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.

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Over past decades, technology innovation in exploiting unconventional resources has become increasingly important. Associated with technologies applied in shale gas development, exploiting tight oil resources comes into a new stage. Primary recovery in tight oil reservoirs remains low even produced with massively hydraulically fractured horizontal wells. Waterflooding is applicable over a wide range of reservoir conditions but its recovery is not high enough. In addition, gas flooding suffers from channeling problems with existence of highly permeable channels. A water alternating gas (WAG) process seems a good method to recovery tight oil. Recent breakthrough in nanotechnology provides a promising technique in the oil and gas industry. Nanoparticles have a very high surface-volume ratio, easily moving into tight formation without external forces. Nanoparticles additive does not raise weight of an injection fluid, associated with wettability alteration and interfacial tension reduction, and can be an excellent solution in improving recovery in tight oil reservoirs. This paper demonstrates the merits of nanofluids; concentration of 0.05wt% nanofluid gives the best performance in a core flooding test. Simulations of nanoparticles additive in a WAG process are run by Eclipse and CMG in various cases. As the degree of wettability alteration and permeability reduction highly depends on concentration of nanoparticles underground, a tracer is applied in the simulations to confirm the locations of nanoparticels underground and its concentration, and it shows that nanoparticles mainly stay around injection wells and high permeable zones. Simulation results show that a nanofluid alternating gas (NAG) process has a great potential in improving WAG performance, and it performs better with existence of natural fractures.

The objective of this paper is to investigate the possibility of using gas injection to improve liquids recoveries from containers in shale condensate and shale oil reservoirs. Liquids recoveries from shales are known to be very low. A method is proposed to increase these recoveries through gas recycling and by using dry gas that is available within relatively short distances of the shale condensate and oil containers considered in this study. This dry gas is not being produced at this time due to current market conditions. In practice, some shale reservoirs such as the Eagle Ford in the United States and the Duvernay in Canada present the challenge of unconventional fluids distribution: shallower in the structure there is black oil, deeper is condensate and even deeper is dry gas. So the fluids distribution is exactly the opposite of what occurs in conventional reservoirs. Differences in burial depth, temperature, and vitrinite reflectance are used to explain this unique distribution. Ramirez and Aguilera (2014) have shown that fluids in shale reservoirs have remained with approximately the same original distribution (i.e. approximately the same dry gas-condensate contact and approximately the same condensate-oil contact) over geologic time. These fluids are the target of the research results presented in this paper. The investigation involves three basic cases, all of them with horizontal wells. In the first case, a single porosity compositional simulation is used to investigate the possibility of improved liquid recovery from the condensate container by using dry gas injection obtained from the recycling process plus dry gas from the deeper part of the structure. Fluid properties are similar to those of the Duvernay shale. In the second case, dual permeability compositional simulations are used to investigate practical aspects of the condensate container that can lead to improved recoveries in the Eagle Ford shale. Sensitivities are run that include bottomhole pressure (BHP), natural fracture permeability and spacing, hydraulic fracture length and spacing, and distance between parallel wells. Results from dual permeability simulations are compared with dual porosity behavior. Fluid properties are similar to those of the Eagle Ford shale. In the third case, compositional single porosity, dual porosity and dual permeability simulations are used to study the possibility of injecting gas in the oil container. A cyclic huff and puff gas injection is also investigated. Fluids and rock properties are similar to those of the Eagle Ford shale. The study leads to the conclusion that dry gas from deeper shales can be put to good use by injecting it into the middle and upper parts of the structure. In the middle part of the structure there is a container where gas condensate is predominant. In here, a re-cycling injection project allows to inject dry gas stripped from the condensate fluids. This is supplemented with dry gas produced from the deeper part of the structure. In the upper part of the structure there is a container where oil is predominant. In here, injection is implemented using dry gas produced from the deeper part of the structure. Permeability plays a critical role in the case of single porosity simulations. Dual porosity and dual permeability simulations indicate that oil recovery can be enhanced significantly in naturally fractured shales. Diffusion plays a fundamental role on the performance of shale gas injection particularly in the case of naturally fractured shales. It is found that cyclic huff and puff gas injection can help increase oil recovery. To the best of our knowledge, the idea developed in this paper that includes all fluids (oil, condensate and dry gas) present in the same shale structure within relatively short distances of each other has not been published previously in the literature.

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