AUTHOR=Liu Mingtao , Hao Ruihui , Leng Bing , Meng Xiangyu , Wang Guoyu , Pang Zhaohe , Zhang Yaojin 

TITLE=Study on liquid carrying law and foam drainage system optimization design for liquid-loading gas wells

JOURNAL=Frontiers in Earth Science

VOLUME=Volume 13 - 2025

YEAR=2025

URL=https://www.frontiersin.org/journals/earth-science/articles/10.3389/feart.2025.1671644

DOI=10.3389/feart.2025.1671644

ISSN=2296-6463

ABSTRACT=IntroductionWith the global energy demand on the rise, natural gas plays a crucial role as a clean and efficient energy source. However, wellbore liquid loading has become a key constraint on the stable production of gas fields in their mid-to-late stages—specifically, it affects approximately 40% of the gas wells in the Liaohe Oilfield, leading to productivity declines or even well shut-ins. Foam Assisted Lift (FAL) is a mainstream technical solution to mitigate wellbore liquid loading due to its low cost and strong adaptability. Nevertheless, FAL is plagued by crude design of dosing parameters in practical applications, which either causes unnecessary chemical waste (from overdosing) or results in operational failure (from underdosing), limiting its efficiency and economic viability.MethodsThis study focused on three typical gas wells (Well Y-1, Y-2, and Y-3) with distinct liquid loading and FAL application statuses: Well Y-1 did not adopt foam drainage technology; Well Y-2 achieved good liquid production after FAL application but suffered from excessive foam drainage agent injection; Well Y-3 used FAL but failed to meet the expected foam drainage target. To address the limitations of traditional FAL parameter design, this research innovatively treated foam as a special type of liquid to align with existing wellbore pressure (e.g., Beggs-Brill method) and temperature distribution models. On this basis, three core technical components were developed: 1) a segmented liquid loading calculation model based on the casing-tubing pressure difference; 2) a comprehensive dosing parameter optimization system covering initial dosage, daily replenishment amount, and injection cycle; and 3) validation of critical liquid-carrying velocity models (including the Turner model, Li Min model, and Wang Yizhong model) to screen the most applicable one for foam systems.ResultsThe optimized FAL scheme yielded significant performance improvements and cost reductions. In terms of liquid-carrying capacity: Well Y-1 (previously without FAL) saw a 26.89% enhancement, and Well Y-3 (with underperforming FAL) saw a 22.64% enhancement. In terms of cost control: the daily dosing amount for Well Y-2 was reduced to 32.3% of the original dosage, and the FAL operation cycle for Well Y-3 was extended from 6 days to 17 days, reducing both chemical consumption and operational frequency. Additional key findings include: 1) the Wang Yizhong model was confirmed to have high engineering applicability for predicting foam liquid-carrying capacity, outperforming the Turner and Li Min models; 2) the SP-7 foaming agent exhibited better foaming and liquid-carrying performance under low-salinity conditions; and 3) concentration of the foaming agent, gas flow rate, and wellbore temperature were identified as key factors significantly influencing the efficacy of SP-7.DiscussionThis research addresses the core problem of crude dosing parameter design in traditional FAL technology by integrating a segmented liquid loading calculation model and a targeted parameter optimization system. The confirmation of the Wang Yizhong model’s applicability provides a reliable theoretical tool for foam liquid-carrying prediction, while the insights into SP-7’s performance under different conditions offer practical guidance for foaming agent selection in field operations. Overall, this study establishes a technical foundation for efficient, cost-effective foam drainage in liquid-loading gas wells, particularly those in mid-to-late-stage gas fields like the Liaohe Oilfield, and provides a reference for solving similar liquid loading challenges in other gas-producing regions.