Gas Injection for EOR in Organic Rich Shales. Part II: Mechanisms of Recovery
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Copyright 2018, Unconventional Resources Technology Conference (URTeC). Laboratory experiments of gas injection in organic rich shales have resulted in significant oil recovery. In Part I (Tovar, Barrufet, and Schechter 2018), we presented an operational philosophy to maximize the recovery factor using a huff and puff injection scheme at the highest possible pressure, regardless of the MMP value. This paper focuses in the impact that fluid transport in organic rich shale has on the recovery mechanisms under gas injection and provides the rationale behind the proposed operational philosophy. We used CT-scanning data from nine core-flooding experiments conducted by injecting CO2 in organic rich shale sidewall cores, two injecting N2, and three further tests of CO2 injection in Berea sandstone thus providing a baseline for comparison to high permeability rock. The core plugs were re-saturated with crude oil in the laboratory, and the experiments were performed at reservoir pressure and temperature using a novel design that replicates gas injection through a hydraulic fracture as closely as possible. CT-scanning was used to visualize the compositional changes with time and space during gas injection. The overall difference in composition between the oil injected and the oil recovered was obtained using gas chromatography. As gas surrounds the oil saturated sample, a peripheral, slow-kinetics vaporizing gas drive is the main production mechanism. Gas injection is performed using a core-holder configuration designed specifically to mimic injection into proppant filled hydraulic fractures, due to lack of injectivity directly into the shale rich matrix. Gas flows preferentially through the proppant due to its high permeability, avoiding the formation and the displacement of a miscible front along the rock matrix to mobilize the oil. Instead, the gas surrounding the reservoir core sample vaporizes the light and intermediate components from the crude oil, making recovery a function of the fraction of oil that can be vaporized into the volume of gas in the fracture at the prevailing thermodynamic conditions. The mass transfer between the injected gas and the crude oil is sufficiently fast to result in significant oil production during the first 24 hours, but slow enough to cause the formation of a compositional gradient within the matrix that exists even six days after injection has started. The peripheral production and the slow kinetic aspects of the recovery mechanism, are a consequence of the low fluid transport capacity associated with the organic rich shale that is saturated with liquid hydrocarbons. The combination of different injection gases and reservoir rocks in our experiments enabled us to effectively isolate the effects of transport properties and phase behavior. In this work, the operational guidelines regarding injection pressure and soak time derived directly from experimental observations are explained in the light of the new production mechanisms using ternary diagrams, thus providing the necessary understanding to successfully conduct gas injection in organic rich, liquid saturated shale reservoirs. Given the vast volume of crude oil trapped in shale reservoirs, this is an important step towards understanding gas injection in Unconventional Liquid Reservoirs (ULR).
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Proceedings of the 6th Unconventional Resources Technology Conference
