Sustainable Materials for Oil and Gas Applications 0128243805, 9780128243800

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SUSTAINABLE MATERIALS FOR OIL AND GAS APPLICATIONS

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Modern Materials and Sensors for the Oil and Gas Industry Series

SUSTAINABLE MATERIALS FOR OIL AND GAS APPLICATIONS Volume 1 Edited by

CENK TEMIZEL Saudi Aramco, Dhahran, Kingdom of Saudi Arabia

MUFRETTIN MURAT SARI Texas A&M University, Commerce, TX, United States

CELAL HAKAN CANBAZ Ege University, Izmir, Turkey

LUIGI A. SAPUTELLI Frontender Corporation, Houston TX, United States

OLE TORSÆTER Porous Media Laboratory (PoreLab), Department of Geoscience and Petroleum, Norwegian University of Science and Technology (NTNU), Trondheim, Norway

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 © 2021 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. British Library Cataloguing-in-Publication Data A catalogue record for this book is available from the British Library Library of Congress Cataloging-in-Publication Data A catalog record for this book is available from the Library of Congress ISBN: 978-0-12-824380-0 For Information on all Gulf Professional Publishing publications visit our website at https://www.elsevier.com/books-and-journals

Publisher: Joe Hayton Acquisitions Editor: Katie Hammon Editorial Project Manager: Alice Grant Production Project Manager: Sojan P. Pazhayattil Cover Designer: Miles Hitchen Typeset by MPS Limited, Chennai, India

Dedications

To my beautiful wife, Saule, for her love, inspiration, and continuous support. Cenk Temizel

To my lovely wife, Gulhan, for her valuable support and encouragement along with my academic career. . . And, to my kids, Ece, Emre, and Kaan for their patience and understanding even when I was very busy. I am truly blessed to have each of them in my life and their love and devotion made everything else possible. Mufrettin Murat Sari

My effort that went into the creation of this book is dedicated to my wife, Ezgi Canbaz who assisted me and laid the way open for maximizing my concentration, to my parents Fusun and Kaya Canbaz who gave their true love without any expectations and supported me with patience in any circumstances, and to my brother Serkan who made me feel lucky to have a honest brother like him. Celal Hakan Canbaz

For my family who provides me the energy and inspiration, all the time. Luigi A. Saputelli

Thanks for the support from PoreLab Center of Excellence and Department of Geoscience and Petroleum, Norwegian University of Science and Technology. Ole Torsæter

The Editors also would like to thank the following lead and coauthors for their valuable assistance: Alperen Sahinoglu; Adil Ozdemir; Bao Jia; Charles Bose; Dupeng Liu; Fatma Sebnem Kucuk; Hon Chung Lau; Hongsheng Wang; Javid Shiriyev; Kamil Kucuk; Luky Hendraningrat; Mohammed Jahangir; Oney Erge; Rahul Ranjith; Sai Wang; Sercan Gul; Shidong Li; Varun Rai; Vivek Singhal.

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Contents List of contributors About the authors Preface for volume 1

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1. Importance and emergence of advanced materials in energy industry

1

Fatma Sebnem Küçük, Kamil Küçük and Cenk Temizel 1.1 Introduction 1.2 Importance of advanced materials in the oil and gas industry 1.3 Importance of nanotechnology in the oil and gas industry 1.4 Challenges in the oil and gas industry and nanotechnological solutions 1.5 Outlook and future challenges 1.6 Conclusions References

2. A biophilic material in petroleum exploration and production: iodine

1 6 10 12 21 21 22

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Adil Ozdemir, Alperen Sahinoglu, Muhammed Jahangir and Cenk Temizel 2.1 2.2 2.3

Introduction Relationship between petroleum and iodine Occurrence mechanisms of iodine-rich waters and their relations with oil and gas deposits 2.4 Iodine geology in oil and gas exploration 2.5 Iodine hydrogeochemistry in reservoir evaluation and oil production 2.6 Conclusions References

3. Advanced materials and sensors in well logging, drilling, and completion operations

27 29 34 44 79 82 84

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Sercan Gul, Javid Shiriyev, Vivek Singhal, Oney Erge and Cenk Temizel 3.1 Introduction 3.2 Advanced sensors in well logging operations 3.3 Advanced sensors in drilling and well completion operations 3.4 Advanced materials in drilling and well completion operations References

93 94 98 116 119

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4. Nanoparticles for enhanced oil recovery

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Shidong Li, Hon Chung Lau, Ole TorsÌter, Luky Hendraningrat and Cenk Temizel 4.1 Introduction 4.2 Physics and chemistry of nanoparticles 4.3 Enhanced oil recovery mechanisms of nanofluid 4.4 Adsorption and transportation of nanoparticles in porous media 4.5 Health, safety and environment 4.6 Future works 4.7 Conclusions References

5. Intelligent materials in unconventional oil and gas recovery

125 129 133 156 162 167 167 169

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Bao Jia, Charles Bose, Sai Wang, Dupeng Liu, Hongsheng Wang and Cenk Temizel 5.1 Introduction 5.2 Nanocatalysis and nanofluids for heavy oil 5.3 Nanoparticles for enhanced oil recovery in shales 5.4 Materials for formation damage control 5.5 Materials to strengthen wellbore in shales 5.6 Materials to improve gas hydrate recovery References

6. State-of-the-art materials in petroleum facilities and pipelines

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Rahul Ranjith, Varun Rai and Cenk Temizel 6.1 Introduction 6.2 Advanced materials for produced water treatment in oil and gas facilities 6.3 Advanced sensing techniques for oil and gas facilities and pipelines 6.4 Nanocoatings for oil & gas facilities References Further reading Index

207 209 222 227 244 246 247

List of contributors Charles Bose Department of Chemical & Petroleum, University of Kansas, Lawrence, KS, United States Oney Erge Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, United States Sercan Gul Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, United States Luky Hendraningrat PETRONAS, Kuala Lumpur, Malaysia Muhammed Jahangir Spud Energy Pty Limited, Islamabad, Pakistan Bao Jia Department of Chemical & Petroleum, University of Kansas, Lawrence, KS, United States Fatma Sebnem Küçük Department of Geological Engineering, Cumhuriyet University, Sivas, Turkey Kamil Küçük Department of Physics & CSRRI, Illinois Institute of Technology, Chicago, IL, United States Hon Chung Lau Institute of Chemical and Engineering Sciences, Agency for Science, Technology and Research (A*STAR), Singapore, Singapore; Department of Civil and Environmental Engineering, National University of Singapore, Singapore, Singapore Shidong Li Institute of Chemical and Engineering Sciences, Agency for Science, Technology and Research (A*STAR), Singapore, Singapore Dupeng Liu Department of Chemical & Petroleum, University of Kansas, Lawrence, KS, United States Adil Ozdemir Adil Özdemir Consulting, Ankara, Turkey Varun Rai Enfinite Technologies, Houston, TX, United States Rahul Ranjith Enfinite Technologies, Houston, TX, United States Alperen Sahinoglu Graduate School of Natural and Applied Science, ˙Istanbul Esenyurt University, ˙Istanbul, Turkey

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Javid Shiriyev Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, United States Vivek Singhal Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, United States Cenk Temizel Saudi Aramco, Dhahran, Kingdom of Saudi Arabia Ole Torsæter Porous Media Laboratory (PoreLab), Department of Geoscience and Petroleum, Norwegian University of Science and Technology (NTNU), Trondheim, Norway Hongsheng Wang Department of Petroleum Engineering, University of North Dakota, Grand Forks, ND, United States Sai Wang Department of Petroleum Engineering, University of North Dakota, Grand Forks, ND, United States

About the authors

Cenk Temizel is a Sr. Reservoir Engineer with Saudi Aramco. He has around 15 years of experience in the industry working on reservoir simulation, smart fields, heavy oil, optimization, geomechanics, integrated asset modeling, unconventionals, EOR in the Middle East, the United States, and the United Kingdom. He was a teaching/ research assistant at the University of Southern California and Stanford University before joining the industry. He serves as a technical reviewer for petroleum engineering journals. His interests include reaction kinetics/dynamics of fluid flow in porous media and enhanced oil recovery processes. He served as a session chair and member of organizing committees for several SPE conferences. He has around 100 publications and patents. He holds a BS degree (Honors) from Middle East Technical University
Ankara (2003) and an MS degree (2005) from University of Southern California (USC), Los Angeles, CA, United States both in petroleum engineering. Affiliation: Saudi Aramco, Dhahran, Kingdom of Saudi Arabia Contact Details: Cenk Temizel 2855 Pinecreek Dr. A328, Costa Mesa, CA, 92626, United States Phone: 11-650-3195742 e-mail: [email protected] Mufrettin Murat Sari is a Chemistry Professor at the Department of Chemistry, Texas A&M University, Commerce, TX, United States, and Life and Health Science Department, University of North Texas at Dallas. He has 20 years of experience in the fields of Materials Chemistry, Applied Biochemistry, and Nanotechnology. His research interests are micro/nanomaterials, nanofluids, nanopharmaceuticals, modified surfaces, and their biotechnological, engineering, and environmental applications. Previously, as main academic appointments, he was a teaching assistant at Hacettepe University, researcher at Criminal Department Research Center, Ankara, Turkey, professor at Military Academy, and visiting professor at Texas A&M University, College Station. He received a PhD degree from Hacettepe University in 2005. He has around 40 scientific articles/proceedings and other publications with hundreds of citations. Also, he joined Interfacial Phenomena in Nanotechnology and Biotechnology, IPNB, Research Group at Texas A&M University for postdoctoral study in 2015 and studied Design of 2-Dimensional Next Generation Thermal Interface Nanomaterials.

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About the authors

Affiliation: Texas A&M University, Commerce, TX, United States Contact Details: Mufrettin Murat Sari, Department of Chemistry, Texas A&M University-Commerce, Commerce, TX, 75428, United States e-mail: [email protected], [email protected] Celal Hakan Canbaz is a Senior Reservoir Engineer with 16 years of experience. Previously, he had Reservoir Domain Champion position with Schlumberger in Middle East, Researcher position with The Petroleum Institute (former ADNOC Institution) and Research/Teaching Assistant position with Istanbul Technical University. He is an expert in SCAL analysis, reservoir wettability characterization, well testing analysis, perforation and testing design, multiphase flow meters, CO2/Oil/ Water interactions, wellbore flow dynamics, and PVT data interpretation. He involved more than 30 projects with Shell, BP, Chevron, ExxonMobil, and Petrochina in Middle East. He is the first place winner of several paper contests in different SPE organizations (Turkey, UAE and Oman), author/co-author of more than 30 conference/journal papers, two books, a US Patent, and technical reviewer of several energy related journals. He holds a BSc (2005) and MSc (2008) degrees in Petroleum and Natural Gas Engineering from ITU, and PhD in Energy from Ege University, Turkey. Affiliation: Ege University, Izmir, Turkey Contact Details: Celal Hakan Canbaz Geoscience and Reservoir Engineering Consultant Phone: 190 5425906970 e-mail: [email protected]

Luigi A. Saputelli is a Reservoir Engineering Expert Advisor with 30 years of experience as reservoir, drilling and production engineer in PDVSA, ADNOC, Hess and Halliburton. He is a researcher, lecturer, and active volunteer in the Society of Petroleum Engineers (SPE) where he serves as JPT editor since 2012, Production and Operations Advisory Board since 2010, founding member of Real-time Optimization Interest Group and Petroleum Data-driven Analytics technical sections. He is recipient of the 2015 SPE International Production and Operations Award.

About the authors

He has published more than 100 industry papers on digital oilfield, reservoir management, and real-time production optimization. He holds a BSc in Electronic Engineer from Universidad Simon Bolivar (1990), with a MSc in Petroleum Engineering from Imperial College (1996), and a PhD in chemical engineering from University of Houston (2003). He is also serving as managing partner in Frontender, a services firm in Houston. Affiliation: Frontender Corp., Houston, TX, United States Contact Details: Frontender Corporation, 8558 Katy Freeway Suite 103, Houston TX 77024, Phone: 11 281 217 2783 Phone: 1971 55 930 4236 e-mail: [email protected] Ole Torsæter is Professor in reservoir engineering at the Norwegian University of Science and Technology (NTNU), research associate at PoreLab a Norwegian Centre of Excellence and Adjunct Professor at the University of Oslo. He has been researcher or visiting professor with SINTEF, Phillips Petroleum, ResLab, New Mexico Tech, Texas A & M, University of Bordeaux and A*STAR, Singapore. Torsæter has supervised 220 Master- and 25 PhD-candidates, and he has published 200 research papers and the most recent are on nanofluids for EOR. Ole Torsæter has a Dr degree from NTNU with a thesis on water imbibition in chalk where he showed that the Ekofisk Field was a good candidate for water flooding. He received the Darcy Technical Achievement Award from the Society of Core Analysts (2014), Distinguished Achievement Award (2016) and Management and Information Award (2018), both from SPE. He is member of the Norwegian Academy of Science and Technology. Affiliation: Department of Geoscience and Petroleum, the Norwegian University of Science and Technology (NTNU), Trondheim, Norway Contact Details: Ole Torsæter Department of Geoscience and Petroleum, Norwegian University of Science and Technology (NTNU), S.P. Andersens v. 15 A, 7031 Trondheim, Norway Phone: 147 91897302 e-mail: [email protected]

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Preface for volume 1

Worldwide energy consumption is expected to grow by almost 50% compared to current levels by 2030. Although there is a strong and increasing demand for energy resources, discoveries of new energy fields and reservoirs are declining, and the energy industry has challenges to increase energy resources for sustainability. Oil and gas industry is facing a decline in conventional oil and gas reserves. It is estimated that there will remain trillions of barrels of oil in all oilfields in the world, even after exploitation through existing methods. It is important to increase the recovery efficiency of the reservoir where the associated technology and materials are crucial. Several chemical methods, nonhydrocarbon gas methods, and thermal methods are applied to enhance the oil recovery, but the recovery challenge remains. Therefore less expensive, more efficient, and environmentally friendly methods are strongly needed. The demand for more effective materials will increase during the production period as companies meet the challenges of more extreme conditions, where materials are required to perform effectively in these environments. The energy industry has been keen but a late adapter of new generation materials based on emerging technologies throughout the years. For instance, with the high margins of profit, the petroleum industry has been capable of adapting and utilizing the latest technologies in a wide spectrum from exploration to production. Using advanced materials and sensors in the energy branches have achieved a breakthrough and opened up a new venue in a wide variety of high-tech applications. For example, nanomaterials, smart polymers, nanofluids, nanoelectronics, quantum dots, nanosensors, nanomagnetic, ferrofluids, nanocomposites, and fiber optic sensors, surface-active nanoparticles, iron, nickel, copper, iron oxide, and copper oxide-based nanocatalysts, single and multiwall carbon tubes, fullerenes, biodegradable polymeric nanomaterials, new generation shape memory alloys, piezoelectric materials, graphene-based materials and sensors, enzyme-immobilized nanosorbents, bioderived porous carbons, functionalized nanofibrillated cellulose, and new generation biophilic materials have been used effectively in different energy fields. Although the number of researches in energy areas including such state-of-the-art materials and sensors increases rapidly and they demonstrate promising results over the last decades, their current level of use in related technology is not satisfying and far behind than expected. Also, the literature lacks a comprehensive reference where the advanced materials used in the energy branches are thoroughly covered and explained. Therefore this study aims to close this gap

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providing a strong reference by the experts in respective subjects in different energy areas recently being adopted by the industry. This volume in the Modern Materials and Sensors for the Oil and Gas Industry Book Series includes six chapters. Chapter 1, Importance and Emergence of Advanced Materials in Energy Industry, is a comprehensive introduction of the book, the importance and emergence of advanced materials and sensors with a focus on nanotechnology- and nanomaterialsbased solutions for the oil and gas industry. Besides recent developments and advances, present problems and challenges have also been discussed. Chapter 2, A Biophilic Material in Petroleum Exploration and Production: Iodine, focuses on the importance of iodine as a biophilic material petroleum for exploration and production. It includes the relationships between iodine and petroleum systems, the usage of iodine containing hydrogeochemical and pedogeochemical methods in petroleum exploration and production, case studies, and recent advances. Chapter 3, Advanced Materials and Sensors in Well Logging, Drilling, and Completion Operations, covers the use of materials and sensors in well logging, drilling and completion operations, provides a review of select, relatively advanced materials and sensors in various disciplines in well construction. It also aims to increase awareness in the industry to gain more insight into the advanced sensors and materials and to use them for safe and optimized operations. Chapter 4, Nanoparticles for Enhanced Oil Recovery, specifies the use of nanoparticles in Enhanced Oil Recovery, EOR, in detail beginning with a discussion of the potential use of nanoparticles in the upstream oil industry. Then, the unique physics and chemistry of nanoparticles, improvement of the mobility control and capillary number using them have been presented in detail. After focusing on HSE aspects of nanoparticles both in laboratory investigation and field applications, the chapter concludes with suggestions for future research. Chapter 5, Intelligent Materials in Unconventional Oil and Gas Recovery, includes a detailed review of materials containing unconventional oil and gas recovery. The authors aimed to provide the most up-to-date progress of nanomaterial applications in unconventional reservoirs, including the heavy oil reservoirs, shale reservoirs, and gas hydrate formations. Furthermore, the detailed aspects include nanocatalysis and nanofluids for heavy oil recovery and upgrading, nanoparticles’ synthetic function with surfactant in shale oil enhanced oil recovery, nanoparticles for fines migration and formation damage control, wellbore strengthening, and the preliminary progress of nanoparticle application for gas hydrate recovery have been discussed in detail. Finally, Chapter 6, State-of-the-Art Materials in Petroleum Facilities and Pipelines, covers state-of-the-art materials in petroleum facilities and pipelines. The authors discussed the latest applications aimed to solve current problems and challenges in petroleum facilities and pipelines using nanotechnology-based materials and sensors

Preface for volume 1

such as nanomembranes, magnetic nanoparticles, silane-nanoceramic coatings, carbon nanotubes, and graphene-based sensors. The book is prepared for a wide range of readers, including university students and researchers from diverse backgrounds such as: petroleum engineers, petroleum researchers, nanotech researchers in the oil and gas industry, chemical engineers, and material scientists. Numerous researchers having various backgrounds from different countries made a valuable contribution to this book. It comprises a list of processes across the upstream and downstream sectors of the industry coupled with the latest research involving advanced nanomaterials, helping engineers get up to speed on the field of nanoparticle applications in the petroleum industry. Supplied by contributing experts in both academic and corporate backgrounds, the reference contains a precise balance on developments, applications, advantages, and challenges remaining. Located in one convenient resource, “Sustainable Materials for Oil and Gas Applications” addresses real solutions as oil and gas companies continue to deliver energy needs while lowering emissions. We hope that the chapters of this volume will enable the readers with valuable insight into materials and sensors for oil and gas applications with respect to the production, design, fundamentals of architecture, and applications.

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CHAPTER ONE

Importance and emergence of advanced materials in energy industry Fatma Sebnem Küçük1, Kamil Küçük2 and Cenk Temizel3 1

Department of Geological Engineering, Cumhuriyet University, Sivas, Turkey Department of Physics & CSRRI, Illinois Institute of Technology, Chicago, IL, United States 3 Saudi Aramco, Dhahran, Kingdom of Saudi Arabia 2

1.1 Introduction Our social, technological, and political aspirations and needs have been met and also limited by advances in the development of materials and energy since ancient times [1,2]. However, energy needs and challenges in today’s fast-moving world with many advanced technologies have become greater and greater than ever seen before, with the necessities of the modern age, the rising expectations of developing nations as well as growing global communication [3]. Hence, having or accessing to cleaner, cheaper, and more reliable energy and energy sources has become a crucial issue for the wealth, lifestyle, and self-image of both every country and all people. According to the last statistical report of British Petrol (BP) written in 2017, the global energy demand is anticipated to continue to increase over the next few decades owing to the fact that the world’s energy consumption will also cascade by as much as 50% by 2040 [4,5]. In this scenario, when we look at the big picture all over the earth in terms of energy consumption, Fig. 1.1A indicates that the World’s energy consumption went up by 1.0% in 2016, well below the 10-year average of 1.8% and the third consecutive year at or below 1%. Like the case in 2015, the growth was below average in all regions except Europe and Eurasia [5]. Except for oil and nuclear power, it is reported that all other fuels also grew at below-average rates. Moreover, oil provided the biggest increase to energy consumption at 77 million tons of oil equivalent (Mtoe), followed by renewable power (53 Mtoe) and natural gas (57 Mtoe). It seems that oil still remains the dominant fuel in Africa and the Americas, whereas natural gas dominates in the Middle East and Europe and Eurasia. As for coal, it is the dominant fuel in the Asia Pacific region, accounting for 49% of regional energy consumption. Besides, in 2016, coal’s share of primary energy fell to its lowest level in our data series in Europe and Eurasia, North America, and Africa. When we look at Fig. 1.1B, Asia seems to be the leading consumer of hydroelectricity, oil, coal, and for the first Sustainable Materials for Oil and Gas Applications. DOI: https://doi.org/10.1016/B978-0-12-824380-0.00002-5

© 2021 Elsevier Inc. All rights reserved.

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Figure 1.1 (A) Energy consumption of the World in terms of different energy sources, (B) regional fuel consumption by 2016, (C) distribution of proved reserves in 1996, 2006, and 2016, (D) oil production and consumption region by region. Data from BP Statistical Review of World Energy 20171 [5].

time in 2016 [6], while the leading consumer of renewables in power generation, overtaking Europe and Eurasia countries. Additionally, Europe and Eurasia still remain the leading consumer of natural gas and nuclear power. It can also be deduced from other plots (see Fig. 1.1B and C) that Asia dominates global coal consumption, accounting for almost three-quarters of global consumption (73.8%) [5]. Fig. 1.2 exhibits that oil still remains the world’s dominant fuel which is making up roughly a third of all energy consumed. In 2016 it was reported that oil obtained global market share for the second year in a row, following 15 years of decreases from 1999 to 2014. On the other hand, coal’s market share reduced to 28.1%, which is the lowest level for it since 2004 [5]. The conquests and the challenges both in energy and in its consumption are directly associated with the global use of electricity, and the electrical technology has been exposed to many revolutions after the first primitive electricity grids were installed by Edison, Tesla, and Westinghouse in the last century [1,2]. Although the electricity has been used principally for lighting, now it has become the potent symbol of modern life and has been exclusively used for communication, entertainment, trains, refrigeration, and various industries as 1

https://www.fuelseurope.eu/wp-content/uploads/2017/06/20170704-Graphs_FUELS_EURO.

Importance and emergence of advanced materials in energy industry

Figure 1.2 Global primary energy consumption concerning energy sources. Data from BP Statistical Review of World Energy 2017 [5].

well as powering lights [1,7,8]. Even though the majority of the world has already met and been using the electricity as the most miscellaneous energy carrier since the past century, the groundbreaking research and development on advanced materials and alternative energy sources should be still carried out by material scientists who are looking forward to opening new horizons in material science for more clean, economic, and sustainable energy due to both the changes in our lives and the necessities of today’s world, in addition to existing incremental improvements. Currently, there is a tremendous effort for not only configuring carbon-based energy sources such as gasoline for engines into electric motors but also transforming from coal-fired electric power generation to clean, renewable, sustainable, solar, wind, and nuclear energy sources for electricity. For example, it has been already reported that the capacity and reliability of urban grids in New York and New Orleans which have high density and recovering areas has significantly increased. For this reason, the following new generation of advanced materials and technology should be developed in response to these advances; “battery materials for massive electrical energy storage, high-efficiency and low-cost solar cells, corrosion-resistant alloys for high-temperature power conversion, strong, lightweight composites for turbine blades, superconducting power distribution cables, advanced power handling electronics, and more” [1,7,9]. As for the transportation by air, land, or sea, it still maintains its importance and keeps up to date in today’s world due to the fact that it is always an essential part of

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our daily life. In this regard, breakthrough developments in the advanced materials and nanotechnology such as “lightweight aerospace alloys, high-temperature engine materials, and advanced composites, etc.” have been a crucial issue of improving safety, cost, energy efficiency, and capability of the vehicles used for modern transportation. When the current fossil fuel paradigm and further improvements in energy efficiency and safety is considered, it is necessary that materials research should be focused on; “Improving combustion efficiencies, Batteries for electric and hybrid vehicles, Fuel cells, Hydrogen storage, New tire compounds and manufacturing processes, Biofuel production, and more” [1,2]. Despite the current existing improvements and developments in nanotechnology and advanced materials, a significant part of the world still suffers from a lack of sufficient energy and energy sources. For instance, about 1.3 billion people currently lack electricity, and the electricity grid is insufficient in many other parts of the world [1,7]. In this perspective, innovative approaches are required to overcome this type of problem because at present we don’t have “a silver bullet” so as to meet the enormous energy needs of the developed and developing countries as well as today’s modern world, and hence considering and evaluating of the full spectrum of the energy options are so crucial [1]. In this perspective, “nanotechnology and advanced materials” has become a vogue word in the last several decades. So, it is said that their growing manufactural usage and advantages providing us to control the dimension at nanoscale (less than 100 nm) for advanced materials are one of the biggest reason of the improvements and advances in the O&G industry, in addition to many other industries and science [4,10,11]. Fig. 1.3A indicates the trend in the demand and marketing volume for advanced materials and nanotechnology which have been used in all sectors of Industry since 1990. Although some groups from both industry and academia work separately to get research grants or dollars with uncoordinated efforts that don’t provide a clear route and plan for better energy future [12] the nanotechnology has been poised to impact

Figure 1.3 (A) All sectors of industry used advanced materials and nanotechnology (Data from University of Delaware [11]), (B) research on nanotechnology and advanced materials application in the petroleum industry [3]. (Reproduced based on Ref. [2] and [11]).

Importance and emergence of advanced materials in energy industry

strikingly on all sectors of industry with respect to materials, tools, and devices since 1990, as shown in Fig. 1.3A [11]. As for the importance and urgency of advanced materials and nanotechnologic solutions in the O&G industry, it is said that “Exploration, Reservoir, Drilling, Completion, Production, and Processing & Refining” are principally known as different Petroleum disciplines which are required the use of “advanced materials and nanotechnology” [3]. The number of experimental studies on nanotechnology and the development of advanced materials related to the O&G industry has been increasing dramatically since 2011. Fig. 1.3B indicates the number of both experimental and theoretical research articles published in this field [3]. As an example, in oil and gas applications, the use of both advanced nanomaterials and nanotechnology leads to an increment in the opportunities in order to enhance geothermal resources by remedying thermal conductivity, making downhole separation better, and focusing on the development of noncorrosive materials that could be used for geothermal energy production [11]. Nanosensors which were developed for enhancing the resolution of the subsurface imaging resulting in advanced field characterization techniques can also be given as another example. Moreover, they bring many novel approaches to both improved post and preproduction processes, in a fashion similar to these. Therefore nanotechnology and advanced materials approaches have been extremely attracted attention for the stage of production so as to improve the oil recovery via molecular modification and manipulate the interfacial characteristics [10]. Although we will increasingly continue to use alternative energy sources such as nuclear and renewable energy in the next years, it is considered that (1) alternative energy sources will not take the place of hydrocarbons in the near future, (2) they will be continued to use or evaluate as supplement and complement, and (3) the increment in the use of alternative energy sources will be relatively smaller than the use of hydrocarbons [4,10]. Since the main challenge in the near future will be meeting the World’s growing energy demand, evolutionary advances in the oil and gas industry’s core science and engineering are considered as an exclusive remedy [4,5,8,9]. For this reason, the challenges need to be addressed by developing and improving existing advanced materials and nanotechnological solutions more than ever. Recent innovations and improvements both in nanotechnology and in advanced materials show their potentials in order to extend the industry across the current alternatives for energy supply by introducing these type of technologies which are more efficient and more environmentally friendly [4,13,14]. In this regard, with recent scientific research and technological developments in both areas, the distinctive physical and chemical properties of both advanced and nanomaterials such as mechanical, optical, magnetic, thermal, and electronic, etc. have been already observing and investigating at the nanolength scale [15]. Briefly, an overview of the importance and urgency of advanced materials and nanotechnology in the O&G industry will be mentioned and discussed in this chapter, in addition to the recent research developments which have been done all around the

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world and the latest nanotechnological solutions. Such advances in our science and technology, which lie from essential developments in materials and chemistry to improving manufacturing processes, is so crucial for our energy future and establishing new businesses which enhance economic prosperity [1,9,16]. Also, the main objective of this chapter created as an introduction of the book paves the way for learning and reaching valuable knowledge, which is needed for advanced materials and nanotechnology applications currently used in the O&G industry, for many students, researchers, and organizations who are interested in the integration of these technological advancements, in order to figure out the challenges and the nanotechnological revolution in the O&G Industry [10]. In this way, it is also expected that this chapter will provide examples illustrating how materials research and development make a contribution to today’s energy technologies and the challenges which are burning issues that should be solved to meet our energy needs at the soonest possible date.

1.2 Importance of advanced materials in the oil and gas industry 1.2.1 Introduction Since the exploration in the O&G industry is usually tried to carry out in the deepest waters or at greatest depths beneath the ocean floor, the development of new nanotechnologies and advanced materials as well as enhancing the properties and operation limits of existing materials is so significant. Although the O&G industry has already got a considerable knowledge taking cognizance of the performance of many conventional metallic alloys, more systematic procedures for materials selection are still need in order to improve their applications and to minimize the safety risk and environmental impact of deep and ultra-deep deployments [2]. In this section, the current challenges in the O&G industry and the most promising advanced materials, which are used in the drilling and production of oil and natural gas from ultra-deep reservoirs, will be explained in detail, in addition to emerging developments and technologies.

1.2.2 Advanced materials Recently, many multifunctional, stronger, and lighter materials, etc. have been already produced by using many different advanced techniques such as Nanotechnology, and they are well known in the technical literature and currently used in the companionable industries. In this regard, “advanced materials” can be described as one of those materials that have at least one significantly “superior property,” by comparison with the conventional alloys [2]. They are typically made either from the nonequilibrium microstructure

Importance and emergence of advanced materials in energy industry

or from the innovative chemical composition. Three types of advanced materials will be mentioned as an example here due to their importance in O&G production. 1.2.2.1 Nanocrystalline materials Reducing the grain size of the materials from the microscale to the nanoscale helps to acquire an enhancement of both strength and toughness, as shown in Fig. 1.4A [2,17,18]. For instance, the conventional metallic alloys which have usually shown grain sizes in the range of 10
100 μm or even higher for some cast materials, whereas the grain size of the nanocrystalline (NC) materials is typically changing between in the range of 10 and 100 nm [2]. A convenient “two-step bottom-up” [19] or “one-step top-down” [20] fabrication approaches are usually preferred for developing bulk nanocrystalline alloys [4]. In the former, nanoscale clusters are assembled and then converted into the bulk microstructure, while the bulk material in the microscale is reduced to the nanoscale in the latter, as given in Fig. 1.4B. Since “two-step bottom-up” method principally requires high pressure and heat treatment during the consolidation step, this step must be carefully performed to minimize the coarsening in the grain size as well as the traces of artifacts [21]; on the contrary, “one-step top-down” methods such as electrodeposition and mechanical attrition are found more useful due to enabling to get more dense and almost artifact-free NC materials [2]. 1.2.2.2 Bulk metallic glass When some desirable properties of metals and the formability of glasses are combined, bulk metallic glasses (BMG) indicates attractive properties due to their amorphous state [2].

Figure 1.4 (A) Schematically the effects of decreasing grain size on several material properties [17], optical image of coarse-grained iron specimen: (left) annealed, (middle) as cast, and (right) SEM image of NC iron deposit [18], (B) Schematic drawing to illustrate “bottom-up” and “top-down” fabrication methods of NC materials [2]. (Reproduced based on Refs. [2], [17], and [18]).

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Figure 1.5 (A) Model of a simple binary metallic glass: the blue balls represent the solvent Zr atoms centered around Pt solute atoms [22] and (B) bulk metallic glasses (BMGs) with critical casting thickness for glass formation developed in various alloy systems as a function of the year of their discovery [2,24]. (Reproduced based on Refs. [2], [22], and [24]).

In Fig. 1.5A shows the model of a simple binary metallic glass: interpenetrating quasiequivalent clusters sharing faces, edges, or vertices in the atomic packing configuration of a Zr
Pt metallic glass [22]. Duwez and his colleagues introduced “rapid melt-quenching techniques,” and they proved that certain metallic alloy melts could be solidified to the glassy state at cooling rates of 106 Ks21 and higher at the beginning of the 1960s [23]. In theory, it is said that any metallic alloy can be transformed a glassy state by extremely rapid solidification process. On the other hand, working at such fast cooling rates has a drawback which results in the producing of thin materials in minimal quantities [2]. Those multicomponent alloy systems which have been developing since the 1980s with high glass forming ability (GFA) are known as BMG, and GFA technically refers to the ability of forming larger than 1 mm thickness of material in the glassy state at relatively low cooling rate (,100 Ks21), as shown in Fig. 1.5B [2,22,24]. As for the fabrication methods of BMG’s all, it can be said that nonequilibrium processing techniques are mostly preferred to minimize the crystallization problem [2]. Schroers says in his review article published in 2010 that the most widely used methods are solidification processes necessitating direct casting and thermoplastic forming (TPF) [2,25]. In the TPF method BMG’s with high GFA is thermoplastically formed in their supercooled liquid state which is above its glass transition temperature, whereas direct casting method needs faster cooling from melting temperature to glass transition temperature by omitting crystallization [2,26]. Also, some other BMG alloy systems such as Mg-based, Zr-based, and Fe-based systems have been already studied concerning the corrosion behavior [27], and they showed great corrosion resistance and repassivation ability when the systems are exposed to the corrosive environment [2]. BMG has also been used on many different areas such as high corrosion-resistant coating, wear resistant

Importance and emergence of advanced materials in energy industry

surface of the drill head, pipes for the mass flow meter, valves and springs, strengthened edges of tools, precise miniature parts of pressure sensors, etc. in the O&G production process [2,27]. However, the primary use of BMG’s will be restrained to smaller crucial components with a high demand for the performance owing to their low impact toughness and high cost [25]. For this reason, scientists currently prefer to work on Fe-based BMG’s in order to make them more effective and cheaper [27]. 1.2.2.3 Diamond-like carbon Carbon is known as a unique element among other elements in the periodic table due to its diversity of short, medium, and long-range configurations which form it itself or with other elements. Graphite (sp2, threefold planar bonding), and diamond (sp3, in the cubic system with fourfold tetrahedral bonding), which are popular crystalline forms of carbon, have been used for a long time, as well as other carbon materials like coals that are not explicitly characterized [28] (see Fig. 1.6A). As for diamond-like carbon (DLC), it has attracted significant attention of both industrial and scientific community because of its miscellaneous electronic structure consisting of both graphite-like sp2 and diamond-like sp3 sites [30]. DLC is made up of various amorphous carbon materials incorporating a significant fraction of sp3 electron configuration in the carbon
carbon bonds, which leads to that these materials can have the similar mechanical performance of diamond (see Fig. 1.6A) [2,21,28]. Fig. 1.6B indicates the determination of the characteristics of DLC films by using the ratio of sp3 and sp2 electron configuration of bonding and hydrogen. For the most part, DLC films having low “sp3/sp2” ratios show better optical and electrical properties, comparing to the other films which have higher “sp3/sp2” ratios and exhibit better mechanical properties [30]. DLC films are also considered as a promising coating material because they can create a physical barrier in the corrosive environment due to their great chemical stability [2].

Figure 1.6 (A) Comparison of carbon
carbon bonding and structure of diamond (sp3), graphite (sp2) and DLC coating (mixed sp2/sp3) [2] (Source: wikipedia.org), (B) ternary phase diagram of C, H system showing a-C:H, ta-C and other forms of DLC fil [29]. (Reproduced based on Refs. [2] and [29]).

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There are three main reasons which make DLC films more attractive than other options, (1) they provide low deposition temperature (i.e., the room temperature is enough to coat any materials with DLC), (2) they offer an inexpensive coating process, and (3) their properties can be easily widened and tailored by deposition methods with doping different elements such as hydrogen, carbide, nitrogen (N-DLC or CNx films), fluorine (F-DLC), silicon (Si-DLC), and metals (M-DLC) [2,31]. The incorporation of these doping elements with DLC films helps to achieve further possibilities of controlling the chemistry, and ultimately the tribochemistry of the films [31]. In this regard, to produce better DLC films for enhancing thermal stability, toughness, and adhesion, scientists have already tried to modify them with “carbide doping” or “metal doping” [31,32]. In brief, since DLC has many superior features such as hardness, low friction, long-lasting, wear and corrosion resistant, their usage as a coating material in the O&G industry can be expanded to the chemical pumps or multiphase pumps, thread connections, valves, elastomer seals, the drilling tools, and so on [2].

1.3 Importance of nanotechnology in the oil and gas industry “Nano” implies as a thousand millionths (1029), with a nanometer equaling a millionth of a millimeter [11,13,33]. In other words, one nanometer (1 nm 5 1 3 1029 m) can be equated as the width of 10 Hydrogen atoms approximately, when the atomic radius of one hydrogen atom is considered as 53 pm (1 pm 5 1 3 10212 m). To classify the materials either as a simple nanomaterial or an advanced nanomaterial, they must be sized at the nanoscale. For instance, a nanosized material is physically defined by having a dimension which is thousand millionths of a meter [33]. In the literature, the term “nanotechnology” is usually used to refer to the art and science of building new functional materials at the nanoscale. Specifically, in 2006 Mokhatab et al., define that “the nanotechnology is a technique to manipulate or create matter at the molecular level which makes it possible to produce materials with enhanced and improved properties (or, more accurately, altered), such as being greater capabilities in heat and electrical conductivity, being lightweight, and having ultrahigh strength” [11]. Accordingly, the main objective of the nanoscientist who is interesting in nanotechnology is to build or develop new structures and substances by imprinting molecules and atoms on this scale. They also mentioned in their study that “top-down nanofabrication,” which involves working with bulk materials and reducing them to the nanoscale, is the most common approach currently used in the development of new technologies, especially in the O&G industry [11]. Nanotechnology is so sensational and keeps itself up-to-date owing to the fact that the science and engineering behind it still remain a mystery. There was not a real attempt toward the use of nanoparticles until the production of carbon black in the early 20th

Importance and emergence of advanced materials in energy industry

Figure 1.7 (A) Multiwalled carbon-nanotube, (source: www.nanotech-now.com) [10] and (B) atomic structure of carbon nanotubes [11]. (Reproduced based on Refs. [10] and [11]).

century and fumed silica in the 1940s following it [34]. In this regard, the discovery of “buckminsterfullerene (C60) (see Fig. 1.7)” by Kroto et al. in 1985 [35] and helical microtubules of graphitic carbon known as “carbon nanotubes” by Lijima, in 1991 [36,37] paved the way for the development of nanomaterials and enabled scientists to explore the use of these materials more solicitously [34]. As a matter of fact, it is said by Islam in his hypothesis that “the physical and chemical laws directly associated with the materials at the nanoscale are at odds with those that have been widely used and accepted in larger scales” [11,38]. This hypothesis was also supported by a study carried out by chemist and physicist Richard Errett Smalley from Rice University who was awarded the Nobel Prize in Chemistry in 1996, “for the discovery of a new form of carbon C60,” also known as buckyballs.2 His studies showed that carbon nanotubes (see Fig. 1.7) and fullerenes (buckyballs), nanoparticles of carbon characterized as graphite in the literature were out of step with graphite [11,39]. In this perspective, advancements in the nanotechnology are so significant because they can enable us to develop enhanced materials and devices with features and characteristics, which cannot be achieved by using conventional methods and techniques [4]. Current demands and needs of all sectors of industry for having this type of advanced technological devices and tools keep the nanotechnology up-to-date and alive [11]. Although the current challenges facing by the O&G industry and the nanotechnological solutions to address them will be mentioned in Section 1.4 in detail, several examples which also show the importance and urgency of nanotechnology and nanomaterials specifically used in the petroleum and natural gas industry is worth saying here. In this 2

https://en.wikipedia.org/wiki/Richard_Smalley.

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regard, the first example is that nanotechnology and nanomaterials allow us to develop new resources by improving downhole separation and enhancing thermal conductivity [13,16]. “Nanoscale metals” which are used to delineate ore deposits for geochemical exploration can be given as the second example [13]. The third example is that nanotechnology can be used to develop new metering techniques by using nanosensors in order to provide more detailed information about the reservoir [4]. The fourth example is that other emerging applications and methods of nanotechnology in the O&G industry are “smart fluids” which are used to improve oil recovery and drilling process [4,11,13,40]. The final one is “nanocatalysts,” they are also delivering a remedy for onsite upgrading of heavy crude oil and bitumen [41,42]. We tried to explain the importance and urgency of both advanced materials and nanotechnology in the O&G industry by giving many different examples in a lot of ways till now. In the following sections, the challenges currently encountered in the O&G industry and the nanotechnological solutions getting over them will be mentioned, and then, an outlook and future challenges will be pointed out as well as future trends of advanced materials and nanotechnology applications in the O&G industry [4].

1.4 Challenges in the oil and gas industry and nanotechnological solutions The O&G industry is currently suffering both from many major and from minor challenges varying from upstream, midstream to downstream [43] (see Fig. 1.8), which should be overcome with the long-term and short-term applications and solutions with respect to nanotechnology, advanced materials, and safe environmental operations. These challenges and nanotechnological solutions, which were summarized by Kong and Ohadi in their paper (Table 1.1), in 2011, have indicated the importance and urgency of the revolutionary solutions in the O&G industry [4].

Figure 1.8 Well-to-consumer supply chain for petroleum products, from upstream, midstream to downstream [43]. (Reproduced based on the Ref. [43]).

Table 1.1 Recent needs and challenges in the O&G industry and nanotechnology solutions [4]. (Reproduced based on the Ref. [4]). Area

Industry needs

Nanotech solutions

Exploration

Less invasive methods of exploration, remote sensing Methods to “sniff” for new pockets of oil Enhanced resolution for subsurface imaging and computational techniques Improved temperature and pressure in deep wells and hostile environments Improved instrumentation for gas adsorption Improved 1, 2, 3, and 4-D seismic resolution Enhanced remote imaging, real-time continues monitoring of flow-rate, pressure, and other parameters during production, wireless telemetry, in-situ chemical sensing Accurate early warning detection and location of leaks (preventing environmental hazards) Improved reservoir illumination and characterization, including improved signal-to-noise ratio of subsalt events, improved velocity-modeling accounting for anisotropy Improved sand exclusion and mobility of injectant Controlled agglomeration of particles Ability to capture and store CO2 Improved stability and pressure integrity and heat transfer efficiency Ability to minimize damage to the formation of offshore platforms, reduce their weight requirements, and increase their sturdiness Increased effectiveness and longevity of drilling components, making cheaper, lighter, and stronger pipes and drill bits Extended lifetime of equipment with corrosion resistance, adhesion enhancement, and wear resistance The improved strength-to-weight ratio for an expanding range of geological settings Expandable tubulars for deeper wells without needing to telescope the well, or casingless wells Improved cement integrity—light density and high strength, hole quality, and well placement, hermetic seals Innovative drill engines that can be sent deep into the shaft; improved elastomers Ability to prevent biofouling

Nanosensors and Imaging

Improved drilling fluids and thermal conductivity Removal of toxic metals (mercury, cadmium, lead) Ability to prevent drilling mud invasion, separating mud filtrate, and formation water

Nanofluids and nanomembranes

Reservoir management

Drilling

Nanosensors

Nanomembranes

Nanomaterials, fluids, and coatings Nanomaterials and coatings

(continued)

Table 1.1 (Continued) Area

Industry needs

Nanotech solutions

Production

In-situ sensing and control, monitoring of stresses in real-time Ability to direct fracturing and withstand high temperatures to go deep into challenging resources of wellbore deep reading of oil
water interface chemical detection with no active components downhole Enhanced measurements in the borehole (pressure, temperature, composition, conductivity) Accurate detection and location of leaks (pipeline, downhole) Improved understanding of matrix, fracture, fluid properties, and production-related changes Increased wear resistance Self-healing materials Pressure integrity, improved robustness Enhanced hydrophobic or hydrophilic behavior for water flood applications Improved water filtration (for industrial, agricultural, and portable use) Filtration of impurities from heavy oil and tight gas Desulfurization, inhibiting H2S producing bacteria Cost-effective CO2 sequestration Sand exclusion Effective water-shutoff Scale/wax removal Easy separation of oil/water emulsion on the surface High-strength/lightweight proppants Environmentally friendly fluids Enhanced oil recovery: enhanced fluid viscosity and molecular modification Improved production rates and water disposition Reversible/reusable swellable Ability to manipulate the interfacial characteristics of the rock
fluids relationship Reversible and controllable making and breaking of emulsion or foam Improved combustion and enhanced prevention of fouling and corrosion

Nanosensors

Increased refining capacity and speed. Better insulation and separation materials. Efficient conversion of hydrocarbons and refining efficiency (including extra heavy and sour crude oils) into clean transportation fuels Improved monitoring during oil refining

Nanomembranes and nanocatalysts

Refining and processing

Nanomaterials and coatings

Nanomembranes

Nanofluids

Nanosensors

Importance and emergence of advanced materials in energy industry

In recent several decades, some of these challenges have been already solved with improvements and technical developments both in nanotechnology and in advanced materials, but many of them are still waiting as an open question [10,11,13]. In this perspective, it will be mentioned both what the needs are and what the solutions required usage of advanced and nanomaterials are, in addition to the recent progress related to research and development in the areas which are more critical for the O&G industry and considered as priority targets.

1.4.1 Exploration Nowadays, it is known that oil and gas demand is continuously increasing more and more due to growth in energy consumption corresponding with the needs of the globalizing world [5]; on the contrary, recoverable oil and gas reserves or resources are decreasing. In this aspect, to have better field characterization techniques and processes that are resulting in enhanced oil recovery (EOR) is of vital importance evermore [4]. Since the recent years have brought many groundbreaking developments in O&G exploration in all around the world, recoverable oil and gas reserves have been jumped up from 614.0 3 108 t to 39.9 3 1012 m3 from 2001 to 2011, respectively [5,44]. The proved O&G reserves in China also increased from 112.2 3 108 t and 5.8 3 1012 m3 can be given as another example in the same time period [44]. According to geoscientists working in the O&G industry, more reservoirs can be reached, and eventually, more oil and gas can be extracted with a better understanding of the chemical and physical properties of existing reservoirs. Similarly, the recent estimations and statistics which were well done by the US Department of Energy (DOE) and other sources also show that about 67% of all US oil remains in place and we need advanced materials and nanotechnological solutions to recover it [4,45]. Since conventional sensing technologies can be used or operated in only a few inches from the wellbore, except “seismic techniques,” they should be improved or exchanged with new technologies in order to get more information in detail. If we look at today’s existing state of the art technologies, they still deprive of the better resolution and/or the ability to deeper penetration level [10]. Conventional electrical sensors and other measuring tools should also be more reliable and provide accurate information for working in harsh environmental conditions such as high pressure and high temperature [21,45]. Although the use of 4D seismic surveys, that is well known as the process of repeating a series of 3D seismic surveys over a producing reservoir in time-lapse mode, has been commonly using and has already shown a significant impact in reservoir management [46], “sophisticated modeling and simulation techniques,” “advanced downhole electrical methods,” and “sensitive electromagnetic imaging methods,” are still needed for the O&G industry in order to enhance in-depth understanding of the reservoirs [4,11,47]. Accuracy in the detection and characterization of the remaining O&G in

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the reservoirs (billions of barrels of potentially available supply in many cases, especially in the oil-reach areas of the world) is so crucial due to the fact that small improvements in the EOR factors come to mean “billions of dollars in extra revenues” [4]. Advances in sensor technology are needed to make a further thought or an investigation on the properties of oil and gas reservoirs. These advances would make possible to figure out the complex nature of the rock and fluid interactions, in addition to laying a scheme on better exploitation plans for detected oil and gas [4]. In addition to these, they would also allow us to operate sensors at much higher temperatures and pressures in deep wells and hostile environments [4,8,48]. Moreover, the advances and enhancements in imaging, monitoring, and computational techniques should also be improved so as to have a better exploration (discovery), sizing and characterization of oil and gas reservoirs [4,8]. The tightest passages in typical oil-bearing sandstones (ranging from 1 to 15 μm) and injection of custom-designed nanoparticles and nanosensors (ranging from 1 to 100 nm) has attracted petroleum geologists’ attention [10,34]. In this perspective, the Advanced Energy Consortium was constituted in close connection with major oil companies, such as Shell, Schlumberger, BP, Total, and ConocoPhillips in order to discuss and figure out the potential of “nanotechnology and nanosensors” in the United States, in 20083 [45]. The consortium’s primary goal is defined in their website as “to develop intelligent subsurface micro- and nano-sensors which can be injected into O&G reservoirs to improve the recovery of new and existing hydrocarbon resources and enable the characterization of the space in 3D” [4]. Nanoparticles, providing many useful and flexible varieties in terms of optical, magnetic, and electrical properties compared to their bulk counterparts, are considered as excellent candidates in order to develop sensors and to form imaging contrast agents [15]. As a novel tool for measuring and imaging in oil exploration, hyperpolarized silicon nanoparticles are useful [4,40,49]. Briefly, it can be clearly said that both nanotechnology and advanced materials have shown their potentials on enhancing the exploration of geothermal resources by improving nano-based materials concerning needed physical and chemical properties.

1.4.2 Drilling and production Since conveniently accessible reserves have been on the point of exhausting, the oil and gas exploration and production (E&P) industry encounters increasing technical challenges because of changes in the length of horizontal departure to maximize production, the nature of subsurface geohazards with increasing depth, the complexity of drilling operations, the operational depth, and the shape of wellbore profiles or number of laterals from a mother bore to maximize reservoir contact [33]. These technical challenges restrict the operation capabilities of drilling and production technologies and result in an 3

http://www.beg.utexas.edu/aec.

Importance and emergence of advanced materials in energy industry

increment in the cost [42]. Additionally, The O&G industry is also suffering from the materials-related challenges owing to many critical changes in the physical, chemical, and thermal conditions of deeper horizons, along with increasingly strict environmental regulations [4,33]. At present, the O&G industry like many other types of industries needs mechanically more strong, physically smaller, chemically and thermally more stable, biologically degradable, eco-friendly chemicals, polymers, or natural products for designing smart fluids that will be used in drilling and production [34]. Approximately 45% of future hydrocarbon recovery will be obtained from offshore reserves, according to the forecasting study conducted and reported by Amanullah and Ashraf [33]. The exploitation and exploration of deep-water hydrocarbon reserves or resources are technically bound up with a set of drilling hazards which are not normally faced in onshore or shallow-water conditions [44,50]. The conventional drilling and stimulation fluids have shown poor performance on account of the changes in operating conditions such as operational depth or a shift from vertical to horizontal. The conventional or standard macro and micro material-based drilling, drill-in, completion, stimulation fluids have brought limited solutions to these drilling and production challenges because of both size and concentration effect of the materials along with the constrained functional ability of macro and microparticles [33]. Besides, lightweight, rugged, and improved structural materials for various applications, such as weight reduction of offshore platforms, energy-efficient transportation vessels, and better-performing drilling parts are also needed in the drilling industry [15]. Scale formation and the untimely deposition of heavy organics (asphaltenes, asphalts, bitumens, resins, diamondoids, and wax) which is present in petroleum and petroleum-derived fluids are known as one of the main complex problems facing oil production [40,51]. These problems and drawbacks lead to a significant market opportunity for nanotechnological solutions requiring the use of advanced materials, which can specifically deal with corrosive impurities, high temperature, and high-pressure conditions, as well as shock loads, abrasion, and other hostile environmental conditions. If drilling equipment and platforms are made up of or coated with nanomaterials, their corrosion resistance, wear resistance, shock-resistance, and thermal conductivity can be improved and enhanced [4,45]. For instance, nanoparticles, particularly nano-SiO2 and nano-Fe2O3 have been widely used to enhance both flexural and compressive strengths of Belite and Portland cement [52,53]. In addition to these, the study related to the self-monitoring capability of cement mortar by using nano-Fe2O3 has been conducted by Li et al. [54]. Because of the unique characteristics and interaction potential of nanomaterials, by comparison with their pristine or baseline materials, it is considered that they have become a promising candidate in order to design a “smart fluid” for oil and gas field applications [13,16,33]. In this regard, since advances in nanotechnology and material science have been enhanced and become more important so far, they should offer an insight into the development of a new generation of fluids called as “smart fluids” for drilling, production, and stimulation-related applications in the O&G industry owing to

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the scope of manufacturing of tailored nanoparticles with custom-made functional behaviors, ionic natures, physical shapes and sizes, charge densities, and unit volumes [4,11,15]. Therefore such “smart fluids” will undoubtfully help us to enhance drilling by bringing many benefits into the operation process, such as wettability alteration, advanced drag reduction, and binders for sand consolidation [55,56]. By using such nanofluids can also help to minimize the damage to the reservoir rock in the well, which makes it possible to extract more oil [16]. As another example stating the advantages and benefits of the use of nanomaterials in the O&G industry, it can be given that the asphaltene adsorption capacity onto nickel microparticles has demonstrated some incontrovertible or certain drawbacks by comparison with nickel nanoparticles, when they have been used to remove asphaltenes from heavy oil model solutions by adsorption [57].

1.4.3 Enhanced oil recovery It is said that there are two main ways to meet the fast growth of worldwide oil and gas demand effectively: (1) new hydrocarbon resources should be discovered, and (2) the oil and gas recovery of present reservoirs should be enhanced [10]. Unfortunately, the statistical studies show that there is a vast decreasing at the rate of new oilfield discoveries and most of the existing active oil fields are in their late stages of production [44]. The use of EOR methods, which are classified into five main categories: gasbased, water-based, thermal, others, and combination technologies [58], is essential to increase the oil production of oil fields because in many of the world’s reservoirs about two thirds of the oil in place cannot be recovered by conventional production methods [4,59]. Here, we will take a look at these methods in three major categories; (1) thermal recovery, (2) gas injection, and (3) chemical injection, which are found to be more successful in terms of commercial aims [4]. The first method is “thermal recovery” which is important for recovering viscous oils from subterranean formations, and specifically, it is considered as an improved steam flooding method for recovering such oils. A thermal oil recovery process is described in which steam is injected into a heavy oil-bearing formation through a horizontally drilled injection well and oil is produced through a horizontal production well parallel to the injection well [48]. The introduction of heat such as the injection of steam is to decrease the viscosity of the heavy viscous oil and to increase its ability to flow through the reservoir [4,44,60]. The second method is “gas injection” that uses gases such as natural gas, nitrogen, or carbon dioxide which expand in a reservoir to push additional oil to a production wellbore, or some other gases which are enable to dissolve in the oil to make its viscosity lower and improve its flow rate [13,60]. As for the final method, it is “chemical injection” that needs the use of long-chained molecules, called polymers so as to improve the effectiveness of water flood or the use of detergent-like surfactants in order to help lower the surface tension which often prevents oil droplets from moving through a reservoir [50,60].

Importance and emergence of advanced materials in energy industry

On the other hand, each of these techniques is suffering from some main drawbacks resulting from their high costs or, in some cases, low oil recovery [4,60]. Chemical EOR processes such as polymer flooding, alkaline injection, and surfactant flooding or their combinations are also suffering from the high cost of the injectants, potential corrosion of the formation, and injectant loss during the flow-through reservoir, in commercial operations. For all these reasons, the O&G industry still requires low-mobility and costeffective injectants [4,60,61]. Nanotechnology and nanotechnological solutions that require using of advanced and nanomaterials are offering a way to control oil recovery processes which are matched by neither current nor previous technology [48,58]. If we are talking about the viscosity of a fluid injected to displace oil, such as water, CO2 or surfactant solution, it is expected that it’s viscosity is typically lower than the viscosity of the oil [8]. In this context, adding nanoparticles can regulate the viscosity of the injected fluid to an optimum level with net effect of improving both the mobility, and attendantly the oil recovery efficiency, because many research activities have already indicated that the properties of the base fluid such as thermal conductivity, density, viscosity, and specific heat can be improved by adding the nanoparticles. For example, the studies have shown that the viscosity of CO2 combined with a small amount of dispersant and 1% CuO nanoparticles is over 140 times greater than conventional CO2 [4,61,62]. In the light of these studies, it is said that the higher sweep efficiency and desired mobility ratio resulting in a much higher oil recovery can be achieved by dispersing such nanoparticles into the driving CO2 fluids [45]. In 2008 ConocoPhillips and the University of Kansas announced a 3-year collaborative nanotechnology research program which will focus on the testing and development of new technologies for oilfield stimulation to enhance recovery to help meet growing energy demand. The primary goal of this collaboration was to create novel polymer-type nanoparticles which can be incorporated with EOR injection fluids to make hydrocarbon recovery from reservoirs much better with more efficient and environmentally favorable ways and to conduct initial screening and testing [63,64]. Emulsification described as a process which forms a liquid, known as an emulsion, containing tiny droplets of fat or oil suspended in a fluid, usually water, is another way to increase viscosity [14,65]. However, many current methods to stabilize emulsions are still so expensive and poorly suited to large-scale applications; in this aspect, the use of surface-modified nanoparticles for their stabilization can help to solve these problems [4,66]. If emulsions can be stabilized by using nanoparticles, then they can make a stand against the high-temperature reservoir conditions for extended periods [67]. Emerging nanoemulsions such as water-in-oil (W/O) and oil-in-water (O/W) have also attracted considerable attention for applications in the O&G industry since the last two decades [68
70]. They have made a significant contribution to enhancing of the potential capability for EOR because of their characteristics such as having

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good injectivity with droplets ranging between 1 and 200 nm, penetration without filtration, being more stable over time, resisting to coalescence and exchanging of the dispersed phase between droplets [4,68]. These emulsions made up of nanoparticles have also provided many revolutionary advantages such as forming a compact layer of nanoparticles at the droplets’ interface, demonstrating potential to deal with the limitations encountered with emulsion stabilized by colloidal solids or surfactants, and using as a good approach for CO2 sequestration, as they can be operated consistently under reservoir conditions [4].

1.4.4 Refining and processing What some operational problems that oil refineries are currently facing can be counted as political problems, feedstock supply, the sale of products, operational risk, health safety and environment (HSE), human capital management, technology upgrade, equipment depreciation, quality control, etc. However, limiting sulfur and CO2 emissions to stabilize atmospheric CO2 and limit global warming are known as main challenges which the refining and processing industry should be overcome first [4]. In addition to these, the growing expectation and demand for cleaner fuels and quality feedstock can be said as another challenge [4,5,43]. Oil and gas refineries must produce higher yields in addition to consuming fewer resources (such as steel, energy, and CO2) [5,9]. Another major challenge in the refining and processing industry is impurities such as heavy yields and side products in crude oil [71,72]. Enhancements and improvements both in nanotechnology and advanced materials (since the early 1990s) have made an enormous contribution to refining and converting fossil fuels [4]. The development of mesoporous catalysts such as MCM-41 (Mobil Composition of Matter), which is the primary representative of the M41S group of mesoporous molecular sieves, whose characteristic features are huge sizes of pores (channels) and large parameters of elementary cells [73
75], have a significant impact on the improvement of downstream refining [15,45]. The development of nanofilters and materials is also so important in taking away of harmful toxic substances such as mercury from soil and water, nitrogen oxides, and related acids and acid anhydrides from vapor, sulfur oxides, with exact precision. This type of developments in nanotechnology is opening new doors into the development of a new generation of nanomembranes specifically for improved removal of impurities from oil and separation of gas streams, as well as bringing a matter to a solution to carbon capture and long-term storage [4,45]. Nanotechnological solutions and advances in the material science are also significant in terms of working toward a solution for carbon capture and longterm storage [10], as well as making a contributions to the development of a new generation of nanomembranes for enhanced separation of gas streams and removal of impurities from oil [45,76].

Importance and emergence of advanced materials in energy industry

The upgrading of heavy crude oil and bitumen is known as another significant challenge which is addressed to the Vapex (vapor extraction) process considered a beneficial method for the recovery of highly viscous heavy oil and bitumen [77]. To transport these chemicals to the locations where they can be configured into valuable products is so hard owing to their high density and viscosity [71,77]. For this reason, nanocatalysts are considered as an excellent candidate to overcome the difficulties of on-site upgrading of bitumen and heavy crude oil [41]. For the development of the processes and specifically designed nanocatalysts for on-site field upgrading combined with hydrogen/methane production, more significant resources should be allocated, and intense research activities should be carried out [4,16].

1.5 Outlook and future challenges Since many developments and advances on nanomaterials have been carrying out in laboratory conditions, many serious challenges and problems are still waiting for revolutionary solutions and breakthroughs in field implementation for oil production in complex and challenging underground environments [11]. Before nanomaterial-based materials developed and produced in the research laboratories of the O&G industry can be transferred into practice, there are also many difficulties waiting for urgent remedies, such as the lean production and making industrialization of nanomaterials easier [4,44]. Some of the barriers that may decelerate the execution of future advances and improvements in nanosystems for the O&G sector was also worded by Xiangling Kong, in 2010, as follows; (1) Lack of strong support for innovation in the E&P sector, (2) barriers to entry and adoption, (3) perceived cost and risk, (4) lack of awareness [4,16]. As long as the current interest in nanotechnologies and advanced materials in the O&G industry is increasingly continuing, many solutions and improvements can be created to overcome the difficulties that have been noted above. As soon as these solutions are generated and the related technologies are successfully developed, “nanotechnologies and advanced materials” can be extensively used in the field applications of the O&G industry [4,11,45].

1.6 Conclusions Due to the fact that the use of nanomaterials has been making a huge contribution to technological advances in a number of industries, advanced materials, and nanotechnologies still have promising potential to bring revolutionary changes in many different areas of the O&G industry, such as exploration, drilling, production, EOR, and refining, as already mention above.

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In short, there are still numerous areas that nanotechnology can make a considerable contribution for more influential, much cheaper, and more eco-friendly technologies [45]. This book provides an overview of advanced materials used in the O&G industry, with a particular focus on nanotechnological solutions corresponding with the industry’s needs. In this perspective, recent research and technical & experimental developments were briefly reviewed, in addition to the potential opportunities and challenges that encounter future trends of nanotechnology applications in the O&G industry were also discussed.

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CHAPTER TWO

A biophilic material in petroleum exploration and production: iodine Adil Ozdemir1, Alperen Sahinoglu2, Muhammed Jahangir3 and Cenk Temizel4 1

Adil Özdemir Consulting, Ankara, Turkey Graduate School of Natural and Applied Science, ˙Istanbul Esenyurt University, ˙Istanbul, Turkey 3 Spud Energy Pty Limited, Islamabad, Pakistan 4 Saudi Aramco, Dhahran, Kingdom of Saudi Arabia 2

2.1 Introduction Iodine has been detected in some of the oilfield brines, and iodine has been determined quantitatively in one sample and found to amount to 29 ppm in the SunsetMidway oilfield (United States). In 1894 in one of the old Jewett and Blodgett wells in the Sunset field, 19.8 ppm of iodine in water was reported. Also, it has been stated waters from several other wells gave a “strong reaction” to iodine [1]. It was identified in 1910 that all the waters in the Romanian oilfields contained high amounts of iodine and that the iodine content in waters in nonoil-bearing regions was very low or nil [2]. Therefore the presence of iodine in the water was been evaluated as an direct indicator of the presence of oil. Iodine content of fossil seawater released during the burial of petroliferous sediments is higher than normal seawater; thus it identified that as the cause of a local high iodine concentration in the basin of high iodine content oilfield waters [3]. Exploration in the petroliferous Pannonian basin containing the giant Algyo gasfield was triggered by the Hajduszoboszlo-1 well drilled as a first partly successful wildcat well in 1924
1925 years. The well has produced hot (73 C), iodine-rich water at a rate of 1600 L/minute and methane gas at a rate of 3700 m3/day from a depth of 1090 m. The iodine-rich waters eventually turned Hajduszoboszlo into a health spa and the methane gas has been used locally to generate electricity [4]. It has been stated that a vast amount of iodine found in waters is originates from petroleum, and, iodine is a direct hydrogeochemical indicator for petroleum [5]. Many studies have proven the relationship between petroleum and iodine-rich waters in hydrocarbon production basins [2,6
18]. Iodine has been used to discover an oil or gasfield in many studies [13,19
34]. The relationship between petroleum and iodine in formation waters of 243 production wells in 52 oilfields which have different geological structures in the Southeastern Anatolia and Thrace Basins (Turkey) has been examined (accounting for more than 95% of oil and Sustainable Materials for Oil and Gas Applications. DOI: https://doi.org/10.1016/B978-0-12-824380-0.00006-2

© 2021 Elsevier Inc. All rights reserved.

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gas production of Turkey). It has been stated that the all of oil reservoir waters in the Southeastern Anatolia and Thrace basins are not saline. However, all of them are rich in iodine like in other oil- and gas-production fields/basins of the world. It has been stated that the iodine content of reservoir waters and oilfield reserves (petroleum saturation) is high in the basin with source rocks containing high organic matter (kerogen). In this case, the water saturation of the production wells will decrease. Also, it has been stated that the iodine-rich waters are a direct indicator determining the potential producible oil reservoirs (containing mature hydrocarbons) in the Southeastern Anatolia is a direct indicator [18]. Iodine, which was discovered by Courtois in 1811 by extracting it from seaweed ash, is scarcely found on the Earth’s crust. 99.6 % of which is composed of 32 main elements. The remaining 0.4 % shared among 64 trace elements. Ranking 61 among these 64 elements in abundance, iodine is one of scarcest nonmetal elements within the composition of Earth’s crust [35]. It is a halogen with the symbol I, atomic number 53, atomic mass 126.92, density 4.93 gr/cm3 and valency 21, 11, 13, 15, 17. A special book on iodine chemistry and applications has been published [36]. In seawater, there is 0.05 ppm iodide ion concentration. The behaviors of iodine significantly differ from that of chlorine, since it has the most biophilic features among the halogens. The most significant reservoir of chlorine in the world is seawater, whereas the source of iodine is marine sediments [37]. Organic-rich sediments or their volatile derivatives (hydrocarbons) are primary sources of iodine in sedimentary basins. Iodine enrichment in waters increases with proximity to petroleum reservoirs and depth of burial [38,39]. Salt lakes either contain a little iodine or no iodine [38]. Iodine-rich waters have been classified in two groups: (1) gaseous or petroliferous iodine-rich waters in oil and gas fields, (2) iodine-rich waters with dry gas (dissolved natural gas) (Fig. 2.1) [40]. In recent years, many studies have been made on the relations between iodine and oil and gas deposits in detail [e.g., 16
18,33].

Figure 2.1 Environments where iodine is present [41,42].

A biophilic material in petroleum exploration and production: iodine

2.2 Relationship between petroleum and iodine 2.2.1 Relationships between iodine, organic matter, and organic carbon Iodine enrichment is a precise indicator of buried iodine-rich organic matter and is related to the rate of sedimentation (Fig. 2.1). In zones with rapid sedimentation, iodine-rich organic matter is buried rapidly, and most of the iodine is trapped in porewaters. In slow sedimentation zones, most of the iodine is also released into seawater [39]. The biological connection between iodine and carbon systems has been well established. There is a strong relation between organic C and iodine concentrations in marine sediments. Iodine is found in low concentrations in sedimentary rocks (for instance in carbonates ,1 ppm, in marine evaporites ,0.1 ppm). Shales generally contain high iodine concentrations like 1
20 ppm. The iodine amount found in sedimentary rocks cannot be found in any rock-forming mineral and cannot be absorbed in clay. It is more related to preserved organic C [10,43]. High amounts of iodine concentrations have been measured in shales containing kerogen, the primary organic matter [43]. The close link between the oil contents of shale and organic carbon content, and the iodine content of Lias Ɛ(Posidonia) and Kimmeridge shales has been shown in the source rocks of the North Sea (England) oil and gas fields [43,44]. As iodine content increases in shales, oil, and organic carbon contents are seen to increase (Fig. 2.2) [18]. It has been stated that total

Figure 2.2 Relationships between the iodine content of surface sediment, sedimentation rate (A), and carbon accumulation rate (B) [49]. The equations were determined from the graphics.

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organic carbon (TOC) values of Kimmeridge shales is .10% [45] and carbon contents of Lias Ɛ shales are 9% and oil yield as 40
45 L/tons [46]. The relationship between the iodine and TOC contents of the sediments drilled in the water wells is also compatible (Fig. 2.3) [47,48].

Figure 2.3 (A) The relationship between oil and iodine contents of Lias (Posidonia) shales [44]. (B) The relationship between organic carbon and iodine contents of Kimmeridge petroleum source rocks [43].

A biophilic material in petroleum exploration and production: iodine

2.2.2 Relationships of formation, migration, and trapping between oil and iodine The formation of hydrocarbons is a result of the increase in iodine content in porewaters with depth and release of iodine from decomposed iodine-rich organic matter [39,50
53]. Because the iodine content of seawater is 0.05 ppm [54], the iodine content of marine particles is generally between 200 and 1300 ppm [55]. As a result of the decomposition of such iodine-rich organic matter and the release of iodine to aqueous phase during diagenesis, the iodine content increases over 250 ppm in sedimentary porewaters [39,52,56,57]. For example, the iodine concentrations of formation waters in the Lunnan oilfield (Tarim basin, China) are between 3.70 and 31.2 mg/L. The reason for such a significant amount of iodine enrichment in waters cannot be seawater evaporation, halite dissolution, or any mineral transition process (plagioclase albitization or dolomitization). Such high iodine concentration is an indicator of the presence of organic matter related to the biophilic character of iodine [58]. The high iodine content of organic-rich mudrocks and oils show that iodine in formation waters (oilfield waters) has an organic origin [59,60]. Waters associated with hydrocarbons sometimes expand to the other parts of sedimentary basins as a result of the burial of the basin (within geological time) [61]. Such waters are formed together with petroleum [12] and contain some natural tracers presenting the geochemical evolution of source rocks [15]. Many studies have been stated that iodine indicates presence of organic matter in the basin [7,8,43,62
69]. Iodine concentrations show good relations with changes in organic matter amounts in marine sediments [70]. The source of iodine in sedimentary basin brines, which are large amounts of hydrocarbon accumulation, is organic-rich dehydrated sediments in the buried basin [8,10,30,68,71]. It is known that oilfield waters contain iodine with higher concentrations compared to seawater [7]. Therefore in the early stages of diagenesis, iodine in petroleum source rocks is preserved to a great extent [70]. Compaction in deeply buried marine sediments pushes the iodine-rich porewaters toward sands, which are more conductive from clays and muds. Decomposition of organic matter releases iodine to porewaters, but this is a slow process. Diagenesis of marine muds to shales causes a decline of approximately 40%
10% in the porosity from less and from 50 to 8 ppm in iodine content (solid phase). This process is a function of the pace of release, the age of sediment, depth and mineralogy, formation temperature, and nature of bound iodine [72]. While organic matter turns into petroleum, most of the iodine is released to related waters [73]. In halogen systematics of marine porewaters it is seen that gas hydrates and most of the organic bromine is merged whereas maturing hydrocarbons, H2S, 1/2 CH4, and iodine migrate together from the basins forming them (Fig. 2.4) [53,74
76]. Combined noble gas and halogen analyses provide an intriguing new method for investigating hydrocarbon
groundwater interactions. Because hydrocarbons elevate Br and I contents of formation waters, noble gases and halogens are shared between hydrocarbons and groundwater [74].

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Figure 2.4 The relationship between the iodine and TOC contents of the sediments in the shallow groundwater well [47].

Buried organic matter turns into petroleum after maturing and causes the increase of iodine concentration in surrounding waters. It is the source of iodine in basin waters having vast amounts of hydrocarbon accumulation, which have dominant control over the total iodine concentration. Also, these iodine-rich waters mediate the hydrocarbon migration [58]. Formation water has the same 129I/I age as organic matter associated with it [77]. Iodine has preserved its association with organic C throughout the decomposition of organic matter and the sedimentation process and is released in water during thermal maturing. As iodine protects its close relation with organic C systems, the age of iodine is the age of the organic matter with which it is in related [78]. The decomposition of TypeII kerogen is the primary source of the iodine found in formation waters [60,79]. The formation waters have been subcategorized according to the type of source rock (kerogen) as [60]: Type-II (Algal or other marine material, oil-prone) or Type-III (Terrestrial plant

A biophilic material in petroleum exploration and production: iodine

material, gas-prone). The relation between the type of basin and bromine concentrations is a function of the dominance of the marine sedimentation in a basin. But iodine concentrations in formation waters are independent of the type of kerogen [10,59,60]. The relationships of formation, migration, and trapping between iodine and petroleum have been examined in Fig. 2.5 [60].

Figure 2.5 (A) Migration Model [74], (B) Trapping Model [80] to the Lennard shelf of maturing hydrocarbons with Iodine.

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2.3 Occurrence mechanisms of iodine-rich waters and their relations with oil and gas deposits 2.3.1 Iodine-rich waters The iodine contents of surface waters and groundwaters which are not related to hydrocarbons are quite low. These water types usually contain trace amounts of iodine (in ppb level). The waters with the highest iodine content are those waters associated with hydrocarbon accumulations, and these waters contain iodine in ppm levels. Iodine in volcanic fluids has two sources: (1) gas outflow from the magma, and (2) interaction of groundwater or seawater with hot magma material [74]. Iodine penetrates geothermal systems from evaporites and organic-rich sedimentary rocks [81]. Many studies have proven the relationship between iodine-rich geothermal fluids and petroleum systems [57,82
90]. Iodine-rich waters are paleo-sea porewaters derived from kerogen-containing sediments that have generated oil through geological times and have sent mature hydrocarbons [Total Petroleum Hydrocarbons (TPH)] into reservoir rock. Iodine-rich waters are waters of rich in mature petroleum hydrocarbons at the same time. Iodine-rich waters containing n-alkane hydrocarbons of crude oil, and derived together with hydrocarbons from source rock are understood to have been deposited together with hydrocarbons in the reservoir rock [91]. Species and ratios of iodine in groundwaters are vary. The presence of iodine in different species and ratios shows that iodine type and ratio are controlled by multiple factors [92]. There are three types of iodine, iodate, and organic iodine (organoiodine) in the water systems. The presence of iodine species in groundwater depends on the chemical properties of water, such as pH, Eh, and organic carbon content (Figs. 2.6 and 2.7) [92]. The understanding of the different geochemical behaviors of iodine species helps explain the formation of iodine-rich groundwaters containing iodate and iodide as the main species in shallow (oxidizing conditions) and deep (reducing conditions) groundwaters [47]. The iodine species in groundwater is primarily controlled by the redox potential (Eh) (Figs. 2.8 and 2.9). The reducing environment contains higher amounts of iodine than the oxidizing environment [70]. In reducing conditions, iodide is the dominant dissolved species (the second species is organic iodine and organic carbon enrichment is observed) while iodate is the dominant dissolved species in anoxic and oxic conditions (the second species is dissolved iodide) [47,92]. In the kinetic control of iodine transition in aquifer systems, several studies indicate the importance of pH conditions [47,95]. Iodine-rich groundwaters in the anoxic environment (moderate Eh) show that high pH conditions support iodine enrichment in groundwater. As the pH increases, the positive charge on the surface of the metal oxide minerals decreases and the iodine transition from the sediments to the groundwater begins [92,96]. The relationship between iodine species and their proportions in groundwater has been evaluated on the ternary diagram in some studies (Fig. 2.10) [92,97]. In 57% of water samples, the ratio of iodate to total iodine is more than 60%. Iodide is found as the main

A biophilic material in petroleum exploration and production: iodine

Figure 2.6 The role of natural organic matter (NOM) and organic mineral complexes on the species and absorption of iodine in groundwater [47]. OC, Organic carbon; OI, organic iodine; OM, organic matter.

Figure 2.7 The relationship between the dissolved organic carbon and total iodine contents of different water samples with high hydrogen sulfide [93].

species in 22% of the samples. The groundwaters with high iodine contents are located in the middle of the basin [92]. Samples in the basin sides contain predominantly iodate while iodide is a secondary ingredient. The distribution of organic iodine (organoiodine) is controlled by the increased organic matter content in the aquifers [97]. Therefore the determination of the spatial distributions of iodine species in groundwaters of a basin will be useful in oil and gas exploration (Fig. 2.11). Iodine compounds are easily soluble in water [26].

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Figure 2.8 Eh-pH diagram of chemical species of iodine. In low redox conditions (Eh # 0.65), iodine species is iodide as independent of pH. Under low pH and 0.65 , Eh , 0.85 conditions, iodine (I2) is the dominant species. Eh . 1 conditions, oxidized iodine species are observed. IO3 is the most abundant iodine species in a wide pH range [94].

Figure 2.9 The relationship between the redox potential (Eh) and anionic organic iodine contents in water samples [93].

A biophilic material in petroleum exploration and production: iodine

Figure 2.10 Ternary diagram of iodine species in groundwater [97].

Figure 2.11 Iodine species in treated drinking water of Denmark [98].

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2.3.2 Occurrence mechanisms of iodine-rich waters The sources of iodine in surface waters and groundwaters located in basins with a large number of oil and gas accumulations are hydrocarbons, and iodine-rich reservoir waters migrated from oil and gas deposits in the subsurface to surface/nearsurface [7,17,56,99]. The hydrocarbons- and iodine-rich reservoir waters derived from petroleum reservoirs to the surface or near-surface areas cause iodine and petroleum hydrocarbons (TPH) enrichment in surface waters and groundwaters. Only crude oil has no potential to form hydrocarbons- and iodine-rich surface water and groundwater. This is because the iodine concentration of crude oil has been determined to be very low (,1 mg/L) [18,100
103]. In deep sedimentary basins, the flow mechanism of these fluids from depths to earth’s surface has been proved [103,104]. The long distance vertical migration model for hydrocarbons and waters related to iodine has been submitted in the study made on fluid movements in sedimentary basins and age of source [56]. Occurrence mechanisms of iodine-rich surface waters and groundwaters and the relationship between iodine-rich waters and petroleum systems in the Western Caspian (Azerbaijan), Eastern Caspian (Turkmenistan), Sacramento (United States), Po (Italy), and Joban-Hamadori (Japan) petroliferous basins have been examined. It has been determined that the reason for the iodine enrichment in surface waters and groundwaters of these basins containing oil and gas deposits is the iodine-rich reservoir waters and hydrocarbons derived from oil and gas deposits in the subsurface to surface and near-surface with the effect of geological events [17]. In this study, it has been proved that a hydrocarbon- and iodine-rich water basin is located surrounding an oil or gas reservoir, produced by primary methods. Based on this study [17], water samples were taken from water wells in Batman city center to examine the effect on the iodine contents of groundwaters in the region of the Batı-Raman and Raman oilfields (Southeastern Anatolia basin), which are the major producing oilfields of Turkey. As a result of the analyses, it was seen that the iodine contents of the samples were above the iodine contents in the normal groundwaters. Therefore if there is a commercial oil or gas deposit in a region, the iodine contents of surface waters and groundwaters in that region will be higher than the iodine contents of normal surface waters and groundwaters (due to water
rock
hydrocarbon interaction) (Fig. 2.12). This close relationship between hydrocarbons and iodine shows that a basin’s unknown potential for oil and gas can be evaluated by an iodine analysis on the cold and hot surface waters and groundwaters. This relationship is also significant to determine future exploration targets. The thrust-and-fold belt is featured by its box-shape in the crest and the faults in the wings. These belts contain structures forming a trap for hydrocarbons. The iodinerich waters and hydrocarbons are closely related to the fault systems. The major

A biophilic material in petroleum exploration and production: iodine

Figure 2.12 The effect on iodine contents of groundwaters in the region of the Batı Raman and Raman oilfields (Southeastern Anatolia basin, Turkey). Yellow circles: iodine contents of water wells (mg/L), red circles: iodine contents of waters produced from oil wells (iodine content .1 mg/L), blue circles: iodine contents of waters produced from oil wells (iodine content ,1 mg/L). The distance between the Batı Raman oilfield and shallow water wells is about 8 km, the Raman oilfield is about 20 km.

pathway of iodine-rich waters is the complex fault system along the crest of the thrust-and-fold belt. The hydrocarbons- and iodine-rich reservoir waters derived from petroleum reservoirs on the surface or near-surface areas cause describable iodine and petroleum hydrocarbons (TPH) enrichment in surface waters and groundwaters. Iodine-rich waters diffuse to the crest along faults and form a reduction zone (Fig. 2.13) [17]. The iodine-rich surface and groundwaters have occurred as a result of mixing with meteoric water and migrating to traps/structures formed with folding and faulting (uplifting and denudation) at the active tectonic stage of iodine-rich waters derived together with hydrocarbons from source rocks containing organic matter formed during previous geologic periods (Figs. 2.14 and 2.15) [33]. The effect on surface waters and groundwaters in regions producing waters from conventional oil and gas fields and flow back fluids produced with the hydraulic

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Figure 2.13 The schematic showing of hydrocarbons- and iodine-rich waters in a thrust-fold belt. The hydrocarbons- and iodine-rich reservoir waters derived from petroleum reservoir to the surface or near-surface areas cause iodine and mature petroleum hydrocarbons (TPH) enrichment in surface waters and groundwaters [17].

fracturing method (unconventional method) from organic-rich shales has been investigated [106
108]. According to the results of the studies, it is seen that hydraulic fracture flow back fluids coming especially from organic-rich shales cause the increase of iodine in waters in the region, compared to other halogens (Fig. 2.16). Production operations of shale oil and gas have proven both the mechanism of iodine enrichment in waters associated with hydrocarbon accumulations and the migration together of maturing hydrocarbons and iodine from source rock [57]. Also, results of the studies show that it is a direct indicator for the presence of oil and gas of iodine enriched in surface waters and groundwaters in the environment, derived from hydrocarbon reservoirs on the subsurface [106
108]. With the effect of magmatic activities, hydrocarbons- and iodine-waters can be transported from the oil reservoirs to the surface and mixed with waters of different origin (Fig. 2.17). Hydrocarbons- and iodine-rich geothermal fluids formed as a result of these magmatic activities are an essential indicator of the petroleum system in the basin where magmatic activity occurs. The relationships between oilfield waters,

A biophilic material in petroleum exploration and production: iodine

Figure 2.14 Geological processes forming iodine-rich surface water and groundwater. (A) The release of iodine into waters associated with organic matter while organic matter turns into oil. (B) Settlement to reservoir rocks (secondary migration) and mixing with meteoric waters (third migration) of hydrocarbons- and iodine-rich waters migrated from source rocks (primary migration) [17,33,105].

Figure 2.15 The relationship between active faults and known iodine-rich waters of Turkey. Red lines: active faults, yellow cycles: iodine-rich waters [33].

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Figure 2.16 The effect on surface waters into which have been discharged of flowback fluids produced from shale gas extraction using the hydraulic fracturing method. As a result of discharging, iodine and bromine contents of surface waters elevate [106].

Figure 2.17 The iodine contents in the geothermal fluids of Great Basin located near to oil and gas fields in the western part of the United States. The reason for the high iodine content in these fluids is oil and gas deposits associated with geothermal fluids. Yellow circles: iodine contents of oilfield waters, blue circles: iodine contents of geothermal fluids [16].

geothermal fluids, and iodine, and the source of iodine in geothermal systems have been examined in detail [82
84,109]. The reason for iodine enrichment in surface waters, and groundwaters and geothermal resources are oil and gas deposits in the subsurface [57]. It has been determined that oil settlement to the reservoir is caused by the partial rising and mixing with freshwater and mainly by mixing with geothermal fluids. Both chemical and isotopic data of this study show the significant role of freshwater, especially geothermal fluid, at the oil settlement to the reservoir.

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A biophilic material in petroleum exploration and production: iodine

The iodine content in the geothermal fluids of the Great Basin, found near to oil and gas fields in the western part of the United States is quite high. The reason for the high iodine content in these fluids is oil and gas deposits associated with geothermal fluids (Fig. 2.17) [16].

2.3.3 Relationship between oil and gas deposits and iodine-rich waters The reservoir waters of oil and gas fields are predominantly petroleum-related porewater and are generally saline. However, there are also freshwaters associated with oil and gas deposits. After petroleum-related waters migrate to the reservoir, it can be invaded by meteoric waters [110]. Oilfield waters are fossil marine waters (seawater at the time of oil formation). Therefore the salinity ratios should be close to or higher than seawater. The salinity of so many oilfield waters is lower than seawater salinity. However, alongside saline oilfield waters, there are many oilfields worldwide containing brackish (total dissolved solids, TDS: 1000
10,000 mg/L) and fresh (total dissolved solids, TDS: 1000 mg/L) waters (Table 2.1 and Fig. 2.18). However, all oil and gas reservoir waters are rich in iodine [18]. Thus the distinguishing property among all oilfield waters and other water types (seawater, freshwater, and saline waters derived from evaporates, etc.) is because the contents of the iodine of oilfield waters is higher than other water resources. Iodine-rich waters are direct indicators for reservoirs in which the oil and gas can be produced (containing mature hydrocarbons). For this reason, it is more appropriate to use iodine-rich or iodized water instead of saline water for oilfield reservoir water (Fig. 2.18) [18].

Table 2.1 Produced water quality percentage for ranges (mg/L TDS) in oil and gas basins of onshore United States [111]. Basin

Produced water quality percentages for ranges (mg/L TDS) 0
9999 10,000
49,999 50,000
99,999 100,000
199,999 200,000
460,000

Alaska North Slope Alaska Cook Inlet Anadarko Bighorn Arkoma Fort Worth Greater Green River North Central Montana Permian Powder River Williston Wind River

8 51 4 23 79 0 65 86 6 60 10 75

92 48 25 19 20 4 23 13 21 33 16 24

0 1 15 18 1 15 8 0.5 29 3 13 0.8

0 0 28 39 0.4 49 4 0.3 31 4 19 0.6

0 0 28 1 0.04 31 0 0.5 13 0.8 41 0.08

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Figure 2.18 Produced water quality percentages for ranges (mg/L TDS) in select oil and gas basins of onshore United States [111].

2.4 Iodine geology in oil and gas exploration Oil and gas reservoirs producing by primary methods have a natural water layer rich in petroleum hydrocarbons (TPH) and iodine. This water layer forms a water basin which is TPH- and iodine-rich around the oil and gas reservoir (Fig. 2.19) [17,91]. This iodine-rich water constitutes the most significant part of the volume of fluid produced during oil and gas production processes [91]. This water, which comes with oil and gas to the surface during production, is defined as produced water. Gas, oil, and iodine-rich water coexist in the subsurface. Because the density of the oil (0.6
1 g/cm3) is lower than the density of the iodine-rich water (iodine density: 4.93 g/cm3), the oil layer entrapped is above this iodine-rich water layer. In production wells, when the oil in the reservoir decreases, the underlying TPH- and iodine-rich water invades the oil reservoir. After a while, very little oil comes from the subsurface to the surface together with abundantly iodine-rich water. In this case, since the concept of the economy does not exist in the reservoir, the activity of this production well is terminated.

A biophilic material in petroleum exploration and production: iodine

Figure 2.19 Transformation of iodine-rich organic matter to hydrocarbon, evolutionary process of occurrence of iodine-rich waters, and components of an anticline oil reservoir produced by primary methods [18,91].

2.4.1 Hydrogeochemistry in oil and gas exploration The investigation of groundwater characteristics is an essential issue in the evaluation of the oil potential of various regions in different exploration stages [112]. This is because water is the primary factor affecting the migration and accumulation of hydrocarbons. Hydrocarbons generated from the source rocks before accumulating in a trap are carried by water in the pores of the compact sedimentary rocks. Due to togetherness lasting for millions of years after the formation and migration of hydrocarbons, it is firstly a necessary determination of the basic characteristics of water emplaced in the reservoir rock pores for understanding the presence of hydrocarbons [113]. Oil generated from organic matter is transported and stored in traps by the displacement of water in pores under geological conditions. The movement of water in pores

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contributes significantly to the accumulation of oil. There are two possibilities for this case: (1) accumulation in the stagnant water system (accumulation in hydrostatic conditions) (2) accumulation in the mobile water system (accumulation in hydrodynamic conditions). Since long-lasting hydrodynamic conditions do not destroy the reservoirs, oil accumulations are also likely to occur in these conditions [114]. Connate water is water trapped in the pores of sedimentary rocks (depositional water). Formation water is water found in deeply buried, porous, and permeable sedimentary rocks [59]. Formation water is evidence that oil has formed in closed compartments of rocks. Formation water is an important fluid which a permanent friend of oil in the reservoirs and provides useful information about [115]: 1. Identification of close and possibly related formation waters associated with oil deposits: Concentrations of detectable petroleum compounds in formation water are different in traps containing hydrocarbons from traps which are barren. These waters provide means for oil exploration. The potential of this method is high. Formation water is encountered during all deep drilling operations. The high concentration of detectable petroleum compounds in water increases the likelihood of oil deposits in the vicinity. 2. Understanding and mapping the structure of oilfields: Oil and gas fields are heterogeneous. Petroleum-containing rocks can only become distinguished by determining the rock sections containing water with a higher concentration of detectable petroleum. The detailed structure of each site can be mapped according to the characteristics of the petroleum-containing water. This type of information is crucial for the selection of the central production facilities and development/new wells locations. 3. The hydrogeochemical exploration aims to find direct and indirect indicators for oil and gas deposits which can be produced as economically as possible, to determine the hydrocarbon presence and to estimate the most promising regions on a general or specific scale. This exploration method is especially important for obtaining information about the presence or absence of oil and gas in the basins where geological structures are not well-known. Because hydrogeochemical exploration indicates the existence of a geological structure or trap, investigation of structural conditions, and integration with hydrogeochemical indicators will naturally facilitate oil and gas exploration. Today, hydrogeochemical exploration is carried out primarily in regions where many water resources (cold and hot springs and wells) are found and the petroleum potential is not known in detail. These hydrogeochemical data are highly valuable in the regions where the geology and the chemical composition of waters are well-known. Because hydrogeochemical exploration is mainly based on the interpretation of existing water analysis and, if necessary, results of the new analyses. Hydrogeochemical maps are prepared from these water analysis data and the oil and gas potential of the region is evaluated on

A biophilic material in petroleum exploration and production: iodine

these maps with the integration of geological and geophysical data. Then, they are classified into regions where commercial oil and gas can be discovered [116]. A large number of hydrogeochemical exploration methods have been developed by researchers for oil and gas based on the geological features of basins and hydrogeochemistry data of hydrocarbon production wells [9,116
123]. While it is not possible to estimate the cost of a groundwater-based petroleum exploration method, this research method could reduce the cost of exploration on onshore by up to 50% [124]. Since the reservoir characteristics of rocks are not taken into consideration, it is not possible to estimate the commercial value of the areas, which have a high oil and gas potential, based on the hydrogeochemical data [18]. However, it has been shown that in some cases hydrogeochemical data predict petroleum presence and its commercial value in a given region, as well as even the structure of deposits [125].

2.4.2 Iodine hydrogeochemistry in oil and gas exploration The rocks are tilted and bent by Earth’s forces (plate tectonics including gravity). As a result of these geological events, many petroleum traps and cover rock types occur. Understanding the occurrences of these trap types helps to determine potential reservoir regions of oil and gas. The primary purpose of petroleum exploration is to estimate locations of these potential reservoirs in complex terrains. On this subject, the information acquired from drilling wells is critical because drilling wells provide direct information about petroleum reservoirs. However, the drilling well only provides information about the petroleum geology of locations that are drilled, and only acquires this information, which is also quite expensive. Geophysical methods do not provide any information about whether there is oil or gas in a basin/trap. Therefore the geochemical survey is the most-effective initial exploration method to discover a commercial hydrocarbon accumulation and to reduce risks and costs. This is because the hydrocarbon components that are determined by geochemical methods are only found together with hydrocarbon accumulations or derived from them. Chemical materials (petroleum hydrocarbons, iodine etc.) determined in rock, gas, or water samples with geochemical methods are evidence of the presence of petroleum in a basin/trap. The main principle of a geochemical survey is the separating from the mean values of geochemical anomalies to determine hydrocarbon accumulation regions. With the data obtained from geological and geochemical methods, for petroleum exploration in the wildcat or known sedimentary basins, creating target areas for geophysical measurements and drilling is a result of the experiences acquired in the sector so far. Success ratios for different exploration methods have been identified as: random drilling 5.8%; geology 1 drilling 8.2%; geophysics 1 drilling 14.9%, and geology 1 geochemistry 1 geophysics 1 drilling 57.8% [126]. The explorations in the oil and gas industry are carried out as structure-targeted (trap) with the seismic survey and source rock-targeted with the organic geochemical survey. The results of approximately a hundred years of exploration activities, the success ratio of

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commercial hydrocarbon discovery is 10%
20% with the data obtained through these methods [18]. Iodine hydrogeochemical methods based on the investigation of the relationship of oil and gas deposits with the iodine found in surface waters and groundwaters aim at determining the areas containing hydrocarbon accumulations in the basin where the oil and gas deposits have been located [18]. Reservoir-targeted iodine geochemistry surveys have a simple sampling process, and laboratory analyses can yield results in a short time. The results are low cost, reliable, and consistent. When these data are utilized with other geological and geophysical methods, they will be a practical and useful tool to reduce the hydrocarbon exploration risk to a minimum and to discover new deposits suitable for commercial production. Because the results can be controlled and easily repeated, the method is thought to reduce the exploratory risk and costs. It is also foreseen that iodine analyses (chemical and isotopic) that will be carried out in drilled wells in oilfields at the production stage will provide significant contributions in selecting new well locations and accordingly determining the direction of field development [18]. Iodine-rich waters are also rich in mature petroleum hydrocarbons [91]. The relationship between TOC and iodine in some oilfield waters of the US basins show that be a close relation of organic carbon and iodine during decomposition and sedimentation of organic matter, release into related formation water of the iodine during thermal maturation, and migrated together to the reservoir (Fig. 2.20). Fig. 2.20 explains that iodine-rich waters can be used reliably in discovering commercial hydrocarbon accumulations because of this linear relationship between iodine and TOC in the basin scale. In this graph, the relation between iodine and organic carbon is linear in the basin scale. But, the relationship between iodine and petrogenic hydrocarbons in shallow surface waters and groundwaters is set up, whereas the correlation with TOC isn’t set up. This is because in shallow geological environments, there are different superficial organic substances other than petrogenic hydrocarbons that may form TOC in the water. However, only petrogenic hydrocarbons and iodine-rich reservoir waters derived from oil and gas deposits in the subsurface with the effect of geological events (tectonism, volcanism, etc.) can increase the iodine and hydrocarbon contents of surface waters and groundwaters. Hydrocarbons derived from the reservoir in the subsurface by atmospheric effects may be degraded or volatilizable. But iodine is a stable element and does not volatilize. It is the main reason why iodine is an excellent surface exploration material. Due to this feature, iodine provides an advantage according to TOC, etc. parameters. Iodinerich waters containing mature petroleum hydrocarbons detected in many different locations in a region/basin will naturally increase the chances of discovering an economic deposit in the exploration area. Instead of a hydrocarbon seep or source rock that has lost its volatile components by atmospheric and geological effects, it would be more appropriate surface survey method examining with organic geochemical and

A biophilic material in petroleum exploration and production: iodine

Figure 2.20 The relationship between total organic carbon (TOC) and iodine contents of produced waters from oil wells in some basins of US Data of graphics [127].

stable iodine isotope (129I) methods of hydrocarbons- and iodine-rich waters which same age and origin with possible petroleum deposits in exploration area. Iodine-rich waters provide proving from the surface or near-surface levels of the presence of commercial hydrocarbon deposit in the subsurface. Iodine compound types associated with oil and gas deposits are not identified. A possible type is CH3I [128]. Those compounds made between hydrocarbons and iodine should be the reason of iodine-rich waters are also rich in mature petroleum hydrocarbons. All petroleum geochemical analyses (gas chromatography, gas chromatography-mass spectrometry, pyrolysis, etc.) performed on rock samples have been applied to hydrocarbons containing water samples [32,91,129]. As a result of these studies, the results of hydrogeochemical and organic geochemical analyses made on source rocks, gas, and water samples in the same regions/basins were seen to be compatible with each other. Currently, petroleum exploration activity starts with organic geochemical analyses performed on the source rock or gas samples in the exploration area. Iodine-rich waters are also rich by mature petroleum hydrocarbons. Therefore all organic geochemical analyses (chemical and isotopic) performed on source rock or gas samples can also be applied to these hydrocarbons-rich waters. Iodine-rich waters are an especially unique geochemical tool for petroleum exploration in basins/regions, where source rocks are not exposed at surface as outcrops (covered basins) or have been exhausted (depleted). Thus the

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integrated usage of reservoir-targeted iodine geology methods (water and soil) and oil in water analysis (TPH) is a more suitable from the source rock-targeted organic rock or gas geochemistry for oil and gas exploration in active tectonic (dynamically “excited”— “unbalanced”) and geologically complex basins. This integrated method has a significant advantage like providing of sampling richness for exploration in the basin/regions where a large number of water resources are available, and proving the presence of oil and gas deposits be demonstrated from a large number of samples. Through this feature of iodine-rich waters, the chances of discovering commercial hydrocarbon accumulations are increased. Source rock is a sedimentary rock which generated oil, currently generating oil or could generate oil [130]. Source rocks can be classified as potential (could generate oil), effective (currently generating oil), relic effective (generated oil), or spent (generated oil). A potential source rock is a rock that contains enough carbon- and hydrogenrich organic matter to generate and expel hydrocarbons. A potential source rock contains adequate quantities of organic matter to generate petroleum, but only becomes an effective source rock when it generates bacterial gas at low temperatures, or it reaches the proper level of thermal maturity to generate oil. An effective source rock is an organic-rich rock that is currently generating and has expelled hydrocarbons. An effective source rock is generating or has generated and expelled petroleum. An active source rock is generating and expelling petroleum at the critical moment, most commonly, because it is within the oil window. A relic effective (inactive) source rock is an effective source rock which has ceased to generate and expel hydrocarbons due to thermal cooling (uplift) before exhausting its organic matter supply. It has stopped generating petroleum, although it still shows petroleum potential. Inactive source rock is not generating oil today, but in the past, it had been an active source rock. A spent (exhausted, depleted) source rock is an active source rock which has exhausted its ability to generate and expel hydrocarbons either through insufficient remaining organic matter or due to reaching over-maturity. A spent source rock has reached the postmature stage of maturity and is incapable of further oil generation, but may still be capable of generating wet and dry gas. A petroleum system is a system containing active source rock. Active source rocks include rocks or sediments that are generating petroleum without thermal maturation. This once-active source rock may now be inactive or exhausted (depleted, spent) [131
134]. Thus in regions where the iodine-rich waters containing mature petroleum hydrocarbons are present but where the effective source rocks don’t outcrop, there are two possibilities for the source of hydrocarbons in these waters: (1) In the region, there are effective petroleum source rocks (shale, mudstone, carbonate, etc.) completely covered by stratigraphic or tectonically younger or older units. (2) In the region, there are petroleum source rocks that have been relic effective (inactive) or exhausted (spent). The source of the hydrocarbons in the iodine-rich waters, the covered effective source rocks or black, gray, and brown metamorphic

A biophilic material in petroleum exploration and production: iodine

rocks (schist, phyllite, slate, crystallized limestone, marble) which sedimentary rocks (shale, mudstone, etc.) of before metamorphism may be the relic effective (inactive) or exhausted (spent) source rocks in region. In a petroleum system, it is understood that hydrocarbons generated from source rock and migrated to the reservoir rock represent by TPH of iodine-rich waters (Fig. 2.21) [91]. Migratory hydrocarbons in iodine-rich waters are different from autochthonous

Figure 2.21 Wehner diagram used to evaluate the hydrocarbon potential of source rocks according to the relationship between total organic carbon (TOC) and hydrocarbons (TPH) [135].

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hydrocarbons (hydrocarbons in source rocks). Gas chromatograms of migratory hydrocarbons in iodine-rich waters illustrate the feature of maturing n-alkanes that is shown by a nearly disappearing odd-even predominance (Carbon Preference Index 5 0.89
1.25) [32,91]. The relationship between iodine and organic carbon is linear [16], and the age of iodine in mature hydrocarbon-containing iodine-rich waters is also the age of the hydrocarbons [56,68,69,82]. Therefore with iodine 129I or δ13C stable carbon isotope analysis, it is possible to determine the source and age of mature hydrocarbons in iodine-rich waters (Fig. 2.22). Also, the source of carbon in water (organic or inorganic) can be determined by the δ13C isotope (Fig. 2.23).

Figure 2.22 Determination of geological age of iodine- and hydrocarbons-rich waters according to the composition of average carbon isotope (δ13C, %) [136,137].

Figure 2.23 Carbon sources in nature [138].

A biophilic material in petroleum exploration and production: iodine

The basic workflow of the reservoir-targeted integrated exploration method in tectonically active (dynamically “excited”—“unbalanced”) or geologically complex basins is as follows (Fig. 2.24, Tables 2.2 and 2.3). 1. Literature research and database preparation (previous geological, geophysical, geochemistry, drilling data, etc.). 2. Making hydrogeochemical (iodine, chlorine, bromine, and oil in water) and isotopic analyses (129I and 13C/12C) on samples taken from water resources planned in the exploring basin. 3. Evaluation of hydrogeochemical and isotopic analyses results of water samples. • Iodine hydrogeochemistry evaluations. • Organic geochemistry evaluations by results of oil in water (TPH) analysis. 4. Preparation of aeromagnetic and regional gravity maps of the area(s) found iodine- and hydrocarbons-rich water samples (determination of the target area). 5. Preparation of geological maps and cross-sections of the target area. 6. Integrated interpretation of geological and geophysical data. • Petroleum geology evaluations. • Subsurface geology and structural evaluations (determination of possible trap). 7. Collection and Iodine pedogeochemistry analysis of samples from the soil over the possible trap location (s). • Preparation and interpretation of iodine anomaly maps. • Determination of possible drilling location from iodine anomaly maps. 8. Verification of trap and drilling location determined by suitable geophysical method (s) and preparation of possible geological section of the well which will be drilled. 9. Slim-hole drilling (iodine analysis on mud samples during drilling). • Identification whether there is commercial oil or gas in well from change or no change of iodine content of drilling mud. • Determination of zone (s) which will be perforated in well according to iodine content of drilling mud. • Prediction of hydrocarbon volume which will be produced from well according to iodine content of drilling mud. 10. Production Well Drilling. 2.4.2.1 Integrated use of iodine hydrogeochemistry and oil in water analysis (total petroleum hydrocarbons in water) in oil and gas exploration Groundwater is the determining factor for the oil
gas reservoir forming process. It controls the diagenetic environment, migration of hydrocarbons, and dissolution [89,129,139]. Water
rock
hydrocarbon interaction is the key factor for oil
gas reservoir spatial evolution and functions in the whole diagenetic process [129,140]. Moreover, the interaction between water, rock, and hydrocarbon is a complicated physiochemical process in which all the minerals, organic matter, and formation water are both reactants and products.

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Figure 2.24 The basic workflow of the reservoir-targeted integrated exploration method.

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A biophilic material in petroleum exploration and production: iodine

Table 2.2 Analyses planned to be carried out in 1, 2, and 3 stages (Fig. 2.24) of the method. Analysis material Analysis type Parameter

Natural water

Chemical analysis

Natural water

Extraction and chromatographic analysis Isotope analysis Chemical analysis

Natural water Soil

I, Cl, Br Iodine type (iodate, iodine, organic) Oil in water (total petroleum hydrocarbons) gas chromatography, BTEX, rock-eval pyrolysis 129 129 I , I/I, 13C/12C (δ13C) Iodine concentration, iodine types (iodate, iodine, organic iodine)

Table 2.3 The work-time schedule of the integrated method for each basin/region. Stage WT No. WT name/description

Weeks 1

1

2

3

2

3

4

5

6

7

1

Literature research and database preparation X X

2

Sampling from water resources

3

Chemical analyses

X X

4

Isotopic analyses

X X

5

Evaluation of chemical and isotopic analysis results

6

Preparation of aeromagnetic and regional gravity maps

X X

7

Preparation of geological maps and cross-sections

X X

8

Integrated interpretation of geological and geophysical data

9

Sampling from soil

10

Soil chemical analysis, preparation of iodine anomaly map and interpretation

8

9

10

X X

X X

X X X X X X

Dynamic equilibrium between dissolution and precipitation at a special temperature and pressure will be reached in this process. The most direct manifestation for water
rock
hydrocarbon interaction is the physiochemical characteristic changing in groundwater and strata [129]. Surface waters and groundwaters associated with hydrocarbon accumulations or contaminated by hydrocarbons typically contain a high amount of hydrocarbons. Value of

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TPH of a water sample is an important parameter used to determine hydrocarbon contamination of surface waters and groundwaters. Determination of TPH value provides information on petroleum contamination of groundwater. TPH analysis is the calculation of TPH value (hydrocarbon content) with the help of the remaining area in the C8
C40 carbon range. This range of carbon ranges from low boiling volatile hydrocarbon compounds to nonvolatile compounds in the high boiling point range [141]. To determine TPH concentrations in water contaminated by hydrocarbons is used gas chromatography. There are numerous studies in the literature on the use of TPH analysis (especially environmental engineering applications) in surface waters, groundwater, oilfield produced waters [141
146]. Analyses performed on water resources (that organic geochemical parameters can be determined, TPH analysis, etc.) in basins/regions where source rocks are not exposed at surface as outcrops (covered basins) or have been exhausted (depleted, spent) are particularly important in terms of reduction of exploration risk and cost (to increase chances of economic success). Gas chromatography analysis has been conducted in the groundwaters of Guizhou (China) of the Western Triassic. In all of the waters in the region, n-alkane hydrocarbons have been detected. In the study, groundwater with hydrocarbon content .0.05 mg/L has been defined as hydrocarbon-rich groundwater (groundwater grade III, second level drinking water source according to China quality standard). Groundwaters in the study area were monitored throughout 5 years, and the amount of petroleum hydrocarbon in groundwater were determined to be .0.05 mg/L. It has been determined that the low-level anthropogenic contamination cannot produce high hydrocarbon groundwater in the area. Organic geochemistry and biomarker characteristics were used to determine the hydrocarbon potential of the rocks in the region and the hydrocarbon source in shallow groundwater. It has been determined that the rocks had high hydrocarbon potential in the region. It has also been determined that the hydrocarbons in groundwater are the original and mature hydrocarbons. Moreover, it has been seen that organic geochemical and biomarker characteristics of the samples taken from rock and deep groundwaters are compatible with each other (Fig. 2.25). It has been determined that the hydrocarbon content in shallow aquifers increased with water
rock
hydrocarbon interaction. Instead of shallow groundwater, saturated carbons in the deep groundwater, similar to those of the rocks in the region, were found. These results indicated that the high concentrations of original hydrocarbons in groundwaters could be due to the hydrocarbon release from corrosion and extraction out of strata over time [129]. It has been determined that n-alkane hydrocarbons originated from crude oil in the TPH analysis performed in Hasano˘glan (Ankara) water samples. The origin, maturity, sedimentation environments of the hydrocarbons in water samples, have been interpreted using Pristane (Pr)/Phytane (Ph) ratio, Pr/Ph
CPI, and Pr/n-C17
Ph/n-C18 diagrams prepared by n-alkane distributions in gas chromatograms. As a result of the study, it has

A biophilic material in petroleum exploration and production: iodine

Figure 2.25 Phytane to n-C18 alkane (Ph/n-C18) versus pristine to n-C17 alkane (Pr/n-C17) ratios of deep groundwater and rock samples taken from the same region [129]. The organic geochemical and biomarker characteristics of the samples taken from rock and deep groundwaters are compatible with each other.

been identified that the hydrocarbons- and iodine-rich waters are evidence of the petroleum system in the region and the iodine-rich waters are rich in mature petroleum hydrocarbons [32]. In another study, the oil and gas potential of the Ulukı¸sla (Ni˘gde) basin has been evaluated using hydrogeochemical, organic geochemical, and tectonic features (with gravity and aeromagnetic data). The presence of n-alkane hydrocarbons in the TPH analysis, performed in water samples has been determined. It has been seen that the results of the hydrogeochemical and the organic geochemical analysis of the samples taken of the water wells were found to be consistent with each other. In the study, it has been stated that the Ulukı¸sla basin has a high oil and gas potential due to the presence of hydrocarbons- and iodine-rich water resources [34]. The usability in oil and gas exploration of TPH analysis in water was examined, defining the hydrocarbon content of water. For this purpose, the results of TPH analysis performed in the surface waters and groundwaters of the Yüksekova (Hakkari), Ulukı¸sla (Ni˘gde), and Hasano˘glan (Ankara) regions were compared with the results of

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classical petroleum geochemistry analysis in the same region. It has been seen that the results of the hydrogeochemical analysis of the samples taken of the water wells and the organic geochemical analysis of the source rock and gas samples were found to be consistent with each other. Also, the TPH values of water samples were seen to be significantly higher than the recommended limit values. Besides, it has been determined that n-alkane hydrocarbons identified in all waters of three regions originated from crude oil. As a result of the study, it has been determined that it can be used successfully as a geochemical method in the petroleum exploration of TPH analysis made on waters samples. Also, it has been concluded that basins containing oil and gas deposits can be determined by this analysis. It would be possible a practical and cost-effective tool if used together with other geological and geophysical methods of this analysis method to minimize the risk and cost of hydrocarbon exploration and to discover new commercial oil and gas deposits. In the study has reported that to be the iodinerich waters at the same time of the waters at petroliferous basins containing mature hydrocarbons-rich (TPH-rich) surface waters and groundwaters. Also, it has been reported that waters associated with oil and gas deposits of the surface waters and groundwaters containing TPH .0.5 mg/L [91]. It has been stated that reservoir-targeted organic hydrogeochemical methods may be more useful than the source rock-targeted organic rock and gas geochemistry for oil and gas exploration in active tectonic (dynamically “excited”—“unbalanced”) and geologically complex basins [33]. Waters associated with economic oil and gas deposits are distinguished from other water types by the high iodine- and hydrocarbon-contents which can be determined by easy and cheap analysis methods. Iodine, chlorine, bromine, and oil in water are laboratory analyses which are low cost, reliable, consistent, simple, and short-time sampling processes. The process of data collection, analysis, and interpretation of iodine geology are carried out by using modern laboratory equipment and techniques together with meticulous field geology, hydrogeochemistry, and pedogeochemistry studies. For example, the content of iodine in water is determined by the spectrophotometer, and iodine isotope (129I) is determined by the mass spectroscopy device (AMS). The first target of the method based on the integrated usage of iodine geology methods and oil analysis in water is to determine the TPH- and iodine-rich water basin (Fig. 2.19) formed around an oil or gas reservoir. Therefore the method is carried out primarily in basins/regions where many water resources (cold and hot springs and wells) are found and where the petroleum potential is not known in detail. Water samples are taken with scaled-plastic bottles via standard hydrogeochemical methods from cold and hot water resources and wells in the study area for reservoir-targeted iodine hydrogeochemistry and oil in water analyzes (Fig. 2.26). Iodine, chlorine, bromine, and TPH values of the waters are identified with laboratory analyses to generate data for iodine geology and organic hydrogeochemical evaluations. The analysis of iodine, bromine, and chlorine (API RP45 method) are performed on water samples

A biophilic material in petroleum exploration and production: iodine

Figure 2.26 Sampling from a natural water resource with the scaled-plastic bottle and water samples taken in 1 L scale plastic bottles.

taken using the Hach method with titration and the UV spectrophotometer device. With these analyses, direct total concentrations of water samples (in mg/L) are determined, and these concentrations are used in evaluations. In the determination of TPH, the determination of hydrocarbons: Solvent extraction and gas chromatography method (ISO 9377-2) is used in the standard test method (other methods: EPA Method 1664 and ASTM D7678-11). In this analysis method, flat-chain and branched aliphatic, alicyclic, aromatic, or alkyl-variable aromatic hydrocarbons are separated and the total amount of petroleum hydrocarbons are determined in the samples taken from underground, surface, and distribution waters. These samples are stored by acidification to prevent events—such as evaporation or biodegradation in the samples— that may affect the number of hydrocarbons. The samples are analyzed for 14 days if acidified, and within 7 days if not done, and stored at 5 C 6 3 C before analysis. Iodine and TPH contents of water resources (cold and hot springs, water- and geothermal-wells) in the study area can be measured with portable iodine photometer/ checker and an oil in water analyzer (Figs. 2.27 and 2.28). These portable instruments can be used to obtain the preliminary evidence in the study area and to select samples to be sent for analysis from the water resources studied. This style allows both the right selection of samples to be sent to the laboratory for analysis and optimum sampling. Also, it provides an understanding of the presence of oil and gas in the study area, before laboratory analysis. The main advantage of an iodine photometer/checker is its small size and measurement simplicity. Within a few minutes, the photometer directly displays the iodine content of the water sample in ppm on the LCD. When a specific reagent (potassium iodide) is added, the water sample takes on a degree of coloration that is proportional to the iodine content (Fig. 2.29). The reaction between iodine and the reagent causes

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Figure 2.27 Various types of portable iodine checkers/photometers, 10 mL small glass cuvettes, and potassium iodide powder reagents.

Figure 2.28 Various types of portable oil in water (TPH) analyzers.

Figure 2.29 The coloration of iodine-rich and noniodine waters after the addition of potassium iodide reagent to the water sample.

A biophilic material in petroleum exploration and production: iodine

a pink tint in the water sample. The photometer measures this coloration. When a light beam passes through the colored water sample, energy with a specific wavelength is absorbed by the iodine in water. The photometer determines the coloration of the sample by measuring the transmission or absorption of light of this wavelength. The photometer then uses a microprocessor to calculate the concentration and displays the result. Iodine photometry can be made to measure 0
12.5 ppm. The photometer can be tested in scale with the water of known iodine content prepared with mixed the noniodized water and iodized table salts. Oil-generating source rocks can be divided into two groups: organic-rich shales and carbonates/evaporites. Shales have high iodine concentrations like 1
20 ppm. The iodine is present in low concentrations in sedimentary rocks (e.g., ,1 ppm in carbonates, ,0.1 ppm in marine evaporites). Sandstones and carbonates do not contain abundant halogens [10,43,60]. Previous studies show that iodine content .1 ppm in formation waters of oil and gas production basins/fields [18,127]. The waters with iodine content .1 ppm are waters associated with oil and gas deposits [9,12,18]. The waters with iodine content ,1 ppm are oilfield waters which are decreased iodine content and mixed with other water types (seawater, meteoric, and saline water)in the basin of oilfield waters with iodine content .1 ppm [18]. Since the iodine content is low in these waters, there may be no coloration after the addition of reagents to the waters. However, in previous studies [32,91], the presence of petroleum hydrocarbons were determined in TPH analyzes performed in waters with iodine content ,1 ppm. The iodine content of the water rich in hydrocarbons can be ,1 ppm. This is because the hydrocarbons-generating source rocks are carbonates/ evaporites or have mixed with meteoric and salt water of the iodine-rich waters. It has been stated that hydrocarbon-rich waters of surface and groundwaters containing TPH .0.5 ppm [91], hydrocarbon content .0.05 ppm [129]. Therefore these values can be taken as reference in TPH analyses to be made in-situ in water resources. Thus all of the samples taken from waters containing TPH .0.05 ppm should be sent to the laboratory for analysis with more sensitive instruments. 2.4.2.1.1 Determination of relationship with hydrocarbon accumulations of waters

The “Oilfield Water Differentiation Plot” based on I/Cl and Cl ratios of waters is used to determine iodine-rich surface waters and groundwaters associated with oil and gas deposits (Fig. 2.30). This plot is possible in evaluating the relationship between hydrocarbon accumulatios with surface waters and groundwaters to examine oil and gas potential of a basin. The evaporation of seawater by 15 times may cause ,1 mg/L iodine content in surface and groundwaters [147]. Therefore to be also rich in mature petroleum hydrocarbons for water with iodine content ,1 mg/L is evidence of associated producible hydrocarbon accumulations which are volatile derivatives of organic-rich sedimentary rocks (Fig. 2.31, Tables 2.4 and 2.5). Also, 129I/I iodine

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Figure 2.30 (A) I/Cl-Cl ratio [33], (B) I/Cl ratio [149] plots. Iodine-rich oilfield waters data: [18]. Iodine-rich surfaces and groundwaters data: Table 2.4. Iodine (0.87 mg/L) and chloride (76.75 mg/L) data: [100
103].

isotope ratios of water resources containing ,1 mg/L iodine can be used to determine the source of iodine in water samples [148]. The occurrence mechanisms of iodine-rich surface waters and groundwaters and the relationship between iodine-rich waters and petroleum systems in the Western Caspian (Azerbaijan), Eastern Caspian (Turkmenistan), Sacramento (United States), Po (Italy), and Joban-Hamadori (Japan) petroliferous basins have been examined. Iodine contents of waters in examined petroliferous basins are mostly .1 mg/L [17]. Therefore the source of iodine in surface waters and groundwaters are the organicrich sedimentary rocks and these iodine-rich waters are associated with oil and gas deposits in the basins where they are located (Fig. 2.32). Iodine-rich waters in the

A biophilic material in petroleum exploration and production: iodine

Figure 2.31 Some waters enriched in both iodine and mature petroleum hydrocarbons (TPH) of ˘ ˘ Turkey. Burgundy star: Antakya (Hatay), yellow star: Ulukı¸sla (Nigde), green star: Güzelyurt (Nigde), red star: Yüksekova (Hakkari), pink star: Aydıntepe (Bayburt), orange star: Germencik (Aydın), turquoise star: Center (Aydın) (Table 2.4).

examined basins are the oilfield waters mixed with seawaters and freshwaters. Most of the iodine-rich waters are brackish and saline and some of them are brine. The iodine-rich saline oilfield waters mixed with freshwater have formed iodine-rich brackish water. None of the iodine-rich waters in the investigated basins has been formed as a result of seawater evaporation or halite dissolution. The iodine-rich waters in Po (Italy), Western Caspian (Azerbaijan), Eastern Caspian (Turkmenistan) basins have been associated with mud volcanoes and petroleum systems in the basins. The iodine-rich waters in the Joban and Homadori petroliferous basins (Japan) are waters mixed with iodine-rich paleo-seawaters, which have derived from the Iwaki-oki gas field. The iodine-rich waters in the Sacramento basin (United States) are the waters mixed with iodine-rich reservoir waters derived from gas fields in the Sacramento basin. Also, in some water resources, hydrocarbons have been determined. The reasons for the iodine enrichment in all surface waters and groundwaters of these basins which contain oil and gas deposits are iodine-rich reservoir waters and hydrocarbons that migrate from oil and gas deposits in the subsurface to surface and near-surface with the effect of geological events (tectonism, volcanism, etc.). The iodine in the surface waters and groundwaters of investigated petroliferous basins is derived from organicrich rocks and has the same origin with iodine in the oilfield waters [17].

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Table 2.4 Some waters enriched in both iodine and mature petroleum hydrocarbons (TPH) of Turkey [33,91]. City Sample Coordinates I Cl TPH Maturity of (mg/L) (mg/L) (mg/L) hydrocarbons X Y

Ankara

Ni˘gde

Hakkâri Bayburt Aydına

Hataya a

Hasano˘glan-1 Hasano˘glan-2 Hasano˘glan-3 Hasano˘glan-4 Hasano˘glan-5 Hasano˘glan-6 Hasano˘glan-7 Ulukı¸sla-1 Ulukı¸sla-2 Ulukı¸sla-3 Güzelyurt-1 Güzelyurt-2 Yüksekova-1 Yüksekova-2 Aydıntepe Germencik Germencik Germencik Germencik Germencik Germencik Germencik Center Center Center Center Center

4434514 4433162 4429243 4430981 4430089 4431677 4429042 4156494 4156494 4156494 4237794 4237304 4128721 4128721 4470574 4191312 4190846 4190097 4193898 4193561 4196894 4193730 4188921 4188729 4190357 4191224 4016210

503880 508986 5111121 510944 511113 510932 511255 629950 629950 629950 611098 610833 406536 406536 587009 552690 552774 552748 551151 552028 555879 556606 579273 579083 579245 578287 246238

0.03 0.04 0.05 0.03 0.03 0.05 0.09 8 6 3 0.28 0.33 0.08 0.05 0.05 0.06 0.06 0.04 0.03 0.03 0.03 0.05 0.11 0.03 0.07 0.10 5.5

23.9 17.7 26.4 27.5 22.8 23.5 49.2 2302 1058 1305 1481.4 1763 15 15 6.5 1569 1477.6 1484.6 1386 1611.3 1737.9 1238.4 696.6 154.8 443.3 397.5 122

42.38 23.39 24.04 45.31 37.91 42.09 41.34 7.49 7.27 4.50 0.1 0.1 16.18 12.01 75.3 45.86 114.76 9.65 5.97 6.02 45.72 16.94 6.66 6.77 8.24 70.52 0.126

Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature Mature

This study.

2.4.2.1.2 Determination of iodine source in water and relationship between I/Br ratio of waters and Kerogen type

In abundant in formation waters in a sedimentary basin, chlorine is the first and bromine is the second halogen (Fig. 2.33). Chlorine and bromine have a strong systematic which gives rise to the thought that they have the same control mechanism. Fluorine is in relatively high concentrations only in high chlorine and bromine concentrations. This case shows that concentrations of fluorine, chlorine, and bromine are controlled most probably by the same processes. Iodine is not related to any other halogens and indicates that the concentration of iodine in water is controlled by different processes [60]. The iodine in the oilfield waters is derived from a secondary source (iodine

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A biophilic material in petroleum exploration and production: iodine

Table 2.5 Relation to hydrocarbon accumulations of the waters (see Table 2.4). City

Sample

I (mg/L)

TPH (mg/L)

Water type

Relation to hydrocarbons accumulations

Ankara

Hasano˘glan-1 Hasano˘glan-2 Hasano˘glan-3 Hasano˘glan-4 Hasano˘glan-5 Hasano˘glan-6 Hasano˘glan-7 Ulukı¸sla-1 Ulukı¸sla-2 Ulukı¸sla-3 Güzelyurt-1 Güzelyurt-2 Yüksekova-1 Yüksekova-2 Aydıntepe

0.03 0.04 0.05 0.03 0.03 0.05 0.09 8 6 3 0.28 0.33 0.08 0.05 0.05

42.38 23.39 24.04 45.31 37.91 42.09 41.34 7.49 7.27 4.50 0.10 0.10 16.18 12.01 75.30

Freshwater

Oilfield water mixed with freshwater

Brackish water

Oilfield water

Brackish water

Germencik Germencik Germencik Germencik Germencik Germencik Germencik Center Center Center Center Antakya

0.06 0.06 0.04 0.03 0.03 0.03 0.05 0.11 0.03 0.07 0.10 5.5

45.86 114.76 9.65 5.97 6.02 45.72 16.94 6.66 6.77 8.24 70.52 0.13

Oilfield water mixed with freshwater Oilfield water mixed with freshwater Oilfield water mixed with freshwater Oilfield water mixed with salt-solution brines

Ni˘gde

Hakkâri Bayburt Aydın

Hatay

Freshwater Freshwater Saline water

Saline water

Oilfield water mixed with freshwater

Freshwater

Oilfield water

release from the organic-rich formation) rather than seawater evaporation (Fig. 2.34) [59,106]. Organic-rich marine sediments and halite are primary sources for iodine in the terrestrial environment. These sources can be differentiated with I/Br ratios [37,56,150]. Compliance of iodine with evaporite minerals is lower than that of bromine [151]. Most of the marine porewaters have similar organic Br/I ratios with seaweeds and corals [8,74]. Sources of low iodine concentration in sediments and organic matters in the terrestrial environment usually are rainwater [151]. Waters associated with hydrocarbons are derived from organic-rich sediments, and they have higher iodine content than the waters derived from sediments not containing organic matters [59,60,151]. Potentially iodine is related with organic-rich rocks independently of marine and terrestrial environment and is used as a good tracer for sedimentary basin brines. As Br/I ratios of organic

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Figure 2.32 (A) I/Cl-Cl ratio [33], (B) I/Cl ratio [149] plots [17]. Yellow circles: mineral waters, hot springs, and serpentinizing springs of Sacramento basin (United States). Magenta triangles: meteoric waters of Sacramento basin (United States). Blue triangles: waters of Eastern Caspian basin (Turkmenistan). Pink triangles: waters of Joban-Hamadori basin (Japan). The green diamonds: waters of Po basin (Italy).

matter derived from marine and terrestrial are not the same, it is appropriate to use Br/I ratios to differentiate between marine source rocks and terrestrial source rocks in organic-rich environments [151]. Br/I ratios can determine oil-water samples produced from reservoirs. These ratios are likely reflecting the different petroleum source rocks and can be separated from the terrestrial and marine source rocks. Coupled with other techniques (i.e., groundwater flow modeling, basin modeling) conservative tracers yield a better in the understanding of fluid migration in oilfields [15].

A biophilic material in petroleum exploration and production: iodine

Figure 2.33 Comparison of halogen concentrations of formation waters in sedimentary basins. Chlorine is the most abundant halogen followed by bromine, then iodine and finally fluorine [60].

Figure 2.34 Iodine
Bromine concentration data of oil and gas fields (492 data points) taken from 36 publications of various global basins. All oil and gas field formation waters contain higher iodine concentrations than can be accounted for by evaporation. The input of iodine from organic-rich sediment is normal showing that iodine is not a conservative element in formation waters associated with sedimentary basins. The plot also has porewater compositions from moderately buried organic-rich sediments showing iodine enrichment due to the release of iodine from altered organic matter [59].

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Oil generated from organically different source rocks accumulated in reservoirs during various times in geologic history, lead to a separate Br/I observed in formation waters. The different signatures are reflective of either a lacustrine or marine source rock (Table 2.6). Br/I ratios from the waters produced with oil separate formation waters and identify lacustrine from marine origins. Br/I ratios of the produced waters separated from an oil-water solution can also show formation waters from multiple formations naturally mixed or mixed in production wells [15]. Iodine is more mobile than bromine in oxidized porewaters [39]. In sedimentary basins, it is probable that the Br/I ratios of some fluids and solids interacting with organic matter will increase (Table 2.6). The Iodine concentration has been shown to increase as peat ages and as it is diagenetically altered during burial, from lignite to bituminous coal, and finally anthracite. The coal absorbed additional iodine during this metamorphism. The iodine concentration is higher in marine coals than freshwater coals suggesting that the specific depositional environment plays a major role [59]. Iodine and bromine released during the decomposition of organic matter are used to identify the origin of fluid. The Br/I ratios of waters can determine the terrestrial or marine origin of waters. Because the Br/I ratios of organic matter (kerogen) originated from marine and terrestrial environments are not the same [15,60]. It has been observed that organic-rich rocks represent different geological environments according to their Br/I ratios [15]. Iodine concentration is high in the marine environment. A terrestrial environment probably has higher Br/I ratios whereas marine organic-rich environment has high iodine content and lower Br/I ratios [15,60]. Br/I ratios have been used to determine the type of source rocks (marine an/or terrestrial) formed from organic matters in organic-rich environments [15,74]. I/Br ratio of iodine-rich waters settled to the reservoir and migrated together with maturing hydrocarbons Table 2.6 Br/I ratios of various organic solid substances and fluids. Organic matter Br/I ratio

Alberta crude oils Pitch of crude oil Marine porewaters Formation waters with marine origin Formation waters with lacustrine origin Marcellus shale production waters Brazilian coal Australian coal Indonesian coal Vietnam coal China coal-1 China coal-2 Peat bog

0.53 0.82 0.5
2.5 1.2
2.4 2.9
8.2 19 4 2.05 7.15 6.60 13.54 9.20 11 6 4

References

[102] [99] [73] [14]

[152] [153]

[154]

A biophilic material in petroleum exploration and production: iodine

Figure 2.35 The relationship between I/Br ratios of formation waters and kerogen type [18].

derived from source rock can be used to determine hydrocarbons-generating kerogen type (Fig. 2.35) [18]. 2.4.2.1.3 Determination of source, maturity, and sedimentation environment redox conditions of hydrocarbons in iodine-rich waters by organic geochemical methods

There are detailed studies examining sources of hydrocarbons and properties of petroleum geochemistry in hydrocarbon-rich waters by using organic geochemical analysis and methods [32,91,129]. Alkanes (paraffinic hydrocarbons) are in the form of a straight or branched chain without the ring structure of the paraffin series known to the formula CnH2n 1 2. It is also known as a saturated hydrocarbon group since carbon atoms are bonded in a single covalent bond and other bonds are saturated with hydrogen. Methane (CH4) is the simplest hydrocarbon. The Carbon Preference Index (CPI), a ratio between single and even carbon number n-alkane amounts, is determined by measuring the heights of the peaks in gas chromatograms. The dominant peaks in these chromatograms are n-alkanes. CPI is an indicator of the source of n-alkane [91]. In the calculation of the CPI index suggested different formulas by researchers. Calculation of CPI index of water samples: CPI 5 1/2 3 [(C25 1 C27 1 C29 1 311 33)/(C241 C261 C281 30 1 32)] 1 [(C251 C271 C29 1 311 33)/(C26 1 C28 1 C30 1 C32 1 C34)] [155]. The NAR (Natural N-alkane Ratio) parameter has been proposed to evaluate the source of hydrocarbons in the environment (natural or petroleum n-alkane) [156]. This ratio is zero or close to zero for petroleum hydrocarbons and crude oil. In other hydrocarbon sources, the ratios are higher. The following formula calculates the

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NAR ratio.

P NAR 5

 P n-alkðC19232 Þ 2 2 even n-alkðC20232 Þ P n-alkðC19232 Þ

(2.1)

The Carbon Preference Index (CPI) is used to interpret the type of organic matter, the sedimentation environment, and thermal maturity. This index can be applied to any range of the carbon sequence. The CPI value is markedly higher than 1 (single n-alkane preference) or less than 1 (double n-alkane preferential) indicating thermally immature oil or bitumen samples. CPI value approaches 1 with increasing maturity [138]. CPI values smaller than 1 are typically observed in oil and bitumen associated with very salty carbonate, evaporite, or highly saline environments [130,157]. A high CPI value in the immature or low-maturity sample reflects the input of organic matter derived from higher terrestrial plants [158]. By using gas chromatography analysis results, the Carbon Preference Index (CPI), Pristane/Phytane ratio (Pr/Ph), isoprenoid/n-alkane ratio (Pr/n-C17 and Ph/ n-C18) are calculated, and n-alkane distributions are interpreted [91] (Table 2.7). Table 2.7 Some waters enriched in both iodine and mature petroleum hydrocarbons (TPH) of Turkey. ˙Il Numune I (mg/L) TPH (mg/L) CPI Pr/Ph Pr/n-C17 Ph/n-C18

Ankaraa

Aydınb

Hasano˘glan-1 Hasano˘glan-2 Hasano˘glan-3 Hasano˘glan-4 Hasano˘glan-5 Hasano˘glan-6 Hasano˘glan-7 Germencik Germencik Germencik Germencik Germencik Germencik Germencik Center Center Center Center

0.03 0.04 0.05 0.03 0.03 0.05 0.09 0.06 0.06 0.04 0.03 0.03 0.03 0.05 0.11 0.03 0.07 0.10

42.38 23.39 24.04 45.31 37.91 42.09 41.34 45.86 114.76 9.65 5.97 6.02 45.72 16.94 6.66 6.77 8.24 70.52

1.25 1.01 1.08 1.07 1.06 1.17 1.05 1.06 1.04 0.98 1.08 0.98 0.89 0.99 0.92 0.92 0.98 0.92

0.53 0.94 0.95 0.28 0.74 0.97 0.53 0.86 0.52 0.70 0.64 0.61 0.48 0.81 0.80 0.66 0.72 0.62

0.68 1.90 1.32 1.25 1.29 1.18 1.11 0.50 0.35 0.25 0.34 0.33 0.33 0.25 0.34 0.33 0.34 0.33

0.64 0.99 0.78 1.75 0.70 0.98 0.63 0.58 0.67 0.36 0.52 0.54 0.69 0.31 0.42 0.50 0.47 0.54

The hydrocarbon content of the water samples is significantly higher than the hydrocarbon limit values that should be found in TPH ,0.5 mg/L [91] and hydrocarbon content ,0.05 mg/L [129]. Therefore the water
rock
hydrocarbon interaction has caused the hydrocarbon enrichment in water. According to the CPI values [91], the source of all n-alkanes in the water samples is petrogenic (crude oil) hydrocarbons and organic matter derived from marine organisms, and all hydrocarbons are mature. a Ref. [31]. b This study.

A biophilic material in petroleum exploration and production: iodine

N-alkanes closest to isoprenoids in gas chromatograms are used in isoprenoid/nalkane ratios. With pristane n-C17, the phytane has double peaks with an n-C18. Pr/Ph ratio and a good correlation parameter. Although pristane (Pr) and phytane (Ph) define other sources, they are derived from phytyl which is the side chain of chlorophyll, especially in phototropic organisms. In anoxic conditions, the side chain of phytyl is broken off, and it is reducing in the phytol to form the phytane. In oxidic conditions, the phytol is reducing to pristane [157]. Thus the Pr/Ph ratio reflects the redox potential of the deposition environment. Pr/Ph ,1 indicates anoxic storage, if higher than 1, it indicates oxic conditions [159]. The Pr/Ph ratio also provides information about the paleoenvironment and maturity (Figs. 2.36
2.38) [160]. Pr/n-C17 and Ph/n-C18 ratios are widely used in petroleum correlation studies. Samples with high levels of oxidation are oxidizing, while the high phytane content reflects a reducing source. Therefore the diagrams of Pr/n-C17 versus Ph/n-C18 are used to classify petroleum or bitumen in different groups [161]. The Pr/Ph ratio above 1.5 indicates that the Pr/Ph ratios may be higher than 1 for anoxic deposition environment, although they indicate settling conditions in an oxygenated environment according to standard geochemical interpretation. Lower values may show less oxic conditions than other parts of the same sequence [162].

Figure 2.36 Ph/Pr diagram of the water samples (Table 2.7). The diagram: [163]. The source rock of ˘ the hydrocarbons in both Hasanoglan (Ankara) and Germencik and Center (Aydın) water samples is marine source rock.

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Figure 2.37 Carbon Preference Index (CPI)
Pr/Ph diagram of the water samples (Table 2.7). The ˘ diagram: [164], green triangles: Hasanoglan (Ankara) samples, blue circles: Germencik and Center ˘ (Aydın) samples. The hydrocarbons in Hasanoglan (Ankara), Germencik and Center (Aydın) water samples have been deposited in a marine environment. Part of the hydrocarbons in Germencik and Center (Aydın) water samples are hydrocarbons associated with hypersaline carbonate or evaporitic environments.

Figure 2.38 Pr/Ph
CPI diagram of the water samples (Table 2.7). The diagram: [165], green trian˘ gles: Hasanoglan (Ankara) samples, blue circles: Germencik and Center (Aydın) samples. ˘ Hasanoglan (Ankara) water samples are located in a more reducing area, and they are at similar maturity levels. Germencik and Center (Aydin) water samples are mostly mature hydrocarbons, and some of them are in the more reducing area, and they are at similar maturity levels.

A biophilic material in petroleum exploration and production: iodine

Figure 2.39 Pr/n-C17
Ph/n-C18 diagram of the water samples (Table 2.7). The diagram: [166,167], ˘ green triangles: Hasanoglan (Ankara) samples, blue circles: Germencik and Center (Aydın) samples. The hydrocarbons in Germencik and Center (Aydın) water samples are generated from the carbon˘ ate source rock deposited in an open sea environment. The hydrocarbons in Hasanoglan (Ankara) samples are generated from the carbonate and shale source rocks deposited in the transition zone ˘ and swamp environment. The hydrocarbons in Hasanoglan (Ankara) water samples have been deposited in a marginal inner sea formed by continental rifting [32].

The ratio of isoprenoid/n-alkane decreases with the increase in maturity as the n-alkane is released rather than with the breakthrough [129,161] and is used as a measure of maturity for biodegradable oil and bitumen samples. This ratio increases with the biodegradation due to the easier disappearance of n-alkanes [161] and is also influenced by organic matter input and secondary functions. The lithology and sedimentation environments of the source rock can be determined by using the Pr/nC17
Ph/n-C18 diagram (Figs. 2.39 and 2.40). Besides, pristane/phytane and (Pr 1 Ph)/(n-C17 1 n-C18) the diagram provides information about oxic or anoxic conditions (Fig. 2.41) [161]. The organic geochemical analyses include both optical and chemical methods [130]. The data obtained from these methods link together: (1) the amount of organic matter/oil or gas richness (2) the proneness of the organic matter (kerogen) to oil or gas and (3) the maturation stage (immature, mature, or over-mature/metamorphized) [159]. The thermal maturation indicators and vitrinite reflectance value by CPI (Carbon Preference Index) value of hydrocarbons in iodine-rich waters can be identified (Fig. 2.42).

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Figure 2.40 Pr/n-C17
Ph/n-C18 diagram of the water samples (Table 2.7). The diagram: [168], ˘ green triangles: Hasanoglan (Ankara) samples, blue circles: Germencik and Center (Aydın) samples. ˘ The source rock which generated the hydrocarbons in Hasanoglan (Ankara) water samples was deposited in the reducing and transition zone (Type II
III kerogen). The source rock which generated hydrocarbons in Germencik and Central (Aydın) water samples were deposited in the marine reducing (Type-II kerogen) and the transition environment (Type II
III kerogen). The fact that the samples are located in the same area and close to each other is an indication that they are related genetically; in other words, they were generated from the same source rock.

Figure 2.41 Pr/Ph 2 (Pr 1 Ph)/(n-C17 1 n-C18) diagram of the water samples (Table 2.7). The dia˘ gram: [169], green triangles: Hasanoglan (Ankara) samples, blue circles: Germencik and Center (Aydın) samples. All hydrocarbons in water samples were deposited in primary dysoxic to oxic conditions.

A biophilic material in petroleum exploration and production: iodine

Figure 2.42 Correlation of thermal maturation indicators with vitrinite reflectance (Ro) and Carbon Preference Index (CPI) values [91,170,171].

2.4.3 Usage of iodine-129 isotope in petroleum geology Iodine, which is a stable biophilic element, is found in highly enriched amounts in fluids associated with hydrocarbons such as oilfield waters [15,56]. Due to this feature, the iodine isotope (129I) has been used in recent years to determine hydrocarbon sources in various structures and the age of formation water associated with these hydrocarbon sources (since the age of the iodine in the formation waters is also the age of hydrocarbons in the basin) and migration processes [39,53,56
58,69,75,84,90,101,172
178]. The occurrence of hydrocarbons, time of maturation and the starting of migration are critical questions in understanding the processes of formation of oil reservoirs. 129I isotope system can be used to find answers to these questions (Fig. 2.43) [58,84]. It can provide useful information to reduce the costs of petroleum exploration activities and to increase efficiency because hydrocarbon migration is related to water movement [33]. A graph to determine the source of iodine in the water sample according to 129I/I ratio has been prepared [148]. The usage of iodine isotope (129I) in petroleum geology has been examined in detail [16].

2.4.4 Usage of iodine pedogeochemistry in oil and gas exploration It has been observed that iodine concentrations in soils have hydrocarbon accumulations higher than a few times above average value [5,20,21,23,26]. The standard iodine content

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Figure 2.43 The evolution of 129I concentrations in source rocks and reservoir rocks (heavy lines) and the decrease of 129I concentrations after the separation from the source rocks (thin lines). The numerical time scale refers to residence times associated with the decay curves (thin lines), the geological time scale to the age of formations and the buildup curves (heavy lines). Data points are plotted on the uncorrected decay curve, the line above it indicates the decay corrected for the contribution from the production in the reservoir rock. Potential contribution from preanthropogenic meteoric water is also shown in the diagram [84].

of the soil is 1024%. However, the iodine content in soils in oil and gas deposits increases until 103% or 102% [179]. In many studies, iodine pedogeochemistry has been used as a geochemical method for petroleum exploration [5,21,23,25
27,30,31,180,181]. Sampling and analysis of iodine pedogeochemical surveys are much simpler than that of soil gas. If sufficient samples are collected, the interpretation of results is easy. Unlike gases or liquids, iodine compounds are more stable. Iodine compounds in the soil are not easily affected by barometric pressure fluctuations, sudden changes in amounts of soil gas, soil wetting, or drying or changes affecting evaporation of water in the soil. An essential advantage of the iodine pedogeochemical survey is the easy and cost-effective repeatability of measurements. Also, the simplicity of sampling and analysis reduces error probability. The iodine pedogeochemistry survey has been tested on soils above many oil and gas fields which exploration studies have been completed and in production [26]. Many studies, a positive correlation between iodine and seismic anomalies was seen (Fig. 2.44) [26,31,181]. The usage of iodine pedogeochemistry in oil and gas exploration has been examined in detail [16].

A biophilic material in petroleum exploration and production: iodine

Figure 2.44 The relationship between interpreted seismic measurement and iodine pedogeochemistry measurements along a seismic line [26].

2.4.5 Usage of iodine hydrogeochemistry during well drilling The change of iodine content with depth has been studied, and usability as an indicator of whether there is commercial oil or gas in well during oilwell drilling of change of iodine content has been evaluated (Fig. 2.45). For this purpose, total iodine concentrations (mg/L) of the waters separated from drilling mud samples (well inlet and outlet) taken as parallel to penetration during oil well drilling has been detected. Iodine analyses have been carried out by means of titration and UV spectrophotometer based on the Hach method [182] in laboratories [18]. The iodine content in the well increased in parallel with the increase in depth up to the oil zone. In the well which started with drilling mud containing 0.20 mg/L iodine at 100 m depth, the content of iodine of drilling mud increased to over 1 mg/L. when the well reached a depth of 700 m. At a depth of 2000 m, the content of iodine of drilling mud suddenly increases to 10.72 mg/L. This zone is the water zone (containing gas 1 condensate?) above the oil zone. In the oil zone, the iodine content of drilling is significantly decreased (average 0.55 mg/L), because, the content of the iodine of crude oil is ,1 mg/L [100
103]. At a depth of 2330 m, it enters from the oil zone to the lower water zone. In this zone, the iodine content of drilling

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Figure 2.45 Identification of the oil zone by iodine analysis performed in drilling mud during oilwell drilling [18].

mud increases yet again (.1 mg/L). Therefore the oil well terminates at a depth of 2337 m. Perforation zones (oil zones) determined through geophysical logs and oil zones are compatible with oil zones determined by drilling mud iodine analysis. From nonwater oil wells, 512 barrels/day of net oil is produced [18].

A biophilic material in petroleum exploration and production: iodine

By performing iodine analysis on mud samples during drilling, it may be possible to determination whether there is commercial oil or gas in the well. Moreover, the zone(s) perforated in the well and the prediction of the volume of oil produced from it may also be determined (from increases/peaks in iodine contents of drilling mud both in entrance and exit of oil zone) [18]. Moreover, this data shows that iodine could be used as an excellent hydrocarbon accumulation indicator during both the exploration and drilling. In case there is no iodine increase in the drilling mud after a certain depth during the penetration in the well (if iodine content is ,1 mg/L), the well can be terminated before the planned depth. Thus, the drilling can be economized. Furthermore, before the blowout, it is thought that the blow-out zones can be determined from sudden increases in the content of the iodine of the drilling mud. With this method, precautions can be taken to prevent blow-outs. The iodine contents of fields where carbonate source rocks, are very low according to fields where there are shale source rocks. In the well drilled in the hydrocarbon fields formed by both source rock groups, the iodine can be measured from drilling mud and is a good indicator for the presence of oil in the well.

2.5 Iodine hydrogeochemistry in reservoir evaluation and oil production Water chemistry data in western Siberia (Russia) is used to estimate the amount and phase composition of hydrocarbons in reservoirs. Water chemistry data are useful indicators for migration processes as well as the formation of hydrocarbon accumulations and phase stages. The amount of total dissolved solids and content of salt ions (Na, Ca, Mg, Cl, HCO3, and others), trace elements (I, B, Br) and dissolved gases have an essential effect on the reservoir potential [112,183
185]. The amounts of water produced are different in oil and gas production fields. The quantity of water produced depends on the oil extraction technology and reservoir characteristics. Generally, gas wells contain less water than oil wells [186,187]. The average global water/oil ratio is 2/1
3/1, but in the United States it is 7/1. According to the produced water researches of the API (The American Petroleum Institute), the amount of produced water increases as a result of the age of the oil production wells. In older wells in the United States, this value can be increased up to .50/1 [188]. In studies of API, the oil/water ratio has been calculated at approximately 7.5 barrels of water per barrel of water. In oil wells which have reached the end of production, the amount of water can be 10
20 barrels for each barrel of oil. When water management costs become high, the oil well becomes uneconomical [188,189]. In the oilfields of the Cambay basin where formation waters with low iodine content are located, it is known that a vast amount of water is produced together with oil. The Ahmedabad oilfield including 25 subfields has been producing oil for more

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than 50 years. These fields have problems such as being multilayer, heterogeneous, low permeable, low producing, and containing tight reservoirs. These difficulties cause various exploration and production challenges (water injection to the reservoir, etc.) to extract oil and gas from this basin. Similarly, the iodine contents of reservoir waters are low in Southeastern Anatolia basin, and a vast amount of water is produced together with oil. In addition, there are exploration and production difficulties similar to the Cambay basin [18,190,191]. The waters/fluids produced from the reservoir and injected into the reservoir to increase production are the undesirable elements in the oil and gas production areas in terms of increased production costs and environmental impacts. Therefore it is desirable to produce as much oil or gas as possible from the production wells and as little water as possible.

2.5.1 The relationships between oil (bbl)/water (bbl) ratios, water% (bbl) ratios, and iodine contents of formation waters In the oil and gas fields in the Southeastern Anatolia basin (Turkey) the relations between oil (bbl)/water (bbl) ratios and water% (bbl) ratios, the iodine contents of formation waters of production wells have been examined. A significant relationship has been found between the measured iodine contents and Cumulative Oil (bbl)/Water (bbl) ratios. As the iodine content increased, the oil (bbl)/water (bbl) ratio also increased (Fig. 2.46). There was also a significant relationship between the iodine

Figure 2.46 The relationship between iodine content of formation waters and cumulative production oil (bbl)/water (bbl) ratios in oilfields of the Southeastern Anatolia basin [18].

A biophilic material in petroleum exploration and production: iodine

Figure 2.47 The relationship between iodine contents of formation waters and %water (bbl) ratios in oilfields of the Southeastern Anatolia basin [18].

contents and water% (bbl) ratio. As the iodine content increased, the water% (bbl) ratio decreased (Fig. 2.47) [18]. The relationship between iodine and organic matter/organic carbon is linear. Therefore iodine contents of reservoir waters (petroleum saturation, oil/water ratio) are high in petroliferous basins found in source rocks containing high organic matter (kerogen). In this case, the water saturation (water% ratio) of production wells will decrease because the abundance of iodine in formation waters is due to the release of most of the iodine in organic matter into related water during the transformation of organic matter to petroleum [18].

2.5.2 The relationship between iodine contents of formation waters and oilfield reserves The relationship between the iodine contents of formation waters and reserves of some basins containing giant oil and gas fields of the United States, the oilfields in Southeastern Anatolia (Turkey) and Cambay (India) basins are given in Fig. 2.48 (giant oilfield .500 million bbls of oil or oil equivalent gas reserve oilfield). The reserves of fields are increased as the iodine contents of reservoir waters increase. Therefore reserves of fields will also be high in basins where there is a high iodine content in the waters because iodine enrichment is a sensitive indicator for the history of the buried iodine-rich organic matter. Thus the iodine contents of waters will be high due to the fast sedimentation and high carbon deposition rate in basins where giant oil and gas fields are located. In basins

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Figure 2.48 The relationship between reserves and iodine contents of formation waters in US basins containing giant oil and gas fields, and main oilfields of Southeastern Anatolia (Turkey) and Cambay (India) [18].

where there are low reserve oil and gas fields, the iodine content of water will be low due to slow sedimentation and the low carbon deposition rate and release of iodine into the sea [18].

2.6 Conclusions 1. All waters of the world’s petroleum production basins are not saline, but all of them are rich in iodine. Iodine-rich waters are a direct indicator for oil and gas reservoirs (containing mature petroleum hydrocarbons). 2. Iodine-rich waters are paleo-sea porewaters derived from kerogen-containing sediments that have generated oil throughout geological times and have sent mature hydrocarbons into reservoir rock. Iodine-rich waters have been deposited together with hydrocarbons in the reservoir rock. 3. Iodine-rich waters are also rich in mature petroleum hydrocarbons (the age of the iodine in the formation waters is also the age of hydrocarbons in the basin). 4. Hydrocarbons and iodine-rich waters may be derived from the reservoir in the subsurface to surface by geological events (tectonism, volcanism, etc.). Surface hydrocarbons seeps, which are direct indicators of a petroleum system in the subsurface may be degraded or volatilizable by atmospheric effects. But iodine is a stable biophilic element and does not volatilize. It is the main reason why iodine

A biophilic material in petroleum exploration and production: iodine

5. 6.

7.

8.

9.

10. 11.

is an excellent surface exploration material. Due to this feature, iodine provides an advantage according to TOC, etc. parameters. Iodine-rich waters containing mature petroleum hydrocarbons detected in many different locations in a region/ basin will naturally increase the chances of discovering an economic deposit in the exploration area. Instead of a hydrocarbon seep or source rock that has lost its volatile components by atmospheric and geological effects, it would be more appropriate to use a surface survey method examining with organic geochemical and stable iodine isotope (129I) methods of hydrocarbons- and iodine-rich waters which same age and origin with possible petroleum deposits in exploration area. Because iodine-rich waters provide proving from the surface or near-surface levels of the presence of oil or gas deposits in the subsurface. All organic geochemical analyses performed on rock and gas samples can also be applied to iodine- and hydrocarbons-rich waters. For oil and gas exploration in active tectonic (dynamically “excited”—“unbalanced”) and geologically complex basins, a more suitable integrated use of reservoir-targeted iodine geochemistry (water and soil) and oil in water analysis [Total Petroleum Hydrocarbons (TPH)] instead of the source rock-targeted organic rock and gas geochemistry can be employed. The integrated method has a significant advantage like providing a sampling of the richness for exploration in the basin/regions where a large number of water resources are available and proving of the presence of oil and gas deposits be demonstrated from a large number of samples. Through this feature of iodine-rich waters, the chances of discovering commercial hydrocarbon accumulations will be increased. Iodine-rich waters are an especially unique geochemical tool for petroleum exploration in basins/regions, where source rocks are not exposed at surface as outcrops (covered basins) or have been exhausted (depleted, spent). By performing iodine analysis on mud samples during drilling, it may be possible to determination whether there is commercial oil or gas in the well. Moreover, the zone(s) perforated in the well and the prediction of the volume of oil produced from it may also be determined. The iodine contents of reservoir waters (petroleum saturation, oil/water ratio) are high in petroliferous basins where source rocks containing high organic matter (kerogen) are found. In this case, the water saturation (water% ratio) of production wells will decrease. Reserves of oilfields are increased as the iodine contents of reservoir waters increase. Iodine analyses performed on wells of oilfields at the production stage will provide significant contributions in selecting new well locations and accordingly determining the direction of field development.

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63. [178] P.H. Santschi, C. Xu, S. Zhang, K.A. Schwehr, R. Grandbois, D.I. Kaplan, et al., Iodine and plutonium association with natural organic matter: a review of recent advances, Appl. Geochem. (2016). Available from: https://doi.org/10.1016/j.apgeochem.2016.11.009. [179] V.A., Kovda, P.S. Salvin, Soil-geochemical indicators of deep oil bearing rocks: Akad. Nauk. SSSR (Kartsev, A.A., Tabasaranskii, S.A., Subbota, M.I. and Mogilevsky, G.A., 1954). Geochemical methods of prospecting and exploration for petroleum and natural gas (in P. A. Witherspoon and W. D, Romey, eds., English translation: Berkeley, Univ. Calif. Press, 1959, 238 p) (1951). [180] X. Xuejing, Y. Binzhong, Application of multiparametric geochemical methods in the search for oil in the Qinggang region near Daqing oil field, J. Geochem. Explor. 33 (1989) 203
213. [181] B.I. Collinsa, S.A. Tedesco, W.F. Martin, Integrated petroleum project evaluation three examples from the Denver-Julesburg Basin, Colorado, J. Geochem. Explor. 43 (1992) 67
89. [182] Hach Chemical Co, DPD method for iodine (adapted Palin, A.T., 1967. Method for the determination, in water, of free and combined available chlorine, chlorine dioxide and chlorite, bromine, iodine, and ozone, using diethyl-p-phenylene diamine -DPD, J. Inst. Water Eng. 21 (1992) 537
547. [183] T.V. Pogodaeva, T.I. Zemskaya, L.P. Golobokova, O.M. Khlystov, H. Minami, H. Sakagami, Chemical composition of pore waters of bottom sediments in different Baikal basins, Russian Geol. Geophys. 48 (11) (2007) 886
900 (1144-1160). [184] C.L. Shvartsev, D.A. Novikov, The nature of vertical hydrogeochemical zoning of petroleum deposits (exemplified by the Nadym-Taz interfluve, West Siberia), Russian Geol. Geophys. 45 (8) (2004) 1008
1020 (960-972). [185] V.S. Surkov, A.M. Kazakov, V.P. Devyatov, L.V. Smirnov, O.V. Shiganova, A.E. Ekhanin, et al., Lower-middle Jurassic strata of the southern West Siberia (geochemistry, groundwater geology, and petroleum potential), Geologiya Nefti i Gaza 3-4 (1999) 3
11. [186] J.C. Campos, R.M.H. Borges, A.M.O. Filho, R. Nobrega, G.L. Sant’Anna Jr., Oilfield wastewater treatment by combined microfiltration and biological processes, Water Res. 36 (2002) 95
104. [187] X. Qiao, Z. Zhang, J. Yu, X. Ye, Performance characteristics of a hybrid membrane pilot-scale plant for oilfield-produced wastewater, Desalination 225 (1
3) (2008) 113
122. [188] J.A. Veil, Comparison of two international approaches to controlling risk from produced water discharges. Paper presented at the 70th PERF meeting, Paris, France, 2006. [189] R., Lee, R., Seright, M., Hightower, A., Sattler, M., Cather, B., McPherson, et al., Strategies for Produced Water Handling in New Mexico. Groundwater Protection Council Produced Water Conference, 2002. Available from: http://www.gwpc.org/meetings/special/PW%202002/Papers/ Robert_Lee_PWC2002.pdf. [190] B. Rebary, M. Raichura, S.R. Mangukia, R. Patidar, Mapping of iodine, lithium and strontium in oilfield water of Cambay basin, Gujarat, J. Geol. Soc. India 83 (2014) 669
675. [191] A., Gupta, P. Gupta, E. Saxena, First application of Multistage Fracturing Technology in onshore field of ONGC - A new breakthrough. PETROTECH-2016, 12th International Oil & Gas Conference and Exhibition. New Delhi, ˙India, Technical Paper. 2016. Available from: http:// petrotech.in/uploadfiles/434id_Abstract%20for%20Multistage%20Fracturing.pdf.

CHAPTER THREE

Advanced materials and sensors in well logging, drilling, and completion operations Sercan Gul1, Javid Shiriyev1, Vivek Singhal1, Oney Erge1 and Cenk Temizel2 1 Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, United States 2 Saudi Aramco, Dhahran, Kingdom of Saudi Arabia

3.1 Introduction This chapter explains some of the recent advancements and developments in the materials and sensor used in well logging, drilling, and well completion operations. The chapter is composed of three main sections. Section 3.2 explains the advanced sensors used in well logging operations. Well logging operations are, by nature, related to obtaining downhole data from various depths and processing this data to get a further understanding of the downhole formations and fluids. In the last decades, most of the advancements on the area was done in microseismic imaging (Section 3.2.1), tiltmeter mapping (Section 3.2.2), and electromagnetic-based deep reservoir monitoring (Section 3.2.3). Section 3.3 explains the advanced sensing systems used in drilling and well completion operations. Section 3.3.1 explains the fiber optic sensors. Using this technology, obtaining distributed data from downhole in static or dynamic conditions became a reality. Section 3.3.2 explains the most advanced three-dimensional (3D) computer vision techniques for cuttings monitoring. Section 3.3.3 summarizes the advancements on difficult to automate measurements of drilling and completion fluids (automated fluid rheology and density, high-pressure mass flow rate, etc.). Section 3.4 is related further with advanced materials. There has been many advancements on the materials used in the oil and gas industry, such as the alloys of chemical compositions of drill bits and casings, composite systems, etc. However, it is not possible to explain everything in one book chapter. Therefore only some selected advanced materials (nanoparticles in drilling fluids, altered fracturing fluid, and proppants and chemical tracers) are explained in Section 3.4.

Sustainable Materials for Oil and Gas Applications. DOI: https://doi.org/10.1016/B978-0-12-824380-0.00004-9

© 2021 Elsevier Inc. All rights reserved.

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3.2 Advanced sensors in well logging operations 3.2.1 Microseismic imaging Microseismic imaging is one of the widely used hydraulic fracture monitoring tools in the industry. The objective of the imaging is to define the fracture growth characteristics during the fracturing operations. Its real-time visualization capabilities can be used to assess the effectiveness of the fracture growth in the presence of complex natural fracture geometries. The two most common outputs of microseismic monitoring are the location of events and their magnitude where the activity map helps to determine fracture height, length, and azimuth. In particular, the activity map locates the activated fractures and outlines the stimulated reservoir volume. This fracturing imaging technique relies on the detection of micro-earthquakes or acoustic emissions associated with seismic emission generated by rock failure events during or after the operations. The hydraulic fracturing induces an increase in the formation stress and an increase in pore pressure. Large tensile stresses are formed ahead of the crack tip, and these create large amounts of shear stress. Both mechanisms affect the stability of planes of weakness, such as natural fractures and bedding planes, surrounding the hydraulic fracture and, therefore, cause them to undergo shear slippage. These shear movements emit both compressional (P-waves) and shear (S-waves) waves which can be detected on the offset wells not to interfere with the operational noises in the treatment well. A typical application requires the installation of seismic sensors, usually geophones, in the observation well (Fig. 3.1). An array of triaxial geophones can be deployed on a specialized

Figure 3.1 Diagram showing the deployment of microseismic tools and the treatment well [1].

Advanced materials and sensors in well logging, drilling, and completion operations

fiber optic wireline. This offset well can be several hundred meters away from the respective treatment well. The distance to the microseismic events can be calculated by measuring the arrival time delay between the compression and shear waves also requiring an accurate formation velocity model that typically are built using sonic logs, a low-noise environment, highly sensitive geophones, knowledge of the exact location, and orientation of the receivers. The geophone orientation in the tool string can be determined using the released seismic energy during perforation shots in the treatment wells. The quality of azimuth measurements is evaluated using hodogram consistency analysis. The hodogram variation shows the difference between the individual sensor azimuth and the average azimuth for each event, and either P-waves or S-waves are used to calculate the azimuth. The microseismic monitoring technique has been implemented all around the world [2
4], and in summary, microseismic events have been detected a few hundred meters away from the wellbore where the majority of events are located in the first hundred meters.

3.2.2 Tiltmeter mapping Tiltmeter is one of the other earlier diagnostic methods that have been used for fracture mapping. It is based on the deformation monitoring created in the rock surrounding due to the induced fractures, and the observation can be carried either on the surface or downhole (Fig. 3.2). In the surface deployment of tiltmeters, the tilt of the earth at several locations is measured to obtain the fracture azimuth. The surface monitoring prevents the detection of fracture length and height due to the loss in the resolution with the distance to the events [5,6]. In the downhole deployment of tiltmeters, sensors are placed in one

Figure 3.2 The principle of tiltmeter fracture mapping [5].

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or a few monitor wells next to the treatment well, and the deformations in the proximity to the fracture can be better captured [7,8].

3.2.3 Electromagnetic-based deep reservoir monitoring Electromagnetic monitoring techniques are based on the alteration of proppant characteristics and deployment of electromagnetic acquisition techniques to locate those proppants. In the field applications, the Electromagnetic (EM) property contrast between the proppants and the surrounding formation is usually achieved by increasing electrical conductivity of proppants [9], although in theory, the contrast can also be achieved by increasing the proppant’s magnetic permeability and electrical permittivity [10]. A variety of field data acquisition techniques can be implemented to sense the EM fields scattered from proppants with high electrical conductivity contrast over the background shale. One acquisition technique, employed in [9,11,12], is to use receiver arrays densely deployed on the surface to sense the response to an electric current emitted into the subsurface by electrodes (Fig. 3.3). While the spatially dense surface receiver array allows for relatively extensive coverage of the stimulated area, this transmitter
receiver coupling is inherently depth limited. As the source-observer distance increases, EM fields are significantly attenuated by the overburden layers greatly obfuscating the signals of interest. This limitation can be considerably mitigated by utilizing source/observers in the vicinity of propped hydraulic fractures. In Shiriyev et al. [14], such a low-frequency induction tool, where both sources and observers (triaxial induction coils) are placed on the same backbone, were experimentally and numerically studied and found to be

Figure 3.3 A mapped propped fracture volume [13].

Advanced materials and sensors in well logging, drilling, and completion operations

Figure 3.4 A schematic of the low-frequency induction tool for fracture mapping in an open-hole wellbore [14].

sensitive to various propped fracture properties in open-hole completion wells. In such a typical application, the low-frequency induction tool is shown to be accurately detecting proppant location 40 m beyond the wellbore. Typically, the tool is composed of one transmitter and two receiver coils (Fig. 3.4). The transmitter coil pulses EM fields that induce currents on the surface of the fracture. This current emits secondary EM fields, which carries the information of the propped fracture geometry and is captured by the receivers. While working well for open-hole completions, these methods are still expected to fail when operated within a highly conductive steel casing.

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Figure 3.5 A schematic of the electrode-based measurements outside of the casing. Inside the well are the coiled tubing and BHA. The numbered blocks indicate insulating gaps and the curved line “a” and “b” depict hydraulic fractures [17].

Another way of monitoring fractures in the vicinity can be possible by direct excitation of the casing itself enabling resistivity measurements in the cased-hole applications [15,16]. Using this idea, a novel concept of an electrode-based resistivity tool was proposed in Ref. [17] (Fig. 3.5). It makes use of standard steel casing sections, separated by insulating gaps, and makes measurements in the same well. Each pair of casing sections, connected by a thin gap section, can be excited independently by a bottom-hole assembly, such that the casing pair acts as a transmitter. When not excited, a casing pair separated by the gap serves as a receiver, recording information on the fractures in contact with the casing.

3.3 Advanced sensors in drilling and well completion operations 3.3.1 Fiber optic sensors Transmitting information (or data) from one place to another is performed by communication systems. An electromagnetic carrier wave often carries this information with a frequency in the range of 1 MHzmegahertz to 100 THz [18]. Systems which use optical communication use high carrying frequencies and therefore are called as lightwave systems. Fiber optic communication systems are an example of lightwave systems which uses optical fibers to transmit information from one point to another whether it is separated by several or 1000 km [18]. Fiber optic systems are used in different forms in the oil and gas industry since they enable distributed measurements throughout the well. Some of the most used types of fiber optic (distributed) sensing methods are as below: • Distributed temperature sensing • Distributed acoustic sensing • Distributed strain sensing

Advanced materials and sensors in well logging, drilling, and completion operations

In the last decade, distributed sensing technology was applied to various areas in the oil and gas industry with special interest in well completion operations. Some well completion operations where fiber optic sensing can be applied are listed as below: • Steam injection profiling [19] • Water injection profiling [20] • Acid injection profiling [21] • Hydraulic fracturing diagnostics [22] • Real-time cement displacement tracking [23] • Downhole leak determination [24] Fiber optics do not only provide continuous monitoring. Full-length wellbore characteristics can also be transferred to the surface in real-time using this system. Therefore applications of fiber optic sensing technology are not limited to the above. The system can be used when it is necessary to obtain distributed measurements from wellbores in real-time. It requires no installation of downhole equipment and does not intervene in the operations. There are no electrical wires, no sensors, no electrical connections, or electronics along the line. A single fiber optic cable temporarily or permanently installed in the well provides the distributed measurement along the wellbore [25]. Fiber optic sensing works by probing a line by a short laser light pulse. That pulse travels along the fiber and collides with the atoms and the lattice structure of the fiber. As also illustrated in Fig. 3.6, this causes them to emit small amounts of light at various frequencies which travel back to the beginning of the fiber. Using the instrumentation box, this back-reflected light is analyzed which determines the distributed measurements at the point from which the back-reflection occurred [25]. It is known that the velocity of light is constant everywhere, even in fiber. Therefore the travel time between the first origination of the pulse and the back-reflection is used to determine the position of the recorded measurements. Continuous measurement of this enables

Figure 3.6 Illustration of the traveling light pulse, sensing back-reflected light back to the instrumentation box [25].

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Figure 3.7 Protection of fiber lines used in oil and gas downhole environments. Example of protection methods for using only one multimode fiber line (A) or one multimode fiber line with two single mode or other types lines (B). [25].

the generation of continuous real-time distributed measurements. Such a measurement profile is called as distributed sensing or distributed sensor [25]. Fiber is too fragile to be used by itself in oil and gas operations. For this reason, they must be protected using steel capillary tubes (mostly a 3 mm stainless-steel pipe) and plastic sheaths which are further protected by another steel tube and rugged plastic housing. Fig. 3.7 shows an example of protection methods for using only one multimode fiber line (a) or one multimode fiber line with two single mode or other types lines (b). There are various options in fiber optic distributed sensor installations in oil and gas wells. These can be categorized as retrievable, semipermanent, and permanent type installations. In a retrievable installation, fiber optic line is run into the well using a steel capillary tube which has a diameter of about 3 mm. There are various ways of using semipermanent applications. The first option is to run the fiber optic line through coiled tubing and leave it in place for continuous and periodic measurements. The second option could be to use a stainless-steel capillary tube which is strapped outside of the production casing and run the fiber optic line into this tube [25]. The permanent application can be done by installing the fiber optic line behind the casing while cementing the well [23]. In this situation, the capillary tube cannot be pulled easily from the well. In terms of the deployment of the fiber, there are four primary methods; single end straight fiber, single end straight fiber with downhole temperature gauge, partially returned fiber, and double ended fiber. During field applications, the further analysis shall be performed to choose the deployment methods since they all have advantages or disadvantages within each other (which is further related to cost and calibration of the systems) [25].

Advanced materials and sensors in well logging, drilling, and completion operations

3.3.2 Three-dimensional computer vision techniques The application of 3D computer vision techniques in the oil and gas industry (especially drilling or well completion) is of high importance for automated operations. The most recent advancement in applying this technology is on the real-time borehole condition monitoring which uses new 3D cuttings sensing technology [26]. The distance between a target surface and the sensor’s reference position are measured using 3D vision techniques. Moreover, the same technology allows to range measurements, 3D modeling, object detection, and many other sensing applications [26]. To achieve this, various technologies in photonics, electronics, and computer vision are applied together [26]. Stereo vision, time-of-flight and structured light (fixed pattern and programmable pattern) are the three major depth sensing techniques. Sections 3.3.2.1, 3.3.2.2, and 3.3.2.3 introduce stereo vision, time-of-flight, and structured light systems, respectively. Further detail on the application of 3D computer vision technology in the oil and gas industry by 3D cuttings sensing technology is explained in Section 3.3.2.4. 3.3.2.1 Stereo vision Stereo vision technique employs two cameras which are positioned parallel to each other. For the application, the cameras should have the same focal length as their X-axis intersecting and aligning with the baseline. Fig. 3.8 illustrates a typical stereo vision system [27]. Eqs. (3.1) and (3.2) [27] are used to calculate the projections of point P, where Eq. (3.1) is for the image acquired by the left camera and Eq. (3.2) is for the image

Figure 3.8 Typical stereo vision system. Retrieved from National Instruments [27].

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acquired by the right camera, respectively. XA ZA

(3.1)

XA 2 b ZA

(3.2)

uL 5 f uR 5 f

where b is the baseline, f is the focal length of camera, uL and uR are the projections of the real-world point P in an image acquired by the left and right cameras, XA is the X-axis of a camera, ZA is the optical axis of a camera, P is a real-world point defined by the coordinates X, Y, and Z. The distance between conjugate points (also referred to as disparsity—d) is calculated using Eq. (3.3) [27]. b (3.3) ZA where b is the baseline, f is the focal length of the camera, ZA is the optical axis of a camera, uL and uR are the projections of the real-world point P in an image acquired by the left and right cameras. Due to the required computational time, this system is mostly used for 3D scanning of static objects or scans performed at low frequencies [26]. d 5 ðuL 2 uR Þ 5 f

3.3.2.2 Time-of-flight 3D Time-of-flight (TOF) provides 3D imaging by active modulated light source together with a complementary metal-oxide-semiconductor pixel array. As illustrated in Fig. 3.9, a 3D TOF illuminates the scene with a modulated light source [28]. The system measures the shifting in phases between the reflection and illumination, which is then transferred to distance. The illumination is generated by a light-emitting diode or solid-state laser, which operates in the range of near-infrared (B850 nm) [28]. The photonic energy is

Figure 3.9 3D time-of-flight camera operation. Retrieved from Texas Instruments [28].

Advanced materials and sensors in well logging, drilling, and completion operations

converted to electrical current by the imaging sensor, which receives the reflection of generated light. Depth or distance information is therefore embedded only in the reflected component [28]. The source is typically a square or sinusoidal wave. However, the first is more common due to the ease of use in digital circuits [28]. The system is advantageous due to fast computational speed, high-resolution, and low cost [26]. However, if the emitted light wavelength is in the range of background light, there might be suppressions in the detection sensitivity [28]. 3.3.2.3 Structured light vision Composed of one or more cameras and light sources, structured light vision (also known as “active stereo” or “white light scanning” [29]) is suitable for operations in controlled (i.e., industrial, medical, etc.) or poorly lighted (i.e., submarine, confined space, etc.) environments [30]. The system projects a band of light onto the target’s surface, and the distorted light pattern on the surface is observed using the cameras [26,30]. The pattern is composed of gray codes, light stripes, sine waves, or speckle patterns [31] as illustrated in Fig. 3.10. Using various algorithms [32], the 3D geometric profile or shape of the target source can be computed by the distorted light pattern. Projection and laser interference are the two major techniques to generate the pattern [26]. The projection technique works by emitting the incoherent light with a coded pattern. This system does not make a line by line scan but takes a full snap over a target’s surface. For this reason, this technique is affected by the changes in the ambient lighting environment. On the other hand, laser interference scans the line pattern and makes the height calculation by the triangulation method. This technique can be used at higher frequencies compared to the projection technique and is less affected by the changes in ambient lighting conditions [26]. Table 3.1 summarizes the advantages and disadvantages of each of the mentioned 3D computer vision techniques (stereoscopic vision, time-of-flight, and structured

Figure 3.10 Illustration of structured light [31].

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Table 3.1 Comparisons of 3D vision sensor technologies [33]. Stereoscopic vision

Depth Accuracy mm to cm The difficulty with a smooth surface Scanning speed Medium Limited by software complexity Distance range Midrange

Low light performance Outdoor performance

Software complexity Material cost

Time of flight

Structured light Fixed pattern

Programmable pattern

mm to cm Depends on the resolution of the sensor

mm to cm

um to mm Variable patterns and different light sources improve accuracy

Fast Limited by sensor speed

Fast Limited by camera speed

Fast/medium Limited by camera speed

Weak

Short to long range Very short to midrange Very short to midrange Depends on Depends on Depends on laser illumination power illumination power power and modulation Good Good Good

Good

Fair

High

Depends on Depends on illumination power illumination power Low Low/middle

Depends on illumination power Middle/high

Low

Middle

Middle/high

Weak/fair

Middle

Weak/fair

light) according to their depth accuracy, scanning speed, distance range, low light performance, outdoor performance, software complexity, and material cost. 3.3.2.4 2D and 3D integrated cuttings sensing technology 3D cuttings sensing technology uses a 2D high-resolution camera and a 2D/3D laser sensor, which uses structured light vision technology, to measure properties of cuttings or cavings generated during drilling. This sensor is connected in front of the shale shaker sliding ramp and can provide cutting and caving volume, size distribution, and shape profile in real-time [26], as shown in Fig. 3.11. The volume measurements can be done by using a 2D laser profile scanner, which measures the distance to the target’s surface, and reconstructing the 3D depth profile using accurate moving speed input. The speed measurements are also done using an algorithm which evaluates the difference in the obtained 2D images at every time increment [26]. Size distribution and shape profile (caving detection) analysis require using a 2D highresolution camera and a 3D profile laser scanner. This system collects point depth and cloud data of particles passing through the shale shaker. Computer vision, machine learning, and artificial neural networks (ANNs) algorithms are applied to provide the shape profile (e.g., angularity, flatness, etc.) and size distribution of cuttings and cavings in real-time [26].

Advanced materials and sensors in well logging, drilling, and completion operations

Figure 3.11 2D and 3D integrated cuttings sensor connected on the shale shakers [26].

3.3.3 Fluid measurement sensors 3.3.3.1 Automated fluid rheology and density The quality of a drilling or completion fluid is significant for the success of a well construction operation [34]. The properties of these fluids (both physical and chemical) are subject to change as the fluid circulates in the wellbore due to various reasons such as contamination of formation clays, shear or thermal degradation [35], bacteria development [36], etc. Various chemical additives are used during drilling for maintenance of the fluid [37]. The optimum maintenance of these fluids, however, requires frequent and accurate fluid property measurements [38]. There are various sensors which can provide physical and chemical properties of Newtonian fluids in real-time (e.g., viscosity, density, pH, conductivity, etc.). However, the fluids used in drilling and well completion operations have more complex characteristics compared to Newtonian fluids. Drilling fluids are shear thinning fluids, which is an essential property for hole cleaning [34]. In current practice, such measurements are conducted by a mud engineer at the rig site using test protocols and equipment as standardized by API 13B-1 and 13B-2 [39]. However, these tests are intermittent, and the test results are only available two times a day [38]. They are performed at atmospheric pressures and room temperatures, which is mostly not reflecting the downhole conditions. Moreover, there exists a bias due to the human factor, and the results of reported parameters are subject to change depending on the mud engineer’s experience. Out of all the parameters characterizing a non-Newtonian fluid, the two most important ones are the fluid density and rheology. The most recent development in measuring both in near real-time is by a pipe viscometer [39] together with another inline sensor called as a Coriolis meter, which provides density and temperature measurements. A schematic of a pipe viscometer is shown in Fig. 3.12. A pipe viscometer has a differential pressure sensor in the straight pipe test section. By a positive displacement pump connected to itself, the pipe viscometer records

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Figure 3.12 Schematic of a pipe viscometer system [39].

Figure 3.13 Schematic of a Coriolis flow and density meter. Retrieved from Micro Motion.

the frictional pressure loss of a tested fluid in different flow rates [39]. Another advantage of the pipe viscometer is, by connecting the system to a heating unit, the fluids can be tested at elevated temperatures [35]. For higher accuracies, the flow rate and density measurements are conducted using a Coriolis flow meter, which is illustrated in Fig. 3.13. The Coriolis meter is the most accurate of the commonly used industrial flow sensors since its introduction [40]. A Coriolis meter operates by oscillating a flow tube (Fig. 3.13) during fluid flow through themselves. Two sensors (electromagnetic velocity detectors) monitor the vibration in the tube oscillation in this process. For a given flow tube, the frequency in the oscillation varies with fluid density. Hence, accurate measurement of the frequency of vibration enables the fluid density to be calculated [40]. Moreover, the Coriolis forces during the flow create a phase difference between the two electromagnetic velocity detectors. Mass flow rate calculations are made from this difference. Therefore using one sensor, two different parameters (mass flow rate and density) during process flow can be measured in real-time. It should be noted that Coriolis flow meters have pressure limitations for their operations. A high-pressure mass flow rate and density measurement sensor is explained in Section 3.3.2.

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3.3.3.1.1 Obtaining the rheological parameters

In a pipe with known dimensions, wall shear stress can be calculated by the pressure loss data obtained in laminar flow as in Eq. (3.4) [37]. τw 5

D ΔP 4 ΔL

(3.4)

where D is the pipe’s inside diameter (m), ΔP is the measured frictional pressure loss (Pa) in the test section ΔL is the length of the test section (m) and τ w is the wall shear stress (Pa). Eq. (3.5) is used to calculate the velocity of flow in the pipe [37]. v5

4Q πD2

(3.5)

where v is the velocity (m/s), Q is volumetric flow rate (m3/s) and D is the pipe’s inside diameter (m). The Reynolds number can be calculated by mud velocity, density, and the wall shear stress as in Eq. (3.6) to verify the flow regime during the rheology test. For the next steps, it is essential to eliminate the data in the turbulent flow regime (i.e., Re . 2100) to have accurate non-Newtonian fluid rheological property calculations [37]. Re 5

8ρv 2 τw

(3.6)

where v is the mud velocity (m/s) in the pipe and ρ is the mud density (kg/m3) and τ w is the wall shear stress (Pa). The flow behavior index (N) at each flow rate can be calculated using Eq. (3.7) [37]. dðlnτ w Þ N 5  8v d ln D

(3.7)

Once the flow behavior index is known, the shear rate of a non-Newtonian fluid in the pipe can be calculated using Eq. (3.8) [37].   8v 3N 1 1 γ_ 5 D 4N

(3.8)

where γ_ is the shear rate (1/s), v is the velocity (m/s), D is the pipe’s inside diameter (m), and N is the flow behavior index calculated by Eq. (3.7) [37]. Using the shear stress (as obtained from Eq. 3.4) versus. shear rate (as obtained from Eq. 3.8) data, the non-Newtonian rheological constants characterizing a YPL fluid (m, K, and τ y ) can be calculated by curve fitting methods to the Herschel
Bulkley rheology

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equation (Eq. 3.9) [37]. τ w 5 τ y 1 K ðγ_ Þm

(3.9)

where m is the fluid behavior index, K is the consistency index (Pa.sm), τ y is the yield stress (Pa), and γ_ is the shear rate (1/s). 3.3.3.2 Flow rate, density and mass flow rate measurement meters 3.3.3.2.1 Transit time ultrasonic flow meter

Among the various types of noninvasive ultrasonic meters that are available to measure flow rate, the transit time ultrasonic flow meter is the preferred meter in the oil and gas industry given its wide range of applications and high accuracies [41]. It is used in wastewater, chemical, and paper industries, and for measurement of flow rate of fly ash slurries in power stations and multiphase slurries in mining applications [42]. It has an average lifetime of about 6 years and is available as a spool-piece meter or as a noninvasive clamp-on meter. Even though the spool-piece meter has a higher accuracy in comparison to the transit time clamp-on, it is not as commonly used because it is a more invasive meter. The clamp-on meter is particularly suited for applications that require continuity in production. As a result, it has experienced widespread adoption in industries such as nuclear energy and oil and gas production [43]. It has also seen significant interest in recent years due to the noninvasive nature and lower installation costs. The measurement is performed using two piezoelectric transducers, both of which act as an ultrasound transmitter and a receiver. The flow velocity is proportional to the difference between the propagation time of ultrasound in the upstream and downstream direction of flow. The volumetric flow rate is determined by multiplying the calculated velocity by the cross-sectional pipe area. The travel time can be measured accurately to a resolution of about 50 ps [44]. The meter’s conceptual schematic is shown in Fig. 3.14A. With regards to accuracy, for fluid velocities greater than 1 m/s, these meters have typical errors of less than 5%, repeatability, and reproducibility (under unclamping and reclamping conditions) of greater than 99% and 98%, respectively. The meter accuracy deteriorates toward the lower end of its specified flow range [41].

Figure 3.14 (A) Clamp-on transit time ultrasonic flow meter conceptual schematic, (B) transducers in V-mode, (C) waveform conversion diagram, (D) schematic of a pulsed ultrasound Doppler meter.

Advanced materials and sensors in well logging, drilling, and completion operations

The ultrasonic transducer is the most important component of this meter. The transducer must be selected carefully as its characteristics affect the stability and capability of the entire detecting system. It is recommended that both transducers be on the same side of the pipe (V-mode configuration) which also simplifies the calculation of the optimal separation distance between the transducers [45]. Transducers in the V-mode configuration are shown in Fig. 3.14B, where “d” is the propagation distance and “θ0” is the angle of incidence. One of the factors affecting transducer selection is the angle of incidence “θ0” [45]. As shown in Fig. 3.14C, the incident beam (angle “θ0”) is split into a shear (angle “θ1”) and longitudinal wave at the pipe surface. These shear and longitudinal waves continue to propagate as two separate longitudinal waves at the pipe liquid interface. To accurately measure fluid velocity, it is desirable that only one longitudinal wave be transmitted through the pipe wall and to the receiving transducer. This can be achieved by adjusting “θ0.” The critical values that limit “θ0” can be calculated using Snell’s law [45]. Other factors affecting transducer selection are fluid temperature, viscosity, and the required ultrasound frequency (a function of “d”) [45]. A variety of parameters affect meter performance. These include pipe size, material and wall thickness, pipelining material type and thickness, meter location and mounting, surrounding mechanical and electrical noise, other operational conditions, and fluid density [41,42]. Additionally, various coefficients if not properly accounted for can result in errors. They include electromechanical coupling coefficients, transmission coefficients, reception coefficients, various mechanical coefficients, acoustic impedances, and dielectric constants [42]. Errors can also be generated by local variations in temperature, pressure, and density. The meter is not well suited for conditions with solid diameters greater than 1/8th of ultrasound wavelength, high solids content, or presence of air bubbles. Air bubbles affect the speed of sound in the liquid and scatter the ultrasound signal, leading to attenuation and degradation of the signal-to-noise ratio (SNR). Air entrainment over 10% can cause much degradation in measurement accuracy [41]. Particles larger than one wavelength of the ultrasound cause scattering errors, which is also known as the scattering effect. A clustering of particles much smaller than one wavelength may also cause scattering errors, due to local changes in fluid viscosity, known as the viscous effect. Large Reynolds number values and drag created by the particles result in errors due to the inertial effect. The weakening of the ultrasonic wavefront and the breakup of the ultrasonic signals due to these three effects are major sources of error [42]. The resonant and thermal characteristics of some particles can also lead to significant attenuation. To minimize errors that result from changes in fluid viscosity, meter recalibration is recommended. An increase in viscosity results in an increase in ultrasound attenuation [46]. Water, for example, has a kinematic viscosity of 1.003 3 1026 m2/s at 20 C and

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an ultrasound attenuation of 0.22 dB/m at 1 MHz. Castor oil in comparison has a kinematic viscosity of 1.1 3 102 m2/s at 20 C and an attenuation of 95 dB/m at 1 MHz. Since attenuation is proportional to the square of the ultrasound frequency, it is recommended that a lower frequency is used for Castor oil [41]. Also, the transmitter and receivers in these meters use pulsed excitation. Pulsed signals have a fundamental wave mode that is composed of various wave modes, each with their distinct phase velocity. It is straightforward for this fundamental wave mode to get distorted when transmitted through a viscous fluid. The distortion makes it difficult for the fundamental wave mode to be detected by the receiver. Also, in pulse mode the resonance frequencies of the transmitter and receiver are not identical, and vary with temperature independently, resulting in significant measurement errors [46]. Researchers are looking at continuous excitation of the transducers instead of the pulsed excitation [46]. The transmitter and receiver under continuous excitation are forced into excitation by the same signal and are therefore guaranteed to be at a constant known frequency. Moreover, using continuous excitation, excitation energy can be increased by extending the excitation duration without increasing the instantaneous power (which is the case with pulsed excitation), leading to an improvement in the SNR of the receiving waveform. ANNs or machine learning tools are also being used in series with an “ultrasound frequency to voltage converter” and are eliminating the need for calibrations with changes in pipe diameter, liquid density, and liquid temperature. Since the flow profile also influences measured flow velocity, research efforts are also underway to increase the number of sound paths and therefore increase accuracy by eliminating the dependence of flow profile and flow disturbance [44]. 3.3.3.2.2 Pulsed ultrasound Doppler flow meter

A Doppler flow meter works on the principle of reflection of transmitted sound waves by the moving particles (solids/bubbles) in the liquid. The reflected waves have a different frequency than the transmitted sound waves Fig. 3.14D. The difference in frequency between the transmitted and reflected sound waves is proportional to the velocity of the fluid. The Doppler meter can be used to measure an instantaneous one-dimensional velocity profile in opaque fluids along a fixed measurement axis. Its low accuracy and low reliability make it generally unsuitable for oil and gas applications [47]. It is a noninvasive meter which is highly sensitive to temperature variations but is generally not affected by other fluid properties. If temperature corrections are not incorporated accuracies better than 2%
8% are not achievable, especially at the outflow from hot wells with a partially filled pipe [47]. Another limitation of the Doppler technology is its inability to account for changes in sound speed due to changes in particle concentration in the fluid, resulting in measurement errors [48]. For a correct implementation of the Doppler meter, it is required that the transducer probe size and sound frequency be selected based on the application [48].

Advanced materials and sensors in well logging, drilling, and completion operations

The velocity profile using a Doppler meter is typically estimated through a weighted mean of the Doppler power spectra from each depth [49]. Reliable velocities can only be obtained after averaging over several pulses (in some instances greater than a thousand) [48]. The time between two emissions determines the resolution of the velocity profile. If the time between two emissions is long, fast particles will have moved too much to yield echoes that correlate [48]. The Doppler flow meter has poor SNR in the regions close to the conduit walls. Turbulence measurements near the pipe wall, where velocity gradients are high, are very difficult to obtain even for pipes with diameters as large as 46 mm [50]. These turbulence measurements are possible if invasive techniques are used. 3.3.3.2.3 Magnetic flow meter

The conventional magnetic flow meter has two sensing electrodes and operates on the principle of Faraday’s law of electromagnetic induction. The voltage induced across the conductors of the magnetic meter, due to the flowing fluid perpendicularly through the magnetic field, is proportional to the velocity of that fluid. The velocity can then be multiplied by the pipe area to get the volumetric flow rate. Magnetic flow meters have been around since the 1950s and are field-proven devices. These meters can handle up to 41.37 MPa of pressure. Typical lifetime for the fluid passageway through the meter is 10 years and 5 years for the transmitter. It requires less energy to operate compared to an ultrasonic or Venturi meter. The meter is highly accurate, and the output signal is only marginally affected by changes in fluid properties provided the fluid is conductive [47]. It is not a good choice for oil-based, and synthetic-based muds as these muds are nonconductive [51]. It can be used to monitor the flow of a dirty, cuttings-laden, and variable viscosity fluids such as water-based drilling muds [52,53]. Single-phase volumetric axisymmetric flow rate can be measured with an error as low as 6 0.05% [54]. For axisymmetric flow, a straight pipe of at least 5
10 pipe diameters is required before flow enters the meter. This can add to cost and may not always be feasible if space is limited [55]. Meter accuracy greater than 99% can be expected for Reynolds number values greater than 19,000. The accuracy drops considerably for Reynolds number less than 19,000, with values as low as 97% for Reynolds number around 10,000 [56]. The meter accuracy deteriorates with time due to wear of both the tube and the electronics. The meter is unable to distinguish between air and liquids and is therefore not recommended for aerated fluids. When the velocity profile is highly nonuniform, for example, downstream of partially open valves (in single-phase flows), the meter’s accuracy can be severely affected. Lack of axial symmetry can lead to errors of 10% or more [57] and is typically observed in multiphase and cuttings-laden fluid flows in both horizontal and inclined pipes. These variations are weight driven and occur principally in the direction of gravity resulting in a minimum axial velocity at the lower

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side of the pipe cross-section and maximum velocity at the upper side of the pipe cross-section [54]. For single phase, nonaxisymmetric flows, smoothening the magnetic field by increasing the number of electrodes from two to six and making the magnetic field more homogenous (by changing pole geometry), can significantly reduce errors (almost by order of magnitude in some cases). Minor variations of fluid conductivity encountered in the cross-section of multiphase flows only have a minimal effect on the operation of electromagnetic flow meters, especially if the volume fraction of the nonconducting dispersed phase is less than about 0.4 [53]. 3.3.3.2.4 Gamma-ray densitometer

A gamma-ray densitometer (Fig. 3.15) is a very accurate instrument used in the oil and gas industry for fluid bulk density measurement, gas volume fraction (GVF) characterization, and liquid interface identification [58]. It is the most reliable noninvasive (external to process piping) method for measuring the void fraction inside a thick stainless-steel pipe [59]. The density of liquid oil-field slurry, independent of its composition, can be measured within 29.96 kg/m3 of true density. Several commercial multiphase flow meters use gamma-densitometry as part of their measurement systems [60]. The drawbacks of this meter are the logistical challenges it creates for the operator since it requires a radioactive source and the additional costs that go along with it [61]. In addition to the extra paperwork, the source has to be tracked throughout its life and then disposed of in a safe way. It also has to be handled appropriately during storage, transportation, and installation [61]. Gamma-ray densitometry works by comparing the incident gamma rays to the attenuated gamma rays after they have passed through the object whose density is being measured. The densitometer is composed of a gamma-ray source, a collimator, a scintillation detector (operated in count mode), and a data acquisition system that includes an amplifier, a single or multichannel analyzer and a counter [59]. While a single energy source gamma-ray meter is sufficient for two-phase void fraction measurements, a dual-energy

Figure 3.15 A detailed schematic of a single beam gamma-ray densitometer.

Advanced materials and sensors in well logging, drilling, and completion operations

source meter is required for three-phase void fraction measurements. It is essential that a meter is selected such that the detectors are operating in count mode (counting the total number of photons) versus the current mode (measuring the total energy deposited by the photons), to avoid drift in the output signal [62]. The gamma-ray densitometer has two major methods of operation: transmission mode and scattering mode. In the transmission mode, the detector is placed along the centerline of the source, whereas in the scattering mode, multiple detectors are placed at different angles from the source centerline. The transmission-based technique is preferred, as it is more sensitive to density changes and results in greater counting statistics [58,63]. The attenuation of gamma rays at low energies is dominated by the photoelectric effect (a function of material atomic number and incident ray energy). At high energies, as typically used in gamma-ray densitometry, attenuation is dominated by Compton scattering (a function of the material density and the incident ray energy) [60,64,65]. Therefore high energy gamma-ray densitometry is very suitable for determining the density of unknown materials [65]. Density lookup charts for a given source and detector combination can be built using empirical attenuation data from different materials of known density. The density of an unknown material in the field can then be interpolated using these lookup charts and the amount by which it attenuates gamma rays [58]. Homogenous mixing of multiphase or aerated liquids is essential for accurate density predictions [61]. The accuracy depends on parameters such as source-to-detector distance, pipe wall thickness, fluid density, source energy, radiation intensity, and duration over which measurement data is averaged. High accuracy measurements require an exposure time of 50 seconds or greater [66]. The most widely used gamma-ray source is Cs-137, which has a radiation energy of 661.6 keV. Another popular source is Am-241 which has a radiation energy of 59.5 keV [66]. Am-241 has higher sensitivity than Cs-137 when trying to distinguish between low-density phases such as oil and water, or water and air. This is because energies ,100 keV offer a better contrast between the mass absorption coefficients of oil and water. The mass absorption coefficient is low for low-density fluids like water, oil, and air for energies greater than 100 keV. Therefore gamma rays pass through these fluids without much attenuation, making it hard to distinguish between the two due to reduced contrast [66]. Thallium-activated sodium iodide, NaI (TL) scintillators are the most commonly used detectors due to their high light output yields, which result in high efficiency and energy resolution [63]. Detectors are rated on their robustness, stopping efficiency, count rate, and sensitivity to vibrations and temperature. Another common detector used is the semiconductor-based CdZnTe type. These detectors are superior but significantly more expensive than the NaI(TL) [67]. A data acquisition system and a data processing system are also needed to interpret the data collected by the detectors.

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Gamma-ray technology is also used to determine air content in the fluid. Dualenergy gamma-ray detection results in higher accuracy compared to single energy gamma-ray detection for GVF determination of two-phase fluids. Furthermore, accuracy is improved by incorporating the scattering measurements along with the transmission [67]. Another advantage of dual mode operation is that it can provide flow-regime information and information on the salinity of the water fraction [67]. Salinity has a very significant impact on GVF measurement when using low energy radiation [67]. If GVF begins to exceed 70%, discrepancies in the gas phase fraction measurement between the hard (high energy) and soft (low energy) gamma counts, caused by phase slip, can be observed [60]. 3.3.3.2.5 Coriolis U-tube mass flow rate meter

The Coriolis U-tube meter Fig. 3.16A also referred to as the Coriolis meter, is widely used in the oil and gas industry to make mass flow rate measurements. It works by measuring the phase difference of oscillating flow tubes between the inlet and outlet of the instrument. Under no-flow condition, the two tubes oscillate in phase Fig. 3.16C, and during flow, they oscillate out of phase Fig. 3.16D typically in a sinusoidal fashion. The phase difference is proportional to the mass flow rate through the tube. Most commercial Coriolis meters use two identical tubes to make the phase shift measurements more sensitive. The two tubes are typically driven at their first natural frequency [68]. The phase difference is registered by two pick-off sensors located at the inlet and the outlet of the meter as shown in Fig. 3.16B and forms the basis of the final derived reading. The electromagnetic drive coil and magnet are shown in Fig. 3.16B ensure the tubes are always oscillating at constant amplitude and at their first natural frequency. The driving force/gain changes as the mass of the flow tube (function of fluid density) changes. A Coriolis meter is very accurate for measuring single-phase fluid flow (both gas and liquid). However, it underperforms with aerated liquids and batch flow which

Figure 3.16 (A) U-tube Coriolis meter, (B) internal components, (C) Coriolis meter working principle at no flow, (D) Coriolis meter working principle at flow. Image courtesy Emerson, reproduced with approval.

Advanced materials and sensors in well logging, drilling, and completion operations

are common while drilling [69,70]. The Coriolis meter, in-spite of its shortcoming in dealing with aerated fluids is considered as the meter of choice for MPD. It is valued for its high accuracy and quick measurement times during drilling operations [71]. It is a relatively expensive and large meter, only suited for pressures below 7.2 MPa. The Coriolis meter is not recommended for heavily aerated fluids or slug flow/ batching applications, where air and fluid follow in rapid successions [69,70]. The meter lacks the fast response time (defined by how quickly a device can respond to periodically changing flow rates) and low latency (defined as the time it takes for the flow meter output to respond to a change in flow) required for batching operations [69]. Even the best Coriolis meters in the industry struggle with batch times of less than 0.5 seconds and some perform badly even at 20 seconds batch times [69]. The bubble theory, the resonator theory, and the damping theory describe three types of phenomenon that arise in a Coriolis meter due to aeration. The bubble theory aims to resolve issues that arise due to the amplitude of bubble oscillations inside the tube being greater than the tube oscillations. The resonator theory aims to resolve issues that arise from the entrained volume of liquid inside the bubbles themselves. The errors from the resonator effect are a function of resonant frequency, the excitation frequency of the tubes, the air content, and the process pressure. The damping theory aims to resolve issues that arise due to the friction between the liquid, the bubbles, and the pipe wall due to nonuniform distribution of bubbles [72]. The damping effect causes significant flow tube damping to occur due to loss of mechanical energy from frictional interactions between the compressible air, fluid, and tube wall [72]. Aeration can result in damping of flow tube that is two orders of magnitude greater than damping that results from single-phase fluid flow [70]. Aerated liquids, therefore require greater power from the drive system to maintain the natural frequency and amplitude of the tubes. In theory, the drive coils can be designed to meet the increased energy demands. In practice, however, this extra power is not available as the drive system power is limited for intrinsic safety reasons. Furthermore, the drive system tracking and response time is not fast enough. It struggles to keep pace with the changes in the damping force due to the chaotic nature of the bubbles in the fluid. Another problem when dealing with aerated liquids is the drive gain saturation, which often results in stalling of the meter [40,69,70]. Drive gain saturation occurs when the controller’s allowable current limit has been exceeded and the gain is therefore not sufficient to compensate for damping. As a result, the tube dampens even more, leading to even a higher gain requirement. This eventually results in meter stalling. To correct for the damping effect, straight or slightly curved tube designs are also being investigated [40,70]. This tube design allows for more uniform bubble distribution. In a vertical installation (meter inlet and outlet are perpendicular to the ground)

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using a straight tube, the bubbles get distributed uniformly enough to drive the error due to the damping effect to zero. Furthermore, the design is more compact and causes less pressure drop than the U-tube geometry. However, caution needs to be exercised, as the straight tube has a high excitation frequency, which can lead to the resonator effect dominating over the bubble effect. However, if there is a likelihood that the resonator effect will work to compensate for the error caused by the bubble effect, the straight tube design works well. Also, the straight tube design has low tube oscillation amplitude, and therefore low-phase difference range and poorer SNR [40,70]. Another solution for dealing with aerated flows is to use ANNs and empirical models that can be customized to provide measurement corrections. ANNs have been applied successfully to correct for errors for aerated fluids within a known range of operating conditions, after much data collection and laboratory experimentation. ANN’s can capture patterns and trends from the complex set of data that is captured during experiments. If the operating conditions are changed, data will have to be recollected and the ANN reconfigured. The accuracy of the Coriolis meter measurements can be significantly increased using ANN’s. Research is also ongoing to improve the slow dynamic response and the poor performance of the Coriolis meter when handling flow from large, slower positive displacement pumps, especially in short batches. Slow dynamic response is not an issue when dealing with smaller or faster pumps as the flow pulsations tend to get averaged [69]. Efforts are also being devoted to address driver power limitations by using a two-driver design model instead of single driver design and by reducing the mass flow rate into the Coriolis meter by splitting the flow [40,70].

3.4 Advanced materials in drilling and well completion operations 3.4.1 Nanoparticles in drilling fluids The design of drilling and completion fluids is one of the essential parts for a successful well construction operation. This fluid can be in the form of a water-based mud (mostly including clays, weighting agents, and polymers) or an oil-based mud (the emulsion of water in oil with the additives of emulsion stabilizers, weighting agents, and rheology modifiers). The most recent advancements on the drilling and completion fluid technology are in the applications of nanoparticle additives, which are defined as particles between 1 and 100 nm in size, with a surrounding interfacial layer. Nanofluids, therefore are colloidal suspensions containing various amounts of nanoparticles [73].

Advanced materials and sensors in well logging, drilling, and completion operations

Figure 3.17 SEM images of the HPHT filtrate cakes from the base fluid (A) and a nanoparticle added fluid (0.5 wt.%) (B) [73].

Recent advancements in nanofluids for drilling and well completion operations are on optimizing the rheology and filtration characteristics of fluids which can withstand high-pressure and high-temperature environments [73]. The most important advantage of using a nanofluid is the significant benefit of high-pressure high-temperature fluid loss. This can be achieved with an optimum concentration of around 0.5 wt.%. As shown in Fig. 3.17, a smooth filtrate cake is observed in the based fluid while the filtrate cake obtained from the nanofluid showed chain-like structures. This behavior increases the surface area of the filtrate cake and enhances its ability to decrease fluid losses. A flat type gel strength while maintaining optimal yield stress can be observed in nanoenhanced fluids. This shows that they have great potential for cuttings suspension and transport in drilling operations. Nanofluids also have the capability of plugging the pores in shale formations, therefore reducing the shale permeability. Moreover, they can be used as wellbore strengthening additives [73].

3.4.2 Altered fracturing fluid and proppants The use of radioactive tracers along with the spectral gamma-ray logging has found the application in the oil industry to determine the fracture growth patterns. The idea is to tag the materials placed downhole with one or more radioactive isotopes that emit gamma rays and then to process the measured spectra to determine the locations of the individual tracers. These tracers can be mixed with fracturing slurry, and the depth of investigation is limited to that of gamma-ray tools which are about a few feet. The gamma-ray data contain information regarding the radial distributions of the tagged materials as well as the variation of isotope concentrations with depth. The technique has gained wide acceptance because two or more tracer isotopes (nonwash off radioactive ceramic based tracers) with distinct gamma-ray signatures can be detected simultaneously, allowing several materials or several stages to be tagged during operation [74]. Afterward, a single logging pass of spectral gamma-ray tool (with a few hundred spectral

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Figure 3.18 Left pictures show regular ceramic proppants used in the fracturing operations; the right figure shows electrically conductive proppants [11].

channels) is sufficient to identify the individual tracers and, thus to use this information to evaluate the effectiveness of the job [75]. To reduce health, safety and environmental concerns related to the radioactive material use, high thermal neutron capture cross-section contrast agents have been alternatively introduced in Mulkern et al. [76]. In the presented field application, boron carbide particles (chemically inert under typical conditions of hydraulic fracturing) added to the fracturing slurry as a tag material to locate fracture height. The particle sizing can be matched to that of operation materials to travel at the same velocity as pumped fluid giving a homogeneous distribution of the tracer throughout a fluid displacement. The use of neutron logs afterward can provide the same information of the fractures. The technique suffers from the same limited investigation area of the neutron logs and a limited number of available tags [77]. In Hauptmann et al. [44], the propagation of the contrast agents into the induced and natural fracture network is suggested to be enhanced using an externally applied electric field. The characterization of the fracture density in the unpropped area can be carried using the enhanced neutron porosity logs. In the other electromagnetic-based techniques, as discussed in the electromagnetic-based monitoring techniques, numerous proppant types (Fig. 3.18) have been reported to exhibit large effective electrical conductivities and been used in some field [11,13] and laboratory experiments [78]. In the laboratory experiments with petroleum coke (PC), the high electrical conductivity of 5000 S/m is measured when the confining stress is above 3000 psi. Particle size is shown not to play a noticeable role in the measured results. The effective conductivity decreases with an increasing weight percentage of sand staying above 1500 S/m effective conductivity when up to 50% sand was added. While providing the necessary contrast in electrical conductivity, the PC is also shown to sustain mechanical integrity under high confining stresses [17].

Advanced materials and sensors in well logging, drilling, and completion operations

3.4.3 Chemical tracers Other than radioactive tracers, there are water, oil, or gas soluble chemical tracers used in the industry which can be either liquid or solid and are also environmentally safe. They are used for displacement efficiency assessment in conventional reservoirs or to determine the connectivity/effectiveness of the hydraulic fracture stimulation in unconventional reservoirs. In the latter case, tracers are injected into the formation along with the fracturing fluids. At the end of tracer test, the information from the injector and monitor wells on the percent of tracer recovered relative to the amount of tracer injected, and the amount of tracer recovered from each stage normalized by the total amount of tracer recovered from the stage enables reservoir characterization. In Salman et al. [79], some of the mentioned aqueous chemical tracers are thiocyanates and fluorobenzoic acids, oil-soluble tracers are alkyl esters which partition in oil and water, and gas tracers include sulfur hexafluoride. The majority of tracer tests in unconventional reservoirs use emulsion tracers because these tracers reveal information about the interwell connectivity, fracture system, and flow patterns. Moreover, they do not require well shut-in and are more economical than the other tracer types. Perforation tracers are the other type for high-temperature environment associated with perforating charges used in plug-and-perf fracturing operations. Controlled release tracers are tracer-polymer compounds placed outside of liner, which release tracers upon contact with formation fluids [79].

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CHAPTER FOUR

Nanoparticles for enhanced oil recovery Shidong Li1, Hon Chung Lau1,2, Ole Torsæter3, Luky Hendraningrat4 and Cenk Temizel5 1 Institute of Chemical and Engineering Sciences, Agency for Science, Technology and Research (A*STAR), Singapore, Singapore 2 Department of Civil and Environmental Engineering, National University of Singapore, Singapore, Singapore 3 Porous Media Laboratory (PoreLab), Department of Geoscience and Petroleum, Norwegian University of Science and Technology (NTNU), Trondheim, Norway 4 PETRONAS, Kuala Lumpur, Malaysia 5 Saudi Aramco, Dhahran, Kingdom of Saudi Arabia

4.1 Introduction Economic growth and improving prosperity in the world result in increased energy demand. However, the drive to improve energy efficiency is causing the global energy consumption to increase less than earlier years. According to BP Global Energy Review [1] the increase in 2016 is less than 1% and the energy mix is shifting towards cleaner, lower carbon fuels, driven by environmental needs and technological advances. However, the share of renewable energy within the total energy mix remains small, at around 4%, so this source will only have a complimentary role in the next two decades. On the other hand, the oil companies are facing a decrease in easily recoverable oil and gas reserves and the development of new technologies to increase the effectiveness of exploration and production is continuously ongoing. Today less than half of the total oil discovered can be recovered using conventional water and/or hydrocarbon gas injection. A number of chemical methods, nonhydrocarbon gas methods and thermal methods are applied to enhance the oil recovery, but the recovery challenge still persists. Therefore, less expensive, more efficient and environmentally friendly enhanced oil recovery (EOR) methods are needed. The oil industry has over the years observed the success of nanotechnology in many aspects of aerospace, biology, and medicine. This has encouraged the industry to start research projects on nanotechnology for the oilfield applications. Society of Petroleum Engineers (SPE) has organized workshops. Exploration and production networks using nanotechnology have been established and several collaboration projects between the oil industry and academia have been initiated. Some of these projects were successful, especially for the single well applications, such as dissolvable ball-drop Sustainable Materials for Oil and Gas Applications. DOI: https://doi.org/10.1016/B978-0-12-824380-0.00005-0

© 2021 Elsevier Inc. All rights reserved.

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systems used in horizontal well completions [2], completion fluids [3], and additives used to enhance drilling fluids [4]. Nanotechnology has the potential to improve well and near well constructions, equipment, and procedures. Below is a table indicating some nanoparticle (NP) technology research subjects and related applications [5]. The aim of this chapter is to summarize results from the laboratory research on adding NPs to the injection fluid to improve oil recovery. So the two last rows of Table 4.1 will be discussed in detail. The oil industry has over time increased hydrocarbon recovery by using horizontal drilling, reservoir characterization, 4D seismic, and various injection techniques beyond water and gas injection. Fig. 4.1 shows technical options to target remaining immobile and mobile oil after water and/or gas injection. As observed from the figure, EOR is defined as increased recovery based on injection of fluids not originally found in the reservoir such as chemicals, carbon dioxide (CO2), and steam. Improved oil recovery (IOR) refers to increased recovery using non EOR methods such as infill drilling, artificial lift, smart wells, stimulation, etc. The following situation is common in many reservoirs. First, immobile oil constitutes about 45% of remaining oil in producing fields and Table 4.1 Examples of nanotechnology and oil field applications [5]. Nanotechnology/tool

Oilfield application

Nano electronics/nano sensors Nano optics/quantum dots Nano magnetism/ ferrofluids

Reservoir and flood front Long battery life under imaging reservoir conditions Logging Transport through reservoir Reservoir/fracture imaging Development of magnetic NPs, electromagnetic sources and receivers, data acquisition and signal processing software Produced water treatment Scale up from lab to field

Nano magnetism/ magnetic NPs Nano compositesand fibers/single wallcarbon tube, fullerenes, multiwall carbon tube Nano thin film/ nanocomposite coatings Nano catalyst/nickel NPs Nano encapsulation/ chemical laden NPs, biodegradable polymericNPs, phase inversion nanoencapsulation Surface active NPs/ functionalized NPs

Key challenges

New casing and tubing materials, drill bits, and proppants

Constructing and testing prototype

Drill bits, drilling fluids, completion fluids, shale inhibition Catalyst for in situ thermal upgrading of heavy oil Acid stimulation, profile control, gas mobility control

Construction and testing prototype

EOR

Transport through reservoir

Transport through reservoir, scale up Scale up from lab to field

Example publication

[6,7]

[8
11]

[12,13]

Nanoparticles for enhanced oil recovery

Figure 4.1 Fraction of oil left in fields in production classified in the types of immobile oil and mobile oil. The boxes show increased recovery measures that can be used [14].

this oil cannot be produced by standard water or gas injection. Second, there is a limited window of opportunity for increased recovery methods for large and mature fields since these fields have already reached a high recovery factor. Third, the recovery factor for oil has not increased much in the last decade. Fourth, small fields have a recovery factor of approximately 30% which has not increased in the last two decades. EOR methods like chemical methods, microbial oil recovery (MIOR), miscible gas injection methods and CO2 can be used to remobilize and produce remaining immobile oil (Fig. 4.2). However, up to now most EOR methods have not been economic and there are two ways to improve the economy: optimize the method or reduce the uncertainty. Still we lack the fundamental understanding of how oil is immobilized and of mechanisms that remobilize it. Trapping of oil happens either by isolation of oil in large water wet pores or by microscopic by-passing through capillary fingering. Developments in computer tomography scanning technology and pore-scale flow/network simulations have lately given fundamental insight into EOR mechanisms. Still there are phenomena of fundamental importance for recovery of immobile oil that are not well understood. Examples include how crude oil wets the rock through nano-meter scale water films. Hopefully, spin-offs from fundamental chemistry, physics, nanotechnology, and micro fluidics can contribute to an improved understanding. Since nanotechnology has been successfully applied in several areas of the petroleum industry and EOR mechanisms need active ingredients on nano scale, it is natural that injection of NPs becomes a viable option in the oil industry. In the last decade, many types of nanofluid (NPs suspended in water) behavior in porous media have been studied with respect to mobility control, displacement on pore scale and general transport in porous media. However, as indicated in Fig. 4.3, the final approval of a field scale nanofluid injection requires positive input from studies on many scales.

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Figure 4.2 Simplified mechanistic view of some EOR methods that effect interfacial tension (IFT). Based on a figure from J.J. Taber, Recovery Processes in Porous Media, New Mexico Tech, United States, 1991 [15].

Figure 4.3 Typical project plan for implementation of nanotechnology for EOR. Modified from Z. Zhang, O. Torsaeter, Nanofluid Enhanced Oil Recovery - Preliminary Experimental Results, Norwegian University of Science and Technology (NTNU), 2013 [16].

Nanoparticles for enhanced oil recovery

4.2 Physics and chemistry of nanoparticles Nanoparticles owe their unique physical and chemical properties to their extremely large surface-area-to-volume ratio. The ratio of surface atoms to interior atoms changes drastically if one divides a macroscopic object into very small parts. For example, the percent of surface atoms in a cube of iron of 1 cm3 is only 1 3 1025%. When the cube is divided into smaller cubes with an edge of 10 nm, the percent of surface atoms would increase to 10%. In a cube of 1 nm3, every atom would be a surface atom. As the dimension of the cube decreases to nanometer, the proportion of surface atoms increases exponentially. Since the total surface energy of a material increases with its overall surface area, NPs possess a huge surface energy. According to thermodynamics, all matters seek to reside in a lower energy state. There is therefore a tendency for NPs to reduce their surface energy by various means such as agglomeration with other NPs to form bigger nanostructures or combining with other nano size or colloidal structures to reduce the overall surface area. This is one reason why NPs are so surface active thus resulting in their unique physical and chemical properties. Due to their small size and enhanced chemical reactivity, NPs have been used in targeted drug delivery, medical and dental imaging, high strength materials, and catalysis, etc. However, the application of nanotechnology to the oilfield is relatively new and is in its early stage.

4.2.1 Types of nanoparticles Typically, NPs have size ranging from 1 to 100 nm. There are many types of NPs ranging from simple metallic NPs (e.g., gold and silver NPs) and oxide NPs (e.g., metal oxide and silica NPs) to highly complex NPs used for targeted drug delivery. Besides having a simple core, NPs can be made to have an outer protective shell to protect them from the environment. Furthermore, the surface of a NP can be functionalized, taht is, different materials such as special molecules or polymers can be attached to the surface for particular purposes, such as enhancing its stability in the suspending medium. Indeed, technology exists to create NPs from simple to very complex structures depending on applications. Silica NP was the most reported for EOR applications, and fumed silica NP and colloidal silica NP were commonly used in laboratory experiments. Fumed silica NP is made from flame pyrolysis in which silicon tetrachloride reacts with hydrogen and oxygen, and the SiO2 NPs grows in size or aggregates (Fig. 4.4). Fumed silica NPs are white powder with low bulk density. Colloid silica NPs are stable suspension systems in which the continuous phase is a liquid and the discontinuous phase is silica in the colloidal state of subdivision [18]. For colloid silica NPs system, particles that are small

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Figure 4.4 Fumed silica NP synthesis in the flame [17].

Figure 4.5 Two-dimensional random network of a dehydrated but hydroxylated colloidal silica particle [18].

enough that gravity doesn’t cause them to settle, but large enough not to pass through a membrane and allow other molecules and ions to pass freely, normally particle sizes range from about 1 to 100 nm and the structure of colloidal silica NP is shown in Fig. 4.5. Cryogenic transmission electron microscopy images of fumed silica and colloidal NPs are shown in Fig. 4.6.

Nanoparticles for enhanced oil recovery

Figure 4.6 Cryogenic transmission electron microscopy images of fumed silica NPs (left) and colloidal silica NPs (right).

4.2.2 Physical properties of silica nanoparticles Physical properties of NPs include shape, size, state of size distribution, specific surface area, agglomeration/aggregation, surface morphology/topography, and structure including crystallinity, defect structure, and dispersity [19]. The size, size distribution, specific surface area, agglomeration/aggregation, and dispersity in water of NPs are important for EOR application. The size of NP can be identified as the most important parameter of nanomaterial, and nano-size also makes NPs exhibit unique properties from their bulk material. Normally, the size of NPs ranges from 1 to 100 nm, which allows NPs penetrate through reservoir easily. The size distribution of NPs follows normal distribution, and the narrower size distribution the easier can be used for EOR. As discussed above, nano-size of NPs results in big surface area, the relation between particles size and surface area is shown in Fig. 4.7. The big surface area leads to high surface energy, which determines adsorption ability of NPs in porous media and agglomeration/aggregation of NPs. The agglomeration/aggregation of NPs can be mitigated by adding stabilizer or surface modification. For hydrophilic NPs, they are easily to be dispersed in aqueous phase with enough mixing energy, sonication is commonly used.

4.2.3 Chemical properties of silica nanoparticles Chemical properties of NP include the elemental composition of nanomaterials and its surface chemistry such as zeta potential and stability [19]. The chemical properties of a material are determined by the type of motion of its electrons. Different type of NP

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Figure 4.7 NPs surface area in relation to the mean primary particle size [20].

Figure 4.8 Effect of pH in the colloidal silica
water system [18].

has different chemical properties. Here, we describe the chemical characteristics of hydrophilic silica NPs for EOR application. The value of zeta potential for silica NPs dispersion is less than 230 mV, which is considered as a stable system. However, many factors can affect NPs stability, like temperature, salinity, and pH. The effect of pH on stability of silica NPs is shown in Fig. 4.8.

Nanoparticles for enhanced oil recovery

Figure 4.9 Silanol groups (left) and siloxane groups (right) [20].

Surface functional groups of NP determine the chemistry of NP. For silica NP, there are two main functional groups that present on NP surface: the silanol groups and the siloxane groups, as shown in Fig. 4.9. The siloxane groups are largely chemically inert and also display hydrophobic behavior [20]. However, the hydrophilic nature of the silanol groups is predominant on silica NP surface, which make most of silica NPs is hydrophilic and easily dispersed in aqueous phase. The silanol group also makes it possible to graft NPs with different functional group.

4.3 Enhanced oil recovery mechanisms of nanofluid 4.3.1 Mobility control 4.3.1.1 Nanoparticles stabilized foam Gas injection is one of the most widely used tertiary EOR methods. Injected gas includes CO2, natural gas, and nitrogen. Some most commonly injected gases for miscible displacement, for example CO2 and nitrogen, can reduce oil viscosity and oil
water IFT [21]. However, the viscous fingering due to low viscosity of gas, reservoir heterogeneity, and gravity segregation results in poor sweep efficiency for gas flooding. Foam was used to mitigate these problems by reducing mobility of gas in reservoir [22,23]. Foam is generated when a liquid that containing a small amount of foaming agent contacts with a gas and sufficient mechanical energy is provided to stabilize the discontinuous gas phase dispersed within a continuous aqueous phase [21]. The mechanism is immobilizing or trapping injected gas in the porous media and increasing the apparent viscosity of gas, thus improving the reservoir sweep efficiency. Traditionally, surfactants are commonly used to generate and stabilize foams, but they tend to degrade at high temperature and high salinity condition. NP was proposed to assistant surfactant to stabilize foam or stabilize foam by itself alone with the benefit of longer foam stability and better EOR performance [24,25]. Emrani et al. [26] investigated the use of silica NPs to enhance the stability of foam generated by alpha-olefin sulfonate (AOS) surfactants. Their results showed that AOS

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and silica NPs generated stronger foams with fine texture. High temperature stability test also confirmed that foam stability improved when NPs were added into an AOS solution. The possible reason might be NPs adsorption at the gas-aqueous interface, which can prevent bubble coalescence. Coreflooding experiments with foam were performed. Compared with foam injection stabilized with AOS only, pressure drop was doubled for the foam injection stabilized both with AOS and silica NPs. This indicated that apparent foam viscosity increased thus giving a lower mobility. Research by Mo et al. [24] has shown that it is possible to stabilize foam by using silica NPs alone. Stable CO2 foam was generated when CO2 and silica NP dispersion flowed through a core sample, and CO2 foam could be stabilized with NP concentration as low as 100 ppm. Foam mobility decreased and the foam resistance factor increased with the increase of NP concentration. CO2 foam remained stable after 48 hours and showed good stability. NPs adsorbed at the CO2-water interface and formed a rigid barrier that impeded bubble coalescence. The attachment energy of NPs adsorbed at the CO2-water interface is one to several thousands of kT, while surfactant molecules only have several kT. In addition to silica NPs, fly ash NPs has also been proposed to stabilize foam [27]. Fly ash is a noncombustible solid inorganic matter and is a byproduct of coal combustion. The chemical composition of fly ash depends on composition of coal and high-temperature combustion and the postcombustion cooling process. Normally the chemical composition of fly ash includes SiO2, Al2O3, Fe2O3, CaO, MgO, Na2O, K2O, TiO2, BaO, SO3, P2O5, and few amount of other metallic oxide [28]. Eftekhari et al. [29] used ultrasonic grinding and a de-agglomeration device to reduce particle size of fly ash to around 200 nm. Their results showed that the nitrogen foam stabilized with fly ash NPs and AOS is stronger and more stable than the foam stabilized by AOS only in presence of crude oil. Research by Singh et al. [30] shows that strong CO2 foam with fine texture can be generated in situ in porous media by using fly ash NPs together with a nonionic surfactant. Fly ash is industrial waste products, which give this method advantage on cost efficiency [30]. Guo et al. [31] and Lu et al. [32] investigated the effect of NPs stabilized foam on EOR by using microfluidic and sandpack flooding. CO2 foam stabilized with AOS- Olefin Sulfonate Lauramidopropyl Betaine and NPs exhibited superior formability and stability compared to other NP-surfactant mixtures and resulted in high oil recovery of 95%. Lu et al. [32] showed that silica NPs can increase the dilational viscoelasticity of the gas-water interface, and foam injection can improve sweep efficiency by blocking pore channels through capture-plugging and bridgeplugging. The trapped oil droplets can be produced by elastic forces of gas bubbles (Fig. 4.10). The sandpack flooding experiments indicated that additional oil recovery due to NP stabilized foam injection was about 27% by using 0.5 wt.% silica NPs suspension.

Nanoparticles for enhanced oil recovery

Figure 4.10 Pore-scale images of the formation if oil threads in the interchanges of pores. (A): 0.148 PV; (B) 0.159 PV [31].

4.3.1.2 Nanoparticles-enhanced polymer flooding at high temperature and high salinity conditions Polymer flooding is a widely applied mobility control method for EOR. Mobility control is usually discussed in terms of mobility ratio (M), defined by the following equation.   krD =μD SD  M5  (4.1) krd =μd Sd where, krD is relative permeability of the displacing phase, krd is relative permeability of the displaced phase, μD is viscosity of the displacing phase, μd is viscosity the displaced phase. The numerator is to be computed at SD, the average saturation of the displacing phase in region behind the displacing phase front. The denominator is to computed at Sd, the average saturation of the displaced phase in the region before the displacing phase front [21]. When M .1 displacement is unfavorable and results in fingering (Fig. 4.11A). However, when M # 1 displacement is favorable and has better sweep efficiency (Fig. 4.11B). Polymer is commonly used to increase displacing phase viscosity and reduce the mobility ratio. Partially hydrolyzed polyacrylamide (HPAM) is the most widely used polymer for mobility control and has been applied in fields worldwide [33]. However, successful application of HPAM is restricted by polymer degradation, especially in high-temperature and high-salinity reservoirs [34]. In such harsh environments the acrylamide groups of the HPAM would undergo a hydrolysis process to generate acrylate or carboxylic groups [34,35] and the cations in brine will shield the mutual repulsion from the carboxylic groups, leading to collapse of the polymer coils and decrease in the hydrodynamic volume [36
38]. Both can result in viscosity reduction of the polymer solution.

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Figure 4.11 Schematic of mobility control improvement with polymer flooding [21]. (A) Waterflood; (B) polymer flood.

Figure 4.12 Viscosities of 0.5 wt.% HPAM with different silica NPs loadings (25 C and 85 C, 8 wt.% NaCl, and shear rates from 500 to 1000 s21) [33].

Recently, introducing silica NPs into polymer solution has been proposed to improve polymer flooding performance under high-temperature and high-salinity conditions [33,39,40]. Addition of silica NPs is expected to form chemical bonds bridging NPs and polymer chains and to improve rheological properties of polymer solutions. As shown in Fig. 4.12, the viscosity of HPAM and silica NPs hybrid increases with increasing NP concentration under both low and high temperatures, while the viscosity of NP suspension is close to that of water and is independent of concentration. Thus, the viscosity increase of the hybrid cannot be regarded as a superposition of the viscosity of HPAM solution and that of the NP suspension. A rapid viscosity increase was observed beyond a certain critical NP concentration (CNC) [33].

Nanoparticles for enhanced oil recovery

Zhu et al. [39] also studied effect of silica NPs on the rheological behavior of hydrophobically associating partially hydrolyzed polyacryamide (HAHPAM). Viscosities of hybrid of silica NPs and HAHPAM versus different shear rate were measured and shown in Fig. 4.13. It can be seen that the hybrids with different NP loading all exhibit nonNewtonian shear-thinning behavior. However, similar with the HPAM/NP hybrid case, viscosity of the hybrids apparently increases with addition of silica NPs. The hybrids with high concentration of NPs still have relatively higher viscosity at high shear rates. The mechanism for viscosity increase of HPAM/NP hybrid was explained with Fourier transform infrared spectroscopy by Hu et al. [33]. As shown in Fig. 4.14 left, two peaks corresponding to SiaOaSi asymmetric stretching and SiaOaSi bending vibrations were found both in silica NP and hybrid samples. However, these two peaks show notable shift, which may be due to a combined effect between silica NPs

Figure 4.13 Apparent viscosity plotted as a function of shear rate for HAHPAM/NPs hybrids in brine with different silica loading (TDS 5 32,868 mg/L, [Ca21] 1 [Mg21] 5 873 mg/L, T 5 85 C, Cp 5 0.5 wt.%) [39].

Figure 4.14 Left: FTIR spectra for 0.5 wt.% HPAM, 0.5 wt.% HPAM/0.8 wt.% NP hybrid, and silica NPs; Right: Potential interactions between silica NPs and HPAM [33].

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Figure 4.15 Cartoons illustrating the adsorption of SiO2 NPs onto polymer chains for a given polymer concentration: (A) particles increasingly adsorbed onto polymer chains via hydrogen bonds; (B) saturation reached (i.e., the CNC value) with all of the carbonyl groups attached by SiO2 NPs; (C) particles accumulating and bridging in the network [33].

and HPAM. For instance, hydrolysable covalent cross-links between silica NPs and HAPM (Fig. 4.14 right) might exist in the system. And a new peak at 920 cm21 was found in the hybrid’s spectra, which corresponds to a SiaOaH bending vibration indicating the hydroxyl on silica surfaces. These aOH groups can react with the amide groups and form hydrogen bonding (SiOaH    NaH, SiOaH    OaCNH2 and SiO    HNHaCOaC) as shown in Fig. 4.14 right. The formation of hydrolysable covalent cross-links and hydrogen bond could bridge silica NPs with HPAM forming stronger structures, which can strengthen HPAM and increase the viscosity of the hybrids. As mentioned above, the viscosity for HPAM/NP hybrids increases more quickly when the NP concentration is higher than CNC. As illustrated in Fig. 4.15, when the NP concentration is lower than the CNC, most of particles are absorbed onto the polymer and form hydrogen bonds, so there are no free NPs in the system. However, when the NP concentration is higher than the CNC, free NPs are available, which can cross-link different polymer chains and prevent them from moving or rotating [33]. This would lead to a rapid increase in viscosity. High temperatures and high salinities can affect performance of polymer flooding, so the rheological behavior of HPAM/NP hybrids under these conditions is critical for its application in field. Hu et al. [33] investigated the effect of temperature and salinity on viscosity of HPAM/NP hybrids. As shown in Fig. 4.16 left, the hybrids had a higher viscosity than HPAM solution in all temperature ranges, despite both samples underwent a significant viscosity decrease when temperature increased. However, since the hydrogen bond was sensitive to temperature, a quicker viscosity decrease of HPAM/NP hybrids was observed. When temperature increased a large amount of hydrogen bonds between silica NPs and HPAM might be broken and resulted in disassociation of the network junctions and binding of NPs to HPAM. Salt tolerance is another important property for the application of the hybrids. In Fig. 4.16 right, the hybrids had higher viscosity than HPAM solution both at low and high

Nanoparticles for enhanced oil recovery

Figure 4.16 Left: Comparison of the temperature effect on the effective viscosities at different temperatures (8 wt.% NaCl and shear rates of 500
1000 s21); right: Example influence of the ionic strength on the average viscosity (T 5 25 C and shear rates from 500 to 1000 s21) [33].

Figure 4.17 Example of viscosity change with aging time (aging at 80 C and 8 wt.% NaCl) [33].

salinity conditions, and the optimal NaCl concentration (c. 2.0 wt.%) for viscosity of the hybrids was also higher than that (about 1.5 wt.%) of HPAM solution. The results showed that NPs still can cross-link HPAM chains and increase viscosity at high salinity condition. During polymer flooding, degradation of polymer may reduce the polymer viscosity as well as efficiency of polymer flooding. Hu et al. [33] examined the long-term thermal stability of HPAM/NP hybrids and their results are shown in Fig. 4.17. It can be seen that the hybrids had much better thermal stability than HAPM. After 12 days HPAM lost most of its viscosity, whereas a slight viscosity increase of the hybrids was observed. It appeared that aging of the hybrids was helpful for the bridging of NPs with polymer chains and prevented polymer from degradation.

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Figure 4.18 Recovery factor, water cut and flooding pressure plotted as a function of injected volume of the samples: (A) 0.5% HAHPAM and (B) 0.5% HAHPAM/0.5% silica hybrid (TDS 5 32,868 mg/L, [Ca21] 1 [Mg21] 5 873 mg/L; T 5 85 C; injected volume 5 30% PV; injected rate 5 0.23 mL/min). [39]

A core flooding experiment with HAHPAM/NP hybrids was conducted by Zhu et al. [39] to examine the efficiency of polymer flooding enhanced with NPs, and the results are shown in Fig. 4.18. It was found that additional recovery from HAHPAM/ NP hybrids flooding was 10.57% of original-oil-in-place (OOIP), whereas for HAHPAM flooding recovered 5.44% of OOIP. The higher recovery factor with the hybrids flooding can be ascribed to its better rheological performance under high temperature and high salinity condition as well as favorable long-term thermal stability of the hybrid samples. Overall, the polymer/NP hybrid can enhance polymer flooding efficiency by improving mobility ratio under reservoir conditions. 4.3.1.3 Diversion using nanofluid There are a lot of research activities to develop nanotechnology to overcome shortcomings in traditional EOR methods [41
44]. They include tailoring chemical molecules for more efficient EOR agents, and smart high efficiency delivery of the EOR agents. Development of efficient drug delivery in the human body is an example of nanotechnology that could be modified and up scaled to improve the efficiency of chemical flooding. There has long been a need for more efficient water diversion techniques by improved in-depth placement of gelling chemicals to increase oil recovery in waterflooding and to reduce unwanted water circulation in heterogeneous reservoirs. New research efforts on diversion technology recognize the environmental challenges using chemicals and emphasize the development of green chemical systems for such applications. Table 4.2 gives an overview of the state-of-the-art diversion technology. At present, many research groups are developing surface functionalized NPs that together with polymers will improve gel properties and control gel formation and

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Table 4.2 Water diversion technology [44]. Technology

State of the art

The field scale projects on conventional polymer flooding has been initiated mainly based on polyacrylamide (characterized as a red chemical). Some polymer gel systems have been tested in single wells, but there are no large scale field implementations of such methods offshore. Nanotechnology Has created breakthrough results in various technologies and markets Polymer gel technology in EOR

Progress beyond state-of-the-art through nanotechnology.

Enabling hybrid material technology as a next generation of chemical EOR. Investigations on the fundamentals behind the formation of robust and green gels. Studies on the interaction of nanosized particles and polymers. Improved knowledge on integration between nanotechnology and polymer technology applied to EOR

Figure 4.19 Water diversion by placement of gel deep into a high permeability reservoir layer.

thereby increase oil recovery (Fig. 4.19). Incremental recovery from water diversion is generally expected to be about 2% above standard water flooding, but the potential is much bigger. This can be achieved by: • Improving our understanding of the effect of functional NPs on the gel formation with polymers by crosslinking, and their transport through the oil reservoir. • Developing hybrid materials, both in terms of functionality and size. • Developing systems of NPs with polymers that delay gelling for several weeks or months to assure in-depth placement of gels. • Achieving controlled release of encapsulated active components. • Acquiring data on the effects of real reservoir parameters such as temperature, pressure, brine salinity, and presence of crude oil on gel behavior. The last stage in the testing of NP-polymer improved gel system is to validate the gel in a pilot scale test in waterflooding or in combination with other materials for EOR.

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High water cut becomes an increasing problem late in the field production period often due to heterogeneities or high permeable reservoir zones (i.e., thief zones) when the field is produced by waterflooding. Deep placements of gels which will result in blocking the high-permeability flow channels of water and diverting the water to lower-permeability areas has a potential of reducing water production significantly and improving the waterflood in unswept areas. Placement of gels is, however, a challenging task since a high viscous gel cannot be transported deep into the formation. The oil industry has applied various chemical and mechanical methods for water control for more than three decades [45,46]. Fig. 4.19 illustrates the concept of delayed gelling by nanotechnology. The method is often characterized as near-wellbore or in-depth reservoir treatments. Correct diagnostics of the excess water problems based on extensive reservoir engineering and completion engineering studies is essential for selecting suitable technologies for successful treatments [47]. In the last decade there has been an interesting development of thermally active polymers for in-depth reservoir treatments [48,49]. A low viscous solution consisting of an expandable submicron particulate polymer is injected into the formation, and the polymer starts “popping up” (when crosslinks start to break) when triggered by heat and time. The design is challenging since it will require a proper temperature gradient in the formation for the placement of the blocking polymers. This may limit the applicability of this technology. Another very interesting method is to inject a low viscous polymer solution together with a crosslinking chemical. The gelation is delayed by adding polyethylene imine (PEI) which enables injection of polymer system into the formation before high viscous gels are formed [50]. There are, however, several factors that affect the delay in gelling time strongly like temperature, pH, and salinity. Therefore, the primary challenge in EOR is correct in-depth placement of the highly viscous gel for a given reservoir situation, and in many cases the delay in gelation time may not be appropriate for the actual reservoir situation. Most polymer gelling systems are based on polyacrylamide which is environmentally characterized as a “red” chemical, thus making applications in most areas challenging. In addition, some of the crosslinking agents (i.e., chromium) may not be environmentally acceptable. A quite recent development is a new type of NP which acts as environmental friendly cross-linkers for HPAM and possibly other polymers. The cross-linking functionality of the NPs will be initially blocked and then released slowly under the reservoir conditions, ensuring a controlled gel placement (Fig. 4.20) [51]. Fig. 4.20A shows that a combination of NPs with active cross-linking groups with HPAM will lead to the formation of gel. Fig. 4.20B shows that when the active groups are blocked, no HPAM gels are expected. In Fig. 4.20C, the blocking groups undergo slow hydrolysis (or another decomposition reaction) making the active

Nanoparticles for enhanced oil recovery

Figure 4.20 Illustration of delayed gelling due to NPs with gradually de-blocking the crosslinking functionality [51].

cross-linking groups available again. As a result, the formation of HPAM gel is retarded. The development of a new functionalized silica NP technology using organic/ inorganic nanostructured hybrid polymers has interesting potential [52]. By using NPs as crosslinking agents, it is possible to form stable gels without the use of, for instance, chromium which is not environmentally acceptable. As an additional benefit, this technology can provide a more hydrophobic gel than the components themselves. Movement of water could therefore be more efficiently hindered than movement of produced oil, thus leading to improved oil recovery. NPs possess a very high surface specific area that gives them enhanced surface reactivity compared to bulk. This reactivity is controlled in a proper way in order to prepare gel networks of particles with the surrounding. In the last few years there has been a lot of interest and discussions on how nanotechnology may be applied to EOR and specially mobility control and water diversion. The research includes studies of NPs which offer different ways of controlling oil recovery processes related mobility control. Huang et al. [53] describe a colloidal silica gel system where the gelation is activated by salt. Suleimanov and Veliyev [54] showed that the polymer gel strength is improved by adding metal NPs. The main mechanism is that the NPs with high surface area are evenly distributed in the gel, which results in increased gel strength.

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4.3.2 Increase in capillary number 4.3.2.1 Oil
water interfacial tension reduction and emulsification by nanoparticles Interfacial tension (IFT) is the tendency of a liquid to possess a minimum free surface when it is in contact with another immiscible liquid. Interfacial tension occurs because a molecule near an interface has different molecular interactions than an equivalent molecule within the bulk fluid [55]. Capillary force plays an important role in EOR process. Interfacial tension reduction can reduce the capillary force between oil and water and release some trapped oil drops. The capillary number is a dimensionless number that describes the relative importance of viscous forces to capillary forces during the process of an immiscible displacement. Mathematically, it can be represented by: NC 5

Viscous forces νμ 5 Capillary forces σ

(4.2)

where, ν is the velocity; μ is the viscosity, and σ is the oil
water IFT. During a flooding process, if NC .. 1, viscous forces dominate over capillary forces. However, if NC ,, 1, viscous forces are negligible compared with capillary forces. A high capillary number is essential to obtaining a higher oil recovery. In order to get a higher capillary number, IFT needs to be reduced to an ultralow magnitude (1023 mN/m) [56]. Historically, surfactants have been used to reduce the IFT to achieve a high capillary number. NPs may have some effect on oil
water interface and can potentially reduce the oil
water IFT. When NPs are introduced into an oil
water system, they move to oil
water interface to reduce IFT [57]. The effect of NPs on IFT reduction by a surfactant solution was also been investigated by Munishi et al. [58]. They concluded that the presence of NPs changes the rheological properties and increases the efficiency of surfactant solution on oil displacement processes. When the NP concentration is low, they are absorbed at the oil
water interface and reduce the IFT. However, at high concentrations, the NPs nearly completely remove the surfactant from the bulk aqueous phase. Thus, at low NP concentrations, the IFT of the dispersion is determined by a mixed layer composed of adsorbed NPs and surfactant at the liquid interface [59]. A number of IFT measurements have been performed either for NPs alone or in conjunction with surfactants. Table 4.3 shows some published IFT measurements. NPs with and without surfactant alone can reduce IFT. Table 4.3 shows that compared with traditional surfactant solution; silica NPs cannot reduce oil
water IFT to 1023 to 1022 mN/m. So IFT reduction by simple NPs may not be play an important role during nanofluid EOR process. However, it is still possible to reduce oil
water IFT further by modifying the NPs. One of the most common approaches is through surface-modification or asymmetrical surface-modification. If a NP is modified with hydrophobic and hydrophilic groups on opposite sides, thus creating a Janus particle (named by Nobel

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Table 4.3 Effect of NPs on oil
water IFT reduction. NP

NP conc. (wt.%)

NP size, nm

Surfactant

Surfactant conc. (wt.%)

IFT without NP (mN/m)

IFT with NP (mN/m)

References

SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 Al2O3 Fe2O3 ZrO2 ZrO2 ZrO2 ZrO2 ZrO2

0.3 0.1 0.1 0.01 0.05 0 0.1 0.5 1 1.5 2 0.1 0.2 0.1 0.2 0.1 0.2 0.3 0.3 0.01 0.01 0.001 0.01 0.1

1030 1140 12 7 7 14 14 14 14 14 14 7 7 7 7 7 7 40 20
35 14 14 10.5 10.5 10.5

None None None None None SDS* SDS SDS SDS SDS SDS SDS SDS SDS SDS SDS SDS None None SDS C12TAB None None None

0 0 0 0 0 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.1 0.1 0.2 0.2 0 0 0.2 0.3 0 0 0

38.5 13.62 25 19.2 19.2 21.7 21.7 21.7 21.7 21.7 21.7 7.43 7.43 3.53 3.53 2.6 2.6 38.5 38.5 16 18.4 51.4 51.4 51.4

1.45 10.69 5 12.3 8.9 4.2 4.5 5.2 5.8 6.1 6.3 3.71 4.64 2.59 2.76 1.87 2.42 2.25 2.75 3.1 5.4 37.2 37.2 36.8

[60] [61] [62] [57] [57] [63] [63] [63] [63] [63] [63] [64] [64] [64] [64] [64] [64] [60] [60] [65] [65] [66] [66] [66]

Figure 4.21 Sketch of a Pickering emulsion and a classical (surfactant-based) emulsion [68].

Laureate P. G. de Gennes), it has the potential to reduce IFT significantly. The surface activity of Janus particle is dependent on its surface modification. To use Janus particles as active surfactants, each side of the particle must exhibit distinctive surface hydrophilicity [67]. NPs also can also stabilize emulsion due to its active surface properties. Since this phenomenon was found by Pickering in 1907, this kind of emulsion also is referred to as Pickering emulsions (Fig. 4.21) [69]. Stabilization is achieved when nanometer to

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Figure 4.22 Contact angle on particle surface and its relationship with emulsion type [71].

micrometer-sized particles diffuse to the interfacial region and remain there in a stable mechanical equilibrium [70]. A critical parameter in the design of a Pickering emulsion is the three-phase contact angle, which determines the position of the particles relative to the oil
water interface. This angle is pictured in Fig. 4.22 for an ideal and spherical particle residing at an oil
water interface [71]. Furthermore, the type of emulsion, water-in-oil (w/o) or oil-in-water (o/w) depends on the wettability of the particles. Thus, hydrophobic particles will form a contact angle higher than 90 degrees, such that a larger fraction of the particle surface will reside in oil rather than in water. Thus they will normally stabilize w/o emulsions. For hydrophilic particles with a contact angle less than 90 degrees, o/w emulsions will be formed [70] A Scanning Electron Microscope image of o/w Pickering emulsions is shown in Fig. 4.23. It can be seen that the oil drop is surrounded by spherical particles. Pickering emulsions have some advantages compared to classical emulsions, such as better elastic ability to withstand a high pressure, a narrow size distributions, and a higher stability [70]. The emulsifiers of Pickering emulsion include silica particles [71], clay [73], latexes [74], magnetic particles [70], and nano-cellulose [75]. NPs stabilized emulsion was proposed for reservoir conformance control due to its special properties [76]. The steady-state viscosity of the NPs stabilized emulsion was measured across a range of shear rates and is shown in Fig. 4.24. It can be seen that the emulsion is shear-thinning and has ability to increase viscosity of injection fluid to obtain a better mobility ratio. In addition to the shear rate, emulsion viscosity should depend on the volume fraction of the dispersed phase and the droplet size [76].

Nanoparticles for enhanced oil recovery

Figure 4.23 Scanning electron microscope image of a10 μm diameter Pickering emulsion composed of 0.9 μm diameter particles (A) Scanning electron microscope image of a10μm diameter Pickering emulsion composed of 0.9 μm diameter particles, (B) and (C) are close-ups of (A) and (B), respectively [72].

Figure 4.24 Steady shear viscosity of crude oil-in-synthetic field brine emulsion prepared with 1 part oil to 2 parts brine; the brine contained 10 wt.% 5-nm silica particles [76].

Kumar et al. [77] conducted a sandpack flooding for an emulsion stabilized with a surfactant (TDA). Fig. 4.25 shows the cumulative oil recovery and the pressure profile for the brine and surfactant flooding. After brine flooding, oil recovery was about 0.225 pore volume (PV) and the highest-pressure drop was 30 psi.

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Figure 4.25 Oil recovery and pressure drop for 20,000 ppm brine flood followed by the surfactant (0.1 wt.% TDA, 0.5 wt.%, alkali and 20,000 ppm NaCl brine) injection [77].

During injection of surfactant flooding, the pressure drop increased to 110 psi and significant amount of additional oil was mobilized and emulsions were generated in situ. The oil recovery increased to 0.47 PV at the end of surfactant flooding. The generation of w/o emulsion was observed at the outlet and the emulsions had a viscosity ranging from 17,000 to 20,000 cP. The additional produced oil was mobilized by emulsification, as the stabilized emulsion filled the water flooding fingers to increase the pressure drop [77]. NPs stabilized emulsion has also been investigated for controlled release system [78]. Nano-emulsions containing oilfield chemicals may also be applied to well treatments (scale inhibition, acidizing, etc.), flow assurance (inhibition packages), deposit removal/clean-up and EOR (delivering surfactant or polymer to a targeted region). 4.3.2.2 Wettability alteration by nanoparticles Wettability is defined as the tendency of one fluid to spread over a specific solid surface in the presence of other immiscible fluids [55]. The extent of wettability can be shown with the contact angle of a droplet the on a solid surface. For a rock surface, wettability is a result of adhesion forces between the fluids and the minerals of the rock. When one fluid is in intimate contact with a surface immersed in another immiscible fluid, it has an angel of θ through the wetting phase. This angle is defined as the contact angle and is a function of relative adhesive forces at the intersection. The contact angle of an oil drop resting on a rock surface immersed in water can be expressed as cosðθÞ 5

ðσos 2 σws Þ σow

(4.3)

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where, σos represents the interfacial tension between oil and solid, σws between water and solid, and σow between oil and water [79]. Wettability controls the flow and distribution of fluids in a reservoir. Many investigations of wettability and its effects on oil recovery have concluded that neutral wetness is the most favorable reservoir wettability for maximum oil recovery from a reservoir [80]. The wetting state of a reservoir is determined by the interactions between the rock and fluids residing in the reservoir. It can vary from strongly waterwet to strongly oil-wet [79]. Changing the wettability of a reservoir to a more favorable state is critical to higher oil recovery. Traditionally, surfactants are used to alter reservoir wettability. However, adsorption of surfactants on reservoir surfaces and precipitation by divalent cations in the reservoir reduce the efficiency and attractiveness of using surfactant to alter reservoir wettability [79]. Recently, researchers have studied using hydrophilic silica NPs for altering reservoir wettability [81]. Due to their large surface area, NPs can be easily adsorbed on pore surfaces resulting in wettability alteration. Various authors performed contact angle measurements between oil and different NP suspension and their results are shown in Table 4.4 [58, 61, 83
85]. It can be seen that no matter what the initial wettability state was, NPs reduced the contact angle and changed the wettability to more water-wet. A picture of an oil drop for contact angle measurement is shown in Fig. 4.26. The oil drop is more spherical in a NP suspension than in synthetic seawater [85]. Li et al. [83,86,87] performed wettability alteration experiments on oil-wet, neutral-wet and water-wet core plugs. Wettability index (WI) is an important parameter that describes wettability of a reservoir. Measured by Amott method, WI can be defined by the following equation: WI 5

Vo1 Vw1 2 Vo1 1 Vo2 Vw1 1 Vw2

(4.4)

where, Vo1 and Vo2 are oil production volume during spontaneous imbibition and forced imbibition, respectively. Vw1 and Vw2 are water production volume from spontaneous drainage and forced drainage, respectively [55]. The relation between WI and the wettability of a reservoir is defined in Table 4.5. In the wettability alteration experiment, WI was measured and used to evaluate wettability change of core plugs due to NP suspension injection. Hydrophilic silica colloidal NPs (CNP) was utilized in this study. The results of WI measurement for NPs treated oil-wet, neutral-wet and water-wet core plugs are shown in Figs. 4.27
4.29, respectively. For oil-wet core plugs treated with NPs, wettability was changed to more water-wet and the higher NP concentration the more water-wet the core plug became. The core plugs treated with highest NP concentration (0.5 wt.%) had a WI of almost 0.6 [83]. This was a significant wettability change

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Table 4.4 Effect of NPs on oil-rock contact angle change. NPs

T ( C)

Dispersion media

NP conc. (wt.%)

Contact angle of original surface (degrees)

Contact angle after treatment (degrees)

References

SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 SiO2 Al2O3 Al2O3 Al2O3 Al2O3 Al2O3 Fe2O3 TiO2 TiO2 TiO2 TiO2

25 26 40 50 60 25 25 25 25 25 25 25 25 25 25 25 26 40 50 60 25 26 40 50 60

Propanol Water Water Water Water Water Water Water Water Water Brine Brine SSW SSW pH 5 3 SSW pH 5 2 Propanol Water Water Water Water Propanol Water Water Water Water

0.3 0.005 0.005 0.005 0.005 0.01 0.05 0.1 0.5 1 0.05 0.1 0.2 0.2 0.2 0.3 0.005 0.005 0.005 0.005 0.3 0.005 0.005 0.005 0.005

134 90 87 83 82 72.8 72.8 72.8 72.8 72.8 52 52 56.8 73.3 60.7 134 90 87 83 82 134 90 87 83 82

82 26 25 21 18 63.8 61.2 57.6 53.2 49.3 30 22 22.4 26.6 23.4 90 71 66 65 61 98 57 52 49 46

[60] [82] [82] [82] [82] [84] [84] [84] [84] [84] [57] [57] [85] [85] [85] [60] [82] [82] [82] [82] [60] [82] [82] [82] [82]

Figure 4.26 Contact angle between oil and a NP suspension on a quartz surface [85].

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Table 4.5 Approximate relationship between wettability and wettability index [88]. Wettability Oil wet Intermediate wet Slightly oil wet Neutral wet

Wettability index 21 to 20.3 20.3 to 20.1

Water wet

Slightly water wet

20.1 to 0.1 0.1 to 0.3

Figure 4.27 Wettability index for oil wet cores treated with CNP [83].

Figure 4.28 Wettability index for neutral wet cores treated with CNP [86].

0.3 to 1

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Figure 4.29 Wettability index for water wet cores treated with CNP [87].

compared with the initial wettability of 20.4 and would change oil
water distribution as well as oil
water relative permeability. NPs also altered neutral-wet core plugs to more water-wet, but not as significantly as wettability change of oil-wet cores. The reason might be different NP adsorption behavior on cores of different wetting state [86]. Since the water-wet core plugs were already strongly water-wet, no obvious wettability change was observed. There was only minor WI increase for core plugs treated with 0.05 and 0.2 wt.% NPs [87]. Li et al. [85] performed wettability alteration visualization experiment on a glass micromodel by using fumed hydrophilic silica NPs. The microscopic images of two locations in a micromodel were taken at initial water saturation and are shown in Figs. 4.30 and 4.31 with different magnification. As shown in Fig. 4.30, before NPs were injected, the wettability of the micromodel was close to oil-wet, since the crude oil almost wet the glass grains completely. However, after NPs injection, the hydrophilic NPs adsorbed on glass grains and formed a thin water layer. Due to different reflective indexes of water and crude oil, the water layer was seen as black curves along the grains. Zoomed-in images of the micromodel are shown in Fig. 4.31, where a thin water layer can be seen clearly at the grain surface. These water layers were formed due to adsorption of hydrophilic NPs on the grain surface. This phenomenon was observed over the entire micromodel. All glass grains were surrounded with black curves indicating the wetting state had been changed from oil to water-wet.

Nanoparticles for enhanced oil recovery

Figure 4.30 Microscope images of micromodel with magnification of 5 [85].

Figure 4.31 Microscope images of micromodel with magnification of 20 [85].

Disjoining pressure is proposed as a mechanism for NPs to change the wettability of the reservoir surface. Various authors have investigated the ability of a nanofluid to displace oil from a solid surface due to disjoining pressure [89
91]. The phenomenon of NPs ordering (Fig. 4.32) themselves into a confined wedge film geometry between an oil drop and a solid substrate is a consequence of entropy increase of the overall NP dispersion by permitting greater freedom for NPs in the bulk liquid. These ordered microstructures exert an excess pressure separating the two surfaces confining the nanofluid. This excess pressure is defined as structural disjoining pressure [91].

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Figure 4.32 NP structuring in the wedge-film resulting in structural disjoining pressure gradient at the wedge vertex [91].

The particles that are present in this three-phase contact region tend to form a wedge-like structure and force themselves between the discontinuous phase and the substrate (Fig. 4.32). Particles present in the bulk fluid exert a pressure forcing the particles in the confined region forward, imparting the disjoining pressure. The energies that drive this mechanism are Brownian motion and electrostatic repulsion between the particles. The force imparted by a single particle is extremely weak, but when large amounts of small particles are present, the force can be upwards of 50,000 Pa at the vertex. Particle size and the associated particle charge density also affect the strength of this force: the smaller the particle size, the higher the charge density, and the larger the electrostatic repulsion between those particles. When this force is confined to the vertex of the discontinuous phases, displacement occurs in an attempt to regain equilibrium. As with any colloidal system, particle size, temperature, salinity of the carrier fluid, and the surface characteristics of the substrate also affect the magnitude of the disjoining force [92]. The effect of disjoining pressure on releasing oil from a solid surface is shown in Fig. 4.33 [89]. Fig. 4.33A shows the interference patterns produced by an oil droplet on a glass/air surface observed by reflected light using a differential microscope. The sequence of photographs shown in Fig. 4.33B
E depicts the three phase contact angle dynamics and the various steps of oil droplet removal from the glass surface in the presence of an aqueous surfactant solution. It can be seen that the surfactant solution penetrates between the oil and glass surface as witnessed by the speckled band between dark and light areas in Figs. 4.33B and C and the formation of small aqueous lenses between the oil and solid surface. In effect, two contact regions are established: the first one is between the oil droplet, the solid surface and the aqueous surfactant

Nanoparticles for enhanced oil recovery

Figure 4.33 Dynamics of the three-phase contact region. a, Photomicrograph showing the oil drop placed on a glass surface and differential interference patterns formed at the three-phase (solid
liquid
air) contact region. b
e, Photomicrographs taken at increasing times after addition of the aqueous micellar solution: b, 30s; c, 2 min; d, 4 min; and e, 6 min. b, The beginning of the formation of the pre-wetting aqueous film between the glass surface and the oil droplet. c, The spreading of the pre-wetting film. d, The pre-wetted film now covers the whole area, and small water lenses are formed. e, The separation of oil droplet from the glass surface by a thick aqueous film with a dimple. [89].

solution (outer region), and the second one is between the oil droplet, the solid surface, and the aqueous film with lenses (inner region). A prewetted aqueous film with lenses is formed between the two regions. The thickness of the speckled band increases with time, because the inner contact region recedes more rapidly than the outer contact line (Fig. 4.33D). Eventually, the oil droplet is separated completely from the solid surfaces by a thick aqueous film with a dimple (Fig. 4.33E). 4.3.2.3 In situ upgrading of heavy oil with nanoparticles Due to their large surface area, metallic NPs such as Ni, CuO/ZnO can be used as catalysts for in situ upgrading of heavy oil and bitumen during steam injection through a chemical process known as aquathermolysis. During this process, the presence of nanocatalysts catalyzes the breaking of carbon-sulfur bonds as follows [93]: RCH2 CH2 SCH3ðlÞ 1 2H2 OðlÞ 5 RCH3ðlÞ 1 CO2ðgÞ 1 H2ðgÞ 1 H2 SðgÞ 1 CH4ðgÞ (4.5) According to this reaction, the Carbon
Sulphur bond breaks and reduces the viscosity of the heavy oil or bitumen. Since most of the reaction products are in the

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gaseous phase, the density of the heavy oil or bitumen will also decrease. The production of CO2 and H2 will further improve the oil quality. Maity et al. [94] reported on benefits of aquathermolysis on desulfurization, hydrogenation, and viscosity reduction. Shokrlu and Babadagli (2011) [12] found that 500 ppm nickel NPs resulted in a viscosity reduction from 2700 to 1900 mPa  s. This effect of NPs on viscosity reduction has also been observed by Clark et al. [95,96]. Franco et al. [97] used bimetallic nanocatalysts to assist in heavy oil upgrading during continuous steam injection process. Hendraningrat et al. [98] reported on successfully reducing the viscosity of an Athabasca bitumen by about 80% using NP assisted aquathermolysis at 240  C for 12 hours using a hydrogen donor, decalin.

4.4 Adsorption and transportation of nanoparticles in porous media NPs adsorption and transport behavior is important for its EOR application. First, NPs need to be adsorbed on pore wall and oil
water interface to change wettability and reduce IFT. However, too much NPs adsorption and retention inside reservoir may cause formation damage and permeability impairment. Better understanding of NPs adsorption and transport behavior inside porous media is helpful to tailor NPs with proper surface property for EOR application. When hydrophilic nanofluid is injected into porous medium, five phenomena will occur: adsorption, desorption, blocking, transportation and aggregation of NPs. Five forces dominate the interactions between NPs and pore walls: the attractive potential force of van der Waals, repulsion force of electric double layers, Born repulsion, acidbase interaction, and hydrodynamics [99]. When the total force of these five forces is negative, the attraction is larger than repulsion between NPs and pore walls, which leads to adsorption of NPs on the pore walls. Otherwise desorption of NPs from the pore walls will occur. Adsorption and desorption is a dynamic balance process controlled by the total force between NPs and pore walls. Zhang et al. [100] discussed that both reversible and irreversible adsorption of NPs occurs during transport through porous medium. Blocking will take place if the diameter of the particle or NPs aggregation is larger than the size of pore throat. The aggregation of NPs happens if the previous equilibrium of the NP dispersion system breaks up and NPs form clusters [101]. Some images of adsorption and aggregate of NPs in porous medium are shown in Fig. 4.34. Beside above five forces, there are several factors can affect NPs adsorption inside porous media. Caldelas [103] reported that more NPs adsorption was observed in Boise sandstone at higher ionic strengths. Caldelas et al. [104] found a slight silica NPs adsorption increase in sandstone as the temperature increased from 55 C to 80 C. Hoek et al. [105] investigated the effect of surface roughness on NPs adsorption and observed higher

Nanoparticles for enhanced oil recovery

Figure 4.34 NPs adsorption inside porous medium. Left: ESEM image of NP adsorption inside core [102]; right: Microscope image of NPs adsorption in glass micromodel.

adsorption rate on rougher surface. Lecoanet and Wiesner [106] revealed that more NPs were adsorbed and retained in the same column with a lower flow rate.

4.4.1 Stability of nanoparticles suspension at reservoir conditions Stability of NP suspension at reservoir salinity and temperature is very important for their transport through the reservoir. If NPs lose their stability and aggregate to from larger particles, they may block some pore channels and impair the reservoir permeability. Furthermore, a high-temperature and high-salinity environment is unfavorable for NP stability. According to the DLVO theory [107,108], presence of cations in a NP suspension will lead to a thinner double layer. Divalent cations such as Mg21, Ca21, and Ba21 are effective in suppressing the double layers and result in NP aggregation [109]. A high temperature also increases the aggregation rate of NPs. At the same salinity, NP aggregates at 70 C are much larger than those at 25 C. Li et al. [110] studied ways to improve the stability of NP suspension and the effect of reservoir rocks on NP stability. Two approaches, namely, addition of hydrochloric acid (HCl) as a stabilizer and surface modification of NP with zwitterionic monomers to increase the double layer thickness were investigated (Fig. 4.35). Visualization experiments were performed at 70 C and atmosphere pressure for fumed silica NPs (FNP), FNP with HCl as a stabilizer (FNP-HCl) and zwitterionic monomers surface modified FNP (FNP-MD). The time when NP aggregation occurred for each sample was recorded and given in Table 4.6. It can be seen that FNP suspensions had the worst stability. All samples aggregated within two days. FNP-MD suspensions had the best stability. Five samples were still stable after thirty

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Figure 4.35 Schematic of preparation zwitterionic monomers surface modified NPs [110]. Table 4.6 NP stability screening test [110]. NPs Conc. (wt.%) FNP

0.1 0.2 0.3 0.4 0.5

day 2 day 1 ,1 day ,1 day ,1 day

FNP-MD

FNP-HCl

.30 .30 .30 .30 .30

.30 days day 25 day 15 day 12 day 10

days days days days days

Figure 4.36 FNP suspensions with reservoir rocks: (A), Day 1; (B), Day 2; (C), Day 4. (1: BBS1; 2: BSS2; 3: quartz; 4: limestone; 5: chalk; 6: shale) [110].

days. Compared with FNP cases, adding HCl into FNP can delay NP aggregation and the higher the HCl concentration the longer is the stabilization time [110]. Five reservoir rocks (Two Berea sandstones, chalk, limestone, and shale), as well as pure quartz as reference sample, were used to investigate the effect of reservoir rocks on the stability of NP suspension at 70 C. The photographs of FNP and FNP-MD samples with different rock samples are shown in Figs. 4.36 and 4.37, respectively. The results show that reservoir rocks such as limestone, chalk, and shale had a significant effect on NP stability. Due to high carbonate content, these rocks reacted with H1 ions in the NP suspension and destabilize it quickly. For the FNP-MD suspension, almost no rock sample affected its stability. The samples were stable after 30 days at 70 C [110].

Nanoparticles for enhanced oil recovery

Figure 4.37 FNP-MD suspensions with reservoir rocks: (A), Day 1; (B), Day 7; (C), Day 30. (1: BBS1; 2: BSS2; 3: quartz; 4: limestone; 5: chalk; 6: shale) [110].

4.4.2 Adsorption and transportation of nanoparticles in core samples Li et al. [83,86,87,111] performed single phase flooding experiments for oil-wet, neutral-wet, and water-wet Berea sandstone cores with nano-structure particle (NSP) and colloidal nanoparticles (CNP) suspension. NP adsorption curves were plotted and the differential pressure was measured to analyze NP adsorption and transport. Fig. 4.38 shows the differential pressure of oil-wet coreflooding experiments for NSP and CNP nanofluid with different NP concentrations. There was a big difference on differential pressure between NSP and CNP nanofluid injection. A higher differential pressure was observed in NSP injection and it increased with NP concentration. At the end of the nanofluid injection, the pressure was still increasing. During postflush brine injection, the differential pressure was still higher than the initial differential pressure during brine injection, thus implying NP adsorption and retention inside the core. The differential pressure during CNP nanofluid injection was kept constant during whole process and independent of NP concentration. It shows that CNP can propagate through the core without too much reduction on permeability, while NSP injection resulted in significant permeability impairment. Similar phenomena were also observed in single phase coreflooding experiments with neutral-wet and water-wet cores. NP adsorption curves for oil-wet, neutral-wet, and water-wet coreflooding are shown in Figs. 4.39
4.41, respectively. A dimensionless NP concentration (DNC) was used to show NP concentration changes during injection. It is defined as the ratio of effluent NP concentration to injected NP concentration. By comparing the CNC effluent curve with the tracer curve (orange), the NP adsorption behavior can be analyzed. NSP and CNP had different adsorption behavior in the core plugs. CNP had an ideal adsorption curve, where its concentration both increased and decreased later than tracer curve, indicating adsorption and desorption. Effluent NP concentration exhibited a plateau (almost equal to injected concentration) after adsorption on pore

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Figure 4.38 Differential pressure curves for oil wet cores with NSP injection (left) and CNP injection (right) [112].

Figure 4.39 Effluent NP concentration curves for oil wet cores (left: NSP; right: CNP) [112].

Dimensionless nanoparcles concentraon

1

N.W. NSP-0.05 wt.% N.W. NSP-0.2 wt.% N.W. NSP-0.5 wt.% Tracer

0.9 0.8

Nanofluid injection

0.7 0.6 0.5

Post-flush injection

0.4 0.3 0.2 0.1

0 0

1

2

3

4

Pore volume

5

6

7

8

Figure 4.40 Effluent NP concentration curves for neutral wet cores (left: NSP; right: CNP) [112].

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Figure 4.41 Effluent NP concentration curves for water wet cores (left: NSP; right: CNP) [112].

Table 4.7 NPs adsorption and retention percentage in different wettability cores for NSP and CNP [112]. NPs concentration wt.% NSP CNP

Oil wet Neutral wet Water wet

0.05%

0.2%

0.5%

0.2%

0.5%

36.1% 69.2% 37.8%

25% 70.1% 34.7%

16.3% B 27.3%

2.1% 20.1% 20.3%

1.8% 10.2% 4.6%

walls reached equilibrium. However, NSP had different adsorption curves. Its concentration decreased later than the tracer curve suggesting no NP desorption was observed. The plateau value was smaller than CNP case, which showed larger NP adsorption. The wetting state of the core also has an effect on NP adsorption and transport. Table 4.7 gives NPs adsorption and retention percentage in different wettability cores for NSP and CNP. The highest adsorption and retention of NSP occurred in a neutral-wet core where about 70% of NPs were adsorbed and trapped in the core. Fewer NPs were adsorbed and trapped in the oil-wet and water-wet cores. For CNP the least NP adsorption and retention occurred in an oil-wet core and more adsorption and retention of NPs was found in the neutral-wet and oil-wet cores. The permeability of core plugs before and after NP injection was measured and are shown in Table 4.8. It can be seen that almost in all cases, NSP injection resulted in significant the permeability reduction. Some core plugs became almost impermeable. The most probable reason was that NSP NPs aggregated and formed clusters which blocked pore and pore channels. However, CNP NP injection had almost no effect on permeability. Since CNP does not aggregate easily, it does not form aggregate to block pore channels and the adsorption of CNP might be close to a monolayer.

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Table 4.8 Permeability of core plugs [112]. Injection scenario k, mD (before NP injection)

k, mD (after NP injection)

kpost/kpre, %

O.W. NSP 0.05 wt.% O.W. NSP 0.2 wt.% O.W. NSP 0.5 wt.% O.W. CNP 0.05 wt.% O.W. CNP 0.2 wt.% O.W. CNP 0.5 wt.% N.W. NSP 0.05 wt.% N.W. NSP 0.2 wt.% N.W. NSP 0.5 wt.% N.W. CNP 0.05 wt.% N.W. CNP 0.2 wt.% N.W. CNP 0.5 wt.% W.W. NSP 0.05 wt.% W.W. NSP 0.2 wt.% W.W. NSP 0.5 wt.% W.W. CNP 0.05 wt.% W.W. CNP 0.2 wt.% W.W. CNP 0.5 wt.%

75.2 32.5 24.4 445.3 304.7 224.8 43.3 1.7 null 406.3 445.3 625.9 19.3 5.9 1.6 367.6 361.8 171.5

0.227 0.088 0.046 1.038 0.921 0.981 0.084 0.005 null 0.947 0.923 0.919 0.072 0.013 0.005 1.000 1.172 1.037

330.8 367.6 526.3 428.9 330.8 229.3 514.6 317.2 66.5 428.9 482.5 681.1 269.3 463.2 326.2 367.6 308.8 165.4

4.5 Health, safety and environment 4.5.1 Classification of water based chemicals Water based EOR techniques often involve injection of large amounts of chemicals into the reservoirs (polymers, surfactants, and other chemicals). Ideally these chemicals should be retained in the reservoirs, but it may be unavoidable that significant amounts will reach the production wells. It is unrealistic to separate all the chemicals from the produced water. For offshore EOR applications, this problem must therefore be solved either by using chemicals that can be discharged to the sea, or by re-injection of produced water. The first solution will strongly restrict the choice of chemicals for a given application and the most effective chemicals may have to be excluded. Re-injection of produced water will eliminate potential emissions, and the restrictions in choice of chemicals should disappear. This will also solve the problem of discharge of oil residues and possible production chemicals to the sea. In the oil industry chemicals are used not only as EOR agents, but also in drilling fluids, well intervention fluids, processing, and transportation (Fig. 4.42). Applied chemicals have to be approved based on properties like biodegradation, toxicity, and

Nanoparticles for enhanced oil recovery

Figure 4.42 Possible chemical discharge on an offshore platform [113].

bioaccumulation. Excluded from these approval tests are the so called green chemicals. In Europe these chemicals are approved and are included on the PLONOR (Pose Little Or No Risk To The Environment) list by OSPAR (Oslo and Paris Commission). The purpose of OSPAR is to protect the marine environment of the North-Atlantic and the OSPAR documents present guidelines for testing of chemicals used offshore [113]. Results from these tests classifies the different chemicals into four categories; black, red, yellow, and green. Black chemicals are illegal to use offshore but minor exceptions can be made if there are underlying safety or technical reasons. Red chemical category includes chemicals that are slowly degradable, shows potential for bioaccumulation and/or shows a high level of toxicity. These chemicals are often a danger to the environment, and it is therefore important to find more environmentally friendly and sustainable replacements. Yellow chemicals comprise of chemicals that are not included in the red and black categories. These are normally not classified as very environmentally dangerous. Green chemicals are considered to have little or no negative environmental effect and comprise chemicals that are covered by the PLONOR list. In offshore operations more than 99% of the chemicals that are discharged comprise of green and yellow chemicals. Nevertheless, 1% of black and red category

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chemicals is too much and finding environmentally friendly substitutes is still of great importance [114].

4.5.2 Environmental impact of chemical enhanced oil recovery The aim of chemical EOR is to recover capillary trapped oil and/or increase the sweep efficiency. Polymers, surfactants, and nanofluids are all classified as chemical EOR methods. In the following a brief discussion on the chemicals will be included with the emphasis on the environmental impact of NPs. Polymer water flooding is used for producing more of the mobile oil by increasing the injection fluid viscosity. Offshore polymer injection projects have been carried out in several places worldwide. Most polymers are classified in the red category of chemicals since they are not easily biodegraded. They should therefore not be discharged in the ocean, and reinjection of the produced water is needed. In addition, backproduced water tends to create a large amount of sludge that needs special handling [115]. One polymer that is commonly used for EOR purposes is HPAM, which is a nontoxic organic chemical. This polymer is classified in the red category due to slow biodegradability. For a chemical to have good potential as an EOR agent it however needs to be stable, and therefore a high degree of biodegradability is not beneficial. This is why red chemicals often show the best potential as EOR agents. Biopolymers has also been tested for EOR purposes, however, the problem here is that they are eaten up by bacteria. To avoid this, toxic biocides are added and thereby the advantages of using biopolymers are reduced. Surfactants are used to lower the interfacial tension between oil and water, and thereby mobilizing capillary trapped oil. Polymers have been applied to a few places offshore, but surfactants have only at a few occasions been used offshore. Most surfactants used onshore today are in the red category. Nanoparticles of various types have been applied for EOR purposes in the laboratory. These NPs are so called “free,” meaning that they are present in a powder form or in a liquid. They have the potential to be released to the environment and they have different properties and different levels of toxicity, biodegradation and bioaccumulation [116]. MgO, SiO2, and Fe2O3 are all chemicals included in the PLONOR list which comprise so called green chemicals [113]. These chemicals can therefore be used and discharged into the ocean without further testing. Data on bioaccumulation and biodegradation of MgO, SiO2, and Fe2O3 are not required for inorganic substances like these. Toxicity data is therefore the only data that are required for these substances. Through the European Chemical Agency (ECHA), the registration, evaluation, approval, and limitation of different chemicals are stated in the REACH regulations [117]. Information about all chemicals used for NPs is given by ECHA [118]. Here it is stated that it is no hazards identified regarding the use of TiO2. Presently, release of this substance to the

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environment is from paints, fragrances, machine wash liquids/detergents etc. Al2O3 is listed as a chemical with no identified eco toxic hazards. Release of this substance to the environment happens from industrial activity, paint, air fresheners or machine wash liquids/detergents etc. ZnO is listed as very toxic to aquatic life with long lasting effects [118] and will most likely fall under the black or red chemical classification category for NPs, and thus cannot be discharged to the ocean. Presently research is conducted on using cellulose NPs as an EOR agent. Cellulose is produced from wood and is both renewable, nontoxic and biodegradable [119]. These NPs can therefore be discharged into the ocean and re-injection of produced water (if free from oil) is not necessary. Volumetric of chemicals have to be considered in environmental impact evaluation. In addition to the classification of the different chemicals the required amount of the different chemicals is an important factor, both in regards to the environment and the economy. Table 4.9 indicates data for a typical reservoir [120]. Reasonable concentrations of polymers and surfactants are from field data and the concentration of NPs is based on experimental results [57]. The total amount of chemicals is calculated using a total reservoir bulk volume of 10 3 109 m3, and an average porosity of 20%. The amount of pore volume required for chemical waterflooding and nanoflooding is typical values from the literature. Since the concentration of chemicals is given in weight percent, the amount of chemicals is in kg (assuming the density of surfactants and polymers are equal to that of water and the NPs have the density of silica). Only small concentrations of the different chemicals are needed, but due to the field scale operation the total amount is large. An important factor here is that polymers and surfactants most likely are in the red or yellow category, while silica is green. Offshore constraints may often have negative effect on the efficiency of EOR processes. When injecting large amounts of NPs and/or chemicals into the reservoir, some of it will find its way back to the production facility together with the produced water. This produced water must be cleaned to the level required by regulations before pumping it to the ocean or the produced water must be re-injected to the reservoir. Re-injection of the produced water is common in offshore fields today, since this method allows the use of the most efficient chemicals [121]. However, the re-injection wells have a downtime of about 2%
4%. This reduces the production Table 4.9 Required amounts of polymers, surfactants, and NPs considering a medium size reservoir (10 3 109 m3) with a porosity of 20% [120]. EOR Concentration Pore volume Fluid volume Mass (109 kg) 9 3 method (wt.%) injection (frac.) injected (10 m )

Polymers Surfactant Silica NPs

0.09 0.175 0.05

0.2 0.1 0.1

0.4 0.2 0.2

0.36 0.35 0.27

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efficiency since the storage space offshore is highly limited and thereby the water containing the chemicals cannot be released to the ocean or stored on the platform.

4.5.3 Safety and health related to nanoparticle handling Nanotechnology is today used in many industries and a lot of studies have been performed on the interaction of nanomaterials with mammalian cells and laboratory animals to investigate safety and health related to NPs [122]. Some of these studies indicate negative impact of nanomaterials on life forms, but we should keep in mind that these studies use specific NPs in a controlled environment. These studies indicate a trend and the real interactions are likely to be more random. However, it is no doubt that biological interactions of nanomaterial (nanotoxicology) are a complex subject (Fig. 4.43). The studies show that different nanomaterials affect different types of life forms in different ways, which results in different impact on their health. In NP EOR processes we are working with particles that are in powder form or in a liquid and these particles can possibly enter the human body through inhalation, swallowing or through the skin. However, we should also notice that not all nanomaterials are harmful. By keeping all this research in mind it is possible to design safe NPs for the oil industry [123,124].

Figure 4.43 Schematic outline of important parameters in cell interactions with NPs [122].

Nanoparticles for enhanced oil recovery

4.6 Future works More work is needed before nano assisted EOR methods will be used widely in field applications. NPs have proved to be effective in many EOR-studies, but most of these studies have been laboratory experiments done at conditions other than those in the reservoir. However, even at laboratory conditions the NP oil recovery mechanisms are not well understood. Therefore, more studies are needed, especially at harsh reservoir conditions, to understand the EOR-mechanisms and investigate novel applications of NPs in EOR processes. With better knowledge of the recovery mechanisms it should be possible to tailor make cheap NPs for a specific EOR-application either as a single additive to the injection water or as an additive in combination with other EOR-chemicals (polymers and/or surfactants). When adequate knowledge of the nano-assisted EOR mechanisms is obtained, the next step would be field implementation. This requires data on field conditions, process variables, and scaling up theory from the laboratory to the field. Quite good screening criteria exist today, but it would be even better to have a modeling tool for scale up. Such tool is not available today and will require development of mathematical models for EOR-processes with NPs. Simulation modeling of these processes will help the reservoir engineers in the evaluation of various nano-based EOR-methods and reduce the uncertainties involved in using nano-EOR in the field.

4.7 Conclusions Up to now many EOR methods have not been economic and there are ongoing activities to optimize the methods and reduce the uncertainty. However, still we lack the fundamental understanding of how to mobilize trapped oil. Developments in computer tomography scanning technology, pore-scale flow, and network simulations have lately given fundamental insight of EOR recovery mechanisms. Now we have the possibility to study how crude oil wets the rock through nano-meter scale water films. Hopefully spin-offs from fundamental chemistry (such as ionexchange), physics, nanotechnology, and micro fluidics can contribute to improved understanding. Since EOR mechanisms need active ingredients on nano scale, it was natural that injection of NPs became a viable option in the oil industry. In the last decade many types of nanofluid behavior in porous media have been studied with respect to mobility control, displacement on pore scale, fundamental properties like interfacial tension

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and wettability and general transport mechanisms. Presently, the main concluding statements regarding NP based EOR are: 1. New oil fields are more difficult to find than previously which may result in more EOR activities in future. New EOR methods based on NPs as additive are promising because they are environmentally friendly, and can be tailored made to suit particular reservoirs conditions. 2. NPs own their unique physical and chemical properties to their extremely large surface-area-to-volume ratio. Today technology exists to prepare NPs from simple to very complex structures depending on application. 3. Laboratory studies indicate NPs can reduce the oil
water IFT, but not to around 1023 mN/m which is needed to have a significant reduction residual oil saturation. This suggests that lowering oil
water IFT is not the main cause for nano-EOR. However, NP stabilized emulsions can be used for conformance control, well treatment, flow assurance, and targeted deliver of cleanup fluids or surfactants. 4. Wettability alteration is an important effect of adding NPs to the injection fluid. Many studies have shown that in oil-wet reservoirs, NPs have the ability to alter the rock surface more water wet, thus leading to mobilization of oil drops in the pore space. 5. Polymer flooding can be more efficient if NPs are added to the polymer to increase the polymer viscosity so as to give a more favorable mobility ratio. In addition, NPs can stabilize foam which is used for mobility control. 6. One major problem in waterflooding of layered and heterogeneous reservoirs is early water breakthrough in high permeability streaks. Gel plugs are often placed in these zones to divert the water to less permeable zones. Surface functionalized NPs together with polymer can control gel formation and thereby improve water diversion and oil recovery. 7. The applicability of NPs in EOR processes is highly dependent on the transport properties of the particles. When NPs are dispersed as single particles they will move freely in the pore space and will not have any effect on permeability. However, if NPs agglomerate, they may block pore space and reduce permeability. It has also been observed that there is a reduction in permeability due to adsorption of NPs on the rock, especially if the adsorption is multilayered. 8. Stability of NPs in the injected fluid at reservoir temperature and salinity is needed for the transport of NPs through the reservoir. It is found that hightemperature, high-salinity, presence of solids such as limestone, shale, and chalk adversely affects stability of fumed silica NPs. A low pH, however, enhances the stability of fumed silica NPs. 9. Metallic NPs can act as catalysts for in situ upgrading of heavy oil or bitumen during steam injection through a chemical process known as aquathermoloysis, whereby the carbon
sulphur bond is broken. During this process, the viscosity of heavy oil is significantly reduced.

Nanoparticles for enhanced oil recovery

10. To date, no field trials of nano-EOR, other than conformance control, has been reported. 11. In nano-EOR processes, NPs are delivered to the field either in powder form or suspended in a liquid. Although NPs can possibly enter the human body through inhalation, swallowing or through the skin. It is possible to develop procedures for safe handling of NPs and even design safe NPs for EOR.

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CHAPTER FIVE

Intelligent materials in unconventional oil and gas recovery Bao Jia1, Charles Bose1, Sai Wang2, Dupeng Liu1, Hongsheng Wang2 and Cenk Temizel3 1

Department of Chemical & Petroleum, University of Kansas, Lawrence, KS, United States Department of Petroleum Engineering, University of University of North Dakota, Grand Forks, ND, United States Saudi Aramco, Dhahran, Kingdom of Saudi Arabia

2 3

5.1 Introduction Unconventional oil and gas resources usually fall into the following categories: (1) heavy oil and tar sands; (2) shale gas and tight gas; (3) shale oil and oil shale; (4) coalbed methane; and (5) gas hydrate. Globally, the gas reserve in the conventional plays is 6600 1 trillion cubic feet (TCF), in comparison, the reserve in unconventional plays is 730,000 1 TCF; and the oil reserve is between 9 and 13 trillion barrels in the conventional play while the reserve in the unconventional is more than twice as many [1]. Therefore, it is necessary to develop advanced technologies for unconventional to meet the world’s increasing energy consumption. Oil and gas industry plays a vital role for the global energy supply. The primary oil recovery is driven by the energy of the reservoir itself, the producing mechanisms include water drive, gas drive, and gravity drainage. After the primary process, secondary, and tertiary recovery methods, such as water flooding, miscible gas flooding, and polymer flooding [2
5] can be applied to recover the residual oil. These traditional methods might not work in unconventionals due to the unique reservoir characters, like the ultra-low permeability and porosity of shale reservoirs [6]. Utilization of nanoparticles to improve oil recovery has attracted more and more attention and has made remarkable progress in the laboratory. However, understanding of mechanisms of improved performance by nanoparticles, and the flow dynamics of nanofluids is still limited especially in unconventional plays. In this chapter, we aim to provide the nanotechnology updates including the theory fundamentals, experimental and model progress, and challenges for various unconventional resources.

Sustainable Materials for Oil and Gas Applications. DOI: https://doi.org/10.1016/B978-0-12-824380-0.00001-3

© 2021 Elsevier Inc. All rights reserved.

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5.2 Nanocatalysis and nanofluids for heavy oil The global oil demand rises continually due to the growth of world population and increasing technological development and living standard. Meanwhile, the consumption of conventional light oils has resulted in declining reserves of these resources. Therefore, substantial efforts have been devoted to the effective production and utilization of unconventional fossil fuel including heavy and extra-heavy (i.e., natural bitumen or oil sands) oils which account for 70% of total world oil reserves [7]. Compared to the conventional light oils production, recovery of heavy oil is more problematic for its high viscosity and immobility, high carbon/hydrogen (C/H) ratios, high heteroatom contents, and complex formation configuration [8]. To address these challenges, the rapidly growing nanotechnology has been utilized in heavy oil upgrading and recovery enhancement with considerable potential of economic and environmental benefits [9].

5.2.1 Mechanisms of nanomaterials in heavy oil reservoirs 5.2.1.1 Nanocatalysis The thermal upgrading process involves simultaneous cracking and hydrogenation of heavy molecules to lighter components with smaller molecules, which is effective method for heavy oil processing. In the 1980s, Hyne [10] reported that steam injection would bring not only the physical reduction of heavy oil viscosity by temperature increase but also the chemical reactions with oil components. The reaction route was named “aquathermolysis.” The following mechanism is proposed to be the main reaction for aquathermolysis: RCH2 CH2 SCH3 1 2H2 O 5 RH3 1 CO2 1 H2 1 H2 S 1 CH4

(5.1)

The introduction of catalysts is essential for promoting the hydrocracking (HCK), hydrodesulfurization (HDS), hydrodenitrogenation (HDN), hydrodeoxygenation (HDO), and hydrodemetallization (HDM). The nanoparticle catalysts, with enhanced catalytic activity, good dispersion ability, and high resistance to pore plugging, have been applied for the concept of “underground refinery” to enhance heavy oil recovery. Till now, various transition metals and oxides including Mo, Fe, Ni, Cu, Fe2O3, CuO, and alloys based nanocatalysts have been reported for heavy oil processing in the subsurface reservoirs. The utilization of nanocatalysis for in situ heavy oil processing has several advantages as follows. (1) It provides a large contact surface area between oil and catalysis that accelerates the hydrogenation process. (2) In the absence of pores in nanocatalysts, the deactivation happened on supported catalysts due to coke deposition and metal poisoning would be significantly reduced [3]. (3) The in situ prepared nanocatalysts could be injected into the

Intelligent materials in unconventional oil and gas recovery

Figure 5.1 Schematic of nanoparticle-assist heavy oil recovery [11].

subsurface along with steam and hydrogen reactant (Fig. 5.1). (4) The in situ reaction increasing the H/C atomic ratio in products and reducing both viscosity and coke formation [12]. (4) Hydrogenation is an exothermic reaction, the heat liberated further reduced the liquid products viscosity. (F) In situ processing reduces the operating costs as well as environmental concerns associated with greenhouse gas (GHG) emissions, Sox, and NOx production solid waste by-products and even fresh water consumption [13]. 5.2.1.2 Nanofluids A nanofluid is defined as a based fluid such water, oil or gas with nanoparticles (NPs) that have an average size of less than 100 nm in colloidal suspension [14]. The nanofluid systems have been applied in oil industry to increase heavy oil recovery, improve water disposition, break emulsions, and change the hydrophilic and hydrophobic behavior of water flood application [15]. EOR mechanisms by nanofluids injection contributing to improved oil recovery can be classified (Fig. 5.2). With the nanofluids injection, the pressure on the interface between oil and water is larger than the pressure in the bulk phase that causes a disjointing pressure. Under the influence of disjointing pressure, the nanoparticles form a self-assembled wedgeshaped film to separate the oil droplets from the rock surface and promote the heavy oil recovery. Nanoparticle plugging can be categorized as mechanical plugging and logjamming. Mechanical plugging might occur in the porous media when the particle size is larger than the size of the pore throat. When nanoparticle flows from the pore body to the pore throat, particles might accumulate at the entry of the pore throat to form log-jamming plugging. The pressure built up at the entry can push out the oil trapped in the pore, contributing to more oil recovery. The mechanism is shown in Fig. 5.3. The rock wettability is the tendency of a fluid to adhere to the rock surface competing with another immiscible fluid [17]. The nanofluids act as wettability

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Figure 5.2 EOR mechanisms by nanofluids injection. (A) disjointing pressure; (B) pore channels plugging; (C) wettability alternation; and (C) prevention asphaltene precipitation [7].

Figure 5.3 The schematic of two mechanisms causing pore channels plugging (A) mechanism entrapment (B) log-jamming [16].

modifier to alter the wettability of reservoir rock from oil-wet to water-wet favoring the heavy oil recovery [18]. A more favorable wettability with the contact angle smaller than 90 degrees can be obtained as illustrated in Fig. 5.4. Although the behavior seems similar to the conventional wettability behavior [20], results of contact angle degrees differs through to the water-wet side by applied nanofluid phase. The asphaltene precipitation could result in wettability alteration, formation permeability reduction, and transportation pipelines blockage which is detrimental to oil

Intelligent materials in unconventional oil and gas recovery

Figure 5.4 A schematic diagram of rock wettability conditions of a rock-brine/nanofluid-oil system [19,20].

recovery. NPs could effectively stabilize the asphaltene precipitation without causing environmental hazards. What’s more, the addition of nanoparticles in traditional fluids increases its effective viscosity and lower the interfacial tensions (IFT). The improved sweep efficiency for the injected fluids facilitates the heavy oil recovery process.

5.2.2 Studies of nanomaterials in heavy oil reservoirs Clark et al. [21] reported the first application of metal in upgrading bitumen by aquathermolysis [22] referring to the process of breakdown of CaS bound between asphaltene molecules which has the effect of reducing viscosity and increasing the saturation of saturates and aromatics. They found that mixing brine with metal compound instead of pure brine helps reduce the viscosity of heavy oil and reduce the asphaltene content. There exists controversy whether the metal should be aqueous or not to be functional in heavy oil recovery [23
25]. Shokrlu and Tayfun [26] reported applications of different types of metal nanoparticles in upgrading heavy oil/bitumen. They reported that viscosity reduction by nanoparticle could be achieved with or without steam stimulation, but steam stimulation has the bonus effect due to the aquathermolysis which is catalyzed by metal nanoparticles. The effect of reducing heavy oil viscosity depends on particle species because of different exothermic reactions. Besides the viscosity reduction effect, they found that nanoparticles also increase the thermal conductivity of the heavy oil. A key bottleneck for in situ application of nanocatalysts is their recyclability. Peluso [27] proposed an alternative process for downhole upgrading. As shown in Fig. 5.5, the nanocatalysts are injected through the injector well inside the porous media and upgraded oil is produced via the recovery well. Produced liquid from the reservoir contains active nanocatalysts inside the nondistillable residue that can be recycled and rejected to the porous reservoir. Greff and Babadagli [28] applied microwave radiation emitting high-frequency waves to study heavy oil viscosity reduction of different metal nanoparticles (Fe, Fe3O4, and Cu) with different concentrations under different temperatures and pressures. They reported

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Figure 5.5 Schematic representation of in situ upgrading process in the presence of nanocatalysts [27].

that heavy oil viscosity increases because of vaporization of the light components with the fraction up to 40%. They claimed that the vaporization is favorable for oil production for that the light components turn to be gas phase under high temperature which is a feature of deep reservoirs. Ehtesabi et al. [29] investigated heavy oil recovery in Berea sandstone with TiO2 nanofluids in the form of anatase and amorphous. High oil recovery factor between 49% and 80% were observed. The pressure drop across the core plug was small when the particle concentration was 0.01% but very high when concentration increases to 1% with small oil recovery, indicating the pore throat was blocked under high nanoparticle concentration that nanorods were formed when nanoparticles aggregate. Contact angle measurement showed that rock wettability was changed that is critical to the improved oil recovery. Ehtesabi et al. [29] reported four field tests in the Colombian heavy oil formations: two at the Castilla and two at the Chichimeme. Core flooding tests showed that mechanisms contributing to EOR are wettability alternation, removal of the deposited asphaltene, and reducing oil viscosity. 200 and 150 bbls were injected into two wells in the Castilla, instantaneous oil rate of 270and 280 bopd were observed, and the BSW was decreased around 11%. Also, in one well it was observed that the skin damage reduced by 73% and oil viscosity decreased by 47%. 86 and 107 bbls were injected into two wells in the Chichimenme, instantaneous oil rate of 310 and 87 bopd were observed; however, no BSW reduction was observed. The final production results still

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need more evaluation; on the whole, the field tests were successful that nanofluids injection could be expected to increase oil recovery in other similar fields. Alomair et al. [30] investigated heavy oil recovery in Berea sandstone with the presence of various nanoparticles dispersed in brine with comparisons without the presence of nanoparticles. The heavy oil they used is with a density of 17.45 degrees API. Based on their results, under low concentration of brine under 0.05 wt.%, the nanoparticle has the effect of decreasing interfacial tension as brine concentration decreases. However, as the concentration increases to 0.1 wt.%, the interfacial tension starts to increase as the concentration increases. By comparing different nanoparticles, they found that silicon oxide (SiO2) and aluminum oxide (Al2O3) outperform than nickel oxide (NiO) and titanium (TiO2) because they reduce the interfacial tension to a larger extent. The combined use of SiO2 and Al2O3 is proposed in their work, which increases oil recovery factor by 9.6%. Another finding is that the nanofluids hamper the formation of asphaltene precipitation. Cheraghian et al. [31] used five-spot etched glass model to study heavy oil recovery performance using fumed silica nanoparticle with and without the presence of surfactant. The oil density they used is 17 degrees API at 25 C. Adding silica nanoparticle in the injection fluids significantly outperforms than the scenario with surfactant alone. Increased oil recovery was as high as 13%. The possible reasons attributing to the result are: (1) viscosity increase double of the value with surfactant alone, leading to more favorable mobility ratio; (2) nanoparticle adsorption induces wettability alternation that decreases the contact angle on the rock surface caused by the intrinsic property of the SiO2 nanoparticles that they are hydrophilic. Bazazi et al. [32] applied micromodels to investigate the effect of silica-based nanofluid on the Alberta heavy oil recovery with reference experiments performed with the nonionic Tween 20 surfactant and pure water flooding. Heavy oil displacement experiments increased the oil recovery factor by 18%
39% using silica-based nanofluid and surfactant. Experiments results showed that the emulsion formation with the related chemicals is the main contributor to the higher oil recovery compared with water flooding. López et al. [33] studied the catalytic steam gasification of Colombian extra-heavy oil (EHO) fractions using functionalized aluminosilicates with NiO, MoO3, and CoO nanoparticles and evaluated the synergistic effect between active phase and the support. The results show the presence of a bimetallic active phase promote the aliphatic chains decomposition and the heteroatoms bonds dissociation. In addition, the bimetallic catalyst also reduces the coke formation after steam gasification process, yielding a conversion factor greater than 93%. Hosseinpour et al. [34] studied the catalytic performance of iron/iron oxide nanocatalysts for upgrading vacuum residue (VR) in supercritical water (SCW) and formic acid (FA) solution. By applying isotope labeling technique, they demonstrated the

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hematite iron oxide nanoparticles with a higher oxidation state (Fe31) are more effective in the oxidative removal of heteroatoms (sulfur, nitrogen) and in the reduction of heavy constituents (e.g., asphaltene) to light oil. The nanoparticles in SCW 1 FA solution provide better upgrading results by promoting the catalytic oxidative cracking and hydrogenation of heavy oil. Zhang et al. [35] reported an inorganic mesh membrane made up of cupric phosphate (Cu3(PO4)2) in a special intersected nanosheets-constructed structure. By combing the hierarchical structure with strong hydration ability of Cu3(PO4)2, the nanosheets-wrapped membrane exhibits a superhydrophilic and underwater superoleophobic property. The excellent anti oil-fouling and antibio-fouling property show great potential for practical application in heavy oil and water separation (see Fig. 5.6). Hassanpour et al. [36] investigated concentrations effect of titanium oxide and iron oxide nanoparticles retarding the asphaltene precipitating in the process of CO2 injection into synthetic oils. The experimental results show that both nanoparticles can reduce the IFT between CO2 gas and synthetic oil solution and effectively impede the precipitation of asphaltene. The reduced intensity of asphaltene precipitation in the optimum concentration for oil solutions containing Fe3O4 and TiO2 nanoparticles is 18% and 17%, respectively (see Fig. 5.7). Because of their unique properties, nanocatalysts, and nanofluids have considerable potential applications for enhancing heavy oil upgrading and recovery. However, employment of these technologies in oil industry are still facing several important issues. The challenges include the aggregation problem because some nanoparticles cannot endure high salinity, high temperature and pressure environment; combined effects of multiple nanofluids need more experimental work; modeling of nanofluids injection still needs more sound basis prior to filed-operation.

Figure 5.6 The nanosheets-wrapped membrane for oil/water separation [35].

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Figure 5.7 Interfacial tension reduction caused by nanoparticles at optimum concentration [36].

5.3 Nanoparticles for enhanced oil recovery in shales Nanoparticles have special characteristics for EOR in shale reservoirs because they have excellent propagation ability in the porous media [37] without blocking pore throats; can be easily modified to adjust for different characterized reservoir; can modify the reservoir properties for subsequent EOR propose [38,39]; can be directed to the targeting location accurately and easy to recycle on the production side assist to reduce the residual oil saturation. Nanoparticles work in shales by stabilizing the generated foam generated with surfactant; modifying oil viscosity; alternating the rock wettability; and controlling the flow conformance. Pu and Zhao [40] proposed to combine the functional nanoparticles with surfactant for the EOR in Williston Basin. The Williston Basin is a large intracratonic sedimentary basin of North America, it covers the great proportion of North Dakota and extends to Montana and South Dakota. Also, southeastern part of Saskatchewan and a small section of southwestern Manitoba of Canada also lie in the Williston Basin. This hydrocarbonrich basin is performed as the oval-shaped structure and the tremendous surface area which is around 120,000
240,000 square miles is perfectly suited for serving as hydrocarbon source rocks. The Bakken Formation, which is assumed as the main production zone, is located at the deep part of Williston Basin, was investigated and confirmed as a very thin (maximum thickness 145 ft.), naturally fractured Upper Devonian-Lower Mississippian sedimentary unit (Fig. 5.8). The Bakken formation could be divided into three intervals: the upper and lower shale, which contains the rich organic contents thus were considered

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Figure 5.8 The Williston Basin and Bakken formation [41].

as source rock of the Bakken formation, and the lithologically variable middle member [42]. The Bakken formation was estimated to contain an enormous amount of oil, estimated from 200 to 400 billion barrels. Although the Bakken Formation is very thin compared to other oil producing horizons, it has recently attracted much attention because it’s extremely high carbon content places it among the richest hydrocarbon source rocks in the world. While for this formation, the porosity and permeability were proved to be low due to the shale type of rock. Even though the horizontal drilling and multi-stage hydraulic fracturing technologies contribute to the current high oil production rate, primary recovery is still low, ranging from 5% to 10% of OOIP. The project from the Oil and Gas Research Council (OGRC) at North Dakota aims to develop an innovative silica nanoparticle enriched with surfactant for the process of EOR in middle Bakken formation. The mixed solution which mainly contained NPs and Surfactant was predicted to penetrate into the matrix deeply and displace the oil out which locked in the micro and nanopore size. The designed silica nanoparticles were proposed to maintain several features when injected into the tight formation: (1) controllable delivery of surfactant and alter the wettability of interfaces of oil with the fluid; (2) high mobility, water solubility, stability, and uniform dispersion in the reservoir fluids; (3) tunable chemical composition, shape, size, porosity, and functionality; (4) environmentally friendly; and (5) low cost.

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The silica and carbon NPs are proved to be the effective surfactant carrier for the EOR fluid composition. In this research project, the researchers will first develop the porous and nonporous silica nanoparticles and carbon nanoparticles. Then the surfactant will be doped into the porous nanoparticles, while for the nonporous nanoparticle, the surfactant will adhere to the surface of this type of nanoparticles. Generally, more surfactant was expected to be carried by the porous nanoparticles. The surfactant carrying efficiency was mainly controlled by the two parameters, the nanoparticle size and nanoparticle porosity, which can optimize the carrying efficiency by tuning the above factors. The generated hybrid between nanoparticle and surfactant is termed as the key element in the fluid. Their tiny size and purpose-designed surface chemistry will alter the reservoir fluid interfacial wettability, decrease the interfacial energy barrier, and enhance the fluid movability, and furthermore, facilitate the penetration of rocks as well as drainage of rocks after displacing oil. Furthermore, the nature of the silica and carbon materials will outstand at harsh environment, such as high temperature, high pressure and extreme salinity (194 F
248 F, TDS 150,000
300,000 ppm). Since then, the critical step for this project is to synthesize and optimize the nanoparticle-surfactant. In their work, the reverse micro method and the Sober method followed heating treatment were applied to generate the silica nanoparticles. To synthesize the carbon nanoparticles, the bottom-up chemical method was proposed. Then the surfactant was integrated to the nanoparticles to achieve the initial purpose. Fig. 5.9 illustrates the schematic diagram of development of nanoparticle enriched surfactant for the EOR process. Up-to-date, this project is at the initial nanoparticles’ synthesis stage. The further research will focus on the surfactant screening and nanoparticle-surfactant interactions, including phase behavior investigation, optimization of the solubilization ratio and salinity, the interfacial tension measurement, and the critical micelle concentration (CMG) measurement. The last stage will be the evaluation and optimization of the

Figure 5.9 Schematic diagram of nanoparticle-surfactant fluid for EOR [35].

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nanoparticle-surfactant hybrid for EOR process. In this stage, the adsorption of surfactants from aqueous solutions in the porous media will be conducted because surfactant loss attributed to adsorption on the reservoir rocks impairs the effectiveness and renders the process economically unfeasible. Also, the oil recovery experiments, including the imbibition test and core flooding experiments will be carried out to help set up the economic analysis. The anticipated results will focus on conceptual validation and thorough understanding of the application of nanoparticle-loaded surfactant effects on Bakken tight formation. Applying nanoparticles to the tight formation will face some challenges. First, the tight formation constitutes with the micro and nanopore size, thus the diameter control of the NPs will be the main challenge for the fluid flow through the porous media. Second, a key consideration to impede the NPs penetrate into the tiny throats will be the high temperature, high pressure, and high salinity downhole environment. Those harsh conditions may alter the properties of the NPs and then lost the function of replacing the residual oil blocked in the nanoscale pore. For example, most of the reported NPs cannot resist the high salinity conditions. With the high concentration of the saline ions, the NPs might agglomerate that the obvious aggregation will be a barrier for the nanoscale particles penetrate into the formation and prevent the effective injectivity.

5.4 Materials for formation damage control 5.4.1 Mechanisms of formation damage Formation damage in the subsurface is due to: (1) fines migration; (2) clay swelling; and (3) fluid loss during drilling and completions. 5.4.1.1 Formation damage due to fines migration Fines are small unconsolidated particles generally smaller than 37 μm, which are detached and released from rock surfaces. Formation fines can include clay as well as nonclay particles, and they may or may not be charged. These loose unconsolidated particles move with the fluid flow and cause formation damage when they block pores of formation rocks. Pore plugging results in a reduction of productivity index. Several surface forces have been held accountable for this phenomenon: (1) London/Van der Waal’s attraction; (2) double layer and Born repulsion; and hydrodynamic forces. These forces cause detachment of fines from their respective surfaces, when the total interaction between fines and pore surfaces become positive (repulsive forces exceed attractive forces) [43]. Khilar and Fogler [44] explained all the effective surface forces

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Table 5.1 Effective potential in fines migration. Force effect Symbol

Force

Repulsion Attraction Repulsion Attraction Repulsion

Electric double layer London/van der Waals Born Acid/base interaction Hydrodynamic potential

VDLR VLVA VBR VAB VHR

between fines and pore surfaces. They consist of both colloidal and hydrodynamic forces. Forces and the respective roles played in fines detachment are listed in Table 5.1 [44]. Total interaction energy between fines and surface is the summation of all effective potentials. VT 5 VDLR 1 VLVA 1 VBR 1 VAB 1 VHR

(5.2)

Repulsive forces are dominant if VT is positive whereas attractive forces are dominant if it is negative [45]. Fines migration occurs during several stages of oil and gas well operations: during drilling fluid invasion into the formation, during oil and gas production and during water flooding operations. Well productivity reduction due to fines migration involves different stages like detachment of particles from the surface, their mobilization, followed by capture by the rock resulting in a permeability decline. Several laboratory studies have recorded a direct correlation between permeability decline and a piecewise change in injection velocity during core flood studies [46,47]. Migrating fines, clog the pore throat diameters of formation rock reducing the number of pore throats contributing towards production (Fig. 5.10). Flow velocity accelerates the movement of fines [47]. The minimum flow rate at which fines detach and migrate within the pores of the formation is known as “critical flow rate.” Reservoir fluid velocity increases exponentially near the wellbore and can overcome the critical velocity, required for suspending fines in the liquid stream. With continued well production, these fines keep getting deposited near the wellbore leading to very high skin values near the wellbore region. Other factors thought to be impacting fines migration include salinity, pH, temperature, residual oil saturation, wettability, oil polarity, and fractional flow of oil and water (Fig. 5.11) [49,50]. Previous studies have also shown that fines invasion can significantly reduce proppant pack permeability affecting well production. Damage to proppant pack permeability can occur either due to one or all off the following mechanisms [51]: (1) surface deposition of particles; (2) pore-throat bridging and accumulation; (3) internal filter cake formation; (4) external filter cake formation, and (5) infiltration sedimentation.

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Figure 5.10 Fines causing permeability decline by plugging pore throats [48].

Figure 5.11 Formation fines migration after several months of well production [48].

5.4.1.2 The problem of fines migration during low salinity water flooding Low Salinity Water Flooding (LWSF) is a very popular EOR method in the industry, and its advantages have been proved in numerous experimental studies and field trials. However, the low salinity injection fluid might trigger formation damage by causing fines migration, due to the incompatibility of injection fluid with reservoir fluids. The chemical environment of the reservoir, including pH, fluid salinity, temperature, etc are altered by injected low salinity fluid [52]. Fines settled on pores result in severe permeability impairment near the wellbore, reducing well injectivity during LSWF. To take advantage of the positive benefits of LSWF, it is very important that fines migration has to be controlled by either limiting flow rate or by forcing them to settle down somehow.

5.4.2 Formation damage control due to fines migration using nanoparticles The oil industry has in the recent past turned to nanotechnology to solve the age-old fines migration problem. Due to their small size, large surface area to mass ration, chemical and thermal stability and the added advantage of being environmentally friendly, nanoparticles are ideal solutions for many challenges faced by oil and gas industry. Nanoparticles are superior to their larger sized parent chemicals due to their enhanced mechanical, electrical and thermal properties, and interaction potential.

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When it comes to combating fines migration, they can exist in the smallest of pore throats, without affecting the total porosity and permeability [53]. The best strategy to avoid fines migration would be preventing them from getting detached from parent surface. This can be achieved either by maintaining flow rate below a critical rate and somehow preventing them from migrating. Nanoparticles having extremely high surface areas of approximately about 200 m3/g can help achieve this objective by altering the surface potential of fine particles or grain surfaces. These nanoparticles are usually on the order of tens of nanometers. Owing to their small size compared to pore-throat sizes, the nanofluid flow has a negligible effect on pore-throat structures and total reservoir permeability. It is thought that nanoparticles can effectively reduce the double-layer repulsive forces between fine particles and rock grains by changing associated zeta potentials of absorbents. This reduction in repulsive forces among loose particles helps maintain the integrity of rock textures preventing fines detachments. Modified physiochemical forces like London-van der Waals, electric double layer, and Born repulsive forces help retain more fine particles [49,52,54] introduced the idea of using nanoparticles as a remedy for formation damage by using nanoparticles for fines fixation in proppant packs. The idea is to change the surface characteristics of porous media by treating them with nanoparticles to stick fines firmly in place and prevent their movement in porous rocks. The Derjaguin-Landau-Verwey-Overbeek (DLVO) theory, states that when two particles are near each other, the stability of particles in solution is affected by the total energy of interactions, which includes attractive and repulsive terms such as electric DLR, LVA, Born repulsion, acid/base interaction, and hydrodynamic forces [44]. This energy of interaction vs distance of separation relation is demonstrated in Fig. 5.12.

Figure 5.12 Energy of interaction vs. distance of separation [55].

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Ahmadi et al. [43] assumed Born repulsion to be negligible in their study because the distance of interaction was more than 1 nm. Acid/base interaction was also ignored because they used distilled water in their tests. Hydrodynamic forces were also neglected because in their study, fluid flow velocity was slow (aided by gravity forces). These assumptions limited forces under study to be just DLR and LVA. Specific nanoparticles were selected based on their ability to prevent fines migration. Parameters used in selection were specific surface area and the capability to capture and attach particles to the surface. Accordingly, SiO2, Al2O3, and MgO NPs were selected for the study. SiO2 particles (sphere shaped glass beads) were used to prepare a synthetic porous medium to simulate sandstone reservoir rocks. To study the effect of coating with nanoparticles on preventing fines migration, surface of nanoparticles was coated with different types of nanofluid treatments. Fines used in this study, were composed of different minerals that are representative of formation fines in the reservoir [43]. A fine suspension was made in a funnel, by adding fine particles to distilled water (to prevent effects of acid/base interaction), which was injected from the top of the packed-column and flowed down through the packed bed because of gravity forces (to avoid effects of hydrodynamic forces). An untreated bed, consisting of untreated silica particles was used as the reference test for the studies. Coating the silica particles with nanoparticles, was expected to have an impact on the total energy of interactions between fines and pore surfaces. SEM imaging, energy-dispersive X-ray spectroscopy analysis of treated silica particles, as well as zeta-potential tests, were carried out to ensure proper coating was obtained. Zeta potential provides important information on colloidal characteristics, surface potential, double-layer structure, and point of zero charge [43]. Theoretical studies conducted on the effect of nanoparticles to firmly set fines in place revealed changes in DLR and LVA owing to presence of nanoparticles on the surface. Measured zeta potential values, the main parameter influencing DLR was used to calculate total energy of interaction. MgO was found to have the highest tendency to reduce fines migration by influencing surface properties of coated materials. Experimental results also confirmed conclusions from theoretical studies [43].

5.4.3 Formation damage due to clay instability 5.4.3.1 Mechanisms of clay instability Clay minerals can cause significant formation damage to hydrocarbon reservoirs by fines migration and clay swelling. Formation damage often leads to poor productivity because of their negative impact on reservoir permeability. Swelling clays include smectites, vermiculite, and swelling chlorite. Swelling clays carry a structural charge deficiency which is balanced by interlayer cations. Hydration of interlayer cations and formation of diffuse double layer cause expansion of structural layers and thus clay swelling [56].

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Clay stabilizers are the chemicals used in the industry to mitigate clay swelling problem. Since both fines migration and clay swelling are caused by the negative surface charge on clay particles, most clay stabilizers are designed to neutralize this negative charge. Clay stabilizers are usually simple inorganic salts, cations, cationic inorganic polymers, cationic organic polymers, anionic organic polymers, and nonionic organic polymers. The conventional practice of using brine such as 4% KCl is cheap, but it can stabilize clay swelling only until the well is put into production because K 1 ions get washed away during the production phase. Smectite clay is usually most susceptible to clay swelling. Change in water chemistry at the wellbore location due to drilling fluids and influx of produce water are the main reasons that usually trigger clay swelling [57]. 5.4.3.2 Application of nanoparticles for clay stabilization Patel et al. [57] studied the effectiveness of five commercially available nanoparticlesSiO2, Al2O3, ZnO, Fe2O3, and ZrO2, in preventing swelling of natural bentonite clay, rich in montmorillonite. Effectiveness was measured using a visual swelling index method based on ASTM D5890-11 and was compared to the swelling in 4% KCl brine [57]. The height of the clay in a vial was recorded every 24 hours for three days, and this measured height is compared to the initial height of the clay hinitial to calculate a parameter called Swelling Index (SI) (Fig. 5.13). SI 5 ht 2 hinitial=hinitial

(5.3)

Figure 5.13 The effectiveness of nanoparticle treatments to prevent bentonite swelling after washing KCl from the sample. The Baseline swelling indexes of bentonite measured in distilled water (2.6) and KCl brine (0.94) are shown as dashed lines [57].

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The study confirmed the potential of commercial nanoparticles to mitigate clay swelling although it does not mention the mechanism involved. Silica nanoparticles showed most promising results among all the nanoparticles tested in the studies by recording lowest volume expansion in visual swell tests. Swelling index tests showed even improved results when silica nanoparticles were used in conjunction with 4 wt.% KCl. Nanoparticles continued to mitigate swelling even after washing clay with fresh water. Results confirm that silica nanoparticles reduce swelling of clay powders [57]. Agarwal et al. [58] studied the effect of colloidal silica nanoparticles in clay stabilization in further detail. Silica nanoparticles were selected because of their abundant availability and low production cost. It was postulated that silica nanoparticles could reduce formation damage due to clay instability problems, by electrostatically pinning the charges on clay particles in the pore surfaces. Moreover, silica nanoparticles are nontoxic in nature and hence environment-friendly. Sandstone core samples were treated by cationic and anionic colloidal nanoparticle dispersion inside a core holder. Nanoparticles were injected using a core flooding test apparatus. Differential pressure measurements across the core samples at regular intervals were studied to analyze the difference in permeability values when nanoparticles were used [58]. Effluent samples were also analyzed at regular intervals to evaluate the presence of migrated clay particles. Particle size and zeta potential measurements were also carried out to understand the interaction between nanoparticles and clay particles. Studied confirmed significant improvement in clay stabilization when colloidal nanoparticles were added to the aqueous fluid system, possibly due to adsorption of nanoparticles on the clay particle active sites. Permeability values were found to be significantly higher for the core flooding tests where sandstone samples were treated with positively or negatively charged nanoparticles. The reason is thought to be the attachment of positively charged nanoparticles to the negatively charged clay surfaces, thereby pinning clay particles in the pore surfaces. Negatively charged nanoparticles attach to the positively charged edges of the clay particles preventing water molecules and ions from intercalating into the clay laminated structures. Thus, the combined effect of positive and negative charged nanoparticles, are expected to ensure long-term clay stability [58]. Bottle tests were also conducted to study the effect of nanoparticles on montmorillonite clay (swellable clay). Montmorillonite clay was dispersed in de-ionized solution with and without nanoparticles. In the absence of nanoparticles, almost all clay particles precipitated, forming a thick layer. However, upon addition of nanoparticles, most bigger clay particles settled down, forming much thinner and stable layer, leaving only finer clay particles in the de-ionized water. Bottle tests showed efficiency of silica nanoparticles in stabilizing montmorillonite clay and in suppressing clay swelling [58] (Figs. 5.14 and 5.15).

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Figure 5.14 Structure of typical clay particle with negatively charged faces and positively charged edges. Cation nanoparticles can absorb onto negatively charged faces of clay particles and anionic nanoparticles can absorb onto the positively charged edges of clay particles [58].

Figure 5.15 (A) Clay particle stabilization with cationic nanoparticles on the surface. (B) Anionic nanoparticles on the edges [58].

5.4.4 Formation damage due to fluid leak-off 5.4.4.1 Mechanisms of fluid leak-off The Invasion of drilling fluids causes formation damage. Formation damage by fluid leak-off is, to an extent controlled by the formation of mud filter cakes. Fluid loss occurs due to the differential pressure between well-bore pressure and reservoir pressure. After a portion of the fluid leaks-off into the reservoir, a mud filter cake forms on the rock surface which reduces further infiltration of fluid into the reservoir. A good drilling fluid would not only exhibit good suspension capability of transporting cuttings out of the wellbore during drilling but also form a stable filter cake which helps in minimizing fluid leak-off into the reservoir. Nanoparticles have been added to drilling fluids to enhance their viscosity and to aid information of more effective filter cakes. The fluid which “leaks off” into the reservoir, during drilling and completion operations, often cause physical and hydraulic damage to the reservoir. Hydraulic damage is caused in the area invaded by the leaked off fluid, due to shifts in capillary

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pressure and relative permeability curves [59]. The volume of the fluid lost into the formation depends on several parameters like permeability of the formation, the viscosity of the fluid injected, the difference between fracture injection pressure and reservoir pressure and the initial water saturation of the formation [60
62]. There is an inverse square root relation between capillary pressure and permeability of the formation into which fluid leaks-off. Hence damages due to fluid leak-off are significant even in tight and ultra-tight formations, despite fluid loss volumes being small, owing to the very low permeability of these formations [62]. 5.4.4.2 Nanoparticles for fluid leak-off Barry et al. [63] and Jung et al. [64] have studied the effect of adding ferric oxide nanoparticles to bentonite drilling fluids. Nanoparticles were found to have a positive impact on rheological and filtration properties of bentonite-based drilling fluids. Contreras et al. investigated the application of in-house prepared iron-based nanoparticles (NP1) and calcium-based nanoparticles (NP2) with oil-based mud, to reduce filtration loss in permeable media under high-pressure high-temperature conditions. Ceramic disks were used as filtration media to test the efficiency of nanoparticles with glide graphite in porous media. Experiments were carried out at different concentrations of graphite and reduction in filtrate volumes were observed up to 76% [65]. The behavior of NP and graphite at low pressure and temperature conditions were also investigated, and both NP’s showed a reduction up to 100% when tested with low and high graphite concentrations. Results concluded that blends of NP’s and graphite could be used as additives with oil-based muds to minimize formation damage [65]. Vryzas et al. [66] studied the fluid loss characteristics of Iron Oxide (Fe2O3) and Silica Nanoparticles (SiO2) when used with water-based drilling fluids. Studies were conducted using both American Petroleum Institute (API) static filter press and a High-Pressure High Temperature (300 psi/2500 F) filter press. A CT scan was used for analyzing filter cake and a SEM was used to analyze the morphology of the filter cake formed. API static and HTHP filter press studies indicated a significant improvement in fluid loss and filter cake characteristics for samples containing iron oxide nanoparticles. 0.5% was found to be the optimal concentration for the Fe2O3 nanoparticles above which the fluid loss characteristics and fluid loss properties were negatively impacted.

5.5 Materials to strengthen wellbore in shales The wellbore stability problem becomes more complex in unconventional (shale gas/oil) reservoirs due to the interactions between drilling fluids and sensitive shales [67]. Wellbore instability is a critical issue in many shale gas reservoirs as it is

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important for the effective development of gas resources from the shales. Shales usually have a considerable amount of kerogen (organic matters) and high content of clay, which make the rock hard and brittle [68
71]. Generally, most of the pores in shales are in nano-meter scale, and the pore structures are complicated because of the existence of finely dispersed kerogen [68,69,72]. An image of kerogen in a shale sample from the Lower Bakken formation in the Williston Basin [73] clearly shows the complex pore structures and size distribution in the kerogen. High-pressure mercury injection capillary pressure (MICP) measurements have conducted for numerous shale samples, which indicate that most of the pore throat radii in kerogen are usually very small (r # 4 nm) [73
76] that nanoparticle can penetrate through if the particle size is smaller than the pore size [77]. Such small pore throats induce high capillary pressure between phases when oil, gas, and water coexist in the core. The smaller the pore throat size, the more difficult it is to overcome capillary resistance between phases. Therefore, the flow mechanisms of drilling fluids in shales must be thoroughly studied to solve the wellbore stability problem in the shale reservoirs. Because of the tiny pore size distribution in the shale formations, the fluid flow mechanisms are different to that in conventional rocks [78]. Four flow regimes can be defined by the Knudsen number [73]. The high flow rate is achievable in the viscous flow region where Darcy’s Law is applicable in conventional reservoirs. However, in shale reservoirs, the flow is mainly in the free molecular flow region, molecular diffusion dominates the transportation in the pore space. Therefore, diffusion and adsorption play important roles in the fluid transportation process when drilling wells in the shale formations [79
81]. In order to strengthen the wellbore in the shale formations during the drilling process, nanoparticles are used to stabilize the shales considering the nano-meter pores in there.

5.5.1 Mechanisms of wellbore strengthening The adsorption of water to shale is known to change some of the physical properties of the rock, which has been shown to have a negative effect on the compressive strength of the rock [80]. When water-based mud is used as a drilling fluid, the adsorption of water on the shale needs to be considered in the drilling plan. Dokhani et al. [81] studied the moisture adsorption to shale surfaces is investigated to identify the proper isotherm type curve. Their results showed that the moisture content of shale is correlated with water activity using a multilayer adsorption theory, and the GAB (Guggenheim, Anderson, and De Boer) model can be used to describe the adsorption process for the selected shale types. Cai et al. [82] investigated the water invasion problem to the shales and found that particles in conventional drilling fluids are too large to seal the nano-sized pore throats of shales and to build an effective mud cake on the shale surface and reduce fluid invasion. However, nanoparticles are

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able to decrease the water invasion and stabilize the shale during the drilling process. Based on laboratory experiments, they developed commercially available, inexpensive, nonmodified silica nanoparticles (particle sizes vary from 5 to 22 nm) to improve water-based drilling muds properties used in shale reservoir drilling. A stable wellbore maintenance in the operation of drilling and production is fully important. Petroleum engineers have taken considerable measures to increase the fracture pressure of rock at depth since 1940. High pressure on the shale formations is one of the main reasons for wellbore stability problems. The stable status must keep the shape and direction of the hole under control during drilling and prevent solid particle influx and hole collapse during production. Two factors are influencing the wellbore stability: 1. Controllable factors: including the wellbore fluid pressure and chemical composition. Researchers studying on montmorillonitic rocks and clays held the opinion that, some kinds of shales can absorb (or desorb) water or ion and swell (or shrink), which lead to the expansion. The difference between the drilling fluids and shales is the driving force of this interaction, which could weaken the shale formation [83]. Some researchers have focused on shale-fluid interaction [84] and wellbore stability [85]. 2. Uncontrollable factors: including rock strength, pore pressure, and earth stresses. From the point of geomechanics, the increase of pore pressure could lead to the decrease of effective stress [86], which weaken the shale rock and cause the problems of wellbore instability [87]. For conventional formation, during overbalanced drilling, the solid particles in the drilling fluids could enter the pores of formation, which creates the mud cake, preventing the further filtration [88]. However, the prevention mechanism is difficult to achieve because the solid particles in conventional drilling fluid cannot match the scale of pore size of shale formations [87]. This difficulty can cause wellbore stability problems in shale formations, which arouses in-depth study on sealing of pores or microcracks of shale. Considering that the size of nanoparticles is comparable to those of pores in shales, it can be a potential alternative to seal the pores and microcracks of shale. For now, though, the application of nanoparticles in wellbore stability is in the preliminary stage. An example is Atoka Shale; the permeability was reduced to 1% after adding 5
22 nm silica nanoparticles [82]. The nanoparticles penetrate into the shale in deep. As a result, it prevents water invasion. However, limited types of nanoparticles as sealing agents have been tested. Further studies and field application to improve our understanding of the mechanism about how the nanoparticles seal pores and microcracks need to be performed.

5.5.2 Nanoparticles for wellbore strengthening Nanoparticles are able to decrease the water invasion and stabilize the shale during the drilling process. Based on laboratory experiments, they developed commercially

Intelligent materials in unconventional oil and gas recovery

available, inexpensive, nonmodified silica nanoparticles (particle sizes vary from 5 to 22 nm) to improve water-based drilling muds properties used in shale reservoir drilling. The work presented herein concentrates on improved wellbore stability using NP as agents in drilling fluid formulations. Contreras et al. [65] presented an experimental study where a significant fracture pressure increase was achieved in shale and the predominant wellbore strengthening mechanism was identified. They found that the main implication of the work is that wellbore strengthening occurs in shale formations using oil-based mud with the addition of nanoparticles (NPs) and graphite. Jung et al. [89] compared the performance of water-based and oil-based muds on shale formations, where they found that either internal or external filter cakes should be developed to reduce water invasion from water-based mud. Since shale has extremely low permeability and a very small pore throat size, normal mud cakes fail to reduce the fluid invasion. However, adding nanoparticle additives to water-based drilling fluids can significantly reduce water invasion into shales. They reported results for shale permeability and pressure penetration though shales using different fluids: brine, base mud, and nanoparticle-based muds. Different concentrations of nanoparticles in the mud were used to define the effects of nanoparticles clearly. Their results clearly showed that nanoparticles could act as good shale inhibitors to ensure wellbore stability during drilling. Hoxha et al. [90] analyzed the mechanisms of shale stabilization using nanoparticles. They identified that traditional water-based fluids tend to penetrate into shale formations, and interact with clay minerals, resulting in clay swelling and wellbore instability, especially for the deep-water shales. They studied the pore pressure transmission (PPT) tests with test fluids that contain two new families of nanoparticles and evaluated the major factors that affect pore pressure transmission in different shales. The results of PPT tests using fluids that contain nanoparticles in different sizes, types, and concentrations showed that nanoparticles of 10 nm size could delay the time needed to reach the equilibrium state in the shales. Fast pore pressure transmission and the time delay to reach the equilibrium state will reduce hydration and swelling of shales and improve wellbore stability in deepwater drilling. Aftab et al. [91] investigated five different drilling mud systems for enhancement of rheological properties and shale inhibition by adding nanoparticles in the muds. It showed that the addition of nanoparticles in the KCl mud system could improve the shale inhibition. API, HPHT filtrate loss volume, plastic viscosity (PV) and yield point (YP) were improved using nanoplatelet (GNP). Their results showed that shale swelling is mitigated by a small concentration of KCl with GNP compared to the mud a with a higher concentration of KCl and PHPA in the water-based mud. Thus, GNP better enhanced the performance of water-baesd mud. Intensive study on nanoparticles adsorption onto surfaces has been done in the scientific fields of biotechnology and biomedical industries. Based on the DLVO theory,

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Figure 5.16 Diagram of electrostatic interactions between charged NPs and shale [90].

because of the high surface-to-volume ratio of nanoparticles, NPs exhibit phenomenal surface-active properties, allowing for their customized attachment to compounds which can be utilized for “fit-for-purpose” application [90]. For the nanoparticles as sealing agents in shales, the electrostatic and electrokinetic interaction between shale surface and nanoparticles at fluid interface works. Fig. 5.16 shows the diagram of electrostatic interaction. Two factors are controlling the interaction [55,92]: 1. Surface potential and surface charge density of NPs and shale: a dominant factor of the attractive and repulsive forces, which could determine whether the NPs could reach close enough and adhere to the shale surface or not. 2. Attractive and repulsive forces between NPs: determines the NPs would be dispersed and suspended individual nanoparticle or aggregated floating (or settling) nanoparticle clusters. Nanoparticle adherence to the shale surface is the result of comprehensive factors. The overall surface distribution of shale depends on the rock/mineral matrix and pore matrix. The interaction between the nanoparticle and oppositely charged surface of shale, depending on the surface charge orientation and magnitude, is one of the main factors of the adsorption kinetics. In addition, the particle concentration, the distance between NPs or NP and shale surface, and shale properties (CEC, TOC, and catalytic activity of the clay surface, etc.) are also significant factors [92]. DLVO theory above describes the stability of nanoparticle dispersions and their attraction/repulsion from the surface with the same composition. However, because of the heterogeneous composition of the shale surface, adsorption on shale surface with different composition should not be ignored. The dominating compositions of

Intelligent materials in unconventional oil and gas recovery

shale are silicate, carbonate minerals, and aluminosilicate. The variation in Hamaker constant for interactions among these materials through water is roughly a factor of 2 or 3, with the attraction between silica NPs and a silica substrate being the weakest interaction while interactions with calcite are the strongest [92,93]. Except the classical DLVO theory discussed above, which only consider van der Waals and electrostatic interactions, some other interactions should be considered to understand the interparticle interactions better [94,95], including the effects due to polarizability, charge distribution, ion adsorption, and pH, etc. Although all these effects should be taken into account, during the operation of drilling, salinity and pH of drilling fluids, and nanoparticle surface chemistry through appropriate functionalization are the only controllable factors. All these factors take effect by altering the zeta potential of the nanoparticle. Most NPs will acquire an electrical surface charge in aqueous solution. The surface charge density and the zeta potential of the colloid regulate the surface chemistry of a nanoparticle. The surface chemistry is always altered by tuning the pH of the nanoparticle dispersion, which achieved by adding alkali or acid to the charged NP dispersion. The behavior of NPs in drilling fluid must, therefore, be tuned by the characteristics of the shale formation being drilled through (mineralogy, native fluid composition, temperature etc.). According to the theory above, for better sealing effect, low electrostatic repulsion, high inter-particle repulsion between NP and proper NP size and concentration are required [90]. NPs as the sealing agents show great potential and obvious success in the oilfield operation. However, there are some concerns with the previous work: 1. The test artifacts in the oilfield application In some work, like the work by Sensoy et al. [96], the pressure transmission rate reductions caused by nanoparticles laden fluids, is close to the effects of simple water-based muds tested before the NP laden fluids. His result showed that even without NP fluids, the ordinary water-based muds show high-quality performance in shale stability, which theoretically should not happen. Therefore the test artifacts, like fluid leakage outside the shale test plug, will weaken the validity of the NPs as sealing agents. 2. The conflict between effects and economic and operational feasibility If the concentration of NPs is greater than 5% by weight, the beneficial effects are significant [82,96], because with proper NP size and concentration, the shale surface can be covered effectively. However, the high concentration is a doubleedged sword. First, high concentrations will increase the cost greatly, making the operation less feasible economically. In addition, high concentration means that less interparticle spacing, higher aggression kinetics, less colloidal stability [97]. Because of a significant amount of attractive force towards each other, the increase of nano-fluid viscosity cannot be avoided [97]. Also, how to balance effects and feasibility is also a concern.

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3. Limited understanding of mechanism of sealing Some researchers use “pore plugging” to describe the mechanism of pressure transmission by NPs, which primarily based on the suitable size of NP and shale pore throats. However, filtration of NPs across the extremely low-permeability (scale of nD) shale might be impossible. At the same time, NPs are able to adhere to shale pore. Till now neither explicit mechanism nor explanation has been provided that more tests are required.

5.6 Materials to improve gas hydrate recovery 5.6.1 Gas hydrate recovery mechanism Gas hydrate is one kind of unconventional resources that exists both onshore and offshore and not only on earth by also on other planets. Globally there is more than 1.5 3 106 m3 natural gas with the state of “hydrated” globally. If brought up to the onshore, the gas hydrate breaks down and its volume increases by 160 times [98]. Because of the large gas initially in place, it is of significant economic significance to efficiently and safely produce gas from gas hydrate. In gas hydrate, gas is stored in a crystalline cell composed of water molecules. Water molecules forms a cage to accommodate gas molecule as a “guest.” Water molecules are held together by hydrogen bonds between them and van der Waals force further stabilizes them. Shapes of natural gas hydrate crystals and gas composition vary in nature is used as a criterion to identify different species. Type I and Type II are both composed of small and large cages. The small cage of Type I is composed of 9 dodecahedrons from 12 pentagons and large cage is composed of 12 tetrakaidecahedrons from 12 pentagons and 2 hexagons. Gas hydrate remain stable over a wide range of pressure (2.9 3 10212 psi to 2.9 3 106 psi) and temperature (2333.67 F
170.33 F) [98]. Production of free gas form the gas hydrate deposit is considered to be economical when the gas hydrate saturation is between 30% and 40% involving the process of phase change from solid to gas. Generally speaking, there are three approaches that gas hydrate can be recovered: thermal, depressurization, and chemical inhibition injection. The thermal method involves injecting steam or hot water that requires large and continuous heat source supply which can be quantified by the difference between the original temperature and gas hydrate equilibrium pressure. The thermal parameters need to be evaluated include thermal conductivity, thermal diffusivity and specific heat. Unfortunately, large heat loss accompanies the period of thermal fluids reaching the targeted gas hydrate zone. The depressurization method refers to the process that injecting water to reduce the pore pressure of gas hydrate below its equilibrium pressure. The chemical method involves the process of injecting inhibitors such as methanol or ethylene glycol that

Intelligent materials in unconventional oil and gas recovery

would cause the gas hydrate deposit unstable and decompose into free gas phase. The large cost of chemical inhibitors is a main issue for this method. Another issue is that chemical inhibitors have the potential of corroding pipelines and other metal facilities.

5.6.2 Nanoparticles for gas hydrate recovery Bhatia and Chacko [99] proposed using a self-heating nanoparticle Nickel Ferrite, NiFe2O4, to decompose the gas hydrate deposit by coinjection with air. The nanoparticles are functional in a magnetic field where the temperature rise causes the disruption of the phase equilibrium in the gas hydrate formation, leading the release of free methane gas. The orientation change of magnetic field causes the energy dissipation of nanoparticles accelerated by the large surface area ratio which is the key that nanoparticle works. The size of nanoparticles is between 30 and 50 nm allowing them to pass through the porous gas hydrate formation freely. Fig. 5.17 shows the schematic of the field application of using nanoparticle to produce gas hydrate. A horizontal well is used as the injection unit and a vertical well is used as the production unit. Frequency of 40 kHz with the strength of 160 Oe is applied in the filed to activate the nanoparticles. Laboratory experiments show that the temperature is heated up to 42 C after the magnetic strength increases from 120 to 160 Oe. After contacted with the nanoparticles, the pore pressure of gas hydrate decreases leading to its decomposition by breaking the H-bonds. The released free gas flows toward the production well to the surface. There are several advantages of nanoparticle injection to recover gas hydrate. First, the Ni-Fe nanoparticles are of nanometer size and environmentally friendly; they are eco-friendly and will not cause damage to the well site facilities like other chemical inhibitors. Second, synthesis of the Ni-Fe nanoparticles can be economically manufactured from the eggwhite containing gelling agents. Third, only a small amount of nanoparticles are required for the hydrate decomposition.

Figure 5.17 Schematic of nanoparticle injection to recover gas hydrate deposit. Modified from K.H. Bhatia, L.P. Plakotu, Ni-Fe nanoparticle: an innovative approach for recovery of hydrates, in: Brasil Offshore, Macaé, Brazil, 2011.

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From another perspective, the formation of gas hydrate deposit might plug in the pipelines and production lines as solid ice, causing corrosion problems and reducing the flow capacity. reported that they used a kind of proprietary nonpolar nanomaterials to coat on the wall inner surface to prevent the direct contact between the hydrate and substrate surface. The nanoparticles reduce the interfacial tension and increase the contact angle between hydrate and substrate. The performance of hydrophobicity is excellent that the contact angle reaches nearly 90 degrees with the coating thickness less than 37.5 μm. The small thickness enables the thermal and energy resistance varies negligibly. The nanoparticle coating shows great resistance to corrosion over wide ranges of temperature and pressure.

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59. [99] K.H. Bhatia, L.P. Plakotu, Ni-Fe nanoparticle: an innovative approach for recovery of hydrates, in: Brasil Offshore, Macaé, Brazil, 2011.

CHAPTER SIX

State-of-the-art materials in petroleum facilities and pipelines Rahul Ranjith1, Varun Rai1 and Cenk Temizel2 1

Enfinite Technologies, Houston, TX, United States Saudi Aramco, Dhahran, Kingdom of Saudi Arabia

2

6.1 Introduction 6.1.1 Oil and gas facilities Oil and gas facilities comprise the section of an oilfield between the production/ injection wells and oil transportation systems (pipelines, trucks, rail etc). Fluids that flow into the facility from wellheads are a mixture of oil, gas, and water along with other contaminants, and the primary function of the facility is to separate the valuable components (oil and gas) of the fluid mixture from the nonvaluable ones (water and contaminants). There are specific standards to which oil must be treated prior to transport or sales. Gas treatment typically requires compressors and dehydration units. In addition, the water that is produced along with oil and gas must be treated to remove contaminants prior to disposal or re-use. The standards for water quality after produced water treatment vary geographically and in general, corrosion is a major challenge with respect to facility maintenance. Safety systems for firefighting, hazardous gas exposure detection, life rafts in offshore fields and shutdown systems comprise the auxiliary components of an oil and gas facility. A typical facility which includes all systems required for treating oil, gas, and water is shown in Fig. 6.1.

6.1.2 Oil and gas pipelines In the oil and gas industry, pipelines are mainly used for the transport of liquid petroleum, natural gas and refined petroleum products. The largest pipeline network in the world is in the United States with over a million miles of natural gas pipelines and 0.15 million miles of liquid petroleum and refined product pipelines [2]. Natural gas pipelines extend from oil and gas production facilities and LNG import/export

Sustainable Materials for Oil and Gas Applications. DOI: https://doi.org/10.1016/B978-0-12-824380-0.00003-7

© 2021 Elsevier Inc. All rights reserved.

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Figure 6.1 Components of a typical oil and gas facility [1]. Oil Facility. Petrowiki. ,https://petrowiki. org/Oil_facility..

terminals to a network that delivers it to end-users that include powerplants, industrial heating units and households. They have three sub-units, namely, gathering stations to take the natural gas from wellhead to a facility for treatment, long distance transmission systems, and local distribution systems. Liquid petroleum pipelines include gathering units from oilfields to a refinery, and a network of pipelines from refineries to fuel terminals for truck-based delivery to end-users or storage stations. The pipelines from refineries to fuel terminals are smaller in diameter than large sized cross-country petroleum pipelines that connect oil producing locations to refineries [3]. Owing to such a large network of pipelines, specially designed systems called “pigs” are deployed within pipelines to maintain integrity and reliability [4]. There are three types of pig systems: • Scraper systems —As the name suggests, it contains a tool that scrapes against the inner surface of the pipeline as it moves along. • Scrubber systems —Contain rotating brushes that remove precipitates or scales from the interior surface of the pipeline as it moves along it. • Smart pigs—They are built-in with diagnostic systems that provide data for an in-depth analysis of corrosion or other issues within the pipeline. In the sections below, new technologies for early identification and prevention of corrosion in pipelines and oil and gas facilities, as well as low-cost environmentfriendly produced water treatment technologies will be discussed in detail.

State-of-the-art materials in petroleum facilities and pipelines

6.2 Advanced materials for produced water treatment in oil and gas facilities Water produced along with oil and gas during production operations can contain dissolved volatile organic compounds (VOC), clay particles, heavy metals, radioactive elements, chemical additives and oil. 14 billion barrels of coproduced water globally from oil and gas operations represent a significant stream of waste. There are stringent environmental regulations imposed upon them prior to disposal or re-use and strict water quality guidelines, if opted to be re-injected for additional recovery, to prevent downhole plugging issues; Amount of oil in water must be below 42 parts per million (ppm) and total amount of suspended solids must be below 10 mg/L [5]. There are multiple nanotechnology-based methods, which are areas of significant research interest, that can help oil and gas producers treat produced water and economically meet their environmental goals. Three types are particularly discussed below—Nano-filtration using Membranes, Magnetic Nanoparticles, and Nanostructured Metal Oxides.

6.2.1 Nano-filtration membranes Nanomembranes are essentially thin films (membranes) containing pores at the nanometer (nm) scale that act as nano-filters for fluids that pass through them. The pore sizes vary between 1 and 10 nm [6] and their filtration capabilities (pore size) lie within those of ultrafiltration and reverse osmosis (Fig. 6.2). There are multiple techniques for identifying the structure and size of pores in membranes, such as permporometry,

Figure 6.2 Pore size ranges in membrane technology. Membrane technology. Lenntech. ,https:// www.lenntech.com/processes/pesticide/nanofiltration/nanofiltration.htm..

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atomic force microscopy (AFM), scanning electron microscope (SEM), mercury porosimetry, bubble point technique etc [7]. The pressure gradient between permeate and feed side of the nanomembranes is what drives the fluid through it. Naturally, accumulation of particles that are larger than the pore size of these membranes leads to fouling and is a potential challenge with their use. Advantages of nanomembranes for filtration, especially with regards to produced water treatment in oil and gas facilities are [8]: • Low pressure requirements for operation (72
400 psi) • High flux • Low capital investment (membrane cost) • Low operational costs Membrane based distillation of produced water has shown promise in removal of contaminants prior to disposal, re-purposing or re-injection. In the section below, two nanomembranes that have been developed for produced water treatment will be discussed; Nanofibrous Polyvinylidene Fluoride Membrane, and Hybrid Carbon Nanotube (CNT) and Carbon Nitride Membrane.

6.2.1.1 Nanofibrous polyvinylidene fluoride membrane (PVDF) Moradi et al. (2017) developed and demonstrated the performance of nanofibrous polyvinylidene fluoride in the air gap membrane distillation process (AGMD) for oil removal from produced water. AGMD process consists of a feed of hot water that is in contact with a hydrophobic membrane [9]. The membrane is in contact with a conductive sheet on the other side, forming an air gap, and only allows steam to pass through it. Such membranes are stacked together to use the heat energy from steam that passes through one membrane, to be exchanged to the next unit while steam condenses at the end of the air gap. There are many studies that display the performance of AGMD processes with micro-porous membranes, but not many with nanoporous membranes. Moradi et al. (2017) addresses this key gap to demonstrate the superior effectiveness of using nanotechnology in the membrane distillation process through a lab-scale experimental setup shown in Fig. 6.3. The components of the AGMD experimental set-up are as follows: [1] [2] [3] [4] [5]

Water heater Hot water bath Feed tank Thermocouple Peristaltic pump

[6] Flow meter [7] Water cooler [8] Cold water bath [9] Cooling liquid [10] Permeate tank

[11] [12] [13] [14] [15]

Balance Membrane Cold plate Air Gap AGMD Module

To synthesize the nanofiltration membrane, polyvinylidene fluoride (PVDF) solution was prepared and subject to the electrospinning technique (Fig. 6.4). At 500 rpm

State-of-the-art materials in petroleum facilities and pipelines

Figure 6.3 Air gap membrane distillation process experimental setup [10]. R. Moradi, M. Mehrizadeh, H. Niknafs. Produced water treatment by using nanofibrous polyvinylidene fluoride membrane in air gap membrane distillation (Azeri). Soc. Pet. Eng. (2017).

and a flowrate of 0.9 ml/hr, the PVDF solution is spun onto a nonwoven polypropylene supported by a rotating drum. Fig. 6.5 shows the SEM images post the preparation of the nanofibrous PVDF, having an interwoven net-like anatomy with pore-sizes between 220 and 470 nm. In their study, the produced water used was similar in composition to that of operations from the Caspian Sea. Table 6.1 compares the properties of the model sample to a real field sample. The model sample preparation consisted of waste oil and an emulsifier being mixed through stirring in a heated vessel at 45 C for 1 hour, in the presence of double distilled water. To attain homogeneity within the sample it was put through ultrasonication, a technique that uses high frequency acoustics for breakdown of clusters. Prior to introduction of the sample to AGMD, it was put through prefiltration processes to prevent fouling of the nanofiltration (nanofibrous PVDF) membrane. During the AGMD process, the peristaltic pump

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Figure 6.4 Preparation of nanofibrous PVDF by electrospinning. R. Moradi, M. Mehrizadeh, H. Niknafs. Produced water treatment by using nanofibrous polyvinylidene fluoride membrane in air gap membrane distillation (Azeri). Soc. Pet. Eng. (2017).

measured the circulation rate of the model sample water through each nanofibrous PVDF membrane unit to ensure it was set to two values of 0.5 and 1 mol/L. Temperature of the inlet water was set at three separate values of 68 C, 75 C, and  83 C and condensed water was cooled to 15 C. Circulation rate of 0.5 mol/L gave a higher rate of flux in the AGMD process than 1 mol/L. The amount of solute, total organic content and oiliness of the outlet solution (permeate) was compared to the inlet solution (model sample of produced water) by using conductivity meters, photometers and spectroscopy respectively. They were used to compare the performance of nanofibrous PVDF to commercially available PVDF membrane. Salt retention and the rate of permeate transfer (flux) were found to be 20% more in the case of nanofibrous PVDF membrane due to a lower average pore size. Also, a comparison of oiliness of the permeate from the AGMD process using both these membranes showed a two-fold increase in oil rejection when nanofibrous PVDF membranes were used instead of commercially available PVDF, hence proving its superior performance in produced water treatment. 6.2.1.2 Hybrid carbon nanotube (CNT) and carbon nitride (CNx) membrane Flowback water from hydraulic fracturing in onshore and offshore well completion or workover programs contain various contaminants, especially salt mixtures. In offshore

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Figure 6.5 SEM images of nanofibrous PVDF prepared from electrospinning. R. Moradi, M. Mehrizadeh, H. Niknafs. Produced water treatment by using nanofibrous polyvinylidene fluoride membrane in air gap membrane distillation (Azeri). Soc. Pet. Eng. (2017). Table 6.1 Properties of model sample and real field sample of produced water. Property Model sample

Dispersed oil mg/l pH value Conductivity μS/cm TOC mg/l Oil weight ratio wt%

140 6 10 7.1 6 0.2 200 6 5 60.0 6 10 10

Real sample

740 6 50 6.0 6 0.5 31000 6 10000 1400 6 200


R. Moradi, M. Mehrizadeh, H. Niknafs. Produced water treatment by using nanofibrous polyvinylidene fluoride membrane in air gap membrane distillation (Azeri). Soc. Pet. Eng. (2017).

operations, there are strict regulations for disposal of water containing zinc and given their location, water filtration at a large scale for produced water re-injection can be very costly. However, they are a mandatory process to prevent corrosion and fouling issues of downhole components in wells. In addition, due to the water-intensive nature of such operations, there is a need for an improvement in the economics of on-site flowback water filtration processes. Membrane based filtration is a viable solution, but there are durability problems with conventional membranes with respect to thermal resistance and fouling (Table 6.2). Ventura et al. (2017) synthesized a hybrid

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Table 6.2 Comparison of filtration membrane materials. Membrane material Solvent resistance

Thermal resistance ( C)

Polyamide Cellulose acetate Polyvinylidene fluoride Polyacrylonitrile CNT

60 65 80 80 600

High Low Medium High High

D. Ventura, et al. Assembly of cross-linked multi walled carbon nanotube. Carbon 48 (4) (2010) 987
994.

Figure 6.6 Hybrid CNT-CNx membrane for flowback water filtration. D. Ventura, et al. Assembly of cross-linked multi walled carbon nanotube. Carbon 48 (4) (2010) 987
994.

CNT and CNx membranes for flowback water filtration (Fig. 6.6) as an alternative to conventional membranes for removal of nano-sized particulates and charged ions (Barium, Magnesium, Sodium, and Zinc), and demonstrated its effectiveness by passing 10 nm Iron Oxide and real-field flowback water sample [11]. In this study, hybrid CNT and CNx membranes were developed by using the pi-stacking method between their particles. Within a CNT, synthesized from regular filtration by suspension methods, the nanotubes are oriented randomly as shown in Fig. 6.7 [12]. To enable the dual-filtration capability of nanoparticles, and charge ion removal, CNx particles must be dispersed throughout each CNT membrane. This is done while fabricating a CNT mat; CNx particles are introduced and attached to the nanotube mesh (Fig. 6.7A) using the vacuum filtration process [11]. To synthesize CNx, 1.9 g, 0.4 g, and 75 mL of cyanuric chloride, lithium nitride and diglyme respectively, were refluxed at 160 C in inert conditions after which they were subject to washing by de-ionized water and ethanol. Fig. 6.7 shows the hybrid CNT-CNx mat (50 μm thick) synthesized by the processes described above. The prepared CNT-CNx mats were tested for performance by passing a water sample containing 10 nm Fe3O4 particles, as well as a 15 mL field sample of flowback water. In both cases, there was a visible change in the water color pre and post-filtration as shown in Fig. 6.8. To measure filtration performance, UV spectroscopy and SEM were used. Fe3O4 nanoparticles typically exhibit high absorbance (0.5
1.4) between 250 and 400 nm wavelengths. In the case of the water sample with Fe3O4 nanoparticles, UV

State-of-the-art materials in petroleum facilities and pipelines

Figure 6.7 High resolution scanning electron microscopy images of (A) CNT mesh (B) CNx particles dispersed throughout CNT membrane. D. Ventura, et al. Assembly of cross-linked multi walled carbon nanotube. Carbon 48 (4) (2010) 987
994.

Figure 6.8 CNT-CNx membrane filtration performance on (A) Water sample with 10 nm Fe3O4 nanoparticles and (B) Flowback water from a real-field. D. Ventura, et al. Assembly of cross-linked multi walled carbon nanotube. Carbon 48 (4) (2010) 987
994.

spectroscopy showed that postfiltration, the water samples’ absorption intensity within the 250
400 nm range displayed a significant decrease of ,0.2, suggesting good performance of the hybrid CNT-CNx mat for Fe3O4 nanoparticle filtration. This was proven by the postfiltration SEM images of the hybrid mat (Fig. 6.9), which clearly show Fe3O4 nanoparticles retained within the CNT mesh. In the case of real-field flowback water sample, inductively coupled plasma optical emission spectrometry (ICP-OES) was used to measure hybrid membrane filtration performance with respect to reducing the concentration of Barium (Ba), Magnesium (Mg), Sodium (Na), and Zinc (Zn) ions. To highlight the superior performance of hybrid CNTCNx membranes, ion concentration values postfiltration were compared to that of filtration using CNx alone. The hybrid membrane reduced Zn concentration by a whopping 52%, as compared to 26% in the case of standalone CNx filtration. Also, Ba, Mg, and Na concentrations were reduced by 20% on average by the hybrid membrane as compared to 7%, 1%, and 5% respectively, when CNx alone was used.

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Figure 6.9 High resolution SEM showing Fe3O4 nanoparticles trapped within the CNT-CNx membrane postfiltration. D. Ventura, et al. Assembly of cross-linked multi walled carbon nanotube. Carbon 48 (4) (2010) 987
994.

6.2.2 Magnetic nanoparticles (MNP) As their name suggests, the functionality of magnetic nanoparticles can be altered by exposure to magnetic fields. There are three types of MNPs—Oxides (ferrite), Metallic and Metallic with a shell. Metallic nanoparticles with a shell are more stable in organic and inorganic solvents, and have higher magnetization compared to oxide or metallic MNPs [13]. Owing to the magnetic behavior of individual NPs from surface effects, they display unique properties such as superparamagnetism, high amounts of irreversibility of field, high saturation field and extra anisotropy conditions [14]. Magnetic coercivity is the property used to identify the resistance level of a magnetic material to an external magnetic field prior to losing its magnetism. A coercivity level of zero indicates superparamagnetism and there is a minimum particle size level below which the coercivity of that particle allows it to be superparamagnetic (Fig. 6.10). The spin from charged particles gives rises to a magnetic dipole, also known as a magneton. In MNPs, the magnetons are all aligned in a single direction and hence, have a single magnetic domain. Superparamagnetism is displayed by these single magnetic domain particles. MNPs, being superparamagnetic and below the critical particle size threshold, are nonmagnetic in the absence of a magnetic field and become magnetized only in the presence of an external magnetic field as shown in Fig. 6.11. In these particles, above the magnetic ordering temperature (Tn), the thermal energy causes magnetic moments to randomly fluctuate, which disrupts their macroscopic magnetic ordering. In the figure, Ds refers to superparamagnetism and Dc refers to the minimum critical particle size. On the introduction of an external magnetic field, its magnetic domain aligns with that of the external field [14].

State-of-the-art materials in petroleum facilities and pipelines

Figure 6.10 Relation of coercivity to size of a nanoparticle. A. Akbarzadeh, M. Samiei, S. Davaran. Magnetic nanoparticles: preparation, physical properties, and applications in biomedicine. Nanoscale Res. Lett., 7(1) (2012) 144.

Figure 6.11 MNP exhibiting superparamagnetism. A. Akbarzadeh, M. Samiei, S. Davaran. Magnetic nanoparticles: preparation, physical properties, and applications in biomedicine. Nanoscale Res. Lett., 7(1) (2012) 144.

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6.2.2.1 MNPs for EOR polymer removal from produced water Ko et al. (2017) investigated and demonstrated the effectiveness of magnetic nanoparticles for removal of two types of EOR polymers from produced water—8 MD and 20 MD HPAM. MNPs have the ability to be adsorbed on to the surface of contaminants, thereby allowing for a high-gradient separation (up to 104 T/m) of the contaminant (HPAM) from water under the application of an external magnetic force. In this study, the environmental benefits from surface regeneration MNPs were also demonstrated. The regenerated MNPs were reused up to 10 times with a good level of performance. Also, depending on the contaminant that needs to be targeted, MNP surfaces can be modified by using an appropriate coating to ensure that they attach to these contaminants. This functionality depends on pH and salinity and can be controlled by pH alteration and introduction of external attractive/repulsive forces. To prepare MNPs, ferrous chloride and ferric chloride in the presence of citric acid as a stabilizer and ammonium hydroxide as a base, was subjected to heat and robust stirring. This process led to MNP nucleation and the resulting medium underwent five washing cycles with de-ionized water, to ultimately synthesize MNPs (Fig. 6.12). Prior to coating MNPs with Silica using tetraethyl orthosilicate (TEOS), it underwent sonication to ensure homogeneity, after which in the presence of ethanol, water, and ammonium hydroxide the mixture was stirred and through the 3-APTES coating process, silica-coated MNPs (Si-MNP) and noncoated MNPs were functionalized by amines. In the case of silica-coated MNPs, the thickness of silica shell is directly proportional to the amount of TEOS used during Si-MNP preparation. In this study, the silica shell thickness was measured between 10 and 15 nm using a transmission electron microscope

Figure 6.12 MNP, A-MNP, and Si-A-MNP synthesis. S. Ko, H. Lee, C. Huh. Efficient removal of enhanced-oil-recovery polymer from produced water with magnetic nanoparticles and regeneration/ reuse of spent particles. Soc. Pet. Eng. (2017).

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Figure 6.13 TEM images for MNP, Si-MNP, and A-MNP. S. Ko, H. Lee, C. Huh. Efficient removal of enhanced-oil-recovery polymer from produced water with magnetic nanoparticles and regeneration/ reuse of spent particles. Soc. Pet. Eng. (2017).

Table 6.3 Characteristics of synthesized MNPs [15]. Hydrodynamic size (nm)

Zeta potential (mV)

MNP A-MNP Si-MNP Si-A-MNP

32 229 42

51 66 201 256

S. Ko, H. Lee, C. Huh. Efficient removal of enhanced-oil-recovery polymer from produced water with magnetic nanoparticles and regeneration/reuse of spent particles. Soc. Pet. Eng. (2017).

(Fig. 6.13). To maintain stability of Si-MNPs and amine functionalized MNPs (A-MNPs), their pH was changed to 4.5 after washing with de-ionized water. Dynamic light scattering and ICP-OES at absorbance wavelength of 284 nm gave the hydrodynamic size, zeta potential, and iron concentrations in the synthesized MNPs (Table 6.3). Si-A-MNPs and A-MNPs were synthesized with a positively charged surface, having zeta potential of 32 and 42 mV respectively, to ensure adsorption on negatively charged EOR polymer surfaces (Fig. 6.14). Using a vibrating sample magnetometer, the saturation magnetization of MNP, A-MNP and Si-MNP were measured. The magnetization of MNP and A-MNP showed values of 90 emu/g, whereas Si-MNP showed 87 emu/g, thereby confirming that a coating (shell) of silica did not affect magnetic separation. 8-MD HPAM and 20-MD HPAM polymer solutions were diluted in to four different brine solutions, • Standard API brine with 2% calcium chloride and 8% sodium chloride • 2% sodium chloride solution • 2% sodium chloride with pH adjusted to 9.5 using an alkali to represent brine found in field operations • Synthetic seawater (SSW)

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Figure 6.14 Polymer separation and MNP regeneration process. S. Ko, H. Lee, C. Huh. Efficient removal of enhanced-oil-recovery polymer from produced water with magnetic nanoparticles and regeneration/reuse of spent particles. Soc. Pet. Eng. (2017).

MNP, A-MNP, Si-MNP and Si-A-MNP were introduced to different polymer-brine solutions at a pH of 8.5, in the presence of de-ionized water, and then vigorously mixed via a shaker. Through this process MNPs formed agglomerates with polymers (Fig. 6.14) and could be clearly distinguished from the brine solution using a magnet. On increasing the pH of the solution to 11, amine functionalized MNPs—polymer agglomerates were introduced to a new de-ionized water sample and subjected to shaking in order to regenerate the MNPs (separate them from the polymer). At pH 11, the amine functionalized MNP had a zeta potential of 0 and the regenerated MNPs were collected by using a magnet. The new polymer-deionized water sample was tested using UV-VIS

State-of-the-art materials in petroleum facilities and pipelines

spectroscopy to measure the amount of polymer in sample. Absorbance of polymer was determined earlier to be 520 nm, and this was used to estimate the percentage removal efficiency. The percentage removal efficiency of MNPs depends on, • Brine concentration • Polymer molecular weight • Fe (Iron) concentration • Surface coating • Number of times MNPs are regenerated and reused A comparison of the removal efficiencies between A-MNPs and Si-A-MNPs is given in Fig. 6.15. A-MNPs showed a better overall removal efficiency of 53%
100% across all brine and seawater solutions for the 8MD HPAM polymer, as compared to Si-A-MNP. Especially in the case of API solution, A-MNP displayed a better separation performance for 8MD HPAM. With high enough concentrations of A-MNP (14 g/L), both 8MD and 20MD HPAM polymers were completely separated from the API, brine solution and seawater solutions. Sodium ion concentration was the highest in API and was suggested as the reason for lower removal efficiency as compared to

Figure 6.15 Comparison of removal efficiency of 8MD and 20MD HPAM by A-MNP and Si-A-MNP [16]. M. Duan, Y. Ma, S. Fang, P. Shi, J. Zhang B. Jing. Treatment of wastewater produced from polymer flooding using polyoxyalkylated polyethyleneimine. Sep. Purif. Technol. 133 (2014) 160
167.

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Table 6.4 Effect of Fe concentration of removal efficiency of A-MNP and Si-A-MNP. Fe concentration (g/L) Type of MNP Removal efficiency Removal efficiency of 8MD HPAM (%) of 20 MD HPAM (%)

1 2 4 7

A-MNP Si-A-MNP A-MNP Si-A-MNP A-MNP Si-A-MNP A-MNP Si-A-MNP

32 60 39 80 53 92 70 96

30 70 32 82 50 99 82 99

other brine solution, especially in the case of Si-A-MNP. Si-A-MNP displayed a better removal efficiency in the case of 20 MD HPAM polymer across all brine solutions. As Si-A-MNP has a higher zeta potential of 42 mV compared to 32 mV of A-MNP, it possesses more positively charged ions. Hence, due to a stronger affinity to the negatively charged surface of the polymers, it displayed a better removal efficiency across all brine solutions, especially in the case of 20MD HPAM. As can be seen from Fig. 6.15, A-MNP was used in three difference concentration of 4, 7, and 11 g/L, whereas Si-A-MNP was used in two different concentrations of 4 and 7 g/L. Effect of Fe concentration on API was least correlated amongst all brine solutions. However, both A-MNP and Si-A-MNP were tested with Fe concentrations of 1 and 2 g/L as well. A comparison on the effect of Fe concentration on MNP removal efficiency is given in Table 6.4. For lower Fe concentrations, it was clear that the silica shell on Si-AMNP played a role in having a two-fold improvement in polymer removal performance as compared to A-MNP. Using pH adjustment, in the case of Si-A-MNPs, the regenerated MNPs could be used upto three times with a 90% polymer removal efficiency, even in seawater solutions. This highlights the environmental benefit of using MNPs in field operations for produced water filtration to help improve water quality standards prior to disposal or reuse, instead of chemical additives.

6.3 Advanced sensing techniques for oil and gas facilities and pipelines 6.3.1 Graphene and its potential in sensing Graphene consists of single layered, one atom thick, sp2 hybridized carbon atoms in a hexagonal structure. As shown in Fig. 6.16, graphene has a strong pi-stacking between carbon atoms and adjacent pi-orbitals on sp2 hybridized carbon atoms, and they are

State-of-the-art materials in petroleum facilities and pipelines

Figure 6.16 Graphene structure. W. Choi, I. Lahiri, R. Seelaboyina, Y.S. Kang. Synthesis of graphene and its applications: a review. Crit. Rev. Solid. State Mater. Sci., 35, 1 (2010) 52
71.

Figure 6.17 Multifunctional sensing ability of grapheme. Sensors. University of Manchester. ,https:// www.graphene.manchester.ac.uk/learn/applications/sensors/..

structured similar to aromatic molecules. In addition, the electrons are delocalized, i.e., not associated with a covalent bond, and sigma-orbitals are formed directly between nuclei of bonding atoms, thereby giving rise to a strong rigid structure [17]. It has a multitude of highly attractive properties, which have fueled its application across many industries ranging from biomedicine and life sciences to construction and energy. To name a few, it exhibits [18]: • High thermal conductivity ( . 3000 W/mK) • Impermeablility to fluids; hydrophobic • High amount of electrical conductivity (106 orders of magnitude more than copper) • High modulus of elasticity (B1 TPa) • Large surface area • Lab scale synthesis at low costs Chemical vapor deposition (CVD), graphite-based liquid phase exfoliation and synthesis from silicon carbide are the different techniques to produce graphene [19]. Considering its unique structure and property, every atom within graphene can sense any variations in its immediate environment, making it an excellent material to be used as a sensor [20]. Owing to its large surface area and high electrical and thermal conductivity, graphene can easily interact with molecules in the environment and bind to them, which will result in a change in its conductivity. It also has the property of being functionalized by bonding with another material to interact with specific materials in the environment. Through these processes, the ability to measure ultra-sensitive changes with respect to certain materials or conditions in the surrounding environment (gas, pressure, light, temperature, magnetic field etc) is what makes graphene an ideal sensing material [21] (Fig. 6.17).

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In the sections below, two applications of graphene for pipelines and oil and gas facilities will be discussed. 6.3.1.1 Graphene sensor for CO2 detection In pipelines, fracture propagation from deformation of ductile pipeline materials is a major issue affecting integrity. This problem gets amplified in CO2 pipelines, since CO2 decompresses quicker than other gasses, and hence its decompression speed must be maintained above fracture propagation speed. Pipeline fluid temperature, pressure, and presence of impurities are all factors that affect the rate of decompression of CO2. Currently, multiple types of solid-state gas sensors such as metal oxide sensor, IR sensor, and electrochemical sensors are used to detect CO2 vaporization from the liquid CO2 stream within a pipeline. However, there are reliability and precision issues faced with the use of these sensors. To address them, Al Shehhi et al. (2017) developed a novel graphene sensor for high precision CO2 detection as well as other mixtures down to a 100-ppm level. The sensor was developed with three different architectures: • Backgated—Detects ions • Membrane—Detects precipitates in the pipeline fluid • Kelvin—Detects metal contacts (Ti, Ni, Al, Cu etc) Graphene used in their demonstration was first developed by the Chemical Vapor Deposition (CVD) technique. In the CVD process, disassociated carbon atoms are created as a thin film by subjecting a substrate to extremely high temperatures and then the disassociated carbon atoms are heated in the presence of a catalyst to form a carbon structure that represents graphene [22]. Graphene is then transferred on to two substrates, glass and silicon dioxide, using Polymethyl methacrylate (PMMA). Graphene is first coated with PMMA on a hot copper plate, and then dipped in an etchant as shown in Fig. 6.18. The graphene-PMMA sample is then placed onto the substrate in deionized water, cleaned using acetone and dried in order to form a wafer like material with the substrate. To show the performance of the graphene-substrate sensor in detecting CO2 and other gases, it was subject to gas testing in a chamber. Electrical resistance of the sensor was first measured at atmospheric pressure and vacuum conditions and then after the introduction of two target gases (CO2 and O2) into the test chamber. The difference in electrical resistivity before and after the introduction of target gases gave its sensitivity and was also a proof of the reversibility of its resistance. CO2 at 496 ppm concentration was introduced at room temperature and at 40 C, while O2 at 800ppm concentration was introduced only at room temperature into the chamber. The sensor showed a decrease in electrical resistivity by 5% when exposed to room temperature CO2, a 22% decrease when exposed to CO2 at 40 C and a 6.2% decrease when exposed to O2 (Fig. 6.19).

State-of-the-art materials in petroleum facilities and pipelines

Figure 6.18 Transfer of graphene to glass an SiO2 substrates. Al Shehhi et al. (2017).

Figure 6.19 Sensor response to CO2 and O2. Al Shehhi et al. (2017).

6.3.1.2 Graphene sensor for scale monitoring Sulphate scaling is a key issue that results in loss of mechanical integrity of pipes in O&G facilities and pipelines and leads to expensive workover operations. Hence, there is a need for high-precision and low-cost continuous scale monitoring. Bouchalkha et al. (2018) developed a novel graphene-based sensor for ultra-precision scale monitoring in oilfield pipes and oil pipelines. In this study, silicon dioxide was used as the substrate during graphene sensor fabrication (Fig. 6.20). Graphene was synthesized using CVD, and using exfoliation and patterning, was put onto the substrate layer. In order to be used as an electrical resistivity sensor, all areas except for the sensing area were insulated and covered (Fig. 6.21). Raman spectroscopy on the sensor indicated a good quality sensing surface. Strontium sulphate solutions, with different concentrations of strontium ions in de-ionized water, were then prepared to test the performance of the fabricated sensor using a four-probe measurement method as shown in Fig. 6.21. The sensor was first

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Figure 6.20 Sensor fabrication process [23]. T. Wang, et al. A review on graphene-based gas/vapor sensors with unique properties and potential applications. Nano-Micro Lett. 8 (2016) 95
119.

Figure 6.21 Fabricated graphene sensor [39]. A. Bouchalkha, R. Karli, K. Alhammadi, A. Anjum, I. Saadat, A. Al Ghaferi. Graphene based sensor for scale monitoring. Soc. Explor. Geophys. (2018).

Figure 6.22 Initial response of graphene sensor to different strontium ion concerntrations after production [39]. A. Bouchalkha, R. Karli, K. Alhammadi, A. Anjum, I. Saadat, A. Al Ghaferi. Graphene based sensor for scale monitoring. Soc. Explor. Geophys. (2018).

dipped in de-ionized water to get a neutral resistivity value and then into a strontium sulphate solution. This process was repeated for all concentrations. As can be seen in Figs. 6.22 and 6.23, the results of the four-probe method were taken right after dipping the sensor in solution, right after it was prepared and after two days. The neutral

State-of-the-art materials in petroleum facilities and pipelines

Figure 6.23 Response of graphene sensor to different strontium ion concerntrations two days after production [39]. A. Bouchalkha, R. Karli, K. Alhammadi, A. Anjum, I. Saadat, A. Al Ghaferi. Graphene based sensor for scale monitoring. Soc. Explor. Geophys. (2018).

electrical resistivity was shown to be 10 kΩ (indicating stability) and resistivity to different concentrations of strontium sulphate varied between 18 and 25 kΩ (indicating good sensor range).

6.4 Nanocoatings for oil & gas facilities 6.4.1 Silane-nanoceramic coating A composite of silane-nanoceramic as a coating medium for riser systems in subsea applications has many advantages as compared to existing technologies. The primary advantage being heat-insulation properties of silane nanoceramic coatings that have low thermal conductivity and a high thermal insulation effect. In addition, silane-nanoceramic composites have characteristics of seawater corrosion resistance, antiseismic and environmental protection, easy installation, long service life and strong adhesion [24]. 6.4.1.1 Silane-nanoceramic as a thermal insulator The thermal conductivity of silane nanoceramics can be as low as 0.028 W/m.K. In addition, when the inner temperature of a riser system is maintained at 350 C, the heat insulation rate can reach about 70%. Fig. 6.24 shows the heat transfer mechanism of silane-nanoceramic composite coatings. Heat insulation coatings can be broadly classified into three types; blocking, reflecting, and radiating [25].

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Figure 6.24 Heat transfer method of silane nanoceramic composite coating [26]. L. Xiaoyan, Z. Haiqian, W. Zhonghua. Heat transfer experiment and simulation of vacuum heat-insulation oil pipe coupling. J. Eng. Thermophys. 30(11) (2009) 1895
1897.

Silane-nanoceramic coatings take advantage of both block and reflecting coating types. In this coating, both conduction and convection effects are reduced, since nano-ceramic beads are filled with N2, CO2 and other gases that results in low thermal conductivity and high vacuum. Thermal insulation is achieved by reflection and scattering inside the coating, as nano-ceramic coatings have a closed void structure. 6.4.1.2 Experimental analysis and validation An experimental study was conducted by Hu et al. (2018) to study the thermal insulation and corrosion resistance properties of silane-nanoceramic coatings for riser systems in subsea applications. The thermal insulation properties of different insulation coating materials were simulated using an infrared lamp, to compare their properties to a silane-nanoceramic coating. This study also implemented a riser heating system to compare different insulation coatings. For thermal insulation properties, an investigation was also conducted to observe the effects of the coating structure and thickness of silane-nanoceramic coatings. In addition, field experiments were conducted to observe the corrosion resistance properties of this coating. Both, thermal insulation and seawater corrosion resistance were considered. 6.4.1.3 Thermal insulation effect In this study, four different types of coatings were compared and observed to test their thermal properties. The four coatings used are as follows: • Ordinary ceramic insulation coating (Type A); • Silane-nanoceramic insulation coating (Type B); • Inorganic fibers vacuum insulation board (Type C); • EPDM insulation rubber (Type D). The performance parameters of these four coatings are shown in Table 6.5. Results of these comparisons and observations made in this study are briefly discussed in the sections below.

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Table 6.5 Performance parameters of four different insulation coatings. Heat insulation coatings

Thermal conductivity coefficient W/(m  K)

Bulk density kg/m3

Operating temperature range ( C)

Water absorption

A coating B coating C coating D coating

0.116 0.028 0.035 0.077

100 135 240 78

240B400 240B400 250B700 250B125

# 5% # 5% 0 # 10%

L. Xiaoyan, Z. Haiqian, W. Zhonghua. Heat transfer experiment and simulation of vacuum heat-insulation oil pipe coupling. J. Eng. Thermophys. 30(11) (2009) 1895
1897.

6.4.1.3.1 Comparison between ordinary ceramic coatings and silane-nanoceramic coatings

Ordinary ceramic coatings (Type A) get their high thermal insulation properties because of low thermal conductivity and high porosity. Silane-nanoceramic coatings (Type B) have additional properties like high spectral selectivity between visible and infrared light, enhanced material super plasticity, hardness, ductility, and toughness [27]. In the experiment performed by Hu et al. (2018), two infrared lamps were used to heat both Type A and Type B coatings. The front and back surfaces were heated evenly by placing them on a rotating turntable. Temperature data was measured at different points using an infrared imager, as shown in Table 6.6. From Table 6.6, it can be observed that as the testing time increases, so does the temperatures in both coatings. However, the front surface temperature rises faster as compared to the back surface. This is because the front surface is directly exposed to the infrared lamp, whereas lower temperature increase in the back surface is because of the thermally insulated coatings. The silane-nanoceramic coating (Type B) has a higher temperature difference between the front and the back surface as compared to the ordinary ceramic coating (Type A). This is due to the fact that the nanoceramic coatings have a three-dimensional silane network, which reduces the thermal conductivity of these coatings. In addition to having low thermal conductivity, the electromagnetic property of this coating will not only reflect, but also refract the UV-rays [28]. This results an in increased amount of heat absorbed by a silane-nanoceramic coating. 6.4.1.3.2 Comparison between different riser installation coatings

The materials used for thermally insulating riser systems are vacuum insulation materials [26], organic insulation rubbers [29] and silane compound ceramics. Their properties are compared in Table 6.7. For the experimental analysis [30], materials chosen in accordance are silanenanoceramic coating(B), inorganic fibers vacuum insulation(C), and EPDM rubber insulation(D). Fig. 6.25 shows the external temperature change with time for all three coatings. The insulation rates were found to be 75.1% for coating B, 72.5% for coating C, and 70.5% for coating D. In conclusion, silane-nanoceramics had the best

Table 6.6 Infrared cloud images for ordinary ceramic (Type A) and silane-nanoceramic (Type B) coatings. Time (Min)

Coating types

10

30

90

120

Infrared cloud image (front)

Average temperature Infrared cloud image (front) (back)

Average temperature Temperature (back) difference

A

44.0

27.3

16.7

B

43.1

27.6

15.5

A

45.4

30.2

15.2

B

44.7

30.3

14.4

A

47.0

30.9

16.1

B

45.8

31.0

14.8

A

47.7

30.8

16.9

B

47.1

31.0

16.1

L. Xiaoyan, Z. Haiqian, W. Zhonghua. Heat transfer experiment and simulation of vacuum heat-insulation oil pipe coupling. J. Eng. Thermophys. 30(11) (2009) 1895
1897.

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Table 6.7 Features of riser thermal insulation coatings. Technologies

Mechanism

Operation

Cost

Disadvantage

Vacuum insulation

Improve the vacuum Vacuum degree is High Hydrogen evolution degree of casing limited by the large reaction will reduce annulus to reduce the size of the riser and the vacuum degree of thermal conductivity, the annular space, it vacuum, impact the the lowest thermal is only used in the heat insulation effect. conductivity, the best heat-insulated tubing heat insulation. Polymer The thermal conductivity Widely applications and Low Low highest tolerance composite depends on the easily operation. temperature, easily property and deformation in high distribution of fillers in temperature polymer-based environment. materials Organic coating The organic materials Widely applications and Low Organic materials easily with lower thermal easily operation. carbonized at high conductivity play an temperatures, the important effect. choice of high-quality temperature-resistant materials is difficult. L. Xiaoyan, Z. Haiqian, W. Zhonghua. Heat transfer experiment and simulation of vacuum heat-insulation oil pipe coupling. J. Eng. Thermophys. 30(11) (2009) 1895
1897.

Figure 6.25 Surface temperature variations of riser insulation technologies [26].

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insulation properties. In addition, these coatings have a number of other advantages like [31]: • Pollution free (Nonphosphating) • Wide temperature range (240 C
400 C) • Good shock resistance • Strong Adhesion • Superplasticity • Low water vapor permeability Thus, the application of silane-nanoceramic coatings can be cosidered as an excellent option for thermal insulation of riser systems. 6.4.1.3.3 Thermal insulation with respect to coating structure

The coating structure influences the insulation properties of a coating material. To observe the effects of the coating layer structure for silane-nanoceramic, an experiment was carried on three different set-ups by Xiaoyan et al. (2009): • Riser outer wall sprayed with two layers of silane-nanoceramic coating. • One coating each on the inner and outer layer. • Riser inner wall sprayed with two layers of insulation material coating. The observations of this experiment are shown in Fig. 6.26. The insulation rates first reach a maximum, and then decrease and reach stability. From Fig. 6.26 it can be inferred that spraying two layers of the insulation coating on the outer wall gives the best results. 6.4.1.3.4 Thermal insulation with respect to coating thickness

Thermal insulation effect increases as coating thickness increases [32]. For a riser system, there are limitations to the coating thickness, which are dependent on the construction conditions and various other factors. Thus, an optimal thickness needs to be considered. In the experiment conducted by Hu et al. (2018), six different thicknesses are considered for testing the silane-nanoceramic coating as shown in Fig. 6.27. From this experiment it was observed that the thermal insulation effect is significantly influenced by the thickness of the coating material. As the coating thickness of the silanenanoceramic increases so does its insulation properties. 6.4.1.4 Seawater corrosion resistance An important feature for using a riser system at subsea environments is its property of corrosion resistance. Xiaoyan et al. (2009) also examined the corrosion resistance properties of silane-nanoceramic coatings on riser systems. The properties of silanenanoceramic materials are displayed in Table 6.8. This study [30], mainly investigated the antiseawater immersion properties of silane-nanoceramic coatings and its salt spray corrosion resistance. The theoretical

State-of-the-art materials in petroleum facilities and pipelines

Figure 6.26 Coating structure influence on thermal insulation [26].

Figure 6.27 Coating thickness vs thermal insulation for silane-nanoceramic [26].

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Table 6.8 Important properties of silane-nanoceramic materials for corrosion resistance. Number Properties Value

1 2

Appearance of Coating Film Acid Resistance (10% sulfuric acid, 3 months)

3 4 5

Alkali Resistance (10% sodium hydroxide solution, 3 months) Salt Spray Resistance (10000 h) Oil Resistance (93 # gasoline, 3 months)

6 7 8 9 10

Pencil Hardness Adhesion (circle method), level Thermal Conductivity At Room Temperature Contact Angle (water phase) Solid Content (%)

Flat and smooth No bubbling, peeling, pulverizing No bubbling, peeling, pulverizing No bubbling, peeling, rusting. No bubbling, peeling, pulverizing $ 3H 0 0.028 W/m  K $ 105* $ 95

L. Xiaoyan, Z. Haiqian, W. Zhonghua. Heat transfer experiment and simulation of vacuum heat-insulation oil pipe coupling. J. Eng. Thermophys. 30(11) (2009) 1895
1897.

Figure 6.28 UV resistance of coating generally measured on top layers. L. Xiaoyan, Z. Haiqian, W. Zhonghua. Heat transfer experiment and simulation of vacuum heat-insulation oil pipe coupling. J. Eng. Thermophys. 30(11) (2009) 1895
1897.

service life of silane-nanoceramic coatings is approximately 40 years (Fig. 6.28). This greatly improves the service life of the riser system. Fig. 6.29 shows a plot of anticorrosion life as it increases with coating thickness [1]. Using a coating thickness of 300 μm gives a service life of 15 years, which matches the international standards required. Thus, to reach the optimum anticorrosion life, the thickness of a nano-ceramic coating can be increased.

State-of-the-art materials in petroleum facilities and pipelines

Figure 6.29 Seawater corrosion resistance versus coating thickness. L. Xiaoyan, Z. Haiqian, W. Zhonghua. Heat transfer experiment and simulation of vacuum heat-insulation oil pipe coupling. J. Eng. Thermophys. 30(11) (2009) 1895
1897.

6.4.2 Carbon nanotube composites Over the last few decades, the presence of offshore oil facilities in deep sea fields have exponentially increased in several parts of the world. The equipments and facilities have higher technical demands and need to work in severe conditions, and sometimes at sea depths varying from 1500 to 3000 m. The methods of production and equipments need to be specifically designed for deep water constraints like low temperatures, high corrosion resistance, thermally insulated power transmission cables and high-water pressure. With the advancement of material science, specifically in the fields of nano-technology, new and advanced materials are being implemented for deepwater applications. One such material that has tremendous application in this industry is Carbon Nanotubes (CNT). Carbon Nanotubes are allotropes of carbon with a tubular structure that has excellent thermal, electrical, chemical and mechanical properties. Broadly, Carbon Nanotubes can be classified as Single-walled carbon nanotubes (SWCNT) and Multiwalled carbon nanotubes (MWCNT). These are shown in Figs. 6.30 and 6.31. 6.4.2.1 Application in ultradeepwater oil fields Power transmission is an important factor to consider when designing deep water facilities and systems in the oil and gas industry. Design and development of conductors with higher power transmission efficiency, lower power transmission voltage, and superior mechanical properties compared to existing technologies have tremendous application potential. New-age power umbilicals can transmit more power to the subsea floor while increasing reliability and safety due to lower operating voltages. These

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Figure 6.30 Single walled carbon nanotube [33]. P. Veliz, D. Kong. Design of chamber with carbon nanotubes for deep water installations. In OTC Brasil. Offshore technology conference (2015).

Figure 6.31 Multi walled carbon nanotube. P. Veliz, D. Kong. Design of chamber with carbon nanotubes for deep water installations. In OTC Brasil. Offshore technology conference (2015).

factors will in turn improve downhole electrical pumps, increase the efficiency of existing wellsites and increase the electrical transmissibility through the well head. Several research programs are developing CNT conductors for their use in various industries like aerospace, medical devices, transportation, and microelectronics. Efforts are also underway in using CNTs for large scale applications. Compared to Copper (Cu) wires, higher resistivity levels were observed in Chlorosulphuric acid-based solutions for CNT fibers and iodine-doped CNT cables. In addition, their specific conductivity is higher compared to all metals except sodium [34,35]. For its use in gas and oil fields, with respect to power transmission applications, the requirements needed are dense structures that are aligned along the direction of current flow. Secondly, to enable high percolation density within the entire CNT/Metal matrix, new techniques need to be developed to electrically connect the tubes together in the transverse direction. A study conducted by T.G. Holesinger et al. (2014), successfully developed wires with CNT coatings with high conductivity. These wires were much lighter as compared to

State-of-the-art materials in petroleum facilities and pipelines

traditional copper wires. The goal of this study was to develop a CNT composite wire that had features enabling the composite wires to be used in a similar manner as traditional Cu wires with respect to its field deployment and handling. A brief description of the types of composite wires developed and their resistivity measurements are provided in the sections below. 6.4.2.2 Carbon nanotube arrays The Cu composite wires with CNT were developed by dip-coating CNT solutions in a copper wire former. Multiwalled-CNTs were attained from arrays grown using a source gas, which was ethylene. An in-depth look at the growth process can be understood elsewhere [36]. Fig. 6.32 shows an SEM image of an as-grown array. At 0.75 mm tall this was one of the shorter arrays used in the study [37]. The average range of the forest height was from 1.5 to 2 mm, however, taller arrays (3 mm) were used as well. Taller arrays are more time intensive to develop because the preparation process involves preparing each individual CNT with small fibers for the coating process. A TEM image of a multiwalled-CNT (10 mm diameter) is shown in Fig. 6.33. During the solution process for the growth of CNTs, ultrasonic assistance was avoided, which lead to the lengths of CNTs being well defined. 6.4.2.3 Water-based CNT composite conductors To coat the CNT onto a copper-based wire, a water-based solution was used [37]. Fig. 6.34 and 6.35 show SEM images of thin CNT coatings achieved using waterbased solutions. The CNT fibers are more often than not aligned along the axis of the wire and the coating achieved was smooth. Fig. 6.36 is a TEM image of CNT bundles that are tightly packed in these thin coatings.

Figure 6.32 SEM image of as-grown, 0.75 mm tall multiwalled-CNT array. Z. Yao, W. Jinquan, V. Robert, et al. Iodine doped carbon nanotube cables exceeding specific electrical conductivity of metals Sci. Rep. 1 (2011). Weast, R.C., ed. (1983) 63rd ed. CRC handbook of chemistry and physics, CRC Press, Inc.

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Figure 6.33 TEM image of a CNT bundle cross-section. Z. Yao, W. Jinquan, V. Robert, et al. Iodine doped carbon nanotube cables exceeding specific electrical conductivity of metals Sci. Rep. 1 (2011). Weast, R.C., ed. (1983) 63rd ed. CRC handbook of chemistry and physics, CRC Press, Inc.

Figure 6.34 SEM image of thinly coated CNT based on a water-based solution. Z. Yao, W. Jinquan, V. Robert, et al. Iodine doped carbon nanotube cables exceeding specific electrical conductivity of metals Sci. Rep. 1 (2011). Weast, R.C., ed. (1983) 63rd ed. CRC handbook of chemistry and physics, CRC Press, Inc.

Figure 6.35 SEM image of a thinly coated CNT wire on a water-based solution. Z. Yao, W. Jinquan, V. Robert, et al. Iodine doped carbon nanotube cables exceeding specific electrical conductivity of metals Sci. Rep. 1 (2011). Weast, R.C., ed. (1983) 63rd ed. CRC handbook of chemistry and physics, CRC Press, Inc.

State-of-the-art materials in petroleum facilities and pipelines

Figure 6.36 TEM image of a cross-section view of the thinly coted CNT wire. Z. Yao, W. Jinquan, V. Robert, et al. Iodine doped carbon nanotube cables exceeding specific electrical conductivity of metals Sci. Rep. 1 (2011). Weast, R.C., ed. (1983) 63rd ed. CRC handbook of chemistry and physics, CRC Press, Inc.

Figure 6.37 SEM image of a thick coated CNT composite wire. Z. Yao, W. Jinquan, V. Robert, et al. Iodine doped carbon nanotube cables exceeding specific electrical conductivity of metals Sci. Rep. 1 (2011). Weast, R.C., ed. (1983) 63rd ed. CRC handbook of chemistry and physics, CRC Press, Inc.

Figure 6.38 Cross-section of a thick coated CNT composite wire. Z. Yao, W. Jinquan, V. Robert, et al. Iodine doped carbon nanotube cables exceeding specific electrical conductivity of metals Sci. Rep. 1 (2011). Weast, R.C., ed. (1983) 63rd ed. CRC handbook of chemistry and physics, CRC Press, Inc.

On the other hand, when thicker coatings were achieved, they had a rougher a surface and considerable thickness variation along the wire. Fig. 6.37 and 6.38 shows a thickly coated CNT composite wire. In addition, such thick composite wires had porosity as well.

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Figure 6.39 Presence of Cu nanoparticles in CNT composite wires. Z. Yao, W. Jinquan, V. Robert, et al. Iodine doped carbon nanotube cables exceeding specific electrical conductivity of metals Sci. Rep. 1 (2011). Weast, R.C., ed. (1983) 63rd ed. CRC handbook of chemistry and physics, CRC Press, Inc.

In some samples, a dispersion of Cu particles was observed when adding Cu via solution deposition. This is shown in Fig. 6.39. 6.4.2.4 Acid-based CNT composite conductors Sulphuric acid based solutions were also used in this study [37] to get CNT coatings onto copper wire formers. The CNT coating is shown in Fig. 6.40. Mechanical deformation properties of these wires were studied by drawing them using conventional wire drawing pellets. As shown in Fig. 6.41, the wire drawing process improved the shape density of the coatings as well as alignment. Fig. 6.42 shows the alignment achieved after wire drawing. Fig. 6.43 shows the smooth surface morphology that was achieved after undergoing the wire drawing process. 6.4.2.5 Resistivity observation and study conclusion For water-based CNT coatings, the wire resistivity measurements are provided in Table 6.9. In addition to these resistivities, values for Cu and Al [38] are also provided for comparison. In Table 6.10, whole wire resistivities for CNT coated wires produced in an acidbased solution after undergoing the wire drawing process are provided. Li et al. [36], showed promising results for the use of CNT composite wires. Even though none of the wires were better than Cu, many of the CNT composite wires had better wire resistivity values as compared to Al. As shown in Fig. 6.44, few of the coatings had cracked structures, which is indicative of significant structural damage.

State-of-the-art materials in petroleum facilities and pipelines

Figure 6.40 CNT coating on Cu wire using an acid-based solution. Z. Yao, W. Jinquan, V. Robert, et al. Iodine doped carbon nanotube cables exceeding specific electrical conductivity of metals Sci. Rep. 1 (2011). Weast, R.C., ed. (1983) 63rd ed. CRC handbook of chemistry and physics, CRC Press, Inc.

Figure 6.41 CNT coated wires after undergoing a wire-drawing process. Z. Yao, W. Jinquan, V. Robert, et al. Iodine doped carbon nanotube cables exceeding specific electrical conductivity of metals Sci. Rep. 1 (2011). Weast, R.C., ed. (1983) 63rd ed. CRC handbook of chemistry and physics, CRC Press, Inc.

Figure 6.42 CNT alignment with coating using an acid-based solution. Z. Yao, W. Jinquan, V. Robert, et al. Iodine doped carbon nanotube cables exceeding specific electrical conductivity of metals Sci. Rep. 1 (2011). Weast, R.C., ed. (1983) 63rd ed. CRC handbook of chemistry and physics, CRC Press, Inc.

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Figure 6.43 Surface morphology of CNT coating after wire-drawing process. Z. Yao, W. Jinquan, V. Robert, et al. Iodine doped carbon nanotube cables exceeding specific electrical conductivity of metals Sci. Rep. 1 (2011). Weast, R.C., ed. (1983) 63rd ed. CRC handbook of chemistry and physics, CRC Press, Inc.

Table 6.9 CNT coated resistivities obtained using water-based solutions for different wire substrates. Wire

Wire substrate

Dispersant

Cu (O2 free) Cu (annealed) Cu (hard drawn) Al 17_7 7_7 24_3 33_2





20 20 28 28

AWG AWG AWG AWG

Cu Cu Cu Cu

28_1 16_7 17_3 29_2 32_2

28 20 20 28 28

AWG AWG AWG AWG AWG

Cu Cu Cu Cu Cu

6_1 30_2 30_1 27_1

20 28 28 28

AWG AWG AWG AWG

Cu Cu Cu Cu

water/Dawn water/Dawn water/Dawn water/Triton X water/Dawn water/Dawn water/Dawn water/Dawn water/Triton X water/Dawn water/Dawn water/Dawn water/Dawn

Wire resistivity (μΩ  cm)

Substrate resistivity (μΩ  cm)

Calculated CNT coating resistivity (μΩ  cm)

Coating thickness (μm)

CNT coating: percentage of cross-section (%)

1.68 1.72 1.77





















2.82 1.88 1.82 2.48 2.52


1.79 1.77 1.86 1.84


4.8 2.7 17.3 37.5


15.6 19.5 21.7 29.2


7.5 9.4 23.1 29.3

2.78 2.26 2.3 3.19 3.68

1.87 1.82 1.82 1.85 1.96

23.6 19.0 41.6 20.9 29.9

43.4 49.9 52.1 53.8 67.0

38.7 21.7 22.0 46.2 52.7

2.53 4.72 5.55 7.96

1.84 1.77 1.90 1.91

22.3 48.9 45.0 98.4

77.4 105.0 110.0 170.0

29.8 64.9 66.1 77.5

Z. Yao, W. Jinquan, V. Robert, et al. Iodine doped carbon nanotube cables exceeding specific electrical conductivity of metals Sci. Rep. 1 (2011). Weast, R.C., ed. (1983) 63rd ed. CRC handbook of chemistry and physics, CRC Press, Inc.

This study shows that progress has been made in developing CNT coated wires that can be used as a replacement for Cu wires, with excellent handling and conductivity properties. A general trend observed for thick CNT coatings was lower resistivities, which could indicate degradation of the coating uniformity with thickness. Thin coatings on the other hand were more uniform and had higher resistivities. Future work will consist of improving the thickness without structural damage for smooth and conductive CNT coated composites.

Table 6.10 CNT coated resistivities for wires produced from an acid-based (H2SO4) based solution and undergoing a wire drawing process. Wire

Wire substrate

Dispersant Wire resistivity (μΩ  cm)

Substrate** resistivity (μΩ  cm)

Calculated CNT coating resistivity (μΩ  cm)

Coating thickness (μm)

CNT coating: percentage of wire cross-section (%)

Cu (O2 free) Cu (annealed) Cu (hard drawn) 26 AWG Cu Wire* 28 AWG Cu Wire* Al 46_17 42_17 42_14 41_13 42_18 45_1 43_7 45_3 42_15 43_3 41_11A 46_9A 45_2 41_4A 41_12 43_5 44_11 44_1A 47_5 47_1









1.68 1.72























1.77



















1.76



















1.78














28 AWG Cu 28 AWG Cu 26 AWG Cu 28 AWG Cu 28 AWG Cu 28 AWG Cu 28 AWG Cu 28 AWG Cu 28 AWG Cu 28 AWG Cu 28 AWG Cu 28 AWG Cu 28 AWG Cu 26 AWG Cu 28 AWG Cu 28 AWG Cu 28 AWG Cu 28 AWG Cu 28 AWG Cu 28 AWG Cu

H2SO4 H2SO4 H2SO4 H2SO4 H2SO4 H2SO4 H2SO4 H2SO4 H2SO4 H2SO4 H2SO4 H2SO4 H2SO4 H2SO4 H2SO4 H2SO4 H2SO4 H2SO4 H2SO4 H2SO4

2.82 2.12 2.22 2.17 2.44 2.36 2.45 2.43 2.45 2.33 2.52 2.55 2.48 2.62 2.47 2.66 3.13 3.32 3.40 3.57 3.58


1.82 1.83 1.80 1.86 1.81 1.87 1.85 1.82 1.84 1.87 1.87 1.79 1.89 1.87 1.84 1.85 1.90 1.87 1.87 1.84


7.9 15.1 27.8 27.6 60.6 25.2 20.0 46.1 9.3 46.1 44.3 41.7 26.6 51.1 101.5 36.6 66.5 133.3 70.6 165.5


16.8 18.3 20.8 23.1 23.2 25.0 25.3 25.5 25.9 26.8 27.2 28.3 30.3 30.8 32.0 50.2 52.5 54.0 61.0 61.8


18.5 20.0 17.9 25.1 24.3 25.6 26.1 26.5 27.6 27.0 28.0 29.8 29.9 25.3 31.3 43.0 44.2 45.6 48.9 49.2

Z. Yao, W. Jinquan, V. Robert, et al. Iodine doped carbon nanotube cables exceeding specific electrical conductivity of metals Sci. Rep. 1 (2011). Weast, R.C., ed. (1983) 63rd ed. CRC handbook of chemistry and physics, CRC Press, Inc.

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Figure 6.44 SEM image of a crack in the structure in a CNT coated wire. Z. Yao, W. Jinquan, V. Robert, et al. Iodine doped carbon nanotube cables exceeding specific electrical conductivity of metals Sci. Rep. 1 (2011). Weast, R.C., ed. (1983) 63rd ed. CRC handbook of chemistry and physics, CRC Press, Inc.

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61. [41] S. Ko, V. Prigiobbe, C. Huh, S.L. Bryant, M.V. Bennetzen, K. Mogensen, Accelerated oil droplet separation from produced water using magnetic nanoparticles, Soc. Pet. Eng. (2014). Available from: https://doi.org/10.2118/170828-MS. [42] R. Moradi, J. Karimi-Sabetb, M. Shariaty-Niassara, Y. Amini, Air gap membrane distillation for enrichment of H218O isotopomers in natural water using poly(vinylidenefluoride) nanofibrous membrane, Chem. Eng. Proc: Process. Int. 100 (2016) 26
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11596. Available from: https://doi.org/10.1021/ja993280v. [44] A. Srivastava, O.N. Srivastava, S. Talapatra, Vajtai, M. Robert, P. Ajayan, Carbon nanotube filters, Nat. Mater. 3 (2004) 610
614. Available from: https://doi.org/10.1038/nmat1192. [45] Q. Zheng, J.K. Kim, Graphene for transparent conductors: synthesis, properties and applications (2015). doi: 10.1007/978-1-4939-2769-2, ISBN: 978-1-4939-2768-5.

Index Note: Page numbers followed by “f” and “t” refer to figures and tables, respectively.

A A-MNPs. See Amine functionalized MNPs (A-MNPs) Acid-based CNT composite conductors, 240 Active stereo. See Structured light vision Adsorption of nanoparticles in core samples, 159
161 in porous media, 156
161 Advanced downhole electrical methods, 15
16 Advanced Energy Consortium, 16 Advanced materials, 3
5, 4f in drilling and well completion operations altered fracturing fluid and proppants, 117
118 chemical tracers, 119 nanoparticles in drilling fluids, 116
117 enhancements and improvements in, 20 experimental studies, 5 future challenges, 21 importance of, 6
10 for produced water treatment, 209
222 magnetic nanoparticles, 216
222 nano-filtration membranes, 209
215 for produced water treatment in oil and gas facilities, 209
222 Advanced sensing techniques for O&G facilities and pipelines, 222
227 Advanced sensors in drilling and well completion operations fiber optic sensors, 98
100 fluid measurement sensors, 105
116 3D computer vision techniques, 101
104 in well logging operations electromagnetic-based deep reservoir monitoring, 96
98 microseismic imaging, 94
95 tiltmeter mapping, 95
96 AFM. See Atomic force microscopy (AFM) Air gap membrane distillation process (AGMD), 210
212, 211f Al2O3. See Aluminum oxide (Al2O3) Algyo gasfield, 27

Alpha-olefin sulfonate surfactants (AOS surfactants), 133
134 Altered fracturing fluid, 117
118 Aluminum oxide (Al2O3), 181 Am-241, 113 American Petroleum Institute (API), 79, 194 API RP45 method, 58
59 Amine functionalized MNPs (A-MNPs), 218
222, 219f ANNs. See Artificial neural networks (ANNs) AOS surfactants. See Alpha-olefin sulfonate surfactants (AOS surfactants) API. See American Petroleum Institute (API) Artificial neural networks (ANNs), 104, 110, 116 Asphaltene precipitation, 178
179 Atomic force microscopy (AFM), 209
210 Automated fluid rheology and density, 105
108 pipe viscometer system, 106f rheological parameters, 107
108

B Bakken formation, 183
184, 184f Black chemicals, 163 BMG. See Bulk metallic glass (BMG) Bottle tests, 192 British Petrol (BP), 1 Bromine, 64
65, 68
69 Bubble point technique, 209
210 Bubble theory, 115 Buckminsterfullerene (C60), 10
11 Buckyballs, 10
11 Bulk metallic glass (BMG), 7
9, 8f

C C/H ratios. See Carbon/hydrogen ratios (C/H ratios) Cambay basin oilfields, 80
81 Capillary force, 144 Capillary number, 144 increase in oil
water IFT reduction and emulsification, 144
148

247

248

Index

Capillary number (Continued) in situ upgrading of heavy oil with NPs, 155
156 wettability alteration by NPs, 148
155 Carbide doping, 10 Carbon, 9 NPs, 185 sources in nature, 50
51, 52f Carbon nanotube (CNT), 10
11, 11f, 235 alignment with coating using acid-based solution, 241f arrays, 237 CNT coated resistivities for wires, 243t CNT coated wires after undergoing wiredrawing process, 241f coating on Cu wire, 241f composites, 235
244 acid-based CNT composite conductors, 240 application in ultradeepwater oil fields, 235
237 resistivity observation, 240
244 water-based CNT composite conductors, 237
240 conductors, 236 Carbon Preference Index (CPI), 69
71, 72f Carbon/hydrogen ratios (C/H ratios), 176 Chemical vapor deposition (CVD), 223
224 Chemical EOR processes, 18
19 Chemical injection, 18
19 Chemical tracers, 119 Chlorine, 64
65 Clamp-on meter, 108 Clay instability mechanisms, 190
191 nanoparticle application for clay stabilization, 191
192 Clay minerals, 190 Clay stabilizers, 191 CMG. See Critical micelle concentration (CMG) CNC. See Critical NP (CNC) CNP. See Colloidal nanoparticles (CNP) CNT. See Carbon nanotube (CNT) Colloid silica NPs, 129
130 Colloidal nanoparticles (CNP), 149, 159 Colombian EHO fractions, 181 Compton scattering, 113 Computer vision, 104

Connate water, 46
47 Coriolis meter, 105
106, 114
116 Coriolis U-tube mass flow rate meter, 114
116, 114f Coriolis flow and density meter, 106f CPI. See Carbon Preference Index (CPI) Critical micelle concentration (CMG), 185
186 Critical NP (CNC), 136 Cs-137, 113 Cupric phosphate (Cu3(PO4)2), 182 CVD. See Chemical vapor deposition (CVD)

D Damping theory, 115 Darcy’s Law, 195 Derjaguin-Landau-Verwey-Overbeek theory (DLVO theory), 189, 198
199 Desorption, 156 Diamond-like carbon (DLC), 9
10 Diamond-like carbon doping with fluorine (F-DLC), 10 Diamond-like carbon doping with metals (M-DLC), 10 Diamond-like carbon doping with nitrogen (N-DLC), 10 Diamond-like carbon doping with silicon (Si-DLC), 10 Dimensionless NP concentration (DNC), 159
161 Direct casting, 8
9 Disjoining pressure, 153 Distributed sensing, 99
100 Diversion using nanofluid, 140
143 water diversion technology, 141f, 141t DLC. See Diamond-like carbon (DLC) DLVO theory. See Derjaguin-Landau-VerweyOverbeek theory (DLVO theory) DNC. See Dimensionless NP concentration (DNC) DOE. See US Department of Energy (DOE) Double layer and Born repulsion, 186
187 Drilling operations advanced materials, 116
119 advanced sensors, 98
116 and production, 16
18 Drive gain saturation, 115

249

Index

E

F

E&P industry. See Exploration and production industry (E&P industry) ECHA. See European Chemical Agency (ECHA) Effective source rock, 50
51 EHO. See Extra-heavy oil (EHO) Electromagnetic carrier wave, 98 Electromagnetic-based deep reservoir monitoring, 96
98 electrode-based measurements, 98f Electrospinning, 212f, 213f Emulsification, 19, 144
148, 145t Emulsion, 19 Energy mix, 125 Enhanced oil recovery (EOR), 15
16, 18
20, 125, 127, 128f future works, 167 health, safety and environment environmental impact of chemical EOR, 164
166 safety and health related to nanoparticle handling, 166 water based chemicals, 162
164 mechanisms of nanofluid increase in capillary number, 144
156 mobility control, 133
143 nanoparticle-surfactant fluid, 185f nanoparticles, 129
133 adsorption and transportation in core samples, 159
161 adsorption and transportation in porous media, 156
161 in shales, 183
186 project plan for implementation of nanotechnology, 128f Environmental impact of chemical EOR, 164
166 EOR. See Enhanced oil recovery (EOR) European Chemical Agency (ECHA), 164
165 Exploration, 125
126 in O&G industry, 15
16 in petroliferous Pannonian basin, 27 Exploration and production industry (E&P industry), 16
17 Extra-heavy oil (EHO), 181

F-DLC. See Diamond-like carbon doping with fluorine (F-DLC) FA solution. See Formic acid solution (FA solution) Fe-based BMG systems, 8
9 Fiber, 100 Fiber optic sensors, 98
100 Field tests in Colombian heavy oil formations, 180
181 Fines migration effective potential in, 187t formation damage control due to, 188
190 formation damage due to, 186
187 formation damage problem of, 188 “Fit-for-purpose” application, 197
198 Flow behavior index, 107 Fluid leak-off mechanisms, 193
194 nanoparticles for, 194 Fluid measurement sensors automated fluid rheology and density, 105
108 Coriolis U-tube mass flow rate meter, 114
116, 114f gamma-ray densitometer, 112
114, 112f magnetic flow meter, 111
112 pulsed ultrasound Doppler flow meter, 110
111 transit time ultrasonic flow meter, 108
110 Fluorine, 64
65 Fly ash NPs, 134 FNP. See Fumed silica NPs (FNP) Formation damage clay instability mechanisms, 190
191 nanoparticle application for clay stabilization, 191
192 control due to fines migration using nanoparticles, 188
190 effective potential in fines migration, 187t due to fines migration, 186
187 fluid leak-off mechanisms, 193
194 nanoparticles for, 194 problem of fines migration during LWSF, 188 Formation water, 46
47

250

Index

Formation water (Continued) relationships between oil (bbl)/water (bbl) ratios, water% (bbl) ratios, and iodine contents, 80
81 Formic acid solution (FA solution), 181
182 Fracturing imaging technique, 94 Fullerenes, 10
11 Fumed silica NPs (FNP), 157 suspensions with reservoir rocks, 158f

G GAB model. See Guggenheim, Anderson, and De Boer model (GAB model) Gamma-ray densitometer, 112
114, 112f Gas chromatography analysis, 56, 70
71 Gas hydrate recovery mechanism, 200
201 nanoparticles for, 201
202 Gas injection, 18
19 Gas volume fraction (GVF), 112 GHG emissions. See Greenhouse gas emissions (GHG emissions) Glass forming ability (GFA), 7
8 Graphene, 222
227, 223f fabricated graphene sensor, 226f multifunctional sensing ability, 223f sensor for CO2 detection, 224 fabrication process, 226f for scale monitoring, 225
227 transfer to glass, 225f Green chemicals, 163 Greenhouse gas emissions (GHG emissions), 176
177 Groundwaters, 55
56 Guggenheim, Anderson, and De Boer model (GAB model), 195
196 GVF. See Gas volume fraction (GVF)

H HAHPAM. See Hydrophobically associating partially hydrolyzed polyacryamide (HAHPAM) HCK. See Hydrocracking (HCK) HDM. See Hydrodemetallization (HDM) HDN. See Hydrodenitrogenation (HDN) HDO. See Hydrodeoxygenation (HDO) HDS. See Hydrodesulfurization (HDS) Health safety and environment (HSE), 20

Heavy oil reservoirs nanomaterials mechanisms in, 176
179 nanomaterials studies in, 179
182 Homogenous mixing of multiphase or aerated liquids, 113 HPAM. See Hydrolyzed polyacrylamide (HPAM) HPAM/NP hybrids, 137
138, 137f, 140 HSE. See Health safety and environment (HSE) Hybrid carbon nanotube and carbon nitride membrane (Hybrid CNT-CNx membrane), 212
215 filtration performance, 215f for flowback water filtration, 214f Hybrid CNT-CNx membrane. See Hybrid carbon nanotube and carbon nitride membrane (Hybrid CNT-CNx membrane) Hydrocarbons, 28, 45
46 derived from reservoir in subsurface, 48
49 source, maturity, and sedimentation environment redox conditions, 69
74 Hydrocarbons-rich geothermal fluids, 40
43 Hydrocarbons-rich reservoir waters, 38 Hydrocarbons-rich waters, 40f Hydrochloric acid (HCl), 157 Hydrocracking (HCK), 176 Hydrodemetallization (HDM), 176 Hydrodenitrogenation (HDN), 176 Hydrodeoxygenation (HDO), 176 Hydrodesulfurization (HDS), 176 Hydrodynamic forces, 186
187 Hydrogenation, 176
177 Hydrogeochemical exploration, 46
47 Hydrogeochemical maps, 46
47 Hydrogeochemistry in oil and gas exploration, 45
47 Hydrolyzed polyacrylamide (HPAM), 135, 139, 142
143, 164 Hydrophilic silica CNP, 149 Hydrophobically associating partially hydrolyzed polyacryamide (HAHPAM), 137

I ICP-OES. See Inductively coupled plasma optical emission spectrometry (ICP-OES) IFT. See Interfacial tensions (IFT) Improved oil recovery (IOR), 126
127 In situ upgrading of heavy oil with NPs, 155
156

251

Index

Inductively coupled plasma optical emission spectrometry (ICP-OES), 215 Intelligent materials in unconventional oil and gas recovery formation damage due to clay instability, 190
192 control due to fines migration using nanoparticles, 188
190 effective potential in fines migration, 187t due to fines migration, 186
187 due to fluid leak-off, 193
194 problem of fines migration during LWSF, 188 gas hydrate recovery mechanism, 200
201 nanoparticles for, 201
202 nanomaterials mechanisms in heavy oil reservoirs nanocatalysis in heavy oil, 176
177 nanofluids in heavy oil, 177
179 nanomaterials studies in heavy oil reservoirs, 179
182 nanoparticles for enhanced oil recovery in shales, 183
186 wellbore strengthening mechanisms, 195
196 nanoparticles for, 196
200 Interfacial tensions (IFT), 144, 178
179 reduction caused by nanoparticles, 183f Iodine, 27 contents in geothermal fluids of Great Basin, 42f discovery, 28 enrichment, 29 environments, 28f geology in oil and gas exploration, 44
79 pedogeochemistry usage in oil and gas exploration, 75
76 release, 68
69 species in groundwater, 37f in treated drinking water, 37f Iodine hydrogeochemistry in oil and gas exploration, 47
74 coloration of iodine-rich and noniodine waters, 60f integrated use, 53
74 sampling from natural water resource, 59f work-time schedule of integrated method, 55t

in reservoir evaluation and oil production, 79
82 relationship between iodine contents of formation waters and oilfield reserves, 81
82 relationships between oil (bbl)/water (bbl) ratios, water% (bbl) ratios, and iodine contents of formation waters, 80
81 usage during well drilling, 77
79 Iodine-129 isotope usage in petroleum geology, 75 Iodine-rich geothermal fluids, 40
43 groundwater, 41f reservoir waters, 38 surface water, 41f Iodine-rich waters, 27, 34
37, 40f occurrence mechanisms of, 38
43 oil and gas deposits relationship and, 43 relationship between active faults and, 41f Iodine
petroleum relationship, 27
28 formation, migration, and trapping relationships between oil and iodine, 30f, 31
33 iodine, organic matter, and organic carbon relationship, 29
30 IOR. See Improved oil recovery (IOR) Iron Oxide (Fe2O3), 194

K Knudsen number, 195

L Lightwave systems, 98 Liquid petroleum pipelines, 207
208 Log-jamming, 177
178, 178f London/Van der Waal’s attraction, 186
187 Low salinity water flooding (LWSF), 188 Lunnan oilfield, 31

M M-DLC. See Diamond-like carbon doping with metals (M-DLC) Machine learning, 104 tools, 110 Magnetic coercivity, 216, 217f Magnetic flow meter, 111
112 Magnetic nanoparticles (MNP), 216
222 for EOR polymer removal from produced water, 218
222

252

Index

MCM-41. See Mobil Composition of Matter (MCM-41) Membrane based distillation, 210 Mercury injection capillary pressure (MICP), 195 Mercury porosimetry, 209
210 Metal doping, 10 Methane (CH4), 69 Mg-based BMG systems, 8
9 MICP. See Mercury injection capillary pressure (MICP) Microseismic imaging, 94
95 deployment of microseismic tools and treatment well, 94f Migration Model, 33f Million tons of oil equivalent (Mtoe), 1 MNP. See Magnetic nanoparticles (MNP) Mobil Composition of Matter (MCM-41), 20 Mobility control diversion using nanofluid, 140
143 nanoparticles stabilized foam, 133
134 nanoparticles-enhanced polymer flooding, 135
140 Mobility ratio (M), 135 Mtoe. See Million tons of oil equivalent (Mtoe) Multiwalled carbon nanotubes (MWCNT), 11f, 235, 236f MWCNT. See Multiwalled carbon nanotubes (MWCNT)

N N-DLC. See Diamond-like carbon doping with nitrogen (N-DLC) NaI (TL) scintillators, 113 Nano-filtration membranes, 209
215 hybrid CNT and CNx membrane, 212
215, 214f nanofibrous PVDF, 210
212 Nano-structure particle (NSP), 159 Nanocatalysis in heavy oil, 176
177 Nanocatalysts, 11
12 Nanocoatings for oil and gas facilities carbon nanotube composites, 235
244 silane-nanoceramic coating, 227
234 Nanocrystalline materials (NC materials), 7 Nanoemulsions, 19
20 Nanofibrous PVDF, 210
212 preparation, 212f, 213f Nanofluids, 117

EOM mechanisms increase in capillary number, 144
156 mobility control, 133
143 in heavy oil, 177
179 Nanomaterials mechanisms nanocatalysis in heavy oil, 176
177 nanofluids in heavy oil, 177
179 studies in heavy oil reservoirs, 179
182 Nanomembranes, 209
210 Nanoparticles (NPs), 16, 125
126, 129
133, 143, 164
165 adherence, 198 adsorption and transportation of nanoparticles in core samples, 159
161 in porous media, 156
161 adsorption inside porous medium, 157f application for clay stabilization, 191
192 in drilling fluids, 116
117 effect on oil-rock contact angle change, 150t for enhanced oil recovery in shales, 183
186 for fluid leak-off, 194 fumed silica NP synthesis, 130f for gas hydrate recovery, 201
202 NP-enhanced polymer flooding, 135
140 oil
water IFT reduction and emulsification, 144
148, 145t plugging, 177
178 silica nanoparticles chemical properties, 131
133 physical properties, 131 stabilized foam, 133
134 structuring in wedge-film resulting, 154f two-dimensional random network, 130f types, 129
130 for wellbore strengthening, 196
200 Nanoscale metals, 11
12 Nanotechnological solutions, 20 challenges in, 12
21, 13t Nanotechnology, 3
7, 4f, 125
126 enhancements and improvements in, 20 experimental studies, 5 future challenges, 21 in O&G industry, 10
12 and oil field applications, 126t Natural N-alkane Ratio (NAR), 69
70 Natural organic matter (NOM), 33f, 34 NC materials. See Nanocrystalline materials (NC materials)

253

Index

Newtonian fluids, 105 Nickel oxide (NiO), 181 NOM. See Natural organic matter (NOM) Noncoated MNPs, 218
219 NPs. See Nanoparticles (NPs) NSP. See Nano-structure particle (NSP)

O O&G industry. See Oil and gas industry (O&G industry) O/W. See Oil-in-water (O/W) Offshore constraints, 165
166 Offshore polymer injection projects, 164 OGRC. See Oil and Gas Research Council (OGRC) Oil and gas (O&G) pipelines, 207
208 advanced sensing techniques for, 222
227 Oil and gas exploration (O&G exploration) hydrogeochemistry in, 45
47 iodine geology in, 44
79 iodine hydrogeochemistry, 47
74 usage during well drilling, 77
79 iodine pedogeochemistry usage in, 75
76 iodine-rich organic matter transformation to hydrocarbon, 45f Oil and gas facilities (O&G facilities), 207 advanced materials for produced water treatment, 209
222 advanced sensing techniques, 222
227 components, 208f nanocoatings carbon nanotube composites, 235
244 silane-nanoceramic coating, 227
234 Oil and gas industry (O&G industry), 6, 175 advanced materials in, 6
10 BMG, 7
9, 8f DLC, 9
10 NC materials, 7 challenges in, 12
21, 13t drilling and production, 16
18 enhanced oil recovery, 18
20 exploration, 15
16 refining and processing, 20
21 iodine
bromine concentration data, 67f nanotechnology in, 10
12 Oil and Gas Research Council (OGRC), 184 Oil-generating source rocks, 61 Oil-in-water (O/W), 19
20 Oilfield Water Differentiation Plot, 61
62

Oil
water IFT reduction, 144
148 Once-active source rock, 50
51 “One-step top-down” fabrication approach, 7 Ordinary ceramic coatings, 229, 230t Organic geochemical methods, 69
74 Organic mineral complexes, 33f, 34 Organic-rich marine sediments, 65
66 Organic-rich sediments, 28 Oslo and Paris Commission (OSPAR), 162
163

P P-waves, 94
95 PC. See Petroleum coke (PC) PEI. See Polyethylene imine (PEI) Permporometry, 209
210 Petroleum, 17, 50
51 geochemical analyses, 49
50 petroleum-derived fluids, 17 relationship with iodine, 27
33 Petroleum coke (PC), 118 Phytane (Ph), 70
71 Pickering emulsion, 145f, 146, 147f Pipe viscometer system, 105
106, 106f Plastic viscosity (PV), 197 PLONOR. See Pose Little Or No Risk To The Environment (PLONOR) PMMA. See Polymethyl methacrylate (PMMA) Polyethylene imine (PEI), 142 Polymer flooding, 135, 138 Polymer water flooding, 164 Polymethyl methacrylate (PMMA), 224 Polyvinylidene fluoride membrane (PVDF), 210
211 nanofibrous, 210
212 Pore plugging, 200 Pore pressure transmission tests (PPT tests), 197 Pore volume (PV), 147 Portable iodine checkers/photometers, 59
61, 60f Portable oil in water (TPH) analyzers, 60f Pose Little Or No Risk To The Environment (PLONOR), 162
163 Potential source rock, 50
51 PPT tests. See Pore pressure transmission tests (PPT tests) Pristane (Pr), 70
71 Proppants, 117
118 Pulsed ultrasound Doppler flow meter, 110
111 PV. See Plastic viscosity (PV); Pore volume (PV) PVDF. See Polyvinylidene fluoride membrane (PVDF)

254

Index

R Red chemical, 163
164 Redox potential (Eh), 34 Refining and processing in O&G industry, 20
21 Relic effective (inactive) source rock, 50
51 Reservoir rocks, 158 Reservoir-targeted integrated exploration method, 54f Reynolds number, 107 Riser installation coatings, 229
232, 231t surface temperature variations, 231f Rock wettability, 178

S S-waves, 94
95 Safety and health related to nanoparticle handling, 166 Salt lakes, 28 Scanning electron microscope (SEM), 209
210 Scattering effect, 109 Scraper systems, 208 Scrubber systems, 208 SCW. See Supercritical water (SCW) Seawater corrosion resistance, 232
234, 234t SEM. See Scanning electron microscope (SEM) Sensitive electromagnetic imaging methods, 15
16 Shales materials to strengthen wellbore in, 194
200 nanoparticles for enhanced oil recovery in, 183
186 SI. See Swelling Index (SI) Si-A-MNPs, 218f, 220
222 Si-DLC. See Diamond-like carbon doping with silicon (Si-DLC) Si-MNP. See Silica-coated MNPs (Si-MNP) Signal-to-noise ratio (SNR), 109 Silane-nanoceramic coating, 227
234 experimental analysis and validation, 228 heat transfer method, 228f performance parameters of insulation coatings, 229t seawater corrosion resistance, 232
234, 234t silane-nanoceramic as thermal insulator, 227
228 thermal insulation effect, 228
232 Silica nanoparticles (Silica NP), 129
130, 185, 191
192, 194

chemical properties, 131
133 physical properties, 131 Silica-coated MNPs (Si-MNP), 218
222, 219f Silicon oxide (SiO2), 181 Single walled carbon nanotubes (SWCNT), 235, 236f Smart fluids, 11
12, 17
18 Smart pigs, 208 Smectite clay, 191 SNR. See Signal-to-noise ratio (SNR) Society of Petroleum Engineers (SPE), 125
126 Sophisticated modeling and simulation techniques, 15
16 Source rock, 50
51 Southeastern Anatolia and Thrace Basins, 27
28 SPE. See Society of Petroleum Engineers (SPE) Spent (exhausted, depleted) source rock, 50
51 SSW. See Synthetic seawater (SSW) Stability of NP suspension at reservoir conditions, 157
158 Stereo vision, 101
102, 101f Strontium sulphate solutions, 225
227 Structured light vision, 103
104 Sulphate scaling, 225 Sunset-Midway oilfield, 27 Supercritical water (SCW), 181
182 Superior property, 6
7 Superparamagnetism, 216, 217f Surface waters, 38, 55
56 Surfactants, 164 SWCNT. See Single walled carbon nanotubes (SWCNT) Swelling clays, 190 Swelling Index (SI), 191
192 Synthesized MNPs, 219t Synthetic seawater (SSW), 219

T TCF. See Trillion cubic feet (TCF) Tetraethyl orthosilicate (TEOS), 218
219 Thallium-activated sodium iodide, 113 Thermal insulation coating structure influence on, 233f effect, 228
232 with respect to coating structure, 232 with respect to coating thickness, 232 Thermal recovery, 18
19 Thermoplastic forming (TPF), 8
9

255

Index

Three-dimensional (3D) computer vision techniques, 101
104 stereo vision, 101
102, 101f structured light vision, 103
104 2D and 3D integrated cuttings sensing technology, 104, 105f 3D vision sensor technologies comparisons, 104t 3D time-of-flight (TOF), 102
103 camera operation, 102f Thrust-and-fold belt, 38
39 Tiltmeter mapping, 95
96 low-frequency induction tool for fracture mapping, 97f mapped propped fracture volume, 96f principle of tiltmeter fracture mapping, 95f Titanium oxide (TiO2), 181 TOC. See Total organic carbon (TOC) TOF. See 3D time-of-flight (TOF) Top-down nanofabrication, 10 Total organic carbon (TOC), 29
30 Total Petroleum Hydrocarbons (TPH), 34 enrichment, 38
39, 44 TPF. See Thermoplastic forming (TPF) TPH. See Total Petroleum Hydrocarbons (TPH) Transit time ultrasonic flow meter, 108
110 Transportation of nanoparticles in core samples, 159
161 in porous media, 156
161 Trapping Model, 33f Triaxial induction coils, 96
97 Trillion cubic feet (TCF), 175 2D and 3D integrated cuttings sensing technology, 104, 105f “Two-step bottom-up” fabrication approach, 7 Type-II kerogen, 32
33 Type-III kerogen, 32
33

U Ultradeepwater oil fields, application in, 235
237 Ultrasonic transducer, 109 Unconventional oil and gas resources, 175 US Department of Energy (DOE), 15
16

Vapor extraction (Vapex), 21 Viscous effect, 109 Volatile organic compounds (VOC), 209 Volumetric of chemicals, 165

W W/O. See Water-in-oil (W/O) Water, 109
110 associated with hydrocarbons, 31 enriched in iodine and mature petroleum hydrocarbons, 63f, 64t, 70t relation to hydrocarbon accumulations of, 65t relationship with hydrocarbon accumulations of, 61
63 Water based chemicals, 162
164, 163f Water-based CNT composite conductors, 237
240 Water-in-oil (W/O), 19
20 Water
rock
hydrocarbon interaction, 53
55 Well completion operations, 93 advanced materials in, 116
119 advanced sensors in, 98
116 Well drilling, iodine hydrogeochemistry usage during, 77
79 Well logging operations, advanced sensors in electromagnetic-based deep reservoir monitoring, 96
98 microseismic imaging, 94
95 tiltmeter mapping, 95
96 Well-to-consumer supply chain, 12, 12f Wellbore instability, 194
195 Wellbore strengthening mechanisms of, 195
196 nanoparticles for, 196
200 Wettability alteration by NPs, 148
155 Wettability index (WI), 149, 151f, 152f White light scanning. See Structured light vision Williston Basin, 183
184, 184f

Y Yellow chemicals, 163 Yield point (YP), 197

V

Z

Vacuum residue (VR), 181
182

Zr-based BMG systems, 8
9