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The AAPG/Datapages Combined Publications Database

AAPG Bulletin


AAPG Bulletin, V. 104, No. 1 (January 2020), P. 37-52.

Published by the American Association of Petroleum Geologists. Copyright ©2020 ExxonMobil Research and Engineering Company. All rights reserved.

DOI: 10.1306/04151918083

Nuclear magnetic resonance and x-ray microtomography pore-scale analysis of oil recovery in mixed-porosity carbonates

Hubert King,1 Michael Sansone,2 John Dunsmuir,3 Nicole Callen,4 Pavel Kortunov,5 Ye Xu,6 Antonio Buono,7 Bo Gao,8 and James Kralik9

1ExxonMobil Corporate Strategic Research, Annandale, New Jersey; [email protected]
2ExxonMobil Corporate Strategic Research, Annandale, New Jersey; [email protected]
3ExxonMobil Corporate Strategic Research, Annandale, New Jersey; [email protected]
4ExxonMobil Corporate Strategic Research, Annandale, New Jersey; [email protected]
5ExxonMobil Corporate Strategic Research, Annandale, New Jersey; [email protected]
6ExxonMobil Corporate Strategic Research, Annandale, New Jersey; [email protected]
7ExxonMobil Upstream Research Company, Annandale, New Jersey; [email protected]
8ExxonMobil Upstream Research Company, Annandale, New Jersey; [email protected]
9ExxonMobil Upstream Research Company, ExxonMobil, Annandale, New Jersey; [email protected]


With the recognition that carbonate reservoir rocks commonly contain a significant microporosity component (pore sizes ∼1 μm), there has been an ongoing effort to understand how this affects hydrocarbon recovery. This work reports x-ray microtomography (XMT) and nuclear magnetic resonance (NMR) data on two characteristic rock types. One is micropore dominated, and the other exhibits mixed-pore sizes. Several new techniques are introduced to accommodate investigation of full-sized core-plug samples having preserved wettability and to perform such studies with native fluids. First, the uses of high-field NMR techniques are demonstrated to determine porosity, overall oil and water content, and how these fluids are distributed between micro- and macropores. It is found that microporosity values agree with those obtained by optical (total pore system) analysis. Second, the use of xenon gas to tag the native oil phase for XMT imaging is demonstrated, showing how this helps determine contributions from pores that are smaller than the instrument resolution. Finally, a new method that uses NMR measurements of oil and water saturations to constrain the image analysis is demonstrated. The analysis shows the extent to which oil recovery occurs from the different pore systems. In both rock types, oil in the macroporosity is preferentially swept. Nevertheless, in agreement with a recent theory, oil recovery from the microporosity is significant. For the 70% microporosity sample, approximately one-third of the total oil recovery comes from the micropores, a factor that agrees well with theory.

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