Shale: Subsurface Science and Engineering (Geophysical Monograph Series) [1 ed.] 1119066689, 9781119066682

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Geophysical Monograph Series

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Geophysical Monograph 245

Shale

Subsurface Science and Engineering Thomas Dewers Jason Heath Marcelo Sánchez Editors

This Work is a co‐publication of the American Geophysical Union and John Wiley & Sons, Inc.

This Work is a co‐publication between the American Geophysical Union and John Wiley & Sons, Inc. This edition first published 2020 by John Wiley & Sons, Inc., 111 River Street, Hoboken, NJ 07030, USA and the American Geophysical Union, 2000 Florida Avenue, N.W., Washington, D.C. 20009 © 2020 the American Geophysical Union All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted, in any form or by any means, electronic, mechanical, photocopying, recording, or otherwise, except as permitted by law. Advice on how to obtain permission to reuse material from this title is available at http://www.wiley.com/go/permissions

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Contents Contributors ��������������������������������������������������������������������������������������������������������������������������������������������������������vii Preface �����������������������������������������������������������������������������������������������������������������������������������������������������������������ix Acknowledgments�������������������������������������������������������������������������������������������������������������������������������������������������xi

Part I: Shale and Clay Overview 1. Mudrock Components and the Genesis of Bulk Rock Properties: Review of Current Advances and Challenges Kitty L. Milliken and Nicholas W. Hayman........................................................................................................3 2. Chemical Composition of Formation Water in Shale and Tight Reservoirs: A Basin‐Scale Perspective Yousif Kharaka, Kathleen Gans, Elisabeth Rowan, James Thordsen, Christopher Conaway, Madalyn Blondes, and Mark Engle...............................................................................................................................27 3. From Nanofluidics to Basin‐Scale Flow in Shale: Tracer Investigations Yifeng Wang..................................................................................................................................................45 4. Metals in Oil and Gas‐Bearing Shales: Are They Potential (Future) Ore Deposits? Mark J. Rigali and James L. Krumhansl............................................................................................................59 5. Coupled Thermal–Hydraulic–Mechanical and Chemical Modeling of Clayed Rocks Leonardo do N. Guimarães, Antonio Gens, and Marcelo Sánchez..................................................................69 6. Thermo‐Hydro‐Mechanical Testing of Shales Alessio Ferrari and Enrique Romero Morales..................................................................................................83 7. Geomechanics of Shale Repositories: Mechanical Behavior and Modeling Miguel A. Mánica, Daniel F. Ruiz, Jean Vaunat, and Antonio Gens..................................................................99 8. Generation and Self‐Sealing of the Excavation‐Damaged Zone (EDZ) Around a Subsurface Excavation in a Claystone Paul Bossart, Christophe Nussbaum, and Kristof Schuster............................................................................125 9. Shale and Wellbore Integrity J. William Carey and Malin Torsæter.............................................................................................................145

Part II: Unconventional Oil and Gas 10. Characterization of Unconventional Resource Shales (Mudstones): The Necessity of Multiscale Scientific Integration Roger M. Slatt..............................................................................................................................................163 11. Wellbore Mechanics and Stability in Shale Amin Mehrabian, Vinh X. Nguyen, and Younane N. Abousleiman................................................................197 12. Modeling Hydraulic Fracturing of Unconventional Reservoirs Ahmad Ghassemi and Zhennan Zhang........................................................................................................213 v

vi Contents

13. Flow of Gas and Liquid in Natural Media Containing Nanoporous Regions Timothy J. Kneafsey and Sharon Borglin.......................................................................................................235 14. Factors Affecting Hydrocarbon and Water Mobility in Shales Charles Bryan and Pat Brady.......................................................................................................................255 15. Dynamics of Matrix‐Fracture Coupling During Shale Gas Production I. Yucel Akkutlu and Asana Wasaki..............................................................................................................273 Index������������������������������������������������������������������������������������������������������������������������������������������������������������������287

Contributors Younane N. Abousleiman Mewbourne School of Petroleum and Geological Engineering School of Civil Engineering and Environmental Science ConocoPhillips School of Geology and Geophysics PoroMechanics Institute The University of Oklahoma Norman, OK, USA

Mark Engle United States Geological Survey Reston, VA, USA; Department of Geological Sciences University of Texas at El Paso El Paso, TX, USA Alessio Ferrari Laboratory for Soil Mechanics (LMS) School of Architecture, Civil and Environmental Engineering (ENAC) Ecole Polytechnique Fédérale de Lausanne (EPFL) Lausanne, Switzerland

I. Yucel Akkutlu Department of Petroleum Engineering Texas A&M University College Station, TX, USA Madalyn Blondes United States Geological Survey Reston, VA, USA

Kathleen Gans United States Geological Survey Menlo Park, CA, USA

Sharon Borglin Earth and Environmental Sciences Lawrence Berkeley National Laboratory Berkeley, CA, USA

Antonio Gens Department of Civil and Environmental Engineering Technical University of Catalonia Barcelona, Spain

Paul Bossart Federal Office of Topography Swiss Geological Survey at Swisstopo Bossart, Switzerland

Ahmad Ghassemi Mewbourne School of Petroleum and Geological Engineering The University of Oklahoma Norman, OK, USA

Pat Brady Nuclear Energy Fuel Cycle Programs Sandia National Laboratories Albuquerque, NM, USA

Leonardo do N. Guimarães Department of Civil Engineering and Environmental Engineering Federal University of Pernambuco Recife, Brazil

Charles Bryan Storage and Transportation Technology Nuclear Energy Fuel Cycle Programs Sandia National Laboratories Albuquerque, NM, USA J. William Carey Earth and Environmental Sciences Division Los Alamos National Laboratory Los Alamos, NM, USA

Nicholas W. Hayman John A. and Katherine G. Jackson School of Geosciences Institute for Geophysics The University of Texas at Austin Austin, TX, USA

Christopher Conaway United States Geological Survey Menlo Park, CA, USA

Yousif Kharaka United States Geological Survey Menlo Park, CA, USA

vii

viii Contributors

Timothy J. Kneafsey Earth and Environmental Sciences Lawrence Berkeley National Laboratory Berkeley, CA, USA

Marcelo Sánchez Zachry Department of Civil Engineering Texas A&M University College Station, TX, USA

James L. Krumhansl 813 Solano Drive NE Albuquerque, NM, USA

Kristof Schuster Federal Institute for Geosciences and Natural Resources (BGR) Hannover, Germany

Miguel A. Mánica Instituto de Ingeniería Universidad Nacional Autónoma de México Cuidad de México, México Amin Mehrabian John and Willie Leone Family Department of Energy and Mineral Engineering Earth and Mineral Sciences Energy Institute The Pennsylvania State University University Park, PA, USA Kitty L. Milliken Bureau of Economic Geology The University of Texas at Austin Austin, TX, USA Vinh X. Nguyen PVEP POC Ho Chi Minh City, S.R. Vietnam Christophe Nussbaum Federal Office of Topography Swiss Geological Survey at Swisstopo Wabern, Switzerland Mark J. Rigali Applied Systems Analysis and Research Sandia National Laboratories Albuquerque, NM, USA Enrique Romero Morales Department of Civil and Environmental Engineering Universitat Politècnica de Catalunya (UPC) ‐ BarcelonaTech Barcelona, Spain Elisabeth Rowan United States Geological Survey Reston, VA, USA Daniel F. Ruiz Department of Civil and Environmental Engineering Universitat Politecnica de Catalunya (UPC) BarcelonaTech Barcelona, Spain

Roger M. Slatt School of Geosciences Institute of Reservoir Characterization The University of Oklahoma Norman, OK, USA James Thordsen United States Geological Survey Menlo Park, CA, USA Malin Torsæter Department of Petroleum SINTEF Industry Trondheim, Norway Jean Vaunat Department of Civil and Environmental Engineering Universitat Politècnica de Catalunya (UPC) ‐ BarcelonaTech Barcelona, Spain Yifeng Wang Nuclear Waste Disposal Research and Analysis Sandia National Laboratories Albuquerque, NM, USA Asana Wasaki Department of Petroleum Engineering Texas A&M University College Station, TX, USA; Japan Petroleum Exploration Co., Ltd. (JAPEX) Tokyo, Japan Zhennan Zhang School of Naval Architecture Ocean and Civil Engineering Shanghai Jiao Tong University Shanghai, China

Preface The timing has never been more opportune for a summary treatise on the subsurface science and engineering of shale; this is suggested by several factors. The rise of shale oil and gas is predicted by some to enable energy independence and export in the United States in the coming decades. Consequently, the now‐common “shale” brings to mind a reinvigorated fossil‐fuel energy economy, to others a means to transition from coal to renewable resources via cleaner natural gas, and to still others “fracking” across the landscape, threatening the environmental quality of water and air. At the basic science level, new imaging techniques, including dual focused ion beam‐ scanning electron and neutron scattering methods, have emerged in the last decade that allow unprecedented internal three‐dimensional views into shale pore network topologies and pore lining phases at previously unobtainable length scales (i.e., nanometers). Shales have always been considered as a major sealing lithology and source for oil and gas reservoirs. Inasmuch as these seals already existed for trapping hydrocarbons, and hydrocarbon generation and migration was mostly ancient history, interest in shale specifically as an engineering target was never a priority for the oil and gas industry. Industry was always more concerned with conventional sandstone and carbonate reservoirs that lie beneath the shales, and the shale formations themselves were mostly viewed as problematic from a drilling perspective and handled on a field‐by‐field basis. Recent occurrences have renewed interest in shale science and engineering: 1. While shales were long‐known reservoirs for oil and gas, and so‐called hydrofracking was viable technology for reservoir stimulation since the 1950s, advances in horizontal drilling together with fracking made extraction of oil and gas from shales economically viable, hence the shale gas “revolution.” The last 5 years have seen unbounded growth in the study of gas shales in China. 2. Recent recognition of saline formations as a large potential reservoir for secure carbon sequestration brings the need for secure storage, and hence “caprocks” as sealing formations. Inasmuch as most saline formations are clastic reservoirs composed of sandstones, depositional predisposition led to shales as the dominant proposed caprock lithology. The question of storage security, and caprock integrity, for geologic carbon storage, is largely a question of shale performance assessment. Natural and induced fractures in caprock as potential leakage pathways is a difficult research topic from field, laboratory, and multiphysics reactive transport modeling

perspectives, but key to regulatory and public acceptance of large‐scale CO2 storage. 3. The uncertainty of Yucca Mountain as the geologic repository for United States domestic nuclear waste has led to a reconsideration of shale formations as such in the United States. The recognition that shale formation pore‐ water overpressure, resulting from ice sheet compression, has persisted at least for 10,000 years is strong evidence for the sealing potential for these rock types on repository‐ requisite time scales. Shales are the dominant lithology considered for many proposed European repositories. 4. Shales are under renewed scrutiny as hosts for light and heavy rare‐earth elements. These are in high demand for aerospace and electronics industries and there is growing concern of a worldwide shortage. A newly released study by the United States Geological Survey suggests that United States reserves in predominately shale formations are larger than previously thought, with potential geopolitical consequences. Fundamental understanding for successful subsurface science and engineering of shale is however lacking. There is no consensus as to factors underlying the observed rapid decline in gas production in shale gas fields. Movement of CO2 plumes in the subsurface through mudstone caprocks has not followed model prediction. Current coupled hydro‐thermo‐mechanical models struggle to describe large‐scale tests in mudstone formations in European underground laboratories. Essentially, the response of anisotropic heterogeneous shale/mudstone lithologies to engineered three‐dimensional thermal, fluid flow, and stress perturbations are not currently quantifiable to a degree where prediction is ­ viable. These important sedimentary rocks have grain sizes on the order of microns (1 mm contains a 1000 μm) and pore sizes from microns to nanometers (1 μm ­contains a 1000 nm) and contain organic material and abundant clay minerals, which possess unique properties of shrink‐ swell, large surface area for sorption, and intergranular water and exchangeable cations. Shales exert a profound influence on groundwater hydrology and are the source rock, trap, and reservoir for shale oil and gas. Use of shales for both resource and storage purposes in a sustainable and efficient manner requires mastery of many aspects unique to shale as opposed to other rock types, such as fluid flow and transport through complex, multiscale pore and fracture networks. In this volume, we bring together a series of chapters from recognized experts from industry, academia, private ix

x Preface

research institutions, and national laboratories compiling of a state of the art of current science and engineering practices involving this most enigmatic of rock types. This includes a basic overview of shale heterogeneity from nanometers to kilometers, the basic science of coupled multiphysics of shale rock in the subsurface (i.e., flow, transport, geochemistry, and geomechanics), and engineering practices associated with shale oil  and gas extraction, seal integrity for carbon and

other waste storage, and other shale‐containing natural resources. We offer a survey of the existing state of knowledge and organize relevant research needs relevant to subsurface engineering endeavors for the coming decades. Thomas Dewers Jason Heath Marcelo Sánchez

Acknowledgments We thank the many authors of this book for their t­ ireless patience as the project waxed and waned its way to completion. It is pleasure for Dewers and Heath to acknowledge support from the U.S. Department of Energy, Office of Science, Office of Basic Energy Sciences, under contract DE‐SC0006883. In particular, Nick Woodward, in his years as our Program Manager, enthusiastically supported our interest in shale and pushed us to make connections between the basic science of, and applied engineering, shale for resource and storage. The many reviewers of the individual chapters are graciously thanked for their contributions as well. We thank

c­olleagues at Sandia Labs and students and faculty at associated universities including Alex Rinehart, Peter Mozley, Dana Ulmer Scholle, Jon Lorentz, Scott Cooper, Peter Eichhubl, Mathew Ingraham, Joe Michael, Hongkyu Yoon, Zuleima Karpyn, and many others, all of whom have contributed greatly to our knowledge of old mud. Sandia National Laboratories is a multimission laboratory managed and operated by National Technology and Engineering Solutions of Sandia, LLC., a wholly owned subsidiary of Honeywell International, Inc., for the U.S. Department of Energy’s National Nuclear Security Administration under contract DE‐NA‐0003525.

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Part I Shale and Clay Overview

1 Mudrock Components and the Genesis of Bulk Rock Properties: Review of Current Advances and Challenges Kitty L. Milliken1 and Nicholas W. Hayman2

Abstract Fine‐grained sediment (mud) and lithified equivalents (mudrock, mudstone, and shale) contain components similar to ones in coarser sedimentary materials, albeit of such small size that high‐resolution imaging is required to observe them. Such imaging reveals that fine‐grained sedimentary rocks display diversities of grains, pores, and diagenetic features that actually exceed the variations of components in common sandstones and limestones. Mudrock diversity reflects the extraordinary range of grain and pore sizes, which extend from detrital grains and authigenic crystals in the 50% particles that are 3/4 (Shepard, 1954) clay‐size particles by volume are, in fact, rather rare in nature. Note that “clay size” is 20 vol.%), in most cases it is still below the range in overall silt content, 60–74% (40–26% intersilt volume), that would be needed for a self‐supporting silt‐ grain framework that might form a true stress‐bridging system protecting interparticle porosity. However, such estimates of percentages are based on analogy to sandstones (Paxton et  al., 2002), whereas silt grains in mudrocks have shapes that are considerably less equant than those of grains in sandstones (Haines and Mazzullo, 1988; Mazzullo and Crisp, 1985), so more open, but still‐ touching, stacking arrangements, and ultimately, also tighter packing, may be possible. More likely, however, is the effect of silt particles, in most instances not in contact with one another, on the surrounding matrix. Most compaction models begin with the “March model” (Schumann et al., 2014; Sintubin, 1994; Voltolini et  al., 2009) wherein elongated particles rotate into a preferred orientation perpendicular to the overburden, typically bedding‐plane‐parallel in basin settings, and then remain in that orientation with further burial. Such a model is consistent with compactional stabilization wherein most porosity is lost in the upper few hundred meters (or less) of burial, below which the remaining porosity is protected and any subsequent porosity loss is primarily via cementation (Paxton et al., 2002). Indeed, in mudrocks there appears to be limits on compaction wherein small pores in the clay‐sized matrix are protected

18  Shale: Subsurface Science and Engineering

during deep burial (Emmanuel and Day‐Stirrat, 2012), a finding supported by experiments that fail to generate the small porosities of the deep basin (Mondol et al., 2007; Schneider et al., 2011). Analysis of grain shape and orientation in mudrocks also supports March‐model behavior in that preferred orientations are relatively constant irrespective of sampling depth (Sintubin, 1994). In other words, anisotropy is profound (Day‐Stirrat et al., 2008a; Gu et al., 2015). These trends in compaction and porosity changes illustrate that mudrock properties do not follow the relatively simple patterns documented for sandstones across depth (summarized by Milliken and Day‐Stirrat, 2013). This is due to both chemical and mechanical aspects of mudrock diagenesis: (i) grain assemblages are far more reactive than in sandstones (Aplin and Macquaker, 2011; Milliken, 2014) and thus cementation can be early (Milliken, 2014; Milliken and Day‐Stirrat, 2013; Taylor and Macquaker, 2014); (ii) small pore sizes favor fast growth of small crystals (Lander and Laubach, 2015), (iii) fluid flow can be quite fast because the small pore sizes favor non‐Darcian flow that allows for slip on the water‐mineral interfaces (Javadpour, 2009), and (iv) pores are generally too small to host the nuclei needed for large crystal growth (Emmanuel et  al., 2010), and the fluids contained in nanopores may be exceedingly rich in ions that interact with pore wall in ways that restrict transport and growth rates (Haluszczak et  al., 2013; Hu et  al., 2015; Rowan et al., 2015). In other words, the low porosity, small pore size, and compositional nature of solids and fluids in fine‐grained sedimentary materials may suppress the compaction and cementation patterns and rates that are associated with coarser sediments. This intersection of the components in fine‐grained sedimentary materials with postdepositional processes thus gives rise to the experimentally observed multiscale matrix permeability (Bhandari et  al., 2015; Schneider et al., 2011) that are included in some modeling approaches (Mehmani et al., 2013). 1.3.1.2. Final Remarks: Rich Opportunities for Mudrock Investigations Predictive models for the chemical and mechanical evolution of muddy sediments in the upper few kilometers of sedimentary basins have not yet reached the level of ­efficacy that characterizes cementation and compaction models in sandstones. However, high‐resolution imaging, together with new technologies for preparation of flat surfaces with little mechanical damage, has transformed our understanding of mudrock components and the historical processes manifested in their diagenetic features. Below is a short listing of basic and applied research problems that will benefit from the enhanced opportunities for quantification provided by recent technological

advances in mudrock component characterization. In every case an integration of high‐resolution pore imaging, EDS elemental mapping, and CL imaging can be usefully combined with different measurements of porosity, permeability, and mechanical properties to refine a predictive understanding rock property evolution. 1. How do compaction and cementation interact in porosity decline in muds? This is a very fundamental aspect of mudrock diagenesis for which we currently lack a satisfactory understanding. 2. What compactional states are observed across ­compositional variations of the detrital assemblage for a given burial history? 3. Under what range of silt content do silt‐size particles within mudrocks form rigid framework packs? How does the proximity of silt components change in response to compaction? Answers to these questions have significant implications for understanding the evolution of velocity in mudrock compaction because silt grains are relatively rigid compared to the surrounding porous packs of clay‐ size clay‐minerals, and if touching, would transmit sonic waves more readily. 4. What are the quantitative relationships between cementation and brittle behavior in mudrocks? How much cement of a given type does it take to shift from deformation by grain displacement to brittle behavior, and in the case of brittle mudrocks, to materially affect the crack path? 5. What are the kinetic limitations on nucleation and crystal growth at nanometer scales? 6. Does pressure dissolution mobilize silica in mudrock? If so, pressure and temperature regimes of this potentially important process need to be identified. 7. How do diagenetic processes impact anisotropy in mudrocks? The preferred alignment of elongated particles at deposition is well established, but the impacts of cementation, compaction, and pressure dissolution have yet to be fully quantified across burial histories in muds. ­ACKNOWLEDGMENTS KLM’s mudrock studies have received support from the National Science Foundation, the Department of Energy, industry consortia at the University of Texas at Austin in the Department of Geological Sciences and the Bureau of Economic Geology, individual petroleum companies, and the Geology Foundation of the Jackson School of Geosciences. Samples shown in Figures 1.2–1.4 were provided by the International Ocean Discovery Program (IODP). NWH thanks the Mudrock Systems Research Laboratory (MSRL) of the BEG, the SUTUR program (Shell‐UT), the Research Partnership to Secure Energy for America under subcontract 12122‐52, and CFSES, an Energy Frontier Research Center funded by

Mudrock Components and the Genesis of Bulk Rock Properties  19

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Mudrock Components and the Genesis of Bulk Rock Properties  23 Michalpoulos, P., and Aller, R. C. (2004). Early diagenesis of biogenic silica in the Amazon delta: Alteration, authigenic clay formation, and storage. Geochimica Cosmochimica Acta, 68, 10611085. Milliken, K., Choh, S.‐J., Papazis, P., and Schieber, J., 2007a, “Cherty” stringers in the Barnett Shale are agglutinated foraminifera. Sedimentary Geology, 198, 221–232. Milliken, K. L. (1989). Petrography and composition of authigenic feldspars, Oligocene Frio Formation, South Texas. Journal of Sedimentary Petrology, 59, 361–374. Milliken, K. L. (1992). Chemical behavior of detrital feldspars in mudrocks versus sandstones, Frio Formation (Oligocene), South Texas. Journal of Sedimentary Petrology, 62, 790–801. Milliken, K. L. (1994). Cathodoluminescent textures and the origin of quartz silt in Oligocene mudrocks, South Texas. Journal of Sedimentary Research, 64A, 567–571. Milliken, K. L. (2004). Late diagenesis and mass transfer in sandstone‐shale sequences. In Mackenzie, F. T. (Ed.) Sediments, Diagenesis, and Sedimentary Rocks (Vol. 7, pp. 159–190). Oxford, Elsevier‐Pergamon. Milliken, K. L. (2013). SEM‐based cathodoluminescence imaging for discriminating quartz types in mudrocks, Unconventional Resources Technology Conference, Denver, Colorado, 2013, American Asssociation of Petroleum Geologists and Society of Petroleum Engineers, URTeC 1582467. Milliken, K. L. (2014). A compositional classification for grain assemblages in fine‐grained sediments and sedimentary rocks. Journal of Sedimentary Research, 84, 1185–1199. Milliken, K. L. (2019). Compactional and mass‐balance constraints inferred from the volume of quartz cementation in mudrocks. In Camp, W., et  al. (Eds.) Mudstone Diagenesis. New Research Perspectives for Shale Hydrocarbon Reservoirs, Seals, and Source Rocks, AAPG Memoir (Vol. 161). Tulsa, OK, The American Association of Petroleum Geologists. Milliken, K. L., and Choh, S.‐J. (2011). Carbonate Petrology: An Interactive Petrography Tutorial, v. 1.0, Discovery Series (Vol. 15). Tulsa, OK, DVD. Milliken, K. L., Choh, S.‐J, and McBride, E. F. (2007b). Sandstone Petrology. A Tutorial Petrographic Image Atlas, 2.0, Discovery Series (Vol. 10). Tulsa, OK, American Association of Petroleum Geologists, DVD. Milliken, K. L., and Curtis, M. E. (2016). Imaging pores in sedimentary rocks: Foundation of porosity prediction. Marine and Petroleum Geology, 73, 590–608. Milliken, K. L., and Day‐Stirrat, R. J. (2013). Cementation in mudrocks. Brief review with examples from cratonic basin mudrocks. In Chatellier, J.‐Y. and Jarvie, D. M. (Eds.) Critical Assessment of Shale Resource Plays, AAPG Memoir (Vol. 103, pp. 133–150). Tulsa, OK, American Association of Petroleum Geologists, DVD. Milliken, K. L., and Zhang, T. (2019). Mineral diagenetic control on hydrocarbon expulsion in organic-rich mudrocks, Bakken Formation, North Dakota U.S.A.: Proceedings, Sixth EAGE Shale Workshop, April 28-May 1, Bordeaux, France, European Association of Geoscientists and Engineers, DOI 10.3997/2214-4609.20190028. Milliken, K. L., Ergene, S. M., and Ozkan, A. (2016), Quartz types, authigenic and detrital, in the Upper Cretaceous Eagle

Ford Formation, South Texas, USA. Sedimentary Geology, 339, 273–288. Milliken, K. L., Esch, W. L., Reed, R. M., and Zhang, T. (2012a). Grain assemblages and strong diagenetic overprinting in siliceous mudrocks, Barnett Shale (Mississippian), Fort Worth Basin, Texas, U.S.A. AAPG Bulletin, 96, 1553–1578. Milliken, K. L., Ko, L., Pommer, M., and Marsaglia, K. M. (2014). SEM petrography of eastern Mediterranean sapropels: Analogue data for assessing organic matter in oil and gas shales. Journal of Sedimentary Research, 84, 961–974. Milliken, K. L., and Land, L. S. (1993). The origin and fate of silt‐sized carbonate in subsurface Miocene‐Oligocene mudrocks, South Texas Gulf Coast. Sedimentology, 40, 107–124. Milliken, K. L., Mack, L. E., and Land, L. S. (1994). Elemental mobility in sandstones during burial: Whole‐rock chemical and isotopic data, Frio Formation, South Texas. Journal of Sedimentary Research, A64, 788–796. Milliken, K. L., McBride, E. F., Cavazza, W., Cibin, U., Fontana, D., Picard, M. D., and Zuffa, G. (1998). Geochemical history of calcite precipitation in Tertiary sandstones, Northern Apennines, Italy. In Morad, S. (Ed.). Carbonate Cementation in Sandstones: Distribution Patterns and Geochemical Evolution, Special Publication (Vol. 26, pp. 213– 240). International Association of Sedimentologists. Milliken, K. L., McCarty, D. K., and Derkowitz, A. (2018). Grain assemblages and diagenesis in the tarl‐dominated Lower Silurian mudrock succession of the western margin of the east European craton in Poland and Lithuania. Sedimentary Geology, 374, 115–133. Milliken, K. L., and Olson, T. (2017). Silica diagenesis, porosity evoluiton, and mechanical behavior in siliceous mudstones, Mowry Shale (Cretaceous), Rocky Mountains, U.S.A. Journal of Sedimentary Research, 87, 366–387. Milliken, K. L., Papazis, K., Day‐Stirrat, R. J., and Dohse, C. (2012b). Carbonate lithologies of the Barnett Shale. In Breyer, J. (Ed.) Shale Reservoirs—Giant Resources for the 21st Century, AAPG Memoir (Vol. 97, pp. 290–321). Tulsa, OK, The American Association of Petroleum Geologists. Milliken, K. L., and Reed, R. M. (2010). Multiple causes of diagenetic fabric anisotropy in weakly consolidated mud, Nankai accretionary prism, IODP Expedition 316. Journal of Structural Geology, 32, 1887–1898. Milliken, K. L., Rudnicki, M., Awwiller, D. N., and Zhang, T. (2013). Organic matter‐hosted pore system, Marcellus Formation (Devonian), Pennsylvania, USA. AAPG Bulletin, 97, 177–200. Milliken, K. L., Shen, Y., Ko, L. T., and Liang, Q. (2017). Grain composition and diagenesis of organic‐rich lacustrine tarls, Triassic Yanchang Formation, Ordos, Basin, China. Interpretation, 5, SF189–SF210. Mlynarczuk, M., and Skiba, M. (2017). The application of artificial intelligence for the identification of the maceral groups and mineral components of coal. Computers and Geosciences, 103, 133–141. Mondol, N. H., Bjorlykke, K., Jahren, J., and Hoeg, K. (2007). Experimental mechanical compaction of clay mineral aggregates: Changes in physical propeties of mudstones during burial. Marine and Petroleum Geology, 24, 289–311.

24  Shale: Subsurface Science and Engineering Nole, M., Daigle, H., Milliken, K. L., and Prodanovic, M. (2016). A method for estimating microporosity of fine‐ grained sediments and sedimentary rocks via SEM image analysis. Sedimentology, 63, 1507–1521. Oertel, G. (1983). The relationship of strain and preferred orientation of phyllosilicate grains in rocks‐a review. ­ Tectonophysics, 100, 413–447. Oertel, G., and Curtis, C. D. (1972). Clay‐ironstone concretion preserving fabrics due to progressive compaction. Geological Society of America Bulletin, 83, 2597–2606. Passey, Q. R., Bohacs, K. M., Esch, W. L., Kimentidis, R., and Sinha, S. (2010). From oil‐prone source rock to gas‐producing shale reservoir: Geologic and petrophysical characterization in unconventional shale‐gas reservoirs, CPS/SPE International Oil & Gas Conference and Exhibition, Beijing, China, 2010, Society of Petroleum Engineers, SPE 121250. Patzek, T. W., Male, F., and Marder, M. (2013). Gas production in the Barnett Shale obeys a simple scaling theory. Proceedings of the National Academy of Science, 110, 19731–19736. Paxton, S. T., Szabo, J. O., Adjukiewicz, J. M., and Klimentidis, R. E. (2002). Construction of an intergranular volume compaction curve for evaluating and predicting compaction and porosity loss in rigid‐grain sandstone reservoirs. AAPG Bulletin, 86, 2047–2067. Petrelli, M., and Perugini, D. (2016). Solving petrological problems through machine learning; the study case of tectonic discrimination using geochemical and isotopic data. Contributions to Mineralogy and Petrology, 171, no. 10, doi: 10.1007/s00410‐016‐1292‐2. Pommer, L., Gale, J. F. W., Eichhubl, P., Fall, A., and Laubach, S. E., (2013). Using structural diagenesis to infer the timing of natural fractures in the Marcellus Shale, Proceedings Unconventional Resources Technology Conference, Denver, Colorado, 2013, SPE‐AAPG‐SEG, SPE 168770/URTeC 1580135. Pommer, M. E., and Milliken, K. L. (2015). Pore types and pore‐size distributions across thermal maturity, Eagle Ford Formation, South Texas. AAPG Bulletin, 99, 1713–1744. Potter, E., Maynard, J. B., and Depetris, J. (2005). Mud and Mudstones: Introduction and Overview. Berlin, Federal Republic of Germany, Springer‐Verlag, 297 pp. Radlinski, A. P., Ioannidis, M. A., Hinde, A. L., Hainbuchner, M., Baron, M., Rauch, H., and Kline, S. R. (2004a). Angstrom‐to‐millimeter characterization of sedimentary rock microstructure. Journal of Colloid and Interface Science, 274, 607–612. Radlinski, A. P., Mastalerz, M., Hinde, A. L., Hainbuchner, M., Rauch, H., Baron, M., Lin, J. S., Fan, L., and Thiyagarajan, P. (2004b). Application of SAXS and SANS in evaluation of porosity, pore size distribution and surface area of coal. International Journal of Coal Geology, 59, 245–271. Rowan, E. L., Engel, M. A., Draemer, T. F., Schroeder, K. T., Hammack, R. W., and Doughten, M. W. (2015). Geochemical and isotopic evolution of water producted from Middle Devonian Marcellus shale gas wells, Appalachian basin, Pennsylvania. AAPG Bulletin, 99, 181–206. Rubinstein, N., Fazio, A. M., Scasso, R. A., and Carey, S. (2013). Association of phosphate with rhyolite glass in marine Neogene tuffs from Patagonia, Argentina. Sedimentology, 60, 1007–1016.

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2 Chemical Composition of Formation Water in Shale and Tight Reservoirs: A Basin‐Scale Perspective Yousif Kharaka1, Kathleen Gans1, Elisabeth Rowan2, James Thordsen1, Christopher Conaway1, Madalyn Blondes2, and Mark Engle2,3

ABSTRACT The salinity of pore waters in petroleum reservoir rocks, including shale and tight reservoirs, varies from ~1000 to >400,000 mg/L TDS. Detailed chemical and isotopic data for >115,000 produced‐water samples, listed in our USGS Database, show the waters are of meteoric, marine connate, or mixed origin. During diagenesis, waters of deposition evolve to Na–Cl‐, Na–Cl–CH3COO‐, or Na–Ca–Cl‐type waters by a combination of several processes: (i) dissolution of halite; (ii) diffusion and advection near salt domes; (iii) reflux and incorporation of bittern water; (iv) dissolution, precipitation, and transformation of minerals; (v) interactions with shales that behave as geologic membranes; and (vi) interactions with petroleum, solid organics, and bacteria. Geochemical data of pore waters in shale and tight reservoirs have been reported in only a few detailed studies, but we have received such data from oil companies for ~15,000 samples of “flowback” and produced waters. The salinities and compositions carry large uncertainties, especially for the “flowback” samples that are a mixture of pore water and the hydraulic fracturing fluids. An important conclusion is that the chemical and isotopic data for these waters are comparable with data from conventional oil and gas wells from the same basin, at the same general T–P conditions.

2.1. ­INTRODUCTION

basins with salt domes or bedded evaporites, such as the Northern Gulf of Mexico, the Michigan, and the Williston Basins (see Kharaka and Hanor, 2014, for a recent review and many references). Salinities in sedimentary basins generally increase with depth, but the rate of increase is highly variable and variations can be large in formation waters from different areas of the same basin or subbasin and even in waters from the same petroleum field. Where evaporites are absent and thick shale beds are present in the geologic section, such as the Central Valley, California, and the southern Louisiana and southwestern Texas Gulf Coast, salinities are lower and show reversals with depth (Fig. 2.1). Chemical analyses of formation water from some gas wells, especially those from reservoirs at temperatures higher than 100 °C, may not represent the true chemical composition of formation waters from the production zones because of dilution by mixing with condensed

Pore waters comprise ~20% by volume of most sedimentary basins. Petroleum reservoirs are generally present below the zone of shallow meteoric groundwater circulation, and have in situ temperatures of ~20 °C to more than 150 °C and fluid pressures of about 100 to more than 1000 bar. The salinity of pore waters in petroleum reservoir rocks, including shale and other low permeability reservoirs (the unconventional sources of oil and natural gas), varies widely from ~1000 mg/L to over 400,000  mg/L total dissolved solids (TDS). Salinities higher than ~100,000 mg/L TDS are generally present in  United States Geological Survey, Menlo Park, CA, USA  United States Geological Survey, Reston, VA, USA 3  Department of Geological Sciences, University of Texas at El Paso, El Paso, TX, USA 1 2

Shale: Subsurface Science and Engineering, Geophysical Monograph 245, First Edition. Edited by Thomas Dewers, Jason Heath, and Marcelo Sánchez. © 2020 American Geophysical Union. Published 2020 by John Wiley & Sons, Inc. 27

28  Shale: Subsurface Science and Engineering 0 Michigan

Illinois

Depth of reservoir rock (km)

1 Alberta

2 North Louisiana

California

3

South Louisiana Central Mississippi

4 0

100

200

300

400

500

Water salinity (g/L)

Figure 2.1 Salinity distribution with depth of the reservoir rocks from several basins in North America. Note the different trends and the reversal of salinity in California and south Louisiana. Reproduced from Kharaka and Thordsen (1992).

water vapor produced with natural gas. This problem is particularly severe in wells that produce small volumes of water relative to the amount of natural gas, 100,000 mg/L) brines present in many sedimentary basins where evaporites are, or were, present. Congruent and incongruent dissolution and precipitation reactions, other than for halite, that probably control the major cation compositions of formation waters include dolomitization of limestone, resulting in a major increase of calcium and a major decrease of magnesium, as in reaction (2.1):

6.0

A

F

dis s. Na CI

Coastal Texas and

50 %

mi x

+

Louisiana

4.5 S.W.

4.0 1.0

C 50%

5.0

50 %

Log Cl (mg/L)

5.5

10%

100%

B

50%

Mixing line S.W. + Norph. W.

Mg 2

2CaCO3 s



CaMg CO3

2 s

Ca 2 (2.1)

10%

The albitization of plagioclase feldspar, as in reaction (2.2), also increases calcium concentrations but lowers the concentration of sodium:

Mixing line M.W. + Norph. W. E

D

2.0

3.0

Na 0.7 Ca 0.3 Al1.3Si2.7 O8 s

4.0

Log Br (mg/L)

0.6 Na

andesine

Figure 2.3  Distribution of Cl and Br in formation waters from the central Mississippi Salt Dome Basin relative to the evaporation line for seawater (SW, A–B) and mixing lines between Norphlet water (Norph. W) with meteoric (MW) and with sea (SW) waters. Line E–F gives the trend when the mixture of meteoric and Norphlet waters dissolves halite with 70 ppm Br. Line C–D gives the trend where 50% of the Cl concentration in the mixture of meteoric and Norphlet waters is from the dissolution of halite. Note that the samples from coastal Texas and Louisiana (dashed field) plot in a field with lower Br/Cl ratios. Modified from Kharaka and Thordsen (1992).

1.2SiO2 s quartz

1.3NaAlSi3 O8 0.3Ca 2



Finally, clay transformations, especially the conversion of smectite to mixed‐layer smectite‐illite and finally to illite, are extremely important reactions in many sedimentary basins where thick shale beds are present at temperatures higher than ~80 °C. For the northern Gulf of Mexico Basin, several incongruent reactions conserving Al or maintaining a constant total volume have been proposed for this transformation (Boles and Franks, 1979). Reaction (2.3) from

10 Normal seawater chlorinity

Illinois Basin

Concentration in brine versus concentration in seawater

Ca

1

Na K Mg

0.1

HCO3 SO4 0

20

40

60

(2.2)

albite

80

100

120

140

Chloride (‰)

Figure 2.4  Generalized relative variations in the composition of major ions in formation waters from the Illinois Basin. The normalized ratios indicate that relative to seawater, the formation waters are always depleted in SO4, Mg, and K but that they become progressively enriched in Ca and K and depleted in HCO3 with increasing chlorinity. Reproduced from Kharaka and Hanor (2014).

32  Shale: Subsurface Science and Engineering

Kharaka and Hanor (2014), conserving both Al and Mg and precipitating chlorite, quartz, and illite, is probably a closer approximation to the field situation based on the composition of formation water observed in the northern Gulf of Mexico Basin.

10.8H

3.81K

1.69KNaCa 2Mg 4Fe 4 Al14Si38O100 OH

10H2 O

K 5.5Mg 2Fe1.5 Al22Si35O100 OH

1.59Mg3Fe2 AlSi3O10 OH 22.8H2O 1.69Na

8

3.38Ca 2

24.4SiO2 s 2.06Fe3

20

20

(2.3)

The Fe3+ in this reaction will be reduced by organics to Fe2+ and some may precipitate as pyrite or ankerite. The overall reaction consumes large amounts of K and H+ and adds important amounts of Ca, Na, and some Fe2+ to the pore water. The concentrations and proportions of strontium, barium, and iron are generally higher than those in ocean water and increase with increasing calcium concentration and chlorinity. The ratios of lithium, potassium, rubidium, and cesium to sodium generally increase with increasing subsurface temperature, but again, there is a great deal of scatter in the data and their proportions vary from basin to basin (Kharaka and Thordsen, 1992; Hanor, 2001). Plots of cation concentrations versus chloride show 1 : 1 slope on log–log plots for Na and K, but a 2  :  1 slope for divalent cations Mg, Ca, and Sr. This difference in the rate of increase of Na and Ca with Cl (salinity) can be accounted for largely by rock buffering (Hanor, 2001) and gives rise to the observed progression from Na–Cl to Na–Ca–Cl to Ca–Na–Cl waters with increasing salinity in basinal waters (Hanor, 1987; Davisson and Criss, 1996). The Li/Na, K/Na, and Rb/Na ratios in basinal brines generally increase with increasing temperatures. The proportions of alkali metals alone or combined with those of alkaline earth metals, magnesium and calcium in particular, and the concentrations of SiO2 are so strongly dependent on subsurface temperatures of the reservoir rocks that they have been combined into several chemical geothermometers (see table 4 in Kharaka and Hanor, 2014) that can be used to estimate the reservoir temperatures (Kharaka and Mariner, 1989; Pang and Reed, 1998). The most useful “chemical markers” for increasing subsurface temperatures are the concentrations of silica, boron, and ammonia, and the Li/Mg, Li/Na, and K/Na ratios. Chloride is by far the dominant (>90%) anion in nearly all basinal formation waters and explaining the origin of saline waters in sedimentary basins is, to some degree, the problem of explaining the origin of the dissolved chloride. Chloride and bromide, as explained above, are fairly

closely coupled in their subsurface geochemistry, and are the best criteria for distinguishing brine formed by dissolution of halite from those formed by subaerial evaporation of seawater (Fig. 2.3). Bromide is depleted in halite as it concentrates in the bittern water. This leads to lower Br/Cl ratios and the trend of the Cl–Br plot for the pore waters in parts of the Gulf Coast with salt domes relative to evaporated seawater past halite precipitation (Fig. 2.3), which is responsible for the high‐salinity brines with higher Br/Cl ratios obtained from the central Mississippi Salt Dome Basin (Carpenter, 1978; Kharaka et al., 1987). In contrast to chloride and bromide, the other dissolved halogens, fluoride and iodide, have distinctly different systematics in basinal waters, with iodide controlled by partitioning into organic matter and fluoride controlled by the solubility of fluorite (Kharaka and Thordsen, 1992; Hitchon, 1995; Lu et  al., 2014). Ammonia and, to a lesser degree, Br are also influenced by the type and maturity of organic matter in reservoir rocks (Engle et al., 2016). Polyatomic anions, sulfate and bicarbonate, controlled by the solubility of their salts with Ca and other divalent cations decrease with increasing chlorinity and are depleted relative to their values in seawater (Fig.  2.4). Acetate and other short‐ chain aliphatic acid anions may comprise a substantial portion of total anions, especially in the Na–Cl– CH3COO‐type waters that are present mainly in Cenozoic reservoir rocks at temperatures of 80–120 °C. In these waters, acetate and other organic acid anions can reach concentrations of up to 10,000 mg/L and contribute up to 99% of the measured alkalinities (Willey et  al., 1975; Crossey et al., 1986; Hanor and Workman, 1986; Kharaka et al., 2000). 2.3. ­FORMATION WATER IN SHALE AND TIGHT RESERVOIRS Almost all the chemical and isotopic data currently available for deeper sedimentary basins, as already stated, have been obtained from produced water collected while drilling for or during production of conventional oil and gas. Starting in 1991, but mainly in the last 10 years, production of gas and oil from shale, siltstones, and other very low permeability (12 months and grab samples from Marcellus Shale gas wells in Pennsylvania and West Virginia are used by Rowan et  al. (2015), Engle and Rowan (2014), and Haluszczak et  al. (2013) to address the origin of the water and solutes produced over the long term. After chemical steady states are reached, which can take many months (Fig.  2.6), the chemical parameters show Na–Ca–Cl-type brines with extremely high salinities (≥200,000 mg/L TDS) that are similar to those in produced water brines from conventional oil and gas wells in the region tapping permeable host formations ranging in age from Ordovician to Devonian (Figs.  2.5 and 2.6). The Cl–Br–Na relationships, including the relatively high Br/Cl ratios, indicate that the brines are bittern water originating from evaporation of ancient seawater past halite precipitation (see line A, C, and B in the Cl–Br plot in Fig. 2.3); some dilution and mixing with modified seawater is also possible. The chemical and isotopic data, including 87Sr/86Sr ratio, show that the water originated in the Marcellus Shale and the solutes

34  Shale: Subsurface Science and Engineering 350,000 Well A, Greene Co. (time series) Well B, Greene Co. (time series)

300,000

Well C, Greene Co. (time series) Well D, Greene Co. (vertical) U. Dev. Ss wells, Greene Co.

250,000 TDS (mg/L)

Tioga Co. wells

200,000

150,000

100,000

50,000

-

0

1

10

1000

100

10,000

Time from begining of production (days)

Figure 2.5  Salinity time series for three unconventional gas wells and grab samples from unconventional (Tioga Co. wells) and conventional (well D, and U. Devonian sandstone) wells completed in the Marcellus Shale in Pennsylvania. Day 0 refers to the composition of the hydraulic fracturing fluid minus proppant. Note that more than a year of production is required before the compositions of produced waters reach steady states.

100,000

Concentration (mg/L)

10,000 Sr Ba Li

1000

Na Ca K Br

100

10

0

1

10 Day

100

1000

Figure 2.6  Time series for element concentrations in Marcellus Shale produced waters from well B, located in Green County, Pennsylvania. Day 0 refers to the composition of the hydraulic fracturing fluid minus proppant. Note that the element concentrations continue to increase, but the trends are not linear and values do not reach steady states for many months of petroleum production.

Chemical Composition of Formation Water in Shale and Tight Reservoirs  35

enhance the management of produced water, for determining the suitability of water reuse and for identifying regions where nonpotable hydraulic fracturing water may be obtainable. Results show that for the same basin/subbasin and general depth, the chemical and isotopic data from the 15,000 samples from unconventional wells are generally comparable with values obtained from more than 100,000 wells currently listed in the same USGS Produced Waters Geochemical Database, but collected from conventional oil and gas wells (Blondes et al., 2017). In the case of the 118 shale gas samples received from Cimarex Energy and obtained from the Devonian Woodford/Cana Shale located in the Anadarko Basin of Oklahoma, the salinity values (Fig.  2.7) and the Ca concentrations (Fig.  2.8) are generally in the same range of values for tight oil samples obtained from the Woodford Formation; values for salinity and Ca concentrations obtained from conventional petroleum wells producing from non‐ Woodford formations in the larger Anadarko Basin are also comparable, even though the data show much more scatter. Geochemical data for 300 samples from the unconventional (tight oil) and 100 samples from conventional oil wells in the prolific Late Devonian to Early Mississippian Bakken Formation of North Dakota and Montana are listed in the updated USGS National Produced Waters Geochemical Database (Blondes et al., 2017). Again, the high salinity values (Fig. 2.9) and the Ca concentrations (Fig. 2.10), to a first approximation, are generally in the same range of values for the two sets of samples. The values would be even closer if we exclude lower salinity

0

TDS (mg/L) 10,000 20,000 30,000

40,000

8000 9500 11,000 Depth (ft)

did not originate from dissolution of salts in dry shale by the injection fluids (Chapman et  al., 2012; Engle and Rowan, 2014; Rowan et al., 2015). Chemical and isotopic data from ~15,000 samples of flowback and produced waters from unconventional sources of petroleum from the major sedimentary basins in the United States have been received from oil companies and state divisions of oil and gas and recently have been compiled and added to the updated and expanded USGS Produced Waters Geochemical Database (Blondes et al., 2017). The salinities and chemical compositions of these waters carry large uncertainties, vary widely with time of sampling following petroleum production, indicating initial mixing with injection fluids, and salinities and compositions at steady states vary greatly from basin to basin. On a basin scale, results show formation waters with relatively low salinities, ~15,000–30,000 mg/L TDS, are present in the Fayetteville Shale, Arkansas; Woodford Formation, Oklahoma; and in Monterey Formation, California. Produced water salinities in Barnett Shale, Texas, and in Wolfcamp and “Cline” shales, Texas and New Mexico average ~100,000 mg/L, but higher average salinities (~200,000 mg/L) are obtained in brines from Marcellus Shale, Pennsylvania and Haynesville, Texas. mg/L) are Even higher average salinities (>250,000  observed in brine in Bakken Shale of North Dakota and Montana. The USGS National Produced Waters Geochemical Database initially had geochemical data obtained from conventional oil and gas wells and received from oil companies for ~65,000 wells (Breit et al., 2001). This database is being updated and expanded and currently has data from more than 115,000 wells that include the 15,000 samples from unconventional petroleum wells (Fig. 2.2) discussed above (Blondes et  al., 2017). Some culling of data obtained from petroleum companies occurred, resulting in reduced total number of samples listed in the databases; the relatively simple culling criteria are discussed in Breit et  al. (2001) and Blondes et  al. (2017). Even with culling, the USGS National Produced Waters Geochemical Database should be used with careful consideration of its limitations. The database is considered sufficiently accurate to provide an indication of tendencies in water salinity and composition from geographically and geologically defined areas. It is not appropriate for depiction of modern produced water compositions or examination of trends on small scales (Blondes et  al., 2017). The chemical and isotopic data listed in these databases carry large uncertainties and require additional culling and analysis, but the databases are an important resource for those interested in determining the geochemical nature of deep formation water, contamination sources, and impacts of hydraulic fracturing. Energy companies can utilize the database to

12,500 14,000 15,500

Anadarko shale gas Anadarko tight oil

17,000

Anadarko conventional

Figure 2.7 Salinity–depth distribution of produced waters obtained from conventional and unconventional oil and gas wells located in the Anadarko Basin of Oklahoma and listed in the USGS National Produced Waters Geochemical Database (Blondes et al., 2017).

36  Shale: Subsurface Science and Engineering Ca (mg/L)

Ca (mg/L) 8000

0

100

200

300

400

0 7000

9500

10,000 20,000

30,000 40,000 Bakken tight oil Bakken conventional

8000

12,500

Anadarko shale gas Anadarko tight oil

9000 10,000

Anadarko conventional

14,000

11,000

15,500

12,000

17,000

Figure 2.8  Concentrations of Ca plotted as a function of depth in produced waters obtained from conventional and unconventional oil and gas wells located in the Anadarko Basin of Oklahoma and listed in the USGS National Produced Waters Geochemical Database (Blondes et al., 2017). TDS (mg/L) 50,000 7000

150,000

250,000

350,000

8000 Bakken tight oil Bakken conventional

Depth (ft)

Depth (ft)

Depth (ft)

11,000

9000 10,000 11,000 12,000

Figure 2.9 Salinity–depth distribution of produced waters obtained from conventional and unconventional oil wells producing from the Bakken Formation in the Williston Basin of North Dakota and Montana and listed in the USGS National Produced Waters Geochemical Database (Blondes et al., 2017).

samples from unconventional oil wells that likely represent a mixture of natural formation water (~300,000 mg/L TDS) and fracturing fluid that is comprised mainly of fresh surface and shallow groundwater. 2.3.1. Shales as Geologic Membranes Interpretations of the chemical and isotopic data obtained from shale reservoirs are further complicated by the fact that the clay minerals in shale have high exchange

Figure 2.10 Concentrations of Ca plotted as a function of depth in produced waters obtained from conventional and unconventional oil wells producing from the Bakken Formation in the Williston Basin of North Dakota and Montana and listed in the USGS National Produced Waters Geochemical Database (Blondes et al., 2017).

capacity and act as semipermeable membranes. These properties of shale have been conclusively demonstrated by laboratory experimental data (Kharaka and Berry, 1973; Fritz and Marine, 1983; Whitworth and Fritz, 1994; Mazurek et al., 2015) and field evidence (Hanshaw and Hill, 1969; Berry, 1973; Kharaka and Berry, 1974). The chemical composition of water in sedimentary basins, including pore waters in shale, and the flow of water and chemicals into and out of shale following hydraulic fracturing can be significantly affected by interaction with geologic membranes as follows: 1. Compacted clays and shale serve as semipermeable membranes that retard by varying degrees (selectivity) the flow of dissolved chemical species with respect to water. Subsurface water that has flowed through a geologic membrane (effluent water) is lower in TDS and has a chemical composition different from that of the original solution (input water) or from the solution remaining in the aquifer on the input side of the membrane (hyperfiltrated water). 2. Subsurface waters squeezed from massive shale and siltstones are present in large areas in many sedimentary basins, such as the Gulf Coast (Kharaka and Berry, 1980) and the Central Valley, California (Berry, 1973; Kharaka et  al., 1985); these waters also exhibit increasing “membrane effluent” characteristics with increasing depth (increased compaction). The lowest salinities of waters in these two basins are 5,000–10,000 mg/L, and these values are about a quarter of the salinities of formation waters at comparable depths in these basins that were not affected by this process. Laboratory experiments (Kryukov et al.,

Chemical Composition of Formation Water in Shale and Tight Reservoirs  37

1962; Kharaka and Berry, 1974) have shown that water squeezed from uncompacted clays and shale has the same salinity and chemical composition as the initial solution. As compaction pressure is increased, the salinity of squeezed water decreases and shows selectivity and other membrane filtration characteristics. 3. Clay minerals have cation exchange capacities that are ~5 meq/100 g for kaolinite, 70 meq/100 g for illite, and 150 meq/100 g for smectite. The chemical composition of pore water within the double layer and membrane properties of clays are directly related to their selectivities and exchange capacities, and exchange reactions are relatively fast and can rapidly modify the composition of pore water in shale. 4. During hydraulic fracturing, a significant fraction of the injected water is imbibed into small pores in the shale, and the imbibition process may continue over a period of weeks to months (Roychaudhuri et al., 2011). The composition of imbibed water will be determined not only by the mixing between the pore water and injected fluid but also by the membrane properties of shale. The chemical composition of produced water in shale reservoirs will be impacted by their membrane properties, and the chemicals in the fracturing fluids will mix with those present in shale pore water, but this mixing is not simple and proportional as it would be complicated by selective exchange with chemicals on the mineral exchange sites and within the “Stern” layer. Exchange selectivities and retardation factors for dissolved species need to be determined and understood for shale minerals and pore waters in order to obtain accurate results from simulations of water‐mineral interactions resulting from hydraulic fracturing and petroleum production from shale (see Warren and Smalley, 1994; Kharaka and Hanor, 2014; and references therein for more details on this topic). 2.4. ­ENVIRONMENTAL IMPACTS OF SHALE GAS AND TIGHT RESERVOIRS: WATER USE AND WASTE‐WATER DISPOSAL CHALLENGES Exploration for and production of shale gas cause major local surface land disturbance, air and noise pollution, and habitat fragmentation and other ecological impacts (US EPA, 2011, 2015; Gregory et al., 2011; Warner et al., 2013, 2014; Arthur and Cole, 2014; Skalak et  al., 2014). Potential contamination of surface water and groundwater is the major environmental concern (Rostrom and Arkadakskiy, 2014; National Academy of Sciences, 2015; Molofsky et  al., 2016; Harkness et  al., 2017; McMahon et al., 2017; Nicot, 2017; Vengosh et al., 2017; Soeder and Kent, 2018). However, communities in some impacted areas are also concerned about the possibility of induced seismicity (Vidic et  al., 2013; Vengosh

et al., 2014). Except for a few known events, most known injection‐induced earthquakes do not happen during the relatively short time of hydraulic fracturing, but are associated with produced water disposal activities. There is evidence that recent, moderately strong earthquakes (magnitude 4.0–5.8) that occurred in shale gas‐producing areas in Arkansas, Colorado, Ohio, Oklahoma, and Texas were induced by produced water disposal or other gas‐ and oil‐related activities (Ellsworth et  al., 2012; National Academies Press, 2012; Ellsworth, 2013; Rubinstein and Mahani, 2015). The shale gas is held in pore spaces and natural fractures or is adsorbed onto the organic material (kerogen) and clay minerals in the formation. Shale total porosity (5–10%) is moderate, but the natural permeability of shale is extremely low (in nanodarcies) requiring horizontally completed wells (up to 3500 m long) and massive, multistage hydraulic fracturing to create pathways for the gas to flow into the well at economic rates. Significant volumes of water, ~500 m3/well for Marcellus Shale to 5000 m3/well for the deeper Haynesville Shale, are also used for drilling the gas wells. Because several hundred wells (Fayetteville and Haynesville Shale) and close to 1000 (Barnett and Marcellus Shale) wells were completed during peak years, the total volume of fresh water used for drilling and fracturing in some cases is high, approaching 10 million m3/year for the Barnett and Marcellus Shale (GWPC and ALL Consulting, 2009). Calculations show that the total water used for drilling and fracturing shale gas wells is relatively low compared to the consumptive total water (surface and groundwater) usage in wet regions (e.g., 0.06% of available water for the Marcellus Shale); but is much higher in arid regions (0.4% for the Barnett Shale and 0.8% for the Haynesville Shale) where water needed for shale gas could be a significant constraint for gas development because its use could impact the available water supply for domestic, irrigation, or other uses (GWPC and ALL Consulting, 2009; Nicot and Scanlon, 2012). Reclaiming produced water for reuse is rather expensive but possible where water salinity is relatively low (250,000 mg/L) are observed in brines obtained from the Bakken Shale, North Dakota, and Montana. An important initial conclusion from these data is that for the same basin and general T–P conditions, the chemical and isotopic data for these samples are comparable with data from more than 160,000 samples currently listed in the same USGS National Produced Waters Geochemical Database, but collected from conventional oil and gas wells (Blondes et al., 2017). There are several important questions that need to be investigated further to improve our understanding of the geochemistry of natural formation waters in shale and tight reservoirs, and to minimize potential environmental impacts, especially groundwater contamination, related to exploration and production operations. These investigations include: (i) the spatial and temporal contamination of pore water in shale with drilling and fracturing fluids, using natural and man‐made chemical and isotopic tracers; (ii) detailed differences in the chemical and isotopic compositions of produced water obtained from shale and tight reservoirs and from adjoining conventional reservoirs from the same basin/subbasin and at comparable T and P conditions; (iii) importance of geological membranes in controlling the flow of solutes through shale and out of shale: investigate ionic selectivities and membrane efficiencies; (iv) the role of organic matter (quantity, type, and maturity) in modifying the chemical composition of pore water and the general behavior of shale; and (v) the lists of chemicals added to the fracturing fluids, their toxicity, and interactions with natural fluids and rocks.

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3 From Nanofluidics to Basin‐Scale Flow in Shale: Tracer Investigations Yifeng Wang

ABSTRACT Understanding fluid flow and transport in shale is of great importance to the development of unconventional hydrocarbon reservoirs and nuclear waste repositories. Tracer techniques have proven to be a useful tool for gaining such understanding. Shale is characterized by the presence of nanometer‐sized pores and the resulting extremely low permeability. Chemical species confined in nanopores could behave drastically differently from those in a bulk system and the interaction of these species with pore surfaces is much enhanced due to a high surface/fluid volume ratio, both of which could potentially affect tracer migration and chromatographic differentiation in shale. Nanoconfinement manifests the discrete nature of fluid molecules in transport, there­ fore enhancing mass‐dependent isotope fractionations. All these effects combined lead to a distinct set of tracer signatures that may not be observed in a conventional hydrocarbon reservoir or highly permeable groundwater aquifer system. These signatures can be used to delineate flow regimes, trace fluid sources, and quantify the rate and extent of a physical/chemical process. Such signatures can be used for the evaluation of cap rock structural integrity, the postclosure monitoring of a geologic repository, or the detection of a possible contamination in a water aquifer by a shale oil/gas extraction.

3.1. ­INTRODUCTION

permeability, as a  rule of thumb, a significant advective flow would be possible in a shale formation only if the formation is intercepted by a connected fracture network. In shale gas production by hydrofracturing, methane and other gases first release from a shale matrix and diffuse into the surrounding induced fractures, and then advectively trans­ port from fractures to a production well (Ho et al., 2016). Similarly, a basin‐scale advective fluid communication may occur across shale formations in a sedimentary basin only if the formations are dissected by high‐angle fractures or faults. Since the flow rate in fractures is usually high, mass transfer in a shale matrix is expected to be a limiting step for the overall process. The low permeability of shale is attributed to the predom­ inant presence of nanometer‐sized pores (~1–100 nm) (Clarkson et al., 2013). Recent studies show that chemical species confined within such small pores would behave drastically differently from those in a bulk system (Wang, 2014). As discussed below, nanopore confinement may

Understanding fluid flow and transport in shale is of great interest to the extraction of oil/gas from an unconventional hydrocarbon reservoir and to the development of a deep geologic repository for long‐term disposal of spent nuclear fuel as well as to CO2 sequestration and storage (Javadpour et al., 2007; Heath et al., 2009; Hendry et al., 2015). Shale formations, generally treated as impermeable aquitards in hydrology, have extremely low permeability (10−19 to 10−21 m2) (Boisson et  al., 2001; Monteiro et  al., 2012). The existing knowledge about fluid flow in porous media, obtained mostly from conventional hydrocarbon reservoirs or ground­ water aquifers, may not be transferable to shale formations. For example, a fluid flow in shale may not follow the tradi­ tional Darcy law (e.g., Fathi et al., 2012). Because of the low Nuclear Waste Disposal Research and Analysis, Sandia National Laboratories, Albuquerque, NM, USA

Shale: Subsurface Science and Engineering, Geophysical Monograph 245, First Edition. Edited by Thomas Dewers, Jason Heath, and Marcelo Sánchez. © 2020 American Geophysical Union. Published 2020 by John Wiley & Sons, Inc. 45

46  SHALE: SUBSURFACE SCIENCE AND ENGINEERING

have important ramifications to tracer migration and iso­ tope fractionation, giving rise to a set of tracer signatures that may not be observed in a conventional hydrocarbon reservoir or highly permeable groundwater aquifer system. These signatures can be used to delineate flow regimes, trace fluid sources, and quantify the rates of physical and chemical processes involved. The objective of this chapter is to highlight some recent progress in tracer studies related to multiscale fluid flows in shale for­ mations and to illustrate how nanoscale processes affect large‐scale tracer signatures. 3.2. ­ENVIRONMENTAL TRACERS Tracers are identifiable entities or features that can be used to infer the sources or behaviors of fluids in a geologic system (Evans, 1983; Leibundgut et  al., 2009). They can broadly be categorized into two groups by their origins: environmental tracers, which are naturally pre­ sent in geologic media (including those accidently intro­ duced by anthropogenic activities); and artificial tracers, which are deliberately introduced into the media for a specific purpose. For reference, the list of environmental tracers commonly used in shale research is provided in Table 3.1. Most common tracers are isotopes of chemical elements. D/H and 18O/16O are two commonly used ­isotope couples in groundwater studies. A small variation in isotopic composition is determined with a mass spec­ trometer and described by the difference between a stan­ dard sample and a measured sample (Evans, 1983):



1000

Rsample Rstandard ‰ (3.1) Rstandard

1



ln

2

b T

a

1 2

c (3.2) T2

where α1 − 2 is the fractionation factor R1/R2; T is the abso­ lute temperature; and a, b, and c are constants. Equilibrium isotope fractionations usually decrease as the temperature increases, and at equilibrium a heavy iso­ tope of an element tends to be concentrated in a sub­ stance where that element forms strong bonds (Schauble, 2004). Thus, moisture evaporated from seawater is depleted in D and 18O. As shown in Figure 3.1, δD and δ18O values for modern precipitation, surface water, and groundwater roughly fall on a meteoric water line or an evaporation line, with glacial meltwater towards the most negative end (Evans, 1983; Leibundgut et al., 2009). Kinetic isotope fractionations are also common in nature. Such fractionations are usually driven by the effect of iso­ tope mass on molecule velocities and diffusivities (Schauble, 2004). For example, in diffusion of a trace gas X with mass mX through a medium with mass mY, the diffusivity ratio of a light to a heavy isotope can be related to the masses by: 1 Dlight X Dheavy X

mlight X 1 mheavy X

1 mY 1 mY

(3.3)

where Dlight X and Dheavy X are the diffusivities of light and heavy isotopes of X, respectively. This kinetic effect may play an important role in isotope fractionation in shale as discussed below. –20

where R is the ratio of a heavy isotope to a light isotope. The isotopic enrichment between two coexisting phases can be expressed by:

–25 –30

1) t (5: wa n o i c ri rat eo vapo et E M ) (3:1 tion a r t i f Ultra

Environmental tracers Stable isotopes H 18 O 13 C 3 He 4 He 87 Sr/86Sr 11 B 7 Li Dissolved geochemical species Cl− Br− I− 2

Radioactive isotopes C 129 I 234 U/238U   Noble gases Xe Ar Kr Physical chemical parameters Pressure anomaly 14

δD (‰)

–35

Table 3.1  List of Environmental Tracers Used in Shale Research.

1)

8:

( er

–40 –45 –50 –55 –60

–70 –10

er

at

–65

w elt

M –9

–8

–7 δ18O

–6

–5

–4

(‰)

Figure 3.1  δD–δ18O relationships for waters originating from precipitation, evaporation, and ultrafiltration, characterized by different slopes. Data points are for waters extracted from Opallinus Clay at Benken (Switzerland) (Mazurek et al., 2009).

From Nanofluidics to Basin‐Scale Flow in Shale  47

Radioactive isotopes have been used for groundwater dating (IAEA, 2013). The age of a fluid can be calculated by:

t

t1/ 2 N 0 ln ln 2 N

(3.4)

where t1/2 is the half‐life of a radionuclide used; N0 and N are the original and the current numbers of atoms of the radionuclide, respectively. Applicability of a specific iso­ tope depends on the timescale of a geochemical/hydro­ logic process of concern, ranging from thousands to millions of years. Radionuclides commonly used for geo­ fluid dating include 14C, 4He, 234U/238U, 129I, and so on. Dissolved chemical species that have no or very weak interactions with host geologic media can also be used as environmental tracers. Good examples include Cl−, Br−, I−, noble gases, and others. Anionic species such as Cl−, Br−, and I− are widely used in hydrology, due to their near‐zero adsorption coefficients. However, it should be aware that their chemical behaviors can be significantly modified in shale pores due to nanocon­ finement (Wang, 2014). Noble gases are useful tracers for tracing geofluid sources and migration pathways due to their chemical inertness (e.g., Ballentine, 1991; Gilfillan et al., 2011). Noble gases derive from three dis­ tinct sources: the crust, the mantle, and the atmosphere. Crustal noble gases such as 4He and 40Ar are produced from the spontaneous fission of uranium, thorium, and potassium in crustal rocks while mantle noble gases such as 3He were trapped during Earth accretion and released from mantle degassing. Atmospheric noble gases such as 20Ne are dissolved in surface water and enter the subsurface through groundwater recharge. The distinct characteristics of the three sources may allow us to determine the relative contribution of each source to a specific geofluid. Some physical parameters can also be used as tracers. For example, geothermal heat has been used to detect large‐scale upwelling groundwater flows (Saar, 2011). A minimal permeability (>5 × 10−17 m2) is generally required for a significant heat transfer by an advective ground­ water flow. The tracer of geothermal heat may not be applicable to shale formations, which are known for their extremely low permeability (10−19 to 10−21  m2) (Boisson et  al., 2001; Monteiro et  al., 2012). However, other physical characteristics could be useful. For example, abnormal fluid pressures have been proposed as an indicator of a slow relaxation of fluid flow in shale in response to an external mechanical disturbance such as glaciation and deglaciation (Neuzil, 1995). In contrast to aforementioned environmental tracers, artificial tracers are much less used in the study of fluid flow in shale. This is because an actual field‐scale flow test in a shale environment is in general not feasible. One

potential application of artificial tracers is the character­ ization of a fracture system created by hydrofracturing in a shale formation. In this case, artificial tracers may pro­ vide valuable information regarding the stimulated volume of hydrofracturing. Artificial tracers such as engineered (smart) nanoparticles may be particularly useful for such applications (Subramanian et al., 2013). 3.3. ­NANOFLUIDICS IN SHALE Recently developed nanofluidics and nanogeochemis­ try provide important insights into fluid flow and trans­ port in shale. Shale can be viewed as a naturally occurring nanocomposite characterized by the presence of nano­ meter‐scale pores (Chalmers and Bustin, 2008; Clarkson et al., 2013). The porosity of shale is dominated by pores of ~1–100 nm in diameter (Fig. 3.2). This pore size distri­ bution has important implications to fluid flow and transport in shale (Wang, 2014 and references therein). Nanopore confinement can significantly modify the physical and chemical properties of a chemical species. Figure 3.3 shows the freezing point depression of water in nanoconfinement (Shimizu et  al., 2015), which may be responsible for the observed increase in unfrozen water content in clay‐rich formations as compared to other for­ mations in a permafrost region (Osterkamp and Burn, 2002; Wang, 2014). One important modification to water properties by nanoconfinement is the reduction in dielectric constant. Molecular dynamics (MD) simulations show that the dielectric constant of water in a nanoscale cavity is signif­ icantly smaller than that of the corresponding bulk phase (Senapati and Chandra, 2001). The reduction in dielectric constant inevitably leads to the decrease in the solvation energy of a cation or an anion in aqueous solutions (Wang, 2014). The hydration of Li+, Na+, K+, F−, and Cl− inside carbon nanotubes have been studied with MD sim­ ulations (Shao et  al., 2008), which show that the first coordination shells of the five ions still exist in nanocon­ finement but the structure of the first coordination shells of cations become considerably less ordered in nanocon­ finement as compared to that in the bulk phase. The coordination number of an ion decreases with increasing pore surface charge and decreasing pore size (Kalluri et al., 2011). Overall, the nanopore confinement tends to reduce the tendency of water for ion hydration, thus enhancing ion pairing. As discussed below, this effect may have an important implication to tracer transport in shale formations. Since a fluid in a nanometer channel contains far fewer molecules than that in a macroscopic system, the discrete nature of fluid molecules is manifested in fluid flow and transport (Wang, 2014). The flow regimes in a flow channel and the applicability of conventional continuum

f(r) (nm–1)

48  SHALE: SUBSURFACE SCIENCE AND ENGINEERING 1.0E+00 1.0E–01 1.0E–02 1.0E–03 1.0E–04 1.0E–05 1.0E–06 1.0E–07 1.0E–08 1.0E–09 1.0E–10 1.0E–11 1.0E–12 1.0E–13

Barnett shale

1

10

1000

100

Pore radius (r) (nm)

Figure 3.2  Pore size distribution in Barnett Shale characterized with small angle neutron scattering. f(r) is the pore size distribution in terms of the number of pores. Data from Clarkson et al. (2013). 0.5 70

0.4 0.4 0.3

60 Tbulk – Tpore (K)

Volume fraction of unfrozen water

0.5

Freezing point depression by nanopore confinement

50 40 30 20 10

0.3

0

0

0.02

0.04

0.06

0.2

1/r (pore radius) (1/Å)

0.2

Effect of nanopore confinement

0.1

0.08

Clay

0.0 0.0 –4

Silt Sand –3

–2

–1

0

Temperature (°C)

Figure 3.3 Freezing point depression by nanopore confinement and its effect on the content of unfrozen water in permafrost region. Water content data from Osterkamp and Burn (2002).

theory to the flow can be determined by a dimensionless parameter, called Knudsen number (Kn) (Sparreboom et al., 2010):

Kn

l (3.5) L

where L is the characteristic size of the channel and l is the mean free path length for a gas or the interaction length of a molecule with its neighbors (~10 molecule length) for a liquid. A Kn number of unity characterizes the transition

between continuum and discrete flows. For a gaseous flow, the continuum Navier‐Stokes equation is valid only for Kn