and liquid fraction below the saturation pressure were determined in the Temperature range up to 473.15 K by using a high pressure vibrating tube densitometer and a PVT cell. The obtained data were modelled by using equations of state including Soave-Redlich-Kwong (SRK), Peng-Robinson (PR), volume translated SRK (SRK-VT), volume translated PR (PR-VT) and Perturbed-Chain Statistical Association Fluid Theory (PC-SAFT). Among these models, the performance in saturation pressure prediction is system-dependent and it is hard to generalize the observation. PC-SAFT models volumetric properties satisfactorily. Regarding density calculation, it performs similarly to SRK-VT and PR-VT for the two fluids investigated here. Concerning isothermal compressibility, PC-SAFT is slightly better.
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General approach to characterizing Reservoir fluids for EoS models using a large PVT database
Fluid Phase Equilibria, 2017Co-Authors: Farhad Varzandeh, Erling Halfdan StenbyAbstract:Abstract Fluid characterization is needed when applying any EoS model to Reservoir fluids. It is important especially for non-cubic models such as PC-SAFT where fluid characterization is less mature. Furthermore, there is a great interest to apply non-cubic models to high pressure high Temperature Reservoir fluids as they are believed to give better description of density and compressibility over a wide Temperature and pressure range. We proposed a general approach to characterizing Reservoir fluids and applied it to PC-SAFT. The approach consists in first, developing the correlations based on the DIPPR database, and then adjusting the correlations based on a large PVT database. The adjustment was made to minimize the deviation in key PVT properties like saturation pressures, densities at Reservoir Temperature and stock tank oil densities, while keeping the n-alkane limit of the correlations unchanged. The general approach can also be applied to other EoS models for improving their fluid characterization and we showed this for SRK and PR. In addition, we developed a PNA based characterization method for PC-SAFT based on the same general principles. We made a comprehensive comparison in PVT calculation involving 17 EoS-characterization combinations and 260 Reservoir fluids. The new characterization methods generally improved the PVT calculation results.
J P Courcy - One of the best experts on this subject based on the ideXlab platform.
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high pressure high Temperature Reservoir fluids investigation of synthetic condensate gases containing a solid hydrocarbon
Fluid Phase Equilibria, 1995Co-Authors: Philippe Ungerer, B Faissat, C Leibovici, H Zhou, E Behar, Gerard Moracchini, J P CourcyAbstract:In deep North Sea Reservoirs, condensate gases have been found at high Temperatures (up to 190 °C) and pressures (up to 1100 bar). Some of these methane-rich fluids are near critical and may contain significant amounts of high molecular weight hydrocarbons. These features make it particularly difficult to study their thermodynamic behaviour, as well from an experimental as from a theoretical point of view. As such contrasted mixtures have not been extensively studied in the literature, we have also started data acquisition on synthetic mixtures. Compared with real fluids, synthetic mixtures allow indeed a more reliable test of thermodynamic models because their composition is much better controlled. Four synthetic gas condensates containing 6 or 7 components have been investigated in a visual cell to show the sensitivity of phase equilibria with respect to small quantities of heavy alkanes (nC36) and aromatics (phenanthrene). A very large sensitivity has been found, since addition of about 1% mol. of a heavy hydrocarbon may increase dew pressures by 200 bar in some cases. Crystallization of heavy hydrocarbons has been observed for Temperatures 10–30 °C lower than pure component melting Temperatures. These features have been modelled, using the Peng-Robinson equation of state for fluid phases. As a general feature, the Peng-Robinson EOS reproduces adequately the phase envelope of these fluids with regressed interaction parameters between methane and the heaviest hydrocarbon. However, prediction of liquid dropout is unsatisfactory. A simple model of crystallization has been used to predict appearance of solid from gas, which accounts for solid state transitions. This model accounts fairly well for phenanthrene or nC36 crystallization at high pressure.
