## 1 Introduction  
Carbonate reservoirs are an important part of worldwide oil and gas resources. This type of reservoir usually has strong heterogeneity [1; 2; 3], with a complex pore structure and well-developed natural fractures. During reservoir development [4; 5; 6; 7], the fluid undergoes phase change and degassing when the formation pressure is lower than the bubble point pressure of crude oil. This leads to the subsequent waterflooding displacement under oil and gas two-phase condition, also followed by a secondary phase change of oil and gas caused by the increasing of formation pressure [8; 9; 10]. Understanding the oil and gas migration mechanism and how the flow behavior of water drives the phase change of oil and gas is important for waterflooding, especially for achieving economic and efficient development of volatile carbonate reservoirs. [PERSON] applied the two-dimensional etched glass micropore model, through visualization technology, to study the characteristics of the gas-liquid phase change in condensate gas on a micro level [11]. As the pressure decreased, the anti-condensate liquid first appeared in the small pores and the tip of the blind pore, then gradually filled the larger pores. When the pressure dropped to the maximum anti-condensate pressure of the condensate gas, the evaporation of the anti-condensate liquid in the pores was reduced. It reflected the role of porous media adsorption and capillary aggregation. [PERSON] carried out physical simulation experiments by using two capillary models (lipophilic and hydrophilic) and a planar glass bead porous media-filling model to study the mechanism of gas-liquid seepage accompanied by phase change [12]. It is found that the pipe radius and seepage velocity have an influence on the oil-gas ratio during gas-liquid seepage accompanied by the phase change under low-pressure conditions. If the capillary radius grows longer and the seepage velocity increases, the gas-liquid ratio will be raised, but the absolute pressure reduction will be small. It is found that the suitable water injection time is when the formation pressure is reduced to more than 87% of the bubble point pressure. [PERSON] demonstrated capillary interactions between flowing bubbles and previously captured oil phases (three-phase ganglion dynamics) by using an etched glass microfluidic pore network model and a micro-core oil-flooding device, integrated with microcomputer tomography (CT) imaging equipment [13]. It enabled some of the crude oil to be mobilized and significantly improved oil recovery [14; 15]. Based on the pore network experiment of the sandfill core and the simulation parameters measured by the experiment, [PERSON] used the gas-water seepage model to predict the relative permeability and capillary force of the gas-water phase under different temperature and pressure conditions [16]. The size of filling sand particles, injection pressure and temperature had different effects on the gas-liquid seepage characteristics at different stages. [PERSON] carried out experiments on the properties of crude oil PVT and core displacement [17; 18], based on characteristics of crude oil phase and reservoirs. They discovered the influence of crude oil phase transition on the seepage characteristics and development effects of reservoirs with different fracturing degrees, and suggested that water injection should be appropriately started as soon as possible when developing weak volatile carbonate reservoirs [19]. [PERSON] studied the law of near-critical fluid phase transition and the law of physical property change through conventional fluid PVT experiments and reservoir production dynamic analysis [20]. It was found that the near-critical fluid while developing volatile reservoirs is in an unbalanced phase transition system. A degassing lag effect occurred in the production process.