Since the structure of horizontal gas wells is more intricate than that of vertical wells, there is a lack of consistency in the form of liquid-carrying in different portions. Applying the commonly utilized liquid-carrying hypothesis of vertical gas wells into horizontal gas wells is therefore challenging. The maximum liquid volume that the gas flow could raise, the gas flow rate, and the maximum amount of energy that could be produced from a specific amount of gas flow should all be considered when determining the liquid volume that the gas flow could lift. This study is the first to integrate theoretical analysis with laboratory testing to analyze the gas–liquid flow law of drainage stability at varied tubing depths. The impact of gas drainage stability is then verified through the laboratory experiments. The novel model of various tubing depths, which is based on the energy of inflow and outflow from the horizontal well, is cleverly built. According to the study, the fluctuation is typically less when the tubing reaches the heel of the horizontal section than it is in the other sections, and the relative error of the new model, which is validated using laboratory tests, is typically less than 10%. The research showed that for horizontal gas wells with a normal structure, the gas flow and liquid discharge are most stable when the tubing reaches the heel of the horizontal section. Instead of depending exclusively on crucial liquid-carrying gas flow rates, the new model uses the combination of gas and liquid flow rates to make decisions concerning liquid loading and to quantify the liquid removal in real time, which is more realistic. The research illustrates how the study could provide a factual basis for assessing the capacity of horizontal gas wells to raise the liquid.

In the pipeline system for liquid carrying particle, local erosion wear broken has become the main damage mechanism of pipe in the fracturing operations of oil-gas engineering as a large number of particles continually impact on the inner surface of pipes. Computational Fluid Dynamics simulation was performed to determine the evolutionary process of erosion wear in tubing connector, which was the weakness of pipeline system, and a new way to predict the pipeline safety was provided. Based on the Euler method, the volume fraction of the particulate phase and interphase momentum exchange were included in the liquid flow equations due to the influence of dense particle on fluid flow, and the particle trajectory were calculated in the Lagrange frame by analyzing the forces from the interaction of liquid and particle and particles collision. With the erosion damage model, the erosion rate/depth in the connector was calculated to reconstruct the mesh model of shoulder with 5 tori. Torus 1 is closest to axis while torus 5 is on the outmost wall of the connector. During the erosion event, greatest erosion and hence surface deformation occurs on tori 1 and 2, and this affects the surrounding flow and particle movement. After 10 h, there was a dramatic drop in the maximum erosion rate, which illustrated a conservative prediction for pipeline service life if the initial erosion rate was used. A physical erosion experiment was also performed to identify the weight loss and erosion characteristic of the inner surface with erosion time of 55 h. It was observed that the erosion simulations provided relative errors within 18% for erosion length and weight loss compared to the experimental values and a valid simulation method for the erosion evolution was proposed to predict the erosion life of tubing connector.

Accurate multiphase flow measurement in horizontal wells is fundamentally challenged by the antagonistic electrical responses of water and gas: Electrical Resistance Tomography (ERT) loses sensitivity to thin liquid films, while Electrical Capacitance Tomography (ECT) suffers signal saturation in conductive water, preventing either modality from covering the full operating envelope alone. This study proposes a physics-guided hybrid modeling framework that integrates multi-modal ERT/ECT sensing to achieve high-precision flowrate inversion. The framework utilizes a corrected multi-modal fusion algorithm, achieving a liquid holdup MAPE of 2.5 ± 0.5% representing a nearly two-fold improvement over the best single-modality system (Direct ERT, 4.5%). For velocity estimation, an optimized cross-correlation method yields results with ± 3.0% error, incorporating multi-sensor and multi-sequence fusion. A key finding is that deep neural networks exhibit Architectural Phase Specialization: multi-branch architectures (MB-DNN) perform strongly on localized, heterogeneous liquid structures (2.0% liquid error), whereas fully-connected architectures (FC-DNN) excel at capturing the global patterns of the continuous gas core (1.2% gas error). By hybridizing a calibrated drift-flux physical model with these phase-specialized DNNs, the framework achieves overall averaged errors of 1.8% for gas and 1.5% for liquid across the full experimental envelope. The proposed framework was evaluated on 444,313 experimental samples and subsequently validated in a three-month industrial trial at the Puguang gas field under extreme conditions (26 MPa, 80 °C), where it maintained a prediction error of ± 2.3%. This work establishes a scalable, physically consistent paradigm for intelligent hydrocarbon production monitoring.

As the structure of horizontal gas wells is more complicated than that of vertical wells, the form of the liquid-carrying in different sections does not well agree. This makes it problematic to apply the widely used liquid-carrying theory of vertical gas wells in horizontal gas wells. Since the theory focused on the critical gas flow rate, it cannot quantify how much liquid it can remove. Simultaneously, it ignores the fact that the liquid-carrying ability of gas flow is limited and the producing liquid has a certain amount of flowing energy. In this study, the gas-liquid flow law of horizontal gas wells and wellhead drainage stability in different tubing depths were firstly studied. Then, the stability of gas drainage for different tubing depths was analyzed and confirmed. Given the disadvantages of the typical theory of critical gas flow, the mathematical model of different tubing depths for gas drainage is established for horizontal gas wells. The innovative model could take the energy of gas flow and liquid flow into account, and quantify the liquid volume which was removed. By verifying the model with the experiments, the result showed that the relative error of the model is generally less than 10%. It shows the research could provide a scientific basis for the analysis and liquid-carrying capacity for horizontal gas wells.