Prediction of Liquid Loading in Changning Shale Gas Well

Addressing the technical challenge of fluid accumulation in Changning shale gas wellbores, we employed the Beggs Brill model to establish a tubing pressure drop calculation model. By integrating this model with the calculation model for annular static gas column pressure and fitting the casing pressure and bottom hole flow pressure production data, we derived a comprehensive calculation model for determining the depth of fluid accumulation in both the tubing and annulus. The accuracy of the model was validated through on-site assessments involving flow pressure, static pressure, and liquid accumulation depth testing. Utilizing Java language and a web development framework, we developed a wellbore fluid accumulation prediction software. This software enables production performance analysis and prediction of wellbore fluid accumulation, providing essential technical support for accurately forecasting fluid accumulation in Changning shale gas wells. 1. INTRODUCTION During the middle and later stages of exploitation, the decline in gas production from Changning shale gas wells can be attributed to insufficient formation energy. Inadequate liquid carrying capacity in the production of gas wells during these stages is a consequence of the backflow of fracturing fluid retained from the early stages, leading to a susceptibility to wellbore fluid accumulation. [1-3] Consequently, predicting wellbore fluid accumulation becomes paramount for ensuring the stability of the shale gas well production process. To address this, scholars have extensively researched methods for predicting wellbore fluid accumulation. Classic empirical calculation models, such as those proposed by Duns-Ros, Hagedorn-Brown, Orkiszewski, and Beggs-Brill et al., [4-7] are based on a wealth of experimental data and empirical formulas. In a later stage, Hasan et al.[8] introduced a new expression for liquid holdup grounded in the drift flow model. However, the empirical coefficients of traditional models have poor calculation accuracy in the Changning block, these models have limitations when applied to the conditions of calculating wellbore fluid accumulation in Changning shale gas wells, making it challenging to accurately predict the characteristics of wellbore fluid accumulation.[9] To tackle the challenge of accurately predicting fluid accumulation, a novel pressure drop calculation model for gas-liquid two-phase flow in the Changning shale gas wellbore was developed. The accuracy of the model was validated through on-site assessments involving flow pressure, static pressure, and liquid accumulation depth testing. Additionally, corresponding software for predicting wellbore fluid accumulation was created, ensuring an accurate forecast of fluid accumulation in the wellbore.