Temperature prediction of two phase flow in wellbore using modified heat transfer model: An experimental analysis

Hou, Zhaokai; Yan, Tie; Li, Zhaoxuan; Feng, Jinyu; Sun, Shuzheng; Yuan, Yuan

doi:10.1016/j.applthermaleng.2018.12.022

Cited by 17 publications

(5 citation statements)

References 18 publications

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“…For a two phase system of air-water, the production pressure was higher compared to a single phase system. Hou et al [6] used a modified heat transfer model to predict the temperature of a two-phase geothermal fluid flow in the production pipelines. To predict the behavior of the flow, a Computational Fluid Dynamics (CFD) model was used.…”

Section: Introductionmentioning

confidence: 99%

Two-Phase Turbulent Fluid Flow in a Geothermal Pipe with Chemical Reaction

Eric

Kinyanjui

Abonyo

2022

Journal of Applied Mathematics

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In this study, two-phase non-Newtonian turbulent fluid flow in an inclined geothermal pipe with chemical reaction was considered. The governing nonlinear partial differential equations derived were solved numerically using Finite Difference Method. Influence of flow parameters on the temperature, concentration and velocity profiles were analyzed graphically. From the mathematical analysis of the model, it was established that the chemical reaction parameter significantly influenced the concentration distribution in both gaseous and liquid phases. Findings further revealed that decreasing the chemical reaction parameter resulted in decreased concentration of the geothermal fluid, which causes corrosion of geothermal pipes. These findings provide important information to engineers and researchers in making better decisions in terms of design, sizing and maintenance of flow systems in geothermal pipes.

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Section: Introductionmentioning

confidence: 99%

Two-Phase Turbulent Fluid Flow in a Geothermal Pipe with Chemical Reaction

Eric

Kinyanjui

Abonyo

2022

Journal of Applied Mathematics

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“…Based on this, Yin and Gao, combined with the correction of compressibility and gas-liquid mixing density, established a pseudo single-phase flow wellbore-temperature field model considering the change of wellbore fluid flow pattern [13,14]. Hou studied the influence of gas-liquid two-phase flow pattern change on fluid heat-transfer ability through experiments [15]. According to the change of fluid flow characteristics after well shut-in, Song established a transient model of the temperature field of ocean wellbore under the condition of well shut-in and studied the heattransfer mechanism during well shut-in [16].…”

Section: Introductionmentioning

confidence: 99%

Wellbore Temperature and Pressure Calculation of Offshore Gas Well Based on Gas–Liquid Separated Flow Model

et al. 2022

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Compared with land wells, the production environment and reservoir depth of offshore oil and gas wells are more complex and shallower. Further, HPHT production fluid there will produce strong temperature and pressure disturbance that affects the wellbore, which easily generates wellbore safety problems, such as wellhead growth and leakage caused by the incompatible deformation of casing and cement sheath. Therefore, obtaining an accurate wellbore temperature and pressure field is the key to implementing a wellbore safety assessment. Based on the gas–liquid two-phase separated method, this paper established an improved calculation model of wellbore temperature and pressure field for offshore HPHT wells. This model also takes into account the heat transfer environment characteristics of “formation-seawater-air” and the influence of well structure. Compared with the measured data of the case well, the error of temperature and pressure calculation results of the improved model are only 0.87% and 2.46%. Further, its calculation accuracy is greatly improved compared to that of the traditional gas–liquid homogeneous flow calculation model. Based on this model, the influencing factors of wellbore temperature and pressure in offshore gas wells are analyzed. The results show that forced convection heat exchange between seawater–air and wellbore is stronger than that between wellbore and formation. Reducing the gas–liquid ratio of the product can effectively reduce wellbore temperature and increase wellbore pressure. The gas production has a significant impact on the wellbore temperature. When the gas production rises from 10 × 104⋅m3/d to 60 × 104⋅m3/d, the wellhead temperature rises from 63 °C to 99 °C. However, due to the mutual influence of friction pressure drop and hydrostatic pressure drop, wellbore pressure increases first and then decreases with the increase in gas production. The improved model can provide a more accurate estimate of the time to reach the rated wellhead temperature. Meanwhile, this model displays accurate theoretical support for the rational formulation of the production plan after the well opening, so as to avoid excessive restrictions on the initial production rate.

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“…Based on the experimental study of heat transfer of single-phase flow and gas-liquid two-phase flow in the wellbore, Zhaokai Hou et al (Hou et al 2019) proposed a series of new correlations for calculating the convective heat transfer coefficients of various flows (including single flow, bubble flow, intermittent flow, and annular flow), analyzed the wellbore temperature by using the improved heat transfer model, and obtained the drilling fluid displacement, inlet temperature The influence of geothermal gradient and formation gas invasion velocity on wellbore temperature. But, the coupling effect of temperature and pressure is not considered in the model.…”

Section: Introductionmentioning

confidence: 99%

Investigation and application of wellbore temperature and pressure field coupling with gas–liquid two-phase flowing

Zheng

Dou

et al. 2021

J Petrol Explor Prod Technol

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With the development of gas well exploitation, the calculation of wellbore with single-phase state affected by single factor cannot meet the actual needs of engineering. We need to consider the simulation calculation of complex wellbore environment under the coupling of multiphase and multiple factors, so as to better serve the petroleum industry. In view of the problem that the commonly used temperature and pressure model can only be used for single-phase state under complex well conditions, and the error is large. Combined with the wellbore heat transfer mechanism and the calculation method of pipe flow pressure drop gradient, this study analyzes the shortcomings of Ramey model and Hassan & Kabir model through transient analysis. Based on the equations of mass conservation, momentum conservation and energy conservation, and considering the interaction between fluid physical parameters and temperature and pressure, the wellbore pressure coupling model of water-bearing gas well is established, and the Newton Raphael iterative method is used for MATLAB programming. On this basis, the relationship between tubing diameter, gas production, gas–water ratio, and wellbore temperature field and pressure field in high water-bearing gas wells is discussed. The results show that the wellbore temperature pressure coupling model of high water-bearing gas well considering the coupling of gas–liquid two-phase flow wellbore temperature pressure field has higher accuracy than Ramey model and Hassan & Kabir model, and the minimum coefficients of variation of each model are 0.022, 0.037 and 0.042, respectively. Therefore, the model in this study is highly consistent with the field measured data. Therefore, the findings of this study are helpful to better calculate the wellbore temperature and pressure parameters under complex well conditions.

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Temperature prediction of two phase flow in wellbore using modified heat transfer model: An experimental analysis

Cited by 17 publications

References 18 publications

Two-Phase Turbulent Fluid Flow in a Geothermal Pipe with Chemical Reaction

Two-Phase Turbulent Fluid Flow in a Geothermal Pipe with Chemical Reaction

Wellbore Temperature and Pressure Calculation of Offshore Gas Well Based on Gas–Liquid Separated Flow Model

Investigation and application of wellbore temperature and pressure field coupling with gas–liquid two-phase flowing

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