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CO2 injection has become one of the most important methods of enhanced oil recovery in tight reservoirs， but some hydrocarbon gases have more viscosity-reducing and miscibility on oil compared to pure CO2. Therefore， this article studied the saturation pressure and viscosity changes of oil with CO2 and composite gas （CO2 and C2H6） by PVT experiments at high-temperature and high-pressure and revealed the percentage of producing oil with different gases， huff and puff pressures， and rounds by core huff and puff experiments at high-temperature and high-pressure. The results show that the C2H6 in the composite gas enhances the gas and liquid miscibility， improves the CO2 viscosity reduction and dissolution ability， and significantly increases the fluidity of oil. With the increase of C2H6 mole fraction in the composite gas， the saturation pressure of oil increases by 26.54% from 14.24 MPa to 18.02 MPa， and the viscosity of crude oil decreases from 23.68 mPa·s to 8.76 mPa·s. Under different huff and puff pressures， the oil recoveries of composite gas （CO2 and C2H6） are better than that of pure CO2， and the increase of recovery near the minimum miscibility pressure is higher than under other huff and puff pressures. The percentage of producing oil by composite gases is higher than that of pure CO2 in the pores of 0.0001-0.001 μm and 0.01-1 μm.

Natural Gas Hydrate (NGH) has attracted increasing attention for its great potential as clean energy in the future. The main heat transfer mode that controls the thermal front movement in the process of NGH exploitation by heat injection was discussed through NGH thermal stimulation experiments, and whether it is reliable that most analytical models only consider the heat conduction but neglect the effect of thermal convection was determined by the comparison results between experiments and Selim’s thermal model. And the following findings were obtained. First, the movement rate of thermal front increases with the rise of hot water injection rate but changes little with the rise of the temperature of the injected hot water, which indicated that thermal convection is the key factor promoting the movement of thermal front. Second, the thermal front movement rates measured in the experiments are about 10 times that by the Selim’s thermal model, the reason for which is that the Selim’s thermal model only takes the heat conduction into account. And third, theoretical calculation shows that heat flux transferred by thermal convection is 15.56 times that by heat conduction. It is concluded that thermal convection is the main heat transfer mode that controls the thermal front movement in the process of NGH thermal stimulation, and its influence should never be neglected in those analytical models.

The difficulty of deploying remaining oil from unconventional reservoirs and the increasing CO2 emissions has prompted researchers to delve into carbon emissions through Carbon Capture, Utilization, and Storage (CCUS) technologies. Under the confinement of nanopore in unconventional formation, CO2 and hydrocarbon molecules show different density distribution from in the bulk phase, which leads to a unique phase state and interface behavior that affects fluid migration. At the same time, mineral reactions, asphaltene deposition, and CO2 pressurization will cause the change of porous media geometry, which will affect the multiphase flow. This review highlights the physical and chemical effects of CO2 injection into unconventional reservoirs containing a large number of micro-nanopores. The interactions between CO2 and in situ fluids and the resulting unique fluid phase behavior, gas-liquid equilibrium calculation, CO2 adsorption/desorption, interfacial tension, and minimum miscible pressure (MMP) are reviewed. The pore structure changes and stress distribution caused by the interactions between CO2, in situ fluids, and rock surface are discussed. The experimental and theoretical approaches of these fluid-fluid and fluid-solid reactions are summarized. Besides, deficiencies in the application and safety assessment of CCUS in unconventional reservoirs are described, which will help improve the design and operation of CCUS. [ABSTRACT FROM AUTHOR]

CO2-alternating-water injection is an effective way of enhancing recovery for low-permeability oil reservoirs. The injection process is one of the essential issues that are facing severe challenges because of the low permeability and poor pore space connectivity. Previous researchers mentioned that water injection ability could be decreased by around 20% after the CO2-flooding; hence, it is necessary to quantify the water injectivity variation during an alternated injection process. In this paper, a CO2 convection-diffusion model is established based on the seepage law of CO2 and dissipation effect. The relationship between the width of miscible flooding and injection time is defined. Besides, an equivalent resistance method is introduced for developing a capillary bundle model for featuring an unequal diameter for CO2 water vapor alternate flooding. CO2-oil and CO2-water interactions are analyzed using the new model. The effects of oil viscosity, pore throat ratio, CO2 slug size, and equivalent permeability of the capillary bundle on water injection are analyzed. The result indicates that water injection ability increases with the rise of CO2 slug size and equivalent permeability of the capillary bundle and decreases with the increase of viscosity and pore throat ratio. [ABSTRACT FROM AUTHOR]

CO2 capture and reinjection process (CCRP) can reduce the used CO2 amount and improve the CO2 storage efficiency in CO2 EOR projects. To select the best CCRP is an important aspect. Based on the involved equipment units of the CCRP, a novel techno-economic model of CCRP for produced gas in CO2 EOR and storage project was established. Five kinds of CO2 capture processes are covered, including the chemical absorption using amine solution (MDEA), pressure swing adsorption (PSA), low-temperature fractionation (LTF), membrane separation (MS), and direct reinjection mixed with purchased CO2 (DRM). The evaluation indicators of CCRP such as the cost, energy consumption, and CO2 capture efficiency and purity can be calculated. Taking the pilot project of CO2 EOR and storage in XinJiang oilfield China as an example, a sensitivity evaluation of CCRP was conducted based on the assumed gas production scale and the predicted yearly gas production. Finally, the DRM process was selected as the main CCRP associated with the PSA process as an assistant option. The established model of CCRP can be a useful tool to optimize the CO2 recycling process and assess the CO2 emission reduction performance of the CCUS project. [ABSTRACT FROM AUTHOR]