Natural mineralized fractures from the Montney-Doig unconventional reservoirs (Western Canada Sedimentary Basin): Timing and controlling factors

Highlights

• Fracture diagenesis of Montney-Doig Fms in sub-surface cores was characterized.

• Lithology-related factors controlled fracture occurrence.

• Timing of fracture opening and role of circulating paleo-fluids were constrained.

• The succession behaved like a closed hydraulic system during Late Cretaceous - Paleogene time.

Abstract

Characterizing the origin of natural fractures in organic-rich fine-grained deposits is key to constraining permeability evolution in these potential source rocks and tight reservoirs, as well as to assess the hydraulic connectivity of the fluid systems in which they develop.

Differently oriented calcite-filled fractures (i.e. veins), hosted by organic-rich mudrocks of the Lower-Middle Triassic Montney-Doig unconventional resource play (Western Canada Sedimentary Basin), were sampled in sub-surface well cores from British Columbia. A multidisciplinary approach (including sedimentology, Rock-Eval pyrolysis, petrography, O–C–Sr isotope geochemistry and fluid inclusion microthermometry) was applied to host-rocks and fracture filling calcites.

The results demonstrate the relevance and usefulness of such multidisciplinary studies to gather insights on: 1) the lithology-related factors controlling fracture occurrence; 2) the timing of fracture opening and the origin of the circulating paleo-fluids; 3) the openness of the fluid system through time.

More specifically, host-rock facies (particularly grain size) and vertical facies changes appear to be the leading factors controlling fracture occurrence. A less relevant role was played by the occurrence of diagenetic carbonates, while TOC possibly did not control fracture occurrence.

Three generations of calcite cemented fractures were identified. Vertical fractures (first generation) post-dated the onset of oil generation (Late Cretaceous). Horizontal, bedding-parallel fractures (second generation) post-dated the onset of gas generation and possibly opened close to maximum burial, corresponding to peak hydrocarbon (CH₄) generation (Late Cretaceous - Early Paleogene). Vertical fractures (third generation) post-dated the horizontal ones and opened during basin uplift (Middle to Late Paleogene).

The consistent petrographic and geochemical features of all the calcite cements point to parent fluids in equilibrium with the host-rock lithologies, that possibly behaved as a closed hydraulic system during Late Cretaceous to Paleogene time; this would support the hypothesis that, at least in the portion of the basin investigated, the Montney Fm also acted as source rock of the unconventional system.

Introduction

Fine-grained siliciclastic deposits like shales and siltstones (i.e. mudrocks, sensu Lazar et al., 2015) largely contribute to the filling of sedimentary basins and most commonly constitute low-permeability rock units, unless they are affected by fracturing processes. Natural fractures commonly occur in mudrocks (e.g. Gale et al., 2014; Ukar et al., 2017; Hooker et al., 2019), though their occurrence and the extent to which they enhance the overall rock permeability still remain poorly constrained (Dewhurst et al., 1999).

The development and sealing of natural fractures within organic-rich mudrock successions have received great attention since the interest of exploration in unconventional gas and oil plays rose, particularly in North America (Curtis, 2002; Gale et al., 2007; Engelder et al., 2009). These plays encompass a variety of low-permeability reservoirs that require hydraulic fracturing to be commercially productive and are generally found within or in close association with source rock intervals. The rising interest for unconventional oil and gas plays revealed that source rocks in these settings may also represent the reservoirs of hydrocarbon (HC) accumulations which may be generated in-situ or may have migrated from external sources. Discriminating among the possible behaviors (open versus closed system) of organic-rich mudrock successions during burial and thermal maturation in such plays is relevant to, among others, better assess the amounts of ultimate HC in place (e.g. Jarvie et al., 2007).

On the other hand, characterizing the processes that cause natural fractures in fine-grained organic-rich deposits is crucial to better understand permeability evolution within these potential tight reservoirs (Gale and Holder, 2010; Cobbold et al., 2013; Gasparrini et al., 2014). Several mechanisms may act independently or in combination to cause fracture growth such as the conversion of organic matter in HC (Spencer, 1987; Ozkaya, 1988; Vernik, 1994; Jochum et al., 1995; Marquez and Montjoy, 1996; Zanella et al., 2014; Meng et al., 2017), the build-up of tectonic stress at different moments of the basin history (Ukar et al., 2017; Hooker et al., 2019), as well as the occurrence of specific diagenetic processes (e.g. Van de Kamp, 2008; Gasparrini et al., 2014; Hooker et al., 2017a). Regardless of the mechanisms, mineral cementation may accompany fracturing to form mineralized fracture (i.e. veins), which investigation may help discriminating fracture growth timing and/or genetic mechanism. This may be relevant for predicting evolution of hydraulic connectivity through time and joint relationships with organic matter maturation that can provide constraints to calibrate numerical models for the exploration and production of unconventional resources (e.g. Romero-Sarmiento et al., 2013; Sassi et al., 2013).

Additionally, the localization of the fractures in organic-rich mudrocks may be controlled by different factors capable of affecting the mechanical properties of the rocks (e.g. Young's modulus, Poisson's ratio). Primary sedimentary features of these deposits (e.g. grain size, total organic carbon (TOC), mineralogy), their diagenetic modifications during burial (e.g. cementations, replacements) and the vertical heterogeneities of the succession (e.g. bed thickness, facies stacking pattern, fissility), may control mechanical properties and therefore the localization of fractures and consequently, the rock response to hydraulic fracturing (e.g. Vishkai et al., 2017). However, consensus is not reached in literature on the role of these different factors (Engelder and Peacock, 2001; Rijken and Cooke, 2001; Peacock and Mann, 2005; Wang and Gale, 2009; Gale et al., 2014; Wang et al., 2016; Ilgen et al., 2017; Hooker et al., 2020; Peng et al., 2020) and this is especially true when referring to the coarser mudrock end-member, i.e. the siltstones (e.g. Vaisblat et al., 2017a; 2019; Chatellier et al., 2018).

For the different reasons mentioned above, characterizing the factors controlling the occurrence of natural fractures in organic-rich fine-grained deposits, as well as framing the timing and mechanism of fracturing within the local geological evolution, is key to evaluate permeability and fluid pathway potential through time of these rocks, and hence their present reservoir properties and sealing capacity.

Our study focuses on the mudrocks from the Lower-Middle Triassic Montney-Doig Fms in the Western Canadian Sedimentary Basin (WCSB). More specifically, the Montney Fm is one of the largest economically feasible resource plays and is classified as an unconventional tight oil and gas siltstone reservoir (Davies et al., 1997; Moslow, 2000; Euzen et al., 2018). Since the failure mechanics of such rocks is poorly understood and seldom incorporated in hydraulic fracturing or geomechanical models, this formation has received much attention in terms of characterization of physical and mechanical properties from laboratory tests (Ghanizadeh et al., 2015, Ghanizadeh et al., 2015; Vishkai et al., 2017; Vaisblat et al., 2017a, 2019; Riazi et al., 2017; McKean and Priest, 2019). Geometric features and structural fabrics of fractures in the Montney Fm have been investigated from well cores only by few authors (Davies et al., 2014; Gillen et al., 2019). Surprisingly however, poor attention has been paid to the characterization of the occurrence (in space and time) of natural mineralized fractures.

In an attempt at shedding new light onto these last issues, we investigated mineralized fractures occurring in the Montney-Doig lithologies from two well cores located in British Columbia by applying a multidisciplinary approach (including sedimentology, Rock-Eval pyrolysis, petrography, O–C–Sr isotope geochemistry and fluid inclusion microthermometry) to host-rocks and fracture filling calcites. The main purposes of this survey were: 1) to constrain the factors controlling fracture occurrence in relation with the host-rock properties, 2) to define the relative timing of fracture opening in the framework of the burial and geodynamic history of the WCSB, and 3) to assess the origin of the circulating paleo-waters precipitating the fracture-sealing minerals, in order to gain insight on the fluid system openness through time.