In this paper, production characteristics of tight oil reservoirs are summarized and analyzed, the investigated reservoirs include Cardium sandstone reservoir and Pekisko limestone reservoir. The phenomenon that gas and oil or water and oil are co-produced at an early stage of exploitation has been observed. In addition, water cut of many tight oil producers remains constant or undergoes reduction as production proceeds within first 36 months. Since an oil rate drops quite a lot in the first year's production of tight oil reservoirs, reservoir simulations are run to investigate an effect of different parameters on tight oil production. Randomized experiments are created with geological and engineering parameters as uncertain factors and an oil rate as the response factor. The method of analysis of variance (ANOVA) is used to analyze the difference between group means and to determine statistical significance. Reservoir properties such as permeability, pressure, wettability, oil API, and oil saturation and engineering parameters including a fracture stage and well operations have tremendous effects on oil production. Oil recovery factor increment in tight oil reservoirs highly depends on enlarging a contact area, improving oil relative permeability, reducing oil viscosity and altering wettability. Future research and development trends in tight oil exploitation are highlighted. As primary recovery is quite low in tight oil reservoirs, the multistage fracturing technology is a necessity and it must be conducted based on a deep understanding of petrophysical and geomechanical properties. Water alternating gas (WAG) seems the best fit for tight oil exploitation. The way to improve WAG performance, including CO2 foam stabilized with surfactant or nanoparticles, low salinity water or nanofluids alternating CO2, will earn more and more attention in the future of tight oil development.
Tight oil resources have become increasingly important as massive hydraulic fracturing techniques breakthrough. Water flooding is generally applied to tight oil reservoirs; however, the oil recovery achieved by water flooding is quite low. A CO 2 miscible flooding process is regarded as a primary enhanced oil recovery (EOR) technique for conventional oil reservoirs as CO 2 can extract oil even at a high water cut. Furthermore, many CO 2 field trials in low permeability reservoirs have been recorded as successful. As CO 2 utilization efficiency drops when formation permeability goes down, CO 2 injection in a miscible condition for tight oil exploitation may not be as profitable as that in conventional oil reservoirs.In tight formations, there exist small pore throats, even at nanoscale. As the confined space in nanopores may shift a phase envelop and lower CO 2 minimum miscible pressure (MMP), operating a well in a near-miscible region where pressure is slightly less than MMP as measured in the lab may result in a good chance of miscibility for some parts of a tight oil reservoir.In this paper, equations of state (EOS) calculations are conducted in order to see the effects of confinement on a CO 2 injection process in tight oil reservoirs. On the basis of Cardium reservoir properties, numerical reservoir simulations are run to investigate the effects of confinement caused by a small pore throat size in 50 nm and 10nm on the CO 2 injection process. Comparisons of CO 2 near-miscible and miscible processes are made with various pore throat sizes. Results show that confinement effects in tight formations help to lower the bubble point pressure and boost an oil rate during CO 2 injection. However, CO 2 EOR efficiency goes down as formation pressure approaches MMP as mearsured in the lab. It is not necessary for CO 2 injection to operate in an above MMP condition in tight formations, where a nanopore size is present. In this way, the volume of CO 2 injected can be reduced. For tight oil reservoirs with a small pore throat size, a CO 2 near-miscible process is more suitable than miscible flooding.
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