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Claudio Alimonti - One of the best experts on this subject based on the ideXlab platform.
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using transient inflow performance relationships to model the dynamic interaction between reservoir and wellbore during pressure testing
Journal of Energy Resources Technology-transactions of The Asme, 2008Co-Authors: Aldo Costantini, G F Hewitt, Gioia Falcone, Claudio AlimontiAbstract:The fundamental understanding of the dynamic interactions between multiphase flow in the reservoir and that in the wellbore remains surprisingly weak. The classical way of dealing with these interactions is via inflow performance relationships (IPRs), where the inflow from the reservoir is related to the pressure at the bottom of the well, which is a function of the multiphase flow behavior in the well. A steady-state IPRs are normally adopted, but their use may be erroneous when transient multiphase flow conditions occur. The transient multiphase flow in the wellbore causes problems in well test interpretation when the well is shut-in at the surface and the Bottomhole pressure is measured. The pressure buildup (PBU) data recorded during a test can be dominated by transient wellbore effects (e.g., phase change, flow reversal, and re-entry of the denser phase into the producing zone), making it difficult to distinguish between true reservoir features and transient wellbore artifacts. This paper introduces a method to derive the transient IPRs at Bottomhole conditions in order to link the wellbore to the reservoir during PBU. A commercial numerical simulator was used to build a simplified reservoir model (single well, radial coordinates, homogeneous rock properties) using published data from a gas condensate field in the North Sea. In order to exclude wellbore effects from the investigation of the transient inflow from the reservoir, the simulation of the wellbore was omitted from the model. Rather than the traditional flow rate at surface conditions, Bottomhole pressure was imposed to constrain the simulation. This procedure allowed the flow rate at the sand face to be different from zero during the early times of the PBU, even if the surface flow rate is equal to zero. As a result, a transient IPR at Bottomhole conditions was obtained for the given field case and for a specific set of time intervals, time steps, and Bottomhole pressure. In order to validate the above simulation approach, a preliminary evaluation of the required experimental setup was carried out. The setup would allow the investigation of the dynamic interaction between the reservoir, the near-wellbore region, and the well, represented by a pressured vessel, a cylindrical porous medium, and a vertical pipe, respectively.
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using transient inflow performance relationships to model the dynamic interaction between reservoir and wellbore during pressure testing
ASME 2007 26th International Conference on Offshore Mechanics and Arctic Engineering, 2007Co-Authors: Aldo Costantini, G F Hewitt, Gioia Falcone, Claudio AlimontiAbstract:The fundamental understanding of the dynamic interactions between multiphase flow in the reservoir and that in the wellbore remains surprisingly weak. The classical way of dealing with these interactions is via inflow performance relationships (IPR’s), where the inflow from the reservoir is related to the pressure at the bottom of the well, which is a function of the multiphase flow behaviour in the well. Steady-state IPR’s are normally adopted, but their use may be erroneous when transient multiphase flow conditions occur. Transient multiphase flow in the wellbore causes problems in well test interpretation when the well is shut-in at surface and the Bottomhole pressure is measured. Pressure build-up (PBU) data recorded during a test can be dominated by transient wellbore effects (e.g. phase change, flow reversal and re-entry of the denser phase into the producing zone), making it difficult to distinguish between true reservoir features and transient wellbore artefacts. This paper introduces a method to derive the transient IPR’s at Bottomhole conditions in order to link the wellbore to the reservoir during PBU. A commercial numerical simulator was used to build a simplified reservoir model (single well, radial co-ordinates, homogeneous rock properties) using published data from a gas condensate field in the North Sea. In order to exclude wellbore effects from the investigation of the transient inflow from the reservoir, the simulation of the wellbore was omitted from the model. Rather than the traditional flow rate at surface conditions, Bottomhole pressure was imposed to constrain the simulation. This procedure allowed the flow rate at the sand face to be different from zero during the early times of the PBU, even if the surface flow rate is equal to zero. As a result, a transient IPR at Bottomhole conditions was obtained for the given field case and for a specific set of time intervals, time steps and Bottomhole pressure. In order to validate the above simulation approach, a preliminary evaluation of the required experimental set-up was carried out. The set-up would allow the investigation of the dynamic interaction between the reservoir, the near-wellbore region and the well, represented by a pressured vessel, a cylindrical porous medium and a vertical pipe, respectively.Copyright © 2007 by ASME
Aldo Costantini - One of the best experts on this subject based on the ideXlab platform.
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using transient inflow performance relationships to model the dynamic interaction between reservoir and wellbore during pressure testing
Journal of Energy Resources Technology-transactions of The Asme, 2008Co-Authors: Aldo Costantini, G F Hewitt, Gioia Falcone, Claudio AlimontiAbstract:The fundamental understanding of the dynamic interactions between multiphase flow in the reservoir and that in the wellbore remains surprisingly weak. The classical way of dealing with these interactions is via inflow performance relationships (IPRs), where the inflow from the reservoir is related to the pressure at the bottom of the well, which is a function of the multiphase flow behavior in the well. A steady-state IPRs are normally adopted, but their use may be erroneous when transient multiphase flow conditions occur. The transient multiphase flow in the wellbore causes problems in well test interpretation when the well is shut-in at the surface and the Bottomhole pressure is measured. The pressure buildup (PBU) data recorded during a test can be dominated by transient wellbore effects (e.g., phase change, flow reversal, and re-entry of the denser phase into the producing zone), making it difficult to distinguish between true reservoir features and transient wellbore artifacts. This paper introduces a method to derive the transient IPRs at Bottomhole conditions in order to link the wellbore to the reservoir during PBU. A commercial numerical simulator was used to build a simplified reservoir model (single well, radial coordinates, homogeneous rock properties) using published data from a gas condensate field in the North Sea. In order to exclude wellbore effects from the investigation of the transient inflow from the reservoir, the simulation of the wellbore was omitted from the model. Rather than the traditional flow rate at surface conditions, Bottomhole pressure was imposed to constrain the simulation. This procedure allowed the flow rate at the sand face to be different from zero during the early times of the PBU, even if the surface flow rate is equal to zero. As a result, a transient IPR at Bottomhole conditions was obtained for the given field case and for a specific set of time intervals, time steps, and Bottomhole pressure. In order to validate the above simulation approach, a preliminary evaluation of the required experimental setup was carried out. The setup would allow the investigation of the dynamic interaction between the reservoir, the near-wellbore region, and the well, represented by a pressured vessel, a cylindrical porous medium, and a vertical pipe, respectively.
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using transient inflow performance relationships to model the dynamic interaction between reservoir and wellbore during pressure testing
ASME 2007 26th International Conference on Offshore Mechanics and Arctic Engineering, 2007Co-Authors: Aldo Costantini, G F Hewitt, Gioia Falcone, Claudio AlimontiAbstract:The fundamental understanding of the dynamic interactions between multiphase flow in the reservoir and that in the wellbore remains surprisingly weak. The classical way of dealing with these interactions is via inflow performance relationships (IPR’s), where the inflow from the reservoir is related to the pressure at the bottom of the well, which is a function of the multiphase flow behaviour in the well. Steady-state IPR’s are normally adopted, but their use may be erroneous when transient multiphase flow conditions occur. Transient multiphase flow in the wellbore causes problems in well test interpretation when the well is shut-in at surface and the Bottomhole pressure is measured. Pressure build-up (PBU) data recorded during a test can be dominated by transient wellbore effects (e.g. phase change, flow reversal and re-entry of the denser phase into the producing zone), making it difficult to distinguish between true reservoir features and transient wellbore artefacts. This paper introduces a method to derive the transient IPR’s at Bottomhole conditions in order to link the wellbore to the reservoir during PBU. A commercial numerical simulator was used to build a simplified reservoir model (single well, radial co-ordinates, homogeneous rock properties) using published data from a gas condensate field in the North Sea. In order to exclude wellbore effects from the investigation of the transient inflow from the reservoir, the simulation of the wellbore was omitted from the model. Rather than the traditional flow rate at surface conditions, Bottomhole pressure was imposed to constrain the simulation. This procedure allowed the flow rate at the sand face to be different from zero during the early times of the PBU, even if the surface flow rate is equal to zero. As a result, a transient IPR at Bottomhole conditions was obtained for the given field case and for a specific set of time intervals, time steps and Bottomhole pressure. In order to validate the above simulation approach, a preliminary evaluation of the required experimental set-up was carried out. The set-up would allow the investigation of the dynamic interaction between the reservoir, the near-wellbore region and the well, represented by a pressured vessel, a cylindrical porous medium and a vertical pipe, respectively.Copyright © 2007 by ASME
Gensheng Li - One of the best experts on this subject based on the ideXlab platform.
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Gas kick simulation in oil-based drilling fluids with the gas solubility effect during high-temperature and high-pressure well drilling
Applied Thermal Engineering, 2019Co-Authors: Zhengming Xu, Xianzhi Song, Gensheng LiAbstract:Abstract The high solubility of the invaded gas in oil-based drilling fluids and the heat transfer between annulus fluids and the surrounding formation make the accurate prediction and effective control of the Bottomhole pressure (BHP) difficult during deep well drilling. In this study, a transient gas-liquid two-phase flow model considering the gas solubility and heat transfer effects is developed to simulate multiphase flow behaviors after gas kick in oil-based drilling fluids. Finite difference method is adopted to solve the governing equations. Predicted wellbore temperature and pressure distributions are in good agreement with field data, which indicates the accuracy of this model. Based on the proposed model, the flowing and thermal behaviors of gas and liquid phases in the annulus are compared when the gas solubility effect and the heat transfer effect are incorporated and not incorporated into the model. In the case of this study, without considering the gas solubility effect, the Bottomhole pressure could be underestimated by 4.2% (2.92 M P a ), while the Bottomhole temperature is overestimated by 3.2% (3.74 °C). Without considering the heat transfer effect, the Bottomhole pressure could be overestimated by 11.4% (7.94 M P a ) under steady flow conditions. Besides, the effects of the reservoir pressure difference, choke pressure, geothermal gradient, and well depth on the wellbore pressure and temperature distributions are investigated. The results of this study may help field operators to accurately predict and effectively control the Bottomhole pressure after gas kick in oil-based drilling fluids during deep well drilling.
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numerical analysis of transient conjugate heat transfer and thermal stress distribution in geothermal drilling with high pressure liquid nitrogen jet
Applied Thermal Engineering, 2018Co-Authors: Shikun Zhang, Gensheng Li, Zhongwei Huang, Xiaoguang Wu, Chi Peng, Wenping ZhangAbstract:Abstract This paper presents a numerical analysis of heat transfer and thermal stress in Bottomhole rocks during geothermal drilling with high-pressure liquid nitrogen jet. The simulation is conducted by a three-dimensional model in transient state. The conjugate heat transfer method is employed to compute heat transfer between solid and liquid. The thermo-physical properties of liquid nitrogen and rocks are considered in detail. The results indicate that high velocity and turbulence kinetic energy of liquid nitrogen jet at impingement surface enhance heat transfer efficiency between cryogenic fluid and hot rock. Huge tensile stress is generated adjacent to the solid-liquid interface, which is favorable for rock breaking on Bottomhole. The primitive rock temperature has a significant impact on maximal stress value. A set of experiments is conducted to validate the effects of thermal stresses on rock breakage. The thermal stresses diminish significantly under laboratory conditions without effective constraint on rock boundaries. In our experiments, the coal rather than other types of rock, was selected as working specimen due to its well-developed natural cracks and small tensile strength. Our results would shed light on the geothermal drilling with high-pressure nitrogen jet.
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Comparison of numerical analysis on the downhole flow field for multi-orifice hydrothermal jet drilling technology for geothermal wells
Geothermics, 2017Co-Authors: Xianzhi Song, Gensheng Li, Guodong Ji, Zhaoyu PangAbstract:Abstract Newly developed hydrothermal jet drilling technology has the potential of being economically advantageous over conventional drilling techniques for drilling deep wells in hard formations. By applying coiled tubing techniques and modulating fluid media in the Bottomhole reaction chamber, there can be a high temperature and high velocity jet striking and conducting heat to break the rock. So far, there has been no specific study on the influence of nozzle structure on the flow field of multiple hydrothermal jets. This paper presents hydrothermal jet models with different numbers of orifices to investigate the features of flow field, carrying capacity, drilling ability and cooling effect. Results show that for two models in the absence of cooling water, the Bottomhole center temperature and pressure are higher than the two sides under multiple hydrothermal jets conditions. This is similar to the flow pattern for a single jet. Additionally, for the five-orifice nozzle with cooling water injected, the entire high temperature region is cylindrical. Ambient cooling water envelops the inner hot water. By comparing different models, the five-orifice nozzle model without cooling water shows a circular symmetric distribution of the Bottomhole temperature. With cooling water injected, the central high temperature region becomes rectangular, while the margin of the well bottom is cooled by the peripheral cooling water. The bottom rock average temperature in five-orifice model is lower than for the four-orifice model due to more drastic thermal and kinetic transfer between the hydrothermal jet and the cooling water. The five-orifice nozzle model is better than the four-orifice nozzle model in terms of Bottomhole temperature, Bottomhole pressure and carrying capacity. Therefore, the five-orifice nozzle should be adopted for hydrothermal jet drilling. It is also feasible to pump down relatively high temperature cooling water to guarantee the high temperature downhole environment. Meanwhile, the cooling water pressure should be controlled during the drilling process for better cooling efficiency. All results in this paper are relevant to the parameters design for multi-orifice hydrothermal jet drilling technology.
Tao Zhang - One of the best experts on this subject based on the ideXlab platform.
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Thermal performance analysis of drilling horizontal wells in high temperature formations
Applied Thermal Engineering, 2015Co-Authors: Gonghui Liu, Tao ZhangAbstract:Abstract An integrated circulation temperature model for horizontal well drilling was developed, field-tested, and compared with results from vertical wells in order to accurately predict Bottomhole temperature while addressing the difference in Bottomhole temperatures between horizontal and vertical wells. The model divides the well drilling operation into five distinct interconnected regions each characterized by their own distinct thermal and fluid flow processes, as well as the mechanical and hydraulic energy exchange and heat conversion. A finite volume method of numerical simulation is then used to solve the differential equations. The simulation results were then calibrated and validated using field measurements, and a subsequent analysis of the heat source distribution and sensitivity revealed that the variation in temperature of horizontal drilling is quite different than that experienced with vertical wells. The long horizontal section, heat transfer term and fluid specific heat capacity are found to be the main reasons why the Bottomhole temperature for horizontal wells rises well above the static formation temperature. The parameters in vertical wells are more sensitive than that in horizontal wells. When the Bottomhole temperature exceeds the static formation temperature in horizontal wells, parameters such as pumping rate have an opposite effect on Bottomhole temperature, as compared to vertical wells.
Gonghui Liu - One of the best experts on this subject based on the ideXlab platform.
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A new method for early gas kick detection based on the consistencies and differences of Bottomhole pressures at two measured points
Journal of Petroleum Science and Engineering, 2019Co-Authors: Hongwei Yang, Gonghui Liu, Chao Wang, Hailong Jiang, Kuidong Luo, Bin WangAbstract:Abstract Early gas kick detection is an important measure to ensure well control safety. In accordance with the fluctuation of the Bottomhole pressure during early gas kick, the gas kick can be detected rapidly and early with downhole measurement tool. At present, erroneous diagnosis often occurred when gas kick detection was performed using pressure fluctuations of a single measured point. In this paper, firstly, considering the water hammer effect, a wellbore pressure fluctuation model at the initial stage of gas kick was established to accurately describe the transient annular pressure variations. The model was solved using the composite difference scheme and was verified using a laboratory gas kick experiment. Secondly, a dual-measured-points (DMP) method for early gas kick detection was presented based on the consistencies and discrepancies of Bottomhole pressures at two measured points. The distance between two measured points was optimized. Simulation results indicated that the annular pressure at the measured point increased and periodically changed with time in the initial stage of gas kick, and then declined approximately linearly after the gas-liquid interface reached the measured point. The distance between the two measured points was mainly dominated by the borehole diameter, and increased with the decrease of borehole diameter. The gas kick confirmation time (GKCT) obtained using DMP method was 2–7 min and the corresponding gas kick confirmation volume (GKCV) was 0.3–0.5 m3. The GKCT diminished with the increase of the formation permeability and Bottomhole negative differential pressure, and with the decrease of the borehole diameter and well depth.
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Thermal performance analysis of drilling horizontal wells in high temperature formations
Applied Thermal Engineering, 2015Co-Authors: Gonghui Liu, Tao ZhangAbstract:Abstract An integrated circulation temperature model for horizontal well drilling was developed, field-tested, and compared with results from vertical wells in order to accurately predict Bottomhole temperature while addressing the difference in Bottomhole temperatures between horizontal and vertical wells. The model divides the well drilling operation into five distinct interconnected regions each characterized by their own distinct thermal and fluid flow processes, as well as the mechanical and hydraulic energy exchange and heat conversion. A finite volume method of numerical simulation is then used to solve the differential equations. The simulation results were then calibrated and validated using field measurements, and a subsequent analysis of the heat source distribution and sensitivity revealed that the variation in temperature of horizontal drilling is quite different than that experienced with vertical wells. The long horizontal section, heat transfer term and fluid specific heat capacity are found to be the main reasons why the Bottomhole temperature for horizontal wells rises well above the static formation temperature. The parameters in vertical wells are more sensitive than that in horizontal wells. When the Bottomhole temperature exceeds the static formation temperature in horizontal wells, parameters such as pumping rate have an opposite effect on Bottomhole temperature, as compared to vertical wells.