Solvent Processes in Refining Technology (Petroleum Refining Technology Series) [1 ed.] 1032028009, 9781032028002

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Solvent Processes in Refining Technology This book focuses on the various solvent processes that are used in crude oil refineries. It presents the differences between each type of process and discusses the types of feedstock that can be used for the processes. This accessible guide is written for managers, professionals, and technicians as well as graduate students transitioning into the refining industry.

KEY FEATURES: • Describes the various steps that are necessary for the solvent treatment of various feedstocks in crude oil refineries. • Brings the reader up to date and adds more data. • Provides an extensive glossary. • Considers next-generation processes and developments.

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 Solvent Processes in Refining Technology James G. Speight

Solvent Processes in Refining Technology

James G. Speight

Designed cover image: © shutterstock First edition published 2024 by CRC Press 2385 NW Executive Center Drive, Suite 320, Boca Raton FL 33431 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 publishers 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: 978-1-032-02800-2 (hbk) ISBN: 978-1-032-02806-4 (pbk) ISBN: 978-1-003-18527-7 (ebk) DOI: 10.1201/9781003185277 Typeset in Times by Apex CoVantage, LLC

Contents Preface�����������������������������������������������������������������������������������������������������������������������������������������������ix About the Author�������������������������������������������������������������������������������������������������������������������������������xi Chapter 1 Solvents in the Refinery����������������������������������������������������������������������������������������������� 1 1.1 Introduction������������������������������������������������������������������������������������������������������� 1 1.2 Types of Solvents����������������������������������������������������������������������������������������������� 7 1.3 Production of Solvents in the Refinery�������������������������������������������������������������� 7 1.3.1 Naphtha������������������������������������������������������������������������������������������������9 1.3.2 Kerosene��������������������������������������������������������������������������������������������� 14 1.3.3 Middle Distillates������������������������������������������������������������������������������� 16 1.3.4 Other Solvents������������������������������������������������������������������������������������ 17 1.3.5 Water as a Solvent������������������������������������������������������������������������������ 17 1.4 Solvent-Based Processes��������������������������������������������������������������������������������� 18 1.4.1 Refining Processes����������������������������������������������������������������������������� 18 1.4.2 Gas Processing Operations���������������������������������������������������������������� 21 1.5 Solvent Processes�������������������������������������������������������������������������������������������� 22 1.5.1 Deasphalting Processes���������������������������������������������������������������������� 23 1.5.2 Dewaxing Processes���������������������������������������������������������������������������24 1.5.3 Solvent Extraction Processes��������������������������������������������������������������25 References������������������������������������������������������������������������������������������������������������������ 33 Chapter 2 Deasphalting Processes���������������������������������������������������������������������������������������������� 35 2.1 Introduction����������������������������������������������������������������������������������������������������� 35 2.2 Feedstocks������������������������������������������������������������������������������������������������������� 37 2.2.1 Types of Feedstocks��������������������������������������������������������������������������� 37 2.2.2 Feedstock Evaluation������������������������������������������������������������������������� 38 2.3 Process Principles�������������������������������������������������������������������������������������������� 45 2.4 Process Parameters������������������������������������������������������������������������������������������ 48 2.4.1 Feedstock Selection���������������������������������������������������������������������������� 48 2.4.2 The Process���������������������������������������������������������������������������������������� 48 2.5 Process Options����������������������������������������������������������������������������������������������� 54 2.5.1 Deep Solvent Deasphalting���������������������������������������������������������������� 54 2.5.2 Demex������������������������������������������������������������������������������������������������ 55 2.5.3 MDS��������������������������������������������������������������������������������������������������� 56 2.5.4 Residuum Oil Supercritical Extraction���������������������������������������������� 57 2.5.5 Solvahl������������������������������������������������������������������������������������������������ 57 2.5.6 Lube Deasphalting����������������������������������������������������������������������������� 57 2.5.7 Other Options������������������������������������������������������������������������������������� 58 2.6 Integration with Other Processes�������������������������������������������������������������������� 58 2.7 Fouling during Deasphalting��������������������������������������������������������������������������� 59 References������������������������������������������������������������������������������������������������������������������ 60

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Chapter 3 Dewaxing Processes��������������������������������������������������������������������������������������������������� 63 3.1 Introduction����������������������������������������������������������������������������������������������������� 63 3.2 Composition and Properties of Waxes������������������������������������������������������������64 3.2.1 Composition��������������������������������������������������������������������������������������� 65 3.2.2 Wax Appearance Temperature or Cloud Point����������������������������������66 3.2.3 Factors Controlling Wax Deposition��������������������������������������������������66 3.2.4 Wax Deposition Mechanism�������������������������������������������������������������� 67 3.3 Process Principles�������������������������������������������������������������������������������������������� 68 3.3.1 Non-Catalytic Dewaxing�������������������������������������������������������������������� 70 3.3.2 Catalytic Dewaxing���������������������������������������������������������������������������� 71 3.4 Feedstocks������������������������������������������������������������������������������������������������������� 73 3.4.1 Feedstock Evaluation������������������������������������������������������������������������� 74 3.4.2 Use of the Data����������������������������������������������������������������������������������� 79 3.5 Process Options�����������������������������������������������������������������������������������������������80 3.5.1 The Dewaxing Process�����������������������������������������������������������������������80 3.5.2 Optional Processes����������������������������������������������������������������������������� 82 3.6 Fouling during Dewaxing�������������������������������������������������������������������������������84 References������������������������������������������������������������������������������������������������������������������ 86 Chapter 4 Solvent-Based Processes�������������������������������������������������������������������������������������������� 89 4.1 Introduction����������������������������������������������������������������������������������������������������� 89 4.2 Solvent-Based Processes���������������������������������������������������������������������������������90 4.3 Commercial Processes������������������������������������������������������������������������������������ 93 4.3.1 Caustic Processes������������������������������������������������������������������������������� 95 4.3.2 Acid Processes������������������������������������������������������������������������������������ 98 4.3.3 Solvent–Clay Processes�������������������������������������������������������������������� 100 4.3.4 Oxidative Processes������������������������������������������������������������������������� 103 4.4 Solvent Extraction����������������������������������������������������������������������������������������� 107 4.4.1 Processes������������������������������������������������������������������������������������������ 107 4.4.2 Other Options����������������������������������������������������������������������������������� 112 References���������������������������������������������������������������������������������������������������������������� 112 Chapter 5 Gas-Treating Processes�������������������������������������������������������������������������������������������� 114 5.1 Introduction��������������������������������������������������������������������������������������������������� 114 5.2 Gas Streams��������������������������������������������������������������������������������������������������� 114 5.2.1 Gas Streams from Crude Oil������������������������������������������������������������ 115 5.2.2 Natural Gas�������������������������������������������������������������������������������������� 118 5.2.3 Other Gas Streams��������������������������������������������������������������������������� 119 5.3 Chemical Solvent Processes�������������������������������������������������������������������������� 126 5.3.1 Glycol Processes������������������������������������������������������������������������������� 128 5.3.2 Olamine Processes��������������������������������������������������������������������������� 129 5.4 Physical Solvent Processes���������������������������������������������������������������������������� 133 5.4.1 Fluor Process������������������������������������������������������������������������������������ 134 5.4.2 Rectisol Process������������������������������������������������������������������������������� 135 5.4.3 Selexol Process��������������������������������������������������������������������������������� 135 5.4.4 Sulfinol Process�������������������������������������������������������������������������������� 135 5.5 Methanol-Based Processes���������������������������������������������������������������������������� 136 5.6 Water Washing Processes������������������������������������������������������������������������������ 137 5.6.1 Wet Scrubbing���������������������������������������������������������������������������������� 137 5.6.2 Other Methods���������������������������������������������������������������������������������� 138

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5.6.3 Solids Blowdown������������������������������������������������������������������������������ 139 5.6.4 Deposit Control�������������������������������������������������������������������������������� 140 5.6.5 Monitoring���������������������������������������������������������������������������������������� 140 5.7 Alkali Washing Processes����������������������������������������������������������������������������� 142 5.7.1 Caustic Scrubbing���������������������������������������������������������������������������� 142 5.7.2 Hot Potassium Carbonate Process���������������������������������������������������� 143 5.7.3 Other Processes�������������������������������������������������������������������������������� 143 References���������������������������������������������������������������������������������������������������������������� 144 Chapter 6 Biomass, Bio-oil, and Biogas Treating Processes���������������������������������������������������� 146 6.1 Introduction��������������������������������������������������������������������������������������������������� 146 6.2 Biomass Resources���������������������������������������������������������������������������������������� 148 6.2.1 Categories����������������������������������������������������������������������������������������� 150 6.2.2 Types������������������������������������������������������������������������������������������������ 153 6.2.3 Waste������������������������������������������������������������������������������������������������ 156 6.3 Evaluation������������������������������������������������������������������������������������������������������ 160 6.4 Refinery Streams from Biomass�������������������������������������������������������������������� 161 6.4.1 Biogas����������������������������������������������������������������������������������������������� 161 6.4.2 Landfill Gas�������������������������������������������������������������������������������������� 163 6.4.3 Synthesis Gas����������������������������������������������������������������������������������� 164 6.4.4 Product Treating������������������������������������������������������������������������������� 164 6.5 Preparation for Processing���������������������������������������������������������������������������� 168 6.5.1 Properties����������������������������������������������������������������������������������������� 169 6.5.2 Pretreatment������������������������������������������������������������������������������������� 169 6.6 Extraction������������������������������������������������������������������������������������������������������ 172 References���������������������������������������������������������������������������������������������������������������� 174 Chapter 7 The Future of Solvent Processes������������������������������������������������������������������������������ 178 7.1 Introduction��������������������������������������������������������������������������������������������������� 178 7.2 History����������������������������������������������������������������������������������������������������������� 178 7.3 Refinery Configuration���������������������������������������������������������������������������������� 181 7.3.1 Crude Oil Refinery��������������������������������������������������������������������������� 181 7.3.2 Biorefinery���������������������������������������������������������������������������������������� 183 7.3.3 Coal Liquids Refinery���������������������������������������������������������������������� 188 7.3.4 Shale Oil Refinery���������������������������������������������������������������������������� 189 7.3.5 Gasification Refinery������������������������������������������������������������������������ 190 7.4 Products from Alternate Feedstocks������������������������������������������������������������� 192 7.4.1 Gaseous Fuels����������������������������������������������������������������������������������� 193 7.4.2 Liquid Fuels�������������������������������������������������������������������������������������� 194 7.4.3 Solid Fuels���������������������������������������������������������������������������������������� 195 7.5 The Reconfigured Refinery��������������������������������������������������������������������������� 195 7.6 The Future of Solvent Refining and Gas Processing�������������������������������������200 References���������������������������������������������������������������������������������������������������������������� 205 Glossary����������������������������������������������������������������������������������������������������������������������������������������207 Conversion Factors���������������������������������������������������������������������������������������������������������������������� 255 Index���������������������������������������������������������������������������������������������������������������������������������������������� 257

Preface This series of eight books is designed to present 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 pretreatment 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 viscous feedstocks; (4) the development of advanced hydrocracking processes for heavy feedstock upgrading; (5) the development of innovative upgrading processes for 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 for the potential processes of the evolving 21st century. As the fifth book in the series, this book will focus on the various solvent processes that are used in crude oil refineries. The differences between each type of process 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, the relationships among the various processes in a refinery, and the use of solvents in a refinery (often referred to as solvent treating irrespective of the actual solvent-based process or the use of water as the solvent). Solvents are widely used in many refineries for many processes, not the least of which is refining lubricating oils as well as a host of other refinery stocks. In the refinery, solvent processes are those processes in which a solvent is the principal agent that is used to either convert the feedstock to one or more desirable feedstocks or to remove impurities from the feedstock in order for the product to meet the various specifications for sales. Chapter 2 describes various solvent deasphalting processes, which are a major part of refinery operations because of the increased acceptance of viscous feedstocks (heavy crude oil, extra heavy crude oil, and tar sand bitumen) as well as the changing composition of the more conventional refinery feedstocks that have increased amounts of atmospheric and vacuum residua. This chapter presents descriptions of the various aspects of deasphalting, especially the feedstocks and feedstock properties that are essential to the efficient outcome of the process. Chapter  3 deals with the wax constituents that occur in paraffinic crude oils and in refinery products, often in the form of microcrystalline wax or paraffin wax. The wax that exists in paraffinic crude oils mostly contains paraffin hydrocarbon derivatives (i.e. paraffin wax; C18 to C36) and naphthene hydrocarbon derivatives (C30 to C60). The hydrocarbon element of wax is able to present in several phases, namely gas, liquid, and particles (solids), depending on the flow conditions, that is, pressure and temperature. This chapter presents descriptions of the dewaxing concept and the various processes that are used within refining to remove wax constituents from feedstocks. Chapter 4 covers the various solvent processes that are used in a refinery. Whereas the focus of the earlier chapters of this book has been on deasphalting and dewaxing, it would be remiss to omit the other solvent processes that are used in the refinery such as the solvent processes that are used for product treating (this chapter) and for treating the various gas streams that occur in the refinery. However, it must be understood that in many cases, the solvent is aqueous (i.e. water based) and is not always organic. Chapter 5 presents a description of the various gas-treating processes that are employed to separate all of the various gaseous hydrocarbon derivatives and fluids from raw or untreated natural gas. Major transportation pipelines usually impose restrictions on the makeup of the natural gas that is allowed into the pipeline that require that gas be purified before it is transported. Although ethane, propane, butane, and pentane hydrocarbon derivatives must be removed from natural gas streams, this does not mean that they are all waste products; on the contrary, these derivatives are valuable feedstocks for the production of petrochemicals and solvents.

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Preface

The focus of this chapter is gas cleaning (the removal of contaminants) from gas streams by the use of solvents, including the use of water as a solvent and as a carrier vehicle to convey reactants to the reaction site. The various analytical needs that are required when water is employed for gas cleaning operations are also presented. Chapter  6 presents the concept of processing biomass either as a co-feedstock in a crude oil refinery or in a refinery dedicated to biomass as the feedstock (i.e. biorefinery). Biomass (as a collective term) represents several types of natural plant material, each constituent of which is a complex mixture of chemicals and materials; as such, it has high potential as feedstock for a wide range of chemicals and materials with applications in industries from pharmaceuticals to furniture. The focus of the chapter is the use of solvents to convert biomass to useful products. The chapter also includes suggestions for converting biogas and bio-oil to saleable products. Chapter 7 introduces the challenges from the changing trends in current feedstocks accepted by refineries including feedstock composition and also from changes in the product slates that refineries will adapt. Furthermore, given the increasingly stringent distillation specifications being imposed through legislation on environmentally complex chemical operations, the refining industry in the near future will need to become increasingly flexible to meet new product specifications though innovative new processing schemes. The chapter presents suggestions and opinions of the means by which refinery processes will evolve during the next three to five decades. The chapter discusses (1) comparisons of current conventional feedstocks with viscous feedstocks and bio-feedstocks, (2) the evolution of refineries since the 1950s, (3) the properties and refinability of viscous feedstocks and bio-feedstocks, (4) the choice between thermal processes and hydroprocesses, and (5) the evolution of products to match the environmental market, with more than passing consideration of the effects of feedstocks from coal and from oil shale. In addition, there will also be the need to control the effects of possible changes in crude oil slate on the emission of carbon dioxide. This means a movement from conventional means of refining heavy feedstocks using (the currently typical) coking technologies to more innovative processes (including solvent-based processes and hydrogen management) that will produce the maximum amounts of liquid fuels from the feedstock and maintain emissions within environmental compliance (Penning, 2001; Davis and Patel, 2004; Speight, 2014a, 2020; Farnand et al., 2015). Each chapter will present to the reader the various steps that are necessary for the solvent treatment of various feedstocks. The book brings the reader up to date and adds more data including processing options that may well be the processes of choice in the 21st-century refinery. By expanding the understanding of the use of solvents in the refinery, 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 changes in 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 fifty years. Such personnel include (1) professionals in the refining industry, (2) technicians in the refining industry, (3) industry management personnel who need to understand the various processes and the roles of these processes in producing the desired feedstocks for further processing and the use of solvents to produce saleable products, and (4) the academic staff and graduate students who are moving into the refining industry. Any non-technical readers, with help from the extensive glossary, will also benefit from the series. Dr. James G. Speight Laramie, Wyoming, USA June 2023

About the Author Dr. James G. Speight has a BSc and PhD in chemistry; he also holds a DSc in geological sciences and a PhD in petroleum engineering. He has more than fifty years of experience in areas associated with (1) the properties, recovery, and refining of conventional petroleum, heavy oil, and tar sand bitumen; (2) the properties and refining of natural gas; and (3) the properties and refining of biomass, biofuels, and biogas and the generation of bioenergy. His work has also focused on environmental effects, environmental remediation, and safety issues associated with the production and use of fuels and biofuels. He is the author (and coauthor) of more than 100 books related to petroleum science, petroleum engineering, biomass and biofuels, and environmental sciences. Although he has always worked in private industry and has focused on contract-based work, Dr. Speight has served as a visiting professor in the College of Science, University of Mosul (Iraq) and a visiting professor in chemical engineering at the Technical University of Denmark and at the University of Trinidad and Tobago as well as in adjunct appointments at various universities. He has also served as a thesis examiner for more than 25 theses. As a result of his work, Dr. Speight has been honored as the recipient of the following awards: (1) Diploma of Honor, United States National Petroleum Engineering Society for Outstanding Contributions to the Petroleum Industry, 1995; (2) Gold Medal of the Russian Academy of Sciences for Outstanding Work in the Area of Petroleum Science, 1996; (3) Einstein Medal of the Russian Academy of Sciences In recognition of Outstanding Contributions and Service in the field of Geologic Sciences, 2001; (4) Gold Medal – Scientists without Frontiers, Russian Academy of Sciences In recognition of His Continuous Encouragement of Scientists to Work Together across International Borders, 2005; (5) Gold Medal – Giants of Science and Engineering, Russian Academy of Sciences In recognition of Continued Excellence in Science and Engineering, 2006; (6)  Methanex Distinguished Professor, University of Trinidad and Tobago In Recognition of Excellence in Research, 2007; and (7) The American Excellence Award for Excellence in Client Solutions from the United States Institute of Trade and Commerce, Washington, DC, 2018.

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Solvents in the Refinery

1.1 INTRODUCTION The refining of crude oil and use of crude-oil-derived products can be traced back over 5,000 years to ancient times, when crude oils, crude oil products, and asphalt-type products were isolated from natural seepages, especially seepages of bituminous material (Abraham, 1945; Forbes, 1958a, 1958b, 1959; Hoiberg, 1960). Any treatment of oil products (such as allowing for more volatile components to escape prior to use in lamps) or the asphalt product (such as hardening – by oxidation – in the air prior to use) can be considered refining under the general definition. However, crude oil refining (as practiced in a modern refinery) is a very recent technology, and many innovations evolved during the 20th century. Briefly, crude oil refining is the separation of a crude oil feedstock into a variety of boiling-range fractions and the subsequent treating of these fractions to yield marketable products (Table 1.1). A refinery is essentially a group of manufacturing plants that vary in number with the variety of products produced (Figure 1.1) (Gary et al., 2007; Speight, 2014, 2017; Hsu and Robinson, 2017). Refineries can be broadly categorized into different types as dictated by their functions: (1) topping, (2) hydroskimming, and (3) cracking (Speight, 2014, 2017). A topping refinery involves fractionating the refinery feedstock, and these oil fractions are either sold domestically or exported to oil refining and petrochemical companies that have the necessary production facilities to process them. Products of the topping refinery typically include (1) fuel gas, (2) liquefied petroleum gas (LPG), (3) low-boiling naphtha, (4) high-boiling naphtha, (5) middle distillates, (6) atmospheric gas oil, and (7) atmospheric residuum. Some topping refineries may have a small-scale asphalt production section. A hydroskimming refinery has a distillation unit to separate the crude oil into a variety of fractions; a vacuum distillation unit for the further separation of the high-boiling fractions of the oil; a catalytic reformer; and hydrotreating units for treating the naphtha, distillate, and vacuum gas oil fractions. It is more complex than a topping refinery because of the inclusion of the hydrotreating units. A cracking refinery includes either fluid catalytic crackers or possibly vacuum gas oil hydrotreaters and alkylation units in addition to the hydroskimming units. Refinery configurations that rely predominantly on cracking are often referred to as medium- or high-conversion refineries. In all three cases, solvents are employed on as as-needed product-related basis. For example, solvent deasphalting is sometimes used in conjunction with delayed or fluid coking or visbreaking to enhance the viscous feedstock upgrading capabilities of the refinery (Speight, 2013c, 2014, 2017; Zachariah and de Klerk, 2017). The processes used to separate refinery feedstock into various fractions (and the conversion of the separated fractions into saleable products) must be selected according to the market demand. For example, the manufacture of products from the lower-boiling fractions of crude oil may also produce higher-boiling products that are useful as products or as feedstocks for other refinery processes. If the higher-boiling products cannot be used, for example as fuel oil, these products will accumulate until refinery storage facilities are full or optional uses are defined. To prevent a storage bottleneck in the refinery system, the options for the use of such products must be sufficiently flexible to allow for changing the refinery operations on an as-needed basis. Typically, thermal and/or catalytic processes are used to convert the excess higher-boiling products into, for example, naphtha (a component of gasoline) or kerosene (a middle distillate) with coke as the residual product, or vacuum distillation is used to separate the higher-boiling products into the base oils for the production of lubricating oil and asphalt (Table 1.2) (Gary et al., 2007; Speight, 2014, 2017; Hsu and Robinson, 2017). DOI: 10.1201/9781003185277-1

1

2

Solvent Processes in Refining Technology

TABLE 1.1 General Descriptions of Refinery Operations Fractionation (distillation) The separation of crude oil in atmospheric and vacuum distillation towers into groups of hydrocarbon compounds of differing boiling-point ranges Products are referred to as fractions or cuts. Conversion processes Designed to change the molecular size and/or structure of hydrocarbon constituents of the feedstock. These processes include: – Decomposition (dividing) by thermal and catalytic cracking – Unification (combining) through alkylation and polymerization – Alteration (rearranging) with isomerization and catalytic reforming Treatment processes Used to prepare hydrocarbon streams for additional processing and to prepare finished products May include removal or separation of aromatics and naphthenes, impurities, and undesirable contaminants. Treatment may involve chemical or physical separation, such as dissolving, absorption, or precipitation using a variety and combination of processes including desalting, drying, hydrodesulfurizing, solvent refining, sweetening, solvent extraction, and solvent dewaxing. Formulating and blending The process of mixing and combining hydrocarbon fractions, additives, and other components to produce finished products that meet specific specifications Other refining operations include: Light-ends recovery Sour-water stripping Solid waste, process water, and wastewater treatment Cooling, storage and handling, and product movement Hydrogen production Acid and tail-gas treatment Sulfur recovery

The term middle distillate is used to describe a range of refined products that result from the fractional distillation of crude oil into lower-boiling products (e.g., LPGG and naphtha) and higherboiling products, such as atmospheric gas oil (Table 1.2). As the basic elements of crude oil, compounds of carbon and hydrogen form the main inputs into a refinery, combining 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 three basic groupings of products that are produced when it is broken down into cuts or fractions. The naphtha fractions (low boiling and high boiling) form the lower-boiling products and are usually more valuable than the higher-boiling fractions; they provide LPG, naphtha, aviation fuel, motor fuel, and feedstocks for the petrochemical industry. Naphtha, a blend stock for manufacturing gasoline and a variety of solvents, is extracted from both the low- and middle-boiling distillate fractions and is also used as a feedstock for the petrochemical industry (Speight, 2014, 2019b). The middle distillates from refinery processes refer to products from the middle-boiling range of crude oil and include kerosene, diesel fuel, distillate fuel oil, and light gas oil; waxy distillates and lower-boiling lubricating oils are often included in the middle distillate category (Gary et al., 2007; Speight, 2014, 2017; Hsu and Robinson, 2017). The remainder of crude oil includes higher-boiling

Solvents in the Refinery

3

FIGURE 1.1  Schematic overview of a refinery. Source: OSHA Technical Manual, Section IV, www.osha.gov/dts/osta/otm/otm_iv/otm_iv_2.html

gas oil and residuum (the non-volatile fraction of the crude oil). The residuum can also produce heavy lubricating oils and waxes, but it is more often used for asphalt production. The complexity of crude oil is demonstrated by the fact that the actual proportions of light, medium, and heavy fractions vary significantly from one crude oil to another. The refining industry has been the subject of four major forces that 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, natural gas, and coal; (3) environmental regulations that include more stringent regulations in relation to sulfur in gasoline and diesel; and (4) technology development such as new catalysts and processes. In the opening decades of the 20th century, crude oil refinery processes were developed to extract kerosene for use as an illuminator fuel for oil lamps. Any other products were considered to be unusable and were usually discarded, often into a nearby river or a landfill. Thus, the first refining processes were developed to produce (and improve the quality of) kerosene. However, the invention of the internal combustion engine and the increasing use of the engine as a means of transportation in automobiles at the time (around the time of World War I) led to an increasing demand for gasoline for use as a motor fuel for cars and trucks. Refinery methods had to be constantly adapted and improved to meet the quality requirements and needs of automobile engines and, as a result of World War I, aircraft engines (Speight, 2014, 2017). Since then, the necessary trend throughout the refining industry has been to produce more products from each barrel of crude oil and to process those products in different ways to meet the specifications for use in modern engines. Overall, the demand for gasoline has rapidly expanded as well as

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Solvent Processes in Refining Technology

TABLE 1.2 The Boiling Ranges of Various Oil Fractions ----Boiling Range Fraction

°C

°F*

Low-boiling naphtha

30–150

30–300

High-boiling naphtha

150–180

300–400

Middle distillates**

180–290

400–500

Kerosene

180–260

355–500

Fuel oil

205–290

400–550

Atmospheric gas oil

260–315

500–800

Vacuum gas oil

425–600

800–1100

Light vacuum gas oil

315–425

600–800

Heavy vacuum gas oil

425–600

425–600

Residuum

>510

>950

 * For convenience, boiling ranges can vary from refinery to refinery and are approximate; for convenience, they are converted to the nearest 5°. ** Obtained in the middle-boiling range, 180 to 260°C (355 to 500°F), during the crude oil distillation process. The middle distillates are so named because the fractions are removed at mid height in the distillation tower during the multistage distillation. Source: Speight, J.G. 2023. Petroleum Refining Technology Series Volume 4: Hydrotreating and Hydrocracking. CRC Press, Taylor & Francis Group, Boca Raton, Florida.

the demand for (1) low-boiling distillates as feedstocks for the production of petrochemicals, (2) gas oils and fuels for domestic central heating, and (3) fuel oil for power generation. As the need for lower-boiling products developed, the refinery feedstocks yielding the desired quantities of the lower-boiling products became less available, and refineries had to introduce conversion processes to produce greater quantities of lighter products from the higher-boiling fractions (Table 1.3) (Gary et al., 2007; Speight, 2014, 2017; Hsu and Robinson, 2017). In short, refineries have been introducing increasingly complex processing units in order to produce maximum yields of lower-boiling products from the higher-boiling fractions of refinery feedstocks (Gary et al., 2007; Speight, 2014, 2017; Hsu and Robinson, 2017). Refinery processes for crude oil are generally divided into three categories: (1) separation, of which distillation is the prime example as well as the various solvent-dependent processes; (2) conversion, of which coking and catalytic cracking are prime examples; and (3) finishing, of which hydrotreating to remove sulfur is a prime example. Finishing includes processes in which a product is treated with a solvent to enhance the purity of the product such as occurs in many gas-processing operations. The configurations of refineries vary (Gary et al., 2007; Speight, 2014, 2017; Hsu and Robinson, 2017). Some may be more oriented toward the production of gasoline (large reforming and/or catalytic cracking), whereas others may be more oriented toward the production of middle distillates such as jet fuel and gas oil. Although crude oil refining is often associated with conversion processes that involve thermal or catalytic reactors, there is a variety of processes that involve the use of solvents. Processes utilizing the selective action of solvents are used mainly during the refining of base oils and other petroleum processing. Fractions generated during distillation under low pressure may

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Solvents in the Refinery

TABLE 1.3 Simplified Distinctions between Conventional Crude Oil, Heavy Oil, Extra Heavy Oil, Tar Sand Bitumen, and Residua* Type Conventional crude oil

Properties Naturally occurring API gravity: >20 sulfur: 1.439 @ 20°C (68°F)

* C17 (m.p.: 21°C (70°F) is the first n-paraffin hydrocarbon that is a solid at room temperature; in this table, the properties of n-C18 are used as the examples.

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smaller. In addition, the branched chains in the microcrystalline waxes are presented at random along the carbon chain, whereas in paraffin wax, they are located at the end of the chain. The cyclo-alkane (i.e. naphthene) derivatives consist mainly of monocyclic systems such as monocyclopentyl, mono-cyclohexyl, di-cyclohexyl, and poly-cycloparaffin derivatives. Some microcrystalline waxes are mainly composed of multiple-branched iso-paraffin and m ­ ono-cycloparaffin derivatives. The non-hydrogenated micro waxes also contain predominantly mono-cyclic derivatives and heterocyclic aromatic compounds. Microcrystalline waxes have higher molecular weights (around 600 to 800), higher density, and higher refractive indices than the paraffin waxes. The oil content of a wax is an indicator of quality and can be determined by a test that depends upon the differential solubility of the oil and the wax in a given solvent. Microcrystalline waxes have a higher affinity for oil than paraffin waxes because of their smaller crystal structure; the oil content of microcrystalline wax is 1 to 4% w/w, depending on the grade of wax.

3.2.2  Wax Appearance Temperature or Cloud Point The wax appearance temperature is the temperature below which wax starts to appear in a waxy crude liquid. When crude oil that contains waxy constituents is cooled to a temperature that is lower than the wax appearance temperature, the wax molecules form clusters of aligned paraffin chains. When these hydrocarbon nuclei reach a critical size, they become stable, and further attachment of molecules leads to growth of the crystal. At that point, the formation of the nuclei causes the fluid to reach the wax appearance temperature (the fluid becomes cloudy), which is also referred to as the ‘cloud point’. If the wax appearance temperature of a produced waxy crude oil or a transported waxy crude oil is found to be significantly higher than the temperature that is expected to be encountered during production or transportation, wax deposition problems should be expected, and actions should be taken to avoid the problem. At the cloud point, the liquid has lost transparency and takes on a cloudy appearance, making the cloud point an important characteristic that is used to evaluate the potential wax precipitation from a given fluid.

3.2.3 Factors Controlling Wax Deposition Wax deposition within a pipeline is affected by several factors that include (1) the temperature, (2) the pressure, and (3) the molecular weight of the wax. For the proper design, operation, and optimization of a waxy crude production and transportation system, the effect of each of these factors should be investigated carefully following documented experimental procedures and standards (Eghbali et al., 2013). Wax deposition into the production system generally requires a nucleating agent, such as an asphaltene constituent or an inorganic solid. The deposits of wax can vary in composition and in consistency, with the consistency ranging from a semi-solid material (sometimes referred to as ‘mush’) to a hard brittle material. The hard brittle deposits are due to the presence of longer-chain n-paraffin derivative, whereas while the mush will contain lower-molecular-weight hydrocarbon derivatives or contaminants that interfere with the physical properties of the wax constituents. For example, deposits of the paraffin constituents can also contain foreign (i.e. non-paraffin) constituents such as asphaltene, resin, gum, fine-rain sand, silt, clay, salt, and water. More typically, the high-molecular-weight wax constituents can deposit even in the higher-temperature sections of a well, a pipeline, or a process unit, whereas the lower-molecular-weight wax constituents fractions tend to deposit in lower-temperature regions of the well, the pipeline, or the process unit. With a further reduction in the temperature, the liquid phase (i.e. the oil) may eventually change into a gel that has complex flow behavior; specifically, the gel becomes a yield-pseudoplastic or yield-plastic non-Newtonian fluid. However, regardless of the rheological behavior that is exhibited by the oil, the viscosity is always inversely proportional to the temperature of the oil. The solubility of the waxy constituents of an oil is also directly proportional to process temperature, and when

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water is present in the crude, wax deposition tends to reduce because the water decreases the temperature drop of the oil, thereby keeping the solution above the pour point temperature (Sadeghazad and Christiansen, 1998). The water is able to maintain the oil temperature because oil has only approximately 50% of the specific heat of water. Pressure is the second factor that affects the deposition of wax in that the wax present in the oil has a positive divergence, and the solubility of the wax present in the oil decreases with the increase in pressure. The third factor that has an effect on wax deposition is the molecular weight of the constituents of the wax; this is because the solubility of these constituents in the oil will decrease with increasing molecular weight and melting point. In addition, the solution composition greatly affects the wax deposition as well. Specifically, the cloud point decreases for a wax solution with a lighter composition, meaning that it will take longer for the wax to deposit (Sadeghazad and Christiansen, 1998; Tripathy et al., 2021).

3.2.4  Wax Deposition Mechanism In an investigation of the deposition mechanisms of wax, which are (1) the molecular diffusion of wax molecules, (2) the shear dispersion of wax crystallites, (3) the Brownian diffusion of wax crystallites, and (4) gravity settling, researchers observed that the gravity settling of paraffin crystals in flow line conditions is negligible because of the effect of shear dispersion (Burger et al., 1981; Theyab, 2018). These four wax deposition mechanisms are discussed in the following subsections. 3.2.4.1  Molecular Diffusion Molecular diffusion is the prevalent mechanism of deposition in well tubing. To avoid wax deposition in a flowing well or in a pipeline, the temperature of the flowing oil needs to be maintained above the cloud point until the oil reaches the destination. Wax deposition is also enhanced as a result of radial heat transfer from the tubing core toward the surroundings. However, there are situations in which wax precipitation does not necessarily lead to wax deposition because the individual wax crystals tend to disperse in the fluid instead of depositing on a surface. If the number of wax crystals becomes large enough or if other nucleating materials such as asphaltene constituents, fine mineral matter, clay minerals, or corrosion products are present, the crystals may agglomerate into larger particles that may then separate from the fluid in the form of a solid deposit. When wax deposition occurs, a concentration gradient is established in the oil as a result of a temperature gradient profile that is due to the increasing solubility of the wax constituents with increasing temperature. The concentration gradient causes wax constituents in the solution to diffuse from the warmer oil, which has a greater concentration of dissolved waxes, to the cooler oil, which has a lower concentration of the wax constituents. This causes the molecular diffusion of the wax crystals toward the surface wall. In fact, the wax concentration gradient is triggered as the differential temperature at a cross-section causes the particles near the cold walls to start the deposition from the oil solution and develop an initial layer of deposit. 3.2.4.2  Shear Dispersion At low temperature, shear dispersion is believed to be the most-frequently occurring mechanism. It deals most with particles that are settling on the surface of a cold pipe due to the grooved or rough surface as well as the intermolecular forces. However, investigators have established that the shear dispersion is not significant based on field operating experience as well as experimental investigations. During the flow of a waxy fluid in a pipeline, a shearing effect can occur near the wall of the pipe, and the fluid will flow more slowly near the wall of the pipe because of the shearing effect and the friction, which causes a shear dispersion. The shear dispersion is most effective when the

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temperature of the flowing oil is below the wax appearance temperature, thus causing high wax precipitation. The shear dispersion coefficient is represented by the following equation (Burger et al., 1981): Ds = a2γC∗w/10 In this equation, Ds is the shear dispersion coefficient (m2/s); a is the particle diameter, m; Cw is the wax volume fraction concentration excluding the wall fraction; and ɤ is the oil shear rate on the wall, s−1. 3.2.4.3  Brownian Diffusion When tiny solid crystals are suspended within the oil, they collide frequently with thermally vibrant molecules. Due to such collisions, a Brownian movement is initiated, and the coefficient of the Brownian diffusion is expressed by the following equation: Db = RT/6πμaN In this equation, R is the gas constant (J/mol.K); Ta is the absolute temperature (K); U is the viscosity (Pa.s); a is the particle diameter (μm); and N is Avogadro’s number (mol), but the Brownian diffusion can be ignored (Burger et al., 1981). 3.2.4.4  Gravity Settling Because the wax crystals are denser than the oil constituents, the wax crystals tend to settle and deposit, but it is generally considered that the gravitational wax deposition is insignificant. However, the turbulent flow or shear dispersion has the ability to disperse the settling particles and eliminate the gravity settling phenomenon.

3.3  PROCESS PRINCIPLES The main purpose of dewaxing is to remove hydrocarbons that solidify readily (i.e. the wax constituents) in order to produce the base stock with a low pour point for the manufacture of lubricating oil base stock. The need to remove the waxy constituents arises because the wax can precipitate as a solid phase on the pipe wall when its temperature drops below wax appearance temperature. This results in the restriction of the flow of the liquid through the pipeline, which then creates pressure abnormalities and an artificial blockage, leading to a reduction or interruption in the production process. Paraffin wax produced from crude oil consists primarily of long-chain, saturated hydrocarbon derivatives (i.e. linear n-alkane hydrocarbon derivatives, paraffin hydrocarbon derivatives) with carbon chain lengths of C18 to C75 and having individual melting points of 40 to 70°C (104 to 158°F); this wax is commonly referred to as macrocrystalline wax. Naphthene hydrocarbon derivatives (C18 to C36) may also appear as wax deposits and are often referred to as microcrystalline wax. Microcrystalline waxes (naphthene or iso-paraffin) are produced by deoiling petroleum, whereas macrocrystalline waxes (paraffins wax) consists of long straight-chain saturated hydrocarbons (linear alkane derivatives). Paraffin waxes constitute the major types of crude oil waxes, which are solid hydrocarbons at room temperature. Briefly, ‘slack wax’ is a refinery term for the crude paraffin wax separated from the solvent dewaxing of base stocks; it contains oil in amounts ranging from 20 to 50% w/w) and must be removed to produce hard or finished waxes. If the slack wax separates from residual oil fractions, the oil-bearing slack is frequently called petrolatum, which is a general name applied to a slightly oiled, crude, microcrystalline wax. It is a semi-solid, jelly-like material that is obtained from a certain type of high-boiling crude oil distillate or residuum.

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Additionally, ozokerite wax is a naturally occurring microcrystalline mineral wax, and ceresin is a microcrystalline wax. It is also the name formerly given to the hard white wax obtained from fully refined ozokerite. Ceresin and ceresin derivatives in crude oils appear to have the same composition, structure, and physical and chemical properties. Briefly, ceresin (also known as cerin, cerasin, cerosin, ceresin wax, or ceresine) is a wax derived from ozokerite (or ozocerite and often referred to as earthwax or earth wax), which is a naturally occurring odoriferous mineral wax or paraffin found in many localities. Lacking a definite composition and crystalline structure, ozokerite is not considered a mineral but is considered to be a mineraloid, a naturally occurring mineral-like substance that does not demonstrate crystallinity and that possesses a chemical composition that varies beyond the generally accepted ranges for specific minerals. Although the light (low-density) crude oils are preferred refinery feedstocks, the production and transportation of wax-associated light crude can be difficult because the pressure drop from the reservoir to the production facility can be substantial, which can cause common wax to precipitate and deposit on surfaces and/or collect in low-energy regions or can increase the effective viscosity of the flowing fluid. The two types of wax crystal studied are microcrystalline and macrocrystalline waxes, and knowledge of the wax type aids in understanding the fluid flow dynamics of the oil and preventing wax blockage. There are several methods of dewaxing crude oil and other refinery feedstocks: (1) solvent dewaxing, which can be applied to light, intermediate, and heavy lubricating oil distillates; (2) catalytic dewaxing, which is a selective hydrocracking process; and (3) urea dewaxing, which offers a viable means of segregating the wax constituents during the dewaxing process. Solvent dewaxing involves mixing the feedstock with the solvent, chilling the mixture to crystallize wax, and recovering the solvent, and a catalyst is not involved in the process. In contrast, catalytic dewaxing involves the use of a catalyst, and with selective hydrocracking, the wax constituents are cracked to produce low-boiling hydrocarbon products. In a third process, urea dewaxing, various straight-chain organic compounds and also slightly branched compounds are capable of forming complexes (adducts) with urea (H2NCONH2) that are crystalline at room temperature (Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). The solvent refining processes including solvent extraction and solvent dewaxing, which usually remove undesirables at intermediate refining stages or just before sending the product to storage. Various process technologies have been developed for solvent dewaxing, but all have the same general steps: (1) mixing the feedstock with a solvent, (2) precipitating the wax from the mixture by chilling, and (3) recovering the solvent from the wax and dewaxed oil for recycling by distillation and steam stripping. Other solvents sometimes used include benzene, methyl isobutyl ketone, propane, crude oil naphtha, ethylene dichloride, methylene chloride, and sulfur dioxide. The characteristics of the ideal dewaxing solvent include the following: (1) a low wax solvent power, (2) a high oil solvent power, (3) a low freezing point, (4) low viscosity, (5) high chemical stability, and (6) high thermal stability (Wauquier, 2000; Parkash, 2003; Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017). MEK dewaxing consists of three basic steps: (1) crystallization, which involves diluting and chilling the feedstock; (2) filtration to separate the wax and the dewaxed oil filtrate; and (3) solvent recovery, which involves separating the solvent from the wax and the oil. A major part of the chilling operation (∼60%) can be obtained by heat exchange between the feedstock and solvent with cold filtration being used as the chilling medium in the double-pipe exchangers. The remainder of the refrigeration required for chilling is obtained by indirect heat exchanger with a refrigerant in the double pipe chillers. The slurry, which leaves the chillers at a temperature of 3 to 11°C (5 to 20°F) below the desired pour point, is filtered using rotary vacuum filters, and the wax cake is washed with a spray of cold solvent before being discharged by a gas blowback.

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3.3.1  Non-Catalytic Dewaxing This process typically involves the use of solvents such as a mixture of methyl ethyl ketone and benzene. However, most of the energy consumption in solvent dewaxing is in the regeneration of solvent, and the current trend has been to use lower solvent dilution ratios and smaller amounts of solvent in washing the precipitate (wax cake) on filter media. In contrast, increasing the ­solvent-to-oil ratio enhances the filtration rate because the solvent prompts the crystal growth and lowers the vis­cosity of the oil-plus-solvent mixture and can lead to an increase in the yield of the dewaxed oil while decreasing the oil content in the wax (Ali, 2014). The major processes that are currently in use are ketone dewaxing processes. Commonly used processes are (1) Exxon Dilchill and (2) the Texaco process. Texaco solvent dewaxing (also called the MEK process) uses a mixture of MEK (CH3C(=O)CH2CH3) and toluene as the dewaxing solvent and sometimes uses mixtures of other ketones and aromatic solvents. Exxon Dilchill dewaxing uses direct cold-solvent dilution chilling in a crystallizer that is inserted in place of the scraped surface exchangers that are used in the Texaco process. The two commonly used solvents that are employed in solvent dewaxing units are MEK and propane, and although the majority of dewaxing units use MEK, some advantages of using propane as a solvent instead include the following: (1) propane is used both as a diluent and as a refrigerant, (2) asphaltenes and resins are rejected in the feedstock, and (3) there are higher viscosity indices than with ketone dewaxing. To prevent wax from depositing on the walls of the inner pipe, blades or scrapers extend the length of the pipe and are fastened to a central rotating shaft scrape off the wax. Slow chilling reduces the temperature of the waxy oil solution to 2°C (35°F), and then faster chilling reduces the temperature to the approximate pour point required in the dewaxed oil. The mixture is then pumped to equipment in which the bottom half of the drum of a rotary vacuum filter dips. The drum (which is typically around 8 feet in diameter and 14 feet long and often covered with filter cloth) rotates continuously in the filter case. Vacuum within the drum sucks the solvent and the oil dissolved in the solvent through the filter cloth and into the drum. A knife-edge insert is used to scrape off the wax, thereby allowing the wax cake to fall into the conveyor, after which the wax is moved from the filter by the rotating scroll. The deoiled wax is melted in heat exchangers and pumped to a distillation tower operated under vacuum, where a large part of the ketone is evaporated or flashed from the wax. The rest of the ketone is removed by heating the wax and passing it into a fractional distillation tower operated at atmospheric pressure and then into a stripper where steam removes the last traces of ketone. Each of the waxes is actually a mixture of a number of different waxes that include the lowboiling (low-density) light paraffin distillates (paraffin waxes that have melting points around 30 to 70°C or 90 to 160°F) that are characterized by a tendency to harden into large crystals. However, the high-boiling (high-density) paraffin distillate yields a wax composed of a series of waxes, each with a melting point in the range of 60 to 90°C (140 to 200°F), that harden into small crystals that give them the name microcrystalline wax or ‘microwax’. Upon refrigeration, any wax constituents will solidify to form crystals and are carried in the solvent to a rotary filter, where wax is separated on a filter cloth covering the rotating drum. The filter cake (i.e. a layer of wax) on the drum is scraped from the filter by a blade and carried away in a solvent stream to a steam-stripping unit to recover and recycle the solvent separated from the wax product. The wax product (the slack wax) is not a waste and can be used to produce paraffin wax (for the manufacture of candles), microwax (for use in the cosmetics industry), and petrolatum (for the manufacture of petroleum jelly). The dewaxed oil from the filtration unit is also steam stripped to recover the solvent to produce the lubricating oil base stock. The slack wax from high-boiling paraffin distillate may be sold as dark raw wax, and the wax from the intermediate paraffin distillate may be sold as pale raw wax, which is often treated with lye (caustic solution) and clay to remove odor and improve the color. The petrolatum layer is also distilled to remove naphtha and may be clay treated or acid and clay treated to improve the color.

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3.3.2 Catalytic Dewaxing Catalytic dewaxing is a hydrocracking process and is therefore operated at elevated temperatures (280 to 400°C, 550–750°F) and pressures (300/1500 psi). Dewaxing can be achieved by isomerization, as with Chevron Isodewaxing, to convert the lower-melting-point derivatives to n-paraffin derivatives. The properties targeted for improvement are the pour point and viscosity of middle distillates and lubricants, the cloud point of diesel fuel, and the freeze point of jet fuel. Due to the high melting points, long-chain normal paraffin hydrocarbon derivatives have a detrimental effect on the low-temperature properties of middle distillates and lubricating oils. If the chain lengths of the normal paraffin derivatives and the minimally branched paraffin hydrocarbon derivatives are reduced, the cold flow properties are improved with catalytic dewaxing. Typically, the process uses a single-stage, once-through hydrocracking process for catalytic dewaxing, with or without hydrotreating, depending on the sulfur and nitrogen content of the feedstock. The catalytic process uses a trickle-bed reactor containing a bifunctional zeolite catalyst under hydrogen flow. A non-noble metal (such as a nickel-based catalyst) is supported on a mediumpore zeolite (such as ZSM-5, which is particularly suitable for obtaining high selectivity). Then, the feedstock (typically a DAO that should be free of PNAs) goes through a heater with hydrogen gas present, and then it passes into a reactor containing a molecular sieve that is operated under high temperature (280 to 400°C, 535 to 750°F) and pressure (300 to 1500 psi). From the reactor, the product mix is sent to a distillation unit that separates naphtha and the lubricating oil base stock. The aim of the process is to transform high-melting-point waxy molecules into low-pour products of non-waxy structure, and the process concept involves the selective cracking of high-pour, straight-chain paraffin hydrocarbon derivatives followed by the isomerization of the products into low-pour iso-paraffin derivatives. Catalytic dewaxing is employed as a low-severity conversion process involving the use of a selective catalytic for cracking n-paraffin derivatives. The selective cracking of n-alkane hydrocarbon derivatives takes place in the pores of molecular sieve catalysts (zeolites) with pore openings of around 0.6 nanometers (0.6 nm), which restricts the access of the iso-paraffin derivative because of the larger iso-derivative due to branching in the hydrocarbon skeleton. This selective cracking increases the ratio of iso-paraffin hydrocarbon derivatives to n-paraffin hydrocarbon derivatives in the product and also lowers the pour point. The advantages of catalytic dewaxing include (1) the production of lubricating oil base stock with lower pour point and in higher yield compared with the product obtained from solvent dewaxing, (2) good product stability, and (3) the flexibility of the process to produce both lubricating oil base stock and light distillates. However, the conditions for a particular dewaxing operation depend upon the nature of the feedstock and the product pour point required. The catalyst employed for the process is a mordenite-type catalyst (a zeolite mineral with the chemical formula, (Ca.Na2. K2)Al2Si10O24.7H2O)) that has a suitable pore structure to be selective for cracking the n-paraffin (linear paraffin) derivatives. Platinum on the catalyst serves to hydrogenate the reactive intermediates so that further paraffin degradation is limited to the initial thermal reactions. The process has been employed to successfully dewax a wide range of naphthenic feedstocks, but it may not be suitable to replace solvent dewaxing in all cases. The process has the flexibility to fit into normal refinery operations and can be adapted for prolonged periods on-stream. Other processes include ExxonMobil distillate dewaxing, in which the long paraffin chains are selectively cracked to form shorter chains using a shape-selective zeolite that rejects ring compounds and iso-paraffin hydrocarbon derivatives. In a related process, the paraffin hydrocarbon derivatives are selectively isomerized using low-pressure conditions. This process also uses a zeolite catalyst to convert low-quality gas oil into diesel fuel. In catalytic dewaxing, the proprietary catalyst can be reactivated to fresh activity by relatively mild non-oxidative treatment. Of course, the time allowed between reactivation is a function of

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the feedstock, but after numerous reactivations, it is possible that there will be coke buildup on the catalyst. The process can be used to dewax a full range of lubricating base stocks and, as such, has the potential to be used in conjunction with or completely replace solvent dewaxing. Both the catalytic dewaxing processes have the potential to change the conventional thoughts about dewaxing inasmuch as they are not solvent processes and may be looked upon (more correctly) as thermal processes rather than treatment processes. However, both provide viable alternatives to the solvent processes and offer a further advance in the science and technology of refinery operations. Alternatively, in Chevron Isodewaxing, dewaxing is brought about by isomerizing the linear paraffin (n-paraffin) derivatives to branched paraffin hydrocarbon derivatives by using a molecular sieve catalyst containing platinum, which is typically a synthetic zeolite, or other microporous molecular sieves. In the process, which is followed by a hydrofinishing step, a waxy feedstock from a hydrocracker or hydrotreater, together with the hydrogen-containing gas, is heated and fed to the Isodewaxing reactor. The conditions in the reactor cause the isomerization of n-paraffin hydrocarbon derivatives to iso-paraffin hydrocarbon derivatives, and other paraffin hydrocarbon derivatives are cracked to highly saturated low-boiling products such as jet fuel and diesel fuel. The effluent from the Isodewaxing reactor is then sent for hydrofinishing, including aromatic hydrocarbon derivatives saturation, to provide the product. The catalysts used in the Isodewaxing and hydrofinishing units are selective for dewaxing and hydrogenation. The catalysts are at their maximum efficiency with low-sulfur and low-nitrogen feedstocks. The process generally uses a high-pressure recycling loop. Because of the conversion of wax constituents to other usable products, the process has obvious benefits over solvent dewaxing because the quality of the product is higher. There are also later-generation dewaxing processes that are being brought on-stream in various refineries. For example, British Petroleum has developed a hydrocatalytic dewaxing process that is reputed to overcome some of the disadvantages of the solvent dewaxing processes. In the British Petroleum process, waxy molecules are removed from heavy distillate fuel cuts or lubricating oil distillates. The major properties for base oil required for making lubricating oil are viscosity, viscosity index (VI), and pour point. It is essential that the base stock possess low viscosity, high VI, and low pour point. The traditional method is to treat certain vacuum distillates using the selective extraction of aromatic hydrocarbon derivatives (to increase the VI) followed by solvent dewaxing (to decrease pour point) and acid/clay treatment for finishing or hydrofinishing. However, the yield of base stock is poor, and low valued product like slack wax is generated in the solvent extraction method. Catalytic treatment has evolved as another alternative. Hydrogenation and isomerization of normal paraffin derivatives, which are the major precursors for wax generation, can produce a base oil with a high VI and a low pour point. Though catalytic dewaxing is carried out at present by hydrogenation, hydrotreating, or partial hydrocracking, Isodewaxing is a low-temperature catalytic process that yields more, in comparison with catalytic dewaxing, base oil with high VI and low pour point. In the isomerization reaction, normal paraffin hydrocarbon derivatives are converted to iso-paraffin hydrocarbon derivatives with substantially lower pour points than those of normal paraffin hydrocarbon derivatives without affecting the high VI. The catalyst used in this process is platinum on H-mordenite, and the temperature is maintained between 290 to 400°C (555 to 750°F) in a hydrogen atmosphere. Because the reactions are slightly exothermic, it is essential to use hydrogen as the quenching medium, which is a coke suppressor as well. In the process, feed is mixed with hydrogen and preheated before it enters the reactor, and the product is flashed to separate hydrogen followed by stripping of the cracked gases. Multiple reactor beds in a single reactor are preferred. Finally, one of the factors that limits the capacity of a solvent dewaxing plant is the rate of wax filtration (and separation in general) from the dewaxed oil, which in turn is strongly influenced by

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the crystal structure of the precipitated wax. Although the crystal structure of the precipitated wax is influenced by various operating conditions in the dewaxing process, for any given feed, it is most strongly influenced by the chilling conditions. The size and crystal structure of the precipitated wax, the occlusion of oil in the wax crystal, and the condition of the oil left in the crystal are extremely varied and depend on the wax composition and precipitation conditions. These conditions also affect the separation (filtration) rate of the dewaxed oil from the wax and the yield of dewaxed oil. In some cases, most notably when the waxy oil is a bright stock, the wax crystals are of an extremely fine size and not all are separated by filtration: Some leave the filter with the dewaxed oil component, which creates an objectionable haze in the oil. Dewaxing aids (such as alpha-olefin copolymers) can assist the process, including mixtures such as (1) an ethylene-vinyl acetate copolymer and (2) an ester of an aliphatic alcohol having from 2 to 20 carbon atoms with acrylic or methacrylic acid; the esters of aliphatic alcohols and acrylic or methacrylic acid, and polymeric dewaxing aids comprising condensation products of chlorinated paraffin hydrocarbon derivatives and naphthalenes alone or mixed with the aforementioned esters. However, in the case of viscous feedstocks, these aids require a relatively high concentration of the dewaxing aid in the oil for maximum efficiency. This is especially true when a heavy oil raffinate or a bright stock or heavy distillate is solvent dewaxed. Because of the presence of many fine particles of wax in the oil, the filter rate of the dewaxing oil tends to be low, and the oil also may possess or develop a haze (Briens et al., 1987).

3.4 FEEDSTOCKS The feedstocks that require dewaxing can be as varied as DAO (Chapter 2) or the heavy vacuum gas oil from the vacuum distillation unit as well as a variety of products that contain wax constituents but that are not required in the product for sales. However, in the schematic process shown immediately below, not all feedstocks (especially the viscous feedstocks) can produce waxy products; the output is very much dependent upon the type of feedstock.

Vacuum distillation Heavy vacuum gas oil C18-C40 n-alkanes and iso-alkanes Vacuum residuum deasphalter pitch Asphalt Vacuum residuum deasphalted oil Lubricating oil base stock (C18-C26 n-alkanes and iso-alkanes) Wax (C26-C40 n-alkanes) The main purpose of dewaxing is to remove hydrocarbons that solidify readily (i.e. wax) to make lubricating oil base stock with a low pour point (-23 to -10°C; -9 to 14°F). In addition to low pour points, other important properties of base stocks for lubricating oil include the volatility, which should be sufficiently low to keep oil in the liquid phase during engine operation, and the viscosity, which must be controlled because of lubrication and heat transfer considerations. In fact, moderate viscosity is desired because low viscosity may not provide the required lubrication and lead to high friction between metal parts, and high viscosity causes a loss of energy. The VI is also an important property; it indicates a change in viscosity with temperature, and a small change in viscosity is desired over a wide temperature oil. A high VI ensures that the lubricating oil will function well at both cold start and at high temperatures generated by the engines.

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Finally, the thermal stability is important because high thermal stability – often equivalent to a small degree of thermal degradation at a high temperature – is necessary to minimize viscosity loss and coke deposition on metal surfaces. All of these properties depend on the molecular composition of the hydrocarbons constituting the lubricating oil base stocks. Commercial engine oils and other commercial lubricating oils are formulated with chemical additives that enhance the performance of the base stocks.

3.4.1 Feedstock Evaluation Fractionation for determining the composition of the feedstocks for deasphalting (Chapter 2) are of lesser value and not in common use for feedstocks destined for dewaxing. Distillation is the most widely used separation process in the crude oil industry (Parkash, 2003; Gary et al., 2007; Hsu and Robinson, 2017; Speight, 2017). In fact, knowledge of the boiling range of crude feedstocks and finished products has been an essential part of the determination of feedstock quality since the start of the refining industry. The technique has been used for controlling plant and refinery processes as well as for predicting product slates. Thus, it is not surprising that routine laboratory scale distillation tests have been widely used for determining the boiling ranges of crude feedstocks and a whole slate of refinery products (Speight, 2015). There are some limitations to the routine distillation tests. For example, although many heavy crude oils contain volatile constituents, it is not always advisable to use distillation to identify these volatile constituents. Thermal decomposition of the constituents of feedstocks is known to occur at approximately 350°C (660°F), and thermal decomposition of the constituents of the heavier, but immature, crude oil has been known to commence at temperatures as low as 200°C (390°F). Thus, thermal alteration of the constituents and erroneous identification of the decomposition products as natural constituents is always a possibility. In contrast, the limitations to the use of distillation as an identification technique may also be economic, and the detailed fractionation of the sample may be of secondary importance. There have been attempts to combat these limitations, but it must be recognized that the general shape of a oneplate distillation curve is often adequate for making engineering calculations, correlating with other physical properties and predicting the product slate. 3.4.1.1  Chromatographic Methods Chromatography is a collective term for a set of methods for separating the constituents of mixtures, either by molecular weight, boiling point, or polarity. For the analysis, the mixture is dissolved in a fluid (referred to as the mobile phase) that carries the mixture through a structure holding another material (referred to as the stationary phase). The various constituents of the mixture travel at different speeds, causing them to separate. The separation is based on differential partitioning between the mobile and stationary phases, and differences in the partition coefficients of the different constituents result in differential retention on the stationary phase, which thus changes the separation. A chromatographic technique may be preparative or analytical. The purpose of preparative chromatography is to separate the components of a mixture for more advanced use (it is thus a form of purification). Analytical chromatography generally requires smaller amounts of material and is for measuring the relative proportions of analytes in a mixture. The two are not mutually exclusive. Analysis by means of adsorption chromatography (see Section 2.1.2) has been applied to a wide variety of feedstock types and products (Speight, 2015). These types of analysis are often abbreviated by the names PONA, PIONA, PNA, PINA, or SARA. The type and relative amounts of certain hydrocarbon classes in the matrix can have a profound effect on the quality and performance of the hydrocarbon product. and two standard test methods have been used predominantly over the years: ASTM D2007 and ASTM D4124. The fluorescent indicator adsorption method (ASTM D1319) has served for over 30 years as the official method of the crude oil industry for measuring the amount of paraffin, olefin, and aromatic hydrocarbon derivatives. The technique consists of displacing a

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sample under iso-propanol pressure through a column packed with silica gel in the presence of fluorescent indicators specific to each hydrocarbon family. Despite its widespread use, fluorescent indicator adsorption has numerous limitations (Suatoni and Garber, 1975; Miller et al., 1983; Norris and Rawdon, 1984). The segregation of individual components from a mixture can be achieved by applying adsorption chromatography in which the adsorbent is either packed in an open tube (column chromatography) or shaped in the form of a sheet (thin-layer chromatography). A suitable solvent is used to elute from the bed of the adsorbent, and the separation is usually performed for the purpose of determining the composition of a sample (Speight, 2014, 2015). Even with such complex samples as feedstock blends as well as extra heavy oil and tar sand bitumen, some information about the chemical structure of a fraction can be gained from the separation data. In the present context, the challenge is the nature of the paraffin constituents in the feedstocks; it is these constituents that are largely responsible for wax deposition during refining operations. In an examination of the potential feedstock for a dewaxing unit, the various compound types should be concentrated into a reasonable number of discrete fractions, and each fraction should contain specific types of heteroatomic compounds. It is also necessary that most of the hetero-compounds be separated from the hydrocarbon derivatives and sulfur compounds that may constitute the bulk of the sample. Additionally, and perhaps the most important aspect of the separation, is that yields of the various fractions and the distribution of the compound types among the fractions should be constant within the limits of experimental error. The analytical procedures should also be relatively simple to perform and free of complexity. Finally, the overall separation procedure should yield quantitative or near quantitative recovery of the various heteroatomic species present in the feedstock. There should be no significant loss of these species to the adsorbent or, perhaps more important, any chemical alteration of these compounds. Chemical alteration could give misleading data that could have serious effects on refining predictions or on geochemical observations. Researchers have developed several methods of analyzing crude oil feedstocks. The following subsections present brief descriptions of how chromatography can be applied to the analysis of feedstocks for dewaxing. The goal of the methods is to identify the presence of waxy constituents in feedstocks and whether or not the feedstock should be submitted to a dewaxing process. 3.4.1.1.1  Gas–Liquid Chromatography Gas–liquid chromatography is a method for separating the volatile components of various mixtures. It is a highly efficient fractionating technique, and it is ideally suited to the quantitative analysis of mixtures when the possible components are known and the interest lies only in determining the amounts of each present. Indeed, gas chromatography has taken over much of the work previously done by the other techniques; it is now the preferred technique for the analysis of hydrocarbon gases, and gas chromatographic in-line monitors are having increasing application in refinery plant control. Gas chromatography analysis has been used extensively for identifying individual components as well as percentage compositions (ASTM D2163, ASTM D2504, ASTM D2505, ASTM D2593, ASTM D2597, ASTM D2712, ASTM D4424, ASTM D4864, ASTM D5303, ASTM D6159) in the gasoline boiling range (ASTM D2427, ASTM D3525, ASTM D3606, ASTM D3710, ASTM D4815, ASTM D5134, ASTM D5441, ASTM D5443, ASTM D5501, ASTM D5580, ASTM D5599, ASTM D5623, ASTM D5845, ASTM D5986); in higher-boiling ranges such as diesel fuel (ASTM D3524), aviation gasoline (ASTM D3606), engine oil, motor oil, and wax (ASTM D5442); and in the boiling-range distribution of feedstock fractions (ASTM D2887, ASTM D5307) or the purity of solvents using capillary gas chromatography (ASTM D2268) (Speight, 2014, 2015). The evolution of gas–liquid chromatography has been a major factor in the successful identification of feedstock constituents. It is, however, almost impossible to apply this technique to the higherboiling feedstock constituents because of the comparatively low volatility. It is this comparative

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lack of volatility in the higher-molecular-weight asphaltic constituents of the feedstock that brought about another type of identification procedure, namely, carbon-type analysis. Gas–liquid chromatography also provides a simple and convenient method for determining n-paraffin distribution throughout the feedstock distillate range. In this method, the n-paraffin hydrocarbon derivatives are first separated by activated chemical destruction of the sieve with hydrofluoric acid, and the identity of the individual paraffin hydrocarbon derivatives is determined chromatographically. This allows n-paraffin distribution throughout the boiling range 170 to 500°C (340 to 930°F) to be determined. Pyrolysis gas chromatography can be used for information on the gross composition of the viscous feedstocks. In this method, the sample to be investigated is pyrolyzed (thermally decomposed), and the products are introduced into a gas chromatography system by which the analysis is obtained. There has also been extensive use of pyrolysis gas chromatography by geochemists to correlate crude oil with source rock and to derive geochemical characterization parameters from oil-bearing strata. 3.4.1.1.2  Gel Permeation Chromatography There are two additional techniques that have evolved from the more recent development of chromatographic methods: (1) gel filtration chromatography and (2) gel permeation chromatography. The first technique was developed using soft, cross-linked dextran beads, and biochemists have been successfully applied the technique to aqueous systems. The second technique employs semirigid, cross-linked polystyrene beads, but in both techniques, the packing particles swell in the chromatographic solvent and form a porous gel structure. The distinction between the methods is based on the observation that the dextran swells to a much greater extent than the polystyrene. Subsequent developments of rigid porous packings of glass, silica, and silica gel have led to their use and classification as packings for gel permeation chromatography. Gel permeation chromatography (also referred to as size exclusion chromatography because of the method of analyzing and identifying the constituents of the mixture), in the simplest representation of the method, consists of employing columns packed with gels of varying pore sizes in a liquid chromatograph (Carbognani, 1997). Under conditions of constant (and stable) flow, the solutes are injected onto the top of the column, whereupon they appear at the detector in order of decreasing molecular weight. The separation is based on the fact that the larger solute molecules cannot be accommodated within the pore systems of the gel beads and thus are eluted first. In contrast, the smaller solute molecules have increasing volume within the beads, depending upon their relative size, and require more time to elute. 3.4.1.1.3  High-Performance Liquid Chromatography High-performance liquid chromatography (HPLC), particularly in the normal phase mode, has found great utility in separating different hydrocarbon group types and identifying specific constituent types (Colin and Vion, 1983; Miller et al., 1983). HPLC has particular value for identifying the molecular types in highly viscous feedstocks, such as heavy crude oil, extra heavy crude oil, and tar sand bitumen. The molecular species in the asphaltene fraction have been of particular interest, leading to identification of the size of polynuclear aromatic systems in the asphaltene constituents (Colin and Vion, 1983; Felix et al., 1985; Speight, 1994). The general advantages of HPLC are (1) each sample is analyzed as received, (2) the boiling range of the sample is generally immaterial, (3) the total time per analysis is usually only minutes, and (4) the method can be adapted for on-stream analysis. 3.4.1.1.4  Ion-Exchange Chromatography Ion-exchange chromatography is widely used in the analyses of feedstock fractions for the isolation and preliminary separation of acid and basic components (Speight, 2015). This technique has the advantage of greatly improving the quality of a complex operation, but it can be very time consuming.

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Cation-exchange chromatography has been used primarily to isolate the nitrogen constituents in a feedstock fraction. The relative importance of these compounds in feedstocks has arisen because of their deleterious effects in many refining processes. They reduce the activity of cracking and hydrocracking catalysts and contribute to gum formation, color, odor, and poor storage properties of the fuel; however, not all basic compounds isolated by cation-exchange chromatography contain nitrogen. Anion-exchange chromatography is used to isolate the acid components (such as carboxylic acids and phenols) from feedstock fractions. 3.4.1.1.5  Supercritical Fluid Chromatography A supercritical fluid is defined as a substance above its critical temperature that has properties not usually found at ambient temperatures and pressures. Use of a fluid under supercritical conditions conveys upon the fluid extraction capabilities that allows the opportunity to improve recovery of a solute. In a chromatographic column, the supercritical fluid usually has a density approximately onethird to one-fourth of that of the corresponding liquid when used as the mobile phase; the diffusivity is approximately 1/100 that of a gas and approximately 200 times that of the liquid. The viscosity is of the same order of magnitude as that of the gas. Thus, for chromatographic purposes, such a fluid has more desirable transport properties than a liquid. In addition, the high density of the fluid results in a 1000-fold better solvency than that of a gas. This is especially valuable for analyzing high-molecular-weight compounds. A primary advantage of chromatography using supercritical mobile phases results from the mass transfer characteristics of the solute. The increased diffusion coefficients of supercritical fluids compared with liquids can lead to greater speed in separations or greater resolution in complex mixture analyses. Another advantage of supercritical fluids compared with gases is that they can dissolve thermally labile and non-volatile solutes and, upon expansion (decompression) of this solution, introduce the solute into the vapor phase for detection. Although supercritical fluids are sometimes considered to have superior solvating power, they usually do not provide any advantages in solvating power over liquids given a similar temperature constraint. In fact, many unique capabilities of supercritical fluids can be attributed to the poor solvent properties obtained at lower fluid densities. This dissolution phenomenon is increased by the variability of the solvent power of the fluid with density as the pressure or temperature changes. The solvent properties that are most relevant for supercritical fluid chromatography are the critical temperature, polarity, and any specific solute–solvent intermolecular interactions (such as hydrogen bonding) that can enhance solubility and selectivity in a separation. Non-polar or low-polarity solvents with moderate critical temperatures (e.g., nitrous oxide, carbon dioxide, ethane, propane, pentane, xenon, sulfur hexafluoride, and various freon derivatives) have been well explored for use in supercritical fluid chromatography. Carbon dioxide has been the fluid of choice in many supercritical fluid chromatography applications because of its low critical temperature (31°C, 88°F), nontoxic nature, and lack of interference with most detection methods. 3.4.1.2  Spectroscopic Methods Distillation is the most widely used separation process in the crude oil industry (Parkash, 2003; Gary et al., 2007; Hsu and Robinson, 2017; Speight, 2017). In fact, knowledge of the boiling range of crude feedstocks and finished products has been an essential part of the determination of feedstock quality since the start of the refining industry. The technique has been used for control of plant and refinery processes as well as for predicting product slates. Thus it is not surprising that routine laboratory-scale distillation tests have been widely used for determining the boiling ranges of crude feedstocks and a whole slate of refinery products (Speight, 2015). There are some limitations to the routine distillation tests. For example, although many heavy crude oils contain volatile constituents, it is not always advisable to use distillation to identify these volatile constituents. Thermal decomposition of the constituents of feedstocks is known to occur at approximately 350°C (660°F), but thermal decomposition of the constituents of the heavier, but

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immature, crude oil has been known to commence at temperatures as low as 200°C (390°F). Thus, the thermal alteration of the constituents and erroneous identification of the decomposition products as natural constituents is always a possibility. The limitations to the use of distillation as an identification technique may be economic, and detailed fractionation of the sample may also be of secondary importance. There have been attempts to combat these limitations, but it must be recognized that the general shape of a one-plate distillation curve is often adequate for making engineering calculations, correlating with other physical properties, and predicting the product slate. Nowhere is the contribution of spectroscopic studies more emphatic than in delineating the structural types in the various feedstocks. This has been necessary because of the unknown nature of these feedstocks by refiners. One particular example is the ndM method (ASTM D3238) that is designed to determine the distribution of carbon types for the structural group analysis of feedstocks (Speight, 2015). However, the intent here is not to convey that any one of these methods can be used for identification purposes. Although these methods may fall short of complete acceptability as methods for the characterization of individual constituents of feedstocks, they can be used as methods by which an overall evaluation of the feedstock may be obtained in terms of various molecular types in the feedstock. 3.4.1.2.1  Infrared Spectroscopy Conventional infrared spectroscopy yields information about the functional features of various feedstock constituents. For example, infrared spectroscopy will aid in the identification of N-H and O-H functions, the nature of polymethylene chains, the C-H out-of-place bending frequencies, and the nature of any polynuclear aromatic systems. With the recent progress over the past four decades in Fourier-transform infrared spectroscopy, quantitative estimates of the various functional groups can also be made. This is particularly important for the higher-molecular-weight solid constituents of a feedstock (i.e. the asphaltene fraction). It is also possible to derive structural parameters from infrared spectroscopic data: (1) saturated hydrogen to saturated carbon ratio, (2) paraffinic character, (3) naphthenic character, (4) methyl group content, and (5) paraffin chain length. In conjunction with proton magnetic resonance (see Section 3.4.1.2.2), structural parameters such as the fraction of paraffinic methyl groups to aromatic methyl groups can be obtained. 3.4.1.2.2  Mass Spectrometry Mass spectrometry can play a key role in the identification of the constituents of feedstocks and products. The principal advantages of mass spectrometric methods are (1) the high reproducibility of quantitative analyses, (2) the potential for obtaining detailed data on the individual components and/or carbon number homologues in complex mixtures, and (3) a minimal sample size is required for analysis. The ability of mass spectrometry to identify individual components in complex mixtures is unmatched by any modern analytical technique; perhaps the exception is gas chromatography. However, there are disadvantages arising from the use of mass spectrometry: (1) the limitation of the method to organic materials that are volatile and stable at temperatures up to 300°C (570°F) and (2) the difficulty of separating isomers for absolute identification. The sample is also usually destroyed, but this is seldom a disadvantage. Nevertheless, in spite of these limitations, mass spectrometry does furnish useful information about the composition of feedstocks and products even if this information is not as exhaustive as might be required. There are structural similarities that might hinder the identification of individual components; consequently, identification by type or by homologue will be more meaningful because similar structural types may be presumed to behave similarly in processing situations. Knowledge of the individual isomeric distribution may add only a little to an understanding of the relationships between composition and processing parameters.

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Mass spectrometry is a technique that should be used discriminately where a maximum amount of information can be expected. The higher-molecular-weight non-volatile constituents are, for practical purposes, beyond the useful range of routine mass spectrometry. In fact, at the elevated temperatures that are necessary to encourage volatility of the sample, thermal decomposition will occur in the inlet of the spectrometer, and any subsequent analysis will be biased toward the low-molecularweight end and to the lower-molecular-weight products produced by the thermal decomposition. 3.4.1.2.3  Nuclear Magnetic Resonance Spectroscopy Nuclear magnetic resonance spectroscopy has frequently been employed for general studies and for structural studies of feedstock constituents (Hasan et al., 1989). In fact, proton magnetic resonance studies (along with infrared spectroscopic studies) were, perhaps, the first studies of the modern era that allowed structural inferences to be made about the polynuclear aromatic systems that occur in the high-molecular-weight constituents of a feedstock. In general, the proton (hydrogen) types in feedstock fractions can be subdivided into five types: (1) aromatic hydrogen, (2) substituted hydrogen next to an aromatic ring, (3) naphthenic hydrogen, (4) methylene hydrogen, and (5) terminal methyl hydrogen remote from an aromatic ring. Other ratios are also derived from which a series of structural parameters can be calculated. However, it must be remembered that the structural details of entities obtained using physical techniques are, in many cases, derived by inference, and some signals can be obscured by intermolecular interactions. This can cause errors in deduction reasoning that can have a substantial influence on the outcome of the calculations (Speight, 1994, 2014, 2015). It is in this regard that carbon-13 magnetic resonance can play a useful role because the method results in an analysis of the distribution of the carbon types and the obvious structural parameter to be determined is the aromaticity, fa.

3.4.2 Use of the Data Thus, through a combination of proton and carbon magnetic resonance techniques, refinements can be made on the structural parameters and for solid state high-resolution carbon-13 magnetic resonance, additional structural parameters can be obtained. In fact, the data derived from using multiple evaluation methods rather than only one described here can be employed to give the refiner an indication of the means by which the crude feedstock should be processed as well as for the prediction of product properties (Dolbear et al., 1987; Wallace and Carrigy, 1988; Speight, 2015). Other properties may also be required for further feedstock evaluation, or, more likely, for comparison between feedstocks even though they may not play any role in dictating which refinery operations are necessary. A simple example of such an application is the ability of the investigator to calculate the yields of product from delayed coking operations by using the carbon residue and the API gravity of the feedstock (Speight, 2014, 2015, 2017). Nevertheless, it must be emphasized that proceeding from the raw evaluation data to full-scale production is not the preferred step; further evaluation of the processability of the feedstock is usually necessary through the use of a pilot-scale operation. To take the evaluation of a feedstock one step further, it may then be possible to develop correlations between the data obtained from the actual plant operations (as well as the pilot plant data) with one or more of the physical properties determined as part of the initial feedstock evaluation. However, it is essential that when such data are derived, the parameters employed be carefully specified. For example, the data presented in the available data were derived on the basis of straightrun residua having API gravity less than 18. The gas–oil end point was 470 to 495°C (875 to 925°F), the gasoline end point was 205°C (400°F), and the pressure in the coke drum was standardized at 35 to 45 psi. Even with such applicability, proceeding from the raw evaluation data to full-scale production is not always the preferred step. Further evaluation of the processability of the feedstock is usually necessary through the use of a pilot-scale operation. To take the evaluation of a feedstock one step

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further, it may then be possible to develop correlations between the data obtained from the actual plant operations (as well as the pilot plant data) with one or more of the physical properties determined as part of the initial feedstock evaluation.

3.5  PROCESS OPTIONS Paraffinic crude oils often contain microcrystalline or paraffin waxes. The crude oil may be treated with a solvent such as MEK to remove this wax before it is processed. There are several processes in use for solvent dewaxing, but all have the same general steps: (1) contacting the feedstock with the solvent, (2) precipitating the wax from the mixture by chilling, and (3) recovering the solvent from the wax and the dewaxed oil for recycling. The processes use benzene-acetone (solvent dewaxing), propane (propane dewaxing), trichloroethylene (separator-Nobel dewaxing), ethylene dichloride-benzene (Barisol dewaxing), and urea (urea dewaxing), as well as liquid sulfur dioxide-benzene mixtures.

3.5.1 The Dewaxing Process Dewaxing, which is often referred to as solvent dewaxing, is a physical process in which the wax is separated from the feedstock by freezing and solvent transport. The current solvent dewaxing process (Figure 3.1) consists of the following steps: (1) crystallization, (2) filtration, and (3) solvent recovery. More specifically, in the crystallization step, the feedstock is diluted with the solvent and chilled to solidify the wax components, thereby allowing the removal of wax from the solution of then dewaxed oil and solvent in the filtration step. Solvent recovery removes the solvent from the wax cake and filtrate for recycling by flash distillation and stripping. The process as practiced in most modern refineries involves mixing the feedstock with one to four times its volume of the ketone after which the mixture is then heated until the oil is in solution and the solution is chilled at a slow, controlled rate in double-pipe, scraped-surface exchangers (Gary et al., 2007; Speight, 2014; Hsu and Robinson, 2017). Cold solvent, such as filtrate from the filters, passes through the two-inch annular space between the inner and outer pipes and chills the waxy oil solution flowing through the inner six-inch pipe.

FIGURE 3.1  A solvent dewaxing unit. Source: OSHA Technical Manual, Section IV, Chapter 2: Petroleum Refining Processes. www.osha.gov/dts/osta/otm/ otm_iv/otm_iv_2.html

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To prevent wax from depositing on the walls of the inner pipe, blades or scrapers extending the length of the pipe and fastened to a central rotating shaft scrape off the wax. Slow chilling reduces the temperature of the waxy oil solution to 2°C (35°F), and then faster chilling reduces the temperature to the approximate pour point required in the dewaxed oil. The mixture is then pumped to a filter case into which the bottom half of the drum of a rotary vacuum filter dips. The drum, 8 feet in diameter, 14 feet long, and covered with filter cloth, rotates continuously in the filter case. A vacuum within the drum sucks the solvent and the oil dissolved in the solvent through the filter cloth and into the drum. The wax crystals collect on the outside of the drum to form a wax cake, and as the drum rotates, the cake is brought above the surface of the liquid in the filter case; sprays of liquid ketone then wash the oil out of the cake and into the drum. A knifeedge scrapes off the wax, and the cake falls into the conveyor and is moved from the filter by the rotating scroll. The deoiled wax is melted in heat exchangers and pumped to a distillation tower operated under vacuum, where a large part of the ketone is evaporated or flashed from the wax. The rest of the ketone is removed by heating the wax and passing it into a fractional distillation tower operated at atmospheric pressure and then into a stripper where steam removes the last traces of ketone. An almost identical system of distillation is used to separate the filtrate into dewaxed oil and ketone, after which both the ketone from both the filtrate and wax slurry can be reused. Clay treatment or hydrotreating finishes the dewaxed oil as previously described. The wax (slack wax) contains essentially no oil, in contrast with the 50% in the slack wax obtained by cold pressing, but it is still the raw material for either sweating or wax recrystallization, which subdivides the wax into a number of wax fractions with different melting points (Gary et al., 2007; Speight, 2014). Solvent dewaxing is multifunctional in that the process can be applied to light, intermediate, and heavy lubricating oil distillates, but each distillate produces a mixture of a number of waxes. For example, the wax obtained from light paraffin distillate consists of a series of paraffin waxes that have melting points in the range of 30 to 70°C (90 to 160°F), which are characterized by a tendency to harden into large crystals. However, heavy paraffin distillate yields a wax composed of a series of waxes with melting points in the range of 60 to 90°C (140 to 200°F), which harden into small crystals from which they derive the name of microcrystalline wax or microwax. The major processes that are currently used are ketone dewaxing as well as the Di/Me process and propane dewaxing. The most widely used ketone processes are Texaco solvent dewaxing process and the Exxon Dilchill process. Both processes consist of diluting the waxy feedstock with solvent while chilling at a controlled rate to produce a slurry. The slurry is filtered using rotary vacuum filters, and the wax cake is washed with cold solvent. The filtrate is used to prechill the feedstock and solvent mixture. In order to further reduce the oil content of the wax, the primary wax cake is diluted with additional solvent and filtered a second time. The solvent recovered from the dewaxed oil and wax cake by flash vaporization is recycled back into the process. The Dilchill process produces large, dense, spherical wax crystals, resulting in superior separation of oil from wax. The separation takes place more readily than with the conventional, ­incremental-dilution solvent technology because of the higher attainable filtration rates. In an additional processing step, the dewaxed slack wax may be mixed with warm solvent (warmup deoiling) to melt the outer soft-wax structure of the crystals and, by re-filtration, a fully deoiled, hard-wax product is recovered. Di/Me dewaxing uses a mixture of dichloroethane (CH2ClCH2Cl) and methylene dichloride (CH2Cl2) as the dewaxing solvent. Propane dewaxing is essentially the same as the ketone process except for the following: (1) Propane is used as the dewaxing solvent, (2) higher-pressure equipment is required, and (3) chilling takes place in evaporative chillers by vaporizing a portion of the dewaxing solvent. Although this process generates a better product and does not require crystallizers, the temperature difference between the dewaxed oil and the filtration temperature is higher than that for the ketone processes (higher energy costs), and dewaxing aids are required to obtain good filtration rates.

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3.5.2 Optional Processes Other processes that are available or have been used in the past include (1) centrifuge dewaxing, (2) cold press, (3) distillate dewaxing, (4) Isodewaxing, and (5) urea dewaxing. An overview of each of these processes is presented in the following subsection. 3.5.2.1  Centrifuge Dewaxing Another method of separating petrolatum (a semisolid mixture of hydrocarbons obtained from crude oil also called petroleum jelly) from reduced crude is centrifuge dewaxing. In this process, the reduced crude is dissolved in naphtha and chilled to around −18°C (0°F), which causes the wax to separate. The mixture is then fed to a battery of centrifuges where the wax is separated from the liquid. However, the centrifuge method has now been largely displaced by solvent dewaxing and more modern methods of wax removal. The use of the centrifuge for dewaxing lubricating oil arose because of the need to obtain better results than had been attained by the cold settling dewaxing process, which at the time was the only known method for dewaxing steam-refined cylinder stock (the residual material that remains after the vaporization of lower boiling base oil), the product known as bright stock being commonly used for building up ‘pressed’ (i.e. dewaxed) neutrals. The process consisted of mixing the cylinder stock with approximately one and one-half times its volume of naphtha, heating it to completely dissolve all of the oil and wax and then slowly chilling to a temperature of around −9°C (15°F) in insulated tanks, which led to precipitation and gravity settling of the wax. The supernatant liquid was then drawn off and the naphtha distilled off, leaving a still residue of bright stock. Any settling product of a sludge-type nature was withdrawn, and after removing the naphtha by distillation, the residue was designated petrolatum. At some point in the process, preferably after the dilution but before chilling, the mixture was decolorized by percolation through an adsorbent, commonly through Fuller’s earth. 3.5.2.2  Cold Press Dewaxing Cold press dewaxing uses the principle that a low temperature causes the materials to the oil content of crystalline wax to be easily removed, and investigators developed methods to dewax the high-viscosity paraffinic oils. The methods were alike in that the waxy oil was dissolved in a solvent that would keep the oil in solution and thereby allow the wax to separate as crystals when the temperature was lowered. The processes differed chiefly in the use of the solvent, although the commercially used solvents were naphtha, propane, sulfur dioxide, acetone-benzene, trichloroethylene, ethylene dichloride-benzene (the Barisol process), methyl ethyl ketone-benzene (the Benzol process), methyl-n-propyl ketone [CH3C(=O)CH2CH2CH3], and methyl-n-butyl ketone [CH3C(=O) CH2CH2CH2CH3]. Thus, the lowest-viscosity paraffinic oils were dewaxed by the cold press method to produce oils with a pour point of 2°C (35°F). In the case of the low-boiling (low-density) paraffin distillate oils, the paraffin wax crystallized into large crystals when chilled that could be readily separated from the oil. 3.5.2.3  Distillate Dewaxing In this process, waxy distillate feedstocks are dewaxed by being passed over a catalyst bed containing a mixture of medium- and large-pore zeolites in the presence of a hydrogenation component. An example of the process is ExxonMobil distillate dewaxing (Smith et  al., 1980), by which dewaxing is achieved by selective cracking in which the long paraffin chains are cracked to form shorter chains using a shape-selective zeolite that rejects ring compounds and iso-paraffin hydrocarbon derivatives. In a related process, the paraffin hydrocarbon derivatives are selectively isomerized using low-pressure conditions (Smith et al., 1980). This process also uses a zeolite catalyst to convert low-quality gas-oil into diesel fuel.

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In the process, the catalyst can be reactivated to fresh activity by relatively mild non-oxidative treatment. Of course, the time allowed between reactivation is a function of the feedstock, but after numerous reactivations, it is possible that there will be coke buildup on the catalyst. The process can be used to dewax a full range of lubricating base stocks, and as such has the potential to completely replace solvent dewaxing or can even be used in combination with solvent dewaxing. This latter option, of course, serves to de-bottleneck existing solvent dewaxing facilities. Both the catalytic dewaxing processes have the potential to change the conventional thoughts about dewaxing inasmuch as they are not solvent processes and may be looked upon more correctly as thermal rather than treatment processes. 3.5.2.4 Isodewaxing Isodewaxing catalytically isomerizes the molecular structure of the wax into C20+ iso-­paraffin hydrocarbon derivatives that have a high VI, low pour point, and resistance to oxidation. Furthermore, because the process preserves the paraffinic character of the base oil, Isodewaxing can produce a higher index in the product and/or a higher yield than other dewaxing processes. In the process, which is followed by a hydrofinishing step, waxy feedstock from a hydrocracker or hydrotreater, together with the hydrogen-containing gas, is heated and fed to the Isodewaxing reactor in which normal paraffin derivatives are isomerized to iso-paraffin hydrocarbon derivatives with a high VI and lower pour point. Other paraffin derivatives are cracked to highly saturated lowboiling products, such as high smoke point jet and high cetane index diesel fuel. The effluent from the Isodewaxing reactor is then sent to the hydrofinishing unit, where hydrofinishing, including the saturation of aromatic constituents, provides the product. The catalysts used in the Isodewaxing and hydrofinishing units are selective for dewaxing and hydrogenation. The catalysts are at their maximum efficiency with low sulfur and low nitrogen feedstocks. The process generally uses a high-pressure recycling loop. Because of the conversion of wax constituents to other usable products, the process has obvious benefits over solvent dewaxing because it yields a higher-quality product. The finishing technology (referred to as Isofinishing) uses noble metal catalysts (which require lower operating temperatures than base metal catalysts for the equivalent product oxidation stability) to remove aromatic constituents from the product and obtain excellent oxidation stability in the product. Isofinishing can also be a stand-alone process. 3.5.2.5  Urea Dewaxing Urea dewaxing warrants mention because it is highly selective and, in contrast to the other dewaxing techniques, it can be achieved without refrigeration. The process is used for producing ­low-pour-point oils in which urea (H2NCONH2) forms a solid complex (an adduct) in which it selectively crystallizes around long, straight-chain paraffin hydrocarbon derivatives to form a filterable solid (the adduct). This selectivity of adduct formation is a function of the cross-section of the hydrocarbon molecules as related to the geometry of the urea crystal. The conditions in the reactor, that is, (1) the temperature, (2) the water content, (3) the urea-to-feedstock ratio, (4) the ­solvent-to-feedstock ratio, (4) the flow and mixing, and (5) the type of solvent, determine the structure of the adduct (Mohammed and Akram, 2010). Furthermore, in contrast to the other dewaxing techniques, urea dewaxing can be achieved without refrigeration, and the process is particularly useful for producing a range of lubricating oils. In addition, the purity of recovered n-paraffin is often very low because of non-normal hydrocarbons participating in the adduct formation. Because of the oil viscosity, good contact between oil and urea is not achieved, and difficulties are encountered during filtration, and it is necessary to use a solvent to avoid these troubles. This solvent must dissolve oil and wax but not the urea. Urea dewaxing results in the selective crystallization of paraffin hydrocarbon derivatives with long straight chains, and the product is in the form of a solid, filterable complex or adduct. This selectivity of adduct formation is a function of the cross-section of the hydrocarbon molecules as

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related to the geometry of the urea crystal. The conditions in the reactor (temperature, water content, urea to feed and solvent to feed ratio, flow and mixing, type of solvent and/or activator, etc.) will determine the structure of the adduct. X-ray studies indicate that the crystal structure of urea changes from a tetragonal to a hexagonal system during the complex formation process. The urea molecules wrap around the straight-chain molecules in a hexagonal spiral, and the spirals form channels having a diameter of approximately 5 Angstrom units, large enough to accommodate straight-chain but not branched-chain or cyclic molecules (an Angstrom is a unit of length equal to one hundred-millionth of a centimeter, i.e. 1 centimeter × 10 –8 or 10 −10 meter).

3.6  FOULING DURING DEWAXING Crude oil comprises a mixture of molecules of different molecular weight and (in many cases) polarity, with low-molecular-weight species such as methane that are responsible for solid hydrate formation at high pressure and low temperature and high-molecular-weight constituents (such as the long-chain linear alkane hydrocarbon derivatives and the iso-paraffin hydrocarbon derivatives) that tend to change phase at low temperature in both the macrocrystalline and microcrystalline phases. As introduced in the deasphalting chapter (Chapter 2), the term ‘fouling’ as it pertains to the crude oil refining industry and in the context of this chapter refers to (1) deposit formation, (2) encrustation, (3) scale formation, (4) slagging, and (5) sludge formation, any of which can have an adverse effect on operations. In the current context, fouling is the accumulation of unwanted material (such as wax) within a processing unit or on the solid surfaces of the unit that has an adverse effect on the function of the unit. 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 increased maintenance costs. Wax from crude oil has a myriad of uses, especially in the petrochemical industry when the wax can be converted to other products (Speight, 2014, 2017, 2019). However, the separation of wax from a liquid during process operations (often referred to as wax deposition or wax precipitation) can cause the wax to be categorized as a foulant (Theyab, 2018). However, wax deposition and wax precipitation are in fact different concepts. Wax deposition refers to the formation of a layer of separate solid phase and the eventual growth of this layer on a surface in contact with the crude oil or the crude oil product. Wax deposits can be formed from an already precipitated solid phase (wax) through shear dispersion, gravity settling, and Brownian motion or from dissolved wax molecules through molecular diffusion. The deposition of waxy constituents can result in (1) the restriction of crude oil flow in the pipeline, (2) the creation of pressure abnormalities, and (3) an artificial blockage that leads to a reduction or interruption in the production. In some circumstances, such interruption can be the cause for a pipeline or a production facility to be abandoned. One of the important aspects of wax deposition is that the wax is not always a solid but may be in the form of a gel that consists of solid wax crystals and trapped liquid. The precipitation of wax components out of a crude oil or from a crude oil product is responsible for changes in the crude oil properties or the product properties, including the gelation of the liquid and an increase in the viscosity. The main factor that affects the wax deposition is a low temperature (especially a sudden drop in temperature). Therefore, wax deposition prevention becomes very important in handling many waxy crude oils and waxy products Fouling, as exemplified by the deposition of wax during oil refining, can occur in a variety of processes when the wax constituents are present in the feedstock or are products of the process and is detrimental to the process as well as to any succeeding process. Thus, the separation of waxy solids can occur whenever the solvent characteristics of the liquid phase are no longer adequate to

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maintain the waxy constituents in solution. Examples of such occurrences are (1) wax separation when there is a drop in temperature or the aromaticity of the liquid medium increases; (2) the formation of waxy sludge or waxy sediment in a reactor, which occurs when the solvent characteristics of the liquid medium change so that the wax materials separate; and (3) sludge or sediment formation in fuel products, which occurs because of the interplay of several chemical and physical factors such as the separation of waxy constituents during the transportation and use of waxy crude oils or waxy crude oil products. In short, in the same way as deasphalting (Chapter  2), dewaxing is used to remove potential foulants from crude oil and crude oil products, and both the resulting crystalline wax and microcrystalline wax that occur in lubricating oil fractions derived from crude oil feedstocks are undesirable components of the finished oils. Advances during the past several decades have resulted in the extensive use of solvents for dewaxing. Solvent dewaxing is a conventional process for producing lubricating oil. Except for a small volume of lubricating oils from naphthenic crude oils, most base stocks for lubricating oil manufacture are derived from waxy crude oils. The wax must be removed from the base stocks to give the lubricating oil product good ambient- and low-temperature lubricant performance. Removal of wax achieves the low pour point and cloud point specifications of the base stocks. The recovered wax (slack wax) may be fed to catalytic or steam cracking units, but often refiners upgrade it by producing a high-margin, hard wax product that requires the dewaxed slack wax to be further processed in a deoiling step. Although there are several processes in use for solvent dewaxing, all have the same general steps. Other solvents beyond the standard that are sometimes used include benzene, methyl isobutyl ketone, propane, petroleum naphtha, ethylene dichloride, methylene chloride, and sulfur dioxide, and there is also a catalytic as well as a non-catalytic solvent dewaxing process. Further developments will occur in the types of catalysts designed for dewaxing, and future refineries will make greater use of membrane separators. A membrane process can be used to prevent hold-ups in the refrigeration and recovery sections of a solvent lubricating plant. However, the membrane will require a high flux and must be robust and able to withstand continuous service. In addition, with the use of microwave technology steadily growing in industrial processes and the wax interacting with the electromagnetic energy of the microwaves, it will not be surprising to see such an installation is the refinery of the future where wax may arise from additional sources (including bio-sources) and have different properties that are not conducive to separation by the typical dewaxing process. The terms ‘wax deposition’ or ‘paraffin deposition’ refer to the accumulation of paraffin wax on the surface of a substance, typically a liquid or gas. This can occur in a variety of contexts, including the production and transport of oil and natural gas, the refining of petroleum products, and the storage and transport of chemicals. For the transportation of crude oil in a pipeline, wax can be deposited on to the inner surface of the pipeline, reducing the area and increasing the pressure requirement for fluid to flow. To prevent wax deposition, various techniques can be used, including heating the fluid to dissolve wax back into the oil phase, adding chemicals to prevent wax formation, and using specialized equipment or a pig to remove the wax deposit from the pipe wall surface. In addition, the term ‘wax deposition’ should not be confused with the term ‘wax precipitation’. The precipitation of wax refers to the phase change of the dissolved wax in liquid phase into solid wax particles. This phenomenon is governed by the thermodynamic equilibrium of wax in oil. The wax precipitation is a necessary but not sufficient condition for wax deposition to occur: Rather, the solid surface temperature for wax to be deposited on must be lower than the temperature of waxy oil solution. Wax deposition can restrict crude oil flow in the pipeline, creating pressure abnormalities and reducing or interrupting the production, sometimes to the extent that the pipeline or production facility is abandoned. Wax deposition also leads to formation damage near the wellbore, reduction in permeability, and changes in the reservoir fluid composition and fluid rheology due to phase separation as wax solid precipitates. One of the important issues to be noted is that the wax deposit

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is not solid wax but a gel that consists of solid wax crystals and trapped liquid. The deposit may also harden with time. The precipitation of wax out of a crude oil is responsible for changes in the properties of the crude oil properties, including the gelation of oil and an increase in viscosity. Wax contains a ­high-molecular-weight n-paraffin derivatives that consist of long-chain alkane hydrocarbon derivatives with 20 to 50 carbon atoms. Wax can precipitate as a solid phase when the crude oil temperature drops below the wax appearance temperature, the temperature at which the first wax crystals start to form in the crude oil in a cooling process. The precipitated wax constituents near a pipe wall start to form an incipient gel at the cold surface. The incipient gel formed at the pipe wall is a three-dimensional network structure of wax crystals and contains a significant amount of oil trapped within it. The gel grows over time, and there are radial thermal and mass transfer gradients as a result of heat loss to the surrounding area. Moreover, there are several factors that affect wax deposition in pipelines, such as pipe wall temperature (inlet coolant temperature), crude oil composition, crude oil temperature, ambient temperature, flow rate, thermal history, time, and pressure.

REFERENCES Ali, Q.Y.M. 2014. Effect of Dewaxing on Some Properties of Crude Oil and Diesel at the Kurdistan Region – Iraq. International Journal of Advanced Scientific and Technical Research, 2(4): 598–603. https://rspublication.com/ijst/2014/april14/53.pdf. As’ad, A.M., Yeneneh, A.M., and Obanijesu, E.O. 2015. Solvent Dewaxing of Heavy Crude Oil with Methyl Ethyl Ketone. Journal of Petroleum  & Environmental Biotechnology, 6(2): 213–218. www. researchgate.net/publication/276139540_Solvent_Dewaxing_of_Heavy_Crude_Oil_with_Methyl_ Ethyl_Ketone. ASTM D1319. 2022. Standard Test Method for Hydrocarbon Types in Liquid Petroleum Products by Fluorescent Indicator Adsorption. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D2163. 2022. Standard Test Method for Determination of Hydrocarbons in Liquefied Petroleum (LP) Gases and Propane/Propene Mixtures by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D2268. 2022. Standard Test Method for Analysis of High-Purity n-Heptane and Isooctane by Capillary Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D2427. 2022. Standard Test Method for Determination of C2 through C5 Hydrocarbons in Gasolines by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D2504. 2022. Standard Test Method for Non-condensable Gases in C2 and Lighter Hydrocarbon Products by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D2505. 2022. Standard Test Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D2593. 2022. Standard Test Method for Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D2597. 2022. Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D2712. 2022. Standard Test Method for Hydrocarbon Traces in Propylene Concentrates by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D2887. 2022. Standard Test Method for Boiling Range Distribution of Petroleum Fractions by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D3525. 2022. Standard Test Method for Gasoline Diluent in Used Gasoline Engine Oils by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D3606. 2022. Standard Test Method for Determination of Benzene and Toluene in Finished Motor and Aviation Gasoline by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D3710. 2022. Standard Test Method for Boiling Range Distribution of Gasoline and Gasoline Fractions by Gas Chromatography. Annual Book of Standards, ASTM International, West Conshohocken, PA.

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ASTM D4124. 2022. Standard Test Method for Separation of Asphalt into Four Fractions. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D4424. 2022. Standard Test Method for Butylene Analysis by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D4815. 2022. Standard Test Method for Determination of MTBE, ETBE, TAME, DIPE, Tertiary-Amyl Alcohol and C1 to C4 Alcohols in Gasoline by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D4864. 2022. Standard Test Method for Determination of Traces of Methanol in Propylene Concentrates by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D5134. 2022. Standard Test Method for Detailed Analysis of Petroleum Naphtha through ­n-Nonane by Capillary Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D5303. 2022. Standard Test Method for Trace Carbonyl Sulfide in Propylene by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D5307. 2022. Standard Test Method for Determination of Boiling Range Distribution of Crude Petroleum by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D5441. 2022. Standard Test Method for Analysis of Methyl Tert-Butyl Ether (MTBE) by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D5442. 2022. Standard Test Method for Analysis of Petroleum Waxes by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D5443. 2022. Standard Test Method for Paraffin, Naphthene, and Aromatic Hydrocarbon Type Analysis in Petroleum Distillates through 200°C by Multi-Dimensional Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D5501. 2022. Standard Test Method for Determination of Ethanol and Methanol Content in Fuels Containing Greater than 20% Ethanol by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D5580. 2022. Standard Test Method for Determination of Benzene, Toluene, Ethylbenzene, p/m-Xylene, o-Xylene, C9 and Heavier Aromatics, and Total Aromatics in Finished Gasoline by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D5599. 2022. Standard Test Method for Determination of Oxygenates in Gasoline by Gas Chromatography and Oxygen Selective Flame Ionization Detection. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D5623. 2022. Standard Test Method for Sulfur Compounds in Light Petroleum Liquids by Gas Chromatography and Sulfur Selective Detection. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D5845. 2022. Standard Test Method for Determination of MTBE, ETBE, TAME, DIPE, Methanol, Ethanol and t-Butanol in Gasoline by Infrared Spectroscopy. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D5986. 2022. Standard Test Method for Determination of Oxygenates, Benzene, Toluene, C8–C12 Aromatics and Total Aromatics in Finished Gasoline by Gas Chromatography/Fourier Transform Infrared Spectroscopy. Annual Book of Standards. ASTM International, West Conshohocken, PA. ASTM D6159. 2022. Standard Test Method for Determination of Hydrocarbon Impurities in Ethylene by Gas Chromatography. Annual Book of Standards. ASTM International, West Conshohocken, PA. Briens, C.L., Ewener, P.C., and Sankey, B.M. 1987. Solvent Dewaxing of Waxy Hydrocarbon Distillates. European Patent Office, No. 0160754. https://patentimages.storage.googleapis.com/86/d6/ca/7a655 49700413b/EP0160754B1.pdf. Burger, E.D., Perkins, T.K., and Striegler, J.H. 1981. Studies of wax deposition in the trans-Alaska pipeline. Journal of Petroleum Technology, 33: 1075–1086. Carbognani, L. 1997. Fast Monitoring of C20-C160 Crude Oil Alkanes by Size-Exclusion ChromatographyEvaporative Light Scattering Detection Performed with Silica Columns. Journal of Chromatography A, 788: 63–73. Colin, J.M., and Vion, G. 1983. Routine Hydrocarbon Group-Type Analysis in Refinery Laboratories by HighPerformance Liquid Chromatography. Journal of Chromatography, 280: 152–158. Dolbear, G.E., Tang, A., and Moorehead, E.L. 1987. Upgrading Studies with California, Mexican, and Middle Eastern Heavy Oils. In: Metal Complexes in Fossil Fuels. R.H. Filby and J.F. Branthaver (Editors). Symposium Series No. 344. American Chemical Society, Washington, DC. Page 220. Eghbali, M.H., Solaimany Nazar, A.R., and Tavakoli, T. 2013. An Experimental Study on the Operational Factors Affecting the Oil Content of Wax During Dewaxing Process: Adopting a DOE Method. Iranian

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Journal of Oil & Gas Science and Technology, 2(1): 1–08. https://ijogst.put.ac.ir/article_3033_08c7bb0 1536f34834d4d1bd8ffaa43eb.pdf. Felix, G., Bertrand, C., and Van Gastel, F. 1985. Hydroprocessing of Heavy Oils and Residua. Chromatographia, 20(3): 155–160. Gary, J.H., Handwerk, G.E., and Kaiser, M.J. 2007. Petroleum Refining: Technology and Economics, 4th Edition, Marcel Dekker Inc., New York. Hasan, M., Ali, M.F., and Arab, M. 1989. Structural Characterization of Saudi Arabian Extra Light and Light Crudes by 1-H and 13-C NMR Spectroscopy. Fuel, 68: 801–803. Hsu, C.S., and Robinson, P.R. (Editors) 2017. Handbook of Petroleum Technology. Springer AG, Cham, Switzerland. Miller, R.L., Ettre, L.S., and Johansen, N.G. 1983. Quantitative Analysis of Hydrocarbons by Structural Group Type in Gasoline and Distillates. Part II. Journal of Chromatography, 259: 393. Mohammed, A-H.A., and Akram, N.S.D. 2010. The Effect of Operating Conditions of Urea Dewaxing on the Pour Point of Light Lubricating Oil. Iraqi Journal of Chemical and Petroleum Engineering, 11(1): 59–63. Mohyaldinn, M.E., Husin, H., Hasan, N., Mohamed, M.B., Elmubarak, M.H.B., Genefid, A.M.E., and Dheeb, M.E.A. 2019. Challenges During Operation and Shutdown of Waxy Crude Pipelines. Processing of Heavy Crude Oils – Challenges and Opportunities. IntechOpen. www.intechopen.com/chapters/69274. Norris, T.A., and Rawdon, M.G. 1984. Determination of Hydrocarbon Types in Petroleum Liquids by Supercritical Fluid Chromatography with Flame Ionization Detection. Analytical Chemistry, 56: 1767–1769. Parkash, S. 2003. Refining Processes Handbook. Gulf Professional Publishing, Elsevier, Amsterdam, The Netherlands. Richter, F. 2002. Effect of Waxes on Bitumen Quality. Oil Gas European Magazine (2): 35–38. Ruben, F.G., Visintina, T.P., Lockharta, R.L., and Paolo, D. 2008. Structure of Waxy Crude Oil Emulsion Gels. Journal of Non-Newtonian Fluid Mechanics, 149(1–3): 34–39. Sadeghazad, A., and Christiansen, R.L. 1998. The Effect of Cloud Point Temperature on Wax Deposition in the 8 Abu Dhabi International Petroleum Exhibition and Conference. U.A.E., Abu Dhabi. Smith, K.W., Starr, W.C., and Chen, N.Y. 1980. New Process Dewaxes Lube Base Stocks. Oil & Gas Journal, 78(21): 75. Speight, J.G. 1994. Chemical and Physical Studies of Petroleum Asphaltenes. In: Asphaltenes and Asphalts, I. Developments in Petroleum Science, 40. T.F. Yen and G.V. Chilingarian (Editors). Elsevier, Amsterdam, The Netherlands. Chapter 2. Speight, J.G. 2014. The Chemistry and Technology of Petroleum, 5th Edition. CRC Press, Taylor & Francis Group, Boca Raton, FL. Speight, J.G. 2015. Handbook of Petroleum Product Analysis, 2nd Edition. John Wiley & Sons Inc., Hoboken, NJ. Speight, J.G. 2017. Handbook of Petroleum Refining. CRC Press, Taylor & Francois Group, Boca Raton, FL. Speight, J.G. 2019. Handbook of Petrochemical Processes. CRC Press, Taylor & Francis Group, Boca Raton, FL. Suatoni, J.C., and Garber, H.R. 1975. HPLC Preparative Group-Type Separation of Olefins from Synfuels. Journal of Chromatographic Science, 13: 367. Theyab, M.A. 2018. Wax Deposition Process: Mechanisms, Affecting Factors and Mitigation Methods. Open Access Journal of Science, 2(2): 109–115. https://medcraveonline.com/OAJS/wax-deposition-processmechanisms-affecting-factors-and-mitigation-methods.html. Tripathy, A.S., Nath, G., Sahoo, G., and Paikaray, R. 2021. Solvent Treatment on Cloud Point for Dewaxing in Crude Oil Industries. Journal of Scientific & Industrial Research, 80: 115–121. https://nopr.niscpr.res.in/ bitstream/123456789/56132/1/JSIR%2080%282%29%20115-121.pdf. Wallace, D., and Carrigy, M.A. 1988. New Analytical Results on Oil Sands from Deposits Throughout the World. Proceedings. 3rd UNITAR/UNDP International Conference on Heavy Crude and Tar Sands. R.F. Meyer (Editor). Alberta Oil Sands Technology and Research Authority, Edmonton, Alberta, Canada. Wauquier, J-P. 2000. Petroleum Refining, Volume 2 – Separation Processes. Editions Technip, Paris, France.

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Solvent-Based Processes

4.1 INTRODUCTION Although the focus of the earlier chapters of this book has been on deasphalting and dewaxing, it would be remiss to omit the other solvent processes that are used in the refinery such as the processes that are used for product treating (this chapter) and for treating the various gas streams that occur in the refinery (Gary et al., 2007; Speight, 2011; Marchetti et al., 2014; Speight, 2014; Hsu and Robinson, 2017; Speight, 2017Khani and Rezaeye, 2018). However, it must be understood that in many cases, the solvent is an aqueous (i.e. water-based) solvent, and it is not always organic. As already noted (Chapter 1), crude oil and the products arising therefrom have been used for millennia, leading to crude oil being an important raw material for the modern world (Abraham, 1945; Forbes, 1958a, 1958b, 1959; James and Thorpe, 1994). Crude oil provides not only raw materials for the ubiquitous plastics and other products but also fuel for energy, industry, heating, and transportation. Thus, the use of crude oil and the development of related technology is not such a modern subject as we are inclined to believe. The crude oil industry is essentially a 20th-century industry; nevertheless, to understand the evolution of the industry, it is essential to have a brief understanding of the first uses of crude oil. From a chemical standpoint, crude oil is an extremely complex mixture of hydrocarbon compounds, usually with minor amounts of nitrogen-, oxygen-, and sulfur-containing compounds as well as trace amounts of metal-containing compounds (Chapter  7) (Speight, 2001, 2002, 2014, 2017). In addition, the properties of crude oil vary widely and are not conducive to modern-day use as used in the early days of the refining industry. Thus, crude oil is not used in its raw state; instead, a variety of processing steps are required to convert crude oil from its raw state to products that are usable in modern society. The fuel products that are derived from crude oil supply more than half of the total supply of energy of the world given that naphtha and diesel fuel provide fuel for automobiles, tractors, trucks, aircraft, and naval vessels. Crude oil products are also the basic materials used for the manufacture of synthetic fibers for clothing and in plastics, paints, fertilizers, insecticides, soaps, and synthetic rubber. In fact, the uses of crude oil as a source of raw material in manufacturing are central to the functioning of modern industry (Gary et al., 2007; Speight, 2011, 2014; Hsu and Robinson, 2017; Speight, 2017). For the purposes of terminology, it is preferable to subdivide crude oil and related materials into three major classes (Speight, 2014, 2017): (1) materials that are of natural origin, (2) materials that are manufactured, and (3) materials that are integral fractions derived from the natural or manufactured products. The materials included in categories 1 and 2 are relevant here because of their participation in product streams. Straight-run constituents of crude oil (i.e. constituents distilled without change from crude oil) are used in products. Manufactured materials are produced by a variety of processes and are also used in product streams. Category 3 materials are usually those materials that are isolated from crude oil or another product using a variety of techniques (Speight, 2014, 2017), and they are not included here. Producing liquid products by distillation or by cracking is the first of a series of process operations that lead to the production of marketable liquid products and are followed by secondary processes or product improvement processes because they are not used directly on the crude oil but are used on primary product streams that have been produced from the crude oil (Gary et al., 2007; Speight, 2011, 2014; Hsu and Robinson, 2017; Speight, 2017). In addition, the term product improvement, as used in this chapter, includes processes such as reforming in which the molecular structure of the feedstock is reorganized. An example is the DOI: 10.1201/9781003185277-4

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conversion of n-hexane to cyclohexane or cyclohexane to benzene. These processes reform or rearrange one particular molecular type to another, thereby changing the properties of the product relative to the feedstock. Such processes expand the utility of products and are also not the subject of this chapter. It is, rather, the purpose of this chapter to present the concepts behind these secondary processes with specific examples of those processes that have reached commercialization. It must be understood that the process examples presented here are only a selection of the total available. The choice of a process for inclusion here was made to illustrate the different process types that are available.

4.2  SOLVENT-BASED PROCESSES The solvent-based processes that are used in the refinery are commonly based on the principle of solvent extraction, that is, the removal of a solute component from a solid using a liquid solvent, which is one of the modern extraction processes in a refinery (Chapter 1). In many cases, the solvent is an aqueous solution of a solute that is suitable for treatment of the product, and the process may be referred to as leaching, washing, or solid–liquid extraction. In solvent extraction (also known as liquid–liquid extraction or partitioning), a mixture of two or more constituents is treated with a solvent that preferably dissolves one or more of the constituents in the mixture to produce a raffinate (the insoluble portion) and an extract (the soluble constituents) that appears in the solvent-rich phase. The solute is the component transferred from the raffinate to the extract, while the diluent is the component left behind in the raffinate. The solvent in the extract that leaves the extractor is usually collected and reused (Figure 4.1). The feedstocks to solvent extraction have typically been vacuum distillate fractions such as vacuum gas oil and the soluble oil from the deasphalting process. These feedstocks are suitable for the production of lubricating oil base stock. In addition, the hydrocarbon-types solvents derived from crude oil in the refinery, in addition to aromatic solvents such as toluene, are often divided into three (or more) groups: (1) special boiling point spirits, (2) white spirits, and (3) kerosene-type solvents (Table 4.1). The special boiling point spirits and the white spirits are produced in the distillation section of the refinery. However, other important solvents that are used in the refinery may not be produced onsite but are brought to the site from the manufacturer. For example, solvents such as phenol, furfural, and n-methyl pyrrolidone are often utilized in refineries (Table 4.2). These solvents have a strong affinity for aromatic hydrocarbon derivatives. The processed feedstock, the pollutants present, and

FIGURE 4.1  Simplified schematic of the solvent extraction process.

TABLE 4.1 Examples of Hydrocarbon-type Solvents Produced in a Refinery Solvent type*

Boiling range, °C

Boiling range, °F**

Special boiling point spirits

30 to 160

86 to 320

White spirits

150 to 210

300 to 410

Kerosene-type solvents

160 to 300

320 to 570

  * Names and boing range will vary within the refinery system. ** Rounded to the nearest 5°

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TABLE 4.2 General Properties of Solvents Used in a Refinery Solvent

Phenol

Furfural

N-Methyl-2-pyrrolidone C5H9NO

Molecular formula

C6H6O

C5H4O2

Molecular weight

94

96

99

Boiling point, °C

182

162

204

°F

399

359

323

Flash point °C

80

58

56

°F

175

137

187

Melting point, °C

40

-38

-82

°F

106

-7

-12

1.07

1.16

1.03

Specific gravity

the finished product requirements all affect the selection of specific processes and any necessary chemical agents. In solvent-based processes, the lubricating oil feedstocks and the solvent are contacted in a trayed column countercurrently. There are several types of continuous treater tower designs used in conventional lube plants; examples include trayed towers, packed towers, and rotating disk contactors. The internal components of the tower that is used for the treating process are designed to promote intimate contact of the extractable material with the solvent to enable the oil and the solvent phases. The aromatic constituents are extracted from the upward-flowing stream, which is enriched in paraffin constituents. However, the complete removal of the aromatic constituents from the feedstock is desired from the feed, and therefore, the removal of aromatic constituents is carefully selected based on the required adjustment of the viscosity and viscosity index of the final product. The raffinate stream exits from the top of the tower and is sent to a solvent recovery section for the separation and recovery of the solvent from this stream. The separation of the solvent is achieved by vacuum flashing and steam stripping under the vacuum. The extract stream, which contains the bulk of the solvent, exits the bottom of the extraction tower and is sent to the recovery section in which the solvent is separated from the extract phase by multiple-effect evaporation at various pressures followed by vacuum flashing and steam stripping under vacuum. The overhead vapors from the steam strippers are condensed and combined with solvent condensate from recovery sections and distilled at low pressure to remove water from the solvent. The stripped solvent subsequently undergoes some regeneration to prepare the solvent phase for recycling. The stripped solution is then treated to remove the desired product before recycling the solvent. Another frequently used solvent that is of value is water, which is not always given the recognition that it deserves as a solvent. Water can exhibit excellent solvent properties because the relatively small size of water molecules typically allows many water molecules to surround one molecule of solute. Briefly, water (H2O) is a polar molecule that has a partially positive charge (on the oxygen atom) and a partially negative charge on each of the hydrogen atoms; as a result, it readily dissolves ions and polar molecules. Water is therefore referred to as a solvent because of its capacity to dissolve other polar molecules and ionic compounds. Furthermore, the partially negative dipole of the oxygen atom is attracted to positively charged components of the solute, and conversely, the negative dipoles of the hydrogen atoms are attracted to the negatively charged dipoles of the solute. Furthermore, the polar nature of water allows water to participate in hydrogen bonding. The hydrogen bonds form as a result of the intermolecular forces between neighboring water molecules and other polar molecules in which the positive hydrogen of a water molecule bonds (electronically) with the negative oxygen of the next molecule (Figure 4.2), leading to a chain of water molecules.

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FIGURE 4.2  Schematic example of a hydrogen bond between two water molecules.

Hydrogen bonding can also occur in between both water molecules and other (inorganic or organic) substances where polarity of the non-water molecule is present. On a molecular basis, many salts (which are typically ions and carry positive and negative charges) dissolve in water because of the electrical charges and because both water and salt compounds are polar, with positive and negative charges on opposite sides in the molecule. The bonds in salt compounds are ionic bonds in which both parts of the salts have an electrical charge, and water is ionic in nature, with two hydrogen atoms both situating themselves with their positive charge on one side of the oxygen atom, which has a negative charge; this leads to the polar association of the water molecules with salt molecules. More specifically, the positively charged sides of the water molecules (the hydrogen atoms) are attracted to the negatively charged ions in the salt, and the negatively charged side of the water molecule (the oxygen atom) is attracted to the positively charged ions in the salt. Water can also serve as an excellent carrier of molecules to a reaction site, thereby influencing the many reactions that are necessary in a successful refinery. This is especially true in the gas-processing section of a refinery, where water is frequently used as a solvent carrier in gas-treating processes (Chapter 5). Finally, the solvents used in a refinery have varying volatility that makes them suitable for a variety of solvent-related tasks. Typically, the solvents are produced within the refinery and contain paraffin hydrocarbon derivatives, naphthene hydrocarbon derivatives, and aromatic hydrocarbon derivatives, albeit in different ratios (Chapter 1). These solvents usually have no color and are immiscible with water (also used as a solvent in the refinery) and have different applications, and they are also used as intermediates in some chemical reactions to produce a variety of petrochemical products (Speight, 20–14, 2017, 2019). However, even when the solvents are produced in a refinery, their properties, especially capacity, must be given serious consideration. By definition, solvent capacity is the ratio of the solute concentration in the solvent to the solute remaining the raffinate phase, which can play an equally important role in the choice of solvent. Furthermore, many solvents with high capacity may have low selectivity, and solvents with a low capacity may exhibit low capacity for specific solutes. As an example, sulfolane typically has a greater capacity for hydrocarbon derivatives than diethylene glycol, and although the selectivity of sulfolane may be higher for certain feed mixtures with higher benzene and toluene content, diethylene glycol may have a higher selectivity for other mixtures that have a higher xylene isomer content (Zahed et al., 1987). Thus, the solvent extraction process has the potential to produce products more efficient than those produced by low-temperature distillation. However, the extracting solvent must have two important properties, (1) the ability to extract the solute from solution and (2) rejecting the contaminants in the solution. Using the desulfurization of crude oil fractions by solvent extraction as the example, the composition of crude oil consists of various individual fractions at different boiling points. The fractions with boiling points above 350°C (660°F), which are obtained after most of the distillable products have been removed from the original crude oil, fractions contain different amount of sulfur, typically from about 1 to 4% w/w, or even higher. A large portion of the sulfur-containing constituents can be transferred to the distillates during the refining process as hydrogen sulfide, organic sulfide derivatives, organic disulfide sulfide derivatives, benzothiophene sulfide derivatives, dibenzothiophene sulfide derivatives, and the respective alkylated derivatives (Gary et al., 2007; Speight, 2011, 2014; Hsu and Robinson, 2017; Speight, 2017).

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The adverse environmental issues caused by sulfur emissions have made reducing sulfur content in crude oil products a priority in the refining industry. The conversion of sulfur into sulfur oxides (SOx, where x = 2 or 3) along with the production of the oxides of nitrogen (NOx, where x = 1 or 2) during combustion occurs, and these gases are adsorbed by the water in the atmosphere, resulting in the production of acid rain (Speight, 1996): SO2 + H2O → H2SO3 sulfurous acid SO3 + H2O → H2SO4 sulfuric acid NO + H2O → HNO2 nitrous acid 3NO2 + 2H2O → HNO3 nitric acid There are various chemical processes that can be applied to the removal of sulfur from crude oil and crude oil products, including catalytic transformation processes such as hydro-desulfurization and physiochemical processes such as solvent extraction, oxidation, adsorption, and the use of bioenzymes (Gary et al., 2007; Speight, 2011, 2014; El-Gendy and Speight, 2016; Hsu and Robinson, 2017; Speight, 2017; Speight and El-Gendy, 2018). However, solvent-based processes are also available. For example, oxidational desulfurization can be an economical alternative for lowering the sulfur content of diesel fuel (De Filippis and Scarsella, 2003; Sampanthar et al., 2006; Kadijani et al., 2014). In the process, the oxidants oxidize the organic sulfur, and the reaction products are removed by liquid extraction or adsorption. The most efficient and available extractive agent is an aqueous solution of acetone, although a wide variety of polar solvents and binary systems, namely methanol, N, N-dimethylformamide, dimethyl sulfoxide, dimethylformamide and acetonitrile, can be used in this process (Yazu et al., 2001; Campos‐Martin et al., 2010; Zhang et al., 2011; Kim et al., 2012). In desulfurization by solvent extraction, the organic sulfur compounds are removed from the solvent by distillation, and the solvent is recycled. The solubility of the organic sulfur compounds in the applied solvent is very important for extractive desulfurization efficiency, and hence, choosing the proper solvent according to the nature of the present organic sulfur compounds is also important. Sulfolane (2, 3, 4, 5-tetrahydrothiophene-1,1-dioxide) is an organic sulfur compound (classed as a cyclic sulfone) with the formula (CH2)4SO2 (C4H8O2S). It is a colorless liquid commonly used in the chemical industry as a solvent for extractive distillation and chemical reactions because of its ability to extract polar sulfur compounds and aromatics from hydrocarbon mixtures. Ionic liquids (Chapter 1) are also capable of removing organic sulfur compounds without the simultaneous (and not always desirable) removal of aromatic constituents.

4.3  COMMERCIAL PROCESSES The commercial processes used in a crude oil refinery are used to remove contaminants such as organic compounds containing sulfur, nitrogen, and oxygen as well as dissolved metals and inorganic salts (soluble salts dissolved in emulsified water) from crude oil fractions or product streams. The primary purpose of the majority of the treating processes is the elimination of the contaminants enumerated above.

FIGURE 4.3  Sulfolane.

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As an example, solvent extraction followed by use of an adsorbent has been found to be one of the competitive processes for recycling used lubricating oil. The principle behind solvent extraction is the injection of diluents (such as naphtha) that is obtained from the distillation section of the refinery to remove any contaminants and to produce a finished (or partly finished) product. The term ‘sweetening’ is applied, for example, to naphtha (and other blend stocks for gasoline production) and refers to the removal of sulfur compounds (such as hydrogen sulfide, mercaptan derivatives, and thiophene derivatives) to improve color, odor, and oxidation stability. The sweetening can also be used to reduce the concentration of carbon dioxide in gas streams. Choices of a treating method depend on (1) the nature of the crude oil fraction, (2) the amount of contaminants is the product, (3) the type of contaminants that are to be removed, (4) the extent to which the treating process removes the contaminants, and (5) the desired specification of the treated end product. Treating processes include the use of acids, solvents, alkalis, oxidization, and adsorption by treating with clay or any of the aforementioned methods. Sulfuric acid is the most commonly used acid treatment and results in partial or complete removal of unsaturated hydrocarbons, sulfur, nitrogen, oxygen compounds, and resin and asphaltene constituents. Clay/lime treatment of acid-refined oil removes traces of asphaltic materials and other compounds, improving product color, odor, and stability. Caustic treating (using sodium hydroxide or potassium hydroxide) is used to improve odor and color by removing organic acids (naphthenic acids, phenols) and sulfur compounds (mercaptan derivatives, RSH, and hydrogen sulfide, H2S) with a caustic wash. By combining caustic soda solution with various solubility promoters (e.g., methyl alcohol and cresols), up to 99% of all mercaptan derivatives as well as oxygen- and nitrogencontaining constituents can be dissolved from crude oil fractions. Solutions of caustic (sodium hydroxide) or olamine (such as diethanolamine) derivatives (Chapter 5) or fixed-bed catalytic hydrotreating sweetening also may be used (Gary et al., 2007; Speight, 2011, 2014; Hsu and Robinson, 2017; Speight, 2017). Some processes simultaneously dry and remove sulfur from the process feedstocks by adsorption of the contaminants on a molecular sieve. This is especially true for the removal of sulfur species from the feedstock. A typical process produces elemental sulfur by burning hydrogen sulfide under controlled conditions (Gary et  al., 2007; Speight, 2011, 2014; Hsu and Robinson, 2017; Speight, 2017). Knock-out pots (also referred to as knock-out drums or flash drums) are designed to remove bulk liquids and particulate matter from gas streams based on gravitational separation at an optimum vapor velocity. In the present context, the process stream enters the knock-out pot and contacts a deflector to generate a radial flow pattern, thereby causing centrifugal separation. Typically, knockout pots are used to remove water and hydrocarbons from feed gas streams, after which the gases are then exposed to a catalyst to recover additional sulfur. Any sulfur vapor from burning and conversion is condensed and recovered. Depending on the feedstock and the nature of contaminants, desulfurization methods vary from adsorption by activated charcoal (ambient temperature) to catalytic hydrogenation (at high temperature) of the gas stream with zinc oxide (ZnO). Fractions or streams produced by product improvement processes often contain small amounts of impurities that must be removed. The most common impurities are sulfur compounds that occur in crude oil, such as sulfide derivatives (R-S-R’) and the foul-smelling RSH (also called thiol derivatives). Oxygen compounds in the form of carboxylic acid derivatives (RCO2H) and phenol derivatives (ArOH, where Ar is an aromatic group) may also be present. Nitrogen-containing compounds derived from those that occur in crude oil are also present. Furthermore, olefin derivatives (RCH=CHR1) must also be eliminated from a feedstock or aromatic derivatives removed from a solvent because both are considered impurities. Similarly, polymerized material, asphaltene derivatives, or resin constituents may be impurities, depending on whether their presence in a finished product is harmful. Treatment processes for the removal of sulfur-containing and nitrogen-containing compounds are much less severe than desulfurization and denitrogenation (Gary et  al., 2007; Speight, 2011, 2014; Hsu and Robinson, 2017; Speight, 2017). In fact, it is generally recognized that the removal (or conversion) of sulfur and nitrogen compounds in distillates is usually limited to mercaptan

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derivatives and the lower-molecular-weight (non-mercaptan) sulfur compounds. When there is more than a trace amount (>0.1 %) of heteroatom derivatives present (i.e. sulfur-, nitrogen-, and oxygencontaining constituents), it is often more convenient and economical to resort to such methods as those thermal processes (e.g., hydroprocesses) that bring about a decrease in all types of heteroatomic compounds because of the propensity of these derivatives to form insoluble coke precursors and coke (Gary et al., 2007; Speight, 2011, 2014; Hsu and Robinson, 2017; Speight, 2017), which will separate from the reaction medium during the early stages of the reaction as an insoluble residue that, in many cases, can be conveniently separated from the reactants by mechanical means. If mercaptans are also present in the raw kerosene, a doctor treatment in addition to lye treatment (caustic treatment) is required, but poor-quality raw kerosene may require, in addition to these treatments, treatment with sulfuric acid and Fuller’s earth. The lowest-quality raw kerosene requires treatment with strong sulfuric acid, neutralization with lye, and redistillation. It is the purpose of this section to present an outline of the processes that are available for treatment to remove contaminants from streams that will be eventually used as stock for products. The processes outlined here are not usually shown on a refinery schematic but would be placed in the general area for finishing, after the processes shown on a schematic and prior to the designation of the product.

4.3.1 Caustic Processes Caustic-based processes (often referred to as caustic washing processes because of the need to use and aqueous solution of the alkali) are processes for treating a product with a solution of caustic soda to remove impurities. Moreover, washing crude oil and crude oil products with solutions of alkali (caustic or lye) is almost as old as the crude oil industry. As an example, gas streams are usually contaminated with low-boiling mercaptan derivatives (such as methyl mercaptan, CH3SH, ethyl mercaptan, C2H5SH, propyl mercaptan, (C3H7SH, and butyl mercaptan, C4H9SH) (Chapter 5), which tend to concentrate in the fraction known as natural gas liquids, in the product known as liquefied petroleum gas (LPG), or in condensate streams because of similar volatility (i.e. similar boing points). In caustic wash processes, the low-boiling mercaptan derivatives are first extracted from the liquid hydrocarbon phase by contacting the stream with a concentrated aqueous solution of the caustic, which is then regenerated by means of low temperature catalytic oxidation that is accomplished by injecting air and converting the mercaptan derivatives into disulfide derivatives that are further separated from the caustic solution: 2C4H9SH + [O] → C4H9SSC4H9 + H2O Thus, it is not surprising that lye treatment (i.e. washing with caustic soda) has been used widely on many crude oil fractions and crude oil products. In fact, it is sometimes used as a pretreatment for sweetening (i.e. sulfur removal) and other processes. The process consists of mixing a water solution of lye (sodium hydroxide or caustic soda) with an oil fraction: 2NaOH + H2S → 2Na2S + 2H2O The treatment is carried out as soon as possible after the crude oil fraction or the crude oil product is distilled because contact with aerial oxygen forms free sulfur, which is very corrosive and difficult to remove. 4.3.1.1  Dualayer Distillate The Dualayer distillate process (sometimes referred to as the Dualayer process) is a process for the removal of mercaptan derivatives and oxygenated derivatives distillate fractions. The process is

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similar in character to the Duosol process in that caustic solution and cresylic acid (cresol, methylphenol, CH3C6H4OH) are used as the wash solution. The process extracts organic acid substances (including RSH) from distillate fractions or from cracked fractions. In a typical operation, the Dualayer reagent is mixed with the distillate at about 55°C (130°F) and passed to the settler where, by application of electrical coagulation, three layers are formed. The product is withdrawn from the top layer, the Dualayer reagent is withdrawn from the bottom layer, excess water is removed and additional caustic the added, and the Dualayer agent is recycled for further use. 4.3.1.2  Dualayer Gasoline The Dualayer gasoline process is a modification of the Dualayer distillate process in that it is used to extract hydrogen sulfide (H2S) and mercaptan derivatives from LPG and naphtha. The feedstock (typically a naphtha fraction to be used as a gasoline blend stock), free of hydrogen sulfide, is contacted with the Dualayer solution at 50°C (120°F) in at least two stages, after which the treated naphtha is washed and stored. The treating solution is diluted with water (60 to 70% of the solution volume) and stripped of mercaptan derivatives, naphtha, and excess water, and the correct amount of fresh caustic is added to obtain the regenerated reagent. 4.3.1.3  Electrolytic Mercaptan The electrolytic mercaptan process employs an aqueous solution to extract mercaptan derivatives from refinery streams and regenerate the solution. In the process, the feedstock is prewashed to remove hydrogen sulfide and contacted countercurrently with the treating solution in a mercaptan extraction tower. The mixture is then pumped to the cell where mercaptan derivatives are converted to disulfide derivatives, which can be separated from the regenerated solution. 4.3.1.4 Ferrocyanide The ferrocyanide process uses a regenerative chemical treatment for removing mercaptan derivatives from straight-run naphtha as well as from similar product streams, using caustic-sodium ferrocyanide reagent. For example, naphtha is washed with caustic solution to remove hydrogen sulfide and then washed countercurrently in a tower with the treating agent. The spent solution is mixed with fresh solution that contains ferricyanide, and the mercaptans are converted to insoluble disulfide derivatives that are removed by a countercurrent wash using a hydrocarbon liquid. The solution is then recycled, and part of the ferrocyanide is converted to ferricyanide by an electrolyzer. 4.3.1.5  Lye Treatment Lye (sodium hydroxide) treatment is carried out in continuous treaters, which essentially consist of a pipe containing baffles or other mixing devices into which the oil and lye solution are both pumped. The pipe discharges into a horizontal tank where the lye solution and oil separate. Treated oil is withdrawn from near the top of the tank; lye solution is withdrawn from the bottom and recirculated to mix with incoming untreated oil. Caustic solutions ranging from 5 to 20% w/w are used at 20 to 45°C (70 to 110°F) and 5 to 40 psi. However, a high temperature and a strong caustic solution are usually avoided because of the risk of color body formation and loss of stability of the product. Typically, the spent lye solution (produced by removal of hydrogen sulfide) is not regenerated, whereas blowing with steam can regenerate lye solution spent by removal of mercaptan contaminants, which reforms sodium hydroxide and mercaptans from the spent lye. The mercaptan derivatives separate as a vapor and typically are destroyed by combustion in a furnace. Spent lye (caustic solution) can also be regenerated in a stripper tower by use of steam. The overhead consists of steam and mercaptan derivatives, as well as the small amount of feedstock oil that has become associated with the lye solution during treatment. Condensing the overhead stream

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from the process allows the mercaptan derivatives to be recovered from the water as a separate stream. A non-regenerative caustic treatment option is generally applied when the contaminating materials are in a low concentration and waste disposal is not a major issue. However, the use of nonregenerative systems is on the decline because of the frequently occurring waste disposal problems that arise from environmental considerations and because of the availability of numerous other processes that can more completely remove contaminating materials. 4.3.1.6 Mercapsol The Mercapsol process is a regenerative process that is used to extract mercaptan derivatives by means of sodium hydroxide (or potassium hydroxide), together with cresols, naphthenic acids, and phenol. In the process, naphtha (for example) is contacted countercurrently with the mercapsol solution, and the treated product is removed from the top of the tower. The spent solution is stripped to remove naphtha, followed by steam stripping of the solution to remove any mercaptans derivative. 4.3.1.7  Polysulfide Treatment Polysulfide treatment is a non-regenerative chemical treatment process that is used to remove elemental sulfur from refinery liquids. The polysulfide solution is most active when the composition approximates Na2S, to Na2S3, but activity decreases rapidly when the composition approaches Na2S4. When the solution is discarded, a portion (ca. 20%) is retained and mixed with fresh causticsulfide solution, which eliminates the need to add free sulfur. Indeed, if the material to be treated contains hydrogen sulfide in addition to free sulfur, it is often only necessary to add fresh caustic. 4.3.1.8 Sodasol A lye solution removes only the lighter or lower-boiling mercaptans, but various chemicals can be added to the lye solution to increase its ability to dissolve the heavier mercaptans. The added chemicals are generally known as solubility promoters or solutizers. Several different solutizers have been patented and are used in processes that differ chiefly in the composition of the solutizers. In the Sodasol process, the treating solution is composed of lye solution and alkyl phenols (acid oils), which occur in cracked naphtha and cracked gas oil and are obtained by washing cracked naphtha or cracked gas oil with the lye solution. The lye solution, with solutizers incorporated, is then ready to treat product streams, such as straight-run naphtha. The process is carried out by pumping a sour stream up a treating tower countercurrent to a stream of Sodasol solution that flows down the tower. As the two streams mix and pass, the solution removes mercaptans and other impurities, such as oxygen compounds (phenols and acids), as well as some nitrogen compounds. The treated stream leaves the top of the tower; the spent Sodasol solution leaves the bottom of the tower to be pumped to the top of a regeneration tower, where mercaptans are removed from the solution by steam. The regenerated Sodasol solution can then be sent (pumped) to the top of the treatment tower to treat more material. A variation of the Sodasol process is the Potasol process, which uses potassium hydroxide instead of lye (sodium hydroxide). 4.3.1.9 Solutizer The Solutizer process is a regenerative process using such materials as potassium iso-butyrate and potassium alkylphenolate in strong aqueous potassium hydroxide to remove mercaptans. After the removal of the mercaptans and recovery of the hydrocarbon stream, regeneration of the spent solution may be achieved by heating and steam blowing at 130°C (270°F) in a stripping column in which steam and mercaptans are condensed and separated. The spent solution may also be contacted with carbon dioxide air, after which the disulfides formed by oxidation of the mercaptans are extracted by a naphtha wash. Air blowing in the presence of tannin (tannin Solutizer process) catalytically oxidizes mercaptans to the corresponding disulfides, but there may be side reactions that can lead to reagent contamination.

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4.3.1.10  Steam-Regenerative Caustic Treatment Steam-regenerative caustic treatment is directed toward the removal of mercaptan derivatives from such products as low-boiling naphtha. The caustic solution is regenerated by steam blowing in a stripping tower. The nature and concentration of the mercaptans to be removed dictate the quantity and temperature of the process. However, the caustic solution gradually deteriorates because of the accumulation of material that cannot be removed by stripping; the caustic quality must be maintained by either continuous or intermittent discard and replacement of a minimum amount of the operating solution. 4.3.1.11 Unisol The Unisol process is a regenerative process that can be applied not only to mercaptan derivatives but also to various nitrogen-containing compounds from sour naphtha or from distillates. The naphtha, which is free of hydrogen sulfide, is washed in a countercurrent operation with an aqueous caustic-methanol solution at a temperature of around 40°C (100°F). The spent caustic is regenerated in a stripping tower (145 to 150°C, 290 to 300°F), where methanol, water, and mercaptans are removed.

4.3.2 Acid Processes Treating products with acids is, like caustic treatment, a procedure that has been in use for a considerable time in the industry. Various acids, such as hydrofluoric acid, hydrochloric acid, nitric acid, and phosphoric acid, have been used in addition to the more commonly used sulfuric acid, but in most instances, there is little advantage in using any acid other than sulfuric. Until about 1930, acid treatment was almost universal for all types of refined products, especially for cracked naphtha, kerosene, and lubricating oil stocks. Cracked products were acid treated to stabilize against gum formation and color darkening (oxidation) and to reduce sulfur content if necessary. However, there were appreciable losses due to polymer formation (from olefins in cracked products) initiated by the sulfuric acid. Other processes have now superseded the majority of the acid treatment processes. However, acid treatment has been continued for desulfurizing high-boiling fractions of cracked naphtha, for refining kerosene, for manufacture of low-cost lubricating oil, and for making such specialties as insecticide naphtha, pharmaceutical white oil, and insulating oil. The reactions of sulfuric acid with fractions are complex. The undesirable components to be removed are generally present in small amounts; large excesses of acid are required for efficient removal, which may cause marked changes in the remainder of the hydrocarbon mixture. Paraffin and naphthene hydrocarbon derivatives (in the pure forms) are not attacked by concentrated sulfuric acid at low temperatures and during the short time of conventional refining treatment, but solutions of light paraffins and naphthenes in the acid sludge can occur. Fuming sulfuric acid (oleum) absorbs small amounts of paraffins when contact is induced by long agitation; the amount of absorption increases with time, temperature, concentration of the acid, and complexity of structure of the hydrocarbons. With naphthenes, fuming sulfuric acid causes sulfonation as well as rupture of the ring. The action of sulfuric acid on olefin hydrocarbons is very complex. The main reactions involve ester formation and polymerization. The esters formed by the reaction of sulfuric acid with olefins in cracked distillates are soluble in the acid phase but are also to some extent soluble in hydrocarbons, especially as the molecular weight of the olefin increases. The esters are usually difficult to hydrolyze and remove by alkali washing. They are, however, unstable on standing for a long time, and products containing them (acid-treated cracked naphtha) may evolve sulfur dioxide and deposit intractable materials. The esters are quite unstable on heating, so that a redistilled, acid-treated cracked distillate usually requires alkali washing after the customary distillation.

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Aromatics are not attacked by sulfuric acid to any great extent under ordinary refining conditions unless they are present in high concentrations. However, if fuming acid is used or if the temperature is allowed to rise above normal, sulfonation may occur. When both aromatics and olefins are present, as in distillates from cracking units, alkylation can occur. Thus, as indicated, acid treatment of cracked naphtha distillate brings about losses due to chemical reaction and polymerization of some of the olefins to constituents boiling above the naphtha range. This makes redistillation necessary, and such losses may total several percent, even when refrigeration is employed to maintain a low temperature. Acid treatment of high-boiling distillates and residua presents different problems. Most of these contain at least a small proportion of dissolved or suspended asphaltic substances, and almost all the acid comes out as sludge (acid tar); its separation is aided by the addition of a little water or alkali solution. However, there may be obvious chemical changes, such as sulfur dioxide evolution, and washed (acid-free) sludge from the treatment of practically sulfur-free oils may contain up to 10% combined sulfur derived from the treating acid. Although largely displaced for bulk production of both naphtha and lubricating oils, acid treatment still serves many special purposes. Paraffin distillates intended for dewaxing might receive light treatment to facilitate wax crystallization and refining, whereas insulating oils, refrigeration compressor oils, and white oils may be treated more severely. The sludge produced on acid treatment of distillates, even naphtha and kerosene, is complex in nature. Esters and alcohols are present from reactions with olefins; sulfonation products from reactions with aromatics, naphthenes, and phenols; and salts from reactions with nitrogen bases. In addition, such materials as naphthenic acids, sulfur compounds, and asphaltic material are all retained by direct solution. To these constituents must be added the various products of oxidation-reduction reactions: coagulated resins, soluble hydrocarbons, water, and free acid. Disposal of the sludge is difficult, as it contains unused free acid that must be removed by dilution and settling. The disposal is a comparatively simple process for the sludge resulting from treating naphtha and kerosene, the so-called light oils. The insoluble oil phase separates out as a mobile tar-like material that can be mixed and burned without too much difficulty. Sludge from heavy oil and bitumen, however, separates out as granular semisolids, which is considerably difficult to handle. In all cases, careful separation of reaction products is important to the recovery of well-refined materials. This may not be easy if the temperature has risen as a consequence of chemical reaction. This will result in a persistent dark color traceable to colloidally distributed reaction products. Separation may also be difficult at low temperature because of the high viscosity of the feedstock, but this problem can be overcome by dilution with propane or with low-boiling naphtha. When acid treatment cannot be applied continuously by mechanical agitation followed by effective separation, the older batch agitators are employed. These devices are vertical reactors holding up to several thousand barrels, provided with conical bottoms for sludge drainage. The contact time is difficult to control and may amount to several hours, but the separation of acid tar is desirable to avoid discoloration by resolution and to permit handling the sludge before it becomes undesirably viscous. Breaking out the suspended acid tar, often referred to as pepper sludge, is helped by adding a little water and agitating, and the subsequent separation of tar closely resembles the precipitation of a colloidal suspension. The sludge is allowed to settle, and the sour oil is washed with water, usually after transfer to another container, to avoid retention of acid tar in the system during the alkali washing that follows. Sodium hydroxide solution (10 to 25 % concentration) may be used for non-viscous products, but for viscous oils, more dilute solutions are employed, and only a very slight excess of alkali is used, but no attempt is made at its recovery. Emulsion-breaking chemicals are sometimes required in alkali washing; the use of aqueous alcohol is customary when fuming acid has been employed, as for sulfonates and white oils. Final water washing followed by air blowing to dry the oils is the customary procedure.

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4.3.2.1 Nalfining Nalfining is a continuous process that employs acetic anhydride and a caustic rinse to convert contaminants into less objectionable, but oil-soluble, compounds. The anhydride is injected into the product stream, where it reacts with oxygen to form the ester, with sulfur to form the thiaester, with nitrogen to form substituted amides, and with complex organic impurities to form environmentally benign products. The caustic rinse neutralizes the potentially corrosive acetic acid. 4.3.2.2  Sulfuric Acid Sulfuric acid treatment can be used as a continuous method or as a batch method that is used to remove sulfur compounds from product streams. The process can also be applied to the removal of asphaltic materials from various high-boiling refinery streams. The acid strength varies from fuming sulfuric acid (>100 %) to 80% sulfuric acid, although acid of around 93% is the most commonly used. The weakest suitable acid is used for each particular situation to reduce sludge formation from the aromatic and olefin hydrocarbons. The use of strong acid dictates the use of a fairly low temperature (−4 to 10°C, 25 to 50°F), but higher temperatures (20 to 55°C, 70 to 130°F) are possible if the product is to be redistilled.

4.3.3 Solvent–Clay Processes Treating distillates and residua by passing them through materials possessing decolorizing power has been operating for many years (Gary et  al., 2007; Speight, 2011, 2014; Hsu and Robinson, 2017; Speight, 2017). For example, various clays and similar materials are used to treat fractions to remove diolefins, asphaltic materials, resins, acids, and colored bodies. Cracked naphtha was frequently clay treated to remove diolefins that formed gums in naphtha. Other processes have now largely superseded this clay treatment, in particular inhibitors, which when added in small amounts to naphtha prevent gums from forming. Nevertheless, clay treatment is still used as a finishing step in the manufacture of lubricating oils and waxes. The clay removes traces of asphaltic materials and other compounds that give oils and waxes unwanted odors and colors. The original method of clay treatment was to percolate a fraction through a tower containing coarse clay pellets. As the clay absorbed impurities from the fraction, the clay became less effective. Removing it from the tower periodically restored the activity of the clay, and the absorbed material was burned under carefully controlled conditions so as not to sinter the clay. The percolation method of clay treatment was widely used for lubricating oils but has been largely replaced by clay contacting. 4.3.3.1  Alkylation Effluent Treatment Alkylation as practiced in a crude oil refinery is a chemical process in which gaseous hydrocarbon derivatives are combined to produce high-octane components as a blend stock for the production of naphtha. Typically, the feedstocks for the process consist of olefin derivatives such as propylene (CH3CH=CH2) and butylene (CH3CH2CH=CH2, CH3CH-=CHCH3) and iso-paraffin derivatives such as isobutane [(CH3)2C=CH2]. In the process, the hydrocarbon stream (in liquid form) is under sufficient pressure and low temperature to ensure that the stream remains in the liquid state. The reaction products are sent to an acid settler where the acid is recycled back to the reactor. Products are then separated into gaseous LPG propane and n-butane and the desired product (often referred to as alkylate). This is a continuous liquid percolation process in which the reactor effluent (from the alkylation process) is coalesced in a vessel containing glass wool and steel mesh and then charged, alternately, to two bauxite (medium mesh) towers. The bauxite is regenerated with a mixture of steam and gas. Bauxite is a naturally occurring mineral material that is composed primarily of one or more aluminum hydroxide minerals, plus various mixtures of silica, iron oxide, titania, aluminosilicate,

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and other impurities in minor or trace amounts. It is converted to alumina using the Bayer process in which the bauxite is combined with caustic soda, lime, and steam to produce sodium aluminate [primarily NaAl(OH)4]. The process contributes to the efficient utilization of C4 olefin derivatives that are generated in the cracking operations. Iso-butane has been added to butene derivatives (and to other lowboiling olefins) to produce a mixture of highly branched octane derivatives. The reaction is thermodynamically favored at low temperatures (85 3–8 1–5 1–2 1–5 1–2 1–2 1–5 C=C