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Abstract

AAPG Bulletin, V. 101, No. 6 (June 2017), P. 807-827.

Copyright ©2017. The American Association of Petroleum Geologists. All rights reserved. Green Open Access. This paper is published under the terms of the CC-BY license.

DOI: 10.1306/09221616069

Oil retention and porosity evolution in organic-rich shales

Yuanjia Han,1 Brian Horsfield,2 Richard Wirth,3 Nicolaj Mahlstedt,4 and Sylvain Bernard5

1Section 3.2 Organic Geochemistry, German Research Centre for Geosciences, Telegrafenberg, Potsdam 14473, Germany; [email protected]
2Section 3.2 Organic Geochemistry, German Research Centre for Geosciences, Telegrafenberg, Potsdam 14473, Germany; [email protected]
3Section 4.3 Chemistry and Physics of Earth Materials, German Research Centre for Geosciences, Telegrafenberg, Potsdam 14473, Germany; [email protected]
4Section 3.2 Organic Geochemistry, German Research Centre for Geosciences, Telegrafenberg, Potsdam 14473, Germany; [email protected]
5Institut de Minéralogie, de Physique des Matériaux et de Cosmochimie, Sorbonne Universités, Centre National de la Recherche Scientifique Unités Mixtes de Recherche 7590, Muséum National d’Histoire Naturelle, Université Pierre et Marie Curie, 61 rue Buffon, 75005 Paris, France; [email protected]

ABSTRACT

Petroleum is retained in shales either in a sorbed state or in a free form within pores and fractures. In shales with oil resource potential, organic matter properties (i.e., richness, quality, and thermal maturity) control oil retention in general. In gas shales, organic pores govern gas occurrence. Although some pores may originate via secondary cracking reactions, it is still largely unclear as to how these pores originate. Here we present case histories mainly for two classic shales, the Mississippian Barnett Shale (Texas) and the Toarcian Posidonia Shale (Lower Saxony, Germany). In both cases, shale intervals enriched in free oil or bitumen are not necessarily associated with the layers richest in organic matter but are instead associated with porous biogenic matrices. However, for the vast bulk of the shale, hydrocarbon retention and porosity evolution are strongly related to changes in kerogen density brought about by swelling and shrinkage as a function of thermal maturation. Secondary organic pores can form only after the maximum kerogen retention (swelling) ability is exceeded at Tmax (the temperature at maximum rate of petroleum generation by Rock-Eval pyrolysis) around 445°C (833°F), approximately 0.8% vitrinite reflectance. Shrinkage of kerogen itself leads to the formation of organic nanopores, and associated porosity increase, in the gas window.

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