Fossil Energy (Encyclopedia of Sustainability Science and Technology Series) 1493997629, 9781493997626

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Encyclopedia of Sustainability Science and Technology Series Editor-in-Chief: Robert A. Meyers

Ripudaman Malhotra  Editor

Fossil Energy Second Edition

A Volume in the Encyclopedia of Sustainability Science and Technology, Second Edition

Encyclopedia of Sustainability Science and Technology Series Editor-in-Chief Robert A. Meyers

The Encyclopedia of Sustainability Science and Technology series (ESST) addresses the grand challenge for science and engineering today. It provides unprecedented, peer-reviewed coverage in more than 600 separate articles comprising 20 topical volumes, incorporating many updates from the first edition as well as new articles. ESST establishes a foundation for the many sustainability and policy evaluations being performed in institutions worldwide. An indispensable resource for scientists and engineers in developing new technologies and for applying existing technologies to sustainability, the Encyclopedia of Sustainability Science and Technology series is presented at the university and professional level needed for scientists, engineers, and their students to support real progress in sustainability science and technology. Although the emphasis is on science and technology rather than policy, the Encyclopedia of Sustainability Science and Technology series is also a comprehensive and authoritative resource for policy makers who want to understand the scope of research and development and how these bottom-up innovations map on to the sustainability challenge. More information about this series at https://link.springer.com/bookseries/ 15436

Ripudaman Malhotra Editor

Fossil Energy Second Edition A Volume in the Encyclopedia of Sustainability Science and Technology, Second Edition

With 173 Figures and 68 Tables

Editor Ripudaman Malhotra Malhotra Energy Consultancy San Carlos, CA, USA

ISBN 978-1-4939-9762-6 ISBN 978-1-4939-9763-3 (eBook) ISBN 978-1-4939-9764-0 (print and electronic bundle) https://doi.org/10.1007/978-1-4939-9763-3 1st edition: © Springer Science+Business Media New York 2013 2nd edition: © Springer Science+Business Media, LLC, part of Springer Nature 2020 This work is subject to copyright. All rights are reserved by the Publisher, whether the whole or part of the material is concerned, specifically the rights of translation, reprinting, reuse of illustrations, recitation, broadcasting, reproduction on microfilms or in any other physical way, and transmission or information storage and retrieval, electronic adaptation, computer software, or by similar or dissimilar methodology now known or hereafter developed. The use of general descriptive names, registered names, trademarks, service marks, etc. in this publication does not imply, even in the absence of a specific statement, that such names are exempt from the relevant protective laws and regulations and therefore free for general use. The publisher, the authors, and the editors are safe to assume that the advice and information in this book are believed to be true and accurate at the date of publication. Neither the publisher nor the authors or the editors give a warranty, expressed or implied, with respect to the material contained herein or for any errors or omissions that may have been made. The publisher remains neutral with regard to jurisdictional claims in published maps and institutional affiliations. This Springer imprint is published by the registered company Springer Science+Business Media, LLC, part of Springer Nature. The registered company address is: 233 Spring Street, New York, NY 10013, U.S.A.

Series Preface

Our nearly 1000-member team recognizes that all elements of sustainability science and technology continue to advance as does our understanding of the needs for energy, water, clean air, food, mobility, and health, and the relation of every single aspect of this vast and interconnected body of knowledge to climate change. Our Encyclopedia content is at a level for university students, professors, engineers, and other practicing professionals. It is gratifying for our team to note that our online First Edition has been heavily utilized as evidenced by over 500,000 downloads which of course is in addition to scientists’ utilization of the Encyclopedia and individual “spin-off” volumes in print. Now we are pleased to have a Living Reference on-line which assures the sustainability community that we are providing the latest peer-reviewed content covering the science and technology of the sustainability of the earth. We are also publishing the content as a Series of individual topical books for ease use by those with an interest in particular subjects, and with expert oversight in each field to ensure that the second edition presents the state-of-the-science today. Our team covers the physical, chemical and biological processes that underlie the earth system including pollution and remediation and climate change, and we comprehensively cover every energy and environment technology as well as all types of food production, water, transportation and the sustainable built environment. Our team of 15 board members includes two Nobel Prize winners (Kroto and Fischlin), two former Directors of the National Science Foundation (NSF) (Colwell and Killeen), the former President of the Royal Society (Lord May), and the Chief Scientist of the Rocky Mountain Institute (Amory Lovins). And our more than 40 eminent section editors and now book editors, assure quality of our selected authors and their review presentations. The extent of our coverage clearly sets our project apart from other publications which now exist, both in extent and depth. In fact, current compendia of the science and technology of several of these topics do not presently exist and yet the content is crucial to any evaluation and planning for the sustainability of the earth. It is important to note that the emphasis of our project is on science and technology and not on policy and positions. Rather, policy makers will use our presentations to evaluate sustainability options. Vital scientific issues include: human and animal ecological support systems, energy supply and effects, the planet’s climate system, systems of

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Series Preface

agriculture, industry, forestry, and fisheries and the ocean, fresh water and human communities, waste disposal, transportation and the built environment in general and the various systems on which they depend, and the balance of all of these with sustainability. In this context, sustainability is a characteristic of a process or state that can be maintained at a certain level indefinitely even as global population increases toward nine billion by 2050. The population growth, and the hope for increase in wealth, implies something like a 50% increase in food demand by as early as 2030. At the same time, the proportion of the population that lives in an urban environment will go up from about 47% to 60%. Global economic activity is expected to grow 500%, and global energy and materials use is expected to increase by 300% over this period. That means there are going to be some real problems for energy, agriculture, and water, and it is increasingly clear that conflicting demands among biofuels, food crops, and environmental protection will be difficult to reconcile. The “green revolution” was heavily dependent on fertilizers which are manufactured using increasingly expensive and diminishing reserves of fossil fuels. In addition, about 70% of available freshwater is used for agriculture. Clearly, many natural resources will either become depleted or scarce relative to population. Larkspur, CA, USA November 2019

Robert A. Meyers, Ph.D. Editor-in-Chief

Volume Preface

To many in the sustainability community, fossil energy is an anathema. Continued use of fossil resources – oil, coal, natural gas – poses threats to the environment through the emission of pollutants and greenhouse gases. The fact that they are a limited or exhaustible resource means that in the future we could either run out of them or their extraction will get progressively harder to a point that it takes more energy to extract them than would be derived from their use. Using fossil energy is clearly not sustainable, and the world has to look to renewable resources for long-term survival. This is an encyclopedia about the science and technology of sustainability. The word, sustainability shares its root with sustenance. Any discussion of sustainability must therefore include discussions of sustenance, and in the context of modern society, sustenance stems from the use of energy. We derive energy from a number of different sources. Annual global consumption of primary energy in 2010 (the time of publication of the First Edition) was on the order of 500 exajoules (EJ), about 85% of which comes from fossil resources. From 500 EJ/year, the global energy demand is expected to rise to somewhere between 1000 and 1500 EJ/year by the middle of this century. The drivers for this increased demand are already in place. Large segments of China, India, and Brazil are poised to increase their standard of living – and the concomitant energy demand – substantially. If the average energy consumption in the AsiaPacific region were to reach the current global average, which is about half of what is consumed in Europe and Japan, the demand would increase by an amount equal to the total energy consumption in the North America region. As we get ready to publish the Second Edition of the Encyclopedia of Sustainable Science and Technology, I pause to reflect on some of the developments since the publication of the First Edition. Global energy consumption has increased 12% to 560 EJ. Contribution of renewable resources like wind and solar energy has more than doubled, but 85% of global primary energy is still provided by fossil energy sources of oil, coal, and natural gas. As a result, 34 billion metric tonnes (Gt) of CO2 were emitted from the energy use in 2017. Production of shale oil by hydraulic fracturing in the USA has had a major impact on the global supply and price of oil. The relative speed with which this resource can be produced and shut down has allowed global oil price to stabilize close to $50/bbl. The threat to global climate posed by greenhouse gases (GHG) and the role of humans in it are now clearer than when these concerns first gained vii

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prominence in the 1980s. In its 2013 Summary for Policy Makers the Intergovernmental Panel on Climate Change (IPCC) spells out the underlying physical basis of the threat (Climate Change 2013: The Physical Science Basis, Fifth Assessment Report of the IPCC. www.climatechange2013.org). Calls for quickly curbing GHG emissions can be heard not just from environmental groups but also from many business communities and national governments. Yet, global trends show little progress. The Papal Encyclical issued in July 2015 also drew attention to the growing threat of climate change and its disproportionate impact on the impoverished (Pope Francis, “Encyclical Letter Laudato Si ” July 2015. https://laudatosi. com/watch). Pope Francis called for “changes of lifestyle, production and consumption, in order to combat this warming or at least the human causes which produce or aggravate it.” His statements about combating climate change received much attention, but there was another deeper message in his statement, the one about consumerism and social injustice it engenders that seems to have been largely ignored. The pope recognized the need for vastly expanding renewable energy sources, but also noted that, “(f)or poor countries, the priorities must be to eliminate extreme poverty and to promote the social development of their people.” Around the same time as the Pope’s Encyclical, the World Bank also issued Sustainable Development Goals for the world which lists goals and targets in 17 areas: eradicating poverty, providing adequate food and clean water, reducing gender inequality, taking urgent action to combat climate change, and ensuring access to affordable reliable energy is listed among the goals. Achieving most of these goals requires increasing global energy supply. Speaking about the enormous progress in alleviating poverty around the world, Dr. Jim Yong Kim, President of World Bank, noted that over a billion people have been lifted out of poverty in the last 25 years, and he could foresee lifting another billion in not too distant future. The progress Dr. Kim noted was made on the backs of coal and oil. Can we afford to do the same to help the next billion without risking catastrophic consequences of climate change? The SDG of removing poverty runs up against the need to curb CO2 emissions. The World Bank and many other institutions think that widespread deployment of renewables, such and wind and solar power, can provide the necessary energy. While renewables have a place in the future mix of global energy sources, we cannot and should not count on intermittent sources alone to meet the demands of industries and megacities. Unfortunately, the one CO2-free energy source that is capable of generating the required scale of power, nuclear, is something that the World Bank does not support developing. Amid much fanfare about 200 nations signed the Paris Agreement to curb global GHG emissions in December 2015. It was an unprecedented achievement given the previous failed attempts. All nations acknowledged the peril the world faces from climate change, which is engendered by continued emission of GHG, principally from the use of fossil fuels. The countries pledged to cut down their GHG emissions either in absolute numbers or relative to an expected business-as-usual (BAU) scenario. The individual countries determine the GHG reductions they pledge to make. However,

Volume Preface

Volume Preface

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there is no mechanism of punitive action to force the countries to stick to the pledged contributions except a public shame. The intended nationally determined contributions (INDCs) are reported to the UN, and the emissions of each country are measured and reported in an agreed-upon standard way, and both these are available to the public. The lack of enforcement is a recognition of political realities; any agreement that had forced compliance would not have had the support of many countries. The Paris Agreement sets a goal of limiting the rise in global temperature to 2  C above the pre-industrialization level, with a stretch goal of limiting the rise to 1.5  C. Even achieving the 2  C target is a daunting challenge and requires limiting total emissions to about 350 Gt CO2. The world currently emits about 36 Gt CO2 from energy use each year. To meet the stated goal the world must reduce GHG emissions to 17 Gt-CO2/year by 2035 and achieving a net zero emissions by 2050. As of this writing, 180 countries have submitted their INDCs. However, even if all these nations complied with their pledged INDCs, the global emissions would rise to 55 Gt-CO2/year by 2035! The only hope for success is if, as envisioned in the Paris Agreement, the signatory nations review and ramp up their pledges every few years. Will we? Under BAU the annual energy consumption is expected to rise to more than double by 2050. Even under an all-renewable, all-electric scenario, which could conceivably avoid two-thirds of the primary energy, the world would require generating over 100,000 TWh of electricity relative to 24,000 TWh in 2014; in other words, more than quadrupling the current global electricity production. There remains a large gap between the targeted reductions in GHG emissions and those achieved or pledged by nations, chiefly because the energy needed to alleviate poverty is huge and cannot be met by renewable power sources like wind and solar. I find it appalling that the word energy appears only three times in the 31-page Agreement. The word appears twice on page two where the Conference of Parties “acknowledges the need to promote universal access to sustainable energy in developing countries, in particular in Africa, through the enhanced deployment of renewable energy.” The third time the word is used is on page 31 as part of the name of UN’s IAEA: International Atomic Energy Agency. No wonder then that there is such huge chasm between the target reductions in CO2 and the pledged INDCs. Against this rather dreary picture, I struggle to not fall into despair and keep hope alive. What helps is the recognition that there are thousands of scientists and engineers, particularly of the younger generation, who are stepping up their efforts at developing CO2-free sources of energy and technologies that vastly improve the energy efficiency of a whole host of systems: industrial processes, appliances, transportation, and communication, among others. Successful and widespread deployment of those technologies is the pathway for a sustainable future. San Carlos, CA, USA November 2019

Ripudaman Malhotra Volume Editor

Contents

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1

Oil and Natural Gas: Global Resources . . . . . . . . . . . . . . . . . . . . . . Peter J. McCabe

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Oil Shale Processing, Chemistry, and Technology . . . . . . . . . . . . . . Vahur Oja and Eric M. Suuberg

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Fossil Energy: Introduction Ripudaman Malhotra

Petroleum and Oil Sand Exploration and Production James G. Speight

Hydraulic Fracturing Fred Aminzadeh

Petroleum Refining and Environmental Control and Environmental Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101 James G. Speight Internal Combustion Engines, Developments in . . . . . . . . . . . . . . . 133 Timothy J. Jacobs Alaska Gas Hydrate Research and Field Studies S. L. Patil, A. Y. Dandekar, and S. Khataniar

. . . . . . . . . . . . . . 185

Gas to Liquid Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 203 Marianna Asaro, Ronald M. Smith, and Burtron H. Davis Natural Gas Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 249 Raub W. Smith and S. Can Gülen Coal and Peat: Global Resources and Future Supply . . . . . . . . . . . 309 Mikael Höök Coal and Other Mining Operations: Role of Sustainability . . . . . . 333 Sandip Chattopadhyay and Devamita Chattopadhyay Coal Preparation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 357 Gerald H. Luttrell and Rick Q. Honaker Coal to Liquids Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 387 Marianna Asaro, Ronald M. Smith, and Burtron H. Davis xi

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CO2 Reduction and Coal-Based Electricity Generation . . . . . . . . . 427 János Beér Pulverized Coal-Fired Boilers and Pollution Control . . . . . . . . . . . 439 David K. Moyeda Mitigation of Airborne Pollutants in Coal Combustion: Use of Simulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 467 Bradley R. Adams CO2 Capture and Sequestration . . . . . . . . . . . . . . . . . . . . . . . . . . . . 503 Abhoyjit S. Bhown, Grant Bromhal, and Gabriel Barki Policy Instruments for Mitigating Carbon Dioxide Emissions . . . . 519 Adam Rose and Brandt Stevens Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 539

Contents

About the Editor-in-Chief

Robert A. Meyers President: RAMTECH Limited Manager, Chemical Process Technology, TRW Inc. Post doctoral Fellow: California Institute of Technology Ph.D. Chemistry, University of California at Los Angeles B.A., Chemistry, California State University, San Diego

Biography Dr. Meyers has worked with more than 20 Nobel laureates during his career and is the originator and serves as Editor in Chief of both the Springer Nature Encyclopedia of Sustainability Science and Technology and the related and supportive Springer Nature Encyclopedia of Complexity and Systems Science.

Education Postdoctoral Fellow: California Institute of Technology Ph.D. in Organic Chemistry, University of California at Los Angeles B.A., Chemistry with minor in Mathematics, California State University, San Diego Dr. Meyers holds more than 20 patents and is the author or Editor in Chief of 12 technical books including the Handbook of Chemicals Production Processes, Handbook of Synfuels Technology, and Handbook of Petroleum Refining Processes now in 4th Edition, and the Handbook of Petrochemicals xiii

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Production Processes, now in its second edition (McGraw-Hill), and the Handbook of Energy Technology and Economics, published by John Wiley & Sons; Coal Structure, published by Academic Press; and Coal Desulfurization as well as the Coal Handbook published by Marcel Dekker. He served as chairman of the Advisory Board for A Guide to Nuclear Power Technology, published by John Wiley & Sons, which won the Association of American Publishers Award as the best book in technology and engineering.

About the Editor-in-Chief

About the Editor

Ripudaman Malhotra completed his Ph.D. in Chemistry in 1979 at the University of Southern California, Los Angeles, CA, and both M.Sc. and B.Sc. in Chemistry in 1973 and 1971, respectively, at Delhi University, India. He was a research chemist at SRI International from 1979 to 2015 (retired), and during his 36-year tenure at SRI, he worked extensively on the chemistry of processing fossil fuels. His detailed mechanistic studies of these systems have resulted in innovative processes that achieve desired product selectivity and increased efficiency. As someone deeply engaged in energy research, he was acutely aware of the looming energy crisis, which was being exacerbated by the potential of global climate change. He broadened his research interests into studying alternate resources such as biomass and application of biotechnology in the areas of energy, chemicals, and the environment. In 2005, he joined Hew Crane and Ed Kinderman to co-author A Cubic Mile of Oil: The Looming Energy Crisis and Options for Averting It, which was published by the Oxford University press in 2010. Among his technical works are 100 papers in archival literature, co-authorship of a book on nitrations, the editing of a book on combinatorial materials development, and co-editorship of a book on advanced materials. He is a section editor of Encyclopedia of Sustainable Science and Technology and an active member of the Energy and Fuels Division of the American Chemical Society. In 2005, he was named an SRI Fellow, the highest award SRI bestows on its employees for excellence in research, and in 2018, he was named a Fellow of the American Chemical Society. He was honored with Storch Award in Fuel Sciences, Energy and Fuels Division, American Chemical Society, in 2015; Glenn Award, Division of Fuel Chemistry, American Chemical Society, in 1991; and Newcomb Cleveland Prize, American Association for the Advancement of Science, in 1987. xv

Contributors

Bradley R. Adams Department of Mechanical Engineering, Brigham Young University, Provo, UT, USA Fred Aminzadeh University of Southern California, USC Viterbi School of Engineering, Los Angeles, CA, USA FACT Inc., Santa Barbara, CA, USA Marianna Asaro SRI International, Menlo Park, CA, USA Gabriel Barki NETL’s Mission Execution and Strategic Analysis Site Support Contract, KeyLogic Systems, Pittsburgh, PA, USA János Beér MIT, Cambridge, MA, USA Abhoyjit S. Bhown Electric Power Research Institute, Palo Alto, CA, USA Grant Bromhal US DOE National Energy Technology Labaratory, Pittsburgh, PA, USA Devamita Chattopadhyay ERG (Eastern Research Group, Inc.), Chantilly, VA, USA Sandip Chattopadhyay Tetra Tech Inc., Cincinnati, OH, USA US Environmental Protection Agency, Office of Pollution Prevention and Toxics, Washington, DC, USA A. Y. Dandekar Institute of Northern Engineering, University of Alaska, Fairbanks, AK, USA Burtron H. Davis Center for Applied Energy Research, University of Kentucky, Lexington, KY, USA S. Can Gülen Bechtel Infrastructure & Power Inc., Reston, VA, USA Mikael Höök Department of Earth Sciences, Uppsala University, Uppsala, Sweden Rick Q. Honaker Department of Mining Engineering, Mining and Mineral Resources Engineering University of Kentucky, Lexington, KY, USA Timothy J. Jacobs Department of Mechanical Engineering, Texas A&M University, College Station, TX, USA xvii

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S. Khataniar Institute of Northern Engineering, University of Alaska, Fairbanks, AK, USA Gerald H. Luttrell Department of Mining and Minerals Engineering, Holden Hall Virginia Polytechnic Institute and State University, Blacksburg, VA, USA Ripudaman Malhotra Malhotra Energy Consultancy, San Carlos, CA, USA Peter J. McCabe School of Earth, Environmental and Biological Sciences, Queensland University of Technology, Brisbane, QLD, Australia David K. Moyeda GE Energy, Irvine, CA, USA Vahur Oja Department of Chemical Engineering, Tallinn University of Technology, Tallinn, Estonia S. L. Patil Institute of Northern Engineering, University of Alaska, Fairbanks, AK, USA Adam Rose Price School of Public Policy, and Faculty Fellow, Schwarzenegger Institute for State and Global Policy, University of Southern California, Los Angeles, CA, USA Raub W. Smith GE Power, Schenectady, NY, USA Ronald M. Smith SRI Consulting, Menlo Park, CA, USA James G. Speight CD&W Inc., Laramie, WY, USA Brandt Stevens BK Stevens Consulting, Sacramento, CA, USA Eric M. Suuberg Division of Engineering, Brown University, Providence, RI, USA

Contributors

Fossil Energy: Introduction Ripudaman Malhotra Malhotra Energy Consultancy, San Carlos, CA, USA

The challenge of achieving a sustainable future is in being able to balance the energy requirements for the billions of people, so they can lead healthy and productive lives against the need to preserve the environment by not running into its limits in its ability to supply the resources or act as a sink for the waste [1]. The collection of chapters in this section examines the current status, assesses the resource potential of the various fossil fuels, examines the technologies for using them, and reviews the environmental impact of their use. Petroleum and natural gas have similar origin and often occur together in geologic formations, and their global distribution and production is discussed together in the chapter by McCabe (▶ “Oil and Natural Gas: Global Resources”). This chapter makes clear the distinction between reserves and resources. Reserves represent only that fraction of the resource base that can be economically recovered using current technology. These are not fixed quantities as both technology and economics change over time. Global annual production (and consumption) of oil in 2010 was 31 billion barrels and of natural gas was around 120 trillion cubic feet. In energy units, they correspond to 180 EJ of oil and 120 EJ of natural gas [2]. The current reserves are estimated at 1,236 billion barrels of conventional oil (7,500 EJ) and 6,545 tcf of natural gas (6,500 EJ). The current reserves to production ratio (R/P) are about 40 for oil and about 55 for natural gas. The R/P ratio has often been mistakenly taken as the time to exhaustion, but new discoveries as well as advances in technology add to the reserves. In the case of oil, for example, the R/P ratio has stayed around

40–50 years or more than 60 years even with the steadily increasing oil consumption. In addition, there are also unconventional accumulations of these hydrocarbon resources, and extracting them requires development of new technologies. In the case of oil, the unconventional resources are oil sands, oil shale, and heavy oil. Unconventional resources of natural gas are coal bed methane, tight gas, shale gas, and gas hydrates. These unconventional resources are vast and have the potential of more than doubling our resource endowment. Exploration and production of oil from sedimentary deposits and oil sands is the subject of a chapter by Speight (▶ “Petroleum and Oil Sand Exploration and Production”). The processes for recovering oil could be a simple matter of drilling into the formation with the oil flowing to the surface under its own pressure, or it may require injection of gases, fluids, and surfactants to coax it to flow. In extreme cases, it may even require underground combustion of a portion of the resource to release the oil. Speight describes the chemical and physical factors that govern the flow of oil and the technology options currently available. In a different chapter, Speight (▶ “Petroleum Refining and Environmental Control and Environmental Effects”) provides an account of the different processes such as distillation, catalytic cracking, hydrotreating, reforming, and deasphalting used in the refining of crude oil. The chapter also deals with environmental effects of the gaseous, liquid, and solid effluents from these processes. Production of oil from shale is principally achieved by retorting of shale, or other thermal processes including in situ pyrolysis. Oja and Suuberg (▶ “Oil Shale Processing, Chemistry, and Technology”) detail the chemistry and technology of these processes in the chapter. A new chapter by Aminzadeh (▶ “Hydraulic Fracturing”) makes a clear distinction between oil shale and shale oil. The former is the rock-bearing precursors to oil, kerogen, and requires thermal processing to generate oil, while the latter is oil (or gas) that has already been produced by

© Springer Science+Business Media, LLC, part of Springer Nature 2020 R. Malhotra (ed.), Fossil Energy, https://doi.org/10.1007/978-1-4939-9763-3_920 Originally published in R. A. Meyers (ed.), Encyclopedia of Sustainability Science and Technology, © Springer Science+Business Media, LLC, part of Springer Nature 2019, https://doi.org/10.1007/978-1-4939-2493-6_920-4

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geologic forces but it is trapped in low permeability shale. The chapter describes the recent developments in hydraulic fracturing and its impact on the geopolitics. Gas hydrates represent a particularly noteworthy resource and are reviewed in the chapter by Patil et al. (▶ “Alaska Gas Hydrate Research and Field Studies”). They are naturally occurring icelike substances in which methane or other light gases are trapped in the cage structures formed by water molecules. They are stable under certain conditions of temperature and pressure, and can be found at many places around the world at depths of several hundred meters below the seabed and in the permafrost in the polar region. Global estimates of gas hydrates are on the order of 500,000 tcf, about a hundred times the proved reserves of natural gas. Apart from being a potentially very important source for energy in the future, the gas hydrates are also important from the perspective of climate change. A general warming could release substantial amounts of methane, which – being a potent greenhouse gas – would reinforce any global warming. Oil remains the prized fuel. It has a high energy density and as a liquid it is well suited for transportation. The transportation sector relies on oil for over 90% of its energy needs (the remainder being mostly furnished by coal – via electricity) [3]. Given the importance of liquid fuels, there is considerable interest in converting coal and natural gas, the other hydrocarbon resources, into oil. In a pair of chapters, Asaro, Smith and Davis (▶ “Gas to Liquid Technologies” and ▶ “Coal to Liquids Technologies”) provide an overview of the various processes for converting natural gas and coal to liquids. For the second edition, these chapters were revised by Davis, and these reviews cover the basic chemistry and catalytic technologies behind the different approaches. The chapter on ▶ “Gas to Liquid Technologies” deals with steam reforming of methane, autothermal reforming, and partial oxidation approaches for producing syngas, including strategies for managing the heat and mass transfer through the use of different reactor technologies. The chapter next covers the conversion of syngas into liquids by Fischer-Tropsch (FT) synthesis. The chapter on

Fossil Energy: Introduction

▶ “Coal to Liquids Technologies” reviews the different approaches like pyrolysis, direct liquefaction, co-processing with petroleum, and indirect liquefaction that first converts coal into syngas and then uses FT or other conversion process to make liquid fuels. The internal combustion engines that power these vehicles covert only about 20–30% of the energy in the fuel to motive power. Increasing the efficiency of the engines used in transportation represents a significant opportunity to reduce future demand for oil, as well as reduce the carbon footprint of the cars, trucks, and planes. Jacobs (chapter ▶ “Internal Combustion Engines, Developments in”) provides a detailed account of the thermodynamics of the different kinds of engines and of the various technologies under development for improving the efficiency of the internal combustion engines. These include strategies such as engine downsizing, turbocharging, better controls, variable geometry engines, variable valve timing, homogeneous charge compression engines, and waste heat recovery. Höök (chapter ▶ “Coal and Peat: Global Resources and Future Supply”) reviews the global coal and peat resources, which are substantially larger than conventional oil and gas resources. Peat and coal are also distributed more evenly around the globe. The proved reserves of coal are estimated at between 800 billion and a trillion metric tons, representing roughly 20,000 EJ. Most coal is derived from trees and ferns that grew some 250–300 million years ago during the carboniferous period. Aerobic bacteria generally decompose most plant matter into CO2, but when a tree fell into a swamp and was buried with limited exposure to oxygen, it could be partially preserved. That phenomenon occurs even today and is evidenced in the formation of peat (very young coal) in bogs. Unlike coal, peat has a low calorific content and its commercial use as an energy resource is limited. However, peat is important from global carbon cycle. Peat bogs store vast amounts of carbon, but the product of anaerobic decomposition, methane, contributes to greenhouse gases in the atmosphere such that under steady-state conditions they comprise only a slight sink of carbon. The situation changes with

Fossil Energy: Introduction

fires as peat bogs become major source of carbon in the atmosphere. Human activities, such as drainage of the area for agriculture, exacerbate the situation, as more peat gets exposed and the swamp is not wet enough to squelch the fire. Estimates of the amounts of carbon released from peat are on the order of several billion tons, the same order of magnitude as from fuels used in transportation or power production. As coal resources are vast, they are likely to continue to contribute substantially to global energy mix. However, their use also presents a number of challenges, beginning with mining, and through coal preparation and use. Mining operations result in excavation of billions of tons of earth, and depending on the nature of the waste rock and how it is handled, it can lead to contamination of air, water, and soil systems. The wideranging nature of environmental impact necessitates a commensurately broad portfolio of technologies for the remediation, restoration, and reclamation. Chattopadhyay and Chattopadhyay (chapter ▶ “Coal and Other Mining Operations: Role of Sustainability”) provide an overview of the environmental impact of coal mining, and mining processes in general, as well as review the range of the chemical and biochemical strategies to mitigate the impact. The run-of-mine coal is often laden with noncombustible minerals such as shale and clays that reduce its heating value. Cleaning and washing of coals removes many of these impurities and upgrades the coal into a marketable resource, improves the performance of power plants, and also reduces potential harmful emissions and dust. Luttrell and Honaker (chapter ▶ “Coal Preparation”) review these cleaning and preparation operations, and point out the importance of cheap preparation in extending the resource base. Electricity is one of the most useful forms of energy; its importance to the way we live cannot be overemphasized. It can be used to perform all kinds of useful functions and services that people desire, and at the point of use, it produces no pollution. Electricity is a secondary source of energy, as it must be produced from primary sources such as coal, natural gas, oil, nuclear, hydro, and, of late, increasingly from wind and

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solar. In 2010, the global production of energy was 21,325 trillion kWh, which is equivalent to 77 EJ. However, since 68% of electricity is derived from burning fossil fuels at an average efficiency of 38%, the total primary energy the world consumed as electricity amounts to 135 EJ, or roughly 27% of the total energy consumed. Electricity demand in the world is projected to rise at a rate greater than for total energy, and meeting that need for additional sources for producing electricity is critical human welfare. Several chapters in this section are devoted to production of electrical power. As the fuel with the lowest levelized cost of electricity, coal remains the dominant fuel for producing electricity, and furnishes over half of the electricity. It results in the emission of about 900 g CO2 per kWh, highest of any fossil resource. The development of coal power in future is going to be constrained by the concerns of CO2 emissions, and Beér (chapter ▶ “CO2 Reduction and CoalBased Electricity Generation”) discusses the different technology options for increasing the efficiency of coal-fired power plants and reducing the CO2 emissions. Ultrasupercritical steam cycles and combined heat and power applications are relatively straightforward to apply and have the potential to reduce the largest tonnage of emissions. Of course, there are other pollutants also that are emitted when coal is used for power productions. Chief among them are oxides of sulfur and nitrogen and toxic metals such as mercury, selenium, and arsenic, as well as carcinogenic PAHcontaining soot aerosols. Moyeda (chapter ▶ “Pulverized Coal-Fired Boilers and Pollution Control”) reviews the technologies for scrubbing the stack gas emissions. The deployment of scrubbers for the nitrogen and sulfur oxides, following the Clean Air and Water Act in the 1980s, greatly improved the quality of air and water systems. Natural gas is the other major fuel for producing electric power. When used in a gas-fired combined-cycle mode, it produces only 380 g CO2/kWh. Smith and Gülen (chapter ▶ “Natural Gas Power”) review the technology for power generation from natural gas. They discuss the different sources of natural gas and provide a

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brief history followed by detailed thermodynamics of gas turbines and modern power plants designs that incorporate combined cycle for maximum overall efficiency. They also review emissions from NGCC plants, notably NOx, and strategies for minimizing them. The chapter concludes with a discussion of power plant economics. In a new chapter, the use of process simulation in mitigating pollution emissions is reviewed by Adams (▶ “Mitigation of Airborne Pollutants in Coal Combustion: Use of Simulation”). Carbon capture and sequestration (CCS) as a strategy for stabilizing atmospheric CO2 levels is receiving considerable attention. Friedman’s chapter in the first edition has been revised by Bhown, Bromhal, and Barki (▶ “CO2 Capture and Sequestration”); it provides an overview of the state of technology and the different embodiments of CCS. These cover various strategies for first capturing the CO2, which may be performed pre- or post-combustion or from the atmosphere, as well as discuss the energy requirements under these different scenarios. The chapter also reviews the geochemistry of various options for sequestering the captured CO2, either in deep saline aquifers or in other geological formations. In another new chapter, Rose and Stevens (▶ “Policy Instruments for Mitigating Carbon Dioxide Emissions”) present policy options such as carbon pricing and cap-and-trade that can be employed for reducing emissions of carbon dioxide. The Fossil Energy section of the Second Edition of the Encyclopedia of Sustainable Science and Technology has been thoroughly revised. Some salient changes include the following: 1. Reserves and resources of different fossil fuels have been updated to reflect current status.

Fossil Energy: Introduction

2. A new chapter by Amizadeh on recovery of oil and gas from tight resources through hydraulic fracture of shale has been added. 3. A clear distinction between oil shale and shale oil. The former is the rock-bearing precursors to oil, kerogen, and requires thermal processing to generate oil, while the latter is oil (or gas) that has already been produced by geologic forces but it is trapped in low permeability shale. 4. Commercial developments in the coal-to-gas and coal-to-liquid processes have been updated. 5. The chapter on mining has been updated to describe how to maximize the benefits of mining sector while improving the environmental and social sustainability. 6. Technological advances and commercial developments in carbon capture and sequestration have been added. 7. A new chapter has been added to describe the use of process simulation to mitigating airborne pollutants formed during coal combustion. 8. A new chapter has been added to describe policy options for mitigating CO2 emissions.

Bibliography 1. Meadows D, Randers J, Meadows D (2004) Limits to growth, the 30-year update. Chelsea Green Publishing, Hartford 2. BP Magazine (2011) BP statistical review of world energy, June 2011. www.BP.com 3. Energy Information Administration (2010) Annual energy review. http://www.eia.gov/emeu/aer/pecss_dia gram.html

Oil and Natural Gas: Global Resources Peter J. McCabe School of Earth, Environmental and Biological Sciences, Queensland University of Technology, Brisbane, QLD, Australia

Article Outline Glossary Definition of the Subject Introduction Oil and Gas in Conventional Fields Tight Gas Oil Sands Coal Bed Methane Oil Shale and Shale Oil Shale Gas Gas Hydrates Estimated Volumes of Remaining Oil and Gas Resources Future Directions Bibliography

Oil sands Sandstones that are naturally impregnated with bitumen, a highly viscous form of petroleum. Synonymous with bituminous sands and tar sands. Oil shale A rock that contains significant amounts of solid organic chemical compounds (kerogen) that can generate oil when heated. Reserves The discovered, but not yet produced, amounts of oil or gas that could be extracted profitably with existing technology under present economic conditions. Resources The amounts of oil and gas that have been discovered plus the estimated amount that remains to be discovered. Shale gas Natural gas that is produced from shale. Tight gas Natural gas that is extracted from rocks with very low porosity and permeability and which is, therefore, relatively difficult to produce. Unconventional oil and gas Oil and natural gas accumulations that require extraction techniques that allow easier flow of oil and gas to a well (for example, hydraulic fracturing to open pathways or in situ heating to reduce viscosity) or by processing after mining.

Glossary Definition of the Subject Coal bed methane (CBM) Natural gas (methane) that can be extracted from coal beds. Synonymous with coal bed gas and coal seam gas (CSG). Conventional oil and gas Oil and natural gas that occur in the subsurface and that can be produced using conventional methods of well drilling. Gas hydrates Accumulations of natural gas that are trapped in ice-like crystalline solids consisting of gas molecules surrounded by cages of water molecules. Hydrates are stable at certain temperatures and pressures within some sea-floor sediments and within permafrost in polar regions. Synonymous with gas clathrates.

Crude oil and natural gas (mostly methane but including some longer-chain hydrocarbons) have been used by humans for thousands of years for a variety of purposes including lighting, heating, and medicinal uses. However, use was limited by access to natural seeps of oil and gas and the available technologies to extract and store the products. The earliest known oil wells were drilled in China in the fourth century using bamboo. It was not, however, until the mid-nineteenth century that large-scale production began, when metal piping allowed deeper drilling into hard rock. Early commercial production began in Poland and Romania and this was followed rapidly

© Springer Science+Business Media, LLC 2012 R. Malhotra (ed.), Fossil Energy, https://doi.org/10.1007/978-1-4939-9763-3_71 Originally published in R. A. Meyers (ed.), Encyclopedia of Sustainability Science and Technology, © Springer Science+Business Media LLC, 2012 https://doi.org/10.1007/978-1-4419-0851-3_71

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Oil and Natural Gas: Global Resources

by drilling successes in the Russian Empire, in what is now Azerbaijan, and in the United States. Development of the process of fractional distillation at this time fuelled the demand for crude oil, which could now be economically refined into kerosene for use in oil lamps. The development of the internal combustion engine also created a demand for oil and this greatly expanded with Karl Benz’s invention of the gasoline-powered automobile, patented in 1886. The transport sector became the dominant user of oil and currently accounts for 61.4% of oil consumption [1]. Other major uses include lubrication, chemical feedstock, and domestic heating. Production has risen dramatically over the last century (Fig. 1) and production of crude oil today is approximately 73 million barrels per day (a “barrel” is 42 US gallons). The United States dominated world oil production for the first half of the twentieth century, accounting for over 50% of the world’s annual production until 1960. After World War II demand for oil increased at a rapid rate and production increased fivefold between 1950 and 1972. As the world economy rapidly grew, international trade in oil was facilitated by the development of supertankers. The dominance of the United States decreased as several other regions increased their

share of production, particularly the Middle East and the Soviet Union. The Organization of the Petroleum Exporting Countries (OPEC) was formed in 1960 and by 1972 was responsible for over 50% of the world’s oil production. The cartel restricted the supply of oil during the 1970s, resulting in a fivefold increase in prices. The resulting fall in demand and oversupply led to a price collapse in the early 1980s. OPEC has subsequently never exceeded 42% of world production [2] but the rapid economic expansion of many countries in the first decade of the twenty-first century resulted in relatively high prices again as demand increased substantially. Today 60% of the world’s oil production is from six countries, of which five belong to OPEC (Table 1). Although natural gas had long been used in limited amounts for illumination, much of the natural gas that was originally discovered in association with oil was vented or flared because there was no way of commercializing the gas. Reliable pipelines to transport gas were not developed until after World War II. Natural gas is now used primarily for electrical generation in power plants, domestic heating, manufacturing fertilizers, and for other industrial purposes. World production of natural gas grew steadily in the 30 years after World War II, though at a slower rate than oil production.

200 180 160 Oil

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Oil and Natural Gas: Global Resources, Fig. 1 World production of crude oil and natural gas since World War II expressed in units of energy for comparative purposes. (Based on EIA data [2])

Oil and Natural Gas: Global Resources

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Oil and Natural Gas: Global Resources, Table 1 Major producers of crude oil. (From [1]) Country Russia Saudi Arabia USA Iran China Canada Mexico Venezuela Kuwait U.A.E. Rest of world

% of world total 12.9 11.8 8.3 5.4 5.0 4.0 3.8 3.3 3.2 3.1 39.2

public and private transport systems, are all heavily dependent on oil and natural gas: they fuel over 96% of the transport sector. On the negative side they are a major source of CO2 emissions, though cleaner than coal per unit of power generated. The successful development of cleaner and economically viable alternative fuels is essential in the long run but the world’s economy today is heavily dependent on the supply of oil and natural gas. This raises the question as to how much oil and natural gas remain in the ground. How long will oil and gas resources be available for mankind?

Introduction Oil and Natural Gas: Global Resources, Table 2 Major producers of natural gas. (From [1]) Country USA Russia Canada Iran Norway China Qatar Algeria Netherlands Indonesia Rest of world

% of world total 19.2 19.0 5.1 4.6 3.4 2.9 2.9 2.6 2.5 2.5 35.3

Production was dominated by the United States, which produced over 50% of the world’s annual production until 1973. Since the early 1970s world gas production has risen at a similar rate to oil production (Fig. 1). While the market for natural gas was once limited to the reach of pipelines, natural gas can now be transported globally using liquefied natural gas (LNG) tankers. This requires removal of impurities and cooling of the gas to approximately – 160  C. LNG now accounts for 6% of the global market. Today ten countries produce 65% of the world’s natural gas (Table 2). Together oil and natural gas currently comprise 54.3% of the world’s total annual consumption of energy and, as such, are a major foundation of the global economy. In particular, the transportation of food, raw materials, and goods to market, as well as

Predictions of future shortages of oil began shortly after commercial production started in the late nineteenth century. In the first half of the twentieth century, there was national concern about imminent and irreversible shortages of oil on at least six occasions [3]. In the 1950s M. King Hubbert, a geophysicist at Shell Development Company in Houston, developed a model of a cycle of production of finite nonrenewable resources that aimed to predict future production from analysis of production-to-date and estimates of the amount of remaining resource in the ground [4, 5]. In a series of publications Hubbert predicted that US oil production would peak by 1975 at the latest: actual peak production was in 1970. The peak in US production gave credence to Hubbert’s methodology, which is now commonly referred to as the “Hubbert curve” [6]. Fears arose of global depletion of fossil energy resources. In 1972 a report for the Club of Rome, a global think tank, examined known reserves of oil and gas and predicted the time of total depletion under various scenarios [7]. Assuming exponential growth in consumption, the report predicted depletion of known reserves of oil by 1992 and natural gas by 1994. Even under what was considered an optimistic scenario wherein reserves could be increased fivefold by new exploration, oil was predicted to be totally depleted by 2022 and gas by 2021. These predictions, though influential at the time, proved unfounded largely because consumption did not increase at an exponential rate.

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In 1962 Hubbert predicted that world oil production would peak in 2000 and, again, in 1969 predicted the peak would be between 1990 and 2000 [5]. As the turning point of the millennium approached predictions of “peak oil” increased. Most of the predictions suggested a peak in the first years of the twenty-first century. For example, in 1988 Campbell, using the Hubbert curve analysis, predicted a peak between 2000 and 2005 [8]. Actual production between 2006 and 2010 has been 4.7% higher than in the previous 5 years (Fig. 1). However, predictions of imminent “peak oil” persist and proponents point out that production has been relatively level for the last 6 years (to 2010). Others point to global political and economic reasons for the recent relatively flat production rate. The basic problem with the Hubbert curve analysis is that estimates of remaining resources change through time. The amount of oil and gas on the planet is undoubtedly finite. The amount is large but much of it would be prohibitively expensive to produce using present-day technologies. Resource estimates therefore tend to focus on oil and gas accumulations that are anticipated to be economically viable for production, either at present or within the foreseeable future. Advances in technology, however, may make accumulations technically accessible at lower costs over time, thus increasing the size of estimated remaining resources. In addition, advances in geologic concepts and subsurface imaging through geophysical techniques have shown oil and gas resources to be substantially more extensive than was at one time thought. As a result, many predictions using the Hubbert curve analysis have been far less successful than Hubbert’s prediction of US peak production. Hubbert [5] in 1962, for example, predicted US natural gas production would peak in 1975 but production in 2010 was at an all time high. Another example is Campbell’s 1988 prediction [8] that underestimated US oil production in 2010 by 70%. The following sections describe the various types of geologic occurrence of oil and gas and how scientific and technological advances have changed the perception of the size and economic viability of the resources over the last few

Oil and Natural Gas: Global Resources

decades. Oil and gas resources are often divided into conventional or unconventional resources. The definition of what is conventional varies between authors but generally refers to those resources that can be produced using longestablished methods of well-drilling where the oil and gas can be brought to the surface under its own pressure or by pumping without significant stimulation such as in situ fracturing of the host rock. Unconventional resources, by contrast, require more complex methods of extraction of the resource from the host rock. They include tight gas, oil sands, coal bed methane (CBM), shale gas, shale oil, and gas hydrates.

Oil and Gas in Conventional Fields Oil and gas is generated from organic-rich rocks by thermogenic or biogenic processes. When such “source rocks” are exposed over periods of geologic time to high temperatures the organic material breaks down releasing oil and gas that then migrate toward the surface due to buoyancy. The temperature required for thermal maturation of a source rock varies depending on the type of organic material but the minimum temperature for oil generation is approximately 50  C and for gas generation is 100  C. Most thermogenic oil and gas are generated at depths of 2–6 km. Methane may also be produced from source rocks by the biogenic breakdown of organic material in source rocks. Such biogenic gas is produced at lower temperatures and at shallower depths. Whether of thermogenic or biogenic origin, oil and gas can be trapped by buoyancy in “reservoirs” in porous rocks beneath an impermeable layer of rock typically at depths of over 1 km. The permeable nature of the host rock, high pressures related to depth of burial, and the concentration of oil and gas in discrete reservoirs allow relatively easy extraction of oil and gas by drilling wells. Until the 1990s almost all the world’s oil and gas production was produced from such “conventional” fields. Natural gas in conventional fields may occur with (“associated gas”) or without (“nonassociated gas”) oil. In either case the gas may contain compounds that can be separated at

Oil and Natural Gas: Global Resources

the surface as liquids. Natural gas liquids (NGLs) such as propane, butane, and pentane are sometimes included in reporting oil production but are not insignificant: they comprise, for example, 3.5% of the total energy production of the United States. Estimates of the world’s original endowment of conventional oil and gas resources have tended to increase because of the advances in technology over time [9]. Advances in geologic concepts, drilling technologies, seismic imaging, and computer modeling using large datasets have progressively revolutionized the search for oil and gas over the last century. Likewise, advances in production technologies, pipeline construction, and tankers have all made resources available that at one time would have been considered economically unviable. Advances in science and technology allow more oil and gas to be found in old fields, within existing petroleum provinces, and in new frontier regions. Existing oil and gas fields that have already been in production for years may, at first blush, seem unusual sites to look for further reserves. However, the US Geological Survey (USGS) in 2000 estimated that 48% of the oil and 41% of the natural gas that remains to be added to reserves in the future lie within existing fields [10]. Increases in successive estimates of the estimated recoverable oil and gas are known as “reserve growth” On average, only 22% of the oil is currently recovered from fields worldwide [11]. There are many reasons for such a low percentage. Much of the oil within a reservoir rock will not easily move toward wells. Enhanced recovery methods such as gas reinjection, water-flooding, and flushing with polymers and surfactants can free up more of the oil. While such secondary and tertiary recovery methods are commonly used in mature oil fields in developed countries, they are not yet widely used in many other regions. Another reason for reserve growth is that there is rarely a single reservoir within an oil or gas field as most are split into numerous compartments, each containing amounts of oil/gas in varying amounts. Advances in seismic imaging over the last 20 years have allowed not only good visualization of these compartments but also the fluids within

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the compartments. At the same time, technological advances allow drilling with much greater precision permitting access to much smaller subsurface targets over time. While it will never be possible to economically drain all the oil and gas out of a field, recovery rates of over 70% may eventually be feasible in many areas [12]. Much oil and natural gas also remains to be found in undiscovered fields within existing petroleum provinces. The largest fields tend to be discovered early in the exploration history of a basin and progressively smaller ones are found over time. The infrastructure that is built to develop the larger fields allows fields to be developed that would otherwise be too small to justify the construction of pipelines, platforms, ports, and processing facilities. By analogy estimates can be made of the number and size of remaining undiscovered fields from the discovery history of a petroleum province. This methodology may underestimate the total resource if more than one type of oil and gas accumulation is present. For example, the discovery of giant oil and gas fields in the subsalt regions in offshore regions of the Gulf of Mexico added a new “play” in what was thought to be a mature oil province. There is a strong possibility that further major accumulations of conventional oil and gas will also be found in frontier basins where little or no exploration has taken place. Most of the potential areas are in regions of deepwater or harsh climates. Over time technological advances have made exploration feasible in areas once thought inaccessible. This has been particularly true in the ability to drill to deeper depths. In 1960 any drilling in water depths over 20 m was regarded as “deepwater” but by 1980 oil fields had been found in over 300 m water depth, by 1990 in over 850 m water depth, and by 2010 in over 2400 m water depth [13]. Total drilling depths also increased dramatically with a record set in 2009 with the discovery of the giant Tiber oil field in the Gulf of Mexico which is at 1200 m water depth, with a total drilling depth of 10,680 m. In the last decade giant oil fields have been found in ultra-deepwater areas not only in the Gulf of Mexico but also offshore West Africa and Brazil. The giant Brazilian Tupi field lies not only in deepwater

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(>2000 m) but also below a 2000 m thick layer of salt. It is only recently that seismic technology has allowed an understanding of the structures below thick salts and drilling technologies have permitted drilling through such strata. As in the past, technological advances will permit exploration for oil and gas in frontier regions currently regarded as inaccessible. Future exploration in deepwater will likely lead to more significant discoveries. Outside the Atlantic realm other regions with potential for deepwater exploration include offshore East Africa, the Great Australian Bight, and offshore New Zealand. There is a growing interest in the potential of the Arctic region where geologists believe there are substantial oil and gas resources but where the severe climate, ice floes, and icebergs all make exploration and development hazardous and in many areas either prohibitively expensive or impossible using currently available technologies [14].

Tight Gas In conventional fields gas moves easily through the permeable host rock and naturally moves toward wells and up to the surface because of pressure differences. By contrast, sandstones that have very low permeability require considerably more effort to produce the gas. These sandstones are generally thinner than those in conventional fields and have been buried to great depth. The pores in the sandstone, in which the gas is trapped, have been reduced in size by compaction and cementation during burial. These “tight sands” typically occur near the center of sedimentary basins and are sometimes referred to as “basincentered gas” accumulations. Production of gas from tight sands requires extensive and complex drilling. Because each well produces relatively small volumes of natural gas, many wells must be drilled. Hydraulic fracturing of the host rock can increase the rate of flow of gas to a well. Although basin-centered gas accumulations can occur over very wide geographic areas, production is generally from limited regions of a basin. The geologic nature of these so-called

Oil and Natural Gas: Global Resources

“sweet spots” is debated as to whether they are regions with enhanced permeability created by natural fractures in the rock or are buoyancy traps similar to conventional gas fields [15]. Resource estimates of basin-centered gas are typically very large but in some cases may be reevaluated as geologists develop a better understanding of the nature of sweet spots. Nevertheless, tight gas is undoubtedly a major resource and, historically, it has been the most important component of unconventional gas production in North America but relatively few tight gas fields have yet been developed outside of North America. Production has risen from 10% of total natural gas production in the United States in 1990 to 28% in 2009 [2, 16]. Given the magnitude and widespread nature of these accumulations in North America it seems likely that tight gas resources occur in many sedimentary basins worldwide. Exploration and development of such resources must compete with conventional gas resources that are much cheaper to produce, and which in many cases may lie at shallower depths within the same sedimentary basin. However, it is probably only a matter of time before tight gas resources are developed in many regions of the world.

Oil Sands Oil sands are rocks that consist predominantly of sandstones which contain bitumen within the pore spaces that has been produced by the biodegradation of oils in the subsurface. Most oil reservoirs are sufficiently hot that biogenic activity is curtailed or absent. However, oil that migrates into shallow reservoir rocks may be altered completely to bitumen that is very viscous. Although found close to the surface, production of oil from oil sands is expensive. The bitumen must be heated before it will flow and commercial extraction requires large amounts of energy. Once extracted the bitumen must also be upgraded by purification and hydrogenation before it can be refined like conventional crude oil. Although oil sands have long been recognized and used in limited ways, it is only within the last

Oil and Natural Gas: Global Resources

40 years that commercial production has grown. Canadian oil sands production began in 1967 and production has grown steadily. By 2009 production from oil sands was equivalent to over 550 million barrels of oil, accounting for 49% of Canada’s oil production in 2009 [17]. Though production was initially subsidized, production costs have fallen with technological advances and is now economically viable at $50/barrel and production is forecast to more than triple by 2025 [18]. Venezuela also has substantial oil sand deposits [19] and smaller accumulations are known in Russia and the Middle East.

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CBM occurs at much shallower depths than most conventional gas fields: generally less than 900 m. Extraction of CBM, however, requires many closely spaced wells: over 20,000 wells had been drilled in the Powder River Basin [21] and over 17,000 in Alberta [22]. The gas is adsorbed onto the pore space in coals and must be released by depressurization, allowing the gas to flow toward the well along natural fractures known as “cleats” or by pathways produced by artificial hydraulic fracturing.

Oil Shale and Shale Oil Coal Bed Methane The presence of methane in coal beds had long been a hazard for underground coal mining and it is only recently that this gas has been seen as an economic resource. Modern mining techniques aimed at mitigating the potential for lethal buildup of methane in mines extracts the gas during or before mining as coal mine methane (CMM), which in some cases is used for power generation. More significant from an energy resource perspective is the natural gas extracted from coal beds by wells in regions where no mining is planned: this is known as coal bed methane (CBM) or coal seam gas (CSG). Commercial production of CBM began in the United States in 1989 and annual production had grown to almost 2 trillion cubic feet (TCF) in 2009, which was 8% of total US gas production [2]. Early production was predominantly from bituminous coals in the San Juan and Raton Basins of New Mexico and Colorado. Production from these areas still accounts for almost 50% of US production. In 2000 production began from the lower-rank subbituminous and lignite coals of the Powder River Basin in Wyoming which by 2010 comprised 28% of US CBM production. Over the last decade, the technology and knowhow for CBM extraction has spread from the United States to other major coal-bearing regions, particularly Canada, Australia, China, and parts of Europe. Australia plans to export CBM gas as LNG [20].

Oil can be produced from some organic-rich finegrained rocks that are normally referred to as “shales” even if the host rock is not strictly a shale by a geologic definition. Production from such sources has a long history. Production of oil from shales for illumination preceded the discovery of conventional petroleum resources in the mid-nineteenth century but for most of the twentieth century production of such oil was a very minor component of global petroleum production. However, in the first decade of the twenty-first century there has been a resurgence of interest in these resources because of advances in technology and rising energy prices. “Oil shales” are rocks that contain significant amounts of solid organic chemical compounds (kerogen) that have not been buried deeply enough to allow for oil maturation. Production is generally done by mining the rock and heating it in a retort in a processing plant close to the mine where the oil and associated gases can be captured. The oil may also be extracted using in situ methods which require heating the subsurface rock by injection of hot fluids, gases, or steam, or by the use of heating elements. As the oil is expelled from the kerogen it can then be induced to flow toward conventional oil wells for extraction. The leading producer of oil shale in the world is Estonia, where 90% of the power is generated from that source. By far the largest accumulations of oil shale, however, are in the United States, particularly in the Green River Formation of

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Colorado, Utah, and Wyoming, that were deposited within ancient saline lake systems some 40–50 million years ago. There are also major accumulations in Devonian–Mississippian black shales in the eastern United States that were deposited in marine environments over 350 million years ago. With the high oil prices of the late 1970s a number of pilot projects produced oil from the Green River Formation in Colorado but plans for major commercial exploitation were abandoned when prices fell in the early 1980s. Interest in the potential for production has been rekindled with the high oil prices in recent years. Other countries with significant oil shale accumulations include Australia, Brazil, the Democratic Republic of the Congo, and Russia [23]. “Shale oil” is oil that is trapped within a finegrained rock. Extraction of the oil does not require heating but the low permeability of the rocks requires that the rock be artificially fractured in situ to allow flow toward a well. Once regarded only of scientific interest, recent advances in hydraulic fracturing have made shale oil economically viable in some areas. The best known shale oil accumulation is the Bakken Formation of the Williston Basin of Montana and North Dakota and adjoining parts of Canada [24]. From a geologic perspective, the Bakken is a petroleum source rock that reached maturation but, unlike most mature source rocks, the oil was never expelled to migrate to conventional traps.

Shale Gas Natural gas is present in some organic-rich mudrocks. Shale gas has been produced in small quantities for well over a century but recent advances in technology allow much higher rates of production. Shale beds are relatively thin and vertical wells provide access to a very limited volume of rock. It is now possible to drill at any angle and to deviate wells at depth to follow individual shale beds over great distances, allowing access to large volumes of gas-bearing shale. While production used to be primarily from naturally fractured shales, much recent production from shales is aided by hydraulic fracturing

Oil and Natural Gas: Global Resources

technologies. The fractures provide avenues for gas migration toward the wells. The new technologies for shale gas production have revolutionized US gas production. Shale gas production was approximately 1% of total US production in 2000 but had risen to 14% of total production in 2009 and is forecast to be 45% of production by 2035 [2]. The potential of shale gas has been questioned by some [25]. Like tight gas, production is from sweet spots whose nature and lateral extent remains to be better defined. The dramatic rise in US production has, however, spurred interest in shale gas in many other parts of the world, especially in Canada, Central Europe, China, India, and Australia.

Gas Hydrates Gas hydrates (also called clathrates) are solid icelike substances consisting of rigid cages of water molecules that enclose molecules of gas – mainly methane. Hydrates are stable in a restricted range of temperatures and pressures and occur in two regions: in polar regions, where they are associated with permafrost, and at shallow depths in sediment on the outer continental shelves, in water depths over 300 m [26]. Hydrates can pose an environmental problem because natural breakdown of accumulations can result in slumping of the seabed and outgassing of methane to the atmosphere. On the other hand, if appropriate technologies are developed, hydrates may be a future source of natural gas. Current technologies allow production only at costs substantially above the market prices that have prevailed over the last decade [27]. Production would require depressurization, thermal stimulation, or injection of inhibitors to destabilize the hydrate lattices, releasing the methane to flow toward wells.

Estimated Volumes of Remaining Oil and Gas Resources Proved reserves are the volume of known oil and gas accumulations that can be produced at a profit under existing economic and operating conditions.

Oil and Natural Gas: Global Resources

Estimates of world-proved reserves of oil and gas are compiled using best available information by several organizations including the International Energy Agency, IHS Energy, and BP. Proved reserves of oil and gas are not routinely reported in many countries. In fact, some of the largest producers consider reserves as state secrets. This lack of transparent reporting has led some to question the size of global reserves giving credence to predictions of imminent production declines [28]. However, though differing in detail the reserves estimated by different agencies are similar in estimated overall size. As of the end of 2009, BP [29] estimated globally proved reserves of 1333 billion barrels of oil (BBO), equivalent to over 45 years of production at 2009 rates. With the exception of 237 billion barrels of oil in the Canadian oil sands, these reserves are entirely of conventional oil. BP also estimated globally proved reserves of natural gas at 6621 trillion cubic feet (TCF), equivalent to 63 years of production. These reserves are predominantly conventional gas. In addition to proved reserves, there are undiscovered resources and “contingent resources” that are currently noncommercial but could probably be produced under different economic conditions. The most recent comprehensive global estimate of undiscovered oil and gas resources was published by the USGS in 2000 [10]. This was a geologically based study of 128 geologic provinces that included the producing basins that accounted for more than 95% of the world’s known oil and gas outside of the United States. The study also examined the discovery history of each province up to 1996. The report included probabilistic estimates of the volumes of conventional oil, gas, and natural gas liquids that might be added to proved reserves from new field discoveries in the studied provinces from the 1996 baseline. The assessment estimated that there was a 95% chance of discovering another 334 BBO of conventional oil and a 5% chance of discovering 1107 BBO. The median estimate, the 50% chance, was that 607 BBO of oil might yet be found in the studied provinces. For conventional natural gas, the assessment estimated that there was a 95% chance of discovering another 2299 TCF and a 5% chance of

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discovering 8174 TCF. The median estimate was that 4333 of natural gas might be found in the studied provinces. More recent estimates by the USGS that have concentrated on specific regions of the world suggest that on balance their 2000 estimates are probably reasonable estimates of the global picture though there is need for revision in some areas. A 2010 study [30] estimates 17% less undiscovered oil and 20% less undiscovered natural gas than in the 2000 assessment in eight basins in Southeast Asia; however, there had been at least 10 years of discoveries between the two assessments. Furthermore, the 2010 assessment examined a number of additional basins in Southeast Asia resulting in an overall increase in estimated undiscovered oil of 71% and natural gas by 66%. The 2008 USGS assessment of the Arctic revised down the estimate of undiscovered oil by 48%, largely because of a reappraisal of the West Siberian Basin, but increased the estimate of natural gas by 21% by including a number of basins not in the 2000 assessment [14]. The USGS 2000 assessment [10] also estimated the amount of reserve growth that could be anticipated to 2025 for fields that had been discovered prior to 1996. The median estimate for reserve growth for conventional oil was 612 BBO and for conventional natural gas 3305 trillion cubic feet. At the time of writing, the midpoint of the time interval has been reached over which reserve growth was predicted and a substantial amount of the predicted reserve growth has already occurred [31]. It seems unreasonable, however, to assume that reserve growth will cease in 2025 and interestingly King [32], using a different methodology and separate data from that used by the USGS, estimated future reserve growth of oil at between 200 to 1000 BBO – almost exactly the same range that the USGS predicted would occur from 1996. Table 3 provides an estimate of remaining oil resources at the end of 2007. The proved reserve numbers are from BP [29] and are slightly lower than those of EIA [2]. The estimated volume of oil in undiscovered fields is revised down from the median estimate in the USGS 2000 assessment because 16.5% of that volume had been

14

Oil and Natural Gas: Global Resources

Oil and Natural Gas: Global Resources, Table 3 Estimate of remaining oil resources including NGL (billion barrels). Sources and rationale for estimates are given in text. For comparison, annual production of oil was approximately 29.2 billion barrels in 2009 Conventional Proved reserves Reserve growth Undiscovered fields Total conventional Unconventional Oil sands proved reserves Oil sands resources (incl. reserves) Oil shale resources Total unconventional

1236 600 600 2436 237 820 2826 3141

discovered by 2007 [31]. However, it should be noted that this may be conservative as the 2000 assessment did not include the United States and many geologic basins that have relatively small volumes of discovered oil or where there has been little or no exploration. The reserve growth numbers are based on King [31] for crude oil, as discussed above, and 50% of the USGS 2000 estimated median reserve growth for NGL that was predicted to occur between 1996 and 2025. The oil sand reserve and resource estimates are for Canada [33] and Venezuela [19] only though there are smaller oil sand accumulations in several other countries. The shale oil estimate is from Dyni [23]. The estimated remaining conventional oil is equivalent to 79 years of annual production at 2009 rates. The estimated unconventional oil adds up to the equivalent of 125 years of annual production. Global reserves of natural gas in 2010 were estimated at a little over 6600 TCF by BP [29] and EIA [2]. Taking into account discoveries since 1996 [31] and revising down the median estimate of gas in undiscovered fields from the USGS 2000 assessment, and also assuming 50% of the estimated reserve growth has taken place, the remaining conventional natural gas resources are estimated at approximately 11,850 TCF, equivalent to about 87 years of annual production at 2009 rates. Estimating global abundance of unconventional gas resources is difficult because

development of these resources is largely in its infancy, especially outside of North America. Recently published estimates of recoverable shale gas resources in the United States and Canada vary between 50 and 1000 TCF [34]. Estimates for the rest of the world would likely have an even larger range. It is particularly important to discriminate between “in-place resources” and those that are economically recoverable. The USGS [35] estimated that the United States has 700 TCF of CBM gas in place but only 100 TCF that would be economically recoverable. As 20.5 TCF was produced over the following 13 years under a major drilling effort, 100 TCF may be an optimistic estimate of ultimate recovery. The USGS [35] also suggested that global in-place CBM gas resources may be as high as 7500 TCF but recoverable resources may well be an order of magnitude lower. Australia, for example, has 9% of the world’s coal resources [2] and an estimated 153 TCF of recoverable CBM gas, of which 90% is currently sub-economic or not yet proven by drilling [20]. While extraordinarily large estimates of unconventional gas resources (particularly for hydrates) should be regarded with some scepticism from an economic perspective, there is ample evidence that unconventional gas resources are abundant. In the United States, which has a wide variety of geologic basins, 50% of the gas produced in 2010 was unconventional and it is not unreasonable to suppose that globally the abundance of unconventional gas resources is of a similar scale to conventional gas resources.

Future Directions A strong case could be made that the estimates of remaining oil and gas presented above are on the low side because, as in the past, unanticipated technological advances may make additional oil and gas accumulations economically viable. Forty years ago large-scale economic extraction of oil from oil sands, gas from gas shales, gas from coal beds, and gas from tight sandstones all seemed improbable, but all are now a significant part of world production. However, even if the estimates are somewhat optimistic, it is clear that there is a

Oil and Natural Gas: Global Resources

large volume of remaining recoverable oil and gas resources. How much of that resource will eventually be extracted remains to be seen. There are clearly environmental costs to oil and gas extraction. Pursuing hard-to-get resources raises the risk of disasters such as the BP Deepwater Horizon spill in 2010 [13] that can profoundly influence public opinion. Ecosystems are impacted by large-scale mining of oil sands and oil shales and some in situ extraction of unconventional oil and gas has the potential to influence groundwater supplies. Large volumes of water can be produced during CBM development. The biggest concern, however, is in the consumption of oil and gas with associated rising levels of greenhouse gases in the atmosphere and predictions of global climate change. On the other hand, substitution of natural gas for coal in power plants, more efficient vehicles, and carbon capture and storage could also make substantial reductions in global greenhouse gas emissions. How much of the remaining oil and gas resources will be produced will depend on competition over time from other energy sources, especially renewables and nuclear. It is sometimes assumed that the depletion of global oil resources will inevitably lead to high oil prices that will allow more expensive energy sources to become competitive. However, historically substitution of one energy source by another has taken place primarily by reduction in costs of the substituting energy source [9]. Rather than a result of longterm depletion of the resource, the high oil prices of the first decade of the twenty-first century arguably reflect more restrictions of supply related to conflicts and political problems coinciding with a rapid rise in demand, especially from developing countries. Oil and natural gas may lose global market share in the future either because technological advances permit cheaper production of alternate energy sources or because of political influence on the market, including restrictions on supplies of oil and natural gas or incentives against their consumption, such as carbon taxes. Nevertheless, given the rising global demand for energy, it seems likely that oil and gas will be a major part of the energy mix for most, if not all, of the twenty-first century.

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Bibliography Primary Literature 1. International Energy Agency (2010) Key world energy statistics. OECD/IEA, Paris 2. Energy Information Agency (2011). http://www.eia. doe.gov/. Accessed Apr 2011 3. Fanning LM (1950) A case history of oil-shortage scares. In: Fanning LM (ed) Our oil resources. McGraw-Hill, New York, pp 306–406 4. Hubbert MK (1956) Nuclear energy and the fossil fuels, Shell Development Company Publication 95. Shell Development Company, Houston, p 40 5. Hubbert MK (1962) Energy resources: a report to the committee on natural resources, National Academy of Sciences-National Research Council Publication 1000-D. National Academy of Sciences-National Research Council, Washington, 141 p 6. Deffeyes KS (2001) Hubbert’s peak: the impending world oil shortage. Princeton University Press, Princeton, p 208 7. Meadows DH, Meadows DL, Randers J, Behrens WW III (1972) The limits to growth. Universe Books, New York, p 205 8. Campbell CJ (1988) The coming oil crisis. MultiScience, Brentwood, p 210 9. McCabe PJ (1998) Energy resources – cornucopia or empty barrel? AAPG Bull 82:2110–2134 10. United States Geological Survey (2000) World petroleum assessment 2000 – description and results, U.S. Geological Survey Digital Data Series DDS-60. U.S. Geological Survey, Denver. http://pubs.usgs. gov/dds/dds-060/ 11. Sandrea I, Sandrea R (2007) Global oil reserves-1: recovery factors leave vast target for EOR technologies. Oil Gas J 105(5):44–47 12. Sandrea I, Sandrea R (2007) Global oil reserves-2: recovery factors leave EOR plenty of room for growth. Oil Gas J 105(12):39–42 13. National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling (2011) Deep water: the Gulf oil disaster and the future of offshore drilling, p 380. https://s3.amazonaws.com/pdf_final/DEEPWA TER_ReporttothePresident_FINAL.pdf 14. Gautier DL, Bird KJ, Charpentier RC, Grantz A, Houseknecht DW, Klett TR, Moore TE, Pitman JK, Schenk CJ, Schuenemeyer JH, Sørensen K, Tennyson ME, Valin ZC, Wandrey CJ (2009) Assessment of undiscovered oil and gas in the Arctic. Science 324:1175–1179 15. Shanley KW, Cluff RM, Robinson JW (2004) Factors controlling prolific gas production from lowpermeability sandstone reservoirs: implications for resource assessment, prospect development, and risk analysis. AAPG Bull 88: 1083–1121 16. Nehring R (2008) Growing and indispensable: the contribution of production from tight-gas sands to U.S. gas production. In: Cumella SP, Shanley KW, Camp WK (eds) Understanding, exploring, and

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Oil and Natural Gas: Global Resources developing tight-gas sands – 2005 Vail Hedberg conference, AAPG Hedberg Series, No. 3. American Association of Petroleum Geologists, Tulsa, pp 5–12 Canadian Association of Petroleum Producers (2011) Statistical handbook for Canada’s upstream petroleum industry. Canadian Association of Petroleum Producers, 2011–9999, CAL, p 211 The Economist (2011) Muck and brass Economist 398(8717):77–80 United States Geological Survey (2009) An estimate of recoverable heavy oil resources of the Orinoco oil belt, Venezuela, U.S. Geological Survey Fact Sheet 2009–3028. U.S. Geological Survey, Reston, p 4 Australian Government (2010) Australian energy resource assessment. Department of Resources, Energy and Tourism, Canberra, p 358 Swindell GS (2007) Powder River Basin coalbed methane wells – reserves and rates Society of Petroleum Engineers Report SPE 107308 Energy Resources Conservation Board (2010) ST109: Alberta coalbed methane well locations. Energy Resources Conservation Board, Calgary, p 426 Dyni JR (2006) Geology and resources of some world oil-shale deposits, U.S. Geological Survey Scientific Investigations Report 2005–5294. U.S. Geological Survey, Reston, p 42 U.S. Geological Survey (2008) Assessment of undiscovered oil resources in the DevonianMississippian Bakken Formation, Williston Basin province, Montana and North Dakota, U.S Geological Survey Fact Sheet 2008–3021. U.S. Geological Survey, Reston Klump E, Polson J (2009) Shale-gas skeptic's supply doubts draw wrath of Devon (update 2). http://www. bloomberg.com/ apps/news?pid=newsarchive&sid= asEUlpJcuZB4. Accessed Apr 2011

26. Kvenvolden KA (1993) A primer on gas hydrates. In: Howell DG et al (eds) The future of energy gases, US Geological Survey Professional Paper 1570. U.S. G.P. O, Washington, DC, pp 279–291 27. Walsh MR, Hancock SH, Wilson SJ, Patil SL, Moridis GJ, Boswell R, Collett TS, Koh CA, Sloan ED (2009) Preliminary report on the commercial viability of gas production from natural gas hydrates. Energy Econ 31:815–823 28. Simmons MW (2005) Twilight in the desert. Wiley, Hoboken, p 422 29. BP (2010) BP Statistical review of world energy, June 2010. http://bp.com/statisticalreview. Accessed Apr 2011 30. United States Geological Survey (2010) Assessment of undiscovered oil and gas resources of Southeast Asia, USGS Fact Sheet 2010–3015. U.S. Geological Survey, Reston 31. Gautier DL, McCabe PJ, Ogden J, Demayo TN (2010) Resources, reserves, and consumption of energy. In: Graedel TE, van der Voet E (eds) Linkages of sustainability, Strungmann Forum Report. MIT, Cambridge, pp 323–340 32. King KC (2007) Growth; are we underestimating recent discoveries? Abstracts, annual meeting. AAPG 2007:77 33. Government of Canada (2010) Oil sands – a strategic resource for Canada, North America and the world. Natural Resources Canada, Ottawa. http://www.nrcanrncan.gc.ca/eneene/pdf/os-sb-eng.pdf 34. Mohr SH, Evans GM (2010) Shale gas changes N. American gas production projections. Oil Gas J 108(26):60–64 35. U.S. Geological Survey (1997) Coalbed methane – an untapped energy resource and an environmental concern, USGS Fact Sheet FS-019-97. U.S. Geological Survey, Denver. http://energy.usgs.gov/factsheets/ Coalbed/coalmeth.html

Petroleum and Oil Sand Exploration and Production James G. Speight CD&W Inc., Laramie, WY, USA

Article Outline Glossary Definition of the Subject Introduction Petroleum Exploration and Production Oil Sand Exploration and Production Future Directions Bibliography

Glossary Exploration, recovery, team-based methods, in situ combustion, oil mining, oil sand mining, hot-water process, bitumen, in situ conversion, the future.

Definition of the Subject Depletion of the reserves of conventional (easyto-refine) crude oil is continuing at a noticeable rate, and other sources of hydrocarbons are required – these include crude oil from tight formations, heavy oil (a type of petroleum), and bitumen from oil sand (tar sand) deposits.

Introduction Petroleum occurs in the microscopic pores of sedimentary rocks that form a reservoir – typically, reservoir rock consists of sand, sandstone, limestone, or dolomite. However, not all the pores in a rock will contain petroleum – some will be filled with water or brine that is saturated with minerals.

Both oil and gas have a low specific gravity relative to water and, because of this density difference, will pass through the more porous sections of reservoir rock from their source area to the surface unless restrained by a trap. A trap is a reservoir that is overlain and underlain by dense impermeable cap rock or a zone of very low or no porosity that restrains migrating hydrocarbon. Reservoirs vary in size up to miles in length and breadth and can range in thickness from several inches to hundreds of feet or more. In general, petroleum is extracted by drilling wells from an appropriate surface configuration into the crude oil-containing reservoir, and the wells (production wells) are designed to contain and control all fluid flow throughout the production operations. The number of wells required for a reservoir is dependent on a combination of technical and economic factors used to determine the most likely range of recoverable reserves relative to a range of potential investment alternatives. In summary, the drilling program and the crude oil recovery program are reservoir specific (site specific). In terms of site specificity, the crude oil production rates from a reservoir depend on several factors, such as (i) reservoir geometry, which is primarily the thickness of the reservoir formation and the continuity of the formation, (ii) reservoir pressure, (iii) reservoir depth, (iv) the rock type and the permeability of the formation, (v) fluid saturation and fluid properties, (vi) the extent of fracturing, (vii) the number of wells and their locations in the formation, and (viii) the ratio of the permeability of the formation to the viscosity of the oil [1, 2]. Furthermore, the geological variability of reservoirs means that production profiles differ from field to field.

Petroleum Exploration and Production Exploration Exploration for petroleum originated in the latter part of the nineteenth century when geologists

© Springer Science+Business Media, LLC, part of Springer Nature 2020 R. Malhotra (ed.), Fossil Energy, https://doi.org/10.1007/978-1-4939-9763-3_99 Originally published in R. A. Meyers (ed.), Encyclopedia of Sustainability Science and Technology, © Springer Science+Business Media, LLC, part of Springer Nature 2017, https://doi.org/10.1007/978-1-4939-2493-6_99-3

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began to map land features that were favorable for the collection of oil in a reservoir. Of interest to geologists were outcrops that provided evidence of alternating layers of porous and impermeable rock. The porous rock (typically a sandstone, limestone, or dolomite) provides the reservoir for the petroleum, while the impermeable rock (typically clay minerals or shale) prevents migration of the petroleum from the reservoir. By the early part of the twentieth century, most of the areas where surface structural characteristics offered the promise of oil had been investigated, and the era of subsurface exploration for oil began in the early 1920s. New geological and geophysical techniques were developed for areas where the strata were not sufficiently exposed to permit surface mapping of the subsurface characteristics. In the 1960s, the development of geophysics provided methods for exploring below the surface of the earth. In petroleum exploration, terms as geophysical borehole logging can imply the use of one or more of the geophysical exploration techniques. This procedure involves drilling a well and using instruments to log or make measurements at various levels in the hole by such means as gravity (density), electrical resistivity, or radioactivity. The principles used are basically magnetism (magnetometer), gravity (gravimeter), and sound waves (seismograph). These techniques are based on the physical properties of materials that can be utilized for measurements and include those that are responsive to the methods of applied geophysics. Furthermore, the methods can be subdivided into those that focus on gravitational properties, magnetic properties, seismic properties, electrical properties, electromagnetic properties, and radioactive properties. These geophysical methods can be subdivided into two principal groups: (i) those methods without depth control and (ii) those methods having depth control. In the first group of the measurements (those without depth control), the methods incorporate effects from both local and distant sources. For example, gravity measurements are affected by the variation in the radius of the earth with latitude. They are also affected by the elevation of the site relative to sea level, the thickness of the

Petroleum and Oil Sand Exploration and Production

earth’s crust, and the configuration and density of the underlying rocks, as well as by any abnormal mass variation that might be associated with a mineral deposit. In the second group of measurements (those with depth control), seismic or electric energy is introduced into the ground, and variations in transmissibility with distance are observed and interpreted in terms of geological quantities. Depths to geological horizons having marked differences in transmissibility can be computed on a quantitative basis and the physical nature of these horizons deduced. However, geophysical exploration techniques cannot be applied indiscriminately. Knowledge of the geological parameters likely to be associated with the mineral or subsurface condition being studied is essential both in choosing the method to be applied and in interpreting the results obtained. Furthermore, not all the techniques described here may be suitable for petroleum exploration. A basic rule of thumb in the upstream (or producing) sector of the oil and gas industry has been (and maybe still is in some circles of exploration technology) that the best place to find new crude oil or natural gas is near formations where it has already been found. The financial risk of such a plan is far lower than that associated with drilling a wildcat hole (a drill hole in an unknown area where oil has not been found prior to the commencement of the new drill hole) in a prospective, but previously unproductive, area. On the other hand, there is a definite trade-off between rewards for risk. The returns on drilling investment become ever leaner as more wells are drilled in a particular area because the natural distribution of oil and gas field volumes tends to be approximately log geometric – there are only a few large oil fields (giant and supergiant oil fields), whereas there are a great many small oil fields [3]. The drilling job is complete when the drill bit penetrates the reservoir and the reservoir is evaluated to see whether the well represents the discovery of a prospect or whether it is a dry hole. If the hole is dry, it is plugged and abandoned. On the other hand, if the presence of crude oil has been established, the prospect becomes a live

Petroleum and Oil Sand Exploration and Production

prospect, and once the final depth has been reached, the well is completed to allow oil to flow into the casing in a controlled manner. First, a perforating gun is lowered into the well to the production depth. The gun has explosive charges to create holes in the casing through which oil can flow. After the casing has been perforated, a small-diameter pipe (tubing) is run into the hole as a conduit for oil and gas to flow up the well, and a packer is run down the outside of the tubing. When the packer is set at the production level, it is expanded to form a seal around the outside of the tubing. Finally, a multivalve structure – the Christmas tree (Fig. 1) – is installed at the top of the tubing and cemented to the top of the casing. The Christmas tree allows them to control the flow of oil from the well.

Onshore Production Recovery, as applied in the petroleum industry, is the production of oil from a reservoir. There are several methods by which this can be achieved that range from recovery due to reservoir energy (i.e., the oil flows from the well hole without assistance) to enhanced recovery methods in which considerable energy must be added to the reservoir to produce the oil. However, the effect of

Petroleum and Oil Sand Exploration and Production, Fig. 1 The Christmas tree

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the recovery method on the crude oil and on the reservoir must be considered before method application. Furthermore, as might be expected, the type of exploration technique employed depends upon the nature of the site, and as for many environmental operations, the recovery techniques applied to a specific site are dictated by the nature of the site and are, in fact, site specific. There are three phases for recovering oil from reservoirs (Fig. 2) that are appropriately named: (i) primary recovery, (ii) secondary recovery, and (iii) tertiary recovery. Primary recovery occurs as wells produce because of natural energy from expansion of gas and water within the producing formation, pushing fluids into the wellbore and lifting the fluids to the surface. Secondary recovery requires energy to be applied to lift fluids to surface – this may be accomplished by injecting gas down a hole to lift fluids to the surface, installation of a subsurface pump, or injecting gas or water into the formation itself. Tertiary recovery occurs when a means is required to increase fluid mobility within the reservoir – this may be accomplished by introducing additional heat into the formation to lower the viscosity (thin the oil) and improve its ability to flow to the wellbore. Heat may be introduced by either (i) injecting chemicals with water (chemical flood, surfactant

polish rod stuffing box tubing pressure gauge

tubing flow valve

master valve casing pressure gauge

flow line

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Petroleum and Oil Sand Exploration and Production

Petroleum and Oil Sand Exploration and Production, Fig. 2 Methods for oil recovery

Primary Recovery Artificial Lift

Natural Flow

Pump,Gas Lift,Etc.

Secondary Recovery Pressure Maintenance

Waterflood

Water,Gas Reinjection

Tertiary Recovery

Thermal

flood), (ii) injecting steam (steam flood), or (iii) injecting oxygen to enable the ignition and combustion of oil within the reservoir) ( fireflood). Generally, conventional crude oil reservoirs often exist (i) with an overlying gas cap, (ii) in communication with aquifers, or (iii) both. The crude oil resides together with water and free gas in very small holes (pore spaces) and fractures. The size, shape, and degree of interconnection of the pores vary considerably from place to place in an individual reservoir. Below the oil layer, the sandstone is usually saturated with salt water. The oil is released from this formation by drilling a well and puncturing the limestone layer on either side of the limestone dome or fold. If the peak of the formation is tapped, only the gas is obtained. If the penetration is made too far from the center, only salt water is obtained. Therefore, in designing a recovery project, it is a general practice to locate injection and producing wells in a regular geometric pattern so that a symmetrical and interconnected network is formed and production can be maximized. However, the relative location of injectors and producers depends on factors such as (i) reservoir geometry, (ii) reservoir lithology, (iii) reservoir depth, (iv) porosity, (v) permeability, (vi) continuity of reservoir rock properties, (vii) magnitude and distribution of fluid

Gas

Chemical

Microbial

saturations, and, last, but certainly not least (viii) fluid properties. Overall, the goal is to increase the mobility of the oil, and once production begins, the performance of each well and reservoir is monitored, and a variety of engineering techniques are used to progressively refine reserve recovery estimates over the producing life of the field. The total recoverable reserves are not known with complete certainty until the field has produced crude oil to the point of depletion (where no more crude oil can be produced) or its economic limit and abandonment. Generally, the first stage in the extraction of crude oil is to drill a well into the underground reservoir. Often, many wells (multilateral wells) will be drilled into the same reservoir to ensure that the extraction rate will be economically viable. Also, some wells (secondary wells) may be used to pump water, steam, acids, or various gas mixtures into the reservoir to raise or maintain the reservoir pressure and so maintain an economic extraction rate. Directional drilling is also used to reach formations and targets not directly below the penetration point or drilling from shore to locations under water [4]. A controlled deviation may also be used from a selected depth in an existing hole to attain economy in drilling costs. Various types

Petroleum and Oil Sand Exploration and Production

of tools are used in directional drilling along with instruments to help orient their position and measure the degree and direction of deviation; two such tools are the whipstock and the knuckle joint. The whipstock is a gradually tapered wedge with a chisel-shaped base that prevents rotation after it has been forced into the bottom of an open hole. As the bit moves down, it is deflected by the taper about 5
from the alignment of the existing hole. If the underground pressure in the oil reservoir is sufficient, the oil will be forced to the surface under this pressure (primary recovery). Natural gas (associated natural gas) is often present, which also supplies needed underground pressure (primary recovery). In this situation, it is sufficient to place an arrangement of valves on the wellhead – the Christmas tree (Fig. 1) – in order to connect the well to a pipeline network for storage and processing. For limestone reservoir rock, acid is pumped down the well and out the perforations. The acid dissolves channels in the limestone that lead oil into the well. For sandstone reservoir rock, a specially blended fluid containing proppants (sand, walnut shells, aluminum pellets) is pumped down the well and out the perforations. The pressure from this fluid makes small fractures in the sandstone that allow oil to flow into the well, while the proppants hold these fractures open. Once the oil is flowing, production equipment is set up to extract the oil from the well. A well is always carefully controlled at the stage of production (the flush stage) to prevent the potentially dangerous and wasteful gusher. This is a dangerous condition and is (hopefully) prevented by the blowout preventer and the pressure of the drilling mud. In most wells, acidizing or fracturing the well starts the oil flow. Whatever the nature of the reservoir rock (sandstone, SiO2, limestone, or CaCO3), over the lifetime of the well, the pressure will fall, and at some point, there will be insufficient underground pressure to force the oil to the surface. Secondary oil recovery uses various techniques to aid in recovering oil from depleted or low-pressure reservoirs. Sometimes pumps, such as beam pumps (horsehead pumps) and electrical submersible

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pumps, are used to bring the oil to the surface. Other secondary recovery techniques increase the reservoir’s pressure by water injection, natural gas reinjection and gas lift, which injects air, carbon dioxide, or another gas into the reservoir. In addition, reservoir heterogeneity, such as fractures and faults, can cause reservoirs to drain inefficiently during the production stage, and any highly cemented zones or shale zones (i.e., low-permeability zones) can produce barriers to the flow of fluids in reservoirs and lead to high residual oil saturation. Reservoirs containing crude oils with low API gravity often cannot be produced efficiently without application of enhanced oil recovery (EOR) methods because of the high viscosity of the crude oil. Conventional primary and secondary recovery processes are ultimately expected to produce about one-third of the original oil-in-place (OOIP), although recoveries from individual reservoirs can range from less than 5% v/v to as high as 80% v/v of the original oil-in-place. This broad range of recovery efficiency is a result of variations in the properties of the specific rock and fluids involved from reservoir to reservoir as well as the kind and level of energy that drives the oil to producing wells, where it is captured. However, there is always the potential for adverse effects (Table 1). Crude oil is also produced from offshore fields, usually from steel drilling platforms set on the ocean floor. In shallow, calm waters, these may be little more than a wellhead and workspace, but the larger ocean rigs include the well equipment and processing equipment as well as crew quarters. Such platforms include the floating tension leg platform that is secured to the seafloor by giant cables and drillships. Such platforms can hold a steady position above a seafloor well using constant, computer-controlled adjustments. In Arctic areas, islands may be built from dredged gravel and sand to provide platforms capable of resisting drifting ice fields. Primary Recovery Methods

Petroleum recovery usually starts with a formation pressure high enough to force crude oil into the well and sometimes to the surface through the

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Petroleum and Oil Sand Exploration and Production

Petroleum and Oil Sand Exploration and Production, Table 1 Recovery process parameters and their potential adverse effects Property Carbon dioxide injection

Miscible flooding

Organic chemicals

Acidizing

Pressure decrease

Temperature decrease

Comments Lowers pH; can change oil composition leading to phase separation of sludge or sediment and blocking of channels Hydrocarbon-rich gases lower the solubility parameter and solvent power of the oil and cause separation of asphaltene material Can lower the solubility parameter and solvent power of the oil and cause separation of asphaltene material; blocking of channels Interaction of crude oil constituents upsetting molecular balance and deposition of sludge or sediment; blocking of channels Can change composition of oil medium leading to phase separation of asphaltene material as sludge or sediment; blocking of channels Can change composition of oil medium leading to phase separation of asphaltene material as sludge or sediment; blocking of channels

tubing [5]. For a newly opened formation and under ideal conditions, the proportions of gas may be so high that the oil is, in fact, a solution of liquid in gas that leaves the reservoir rock so efficiently that a core sample will not show any obvious oil content. A general rough indication of this situation is a high ratio of gas to oil produced. This ratio may be zero for fields in which the rock pressure has been dissipated. The oil must be pumped out to as much as 50,000 ft3 or more of gas per barrel of oil in the so-called condensate reservoirs, in which a very light crude oil (0.80 specific gravity or lighter) exists as vapor at high pressure and elevated temperature. Once production commenced, the crude oil moves out of the reservoir into the well by one or more of four processes. These processes are (i) dissolved gas drive, (ii) gas cap drive, (iii) water drive, and (iv) gravity drive. Early recognition of the type of drive involved is essential to the efficient development of an oil field.

In dissolved gas drive (solution gas drive) [2, 4], the propulsive force is the gas in solution in the oil, which tends to come out of solution because of the pressure release at the point of penetration of a well. Dissolved gas drive is the least efficient type of natural drive as it is difficult to control the gas-oil ratio and the bottom-hole pressure drops rapidly. If gas overlies the oil beneath the top of the trap, it is compressed and can be utilized (gas cap drive) to drive the oil into wells situated at the bottom of the oil-bearing zone [2, 4]. By producing oil only from below the gas cap, it is possible to maintain a high gas-oil ratio in the reservoir until almost the very end of the life of the pool. If, however, the oil deposit is not systematically developed so that bypassing of the gas occurs, an undue proportion of oil is left behind. Usually, the gas in a gas cap (associated natural gas) contains methane and other hydrocarbons that may be separated out by compressing the gas. A well-known example is natural gasoline that was formerly referred to as casinghead gasoline or natural gas gasoline. However, at high pressures, such as those existing in the deeper fields, the density of the gas increases, and the density of the oil decreases until they form a single phase in the reservoir. These are the so-called retrograde condensate pools because a decrease (instead of an increase) in pressure brings about condensation of the liquid hydrocarbons. When this reservoir fluid is brought to the surface and the condensate is removed, a large volume of residual gas remains. In many cases, this gas is recycled by compression and injection back into the reservoir, thus maintaining adequate pressure within the gas cap, and condensation in the reservoir is prevented. The most efficient propulsive force in driving oil into a well is natural water drive, in which the pressure of the water forces the lighter recoverable oil out of the reservoir into the producing wells [2, 4]. In anticlinal accumulations, the structurally lowest wells around the flanks of the dome are the first to come into water. Then, the oil-water contact plane moves upward until only the wells at the top of the anticline are still producing oil; eventually, these also must be abandoned as the water displaces the oil. The force behind the water drive may be hydrostatic pressure, the expansion of

Petroleum and Oil Sand Exploration and Production

the reservoir water, or a combination of both. Water drive is also used in certain submarine fields. Gravity drive is an important factor when oil columns of several thousands of feet exist. Furthermore, the last bit of recoverable oil is produced in many pools by gravity drainage of the reservoir. Another source of energy during the early stages of withdrawal from a reservoir containing undersaturated oil is the expansion of that oil as the pressure reduction brings the oil to the bubble point (the pressure and temperature at which the gas starts to come out of solution). The recovery efficiency for primary production is generally low when liquid expansion and solution gas evolution are the driving mechanisms. Much higher recoveries are associated with reservoirs with water and gas cap drives and with reservoirs in which gravity effectively promotes drainage of the oil from the rock pores. The overall recovery efficiency is related to how the reservoir is delineated by production wells. However, for primary recovery operations, no pumping equipment is required. If the reservoir energy is not sufficient to force the oil to the surface, then the well must be pumped. In either case, nothing is added to the reservoir to increase or maintain the reservoir energy or to sweep the oil toward the well. The rate of production from a flowing well tends to decline as the natural reservoir energy is expended. When a flowing well is no longer producing at an efficient rate, a pump is installed. There are also two processes that can be used to improve formation characteristics, namely, acidizing and fracturing. Acidizing involves injecting an acid into a soluble formation, such as a carbonate, where it dissolves rock. This process enlarges the existing voids and increases permeability. Hydraulic fracturing (fracking) involves injecting a fluid into the formation under significant pressure that makes existing small fractures larger and creates new fractures. Petroleum production is invariably accompanied by a decline in reservoir pressure, and primary recovery comes to an end as the reservoir energy is reduced. At this stage, secondary recovery methods are applied to replace produced reservoir fluids and maintain (or increase) reservoir pressure.

23

Secondary Recovery Methods

Secondary oil recovery methods use various techniques to aid in recovering oil from depleted or low-pressure reservoirs. Surface pumps or submerged pumps (electrical submersible pumps (ESPs)) are often used to bring the oil to the surface. Other secondary recovery techniques increase the reservoir pressure by water injection and/or by gas injection. In fact, the first method recommended for improving the recovery of oil was a pressure maintenance project which involved the reinjection of natural gas, and there are indications that gas injection was utilized for this purpose before 1900 [6, 7]. The most common follow-up secondary recovery operations usually involve the application of pumping operations or of injection of materials into a well to encourage movement and recovery of the remaining petroleum. The pump, generally known as the horsehead pump (pump jack, nodding donkey, or sucker rod pump), provides mechanical lift to the fluids in the reservoir. The up-and-down movement of the sucker rods forces the oil up the tubing to the surface. A walking beam powered by a nearby engine may supply this vertical movement, or it may be brought about using a pump jack, which is connected to a central power source by means of pull rods. Depending on the size of the pump, it generally produces up to one-third of a barrel of an oil-water emulsion at each stroke. The size of the pump is also determined by the depth and weight of the oil to be removed, with deeper extraction requiring more power to move the heavier lengths of the rod. Secondary oil recovery operations also involve the injection of water or gas into the reservoir. When water is used, the process is called a waterflood and with gas, a gas flood. Separate wells are usually used for injection and production. The injected fluids maintain reservoir pressure or repressure the reservoir after primary depletion and displace a portion of the remaining crude oil to production wells. In the water-flooding process, water is injected into a reservoir to obtain additional oil recovery through movement of reservoir oil to a producing well. Generally, the selection of an appropriate

24

Petroleum and Oil Sand Exploration and Production

flooding pattern for the reservoir depends on the quantity and location of accessible wells. Frequently, producing wells can be converted to injection wells, whereas in other circumstances it may be necessary or advantageous to drill new injection wells. The mobility of oil is the effective permeability of the rock to the oil divided by the viscosity of the oil: l ¼ k=m In this equation, l is the mobility, md/cP; k is the effective permeability of reservoir rock to a given fluid, md; and m is the fluid viscosity, cP. Thus, the mobility ratio (M) is the mobility of the water divided by the mobility of oil: M ¼ Krw mo =Kro mw In this equation, Krw is the relative permeability to water, Kro is the relative permeability to oil, mo is the viscosity of the oil, and mw is the viscosity of water. The mobility ratio (M) refers that Ko is the mobility of oil ahead of the front (measured at Swc), while Kw is the mobility of water at average water saturation in the water-contacted portion of the reservoir. The mobility ratio of a waterflood will remain constant before breakthrough, but will increase after water breakthrough corresponding to the increase in water saturation and relative permeability to water in the water-contacted portion of the reservoir. Furthermore, the mobility ratio at water breakthrough is the term that is of significance in describing relative mobility ratio, i.e., M 1 indicates an unfavorable displacement as water moves faster than oil. The well pattern can also contribute to the efficiency of crude oil production. Generally, the choice of pattern (Table 2) for waterflooding must be consistent with the existing wells. The objective is to select the proper pattern that will provide the injection fluid with the maximum possible contact with the crude oil to minimize bypassing by the water. However, reservoir uniformity (and heterogeneity) must be given consideration such

Petroleum and Oil Sand Exploration and Production, Table 2 The ratio of injection well production for various patterns Pattern Four spot Five spot Seven spot Inverted seven spot Nine spot Inverted nine spot a

Ratioa 2 1 0.5 2 0.33 3

Ratio of production wells to injection wells

the structure of the reservoir can (will) dictate the choice of pattern, and mobility ratio has an important influence on pattern selection. If the ratio is unfavorable, the injectivity of an injector will exceed the productivity of a producer, and water injection will be supersede oil production. Hence, to balance the production with the water injection, more producers than injectors are required. On the other hand, if the mobility ratio is favorable, the injectivity is impaired, and the pattern should have more injectors than producers. In a four-spot pattern, the distance between all like wells is constant. Any three injection wells form an equilateral triangle with a production well at the center. The four spots may be used when the injectivity is high or the heterogeneity is minimal. In a five-spot pattern, the distance between all like wells is constant. Four injection wells form a square with a production well at the center. If existing wells were drilled on square patterns, five-spot patterns (as well as nine-spot patterns) are most commonly used since they allow easy conversion to a five-spot waterflood. In the sevenspot pattern, the injection wells are located at the corner of a hexagon with a production well at its center. If the reservoir characteristics yield lower than preferred injection rates, either a seven-spot (or a nine-spot) pattern should be considered because there are more injection wells per pattern than producing wells. In the nine-spot pattern, the arrangement is similar to that of the five spot but with an extra injection well drilled at the middle of each side of the square. The pattern essentially contains eight injectors surrounding one producer. If existing wells were drilled on square patterns, nine-spot

Petroleum and Oil Sand Exploration and Production

patterns (as well as five-spot patterns) are most commonly used. If the reservoir characteristics yield lower injection rates than those desired, one should consider using either a nine-spot pattern or a seven-spot pattern where there are more injection wells per pattern than producing wells. In the inverted seven-spot pattern, the arrangement is similar to the normal seven-spot pattern, except where the position of the producer well was in the normal seven-spot pattern, there is now an injector well. Likewise, where the injector wells were in the normal seven-spot pattern, there are now producer wells. The inverted seven-spot pattern may be used when the injectivity is high or the heterogeneity is minimal. The arrangement of the wells is similar to the normal nine-spot pattern except the position of the producer well in the normal nine-spot pattern is occupied by an injector well. Likewise, where the positions of the injector wells were in the normal nine spot, there are now producer wells. If the reservoir is homogenous and the mobility ratio is unfavorable, the inverted nine-spot pattern may be promising. In the direct line-drive pattern, the lines of injection and production are directly opposite to each other. If the injectivity is low or the heterogeneity is large, direct line drive is a good option. Anisotropic permeability, permeability trends, or oriented fracture systems favor line-drive patterns. In the staggered line-drive pattern, the wells are in lines as in the direct line, but the injectors and producers are no longer directly opposed but laterally displaced by a distance specified that is dependent upon the distance between wells of the same type and the distance between the lines of injector wells and producer wells. The staggered line-drive pattern is also effective for reservoirs where there is anisotropic permeability or permeability trends or oriented fracture systems.

Enhanced Oil Recovery Methods

Traditional primary and secondary recovery methods typically recover less than half (sometimes less than one-third) of the oil, only one-third of the original oil-in-place. It is at some point before secondary recovery ceases to remain feasible that enhanced oil recovery methods must be applied if further oil is to be recovered.

25

Enhanced oil recovery (tertiary oil recovery) is the incremental ultimate oil that can be recovered from a petroleum reservoir over oil that can be obtained by primary and secondary recovery methods [2, 4, 8, 9]. Enhanced oil recovery methods offer prospects for ultimately producing 30–60% v/v, or more, of the original oil-in-place. Enhanced oil recovery processes use thermal, chemical, or fluid phase behavior effects to reduce or eliminate the capillary forces that trap oil within pores, to thin the oil or otherwise improve its mobility, or to alter the mobility of the displacing fluids. In some cases, the effects of gravity forces, which ordinarily cause vertical segregation of fluids of different densities, can be minimized or even used to advantage. The various processes differ considerably in complexity, the physical mechanisms responsible for oil recovery, and the amount of experience that has been derived from field application. The degree to which the enhanced oil recovery methods are applicable in the future will depend on development of improved process technology. It will also depend on improved understanding of fluid chemistry, phase behavior, and physical properties and on the accuracy of geology and reservoir engineering in characterizing the physical nature of individual reservoirs [10]. The steam-based methods are the most advanced of all enhanced oil recovery methods in terms of field experience and thus have the least uncertainty in estimating performance when a good reservoir description is available. Steam processes are most often applied in reservoirs containing heavy crude oil, usually in place of rather than following secondary or primary methods. Commercial application of steam processes has been underway since the early 1960s. For taxation purposes, the Internal Revenue Service of the United States has listed the projects that qualify as enhanced oil recovery projects [11] and are therefore available for a tax credit, and these projects are: 1. Thermal Recovery Methods Thermal methods of recovery reduce the viscosity of the crude oil by heat so that it flows more easily into the production well. (a) Steam drive injection – the continuous injection of steam into one set of wells (injection wells) or other injection source to effect oil

26

Petroleum and Oil Sand Exploration and Production

displacement toward and production from a second set of wells (production wells). (b) Cyclic steam injection – the alternating injection of steam and production of oil with condensed steam from the same well or wells. (c) In situ combustion – the combustion of oil or fuel in the reservoir sustained by injection of air, oxygen-enriched air, oxygen, or supplemental fuel supplied from the surface to displace unburned oil toward producing wells. This process may include the concurrent, alternating, or subsequent injection of water. 2. Gas Flood Recovery Methods (a) Miscible fluid displacement – the injection of gas (e.g., natural gas, enriched natural gas, a liquefied petroleum slug driven by natural gas, carbon dioxide, nitrogen, or flue gas) or alcohol into the reservoir at pressure levels such that the gas or alcohol and reservoir oil are miscible. (b) Carbon dioxide augmented waterflooding – the injection of carbonated water, or water and carbon dioxide, to increase waterflood efficiency. (c) Immiscible carbon dioxide displacement – the injection of carbon dioxide into an oil reservoir to effect oil displacement under conditions in which miscibility with reservoir oil is not obtained; this process may include the concurrent, alternating, or subsequent injection of water. (d) Immiscible nonhydrocarbon gas displacement – the injection of nonhydrocarbon gas (such as nitrogen) into an oil reservoir, under conditions in which miscibility with reservoir oil is not obtained, to obtain a chemical or physical reaction (other than pressure) between the oil and the injected gas or between the oil and other reservoir fluids; this process may include the concurrent, alternating, or subsequent injection of water. 3. Chemical Flood Recovery Methods (a) Surfactant flooding is a multiple-slug process involving the addition of surface-active chemicals to water [12]. These chemicals

reduce the capillary forces that trap the oil in the pores of the rock. The surfactant slug displaces most the oil from the reservoir volume contacted, forming a flowing oil-water bank that is propagated ahead of the surfactant slug. The principal factors that influence the surfactant slug design are interfacial properties, slug mobility in relation to the mobility of the oil-water bank, the persistence of acceptable slug properties and slug integrity in the reservoir, and cost. (b) Microemulsion flooding also known as surfactant-polymer flooding involves injection of a surfactant system (e.g., a surfactant, hydrocarbon, cosurfactant, electrolyte, and water) to enhance the displacement of oil toward producing wells, and [2] caustic flooding – the injection of water that has been made chemically basic by the addition of alkali metal hydroxides, silicates, or other chemicals. (c) Polymer-augmented waterflooding – the injection of polymeric additives with water to improve the areal and vertical sweep efficiency of the reservoir by increasing the viscosity and decreasing the mobility of the water injected; polymer-augmented waterflooding does not include the injection of polymers for modifying the injection profile of the wellbore or the relative permeability of various layers of the reservoir, rather than modifying the water-oil mobility ratio. In keeping with the reservoir characteristics being a major issue to crude oil production, for the enhanced oil recovery processes that involve the use of chemicals – surfactant/polymer, polymer, and alkaline flooding [13] – it must be recognized that each reservoir has unique fluid and rock properties, and specific chemical systems must be designed for each individual application. The chemicals used, the concentration of the chemicals, and the number of chemical as well as the amount of chemicals are also dependent upon the specific properties of the fluids and the rocks involved and upon economic considerations. Certain types of reservoirs, such as those with very viscous crude oils and some low-permeability carbonate (limestone, dolomite, or chert)

Petroleum and Oil Sand Exploration and Production

reservoirs, respond poorly to conventional secondary recovery techniques. The viscosity (or the API gravity) of crude oil is an important factor that must be considered when heavy oil is recovered from a reservoir. In these reservoirs, it is desirable to initiate enhanced oil recovery operations as early as possible, which may mean considerably abbreviating conventional primary recovery operations and secondary recovery operations to the extent that these operations may be bypassed. Thermal enhanced oil recovery processes add heat to the reservoir to reduce oil viscosity and/or to vaporize the oil. In both instances, the oil is made more mobile so that it can be more effectively driven to producing wells. In addition to adding heat, these processes provide a driving force (pressure) to move oil to producing wells. These methods have found most use when the oil in the reservoir has a high viscosity. For example, heavy oil is usually highly viscous (hence the use of the adjective heavy), with a viscosity ranging from approximately 100 cP to several million centipoises at the reservoir conditions. In addition, oil viscosity is also a function of temperature and API gravity [2, 14]. Thus, for heavy crude oil samples with API gravity ranging from 4 to 21
API (1.04–0.928 kg/m3): loglogðms þ aÞ ¼ A  B logðT þ 460Þ In this equation, ms is the oil viscosity in cP, T is the temperature in
F, A and B are constants, and a is an empirical factor used to achieve a straight-line correlation at low viscosity. This equation is usually used to correlate kinematic viscosity in centistokes, in which case an a of 0.6–0.8 is suggested (dynamic viscosity in cP equals kinematic viscosity in cSt times density in g/ml). An alternative equation for correlating viscosity data (where A and B are constants and T* is the absolute temperature) is m ¼ aeb=T Steam drive injection (steam injection) has been commercially applied since the early 1960s. The process occurs in two steps: (i) steam stimulation of production wells, that is, direct steam stimulation, and (ii) steam drive by steam

27

injection to increase production from other wells (indirect steam stimulation). When there is some natural reservoir energy, steam stimulation normally precedes steam drive. In steam stimulation, heat is applied to the reservoir by the injection of high-quality steam into the produce well. This cyclic process (huff and puff or steam soak) uses the same well for both injection and production. The period of steam injection is followed by production of reduced viscosity oil and condensed steam (water). One mechanism that aids production of the oil is the flashing of hot water (originally condensed from steam injected under high pressure) back to steam as pressure is lowered when a well is put back on production. Cyclic steam injection is the alternating injection of steam and production of oil with condensed steam from the same well or wells. Thus, steam generated at surface is injected in a well, and the same well is subsequently put back on production. The process includes three stages: (i) the injection, during which a measured amount of steam is introduced into the reservoir; (ii) the soak period, which requires that the well be shut in for a period of time, which is usually measured in days, to allow uniform heat distribution to reduce the viscosity of the oil (alternatively, to raise the reservoir temperature above the pour point of the oil; and (iii) the production stage in which the now-mobile oil is produced through the injection well. The cycle is repeated until the flow of crude oil diminishes to a point of no returns. Using in situ combustion to stimulate oil production is regarded as attractive for deep reservoirs [15] and, in contrast to steam injection, usually involves no loss of heat. The duration of the combustion may be short (k>1 md, and [3] a high-permeability reservoir might be 25 md >k. If the formation contains crude oil with a fluid viscosity of 2 cP, all the permeability values must be multiplied by a factor of 100 to determine whether the reservoir is a low-permeability, moderate-permeability, or high-permeability formation. Thus, the definition of reservoir permeability depends on the value of the viscosity of the reservoir fluid. In heavy-oil reservoirs, in which the viscosity of the fluid is on the order of several thousand centipoises, formations with a permeability on the order of several Darcys are a low-permeability reservoir. By inference, if the reservoir is a formation containing either natural gas or conventional (light) crude oil, a permeability on the order of several hundred millidarcies or more can be considered to be a high-permeability reservoir. Furthermore, the main reasons for fracture treating high-permeability formations are (i) to improve both the reservoir and wellbore communication, (ii) to bypass formation damage, (iii) to reduce the drawdown around the wellbore, (iv) to increase the back stress on the formation, (v) to control sand production, (vi) to reduce fines migration, (vii) to reduce asphaltene deposition, and (viii) to reduce water coning [24]. By creating

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a short, highly conductive fracture connecting the reservoir to the wellbore, the productivity index is increased; thus, more oil and gas can be produced with a lower drawdown. As the drawdown is reduced, the tendency of a poorly consolidated reservoir to produce sand is also reduced. In certain formations, the reduction in drawdown also helps to deter (i) fines migration, (ii) deposition of asphaltene deposition, and (iii) water coning – the phenomenon in which bottom water gradually and frequently suddenly displaces a part or all of the oil production when a certain rather critical production rate from the well is exceeded. Finally, hydraulic fracturing is utilized offshore primarily during the well completion phase of developing a well for production to enhance safety and security of the well while optimizing production. This constitutes most hydraulic fracturing activities that are conducted offshore. Hydraulic fracturing can also be used to prepare a well for enhanced oil recovery or to work over the well to increase production when the well has been under production for some time. Coupled with hydraulic fracturing, the crude oil and natural gas resources in shale formation and in tight formations (often referred to as tight oil and tight gas, respectively) become accessible and recoverable. Furthermore, horizontal drilling makes it possible for a well to be drilled vertically several thousand feet or meters and then curved to extend at an angle parallel to the earth’s surface, threading the well through the horizontal gas formation to capture more pockets of gas. On the other hand, in some geological settings, it is more appropriate to directionally drill s-shaped wells from a single pad to minimize surface disturbance. These types of wells are drilled vertically several thousand feet and then extend in arc shapes beneath the surface of the earth. Whatever the type of well, multiple wells can be drilled from a central location to proceed in different directions within the reservoir. During drilling, mobile drilling units are moved between wells on a single drilling location (pad), which avoids dismantling and reassembling drilling equipment for each well, making the process shorter. This procedure limits the required number of drilling pads and, therefore, leaves a smaller environmental footprint on the surface.

Petroleum and Oil Sand Exploration and Production

Offshore Production A range of different structures are used offshore oil production, depending on size and water depth. In the several decades, there has been an evolution of the offshore installations, including those that rest on the sea bottom. These include installations with multiphase piping to the shore with no offshore topside structure. In addition, deviation drilling (directional drilling) is used to reach different parts of the reservoir from a few wellhead cluster locations which have replaced the outlying wellhead towers. A shallow water complex (typically found in water depths up to 350 ft) is characterized by several independent platforms with different parts of the process and utilities linked with gangway bridges. Individual platforms include the wellhead platform, the riser platform, the processing platform, the accommodations platform, and the power generation platform. A gravity base complex consists of enormous concrete fixed structures placed on the bottom, typically with oil storage cells in the skirt that rest on the sea bottom. The large deck receives all parts of the process and utilities in large modules. Large fields at 350–1600 ft water depth are typical of such complexes. The concrete was poured at an onshore location, with enough air in the storage cells to keep the structure floating until it is towed out to sea and lowered on to the seabed. A compliant tower platform is similar to a fixed platform and consists of a narrow tower, attached to a foundation on the seafloor and extending up to the platform. This tower is flexible, as opposed to the relatively rigid legs of a fixed platform. This flexibility allows them to operate in much deeper water, as they can “absorb” much of the pressure exerted by the wind and sea. Compliant towers are used between 1600 and 3300 ft water depth. A floating production platform has all topside systems located on a floating structure with dry or subsea wells. The floating production, storage, and offloading platform has the advantage of being a stand-alone structure that does not need external infrastructure such as pipelines or storage. Crude oil is offloaded to a shuttle tanker at regular intervals, from days to weeks, depending on production and storage capacity. The platform

Petroleum and Oil Sand Exploration and Production

31

Petroleum and Oil Sand Exploration and Production, Table 3 Types of ocean tankers used for crude oil transportation Type/cargo 1. VLCC/crude 2. Multiproduct/crude-heated tanks 3. Clean/dirty product 4. LPG carrier 5. LNG spherical tanks 6. LNG “oblong” tanks

Length (m) 332 244 183 209 272 287

Beam (m) 58 42 32 31.4 47.2 41.8

Draft (m) 22 14.6 12.2 12.5 11.4 11.3

dwt* 298,000 105,000 47,000 47,000 67,000 71,470

Speed (knot) 15.5 14 15.6 – 18.5 19.2

dwt* (deadweight tons) is the cargo capacity of the vessel

is typically a tanker-type hull or barge, often converted from an existing crude oil tanker (VLCC or ULCC) (Table 3). The wellheads or subsea risers from the sea bottom are located on a central or bow-mounted turret so that the ship can rotate freely to point into wind, waves, or current. The turret has wire rope and chain connections to several anchors (position mooring), or it can be dynamically positioned using thrusters (dynamic positioning). Most installations use subsea wells. The main process is placed on the deck, while the hull is used for storage and offloading to a shuttle tanker. A tension leg platform consists of a structure held in place by vertical tendons connected to the seafloor by pile-secured templates. The structure is held in a fixed position by tensioned tendons, which provide for use of the platform in a broad water depth range up to about 6500 ft. The tendons are constructed as hollow high-tensile strength steel pipes that carry the spare buoyancy of the structure and ensure limited vertical motion. A semisubmersible platform has a similar design but without taut mooring. This arrangement permits more lateral and vertical motion and is generally used with flexible risers and subsea wells. A SPAR platform consists of a single tall floating cylindrical hull, supporting a fixed deck. The cylinder does not however extend all the way to the seabed, but is tethered to the bottom by a series of cables and lines. The large cylinder serves to stabilize the platform in the water and allows for movement to absorb the force of potential hurricanes. SPARs can be quite large and are used for water depths from 350 ft and up to 16,000 ft.

SPAR is not an acronym, but refers to its likeness to a ship’s spar. SPARs can support dry completion wells, but are more often used with subsea wells. Subsea production systems are wells located on the seafloor, as opposed to the surface. As in a floating production system, the petroleum is extracted at the seabed and can then be “tied-back” to an already existing production platform or even an onshore facility, limited by horizontal distance or “offset.” The well is drilled by a movable rig, and the extracted oil and natural gas are transported by undersea pipeline and riser to a processing facility. This allows one strategically placed production platform to service many wells over a reasonably large area. Subsea systems are typically in use at depths of 500 m or more and do not have the ability to drill, only to extract and transport. Drilling and completion are performed from a surface rig. Horizontal offsets of up to 250 km/150 miles are currently possible.

Oil Sand Exploration and Production Heavy oil and bitumen (the component of interest in an oil sand deposit) are often defined (loosely and incorrectly) in terms of API gravity. A more appropriate definition of bitumen, which sets it aside from heavy oil and conventional petroleum, is based on the recovery process as presented in the definition of oil sand (tar sand) offered by the US government as the extremely viscous hydrocarbon which is not recoverable in its natural state by conventional oil well production methods

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including currently used enhanced recovery techniques [2, 4]. By inference, conventional petroleum and heavy oil (recoverable by conventional oil well production methods including currently used enhanced recovery techniques) are different to oil sand bitumen. Be that as it may, some stage of production, conventional petroleum (in the later stages of recovery) and heavy oil (in the earlier stages of recovery) may require the application of enhanced oil recovery methods for recovery. Both heavy oil and oil sand bitumen are difficult to refine, and, in this context of this section, there are three other types of feedstocks that are worthy of mention: extra heavy oil, highacid crude oil, and opportunity crude oil (Table 4). Extra heavy oil is a nondescript term (related to viscosity) of little scientific meaning which is usually applied to oil sand bitumen, which is generally incapable of free flow under reservoir conditions. The general difference is that extra heavy oil, which may have properties similar to oil sand bitumen in the laboratory, unlike oil sand bitumen in the deposit, has some degree of mobility in the reservoir or deposit [25]. Extra heavy oils can flow at reservoir temperature and can be produced economically, without additional viscosity-reduction techniques, through variants of conventional processes such as long horizontal wells or multilaterals. This is the case, for instance, in the Orinoco basin (Venezuela) or in offshore reservoirs of the coast of Brazil, but once outside of the influence of the high reservoir temperature, these oils are too viscous at surface to be transported through conventional pipelines and require heated pipelines for transportation. Alternatively, the oil must be partially upgraded or fully upgraded or diluted with a light hydrocarbon (such as aromatic naphtha) to create a mix that is suitable for transportation. High-acid crude oil is crude oil that contain considerable proportions of naphthenic acids which, as commonly used in the petroleum industry, refers collectively to all of the organic acids present in the crude oil [26]. In many instances, the high-acid crude oils are the heavier crude oils. The total acid matrix is therefore complex, and it is unlikely that a simple titration, such as the traditional methods for measurement of the total

Petroleum and Oil Sand Exploration and Production

acid number, can give meaningful results to use in predictions of problems. An alternative way of defining the relative organic acid fraction of crude oils is therefore a real need in the oil industry, both upstream and downstream. Opportunity crude oils are either new crude oils with unknown or poorly understood properties relating to processing issues or are existing crude oils with well-known properties and processing concerns [27]. Opportunity crude oils are often, but not always, heavy crude oils but in either case are more difficult to process due to high levels of solids (and other contaminants) produced with the oil, high levels of acidity, and high viscosity (Table 5). These crude oils may also be incompatible with other oils in the refinery feedstock blend and cause excessive equipment fouling when processed either in a blend or separately. There is also the need for a recovery operations to be on guard to accommodate opportunity crude oils and/or high-acid crude oils which, for many general refining purposes, are often included in the term heavy feedstocks. Oil Mining Oil mining is the term applied to the surface or subsurface excavation of petroleum-bearing formations for subsequent removal of the heavy oil or bitumen by washing, flotation, or retorting treatments. Oil mining includes recovery of oil and/or heavy oil by drainage from reservoir beds to mine shafts or other openings driven into the rock or by drainage from the reservoir rock into mine openings driven outside the reservoir but connected with it by boreholes or mine wells. Oil mining methods should be applied in reservoirs that have significant residual oil saturation and have reservoir or fluid properties that make production by conventional methods inefficient or impossible. The high well density in improved oil mining usually compensates for the inefficient production caused by reservoir heterogeneity. However, close spacing of the production wells can also magnify the deleterious effects of reservoir heterogeneity. If a high-permeability streak exists with a lateral extent that is less than the inter-well spacing of

Petroleum and Oil Sand Exploration and Production

33

Petroleum and Oil Sand Exploration and Production, Table 4 Simplified differences between the various types of crude oil and tar sand bitumena Conventional crude oil Mobile in the reservoir; API gravity: >25
High-permeability reservoir Primary recovery and secondary recovery Tight oil Similar properties to the properties of conventional crude oil; API gravity: >25
Immobile in the reservoir Low-permeability reservoir (tight sands, tight shale formation) Horizontal drilling into reservoir and fracturing (typically multi-fracturing) to release fluids/gases Medium crude oil Similar properties to the properties of conventional crude oil; API gravity: 20–25
High-permeability reservoir Primary recovery and secondary recovery Opportunity crude oil May have similar properties to the properties of conventional crude oil API gravity: 20–25
High-permeability reservoir Primary recovery and secondary recovery Typically needs cleaning (processing) before refining because of contaminants Heavy crude oil More viscous than conventional crude oil; API gravity: 10–20
Mobile in the reservoir Recovery method: typically, enhanced oil recovery such as a steam-based process High-acid crude oil Can be equivalent to medium crude oil or heavy crude oil and recovered accordingly API gravity: (typically) 15–25
Total acid number (TAN) >0.5 mg KOH/ml of crude Extra heavy oil Similar properties to the properties of tar sand bitumen; API gravity: 5

35.0°N

35.0°N Oil Fields (4) Oil Fields (5)

km 0

121.0°W

25

0.7 50

120.5°W

0.9 1.1 b-value

120.0°W

1.3

km 0

119.5°W

119.0°W

25

0

5

10

15

50

No Frac. Wells 34.5°N 121.5°W 121.0°W 120.5°W 120.0°W 119.5°W 119.0°W 118.5°W

Hydraulic Fracturing, Fig. 7 Spatial variations in b-value in the study region (Left), color coded number of hydraulic fracturing in a few sizable oil and gas fields in San Joaquin Valley (Right)

(right) shows a few large oil fields with the color coded number of hydraulic fracturing jobs. The probability of activating faults due to anthropogenic influences is likely highest in regions where active faults, fluid injection wells, and low b-values have been encountered. This is the case, e.g., within the southern part of the study region. In the proximity of active faults, both different types of seismicity may occur and more detailed studies are required to differentiate induced from natural (tectonic) seismicity. Areas of relatively high b-values are likely connected to smaller ambient stresses and seismic events are less likely to grow to large sizes.

Assessment of Global Oil and Gas Resources Amenable for Extraction Via Hydraulic Fracturing Shale resources as well as tight oil and gas are known to exist in parts of Europe, Australia, Russia, China, and elsewhere, but this resource has not been fully characterized by test wells. National Energy Technology Laboratory (NETL) highlighted the technology developments that have led to the emergence of shale gas development in a large scale [36]. The US Energy Information Agency has published assessments of shale gas and oil resources in various countries and basins; according to the compilation published in 2015, the technically recoverable

wet shale gas and tight oil in 46 countries is 7,577 tcf and 419 billion barrels (Gbbl), respectively. These values are larger than the proved global reserves of 6,832 tcf of natural gas and 240 Gbbl of oil [37]. Shale gas resources in the USA, Canada, and Mexico are 623, 573, and 545 tcf, respectively. Outside North America, significant resources are present in China (1100 tcf), Argentina (800 tcf), Algeria (707 tcf), and Australia (430 tcf). Technically recoverable global tight oil resources are estimated at 419 bbl. Substantial tight oil resources are found in the USA (78 Gbbl), Russia (75 Gbbl), China (32 Gbbl), Libya (26 Gbbl), and the UAE (23 Gbbl). Whereas production of shale gas and oil in the US has been commercially deployed for over a decade now, it has not been widely deployed elsewhere. Factors limiting the development include public resistance to the technology, availability of adequate water, and lack of suitable geologic conditions. If the experience in the US is replicated in other countries, tight gas and oil resources could play a very large role in the global energy scene.

Economics of Hydraulic Fracturing The total investment for a hydraulic fracturing well must cover not only the cost of drilling and completing the well, but also of obtaining land

98

rights and permits. These costs vary with location, and there is a broad range of costs. According to the Energy Information Agency, the costs can range between three and ten million dollars a well. Depending on the geology, the wells produce different amounts of oil and gas, with oil being the more valuable product, and the one that determines the economics. There are wells that only produce gas, but, because there is already an oversupply of gas such that no new dry wells are being developed, only those with takeoff contracts are in production. It is a shame that the associated gas from oil-producing wells in Bakken and other basins are being flared for lack of pipeline infrastructure. For new HF wells, the average breakeven cost of crude oil from different basins currently ranges between $30 and $55 per bbl. The total cost depends on the geographic location, depth of the target, horizontal length of the well (offset), number of HF stages, and many other factors. For example, in the Wolfcamp Delaware basin, the average breakeven cost is $42/bbl, while in the Bakken basin it is $52. These costs are considerably lower than they were in 2008 (~$70/bbl), when fracking first became commercially viable, thanks to the spike in crude oil prices. Innovations such as methods for better locating resources, more efficient drilling, and multipad drilling have markedly reduced costs. In face of losing market share, in 2012, the Organization of the Petroleum Exporting Countries (OPEC) and Russia decided to increase their production and drive down the price of oil from $100/bbl to $50/bbl. At $50/bbl, producing conventional oil is still profitable. The expectation was that the competition would be driven out of business at this reduced price. However, because of the improved technologies, producing oil from many of tight formations was still profitable. Operations at those that were not profitable were simply turned off temporarily and could be brought on-line quickly when conditions became favorable. The rapidity with which HF wells can be turned off or brought back on stream is a game changer in the geopolitics of oil. Furthermore, the new focus on “refracking” to extend the life of the shale oil and gas fields may become a new normal.

Hydraulic Fracturing

See additional references on: What can microseismic tell us about HF [38], Geomechanical approach for microseismic fracture mapping [39], Finite element method based modeling of HF [40], Flowback of Fracturing Fluids with upgraded visualization of HF and its Implication of on Overall Well Performance [41], Simulation of Hydraulic Fracturing-Induced Permeability Stimulation using Coupled Flow and Continuum Damage Mechanics [42] and Oil, the Next Revolution [43].

Future Work In spite of many advances made in different aspects of HF, many new technologies need to be developed and implemented in order to make the operation more efficient, reduce cost, and minimize its environmental footprint. A few areas requiring further attention are highlighted below: (a) To improve the operational aspects of HF, a better understanding of the reservoir parameters and geology is important. More effective use of machine learning techniques for optimum well placement and determining the best parameters for multistage fracking is crucial. One such idea involves DNA fingerprinting where different types of data are fused to improve the HF operation [44]. (b) Given the short lived impact of HF, “refracking” is often required after a period of time (1–3 years from the original operation). This presents another opportunity for future research to make optimum re-fracking decisions. (c) “Shock-Waves” or super waves [45] and Pulsed Power Plasma Stimulation [46] are being considered as an alternative approach to create similar or better results as the conventional HF. These approaches aim at different stimulation techniques that do not require the injection of water or the use of chemical additives. They promise to reduce cost with more favorable operational conditions and less negative environmental impacts.

Hydraulic Fracturing

(d) Aside from the waterless/chemical-less possibilities for HF, many artificial neural network and AI based approaches are being considered for an optimum fresh water use management and recycling the frack-fluid. Best management practices must be developed that will reduce fresh water requirements, disposal challenges, and environmental impacts including truck traffic, site congestion, and exposure to harmful chemicals by promoting recovery and re-use of produced water for well drilling and completion applications using best practices. This is of special importance where water supplies are limited and environmental regulations are limited. (e) In many situations, a good portion of the injected HF liquid (FP) returns to the surface with the oil and natural gas being produced. Research should continue to further characterize these returned liquids and establish safe methods for treating/disposing of them. In the meantime, less hazardous HF fluids should continue to be explored iteratively, with their use potential characterized within a lifecycle framework. Energy intensive aspects of treatment of FP to safely return water to the local environment should also be addressed.

Bibliography 1. National Academy of Sciences (2012) Induced Seismicity Potential in Energy Technologies. https://www. nap.edu/resource/13355/Induced-Seismicity-ReportBrief-Final.pdf 2. King GE (2012) Hydraulic fracturing 101: what every representative, environmentalist, regulator, reporter, investor, university researcher, neighbor and engineer should know about estimating frac risk and improving frac performance in unconventional gas and oil. In: SPE 152596, SPE hydraulic fracturing technology conference 3. California Council on Science and Technology (2016) Advanced well stimulation technologies in California: an independent review of scientific and technical information, July 2016. https://ccst.us/wpcontent/uploads/160708-blm-report.pdf 4. Colorado Oil & Gas Conservation Commission (2011) Frequently asked questions about hydraulic fracturing. https://cogcc.state.co.us/Announcements/ Hot_Topics/Hydraulic_Fracturing/Frequent_Questions_ about_Hydraulic%20Fracturing.pdf

99 5. U.S. Energy Information Administration (2018) Petroleum and other liquids data. https://www.eia.gov/petro leum/data.php#crude 6. BP Statistical Review of Global Energy (2017) https:// www.bp.com/en/global/corporate/energy-economics/ statistical-review-of-world-energy.html 7. Baker Hughes (2017) Baker Hughes rig count. http:// phx.corporate-ir.net/phoenix.zhtml?c=79687&p=irolrigCountOverview 8. FT (2018) https://www.ft.com/content/a8314d060741-11e8-9650-9c0ad2d7c5b5 9. DOE’s Unconventional Gas Research Programs 1976–1995. https://geographic.org/unconventional_ gas_research/eastern_gas.html 10. Minh-Thong Le (2018) An assessment of the potential for the development of the shale gas industry in countries outside of North America. Heliyon 4:e00516. https://doi.org/10.1016/j.heliyon.2018.e00516 11. Warpinski NR, Mayerhofer MJ, Vincent MC, Cipolla CL, Lolon EP (2009) Stimulating unconventional reservoirs: maximizing network growth while optimizing fracture conductivity. J Can Pet Technol 48(10):39–51. SPE-114173-PA. https://doi.org/ 10.2118/114173-PA 12. Lacazette A, Vermilye J, Fereja S, Sizking C (2013) Ambient fracture imaging: a new passive seismic method. In: Unconventional resources technology conference (URTeC), Denver, 12–14 Aug 2013 13. Maity D, Salehi I, Ciezobka J (2014) Semblance weighted emission mapping for improved hydraulic fracture treatment characterization. In: SEG annual meeting, Denver, 26–31 Oct 2014 14. Das I, Zoback MD (2013) Long-period long-duration seismic events during hydraulic stimulation of shale and tight-gas reservoirs – Part 2: location and mechanisms. Geophysics 78(6):KS97–KS105 15. Maity D, Aminzadeh F (2015) Novel fracture zone identifier attribute using geophysical and well log data for unconventional reservoirs. Interpretation 3(3):T155–T167. https://pdfs.semanticscholar.org/ 0ccb/4a21a8dd7d4a4b1bb2be4f8ce0192811aa9e.pdf 16. Wessels S, Kratz M, Pena ADL (2011) Identifying fault activation during hydraulic stimulation in the Barnett shale: source mechanisms, b values, and energy release analysis of microseismicity. In: SEG annual meeting, San Antonio, 18–23 Sept 17. Maity D, Ciezobka J (2018) Correlating microseismicity with relevant geophysical and petrophysical data to understand fracturing process during hydraulic stimulation: a case study from the Permian Basin. In: SEG annual meeting, Anaheim, 15–19 Oct 18. Ciezobka J, Courtier J, Wicker J (2018) Hydraulic fracturing test site (HFTS) – project overview and summary of results. In: Unconventional resources technology conference (URTeC), Houston, 23–25 July 19. Maity D, Ciezobka J, Eisenlord S (2018) Assessment of in-situ proppant placement in SRV using throughfracture core sampling at HFTS. In: Unconventional resources technology conference (URTeC), Houston, 23–25 July

100 20. Ante MA, Manjunath GL, Aminzadeh F, Jha B (2018) Microscale laboratory studies for determining fracture directionality in tight sandstone and shale during hydraulic fracturing. In: Unconventional resources technology conference (URTeC), Houston, 23–25 July 2018. https://doi.org/10.15530/urtec2018-2903021 21. Maity D, Aminzadeh F (2013) A new approach towards optimized passive seismic survey design with simultaneous borehole and surface measurements. In: Joint PSAAPG/SPE/PSSEPM/PCS-SEG conference, Monterey, 19–25 Apr 2013 22. Boroumand N, Eaton D (2016) Interpreting microseismic data from hydraulic fracturing: understanding subsurface deformation through numerical modeling, recorder. Can Soc Explor Geophys 41(09) 23. Eyre TS, Van Der Baan M (2015) Introduction to moment tensor inversion of microseismic events. In: GeoConvention, Calgary, 4–8 May 2015 24. Tan Y, Engelder T (2016) Further testing of the bedding-plane-slip model for hydraulic-fracture opening using moment-tensor inversions. Geophysics 81(5). https://library.seg.org/doi/10.1190/geo2015-0370.1 25. EPA (2018) http://science.sciencemag.org/content/ early/2018/06/20/science.aar7204 26. Jabbari N, Aminzadeh F, de Barros F (2016) Hydraulic fracturing and the environment, risk assessment for groundwater contamination. Stoch Environ Res Risk Assess 30:10. https://doi.org/10.1007/s00477-0161280-0 27. Jabbari N, Aminzadeh F, de Barros F (2015) Assessing the groundwater contamination potential from a well in a hydraulic fracturing operation. J Sustain Energy Eng 3(1):66–79 28. Eisenlord S, Hayes T, Perry K (2018) Environmental impact analysis on the hydraulic fracture test site (HFTS). In: Unconventional resources technology conference (URTeC), Houston, 23–25 July 29. Ceres (2016) Hydraulic fracturing & water stress: water demand by the numbers. https://www. ceres.org/resources/reports/hydraulic-fracturing-waterstress-water-demand-numbers 30. Fracking in Texas, Ballotpedia. https://ballotpedia. org/Fracking_in_Texas 31. Lebas R, Lord P, Luna D et al (2013) Development and use of high-TDS recycled produced water for crosslinked-gel-based hydraulic fracturing. Presented at the SPE hydraulic fracturing technology conference, Woodlands, 4–6 Feb. SPE-163824-MS. https://doi. org/10.2118/163824-MS 32. Hydralicfracturing.com (2018) http://www.hydraulic fracturing.com/#/?section=air-emissions 33. Petersen MD, Moschetti MP, Powers PM, Mueller CS, Haller KM, Frankel AD, Zeng Y, Rezaeian S, Harmsen SC, Boyd OS, Field N, Chen R, Rukstales KS, Luco N, Wheeler RL, Williams RA, Olsen AH (2014) Documentation for the 2014 update of the

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United States national seismic hazard maps. U.S. Geological Survey open-file report 2014–1091, 243p. https://doi.org/10.3133/ofr20141091. URTeC: 2903021 Aminzadeh F, Goebel THW (2013) Identifying induced seismicity in active tectonic regions: a case study of the San Joaquin Basin, California. AGU fall meeting, Abstract: S31F-06, San Francisco Goebel THW, Hosseini SM, Cappa F, Hauksson E, Ampuero JP, Aminzadeh F, Saleeby JB (2016) Wastewater disposal and earthquake swarm activity at the southern end of the Central Valley, California. Geophys Res Lett 43. https://doi.org/10.1002/ 2015GL066948 NETL (2011) https://www.netl.doe.gov/file%20library/ research/oil-gas/Shale_Gas_March_2011.pdfNetl https://www.eia.gov/analysis/studies/worldshalegas/, BP 2018 Maxwell S (2014) What can microseismic tell us about hydraulic fracturing? In: AAPG/SEG/SPWLA Hedberg conference, Austin, 7–11 Dec 2014 Hosseini M, Aminzadeh F (2014) A geomechanical approach for microseismic fracture mapping. In: AAPG/SEG/SPWLA Hedberg conference, Austin, 7–11 Dec 2014 Khodabakhshnejad A, Aminzadeh F (2014) An extended finite element method based modeling of hydraulic fracturing. In: AAPG/SEG/SPWLA Hedberg conference, Austin, 7–11 Dec 2014 Desi K, Aminzadeh F (2016) Flowback of fracturing fluids with upgraded visualization of hydraulic fracturing and its implication of on overall well performance. J Sustain Energy Eng 4(3–4):250–261 Samnejad M, Aminzadeh F, Jha B (2017) Simulation of hydraulic fracturing-induced permeability stimulation using coupled flow and continuum damage mechanics, SPE-187250-MS. In: ATCE conference in San Antonio, 9–11 Oct 2017 Maugeri L (2012) Oil, the next revolution. Discussion paper 2012-10, Belfer Center for Science and International Affairs, Harvard Kennedy School, June 2012 Aminzadeh F, Ranjith R, Lingareddy M, Suhag A, Jha B, Alimi H (2017) DNA fingerprinting to optimize reservoir characterization and hydraulic fracturing, using machine learning based integration of geophysics, geochemistry and geomechanics with machine learning. Provisional patent, D2018-0109, University of Southern California Biennier L, Jayaram V, Suas-David N, Georges R, Kiran Singh M, Arunan E, Kassi S, Dartois E, Reddy KPJ (2017) Shock-wave processing of C60 in hydrogen. Astron Astrophys. https://doi.org/10.1051/00046361/201629067 Xiao Y, House W, Unal E, Soliman M (2017) Pulsed power plasma stimulation technique – experimental study on single pulse test for fracture initiation. ISH J Hydraul Eng 4(3):67–74

Petroleum Refining and Environmental Control and Environmental Effects James G. Speight CD&W Inc., Laramie, WY, USA

Recovery Recovery of petroleum at the surface using primary, secondary, and tertiary recovery methods. Tar sand mining Recovery of tar sand by mining (digging) tar sand from the formations at or close to the surface.

Definition of the Subject Article Outline Glossary Definition of the Subject Introduction Refinery Processes Environmental Regulations and Pollutants Refinery Emissions Entry into the Environment Toxicity Managing Wastes and Future Directions Bibliography

Glossary Bitumen A semi-solid to solid hydrocarbonaceous material found filling pores and crevices of sandstone, limestone, or argillaceous sediments such as tar sand. Exploration The search for petroleum using a variety of physical and spectrographic methods. Hot water process The recovery of bitumen from tar sand by use of hot water whereby the bitumen floats and the sand sinks. In situ conversion Partial or complete conversion of heavy oil or tar sand bitumen in the reservoir or deposit as part of the recovery process. Oil mining The recovery of petroleum using a mining method whereby an underground chamber is produced by mining and the oil is allowed or encouraged to drain into the chamber.

The work summarizes the various processes and the process emissions that occur during crude oil refining. There are also general descriptions of the various pollution, health, and environmental problems especially specific to the crude oil industry and places in perspective government laws and regulations as well as industry efforts to control these problems.

Introduction Despite the numerous safety protocols that are in place and the care taken to avoid incidents that affect the environment, virtually every industry suffers accidents that lead to environmental problems, to complexities, and to chemical contamination. And this does not include environmental contamination from domestic source! Furthermore, it must be recognized that the capacity of the environment to absorb effluents from crude oil processing and the use of the products are not unlimited. In fact, the environment is an extremely limited resource, and discharge of chemical emissions into it should be subject to severe constraints. Thus, it is necessary to understand the nature and magnitude of the problems involved [1]. Hence, in the current context, there is an essential need for control over the amounts and types of emissions from the use of crude oil and its products. Crude oil (petroleum) is a major energy source in many parts of the world and will continue to be a primary source of energy for the next several

© Springer Science+Business Media, LLC, part of Springer Nature 2020 R. Malhotra (ed.), Fossil Energy, https://doi.org/10.1007/978-1-4939-9763-3_70 Originally published in R. A. Meyers (ed.), Encyclopedia of Sustainability Science and Technology, © Springer Science+Business Media, LLC, part of Springer Nature 2017, https://doi.org/10.1007/978-1-4939-2493-6_70-3

101

102

Petroleum Refining and Environmental Control and Environmental Effects C1 To C4 Crude Unit

Naphtha

Reformate

Hydro– Treating

Reforming

Alkylation

Diesel and Jet Fuel

Hydro– Treating

Atmospheric Distillation

Alkylate

Gasoline Hvy Atm Gas Oil

FCC Feed Hydro– Refining

Fluidized Catalytic Cracking

Fuel Oil

Vacuum Distillation

Lt Vac Gas Oil Hydrocracking

Hvy VGO Resid

Fuel Gas and Coker Gasoline Thermal Processing

Coke Hydrogen Sulfide–containing Gas

Sulfur Complex

Sulfur

Petroleum Refining and Environmental Control and Environmental Effects, Fig. 1 Schematic overview of a refinery

decades. However, considering the composition of crude oil and the products arising therefrom, it is not surprising that crude oil itself and crude oil-derived products can have adverse effects on the environment. Crude oil, in the unrefined or crude form, like many industrial feedstocks, has little or no direct use, and its value as an industrial commodity is only realized after the production of salable products by a series of refining steps (Fig. 1). Each refining step is, in fact, a separate process and thus a refinery is a series of integrated process units that generate the desired products to meet the demands of the market. Therefore, the value of petroleum is directly related to the yield of products and is subject to the call of the market. In general, crude oil, once refined by a variety of process units, yields salable products. The purpose of this article is to summarize the typical refinery processes and to present the various pollution, health, and environmental problems that are especially specific to the crude oil refining industry and to briefly present the government laws and regulations (of the United States) as well as industry efforts to control these problems [2–5].

Refinery Processes Crude oil refining is a complex sequence of chemical and physical changes that result in the production of a variety of products (Table 1) (Fig. 1). In fact, crude oil refining might be considered as a collection of individual, yet related, processes that are each capable of producing effluent streams. Moreover, refining crude oil, as it is currently known, will continue at least for the next several decades. Crude oil refining consists of, initially unless properties dictate otherwise, dividing the petroleum into fractions of different boiling ranges by distillation. Other forms of treatment are utilized during the refining process to remove undesirable components of the crude oil. The fractions themselves are often further distilled to produce the desired commercial product. A variety of additives may be incorporated into some of the refined products to adjust the octane ratings or improve engine performance characteristics. In terms of individual processes, the potential for waste generation and, hence, leakage of emissions rests with all refining units, and special care must be taken to ensure the security of the environment.

Petroleum Refining and Environmental Control and Environmental Effects

103

Petroleum Refining and Environmental Control and Environmental Effects, Table 1 Summary of refinery processes Process name Action (i) Separation processes Desalting Separation Atmospheric Separation distillation Vacuum Separation distillation (ii) Conversion processes Catalytic Alteration cracking Coking Polymerize

Method

Purpose

Feedstock(s)

Product(s)

Nonthermal Thermal

Remove brine Separate fractions without cracking Separate fraction without cracking

Crude oil Desalted crude oil Atmospheric residuum

Clean crude oil Gas, gas oil, distillate, residuum Gas oil, lube stock, residuum

Catalytic

Upgrade gasoline

Thermal

Convert residuum

Gas oil, residuum Residuum

Naphtha, petrochemical feedstocks Naphtha, petrochemical feedstocks Lower-boiling, highquality products

Thermal

Hydrocracking

Hydrogenation

Catalytic

Produce lowerboiling products

Visbreaking

Decomposition

Thermal

Reduce viscosity

(iii) Skeletal alteration processes Alkylation Combining

Catalytic

Polymerization

Catalytic

Combine olefin and iso-paraffin Combine two or more olefins

Polymerize

Desalting Crude oil often contains water, inorganic salts, suspended solids, and water-soluble trace metals. As a first step in the refining process, to reduce corrosion, plugging, and fouling of equipment and to prevent poisoning the catalysts in processing units, these contaminants must be removed by desalting (dehydration). The two most typical methods of crude oil desalting are (i) chemical separation and (ii) electrostatic separation. In chemical desalting, water and chemical surfactant (demulsifiers) are added to the crude oil, heated so that salts and other impurities dissolve into the water or attach to the water, and then held in a tank where they settle out. Electrical desalting is the application of high-voltage electrostatic charges to concentrate suspended water globules in the bottom of the settling tank. Surfactants are added only when the crude oil contains suspended solids. A third and less common process involves filtering heated crude oil using diatomaceous earth. In the desalting process, the feedstock crude oil is heated to between 65 and 177
C (150
and

Gas oil, cracked oil, residual Atmospheric tower resid Iso-butane/ olefin Cracked olefins

Distillate, cracked residuum Iso-octane (alkylate) High-octane naphtha, petrochemical feedstocks

350
F) to reduce viscosity and surface tension for easier mixing and separation of the water, but the temperature is limited by the vapor pressure of the crude oil constituents. In both methods, other chemicals may be added – ammonia is often used to reduce corrosion, and caustic or acid may be added to adjust the pH of the water wash. Wastewater and contaminants are discharged from the bottom of the settling tank to the wastewater treatment facility, while the desalted crude is continuously drawn from the top of the settling tanks and sent to the crude distillation tower. The process creates an oily sludge that may, depending upon the constituents, be a hazardous waste and a high-temperature salt wastewater stream (i.e., sent for treatment with other refinery wastewaters). The primary polluting constituents in desalter wastewater include hydrogen sulfide, ammonia, phenol, high levels of suspended solids, and dissolved solids, with a high biochemical oxygen demand (BOD). In some cases, it is possible to recycle the desalter effluent water back into the

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Petroleum Refining and Environmental Control and Environmental Effects

Petroleum Refining and Environmental Control and Environmental Effects, Table 2 Different generic boiling fractions separated from crude oil by distillation Fraction Light naphtha Medium naphtha Heavy naphthab Kerosenec Light gas oil Heavy gas oil Lubricating oil Vacuum gas oil Residuum

Boiling rangea
C 1 to 150 50–180 150–205 205–260 260–315 315–425 >400 425–600 >510




F 30–300 120–355 300–400 400–500 400–600 600–800 >750 800–1100 >950

Petroleum Refining and Environmental Control and Environmental Effects, Table 3 Properties of the various fuel oils Fuel oil No. 1 fuel oil

No. 2 fuel oil

a

For convenience, boiling ranges are converted to the nearest 5
b Sales gasoline is a product produced by blending several streams, including naphtha c Kerosene destined for conversion to diesel fuel; crude kerosene is often quoted as having a wider boiling range (150–350
C, 302–662
F) before separation into various fuel and/or solvent products

desalting process, depending upon the type of crude being processed. Regulations are in place that set the maximum contamination concentration levels that are designed to ensure environmental safety. The inorganic chemicals that occur in desalter effluents include salts of calcium, magnesium, sodium, and potassium with lesser amounts of copper, iron, manganese, and zinc that include bicarbonates, carbonates, chlorides, and sulfates. Other factors include the pH (alkalinity/acidity of the stream), hardness, electrical conductivity, total dissolved solids, and surfactants. A high level of any of these three chemicals in the soil or in the water is an indication that one or more specific processes (identified from the chemicals that have been released) or pollution prevention processes are not performing as required by operational specifications. Distillation Atmospheric and vacuum distillation units are closed processes, and exposure to hazardous materials is expected to be minimal. The output of both units are product streams of various boiling ranges (Table 2). The residua that are produced by distillation are the results of a

No. 4 fuel oil

No. 5 fuel oil No. 6 fuel oil

Properties Similar to kerosene or range oil (fuel used in stoves for cooking) Defined as a distillate intended for vaporizing in pot-type burners and other burners where a clean flame is required Often called domestic heating oil Properties are similar to diesel and higherboiling jet fuels Defined as a distillate for general purpose heating in which the burners do not require the fuel to be completely vaporized before burning A light industrial heating oil that is intended where preheating is not required for handling or burning Two grades that differ primarily in safety (flash) and flow (viscosity) properties A heavy industrial oil that often requires preheating for burning and, in cold climates, for handling A heavy residuum oil Commonly referred to as Bunker C oil when it is used to fuel ocean-going vessels Preheating is required for both handling and burning this oil

concentration process on nonvolatile constituents and contain significantly less hydrocarbon constituents than the original crude oil. The constituents of residua may, depending on the crude oil, be molecular entities of which the majority contains at least one heteroatom. Air emissions from a crude oil distillation unit include emissions from the combustion of fuel oils (Table 3) in process heaters and boilers, fugitive emissions of volatile constituents in the crude oil and fractions, and emissions from process vents. The primary source of emissions is combustion of fuels in the crude preheat furnace and in boilers that produce steam for process heat and stripping. When operating in an optimum condition and burning cleaner fuels (e.g., natural gas, refinery gas), these heating units create relatively low emissions of sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO), hydrogen sulfide (H2S), particulate matter, and volatile

Petroleum Refining and Environmental Control and Environmental Effects

hydrocarbons. If fired with lower-grade fuels (e.g., refinery fuel pitch, coke) or operated inefficiently (incomplete combustion), heaters can be a significant source of emissions. Fugitive emissions of volatile hydrocarbons arise from leaks in valves, pumps, flanges, and other similar sources where crude and its fractions flow through the system. While individual leaks may be minor, the combination of fugitive emissions from various sources can be substantial. Those potentially released during crude distillation include ammonia, benzene, toluene, and xylenes, among others. These emissions are controlled primarily through leak detection and repair programs and occasionally using special leak resistant equipment. When sour (high-sulfur) crude oil is processed, there is an increased potential for exposure to hydrogen sulfide in the preheat exchanger and furnace, tower flash zone and overhead system, vacuum furnace and tower, and bottoms exchanger. Hydrogen chloride (arising from the brine in the original crude oil) may be present in the preheat exchanger, tower top zones, and overheads. Wastewater may contain water-soluble sulfides in high concentrations and other watersoluble compounds such as ammonia, chlorides, phenol, mercaptans, etc., depending upon the crude feedstock and the treatment chemicals. Safe work practices and/or the use of appropriate personal protective equipment may be needed for exposures to chemicals and other hazards, such as heat and noise, and during sampling, inspection, maintenance, and turnaround activities. The primary source of emissions is combustion of fuels in the crude preheat furnace and in boilers that produce steam for process heat and stripping. In addition to the expected emissions from the crude oil, the distillation units generate considerable wastewater. The process water used in distillation often comes in direct contact with oil and can be highly contaminated. The typical constituents of sour wastewater streams from crude distillation include hydrogen sulfide, ammonia, suspended solids, chlorides, mercaptans, and phenol, characterized by a high pH (i.e., high alkalinity). Both atmospheric distillation and vacuum distillation produce an oily sour wastewater

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(condensed steam containing hydrogen sulfide and ammonia) from side stripping fractionators and reflux drums. Many refineries now use vacuum pumps and surface condensers in place of barometric condensers to eliminate the generation of the wastewater stream and reduce energy consumption. Reboiler side-stripping towers rather than open steam stripping can also be utilized on the atmospheric tower to reduce the quantity of sour water condensate. Visbreaking and Coking Visbreaking (viscosity reduction, viscosity breaking), a mild form of thermal cracking, is used to produce more desirable and valuable products. The process is a relatively mild, liquid-phase thermal cracking process used to convert heavy, highviscosity feedstocks to lower viscosity fractions suitable for use in heavy fuel oil. A secondary benefit from the visbreaking operation is the production of naphtha and gas oil streams that usually have higher product values than the visbreaker charge. Visbreaking also produces a small quantity of hydrocarbon gases and a larger amount of gasoline and remains a process of promise for heavy feedstocks [6, 7]. The process can also be used as the preliminary (pretreatment) step for upgrading heavy feedstocks [8]. In this type of process, the heavy feedstock is first thermally cracked using visbreaking or hydrovisbreaking technology to produce a product that is lower in molecular weight and boiling point than the feed. The product is then deasphalted using an alkane solvent at a solvent to feed ratio of less than two wherein separation of solvent and deasphalted oil from the asphaltenes is achieved using a two-stage membrane separation system in which the second stage is a centrifugal membrane. Like many thermal cracking processes, visbreaking tends to produce a relatively small amount of fugitive emissions and sour wastewater [9, 10]. Usually some wastewater is produced from steam strippers and the fractionator. Wastewater is also generated during unit cleanup and cooling operations and from the steam injection process to remove organic deposits from the soaker or from the coil. Combined wastewater

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Petroleum Refining and Environmental Control and Environmental Effects

flows from thermal cracking, and coking processes are approximately three gallons per barrel of process feed. Propylene (CH3CH=CH2; b.p. –48
C, 54
F), another source of toxic releases from refineries, is produced during cracking and coking processes. In addition to being a gas, propylene has a measurable solubility in water which increases the potential for release to both air and water during processing. Coking is a thermal process for the continuous conversion of residua into lower-boiling products. The feedstock can be atmospheric residuum, vacuum residuum, or cracked residuum, and the products are gases, naphtha, fuel oil, gas oil, and coke. Coking processes generally utilize longer reaction times than thermal cracking processes, and to accomplish this, drums or chambers (reaction vessels) are employed, but it is necessary to use two or more such vessels so that coke removal can be accomplished in those vessels not on-stream without interrupting the semicontinuous nature of the process. Gas oil may be the major product of a coking operation and serves primarily as a feedstock for catalytic cracking units. The coke can be used as fuel, but processing for specialty uses, such as electrode manufacture, production of chemicals, and metallurgical coke, is also possible. For these latter uses, the coke may require treatment to remove sulfur and metal impurities – calcined petroleum coke can be used for making anodes for aluminum manufacture and a variety of carbon or graphite products such as brushes for electrical equipment. Delayed coking is the oldest, most widely used process and has changed very little in the five or more decades in which it has been on stream in refineries. Fluid coking is a continuous fluidized solids process that cracks feed thermally over heated coke particles in a reactor vessel to gas, liquid products, and coke. Heat for the process is supplied by partial combustion of the coke, with the remaining coke being drawn as product. The new coke is deposited in a thin fresh layer on the outside surface of the circulating coke particle. Coking processes produce a relatively small amount of sour wastewater from steam strippers and fractionators. Wastewater is generated during coke removal and cooling operations and from the

steam injection process to cut coke from the coke drums. Combined wastewater flows from thermal cracking, and coking processes are approximately three gallons of water per barrel of feedstock. Like most separation processes in the refinery, the process water used in coker fractionators (as is also the case in other product fractionators) often comes in direct contact with oil and can have a high oil content (much of that oil can be recovered through wastewater oil recovery processes). Thus, the main constituents of sour water from catalytic cracking include high levels of oil, suspended solids, phenols, cyanides, hydrogen sulfate, and ammonia. Typical wastewater flow from catalytic cracking is about 15.0 gallons per barrel of feed processed (more than one-third of a gallon of wastewater for every gallon of feed processed) and represents the second largest source of wastewater in the refinery. Particulate emissions from the decoking operations can be considerable. Coke-laden water from decoking operations in delayed cokers (hydrogen sulfide, ammonia, suspended solids) and coke dust (carbon particles and hydrocarbons) occurs. Fluid Catalytic Cracking Catalytic cracking is widely used to convert heavy oils into more valuable naphtha (a blend stock for gasoline manufacture) and other low-boiling products. As the demand for gasoline increased, catalytic cracking replaced thermal cracking with the evolution of catalytic cracking. Fluid catalytic cracking (FCC) refers to the behavior of the catalyst during this process insofar as the fine, powdered catalyst (typically zeolites, which have a particle size on the order of 70 m) takes on the properties of a fluid when it is mixed with the vaporized feed. Fluidized catalyst particles circulate continuously between the reaction zone and the regeneration zone. In terms of process parameters, catalytic cracking is typically performed at temperatures ranging from 485 to 540
C (900–1,000
F) and pressures up to 100 psi. Feedstocks for the process have typically been gas oil fractions, but the focus is shifting to gas oil-residua blends, gas oil-heavy oil blends, and gas oil-bitumen [11]. In some cases, heavy oils have

Petroleum Refining and Environmental Control and Environmental Effects

been blended with the minimum amount of gas oil (added as a flux) as the feedstock to catalytic cracking units. In the process, the feedstock enters the unit at temperatures on the order of 485–540
C (900–1,000
F), and the circulating catalyst provides heat from the regeneration zone to the oil feed. Carbon (coke) is burned off the catalyst in the regenerator, raising the catalyst temperature from 620 to 735
C (1,150–1,350
F), before the catalyst returns to the reactor. Fluid catalytic cracking units are major sources of air emissions in refineries [5]. Air emissions are released in process heater flue gas, as fugitive emissions from leaking valves and pipes, and during regeneration of the cracking catalyst. If not controlled, catalytic cracking is one of the most substantial sources of carbon monoxide and particulate emissions in the refinery. In non-attainment areas where carbon monoxide and particulates are above acceptable levels, carbon monoxide waste heat boilers and particulate controls are employed. Carbon monoxide produced during regeneration of the catalyst is converted to carbon dioxide either in the regenerator or further downstream. Catalytic crackers are also significant sources of sulfur oxides and nitrogen oxides. The nitrogen oxides produced by catalytic crackers are expected to be a major target of emission reduction in the future. Catalytic cracking units, like coking units, usually include some form of fractionation or steam stripping as part of the process configuration. These units all produce sour waters and sour gases containing some hydrogen sulfide and ammonia. Like crude oil distillation, some of the toxic releases reported by the refining industry are generated through sour water and gases, notably ammonia. Gaseous ammonia often leaves fractionating and treating processes in the sour gas along with hydrogen sulfide and fuel gases [5]. Catalytic cracking (primarily fluid catalytic cracking) generates considerable sour wastewater from fractionators used for product separation, from steam strippers used to strip oil from catalysts, and in some cases from scrubber water. The steam stripping process used to purge and regenerate the catalysts can contain metal impurities from the feed in addition to oil and other contaminants. Sour

107

wastewater from the fractionator/gas concentration units and steam strippers contain oil, suspended solids, phenols, cyanides, hydrogen sulfide, ammonia, spent catalysts (metals) and hydrocarbons. Catalytic cracking generates significant quantities of spent process catalysts (containing metals from crude oils and hydrocarbons) that are often sent off-site for disposal or recovery or recycling. Management options can include land filling, treatment or separation and recovery of the metals. Metals deposited on catalysts are often recovered by third-party recovery facilities. Spent catalyst fines (containing aluminum silicate and metals) from electrostatic precipitators are also sent off-site for disposal and/or recovery options. Catalytic crackers also produce a significant amount of fine catalyst dust that results from the constant movement of catalyst grains against each other. This dust contains primarily alumina (Al2O3) and small amounts of nickel (Ni) and vanadium (V) and is generally carried along with the carbon monoxide stream to the carbon monoxide waste heat boiler. The dust is separated from the carbon dioxide stream exiting the boiler using cyclones, flue gas scrubbing, or electrostatic precipitators. Hydrocracking and Hydrotreating Hydrocracking is a refining technology in which the outcome is the conversion of a variety of feedstocks to a range of products, and units to accomplish this goal can be found at various points in a refinery (Fig. 1) [12, 13, 14]. The concept of hydrocracking allows the refiner to produce products having a lower molecular weight with a higher hydrogen content and a lower yield of coke. In summary, hydrocracking facilities add flexibility to refinery processing and to the product slate. Hydrocracking is more severe than hydrotreating there being the intent, in hydrocracking processes, to convert the feedstock to lower-boiling products rather than to treat the feedstock for heteroatom and metal removal only. Hydrocracking generates air emissions through process heater flue gas, vents, and fugitive emissions [5]. Unlike fluid catalytic cracking catalysts, hydrocracking catalysts are usually regenerated off-site after months or years of operations, and little or no emissions or dust are

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Petroleum Refining and Environmental Control and Environmental Effects

generated. However, the use of heavy oil as feedstock to the unit can change this balance. Hydrocracking produces less sour wastewater than catalytic cracking. Hydrocracking, like catalytic cracking, produces sour wastewater at the fractionator. These processes include processing in a separator (API separator, corrugated plate interceptor) that creates sludge [5]. Physical or chemical methods are then used to separate the remaining emulsified oils from the wastewater. Treated wastewater may be discharged to public wastewater treatment, to a refinery secondary treatment plant for ultimate discharge to public wastewater treatment, or may be recycled and used as process water. The separation process permits recovery of usable oil and creates a sludge that may be recycled or treated as a hazardous waste. In addition, oily sludge from the wastewater treatment facility that result from treating sour wastewaters may be hazardous wastes (unless they are recycled in the refining process). These include API separator sludge, primary treatment sludge, sludge from various gravitational separation units, and float from dissolved air flotation units. Like catalytic cracking, hydrocracking processes generate toxic metal compounds, many of which are present in spent catalyst sludge and catalyst fines generated from catalytic cracking and hydrocracking. These include metals such as nickel (Ni), cobalt (Co), and molybdenum (Mo). Hydrotreating is the less severe removal of heteroatomic species by treatment (milder than hydrocracking) of a feedstock or product in the presence of hydrogen [5]. The character of the hydrotreating processes is chemically very simple since they essentially involve removal of sulfur and nitrogen as hydrogen sulfide and ammonia, respectively: Sfeedstock þ H2 ! H2 S 2Nfeedstock þ 3H2 ! 2NH3 However, nitrogen is the most difficult contaminant to remove from feedstocks, and processing conditions are usually dictated by the requirements for nitrogen removal. In general, any catalyst capable of participating in hydrogenation reactions may be used for

hydrodesulfurization. The sulfides of hydrogenating metals are particularly used for hydrodesulfurization, and catalysts containing cobalt, molybdenum, nickel, and tungsten are widely used on a commercial basis. Hydrotreating catalysts are usually cobalt-molybdenum catalysts, and under the conditions whereby nitrogen removal is accomplished, desulfurization usually occurs as well as oxygen removal. Indeed, it is generally recognized that fullest activity of the hydrotreating catalyst is not reached until some interaction with the sulfur (from the feedstock) has occurred, with part of the catalyst metals converted to the sulfides. Too much interaction may of course lead to catalyst deactivation. The hydrotreating process generates air emissions through process heater flue gas, vents, and fugitive emissions [5]. Unlike fluid catalytic cracking catalysts, hydrotreating catalysts are usually regenerated off-site after months or years of operations, and little or no emissions or dust are generated from the catalyst regeneration process at the refinery. The off-gas stream from hydrotreating is usually very rich in hydrogen sulfide and light fuel gas. This gas is usually sent to a sour gas treatment and sulfur recovery unit along with other refinery sour gases. Fugitive air emissions of volatile components released during hydrotreating may also be toxic components. These include benzene, toluene, and the xylene isomers (BTX), and other volatiles that are considered to be toxic chemical releases under the EPA Toxics Release Inventory [15, 16]. Hydrotreating also produces some residual materials in the form of spent catalyst fines, usually consisting of aluminum silicate and some metals (e.g., cobalt, molybdenum, nickel, tungsten). Spent hydrotreating catalyst is now listed as a hazardous waste (except for most support material). Hazardous constituents of this waste include benzene and arsenia (arsenic oxide, As2O3). The support material for these catalysts is usually an inert ceramic (e.g., alumina, Al2O3). Hydrotreating generates sour wastewater from fractionators used for product separation. Like most separation processes in the refinery, the process water used in fractionators often comes in direct contact with oil and can be highly contaminated. It also contains hydrogen sulfide and ammonia and must be treated along with other refinery sour

Petroleum Refining and Environmental Control and Environmental Effects

waters. Oily sludge from the wastewater treatment facility that result from treating oily and/or sour wastewaters from hydrotreating and other refinery processes may be hazardous wastes, depending on how they are managed. These include API separator sludge, primary treatment sludge, sludge from various gravitational separation units, and float from dissolved air flotation units. Alkylation and Polymerization In the alkylation process, a low-molecular-weight olefin with isobutane in the presence of a catalyst, either sulfuric acid or hydrofluoric acid. The chemistry of the combination of olefins with paraffins to form higher iso-paraffins is simple: ðCH3 Þ3 CH þ CH2 ¼ CH2 ! ðCH3 Þ3 CHCH2 CH3 The high-octane value of the product (alkylate) is an excellent blending stock for premium grades of gasoline. Furthermore, since alkylate contains no olefins, no aromatics, and no sulfur, it is also an excellent blending stock for use in reformulated gasoline. The alkylation reaction is catalyzed by the presence of very strong acid, either sulfuric acid or hydrofluoric acid. In the sulfuric-acid-based alkylation process, the acid is continually cycled through the process; but as it cycles, it becomes diluted and contaminated from impurities in the hydrocarbon feeds. The alkylation reactors typically operate at temperatures 2–21
C (35–70
F, maximum) to minimize polymerization of the olefins to form undesirable hydrocarbons) for the sulfuric acid process. The concentration of the sulfuric acid catalyst is important to the efficiency of the alkylation reaction; when the concentration of the acid decreases to approximately 88% v/v, a portion of the contaminated acid is withdrawn and replaced with fresh acid. The contaminated, dilute sulfuric acid is then regenerated to its original purity and concentration. Hydrofluoric acid exists in a vapor state at ambient conditions, and this dictates that extreme precaution is necessary to ensure that this toxic substance is contained inside the process equipment. The hydrofluoric acid process, which is less sensitive to polymerization at warmer

109

temperatures, typically operates at reactor temperatures of 21–38
C (70–100
F). Iso-butane concentrations are maintained very high (i.e., at ratios of 4:1 or more above the reaction requirements) in the reactor vessels to ensure that the olefins are reacted. The reactor effluent is distilled to separate the propane, iso-butane, and alkylate boiling fractions. The propane is routed to propane product treating, the isobutane is recycled back to the alkylation reactors, and the alkylate is routed to gasoline blending, or in some cases to additional solvents refinery processing. The polymerization process (more correctly, the oligomerization process), as practiced in the petroleum industry, is a process by which olefin gases are converted to liquid condensation products that may be suitable for gasoline (hence polymer gasoline, polymerate) or other liquid fuels. The feedstock for the process usually consists of propylene (propene, CH3.CH=CH2) and butylenes (butenes, various isomers of C4H8) from cracking processes or might even be selective olefins for dimer, trimer, or tetramer production: nCH2 ¼ CH2 ! HðCH2 CH2 Þn H In this process, n is usually 2 (dimer), 3 (trimer), or 4 (tetramer); the molecular size of the product is limited to give products boiling in the gasoline range constituents. This contrasts with polymerization that is carried out in the polymer industry where n may be on the order of several hundred. The four-carbon to 12-carbon compounds that are required as the constituents of liquid fuels are the prime products. However, in the petrochemical section of a refinery (Tables 4 and 5), polymerization, which results in the production of, for example, polyethylene, is allowed to proceed until the products having the required high molecular weight have been produced. The process may be accomplished thermally or in the presence of a catalyst at lower temperatures. Thermal polymerization is regarded not as effective as catalytic polymerization but has the advantage that it can be used to polymerize saturated materials that cannot be induced to react by catalysts. The process consists essentially of vaporphase cracking of, say, propane and butane followed by prolonged periods at high

110

Petroleum Refining and Environmental Control and Environmental Effects

Petroleum Refining and Environmental Control and Environmental Effects, Table 4 Examples of hydrocarbon intermediates used in the petrochemical industry

Carbon number 1 2

Hydrocarbon type Saturated Methane Ethane

3 4

Propane Butanes

5

Pentanes

6

Hexanes Cyclohexane

7 8

Propylene Butane Butene(s) Cyclohexane Benzene Toluene Xylene(s) Ethylbenzene Alkylbenzenes >C9

Ethylene Acetylene Propylene n-Butenes Isobutene Butadiene Isopentenes (Isoamylenes) Isoprene Methylpentenes

Benzene Toluene Xylenes Ethylbenzene Styrene Cumene

Propylene tetramer tri-Isobutylene Dodecylbenzene n-Olefins n-Paraffins

Petroleum Refining and Environmental Control and Environmental Effects, Table 5 Sources of petrochemical intermediates Hydrocarbon Methane Ethane Ethylene Propane

Aromatic

Mixed heptenes di-Isobutylene

9 12 18 6–18 11–18

Unsaturated

Source Natural gas Natural gas Cracking processes Natural gas, catalytic reforming, cracking processes Cracking processes Natural gas, reforming and cracking processes Cracking processes Distillation Catalytic reforming Catalytic reforming Catalytic reforming Catalytic reforming Alkylation Polymerization

temperature (510–590
C, 950–1,100
F) for the reactions to proceed to near completion. Emissions from alkylation processes and polymerization processes include fugitive emissions of volatile constituents in the feed and emissions that arise from process vents during processing. These can take the form of acidic hydrocarbon gases, non-acidic hydrocarbon gases, and fumes that may have a strong odor (from sulfonated organic compounds and organic acids, even at low concentrations). To prevent releases of hydrofluoric acid, refineries install a variety of mitigation and control technologies (e.g., acid inventory reduction, hydrogen fluoride detection systems, isolation valves, rapid acid transfer systems, and water spray systems). In hydrofluoric acid alkylation processes, acidic hydrocarbon gases can originate anywhere hydrogen fluoride is present (e.g., during a unit

Petroleum Refining and Environmental Control and Environmental Effects

upset, unit shutdown, or maintenance) [5]. Hydrofluoric acid alkylation units are designed to pipe these gases from acid vents and valves to a separate closed-relief system where the acid is neutralized. Another source of emissions is combustion of fuels in process boilers to produce steam for strippers. As with all process heaters in the refinery, these boilers produce significant emissions of sulfur oxides, nitrogen oxides, carbon monoxide, particulate matter, and volatile hydrocarbons. Alkylation generates relatively low volumes of wastewater, primarily from water washing of the liquid reactor products. Wastewater is also generated from steam strippers, depropanizers and debutanizers, and can be contaminated with oil and other impurities. Liquid process waters (hydrocarbons and acid) originate from minor undesirable side reactions and from feed contaminants and usually exit as a bottoms stream from the acid regeneration column. The bottom layer is an acid-water mixture that is sent to the neutralizing drum. The acid in this liquid eventually ends up as insoluble calcium fluoride. Sulfuric acid alkylation generates considerable quantities of spent acid that must be removed and regenerated. Nearly all the spent acid generated at refineries is regenerated and recycled and, although technology for on-site regeneration of spent sulfuric acid is available, the supplier of the acid may perform this task off-site. If sulfuric acid production capacity is limited, acid regeneration is often done on-site. The development of internal acid regeneration for hydrofluoric acid units has virtually eliminated the need for external regeneration, although most operations retain one for start-ups or during periods of high feed contamination. Both sulfuric acid and hydrofluoric acid alkylation units generate neutralization sludge from treatment of acid-laden streams with caustic solutions in neutralization or wash systems. Sludge from hydrofluoric acid alkylation neutralization systems consists largely of calcium fluoride and unreacted lime and is usually disposed of in a landfill. It can also be directed to steel manufacturing facilities, where the calcium fluoride can be used as a neutral flux to lower the slag-melting temperature and improve slag fluidity. Calcium

111

fluoride can also be routed back to a hydrofluoric acid manufacturer. A basic step in hydrofluoric acid manufacture is the reaction of sulfuric acid with fluorspar (calcium fluoride) to produce hydrogen fluoride and calcium sulfate. Spent alumina is also generated by the defluorination of some hydrofluoric acid alkylation products over alumina. It is disposed of or sent to the alumina supplier for recovery. Other solid residuals from hydrofluoric acid alkylation include any porous materials that may have contacted the hydrofluoric acid.

Catalytic Reforming Catalytic reforming consists of two types of chemical reactions that are catalyzed by two different types of catalysts: (i) isomerization of straightchain paraffins and isomerization (simultaneously with hydrogenation) of olefins to produce branched-chain paraffins and (ii) dehydrogenationhydrogenation of paraffins to produce aromatics and olefins to produce paraffins. The process is used to convert alkanes (paraffins) to cycloalkanes (cycloparaffins) and to aromatics, and emissions from catalytic reforming include fugitive emissions of volatile constituents in the feed and emissions from process heaters and boilers [5]. As with all process heaters in the refinery, combustion of fossil fuels produces emissions of sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO), particulate matter, and volatile hydrocarbons (volatile organic chemicals, VOCs). Furthermore, benzene, toluene, and the xylene isomers are toxic aromatic chemicals that are produced during the catalytic reforming process and used as feedstocks in chemical manufacturing. Due to their highly volatile nature, fugitive emissions of these chemicals are a source of their release to the environment during the reforming process. Point air sources may also arise during the process of separating these chemicals. In a continuous reformer, some particulate and dust matter can be generated as the catalyst moves from reactor to reactor and is subject to attrition. However, due to catalyst design, little attrition occurs, and the only outlet to the atmosphere is the regeneration vent, which is most often

112

Petroleum Refining and Environmental Control and Environmental Effects

scrubbed with a caustic to prevent emission of hydrochloric acid (this also removes particulate matter). Emissions of carbon monoxide and hydrogen sulfide may occur during regeneration of catalyst. Isomerization Catalytic reforming processes provide highoctane constituents in the heavier gasoline fraction, but the n-paraffin components of the lighter gasoline fraction, especially butane (C4) to hexane (C6), have poor octane ratings. The conversion of these n-paraffins to their isomers (isomerization) yields gasoline components of high octane rating in this lower boiling range. Conversion is obtained in the presence of a catalyst (aluminum chloride activated with hydrochloric acid), and it is essential to inhibit side reactions, such as cracking and olefin formation. Thus, the process can be used to convert n-butane, n-pentane, and n-hexane into their respective iso-paraffins of substantially higher octane number. The straight-chain paraffins are converted to their branched-chain counterparts whose component atoms are the same but are arranged in a different geometric structure. Isomerization is important for the conversion of n-butane into iso-butane, to provide additional feedstock for alkylation units, and the conversion of normal pentanes and hexanes into higherbranched isomers for gasoline blending (Table 6). Isomerization processes produce sour water and caustic wastewater. The ether manufacturing process utilizes a water wash to extract methanol or ethanol from the reactor effluent stream. After the alcohol is separated, this water is recycled back to the system and is not released. In those cases, where chloride catalyst activation agents are added, a caustic wash is used to neutralize any entrained hydrogen chloride. This process generates caustic wash water that must be treated before being released. Deasphalting and Dewaxing Deasphalting

Propane deasphalting is commonly used to precipitate asphaltene constituents and resin

Petroleum Refining and Environmental Control and Environmental Effects, Table 6 Component streams for gasoline Stream (i) Paraffins Butane Iso-pentane

Alkylate Isomerate Naphtha Hydrocrackate (ii) Olefins Catalytic naphtha Cracked naphtha Polymer (iii) Aromatics Catalytic reformate

Producing process

Boiling range

C F

Distillation Conversion Distillation Conversion Isomerization Alkylation Isomerization Distillation Hydrocracking

0

32

27

81

40–150 40–70 30–100 40–200

105–300 105–160 85–212 105–390

Catalytic 40–200 cracking Steam 40–200 cracking Polymerization 60–200

105–390

Catalytic reforming

40–200

105–390 140–390 105–390

constituents from residua, heavy oils, extra heavy oils, and tar sand bitumen. The deasphalted oil (the soluble product of propane deasphalting that is reactively low in the presence of cokeforming constituents and metal-containing catalyst poisons) is then sufficiently cleaned to be sent to a hydrotreating unit or a hydrocracking unit or to be used as blend stock for fuel oil. In the process, liquid propane (liquefied under pressure) is the usual solvent of choice due to its unique solvent properties. At lower temperatures (38–60
C, 100–140
F), paraffins are very soluble in propane, and at higher temperatures (approximately 93
C, 200
F), hydrocarbons are almost insoluble in propane. The propanedeasphalting process is analogous to solvent extraction in that a packed or baffled extraction tower or rotating disc contactor is used to mix the oil feedstocks with the solvent. In the well-established tower method, four to eight volumes of propane are fed to the bottom of the tower for every volume of feed flowing down from the top of the tower. The oil, which is more

Petroleum Refining and Environmental Control and Environmental Effects

soluble in the propane, dissolves and flows to the top. The higher-molecular-weight polar asphalt constituents flow to the bottom of the tower where they are removed in a propane mix. Propane is recovered from the two streams through two-stage flash systems followed by steam stripping in which propane is condensed and removed by cooling at high pressure in the first stage and at low pressure in the second stage. The asphalt recovered can be blended with other asphalt, or heavy fuel oil, or can be used as feed to the coker. The propane recovery stage results in propane-contaminated water that typically is sent to the wastewater treatment plant. Air emissions may arise from fugitive propane emissions and process vents. These include heater stack gas (carbon monoxide, sulfur oxides, nitrogen oxides, and particulate matter) as well as hydrocarbon emission such as fugitive propane and fugitive solvents. Steam stripping wastewater (oil and solvents) and solvent recovery wastewater (oil and propane) are also produced.

113

selectively cracked on zeolite-type catalysts, and the lower-boiling reaction products are separated from the dewaxed feedstock oil by fractionation The dewaxing process also produces heater stack gas (carbon monoxide, sulfur oxides, nitrogen oxides, and particulate matter) as well as hydrocarbon emission such as fugitive propane and fugitive solvents [5]. Steam stripping wastewater (oil and solvents) and solvent recovery wastewater (oil and propane) are also produced. The fugitive solvent emissions may be toxic (toluene, methyl ethyl ketone, methyl isobutyl ketone). Finally, the so-called finishing processes (Table 7) include a variety of individual process units that are used to produce the finished product, i.e., a product that will be ready for sales or ready for sales after blending.

Environmental Regulations and Pollutants

Dewaxing

The solvent dewaxing process is used to remove wax (n-paraffin hydrocarbons, straight-chain paraffin hydrocarbons) from deasphalted lubricating oil base stocks. The main process steps include mixing the feedstock with the solvent, chilling the mixture to crystallize wax, and recovering the solvent. Commonly used solvents include toluene and methyl ethyl ketone (MEK) – methyl isobutyl ketone is also used in a wax deoiling process to prepare food-grade wax. Although some of the old methods are still in commercial use, there are three main methods used in modern refinery technology: i. Processes in which the feedstock is mixed with one or more solvents - the feedstock is cooled to allow the formation of wax crystals, and the solid phase is separated from the liquid phase by filtration ii. The urea dewaxing processes in which urea straight-chain paraffin adducts are formed and then separated by filtration from the dewaxed oil iii. Catalytic dewaxing processes in which straight-chain paraffinic hydrocarbons are

An environmental regulation is a legal mechanism that determines how the policy directives of an environmental law are to be carried out. An environmental policy is a requirement that specifies operating procedures that must be followed. An environmental guidance is a document developed by a governmental agency that outlines a position on a topic or which gives instructions on how a procedure must be carried out. It explains how to do something and provides governmental interpretations on a governmental act or policy. Environmental issues range from the effects of pollutants on the population at large to effects on the lives of workers in various occupations where sickness or disability can result from exposure to chemical agents. There are a variety of regulations (Table 8) that apply to crude oil refining [5]. The most popular is the series of regulations known as the Clean Air Act that first was introduced in 1967 and was subsequently amended in 1970 and most recently in 1990. The most recent amendments provide stricter regulations for the establishment and enforcement of national ambient air quality

114

Petroleum Refining and Environmental Control and Environmental Effects

Petroleum Refining and Environmental Control and Environmental Effects, Table 7 Finishing processes Process Amine treating

Action Treatment

Method Absorption

Desalting

Dehydration

Absorption

Drying and sweetening Furfural extraction

Treatment

Absorption/ thermal Absorption

Hydrodesulfurization

Treatment

Catalytic

Hydrotreating

Hydrogenation

Catalytic

Remove impurities, saturate olefins

Phenol extraction Solvent deasphalting

Solvent extraction Treatment

Absorption/ thermal Absorption

Improve viscosity index, color Remove asphalt

Solvent dewaxing

Treatment

Cool/filter

Solvent extraction

Solvent extraction

Absorption/ precipitation

Remove wax from lube stocks Separate unsaturated oils

Sweetening

Treatment

Catalytic

Solvent extraction

standards for, as an example, sulfur dioxide. These standards do not stand alone, and there are many national standards for sulfur emissions. Crude oil production and refining produce chemical waste [4, 5]. If this chemical waste is not processed in a timely manner, it can become a pollutant. Under some circumstances, chemical waste is reclassified as hazardous waste, which is any gaseous, liquid, or solid waste material that, if improperly managed or disposed of, may pose hazards to human health and the environment. In some cases, the term chemical waste is used interchangeably (often incorrectly) with the term hazardous waste, but chemical waste should be considered as hazardous unless proven otherwise, and the correct use of the terms must be used. A pollutant is a chemical that is discharged into a specific location (an ecosystem) that is typically

Purpose Remove acidic contaminants Remove contaminants Remove water and sulfur compounds Upgrade mid-distillate and lubes Remove sulfur, contaminants

Remove hydrogen sulfide and mercaptans

Feedstock(s) Sour gas Crude oil Liquid hydrocarbons Cycle oils

High-sulfur residuum, gas oil Residuum, cracked products Lube oil base stocks Vacuum tower residual, propane Vacuum lube oil Gas oil, reformate, distillate Untreated distillate/ gasoline

Product(s) Acid free gases Desalted crude oil Sweet and dry hydrocarbons High-quality diesel, lube oil Desulfurized olefins Cracker feed, distillate, lube High-quality lube oils Heavy lube oil, asphalt Dewaxed lube base stock High-octane gasoline High-quality distillate/ gasoline

not indigenous to the ecosystem, or, if the chemical occurs naturally, it becomes a pollutant when it is present in a concentration greater than the naturally occurring concentration thereby causing an adverse effect on the ecosystem. The pollutant is often the product of human activity and has a detrimental effect on the environment, in part or in toto. Pollutants can also be subdivided into two classes: (i) primary and (ii) secondary. Thus: Source ! Primary pollutant ! Secondary pollutant A primary pollutant is a chemical that is emitted directly from the source. In terms of atmospheric pollutants from crude oil, examples are carbon oxides (COx – carbon monoxide, CO, and carbon dioxide, CO2), sulfur dioxide (SO2),

Petroleum Refining and Environmental Control and Environmental Effects Petroleum Refining and Environmental Control and Environmental Effects, Table 8 Examples of environmental regulations that apply to crude oil refineries First enacted 1970

Clean Water Act (Water Pollution Control Act)

1948

Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) Hazardous Materials Transportation Act Occupational Safety and Health Act (OSHA) Oil Pollution Act Resource Conservation and Recovery Act (RCRA) Safe Drinking Water Act Toxic Substances Control Act (TSCA or TOSCA)

1980

Amended 1977 1990 1965a 1972b 1977 1987c 1986d

1974

1990

1970

1987e

1973 1976

1990f 1984g

1974 1976

h

Clean Air Act (CAA)

1986 1984i

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½Scrude oil þH2 ! H2 S þ hydrocarbons 2½Ncrude oil þ 3H2 ! 2NH3 þ hydrocarbons On the other hand, a secondary pollutant is a chemical that is produced by interaction of a primary pollutant with another chemical or which is produced by dissociation of a primary pollutant or other effects within an ecosystem. Again, using the atmosphere as an example, the formation of the constituents of acid rain is an example of the formation of secondary pollutants: SO2 þH2 O ! H2 SO3 ðsulfurous acidÞ 2SO2 þO2 ! 2SO3 ðsulfur trioxideÞ SO3 þH2 O ! H2 SO4 ðsulfuric acidÞ NO þ H2 O ! HNO2 ðnitrous acidÞ 3NO2 þ 2H2 O ! HNO3 ðnitric acidÞ In many cases, these secondary pollutants can have significant environmental effects, such as participation in the formation of acid rain and smog [5].

a

Water Quality Act Water Pollution Control Act c Water Quality Act d Also includes the Superfund Amendments and Re-authorization Act (SARA) Amendments e Several amendments during the 1980s f Interactive with various water pollution acts g Includes the Federal Hazardous and Solid Waste Amendments h Several amendments during the 1970s, the 1980s, and the 1990s i Import rule enacted; as of June 22, 2016, includes the Frank R. Lautenberg Chemical Safety for the 21st Century Act, which updates the Toxic Substances Control Act b

and nitrogen oxides (NOx – nitric oxide, NO, and nitrogen dioxide, NO2) from fuel combustion operations: 2½Ccrude oil þO2 ! 2CO ½Ccrude oil þO2 ! CO2 ½Scrude oil þO2 ! SO2 2½Ncrude oil þO2 ! 2NO ½Ncrude oil þO2 ! NO2 Hydrogen sulfide (H2S) and ammonia (NH3) are produced during refining of sulfur-containing and nitrogen-containing feedstocks:

Refinery Emissions Crude oil, like any other raw material, can produce chemical waste. By 1960, the crude oil refining industry had become well established throughout the world. Effluent water, atmospheric emissions, and combustion products also became a focus of increased technical attention [4, 5]. Refineries produce a wide variety of products from crude oil feedstocks and feedstock blends. During crude oil refining, refineries use and generate chemical wastes, some of which are present in air emissions, wastewater, or solid wastes (Table 9) [5]. Emissions are also created through the combustion of fuels and as by-products of chemical reactions occurring when crude oil fractions are upgraded. A large source of air emissions are, generally, the process heaters and boilers that produce carbon monoxide, sulfur oxides, and nitrogen oxides, leading to pollution and the formation of acid rain. Hence, there is the need for gas-cleaning operations on a refinery site so that such gases are cleaned from the gas stream prior to entry into the atmosphere. Fugitive emissions of volatile hydrocarbons arise from leaks in valves, pumps, flanges, and

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Petroleum Refining and Environmental Control and Environmental Effects

Petroleum Refining and Environmental Control and Environmental Effects, Table 9 Examples of emissions and waste from refinery processes

Process Desalting

Air emissions Heater stack gasa, fugitive emissionsb

Atmospheric distillation

Heater stack gas, fugitive emissions, steam ejector emissions Heater stack gas, fugitive emissions, steam ejector emissions Heater stack gas, fugitive emissions

Vacuum distillation

Thermal cracking Visbreaking

Heater stack gas, fugitive emissions

Coking

Heater stack gas, fugitive emissions, decoking emissions Heater stack gas, fugitive emissions

Catalytic cracking

Catalytic hydrocracking

Hydrotreating/ hydroprocessing

Hydrocracking

Alkylation

Isomerization

Polymerization

Catalytic reforming

Heater stack gas, fugitive emissions, catalyst regeneration (dust) Heater stack gas, fugitive emissions, catalyst regeneration gases Heater stack gas, fugitive emissions, catalyst regeneration gases Heater stack gas, fugitive emissions (hydrocarbons) Heater stack gas, HCl, fugitive emissions Hydrogen sulfide from caustic washing Heater stack gas, fugitive emissions, catalyst regeneration gasesa

Residual wastes generated Crude oil/desalter sludge Little or no residual waste Little or no residual waste Little or no residual waste Little or no residual waste Coke dust

Spent catalysts, spent catalyst fines Spent catalysts fines Spent catalyst fines Spent catalyst fines Neutralized alkylation sludge Calcium chloride sludge Spent catalyst Spent catalyst fines (continued)

Petroleum Refining and Environmental Control and Environmental Effects, Table 9 (continued)

Process Solvent extraction

Air emissions Fugitive solvents

Dewaxing

Fugitive solvents, heaters

Propane deasphalting

Heater stack gas, fugitive propane

Wastewater treatment

Fugitive emissions (H2S, NH3, and hydrocarbons)

Residual wastes generated Little or no residual waste Little or no residual waste Little or no residual waste Various types of sludged

a Typically: CO, SOx, NOx, hydrocarbons, particulate matter b Typically: hydrocarbons c Typically: CO, NOx, SOx d API separator sludge, chemical precipitation sludge, biological sludge

other similar sources where crude and its fractions flow through the system. While individual leaks may be minor, the combination of fugitive emissions from various sources can be substantial. These emissions are controlled primarily through leak detection and repair programs and occasionally using special leak-resistant equipment. The primary measure of the environmental impact of refinery wastes is their toxicity to exposed organisms. The toxicity of a substance is most commonly reported as its concentration in water that results in the death of half of the exposed organisms within a given length of time. Exposure times for toxicity tests are typically 96 h, although other times have been used. Gaseous Emissions Gaseous emissions from crude oil refining create several environmental problems [5]. During combustion, the combination of hydrocarbons, nitrogen oxide, and sunlight results in localized low levels of ozone or smog. This is particularly evident in large urban areas and especially when air does not circulate well. Crude oil use in automobiles also contributes to the problem in many

Petroleum Refining and Environmental Control and Environmental Effects

areas. The primary environmental consequences of air pollutants are respiratory difficulties in humans and animals, damage to vegetation, and soil acidification. Releases of hydrogen sulfide, of course, can be fatal to those exposed. The terms refinery gas and process gas are also often used to include any of the gaseous products and by-products that emanate from a variety of refinery processes [4, 5]. There are also components of the gaseous products that must be removed prior to release of the gases to the atmosphere or prior to use of the gas in another part of the refinery, i.e., as a fuel gas or as a process feedstock. Refinery and natural gas streams may contain large amounts of acid gases, such as hydrogen sulfide (H2S) and carbon dioxide (CO2) [3, 4]. Hydrogen chloride (HCl), although not usually considered to be a major pollutant in crude oil refineries, can arise during processing from the presence of brine in crude oil that is incompletely dried. It can also be produced from mineral matter, and other inorganic contaminants are gaining increasing recognition as a pollutant which needs serious attention. Acid gases corrode refining equipment, harm catalysts, pollute the atmosphere, and prevent the use of hydrocarbon components in petrochemical manufacture. When the amount of hydrogen sulfide is large, it may be removed from a gas stream and converted to sulfur or sulfuric acid. Some natural gases contain sufficient carbon dioxide to warrant recovery as dry ice, i.e., solid carbon dioxide. And there is now a conscientious effort to mitigate the emission of pollutants from hydrotreating process by careful selection of process parameters and catalysts [4, 5]. Crude oil refining produces gas streams that often contain substantial amounts of acid gases such as hydrogen sulfide and carbon dioxide. More particularly hydrogen sulfide arises from the hydrodesulfurization of feedstocks that contain organic sulfur: ½Sfeedstock þH2 ! H2 S þ hydrocarbons Crude oil refining involves, except for some of the more viscous crude oils, a primary distillation

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of the hydrogen mixture, which results in its separation into fractions differing in carbon number, volatility, specific gravity, and other characteristics [5]. The most volatile fraction, which contains most of the gases which are generally dissolved in the crude, is referred to as pipe still gas or pipe still light ends and consists essentially of hydrocarbon gases ranging from methane to butane(s) or sometimes pentane(s). The gas varies in composition and volume, depending on crude origin and on any additions to the crude made at the loading point. It is not uncommon to re-inject light hydrocarbons such as propane and butane into the crude before dispatch by tanker or pipeline. This results in a higher vapor pressure of the crude, but it allows one to increase the quantity of light products obtained at the refinery. Since light ends in most crude oil markets command a premium, while in the oil field itself propane and butane may have to be re-injected or flared, the practice of spiking crude oil with liquefied crude oil gas is becoming common. In addition to the gases obtained by distillation of crude oil, more highly volatile products result from the subsequent processing of naphtha and middle distillate to produce gasoline. Hydrogen sulfide is produced in the desulfurization processes involving hydrogen treatment of naphtha, distillate, and residual fuel and from the coking or similar thermal treatments of vacuum gas oils and residual fuels. The most common processing step in the production of gasoline is the catalytic reforming of hydrocarbon fractions in the heptane (C7) to decane (C10) range. In a series of processes commercialized under the generic name reforming, paraffin and naphthene (cyclic nonaromatic) hydrocarbons are altered structurally in the presence of hydrogen and a catalyst into aromatics or isomerized to more highly branched hydrocarbons. Catalytic reforming processes thus not only result in the formation of a liquid product of higher octane number but also produce substantial quantities of gases. The latter are rich in hydrogen but also contain hydrocarbons from methane to butanes, with a preponderance of propane (CH3CH2CH3), n-butane (CH3CH2CH2CH3), and iso-butane [(CH3)3CH].

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Petroleum Refining and Environmental Control and Environmental Effects

A second group of refining operations that contribute to gas production is that of the catalytic cracking processes [5]. These consist of fluid-bed catalytic cracking in which heavy gas oils are converted into gas, liquefied crude oil gas, catalytic naphtha, fuel oil, and coke by contacting the heavy hydrocarbon with the hot catalyst. Both catalytic and thermal cracking processes, the latter being now largely used to produce chemical raw materials, result in the formation of unsaturated hydrocarbons, particularly ethylene (CH2=CH2), but also propylene (propene, CH3.CH=CH2), iso-butylene [iso-butene, (CH3)2C=CH2] and the n-butenes (CH3CH2CH=CH2, and CH3CH=CHCH3) in addition to hydrogen (H2), methane (CH4) and smaller quantities of ethane (CH3CH3), propane (CH3CH2CH3), and butanes [CH3CH2CH2CH3, (CH3)3CH]. Diolefins such as butadiene (CH2=CH.CH=CH2) are also present. Additional gases are produced in refineries with visbreaking and/or coking facilities that are used to process of the heaviest crude fractions. In the visbreaking process, a high-boiling feedstock (such as a residuum or heavy oil) is passed through externally fired tubes and undergoes liquid-phase cracking reactions, which result in the formation of lower-boiling fuel oil components. Oil viscosity is thereby reduced, and some gases, mainly hydrogen, methane, and ethane, are formed. Substantial quantities of both gas and carbon are also formed in coking (both delayed coking and fluid coking) in addition to the middle distillate and naphtha. When coking residual high-boiling feedstocks, the feedstock is preheated and contacted with hot carbon (coke) which causes extensive cracking of the feedstock constituents of higher molecular weight to produce lower-molecular-weight products ranging from methane, via liquefied crude oil gas and naphtha, to gas oil and heating oil. Products from coking processes tend to be unsaturated, and olefin components predominate in the gases produced during coking processes. A further source of refinery gas is hydrocracking; a catalytic high-pressure pyrolysis process in the presence of fresh and recycled hydrogen and the process is directed mainly at the production of additional middle distillates and gasoline. Since

hydrogen is to be recycled, the gases produced in this process again must be separated into lighter and heavier streams; any surplus recycle gas and the liquefied crude oil gas from the hydrocracking process are both saturated. Both hydrocracker gases and catalytic reformer gases are commonly used in catalytic desulfurization processes. In the latter, feedstocks ranging from light to vacuum gas oils are passed at pressures of 500–1,000 psi with hydrogen over a hydrofining catalyst. This results mainly in the conversion of organic sulfur compounds to hydrogen sulfide, ½Sfeedstock þH2 ! H2 S þ hydrocarbons The reaction also produces some light hydrocarbons by hydrocracking. Thus, refinery streams, while ostensibly being hydrocarbon in nature, may contain large amounts of acid gases such as hydrogen sulfide and carbon dioxide. Most commercial plants employ hydrogenation to convert organic sulfur compounds into hydrogen sulfide. Hydrogenation is effected by means of recycled hydrogen-containing gases or external hydrogen over a nickel molybdate or cobalt molybdate catalyst. In summary, refinery process gas, in addition to hydrocarbons, may contain other contaminants, such as carbon oxides (COx, where x = 1 and/ or 2), sulfur oxides (SOx, where x = 2 and/or 3), as well as ammonia (NH3), mercaptans (R-SH), and carbonyl sulfide (COS). The presence of these impurities may eliminate some of the sweetening processes, since some processes remove large amounts of acid gas but not to a sufficiently low concentration. On the other hand, there are those processes not designed to remove (or incapable of removing) large amounts of acid gases, whereas they can remove the acid gas impurities to very low levels when the acid gases are present only in low-to-medium concentration in the gas. From an environmental viewpoint, it is not how these gases can be utilized but it is the effects of these gases on the environment when they are introduced into the atmosphere. In addition to the corrosion of equipment of acid gases, the escape into the atmosphere of

Petroleum Refining and Environmental Control and Environmental Effects

sulfur-containing gases can eventually lead to the formation of the constituents of acid rain, i.e., the oxides of sulfur (SO2 and SO3). Similarly, the nitrogen oxides (NOx, x = 1 or 2 – nitric oxide, NO, and nitrogen dioxide, NO2) can also lead to nitrous and nitric acids which are the other major contributors to acid rain. The release of carbon dioxide and hydrocarbons as constituents of refinery effluents can also influence the behavior and integrity of the ozone layer. Hydrogen chloride, if produced during refining, quickly picks up moisture in the atmosphere to form droplets of hydrochloric acid and, like sulfur dioxide, is a contributor to acid rain [5]. However, hydrogen chloride may exert severe local effects because, unlike sulfur dioxide, it does not need to participate in any further chemical reaction to become an acid, and under atmospheric conditions that favor a buildup of stack emissions in a large industrial complex or power plant, the amount of hydrochloric acid in rainwater could be quite high. Natural gas is also capable of producing emissions that are detrimental to the environment. While the major constituent of natural gas is methane, there are components such as carbon dioxide (CO), hydrogen sulfide (H2S), and mercaptans (thiols; R-SH), as well as trace amounts of sundry other emissions. The fact that methane has a foreseen and valuable end-use makes it a desirable product, but in several other situations, it is considered a pollutant, having been identified a greenhouse gas. Hydrogen chloride (HCl), although not usually considered to be a major emission, is produced from mineral matter and the brines that often accompany crude oil during production and is gaining increasing recognition as a contributor to acid rain. However, hydrogen chloride may exert severe local effects because it does not need to participate in any further chemical reaction to become an acid. Under atmospheric conditions that favor a buildup of stack emissions in the areas where hydrogen chloride is produced, the amount of hydrochloric acid in rainwater could be quite high. In addition to hydrogen sulfide and carbon dioxide, gas may contain other contaminants,

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such as mercaptans (RSH) and carbonyl sulfide (COS). The presence of these impurities may eliminate some of the sweetening processes since some processes remove large amounts of acid gas but not to a sufficiently low concentration. On the other hand, there are those processes that are not designed to remove (or are incapable of removing) large amounts of acid gases. However, these processes are also capable of removing the acid gas impurities to very low levels when the acid gases are there in low-to-medium concentrations in the gas. On a regional level, the emission of sulfur oxides (SOx) and nitrogen oxides (NOx) can also cause the formation of acid species at high altitudes, which eventually precipitate in the form of acid rain, damaging plants, wildlife, and property. Most crude oil products are low in sulfur or are desulfurized, and while natural gas sometimes includes sulfur as a contaminant, it is typically removed at the production site. At the global level, there is concern that the increased use of hydrocarbon-based fuels will ultimately raise the temperature of the planet (global warming), as carbon dioxide reflects the infrared or thermal emissions from the earth, preventing them from escaping into space (greenhouse effect). Whether the potential for global warming becomes real will depend upon how emissions into the atmosphere are handled. There is considerable discussion about the merits and demerits of the global warming theory, and the discussion is likely to continue for some time [17]. Be that as it may, the atmosphere can only tolerate pollutants up to a limiting value, and that value needs to be determined. In the meantime, efforts must be made to curtail the use of noxious and foreign (nonindigenous) materials into the air. There are a variety of processes which are designed for sulfur dioxide removal from gas streams [4, 5], but scrubbing process utilizing limestone (CaCO3) or lime [Ca(OH)2] slurries has received more attention than other gas scrubbing processes. Most the gas scrubbing processes are designed to remove sulfur dioxide from the gas streams; some processes show the potential for removal of nitrogen oxide(s). In summary, crude oil refining can result in considerable gaseous emissions. It is a question

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Petroleum Refining and Environmental Control and Environmental Effects

of degree insofar as the composition of the gaseous emissions may vary from coal to crude oil, but the constituents are, in most cases, the same.

Liquid Effluents It is convenient to divide the hydrocarbon components of crude oil into the following three classes: (i) paraffins, which are saturated hydrocarbons with straight or branched chains; (ii) naphthenes or alicyclic hydrocarbons, which are saturated hydrocarbons containing one or more rings, each of which may have one or more paraffin side chains; and (iii) aromatic hydrocarbons, which are containing one or more aromatic nuclei (e.g., benzene, naphthalene, and phenanthrene) which may be co-joined with (substituted) naphthene rings and/or paraffin side chains. Thermal processing can significantly increase the concentration of polynuclear aromatic hydrocarbons in the product liquid because the low-pressure hydrogen-deficient conditions favor aromatization of naphthene constituents and condensation of aromatics to form larger ring systems. To the extent that more compounds like benzo(a)pyrene are produced, the liquids from thermal processes will be more carcinogenic than asphalt. The sludge produced on acid treatment of crude oil distillates, even gasoline and kerosene, is complex in nature [5]. Esters and alcohols are present from reactions with olefins; sulfonation products from reactions with aromatic compounds, naphthene compounds, and phenols; and salts from reactions with nitrogen bases. To these, constituents must be added the various products of oxidation-reduction reactions: coagulated resins, soluble hydrocarbons, water, and free acid. The disposal of the sludge is a comparatively simple process for the sludge resulting from treating gasoline and kerosene, the so-called light oils. The insoluble oil phase separates out as a mobile tar, which can be mixed and burned without too much difficulty. In all cases, careful separation of reaction products is important to the recovery of well-refined materials. This may not be easy if the temperature has risen because of

chemical reaction. This will result in a persistent dark color traceable to reaction products that are redistributed as colloids. Separation may also be difficult at low temperature because of high viscosity of the stock, but this problem can be overcome by dilution with light naphtha or with propane. In addition, delayed coking also requires the use of large volumes of water for hydraulic cleaning of the coke drum. However, the process water can be recycled if the oil is removed by skimming and suspended coke particles are removed by filtration. If this water is used in a closed cycle, the impact of delayed coking on water treatment facilities and the environment is minimized. The flexicoking process offers one alternative to direct combustion of coke for process fuel. The gasification section is used to process excess coke to mixture of carbon monoxide (CO), carbon dioxide (CO2), hydrogen (H2), and hydrogen sulfide (H2S) followed by treatment to remove the hydrogen sulfide. Currently, maximum residue conversion with minimum coke production is favored over gasification of coke. The environmental impact of hydrocarbons in water varies considerably. The toxicity of aromatic hydrocarbons is relatively high, while that of straight-chain paraffins is relatively low. LC50 values for the most common aromatic hydrocarbons found in the crude oil industry (benzene, toluene, xylene, and ethylbenzene) are on the order of 10 ppm. Hydrocarbon concentrations of less than 1 mg/l in water have been shown to have a sublethal impact on some marine organisms. High-molecular-weight paraffins, on the other hand, are essentially nontoxic. Chronic exposures of entire ecosystems to hydrocarbons, either from natural seeps or from crude oil facilities, have shown no long- or intermediate-term impact; the ecosystems have all recovered when the source of hydrocarbons was removed. The toxicity of heavy metals found in the crude oil refining industry varies widely. The toxicity of many heavy metals lies in their interference with the action of enzymes, which limits or stops normal biochemical processes in cells. General effects include damage to the liver, kidney, or reproductive, blood-forming, or nervous systems.

Petroleum Refining and Environmental Control and Environmental Effects

With some metals, these effects may also include mutations or tumors. Heavy metal concentrations allowed in drinking water vary for each metal but are generally below about 0.01 mg per l. Solid Effluents Catalyst disposal is a major concern in all refineries. In many cases, the catalysts are regenerated at the refinery for repeated use. Disposal of spent catalysts is usually part of an agreement with the catalysts manufacturer, whereby the spent catalyst is returned for treatment and remanufacture. The formation of considerable quantities of coke in the coking processes is a cause for concern since it not only reduces the yield of liquid products but also initiates the necessity for disposal of the coke. Stockpiling to coke may be a partial answer unless the coke contains leachable materials that will endanger the ecosystem because of rain or snow melt. In addition, the generation and emission of sulfur oxides (particularly sulfur dioxide) occurs from the combustion sulfur-containing coke as plant fuel. Sulfur dioxide (SO2) has a wide range of effects on health and on the environment. These effects vary from bronchial irritation upon short-term exposure to contributing to the acidification of lakes. Emissions of sulfur dioxide, therefore, are regulated in many countries.

Entry into the Environment It is almost impossible to transport, store, and refine crude oil without spills and losses. It is difficult to prevent spills resulting from failure or damage on pipelines. It is also impossible to install control devices for controlling the ecological properties of water and the soil along the length of all pipelines. The soil suffers the most ecological damage in the damage areas of pipelines. Crude oil spills from pipelines lead to irreversible changes of the soil properties. The most affected soil properties by crude oil losses from pipelines are filtration, physical, and mechanical properties. These properties of the soil are important for maintaining the ecological equilibrium in the damaged area.

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Principal sources of releases to air from refineries include (i) combustion plants, emitting sulfur dioxide, oxides of nitrogen and particulate matter; (ii) refining operations, emitting sulfur dioxide, oxides of nitrogen, carbon monoxide, particulate matter, volatile organic compounds, hydrogen sulfide, mercaptans and other sulfurous compounds; and (iii) bulk storage operations and handling of volatile organic compounds (various hydrocarbons). Considering this, it is necessary to consider the regulatory requirements, such as air emission permits stipulating limits for specific pollutants, and possibly health and hygiene permit requirements as well as requirements for the monitoring program and the requirements to upgrade pollution abatement equipment. Storage and Handling of Crude Oil and Crude Oil Products Large quantities of environmentally sensitive crude oil products are stored in (i) tank farms which include multiple tankage; (ii) single above-ground storage tanks, ASTs; (iii) semiunderground, SUSTs, or underground storage tanks, USTs. Smaller quantities of materials may be stored in drums and containers of assorted compounds, such as lubricating oil, engine oil, and other products for domestic supply. In light of this, it is also necessary to consider (i) secondary containment of tanks and other storage areas and integrity of hard standing (without cracks, impervious surface) to prevent spills reaching the wider environment: also secondary containment of pipelines where appropriate; (ii) age, construction details, and testing program of tanks; (iii) labeling and environmentally secure storage of drums (including waste storage); (iv) accident/fire precautions and emergency procedures; and (v) disposal/recycling of waste or “out of spec” oils and other materials. There is a potential for significant soil and groundwater contamination to have arisen at crude oil refineries. Such contamination consists of: i. Crude oil hydrocarbons including lowerboiling, very mobile fractions (paraffins, cycloparaffins, and volatile aromatics such as benzene, toluene, ethylbenzene, and xylenes)

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ii.

iii.

iv.

v.

vi.

Petroleum Refining and Environmental Control and Environmental Effects

typically associated with gasoline and similar boiling range distillates Middle distillate fractions (paraffins, cycloparaffins, and some polynuclear aromatics) associated with diesel, kerosene, and lowerboiling fuel oil, which are also of significant mobility Higher-boiling distillates (long-chain paraffins, cycloparaffins, and polynuclear aromatics) that are associated with lubricating oil and heavy fuel oil Various organic compounds associated with crude oil hydrocarbons or produced during the refining process, e.g., phenols, amines, amides, alcohols, organic acids, nitrogen, and sulfur-containing compounds Other organic additives, e.g., antifreeze (glycols), alcohols, detergents, and various proprietary compounds Various heavy metals Key sources of such contamination at crude oil refineries are at (i) transfer and distribution points in tankage and process areas, also general loading and unloading areas, (ii) land farm areas, (iii) tank farms, (iv) individual aboveground storage tanks and particularly individual underground storage tanks, (v) additive compounds, and (vi) pipelines, drainage areas as well as on-site waste treatment facilities, impounding basins, lagoons, especially if unlined. While contamination may be associated with specific facilities, the contaminants are relatively highly mobile in nature and have the potential to migrate significant distances from the source in soil and groundwater. Crude oil hydrocarbon contamination can take several forms: free-phase product, dissolved-phase, emulsified phase, or vapor phase. Each form will require different methods of remediation so that cleanup may be complex and expensive. In addition, crude oil hydrocarbons include several compounds of significant toxicity, e.g., benzene and some polyaromatics are known carcinogens. Vapor phase contamination can be of significance in terms of odor issues. Due to the obvious risk of fire, refineries are equipped with sprinkler or spray systems

that may draw upon the main supply of water, or water held in lagoons, or from reservoirs or neighboring water courses. Such water will be polluting and require containment. Thus, refining facilities require significant volumes of water for on-site processes (e.g., coolants, blowdowns, etc.) as well as for sanitary and potable use. Wastewater will derive from these sources (process water) and from storm water runoff. The latter could contain significant concentrations of crude oil product. Crude oil hydrocarbons, either dissolved, emulsified, or occurring as free-phase, will be the key constituents although wastewater may also contain significant concentrations of phenols, amines, amides, alcohols, ammonia, sulfide, heavy metals, and suspended solids. Wastewaters may be collected in separate drainage systems (for process, sanitary and storm water) although industrial and storm water systems may in some cases be combined. In addition, ballast water from bulk crude tankers may be pumped to receiving facilities at the refinery site prior to removal of floating oil in an interceptor and treatment as for other wastewater streams. On-site treatment facilities may exist for wastewater, or treatment may take place at a public wastewater treatment plant. Storm water/process water is generally passed to a separator or interceptor prior to leaving the site which takes out free-phase oil (i.e., floating product) from the water prior to discharge or prior to further treatment (e.g., in settling lagoons). Discharge from wastewater treatment plants is usually passed to a nearby watercourse. Other wastes that are typical of a refinery include (i) waste oils, process chemicals, and still resides; (ii) non-specification chemicals and/or products; (iii) waste alkali such as sodium hydroxide; (iv) waste oil sludge from interceptors, tanks, and lagoons; and (v) solid wastes such as cartons, rags, catalysts, and coke. Release into the Environment Crude oil products released into the environment undergo weathering processes with time. These

Petroleum Refining and Environmental Control and Environmental Effects

processes include evaporation, leaching (transfer to the aqueous phase) through solution and entrainment (physical transport along with the aqueous phase), chemical oxidation, and microbial degradation. The rate of weathering is highly dependent on environmental conditions. For example, gasoline, a volatile product, will evaporate readily in a surface spill, while gasoline released below 10 ft of clay topped with asphalt will tend to evaporate slowly (weathering processes may not be detectable for years). An understanding of weathering processes is valuable to environmental test laboratories. Weathering changes product composition and may affect testing results, the ability to bioremediate, and the toxicity of the spilled product. Unfortunately, the database available on the composition of weathered products is limited. However, biodegradation processes, which influence the presence and the analysis of crude oil hydrocarbons at a site, can be very complex. The extent of biodegradation is dependent on many factors including the type of microorganisms present, environmental conditions (e.g., temperature, oxygen levels, and moisture), and the predominant hydrocarbon types. In fact, the primary factor controlling the extent of biodegradation is the molecular composition of the crude oil contaminant. Multiple ring cycloalkanes are hard to degrade, while polynuclear aromatic hydrocarbons display varying degrees of degradation. Straight-chain alkanes biodegrade rapidly with branched alkanes and single-saturated ring compounds degrading more slowly. The primary processes determining the fate of crude oils and oil products after a spill are (i) dispersion, (ii) dissolution, (iii) emulsification, (iv) evaporation, (v) leaching, (vi) sedimentation, (vii) spreading, and (viii) wind. These processes are influenced by the spill characteristics, environmental conditions, and physicochemical properties of the spilled material. Dispersion

The physical transport of oil droplets into the water column is referred to as dispersion. This is often a result of water surface turbulence but also may result from the application of chemical agents

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(dispersants). These droplets may remain in the water column or coalesce with other droplets and gain enough buoyancy to resurface. Dispersed oil tends to biodegrade and dissolve more rapidly than floating slicks because of high surface area relative to volume. Most of this process occurs from about half an hour to half a day after the spill. Dissolution

Dissolution is the loss of individual oil compounds into the water. Many of the acutely toxic components of oils such as benzene, toluene, and xylene will readily dissolve into water. This process also occurs quickly after a discharge but tends to be less important than evaporation. In a typical marine discharge, generally less than 5% v/v of the benzene is lost to dissolution while greater than 95% v/v is lost to evaporation. For alkylated polynuclear aromatic compounds, solubility is inversely proportional to the number of rings and extent of alkylation. The dissolution process is thought to be much more important in rivers because natural containment may prevent spreading, reducing the surface area of the slick, and thus retarding evaporation. At the same time, river turbulence increases the potential for mixing and dissolution. Most of this process occurs within the first hour of the spill. Aromatics, and especially the benzene, toluene, ethyl benzene, and xylene isomers (BTEX) blend, tend to be the most water-soluble fraction of crude oil. Crude oil-contaminated groundwater tends to be enriched in aromatics relative to other crude oil constituents. Relatively insoluble hydrocarbons may be entrained in water through adsorption into kaolinite particles suspended in the water or as an agglomeration of oil droplets (microemulsion). In cases where groundwater contains only dissolved hydrocarbons, it may not be possible to identify the original crude oil product because only a portion of the free product will be present in the dissolved phase. As whole product floats on groundwater, the free product will gradually lose the water-soluble compounds. Groundwater containing entrained product will have a gas chromatographic fingerprint that is a combination of the free product chromatogram plus enhanced amounts of the soluble aromatics.

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Petroleum Refining and Environmental Control and Environmental Effects

Generally, dissolved aromatics may be found quite far from the origin of a spill, but entrained hydrocarbons may be found in water close to the crude oil source. Oxygenates, such as methyl-tbutyl ether (MTBE), are even more water soluble than aromatics and are highly mobile in the environment. Emulsification

Certain oils tend to form water-in-oil emulsions (where water is incorporated into oil) or “mousse” as weathering occurs. This process is significant because, for example, the apparent volume of the oil may increase dramatically, and the emulsification will slow the other weathering processes, especially evaporation. Under certain conditions, these emulsions may separate and release relatively fresh oil. Most of this process occurs from about half a day to 2 days after the spill. Evaporation

Evaporative processes are very important in the weathering of volatile crude oil products and may be the dominant weathering process for gasoline. Automotive gasoline, aviation gasoline, and some grades of jet fuel (such as the fuel designated JP-4) contain 20–99% v/v highly volatile constituents (i.e., constituents with less than nine carbon atoms). Evaporative processes begin immediately after oil is discharged into the environment. Some light products (like 1-ring to 2-ring aromatic hydrocarbons and/or low-molecular-weight alkanes less than n-C15) may evaporate entirely; a significant fraction of heavy refined oils also may evaporate. For crude oils, the amount lost to evaporation can typically range from approximately 20 to 60% v/v. The primary factors that control evaporation are the composition of the oil, slick thickness, temperature and solar radiation, wind speed, and wave height. While evaporation rates increase with temperature, this process is not restricted to warm climates. It is not unusual for evaporative processes, however, to be working simultaneously with other processes to remove the volatile aromatics such as benzene and toluene.

Leaching

Leaching is the loss or extraction of certain materials from a carrier into a liquid (usually, but not always a solvent). Leaching processes introduce hydrocarbon into the water phase by solubility and entrainment. Leaching processes of crude oil products in soils can have a variety of potential scenarios. Part of the aromatic fraction of a crude oil spill in soil may partition into water that has been in contact with the contamination. Sedimentation or Adsorption

As mentioned above, most oils are buoyant in water. However, in areas with high levels of suspended sediment, crude oil constituents may be transported to the river, lake, or ocean floor through the process of sedimentation. Crude oil and crude oil constituents may adsorb on to sediments and sink or be ingested by zooplankton and excreted in fecal pellets that may settle to the bottom. Crude oil stranded on shorelines also may pick up sediments, float with the tide, and then sink. Most of this process occurs from about 2 to 7 days after the spill. Spreading

As oil enters the environment, it begins to spread immediately. The viscosity of the oil, its pour point, and the ambient temperature will determine how rapidly the oil will spread, but light oils typically spread more rapidly than heavy oils. The rate of spreading and ultimate thickness of the oil slick will affect the rates of the other weathering processes. For example, discharges that occur in geographically contained areas (such as a pond or slowmoving stream) will evaporate more slowly than if the oil could spread. Most of this process occurs within the first week after the spill. Wind

Wind (aeolian) transport (relocation by wind) can also occur and is relevant when catalyst dust and coke dust are considered. Dust becomes airborne when winds traversing arid land with little vegetation cover pick up small particles such as catalyst dust, coke dust, and other refinery debris and send them skyward. Wind transport may occur through suspension, saltation, or creep of the particles.

Petroleum Refining and Environmental Control and Environmental Effects

Toxicity With few exceptions, the constituents of crude oil, crude oil products, and the various emissions are hazardous to the health. There are always exceptions that will be cited in opposition to such a statement, the most common exception being the liquid paraffin that is used medicinally to lubricate the alimentary tract. The use of such medication is common among miners who breathe and swallow coal dust every day during their work shifts. Another approach is to consider crude oil constituents in terms of transportable materials, the character of which is determined by several chemical and physical properties (i.e., solubility, vapor pressure, and propensity to bind with soil and organic particles). These properties are the basis of measures of leachability and volatility of individual hydrocarbons. Thus, crude oil transport fractions can be considered by equivalent carbon number to be grouped into 13 different fractions. The analytical fractions are then set to match these transport fractions, using specific n-alkanes to mark the analytical results for aliphatic compounds and selected aromatic compounds to delineate hydrocarbons containing benzene rings. The range of chemicals in crude oil and crude oil products is so vast that summarizing the properties and/or the toxicity or general hazard of crude oil in general or even for a specific crude oil is a difficult task. However, crude oil and some crude oil products, because of the hydrocarbon content, are at least theoretically biodegradable but large-scale spills can overwhelm the ability of the ecosystem to break the oil down. The toxicological implications from crude oil occur primarily from exposure to or biological metabolism of aromatic structures. These implications change as an oil spill ages or is weathered.

Lower-Boiling Constituents Many of the gaseous and liquid constituents of the lower-boiling fractions of crude oil and in crude oil products fall into the class of chemicals which have the one or more of the following characteristics are hazardous by the Environmental Protection Agency.

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1. Ignitability-Flammability A liquid that has a flash point of less than 60
C (140
F) is considered ignitable. Some examples are benzene, hexane, heptane, benzene, pentane, crude oil ether (low boiling), toluene, and xylene isomers. 2. Corrosivity An aqueous solution that has a pH of less than or equal to 2 (high acidity), or greater than or equal to 12.5 (high alkalinity), is considered corrosive. Most crude oil constituents and crude oil products are not corrosive, but many of the chemicals used in refineries are corrosive. Corrosive materials also include substances such as sodium hydroxide and some other acids or bases. 3. Reactivity Chemicals that react violently with air or water are considered hazardous. Examples are sodium metal, potassium metal, phosphorus, etc. Reactive materials also include strong oxidizers such as perchloric acid and chemicals capable of detonation when subjected to an initiating source, such as solid, dry