The influence of rigid matrix minerals on organic porosity and pore size in shale reservoirs: Upper Devonian Duvernay Formation, Alberta, Canada

Highlights

• Biogenic microcrystalline quartz enhances organic porosity and pore size.

• A ratio of biogenic silica to TOC acts as a proxy for compaction resistance.

• Micropores dominate when volume of rigid matrix minerals is low.

• Pore systems switch from biogenic- to clay-dominated laterally and vertically.

Abstract

Organic porosity is an important component of the pore system in many shale hydrocarbon reservoirs. While much research has been directed towards understanding the development of organic porosity as a function of thermal maturity, relationships between mineralogy and organic porosity have been less extensively investigated. This study illustrates the role of rigid matrix minerals, particularly biogenically-sourced microcrystalline quartz, on organic porosity and pore size evolution.

The Upper Devonian Duvernay Formation of western Canada is a siliceous-calcareous self-sourced reservoir with 3.2-3.79 wt. % average total organic carbon (TOC) content in a study area occurring in the volatile oil to dry gas thermal maturity zones. Biogenic silica is widely distributed throughout the matrix as microcrystalline quartz and locally comprises >50 wt. % of the rock. Porosity and pore size data gathered from BIB- and FIB-SEM, helium porosimetry, H¹ NMR T2, and MICP indicate that organic porosity and pore size is enhanced when in association with biogenic silica. Biogenic silica forms a rigid siliceous matrix framework that limits compaction of pores and ductile organic matter and clay minerals. Where biogenic silica concentration is low, clay mineral (mica+illite) interparticle micro- and fine mesopores dominate. In these samples detrital quartz and biogenic silica have limited influence on pore size other than to preserve the small fraction of organic macropores. The occurrence of biogenic- and clay-dominated pore systems varies systematically with stratigraphic and lateral variations in lithofacies, and sharp contrasts are observed across sequence boundaries. The observation that mineralogy strongly influences organic pore preservation confirms that studies examining the relationship between thermal maturity and organic porosity must account for mineralogical variations.

Introduction

Characterizing pore systems in shale hydrocarbon reservoirs is critical for defining hydrocarbon storage volume and reservoir permeability. Intense focus on exploration and development of unconventional hydrocarbon reservoirs in the last two decades has yielded tremendous volumes of literature on the geology and reservoir properties of organic-rich mudstones, yet our knowledge of the fundamental processes that govern porosity creation and destruction in these systems is still growing.

Organic matter (OM) is typically a significant host of porosity in self-sourced shale hydrocarbon reservoirs, leading to positive correlations between total organic carbon (TOC) content and porosity (Jarvie, 2012; Milliken et al., 2013 among many others). This relationship is caused by several factors. Firstly, compactional loss of primary inorganic porosity is drastic in mudstones due to their high initial water content, and the presence of ductile clay minerals, micas, and OM which are easily compressed, deformed, and reoriented in response to increased effective stress (Velde, 1996; Mondol et al., 2008; Aplin and Macquaker, 2011, references therein). Secondly, inorganic porosity can be occluded by pore-filling cements (Lash and Blood, 2004; Milliken et al., 2012; Milliken and Day-Stirrat, 2013; Milliken and Olson, 2017), and post-oil solid bitumen (Loucks and Reed, 2014; Pommer and Milliken, 2015; Sanei et al., 2015; Wood et al., 2015, Wood et al., 2018; Akihisa et al., 2018; Camp, 2019) which forms as result of secondary cracking of oil that has been expelled from kerogen and has migrated into open pore space (Jacob, 1985, Jacob, 1989; Curiale, 1986; Hwang et al., 1998; Wilson, 2000; Jarvie et al., 2007; Cardott et al., 2015). Thirdly, solid bitumen generates secondary porosity during thermal maturation and transformation into liquid hydrocarbons (Loucks et al., 2009; Curtis et al., 2012; Mastalerz et al., 2013; Pommer and Milliken, 2015; Cardott et al., 2015; Dong et al., 2019a; Camp, 2019).

However, despite these processes favoring the dominance of organic-hosted porosity, TOC-porosity relationships can be very complex. In many studies, strong TOC-porosity correlations are not observed, which in some cases is due to the presence of a significant inorganic porosity fraction, often as inter-particle pores between detrital grains, clay platelets, or carbonate skeletal fragments, or intra-particle pores associated with fossil chambers and mineral dissolution (Schieber, 2010; Slatt and O’Brien, 2011; Loucks et al., 2010, Loucks et al., 2012; Fishman et al., 2012; Pommer and Milliken, 2015; Nie et al., 2015; Ardakani et al., 2017; Ko et al., 2017; Nie et al. 2019; Dong et al., 2019a).

In other cases, the lack of a strong TOC-porosity correlation may be attributed to the varying potential for organic porosity generation of different maceral types (Löhr et al., 2015; Chalmers and Bustin, 2017; Teng et al., 2017; Nie et al., 2018). Hydrogen-poor type III and IV kerogen macerals such as zooclasts and inertinite are commonly observed to be non-porous in thermally mature samples (Ardakani et al., 2018), due to compaction and occlusion of primary kerogen pores, and limited thermal transformation into liquid hydrocarbons which would otherwise have created secondary organic pores. Solid bitumen porosity may also vary as a function of the composition of the primary maceral or liquid hydrocarbon from which the solid bitumen formed (Liu et al., 2017; Misch et al., 2019).

A growing number of recent papers have suggested that organic porosity is influenced by mineralogy and rock fabric (Fishman et al., 2012; Milliken et al., 2013; Guo et al., 2019a; Dong et al., 2019b). In particular, the presence of rigid matrix framework minerals that reduce effective stress on OM particles help to preserve organic pores from collapse.

The study presented here is an examination of pore systems in the Duvernay Formation shale hydrocarbon reservoir of western Canada. The study does not attempt to describe the full range of pore types and characteristics across the entire Duvernay play, nor does it describe the influence of thermal maturity on organic porosity development. The reader is directed to Dong et al. (2019a) for such discussions. Rather, this study presents observations of large intra-well variations in porosity which cannot be explained based on thermal maturity differences. We discuss the mechanisms by which rigid matrix minerals, in this case microcrystalline quartz sourced from biogenic silica, exert a strong control on pore volume and pore size distribution, particularly for organic porosity.