With the increasing importance of unconventional resource plays, efforts have been made to better estimate the storage capacity of unconventional reservoirs. Proper estimation of oil/gas in-place requires, among other considerations, improved determination of the expulsion capacity and porosity of tight reservoirs. In organic-rich rocks, permeability of the hydrocarbon-wet pore network (i.e., organic pores) can be significantly higher than that of the inorganic matrix and fracture pore network. Therefore, organic porosity can be an important factor on the economic viability of unconventional plays.

Unlike conventional systems, where a substantial portion of the generated hydrocarbons are presumed to be expelled from the source rock into the carrier system, economically successful unconventional plays require a significant percentage of the generated hydrocarbons be retained within the source interval. Many unconventional plays consist of a self-sourced petroleum system, where source and reservoir are contained within the same geologic unit. In this type of “massive source-reservoir” system (e.g., Marcellus Fm.), generated hydrocarbons are largely retained within the source rock, limited amounts of resource “bleed” from the source rock’s edge, and the overall expulsion efficiency is limited. Limited primary migration or expulsion leads to the development of excellent shale plays and somewhat reduced conventional resources. Thickness of the source interval is a major control on the effectiveness of these systems. Further examination of unconventional plays reveals two additional plausible expulsion models. In “sandwiched reservoirs,” a reservoir (conventional or unconventional) lays between organic-rich source intervals, with the upper and lower source intervals feeding into a common reservoir (e.g., Bakken Fm.) Expulsion efficiency in this type of system is greater than in “massive source-reservoirs.” Depending on the nature of the reservoir/carrier, secondary migration may occur, and the thermal maturity of the reservoir may be less than that of the produced hydrocarbon. The third expulsion model is defined by “interbedded source-reservoir couplets” such as those characteristic of the Wolfcamp Fm. (Permian Basin). This model is characterized by the highest expulsion efficiency. Secondary migration is likely, and the net reservoir interval is not easily defined.

Porosity is another parameter critical to hydrocarbon in-place estimates, with organic porosity potentially playing a key role on hydrocarbon storage, migration, and production, particularly in massive source-reservoirs. Organic pores, if present in situ, provide space for hydrocarbon storage and increase surface area resulting in higher absorption capacity. However, organic pore size can restrict the influence of organic porosity in liquid-rich plays. Additionally, the connectivity of these pores may be somewhat limited and dependent on the nature of the organic network, thus limiting their impact on permeability. Detailed review of the available literature on organic porosity reveals contradictory information regarding where (e.g., in kerogen macerals, bitumen, and/or pyrobitumen), when (prior to diagenesis, within the oil window, or beyond), and how (e.g., inherited or authigenic) organic pores form. The influence of organic richness on organic porosity development is also up for debate. Many of these apparent contradictions are a function of the nature of the data sets upon which the studies are based. Some of the key issues that need to be clarified when addressing organic porosity are terminology (i.e., terms vary depending on authors’ expertise) and differences in pore morphology (e.g., spongy, isolated bubbles, or fractures). Diverse pore morphologies indicate multiple mechanisms for formation and/or growth of organic pores, suggesting more complexity to organic porosity development than often implied. Finally, it is important to evaluate the extent by which the acts of obtaining and observing the samples containing these pores may result in alteration of the rocks and the pores themselves, potentially producing “organic pores” not reflective of native conditions.