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Pores, fractures, caves, and other storage spaces are commonly distributed in fractured-vuggy carbonate reservoirs. During the drilling process, more than half of all drill-in fluid loss issues are caused by developed caves. Cave scales range from centimeters to meters, making leak prevention increasingly difficult through the use of traditional technologies. Currently, there is still high demand for the understanding of feasible loss control techniques, especially in fractured-vuggy carbonate reservoirs. Multistage Bridge Plugging (MBP) technology has facilitated pioneering experiments in many oilfields, but the success rate of plugging is less than 50%, and the effects of plugging are uncontrollable and difficult to predict. This is due to a lack of clarity regarding the plugging mechanism and the key controlling factors. In this study, we used the Discrete Element Method (DEM) simulation method to investigate the controlling factors of MBP technology, and analyzed its applicable conditions. We found that the prerequisite for the success of MBP is the presence of a constricted throat near the wellbore when drilling the well hole; the first-stage bridging ball is the key to the success of MBP. Larger ball radius, cave inclination and initial flow rate, and lower ball velocity are beneficial to the first-stage bridging. All discussion in this research is based on the ideal situation. However, the cave pattern is difficult to describe using several models, let alone by one ideal model. With the progress of seismic fine description technology and mud logging, more accurate characterization of caves in carbonate reservoirs will help to accurately formulate the plugging scheme and greatly improve the success rate of plugging technology. Additionally, the engineering risks of this technology, such as plugging the coiled tubing, need to be further studied. [ABSTRACT FROM AUTHOR]

Low-permeability near-critical volatile reservoirs are characterized by light oil, complex fluid phase, and strong reservoir inhomogeneity, etc. Purely injecting CO2 will create a series of problems, such as serious gas channeling, low sweep efficiency, and low oil recovery. Therefore, in this paper, through a combination of experiments and simulations and in the process of studying the problem from simple to complex, we carried out phase equilibrium experiments for CO2-near-critical volatile oil and CO2-near-critical volatile oil-formation water, as well as experiments for minimum miscible pressure of slim-tube with pure CO2 and CO2–water co-injection to the comparative study of the miscible characteristics and displacement oil efficiency between pure CO2 injection and CO2–water co-injection. It provides an important reference for improving oil recovery by CO2–water co-injection in low-permeability near-critical volatile reservoir. The results of CO2-near-critical volatile oil/CO2-near-critical volatile oil-formation water phase equilibrium experiments show that the saturation pressure, density, and gas–oil ratio of the system increase, and the viscosity decreases with the increase in CO2 injection. In the three-phase system of CO2-near-critical volatile oil-formation water, the CO2 content in the flash gas of crude oil, gas–oil ratio, and gas–water ratio are negatively correlated with the water saturation. The results of slim-tube experiments and simulations on the miscible characteristics and displacement oil efficiency of pure CO2 injection and CO2–water co-injection show that the recovery degree of crude oil under CO2–water co-injection is higher than that of pure CO2 injection, and the CO2 dissolved transition section in oil and gas is shorter and the gas breakthrough time is later under CO2–water co-injection, which effectively increases the sweep efficiency and improves the degree recovery of crude oil. When CO2–water co-injection, the ratio of water is higher, the later the gas–oil ratio rises, the later the CO2 breakthrough, and the higher the degree of crude oil recovery. It indicates that when CO2–water co-injection, the ratio of water is higher, the more CO2 is dissolved in water, which effectively inhibits the occurrence of gas channeling and increases the sweep area, thus improving the degree recovery of crude oil. The research results of this paper provide an experimental basis and theoretical foundation for CO2–water co-injection for enhanced crude oil recovery in low-permeability near-critical volatile reservoirs. [ABSTRACT FROM AUTHOR]

The Neogene Guantao Formation Reservoir in the PLOilfield is a unconsolidated sandstone with high porosity and high permeability. The reservoir diagenesis is weak and dominated by compaction diagenesis. At present, insufficient research into the relationship between the pore characteristics and sedimentary microfacies of shallow delta sandstone reservoirs restricts the prediction of favorable reservoir distribution. This article takes the unconsolidated sandstone reservoir of the Guantao Formation as the research object and analyzes the potential coupling relationship between pore characteristics and sedimentary microfacies. In this study, seven typical sedimentary microfacies were identified and the microscopic characteristics of different sedimentary microfacies reservoirs are described. The results show that the pore structure of various sedimentary microfacies is comprehensively influenced by the sedimentary rock texture, siliceous minerals, and clay mineral distribution. Characterized by more abundant hard quartz and feldspar minerals, positive skewness, and lower pore sorting coefficients, the arenaceous microfacies possess larger pore throat radius and lower pore fractal dimensions than argillaceous microfacies. Finally, due to the difficulty of coring in offshore oilfields and the lack of data on mercury injection experiments, empirical formulas for the porosity, permeability, and pore throat radius of conventional core tests were established, and the pore radius that corresponded to 35% mercury saturation (r35) was used as the characteristic pore structure parameter. The grey correlation method was used to analyze the influence of sedimentary structure factors and mineral content differences on r35 and to determine the main controlling factors. [ABSTRACT FROM AUTHOR]

The abundant reserve of shale gas in Sichuan Basin has become a significant natural gas component in China. To achieve efficient development of shale gas, it is necessary to analyze the stress state, pore pressure, and reservoir mechanical properties such that an accurate geomechanical model can be established. In this paper, Six wells of Neijiang-Dazu and North Rongchang (NDNR) Block were thoroughly investigated to establish the geomechanical model for the study area. The well log analysis was performed to derive the in-situ stresses and pore pressure while the stress polygon was applied to constrain the value of the maximum horizontal principal stress. Image and caliper data, mini-frac test and laboratory rock mechanics test results were used to calibrate the geomechanical model. The model was further validated by comparing the model prediction against the actual wellbore failure observed in the field. It was found that it is associated with the strike-slip (SS) stress regime; the orientation of SHmax was inferred to be 106–130° N. The pore pressure appears to be approximately hydrostatic from the surface to 1000 m true vertical depth (TVD), but then becomes over-pressured from the Xujiahe formation. The geomechanical model can provide guidance for the subsequent drilling and completion in this area and be used to effectively avoid complex drilling events such as collapse, kick, and lost circulation (mud losses) along the entire well. Also, the in-situ stress and pore pressure database can be used to analyze wellbore stability issues as well as help design hydraulic fracturing operations. [ABSTRACT FROM AUTHOR]