Organic porosity: A geochemist's view of the current state of understanding

With the increasing interest in unconventional resource plays, there have been important changes in the way how reservoirs and their attributes are assessed and characterized. Of particular relevance to the development of unconventional plays has been the focus on the assessment of organic porosity. A review of the available literature reveals contradictions with respect to where organic porosity develops (kerogen, bitumen, or pyrobitumen), when it develops with respect to hydrocarbon generation and cracking (within the oil window or beyond), its mode of formation (inherited or authigenic), the influence of organic carbon content, and the importance of organic porosity with respect to hydrocarbon storage and production. Many of these apparent contradictions appear to result from the nature of the data sets upon which the studies are based. Organic pore size generally limits the role that organic porosity plays in liquid-rich plays. From the available literature, it has become clear that there are number of issues that need to be clarified when addressing organic porosity. One such issue is terminology. There appears to be confusion in the usage of the terms kerogen, bitumen, and pyrobitumen. This confusion exists in the literature and reports prepared by various service providers for those engaged in the exploration and exploitation of unconventional resources. Another issue is the observed differences in the morphology of the organic pores (e.g., spongy, isolated bubbles, or fractures). Differences in pore morphology indicate multiple mechanisms for formation and/or growth of organic pores, suggesting more complexity to organic porosity development than often implied. For example, the spongy appearance of organic pores in some systems could reflect the amorphous character of some oil-prone kerogen, whereas the bubble pore character could be the result of degassing during the transition from the oil window into the gas window or an artifact of decompression and degassing as bitumen solidifies during core retrieval. Similarly, fractures could be a result of the conversion of oil to gas and the inability of the gas to escape or could be desiccation cracks, possibly formed after sample retrieval. Organic pores, if present in situ, increase space for hydrocarbon storage and increase surface area resulting in higher absorption capacity. However, the connectivity of these pores may be somewhat limited and may be dependent on the nature of the organic network, thus limiting their impact on permeability. A challenge when studying organic porosity is its observed variability within an individual reservoir. Very different spatial distribution of pores can occur between adjacent organic particles (e.g., macerals, solid bitumen) as well as within individual macerals. It has been suggested that this could be, in part, a result of organic-inorganic interactions although alternative interpretations have also been proposed. Further complicating the scientific understanding of organic porosity is the possibility that the act of studying the samples containing these pores may result in alteration of the rocks and the pores themselves. Therefore, observed organic pores may not be reflective of native conditions. The lack of a clear understanding of organic porosity development in unconventional mudstone reservoirs is by no means a surprise. Porosity and its development in conventional reservoirs have been studied since Sorby began the examination of sandstone thin sections in 1850 and is still under examination, while organic porosity has been studied for less than a decade. The focus of this study is to provide a review of porosity associated with the organic fraction, which may, in some shale-reservoirs, play a key role in hydrocarbon storage, migration, and production. (C) 2018 Elsevier Ltd. All rights reserved.