Characterization of fine-scale rock structure and differences in mechanical properties in tight oil reservoirs: An evaluation at the scale of elementary lithological components combining photographic and X-ray computed tomographic imaging, profile-permeability and microhardness testing. (September 2016)

• Record Type: Journal Article
• Authors: Solano, N.A.; Clarkson, C.R.; Krause, F.F.
• Is Part Of: Journal of unconventional oil and gas resources. Volume 15(2016:Sep.)
• Page Start: 22
• Page End: 42
• Publication Date: 2016-09
• Subjects: Tight oil reservoir -- Cardium Formation -- Bioturbation -- X-ray CT -- Profile (probe) permeability -- Microhardness -- Pembina field; Secondary recovery of oil -- Periodicals; Shale gas -- Periodicals; Heavy oil -- Periodicals; Shale oils -- Periodicals; Energy development -- Periodicals; Petroleum -- Periodicals; Oil-shales -- Periodicals; Natural gas -- Periodicals; Coalbed methane -- Periodicals; Petroleum industry and trade -- Periodicals; 665.4
• DOI: 10.1016/j.juogr.2016.04.003
• Languages: English
• ISSNs: 2213-3976

Abstract

Graphical abstract: Highlights: A workflow is proposed for the petrophysical evaluation of highly heterogeneous lithofacies. The evaluation is performed individually for each type of elementary lithological component. Measurements include 2D mapping of profile permeability and microhardness at the core-scale. Procedures for the volumetric population of these properties in the cores are explained. Relationships between porosity, permeability, and microhardness are investigated. Abstract: Optimal development of tight-oil resources requires better petrophysical understanding of several key reservoir and mechanical properties. We highlight these for the Cardium Formation at the Pembina field, where controls on these properties appear to occur within elementary lithological components (ELCs) at the cm- to sub-cm scale moderated in part by the effects of synsedimentary bioturbation. This complexity in reservoir behavior necessitates new and innovative approaches for petrophysical property estimation, which is the subject of the current work. The workflow outlined starts with the quantification of the volumetric distribution of ELCs. For this purpose, 360° photographic imaging was used to first identify ELCs, and then quantify their volumetric percentages in whole core. This initial step is limited to the exposed surfaces of the core, consequently we used X-ray computed tomography (XRCT) in order to project the ELCs volumetric distribution into the core interior. The correlation between CT number, mineralogy, and bulk density of the rock further allowed porosity to be calculated from XRCT and shed light on its distribution throughout the core interior. Variations in fine-scale permeability were evaluated by collecting pressure-decay profile permeability measurements across a core slab surface following a 5 × 5 mm-2D grid. Relationships between ELCs permeability and porosity were then generated and, when combined with the volumetric distribution of ELCs previously assessed, enabled a 3D distribution of reservoir quality at the mm-scale throughout the core. Finally, microhardness data was collected on the same 2D grid enabling ELC-scale quantification of mechanical properties. Reservoir properties of whole core samples identified in previous publications appear to be reasonably predicted when utilizing ELCs-specific permeability versus porosity transforms and volumetric percentages generated in this study, thus demonstrating scale-up potential.