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High-pressure combustion tube test was conducted to evaluate the effectiveness of air injection in terms of hydrocarbons generation from kerogen bearing rocks and to compare combustion front quenching techniques. The test consisted of several stages including air injection, stop of air injection, reigniting and quenching of combustion front with nitrogen. As a result, temperature profiles along the tube were obtained and it was shown that the temperature of 200°C is sufficient for effective and stable high-temperature oxidation of absorbed hydrocarbons, resins and asphaltenes and kerogen. Successful reigniting indicates a high probability of igniting after the air injection shutdown due to various reasons, including technological. The maximum temperature reached in the model was 920°C. The combustion front propagated faster in the zones packed with consolidated core samples, simulating the fracture or the permeable channels. It can be explained by the breakthrough of the combustion front through the permeable zones. At the same time, combustion in areas with consolidated samples continued at a slower rate. The consolidated sample and the crushed rock burn at different rates, but the peak temperatures are the same. Two methods of combustion front quenching were compared, namely air injection shutdown and nitrogen purge. When the air injection stopped, the core model cooled down faster than during nitrogen purge. It can be explained by the displacement of the trapped oxygen in the model by injected nitrogen, which led to the continuation of oxidation reactions until all oxygen consumed by oxidation reactions. In the case of air injection shut down oxygen was observed in evolved gases. Evolved gas composition was determined, which can serve as "in-situ thermometer" of the processes, and indicator of what lithologic types of rocks affected by the combustion front. References 1. Kalmykov G.A., Stroenie bazhenovskogo neftegazonosnogo kompleksa kak osnova prognoza differentsirovannoy nefteproduktivnosti (The structure of the Bazhenov oil and gas bearing complex as the basis for the forecast of differentiated oil production): thesis of doctor of geological and mineralogical science, Moscow, 2016. 2. Jacobs T., Shale EOR delivers, so why won’t the sector go big?, JPT Digital Editor, 2019, V. 71, no. 5, https://doi.org/10.2118/0519-0037-JPT. 3. Secure fuels from domestic resources: Profiles of companies engaged in domestic oil shale and tar sands resource and technology development, 2011, URL: https://www.energy.gov/sites/prod/files/2013/04/f0/SecureFuelsReport2011.pdf. 4. Bokserman A.A., Grayfer V.I., Kokorev V.I., Chubanov O.V., Thermogas recovery method (In Russ.), Interval, 2008, no. 7, pp. 26-33. 5. Moore R.G., Mehta S.A., Ursenbach M.G., A guide to high pressure air injection (HPAI) based oil recovery, SPE-75207-MS, 2002, https://doi.org/10.2523/75207-MS 6. Gutierrez D., Moore R.G., Ursenbach M.G., Mehta S.A., The ABCs of in situ combustion simulations: From laboratory experiments to the field scale, SPE-148754-MS, 2011, https://doi.org/10.2118/148754-MS. 7. Kök M. V., Guner G., Bagc S., Application of EOR techniques for oil shale fields (in-situ combustion approach), Oil Shale, 2008, V. 25, pp. 217–225. https://doi.org/10.3176/oil.2008.2.04. 8. Bondarenko T.M. et al., Laboratory modeling of high-pressure air injection in oil fields of Bazhenov formation (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2017, no. 3, pp. 34–39. 9. Nikitina E.A., Tolokonskiy S.I., Shchekoldin K.A., Analysis of laboratory studies and field test results for thermal and gas EOR method (In Russ.), Neftyanoe khozyaystvo = Oil industry, 2018, no. 9, pp. 62–67. |
