The Experts below are selected from a list of 156 Experts worldwide ranked by ideXlab platform
A.r. Hasan - One of the best experts on this subject based on the ideXlab platform.
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nonisothermal reservoir Wellbore Flow modeling in gas reservoirs
Journal of Natural Gas Science and Engineering, 2018Co-Authors: C.s. Kabir, A.r. HasanAbstract:Abstract Most analytical and numerical Flow modeling presuppose isothermal Flow behavior in the reservoir. However, for high rates and large consequent drawdown gas reservoirs, the nonisothermal behavior becomes the norm due to the Joule-Thomson (J-T) effect. Other factors, such as a fluid's adiabatic expansion (AE), heat convection, and the heat exchange with surrounding formations may also make contributions. Accounting for this nonisothermal Flow behavior becomes a necessity for accurately estimating a well's performance due to changes in fluid properties. This paper starts with the general energy balance in the reservoir and presents a semianalytical solution to estimate the nonisothermal, single-phase gas temperature in the reservoir during production. This solution considers the J-T effect, adiabatic expansion effect, transient temperature behavior, heat convection, and heat exchange of fluid with over and under-burden formation. The variations of gas viscosity, density, J-T coefficient as a function of temperature and pressure are taken into consideration by making a small spatial step at each computational node. A field case study validates the time-variant Wellbore temperature profiles with the coupled reservoir heat-transfer model. Distributed temperature measurements or DTS during a drillstem test (DST) made this validation feasible. The J-T effect dominates in the near Wellbore region due to dramatic pressure change. The J-T induced cooling usually occurs for gas in the reservoir. However, for high-pressure systems, the gas behaves like a liquid and gets heated up. For some intermediate pressure intervals, the gas temperature slightly increases with expansion, reach a plateau, and then gradually decreases as the gas moves toward the Wellbore with declining pressure. By coupling the reservoir heat-transfer model with the Wellbore heat-transfer model, one can monitor more accurately.
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Simplified Wellbore Flow Modeling in Gas-Condensate Systems
SPE Annual Technical Conference and Exhibition, 2004Co-Authors: C.s. Kabir, A.r. HasanAbstract:Predicting long-term reservoir performance with realistic Wellbore models is fraught with uncertainty because of the complexity of two-phase Flow. Even a calibrated two-phase-Flow model departs from its expected performance trend when changes in Flow conditions occur. The full-length paper explores the possibility of using simplified approaches to computing bottomhole pressure (BHP) from wellhead pressure (WHP), measured rates, gravity of producing fluids, and tubular dimensions. Statistical results from BHP computations on three independent data sets comprising 167 gas/condensate-well tests show that the homogeneous model compares quite favorably with mechanistic two-phase-Flow models.
Weiqiang Song - One of the best experts on this subject based on the ideXlab platform.
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Wellbore Flow field of coiled tubing drilling with supercritical carbon dioxide
Greenhouse Gases-Science and Technology, 2017Co-Authors: Weiqiang Song, Ruihe Wang, Mengyun ZhaoAbstract:To achieve better well control for supercritical carbon dioxide drilling, a mathematical model was presented to investigate the pressure and temperature profile in both the tubing and the annulus. The closed model fully couples the hydraulics, heat transfer, and compressibility of carbon dioxide, and then the Wellbore Flow field is presented and analyzed based on field application. The results show that the pressure change of carbon dioxide is 36.7% smaller than that of water along the annulus in the study case. Carbon dioxide changes into supercritical state when the depth equals 700 m ∼830 m in the tubing, and it could maintain in supercritical state in the whole annulus. Both the pressure profile and the temperature profile are highly coupled with the physical properties of carbon dioxide. The density of carbon dioxide is large enough to drive downhole motors and its capacity is much larger than that of air in the Wellbore. The pressure increases lightly with increasing mass Flow rate in the annulus; however, it is significantly and positively impacted by the outlet pressure. The influence of outlet pressure on temperature profile is negligible in the tubing. The inlet temperature could not impact the pressure profile in the annulus, and its influence on temperature profile mainly lies in the shallow section of the tubing. It is newly validated that supercritical carbon dioxide drilling is more suitable for the exploitation of unconventional reservoirs with narrow pressure windows. The results could lay a theoretical foundation for practical application. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd.
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coupling model for carbon dioxide Wellbore Flow and heat transfer in coiled tubing drilling
Journal of Natural Gas Science and Engineering, 2016Co-Authors: Hongjian Ni, Weiqiang Song, Ruihe Wang, Zhonghou ShenAbstract:Abstract In order to drill with carbon dioxide as the circulation fluid, a mathematical model was proposed to investigate the Flow field in both tubing and annulus. Based on finite volume method, the closed model fully couples the hydraulics, heat transfer and physical properties of carbon dioxide. According to field application, the model is solved and discussed with a case study. The results show that, the pressure is in positive correlation with well depth in both tubing and annulus. The fluid temperature increases fast after liquid carbon dioxide is pumped into tubing and then the increasing rate slows down with increasing depth. Carbon dioxide changes into supercritical state when the depth equals 780 m. The pressure drop of bit jet is 9.78 MPa and the temperature difference between carbon dioxide and formation rock is 12.11 K at bottom hole. In the annulus, the temperature decreases as carbon dioxide Flows upward and it is higher than geothermal temperature when depth is less than 927 m. The changes in physical properties are mainly dominated by temperature change in the tubing and by pressure change in the annulus. The density, viscosity and thermal conductivity all witness a constant decrease along the Flow route, and the changing trends develop faster at shallow well section in the tubing. At bottom hole, the density is large enough to drive down-hole motors. The heat capacity changes little in the tubing and then increases rapidly when Flowing upward along the annulus. The capacity is much larger than that of air in Wellbore. Carbon dioxide maintains in supercritical state in the annulus and provides advantages for reservoir exploitation. This study aims to lay theoretical foundation for practical application.
Barry Freifeld - One of the best experts on this subject based on the ideXlab platform.
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fully coupled Wellbore reservoir modeling of geothermal heat extraction using co2 as the working fluid
Geothermics, 2015Co-Authors: Barry Freifeld, Christine Doughty, Steven Zakem, Ming Sheu, Bruce Cutright, Tracy TerrallAbstract:Abstract We consider using CO 2 as an alternative to water as a working fluid to produce geothermal electricity through the application of a coupled reservoir, Wellbore, and surface power-plant model. Our approach has relaxed some of the simplifying assumptions others have made in previous work, through the application of a subsurface reservoir model fully coupled with a detailed Wellbore simulator. We also include a simplified representation of CO 2 turbomachinery for a surface plant optimized for direct use of supercritical CO 2 . The Wellbore model includes heat transfer between the fluid in the well and the surrounding formation, in addition to frictional, inertial, and gravitational forces. Our results show that thermophysical operating conditions and the amount of power production are greatly influenced by Wellbore Flow processes and by Wellbore/caprock heat transfer. We investigate competing effects that control development of a thermosiphon, which enables production of geothermal electricity without the need for a continuously operating external pump.
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numerical simulations of the macondo well blowout reveal strong control of oil Flow by reservoir permeability and exsolution of gas
Proceedings of the National Academy of Sciences of the United States of America, 2012Co-Authors: Curtis M. Oldenburg, Karsten Pruess, Stefan Finsterle, Barry Freifeld, George J MoridisAbstract:In response to the urgent need for estimates of the oil and gas Flow rate from the Macondo well MC252-1 blowout, we assembled a small team and carried out oil and gas Flow simulations using the TOUGH2 codes over two weeks in mid-2010. The conceptual model included the oil reservoir and the well with a top boundary condition located at the bottom of the blowout preventer. We developed a fluid properties module (Eoil) applicable to a simple two-phase and two-component oil-gas system. The Flow of oil and gas was simulated using T2Well, a coupled reservoir-Wellbore Flow model, along with iTOUGH2 for sensitivity analysis and uncertainty quantification. The most likely oil Flow rate estimated from simulations based on the data available in early June 2010 was about 100,000 bbl/d (barrels per day) with a corresponding gas Flow rate of 300 MMscf/d (million standard cubic feet per day) assuming the well was open to the reservoir over 30 m of thickness. A Monte Carlo analysis of reservoir and fluid properties provided an uncertainty distribution with a long tail extending down to 60,000 bbl/d of oil (170 MMscf/d of gas). The Flow rate was most strongly sensitive to reservoir permeability. Conceptual model uncertainty was also significant, particularly with regard to the length of the well that was open to the reservoir. For fluid-entry interval length of 1.5 m, the oil Flow rate was about 56,000 bbl/d. Sensitivity analyses showed that Flow rate was not very sensitive to pressure-drop across the blowout preventer due to the interplay between gas exsolution and oil Flow rate.
C.s. Kabir - One of the best experts on this subject based on the ideXlab platform.
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nonisothermal reservoir Wellbore Flow modeling in gas reservoirs
Journal of Natural Gas Science and Engineering, 2018Co-Authors: C.s. Kabir, A.r. HasanAbstract:Abstract Most analytical and numerical Flow modeling presuppose isothermal Flow behavior in the reservoir. However, for high rates and large consequent drawdown gas reservoirs, the nonisothermal behavior becomes the norm due to the Joule-Thomson (J-T) effect. Other factors, such as a fluid's adiabatic expansion (AE), heat convection, and the heat exchange with surrounding formations may also make contributions. Accounting for this nonisothermal Flow behavior becomes a necessity for accurately estimating a well's performance due to changes in fluid properties. This paper starts with the general energy balance in the reservoir and presents a semianalytical solution to estimate the nonisothermal, single-phase gas temperature in the reservoir during production. This solution considers the J-T effect, adiabatic expansion effect, transient temperature behavior, heat convection, and heat exchange of fluid with over and under-burden formation. The variations of gas viscosity, density, J-T coefficient as a function of temperature and pressure are taken into consideration by making a small spatial step at each computational node. A field case study validates the time-variant Wellbore temperature profiles with the coupled reservoir heat-transfer model. Distributed temperature measurements or DTS during a drillstem test (DST) made this validation feasible. The J-T effect dominates in the near Wellbore region due to dramatic pressure change. The J-T induced cooling usually occurs for gas in the reservoir. However, for high-pressure systems, the gas behaves like a liquid and gets heated up. For some intermediate pressure intervals, the gas temperature slightly increases with expansion, reach a plateau, and then gradually decreases as the gas moves toward the Wellbore with declining pressure. By coupling the reservoir heat-transfer model with the Wellbore heat-transfer model, one can monitor more accurately.
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Simplified Wellbore Flow Modeling in Gas-Condensate Systems
SPE Annual Technical Conference and Exhibition, 2004Co-Authors: C.s. Kabir, A.r. HasanAbstract:Predicting long-term reservoir performance with realistic Wellbore models is fraught with uncertainty because of the complexity of two-phase Flow. Even a calibrated two-phase-Flow model departs from its expected performance trend when changes in Flow conditions occur. The full-length paper explores the possibility of using simplified approaches to computing bottomhole pressure (BHP) from wellhead pressure (WHP), measured rates, gravity of producing fluids, and tubular dimensions. Statistical results from BHP computations on three independent data sets comprising 167 gas/condensate-well tests show that the homogeneous model compares quite favorably with mechanistic two-phase-Flow models.
Zhongwei Chen - One of the best experts on this subject based on the ideXlab platform.
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large scale study of the effect of Wellbore geometry on integrated reservoir Wellbore Flow
Journal of Natural Gas Science and Engineering, 2016Co-Authors: Mohsen Azadi, S M Aminossadati, Zhongwei ChenAbstract:Extraction of coal seam gas (CSG) prior to mining is crucial for reducing the potential risks of gas outburst and explosions during underground coal mining as well as gas production purposes. Many numerical and experimental studies have been carried out to identify the factors affecting the gas productivity. These factors include coal properties, gas content and Wellbore geometries. Two different Flow conditions determine the gas production efficiency: The gas Flow inside the Wellbore injected from wall, and the Flow through porous coal medium. The full understanding of simultaneous Flow of fluids through reservoir and Wellbore is critical for analysing the reservoir behaviour. However, previous studies examined the Flow of these fluids separately. In this research, a large scale three-dimensional model for simulation of integrated reservoir-Wellbore Flow is developed to study the effect of Wellbore geometry on Flow characteristics and Wellbore productivity. Four different Wellbore diameters of 0.075, 0.10, 0.125 and 0.15 m as well as three different lengths of 50, 100, and 150 m were chosen to accomplish the parametric study of Wellbore geometry. It is assumed that the Wellbores were in a steady-state condition for two different single phase scenarios of water and methane gas Flow. The simulation results were validated against the pressure drop models for internal single phase gas and water Flow reported in the literature. The obtained results revealed that increasing the Wellbore diameter led to reduction of fluid pressure in the coal seam. Regarding the effect of Wellbore length, it was observed that at a specific distance from Wellbore outlet, the pressure distribution is independent of the Wellbore length and upstream effects. It is also shown that Wellbore production could be enhanced by increasing the diameter and the length of Wellbore for both gas and liquid Flow. The developed integrated framework can be used further for study of any enhanced gas recovery method by changing the boundary conditions based on the physical model.