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By comparing the quantitative pore results of geological samples from natural evolution profiles and simulated experiment samples, it is believed that the volume changes of pores of different scales are basically similar throughout the evolution of source rocks. Macropores and mesopores have a greater impact on pore changes. They should be the main contributors to the total porosity of rocks, and there is a certain conversion relationship between pores of different sizes. Diagenetic evolution and tectonic changes are the main external factors that cause pore changes while hydrocarbon generation and expulsion processes are the internal factors. In addition, there are some differences in the pore space and size (scale) of hydrocarbon products formed by source rocks during different evolutionary stages. This is useful for determining the storage mechanism of conventional and unconventional oil and gas resources corresponding to different evolutionary stages in the shale formation.

In view of the disadvantage that the absolute difference of time-lapse seismic (the difference between monitoring data and base data) is not only related to the change of oil saturation, but also closely related to the thickness of reservoir, a time-lapse seismic “relative difference method” (the ratio of monitoring data to base data) not affected by the thickness of reservoir but only related to the change of fluid saturation, is proposed through seismic forward modeling after fluid displacement simulation. Given the same change of fluid saturation, the absolute difference of time-lapse seismic conforms to the law of “tuning effect” and seismic reflection of “thin bed”, and the remaining oil prediction method based on absolute difference of time-lapse seismic is only applicable to the reservoirs with uniform thickness smaller than the tuning thickness or with thickness greater than the tuning thickness. The relative difference of time-lapse seismic is not affected by reservoir thickness, but only related to the change of fluid saturation. It is applicable to all the deep-sea unconsolidated sandstone reservoirs which can exclude the effect of pressure, temperature, pore type and porosity on seismic. Therefore, the relation between the relative difference of time-lapse seismic and the change of fluid saturation, which is obtained from seismic forward modeling after Gassmann fluid displacement simulation, can be used to quantitatively predict the change of reservoir water saturation and then the distribution of the remaining oil. The application of this method in deep sea Zeta oil field in west Africa shows that it is reasonable and effective. Key Words: time-lapse seismic, remaining oil quantitative prediction, unconsolidated sandstone reservoir, fluid displacement, absolute difference, relative difference, Zeta oil field, West Africa

As the most frontiers in petroleum geology, the study of dissolution-based rock formation in deep carbonate reservoirs provides insight into pore development mechanism of petroleum reservoir space, while predicting reservoir distribution in deep-ultradeep layers. In this study, we conducted dissolution-precipitation experiments simulating surface to deep burial environments (open and semiopen systems). The effects of temperature, pressure, and dissolved ions on carbonate dissolution-precipitation were investigated under high temperature and pressure (~200°C; ~70 Mpa) with a series of petrographic and geochemical analytical methods. The results showed that the window-shape dissolution curve appeared in 75~150°C in the open system and 120~175°C in the semiopen system. Furthermore, the dissolution weight loss of carbonate rocks in the open system was higher than that of semiopen system, making it more favorable for gaining porosity. The type of fluid and rock largely determines the reservoir quality. In the open system, the dissolution weight loss of calcite was higher than that of dolomite with 0.3% CO2 as the reaction fluid. In the semiopen system, the weight loss from dolomitic limestone prevailed with 0.3% CO2 as the reaction fluid. Our study could provide theoretical basis for the prediction of high quality carbonate reservoirs in deep and ultradeep layers.