Hydraulic Fracturing Chemicals and Fluids Technology [2 ed.] 0128220716, 9780128220719

Table of contents :
Cover
HYDRAULIC
FRACTURING
CHEMICALS AND
FLUIDS
TECHNOLOGY
Copyright
Contents
Preface to the second edition
Preface to the first edition
How to use this book
Index
Bibliography
Acknowledgments
1 General aspects
1.1 Functional categories of hydraulic fracturing chemicals
1.2 Stresses and fractures
1.2.1 Fracture initialization pressure
1.2.2 Pressure decline analysis
1.3 Comparison of stimulation techniques
1.3.1 Action of a fracturing fluid
1.3.2 Stages in a fracturing job
1.4 Simulation methods
1.4.1 Productivity
1.4.2 Fracture propagation
1.4.3 Proppants
1.4.4 Fluid loss
1.4.5 Foam fluid
1.4.6 Discharge control
1.5 Testing
1.5.1 Proppant placement
1.5.2 Slickwater fracturing
1.5.3 Erosion
1.5.4 Fluid leakoff
1.5.5 Damaged well
1.5.6 Crosslinked fluids
1.5.7 Phase trapping
1.5.8 Water imbibition
1.6 Special applications
1.6.1 Coiled tubing fracturing
Hydrajet fracturing
1.6.2 Tight gas
1.6.3 Shale gas
1.6.4 Coalbed methane
1.7 Shale reservoirs
1.8 Hydraulic fracturing with nanoparticles
1.8.1 Wellbore sealant using nanoparticles
References
2 Fluid types
2.1 Comparison of different techniques
2.2 Expert systems for assessment
2.3 Oil-based systems
2.4 Foam-based fracturing fluids
2.4.1 Foam types
2.4.2 Shale gas fracturing using a foam-based fracturing fluid
2.4.3 Dry foams
2.5 Utilization of hydraulic fracturing fluids
2.5.1 Chemical degradation of PAM during hydraulic fracturing
2.6 Improved thermal stability
Furfural degradation
2.7 Acid fracturing
2.7.1 Encapsulated acids
2.7.2 In situ formation of acids
2.7.3 Fluid loss
2.7.4 Gel breaker for acid fracturing
2.8 Special problems
2.8.1 Corrosion inhibitors
2.8.2 Iron control in fracturing
2.8.3 Enhanced temperature stability
2.8.4 Chemical blowing
2.8.5 Frost-resistant formulation
2.8.6 Formation damage in gas wells
2.9 Characterization of fracturing fluids
2.9.1 Rheologic characterization
2.9.2 Zirconium-based crosslinking agent
2.9.3 Oxidative gel breaker
2.9.4 Size exclusion chromatography
2.9.5 Assessment of proppants
References
3 Thickeners
3.1 Nanoparticle-enhanced hydraulic fracturing fluids
Polymers
pH-responsive thickeners
Mixed metal hydroxides
3.2 Thickeners for water-based systems
Zirconium-based crosslinking composition
3.2.1 Guar
3.2.2 Hydroxyethyl cellulose
3.2.3 Biotechnologic products
Gellan gum and wellan gum
Reticulated bacterial cellulose
Xanthan gum
3.2.4 Viscoelastic formulations
3.2.5 Miscellaneous polymers
Lactide polymers
Biodegradable formulations
3.3 Concentrates
3.4 Thickeners for oil-based systems
3.4.1 Organic gel aluminum phosphate ester
3.4.2 Increasing the viscosity of diesel
3.5 Viscoelasticity
3.5.1 Viscoelastic thickeners
3.5.2 Enhanced shear recovery agents
References
4 Friction reducers
4.1 Incompatibility
4.2 Polymers
4.3 Environmental aspects
4.4 Carbon dioxide-foamed fluids
4.4.1 Polymer emulsions
4.5 Oil-external copolymer emulsions
4.6 Poly(acrylamide) with weak labile links
References
5 Fluid loss additives
5.1 Mechanism of action of fluid loss agents
5.1.1 Fluid loss measurement
5.1.2 Action of macroscopic particles
5.2 Additive chemicals
5.2.1 Granular starch and mica
5.2.2 Depolymerized starch
5.2.3 Controlled degradable fluid loss additives
Degradation of fluid loss additives
5.2.4 Succinoglycan
5.2.5 Scleroglucan
5.2.6 Poly(orthoester)s
5.2.7 Poly(hydroxyacetic acid)
5.2.8 Polyphenolics
5.2.9 Phthalimide as a diverting material
5.2.10 Viscoelastic additives
Degradation of fluid loss additives
References
6 Emulsifiers
6.1 Oil-in-water emulsions
6.2 Invert emulsions
6.3 Water-in-water emulsions
6.4 Oil-in-water-in-oil emulsions
6.5 Microemulsions
6.6 Solids-stabilized emulsion
6.7 Biotreated emulsion
References
7 Demulsifiers
7.1 Basic action of demulsifiers
7.1.1 Desired properties
7.1.2 Mechanisms of demulsification
Stabilization of water-in-oil emulsions
Interfacial tension relaxation
7.2 Chemicals
7.3 Chelating agents
References
8 Clay stabilization
8.1 Properties of clays
8.1.1 Swelling of clays
8.1.2 Montmorillonite
8.1.3 Guidelines
8.2 Mechanisms causing instability
8.2.1 Kinetics of swelling of clays
8.2.2 Hydrational stress
8.2.3 Borehole stability model
8.2.4 Shale inhibition with water-based muds
8.2.5 Inhibiting reactive argillaceous formations
8.2.6 Formation damage by fluids
8.3 Swelling inhibitors
8.3.1 Salts
8.3.2 Quaternary ammonium salts
8.3.3 Potassium formate
8.3.4 Saccharide derivatives
8.3.5 Sulfonated asphalt
8.3.6 Grafted copolymers
8.3.7 Poly(oxyalkylene amine)s
8.3.8 Anionic polymers
8.3.9 Amine salts of maleic imide
8.3.10 Guanidyl copolymer
8.3.11 Special clay stabilizers
References
9 pH control additives
9.1 Theory of buffers
9.2 pH control
References
10 Surfactants
10.1 Performance studies
10.1.1 Multistage hydraulic fracturing
10.1.2 Viscoelastic surfactants
10.1.3 Cationic surfactants
10.1.4 Anionic surfactants
10.1.5 Anionic brominated surfactants
10.2 Shale colonizing microorganisms
10.3 Surfactants for waterless hydraulic fracturing
References
11 Scale inhibitors
11.1 Classification and mechanism
11.1.1 Thermodynamic inhibitors
11.1.2 Kinetic inhibitors
11.1.3 Adherence inhibitors
11.1.4 Interference of chelate formers
11.2 Mathematical models
11.2.1 Optimal dose
11.2.2 Precipitation squeeze method
11.3 Inhibitor chemicals
11.3.1 Water-soluble inhibitors
Acids
Hydrofluoric acid
Encapsulated scale inhibitors
Chelating agents
EDTA
Phosphonates
Alkaline earth sulfates
Biodegradable scale inhibitors
Sodium iminodisuccinate
Disodium hydroxyethyleneiminodiacetic acid
Sodium gluconate and sodium glucoheptonate
Sodium poly(aspartate)
11.3.2 Oil-soluble scale inhibitors
Aloe-based scale inhibitor
Acrolein copolymer
11.3.3 High reservoir temperatures
References
12 Foaming agents
12.1 Environmentally safe fluids
12.2 Liquid carbon dioxide foams
References
13 Defoamers
13.1 Theory of defoaming
13.1.1 Stability of foams
13.1.2 Action of defoamers
Spreading coefficient
13.2 Classification of defoamers
13.2.1 Active ingredients
Liquid components
Synergistic antifoam action by solid particles
Silicone antifoaming agents
Exemplary composition
References
14 Crosslinking agents
14.1 Kinetics of crosslinking
14.1.1 Delayed crosslinking
14.2 Crosslinking additives
14.2.1 Borate systems
14.2.2 Titanium compounds
14.2.3 Zirconium compounds
14.2.4 Guar
Hydroxypropyl guar
14.2.5 Delayed crosslinking additives
References
15 Gel stabilizers
15.1 Chemicals
15.2 Special issues
15.2.1 Water softeners
15.2.2 Borate reserve
15.2.3 Electron donor compounds
15.2.4 Effects of pH on gel stability
References
16 Gel breakers
16.1 Gel breaking in water-based systems
16.2 Oxidative breakers
16.2.1 Hypochlorite salts
16.2.2 Peroxide breakers
16.2.3 Redox gel breakers
16.3 Delayed release of acids
16.3.1 Hydroxyacetic acid condensates
16.4 Enzyme gel breakers
16.4.1 Interactions
16.5 Encapsulated gel breakers
16.6 Gel breaking of guar
16.6.1 Enzyme breaking of guar
16.7 Viscoelastic surfactant-gelled fluids
16.8 Granules
16.8.1 Gel breakers for oil-based systems
Enzyme-based gel breaking
Breaker enhancers for VESs
Surfactant polymer compositions
References
17 Biocides
17.1 Mechanisms of growth
17.1.1 Growth of bacteria supported by oilfield chemicals
17.1.2 Mathematical models
Model of colony growth
17.1.3 Sulfate reducing bacteria
17.1.4 Bacterial corrosion
pH regulation
Biocide enhancers
17.1.5 Methanogens
17.2 Performance control
17.3 Treatments with biocides
17.3.1 Previously fractured formations
17.3.2 Intermittent addition of biocide
17.3.3 Nonbiocidal control
Biocompetitive exclusion technology
Inhibitors for bacterial films
Periodic change in ionic strengths
17.4 Special chemicals
References
18 Proppants
18.1 Fluid loss
18.2 Tracers
18.3 Proppant diagenesis
18.4 Propping agents
18.4.1 Extrusion process for proppant production
18.4.2 Sand
18.4.3 Nanoparticle-patterned ceramsites
18.4.4 Ceramic particles
18.4.5 Electrically conductive proppants
18.4.6 Tailoring the surface wettability
18.4.7 Slickwater treatment
18.4.8 Bauxite
18.4.9 Light-weight proppants
Computational and experimental approach
Inverted proppant convection
18.4.10 Porous pack with fibers
18.4.11 Coated proppants
18.4.12 Antisettling additives
18.4.13 Proppant flowback
Thermoplastic films
Adhesive-coated material
Magnetized material
References
19 Special compositions
19.1 Heat generating system
19.1.1 Microencapsulation of oxalic acid via coacervation
19.2 Crosslinkable synthetic polymers
19.3 Single-phase microemulsion
19.4 Crosslinking composition
References
20 Environmental aspects
20.1 Risk analysis
20.1.1 Environmental contamination and toxicity
Current governance approaches
Hydraulic fracturing waste water
Methane leakage
Neurodevelopmental and neurological effects
Bacterial stress responses
Risk of childhood leukemia
20.1.2 Classification of hydraulic fracturing chemicals
FracFocus registry
REPROTOX database
Globally harmonized system
Comprehensive model
Indexing methods
HYDRUS computer software
Cytoscape analysis
Modeling inhalation exposure
Comparison of the use of chemicals with different methods
Current regulatory issues
Biocides in hydraulic fracturing fluids
Contaminated surface water for fish and mussels
Groundwater contamination
Delayed hydrogen sulfide production
Potential hazards for drinking water resources
20.1.3 Analysis methods
Reactor for investigating subsurface chemical transformations
Gas chromatography-mass spectrometry
Liquid chromatography-high-resolution mass spectrometry
Liquid chromatography-electrospray ionization mass spectrometry
Molecular imprinted polymers
Shale waste water samples
Shale gas flowback and produced waters
Risk quotient approach
Statistical analysis of flowback and produced waters
Geochemical fingerprints
Special components
Organic compounds
Semivolatile hydrocarbons
Polypropylene glycols and polyethylene glycol carboxylates
Halogenated organic compounds
Fracking-derived gases
Microcosm experiments
Degradation of glutaraldehyde
Degradation of poly(ethylene glycol)s and poly(propylene glycol)s
20.2 Treatment methods
20.2.1 Natural attenuation of nonionic surfactants
20.2.2 Visible light photocatalysis
20.2.3 Biological treatment of produced water
Degradation of guar
Sequencing batch reactor
20.2.4 Biodegradation in agricultural topsoil
20.2.5 Aerobic biodegradation of organic compounds
Synthetic hydraulic fracturing fluid
Biodegradation of alkyl and nonylphenol ethoxylate surfactants
20.2.6 Microbial electrochemical cells
20.2.7 Iron-biochar composites
20.2.8 Estrogen and androgen receptor activity
Endocrine disrupting chemicals
Adipogenic activity
Endocrine disrupting activity
Immunotoxicity to amphibian tadpoles
20.2.9 Produced water treatment
Degraded poly(acrylamide)
Boron removal from waste water
Biological methods
Treatment by coagulation-adsorption
Oxidation of evaporated hydraulic fracturing waste water
Membranes
Microfiltration membranes
Extractive membrane bioreactor
Desalination of shale gas waste water
Simulation of a waste water surface spill on agricultural soil
20.3 Contaminated water reclaim
20.3.1 Waste water from hydrofracturing
Downhole chemistry of glutaraldehyde
20.3.2 Phosphorus recovery in flowback fluids
20.4 Green formulations
20.4.1 Biodegradable chelants
20.4.2 Nontoxic flowback formulation
20.4.3 Crosslinking agents
20.5 Self-degrading foaming composition
References
Index
Back Cover

Citation preview

HYDRAULIC FRACTURING CHEMICALS AND FLUIDS TECHNOLOGY

HYDRAULIC FRACTURING CHEMICALS AND FLUIDS TECHNOLOGY Second edition

JOHANNES FINK University of Leoben Leoben, Austria

Gulf Professional Publishing is an imprint of Elsevier 50 Hampshire Street, 5th Floor, Cambridge, MA 02139, United States The Boulevard, Langford Lane, Kidlington, Oxford, OX5 1GB, United Kingdom Copyright © 2020 Elsevier Inc. All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, recording, or any information storage and retrieval system, without permission in writing from the publisher. Details on how to seek permission, further information about the Publisher’s permissions policies and our arrangements with organizations such as the Copyright Clearance Center and the Copyright Licensing Agency, can be found at our website: www.elsevier.com/permissions. This book and the individual contributions contained in it are protected under copyright by the Publisher (other than as may be noted herein). Notices Knowledge and best practice in this field are constantly changing. As new research and experience broaden our understanding, changes in research methods, professional practices, or medical treatment may become necessary. Practitioners and researchers must always rely on their own experience and knowledge in evaluating and using any information, methods, compounds, or experiments described herein. In using such information or methods they should be mindful of their own safety and the safety of others, including parties for whom they have a professional responsibility. To the fullest extent of the law, neither the Publisher nor the authors, contributors, or editors, assume any liability for any injury and/or damage to persons or property as a matter of products liability, negligence or otherwise, or from any use or operation of any methods, products, instructions, or ideas contained in the material herein. Library of Congress Cataloging-in-Publication Data A catalog record for this book is available from the Library of Congress British Library Cataloguing-in-Publication Data A catalogue record for this book is available from the British Library ISBN: 978-0-12-822071-9 For information on all Gulf Professional Publishing publications visit our website at https://www.elsevier.com/books-and-journals Publisher: Joe Hayton Senior Acquisitions Editor: Katie Hammon Editorial Project Manager: Danielle McLean Production Project Manager: Prem Kumar Kaliamoorthi Designer: Christian Bilbow Typeset by VTeX

Contents Preface to the second edition Preface to the first edition Acknowledgments

1. General aspects Functional categories of hydraulic fracturing chemicals Stresses and fractures 1.2.1. Fracture initialization pressure 1.2.2. Pressure decline analysis 1.3. Comparison of stimulation techniques 1.3.1. Action of a fracturing fluid 1.3.2. Stages in a fracturing job 1.4. Simulation methods 1.4.1. Productivity 1.4.2. Fracture propagation 1.4.3. Proppants 1.4.4. Fluid loss 1.4.5. Foam fluid 1.4.6. Discharge control 1.5. Testing 1.5.1. Proppant placement 1.5.2. Slickwater fracturing 1.5.3. Erosion 1.5.4. Fluid leakoff 1.5.5. Damaged well 1.5.6. Crosslinked fluids 1.5.7. Phase trapping 1.5.8. Water imbibition 1.6. Special applications 1.6.1. Coiled tubing fracturing 1.6.2. Tight gas 1.6.3. Shale gas 1.6.4. Coalbed methane 1.7. Shale reservoirs 1.8. Hydraulic fracturing with nanoparticles 1.8.1. Wellbore sealant using nanoparticles References

1.1. 1.2.

xiii xv xvii

1 1 3 3 4 4 4 5 5 6 7 7 8 8 8 9 9 9 10 10 11 11 12 13 14 15 16 17 18 21 23 24 24 v

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Contents

2. Fluid types Comparison of different techniques Expert systems for assessment Oil-based systems Foam-based fracturing fluids 2.4.1. Foam types 2.4.2. Shale gas fracturing using a foam-based fracturing fluid 2.4.3. Dry foams 2.5. Utilization of hydraulic fracturing fluids 2.5.1. Chemical degradation of PAM during hydraulic fracturing 2.6. Improved thermal stability 2.7. Acid fracturing 2.7.1. Encapsulated acids 2.7.2. In situ formation of acids 2.7.3. Fluid loss 2.7.4. Gel breaker for acid fracturing 2.8. Special problems 2.8.1. Corrosion inhibitors 2.8.2. Iron control in fracturing 2.8.3. Enhanced temperature stability 2.8.4. Chemical blowing 2.8.5. Frost-resistant formulation 2.8.6. Formation damage in gas wells 2.9. Characterization of fracturing fluids 2.9.1. Rheologic characterization 2.9.2. Zirconium-based crosslinking agent 2.9.3. Oxidative gel breaker 2.9.4. Size exclusion chromatography 2.9.5. Assessment of proppants References

2.1. 2.2. 2.3. 2.4.

3. Thickeners 3.1. 3.2.

3.3. 3.4.

Nanoparticle-enhanced hydraulic fracturing fluids Thickeners for water-based systems 3.2.1. Guar 3.2.2. Hydroxyethyl cellulose 3.2.3. Biotechnologic products 3.2.4. Viscoelastic formulations 3.2.5. Miscellaneous polymers Concentrates Thickeners for oil-based systems 3.4.1. Organic gel aluminum phosphate ester

29 34 35 35 35 36 37 38 39 39 40 41 42 42 42 43 43 43 43 45 45 46 46 47 47 48 48 48 49 49

55 55 59 60 63 64 65 67 68 70 70

Contents

3.4.2. Increasing the viscosity of diesel Viscoelasticity 3.5.1. Viscoelastic thickeners 3.5.2. Enhanced shear recovery agents References

3.5.

4. Friction reducers Incompatibility Polymers Environmental aspects Carbon dioxide-foamed fluids 4.4.1. Polymer emulsions 4.5. Oil-external copolymer emulsions 4.6. Poly(acrylamide) with weak labile links References

4.1. 4.2. 4.3. 4.4.

5. Fluid loss additives Mechanism of action of fluid loss agents 5.1.1. Fluid loss measurement 5.1.2. Action of macroscopic particles 5.2. Additive chemicals 5.2.1. Granular starch and mica 5.2.2. Depolymerized starch 5.2.3. Controlled degradable fluid loss additives 5.2.4. Succinoglycan 5.2.5. Scleroglucan 5.2.6. Poly(orthoester)s 5.2.7. Poly(hydroxyacetic acid) 5.2.8. Polyphenolics 5.2.9. Phthalimide as a diverting material 5.2.10. Viscoelastic additives References

5.1.

6. Emulsifiers 6.1. Oil-in-water emulsions 6.2. Invert emulsions 6.3. Water-in-water emulsions 6.4. Oil-in-water-in-oil emulsions 6.5. Microemulsions 6.6. Solids-stabilized emulsion 6.7. Biotreated emulsion References

vii

70 71 73 74 75

81 81 81 82 84 84 85 86 87

89 89 89 90 92 92 93 93 94 95 95 96 97 97 98 100

105 105 106 106 107 107 108 111 112

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Contents

7. Demulsifiers Basic action of demulsifiers 7.1.1. Desired properties 7.1.2. Mechanisms of demulsification 7.2. Chemicals 7.3. Chelating agents References

7.1.

8. Clay stabilization Properties of clays 8.1.1. Swelling of clays 8.1.2. Montmorillonite 8.1.3. Guidelines 8.2. Mechanisms causing instability 8.2.1. Kinetics of swelling of clays 8.2.2. Hydrational stress 8.2.3. Borehole stability model 8.2.4. Shale inhibition with water-based muds 8.2.5. Inhibiting reactive argillaceous formations 8.2.6. Formation damage by fluids 8.3. Swelling inhibitors 8.3.1. Salts 8.3.2. Quaternary ammonium salts 8.3.3. Potassium formate 8.3.4. Saccharide derivatives 8.3.5. Sulfonated asphalt 8.3.6. Grafted copolymers 8.3.7. Poly(oxyalkylene amine)s 8.3.8. Anionic polymers 8.3.9. Amine salts of maleic imide 8.3.10. Guanidyl copolymer 8.3.11. Special clay stabilizers References

8.1.

9. pH control additives 9.1. Theory of buffers 9.2. pH control References

10. Surfactants 10.1. Performance studies 10.1.1. Multistage hydraulic fracturing 10.1.2. Viscoelastic surfactants

113 114 114 114 114 115 116

119 119 120 123 124 124 125 125 125 126 126 126 126 127 127 129 129 129 130 130 131 132 132 134 135

141 141 144 145

147 147 148 148

Contents

10.1.3. Cationic surfactants 10.1.4. Anionic surfactants 10.1.5. Anionic brominated surfactants 10.2. Shale colonizing microorganisms 10.3. Surfactants for waterless hydraulic fracturing References

11. Scale inhibitors 11.1. Classification and mechanism 11.1.1. Thermodynamic inhibitors 11.1.2. Kinetic inhibitors 11.1.3. Adherence inhibitors 11.1.4. Interference of chelate formers 11.2. Mathematical models 11.2.1. Optimal dose 11.2.2. Precipitation squeeze method 11.3. Inhibitor chemicals 11.3.1. Water-soluble inhibitors 11.3.2. Oil-soluble scale inhibitors 11.3.3. High reservoir temperatures References

12. Foaming agents 12.1. Environmentally safe fluids 12.2. Liquid carbon dioxide foams References

13. Defoamers 13.1. Theory of defoaming 13.1.1. Stability of foams 13.1.2. Action of defoamers 13.2. Classification of defoamers 13.2.1. Active ingredients References

14. Crosslinking agents 14.1. Kinetics of crosslinking 14.1.1. Delayed crosslinking 14.2. Crosslinking additives 14.2.1. Borate systems 14.2.2. Titanium compounds 14.2.3. Zirconium compounds 14.2.4. Guar

ix

149 150 153 154 155 155

157 157 159 160 160 160 160 161 161 162 162 168 170 170

175 176 177 178

179 179 179 180 181 182 184

187 187 187 187 187 189 191 192

x

Contents

14.2.5. Delayed crosslinking additives References

15. Gel stabilizers 15.1. Chemicals 15.2. Special issues 15.2.1. Water softeners 15.2.2. Borate reserve 15.2.3. Electron donor compounds 15.2.4. Effects of pH on gel stability References

16. Gel breakers 16.1. Gel breaking in water-based systems 16.2. Oxidative breakers 16.2.1. Hypochlorite salts 16.2.2. Peroxide breakers 16.2.3. Redox gel breakers 16.3. Delayed release of acids 16.3.1. Hydroxyacetic acid condensates 16.4. Enzyme gel breakers 16.4.1. Interactions 16.5. Encapsulated gel breakers 16.6. Gel breaking of guar 16.6.1. Enzyme breaking of guar 16.7. Viscoelastic surfactant-gelled fluids 16.8. Granules 16.8.1. Gel breakers for oil-based systems References

17. Biocides 17.1. Mechanisms of growth 17.1.1. Growth of bacteria supported by oilfield chemicals 17.1.2. Mathematical models 17.1.3. Sulfate reducing bacteria 17.1.4. Bacterial corrosion 17.1.5. Methanogens 17.2. Performance control 17.3. Treatments with biocides 17.3.1. Previously fractured formations 17.3.2. Intermittent addition of biocide 17.3.3. Nonbiocidal control

194 195

199 199 200 200 200 201 203 203

205 205 206 206 207 207 207 208 208 209 209 210 212 214 215 215 218

223 224 224 224 226 227 228 229 229 229 230 230

Contents

17.4. Special chemicals References

18. Proppants Fluid loss Tracers Proppant diagenesis Propping agents 18.4.1. Extrusion process for proppant production 18.4.2. Sand 18.4.3. Nanoparticle-patterned ceramsites 18.4.4. Ceramic particles 18.4.5. Electrically conductive proppants 18.4.6. Tailoring the surface wettability 18.4.7. Slickwater treatment 18.4.8. Bauxite 18.4.9. Light-weight proppants 18.4.10. Porous pack with fibers 18.4.11. Coated proppants 18.4.12. Antisettling additives 18.4.13. Proppant flowback References 18.1. 18.2. 18.3. 18.4.

19. Special compositions 19.1. Heat generating system 19.1.1. Microencapsulation of oxalic acid via coacervation 19.2. Crosslinkable synthetic polymers 19.3. Single-phase microemulsion 19.4. Crosslinking composition References

20. Environmental aspects 20.1. Risk analysis 20.1.1. Environmental contamination and toxicity 20.1.2. Classification of hydraulic fracturing chemicals 20.1.3. Analysis methods 20.2. Treatment methods 20.2.1. Natural attenuation of nonionic surfactants 20.2.2. Visible light photocatalysis 20.2.3. Biological treatment of produced water 20.2.4. Biodegradation in agricultural topsoil 20.2.5. Aerobic biodegradation of organic compounds 20.2.6. Microbial electrochemical cells

xi

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237 237 238 238 239 239 241 241 241 242 243 244 245 245 247 247 249 250 251

255 255 256 257 257 258 258

259 259 260 265 279 293 293 294 294 296 298 299

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Contents

20.2.7. Iron–biochar composites 20.2.8. Estrogen and androgen receptor activity 20.2.9. Produced water treatment 20.3. Contaminated water reclaim 20.3.1. Waste water from hydrofracturing 20.3.2. Phosphorus recovery in flowback fluids 20.4. Green formulations 20.4.1. Biodegradable chelants 20.4.2. Nontoxic flowback formulation 20.4.3. Crosslinking agents 20.5. Self-degrading foaming composition References Index

299 301 307 314 315 317 317 317 318 318 318 320 331

Preface to the second edition The first edition of this text appeared in 2013. In the second edition, the recent literature has been included, so the text is now updated up to 2019. The emerging basic issues here are environmental contamination and toxicity, treatment methods of waste materials, and methods of usage. J.K.F.

xiii

Preface to the first edition This manuscript focuses on the recent developments in fracturing fluids with respect to chemical aspects. After a short introduction to the basic issues of fracturing, the text focuses mainly on the organic chemistry of fracturing fluids. The nature of the individual additives and an explanation why the individual additives act in the desired way are explained. The material presented here is a compilation from the literature, including patents. In addition, as environmental aspects are increasingly gaining importance, this issue is also dealt in detail.

How to use this book Index There are three indices, i.e., an index of acronyms, an index of chemicals, and a general index. In a chapter, if an acronym occurs for the first time, it is written in full and abbreviated, e.g., acrylic acid (AA), and placed in the index. If it occurs afterwards it is given in the abbreviated form only, i.e., AA. If a term occurs only once in a specific chapter, it is given exclusively in full. In the chemical index, boldface page numbers refer to the sketches of structural formulas or to reaction equations.

Bibliography The bibliography is given per chapter and is sorted in the order of occurrence. After the bibliography, a list of tradenames that are found in the references and which chemicals are behind these names, as far as laid open, is added.

xv

Acknowledgments

The continuous interest and the promotion by Professor Wolfgang Kern, the head of our department, are highly appreciated. I am indebted to our university librarians, Dr. Christian Hasenhüttl, Dr. Johann Delanoy, Franz Jurek, Margit Keshmiri, Dolores Knabl, Friedrich Scheer, Christian Slamenik, and Renate Tschabuschnig for support in literature acquisition. This book could otherwise not have been compiled. Thanks are given to Professor I. Lakatos, of the University of Miskolc, who directed my interest to this topic. Last but not least, I want to thank the publisher for kind support, in particular Katie Hammon. J.K.F.

xvii

CHAPTER 1

General aspects Hydraulic fracturing is a technique used to stimulate the productivity of a well. A hydraulic fracture is a superimposed structure that remains undisturbed outside the fracture. Thus the effective permeability of a reservoir remains unchanged by this process. The increased wellbore radius increases its productivity, because a large contact surface between the well and the reservoir is created.

1.1 Functional categories of hydraulic fracturing chemicals The functional categories of hydraulic fracturing chemicals are presented in Table 1.1.

Table 1.1 Functional categories of hydraulic fracturing chemicals [1,2]. Category

Technical use

Example compounds

Acids

To achieve greater injection ability or penetration and later to dissolve minerals and clays to reduce clogging, allowing gas to flow to the surface.

Hydrochloric acid

Biocides

To prevent bacteria that can erode pipes and fittings and to break down gellants that serve to ensure that fluid viscosity and proppant transport are maintained.

1-Methyl4-isothiazolin-3-one, bronopol, glutaraldehyde

Breakers

To allow the breakdown of gellants used to carry the proppant; these are added near the end of the hydraulic fracturing sequence to enhance flowback.

Ammonium persulfate, magnesium peroxide

Clay stabilizers

To create a fluid barrier to prevent mobilization of clays, which can plug fractures.

Tetramethyl ammonium chloride, sodium chloride

Hydraulic Fracturing Chemicals and Fluids Technology https://doi.org/10.1016/B978-0-12-822071-9.00008-6

Copyright © 2020 Elsevier Inc. All rights reserved.

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Table 1.1 (continued) Category

Technical use

Example compounds

Corrosion inhibitors

To reduce the potential for rusting in pipes and casings.

Ethoxylated octylphenol and nonylphenol, isopropanol

Crosslinkers

To thicken fluids, often with metallic salts, in order to increase viscosity and proppant transport.

Ethylene glycol, sodium tetraborate decahydrate, petroleum distillate

Defoamers

To reduce foaming after it is no longer needed in order to lower surface tension and allow trapped gas to escape.

2-Ethylhexanol, oleic acid, oxalic acid

Foamers

To increase carrying capacity while transporting proppants and decreasing the overall volume of fluid needed.

2-Butoxyethanol, diethylene glycol

Friction reducers

To make water slick and minimize the friction created under high pressure and to increase the rate and efficiency of moving the hydraulic fracturing fluid.

Acrylamide, ethylene glycol, petroleum distillate, methanol

Gellants

To increase viscosity and suspend sand during proppant transport.

Propylene glycol, guar gum, ethylene glycol

pH controllers

To maintain the pH at various stages with buffers to ensure maximum effectiveness of various additives.

Sodium hydroxide, acetic acid

Proppants

To hold fissures open, allowing gas to flow out of the cracked formation; usually composed of sand and occasionally glass or ceramic beads.

Styrene, crystalline silica, ceramic, graphite

Scale inhibitors

To prevent buildup of mineral scale that can block fluid and gas passage through the pipes.

Acrylamide, sodium polycarboxylate

Surfactants

To decrease liquid surface tension and improve fluid passage through pipes in either direction.

Naphthalene, 1,2,4-trimethylbenzene, ethanol, methanol, 2-butoxyethanol

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1.2 Stresses and fractures Hydraulic fracturing is one of the newer techniques in petroleum sciences; it has only been used for approximately 60 years. The classic treatment of hydraulic fracturing states that the fractures are approximately perpendicular to the axis of the least stress [3]. For most deep reservoirs, the minimal stresses are horizontal, hence vertical stresses will occur in fracturing. The actual stress can be calculated by balancing the vertical geostatic stress and the horizontal stress by the common tools of the theory of elasticity. For example, the geostatic stress must be corrected in a porous medium filled with a liquid having a poroelastic constant and hydrostatic pressure. The horizontal stress can be calculated from the corrected vertical stress with the Poisson ratio. Under some circumstances, in particular in shallow reservoirs, horizontal stresses can be created, as well as vertical stresses. The possible stress modes are summarized in Table 1.2. Table 1.2 Modes of stresses in fractures.

pb

Fracture initialization pressure

3sH ,min

Minimal horizontal stress

sH ,max

Maximal horizontal stress (= minimal horizontal stress + tectonic stress)

T

Tensile strength of rock material

p

Pore pressure

1.2.1 Fracture initialization pressure Knowledge of the stresses in a reservoir is essential to find the pressure at which initiation of a fracture can take place. The upper bound of this pressure can be estimated using a formula given by Terzaghi [4], which states that pb = 3sH ,min − sH ,max + T − p.

(1.1)

The variables are explained in Table 1.2. The closure pressure indicates the pressure at which the width of the fracture becomes zero. This is normally the minimal horizontal stress.

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1.2.2 Pressure decline analysis The pressure response during fracturing provides important information about the success of the operation. The fluid efficiency can be estimated from the closure time.

1.3 Comparison of stimulation techniques In addition to hydraulic fracturing, there are other stimulation techniques, such as acid fracturing or matrix stimulation, and hydraulic fracturing is also used in coal seams to stimulate the flow of methane. Fracturing fluids are often divided into water-based, oil-based, alcohol-based, emulsion, or foam-based fluids. Several reviews are available in the literature dealing with the basic principles of hydraulic fracturing, and the guidelines that are used to select a formulation for a specific job [5–7]. Polymer hydration, crosslinking, and degradation are the key processes that these materials undergo. Technological improvements over the years have focused primarily on improved rheological performance, thermal stability, and cleanup of crosslinked gels.

1.3.1 Action of a fracturing fluid Fracturing fluids must meet a number of requirements simultaneously. They must be stable at high • temperatures, • pumping rates, and • shear rates. These severe conditions can cause the fluids to degrade and prematurely settle out the proppant before the fracturing operation is complete. Most commercially used fracturing fluids are aqueous liquids that have been either gelled or foamed. Typically, the fluids are gelled by a polymeric gelling agent. The thickened or gelled fluid helps keep the proppants within the fluid during the fracturing operation. Fracturing fluids are injected into a subterranean formation for the following purposes [8]: • to create a conductive path from the wellbore extending into the formation and • to carry proppant material into the fracture to create a conductive path for produced fluids.

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1.3.2 Stages in a fracturing job A fracturing job has several stages, including injecting a prepad, a pad, and a proppant containing fracturing fluid, and finally, a treatment with flush fluids. A prepad is a low-viscosity fluid used to condition the formation, which may contain fluid loss additives and surfactants and have a defined salinity to prevent formation damage. The generation of the fractures takes place by injecting the pad, a viscous fluid, but without proppants. After the fractures develop, a proppant must be injected to keep them permeable. When the fracture closes, the proppant left there creates a large flow area and a highly conductive pathway for hydrocarbons to flow into the wellbore. Thus, the proppant is utilized to maintain an open fracture. Viscous fluids are utilized to transport, suspend, and eventually allow the proppant to be trapped inside the fracture. These fluids typically exhibit a power law behavior for the range of shear rates encountered in hydraulic fracturing treatments. A uniform proppant distribution is needed in order to get a uniformly conductive fracture along the wellbore height and fracture half-length, but the complicated nature of proppant settling in non-Newtonian fluids often leads to a higher concentration of proppant in the lower part of the fracture. This often leads to a lack of adequate proppant coverage of the upper portion of the fracture and the wellbore. Clustering of proppant, encapsulation, bridging, and embedment are all phenomena that lower the potential conductivity of the proppant pack [9]. The job ends eventually with a cleanup stage, in which flush fluids and other cleanup agents are applied. The actual detailed time schedule depends on the particular system used. After the completion the fluid viscosity should decrease to allow the placement of the proppant and a rapid fluid return through the fracture. It is important to control the time at which the viscosity break occurs. In addition, the degraded polymer should produce little residue to restrict the flow of fluids through the fracture.

1.4 Simulation methods The estimation of the fracture geometry is one of the most difficult technical challenges in hydraulic fracturing technology [10]. A discrete element simulation for the hydraulic fracture process in a petroleum well that takes into account the elastic behavior of the rock and

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the Mohr–Coulomb fracture criterion has been presented [11]. The modeling of the rock was done as an array of Voronoi polygons joined by elastic beams that are submitted to tectonical stresses and the hydrostatic pressure of the fracturing fluid. The fluid pressure is treated similar to that of a hydraulic column. The results show that the simulation process follows a real situation. A three-dimensional nonlinear fluid solid coupling finite element model was established based on the finite element software ABAQUS [10]. The staged fracturing process of a horizontal well in the Daqing Oilfield, China was simulated with the model, taking account perforation, the wellbore, cement casing, one pay zone, two barriers, microannulus fracture, and transverse fracture. These experimental data were used in numerical computation. Microannulus fracture and transverse fracture are generated simultaneously and a typical T-shaped fracture occurs at the early stage of treatment history, then the microannulus disappears and only the transverse fracture remains and propagates. The pore pressure distribution in the formation and the fracture configuration during the treatment history can be obtained. The evolution of bottomhole pressure as the direct output of simulation coincides with the experimental data [10].

1.4.1 Productivity A model has been developed that calculates the productivity of a hydraulically fractured well, including the effect of fracture face damage caused by fluid leakoff [12]. The results of this model have been compared with three previous models. These models assume either elliptical or radial flow around the well, with permeability varying azimuthally. Significant differences in the calculated well productivity indicate that earlier assumptions made regarding the flow geometry can lead to significant overestimates of the well productivity index. An agreement with the analytical solution given by Levine and Prats [13] has been shown for finite-conductivity fractures and no fracture damage. The simple and discrete nature of the model makes it ideal for implementation in spreadsheets and to connect to fracture performance models. Cleanup of the damage in the invaded zone depends on the capillary properties of the formation and the pressure applied across the damaged zone

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during production [12]. It has also been found that the invaded zone will cause a significant damage when the permeability of the damaged zone is reduced by more than 9%.

1.4.2 Fracture propagation The propagation of a two-dimensional preexisting fracture in permeable rock by the injection of a viscous, incompressible Newtonian fluid has been modeled [14]. In particular, the method of Fitt [15] for the solution of hydraulic fracturing in an impermeable rock has been extended to a permeable rock. The fluid flow in the fracture is assumed to be laminar. By the application of the lubrication theory, a partial differential equation relating the half-width of the fracture to the fluid pressure and leakoff velocity has been derived. The solution of this equation yields the leakoff velocity as a function of the distance along the fracture and time. The group-invariant solution is derived by considering a linear combination of the Lie point symmetries. The boundary value problem has been reformulated as a pair of initial value problems. The model in which the leakoff velocity is proportional to the fracture half-width is considered [14]. A model of a hydraulic fracture with a tip cohesive zone according to the Barenblatt approach [16] has been presented [17]. The particular case of an inviscid fracturing fluid and impermeable rock has been studied. An inviscid fluid is assumed to have zero viscosity. It has been proved that assuming finite cohesive stresses, the cohesive zone length cannot also exceed a certain limit. The limit form of the cohesive zone is obtained, and the limit fracture toughness is thus evaluated. The effective fracture toughness tends to the limit value with power of −0.5.

1.4.3 Proppants The proppant is the most critical issue of a fracture treatment for a well, as it largely defines the ultimate deliverability. The most efficient and effective fracture stimulation designs create an optimal effective fracture area. This is the area of a created fracture with enough conductivity contrast to promote an accelerated drainage of the reservoir [18]. A strong correlation was observed among all the designs between the effective fracture area and predicted cumulative production of 360 days. The cumulative production was significantly less sensitive to the conductivity of the fracture than to the effective area of the fracture. Stimulation designs

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Hydraulic Fracturing Chemicals and Fluids Technology

employing proppant partial monolayers can be competitive or less costly than fracture jobs that use conventional proppants.

1.4.4 Fluid loss The modeling of the fluid loss is important for planning a fracturing job and analysis of the finished process. Due to its complexity, theoretical models are set up rather with difficulties, because many of the parameters are difficult or impossible to evaluate. Empirical and semiempirical models have been set up. Testing protocols also influence the quality of the data on which these models are based. Some of the currently used models have been reviewed and two different models have been proposed that provide better fits to the available data than the previous models [19].

1.4.5 Foam fluid A numerical simulation study on the rheology of a foam fluid was carried out by treating the inner phase as a granular fluid using the mixture model [20]. The results of the simulation show that the gas phase is well distributed. The higher the foam quality is, the higher is the velocity gradient near the wall. In the case of turbulence, both the turbulent kinetic energy and the viscosity increase as the foam quality increases. At a foam quality of 63% the rheology of the foam fracturing fluid changes sharply. The results of the simulation indicate that the mixture model is more applicable and effective to the region where foam quality is more than 63% [20].

1.4.6 Discharge control A control and inspection system has been designed which enables the fracture fluid discharge to orderly avoid certain disadvantages such as pressure vibration and sand-back, as found sometimes when a manual control is used [21]. A computer program is used as the interface for conversation between man and machine. The program is designed and used as an online control equipment gathering pressure and flux parameters and control of valve state and status display. In this way the best method of discharging a fracturing fluid is utilized. Actual results have been exemplary presented.

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1.5 Testing 1.5.1 Proppant placement In hydraulic fracturing treatments, a fracture is initiated by rupturing the formation at high pressure by means of a fracturing fluid. Slurry, composed of propping material carried by the fracturing fluid, is pumped into the induced fracture channel to prevent fracture closure when fluid pressure is released. The improvement in productivity is mainly determined by the propped dimension of the fracture, which is controlled by the transport of the proppant and a proper placement of the proppant. Settling and convection are the controlling mechanisms of the placement of the proppant. The proppant transport and the placement efficiency using non-Newtonian fluids was experimentally investigated and numerically simulated. A small glass model was used to simulate the hydraulic fracture and additional parameters, such as slurry volumetric injection rate, proppant concentration, and the rheology properties arising from the polymer [22]. Small glass models can easily and inexpensively simulate the flow patterns in hydraulic fractures. The observed flow patterns are strikingly similar to those obtained by very large flow models. When the ratio of viscous energy to gravitational energy increases the settling decreases and the efficiency of proppant placement increases. An enhanced non-Newtonian flow behavior index results in less efficiency of proppant placement.

1.5.2 Slickwater fracturing Low-damage fracturing fluids are normally used for better fracture dimension confinement and lower residue. This leads not only to longer fracture lengths, but also to higher fracture conductivity. The slickwater fracturing technology, developed in the 1980s, is less expensive than gel treatments. Fluid and proppant volumes can be reduced, and treatment flow rates can be increased significantly. When compared to conventional gel treatments, slickwater fracturing can generate similar or better production responses [23]. Slickwater fracturing has been increasingly applied to stimulate unconventional shale gas reservoirs [24]. In comparison to crosslinked fluids, slickwater used as a fracturing fluid has several advantages, including low cost, a higher possibility of creating complex fracture networks, less formation damage, and ease of cleanup.

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Hydraulic Fracturing Chemicals and Fluids Technology

An enormous amount of water is injected into the formation during the treatment. Even with a good recovery of injected water from flowback, large quantities of water are still left within the reservoir. The dynamics of the water phase both within the created hydraulic fractures and the reactivated natural fractures have a significant impact on the effectiveness of the treatment. It is controlled by the relative permeability, capillary pressure, gravity segregation, and the fracture conductivity. Reservoir simulation models have been used to investigate the changes of the distribution of the water saturation in the fractures during production. Water imbibitions caused by capillary pressure and gravity segregation can play important roles in distribution of the water saturation, in particular during extended shutin, which in turn affects the gas flow [24].

1.5.3 Erosion Erosion phenomena are common in the petroleum industry. Damages of material occur frequently in high-pressure pipelines in the course of hydraulic fracturing [25]. With increasing operation times, the erosion and corrosion defects on the inner surface of the pipeline result in serious material loss and thus in a failure of the equipment. A device to simulate the erosive wear behavior of metal materials caused by a fracturing fluid has been developed [25]. The erosion failure mechanism caused by various parameters, such as velocity of multiphase flow, fracturing proppant, and impact angles, has been investigated. Also, microcosmic surface testing was also used to analyze the erosion failure mechanism of metal materials at high-pressure pipelines.

1.5.4 Fluid leakoff While a hydraulic fracture is propagating, fluid flow and associated pressure drops must be accounted for both along the fracture path and also perpendicularly, into the formation that should be fractured [26]. Fluid leakoff is the main factor that governs the crack length. To find an effective approach for the mathematical description of this phenomenon, the thin crack can be represented as the boundary condition for pore pressure spreading in the formation. Such a model was already used for the conduction of heat into a rock formation from a seam in the course of injection of hot water. A solution for a linearized form of equations has been presented that allows the application of an integral transformation. The resulting analytical

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11

solution of the equations includes some integrals that can be calculated numerically. This model allows a rigorous tracking of the created fracture volume, leakoff volume, and increasing fracture width. The model is advantageous over discrete formulations and allows in-time calculations of the resulting fracture dimensions during the injection of the fracturing fluid [26].

1.5.5 Damaged well A detailed description of the conditions in the hydraulically damaged fracture environment after closure and how to integrate it into a reservoir simulation model has been presented [27]. A special algorithm for the initialization was developed and tested in a support tool to allow the computing of postfracture performance in tight gas formations by a reservoir simulator. To represent the fracture geometry and properties, the information about the distribution of the proppant concentration in the fracture as well as the fracture width variation was translated into the permeabilities and porosities of the fracture gridblocks. The fracture propagation in the course of the fracturing period under consideration of the leakoff processes was modeled. The penetration of the fracturing fluid into the matrix was modeled by using the Buckley–Leverett equations for a two-phase immiscible displacement [27].

1.5.6 Crosslinked fluids The rheology and convective heat transfer characteristics of boratecrosslinked guar and borate-crosslinked foam fracturing fluid has been assessed by conducting experiments on a large-scale test loop at 30 MPa [28]. The results indicate a severe chemical degradation of borate-crosslinked guar at elevated temperatures. When the temperature was higher than the threshold value, the crosslinking agent was almost disabled and the guar was no longer crosslinked. Also, the viscosity of the borate-crosslinked foam fracturing fluid was proportional to the increment of the quality of the foam. This is inversely proportional to the increase in temperature. The influence of the fluid behavior index on the velocity gradient of non-Newtonian fluid at the wall is substantial. A negative temperaturedependent convective heat transfer coefficient is found. The contribution of shear-induced bubble-scale microconvection significantly contributes to the heat transfer enhancement of a foam fluid.

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Hydraulic Fracturing Chemicals and Fluids Technology

Correlations between the viscosity and the convective heat transfer coefficient of the borate-crosslinked guar and the foam fracturing fluid were established [28].

1.5.7 Phase trapping Displacement pressure difference and initial water saturation are two key factors of evaluating water phase trapping damage under a given reservoir situation [29]. Requiring a high displacement pressure to drive liquid through a tight rock, the conventional method has difficulty in measuring very small liquid flow rates. Besides, there exists a strongly advantageous flow path selectivity phenomenon, causing a situation where the water existing in those thinner pores cannot be moved effectively. As a result, the irreducible water saturation is high after oil displacing water, thus leading to an overestimated oil permeability damage from water phase trapping. A high back pressure displacement method has been presented for the establishment of initial water saturation and the measurement of liquid permeability of core samples from tight oil reservoirs [29]. The damage of water phase trapping using this method was compared with the results that were obtained by a conventional method. According to the reservoir fluid flow situation, pore pressure and downstream pressure were simulated by the operation of back pressure. The results showed that an average initial water saturation of 46.2% was established by the conventional method. However, the saturation established with the use of the new method was only 29.9%, which was consistent with the results from sealed core data of the reservoir. The oil permeability damage derived from water phase trapping was estimated as an average of 37.0% with the conventional method while it was 21.8% by the new method. The conventional method overestimated the damage of water phase trapping at 41.4% [29]. Aqueous phase trapping often occurs when water-based fluids are used for drilling, completion, and stimulation operations [30]. Aqueous phase is known to lower the productivity of the tight gas sandstone reservoirs significantly. The use of surfactants is commonly recommended for mitigating the formation damage due to ubiquitous aqueous phase trapping in these reservoirs. However, mechanisms by which surfactants help to remove the formation damage due to aqueous phase are currently not fully understood. The mechanisms of the trapped aqueous phase removal from the tight gas sandstone formations were investigated by considering the effect of

General aspects

13

surfactants on the wettability alteration, the work of adhesion, and the apparent water film thickness. Theoretical methods suggest that furthermore the larger the contact angle that the drop of water creates with the reservoir rock surface is, the less energy is required for producing gas to displace the water from the reservoir [30]. A maximum increase in the contact angle was obtained when 0.05% cationic surfactant solution was used. Results from other experimental work have shown that the 0.05% cationic surfactant solution was conducive to reduce the work of adhesion, the water saturation, and the apparent water film thickness, thereby effectively removing the aqueous phase trapping damage and regaining rock permeability. Surfactants are becoming more effective in removing the trapped aqueous phase as the drawdown pressure increases [30].

1.5.8 Water imbibition Spontaneous imbibition in shale is commonly observed during and after hydraulic fracturing. This mechanism greatly influences hydrocarbon recovery in shale [31]. The recent advances in shale spontaneous imbibition have been reviewed from three aspects, i.e., conventional spontaneous imbibition models, common experimental methods, and key mechanisms that need to be focused on [31]. The water uptake of gas shales is critical for designing and optimizing hydraulic fracturing operations during which a large volume of fracturing water containing dissolved oxygen is injected into tight reservoirs [32]. Recent studies showed that the dissolved oxygen may promote certain oxidation reactions, which can affect the salinity and the pH of the flowback water. However, the effects of dissolved oxygen and oxidation reactions on water imbibition into the shale matrix and on the concentration of individual ions in flowback water are still poorly evaluated. Water imbibition experiments were conducted under degassed and oxic conditions. The imbibed water mass and the concentrations of different ions in water were measured. The results of the study showed that the initial rate and final amount of water imbibition were higher under degassed conditions compared with that under oxic conditions. These differences are mainly due to the enhanced dissolution of air in the shale pore network into the imbibing water under degassed conditions and the consequent increase in the relative permeability of water.

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Hydraulic Fracturing Chemicals and Fluids Technology

The results of the study also suggested that the oxidation of pyrite by dissolved oxygen produces sulfate and iron ions. The abundance of pores in the vicinity of pyrite minerals provides a pyrite-, water-, and oxygen-rich environment which favors the oxidation of pyrite [32]. The main influence factors, such as the permeability, clay content, fracturing fluid type, capillary pressure, wetting angle, and fracture were systematically investigated based on a guar gum fracturing fluid and the slickwater fracturing fluid both commonly used in the Ordos basin [33]. The results of the study showed that the clay content was the key factor to control capillary imbibition and osmosis, and the linear relationship between the volume of imbibed fluid and clay content of core sample was observed. In addition, for the loss of fracturing fluid, the important control factors were capillary imbibition and osmotic force. The capillary imbibition was 4.7 times the imbibed mass of osmotic absorption, and the guar gum fracturing fluid was 2 times the imbibition rate of slickwater fracturing fluid. These results indicate that the reservoir rock with fracture is advantageous to oil recovery in the imbibition process [33]. Surfactant-enhanced spontaneous imbibition is an effective method to enhance the oil recovery in shale reservoirs [34]. The effect of added surfactants on the spontaneous imbibition was investigated in shale rocks using NMR tests. Contact angles and IFT were measured to evaluate the efficiency of different surfactants in terms of wettability alteration and IFT reduction. According to the experimental results, the studied anionic surfactants perform better on the wettability alteration of shale rocks than studied nonionic surfactants, and the key factor to enhance the shale oil recovery may be wettability alteration [34].

1.6 Special applications Unconventional gas reservoirs, including tight gas, shale gas, and coalbed methane, are becoming a critically important component of the current and future gas supply [35]. However, these reservoirs often present unique stimulation challenges. The use of water-based fracturing fluids in low-permeability reservoirs may result in a loss of effective fracture half-length caused by phase trapping associated with the retention of the introduced water into the formation. This problem is still increased by the water-wet nature of most tight gas reservoirs, because of the strong spreading coefficient of water in such

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a situation. The retention of increased water saturation in the pore system can restrict the flow of gaseous hydrocarbons, such as methane. Capillary pressures of 10–20 MPa or higher can be present in lowpermeability formations at low water saturation. Furthermore, the use of water in unsaturated reservoirs may also reduce the permeability and thus the gas flow by a continuous increase in water saturation of the reservoir. Compositions of liquid petroleum gas and a volatile hydrocarbon fluid may be helpful for phase trapping of water [35].

1.6.1 Coiled tubing fracturing The success of coiled tubing fracturing in shallow wells has increased the interest in using coiled tubing also for fracturing deeper and hotter wells [36]. The key performance requirements of a coiled tubing fracturing fluid for deeper wells are low frictional pressure loss and an adequate proppant carrying capability after exposure to high-shear zones and high temperatures. The results of pilot-scale and field-scale testing have been presented [36]. These studies resulted in the development of an optimized coiled tubing fracturing fluid. Polymer-based fracturing fluids can be controllably delayed to have low frictional pressure loss through the curved coiled tubing unit and also through a straight tubing. However, the stability of the fluid can be reduced significantly when the fluid is pumped through a tubing with a small diameter and subsequently through high-shear zones. A correct selection of the fluid is required to meet the requirements in these environments. A successful formulation of a fluid needs to balance the limitations of frictional pressure loss with the maximum rheological stability of the fluid.

Hydrajet fracturing Hydrajet fracturing with coiled tubing is a unique technology for lowpermeability horizontal and vertical wells. This method uses fluids under high pressure to initiate and accurately place a hydraulic fracture without packer, saving operating time and lowering operating risk. A hydrajet fracturing tool has been described in the literature [37]. During the fracturing process the fracturing tool is positioned within a formation to be fractured and fluid is then jetted through the fluid jet against the formation at a pressure sufficient to cut through the casing and cement

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Hydraulic Fracturing Chemicals and Fluids Technology

sheath and form a cavity therein. The pressure must be high enough to also be able to fracture the formation by stagnation pressure in the cavity. A high stagnation pressure is produced at the tip of a cavity in a formation being fractured because of the jetted fluids being trapped in the cavity as a result of having to flow out of the cavity in a direction generally opposite to the direction of the incoming jetted fluid. The high pressure exerted on the formation at the tip of the cavity causes a fracture to be formed and extend some distance into the formation. In certain situations, a propping agent is suspended in the fracturing fluid which is deposited in the fracture. The propping agent may be a granular substance such as, for example, sand grains, ceramic or bauxite or other man-made grains, walnut shells, or other material carried in suspension by the fracturing fluid. The propping agent functions to prevent the fractures from closing and thereby provides conductive channels in the formation through which produced fluids can readily flow to the wellbore. The presence of the propping agent also increases the erosive effect of the jetting fluid [38]. The mechanisms of hydrajet perforation and hydrajet fracture initiation have been studied [39]. Frictions for one kind of fracturing fluid in coiled tubing have been computed to determine the pump pressure and flow rate for field testing. By comparison of theory and practice it has been proven that the theoretical calculation and field-testing data of hydraulic parameters are basically identical. It has been also proven that the tools meet the requirements of field testing [39].

1.6.2 Tight gas Hydraulic fracturing is one of the best technologies to improve the productivity from tight gas wells [40]. In such low-permeability reservoirs, careful consideration must be given to the proper selection of the fracturing fluid. Some reservoirs are underpressured and require the use of energized fluids, while others are sensitive to water-based fluids because of clay swelling and migration. Proppant pack damage because of gel residue is one of the primary causes of low production rates after hydraulic fracturing treatments. In order to minimize the damage and to maximize the production, a new premium, highly efficient fracturing fluid has been developed. This system is composed from carboxymethyl guar in small amounts and a zirconium crosslinking agent. The delay time of crosslinking can be adjusted, which makes the fluid ideal for deep-well fracturing and coiled

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17

tubing treatment since the frictional pressure losses can be minimized. The system can be energized or foamed with carbon dioxide and nitrogen or may also be used in binary foam systems. Case histories have been presented [40]. Energized fluids such as carbon dioxide foam or commingled carbon dioxide fluids are predominantly used for the optimization of the backflow and the proppant transport. Cold fracturing fluids have a strong cooling effect in the fracturing process mainly in rock stress reduction; however, these kinds of fluids should be precisely evaluated in terms of thermal stress effect, cleanup process, and proppant movement [41]. A cold water fluid has been tested successfully in geothermal reservoirs. This stimulation technique is successful in these fields but not in tight gas reservoirs. The use of liquid carbon dioxide as a fracturing fluid offers a viable method of stimulation. The successful application of these fluids to a variety of formations in the USA was shown. The process has proven to be an economical alternative to conventional stimulation fluids. Liquid nitrogen can also be used in limited cases. From these results it can be concluded that liquid carbon dioxide seems to be the most efficient fracturing fluid for tight gas stimulations. The coupling of the cold fracture technology with underground carbon dioxide capture and storage is an interesting promising alternative possibility [41].

1.6.3 Shale gas A method has been described for the in situ production of oil shale and gas hydrates wherein a network of fractures is formed by injecting liquified gases into a horizontally disposed fracturing borehole. Heat is thereafter applied to liquify the kerogen or to dissociate the gas hydrates so that shale oil or gases can be recovered from the fractured formations [42]. Liquid nitrogen injected at a fracturing pressure of 500 psi will increase its volume 14-fold at a temperature of −60◦ C (−75◦ F). If, however, no increase in fracture volume occurs, the expansion pressure would increase to approximately 7,000 psia at this temperature. The utilization of water as a heating agent is important because the injection of the water will replace the void spaces created by the dissociation of the gas hydrate and the shrinking of the hydrate ice and will also prevent possible slumping of the hydrate beds [43].

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Hydraulic Fracturing Chemicals and Fluids Technology

After injection, the heated water will dissociate the gas hydrate and the gas will migrate downward through the created fracture system to the lower production borehole and into the casing annulus and thence to the surface. The required energy to heat the water can be supplied by the combustion of the produced gas in fuel steam generators. The injection of the hot water should occur into the top of the gas hydrate zone to permit the injected water to migrate downward so that no old water would steal heat from the new water being injected, as would occur if injection was instigated from the lower zone. The hydrostatic pressure and increased injection pressure, with a lower production borehole pressure, would force the liberated gas to flow downward rather than upward from the buoyancy factor [43].

1.6.4 Coalbed methane The production of natural gas from coal typically requires a stimulation with hydraulic fracturing. Basic studies on the effectiveness of various treatment methods for coal beds have been presented in the literature [44,45]. Treating a coal seam with a well treatment fluid containing a dewatering agent will enhance the methane production through a well. This additive enhances the permeability of the formation to water production and binds tenaciously to the coal surface so that the permeability enhancement benefits are realized over a long production term. Dewatering surfactants can be poly(oxyethylene), poly(oxypropylene), and poly(ethylene carbonate)s [46] or p-tert -amylphenol condensed with formaldehyde, or they can be composed of a copolymer from 80–100% alkyl methacrylate monomers and hydrophilic monomers [47]. Selected compounds for this purpose are shown in Fig. 1.1. Such a well treatment fluid may be used in both fracturing and competition operations to enhance and maintain fracture conductivity over an extended period of production. Active water and plant gum fracturing fluids are widely used for coalbed methane in China [48]. However, there are limitations due to poor rheological properties, high content of water-insoluble substances, and high residual content. A gel fracturing fluid was used that is composed of nonionic poly(acrylamide), ZrOCl2 as crosslinking agent, a pH modifier, a gel breaker with (NH4 )2 S2 O8 , and an activator. This formulation was used in a lowtemperature (20–40◦ C) and low-permeability coalbed methane reservoir.

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19

Figure 1.1 Monomers for dewatering.

This type of gel fracturing fluid has the advantages of easy preparation, low cost, strong shearing resistance capacity, low filtration coefficient, rapid break, lack of residual after gel breaking, and ease of flowback. Further, the performance of gel fracturing fluid is superior to that of active water and vegetable gum, and it is very suitable for use as a fracturing treatment in coalbed methane at low temperatures [48]. Traditional hydraulic fracturing has become an effective stimulation method for the extraction of coalbed methane and has attained many remarkable achievements in the application. However, certain problems, such as greater water pressure, larger volume of fracturing equipment, and a stricter sealing requirement, have gradually arisen in the field application [49]. To improve the application situation, a newly developed technology of pulse hydraulic fracturing was proposed to enhance the coalbed methane drainage via accumulating the damages in the reservoirs and weakening the rock strength by exciting oscillation from pulsating water pressure. Comparison of fracture behaviors between pulse hydraulic fracturing and traditional hydraulic fracturing at various side-pressure ratios was executed using numerical software of PFC2D. The results demonstrated that the fracture pressures required for pulse hydraulic fracturing, which induced more cracks and a larger fracturing region, were all lower than those for traditional hydraulic fracturing. Additionally, the field application of pulse hydraulic fracturing was performed for the N2706 floor roadway

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with crossing holes in the Daxing coal mine, Liaoning Province, China. The results demonstrated that [49]: 1. all the fracturing holes for pulse hydraulic fracturing had lower fracture pressure than the calculated initiation pressure by traditional hydraulic fracturing, which is consistent with the simulation results, and 2. the drainage parameter values of holes made via pulse hydraulic fracturing, such as drainage concentration and drainage pure volume, were generally greater than those of traditional hydraulic fracturing. All of the simulation and application results expressed that pulse hydraulic fracturing had greater superiority than traditional hydraulic fracturing in the application of coalbed methane recovery based on the features of lower fracturing pressure and the generation of more cracks. A large amount of accumulated damage produced by pulse hydraulic fracturing could greatly destroy the integrality of coal, which induced the generation of many microcracks, significantly weakening the strength of the reservoir. Thus, more complicated fracture networks would be formed under a lower water pressure. Moreover, the proportion of mesopores and macropores increased after pulse hydraulic fracturing, and the porosity increased by 17.29%, which indicated that pulse hydraulic fracturing could significantly improve the permeability of coalbed methane reservoirs [49]. The permeability of coal is a key parameter in coalbed methane recovery. Minerals are known to occlude the flow paths and reduce coal permeability. The pore space variation of coal due to dissolution of syngenetic and epigenetic minerals was numerically simulated [50]. A high-resolution helical microcomputed tomography scanner was used to acquire three-dimensional images from the internal structure of a coal sample that contained both syngenetic and epigenetic minerals. Two subsets are then obtained from the images and segmented to separate syngenetic minerals, epigenetic minerals, and macerals [50]. The syngenetic and epigenetic minerals were dissolved individually and together and their impact on porosity and permeability was studied. The minerals are identified through scanning electron microscopy with energy dispersive spectroscopy (SEM-EDS). The dissolution process was performed based on a first-order kinetic reactive model. The numerical model combined lattice Boltzmann methods and finite volume methods. The results showed that the coal permeability significantly increases when a reactive solution is introduced. It was observed that the permeability increases due to the change of porosity and is approximately 50% greater when only epigenetic minerals are dissolved.

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21

So, it was demonstrated that dissolving syngenetic minerals that are contiguous to the connected flow network can enhance the permeability through increasing the available connected void spaces. Also, it was shown that the gap, which at some cases occurs due to mineral detachment from the fracture wall, has a direct impact on dissolution performance [50].

1.7 Shale reservoirs One main problem in shale reservoir development is the sharp decline in liquid production in all hydraulically fractured wells [51]. In recent years, CO2 huff-n-puff injection has been proved to be a potential method to enhance oil recovery. The effects of injection pressure and imbibition water on CO2 huff-n-puff performance were investigated. Eagle Ford core samples and Wolfcamp dead oil were used in this experimental study. The microscopic pore characteristics of Eagle Ford shale core samples were analyzed, and the results showed that 98.08% of the pore sizes are distributed between 3 nm and 50 nm. The experimental results demonstrated the great potential of CO2 huff-n-puff enhanced oil recovery (EOR). The cumulative oil recovery can reach 68% after seven huff-n-puff cycles. The oil recovered in each cycle decreases as the injection cycle number increases due to the permeability damage caused by asphaltene precipitation, oil saturation reduction, and low injected CO2 sweep efficiency. The effect of injection pressure was studied by injecting CO2 at both immiscible and miscible conditions. CO2 huff-n-puff has better performance (more than 9.1% EOR) under miscible conditions than immiscible conditions. After that, a novel experiment was designed to saturate the core samples with both water (15% KCl) and Wolfcamp dead oil to investigate the influence of imbibition water on CO2 huff-n-puff EOR performance. The existence of imbibition water impedes oil production in shale core samples. The oil recovery decreased about 45.3% after seven huff-n-puff cycles compared to the condition without water. A simulation study provided a better understanding of CO2 huff-n-puff application in liquid-rich shale reservoirs, which is fundamentally important for applying and optimizing CO2 huff-n-puff in field production [51]. Multistage hydraulic fracturing is an indispensable approach to enable shale oil available and affordable. However, a low flowback water recovery of usually less than 30% after fracking has been widely observed, which is triggering both technical and environmental concerns [52]. It has been confirmed that water uptake is a complex function of physicochemical pro-

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cesses in particular capillary forces. However, there have been a few direct investigations on the characterization of the wettability of oil–brine–shale from the geochemical perspective, especially organic matter, which impedes to better manage and predict flowback water recovery. To gain a deeper understanding of the system wettability, it was hypothesized that the hydraulic fracturing fluid (usually slick water with low salinity less than 5000 ppm) increases the hydrophilicity of oil–brine–organic matter systems, thereby contributing to water uptake in shale. Lowering salinity, particularly in Ca2+ and Mg2+ , increases the oil and organic matter surface potentials and facilitates electrical double layer expansion. Thus it triggers the hydrophilicity. A geochemical simulation was conducted using literature data to account for the incremental oil recovery from shale oil rocks in lowsalinity brines. Surface species and surface potential of oil and organic matters were computed as a function of pH for different brine salinity (280,000, 140,000, and 28,000 ppm of formation brine and 20,000 ppm of KCl) at different temperatures of 25◦ C, 60◦ C, and 100◦ C. Surface complexation modeling results showed that the oil–brine– organic matter system wettability is primarily controlled by in situ salinity and secondarily affected by pH and temperature. At a given pH, decreasing salinity triggers a greater positive surface potential for both oil and organic matter surfaces, implying a greater electrical double layer expansion and thus hydrophilicity. Moreover, the surface potential for oil and organic matter decreases with increasing pH, which would even be shifted from positive to negative in the presence of low-salinity water. Furthermore, the surface potential of both oil and organic matter decreases with increasing temperature at in situ pH from 3.5 to 7. The disjoining pressure results show that saturating a sample from high-salinity brine formation to lowsalinity KCl solution will shift the disjoining pressure from negative values (attraction) to positive values (repulsion). The results support the hypothesis that lowering the salinity increases the hydrophilicity of oil–brine–organic matter, which likely contributes to water uptake by shale [52]. Multistage hydraulic fracturing along with horizontal wells is widely used to create complex fracture networks in tight oil reservoirs [53]. An analysis of field flowback data showed that most of the fracturing fluids are contained in a complex fracture network, and fracture closure is the main driving mechanism during early cleanup. At present, the related fracture parameters cannot be accurately obtained, so it is necessary to study the

General aspects

23

impacts of fracture compressibility and the uncertainty on water loss and the subsequent production performance. A series of mechanistic models are established by considering stressdependent porosity and permeability [53]. The impacts of fracture uncertainties, such as natural fracture density, proppant distribution, and natural fracture heterogeneity, on flowback and productivity can be quantitatively assessed. The results of the study indicate that considering fracture closure during flowback can promote the water imbibition into the matrix and delay the oil breakthrough time compared with ignoring fracture closure. With the increase of natural fracture density, the oil breakthrough time is advanced, and more water is retained underground. When natural fractures connected with hydraulic fractures are propped, the well productivity will be enhanced, but proppant embedment can cause a loss of oil production. Additionally, the fracture network with more heterogeneity will lead to a lower flowback rate, which presents an insight in the role of fractures in water loss [53].

1.8 Hydraulic fracturing with nanoparticles A method for controlling fluid loss into the pores of an underground formation during fracturing operations has been presented [54]. Here, nanoparticles are added to the fracturing fluid to plug the pore throats of pores in the underground formation. As a result, the fracturing fluid is inhibited from entering the pores. By minimizing the fluid loss, higher fracturing fluid pressures are maintained, resulting in more extensive fracture networks. Additionally, the nanoparticles minimize the interaction between the fracturing fluid and the formation, especially in water-sensitive formations. As a result, the nanoparticles help maintain the integrity and conductivity of the generated, propped fractures. The nanoparticles are selected from the group consisting of silica, graphene, aluminum, iron, titanium, metal oxides, hydroxides, and mixtures thereof. The nanoparticles make up from about 0.01 g to about 10 g of nanoparticles per 100 ml of the pad fluid. Further, the nanoparticles have at least one flat face to thereby cover the pore throats and inhibit the movement of the pad fluid into the pores of the underground formation [54].

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1.8.1 Wellbore sealant using nanoparticles A wellbore can be internally sealed with nanoparticles [55]. Pore throats within the formation are plugged by the nanoparticles in the treatment fluid. Internal sealing reduces leakoff from filter cake damage, and also eliminates buildup of surface filter cake. Sealing the pore structure of a particular wellbore zone alleviates the need for additional lost circulation material, resulting in a very thin filter cake and significantly reducing the chance of differential sticking. Also, oil-based muds can be replaced with water-based equivalents. The nanoparticle treatment fluid results in a permanent reduction in the permeability of the formation, and is therefore particularly suitable for wells that will be stimulated using perforations, matrix acidizing, or fracturing techniques. In a tested embodiment, nanocrystalline cellulose with a length of about 100 nm and a diameter of about 6 nm was dispersed in an approximate 1% brine solution (CaCl2 /CaBr2 12.2 ppg [pounds per gallon], 14,618,82 g l−1 . To determine the extent of formation plugging, a measurement of the permeability of a core sample before and after introduction of a treatment fluid was performed (three pore volume, flow rate less than or equal to 2 ml min−1 ). The testing was done at 250◦ F (121◦ C). The initial and final core permeability was measured using a 2% KCl solution. The initial permeability of the tested core was measured to be 744 mD (flow rate less than or equal to 5 ml min−1 ). After introduction of the treatment fluid and a shutin time of approximately 18 h, the permeability of the core was down to 11 mD. Thus, the introduction of the nanocrystalline cellulose into the relatively high-permeability core created a significant pore plugging [55].

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[23] S.N. Shah, A.H.A. Kamel, Investigation of flow behavior of slickwater in large straight and coiled tubing, SPE Production & Operations 25 (1) (2010) 70–79. [24] Y. Cheng, Impact of water dynamics in fractures on the performance of hydraulically fractured wells in gas-shale reservoirs, Journal of Canadian Petroleum Technology 51 (2) (2012) 143–151. [25] J. Zhang, J. Fan, Y. Xie, H. Wu, Research on erosion of metal materials for high pressure pipelines, Advanced Materials Research (Durnten-Zurich, Switzerland) 482–484 (2) (2012) 1592–1595. [26] M.J. Economides, D.N. Mikhailov, V.N. Nikolaevskiy, On the problem of fluid leakoff during hydraulic fracturing, Transport in Porous Media 67 (3) (2007) 487–499. [27] A. Behr, G. Mtchedlishvili, T. Friedel, F. Haefner, Consideration of damaged zone in a tight gas reservoir model with a hydraulically fractured well, SPE Production & Operations 21 (2) (2006) 206–211. [28] X. Sun, S.-Z. Wang, Y. Bai, S.-S. Liang, Rheology and convective heat transfer properties of borate cross-linked nitrogen foam fracturing fluid, Heat Transfer Engineering 32 (1) (2010) 69–79. [29] J. Tian, Y. Kang, P. Luo, L. You, D. Zhang, A new method of water phase trapping damage evaluation on tight oil reservoirs, Journal of Petroleum Science & Engineering 172 (2019) 32–39. [30] Y. Zhong, H. Zhang, E. Kuru, J. Kuang, J. She, Mechanisms of how surfactants mitigate formation damage due to aqueous phase trapping in tight gas sandstone formations, Colloids and Surfaces. A, Physicochemical and Engineering Aspects 573 (2019) 179–187. [31] C. Li, H. Singh, J. Cai, Spontaneous imbibition in shale: A review of recent advances, Capillarity 2 (2) (2019) 17–32. [32] M. Xu, M. Binazadeh, A. Zolfaghari, H. Dehghanpour, Effects of dissolved oxygen on water imbibition in gas shales, Energy & Fuels 32 (4) (2018) 4695–4704. [33] S. Liu, J. Wang, H. He, H. Wang, Mechanism on imbibition of fracturing fluid in nanopore, Nanoscience and Nanotechnology Letters 10 (1) (2018) 87–93. [34] J. Liu, J.J. Sheng, Experimental investigation of surfactant enhanced spontaneous imbibition in chinese shale oil reservoirs using NMR tests, Journal of Industrial and Engineering Chemistry 72 (2019) 414–422. [35] R.S. Lestz, L. Wilson, R.S. Taylor, G.P. Funkhouser, H. Watkins, D. Attaway, Liquid petroleum gas fracturing fluids for unconventional gas reservoirs, Journal of Canadian Petroleum Technology 46 (12) (2007) 68–72. [36] K.E. Cawiezel, R.S. Wheeler, D.R. Vaughn, Specific fluid requirements for successful coiled-tubing fracturing applications, SPE Production & Operations 22 (1) (2007) 83–93. [37] D.M. Justus, Hydrajet perforation and fracturing tool, US Patent 7 159 660, assigned to Halliburton Energy Services, Duncan, OK, January 9, 2007. [38] J.B. Surjaatmadja, Hydrajet tool for ultra high erosive environment, US Patent 7 841 396, assigned to Halliburton Energy Services Inc., Duncan, OK, November 30, 2010. [39] S. Tian, G. Li, Z. Huang, J. Niu, Q. Xia, Investigation and application for multistage hydrajet-fracturing with coiled tubing, Petroleum Science and Technology 27 (13) (2009) 1494–1502. [40] D.V.S. Gupta, T.L. Jackson, G.J. Hlavinka, J.B. Evans, H.V. Le, A. Batrashkin, M.T. Shaefer, Development and field application of a low-pH, efficient fracturing fluid for

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tight gas fields in the Greater Green River basin, Wyoming, SPE Production & Operations 24 (4) (2009) 602–610. M.M. Rafiee, T. Wilsnack, H.D. Voigt, F. Haefner, Cold-frac technology in tight gas reservoirs, in: DGMK/OGEW-Frühjahrstagung des Fachbereiches Aufsuchung und Gewinnung, 2009, DGMK Tagungsbericht 1 (2009) 441–450. J.Q. Maguire, In-situ method of producing oil shale and gas (methane) hydrates, onshore and off-shore, US Patent 7 198 107, assigned to Maguire and James Q., Norman, OK, April 3, 2007. J.Q. Maguire, In-situ method of fracturing gas shale and geothermal areas, US Patent 7 784 545, August 31, 2010. M.W. Conway, R.A. Schraufnagel, The effect of fracturing fluid damage on production from hydraulically fractured wells, in: Proceedings Volume, Ala Univ. et al. Int. Unconven. Gas Symp. (Intergas 95), Tuscaloosa, AL, 5/14–20/95, 1995, pp. 229–236. G.S. Penny, M.W. Conway, Coordinated studies in support of hydraulic fracturing of coalbed methane, Final report (July 1990 – May 1995), Gas Res. Inst. Rep. GRI-95/0283, Gas Res. Inst., September 1995. K.H. Nimerick, J.J. Hinkel, Enhanced methane production from coal seams by dewatering, EP Patent 444 760, assigned to Pumptech NV and Dowell Schlumberger SA, September 4, 1991. W.M. Harms, E. Scott, Method for stimulating methane production from coal seams, US Patent 5 249 627, assigned to Halliburton Co., October 5, 1993. C. Dai, Q. You, H. Zhao, B. Guan, X. Wang, F. Zhao, A study on gel fracturing fluid for coalbed methane at low temperatures, Energy Sources, Part A: Recovery Utilization, and Environmental Effects 34 (1) (2011) 82–89. J. Xu, C. Zhai, L. Qin, Mechanism and application of pulse hydraulic fracturing in improving drainage of coalbed methane, Journal of Natural Gas Science and Engineering 40 (2017) 79–90. H.L. Ramandi, M. Liu, S. Tadbiri, P. Mostaghimi, Impact of dissolution of syngenetic and epigenetic minerals on coal permeability, Chemical Geology 486 (2018) 31–39. L. Li, J.J. Sheng, Y. Su, S. Zhan, Further investigation of effects of injection pressure and imbibition water on CO1 huff-n-puff performance in liquid-rich shale reservoirs, Energy & Fuels 32 (5) (2018) 5789–5798. L. Zeng, Y. Chen, M.M. Hossain, A. Saeedi, Q. Xie, Wettability alteration induced water uptake in shale oil reservoirs: A geochemical interpretation for oil-brine-OM interaction during hydraulic fracturing, International Journal of Coal Geology 213 (2019) 103277. K. Liao, S. Zhang, X. Ma, Y. Zou, Numerical investigation of fracture compressibility and uncertainty on water-loss and production performance in tight oil reservoirs, Energies 12 (7) (March 2019) 1189. P.d. Nguyen, J.C. Hampton, System and method for hydraulic fracturing with nanoparticles, US Patent Application 20180 010 435, assigned to Halliburton Energy Services, Inc., Houston, TX, January 2018. D.J. Brady, M.K.R. Panga, W. Abdallah, Wellbore sealant using nanoparticles, US Patent Application 20180 037 797, assigned to Schlumberger Technology Corp., February 2018.

CHAPTER 2

Fluid types Generally, a hydraulic fracturing treatment involves pumping a proppantfree viscous fluid, or pad, which is usually water with some fluid additives, in order to generate high viscosity, into a well faster than the fluid can escape into the formation. This causes the pressure to rise and the rock to break, creating artificial fractures or enlarging existing ones. After fracturing the formation, a propping agent, such as sand, is added to the fluid. This forms a slurry that is pumped into the newly formed fractures in the formation to prevent them from closing when the pumping pressure is released. The proppant transportability of a base fluid depends on the type of viscosifying additives that have been added to the water base [1]. Since the late 1950s, more than half of fracturing treatments have been conducted with fluids comprising guar gums or guar derivatives such as hydropropyl guar (HPG), hydroxypropyl cellulose (HPC), carboxymethyl guar, and carboxymethyl hydropropyl guar. Crosslinking agents based on boron, titanium, zirconium, or aluminum complexes are typically used to increase the effective molecular weight of the polymers and make them better suited for use in high-temperature wells. Cellulose derivatives, such as hydroxyethyl cellulose (HEC) or HPC and carboxymethylhydroxyethyl cellulose, are also used, with or without crosslinkers. Xanthan and scleroglucan have also been shown to have excellent proppant suspension ability, but they are more expensive than guar derivatives and are therefore used less frequently. Poly(acrylamide) (PAM) and polyacrylate polymers and copolymers are typically used for high-temperature applications or as friction reducers at low concentrations for all temperatures ranges [1]. Polymer-free, water-based fracturing fluids can be obtained by using viscoelastic surfactants (VESs). These fluids are normally prepared by mixing appropriate amounts of suitable surfactants such as anionic, cationic, nonionic, and zwitterionic surfactants. Their viscosity is attributed to the three-dimensional structure formed by the components in the fluids. The viscosity increases when the surfactant concentration exceeds a critical conHydraulic Fracturing Chemicals and Fluids Technology https://doi.org/10.1016/B978-0-12-822071-9.00009-8

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Figure 2.1 Betaine.

centration. Then the surfactant molecules aggregate into micelles, which can interact to form a network that exhibits viscous and elastic behavior. Cationic VESs – typically consisting of long-chain quaternary ammonium salts such as cetyltrimethylammonium bromide – have so far been the type attracting most commercial interest. Other common reagents that generate viscoelasticity in surfactant solutions include salts, such as ammonium chloride, potassium chloride, sodium chloride, sodium salicylate, and sodium isocyanate, and also nonionic organic molecules, such as chloroform. The electrolyte content of surfactant solutions is also important for controlling their viscoelastic behavior [1]. Fluids of this type of cationic VESs tend to loose their viscosity at high brine concentrations, hence they have seen limited use as gravel packing or drilling fluids. Anionic VESs are also used. Amphoteric/zwitterionic surfactants [2] and an organic acid or salt or an inorganic salt can also impart viscoelastic properties. The surfactants could be, for dihydroxyl alkyl glycinate, alkyl amphoacetate, or VES propionate, alkyl betaine, alkyl amidopropyl betaine, and alkylamino monoor dipropionates derived from certain waxes, fats, and oils. They are used in conjunction with inorganic water-soluble salt or organic additives such as phthalic acid, salicylic acid, or their salts. Amphoteric/zwitterionic surfactants, in particular those comprising a betaine moiety, are useful for a temperature up to about 150◦ C and are therefore of particular interest for medium- to high-temperature wells. Betaine is shown in Fig. 2.1. However, like the cationic viscoelastic surfactants mentioned above, anionic surfactants are usually not compatible with high brine concentrations. Polymer-free VES fluids are used to minimize the damage to the proppant pack and to efficiently transport the proppants into fractures. Proper assessment of the rheologic properties and the proppant settling of the fluids plays an important role in fracturing engineering [3].

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The rheology and viscosity temperature properties of a VES fracturing fluid have been investigated. The VES fluid behaves as a non-Newtonian shear thinning fluid and the power law model can be used to describe fluid rheology within a certain range of shear rate and temperature. However, with an increase of the shear rate and the temperature, the fluid approaches a Newtonian fluid. When the VES concentration is 4%, the fluid may generate a stable micromesh wormlike micelle structure, which results in a good viscoelasticity and a high proppant carrying capacity [3]. A formulation of an easy-to-prepare, surfactant-based polymer-free fluid has been described [4]. Possible components in the fluid that have been tested are tetradecyl trimethyl ammonium bromide, cetyl trimethyl ammonium bromide, octadecyl trimethyl ammonium bromide, and salicylic acid. The properties as a fracturing fluid were evaluated with regard to viscoelasticity and proppant carrying capability. These water-based gels have a strong capacity to carry proppants and a high viscoelasticity. The best performance was obtained from the gels derived from octadecyl trimethyl ammonium bromide with salicylic acid. The viscoelasticity of these gels increases with the ratio of ammonium bromide to acid [4]. Proppants can be sand, intermediate-strength ceramic proppants, or sintered bauxites, which can be coated with a resin to improve their clustering ability. They can be coated with resin or a proppant flowback control agent such as fibers. By selecting proppants having a property such as density, size, or concentration, different settling rates will be achieved. Waterfrac treatments combine low-cost, low-viscosity fluids to stimulate very low-permeability reservoirs. The treatments rely on the mechanisms of asperity creation (rock spalling), shear displacement of rock, and localized high concentration of proppant to create adequate conductivity, with the last mechanism being mostly responsible for the success of the treatment. The mechanism can be described as analogous to a wedge splitting wood. A viscous well treatment fluid is generally composed of a polysaccharide or synthetic polymer in an aqueous solution, which is crosslinked by an organometallic compound. Examples of well treatments in which metal crosslinked polymers are used are hydraulic fracturing, gravel packing operations, water blocking, and other well completion operations. In order for the treatment to be successful, the fluid viscosity should eventually diminish to a level approaching that of water after the proppant is placed. This allows a portion of the treating fluid to be recovered

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without producing excessive amounts of proppant after the well is opened and returned to production. If the viscosity of the fluid is low, it will flow naturally from the formation under the influence of formation fluids. This viscosity reduction or conversion is referred to as breaking, and is accomplished by incorporating chemical agents, referred to as breakers, into the initial gel. Some fracturing fluids, such as those based upon guar polymers, break naturally without the intervention of a breaking agent, but their breaking time is generally somewhere in the range from greater than 24 hours to weeks, months, or years, depending on the conditions in the reservoir. To decrease this break time, chemical agents are usually incorporated into the gel. These are typically either oxidants or enzymes that degrade the polymeric gel structure. Oxidizing agents, such as persulfate salts, chromous salts, organic peroxides or alkaline earth or zinc peroxide salts, or enzymes are the most effective. The timing of the break is also of great importance. Gels that break prematurely can cause suspended proppant material to settle out. They penetrate before a sufficient distance into the produced fracture. Premature breaking can also lead to a premature reduction in the fluid viscosity, resulting in an inadequate fracture width. On the other hand, gelled fluids that break too slowly can cause slow recovery of the fracturing fluid, with attendant delay in resuming production. Additional problems may occur, such as the tendency of proppant to become dislodged from the fracture, resulting in at least partial closing and decreased efficiency of the fracturing operation. The fracturing gel should preferably begin to break when the pumping operations are finished, and be completely broken within about 24 hours after completion of the treatment. Fracturing fluid compositions comprise a solvent, a polymer-soluble or hydratable in the solvent, a crosslinking agent, an inorganic breaking agent, an optional ester compound, and a choline carboxylate. The solvent may be an aqueous potassium chloride solution, and the inorganic breaking agent may be a metal-based oxidizing agent, such as an alkaline earth metal or a transition metal, or it may be magnesium, calcium, or zinc peroxide. The ester compound may be an ester of a polycarboxylic acid, such as an ester of oxalate, citrate, or ethylenediamine tetraacetate. Those having hydroxyl groups can also be acetylated, for instance, citric acid can be acetylated to form acetyl triethyl citrate, which is a preferred ester.

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Table 2.1 Components in fracturing fluids. Component/category

Function/remark

Water-based polymers

Thickener, to transport proppant, reduces leakoff in formation Reduce drag in tubing Form filter cake, reduce leakoff in formation if thickener is not sufficient Degrade thickener after job or disable crosslinker (wide variety of different chemical mechanisms) For diesel premixed gels For clay bearing formations Prevent water-wetting of formation Destroy emulsions Increase the stability of fluid (e.g., for elevated temperature applications) Increase the viscosity of the thickener For foam-based fracturing fluids Keep gels active longer Break a foam Same as crosslinkers for oil-based fracturing fluids Prevent microbial degradation Common Increase viscosity Used in water-sensitive formations Used also for other operations Premixed gel on diesel base Proppant material Proppant material

Friction reducers Fluid loss additives Breakers Emulsifiers Clay stabilizers Surfactants Nonemulsifiers pH control additives Crosslinkers Foamers Gel stabilizers Defoamers Oil-gelling additives Biocides Water-based gel systems Crosslinked gel systems Oil-based systems Polymer plugs Gel concentrates Resin-coated proppants Ceramics

The hydratable polymer can be a water-soluble polysaccharide, such as galactomannan or cellulose, and the crosslinking agent may be a borate, titanate, or zirconium containing compound, such as Na3 BO3 · n H2 O. A general review of commercially available additives for fracturing fluids is given in the literature [5]. Possible components in a fracturing fluid are listed in Table 2.1, which indicates the complexity of a fracturing fluid formulation. Some additives may not be used together, such as oil-gelling

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Hydraulic Fracturing Chemicals and Fluids Technology

Table 2.2 Various types of hydraulic fracturing fluids. Type

Remarks

Water-based fluids Oil-based fluids Alcohol-based fluids Emulsion fluids Foam-based fluids Noncomplex gelled water fracture Nitrogen foam fracture Complexed gelled water fracture Premixed gel concentrates In situ precipitation technique

Predominant Water-sensitive; increased fire hazard Rarely used High pressure, low temperature Low pressure, low temperature Simple technology Rapid cleanup Often the best solution Improve process logistics Reduces scale forming ingredients [7,8]

additives in a water-based system. More than 90% of the fluids are based on water. Aqueous fluids are economical and can provide control of a broad range of physical properties if used with additives. Additives for fracturing fluids serve two purposes [6]: 1. they enhance fracture creation and proppant carrying capability and 2. they minimize formation damage. Viscosifiers, such as polymers and crosslinking agents, temperature stabilizers, pH control agents, and fluid loss control materials assist the creation of a fracture. Formation damage is reduced by gel breakers, biocides, surfactants, clay stabilizers, and gases. Table 2.2 summarizes the various types of fluids and techniques used in hydraulic fracturing.

2.1 Comparison of different techniques The optimal technique to be used depends on the type of reservoir. Reports that compare the techniques in a related environment are available. In the Kansas Hugoton field (Mesa Limited Partnership), several hydraulic fracturing methods were tested [9]. A method in which a complexed gelled water fracture was applied was the most successful when compared with a foam technique and with older and simpler techniques. The study covers some 56 wells where such techniques were applied.

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35

2.2 Expert systems for assessment A PC-based, interactive computer model has been developed to help engineers choose the best fluid and additives and the most suitable propping agent for a given set of reservoir properties [10,11]. The model also optimizes treatment volume, based on reservoir performance and economics. To select the fluids, additives, and propping agents, the expert system surveys stimulation experts from different companies, reviews the literature, and then incorporates the knowledge so gained into rules, using an expert system shell. In addition, the fluid leakoff during hydraulic fracturing can be modeled, calculated, and measured experimentally. Procedures for converting laboratory data to an estimate of the leakoff under field conditions have been given in the literature [12].

2.3 Oil-based systems One advantage of fracturing with hydrocarbon gels compared with waterbased gels is that some formations may tend to imbibe large quantities of water, whereas others are water-sensitive and will swell if water is introduced.

2.4 Foam-based fracturing fluids Foam fluids can be used in many fracturing jobs, especially when environmental sensitivity is a concern [13]. Foam-fluid formulations are reusable, are shear-stable, and form stable foams over a wide temperature range. They exhibit high viscosities even at relatively high temperatures [14]. Carbon dioxide, nitrogen, and binary high-quality foams are widely used in tight and deep formations due to their capacity to energize the fluid and improve the total flowback volume and rate [15]. A foamed fracturing fluid has a relatively large volume of gas dispersed in a relatively small volume of liquid. A foamed fracturing fluid also includes a surfactant for facilitating the foaming and stabilization of the foam produced when the gas is mixed with the liquid [16]. A coarse foamed fluid has a relatively nonuniform bubble size distribution, e.g., a combination of large and small gas bubbles, whereas a fine texture foam has relatively uniform bubble size distribution and most of the bubbles are relatively small [17].

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Hydraulic Fracturing Chemicals and Fluids Technology

In coarse foamed fracturing fluids, there may be also regions of fine textured foam. Such foams are able to support the proppant in the fine textured regions even at very high foam quality levels. The most commonly used gases for foamed fracturing fluids are nitrogen and carbon dioxide because they are noncombustible, readily available, and relatively cheap [16]. Surfactants designed to reduce surface and interfacial tension are also a key element in the design of fluid systems to enhance recovery and reduce entrapment of fluid barriers within the formation [15]. Enhanced fluid recovery improves overall completions economics due to less total treatment cost and less time required for flowing back fluids. The most important benefit is achieving a less damaged proppant pack, resulting in higher fracture conductivity. The application of carbon dioxide-foamed fluids and surfactants to enhance fracturing fluid recovery have been reviewed [15]. Recyclable foamed fracturing fluids are available [18]. After placement, the pH of the fracturing fluid is changed so that the foam is destroyed. At this stage, the fracturing fluid also releases its proppant. Afterwards, the fracturing fluid is allowed to flow back to the surface. Eventually, it can be recycled by changing the pH of the fracturing fluid back to the first pH and adding a gas to the fluid, causing it to foam again.

2.4.1 Foam types Natural gas extraction is a greener solution to world energy resource depletion and water-based hydraulic fracturing is traditionally used to produce gas from deep and tight geological formations. However, since this practice fails to produce a commercially viable amount of gas and raises many environmental issues, better alternatives have been tested, among which the usage of foam-based fluid is a comparatively novel but effective technique. The methods used in foam-based fluid fracturing were reviewed [19]. Foams are made by mixing a gas phase with a liquid phase using a suitable surfactant, and the foam quality is composition-dependent, with high-quality foams having higher percentages of gas. The properties of the injecting foam, including its rheology and viscosity, are important for the fracturing process. The most widely used foam types in the industry and their constituents are described in Table 2.3. According to current studies, foams have two separate flow regimes (low and high quality) and a unique multiphase flow pattern. The foam viscosity should be low to enter the ends of the fracture and high to have a

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37

Table 2.3 Foam types [20]. Type

Water-based foams Carbon dioxide-based foams Acid-based foams Alcohol-based foams

Main constituents

Water + foaming surfactant + nitrogen (gas) or carbon dioxide (gas) Carbon dioxide (liquid) + foaming surfactant + nitrogen (gas) Acid + foaming surfactant + nitrogen (gas) Methanol + foaming surfactant + nitrogen (gas)

good proppant carrying capacity. Greater proppant carrying capacity, lower water consumption and chemical usage, quicker and easier fluid flowback, and less environmental damage are the advantages of foam-based fracturing, and lack of knowledge, high capital cost, and potential damage to the environment from surfactants are the limitations [19].

2.4.2 Shale gas fracturing using a foam-based fracturing fluid Actually, the extremely low permeability of shale plays has caused them to fail to produce a commercially viable amount of gas. Therefore, appropriate production enhancement techniques, including hydro-fracturing, are required [21]. The research on shale gas production enhancement using foam-based hydro-fracturing has been reviewed [21]. Further, the study focuses on research on shale deposit distribution around the world, the importance of shale gas recovery, major shale gas recovery enhancement techniques, the effectiveness of foam-based fracturing depending on the foam type used and the formation properties, advantages, and limitations of foam-based fracturing compared to other fluids, and existing experimental and numerical studies and field studies. According to the available experimental and modeling studies on foam fracturing, nitrogen-based foams are stronger than carbon dioxide-based foams. The effective viscosity that controls the foam rheology decreases with increasing temperature and decreasing pressure and foam quality, and fracture length reduces and fracture width increases with increasing foam quality. Although this technique has been tested in few shale plays worldwide, most studies have been performed in the USA and Canada. Therefore, the foam fracturing technique is still comparatively novel for other countries around the world [21].

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Hydraulic Fracturing Chemicals and Fluids Technology

2.4.3 Dry foams The amount of fresh water used in hydraulic fracturing can be significantly reduced by employing produced water-compatible supercritical CO2 foams [22]. Foams generated using surfactants only have suffered from long-term stability issues resulting in low viscosity and proppant carrying problems. Foam lamella stabilization with polyelectrolyte complex nanoparticles and wormlike micelles was investigated [22]. Electrostatic interactions were studied as the defining factors improving the hydraulic fracturing performance using the polyelectrolyte complex nanoparticle system prepared in produced water. Two oppositely charged polyelectrolytes were investigated to generate a more stable lamella between the aqueous phase and the supercritical CO2 while degrading in the presence of crude oil. The generated dry foam system was then used as a hydraulic fracturing fluid in a tight shale formation. The strong compatibility of the synthesized polyelectrolyte complex nanoparticles with zwitterionic surfactants prepared in highly concentrated brine in the form of wormlike micelles above the critical micelle concentration helps develop a highly viscous, dry foam capable of using produced water as its external phase. This foam system improves the fracture propagation and proppant transport fracture cleanup compared to the base case foam system with no polyelectrolyte complex nanoparticles. The formation of polyelectrolyte complex surfactant nanoparticles was verified via zeta potential, particle size analysis, and transmission electron microscopy; the underlying mechanism was identified as electrostatic rearrangement of wormlike micelles along the polyelectrolyte complex nanoparticle’s perimeter or formation of electrostatically bonded micelles with the nanoparticle to create a new enhanced nanoparticle. A Raman spectroscopic model was developed to understand the polyelectrolyte complex nanoparticle surfactant spectra and subsequent spectroscopic and hence structural changes associated with complexation [22]. An enhanced bulk viscosity and improved foam quality as a result of complexation at the interface were identified with rheometry in addition to sand pack experiments with polyelectrolyte complex nanoparticle surfactant ratios of 1:9 and 4:6 in 33.3 kppm and 66.7 kppm salinity brine systems, respectively. An enhancement in the shear thinning and cleanup efficiency of the fracturing fluid was observed. Formation damage was controlled by the newly introduced mixtures as fluid loss volume decreased across the tight Kentucky sandstone cores by up to 78% and 35% for supercritical CO2

Fluid types

39

foams made with polyelectrolyte complex nanoparticle wormlike micelles in 33.3 kppm and 66.7 kppm salinity brine, respectively. The produced water compatibility and reduction of water disposal presented the prospect of environmentally friendly supercritical CO2 foams for hydraulic fracturing of unconventional reservoirs [22].

2.5 Utilization of hydraulic fracturing fluids Recent advances in hydraulic fracturing, in conjunction with horizontal drilling, have enabled large-scale extraction of natural gas and oil from shale formations. Despite its advances and enormous economic benefits, opportunities remain to increase hydraulic fracturing efficiency and to minimize potential environmental impacts. Three key themes have been reviewed that are associated with development and utilization of hydraulic fracturing fluids [23]: 1. characteristics and behavior of fracturing fluids, 2. understanding and predicting migration and fate of fracturing fluids, and 3. technologies to reduce environmental impact of fracturing fluids. The key techniques and findings on rheology of hydrogel-based fluids, high-fidelity simulation of propagation transport, potential environmental impacts, geosynthetics in mitigating contamination, and greener fracturing fluids were discussed [23].

2.5.1 Chemical degradation of PAM during hydraulic fracturing PAM-based friction reducers are a primary ingredient of slickwater hydraulic fracturing fluids. However, only little is known regarding the fate of these polymers under downhole conditions, which could have important environmental impacts including decisions on strategies for reuse or treatment of flowback water [24]. The chemical degradation of a high-molecular weight PAM was evaluated, including the effects of shale, oxygen, temperature, pressure, and salinity [24]. The data were obtained with a slickwater fracturing fluid exposed both to a shale sample collected from a Marcellus outcrop and to Marcellus core samples at high pressures/temperatures simulating downhole conditions. Based on size exclusion chromatography analysis, the peak molecular weight of the PAM was reduced by 2 orders of magnitude, from roughly 10 MDa to 200 kDa under typical high-pressure/-temperature

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Hydraulic Fracturing Chemicals and Fluids Technology

fracturing conditions. The rate of degradation was independent of pressure and salinity but increased significantly at high temperatures and in the presence of oxygen dissolved in fracturing fluids. The results were consistent with a free radical chain scission mechanism, supported by measurements of sub-µM hydroxyl radical concentrations. The shale sample adsorbed some PAM of around 30%, but importantly it catalyzed the chemical degradation of PAM, likely due to dissolution of Fe2+ at low pH. These results give an evidence of the radical-induced degradation of PAM under high pressure/temperature hydraulic fracturing conditions without an additional oxidative breaker [24].

2.6 Improved thermal stability To withstand high-temperature environments, higher loadings of polymer are required for hydraulic fracturing fluids. This leads to an increase in polymer and additive concentrations [25]. However, these higher loading fluids do not break completely, and generate residual polymer fragments that can plug the formation and reduce fracture conductivity significantly. A new hybrid dual polymer hydraulic fracturing fluid was introduced that was developed for high-temperature applications [25]. The fluid consists of a guar derivative and a PAM-based synthetic polymer. Compared to conventional fracturing fluids, this system is easily hydrated, requires fewer additives, can be mixed on the fly, and is capable of maintaining excellent rheological performance at low polymer loadings. In this work, the fluid is further optimized to withstand even higher temperatures, up to 204◦ C. Total polymer loadings of 30 lb/1000 gal and 40 lb/1000 gal dual polymer fracturing fluid were tested and were prepared in the ratio of 1:1 and 1:2 (CMHPG:Synthetic). They were then crosslinked with a metallic crosslinker and placed in a rheometer to measure the viscosity between 200 and 400◦ F. After observing the failure temperature of the mixtures, additives such as buffers, crosslinking delayers, and oxygen scavengers were added and tested at temperatures above that point. The type of crosslinker used was also varied to observe the effects of the rate of release of the metallic crosslinker on thermal stability. The results indicate that the 1:2 (CMHPG:Synthetic) mixture performed better at temperatures exceeding 330◦ F than the 1:1 mixture. The failure points were 350◦ F for the latter and 370◦ F for the former. The addi-

Fluid types

41

tion of a crosslinker that allowed a more controllable release was observed to improve the thermal stability of the fluid mixture above 370◦ F by increasing the polymer’s shear tolerance. The addition of additives to the mixture was shown to improve the thermal stability of the solution to varying degrees. Of the three additives, the most significant enhancement came from the addition of oxygen scavengers while the least was from the buffer solution [25].

Furfural degradation Persulfate may be activated under conditions like those encountered in the wellbore, thus producing strong oxidizing radicals that degrade organic compounds. The persulfate-activated transformation of organic additives was examined in a simulated hydraulic fracturing brine by investigating the transformation of furfural [26]. Pseudofirst-order reaction kinetics of furfural degradation in conditions that mimic a fracture, including high temperature, acidified pH, ferric sulfate, and a laboratory-simulated hydraulic fracturing brine, were established. The activation energies for furfural removal in acidic (pH 2.54) hydraulic fracturing brine was 105.6 kJ mol−1 without ferric sulfate and 105.1 kJ mol−1 with 23.3 mg l−1 ferric sulfate. A high-pressure reactor was used to simulate the effects of pressure on persulfate activation. Increasing pressure was shown to increase activation of persulfate at 55◦ C. Applying 3000 psi (207 bar) to the reactor nearly halved the apparent furfural activation energy compared to experiments under atmospheric pressure. Finally, reaction byproducts were presented with the findings showing that halogenated organic byproducts form in hydraulic fracturing brine during persulfate use [26].

2.7 Acid fracturing A difference exists between acid fracturing and matrix acidizing. Acid fracturing is used for low-permeability, acid-soluble rocks. Matrix acidizing is a technique used for high-permeability reservoirs. Candidates for acid fracturing are formations such as limestones (CaCO3 ) or dolomites (CaCO3 × MgCO3 ). These materials react easily with hydrochloric acid to form chlorides and carbon dioxide. In comparison with the fracturing technique with proppants, acid fracturing has the advantage that no problem with proppant cleanout will appear. The acid etches the fracture faces unevenly, which on

42

Hydraulic Fracturing Chemicals and Fluids Technology

closure retain a highly conductive channel for the reservoir fluid to flow into the wellbore [27]. On the other hand, the length of the fracture is shorter, because the acid reacts with the formation and therefore is spent. If traces of fluoride are in the hydrochloric acid, then insoluble calcium fluoride is precipitated out. Therefore, plugging by the precipitate can jeopardize the desired effect of stimulation.

2.7.1 Encapsulated acids Acids, in particular, and etching agents, in general, may be mixed with a gelling agent and encapsulated with oils and polymers [28,29].

2.7.2 In situ formation of acids While acid fracturing is usually applicable for carbonate formations, acid fracturing in sandstone formations has been not a common practice due to the low rock solubility of mud acid. Methods and compositions that are useful in effective acid fracturing of sandstone formations have been developed. Such a method of acid fracturing consists of [30]: 1. injecting into the formation an acid fracturing fluid at a pressure sufficient to form fractures within the formation, the acid fracturing fluid comprising a sulfonate ester, a fluoride salt, a proppant, and water, the sulfonate ester being hydrolyzed to produce sulfonic acid and 2. producing hydrofluoric acid in situ in the formation by reacting the sulfonic acid with the fluoride salt subsequent to injection of the acid fracturing fluid into the formation. Generating hydrofluoric acid in situ makes it possible to perform acid fracturing of sandstone formations with the assistance of partial monolayers of effectively placed propping agents and to create enlarged propped fractures. Increased fracture widths will lead to higher fracture conductivity and enhanced hydrocarbon production than what is generally achieved from a conventional propped fracturing treatment.

2.7.3 Fluid loss Fluid loss limits the effectiveness of acid fracturing treatments. Therefore, formulations to control fluid loss have been developed and characterized [31,32]. It was discovered that viscosifying the acid resulted in a remarkable improvement in acid fluid loss control. The enhancement was most pronounced in very low-permeability limestone cores. The nature of the

Fluid types

43

viscosifying agent also influenced the success. Polymeric materials were more effective than surfactant type viscosifiers [33]. A viscosity-controlled acid contains gels that break back to the original viscosity 1 day after being pumped. These acids have been used both for matrix acidizing and for fracture acidizing to obtain longer fractures. The pH of the fluid controls the gel formation and breaking. The gels are limited to formation temperatures of 50–135◦ C [34].

2.7.4 Gel breaker for acid fracturing A particulate gel breaker for acid fracturing for gels crosslinked with titanium or zirconium compounds is composed of complexing materials such as fluoride, phosphate, sulfate anions, and multicarboxylated compounds. The particles are coated with a water-insoluble resin coating, which reduces the rate of release of the breaker materials of the particles so that the viscosity of the gel is reduced at a retarded rate [35].

2.8 Special problems 2.8.1 Corrosion inhibitors Water-soluble 1,2-dithiol-3-thiones for fracturing fluids and other workover fluids have been described as corrosion inhibitors for aqueous environments [36]. These compounds are prepared by reacting a poly(ethylene oxide) that is capped with isopropylphenol with elemental sulfur. The compounds perform better in aqueous systems than their nonoxylated analogs. The concentration range is usually in the 10–500 ppm range, based on the weight of the water in the system.

2.8.2 Iron control in fracturing Results from laboratory tests and field jobs show that iron presents a significant and complex problem in stimulation operations [37]. The problem presented by an acidizing fluid differs from that presented by a nonacidic or weakly acidic fracturing fluid. In general, acid dissolves iron compounds from the equipment and the flow lines as it is mixed and pumped into the formation. The acid may dissolve additional iron as it reacts with the formation. If the fluid does not contain an effective iron control system, the dissolved iron could precipitate. This precipitate may then accumulate as it is carried toward the wellbore during flowback. This accumulation of solids may de-

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Hydraulic Fracturing Chemicals and Fluids Technology

Figure 2.2 Complexing agents for iron control.

crease the natural and the created permeability and can have a detrimental effect on the recovery of the treating fluid and production. Iron can be controlled with certain complexing agents, in particular glucono-δ -lactone, citric acid, ethylenediamine tetraacetic acid, nitrilo triacetic acid, hydroxyethylethylenediaminetriacetic acid, hydroxyethyliminodiacetic acid, and the salts from those compounds. These compounds must be added together with nitrogen containing compounds such as hydroxylamine salts or hydrazine salts [38–40]. Some complexing agents are shown in Fig. 2.2. In general, chelating agents possess some unique chemical characteristics. The most significant attribute of these chemicals is the high solubility of the free acids in aqueous solutions. Linear core flood tests were used to study the formation of wormholes. Both hydroxyethylethylenediaminetriacetic acid and hydroxyethyliminodiacetic acid produced wormholes in limestone cores when tested at 65◦ C (150◦ F). However, the efficiency and capacities differ. Because these chemicals have a high solubility in the acidic pH range, it was possible to test acidic formulations with a pH of less than 3.5 [41].

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Table 2.4 Formulation for a high-temperature guar-based fracturing fluid [45]. Component Action

Guar gum Zirconium or hafnium compound Bicarbonate salt

Thickener Crosslinking agent Buffer

To control the iron in an aqueous fracturing fluid having a pH below 7.5, a thioalkyl acid may be added [42]. This is a reducing agent for the ferric ion, contrary to the complexants described in the previous paragraph.

2.8.3 Enhanced temperature stability During the initial fracturing process, degradation which results in a decrease in viscosity is undesirable. The polymer in fracturing fluids will degrade at elevated temperatures. One method to prevent degradation too early is to cool down the formation with large volumes of pad solution before the fracturing job. Furthermore, the temperature stability of the fracturing fluid is extended through the addition of quantities of unhydrated, particulate guar or guar derivative polymers before pumping the fracturing fluid into the formation [43]. Finally, the adjustment of the pH to moderate alkaline conditions can improve the stability. The temperature resistance of guar gum can be improved by silanization [44]. The optimal reaction conditions are a reaction temperature of 85◦ C and a molar ratio of guar gum to trimethylsilane chloride of 5:1. The viscosity of a silanized guar gum-based aqueous gel was greatly improved even at a high temperature of 80◦ C. The preferred crosslinkers for high-temperature applications are zirconium compounds. A formulation for a high-temperature guar-based fracturing fluid is given in Table 2.4. The fracturing fluid exhibits good viscosity and is stable at moderate to high temperatures of 80–120◦ C.

2.8.4 Chemical blowing The efficiency of a fracturing fluid produced back from a formation can be increased by adding blowing agents [46,47]. After placing the blowing agent, for example, agglomerated particles and granules containing the blowing agent and fracturing the formation, the blowing agent decomposes. Blowing agents are summarized in Table 2.5. Thereby the filter cake

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Hydraulic Fracturing Chemicals and Fluids Technology

Table 2.5 Blowing agents [47]. Chemical compound

Dinitrosopentamethylenetetramine Sodium hydrogen carbonate p-Toluene sulfonyl hydrazide Azodicarbonamide p,p -Oxybis(benzenesulfonyl hydrazide) Table 2.6 Frost-resistant formulation for hydraulic fracturing fluids [48]. Component

%

phasea

Hydrocarbon Surfactant Mineralized water Sludge from production of sulfonate additives (hydrocarbons 10–30%, calcium sulfonate 20–30%, calcium carbonate and hydroxide 18–40%)b Emultalc a b c

2 to 20

10 to 35

0.5 to 2.0

Gas condensate, oil, or benzene. Slows down filtration and increases sand holding capability, frost resistance, and stability. Surfactant emulsifier.

becomes more porous or provides a driving force for the removal of fluid load from the matrix. Increased porosity enhances the communication between the formation and the fracture, thus increasing the efficiency of the production of the fracturing fluid. The gas liberation within the matrix establishes the communication pathways for subsequent fracture and the well.

2.8.5 Frost-resistant formulation A frost-resistant formulation is given in Table 2.6. The composition has a frost resistance of −35 to −45◦ C [48].

2.8.6 Formation damage in gas wells A study [49] on formation damage using artificially fractured, low-permeability sandstone cores indicated that viscosified fracturing fluids can severely restrict the gas flow through narrow fractures. Poly(saccharide) polymers such as hydroxypropyl guar, HEC, and xanthan gum caused a significant reduction in gas flow through the cracked cores, of up to 95%.

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47

In contrast, PAM gels caused little or no reduction in the gas flow through cracked cores after a liquid cleanup. Other components of fracturing fluids, such as surfactants and breakers, caused less damage to gas flows.

2.9 Characterization of fracturing fluids Historically, viscosity measurements have been the single most important method to characterize fluids in petroleum producing applications. Whereas the ability to measure a fluid’s resistance to flow has been available in the laboratory for a long time, a need to measure the fluid properties at the well site has prompted the development of more portable and less sophisticated viscosity measuring devices [50]. These instruments must be durable and simple enough to be used by persons with a wide range of technical skills. As a result, the Marsh funnel and the Fann concentric cylinder, both variable-speed viscometers, have found wide use. In some instances, the Brookfield viscometer has also been used. However, it has been established that an intense control of certain variables may improve the execution of a hydraulic fracturing job and the success of a stimulation. Therefore, an intense quality control is recommended [51,52]. Such a program includes monitoring the breaker performance at low temperatures and measuring the sensitivity of fracturing fluids to variations in crosslinker loading, temperature stabilizers, and other additives at higher temperatures.

2.9.1 Rheologic characterization To design a successful hydraulic fracturing treatment employing crosslinked gels, accurate measurements of the rheologic properties of these fluids are required. Rheologic characterization of borate-crosslinked gels turned out to be difficult with a rotational viscometer. In a laboratory apparatus, field pumping conditions (i.e., crosslinking the fluid on the fly) and fluid flow down tubing or casing and in the fracture could be simulated [53]. The effects of the pH and temperature of the fluid and the type and concentration of the gelling agent on the rheologic properties of fluids have been measured. These parameters have significant effects on the final viscosity of the gel in the fracture. Correlations to estimate friction pressures in field-size tubulars have been developed from laboratory test data. In conjunction

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Hydraulic Fracturing Chemicals and Fluids Technology

Figure 2.3 Colorimetric reagent to measure zirconium levels in gels.

with field calibrations, these correlations can aid in accurate prediction of the friction pressure of borate-crosslinked fluids.

2.9.2 Zirconium-based crosslinking agent The concentration of a crosslinking agent containing zirconium in a gel is determined by first adding an acid to break the gel and converting the zirconium into the ionic noncomplexed form [54], followed by the addition of Arsenazo III to produce a colored complex, which can be detected with standard colorimetric methods. Arsenic compounds are highly toxic. The colorimetric reagent to measure zirconium in gels is shown in Fig. 2.3.

2.9.3 Oxidative gel breaker The concentration of an oxidative gel breaker can be measured by colorimetric methods, by periodically or continuously sampling the gel [55]. The colorimetric reagent is sensitive to oxidizing agents. It contains iron ions and thiocyanate. Thus the quantity of breaker added to the fracturing fluid can be controlled. The method is based on the oxidation of ferrous ions to ferric ions, Fe2+ A Fe3+ + e− , which form a deep red complex with thiocyanate.

2.9.4 Size exclusion chromatography Size exclusion chromatography [56,57] has been used to monitor the degradation of the thickeners initiated by various oxidative and enzymatic breakers. The research revealed that a partially broken or unbroken polymer may result in a significant reduction of the flow through a porous medium. An

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insoluble residue was generated during the degradation of guar polymers. This residue can affect the pore size of the medium [58].

2.9.5 Assessment of proppants There are standardized methods for the characterization of the effect of proppants [59,60]. The general methods of assessment have been exemplified [61]. For some proppants, the experiments reveal relationships between the long-term fracture conductivity and the closure pressure as a polynomial [61], F = A1 + A2 P + A3 P 2 + A4 P 3 ,

(2.1)

where F is the long-term fracture conductivity, P is the closure pressure, and Ai are some constants. Similarly, an exponential relationship between fracture conductivity F and time t has be obtained for a certain closure pressure [61], F = exp(−A5 t) + A6 .

(2.2)

References [1] B. Lukocs, S. Mesher, T.P.J. Wilson, T. Garza, W. Mueller, F. Zamora, L.W. Gatlin, Non-volatile phosphorus hydrocarbon gelling agent, July 2007. [2] T.L. Allan, J. Amin, A.K. Olson, R.G. Pierce, Fracturing fluid containing amphoteric glycinate surfactant, US Patent 7 399 732, assigned to Calfrac Well Services Ltd., Calgary, Alberta, CA, Chemergy Ltd., Calgary, Alberta, CA, July 15, 2008. [3] Z. Wang, S. Wang, X. Sun, The influence of surfactant concentration on rheology and proppant-carrying capacity of VES fluids, Advanced Materials Research (DurntenZurich, Switzerland): Pt. 1, Natural Resources and Sustainable Development 361–363 (2012) 574–578. [4] Q. Deng, J. Xu, X. Gu, Y. Tang, Properties evaluation of polymer-free fluid for fracturing application, Advanced Materials Research (Durnten-Zurich, Switzerland): Pt. 2, Advanced Composite Materials 482–484 (2012) 1180–1183. [5] Anonymous, Fracturing products and additives, World Oil 220 (8) (August 1999), 135, 137, 139–145. [6] P.C. Harris, Fracturing-fluid additives, Journal of Petroleum Technology 40 (10) (October 1988) 1277–1279. [7] M.J. Hrachovy, Hydraulic fracturing technique employing in situ precipitation, WO Patent 9 406 998, assigned to Union Oil Co. California, March 31, 1994. [8] M.J. Hrachovy, Hydraulic fracturing technique employing in situ precipitation, US Patent 5 322 121, assigned to Union Oil Co. California, June 21, 1994. [9] T.L. Cottrell, W.D. Spronz, W.C. Weeks III, Hugoton infill program uses optimum stimulation technique, Oil & Gas Journal 86 (28) (1988) 88–90.

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[10] S.A. Holditch, H. Xiong, Z. Rahim, J. Rueda, Using an expert system to select the optimal fracturing fluid and treatment volume, in: Proceedings Volume, SPE Gas Technol. Symp., Calgary, Can, 6/28–30/93, 1993, pp. 515–527. [11] H. Xiong, B. Davidson, B. Saunders, S.A. Holditch, A comprehensive approach to select fracturing fluids and additives for fracture treatments, in: Proceedings Volume, Annu. SPE Tech. Conf., Denver, 10/6–9/96, 1996, pp. 293–301. [12] G.S. Penny, C.M. W, Fluid Leakoff, Recent Advances in Hydraulic Fracturing (SPE Henry L. Doherty Monogr Ser), vol. 12, SPE, Richardson, Texas, 1989, pp. 147–176. [13] A.L. Stacy, R.B. Weber, Method for reducing deleterious environmental impact of subterranean fracturing processes, US Patent 5 424 285, assigned to Western Co. North America, June 13, 1995. [14] J.E. Bonekamp, G.D. Rose, D.L. Schmidt, A.S. Teot, E.K. Watkins, Viscoelastic surfactant based foam fluids, US Patent 5 258 137, assigned to Dow Chemical Co., November 2, 1993. [15] H.C. Tamayo, K.J. Lee, R.S. Taylor, Enhanced aqueous fracturing fluid recovery from tight gas formations: foamed CO2 pre-pad fracturing fluid and more effective surfactant systems, Journal of Canadian Petroleum Technology 47 (10) (2008) 33–38. [16] T.D. Welton, B.L. Todd, D. McMechan, Methods for effecting controlled break in pH dependent foamed fracturing fluid, US Patent 7 662 756, assigned to Halliburton Energy Services, Inc., Duncan, OK, February 16, 2010. [17] R.L. Middaugh, P.C. Harris, S.J. Heath, R.S. Taylor, O.F. Hoch, M.L. Phillippi, B.F. Slabaugh, J.M. Terracina, Coarse-foamed fracturing fluids and associated methods, US Patent 7 261 158, assigned to Halliburton Energy Services, Inc., Duncan, OK, August 28, 2007. [18] J. Chatterji, B.J. King, K.L. King, Recyclable foamed fracturing fluids and methods of using the same, US Patent 7 205 263, assigned to Halliburton energy Services, Inc., Duncan, OK, April 17, 2007. [19] W.A.M. Wanniarachchi, P.G. Ranjith, M.S.A. Perera, A. Lashin, N. Al Arifi, J.C. Li, Current opinions on foam-based hydro-fracturing in deep geological reservoirs, Geomechanics and Geophysics for Geo-Energy and Geo-Resources 1 (3–4) (2015) 121–134. [20] L. Gandossi, U. Von Estorff, An overview of hydraulic fracturing and other formation stimulation technologies for shale gas production, Eur. Commisison Jt. Res. Cent. Tech. Reports 26347, 2015, pp. 1–57. [21] W.A.M. Wanniarachchi, P.G. Ranjith, M.S.A. Perera, Shale gas fracturing using foambased fracturing fluid: a review, Environmental Earth Sciences 76 (2) (2017) 91. [22] H. Hosseini, J.S. Tsau, K. Shafer-Peltier, C. Marshall, Q. Ye, R. Barati Ghahfarokhi, Experimental and mechanistic study of stabilized dry CO2 foam using polyelectrolyte complex nanoparticles compatible with produced water to improve hydraulic fracturing performance, Industrial & Engineering Chemistry Research 58 (22) (2019) 9431–9449. [23] L. Thomas, H. Tang, D.M. Kalyon, S. Aktas, J.D. Arthur, J. Blotevogel, J.W. Carey, A. Filshill, P. Fu, G. Hsuan, T. Hu, D. Soeder, S. Shah, R.D. Vidic, M.H. Young, Toward better hydraulic fracturing fluids and their application in energy production: a review of sustainable technologies and reduction of potential environmental impacts, Journal of Petroleum Science and Engineering 173 (2019) 793–803. [24] B. Xiong, Z. Miller, S. Roman-White, T. Tasker, B. Farina, B. Piechowicz, W.D. Burgos, P. Joshi, L. Zhu, C.A. Gorski, A.L. Zydney, M. Kumar, Chemical degradation

Fluid types

[25]

[26]

[27] [28]

[29] [30] [31]

[32]

[33]

[34] [35] [36] [37]

[38] [39]

[40] [41]

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of polyacrylamide during hydraulic fracturing, Environmental Science & Technology 52 (1) (2018) 327–336. T. Almubarak, L. Li, H. Nasr-El-Din, J.H. Ng, K. Sokhanvarian, M. Alkhaldi, S. Almubarak, Pushing the thermal stability limits of hydraulic fracturing fluids, in: SPE Asia Pacific Oil and Gas Conference and Exhibition, Society of Petroleum Engineers, Brisbane, Australia, 2018, pp. 1–16. K.E. Manz, T.J. Adams, K.E. Carter, Furfural degradation through heat-activated persulfate: impacts of simulated brine and elevated pressures, Chemical Engineering Journal 353 (2018) 727–735. H. Mukherjee, G. Cudney, Extension of acid fracture penetration by drastic fluid-loss control, SPE Unsolicited Paper (1992). M.E. Gonzalez, M.D. Looney, The use of encapsulated acid in acid fracturing treatments, WO Patent 0 075 486, assigned to Texaco Development Corp. and Gonzalez, Manuel E. and Looney, Mark D., December 14, 2000. M.E. Gonzalez, M.D. Looney, Use of encapsulated acid in acid fracturing treatments, US Patent 6 207 620, assigned to Texaco Inc., March 27, 2001. Q. Qu, X. Wang, Method of acid fracturing a sandstone formation, US Patent 7 704 927, assigned to BJ Services Company, Houston, TX, April 27, 2010. B.D. Sanford, C.R. Dacar, S.M. Sears, Acid fracturing with new fluid-loss control mechanisms increases production, little knife field, North Dakota, in: Proceedings Volume, SPE Rocky Mountain Reg. Mtg., Casper, Wyo, 5/18–21/92, 1992, pp. 317–324. D.J. White, B.A. Holms, R.S. Hoover, Using a unique acid-fracturing fluid to control fluid loss improves stimulation results in carbonate formations, in: Proceedings Volume, SPE Permian Basin Oil & Gas Recovery Conf., Midland, Texas, 3/18–20/92, 1992, pp. 601–610. R.D. Gdanski, Fluid properties and particle size requirements for effective acid fluidloss control, in: Proceedings Volume, SPE Rocky Mountain Reg. Mtg.: Low Permeability Reservoirs Symp., Denver, 4/26–28/93, 1993, pp. 81–94. V. Yeager, C. Shuchart, In situ gels improve formation acidizing, Oil & Gas Journal 95 (3) (1997) 70–72. J.L. Boles, A.S. Metcalf, J.C. Dawson, Coated breaker for crosslinked acid, US Patent 5 497 830, assigned to BJ Services Co., March 12, 1996. B.A. Oude Alink, Water soluble 1,2-dithio-3-thiones, US Patent 5 252 289, assigned to Petrolite Corp., October 12, 1993. P. Smolarchuk, W. Dill, Iron control in fracturing and acidizing operations, in: Proceedings Volume, volume 1, 37th Annu. Cim. Petrol. Soc. Tech. Mtg., Calgary, Can, 6/8–11/86, 1986, pp. 391–397. W.R. Dill, W.G.F. Ford, M.L. Walker, R.D. Gdanski, Treatment of iron-containing subterranean formations, EP Patent 258 968, March 9, 1988. W.W. Frenier, Well treatment fluids comprising chelating agents, WO Patent 0 183 639, assigned to Sofitech NV and Schlumberger Serv. Petrol and Schlumberger Canada Ltd. and Schlumberger Technol. BV and Schlumberger Holdings Ltd., November 8, 2001. M.L. Walker, W.G.F. Ford, W.R. Dill, R.D. Gdanski, Composition and method of stimulating subterranean formations, US Patent 4 683 954, August 4, 1987. W.W. Frenier, C.N. Fredd, F. Chang, Hydroxyaminocarboxylic acids produce superior formulations for matrix stimulation of carbonates, in: Proceedings Volume, SPE Europe Formation Damage Conf., The Hague, Netherlands, 5/21–22/2001, 2001.

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[42] M. Brezinski, T.R. Gardner, W.M. Harms, J.L. Lane Jr., K.L. King, Controlling iron in aqueous well fracturing fluids, EP Patent 599 474, assigned to Halliburton Co., June 1, 1994. [43] K.H. Nimerick, C.L. Boney, Method of fracturing high temperature wells and fracturing fluid therefore, US Patent 5 103 913, assigned to Dowell Schlumberger Inc., April 14, 1992. [44] J. Zhang, G. Chen, Improvement of the temperature resistance of guar gum by silanization, Advanced Materials Research (Durnten-Zurich, Switzerland): Pt. 1, Advanced Materials 415–417 (2012) 652–655. [45] H.D. Brannon, R.M. Hodge, K.W. England, High temperature guar-based fracturing fluid, US Patent 4 801 389, assigned to Dowell Schlumberger Inc., January 31, 1989. [46] I.S. Abou-Sayed, R.D. Hazlett, Removing fracture fluid via chemical blowing agents, US Patent 4 832 123, assigned to Mobil Oil Corp., May 23, 1989. [47] A.R. Jennings Jr., Method of enhancing stimulation load fluid recovery, US Patent 5 411 093, assigned to Mobil Oil Corp., May 2, 1995. [48] K.A. Barsukov, V.Y. Ismikhanov, A.A. Akhmetov, G.S. Pop, G.A. Lanchakov, V.M. Sidorenko, Composition for hydro-bursting of oil and gas strata – consists of hydrocarbon phase, sludge from production of sulphonate additives to lubricating oils, surfactant-emulsifier and mineralised water, SU Patent 1 794 082, assigned to Urengoi Prod. Assoc., February 7, 1993. [49] B.L. Gall, D.R. Maloney, C.J. Raible, A.R. Sattler, Permeability damage to natural fractures caused by fracturing fluid polymers, in: Proceedings Volume, SPE Rocky Mountain Reg Mtg., Casper, Wyo, 5/11–13/88, 1988, pp. 551–560. [50] C.F. Parks, P.E. Clark, O. Barkat, J. Halvaci, Characterizing polymer solutions by viscosity and functional testing, in: Proceedings 192nd ACS Nat. Mtg., vol. 55, Amer. Chem. Soc. Polymeric Mater Sci Eng. Div Tech. Program, Anaheim, Calif., 9/7–12/86, 1986, pp. 880–888. [51] J.W. Ely, How intense quality control improves hydraulic fracturing, World Oil 217 (11) (November 1996), 59, 60, 62–65, 68. [52] J.W. Ely, B.C. Wolters, S.A. Holditch, Improved job execution and stimulation success using intense quality control, in: Proceedings Volume, 37th Annu. Southwestern Petrol. Short Course Ass. et al. Mtg., Lubbock, Texas, 4/18–19/90, 1990, pp. 101–114. [53] S.N. Shah, P.C. Harris, H.C. Tan, Rheological characterization of borate crosslinked fracturing fluids employing a simulated field procedure, in: Proceedings Volume, SPE Prod. Technol. Symp., Hobbs, N Mex, 11/7–8/88, 1988. [54] S. Chakrabarti, C.Z. Marczewski, Determining the concentration of a cross-linking agent containing zirconium, GB Patent 2 228 996, assigned to British Petroleum Co. Ltd., September 12, 1990. [55] S. Chakrabarti, J.P. Martins, D. Mealor, Method for controlling the viscosity of a fluid, GB Patent 2 199 408, assigned to British Petroleum Co. Ltd., July 6, 1988. [56] H.D. Brannon, J.P.R.M. Tjon, Characterization of breaker efficiency based upon size distribution of polymeric fragments, in: Proceedings Volume, Annu. SPE Tech. Conf., Dallas, 10/22–25/95, 1995, pp. 415–429. [57] B.L. Gall, C.J. Raible, The use of size exclusion chromatography to study the degradation of water-soluble polymers used in hydraulic fracturing fluids, in: Proceedings 192nd ACS Nat. Mtg., vol. 55, Amer. Chem. Soc. Polymeric Mater Sci Eng. Div Tech. Program, Anaheim, Calif., 9/7–12/86, 1986, pp. 572–576.

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[58] A. Kyaw, B.S. Binti, Nor Azahar, S.Q. Tunio, Fracturing fluid (guar polymer gel) degradation study by using oxidative and enzyme breaker, Research Journal of Applied Sciences, Engineering and Technology 4 (12) (2012) 1667–1671. [59] Petroleum and natural gas industries – Completion fluids and materials – Part 5: Procedures for measuring the long-term conductivity of proppants, ISO Standard ISO-13503-5, International Organization for Standardization, Geneva, Switzerland, 2006. [60] Recommended practice for measuring the long-term conductivity of proppants, API Standard API RP 19C, American Petroleum Institute, Washington, DC, 2008. [61] Q. Wen, S. Zhang, L. Wang, Y. Liu, X. Li, The effect of proppant embedment upon the long-term conductivity of fractures, Journal of Petroleum Science & Engineering 55 (3–4) (February 2007) 221–227.

CHAPTER 3

Thickeners A variety of compounds useful as thickeners is shown in Table 3.1. Subsequently, the individual compounds are explained in detail.

3.1 Nanoparticle-enhanced hydraulic fracturing fluids The application of horizontal drilling and hydraulic fracturing stimulations for improving hydrocarbon productivity from low-permeable reservoirs is a well-established practice [19]. However, the development of fracturing Table 3.1 Thickeners. Compound

References

A water-soluble copolymer of hydrophilic and hydrophobic monomers, acrylamide (AAm)-acrylate of silane or siloxane Carboxymethyl cellulose, poly(ethylene glycol) Combination of a cellulose ether with clay Amide-modified carboxyl containing poly(saccharide) Sodium aluminate and magnesium oxide Thermally stable hydroxyethyl cellulose (HEC) 30% ammonium or sodium thiosulfate and 20% HEC Acrylic acid (AA) copolymer and oxyalkylene with hydrophobic group Copolymers acrylamide-acrylate and vinylsulfonate-vinylamide Cationic poly(galactomannan)s and anionic xanthan gum Copolymer from vinyl urethanes and AA or alkyl acrylates 2-Nitroalkyl ether-modified starch Polymer of glucuronic acid Ferrochrome lignosulfonate and carboxymethyl cellulose Cellulose nanofibrilsa Quaternary alkyl amido ammonium salts Chitosanb

[1]

a b

[2,3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15,16] [17] [18]

Stable up to temperatures of about 180◦ C. Solubilized in acidic solution.

Hydraulic Fracturing Chemicals and Fluids Technology https://doi.org/10.1016/B978-0-12-822071-9.00010-4

Copyright © 2020 Elsevier Inc. All rights reserved.

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fluids that can maintain excellent rheological properties at reservoir conditions, as well as minimize damage to the formation, is still very challenging. There has been increasing interest in recent years in the improvement of the hydraulic fracturing stimulation through the application of nanotechnology. The current status of nanoparticle applications for hydraulic fracturing treatments of the unconventional reservoirs has been reviewed [19]. Also, the mechanisms and applications, the findings, and the technical challenges and directions for future studies were detailed. The collected literature demonstrated the promising applications of nanomaterials for improving the rheology of viscoelastic surfactant fluid, foam-based fluid, and polymer-based fracturing fluid using nanocrosslinkers and biopolymer nanocomposites. The results of previous studies showed that the unique properties of nanomaterials, such as their small sizes, high specific surface area, magnetic properties, superior strength, and stability could be exploited in the development of downhole nanosensors, nanoproppants, gel breakers, and fluid loss control agents. More work will be required to understand the crosslinking mechanisms of nanocrosslinkers and the mechanisms governing the enhancement in fracturing fluid viscosity in the presence of nanoparticles at reservoir conditions. The potential applications of generally used nanoparticles, such as aluminum oxide, copper oxide, carbon nanotubes, and low-cost nanoparticles such as calcium carbonate, silicon dioxide, and fly ash nanoparticles, in unconventional reservoirs need to be further researched. The improved hydrocarbon recovery from the unconventional reservoirs through wettability alterations and interfacial tension reduction by nanofluids and the use of nanoparticle-enhanced combined fracturing fluid systems present exciting future opportunities [19]. More recently, hydraulic fracturing fluids may incorporate small-sized particles in the nanometer size range [20]. Such nanoparticles have addressed certain technological limitations of fracturing fluids. For example, viscoelastic surfactant fluids were reported to suffer high leakoff rates in moderate permeability reservoirs (200 md) and were limited in temperature. Beyond approximately 104◦ C, viscosity was diminished significantly. Another challenge is the pressure-dependent behavior of boratecrosslinked gels, where the viscosity was found to drop significantly under high pressures. Also, in high-temperature reservoirs (>178◦ C), it is very challenging to design a fluid that can sustain enough viscosity for a required period of time.

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Synthetic polymers, mainly acrylamide-based polymers, are commonly used and have been reported to be used at high concentrations. These highconcentration requirements are imposed by the need for a stable viscosity under high-temperature conditions. However, a high polymer loading increases the potential of formation damage caused by the fluid residue. These challenges, which can be addressed by nanotechnology, could have a major impact on hydraulic fracturing applications. For instance, the working temperature limit of viscoelastic surfactantbased fluids was improved from 93 to 121◦ C by adding zinc oxide and magnesium oxide nanoparticles. The borate-crosslinked gels were found to maintain their viscosity at pressures up to 20,000 psi when using boronic acid-functionalized nanolatex silica particles as crosslinking agents, while under such high pressures, conventional borate crosslinkers showed more than 80% reduction in viscosity. Moreover, the rheological properties of mixed viscoelastic surfactant/polymer fluids were enhanced when using nanoparticles. The use of foams can reduce the amount of water consumed in hydraulic fracturing. An α -olefin sulfonate surfactant can be foamed by the use of carbon dioxide. Aluminum oxide nanoparticles were found to stabilize the foams created by an α -olefin olefin sulfonate, viscoelastic surfactant, and carbon dioxide. This has a potential application in waterless fracturing. All of these aspects have been reviewed, and the most recent experience of nanoparticle usage in hydraulic fracturing fluids design were summarized [20].

Polymers Thickener polymers include poly(urethane)s, poly(ester)s, and poly(acrylamide)s, and also natural polymers and modified natural polymers [21]. pH-responsive thickeners

The viscosity of ionic polymers is dependent on the pH. In particular, pH-responsive thickeners can be prepared by copolymerization of acrylic or methacrylic acid ethyl acrylate or other vinyl monomers and tristyrylpoly(ethyleneoxy)x methyl acrylate. Such a copolymer provides a stable aqueous colloidal dispersion at a pH lower than 5.0 but becomes an effective thickener for aqueous systems upon adjustment to a pH of 5.5 to 10.5 or higher [22,23].

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Mixed metal hydroxides By addition of mixed metal hydroxides, typical bentonite muds are transformed to an extremely shear thinning fluid [24]. At rest these fluids exhibit a very high viscosity but are thinned to an almost waterlike consistency when shear stress is applied. In theory, the shear thinning rheology of mixed metal hydroxides and bentonite fluids is explained by the formation of a three-dimensional, fragile network of mixed metal hydroxides and bentonite. The positively charged mixed metal hydroxide particles attach themselves to the surface of negatively charged bentonite platelets. Typically, magnesium aluminum hydroxide salts are used as mixed metal hydroxides. Mixed metal hydroxides demonstrate the following advantages in drilling [25]: • high cuttings removal, • suspension of solids during shutdown, • lower pump resistance, • stabilization of the borehole, • high drilling rates, and • protection of the producing formation. Mixed metal hydroxide drilling muds have been successfully used in horizontal wells, in tunneling under rivers, roads, and bays, for drilling in fluids, for drilling large-diameter holes, with coiled tubing, and to ream out cemented pipe. Mixed metal hydroxides can be prepared from the corresponding chlorides treated with ammonium [26]. Experiments done with various drilling fluids showed that the mixed metal hydroxides system, coupled with propylene glycol [27], caused the least skin damage of the drilling fluids tested. Thermally activated mixed metal hydroxides made from naturally occurring minerals, especially hydrotalcites, may contain small or trace amounts of metal impurities besides the magnesium and aluminum components, which are particularly useful for activation [28]. Mixed hydroxides of bivalent and trivalent metals with a threedimensional spaced-lattice structure of the garnet type (Ca3 Al2 (OH)12 ) have been described [29,30].

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Table 3.2 Overview of thickeners suitable for fracturing fluids. Thickener

References

guara

Hydroxypropyl Galactomannansb HEC-modified vinylphosphonic acid Carboxymethyl cellulose Polymer from N-vinyl lactam monomers, vinylsulfonatesc Reticulated bacterial cellulosed Bacterial xanthane a b c d e

[33] [34] [35] [36] [37]

General purpose eightfold power of thickening in comparison to starch. Increased temperature stability, used with boron-based crosslinkers. High-temperature stability. Superior fluid performance. Imparts high viscosity.

3.2 Thickeners for water-based systems A gelling agent is also known as a viscosifying agent, and refers to a material that can make the fracturing fluid into a gel, thereby increasing its viscosity [31]. Suitable gelling agents include guar gum, xanthan gum, welan gum, locust bean gum, gum ghatti, gum karaya, tamarind gum, and tragacanth gum. Guar gum can be functionalized to hydroxyethyl guar, hydroxypropyl guar, or carboxymethyl guar. Examples of water-soluble cellulose ethers include methyl cellulose, carboxymethyl cellulose (CMC), HEC, and hydroxyethyl carboxymethyl cellulose [31]. Artificial polymers, such as copolymers from AAm, methacrylamide, AA, or methacrylic acid, or those from 2-acrylamido-2-methyl-1-propane sulfonic acid (AMPS) derivates and N-vinylpyridine, have all been used [31], but also naturally occurring polysaccharides and their derivatives [32]. They can increase the viscosity of the fluid when used in comparatively small amounts. Table 3.2 presents polymers suitable for fracturing fluids. Guar is shown in Fig. 3.1. In hydroxypropyl guar, some of the hydroxyl groups are etherified with oxopropyl units. Compositions for gelling a hydrocarbon fracturing fluid are fundamentally different from those for aqueous fluids. A possible formulation consists of a gelling agent, a phosphate ester, a crosslinking agent, a multivalent metal ion, and a catalyst, a fatty quaternized amine [38].

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Figure 3.1 Structural unit of guar.

Zirconium-based crosslinking composition Some commercially available zirconate crosslinkers, such as tetra triethanol amine zirconate, crosslink too fast at high pH conditions, thus causing a significant loss in viscosity due to shear degradation [39]. In contrast, other zirconium complexes of triethanol amine [40–42] can be used, but they suffer from a slow rate of crosslinking [39]. In addition, a similar loss in viscosity due to shear degradation is observed. A water-based crosslinking composition has been developed that contains a pH buffer, a crosslinkable organic polymer, and a solution of a zirconium crosslinking agent [39]. The zirconium complex has an alkanolamine and ethylene glycol. A most suitable tetraalkyl zirconate is tetra-n-propyl zirconate, available as TYZOR NPZ, a solution in n-propanol, with a zirconium content as ZrO2 of about 28% by weight. The composition is further comprised of a crosslinkable organic polymer, e.g., guar deviates. However, CMCs are advantageous when the pH of the composition is less than 6.0 or higher than 9.0, or when the permeability of the formation is such that one wishes to keep the residual solids at a low level to prevent damage to the formation [39].

3.2.1 Guar Guar is a branched polysaccharide from the guar plant Cyamopsis tetragonolobus, which originated in India, and is now also found in the southern United States. It has a molar mass of approximately 220 kDa, and it consists

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of mannose in the main chain and galactose in the side chain. The ratio of mannose to galactose is 2:1. Polysaccharides having this structure are referred to as heteromannans, and in particular as galactomannans. Derivatives of guar are therefore sometimes called galactomannans. Guar-based gelling agents, typically hydroxypropyl guar, are widely used to viscosify fracturing fluids because of their desirable rheological properties, economics, and ease of hydration. Nonacetylated xanthan is a variant of xanthan gum which interacts synergistically with guar to give superior viscosity and particle transport at lower polymer concentrations. Static leakoff experiments with borate-crosslinked and zirconatecrosslinked hydroxypropyl guar fluids showed practically the same leakoff coefficients [43]. An investigation of their stress-sensitive properties showed that zirconate filter cakes have viscoelastic properties, but borate filter cakes are merely elastic. Noncrosslinked fluids show no filter cake type behavior for a large range of core permeabilities, but rather a viscous flow that is dependent on characteristics of the porous medium. The addition of glycols, such as ethylene glycol (EG), to aqueous fluids gelled with guar gum can increase the viscosity of the fluid and stabilize the fluid brines. Such fluids are more stable at high temperatures from 27–177◦ C (80–350◦ F). The formation damage is minimized after hydraulic fracturing operations, as less of the guar polymer can be used, but the same viscosity is achieved by the addition of a glycol [44]. The crosslinker can be a borate, a titanate, or a zirconate. The stability of the gel is improved by the addition of sodium thiosulfate. The development of the viscosity at 93◦ C (200◦ F) of brine fluids with 2.4 kg m−3 guar and 5% KCl, with varying amounts of EG, is shown in Fig. 3.2. By using the sodium derivative of ethylenediamine tetraacetic acid as gel breaker in these compositions with EG, the decay of viscosity with time can be adjusted accordingly [44]. Anionic galactomannans, which are derived from guar gum by partially esterifying hydroxyl groups with sulfonate groups that result from AMPS and 1-allyloxy-2-hydroxypropyl sulfonic acid [45], have been claimed to be suitable as thickeners. The composition is capable of producing enhanced viscosities, when used alone or in combination with a cationic polymer and distributed in a solvent. Polyhydroxy compounds can be modified by various reactions. Etherification, exemplified with dextrose as the model compound, is shown in

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Figure 3.2 Viscosity of guar brines with varying amounts of ethylene glycol (EG) [44].

Figure 3.3 Modification of polyhydroxy compounds.

Fig. 3.3. Vinyl compounds used for the modification of guar are shown in Fig. 3.4. The temperature stability of fracturing fluids containing galactomannan polymers is increased by adding a sparingly soluble borate with a slow solubility rate. This provides a source of boron for solubilizing at elevated temperatures, thus enhancing the crosslinking of the galactomannan polymer. The effect of nanoparticles on the rheology of fracturing fluids has been studied [46]. Vapor-grown carbon fibers have been coated with silica and subsequently functionalized with octadecyltrichlorosilane. The so modified fibers have been added to a fracturing fluid gel. Rheological measurements at a pH of 8.6, 9.3, and 10.3, respectively, showed an interaction with the gels only at a lower pH than typically used for fracturing fluids.

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Figure 3.4 Vinyl modifiers for guar gum.

The presence of the modified nanoparticles minimally increases the storage modulus of the guar gels. These gels behave similarly to the plain guar gels, displaying no permanent damage to the gels under the applied shear. In addition, the presence of the modified nanoparticles does not seem to alter the structure and the crosslinking sites of the guar gel [46]. The grafting of a poly(alkoxyalkyleneamide) to guar gum gives suitable guar derivates. The modification of either guar gum or hydroxypropyl guar is achieved in a three-step process [47]: 1. carboxymethylation with sodium chloroacetate, 2. esterification with dimethyl sulfate, and 3. amidation with a poly(alkoxyalkyleneamide). The process was followed by infrared spectroscopy. A series of hydroxypropyl guar derivates with degrees of carboxymethylation of 0.2–0.3 were modified with poly(alkoxyalkyleneamide) with molecular weights ranging from 300 to 3000 Da. The ratio of oxypropylene to oxyethylene units in the poly(alkoxyalkyleneamide) was varied from 9:1 to 8:58 in order to adjust the hydrophobicity of the final materials. The viscosities of the grafts are one to two orders of magnitude lower than that of the neat guar gum [47].

3.2.2 Hydroxyethyl cellulose HEC can be chemically modified by the reaction with vinylphosphonic acid in the presence of the reaction product of hydrogen peroxide and a

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Figure 3.5 Amylose and cellulose.

ferrous salt. The HEC forms a graft copolymer with the vinylphosphonic acid. Amylose and cellulose are shown in Fig. 3.5. Amylose is a linear polymer of glucose and is water-soluble. The difference between amylose and cellulose is the way in which the glucose units are linked; amylose has α -linkages, whereas cellulose contains β -linkages. Because of this difference, amylose is soluble in water and cellulose is not. Chemical modification allows cellulose to become water-soluble. Modified HEC has been proposed as a thickener for hydraulic fracturing fluids [34]. Polyvalent metal cations may be employed to crosslink the polymer molecules to further increase the viscosity of the aqueous fluid.

3.2.3 Biotechnologic products Gellan gum and wellan gum Gellan gum is the generic name of an extracellular polysaccharide produced by the bacterium Pseudomonas elodea. It is a linear anionic polysaccharide with a molecular mass of 500 kDa, consisting of 1,3-β -D-glucose, 1,4-β -D-glucuronic acid, 1,4-β -D-glucose, and 1,4-α -L-rhamnose. Wellan gum is produced by aerobic fermentation. The backbone of wellan gum is identical to gellan gum, but it has a side chain consisting of L-mannose or L-rhamnose. It is used in fluid loss additives and is extremely compatible with calcium ions in alkaline solutions.

Reticulated bacterial cellulose Cellulose produced by bacteria, with an intertwined reticulated structure, has unique properties and functionalities, unlike conventional cellulose. It

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65

Table 3.3 Variant xanthan gums. Number

Repeating units

Ratio

Pentamer Tetramer

D-glucose: D-mannose: D-glucuronic acid D-glucose: D-mannose: D-glucuronic acid

2:2:1 2:1:1

Figure 3.6 Carbohydrates and derivates.

improves fluid rheology and particle suspension over a wide range of conditions in aqueous systems [36].

Xanthan gum Xanthan gum is produced by the bacterium Xanthomonas campestris, and has been used commercially since 1964. Xanthans are water-soluble polysaccharide polymers with the repeating units [48] shown in Table 3.3 and Fig. 3.6. The D-glucose moieties are linked in a β -(1,4) configuration, and the inner D-mannose moieties are linked in an α -(1,3) configuration, generally alternating with glucose moieties. The D-glucuronic acid moieties are linked in a β -(1,2) configuration to the inner mannose moieties. The outer mannose moieties are linked to the glucuronic acid moieties in a β -(1,4) configuration. Xanthan gum is used in oilfield applications in the form of a fermentation broth containing 8–15% of the polymer. The viscosity is less dependent on the temperature than that of other polysaccharides.

3.2.4 Viscoelastic formulations Viscoelastic surfactant (VES) fluids have the following advantages over conventional polymer formulations [49]: • higher permeability in the oil bearing zone, • lower formation or subterranean damage,

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• higher viscosifier recovery after fracturing, • no need for enzymes or oxidizers to break down viscosity, and • easier hydration and faster buildup to optimum viscosity.

Disadvantages and drawbacks of VES fluids are their high costs, their low tolerance to salts, and stability against high temperatures as found in deep-well applications. However, there are recent formulations that overcome these difficulties, at least to some extent. The components of a viscoelastic fluid are a zwitterionic surfactant, erucyl amidopropyl betaine, an anionic polymer, or N-erucyl-N,N-bis(2hydroxyethyl)-N-methyl ammonium chloride, poly(napthalene sulfonate), and cationic surfactants, methyl poly(oxyethylene) octadecanammonium chloride and poly(oxyethylene) cocoalkylamines [50,49]. The corresponding fluids exhibit a good viscosity performance. Typical viscoelastic surfactants are N-erucyl-N,N-bis(2-hydroxyethyl)N-methyl ammonium chloride and potassium oleate, solutions which form gels when mixed with corresponding activators such as sodium salicylate and potassium chloride [51]. The cationic surfactant should be soluble in both organic and inorganic solvents. Solubility in hydrocarbon solvents is promoted by attaching multiple long-chain alkyl groups to the active surfactant unit [51]. Examples are hexadecyltributylphosphonium and trioctylmethylammonium ions. In contrast, cationic surfactants for viscoelastic solutions have rather a single, long, linear hydrocarbon moiety attached to the surfactant group. Obviously, there is a conflict between the structural requirements for achieving solubility in hydrocarbons and for the formation of viscoelastic solutions. As a compromise, surfactant compounds that are suitable for reversibly thickening water-based wellbore fluids and also soluble in both organic and aqueous fluids have been designed. Tallow amido propylamine oxide [52] is a suitable, nonionic surfactant gelling agent. Nonionic fluids are inherently less damaging to the producing formations than cationic fluid types, and are more efficacious than anionic gelling agents. The synthesis of branched oleates has been described. 2-Methyl oleic acid methyl ester, or 2-methyl oleate, can be prepared from methyl oleate and methyl iodide in the presence of a pyrimidine-based catalyst [51]. The methyl ester is then hydrolyzed to obtain 2-methyl oleic acid. It is sometimes believed that contact with a VES-gelled fluid instantaneously reduces the viscosity of the gel, but it has been discovered that

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Figure 3.7 2 -Ethylhexyl acrylate.

Figure 3.8 Monomers for synthetic thickeners.

mineral oil can be used as an internal breaker for VES-gelled fluid systems [53]. The rate of viscosity breaking at a given temperature is influenced by the type and amount of salts present. In the case of low-molecular weight mineral oils, it is important to add them after the VES component is added to the aqueous fluid. By using combinations of internal breakers, both the initial and final break of the VES fluid may be customized. Fatty acid compounds or bacteria may be used in addition to mineral oil [54,53].

3.2.5 Miscellaneous polymers A copolymer of 2 -ethylhexyl acrylate and acrylic acid is not soluble either in water or in hydrocarbons. The ester units are hydrophobic and the acid units are hydrophilic. An aqueous suspension with a particle size smaller than 10 µm can be useful in preparing aqueous hydraulic fracturing fluids [55]. 2 -Ethylhexyl acrylate is shown in Fig. 3.7. A water-soluble polymer of N-vinyl lactam or vinyl containing sulfonate monomers reduces the water loss and enhances other properties of well treating fluids in high-temperature subterranean environments [35]. Lignites, tannins, and asphaltic materials are added as dispersants. Vinyl monomers are shown in Fig. 3.8.

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Lactide polymers Degradable thermoplastic lactide polymers are used for fracturing fluids. Hydrolysis is the primary mechanism for degradation of the lactide polymer [56].

Biodegradable formulations Biodegradable drilling fluid formulations have been suggested, which consist of a polysaccharide in a concentration that is insufficient to permit contamination by bacteria. The polymer is a high-viscosity CMC that is sensitive to bacterial enzymes produced by the degradation of the polysaccharide [57]. The biodegradability of seven kinds of mud additives was studied by determining the content of dissolved oxygen in water, a simple biochemical oxygen demand testing method. The biodegradability is high for starch but lower for polymers of allyl monomers and additives containing an aromatic group [58].

3.3 Concentrates Historically, fracture stimulation treatments have been performed by using conventional batch mix techniques, which involves premixing chemicals into tanks and circulating the fluids until a desired gelled fluid rheology is obtained. This method is time consuming and burdens the oil company with disposal of the fluid if the treatment ends prematurely. Environmental damage during spillage or disposal can be avoided if the fluid is capable of being gelled as needed. Thus gelling-as-needed technology has been developed with water, methanol, and oil [59]. This procedure eliminates batch mixing and minimizes handling of chemicals and base fluid. The customer is charged only for products used, and environmental concerns regarding disposal are virtually eliminated. Computerized chemical addition and monitoring, combined with on-site procedures, ensure quality control throughout treatment. Fluid rheologies can be accurately varied during the treatment by varying polymer loading. The use of a diesel-based concentrate with hydroxypropyl guar gum has been evolved from batch-mixed dry powder procedures [60]. The application of such a concentrate reduces system requirements, and companies can benefit from the reduced logistic burden that comes from using the diesel hydroxypropyl guar gum concentrate.

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Table 3.4 Components of a slurry concentrate [61]. Component

Example

Hydrophobic solvent base Suspension agent Surfactant Hydratable polymer

Diesel Organophilic clay Ethoxylated nonyl phenol Hydroxypropyl guar gum

Figure 3.9 Surfactants in a slurry concentrate.

A fracturing fluid slurry concentrate has been proposed [61] that consists of the components shown in Table 3.4. Such a polymer slurry concentrate will readily disperse and hydrate when admixed with water at the proper pH, thus producing a high-viscosity aqueous fracturing fluid. The fracturing fluid slurry concentrate is useful for producing large volumes of high-viscosity treating fluids at the well site on a continuous basis. Suitable surfactants are shown in Fig. 3.9. Fluidized aqueous suspensions of 15% or more of HEC, hydrophobically modified cellulose ether, hydrophobically modified HEC, methyl cellulose, hydroxypropylmethyl cellulose, and poly(ethylene oxide) are prepared by adding the polymer to a concentrated sodium formate solution containing xanthan gum as a stabilizer [62]. The xanthan gum is dissolved in water before sodium formate is added. Then the polymer is added to the solution to form a fluid suspension of the polymers. The polymer suspension can serve as an aqueous concentrate for further use.

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Figure 3.10 Aluminum isopropoxide.

3.4 Thickeners for oil-based systems 3.4.1 Organic gel aluminum phosphate ester A gel of diesel or crude oil can be produced using a phosphate diester or an aluminum compound with phosphate diester [63]. The metal phosphate diester may be prepared by reacting a triester with phosphorous pentoxide to produce a poly(phosphate), which is then reacted with hexanol to produce a phosphate diester [64]. The latter diester is then added to the organic liquid along with a nonaqueous source of aluminum, such as aluminum isopropoxide (cf. Fig. 3.10), in diesel oil, to produce the metal phosphate diester. The conditions in the previous reaction steps are controlled to provide a gel with good viscosity versus temperature and time characteristics. All the reagents are substantially free of water and will not affect the pH. The synthesis of a phosphate diesters is shown in Fig. 3.11. It runs via triethyl phosphate, phosphorous pentoxide, and the esterification reaction with hexanol. Enhancers for phosphate esters are amino compounds [65]. The 2-ethylhexanoic acid trialuminum salt has been suggested with fatty acids as an activator [66]. Another method to produce oil-based hydrocarbon gels is to use ferric salts [67] rather than aluminum compounds for combination with orthophosphate esters. The ferric salt has the advantage of being usable in the presence of large amounts of water, up to 20%. Ferric salts can be applied in wide ranges of pH. The linkages that are formed can still be broken with gel breaking additives conventionally used for that purpose.

3.4.2 Increasing the viscosity of diesel A copolymer of N,N-dimethylacrylamide and N,N-dimethyl aminopropyl methacrylamide, a monocarboxylic acid, and ethanolamine may serve to in-

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Figure 3.11 Synthesis of higher phosphoric esters.

crease the viscosity of diesel or kerosene [68]. These compounds are shown in Fig. 3.12.

3.5 Viscoelasticity Viscoelastic materials exhibit both viscous and elastic properties under mechanical deformation. Such materials exhibit a hysteresis in the stress strain

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Figure 3.12 Monomers in a copolymer for viscosifying diesel.

Figure 3.13 Maxwell model.

curves. Further, a relaxation of stress occurs under constant strain, i.e., the stress is diminished. Moreover, viscoelastic materials are creeping. A simple model for such materials has been worked out by James Clerk Maxwell already in 1867 [69]. A Maxwell fluid, or Maxwell body, can be modeled by an idealized viscous damper and by an idealized elastic spring connected in series. The basic device is shown in Fig. 3.13. Thus the Maxwell model can explain both elastic properties and viscous properties. Some basic issues of the Maxwell model have been revisited [70]. The basic Maxwell model can be represented by d εt d εd d εs σ 1 d σ = + = + . dt dt dt η E dt

(3.1)

The change of total elongation εt in time t is the sum of the change of elongation of the damper εD and the change of elongation of the spring εt . The right-hand side of Eq. (3.1) contains simply Newton’s law of flow and Hooke’s law of the elongation of an ideal spring, i.e., d εd σ = , dt η

εs =

1 σ, E

the latter in the rather uncommon differential form. Thus, η is the Newtonian viscosity, σ is the stress, and E is the elastic modulus. By the way, if the spring and the damper are coupled parallel instead of consecutively, the

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Figure 3.14 Viscosity versus concentration of surfactant [72].

Kelvin–Voigt model emerges, which may be experienced in self-closing doors. The property of viscoelasticity has been well investigated [71]. Aqueous solutions of cationic surfactants with strong binding forces of the ions show properties similar to gels. Microstructural transitions and rheological properties of viscoelastic solutions formed in a catanionic surfactant system were studied using a combination of rheology and dynamic light scattering [72]. The rheological behavior can be very complicated. In a study on a surfactant system based on dodecyltriethylammonium bromide and sodium dodecyl sulfate, wormlike micelles began to form above a certain surfactant concentration, caused by the growth of small cylindrical micelles. In an intermediate concentration range, the system exhibits a linear viscoelasticity with the characteristics of a Maxwell fluid. Eventually, at higher surfactant concentrations, a transition from linear micelles to branched structures may take place. The changes of the viscosity at zero shear rate with the total concentration of surfactant with a ratio of dodecyltriethylammonium bromide to sodium dodecyl sulfate of 27:73 are shown in Fig. 3.14.

3.5.1 Viscoelastic thickeners Viscoelasticity is caused by a different type of micelle formation than the usual spherical micelles formed by most surfactants. VESs are believed to impart viscosity to an aqueous fluid by the molecules organizing themselves

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into micelles. Spherical micelles do not give increased viscosity; however, when the micelles have an elongated configuration, for instance rod-shaped or worm-shaped, they become entangled with one another, thereby increasing the viscosity of the fluid [73]. Elongated VES structures are referred to as living because there is a continuous exchange of VES type surfactants leaving the VES micelle structures to the aqueous solution and other surfactants leaving the aqueous solution and entering or reentering the VES micelle structures. VES solutions exhibit a shear thinning behavior. They remain stable despite repeated high-shear applications. By comparison, a typical polymeric thickener will irreversibly degrade when subjected to high-shear applications [74]. Internal breakers work by the rearrangement of the VES micelle from rod-shaped or worm-shaped elongated structures to spherical structures. In other words, they perform the collapse or rearrangement of the viscous elongated micelle structures to nonviscous, more spherical micelle structures [73].

3.5.2 Enhanced shear recovery agents Some viscoelastic surfactant fluids exhibit a low shear recovery when subjected to high shear. However, unacceptably long shear recovery times hinder the operation of deep-well oilfield applications. Enhanced shear recovery agents reduce the shear recovery time of a viscoelastic surfactant fluid. Enhanced shear recovery agents are based on alkylated poly(glucoside)s, poly(glucamide)s, or copolymers based on ethylene glycol ethyl ether acrylate. Glucamides consist of cyclic forms of glucose in which the hydrogen of the hemiacetal group has been replaced with an alkyl or aryl moiety. The basic structures of glucoside and glucamide are shown in Fig. 3.15. Viscoelastic surfactant fluids are made by mixing suitable surfactants. When the surfactant concentration significantly exceeds a critical level, and is eventually subjected to the presence of an electrolyte, the surfactant molecules aggregate and form structures, such as micelles, that can interact to form a network exhibiting viscoelastic behavior [75]. Viscoelastic surfactant solutions can be formed by the addition of certain reagents to concentrated solutions of surfactants. The surfactants are long-chain quaternary ammonium salts such as cetyltrimethyl ammonium bromide.

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Figure 3.15 Glucoside and glucamide structures [74].

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[30] H. Mueller, W. Breuer, C.P. Herold, P. Kuhm, S. von Tapavicza, Mineral additives for setting and/or controlling the rheological properties and gel structure of aqueous liquid phases and the use of such additives, US Patent 5 663 122, assigned to Henkel KG Auf Aktien, September 2, 1997. [31] T.D. Welton, B.L. Todd, D. McMechan, Methods for effecting controlled break in pH dependent foamed fracturing fluid, US Patent 7 662 756, assigned to Halliburton Energy Services, Inc., Duncan, OK, February 16, 2010. [32] Z.R. Lemanczyk, The use of polymers in well stimulation: an overview of application, performance and economics, Oil Gas European Magazine 18 (3) (October 1992) 20–26. [33] T.C. Mondshine, Crosslinked fracturing fluids, WO Patent 8 700 236, assigned to Texas United Chemical Corp., January 15, 1987. [34] M.D. Holtmyer, C.V. Hunt, Crosslinkable cellulose derivatives, EP Patent 479 606, assigned to Halliburton Co., April 8, 1992. [35] P. Bharat, Well treating fluids and additives therefor, EP Patent 372 469, June 13, 1990. [36] J.A. Westland, D.A. Lenk, G.S. Penny, Rheological characteristics of reticulated bacterial cellulose as a performance additive to fracturing and drilling fluids, in: Proceedings Volume, SPE Oilfield Chem. Int. Symp., New Orleans 3/2–5/93, 1993, pp. 501–514. [37] R.M. Hodge, Particle transport fluids thickened with acetylate free xanthan heteropolysaccharide biopolymer plus guar gum, US Patent 5 591 699, assigned to Du Pont De Nemours & Co., January 7, 1997. [38] S. Lawrence, N. Warrender, Crosslinking composition for fracturing fluids, US Patent 7 749 946, assigned to Sanjel Corporation, Calgary, Alberta, CA, July 6, 2010. [39] D.E. Putzig, Zirconium-based cross-linking composition for use with high pH polymer solutions, US Patent 8 153 564, assigned to Dorf Ketal Speciality Catalysts, LLC, Stafford, TX, April 10, 2012. [40] G.J. Rummo, R. Startup, Bisalkyl bis(trialkanol amine)zirconates and use of same as thickening agents for aqueous polysaccharide solutions, US Patent 4 578 488, assigned to Kay-Fries, Inc., Stony Point, NY, March 25, 1986. [41] C.H. Kucera, Fracturing of subterranean formations, US Patent 4 683 068, assigned to Dowell Schlumberger Incorporated, Tulsa, OK, July 28, 1987. [42] S.E. Baranet, R.M. Hodge, C.H. Kucera, Stabilized fracture fluid and crosslinker therefor, US Patent 4 686 052, assigned to Dowell Schlumberger Incorporated, Tulsa, OK, August 11, 1987. [43] S.C. Zeilinger, M.J. Mayerhofer, M.J. Economides, A comparison of the fluid-loss properties of borate-zirconate-crosslinked and noncrosslinked fracturing fluids, in: Proceedings Volume, SPE East Reg Conf., Lexington, KY, 10/23–25/91, 1991, pp. 201–209. [44] P.A. Kelly, A.D. Gabrysch, D.N. Horner, Stabilizing crosslinked polymer guars and modified guar derivatives, US Patent 7 195 065, assigned to Baker Hughes Incorporated, Houston, TX, March 27, 2007. [45] M.H. Yeh, Anionic sulfonated thickening compositions, EP Patent 632 057, assigned to Rhone Poulenc Spec. Chem. C, January 4, 1995. [46] H.R. Jafry, M. Pasquali, A.R. Barron, Effect of functionalized nanomaterials on the rheology of borate cross-linked guar gum, Industrial & Engineering Chemistry Research 50 (6) (2011) 3259–3264. [47] A. Bahamdan, W.H. Daly, Hydrophobic guar gum derivatives prepared by controlled grafting processes, Polymers for Advanced Technologies 18 (8) (2007) 652–659.

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[48] D.H. Doherty, D.M. Ferber, J.D. Marrelli, R.W. Vanderslice, R.A. Hassler, Genetic control of acetylation and pyruvylation of xanthan based polysaccharide polymers, WO Patent 9 219 753, assigned to Getty Scientific Dev Co., November 12, 1992. [49] F. Li, M. Dahanayake, A. Colaco, Multicomponent viscoelastic surfactant fluid and method of using as a fracturing fluid, US Patent 7 772 164, assigned to Rhodia, Inc., Cranbury, NJ, August 10, 2010. [50] I. Couillet, T. Hughes, Aqueous fracturing fluid, US Patent 7 427 583, assigned to Schlumberger Technology Corporation, Ridgefield, CT, September 23, 2008. [51] T.G.J. Jones, G.J. Tustin, Process of hydraulic fracturing using a viscoelastic wellbore fluid, US Patent 7 655 604, assigned to Schlumberger Technology Corporation, Ridgefield, CT, February 2, 2010. [52] P.M. McElfresh, C.F. Williams, Hydraulic fracturing using non-ionic surfactant gelling agent, US Patent 7 216 709, assigned to Akzo Nobel N.V., Arnhem, NL, May 15, 2007. [53] J.B. Crews, T. Huang, A.D. Gabrysch, J.H. Treadway, J.R. Willingham, P.A. Kelly, W.R. Wood, Methods and compositions for fracturing subterranean formations, US Patent 7 723 272, assigned to Baker Hughes Incorporated, Houston, TX, May 25, 2010. [54] J.B. Crews, Bacteria-based and enzyme-based mechanisms and products for viscosity reduction breaking of viscoelastic fluids, US Patent 7 052 901, assigned to Baker Hughes Incorporated, Houston, TX, May 30, 2006. [55] W.M. Harms, L.R. Norman, Concentrated hydrophilic polymer suspensions, US Patent 4 772 646, September 20, 1988. [56] C.E. Cooke Jr., Method and materials for hydraulic fracturing of wells using a liquid degradable thermoplastic polymer, US Patent 7 569 523, August 4, 2009. [57] J.J.M. Pelissier, S. Biasini, Biodegradable drilling mud (boue de forage biodegradable), FR Patent 2 649 988, January 25, 1991. [58] D.R. Guo, J.P. Gao, K.H. Lu, M.B. Sun, W. Wang, Study on the biodegradability of mud additives, Drilling Fluid and Completion Fluid 13 (1) (1996) 10–12. [59] G. Gregory, D. Shuell, J.E. Thompson Sr, Overview of contemporary lfc (liquid frac concentrate) fracture treatment systems and techniques, in: Proceedings Volume, number 91-01. 4th Cade/caodc Spring Drilling Conf., Proc., Calgary, Can, 4/10–12/91, 1991. [60] W.M. Harms, M. Watts, J. Venditto, P. Chisholm, Diesel-based hpg (hydroxypropyl guar) concentrate is product of evolution, Petroleum Engineer International 60 (4) (April 1988) 51–54. [61] H.D. Brannon, Fracturing fluid slurry concentrate and method of use, EP Patent 280 341, August 31, 1988. [62] C.L. Burdick, J.N. Pullig, Sodium formate fluidized polymer suspensions process, US Patent 5 228 908, assigned to Aqualon Co., July 20, 1993. [63] J.M. Gross, Gelling organic liquids, EP Patent 225 661, assigned to Dowell Schlumberger Inc., June 16, 1987. [64] D.A. Huddleston, Hydrocarbon geller and method for making the same, US Patent 4 877 894, assigned to Nalco Chemical Co., October 31, 1989. [65] G.G. Geib, Hydrocarbon gelling compositions useful in fracturing formations, US Patent 6 342 468, assigned to Ethox Chemicals Llc., January 29, 2002. [66] S. Subramanian, Y.P. Zhu, C.R. Bunting, R.E. Stewart, Gelling system for hydrocarbon fluids, WO Patent 0 109 482, assigned to Crompton Corp., February 8, 2001.

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[67] K.W. Smith, L.J. Persinski, Hydrocarbon gels useful in formation fracturing, US Patent 5 417 287, assigned to Clearwater Inc., May 23, 1995. [68] M.D. Holtmyer, C.V. Hunt, Method and composition for viscosifying hydrocarbons, US Patent 4 780 221, October 25, 1988. [69] J.C. Maxwell, On the dynamical theory of gases, Philosophical Transactions of the Royal Society of London 157 (1) (January 1867) 49–88. [70] I.J. Rao, K.R. Rajagopal, On a new interpretation of the classical Maxwell model, Mechanics Research Communications 34 (7–8) (October-December 2007) 509–514. [71] H. Rehage, H. Hoffmann, Rheological properties of viscoelastic surfactant systems, Journal of Physical Chemistry 92 (16) (August 1988) 4712–4719. [72] H. Yin, Y. Lin, J. Huang, Microstructures and rheological dynamics of viscoelastic solutions in a catanionic surfactant system, Journal of Colloid and Interface Science 338 (1) (October 2009) 177–183. [73] J.B. Crews, T. Huang, Use of oil-soluble surfactants as breaker enhancers for ves-gelled fluids, US Patent 7 696 135, assigned to Baker Hughes Incorporated, Houston, TX, April 13, 2010. [74] A. Colaco, J.-P. Marchand, F. Li, M.S. Dahanayake, Viscoelastic surfactant fluids having enhanced shear recovery, rheology and stability performance, US Patent 7 279 446, assigned to Rhodia Inc., Cranbury, NJ, Schlumberger Technology Corporation, Sugarland, TX, October 9, 2007. [75] P. Sullivan, Y. Christanti, I. Couillet, S. Davies, T. Hughes, A. Wilson, Methods for controlling the fluid loss properties of viscoelastic surfactant based fluids, US Patent 7 081 439, assigned to Schlumberger Technology Corporation, Sugar Land, TX, July 25, 2006.

CHAPTER 4

Friction reducers During the drilling, completion, and stimulation of subterranean wells, treatment fluids are often pumped through tubular structures, e.g., pipes or coiled tubing. A considerable amount of energy may be lost due to turbulence in the treatment fluid. As a result of these energy losses, additional horsepower may be necessary to achieve the desired treatment [1]. Low pumping friction pressures are achieved by delaying the crosslinking of the compositions, but there are also specific additives available to reduce the drag in the tubings. The first application of drag reducers was using guar in oil well fracturing, now a routine practice. Relatively small quantities of a bacterial cellulose (0.60–1.8 g l−1 ) in hydraulic fracturing fluids enhance their rheologic properties [2]. The suspension of the proppant is enhanced and friction loss through well casings is reduced.

4.1 Incompatibility Although quaternary surfactants can be useful when used together with biocides, some quaternary surfactants may have a fundamental incompatibility with anionic friction reducers, which are also useful in subterranean operations. It is believed that this fundamental incompatibility may arise from charges present on both molecules that may cause the quaternary surfactant and the friction reducer to react, and eventually a precipitate is formed. Additionally, some biocides, e.g., oxidizers, may degrade certain friction reducers [3].

4.2 Polymers Poly(acrylamide) (PAM) and poly(acrylate) polymers and copolymers are used typically for high-temperature applications or friction reducers at low concentrations for all temperatures ranges [4]. To reduce the energy losses in the course of pumping, certain friction reducing polymers have been included in treatment fluids. Hydraulic Fracturing Chemicals and Fluids Technology https://doi.org/10.1016/B978-0-12-822071-9.00011-6

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Table 4.1 Monomers for friction reducing polymers [1]. Monomer

Acrylamide Acrylic acid 2-Acrylamido-2-methylpropane sulfonic acid N,N-dimethylacrylamide Vinyl sulfonic acid N-Vinyl acetamide N-Vinyl formamide Itaconic acid Methacrylic acid Acrylic acid esters Methacrylic acid esters

In general, friction reducing polymers are high-molecular weight polymers, such as those having a molecular weight of at least about 2.5 MDa. Typically, friction reducing polymers are linear and flexible. One example of such a friction reducing polymer is a copolymer from acrylamide (AAm) and acrylic acid [1]. A wide variety of monomers may be suitable for use with the present technique. These are summarized in Table 4.1. Friction reducing polymers may be in the acid form or in the salt form. Multivalent ions contained in the water used to prepare the treatment fluids may undesirably interact with the friction reducing polymers. The multivalent ions may reduce the effectiveness of the friction reducing polymers. The use of complexing agents to control the multivalent ions in the water can improve the performance of the friction reducing polymers. It has been discovered that addition of the complexing agent to the concentrated polymer composition rather than to the water may reduce the amount of the complexing agent needed to improve performance of the friction reducing polymers. By adding an inorganic complexing agent to the oil continuous phase, where it is insoluble, a much improved friction reducer performance can be observed. Examples of complexing agents are shown in Table 4.2.

4.3 Environmental aspects The use of friction reducing polymers has proved challenging from an environment standpoint [6]. For example, many of the friction reducing

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Table 4.2 Complexing agents [1,5]. Compound

Carbonates Phosphates Pyrophosphates Orthophosphates Citric acid Gluconic acid Glucoheptanoic acid Ethylenediamine tetraacetic acid Nitrilotriacetic acid

polymers that have been used previously are provided as oil-external emulsion polymers, wherein upon addition to the aqueous treatment fluid, the emulsion should invert, releasing the friction reducing polymer into the fluid. While aqueous pad fluids and other aqueous well treating fluids containing friction pressure reducers have been used successfully, the friction pressure reducers have been suspended in a hydrocarbon–water emulsion and as a result they have been toxic and detrimental to the environment. Thus, there are needs for improved friction pressure reducers which are nontoxic and environmentally acceptable [7]. The hydrocarbon carrier fluid present in the oil-external emulsion may pose environmental problems with the subsequent disposal of the treatment fluid. Among other reasons, disposal of hydrocarbons, e.g., the carrier fluid in the oil-external emulsion, may have undesirable environmental characteristics or may be limited by strict environmental regulations in certain areas of the world [6]. Furthermore, the hydrocarbon carrier fluid present in the oil-external emulsion also may undesirably contaminate water in the formation. Waterbased friction reducing polymers seem to be more suitable than other polymer types for environmental aspects. A nontoxic environmentally acceptable friction pressure reducer can be formulated from a copolymer of AAm and dimethylaminoethyl acrylate quaternized with benzyl chloride and a stabilizing and dispersing homopolymer of acryloyloxyethyltrimethyl ammonium chloride [7]. The structure of this monomer is shown in Fig. 4.1.

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Figure 4.1 Acryloyloxyethyltrimethyl ammonium chloride. Table 4.3 Friction reduction by AMPS-based polymers for foamed liquids [8]. Polymer type AMPS/[%] Friction loss/[%]

Acrylamide, traces acrylate 15–20% AMPS, acrylamide, traces acrylate Cationic acrylamide 80%) were not evaluated by the International Agency for Research on Cancer and therefore could not be reviewed. Of the 111 potential water contaminants and 29 potential air pollutants evaluated by the International Agency for Research on Cancer (119 unique compounds), 49 water and 20 air pollutants were known, probable, or possible human carcinogens (55 unique compounds). Potential water contaminants and air pollutants related to unconventional oil and gas development with evidence of carcinogenicity are shown in Table 20.1.

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Table 20.1 Potential water contaminants and air pollutants with carcinogenicity for leukemia [21]. Water contaminants

Air pollutants

Carcinogenic to humans

1,3-Butadiene Benzene Cadmium Ethanol Formaldehyde Ethylene oxide

1,3-Butadiene Benzene Diesel Ethanol Formaldehyde

Probably carcinogenic to humans

Tetrachloroethylene

Tetrachloroethylene

Possibly carcinogenic to humans

Styrene 1,2-Propylene oxide Hydrazine

Styrene

A total of 17 water and 11 air pollutants (20 unique compounds) showed evidence of increased risk for leukemia/lymphoma, including benzene, 1,3-butadiene, cadmium, diesel exhaust, and several polycyclic aromatic hydrocarbons. Though information on the carcinogenicity of compounds associated with unconventional oil and gas development was limited, the present assessment identified 20 known or suspected carcinogens that could be measured in future studies to advance exposure and risk assessments of cancer causing agents. These findings support the need for investigations of the relationship between unconventional oil and gas development and risk of cancer in general and childhood leukemia in particular [21].

20.1.2 Classification of hydraulic fracturing chemicals FracFocus registry Much interest has been directed at the chemical structure of hydraulic fracturing additives in unconventional gas exploitation [22]. The structural properties have been reviewed, which motivate hydraulic fracturing applications, and which determine environmental fate and toxicity. This quantitative overview relied on voluntary US disclosures evaluated from

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the FracFocus registry by different sources and on a House of Representatives (Waxman) list. Out of over 1000 reported substances, classification by chemistry yielded succinct subsets able to illustrate the rationale of their use, and physicochemical properties relevant for environmental fate, toxicity, and chemical analysis. While many substances were nontoxic, frequent disclosures also included notorious groundwater contaminants like petroleum hydrocarbons (solvents), precursors of endocrine disruptors like nonylphenols (nonemulsifiers), toxic propargyl alcohol (corrosion inhibitor), tetramethylammonium (clay stabilizer), biocides, or strong oxidants. The application of highly oxidizing chemicals, together with occasional disclosures of putative delayed acids and complexing agents, i.e., compounds designed to react in the subsurface, suggests that relevant transformation products may be formed [22]. In another study, 1021 chemicals identified in hydraulic fracturing fluids, waste water, or both were systematically evaluated for potential reproductive and developmental toxicity to triage those with potential for human health impact [23]. The disclosure of hydraulic fracturing chemicals is required by a lot of states [24]. Direct reporting is done to FracFocus [25]. FracFocus contains the most comprehensive dataset on fracturing chemicals but faces data quality and transparency criticisms. In response, FracFocus announced upgrades, and since May 2015, FracFocus publishes aggregated data. In a study, 96,449 forms submitted between March 9, 2011 and April 13, 2015 were analyzed [24]. It was found that the rates of withheld chemical information have increased since 2013, and appear unaffected by different legal requirements. Automatic field population and prompts in FracFocus can reduce data error, while enforcement signals, education, and harmonized requirements may boost compliance and enhance disclosure. Systems reporting should occur, with states retaining authority to request product-specific ingredient lists [24].

REPROTOX database The REPROTOX database was evaluated using Chemical Abstract Service registry numbers for chemicals with available data. Then, the evidence for adverse reproductive and developmental effects was evaluated. The systematic screening approach identified a list of 67 hydraulic fracturing-related candidate analytes based on known or suspected toxic-

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ity. The incorporation of data on potency, physicochemical properties, and environmental concentrations could further prioritize these substances for future drinking water exposure assessments or reproductive and developmental health studies [23].

Globally harmonized system It is important to characterize the chemicals that are found in hydraulic fracturing fluids to evaluate their potential environmental fate, including fate in treatment systems, and human health impacts. Eighty-one common hydraulic fracturing chemical additives were identified and categorized according to their functions [4]. The physical and chemical characteristics of these additives were determined using publicly available chemical information databases; 55 of the compounds are organic and 27 of these are considered readily or inherently biodegradable, while 17 chemicals have high theoretical chemical oxygen demand and are used in concentrations that present potential treatment challenges. Most of the hydraulic fracturing chemicals evaluated are nontoxic or of low toxicity and only three are classified as Category 2 oral toxins according to standards in the Globally Harmonized System of Classification and Labelling of Chemicals. However, toxicity information was not located for 30 of the hydraulic fracturing chemicals evaluated. Volatilization is not expected to be a significant exposure pathway for most hydraulic fracturing chemicals. Gaps in toxicity and other chemical properties suggest deficiencies in the current state of knowledge, highlighting the need for further assessment to understand potential issues associated with hydraulic fracturing chemicals in the environment [4].

Comprehensive model During drilling operations, tons of flowback and produced water, which contain several organic compounds, return to the surface with a potential risk of influencing the surrounding environment and human health [26]. In order to conduct predictive risk assessments a mathematical model is needed to evaluate organic compound behavior along the water transportation process as well as concentration changes over time throughout the operational life cycle. A comprehensive model which fits the experimental data, combining an Organic Matter Transport Dynamic Model with a Two-Compartment

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First-order Rate Constant Model, has been established to quantify the organic compound concentrations. This algorithm model incorporates two transportation rates, fast and slow. The results show that the higher the value of the organic carbon partition coefficient in chemicals is, the later the maximum concentration in water will be reached. The maximum concentration percentage would reach up to 90% of the available concentration of each compound in shale formation (whose origin may be associated with drilling fluid, connate water, and/or rock matrix) over a sufficiently long period of time. This model could serve as a contribution to enhance monitoring strategies, increase benefits by optimizing health risk assessments for local residents, and provide initial baseline data to further operations [26].

Indexing methods Hydraulic fracturing additive and fracturing fluid data were acquired, and environmental and human health hazards were assessed using an indexing approach [27]. The indexing system analyzed chemical toxicological data of different ingredients contained within additives and produced an aggregated environmental and human health safety index for each additive, along with an indicator describing the completeness of the chemical toxicological data. The results of the study showed that commonly used additives are generally associated with medium-level environmental and human health hazards. In each additive category, ingredients of high environmental and human health concern could be identified, and the high hazard designation was primarily attributed to the high aquatic toxicity of the ingredient and carcinogenic effects. Among all assessed additive categories, iron control agents were identified as the greatest environmental and human health hazards [27]. Lack of information, such as undisclosed ingredients and chemical toxicological data gaps, has resulted in different levels of assessment uncertainties. In particular, friction reducers show the highest data incompleteness with regard to environmental and human health hazards. The study revealed the potential environmental and human health hazards associated with chemicals used in current hydraulic fracturing field operations [27]. A fuzzy-based indexing approach was developed for the management of hydraulic fracturing chemical additives. The environmental and human health hazards of an additive are converted to hazard indices using an indexing system [28].

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To account for uncertainties, a fuzzy-based approach was adopted based on fuzzy inference and fuzzy clustering analysis to assess the risk potential of different additives for informed chemical management decision making. The assessment of the randomly selected additives showed that this fuzzybased indexing approach gave different chemical hazard assessment results for about 30% of the assessed additives. This showed that accounting for uncertainties using this methodology can lead to better informed chemical management decision making. The hazard assessment results also indicated that based on current indexing methodology, more than half of the additives permitted for use in hydraulic fracturing operations were considered moderate environmental and human health hazards. Based on this fuzzy-based approach the majority (80%) of the additives were identified as low and very low risk potential due to their low use frequencies [28]. The environmental and human health risks of 105 representative hydraulic fracturing additives used in British Columbia, Canada, were analyzed, based on the three previously listed factors using a fuzzy clustering analysis approach [29]. The performance of additives on these factors was converted into indices using an indexing system. The indices were grouped into seven clusters according to their relative similarities. The environmental and human health risk of each cluster was interpreted based on the resulting indices. The results of this study showed that additives grouped in clusters 7 and 2 had relatively high environmental and human health risks, which require special attention in hydraulic fracturing operations. Clusters 4, 1, and 5 were identified to have moderate environmental and human health risks, while clusters 6 and 3 are of low environmental and human health risk concerns. Many iron control agents were classified into cluster 7, indicating that this type of additives is associated with a high environmental and human health risk. Many friction reducers and gelling agents were classified into cluster 4, characterized by the highest hazard uncertainty. The assessment of hypothetical fracturing fluids showed that using additives grouped in clusters with a low risk could help mitigate the environmental and human health impacts posed by hydraulic fracturing chemicals [29].

HYDRUS computer software The HYDRUS-1D and HYDRUS (2D/3D) computer software packages are widely used for simulating the one-, two-, and three-dimensional

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movement of water, heat, and multiple solutes in variably saturated media [30]. The standard HYDRUS models consider only the fate and transport of individual solutes or solutes subject to first-order degradation reactions, but several specialized HYDRUS add-on modules can simulate more complex biogeochemical processes. A brief overview of the HYDRUS models and their add-on modules has been given [30]. Possible applications of the software to the subsurface fate and transport of chemicals involved in coal seam gas extraction and water management operations were demonstrated. Three fields of application were detailed. The examples were selected to show how users can tailor the required model complexity to specific needs, such as for rapid screening or risk assessments of various chemicals under generic soil conditions, or for more detailed site-specific analyses of actual subsurface pollution problems [30] One application uses the standard HYDRUS model to evaluate the natural soil attenuation potential of hydraulic fracturing chemicals and their transformation products in case of an accidental release. By coupling the processes of retardation, first-order degradation, and convective-dispersive transport of the biocide bronopol and its degradation products, it was demonstrated how natural attenuation reduces the initial concentrations by more than a factor of hundred in the top 5 cm of the soil. A second application uses the UnsatChem module to explore the possible use of coal seam gas-produced water for sustainable irrigation. Simulations with different irrigation waters (untreated, amended with surface water, and reverse osmosis-treated) provided detailed results regarding chemical indicators of soil and plant health, notably SAR, EC, and sodium concentrations. A third application uses the HP1 module to analyze trace metal transport involving cation exchange and surface complexation sorption reactions in a soil leached with coal seam gas-produced water following some accidental water release scenario. The results showed that the main process responsible for trace metal migration in soil is complexation of naturally present trace metals with inorganic ligands such as carbonate and bicarbonate that enter the soil upon infiltration with alkaline produced water.

Cytoscape analysis Epidemiologic studies have suggested associations between proximity to unconventional oil and gas operations with increased adverse birth out-

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comes and cancer, though specific potential etiologic agents have not yet been identified [31]. At the moment, there is no single hazard classification list based on the United Nations Globally Harmonized System (GHS), with countries applying the GHS standards to generate their own chemical hazard classification lists. A current challenge for chemical prioritization, particularly for a multinational industry, is inconsistent hazard classification which may result in misjudgment of the potential public health risks. A novel approach for hazard identification followed by prioritization of reproductive toxicants found in unconventional oil and gas operations using publicly available regulatory databases has been presented [31]. A scoring system was utilized to assign numerical values for reproductive health, cancer, and germ cell mutation hazard endpoints. By Cytoscape analysis, both qualitative and quantitative results were presented visually to readily identify high-priority unconventional oil and gas chemicals with evidence of multiple adverse effects [31]. Cytoscape is an open source bioinformatics software platform for visualizing molecular interaction networks and integrating with gene expression profiles and other state data [32]. Substantial inconsistencies in classification among the 11 databases were observed. By adopting the most stringent classification within and across countries, 43 chemicals were classified as known or presumed human reproductive toxicants (GHS Category 1), while 31 chemicals were classified as suspected human reproductive toxicants (GHS Category 2). The 43 reproductive toxicants were further subjected to analysis for carcinogenic and mutagenic properties. Calculated hazard scores and Cytoscape visualization yielded several high-priority chemicals, including potassium dichromate, cadmium, benzene, and ethylene oxide [31].

Modeling inhalation exposure The possible occupational inhalation exposures and potential risks related to the volatile organic compounds from chemical storage tanks and flowback pits used in hydraulic fracturing were investigated [33]. AERMOD – Description of Model Formulation was used in the study [34]. Potential risks were evaluated based on radial distances between 5 m and 180 m from the wells for 23 contaminants with known inhalation reference concentration or inhalation unit risks (IURs). The results of the study revealed that chemicals used in 12.4% of the wells posed potential acute noncancer risks for exposure and 0.11% of the wells may provide chronic noncancer risks for exposure. Chemicals used

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in 7.5% of the wells were associated with potential acute cancer risks for exposure. Those chemicals used in 5.8% of the wells may be linked to chronic cancer risks for exposure. While eight organic compounds were associated with acute noncancer risks for exposure (>1), methanol was the major compound in the chemical storage tanks (1.00–45.49) in 7282 hydraulic fracturing wells. Wells with chemical additives containing formaldehyde exhibited both acute and chronic cancer risks for exposure with inhalation unit risks greater than 10−6 , suggesting that formaldehyde was the dominant contributor to both types of risks for exposure in hydraulic fracturing. It was also found that due to other existing on-site emission sources of volatile organic compounds and the geographically compounded air concentrations from other surrounding wells, chemical emission data from storage tanks and flowback pits used in this study were lower than reported concentrations from field measurements, where higher occupational inhalation risks for exposure may be expected [33].

Comparison of the use of chemicals with different methods The potential hazards and risks associated with well stimulation in unconventional oil and gas development, such as hydraulic fracturing, acid fracturing, and matrix acidizing, have been investigated and evaluated [35]. Also, federal and state regulations that require chemical disclosure for well stimulation have been implemented as part of an overall risk management strategy for unconventional oil and gas development. The chemical use between routine activities and the more closely regulated well stimulation activities were compared using data collected by the South Coast Air Quality Monitoring District, which mandates the reporting of both unconventional and routine on-field chemical use for parts of Southern California. Data concerning chemical type, mass injected, and water volumes used in oil and gas operations were downloaded from the South Coast Air Quality Monitoring District database [36] for the period of June 4, 2013 to September 2, 2015. Here, operators and chemical suppliers are required to submit and make publicly available chemical usage data related to routine oil and gas activities (well drilling, well completion, and well rework) and well stimulation (hydraulic fracturing, matrix acidizing) in the California counties of San Bernardino, Orange, Riverside, and Los Angeles, including the City of Los Angeles.

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For the chemical additives identified, the toxicological data were collected from online chemical databases. Computational models within the US EPA EPI Suite software (e.g., BIOWIN) were used to fill data gaps when experimental data were unavailable. Rat, mouse, and rabbit acute oral toxicity data and rat and mouse inhalation toxicity data were collected to represent and compare mammalian toxicity of the chemical constituents. An analysis of these data showed that there is a significant overlap in chemical use between so-called unconventional activities and routine activities conducted for well maintenance, well completion, or rework. A comparison within the South Coast Air Quality Monitoring District showed a significant overlap between both types and amounts of chemicals used for well stimulation treatments included under State mandatory disclosure regulations and routine treatments that are not included under state regulations. A comparison between South Coast Air Quality Monitoring District chemical use for routine treatments and statewide chemical use for hydraulic fracturing also showed a close similarity in chemical use between activities covered under chemical disclosure requirements, e.g., hydraulic fracturing, and many other oil and gas field activities. The results of this study indicated that the regulations and risk assessments focused exclusively on chemicals used in well stimulation activities may underestimate the potential hazard or the risk from overall oilfield chemical use [35]. Current regulatory issues

An assessment of federal, state, and local regulations and legal activity regarding hydraulic fracturing as of late 2016 has been given [37]. It includes a postelection assessment of how some results are likely to further impact hydraulic fracturing. This analysis includes a review of recent court cases, pending legal challenges and appeals, relevant statutes, and recent environmental studies affecting hydraulic fracturing. Also, possible future regulatory trends, recommendations for practicing engineers, and suggestions for corporate policy decision makers were discussed [37].

Biocides in hydraulic fracturing fluids Biocides are critical components in hydraulic fracturing fluids that are used for unconventional shale gas development. Bacteria may cause bioclogging and inhibit gas extraction, produce toxic H2 S, and induce corrosion leading

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to downhole equipment failure. The use of biocides such as glutaraldehyde and quaternary ammonium compounds has spurred a public concern and debate among regulators regarding the impact of inadvertent releases into the environment on ecosystem and human health. A critical review of the potential fate and toxicity of biocides used in hydraulic fracturing operations has been given [38]. The following physicochemical and toxicological aspects as well as knowledge gaps that should be considered when selecting biocides are [38]: 1. uncharged species will dominate in the aqueous phase and be subject to degradation and transport whereas charged species will sorb to soils and be less bioavailable, 2. many biocides are short-lived or degradable through abiotic and biotic processes, but some may transform into more toxic or persistent compounds, 3. understanding of the fate of biocides under downhole conditions, such as high pressure, temperature, and salt and organic matter concentrations, is limited, and 4. several biocidal alternatives exist, but high cost, high energy demands, and/or formation of disinfection byproducts limit their use. Environmental impact screening frameworks for identifying organic compounds in hydraulic fracturing fluids have been developed [39]. The majority of these studies, however, evaluated the impact of these chemicals individually and in a general sense, without a specific focus on conditions relevant to the hydraulic fracturing process. Recently, a few studies have addressed interactions within chemical mixtures; however, these studies mostly characterized complex hydraulic fracturing fluid mixtures through bulk parameters rather than by a specific compound approach, as was done in this study. A thorough understanding of chemical and biological interactions in released hydraulic fracturing fluids is extremely important because the chemicals used in hydraulic fracturing have the ability to alter solubility, viscosity, microbial communities, pH, and other aspects of the soil environment that may affect the fate of other additives. Additionally, additives may impact each other directly through chemical reactions [2]. This study may serve as a guide for environmental risk assessment and identification of microbial control strategies to help develop a sustainable path for managing hydraulic fracturing fluids [38]. A suite of stable luciferase reporter gene assays were employed to investigate the potential for selected hydraulic fracturing chemicals or geogenics

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Figure 20.1 Biocides.

to activate or antagonize nuclear receptor signaling. Three biocides were screened: bronopol, glutaraldehyde, and tetrakis(hydroxymethyl)phosphonium sulfate [40]. These compounds are shown in Fig. 20.1. A surfactant (2-butoxyethanol), a friction reducer (polyacrylamide), and a coal seam geogenic (o-cresol) were tested for their potential to act as agonists or antagonists of the estrogen receptor, androgen receptor, progesterone receptor, glucocorticoid receptor, or peroxisome proliferatoractivated receptor (PPAR). None of the chemicals induced luciferase activity in any of assays used in the study. In antagonistic mode, bronopol, glutaraldehyde, and tetrakis(hydroxymethyl)phosphonium sulfate caused reductions in luciferase activity in the reporter assays at concentrations of 50–100 µM. At concentrations of 2–10 µM glutaraldehyde and tetrakis(hydroxymethyl)phosphonium sulfate enhanced the luciferase activity in some assays relative to the controls [40]. None of the other tested chemicals exhibited an antagonism in the selected assays. In most cases, altered receptor signaling only occurred at concentrations exhibiting cytotoxicity. However, proliferator-activated receptor gamma activity and, to a lesser extent, progesterone receptor activity

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were inhibited by tetrakis(hydroxymethyl)phosphonium sulfate at subcytotoxic concentrations. The majority of the tested binary combinations exhibited a significantly less-than-additive cytotoxicity, and none of the combinations exhibited a synergistic cytotoxicity. In summary, the results of the study indicated that the selected chemicals are not likely to function as direct agonists of the nuclear receptors tested, and only one chemical, tetrakis(hydroxymethyl)phosphonium sulfate, was an apparent partial antagonist of two nuclear receptors [40].

Contaminated surface water for fish and mussels Produced water from oil and gas extraction processes has been shown to contain elevated concentrations of major ions. The objective of a study was to determine the potential effects of elevated major ions in produced watercontaminated surface water on a fish (fathead minnow, Pimephales promelas) and a unionid mussel (fatmucket, Lampsilis siliquoidea) after short-term (7 d) exposure [41]. The test organisms were exposed in three reconstituted waters formulated with 1, 2, and 4 times the major ion concentrations measured at a produced water-contaminated stream site 1 month after a produced water spill from an oil production waste water pipeline in the Williston Basin, North Dakota. Reconstituted water mimicking the ionic composition of an upstream site from the spill was used as reference water. Significant reductions in survival and growth of the fish were observed in the 4× treatment compared with the reference. The mussels were more sensitive than the fish, with significant reductions in survival in the 2× and 4× treatments, and significant reductions in length in the 1× and 2× treatments. Overall, these results indicate that elevated concentrations of major ions in produced water-contaminated surface waters could adversely affect the fish and mussels tested and potentially also other aquatic organisms [41].

Groundwater contamination Fracking poses two main risks to the groundwater quality [42]: 1. stray gas migration, and 2. potential contamination from chemical and fluid spills. The risk assessment is complicated due to the lack of predrilling baseline measurements, limited access to well sites and industry data, the constant

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introduction of new chemical additives to frack fluids, and difficulties comparing datasets obtained by different sampling and analytical methods. Specific recommendations to reduce uncertainties and meet science needs for better assessment of groundwater risks include improving data sharing among researchers, adopting standardized methodologies, collecting predrilling baseline data, installing dedicated monitoring wells, developing shale-specific environmental indicators, and providing greater access to field sites, samples, and industry data to the research community [42]. Hydraulic fracturing operations have been regarded as a cause of certain environmental issues including groundwater contamination [43]. The potential for hydraulic fracturing to induce contaminant pathways in groundwater is not well understood since gas wells are completed while isolating the water table and the gas bearing reservoirs lay thousands of feet below the water table. Recent studies have attributed groundwater contamination to poor well construction and leaks in the wellbore annulus due to ruptured wellbore casings. A geospatial model of the Barnett Shale region was created using ArcGIS. ArcGIS is a geographic information system for working with maps and geographic information. It is used for creating and using maps, compiling geographic data, analyzing mapped information, sharing and discovering geographic information, using maps and geographic information in a range of applications, and managing geographic information in a database [44]. This model was used for spatial analysis of groundwater quality data in order to determine if regional variations in groundwater quality, as indicated by various groundwater constituent concentrations, may be associated with the presence of hydraulically fractured gas wells in the region [43]. The Barnett Shale reservoir pressure, completions data, and fracture treatment data were evaluated as predictors of groundwater quality change. The results of the study indicated that elevated concentrations of certain groundwater constituents are likely related to natural gas production. Beryllium could be used as an indicator variable for evaluating fracturing impacts on the regional groundwater quality. The results of the study also indicated that gas well density and formation pressures correlate to change in regional water quality whereas proximity to gas wells, by itself, does not [43].

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Delayed hydrogen sulfide production Horizontal drilling in combination with hydraulic fracturing allows for more efficient extraction of natural gas from less accessible reservoirs [45]. An issue is the increase of hydrogen sulfide and mercaptans during the early production from hot shale gas reservoirs at a temperature of more than 100◦ C. Hydraulic fracturing technologies rely on the use of chemical additives for modifying the physical and chemical properties of fracturing fluids to drag proppant into the reservoir. Under downhole conditions, native hydrogen sulfide or metal sulfides can be partially oxidized by dissolved oxygen or other aqueous species, thus producing elemental sulfur. This elemental sulfur can slowly oxidize the chemical additives, thus regenerating hydrogen sulfide and other organosulfur species. The reaction kinetics of sulfur and alcohol reaction under downhole conditions has been investigated. The rates and the reaction types are presented and discussed as an alternative mechanism for the delayed production of mercaptans and hydrogen sulfide [45].

Potential hazards for drinking water resources Despite the growing concerns over the potential for hydraulic fracturing to impact drinking water resources, there are only limited data available to identify chemicals used in hydraulic fracturing fluids that may pose public health concerns [46]. To explore these potential hazards, a multicriterion decision analysis framework was used to analyze and rank selected subsets of these chemicals by integrating data on toxicity, frequency of use, and physicochemical properties that describe transport in water. The framework employed in the study was a three-part prioritization model, which incorporates data on toxicity, frequency of use, and physicochemical properties (cf. Fig. 20.2). This framework is based on aspects of the method by Mitchell et al. [47], who developed a multicriterion decision analysis approach for ranking chemical exposure potential by integrating data on physicochemical properties and life cycle analysis. The data that were used in this method were obtained from publicly available databases compiled by the United States Environmental Protection Agency as part of a larger study on the potential impacts of hydraulic fracturing on drinking water [46].

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Figure 20.2 Three-part prioritization model [46].

Starting with nationwide hydraulic fracturing chemical usage data from United States Environmental Protection Agency analysis of the FracFocus Chemical Disclosure Registry 1.0, multicriterion decision analysis tests were performed on chemicals that had either noncancer toxicity values (37 chemicals) or cancer-specific toxicity values (10 chemicals) [46]. The noncancer multicriterion decision analysis was then repeated for subsets of chemicals reported in three representative states (Texas, Pennsylvania, and North Dakota). Within each multicriterion decision analysis, chemicals received scores based on relative toxicity, relative frequency of use, and physicochemical properties, such as mobility in water, volatility, and persistence. The results of the study showed a relative ranking of these chemicals based on hazard potential, and can provide preliminary insight into chemicals that may be more likely than others to impact drinking water resources. A comparison of nationwide versus state-specific analysis studies indicated regional differences in the chemicals that may be of more concern to drinking water resources, although many chemicals were commonly used and received similar overall hazard rankings. Several chemicals highlighted by these multicriterion decision analysis methods have been reported in groundwater near areas of hydraulic fracturing activity [46].

20.1.3 Analysis methods Hydraulic fracturing fluids contain a mixture of organic and inorganic additives in an aqueous media. The compositions of these mixtures vary

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according to the region or company use, thus making the process of identifying individual compounds difficult [48]. The analytical characterization of such mixtures is important in order to understand the transport, environmental fate, and ultimate potential health impact in various water compartments associated with hydraulic fracturing. Organic compound classes include solvents, gels, biocides, scale inhibitors, friction reducers, surfactants, and other related compounds. These contaminants are usually present in trace amounts, so sophisticated analytical methodologies are needed in order to fully characterize the chemical composition of fracking fluids. The current trends and emerging technologies in analytical chemistry and their applicability to flowback and produced waters were assessed. Also, underutilized approaches were proposed that may serve as potential solutions to address the issues created by the complex matrices inherent to flowback and produced waters [49]. Also, the known analytical methods for characterizing the potential environmental impacts of unconventional oil and gas development have been reviewed [50].

Reactor for investigating subsurface chemical transformations Hydraulic fracturing coupled with horizontal drilling involves the deepwell injection of a fracturing fluid composed of diverse and numerous chemical additives designed to facilitate the release and collection of natural gas from shale plays [51]. Analysis studies of flowback waste waters have revealed organic contamination from both geogenic and anthropogenic sources. The additional detection of undisclosed halogenated chemicals suggested unintended in situ transformation of reactive additives, but the formation pathways for these are unclear in subsurface brines. To develop an efficient experimental framework for investigating the complex shale-well parameter space, geospatial well data detailing temperature, pressure, pH, and halide ion values have been assessed, as well as industrial chemical disclosure and concentration data [51]. These findings showed that subsurface conditions can reach pressures up to 310 bar and temperatures up to 95◦ C, while at least 588 unique chemicals have been disclosed by industry, including reactive oxidants and acids. To simulate these extreme conditions of subsurface, existing geochemical reactor systems rated to the necessary pressures and temperatures identifying throughput as a key limitation have been assessed.

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Then, a custom reactor system was designed and developed that was capable of achieving 345 bar and 90◦ C at low cost with 15 individual reactors that are readily turned over [51]. To demonstrate the system’s throughput, 12 disclosed hydraulic fracturing chemicals coupled with horizontal drilling were simultaneously tested against a radical initiator compound in simulated subsurface conditions, ruling out a dozen potential transformation pathways in a single experiment. The dynamic and diverse parameter ranges experienced were outlined by hydraulic fracturing coupled with horizontal drilling chemical additives. An optimized framework and a novel reactor system have been described for the methodical study of subsurface transformation pathways [51]. The halogenation of cinnamaldehyde in the presence of ammonium persulfate demonstrated the potential for oxidative breakers to react with halides to yield reactive halogen species [52]. Halogenated product formation, product distribution, and kinetics were evaluated with respect to shale well subsurface conditions, linking transformation risk to measurable welldependent characteristics, e.g., halide compositions, well temperatures, and pH. In a representative flowback brine, the brominated product dominated on a molar percent basis (6 ± 2%, as normalized by initial cinnamaldehyde loading) over chlorinated (1.4 ± 0.4%) and iodinated forms (2.5 ± 0.9%), reflecting relative halide abundance and propensity for oxidation. Thus, relevant subsurface reactions between natural brines and hydraulic fracturing additives can result in the unintended formation of halogenated products [52].

Gas chromatography–mass spectrometry In recent years, modern analytical methodologies, such as gas chromatography–mass spectrometry (GC-MS), have been specifically used to identify organic chemical components of fracking fluids and/or flowback and produced waters associated with the process of hydraulic fracturing [48]. Liquid chromatography coupled with quadrupole time-of-flight mass spectrometry was used to identify chemical additives present in flowback and produced waters [53]. Accurate mass measurements of the main ions and fragments were used to characterize the major components of fracturing fluids. In the study, sodium adducts turned out as the main molecular adduct ions detected for some additives due to oxygen-rich structures. The analyzed classes of chemical components include gels (guar gum), bio-

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cides (glutaraldehyde and alkyl dimethyl benzyl ammonium chloride), and surfactants (cocamidopropyl dimethylamines, cocamidopropyl hydroxysultaines, and cocamidopropyl derivatives). The capabilities of accurate mass and MS-MS fragmentation were explored for the unequivocal identification of these compounds [53,54]. A detailed description of chemical constituents present in hydraulic fracturing waters have been given, as well as the evaluation of the analytical techniques used for their unequivocal determination [48].

Liquid chromatography–high-resolution mass spectrometry The uncertainties and knowledge gaps of chemical risk assessment related to unconventional drillings were assessed in a review [55]. It was discussed how chemical risk assessment in the context of unconventional oil and gas activities differs from conventional chemical risk assessment, and the implications for existing legislation were addressed. An unconventional oil and gas suspect list of 1386 chemicals that might be expected in the unconventional oil and gas water samples was prepared which can be used for liquid chromatography–high resolution mass spectrometry suspect screening. This detailed list can be found online [55]. The information on reported concentrations in unconventional oil- and gas-related water was actualized. Most information relates to shale gas operations, followed by coalbed methane, while only little was found to be available for tight gas and conventional gas. The limited research on conventional oil and gas recovery hampers research whether risks related to unconventional activities are in fact higher than those related to conventional activities. No study was found that analyzed the whole cycle from fracturing fluid, flowback and produced water, and surface water and groundwater. Generally target screening has been used, probably missing the contaminants of concern. Almost half of the organic compounds analyzed in surface water and groundwater exceed the threshold of toxicological concern (TTC) values, so further risk assessment is needed, and the risks cannot be waived. Further, no specific exposure scenarios toward groundwater aquifers exist for unconventional oil- and gas-related activities. Human errors in various stages of the life cycle of unconventional oil and gas production play an important role in the exposure. Neither at the international level nor at the US federal and EU levels, specific regulations for unconventional oil- and gas-related activities are in place to protect environmental and human health. Unconventional oil and gas activities are

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mostly regulated through general environmental, spatial planning, and mining legislation [55].

Liquid chromatography–electrospray ionization mass spectrometry Quantitative analytical methods are needed to evaluate waste water disposal alternatives or to conduct adequate exposure assessments. However, a narrow understanding of how matrix effects change the ionization efficiency of target analytes limits the quantitative analysis of polar to semipolar hydraulic fracturing additives by means of liquid chromatography–electrospray ionization mass spectrometry [56]. To address this limitation, the ways in which matrix chemistry influences the ionization of 17 priority hydraulic fracturing additives were explored with a modified standard addition approach. Then the data were used to quantify hydraulic fracturing additives in hydraulic fracturing-associated fluids. The results demonstrated that hydraulic fracturing additives generally exhibit a suppressed ionization in hydraulic fracturing-associated fluids, though hydraulic fracturing additives that predominantly form sodiated adducts exhibit significantly enhanced ionization in produced water samples, which is largely the result of adduct shifting. In a preliminary screening, glutaraldehyde and 2-butoxyethanol were identified along with homologs of benzalkonium chloride, poly(ethylene glycol), and poly(propylene glycol) in hydraulic fracturing-associated fluids. Then matrix recovery factors were used to provide quantitative measurements of the individual homologs of benzalkonium chloride, poly(ethylene glycol), and poly(propylene glycol) in hydraulic fracturing-associated fluids, ranging from mg l−1 levels in hydraulic fracturing fluid to µg l−1 levels in the samples. This approach is generalizable across sample types and shale formations and yields important data to evaluate waste water disposal alternatives or implement exposure assessments [56].

Molecular imprinted polymers A molecularly imprinted polymer has been described that enables the detection of 2-butoxyethanol, a pollutant associated with hydraulic fracturing contamination [57]. The detection is based on a combination of a colloidal crystal templating and molecular imprinting. The molecularly imprinted polymers display a higher binding capacity for 2-butoxyethanol compared with nonimprinted films, with imprinting efficiencies of around 2.

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The tests relied on the optical effects that are displayed by the uniformly ordered porous structure of the material. The reflectance spectra of the polymer films have characteristic Bragg peaks whose location varies with the concentration of 2-butoxyethanol. Peaks undergo longwave red shifts up to 50 nm on exposure of the molecularly imprinted polymer to 2-butoxyethanol in concentrations in the range from 1 ppb to 100 ppm. This allows a quantitative estimation of the 2-butoxyethanol concentrations present in aqueous solutions. The material is intended for use in the early detection of contamination at hydraulic fracturing sites [57].

Shale waste water samples Six Fayetteville Shale waste water samples were investigated for organic composition using a suite of one- and two-dimensional gas chromatographic techniques to capture a broad distribution of chemical structures [58]. Following the application of strict compound identification confidence criteria, compounds were classified according to their putative origin. The samples displayed distinct chemical distributions composed of typical geogenic substances (hydrocarbons and hopane biomarkers), disclosed unconventional natural gas development additives, e.g., hydrocarbons, phthalates such as diisobutyl phthalate, and radical initiators such as azobis(isobutyronitrile). Also undisclosed compounds, e.g., halogenated hydrocarbons, such as 2-bromohexane or 4-bromoheptane, and chloromethyl alkanoates (chloromethyl propanoate, pentanoate, and octanoate) were found. These were identified as potential delayed acids, i.e., those that release acidic moieties only after hydrolytic cleavage. The identification of halogenated methanes and acetones suggested that those compounds were formed as unintended byproducts. Some of the above-mentioned compounds are shown in Fig. 20.3. This study highlights the possibility that unconventional natural gas development operations generate transformation products and underscores the value of disclosing additives injected into the subsurface [58]. Organic components of unconventional oil and gas waste water can alter the microbial communities and biogeochemical processes, which could alter the rates of essential natural attenuation processes [59]. These findings provide new insights into microbial responses following a release of unconventional oil and gas waste water and are critical for identifying strategies for the remediation and natural attenuation of impacted environments.

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Figure 20.3 Natural gas development additives.

The demand for high-volume, short-duration water withdrawals could create water stress to aquatic organisms in Fayetteville Shale streams sourced for hydraulic fracturing fluids. The potential water stress was estimated using permitted water withdrawal volumes and actual water withdrawals compared with monthly median, low, and high streamflows. The risk for biological stress was considered at 20% of the long-term median and 10% of high- and low-flow thresholds [60]. Most water was permitted from small, free-flowing streams and frack ponds, i.e., dammed streams. Permitted 12 h pumping volumes exceeded the median streamflow at 50% of withdrawal sites in June, when the flows were low. Daily water usage from operator disclosures, compared with median streamflow, showed possible water stress in 7% to 51% of catchments from June–November, respectively. If 100% of produced water was recycled, per-well water use declined by 25%, reducing the threshold exceedance by 10%. Future water stress was predicted to occur in fewer catchments important for drinking water and species of conservation concern due to the decline in new well installations and increased use of recycled water. Accessible and precise withdrawal and streamflow data are critical moving forward to assess and mitigate water stress in streams that experience high-volume withdrawals [60].

Shale gas flowback and produced waters Organic contaminants in shale gas flowback and produced water are traditionally expressed as total organic carbon or chemical oxygen demand.

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These parameters do not provide information on the toxicity and the environmental fate of individual components. Methods for the identification of organic contaminants in flowback and produced water have been reviewed [61]. Risk quotient approach

The risk quotient approach was applied to predict the toxicity of the quantified organic compounds for fresh water organisms in recipient surface waters [61]. This resulted in an identification of a number of flowback and produced water-related organic compounds that are potentially harmful, namely, those compounds originating from shale formations, e.g., polycyclic aromatic hydrocarbons, phthalates, fracturing fluids, e.g., quaternary ammonium biocides and 2-butoxyethanol, and downhole transformations of organic compounds, e.g., carbon disulfide and halogenated organic compounds. Also, the removal of these compounds by flowback and produced water treatment processes has been reviewed and further potential and efficient abatement strategies were defined [61]. Statistical analysis of flowback and produced waters

When the waters from hydraulic fracturing return to the surface, they are characterized by complex organic and inorganic chemistry, and can pose a health risk if not handled correctly. Therefore, these waters must be treated or disposed of properly. The water chemistry of a hydraulically fractured site in the Niobrara formation throughout the flowback period was examined. The samples were collected every other day for the first 18 days, and then on a regular basis for three months [62]. Hydraulic fracturing fluid additives were identified, such as benzalkonium chlorides, alkyl ethoxylates, and poly(ethylene glycol)s, as well as geogenic components present in flowback and produced waters. These findings indicated that alkalinity and iron may limit the reuse of these waters in hydraulic fracturing, while chloride and alkalinity may limit the use of these waters for well casing cement. Also, the presence of numerous surfactant homologs, including biocides, was observed, with the highest levels at the beginning of the flowback period. Principal component analysis identified three unique groupings in the chemical data that correspond to different stages in the flowback period [62]:

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1. the flowback stage (days 1–2), 2. the transition stage (days 6–21), and 3. the produced water stage (days 21–87). The results from this study are important for the designation of decision frameworks for assessing water treatment options, particularly if on-site treatment is attempted [62].

Geochemical fingerprints The identification of geochemical fingerprints of fluids that return to the surface after high-volume hydraulic fracturing of unconventional oil and gas reservoirs has important applications for assessing hydrocarbon resource recovery, environmental impacts, and waste water treatment and disposal. Diagnostic elemental and isotopic signatures (B/Cl, Li/Cl, δ 11 B, and 7 δ Li) have been described [63]. These are useful for the characterization of hydraulic fracturing flowback fluids and distinguishing the sources of hydraulic fracturing flowback fluids in the environment. Data from 39 hydraulic fracturing flowback fluids and produced water samples show that B/Cl (>0.001), Li/Cl (>0.002), δ 11 B(25–31‰), and δ 7 Li (6–10‰) compositions of hydraulic fracturing flowback fluids from the Marcellus and Fayetteville black shale formations were distinct in most cases from produced water sampled from conventional oil and gas wells. The boron isotope geochemistry can be used to quantify small fractions (0.1%) of hydraulic fracturing flowback fluids in contaminated fresh water and can be applied universally to trace hydraulic fracturing flowback fluids in other basins. The environmental application of this diagnostic isotopic tool was validated by examining the composition of effluent discharge from an oil and gas brine treatment facility in Pennsylvania and an accidental spill site in West Virginia. It is assumed that the boron and lithium materials are mobilized from exchangeable sites on clay minerals in the shale formations during the hydraulic fracturing process, resulting in the relative enrichment of boron and lithium in hydraulic fracturing flowback fluids [63]. The environmental impacts of a typical hydraulic fracturing operation for shale gas recovery were evaluated using life cycle assessment, with energy demands for well drilling and fracturing determined from the GHGfrack model [64]. GHGfrack is an open source engineering-based

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model that estimates energy consumption and associated greenhouse gas emissions from drilling and hydraulic fracturing operations [65]. Dominant environmental impacts stem from well construction, which are >63% in all categories, e.g., global warming and eutrophication, and mainly due to diesel fuel combustion and steel production [64]. The relative impacts related to water use, i.e., fracturing fluid components, water/waste water transportation, and waste water disposal, are relatively small, ranging from 5% to 22% of total impacts in all categories. Also, freshwater consumption for fracturing is a small fraction of available water resources for the shale play considered. The impacts of replacing slickwater with CO2 or CH4 -foam fracturing fluid (with 10% by volume of water) were evaluated. The total impacts decrease to less than 12%, and relative impacts related to water use decrease to 2–9% of total impacts. Thus, switching to a foam-based fracturing fluid can substantially decrease water-related impacts (of greater than 60%) but has only marginal effects on total environmental impacts. Changes in lateral well length, produced water-to-fresh water ratios, fracturing fluid composition, and life cycle assessment control volume do not change these findings. More benefits could potentially be realized by considering water versus foam-related impacts of ecological health and energy production [64]. A numerical model of two-phase water and gas flow in a shale gas formation has been presented [66,67]. This model has been used to test the hypothesis that the remaining water is imbibed into the shale rock by capillary forces and retained there indefinitely. A substantial amount of data that are relevant for modeling multiphase flow of water and gas in shale gas formations was collated [68]. The model includes the essential physics of the system and uses the simplest justifiable geometrical structure. The model was applied to simulate wells from a specific well pad in the Horn River Basin, British Columbia, of which there are sufficient available data to build and test the model. The simulation experiments matched the water and gas production data from the wells remarkably closely and showed that all the injected water can be accounted for within the shale system, with most imbibed into the shale rock matrix and retained there for the long term [66].

Special components Organic compounds

Qualitative and quantitative analysis methods of organic compounds identified in high-volume hydraulic fracturing fluids, flowback fluids, and pro-

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duced waters have been reviewed to communicate knowledge gaps that exist in the composition of high-volume hydraulic fracturing waste waters [69]. Analysis methods of organic compounds have been focused on those amenable to gas chromatography, thus focusing on volatile and semivolatile oil and gas compounds. Studies of more polar and nonvolatile organic compounds have been limited by a lack of knowledge of what compounds may be present as well as quantitative methods and standards available for analyzing these complex mixtures. Liquid chromatography paired with high-resolution mass spectrometry has been used to investigate a number of additives and will be a key tool to further research on transformation products that are increasingly solubilized through physical, chemical, and biological processes in situ and during environmental contamination events [69]. In the study, amino-poly(ethylene glycol)s, amino-poly(ethylene glycol) carboxylates, and amino-poly(ethylene glycol) amines were discovered in 20 produced water samples from hydraulic fracturing in the western USA [69]. Semivolatile hydrocarbons

A versatile method was developed for the quantitative analysis of semivolatile linear aliphatic hydrocarbons in the n−C10 to n−C32 range and 16 polycyclic aromatic hydrocarbons in hydraulic fracturing waste waters using solid-phase extraction on disposable octadecyl-bonded silica (C18) cartridges followed by gas chromatography–mass spectrometry [70]. Matrix spikes revealed solid-phase extraction recovery rates in the range of 38–120% for linear aliphatic hydrocarbons (n−C10 to n−C32 ) and 84–116% for polycyclic aromatic hydrocarbons. The limits of detection were in the lower ng l−1 range for both compound groups. To prove the practicability of the developed method in real applications, the treatment performance of a hybrid forward osmosis– reverse osmosis pilot system treating produced water from the DenverJulesburg basin in Colorado was assessed over a period of 8 weeks. The removal efficiency of the overall system after reverse osmosis treatment for n-alkanes was constantly better than 99.4%. The lower-molecular weight polycyclic aromatic hydrocarbons naphthalene, fluorene, and phenanthrene were the most abundant polycyclic aromatic hydrocarbons detected in the produced water feed, filtrate, and concentrate streams during treatment.

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Their concentrations in the produced water feed reached up to 359.3 µg l−1 , 40.7 µg l−1 , and 68.3 µg l−1 . These were the only analyzed poly-

cyclic aromatic hydrocarbons in the final treated water that exceeded the general US Environmental Protection Agency maximum contaminant level for polycyclic aromatic hydrocarbons in drinking water [70]. Polypropylene glycols and polyethylene glycol carboxylates

Attemps were made to separate and identify unknown surfactants present in flowback and produced water from oil and gas wells in the DenverJulesburg Basin (Niobrara Formation) in Weld County, Colorado, USA [71]. PPG and PEG carboxylates were found for the first time in these flowback and produced water samples. These ethoxylated surfactants can be used as friction reducers, clay stabilizers, and surfactants. Ultrahigh-performance liquid chromatography/quadrupole time-offlight mass spectrometry was used to separate and identify the different classes of PPG and PEG carboxylates and their isomers [71]. The Kendrick mass scale [72] was applied along with mass spectrometry/mass spectrometry with accurate mass for rapid and unequivocal identification. The Kendrick mass scaling factor is calculated from the ratio of nominal mass of the group divided by the true accurate mass. This ratio is then multiplied by the measured mass to calculate the Kendrick mass. The importance of the Kendrick mass is that each peak with the same Kendrick mass defect is related by exactly one ethylene oxide unit to the one before or after it in the chromatogram [71]. PPGs and their isomers occur at the ppm concentration range and may be useful as fingerprints of hydraulic fracturing. Comparing these detections to the compounds used in the fracturing process from FracFocus 3.0, it appears that both PPG and PEG are commonly named as additives, but the PEG carboxylates have not been reported. The PEG carboxylates may be trace impurities or degradation products of PEG [71]. Halogenated organic compounds

The current understanding of the specific organic constituents in these hydraulic fracturing waste waters was limited to hydrocarbons and a fraction of known chemical additives. In a study, hydraulic fracturing waste water samples were analyzed using ultrahigh-resolution Fourier transform ion cyclotron resonance mass spectrometry as a nontargeted technique to as-

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sign unambiguous molecular formulas to singly charged molecular ions [73]. Halogenated molecular formulas were identified and confirmed using isotopic simulation and MS-MS fragmentation spectra. The abundance of halogenated organic compounds in flowback fluids rather than older waste waters suggested that the observed molecular ions might have been related to hydraulic fracturing additives and related subsurface reactions, such as through the reaction of shale-extracted chloride, bromide, and iodide with strong oxidant additives, e.g., hypochlorite, persulfate, and hydrogen peroxide, and subsequently with diverse dissolved organic matter. Some molecular ions matched the exact masses of known disinfection byproducts, including diiodoacetic acid, dibromobenzoic acid, and diiodobenzoic acid. The identified halogenated organic compounds, particularly iodinated organic molecules, are absent from inland natural systems and these compounds could therefore play an important role as environmental tracers [73]. Fracking-derived gases

The state-of-the-art techniques and promising new approaches were reviewed for identifying oil and gas production from unconventional reservoirs to resolve whether they are the source of fugitive methane and associated contaminants into shallow aquifers [74]. These approaches may be applied to broader subsurface exploration and development issues, e.g., groundwater resources, or new frontiers of lowcarbon energy alternatives, e.g., subsurface hydrogen storage, nuclear waste isolation, and geologic carbon dioxide sequestration [74].

Microcosm experiments Degradation of glutaraldehyde

Microcosms were used to elucidate the inhibition of biodegradation at varying glutaraldehyde concentrations. In the absence of glutaraldehyde, half-lives ranged from 13 d to >93 d. Mass spectrometry indicated that a trimer was the dominant aqueous-phase glutaraldehyde species. A microbial inhibition was observed at glutaraldehyde trimer concentrations as low as 5 mg l−1 , which demonstrated that the trimer retained some biocidal activity. For most of the compounds, the biodegradation rates slowed with increasing glutaraldehyde concentrations. For many of the compounds, the

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degradation was faster in the columns than the microcosms. Four compounds (2-propanol, ethylene glycol, propargyl alcohol, and 2-butoxyethanol) were found to be both mobile and persistent in groundwater under a range of redox conditions. The glutaraldehyde trimer and 2-ethylhexanol were more rapidly degraded, particularly under oxic conditions [75]. Also, the impacts of exposure to the biocide glutaraldehyde on the biodegradation potential were examined [76]. Microcosms were constructed from hydraulic fracturing-impacted and nonhydraulic fracturingimpacted streamwater within the Marcellus Shale region in Pennsylvania. Microcosms were amended with glutaraldehyde and incubated aerobically for 56 d. Microbial community adaptation to glutaraldehyde was monitored using 16S rRNA gene amplicon sequencing and quantification by qPCR. The abiotic and biotic glutaraldehyde degradation was measured using ultrahigh-performance liquid chromatography–high resolution mass spectrometry and the total organic carbon content. It was found that nonhydraulic fracturing-impacted microcosms biodegraded glutaraldehyde faster than the hydraulic fracturing-impacted microcosms, showing a decrease in degradation potential after exposure to hydraulic fracturing activity. Hydraulic fracturing-impacted microcosms showed higher richness after glutaraldehyde exposure compared to unimpacted streams, indicating an increased tolerance to glutaraldehyde in hydraulic fracturing impacted streams. Beta diversity and differential abundance analysis of sequence count data showed a different bacterial enrichment for hydraulic fracturing-impacted and nonhydraulic fracturing-impacted microcosms after the addition of glutaraldehyde. These findings demonstrated a lasting effect on microbial community structure and glutaraldehyde degradation potential in streams impacted by hydraulic fracturing operations [76]. Degradation of poly(ethylene glycol)s and poly(propylene glycol)s

Poly(ethylene glycol)s and poly(propylene glycol)s are frequently used in hydraulic fracturing fluids and have been detected in water returning to the surface from hydraulically fractured oil and gas wells in multiple basins. The degradation pathways and kinetics for poly(ethylene glycol)s and poly(propylene glycol)s under conditions simulating a spill of produced water to shallow groundwater were identified [77]. Sediment-groundwater microcosm experiments were conducted using four produced water samples from two Denver-Julesburg Basin wells at early and late production. High-resolution mass spectrometry was used

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to identify the formation of mono- and dicarboxylated poly(ethylene glycol)s and monocarboxylated poly(propylene glycol)s, which are products of poly(ethylene glycol) and poly(propylene glycol) biodegradation, respectively. Under oxic conditions, first-order half-lives were shorter for poly(ethylene glycol)s (less than 0.4–1.1 d) than for poly(propylene glycol)s (2.5–14 d) [77]. The degradation of poly(ethylene glycol) and poly(propylene glycol) corresponded to an increased relative abundance of primary alcohol dehydrogenase genes predicted from metagenome analysis of the 16S rRNA gene. Further degradation was not observed under anoxic conditions. These results give an insight into the differences between the degradation rates and pathways of poly(ethylene glycol)s and poly(propylene glycol)s, which may be utilized to better characterize shallow groundwater contamination following a release of produced water [77].

20.2 Treatment methods 20.2.1 Natural attenuation of nonionic surfactants The biodegradability of three widely used nonionic polyglycol ether surfactants, alkyl ethoxylates, nonylphenol ethoxylates, and poly(propylene glycol)s, was evaluated [78]. These compounds function as weatherizers, emulsifiers, wetting agents, and corrosion inhibitors in injected fluids. Under anaerobic conditions, a complete removal of alkyl ethoxylates and nonylphenol ethoxylates from solution was observed within 3 weeks, regardless of whether surfactants were part of a chemical mixture or amended as individual additives. Microbial enzymatic chain shortening was responsible for a shift in ethoxymer molecular weight distributions and the accumulation of the metabolite acetate. Poly(propylene glycol)s bioattenuated the slowest, producing sizable concentrations of acetone, an isomer of propionaldehyde. Surfactant chain shortening was coupled to an increased abundance of the diol dehydratase gene cluster (pduCDE) in Firmicutes metagenomes predicted from the 16S rRNA gene. The pduCDE enzymes are responsible for cleaving ethoxylate chain units into aldehydes before their fermentation into alcohols and carboxylic acids. These data provide a new mechanistic insight into the environmental fate of hydraulic fracturing surfactants after accidental release through chain

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shortening and biotransformation, emphasizing the importance of compound structure disclosure for predicting biodegradation products [78].

20.2.2 Visible light photocatalysis Glutaraldehyde is the most common biocide used in unconventional oil and gas production. The photocatalytic degradation of glutaraldehyde in brine simulating oil- and gas-produced water using an Ag/AgCl/BiOCl composite as a photocatalyst with visible light was investigated. Removal of glutaraldehyde at 0.1 mM in 200 g l−1 NaCl solution at pH 7 was 90% after 75 min irradiation using 5 g l−1 of the photocatalyst. The glutaraldehyde removal followed a pseudofirst-order reaction with a rate constant of 0.0303 min−1 . At a pH of 5 or at 300 g l−1 NaCl, the photocatalytic removal of glutaraldehyde was almost completely inhibited. Similar inhibitions were observed when adding dissolved organic carbon (from humic acid) at 10 and 200 mg l−1 or Br− at 120 mg l−1 to the system. The removal rate of glutaraldehyde markedly increased with increasing pH (5–9), with photocatalyst loading (2–8 g l−1 ) and under 350 nm UV (compared with visible light). In contrast, the removal rate of glutaraldehyde markedly decreased with increasing NaCl and initial glutaraldehyde concentrations (0–300 g l−1 for NaCl and 0.1–0.4 mM for glutaraldehyde). A quenching experiment was also conducted. Electron holes and superoxide were found as the main reactive species responsible for the removal of glutaraldehyde while OH had a very limited effect [79].

20.2.3 Biological treatment of produced water Biological treatment is effective but infrequently used for oil- and gasproduced water. To date, physical–chemical treatment methods have been favored due to the smaller space requirements and operational simplicity. Changing the regulatory requirements and increased interest in recycling and beneficial reuse have led to increased interest in biological treatment. To elucidate its potential role, 59 studies on the biological treatment of produced water were reviewed and summarized [80]. Oilfield-produced water was predominantly studied. More studies using real produced water have been conducted in China than in any other country. Real produced water was used in most studies (73%). Studies were predominantly bench-scale experiments (69%). Fixed-film reactors were most prevalent (27%). The water quality of the produced waters treated was variable; the median concentration of total dissolved

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solids was 28,000 mg l−1 and the median chemical oxygen demand was 1125 mg l−1 . Inhibition by salinity was variable according to the treatment system and study design, but the efficacy generally decreased when total dissolved solids was above 50,000 mg l−1 . For studies treating real samples, average chemical oxygen demand removal was 73% when the concentration of total dissolved solids was less than 50,000 mg l−1 , and 54% when the concentration of total dissolved solids was greater than 50,000 mg l−1 . Key issues were microbial acclimation, toxicity, biological fouling, and mineral scaling. Finding an inoculum was not problematic as microorganisms capable of degrading hydrocarbons were isolated from various environments. Treatment performance was better where synthetic produced water was used in lieu of real samples. Biological treatment is promising for producing effluents suitable for reuse, particularly where it functions as part of a larger treatment train [80]. Hydraulic fracturing of unconventional gas wells utilizes large volumes of water-based fluid to increase formation permeability, and it generates large amounts of waste water as flowback. This water requires a suitable treatment before being reused or discharged into the environment [81]. An overview on the exploration and subsequent environmental implications of unconventional gas sources has been presented, as well as the technologies for treatment of produced water, describing the main results and drawbacks, together with some cost estimates [82]. In particular, the growing volumes of produced water from shale gas plays are creating an interesting market opportunity for water technology and service providers. Membrane-based technologies, such as membrane distillation, forward osmosis, membrane bioreactors and pervaporation, and advanced oxidation processes, e.g., ozonation, Fenton, and photocatalysis, were claimed to be adequate treatment solutions [82].

Degradation of guar A principal ingredient of flowback water is guar gum, used as gelling agent, which may adversely affect advanced flowback water treatment, such as membrane separation [81]. The potential of an activated sludge mixed liquor to degrade guar under typical flowback conditions was demonstrated. Guar was efficiently degraded at a total dissolved solids concentration of 1500 mg l−1 , with more than 90% of the dissolved chemical oxygen demand having been removed after 10 h. Increasing the total dissolved solids concentration to 45,000 mg l−1 inhibited the dissolved chemical oxygen demand degrada-

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tion to 60% removal after 31 h. A high total dissolved solids concentration additionally resulted in an increased effluent level of total suspended solids and turbidity. However, these could be efficiently reduced using ferric chloride coagulation followed by sedimentation and filtration. The biological reduction of the guar concentration increased the flux of a bench-scale ultrafiltration membrane, thus demonstrating the potential of the process to treat flowback water prior to membrane separation [81].

Sequencing batch reactor An aerobic granular sludge tolerable to high salinity and suited to the treatment of flowback water was shown [83]. The performance of a sequencing batch reactor with the aerobic granular sludge for the treatment of the synthetic flowback water and the microbial community structure at different salinity levels were investigated. The aerobic granular sludge fed with synthetic flowback water possessed a larger average particle size and a higher settling rate (50 m h−1 ). When the NaCl concentration increased to 50.0 g l−1 , the removal efficiency of total organic carbon (TOC) increased to 79±1%, and the removal rate of poly(acrylamide) raised up to 42.7±0.7 g m−3 d−1 . Alphaproteobacteria, Betaproteobacteria, Gammaproteobacteria, and Sphingobacteriia dominated in the microbial community of the aerobic granular sludge. Cellvibrionaceae, Rhodocyclaceae, Enterobacteriaceae, Moraxellaceae, Pseudomonadaceae, and Halomonadaceae, belonging to Betaproteobacteria and Gammaproteobacteria, played an important role in degrading poly(acrylamide), polycyclic aromatic hydrocarbons, and some other organics in the flowback water at high salinity. The results of this study suggested that an aerobic granular sludge-based sequencing batch reactor is a promising technology for the treatment of flowback water [83].

20.2.4 Biodegradation in agricultural topsoil Hydraulic fracturing frequently occurs on agricultural land. The extent of sorption, transformation, and interactions among the numerous organic fracturing fluid and oil and gas waste water constituents upon environmental release are hardly known [84]. The processes that control the environmental fate and the toxicity of commonly used hydraulic fracturing chemicals have been studied. PE-based surfactants were completely biodegraded in agricultural topsoil

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within 42–71 d, but their transformation was impeded in the presence of the biocide glutaraldehyde and was completely inhibited by salt at concentrations which are typical for oil and gas waste water. At the same time, aqueous glutaraldehyde concentrations decreased due to sorption to soil and were completely biodegraded within 33–57 d. While no aqueous removal of polyacrylamide friction reducer was observed over a period of 6 months, it crosslinked with glutaraldehyde, further lowering the biocide’s aqueous concentration. These findings highlight the necessity to consider some cocontaminant effects for the risk of fracturing fluid additives and oil and gas waste water constituents in agricultural soils in order to understand their human health impacts, likelihood for crop uptake, and potential for groundwater contamination [84]. Inadvertent spills of flowback water may pose a risk to the surrounding environment due to its high salt content, metals or metalloids (As, Se, Fe, and Sr), and organic additives. The potential impact of flowback water on four representative soils from shale gas regions in northeast China using synthetic flowback solutions was investigated [85]. The compositions of the solutions were representative of flowback water arising at different stages after fracturing well establishment. The effects of the composition of the solution of flowback water on soil ecosystems were assessed in terms of metal mobility and bioaccessibility, as well as biological endpoints using Microtox bioassay (with Vibrio fischeri) and enzyme activity tests. After 1 month artificial aging of the soils with various flowback solutions, the mobility and bioaccessibility of As(V) and Se(VI) decreased as the ionic strength of the flowback solutions increased [85]. The results showed a stronger binding affinity of As(V) and Se(VI) with the soils. Nevertheless, the soil toxicity to V. fischeri only presented a moderate increase after aging, while dehydrogenase and phosphomonoesterase activities were significantly suppressed with increasing ionic strength of flowback solutions. In contrast, polyacrylamide in the flowback solutions led to a higher dehydrogenase activity. These results indicated that soil enzyme activities were sensitive to the composition of flowback solutions. A preliminary human health risk assessment related to As(V) suggested a low level of cancer risk through exposure via ingestion, while holistic assessment of environmental implications is required [85].

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20.2.5 Aerobic biodegradation of organic compounds Synthetic hydraulic fracturing fluid A synthetic hydraulic fracturing fluid was developed from disclosed industry formulas and produced for laboratory experiments using commercial additives in use by Marcellus Shale field crews [86]. The experiments employed an internationally accepted standard method (OECD 301A [87]) to evaluate the aerobic biodegradation potential of the fluid mixture by monitoring the removal of dissolved organic carbon from an aqueous solution by activated sludge and lake water microbial consortia for two substrate concentrations and four salinities. The microbial degradation process removed from 57% to more than 90% of added dissolved organic carbon within 6.5 d, with a higher removal efficiency at more dilute concentrations and little difference in overall removal extent between sludge and lake microbe treatments. The alcohols isopropanol and octanol were degraded to levels below their detection limits, while the solvent acetone accumulated in biological treatments through time. Salinity concentrations of 40 g l−1 or more completely inhibited the degradation during the first 6.5 d of incubation with the synthetic hydraulic fracturing fluid even though communities were preacclimated to salt. Initially diverse microbial communities became dominated by 16S rRNA sequences affiliated with Pseudomonas and other Pseudomonadaceae after incubation with the synthetic fracturing fluid, taxa which may be involved in acetone production. These data expand the understanding of constraints on the biodegradation potential of organic compounds in hydraulic fracturing fluids under aerobic conditions in the event that they are accidentally released to surface waters and shallow soils [86].

Biodegradation of alkyl and nonylphenol ethoxylate surfactants Nonionic polyethoxylates are commonly added surfactants that act as weatherizers, emulsifiers, wetting agents, and corrosion inhibitors in hydraulic fracturing fluid formulations [88]. Understanding the biodegradability of these ubiquitous additives is critical for produced water pretreatment prior to reuse and for improving treatment trains for external beneficial reuse. The effect of produced water total dissolved solids from an unconventional natural gas well on the aerobic biodegradation of alkyl ethoxylate and nonylphenol ethoxylate surfactants was assessed [88].

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Changes in surfactant concentrations, speciation, and metabolites, as well as microbial community composition and activity, were quantified over a 75-day aerobic incubation period. Alkyl ethoxylates were degraded faster than nonylphenol ethoxylates, and both compound classes and bulk organic carbon biodegraded slower in total dissolved solids treatments (10 g l−1 , 40 g l−1 ) compared with the controls. Short-chain ethoxylates were more rapidly biodegraded than longerchain ethoxylates, and changes in the relative abundance of metabolites including acetone, alcohols, and carboxylate and aldehyde intermediates of alkyl units indicated metabolic pathways may shift in the presence of higher concentrations of total dissolved solids in produced water. Thus, it was found that polyethoxylated alcohol surfactant additives are less labile at high concentrations of total dissolved solids. This has important implications for produced water management, as these fluids are increasingly recycled for beneficial reuse in hydraulic fracturing fluids [88].

20.2.6 Microbial electrochemical cells The performance of microbial fuel cells and microbial capacitive deionization cells feeded with waste water produced from the Bakken Shale was evaluated [89]. The produced water was characterized by high levels of dissolved solids and chemical oxygen demand. Two-compartment microbial fuel cells and three-compartment microbial capacitive deionization cells were evaluated under batch-fed mode using mixed microbial consortia in the anode, ferricyanide in the cathode, and produced water as the electrolyte in the anode and capacitive deionization units. Chemical oxygen demand removal in the microbial fuel cells was 88%, while that in the microbial capacitive deionization cells was limited to 76%. The lower performance of the microbial capacitive deionization cells was due to the large impedance (6600  cm2 ) compared with the microbial fuel cells (870  cm2 ). However, the microbial capacitive deionization cells could achieve a twofold higher removal of dissolved solids. Both the microbial fuel cells and microbial capacitive deionization cells suffered from a higher impedance induced by fouling in the latter stages of the operation [89].

20.2.7 Iron–biochar composites Recently, porous carbon or mineral materials, e.g., activated carbon and zeolite, have attracted much attention as nanoscale zerovalent iron supporters,

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owing to their high surface area and specific pore/channel structure that prevent oxidation and aggregation of nanoscale zerovalent iron [90], and therefore may be applicable for fracturing waste water treatment [91–93]. In comparison to activated carbon, biochar, a porous material derived from biological waste via pyrolysis, offers a more sustainable option as a solid support for nanoscale zerovalent iron [94]. More importantly, biochar may carry more abundant oxygen containing surface functional groups (e.g., CO, COC, and CO) than activated carbon, which may be capable of interacting with Fe to form multifunctional Fe–biochar composites [95]. A novel sorbent for the removal of potentially toxic elements, inherent cations, and hetero-chloride from hydraulic fracturing waste water was evaluated [96]. A series of iron–biochar composites with different iron/biochar impregnation mass ratios (0.5:1, 1:1, and 2:1) were prepared by mixing forestry wood waste-derived biochar powder with an aqueous FeCl3 solution and subsequently pyrolyzing them at 1000◦ C in an N2 -purged tubular furnace. The porosity, surface morphology, crystalline structure, and interfacial chemical behavior of the iron–biochar composites were characterized, revealing that Fe chelated with CO bonds as CO−Fe moieties on the biochar surface, which were subsequently reduced to a C−C bond and nanoscale zerovalent Fe during pyrolysis [96]. The chemical mechanism of the synthesis can be summarized as follows [96]: 2FeCl3 + 6H2 0 2Fe(OH)3 C + H2 O 3Fe2 O3 + H2 , CO, C Fe3 O3 3FeO + 6C Fe3 C

A A A A A A A

2Fe(OH)3 + 6HCl, Fe2 O3 + 3H2 O, CO + H2 , 2Fe3 O4 , 3FeO, Fe3 C + 3CO, 3Fe + C.

(20.1)

The performance of the iron–biochar composites was evaluated for the simultaneous removal of potentially toxic elements (Cu(II), Cr(VI), Zn(II), and As(V)), inherent cations (K, Na, Ca, Mg, Ba, and Sr), heterochloride (1,1,2-trichlorethane), and total organic carbon from high-salinity (233 g l−1 total dissolved solids model) fracturing waste water. By elucidating the removal mechanisms of different contaminants, it was demonstrated that iron–biochar (1:1) had an optimal reducing/charge

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transfer reactivity owing to the homogenous distribution of nanoscale zerovalent iron with the highest Fe0 /Fe2+ ratio. A lower Fe content in iron– biochar (0.5:1) resulted in a rapid exhaustion of Fe0 , while a higher Fe content in iron–biochar (2:1) caused severe aggregation and oxidization of Fe0 , contributing to its complexation/(co)precipitation with Fe2+ /Fe3+ . All of the synthesized iron–biochar composites exhibited a high removal capacity for inherent cations (3.2–7.2 g g−1 ) in fracturing waste water through bridging with the CO bonds and cation-p interactions. In summary, the potential efficacy and mechanistic roles of iron–biochar composites for (pre)treatment of high-salinity and complex fracturing waste water could be illustrated [96].

20.2.8 Estrogen and androgen receptor activity The rapid rise in natural gas extraction using the hydraulic fracturing technique increases the potential for contamination of surface and groundwater from chemicals used throughout the process [97]. A lot of products that contain more than 750 chemicals and components are potentially used throughout the extraction process, including more than 100 known or suspected endocrine disrupting chemicals. It was estimated that a selected subset of chemicals used in natural gas drilling operations and also surface and groundwater samples collected in a drilling-dense region of Garfield County, Colorado, would exhibit estrogen and androgen receptor activities. In a study, water samples were collected, solid-phase-extracted, and measured for estrogen and androgen receptor activities using reporter gene assays in human cell lines. Of the 39 unique water samples, 89%, 41%, 12%, and 46% exhibited estrogenic, antiestrogenic, androgenic, and antiandrogenic activities, respectively. Testing of a subset of natural gas drilling chemicals revealed novel antiestrogenic, novel antiandrogenic, and limited estrogenic activities. The Colorado River, the drainage basin for this region, exhibited moderate levels of estrogenic, antiestrogenic, and antiandrogenic activities, suggesting that higher localized activity at sites with known natural gas-related spills surrounding the river might contribute to the multiple receptor activities observed in this water source. The majority of water samples collected from sites in a drilling-dense region of Colorado exhibited more estrogenic, antiestrogenic, or antiandrogenic activities than reference sites with limited nearby drilling operations. These findings suggested that natural gas drilling operations may result in

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an elevated endocrine disrupting chemical activity in surface water and groundwater [97]. The endocrine activities and organic contaminants in groundwater from conventional oil and gas and unconventional oil and natural gas production regions of Wyoming were studied [98]. Groundwater samples were collected from each region, solid-phaseextracted, and assessed for endocrine activities (estrogen, androgen, progesterone, glucocorticoid, and thyroid receptor agonism and antagonism), using reporter gene assays in human endometrial cells [98]. Water samples from unconventional oil and natural gas and conventional oil areas exhibited greater estrogen receptor antagonist activities than water samples from conventional gas areas. Samples from unconventional oil and natural gas areas tended to exhibit progesterone receptor antagonism more often, suggesting there may be an unconventional oil- and natural gas-related impact on these endocrine activities. Unconventional oiland natural gas-specific contaminants in Pavillion groundwater extracts, and these same chemicals at high concentrations in a local unconventional oil and natural gas waste water sample, were also reported. A unique suite of contaminants was observed in groundwater from a permitted drinking water well at a conventional oil and gas well pad and not at any unconventional oil and natural gas sites. High levels of endocrine activities were noted there, suggesting putative impacts on endocrine bioactivities by conventional oil and gas [98]. Hydraulic fracturing flowback and produced water samples were analyzed for toxicity and microbiome characterization over 220 d for a horizontally drilled well in the Denver-Julesburg Basin in Colorado [99]. Cytotoxicity, mutagenicity, and estrogenicity of flowback and produced water were measured via the BioLuminescence Inhibition Assay, Ames II mutagenicity assay, and Yeast Estrogen Screen. Raw flowback and produced water stimulated bacteria in the BioLuminescence Inhibition Assay, but were cytotoxic to yeast in the Yeast Estrogen Screen. Filtered flowback and produced water stimulated cell growth in both the BioLuminescence Inhibition Assay and the Yeast Estrogen Screen. Concentrating 25-fold by solid-phase extraction revealed a significant toxicity throughout well production by the BioLuminescence Inhibition Assay, toxicity during the first 55 d of flowback by the Yeast Estrogen Screen, and mutagenicity by the Ames II mutagenicity assay. The selective pressures of fracturing conditions, including toxicity, affected bacterial and archaeal communities, which were characterized by 16S rRNA gene

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V4V5 region sequencing. Conditions selected for thermophilic, anaerobic, and halophilic bacteria and methanogenic Archaea from the groundwater used for fracturing fluid, and from the native shale community [99].

Endocrine disrupting chemicals Adipogenic activity

New research has evaluated current models of adipogenesis, and new models have been proposed [100]. Only in the last several years have studies really begun to address complex mixtures of contaminants and how these mixtures may disrupt metabolic health in environmentally relevant exposure scenarios. Several studies have begun to assess environmental mixtures from various environments and study the mechanisms underlying their putative metabolic dysfunction. These studies hold real promise in highlighting crucial mechanisms driving observed organismal effects. In addition, high-throughput toxicity databases (ToxCast, etc.) may provide future benefits in prioritizing chemicals for in vivo testing, particularly once the causative molecular mechanisms promoting dysfunction are better understood and expert critiques are used to hone the databases. More than 1000 organic chemicals are used in the production process, and waste water is produced following injection and for the life of the producing well [101]. This waste water is typically disposed of via injecting into disposal wells for long-term storage, treatment and discharge from waste water treatment plants, and/or storage in open evaporation pits. However, waste water spill rates are reported at 2% to 20% of active well sites across regions, increasing concerns about the environmental impacts of these waste waters. The adipogenic activity (both triglyceride accumulation and preadipocyte proliferation) was assessed for a mixture of 23 commonly used unconventional oil and natural gas chemicals and a small subset of unconventional oil and natural gas chemicals waste water-impacted surface water extracts from Colorado and West Virginia, using 3T3-L1 cells and a PPARγ reporter assay [101]. Potent and efficacious adipogenic activity was reported, induced by both a laboratory-created unconventional oil and natural gas chemical mixture and unconventional oil and natural gas chemicals-impacted water samples at concentrations below environmental levels. Also, the activation of PPARγ at similar concentrations for some samples was assessed, suggesting a causative molecular pathway for the observed

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effects, but not for other adipogenic samples, implicating PPARγ -dependent and -independent effects from unconventional oil and natural gas chemical-associated chemicals. In summary, these results suggested that unconventional oil and natural gas chemicals waste water has the potential to impact metabolic health at environmentally relevant concentrations [101]. Endocrine disrupting activity

Oil and natural gas operations have been shown to contaminate surface and groundwater with endocrine disrupting chemicals. Endocrine disrupting chemicals are defined as any exogenous chemical or mixture of chemicals that can interfere with any aspect of hormone action [102]. As many as 1000 endocrine disrupting chemicals have been identified, both synthetic and naturally occurring [103]. The endocrine disrupting activities were investigated for 24 chemicals used for and/or produced by oil and gas operations for five nuclear receptors using a reporter gene assay in human endometrial cancer cells [104]. Also, the concentration of 16 of these chemicals in oil and gas waste water samples was measured. The chemicals that were used for testing are presented in Table 20.2. The reproductive and developmental outcomes in male C57BL/6J mice were assessed after the prenatal exposure to a mixture of these chemicals. It was found that 23 commonly used oil and natural gas operation chemicals can activate or inhibit the estrogen, androgen, glucocorticoid, progesterone, and/or thyroid receptors, and mixtures of these chemicals can behave synergistically, additively, or antagonistically in vitro [104]. The prenatal exposure to a mixture of 23 oil and gas operation chemicals at 3, 30, and 300 µg kg−1 d−1 caused decreased sperm counts and increased testis, body, heart, and thymus weights and increased serum testosterone levels in male mice, suggesting multiple organ system impacts [104]. An investigation has been presented of whether developmental exposure to a mixture of chemicals associated with unconventional oil and gas operations affects the development and function of the immune system [105]. A mixture of 23 chemicals associated with unconventional oil and gas was used as in a previous study (cf. Table 20.2). This mixture demonstrated to affect reproductive and developmental endpoints in mice. C57Bl/6 mice were maintained throughout pregnancy and during lactation on water containing two concentrations of this 23-chemical mixture, and the immune system of male and female adult offspring was assessed. The cellularity of primary and secondary immune organs was examined. Three differ-

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Table 20.2 Tested chemicals [104]. Compound

Uses in oil and gas operation

1,2,4-Trimethylbenzene 2-(2-Methoxyethoxy) ethanol 2-Ethylhexanol 2-Methyl-4-isothiazolin-3-one Acrylamide Benzene Bronopol Cumene Diethanolamine Ethoxylated nonylphenol Ethoxylated octylphenol Ethylbenzene Ethylene glycol Ethylene glycol monobutyl ether Naphthalene N,N-dimethylformamide Phenol Propylene glycol Sodium tetraborate decahydrate Styrene Toluene Triethylene glycol Xylenes

Surfactant Biocide, surfactant Defoamer, breaker Biocide Scale control, friction reducer Paraffin inhibitor, surfactant Biocide Paraffin inhibitor Friction reducer, corrosion inhibitor Surfactant, corrosion inhibitor Surfactant, corrosion inhibitor Nonemulsifier, paraffin inhibitor Crosslinker, friction reducer Surfactant, foamer Surfactant, acid inhibitor Corrosion inhibitor Resin coating for proppants Gellant, breaker Crosslinker Proppant Nonemulsifier, paraffin inhibitor Biocide, dehydration Nonemulsifier, breaker

ent disease models to probe potential immune effects were used: house dust mite-induced allergic airway disease, influenza A virus infection, and experimental autoimmune encephalomyelitis. In all three disease models, developmental exposure altered frequencies of certain T cell subpopulations in female, but not male, offspring. Additionally, in the experimental autoimmune encephalomyelitis model disease, onset occurred earlier and was more severe in females. Our findings indicated that developmental exposure to this mixture had persistent immunological effects that differed between sexes, and exacerbated responses in an experimental model of autoimmune encephalitis. These observations suggested that developmental exposure to complex mixtures of water contaminants, such as those derived from unconventional oil and gas oper-

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ations, could contribute to immune dysregulation and disease later in life [105]. The above-mentioned results suggest possible adverse developmental and reproductive health outcomes in humans and animals that are exposed to potential environmentally relevant levels of oil and gas operation chemicals [104]. A series of recommendations were provided that will allow scientifically defensible, accurate assessments of the potential endocrine-related risks from chemical exposure associated with oil and natural gas operations [106]. Based on the hypothesis that exposure to oil and natural gas chemicals contributes to negative health outcomes, the following recommendations have been given to evaluate the risks posed to humans and wildlife [106]: 1. integrate endocrine-centric endpoints into human health assessments in areas of unconventional drilling operations, 2. perform biomonitoring studies for chemicals and their metabolites in humans, 3. develop an effect-directed screening approach to assess endocrinerelated effects of mixtures, 4. perform controlled laboratory animal studies of exposure to complex mixtures of oil and natural gas chemicals to assess adverse health outcomes, and 5. perform in vitro bioassays to assess receptor interactions with complex mixtures. These recommendations should lead to improved information for resource management decisions and will ultimately protect and improve human health. In a recent study, the evaluation of 48 studies that sampled air near sites of unconventional oil and gas activity identified 106 chemicals detected in two or more previous studies [107]. Ethane, benzene, and n-pentane were the top three most frequently detected chemicals. Twenty-one chemicals have been shown to have endocrine activity, including estrogenic and androgenic activity and the ability to alter steroidogenesis. The literature also suggested that some of the air pollutants may affect reproduction, development, and neurophysiological function, endpoints which can all be modulated by hormones. These chemicals included aromatics, i.e., benzene, toluene, ethylbenzene, and xylene, several polycyclic aromatic hydrocarbons, and mercury [107].

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Immunotoxicity to amphibian tadpoles

Little is known about the impacts of unconventional oil- and gas-associated contaminants on amphibian health and resistance to an emerging ranavirus infectious disease caused by viruses in the genus Ranavirus, especially at the vulnerable tadpole stage [108]. Tadpoles of the amphibian Xenopus laevis and Ranavirus frog virus 3 (FV3) were used as a model relevant to aquatic environment conservation research for investigating the immunotoxic effects of exposure to a mixture of 23 unconventional oil- and gas-associated chemicals with endocrine disrupting compound activity. Xenopus tadpoles were exposed to an equimass mixture of 23 unconventional oil- and gas-associated chemicals in a range from 0.1 to 10 µg l−1 for 3 weeks prior to infection with FV3. The data showed that the exposure to the unconventional oil and gas chemical mixture is toxic for tadpoles at ecological doses of 5 µg l−1 to 10 µg l−1 . Lower doses significantly altered homeostatic expression of myeloid lineage genes and compromised tadpole responses to FV3 through expression of TNF-α , IL-1β , and Type I IFN genes, correlating with an increase in viral load. The exposure to a subset of six unconventional oil and gas chemicals was still sufficient to perturb the antiviral gene expression response. These findings suggest that unconventional oil- and gas-associated water pollutants at low but environmentally relevant doses have the potential to induce acute alterations in antiviral immune function [108].

20.2.9 Produced water treatment Produced water is a significant waste stream that can be treated and reused [6]. However, the removal of the chemicals that are added in hydraulic fracturing must be considered. One motivation for treating and reusing produced water is that the current disposal methods that typically consist of deep-well injection and percolation in infiltration pits are limited. Furthermore, oil and gas production often occurs in arid regions where there is demand for new water sources. Hydraulic fracturing chemical additive data from California were used as a case study where physicochemical and biodegradation data were summarized and used to screen for appropriate produced water treatment technologies [6]. The results of the study indicated that hydraulic fracturing chemicals are largely treatable. Moreover, data that are missing for 24 of the 193 chemical additives were found.

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Degraded poly(acrylamide) High-molecular weight (1–30 MDa) poly(acrylamide) is commonly used as a flocculant in water and waste water treatment, as a soil conditioner, and as a viscosity modifier and friction reducer in both enhanced oil recovery and high-volume hydraulic fracturing [109]. These applications of poly(acrylamide) can result in significant environmental challenges, both in water management and in the contamination of local water supplies after accidental spills. The current applications of high-molecular weight poly(acrylamide) have been summarized, including the potential for poly(acrylamide) degradation by chemical, mechanical, thermal, photolytic, and biological processes [109]. In addition, methods for treating waste water containing partially degraded poly(acrylamide) were discussed along with issues related to the potential toxicity and mobility of poly(acrylamide) in the environment after disposal or accidental release [109].

Boron removal from waste water One promising water management strategy during hydraulic fracturing is treatment and reuse of flowback/produced water. In particular, the saline flowback water contains many of the chemicals employed for fracking, which need to be removed before a possible reuse [110]. Borate-based crosslinkers were used to adjust the rheological characteristics of a fracturing fluid. Alum and ferric chloride were evaluated as coagulants for clarification and boron removal from saline flowback water obtained from a well in the Eagle Ford Shale. Extremely high dosages of greater than 9000 mg l−1 or 333 mM Al and 160 mM Fe, corresponding to Al/B and Fe/B mass ratios of around 70 and molar ratios of around 28 and 13, respectively, were necessary to remove ca. 80% of the boron. Coagulation does not appear to be feasible for boron removal from highstrength waste streams. X-ray photoelectron spectroscopy revealed a B−O bonding on the surfaces of freshly precipitated Al(OH)3 and Fe(OH)3 . This suggested that the boron uptake occurred predominantly via ligand exchange. Attenuated total reflection–Fourier transform infrared spectroscopy provided direct evidence of an inner-sphere boron complexation with surface hydroxyl groups on both amorphous aluminum and iron hydroxides. Only trigonal boron was detected on aluminum flocs since possible presence of tetrahedral boron was masked by severe AlO interferences. Both trigonal

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and tetrahedral conformations of boron complexes were identified on the Fe(OH)3 surfaces [110].

Biological methods More than one-third of organic chemicals have data indicating biodegradability, thus suggesting that a biological treatment would be effective. Adsorption-based methods and partitioning of chemicals into oil for subsequent separation is expected to be effective for approximately one-third of chemicals. Volatilization-based treatment methods, e.g., air stripping, would only be effective for approximately 10% of the chemicals. Reverse osmosis is a good catch-all with over 70% of organic chemicals expected to be removed efficiently. Other technologies, such as electrocoagulation and advanced oxidation, are promising but are lacking experience. Chemicals of most concern due to prevalence, toxicity, and lack of data include propargyl alcohol, 2-mercaptoethyl alcohol, tetrakis hydroxymethyl-phosphonium sulfate, thioglycolic acid, 2-bromo-3-nitrilopropionamide, formaldehyde polymers, polymers of acrylic acid, quaternary ammonium compounds, and surfactants, e.g., ethoxylated alcohols [6]. The biological treatability of produced water samples from the Utica and Bakken Shales was investigated using engineered biofilms [111]. The observed total dissolved organic carbon removal varied between 1% and 87% at normalized total dissolved solid concentrations. This suggested that the composition of produced water, including organic constituents and trace elements such as nutrients and metals, is an important driver of biological treatment performance. Mass spectrometry of the dissolved organic carbon composition revealed various alkanes in all samples, but differences in nonionic surfactant, halogenated, and acidic compound content. Statistical data reduction approaches suggested that the latter two groups are correlated with reduced biodegradation kinetics. These results demonstrate that the combination of biodegradation performance and organic speciation can guide the assessment of the biological treatment of produced water [111].

Treatment by coagulation–adsorption The application of chemical coagulants and powdered activated carbon was investigated to reduce turbidity, dissolved organic carbon, total petroleum hydrocarbons, and poly(ethylene glycol)s in four hydraulic fracturing waste waters [112]. Jar tests were performed to evaluate both the powdered

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activated carbon and coagulants. Treatment goals were operationally defined targeting 90% reduction of turbidity, poly(ethylene glycol)s, and total petroleum hydrocarbons. Coagulation is a chemical process that involves neutralization of charge, whereas flocculation is a physical process and does not involve neutralization of charge [113]. The dose of the coagulant to be used can be determined via the jar test [114,115]. The jar test involves exposing samevolume samples of the water to be treated to different doses of the coagulant and then simultaneously mixing the samples at a constant short mixing time. Powdered activated carbon was found to be effective for removing both poly(ethylene glycol)s and total petroleum hydrocarbons from the waste waters, but would not settle without the addition of a coagulant. Ferric chloride achieved a 90% reduction in turbidity at a lower dose than aluminum chlorohydrate, in the presence and absence of powdered activated carbon. The optimized coagulant dose by itself had little to no effect upon concentrations of dissolved organic carbon and poly(ethylene glycol)s, while greater than 80% removal of total petroleum hydrocarbons, a minor component of dissolved organic carbon, was observed in three of the waters. Powdered activated carbon at 1000 mg l−1 achieved greater than 80% reductions of the total ion chromatogram, while dissolved organic carbon removals ranged from 9.5% to 48.3%. These results suggested that coagulation with ferric chloride at doses as low as 5 mg l−1 is an effective process for turbidity and total petroleum hydrocarbon reduction in hydraulic fracturing waste waters. When coupled with powdered activated carbon the method can also remove dissolved organic carbon and targeted organic contaminants such as poly(ethylene glycol)s [112].

Oxidation of evaporated hydraulic fracturing waste water Experiments were done to quantify the airborne emissions from 12 samples of hydraulic fracturing flowback waste water [116]. The samples were collected in the Permian Basin. Also, the photochemical processing of these emissions leading to the formation of particulate matter was assessed. The concentration of total volatile carbon, i.e., hydrocarbons evaporating at room temperature, averaged 29 mg of carbon per liter. After photochemical oxidation under high NOx conditions, the amount of organic particulate matter formed

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per milliliter of waste water evaporated averaged 24 µg. The amount of ammonium nitrate formed averaged 262 µg. Based on the mean particulate matter formation observed in these experiments, the estimated formation of particulate matter from evaporated flowback waste water in the state of Texas is in the range of estimated particulate matter emissions from diesel engines used in oil rigs. The evaporation of flowback waste water, a hitherto unrecognized source of secondary pollutants, could significantly contribute to ambient particulate matter concentrations [116].

Membranes Membrane applications and opportunities for water management in the oil and gas industry have been described. Membrane processes are key components of the reuse technology since they include some of the best available technologies. Various case studies have been described, which covered various operations such as gas fields, oilfields, oil sands, and shale plays. In these case studies, a wide spectrum of membrane processes, including membrane bioreactors, reverse osmosis, microfiltration, ultrafiltration, nanofiltration, ceramic membranes, forward osmosis, membrane distillation, pressure-retarded osmosis, membrane contactors, and/or processing involving new innovative membrane materials, were either installed at full-scale capacity, evaluated via field-/lab-testing, or investigated through desktop studies [117]. Reverse osmosis and nanofiltration are widely utilized by the industry for water desalination and desulfating, respectively. In addition, membrane filtration and bioreactors are frequently applied as standalone treatments for removal of inorganics and organics, or as pretreatment to desalination membranes [117]. A mathematical model has been proposed to address the optimal design of on-site treatment for both flowback and produced waters, combining reverse and forward osmosis, to simultaneously minimize the freshwater consumption and the specific cost of the fracturing water. The results obtained showed a clear tradeoff between both objectives and highlight the potential of the proposed technology combination to give an environmentally friendly solution to the shale gas-produced water [118]. Sustainable waste water management strategies are required to minimize the impacts of high-volume hydraulic fracturing [119]. Membranes can provide a superior effluent quality in high-volume hydraulic fracturing waste water treatment, but the application of these systems is severely

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limited by membrane fouling. However, the key fouling components in high-volume hydraulic fracturing waste water have not yet been clearly identified and characterized. Microfiltration membranes

It was demonstrated that fouling of microfiltration membranes by synthetic flowback water occurs mostly due to poly(acrylamide), which is a major additive in slickwater fracturing fluids. A synthetic fracturing fluid was incubated in the Marcellus Shale under high-volume hydraulic fracturing conditions (80◦ C, 83 bar, 24 h) to generate synthetic flowback water [119]. Different high-volume hydraulic fracturing conditions and fracturing fluid compositions generated a fouling index for flowback water ranging from 0.1 m−1 to 2000 m−1 , with these values well correlated with the peak molecular weight (ranging from 10 to 1.5 × 104 kDa) and the concentration of high-molecular weight components in the water. The lowest fouling index was observed when poly(acrylamide) was further degraded by ammonium persulfate under high-volume hydraulic fracturing conditions, although this is infrequently used with poly(acrylamide) in current fracturing operations. These results highlight the importance of poly(acrylamide) and its degradation products in fouling of subsequent membrane systems, providing insights that can help in the development of effective treatment processes for high-volume hydraulic fracturing waste water [119]. Also, it has been shown that the chemical functionalization of alumina ceramic microfiltration membranes (0.22 µm pore size) with cysteic acid creates a superhydrophilic surface [120]. This allows the separation of hydrocarbons from frac and produced waters without fouling. The single-pass rejection coefficient was >90% for all samples. The separation of hydrocarbons from water, when the former have hydrodynamic diameters smaller than the pore size of the membrane, occurs due to the zwitter ionically charged superhydrophilic pore surface. Membrane fouling is essentially eliminated, while a specific flux is obtained at a lower pressure of less than 2 bar less than that required achieving the same flux for the untreated membrane of 4–8 bar [120]. Extractive membrane bioreactor

In another study, the biodegradation of selected organic constituents present in hydraulic fracturing waste water was examined in an extractive membrane bioreactor [121,122].

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Synthetic hydraulic fracturing waste water was generated via an extensive literature review and contained high concentrations (1000 mg l−1 ) of a range of compounds of varied hydrophobicity, viz. methyl ethyl ketone, benzene, phenol, and acetic acid, as well as 30–120 g l−1 of Cl− at a low pH. This hostile waste water was circulated through the polymeric tubing, selectively transporting the organic compounds through the membrane for biological degradation by an enriched bacterial consortium [122]. 16S rDNA analysis revealed the presence of five dominant microbial strains, i.e., Pseudomonas sp., Comamonas sp., Achromobacter sp., Lysinibacillus sp., and Oxalobacter sp., within the consortium. Extractive membrane bioreactors in batch operation achieved a 99% removal of methyl ethyl ketone, benzene, and phenol after 72 h and effectively removed acetic acid up to its ionization point. The continuous reactor operation provided 99% removal of benzene and phenol, 96% removal of methyl ethyl ketone, and 53% removal of acetic acid. This demonstrated the effectiveness of carefully selected amphiphilic polymers in such reactors for treating the hydrophilic and hydrophobic organic profile found in hydraulic fracturing waste waters [122]. Desalination of shale gas waste water

Desalination technologies that allow water recycling and/or water reuse are crucial for the shale gas industry. Advances in zero-liquid discharge desalination processes for treating hypersaline shale gas waste water can play a key role in the mitigation of public health and environmental impacts, and in the improvement of overall process sustainability [123]. The most promising thermal-based and membrane-based alternatives for zero-liquid discharge desalination of shale gas waste water have been summarized in monographs [123,124].

Simulation of a waste water surface spill on agricultural soil Hydraulic fracturing waste waters contain synthetic organic components and metal ions derived from the formation waters. The risk of spills of hydraulic fracturing waste water that could impact soil quality and water resources is of great concern. The ability of synthetic components, such as surfactants, in hydraulic fracturing waste water to be transported through soil and to mobilize metals in soil was examined using column experiments [125]. A spill of hydraulic fracturing waste water was simulated in bench-scale soil column experiments that used an agricultural soil and simulated seven

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10 y rain events representing a total of one year’s worth of precipitation for Weld County, Colorado. Although no surfactants or their transformation products were found in leachate samples, copper, lead, and iron were mobilized at environmentally relevant concentrations. In general, after the initial spill event, the metal concentrations increased until the fourth rain event before decreasing. The results from this study suggest that the transport of metals can be caused by the high concentrations of salts present in hydraulic fracturing waste water. A significant decrease in the water infiltration rate of the soil was observed, leading to the point where water was unable to percolate through due to increasing salinity, potentially having a severe impact on crop production [125].

20.3 Contaminated water reclaim Systems and methods have been developed for reclaiming water containing contaminants typically associated with produced water in order to produce a treated water having a quality adequate for reuse as a fracturing water [126]. Produced water includes natural contaminants that come from the subsurface environment, such as hydrocarbons from the oil bearing or gas bearing strata and inorganic salts. The produced water may also include man-made contaminants, which may contain spent fracturing fluids including polymers and inorganic crosslinking agents, polymer breaking agents, friction reduction chemicals, and artificial lubricants. A special problem occurs when the produced water is additionally contaminated with methanol, which will pass through nearly any available membrane filtration system. A system for contaminated water reclaiming includes anaerobically digesting the contaminated water, followed by aerating the water to enhance biological digestion. After aeration, the water is separated using a flotation operation that effectively removes the spent friction reducing agents and allows the treated water to be reclaimed and reused as fracturing water [126]. In a separate branch of the unit, after a sand pack filter a series of bioreactors follows and finally a boron treatment unit. This so cleaned waster can be discharged to the environment. The typical and target values of contaminant concentrations obtained from such a system are shown in Table 20.3.

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Table 20.3 Contaminant concentrations [126]. Contaminant

Typical range /[mg ml−1 ]

Target (maximum) /[mg ml−1 ]

Total dissolved solids 180◦ C Total dissolved solids 105◦ C Total organic carbon Chemical oxygen demand Biological oxygen demand Iron Chloride Potassium Calcium Magnesium Sodium Sulfate Carbonate Bicarbonate Boron

9000–16,000 0–100 400–800 1000–3000 500–1500 1–10 5000–10,000 100–500 50–250 10–100 2000–5000 40–200 0–100 100–1200 0–20

10,000 75 700 2000 1000 5 6000 300 150 25 3000 50 25 800 15

20.3.1 Waste water from hydrofracturing Hydrofracturing can generate large amounts of waste water. The well drilling process involves injecting water, along with sand and a mixture of chemicals. The process involves pumping water into fractures at pressures exceeding 200 bar and flow rates exceeding 5 l s−1 in order to a create long fracture sand pack intersecting with natural fractures in the shale. Totally, the hydrofracturing process can use 10,000 m3 of water [127]. A method for cleaning the postdrilling flowback water from hydrofracturing has been presented. This method includes [127]: • removing the oil from the flowback water, • filtering the flowback water using an ultrafilter with a pore size of about 0.1 µm or less to remove solid particulates and large organic molecules, such as benzene, ethylbenzene, toluene, and xylene, from the water, • concentrating the flowback water to produce a brine that contains about 15–40% of salt relative to the total weight of the flowback brine, • performing one or more chemical precipitation processes using an effective amount of reagents to precipitate out the desired high-quality commercial products, such as barium sulfate, strontium carbonate, or calcium carbonate, and

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• crystallizing the chemically treated and concentrated flowback brine to

produce pure salt products, such as sodium and calcium chloride.

Downhole chemistry of glutaraldehyde Stainless steel reactors are used to simulate the downhole chemistry of the commonly used biocide glutaraldehyde in hydraulic fracturing fluids [8]. The results showed that glutaraldehyde rapidly (t1/2 < 1 h) autopolymerizes, thus forming water-soluble dimers and trimers. It eventually precipitates out at high temperatures of around 140◦ C and/or alkaline pH. It was found that salinity significantly inhibits the glutaraldehyde transformation. Pressure and shale did not affect the glutaraldehyde transformation and/or removal from the bulk fluid. On the basis of experimental pseudosecond-order rate constants, a kinetic model for glutaraldehyde downhole half-life predictions for any combination of these conditions within the limits tested was developed. These findings illustrate that the biocidal glutaraldehyde monomer has limited time to control microbial activity in hot and/or alkaline shales, and may return along with its aqueous transformation products to the surface via flowback and produced water in cooler, more acidic, and saline shales [8]. The degradation kinetics of five hydraulic fracturing compounds (2-propanol, ethylene glycol, propargyl alcohol, 2-butoxyethanol, and 2-ethylhexanol) in the absence and presence of the biocide glutaraldehyde were investigated under a range of redox conditions using sedimentgroundwater microcosms and flow-through columns [75]. Biological treatment is an important technology to remove residual organic compounds in produced water [128]. Biocides are often added to both fracturing fluids and produced water to limit an undesirable microbiological activity. Glutaraldehyde is the most commonly used biocide in hydraulic fracturing methods. Residual biocides in produced water can limit biological treatment efficiency. The effect of glutaraldehyde on the biodegradation of five of the most commonly reported organic compounds in hydraulic fracturing fluids in an engineered biofilm treatment was evaluated. The results of the study demonstrated that glutaraldehyde delays the removal of biological organic compounds by introducing a biodegradation lag phase. In addition, the effects of glutaraldehyde were more pronounced for more rapidly degraded compounds.

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The presence of glutaraldehyde did not decrease the microbial abundance nor drive microbial community structure. This suggested that observed effects were due to an altered microbial activity. These results highlight the necessity to consider cocontaminant interactions during treatment of complex waste streams where residual biocide may be present [128].

20.3.2 Phosphorus recovery in flowback fluids Phosphonate esters are used as gellants in fracturing. In the course of those operations, phosphorus may be included in the crude oil outflow. However, refinery plugging caused by volatile phosphorus components originating from phosphate ester oil gellants has been described, which is a potential risk. A maximum of 0.5 ppm volatile phosphorus in crudes has been proposed to avoid costly unplanned refinery shutdowns. This specification is based on what is considered achievable through a combination of new chemistry and typical field dilution. However, this specification is based on average concentrations of phosphorus added to the oil to gel it and assumes the oil is initially free from phosphorus. In some flowback studies, total and resulting volatile phosphorus concentrations in a great excess of that added have been observed. Potential explanations for phosphorus concentrations significantly higher than those originally added have been given [129]. An inductively coupled plasma optical emission spectroscopy-based method has been developed for the analysis of total volatile phosphorus in distillate fractions of crude oil [130]. However, this method is plagued by poor precision and a high limit of detection of 0.5 mg ml−1 . Another approach uses comprehensive two-dimensional gas chromatography with a nitrogen phosphorus detector. This method provides qualitative and quantitative profiles of alkyl phosphates in industrial petroleum samples with increased precision. A recovery study in a fracturing fluid sample and a profiling study of alkyl phosphates in four recovered fracturing fluids or flowback crude oil mixtures have been presented [130].

20.4 Green formulations 20.4.1 Biodegradable chelants Nowadays, oil companies are requesting green fracturing fluid chemistry. Commonly used demulsifiers and scale inhibitors tend to have environmental concerns and do not have a multifunctional character.

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Biodegradable and nontoxic chelant compositions can perform multiple beneficial functions in an aqueous fracturing fluid through the chelation of ions. Some of the multiple functions include various combinations of the following [131]: • demulsifier, • demulsifier enhancer, • scale inhibitor, • crosslink delay agent, • crosslinked gel stabilizer, • enzyme breaker, and • stabilizer.

20.4.2 Nontoxic flowback formulation A nontoxic, environmentally friendly, green flowback aid that reduces water blockage when injected into a fractured reservoir has been described [132]. Preparation 20–1. The flowback aid has been prepared by dissolving 15 parts of ethyl lactate in 15 parts of methyl tallate. Then, a second solution was prepared by mixing 12.5 parts of lauryl alcohol containing 6 moles of ethylene oxide with 12.5 parts of a 70% aqueous solution of sodium dodecyl sulfosuccinate. Eventually, the two solutions were combined under stirring and 55 parts of water was slowly added to form a clear low-viscosity stable solution. 

20.4.3 Crosslinking agents Group IVB metal alkoxide crosslinkers are both less flammable and environmentally more acceptable with respect to transportation and environmental concerns [133]. These products are commercially available and listed in Table 20.4. Several methods how to prepare crosslinking formulations from these compounds have been described in detail, as well as the rheological performance of the formulations and the degree of flame retardancy [133].

20.5 Self-degrading foaming composition A pH-dependent foamed fracturing fluid has been described. The fracturing fluid is made by combining a gelling agent, a surfactant, and a proppant. The surfactant is capable of facilitating foaming of the fracturing fluid at the

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Table 20.4 Environmentally friendly crosslinking agents [133]. Chemical description

Tradename

C6 alcohol zirconium alkoxide Tetrakis(2-ethylhexyl) zirconate C4 glycol zirconium alkoxide C6 alcohol titanium alkoxide Tetrakis(2-ethylhexyl) titanate C4 glycol titanium alkoxide

Vertec XL985 Vertec XL980 Vertec XL121 Vertec XL990

Figure 20.4 Protonation reaction [134].

initial pH and defoaming of the fracturing fluid when its pH is changed. The pH of the fracturing fluid changes by in situ contact with an acidic material, causing the level of foam in the fracturing fluid to be reduced. As a result of the reduction of the foam, the fracturing fluid deposits the proppant into the fractures formed in the subterranean formation [134]. The fracturing fluid may be returned to the surface for recovery. There it is refoamed by changing its pH back and again injected downhole. Both an amphoteric surfactant and an anionic surfactant may be used. A suitable surfactant is a tertiary alkyl amine ethoxylate. This compound may be converted from a foaming surfactant to a defoaming surfactant by the addition of hydrogen ions. By the addition of hydroxide the foaming property turns back. The protonation reaction is shown in Fig. 20.4. A self-degrading foaming composition has been described that is a mixture of anionic surfactant and nonionic surfactant. The fracturing fluid forms a substantially less stable foam when the foamed fracturing fluid is recovered during reclaim [135]. A preferred anionic surfactant in the self-degrading foaming composition is disodium lauramide monoethanolamine sulfosuccinamate. As nonionic surfactants, ethoxylated fatty acid esters of poly(ethylene glycol) may find use. It has been found that the foam quality degrades more quickly at a higher pH.

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Index

Acronyms

Chemicals

AA Acrylic acid, 55, 170 AAm Acrylamide, 55, 82, 129 AMPS 2-Acrylamido-2-methyl-1-propane sulfonic acid, 59, 84 CMC Carboxymethyl cellulose, 59 EDTA Ethylenediamine tetraacetic acid, 159, 211 EG Ethylene glycol, 61, 132 EO Ethylene oxide, 129 HEC Hydroxyethyl cellulose, 29, 55, 92 HPC Hydroxypropyl cellulose, 29, 107 IFT Interfacial tension, 114 MA Maleic anhydride, 119 PAA Poly(acrylic acid), 159 PAM Poly(acrylamide), 29, 81 PEG Poly(ethylene glycol), 130 PEI Poly(ether imide), 213 PO Propylene oxide, 129 PPCA Phosphino-poly(carboxylic acid), 164 PVS Poly(vinyl sulfonate), 160 VES Viscoelastic surfactant, 29, 65, 98, 214

Acetic acid, 132, 144 2-Acrylamido-2-methyl-1-propane sulfonic acid, 63 Acryloyloxyethyltrimethyl ammonium chloride, 84 Adipic acid, 144 1-Allyloxy-2-hydroxypropyl sulfonic acid, 63 Aluminum isopropoxide, 70 Amidoiminodiacetic acid, 165 N-β -(Aminoethyl)-δ -aminopropyltrimethoxysilane, 249 Aminotri(methylenephosphonic acid), 163 Ammonium persulfate, 94, 210, 215, 312 Amylose, 64 p-tert -Amylphenol, 18, 19 Arabitol, 193 Arsenazol, 48 2,2 -Azobis(2-amidinopropane)dihydrochloride, 128 2,2 -Azobis (2-amidinopropane) dihydrochloride, 128 2,2 -Azo(bis-amidinopropane)dihydrochloride, 217 Azobis(isobutyronitrile), 285 Benzene tetracarboxylic acid, 144 Benzoic acid, 144 Benzylcetyldimethyl ammonium bromide, 128 Betaine, 30 Bis-hexamethylene triamine pentakis(methylene phosphonic acid), 168 N,N-Bis(2-hydroxyethyl)glycine, 191 Bis[tetrakis(hydroxymethyl) phosphonium] sulfate, 163 Borate ions, 200, 201 furnishing, 201 2-Bromohexane, 285 2-Bromo-2-nitro-1,3-propanediol, 96 9-Bromo stearate, 153 331

332

Index

Bronopol, 229, 275 2-(2-Butoxyethoxy)-ethanol, 262 1,2-Butylene oxide, 129 Calcium peroxide, 94, 207 Carboxymethylhydroxyethyl cellulose, 29 Cellulose, 64 Cetyltrimethyl ammonium bromide, 74 Chitosan, 55 Chloromethyl propanoate, 285 Choline, 127 Citric acid, 44, 164, 192 N,N-Diallyl-N-alkyl-N-(sulfoalkyl) ammonium betaine, 163 2,2-Dibromo-3-nitrilopropionamide, 96, 229 Diethylenetriaminepenta, 200 Diethylenetriamine tetramethylene phosphonic acid, 168 Diethylentrilopentrakis(methylenephosphonic acid), 163 Dihydroxyisopropylimino-N,N-diacetic acid, 164 Diisobutyl phthalate, 285 2,5-Dimercapto-1,3,4-thiadiazole, 233 N,N-Dimethylacrylamide, 70, 72 Dimethyl amino ethyl methacrylate, 127, 128, 128 N,N-Dimethyl aminopropyl methacrylamide, 70, 72 α, α -Dimethyl-benzenemethanol, 262 Dimethyl diallyl ammonium chloride, 119, 129 4,4-Dimethyl oxazolidine, 260 N-Dodecene-1-yl-N,N-bis(2-hydroxyethyl)-N-methylammonium chloride, 217 Dodecyl benzene sulfonic acid, 108 Dodecyltriethylammonium bromide, 73 Dotriacontyl pentafluoropropionate, 262 Dulcitol, 193 Erucyl amidopropyl betaine, 66 N-Erucyl-N,N-bis(2-hydroxyethyl)-Nmethyl ammonium chloride, 66, 165 Erythritol, 193 Ethoxylated nonyl phenol, 69

Ethylenediamine tetraacetic acid, 44 2 -Ethylhexyl acrylate, 67 Formic acid, 143 Fumaric acid, 143 Furfural, 41 Furfuryl alcohol, 19 Gluconic acid, 192 Glucono-δ -lactone, 19, 44 D-Glucose, 65 D-Glucuronic acid, 65 Glutaraldehyde, 275 Glyceric acid, 192 Glycerol, 187, 193 N-Glycerylimino-N,N-diacetic acid, 164 Glycolic acid, 192 Glyoxal, 194 Guar, 60 Guar gum, 295 Hexadecyl bromide, 127, 128, 128 Hydroxyacetic acid, 96, 97, 208 Hydroxyethylenediamine tetraacetic acid, 44 Hydroxyethylethylenediaminetriacetic acid, 44 1-Hydroxyethylidene-1,1-diphosphonic acid, 163 Hydroxyethyl-tris-(hydroxypropyl) ethylenediamine, 191 N-(3-Hydroxypropyl)imino-N, 165 N-(3-Hydroxypropyl)imino-N,N-diacetic acid, 164 N-(2-Hydroxypropyl)imino-N,N-diacetic acid, 164 2-Imidazolidinethion, 233 Inositol, 193 1-Iodo-octadecane, 262 Isothiazolin, 229 4-Ketothiazolidine-2-thiol, 233 Lactic acid, 192 Lauryl betaine, 176, 176 Magnesium fluoride, 164, 195 Magnesium peroxide, 94, 207 Maleic acid, 144 Malic acid, 192 Malonic acid, 144 Mandelic acid, 192 Mannitol, 193

Index

D-Mannose, 65 Mercaptobenzimidazole, 232 2-Mercaptobenzoimidazole, 233 2-Mercaptobenzothiazole, 232, 233 2-Mercaptobenzoxazole, 233 2-Mercaptothiazoline, 233 2-Methoxyethylimino-N,N-diacetic acid, 164 3-Methoxypropylimino-N,N-diacetic acid, 164 Methylimino-N,N-diacetic acid, 164 2-Methyl oleic acid, 66 Nitrilo-triacetic acid, 44 Octadecyltrichlorosilane, 62 Octatriacontyl trifluoroacetate, 262 Oxalic acid, 144, 255–257 encapsulated, 256 p,p -Oxybis(benzenesulfonyl hydrazide), 46 Phthalimide, 97, 98, 98 Poly(dimethyl diallyl ammonium chloride), 129 Potassium 2-methyl oleate, 152 Potassium persulfate, 94 N-Pyridineoxide-2-thiol, 232 Pyridine-N-oxide-2-thiol, 233 Rhodamine-B, 110 Sodium hypochlorite, 227 Sodium persulfate, 94, 207 Sodium salicylate, 66, 98 Sorbitan monooleate, 69 Sorbitol, 193 Succinic acid, 144 Succinoglycan, 94 Sulfamic acid, 143 Tallowamidopropylamine, 98 Tartaric acid, 192 Tetrahydro-thiophene-1,1-dioxide, 262 Tetrakishydromethyl phosphonium sulfate, 229 Tetrakis(hydroxymethyl)phosphonium sulfate, 275 Tetra-n-propyl zirconate, 192 Tetra triethanolamine zirconate, 258 1,3,4-Thiadiazole-2,5-dithiol, 232 2-Thioimidazolidone, 232 p-Toluene sulfonyl hydrazide, 46 o-Tolulic acid, 144

333

Trimethyl orthoacetate, 183 Tris(1-chloro-2-propyl)phosphate, 262 Tris(hydroxymethyl)methyliminoN,N-diacetic acid, 164 N-Vinyl lactam, 59 Vinylphosphonic acid, 67 N-Vinyl-2-pyrrolidone, 67 Vinyl sulfonic acid, 67

General index Absorption surface active agent, 179 water, 135 Acid fracturing, 41 Acidizing, 41, 43, 134 Adhesive-coated material proppant, 251 Adipogenic activity, 303 Adsorption bacteria, 224, 231 polymer, 132 Aerobic biodegradation, 298 Asphaltenes stabilization, 114 Bacteria biocides, 223, 232 chemical treatment, 230 controlled degradation by, 94 detection, 223 environmental adaptation, 232 hydrocarbon-oxidizing, 231 pseudomonas elodea, 64 sessile, 230 sulfate-reducing, 223–225, 227, 230, 231 sulfidogenic, 224 xanthomonas campestris, 65 Bacteria control, 230 Bactericides doses, 224 for sulfate-reducing bacteria, 224 fracturing fluids, 230 selection of, 232 Biocides, 273 Biodegradable formulations, 68 Buckley-Leverett equations, 11 Buffer, 143 Ceramic particles, 241

334

Index

Chalcogen heterocyclic compound, 201–203 Chelate, 191 Chelating agents, 44, 116, 164–166 biodegradable, 115 interference, 160 Chemical resistance, 248 Chromatography size exclusion, 48 Clay stabilization, 119 Coacervation, 256, 257 Coating, 251 clay stabilization, 132 encapsulation, 43, 166, 209, 210 proppants, 248, 249 Coiled tubing, 58 Complexing agents, 200, 201 Condensation products hydroxyacetic acid, 208 Controlled solubility compounds, 215 Crosslinking agents, 188 boric acid, 189 polyvalent metal cations, 45, 48 Cuttings removal, 58 Cyclic voltammetry, 150 Cytoscape analysis, 271 Defoaming, 179 Demulsifier effectiveness, 114 Diffusion gas, 179, 180 pore pressure, 124 stability of shales, 125 Displacement emulsion stabilizers, 114 rock, 31 two-phase immiscible, 11 Dolomite, 41 Dynamic tension gradient, 114 Emulsifier, 46 Environmental health concerns, 260 Epoxide resin, 249 Etching, 42 Fermentation aerobic, 64 Filtration rate power law relationship, 90

Flow rate, 90 Fluid loss, 42 guars, 61 mechanism, 89, 90 Fluid loss additive, 89, 90 controlled degradable, 93 degradation, 94, 100 enzymatically degradable, 91 gellan, 64 lignosulfonate, 97 poly(hydroxyacetic acid), 96, 208 starch, 93, 94, 100 tannic-phenolic resin, 97 Foam stability, 180 Foam dilatational elasticity, 180 film thinning, 180 fracturing jobs, 35, 175 Marangoni effect, 179 stability, 179 Formation damage gas wells, 46 FracFocus, 266 Fracture conductivity, 18, 91, 188, 251 Fracturing coal-beds, 18 efficiency, 45 fluid, 255–257 fluid, hydraulic, 255–257 fluid loss, 42 iron control, 45 Friction loss, 81 Garnet type, 58 Gel breaker acid, 248 complexing agents, 43 oxidative, 48 sodium acetate, 215 Gellable polymer, 257 Gelling agent, 42, 47, 206, 210 Geochemical fingerprint, 287 Geospatial model, 277 Granules, 215 Gravel packing, 95 Groundwater contamination, 276 Grouting, 89 Heat generating system, 255

Index

Horizontal well, 58 HYDRUS model, 270 Indexing methods, 268 Inhalation exposure, 271 Interfacial tension, 114, 181 Iron complexing agents, 200 Iron control agents, 268 Kinetics of crosslinking, 187 of degradation, 206, 208 of swelling, 125 Leukemogens, 264 Mathematical models, 160, 224 Metabolism, 227 Methane leakage, 262 Micelle, 114 Microbial fuel cells, 299 Microcosms, 291 Microfiltration membranes, 312 Microflora, 230, 231 Microorganisms, 263 combating, 231 corrosion, 227 Mineral oil, 181 Mineralization, 231 Mixed metal hydroxides, 58 horizontal wells, 58 preparation, 58 thermally activated, 58

Molecularly imprinted polymer, 283 Muds biodegradable, 68 mixed metal hydroxides, 58 shale inhibition, 126 Neurodevelopmental effects, 263 Nutrients simulation, 224 water-soluble, 230 Osmosis, 124, 125 Osmotic swelling, 121 Oxygen scavenger, 199, 202 Protonation reaction, 319 Reverse osmosis, 311 Rice bran extract, 163 Risk quotient approach, 286 Scale inhibitor, 160, 161, 163, 166 encapsulated, 164 Shear viscosity, 114 Sludge, 46, 109 Surface active agents, 147 Surface tension, 179–182 Thickener, 33, 57, 59, 64, 93, 94, 100, 207, 209 UnsatChem module, 270 Waste water disposal alternatives, 283 Water softener, 200 Wax granules, 215

335