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Shale and tight oil reservoirs, with horizontal wells and hydraulic fractures, typically have a recovery ratio of around 10%. The exploration of tight oil and shale in North America has proven economically viable, thanks to advancements, such as horizontal wells, hydraulic fracturing, and other enhanced oil recovery techniques. Taking inspiration from the global experience (the North American shale experience), the exploration and development of the West Siberian tight and shale reserves was more focused on the reported best practices of the exploration of North American shale. In this study, the advance in the specific areas of shale and tight oil exploration was considered, with more emphasis placed on the progress in the exploration of West Siberian shales. According to the review literature, thermal enhanced recovery methods capable of converting organic matter into hydrocarbons were studied more than other methods of enhanced oil recovery. Aligned with global trends, there has been a growing focus on research aiming to integrate data-driven approaches and pore-scale simulations to enhance recovery from tight and shale formations. Multiple pilot studies have showcased promising prospects for implementing multistage hydraulic fracturing. Nevertheless, there are limited pilot studies dedicated to enhanced oil recovery methods for West Siberian shale. [ABSTRACT FROM AUTHOR]

Gas injection has already proven to be an efficient shale oil recovery method successfully tested all around the world. However, gas-enhanced oil recovery methods have never been implemented or tested for the greatest Siberian shale oil formation yet. This article proposes numerical simulation of a hydrocarbon gas injection process into a horizontal well with multiple hydraulic fractures perforating Bazhenov shale oil formation in Western Siberia characterized by ultra-low permeability. A complex field-scale numerical study of gas injection for such a formation has never been performed before and is presented for the first time in our work. The hydrodynamic compositional simulation was performed utilizing a commercial simulator. A sensitivity study for different operating parameters including cycle times, bottom-hole pressures for the production and injection period, and injected gas composition was performed after the model was history matched with the available production data. Some uncertain reservoir properties such as relative permeability curves were also sensitized upon. Two different ways of accounting for multiple hydraulic fractures in the simulation model are presented and the simulation results from both models are compared and discussed. Eventually, huff-n-puff injection of a hydrocarbon gas resulted in a 34–117% increase in oil recovery depending on the fracture model. [ABSTRACT FROM AUTHOR]

In situ shale or kerogen oil production is a promising approach to developing vast oil shale resources and increasing world energy demand. In this study, cyclic subcritical water injection in oil shale was investigated in laboratory conditions as a method for in situ oil shale retorting. Fifteen non-extracted oil shale samples from Bazhenov Formation in Russia (98 °C and 23.5 MPa reservoir conditions) were hydrothermally treated at 350 °C and in a 25 MPa semi-open system during 50 h in the cyclic regime. The influence of the artificial maturation on geochemical parameters, elastic and microstructural properties was studied. Rock-Eval pyrolysis of non-extracted and extracted oil shale samples before and after hydrothermal exposure and SARA analysis were employed to analyze bitumen and kerogen transformation to mobile hydrocarbons and immobile char. X-ray computed microtomography (XMT) was performed to characterize the microstructural properties of pore space. The results demonstrated significant porosity, specific pore surface area increase, and the appearance of microfractures in organic-rich layers. Acoustic measurements were carried out to estimate the alteration of elastic properties due to hydrothermal treatment. Both Young's modulus and Poisson's ratio decreased due to kerogen transformation to heavy oil and bitumen, which remain trapped before further oil and gas generation, and expulsion occurs. Ultimately, a developed kinetic model was applied to match kerogen and bitumen transformation with liquid and gas hydrocarbons production. The nonlinear least-squares optimization problem was solved during the integration of the system of differential equations to match produced hydrocarbons with pyrolysis derived kerogen and bitumen decomposition. [ABSTRACT FROM AUTHOR]