Applicability of Models for Liquid Loading Prediction in Gas Wells

Vieira, Cleide; Stanko, Milan

doi:10.2118/195466-ms

Cited by 5 publications

(2 citation statements)

References 12 publications

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“…A 60 mm diameter test pipe was positioned at angles of 30 • , 45 • and 60 • from horizontal. The experiments showed that the liquid film model was in good agreement with the experimental results [9].…”

Section: Introductionsupporting

confidence: 73%

Research on a New Method for Intermittent Production of Horizontal Wells in Low-Permeability Gas Field

Suo

et al. 2023

Energies

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With the development of drilling technology in recent years, an increasing number of horizontal wells have been widely used in low-permeability gas fields. Although horizontal wells are much more productive than vertical wells, fluid accumulation can occur when the formation energy drops and the gas flow rate in the wellbore is not sufficient to remove the loaded fluid from the wellbore. Intermittent production is a good method for preventing liquid loading, but thus far, there is no difference between the open and closed working system of horizontal wells and that of vertical wells, and there is a certain misunderstanding here. In this work, experiments were conducted on the opening process and closing process of a horizontal well, and it was found that the loaded fluid in the horizontal wellbore is a large source of water. It enters the vertical section during the opening process, thereby raising the liquid level and storing the fluid loaded in the vertical section during the closing process, which is difficult to unload. Combined with the experimental results, the production dynamics of a horizontal well with intermittent production was analyzed, and the well opening process and well closing process were divided into four stages. On this basis, a new multifrequency well opening method for intermittent production of horizontal wells was proposed to unload the liquid in horizontal wellbore. The field application case shows that this method can effectively eliminate the drawbacks caused by using conventional methods and increase the average gas production in one cycle by 46%.

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Section: Introductionsupporting

confidence: 73%

Research on a New Method for Intermittent Production of Horizontal Wells in Low-Permeability Gas Field

Suo

et al. 2023

Energies

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“…The maximum relative error is 8.73%, the minimum is 6.38%, and the errors are not more than 10%, indicating that the new model has high accuracy. The liquid-film reversal model is compared with 110 sets of laboratory experimental data in published literature [29][30][31][32][33][34][35][36][37]. The experiment data covers the pipe size range from 30 mm to 152 mm, with an inclination of 1 degree to 90 degrees.…”

Section: Verification Of the Prediction Model Of Critical Liquid-carrying Gas Velocitymentioning

confidence: 99%

Research on Critical Liquid-Carrying Model in Wellbore and Laboratory Experimental Verification

Hou

Wang

et al. 2021

Processes

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Liquid loading in gas wells may slash production rates, shorten production life, or even stop production. In order to reveal the mechanism of liquid loading in gas wells and predict its critical flowrates, theoretical research and laboratory experiments were conducted in this work. A new model of liquid-film reversal was established based on Newton’s law of internal friction and gas–liquid two-phase force balance, with the critical reverse point obtained using the minimum gas–liquid interface shear force method. In this model, the influences of the pipe angle on the liquid film thickness were considered, and the friction coefficient of the gas–liquid interface was refined based on the experimental data. The results showed that the interfacial shear force increases by increasing the liquid superficial velocity, which leads first to an increase of the critical liquid-carrying gas velocity and then to a decrease, and the critical production also decreases. With 0° as the vertical position of the pipeline and an increase of the inclination angle, the critical liquid-carrying velocity first increases and then decreases, and the maximum liquid-carrying velocity appears in the range of 30–40°. In addition, the critical liquid-carrying gas velocity is positively correlated with the pipe diameter. Compared with the previous model, the model in this work performed better considering its prediction discrepancy with experiment data was less than 10%, which shows that the model can be used to calculate the critical liquid-carrying flow rate of gas wells. The outcome of this work provides better understanding of the liquid-loading mechanism. Furthermore, the prediction model proposed can provide guidance in field design to prevent liquid loading.

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