新型不同气井生产管柱临界携液流量模型建立及效果分析

刘时春; 贾友亮; 白晓弘; 杨旭东; 卫亚明; 赵彬彬; 肖述琴

doi:10.3969/j.issn.1006-6535.2025.04.019

特种油气藏 >

2025 , Vol. 32 >Issue 4: 158 - 166

DOI: https://doi.org/10.3969/j.issn.1006-6535.2025.04.019

钻采工程

新型不同气井生产管柱临界携液流量模型建立及效果分析

刘时春 ,
贾友亮 ,
白晓弘 ,
杨旭东 ,
卫亚明 ,
赵彬彬 ,
肖述琴

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1.中国石油长庆油田分公司,陕西西安 710018;
2.低渗透油气田勘探开发国家工程实验室,陕西西安 710018

刘时春(1997—),男,工程师,2020年毕业于辽宁石油化工大学石油工程专业,2023年毕业于中国石油大学(华东)石油与天然气工程专业,获硕士学位,现主要从事采气工艺研究及采气工具研发工作。

收稿日期: 2024-11-05

修回日期: 2025-05-19

网络出版日期: 2025-09-03

基金资助

中国石油科学研究与技术开发项目“致密气及页岩气井连续管带压完井与采气一体化技术现场试验”(2022ZS26)

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Establishment and effect analysis of critical liquid-carrying flow rate models for new types of production tubing strings in gas wells

LIU Shichun ,
JIA Youliang ,
BAI Xiaohong ,
YANG Xudong ,
WEI Yaming ,
ZHAO Binbin ,
XIAO Shuqin

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1. PetroChina Changqing Oilfield Company, Xi′an, Shaanxi 710018, China;
2. National Engineering Laboratory for Exploration and Development of Low-Permeability Oil and Gas Fields, Xi′an, Shaanxi 710018, China

Received date: 2024-11-05

Revised date: 2025-05-19

Online published: 2025-09-03

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摘要

随着气井开发周期延长,井筒积液问题加剧,导致油田产量下降、采收率降低。为此,基于最小压降理论,针对深度为2 400~4 000 m的直井,采用Ф50.8 mm连续管与Ф60.3 mm油管2种管柱,建立以井口油压、水气比为变量的临界携液流量计算模型。研究表明:Ф50.8 mm连续管自主携液能力更强,积液程度更小,井底流压更低,日产气量更高;临界携液流量随水气比、井口油压、井深增加而增大,其中,水气比与井口油压对临界携液流量的影响程度显著高于井深的影响;当井筒流型转变为段塞流时,Ф50.8 mm连续管气相流量(7 000 m³/d)低于Ф60.3 mm油管(16 000 m³/d),后者生产时间比前者减少了70%以上。现场试验表明,相比Ф60.3 mm油管,Ф50.8 mm连续管完井效率更高,自然连续生产期延长了1.5 a,进一步验证了模型的准确性。该研究可为气井携液规律分析及排水采气措施优化提供理论依据,对提升低产气井开发效益具有重要指导意义。

关键词： 生产管柱; 最小压降理论; 临界携液; 气液两相流动; 井筒流型

本文引用格式

刘时春 , 贾友亮 , 白晓弘 , 杨旭东 , 卫亚明 , 赵彬彬 , 肖述琴 . 新型不同气井生产管柱临界携液流量模型建立及效果分析[J]. 特种油气藏, 2025 , 32(4) : 158 -166 . DOI: 10.3969/j.issn.1006-6535.2025.04.019

Abstract

As the development cycle of gas wells extends, wellbore liquid loading intensifies, leading to reduced field production and recovery. To address this issue, based on the minimum pressure drop theory, critical liquid-carrying flow rate calculation models with wellhead tubing pressure and water-gas ratio as variables were established for vertical wells with depths of 2 400-4 000 m, using two types of tubing strings: Φ50.8 mm coiled tubing and Φ60.3 mm tubing. The study shows that Φ50.8 mm coiled tubing has stronger autonomous liquid-carrying capacity, less severe liquid loading, lower bottom-hole flowing pressure, and higher daily gas production; the critical liquid-carrying flow rate increases with water-gas ratio, wellhead tubing pressure, and well depth, among which the influence of water-gas ratio and wellhead tubing pressure on the critical flow rate is significantly higher than that of well depth; when the wellbore flow pattern transitions to slug flow, the gas flow rate for Φ50.8 mm coiled tubing (7 000 m³/d) is lower than that for Φ60.3 mm tubing (16 000 m³/d), and the production time of the latter is reduced by more than 70% compared to the former. Field tests show that compared to Φ60.3 mm tubing, Φ50.8 mm coiled tubing brings higher completion efficiency, extending the natural continuous production period by 1.5 years, further verifying the accuracy of the model. This research provides a theoretical basis for analyzing gas well liquid-carrying laws and optimizing liquid drainage gas production measures, and offers important guiding significance for improving the development efficiency of low-productivity gas wells.

Key words： production tubing; minimum pressure drop theory; critical liquid-carrying; gas-liquid two-phase flow; wellbore flow pattern

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