Petrophysical and geomechanical characteristics of Canadian tight oil and liquid-rich gas reservoirs: I. Pore network and permeability characterization

Abstract

Abstract The results from an ongoing laboratory study investigating petrophysical characteristics of the Montney and Bakken formations in Canada are presented. The primary objectives are to (1) characterize the pore network (porosity, pore size distribution) and fluid transport (permeability) properties of these formations in areas with limited datasets and (2) analyze the effects of different geological factors on porosity, pore size distribution and permeability. The techniques used for characterization include: Rock–Eval pyrolysis; bitumen reflectance (BRo); grain size measurement; helium pycnometry; low-pressure gas (N2) adsorption (surface area, pore size distribution); pressure-decay profile permeability, pulse-decay and crushed-rock gas (N2, He) permeability and fracture permeability tests. Rock–Eval analysis and microscopic observations indicate that most samples are organic-lean (average TOC content: 0.3 wt.%), ranging from fine-grained siltstone to very fine-grained sandstone (grain size range: 27–53.7 μm). The measured permeability values on core plugs increase with increasing porosity (2.1–14.1%), ranging between 3.3 ⋅ 10−6 and 7.3 ⋅ 10−2 mD. For the core plugs analyzed (“as-received”), profile (probe) permeability values (9.2 ⋅ 10−4–7.3·10−2 mD) are consistently higher than pulse-decay (1.6 ⋅ 10−5–3.9 ⋅ 10−2 mD) and crushed-rock (3.3 ⋅ 10−6–4.6 ⋅ 10−5 mD) permeability values. Corrected profile (probe) permeability values for “in-situ” effective stress (5.3 ⋅ 10−5–2.5 ⋅ 10−2 mD) are, however, comparable with the pulse-decay (1.6 ⋅ 10−5–3.9 ⋅ 10−2 mD) permeability values. Unpropped fracture permeability, determined using an innovative procedure in this work, can be significantly (up to eight orders of magnitude) higher than matrix permeability under similar effective stress conditions. The grain size data are correlated to permeability values. The dominant pore throat diameter controlling fluid flow is estimated for all samples using Winland-style correlations; these values agree with those obtained from low-pressure N2 adsorption analysis. Applying multiple analysis techniques on a large number of samples (26 m of slabbed core, 22 core plugs and their accompanying cuttings), this study provides a comprehensive petrophysical characterization of Montney and Bakken tight oil and liquid-rich gas reservoirs in Canada.