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The lower Wuerhe formation reservoir of the 8th district is a blocky, ultra-low-permeability gravel reservoir with poor waterflooding development, and it is urgent to attack the gas injection gravity flooding. The barrier property of seepage barriers such as interlayers developed inside the reservoir is very important for the study of gas injection gravity flooding. The mineral composition, pore throat structure, and physical characteristics of the interlayer rocks were studied by X-ray diffraction (XRD) whole-rock analysis and nuclear magnetic resonance (NMR). The gas injection breakthrough pressure of the interlayer was studied by core breakthrough experiment and digital core simulation. Based on the determination of the interlayer criteria, logging was used to interpret and characterize the interlayer. The effects of different types of interlayer combinations on gas injection were studied by combining the physical model and numerical simulation methods. The results showed that the lithology of the interlayer in the lower Wuerhe formation of the 8th district was mainly mud-bearing fine gravel with microporosity, average porosity of 6.1% and permeability of 0.0043 mD. The interlayer gas injection breakthrough pressure and permeability were in a logarithmic linear relationship, and the lower limit of gas injection breakthrough under reservoir conditions was 0.003 mD. Initially, it is difficult to flood the upper remaining oil of the gas injection due to the blockage of the interlayer, while in the middle and late stage, the gas-liquid interface gradually reached stability with the increase in injected gas, which has little impact on the final recovery. These results indicate that it is feasible to carry out gas injection gravity flooding in this reservoir. [ABSTRACT FROM AUTHOR]

In this paper, the DBR all-visible mercury-free high-temperature and high-pressure multifunctional formation fluid PVT analyzer developed and produced by Schlumberger company is used to conduct an experimental study on phase behavior characteristics of one offshore high CO2 condensate gas wells. The experiments include two-phase flash experiment, constant composition expansion experiment (CCE experiment), and constant volume depletion experiment (CVD experiment). Experimental results show that the higher the CO2 content in the condensate gas system, the higher the gas-oil ratio of condensate gas, the greater the density of condensate oil, the higher the dew point pressure of condensate gas, the greater the relative volume of condensate gas, the smaller the amount of retrograde condensate oil. And the higher the CO2 content in the condensate gas system, the phase diagram is shifted to the left and up, the critical point of the phase diagram is shifted to the lower left, the smaller the area of the two-phase envelope, the lighter the condensate gas system, the condensate oil recovery is higher. The above experimental results revealed that CO2 is well soluble with condensate gas, the expansion capacity of the condensate gas system was slightly enhanced, and because CO2 has a good extraction capacity, the light components of condensate gas were constantly extracted, the retrograde condensate rate of condensate oil decreases, and the maximum retrograde condensate volume also decreased. However, the condensate oil was produced along with the natural gas, and the higher the CO2 content, the stronger the extraction, the more condensate oil was produced. It is mainly because CO2 has the strong gasification and extraction capacity, on the one hand, the retrograde condensation of condensate gas was inhibited, and on the other hand, reverse evaporation of condensate oil was enhanced. The above experimental results indicate the law of the effect of CO2 on the phase behavior characteristics of condensate gas reservoirs, providing theoretical basis and guidance for the efficient development of condensate gas reservoirs at sea. [ABSTRACT FROM AUTHOR]

In recent years, the shale gas in the southern Sichuan Basin has achieved great commercial development, and the Silurian Longmaxi Formation is the main development stratum. In order to solve the problems of great difference production and inaccurate gas content of the Longmaxi Formation shale gas field in the southern Sichuan Basin, based on thin section identification, argon ion polishing-field emission scanning electron microscopy, high pressure mercury injection, low temperature nitrogen adsorption and the fractal method, the micropore structural heterogeneity of the siliceous shale reservoir of the Longmaxi Formation has been studied. The results show the following: The pores of siliceous shale are mainly intergranular pores and organic pores. Image analysis shows that there are obvious differences in size and distribution of shale pores among different types. The micropore structural heterogeneity is as follows: intragranular pore > intergranular pore > organic pore. In the paper, the combination of low temperature nitrogen adsorption method and high-pressure mercury injection method is proposed to characterize the micropore size distribution and fractal dimension, which ensures the credibility of pore heterogeneity. The shale pores are mainly composed of mesopores (2–20 nm), followed by macropores (100–300 nm). For different pore sizes, the fractal dimension from large to small is mesopore, micropore and macropore. Shale pore structure and fractal dimension are correlated with mineral composition and total organic carbon (TOC) content, but the correlation is significantly different in different areas, being mainly controlled by the sedimentary environment and diagenesis. [ABSTRACT FROM AUTHOR]