The detrital grain size of siltstone reservoirs occupies a middle ground between sandstones and shales, both of which are better understood in terms of their petrophysical properties. Because siltstones can be important hydrocarbon reservoirs, we examine controls on petrophysical properties in the Lower Triassic Montney Formation in western Canada, which hosts world-class reserves of gas, gas liquids and oil. We focus on the effects of rock fabric (including grain size) and composition on pore system characteristics and permeability, drawing contrasts between the three reservoir types. The Montney Formation is an unconventional reservoir through most of its subcrop, with porosities ranging from similar to 3 to 7.5% and permeabilities in the micro to nano Darcy range (6.5*10(-6) mD to 5.6*10(-2) mD). Shale reservoirs worldwide are characterized by similar porosity and permeability values, with porosity of up to 8% (rarely up to 15%) and permeability in the nano to micro-Darcy range. Quartz, clay, and organic matter abundance influence the petrophysical properties of the Montney siltstone. Quartz content exerts a positive control on both porosity and permeability by strengthening the rock framework and reducing porosity loss due to compaction. Elevated clay content is also associated with higher porosity and permeability, in part because of a depositional association with quartz, and in part because clays locally shelter interconnected primary porosity that promotes permeability. Organic matter content is negatively correlated to porosity and permeability despite the presence of organic matter porosity because relict oil (now solid bitumen) occludes primary pores and because other pore types contribute a greater fraction of the total pore volume. Lithofacies, characterized in four cores, are indistinguishable on the basis of petrophysical properties, due to their similar grain size and composition and the massive overprinting by shallow burial diagenesis. While the pore system evolution of sandstones is mainly controlled by the mechanical compaction of hard grains and cementation, pore system evolution of shales is primarily controlled by compaction of ductile grains and diagenesis of primary organic matter, in addition to cementation. Porosity and permeability values of the Montney siltstones are similar to those of shale formations, but the controls on pore system evolution of this intermediate grain size reservoir are predominantly controlled by processes similar to sandstones: compaction, cementation, and cement dissolution. Minor contribution from secondary porosity in bitumen affects some sections of the reservoir in a way that is similar, but not identical, to shale reservoirs.

通过分析上泥盆统Duvernay组页岩样品热成熟度对孔隙空间发育的影响发现,页岩成熟度包含从未成熟到开始产生湿气的各个阶段.受压实作用影响,从未成熟到生油窗口阶段,孔隙空间呈不断缩小趋势.成熟度达到湿气生气阶段的样品孔隙度较高的原因是次生有机质孔隙的形成、长石溶孔的形成以及石英骨架对原生孔隙的保存.由于受到了更高程度的压实作用,导致次生有机质孔隙和长石溶孔消失,处于干气生气阶段的样品孔隙度则显著降低.分析显示,岩样孔隙度的大小与石英含量呈正相关,而与碳酸盐含量呈负相关;其余粘土含量和有机碳含量的关系则不太明显.除了与SiO2含量呈微弱的正相关关系之外,岩样中的其他组分含量与渗透率之间都不存在明显的相关关系.未成熟样品的渗透率往往是最高的,其孔隙和喉道尺寸也是最大的.氮气吸附和压汞分析表明,孔隙和喉道尺寸随着成熟度的增加而不断减小.岩样的扫描电镜和氦离子显微成像分析显示,可见的孔隙以有机质孔隙的形式存在,包括发育在有机物内的气泡状孔隙、微裂隙,而粒间孔隙则主要发育在碳酸盐矿物间、网状粘土矿物间和刚性矿物颗粒间.未成熟岩样的原始孔隙主要为粘土矿物间和其他矿物间的粒间孔隙.处于生油窗口的岩样中有机质充注微裂隙普遍发育,而处于生气阶段的岩样中则普遍发育有次生气泡状有机质充注孔隙.

The influence of thermal maturity on porosity in shale samples from the Upper Devonian Duvernay Formation is examined. The samples span a maturity range from immature to the wet gas window. Porosity decreases from immature to the oil window, primarily because of compaction. Relatively high porosity of wet gas window samples is ascribed to formation of secondary organic pores, feldspar dissolution pores, and primary pore preservation by the quartz framework. The final decline in the porosity of the dry gas window samples is explained by greater compaction, the disappearance of secondary organic pores, and feldspar dissolution pores. Porosity correlates positively to quartz content and negatively to carbonate content; no relationship was evident between porosity and clay or total organic carbon content. No obvious correlations exist between rock composition and permeability except that SiO2 content shows a weakly positive correlation to permeability. Permeability is highest in immature samples, which have the greatest pore and pore-throat sizes. Nitrogen adsorption and mercury injection analysis show that pore and pore-throat sizes decrease with increasing maturity. Visible pores, imaged by scanning electron microscopy and helium ion microscopy, exist as organic pores, including bubblelike pores developed within organic matter (OM) and fissure-type pores, intraparticle pores mainly developed within carbonate grains, and interparticle pores either within a clay-rich matrix or between rigid mineral grains. In immature samples, the primary pores are interparticle pores between clay minerals and other mineral grains. The OM fissures are ubiquitous in oil window samples, and secondary bubblelike OM–hosted pores are well developed within gas window samples.

Abstract The most commonly used technology for development of unconventional reservoirs is horizontal wells combined with large multi-stage hydraulic fracture treatments. However, even with these technological advancements, primary recovery factors are generally less than 10 percent of the hydrocarbon in place. Water is currently the primary fracturing fluid used in most commercial developments. There is growing interest in non-aqueous (e.g. CO2) fluid systems not only to reduce water usage, but to increase well productivity and recovery factors. Use of carbon dioxide (CO2) as a fracturing fluid and an enhanced oil recovery (EOR) agent is also attractive from an environmental point-of-view. Organic rich shale reservoirs can be targets for carbon storage, due to their high CO2 adsorptive abilities and multiple mechanisms for gas storage. Therefore, use of CO2 can have both economic (increased recovery) and environmental (sequestration) benefits. This laboratory study investigates the interactions of CO2 with various cores from three formations (Duvernay, Montney, and Wolfcamp). Multiple core plugs were prepared from each of the three reservoirs. The mineralogy of the samples was measured with x-ray diffraction (XRD), and total organic carbon (TOC) and thermal maturity were determined with a SRA (Source Rock Analyzer). Porosity was also measured under as-received conditions and cleaned and dried conditions with a helium pycnometer. For each sample, its initial baseline permeability to helium was tested under a full cycle of net confining pressures (1,500 psia → 4,500 psia → 1,500 psia) with pressure steps of 1,000 psia using the pressure pulse-decay method. Subsequently the sample was vacuumed for 12 hours, and was then soaked with CO2 for more than 48 hours. Afterwards, the permeability to CO2 was measured under another cycle of confining pressures. Finally, the sample was vacuumed again and the regain permeability to helium was measured. Results indicate that the permeability to helium is generally recovered after CO2 soaking stages for tight-sand samples (e.g., Montney) and may be elevated for some samples enriched in organic matter and clay minerals (e.g., Wolfcamp). Overall the study shows favorable interaction between rock and organic material and CO2, which supports the use of CO2 as a fracturing or EOR fluid in these three reservoirs.

Shale reservoirs of the Middle and Upper Devonian Horn River Group provide an opportunity to study the influence of rock composition on permeability and pore throat size distribution in high maturity formations. Sedimentological, geochemical and petrophysical analyses reveal relationships between rock composition, pore throat size and matrix permeability.In our sample set, measured matrix permeability ranges between 1.69 and 42.81 nanodarcies and increases with increasing porosity. Total organic carbon (TOC) content positively correlates to permeability and exerts a stronger control on permeability than inorganic composition. A positive correlation between silica content and permeability, and abundant interparticle pores between quartz crystals, suggests that quartz may be another factor enhancing the permeability. Pore throat size distributions are strongly related to TOC content. In organic rich samples, the dominant pore throat size is less than 10 nm, whereas in organic lean samples, pore throat size distribution is dominantly greater than 20 nm. SEM images suggest that in organic rich samples, organic matter pores are the dominant pore type, whereas in quartz rich samples, the dominant type is interparticle pores between quartz grains. In clay rich and carbonate rich samples, the dominant pore type is intraparticle pores, which are fewer and smaller in size.High permeability shales are associated with specific depositional facies. Massive and pyritic mud stones, rich in TOC and quartz, have comparatively high permeability. Laminated mudstone, bioturbated mudstone and carbonate facies, which are relatively enriched in clay or carbonate, have fairly low permeability. (C) 2017 Elsevier Ltd. All rights reserved.

This study evaluates pore systems of the Horn River shale in Western Canada Sedimentary Basin from lithofacies classification of core samples to micro-scale pore structure investigation. Samples from the Middle and Upper Devonian Horn River shale sequence were examined by core description, porosity measurement, SEM, and TEM imaging of ion milled samples, and nitrogen adsorption analysis in order to develop a better understanding of the controls of organic and inorganic rock constituents on porosity development and pore microstructure.Five primary shale lithofacies were identified by hand-core and thin section analyses: massive mudstones, massive mudstones with pyrite streaks, laminated mudstones, bioturbated mudstones and carbonates. Porosity ranges from 0.62% to 12.04% and shows wide variation between different lithofacies. Massive mudstones and pyritic mudstones with high total organic carbon (TOC) content have the highest porosity, whereas bioturbated mudstones and carbonates with low TOC content have the lowest porosity. SEM and TEM images suggest that several kinds of sites for porosity development are present, including organic matter, pyrite framboids, clay platelets, quartz rims, carbonate grains and microfractures. A general positive relationship between TOC and porosity indicates that a large proportion of pores are developed in organic matter. Results from the nitrogen adsorption analysis suggest that samples with more organic matter tend to develop smaller pores. Thus while porosity development is a combined function of organic matter, mineral components, fabric and fractures, it is most affected by organic matter concentration.The Muskwa Formation and the Evie Member have more gas storage capacity as they primarily consist of massive mudstones and pyrite-rich mudstones, showing the best porosity. The Otter Park Member has lower porosity, which may relate to the fact that its lithofacies mainly consists of laminated mudstones and bioturbated mudstones.

PreviousNext No AccessUnconventional Resources Technology Conference, Denver, Colorado, 12-14 August 2013A Nearly Complete Characterization of Permeability to Hydrocarbon Gas and Liquid for Unconventional Reservoirs: A Challenge to Conventional ThinkingAuthors: Albert CuiRaphael WustBrent NassichukKen GloverRon BrezovskiCory TwemlowAlbert CuiTrican Geological Solutions Ltd, Calgary, AB, Canada T2E 1M1Search for more papers by this author, Raphael WustTrican Geological Solutions Ltd, Calgary, AB, Canada T2E 1M1Search for more papers by this author, Brent NassichukTrican Geological Solutions Ltd, Calgary, AB, Canada T2E 1M1Search for more papers by this author, Ken GloverTrican Geological Solutions Ltd, Calgary, AB, Canada T2E 1M1Search for more papers by this author, Ron BrezovskiTrican Geological Solutions Ltd, Calgary, AB, Canada T2E 1M1Search for more papers by this author, and Cory TwemlowTrican Geological Solutions Ltd, Calgary, AB, Canada T2E 1M1Search for more papers by this authorhttps://doi.org/10.1190/urtec2013-176 SectionsAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract URTeC 1578611 In recent years interests in the North America oil/gas industry have shifted to and focused on tight/shale liquid-rich gas/oil reservoirs because of the low price of natural gas. It is evident that, beside gas permeability, permeability to hydrocarbon liquids must be understood to properly evaluate liquid production potentials. Previous studies have used gas to determine the intrinsically “true permeability” with the assumption that the “true permeability” corrected from gas permeability is equivalent to the liquid permeability for shale or tight reservoirs with microporous fabric. The microporous fabric with pores or pore-throats in the nanometer size range causes multiple co-existing gas transport mechanisms (continuum/viscous flow, slip flow, transitional and Knudsen diffusion). Several studies have shown that the conventional Klinkenberg correction to gas permeability is no longer appropriate for microporous medium, implying that the permeability to hydrocarbon liquid is likely also different from the gas-based “true permeability”. We envision that for unconventional rocks with nano-scale pores or pore-throats, the intrinsically “true permeability” from gas does not exist alone anymore because the permeability becomes a parameter that measures both the effectiveness of pore-network connectivity and the strong interaction between the specific fluid and the pore structure. In this study, the gas-based “true permeability” of multiple samples of the Montney Formation from the Western Canada Sedimentary Basin were measured with different gases (including helium and argon) using different techniques. Permeability to hydrocarbon liquid (decane) was also tested on duplicate samples. The results show that liquid permeability is significantly lower than the gas permeability, even with Klinkenberg effect corrections. Gas and oil porosity, pore structure and lithology of the samples were also tested using pycnometry, high-pressure mercury-injection porosimetry, scanning electron microscopy, and x-ray diffraction. Integration of the data provides a comprehensive characterization of the permeability and porosity of the samples and sheds insights into our understanding of gas and liquid permeability of unconventional rocks. The implications of the results, the importance of appropriately designed laboratory programs for permeability testing and proper utilization of measured permeability data to evaluate the unconventional gas and oil production potentials are discussed. Keywords: North America, gas, permeability, unconventional, fluid, diffraction, productionPermalink: https://doi.org/10.1190/urtec2013-176FiguresReferencesRelatedDetailsCited ByInvestigation of Diffusion and Sorption in Shale Under Variable Net StressYe Lyu, Devang Dasani, Theodore Tsotsis, and Kristian Jessen1 December 2021Discrete Element Modeling of Permeability Evolution During Progressive Failure of a Low-Permeable Rock Under Triaxial Compression30 August 2021 | Rock Mechanics and Rock Engineering, Vol. 54, No. 12Liquid imbibition in tight rocks: The role of disjoining pressureColloids and Surfaces A: Physicochemical and Engineering Aspects, Vol. 627Permeability of Tight Sand and Shale Formations: A Dual Mechanism Approach for Micro and Nanodarcy Reservoirs24 September 2020Modelling imbibition data for determining size distribution of organic and inorganic pores in unconventional rocksInternational Journal of Coal Geology, Vol. 201Enhancing recovery and sensitivity studies in an unconventional tight gas condensate reservoir27 March 2018 | Petroleum Science, Vol. 15, No. 2A Laboratory Study of CO2 Interactions Within Shale and Tight Sand Cores - Duvernay, Montney and Wolfcamp Formations13 March 2018The porosity and permeability prediction methods for carbonate reservoirs with extremely limited logging data: Stepwise regression vs. N-way analysis of varianceJournal of Natural Gas Science and Engineering, Vol. 42General Gas Permeability Model for Porous Media: Bridging the Gaps Between Conventional and Unconventional Natural Gas Reservoirs6 July 2016 | Energy & Fuels, Vol. 30, No. 7Combined impact of flow regimes and effective stress on the evolution of shale apparent permeabilityJournal of Unconventional Oil and Gas Resources, Vol. 14Klinkenberg gas slippage measurements as a means for shale pore structure characterization3 July 2015 | Geofluids, Vol. 16, No. 2A Statistical Study of Lab Measurements on Montney Tight Rock of Western Canada5 May 2016Lithological Controls on Mechanical Anisotropy in Shales to Predict In Situ Stress Magnitudes and Potential for Shearing of Laminations During Fracturing20 October 2015Permeability Measurement of Organic-Rich Shale - Comparison of Various Unsteady-State Methods28 September 2015Petrophysical and geomechanical characteristics of Canadian tight oil and liquid-rich gas reservoirs: I. 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A Montney Example from the Western Canada Sedimentary Basin11 November 2013 Unconventional Resources Technology Conference, Denver, Colorado, 12-14 August 2013ISSN (online):2159-6832Copyright: 2013 Pages: 1229 publication data© 2013 Published in electronic format with permission by the Society of Exploration Geophysicists, American Association of Petroleum Geologists, and Society of Petroleum EngineersPublisher:Unconventional Resources Technology ConferenceSociety of Exploration Geophysicists HistoryPublished: 26 Sep 2013 CITATION INFORMATION Albert Cui, Raphael Wust, Brent Nassichuk, Ken Glover, Ron Brezovski, and Cory Twemlow, (2013), "A Nearly Complete Characterization of Permeability to Hydrocarbon Gas and Liquid for Unconventional Reservoirs: A Challenge to Conventional Thinking," SEG Global Meeting Abstracts : 1716-1732. https://doi.org/10.1190/urtec2013-176 Plain-Language Summary KeywordsNorth AmericagaspermeabilityunconventionalfluiddiffractionproductionPDF DownloadLoading ...