Hydrotreating and Hydrocracking Processes in Refining Technology (Petroleum Refining Technology Series) [1 ed.] 1032028122, 9781032028125

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Hydrotreating and ­Hydrocracking Processes in ­Refining Technology Written by an industry expert with over 50 years of experience, this book details the various solvent processes that are used in crude oil refineries. Providing an in-depth exploration of the different types of processes, as well as the types of feedstocks that can be used with them, this book prepares readers for changes as the industry evolves. Key Features: • Describes feedstock evaluation and the effects of elemental, chemical, and fractional composition. • Contains an extensive glossary of all related concepts in hydrotreating and hydrocracking processes. • Considers next-generation processes and developments. This book is an essential guide for engineers, scientists, and students in the field of petroleum processing and refining technology, including professionals, technicians, management personnel, and academics. James G. Speight has more than 50 years of experience in areas associated with the properties and processing of conventional crude oil, heavy crude oil, extra heavy crude oil, tar sand bitumen, natural gas, coal, oil shale, biomass, and synthetic fuels. He has well over 400 publications, reports, and presentations detailing these research activities and has taught more than 80 related courses.

Petroleum Refining Technology Series Series Editor: James G. Speight This series of books is designed to address the current processes used by the refining industry and take the reader through the various steps that are necessary for crude oil evaluation and refining. Technological advancements and processing innovations are highlighted in each of the volumes.

Refinery Feedstocks James G. Speight

Dewatering, Desalting, and Distillation in Petroleum Refining James G. Speight

Thermal and Catalytic Processes James G. Speight

Hydrotreating and Hydrocracking Processes in Refining Technology James G. Speight

Hydrotreating and ­Hydrocracking Processes in ­Refining Technology

James G. Speight, PhD, DSc, PhD, CD&W Inc., Laramie, Wyoming, USA

First edition published 2024 by CRC Press 6000 Broken Sound Parkway NW, Suite 300, Boca Raton, FL 33487-2742 and by CRC Press 4 Park Square, Milton Park, Abingdon, Oxon, OX14 4RN CRC Press is an imprint of Taylor & Francis Group, LLC © 2024 James G. Speight Reasonable efforts have been made to publish reliable data and information, but the author and publisher cannot assume responsibility for the validity of all materials or the consequences of their use. The authors and p ­ ublishers have attempted to trace the copyright holders of all material reproduced in this publication and apologize to ­copyright ­holders if permission to publish in this form has not been obtained. If any copyright material has not been ­acknowledged please write and let us know so we may rectify in any future reprint. Except as permitted under U.S. Copyright Law, no part of this book may be reprinted, reproduced, transmitted, or utilized in any form by any electronic, mechanical, or other means, now known or hereafter invented, ­including ­photocopying, microfilming, and recording, or in any information storage or retrieval system, without written ­permission from the publishers. For permission to photocopy or use material electronically from this work, access www.copyright.com or contact the Copyright Clearance Center, Inc. (CCC), 222 Rosewood Drive, Danvers, MA 01923, 978-750-8400. For works that are not available on CCC please contact [email protected] Trademark notice: Product or corporate names may be trademarks or registered trademarks and are used only for identification and explanation without intent to infringe. ISBN: 978-1-032-02812-5 (hbk) ISBN: 978-1-032-02818-7 (pbk) ISBN: 978-1-003-18531-4 (ebk) DOI: 10.1201/9781003185314 Typeset in Times by codeMantra

Contents Preface...............................................................................................................................................xi Chapter 1 Hydroprocesses in the Refinery....................................................................................1 1.1 Introduction........................................................................................................1 1.2 Hydrogen in Refineries.......................................................................................9 1.3 Rationale for Hydrogen Use............................................................................. 14 1.4 Placement in the Refinery................................................................................ 17 1.4.1 Hydrotreating Processes...................................................................... 17 1.4.2 Hydrocracking Processes.................................................................... 22 1.5 Hydroprocessing Viscous Feedstocks..............................................................25 1.6 Hydroprocessing Biomass-Derived Products...................................................26 1.6.1 Vegetable Oils..................................................................................... 27 1.6.2 Algal-Derived Oils.............................................................................. 27 1.7 Hydrogen Production........................................................................................ 27 1.8 Hydrogen Management.................................................................................... 29 References................................................................................................................... 31 Chapter 2 Hydrotreating and Hydrocracking.............................................................................. 35 2.1 Introduction...................................................................................................... 35 2.2 Catalysts........................................................................................................... 35 2.2.1 Hydrotreating Catalysts....................................................................... 36 2.3.2 Hydrocracking Catalysts..................................................................... 39 2.3.3 Use of Biocatalysts.............................................................................. 45 2.3 Process Parameters...........................................................................................46 2.3.1 Hydrogen Partial Pressure................................................................... 50 2.3.2 Space Velocity..................................................................................... 51 2.3.3 Reaction Temperature......................................................................... 51 2.3.4 Catalyst Life........................................................................................ 51 2.3.5 Feedstock Effects................................................................................ 52 2.4 Reactors............................................................................................................ 54 2.4.1 Downflow Fixed-Bed Reactor............................................................. 55 2.4.2 Upflow Expanded-Bed Reactor........................................................... 56 2.4.3 Ebullating-Bed Reactor....................................................................... 56 2.4.4 Slurry-Phase Reactor........................................................................... 57 2.4.5 Demetallization Reactor...................................................................... 58 References................................................................................................................... 58 Chapter 3 Feedstocks: Composition and Evaluation.................................................................... 61 3.1 Introduction...................................................................................................... 61 3.2 Non-Viscous Feedstocks................................................................................... 62 3.2.1 Naphtha............................................................................................... 62 3.2.1.1 Manufacture......................................................................... 62 3.2.1.2 Composition......................................................................... 63 3.2.1.3 Properties and Uses............................................................. 63 v

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3.2.2

Middle Distillates................................................................................64 3.2.2.1 Manufacture.........................................................................64 3.2.2.2 Composition.........................................................................64 3.2.2.3 Properties and Uses............................................................. 65 3.2.3 Gas Oil................................................................................................ 65 3.2.3.1 Manufacture......................................................................... 65 3.2.3.2 Composition......................................................................... 65 3.2.3.3 Properties and Uses............................................................. 67 3.2.4 Wax...................................................................................................... 67 3.2.4.1 Manufacture......................................................................... 68 3.2.4.2 Composition......................................................................... 69 3.2.4.3 Properties and Uses............................................................. 69 3.2.5 Biomass and Bio-Oil........................................................................... 69 3.2.5.1 Manufacture......................................................................... 72 3.2.5.2 Composition......................................................................... 73 3.2.5.3 Properties and Uses............................................................. 73 3.3 Viscous Feedstocks.......................................................................................... 73 3.3.1 Heavy Crude Oil................................................................................. 74 3.3.2 Extra Heavy Crude Oil........................................................................ 75 3.3.3 Tar Sand Bitumen................................................................................ 76 3.3.4 Residuum............................................................................................. 77 3.4 Composition...................................................................................................... 79 3.4.1 Elemental Composition....................................................................... 79 3.4.2 Chemical Composition........................................................................ 81 3.4.2.1 Hydrocarbon Constituents................................................... 82 3.4.2.2 Non-hydrocarbon Constituents............................................ 86 3.4.3.2 Nitrogen Compounds........................................................... 88 3.4.3.3 Oxygen Compounds............................................................ 88 3.4.3.4 Metal-Containing Constituents........................................... 89 3.4.3.5 Porphyrin Derivatives.......................................................... 89 3.5 Fractional Composition....................................................................................90 3.5.1 Solvent Methods.................................................................................. 91 3.5.2 Adsorption Methods............................................................................ 93 3.5.3 Chemical Methods..............................................................................94 3.6 Evaluation......................................................................................................... 95 References................................................................................................................... 98 Chapter 4 Hydrotreating Processes............................................................................................ 101 4.1 Introduction.................................................................................................... 101 4.2 Hydrodesulfurization...................................................................................... 105 4.3 Reactors.......................................................................................................... 106 4.3.1 Downflow Fixed-Bed Reactor........................................................... 107 4.3.2 Upflow Expanded-Bed Reactor......................................................... 107 4.3.3 Demetallization Reactor.................................................................... 108 4.4 Catalysts......................................................................................................... 108 4.5 Processes........................................................................................................ 109 4.5.1 Process Parameters............................................................................ 110 4.5.1.1 Hydrogen Partial Pressure................................................. 110 4.5.1.2 Space Velocity................................................................... 110 4.5.1.3 Reaction Temperature........................................................ 111

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4.5.1.4 Catalyst Life....................................................................... 111 4.5.1.5 Feedstock Effects............................................................... 111 4.6 Viscous Feedstock Hydrodesulfurization...................................................... 112 4.6.1 Processes........................................................................................... 113 4.6.1.1 Autofining Process............................................................. 114 4.6.1.2 Chevron Deasphalted Oil Hydrotreating Process.............. 114 4.6.1.3 Ferrofining Process............................................................ 114 4.6.1.4 Gulf Resid Hydrodesulfurization Process......................... 114 4.6.1.5 Hydrofining Process.......................................................... 115 4.6.1.6 Hyvahl F Process............................................................... 116 4.6.1.7 Isomax Process.................................................................. 117 4.6.1.8 Resid Desulfurization and Vacuum Resid Desulfurization Process..................................................... 117 4.6.1.9 Residfining Process........................................................... 117 4.6.1.10 Shell Residual Oil Hydrodesulfurization.......................... 118 4.6.1.11 Ultrafining Process............................................................ 118 4.6.1.12 Unifining Process.............................................................. 118 4.6.1.13 Unionfining Process.......................................................... 118 4.6.1.14 Other Options.................................................................... 119 4.6.2 Process Parameters............................................................................ 119 4.6.2.1 Catalyst Types.................................................................... 119 4.6.2.2 Metals Accumulation......................................................... 120 4.6.2.3 Catalyst Activity................................................................ 120 4.6.2.4 Temperature and Space Velocity....................................... 120 4.6.2.5 Feedstock Effects............................................................... 120 4.7 Other Options................................................................................................. 123 4.7.1 Catalyst Technology.......................................................................... 124 4.7.2 Gasoline and Diesel Fuel Polishing.................................................. 125 4.7.3 Biodesulfurization............................................................................. 127 4.7.4 Biofeedstocks.................................................................................... 128 References................................................................................................................. 128 Chapter 5 Hydrocracking Processes.......................................................................................... 131 5.1 Introduction.................................................................................................... 131 5.2 Processes and Process Design........................................................................ 135 5.2.1 Process Design.................................................................................. 137 5.2.2 Feedstocks and Hydrogen Requirements.......................................... 139 5.2.3 Design Improvements........................................................................ 139 5.3 Catalysts......................................................................................................... 143 5.4 Options for Viscous Feedstocks..................................................................... 151 5.4.1 Aquaconversion................................................................................. 152 5.4.2 Asphaltenic Bottom Cracking Process.............................................. 152 5.4.3 CANMET Process............................................................................ 153 5.4.4 Chevron RDS Isomax and VRDS Process....................................... 153 5.4.5 ENI Slurry-Phase Technology........................................................... 154 5.4.6 Gulf Resid Hydrodesulfurization Process......................................... 155 5.4.7 H-G Hydrocracking Process............................................................. 155 5.4.8 H-Oil Process.................................................................................... 155 5.4.9 HYCAR Process................................................................................ 157 5.4.10 Hydrovisbreaking Process................................................................. 157

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5.4.11 Hyvahl-F Process.............................................................................. 157 5.4.12 IFP Hydrocracking Process.............................................................. 158 5.4.13 Isocracking Process........................................................................... 158 5.4.14 LC-Fining Process............................................................................ 159 5.4.15 MAKfining Process.......................................................................... 159 5.4.16 Microcat-FC Process......................................................................... 160 5.4.17 Mild Hydrocracking Process............................................................. 160 5.4.18 MRH Process.................................................................................... 160 5.4.19 RCD Unibon Process........................................................................ 161 5.4.20 Residfining Process........................................................................... 161 5.4.21 Residue Hydroconversion Process.................................................... 161 5.4.22 Shell Residual Oil Process................................................................ 161 5.4.23 Tervahl-H Process............................................................................. 162 5.4.24 Unicracking Process.......................................................................... 162 5.4.25 Uniflex Process.................................................................................. 163 5.4.26 Veba Combi-Cracking Process......................................................... 164 5.5 Other Options and the Future......................................................................... 165 References................................................................................................................. 166 Chapter 6 Hydrogen Production................................................................................................. 169 6.1 Introduction.................................................................................................... 169 6.2 Processes Requiring Hydrogen...................................................................... 173 6.2.1 Hydrotreating.................................................................................... 174 6.2.2 Hydrocracking................................................................................... 175 6.3 Hydrogen Production...................................................................................... 176 6.3.1 Feedstocks......................................................................................... 176 6.3.2 Chemistry.......................................................................................... 177 6.3.3 Catalysts............................................................................................ 178 6.3.3.1 Reforming Catalysts.......................................................... 178 6.3.3.2 Shift Conversion Catalysts................................................. 180 6.3.3.3 Methanation Catalysts....................................................... 180 6.4 Commercial Processes................................................................................... 181 6.4.1 Autothermal Reforming.................................................................... 182 6.4.2 Heavy Residue Gasification and Combined Cycle Power Generation.................................................................... 183 6.4.3 Hybrid Gasification Process.............................................................. 183 6.4.4 Hydrocarbon Gasification................................................................. 184 6.4.5 Hypro Process................................................................................... 184 6.4.6 Pyrolysis Processes........................................................................... 184 6.4.7 Shell Gasification Process................................................................. 185 6.4.8 Steam-Methane Reforming............................................................... 185 6.4.9 Steam-Naphtha Reforming................................................................ 187 6.4.10 Synthesis Gas Generation................................................................. 187 6.4.11 Texaco Gasification Process.............................................................. 188 6.5 Hydrogen Purification.................................................................................... 189 6.5.1 Cryogenic Separation........................................................................ 189 6.5.2 Membrane Systems........................................................................... 189 6.5.3 Pressure-Swing Adsorption Units..................................................... 190 6.5.4 Wet Scrubbing................................................................................... 190 6.6 Hydrogen Management.................................................................................. 190

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6.7 Refining Viscous Feedstocks.......................................................................... 192 References................................................................................................................. 192 Chapter 7 Fouling During Hydroprocessing.............................................................................. 197 7.1 Introduction.................................................................................................... 197 7.2 The Concept of Fouling.................................................................................. 197 7.2.1 Types of Fouling................................................................................ 198 7.2.2 Parameters Affecting Fouling........................................................... 201 7.2.2.1 Fluid Flow Velocity...........................................................202 7.2.2.2 Surface Temperature..........................................................202 7.2.2.3 Surface Material................................................................202 7.2.2.4 Surface Roughness............................................................202 7.2.2.5 Fluid Properties.................................................................202 7.2.3 Asphaltene Chemistry and Deposition.............................................. 203 7.2.4 Wax Deposition.................................................................................204 7.2.4.1 Deposition..........................................................................205 7.2.4.2 Factors Leading to Wax Deposition..................................205 7.2.4.3 Mechanism.........................................................................207 7.3 Fouling during Hydrotreating........................................................................207 7.3.1 General Aspects................................................................................208 7.3.2 Catalyst Fouling................................................................................209 7.4 Fouling During Hydrocracking...................................................................... 212 7.4.1 General Aspects................................................................................ 213 7.4.2 Catalyst Fouling................................................................................ 213 7.4.3 Fractionator Fouling.......................................................................... 214 7.5 Impacts of Fouling.......................................................................................... 214 7.5.1 Catalyst Bed Fouling......................................................................... 215 7.5.2 Heat Exchanger Fouling.................................................................... 216 7.6 Management and Mitigation........................................................................... 216 References................................................................................................................. 219 Chapter 8 The Future of Hydroprocesses in the Refinery......................................................... 221 8.1 Introduction.................................................................................................... 221 8.2 Hydroprocesses............................................................................................... 221 8.2.1 Hydrotreating Processes.................................................................... 223 8.2.2 Hydrocracking Processes..................................................................224 8.2.3 Slurry Hydrocracking........................................................................ 225 8.2.4 Process Comparison.......................................................................... 225 8.3 Refining Heavy Feedstocks............................................................................ 226 8.4 Hydrogen Production...................................................................................... 226 8.5 Hydrogen Management.................................................................................. 228 References................................................................................................................. 229 Glossary......................................................................................................................................... 231 Conversion Factors....................................................................................................................... 287 About the Author.......................................................................................................................... 289 Index............................................................................................................................................... 291

Preface This series of books (a total of eight books) presents descriptions of (1) the development of technologies for a variety of feedstocks (including the viscous feedstocks which are often referred to as heavy feedstocks) utilizing advanced pre-treatment processing and hydrotreating, (2) an analysis of the catalyst deactivation mechanism for developing optimum technologies for processing feedstocks with low reactivity, (3) the development of advanced technologies applicable to the viscous feedstocks, (4) the development of advanced hydrocracking processes for heavy feedstock upgrading, (5) development of innovative upgrading processes for the viscous feedstocks, and (6) the role of biomass in the future refinery. Furthermore, each book is a stand-alone volume that will bring the reader further up to date and adds more data as well as processing options that may be the processes of the evolving 21st century. As the fourth book in the series, this book will focus on hydrotreating and hydrocracking. The differences between these processes will be presented and the types of feedstock that can be used for the processes will be discussed. Chapter 1 focuses on the general layout of a refinery and the relationship between the various processes. In order to fully comprehend the function of the various process units within refinery operations, it is necessary to understand the place at which the process units are employed and the reason for this employment. This will assist the reader to place thermal cracking processes and the catalytic cracking process in the correct perspective of the refinery, not forgetting that prior to any conversion processes, it is necessary to desalt, dewater, and distill the raw (i.e., unrefined) refinery feedstock, as described in the second book of this series. Chapter 2 focuses on the composition and properties of the various viscous feedstocks as well as the non-viscous fractions of crude oil, which are also used for the production of products through the application of hydrotreating and hydrocracking processes. These are (1) naphtha, (2) kerosene or middle distillate, and (3) gas oil. These products are typically produced from the conventional refinery feedstocks (i.e., conventional crude oil) but are, nevertheless, feedstocks for hydrotreating and hydrocracking processes that lead to a range of products that also include petrochemical products. In addition, the chapter also provides a description of the viscous feedstocks (i.e., heavy crude oil, extra heavy crude oil, and tar sand bitumen) that can be used for the production of the distillates from which the high-value products can be produced. Chapter 3 presents the composition, properties, and evaluation of the various viscous feedstocks as well as the non-viscous fractions of crude oil, which are also used for the production of products through the application of thermal cracking processes and catalytic cracking processes. These are (1) naphtha, (2) kerosene or middle distillate, and (3) gas oil. These products are typically produced from the conventional refinery feedstocks (i.e., conventional crude oil) and are feedstocks for hydrotreating and hydrocracking processes that lead to a range of products that also include petrochemical products. The chapter also provides a description of the viscous feedstocks (i.e., heavy crude oil, extra heavy crude oil, and tar sand bitumen) that can also be used as feedstocks for hydrotreating and hydrocracking processes for the production of the lower molecular weight products from which high-value products can be produced. Chapter 4 presents descriptions of the various processes that are employed for desulfurization and concurrent demetallization of various feedstocks. Thus, desulfurization is the removal of sulfur or sulfur compounds from crude oil and crude oil products, and demetallization is the removal of metals or metal-containing constituents (such as porphyrins) from crude oil and crude oil products. Chapter 5 describes the processes that can be used for the conversion of a variety of feedstocks to a range of products that can be found at various points in a refinery. Chapter 6 presents a description of the processes that are used to produce hydrogen in the refinery. In general, most of the external hydrogen is manufactured by steam-methane reforming or by xi

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oxidation processes. Other processes such as ammonia dissociation, steam–methanol interaction, or electrolysis are also available for hydrogen production, but economic factors and feedstock availability assist in the choice between processing alternatives. Chapter 7 presents an overview of fouling in the refinery which occurs when there is the deposition and accumulation of unwanted material within a processing unit or on the solid surfaces of the unit to the detriment of function. For example, when fouling does occur during refinery operations, the major effects include (1) loss of heat transfer as indicated by charge outlet temperature decrease and pressure drop increase, (2) blocked process pipes, (3) under-deposit corrosion and pollution, and (4) localized hot spots in reactors, all of which culminate in production losses and even refinery shutdown. This chapter presents a description of the concept of fouling in hydroprocesses which can occur as deposit formation, encrustation, deposition, scaling, scale formation, slagging, and sludge formation, all of which can have an adverse effect on process efficiency and operations. Chapter 8 presents an overview of the importance of the need for hydroprocesses to be integrated into the refinery through the various process innovations that have evolved over the decades of the 20th century and are continuing into the 21st century. Each chapter will present to the reader through the various steps that are necessary for the hydroprocessing of various feedstocks. The book brings the reader up to date and adds more data as well as processing options that may be the processes of the 21st century and into the 21st century. By understanding the evolutionary changes that have occurred to date, this book will satisfy the needs of engineers and scientists at all levels from academia to the refinery and help them understand the initial refining processes and prepare for the new changes and evolution of the industry. The target audience includes engineers, scientists, and students who want an update on petroleum processing and the direction of the industry in the next 50 years. Such personnel include (1) professionals in the refining industry, (2) technicians in the refining industry, and (3) academics in related departments, graduate students who are moving into the refining industry, and management personnel. Any non-technical readers, with help from the extensive glossary, will also benefit from the series. Dr. James G. Speight, Laramie, Wyoming, USA. September, 2022

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Hydroprocesses in the Refinery

1.1 INTRODUCTION Crude oil refining (also commonly referred to as petroleum refining) is achieved through the application of a series of chemical processes, physical processes, chemical engineering processes, and other processes (all of which are crude oil-dependent) that are employed in a refinery to convert (transform) crude oil into useful products such as liquefied petroleum gas (LPG), naphtha solvents, gasoline (often referred to as petrol in some countries), kerosene, jet fuel, diesel fuel, fuel oil, lubricating oil, wax, and asphalt as well as feedstocks for the petrochemical industry. Thus, crude oil refining is a series of unit processes that are used to convert crude oil into a variety of products (Parkash, 2003; Gary et al., 2007; Speight, 2011a, 2014; Hsu and Robinson, 2017; Speight, 2017, 2019a, 2020b). On a historical basis, the first systematic refinery for converting crude oil to saleable products crude oil refinery was built in Ploieşti (Romania) in 1856 using the crude oil that was available in that country. Shortly thereafter, in North America, the first well to recover crude oil was drilled in 1858 by James Miller Williams in Oil Springs, Ontario, Canada, followed by the drilling of a well in Titusville, Pennsylvania, United States, in 1859 (Larraz, 2021). The refining industry has been the subject of several major forces that affect most industries and which have hastened the development of new crude oil refining processes of which the most prominent are (1) the demand for products such as gasoline, diesel, jet fuel, and fuel oil; (2) feedstock supply, specifically the changing quality of crude oil and geopolitics between different countries and the emergence of alternate feed supplies such as heavy crude oil, extra heavy crude oil, and bitumen from tar sand; (3) environmental regulations that include more stringent regulations in relation to sulfur in gasoline and diesel fuel; and (4) technology development such as new catalysts and processes. The start of the 20th century saw the emergence of refinery processes that were developed to extract kerosene for lamps. Any other products were considered to be unusable and were usually discarded, and, thus, the first refining processes were developed to purify, stabilize, and improve the quality of kerosene. However, the invention of the internal combustion engine led (during the years of World War I) to a demand for naphtha (for the production of gasoline) for use in increasing quantities as a starting liquid for use in motor fuel for cars and trucks. Moreover, the demand for the lower boiling products increased, particularly when the market for aviation fuel developed, which, in term, led to the need for improved refining processes that could produce the products to meet the requirements for use in automobile engines and aircraft engines. Since that time, the general trend throughout crude oil refineries has been to produce more distillate products from each barrel of crude oil and to process those products in different ways to meet the product specifications for use in engines. Overall, the demand for (1) gases and low-boiling distillates as feedstocks for the petrochemical industry and (2) the precursors to gasoline and other fuels, (3) as well as the demand for fuel oils for domestic heating and fuel oil for power generation, has expanded at a rapid rate. As a result, the need for the lower boiling products developed, crude oils yielding the desired quantities of the lower boiling products became less available, and refineries had to introduce conversion processes to convert the higher boiling low-value fractions to the lower boiling high-value products. In order to produce the relevant (saleable) products, the means by which a refinery operates depends not only on the nature of the crude oil feedstock but also on the refinery configuration (such as the number and the types of the processes that are employed to produce the desired product DOI: 10.1201/9781003185314-1

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Hydrotreating and Hydrocracking Processes in Refining Technology

slate). In fact, the refinery must be configured according to the influence of the specific demands of a market. In fact, to meet the market demands, refineries need to be constantly adapted and upgraded to remain viable and responsive to ever-changing patterns of crude oil type and crude oil supply. In general, refining crude oil consists of two major phases of production, which are (1) dewatering and desalting followed by distillation or separating of the feedstock into various fractional components based on boing range and involves heating, vaporization, fractionation, condensation, and cooling of feedstock, and (2) cracking processes in which the larger molecular constituents of the feedstock are converted (broken down) into products that are of a lower molecular size and have increased volatility (Speight, 2021, 2022). As first performed using a high temperature and a high pressure, the process involved the use of catalysts to reduce the production of less valuable products such as heavy fuel oil (high-density, high-boiling fuel oil). As the 20th century matured, cracking technology evolved from the need to solve a series of technical issues such as (1) carbon deposition the catalyst surface, (2) catalyst breakage, and (3) equipment failure which led to the development of the fluid catalytic cracking process in the early 1940s. In the modern refinery, the refining activities commence with the receipt of a variety of feedstocks (which can be labeled as crude oil, heavy crude oil, extra heavy crude oil, and tar sand bitumen) for storage. To accomplish the production of saleable products, the flow of the feedstock through a processing flow scheme is determined by the composition of the feedstock and the desired slate of crude oil products (Figure 1.1), but the arrangement of these processes does vary among refineries, and few, if any, employ all of these processes.

FIGURE 1.1  General Outline of a Refinery Showing the Placement of the Hydroprocesses. (Speight, J.G. 2014. The Chemistry and Technology of Petroleum 5th Edition. CRC Press, Taylor & Francis Publishers, Boca Raton Florida. Figure 15.1, page 392.)

Hydroprocesses in the Refinery

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More specifically, a refinery is a group of manufacturing plants that vary in number according to the variety of products produced (Parkash, 2003; Gary et al., 2007; Speight, 2011a, 2014; Hsu and Robinson, 2017; Speight, 2017, 2020b). The processes – in the current context of the hydroprocessing units (Chapter 4) and the hydrocracking units (Chapter 5) – are selected to convert the refinery feedstocks crude oil (or fractions thereof) into products that are manufactured according to market demand. In addition, the current refinery operations include two or more feedstocks which are introduced into the refinery as a blend, thereby introducing the need to determine the compatibility of the various components of the blend and the stability of the blend (Speight, 2021). Moreover, to meet the current market demand for high-octane gasoline, jet fuel, and diesel fuel, any high-boiling fraction of the crude oil and heavy crude oil (such as the gas oil fraction, the residuum, as well as extra heavy crude oil and tar sand bitumen) must be converted to naphtha and other low-boiling fractions. It is in this respect that the older process options such as (1) the thermal cracking process, (2) the visbreaking process, and (3) the various coking processes are used to convert the crude oil constituents into products that are more volatile and can be prepared for sale to the various consumers (Parkash, 2003; Gary et al., 2007; Speight, 2011a, 2014; Hsu and Robinson, 2017; Speight, 2017, 2023). The feedstocks that are difficult to refine but, of necessity, are being accepted by refineries are the viscous feedstocks (often referred to as viscous feedstocks and include materials such as heavy crude oil, extra heavy oil, tar sand bitumen, as well as atmospheric residua and vacuum residua from the refinery distillation section) which are characterized by low API gravity (high density) and high viscosity, high initial boiling point, high-carbon residue, high nitrogen content, high sulfur content, and high metals content (Speight, 2021). In addition to these properties, the viscous feedstocks also have an increased molecular weight and reduced hydrogen content as well as a relatively low content of volatile saturated constituents and aromatic constituents. These feedstocks also contain a relatively high content of asphaltene constituent plus a relatively high content of resin constituents that is accompanied by a high heteroatom (nitrogen, oxygen, sulfur, and metals) content. Thus, the criteria for selection of upgrading options for the viscous feedstocks depend on several factors which must be analyzed in detail before an upgrading sequence is set into motion. The choice is, put simply, to apply (1) a carbon rejection technology sequence or (2) a hydrogen addition technology sequence. However, the deposition of coke on hydroprocessing and hydrocracking catalysts that can lead to fouling and subsequent corrosion as well as coke deposition on any catalysts employed for the process such as can (and will) happen during most types of thermally driven catalytic upgrading which deactivates the catalysts within short time interval (Parkash, 2003; Gary et al., 2007; Speight, 2011a, 2014, 2015; Hsu and Robinson, 2017; Speight, 2017). In addition, the presence of heavy metals (such as vanadium and nickel), sulfur, nitrogen, and other contaminants severely reduces the catalytic activity rapidly. On the other hand, hydrogen addition technologies typically produce a high yield of products which, when compared to the feedstock constituents, have (1) a lower molecular weight and a higher API gravity, (2) a lower density or a higher API gravity, (3) a lower content of sulfur and other contaminants, and (4) a higher commercial value than the products from the carbon rejection technologies, i.e., thermal cracking technologies as well as some of the catalytic cracking technologies) but do the means to produce the amounts of hydrogen and steam required for the hydroprocesses. In both cases, at some stage of the refinery processing options, the minimization of unwanted heteroatom species (such as sulfur, nitrogen, oxygen, and metals) and those contaminants with a high propensity for coke formation and deposition is necessary to sustain not only the activity of the catalyst but also the value of the product(s). In this respect, the presence of hydrogen not only elevates the extent of the removal of heteroatom contaminants that are present in the original refinery feedstock but also increases the ability of the process to accelerate the breakdown of higher molecular weight constituents to lower boiling

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Hydrotreating and Hydrocracking Processes in Refining Technology

products. Furthermore, feedstock conversion (FC) in the absence of concurrent (or consequent) hydrogen transfer without a catalyst (i.e., thermal cracking) may lead to a product that is unstable and incompatible not only with the other products but also with any unchanged feedstock in the reactor. For such feedstocks, a choice of different technologies (or, at least, a modified technology) may be necessary for the refiner to address these types of challenges. By customizing the approach to refining the viscous feedstocks through an understanding of the properties and behavior of such feedstocks, a refinery can meet the challenges that occur during viscous feedstock upgrading (Casey, 2011). For example, understanding the behavior of the feedstock under thermal conditions as well as under conditions in which there is an improved catalyst system with appropriate reactor internals makes it possible to provide optimal performance of the catalyst. In many cases, the successful selection of an emerging technology for viscous feedstock upgrading should consider at least (1) the type and properties of the feedstock to be processed, (2) the quality of upgraded product, (3) suitability of the process, (4) the ease of application of the process by way of the flexibility of the process, (5) the operating parameters in the reactor, and (6) the properties of the products and any by-products. Thus, a major decision at the time of acceptance of and the selection of processes for viscous feedstocks (or a blend of viscous feedstocks) is to acknowledge the practical aspects of upgrading which can include partial upgrading or full upgrading in a conversion refinery (Colyar, 2009). In addition, the regulatory need for the continuing reduction of the amount of sulfur in refinery products has created critical issues in relation to upgrading the viscous feedstocks into acceptable, lowsulfur products. Thus, a refinery must also be flexible and adaptable to changing the operations on an as needed basis, especially if the more viscous feedstocks (such as heavy crude oil, extra heavy crude oil, tar sand bitumen, and distillation residua) are feedstocks that are now commonly accepted and used by the refinery for the production of the necessary market-driven products. The conversion of conventional crude oil to products is well established by the evolution of the hydrogen-based processes but the conversion of viscous feedstocks is now in a significant transition period since the demand is increasing for the production of saleable products such as transportation fuels and solvents. However, in spite of any potential drawbacks or the difficulty of upgrading viscous feedstocks, originally referred to as resid upgrading (bottom of the barrel processing, which was shunned by many refineries in favor of asphalt production), offers a means by which refiners can lower the feedstock cost by using a viscous feedstock as part of a crude oil blend. Although the resid fluid catalytic cracking process (often referred to by the acronym RFCC process) remains one of the most attractive ways to economically upgrade viscous feedstocks into transportation fuels and decrease fuel oil production, there are alternative processing schemes that are applied according to the properties of the feedstock (Kressmann et al., 1998; 2000; Phillips and Liu, 2002; Parkash, 2003; Ross et al., 2005; Gary et al., 2007; Stratiev and Petkov, 2009; Bridjanian and Khadem Samimi, 2011; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017, 2020b, 2021). Nevertheless, there remains the need to understand the hydrotreating processes and the hydrocracking processes in order to (1) reduce and/or inhibit the formation of coke-forming precursors such as the formation of polynuclear aromatic products that are not originally present in the feedstock but are products of the process, and (2) separate an intermediate that produces low amounts of coke before (or during) conversion. An additional challenge for the refinery is to modify the conversion processes to take advantage of nickel and vanadium in the viscous feedstocks in order to generate a dispersed catalyst in situ as a means of reducing (if not eliminating) catalyst costs. Once the refinery feedstock has been cleaned and subjected to the distillation processes (atmospheric distillation and vacuum distillation), the conversion activities start with the cracking processes of which thermal cracking processes (including visbreaking) and catalytic cracking are the prime examples (Parkash, 2003; Hsu and Robinson, 2006; Gary et al., 2007; Speight, 2011a, 2014;

5

Hydroprocesses in the Refinery

Hsu and Robinson, 2017; Speight, 2017, 2020b, 2022). It is, at this stage, that the processing flow scheme (Figure 1.1) is largely determined by the composition of the crude oil feedstock and the slate of the desired products. Alternatively, the feedstock may be introduced to the hydrotreating process and/or hydrocracking process at this point. Thus, the options for feedstock processing must be selected and products manufactured to give a balanced operation in which the refinery feedstock is converted into a variety of products in amounts that are in accord with the demand for each. For example, the manufacture of products from the lower boiling portion of crude oil automatically produces a certain amount of higher boiling components (which is feedstock-dependent) due to the complex chemistry that occurs during the conversion processes. If the latter cannot be sold as, e.g., heavy fuel oil, these products will accumulate until refinery storage facilities are overwhelmed by the ever-increasing amount of the fuel oil. To prevent the occurrence of such a situation, the refinery must be flexible and be able to change operations as needed. This usually means the need for more processes such as (1) vacuum distillation to separate the high-boiling fractions, such as the high-boiling gas oil and asphalt, and (2) a hydrogen-based process to convert an excess of heavy fuel oil into more naphtha with coke as the residual product (Speight, 2021). In the feedstock, the basic elements of crude oil, hydrogen and carbon form the main input into a refinery, combining into thousands of individual constituents, and the economic recovery of these constituents varies with the individual crude oil according to its particular individual qualities, and the processing facilities of a particular refinery. In general, crude oil, once refined, yields a variety of types of fractions (often referred to as ‘cuts’) when the crude oil is distilled (Table 1.1). The gas fraction and the naphtha fraction form the lower boiling products and are usually considerably more valuable than the higher boiling fractions and provide gas (LPG), naphtha, automobile fuel (gasoline or ‘petrol’ as it is referred to in many other countries), motor fuel, and feedstocks, for the petrochemical industry (Table 1.2). TABLE 1.1 Boiling Fractions of Conventional Crude Oil Fraction

Boiling Range °C

Low-boiling naphtha High-boiling naphtha Middle distillatesb Kerosene Fuel oil Atmospheric gas oil Vacuum gas oil Light vacuum gas oil Heavy vacuum gas oil Residuum a

b

30–150 150–180 180–290 180–260 205–290 260–315 425–600 315–425 425–600 >510

°Fa 30–300 300–400 400–500 355–500 400–550 500–800 800–1,100 600–800 425–600 >950

For convenience, boiling ranges which can vary from refinery to refinery are approximate and, for convenience, are converted to the nearest 5°. Obtained in the ‘middle’ boiling range which is on the order of 180°C–260°C (355°F–500°F) during the crude oil distillation process. The middle distillates are named because the fractions are removed at mid-height in the ­distillation tower during the multi-stage distillation.

6

Hydrotreating and Hydrocracking Processes in Refining Technology

TABLE 1.2 Production of Starting Materials for Processing to Products Feedstock

Primary Process

Natural gas

Gas processing

Petrochemical feedstocks

Primary Products

Crude oil

Atmospherics distillation

Gas

Secondary Products

Other Products

Petrochemical feedstocks

Low-boiling naphtha Hydrotreater

Solvents Gasoline blend stock

High-boiling naphtha Hydrotreater

Solvents Gasoline blend stock

Reformer

Gasoline blend stock

Kerosene-middle distillate Hydrotreater

Gasoline blend stock Diesel fuel blend stock

Gas oil Hydrotreater

Fuel oil

Resid Vacuum distillation

Coker

Distillate

Vacuum gas oil

Coke

Hydrocracker

Gasoline blend stock

Blend stock

Diesel fuel blend stock Fuel oil Resid

Asphalt

Deasphalt

Deasphalted oil

Coker

Hydrocracker

Fuel oil

Resid

Asphalt

Distillate

Blend stock

Coke

Also, another valuable product, naphtha (which is a precursor to gasoline and solvents) is produced from the low boiling and the middle range of distillate cuts (sometimes referred to collectively as kerosene and/or as light gas oil) and is also used as a feedstock for the petrochemical industry (Table 1.3). The middle distillates refer to products from the middle boiling range of crude oil and include kerosene, diesel fuel, distillate fuel oil, and light gas oil and emerge from the atmospheric distillation unit between the naphtha and the heavy atmospheric gas oil (Figure 1.1). Waxy distillate (produced from the atmospheric distillation unit) and lower boiling constituents of lubricating oils are sometimes included in the middle distillates. The remainder of the crude oil includes the light vacuum gas oil (VGO) and heavy VGO (from which the higher boiling constituents of lubricating oil can be produced) and residuum (the non-volatile fraction of the atmospheric residuum) (Figure 1.1). The vacuum residuum with further deep distillation may also produce useful products but is more commonly used for asphalt production. The complexity of crude oil is emphasized insofar as the actual proportions of light, medium, and heavy fractions vary significantly from one crude oil to another.

7

Hydroprocesses in the Refinery

TABLE 1.3 Sources of Naphtha Process

Primary Product

Secondary Process

Secondary Product

Atmospheric distillation

Low-boiling naphtha High-boiling naphtha

Cracking Catalytic cracking

Petrochemical feedstock Low-boiling naphtha

Gas oil

Catalytic cracking

Low-boiling naphtha

Gas oil

Hydrocracking

Low-boiling naphtha

Gas oil

Catalytic cracking Hydrocracking

Low-boiling naphtha Low-boiling naphtha

Residuum

Coking

Low-boiling naphtha

Vacuum distillation

Cracking processes

Hydrocracking

Low-boiling naphtha

Low-boiling naphtha High-boiling naphtha

Cracking Catalytic cracking

Petrochemical feedstock Low-boiling naphtha

Gas oil

Catalytic cracking

Low-boiling naphtha

Gas oil

Hydrocracking

Low-boiling naphtha

To convert crude oil into desired products in an economically feasible and environmentally acceptable manner, refinery processes for crude oil are generally divided into three categories: (1) separation processes, of which distillation is the prime example, (2) conversion processes, of which coking and catalytic cracking are prime examples, and (3) finishing processes, of which hydrotreating to remove sulfur is a prime example. In addition, a refinery may be referred to as (1) a topping refinery or (2) a hydroskimming refinery or (3) a conversion refinery. The simplest refinery (the topping refinery) is designed to prepare feedstocks for petrochemical manufacture or for production of industrial fuels and consists of tankage, a distillation unit, recovery facilities for gases and light hydrocarbons, and the necessary utility systems (steam, power, and water-treatment plants). A topping refinery is highly dependent on local markets but the addition of hydrotreating and reforming units to this basic configuration results in a more flexible hydroskimming refinery, which can also produce desulfurized distillate fuels and high-octane gasoline. These types of refineries may produce up to half of their output as residual fuel oil, and they face increasing market loss as the demand for low-sulfur (even no-sulfur) high-sulfur fuel oil increases. The most versatile refinery configuration is the conversion refinery which incorporates all of the basic units found in both the topping and hydroskimming refineries, but it also features gas oil conversion plants such as catalytic cracking and hydrocracking units, olefin conversion plants such as alkylation or polymerization units, and, frequently, coking units for sharply reducing or eliminating the production of residual fuels (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). Modern conversion refineries may produce two-thirds of their output as unleaded gasoline, with the balance distributed between LPG, jet fuel, diesel fuel, and a small quantity of coke. Many such refineries also incorporate solvent extraction processes for manufacturing lubricants and petrochemical units with which to recover propylene, benzene, toluene, and xylenes for further processing into polymers. Finally, the yields and quality of refined crude oil products produced by a refinery depend on the mixture of crude oil used as feedstock and the configuration of the refinery. Light/sweet (conventional low-sulfur) crude oil has inherently greater yields of higher value low-boiling products such naphtha and kerosene. Heavy sour (high viscosity, high sulfur) crude oil produces higher yields of lower value higher boiling products that must be converted into the more preferable lower boiling products (Speight, 2013, 2014).

8

Hydrotreating and Hydrocracking Processes in Refining Technology

Since a refinery is a group of integrated manufacturing plants (Figure 1.1), each of which is selected to give a balanced production of saleable products in amounts that are in accord with the demand for each product, it is necessary to prevent the accumulation of non-saleable products; the refinery must be flexible and be able to change operations as needed. The complexity of crude oil is emphasized insofar as the actual amounts of the products vary significantly from one crude oil to another (Speight, 2014, 2016). In addition, the configuration of the conversion refineries may vary considerably from refinery to refinery insofar as a conversion refinery may be more oriented toward the production of gasoline (large reforming and/or catalytic cracking), whereas the configuration of other conversion refineries may be more oriented toward the production of middle distillates such as jet fuel and gas oil. Moreover, it is only by comprehensively considering factors such as (1) feedstock properties, (2) catalyst performance, (3) product specifications, (4) chemical kinetics, (5) operating conditions, and (6) running period that optimal results can be achieved. Therefore, further improvement of the various upgrading processes for the viscous feedstocks and the development of catalysts, which can tolerate a high content of impurities and metals in the feedstock, are two major challenges for the future. Catalyst activity, selectivity, particle size and shape, pore size and distribution, as well as the type of the reactor, have to be optimized according to the properties of the heavy oils and to the desired purification and conversion levels. In fact, a particularly crucial issue that has arisen within the latter half of the 20th century (and continues in the present) relates to the use of blends of any viscous feedstock with other viscous feedstocks as well as blends of any viscous feedstock with the more typical conventional refinery feedstock. Blending is one of the typical operations that a refinery must pursue not only to prepare a product to meet sales specifications but also to blend different crude oils and viscous feedstocks to produce a total feedstock (Parkash 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). Although simple in principle, the blending operation must be performed with care and diligence based on an understanding of the properties and composition of the feedstock to be blended and whether or not the constituents in the blend will be compatible and not result in the formation of a semi-solid or solid separate phase (Speight, 2014, 2017). Lack of attention to the properties of the individual feedstocks prior to the blending operations can (in the case of the high-asphaltene viscous feedstocks) lead to phase separation (fouling) prior to and during the refining operations because of the phenomenon of incompatibility of the different components of the blend (Schermer et al., 2004; Speight, 2014, 2015). Briefly, fouling as it pertains to the crude oil industry deposit formation, encrustation, deposition, scaling, scale formation, slagging, and sludge formation) which has an adverse effect on the refinery operations (Chapter 7). It is the accumulation of unwanted material within a processing unit or on the solid surfaces of the unit to the detriment of function. For example, when it does occur during refinery operations, the major effects include (1) loss of heat transfer as indicated by charge outlet temperature decrease and pressure drop increase, (2) blocked process pipes, (3) under-deposit corrosion and pollution, and (4) localized hot spots in reactors, all of which culminate in production losses and increased maintenance costs. Thus, the separation of solids occurs whenever the solvent characteristics of the liquid phase are no longer adequate to maintain polar and/or high-molecularweight material in solution. If attention is not paid to the phenomenon of incompatibility of the feedstocks either at the time of blending or because of the effects of elevated temperatures involved in the process, it can result in the occurrence of fouling deposits in heat transfer equipment and reactors (Stark and Asomaning, 2003; Van den Berg et al., 2003). Therefore, it is advisable for the refiner to be able to predict the potential for incompatibility by determining not only the appropriate components for the blend but also the ration of individual crude oils and viscous feedstocks in the blend. Such blends raise the issues of the compatibility of the constituents of the blends which is not always assured, and there can (as a result of blend instability) be excessive laydown of coke (and metals) on the catalyst. Thus, the conversion processes must be chosen accordingly and only after

Hydroprocesses in the Refinery

9

satisfactory test methods have been applied not only to the individual constituents of a blend but also to the blend itself. Once this has been accomplished, the viscous feedstock can proceed to the conversion step. However, incompatibility of the feedstock constituents and fouling (i.e., deposition of solids) by the incompatible constituents can lead to corrosion which is especially relevant when the viscous high-sulfur feedstocks are processed. In such cases, corrosion can occur where metal temperatures are on the order of 230°C–480°C (450°F–900°F). Above 480°C (>900°F), the coke forms a protective layer on the metal as well as deactivation of the catalyst. After presentation of the types of feedstocks that are currently acceptable to a refinery and the future feedstocks (such as the various types of biomass) that will also be acceptable to the future refinery, this chapter presents an introduction to the general layout of a crude oil refinery (with a brief description of the various processes) in order for the reader to place the hydroprocesses, notably (1) the hydrotreating processes and (2) the hydrocracking processes in the context of the overall refinery operations. These processes are important aspects of the conversion of the viscous feedstocks (heavy crude oil, extra heavy crude oil, tars and bitumen, and distillation residua) and while they are the focus of this book, but it would be remiss not to include the use of naphtha, kerosene, and gas oil as feedstocks to hydroprocesses. Furthermore, the refining industry has been the subject of the four major forces that affect most industries and which have hastened the development of new crude oil refining processes: (1) the demand for products such as gasoline, diesel, fuel oil, and jet fuel; (2) feedstock supply, specifically the changing quality of crude oil and geopolitics between different countries and the emergence of alternate feed supplies such as bitumen from tar sand (oil sand), natural gas, and coal; (3) technology development such as new catalysts and processes, especially processes involving the use of hydrogen; and (4) environmental regulations that include more stringent regulations in relation to sulfur in gasoline and diesel (Parkash, 2003; Speight, 2005; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). Categories 1, 2, and 4 are directly affected by the third category (i.e., the use of hydrogen in refineries) and it is this category that will be the subject of this chapter. This chapter presents an introduction to the use and need for hydrogen in crude oil refineries in order for the reader to place the use of hydrogen in the correct context of the refinery. In fact, the use of hydrogen is key insofar as the use of hydrogen allows a refinery to comply with the latest product specifications and environmental requirements for fuel production being mandated by market and governments and helping to reduce the carbon footprint of refinery operations. Thus, in order to fully comprehend the function of the various process units within refinery operations, it is necessary to understand the place at which the process units employed fit into the refinery and the reason for this employment. This will assist the reader to place the hydroprocessing units and hydrocracking units in the correct perspective of the refinery, not forgetting that prior to any conversion processes it is necessary to desalt, dewater, and distill the raw (i.e., unrefined) refinery feedstock.

1.2  HYDROGEN IN REFINERIES Hydrogen is the simplest and most abundant element in the universe and occupies a unique position in the Periodic Table of the Elements (Figure 1.2), but it rarely exists as a gas on the Earth. To be useful as a commodity in the refining industry, hydrogen can be produced from various sources, including fossil fuels, nuclear energy, and biomass. A critical issue facing the modern refinery is the changing landscape in processing crude oil into refined transportation fuels and other products under an environment of increasingly more stringent clean fuel regulations, decreasing heavy fuel oil demand and increasing supply of viscous feedstocks (that are typically referred to as heavy sour feedstocks or heavy high-sulfur feedstocks). Thus, the use of hydrogen is the key that allows refineries to comply with the latest product specifications and environmental requirements for the various products that are mandated by market and

10

Hydrotreating and Hydrocracking Processes in Refining Technology

FIGURE 1.2  The Periodic Table of the Elements Showing the Unique Position of Hydrogen.

governments and help to reduce the carbon footprint of the refineries. Typically, the hydrotreating catalyst is a porous alumina matrix impregnated with combinations of cobalt (Co), nickel (Ni), molybdenum (Mo), and tungsten (W). Moreover, the optimization of the hydrogen network is an important aspect of many refineries that incorporate hydroprocesses as part of the refinery configuration as refineries adapt to address clean fuel trends in order to meet growing transportation fuel demands and to continue to make a profit from their crudes (Long et al., 2011). A key element of a hydrogen network analysis in a refinery involves the capture of hydrogen in its fuel streams and extending its flexibility and processing options. Thus, innovative hydrogen network optimization will be a critical factor influencing future refinery operating flexibility and profitability in a shifting world of crude feedstock supplies and ultra-low-sulfur gasoline and diesel fuel. The chemical nature of the crude oil used as the refinery feedstock has always played the major role in determining the hydrogen requirements of that refinery. For example, the lighter, more paraffinic crude oils will require somewhat less hydrogen for upgrading to, say, a gasoline product than a heavier more asphaltic crude oil. It follows that the hydrodesulfurization of heavy oils and residua (which, by definition, is a hydrogen-dependent process) needs substantial amounts of hydrogen as part of the processing requirements. The history and evolution crude oil refining has been well described elsewhere (Speight, 2014, 2020b), and there is little need to repeat that work here except to note that it is not the intent of this chapter to ignore the myriad of processes in modern refineries that do not use hydrogen but may be dependent upon hydrogenated products in one way or another (Parkash, 2003; Gary et al., 2007; Speight, 2011a, 2014; Hsu and Robinson, 2017; Speight, 2017). Generally, the hydrotreating processes are similar in common elements and, in the process, the liquid feedstock is mixed with hydrogen and fed into a heater and the mixture is brought to the reaction temperature in a furnace and then fed into a fixed-bed catalytic reactor. The effluent is cooled and hydrogen-rich gas is separated using a high-pressure separator. Before the hydrogen is recycled, hydrogen sulfide can be removed using an amine scrubber. Some of the recycle gas is also purged to prevent the accumulation of low-boiling hydrocarbon derivatives (i.e., the C1–C4 derivatives) and to

Hydroprocesses in the Refinery

11

control hydrogen partial pressure. The liquid effluent for the reactor is introduced to a fractionator for product separation. A certain hydrogen partial pressure should be maintained in the reactors by recycling unreacted hydrogen and adding a make-up hydrogen to compensate for the amount consumed. The make-up hydrogen can be calculated by the following expression: Make-up hydrogen = hydrogen in feedstock − hydrogen consumed for chemical reguirement − hydrogen purged − amount of hydrogen dissolved in product The hydrogen purge is the amount of hydrogen lost with the purging of low-boiling hydrocarbons (the C1–C4 hydrocarbons, i.e., the methane, ethane, propane, and butane derivatives) and hydrogen sulfide (if not removed by amine treatment). This hydrogen can be predicted using flash calculation, or using the purge gas ratio. The purge ratio is defined as follows: Purge ratio = ( volume of hydrogen in the purged gas ) /(volume of hydrogen on the make-up gas) Mild processing conditions are employed so that only the more unstable materials are attacked. Thus, nitrogen, sulfur, and oxygen compounds undergo hydrogenolysis to split out ammonia, hydrogen sulfide, and water, respectively. Olefins are unsaturated, and unstable compounds, such as diolefins, which might lead to the formation of gums or insoluble materials, are converted to more stable compounds. Heavy metals present in the feedstock are also usually removed during hydrogen processing. In addition to hydrodesulfurization and hydrodenitrogenation (HDN), the removal of aromatic constituents from some product streams has also become essential. The high aromatic content in diesel fuel has been recognized both to lower the fuel quality and to contribute significantly to the formation of undesired emissions in exhaust gases. Indeed, as a result of the stringent environmental regulations, processes for aromatic reduction in middle distillates have received considerable attention in recent years (Stanislaus and Cooper, 1994). Unsaturated compounds, such as olefin derivatives, are not indigenous to crude oil and produced during cracking processes and need to be removed from product streams because of the tendency of unsaturated compounds and heteroatomic polar compounds to form gum and sediment. In addition, aromatic compounds are indigenous to crude oil and some may be formed during cracking reactions. The most likely explanation is that the aromatic compounds present in product streams are related to the aromatic compounds originally present in crude oil but now having shorter alkyl side chains. Thus, in addition to olefins, product streams will contain a range of aromatic compounds that have to be removed to enable many of the product streams to meet product specifications. Of the aromatic constituents, the polycyclic aromatics are first partially hydrogenated before cracking of the aromatic nucleus takes place. The sulfur and nitrogen atoms are converted to hydrogen sulfide and ammonia, but a more important role of the hydrogenation is probably to hydrogenate the coke precursors rapidly and prevent their conversion to coke. Without the required conversion units, the viscous feedstocks produce lower yields of naphtha and middle distillate. To maintain current gasoline and middle distillate production levels, additional conversion capacity is required because of the differential in the amount of distillates produced from light crude oil and the distillate products produced from heavier crude oil. The concept of hydrocracking allows the refiner to produce products having a lower molecular weight with higher hydrogen content and a lower yield of coke. Process parameters emphasize the relatively severe nature of the hydrocracking process. To take full advantage of hydrocracking, the process must be integrated in the refinery with other process units (Dolbear, 1998; Parkash, 2003; Brunet et al., 2005; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). If high-molecular-weight crude oil fractions are pyrolyzed, i.e., if no hydrogenation occurs, progressive cracking and condensation reactions generally lead to the final products. These products are

12

Hydrotreating and Hydrocracking Processes in Refining Technology

usually (1) gaseous and low-boiling liquid compounds of high hydrogen content, (2) liquid products of intermediate molecular weight with a hydrogen–carbon atomic ratio differing more or less from that of the original feedstock, depending on the method of operation, and (3) high-molecular-weight products, such as coke, possessing a lower hydrogen–carbon atomic ratio than the starting material. Highly aromatic or refractory recycle stocks or gas oils that contain varying proportions of highly condensed aromatic structures (e.g., naphthalene and phenanthrene) usually crack, in the absence of hydrogen, to yield intractable residues and coke (Dehghani et al., 2009). The rapid hydrogenation prevents adsorption of olefins on the catalyst and, hence, prevents their subsequent dehydrogenation, which ultimately leads to coke formation so that long on-stream times can be obtained without the necessity of catalyst regeneration. One of the most important reactions in hydrocracking is the partial hydrogenation of polycyclic aromatics, followed by rupture of the saturated rings to form substituted monocyclic aromatics. The side chains may then be split off to give iso-paraffins. It is desirable to avoid excessive hydrogenation activity of the catalyst so that the monocyclic aromatics become hydrogenated to naphthene derivatives. Furthermore, repeated hydrogenation leads to loss in octane number, which increases the catalytic reforming required to process the hydrocracked naphtha. Side chains of three or four carbon atoms are easily removed from an aromatic ring during catalytic cracking, but the reaction of aromatic rings with shorter side chains appears to be quite different. For example, hydrocracking single-ring aromatics containing four or more methyl groups produces largely iso-butane and benzene. It may be that successive isomerization of the feed molecule adsorbed on the catalyst occurs until a four-carbon side chain is formed, which then breaks off to yield iso-butane and benzene. Overall, coke formation is very low in hydrocracking since the secondary reactions and the formation of the precursors to coke are suppressed as the hydrogen pressure is increased. When applied to viscous feedstocks, the hydrocracking process can be used for processes such as (1) fuel oil desulfurization and (2) conversion of viscous feedstocks to lower boiling distillates. The products from hydrocracking are composed of either saturated or aromatic compounds; no olefins are found. In making gasoline, the lower paraffins formed have high octane numbers; for example, the five- and six-carbon number fractions have leaded research octane numbers of 99–100. The remaining gasoline has excellent properties as a feed to catalytic reforming, producing a highly aromatic gasoline that is capable of a high octane number. Both types of gasoline are suitable for premium-grade motor gasoline. Another attractive feature of hydrocracking is the low yield of gaseous components, such as methane, ethane, and propane, which are less desirable than gasoline. When making jet fuel, more hydrogenation activity of the catalysts is used, since jet fuel contains more saturates than gasoline. Like many refinery processes, the problems encountered in hydrocracking viscous feedstocks can be directly equated to the amount of complex, higher boiling constituents that may require pretreatment (Speight and Moschopedis, 1979; Reynolds and Beret, 1989; Speight, 2000, 2014, 2017). Processing these feedstocks is not merely a matter of applying know-how derived from refining conventional crude oils but requires knowledge of composition and properties. It is the physical and chemical composition of a feedstock that plays a large part not only in determining the nature of the products that arise from refining operations but also in determining the precise manner by which a particular feedstock should be processed. Indeed, the use of thermal (carbon rejection, the term typically used to indicate the formation of a high-carbon solid such as coke) processes and of hydrothermal (hydrogen addition) processes, which were inherent in the refineries designed to process lighter feedstocks, has been a particular cause for concern. This has brought about the evolution of processing schemes that accommodate the heavier feedstocks (Speight, 2011a). As a point of reference, an example of the former option is the delayed coking process in which the feedstock is converted to overhead with the concurrent deposition of coke, e.g., that used by Suncor, Inc., at their oil sands plant. The process can be simply illustrated as (1) a single-stage process or (2) a two-stage operation (Figure 1.3).

Hydroprocesses in the Refinery

13

FIGURE 1.3  A Single-Stage or Two-Stage Showing the Option for a Second Stage. (Speight, J.G. 2014. The Chemistry and Technology of Petroleum 5th Edition. CRC Press, Taylor & Francis Publishers, Boca Raton Florida. Figure 15.1, page 392.)

The single-stage process is typically employed to produce naphtha (the precursor to gasoline), while the two-stage process was developed primarily to produce high yields of gasoline from straight-run gas oil, and the first stage may actually be a purification step to remove sulfur-containing (as well as nitrogen-containing) organic materials. In many two-stage units, the unit is designed so that not all of the feedstock hydrocarbons to the first-stage reactor are hydrocracked (i.e., converted) into lower boiling, lower molecular weight hydrocarbons. Typically, the temperature in the second-stage reactor may range from 345°C to 425°C (650°F to 800°F) and the pressure may be on the order of from 1,200 to 3,000 psi. To a large extent, the amount of hydrogen consumption depends on the feedstock content of sulfur, nitrogen, olefins, and aromatics. The consumption of hydrogen in a hydrocracker may range from 1,000 to 3,000 standard cubic feet per barrel of feedstock. In terms of sulfur removal, it appears that non-asphaltene sulfur in non-asphaltene constituents may be removed before the more refractory sulfur in asphaltene constituents, thereby requiring through desulfurization. This is a good reason for processes to use an extinction-recycling technique to maximize desulfurization and the yields of the desired product. Significant conversion of

14

Hydrotreating and Hydrocracking Processes in Refining Technology

heavy feedstocks can be accomplished by hydrocracking at high severity (Howell et al., 1985). For some applications, the products boiling up to 340°C (650°F) can be blended to give the desired final product. Hydrocracking was initially used to upgrade low-value distillate feedstocks, such as cycle oils (highly aromatic products from a catalytic cracker that usually are not typically recycled to extinction for economic reasons), thermal gas oil, coking unit gas oil, as well as straight-run naphtha (i.e., naphtha from the distillation section of the refinery) and high-boiling cracked naphtha. While whole families of catalysts are required depending on feed available and the desired product slate or product character, the number of process stages is also important to catalysts choice. Generally, the refinery utilizes one of three options. Thus, depending on the feedstock being processed and the type of plant design employed (single-stage or two-stage), flexibility can be provided to vary product distribution among the following principal end products. Though several technologies exist to upgrade viscous feedstocks, selection of the optimum process units is very much dependent on each refiner’s needs and goals, with the market pull being the prime motivator (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). Furthermore, processing options systems to dig deeper into the barrel by converting more of the higher boiling materials to distillable products should not only be cost-effective and reliable, but also flexible. Hydrocracking is an extremely versatile process which can be utilized in many different ways such as conversion of the high-boiling aromatic streams which are produced by catalytic cracking or by coking processes. To take full advantage of hydrocracking the process must be integrated in the refinery with other process units (Figure 1.1).

1.3  RATIONALE FOR HYDROGEN USE The use of hydrogen in thermal processes is perhaps the single most significant advance in refining technology during the 20th century (Dolbear, 1998). In fact, hydrogenation processes are the principal processes used in the manufacture of naphtha and gasoline (Parkash, 2003; Brunet et al., 2005; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). Indeed, with the influx of the more viscous feedstocks into refineries, hydroprocessing will assume a greater role in the refinery of the future. While the lighter, sweet crude oils (i.e. low density, high API gravity, low-sulfur crude oils) require less processing, the viscous refinery feedstocks contain higher levels of sulfur as well as other contaminants. Processing the viscous feedstocks may also begin with the same distillation process as used for the conventional crude oils to produce intermediate products but additional steps are necessary. One such process is the hydrotreating process that was originally (and still is) introduced to remove sulfur (a downstream pollutant) and other undesirable compounds, such as unsaturated hydrocarbon derivatives and any nitrogen-containing constituents from the process stream. In the hydrotreating process, hydrogen is added to the feedstock stream over a bed of catalyst at an intermediate temperature and pressure, as well as other process parameters that are appropriate for the feedstock. As a result, sulfur-containing constituents react with hydrogen to form hydrogen sulfide (H 2S), while nitrogen compounds form ammonia (NH3) and any aromatic derivatives and olefin derivatives form saturated hydrocarbon products. The final product of the hydrotreating process is typically the original feedstock, but free of sulfur and other contaminants. On the other hand, the hydrocracking process is a much more severe operation to produce lower molecular weight products that can be used for the production of hydrocarbon fuels and solvents. Heavy (high-boiling) gas oil, or similar boiling range distillates react with hydrogen in the presence of a catalyst at high temperature and pressure and are converted (hydrocracked) to low-boiling distillate products (such as naphtha, kerosene, and middle distillates). Thus, hydrogen is preferred

Hydroprocesses in the Refinery

15

to the thermal cracking process insofar as it enables a significant reduction in the product boiling range by converting the majority of the feedstock into lower boiling products that are free of sulfur and other contaminants. Thus, hydrogenation processes for the conversion of crude oil fractions and crude oil products may be classified as (1) non-destructive processes, also known as hydrotreating processes, and (2) destructive processes, also known as hydrocracking processes, as well as hydrogenolysis processes which are characterized by the cleavage of carbon–carbon linkages accompanied by hydrogen saturation of the fragments to produce lower boiling products. Such treatment requires severe processing conditions and the use of high hydrogen pressures to minimize polymerization and condensation that lead to coke formation. Many other reactions, such as isomerization, dehydrogenation, and cyclization, occur under the drastic conditions employed. Thus, a comparison of hydrocracking with hydrotreating is useful in assessing the parts played by these two processes in refinery operations. For example, the hydrotreating of distillates may be considered (or defined) as the removal of nitrogen-containing, sulfur-containing, and oxygencontaining constituents in the feedstocks by the selective hydrogenation of these molecular species. The hydrotreating catalysts are usually cobalt plus molybdenum or nickel plus molybdenum (in the sulfide) form impregnated on an alumina base. The hydrotreating process conditions (1,000–2,000 psi hydrogen and approximately 370°C (700°F)) are such that appreciable hydrogenation of aromatics will not occur. However, the denitrogenating, desulfurizing, and de-oxygenating reactions are usually accompanied by small amounts of hydrogenation and hydrocracking. The purpose of the inclusion of hydroprocessing units in a refinery is (1) to improve existing crude oil products or develop new products or uses, (2) to convert inferior or low-grade materials into valuable products, and (3) to transform near-solid residua to liquid fuels. Products are as follows: (1) from naphtha: reformed feedstock and LPG; (2) from atmospheric gas oil: naphtha, kerosene, and petrochemical feedstock; (3) from VGO: LPG, naphtha, kerosene, and lubricating oil; and (4) from residuum: naphtha, kerosene, catalytic cracking feedstock, and feedstock for a coking unit. In addition, there are also several on-site goals that satisfy the feedstock requirement of other refinery processes, which relate to feedstock preparation for downstream units such as (1) hydrotreating naphtha fractions for removal of metal and sulfur, (2) removal of sulfur, metal, polynuclear aromatics derivatives and Conradson carbon precursors from VGO which is to be used as a feedstock for catalytic cracking units, and (3) pretreatment of hydrocracker feedstock to reduce sulfurcontaining constituents, nitrogen-containing constituents, and aromatic constituents. More specifically, a hydrotreating process consists of several attainable goals that provide onspecification products which are (1) kerosene and gas oil, (2) olefin saturation for stability improvement, (3) nitrogen removal, and (4) de-aromatization for kerosene to improve cetane number, which is the percentage of pure cetane in a blend of cetane and alpha-methyl-naphthalene. Furthermore, a growing dependence on high-heteroatom heavy oils and residua has emerged as a result of continuing decreasing availability of conventional crude oil through the depletion of reserves in the various parts of the world. Indeed, it is now clear that there are other problems involved in the processing of the heavier feedstocks and that these heavier feedstocks, which are gradually emerging as the liquid fuel supply of the future, need special attention. The term ‘refinery hydroprocesses’ (which includes hydrotreating processes and hydrocracking processes) refers to processes that use the principle that the presence of hydrogen during a thermal reaction of a crude oil feedstock will terminate many of the coke-forming reactions and enhance the yields of the lower boiling components such as gasoline, kerosene, and jet fuel. The outcome is the conversion of a variety of feedstocks to a range of products (Table 1.4) (Parkash, 2003; Gary et al., 2007; Speight, 2011, 2014; Hsu and Robinson, 2017; Speight, 2017, 2020b). The trend of processing more viscous and high-sulfur (sour) feedstocks, the shift in demand away from gasoline toward more distillate, and more stringent fuel qualities change the fuel and hydrogen balances in most refineries (Parkash, 2003; Ancheyta et al., 2005; Gary et al., 2007; Liu et al., 2009; Speight, 2011a, 2014; Hsu and Robinson, 2017; Speight, 2017).

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Hydrotreating and Hydrocracking Processes in Refining Technology

TABLE 1.4 Summary of Typical Hydrogen Application and Production Process in a Refinery Naphtha hydrotreater

Desulfurization of naphtha from atmospheric distillation; must hydrotreat the naphtha before sending to a catalytic reformer unit.

Distillate hydrotreater

Desulfurization of distillates after atmospheric or vacuum distillation; in some units, aromatic derivatives are hydrogenated to cycloparaffin derivatives or alkane derivatives. Hydrogenation of sulfur compounds to produce hydrogen sulfide as a feedstock for Claus plants. Conversion of normal (straight-chain) paraffin derivatives to iso-paraffin derivatives to improve the product properties (such as the octane number). Hydrogenation of viscous feedstocks to upgrade feedstocks fractions into lighter (low density, lower boiling) more valuable products. Conversion of naphtha-boiling range molecules into higher octane reformate. Hydrogen is a by-product. Produces hydrogen for the hydrotreaters or hydrocracker. Also, steam reforming of higher molecular weight hydrocarbons. Produces hydrogen from low-boiling hydrocarbon derivatives other than methane. Often contains hydrogen in the range up to 50% v/v. Recovery of hydrogen from synthesis gas produced in gasification units. Recovery of hydrogen from synthesis gas produced in gasification units. Analogous to gasification process. Produces synthesis gas from which hydrogen can be isolated.

Hydrodesulfurization Hydroisomerization Hydrocracker Catalytic reformer Steam-methane reformer

Process gas Gasification of residua Gasification of coke Partial oxidation process

Thus, in order to satisfy the changing pattern of product demand, there is an increased need for conversion processes that can be applied to the viscous feedstocks which will take the conversion of the viscous feedstocks beyond current limits and, at the same time, reduce the amount of coke and other non-essential products. Such a conversion scheme may require the use of two or more technologies in series rather than an attempt to develop a whole new one-stop conversion technology. Processes for the conversion of viscous feedstocks are available and include processes such as the visbreaking and coking options which augment the deasphalting units in many refineries operations. An example is the application of a mild visbreaking technology (Speight, 2014, 2022) which takes the feedstock just beyond the point of coke formation (and deposition). In this process, the initial (first-formed) coke forms on any particles of mineral matter in the feedstock, thereby encouraging demineralization of the feedstock along with removal of the constituents that readily form coke and removal of these forming constituents a minor de-coking operation (with concomitant demineralization) with the result that the product is amenable for use as a feedstock for a fluid catalytic cracking unit (Speight and Moschopedis, 1979; Speight, 1987). Hydrotreating achieves the following objectives in addition to those in the aforementioned paragraph and are (1) removal of impurities, such as sulfur, nitrogen, and oxygen for the control of a final product specification or for the preparation of feed for further processing (naphtha reformer feed and FCC feed); (2) removal of metals, usually in a separate guard catalytic reactor when the organometallic compounds are hydrogenated and decomposed, resulting in metal deposition on the catalyst pores as can often occur during the desulfurization of residua – such as atmospheric residua which is often referred to as the ARDS guard reactor; and (3) the saturation of olefin derivatives and their unstable compounds. In addition, the hydrogen requirement for product improvement, which is the hydrotreatment of crude oil products, to ensure that they meet utility and performance specifications, is also increasing. Product improvement can not only involve hydrotreatment but also changes in molecular shape (reforming and isomerization) or change in molecular size (alkylation and polymerization) and hydrotreating can play a major role in product improvement.

Hydroprocesses in the Refinery

17

Thus, there are several valid reasons for removing heteroatoms from crude oil fractions. These include: (1) reduction, or elimination, of corrosion during refining, handling, or use of the various products; (2) production of products having an acceptable odor and specification; (3) increasing the performance and stability of gasoline; (4) decreasing smoke formation in kerosene; and (5) reduction of heteroatom content in fuel oil to a level that improves burning characteristics and is environmentally acceptable. Heteroatom removal, as practiced in various refineries, can take several forms (Speight, 2000) such as concentration in residua during distillation, concentration in coke during coking, or chemical removal (acid treating, caustic treating, i.e., sweetening or finishing processes) (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). Nevertheless, the heteroatom removal from crude oil feedstocks is almost universally accomplished by the catalytic reaction of hydrogen with the feedstock constituents. However, there are certain other refinery processes which are adaptable to residua and heavy oils and which may be effective for reducing, but not necessarily effective for removing completely, the heteroatom content. Finally, when compared to hydrotreating, hydrocracking is an extremely versatile process which can be utilized in many different ways such as conversion of the high-boiling aromatic streams which are produced by catalytic cracking or by coking processes. To take full advantage of hydrocracking, the process must be integrated in the refinery with other process units (Figure 1.1).

1.4  PLACEMENT IN THE REFINERY The use of hydrogen in refinery processes is perhaps the single most significant advance in refining technology during the 20th century and is now an inclusion in most refineries (Figure 1.1). Hydrogenation processes for the conversion of crude oil fractions and crude oil products may be classified as (1) non-destructive hydrogenation and (2) destructive hydrogenation. The usual goal of hydrotreating is to hydrogenate olefins and to remove heteroatoms, such as sulfur, and to saturate aromatic compounds and olefins (Speight, 2000). On the other hand, hydrocracking is a process in which thermal decomposition is extensive and the hydrogen assists in the removal of the heteroatoms as well as mitigating the coke formation that usually accompanies thermal cracking of high-molecular-weight polar constituents.

1.4.1  Hydrotreating Processes The hydrotreating processes typically fall under the umbrella of non-destructive hydrogenation (hydrotreating, simple hydrogenation), generally used for the purpose of improving product quality without appreciable alteration of the boiling range (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). Mild processing conditions are employed so that only the more unstable materials are attacked. Nitrogen, sulfur, and oxygen compounds undergo reaction with the hydrogen to remove ammonia, hydrogen sulfide, and water, respectively. Unstable compounds which might lead to the formation of gums, or insoluble materials, are converted to more stable compounds. The process uses the principle that the presence of hydrogen during a thermal reaction of a crude oil feedstock will terminate many of the coke-forming reactions and enhance the yields of the lower boiling components (such as gasoline, kerosene, and gas oil) and the processing parameters vary depending upon the character and properties of the feedstock (Tables 1.4 and 1.5). On the other hand, destructive hydrogenation (also called hydrogenolysis or hydrocracking) is characterized by the conversion of feedstock higher molecular weight constituents to lower boiling value-added products. Such treatment requires severe processing conditions and the use of high hydrogen pressures to minimize polymerization and condensation reactions that lead to coke formation.

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Hydrotreating and Hydrocracking Processes in Refining Technology

TABLE 1.5 Process Parameters for Hydroprocessing Units Conditions Solid acid catalyst (silica-alumina with rare earth metals, various other options) Temperature: 260°C–450°C (500°F–845°F) (solid/liquid contact) Pressure: 1,000–6,000 psi hydrogen Catalyst life: up to 3 years for gas oil feedstocks Catalyst life: typically less than 1 year for viscous feedstocks Feedstocks Distillates Refractory (aromatic) streams Coker oils Cycle oils Gas oils Residua (as a full hydrocracking or hydrotreating option) Asphaltic constituents (S, N, and metals) removed by deasphalting Products Lower molecular weight paraffin derivatives Some methane, ethane, propane, and butane Hydrocarbon distillates (full range depending on the feedstock) Residual tar (recycle) Contaminants (asphaltic constituents) deposited on the catalyst as coke or metals Variations Fixed bed (suitable for liquid feedstocks) Ebullating bed (suitable for viscous feedstocks)

In a typical process, the feedstock is heated, mixed with hydrogen, and passed through a tower or reactor filled with catalyst pellets (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). The reactor is maintained at a temperature of 260°C–425°C (500°F–800°F) at pressures from 100 to 1,000 psi, depending on the particular process, the nature of the feedstock, and the degree of hydrogenation required. After leaving the reactor, excess hydrogen is separated from the treated product and recycled through the reactor after removal of hydrogen sulfide. The liquid product is passed into a stripping tower where steam removes dissolved hydrogen and hydrogen sulfide and cooled, after which the product is taken to product storage or, in the case of feedstock preparation, pumped to the next processing unit (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). More generally, the operating conditions of the hydrotreating processes include pressure, temperature, catalyst loading, feed flow rate, and hydrogen partial pressure. The hydrogen partial pressure must be greater than the hydrocarbon partial pressure. As approximations, remembering that the processing conditions can vary considerably, the range of operating conditions for hydrotreating of different feedstocks is as follows:

Naphtha

Kerosene

Gas oil

Vac gas oil

Resid

Boiling range

70–180

160–240

230–350

350–550

>550

Operating temp Hydrogen, psi

260–300 75–150

300–340 200–450

320–350 200–600

360–380 600–1,000

360–380 1,800–2,400

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Increasing hydrogen partial pressure improves the removal of sulfur and nitrogen compounds and reduces coke formation. Higher temperatures will increase the reaction rate constant and improve the kinetics. However, excessive temperatures will lead to thermal cracking and coke formation. The space velocity is the reverse of reactor residence time. High space velocity results in low conversion, low hydrogen consumption, and low coke formation. Finally, a word about conversion measures for upgrading processes. Such measures are necessary for any conversion process but more particularly for hydrocracking processes where hydrogen management is an integral, and essential, part of process design. The objective of any upgrading process is to convert heavy feedstock into marketable products by reducing their heteroatom (nitrogen, oxygen, and sulfur) and metal contents, modifying the structures of the asphaltene constituents (reducing coke precursors), and converting the high-molecularweight polar species large molecules into lower molecular weight and lower boiling hydrocarbon products. Upgrading processes are evaluated on the basis of liquid yield (i.e., naphtha, distillate and gas oil), heteroatom removal efficiency, FC, carbon mobilization (CM), and hydrogen utilization (HU), along with other process characteristics. Definition of RC, CM and HU are as follows:

FC = ( feedstock in – feedstock out ) feedstock in × 100



CM = carbon liquids /carbon feedstock × 100



HU = hydrogen liquids /hydrogen feedstock × 100

High CM ( Ni-Mo > Co-Mo > Co-W.

Nickel-tungsten (Ni-W) and nickel-molybdenum (Ni-Mo) on Al2O3 catalysts are widely used to reduce sulfur, nitrogen, and aromatics levels in crude oil fractions by hydrotreating. Molybdenum sulfide (MoS2), usually supported on alumina, is widely used in crude oil processes for hydrogenation reactions. It is a layered structure that can be made much more active by addition of cobalt or nickel. When promoted with cobalt sulfide (CoS), making what is called cobalt-moly catalysts, it is widely used in HDS processes. The nickel sulfide-promoted (NiS-promoted) version is used for HDN as well as HDS. The closely related tungsten compound (WS2) is used in commercial hydrocracking catalysts. Other sulfides (iron sulfide, FeS; chromium sulfide, Cr2S3; and

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Hydrotreating and Hydrocracking

vanadium sulfide, V2S5) are also effective and used in some catalysts. A valuable alternative to the base metal sulfides is palladium sulfide (PdS). Although it is expensive, palladium sulfide forms the basis for several very active catalysts. The life of a catalyst used to hydrotreat crude oil residua is dependent on the rate of carbon deposition and the rate at which organometallic compounds decompose and form metal sulfides on the surface. Several different metal complexes exist in the asphaltene fraction of the residuum and an explicit reaction mechanism of decomposition that would be a perfect fit for all of the compounds is not possible. However, in general, terms, the reaction can be described as hydrogen (A) dissolved in the feedstock contacting an organometallic compound (B) at the surface of the hydrotreating catalyst and producing a metal sulfide (C) and a hydrocarbon (D):

A + B ∧ C + D.

Different rates of reaction may occur with various types and concentrations of metallic compounds. For example, a medium-metal-content feedstock will generally have a lower rate of demetallization compared to high-metal-content feedstock. And, although individual organometallic compounds decompose according to both first- and second-order rate expressions, for reactor design, a secondorder rate expression is applicable to the decomposition of residuum as a whole. Obviously, choice of hydrogenation catalyst depends on what the catalyst designer wishes to accomplish. In catalysts to make gasoline, for instance, vigorous cracking is needed to convert a large fraction of the feed to the kinds of molecules that will make a good gasoline blending stock. For this vigorous cracking, a vigorous hydrogenation component is needed. Since palladium is the most active catalyst for this, the extra expense is warranted. On the other hand, many refiners wish only to make acceptable diesel, a less demanding application. For this, the less expensive molybdenum sulfides are adequate.

2.3.2  Hydrocracking Catalysts In general, the catalysts used in hydrocracking processes are all of the bifunctional type and combine an acid function and a hydrogenating function. The acid function is carried by supports with a large surface area and having a superficial acidity, such as halogenated alumina derivatives, zeolite derivatives, amorphous silica-alumina derivatives, and clay minerals. Palladium sulfide and promoted group VI metal sulfide derivatives (nickel-molybdenum or nickel-tungsten) provide the hydrogenation function. These active compositions saturate aromatics in the feed, saturate olefins formed in the cracking, and protect the catalysts from poisoning by coke. Zeolite derivatives or amorphous silica-alumina provide the cracking functions. The zeolite derivatives are usually type Y (faujasite), ion-exchanged to replace sodium with hydrogen and make up 25%–50% of the catalysts. Pentasils (silicalite or ZSM-5) may be included in dewaxing catalysts. Hydrocracking catalysts, such as nickel (5% w/w) on silica-alumina, work best on feedstocks that have been hydrotreated to low nitrogen and sulfur levels. The nickel catalyst then operates well at 350°C–370°C (660°F–700°F) and a pressure of about 1,500 psi to give good conversion of feed to lower boiling liquid fractions with minimum saturation of single-ring aromatics and a high isoparaffin to n-paraffin ratio in the lower molecular weight paraffins. The poisoning effect of nitrogen can be offset to a certain degree by operation at a higher temperature. However, the higher temperature tends to increase the production of material in the methane (CH4) to butane (C4H10) range and decrease the operating stability of the catalyst so that it requires more frequent regeneration. Catalysts containing platinum or palladium (approximately 0.5% wet) on a zeolite base appear to be somewhat less sensitive to nitrogen than nickel catalysts, and successful operation has been achieved with feedstocks containing 40 ppm nitrogen. This catalyst is also more tolerant of sulfur in the feed, which acts as a temporary poison, the catalyst recovering its activity when the sulfur content of the feed is reduced.

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Hydrotreating and Hydrocracking Processes in Refining Technology

On such catalysts as nickel or tungsten sulfide on silica-alumina, isomerization does not appear to play any part in the reaction, as uncracked normal paraffins from the feedstock tend to retain their normal structure. Extensive splitting produces large amounts of low-molecular-weight (C3–C6) paraffins, and it appears that a primary reaction of paraffins is catalytic cracking followed by hydrogenation to form iso-paraffins. With catalysts of higher hydrogenation activity, such as platinum on silica-alumina, direct isomerization occurs. The product distribution is also different, and the ratio of low- to intermediate-molecular-weight paraffins in the breakdown product is reduced. In addition to the chemical nature of the catalyst, the physical structure of the catalyst is also important in determining the hydrogenation and cracking capabilities, particularly for heavy feedstocks (Fischer and Angevine, 1986; Kobayashi et al., 1987a, b). When gas oils and residua are used, the feedstock is present as liquids under the conditions of the reaction. Additional feedstock and the hydrogen must diffuse through this liquid before reaction can take place at the interior surfaces of the catalyst particle. At high temperatures, reaction rates can be much higher than diffusion rates and concentration gradients can develop within the catalyst particle. Therefore, the choice of catalyst porosity is an important parameter. When feedstocks are to be hydrocracked to produce liquefied petroleum gas and naphtha, pore diffusion effects are usually absent. High surface area (about 300 m2/g) and low to moderate porosity (from 12 D Angstrom with crystalline acidic components to 50 D or more with amorphous materials) catalysts are used. With reactions involving high-molecular-weight feedstocks, pore diffusion can exert a large influence, and catalysts with pore diameters greater than 80 Å are necessary for more efficient conversion. Catalyst operating temperature can influence reaction selectivity since the activation energy for hydrotreating reactions is much lower than that for hydrocracking reaction. Therefore, raising the temperature in a residuum hydrotreater increases the extent of hydrocracking relative to hydrotreating, which also increases the hydrogen consumption. Molybdenum sulfide (MoS2), usually supported on alumina, is widely used in crude oil processes for hydrogenation reactions. It is a layered structure that can be made much more active by addition of cobalt or nickel. When promoted with cobalt sulfide (CoS), making what is called cobalt-moly catalysts, it is widely used in HDS processes. The nickel sulfide (NiS)-promoted version is used for HDN as well as HDS. The closely related tungsten compound (WS2) is used in commercial hydrocracking catalysts. Other sulfides (iron sulfide, FeS; chromium sulfide, Cr2S3; and vanadium sulfide, V2S5) are also effective and used in some catalysts. A valuable alternative to the base metal sulfides is palladium sulfide (PdS). Although it is expensive, palladium sulfide forms the basis for several very active catalysts. Clay minerals have been used as cracking catalysts particularly for heavy feedstocks, and have also been explored in the demetallization and upgrading of heavy crude oil. The results indicated that the catalyst prepared was mainly active toward demetallization and conversion of the heaviest fractions of crude oils. The cracking reaction results from attack of a strong acid on a paraffin chain to form a carbonium ion (a carbon cation, e.g., R+) (Dolbear, 1998). Strong acids come in two fundamental types, Brønsted and Lewis acids. Brønsted acids are the familiar proton-containing acids; Lewis acids are a broader class including inorganic and organic species formed by positively charged centers. Both kinds have been identified on the surfaces of catalysts; sometimes both kinds of sites occur on the same catalyst. The mixture of Brønsted and Lewis acids sometimes depends on the level of water in the system. Examples of Brønsted acids are the familiar proton-containing species such as sulfuric acid (H2SO4). Acidity is provided by the very active hydrogen ion (H+), which has a very high positive charge density. It seeks out centers of negative charge such as the pi-electrons in aromatic centers. The proton in strong acid systems behaves in much the same way, adding to the π-electrons (pi-electrons) and then migrating to a site of high electron density on one of the carbon atoms.

Hydrotreating and Hydrocracking

41

In reactions with hydrocarbons, both Lewis and Brønsted acids can catalyze cracking reactions. For example, the proton in Brønsted acids can add to an olefin double bond to form a carbon cation. Similarly, a Lewis acid can abstract a hydride from the corresponding paraffin to generate the same intermediate (Dolbear, 1998). Although these reactions are written to show identical intermediates in the two reactions, in real catalytic systems the intermediates would be different. This is because the carbon cations would probably be adsorbed on surface sites that would be different in the two kinds of catalysts. Zeolite derivatives and amorphous silica-alumina provide the cracking function in hydrocracking catalysts (Sherman, 1998). Both of these have similar chemistry at the molecular level, but the crystalline structure of the zeolite derivatives provides higher activities and controlled selectivity not found in the amorphous materials. Zeolite derivatives (Greek: zeo, to boil, and lithos, stone) consist primarily of silicon, aluminum, and oxygen and to host an assortment of other elements. In addition, zeolite derivatives are highly porous crystals veined with submicroscopic channels. The channels contain water (hence the bubbling at high temperatures), which can be eliminated by heating (combined with other treatments) without altering the crystal structure (Occelli and Robson, 1989). Typical naturally occurring zeolite derivatives include analcite (also called analcime, Na(AlSi2O6)), and faujasite (Na2Ca(AlO2)2(SiO2)4.H2O) that is the structural analog of the synthetic zeolite X and zeolite Y. Sodalite (Na8[(Al2O2)6(SiO2)6]Cl2) contains the truncated octahedral structural unit known as the sodalite cage that is found in several zeolite derivatives of the faces of the cage are defined by either four or six Al/Si atoms, which are joined together through oxygen atoms. The zeolite structure is generated by joining sodalite cages through the four-Si/ Al rings, so enclosing a cavity or super cage bounded by a cube of eight sodalite cages and readily accessible through the faces of that cube (channels or pores). Joining sodalite cages together through the six-Si/Al faces generates the structural frameworks of faujasite, zeolite X, and zeolite Y. In the zeolite derivatives, the effective width of the pores is usually controlled by the nature of the cation (M+ or M2+). Zeolite-A can form at temperatures below 100°C (212°F), but most zeolite syntheses require hydrothermal conditions (typically 150°C/300°F at the appropriate pressure). The reaction mechanism appears to involve dissolution of the gel and precipitation as the crystalline zeolite, and the identity of the zeolite produced depends on the composition of the solution. Aqueous alkali metal hydroxide solutions favor zeolite derivatives with relatively high aluminum contents, while the presence of organic molecules such as amines or alcohols favors highly siliceous zeolite derivatives such as silicalite or ZSM-5. Zeolite catalysts have also found use in the refining industry during the last two decades. Like the silica-alumina catalysts, zeolite derivatives also consist of a framework of tetrahedral usually with a silicon atom or an aluminum atom at the center. The geometric characteristics of the zeolite derivatives are responsible for their special properties, which are particularly attractive to the refining industry (DeCroocq, 1984). Specific zeolite catalysts have shown up to 10,000 times more activity than the so-called conventional catalysts in specific cracking tests. The mordenite-type catalysts are particularly worthy of mention since they have shown up to 200 times greater activity for hexane cracking in the temperature range of 360°C–400°C (680°F–750°F). Other zeolite catalysts have also shown remarkable adaptability to the refining industry. For example, the resistance to deactivation of the type Y-zeolite catalysts containing either noble or non-noble metals is remarkable, and catalyst life of up to 7 years has been obtained commercially in processing heavy gas oils in the Unicracking-JHC processes. Operating life depends on the nature of the feedstock, the severity of the operation, and the nature and extent of operational upsets. Gradual catalyst deactivation in commercial use is counteracted by incrementally raising the operating temperature to maintain the required conversion per pass. The more active a catalyst, the lower is the temperature required. When processing for gasoline, lower operating temperatures have the additional advantage that less of the feedstock is converted to iso-butane.

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Hydrotreating and Hydrocracking Processes in Refining Technology

Any given zeolite is distinguished from other zeolite derivatives by structural differences in its unit cell, which is a tetrahedral structure arranged in various combinations. Oxygen atoms establish the four vertices of each tetrahedron, which are bound to, and enclose, either a silicon (Si) or an aluminum (Al) atom. The vertex oxygen atoms are each shared by two tetrahedrons, so that every silicon atom or aluminum atom within the tetrahedral cage is bound to four neighboring caged atoms through an intervening oxygen. The number of aluminum atoms in a unit cell is always smaller than, or at most equal to, the number of silicon atoms because two aluminum atoms never share the same oxygen. The aluminum is actually in the ionic form and can readily accommodate electrons donated from three of the bound oxygen atoms. The electron donated by the fourth oxygen imparts a negative, or anionic, charge to the aluminum atom. This negative charge is balanced by a cation from the alkali metal or the alkaline earth groups of the periodic table (Table 2.2). Such cations are commonly sodium, potassium, calcium, or magnesium. These cations play a major role in many zeolite functions and help to attract polar molecules, such as water. However, the cations are not part of the zeolite framework and can be exchanged for other cations without any effect on crystal structure. Zeolite derivatives provide the cracking function in many hydrocracking catalysts, as they do in fluid catalytic cracking catalysts. The zeolite derivatives are crystalline aluminosilicates, and in almost all commercial catalysts today, the zeolite used is faujasite. Pentasil zeolite derivatives, including silicalite and ZSM-5, are also used in some catalysts for their ability to crack long chain paraffins selectively. Typical levels are 25%–50% by wt. zeolite in the catalysts, with the remainder being the hydrogenation component and a silica (SiO2) or alumina (Al2O3) binder. Exact recipes are guarded as trade secrets. Crystalline zeolite compounds provide a broad family of solid acid catalysts. The chemistry and structures of these solids are beyond the scope of this book. What is important here is that the zeolite derivatives are not acidic as crystallized. They must be converted to acidic forms by ion exchange processes. In the process of doing this conversion, the chemistry of the crystalline structure is often TABLE 2.2 Periodic Tale of the Elements

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Hydrotreating and Hydrocracking

changed. This complication provides tools for controlling the catalytic properties, and much work has been done on understanding and applying these reactions as a way to make catalysts with higher activities and more desirable selectivity. As an example, the zeolite faujasite crystallizes with the composition SiO2(NaAlO2)x(H2O)y. The ratio of silicon to aluminum, expressed here by the subscript x, can be varied in the crystallization from 1 to greater than 10. What does not vary is the total number of silicon and aluminum atoms per unit cell, 192. For legal purposes to define certain composition of matter patents, zeolite derivatives with a ratio of 1–1.5 are called type X; those with ratio greater than 1.5 are type Y. Both silicon and aluminum in zeolite derivatives are found in tetrahedral oxide sites. The four oxides are shared with another silicon or aluminum (except that two aluminum ions are never found in adjacent, linked tetrahedral). Silicon with a plus four charge balances exactly half of the charge of the oxide ions it is linked to; since all of the oxygen atoms are shared, silicon balances all of the charge around it and is electrically neutral. Aluminum, with three positive charges, leaves one charge unsatisfied. Sodium neutralizes this charge. The sodium, as expected from its chemistry, is not linked to the oxides by covalent bonds as the silicon and aluminum are. The attraction is simply ionic, and sodium can be replaced by other cations by ion exchange processes. In extensive but rarely published experiments, virtually every metallic and organic cation has been exchanged into zeolite derivatives in studies by catalyst designers. The most important ion exchanged for sodium is the proton. In the hydrogen ion form, faujasite zeolite derivatives are very strong acids, with strengths approaching that of oleum. Unfortunately, direct exchange using mineral acids such as hydrochloric acid is not practical. The acid tends to attack the silica-alumina network, in the same way that strong acids attack clays in the activation processes developed by Houdry. The technique adopted to avoid this problem is indirect exchange, beginning with exchange of ammonium ion for the sodium. When heated to a few hundred degrees, the ammonium decomposes, forming gaseous ammonia and leaving behind a proton:

R – NH +4 ∧ R – H + + NH 3 .

The step is accompanied by a variety of solid-state reactions that can change the zeolite structure in subtle but important ways (Speight, 2000, 2014, 2017). While zeolite derivatives provided a breakthrough that allowed catalytic hydrocracking to become commercially important, continued advances in the manufacture of amorphous silicaalumina made these materials competitive in certain kinds of applications. This was important, because patents controlled by Unocal and Exxon dominated the application of zeolite derivatives in this area. Typical catalysts of this type contain 60%–80% w/w of the silica alumina, with the remainder being the hydrogenation component. A typical level is on the order of 25% w/w alumina (Al2O3). Amorphous silica-alumina is made by a variety of precipitation techniques. The whole class of materials traces its beginnings to silica gel technology, in which sodium silicate is acidified to precipitate the hydrous silica-alumina sulfate; sulfuric acid is used as some or all of the acid for this precipitation, and a mixed gel is formed. The properties of this gel, including acidity and porosity, can be varied by changing the recipe – concentrations, order of addition, pH, temperature, aging time, and the like. The gels are isolated by filtration and washed to remove sodium and other ions. Careful control of the precipitation allows the pore size distributions of amorphous materials to be controlled but the distributions are still much broader than those in the zeolite derivatives. This limits the activity and selectivity. One effect of the reduced activity has been that these materials have been applied only in making middle distillates: diesel and turbine fuels. At higher process severities, the poor selectivity results in the production of unacceptable amounts of methane (CH4) to butane (C4H10) hydrocarbons. Hydrocarbons, especially aromatic hydrocarbons, can react in the presence of strong acids to form coke. This coke is a complex polynuclear aromatic material that is low in hydrogen. Coke can

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Hydrotreating and Hydrocracking Processes in Refining Technology

deposit on the surface of a catalyst, blocking access to the active sites and reducing the activity of the catalyst. Coke poisoning is a major problem in fluid catalytic cracking catalysts, where coked catalysts are circulated to a fluidized-bed combustor to be regenerated. In hydrocracking, coke deposition is virtually eliminated by the catalyst’s hydrogenation function. However, the product referred to as coke is not a single material. The first products deposited are tarry deposits that can, with time and temperature, continue to polymerize. Acid catalyzes these polymerizations. The stable product would be graphite, with very large aromatic sheets and no hydrogen. This product forms only with very high-temperature aging, far more severe than that found in a hydrocracker. The graphitic material is both more thermodynamically stable and less kinetically reactive. This kinetic stability results from the lack of easily hydrogenated functional groups. Catalysts carrying coke deposits can be regenerated by burning off the accumulated coke. This is done by service in rotary or similar kilns rather than leaving catalysts in the hydrocracking reactor, where the reactions could damage the metals in the walls. Removing the catalysts also allows inspection and repair of the complex and expensive reactor internals, discussed below. Regeneration of a large catalyst charge can take weeks or months, so refiners may own two catalyst loads, one in the reactor, and one regenerated and ready for reload. The thermal reactions also convert the metal sulfide hydrogenation functions to oxides and may result in agglomeration. Excellent progress has been made since the 1970s in regenerating hydrocracking catalysts; similar regeneration of hydrotreating catalysts is widely practiced. After combustion to remove the carbonaceous deposits, the catalysts are treated to disperse active metals. Vendor documents claim more than 95% recovery of activity and selectivity in these regenerations. Catalysts can undergo successive cycles of use and regeneration, providing long functional life with these expensive materials. As illustrated above for various forms of more conventional hydrocracking, the type of catalyst used can influence the product slate obtained. Indeed, several catalytic systems have now been developed with a group of catalysts specifically for mild hydrocracking operations. Depending on the type of catalyst, they may be run as a single catalyst or in conjunction with a hydrotreating catalyst. Proper selection of the types of catalysts employed can even permit partial conversion of heavy gas oil feeds to diesel and lighter products at the low hydrogen partial pressures for which gas oil hydrotreaters are normally designed. This ‘mild hydrocracking process’ (so-called because of the relatively ‘mild’ process parameters which do not allow the chemical reactions to proceed to completion) has been attracting a great deal of interest from refiners who have existing hydrotreaters and wish to increase their refinery’s conversion of fuel oil into lower boiling higher value products (Parkash, 2003; Brunet et al., 2005; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). In a well-designed hydrocracking catalyst system, the hydrogenation function adds hydrogen to the tarry deposits. This reduces the concentration of coke precursors on the surface. There is, however, a slow accumulation of coke that reduces activity over 1–2 years period. Refiners respond to this slow reduction in activity by raising the average temperature of the catalyst bed to maintain conversions. Eventually, however, an upper limit to the allowable temperature is reached and the catalyst must be removed and regenerated. Catalysts carrying coke deposits can be regenerated by burning off the accumulated coke. This is done by service in rotary or similar kilns rather than leaving catalysts in the hydrocracking reactor, where the reactions could damage the metals in the walls. Removing the catalysts also allows inspection and repair of the complex and expensive reactor internals, discussed below. Regeneration of a large catalyst charge can take weeks or months, so refiners may own two catalyst loads, one in the reactor and the other regenerated and ready for reload. Catalysts used in residuum upgrading processes typically use an association of several kinds of catalysts, each of them playing a specific and complementary role (Kressmann et al., 1998). Therefore,

Hydrotreating and Hydrocracking

45

the hydrodemetallization catalyst must desegregate asphaltene constituents and remove as much metals (nickel and vanadium) as possible. One catalyst in particular has been developed by optimizing the support pore structure and acidity (Toulhoat et al., 1990). This catalyst allows a uniform distribution of metals deposited and therefore, a high metal retention capacity is reached. A specific HDS catalyst can be placed downstream the hydrodemetallization catalyst and the main function of such positioning is to desulfurize the already deeply demetallized feedstock as well as to reduce coke precursors (1999). Thus, the main function of the HDS catalyst is not the same function as that of the hydrodemetallization catalyst. In addition, for fixed-bed processes, swing guard reactors may be used to improve the protection of downstream catalysts and increases the unit cycle length. For example, the Hyvahl Process (q.v.) includes two swing guard reactors followed by conventional hydrodemetallization and HDS reactors (DeCroocq, 1997). The hydrodemetallization catalyst in the guard reactors may be replaced during unit operation and the total catalyst amount is replaced at the end of a cycle.

2.3.3  Use of Biocatalysts A more recent development of hydroprocesses is the use of biocatalysts to desulfurize feedstocks (McFarland et al., 1998; El-Gendy and Speight, 2016; Speight and El-Gendy, 2018; El-Gendy and Speight, 2022; El-Gendy et al., 2022). Refiners are being continually challenged to produce products with ever-decreasing levels of sulfur. At the same time, the supplies of light, low-sulfur crude oil that favor distillate production are limited and even decreasing. Generally, the sulfur content of crude oil continues to rise (Speight, 2011a, b) with the accompanying decrease in API gravity and an increase in the proportion of residua in the crude oil. These factors require the crude oil to be processed more severely to produce gasoline and other transportation fuels. Thus, many refineries are now configured for maximum gasoline production that also includes increasingly processing highly aromatic distillate byproducts, such as light cycle oil, for the additional feedstock to produce more distillate. In microbial enhanced oil recovery processes, microbial technology is exploited in oil reservoirs to improve recovery. In the process, injected nutrients, together with indigenous or added microbes, promote in situ microbial growth and/or generation of products which mobilize additional oil and move it to producing wells through reservoir repressurization, interfacial tension/oil viscosity reduction, and selective plugging of the most permeable zones. Biocatalyst desulfurization of crude oil distillates is one of a number of possible modes of applying biologically based processing to the needs of the crude oil industry (McFarland et al., 1998; Setti et al., 1999; Abbad-Andaloussi et al., 2003; Mohebali and Ball, 2008). When straight-run naphtha containing various organic sulfur compounds was treated with immobilized cells of mycobacterium goodie for 24 hours at 40°C (104°F), the total sulfur content significantly decreased, from 227 to 71 ppm at 40°C. Furthermore, when immobilized cells were incubated at 40°C (104°F) with Mycobacterium goodii, the sulfur content of the gasoline decreased from 275 to 54 ppm in two consecutive reactions. The soil-isolated strain microbe identified as Rhodococcus erythropolis can efficiently desulfurize benzo-naphtho-thiophene (Figure 2.1) (Yu et al., 2006). The desulfurization product was α-hydroxy-ß-phenyl-naphthalene. Resting cells were able to desulfurize diesel oil (total organic sulfur, 259 ppm) after HDS and the sulfur content of diesel oil was reduced by 94.5% after 24 hours at 30°C (86°F). Biodesulfurization of crude oils was also

FIGURE 2.1  Benzo-naphtho-thiophene.

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Hydrotreating and Hydrocracking Processes in Refining Technology

investigated, and after 72 hours at 30°C (86°F), 62.3% of the total sulfur content in Fushun crude oil (initial total sulfur content, 3,210 ppm) and 47.2% of the sulfur in Sudanese crude oil (initial total sulfur, 1,237 ppm) were removed (see also Abbad-Andaloussi et al., 2003). Heavy crude oil recovery, facilitated by microorganisms, was suggested in the 1920s and received growing interest in the 1980s as microbial enhanced oil recovery. However, such projects have been slow to get under way, although in situ biosurfactant and biopolymer applications continue to garner interest (Van Hamme et al., 2003). In fact, studies have been carried out on biological methods of removing heavy metals such as nickel and vanadium from crude oil distillate fractions, coal-derived liquid shale, bitumen, and synthetic fuels. However, further characterization on the biochemical mechanisms and bioprocessing issues involved in crude oil upgrading are required in order to develop reliable biological processes. For upgrading options, the use of microbes has to show a competitive advantage of enzyme over the tried-and-true chemical methods prevalent in the industry. Currently, the range of reactions using microbes is large but is usually related to production of bioactive compounds or precursors. But the door is not closed and the issues of biodesulfurization and bio-upgrading remain open for the challenge of bulk crude oil processing. These drawbacks limit the applicability of this technology to specialty chemicals and steer it away from bulk crude oil processing. Biodesulfurization is, therefore, another technology to remove sulfur from the feedstock. However, several factors may limit the application of this technology. Many ancillary processes novel to crude oil refining would be needed, including a biocatalyst fermenter to regenerate the bacteria. The process is also sensitive to environmental conditions such as sterilization, temperature, and residence time of the biocatalyst. Finally, the process requires the existing hydrotreater to continue in operation to provide a lower sulfur feedstock to the unit and is more costly than conventional hydrotreating. Nevertheless, the limiting factors should not stop the investigations of the concept and work should be continued with success in mind. Once the concept has been proven on the scale that a refiner would require, the successful microbial technology will most probably involve a genetically modified bacterial strain for (1) upgrading distillates and other crude oil fractions in refineries, (2) upgrading crude oil upstream, and (3) dealing with environmental problems that ace industry, especially in areas related to spillage of crude oil and products. These developments are part of a wider trend to use bioprocessing to make products and do many of the tasks that are accomplished currently by conventional chemical processing. If commercialized for refineries, however, biologically based approaches will be at scales and with economic impacts beyond anything previously seen in industry. In addition, the successful biodesulfurization process will, most likely, be based on naturally occurring aerobic bacteria that can remove the organically bound sulfur in heterocyclic compounds without degrading the product value of the hydrocarbon matrix. However, because of the susceptibility of bacteria to heat, the process will need to operate at temperatures and pressures close to ambient and also use air to promote sulfur removal from the feedstock.

2.3  PROCESS PARAMETERS One of the problems in the processing of high-sulfur feedstocks and/or high-nitrogen feedstocks is the large quantity of hydrogen sulfide (H2S) and ammonia (NH3) that are produced. Substantial removal of both compounds from the recycle gas can be achieved by the injection of water in which, under the high-pressure conditions employed, both hydrogen sulfide and ammonia are very soluble compared with hydrogen and hydrocarbon gases. The solution is processed in a separate unit for the recovery of anhydrous ammonia and hydrogen sulfide. The principal variables affecting the required severity in distillate desulfurization are: (1) hydrogen partial pressure, (2) space velocity, (3) reaction temperature, and (4) feedstock properties (Table 2.3).

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TABLE 2.3 Process Parameters for Hydrodesulfurization Parameter

Naphtha

Residuum

Temperature, °C °F Pressure, psi Liquid hourly space velocity (LHSV) Hydrogen recycle rate, scf/bbl Catalysts life, years Sulfur removal, % Nitrogen removal, %

300–400 570–750 500–1,000 4.0–10.0 400–1,000 3.0–10.0 99.9 99.5

340–425 645–800 800–2,500 0.2-1.0 3,000–5,000 0.5–1.0 85.0 40.0

Hydrotreating is carried out by charging the feed to the reactor, together with a portion of all the hydrogen produced in the catalytic reformer. Suitable catalysts are tungsten-nickel sulfide, cobaltmolybdenum-alumina, nickel oxide-silica-alumina, and platinum-alumina. Most processes employ cobalt-molybdenum catalysts, which generally contain about 10% by weight molybdenum oxide and less than 1% by weight cobalt oxide supported on alumina. The temperatures employed are in the range of 300°C–345°C (570°F–850°F), and the hydrogen pressures are about 500–1,000 psi. The reaction generally takes place in the vapor phase but, depending on the application, may be a mixed-phase reaction. The reaction products are cooled in a heat exchanger and led to a highpressure separator where hydrogen gas is separated for recycling. The product may then be fed to a reforming or cracking unit if desired. The advantages are: (1) the products require less finishing; (2) sulfur is removed from the catalytic cracking feedstock, and corrosion is reduced in the cracking unit; and (3) coke formation during cracking is reduced and higher conversions result, and the catalytic cracking quality of the gas oil fraction is improved. Although hydrocracking will occur during hydrotreating, attempts are made to minimize such effects but the degree of cracking is dependent on the nature of the feedstock. For example, decalin (decahydronaphthalene) cracks more readily than the corresponding paraffin analog, n-decane, [CH3(CH2)8CH3] to give higher iso-paraffin to n-paraffin product ratios than those obtained from the paraffin. A large yield of single-ring naphthenes is also produced, and these are resistant to further hydrocracking and contain a higher than equilibrium ratio of methyl cyclopentane to cyclohexane. When applied to residua, the hydrotreating processes can be used for processes such as (1) fuel oil desulfurization and (2) residuum hydrogenation, which is accompanied by HDS, HDN, and partial conversion to produce products suitable as feedstocks for other processes, such as catalytic cracking. One of the chief problems with hydroprocessing residua is the deposition of metals, in particular vanadium, on the catalyst. It is not possible to remove vanadium from the catalyst, which must therefore be replaced when deactivated, and the time taken for catalyst replacement can significantly reduce the unit time efficiency. Fixed-bed catalysts tend to plug owing to solids in the feed or carbon deposits when processing residual feeds. As mentioned previously, the highly exothermic reaction at high conversion gives difficult reactor design problems in heat removal and temperature control. The problems encountered in hydrotreating heavy feedstocks can be directly equated to the amount of complex, higher boiling constituents that may require pretreatment (Speight and Moschopedis, 1979; Reynolds and Beret, 1989). Processing these feedstocks is not merely a matter of applying know-how derived from refining conventional crude oils but requires knowledge of the composition. The materials are not only complex in terms of the carbon number and boiling point ranges but also because a large part of this envelope falls into a range of model

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compounds and very little is known about the properties. It is also established that the majority of the higher molecular weight materials produce coke (with some liquids) but the majority of the lower molecular weight constituents produce liquids (with some coke). It is to both of these trends that hydrocracking is aimed. It is the physical and chemical composition of a feedstock that plays a large part not only in determining the nature of the products that arise from refining operations but also in determining the precise manner by which a particular feedstock should be processed (Speight, 1986, 2011a). Indeed, the use of thermal (carbon rejection) processes and hydrothermal (hydrogen addition) processes, which were inherent in the refineries designed to process lighter feedstocks, has been a particular cause for concern. This has brought about the evolution of processing schemes that accommodate the heavier feedstocks (Khan and Patmore, 1998; Speight, 2011a). The choice of processing schemes for a given hydrotreating application depends upon the nature of the feedstock as well as the product requirements (Suchanek and Moore, 1986). For higher boiling feedstocks, the process is usually hydrocracking and can be simply illustrated as a single-stage or as a two-stage operation (Figure 2.2). Variations to the process are feedstocks-dependent.

FIGURE 2.2  A Single-Stage or Two-Stage Showing the Option for a Second Stage. (Speight, J.G. 2014. The Chemistry and Technology of Petroleum 5th Edition. CRC Press, Taylor & Francis Publishers, Boca Raton, Florida. Figure 15.1, page 392.)

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FIGURE 2.3  A Distillate Hydrotreater for Hydrodesulfurization. (Speight, J.G. 2014. The Chemistry and Technology of Petroleum, 5th Edition. CRC Press, Taylor & Francis Publishers, Boca Raton, Florida. Figure 15.1, page 392.)

For example, the single-stage process (Figure 2.3) can be used to produce naphtha (which is a blend stock for gasoline and solvents) but is more often used to produce middle distillates from higher boiling feedstocks such as the vacuum gas oils. The two-stage process (Figure 2.2) was developed primarily to produce high yields of gasoline from straight-run gas oil, and the first stage may actually be a purification step to remove sulfurcontaining (as well as nitrogen-containing) organic materials. Both processes use an extinction-recycling technique to maximize the yields of the desired product. Significant conversion of heavy feedstocks can be accomplished by hydrocracking at high severity (Howell et al., 1985). For some applications, the products boiling up to 340°C (650°F) can be blended to give the desired final product. For lower boiling feedstocks, the commercial processes for treating or finishing crude oil fractions with hydrogen all operate in essentially the same manner. The feedstock is heated and passed with hydrogen gas through a tower or reactor filled with catalyst pellets (Figure 2.3). The reactor is maintained at a temperature of 260°C–425°C (500°F–800°F) at pressures from 100 to 1,000 psi, depending on the particular process, the nature of the feedstock, and the degree of hydrogenation required. The liquid product is passed into a stripping tower, where steam removes dissolved hydrogen and hydrogen sulfide, and after cooling the product is run to finished product storage or, in the case of feedstock preparation, pumped to the next processing unit. Excessive contact time and/or temperature will create coking. Precautions need to be taken when unloading coked catalyst from the unit to prevent iron sulfide fires. The coked catalyst should be cooled to below 49°C (300 ppm) of metalcontaining constituents substantially increase catalyst consumption because the metals poison the catalyst, thereby requiring frequent catalyst replacement. The typical desulfurization catalyst is a relatively expensive material for these consumption rates, but there are catalysts that are relatively inexpensive and can be used in the first reactor to remove a large percentage of the metals. Subsequent reactors downstream of the first reactor would use the typical HDS catalyst. Thus, one method of controlling demetallization is to employ separate smaller guard reactors immediately prior to HDS reactor. The preheated feedstock and hydrogen pass through the guard reactors that are filled with the appropriate (demetallization) catalyst for demetallization that is often (as long as economics allows it) the same as the catalyst used in the HDS section. The feedstock is alternated between guard reactors while catalyst in the idle guard reactor is being replaced. When the expanded-bed design is used, the first reactor could employ a relatively low-cost catalyst to remove the metals and subsequent reactors can use the more selective HDS catalyst. The demetallization catalyst can be added continuously without taking the reactor out of service and the spent demetallization catalyst can be loaded to more than 30% w/w vanadium, which makes the demetallization catalyst a valuable source of vanadium. The advantage of this system is that it enables replacement of the most contaminated catalyst (i.e., the guard bed), where pressure drop is highest, without having to replace the entire inventory or shut down the unit. When the expanded-bed design is used, the first reactor could employ a low-cost catalyst (5% of the cost of Co/Mo catalyst) to remove the metals and subsequent reactors can use the more selective hydrodesulfurization catalyst.

REFERENCES Abbad-Andaloussi, S., Warzywoda, M., and Monot, F. 2003. Microbial Desulfurization of Diesel Oils by Selected Bacterial Strains. Révue Institut Français du Pétrole, 58(4): 505–513. Abulnaga, B. 2021. Slurry Systems Handbook. McGraw-Hill Education, New York, pp. 825–829. Ancheyta, J., Rana, N.S., and Furimsky, E. 2005. Hydroprocessing of Heavy Petroleum Feeds. Catalysis Today, 109: 3–15. Ancheyta, J., and Speight, J.G. 2007. Hydroprocessing of Heavy Oils and Residua. CRC Press, Taylor & Francis Group, Boca Raton, Florida.

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Bartholdy, J., and Andersen, S.I. 2000. Changes in Asphaltene Stability during Hydrotreating. Energy & Fuels, 14: 52–55. Brunet, S, Mey, D., Guy Pérot, G., Bouchy, C., and Diehl, F. 2005. On the Hydrodesulfurization of FCC Gasoline: A Review. Applied Catalysis A: General, 278: 143–172. DeCroocq, D. 1984. Catalytic Cracking of Heavy Petroleum Hydrocarbons. Editions Technip, Paris. DeCroocq, D. 1997. Major Scientific and Technical Challenges about Development of New Processes in Refining and Petrochemistry. Révue Institut Français du Pétrole, 52(5): 469–489. Dolbear, G.E. 1998. Hydrocracking: Reactions, Catalysts, and Processes. In: Petroleum Chemistry and Refining. J.G. Speight (Editor). Taylor & Francis, Washington, DC. Duduković, M.P., Larachi, F., and Mills, P.L. 2002. Multiphase Catalytic Reactors: A Perspective on Current Knowledge and Future Trends. Catalysis Reviews: Science and Engineering, 49: 123–246. https://www. tandfonline.com/doi/abs/10.1081/CR-120001460 Eccles, R.M. 1993. Residue Hydroprocessing Using Ebullated-Bed Reactors. Fuel Processing Technology, 35: 21–38. El-Gendy, N.Sh., Nassar, H.N., and Speight, J.G. 2022. Petroleum Nanobiotechnology: Modern Applications for a Sustainable Future. Apple Academic Press-CRC Press, Taylor & Francis Group, Palm Bay Florida. El-Gendy, N.Sh., and Speight, J.G. 2016. Handbook of Refinery Desulfurization. CRC Press, Taylor & Francis Group, Boca Raton, Florida. El-Gendy, N.Sh., and Speight, J.G. 2022. Biotechnology in the Refinery. In: Hydrocarbon Biotechnology: Challenges and Future Trends, W.A. Ismail and J. Van Hamme (Editors). Apple Academic Press, CRC Press, Taylor & Francis Group, Boca Raton, Florida. Fischer, R.H., and Angevine, P.V. 1986. Dependence of Resid Processing Selectivity on Catalyst Pore Size Distribution. Applied Catalysis, 27: 275–283. Gary, J.G., Handwerk, G.E., and Kaiser, M.J. 2007. Petroleum Refining: Technology and Economics 5th Edition. CRC Press, Taylor & Francis Group, Boca Raton, Florida. Ho, T.C. 1988. Hydrodenitrogenation Catalysis. Catalysis Reviews Science and Engineering, 30: 117–160. Howell, R.L., Hung, C., Gibson, K.R., and Chen, H.C. 1985. Catalyst Selection Important for Residuum Hydroprocessing. Oil & Gas Journal, 83(30): 121–128. Hsu, C.S., and Robinson, P.R. (Editors). 2017. Handbook of Petroleum Technology. Springer, Cham, Switzerland. Jacobs, P.A. 1986. In: Metal Clusters in Catalysis, Studies in Surface Science and Catalysis. B.C. Gates (Editor). Elsevier, Amsterdam, Vol. 29, p. 357. Khan, M.R., and Patmore, D.J. 1998. Heavy Oil Upgrading Processes. In: Petroleum Chemistry and Refining. J.G. Speight (Editor). Taylor & Francis, Washington, DC. Kobayashi, S., Kushiyama, S., Aizawa, R., Koinuma, Y., Inoue, K., Shmizu, Y., and Egi, K. 1987a. Kinetic Study on the Hydrotreating of Heavy Oil. 1. Effect of Catalyst Pellet Size in Relation to Pore Size. Industrial & Engineering Chemistry Research, 26: 2241–2245. Kobayashi, S., Kushiyama, S., Aizawa, R., Koinuma, Y., Inoue, K., Shmizu, Y., and Egi, K. 1987b. Kinetic Study on the Hydrotreating of Heavy Oil. 2. Effect of Catalyst Pore Size. Industrial & Engineering Chemistry Research, 26: 2245–2250. Kressmann, S., Guillaume, D., Magalie, R., and Plain, C. 2004. A New Generation of Hydroconversion and Hydrodesulfurization Catalysts. Proceedings. 14th Annual Symposium. Catalysis in Petroleum Refining and Petrochemicals, King Faud University of Petroleum & Minerals, Dhahran, Saudi Arabia. December 5–6. Kressmann, S., Morel, F., Harlé, V., and Kasztelan, S. 1998. Recent Developments in Fixed-Bed Catalytic Residue Upgrading. Catalysis Today, 43: 203–215. McFarland, B.L., Boron, D.J., Deever, W., Meyer, J.A., Johnson, A.R., and Atlas, R.M. 1998. Biocatalytic Sulfur Removal from Fuels: Applicability for Producing Low Sulfur Gasoline. Critical Reviews in Microbiology, 24: 99–147. Meurant, G. 1989. Advances in Chemical Engineering. Academic Press, New York, Vol. 14, pp. 148–150. Mohebali, G., and Ball, A.S. 2008. Biocatalytic Desulfurization (BDS) of Petrodiesel Fuels. Microbiology, 154: 2169–2183. Occelli, M.L., and Robson, H.E. 1989. Zeolite Synthesis. Symposium Series No. 398. American Chemical Society, Washington, DC. Parkash, S. 2003. Refining Processes Handbook. Gulf Professional Publishing, Elsevier, Amsterdam, Netherlands. Reynolds, J.G., and Beret, S. 1989. Effect of Prehydrogenation on Hydroconversion of Maya Residuum. Fuel Science and Technology International, 7: 165–186.

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Setti, L., Farinelli, P., Di Martino, S., Frassinetti, S., Lanzarini, G., and Pifferia, P.G. 1999. Developments in Destructive and Non-Destructive Pathways for Selective Desulfurization in Oil Biorefining Process. Applied Microbiology and Biotechnology, 52: 111–117. Sherman, J.D. 1998. Synthetic Zeolites and Other Microporous Oxide Molecular Sieves. Proceedings. Colloquium on Geology, Mineralogy, and Human Welfare. National Academy of Sciences, Irvine, California. Speight, J.G. 1986. Upgrading Heavy Feedstocks. Annual Review of Energy, 11: 253. Speight, J.G. 2000. The Desulfurization of Heavy Oils and Residua. 2nd Edition. Marcel Dekker Inc., New York. Speight, J.G. 2011a. The Refinery of the Future. Gulf Professional Publishing, Elsevier, Oxford, United Kingdom. Speight, J.G. 2011b. An Introduction to Petroleum Technology, Economics, and Politics. Scrivener Publishing, Salem, Massachusetts. Speight, J.G. 2014. The Chemistry and Technology of Petroleum 5th Edition. CRC Press, Taylor & Francis Group, Boca Raton, Florida. Speight, J.G. 2017. Handbook of Petroleum Refining. CRC Press, Taylor & Francis Group, Boca Raton, Florida. Speight, J.G., and El-Gendy, N.Sh. 2018. Introduction to Petroleum Biotechnology. Gulf Professional Publishing Company, Elsevier, Cambridge, Massachusetts. Speight, J.G., and Moschopedis, S.E. 1979. The Production of Low-Sulfur Liquids and Coke from Athabasca Bitumen. Fuel Processing Technology, 2: 295. Suchanek, A.J., and Moore, A.S. 1986. Efficient Carbon Rejection Upgrades Mexico’s Maya Crude Oil. Oil & Gas Journal, 84(31): 36–40. Toulhoat, H., Szymanski, R., and Plumail, J.C. 1990. Interrelations between Initial Pore Structure, Morphology and Distribution of Accumulated Deposits. Catalysis Today, 7: 531. Van Hamme, J.D., Singh, A., and Ward, O.P. 2003. Recent Advances in Petroleum Microbiology. Microbiology and Molecular Biology Reviews, 67(4): 503–549. Yu, B., Xu, P., Shi, Q., and Ma, C. 2006. Deep Desulfurization of Diesel Oil and Crude Oils by a Newly Isolated Rhodococcus Erythropolis Strain. Applied and Environmental Microbiology, 72: 54–58.

3 Composition and Evaluation Feedstocks

3.1 INTRODUCTION In the unrefined (raw) state crude oil, heavy crude oil, extra heavy crude oil, and tar sand bitumen have minimal value, but when used as feedstocks for the refinery, the result is a variety of high-value liquid fractions that can serve (1) as feedstocks for the production of fuels, solvents, and lubricants, or (2) as a sources of many other products (Speight, 2014, 2017, 2021). In fact, the liquid products derived from crude oil contribute approximately one-third to one-half of the total world energy supply and are used not only for transportation fuels (i.e., gasoline, diesel fuel, and aviation fuel, among others) but also to heat buildings. As a side note, the term black oil is an expression that has arisen and has been used within the past two decades and has seen more common use recently. This term is of unknown scientific origin and engineering origin (other than color) which is reputed to indicate relatively high concentrations of resin constituents and asphaltene constituents in the feedstock and, because of the lack of physical and chemical evidence for the name, is not used in any way in this text. However, in the context of this chapter, the same is not true for heavy crude oil, extra heavy crude oil, and tar sand bitumen which also include the atmospheric and vacuum residua produced by the distillation of crude oil (Speight, 2014, 2017, 2022) that may not be destined for use as asphalt and are often referred to as viscous feedstocks and require application of more novel recovery methods that are used for conventional crude oil (Speight, 2014, 2016). These feedstocks require additional refining steps (such as thermal cracking processes and thermal process involving the use of a catalyst – thermal processes involving the use of hydrogen and a catalyst are deliberately excluded from this text and will be subject of a later volume in this series). Thus, the subject of this text is the thermal processes and catalytic processes that are required to produce the distillate products which can then be used for the production of fuels, solvents, lubricants, and other high-value products such as petrochemical products (Speight, 2014, 2017, 2019, 2021). Furthermore, a major aspect of refinery design is to ensure that the design is adequate to process the feedstocks of different composition (Speight, 2014, 2017, 2020a). Furthermore, the composition of biomass is variable (Speight, 2020b) which is reflected the range of heat value (heat content, calorific value) of biomass, which is somewhat lesser than the heat value for coal and much lower than the heat value for crude oil, generally falling in the range 6,000–8,500 Btu/lb. Moisture content is probably the most important determinant of heating value. Air-dried biomass typically has approximately 15%–20% moisture, whereas the moisture content for oven-dried biomass is around 0%. Moisture content is also an important characteristic of coals, varying in the range of 2%–30%. However, the bulk density (and hence energy density) of most biomass feedstocks is generally low, even after densification, approximately 10% and 40% of the bulk density of most fossil fuels. Therefore, it is the purpose of this chapter to provide a description of the processes that can be used to convert the viscous feedstocks (i.e., heavy crude oil, extra heavy crude oil, and tar sand bitumen) into more useful distillates from which the high-value products can be produced.

DOI: 10.1201/9781003185314-3

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3.2  NON-VISCOUS FEEDSTOCKS While the focus of this chapter is predominantly on the various viscous refinery feedstocks, the nonviscous fractions of crude oil are also used for the production of products through the application of thermal cracking processes and catalytic cracking processes. By way of clarification for this text, a non-viscous feedstock is a low viscosity that flows easily and has no resistance to its flow or internal friction. The term includes (1) naphtha, (2) kerosene, and (3) gas oil. These products are typically produced from the conventional refinery feedstocks (i.e., conventional crude oil) but are, nevertheless, worthy of mention as potential feedstocks for thermal cracking processes and catalytic cracking processes as feedstocks that lead to a range of products that also includes petrochemical products (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017, 2019, 2021).

3.2.1 Naphtha The term naphtha (often referred to as naft in the older literature) is a generic term that is applied to a flammable hydrocarbon liquid that has been refined, partly refined, or an unrefined lower boiling fraction that is derived crude oil fraction. Mixtures labeled naphtha have been produced from natural gas condensate and crude oil distillates. In the strictest sense, not less than 10% v/v of the naphtha should distill below 175°C (345°F) and not less than 95% v/v of the naphtha should distill below 240°C (465°F) under standardized distillation conditions (ASTM D86). More generally, naphtha is an unrefined crude oil that distills below 240°C (465°F) and is (after the gases constituents) the most volatile fraction of the crude oil. In fact, in some specifications, not less than 10% of material should distill below approximately 75°C (167°F), but this can be refinery-dependent (Pandey et al., 2004). Naphtha has been available since the early days of the crude oil industry and, historically goes back even further into history. Indeed, the infamous Greek fire documented as being used in warfare during the last three millennia is a crude oil derivative It was produced either by distillation of crude oil isolated from a surface seepage or (more likely) by destructive distillation of the bituminous material obtained from bitumen seepages (of which there are/were many known during the heyday of the civilizations of the Fertile Crescent). As an example, the bitumen obtained from the area of Hit (Tuttul) in Iraq (Mesopotamia) is such an occurrence (Abraham, 1945; Forbes, 1958a, b, 1959). Other crude oil products boiling within the naphtha boiling range include (1) industrial spirit and white spirit (Guthrie, 1960; Speight, 2014). As an example, of product divergence, the product termed ‘industrial spirit’ comprises liquids distilling between 30°C and 200°C (−1°F and 390°F), with a temperature difference between 5% volume and 90% volume distillation points, including losses, of not more than 60°C (140°F). There are several (eight) grades of industrial spirit, depending on the distillation range. On the other hand, white spirit is an industrial spirit with a flash point above 30°C (99°F) and has a distillation range from 135°C to 200°C (275°F to 390°F). 3.2.1.1 Manufacture Typically, naphtha is prepared by any one of several available methods, which include (1) fractionation of straight-run distillate or cracked distillate or reformer distillate or even, (2) solvent extraction, (3) hydrogenation of cracked distillate, (4) polymerization of unsaturated compounds, i.e., olefin derivatives, and (5) alkylation processes. In fact, the naphtha product may be a combination (a blend) of naphtha streams from more than one of these processes. Naphtha produced by thermal or catalytic cracking processes should be anticipated to contain a variety of olefin derivatives. The more common method of naphtha preparation is distillation of the crude oil – the viscous feedstocks by virtue of their definition and composition contain very little (if any) naphtha constituents. Depending on the design of the distillation unit, either one or two naphtha steams may

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be produced: (1) a single naphtha with an end point of about 205°C (400°F) and similar to straightrun gasoline, or (2) this same fraction divided into a low-boiling (low-density) naphtha and a high boiling (high density) naphtha. The end point of the low-boiling (low-density) naphtha is varied to suit the subsequent subdivision of the naphtha into narrower boiling fractions and may be of the order of 120°C (250°F) (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). Sulfur compounds are most commonly removed (or rendered harmless) by chemical treatment with lye, doctor solution, copper chloride, or similar treating agents and hydrorefining processes are also often used in place of chemical treatment to reduce the sulfur content to an acceptable level (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). Also, naphtha with a low content of aromatic constituents (increase the solvent power of the naphtha) has a slight odor, but there is no need to remove the aromatic constituents unless an odor-free product is specified. Furthermore, naphtha that is either naturally sweet (no odor), or has been treated until sweet, is subdivided into several fractions in efficient fractional distillation towers frequently called pipe stills, columns, and column steam stills (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). A typical arrangement consists of primary and secondary fractional distillation towers and a stripper. High boiling (high density) naphtha, for example, is heated by a steam heater and passed into the primary tower, which is usually operated under vacuum. The low pressure in the unit allows vaporization of the naphtha at the temperatures obtainable from the steam heater. In terms of the purification of the naphtha, several methods, involving solvent extraction or destructive hydrogenation (hydrocracking), can accomplish the removal of aromatic hydrocarbon derivatives from naphtha. By this latter method, aromatic hydrocarbon constituents are converted into odorless, straight-chain paraffin hydrocarbon derivatives that are required in aliphatic solvents (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017, 2019). The Edeleanu extraction process was originally developed to improve the burning characteristics of kerosene by extraction of the smoke-forming aromatic compounds (Speight 2014, 2017). The process is an extraction process in which liquid sulfur dioxide (SO2) is used to selectively extract (dissolves) the aromatic derivatives from kerosene-type liquids to produce the insoluble low aromatic product. Naphtha fractions rich in aromatic derivatives may be treated by the Edeleanu process for the purpose of recovering the aromatic derivatives, or the product stream from a catalytic reformer unit – particularly when the unit is operated to produce maximum aromatic derivatives – may be treated using the Edeleanu process to recover the aromatic derivatives. The other most widely used processes for this purpose are the extractive distillation process and the Udex processes (Speight, 2014, 2017). 3.2.1.2 Composition Naphtha contains varying amounts of paraffin derivatives, olefin derivatives, naphthene derivatives, aromatic derivatives, and, in some cases, olefin derivatives in different proportions in addition to potential isomers of hydrocarbon derivatives that exist in naphtha boiling range. As a result, naphtha is divided predominantly into two main types: (1) aliphatic naphtha and (2) aromatic (naphtha) (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). The two types differ in two ways in the types of the hydrocarbon derivatives that are present and in the methods used for their manufacture. 3.2.1.3  Properties and Uses Naphtha is required to have a low level of odor to meet the specifications for use (Pandey et al., 2004), which is related to the chemical composition – generally paraffin hydrocarbon derivatives possess the mildest odor, and the aromatic hydrocarbon derivatives have a much stronger odor. Naphtha containing

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higher proportions of aromatic constituents may be pale yellow – usually, naphtha is colorless (water white) and can be tested for the level of contaminants. Naphtha is classified as low-boiling (low-density) naphtha and high-boiling (high-density) naphtha. Low-boiling (low-density) naphtha is used as rubber solvent, lacquer diluent, while high boiling (high density) naphtha finds its application as varnish solvent, as well as dyer’s naphtha used in the dyestuffs industry and in the cleaning industry. The main uses of naphtha fall into the general areas of (1) solvents (diluents) for paints, for example; (2) dry-cleaning solvents; (3) solvents for cutback asphalt; (4) solvents in the rubber industry; and (5) solvents for industrial extraction processes (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017, 2021).

3.2.2 Middle Distillates The term ‘middle distillates’ is used to describe a range of refined products, which result from the separation of crude oil through fractional distillation, between lower boiling products (such as liquefied petroleum gas, LPG, and naphtha) and higher boiling products such as fuel oil. The middle distillate fraction of crude oil (sometimes referred to as kerosene and also often referred to as paraffin oil or liquid paraffin) has a boiling range on the order of: 205°C–260°C, 400°F–500°F, and is typically a collection of more specific boiling-range distillates that are obtained in the so-called ‘middle’ boiling range on the order of 180°C–360°C (355°F–680°F) during the crude oil distillation process and are removed at mid-height in the distillation tower during the multi-stage process of thermal separation. Kerosene is an medium that distills between 150°C and 300°C (300°F–570°F) and has a flash point on the order of 25°C (77°F) and is suitable for use as an illuminant when burned in a wide lamp (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017, 2019, 2021). The term kerosene is also often incorrectly applied to various types of fuel oil, but a fuel oil is actually any liquid or liquid crude oil product that produces heat when burned in a suitable container or that produces power when burned in an engine. 3.2.2.1 Manufacture Kerosene was first manufactured in the 1850s from coal tar, hence the name coal oil as often applied to kerosene, but crude oil became the major source after 1859. From that time, the kerosene fraction has remained, a distillation fraction of crude oil. However, the quantity and quality vary with the type of crude oil, and although some crude oils yield high-quality kerosene, other crude oils produce kerosene that requires substantial refining. Kerosene is now largely produced by cracking the less volatile portion of crude oil at atmospheric pressure and elevated temperatures. In the early days of crude oil refining, the poorer quality kerosene was treated with large quantities of sulfuric acid to convert them to marketable products. However, this treatment resulted in high acid and kerosene losses, but the later development of the Edeleanu process overcame these problems (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). 3.2.2.2 Composition Chemically, kerosene is a mixture of hydrocarbon derivatives; the chemical composition depends on its source, but it usually consists of about ten different hydrocarbon derivatives, each containing from 10 to 16 carbon atoms per molecule; the constituents include n-dodecane (n-C12H26), alkyl benzenes, and naphthalene and its derivatives. Kerosene is less volatile than gasoline; it boils between about 140°C (285°F) and 320°C (610°F). Kerosene, because of its use as a burning oil, must be free of aromatic and unsaturated hydrocarbon derivatives, as well as free of the more obnoxious sulfur compounds. The desirable constituents of kerosene are saturated hydrocarbon derivatives, and it is for this reason that kerosene is manufactured as a straight-run fraction, not by a cracking process.

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Although the kerosene constituents are predominantly saturated materials, there is evidence for the presence of substituted tetrahydronaphthalene. Dicycloparaffin derivatives also occur in substantial amounts in kerosene. Other hydrocarbon derivatives with both aromatic and cycloparaffin rings in the same molecule also occur in kerosene. The predominant structure of the di-nuclear aromatic derivatives appears to be that in which the aromatic rings are condensed, such as naphthalene, whereas the isolated two-ring compounds, such as biphenyl, are only present in traces, if at all. 3.2.2.3  Properties and Uses Kerosene is by nature a fraction distilled from crude oil that has been used as a fuel oil from the beginning of the crude oil refining industry. As such, low proportions of aromatic and unsaturated hydrocarbon derivatives are desirable to maintain the lowest possible level of smoke during burning. Although some aromatic derivatives may occur within the boiling range assigned to kerosene, excessive amounts can be removed by extraction; that kerosene is not usually prepared from cracked products almost certainly excludes the presence of unsaturated hydrocarbon derivatives.

3.2.3 Gas Oil The term ‘gas oil’ is a catch-all term that is used to describe a liquid distillation product that is obtained from the distillation section of the refinery that boils between kerosene and lubricating oil. However, this definition can vary from refinery to refinery and, in some refineries, may even include kerosene (at the lower end of the boiling range) and liberating oil (at the upper end of the boiling range). For the purpose of this text, gas oil occurs in the refinery as two fractions which are (1) atmospheric gas oil, often referred to as AGO, and (2) vacuum gas oil, often referred to as VGO (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017, 2019, 2021). Typically, the AGO has a boiling range higher than the kerosene boiling range and is on the order of 300°C (570°F) to 360°C (680°F) which is the temperature just before the distillation is terminated. On the other hand, the VGO is the first fraction that is obtained in the vacuum distillation process and has a boiling range on the order of 360°C to (950°F) which is the temperature at which the vacuum distillation process is terminated to produce the vacuum residuum. In some refineries, the vacuum distillation process may be terminated at 565°C (1,050°F). The gas oil fractions vary in composition depending upon the source and character of the crude oil. Generally, the gas oil fractions may be used as a source of fuel oil or fuel oil blending stock or as a source of lubricating oil. 3.2.3.1 Manufacture There are two types of gas oil fractions that are produced in a refinery and are: (1) AGO and (2) VGO (Table 3.1). The former – the AGO – boils above the middle distillate fractions (at approximately 260°C–425°C, 400°F–800°F). The latter – the vacuum gas oil – is the fraction that is isolated during the initial stages of the vacuum distillation process (boils at approximately 425°C–600°C, 800°F–1,100°F). These data are subject to change depending upon the refinery type of nomenclature. 3.2.3.2 Composition Typically, a gas oil fraction consists of complex mixtures of aliphatic and aromatic hydrocarbon derivatives; the relative amounts depend on the source and properties of the gas oil. The aliphatic alkane derivatives (paraffin derivatives) and cycloalkane derivatives (naphthene derivatives) are hydrogen-saturated and compose as much as 75% v/v (or more) of the gas oil. Aromatic constituents (e.g., benzene, naphthalene, and phenanthrene derivatives) compose up to 25% v/v of the gas oil. In addition, the sulfur content of (atmospheric or vacuum) gas oil can vary up to 5% w/w. The saturate constituents contribute less to the VGO than the aromatic constituents but more than the polar constituents that are now present at percentage rather than trace levels. Vacuum gas

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TABLE 3.1 Boiling Fractions of Conventional Crude Oil Fractiona Naphtha (low-boiling or light naphtha) Naphtha (high boiling or heavy naphtha) Middle distillatesc Kerosene Fuel oil Atmospheric gas oil (light gas oil) Vacuum gas oil (heavy gas oil) Light vacuum gas oil Residuum a

b

c

Boiling Range °C

°Fb

30–150 150–180 180–290 180–260 205–290 260–315 425–600 425–600 >510

30–300 300–400 400–500 355–500 400–550 500–800 800–1,100 425–600 >950

The terminology varies from refinery to refinery and it is preferable to identify the fraction by the respective boiling range. For convenience, boiling ranges which can vary from refinery to refinery are approximate and, for convenience, are converted to the nearest 5°. Obtained in the ‘middle’ boiling range which is on the order of 180°C–260°C (355°F–500°F) during the crude oil distillation process. The middle distillate is so named because the fraction is removed at mid-height in the distillation tower during the multi-stage process of thermal separation.

oil is occasionally used as a heating oil but most commonly it is processed by catalytic cracking to produce naphtha or extraction to yield lubricating oil. Within the vacuum gas oil, saturate derivatives, distribution of paraffin derivatives, iso-paraffin derivatives, and naphthene derivatives is highly dependent upon the crude oil source. Generally, the naphthene constituents account for approximately two-thirds 60% of the saturate constituents but the overall range of variation is from 80%. In most samples, the n-paraffin derivatives from C20 to C44 are still present in sufficient quantity to be detected as distinct peaks in gas chromatographic analysis. The bulk of the saturated constituents in vacuum gas oil consist of iso-paraffin derivatives and especially naphthene species, although isoprenoid compounds, such as squalane (C30) and lycopane (C40), have been detected. Analytical techniques show that the naphthene derivatives contain from one to more than six fused rings accompanied by alkyl substitution. For mono-and di-aromatic derivatives, the alkyl substitution typically involves several methyl and ethyl substituents. Hopanes and steranes have also been identified and are also used as internal markers for estimating biodegradation of crude oils during bioremediation processes (Prince et al., 1994). The aromatic constituents in vacuum gas oil may contain one to six fused aromatic rings that may bear additional naphthene rings and alkyl substituents in keeping with their boiling range. Mono- and di-aromatic derivatives account for approximately 50% v/v of the aromatic derivatives in crude oil vacuum gas oil samples. Analytical data show the presence of up to four fused naphthenic rings on some aromatic compounds. This is consistent with the suggestion that these species originate from the aromatization of steroids. Although present at lower concentration, alkyl benzenes and naphthalene derivatives show one long side chain and multiple short side chains. The fused ring aromatic compounds (having three or more rings) in crude oil include phenanthrene, chrysene, and picene as well as fluoranthene, pyrene, benzo(a)pyrene, and benzo(ghi) perylene. The most abundant reported individual phenanthrene compounds appear to be the three derivatives. In addition, phenanthrene derivatives outnumber anthracene derivatives by as much as 100:1. In addition, chrysene derivatives are favored over pyrene derivative.

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Heterocyclic constituents are significant contributors to the vacuum gas oil fraction. With respect to sulfur-containing compounds, thiophene and thiacyclane sulfur predominate over sulfide-type sulfur. Some constituents may even contain more than one sulfur atom. The benzothiophene derivatives and dibenzothiophene derivatives are the prevalent thiophene forms of sulfur. In the vacuum gas oil range, the nitrogen-containing compounds include higher molecular weight pyridine derivatives, quinoline derivatives, benzoquinoline derivatives, amide derivatives, indole derivatives, and carbazole derivatives, and molecules with two nitrogen atoms (diaza-compounds) with three and four aromatic rings are especially prevalent (Green et al., 1989). Typically, approximately one-third of the compounds are basic, i.e., pyridine and its benzo-derivatives, while the remainder are present as neutral species (amide derivatives and carbazole derivatives). Although benzo- and dibenzo-quinoline derivatives found in crude oil are rich in sterically hindered structures, hindered and unhindered structures have been found to be present at equivalent concentrations in source rocks. This has been rationalized as geo-chromatography in which the less polar (hindered) structures moved more readily to the reservoir and are not adsorbed on any intervening rock structures. Oxygen levels in the vacuum gas oil parallel the nitrogen content. Thus, the most commonly identified oxygen compounds are the carboxylic acids and phenols, collectively called naphthenic acids (Seifert and Teeter, 1970). Lubricating oil – a valuable product that falls within the boiling range of gas oil – has a high boiling point (>400°C, >750°F) and high viscosity. The gas oil fraction that is considered suitable for the production of lubricating oil comprises principally of hydrocarbon derivatives containing from 25 to 35 or even 40 carbon atoms per molecule, whereas residual stocks may contain hydrocarbon derivatives with 50 or more carbon atoms per molecule (in fact, as many as 80 or more carbon atoms per molecule). The composition of lubricating oil may be substantially different from the lubricant fraction from which it was derived since wax (normal paraffin derivatives) is removed by distillation or refining by solvent extraction and adsorption preferentially removes non-hydrocarbon constituents as well as polynuclear aromatic compounds and the multi-ring cycloparaffin derivatives. When distillate production is to be maximized, the amount of gas oil allowed to remain in the non-volatile distillation residue bottoms stream must be minimized. 3.2.3.3  Properties and Uses The gas oil fractions contain mostly high-molecular-weight hydrocarbon derivatives and can be employed to produce lubricating oil and other high-value oils for a variety of uses. In many cases, the gas oil fractions are used as feedstocks for catalytic cracking processes and for hydrocracking processes to produce a variety of products. After hydrotreatment, gas oil can be blended and/or sold as fuel oil.

3.2.4 Wax Wax (often referred to as ‘paraffin wax’) is a soft colorless solid that is derived from, in the current context, crude oil (although sources such as coal liquids and shale oil are also known) that consists of a mixture of hydrocarbon molecules containing between 20 and 40 carbon atoms with the following (approximate) properties: Chemical formula: CnH2n + 2, where n = 20–40 Appearance: white solid Melting temperature: on the order of 45°C–70°C (113°F–158°F) Boiling point: 370°C (698°F) Flash point: 200°C–240°C (392°F–464°F) The use of paraffin wax in a historical sense is varied but for the purpose of this chapter can be taken to the 18th century (Burke, 1996).

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At that time, documents were written or drawn on damp paper with special ink that included gum Arabic, which stayed moist for 24 hours, during which copies could be made by pressing another smooth white sheet against the original and transferring the ink marks to the new sheet. Initially, the copier was not a success. Banks were opposed because they thought it would encourage forgery. Counting houses argued that it would be inconvenient when they were rushed, or working by candlelight. But by the end of the first year, Watt had sold two hundred examples and had made a great impression with a demonstration at the houses of Parliament, causing such a stir that members had to be reminded they were in session. By 1785, the copier was in common use. Then, in 1823, Cyrus P. Dalkin of Concord, Massachusetts, improved on the technique by using two different materials whose effect on history was to be startling. By rolling a mixture of carbon black and hot paraffin wax onto the back of a sheet of paper, Dalkin invented carbon copies. The development laid relatively unnoticed until the 1868 balloon ascent by Lebbeus H. Rogers, the 21-year-old partner in a biscuit-and-greengrocery firm. His aerial event was being covered by the Associated Press and in the local newspaper office after the flight. Rogers was interviewed by a reporter who was using the carbon paper developed by Dalkin. Impressed by what he saw, Rogers terminated his ballooning and biscuits efforts and started a business producing carbon paper for use in order books, receipt books, invoices, etc. In 1873, he conducted a demonstration for the Remington typewriter company, and the new carbon paper became an instant success. The paraffin wax Dalkin used, and which was therefore half-responsible (together with carbon black) for changing the world of business, had originally been produced from oil shale rocks. After the discovery of crude oil in Pennsylvania, in 1857 (Speight, 2014), paraffin oil was produced by distillation and was used primarily as an illuminant to make up for the dwindling supply of spermwhale oil in a rapidly growing lamp market. Chilled down paraffin solidified into paraffin wax. Apart from its use in lighting, the wax was also used to preserve the crumbling Cleopatra’s Needle obelisk in New York’s Central Park. Crude oil wax is of two general types: (1) paraffin wax in crude oil distillates and (2) microcrystalline wax in crude oil residua. However, the melting point of crude oil-derived wax is not directly related to the boiling point because wax contains hydrocarbon derivatives of different chemical structure. Nevertheless, wax is graded according to their melting point and oil content. Microcrystalline waxes form approximately 1%–2% w/w of crude oil and are a valuable product having numerous applications. These waxes are usually obtained from high boiling (high density) lube distillates by solvent dewaxing and from tank bottom sludge by acid clay treatment (Agrawal et al., 1986; Agrawal and Kumar, 1997). However, these crude waxes usually contain appreciable quantity (10%–20% w/w) of residual oil and, as such, are not suitable for many applications such as paper coating, electrical insulation, textile printing, and polishes. 3.2.4.1 Manufacture Paraffin wax from a solvent dewaxing operation is commonly known as slack wax, and the processes employed for the production of waxes are aimed at de-oiling the slack wax (crude oil wax concentrate) (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017, 2019, 2021). Wax sweating was originally used in Scotland to separate wax fractions with various melting points from the wax obtained from shale oil but is being replaced by the more convenient recrystallization process. In wax sweating, a cake of slack wax is slowly warmed to a temperature at which the oil in the wax and the lower melting waxes become fluid and drip (or sweat) from the bottom of the cake, leaving a residue of higher melting wax. However, wax sweating can be carried out only when the residual wax consists of large crystals that have spaces between them, through which the oil and lower melting waxes can percolate; it is therefore limited to wax obtained from low-boiling (low-density) paraffin distillate. Waxes produced by the ‘sweating’ process generally contain small amounts of unsaturated aromatic and sulfur compounds, which are the source of unwanted color, odor, and taste, that reduce the ability of the wax to resist oxidation.

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Wax recrystallization, like wax sweating, is employed to separate slack wax into fractions, but instead of using the differences in melting points, it makes use of the different solubility of the wax fractions in a solvent, such as the ketone used in the dewaxing process (Speight, 2014). These conventional solvent de-oiling processes to upgrade the quality of high-oil-content microcrystalline waxes involve agitation followed by extractive crystallization at low temperatures with solvents such as methyl iso-butyl ketone, methyl ethyl ketone-toluene mixtures, and dichloro-ethane – typically using drum filters. 3.2.4.2 Composition Paraffin wax is a solid crystalline mixture of straight-chain (normal) hydrocarbon derivatives ranging from C20 to C30 and possibly higher, i.e., CH3 (CH2)n CH3 where n ≥ 18 (Speight, 2014, 2017). This type of wax is distinguished by its solid state at ordinary temperatures (25°C, 77°F) and low viscosity (35–45 SUS at 99°C, 210°F) when melted. However, in contrast to crude oil wax, crude oil jelly (also known as petrolatum), although typically solid at ambient temperature, does in fact contain both solid and liquid hydrocarbon derivatives and is, in fact, essentially a low-melting, ductile, microcrystalline wax. 3.2.4.3  Properties and Uses The physical properties of wax are affected by the oil content (Kumar et al., 2007), and hence by achieving desired level of oil content, waxes of desired physical properties can be obtained. The melting point of paraffin wax (ASTM D87) has both direct and indirect significance in most wax utilization. All wax grades are commercially indicated in a range of melting temperatures rather than at a single value, and a range of 1°C (2°F) usually indicates a good degree of refinement. Other common physical properties that help to illustrate the degree of refinement of the wax are color (ASTM D156), oil content, API gravity (ASTM D287), flash point (ASTM D92), and viscosity (ASTM D88 and ASTM D445), although the last three properties are not usually given by the producer unless specifically requested. Crude oil waxes (and petrolatum) find many uses in pharmaceuticals, cosmetics, paper manufacturing, candle making, electrical goods, rubber compounding, textiles, and many more, too numerous to mention here – for additional information, more specific texts on crude oil waxes should be consulted.

3.2.5 Biomass and Bio-Oil Biomass is a term used to describe any material of recent biological origin, including plant materials such as trees, grasses, agricultural crops, and even animal manure. Thus, biomass (also referred to as bio-feedstock) refers to living and recently dead biological material which can be used as fuel or for industrial production of chemicals (Speight, 2020b). On the other hand, for clarification, bio-oil is a liquid product that is produced from biomass materials (such as agricultural crops, algal biomass, municipal wastes, and agricultural and forestry by-products) by thermochemical process, such as pyrolysis. In the pyrolysis process, the biomass is heated in the absence of air or in the absence of oxygen) to generate three types of products based on their nature, which are (1) gaseous products, (2) liquid oil, typically distillable oil, and (3) solid carbonaceous char. In terms of the chemical composition, biomass is a mixture of complex organic compounds that contain, for the most part, carbon, hydrogen, and oxygen, with small amounts of nitrogen and sulfur as well as with traces of other elements including metals. In the most cases the biomass composition is approximately carbon 47%–53% w/w, hydrogen 5.9%–6.1% w/w, and oxygen 41%–45% w/w. The presence of a large amount of oxygen in biomass makes a significant difference with fossilderived hydrocarbon derivatives. When used as fuel, this is less efficient, but more is proving to be more suited for producing higher value bio-products, which contain functional entities within the

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constituent molecules, and a variety of petrochemical products (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017, 2019). The biomass used as industrial feedstock can be supplied by agriculture, forestry, and aquaculture, as well as resulting from various waste materials. The biomass can be classified as follows: (1) agricultural feedstocks, such as sugarcane, sugar-beet, and cassava; (2) starch feedstocks, such as wheat, maize, and potatoes; (3) oil feedstocks, such as rapeseed and soy; (4) dedicated energy crops, such as short rotation coppice which includes poplar, willow, and eucalyptus; (5) high-yield perennial grass, such as miscanthus and switchgrass; (6) non-edible oil plants, such as jatropha, camellia, and sorghum; and (7) lignocellulosic waste material, which includes forestry wood, straw, corn stover, bagasse, paper pulp, and algal crops from land farming. The utilization of biomass through the adoption of the conventional crude oil refinery systems and infrastructure to produce substitutes for fuels and other chemicals currently derived from conventional fuels (coal, oil, natural gas) is one of the most favored methods to combat fossil fuel depletion as the 21st century matures. In a biorefinery, a solid biomass feedstock is converted, through either a thermochemical process (such as gasification, pyrolysis) or a biochemical process (such as hydrolysis, fermentation), into a mixture of organic (such as hydrocarbon derivatives, alcohol derivatives, and ester derivatives) and inorganic compounds (such as carbon monoxide and hydrogen) that can be upgraded through catalytic reactions to high-value fuels or chemicals (Speight, 2014, 2017, 2019, 2020a). Chemically, biomass is carbonaceous feedstock that is composed of a variety of organic constituents that contain carbon, hydrogen, oxygen, often nitrogen, and also small quantities of other atoms, including alkali metals, alkaline earth metals, and heavy metals. The alkali metals consist of the chemical elements lithium (Li), sodium (Na), potassium (K), rubidium (Rb), cesium (Cs), and francium (Fr). Together with hydrogen, they make up Group I of the Periodic Table (Table 3.2). On the other hand, the alkaline earth metals are the six chemical elements in Group 2 of the Periodic Table and are beryllium (be), magnesium (Mg), calcium (Ca), strontium (Sr), barium (Ba), TABLE 3.2 The Periodic Table of Elements

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and radium (Ra) (Table 3.2). These elements have very similar properties – they are shiny, silverywhite, and are somewhat reactive at standard temperature and pressure. Finally, the heavy metals are less easy to define but are generally recognized as metals with relatively high density, atomic weight, or atomic number. The common transition metals such as copper (Cu), lead (Pb), and zinc (Zn) are often classed as heavy metals but the criteria used for the definition and whether metalloids (types of chemical elements which have properties in between, or that are a mixture of, those of metals and nonmetals) are included, vary depending on the context. These metals are often found in functional molecules such as the porphyrin molecules which include chlorophyll and which contains magnesium. Biomass feedstocks and fuels exhibit a wide range of physical, chemical, and agricultural/process engineering properties and is subdivided into three different grades (or types) and the feedstock origin determines the so-called biomass generation. In some cases, the third-generation biomass may also include high-yield algal crops which can be fed directly with concentrated carbon dioxide streams resulting from industrial processes, from coal power plants, and from fermentation of sugars – algal cultures can produce various hydrocarbon derivatives as well as various volatile olefin derivatives. In addition to using biomass for energy for power and heat generation by means of co-firing and gasification, woody crops with their high hemicellulose and cellulose content are well suited for biorefining to yield liquid fuels such as methanol, ethanol, and distillable oil (sometimes referred to as pyrolysis oil or bio-oil), as well as other products, such as specialty chemicals (Ben et al., 2019; Speight, 2019). The thermal decomposition of biomass (typically referred to as pyrolysis) gives usually rise to three phases: (1) gases, (2) condensable liquids, and (3) char/coke. However, there are various types of related kinetic pathways ranging from very simple paths to more complex paths and all usually include several elementary processes occurring in series or in competition. As anticipated, the kinetic paths are different for cellulose, lignin, and hemicelluloses (biomass main basic components) and also for usual biomasses according to their origin, composition, and inorganic contents (Speight, 2020b). Thus, the thermal decomposition of biomass offers a flexible and attractive way of converting solid biomass into an easily stored and transported liquid (bio-oil), which can be successfully used for the production of chemicals in any one of several crude oil refinery-type scenarios. The pyrolysis processes can be categorized as (1) slow pyrolysis, which can take several hours to complete and results in biochar as the main products, or (2) fast pyrolysis, which is completed in a matter of seconds and is currently the most widely used pyrolysis system and can produce a high of bio-oil – on the order of 60% w/w bio-oil along with synthesis gas (20% w/w) and biochar (20% w/w) (Table 3.3). Fast pyrolysis processes include ablative fast pyrolysis, cyclonic fast pyrolysis, open-core fixed-bed pyrolysis, and rotating core fast pyrolysis systems. The essential features of a fast pyrolysis process are (1) high heating, which require a finely ground feedstock, (2) high rate of heat transfer rates, which also requires a finely ground feedstock, (3) carefully controlled reaction temperature on the order of 500°C/930°F, (4) residence time of the pyrolysis vapors in the reactor of less than 1 second, and (5) quenching – i.e., rapid cooling – of the pyrolysis vapors to condense to give the bio-oil.

TABLE 3.3 Biomass Products by Thermal Decomposition Biomass Pyrolysis (550°C, 1,020°F, no air) Gases

H2, CO, CO2, CnH2n + 2

Liquids

CnH2n + 2

Char

Cn

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Bio-oil (sometime known as pyrolysis oil or bio-crude) is a synthetic oil that is obtained by the pyrolysis of dried biomass in the absence of oxygen at a temperature on the order of about 500°C (900°F) with subsequent cooling. The oil may appear as a light-to-dark brown liquid or a fluid type of tar that typically contains levels of oxygen too high to consider the oil as a pure hydrocarbon product. The high oxygen content results in non-volatility, corrosiveness, immiscibility with fossil fuels, thermal instability, and a tendency to polymerize (with an accompanying increase in viscosity) when exposed to air and allowed to oxidize. Bio-oil is a promising alternative refinery feedstock which can be produced from various types of biomass. Typically, bio-oil produced from by pyrolysis of biomass is a complex mixture containing significant quantities of nitrogen and oxygen with high total acid number (TAN). Thus, further treatment, such as denitrogenation and deoxygenation, is required before further use. 3.2.5.1 Manufacture Bio-oil is produced by pyrolysis (fast pyrolysis, flash pyrolysis) of biomass and the process occurs when solid fuels are heated at temperatures between 350°C and 500°C (570°F–930°F) for a very short period of time (340°C, >645°F) used during distillation of flashing (Speight and Francisco, 1990):

RCO 2H → RH + CO 2

In addition to the carboxylic acids and phenolic compounds (ArOH, where Ar is an aromatic moiety), the presence of ketones (>C=O), esters [>C(=O)-OR], ethers (R-O-R), and anhydrides >C(=O)O-(O=)C2,000

Hydrodesulfurization of middle distillates causes a more marked change in the specific gravity of the feedstock, and the amount of low-boiling material is much more significant when compared with the naphtha-type feedstock. In addition, the somewhat more severe reaction conditions (leading to a designated degree of hydrocracking) also lead to an overall increase in hydrogen consumption when middle distillates are employed as feedstocks in place of the naphtha. High boiling distillates, such as the atmospheric gas oil and vacuum gas oil, are not usually produced as a refinery product but are used as feedstocks to other conversion processes to produce lowerboiling products. For example, gas oil can be desulfurized to remove more than 80% of the sulfur originally in the gas oil with some conversion of the gas oil to lower-boiling materials (Table 4.2). The treated gas oil (which has a lower carbon residue as well as a lower sulfur content and a lower nitrogen content relative to the untreated material) can then be converted to lower-boiling products in, say, a catalytic cracker where an improved catalyst life and volumetric yield may be noted. The conditions used for the hydrodesulfurization of a gas oil may be somewhat more severe than the conditions employed for the hydrodesulfurization of middle distillates with, of course, the feedstock in the liquid phase. An advantage of the use of low-, middle-, and high-boiling distillate feedstocks is that the catalyst does not become poisoned by metal contaminants since only negligible amounts of these contaminants will be present in the feedstock. Thus, the catalyst may be regenerated several times and on-stream times between catalyst regeneration (while varying with the process conditions and application) may be of the order of 3–4 years (Table 4.2).

4.6  VISCOUS FEEDSTOCK HYDRODESULFURIZATION The objectives of upgrading viscous feedstocks (such as heavy crude oil, extra heavy crude oil, tar sand bitumen, and residua) are: (1) reduction of metals (such as nickel, vanadium, and iron), (2) reduction in the sulfur content, (3) reduction in the amount of coke formers in the feedstock, (4) reduction in nitrogen, and, last but certainly not least, and (5) conversion of the asphaltene and resin constituents into lower molecular weight easier-to-refine molecular species (such as naphtha, middle distillate, and gas oil) in order to produce higher value feedstocks for the conversion of viscous feedstocks. Upgrading processes can be used for the upgrading of heavy crude oil, extra heavy crude oil, tar sand bitumen, and residua (atmospheric residua, 650°F+, 345°C+, and vacuum residua, 1,050°F+, 565°C+). Two routes exist for residue upgrading: (1) carbon rejection, such as coking processes, and (2) hydrogen addition, such as hydrotreating processes that use a fixed bed unit or an ebullated bed unit (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). The hydrogen addition route is a more expensive option relative to a carbon rejection option but results in a significantly higher yield of liquid products. The two major process designs for the hydrogen

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addition approach are (1) the ebullated-bed process and (2) the ebullating bed and fixed bed. Both the fixed-bed processes and the ebullated-bed processes require a catalyst system with a pore size distribution to match the changing molecular structure of the feedstock constituents. The catalyst can be designed for high metal uptake capacity and moderate sulfur conversion to be applied in the front-end reactor when processing high-metal-containing feedstocks (>70 ppm vanadium). On the other hand, the catalyst may be designed for moderate metals removal capacity but higher activity for sulfur and conversion of the coke precursors which is applied in front-end reactors when processing feedstocks with a lower metal content ( Ni-Mo > Co-Mo > Co-W.

Nickel-tungsten (Ni-W) and nickel-molybdenum (Ni-Mo) on Al2O3 catalysts are widely used to reduce sulfur, nitrogen, and aromatics levels in crude oil fractions by hydrotreating. Molybdenum sulfide (MoS2), usually supported on alumina, is widely used in crude oil processes for hydrogenation reactions. It is a layered structure that can be made much more active by addition of cobalt or nickel. When promoted with cobalt sulfide (CoS), making what is called cobalt-moly catalysts, it is widely used in HDS processes. The nickel sulfide (NiS)-promoted version is used for HDN as well as HDS. The closely related tungsten compound (WS2) is used in commercial hydrocracking catalysts. Other sulfides (iron sulfide, FeS; chromium sulfide, Cr2S3; and vanadium sulfide, V2S5) are also effective and used in some catalysts. A valuable alternative to the base-metal sulfides is palladium sulfide (PdS). Although it is expensive, palladium sulfide forms the basis for several very active catalysts, while clay minerals which are also used as cracking catalysts for viscous feedstocks, especially for demetallization of viscous crude oil, are much cheaper. The choice of hydrogenation catalyst depends on what the catalyst designer wishes to accomplish. In catalysts to make naphtha, for instance, vigorous cracking is needed to convert a large fraction of the feed to the kinds of molecules that will make a good gasoline blending stock. For this vigorous cracking, a vigorous hydrogenation component is needed. Since palladium is the most active catalyst for this, the extra expense is warranted. On the other hand, many refiners wish only to make acceptable diesel, a less demanding application. For this, the less expensive molybdenum sulfides are adequate. The cracking reaction results from attack of a strong acid on a paraffinic chain to form a carbonium ion (carbo-cation, e.g., R+) (Dolbear, 1998). Strong acids come in two fundamental types, Brønsted and Lewis acids. Brønsted acids are the familiar proton-containing acids; Lewis acids are a broader class including inorganic and organic species formed by positively charged centers. Both kinds have been identified on the surfaces of catalysts; sometimes, both kinds of sites occur on the same catalyst. The mixture of Brønsted and Lewis acids sometimes depends on the level of water in the system. Examples of Brønsted acids are the familiar proton-containing species such as sulfuric acid (H2SO4). Acidity is provided by the very active hydrogen ion (H+), which has a very high positive charge density. It seeks out centers of negative charge such as the pi electrons in aromatic centers. Such reactions are familiar to organic chemistry students, who are taught that bromination of aromatics takes place by attack of the bromonium ion (Br+) on such a ring system. The proton in strong acid systems behaves in much the same way, adding to the pi electrons and then migrating to a site of high electron density on one of the carbon atoms. These acids all have high positive charge densities. Examples are aluminum chloride (AlCl3) and the bromonium ion (Br+). Such strong positive species have become known as Lewis acids. This class obviously includes proton acids, but the latter are usually designated Brønsted acids in honor of the Danish chemist J. N. Brønsted, who contributed greatly to the understanding of the thermodynamics of aqueous solutions. In reactions with hydrocarbons, both Lewis and Brønsted acids can catalyze cracking reactions. For example, the proton in Brønsted acids can add to an olefinic double bond to form a carbo-cation. Similarly, a Lewis acid can abstract a hydride from the corresponding paraffin to generate the same intermediate (Dolbear, 1998). Although these reactions are written to show identical intermediates in the two reactions, in real catalytic systems, the intermediates would be different. This is because the carbo-cations would probably be adsorbed on surface sites that would be different in the two kinds of catalysts. Zeolites and amorphous silica-alumina provide the cracking function in hydrocracking catalysts. Both of these have similar chemistry at the molecular level, but the crystalline structure of the zeolites provides higher activities and controlled selectivity not found in the amorphous materials.

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Chemists outside the catalyst field are often surprised that a solid can have strong acid properties. In fact, many solid materials have acid strength matching that of concentrated sulfuric acid. Some specific examples are: (1) amorphous silica-alumina, SiO2/Al2O3, (2) zeolites, (3) activated acid-leached clay minerals, (4) aluminum chloride (AlCl3) and many related metal chlorides, (5) amorphous silica magnesia compounds (SiO2/MgO), (6) chloride-promoted alumina (Al2O3.Cl), and (7) phosphoric acid supported on silica gel, H3PO4/SiO2. Each of these is applied in one or more commercial catalysts in the crude oil refining industry. For commercial hydrocracking catalysts, only zeolites and amorphous silica-alumina are used commercially. In 1756, Baron Axel F. Cronstedt, a Swedish mineralogist, made the observation that certain minerals, when they were heated sufficiently, bubbled as if they were boiling. He called the substances zeolites (from the Greek zeo, to boil, and lithos, stone), which are now known to consist primarily of silicon, aluminum, and oxygen and to host an assortment of other elements. In addition, zeolites are highly porous crystals veined with submicroscopic channels. The channels contain water (hence the bubbling at high temperatures), which can be eliminated by heating (combined with other treatments) without altering the crystal structure (Occelli and Robson, 1989). Typical naturally occurring zeolites include analcite (also called analcime) Na(AlSi2O6), and faujasite Na2Ca(AlO2)2(SiO2)4.H2O that is the structural analog of the synthetic zeolite X and zeolite Y. Sodalite (Na8[(Al2O2)6(SiO2)6]Cl2) contains the truncated octahedral structural unit known as the sodalite cage that is found in several zeolites. The corners of the faces of the cage are defined by either four or six Al/Si atoms, which are joined together through oxygen atoms. The zeolite structure is generated by joining sodalite cages through the four-Si/Al rings, so enclosing a cavity or super cage bounded by a cube of eight sodalite cages and readily accessible through the faces of that cube (channels or pores). Joining sodalite cages together through the six-Si/Al faces generates the structural frameworks of faujasite, zeolite X, and zeolite Y. In zeolites, the effective width of the pores is usually controlled by the nature of the cation (M+ or M2+). Natural zeolites form hydrothermally (e.g., by the action of hot water on volcanic ash or lava), and synthetic zeolites can be made by mixing solutions of aluminates and silicates and maintaining the resulting gel at temperatures of 100°C (212°F) or higher for appropriate periods. Zeolite-A can form at temperatures below 100°C (212°F), but most zeolite syntheses require hydrothermal conditions (typically 150°C/300°F at the appropriate pressure). The reaction mechanism appears to involve dissolution of the gel and precipitation as the crystalline zeolite and the identity of the zeolite produced depend on the composition of the solution. Aqueous alkali metal hydroxide solutions favor zeolites with relatively high aluminum contents, while the presence of organic molecules such as amines or alcohols favors highly siliceous zeolites such as silicalite or ZSM-5. Zeolite catalysts have also found use in the refining industry during the last two decades. Like the silica-alumina catalysts, zeolites also consist of a framework of tetrahedra usually with a silicon atom or an aluminum atom at the center. The geometric characteristics of the zeolites are responsible for their special properties, which are particularly attractive to the refining industry (DeCroocq, 1984). Specific zeolite catalysts have shown up to 10,000 times more activity than the so-called conventional catalysts in specific cracking tests. The mordenite-type catalysts are particularly worthy of mention since they have shown up to 200 times greater activity for hexane cracking in the temperature range of 360°C–400°C (680°F–750oF). Other zeolite catalysts have also shown remarkable adaptability to the refining industry. For example, the resistance to deactivation of the type Y zeolite catalysts containing either noble or non-noble metals is remarkable, and catalyst life of up to 7 years has been obtained commercially in processing viscous gas oils in the Unicracking-JHC processes. Operating life depends on the nature of the feedstock, the severity of the operation, and the nature and extent of operational upsets. Gradual catalyst deactivation in commercial use is counteracted by incrementally raising the operating temperature to maintain the required conversion per pass. The more active a catalyst, the lower is the temperature required. When processing for naphtha, lower operating temperatures have the additional advantage that less of the feedstock is converted to iso-butane.

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Any given zeolite is distinguished from other zeolites by structural differences in its unit cell, which is a tetrahedral structure arranged in various combinations. Oxygen atoms establish the four vertices of each tetrahedron, which are bound to, and enclose, either a silicon (Si) or an aluminum (Al) atom. The vertex oxygen atoms are each shared by two tetrahedrons, so that every silicon atom or aluminum atom within the tetrahedral cage is bound to four neighboring caged atoms through an intervening oxygen. The number of aluminum atoms in a unit cell is always smaller than, or at most equal to, the number of silicon atoms because two aluminum atoms never share the same oxygen. The aluminum is actually in the ionic form and can readily accommodate electrons donated from three of the bound oxygen atoms. The electron donated by the fourth oxygen imparts a negative, or anionic, charge to the aluminum atom. This negative charge is balanced by a cation from the alkali metal or the alkaline earth groups of the periodic table. Such cations are commonly sodium, potassium, calcium, or magnesium. These cations play a major role in many zeolite functions and help to attract polar molecules, such as water. However, the cations are not part of the zeolite framework and can be exchanged for other cations without any effect on crystal structure. Zeolites provide the cracking function in many hydrocracking catalysts, as they do in fluid catalytic cracking catalysts. The zeolites are crystalline aluminosilicates, and in almost all commercial catalysts today, the zeolite used is faujasite. Pentasil zeolites, including silicalite and ZSM-5, are also used in some catalysts for their ability to crack long-chain paraffins selectively. Typical levels are 25%–50% by wt. zeolite in the catalysts, with the remainder being the hydrogenation component and a silica (SiO2) or alumina (Al2O3) binder. Exact recipes are guarded as trade secrets. Crystalline zeolite compounds provide a broad family of solid acid catalysts. The chemistry and structures of these solids are beyond the scope of this book. What is important here is that the zeolites are not acidic as crystallized. They must be converted to acidic forms by ion exchange processes. In the process of doing this conversion, the chemistry of the crystalline structure is often changed. This complication provides tools for controlling the catalytic properties, and much work has been done on understanding and applying these reactions as a way to make catalysts with higher activities and more desirable selectivity. As an example, the zeolite faujasite crystallizes with the composition SiO2(NaAlO2)x(H2O)y. The ratio of silicon to aluminum, expressed here by the subscript x, can be varied in the crystallization from 1 to greater than 10. What does not vary is the total number of silicon and aluminum atoms per unit cell, 192. For legal purposes to define certain composition of matter patents, zeolites with a ratio of 1–1.5 are called type X; those with ratio greater than 1.5 are type Y. Both silicon and aluminum in zeolites are found in tetrahedral oxide sites. The four oxides are shared with another silicon or aluminum (except that two aluminum ions are never found in adjacent, linked tetrahedral). Silicon with a plus four charge balances exactly half of the charge of the oxide ions it is linked to; since all of the oxygens are shared, silicon balances all of the charge around it and is electrically neutral. Aluminum, with three positive charges, leaves one charge unsatisfied. Sodium neutralizes this charge. The sodium, as expected from its chemistry, is not linked to the oxides by covalent bonds as the silicon and aluminum are. The attraction is simply ionic, and sodium can be replaced by other cations by ion exchange processes. In extensive but rarely published experiments, virtually every metallic and organic cation has been exchanged into zeolites in studies by catalyst designers. The most important ion exchanged for sodium is the proton. In the hydrogen ion form, faujasite zeolites are very strong acids, with strengths approaching that of oleum. Unfortunately, direct exchange using mineral acids such as hydrochloric acid is not practical. The acid tends to attack the silica-alumina network, in the same way that strong acids attack clays in the activation processes developed by Houdry. The technique adopted to avoid this problem is indirect exchange, beginning with exchange of ammonium ion for the sodium. When heated to a few hundred degrees, the ammonium decomposes, forming gaseous ammonia and leaving behind a proton:

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R – NH 4+ → R – H + + NH 3 ↑ .

The step is accompanied by a variety of solid-state reactions that can change the zeolite structure in subtle but important ways. This chemistry and the related structural alterations have been described in many articles. While zeolites provided a breakthrough that allowed catalytic hydrocracking to become commercially important, continued advances in the manufacture of amorphous silica-alumina made these materials competitive in certain kinds of applications. This was important, because patents controlled by Unocal and Exxon dominated the application of zeolites in this area. Developments in amorphous catalysts by Chevron and UOP allowed them to compete actively in this area. Typical catalysts of this type contain 60–80 wt.% of the silica-alumina, with the remainder being the hydrogenation component. The amorphous silica-alumina is made by a variety of precipitation techniques. The whole class of materials traces its beginnings to silica gel technology, in which sodium silicate is acidified to precipitate the hydrous silica-alumina sulfate; sulfuric acid is used as some or all of the acid for this precipitation, and a mixed gel is formed. The properties of this gel, including acidity and porosity, can be varied by changing the recipe – concentrations, order of addition, pH, temperature, aging time, and the like. The gels are isolated by filtration and washed to remove sodium and other ions. Careful control of the precipitation allows the pore size distributions of amorphous materials to be controlled but the distributions are still much broader than those in the zeolites. This limits the activity and selectivity. One effect of the reduced activity has been that these materials have been applied only in making middle distillates: diesel and turbine fuels. At higher process severities, the poor selectivity results in production of unacceptable amounts of methane (CH4) to butane (C4H10) hydrocarbons. Hydrocarbons, especially aromatic hydrocarbons, can react in the presence of strong acids to form coke. This coke is a complex polynuclear aromatic material that is low in hydrogen. Coke can deposit on the surface of a catalyst, blocking access to the active sites and reducing the activity of the catalyst. Coke poisoning is a major problem in fluid catalytic cracking catalysts, where coked catalysts are circulated to a fluidized-bed combustor to be regenerated. In hydrocracking, coke deposition is virtually eliminated by the catalyst’s hydrogenation function. However, the product referred to as coke is not a single material. The first products deposited are tarry deposits that can, with time and temperature, continue to become more complex and can reduce the concentration of coke precursors on the surface. There is, however, a slow accumulation of coke that reduces activity over a 1–2-year period. Refiners respond to this slow reduction in activity by raising the average temperature of the catalyst bed to maintain conversions. Eventually, however, an upper limit to the allowable temperature is reached and the catalyst must be removed and regenerated. Catalysts carrying coke deposits can be regenerated by burning off the accumulated coke. This is done by service in rotary or similar kilns rather than leaving catalysts in the hydrocracking reactor, where the reactions could damage the metals in the walls. Removing the catalysts also allows inspection and repair of the complex and expensive reactor internals, discussed below. Regeneration of a large catalyst charge can take weeks or months, so refiners may own two catalyst loads, one in the reactor, and one regenerated and ready for reload. The thermal reactions also convert the metal sulfide hydrogenation functions to oxides and may result in agglomeration. Excellent progress has been made since the 1970s in regenerating hydrocracking catalysts; similar regeneration of hydrotreating catalysts is widely practiced. After combustion to remove the carbonaceous deposits, the catalysts are treated to disperse active metals. Vendor documents claim more than 95% recovery of activity and selectivity in these regenerations. Catalysts can undergo successive cycles of use and regeneration, providing long functional life with these expensive materials.

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Hydrocracking allows refiners the potential to balance fuel oil supply and demand by adding VGO cracking capacity. Situations where this is the case include (1) refineries with no existing VGO cracking capacity, (2) refineries with more VGO available than VGO conversion capacity, (3) refineries where addition of viscous feedstock conversion capacity has resulted in production of additional cracking feedstocks boiling in the VGO range (e.g., coker gas oil), and (4) refineries that have one of the two types of VGO conversion units but could benefit from adding the second type. In some cases, a refiner might add both gas oil cracking and viscous feedstock conversion capacity simultaneously. Those refiners who do choose gas oil cracking as part of their strategy for balancing residual fuel oil supply and demand must decide whether to select a hydrocracker or a fluid catalytic cracking unit. Although the two processes have been compared vigorously over the years, neither process has evolved to be the universal choice for gas oil cracking. Both processes have their advantages and disadvantages, and process selection can be properly made only after careful consideration of many case-specific factors. Among the most important factors are: (1) product slate required, (2) amount of flexibility required to vary the product slate, (3) product quality (specifications) required, and (4) the need to integrate the new facilities in a logical and cost-effective way with any existing facilities. The type of catalyst used can influence the product slate obtained. Indeed, several catalytic systems have now been developed with a group of catalysts specifically for mild hydrocracking operations. Depending on the type of catalyst, they may be run as a single catalyst or in conjunction with a hydrotreating catalyst. Insight into catalyst nanostructures is leading to the development of high-activity catalysts, which provide solutions and designs to meet many product specifications. In addition, such insights are leading to optimization of hydrocracker units with respect to yield structure, product properties, throughput and on-stream efficiency, resulting in improved refinery margins. The development of new hydrocracking catalysts is very dependent on new or modified materials. Topsøe has found unique methods of preparing hydroprocessing catalysts, and through an extensive understanding of the chemistry has demonstrated a high level of expertise in making catalyst carriers with a uniform distribution of acidic sites and hydrogenation metal sites. Many zeolite hydrocracking catalysts are now offered in the trilobe shape which reduces the diffusion path and decrease the pressure drop. The design significantly enhances the accessibility of the active catalyst sites and thus provides a substantial enhance, of the catalyst activity. In order to optimize overall unit performance, catalysts with pore size distribution to match the changing molecular structure of the oil as it processes through the reactor system are necessary. They are applied in the front-end reactor when processing high-metal-containing feedstocks (>70 ppm vanadium). Catalysts which exhibit the high activity for sulfur, coke precursors, and nitrogen conversion are applied in the middle and/or tail-end reactors.

5.4  OPTIONS FOR VISCOUS FEEDSTOCKS The goal of viscous feedstock hydroconversion is to convert feedstocks to low-sulfur liquid products oils or, in some cases, to pretreat feedstocks for fluid catalytic cracking processes. Some of the processes available for hydroprocessing viscous feedstocks are presented below. However, when applied to viscous feedstocks (heavy crude oil, extra heavy crude oil, oil, tar sand bitumen, and residua), the problems encountered can be directly equated to the amount of complex, higher boiling constituents that may require pretreatment (Speight and Moschopedis, 1979; Speight, 2000; Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). Furthermore, the majority of the higher molecular weight materials produce high yields (35%–60% by weight) coke. It is this trend of coke formation that hydrocracking offers some relief. However, asphaltene constituents and metal-containing constituents exert a strong deactivating influence on the catalyst which markedly decreases the hydrogenolysis rate of sulfur compounds, practically without having impact on coke

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formation. In addition, nitrogen-containing compounds are adsorbed on acid sites, blocking the sites and thereby lowering catalyst activity. Thus, during the hydrocracking of viscous feedstocks, preliminary feedstock HDS and demetallization over special catalyst are advantageous. The processes that follow are available for conversion of viscous feedstocks to a variety of product slates and are listed in alphabetical order with no other preference in mind.

5.4.1 Aquaconversion Aquaconversion process is a catalytic steam conversion process that involves the transfer hydrogen from water vapor into the unconverted feedstock, therefore increasing its stability by avoiding the formation of chemical systems that are precursors to coke formation. In this manner, the reactions that lead to coke formation are suppressed, and there is no separation of asphaltene-type material. Typically, the Aquaconversion process extends the maximum conversion level within the stability specification by adding a homogeneous catalyst in the presence of steam. The hydrogen incorporation is much lower than that obtained when using a deep hydroconversion process under high hydrogen partial pressure. Nevertheless, it is high enough to saturate the free radicals, formed within the thermal process, which would normally lead to coke formation. With hydrogen incorporation, a higher conversion level can be reached and thus higher API and viscosity improvements while maintaining syncrude stability. The important aspect of the Aquaconversion technology is that it does not produce coke, nor does it require any hydrogen source or high-pressure equipment. In addition, the Aquaconversion process can be implanted in the production area, and thus the need for external diluent and its transport over large distances is eliminated. Low-boiling distillates from the feedstock can be used as diluent for both the production and desalting processes. Also some catalysts processes have been developed such as catalytic aquathermolysis which is used for upgrading viscous feedstocks (Fan et al., 2004; Li et al., 2007; Wen et al., 2007; Chen et al., 2009; Fan et al., 2009).

5.4.2 Asphaltenic Bottom Cracking Process The asphaltenic bottom cracking (ABC) process can be used for distillate production, hydrodemetallization (HDM), asphaltene cracking, and moderate HDS as well as sufficient resistance to coke fouling and metal deposition using viscous such feedstocks as well as thermally cracked residua, solvent deasphalted bottoms with fixed catalyst beds (Kressmann et al., 1998). The process can be combined with: (1) solvent deasphalting for complete or partial conversion of the residuum or (2) HDS to promote the conversion of residue, to treat feedstock with high metals and to increase catalyst life or (3) hydrovisbreaking to attain high conversion of the viscous feedstock with favorable product stability. In the process, the feedstock is pumped up to the reaction pressure and mixed with hydrogen. The mixture is heated to the reaction temperature in the charge heater after a heat exchange and fed to the reactor. The reactor effluent gas is cooled, cleaned up, and recycled to the reactor section, while the separated liquid is distilled into distillate fractions and vacuum residue which is further separated by deasphalting into deasphalted oil and asphalt using butane or pentane. In case of the ABC-HDS catalyst combination, the ABC catalyst is placed upstream of the HDS catalyst and can be operated at a higher temperature than the HDS catalyst under conventional viscous feedstock HDS conditions. In the VisABC process, a soaking drum is provided after heater, when necessary. Hydrovisbroken oil is first stabilized by the ABC catalyst through hydrogenation of coke precursors and then desulfurized by the HDS catalyst.

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5.4.3 CANMET Process The CANMET hydrocracking process was designed to process viscous feedstocks. The process is now no longer available from the licensors (the Government of Canada) and has been incorporated into the UOP Uniflex process. Nevertheless, the CANMET process is worthy of description here – if only for historical purposes – because of the novel aspect in the successful use of a scavenger to enhance the hydrocracking process and decrease coke formation. The process was specially developed for use with Athabasca bitumen bur can accommodate a variety of viscous feedstocks, including atmospheric residua, and vacuum residua (Pruden, 1978; Pruden et al., 1993). The process was a high-conversion, high-demetallization, viscous feedstock hydrocracking process which, using an additive to inhibit coke formation, achieves conversion of high boiling point hydrocarbons into lighter products. Initially developed to upgrade the heavy crude oils and the tar sand bitumen of Alberta, an ongoing program of development has broadened the technology to processing offshore heavy crude oil and the bottom of the barrel materials from so-called conventional crude oils. The process did not use a catalyst but employs a low-cost additive to inhibit coke formation and allow high conversion of viscous feedstocks into lower-boiling products using a single reactor. The process was unaffected by high levels of feed contaminants such as sulfur, nitrogen, and metals. Conversion of over 90% of the 525°C+ (975°F+) fraction into distillates was attained. In the process, the feedstock and recycle hydrogen gas were heated to reactor temperature in separate heaters. A small portion of the recycle gas stream and the required amount of additive are routed through the oil heater to prevent coking in the heater tubes. The outlet streams from both heaters are fed to the bottom of the reactor. The vertical reactor vessel is free of internal equipment and operates in a three-phase mode. The solid additive particles are suspended in the primary liquid hydrocarbon phase through which the hydrogen and product gases flow rapidly in bubble form. The reactor exit stream was quenched with cold recycle hydrogen prior to the high-pressure separator. The viscous liquids are further reduced in pressure to a hot medium-pressure separator and from there to fractionation. The spent additive leaves with the viscous fraction and remains in the unconverted viscous feedstock. The vapor stream from the hot high-pressure separator is cooled stepwise to produce middle distillate and naphtha that are sent to fractionation where (1) the naphtha product will be hydrotreated and reformed, (2) the low-boiling gas oil product will be hydrotreated and sent to the distillate pool, (3) the high-boiling gas oil product will be used as a feedstock for a fluid catalytic cracking, and (4) the non-volatile product (often referred to as ‘pitch’) will be sold as, e.g., an asphalt constituent or be subject to further cracking. The additive, prepared from iron sulfate [Fe2(SO4)3], is used to promote hydrogenation and effectively eliminate coke formation. The effectiveness of the dual-role additive permits the use of operating temperatures that give high conversion in a single-stage reactor. The process maximizes the use of reactor volume and provides a thermally stable operation with no possibility of temperature runaway. In terms of the additive, the use of iron sulfate is reminiscent of the older red mud process which used an iron-containing mud (an iron-containing slurry) to convert coal to liquids.

5.4.4 Chevron RDS Isomax and VRDS Process The RDS/VRDS process (like the Residfining process) is designed to hydrotreat VGO, atmospheric residuum, vacuum residuum, and other viscous feedstocks to remove sulfur metallic constituents, while part of the feedstock is converted to lower-boiling products. In the case of viscous feedstocks, the asphaltene content is reduced. The process consists of a once-through operation and is ideally suited to produce feedstocks for residuum fluid catalytic crackers or delayed coking units to achieve minimal production of residual products in a refinery. The basic elements of each process are similar and consist of a once-through operation of the feedstock coming into contact with hydrogen and the catalyst in a downflow reactor that is designed

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to maintain activity and selectivity in the presence of deposited metals. Moderate temperatures and pressures are employed to reduce the incidence of hydrocracking and, hence, minimize production of low-boiling distillate products. The combination of a desulfurization step and a viscous feedstock desulfurizer (the VRDS option) is considered to be an attractive alternate to the atmospheric residuum desulfurizer (the RDS option). In addition, either RDS option or the VRDS option can be coupled with other processes (such as delayed coking, fluid catalytic cracking, and solvent deasphalting) to achieve the most optimum refining performance. The principal product is a low-sulfur fuel oil that can be used as a blending stock or as a feedstock for a fluid catalytic unit. The process employs a downflow fixed-bed reactor containing a highly selective catalyst that provides extensive desulfurization at low pressures with minimal cracking and, therefore, low consumption of hydrogen. In the process, which is designed for viscous feedstocks including a wide range of residua and other viscous feedstocks, the feedstock and hydrogen are charged to the reactors in a oncethrough operation. The catalyst combination can be varied significantly according to feedstock properties to meet the required product qualities. Product separation is done by the hot separator, cold separator, and fractionator. Recycle hydrogen passes through a hydrogen sulfide absorber. The on-stream catalyst replacement (OCR) reactor technology improves catalyst utilization and increase run length with high-metals viscous feedstocks. This technology allows spent catalyst to be removed from one or more reactors and replaced with fresh, while the reactors continue to operate normally. The novel use of upflow reactors in the OCR technology provides increased tolerance of feed solids while maintaining low-pressure drop. A related technology (upflow reactor technology) uses a multi-bed upflow reactor for minimum pressure drop in cases where OCR is not necessary. OCR technology and upflow reactor technology are particularly well suited to revamp existing RDS/VRDS units for additional throughput or heavier feedstock. The products (Residuum FCC feedstock, coker feedstock, solvent deasphalter feedstock, or low-sulfur fuel oil, and VGO) are suitable for further upgrading by fluid catalytic cracking units or hydrocrackers for naphtha/ mid-distillate manufacture. Mid-distillate material can be directly blended into low-sulfur diesel or further hydrotreated into ULSD. Thus, the process can be integrated with residuum fluid catalytic cracking units to minimize catalyst consumption, improve yields, and reduce sulfur content of fluid catalytic cracking products.

5.4.5 ENI Slurry-Phase Technology The ENI slurry-phase technology adopts high operating pressures and can achieve near complete-tocomplete conversion of the viscous feedstock while producing finished saleable products (Motaghi et al., 2010, 2011). Moreover, the slurry-phase hydrocracking process can be used to convert viscous feedstocks under process conditions on the order of 450°C (840°F) and 2,000–3,000 psi. The slurryphase process has the potential (which is feedstock dependent) to achieve a high conversion of viscous feedstocks while minimizing by-products such as gas, fuel oil, and coke (Zhang et al., 2007). In the process, fresh feedstock is sent to the fresh feed heater and then mixed with the proprietary catalyst makeup and sent to the upflow slurry bubble column reactor. The stream is subsequently cooled and sent to a cold high-pressure separator to separate the gas stream, rich in hydrogen, and the hydrocarbon liquid stream. The reaction occurs at 400°C–450°C (750°F–840°F) and at approximately 2,200 psi with hydrogen fed from the bottom of the reactor. Under the reaction conditions, the catalyst precursor forms highly dispersed molybdenum sulfide (MoS2) nanoparticles. The unconverted non-volatile fraction at the bottom of the vacuum distillation column, containing all of the catalyst, is recycled back to the reactor, and only a small part of the viscous fraction is purged (1%–3% w/w of the fresh feedstock) to avoid the accumulation of coke precursors and of Ni and V sulfides from the organometallic compounds contained in the feedstock. With the purge, a limited amount of molybdenum is also removed; therefore, an equivalent amount is fed continuously to the reactor to maintain concentration constant. The purge can be used as a fuel in the cement or steel industries. In order to facilitate the handling of the purge and its blending with

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other streams, the viscosity can be adjusted by adding a small amount of a low-value flow improver (such as VGO). The purge can also be treated in a centrifugal decanter to recover the liquid fraction, which is recycled back to the reactor, and a solid product (cake) containing viscous hydrocarbons, coke, and concentrated metal sulfides. The cake can be processed further to recover the metals (molybdenum, vanadium, and nickel). Since the largest part of the catalyst is not lost, but is recycled to the reaction section, the process can operate at a higher catalyst concentration than in the case with other slurry technologies. The process is very flexible with regard to the feedstock and can accept feedstocks such as vacuum residua from different viscous crudes, tar sand bitumen, and refinery visbroken tar. The typical overall performance of the process is (1) metal removal: >99%, (2) Conradson carbon residue reduction: >97% (3 sulfur reduction: >85%), and (4) nitrogen reduction: >40%. Furthermore, because of the recycling of unconverted products and the dispersed catalyst, the process has the ability to reach total conversion of the feedstock.

5.4.6 Gulf Resid Hydrodesulfurization Process The Gulf Resid HDS process is a regenerative fixed-bed process that can be to upgrade viscous feedstocks by catalytic hydrogenation to refined fuel oil or to high-quality catalytic charge stocks. Long on-stream cycles are maintained by reducing random hydrocracking reactions to a minimum, and whole crude oils, virgin, or cracked residua may serve as feedstock. This process is suitable for the desulfurization of high-sulfur residua (atmospheric and vacuum) to produce low-sulfur fuel oils or catalytic cracking feedstocks. The process has three basic variations – the Type II unit, the Type III unit, and the Type IV unit with the degree of desulfurization and process severity, increasing from Type I to Type IV. Thus, liquid products from Types III and IV units can be used directly as catalytic cracker feedstocks and perform similarly to virgin gas oil fractions, whereas liquid products from the Type II unit usually need to be vacuum-flashed to provide a feedstock suitable for a catalytic cracker. Each process type is basically similar to its predecessor but will differ in the number of reactors. For example, modifications necessary to convert the Type II to the Type III process consist of the addition of a reactor and related equipment, while the Type III process can be modified to a Type IV process by the addition of a third reactor section. Types III and IV are especially pertinent to the problem of desulfurizing viscous oils and residua since they have the capability of producing lowsulfur liquid products from high-sulfur viscous feedstocks. On-stream catalyst cycles (which may be on the order of months to years) are feedstock-dependent and desulfurization levels on the order of 65%–75% can be attained.

5.4.7  H-G Hydrocracking Process The H-G hydrocracking process may be designed with either a single- or a two-stage reactor system for conversion of light and viscous gas oils to lower-boiling fractions. The feedstock is mixed with recycle gas oil, makeup hydrogen, and hydrogen-rich recycle gas, and then heated and charged to the reactor. The reactor effluent is cooled and sent to a high-pressure separator, where hydrogen-rich gas is flashed off, scrubbed, and then recycled to the reactor. Separator liquid passes to a stabilizer for removal of butanes and lighter products, and the bottoms are taken to a fractionator for separation; any unconverted material is recycled to the reactor.

5.4.8  H-Oil Process The H-Oil process (Speight, 2014, 2017) is a catalytic process that uses a single-stage, two-stage, or three-stage ebullated-bed reactor in which, during the reaction, considerable hydrocracking takes place. A modification of H-Oil called Hy-C cracking converts viscous distillates to middle distillates and kerosene.

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The process is designed for hydrogenation of viscous feedstocks in an ebullated-bed reactor to produce upgraded crude oil products (Speight, 2014, 2017). The process is able to convert all types of feedstocks to either distillate products as well as to desulfurize and demetallize viscous feedstocks for feed to coking units or fluid catalytic cracking units, for production of low-sulfur fuel oil, or for production to asphalt blending. A modification of the H-Oil process (Hy-C Cracking process) converts high-boiling distillates to middle distillates and kerosene. A wide variety of process options can be used with the H-Oil process (a catalytic ebullated-bed reactor system) to provide an efficient hydroconversion of the viscous feedstock. The system ensures uniform distribution of liquid, hydrogen-rich gas, and catalyst across the reactor. The ebullatedbed system operates under essentially isothermal conditions, exhibiting little temperature gradient across the bed (Kressmann et al., 1998, 2000, 2004). The heat of reaction is used to bring the feed oil and hydrogen up to reactor temperature. In the process, feedstock (which may be combined with recycled residuum) and hydrogen are fed upward through the reactors as a liquid-gas mixture at a velocity such that catalyst is in continuous motion. A catalyst of small particle size can be used, giving efficient contact among gas, liquid, and solid with good mass and heat transfer. Part of the reactor effluent is recycled back through the reactors for temperature control and to maintain the requisite liquid velocity. The entire bed is held within a narrow temperature range, which provides essentially an isothermal operation with an exothermic process. Because of the movement of catalyst particles in the liquid-gas medium, deposition of tar and coke is minimized and fine solids entrained in the feed do not lead to reactor plugging. The catalyst can also be added and withdrawn from the reactor without destroying the continuity of the process. The reactor effluent is cooled by exchange and separates into vapor and liquid. After scrubbing in a lean oil absorber, hydrogen is recycled and the liquid product is either stored directly or fractionated before storage and blending. A variation of this process (the HDH resid hydrocracking process) was originally developed for the upgrading of viscous oils from Orinoco Oil Belt, Venezuela. In the process, the viscous feedstock is slurried with a low-cost catalyst and fed into a series of upflow bubbling (slurry) reactors operating at 420°C–480°C (790°F–900°F) temperature under hydrogen partial pressure. The reaction products are fractionated using a high-pressure, hot separator. While ebullated-bed processes are continuous and produce higher levels of liquid fuels (no coke), it is not always possible to achieve complete viscous feedstock conversion and the unit may still produce 20%–30% v/v of viscous-resid product (Motaghi et al., 2010, 2011). Ebullated beds have also been prone to high operating costs, and have sometimes been plagued with poor operability. The quality of liquid products, although improved over coking, still requires secondary processing to produce clean fuels. The inability to achieve near-complete conversion requires further processing of unconverted resid. In terms of advancement of ebullated-bed technology, the original H-Oil process has evolved, during the past decade, into various configurations that have the potential to play major roles in viscous feedstock upgrading up to and beyond the year 2020. A new development in H-Oil process technology is inter-stage separation for a two-stage unit design (Kressmann et al., 2004). In this configuration, an additional vessel is fed the first-stage reactor effluent (mixed phase) and separates it into vapor and liquid products. The inter-stage liquid is fed to the second-stage reactor and the vapor to the overhead of the hot high-pressure separator located after the second-stage reactor. With inter-stage separation, off-loading of the first-stage reactor gas results in improved reaction kinetics in the second-stage reactor since the amount of gas hold-up in the reactor is greatly reduced and increasing liquid hold-up enables greater conversion of the feedstock. The H-OilDC process (previously known as the T-Star process) is a specially engineered, ebullated-bed process for the treatment of VGOs. Because of the ability to replace the catalyst bed incrementally, the H-OilDC reactor can operate indefinitely – typically, four to five years between turnarounds to coincide with the inspection and maintenance schedule for a fluid catalytic cracking

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unit. The difficult processing requirements which result from stricter environmental regulations and the processing of viscous feedstocks makes H-OilDC a preferred choice for pretreatment of fluid catalytic cracker feedstocks. The H-OilHCC is a viscous crude conversion process produces synthetic crude oil. The objective of the unit is to enable just enough conversion to reduce viscosity and increase stability so that the product can be readily transported to an upgrading center. Among the improvements made to the traditional H-Oil technology are the integration of an inter-stage separator between reactors in series and the application of cascade catalyst utilization. The result is (1) an increase conversion levels, (2) an increase in product stability, and (3) reduced processing costs.

5.4.9  HYCAR Process Briefly, hydrovisbreaking is a non-catalytic process that is conducted under similar conditions to visbreaking and involves treatment with hydrogen under mild conditions. The presence of hydrogen leads to more stable products (lower flocculation threshold) than can be obtained with straight visbreaking, which means that higher conversions can be achieved, producing a lower viscosity product.

5.4.10  Hydrovisbreaking Process The hydrovisbreaking process (also known as the HYCAR process) is a non-catalytic process, is conducted under similar conditions to visbreaking, and involves treatment with hydrogen under mild conditions (Speight, 2014, 2017). The presence of hydrogen leads to more stable products (lower flocculation threshold) than can be obtained with straight visbreaking, which means that higher conversions can be achieved, producing a lower viscosity product. The HYCAR process is composed fundamentally of three parts, which are (1) visbreaking, (2) HDM, and (3) hydrocracking. In the visbreaking section, the viscous feedstock (e.g., vacuum residuum or bitumen) is subjected to moderate thermal cracking while no coke formation is induced. The visbroken oil is fed to the demetallization reactor in the presence of catalysts, which provides sufficient pore for diffusion and adsorption of high-molecular-weight constituents. The product from this second stage proceeds to the hydrocracking reactor, where desulfurization and denitrogenation take place along with hydrocracking.

5.4.11  Hyvahl-F Process The Hyvahl-F process was designed to hydrotreat viscous feedstocks such as atmospheric residua and vacuum residua to convert the feedstock to naphtha and middle distillates (Billon et al., 1994; Speight, 2014, 2017). The main features of the process are its dual-catalyst system and its fixed-bed swing-reactor concept. The first catalyst has a high capacity for metals (to 100% by w/w new catalyst) and is used for both HDM and most of the conversion. This catalyst is resistant to fouling, coking, and plugging by asphaltene constituents (as well as by reacted asphaltene constituents) and shields the second catalyst from the same. Protected from metal poisons and deposition of coke-like products, the highly active second catalyst can carry out its deep HDS and refining functions. Both catalyst systems use fixed beds that are more efficient than moving beds and are not subject to attrition problems. More than 50% of the metals are removed from the feedstock in the guard reactors. In the process, the preheated feedstock enters one of the two guard reactors where a large proportion of the nickel and vanadium are adsorbed and hydroconversion of the high-molecular-weight constituents commences. Meanwhile, the second guard-reactor catalyst undergoes a reconditioning process and then is put on standby. The next processing stage is the HDS stage where the majority of the sulfur as well as some of the nitrogen and the residual metals are removed, and a limited amount of conversion also takes place.

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A related process – the Hyvahl-M process – employs a countercurrent moving-bed reactor and is recommended for viscous feedstocks that contain substantial amounts of metals and asphaltene constituents.

5.4.12 IFP Hydrocracking Process The process features a dual-catalyst system which is composed of (1) a promoted nickel-molybdenum amorphous catalyst that removes sulfur and nitrogen and hydrogenate aromatic rings and (2) a zeolite catalyst that completes the hydrogenation and also promotes the hydrocracking reaction. In the single-stage process, the first reactor effluent is sent directly to the second reactor, followed by the separation and fractionation steps. The fractionator bottoms are recycled to the second reactor or sold. The liquid leaving the separator is fractionated, the middle distillates and lower-boiling streams (Speight, 2014, 2017) are sent to storage, and the high-boiling stream is transferred to the second reactor section and then recycled back to the separator section.

5.4.13 Isocracking Process The hydrocracker is a high-pressure, moderate-temperature conversion unit and the designs include single-stage once-through, single-stage recycle, and two-stage recycle processes. A two-stage hydrocracker with intermediate distillation is an option for maximizing the production middle distillate products. The process can be applied as (1) a single-stage process, often referred to as once-through liquid process, (2) a single-stage, partial recycle of a viscous feedstock, such as viscous crude oil, (3) a single-stage recycle-to-extinction of the feedstock which represents 100% conversion of the feedstock, and (4) a two-stage recycle-to-extinction recycle of the feedstock which also represents 100% conversion of the feedstock (Speight, 2014, 2017). The preferred flow scheme is dependent on the feed properties, the processing objectives, and, to some extent, the specified feed rate. The process uses multi-bed reactors and, in most applications, a number of catalysts are used in a reactor. The catalysts have dual function being a mixture of hydrous oxides (for cracking) and viscous metal sulfides (for hydrogenation). The catalysts are used in a layered system to optimize the processing of the feedstock that undergoes changes in its properties along the reaction pathway (Speight, 2014, 2017). In the process, the feedstock (typically a blend of viscous gas oils) is sent to the first stage of the hydrocracker and is severely hydrotreated. Most of the sulfur and nitrogen compounds are removed from the feedstock and many of the aromatics are saturated. In addition, significant conversion to light products occurs in the first stage. The liquid product from the first stage is then sent to a common fractionation section where, to prevent over-cracking, lower-boiling products are removed by distillation. The unconverted material from the bottom of the fractionator is routed to the secondstage reactor section. The second reaction stage saturates almost all of the aromatics and cracks the oil feed to light products. Due to the aromatics saturation, the second stage produces excellentquality products. The liquid product from the second stage is then sent to the common fractionator, where light products are distilled. The second stage operates in a recycle-to-extinction mode with per-pass conversions ranging from 50% to 80% v/v. The overhead liquid and vapor from the hydrocracker fractionator is further processed in a light ends recovery unit where fuel gas and LPG and naphtha are separated. The hydrogen supplied to the reactor sections of the hydrocracker comes from reformers or steam-reformers. The hydrogen is compressed in stages until it reaches system pressure of the reactor sections. In most commercial Isocracking units, the entire fractionator bottoms fraction is recycled or all of it is drawn as viscous product, depending on whether the low-boiling or high-boiling products are of greater value. If the low-boiling distillate products (naphtha or naphtha/kerosene) are the most valuable products, the higher boiling point distillates (like diesel) can be recycled to the reactor for

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conversion rather than drawn as a product (RAROP, 1991, p. 83; Khan and Patmore, 1998). Product distribution depends upon the feedstock and (as anticipated) the product yield is very much dependent upon the catalyst and the process parameters.

5.4.14 LC-Fining Process The LC-Fining process is a hydrocracking process capable of desulfurizing, demetallizing, and upgrading a wide spectrum of viscous feedstocks by means of an expanded-bed reactor (Bishop, 1990; RAROP, 1991, p. 61; Khan and Patmore, 1998; Speight, 2014, 2017). The process uses the expanded-bed concept which allows processing of a variety of viscous feedstocks (up to and including tar sand bitumen). The catalyst in the reactor behaves like fluid that enables the catalyst to be added to and withdrawn from the reactor during operation. The reactor conditions are near isothermal because the heat of reaction is absorbed by the cold fresh feed immediately owing to through mixing of reactors. In the process, the feedstock and hydrogen are heated separately and then passed upward in the hydrocracking reactor through an expanded bed of catalyst (Speight, 2014). Reactor products flow to the high-pressure, high-temperature separator. Vapor effluent from the separator is let down in pressure, and then goes to the heat exchange and thence to a section for the removal of condensable products, and purification (Speight, 2014, 2017). Liquid is let down in pressure and passes to the recycle stripper. This is a most important part of the high-conversion process. The liquid recycle is prepared to the proper boiling range for return to the reactor. In this way, the concentration of bottoms in the reactor, and therefore the distribution of products, can be controlled. After the stripping, the recycle liquid is then pumped through the coke precursor removal step where high-molecular-weight constituents are removed. The clean liquid recycle then passes to the suction drum of the feed pump. The product from the top of the recycle stripper goes to fractionation and any viscous oil product is directed from the stripper bottoms pump discharge. The residence time in the reactor is adjusted to provide the desired conversion levels. Catalyst particles are continuously withdrawn from the reactor, regenerated, and recycled back into the reactor, which provides the flexibility to process a wide range of viscous feedstocks such as atmospheric and vacuum tower bottoms, coal-derived liquids, and bitumen. An internal liquid recycle is provided with a pump to expand the catalyst bed, continuously. As a result of expanded-bed operating mode, small pressure drops and isothermal operating conditions are accomplished. Small-diameter extruded catalyst particles as small as 0.8 mm (1/32 inch) can be used in this reactor. Although the process may not be the means by which direct conversion of the bitumen to a synthetic crude oil would be achieved, it does nevertheless offer an attractive means of bitumen conversion. Indeed, the process would play the part of the primary conversion process from which liquid products would accrue – these products would then pass to a secondary upgrading (hydrotreating) process to yield a synthetic crude oil.

5.4.15 MAKfining Process The process uses a multiple catalyst system in multi-bed reactors that include quench and redistribution system internals (Hunter et al., 2010; Speight, 2014). In the process, the feedstock and recycle gas and preheated and brought into contact with the catalyst in a downflow fixed-bed reactor. The reactor effluent is sent to high- and low-temperature separators. Product recovery is a stripper/fractionator arrangement. Typical operating conditions in the reactors are 370°C–425°C (700°F–800°F) (single-pass) and 370°C–425°C (700°F–800°F) (recycle) with pressures of 1,000– 2,000 psi (single-pass) and 1,500–3,000 psi (recycle). Product yields depend upon the extent of the conversion.

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5.4.16 Microcat-FC Process The Microcat-FC process (also referred to as the M-Coke process) is a catalytic ebullated-bed hydroconversion process that is similar to Residfining and which operates at relatively moderate pressures and temperatures (Bauman et al., 1993). The catalyst particles, containing a metal sulfide in a carbonaceous matrix formed within the process, are uniformly dispersed throughout the feed. Because of their ultra-small size (10 −4-inch diameter), there are typically several orders of magnitude more of these micro-catalyst particles per cubic centimeter of oil than is possible in other types of hydroconversion reactors using conventional catalyst particles. This results in smaller distances between particles and less time for a reactant molecule or intermediate to find an active catalyst site. Because of their physical structure, micro-catalysts suffer none of the pore-plugging problems that plague conventional catalysts. In the process, the viscous feedstock, the micro-catalyst, and hydrogen are fed to the hydroconversion reactor, and the reactor effluent is sent to a flash separation zone to recover hydrogen, gases, and liquid products, including naphtha, distillate, and gas oil (Speight, 2014, 2017). The residuum from the flash step is then fed to a vacuum distillation tower to obtain a 565°C− (1,050°F−) product oil and a 565°C+ (1,050°F+) bottoms fraction that contains unconverted feed, micro-catalyst, and essentially all of the feed metals.

5.4.17 Mild Hydrocracking Process The mild hydrocracking process uses operating conditions similar to those of a VGO desulfurizer to convert a VGO to significant yields of lighter products. Consequently the flow scheme for a mild hydrocracking unit is virtually identical to that of a VGO desulfurizer. Liquid is preheated against stripper bottoms and in a feed heater before steam-stripping in a stabilizer tower. The process flow scheme is identical to that described above up to the reactor outlet. This arrangement reduces the stabilizer feed preheat duty and the effluent cooling duty by routing hot liquid direct to the stripper tower. For hydrocracking, in order to obtain satisfactory run lengths (approximately 11 months), reduction in feed rate or addition of an extra reactor may be necessary.

5.4.18 MRH Process The MRH process is a hydrocracking process designed to upgrade viscous feedstocks containing large amount of metals and asphaltene, such as vacuum residua and bitumen, and to produce mainly middle distillates (Sue, 1989; RAROP, 1991, p. 65; Khan and Patmore, 1998; Speight, 2014, 2017). In the process, a slurry consisting of viscous oil feedstock and fine powder catalyst is preheated in a furnace and fed into the reactor vessel. Hydrogen is introduced from the bottom of the reactor and flows upward through the reaction mixture, maintaining the catalyst suspension in the reaction mixture. Cracking, desulfurization, and demetallization reactions are taken place via thermal and catalytic reactions. In the upper section of the reactor, vapor is disengaged from the slurry, and hydrogen and other gases are removed in a high-pressure separator. The liquid condensed from the overhead vapor is distilled and then flows out to the secondary treatment facilities. From the lower section of the reactor, a bottom slurry oil that contains catalyst, uncracked residuum, and a small amount of VGO fraction are withdrawn. VGO is recovered in the slurry separation section, and the remaining catalyst and coke are fed to the catalyst regenerator. Product distribution focuses on middle distillates with the process focused as a viscous feedstock processing unit and can be inserted into refinery operations downstream from the vacuum distillation unit.

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5.4.19 RCD Unibon Process The RCD Unibon process (BOC process) is a process to upgrade vacuum residua (RAROP, 1991, p. 67; Khan and Patmore, 1998; Speight, 2014, 2017). There are several possible flow scheme variations involving for the process. It can operate as an independent unit or be used in conjunction with a thermal conversion unit. In this configuration, hydrogen and a vacuum residuum are introduced separately to the heater, and mixed at the entrance to the reactor. To avoid thermal reactions and premature coking of the catalyst, temperatures are carefully controlled and conversion is limited to approximately 70% of the total projected conversion. The effluent from the reactor is directed to the hot separator. The overhead vapor phase is cooled, condensed, and the separated hydrogen is recycled to the reactor. Liquid product goes to the thermal conversion heater where the remaining conversion of nonvolatile materials occurs. The heater effluent is flashed and the overhead vapors are cooled, condensed, and routed to the cold flash drum. The bottoms liquid stream then goes to the vacuum column where the gas oils are recovered for further processing, and the residuals are blended into the viscous fuel oil pool.

5.4.20 Residfining Process Residfining is a catalytic fixed-bed process for the desulfurization and demetallization of atmospheric and vacuum residua (RAROP, 1991, p. 69; Khan and Patmore, 1998; Speight, 2014, 2017). The process can also be used to pretreat viscous feedstocks to suitably low contaminant levels prior to catalytic cracking. In the process, liquid feedstock to the unit is filtered, pumped to pressure, preheated, and combined with treat gas prior to entering the reactors. Provisions are employed to periodically remove the guard while keeping the main reactors on-line. A train of separators is employed to separate the gas and liquid products after which the recycle gas is scrubbed to remove ammonia (NH3) and hydrogen sulfide (H2S). Residfining is an option that can be used to reduce the sulfur, to reduce metals and coke-forming precursors and/or to accomplish some conversion to lower-boiling products as a feed pretreat step ahead of a fluid catalytic cracking unit. There is also a hydrocracking option where substantial conversion of the resid occurs.

5.4.21 Residue Hydroconversion Process In this process, the feedstock can be desalted atmospheric or vacuum residue as well as other viscous feedstocks (Chapter 1) (Speight, 2014, 2017). The reactors are of multi-bed design with inter-bed cooling and the multi-catalyst system can be tailored according to the nature of the feedstock and the target conversion.

5.4.22 Shell Residual Oil Process The Shell residual oil HDS process was originally designed to improve the quality of residual oils by removing sulfur, metals, and asphaltene constituents. The process is suitable for a wide range of the heavier feedstocks, irrespective of the composition and origin, and even includes those feedstocks that are particularly high in metals and asphaltene constituents. Sulfur removal is excellent and substantial reductions in the vanadium content and asphaltene constituents also occur. In addition, a marked increase occurs in the API gravity, and the viscosity is reduced considerably.

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A bunker reactor provides extra process flexibility (especially with reference to processing viscous feedstocks that typically have a high content of metal-containing constituents) if it is used upstream from the desulfurization reactor. A catalyst with a capacity for metals is employed in the bunker reactor to protect the desulfurization catalyst from poisoning by the metals.

5.4.23 Tervahl-H Process In this process, the gas and liquid product from the soaking drum effluent are mixed with recycle hydrogen and separated in the hot separator where the gas is cooled passed through a separator and recycled to the heater and soaking drum effluent. The liquids from the hot and cold separator are sent to the stabilizer section where purge gas and the liquid product are separated. In the related Tervahl-T process, the feedstock is heated to the desired temperature using the coil heater and heat recovered in the stabilization section and held for a specified residence time in the soaking drum.

5.4.24  Unicracking Process Unicracking is a fixed-bed catalytic process that employs a high-activity catalyst with a high tolerance for sulfur and nitrogen compounds and can be regenerated. The design is based upon a singlestage or a two-stage system with provisions to recycle to extinction (RAROP, 1991, p. 79; Khan and Patmore, 1998; Ackelson, 2004). In the process, a two-stage reactor system receives untreated feed, makeup hydrogen, and a recycle gas at the first stage, in which naphtha conversion may be as high as 60% v/v. The reactor effluent is separated to recycle gas, liquid product, and unconverted oil. The second-stage oil may be either once-through or recycle cracking; feed to the second sage is a mixture of unconverted first-stage oil and second-stage recycle. The feedstock and hydrogen-rich recycle gas are preheated, mixed, and introduced into a guard reactor that contains a relatively small quantity of the catalyst. The guard chamber removes particulate matter and residual salt from the feed. The effluent from the guard chamber flows down through the main reactor, where it contacts one or more catalysts designed for removal of metals and sulfur. The catalysts, which induce desulfurization, denitrogenation, and hydrocracking, are based upon both amorphous and molecular-sieve-containing supports. The product from the reactor is cooled, separated from hydrogen-rich recycle gas, and either stripped to meet fuel oil flash point specifications, or fractionated to produce distillate fuels, upgraded VGO, and upgraded vacuum residuum. Recycle gas, after hydrogen sulfide removal, is combined with makeup gas and returned to the guard chamber and main reactors. The most commonly implemented configuration is a single-stage Unicracking design, where the fresh feed and recycle oil are converted in the same reaction stage. This configuration simplifies the overall unit design by reducing the quantity of equipment in high-pressure service and keeping highpressure equipment in a single train. The two-stage design has a separation system in each reaction stage. Two-stage flow schemes can be employed in specific situations such as the two-stage Unicracking process which can be a separate hydrotreating stage or a two-stage hydrocracking process. In the separate hydrotreating flow scheme, the first stage provides hydrotreating of the feedstock, while in the two-stage hydrocracking process, the first stage provides hydrotreating of the feedstock as well as partial conversion of the feed. The second stage of the two-stage design provides the remaining conversion of recycle oil so that overall high conversion from the unit is achieved. In addition, further advances in the two-stage Unicracking process design have included several innovations in each reaction section of the design. The process efficiency is due to the efficient distribution of the feedstock and hydrogen that occurs in the reactor where a proprietary liquid distribution system is employed. In addition, the process catalyst (also proprietary) was designed for the desulfurization of residua and is not merely an upgraded gas oil hydrotreating catalyst as often occurs in various processes. It is a

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cobalt-molybdena-alumina catalyst with a controlled pore structure that permits a high degree of desulfurization and, at the same time, minimizes any coking tendencies. The process uses base-metal or noble-metal hydrogenation-activity promoters impregnated on combinations of zeolites and amorphous-aluminosilicates for cracking activity. The specific metals chosen and the proportions of the metals, zeolite, and non-zeolite aluminosilicates are optimized for the feedstock and desired product balance. This is effective in the production of clean fuels, especially for cases where a partial conversion Unicracking unit and a fluid catalytic cracking unit are integrated. The Unicracking process converts feedstocks into lower molecular weight products that are more saturated than the feed. Feedstocks include atmospheric gas oil, VGO, fluid catalytic cracking/resid catalytic cracking cycle oil, coker gas oil, deasphalted oil, and naphtha. Hydrocracking catalysts promote sulfur and nitrogen removal, aromatic saturation, and molecular weight reduction. All of these reactions consume hydrogen and as a result, the volume of recovered liquid product normally exceeds the feedstock. Many units are operated to make naphtha (for petrochemical or motor-fuel use) as a primary product. Unicracking catalysts are designed to function in the presence of hydrogen sulfide (H2S) and ammonia (NH3). This gives rise to an important difference between Unicracking and other hydrocracking processes: the availability of a single-stage design. In a single-stage unit, the absence of a stripper between treating and cracking reactors reduces investment costs by making use of a common recycle gas system. Process objectives determine catalyst selection for a specific unit. Product from the reactor section is condensed, separated from hydrogen-rich gas, and fractionated into desired products. Unconverted oil is recycled or used as (1) blend stock for the production of lubricating oil, (2) fluid catalytic cracking feedstock, or (3) feedstock for the ethylene cracking unit (Parihar et al., 2012). In addition, mild hydrocracking technology enables optimization of hydroprocessing refinery assets to produce high-quality clean fuels at lower costs and more attractive return on investments than alternative technologies. The advanced partial conversion unicracking process (APCU process) is a recent advancement in the area of ULSD production and feedstock pretreatment for catalytic cracking units. At low conversions (20%–50%) and moderate pressure, the APCU technology provides an improvement in product quality compared to traditional mild hydrocracking. In the process, high-sulfur feeds such as VGO and heavy cycle gas oil are mixed with a heated hydrogen-rich recycle gas stream and passed over consecutive beds of high-activity pretreat catalyst and distillate selective unicracking catalyst. This combination of catalysts removes refractory sulfur and nitrogen contaminants, saturates polynuclear aromatic compounds, and converts a portion of the feed to ULSD fuel. The hydrocracked products and desulfurized feedstock are used as feedstock for a fluid catalytic cracking unit and separated at reactor pressure in an enhanced hot separator. The overhead products for the separator are immediately hydrogenated in the integrated finishing reactor. As pretreatment severity is increased, conversion increased in the fluid catalytic cracker and both naphtha and alkylate octane-barrel output per barrel of cat cracker feedstock increases. APCU units can be customized to achieve maximum octane-barrel production in the cat cracker. Another development in the unicracking family is the HyCycle Unicracking technology that is designed to maximize diesel production for full conversion applications and is an optimized process scheme intended for obtaining maximum yield of high-quality diesel fuel. The process is characterized by lowered pressure, higher space velocity in comparison with conventional units. Due to minimizing potential secondary cracking reactions, less hydrogen per barrel of feedstock is required.

5.4.25  Uniflex Process Uniflex process is an evolved version with significant changes (by UOP) in the former CANMET process which used an empty vessel hydrocracking reactor in which the feedstock is processed in the presence of an iron-sulfide-based catalyst deposited on particles of coal.

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The process is a high-conversion slurry hydrocracking technology that contains elements of a commercially proven slurry reaction system and the UOP Unicracking technology and Unionfining technology. The Uniflex Process can achieve non-distillable conversion levels in excess of 90% w/w with distillate yield in excess of 50% v/v and holds yield and economic advantages over conventional residue upgrading technologies, and other applications of the technology (Gillis et al., 2010). Because the desulfurization activity of iron is very low, molybdenum can be added at a level of tens of ppm in the form of molybdenum naphthenate. The reaction products were fractionated and sent to the hydrotreatment unit, while the unconverted residue (5 to 10% v/v of the feedstock) can be burned or gasified. The process uses an empty vessel hydrocracking reactor in which the feedstock is processed in the presence of an iron-sulfide-based catalyst deposited on particles of coal. Because the desulfurization activity of iron is very low, molybdenum can be added at a level of tens of ppm in the form of molybdenum naphthenate. The reaction products are fractionated and sent to the hydrotreatment unit (Unifining and Unicracking), while the unconverted residue (5%–10% v/v of the feedstock) can be burned or gasified. The flow scheme for the Uniflex process is similar to that of a conventional UOP Unicracking process unit – liquid feedstock and recycle gas are heated to temperature in separate heaters, with a small portion of the recycle gas stream and the required amount of catalyst being routed through the oil heater (Gillis et al., 2010). The outlet streams from both heaters are fed to the bottom of the slurry reactor. The reactor effluent is quenched at the reactor outlet to terminate reactions and then flows to a series of separators with gas being recycled back to the reactor. Liquids flow to the unit’s fractionation section for recovery of light ends, naphtha, diesel, VGOs, and pitch (cracked residuum). Heavy VGO is partially recycled to the reactor for further reaction and conversion. The heart of the Uniflex Process is the upflow reactor that operates at moderate temperature (440°C–470°C; 815°F–880°F) and 2,000 psi. The feedstock distributor, in combination with optimized process variables, promotes intense back-mixing (which provides near-isothermal reactor conditions) in the reactor without the need for reactor internals or liquid recycle ebullating pumps. The back-mixing allows the reactor to operate at the higher temperatures required to maximize vacuum residue conversion. The majority of the products vaporize and quickly leave the reactor (thereby minimizing the potential for secondary cracking reactions), while the residence time of the higher boiling constituents of the feedstock is maximized. The process employs a proprietary, dual-function nano-sized solid catalyst which is blended with the feed to maximize conversion of high-molecular-weight constituents and inhibit coke formation. Specific catalyst requirements depend on feedstock quality and the required severity of operation. The primary function of the catalysts is to effect mild hydrogenation activity for the stabilization of cracked products while also limiting the saturation of aromatic rings. Because of the hydrogenation function, the catalyst also decouples the relationship between conversion and the propensity for carbon residue formation of the feedstock. In terms of slurry hydrocracking processes, metals that have been screened as potential slurry catalysts and include transition metal-based catalysts derived from vanadium, tungsten, chromium, and iron. Homogeneous-catalysts-based hydrocracking technology has been developed for upgrading of heavy crude and tar sand bitumen (Kriz and Ternan, 1994; Speight, 2014). In this process, the hydrocracking catalyst is homogeneously dispersed as a colloid with particles similar in size to that of asphaltene molecule, which results in high conversion of asphaltene constituents (Bhattacharyya and Mezza, 2010; Bhattacharyya et al., 2011).

5.4.26  Veba Combi-Cracking Process The Veba Combi-Cracking process is a thermal hydrocracking process for converting residua and other viscous feedstocks (RAROP, 1991, p. 81; Speight, 2014, 2017). The process is based on the Bergius–Pier technology that was used for coal hydrogenation in Germany up to 1945. The viscous

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feedstock is hydrogenated (hydrocracked) using a commercial catalyst and liquid-phase hydrogenation reactor operating at 440°C–485°C (825°F–905°F) and 2,175–4,350 psi. The product obtained from the reactor is fed into the hot separator operating at temperatures slightly below the reactor temperature. The liquid and solid materials are fed into a vacuum distillation column; the gaseous products are fed into a gas-phase hydrogenation reactor operating at an identical pressure. This high-temperature, high-pressure coupling of the reactor products with further hydrogenation provides a specific process economics. Substantial conversion of asphaltene constituents, desulfurization and denitrogenation take place at high levels of residue conversion. The top product from the hit separator along with any recovered distillates and straight-run distillates enters the gas-phase hydrogenation reactor. This reactor operates at the same pressure as the liquid-phase hydrogenation reactor and contains a fixed bed of commercial hydrotreating catalyst. The operation temperature (340°C–420°C, 645°F–790°F) is controlled by a hydrogen quench. The system operates in a trickle flow mode, which may not be efficient for some viscous feedstocks. The separation of the synthetic crude from associated gases is performed in a cold separator system. The synthetic crude may be sent to stabilization and fractionation unit as required. The gases are sent to a lean oil scrubbing system for contaminant removal and are recycled. Additional low-value refinery streams such as gas oil, deasphalted oil, or catalytic cracker cycle oil may also be directly added to the hydrotreating stage.

5.5  OTHER OPTIONS AND THE FUTURE The heavy residue hydroconversion (HRH) process is a new nano-catalytic technology for upgrading viscous feedstocks, including residua (Khadzhiev et al., 2009; Zarkesh et al., 2011). In the process, the viscous feedstock is introduced to a separator to separate any lower-boiling constituents after which the non-volatile material is sent to the reactor where mixing with hydrogen and catalyst occurs. The catalyst precursors react in situ with hydrogen sulfide in the reactor and produces the nano-catalyst. The reacted feedstock then passes into the distillation unit and un-reacted portion recycles to the beginning of the process. A defined portion of this residue goes to catalyst regeneration unit. The nature of process is such that it can tolerate high amount of heavy metals, asphaltene constituents, and sulfur with an overall feedstock conversion on the order of 95% v/v. The main advantages of the process are: (1) high conversion, (2) high product volume yield, (3) 60%–80% sulfur removal, (4) the catalyst regenerates in the HRH unit, and (5) heavy metal converts to the metal oxides as a by-product. The viscous feedstocks, which require more energy-intensive processing than conventional crude oil, will continue to be a growing portion of refinery feedstocks. However, like many refinery processes, the hydrocracking process can encounter problems from such feedstocks that are associated with the amount of complex, higher boiling constituents that may require pretreatment (Speight and Moschopedis, 1979; Speight, 2000; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). Processing these feedstocks is not merely a matter of applying know-how derived from refining conventional crude oils but requires knowledge of composition and properties (Chapter 1) (Speight, 2001, 2015, 2017). Attempts to modify the process have had some measure of success materials are not only complex in terms of the carbon number and boiling point ranges but also because a large part of this envelope falls into a range of model compounds where very little is known about the properties. Utilizing different types of catalysts can modify the product slate produced and, in addition, reactor design and the number of processing stages play a role in this flexibility. Furthermore, it is apparent that the conversion of the viscous feedstocks requires new lines of thought to develop suitable processing scenarios. Indeed, the use of thermal process (carbon rejection processes) and hydrothermal processes (hydrogen addition processes), which were inherent in the refineries designed to process lighter feedstocks, has been a particular cause for concern. This has brought about, and will continue to bring about in the refinery of the future, the evolution of

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processing schemes that accommodate the heavier feedstocks (Khan and Patmore, 1998; Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). Furthermore, biomass gasification and Fischer–Tropsch synthesis conversion are very likely to be a part of the future refineries as part of the next-generation biofuels developments; refiners will need to monitor closely the latest refinery-related advances as well as future directions in biomass processing. In particular, the response of the refining industry to opportunities for processing viscous feedstocks and resids, mandated biofuels usage, and requirements to comply with carbon dioxide will need to be addressed. Furthermore, gasification with carbon capture and the use of biomass as feedstock should help refiners meet emissions reduction requirements for carbon dioxide. In summary, trends in quality of crude feedstocks has shown a steady decline over the past three decades, and is reflected by declining API gravity and increasing sulfur content requiring changes in hydrocracking operations (Butler et al., 2009). Furthermore, understanding the fundamental crude oil chemistry of the viscous feedstocks and residua is not always sufficiently adequate to predict processing behavior (Niccum and Northup, 2006). In fact, it is only by comprehensively considering related factors such as (1) the properties of feedstock, (2) catalyst performance, (3) product requirements, (4) chemical kinetics, and (5) operating conditions and cycle length that optimal results can be achieved. Therefore, further improvement of the hydrocracking process and catalysts, which can tolerate a high content of impurities and metals, are two major challenges for the refineries (Putek et al., 2008). Catalyst activity, selectivity, particle size and shape, pore size and distribution, as well as the type of the reactor, have to be optimized according to the properties of the viscous feedstocks and the desired conversion levels. Furthermore, processes that offer higher conversion and improved product quality for downstream processing (such as the UOP Uniflex process, formerly the CANMET process) will be in great demand (Gillis et al., 2009, 2010). Integration of such processes with existing coking capacity offer many unique benefits (Gillis et al., 2009, 2010). The effective use of existing assets requires both individual process depth as well as a breadth of refinery knowledge and expertise. This will require (1) an audit of current refinery operations – product blending, unit yields, overall energy, and HU; (2) development of future refinery configuration, focusing on capacity requirements, product slate, and operating efficiency; (3) development of investment alternatives; (4) economic evaluation and project selection; and (5) rapid project implementation.

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Putek, S., Januszewski, D., and Cavallo, E. 2008. Upgrade Hydrocracked Resid through Integrated Hydrotreating. Hydrocarbon Processing, 84(9): 83–92. Rana, M.S., Sámano, V., Ancheyta, J., and Diaz, J.A.I. 2007. A Review of Recent Advances on Process Technologies for Upgrading of Heavy Oils and Residua. Fuel, 86: 1216–1231. RAROP, 1991. In: Heavy Oil Processing Handbook, Y. Kamiya (Editor). Research Association for Residual Oil Processing, Agency of Natural Resources and Energy, Ministry of International Trade and Industry, Tokyo, Japan. Rashid, K. 2007. Optimize Your Hydrocracking Operations. Hydrocarbon Processing, 86(2): 55–63. Scherzer, J., and Gruia, A.J. 1996. Hydrocracking Science and Technology. Marcel Dekker Inc., New York. Speight, J.G. 1990. Tar Sands. In: Fuel Science and Technology Handbook. J.G. Speight (Editor). Marcel Dekker Inc., New York. Speight, J.G. 2000. The Desulfurization of Heavy Oils and Residua. 2nd Edition. Marcel Dekker Inc., New York. Speight, J.G. 2001. Handbook of Petroleum Analysis. John Wiley & Sons Inc., Hoboken, New Jersey. Speight, J.G. 2008. Synthetic Fuels Handbook: Properties, Processes, and Performance. McGraw-Hill, New York. Speight, J.G. 2011a. The Refinery of the Future. Gulf Professional Publishing, Elsevier, Oxford, United Kingdom. Speight, J.G. (Editor). 2011b. Biofuels Handbook. Royal Society of Chemistry, London, United Kingdom. Speight, J.G. 2014. The Chemistry and Technology of Petroleum 5th Edition. CRC Press, Taylor & Francis Group, Boca Raton, Florida. Speight, J.G. 2015. Handbook of Petroleum Product Analysis 2nd Edition. John Wiley & Sons Inc., Hoboken, New Jersey. Speight, J.G. 2017. Handbook of Petroleum Refining. CRC Press, Taylor & Francis Group, Boca Raton, Florida. Speight, J.G., and Moschopedis, S.E. 1979. The Production of Low-Sulfur Liquids and Coke from Athabasca Bitumen. Fuel Processing Technology, 2: 295. Stratiev, D., and Petkov, K. 2009. Residue Upgrading: Challenges and Perspectives. Hydrocarbon Processing, 88(9): 93–96. Sue, H. 1989. The MRH Hydrocracking Process. Proceedings. 4th UNITAR/UNDP Conference on Heavy Oil and Tar Sands. Edmonton, Alberta, Canada, Vol. 5, p. 117. Vauk, D., Di Zanno, P., Neri, B., Allevi, C., Visconti, A., and Rosanio, L. 2008. What Are Possible Hydrogen Sources for Refinery Expansion? Hydrocarbon Processing, 87(2): 69–76. Wade, R., Vislocky, J., Maesen, T., and Torchia, D. 2009. Hydrocracking Catalyst and Processing Developments. Petroleum Technology Quarterly, 14: 81–86. Wen, S.B., Zhao, Y.J., Liu, Y.J., and Hu, S.B. 2007. A Study on Catalytic Aquathermolysis of Heavy Crude Oil during Steam Stimulation. Paper No. 106180-MS, 2007. Proceedings. International Symposium on Oilfield Chemistry, Houston, Texas. February 28-March 2. Zarkesh, J., Ghaedian, M., Hashemi, I., Khademsamimi, A., and Kadzhiev, S. 2011. Heavy Refinery Schemes based on New Nano Catalytic HRH Technology. Proceedings. 2nd International Conference on Chemical Engineering and Applications. International Proceedings of Chemical, Biological and Environmental Engineering (IPCBEE). IACSIT Press, Singapore, Vol. 23, pp. 66–70. Zhang, S., Liu, D., Deng, W., and Que, G. 2007. A Review of Slurry-Phase Hydrocracking Heavy Oil Technology. Energy & Fuels, 21(6): 3057–3062.

6

Hydrogen Production

6.1 INTRODUCTION The use of hydrogen during refining in hydrotreating processes, such as desulfurization (Chapter 4), and hydroconversion processes, such as hydrocracking (Chapter 5), is an acknowledged part of the modern refinery (Scherzer and Gruia, 1996; Dolbear, 1998; Parkash, 2003; Gary et al., 2007; Speight, 2014). Also, hydrogen is also being considered for use as an energy carrier for stationary power and transportation markets. Major current uses of the commercially produced hydrogen include oil refining (hydrotreating crude oil as part of the refining process to improve the hydrogento-carbon ratio of the fuel), food production (e.g., hydrogenation), treating metals, and producing ammonia for fertilizer and other industrial uses. In addition to the conventional hydrogen production methods of steam-methane reforming (SMR) and grid-powered electrolysis (Chapter 1), a new suite of renewable production options is emerging (Table 6.1). These options also include using renewable power directly for electrolysis, various biogas production options using gasification or pyrolysis processes or biomass fermentation with microorganisms, and newly developed photo-electrochemical and thermochemical processes including using microbial electrolysis cells as well as tailored molecules that can facilitate the splitting of water molecules into hydrogen and oxygen with lower energy requirements than conventional electrolysis. In some cases, the hydrogen recycle gas may contain up to 40% v/v of other gases (usually hydrocarbon derivatives) and the catalyst life in the hydrotreater is a strong function of hydrogen partial pressure. Furthermore, the optimum hydrogen purity at the reactor inlet extends the catalyst life if the desulfurization occurs at a lower operating temperature, thereby reducing carbon formation and deposition. Typical purity increases resulting from hydrogen purification equipment and/ or increased hydrogen sulfide removal as well as tuning hydrogen circulation and purge rates, may extend catalyst life on the order of 25%. TABLE 6.1 Options for the Production of Hydrogen in the Refinery Source Natural gas

Process Steam-methane reforming Hydrocarbon reforming Partial oxidation

Crude oil

Steam-methane reforming Naphtha reforming Partial oxidation of resids

Biomass Methanol

Partial oxidation Methanol dehydrogenation Steam–methanol reforming

Coal Water

Partial oxidation Electrolysis Thermochemical methods Nuclear methods

DOI: 10.1201/9781003185314-6

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In fact, the typical refinery runs at a hydrogen deficit and a critical issue facing refiners is the influx of heavier feedstocks into refineries and the need to process the refinery feedstock into refined transportation fuels under an environment of increasingly more stringent clean fuel regulations and the acceptance increasingly viscous high-sulfur feedstocks by refineries. Thus, the need for deeper hydrotreating, because of the environmental mandates for lower sulfur levels in products is driving the demand for more hydrogen. The major source of hydrogen in the refinery has typically been the off-gas from catalytic reforming units. However, as the entry of the high-sulfur feedstocks into refineries increases, additional sources of hydrogen are needed and most refiners have either built an on-site hydrogen plant or have a hydrogen plant on-site which is operated by one of the major commercial gas suppliers. Moreover, as hydrogen use has become more widespread in refineries, hydrogen production has moved from the status of a high-tech specialty operation to an integral feature of most refineries (Raissi, 2001; Vauk et al., 2008; Liu et al., 2010). This has been made necessary by the increase in hydrotreating and hydrocracking, including the treatment of progressively heavier feedstocks. In fact, the continued increase in hydrogen demand over the decades since the end of World War II is a result of the conversion of crude oil to match changes in product slate and the supply of viscous high-sulfur feedstocks oil, and in order to make lower boiling, cleaner, and more salable products. There are also many reasons other than product quality for using hydrogen in processes adding to the need to add hydrogen at relevant stages of the refining process and, most importantly, according to the availability of hydrogen (Bezler, 2003; Miller and Penner, 2003; Ranke and Schödel, 2003). With the increasing need for clean fuels, the production of hydrogen for refining purposes requires a major effort by refiners. In fact, the trend to increase the number of hydrogenation (hydrocracking and/or hydrotreating) processes in refineries coupled with the need to process the heavier oils, which require substantial quantities of hydrogen for upgrading because of the increased use of hydrogen in hydrocracking processes, has resulted in vastly increased demands for this gas. The hydrogen demands can be estimated to a very rough approximation using API gravity and the extent of the reaction, particularly the hydrodesulfurization reaction (Speight, 2000; Speight and Ozum, 2002). But accurate estimation requires equivalent process parameters and a thorough understanding of the nature of ach process. Thus, as hydrogen production grows, a better understanding of the capabilities and requirements of a hydrogen plant becomes ever more important to overall refinery operations as a means of making the best use of hydrogen supplies in the refinery. The chemical nature of the crude oil used as the refinery feedstock has always played the major role in determining the hydrogen requirements of that refinery. For example, the lighter, more paraffinic crude oils will require somewhat less hydrogen for upgrading to, say, a gasoline product than a heavier more asphaltic crude oil (Speight, 2000). It follows that the hydrodesulfurization of viscous feedstocks (including crude oil residua) which, by definition, is a hydrogen-dependent process and requires substantial amounts of hydrogen as part of the processing requirements. In general, considerable variation exists from one refinery to another in the balance between hydrogen produced and hydrogen consumed in the refining operations. However, what is more pertinent to the present text is the excessive amounts of hydrogen that are required for hydroprocessing operations, whether these be hydrocracking or the somewhat milder hydrotreating processes. For effective hydroprocessing, a substantial hydrogen partial pressure must be maintained in the reactor and, in order to meet this requirement, an excess of hydrogen above that actually consumed by the process must be fed to the reactor. Part of the hydrogen requirement is met by recycling a stream of hydrogen-rich gas. However, the need still remains to generate hydrogen as makeup material to accommodate the process consumption of 500–3,000 scf/bbl depending upon whether the viscous feedstock is being subjected to a predominantly hydrotreating process (i.e., a hydrodesulfurization process) or to a predominantly hydrocracking process. In some refineries, the hydrogen needs can be satisfied by hydrogen recovery from catalytic reformer product gases, but other external sources are required. However, for the most part, many refineries now require on-site hydrogen production facilities to supply the gas for their own

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processes. Most of this non-reformer hydrogen is manufactured either by SMR or by oxidation processes. However, other processes, such as ammonia dissociation or the steam–methanol reaction which consists of two sequential reactions: (1) methanol dehydrogenation (CH3OH = CO + 2 H2) and (2) the water gas shift (WGS) reaction may also be used as sources of hydrogen: Ammonia dissociation:

2NH 3 → N 2 + 3H 2

Methanol dehydrogenation:

CH 3OH → CO + 2H 2

WGS reaction:

CO + H 2O → CO 2 + H 2

Also, the electrolysis of water can be used to produce high-purity hydrogen. For example, in a polymer electrolyte membrane (PEM) electrolyzer, the electrolyte is a solid specialty plastic material. Water reacts at the anode to form oxygen and positively charged hydrogen ions (protons). The electrons flow through an external circuit and the hydrogen ions selectively move across the polymer electrolyte membrane to the cathode. At the cathode, hydrogen ions combine with electrons from the external circuit to form hydrogen gas. Anode reaction:

2H 2O → O 2 + 4H + + 4e −

Cathode reaction:

4H + + 4e − → 2H 2

An early use of hydrogen in refineries was to hydrotreat naphtha as a feedstock pretreatment (of the naphtha) for catalytic reforming (which in turn produced hydrogen as a by-product). As environmental regulations tightened, the technology matured and heavier streams were hydrotreated. Thus, in the early refineries, the hydrogen for hydroprocesses was provided as a result of catalytic reforming processes in which dehydrogenation is a major chemical reaction and, as a consequence, hydrogen gas is produced. The low-boiling gases from the catalytic reformer contained a high ratio of hydrogen to methane so the stream is freed from ethane and/or propane to get a high concentration of hydrogen in the stream. In the process, the hydrogen is recycled though the reactors where the reforming of the feedstock takes place to provide the atmosphere necessary for the chemical reactions and also prevents the carbon from being deposited on the catalyst, thus extending its operating life of the catalyst. An excess of hydrogen above whatever is consumed in the process is produced, and, as a result, catalytic reforming processes are unique in that they are the only crude oil refinery processes to produce hydrogen as a by-product (Parkash, 2003; Gary et al., 2007; Speight, 2014, Hsu and Robinson, 2017; Speight, 2017). However, as refineries and refinery feedstocks evolved during the last four decades, the demand for hydrogen has increased and reforming processes are no longer capable of providing the quantities of hydrogen necessary for feedstock hydrogenation. Within the refinery, other processes are used as sources of hydrogen. Thus, the recovery of hydrogen from the by-products of the coking units, visbreaker units, and catalytic cracking units is also practiced in some refineries.

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In coking units and visbreaker units, viscous feedstocks are converted to gases, low-boiling distillates, middle distillates, and coke and, depending on the process parameters, hydrogen is present in a wide range of concentrations. Since coking processes need gas for heating purposes, adsorption processes are best suited to recover the hydrogen because they feature a very clean hydrogen product and an off-gas suitable as fuel. Catalytic cracking is the most important process step for the production of light products from gas oil and increasingly from vacuum gas oil and viscous feedstocks. In catalytic cracking, the molecular mass of the main fraction of the feed is lowered, while another part is converted to coke that is deposited on the hot catalyst. The catalyst is regenerated in one or two stages by burning the coke off with air that also provides the energy for the endothermic cracking process. In the process, paraffins and naphthenes are cracked to olefins and to alkanes with shorter chain length, monoaromatic compounds are dealkylated without ring cleavage, and di-aromatics and poly-aromatics are dealkylated and converted to coke. Hydrogen is formed in the last type of reaction, whereas the first two reactions produce light hydrocarbons and therefore require hydrogen. Thus, a catalytic cracker can be operated in such a manner that enough hydrogen for subsequent processes is formed. In reforming processes, naphtha fractions are reformed to improve the quality of gasoline (Speight, 2000, 2014, 2017). The dehydrogenation of naphthene derivatives to aromatic derivatives are the most important reactions occurring during this process. The dehydrogenation reaction is endothermic and is favored by low pressures and the reaction temperature lies in the range of 300°C–450°C (570°F–840°F). The reaction is performed on platinum catalysts, with other metals, e.g., rhenium, as promoters. Hydrogen is generated in a refinery by the catalytic reforming process, but there may not always be the need to have a catalytic reformer as part of the refinery sequence. Also, the hydrogen produced by the reformer typically is well below the amount of hydrogen required for hydroprocessing purposes. Consequently, an additional source (or sources) of hydrogen is necessary to meet the daily hydrogen requirements of any process where the heavier feedstocks are involved. There has been increased demand for hydrogen in refineries because of the trend to increase the number of hydrogenation (hydrocracking and/or hydrotreating) processes in refineries coupled with the need to process the viscous feedstocks, which require substantial quantities of hydrogen for upgrading (Dolbear, 1998; Parkash, 2003; Gary et al., 2007; Speight, 2014, Hsu and Robinson, 2017; Speight, 2017). Hydrogen has historically been produced during catalytic reforming processes as a by-product of the production of the aromatic compounds used in gasoline and solvents. As reforming processes changed from fixed-bed to cyclic to continuous regeneration, process pressures have dropped and hydrogen production per barrel of reformate has tended to increase. However, hydrogen production as a by-product is not always adequate to the needs of the refinery and other processes are necessary. Thus, hydrogen production by steam reforming or by partial oxidation of residua has also been used, particularly where viscous feedstocks are available. Steam reforming is the dominant method for hydrogen production and is usually combined with pressure-swing adsorption (PSA) to purify the hydrogen to greater than 99% by volume (Bandermann and Harder, 1982). The gasification of residua and coke to produce hydrogen and/or power may become an attractive option for refiners (Dickenson et al., 1997; Gross and Wolff, 2000). The premise that the gasification section of a refinery will be the garbage can for deasphalter residues, high-sulfur coke, as well as other refinery wastes is worthy of consideration. Several other processes are available for the production of the additional hydrogen that is necessary for the various hydroprocessing sequences for viscous feedstocks, and it is the purpose of this chapter to present a general description of these processes. In general, most of the external hydrogen is manufactured by SMR or by oxidation processes. Other processes such as ammonia dissociation, steam–methanol interaction, or electrolysis are also available for hydrogen production, but economic factors and feedstock availability assist in the choice between processing alternatives.

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The processes described in this chapter are those gasification processes that are often referred to the garbage disposal units of the refinery. Hydrogen is produced for use in other parts of the refinery as well as for energy, and it is often produced from process by-products that may not be of any use elsewhere. Such by-products might be the highly aromatic, heteroatom, and metal containing reject from a deasphalting unit or from a mild hydrocracking process. However attractive this may seem, there will be the need to incorporate a gas cleaning operation to remove any environmentally objectionable components from the hydrogen gas.

6.2  PROCESSES REQUIRING HYDROGEN The use of hydrogen in refining processes is perhaps the single most significant advance in refining technology during the 20th century and is now an inclusion in most refineries (Figure 6.1). Hydrogenation processes for the conversion of crude oil fractions and crude oil products may be classified as (1) hydrotreating, which is referred to as nondestructive hydrogenation, and (2) hydrocracking, which is referred to as destructive hydrogenation). Hydrotreating units and hydrocracking units consume hydrogen in a series of reactions which result in the conversion of organic sulfur-containing constituents and nitrogen-containing constituents to hydrogen sulfide (H2S) and ammonia (NH3), respectively. The hydrogen also reacts with the hydrocarbons in the oil, increasing the hydrogen-to-carbon ratio. Hydrocracking reactions also result in the conversion of viscous feedstocks to naphtha-range, kerosene-range, and middle-distillate products (Parkash, 2003; Gary et al., 2007; Speight, 2014, Hsu and Robinson, 2017; Speight, 2017).

FIGURE 6.1  Example of the placement of hydroprocesses in a refinery.

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Hydrotreating and Hydrocracking Processes in Refining Technology

The partial pressure of the hydrogen drives these reactions and suppresses unwanted coke formation. Thus, a minimum hydrogen partial pressure (usually measured as reactor inlet purity or recycle gas purity) is required to operate with a reasonable catalyst life and reactor temperature. However, the minimum hydrogen partial pressure is not a fixed value and is a function of current operating conditions, such as (1) the feedstock flow rate, (2) the properties of the feedstock, (3) the desired products, and (4) the properties of the desired products. Operating ‘below’ the minimum hydrogen partial pressure reduces the life of the catalyst, while operating ‘above’ the minimum hydrogen partial pressure typically requires an increase in total hydrogen supplied to the hydrogen network. In order to accommodate the process in as efficient mode as possible, the process requires (1) regular monitoring of the hydrogen partial pressure in key hydrotreaters and hydrocrackers, (2) have targets for the hydrogen partial pressure that reflect current operating conditions and optimization of the process unit, and (3) adjustment of the hydrogen partial pressures accordingly. Thus, for any set of operating conditions, there is an optimum partial pressure of the hydrogen and, since the partial pressure of the hydrogen drives the reactions, increasing the hydrogen partial pressure can enable (1) an increased feedstock flow rate, (2) improved product properties, or (3) longer life of the catalyst. In hydrocrackers, it can enable improved yields, or greater conversion per pass. Methods to significantly improve hydrogen partial pressure include debottlenecking compression and adding H2S scrubbing of the recycle gas.

6.2.1  Hydrotreating Catalytic hydrotreating is a hydrogenation process used to remove approximately 90% of contaminants such as nitrogen, sulfur, oxygen, and metals from liquid crude oil fractions (Parkash, 2003; Gary et al., 2007; Speight, 2014, Hsu and Robinson, 2017; Speight, 2017). These contaminants, if not removed from the crude oil fractions as they travel through the refinery processing units, can have detrimental effects on the equipment, the catalysts, and the quality of the finished product. Typically, hydrotreating is done prior to processes such as catalytic reforming so that the catalyst is not contaminated by untreated feedstock. In some instances, in order to reduce the sulfur of the product and improve the yields of the product, hydrotreating of the feedstock is also used prior to catalytic cracking and to upgrade middle-distillate crude oil fractions into finished kerosene, diesel fuel, and heating fuel oils. In addition, hydrotreating converts olefin derivatives and aromatic derivatives to saturated products. In a typical catalytic hydrodesulfurization unit, the feedstock is de-aerated and mixed with hydrogen, preheated in a fired heater (315°F–425°F; 600°F–800°F) and then charged under pressure (up to 1,000 psi) through a fixed-bed catalytic reactor (Chapter 4). In the reactor, the sulfur and nitrogen compounds in the feedstock are converted into hydrogen sulfide and ammonia. The reaction products leave the reactor and after cooling to a low temperature enter a liquid/gas separator. The hydrogen-rich gas from the high-pressure separation is recycled to combine with the feedstock, and the low-pressure gas stream rich in hydrogen sulfide is sent to a gas-treating unit where the hydrogen sulfide is removed. The clean gas is then environmentally suitable fuel for the refinery furnaces. The liquid stream is the product from hydrotreating and is normally sent to a stripping column for removal of hydrogen sulfide and other undesirable components. In cases where steam is used for stripping, the product is sent to a vacuum drier for removal of water. In addition, the desulfurized products can be blended for use as a sulfur-free fuel or used as feedstock for a catalytic reforming unit. Hydrotreating processes differ depending upon the feedstock available and catalysts used. Hydrotreating can be used to improve the burning characteristics of distillates such as kerosene insofar as hydrotreatment of the kerosene can convert aromatic derivatives into naphthene derivatives, which are cleaner burning compounds. Lube-oil hydrotreating uses catalytic treatment of the oil with hydrogen to improve product quality. The objectives in mild lube hydrotreating include saturation of olefins and improvements in color, odor, and acid nature of the oil. Mild lube hydrotreating

Hydrogen Production

175

may also be used following solvent processing. Operating temperatures are usually below 315°C (600°F) and operating pressures below 800 psi. Severe lube hydrotreating, at temperatures in the 315°C–400°C (600°F–750°F) range and hydrogen pressures up to 3,000 psi, is capable of saturating aromatic rings, along with sulfur and nitrogen removal, to impart specific properties not achieved at mild conditions. Hydrotreating can also be employed to improve the quality of the naphtha produced by pyrolysis (sometime referred to pyrolysis naphtha, pyrolysis gasoline, or pygas), a by-product from the manufacture of ethylene. Traditionally, the outlet for pygas has been motor gasoline blending, a suitable route in view of its high octane number. However, only small portions can be blended untreated owing to the unacceptable odor, color, and gum-forming tendencies of this material. The quality of pyrolysis pygas, which typically has a content of di-olefin derivatives, can be satisfactorily improved by hydrotreating, whereby conversion of di-olefin derivatives into mono-olefins provides derivatives an acceptable product for blending with other liquid streams to produce gasoline.

6.2.2  Hydrocracking Hydrocracking is (in the simplest form) a two-stage process which combines catalytic cracking and catalytic hydrogenation, whereby higher boiling feedstocks are thermally decomposed in the presence of hydrogen to produce more desirable products. Hydrocracking also produces relatively large amounts of iso-butane for alkylation feedstock and the process also performs isomerization for pour-point control and smoke-point control, both of which are important in high-quality jet fuel. Hydrocracking employs high pressure, high temperature, and a catalyst. Hydrocracking is used for feedstocks that are difficult to process by either catalytic cracking or reforming, since these feedstocks are characterized usually by high polycyclic aromatic content and/or high concentrations of the two principal catalyst poisons, sulfur and nitrogen compounds (Chapter 5). The hydrocracking process depends, to a great extent, on the characteristics (i.e., the physical properties and the chemical properties) of the feedstock and the relative rates of the two competing reactions (i.e., the hydrogenation reactions and the cracking reactions). In the process, a high-boiling aromatic feedstock is converted into lower boiling products under a wide range of very high pressures (1,000–2,000 psi) and fairly high temperatures (400°C–815°C; 750°F–1,500°F), in the presence of hydrogen and special catalysts. If the feedstock has a high content of paraffin derivatives, the primary function of hydrogen is to prevent the formation of polycyclic aromatic compounds. Another important role of hydrogen in the hydrocracking process is to reduce tar formation and prevent buildup of coke on the catalyst. Hydrogenation also serves to convert sulfur and nitrogen compounds present in the feedstock to hydrogen sulfide and ammonia. In the first stage of the process, preheated feedstock is mixed with recycled hydrogen and sent to the first-stage reactor, where catalysts convert sulfur and nitrogen compounds to hydrogen sulfide and ammonia. Limited hydrocracking also occurs. After the hydrocarbon leaves the first stage, it is cooled and liquefied and run through a hydrocarbon separator. The hydrogen is recycled to the feedstock. The liquid is charged to a fractionator. Depending on the products desired (gasoline components, jet fuel, and gas oil), the fractionator is run to cut out some portion of the first-stage reactor out-turn. Product material boiling in the kerosene boiling can be taken as a separate side-draw product or included in the fractionator bottoms (i.e., the non-volatile fraction) with the gas oil. The bottoms fraction is mixed with a hydrogen stream and charged to the second stage. Since this fraction has already been subjected to hydrogenation, cracking, and reforming in the first stage of the process, the operations of the second stage are more severe (a higher temperature and a higher pressure than the first stage). Like the product from the first stage, the second-stage product is separated from the hydrogen and charged to the fractionator.

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6.3  HYDROGEN PRODUCTION There are several well-documented routes for the production of hydrogen in a refinery (Table 6.1). In addition, a refiner can use different feedstocks to produce hydrogen, and examples are natural gas, refinery gas, liquefied petroleum gas (LPG), low-boiling naphtha, and high-boiling naphtha depending on the availability of these refinery products. However, as might be anticipated, the properties of the feedstock will define the processing capability of the hydrogen plant, and the selection, design, and operating parameters of the hydrogen plant depend on the economic values attributed to the feedstock, the fuel, and the steam produced (Bressan et al., 2009; Kalamaras and Efstathiou, 2012; Ehteshami and Chan, 2014). Fossil-fuel processing technologies convert hydrogen-containing materials derived from fossil fuels, such as gasoline, hydrocarbons, methanol, or ethanol, into a hydrogen-rich gas stream. Fuel processing of methane (natural gas) is the most common commercial hydrogen production technology today. Most fossil fuels contain a certain amount of sulfur, the removal of which is a significant task in the planning of hydrogen-based economy. As a result, the desulfurization process will also be discussed. In addition, the very promising plasma reforming technology recently developed will also be presented. Hydrogen gas can be produced from hydrocarbon fuels through three basic technologies: (1) steam reforming, (2) partial oxidation, also commonly known as POX or Pox, and (3) autothermal reforming (ATR). These technologies produce a great deal of carbon monoxide (CO) and, hence, in a subsequent step, one or more chemical reactors are used to largely convert carbon monoxide into carbon dioxide by the WGS reaction and preferential oxidation (PrOx) or methanation reactions.

6.3.1 Feedstocks The most common, and perhaps the best, feedstocks for the steam reforming process are low-­boiling saturated hydrocarbons that have a low sulfur content, including natural gas, refinery gas (i.e., process gas), LPG, and low-boiling naphtha. Natural gas is the most common feedstock for hydrogen production since it meets all the feedstock requirements for the reforming process. Natural gas typically contains more than 90% v/v methane and ethane with the reminder of the volume consisting of propane, butane, and higher boiling hydrocarbons (Mokhatab et al., 2006; Speight, 2007, 2014). Natural gas may (or most likely will) contain traces of carbon dioxide with some nitrogen and other impurities. Purification of natural gas, before reforming, is usually relatively straightforward. Traces of sulfur must be removed to avoid poisoning the reformer catalyst, and zinc oxide treatment in combination with hydrogenation is usually adequate. Refinery gas, containing a substantial amount of hydrogen, can be a convenient feedstock for the steam reforming process since it is produced as a by-product. Processing the refinery gas depends on the composition of the gas stream, particularly the amount of olefin derivatives as well as the amounts of propane and higher molecular weight hydrocarbon derivatives. In addition, olefin derivatives that can cause problems by converting to coke in the reformer are converted to saturated compounds in the hydrogenation unit. Higher boiling hydrocarbons in refinery gas can also form coke, either on the primary reformer catalyst or in the preheater. If there is more than a few percent of C3 and higher compounds, a promoted reformer catalyst should be considered, in order to avoid carbon deposits. However, refinery gas from different sources varies widely in composition and, therefore, is suitability as a feedstock for the hydrogen plant. Catalytic reformer off-gas, e.g., is saturated, very low in sulfur, and often has high hydrogen content. The process gases from a coking unit or from a fluid catalytic cracking unit are much less desirable because of the content of unsaturated constituents (Parkash, 2003; Gary et al., 2007; Speight, 2014, Hsu and Robinson, 2017; Speight, 2017). In addition to olefin derivatives, these gases contain substantial amounts of sulfur that must be removed before the gas is used as a feedstock. These gases are also generally unsuitable for direct hydrogen recovery, since the hydrogen content is usually too low. Hydrotreater off-gas lies in the middle of the range. It is saturated, so it is readily used as hydrogen plant feed. The content of hydrogen and higher boiling hydrocarbon derivatives depends to a large extent on the upstream pressure. Sulfur removal will generally be required.

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6.3.2 Chemistry Before the feedstock is introduced to a process, there is the need for application of a strict feedstock purification protocol. Prolonging catalyst life in hydrogen production processes is attributable to effective feedstock purification, particularly sulfur removal. A typical natural gas or other light hydrocarbon feedstock contains traces of hydrogen sulfide and organic sulfur. In order to remove sulfur compounds, it is necessary to hydrogenate the feedstock to convert the organic sulfur to hydrogen that is then reacted with zinc oxide (ZnO) at approximately 370°C (700°F) that results in the optimal use of the zinc oxide as well as ensuring complete hydrogenation. Thus, assuming assiduous feedstock purification and removal of all of the objectionable contaminants, the chemistry of hydrogen production can be defined. In the steam reforming process, low-boiling hydrocarbon derivatives such as methane are reacted with steam to form hydrogen:

CH 4 + H 2O → 3H 2 + CO.

A more general form of the equation that shows the chemical balance for higher boiling hydrocarbons is

Cn H m + nH 2O → ( n + m / 2 ) H 2   + nCO.

The reaction is typically carried out at approximately 815°C (1,500°F) over a nickel catalyst packed into the tubes of a reforming furnace. The high temperature also causes the hydrocarbon feedstock to undergo a series of cracking reactions, plus the reaction of carbon with steam:

CH 4 → 2H 2 + C



C + H2 O → CO + H 2 .

Carbon is produced on the catalyst at the same time that hydrocarbon derivatives are reformed to hydrogen and carbon monoxide. With natural gas or a similar feedstock, reforming predominates and the carbon can be removed by reaction with steam as fast as it is formed. When higher boiling feedstocks are used, the carbon is not removed fast enough and builds up, thereby requiring catalyst regeneration or replacement. Carbon buildup on the catalyst (when high-boiling feedstocks are employed) can be avoided by addition of alkali compounds, such as potash, to the catalyst, thereby encouraging or promoting the carbon-steam reaction. However, even with an alkali-promoted catalyst, feedstock cracking limits the process to hydrocarbons with a boiling point less than of 180°C (350°F). Natural gas, propane, butane, and light naphtha are most suitable. Pre-reforming, a process that uses an adiabatic catalyst bed operating at a lower temperature, can be used as a pretreatment to allow heavier feedstocks to be used with lower potential for carbon deposition (coke formation) on the catalyst. After reforming, the carbon monoxide in the gas is reacted with steam to form additional hydrogen (the WGS reaction):

CO + H 2O → CO 2 + H 2          ∆H 298K = −16,500 Btu / lb.

This leaves a mixture consisting primarily of hydrogen and carbon monoxide that is removed by conversion to methane:

CO + 3H 2O → CH 4 + H 2O



CO 2 + 4H 2 → CH 4 + 2H 2O.

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The critical variables for steam reforming processes are (1) temperature, (2) pressure, and (3) the steam/hydrocarbon ratio. Steam reforming is an equilibrium reaction, and conversion of the hydrocarbon feedstock is favored by high temperature, which in turn requires higher fuel use. Because of the volume increase in the reaction, conversion is also favored by low pressure, which conflicts with the need to supply the hydrogen at high pressure. In practice, materials of construction limit temperature and pressure. On the other hand, and in contrast to reforming, shift conversion is favored by low temperature. The gas from the reformer is reacted over iron oxide catalyst at 315°C–370°C (600°F–700°F) with the lower limit being dictated activity of the catalyst at low temperature. Hydrogen can also be produced by partial oxidation (POX) of hydrocarbons in which the hydrocarbon is oxidized in a limited or controlled supply of oxygen:

2CH 4 + O 2 → CO + 4H 2         ∆H 298K = −10,195 Btu / lb.

The shift reaction also occurs and a mixture of carbon monoxide and carbon dioxide is produced in addition to hydrogen. The catalyst tube materials do not limit the reaction temperatures in partial oxidation processes, and higher temperatures may be used that enhance the conversion of methane to hydrogen. Indeed, much of the design and operation of hydrogen plants involves protecting the reforming catalyst and the catalyst tubes because of the extreme temperatures and the sensitivity of the catalyst. In fact, minor variations in feedstock composition or operating conditions can have significant effects on the life of the catalyst or the reformer itself. This is particularly true of changes in molecular weight of the feed gas, or poor distribution of heat to the catalyst tubes. Since the high temperature takes the place of a catalyst, partial oxidation is not limited to the lower boiling feedstocks that are required for steam reforming. Partial oxidation processes were first considered for hydrogen production because of expected shortages of lower boiling feedstocks and the need to have available a disposal method for higher boiling, high-sulfur streams such as asphalt or crude oil coke. Catalytic partial oxidation, also known as autothermal reforming, is a process in which oxygen is reacted with a low-boiling feedstock (such as naphtha) and passing the resulting hot product over a reforming catalyst. The use of a catalyst allows the use of lower temperatures than in non-catalytic partial oxidation which causes a reduction in oxygen demand. The feedstock requirements for catalytic partial oxidation processes are similar to the feedstock requirements for steam reforming and light hydrocarbons from refinery gas to naphtha are preferred. The oxygen substitutes for much of the steam in preventing coking and a lower steam/carbon ratio is required. In addition, because a large excess of steam is not required, catalytic partial oxidation produces more carbon monoxide and less hydrogen than steam reforming. Thus, the process is more suited to situations where carbon monoxide is the more desirable product such as, e.g., as synthesis gas for chemical feedstocks.

6.3.3 Catalysts In the current context, the processes that require the use of a catalyst include hydrogenation, steam reforming, shift conversion, and methanation. In fact, the production of hydrogen is one of the most extensive users of catalysts in the refinery. 6.3.3.1  Reforming Catalysts The reforming catalyst is usually supplied as nickel oxide that, during start-up, is heated in a stream of inert gas, then steam. When the catalyst is near the normal operating temperature, hydrogen or a light hydrocarbon is added to reduce the nickel oxide to metallic nickel. The high temperatures (up to 870°C, 1,600°F) and the nature of the reforming reaction require that the reforming catalyst be used inside the radiant tubes of a reforming furnace. The active agent in reforming catalyst is nickel, and normally the reaction is controlled both by diffusion and by heat transfer. Catalyst life is limited as much by physical breakdown as by deactivation.

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Sulfur is the main catalyst poison and the catalyst poisoning is theoretically reversible with the catalyst being restored to near full activity by steaming. However, in practice, the deactivation may cause the catalyst to overheat and coke, to the point that it must be replaced. Reforming catalysts are also sensitive to poisoning by heavy metals, although these are rarely present in low-boiling hydrocarbon feedstocks and naphtha feedstocks. Coking deposition on the reforming catalyst and ensuing gloss of catalyst activity is the most characteristic issue that must be assessed and mitigated. While methane-rich streams such as natural gas or light refinery gas are the most common feeds to hydrogen plants, there is often a requirement for variety of reasons to process a variety of higher boiling feedstocks, such as LPG and naphtha. Feedstock variations may also be inadvertent due, e.g., to changes in refinery off-gas composition from another unit or because of variations in naphtha composition because of feedstock variance to the naphtha unit. Thus, when using higher boiling feedstocks in a hydrogen plant, coke deposition on the reformer catalyst becomes a major issue. Coking is most likely in the reformer unit at the point where both temperature and hydrocarbon content are high enough. In this region, hydrocarbons crack and form coke faster than the coke is removed by reaction with steam or hydrogen, and when catalyst deactivation occurs, there is a simultaneous temperature increase with a concomitant increase in coke formation and deposition. In other zones, where the hydrocarbon-to-hydrogen ratio is lower, there is less risk of coking. Coking depends to a large extent on the balance between catalyst activity and heat input with the more active catalysts producing higher yields of hydrogen at lower temperature, thereby reducing the risk of coking. A uniform input of heat is important in this region of the reformer since any catalyst voids or variations in catalyst activity can produce localized hot spots leading to coke formation and/or reformer failure. Coke formation results in hotspots in the reformer that increases pressure drop and reduces feedstock (methane) conversion, leading eventually to reformer failure. Coking may be partially mitigated by increasing the steam/feedstock ratio to change the reaction conditions but the most effective solution may be to replace the reformer catalyst with one designed for higher boiling feedstocks. A standard SMR catalyst uses nickel on an alpha-alumina ceramic carrier that is acidic in nature. Promotion of hydrocarbon cracking with such a catalyst leads to coke formation from higher boiling feedstocks. Some catalyst formulations use a magnesia/alumina (MgO/Al2O3) support that is less acidic than α-alumina that reduces cracking on the support and allows higher boiling feedstocks (such as LPG) to be used. Further resistance to coking can be achieved by adding an alkali promoter, typically some form of potash (KOH) to the catalyst. Besides reducing the acidity of the carrier, the promoter catalyzes the reaction of steam and carbon. While carbon continues to be formed, it is removed faster than it can build up. This approach can be used with naphtha feedstocks boiling point up to approximately 180°C (350°F). Under the conditions in a reformer, potash is volatile and it is incorporated into the catalyst as a more complex compound that slowly hydrolyzes to release potassium hydroxide (KOH). Alkali-promoted catalyst allows the use of a wide range of feedstocks but, in addition to possible potash migration, which can be minimized by proper design and operation, the catalyst is also somewhat less active than conventional catalyst. Another option to reduce coking in steam reformers is to use a pre-reformer in which a fixed bed of catalyst, operating at a lower temperature, upstream of the fired reformer is used. In a pre-reformer, adiabatic steam-hydrocarbon reforming is performed outside the fired reformer in a vessel containing high-nickel catalyst. The heat required for the endothermic reaction is provided by hot flue gas from the reformer convection section. Since the feed to the fired reformer is now partially reformed, the steam-methane reformer can operate at an increased feed rate and produce 8 to 10% additional hydrogen at the same reformer load. An additional advantage of the pre-reformer is that it facilitates higher mixed feed preheat temperatures and maintains relatively constant operating conditions within the fired reformer regardless of variable refinery off-gas feed conditions. Inlet temperatures

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are selected so that there is minimal risk of coking and the gas leaving the pre-reformer contains only steam, hydrogen, carbon monoxide, carbon dioxide, and methane. This allows a standard methane catalyst to be used in the fired reformer, and this approach has been used with feedstocks up to light kerosene. Since the gas leaving the pre-reformer poses reduced risk of coking, it can compensate to some extent for variations in catalyst activity and heat flux in the primary reformer. 6.3.3.2  Shift Conversion Catalysts The second important reaction in a steam reforming plant is the shift conversion reaction in which hydrogen is produced by the reaction of carbon monoxide and steam:

CO + H 2O → CO 2 + H 2 .

Two basic types of shift catalyst are used in steam reforming plants: iron/chrome high-temperatureshift catalysts, and copper/zinc low-temperature-shift catalysts. High-temperature-shift catalysts operate on the order of 315°C–430°C (600°F–800°F) and consist primarily of magnetite (Fe3O4) with three-valent chromium oxide (Cr2O3) added as a stabilizer. The catalyst is usually supplied in the form of ferric oxide (Fe2O3) and six-valent chromium oxide (CrO3) and is reduced by the hydrogen and carbon monoxide in the shift feed gas as part of the startop procedure to produce the catalyst in the desired form. However, caution is necessary since if the steam/carbon ratio of the feedstock is too low and the reducing environment too strong, the catalyst can be further reduced to metallic iron (which is a catalyst for the Fischer–Tropsch reactions) leading to the production of hydrocarbon derivatives (Davis and Occelli, 2010). On the other hand, low-temperature-shift catalysts operate at temperatures on the order of 205°C–230°C (400°F–450°F) and, because of the lower temperature, the reaction equilibrium is more controllable and lower amounts of carbon monoxide are produced. The low-temperature-shift catalyst is primarily used/ in wet scrubbing plants that use a methanation for final purification. Typically, the PSA units do not use a low temperature because any unconverted carbon monoxide is recovered as reformer fuel. However, low-temperature-shift catalysts are sensitive to poisoning by sulfur and are sensitive to water (liquid) that can cause softening of the catalyst followed by crusting or plugging. The catalyst is supplied as copper oxide (CuO) on a zinc oxide (ZnO) carrier and the copper must be reduced by heating it in a stream of inert gas with the measured quantity of hydrogen. The reaction by which the copper oxide is reduced is strongly exothermic and must be closely monitored (Davis and Occelli, 2010). 6.3.3.3  Methanation Catalysts In wet scrubbing plants, the final hydrogen purification procedure involves methanation in which the carbon monoxide and carbon dioxide are converted to methane:

CO + 3H2O → CH 4 + H 2O



CO 2 + 4H 2 → CH 4 + 2H 2O.

The active agent is nickel, on an alumina carrier. The catalyst has a long life, as it operates under ideal conditions and is not exposed to poisons. The main source of deactivation of the catalyst is plugging of the pore system that can result from carryover of carbon dioxide. The most severe hazard arises from high levels of carbon monoxide or carbon dioxide that can result from breakdown of the carbon dioxide removal equipment or from exchanger tube leaks that quench the shift reaction. The results of breakthrough can be severe, since the methanation reaction produces a temperature rise of 70°C (125°F) per 1% of carbon monoxide or a temperature rise of 33°C (60°F) per 1% of carbon dioxide. While the normal operating temperature during methanation is approximately 315°C (600°F), it is possible to reach 700°C (1,300°F) in cases of major breakthrough.

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Other options for the production of hydrogen include (1) the electrolysis of water and (2) the gasification of biomass. In the first option (the electrolysis of water), the water molecules are split directly into hydrogen and oxygen molecules using electricity and an electrolyzing unit. The two most common types of units are alkaline (in which a potassium hydroxide electrolyte is used) and a solid polymer membrane electrolyte (PEM) (which uses a). The electrolysis reaction produces pure oxygen as a by-product along with pure hydrogen. Thus, 2H 2O → O 2 + 2H 2 .



The electrolysis reaction produces pure oxygen as a by-product along with the pure hydrogen. The oxygen can then be used for productive purposes such as enriching the oxygen content of greenhouses for food production. In the second option (the gasification of biomass), the conversion technologies can be divided into thermochemical processes and biochemical processes. Biomass conversion technologies can be divided into thermochemical and biochemical processes. Thermochemical processes tend to be less expensive because they can be operated at higher temperatures and therefore obtain higher reaction rates. The processes (which can utilize a broad range of biomass types) involve either gasification or pyrolysis (heating biomass in the absence of oxygen) to produce  a  hydrogen-rich stream of gas (synthesis gas which is a blend of hydrogen and carbon monoxide). Thermochemical processes can be operated at higher temperatures and therefore obtain higher reaction rates. The processes involve either gasification or pyrolysis (heating biomass in the absence of oxygen) to produce a hydrogen-rich stream of synthesis gas (a blend of hydrogen and carbon monoxide) and the feedstock can be a broad range of the different types of biomass. Hydrogen can also be produced via other means, including from algae, by direct solar electrochemical processes, and from various nuclear-power-assisted pathways (Lipman, 2011). Thermochemical cycles have been developed already since the 1970s and 1980s when they had to contribute to the search for new sources of production of alternative fuels during the crude oil crisis. In thermochemical water splitting, also called thermolysis, heat alone is used to decompose water to hydrogen and oxygen (Steinfeld, 2005; Balat and Kirtay, 2010). The single-step thermal dissociation of water is described as follows: 2H 2O → 2H 2 + O 2 .



Water will decompose at 2,500°C (4,530°F) and all of the processes have significantly reduced the operating temperature to lower than 2,500°C (4,530°F) (Funk, 2001; Lewis et al., 2003).

6.4  COMMERCIAL PROCESSES In spite of the use of low-quality hydrogen (that contain up to 40% v/v hydrocarbon gases), a highpurity hydrogen stream (on the order of 95–99 v/v hydrogen) is required for hydrodesulfurization, hydrogenation, hydrocracking, and petrochemical processes. Hydrogen plants produce hydrogen primarily through the steam reforming and WGS reactions:

CH 4 + H 2O → 3H 2 + CO



CO + H 2O → H 2 + CO 2 .

The reforming reaction is endothermic and equilibrium limited. In addition, a lower pressure and higher temperature favor higher conversion to hydrogen, and the operating pressure is typically set by a practical hydrogen delivery pressure. The maximum temperature is constrained primarily by tube life and coking concerns. In addition, the steam-to-carbon ratio is a critical operating variable that affects conversion and coking.

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Also, catalytic reforming remains an important process used to convert low-octane naphtha into high-octane gasoline blending components referred to as ‘reformate.’ Also, reforming a feedstock represents the total effect of numerous reactions such as cracking, polymerization, dehydrogenation, and isomerization which can occur in sequence or simultaneously. Also, depending on the properties of, e.g., the naphtha feedstock (as measured by the paraffin, olefin, naphthene, and aromatic content) and catalysts used, reformate can be produced with very high concentrations of toluene, benzene, xylene, and other aromatics useful in gasoline blending and petrochemical processing. Hydrogen is separated from reformate for recycling and use in other processes. There are many different commercial catalytic reforming processes including Platforming, Powerforming, Ultraforming, and Thermofor catalytic reforming (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). In the Platforming process, the first step is preparation of the naphtha feed to remove impurities from the naphtha and reduce catalyst degradation. The naphtha feedstock is then mixed with hydrogen, vaporized, and passed through a series of alternating furnaces and fixed-bed reactors that contain a platinum catalyst. The effluent from the last reactor in the series is cooled and sent to a separator to permit removal of the hydrogen-rich gas stream from the top of the separator for recycling. The liquid product from the bottom of the separator is sent to a fractionator (often referred to as a de-butanizer), and the bottom product (reformate) is sent to storage and butanes and lighter gases pass overhead and are sent to the saturated gas plant. Some catalytic reformers operate at low pressure (e.g., 50–200 psi), and other reformers may operate at pressures on the order of up to 1,000 psi. Some catalytic reforming systems continuously regenerate the catalyst in other systems. Typically, rather interrupt the operations, one reactor at a time is taken off-stream for catalyst regeneration, although some facilities do tend to regenerate all of the reactors during a multi-reactor turnaround. Care must be taken not to break or crush the catalyst when loading the beds, as the small fines will plug up the reformer screens. Precautions against interference by dust when regenerating or replacing catalyst should also be given serious consideration and a water wash should be considered where stabilizer fouling has occurred due to the formation of ammonium chloride and iron salts. In particular, ammonium chloride may form in pretreater exchangers that can lead to serious fouling and corrosion. Also, hydrogen chloride from the hydrogenation of chlorine compounds may form the acid (in the presence of water) or the ammonium chloride salt.

6.4.1 Autothermal Reforming In the ATR process, steam is added in the catalytic partial oxidation process. ATR is a combination of both steam reforming (endothermic) and partial oxidation (exothermic) reactions. ATR has the advantages of not requiring external heat and being simpler and less expensive than steam reforming (SR) of methane. The selection of operation conditions of the reformer depends on the specific target. A main target is the high hydrogen yield with low carbon monoxide content. Maximum hydrogen efficiency and low carbon monoxide content are possible for steam reforming. However, steam reforming is an endothermic process and therefore energy demanding. This energy has to be transferred into the system from the outside. Another significant advantage of the autothermal process over the steam reforming process is that it can be shut down and started very rapidly, while producing a larger amount of hydrogen than the partial oxidation process (Joensen and Rostrup-Nielsen, 2002). There are some expectations that this process will become attractive for the gas-to-liquid fuel industry due to favorable gas composition for the Fischer–Tropsch synthesis (Wilhelm et al., 2001; Joensen and Rostrup-Nielsen, 2002). For methane reforming, the thermal efficiency is comparable to that of POX (on the order of 60%–75%) and slightly less than that of steam reforming (Ayabe et al., 2003). In autothermal reformers (or secondary reformers), the oxidation of methane supplies the necessary energy and carried out either (1) simultaneously or (2) in advance of the reforming reaction (Brandmair et al., 2003; Ehwald et al., 2003; Nagaoka et al., 2003). The equilibrium of the

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methane-steam reaction and the WGS reaction determines the process efficiency and, hence, the optimum yields of hydrogen that can be expected insofar as the optimum conditions for hydrogen production require high temperature at the exit of the reforming reactor (800°C–900°C; 1,470°F–1,650°F), high excess of steam (molar steam-to-carbon ratio on the order of 2.5–3), and relatively low pressures (below 450 psi). High-temperature fuel cells based on molten carbonate (MCFC) or solid oxide (SOFC) technology operate at sufficiently high temperatures to run directly on methane (often referred to as internal reforming). Thus, MCFC and SOFO systems do not need a pure or relatively pure hydrogen stream as do proton exchange membrane (PEM) and phosphoric acid (PAFC) systems, but can run directly on natural gas or biogas or landfill gas. Furthermore, such systems can be designed to produce additional purified hydrogen as a by-product (e.g., for use as a vehicle fuel), by feeding additional fuel and then purifying the hydrogen-rich “anode tail gas” from the fuel cell into purified hydrogen.

6.4.2  Heavy Residue Gasification and Combined Cycle Power Generation In the process, a viscous feedstock (such as residuum) can be gasified and the produced gas is purified to clean fuel gas (Gross and Wolff, 2000). As an example, solvent deasphalter residuum is gasified by partial oxidation method under pressure of approximately 570 psi and at a temperature between 1,300°C and 1,500°C (2,370°F and 2,730°F). The high-temperature-generated gas flows into the specially designed waste heat boiler, in which the hot gas is cooled and high-pressure-­saturated steam is generated. The gas from the waste heat boiler is then sent through a heat exchanger with the fuel gas and flows to the carbon scrubber, where unreacted carbon particles are removed from the generated gas by water scrubbing. The gas from the carbon scrubber is cooled further by the fuel gas and boiler feed water and let into the sulfur compound removal section, where hydrogen sulfide (H2S) and carbonyl sulfide (COS) are removed from the gas to obtain clean fuel gas. This clean fuel gas is heated with the hot gas generated in the gasifier and finally supplied to the gas turbine at a temperature of 250°C–300°C (480°F–570°F). The exhaust gas from the gas turbine having a temperature of approximately 550°C–600°C (1,020°F–1,110°F) flows into the heat recovery steam generator consisting of five heat exchange elements. The first element is a superheater in which the combined stream of the high-pressuresaturated steam generated in the waste heat boiler and in the second element (high-pressure steam evaporator) is super-heated. The third element is an economizer, the fourth element is a low-pressure steam evaporator, and the final or the fifth element is a de-aerator heater. The off-gas from heat recovery steam generator having a temperature of approximately 130°C (265°F) is emitted into the air via stack. In order to decrease the nitrogen oxide (NOx) content in the flue gas, two methods can be applied. The first method is the injection of water into the gas turbine combustor. The second method is to selectively reduce the nitrogen oxide content by injecting ammonia gas in the presence of de-NOx catalyst that is packed in a proper position of the heat recovery steam generator. The latter is more effective that the former to lower the nitrogen oxide emissions to the air.

6.4.3  Hybrid Gasification Process In the hybrid gasification process, a slurry of coal and residual oil is injected into the gasifier where it is pyrolyzed in the upper part of the reactor to produce gas and chars. The chars produced are then partially oxidized to ash. The ash is removed continuously from the bottom of the reactor. In this process, coal and vacuum residue are mixed together into slurry to produce clean fuel gas. The slurry fed into the pressurized gasifier is thermally cracked at a temperature of 850°C–950°C (1,560°F–1,740°F) and is converted into gas, tar, and char. The mixture oxygen and steam in the

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lower zone of the gasifier gasify the char. The gas leaving the gasifier is quenched to a temperature of 450°C (840°F) in the fluidized-bed heat exchanger, and is then scrubbed to remove tar, dust, and steam at around 200°C (390°F). The coal and residual oil slurry is gasified in the fluidized-bed gasifier in which the slurry feedstock is converted to gas and char by thermal cracking reactions in the upper zone of the fluidized bed. The char is the gasified with steam and oxygen that enter the gasifier just below the fluidizing gas distributor (Speight, 2013). Ash discharged from the gasifier is cooled with steam and then discharged into the ash hopper where it can be burned in an incinerator to produce process steam. Also, the coke that is deposited on the silica sand can be removed in the incinerator.

6.4.4  Hydrocarbon Gasification The gasification of hydrocarbon derivatives to produce hydrogen is a continuous, non-catalytic process that involves partial oxidation of the hydrocarbon derivatives. Air or oxygen (with steam or carbon dioxide) is used as the oxidant at temperatures on the order of 1,095°C–1,480°C (2,000°F–2,700°F). Any carbon produced (2%–3% w/w of the feedstock) during the process is removed as a slurry in a carbon separator and pelletized for use either as a fuel or as raw material for carbon-based products.

6.4.5  Hypro Process The Hypro process is a continuous catalytic method for the manufacture of hydrogen from natural gas or from refinery process gas. Using natural gas (i.e., methane as the example), the process is as follows:

CH 4 → C + 2H 2 .

Hydrogen is recovered by phase separation to yield hydrogen of approximately 93% purity; the principal contaminant is methane.

6.4.6  Pyrolysis Processes There has been recent interest in the use of pyrolysis processes to produce hydrogen. Specifically the interest has focused on the pyrolysis of methane (natural gas) and hydrogen sulfide. Natural gas is readily available and offers relatively rich stream of methane with lower amounts of ethane, propane, and butane also present. The thermocatalytic decomposition of the higher molecular weight hydrocarbon derivatives (i.e., C2–C4) in natural gas hydrocarbons offers an alternate method for the production of hydrogen (Uemura et al., 1999; Weimer et al., 2000):

Cn H m → nC + ( m / 2 ) H 2 .

If a hydrocarbon fuel such as natural gas (methane) is to be used for hydrogen production by direct decomposition, then the process that is optimized to yield hydrogen production may not be suitable for production of high-quality carbon black by-product intended for the industrial rubber market. Moreover, it appears that the carbon produced from high-temperature (850°C–950°C; 1,560°F–1,740°F) direct thermal decomposition of methane is soot-like material with high tendency for the catalyst deactivation (Murata et al., 1997). Thus, if the object of methane decomposition is hydrogen production, the carbon by-product may not be marketable as high-quality carbon black for rubber and tire applications. The production of hydrogen by direct decomposition of hydrogen sulfide has been studied extensively and a process proposed (Clark and Wassink, 1990; Zaman and Chakma, 1995; Donini, 1996; Luinstra 1996). Hydrogen sulfide decomposition is a highly endothermic process and equilibrium

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yields are poor (Clark et al., 1995). At temperatures less than 1,500°C (2,730°F), the thermodynamic equilibrium is unfavorable toward hydrogen formation. However, in the presence of catalysts such as platinum-cobalt (at 1,000°C; 1,830°F), disulfides of molybdenum or tungsten Mo or W at 800°C (1,470°F) (Kotera et al., 1976), or other transition metal sulfides supported on alumina (at 500°C–800°C; 930°F–1,470°F), decomposition of hydrogen sulfide proceeds rapidly (Kiuchi 1982, Bishara et al., 1987, Al-Shamma and Naman, 1989, Clark and Wassink, 1990, Megalofonos and Papayannakos, 1997; Arild, 2000; Raissi, 2001). In the temperature range on the order of 800°C–1,500°C (1,470°F–2,730°F), thermolysis of hydrogen sulfide can be treated simply: H 2S → H 2 + 1 / xS x .



In this equation, x = 2. Outside of this temperature range, multiple equilibria may be present depending on temperature, pressure, and relative abundance of hydrogen and sulfur (Clark 1990). Above approximately 1,000°C (1,830°F), there is a limited advantage to using catalysts since the thermal reaction proceeds to equilibrium very rapidly (Clark and Wassink, 1990). The hydrogen yield can be doubled by preferential removal of either H2 or sulfur from the reaction environment, thereby shifting the equilibrium. The reaction products must be quenched quickly after leaving the reactor to prevent reversible reactions.

6.4.7 Shell Gasification Process The Shell Gasification process (partial oxidation process) is a flexible process for generating synthesis gas, principally hydrogen and carbon monoxide, for the ultimate production of high-purity high-pressure hydrogen, ammonia, methanol, fuel gas, town gas, or reducing gas by reaction of gaseous or liquid hydrocarbons with oxygen, air or oxygen-enriched air. The most important step in converting a viscous feedstock to a gas is the partial oxidation of the oil using oxygen with the addition of steam. The gasification process takes place in an empty, refractory-lined reactor at temperatures of approximately 1,400°C (2,550°F) and pressures between 29 and 1,140 psi. The chemical reactions in the gasification reactor proceed without catalyst to produce gas containing carbon amounting to some 0.5%–2% by weight, based on the feedstock. The carbon is removed from the gas with water, extracted in most cases with feed oil from the water, and returned to the feed oil. The high-temperature reformed gas is utilized in a waste heat boiler for generating steam at 850– 1,565 psi. Some of this steam is used as process steam and for preheating the feedstock and the oxygen and oil preheating, and any surplus steam can be used for energy production and/or heating purposes.

6.4.8 Steam-Methane Reforming SMR is the most widely used process that has been employed over a period of several decades for hydrogen production (Cruz and de Oliveira Junior, 2008). In the process, natural gas or other methane stream, such as biogas or landfill gas, is reacted with steam in the presence of a catalyst to produce hydrogen and carbon dioxide. When starting with natural gas, the process is approximately 72% efficient in producing hydrogen on a lower heating value basis. The efficiency can be somewhat lower with sources of methane that include sulfur or other impurities that require a pretreatment cleanup step to remove the impurities upstream of the SMR process. More specifically, the process involves reforming natural gas (predominantly methane) in a continuous catalytic process in which the major reaction of the methane and steam results in the formation of carbon monoxide and hydrogen:

CH 4 + H 2O = CO + 3H 2 .

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In addition, higher molecular weight feedstocks (such as propane and butane) can also be reformed to hydrogen:

C3H8 + 3H 2O → 3CO + 7H 2 .

That is,

Cn H m + nH 2O → nCO + ( 0.5m + n ) H 2 .

In the actual process, the feedstock is first desulfurized by passage through activated carbon, which may be preceded by caustic and water washes. The desulfurized material is then mixed with steam and passed over a nickel-based catalyst (730°C–845°C, 1,350–1,550°F and 400 psi) after which the effluent gases are cooled by the addition of steam or condensate to approximately 370°C (700°F), and any carbon monoxide reacts with steam in the presence of iron oxide catalyst in a shift converter to produce carbon dioxide and hydrogen:

CO + H 2O = CO2 + H 2 .

The carbon dioxide is removed by amine washing; the hydrogen is usually a high-purity (>99%) material. Since the presence of any carbon monoxide or carbon dioxide in the hydrogen stream can interfere with the chemistry of the catalytic application, a third stage is used to convert these gases to methane:

CO + 3H 2 → CH 4 + H 2O



CO 2 + 4H 2 → CH 4 + 2H 2O.

For many refiners, sulfur-free natural gas (CH4) is not always available to produce hydrogen by this process. In that case, higher boiling hydrocarbons (such as ethane, propane, or butane) may be used as the feedstock to generate hydrogen. The net chemical process for SMR is then given by

CH 4 + 2H 2O → CO 2 + 4H 2 .

One way to overcome the thermodynamic limitation of steam reforming is to remove either hydrogen or carbon dioxide as it is produced, hence shifting the thermodynamic equilibrium toward the product side. In this process, the basis is the in situ removal of carbon dioxide by a sorbent such as calcium oxide (CaO):

CaO + CO 2 → CaCO3

Sorption enhancement enables lower reaction temperatures, which may reduce coke deposition on the catalyst while enabling use of less-expensive reactor wall materials. In addition, heat release by the exothermic carbonation reaction supplies most of the heat required by the endothermic reforming reactions and the sorbent can be regenerated by the calcination reaction:

CaCO3 → CaO + CO 2 .

Use of a sorbent typically requires that either (1) there are parallel reactors operated alternatively and out of phase in reforming and sorbent regeneration modes, or (2) the sorbent be continuously transferred between the reformer/carbonator and regenerator/calciner to ensure process efficiency (Balasubramanian et al., 1999; Hufton et al., 1999).

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The SMR process is an ideal source of hydrogen but does require substantial quantities of natural gas which is also a valuable resource for the production of petrochemicals. Also, for each mole of methane reformed to hydrogen, more than one mole of carbon dioxide is co-produced that must be sent for disposal (or use) in an environmentally friendly manner. In fact, the production of hydrogen as a clean burning fuel by way of steam reforming of methane and other fossil-based hydrocarbon fuels is not in environmental balance if in the process, carbon dioxide and carbon monoxide are generated and released into the atmosphere, although alternate scenarios are available (Gaudernack, 1996). Moreover, as the reforming process is not totally efficient, some of the energy value of the hydrocarbon fuel is lost by conversion to hydrogen but with no tangible environmental benefit, such as a reduction in emission of greenhouse gases. Despite these apparent shortcomings, the process has the following advantages: (1) produces 4 moles of hydrogen for each mole of methane consumed, (2) feedstocks for the process (methane and water are readily available), (3) the process is adaptable to a wide range of hydrocarbon feedstocks, (4) operates at low pressures, less than 450 psi, (5) requires a low steam/carbon ratio (2.5–3), (6) good utilization of input energy (reaching 93%), (7) can use catalysts that are stable and resist poisoning, and (8) good process kinetics. Liquid feedstocks (either LPG or naphtha) can also provide backup feed, if there is a risk of a decrease in the supply of natural gas. Also, the handling system for the feedstock needs to include a surge drum, feed pump, vaporizer (usually steam-heated) followed by further heating before desulfurization. The sulfur in liquid feedstocks occurs as mercaptan derivatives (RSH), thiophene (cyclic sulfur-containing systems), or higher boiling derivatives. Typically, these types of compounds are stable and will not be removed by zinc oxide (ZnO) and, therefore, a hydrogenation unit will be required for removal of these sulfur compounds. In addition, olefin derivatives (>C=C300 psi) such as hydroprocessing purge gases. The systems do not contain any moving parts or switch valves and have potentially very high reliability. The major threat is from components in the gas (such as aromatics) that attack the membranes, or from liquids, which plug them. Membrane systems separate gases by taking advantage of the difference in rates of diffusion through membranes (Brüschke, 1995, 2003). Gases that diffuse faster (including hydrogen) become the permeate stream and are available at low pressure, whereas the slower diffusing gases become the non-permeate stream and leave the unit at a pressure close to the pressure of the feedstock at the entry point. The membranes arc fabricated in relatively small modules; for larger capacity, more modules are added. The design of membrane systems involves a tradeoff between pressure drop (and diffusion rate) and surface area, as well as between product purity and recovery. As the surface area is increased, the recovery of fast components increases; however, more of the slow components are recovered, which lowers the purity.

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6.5.3  Pressure-Swing Adsorption Units PSA units use beds of solid adsorbent to separate impurities from hydrogen streams to produce highpurity, high-pressure hydrogen and a low-pressure tail gas stream containing the impurities and small quantities of hydrogen. The catalyst beds are then regenerated by depressurizing and purging operations. Part of the hydrogen (up to 20% v/v) may be lost in the tail gas, which is the gas from industrial processes after all reaction and treatment have taken place. PSA is generally the purification method of choice for steam reforming units because of its production of high-purity hydrogen and is also used for purification of refinery off-gases, where it competes with membrane systems. Many hydrogen plants that formerly used a wet scrubbing process for hydrogen purification are now using the PSA technique for purification (Speight, 2000; Ancheyta and Speight, 2007; Speight, 2014, 2017). The PSA process is a cyclic process that uses beds of solid adsorbent to remove impurities from the gas and generally produces higher purity hydrogen (99.9% v/v percent purity compared to less than 97% v/v purity). The purified hydrogen passes through the adsorbent beds (only a small fraction of the hydrogen stream is absorbed) and the beds are regenerated by depressurization followed by a purging operation at low pressure. When the beds are depressurized, a waste gas (or tail gas) stream is produced and consists of the impurities from the feed (carbon monoxide, carbon dioxide, methane, and nitrogen) plus some hydrogen. This stream is burned in the reformer as fuel, and the operating parameters of the reformer in a PSA plant are monitored so that the tail gas provides up to 85% v/v of the reformer fuel. This gives good burner control because the tail gas is more difficult to burn than regular fuel gas and the high content of carbon monoxide can interfere with the stability of the flame. The PSA system is often cited as the best choice when ultra-high-purity hydrogen product (>99% v/v) is required. Impurities and unrecovered hydrogen are delivered at low pressure and available for fuel. However, system designs for refinery gas streams must account for variability in feed gas conditions. For example, the composition of catalytic reformer off-gas hydrogen can change by 10%–15% v/v as a function of makeup hydrogen purity and specific purge rate set points. When multiple refinery gas streams are mixed, different operating scenarios can significantly change the composition.

6.5.4 Wet Scrubbing Wet scrubbing systems, particularly amine or potassium carbonate systems, are used for removal of acid gases such as hydrogen sulfide or carbon dioxide (Dalrymple et al., 1994). Most systems depend on chemical reaction and can be designed for a wide range of pressures and capacities. They were once widely used to remove carbon dioxide in steam reforming plants, but have generally been replaced by PSA units except where carbon monoxide is to be recovered. Wet scrubbing is still used to remove hydrogen sulfide and carbon dioxide in partial oxidation plants. Wet scrubbing systems remove only acid gases or high-molecular-weight hydrocarbon derivatives but they do not remove methane or other hydrocarbon gases, and hence have little influence on product purity. Therefore, wet scrubbing systems are most often used as a pretreatment step, or where a hydrogen-rich stream is to be desulfurized for use as fuel gas.

6.6  HYDROGEN MANAGEMENT Hydrogen has always played an important role in oil refining, but refiners today are finding that it is one of the most critical challenges as they plan production of environmentally acceptable products, especially the low-sulfur products. Therefore, an effective hydrogen management program must address refinery-wide issues in a systematic, comprehensive way. The hydrogen system consists of hydrogen producers, hydrogen purification, hydrogen consumption, and the distribution network itself.

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Thus, hydrogen management has become a priority when planning to produce lower sulfur products. Along with increased consumption for deeper hydrotreating, additional hydrogen is needed for processing viscous feedstocks and, as a result, hydroprocessing capacity and the associated hydrogen network are limiting refinery capacity and throughput. Furthermore, higher purity of the hydrogen streams’ purities within the refinery are becoming more important to (1) boost hydrotreater capacity, (2) achieve product value improvements, and (3) lengthen catalyst life cycles. Thus, managing current hydrogen infrastructure and planning for future requirements requires careful selection of the best combination of recovery, expansion, efficiency improvements, purification, and new H2 supply options (Davis and Patel, 2004). Many existing refinery hydrogen plants use a conventional process, which produces a mediumpurity (94%–97% v/v) hydrogen product by removing the carbon dioxide in an absorption system and methanation of any remaining carbon oxides. Since the 1980s, most hydrogen plants are built with PSA technology to recover and purify the hydrogen to purities above 99.9%. Since many refinery hydrogen plants utilize refinery off-gas feeds containing hydrogen, the actual maximum hydrogen capacity that can be synthesized via steam reforming is not certain since the hydrogen content of the off-gas can change due to operational changes in the hydrotreaters. Hydrogen management has become a priority in current refinery operations and when planning to produce lower sulfur gasoline and diesel fuels (Zagoria et al., 2003; Méndez et al., 2008; Luckwal and Mandal, 2009). Furthermore, higher hydrogen purity within the refinery network is becoming more important in order to (1) boost the capacity of the hydrotreating units, (2) achieve improvements in the value of the products, and (2) lengthen the life cycles of the catalysts. Improved hydrogen utilization and expanded or new sources for refinery hydrogen and hydrogen purity optimization are now required to meet the needs of the future transportation fuel market and the drive toward higher refinery profitability (Long et al., 2011). Many refineries developing hydrogen management programs fit into the two general categories of either a catalytic-reformer-supplied network or an on-purpose hydrogen supply. Some refineries depend solely on catalytic reformer(s) as their source of hydrogen for hydrotreating. Often, they are semi-regenerative reformers where off-gas hydrogen quantity, purity, and availability change with feed naphtha quality, as octane requirements change seasonally, and when the reformer catalyst progresses from start-of-run to end-of-run conditions and then goes offline for regeneration. Typically, during some portions of the year, refinery margins are reduced as a result of hydrogen shortages. Multiple hydrotreating units compete for hydrogen – either by selectively reducing throughput, managing intermediate tankage logistics, or running the catalytic reformer sub-optimally just to satisfy downstream hydrogen requirements. Part of the operating year still runs in hydrogen surplus, and the network may be operated with relatively low hydrogen utilization (consumption/production) at 70%–80%. Catalytic reformer off-gas hydrogen supply may swing from 75% to 85% hydrogen purity. Hydrogen purity upgrade can be achieved through some hydrotreaters by absorbing high-molecular-weight hydrocarbon derivatives. However, without supplemental hydrogen purification, critical control of hydrogen partial pressure in hydroprocessing reactors is difficult, which can affect catalyst life, feedstock flow rate, and/or the yield of naphtha (gasoline). More complex refineries, especially those with hydrocracking units, also have on-purpose hydrogen production, typically with a steam-methane reformer that utilizes refinery off-gas and supplemental natural gas as feedstock. The steam-methane reformer plant provides the swing hydrogen requirements at higher purities (92 to more than 99% hydrogen) and serves a hydrogen network configured with several purity and pressure levels. Multiple purification units allow for more optimized hydroprocessing operation by controlling hydrogen partial pressure for maximum benefit.

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6.7  REFINING VISCOUS FEEDSTOCKS Over the past several decades, the crude oil feedstocks available to refineries have generally decreased in API gravity (Speight, 2005, 2011, 2014). There is, nevertheless, a major focus in refineries on the ways in which viscous feedstocks (such as heavy crude oil, extra heavy crude oil, tar sand bitumen, and residua) can be converted into low-boiling high-value products (Khan and Patmore, 1997; Speight and Ozum, 2002; Parkash, 2003; Speight, 2005; Hsu and Robinson, 2006; Gary et al., 2007; Rana et al., 2007; Rispoli et al., 2009; Stratiev and Petkov, 2009; Stratiev et al., 2009: Motaghi et al., 2010, ; Speight, 2011, 2014). Simultaneously, the changing crude oil properties are reflected in changes such as an increase in asphaltene constituents, and an increase in sulfur, metal, and nitrogen contents. Pretreatment processes for removing such constituents or at least negating their effect in thermal process would also play an important role. The limitations of processing these viscous feedstocks depend to a large extent on the amount of higher molecular weight constituents (i.e., asphaltene constituents and resin constituents) that contain the majority of the heteroatom-containing compounds, which are responsible for high yields of thermal and catalytic coke (Speight, 2014). Be that as it may, the essential step required of a modern refinery is the upgrading of viscous feedstocks, particularly atmospheric and vacuum residua. Upgrading viscous feedstocks began with the introduction of hydrodesulfurization processes (Speight, 2000; Ancheyta and Speight, 2007). In the early days, the goal was desulfurization but, in later years, the processes were adapted to a 10%–30% partial conversion operation, as intended to achieve desulfurization and obtain low-boiling fractions simultaneously, by increasing severity in operating conditions. However, as refineries have evolved and the feedstocks have morphed into more viscous and blended feedstocks, refining the viscous feedstocks has become a major issue in the modern refinery and several process configurations have been developed to accommodate the viscous feedstocks and any associated blends (Khan and Patmore, 1997; Speight, 2011, 2014, 2017). For example, hydrodesulfurization of light (low-boiling) distillate (naphtha or kerosene) is one of the more common catalytic hydrodesulfurization processes since it is usually used as a pretreatment of such feedstocks prior to deep hydrodesulfurization or prior to catalytic reforming. A similar concept of pretreating residua prior to hydrocracking to improve the quality of the products is also practiced (Speight, 2011, 2014). Hydrodesulfurization of such feedstocks is required because sulfur compounds poison the precious-metal catalysts used in the hydrocracking process can be achieved under relatively mild conditions. If the feedstock arises from a cracking operation (such as cracked residua), hydro-pretreatment will be accompanied by some degree of saturation, resulting in increased hydrogen consumption. Finally, there is not one single process that can be applied to all viscous feedstock that will fit all refineries. Factors such as (1) feedstock composition and (2) existing refinery configuration have a significant effect on the final configuration. Furthermore, a proper evaluation, however, is not a simple undertaking for an existing refinery. The evaluation starts with an accurate understanding of the market for the various products along with corresponding product values at various levels of supply. The next step is to select a set of crude oils that adequately cover the range of crude oils that may be expected to be processed. It is also important to consider new unit capital costs as well as incremental capital costs for revamp opportunities along with the incremental utility, support, and infrastructure costs. The costs, although estimated at the start, can be better assessed once the options have been defined, leading to the development of the optimal configuration for refining the incoming feedstocks.

REFERENCES Al-Shamma, L.M., and Naman, S.A. 1989. Kinetic Study for Thermal Production of Hydrogen from Hydrogen Sulfide by Heterogeneous Catalysis of Vanadium Sulfide in a Flow System. International Journal of Hydrogen Energy, 14(3): 173–179. Ancheyta, J., and Speight, J.G. 2007. Hydroprocessing of Heavy Oils and Residua. CRC Press, Taylor & Francis Group, Boca Raton, Florida.

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Arild, V. 2000. Production of Hydrogen and Carbon with a Carbon Black Catalyst. PCT Int. Appl. No. 0021878. Ayabe, S., Omoto, H., and Utaka, T. 2003. Catalytic Autothermal Reforming of Methane and Propane over Supported Metal Catalysts. Applied Catalysis A, 241(1–2): 261–269. Balasubramanian, B., Ortiz, A.L., Kaytakoglu, S., and Harrison, D.P. 1999. Hydrogen from Methane in a Single-Step Process. Chemical Engineering Science, 54: 3543–3552. Balat, H., and Kirtay, E. 2010. Hydrogen from Biomass - Present Scenario and Future Prospects. International Journal of Hydrogen Energy, 35(14): 7416–7426. Bandermann, F., and Harder, K.B. 1982. Production of Hydrogen via Thermal Decomposition of Hydrogen Sulfide and. Separation of Hydrogen and Hydrogen Sulfide by Pressure Swing Adsorption. International Journal of Hydrogen Energy, 7(6): 471–475. Bezler, J. 2003. Optimized Hydrogen Production – A Key Process Becoming Increasingly Important in Refineries. Proceedings. DGMK Conference on Innovation in the Manufacture and Use of Hydrogen. Dresden, Germany. October 15–17, p. 65. Bishara, A., Salman, O.S., Khraishi, N., and Marafi, A. 1987. Thermochemical Decomposition of Hydrogen Sulfide by Solar Energy. International Journal of Hydrogen Energy, 12(10): 679–685. Brandmair, M., Find, J., and Lercher, J.A. 2003. Combined Autothermal Reforming and Hydrogenolysis of Alkanes. Proceedings. DGMK Conference on Innovation in the Manufacture and Use of Hydrogen. Dresden, Germany. October 15–17, p. 273. Bressan, L., Collodi, G., and Ruggeri, F. 2009. Hydrogen Generation for Modern Refineries. Digital Refining. https://www.digitalrefining.com/article/1000044/hydrogen-generation-for-modern-refineries Brüschke, H. 1995. Industrial Application of Membrane Separation Processes. Pure and Applied Chemistry, 67(6): 993–1002. Brüschke, H. 2003. Separation of Hydrogen from Dilute Streams (e.g. Using Membranes). Proceedings. DGMK Conference on Innovation in the Manufacture and Use of Hydrogen. Dresden, Germany. October 15–17, p. 47. Clark, P.D., Dowling, N.I., Hyne, J.B., and, Moon, D.L. 1995. Production of Hydrogen and Sulfur from Hydrogen Sulfide in Refineries and Gas Processing Plants. Quarterly Bulletin-Alberta Sulphur Research Ltd, 32(1): 11–28. Clark, P.D., and Wassink B. 1990. A Review of Methods for the Conversion of Hydrogen Sulfide to Sulfur and Hydrogen. Alberta Sulfur Research Quarterly Bulletin, 26(2): 3. Cruz, F.E., and de Oliveira Junior, S. 2008. Petroleum Refinery Hydrogen Production Unit: Exergy and Production Cost Evaluation. International Journal of Thermodynamics, 11(4): 187–193. Dalrymple, D.A., Trofe, T.W., and Leppin, D. 1994. Gas Industry Assesses New Ways to Remove Small Amounts of Hydrogen Sulfide. Oil & Gas Journal, 92: 54–60. Davis, B.H., and Occelli, M.L. (Editors). 2010. Advances in Fischer-Tropsch Synthesis, Catalysts, and Catalysis. CRC Press, Taylor & Francis Group, Boca Raton, Florida. Davis, R.A., and Patel, N.M. 2004. Refinery Hydrogen Management. Petroleum Technology Quarterly, 9: 29–35. https://silo.tips/download/hydrogen-management-has Dickenson, R.L., Biasca, F.E., Schulman, B.L., and Johnson, H.E. 1997. Refiner Options for Converting and Utilizing Heavy Fuel Oil. Hydrocarbon Processing, 76(2): 57. Dolbear, G.E. 1998. Hydrocracking: Reactions, Catalysts, and Processes. In Petroleum Chemistry and Refining, J.G. Speight (Editor). Taylor & Francis, Washington, DC. Donini, J. C. 1996. Separation and Processing of Hydrogen Sulfide in the Fossil Fuel Industry. Minimum Effluent Mills Symposium, pp. 357–363. Ehteshami, S.M.M., and Chan, S.H. 2014 Techno-Economic Study of Hydrogen Production via Steam Reforming of Methanol, Ethanol, and Diesel. Energy Technology & Policy: An Open Access Journal, 1(1): 15–22. http://dx.doi.org/10.1080/23317000.2014.933087 Ehwald, H., Kürschner, U., Smejkal, Q., and Lieske, H. 2003. Investigation of Different Catalysts for Autothermal Reforming of i-Octane. Proceedings. DGMK Conference on Innovation in the Manufacture and Use of Hydrogen. Dresden, Germany. October 15–17, p. 345. Find, J., Nagaoka, K., and Lercher, J.A. 2003. Steam Reforming of Light Alkanes in Micro-Structured Reactors. Proceedings. DGMK Conference on Innovation in the Manufacture and Use of Hydrogen. Dresden, Germany. October 15–17, p. 257. Funk, J.E. 2001. Thermochemical Hydrogen Production: Past and Present. International Journal of Hydrogen Energy, 26(3): 185–190. Gary, J.H., Handwerk, G.E., and Kaiser, M.J. 2007. Petroleum Refining: Technology and Economics 5th Edition. CRC Press, Taylor & Francis Group, Boca Raton, Florida. Gaudernack, B. 1996. Hydrogen from Natural Gas without Release of Carbon Dioxide into the Atmosphere. Hydrogen Energy Prog. Proceedings. 11th World Hydrogen Energy Conference, Vol. 1, pp. 511–523.

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Gross, M., and Wolff, J. 2000. Gasification of Residue as a Source of Hydrogen for the Refining Industry in India. Proceedings. Gasification Technologies Conference. San Francisco, California. October 8–11. Hsu, C.S., and Robinson, P.R. (Editors) 2006. Practical Advances in Petroleum Processing Volume 1 and Volume 2. Springer Science, New York. Hufton, J.R., Mayorga, S., and Sircar, S., 1999. Sorption-Enhanced Reaction Process for Hydrogen Production. AIChE Journal, 45: 248–256. Joensen, F., and Rostrup-Nielsen, J.R. 2002. Conversion of Hydrocarbons and Alcohols for Fuel Cells. Journal of Power Sources, 105(2): 195–201. Kalamaras, C.M., and Efstathiou, A.M. 2012. Hydrogen Production Technologies: Current State and Future Developments. Conference Papers in Energy. Hindawi Publishing Corporation, Vol. 2013, p. 690627. http://dx.doi.org/10.1155/2013/690627 Khan, M.R., and Patmore, D.J. 1997. Heavy Oil Upgrading Processes. In Petroleum Chemistry and Refining, J.G. Speight (Editor). Taylor & Francis, Washington, DC. Kiuchi, H. 1982. Recovery of Hydrogen from Hydrogen Sulfide with Metals and Metal Sulfides. International Journal of Hydrogen Energy, 7(6): 477–482. Kotera, Y., Todo, N., and Fukuda, K. 1976. Process for Production of Hydrogen and Sulfur from Hydrogen Sulfide as Raw Material. U.S. Patent No. 3,962,409. June 8. Lewis, M.A., Serban, M., and Basco, J.K. 2003. Hydrogen Production at Ni-Mo > Co-Mo > Co-W.

Nickel-tungsten (Ni-W) and nickel-molybdenum (Ni-Mo) on Al2O3 catalysts are widely used to reduce sulfur, nitrogen, and aromatics levels in crude oil fractions by hydrotreating. Molybdenum sulfide (MoS2), usually supported on alumina, is widely used in crude oil processes for hydrogenation reactions. It is a layered structure that can be made much more active by addition of cobalt or nickel. When promoted with cobalt sulfide (CoS), making what is called cobalt-moly catalysts, it is widely used in HDS processes. The nickel sulfide-promoted version is used for HDN as well as HDS. The closely related tungsten compound (WS2) is used in commercial hydrocracking catalysts. Other sulfides (iron sulfide, FeS, chromium sulfide, Cr2S3, and vanadium sulfide, V2S5) are also effective and used in some catalysts. A valuable alternative to the base metal sulfides is palladium sulfide (PdS). Although it is expensive, palladium sulfide forms the basis for several very active catalysts. The life of a catalyst used to hydrotreat viscous feedstocks is dependent on the rate of carbon deposition and the rate at which organometallic compounds decompose and form metal sulfides on the surface of the catalyst. A variety of metal-containing constituents exist in the asphaltene fraction of the viscous feedstocks, and although a specific reaction mechanism of decomposition that would be a perfect fit for all of the metal-containing constituents would be difficult, if not impossible, in general terms, the reaction can be described as hydrogen that is dissolved in the feedstock contacting an organometallic compound (represented as A) at the surface of the hydrotreating catalyst and producing a metal sulfide (represented as B) and a hydrocarbon derivative (represented as C):

A → B + C.

Different rates of reaction may occur with various types and concentrations of metallic compounds. For example, a medium-metal-content feedstock will generally have a lower rate of demetallization compared to high-metal-content feedstock. And, although individual organometallic compounds decompose according to both first- and second-order rate expressions, for reactor design, a secondorder rate expression is applicable to the decomposition of residuum as a whole. Obviously, choice of hydrogenation catalyst depends on what the catalyst designer wishes to accomplish. In catalysts to make naphtha, for instance, vigorous cracking is needed to convert a large fraction of the feed to the kinds of molecules that will make a good gasoline blending stock.

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For this vigorous cracking, a vigorous hydrogenation component is needed. Since palladium is the most active catalyst for this, the extra expense is warranted. On the other hand, many refiners wish only to make acceptable diesel, a less demanding application. For this, the less expensive molybdenum sulfides are adequate.

7.4  FOULING DURING HYDROCRACKING Hydrocracking is a refining technology that, like hydrotreating (Chapter 5) (Speight, 2000; Parkash, 2003; Gary et al., 2007; Speight, 2014a; Hsu and Robinson, 2017; Speight, 2017), also falls under the general umbrella of hydroprocessing and the result of the process is the conversion of a variety of feedstocks (including the viscous feedstocks) to a range of products and units to accomplish this goal can be found at various points in a refinery. The outcome is the conversion of a variety of feedstocks (such as gas oil, cycle oil, residual fuel oil, reduced crude, heavy oil, extra heavy oil, and tar sand bitumen) to a range of products (Speight, 2005, 2013). These feedstocks are the most difficult to process and cannot be cracked effectively without excessive coke production and catalyst fouling in catalytic cracking units (Parkash, 2003; Gary et al., 2007; Speight, 2014a; Hsu and Robinson, 2017; Speight, 2017). In the process, cracking occurs under hydrogen (1,200–2,000 psi). In some cases, the feedstock is first hydrotreated to remove impurities before being sent to the catalytic hydrocracker – hydrotreating can be accomplished by using the first reactor of the two-reactor hydrocracking process. Water has a detrimental effect on some hydrocracking catalysts and must be removed before the feedstock is sent to the reactor. The water is removed by passing the feed stream through a silica gel or molecular sieve dryer. Depending on the products desired and the size of the unit, catalytic hydrocracking is conducted in either single-stage or multi-stage reactor processes and, typically, the catalysts consist of a crystalline mixture of silica-alumina with small amounts of rare earth metals. The mechanism of hydrocracking is basically similar to that of catalytic cracking but with concurrent hydrogenation (Parkash 2003; Gary et al., 2007; Speight, 2014a; Hsu and Robinson, 2017; Speight, 2017). The rapid hydrogenation reaction prevents adsorption of olefins on the catalyst and, hence, prevents their subsequent dehydrogenation, which ultimately leads to coke formation so that long on-stream times can be obtained without the necessity of catalyst regeneration. One of the most important reactions in hydrocracking is the partial hydrogenation of polycyclic aromatics followed by rupture of the saturated rings to form substituted monocyclic aromatics. The side chains may then be split off to give iso-paraffins. Side chains of three or four carbon atoms are easily removed from an aromatic ring during catalytic cracking, but the reaction of aromatic rings with shorter side chains appears to be quite different. For example, hydrocracking single-ring aromatics containing four or more methyl groups produces largely iso-butane and benzene. It may be that successive isomerization of the feed molecule adsorbed on the catalyst occurs until a fourcarbon side chain is formed, which then breaks off to yield iso-butane and benzene. Overall, coke formation is very low in hydrocracking since the secondary reactions and the reactions that produce precursors to coke are suppressed as the hydrogen pressure is increased. Hydrocracking, like any upgrading process, is evaluated on the basis of liquid yield (i.e., naphtha, distillate, and gas oil), heteroatom removal efficiency, feedstock conversion (FC), carbon mobilization (CM), and hydrogen utilization (HU), along with other process characteristics. Thus,

Feedstock conversion, FC = ( Feedstock IN – Feedstock OUT ) / Feedstock IN × 100



Carbon mobilization, CM = Carbon LIQUIDS / Carbon FEEDSTOCK × 100



Hydrogen utilization, HU = Hydrogen LIQUIDS / Hydrogen FEEDSTOCK × 100.

High CM (90% bitumen. Girbotol process a continuous, regenerative process to separate hydrogen sulfide, carbon dioxide, and other acid impurities from natural gas, refinery gas, etc., using mono-, di-, or triethanolamine as the reagent. Glance pitch an asphaltite. Glycol-amine gas treating a continuous, regenerative process to simultaneously dehydrate and remove acid gases from natural gas or refinery gas. Grahamite an asphaltite. Grassland All open land used primarily for pasture and grazing, including shrub   pasture and range and brush land types of pasture; grazing land with sagebrush and scattered mesquite; and all tame and native grasses, legumes, and other forage used for pasture or grazing; because of the diversity in vegetative composition, grassland pasture and range are not always clearly distinguishable from other types of pasture and range; at one extreme, permanent grassland may merge with cropland pasture, or grassland may often be found in transitional areas with forested grazing land. Gravity see API gravity. Gravity drainage the movement of oil in a reservoir that results from the force of gravity. Gravity segregation partial separation of fluids in a reservoir caused by the gravity force acting on differences in density. Gravity-stable the displacement of oil from a reservoir by a fluid of a different density,  displacement where the density difference is utilized to prevent gravity segregation of the injected fluid. Gray clay treating a fixed-bed, usually fuller’s earth, vapor-phase treating process to selectively polymerize unsaturated gum-forming constituents (diolefins) in thermally cracked gasoline. Grain alcohol see Ethyl alcohol. Gravimetric gravimetric methods weigh a residue. Gravity drainage the movement of oil in a reservoir that results from the force of gravity. Gravity segregation partial separation of fluids in a reservoir caused by the gravity force acting on differences in density. Grease car A diesel-powered automobile rigged post-production to run on used vegetable oil.

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Greenhouse effect

Glossary

T  he effect of certain gases in the Earth’s atmosphere in trapping heat from the sun. Greenhouse gases Gases that trap the heat of the sun in the Earth’s atmosphere, producing the greenhouse effect. The two major greenhouse gases are water vapor and carbon dioxide. Other greenhouse gases include methane, ozone, chlorofluorocarbons, and nitrous oxide. Grid An electric utility company’s system for distributing power. Growing stock A classification of timber inventory that includes live trees of commercial species meeting specified standards of quality or vigor; cull trees are excluded. Guard bed a bed of an adsorbent (such as, e.g., bauxite) that protects a catalyst bed by adsorbing species detrimental to the catalyst. Gulf HDS process a fixed-bed process for the catalytic hydrocracking of heavy stocks to lower boiling distillates with accompanying desulfurization. Gulfining a catalytic hydrogen treating process for cracked and straight-run distillates and fuel oils, to reduce sulfur content; improve carbon residue, color, and general stability; and effect a slight increase in gravity. Gum an insoluble tacky semi-solid material formed as a result of the storage instability and/or the thermal instability of crude oil and crude oil products. Habitat the area where a plant or animal lives and grows under natural conditions. Habitat includes living and non-living attributes and provides all requirements for food and shelter. HAP(s) hazardous air pollutant(s). Hardness the concentration of calcium and magnesium in brine. Hardwoods Usually broad-leaved and deciduous trees. HCPV hydrocarbon pore volume. Headspace the vapor space above a sample into which volatile molecules evaporate. Certain methods sample this vapor. Hearn method a method used in reservoir simulation for calculating a pseudo-relative permeability curve that reflects reservoir stratification. Heating oil see Fuel oil. Heating value The maximum amount of energy that is available from burning a substance. Heat recovery steam a heat exchanger that generates steam from the hot exhaust gases from  generator a combustion turbine. Heavy ends the highest boiling portion of a crude oil fraction; see also Light ends. Heavy fuel oil fuel oil having a high density and viscosity; generally residual fuel oil such as No. 5 and No 6. fuel oil Heavy (crude) oil oil that is more viscous than conventional crude oil, has a lower mobility in the reservoir but can be recovered through a well from the reservoir by the application of secondary or enhanced recovery methods; sometimes, crude oil having an API gravity of less than 20°. Heavy crude oil see Heavy oil. Hectare Common metric unit of area, equal to 2.47 acres. 100 ha = 1 km2. Herbaceous Non-woody type of vegetation, usually lacking permanent strong stems, such as grasses, cereals, and canola (rape). Heteroatom compounds chemical compounds which contain nitrogen and/or oxygen and/or sulfur and /or metals bound within their molecular structure(s). Heterogeneity lack of uniformity in reservoir properties such as permeability.

Glossary

HF alkylation

257

a n alkylation process whereby olefins (C3, C4, C5) are combined with iso-butane in the presence of hydrofluoric acid catalyst. Higgins-Leighton model stream-tube computer model used to simulate waterflood. Hortonsphere (Horton a spherical pressure-type tank used to store a volatile liquid which   sphere) prevents the excessive evaporation loss that occurs when such products are placed in conventional storage tanks. Hot filtration test a test for the stability of a crude oil product. Hot spot an area of a vessel or line wall appreciably above normal operating temperature, usually as a result of the deterioration of an internal insulating liner which exposes the line or vessel shell to the temperature of its contents. Houdresid catalytic a continuous moving-bed process for catalytically cracking reduced  cracking crude oil to produce high-octane gasoline and light-distillate fuels. Houdriflow catalytic a continuous moving-bed catalytic cracking process employing an  cracking integrated single vessel for the reactor and regenerator kiln. Houdriforming a continuous catalytic reforming process for producing aromatic concentrates and high-octane gasoline from low-octane straight naphtha. Houdry butane a catalytic process for dehydrogenating light hydrocarbons to their  dehydrogenation corresponding mono- or diolefins. Houdry fixed-bed a cyclic regenerable process for cracking of distillates.   catalytic cracking  Houdry hydrocracking a catalytic process combining cracking and desulfurization in the presence of hydrogen. Huff-and-puff a cyclic EOR method in which steam or gas is injected into a production well; after a short shut-in period, oil and the injected fluid are produced through the same well. Hydration the association of molecules of water with a substance. Hydraulic fracturing t he opening of fractures in a reservoir by high-pressure, high-volume injection of liquids through an injection well. Hydrocarbonaceous a material such as bitumen that is composed of carbon and hydrogen  material with other elements (heteroelements) such as nitrogen, oxygen, sulfur, and metals chemically combined within the structures of the constituents; even though carbon and hydrogen may be the predominant elements, there may be very few true hydrocarbons. Hydrocarbon compounds c hemical compounds containing only carbon and hydrogen. Hydrocarbon-producing a resource such as coal and oil shale (kerogen) which produces derived  resource hydrocarbons by the application of conversion processes; the hydrocarbons so-produced are not naturally occurring materials. Hydrocarbon resource resources such as crude oil and natural gas which can produce naturally occurring hydrocarbons without the application of conversion processes. Hydrocarbons o rganic compounds containing only hydrogen and carbon. Hydrolysis a chemical reaction in which water reacts with another substance to form one or more new substances. Hydroconversion a term often applied to hydrocracking. Hydrocracking a catalytic high-pressure high-temperature process for the conversion of crude oil feedstocks in the presence of fresh and recycled hydrogen; carbon–carbon bonds are cleaved in addition to the removal of heteroatomic species.

258

Hydrocracking catalyst Hydrodenitrogenation Hydrodesulfurization Hydrofining Hydroforming Hydrogen blistering Hydrogen addition Hydrogenation Hydrogen transfer Hydroprocesses Hydroprocessing Hydrotreating Hydrovisbreaking

Hydropyrolysis Hyperforming Hypochlorite sweetening

Idle cropland Ignitability Illuminating oil Immiscible Immiscible carbon   dioxide displacement

Glossary

a catalyst used for hydrocracking which typically contains separate hydrogenation and cracking functions. the removal of nitrogen by hydrotreating. the removal of sulfur by hydrotreating. a fixed-bed catalytic process to desulfurize and hydrogenate a wide range of charge stocks from gases through waxes. a process in which naphtha is passed over a catalyst at elevated temperatures and moderate pressures, in the presence of added hydrogen or hydrogen-containing gases, to form high-octane motor fuel or aromatics. blistering of steel caused by trapped molecular hydrogen formed as atomic hydrogen during corrosion of steel by hydrogen sulfide. an upgrading process in the presence of hydrogen, e.g., hydrocracking; see Hydrogenation. the chemical addition of hydrogen to a material. In nondestructive hydrogenation, hydrogen is added to a molecule only if, and where, unsaturation with respect to hydrogen exists. the transfer of inherent hydrogen within the feedstock constituents and products during processing. refinery processes designed to add hydrogen to various products of refining. a term often equally applied to hydrotreating and to hydrocracking; also often collectively applied to both. the removal of heteroatomic (nitrogen, oxygen, and sulfur) species by treatment of a feedstock or product at relatively low temperatures in the presence of hydrogen. a non-catalytic process, conducted under similar conditions to visbreaking, which involves treatment with hydrogen to reduce the viscosity of the feedstock and produce more stable products than is possible with visbreaking. a short-residence-time high-temperature process using hydrogen. a catalytic hydrogenation process for improving the octane number of naphtha through removal of sulfur and nitrogen compounds. the oxidation of mercaptan derivatives (RSH) in a sour feedstock by agitation with aqueous, alkaline hypochlorite solution; used where avoidance of free-sulfur addition is desired, because of a stringent copper strip requirements, and minimum expense is not the primary object. L  and in which no crops were planted; acreage diverted from crops to soil-conserving uses (if not eligible for and used as cropland pasture) under federal farm programs is included in this component. characteristic of liquids whose vapors are likely to ignite in the presence of ignition source; also characteristic of non-liquids that may catch fire from friction or contact with water and that burn vigorously. oil used for lighting purposes. two or more fluids that do not have complete mutual solubility and co-exist as separate phases. injection of carbon dioxide into an oil reservoir to effect oil displacement under conditions in which miscibility with reservoir oil is not obtained; see Carbon dioxide-augmented waterflooding.

Glossary

259

Immiscible displacement a displacement of oil by a fluid (gas or water) that is conducted under conditions so that interfaces exist between the driving fluid and the oil. Immunoassay portable tests that take advantage of an interaction between an antibody and a specific analyte. Immunoassay tests are semi-quantitative and usually rely on color changes of varying intensities to indicate relative concentrations. Incinerator Any device used to burn solid or liquid residues or wastes as a method of disposal. Incompatibility the immiscibility of crude oil products and also of different crude oils which is often reflected in the formation of a separate phase after mixing and/or storage; the phenomenon may involve any one of two of several possible events, which are (1) phase separation, (2) precipitation of asphaltene constituents when a paraffinic crude oil is blended with a viscous crude oil, (3) precipitation of asphaltene constituents when a paraffinic crude oil product is blended with a viscous crude oil, (4) when the blend is heated in pipes leading to a reactor, and also through (5) the formation of degradation products and other undesirable changes in the original properties of crude oil products. When such phenomena occur, which may not be immediately at the time of the blend but can occur after an induction period, it is often referred to as instability of the blends. See also Instability. Incremental ultimate the difference between the quantity of oil that can be recovered by  recovery EOR methods and the quantity of oil that can be recovered by conventional recovery methods. Inclined grate A type of furnace in which fuel enters at the top part of a grate in a continuous ribbon, passes over the upper drying section where moisture is removed, and descends into the lower burning section. Ash is removed at the lower part of the grate. Indirect-injection engine An older model of diesel engine in which fuel is injected into a prechamber, partly combusted, and then sent to the fuel-injection chamber. Indirect liquefaction Conversion of biomass to a liquid fuel through a synthesis gas intermediate step. Industrial wood All commercial round wood products except fuel wood. Infill drilling drilling additional wells within an established pattern. Infrared spectroscopy an analytical technique that quantifies the vibration (stretching and bending) that occurs when a molecule absorbs (heat) energy in the infrared region of the electromagnetic spectrum. Inhibitor a substance, the presence of which, in small amounts, in a crude oil product, prevents or retards undesirable chemical changes from taking place in the product, or in the condition of the equipment in which the product is used. Inhibitor sweetening a treating process to sweeten gasoline of low mercaptan content, using a phenylenediamine type of inhibitor, air, and caustic. Initial boiling point the recorded temperature when the first drop of liquid falls from the end of the condenser. Initial vapor pressure the vapor pressure of a liquid of a specified temperature and zero percent evaporated. Injection profile the vertical flow rate distribution of fluid flowing from the wellbore into a reservoir. Injection well a well in an oil field used for injecting fluids into a reservoir.

260

Injectivity In-line blending

Glossary

t he relative ease with which a fluid is injected into a porous rock. The controlled proportioning of two or more component streams to produce a final blended product of closely defined quality from the beginning to the end of the batch which permits the blended product to be used immediately for the prescribed purpose. In situ in its original place; in the reservoir. In situ combustion an EOR process consisting of injecting air or oxygen-enriched air into a reservoir under conditions that favor burning part of the in situ crude oil, advancing this burning zone, and recovering oil heated from a nearby producing well. Instability the inability of a crude oil product to exist for periods of time without change to the product. See also Incompatibility. Integrated gasification a power plant in which a gasification process provides syngas to a   combine cycle (IGCC) c ombined cycle under an integrated control system. Integrity maintenance of a slug or bank at its preferred composition without too much dispersion or mixing. Interface the thin surface area separating two immiscible fluids that are in contact with each other. Interfacial film a thin layer of material at the interface between two fluids which differs in composition from the bulk fluids. Interfacial tension the strength of the film separating two immiscible fluids, e.g., oil and water or microemulsion and oil; measured in dynes (force) per centimeter or milli-dynes per centimeter. Interfacial viscosity the viscosity of the interfacial film between two immiscible liquids. Interference testing a type of pressure transient test in which pressure is measured over time in a closed-in well, while nearby wells are produced; flow and communication between wells can sometimes be deduced from an interference test. Interphase mass the net transfer of chemical compounds between two or more phases.  transfer Iodine number a measure of the iodine absorption by oil under standard conditions; used to indicate the quantity of unsaturated compounds present; also called iodine value. Ion exchange a means of removing cations or anions from solution onto a solid resin. Ion exchange capacity a measure of the capacity of a mineral to exchange ions in amount of material per unit weight of solid. Ions  chemical substances possessing positive or negative charges in solution. Isocracking a hydrocracking process for conversion of hydrocarbons which operates at relatively low temperatures and pressures in the presence of hydrogen and a catalyst to produce more valuable, lower boiling products. Isoforming a process in which olefinic naphtha is contacted with an alumina catalyst at high temperature and low pressure to produce isomers of higher octane number. Iso-Kel process a fixed-bed, vapor-phase isomerization process using a precious metal catalyst and external hydrogen. Isomate process a continuous, non-regenerative process for isomerizing C5-C8 normal paraffin hydrocarbons, using aluminum chloride-hydrocarbon catalyst with anhydrous hydrochloric acid as a promoter.

Glossary

Isomerate process

261

a fixed-bed isomerization process to convert pentane, heptane, and heptane to high-octane blending stocks. Isomerization the conversion of a normal (straight-chain) paraffin hydrocarbon into an iso (branched-chain) paraffin hydrocarbon having the same atomic composition. Isopach a line on a map designating points of equal formation thickness. Iso-plus Houdriforming a combination process using a conventional Houdriformer operated at moderate severity, in conjunction with one of three possible alternatives – including the use of an aromatic recovery unit or a thermal reformer; see Houdriforming. Jet fuel fuel meeting the required properties for use in jet engines and aircraft turbine engines. Joule Metric unit of energy, equivalent to the work done by a force of one Newton applied over distance of one meter (= 1 kg m2/s2). One joule (J) = 0.239 calories (1 calorie = 4.187 J). Kaolinite a clay mineral formed by hydrothermal activity at the time of rock formation or by chemical weathering of rock with high feldspar content; usually associated with intrusive granite rock with high feldspar content. Kata-condensed aromatic Compounds based on linear condensed aromatic hydrocarbon systems,  compounds e.g., anthracene and naphthacene (tetracene). Kauri butanol number A measurement of solvent strength for hydrocarbon solvents; the higher the kauri butanol (KB) value, the stronger the solvency; the test method (ASTM D1133) is based on the principle that kauri resin is readily soluble in butyl alcohol but not in hydrocarbon solvents and the resin solution will tolerate only a certain amount of dilution and is reflected as a cloudiness when the resin starts to come out of solution; solvents such as toluene can be added in a greater amount (and thus have a higher KB value) than weaker solvents like hexane. Kerogen a complex carbonaceous (organic) material that occurs in sedimentary rock and shale; generally insoluble in common organic solvents. Kerosene (kerosine) a fraction of crude oil that was initially sought as an illuminant in lamps; a precursor to diesel fuel. K-factor see Characterization factor. Kilowatt (kW) A  measure of electrical power equal to 1,000 watts. 1 kW = 3,412 Btu/ hr = 1.341 horsepower. Kilowatt hour (kWh) A measure of energy equivalent to the expenditure of one kilowatt for one hour. For example, 1 kWh will light a 100-watt light bulb for 10 hours. 1 kWh = 3412 Btu. Kinematic viscosity the ratio of viscosity to density, both measured at the same temperature. Knock the noise associated with self-ignition of a portion of the fuel-air mixture ahead of the advancing flame front. Kriging a technique used in reservoir description for interpolation of reservoir parameters between wells based on random field theory. LAER Lowest achievable emission rate; the required emission rate in nonattainment permits. a test of burning oils in which the oil is burned in a standard lamp Lamp burning under specified conditions in order to observe the steadiness of the flame, the degree of encrustation of the wick, and the rate of consumption of the kerosene. see Kerosene. Lamp oil

262

Landfill gas

Glossary

A  type of biogas that is generated by decomposition of organic material at landfill disposal sites. Landfill gas is approximately 50 percent methane. See also biogas. Laterite  The name applied to both a soil and a rock type rich in iron and aluminum and is commonly considered to have formed in hot and wet tropical areas. Nearly all laterites are of rusty-red coloration, because of high iron oxide content. Leaded gasoline Gasoline containing tetraethyl lead or other organometallic lead antiknock compounds. Lean gas The residual gas from the absorber after the condensable gasoline has been removed from the wet gas. Lean oil Absorption oil from which gasoline fractions have been removed; oil leaving the stripper in a natural-gasoline plant. Lewis acid A chemical species which can accept an electron pair from a base. Lewis base A chemical species which can donate an electron pair. Light ends The lower boiling components of a mixture of hydrocarbons; see also Heavy ends and Light hydrocarbons. Light hydrocarbons hydrocarbons with molecular weights less than that of heptane  (C7H16). Light oil the products distilled or processed from crude oil up to, but not including, the first lubricating-oil distillate. Light petroleum crude oil having an API gravity greater than 20o. Lignin Structural constituent of wood and (to a lesser extent) other plant tissues, which encrusts the walls and cements the cells together. Ligroine (Ligroin) a saturated crude oil naphtha boiling in the range of 20°C–135°C (68° F–275°F) and suitable for general use as a solvent; also called benzine or crude oil ether. Linde copper sweetening a process for treating gasoline and distillates with a slurry of clay and cupric chloride. Liquid petrolatum see White oil. Liquefied petroleum gas p ropane, butane, or mixtures thereof, gaseous at atmospheric temperature and pressure, held in the liquid state by pressure to facilitate storage, transport, and handling. Liquid chromatography a chromatographic technique that employs a liquid mobile phase. Liquid/liquid extraction an extraction technique in which one liquid is shaken with or contacted by an extraction solvent to transfer molecules of interest into the solvent phase. Liquid sulfur dioxide- a mixed-solvent process for treating lubricating-oil stocks to improve   benzene process viscosity index; also used for dewaxing. Lithology the geological characteristics of the reservoir rock. Live cull A classification that includes live cull trees; when associated with volume, it is the net volume in live cull trees that are 5.0 inches in diameter and larger. Live steam steam coming directly from a boiler before being utilized for power or heat. Liver the intermediate layer of dark-colored, oily material, insoluble in weak acid and in oil, which is formed when acid sludge is hydrolyzed. Logging residues The unused portions of growing-stock and non-growing-stock trees cut or killed logging and left in the woods. Lorenz coefficient a permeability heterogeneity factor.

Glossary

Lower-phase micro  emulsion

263

a microemulsion phase containing a high concentration of water that, when viewed in a test tube, resides near the bottom with oil phase on top. Lube see Lubricating oil. Lube cut a fraction of crude oil of suitable boiling range and viscosity to yield lubricating oil when completely refined; also referred to as lube oil distillates or lube stock. Lubricating oil a fluid lubricant used to reduce friction between bearing surfaces. M85 An alcohol fuel mixture containing 85% methanol and 15% gasoline by volume. Methanol is typically made from natural gas, but can also be derived from the fermentation of biomass. Macrofouling Fouling of refinery equipment and pipes by the deposition of coarse matter from either organic or biological or inorganic origin; these deposits foul the surfaces of heat exchangers and may cause deterioration of the relevant heat transfer coefficient as well as flow blockages. See also Fouling and Microfouling. MACT maximum achievable control technology. Applies to major sources of hazardous air pollutants. Mahogany acids oil-soluble sulfonic acids formed by the action of sulfuric acid on crude oil distillates. They may be converted to their sodium soaps (mahogany soaps) and extracted from the oil with alcohol for use in the manufacture of soluble oils, rust preventives, and special greases. The calcium and barium soaps of these acids are used as detergent additives in motor oils; see also Brown acids and Sulfonic acids. Major source a source that has a potential to emit for a regulated pollutant that is at or greater than an emission threshold set by regulations. Maltene fraction a fraction of crude oil that is soluble in, e.g., pentane or heptane; deas  (maltenes fraction phaltened oil; also the term arbitrarily assigned to the pentane-soluble   or maltenes) portion of crude oil that is relatively high boiling (>300°C, 760 mm) (see also Petrolenes). Marine engine oil oil used as a crankcase oil in marine engines. Marine gasoline fuel for motors in marine service. Marine sediment the organic biomass from which crude oil is derived. Marsh an area of spongy waterlogged ground with large numbers of surface water pools. Marshes usually result from: (1) an impermeable underlying bedrock; (2) surface deposits of glacial boulder clay; (3) a basin-like topography from which natural drainage is poor; (4) very heavy rainfall in conjunction with a correspondingly low evaporation rate; (5) low-lying land, particularly at estuarine sites at or below sea level. Marx–Langenheim model mathematical equations for calculating heat transfer in hot water or steam flood. Mass spectrometer an analytical technique that fractures organic compounds into characteristic ‘fragments’ based on functional groups that have a specific mass-to-charge ratio. Mayonnaise low-temperature sludge; a black, brown, or gray deposit having a soft, mayonnaise-like consistency; not recommended as a food additive! MCL maximum contaminant level as dictated by regulations. Medicinal oil highly refined, colorless, tasteless, and odorless crude oil used as a medicine in the nature of an internal lubricant; sometimes called liquid paraffin.

264

Megawatt(MW):

Glossary

A  measure of electrical power equal to one million watts (1,000 kW). Membrane technology gas separation processes utilizing membranes that permit different components of a gas to diffuse through the membrane at significantly different rates. MDL See Method detection limit. MEK (methyl ethyl A colorless liquid (CH3COCH2CH3) used as a solvent; as a chemical   ketone) intermediate; and in the manufacture of lacquers, celluloid, and varnish removers. MEK deoiling a wax-deoiling process in which the solvent is generally a mixture of methyl ethyl ketone and toluene. MEK dewaxing a continuous solvent dewaxing process in which the solvent is generally a mixture of methyl ethyl ketone and toluene. MEOR microbial enhanced oil recovery. Methanol see Methyl alcohol. Method Detection Limit the smallest quantity or concentration of a substance that the instrument can measure. Methyl t-butyl ether a n ether added to gasoline to improve its octane rating and to decrease gaseous emissions; see Oxygenate. Mercapsol process a regenerative process for extracting mercaptan derivatives (RSH), utilizing aqueous sodium (or potassium) hydroxide containing mixed cresols as solubility promoters. Mercaptans o rganic compounds having the general formula R-SH. Metagenesis t he alteration of organic matter during the formation of crude oil that may involve temperatures above 200°C (390°F); see also Catagenesis and Diagenesis. Methyl alcohol a colorless, volatile, inflammable, and poisonous alcohol (CH 3OH)   (methanol; wood traditionally formed by destructive distillation of wood or, more recently,   alcohol) as a result of synthetic distillation in chemical plants; a fuel typically derived from natural gas, but which can be produced from the fermentation of sugars in biomass. Methyl ethyl ketone see MEK. Mica a complex aluminum silicate mineral that is transparent, tough, flexible, and elastic. Micellar fluid an aqueous mixture of surfactants, co-surfactants, salts, and hydro  (surfactant slug) carbons. The term micellar is derived from the word micelle, which is a submicroscopic aggregate of surfactant molecules and associated fluid. Micelle the structural entity by which asphaltene constituents are dispersed in crude oil. Microcarbon residue The carbon residue determined using a thermogravimetric method. See also Carbon residue. Microcrystalline wax wax extracted from certain crude oil residua and having a finer and less apparent crystalline structure than paraffin wax. Microemulsion a stable, finely dispersed mixture of oil, water, and chemicals (surfactants and alcohols). Microemulsion or an augmented waterflooding technique in which a surfactant system is   micellar/emulsion injected in order to enhance oil displacement toward producing wells.  flooding Microfouling Deposition of solids in refinery equipment or pipes in which the solid is (1) particulate fouling, which is the accumulation of particles on

Glossary

265

a surface, (2) chemical reaction fouling, such as decomposition of organic matter on heating surfaces, (3) solidification fouling, which occurs when components of a flowing fluid with a high-melting-point freeze onto a subcooled surface, (4) corrosion fouling, which is caused by corrosion, (5) biofouling, which can often ensure after biocorrosion which is due to the action of bacteria or algae, and (6) composite fouling, whereby fouling involves more than one foulant or fouling mechanism. See also Fouling and Macrofouling. Microorganisms animals or plants of microscopic size, such as bacteria. Microscopic displacement the efficiency with which an oil displacement process removes the oil  efficiency from individual pores in the rock. Mid-boiling point the temperature at which approximately 50% of a material has distilled under specific conditions. Middle distillate distillate boiling between the kerosene and lubricating oil fractions. Middle-phase micro a microemulsion phase containing a high concentration of both oil  emulsion and water that, when viewed in a test tube, resides in the middle with the oil phase above it and the water phase below it. Migration (primary) the movement of hydrocarbons (oil and natural gas) from mature, organic-rich source rocks to a point where the oil and gas can collect as droplets or as a continuous phase of liquid hydrocarbon. Migration (secondary) the movement of the hydrocarbons as a single, continuous fluid phase through water-saturated rocks, fractures, or faults followed by accumulation of the oil and gas in sediments (traps, q.v.) from which further migration is prevented. Mill residue Wood and bark residues produced in processing logs into lumber, plywood, and paper. Mineral hydrocarbons crude oil hydrocarbons, considered mineral because they come from the earth rather than from plants or animals. Mineral oil the older term for crude oil; the term was introduced in the nineteenth century as a means of differentiating crude oil (rock oil) from whale oil which, at the time, was the predominant illuminant for oil lamps. naturally occurring inorganic solids with well-defined crystalline  Minerals structures. Mineral seal oil a distillate fraction boiling between kerosene and gas oil. Mineral wax yellow to dark brown, solid substances that occur naturally and are composed largely of paraffins; usually found associated with considerable mineral matter, as a filling in veins and fissures, or as an interstitial material in porous rocks. Minimum miscibility see Miscibility.   pressure (MMP) Miscibility  an equilibrium condition, achieved after mixing two or more fluids, which is characterized by the absence of interfaces between the fluids: (1) first-contact miscibility: miscibility in the usual sense, whereby two fluids can be mixed in all proportions without any interfaces forming. Example: At room temperature and pressure, ethyl alcohol and water are first-contact miscible. (2) Multiple-contact miscibility (dynamic miscibility): miscibility that is developed by repeated enrichment of one fluid phase with components from a second fluid phase with which it comes into contact. (3) Minimum miscibility pressure: the minimum pressure above which two fluids become miscible at a given temperature, or can become miscible, by dynamic processes.

266

Miscible flooding Miscible fluid   displacement (miscible   displacement)

Glossary

see EOR process. An oil displacement process is an oil displacement process in which an alcohol, a refined hydrocarbon, a condensed crude oil gas, carbon dioxide, liquefied natural gas, or even exhaust gas is injected into an oil reservoir, at pressure levels such that the injected gas or fluid and reservoir oil are miscible; the process may include the concurrent, alternating, or subsequent injection of water. Mitigation identification, evaluation, and cessation of potential impacts of a process product or by-product. Mixed-phase cracking the thermal decomposition of higher boiling hydrocarbons to gasoline components. Mobility a measure of the ease with which a fluid moves through reservoir rock; the ratio of rock permeability to apparent fluid viscosity. Mobility buffer the bank that protects a chemical slug from water invasion and dilution and assures mobility control. Mobility control ensuring that the mobility of the displacing fluid or bank is equal to or less than that of the displaced fluid or bank. Mobility ratio ratio of mobility of an injection fluid to mobility of fluid being  displaced. Modified alkaline the addition of a co-surfactant and/or polymer to the alkaline flooding  flooding process. Modified/unmodified Traditional diesel engines must be modified to heat the oil before it   diesel engine reaches the fuel injectors in order to handle straight vegetable oil. Modified, any diesel engine can run on veggie oil; without modification, the oil must first be converted to biodiesel. Modified naphtha An insoluble fraction obtained by adding naphtha to crude oil; usu  insolubles (MNI) ally the naphtha is modified by adding paraffin constituents; the fraction might be equated to asphaltenes if the naphtha is equivalent to n-heptane, but usually it is not. The weight of the water contained in wood, usually expressed as a Moisture content (MC) percentage of weight, either oven-dry or as-received. Moisture content, dry Moisture content expressed as a percentage of the weight of oven basis wood, i.e.: [(weight of wet sample - weight of dry sample)/weight of dry sample] × 100. Moisture content, Moisture content expressed as a percentage of the weight of wood as  wet basis received, i.e.: [(weight of wet sample - weight of dry sample)/weight of wet sample] × 100. Molecular sieve a synthetic zeolite mineral having pores of uniform size; it is capable of separating molecules, on the basis of their size, structure, or both, by absorption or sieving. Motor Octane Method a test for determining the knock rating of fuels for use in spark-ignition engines; see also Research Octane Method. Moving-bed catalytic a cracking process in which the catalyst is continuously cycled between  cracking the reactor and the regenerator. MSDS Material safety data sheet. MTBE methyl tertiary butyl ether is highly refined high-octane light distillate used in the blending of gasoline. NAAQS National Ambient Air Quality Standards; standards exist for the pollutants known as the criteria air pollutants: nitrogen oxides (NOx), sulfur oxides (SOx), lead, ozone, particulate matter, less than 10 microns in diameter, and carbon monoxide (CO).

Glossary

Naft

267

A pre-Christian era (Greek) term for that evolved into the name ‘naphtha.’ Napalm  a thickened gasoline used as an incendiary medium that adheres to the surface it strikes. Naphtha a generic term applied to refined, partly refined, or unrefined crude oil products and liquid products of natural gas, the majority of which distills below 240°C (464°F); the volatile fraction of crude oil which is used as a solvent or as a precursor to gasoline. Naphthenes cycloparaffins. Native asphalt see Bitumen. Natural asphalt see Bitumen. Natural gas the naturally occurring gaseous constituents that are found in many crude oil reservoirs; there are also reservoirs in which natural gas may be the sole occupant. Natural gas liquids the hydrocarbon liquids that condense during the processing of hydro (NGL) carbon gases that are produced from oil or gas reservoir; see also Natural gasoline. Natural gasoline a mixture of liquid hydrocarbons extracted from natural gas suitable for blending with refinery gasoline. Natural-gasoline plant a plant for the extraction of fluid hydrocarbon, such as gasoline and liquefied petroleum gas, from natural gas. NESHAP National Emissions Standards for Hazardous Air Pollutants; emission standards for specific source categories that emit or have the potential to emit one or more hazardous air pollutants; the standards are modeled on the best practices and the most effective emission reduction methodologies in use at the affected facilities. Neutralization a process for reducing the acidity or alkalinity of a waste stream by mixing acids and bases to produce a neutral solution; also known as pH adjustment. Neutral oil a distillate lubricating oil with viscosity usually not above 200 seconds at 100°F. Neutralization number the weight, in milligrams, of potassium hydroxide needed to neutralize the acid in 1 g of oil; an indication of the acidity of an oil. Nitrogen fixation The transformation of atmospheric nitrogen into nitrogen compounds that can be used by growing plants. Nitrogen oxides (NOx) Products of combustion that contribute to the formation of smog and ozone. Non-forest land Land that has never supported forests and lands formerly forested where use of timber management is precluded by development for other uses; if intermingled in forest areas, unimproved roads and nonforest strips must be more than 120-feet wide, and clearings, etc., must be more than 1 acre in area to qualify as non-forest land. Non-asphaltic road oil any of the non-hardening crude oil distillates or residual oils used as dust layers. They have sufficiently low viscosity to be applied without heating and, together with asphaltic road oils, are sometimes referred to as dust palliatives. Non-attainment area Any area that does not meet the national primary or secondary ambient air quality standard established (by the Environmental Protection Agency) for designated pollutants, such as carbon monoxide and ozone.

268

Non-industrial private

Glossary

A  n ownership class of private lands where the owner does not operate wood processing plants. Non-ionic surfactant a surfactant molecule containing no ionic charge. Non-Newtonian a fluid that exhibits a change of viscosity with flow rate. NOx The oxides of nitrogen. Nuclear magnetic an analytical procedure that permits the identification of complex mol  resonance spectroscopy ecules based on the magnetic properties of the atoms they contain. No. 1 Fuel oil very similar to kerosene and is used in burners where vaporization before burning is usually required and a clean flame is specified. No. 2 Fuel oil also called domestic heating oil; has properties similar to diesel fuel and heavy jet fuel; used in burners where complete vaporization is not required before burning. No. 4 Fuel oil a light industrial heating oil and is used where preheating is not required for handling or burning; there are two grades of No. 4 fuel oil, differing in safety (flash point) and flow (viscosity) properties. No. 5 Fuel oil a heavy industrial fuel oil which requires preheating before burning. No. 6 Fuel oil a heavy fuel oil and is more commonly known as Bunker C oil when it is used to fuel ocean-going vessels; preheating is always required for burning this oil. Observation wells wells that are completed and equipped to measure reservoir conditions and/or sample reservoir fluids, rather than to inject produced reservoir fluids. Octane barrel yield a measure used to evaluate fluid catalytic cracking processes; defined as (RON + MON)/2 times the gasoline yield, where RON is the research octane number and MON is the motor octane number. Octane number a number indicating the antiknock characteristics of gasoline. Oil bank see Bank. Oil breakthrough (time) the time at which the oil-water bank arrives at the producing well. Oil from tar sand synthetic crude oil. Oil mining application of a mining method to the recovery of bitumen. Oil originally in place the quantity of crude oil existing in a reservoir before oil recovery  (OOIP) operations begin. Oils that portion of the maltenes that is not adsorbed by a surface-active material such as clay or alumina. Oil sand see Tar sand. Oil shale a fine-grained impervious sedimentary rock which contains an  organic material called kerogen. Olefin synonymous with alkene. OOIP see Oil originally in place. Open-loop biomass Biomass that can be used to produce energy and bio-products even though it was not grown specifically for this purpose; include agricultural livestock waste, residues from forest harvesting operations, and crop harvesting. Optimum salinity the salinity at which a middle-phase microemulsion containing equal concentrations of oil and water results from the mixture of a micellar fluid (surfactant slug) with oil. Organic sedimentary rocks containing organic material such as residues of plant and ani rocks mal remains/decay. Orifice-plate mixer A mixer in which two or more liquids are pumped through an orifice   (orifice mixer) constriction to cause turbulence and consequent mixing action.

Glossary

Overhead

269

a portion of the feedstock which is vaporized and removed during distillation. Override the gravity-induced flow of a lighter fluid in a reservoir above another heavier fluid. Oxidation a process which can be used for the treatment of a variety of inorganic and organic substances. Oxidized asphalt see Air-blown asphalt. Ozokerite (Ozocerite) a naturally occurring wax; when refined also known as ceresin. Oxygenate an oxygen-containing compound that is blended into gasoline to  improve its octane number and decrease gaseous emissions; a substance which, when added to gasoline, increases the amount of oxygen in that gasoline blend; includes fuel ethanol, methanol, and methyl tertiary butyl ether (MTBE). Oxygenated gasoline gasoline with added ethers or alcohols, formulated according to the Federal Clean Air Act to reduce carbon monoxide emissions during winter months. Oxygen scavenger a chemical which reacts with oxygen in injection water, used to prevent degradation of polymer. Pale oil a lubricating oil or a process oil refined until its color, by transmitted light, is straw to pale yellow. Paraffinum liquidum see Liquid petrolatum. Paraffin wax the colorless, translucent, highly crystalline material obtained from the light lubricating fractions of paraffin crude oils (wax distillates). Particle density the density of solid particles. Particulate A small, discrete mass of solid or liquid matter that remains individually dispersed in gas or liquid emissions. Particulate emissions particles of a solid or liquid suspended in a gas, or the fine particles of carbonaceous soot and other organic molecules discharged into the air during combustion. Particulate matter particles in the atmosphere or on a gas stream that may be organic or   (particulates) inorganic and originate from a wide variety of sources and processes. Particle size distribution the particle size distribution (of a catalyst sample) expressed as a percent of the whole. Partitioning in chromatography, the physical act of a solute having different affinities for the stationary and mobile phases. Partition ratios, K the ratio of total analytical concentration of a solute in the stationary phase, CS, to its concentration in the mobile phase, CM. Pattern the areal pattern of injection and producing wells selected for a secondary or enhanced recovery project. Pattern life the length of time a flood pattern participates in oil recovery. Pay zone thickness the depth of a tar sand deposit from which bitumen (or a product) can be recovered. Penex process a continuous, non-regenerative process for isomerization of C5 and/ or C6 fractions in the presence of hydrogen (from reforming) and a platinum catalyst. Pentafining a pentane isomerization process using a regenerable platinum catalyst on a silica-alumina support and requiring outside hydrogen. Pepper sludge the fine particles of sludge produced in acid treating which may remain in suspension.

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Glossary

Peri-condensed aromatic Compounds based on angular condensed aromatic hydrocarbon sys compounds tems, such as phenanthrene, chrysene, picene, and other similar condensed aromatic hydrocarbon derivatives. Permeability the ease of flow of the water through the rock. Petrol a term commonly used in some countries for gasoline. Petrolatum a semi-solid product, ranging from white to yellow in color, produced during refining of residual stocks; see Petroleum jelly. Petrolenes the term applied to that part of the pentane-soluble or heptane-soluble material that is low boiling (