Effects of Entrained Hydrocarbon and Organic-Matter Components on Reservoir Quality of Organic-Rich Shales: Implications for “Sweet Spot” Identification and Enhanced-Oil-Recovery Applications in the Duvernay Formation (Canada)

Abstract

Summary The hydrocarbon (HC)-storage capacity of organic-rich shales depends on porosity and surface area, whereas pore-throat-size distribution and pore-throat-network connectivity control permeability. The pores within the organic matter (OM) of organic-rich shales develop during thermal maturation as different HC phases are generated and expelled from the OM. Organic-rich shales can potentially retain a large proportion of the HCs generated during the diagenesis process. Commercial HC production from liquid-rich shale reservoirs can be achieved using completion technologies such as multistage-fractured horizontal wells. However, the ability of industry to identify “sweet spots” along multistage-fractured horizontal wells for both primary and enhanced oil recovery (EOR) is still hampered by insufficient understanding of the effects of type/content of entrained HC/OM components on reservoir quality. The primary objectives of the current study are therefore to establish an integrated experimental workflow to investigate the effect of entrained HC/OM on storage and transport properties of the organic-rich shales, and to provide examples of that experimental workflow through analyzing a selected sample suite from a prolific shale-oil reservoir (the Duvernay Formation) in western Canada. To accomplish this goal, a comprehensive suite of petrophysical analyses is performed on a diverse sample suite from the Duvernay Formation that differs in OM content (2.8 to 5 wt%; n = 5), before and after sequential pyrolysis by a revised Rock-Eval analysis [extended-slow-heating (ESH) Rock-Eval analysis]. Using the ESH cycle, different HC/OM components can be distinguished more easily and reliably during the pyrolysis process: free light oil (S1ESH; up to 150°C), fluid-like HC residue (FHR) (S2a; 150 to 380°C), and solid bitumen/residual carbon (S2b; 380 to 650°C). The characterization techniques used at each stage are helium pycnometry (grain density, helium porosity); low-pressure gas [nitrogen (N2), carbon dioxide (CO2)] adsorption (LPA) [pore volume (PV), surface area, pore-size distribution (PSD) within micropores, mesopores, and smaller macropores]; crushed-rock gas [helium, CO2, N2] permeability; and rate-of-adsorption (ROA) analysis (CO2, N2). Scanning-electron-microscopy (SEM) analysis is further conducted to verify/support the petrophysical observations. Powder X-ray-diffraction (XRD) analyses were performed on all samples in the “as-received” state and after Stage S2b (thermal pyrolysis up to 650°C) to quantify variations in mineralogical compositions and their possible controls on the evolution of petrophysical properties (i.e., porosity/permeability). Organic petrography was conducted on selected samples to characterize the nature of OM. Compared with the “as-received” state, porosity, permeability, modal-pore-size distribution, and surface-area increase with sequential pyrolysis stages, associated with the expulsion and devolatilization of free light oil and FHR (S2a; up to 380°C). However, the change in petrophysical properties associated with the degradation of solid bitumen/residual carbon (S2b; up to 650°C) is variable and unpredictable. The observed reduction in porosity/permeability values after Stage S2b is likely attributed to the occlusion of PV with solid bitumen/residual carbon degradation (i.e., coking); sample swelling caused by water loss from the lattice structure of clay minerals (i.e., illite); and sample compaction as a result of OM removal from the rock matrix. Among various stages of the ESH Rock-Eval pyrolysis, the petrophysical properties that are measured after Stages S1ESH and S2a, as they are related to the expulsion of the lighter and heavier free-HC compounds from the rock matrix, are expected to be the most important for primary and EOR applications. Quantification of the evolution of reservoir quality with HC generation/expulsion has important implications for identifying petrophysical “sweet spots” within unconventional reservoirs, optimizing stimulation design, and targeting specific zones within the reservoir of interest with the OM content/type amenable to maximizing gas storage/transport during cyclic solvent injection for EOR applications. The integrated experimental workflow proposed herein could be of significant interest to the operators of organic-rich shale/mudstone plays (e.g., the Duvernay) as a screening tool for developing optimized stimulation treatments for improving primary and enhanced HC recovery.

Impact of thermal maturity on the concomitant evolution of the ultrafine structure and porosity of marine mudstones organic matter; contributions of electronic imaging and new spectroscopic investigations

“…According to SAXS profiles the variations of the isolated kerogen porosity are mainly due to the decrease in the overall electronic contrast between pores and OM. This may indicate a loss of the primary OM porosity by kerogen deformations during oil generation, such as swelling of kerogen by retained oil as described by Mathia et al (2016) and recently observed by Ghanizadeh et al (2020). The filling of part of the total rock pore volume by the bitumen and oil trapped in the porosity (not extracted before nitrogen adsorption measurements) may explain a great part of the total pore volume loss, (Figure 14), however, the OM porosity (SAXS porosity, P) was measured after the extraction of bitumen and oil by dichloromethane/methanol treatments.…”

Experimental and computational evaluation of cyclic solvent injection in fractured tight hydrocarbon reservoirs

“…The effective diffusion/dispersion coefficients and the fracture aperture were selected as the primary input parameters for optimizing the experimental conditions because they were highly uncertain and the most impactful on oil production/recovery. Matrix permeability was also adjusted slightly but only within the range previously reported for other (Duvernay shale) twin core plug samples with similar porosity and organic/inorganic composition 31 . Two-phase (gas/liquid) relative permeability data, obtained for tight siliceous samples 29 from the Western Canadian Sedimentary Basin were also among the initial selected parameters to constrain the simulation.…”

“…These samples (1.5″ diameter, 2″ length) were drilled parallel to bedding from a 2/3 slabbed core obtained from a vertical well drilled into low-permeability intervals of the Duvernay Formation (Alberta, western Canada). A comprehensive series of geochemical, petrophysical and geomechanical analyses were previously performed on sample pieces and twin core plug samples obtained from the same well and depth 29,39 , serving as an important reference point for the current study. The analyzed samples have the following geochemical and petrophysical properties based on the sub-samples taken from the vicinity of these two core plugs: total organic carbon (TOC) content: 4.26 wt.%; clay content: 33.3%; quartz content: 44.7%; carbonate content: 12.4%; helium porosity: 2.1-3.3%; slip-corrected gas (N 2 ) permeability (1.25•10 -4 md; 900 psi effective stress).…”

Oil Retention in Shales: A Review of the Mechanism, Controls and Assessment

“…Because it is challenging to collect shale sample from immature to overmature stages, the hydrocarbon generation, retention and expulsion evolution profiles of shales can be established through thermal simulation experiments (Ma et al, 2018). Thermal simulation systems can be divided into open, closed and semiclosed systems, and they produce different results (Ghanizadeh et al, 2020). Under geological conditions, petroleum generation, retention and expulsion follow a kinetic evolution process.…”

“…Compared to conventional petroleum systems, shale strata exhibit the characteristics of low porosity and ultralow permeability, and shale oil and gas have received insufficient attention for a long time due to the great difficulty of exploitation (Jarvie, 2012;Chen L. et al, 2019b;Soeder and Borglum, 2019). However, in recent years, with the progress of horizontal drilling, multistage hydraulic fracturing and other engineering techniques, shale oil and gas have become resources with an appreciable development potential (Wang et al, 2015a;Kumar et al, 2017;Zou et al, 2017;Zhao et al, 2018;Chen L. et al, 2019b;Ghanizadeh et al, 2020;Chen et al, 2021). The large-scale development of shale oil in the Permian Basin, Gulf Basin and Williston Basin has provided a new perspective for oil exploration and development (Bai et al, 2020).…”