Carbon Capture, Utilization, and Storage（CCUS） technology is pivotal for global carbon emissions reduction and plays a crucial role in ensuring China's energy security and fostering the concurrent growth of its economy. It also supports China's path towards sustainable development and ecological advancement. While significant strides have been made in CCUS technology within China, challenges persist that hinder its widespread adoption. Based on literature research and work accumulation, the current status of CCUS technology both domestically and internationally is described, and the current technical challenges and research directions that CCUS technology are pointed out. The existing research efforts have provided countermeasures to address the challenges of high energy consumption and cost of capture technologies, the need for further research on oil recovery and storage technologies, the high energy consumption and low conversion efficiency of chemical utilization technologies, and the lack of a technical system for monitoring and evaluating the safety of storage. These countermeasures are as follows: ①Diversified integration of different carbon capture methods to achieve cost reduction at the source based on the characteristics of different emission sources; ②Tackling multi-objective optimization techniques, coordinating and optimizing oil recovery efficiency and CO₂ storage rate; ③Continuously developing new catalysts to accelerate the conversion reaction of CO₂ and improve conversion efficiency; ④Fully draw on the carbon tax policies of countries such as the United States and Australia, explore fiscal and tax incentive policies suitable for China's CCUS industry, increase economic benefits, and enhance enterprise enthusiasm; ⑤Establish a series of standard specifications covering all aspects of the CCUS entire chain, guide the implementation of engineering construction, and reduce enterprise risks from a standardized perspective. Through the implementation of these measures, the rapid development of CCUS technology in China will be promoted, and greater contribution will be made to achieving the goal of carbon neutrality.

CCUS technology is a crucial technology for achieving the goal of “dual carbon”, involving process such as capture, transportation, injection, extraction and re-injection. Shengli Oilfield has developed essential engineering technologies for transportation and injection through years of exploration. To manage the phase changes of CO₂ and the risks of long-distance leakage due to pressure loss and temperature variations, a safety transportation technology for long-distance CO₂ pipelines was established. This technology is based on phase state control, ensuring efficient and cost-effective transportation. developed China’s first casing pipeline transport pump; and built China’s longest long-distance supercritical pressure CO₂ pipeline, which makes up for the shortcomings of the long-distance CO₂ transport in China. In order to meet the needs of high-pressure injection of large-displacement CO₂ in the demonstration project, China’s first high-pressure dense-phase injection pump has been developed, realizing high-pressure dense-phase injection of 40 MPa. In view of the problems of high injection pressure, high gas-to-liquid ratio, low pumping efficiency, and corrosion of CO₂, the engineering process technology of injection and extraction supporting such as safe injection of gas pipeline columns for pressure-free wells, multi-functional oil recovery pipeline columns, and corrosion prevention of CO₂ repulsion has been formed to realize high-efficiency, safe injection and extraction and long-lasting corrosion protection. China's first multi-field, multi-node, one-million-ton CCUS demonstration project integrating pipeline transport engineering, injection equipment, flooding and sequestration, injection-extraction process, and gathering-transmission and re-injection, has been operating well and realizing “smooth, safe, efficient and green” operation in all aspects. This summary of the one-million-ton CCUS transportation-injection-extraction process and supporting equipment in Shengli Oilfield is intended to provide reference and guidance for the construction of subsequent CCUS project.

CCUS（Carbon capture, Utilization and Storage） technology is of great significance to the green and low-carbon transformation and the realization of the “dual carbon” goal, It includes important strategies like CO₂ enhanced oil recovery（EOR） and sequestration. Jiangsu Oilfield has been focusing on CO₂ EOR to improve recovery rates in the challenging fault block reservoirs of the Subei Basin. The company has developed four unique CO₂ EOR models suitable for these complex reservoirs, featuring techniques like gravity-stable displacement. A notable achievement is the successful pilot of the methods such as “simulated horizontal well” GAGD technology in Hua-26 fault block, which led to the one hundred thousand CCUS project tailored for such reservoirs. According to statistics, Jiangsu Oilfield has injected a total of 30.34×10⁴ t of liquid CO₂, with a cumulative oil increase of 9.83×10⁴ t, realizing a better production increase and economic benefits. These technical researches and tests can provide valuable insights for applying CO₂ EOR in similar complex reservoirs.

Numerous oil displacing mechanisms of CO₂ have been widely recognized, but due to reservoir factors, the effectiveness of CO₂ flooding varies significantly under different reservoir conditions. It is necessary to further deepen the research on the micro-interaction mechanisms between CO₂ and crude oil, clarify the CO₂ flooding mode under different reservoir conditions, and maximize the potential of CO₂ flooding. Molecular dynamics simulation methods have been used to study the effects of components, temperature, and pressure on the interaction between oil droplets and CO₂. The kinetic parameters were obtained to quantitatively characterize the oil droplets-CO₂ interaction, clarifying the micro-interaction patterns under different conditions. The simulation results show that the dispersion force is the the main driving force of the interaction between CO₂ and alkane molecules, which mainly includes two aspects: one is the dissolution and diffusion of CO₂ molecules into the oil droplets by overcoming the steric hindrance between alkane molecules, and the other is the extraction attraction of CO₂ molecules to the outer layer molecules of the oil droplets. As the chain length of alkane molecules decreases, the temperature decreases and the pressure increases, the solubility parameter of the oil droplets and the coordination number of CO₂ increase, the curvature of the molecules in the outer layer of the oil droplets decreases, and the interaction between the two is enhanced. It is concluded that CO₂ miscible and near-miscible flooding should be realised as much as possible in light and medium-light reservoirs with lower temperatures and higher pressures, while in medium and heavy reservoirs with higher temperatures and lower pressures, the advantages of CO₂ non-miscible flooding in terms of dissolution viscosity reduction, crude oil volume expansion and energy replenishment should be fully exploited. The study results can provide theoretical guidance for laboratorial research and field application of CO₂ flooding.

CO₂ solubility in saline aquifer is an important parameter for estimating the volume of CO₂ that can be dissolved and stored underground. To rapidly and economically evaluate and analyze the solubility of CO₂ in saline aquifers, a study was conducted using grey GM（1,1） modeling based on existing data of CO₂ solubility in water under various temperatures, pressures, and salinities. By using Markov theory, the state interval was divided, the state transition probability matrix was constructed, and the prediction results were revised. A prediction model of CO₂ solubility in saline aquifer based on grey Markov theory was proposed. The results showed that the average relative errors between the predicted values of the grey Markov theory and the measured values were 1.52%、17.73%、0.21% and 3.97%, respectively. The average relative errors between the prediction results of the gray GM（1,1） model were 2.37%、19.29%、3.62% and 3.94%, respectively. The predicted values of the grey Markov model were more consistent with the measured data, and the prediction performance of the model was better, so as to provide a new method for predicting the solubility of CO₂ in underground salt water.

The pore utilization characteristics of CO₂ during shale oil displacement are a crucial indicator for evaluating its effectiveness in enhancing shale oil reservoir recovery rates. Therefore, experiments on supercritical CO₂ displacing shale cores were conducted in the laboratory, and nuclear magnetic resonance（NMR） online core scanning technology was used to study the pore utilization characteristics and patterns of CO₂ displacement in shale oil reservoirs. The results indicate that immiscible flooding by supercritical CO₂ mainly develops the oil in shale pores with radius of 0.1~3.0 μm, but the oil content in pore radius less than 0.008 μm actually increases. The analysis shows that CO₂ brings shale oil from large pores into small pores through pressure difference and diffusion effect in the shale layer and makes oil undergo adsorption and retention. After a displacement time of five hours, the recovery rate of shale oil by CO₂ displacement reached 35.7%, indicating a relatively effective oil displacement result.

In the development of water-flooded oil fields entering the high water-cut stage, the remaining oil often accumulates at the top of structural high positions or thick oil layers, areas not effectively covered by the existing well network. Utilizing the intrinsic characteristics of the reservoir to inject CO₂ and form a gas cap drive can effectively improve development outcomes and achieve CO₂ sequestration. However, the suitability of specific reservoirs for gas cap drive development requires further study. This study delves into the effectiveness of CO₂ gas cap drive in high water-cut reservoirs by examining the movement of the oil-gas interface during the gas cap drive process, using both numerical and physical simulations. Key evaluation metrics include enhanced oil recovery rate, oil displacement efficiency, time to reach the critical gas-oil ratio, and gas retention rate. The research assesses how various reservoir characteristics, such as formation dip angle, crude oil density, viscosity, reservoir confinement, permeability, and the strength of water drive, influence the efficiency of CO₂ gas cap drive for both oil displacement and sequestration. Focusing on these main evaluation criteria, the study identifies that the suitability of CO₂ gas cap drive in reservoirs during the high water-cut phase is significantly influenced by factors such as reservoir confinement, formation dip angle, crude oil viscosity, permeability, and reservoir thickness. These findings aim to provide a foundation for broadening the application of CO₂ flooding techniques. crude oil viscosity, reservoir permeability, and thickness, to provide a basis for expanding the application range of CO₂ flooding.

Addressing issues such as poor water injection capacity, substandard water quality and wax deposition of high pour point crude oil in low permeability reservoirs of Shuanghe Oilfield in Henan, an independently designed water-CO₂ reservoir injection capability evaluation device was utilized to conduct flowability experiments and CO₂ displacement tests. Combined with core scanning electron microscopy and other testing methods, the main mechanism of poor water injection capacity of Shuanghe low permeability reservoirs was clarified, and the main mechanism of CO₂ improving the injection capacity of low permeability reservoirs was explored. The results show that the deposition of suspended particles in the produced water and wax crystals in the oil can lead to pore blockage, thereby reducing the water injection capacity of the reservoir. CO₂ has a significant dissolving effect on inorganic suspended particles in produced water and on alkaline minerals and carbonate minerals in rocks, which is the main mechanism for significantly enhancing the reservoir's water injection capacity. CO₂ can dissolve paraffin deposits on the rock surface, effectively improving the reservoir's water injection capability. At the same time, the effect of CO₂ flooding is obvious, the recovery rate is increased by 13.01% ~ 21.51%, and the subsequent water flooding is further increased by 5.40% ~ 6.04%. This study shows that CO₂ injection can significantly improve the injection capacity of low permeability reservoirs in Shuanghe Oilfield, and provides theoretical support for the field application of CO₂ injection and oil displacement technology.

Under the background of “carbon peak and carbon neutrality”, traditional chemical enterprises are encountering challenges due to CO₂ emission limitations. CCUS（Carbon Capture, Utilization and Storage） technology emerges as a crucial strategy for addressing CO₂ emissions. To mitigate emissions at the source, chemical companies are turning to CO₂ flue gas capture and recovery technologies, while also exploring ways to integrate these efforts into a cost-effective CCUS industrial chain. To overcome the drawbacks of traditional CO₂ flue gas recovery units, such as large land use, high construction costs, inflexibility, and lengthy construction times, the modular skid-mounted CO₂ recovery technology has been introduced. This innovative approach minimizes upfront investment and accelerates project timelines by modularizing the recovery process, allowing for 100% factory prefabrication and streamlined on-site assembly. The skid-mounted design efficiently organizes pipelines and valves, integrating equipment within each module onto skids, resulting in a fully modular skid-mounted CO₂ recovery unit. Field applications demonstrate significant advantages of the modular skid-mounted approach over conventional methods. For example, a 5×10⁴ tons per year coal-to-hydrogen CO₂ flue gas recovery unit saw a 74.0% reduction in construction costs, a 75.2% decrease in required space, and a 50.0% shorter construction timeline, effectively meeting the objectives of cost reduction and expedited project completion.

The global consensus on achieving carbon neutrality is driven by the urgent need to address climate change caused by excessive CO₂ emissions. Carbon Capture, Utilization, and Storage（CCUS） stands out as a critical solution, receiving significant attention from the researchers. Sinopec Nanjing Research Institute of Chemical Industry Co., Ltd. has been committed to the research and development and application of CO₂ capture and utilization technology for a long time. The institute has perfected three advanced carbon capture methods: low partial pressure flue gas carbon capture technology, NCMA（Nanjing chemical mixed amine） decarburization technology and catalytic hot potassium alkali decarburization technology, which have been successfully applied in many industrial projects. Furthermore, the institute is pushing boundaries in new carbon capture and CO₂ utilization technologies, achieving notable advancements that align with both domestic and international standards.

Addressing the challenges of moderate to strong velocity sensitivity damage and strong to extremely strong water sensitivity damage in the medium and deep heavy oil reservoirs of Xinjiang oilfields, which lead to suboptimal waterflooding outcomes, a study was conducted leveraging the unique physical and chemical properties of CO₂. Utilizing high-temperature, high-pressure PVT apparatus and long core displacement equipment, the feasibility of enhancing oil recovery through CO₂ flooding/huff and puff was explored by determining the high-pressure physical properties of CO₂-crude oil and analyzing the composition and viscosity changes of the produced oil with gas chromatography and high-temperature, high-pressure rheometry. The experimental results show that 57.345% mole fraction of CO₂ can increase the dissolved gas-oil ratio（GOR） from 32 m³/m³ to 149.3 m³/m³, the bubble point pressure（p_b） from 6.8 MPa to 15.7 MPa, the volume coefficient of crude oil from 1.06 to 1.27, the density of crude oil from 0.896 5 g/cm³ to 0.854 8 g/cm³, and the viscosity of crude oil from 419.3 mPa·s to 253.4 mPa·s. Therefore, CO₂ can effectively supplement the formation energy, increase the elastic energy of crude oil and reduce the seepage resistance. The first round of 0.95 PV（pore volume） CO₂ flooding has a crude oil recovery of 32.8%, and the fluid in the porous medium is redistributed after 24 hours of shut-in. The second round of 0.5 PV CO₂ flooding can increase the crude oil recovery by 17.9%. The crude oil recovery of five rounds of CO₂ huff and puff is 63.5%. The viscosity of the produced oil tends to decrease, mainly due to the deposition of asphaltenes in crude oil in porous media. The experimental results have confirmed the feasibility of CO₂ flooding/huff and puff in the recovery of heavy oil in the middle and deep layers of Xinjiang Oilfield.

The shale oil of Lucaogou Formation in Jimsar Sag has the characteristics of extremely low original permeability and high viscosity of crude oil, making it uneconomical to produce under natural conditions. Field practices have demonstrated that dense drilling combined with high-intensity volume fracturing is one of the most effective means to achieve large-scale development of shale oil. However, how to slow down the decline rate of oil wells and improve the recovery rate per well remains a pressing issue to be addressed. From 2019 to 2022, the researches and field tests of CO₂ pre-fracturing assisted production technology were carried out in Jimsar shale oil block. The application effect of CO₂ pre-storage fracturing and CO₂ huff and puff in Jimsar shale oil block was systematically studied and analyzed. The results indicate that supercritical CO₂ has the effects of miscible energy increase, dissolution to improve reservoir conditions, improve imbibition replacement efficiency, and increase the complexity of fracture network. The optimal injection volume, injection speed, and injection methods were determined, and a preliminary technological system for CO₂ pre-fracturing in shale oil reservoirs was established. According to the prediction of production data, the CO₂ pre-fracturing process can increase the final recovery rate by about 20%, which provides a reference for realizing the benefit development of shale oil and improving the development effect of other types of shale reservoirs.

CO₂ flooding and sequestration technology can significantly improve crude oil recovery rates while enge. However, the oil displaceabling large-scale CO₂ flooding and sequestration process is accompanied by various CO₂ leakage risks. In response to the lack of previous CO₂ leakage risk management systems, especially the absence of systems based on online monitoring that support dynamic risk management, research has been conducted on the construction of a CO₂ flooding and sequestration leakage risk management system. Based on the construction of CO₂ flooding and storage leakage risk management system, a dynamic CO₂ leakage risk management system integrating multi-environment real-time risk identification and assessment, multi-space risk prediction, multi-level risk early warning and whole process risk control was developed and applied to the CO₂ flooding and storage demonstration project of Yanchang Petroleum in Ordos Basin. Case studies demonstrate that the developed CO₂ leakage risk management system can dynamically identify various leakage risks throughout the CO₂ flooding and sequestration process across all spaces, effectively supporting the dynamic management of leakage risks. This provides comprehensive and timely safety assurance for CO₂ flooding and sequestration projects, ensuring that potential risks are managed and mitigated effectively to maintain the integrity and success of these projects.

The BZ19-6 condensate gas field, characterized by large reserves, small surface pressure differential, high temperature and pressure reservoir conditions, and low porosity and permeability, is highly susceptible to retrograde condensation contamination during production operations. Evaluating the degree of retrograde condensation contamination and adopting appropriate contamination remediation measures are crucial for improving the situation in the BZ19-6 condensate gas field. The long core failure experiment was carried out using the mixed condensate gas to simulate the reverse condensate pollution, test the gas permeability corresponding to different exhaustion pressure points and evaluate the degree of reverse condensate pollution. Additionally, experiments on remediation of retrograde condensation contamination were carried out using three different approaches: injection of surfactant（TC281）, injection of methanol, and injection of a combination of methanol and surfactant. Furthermore, an experiment was conducted using a combination of methanol and surfactant to address both retrograde condensation and water blockage, a comprehensive liquid phase contamination. The experimental results indicate that all three schemes of injecting active agent（TC281）, injecting methanol and injecting methanol + active agent have certain effects on removing retrograde condensation pollution. The group of injecting methanol + active agent 1 has the best effect on removing retrograde condensation and removing retrograde condensation pollution, and the permeability recovery rate is 84%. The permeability recovery rate of methanol injection to remove retrograde condensation pollution is 81%. The recovery rate of retrograde condensate permeability in the surfactant injection group 1 was 54%. The injection of methanol + active agent 1 relieved the comprehensive liquid phase pollution of reverse condensation + water lock, and the permeability recovery rate reached 80%. These experiments provide guidance for remediation strategies to address retrograde condensation contamination in the BZ19-6 condensate gas field.

Dainan Formation in Majiazui Oilfield is characterized by developed fractures and is primarily composed of structural-lithologic reservoirs. The reservoirs exhibit thin vertical thickness and rapid lateral distribution changes, demanding high precision in reservoir prediction, which conventional seismic inversion methods struggle to meet. To address this challenge, the waveform indication simulation method was employed for thin reservoir prediction in the study area. This method, guided by waveform coherency, uses changes in seismic waveforms laterally instead of variogram functions to simulate target parameters, yielding high-precision inversion results that better conform to sedimentary and geological laws. Taking advantage of the dense and numerous development wells in the study area, and integrating geological, seismic, and well logging data, the spontaneous potential curve, which is sensitive to the reservoir, was selected for waveform indication simulation. This approach was used to predict the distribution of the main oil-bearing sand groups. The inversion results were analyzed in conjunction with the computation wells, check wells, and cross-fault wells, indicating that the waveform indication simulation has high vertical and lateral resolution. It can finely reflect the spatial variation of the reservoir. The main oil-bearing sand group's planar distribution was extracted and found to be consistent with the sedimentary patterns of the study area. Combined with the oil layer distribution map, the target oil-bearing sand group's distribution was re-evaluated, suggesting potential for rolling extension to the west beneath the Ma3 fault. This insight could guide further exploration and development strategies in the Majiazui Oilfield.

The interlayer and intralayer interference, which is commonly existing in the process of oilfield development, especially for the offshore strongly heterogeneous huge thick sandstone and conglomerate reservoirs that are not completely separated vertically, is the basis and internal cause of reservoir subdivision. In practice, interference data are primarily obtained from production logging, which shows that the interference coefficient changes with the development stage and over time. Since production logging is typically a point test, it does not capture the full cycle interference coefficient, highlighting the need for laboratory studies on interlayer and intralayer interference. The theoretical study of interference coefficient involves numerous parameters and the interference coefficient changes with time. This theory can explain the phenomenon that the overall oil production capacity of multi-layer combined production wells is lower than the cumulative amount of multi-layer production, but it fails to solve the theoretical root cause of its formation. So a one-dimensional core displacement experimental device was used for the study of the interlayer and intralayer interference. The experiment shows that for the interlayer interference, the interference coefficient gradually increases with time as water cut rises, but decreases in high water cut period. This is due to the difference in the displacement pressure gradient of each core during single flooding and combined flooding. While for the intralayer interference, the interference coefficient of oil production index is large in the early stage, and gradually decreases with the increase of water cut. The essence of the interference is that the change of seepage resistance of different reservoirs with time results in the change of reservoir flow distribution.

Facing the challenges of extremely high water cut, developed preferential channels, highly dispersed remaining oil, and strong heterogeneity in nearly abandoned reservoirs, the study focuses on the 4-5 layer series of the North Block II（Oil Group No. 2） in the Shuanghe Oilfield. By employing detailed reservoir geological modeling, numerical simulation methods, and microscopic displacement experiments, the distribution characteristics of remaining oil after polymer flooding were characterized. Post-polymer flooding, the remaining oil saturation is higher in areas away from the main streamlines on the macro scale, including non-mainstream areas, weak zones along main streamlines, and peripheral areas with larger injector-producer distances. Vertically, remaining oil tends to accumulate at the top of positive rhythm sequences. Microscopically, the remaining oil is primarily in the form of semi-bound state. Based on the characteristics of remaining oil distribution, a technical concept of heterogeneous composite driving and streamline well pattern densification adjustment was proposed. By adjusting the well pattern to alter streamlines, creating a staggered row and column well pattern with a change in streamline direction of over 30° and a streamline deflection rate of 80%, the effective mobilization of remaining oil is promoted. Numerical simulation predicts that this technique could increase the recovery factor by 10.96%, add 706.1 thousand tons of recoverable reserves, and extend the life cycle by 15 years. This offers a new technical approach for significantly enhancing the recovery factor of reservoirs after polymer flooding.

The single-tubing layered testing and adjustment injection process for offshore oilfields cannot meet the conditions of wells with inclinations greater than 60°. At the same time, steel wire operation is required during logging, and a single well takes six hours on average. The logging efficiency is low, and it cannot truly achieve the real-time monitoring of downhole temperature, pressure, flow rate, and injection volume adjustment. On the basis of introducing the principle, applicability, and characteristics of intelligent polymer injection technology with cable control in offshore oil fields, key supporting tools such as cable control intelligent polymer injection pipe, high viscosity maintaining channel under large flow rate, and ground controller have been developed. Experiments have shown that the pipe has better performance with a differential throttle pressure of less than 4 MPa and a viscosity retention rate of more than 85%. Field applications demonstrated that the cable-controlled smart polymer injection technology can provide real-time feedback on flow rate, pressure, temperature, and other monitoring data during the layered polymer injection debugging process in high-inclination wells. This improves the efficiency of polymer injection well testing and adjustment and the standardization rate of reservoir allocation, offering effective technical support for enhancing the recovery factor in offshore oilfield polymer flooding operations.

The gas-water relative permeability curve reflects the comprehensive physical properties of the reservoir. Clarifying the relationship between the gas-water relative permeability behavior of tight sandstone and the production performance of gas wells is conducive to the efficient development of tight gas reservoirs. Taking the typical tight sandstone gas reservoirs in the eastern margin of Ordos Basin as the research object, the reservoirs are divided into three types and gas-water relative permeability experiments are carried out. Combined with core analysis methods such as X-ray diffraction, scanning electron microscopy and nuclear magnetic resonance, the relationship between gas-water relative permeability and gas well production performance curve is revealed. The results show that: ① The two-phase transition zone of relative permeability curve I is wide, the pore type of which is mainly intergranular pores. The two-phase transition zone of relative permeability curve Ⅱ is narrow, the pore types of which are mainly intergranular pores and intergranular pores. The two-phase transition zone of relative permeability curve Ⅲ is extremely narrow, and the pore type is mainly dominated by intergranular pores; ② The clay mineral content is high. kaolinite and chlorite are conducive to gas-water phase flow. Illite is not conducive to gas-water phase flow; ③ The pore and throat of in the reservoir have large differences and can be roughly divided into three categories: large pores（greater than 1.0 μm）, mesopores（0.1~1.0 μm） and small pores（less than 0.1 μm）. The large pores in the reservoir of class I, Ⅱ and Ⅲ account for about 40%, 10%, and 4%, respectively; ④ The gas wells can be divided into three types, the production performance of which are consistent with the predicted results of the relative permeability curves. The main production layer of the well of class I responds to the reservoir of class I. The effective layer thickness is about 7 m. The average daily production is about 2×10⁴ m³ with a long stable production period. The main production layer of the well of class Ⅱ responds to the reservoir of class Ⅱ. The effective layer thickness is about 5 m. The average daily production is about 1×10⁴ m³. The main production layer of the well of class Ⅲ responds to the reservoir of class Ⅲ. The effective layer thickness is about 6 m. The average daily production is about 0.5×10⁴ m³ with a very short stable production period. By analyzing the gas-water relative permeability characteristics to predict gas well production dynamics, the impact of pore structure and clay minerals on gas-water flow behavior is revealed. This can provide theoretical support for developing measures to reduce resistance and enhance efficiency in the development process of low-pressure, high-water-content tight gas fields.

Liquid loading in gas wells is an important challenge during the middle and later stages of exploitation of large inclined wells in Sulige Block. Current critical liquid carrying models suitable for directional wells are limited and often overlook the effects of tubing diameter, liquid flow velocity, and angle. Utilizing multiphase pipe flow experiments, the liquid carrying mechanism in directional wells was studied, analyzing the effects of tubing diameter, angle, and liquid flow velocity on liquid accumulation in gas wells. Based on the liquid film reversal mechanism, the calculation method of parameters C and m in the WALLIS model was derived using experimental data on the basis of the BELFROID model and WALLIS model. A new critical liquid-carrying model has been established by considering the factors such as pipe diameter, gas density, liquid density, angle, apparent liquid flow rate, and gravitational acceleration. The results of the new model for predicting 62 gas wells with liquid loading in VEEKEN’s literature show an accuracy of 91.94%. The establishment of this new model not only further refines the theory of liquid film reversal but also provides theoretical support for predicting liquid loading events in directional wells, offering a valuable tool for optimizing gas production and mitigating liquid loading issues.