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  cover title : Petroleum Processing Handbook author : McKetta, John J. publisher : CRC Press isbn10 | asin : 0824786815 print isbn13 : 9780824786816 ebook isbn13 : 9780585375700 language : English subject Petroleum--Refining--Handbooks, manuals, etc. publication date : 1992 lcc : TP690.P4723 1992eb ddc : 665.5/ 3 subject :

  Petroleum--Refining--Handbooks, manuals, etc. page_i

  

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  Petroleum Processing Handbook edited by John J. McKetta

  The University of Texas at Austin Austin, Texas

  

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  Library of Congress Cataloging-in-Publication Data Petroleum processing handbook / edited by John J. McKetta. p. cm. "The contents of this volume were originally published in Encyclopedia of chemical processing and design, edited by J.J. McKetta and W.A. Cunningham"-T.p. verso. Includes bibliographical refernces and index.

  ISBN 0824786815 (alk. paper)

  665 .5 ′ 3-dc20 924374 CIP The contents of this volume were originally published in Encyclopedia of Chemical Processing and Design, edited by J.

  J. McKetta and W. A. Cunningham. © 1979, 1981, 1982, 1987, 1988, 1990 by Marcel Dekker, Inc. This book is printed on acid-free paper. Copyright © 1992 by Marcel Dekker, Inc. All Rights Reserved. Neither this book nor any part may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, micro-filming, and recording, or by any information storage and retrieval system, without permission in writing from the publisher. Marcel Dekker, Inc. 270 Madison Avenue, New York, New York 10016 Current printing (last digit): 10 9 8 7 6 5 4 3 2 1

  

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  PREFACE It is time that many of the petroleum processes currently in use be presented in a well-organized, easy-to-read and understandable manner. This hand-book fulfills this need by covering up-to-date processing operations. Each chapter is written by a world expert in that particular area, in such a manner that it is easily understood and applied. Each professional practicing engineer or industrial chemist involved in petroleum processing should have a copy of this book on his or her working shelf. The handbook is conveniently divided into four sections: products, refining, manufacturing processes, and treating processes. Each of the processing chapters contain information on plant design as well as significant chemical reactions. Wherever possible, shortcut methods of calculations are included along with nomographic methods of solution. In the front of the book are two convenient sections that will be very helpful to the reader. These are (1) conversion to and from SI units, and (2) cost indexes that will enable the reader to update any cost information. As Editor, I am grateful for all the help I have received from the great number of authors who have contributed to this book. I am also grateful to the huge number of readers who have written to me with suggestions of topics to be included.

  

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  CONTENTS Preface iii Contributors vii Conversion to SI Units xi Bringing Costs up to Date xiii

  1 Products Petroleum Products

  2 Harold L. Hoffman Petroleum Products, Production Costs

  13 Fabio Bernasconi Octane Boosting

  25 John J. Lipinski and Jack R. Wilcox Octane Catalysts

  31 John S. Magee, Bruce R. Mitchell, and James W. Moore Octane Options

  50 Joseph A. Weiszmann, James H. D'Auria, Frederick G. McWilliams, and Frederick M. Hibbs

  2 Refining Petroleum Processing

  67 page_v Hazardous Waste Regulations

  179 David Olschewsky and Alice Megna Petroleum Waste Toxicity, Prevention

  190 Raymond C. Loehr Petroleum Refining Processes, United States Capacities

  199 Debra A. Gwyn Petroleum Refining Processes, Worldwide Capacities

  214 Debra A. Gwyn

  

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  3 Manufacturing Processes Coking, Petroleum (Delayed and Fluid) 245

  J. D. McKinney Coking, Petroleum (Fluid)

  253

  D. E. Blaser Cracking, Thermal

  281 W. P. Ballard, G. I. Cottington, and T. A. Cooper Cracking, Catalytic

  349

  E. C. Luckenbach, A. C. Worley, A. D. Reichle, and E. M. Gladrow Heavy Oil Cracking

  480 Guy E. Weismantel Cracking, Catalytic, Optimization and Control

  516 J. A. Feldman, B. E. Lutter, and R. L. Hair Deasphalting

  527 Carl Pei-Chi Chang and James R. Murphy Dehydrogenation

  544 Hervey H. Voge Dewaxing, Catalytic

  558 J. D. Hargrove Dewaxing, Solvent

  565

  G. G. Scholten Dewaxing, Urea

  583

  G. G. Scholten page_vi Demetallization/Desulfurization of High Metal Content Petroleum Feedstocks 677 Richard A. Baussell, John Caspers, Kenneth E. Hastings, John D. Potts, and Roger P. Van Driesen Desulfurization, Liquids, Petroleum Fractions

  697 Robert J. Campagna, James A. Frayer, and Raynor T. Sebulsky Desulfurizing Cracked Gasoline and Other Hydrocarbon Liquids by Caustic Soda Treating 727 K. E. Clonts and Ralph E. Maple Doctor Sweetening

  736 Kenneth M. Brown Index

  759

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  CONTRIBUTORS W. P. Ballard Manager, Port Arthur Research Laboratories (Retired), Texaco, Inc., Port Arthur, Texas

  D. B. Bartholic Engelhard Corporation, Specialty Chemicals Division, Menlo Park, Edison, New Jersey Richard A. Bausell Safety Services Manager, Cities Service Research and Development Company, Tulsa, Oklahoma Fabio Bernasconi, Ph.D. Ambrosetti Group, Milan, Italy Frank E. Biasca Manager, Process Technology, SFA Pacific, Inc., Mountain View, California

  D. E. Blaser Engineering Associate, Exxon Engineering Petroleum Department, Exxon Research and Engineering Company, Florham Park, New Jersey Kenneth M. Brown Director, Treating Services (Retired), UOP Process Division, Des Plaines, Illinois Donald R. Burris Manager, Technical Advisory Division, C-E Natco Combustion Engineering, Inc., Denver, Colorado Robert J. Campagna Gulf Science and Technology Company, Pittsburgh, Pennsylvania John Caspers Manager, LC-Fining Design, C-E Lummus Company, Bloomfield, New Jersey

  A. M. Center Engelhard Corporation, Specialty Chemicals Division, Menlo Park, Edison, New Jersey Carl Pei-Chi Chang Process Manager, Refinery Process Division, Pullman Kellogg, Houston, Texas

  G. M. A. Chevalier Shell Internationale Petroleum, Maatschappij BV, The Hague, The Netherlands Brian R. Christian Engelhard Corporation, Specialty Chemicals Division, Menlo Park, Edison, New Jersey K. E. Clonts Vice President, Technical, Merichem Company, Houston, Texas T. A. Cooper Staff Coordinator-Strategic Planning, Texaco, Inc., White Plains, New York Richard A. Corbett, P.E. Refining/Petrochemical Editor, Oil & Gas Journal, Houston, Texas page_viii

  

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  G. I. Cottington Technologist, Port Arthur Research Laboratories, Texaco, Inc., Port Arthur, Texas James H. D'Auria Director, Process Development, UOP Inc., Des Plaines, Illinois J. A. Feldman Senior Process Analysis Engineer (Retired), Applied Automation, Inc., Bartlesville, Oklahoma James A. Frayer Technical Consultant, Gulf Science and Technology Company, Pittsburgh, Pennsylvania

  E. M. Gladrow Senior Research Associate, Exxon Research and Development Laboratories, Baton Rouge, Louisiana Debra A. Gwyn Director of Editorial Surveys, Oil & Gas Journal, Tulsa, Oklahoma R. L. Hair Information Technology Planner, Phillips Petroleum Company, Bartlesville, Oklahoma J. D. Hargrove The British Petroleum Company Limited, Sunbury-on-Thames, Middlesex, England Kenneth E. Hastings Vice President and Director of Research, Cities Service Research and Development Company, Tulsa, Oklahoma Frederick M. Hibbs UOP Inc., Des Plaines, Illinois Harold L. Hoffman Editor, Hydrocarbon Processing, Houston, Texas John J. Lipinski Coastal Eagle Point Oil Company, Westville, New Jersey Raymond C. Loehr, Ph.D. H. M. Acharty Centennial Chair and Professor, Environmental Engineering Program, University of Texas at Austin, Austin, Texas

  E. C. Luckenbach E. & R. Luckenbach and Co., Mountainside, New Jersey

  B. E. Lutter Engineering Director, Automation Group, Applied Automation/Hartman and Braun, Bartlesville, Oklahoma John S. Magee, Ph.D. Technical Director, Katalistiks International, a unit of UOP, Inc., Baltimore, Maryland Ralph E. Maple Assistant General Manager, Process Technology Division, Merichem Company, Houston, Texas John J. McKetta, Ph.D., P.E. The Joe C. Walter Professor of Chemical Engineering, The University of Texas at Austin, Austin, Texas J. D. McKinney Gulf Research and Development Company, Pittsburgh, Pennsylvania page_ix

  

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  Bruce R. Mitchell (deceased) Katalistiks International, a unit of UOP, Inc., Baltimore, Maryland James W. Moore Senior Research Supervisor, Katalistiks International, a unit of UOP, Inc., Baltimore, Maryland James R. Murphy Pullman Kellogg, Houston, Texas David Olschewsky Project Manager, ERT Inc., Dallas, Texas John D. Potts Manager of Research Staff, Cities Service Research and Development Company, Tulsa, Oklahoma

  A. D. Reichie Engineering Advisor, Exxon Research and Development Laboratories, Baton Rouge, Louisiana

  G. G. Scholten Managing Director, Edeleanu GmbH, Frankfurt am Main, Germany Raynor T. Sebulsky General Manager-Products, Refining & Products Division, Gulf Science and Technology Company, Pittsburgh, Pennsylvania Avilino Sequeira, Jr., P. E. Senior Technologies, Texaco, Inc., Port Arthur, Texas Dale R. Simbeck Vice President Technology, SFA Pacific, Inc., Mountain View, California

  A. J. Suchanek Engelhard Corporation, Specialty Chemicals Division, Menlo Park, Edison, New Jersey R. H. van Dongen Shell Internationale Petroleum, Maatschappij BV, The Hague, The Netherlands Roger P. Van Driesen Manager, Petroleum and Coal Process Marketing, C-E Lummus Company, Bloomfield, New Jersey Mattheus M. van Kessel Product Manager, Refinery Catalysts, SICC, London, United Kingdom Hervey H. Voge (deceased) Sebastopol, California Guy E. Weismantel President, Weismantel International, Kingwood, Texas Joseph A. Weiszmann Marketing Manager, Western U.S., UOP, Inc., Des Plaines, Illinois Jack R. Wilcox Harshaw/Filtrol Partnership, Los Angeles, California

  A. C. Worley Senior Engineering Associate, Exxon Research and Engineering Company, Florham Park, New Jersey page_xi

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  CONVERSION TO SI UNITS To convert from To Multiply by acre square meter (m2) 4.046 × 103 angstrom meter (m) 1.0 × 1010 are square meter (m2) 1.0 × 102 atmosphere newton/square meter (N/m2) 1.013 × 105 bar newton/square meter (N/m2) 1.0 × 105 barrel (42 gallon) cubic meter (m3) 0.159

  Btu (International Steam Table) joule (J) 1.055 × 103 Btu (mean) joule (J) 1.056 × 103 Btu (thermochemical) joule (J) 1.054 × 103 bushel cubic meter (m3) 352 × 102 calorie (International Steam Table) joule (J) 4.187 calorie (mean) joule (J) 4.190 calorie (thermochemical) joule (J) 4.184 centimeter of mercury newton/square meter (N/m2) 1.333 × 103 page_xi dram (U.S. fluid) cubic meter (m3) 3.697 × 106 dyne newton (N) 1.0 × 105 electron volt joule (J) 1.60 × 1019 erg joule (J) 1.0 × 107 fluid ounce (U.S.) cubic meter (m3) 2.96 × 105 foot meter (m) 0.305 furlong meter (m) 2.01 × 102 gallon (U.S. dry) cubic meter (m3) 4.404 × 103 gallon (U.S. liquid) cubic meter (m3) 3.785 × 103 gill (U.S.) cubic meter (m3) 1.183 × 104 grain kilogram (kg) 6.48 × 105 gram kilogram (kg) 10 × 103 horsepower watt (W) 7.457 × 102 horsepower (boiler) watt (W) 9.81 × 103 horsepower (electric) watt (W) 7.46 × 102 hundred weight (long) kilogram (kg)

  50.80 hundred weight (short) kilogram (kg) 45.36 inch meter (m) 2.54 × 102 inch mercury newton/square meter (N/m2) 3.386 × 103 page_xii

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  To convert from To Multiply by kip newton (N) 4.45 × 103 knot (international) meter/second (m/s) 0.5144 league (British nautical) meter (m)

  5.559 × 103 league (statute) meter (m) 4.83 × 103 light year meter (m) 9.46 × 1015 liter cubic meter (m3) 0.001 micron meter (m)

  1.0 × 106 mil meter (m) 2.54 × 106 mile (U.S. nautical) meter (m) 1.852 × 103 mile (U.S. statute) meter (m) 1.609 × 103 millibar newton/square meter (N/m2) 100.0 millimeter mercury newton/square meter (N/m2) 1.333 × 102 oersted ampere/meter (A/m)

  79.58 ounce force (avoirdupois) newton (N) 0.278 ounce mass (avoirdupois) kilogram (kg) 2.835 × 102 ounce mass (troy) kilogram (kg) 3.11 × 102 page_xii poise newton second/square meter (N s/m2)

  0.10 pound force (avoirdupois) newton (N)

  4.448 pound mass (avoirdupois) kilogram (kg) 0.4536 pound mass (troy) kilogram (kg) 0.373 poundal newton (N) 0.138 quart (U.S. dry) cubic meter (m3) 1.10 × 103 quart (U.S. liquid) cubic meter (m3) 9.46 × 104 rod meter (m)

  5.03 roentgen coulomb/kilogram (c/kg) 2.579 × 104 second (angle) radian (rad)

  4.85 × 106 section square meter (m2) 2.59 × 106 slug kilogram (kg)

  14.59 span meter (m) 0.229 stoke square meter/second (m2/s) 1.0 × 104 ton (long) kilogram (kg)

  1.016 × 103 ton (metric) kilogram (kg) 1.0 × 103 ton (short, 2000 pounds) kilogram (kg) 9.072 × 102 torr newton/square meter (N/m2) 1.333 × 102 yard meter (m)

  0.914 page_xiii

  

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  TABLE 1 Chemical Engineering and Marshall and Swift Plant and Equipment Cost Indexes since 1950 Year CE Index M&S Index Year CE Index M&S Index 1950

  73.9 167.9 1971

  132.3 321.3 1951

  80.4 180.3 1972

  137.2 332.0 1952

  81.3 180.5 1973

  Cost escalation via inflation bears critically on estimates of plant costs. Historical costs of process plants are updated by means of an escalation factor. Several published cost indexes are widely used in the chemical process industries: Nelson Cost Indexes (Oil and Gas J.), quarterly Marshall and Swift (M&S) Equipment Cost Index, updated monthly CE Plant Cost Index (Chemical Engineering), updated monthly ENR Construction Cost Index (Engineering News-Record), updated weekly All of these indexes were developed with various elements such as material availability and labor productivity taken into account. However, the proportion allotted to each element differs with each index. The differences in overall results of each index are due to uneven price changes for each element. In other words, the total escalation derived by each index will vary because different bases are used. The engineer should become familiar with each index and its limitations before using it. Table 1 compares the CE Plant Index with the M&S Equipment Cost

  84.7 182.5 1974

  165.4 398.4 1954

  86.1 184.6 1975

  182.4 444.3 1955

  88.3 190.6 1976

  192.1 472.1 1956

  1977

  144.1 344.1 1953 page_xiii 1962

  102.0 238.5 1983

  316.9 760.8 1963

  102.4 239.2 1984

  322.7 780.4 1964

  103.3 241.8 1985

  325.3 789.6 1965

  104.2 244.9 1986

  318.4 797.6 1966

  107.2 252.5 1987

  323.8 813.6 1967

  109.7 262.9 1988

  342.5 852.0 113.6 273.1 355.4 895.1

  1969 119.0 285.0

  1990 357.6 915.1

  1970 125.7 303.3

  

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  TABLE 2 Nelson Inflation Refinery Construction Indexes since 1946 (1946 = 100) Date Materials

  Component Labor Component Miscellaneous

  Equipment Nelson

  Inflation Index 1946 100.0 100.0 100.0 100.0

  1947 122.4 113.5 114.2 117.0 1948 139.5 128.0 122.1 132.5 1949 143.6 137.1 121.6 139.7 1950 149.5 144.0 126.2 146.2 1951 164.0 152.5 145.0 157.2 1952 164.3 163.1 153.1 163.6 1953 172.4 174.2 158.8 173.5 1954 174.6 183.3 160.7 179.8 1955 176.1 189.6 161.5 184.2 1956 190.4 198.2 180.5 195.3 1957 201.9 208.6 192.1 205.9 1958 204.1 220.4 192.4 213.9 1959 207.8 231.6 196.1 222.1 1960 207.6 241.9 200.0 228.1 1961 207.7 249.4 199.5 232.7 1962 205.9 258.8 198.8 237.6 1963 206.3 268.4 201.4 243.6 1964 209.6 280.5 206.8 252.1 1965 212.0 294.4 211.6 261.4 1966 216.2 310.9 220.9 273.0 1967 219.7 331.3 226.1 286.7 page_xiv 1977 471.3 774.1 438.2 653.0 1978 516.7 824.1 474.1 701.1 1979 573.1 879.0 515.4 756.6 1980 629.2 951.9 578.1 822.8 1981 693.2 1044.2 647.9 903.8 1982 707.6 1154.2 622.8 976.9 1983 712.4 1234.8 656.8 1025.8 1984 735.3 1278.1 665.6 1061.0 1985 739.6 1297.6 673.4 1074.4 1986 730.0 1330.0 684.4 1089.9 1987 748.9 1370.0 703.1 1121.5 1988 802.8 1405.6 732.5 1164.5 1989 829.2 1440.4 769.9 1195.9 1990 832.8 1487.7 795.5 1225.7

  

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  Index. Table 2 shows the Nelson Inflation Petroleum Refinery Construction Indexes since 1946. It is recommeded that the CE Index be used for updating total plant costs, and the M&S Index or Nelson Index for updating equipment costs. The Nelson Indexes are better suited for petroleum refinery materials, labor, equipment, and general refinery inflation. Since Here, A = the size of units for which the cost is known, expressed in terms of capacity, throughput, or volume; B = the size of unit for which a cost is required, expressed in the units of A; n = 0.6 (i.e., the six-tenths exponent); CA = actual cost of unit A; and CB = the cost for B being sought for the same time period as cost CA. To approximate a current cost, multiply the old cost by the ratio of the current index value to the index at the date of the old cost: Here, CA = old cost; IB = current index value; and IA = index value at the date of old cost. Combining Eqs. (1) and (2): For example, if the total investment cost of Plant A was $25,000,000 for 200-million-lb/yr capacity in 1974, find the cost of Plant B at a throughput of 300 million lb/yr on the same basis for 1986. Let the sizing exponent, n, be equal to

  0.6. From Table 1, the CE Index for 1986 was 318.4, and for 1974 it was 165.4. Via Eq. (3): page_1

  

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  Petroleum Products Harold L. Hoffman Petroleum products are made from petroleum crude oil and natural gas. Similar products are made from other natural resources such as coal, peat, lignite, shale oil, and tar sands. Products from these other sources are frequently called ''synthetic," even though their properties can be indistinguishable from crude oil derived products. Here the term "synthetic" is intended to denote the products came from a raw material other than the more common sources, crude oil or natural gas.

  A list of the principal classes of products made from petroleum crude oil is given in Table 1. As an example of the relative product volume for each class, the average percentages are for United States crude oil refiners typical of the mid-1980s.

  Fuels

  are the major class. Common uses for these products are: to burn in furnaces to supply heat, to aspirate into internal combustion engines to supply mechanical power, or to inject into jet engines to create thrust. In some cases the fuel is a gas, like natural gas or the lighter hydrocarbons from crude oil. In other cases the fuel is a clear or very pale orange tinted liquidoften with dyes added for product identity. And in still other cases the fuel is a heavy, dark liquid or semisolid, unable to flow until heated.

  Building materials

  are also among petroleum products. For example, petroleum asphalt is used for roofing and road coverings. Petroleum waxes are used for waterproofing. After special chemical transformations, some petroleum fractions supply a wide range of plastics, elastomers, and other resins for construction uses.

Chemicals

  derived from petroleum are identified in Table 1 as simply "petrochemical feeds." The term "petrochemicals" was coined in an attempt to retain the identity of some chemicals as coming from petroleum. However, most manufacturing statistics do not use this distinction. So petrochemical production is often combined with chemicals derived from other sources within a single chemical class.

  Take note that a highly industralized economy, like that of the United States, diverts no more then about 7% of all petroleum products (feedstocks plus fuels) to the manufacture of petrochemicals. Yet these petrochemicals have a great variety of uses as shown by the partial listing of Table 2.

  World Consumption The trend in petroleum product usage is indicated by the growth in crude oil consumption. Table 3 gives world crude oil consumption in millions of barrels per day. The distribution among various areas reflect the high consumption within industrialized areas like North America (USA and Canada), Western Europe, and the USSR. page_3

Page 3 TABLE 1 Product Yields from U.S

  Refineries, Mid-1980s Basisa Product Vol.% Still gas

  4.9 Liquefied gas

  3.2 Gasoline, motor

  45.8 Gasoline, aviation

  0.2 Jet fuel

  9.8 Kerosene

  0.7 Special naphtha

  0.4 Petrochemical feeds

  3.1 Distillates

  21.2 Lubricants

  1.2 Waxes

  0.1 Coke

  3.8 Asphalt/road oil

  3.1 Residuals

  6.7 Miscellaneous

  0.5 104.7b Total page_3 TABLE 2 Partial List of Petrochemical Uses Absorbents De-emulsifiers Hair conditioners Pipe Activators Desiccants Heat transfer fluids Plasticizers Adhesives Detergents Herbicides Preservatives Adsorbents Drugs Hoses Refrigerants Analgesics Drying oils Humectants Resins Anesthetics Dyes Inks Rigid foams Antifreezes Elastomers Insecticides Rust inhibitors Antiknocks Emulsifiers Insulations Safety glass Beltings Explosives Lacquers Scavengers Biocides Fertilizers Laxatives Stabilizers Bleaches Fibers Odorants Soldering flux Catalysts Films Oxidation inhibitors Solvents Chelating agents Finish removers Packagings Surfactants Cleaners Fire-proofers Paints Sweeteners Coatings Flavors Paper sizings Synthetic rubber Containers Food supplements Perfumes Textile sizings Corrosion inhibitors Fumigants Pesticides Tire cord Cosmetics Fungacides Pharmaceuticals Cushions Gaskets Photographic chemicals

  

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  TABLE 3 Crude Oil Consumptiona Area Millions of barrels per dayb 1970 1975 1980 1985

  USA and Canada

  15.9

  17.6

  18.3

  16.7 Other Western Hemisphere

  2.6

  3.5

  4.4

  4.4 Western Europe

  12.5

  13.2

  13.6

  11.9 USSR

  5.3

  7.5

  8.8

  8.9 China

  0.6

  1.4

  1.8

  1.8 Other CPE countries

  1.5

  2.2

  2.7

  2.5 Africa

  0.9

  1.1

  1.5

  1.7 Asia and Middle East

  2.6

  3.5

  4.8

  5.6 Japan

  4.0

  5.0

  4.9

  4.4 Australasia

  0.6

  0.7

  0.7

  0.7

  46.5

  55.7

  61.5

  58.6 Total aSource: BP Statistical Review of World Energy, issued annually. bBarrel = 42 US gallons. The drop between 1980 and 1985 is the result of a large increase in crude oil price set by oil producing countries. A fourfold price increase of Middle Eastern oil occurred in 1973. Other increases followed. By 1982, the price increase for the period was 12-fold. Because of the resulting increase in fuel price, many conservation measures were takenespecially with regard to fuels used in consuming countries. Later, a drop in crude oil price failed to return oil consumption to its earlier highs. By mid-1987, oil prices were about half of their earlier peak. Then consumption again began to increase, although at a much reduced paceforecasted at about 2% annually. Product Identity Petroleum products are hydrocarbonscompounds with various combinations of hydrogen and carbon. Because there is an almost inconceivable number of hydrogen-carbon combinations, petroleum products take many forms, limited only by the imagination and ingenuity of the people who work with them. Many of the combinations exist naturally in the page_5

  

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  imposes additional specifications on the new product. Also, product specifications tend to evolve to stay abreast of advances in both product application and manufacturing methods. In earlier times there were two significant product specifications: density and boiling range. From these two physical properties, most other propertiesboth physical and chemicalwere implied. Even today, with many sophisticated analytical tests available, these two specifications of density and boiling range are retained.

  Density

  is determined relative to water at 60°F. But instead of using the units of specific density or specific gravity, the common unit of measure is one specified by the American Petroleum Institute. For this reason, the results are called degrees API gravity. The relation of this term to specific gravity is Thus, a petroleum product with the same specific gravity as water, 1.0, has an API gravity of 10. Products with densities less than water have API gravities larger than 10. For example, automotive gasoline generally has an API gravity of between 50 and 70, with the winter grades slightly lighter (greater API gravity) than the summer grades.

Boiling range

  of a petroleum product is reported in several ways. If the product were a single pure hydrocarbon, it would have a single boiling point. But most petroleum products are groups of hydrocarbonseach with its own normal boiling point as well as an influence on the vaporizing tendencies of neighboring hydrocarbons. The apparatus usually used for measuring boiling range is constructed according to standards specified by the American Society for Testing and Materials. The results are then called ASTM distillation temperatures. Some common terms used with boiling range are as follows: Initial (IBP)the temperature at which the first drop of condensate is formed from vaporizing a sample. Percent distilledtemperatures associated with the recovery of various quantities of condensation from a vaporizing sample; e.g., a 10% ASTM temperature.

  End (EP)the highest temperature reached by the vapor during a distillation test. Volatilitya term sometimes related to the distillation test; e.g., reported as volume % vaporized at specific temperatures. Volatility is used in a general way at other times to denote a product's overall vaporizing characteristics.

  Characterization factor

  is a term that combines both density and boiling range. A popular term is the Watson characterization factor defined as follows: page_6

  

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  where TB is the average of five temperatures (10, 30, 50, 70, and 90% vaporized) in degrees Rankin, and sp gr is specific gravity compared to water at 60°F. To show how the characterization factor is related to chemical composition, consider several variations of six-carbon hydrocarbons. The paraffinic hydrocarbon hexane, C6H14, with its boiling point of 155.7°F (615.7°R) and its specific gravity of 0.664, has a Watson K factor of 12.8. The two isoparaffins are 12.8 and 12.6. At the other end of the scale, the six-carbon aromatic hydrocarbon benzene, C6H6, has a boiling point of 176.2°F (636.2°R) and a specific gravity of 0.884, giving a Watson K factor of 9.7. Cyclohexane is 10.6 and five variations of monoolefins are in the 12.312.5 range. While much better ways now exist for chemical analysis of petroleum products, the characterization factor is still an important criterion for buying and selling crude oil raw material.

Discretionary specifications

  exist for most petroleum products. Product specifications set minimum and maximum boundaries on a product's properties. At the discretion of the manufacturer, a product may be made to excell in one property or another, thereby commanding a higher price in a competitive market. In the sections to follow, the more popular fuel products will be described and their discretionary specifications identified.

  Standards for fuel specifications in the United States are set by the American Society for Testing and Materials. This group has many committees dealing with various products. Committee D is concerned with fuels and related products. Specific specifications are numbered with a suffix denoting the year when a specification was updated. For example, the specifications for automotive gasoline are contained in the standard ASTM D 43979.

  Other countries have similar standard-setting organizations. In West Germany, it is Deutsches Institute fuer Normung, and the specifications are identified with DIN numbers. In the United Kingdom, it is the Institute of Petroleum which uses IP numbers, and in Japan, the Ministry of International Trade and Industry uses MITI numbers. Most of these groups cross-reference each other's numbers for easy comparison.

  Gaseous Products Fuels with four or less carbons in the hydrogen-carbon combination have boiling points less than normal room temperature. Therefore, these products are normally gases. Common classifications for these products are as follows.

  Natural gas

  is methane denoted by the chemical structure CH4, the lightest and least complex of all hydrocarbons. Yet, natural gas from an underground reservoir, when brought to the surface, can contain other heavier hydrocarbon vapors. Such a mixture is called a "wet" gas. Wet gas is usually processed to remove the entrained hydrocarbons heavier than methane. When isolated, the heavier hydrocarbons sometime liquefy and are called natural gas condensate.

  

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Still gas is a broad classification for light hydrocarbon mixtures. "Still" is an abbreviation for distillation. Still gas is the lightest

fraction created when crude oil is processed. If the distillation unit is separating light hydrocarbon fractions, the still gas will be

almost entirely methane (C1) with only traces of ethane and ethylene (C2's). If the distillation unit is handling heavier fractions,

the still gas might also contain propanes (C3's) and butanes (C4's).

  5.0 Butane and heavier, max, vol.%

  0.05

  0.05

  0.05

  100 mL, max, mL

  2.0 Sulfur at 15.6°C, 101 kPa, max, mg/m3 229 343 343 343 Residue on evaporation

  2.0

  2.5 Pentane and heavier, max, vol.%

  2.5

  C, max, kPa 1430 1430 485 Propylene, max, vol.%

  Fuel gas and still gas are terms often used interchangably. Yet fuel gas is intended to denote the product's destinationto be used as a fuel for boilers, furnaces, or heaters.

  2.2 Vapor pressure at 37.8°

  2.2

  

38.3

  38.3

  Mixture Distillation, 95% point, max, °C

  TABLE 4 Specifications for Liquefied Petroleum Gases (ASTM D 1835-76) Property Special- Duty propane Commercial Propane Commercial Butane Propane- Butane

  GASOLINE , or motor fuel, is intended for most spark-ignition engines such as those used in passenger cars, light duty trucks, tractors, motorboats, and engine-driven implements. Gasoline is a mixture of hydrocarbons with

  Specifications for LPG are given in Table 4. Note the common use of metric units. While temperature conversion is fairly common, these other conversion factors might be helpful: Pressure in kilopascals multiplied by 7.5 gives millimeters of mercury. Heat in joules multiplied by 0.24 gives calories.

  LPG

is an abbreviation for liquefied petroleum gas. It is composed of propane (C3) and butane (C4). LPG is stored under

pressure in order to keep these hydrocarbons liquefied at normal atmospheric temperatures. Before LPG is burned, it passes through a pressure relief valve. The reduction in pressure causes the LPG to vaporize (gasify). Winter-grade LPG is mostly propane, the lighter of the two gases and easier to vaporize at lower temperatures. Summer-grade LPG is mostly butane. The better grades of LPG strive for reduced content of unsaturated hydrocarbons (propylene and butylene) because these hydrocarbons do not burn as cleanly as do saturated hydro carbons.

  0.05 page_7

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  Page 8 boiling points in the approximate range of 100 to 400°F. Marketing specifications imposed on this fuel are intended to satisfy

requirements of smooth and clean burning, easy ignition in cold weather, minimal evaporation in hot weather, and stability during

long storage periods. These specifications are listed in Table 5.

  Regular and premium grades are relative classifications for the octane numbers of gasolines. An octane number is a measure of gasoline's ability to resist spontaneous detonation. It is critical that detonation be at a precise time for a gasolineair mixture in a

spark-ignition engine. That time is determined by the electrical spark system. After ignition, the course of the detonation should

progress smoothly, with a flame front moving across the combustion chamber.

  If the fuel has a low octane number, the temperature and pressure wave caused by the spark-timed flame front can cause the

remaining fuelair mixture to ignite spontaneously. This secondary explosion causes an extra pressure pulse heard as knock. Then,

more of the fuel's energy is lost as heat, and the engine delivers less motive power.

Octane numbers are measured in a single-cylinder laboratory engine. As in any spark-ignition engine, the combustion chamber of

the laboratory engine is characterized by two volumes: the larger one determined when the piston is farthest from the cylinder head, the smaller one determined when the piston is closest to the head. The ratio of these two volumes is the engine's

compression ratio. Engines with higher compression ratios require fuels with higher octane numbers if knocking is to be avoided.

  TABLE 5 Specifications for Automotive Gasoline (ASTM D 439-79) Property Volatility Class A B C D E

  Octane number No limit specified Distillation temperature, °C:

  10% evaporated, max

  70

  

65

  60

  55

  50 50% evaporated, min

  77

  

77

  77

  77

  77 50% evaporated, max 121 118 116 113 110 90% evaporated, max 190 190 185 185 185 End point, max 225 225 225 225 225

  Temperature for vapor-

  60

  

56

  51

  47

  41 liquid ratio of 20, min, °C Vapor pressure, max, kPa

  62

  

69

  79 93 103 Lead content, max, g/L: Unleaded grade 0.013 0.013 0.013 0.013 0.013 Conventional grade

  1.1

  1.1

  1.1

  1.1

  1.1 page_9

  

Page 9 For common gasoline engines the compression ratio is fixed. But the laboratory test engine has an adjustable head

  Moving the head toward the piston increases the compression ratio and increases the tendency of a fuel to knock. To test a sample fuel, the compression ratio of the laboratory engine is set for track knockdetermined by a bouncing-pin pressure gauge. To relate the final engine conditions to an octane number, the knocking tendencies of two pure hydrocarbons are used as references. One of these hydrocarbons, isooctane (2,2,4-trimethyl pentane), is assigned an octane number of 100. The other, normal heptane, is assigned an octane number of zero. Mixtures of these reference hydrocarbons are assigned octane numbers equal to the volume percent of isooctane in the mixture. Then to complete the octane rating test, it is required to find the reference mixture that gives the same knock intensity in the test engine as that from the sample fuel. An exact match is not necessary, since the pressure gauge can be used to interpolate between near matches.

  Research and Motor

  octane numbers identify other test engine variablesengine speed and intake air temperature. When the engine runs at 600 r/min and with 125°F intake air temperature, the rating is called a Research octane number, abbreviated RON or simply R. When the engine is operated at 900 r/min and with 300°F intake air temperature, the rating is a Motor octane number, MON or M. Both ratings are important to a multicylinder automobile engine because it usually operates over a wide range of conditions. For marketing purposes, a compromise is used: the arithmetic average of the Research and Motor octane numbers, abbreviated (R+M)/2.

  Leaded and unleaded grades

  denote whether the gasoline mix includes lead additives. Lead compounds such as tetraethyl lead and tetramethyl lead are inexpensive additives to improve the octane rating of a gasoline mix. However, with the introduction of the catalytic muffler to automobile engines (to reduce exhaust emissions), unleaded gasolines were needed. Leaded fuel deactivated the catalyst in the muffler. The transition from an almost totally leaded gasoline market to an unleaded gasoline market is shown in Table 5.

Volatility

  is the third most popular marketing quality of a gasoline. Basically, volatility is a measure of a fuel's ability to vaporize. It attempts to combine vapor pressures and boiling points for the many components of a gasoline blend. Volatility is related to the following engine performance parameters: easy starting, quick warm-up, freedom from carburetor icing, rapid acceleration, freedom from vapor lock, good manifold distribution, and minimum crankcase dilution. In short, volatility compromises two extreme properties: enough low boiling hydrocarbons to vaporize easily in cold weather and enough high boiling hydrocarbons to remain a liquid in an engine's fuel supply system during hotter periods. There must also be enough midboiling components to hold the mixture together. Several of the specifications in Table 5 relate to a fuel's volatility: distillation temperatures (used to determine volume percent vaporized for various conditions), temperature to achieve a 20 vaporliquid ratio, and Reid vapor pressure. The five volatility classes (A through E) are tied to seasonal temperatures and locations by a matrix (not shown here) based on typical weather conditions.

  

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  TABLE 6 Specifications for Aviation Gasolines (ASTM D 910-79) Grade

  Property 80 100 100LL Octane number, min:

  Lean 80 100 100

  Rich 87 130 130

  Performance number, min 87 130 130 Color

  Red Green Blue Tetraethyl lead, max, mL/L

  0.13

  1.06

  0.53 Distillation temperature, °C: 10% evaporated, max

  75

  75

  75 40% evaporated, min

  75

  75

  75 50% evaporated, max 105 105 105 90% evaporated, max 135 135 135 Final boiling point, max 170 170 170

  Vapor pressure, max, kPa

  48

  48

  48 Net heat of combustion, min, kJ/kg 43,520 43,520 43,520 Corrosion, copper strip, max, no.

  1

  1

  1 Gum, potential (5 h), max, mg/100 mL

  6

  6

  6 Lead precipitate, visible, max, mg/100 mL

  3

  3

  3 Sulfur, max, wt.%

  0.05

  0.05

  0.05 page_10 Jet fuels are classified as "aviation turbine fuels," and their specifications are given in Table 7. In this case, ratings relative to octane number are replaced with properties concerned with the ability of the fuel to burn cleanly. These properties are discussed in the following section on diesel fuels.

  DIESEL FUELS are distillates that are slightly heavier than gasoline. Diesel engines rely on compression-induced

  ignition. This means diesel fuel must self-ignite easily. In other words, a diesel fuel needs a property that is the opposite of the antiknock property of gasoline. That opposite property is called cetane rating. The term is derived from the reference fuel, normal cetane, which is easily ignited by compression with air and is the basis for comparing diesel fuel blends. This and other specifications for diesel fuels are given in Table 8. Grade 1-D is a lighter material suitable for winter or low temperature operation. Grade 2-D is suitable for warmer temperature operation. Both of these grades have low sulfur content. Grade 4-D is for special situations where the fuel's flow properties and sulfur content are not critical.

  

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  TABLE 7 Specifications for Aviation Turbine Fuels (ASTM D 1655-80a) Properties Jet A or A-1 Jet B Density at 15°C,g/cm3

  0.7750.8394 0.75040.8013 Distillation temperature, °C: 10% recovered, max

  204.4 20% recovered, max 143.3 50% recovered, max 187.8 90% recovered, max 243.3 Final boiling point, max 300

  Vapor pressure, max, kPa

  20.7 Flash point, min, °C

  37.8 Freezing point, max, °C

  40 Jet A

  50

  47 Jet A-1 Viscosity at 20°C, max, mm2/s (= cSt)

  8 Acidity, total, max, mg KOH/g

  0.1 Net heat of combustion, min, kJ/kg 42,780 42,780 Aromatic compounds, max, vol%

  20

  20 Sulfur, max, wt.%: Mercaptan 0.003 0.003 Total

  0.3

  0.3 Corrosion, copper strip after 2 h at 100°C, max, n o.

  1

  1 Gum, existent, max, mg/100 mL

  7

  7 page_11 TABLE 8 Specifications for Diesel Fuel Oils (ASTM 97578)

  Grade Property 1-D 2-D 4-D Distillation (90%) point, °C 288 max 282338 Flash point, min, °C

  38

  52

  55 Water and sediment, max, vol.%

  

0.05

  0.05

  0.05 Carbon residue on 10% bottom, max, %

  

0.15

  0.35 Ash, max, wt.%

  

0.01

  0.01

  0.01 Viscosity at 40°C, kinematic, mm2/s (= cSt)

  

1.32.4

1.94.1 5.524.0 Sulfur, max, wt.%

  

0.50

  0.50

  2.0 Corrosion, copper strip, max, no.

  3

  3 Cetane number, min

  40

  40

  30

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Page 12

  26.4

  0.10

  0.10

  0.10 Viscosity at 38°C, kinematic, mm2/s (= cSt): min

  1.4

  2.0

  2.0

  5.8

  65 max

  1.00 Carbon residue on 10% bottom, max, %

  2.2

  3.6

  5.8

  26.4 65 194 Corrosion, copper strip, max, no.

  3

  0.5