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Handbook of Petroleum
JAMES G. SPEIGHT
CD-WINC
WILEYINTERSCIENCE
A JOHN WILEY & SONS9 INC., PUBLICATION
New York Chichester Weinheim Brisbane Singapore Toronto
This book is printed on acid-free paper.
Copyright 2001 by John Wiley and Sons, Inc. All rights reserved.
Published simultaneously in Canada.
No part of this publication may be reproduced, stored in a retrieval system or transmitted in any
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For ordering and customer service, call 1-800-CALL-WILEY.
Speight, J. G.
Handbook of petroleum analysis / James G. Speight.
ISBN 0-471-36167-4 (cloth : alk. paper)
1. PetroleumAnalysis. I. Title.
TP691 .S687 2001
665.5dc21
Printed in the United States of America.
Attempts to understand and manipulate chemical processes have persisted over
centuries, with an explosion of technological innovation and research occurring in
the last 100 years. The majority of these efforts have focused on using the knowledge gained to produce a useful product and achieve a perceived improvement in
the performance of that product.
The laws of science will ultimately dictate what can or cannot be done with
feedstocks to provide the needed products. The science of analytical chemistry is
at the core of understanding of both the problems of processing various feedstocks.
This book examines the way that the analytical science has been applied to defining
the properties and behavior of the different feedstocks that are used in the petroleum
refining industry.
In the twentieth century, scientists became increasingly well-versed in utilizing
chemical knowledge to better understand the nature of petroleum, heavy oil, and tar
sand bitumen and the influence of each feedstock on refining scenarios and on the
product slate. Definitions of processing do's and don't's abound in the scientific
and engineering literature, but the essence of these rules depends on analytical
chemical measurements.
Petroleum exhibits a wide range of physical properties, and a wide range of tests
have been (and continue to be) developed to provide an indication of the means by
which a particular feedstock should be processed. Initial inspection of the nature
of the petroleum will provide deductions about the most logical means of refining
or correlation of various properties to structural types present and hence attempted
classification of the petroleum. Proper interpretation of the data resulting from the
inspection of crude oil requires an understanding of their significance.
Evaluation of petroleum for use as a feedstock usually involves an examination
of one or more of the physical properties of the material. By this means, a set of basic
characteristics can be obtained that can be correlated with utility. Consequently,
various standards organizations, such as the American Society for Testing and
Materials in North America and the Institute of Petroleum in Great Britain have
devoted considerable time and effort to the correlation and standardization of
methods for the inspection and evaluation of petroleum and petroleum products.
The acceptance of heavier feedstocks (such as heavy oil and bitumen) by refineries has meant that the analytical techniques used for the lighter feedstocks
have had to evolve to produce meaningful data that can be used to assist in defining refinery scenarios for processing the feedstocks. In addition, selection of the
most appropriate analytical procedures will aid in the predictability of feedstock
behavior during refining. This same rationale can also be applied to feedstocks
behavior during recovery operations.
Because of the wide range of chemical and physical properties, a wide range
of tests have been (and continue to be) developed to provide an indication of the
means by which a particular feedstock should be processed. Initial inspection of
the nature of the petroleum will provide deductions about the most logical means
of refining or correlation of various properties to structural types present and hence
attempted classification of the petroleum. Proper interpretation of the data resulting
from the inspection of crude oil requires an understanding of their significance.
It is for these reasons that understanding the composition of petroleum, heavy
oil, and bitumen as well as the chemical and physical properties of these feedstocks
is extremely important.
An efficient evaluation of a feedstock or product requires the application of
tests to insure that the feedstock or product meets specifications. These are then
used to provide adequate control of product quality without being overrestrictive
with the minimum of testing effort.
Product quality is judged by the performance during service. The performance
of any product in particular service applications is therefore the ultimate criterion
of quality. It is therefore necessary to find properties that allow assessment of the
service performance, especially those tests that correlate closely with the service
conditions. Sometimes the inspection tests attempt to measure these properties,
for example, the research octane number test that was devised to measure the
antiknock performance of motor fuel, or, in many cases, the significant property
is obtained indirectly from the inspection test results.
However, where the specified property is not measured directly, it is important
to ensure that a suitable combination of inspection tests is selected to give a high
degree of correlation with the specified property.
Although the focus on this book is on the relevant ASTM test methods with
the numbers given, where possible the corresponding IP test method number is
also presented. As an aside, the ASTM or the IP may have withdrawn some of
the tests noted herein. Nevertheless these methods are still included because of
their continued use, for whatever reason, by analysts and also for historical (not
hysterical) reference purposes!
Thus this book deals with the various aspects of petroleum analysis and provides
a detailed explanation of the necessary standard tests and procedures that are
applicable to feedstocks to help define predictability of behavior. In addition, the
application of new methods for determining instability and incompatibility as well
as analytical methods related to environmental regulations are described. More
importantly, the book provides details of the meaning of the various test results
and how they might be applied to predict feedstock behavior. Where applicable,
new tests that are not yet accepted as standard tests are described.
The focus of the book is the analysis of crude oil, with lesser emphasis on
product analysis. Although product analysis is an extremely important aspect of
petroleum science and technology, it is felt that the move to different feedstocks for
refinery operations requires that more emphasis be placed on feedstock analysis
and character, at least for this first text. Inclusion of product analyses is a natural
extension of feedstock analysis, and they are included here but not as a separate
section or sections.
Analytical chemists represent a rich resource for the various aspects of petroleum
refining. Analytical chemists recognize that although the recent decades of experience have enhanced knowledge, they have also revealed large gaps in the kind of
data needed to thoroughly understand the nature of petroleum refining.
The development of laboratory instrumentation over the last fifty years has been
one of the forces shaping analytical standards, and improved instrumentation is
already changing approaches to petroleum analysis. Like the twin strands of the
famous DNA double helix, technology and analytical science and regulation will
continue their closely linked relationship.
If this book helps toward a better understanding of the criteria for quality of
petroleum and petroleum products and so leads to the writing of better specifications, it will have served its purpose.
DR. JAMES G. SPEIGHT
A SERIES OF MONOGRAPHS ON
ANALYTICAL CHEMISTRY AND ITS APPLICATIONS
J. D. Winefordner, Series Editor
VoI.
1. The Analytical Chemistry of Industrial Poisons, Hazards, and Solvents.
Second Edition. By the late Morris B. Jacobs
2. Chromatographic Adsorption Analysis. By Harold H. Strain (out of print)
3. Photometric Determination of Traces of Metals. Fourth Edition
Part I: General Aspects. By E. B. Sandell and Hiroshi Onishi
Part HA: Individuals Metals, Aluminum to Lithum. By Hiroshi Onishi
Part HB: Individuals Metals, Magnesium to Zirconium. By Hiroshi Onishi
4. Organic Reagents Used in Gravimetric and Volumetric Analysis. By John
F. Flagg (out of print)
5. Aquametry: A Treatise on Methods for the Determination of Water. Second
Edition (in three parts). By John Mitchell, Jr. and Donald Milton Smith
6. Analysis of Insectidies and Acaricides. By Francis A. Gunther and Roger C.
Blinn (out of print)
7. Chemical Analysis of Industrial Solvents. By the late Morris B. Jacobs and
Leopard Scheltan
8. Colorimetric Determination of Nonmetals. Second Edition. Edited by the
late David F. Boltz and James A. Howell
9. Analytical Chemistry of Titanium Metals and Compounds. By Maurice
Codell
10. The Chemical Analysis of Air Pollutants. By the late Morris B. Jacobs
11. X-Ray Spectrochemical Analysis. Second Edition. By L. S. Birks
12. Systematic Analysis Surface-Active Agents. Second Edition. By Milton
J. Rosen and Henry A. Goldsmith
13. Alternating Current Polarography and Tensammetry. By B. Breyer and
H. H. Bauer
14. Flame Photometry. By R. Hermann and J. Alkemade
15. The Titration of Organic Compounds (in two parts). By M. R. F. Ashworth
16. Complexation in Analytical Chemistry: A guide for the Critical
Selection of Analytical Methods Based on Complexation Reactions. By
the late Anders Ringbom
17. Electron Probe Microanalysis. Second Edition. By L. S. Birks
18. Organic Complexing Reagents: Structure, Behaviour, and Application to
Inorganic Analysis. By D. D. Perrin
19. Thermal Analysis. Third Edition. By Wesley Wm. Wendlandt
20. Amperometric Titrations. By John T. Stock
21. Reflectance Spectroscopy. By Wesley Wm. Wendlandt and Harry G. Hecht
22. The Analytical Toxicology of Industrial Inorganic Poisons. By the late
Morris B. Jacobs
23. The Formation and Properties of Precipitates. By Alan G. Walton
24. Kinetics in Analytical Chemistry. By Harry B. Mark, Jr. And Garry A.
Rechintz
25. Atomic Absorption Spectroscopy. Second Edition. By Morris Slavin
26. Characterization of Organometallic Compounds {in two parts). Edited by
Minoru Tsutsui
27. Rock and Mineral Analysis. Second Edition. By Wesely M. Johnson and John
A. Maxwell
28. The Analytical Chemistry of Nitrogen and Its Compounds {in two parts).
Edited by C. A. Streuli and Philip R. Averell
29. The Analytical Chemistry of Sulphur and Its Compounds {in three parts).
By J. H. Karchmer
30. Ultramicro Elemental Analysis. By Gunther ToIg
31. Photometric Organic Analysis {in two parts). By Eugene Sawicki
32. Determination of Organic Compounds: Methods and Procedures. By
Frederick T. Weiss
33. Masking and Demasking of Chemical Reactions. By D. D. Perrin
34. Neutron Activation Analysis. By D. De Soete, R. Gijbels, and J. Hoste
35. Laser Raman Spectroscopy. By Marvin C. Tobin
36. Emission Spectrochemical Analysis. By Morris Slavin
37. Analytical Chemistry of Phosphorous Compounds. Edited by M. Halmann
38. Luminescence Spectrometry in Analytical Chemistry. By J. D. Winefordner,
S. G. Schulman and T. C. O'Haver
39. Activation Analysis with Neutron Generators. By Sam S. Nargolwalla and
Edwin P. Przybylowicz
40. Determination of Gaseous Elements in Metals. Edited by Lynn L. Lewis,
Laben M. Melnick, and Ben D. Holt
41. Analysis of Silicones. Edited by A. Lee Smith
42. Foundations of Ultracentrifugal Analysis. By H. Fujita
43. Chemical Infrared Fourier Transform Spectroscopy. By Peter R. Griffiths
44. Microscale Manipulations in Chemistry. By T. S. Ma and V. Horak
45. Thermometric Titrations. By J. Barthel
46. Trace Analysis: Spectroscopic Methods for Elements. Edited by J. D.
Winefordner
47. Contamination Control in Trace Element Analysis. By Morris Zief and
James W. Mitchell
48. Analytical Applications of NMR. By D. E. Leyden and R. H. Cox
49. Measurement of Dissolved Oxygen. By Michael L. Hitchman
50. Analytical Laser Spectroscopy. Edited by Nicolo Omenetto
51. Trace Element Analysis of Geological Materials. By Roger D. Reeves and
Robert R. Brooks
52. Chemical Analysis by Microwave Rotational Spectroscopy. By Ravi Varma
and Lawrence W. Hrubesh
53. Information Theory As Applied to Chemical Analysis. B y Karl Eckschlager
and Vladimir Stepanek
54. Applied Infrared Spectroscopy: Fundamentals, Techniques, and Analytical Problem-solving. By A. Lee Smith
55. Archaeological Chemistry. By Zvi Goffer
56. Immobilized Enzymes in Analytical and Clinical Chemistry. By R W. Carr
and L. D. Bowers
57. Photoacoustics and Photoacoustic Spectroscopy. By Allan Rosenewaig
58. Analysis of Pesticide Residues. Edited by H. Anson Moye
59. Affinity Chromatography. By William H. Scouten
60. Quality Control in Analytical Chemistry. Second Edition. By G. Kateman
and L. Buydens
61. Direct Characterization of Fineparticles. By Brain H. Kaye
62. Flow Injection Analysis. By J. Ruzicka and E. H. Hansen
63. Applied Electron Spectroscopy for Chemical Analysis. Edited by Hassan
Windawi and Floyd Ho
64. Analytical Aspects of Environmental Chemistry. Edited by David F. S.
Natusch and Philip K. Hopke
65. The Interpretation of Analytical Chemical Data by the Use of Cluster
Analysis. By D. Luc Massart and Leonard Kaufman
66. Solid Phase Biochemistry: Analytical and Synthetic Aspects. Edited by
William H. Scouten
67. An Introduction to Photoelectron Spectroscopy. By Pradip K. Ghosh
68. Room Temperature Phosphorimetry for Chemical Analysis. By Tuan
Vo-Dinh
69. Potentiometry and Potentiometric Titrations. By E. P. Serjeant
70. Design and Application of Process Analyzer Systems. By Paul E. Mix
71. Analysis of Organic and Biological Surfaces. Edited by Patrick Echlin
72. Small Bore Liquid Chromatography Columns: Their Properties and Uses.
Edited by Raymond P. W. Scott
73. Modern Methods of Particle Size Analysis. Edited by Howard G. Barth
74. Auger Electron Spectroscopy. By Michael Thompson, M. D. Baker, Alec
Christie, and J. F. Tyson
75. Spot Test Analysis: Clinical, Environmental, Forensic and Geochemical
Applications. By Ervin Jungreis
76. Receptor Modeling in Environmental Chemistry. By Philip K. Hopke
77. Molecular Luminescence Spectroscopy: Methods and Applications (in
three parts). Edited by Stephen G. Schulman
78. Inorganic Chromatographic Analysis. Edited by John C. MacDonald
79. Analytical Solution Calorimetry. Edited by J. K. Grime
80. Selected Methods of Trace Metal Analysis: Biological and Environmental
Samples. By Jon C. VanLoon
81. The Analysis of Extraterrestrial Materials. By Isidore Adler
82. Chemometrics. By Muhammad A. Sharaf, Deborah L. Illman, and Bruce
R. Kowalski
83. Fourier Transform Infrared Spectrometry. By Peter R. Griffiths and James
A. de Haseth
84. Trace Analysis: Spectroscopic Methods for Molecules. Edited by Gary
Christian and James B. Callis
85. Ultratrace Analysis of Pharmaceuticals and Other Compounds of Interest.
Edited by S. Ahuja
86. Secondary Ion Mass Spectrometry: Basic Concepts, Instrumental Aspects,
Applications and Trends. By A. Benninghoven, F. G. Riidenauer, and H. W.
87. Analytical Applications of Lasers. Edited by Edward H. Piepmeier
88. Applied Geochemical Analysis. By C. O. Ingamells and F. F. Pitard
89. Detectors for Liquid Chromatography. Edited by Edward S. Yeung
90. Inductively Coupled Plasma Emission Spectroscopy: Part 1: Methodology,
Instrumentation, and Performance; Part II: Applications and Fundamentals. Edited by J. M. Boumans
91. Applications of New Mass Spectrometry Techniques in Pesticide Chemistry. Edited by Joseph Rosen
92. X-Ray Absorption: Principles, Applications, Techniques, of EXAFS,
SEXAFS, and XANES. Edited by D. C. Konnigsberger
93. Quantitative Structure-Chromatographic Retention Relationships. By
Roman Kaliszan
94. Laser Remote Chemical Analysis. Edited by Raymond M. Measures
95. Inorganic Mass Spectrometry. Edited by F. Adams, R. Gijbels, and R. Van
96. Kinetic Aspects of Analytical Chemistry. By Horacio A. Mottola
97. Two-Dimensional NMR Spectroscopy. By Jan Schraml and Jon M. Bellama
98. High Performance Liquid Chromatography. Edited by Phyllis R. Brown
and Richard A. Hartwick
99. X-Ray Fluorescence Spectrometry. By Ron Jenkins
100. Analytical Aspects of Drug Testing. Edited by Dale G. Deustch
101. Chemical Analysis of Poly cyclic Aromatic Compounds. Edited by Tuan
VoDinh
102. Quadrupole Storage Mass Spectrometry. By Raymond E. March and
Richard J. Hughes
103. Determination of Molecular Weight. Edited by Anthony R. Cooper
104. Selectivity and Detectability Optimization in HPLC. By Satinder Ahuja
105. Laser Microanalysis. By Lieselotte Moenke-Blankenburg
106. Clinical Chemistry. Edited by E. Howard Taylor
107. Multielement Detection Systems for Spectrochemical Analysis. By Kenneth
W. Busch and Marianna A. Busch
108. Planar Chromatography in the Life Sciences. Edited by Joseph C.
109. Fluorometric Analysis in Biomedical Chemistry: Trends and Techniques
Including HPLC Applications. By Norio Ichinose, George Schwedt, Frank
Michael Schnepel, and Kyoko Adochi
110. An Introduction to Laboratory Automation. By Victor Cerda and Guillermo
111. Gas Chromatography: Biochemical, Biomedical, and Clinical Applications. Edited by Ray E. Clement
112. The Analysis Chemistry of Silicones. Edited by A. Lee Smith
113. Modern Methods of Polymer Characterization. Edited by Howard G. Barm
and Jimmy W. Mays
114. Analytical Raman Spectroscopy. Edited by Jeanette Graselli and Bernard J.
Bulkin
115. Trace and Ultratrace Analysis by HPLC. By Satinder Ahuja
116. Radiochemistry and Nuclear Methods of Analysis. By William D. Ehmann
and Diane E. Vance
117. Applications of Fluorescence in Immunoassays. By Ilkka Hemmila
118. Principles and Practice of Spectroscopic Calibration. By Howard Mark
119. Activation Spectrometry in Chemical Analysis. By S. J. Parry
120. Remote Sensing by Fourier Transform Spectrometry. By Reinhard Beer
121. Detectors for Capillary Chromatography. Edited by Herbert H Hill and
Dennis McMinn
122. Photochemical Vapor Deposition. By J. G. Eden
123. Statistical Methods in Analytical Chemistry. By Peter C. Meier and Richard
Ziind
124. Laser Ionization Mass Analysis. Edited by Akos Vertes, Renaat Gijbels, and
Fred Adams
125. Physics and Chemistry of Solid State Sensor Devices. By Andreas Mandelis
and Constantinos Christofides
126. Electroanalytical Stripping Methods. By Khjena Z. Brainina and
E. Neyman
127. Air Monitoring by Spectroscopic Techniques. Edited by Markus W. Sigrist
128. Information Theory in Analytical Chemistry. By Karel Eckschlager and
Klaus Danzer
129. Flame Chemiluminescence Analysis by Molecular Emission Cavity Detection. Edited by David Stiles, Anthony Calokerinos, and Alan Townshend
130. Hydride Generation Atomic Absorption Spectrometry. By Jiri Dedina and
Dimiter L. Tsalev
131. Selective Detectors: Environmental, Industrial, and Biomedical Applications. Edited by Robert E. Sievers
132. High Speed Countercurrent Chromatography. Edited by Yoichiro Ito and
Walter D. Con way
Vol. 133. Particle-Induced X-Ray Emission Spectrometry. By Sven A. E. Johansson,
John L. Campbell, and Klas G. Malmqvist
Vol. 134. Photothermal Spectroscopy Methods for Chemical Analysis. By Stephen
E. Bialkowski
Vol. 135. Element Speciation in Bioinorganic Chemistry. Edited by Sergio Caroli
Vol. 136. Laser-Enhanced Ionization Spectrometry. Edited by John C. Travis and
Gregory C. Turk
Vol. 137. Fluorescence Imaging Spectroscopy and Microscopy. Edited by Xue Feng
Wang and Brain Herman
Vol. 138. Introduction to X-ray Powder Diffractometry. By Ron Jenkins and Robert
L. Snyder
Vol. 139. Modern Techniques in Electroanalysis. Edited by Petr Vanysek
Vol. 140. Total Reflection X-Ray Fluorescence Analysis. By Reinhold Klockenkamper
Vol. 141. Spot Test Analysis: Clinical, Environmental, Forensic, and Geochemical
Applications, Second Edition. By Ervin Jungreis
Vol. 142. The Impact of Stereochemistry on Drug Development and Use. Edited by
Hassan Y. Aboul-Enein and Irving W. Wainer
Vol. 143. Macrocyclic Compounds in Analytical Chemistry. Edited by Yury A.
Zolotov
Vol. 144. Surface-Launched Acoustic Wave Sensors: Chemical Sensing and ThinFilm Characterization. By Michael Thompson and David Stone
Vol. 145. Modern Isotope Ratio Mass Spectrometry. Edited by T. J. Platzner
Vol. 146. High Performance Capillary Electrophoresis: Theory, Techinques, and
Applications. Edited by Morteza G. Khaledi
Vol. 147. Solid Phase Extraction: Principles and Practice. By E. M. Thurman
Vol. 148. Commercial Biosensors: Applications to Clinical, Bioprocess and Environmental Samples. Edited by Graham Ramsay
Vol. 149. A Practical Guide to Graphite Furnace Atomic Absorption Spectrometry.
By David J. Butcher and Joseph Sneddon
Vol. 150. Principles of Chemical and Biological Sensors. Edited by Dermot Diamond
Vol. 151. Pesticide Residue in Foods: Methods, Technologies, and Regulations. By
W. George Fong, H. Anson Moye, James N. Seiber, and John P. Toth
Vol. 152. X-Ray Fluorescence Spectrometry. Second Edition. By Ron Jenkins
Vol. 153. Statistical Methods in Analytical Chemistry. Second Edition. By Peter C.
Meier and Richard E. Ziind
Vol. 154. Modern Analytical Methodologies in Fat and Water Soluble Vitamins.
Edited by Won O. Song, Gary R. Beecher and Ronald R. Eitenmiller
Vol. 155. Modern Analytical Methods in Arts and Archaeology. Edited by Enrico
Ciliberto and Guiseppe Spoto
Vol. 156. Shpol'skii Spectroscopy and Others Site Selection Methods: Applications
in Environmental Analysis, Bioanalytical Chemistry and Chemical Physics.
Edited by C. Goojier, F. Ariese and J. W. Hofstraat
Vol. 157. Raman Spectroscopy for Chemical Analysis. By Richard L. McCreery
Vol. 158. Handbook of Petroleum Analysis. By James G. Speight
Preface ............................................................................
Cumulative Listing of Volumes in Series .........................
Definitions and History ..........................................
Introduction .................................................................
Definitions ...................................................................
Historical Perspectives ...............................................
Modern Perspectives .................................................
Analysis and Specifications .......................................
Chemical Composition ...........................................
Ultimate (Elemental) Composition .............................
Chemical Composition ...............................................
Classification ..........................................................
Classification Systems ...............................................
Miscellaneous Systems .............................................
This page has been reformatted by Knovel to provide easier navigation.
Physical Properties ................................................
Elemental (Ultimate) Analysis ....................................
Metal Content .............................................................
Density, Specific Gravity, and API Gravity ................
Viscosity .....................................................................
Surface and Interfacial Tension .................................
Thermal Properties .................................................
Volatility ......................................................................
Liquefaction and Solidification ...................................
Carbon Residue .........................................................
Aniline Point ...............................................................
Specific Heat ..............................................................
Latent Heat .................................................................
Enthalpy or Heat Content ...........................................
Thermal Conductivity .................................................
5.10 Pressure-Volume-Temperature Relationships ..........
5.11 Heat of Combustion ...................................................
5.12 Critical Properties .......................................................
Electrical and Optical Properties ...........................
Electrical Properties ...................................................
Optical Properties .......................................................
Spectroscopic Methods .........................................
Infrared Spectroscopy ................................................
Nuclear Magnetic Resonance ....................................
Mass Spectrometry ....................................................
Ultraviolet Spectroscopy ............................................
X-Ray Diffraction ........................................................
Chemical Methods ..................................................
Functional Group Analysis .........................................
Hydrogenation ............................................................
Oxidation ....................................................................
Halogenation ..............................................................
Thermal Methods .......................................................
Miscellaneous Methods .............................................
Fractional Composition ..........................................
Distillation ...................................................................
Solvent Treatment ......................................................
Adsorption ..................................................................
Chemical Methods .....................................................
10. Chromatographic Analysis ....................................
10.1 Introduction .................................................................
10.2 Gas Chromatography .................................................
10.3 Simulated Distillation ..................................................
10.4 Adsorption Chromatography ......................................
10.5 Gel Permeation Chromatography ..............................
10.6 Ion-Exchange Chromatography .................................
10.7 High-Performance Liquid Chromatography ...............
10.8 Supercritical Fluid Chromatography ..........................
10.9 Thin-Layer Chromatography ......................................
11. Structural Group Analysis .....................................
11.2 Physical Property Methods ........................................
11.3 Spectroscopic Methods ..............................................
11.4 Methods for Heteroatom Systems .............................
12. Molecular Weight ....................................................
12.2 Methods for Molecular Weight Measurement ............
12.3 Molecular Weights of Volatile Fractions ....................
12.4 Molecular Weights of Nonvolatile Fractions ..............
13. Instability and Incompatibility ...............................
13.2 Instability and Incompatibility Assessment ................
13.3 Direct Test Methods ...................................................
13.4 Indirect Test Methods .................................................
14. Use of the Data The Structure of
Petroleum ................................................................
14.2 The Structure of Petroleum ........................................
14.3 The Stability/Instability of the Crude Oil
System .......................................................................
15. Use of the Data Mapping and
Predictability ...........................................................
15.2 Feedstock Mapping ....................................................
15.3 Epilog ..........................................................................
Glossary .........................................................................
Index ...............................................................................
DEFINITIONS AND HISTORY
Petroleum, meaning literally rock oil, is the term used to describe a myriad of
hydrocarbon-rich fluids that has accumulated in subterranean reservoirs. Petroleum
(also called crude oil) varies dramatically in color, odor, and flow properties that
reflect the diversity of its origin.
Historically, physical properties such as boiling point, density (gravity), odor,
and viscosity have been used to describe oils. Petroleum may be called light or
heavy in reference to the amount of low-boiling constituents and the relative density
(specific gravity). Likewise, odor is used to distinguish between sweet (low sulfur)
and sour (high sulfur) crude oil. Viscosity indicates the ease of (or more correctly
the resistance to) flow.
Although not directly derived from composition, the terms light or heavy or
sweet and sour provide convenient terms for use in descriptions. For example,
light petroleum (often referred to as conventional petroleum) is usually rich in
low-boiling constituents and waxy molecules whereas heavy petroleum contains
greater proportions of higher-boiling, more aromatic, and heteroatom-containing
(N-, O-, S-, and metal-containing) constituents. Heavy oil is more viscous than
conventional petroleum. Bitumen is solid or near solid.
Conventional (light) petroleum is composed of hydrocarbons together with
smaller amounts of organic compounds of nitrogen, oxygen, and sulfur and still
smaller amounts of compounds containing metallic constituents, particularly vanadium, nickel, iron, and copper. The processes by which petroleum was formed
dictate that petroleum composition will vary and be site specific, thus leading to
a wide variety of compositional differences. The term site specific is intended to
convey the idea that petroleum composition will be dependent on regional and local
variations in the proportion of the various precursors that went into the formation
of the protopetroleum (page 5) as well as variations in temperature and pressure
to which the precursors were subjected.
Thus the purely hydrocarbon content may be higher than 90% by weight for
paraffinic petroleum and 50% by weight for heavy crude oil and much lower for
tar sand bitumen. The nonhydrocarbon constituents are usually concentrated in
the higher-boiling portions of the crude oil. The carbon and hydrogen content is
approximately constant from crude oil to crude oil even though the amounts of
the various hydrocarbon types and of the individual isomers may vary widely.
Thus the carbon content of various types of petroleum is usually between 83
and 87% by weight and the hydrogen content is in the range of 11-14% by
The near-constancy of carbon and hydrogen contents is explained by the fact
that variation in the amounts of each series of hydrocarbons does not have a
profound effect on overall composition. The atomic ratio of hydrogen to carbon
increases from the low- to the high-molecular-weight fractions. This is attributable
to a decrease in the content of polynuclear aromatics and multiring cycloparaffins
that are found in the higher-boiling fractious.
For higher-boiling feedstocks such as heavy oil and bitumen, the chemical
composition becomes so complex and its relationship to performance so difficult
to define that direct correlation may be impossible. In any case, simpler tests are
required for quality control purposes. Analysis is then confined to the determination
of certain important elements and to characterization of the feedstock in terms of
a variety of structural groups.
General aspects of petroleum quality (as a refinery feedstock) are assessed
by measurement of physical properties such as relative density (specific gravity),
refractive index, or viscosity or by empirical tests such as pour point or oxidation
stability that are intended to relate to behavior in service. In some cases, the
evaluation may include tests in mechanical rigs and engines either in the laboratory
or under actual operating conditions.
Measurements of bulk properties are generally easy to perform and, therefore,
quick and economical. Several properties may correlate well with certain compositional characteristics and are widely used as a quick and inexpensive means to
determine those characteristics. The most important properties of a whole crude
oil are its boiling-point distribution, its density (or API gravity), and its viscosity.
The boiling-point distribution, boiling profile, or distillation assay gives the yield
of the various distillation cuts. It is a prime property in its own right that indicates
how much gasoline and other transportation fuels can be made from petroleum
without conversion. Density and viscosity are measured for secondary reasons. The
former helps to estimate the paraffinic character of the oil, and the latter permits
the assessment of its undesirable residual material that cause resistance to flow.
Boiling-point distribution, density, and viscosity are easily measured and give a
quick first evaluation of petroleum. Sulfur content, another crucial and primary
property of a crude oil, is also readily determined. Certain composite characterization values, calculated from density and mid-boiling point (Chapter 5) correlate
better with molecular composition than density alone.
For heavy oil, bitumen, and residua, density and viscosity still are of great
interest. But for such materials, hydrogen, nitrogen, sulfur, and metal content as
well as carbon residue values become even more important (Table 1.1).
Table 1.1. Analytical Inspections for Petroleum, Heavy Oil,
Bitumen, and Residua
Density, specific gravity
API gravity
Carbon, wt%
Hydrogen, wt%
Nitrogen, wt%
Sulfur, wt%
Pour point
Wax content
Wax appearance
Viscosity (various
temperatures)
Carbon residue of residuum
Distillation profile
All fractions plus
vacuum residue
Heavy Feedstocks
Nickel, ppm
Vanadium, ppm
Iron, ppm
Viscosity (various temperatures
and at reservoir temperature)
Carbon residue*
Ash, wt%
Fractional composition:
Asphaltenes, wt%
Resins, wt%
Aromatic s, wt%
Saturates, wt%
*Conradson carbon residue or microcarbon residue.
The acceptance of these heavy oils and bitumen as refinery feedstocks has meant
that the analytical techniques used for the lighter feedstocks have had to evolve to
produce meaningful data that can be used to assist in defining refinery scenarios for
processing the feedstocks. In addition, selection of the most appropriate analytical
procedures will aid in the predictability of feedstock behavior during refining.
This same rationale can also be applied to feedstock behavior during recovery
operations. Indeed, bitumen, a source of synthetic crude oil, is so different from
petroleum (Table 1.2) (Speight and Moschopedis, 1979; Speight, 1990) that many
of the test methods designed for petroleum may need modification (Wallace, 1988).
Thus knowledge of the composition of petroleum allows the refiner to optimize
the conversion of raw petroleum into high-value products. Petroleum is now the
world's main source of energy and petrochemical feedstock. Originally, petroleum
was distilled and sold as fractions with desirable physical properties. Today, crude
oil is sold in the form of gasoline, solvents, diesel and jet fuel, heating oil,
Table 1.2. Properties of Conventional Crude Oil, Synthetic Crude Oil,
and Bitumen
Viscosity, cp
380CAOO0F
100C/212F
Pour point, 0 F
Elemental analysis (wt%):
Nickel (ppm)
Vanadium (ppm)
Fractional composition (wt%)
Asphaltenes (pentane)
Carbon residue (wt%)
Conradson
ca.-20
<10.0
lubricating oils, and asphalts or it is converted to petrochemical feedstocks such as
ethylene, propylene, the butenes, butadiene, and isoprene. These feedstocks are important because they form the basis for, among others, the plastics, elastomers, and
artificial fiber industries. Modern refining uses a sophisticated combination of heat,
catalyst, and hydrogen to rearrange the petroleum constituents into these products.
Conversion processes include coking, hydrocracking, and catalytic cracking to
break large molecules into smaller fractions; hydrotreating to reduce heteroatoms
and aromatics, creating environmentally acceptable products; and isomerization
and reforming to rearrange molecules to those with high value, e.g., gasoline with
a high octane number.
Also, knowledge of the molecular composition of petroleum allows the environmentalist to consider the biological impact of environmental exposure. Increasingly, petroleum is being produced and transported from remote areas of the world
to refineries located closer to their markets. Although a minuscule fraction of that
oil is released into the environment, the sheer volume involved has the potential
for environmental impact. Information on molecular composition is needed not
only to identify the sources of contamination but also to understand the fate and
effects of its potentially hazardous components.
In addition, knowledge of the composition of petroleum allows the geologist
to answer questions of precursor-product relationships and conversion mechanisms. Biomarkers, molecules that retain the basic carbon skeletons of biological
compounds from living organisms after losing functional groups through the
maturation process, play an important role in such studies. The distribution of
biomarker isomers can not only serve as fingerprints for oil-oil and oilsource correlation (to relate the source and reservoir) but also give geochemical
information on organic source input (marine, lacustrine, or land-based sources),
age, maturity, depositional environment (for example, clay or carbonate, oxygen
levels, salinity), and alteration (for example, water washing, biodegradation).
Because of the complexity of the precursor mix that leads to the
intermediate that is often referred to as protopetroleum and which eventually
to petroleum, the end product contains an extremely wide range of organic functionality and molecular size. In fact, the variety is so great that it is unlikely
that a complete compound-by-compound description for even a single crude oil
would be possible. On the other hand, the molecular composition of petroleum
can be described in terms of three classes of compounds: saturates, aromatics,
and compounds bearing heteroatoms (nitrogen, oxygen, sulfur, and/or metals).
Within each class, there are several families of related compounds. The distribution and characteristics of these molecular species account for the rich variety of
crude oils.
The need for the application of analytical techniques has increased over the past
three decades because of the change in feedstock composition. This has arisen
because of the increased amounts of the heavier feedstocks that are now used
to produce liquid products. Before the energy crises of the 1970s, the heavier
feedstocks were used infrequently as sources of liquid fuels and were mainly used
to produce asphalt. Now these feedstocks have increased in value as sources of
liquid fuels.
of tests have been (and continue to be) developed to provide an indication of
the means by which a particular feedstock should be processed. Initial inspection
of the nature of the petroleum will provide deductions about the most logical
means of refining or correlation of various properties to structural types present
and hence the attempted classification of the petroleum. Proper interpretation of
the data resulting from the inspection of crude oil requires an understanding of the
significance of these properties.
Evaluation of petroleum for use as a feedstock usually involves an examination of one or more of the physical properties of the material. By this means,
a set of basic characteristics can be obtained that can be correlated with utility.
Consequently, various standards organizations, such as the American Society for
Testing and Materials (ASTM) in North America and the Institute of Petroleum
(IP) in Britain have devoted considerable time and effort to the correlation and
standardization of methods for the inspection and evaluation of petroleum and
petroleum products.
is extremely important. However, product characteristics and specifications are also
Having decided what characteristics are necessary, it then remains to describe
the sample in terms of a specification. This entails selecting suitable test methods
and setting appropriate limits. Many specifications in widespread use have evolved
by the addition of extra clauses (rarely is a clause deleted). This has resulted
in unnecessary restrictions that, in turn, result in increased cost of the products
a detailed explanation of the necessary standard tests and procedures that are applicable to feedstocks to help define predictability of behavior. In addition, the appli
cation of new methods for determining instability and incompatibility as well as
analytical methods related to environmental regulations are described. More important, the book provides details of the meaning of the various test results and
how they might be applied to predict feedstock behavior. Where applicable, new
tests that are not yet accepted as standard tests are described.
Terminology is the means by which various subjects are named so that reference
can be made in conversations and in writings and so that the meaning is passed on.
Definitions are the means by which scientists and engineers communicate the
nature of a material to each other and to the world, through either the spoken or
the written word. Thus the definition of a material can be extremely important and
can have a profound influence on how the technical community and the public
perceive that material.
Because of the need for a thorough understanding of petroleum and the associated technologies, it is essential that the definitions and the terminology of
petroleum science and technology be given prime consideration (Speight, 1999a).
This presents a better understanding of petroleum, its constituents, and its various
fractions. Of the many forms of terminology that have been used not all have survived, but the more commonly used are illustrated here. Particularly troublesome,
and more confusing, are those terms that are applied to the more viscous materials, for example, the use of the terms bitumen and asphalt. This part of the text
attempts to alleviate much of the confusion that exists, but it must be remembered
that the terminology of petroleum is still open to personal choice and historical
usage.
Petroleum is a naturally occurring mixture of hydrocarbons, generally in a
liquid state, that may also include compounds of sulfur, nitrogen, oxygen, metals,
and other elements (ASTM D-4175, 1998; Speight, 1999a,b and references cited
therein). The composition of petroleum varies with the source (Table 1.3).
In the crude state, petroleum has minimal value, but when refined it provides
high-value liquid fuels, solvents, lubricants, and many other products (Purdy,
1957). The fuels derived from petroleum contribute approximately one-third to
one-half of the total world energy supply and are used not only for transportation
fuels (i.e., gasoline, diesel fuel, and aviation fuel, among others) but also to heat
buildings. Petroleum products have a wide variety of uses that vary from gaseous
and liquid fuels to near-solid machinery lubricants. In addition, the residue of many
refinery processes, asphalta once-maligned by-productis now a premiumvalue product for highway surfaces, roofing materials, and miscellaneous waterproofing uses.
Crude petroleum is a mixture of compounds boiling at different temperatures
that can be separated into a variety of different generic fractions by distillation.
The terminology of these fractions has been bound by utility and often bears little
relationship to composition.
The molecular boundaries of petroleum cover a wide range of boiling points
and carbon numbers of hydrocarbon compounds and other compounds containing
Table 1.3. Illustration of the Variation in Composition and
Properties of Crude Oil
> 1000 F
Alkanes
Carbon number
Figure 1.1. General boiling point-carbon number profile for petroleum.
nitrogen, oxygen, and sulfur, as well as metallic (porphyrin) constituents. However,
the actual boundaries of such a petroleum map can only be defined arbitrarily in
terms of boiling point and carbon number (Fig. 1.1). In fact, petroleum is so
diverse that materials from different sources exhibit different boundary limits, and
for this reason alone it is not surprising that petroleum has been difficult to map
(Chapter 15) in a precise manner.
Because there is a wide variation in the properties of crude petroleum, the
proportions in which the different constituents occur vary with origin (Gruse
and Stevens, 1960; Speight, 1999a). Thus some crude oils have higher proportions of the lower-boiling components and others (such as heavy oil and bitumen)
have higher proportions of higher-boiling components (asphaltic components and
residuum).
There are several other definitions that also must be included in any text on
petroleum analysis, in particular because this text also focuses on the analysis of
heavy oil and bitumen. These definitions are included because of the increased
reliance on the development of these resources and the appearance of the materials
in refineries.
Heavy oil (heavy crude oil) is more viscous than conventional crude oil and
has a lower mobility in the reservoir but can be recovered through a well from the
reservoir by the application of secondary or enhanced recovery methods.
On the other hand, tar sand is the several rock types that contain an extremely
viscous hydrocarbon that is not recoverable in its natural state by conventional oil
well production methods including currently used enhanced recovery techniques.
More descriptively, tar sand is an unconsolidated to consolidated sandstone or
porous carbonate rock impregnated with bitumen. In simple terms, an unconsolidated rock approximates the consistency of dry or moist sand, and a consolidated
rock may approximate the consistency of set concrete. Alternative names, such
as bituminous sand or (in Canada) oil sand, are gradually finding usage, with the
former name being more technically correct. The term oil sand is also used in the
same way as the term tar sand, and the terms are used interchangeably. The term
oil sand is analogous to the term oil shale. Neither material contains oil, but oil is
produced therefrom by application of thermal decomposition methods.
It is important to understand that tar sand and the bitumen contained therein
are different components of the deposit. The recovery of the bitumen, a hydrocarbonaceous material that can be converted into synthetic crude oil (Table 1.2),
depends to a large degree on the composition and construction of the sands.
It must be noted here that to be chemically correct, it must be recognized that hydrocarbon molecules only contain carbon atoms and hydrogen atoms. The molecular constituents found in tar sand bitumen also contain nitrogen, oxygen, sulfur,
and metals (particularly nickel and vanadium) chemically bound in their molecular
structures. Thus it is chemically correct to refer to bitumen as a hydrocarbonaceous
material, i.e., a term that describes a material that is composed predominantly of
carbon and hydrogen but recognizes the presence of the other atoms.
The term bitumen (also, on occasion, referred to as native asphalt and extra
heavy oil) includes a wide variety of reddish brown to black materials of semisolid,
viscous to brittle character that can exist in nature with no mineral impurity or with
mineral matter contents that exceed 50% by weight. Bitumen is frequently found
filling pores and crevices of sandstone, limestone, or argillaceous sediments, in
which case the organic and associated mineral matrix is known as rock asphalt.
On the basis of the definition of tar sand (above), bitumen is a naturally occurring
hydrocarbonaceous material that has little or no mobility under reservoir conditions
and that cannot be recovered through a well by conventional oil well production
methods including currently used enhanced recovery techniques; current methods
involve mining for bitumen recovery (Speight, 1990).
Because of the immobility of the bitumen, the permeability of the deposit is low
and passage of fluids through the deposit is prevented. Bitumen is a high-boiling
material with little, if any, material boiling below 3500C (6600F), and the boiling
range (Table 1.4) approximates the boiling range of an atmospheric residuum and
has a much lower proportion of volatile constituents than a conventional crude oil
(Table 1.5).
Synthetic crude oil is the hydrocarbon liquid that is produced from bitumen, by
a variety of processes that involve thermal decomposition. Synthetic crude oil (also
referred to as syncrude) is a marketable and transportable product that resembles
conventional crude oil. Synthetic crude oil, although it may be produced from one
of the less conventional fossil fuel sources, can be accepted into and refined by the
usual refinery system.
Table 1.4. Distillation Profile of Bitumen (Athabasca, McMurray Formation, Upper
Cretaceous, Alberta, Canada) and Properties of the Fractions
Whole Bitumen
Fraction*
Boiling Range
0_50
437-^82
437^82
Wt%
Specific API Sulfur
Cumulative Gravity Gravity Wt% (Conradson)
*Distillation at 762 mmHg and then at 40 mmHg for fractions 11-15.
Table 1.5. Distillation Profile or Crude Oil (Leduc, Woodbend, Upper Devonian,
Alberta, Canada) and Properties of the Fractions
Whole Crude Oil
Distillation loss
0-122 2.6
122-167 3.0
>572 22.6
* Distillation at 765 mmHg then at 40 mmHg for fractions 11-15.
Table 1.6. Subdivision of Fossil Fuels into Various Subgroups
Bitumen*
Asphaltite
Asphaltoid
Ozocerite (natural wax)
Asphaltenes
Carbenes1"
Carboids*
Synthetic crude oil
* Bitumen from tar sand deposits,
t Products of petroleum processing.
For the purposes of terminology, it is preferable to subdivide petroleum and
related materials into three major classes (Table 1.6):
materials that are of natural origin;
materials that are manufactured; and
materials that are integral fractions derived from the natural or manufactured
Petroleum is perhaps the most important substance consumed in modern society.
It provides not only raw materials for the ubiquitous plastics and other products
but also fuel for energy, industry, heating, and transportation. The word petroleum,
derived from the Latin petra and oleum, means literally rock oil and refers to
hydrocarbons that occur widely in the sedimentary rocks in the form of gases and
liquids.
The history of any subject is the means by which the subject is studied in the
hopes that much can be learned from the events of the past. In the current context,
the occurrence and use of petroleum, petroleum derivatives (naphtha), heavy oil,
and bitumen is not new. The use of petroleum and its derivatives was practiced
in pre-common era times and is known largely through historical use in many
of the older civilizations (Henry, 1873; Abraham, 1945; Forbes, 1958a,b, 1959,
1964; James and Thorpe, 1994). Thus the use of petroleum and the development
of related technology is not as modern a subject as we are inclined to believe. The
petroleum industry is essentially a twentieth-century industry, but to understand
the evolution of the industry, it is essential to have a brief understanding of the first
uses of petroleum.
Briefly, petroleum and bitumen have been used for millennia. For example, the
Tigris-Euphrates valley, in what is now Iraq, was inhabited as early as 4000 BC
by the people known as the Sumerians, who established one of the first great cultures of the civilized world. The Sumerians devised the cuneiform script, built the
temple-towers known as ziggurats, and developed an impressive code of law, literature, and mythology. As the culture developed, bitumen or asphalt was frequently
used in construction and in ornamental works.
Although it is possible to differentiate between the words bitumen and asphalt
in modern use (Speight, 1999a) the occurrence of these words in older texts offers
no such possibility. It is significant that the early use of bitumen was in the nature
of cement for securing or joining together various objects, and it thus seems likely
that the name itself was expressive of this application.
Early references to petroleum and its derivatives occur in the Bible, although
by the time the various books of the Bible were written, the use of petroleum and
bitumen was established. Investigations at historic sites have confirmed the use of
petroleum and bitumen in antiquity for construction, mummification, decorative
jewelry, and waterproofing as well as medicinal use (Speight, 1978, 1999a). Many
other references to bitumen occur throughout the Greek and Roman empires, and
from then to the Middle Ages early scientists (alchemists) frequently referred to the
use of bitumen. In the late fifteenth and early sixteenth centuries both Christopher
Columbus and Sir Walter Raleigh have been credited with the discovery of the
asphalt deposit on the island of Trinidad and apparently used the material to caulk
their ships. There was also an interest in the thermal product of petroleum (nafta;
naphtha) when it was discovered that this material could be used as an illuminant
and as a supplement to asphalt incendiaries in warfare.
To continue such references is beyond the scope of this book, although they do
give a flavor of the developing interest in petroleum. It is sufficient to note that
there are many other references to the occurrence and use of bitumen or petroleum
derivatives up to the beginning of the modern petroleum industry. However, what
is obvious by its absence is any reference to the analysis of the bitumen that was
used variously through history. It can only be assumed that there was a correlation
between the bitumen character and its behavior. This would be the determining
factor(s) in its use as a sealant, a binder, or as a medicine. In this sense, documented
history has not been kind to the scientist or engineer.
Thus the history of analysis of petroleum and its products can only be suggested
to have started during the second half of the nineteenth century. For example, in
1857 several aromatic hydrocarbons from Burma petroleum were identified by
the formation of the barium salts of benzenesulfonic acids followed by fractional
crystallization (de La Rue and Miller, 1857). In addition, an analytical distillation
of petroleum was carried out in the early 1870s (Silliman, 1872). Further developments of the analytical chemistry of petroleum continued throughout the century
(Mair, 1960).
It might be assumed that the history of petroleum analysis evolved as analytical
chemistry, evolved, and it is correct to ascribe to analytical chemistry a position
of primary importance because only through chemical analysis can matter (in this
context, petroleum) in its variety of forms be dealt with logically.
Thus the stimulus given to petroleum science by new analytical approaches,
either qualitative or quantitative, has been repeatedly observed. Ii is only recently
that analytical chemistry has achieved recognition in keeping with its importance
because the application of new techniques has resulted in new descriptive or theoretical knowledge.
Throughout the development of analytical chemistry, three objectivesspeed,
selectivity, and sensitivityhave been uppermost in the minds of chemists in designing new methods and improving or rejecting older methods. Ideally, and this
is very true in the petroleum industry, an analytical method is most useful when
it combines all three of these objectives. However, in practice, one or even two
may be sacrificed when the third must be given unusual emphasis. For example,
in the petroleum industry, the need to obtain results on-stream and without delay
may dictate the use of methods not particularly noted for their sensitivity. Thus the
purpose of the analysis frequently determines the choice of method.
One important aspect of petroleum analysis is the elemental composition. Liebig
and Dumas so carefully laid the foundations of elemental organic analyses around
1830 that the methods underwent essentially no changes during the rest of the century except for minor modifications involving refinements in design and heating
methods. This was particularly true in the case of carbon and hydrogen. However, in the case of nitrogen, there was a recognized need for a less intricate and
time-consuming procedure than Dumas's method. In 1840, this method still required refinement with respect to the source of carbon dioxide, the degradation
of nitrogen oxides, and the collection of nitrogen. Although these shortcomings
were eliminated during the next two decades, the procedure was still complex
and tedious. It was universally respected for reliability with all types of organic
samples; but whenever other methods could be relied on to give accurate results,
they were preferred.
Mineral matter in petroleum was, and is, generally determined by burning
off the organic matter in a muffle furnace and weighing the ash. The ash might
be further analyzed for individual elements by traditional inorganic methods. It
was of course realized that the minerals in the sample were in a form that differed from the oxides, carbonates, sulfates, phosphates, and chlorides that made up
the ash.
At the same time the concept of proximate analysis was being developed for
coal, specifically, an analytical procedure that gave the amount of fixed carbon
under controlled conditions. This led to an interest in applying the test to the
determination of the carbon residue produced by thermal treatment of petroleum.
By inference, one might assume that the carbon residue test for petroleum was
also based on the need to know the amount of volatile material produced during
cracking.
Therefore, there were continuous attempts to develop methods for petroleum
analysis from the modern inception of the industry in 1859 well into the twentieth
century. Indeed, although qualitative tests had been used since antiquity, they
were highly empirical and amounted to personal spot tests. As the result of the
blossoming interest in reagents and reactions in the seventeenth century, there has
been a continuing focus on numerous specific tests that have qualitative importance.
This led to the development of a systematic basis for group separations, but it was
not until the twentieth century that procedures became highly standardized.
The ASTM became active in developing standard tests for petroleum and
petroleum products in 1904, from which evolved the Technical Committee
D-2 on Petroleum Products and Lubricants with a scope that included almost
all petroleum products. This evolution explains the designation of many standards
for the evaluation of petroleum and petroleum products as ASTM D standards.
This large increase in the numbers of analytical methods applied to petroleum
and petroleum products is, of course, made necessary by the greater attention to
and need for reliable information concerning the composition of petroleum and its
products. This information is increasingly requested in terms of individual hydrocarbons or certainly at a minimum in terms of type such as paraffinic, naphthenic,
aromatic, olefinic, or combinations of these. However, the demand for these data
could not have been met without real advances in the art and science of separating
hydrocarbons and hydrocarbon types and the concurrent development of instrumental methods for determining physical, optical, and spectral properties with
great accuracy and precision.
These developments, together with the fruits of the American Petroleum Institute Research Projects Nos. 6, 42, 44, 45, and 60 in making available both
data on and samples of pure hydrocarbons for calibration purposes, have in effect
marked the culmination of an era for analyses dependent primarily on fractionation, a few physical properties such as boiling point and density, and chemical
reactions.
As a result of this work (Mair, 1960), it was recognized by 1925 or somewhat
earlier that the hydrocarbons in petroleum belonged to several series, including
normal paraffins, branched paraffins, cycloparaffins, and aromatics. For the cyclic
paraffins, the presence of both five- and six-membered ring compounds was established. There was, however, at that time, no reasonably complete analysis of
even the lower-boiling part of the gasoline fraction of any crude petroleum, and
the manner in which the content of the individual constituents varied from crude
to crude was virtually unknown.
During this time, the determination of functional groups, such as carboxyl, ester,
unsaturated bonds, hydroxyl, and methoxyl, took on importance in connection with
the establishment of the constitution of new organic compounds.
Perhaps the most common functional group is the carboxyl or organic acid
group. When this group was present, titration with standard bases was the obvious
method, and this procedure was commonly used. When a single acid of known
identity was present, the procedure permitted direct analysis and also aided identification of pure acids whose identity was unknown, because the neutralization
equivalent provided a guide to the molecular weight. The major drawback in the
titration of organic acids was the fact that most such acids are weak and can only
be titrated accurately by use of the correct indicator. A similar approach could be
used with esters, where a carboxyl group is formed on hydrolysis.
Unsaturation was commonly detected by the decolorizing action of a compound
on permanganate or bromine solutions. The ability of the double bond to absorb
halogen was made the basis of a quantitative procedure.
The presence of hydroxyl groups was best determined by acetylation, followed
by saponification of the ester, separation of the acetic acid by steam distillation,
and titration.
Valuable as though they were, the chemical methods used in the early work
on the composition of petroleum have generally been replaced by more modern
methods. More recent progress has depended in part on the development of improved physical fractionating processes and in part on the development of new
spectrographic methods of recognition. For distillation, laboratory columns of
new design containing up to 200 or more theoretical stages of separation have become available. Such columns are capable of giving a fairly complete separation
of hydrocarbons boiling less than 2 C apart. Improved procedures for azeotropic
distillation have been developed. Spinning band columns and simulated distillation techniques now offer more information than was believed possible using the
methods available in the middle decades of the twentieth century.
Adsorption methods have been developed for separating aromatic hydrocarbons
quantitatively from paraffins and cycloparaffins; the same procedures will break
down aromatic mixtures into mononuclear, dinuclear, and trinuclear portions. In
certain cases, adsorption may be used to separate isomers, particularly aromatic
isomers. An extension of the method of partition chromatography, which makes
use of certain fluorochemicals as the mobile phase, is also effective for separating
paraffins (particularly branched paraffins) from cycloparaffins. The same classes
can also be separated using a partition chromatographic method with liquid displacement. A crystallization procedure for sorting out normal and branched paraffins and cyclic and aromatic hydrocarbons has come into wide use. This process
depends on the formation of solid molecular compounds of the normal paraffins
with urea, the separation of these compounds from the remaining liquid, and the
regeneration of the normal paraffins. Fractionation by thermal diffusion has been
applied to petroleum fractions, particularly in the higher-boiling gas oil and lubricating oil ranges. The separation in this case appears to depend, in part at least, on
the shapes of the component molecules. Where aromatics are absent, the separation is approximately according to cycloparaffin ring content and resembles that
obtained with solvent extraction. Countercurrent solvent extraction has also been
used principally as a means of separating the higher-boiling fractions according to
hydrocarbon type.
Within recent years, molecular spectroscopy has been applied successfully to
determining quantitatively the percentage of each hydrocarbon in mixtures. In
some cases, spectroscopic methods are used to determine hydrocarbon types. For
example, ultraviolet spectroscopy may determine aromatics and mass spectroscopy
the content of paraffins, cycloparaffins, oleflns, and aromatics in straight-run or
cracked fractions in the gasoline range. Even for fractions from lubricating oil distillates (preferably separated as far as practical by other methods) high-temperature
mass spectrometry gives useful information concerning the amounts of certain
types of hydrocarbons and sulfur compounds. Infrared spectroscopy has also been
applied in this molecular weight range to give values of, for example, the content of
methyl groups as well as of methylene groups in long chains and in cycloparaffin
rings.
Petroleum products are used for hundreds of different purposes with widely differing requirements; the criteria for quality are, therefore, numerous and complex.
It is the purpose of this book to identify these criteria, to explain how they are met
by suitable refining, and to describe how the quality is controlled by appropriate
analysis and testing.
In summary, the nineteenth century was a period of consolidation in the field
of chemical analysis from which petroleum analysis was born and benefited. This
was important because it led to an understanding of the relationships of the various constituents for petroleum and hence to real and potential utility of this
resource.
Instrumental methods were recognized as being important in analytical chemistry as the nineteenth century drew to a close. There were the awakenings of the
potential role that instrumentation would play in process control.
MODERN PERSPECTIVES
The modern petroleum industry began in 1859 with the discovery and subsequent
commercialization of petroleum in Pennsylvania (Bell, 1945). During the 6000
years of its use, the importance of petroleum has progressed from the relatively simple use of asphalt from Mesopotamian seepage sites to the present-day refining operations that yield a wide variety of products and petrochemicals (Speight, 1999a).
However, what is more pertinent to the industry is that throughout the millennia
in which petroleum has been known and used, it is only in the twentieth century
that attempts have been made to formulate and standardize petroleum analysis.
As the twentieth century aged, there was increased emphasis and reliance on
instrumental approaches to petroleum analysis. In particular, spectroscopic methods have risen to a level of importance that is perhaps the dream of those who first
applied such methodology to petroleum analysis. Potentiometric titration methods
have also evolved, and the procedures have found favor in the identification of
functional types in petroleum and its fractions.
Spectrophotometers came into widespread use beginning around 1940. These
instruments acquired simplicity of use that led to acquisitions by all laboratories
involved in petroleum analysis.
Ultraviolet absorption, because of its use in studies of the structure of organic
compounds, was particularly useful especially because the aromatic ring systems
have a characteristic absorption that is used as a diagnostic value.
Perhaps the greatest advance in the use of instrumental techniques has been in
the application of infrared spectroscopy to petroleum analysis. Instruments were
available before 1920, but the real progress in infrared work occurred after 1940,
when it became possible to relate certain bands in the spectra of petroleum and
its derivatives with specific groups containing oxygen and nitrogen as well as the
various carbon-carbon bonds.
The mass spectrometer was used for two decades primarily as a research instrument before it began to be considered seriously as an analytical tool. During the
1940s the petroleum industry began to use the mass spectrometer in connection
with the analysis of hydrocarbon mixtures. Although the quantitative interpretation
of such mass spectrograms initially posed a formidable calculation problem, this
instrument has proved to be highly successful in the petroleum industry, especially
with the use of computerized techniques.
Emission spectroscopy has developed more rapidly than any other spectroscopic fields. Indeed, as early as 1920, it had reached a high level of usefulness.
Practical procedures have been developed for the identification of metals and
metalloids. The technique is sensitive to a few parts per million and thus is very
useful for the identification of trace contaminants, as is often required in petroleum
analysis.
And finally, in this note about spectroscopic methods, mention must be made
of the use of nuclear magnetic resonance spectroscopy in petroleum analysis. The
identification of hydrogen types (proton magnetic resonance) and carbon types
(carbon magnetic resonance) must not pass unnoticed!
Analytical chemists usually classify chromatography as an instrumental method,
but it is noted that it differs quite distinctly from the methods described above in
objective and principle. Utilized for the most part in the separation of complex
mixtures, it has only limited applicability to quantitative measurements where the
complexity of petroleum is obvious.
Chemists have long known that many substances are adsorbed from gases and
solutions onto the surface of solid materials. In fact, early experiments on the
adsorption of petroleum constituents on adsorbents were reported at the First
International Petroleum Congress held in Paris in 1900. Thus the importance of
column adsorption was recognized in petroleum science as well as in chemical
analysis in general. The method was soon put to work by petroleum chemists, as
shown by descriptions of studies utilizing a column with ports at various levels
from which samples might be withdrawn and studied to observe changes in boiling
point, density, and viscosity.
Ion exchange materials, long known in the form of naturally occurring
silicates, were used in the earliest types of regenerative water softeners. However, since 1930 chemists have had marked success in producing synthetic resins
with ion exchange properties. Such resins are often used in ion exchange columns,
which are highly effective in bringing about specific separations of petroleum
constituents.
Gas chromatography, or vapor-phase chromatography, found ready applications in petroleum analysis since its introduction in 1952. The identification
of the individual constituents of petroleum fractions was hailed worldwide. A
last, some sense could be made of the composition of the complex system called
petroleum! This technique is still extremely valuable in the analysis of hydrocarbon mixtures of high volatility and has become an important analytical tool in
the petroleum industry. With the development of high-temperature columns the
technique has been extended to mixtures of low volatility, such as gas oils and
some residua.
There are many other analytical techniques that could be added to this catalogue
of historical reminiscences, but that is not the object of this book.
The foregoing section is included to introduce the reader to the historical aspects of petroleum analysis and to show the glimmerings of how it evolved over
the twentieth century. Indeed, despite the historical use of petroleum and related
materials, the petroleum industry is a modern industry, having come into being in
1859. From these comparatively recent beginnings, petroleum analysis has arisen
as a dedicated science.
ANALYSIS AND SPECIFICATIONS
Petroleum exhibits wide variations in composition and properties, and these occur
not only in petroleum from different fields but also in oils taken from different
production depths in the same well. Even though a wealth of data is available on
petroleum from oilfields throughout the world, no entirely satisfactory system for
classifying these oils has been developed.
and viscosity have been used to describe oils. However, because of the molecular complexity of petroleum, heavy oil, and bitumen, there is more to analysis,
identification, and characterization than these four properties would indicate.
Because of the differences in petroleum composition, the importance of the
correct sampling of crude oil that contains light hydrocarbons cannot be overestimated. Properties such as specific gravity, distillation profile, vapor pressure,
hydrogen sulfide content, and octane number of gasoline are affected by the light
hydrocarbon content so that suitable cooling or pressure sampling methods must
be used and care must be taken during the subsequent handling of the oil to avoid
the loss of any volatile constituents. In addition, adequate records of the circumstances and conditions during sampling must be made. For example, sampling
from oilfield separators, the temperatures and pressures of the separation plant,
and the atmospheric temperature should be noted.
Elemental analyses of petroleum show that it contains mainly carbon and hydrogen. Nitrogen, oxygen, and sulfur (heteroelements) are present in smaller amounts
and also trace elements such as vanadium, nickel, etc. Of the heteroelements, sulfur
is the most important. The mixture of hydrocarbons is highly complex. Paraffinic,
naphthenic, and aromatic structures can occur in the same molecule, and the complexity increases with boiling range. The attempted classification of crude oils in
terms of these three main structural types has proved inadequate.
The value of a particular crude to a refiner depends on its quality and whether
he/she can economically obtain a satisfactory product pattern that matches market
demand (market pull). In the main, the refiner is not concerned with the actual
chemical nature of the material but with methods of analysis that would provide
information sufficient to assess the potential quality of the oil, to supply preliminary engineering data, and also to indicate whether any difficulties might arise
in handling, refining, or transporting petroleum or its products. Such information
may be obtained in one of two ways:
1. preliminary assay-inspection data; or
2. a full assay involving the preparation of a true boiling point curve and the
analysis of fractions and product blends throughout the full range of the
crude oil.
The preliminary assay provides general data on the oil and is based on
simple tests such as distillation range, water content, specific gravity, and sulfur
content that enable desirable or undesirable features to be noted. This form of
assay requires only a small quantity of sample and is therefore particularly useful for the analysis of oilfield samples produced from cores, drill stem tests, or
seepages.
The tests in the preliminary assay are relatively simple and can be completed
in a short time and generally on a routine basis. This assay gives a useful general
picture of the quality of a crude, but it does not cover the work necessary to
provide adequate data, for example, for the design of refinery equipment, nor does
it produce a sufficient quantity of the various products from the crude so that they
can be examined for quality.
Owing to the wide variation in the types of crude oil and to the fact that most
companies have evolved their own assay methods, it has proved difficult to devise
a rigid procedure to be followed in all cases, although there are considerable
advantages to be gained if this were possible.
A full assay of petroleum is based on a true boiling point distillation of the
crude, and sufficient data are obtained to assess the yields and properties of the
straight-run products, covering light hydrocarbons, light, middle and heavy distillate, lubricants, residual fuel oil, and residuum.
Petroleum analysis involves not only determining the composition of the material under investigations but, more appropriately, determining the suitability of
the petroleum for refining or the product for use. In this sense, the end product
of petroleum analysis or (testing) is a series of data that allow the investigator to
specify the character and quality of the material under investigation. Thus a series
of specifications are determined for petroleum and its products.
A feedstock or product specification is therefore defined as data that give adequate control of feedstock behavior in a refinery or product quality. Thus a specification offers the luxury of predictability of feedstock behavior in a refinery or of
product quality (therefore, product behavior) relative to market demand.
Ultimately, feedstock behavior and/or product quality is judged by an assessment of performance. And it is performance that is the ultimate criterion of quality.
It is therefore necessary to determine those properties, the values of which can be
established precisely and relatively simply by inspection tests in a control laboratory, that correlate closely with the important performance properties.
Sometimes the inspection tests attempt to measure these properties, for example,
the carbon residue of a feedstock that is an approximation of the amount of the
thermal coke that will be formed during refining or a research octane number test
that was devised to measure performance of motor fuel. In other cases, the behavior
must be determined indirectly from a series of test results.
Each test applied to petroleum and its products may have been justified by a
high correlation with some important performance property, and it must also be
recognized that many of the data from different tests are interrelated. The properties
measured by many of the frequently used tests are far from independent of each
other, and thus (interesting as this may be) there can be a considerable redundancy
of information. For example, vapor pressure is closely related to front-end recovery
in a distillation test, and flash point also bears some relationship to both these
properties. Other examples are also evident and are presented throughout this text.
For the moment, another well-used example is the relationship of density (specific
gravity or API gravity) to viscosity. It is up to the scientist and engineers involved
to determine the tests that are necessary and the tests that are redundant (often
defined in terms of cost).
There are many instances in which interrelationships of the specification data
enable properties to be predicted from the measured properties with as good precision as can be obtained by a single test. It would be possible to examine in this way
the relationships between all the specified properties of a product and to establish
certain key properties from which the remainder could be predicted, but this would
be a tedious task.
An alternative approach to that of picking out the essential tests in a specification
using regression analysis is to examine at the specification as a whole and extract
the essential features. This is termed principal components analysis.
Principal components analysis examines a set of data as points in multidimensional space (n-dimensional, corresponding to n original tests) and finds first the
direction that accounts for the biggest variability in the data (first principal component). The process is repeated until n principal components are evaluated, but
it must be determined which are of practical importance because some principal
components may be due to experimental error. The number of significant principal
components shows the number of independent properties being measured by the
tests considered.
The number of independent properties having been established, there exists a
natural basis for making the specification more efficient. In the long term, it might
be possible to obtain new tests of a fundamental nature to replace existing tests.
In the short term, selecting the best of the existing tests to define product quality
will be beneficial.
It is in the interests of the refiner, the marketer, and the consumer to ensure
that the specifications are efficient. When a refiner is manufacturing a product in
compliance with a number of different marketing specifications, the manufacturing
specification can be drafted in such a way as to ensure that these are all satisfied
in the most efficient manner. In the case of particular marketing specifications,
however, very little improvement can be achieved without the full cooperation of
supplier and consumer.
Because of the difficulty of devising inspection tests that correlate sufficiently
highly with the important performance properties of products, it is possible that
there will be an increasing tendency for product quality to be specified in terms
of suitably chosen indices that are not measured directly in the laboratory but are
calculated from two or more measured properties.
Finally, the analytical methods used to describe conventional petroleum must be
modified for the characterization of heavy oil and bitumen in the same way that tests
for conventional petroleum have been modified and/or replaced by newer, more
relevant test methods. For example, what might appear to be a test of minimal
value for conventional petroleum might afford invaluable data for determining the
behavior of heavy oil or bitumen or the potential product slates from each.
In fact, it is for the reason of behavior differences that research into text methods
for heavy oil and bitumen is continuing (Wallace, 1988; Speight, 1999a,b). Clearly,
for maximum efficiency the tests that are specified for any feedstock or product
should be as independent of each other as possible. In fact, the efficiency of a
specification should be judged by the extent to which the tests specified will:
predict (control) feedstock behavior;
predict (control) product quality;
measure independent properties;
measure these properties with adequate precision; and
offer rapid response to refinery and laboratory demands.
Petroleum analysis has been greatly augmented in recent years by applying a
wide variety of instrumental techniques to studies of the hydrocarbon composition of crude oils and their products (Chapter 10). Before this, hydrocarbon type
analyses (percent paraffins, naphthenes, olefins, and aromatics) were derived from
correlations based on physical data. The advent of instrumental techniques led to
two major developments:
1. individual component analysis; and
2. an extension to and more detailed subdivision of the various compound types
that occur in the higher-boiling ranges of petroleum distillates.
Of these instrumental techniques, gas-liquid chromatography and mass spectrometry are the most important in providing the hydrocarbon composition data
in crude oil assay work. By gas chromatographic analysis, it is now possible to
determine routinely the individual methane (CH4) to heptane (C7Hi6) hydrocarbons and the individual aromatics that boil below 165C (3300F) and also obtain
a complete normal paraffin distribution up to C50. In addition, by using a microcoulometric detector specific to sulfur, the sulfur compound distribution can be
obtained throughout the distillate range. Gas chromatographic analysis can also
be used to provide simulated true boiling point (TBP) curves, and developments in
preparative scale gas-liquid chromatography have made possible the preparation
of fractions in quantities sufficient not only for extensive spectrometric analyses
but also for the normal inspection type tests to be undertaken.
Mass spectrometry offers a very rapid method for obtaining hydrocarbon type
analyses on a wide range of fractions up to and including heavy gas oils. The information obtained on a routine basis subdivides the hydrocarbons into the following
groups. The technique can also be used in conjunction with separation procedures
such as gas-liquid chromatography, molecular distillation, thermal diffusion, or
selective adsorption to provide more detailed analyses where necessary, even on
fractions in the lubricating oil range.
From such knowledge of the chemical composition of petroleum distillates obtained using these instrumental techniques, and the information from the standard
assays, the refiner is better able to predict and control crude oil operations and to
assess the quality and performance of his/her products.
Thus petroleum analysis is a complex subject involving a variety of techniques,
some of which are mentioned above. However, no single technique should supersede the other. Petroleum analysis is a complex discipline that needs a multidimensional approach, and an explanation of the data that are obtained needs adequate
interpretation.
Understanding the methods and the data is the raison d'etre of this book.
Abraham, H. 1945. Asphalts and Allied Substances. Van Nostrand, New York.
ASTM D-4175. 1998. Standard Terminology Relating to Petroleum, Petroleum Products,
and Lubricants. Annual Book of Standards. American Society for Testing and Materials.
West Conshohocken, PA. Vol. 05.02.
Bell, H. S. 1945. American Petroleum Refining, Van Nostrand, New York.
De La Rue, P., and Miller, E. 1857. Proc. R. Soc. (Lond.) 8: 221.
Forbes, R. J. 1958a. A History of Technology, Oxford University Press, Oxford, England.
Forbes, R. J. 1958b. Studies in Early Petroleum Chemistry. E. J. Brill, Leiden, The
Netherlands.
Forbes, R. J. 1959. More Studies in Early Petroleum Chemistry. E. J. Brill, Leiden, The
Forbes, R. J. 1964. Studies in Ancient Technology. E. J. Brill, Leiden, The Netherlands.
Gruse, W. A., and Stevens, D. R. 1960. The Chemical Technology of Petroleum. McGrawHill, New York.
Henry, J. T. 1873. The Early and Later History of Petroleum. VoIs. I and II. APRP Co.,
James, P., and Thorpe, N. 1994. Ancient Inventions. Ballantine Books, New York.
Mair, B. J. 1960. In: The Chemical Technology of Petroleum. W. A. Gruse and D. R. Stevens
(Editors). McGraw-Hill, New York. Chapter 2.
Purdy, G. A. (1957). Petroleum: Prehistoric to Petrochemicals. Copp Clark Publishing,
Toronto, Canada.
Silliman, B. 1872.Am. Chemist!: 18.
Speight, J. G. 1978. Personal observations at the remains of the cities of Babylon, Nineveh,
Calah, and Ur.
Speight, J. G. 1990. In: Fuel Science and Technology Handbook. J. G. Speight (Editor).
Marcel Dekker, New York, Chapters 12-16.
Speight, J. G. 1999a. The Chemistry and Technology of Petroleum. 3rd Edition. Marcel
Dekker, New York.
Speight, J. G. 1999b. The Desulfurization of Heavy Oils and Residua. 2nd Edition. Marcel
Speight, J. G., and Moschopedis, S. E. 1979. In: The Future of Heavy Crude Oil and Tar
Sands. F. R. Meyer and CT. Steele (Editors). McGraw-Hill, New York, p. 603.
Wallace, D. (Editor). 1988. A Review of Analytical Methods for Bitumens and Heavy Oils.
Alberta Oil Sands Technology and Research Authority, Edmonton, AB, Canada.
Petroleum is not a uniform material. In fact, its chemical and physical (fractional)
composition can vary not only with the location and age of the oil field but also
with the depth of the individual well (page 29). Indeed, two adjacent wells may
produce petroleum with markedly different characteristics. On a molecular basis, petroleum is a complex mixture of hydrocarbons with small amounts of organic compounds containing sulfur, oxygen, and nitrogen, as well as compounds
containing metallic constituents, particularly vanadium, nickel, iron, and copper.
The hydrocarbon content may be as high as 97% by weight in a lighter paraffinic
crude oil or about 50% by weight in heavy crude oil and less than 30% by weight
Nevertheless, crude oil (usually heavy crude oil) with as little as 50% by weight
hydrocarbon components can still be classified with some degree of accuracy as
a mixture of naturally occurring hydrocarbons. It will retain most of the essential
characteristics of the hydrocarbons that will be reflected in the crude oil properties
even though the nonhydrocarbon portion of the crude may actually consist of
molecules containing one or perhaps two atoms of elements other than carbon
and hydrogen (Gruse and Stevens, 1960; Speight, 1999, 2000 and references cited
therein).
With the necessity of processing heavy oil, residua, and bitumen to obtain more
gasoline and other liquid fuels, has come the recognition that knowledge of the
constituents of these higher-boiling feedstocks is also of some importance to follow
process chemistry and physics (Speight, 1999, 2000). Indeed, problems (such as
phase separation and coking) encountered in processing the heavier feedstocks can
be explained using this knowledge. Refining these materials is not just a matter
of applying know-how derived from refining conventional crude oils but requires
knowledge of the chemical structure and chemical behavior of these more complex
constituents as they influence refining behavior.
Bitumen is extremely complex, and very little direct information can be obtained by distillation. It is not possible to isolate and identify its constituents
using analytical techniques that rely on volatility. Other methods of identifying the chemical constituents must be employed, and these include a myriad of
fractionation methods (Chapter 9) as well as methods designed to draw inferences
about the hydrocarbon skeletal structures and the nature of the heteroatomic functions (Chapter 8).
However, before any work is carried out in the laboratory, petroleum and
petroleum products must go through a series of cleaning processes before shipping.
Such processes might be the removal of dirt by membrane filters (ASTM D-2276,
IP 216) or other processes that are specific to the nature of the crude oil as well as
the recovery method used in the field. In the membrane filtration test, the dirt is
retained by filtration of a sample through a cellulose membrane and is expressed
as a weight per unit volume of the sample. Such a process may be applicable to
field work, although desalting and dewatering processes are more amenable to
field operations (see, for example, Speight, 1999).
Although more detail is given elsewhere (Chapter 9) on compositional studies,
it is the purpose of this chapter to introduce the analytical chemist to the general
chemical composition of petroleum, heavy oil, and bitumen, thereby setting the
stage for what is to follow. In fact, as a result of this chapter the analyst should
have some understanding of the nature of the beast!
2.2. ULTIMATE (ELEMENTAL) COMPOSITION
At one time, and perhaps even now depending on the crude oil, API gravity,
sulfur content, and viscosity were the predominant data used to determine the
quality of petroleum (Nelson, 1958; Gruse and Stevens, 1960; Speight, 1999,
2000 and references cited therein). As the quality of crude oils changed and the
incorporation of hydroprocesses (hydrotreating and hydrocracking) into refinery
scenarios became necessary to upgrade crude oils to products, the hydrogen content
allowed refiners to estimate the amount of hydrogen need to convert crude oil to, for
example, gasoline and diesel fuel. Thus, elemental analytical data are an important
first test for petroleum. The atomic hydrogen-to-carbon ratio as well as the amount
of sulfur (removal by conversion to H2S) and nitrogen (removal by conversion
to NH3) became important data points. The amount of oxygen received lesser
attention but is now also considered an important factor because of the potential
for problems, such as corrosion of pipes, equipment, and reactors, caused by acidic
compounds and their degradation products. Halogens from the associated brine
were also effective corrosive agents and were detected by analytical techniques.
At the same time, the amount of metals in feedstocks became an important issue
because of catalyst degradation (Wojciechowski and Corma, 1986; Peterson and
Bell, 1987; Gray, 1994).
Metal contents on the order of less than 100 ppm may seem insignificant to the
general observer. However, when one considers that continuous operations and recycle operations can soon cause the metals on the catalyst to exceed 1000 ppm, leading to serious loss of catalyst activity, the issue becomes critical (Wojciechowski
and Corma, 1986; Peterson and Bell, 1987; Gray, 1994). Indeed, removal of sulfur
and nitrogen as their respective hydrogen analogs did not completely eliminate
their effect because both of the hydrogen analogs can result in catalyst deterioration and frequent replacement. The economics of catalyst production and purchase
cannot tolerate frequent replenishment.
Therefore, as the refining industry of the twentieth century progressed and
matured to include heavy feedstocks such as heavy oil and bitumen, the need for
complete elemental analysis became obvious, indeed, conventional. Crude oil was
not immune from such effects as nitrogen and metals can cause, even though the
amounts of these materials in the feedstock were minimal. Concentration of sulfur
compounds, nitrogen compounds, and metals in the residua (Speight, 2000) and
the need to process the residua to liquid fuels (instead of the usual asphalt) added
extra impetus to the need for complete analytical data.
Thus the complete elemental analysis of any feedstock became a necessary
first step in determining the quality of the crude oil and the general behavior of its
constituents. From the available data, it appears that the proportions of the elements
in petroleum vary over fairly narrow limits (Speight, 1999, 2000 and references
cited therein):
Carbon, 83.0-87.0%
Hydrogen, 10.0-14.0%
Nitrogen, 0.1-2.0%
Oxygen, 0.05-1.5%
Sulfur, 0.05-6.0%
Metals (Ni and V), <1000 ppm
despite the wide variation in physical properties from the lighter, more mobile
crude oils at one extreme to the heavier asphaltic crude oils at the other extreme
(see also Charbonnier et al., 1969; Draper et al., 1977). Indeed, when the many
localized or regional variations in maturation conditions are assessed, it is perhaps
surprising that the ultimate compositions are so similar. Perhaps this observation,
more than any other observation, is indicative of the similarity in nature of the
precursors from one site to another.
Thus it is not possible to classify petroleum because of the narrow range of
carbon and hydrogen content in a manner analogous to the way in which coal is
classified (Speight, 1994a). Other methods for petroleum classification must be
sought, but these methods still require elemental analysis as well as the potential
for producing hydrocarbon fuels.
The elemental analysis of tar sand bitumen has also been widely reported (Camp,
1976; Bunger et al., 1979; Meyer and Steele, 1981, Speight, 1999), but the data
suffer from the disadvantages of being too sparsely scattered, and in many cases
identification of the source is too general (e.g., Athabasca tar sand, which covers
several deposits) and is often not site specific. In addition, the analysis is quoted
for bitumen that has been separated from the associated sand that may have been
obtained by any one of several procedures and may therefore not be representative
of the total bitumen on the sand. However, recent efforts have focused on a program
to produce sound, reproducible data from samples for which the origin is carefully
identified (Wallace et al., 1988). It is to be hoped that this program will continue,
as it will provide a valuable database for tar sand and bitumen characterization.
Like conventional petroleum, from the data that are available, the elemental
composition of tar sand bitumen is generally constant and falls into a narrow range
(Speight, 1999, 2000 and references cited therein):
Carbon, 83.5 1.0%
Hydrogen, 10.5 0.5%
Nitrogen, 0.5 0.2%
Oxygen, 1.0 0.5%
Sulfur, 5.0 0.5%
Metals (Ni and V), >1000 ppm
The major exception to these narrow limits is the oxygen content of bitumen,
which can vary from as little as 0.2% to as high as 4.5%. This is not surprising
because when oxygen is estimated by difference the analysis is subject to the
accumulation of all of the errors in the other elemental data. In addition, bitumen
is susceptible to aerial oxygen and the oxygen content is dependent on the sample
history. More specifically, because of the amount of work done on this resource,
the ultimate composition of the Alberta bitumen does not appear to be influenced
by the proportion of bitumen in the oil sand or by the particle size of the oil sand
minerals.
As already noted for the formation of protopetroleum (Chapter 1) and the subsequent maturation processes, when the many localized or regional variations in
maturation conditions are assessed (Speight, 1999), it is perhaps surprising that
the ultimate composition of one bitumen is similar to that of a different bitumen
from another location.
Several generalities can be noted from the ultimate composition that might be
used to give general indications of how the material might behave during processing
(AOSTRA, 1984; Wallace, 1988). For example, the atomic hydrogen-carbon ratio
is generally related to bitumen viscosity insofar as trends can be shown graphically
and hence can be an indicator of the required supplementary heat energy for thermal
extraction processes. The hydrogen-carbon atomic ratio may also be shown to bear
a relationship to the API gravity and to the pour point. However, these trends are
not too specific and may, because of the scarcity of data, be only fortuitous.
There is a relationship of pour point to API gravity for specific families of heavy
oil and bitumen that allows prediction of oil mobility or immobility in the reservoir
(Chapter 5). However, it is certain that the atomic hydrogen-carbon ratio is related
to the hydrogen requirements during processing. The higher the hydrogen-carbon
ratio of bitumen, the higher is its value as refinery feedstock because of the lower
hydrogen requirements.
The nitrogen content of petroleum and heavy oil is usually less than 1.0%
by weight and often less than 0.5% by weight, but the nitrogen content of tar
sand bitumen can be as high as 1.3% by weight. The nitrogen complicates the
refining process by poisoning the catalysts used (Wojciechowski and Corma, 1986;
Peterson and Bell, 1987; Gray, 1994). Elements related to nitrogen content are
sulfur content, hydrogen content, hydrogen-carbon ratio, and distillation profile.
The occurrence of sulfur in petroleum, heavy oil, and bitumen as organic or
elemental sulfur or in produced gas as compounds with oxygen and hydrogen is
an expensive nuisance and therefore, like the nitrogen content, must be known
accurately. The sulfur must be removed from the bitumen at some point in the
upgrading and refining process.
The chemical composition of the volatile fractions of petroleum has been covered
in several texts (Speight, 1999 and references cited therein). However, the chemical composition of the heavier feedstocks is, despite the large volume of work
performed in this area, largely speculative. In fact, the precise chemical composition of petroleum can vary with the location and age of the field in addition to
any variations that occur with the depth of the individual well. Two adjacent wells
may even produce petroleum with very different characteristics. However, general
deductions about the nature of the chemical constituents can be made.
In very general terms (and as observed from elemental analyses), petroleum,
heavy oil, bitumen, and residua are molecular mixtures of: (a) hydrocarbons,
(b) nitrogen compounds, (c) oxygen compounds, (d) sulfur compounds, and
(e) metallic constituents. However, this general definition is not adequate to describe the composition of petroleum et al. as it relates to the behavior of these
feedstocks. Indeed, the consideration of the atomic hydrogen-carbon ratio, sulfur
content, and API gravity are no longer sufficiently adequate to the task of determining refining behavior.
Feedstock behavior during refining is better addressed through consideration
of the molecular make-up of the feedstock (perhaps, by analogy, just as genetic make-up dictates human behavior). The occurrence of amphoteric species
(i.e., compounds having a mixed acid/base nature) is not addressed, nor is the
phenomenon of molecular size or the occurrence of specific functional types
(ASTM F-1186) that can play a major role in the interactions between the constituents of a feedstock. All of these items are important in determining feedstock
behavior during refining operations.
The hydrocarbon content of petroleum may be as high as 97% by weight (for
example, in the lighter parafflnic crude oils). It is, nevertheless, the nonhydrocarbon (sulfur, oxygen, nitrogen, and metal) constituents that play a large part
in determining the processability of the crude oil (Rossini et al., 1953; Brooks
et al., 1954; Lochte and Littmann, 1955; Schwartz and Brasseaux, 1958; Brandenburg and Latham, 1968; Rail et al., 1972). But there is more to the composition of petroleum than the hydrocarbon content. The inclusion of organic
compounds of sulfur, nitrogen, and oxygen serves only to present crude oils as
even more complex mixtures, and the appearance of appreciable amounts of these
nonhydrocarbon compounds causes some concern in the refining of crude oils.
Even though the concentration of nonhydrocarbon constituents (i.e., those organic
compounds containing one or more sulfur, oxygen, or nitrogen atoms) in certain
fractions may be quite small, they tend to concentrate in the higher-boiling fractions of petroleum. Indeed, their influence on the processability of the petroleum
is important irrespective of their molecular size and the fraction in which they
The presence of traces of nonhydrocarbon compounds can impart objectionable characteristics to finished products, leading to discoloration and/or lack of
stability during storage. On the other hand, catalyst poisoning and corrosion are
the most noticeable effects during refining sequences when these compounds are
present (Wojciechowski and Corma, 1986; Peterson and Bell, 1987; Gray, 1994).
It is therefore not surprising that considerable attention must be given to the nonhydrocarbon constituents of petroleum, because the trend in the refining industry,
of late, has been to process more heavy crude oil as well as residua that contain
substantial proportions of these nonhydrocarbon materials (Gray, 1994; Speight,
An understanding of the chemical types (or composition) of any feedstock can
lead to an understanding of the chemical aspects of processing the feedstock.
Processability is not only a matter of knowing the elemental composition of a
feedstock; it is also a matter of understanding the bulk properties as they relate
to the chemical or physical composition of the material. For example, it is difficult to understand, a priori, the process chemistry of various feedstocks from the
elemental composition alone. From such data, it might be surmised that the major difference between a heavy crude oil and a more conventional material is the
hydrogen-carbon atomic ratio alone. This property indicates that a heavy crude oil
(having a lower hydrogen-carbon atomic ratio and being more aromatic in character) would require more hydrogen for upgrading to liquid fuels. This is, indeed,
true but much more information is necessary to understand the processability of
the feedstock.
Hydrocarbon Components
The study of the individual hydrocarbon constituents in petroleum began in the
1850s when alkylbenzenes were reported in a petroleum from Burma. Later,
methylcyclopentane was isolated from a Caucasian petroleum, followed by the
isolation of paraffin hydrocarbons from various petroleum fractions. Distillation
techniques (Chapter 5) were also employed in some of this early work, and the
separation of cyclohexane by crystallization of a distillate fraction into which it
had been concentrated is an example of what could be accomplished at that early
Nevertheless, the isolation of pure compounds from petroleum is an exceedingly
difficult task, even though specific tests are available for the detection of hydrocarbons in petroleum (ASTM, 1998). Hydrocarbon constituents in lower-boiling
fractions can be detected using methods based on, for example, gas chromatography (ASTM D-2360, ASTM D-2597, ASTM D-2600, ASTM D-4626, ASTM D5134) or by mass spectrometry (ASTM D-2425, ASTM D-2786, ASTM D-2789)
(Chapter 4), but the overwhelming complexity of the hydrocarbon constituents of
the higher-molecular-weight fractions as well as the presence of compounds of
sulfur, oxygen, and nitrogen are the main causes for the difficulties encountered.
It is difficult on the basis of the data obtained from synthesized hydrocarbons to
determine the identity or even the similarity of the synthetic hydrocarbons to those
that constitute many of the higher-boiling fractions of petroleum. Nevertheless,
it has been well established that the hydrocarbon components of petroleum are
composed of paraffinic, naphthenic, and aromatic groups. Olefinic groups are not
usually found in crude oils but can be determined (ASTM D-1159; ASTM D-1319;
ASTM E-234), and acetylenic hydrocarbons are very rare indeed. It is therefore
convenient to divide the hydrocarbon components of petroleum into the following
three classes:
1. Paraffins, which are saturated hydrocarbons with straight or branched
chains, but without any ring structure.
2. Naphthenes, which are saturated hydrocarbons containing one or more rings,
each of which may have one or more paraffinic side chains (more correctly
known as alicyclic hydrocarbons).
3. Aromatics, which are hydrocarbons containing one or more aromatic nuclei,
such as benzene, naphthalene, and phenanthrene ring systems, which may
be linked up with (substituted) naphthene rings and/or paraffinic side chains.
The general changes in the composition of petroleum fractions with boiling
point or range are significant. However, most of the published work has focused on
particular boiling fractions (for example, the fraction boiling up to vacuum residua)
of petroleum composition, and an all-encompassing expression of variation of
petroleum composition in terms of its variation with both boiling point and crude
origin is only now starting to become available (Altgelt and Boduszynski, 1994;
Speight, 1999).
It is the goal of this chapter to present a general picture of the constituents of
petroleum and the manner in which the chemical types vary with boiling point.
2.3.1.1. Paraffin Hydrocarbons
The proportion of paraffins in crude oils varies with the type of crude, but within
any one crude oil, the proportion of paraffinic hydrocarbons usually decreases
with increasing molecular weight or boiling point (Fig. 2.1). In the gasoline range,
for instance, paraffin contents as high as 80% have been noted, whereas in the
lubricating oil range a 30% paraffin content is exceptionally high. In fact, many
oils yield lubricating fractions that are totally devoid of paraffins. It is now known
that such trends of molecular composition continue into the (nonvolatile) resin
and asphaltene constituents based on the concept that petroleum is a continuum
(Chapter 14) and that specific compound types exist through the whole crude
Compound , wt. %
Figure 2.1. Distribution of various compound types throughout petroleum.
oil. The difference, of course, is found in the molecular weight of the individual
compound types (Speight, 1999, 2000).
The relationship between the various hydrocarbon constituents of crude oils is
one of hydrogen addition or hydrogen loss (Speight, 1999), and there is no reason to
deny the occurrence of these interconversion schemes during the formation, maturation, and in situ alteration of petroleum. Indeed, a scheme of this type lends even
more credence to the complexity of petroleum within the hydrocarbon series alone.
The abundance of the different members of the same homologous series varies
considerably in absolute and relative values. However, in any particular crude oil or
crude oil fraction, there may be a small number of constituents forming the greater
part of the fraction, and these have been referred to as the predominant constituents
(Rossini and Mair 1959; Bestougeff, 1961). This generality may also apply to other
constituents and is very dependent on the nature of the source material as well as the
relative amounts of the individual source materials prevailing during maturation
conditions (Chapter 1).
Normal paraffin hydrocarbons (n-paraffins, straight-chain paraffins) occur in
varying proportions in most crude oils. In fact, paraffinic petroleum may contain
up to 20-50%by weight w-paraffins in the gas oil fraction. One particular gas oil
(boiling range 150-3500C, 300-6600F) contained every possible normal paraffin
that could be present in this fraction. Furthermore, all the normal paraffins up to and
beyond rc-dodecane (12 carbon atoms) have been isolated from crude oil. However,
naphthenic or asphaltic crude oils sometimes contain only very small amounts of
normal paraffins, as illustrated by the isolation of less than 1% of paraffins from
Borneo crude oil.
Considerable quantities of iso-paraffins have been noted to be present in the
straight-run gasoline fraction of petroleum. The 2- and 3-methyl derivatives are
the most abundant, the 4-methyl derivative is present in small amounts, if at all,
and it is generally accepted that the slightly branched paraffins predominate over
the highly branched materials. It seems that the wo-paraffins occur throughout
the boiling range of petroleum fractions. The proportion tends to decrease with
increasing boiling point; it appears that if the wo-paraffins are present in lubricating
oils their amount is too small to have any significant influence on the physical
properties of the lubricating oils.
As the molecular weight (or boiling point) of the petroleum fraction increases,
there is a concomitant decrease in the amount of free paraffins in the fraction. In
certain types of crude oil, there may be no paraffins at all in the vacuum gas oil
fraction. For example, in the paraffinic crude oils, free paraffins will separate as a
part of the asphaltene fraction but in the naphthenic crude oils, free paraffins are
not expected in the gas oil and asphaltene fractions.
The vestiges of paraffins in the asphaltene fractions occur as alkyl side chains
on aromatic and naphthenic systems, and these alkyl chains can contain forty or
more carbon atoms (Chapter 14).
On a boiling range basis, the low-boiling naphtha fraction (<150C, <300F)
consists mainly of paraffins (Speight, 1999). Any ring compounds are restricted
to alky Icy clohexanes and alky Icy clopentanes and to alkylbenzenes. The sulfur
content varies from a few parts per million to several hundreds of parts per million.
The nitrogen content is so low that it is rarely measured.
2J.1.2.
Cycloparaffin Hydrocarbons (Naphthenes)
Although only a small number of representatives have been isolated so far, cyclohexane, cyclopentane, and decahydronaphthalene derivatives are largely represented in oil fractions. Petroleum also contains poly cyclic naphthenes, such as
terpenes, and such molecules (often designated bridge-ring hydrocarbons) occur
even in the heavy naphtha fractions (boiling point 150-2000C, 300-390 0 F). Naphthene rings may be built up of a varying number of carbon atoms, and among the
synthesized hydrocarbons there are individuals with rings of the three-, four-,
five-, six-, seven-, and eight-membered types. It is now generally believed that
crude oil fractions contain chiefly five- and six-membered rings. Only naphthenes
with five- and six-membered rings have been isolated from the lower-boiling fractions. Thermodynamic studies show that naphthene rings with five and six carbon
atoms are the most stable. The naphthenic acids contain chiefly cyclopentane as
well as cyclohexane rings.
Cycloparaffins (naphthenes) are represented in all fractions in which the
constituent molecules contain more than five carbon atoms. Several series of
cycloparaffins, usually containing five- or six-membered rings or their combinations, occur as polycyclic structures. The content of cycloparaffins in petroleum
varies up to 60% of the total hydrocarbons. However, the cycloparaffin content
of different boiling range fractions of a crude oil may not vary considerably and
generally remains within rather close limits. Nevertheless, the structure of these
constituents may change from one petroleum to another, as well as in the same crude
oil, as a function of the molecular weight or boiling range of the individual fractions.
The principal structural variation of naphthenes is in the number of rings present
in the molecule. The mono- and bicyclic naphthenes are generally the major types
of cycloparaffins in the lower-boiling factions of petroleum, with boiling point or
molecular weight increased by the presence of alkyl chains. The higher-boilingpoint fractions, such as the lubricating oils, may contain two to six rings per
molecule.
The higher-boiling naphtha fractions (150-2000C, 300-3900F) are mainly aliphatic, but they contain lesser amounts of paraffins at the expense of higher amounts
of mono- and dinaphthenes. The aromatics may account for as much as 20 wt%
and consist of paraffin moieties in alkylbenzenes. The sulfur content ranges from
a few hundred parts per million to as high as 2% by weight. The nitrogen content
is usually < 1 ppm.
The kerosene fraction (200-2600C, 400-5000F) typically contains about
70-80% by weight saturates and 20-30% by weight aromatics. The saturated components are considerably more naphthenic than those in the lower-boiling fractions,
but this is dependent on the crude oil. Hydrocarbons with one or two naphthenic
and aromatic rings may be present. The sulfur content may vary from 0.05 to 3.0%
by weight, mainly in the form of sulfides, in acyclic as well as cyclic alkanes, and
of alkylthiophenes and benzothiophenes. The nitrogen content is typically a few
parts per million, but may be higher.
As the molecular weight (or boiling point) of the petroleum fraction increases
to higher ranges, there is a concomitant increase in the amount of cycloparaffinic
(naphthenic) species in the fraction. In the asphaltic (naphthenic) crude oils, the
gas oil fraction can contain considerable amounts of naphthenic ring systems that
increase even more in consideration of the molecular types in the asphaltenes.
However, as the molecular weight of the fraction increases, the occurrence of
condensed naphthene ring systems and alky 1-substituted naphthene ring systems
increases. There is also the premise that the naphthene ring systems carry alkyl
chains that are generally longer than the alkyl substituents carried by aromatic
systems. This can be reflected on hypothetical structures for the asphaltene constituents (Chapter 14).
In the asphaltene fraction, free condensed naphthenic ring systems may occur
but general observations favor the occurrence of combined aromatic-naphthenic
systems that are variously substituted by alkyl systems. There is also general
evidence that the aromatic systems are responsible for the polarity of the asphaltene constituents. The heteroatoms are favored to occur on or within the aromatic
(pseudoaromatic) systems (Chapter 14).
2.3.1.3. Aromatic Hydrocarbons
The occurrence of identifiable aromatic systems in nature is a reality, and the
occurrence of monocyclic and polycyclic aromatic systems in natural product
chemicals is well documented (Sakarnen and Ludwig, 1971; Durand, 1980; Weiss
and Edwards, 1980). However, one source of aromatic systems that is often ignored
is petroleum (Eglinton and Murphy, 1969; Tissot and Welte, 1978; Speight, 1981;
Brooks and Welte, 1984). Therefore, attempts to identify such systems in the
nonvolatile constituents of petroleum should be an integral part of the repertoire
of the petroleum chemist as well as the domain of the natural product chemist.
Crude oil is a mixture of compounds, and aromatic compounds are common to
all petroleum. It is the difference in extent that becomes evident on examination
of a series of petroleum. By far the majority of these aromatics contain paraffinic
chains, naphthene rings, and aromatic rings side by side.
There is a general increase in the proportion of aromatic hydrocarbons with
increasing molecular weight. However, aromatic hydrocarbons without the
accompanying naphthene rings or alky 1-substituted derivatives seem to be present
in appreciable amounts only in the lower petroleum fractions. Thus, the limitations
of instrumentation notwithstanding, it is not surprising that spectrographic identification of such compounds has been concerned with these low-boiling aromatics.
All known aromatics are present in gasoline fractions, but the benzene content is
usually low compared to the benzene homologues, such as toluene and the xylene
isomers. In addition to the 1- and 2-methylnaphthalenes, other simple alkylnaphthalenes have also been isolated from crude oil. Aromatics without naphthene rings
appear to be relatively rare in the heavier fractions of petroleum (e.g., lubricating
oils). In the higher-molecular-weight fractions, the rings are usually condensed
together. Thus components with two aromatic rings are presumed to be naphthalene derivatives, and those with three aromatic rings may be phenanthrene derivatives. Currently, and because of the consideration of the natural product origins of
petroleum, phenanthrene derivatives are favored over anthracene derivatives.
In summation, all hydrocarbon compounds that have aromatic rings, in addition
to the presence of alkyl chains and naphthenic rings within the same molecule,
are classified as aromatic compounds. Many separation procedures that have been
applied to petroleum (Chapter 10) result in the isolation of a compound as an
aromatic even if there is only one such ring (i.e., 6 carbon atoms) that is substituted
by many more than six nonaromatic carbon atoms.
Although not specifically discussed here, a variety of pericondensed polycyclic
aromatic hydrocarbons such as methylchrysene, methyl- and dimethylperylenes,
and benzofluorenes have been identified in crude oil. Chrysene and benzofluorene
homologues seem to predominate over those of pyrene.
It should also be emphasized that in the higher-boiling-point petroleum fractions, many polycyclic structures occur in naphthenoaromatic systems. The naphthenoaromatic hydrocarbons, together with the naphthenic hydrocarbon series,
form the major content of higher-boiling-point petroleum fractions. Usually, the
different naphthenoaromatic components are classified according to the number of aromatic rings in their molecules. The first to be distinguished is the
series with an equal number of aromatic and naphthenic rings. The first members of the bicyclic series C9-Q1 are the simplest, such as the 1-methyl-,
2-methyl, and 4-methylindanes and 2-methyl- and 6-methyltetralins. Tetralin and
methyl-, dimethyl-, methylethyl-, and tetramethyltetralin have been found in several crude oils, particularly in the heavier, naphthenic crude oils.
It is interesting that the distribution of the chains between aromatic and naphthenic rings within the same molecules follows a particular pattern that may also be
evident in the single-ring constituents. The short chains (methyl and ethyl) appear
to be characteristic substituents of the aromatic portion of the molecule, whereas a
limited number (1 or 2) of longer chains may be attached to the cycloparaffin rings.
The total number of chains, which is in general four to six, as well as their length,
increases according to the molecular weight of the naphthenoaromatic compounds.
Atmospheric gas oils (260-3450C, 500-6500F) may have considerable amounts
of aromatics and detectable amounts of polar constituents (Altgelt and Boduszynski,
1994; Speight, 1999 and references cited therein). Besides mono- and dinaphthenes, alkylbenzenes, and alkylnaphthalenes, the atmospheric gas oil fraction may
contain small amounts of higher-ring-number naphthenes and aromatics. Sulfur
contents are typically around 1.5-3.0% by weight but may occasionally reach
4.5% by weight. Besides dialkyl-, alkylaryl-, and arylaryl sulfides and the alkylthiophenes and benzothiophenes, there may now also be some dibenzothiophene
derivatives. Nitrogen content is usually a few hundreds of parts per million, but it
may go up to 1500 ppm for some crude oils.
Of special interest in the present context are the aromatic systems that occur
in the nonvolatile asphaltene fraction (Speight, 1994b). These poly cyclic aromatic
systems are complex molecules that fall into a molecular weight and boiling range
where very little is known about model compounds (Chapter 15). There has not
been much success in determining the nature of such systems in the higher-boiling
constituents of petroleum, i.e., the residua or nonvolatile constituents. In fact,
it has been generally assumed that as the boiling point of a petroleum fraction
increases, so does the number of condensed rings in a polycyclic aromatic system.
To some extent this is true, but the simplicities of such assumptions cause an
omission of other important structural constituents of the petroleum matrix, the
alkyl substituents, the heteroatoms, and any polycyclic systems that are linked by
alkyl chains or by heteroatoms.
The active principle is that petroleum is a continuum (Corbett and Petrossi,
1978; Long, 1979, 1981) (Chapter 14) and has natural product origins (Speight,
1981, 1994b, 1999) (Chapter 1). As such, it might be anticipated that there is
a continuum of aromatic systems throughout petroleum that might differ from
volatile to nonvolatile fractions but that, in fact, are based on natural product
systems. It might also be argued that substitution patterns of the aromatic nucleus
that are identified in the volatile fractions, or in any natural product counterparts,
also apply to the nonvolatile fractions.
The application of thermal techniques to study the nature of the volatile thermal
fragments from petroleum asphaltenes has produced some interesting data relating
to the nature of the aromatic systems in crude oil (Ritchie et al., 1979a, 1979b;
Schucker and Keweshan, 1980; Gallegos, 1981; Raul, 1982; Speight, 1999 and
references cited therein). These thermal techniques have produced strong evidence
for the presence of small (1-4 ring) aromatic systems (Speight and Pancirov,
1984; Speight, 1987). There was a preponderance of single-ring (cycloparaffin
and alkylbenzene) species as well as the domination of saturated material over
aromatic material.
Further studies using pyrolysis/gas chromatography/mass spectrometry (Speight
and Pancirov, 1984) showed that different fractions of an asphaltene would produce the same type of polycyclic aromatic systems in the volatile matter, but the
distribution was not constant (Chapter 11). It was also possible to compute the
hydrocarbon distribution from which, a noteworthy point here, there is preponderance of single ring (cycloparaffin and alkylbenzene) species as well as the
domination of saturated material over aromatic material. The emphasis on lowmolecular-weight material in the volatile products is to be anticipated on the basis
that more complex systems remain as nonvolatile material and, in fact, are converted to coke.
One other point worthy of note is that, at that time, the pyrolysis/gas chromatography/mass spectrometry program did not accommodate nitrogen and oxygen species, whether or not they be associated with aromatic systems. This matter
was resolved, in part, not only by the concentration of nitrogen and oxygen in
the nonvolatile material (coke) but also by the overall low proportions of these
heteroatoms originally present in the asphaltenes (Speight and Pancirov, 1984;
Speight, 1994b). The major drawback to the use of the pyrolysis/gas chromatography/mass spectrometry method to studying aromatic systems in asphaltenes is
the amount of material that remains as a nonvolatile residue.
Of all of the methods applied to determining the types of aromatic systems in
petroleum asphaltenes, one with considerable potential, but given the least attention, is ultraviolet spectroscopy (Friedel and Orchin, 1951; Braude and Nachod,
1955; Rao, 1961; Jaffe and Orchin, 1966; Lee et al., 1981; Bjorseth, 1983).
Typically, the ultraviolet spectrum of an asphaltene fraction shows two major
regions with very little fine structure. Interpretation of such a spectrum can only
be made in general terms (Friedel, 1959; Boyd and Montgomery, 1963; Posadov
et al., 1977). However, the technique can add valuable information about the degree of condensation of polycyclic aromatic ring systems through the auspices
of high-performance liquid chromatography (HPLC) (Lee et al., 1981; Bjorseth,
1983; Monin and Pelet, 1983; Felix et al., 1985; Killops and Readman, 1985;
Speight, 1986). Indeed, when this approach is taken the technique not only confirms the complex nature of the asphaltene fraction but also allows further detailed
identifications to be made of the individual functional constituents of asphaltenes.
An asphaltene fraction produces a multicomponent chromatogram (Chapter 10)
but subfractions produce a less complex and much narrower chromatograph that
may even approximate a single peak that may prove much easier to monitor by the
ultraviolet detector.
These data provide strong indications of the ring-size distribution of the polycyclic aromatic systems in petroleum asphaltenes. For example, from an examination of various functional subfractions, it was shown that amphoteric species
and basic nitrogen species contain polycyclic aromatic systems having two to six
rings per system. On the other hand, acid subfractions (phenolic and/or carboxylic
functions) and neutral polar subfractions (amide and/or imino functions) contain
few if any polycyclic aromatic systems having more than three rings per system
(Chapter 10).
In all cases, the evidence favored the preponderance of the smaller (1-4) ring
systems (Speight, 1986). But perhaps what is more important about these investigations is that the data show that asphaltenes are a complex mixture of compound
types, which confirms fractionation studies, and cannot be represented by any particular formula that is construed to be average. Therefore, the concept of a large
polycyclic aromatic ring system as the central feature of asphaltene molecules
must be abandoned.
In summary, the premise is that petroleum is a natural product and that the
aromatic systems are based on identifiable structural systems that are derived from
natural product precursors.
Unsaturated Hydrocarbons
The presence of olefins (RXH=CRR 1 ) in petroleum has been under dispute for
many years because there are investigators who claim that olefins are actually
present; in fact, these claims usually refer to distilled fractions, and it is very difficult to entirely avoid cracking during the distillation process. Although there may
be fragmentary evidence for the presence of olefins (albeit in very small amounts)
in petroleum, it is perhaps reasonable to assume that olefins are present in crude
oils in only a few special cases. The presence of dienes (R-CH=CH-CH=R1) and
acetylenes (RC=CR 1 ) is considered to be extremely unlikely.
In summary, a variety of hydrocarbon compounds occur throughout petroleum.
Although the amount of any particular hydrocarbon varies from one crude oil to
another, the family from which that hydrocarbon arises is well represented.
Nonhydrocarbon Components
The previous sections present some indication of the types and nomenclature of
the organic hydrocarbons that occur in various crude oils. Thus it is not surprising
that petroleum that contains only hydrocarbons is, in fact, an extremely complex
mixture. The phenomenal increase in the number of possible isomers for the higher
hydrocarbons makes it very difficult, if not impossible in most cases, to isolate
individual members of any one series having more than, say, 12 carbon atoms.
Inclusion of organic compounds of nitrogen, oxygen, and sulfur serves only to
present crude oil as an even more complex mixture than was originally conceived
(Altgelt and Boduszynski, 1994; Speight, 1999, 2000). Nevertheless, considerable progress has been made in the isolation and/or identification of the lowermolecular-weight hydrocarbons, as well as accurate estimations of the overall
proportions of the hydrocarbon types present in various crude oils. Indeed, it has
been established that, as the boiling point of the petroleum fraction increases,
not only the number of the constituents but also the molecular complexity of the
constituents increases (Fig. 2.1).
Crude oils contain appreciable amounts of organic nonhydrocarbon constituents, mainly sulfur-, nitrogen-, and oxygen-containing compounds and, in smaller
amounts, organometallic compounds in solution and inorganic salts in colloidal
suspension. These constituents appear throughout the entire boiling range of the
crude oil but tend to concentrate mainly in the heavier fractions and in the nonvolatile residues.
As the boiling range of the petroleum fractions increases, the concentration of
saturates decreases but the content of ring compounds (naphthenic compounds
and aromatic compounds) increases. Most aromatics are alkylbenzenes and naphthalenes, some of which may contain one or several naphthenic rings. In the middle
distillates and the lower-boiling fractions, the five major sulfur compound classes
(viz., thiols, sulfides, disulfides, sulfoxides, and thiophene derivatives, mainly benzothiophenes) occur. Nitrogen compounds are mostly pyrroles, indoles, pyridines,
and quinolines (Altgelt and Boduszynski, 1994; Speight, 1999, 2000). Among
the oxygen compounds, aliphatic carboxylic acids, aliphatic esters, ketones and
other carbonyl derivatives as a group, dibenzofurans, and phenols are also abundant in the atmospheric gas oil fraction. The concentration of polar constituents in
fractions boiling below 345C (6500F) usually does not exceed 5-10% by weight.
Although their concentration in certain fractions may be quite small, their influence is important. For example, the decomposition of inorganic salts suspended
in the crude can cause serious breakdowns in refinery operations; the thermal
decomposition of deposited inorganic chlorides with evolution of free hydrochloric acid can give rise to serious corrosion problems in the distillation equipment.
The presence of organic acid components, such as mercaptans and acids, can also
promote metallic corrosion. In catalytic operations, passivation and/or poisoning of
the catalyst can be caused by deposition of traces of metals (vanadium and nickel)
or by chemisorption of nitrogen-containing compounds on the catalyst, thus necessitating the frequent regeneration of the catalyst or its expensive replacement
(Wojciechowski and Corma, 1986; Peterson and Bell, 1987; Gray, 1994; Speight,
The presence of traces of nonhydrocarbons may impart objectionable characteristics to finished products, such as discoloration, lack of stability on storage, or a
reduction in the effectiveness of organic lead antiknock additives. It is thus obvious
that a more extensive knowledge of these compounds and of their characteristics
could result in improved refining methods and even in finished products of better
quality. The nonhydrocarbon compounds, particularly the porphyrins and related
compounds, are also of fundamental interest in the elucidation of the origin and
nature of crude oils. Furthermore, a knowledge of their surface-active characteristics is of help in understanding problems related to the migration of oil from the
source rocks to the actual reservoirs.
With the aromatics and polar constituents, the likelihood of molecules having
more than one heteroatom further complicates the structural types and can certainly
complicate the analysis for molecular types. Most aromatic and polar molecules
in the heavy gas oil range contain one to three aromatic rings, predominantly with
naphthenic rings. Compounds with four and more aromatic rings are present at
much lower concentrations.
In addition, heterocompound types with more aromatic rings may be found, e.g.,
benzonaphtho- and dinaphthothiophenes, benzo- and naphthoquinolines, aza- and
diaza derivatives. Compounds with two and three heteroatoms such as amides,
aza-amides, sulfoxides, carboxylic acids, and hydroxycarboxylic acids also occur
(Altgelt and Boduszynski, 1994; Speight 1999, 2000 and references cited therein).
Sulfur compounds are among the most important heteroatomic constituents of
petroleum, and, although there are many varieties of sulfur compounds
(Table 2.1), the prevailing conditions during the formation, maturation, and even
Table 2.1. Types and Nomenclature of Organic Sulfur Compounds
RSR'
Thiols (Mercaptans)
Cyclic Sulfides
RSSR'
Disulfides
Thiophene
B enzothiophene
Dibenzothiophene
Naphthobenzothiophene
in situ alteration may dictate that only preferred types exist in any particular
crude oil. Nevertheless, sulfur compounds of one type or another are present in
all crude oils; in general, the higher the density of the crude oil (or the lower
the API gravity of the crude oil), the higher the sulfur content (Speight, 1999,
2000). The total sulfur in the crude can vary from 0.04% by weight for a light
crude oil to about 5.0% for bitumen. However, the sulfur content of crude oils
produced from broad geographic regions varies with time, depending on the
composition of newly discovered fields, particularly those in different geological
The presence of sulfur compounds in finished petroleum products often produces harmful effects. For example, in gasoline, sulfur compounds promote corrosion of engine parts, especially under winter conditions, when water containing
sulfur dioxide from the combustion may accumulate in the crankcase. In addition,
mercaptans in hydrocarbon solution cause the corrosion of copper and brass in the
presence of air and also affect lead susceptibility and color stability. Free sulfur
is also corrosive, as are sulfides, disulfides, and thiophenes, which are detrimental
to the octane number response to tetraethyl lead. However, gasoline with a sulfur
content between 0.2 and 0.5% has been used without obvious harmful effect. In
diesel fuels, sulfur compounds increase wear and can contribute to the formation
of engine deposits. Although a high sulfur content can sometimes be tolerated in
industrial fuel oils, the situation for lubricating oils is that a high content of sulfur
compounds seems to lower resistance to oxidation and increases the deposition of
solids.
The distribution of sulfur in the various fractions of crude oils has been studied
many times, beginning in 1891. Although it is generally true that the proportion
of sulfur increases with the boiling point during distillation (Speight, 1999, 2000),
the middle fractions may actually contain more sulfur than higher-boiling fractions
as a result of decomposition of the higher-molecular-weight compounds during
the distillation. A high sulfur content is generally considered harmful in most
petroleum products, and the removal of sulfur compounds or their conversion to
less deleterious types is an important part of refinery practice. The distribution of
the various types of sulfur compounds varies markedly among crude oils of diverse
origin, but fortunately some of the sulfur compounds in petroleum undergo thermal
reactions at relatively low temperatures. If elemental sulfur is present in the oil,
a reaction, with the evolution of hydrogen sulfide, begins at about 1500C (3000F)
and is very rapid at 2200C (4300F), but organically bound sulfur compounds do not
yield hydrogen sulfide until higher temperatures are reached. Hydrogen sulfide is,
however, a common constituent of many crude oils, and some crude oils with > 1%
sulfur are often accompanied by a gas having substantial proportions of hydrogen
sulfide.
Several tests are used to determine the amount of sulfur in petroleum and
its products, but the actual determination of sulfur in functional groups is more
difficult. Nevertheless, the identification of sulfur-containing constituents of crude
oils has been the subject of many investigations with the result that many of
the sulfur compound types that occur in crude oils are now known (Thompson
et al., 1976). These vary from the simple thiols (R-SH) to the simple sulfides
(R-SR) and the poly cyclic sulfides, such as compounds with two condensed
rings (Table 2.1).
Several thiophenes have also been isolated from a variety of crude oils; benzothiophene derivatives are usually present in the higher-boiling petroleum fractions.
On the other hand, disulfides are not regarded as true constituents of crude oil but
are generally formed by oxidation of thiols during processing:
2R-SH + [O] R - S - S - R + H2O
At the functional group level, the sulfur compounds reported in crude and
fractions include thiols (mercaptans), sulfides, disulfides, and thiophenes (Robbins,
2000). Generally, however, the bulk of the sulfur in whole crude occurs as sulfides
and thiophenes. The distinction between sulfides and thiophenes is of practical
interest because of their wide differences in reactivity. For example, the thiophenes,
unlike the sulfides, are noncorrosive and are the most difficult sulfur types to remove
from fuels.
The measurement of the distribution thiophene/sulfide sulfur types is not as
straightforward as elemental analysis. Generally, the sulfur in a crude oil is 67%
thiophene and 33% sulfide (thioether). This is based on experience in comparing total sulfur with some of the common methods used for measuring the sulfide sulfur. The latter has been determined indirectly by titration, complexation, and oxidation-Fourier transform infrared spectroscopy (FTIR) on whole
oils and distillates and directly by X-ray photoelectron spectroscopy (XPS) and
X-ray absorption near edge spectroscopy (XANES) measurements on residua and
asphaltenes.
The indirect methods typically involve selective reaction, but few have been
validated independently or compared with one another. Measurements of sulfides by sulfur analyses after separation methods likewise fail to report sulfur
recoveries, provide material balances on real samples, or otherwise demonstrate
selectivity or accuracy. The direct techniques measure both sulfur types by deconvolution of sulfide and thiophene overlapping peaks in the spectra. Overall,
the results reported by the various techniques show a much wider range of sulfide
sulfur than implied by the above generalization (Robbins, 2000). The proportion
of sulfide sulfur in petroleum and distillates varies from < 10 to >60% by weight
of the total sulfur depending on the boiling range, source of the petroleum, and
maturation.
The uncertainty in the efficiency of sulfur-type separations has limited the
characterization of molecular species despite the introduction of a number of
sophisticated measurement techniques. Reactivity differences are recognized between the various types of sulfur, but few contributing structural features have been
identified or quantified. Differences in corrosivity, thermal stability, and oxidative
inhibition have been attributed to variation in sulfide structure. Differences in process resistance by thiophenes are attributed to steric effects. Some techniques have
been developed for molecular structural characterization, but these provide limited
data on narrow areas of interest.
For example, geochemical studies have identified several structural families in
crude oils and source materials (see, e.g., Fig. 2.1). These include the homologous series of C17-C31 bicyclic, C22-C40 tetracyclic, and even C30-C35 hexacyclic
terpenoid sulfides in the heavy oils. Structure of the most abundant member of
the bicyclic series was proven by hydrogenolysis/mass spectrometry of the resulting hydrocarbon skeleton and by synthesis. The C8-C30 dialkylthianes and
dialkylthiolanes were characterized with similar techniques after separation from
the terpenoid sulfides by thiourea adduction. Because higher homologues have
been reported in extracts of recent sediments, these linear monocyclic sulfides
serve as biomarkers for immature crude oils.
These analyses, however, intentionally reject the bulk of the sulfur compounds
to focus on the biomarker structures. The isolation procedures include multiple
reactions and chromatographic separation. Although excellent recovery (98%) is
reported for the selective oxidation of model compounds, the sulfur balances for
real samples are difficult to estimate. Thus, although the characterization provides a
geochemist with biomarker data, it gives an incomplete characterization of sulfides
that can impact processing and products.
For more complete characterization of sulfur types, specifically sulfide sulfur,
the first challenge is to demonstrate an isolation technique that is both selective and
quantitative. That is, the sulfur balance (total sulfur and proportion of sulfide sulfur)
measurements on each fraction are needed for each step of an isolation scheme.
Once the selective isolation of sulfides has been verified, the methods of measuring
molecular structure (e.g., ring number, molecular weight, sulfur bonding) can be
applied to rationalize differences.
Another example of improved sulfur-type separation can be found in the
thiophenes. However, after advanced hydroprocessing, trace refractory sulfur
compounds are found in diesel and gasoline distillates by gas chromatography.
Dibenzothiophene and alkylated homologues are a major contributor to sulfur
in distillate feeds. After conventional processing, the residual sulfur is distributed across numerous sterically hindered dibenzothiophene isomers, such as 4,6
dimethyl dibenzothiophene. The hindered dibenzothiophenes account for less than
half the GC/SCD peaks, with the remainder being distributed across the numerous unknown molecular species at the parts-per-million level. The challenge in
the characterization of these thiophene unknowns is the development of a sulfurselective isolation that would allow characterization of the molecular structure.
Many methods have been proposed for the isolation of dibenzothiophene homologues in petroleum samples. Most begin with the separation of the aromatics
(i.e., alumina or silica gel) followed by some type of sulfur-selective isolation of
the thiophene species. Two approaches are commonly suggested for separation of
thiophenes from the aromatics.
The first approach uses ligand exchange with a supported metal. Separations
using silver (Ag + ), copper (Cu 2+ ), and mercury (Hg 2+ ) as the ligand are limited to
the separation of thiophenes and aromatics with same number of aromatic rings.
If a wide group of aromatics is treated with these ligands, the thiophenes overlap with higher aromatics, i.e., benzothiophene (2-ring sulfur) elutes with the
phenanthrenes (3-ring aromatics). Palladium (Pd 2+ ) is more retentive and requires
stronger solvents for elution. If the solvent is too strong, the palladium-thiophene
complex is eluted and it must be treated with an amine treatment to release the
thiophene species.
The second approach uses a combination of oxidation, chromatographic separation, reduction, and a second chromatographic step. In such an approach, the
effect of steric hindrance on each step must be given consideration; otherwise,
the selectivity and completeness of each step is in serious doubt. Mass recovery and model sulfur-recovery in single steps have been reported for some versions. But the overall sulfur-recovery for oxidative separation of thiophenes is
lacking.
The separation of thiophenes from the fuel distillates is challenging because
some of the structures to be isolated are indeed unknown and the remainder are
sterically hindered. The development of a suitable sulfur-selective separation will
require sulfur recovery data for each step of an isolation scheme. If the product
has been hydroprocessed, the sulfur species can be assumed to be thiophene. Once
isolated, the thiophenes can be characterized using existing methods for measuring
molecular structure (e.g., ring number, molecular weight, sulfur bonding). The
value of the new sophisticated measurement techniques can be improved with the
development of better separations.
Although sulfur is the most important (certainly the most abundant) heteroatom
(i.e., nonhydrocarbon) present in petroleum with respect to the current context,
other nonhydrocarbon atoms can exert a substantial influence not only on the
nature and properties of the products but also on the nature and efficiency of
the process. Such atoms are nitrogen, oxygen, and metals, and because of their
influence on the process, some discussion of each is warranted here.
2.3.2,2. Oxygen Compounds
The analysis for oxygen in petroleum has taken an arduous route. Initially, as
for coal, oxygen was determined by difference after the amounts of all of the
other elements had been determined. The assumption, was, of course, that each
Table 2.2. Types and Nomenclature of Organic
Methyl alcohol
Dimethyl ether
Carboxylic acids
Furans
Furan
CH3 OCH3
C6H5OC6H5
CH3CO2H
C6H5CO2H
CH3CO2CH2CH3
CH=CHOCH=CH
particular method was accurate and that the difference between the sum total
of the other elemental analyses and 100% was the true value of the amount of
oxygen. Unfortunately, this was not always true. However, the oxygen content
of the light crude oils was often so insignificant as to be ignored by investigators. With the appearance of heavier feedstocks in refineries, oxygen cannot be
ignored, so several methods have been developed for accurate analysis of oxygen
in feedstocks.
In recent times, especially within the past three decades, not only has oxygen
analysis been required but there has also been a focus on the various types of
oxygen functions in feedstocks.
Oxygen in organic compounds can occur in a variety of forms (Table 2.2), and
it is not surprising that the more common oxygen-containing compounds occur
in petroleum. The total oxygen content of crude oil is usually less than 2% by
weight, although larger amounts have been reported, but when the oxygen content
is phenomenally high it may be that the oil has suffered prolonged exposure to
the atmosphere either during or after production. However, the oxygen content
of petroleum increases with the boiling point of the fractions examined; in fact,
the nonvolatile residua may have oxygen contents up to 8% by weight. Although
these high-molecular-weight compounds contain most of the oxygen in petroleum
little is known concerning their structure, but those of lower molecular weight have
been investigated with considerably more success and have been shown to contain
carboxylic acids and phenols.
The presence of acid substances (determined by several test methods as an
acid number: ASTM D-664, ASTM D-974, ASTM D-1386, ASTM D-3242) in
petroleum first appears to have been reported in 1874, and it was established
9 years later that these substances contained carboxyl groups and were carboxylic
acids. These were termed naphthenic acids. Although alicyclic (naphthenic) acids
appear to be the more prevalent, it is now well known that aliphatic acids are
also present. In addition to the carboxylic acids, alkaline extracts from petroleum
contain phenols.
It has generally been concluded that the carboxylic acids in petroleum with
fewer than eight carbon atoms per molecule are almost entirely aliphatic in nature;
monocyclic acids begin at C^ and predominate above Cu. This indicates that the
structures of the carboxylic acids correspond with those of the hydrocarbons with
which they are associated in the crude oil. In the range in which paraffins are the
prevailing type of hydrocarbon, the aliphatic acids may be expected to predominate.
Similarly, in the ranges in which monocycloparaffins and dicycloparaffins prevail,
one may expect to find principally monocyclic and dicyclic acids, respectively.
In addition to the carboxylic acids and phenolic compounds, the presence of
ketones, esters, ethers, and anhydrides has been claimed for a variety of crude
oils. However, the precise identification of these compounds is difficult because
most of them occur in the higher-molecular-weight nonvolatile residua. They are
claimed to be products of the air blowing of the residua, and their existence in
virgin petroleum may yet need to be substantiated.
Although comparisons are frequently made between the sulfur and nitrogen
contents and such physical properties as the API gravity, it is not the same with
the oxygen contents of crude oils. It is possible to postulate, and show, that such
relationships exist. However, the ease with which some of the crude oil constituents
can react with oxygen (aerial or dissolved) to incorporate oxygen functions into
their molecular structure often renders the exercise somewhat futile if meaningful
deductions are to be made.
2.3.2.3. Nitrogen Compounds
As with sulfur and oxygen, there are several tests to determine the amount of
nitrogen in crude oil and its products but the identification of the various nitrogen
functions is more difficult.
However, nitrogen in petroleum is classified as basic and nonbasic. The basic
nitrogen compounds (Table 2.3), which are composed mainly of pyridine homologues and occur throughout the boiling ranges, have a decided tendency to exist
in the higher-boiling fractions and residua. The nonbasic nitrogen compounds,
which are usually of the pyrrole, indole, and carbazole types, also occur in the
higher-boiling fractions and residua.
In general, the nitrogen content of crude oil is low and generally falls within the
range 0.1-0.9%, although early work indicates that some crude oils may contain
up to 2% nitrogen. However, crude oils with no detectable nitrogen or even trace
amounts are not uncommon, but in general the more asphaltic the oil, the higher
its nitrogen content.
Table 2.3. Types and Nomenclature of Organic Nitrogen Compounds
Nonbasic
Pyrrole
C4H5N
Ci2H9N
Benzo(a)carbazole
Ci6H11N
Quinoline
Indoline
Benzo(f)quinoline
C13H9N
Insofar as a correlation exists between the sulfur content and API gravity of
crude oils, there also exists a correlation between nitrogen content and the API
gravity of crude oils (Speight, 1999, 2000). It also follows that there is an approximate correlation between the nitrogen content and the carbon residue: the higher
the carbon residue, the higher the nitrogen content. The presence of nitrogen in
petroleum is of much greater significance in refinery operations than might be
expected from the small amounts present. Nitrogen compounds can be responsible
for the poisoning of cracking catalysts, and they also contribute to gum formation
in such products as domestic fuel oil. The trend in recent years toward cutting
deeper into the crude to obtain stocks for catalytic cracking has accentuated the
harmful effects of the nitrogen compounds, which are concentrated largely in the
higher-boiling portions (Gray, 1994; Speight, 2000).
Basic nitrogen compounds with a relatively low molecular weight can be extracted with dilute mineral acids; equally strong bases of higher molecular weight
remain unextracted because of unfavorable partitioning between the oil and aqueous phases. A method has been developed in which the nitrogen compounds are
classified as basic or nonbasic, depending on whether they can be titrated with
perchloric acid in a 50:50 solution of glacial acetic acid and benzene. Application
of this method has shown that the ratio of basic to total nitrogen is approximately
constant (0-30 0.05) irrespective of the source of the crude oil. Indeed, the ratio
of basic to total nitrogen was found to be approximately constant throughout the entire range of distillate and residual fractions. Nitrogen compounds extractable with
dilute mineral acids from petroleum distillates were found to consist of pyridines,
quinolines, and isoquinolines carrying alkyl substituents, as well as a few pyridines
in which the subsistent was a cyclopentyl or cyclohexyl group. The compounds
that cannot be extracted with dilute mineral acids contain the greater part of the
nitrogen in petroleum and are generally of the carbazole, indole, and pyrrole
types.
Porphyrins are a naturally occurring chemical species that have been known to exist
in petroleum for more than 60 years (FaIk, 1964; Smith, 1975; Branthaver, 1990).
They are given separate consideration in this section because of their uniqueness
as separate and distinct chemical entities. They are not usually considered among
the usual nitrogen-containing constituents of petroleum, nor are they considered a
metallo-containing organic material that also occurs in some crude oils. As a result
of these early investigations, there arose the concept of porphyrins as biomarkers
that could establish a link between compounds found in the geosphere and their
corresponding biological precursors (Treibs, 1934; Glebovskaya and Volkenshtein,
Porphyrins usually occur in the nonbasic portion of the nitrogen-containing
concentrate. The simplest porphyrin is porphine, and it consists of four pyrrole molecules joined by methine ( - C H - ) bridges (Branthaver, 1990; Reynolds,
1998; Speight, 1999). The methine bridges establish conjugated linkages between
the component pyrrole nuclei, forming a more extended resonance system. Although the resulting structure retains much of the inherent character of the pyrrole
components, the larger conjugated system gives increased aromatic character to
the porphine molecule (FaIk, 1964; Smith, 1975).
Figure 2.2. The formalized numbering system for porphyrins.
A large number of porphyrin compounds exist in nature or have been synthesized. Most of these compounds have substituents other than hydrogen on
many of the ring carbons. The nature of the substituents on porphyrin rings determines the classification of a specific porphyrin compound into one of various
types according to one common system of nomenclature (Fig. 2.2) (Bonnet, 1978;
Branthaver, 1990; Reynolds, 1998). Porphyrins also have well-known trivial names
or acronyms that are often in more common usage than the formal system of
nomenclature.
When one or two double bonds of a porphyrin are hydrogenated, a chlorin or a
phlorin is the result (Branthaver, 1990). Chlorins are components of chlorophylls,
and they possess an isocyclic ring formed by two methylene groups bridging
a pyrrolic carbon to a methine carbon. Geological porphyrins that contain this
structural feature are assumed to be derived from chlorophylls. Etioporphyrins
are also commonly found in geological materials and have no substituents (other
than hydrogen) on the methine carbons. Benzoporphyrins and tetrahydrobenzoporphyrins have also been identified in geological materials. These compounds
have either a benzene ring or a hydrogenated benzene ring fused onto a pyrrole
unit.
Almost all crude oil, heavy oil, and bitumen contain detectable amounts of
vanadyl and nickel porphyrins. More mature, lighter crude oils usually contain
only small amounts of these compounds. Heavy oils may contain large amounts
of vanadyl and nickel porphyrins. Vanadium concentrations of over 1000 ppm
are known for some crude oils, and a substantial amount of the vanadium in
these crude oils is chelated with porphyrins. In high-sulfur crude oil of marine
origin, vanadyl porphyrins are more abundant than nickel porphyrins. Low-sulfur
crude oils of lacustrine origin usually contain more nickel porphyrins than vanadyl
porphyrins.
Of all the metals in the periodic table, only vanadium and nickel have been
proven definitely to exist as chelates in significant amounts in a large number of
crude oils and tar sand bitumen. The existence of iron porphyrins in some crude oils
has been claimed (Franceskin et al., 1986). Geochemical reasons for the absence
of substantial quantities of porphyrins chelated with metals other than nickel and
vanadium in most crude oils and tar sand bitumen have been advanced (Hodgson
et al., 1967; Baker, 1969; Baker and Palmer, 1978; Baker and Louda, 1986; Filby
and Van Berkel, 1987; Quirke, 1987).
If the vanadium and nickel contents of crude oils are measured and compared
with porphyrin concentrations, it is usually found that not all the metal content
can be accounted for as porphyrins (Dunning et al., 1960; Reynolds, 1998). In
some crude oils, as little as 10% by weight of total metals appears to be chelated
with porphyrins. Only rarely can all measured nickel and vanadium in a crude
oil be accounted for as porphyrinic (Erdman and Harju, 1963). Currently some
investigators believe that part of the vanadium and nickel in crude oils is chelated
with ligands that are not porphyrins. These metal chelates are referred to as nonporphyrin metal chelates or complexes (Crouch et al., 1983; Fish et al., 1984;
Reynolds et al., 1987).
On the other hand, the amount of nonporphyrin metal in crude oils has been
questioned (Goulon et al., 1984). There is the possibility that in such systems as
the heavy crude oils, in which intermolecular associations are important, measurements of the porphyrin concentrations are unreliable and there is a tendency
to undercount the actual values. However, for the purposes of this chapter it is
assumed that nonporphyrin chelates exist in fossil fuels but the relative amount is
as yet unknown.
Finally, during the fractionation of petroleum (Chapter 9), the metallic constituents (metalloporphyrins and nonporphyrin metal chelates) are concentrated in the
asphaltene fraction. The deasphaltened oils (petrolenes and maltenes) (Chapter 9)
contain smaller concentrations of porphyrins than the parent materials and usually
very small concentrations of nonporphyrin metals.
23.2.5.
Metallic Constituents
Metallic constituents are found in every crude oil, and the concentrations must
be reduced to convert the oil to transportation fuel. Metals affect many upgrading
processes and cause particular problems because they poison catalysts used for
sulfur and nitrogen removal as well as other processes such as catalytic cracking
Thus the occurrence of metallic constituents in crude oil is of considerably
greater interest to the petroleum industry than might be expected from the very small
amounts present. Even minute amounts of iron, copper, and particularly nickel and
vanadium in the charging stocks for catalytic cracking affect the activity of the catalyst and result in increased gas and coke formation and reduced yields of gasoline
1999, 2000). In high-temperature power generators, such as oil-fired gas turbines,
the presence of metallic constituents, particularly vanadium, in the fuel may lead
to ash deposits on the turbine rotors, thus reducing clearances and disturbing their
balance. More particularly, damage by corrosion may be very severe. The ash resulting from the combustion of fuels containing sodium and especially vanadium
reacts with refractory furnace linings to lower their fusion points and so cause their
deterioration.
Thus, the ash residue left after burning crude oil is caused by the presence of
these metallic constituents, part of which occur as inorganic water-soluble salts
(mainly chlorides and sulfates of sodium, potassium, magnesium, and calcium)
in the water phase of crude oil emulsions. These are removed in the desalting
operations, either by evaporation of the water and subsequent water washing or
by breaking the emulsion, thereby causing the original mineral content of the
crude to be substantially reduced. Other metals are present in the form of oilsoluble organometallic compounds as complexes, metallic soaps, or in the form
of colloidal suspensions, and the total ash from desalted crude oils is of the order
of 0.1-100 mg/liter. Metals are generally found only in the nonvolatile portion of
crude oil (Altgelt and Boduszynski, 1992; Reynolds, 1998).
Two groups of elements appear in significant concentrations in the original crude
oil associated with well-defined types of compounds. Zinc, titanium, calcium,
and magnesium appear in the form of organometallic soaps with surface-active
properties adsorbed in the water/oil interfaces and act as emulsion stabilizers.
However, vanadium, copper, nickel, and part of the iron found in crude oils seem
to be in a different class and are present as oil-soluble compounds. These metals are
capable of complexing with pyrrole pigment compounds derived from chlorophyll
and hemoglobin and are almost certain to have been present in plant and animal
source materials. It is easy to surmise that the metals in question are present in
such form, ending in the ash content. Evidence for the presence of several other
metals in oil-soluble form has been produced, and thus zinc, titanium, calcium,
and magnesium compounds have been identified in addition to vanadium, nickel,
iron, and copper. Examination of the analyses of a number of crude oils for iron,
nickel, vanadium, and copper indicates a relatively high vanadium content, which
usually exceeds that of nickel, although the reverse can also occur.
Distillation concentrates the metallic constituents in the residua (Reynolds,
1998), although some can appear in the higher-boiling distillates, but the latter
may be caused in part by entrainment. Nevertheless, there is evidence that a portion of the metallic constituents may occur in the distillates by volatilization of
the organometallic compounds present in the petroleum. In fact, as the percentage
of overhead obtained by vacuum distillation of a reduced crude is increased, the
amount of metallic constituents in the overhead oil is also increased. The majority
of the vanadium, nickel, iron, and copper in residual stocks may be precipitated
along with the asphaltenes by hydrocarbon solvents. Thus removal of the asphaltenes with rc-pentane reduces the vanadium content of the oil by up to 95%,
with substantial reductions in the amounts of iron and nickel.
2.3.2.6. Nondistillable Constituents
Although there have been attempts to identify the material boiling up to 7050C
(13000F) (Altgelt and Boduszynski, 1994), the nature of the chemical constituents
in this boiling range remain largely unknown. Thus, on a boiling range basis,
the most important range to the analytical chemist has been, for several decades,
the nondistillable material (boiling point >565C, >1050F) that includes the
nondistillable gas oil, the resins, and the asphaltenes.
The nondistillable residua consist of molecules of such low volatility that are
the most complex of all crude oil fractions, consisting almost exclusively of heterocompounds, most of which contain several heteroatoms per molecule. They
typically account for 30-60% of the total sulfur, 70-90% of the total nitrogen,
and 80-90% of the total vanadium and nickel present in a crude oil. Saturates and
aromatics together make up only a few weight percent of the nondistillable residua.
Depending on the source and nature of the crude oil, approximately 40-70% by
weight of the nondistillable residuum can be separated as an asphaltene fraction
(Chapter 9).
The nondistillable residue can be separated into several fractions of increasing
molecular weight and, thus, of increasing boiling point (Chapter 5). The nonasphaltene (soluble fraction) of a nondistillable residue is so complex that further
separation by chromatography is highly inefficient.
The asphaltene constituents, being insoluble in low-boiling hydrocarbon liquids
such as rc-heptane, are also nondistillable, no matter from what source they are
isolated. Because practically all analytical work on nondistillable compounds was
done on asphaltenes, it is pertinent to use such work as a reference.
What little information we have on the composition of insolubles comes from
elemental analysis, from spectroscopic methods such as infrared spectroscopy,
nuclear magnetic resonance, and XANES spectroscopy, and from degradation
followed by analysis of the fragments. The spectroscopic methods allow the determination of some functional groups and certain aspects of the hydrocarbon skeleton in the sample. The degradative approach leads to more detailed information
on the fragments but not necessarily to quantitative data on the entire molecules
In the 1960s, a chicken wire model with large aromatic and naphthenic pericondensed ring systems was popular for asphaltenes. Modifications of this model
still show up in review articles and other papers, although, generally, this view is
no longer accepted (Speight, 1994b, 1999). These insoluble molecules are now
seen as consisting of one or several relatively small ring clusters made up of only
a few condensed aromatic and naphthenic rings and containing polar heteroatom
groups. In the larger molecules, several ring clusters, and maybe even single rings,
are interconnected by paraffinic groups or chains and by sulfur linkages.
To a large extent, the nondistillable resin and asphaltene constituents have the
same functionalities as simpler petroleum constituents comprising only one or
two heteroatoms, except that they have them in higher concentration (Speight,
1994b, 1999). On the other hand, the high hydrogen deficiencies found in most
high-boiling petroleum fractions seem to be incompatible with very small (1 or 2
ring) aromatic moieties. It is the presence of the heteroatoms (nitrogen and sulfur,
with oxygen playing a lesser role) that contribute to the formation of high yields
of coke from the asphaltene fraction. (Speight, 1994b, 1999).
On the basis of thermodynamic principles, the differences between asphaltenes
and resins (soluble polar fraction) should be gradual rather than abrupt. This is
indeed true (Speight, 1999 and references cited therein), and there are definite
similarities between the constituents of the two fractions when the properties of
asphaltenes and resins obtained from the same residue under identical conditions
by means of three separation methods, namely, adsorption chromatography, are
compared. This, together with the great dependence of asphaltene yields on alkane
type and precipitation conditions, emphasizes the gradual nature of the shift in the
composition of resins and asphaltenes.
The molecular weights of the hydrocarbon-soluble fraction of nondistillable
residua can generally be determined by vapor pressure osmometry without any
difficulty. However, the true molecular weight ranges of the insolubles are hard
to determine. Most have molecular weight distributions ranging from about 500
to a few thousand daltons (Chapter 12). A strong tendency to aggregate makes
vapor pressure osmometry using nonpolar solvents questionable. With polar solvents (such as pyridine and nitrobenzene), considerably lower molecular weight
values are produced, and at elevated temperatures, the molecular weights are even
lower.
Thus the true molecular weights of asphaltene constituents, free from aggregation and other interferences, are not accurately known, although estimations can
be made using graphical methods (Speight, 1999).
The salient features of asphaltene science must be recalled and summarized at
this point.
1. Asphaltenes differ in yield and composition depending not only on crude
oil origin but also on type of residuum from which they have been precipitated
(atmospheric or vacuum), the precipitant (rc-pentane, ^-heptane), and precipitation conditions (sample-to-precipitant ratio, addition of solvents such as benzene,
temperature, agitation, and digestion time).
2. Asphaltenes are not a unique chemical compound group or compound class.
They are a strictly operationally defined solubility fraction. The common phrases
asphaltene molecules or asphaltene-type structures are imprecise and can be misleading. The fraction consists of a large variety of constituents of unknown structure
and wide range of molecular weight.
3. It is also possible to separate the asphaltene fraction (including the resins),
into acids, bases, and neutral species. There are workers who advocate leaving the
asphaltenes in the feedstock and performing such a chemical-type separation on
the whole feedstock.
It is not the purpose of this book to enter the long debate about the pros and
cons of determining an asphaltenes fraction in a feedstock. Item 3 above notwithstanding, the asphaltene must be recognized as the fraction that contains a high
concentration of heteroatoms and especially metals and that has the most adverse
effect on crude oil refining.
Knowing the amount of asphaltene fraction in a feedstock can, indeed, greatly
help in assessing crude oil processability (Speight, 2000). The separation of this
fraction using low-boiling hydrocarbons is a convenient shortcut for concentrating
the most refractory petroleum constituents and determining their amount. It is also
a very common procedure with many variations.
Throughout this book, the asphaltenes are considered as a separate fraction
and are referred to as such. Certain analytical techniques can suffer when the
asphaltenes are not first removed from the feedstock before application of the
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Petroleum (also called crude oil) is a mixture of gaseous, liquid, and solid hydrocarbon compounds that occurs in sedimentary rock deposits throughout the world
and also contains small quantities of nitrogen-, oxygen-, and sulfur-containing
compounds as well as trace amounts of metallic constituents (Bestougeff, 1967;
Colombo, 1967;HobsonandPohl, 1973; Thornton, 1977; Considine and Considine,
1984; Speight, 1999). Thus it might be anticipated that the classification of
petroleum as a hydrocarbon mixture should follow from this definition. However, because of the apparent (contradictory) similarity and diversity of crude oil
this is not the case, and some clarification is required.
Officially, petroleum is defined (Chapter 1) as a naturally occurring mixture
of hydrocarbons, generally in a liquid state, which may also include compounds
of sulfur, nitrogen, oxygen, metals, and other elements (ASTM, 1998). In more
specific terms, petroleum has also been defined (ITAA, 1936) as:
any naturally occurring hydrocarbon, whether in a liquid, gaseous, or solid state;
any naturally occurring mixture of hydrocarbons, whether in a liquid, gaseous,
or solid state; or
any naturally occurring mixture of one or more hydrocarbons, whether in a
liquid, gaseous, or solid state, and one or more of the following: hydrogen
sulfide, helium, and carbon dioxide.
The definition includes any petroleum as defined by paragraph (1), (2) or (3) that
has been returned to a natural reservoir.
These definitions of petroleum are clear in their meaning, but attempting to
classify petroleum takes on other dimensions. As noted, these are the dimensions
of similarity and diversity. Thus the analytical chemist, although provided with
a host of analytical techniques and tools, will find himself/herself stymied when
attempting to classify petroleum on the basis of a single or simple property. Attempts have been made to classify petroleum using a single property such as API
gravity (ASTM D-287, ASTM D-1298, ASTM D-3142) or the kinematic viscosity (ASTM D-445) with only very limited success. The precision and accuracy
of the analytical methods calls into question the real meaning of any such data
(Chapters 4 and 5).
On the other hand, the classification of coal involves a series of steps with welldefined procedure and guidelines at the end of which a classification is achieved
(ASTM D-388). In fact, there are several classification systems for coal (Speight,
1994) that have evolved in various countries and that can be applied successfully and compared knowledgeably with each othernot so for petroleum; please
One of the major disadvantages in attempting a classification of petroleum,
vis-a-vis the classification of coal, is that the elemental (ultimate) composition
of petroleum (Chapter 2) is not reported to the same extent as it is for coal
(Lowry, 1945, 1963; Meyers, 1981; Hessley, 1990; Speight, 1994) and does not
have the same spread of elemental content. The proportions of the elements in
petroleum vary only slightly over fairly narrow limits despite the wide variation
in physical properties from the lighter, more mobile (conventional) crude oil to
bitumen at the other extreme. Thus, as a result of the wide variety of organic
constituents and physical conditions that can play a role in the formation of
petroleum, it is surprising that there is not a wider variation in the composition of
petroleum.
Indeed, there are many general definitions that are really descriptions of
petroleum, heavy oil, and bitumen (Chapter 1), but none are sufficiently accurate to
convey an accurate meaning or to be considered as part of a classification system.
Furthermore, there are several classification methods that are used for chemical characterzation according to functional groups distribution (ASTM F-1186),
infrared absorption spectroscopy (ASTM E-204), the viscosity of industrial lubricants (ASTM D-2422), petroleum waxes for use in rubber compounding (ASTM
D-4924), and the ultraviolet absorptivity of petroleum products (ASTM D-2000).
However, none of these methods is adequate to the task of classifying petroleum.
For the most part, correctly or incorrectly, the classification of petroleum has been
forced into reliance on physical properties. In some cases, one physical property has been used. In other cases, a combination of physical properties has been
Petroleum does exhibit a wide range of physical properties (Chapters 4, 5,
and 6), but, unlike coal, the use of these properties in attempts at classification is
less well defined than the use of the properties in the various coal classification
systems (ASTM D-388; Speight, 1994). However, there are correlations that can
be made between various physical properties presenting relationships for various
crude oils, and even though properties such as viscosity, density, boiling point, and
color of petroleum may vary, the ultimate or elemental analysis varies, as already
noted, over a narrow range for a large number of petroleum samples (Chapter 2).
Therefore, it becomes a matter of what to correlate with what for a functional
classification system.
In fact, a functional classification of petroleum into conventional petroleum,
heavy oil, and tar sand bitumen involves not only an inspection of several properties
but also an additional and workable parameter, reference to the method of recovery
(page 78). Acknowledgment of the recovery method not only adds a new dimension
to the data derived by analytical testing but also identifies and qualifies the nature
of the material under investigation.
Thus it is the purpose of this chapter to review the classification methods that
have evolved over time and to present them for further consideration as the culmination and conjunction of two or more analytical methods. All of these methods
involve determination of the relevant properties of petroleum through analytical
techniques, many of which are covered in the various chapters throughout this
book. No attempt is made in this chapter to reference all of the methods; the more
pertinent methods are noted below.
3.2. CLASSIFICATION SYSTEMS
The original methods of classification arose because of commercial interest in
petroleum type and were a means of providing refinery operators with a rough
guide to processing conditions. It is therefore not surprising that systems based
on a superficial inspection of a physical property, such as specific gravity or API
(Baume) gravity (ASTM D-287, ASTM D-1298, ASTM D-3142) (Chapter 4), are
easily applied and are actually used to a large extent in expressing the quality
of crude oils. Although such a system is approximately indicative of the general
character of a crude oil, as long as materials of one general type are under consideration, application as a general classification method is more difficult and often
fraught with errors. However, generally speaking, among crude oils from a particular area, an oil of 40 API gravity (specific gravity = 0.825) is usually more
valuable than one of 20 API gravity (specific gravity = 0.934) because it contains
a higher proportion of lower-boiling fractions (e.g., naphtha) and lesser amounts
of the higher-boiling (undesirable) asphaltic constituents.
However, in terms of petroleum classification using the elemental composition,
the carbon content is relatively constant, whereas the hydrogen and heteroatom
contents are responsible for the major differences between petroleum classes.
The nitrogen, oxygen, and sulfur can be present in only trace amounts in some
petroleum, which as a result consists primarily of hydrocarbons. On the other
hand, a crude oil containing 9.5% heteroatoms may contain essentially no true
hydrocarbon constituents because the constituents contain at least one or more
nitrogen, oxygen, and/or sulfur atom within the molecular structures.
A case might be made for using the elemental composition as a means of
classification. Indeed, the method might be workable when comparing specific
families of crude oil from a particular region, but the end result offers very little
meaning when applied to petroleum in general. One has to question whether a
hydrogen-to-carbon atomic ratio of 1.60 for one crude oil is really that much
different from a hydrogen-to-carbon ratio of 1.65 of another crude oil when the
heteroelements vary but the API gravity, for example, might be the same for both
crude oils. And the classification web can become even more tangled.
There has been more success in using the molecular types in crude oil as a
means of classification (page 70). The molecular species in petroleum vary from
simple hydrocarbon species (in the majority) to very complex organic molecules
containing atoms of carbon, hydrogen, nitrogen, oxygen, and sulfur (in the minority) as well as trace amounts of metals such as vanadium, nickel, iron, and copper
(Chapter 2). However, classification using the various metals must be approached
with caution because many crude oils pick up errant (nonindigenous) metal species
during pipelining and storage. One would not wish to classify petroleum on the
basis of pipeline construction or storage tank components!
The molecular complexity of petroleum is further illustrated by the number of
potential isomers, i.e., molecules having the same atomic formula, that can exist for
a given number of paraffinic carbon atoms, which increases rapidly as molecular
weight increases:
Carbon atoms
per hydrocarbon
isomers
This same increase in number of isomers with molecular weight also applies to
the other molecular types present. Because the molecular weights of the molecules
found in petroleum can vary from that of methane (CH4; molecular weight 16)
to several thousand (Speight et al., 1985), it is clear that the heavier nonvolatile
fractions can contain virtually unlimited numbers of molecules. However, in reality,
the number of molecules in any specified fraction is limited by the nature of the
precursors of petroleum, their chemical structures, and the physical conditions that
are prevalent during the maturation (conversion of the precursors) processes.
Attempting to use specific compound types as a means of classification has met
with some success but requires careful and detailed analysis. Gas chromatography
can play a major role in such a system but may be better limited to boiling range
analysis (ASTM D-2887) and to specific fractions (ASTM D-3710, ASTM D5134) and response factors (ASTM D-4626). When feedstocks such as heavy oil
and bitumen are considered, gas chromatography does have a role, but it is somewhat limited by the nature of the feedstock. Thus one might be able to classify
Fossil Energy Resources
Tar Sand Bitumen
Geophysical Energy Resources
Figure 3.1. Classification of energy resources.
lower-boiling fractions on the basis of the hydrocarbon content of certain fractions
(see also Chapter 3), but the system would fall short when applied to heavy oil and
Classification as a Hydrocarbon Resource
Petroleum is referred to generically as & fossil energy resource (Fig. 3.1) and is
further classified as a hydrocarbon resource.
Resources can be subdivided and classified as discovered resources or undiscovered resources (Speight, 1999), although how anyone can put meaningful figures
to a term such as undiscovered resources is beyond the scope of this book and the
mental capacity of many scientists and engineers, the author included!
Of the discovered resources, classification is further achieved by consideration of whether or not a discovered resource contains nonrecoverable material or
recoverable material. Of the recoverable material, further subdivision into various
subclasses of reserves applies where the attachment of adjectives such as proven
(e.g., proven reserves) and probable (e.g., probable reserves) also applies. Again,
the derivation of meaningful numbers for terms such as probable reserves is beyond
the scope of this book and the mental capacity of many scientists and engineers,
the author included! Be that as it may, for the purposes of this text the adjective of
consequence is proven (proved), and we will not dabble in numbers for resource
or reserve estimates that border on popular fiction.
To continue, for illustrative (or comparative) purposes in this text, coal and oil
shale kerogen have also been included in this classification. However, the inclusion of coal and oil shale under the broad classification of hydrocarbon resources
has required (incorrectly) that the term hydrocarbon be expanded to include the
macromolecular nonhydrocarbon heteroatomic species that constitute coal and
oil shale kerogen. Use of the term organic sediments would be more correct
(Fig. 3.2). The inclusion of coal and oil shale kerogen in the category of hydrocarbon resources is due to the fact that these two natural resources (coal and oil shale
Associated Gas
Sub-bituminous
Bituminous
Figure 3.2. Classification of organic sediments (from Speight, 1999).
kerogen) will produce hydrocarbons on high-temperature processing. Therefore,
if coal and oil shale kerogen are to be included in the term hydrocarbon resources,
it is more appropriate that they be classed as hydrocarbon-producing resources
under the general classification of organic sediments (Fig. 3.3).
Thus, fossil energy resources divide into two classes:
1. naturally occurring hydrocarbons (petroleum, heavy oil, natural gas, and
natural waxes); and
2. hydrocarbon sources (bitumen, oil shale, and coal) that may be made to
generate hydrocarbons by the application of conversion processes.
Both classes may be aptly, and more correctly, described as organic sediments.
Petroleum and heavy oil fall conveniently and correctly into the first category
listed.
The determination that petroleum can be classed as a hydrocarbon resource
is not beyond the scope of reality. Indeed, petroleum (and its relative heavy oil)
contains high proportions of individual hydrocarbons (Nelson, 1958; Gruse and
Stevens, 1960; Bestougeff, 1967; Hobson and Pohl, 1973; Speight, 1999; and
references cited in all of these texts).
Naturally-occurring
Conversion required
Figure 3.3. Classification of organic sediments based on hydrocarbon content and hydrocarbon potential (from Speight, 1999).
In summary, the classification of petroleum as a naturally occurring mixture
of hydrocarbons is possible by virtue of the fact that it can be separated into
original hydrocarbon constituents that have not been altered by any applied process.
Naturally occurring hydrocarbons are major contributors to the composition of
petroleum. Coal and kerogen do not enjoy this means of separation, and methods
of thermal decomposition must be applied before hydrocarbons are produced. Tar
sand bitumen is analogous to coal and oil shale kerogen insofar as methods of
thermal decomposition must be applied to the bitumen to produce hydrocarbons.
These hydrocarbons did not exist in the natural state in the reservoir and are
derivatives of the thermal process. For commercial purposes, the hydrocarbons
produced from bitumen by thermal processes are collectively called synthetic crude
oil (Speight, 1990).
Thus, using the concept of whether a resource is a naturally occurring hydrocarbon source (natural gas, petroleum, heavy oil) or whether the resource requires
application of heat (tar sand bitumen, coal, oil shale kerogen) to produce hydrocarbon products enables a start to be made in the classification system.
From this start it is possible to move to the next system of classification that
involves an examination of the crude oil on the basis of chemical composition.
Classification by Chemical Composition
Composition refers to the specific mixture of chemical compounds that constitute
petroleum. The composition of these materials is related to the nature and mix of the
organic material that generated the hydrocarbons. Composition is also subject to
the influence of natural processes such as migration (movement of oil from source
rock to reservoir rock), biodegradation (alteration by the action of microbes),
and water washing (effect of contact with water flowing in the subsurface) on that
composition. Thus petroleum is the result of the metamorphosis of natural products
as a result of chemical and physical changes imparted by the prevailing conditions
at a particular locale (Speight, 1999).
Petroleum varies in appearance from a thin (mobile), nearly colorless liquid to
a thick (viscous), almost black oil. The specific gravity (at 15.6C, 600F) varies
correspondingly from about 0.75 to 1.00 (57-10 API), with the specific gravity
of most crude oils falling in the range from 0.80 to 0.95 (45-17 API). Thus it is
not surprising that petroleum varies in composition from one oil field to another,
from one well to another in the same field, and even from one level to another in
the same well. This variation can be both in molecular weight and in the types
of molecules present in petroleum. Thus petroleum may well be described as a
mixture of organic molecules drawn from a wide distribution of molecular types
that lie within a wide distribution of molecular weights.
By definition, a hydrocarbon contains carbon and hydrogen only (Roberts and
Caserio, 1964; Morrison and Boyd, 1973; Fessenden and Fessenden, 1990), with
the inclusion of any other elements (e.g., nitrogen, oxygen, and sulfur) causing
differences in properties and the inclusion of functional groups into the original
hydrocarbon system (ASTM F-1186).
Thus, on the other hand, if an organic compound contains nitrogen, and/or
sulfur, and/or oxygen, and/or metals, it is a heteroatomic compound and not a
hydrocarbon. Organic compounds containing heteroelements (elements such as
nitrogen, oxygen, and sulfur) in addition to carbon and hydrogen are defined in
terms of the locations of these heteroelements within the molecule. In fact, to
a large extent, the heteroatomic function determines the chemical and physical
reactivity of the heteroatomic compounds (Roberts and Cesario, 1964; Morrison
and Boyd, 1973; Fessenden and Fessenden, 1990), and the chemical and physical
reactivity of the heteroatomic compounds is quite different from the chemical and
physical reactivity of the hydrocarbons.
Naturally occurring hydrocarbons are those molecules that contain carbon and
hydrogen only and that occur in nature. The term naturally occurring hydrocarbons does not apply to those hydrocarbons that are produced by applied processes such as the thermal decomposition of coal to produce liquids and gases
or the retorting (thermal decomposition) of oil shale kerogen to produce shale
Petroleum is a naturally occurring hydrocarbon insofar as it contains compounds that are composed of carbon and hydrogen only (Hobson and Pohl, 1973;
Considine and Considine, 1984) and do not contain any heteroatoms (nitrogen, oxygen, and sulfur as well as compounds containing metallic constituents, particularly
vanadium, nickel, iron, and copper). The hydrocarbons found in petroleum are
classified into the following types:
1. paraffins', saturated hydrocarbons with straight or branched chains but without any ring structure;
2. cycloparaffins (naphthenes): saturated hydrocarbons containing one or more
rings, each of which may have one or more paraffinic side chains (more
correctly known as alley die hydrocarbons):
3. aromatics: hydrocarbons containing one or more aromatic nuclei such as
benzene, naphthalene, or phenanthrene ring systems that may be linked up
with (substituted) naphthalene rings and/or paraffinic side chains.
On this basis, petroleum may have some value in the crude state, but when refined
it provides fuel gas, petrochemical gas (methane, ethane, propane, and butane),
transportation fuel (gasoline, diesel fuel, and aviation fuel) solvents, lubricants,
asphalt, and many other products.
In addition to the hydrocarbon constituents, petroleum does contain heteroatomic (nonhydrocarbon) species, but they are in the minority compared to the
macromolecular heteroatom-containing kerogen (Costantinides and Arich, 1967;
Tissot and Welte, 1978).
A widely used classification of petroleum distinguishes between crude oils
either on a.paraffin base (paraffin constituents) or on an asphalt base (cycloparaffin
or naphthene constituents) (Fig. 3.4) and arose because paraffin wax separates
from some crude oils on cooling but other oils show no separation of paraffin wax
on cooling. The terms paraffin base and asphalt base were introduced and have
remained in use (van Nes and van Westen, 1951; Nelson, 1958; Hobson and Pohl,
1973). To accommodate crude oils that were neither paraffin base nor naphthene
base, the term intermediate base is applied.
The presence of paraffin wax is usually reflected in the paraffinic nature of the
constituent fractions, and a high asphaltic content corresponds with the so-called
naphthenic properties of the fractions. As a result, the misconception that paraffinbase crude oils consist mainly of paraffins and asphalt-base crude oils mainly of
cyclic (or naphthenic) hydrocarbons has arisen. In addition to paraffin- and asphaltbase oils, a mixed base class had to be introduced to describe those oils that leave
a mixture of bitumen and paraffin wax as a residue by nondestructive distillation.
In practice, a distinction is often made between light and heavy crude oils
(indicating the proportion of low-boiling material present), which, in combination
with the preceding distinction (paraffinic, asphaltic, and so on), doubles the number
of possible classes.
The United States Bureau of Mines (USBM, 1950) designated eight bases
of crude oil according to the character of a key fraction boiling at 275-3000C
Naphthenic
Figure 3.4. Classification based on hydrocarbon type.
(527-572F) at 40 mm pressure (equivalent to approximately 390-4150C, 733779F at 7060 mm pressure).
For a time, this system of classification proved adequate to the task, and it may
even still be used in some laboratories. The advent of different types of crude oil
(heavy oil) and bitumen as refinery feedstocks has changed the emphasis on this
system. In-house classification of crude oil has depended on the various refinery
scenarios and the need for the various end products.
Correlation Index
An early attempt to give the classification system a quantitative basis suggested that
a crude should be called naphthenic (asphaltic) if the distillation residue contained
less than 2% wax and paraffinic if it contained more than 5%. A division according
to the chemical composition of the 250-3000C (480-5700F) fraction has also been
suggested (Table 3.1).
Difficulties arise in using such a classification in that in the fractions boiling
above 2000C (3900F) the molecules can no longer be placed in one groupbecause
most of them are of a typically mixed nature. Purely naphthenic or aromatic
molecules occur very seldom; cyclic compounds generally contain paraffinic side
chains and often even aromatic and naphthenic rings side by side. More direct
Table 3.1. Classification by Chemical Composition (Adapted from Speight, 1999)
Composition of 250-3000C (480-5700F) fraction
Paraffinic
>46, <61
Crude Oil Classification
>12,
>8,
Paraffinic-naphthenic
Paraffinic-naphthenic-aromatic
chemical information is often desirable and can be supplied by means of the cor-
relation index (CI).
The correlation index, developed by the US Bureau of Mines, is based on the
plot of specific gravity versus the reciprocal of the boiling point in degrees Kelvin
(K = 0C + 273). For pure hydrocarbons, the line described by the constants of
the individual members of the normal paraffin series is given a value of CI = 0
and a parallel line passing through the point for the values of benzene is given as
CI = 100 (Fig. 3.5); thus,
CI = 473.7J - 456.8 + 48, 640/K
where K for a petroleum fraction is the average boiling point determined by the
standard Bureau of Mines distillation method and d is the specific gravity (Gruse
and Stevens, 1960).
Values for the index between 0 and 15 indicate a predominance of paraffinic
hydrocarbons in the fraction. A value from 15 to 50 indicates predominance of
either naphthenes or mixtures of paraffins, naphthenes, and aromatics. An index
value above 50 indicates a predominance of aromatic species.
It is also possible to describe a crude oil by an expression of its chemical composition on the basis of the correlation index data for its middle portions (Fig. 3.6).
The position of a crude on this scale is determined by the average correlation
index for its fractions boiling between 2000C (3900F) at atmospheric pressure and
275C (525F) at 40 mm, and the paraffinic, or cyclic, nature of the fractions, and
thereby the nature of the bulk of the crude, are expressed directly. The height of
the vertical bar above the horizontal indicates the wax content of the heavy gas oil
and light lubricating fractions of that crude, and hence the crystalline wax content
of the crude can be assessed. The length of each bar below the horizontal is a
measure of the carbon residue (Conradson) of the nonvolatile residuum (ASTM
D-189, ASTM D-2416) and therefore serves to indicate the asphalt content of each
residuum and, thus, the content of each crude oil. By combining these chemical
Reciprocal of the Boiling Point, Kelvin x 1,000
Specific Gravity, 60/6O 0 F
Figure 3.5. Reference data for the correlation index (from Speight, 1999).
indications with a qualitative expression of the results achieved by conventional
refining, reasonable assessment can be obtained of a petroleum in relation to both
composition and application.
Density (specific gravity) (Chapter 4) has been, since the early years of the industry,
the principal and often the only specification of crude oil products and was taken
as an index of the proportion of gasoline and, particularly, kerosene present. As
long as only one kind of petroleum was in use the relations were approximately
true, but as crude oils with other properties were discovered and came into use,
the significance of density measurements disappeared. Nevertheless, crude oils of
particular types are still rated by gravity, as are gasoline and naphtha within certain
limits of other properties.
High paraffins, naphthenes
High aromatics
Figure 3.6. Correlation index and crude oil composition.
The use of density values has been advocated for quantitative application with
a scheme based on the American Petroleum Institute (API) gravity of the 250275C (480- 525F, 760 mm) and the 275-3000C (525-5700F, 40 mm) distillation
fractions (Table 3.2). Indeed, investigation of crude oils from worldwide sources
showed that 85% fell into one of the three classes: paraffin base, intermediate
base, or naphthene base.
Classification of heavy oils according to characterization gravity also has been
proposed. This is defined as the arithmetic average of the instantaneous specific
gravity of the distillates boiling at 177C (350F), 232C (4500F), and 288C
(5500F) vapor line temperature at 25-mm pressure in a true boiling point distillation.
In addition, a method of petroleum classification based on other properties,
as well as the density, of selective fractions has been developed. The method
consists of a preliminary examination of the aromatic content of the fraction
boiling up to 145C (295F), as well as that of the asphaltene content, followed
by a more detailed examination of the chemical composition of the naphtha (bp
<200C, <390F). For this examination, a graph is used that is a composite of
curves expressing the relation between percentage distillate from the naphtha, the
aniline point, refractive index, specific gravity, and the boiling point. The aniline point after acid extraction is included to estimate the paraffin-to-naphthene
ratio.
Conventional crude oil and heavy oil have also been defined very generally in
terms of physical properties. For example, the class of heavy oils was considered
Table 3.2. Classification According to API Gravity (Adapted from Speight, 1999)
250-2700C
480-520 0 F
525-5700F
Naphthene
Paraffin-intermediate
Intermediate-paraffin
Intermediate-naphthene
Naphthene-intermediate
Paraffin-naphthene
Naphthene-paraffin
to be those petroleum-type materials that had gravity somewhat less than 20 API,
with the heavy oils falling into the API gravity range of 10-15 (e.g., Cold Lake
crude oil =12 API) and bitumen falling into the 5-10 API range (e.g., Athabasca
bitumen = 8 API). Residua vary depending on the temperature at which distillation is terminated. Atmospheric residua are usually in the 10-15 API range, and
vacuum residua are in the range of 2-8 API (Speight, 2000).
There have been several recent noteworthy attempts to classify crude oil
(Bestougeff et al., 1984; Danyluk et al., 1984; Gibson, 1984; Khayan, 1984) using
one or more of the general physical properties of crude oils. One method uses
divisions by API gravity, which is generally used by most workers, and also uses
viscosity data (Khayan, 1984). This method is essentially a more formal attempt
in which specific numbers are applied (Fig. 3.7).
Several attempts have been made to discriminate or classify heavy oil and
bitumen on the basis of viscosity. For example, it has been recommended that
Viscosity, mPa, cP
Density, kg/m3
Gravity, 0API
Figure 3.7. Viscosity-density relationship of crude oil, heavy oil, and bitumen (from Speight, 1999).
viscosity data be applied to differentiate between petroleum and tar sand bitumen
(Khayan, 1984), thereby offering a means of classifying these two natural products.
The viscosity cutoff point is suggested to be 10,000 centipoises (cp), below which
the material is classified as petroleum and above which the material is classified
as tar sand bitumen. This method is essentially a more formal attempt in which
specific numbers are applied. In addition, the scale can be used for other feedstocks,
such as the conventional petroleum and residua. However, as already noted (page
61), petroleum classification (or, for that matter, any classification system) that is
based on a single measurement is at the mercy of the analyst and the errors that
are inherent in the method.
The line demarcation of 10,000 cp is impractical because there is no one property of a hydrocarbon that can be used to define tar sand bitumen. In addition, the
use of 10,000 cp as the line of demarcation is difficult to accept. Publication in
conference proceedings and in books, where it is used for discussion purposes,
is not a sign of accuracy or general acceptance. Rather, these publications show
that the advisability of the 10,000 cp line has been a topic of for question. Indeed,
the accuracy (reproducibility or repeatability or precision) of the determination
of viscosity almost refutes the use of such numbers. For example, at an accuracy of at least 5% a value of 10,000 cp is, in reality a value between 9500
and 10,500 cp. For extremely viscous materials such as bitumen the margin of
accuracy may be even higher than 5%, and therefore a greater range is represented. In fact, this indicates that a line of demarcation is of little value for these
Indeed, in the author's experience, if viscosity were to be accepted as part of
the definition, any such line of demarcation would have to be much higher (at least
on the order of 50,000 cp or even 100,000 cp). However, this still does not move
away from the use of a single physical property that is subject to errors that are
inherent in the method of measurement.
Carbon Distribution
A method for the classification of crude oils can only be efficient, first, if it indicates
the distribution of components according to volatility, and second, if it indicates one
or more characteristic properties of the various distillate fractions. The distribution
according to volatility has been considered the main property of petroleum, and
any fractionating column with a sufficient number of theoretical plates may be
used for recording a curve in which the boiling point of each fraction is plotted
against the percentage by weight.
However, for the characterization of the various fractions of petroleum, the use
of the n-d-M method [n = refractive index, d = density, M = molecular weight
(Chapter 11)] is suggested. This method enables determination of the carbon distribution and thus indicates the percentage of carbon in aromatic structure (%CA),
the percentage of carbon in naphthenic structure (%CN), and the percentage of
carbon in paraffinic structure (%Cp). The yields over the various boiling ranges
can also be estimated; for example, in the lubricating oil fractions the percentage
of carbon in paraffinic structure can be divided into two parts, giving the percentage of carbon in normal paraffins (%CnP) and the percentage of carbon in
paraffinic side chains. The percentage of normal paraffins present in lubricating
oil fractions can be calculated from the percentage of normal paraffinic carbon
(%Cnp) by multiplication by a factor that depends on the hydrogen content of the
fractions.
It is also possible to extrapolate the carbon distribution to the gasoline range on
the one hand and to the residue on the other hand. A high value of %CA at 5000C
(9300F) boiling point usually indicates a high content of asphaltenes in the residue,
whereas a high value of %Cnp at 5000C (9300F) boiling point usually indicates a
waxy residue.
Viscosity-Gravity Constant
This parameter, along with the Universal Oil Products characterization factor,
has been used to some extent as a means of classifying crude oils. Both
parameters are usually used to give an indication of the paraffinic character
of the crude oil, and both have been used, if a subtle differentiation can be made,
as a means of petroleum characterization rather than for petroleum classification.
Nevertheless, the viscosity-gravity constant was one of the early indices proposed to characterize (or classify) oil types:
vgc = 10J - 1.07521og(v - 38)/10 - log(v - 38)
where d is the specific gravity 60/60F and v is the Saybolt viscosity at 39C
(1000F). For heavy oil where the low-temperature viscosity is difficult to measure,
an alternative formula,
vgc = d - 0.24 - 0.022log(v - 35.5)/0.755
has been proposed in which the 99C (2100F) Saybolt viscosity is used. The two do
not agree well for low-viscosity oils. However, the viscosity-gravity constant is of
particular value in indicating a predominantly paraffinic or cyclic composition. The
lower the index number, the more paraffinic is the stock; for example, naphthenic
lubricating oil distillates have vgc = 0.876 and the raffinate obtained by solvent
extraction of lubricating oil distillate has vgc ~ 0.840.
UOP Characterization Factor
This factor is perhaps one of the more widely used derived characterization or
classification factors and is defined by the formula
K =
^TB/d
where TB is the average boiling point in degrees Rankine (0F + 460) and d is the
specific gravity 60/600F. This factor has been shown to be additive on a weight
basis. It was originally devised to show the thermal cracking characteristics of
heavy oils; thus, highly paraffinic oils have K % 12.5-13.0 and cyclic (naphthenic)
oils have K ^ 10.5-12.5.
Finally, all the classification systems mentioned here are based on the assumption that an oil can be more or less characterized by the properties of one or a few
fractions. However, the properties of certain fractions of a crude oil are definitely
not always reflected in those of other fractions of the same oil. Indeed, some crude
oils have a different chemical character in low-boiling and high-boiling fractions,
and any method of classification in which the properties of a certain fraction are
extrapolated to the whole crude oil must be applied with caution because serious
errors can arise.
In fact, it appears unlikely that it will ever be possible to have a single classification method that will accommodate all crude oils. It is usually necessary to
combine a boiling range analysis with the carbon distribution in the various fractions to gain a reasonable perspective of the crude, which even then gives only an
estimation of the division of products that might be expected in the refinery.
Predicting the behavior of crude oil during production and refining operations requires a detailed knowledge of the structure of crude oil (Chapter 14). The classical
approach of correlating properties with structural types has proved to be of some
value. However, determining the structural types that will dominate the properties
of crude oil is often difficult. Thus other classification systems have evolved.
For example, crude oil can be assessed or defined by its relative distillation
characteristics (Table 3.3), but the properties and character of a residuum from
any particular petroleum depend on the temperature at which the distillation of
the volatile constituents is terminated. Nevertheless, these materials are very difficult to classify because the constituents of heavy oils and residua fall into a
boiling range in which very little is known about the individual model compounds
(Speight, 1999).
Table 3.3. Properties of Tia Juana Crude Oil and Its 6500F, 9500F, and 10500F
Residua (Adapted from Speight, 1999)
Residua
Whole Crude
Yield, vol. %
Sulfur, wt. %
Nitrogen, wt. %
Carbon residue, wt. %
at 100F
at 2100F
Furol
at 21O0F
Pour point, F
950 0 F +
10500F+
It is even more confusing when an increase in boiling point is directly equated
to an increase in the number of rings. Such a system often fails to acknowledge
that an increase in boiling point of any ring compound can also (and more likely
in the case of petroleum constituents) be equated to an increase in the number or
size of the alkyl substituents on the ring.
Another classification method (Burg et a l , 1997) involves the use of chromatographic data. This method evaluates the individual interactions that can take place
at the molecular level and determines the strength of these interactions. The result
is the classification of crude oil on the basis of polarity and relation of polarity to
The United States has defined tar sands as set forth in the 1976 Federal Energy
Administration Ruling (FEA, 1976) that captures the meaning of both tar sand and
tar sand bitumen as
. . . the several rock types that contain an extremely viscous hydrocarbon which is not recoverable in its natural state by conventional oil well production methods including currently
used enhanced recovery techniques. The hydrocarbon-bearing rocks are variously known
as bitumen-rocks oil, impregnated rocks, tar sands, and rock asphalt.
In this definition, the terms must be used in context. For example, removing
specific words such as extremely viscous or natural state does not accomplish
anything. The term extremely viscous cannot be quantified on its own or out of
context and the term natural state as it is applied in the definition is interpreted to
mean composition. Indeed, it is almost as though the formulators of the definition
were looking at the bitumen recovery operations in Canada for guidance insofar as
the Canadian bitumen recovery operations defined bitumen. On the other hand, the
generic term heavy oil is often applied to a petroleum that has an API gravity of less
than 20, and those petroleum materials having an API gravity less than 10 have
been referred to as bitumen. Following from this convenient, but questionable,
generalization, there has also been an attempt to classify petroleum, heavy oil, and
tar sand bitumen using a modified API gravity or viscosity scale.
Use of such a scale would require a fine line of demarcation between the various
crude oils, heavy oils, and bitumen to the point where it would be confusing to
have to differentiate between a material having a viscosity of 9950 cp and one
having a viscosity of 10,050 cp. Furthermore, the inaccuracies (i.e., the limits of
experimental error) of the method of measuring viscosity also increase the potential
for misclassification. The question of the classification of an oil having a viscosity
of 10,000 cp would generate considerable discussion.
The same rationale can be applied to the use of API gravity where the difference
between an oil having an API gravity of 9.9 and an oil having an API gravity of
10.1 is very questionable. One also has to wonder how an oil with an API gravity
of 10.0 might be classified!
To classify petroleum, heavy oil, and bitumen, the use of a single parameter
such as viscosity is not enough. Various other properties, perhaps such as API
gravity, viscosity, elemental analysis, composition, and (more appropriately) the
properties of the fluid in the reservoir as well as the method of recovery must be
acknowledged.
As defined earlier (Chapter 1), bitumen is a naturally occurring material that is
found in deposits in which the permeability is low and passage of fluids through
the deposits can only be achieved by prior application of fracturing techniques.
Tar sand bitumen is a high-boiling material with little, if any, material boiling
below 3500C (6600F), and the boiling range approximates the boiling range of an
atmospheric residuum. It might also be added that the deposits in which bitumen
is found require prior fracturing techniques to overcome the low permeability and
allow the passage of fluids.
Any attempt to classify petroleum, heavy oil, and bitumen on the basis of a single
property is no longer sufficient to define the nature and properties of petroleum and
petroleum-related materials, perhaps being an exercise in futility. Such an attempt
would be analogous to classifying the human race on the basis of the physical
characteristics of a sumo wrestler, thereby omitting many other anthropological
Tar sand bitumen is a naturally occurring material that is immobile in the deposit
and cannot be recovered by the application of enhanced oil recovery technologies,
including steam-based technologies. On the other hand, heavy oil is more mobile
in the reservoir than bitumen and can be recovered by the application of enhanced
oil recovery technologies, including steam-based technologies.
The most significant property of bitumen is its immobility under the conditions
of temperatures and pressure in the deposit. Although the interrelated properties
of API gravity (ASTM D-287) and viscosity (ASTM D-445) may present an indication of the mobility of oil or immobility of bitumen, these properties offer
subjective descriptions of the oil in the reservoir; the most pertinent and objective
representation of this oil or bitumen mobility is the pour point (ASTM D-97).
In fact, the pour point of an oil, when used in conjunction with the reservoir
temperature, gives a better indication of the condition of the oil in the reservoir
than the viscosity. Thus the pour point and reservoir temperature present a more
accurate assessment of the condition of the oil in the reservoir, being an indicator
of the mobility of the oil in the reservoir.
By definition, the pour point is the lowest temperature at which oil will move,
pour, or flow when it is chilled without disturbance under definite conditions
(ASTM D-97).
Most known Canadian tar sand deposits have natural temperatures above the
pour point of the bitumen contained therein, and the bitumen has a viscosity in
excess of 100,000 cp at reservoir temperatures; the bitumen is plastic to semisolid
and is immobile in the deposit.
When used in consideration with reservoir temperature, the pour point gives an
indication of the liquidity of the heavy oil or bitumen and, therefore, the ability of
the heavy oil or bitumen to flow under reservoir conditions. In summary, the pour
point is an important consideration because, for efficient production, additional
energy must be supplied to the reservoir by a thermal process to increase the
reservoir temperature beyond the pour point.
For example, Athabasca bitumen with a pour point in the range of 50-1000C
(122-212F) and a deposit temperature of 4-10 0 C (39-50F) is a solid or near
solid in the deposit and will exhibit little or no mobility under deposit conditions.
Pour points of 35-600C (95-1400F) have been recorded for the bitumen in Utah
with formation temperatures on the order of 100C (500F). This indicates that the
bitumen is solid within the deposit and therefore immobile. The injection of steam
to raise and maintain the reservoir temperature above the pour point of the bitumen
and to enhance bitumen mobility is difficult, in some cases almost impossible.
Conversely, when the reservoir temperature exceeds the pour point the oil is
fluid in the reservoir and therefore mobile. The injection of steam to raise and
maintain the reservoir temperature above the pour point of the bitumen and to
enhance bitumen mobility is possible, and oil recovery can be achieved.
A method that uses the pour point of the oil and the reservoir temperature adds a
specific qualification to the term "extremely viscous" as it occurs in the definition
Table 3.4. Attempted Classification of Bitumen
(Adapted from Speight, 1999)
Maceral
Ozocerite
Gilsonite
Glance pitch
Grahamite
Impsonite
Wurtzilite
Albertite
Epi-impsonite
Meso-impsonite
Cata-impsonite
Migrabitumen
of tar sand. The general applicability of the comparison of the two temperatures
shows promise and warrants further consideration.
A recent attempt (Jacob, 1989) has been made to classify migrabitumen
(Table 3.4). The term migrabitumen signifies a secondary bitumen (or, to use
coal terminology, a secondary maceral) that has been generated from fossil organic material during diagenesis and catagenesis (Hunt, 1996). Perhaps this is one
of the few subgroups of the petroleum-type materials that can be classified with
any degree of accuracy. Their properties are sufficiently different to allow such a
classification.
There have also been several attempts to classify kerogen in addition to the
general type classification that already exists. However, an interesting set of criteria derived from pyrolysis-gas chromatography (Horsfield, 1984) has shown that
hydrocarbon generation can be quantified. It is also interesting to note from this
work that hydrogen deficiency in the original kerogen is not directly equated to
a low oil-producing propensity. This and other work will not only assist in more
accurate descriptions (classification) of kerogen but also offers the potential for a
more detailed description of organic facies).
ASTM. 1998 Annual Book of ASTM Standards. American Society for Testing and Materials,
Bestougeff, M. 1967. In: Fundamental Aspects of Petroleum Geochemistry. B. Nagy and
U. Colombo (Editors). Elsevier, Amsterdam. Chapter 3.
Burg, P., Selves, J. L., and Colin, J. P. 1997. Fuel 76: 85.
Colombo, U. 1967. In: Fundamental Aspects of Petroleum Geochemistry. B. Nagy and
Considine, D. M., and Considine, G. D. 1984. Encyclopedia of Chemistry. 4th Edition. Van
Nostrand Reinhold, New York.
Costantinides, G., and Arich, G. 1967. In: Fundamental Aspects of Petroleum Geochemistry.
B. Nagy and U. Colombo (Editors). Elsevier, Amsterdam. Chapter 4.
Danyluk, M. D., Galbraith, B. E., and Omana, R. A. (1984). In: The Future of Heavy
Crude and Tar Sands. R. F. Meyer, J. C. Wynn, and J. C. Olson (Editors). McGraw-Hill,
New York. p. 3.
FEA. 1976. Public Law FEA-76-4. Federal Energy Administration, Washington, DC.
Fessenden, R. J., and Fessenden, J. S. 1990. Organic Chemistry. 4th Edition. Brooks/Cole
Publishing, Pacific Grove, CA.
Gibson, B. J. (1984). The Future of Heavy Crude and Tar Sands. R. F. Meyer, J. C. Wynn,
and J. C. Olson (Editors). McGraw-Hill, New York. p. 17.
Gruse, W. A., and Stevens, D. R. (1960). The Chemical Technology of Petroleum. McGrawHill, New York.
Hessley, R. A. 1990. In: Fuel Science and Technology Handbook. J. G. Speight (Editor).
Marcel Dekker, New York. Chapter 19.
Hobson, G. D., and Pohl, W. 1973. Modern Petroleum Technology. 4th Edition. Applied
Science Publishers, Barking, England.
Horsfield, B. (1984). In: Advances in Geochemistry. J. Brooks and D. Welte (Editors). 1:
Hunt, J. M. (1996). Petroleum Geochemistry and Geology. 2nd Edition. W. H. Freeman,
ITAA. 1936. Income Tax Assessment Act. Government of the Commonwealth of Australia.
Jacob, H. (1989). Int. J. Coal Geol. 11: 65.
Khayan, M. (1984). The Future of Heavy Crude and Tar Sands. R. F. Meyer, J. C. Wynn,
and J. C. Olson (Editors). McGraw-Hill, New York. p. 7.
Lowry, H. H. 1945. (Editor). Chemistry of Coal Utilization. John Wiley & Sons, New York.
Volumes I and II.
Supplementary Volume.
Meyers, R. A. 1981. In: Coal Handbook. R. A. Meyers (Editor). Marcel Dekker, New York.
p. 7 et seq.
Morrison, R. T., and Boyd, R. N. 1973. Organic Chemistry. 3rd Edition. Allyn and Bacon,
Boston, MA. p. 40.
Nelson, W. L. 1958. Petroleum Refinery Engineering. 4th Edition. McGraw-Hill, New York.
Ray, R. M., Brashear, J. P., and Biglarbigi, K. 1991. Oil Gas J. September 30. p. 89.
Roberts, J. D., and Caserio, M. C. 1964. Basic Principles of Organic Chemistry. W. A.
Benjamin, New York.
Sachanen, A. N. 1945. The Chemical Constituents of Petroleum. Reinhold Publishing, New
Speight, J. G. 1990. In: Fuel Science and Technology Handbook. Marcel Dekker, New York.
Chapters 12-16.
Speight, J. G. 1994. The Chemistry and Technology of Coal. 2nd Edition. Marcel Dekker,
Speight, J. G., Wernick, D. L., Gould, K. A., Overfleld, R. E., Rao, B. M. L., and Savage,
D. W. 1985. Rev. Inst. Francais Petrole. 40: 27.
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McGraw-Hill, New York. p. 3-12.
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Van Nes, K., and van Westen, H. A. (1951). Aspects of the Constitution of Mineral Oils,
Elsevier, Amsterdam.
Petroleum, heavy oil, and bitumen exhibit a wide range of physical properties,
but whereas the properties such as viscosity, density, boiling point, and color of
petroleum, heavy oil, and bitumen vary widely, the elemental (ultimate) analysis
varies over only a narrow range for a large number of samples. In fact, relative to
another fossil energy resource (coal), the carbon content is fairly constant.
The hydrogen and heteroatom contents vary to a greater extent than the carbon
content and are often considered to be responsible for the major differences among
petroleum, heavy oil, and bitumen. However, this does not take into consideration
the relative volatility of the various constituents of these three feedstocks. Nitrogen,
oxygen, and sulfur can be present in only trace amounts in some petroleum, which
as a result consists primarily of hydrocarbons. In fact, bitumen containing 9.5% by
weight heteroatoms may contain very few, if any, true hydrocarbon constituents
because as the constituents contain at least one or more nitrogen, oxygen, and/or
sulfur atoms within the various molecular structures. Coupled with the changes to
the feedstock constituents brought about by refinery operations, it is not surprising
that petroleum characterization is a monumental task.
Refinery processes can be conveniently divided into three fundamentally different types (Fig. 4.1):
separation: division of the feedstock into various streams (or fractions) depending on the nature of the crude material;
conversion: the production of salable materials from the feedstock by skeletal alteration, or even by alteration of the chemical type of the feedstock
constituents; and
finishing: purification of the various product streams by a variety of processes
that remove impurities from the product.
In some cases, a fourth category can be added that includes processes such as
the reforming {molecular rearrangement) processes. For the purposes of this text,
Alkylation
LPG,
Fuel Gas,
Hydrofiner
Atm.
Hydrocracker
Gat Cracker
Kerosene,
Mid-Distillate
Naphtha,
Visbreaker
Cat Cracker
Gasoline,
Light Ends
Deasphalter
Aromatic Oil
Lube Oil,
Wax,
Figure 4.1. Schematic representation of a petroleum refinery (from Speight, 1999).
Table 4.1. Elemental Ratios for Various Fossil Fuels
Carbon Hydrogen Nitrogen Oxygen Sulfur
s/c
o/c
Wt% Atomic Atomic Atomic Atomic
Qayarah
(Iraq)
reforming (etc.) processes are included in the finishing processes because that is
precisely what they are, processes designed to finish various refinery streams and
render the products ready for sale.
The analytical chemist attached to a refinery or process research laboratory
must be able to respond to the requirements of each of the above process categories through use of a variety of analytical methods that produce data for process
predictability and monitoring. The data must be acquired by methods that are quantitatively reproducible and offer a high degree of precision. As a side comment,
one must question the value of any method that might be reproducible but only
offers accuracy to within 10% above or below the true value; that is, a mean data
point that offers 10% variability is of very questionable value.
Although it is possible to classify refinery operations using the general categories outlined above, the behavior of various feedstocks in refinery operations is
not simple. The atomic ratios from ultimate analysis (Table 4.1) can give an indication of the nature of a feedstock and the generic hydrogen requirements needed
to satisfy the refining chemistry (Speight, 1999). Despite this apparent benefit of
knowing the atomic ratios, it is difficult, if not impossible, to predict with any degree
of certainty how the feedstock will behave during refining. Any deductions made
from data such as the atomic ratios are speculative and are open to much doubt.
The chemical composition of a feedstock is a much truer indicator of refining
behavior. Whether the composition is represented in terms of compound types
or in terms of generic compound classes, it can offer the refiner a measure of
predictability through an understanding of the nature of refinery chemistry. Hence,
chemical composition not only plays a large part in determining the nature of the
products that arise from the refining operations but also plays a role in determining
the means by which a particular feedstock should be processed (Nelson, 1958;
Gary and Handwerk, 1975; AIi et al., 1985; Wallace et al., 1988; Speight, 2000).
In another way, the judicious choice of a crude oil to produce any given product
is just as important as the selection of the product for any given purpose. Thus
initial inspection of the nature of the petroleum will provide deductions about the
most logical means of refining or correlation of various properties to structural
types present. In addition, petroleum evaluation using physical property data is a
major part of the initial study of any petroleum destined as a refinery feedstock.
Proper interpretation of the data resulting from the inspection of crude oil requires
an understanding of their significance. In this chapter, an indication of the physical
properties that may be applied to petroleum, or even petroleum product, evaluation
will be presented.
To satisfy specific needs with regard to the type of petroleum to be processed,
as well as to the nature of the product, most refiners have, over time, developed
their own methods of petroleum analysis and evaluation. However, such methods
are considered proprietary and are not normally available. Consequently, various
standards organizations, such as the American Society for Testing and Materials
(ASTM, 1998) in North America and the Institute of Petroleum in Britain (IP,
1999), have devoted considerable time and effort to the correlation and standardization of methods for the inspection and evaluation of petroleum and petroleum
products. A complete discussion of the large number of routine tests available
for petroleum fills an entire book (ASTM, 1998). However, it seems appropriate
that in any discussion of the physical properties of petroleum and petroleum products reference be made to the corresponding test, and accordingly the various test
numbers have been included in the text.
As indicated elsewhere (Speight, 1999, 2000), petroleum is an exceedingly
complex and structured mixture consisting predominantly of hydrocarbons and
containing sulfur, nitrogen, oxygen, and metals as minor constituents. As a result of this complexity, the importance of the correct sampling of either liquefied
petroleum gases (ASTM D-1265) or liquid petroleum (ASTM D-270), heavy oil,
and bitumen (Wallace, 1988) cannot be overstressed. Properties such as elemental
analysis, metal content, density (specific gravity), and viscosity, to mention only a
few properties, are affected by the homogeneity (or heterogeneity) of the sample.
In addition, adequate records of the circumstances and conditions during sampling
must be made; for example, in sampling from oilfield separators, the temperatures
and pressures of the separation plant and the atmospheric temperature would be
noted. An accurate sample handling and storage log should be maintained and
should include information such as:
1. The precise source of the sample, i.e., the exact geographic location or
refinery locale from which the sample was obtained.
A description of the means by which the sample was obtained.
The protocols that have been used to store the sample.
Chemical analyses, such as elemental composition.
Physical property analyses, such as API gravity, pour point, distillation profile, etc.
6. The (ASTM) methods used to determine the properties in items 4 and 5.
7. The number of times that the samples have been retrieved from storage to
extract a portion, i.e., indications of exposure to the air or oxygen.
Attention to factors such as these enables standardized comparisons to be made
when subsequent samples are taken.
However, before this occurs several protocols are involved in initial isolation and
clean up of the sample. In fact, considerable importance attaches to the presence
of water or sediment in crude oil (ASTM D-1796, ASTM D-4007) because they
lead to difficulties in the refinery, for example, corrosion of equipment, uneven
running on the distillation unit, blockages in heat exchangers, and adverse effects
on product quality.
The sediment consists of finely divided solids that may be dispersed in the
oil or carried in water droplets. The solids may be drilling mud or sand or scale
picked up during the transport of the oil or may consist of chlorides derived from
evaporation of brine droplets in the oil. In any event, the sediment can lead to
serious plugging of the equipment, corrosion due to chloride decomposition, and
a lowering of residual fuel quality.
Water may be found in the crude either in an emulsified form or in large droplets
and can cause flooding of distillation units and excessive accumulation of sludge
in tanks. The quantity is generally limited by pipeline companies and by refiners,
and steps are normally taken at the wellhead to reduce the water content as low
as possible. However, water can be introduced during shipment and, in any form,
water and sediment are highly undesirable in a refinery feedstock; the relevant
tests (ASTM D-96, ASTM D-954, ASTM D-1796, IP 75) are regarded as important in crude oil quality examinations. Before assay it is sometimes necessary
to separate the water from a crude oil sample, and this is usually carried out by
one of the procedures described in the preliminary distillation of crude petroleum
(IP 24).
Heavy oil and bitumen often form persistent emulsions that are difficult to
separate, and in testing wax-bearing crude oils for sediment and water care must
be taken to ensure that wax suspended in the sample is brought into solution before
the test; otherwise, it will be recorded as sediment. Careful sampling of a crude
oil is necessary when examination must be made for suspended impurities of the
type discussed.
There is a great variation in the salt content of crude oil depending mainly on the
source and possibly on the producing wells or zones within a field. In addition, at
the refinery, salt water introduced during shipment by tanker may have contributed
to this total salt content. These salts have adverse effects on refinery operations
especially in increasing maintenance following corrosion in crude units and heat
exchangers. It is common practice to monitor wells in a producing field for high
salt content, and it is also general practice to desalt the crude at the refinery. The
determination of the salt content of crude oil is often made, but as with water and
sediment tests, careful sampling is necessary. It would appear that further tests
to determine the corrosiveness due to the individual chemical components of the
"salt" and also a determination of the extent of evolution of hydrogen chloride on
heating would be desirable.
The physical and chemical characteristics of petroleum, heavy oil, and bitumen and the yields and properties of products or fractions prepared from them
vary considerably and are dependent on the concentration of the various types of
hydrocarbons and minor constituents present crude oil. Some types of petroleum
have economic advantages as sources of fuels and lubricants with highly restrictive
characteristics because they require less specialized processing than that needed
for production of the same products from many types of crude oil. Others may
contain unusually low concentrations of components that are desirable fuel or lubricant constituents, and the production of these products from such crude oils
may not be economically feasible.
In the current context, the evaluation of petroleum, heavy oil, or bitumen
for use as a feedstock usually involves an examination of one or more of the
physical properties of the material. By this means, a set of basic characteristics
can be obtained that can be correlated with utility. The physical properties of
petroleum and petroleum products are often equated with those of the hydrocarbons because, although petroleum is indeed a very complex mixture, there is
gasoline, produced by nondestructive distillation (straight-run gasoline), in which
fewer than a dozen hydrocarbons make up at least 50% of the material (Speight,
1999). However, for the purposes of this chapter, data relating to various physical properties have been included as illustrative examples, but theoretical discussions of the physical properties of hydrocarbons were deemed irrelevant and are
Over the past three decades, the overall character of the feedstocks entering
refineries has changed to such an extent that the difference can be measured by a
decrease of several points on the API gravity scale. Consequently, there has been
an increasing need for refineries to accept heavy oil and bitumen as part of the
refinery feedstock inventory. This has, of course, seen an increase in the need to
understand the analytical aspects of these heavier feedstocks. Thus, where possible,
information is included here that relates to the properties and processability of
heavy oil and bitumen.
4.2. ELEMENTAL (ULTIMATE) ANALYSIS
As already indicated (Chapter 2), the atomic ratios of the elements in various
feedstocks have been used as a measure of the general amounts of hydrogen
used to convert the feedstock to a given slate of products. In fact, the analysis
of petroleum for the percentages of carbon, hydrogen, nitrogen, oxygen, and sulfur is perhaps the first method used to examine the general nature and perform
an evaluation of a feedstock. The atomic ratios of the various elements to carbon
(i.e., H/C, N/C, O/C, and S/C) are frequently used for indications of the overall
character of the feedstock as well as the hydrogen requirements to convert the
heteroatoms to their hydrogen analogs (NH3, H2O, H2S). The H-to-C ratio has
been of particular use in the past as a means of estimating the aromaticity of
feedstocks. This ratio finds less use now because of the influx of heavier feedstocks into refineries as well as the need for more accurate estimation of feedstock
However, elemental analysis is still of considerable value in determining the
amounts of elements in feedstocks, especially the trace elements such as vanadium
and nickel, because these materials can have serious deleterious effects on catalyst
performance during refining by catalytic processes. Indeed, one may wonder about
the utility or futility of measuring elements that are present in trace amounts. However, considering the nature of many continuous (as opposed to batch) processes
in which a feedstock might be recycled to extinction and blended on the way with
fresh feedstock (until no more of the desired product is made), the concentration
of the trace elements (metals) on the catalyst can become sufficient to modify, if
not completely change, the catalyst's behavior and efficiency.
It has also become apparent, with the introduction of the heavier feedstocks into
refinery operations, that these ratios are not the only requirement for predicting
feedstock character before refining. The use of more complex feedstocks (in terms
of chemical composition) has added a new dimension to refining operations. Thus,
although atomic ratios, as determined by elemental analyses, may be used on a
comparative basis between feedstocks, there is now no guarantee that a particular feedstock will behave as predicted from these data. Product slates cannot be
predicted accurately, if at all, from these ratios.
The ultimate analysis (elemental composition) of petroleum is not reported to
the same extent as that for coal (Speight, 1994). However, of the data that are
available, the proportions of the elements in petroleum vary only slightly over
narrow limits:
Carbon 83.0-87.0%
Hydrogen 10.0-14.0%
Nitrogen 0.1-2.0%
Oxygen 0.05-1.5%
Sulfur 0.05-6.0%
However, there is a wide variation in physical properties from the lighter, more
mobile crude oils at one extreme to the heavier asphaltic crude oils at the other
extreme. The majority of the more aromatic species and the heteroatoms occur in
the higher-boiling fractions of feedstocks. The heavier feedstocks are relatively
rich in these higher-boiling fractions.
The carbon and hydrogen content is often combined with nuclear magnetic
resonance data to produce average structures. Some comment on the utility or
futility of this aspect of petroleum analysis is made elsewhere (Chapters 11 and 14).
As with coal, there are several ASTM procedures (ASTM, 1998) that can be
applied to the ultimate analysis of petroleum and petroleum products, but many
such methods may have been designed for other materials. Indeed, some of these
methods are used for the elemental analysis of coal.
For example, carbon content and hydrogen content can be determined simultaneously by the method designated for coal and coke (ASTM D-3178) or by the
method designated for municipal solid waste (ASTM E-IIl). Indeed, the latter
method is also suitable for the determination of carbon and hydrogen in heavy oil
and bitumen.
The principles behind carbon and hydrogen analysis have remained relatively
unchanged as the methods have become more automated. However, the precision of the analysis of heavy oil, bitumen, and residua may be much poorer
than anticipated. This may be related not only to the character of the sample
but also to sample size. The use of more controlled combustion conditions as
well as the incorporation of corrections for the presence of solids and water are
Thus the method chosen for the analysis may be subject to the peculiarities
or character of the feedstock under investigation and should be assessed in terms
of accuracy and reproducibility. The methods that are designated for elemental
analysis are:
1. carbon and hydrogen content (ASTM D-1018, ASTM D-3178, ASTM
D-3343, ASTM D-3701, ASTM D-5291, ASTM E-777, IP 338);
2. nitrogen content (ASTM D-3179, ASTM D-3228, ASTM D-3431, ASTM
E-148, ASTM E-258, ASTM D-5291, and ASTM E-778);
3. oxygen content (ASTM E-385), and
4. sulfur content (ASTM D-124, ASTM D-129, ASTM D-139, ASTM
D-1266, ASTM D-1552, ASTM D-1757, ASTM D-2622, ASTM D-2785,
ASTM D-3120, ASTM D-3177, ASTM D-4045 and ASTM D-4294, ASTM
E-443, IP 30, IP 61, IP 103, IP 104, IP 107, IP 154, IP 243).
The hydrogen content of fuels and petroleum products from atmospheric distillates to vacuum residua can also be measured by low-resolution magnetic resonance spectroscopy (ASTM D-3701, ASTM D-4808). The method is claimed to
provide a simple and more precise alternative to existing test methods, specifically
combustion techniques (ASTM D-5291), for determining the hydrogen content of
a variety of petroleum-related materials.
Nitrogen occurs readily in petroleum, with higher amounts usually occurring
heavy oil and bitumen. The organically bound nitrogen compounds cause serious
problems during upgrading, especially when the levels exceed 0.5% by weight, as
happens often in heavy oil and bitumen. Nonaqueous potentiometric titration and
other methods have shown that basic nitrogen can be 35% by weight or more of
the total nitrogen in petroleum, heavy oil, and bitumen. It is this type of nitrogen
that causes poisoning of acidic and metal-containing process catalysts. In addition
to the chemical character of the nitrogen, the amount of nitrogen in a feedstock
determines the severity of the process, the hydrogen requirements, and to some
extent, the coke yield.
The determination of nitrogen in petroleum has been performed regularly by the
Kjeldahl method (ASTM D-3228), the Dumas method, and the microcoulometric (ASTM D-3431) method. The chemiluminescence method is the most recent
technique applied to nitrogen analysis for petroleum.
The chemiluminescence method determines the amount of chemically bound
nitrogen in liquid hydrocarbon samples. In this method, the samples are introduced to the oxygen-rich atmosphere of a pyrolysis tube maintained at 9750 C
(1785F). Nitrogen in the sample is converted to nitric oxide during combustion,
and the combustion products are dried by passage through magnesium perchlorate
[Mg(ClCU )2] before entering the reaction chamber of a chemiluminescence detector. In the detector, ozone reacts with the nitric oxide to form excited nitrogen
dioxide:
NO + O3 = NO2* + O 2
Photoemission occurs as the excited nitrogen dioxide reverts to the ground state:
NO2* = NO2 + hv
The emitted light is monitored by a photomultiplier tube to yield a measure of
the nitrogen content of the sample. Quantitation is based on comparison with the
response for carbazole in toluene standards.
Oxygen is one of the five (C, H, N, O, and S) major elements in heavy oil and
bitumen. Although the level in well-preserved specimens rarely exceeds 1.5% by
weight, it may still be critical to the refiner because of the potential for interaction
during refinery processes. In addition, the type of oxygen function in the material
can have an effect on recovery processes. For example, the presence of carboxylic
acids (-CO2H) can be beneficial to in situ recovery operations by causing a lowering of the interfacial tension (Section 4.6, page 118) between the oil and water.
However, such an effect can have serious drawbacks because of the formation of
stable oil-in-water emulsions that must be broken at the surface before further processing can occur. In addition, the presence of phenolic (Ar-OH) compounds can
lead to the formation of polymers and stable ethers (Ar-O-Ar) during upgrading
that accumulate on catalysts and decrease catalyst activity and efficiency. Guard
beds may be necessary to protect the catalyst.
Many petroleum products do not specify a particular oxygen content, but if
the oxygen compounds are present as acidic compounds such as phenols (ArOH) and naphthenic acids (cycloalkyl-COOH), they are controlled in different
specifications by a variety of tests (Chapters 8 and 11).
The total acidity of a sample or whole feedstock (ASTM D-974, IP 139) is
determined for many products, especially fuels, but the method may lack sufficient sensitivity for specific (military) fuels insofar as the detection of trace acidic
materials that can affect the water separation from the fuel. Various laboratories
have modified this method to accommodate this shortcoming, and there is a more
precise acidity test method (IP 273).
Oxygen-containing impurities in the form of gum are determined by the existent gum test method (ASTM D-382, IP 131) (Chapter 13) and potential gum test
method (ASTM D-873, IP 138). Elemental analysis of the gum can then provide
its composition with some indication of the elements (other than carbon and hydrogen) that played a predominant role in its formation. Functional group analysis
(Chapter 8) of the feedstock and the gum adds further valuable information that
can lead to steps being taken to mitigate gum formation.
As the third most common element in petroleum, sulfur has been analyzed extensively. Analytical methods range from elemental analyses to functional group
(sulfur-type) analyses to structural characterization to molecular speciation
Of the methods specified for the determination of sulfur (page 92), the method
applied to the corrosion effect of sulfur is extremely important for liquid fuels. In
this method (ASTM D-1266, IP 154), fuel corrosivity is assessed by the action
of the fuel on a copper strip {the copper strip test) that helps determine any discoloration of the copper due to the presence of corrosive compounds. The copper
strip is immersed in the fuel and heated at 10O0C (212F) for 2 h in a bomb. A
test using silver as the test metal (IP 227) has also been published. Mercaptans
are usually the corrosive sulfur compounds of reference, and metal discoloration
is caused by formation of the metal sulfide. Thus mercaptan sulfur is an important
property of potential fuels. In addition to the copper strip test, the mercaptan sulfur (R-SH) content (ASTM D-1219, IP 104) provides valuable information. As an
alternative to determining the mercaptan content, a negative result in the Doctor
test (ASTM D-484, IP 30) may also be acceptable for the qualitative absence of
mercaptans.
The determination of sulfur in liquid petroleum hydrocarbons by X-ray fluorescence (ASTM D-2622, IP 336) has become an extremely well-used method over
the past two decades. This method can be used to determine the amount of sulfur
in homogeneous liquid petroleum hydrocarbons over the range of 0.1-6.0% by
weight. Samples with a sulfur content above this range may be determined after
dilution in toluene.
The method utilizes the principle that when a sample is irradiated with a 55Fe
source, fluorescent X rays result. The sulfur Ka fluorescence and a background
correction at adjacent wavelengths are counted. A calibration of the instrument, in
which the integration time for counting is adjusted such that the displayed signal
for the background-corrected radiation equals the concentration of the calibration
standard, gives a direct readout of the weight percent sulfur in the sample.
The determination of sulfur with a dedicated X-ray fluorescence analyzer provides a very fast analysis for homogeneous liquid petroleum hydrocarbons. Distillation cuts provide an excellent sample for this method. The method, however, may
produce unreliable data for samples that are not homogeneous. For these samples,
a gravity separation of the solids occurs during the measurement and gives rise to
time-dependent or biased results.
A small matrix effect occurs because of absorption of the sulfur Ka radiation
by the sample matrix. The atomic hydrogen-to-carbon ratio and density of the
sulfur matrix have both been correlated with this attenuation of X-ray fluorescence,
but, in actual practice, matrix effects are minimized by the calibration procedure.
Linear calibrations for this procedure have been established up to 6% by weight
sulfur. Above this sulfur level, a small bias toward low response may occur and
has been attributed to the self-absorption of the sulfur Ka radiation. Interfering
elements include aluminum, silicon, phosphorus, chlorine, argon, and potassium.
Generally, the amounts of these elements are insufficient to affect sulfur X-ray
counts in samples covered by this method. Atmospheric argon is eliminated by a
helium purge.
It is also possible to determine nitrogen and sulfur simultaneously in petroleum
samples by chemiluminescence and fluorescence. An aliquot of the sample undergoes high-temperature oxidation in a combustion tube maintained at 10500C
(19200F). Oxidation of the sample converts the chemically bound nitrogen to nitric
oxide (NO) and sulfur to sulfur dioxide (SO2).
In the nitrogen detector, ozone reacts with the nitric oxide to form excited
nitrogen dioxide (NO2). As the nitrogen dioxide reverts to its ground state, chemiluminescence occurs and this light emission is monitored by a photomultiplier
tube. The light emitted is proportional to the amount of nitrogen in the sample. In
the sulfur detector, the sulfur dioxide is exposed to ultraviolet radiation and produces a fluorescent emission. This light emission is proportional to the amount of
sulfur and is also measured by a photomultiplier tube. Quantitation is determined
by a comparison to the responses given by standards containing carbazole and
dimethyl sulfoxide in xylene.
Oxidative microcoulometry has become a widely accepted technique for the determination of low concentrations of sulfur in petroleum and petroleum products
(ASTM D-3120). The method involves combustion of the sample in an oxygen-rich
atmosphere followed by microcoulometric generation of triiodide ion to consume
the resultant sulfur dioxide. It is intended to distinguish the technique from reductive microcoulometry that converts sulfur in the sample to hydrogen sulflde that is
titrated with coulometrically generated silver ion.
The advantages of oxidative microcoulometry include sensitivity, selectivity,
speed, linearity of response, and reasonable freedom from interference. The concentration range covered by this method is suitable for many samples in which
bitumen upgrading has resulted in considerable desulfurization. The limitation in
the sensitivity of the method described here arises from the single inlet that is
limited to a maximum sample size of about 5 JULL. The injection of larger samples
may overload the combustion capacity of the pyrolysis tube. Lower sulfur concentrations can be analyzed by controlling the sample injection rate to permit the
combustion of a larger sample volume. The injection rate may be controlled by
using the syringe injection technique or by using a controlled rate injector.
Thus the method determines the sulfur content of liquid petroleum hydrocarbons
with sulfur contents less than about 0.2 wt% and greater than 20 mg/kg and may
be adapted to determine sulfur at higher concentrations.
In this method, samples with high sulfur contents are diluted with toluene and
an aliquot is injected into the quartz boat of a single boat inlet and transferred to a
combustion tube maintained at 975C (1785F). In the presence of an 80% oxygen20% argon gas flow, the sample is oxidized and the combustion products are swept
into a titration cell where the sulfur dioxide component reacts with the triiodide ion
of the electrolyte. The triiodide consumed is coulometrically replaced. The current
required to replace the triiodide is a measure of the total sulfur present in the sample.
Although sodium azide is included in the electrolyte of the microcoulometric titration to minimize halogen and nitrogen interferences, the method is not
applicable when chlorine is present in excess of 10 times the sulfur level or the
nitrogen content exceeds 10% by weight. Heavy metals in excess of 500 mg/kg
also interfere with the method.
The typical light (conventional) petroleum contains less than 1% by weight
sulfur. However, it is the high-sulfur crude oils (>1% by weight sulfur) that represent large reserves. The range of sulfur in petroleum is, of course, attributed to
differences in the depositional environment of the original precursors, the distribution of the precursors, as well as the level of maturity. In addition, sulfur can be
incorporated into petroleum during migration from the source bed to the reservoir
as the liquids pass through sulfur-containing minerals.
The immobility of tar sand bitumen in the deposit often causes anomalous
effects in sulfur distribution. For example, gravity effects as the bitumen matures
may cause a molecular settling in which the higher-molecular-weight (heavier)
fraction of the bitumen (asphaltenes and resins) occurs in increased proportions in
deeper parts of the deposit over the proportion of the asphaltenes and resins in the
bitumen at shallower depths. Because of the higher proportion of sulfur in these
two fractions, the result will be higher proportions of sulfur in the bitumen in the
deeper parts of the deposit.
The sulfur content of petroleum varies from about 0.1 wt. % to about 3 wt. %
for the more conventional crude oils to as much as 5-6% for heavy oil and bitumen.
Residua, depending on the sulfur content of the crude oil feedstock, may be of
the same order or even have a substantially higher sulfur content. Indeed, the
very nature of the distillation process by which residua are produced, that is,
removal of distillate without thermal decomposition, dictates that the majority of
the sulfur, which is located predominantly in the higher-molecular-weight factions,
be concentrated in the residuum.
Of the ultimate analytical data, more has been made of the sulfur content than
any other property. For example, the sulfur content (ASTM D-124, D-1552, and
D-4294) and the API gravity represent the two properties that have, in the past,
had the greatest influence on determining the value of petroleum as a feedstock.
Correlations between sulfur content and other properties have been developed for a
variety of crude oil, heavy oil, and bitumen (Speight, 1999; Speight, 2000). These
correlations illustrate the various interrelationships between the various properties
of the feedstocks.
Because of the importance of sulfur measurements and the variety of methods
available, it is recommended that certified standards (specifically of heavy oil and
bitumen) be used to reduce intra- and interlaboratory errors.
4.3. METALCONTENT
Heteroatoms {nitrogen, oxygen, sulfur, and metals) are found in every crude oil,
and the concentrations must be reduced to convert the oil to transportation fuel. The
reason is that if nitrogen and sulfur are present in the final fuel during combustion,
nitrogen oxides (NOx) and sulfur oxides (SOx) form, respectively. In addition,
metals affect many upgrading processes adversely, poisoning catalysts in refining
and causing deposits in combustion.
Heteroatoms affect every aspect of refining. Sulfur is usually the most concentrated and is fairly easy to remove; many commercial catalysts are available that
routinely remove 90% of the sulfur. Nitrogen is more difficult to remove than sulfur,
and there are fewer catalysts that are specific for nitrogen. Metals cause particular
problems because they poison catalysts used for sulfur and nitrogen removal as
well as other processes such as catalytic cracking. In addition, the levels of nickel
and vanadium in petroleum, heavy oil, and bitumen must be considered by the
geochemist when the origins of petroleum, heavy oil, and bitumen are considered.
Thus the trace components that are also present in crude oils can produce adverse effects in refining by causing corrosion, by affecting the quality of refined
products, or by exerting a deleterious influence on the efficiency of various processing catalysts. This last effect has become of increasing importance because of
modern developments in refinery processing.
Heavy oils, residua, and bitumen contain relatively high proportions of metals
either in the form of salts or as organometallic constituents (such as the metalloporphyrins), which are extremely difficult to remove from the feedstock. Indeed,
the nature of the process by which residua are produced virtually dictates that
all the metals in the original crude oil are concentrated in the residuum (Speight,
2000). Those metallic constituents that may actually volatilize under the distillation conditions and appear in the higher-boiling distillates are the exceptions here.
The deleterious effect of metallic constituents on the catalyst is known particularly
through their ability to modify the selectivity of zeolite catalysts, thereby causing
an increase in the formation of coke at the expense of the more desirable liquid
products. Thus serious attempts have been made to develop catalysts that can tolerate a high concentration of metals without serious loss of catalyst activity or
catalyst life. However, for the most part, the metals concentrate in the coke formed
during thermal processes.
A number of the heavy metals such as nickel, vanadium, copper, and iron can
also be effectively bound in large organic molecules characteristic of those found
in the asphaltene fraction (pentane- or heptane-insoluble portion of the feedstock)
and resins.
Nickel and vanadium porphyrins are commonly found and show high thermal
stability that allows them to pass through the extraction process into the upgrading process. Porphyrins are the major, but certainly not the only, organometallic
complexes present. Metals may simply be entrapped or loosely bound in the very
large molecules present in the asphaltenes and resins. Although iron is present as
organometallic compounds, it occurs mostly in the form of process-accumulated
rust or is scrounged from pipelines by the crude oil during shipping and pipelining.
Thus one should not be caught up in worrying about the geochemical significance
of metal such as iron in crude oil.
Without doubt, these metals are present in petroleum, heavy oil, and bitumen,
and because catalysts are used extensively in upgrading and are readily poisoned
by such metals, it is important to know the amounts present. Significant levels
typically found in heavy oil and bitumen include nickel 20-100 ppm; vanadium
50-250 ppm; and iron 150-1000 ppm.
Vanadium compounds can cause refractory damage in furnaces and adverse
effects in glass manufacture, steel failure in turbines, as well as catalyst poisoning
when present in distillate feedstocks. Arsenic and lead are also active catalyst poisons in reforming processes, and the presence of sodium in fuel oils causes failures
in furnace brickwork. It is necessary, therefore, for crude oils and distillation unit
feedstocks to be examined for the presence of these harmful contaminants and some
form of treatment to be devised for reducing their effect during or before processing.
Thus it is important to monitor process streams for metal content for several
purposes:
1. to track the degree of potential catalyst poisoning that may occur within the
reactor caused by feed metal content;
2. to monitor the degree of catalyst physical or chemical breakdown into the
product streams; and
3. to provide one of many indicators of change in the process operation.
The analysis of process stream solids can be accomplished by several instrumental techniques: Inductively coupled argon plasma (ICAP) spectrometry, atomic
absorption (AA) spectrometry, and X-ray fluorescence (XRF) spectrometry. Each
technique has limitations in terms of sample preparation, sensitivity, sampling,
time for analysis, and overall ease of use.
Thus a variety of tests (ASTM D-482, D-1026, D-1262, D-1318, D-1368,
D-1548, D-1549, D-2547 D-2599, D-2788, D-3340, D-3341, and D-3605) measuring metals either directly or as the constituents of combustion ash have been
designated to determine metals in petroleum products based on a variety of techniques. At the time of writing, the specific test for the determination of metals in
whole feeds has not been designated. However, this task can be accomplished by
combustion of the sample so that only inorganic ash remains (ASTM D-482). The
ash can then be digested with an acid and the solution examined for metal species
by AA spectroscopy (IP 288, IP 285) or by ICAP spectrometry (ASTM C-1109,
ASTM C-I111).
AA provides very high sensitivity but requires careful subsampling, extensive
sample preparation, and detailed sample-matrix corrections. XRF requires little in
terms of sample preparation but suffers from low sensitivity and the application
of major matrix corrections. ICAP spectrometry provides high sensitivity and
few matrix corrections, but requires a considerable amount of sample preparation
depending on the process stream to be analyzed.
Whenever a technique requires ashing of the sample, one of the issues that
arises is the potential loss of volatile nickel and vanadium compounds. Both sulfuric acid and elemental sulfur have been used to prevent loss of these metals. In fact,
because of this, a wet ashing method is often preferred over dry ashing (Wallace,
The analytical method should be selected depending on the sensitivity required,
the compatibility of the sample matrix with the specific analysis technique, and the
availability of facilities. Sample preparation, if it is required, can present problems.
Significant losses can occur, especially in the case of organometallic complexes,
and contamination of environmental samples is of serious concern.
Very low-level samples such as those typically found in conventional petroleum
that may be approaching the lower levels of the parts per billion range are best
analyzed using the flameless atomic absorption method. Use of a combination
plasma atomic emission-mass spectrometry technique is becoming a more popular
analytical method for such samples.
For samples in an aqueous matrix at more moderate levels (0.1-200 ppm),
the plasma atomic emission technique is currently the most applicable. Analysis is achieved by monitoring the emission intensity of the element-specific
ultraviolet/visible radiation emitted as the sample is aspirated into the highly
energetic plasma excitation source. Excitation through air-acetylene or nitrous
oxide-acetylene flame sources may also be used for the analysis of the light alkali metals, especially potassium. Absolute concentration levels are determined
by comparison with known standards analyzed in a similar matrix. Techniques
employing excitation sources such as an arc or spark can also be used effectively
for semiquantitative analysis.
Analysis for metals in an organic matrix is most easily accomplished using
X-ray fluorescence or neutron activation techniques for quantitative analyses.
These particular techniques are also applicable to the direct analyses of oil sand
solids. Spark techniques can be used for qualitative analyses. The direct aspiration
of metal-containing hydrocarbons into the plasma instrument also provides quantitative information, with the assumption that any particulates present are included
in the analyses.
The precision of the analysis depends on the metal itself, the method used, and
the standard used for calibration of the instrument. Relative standard deviations
range from 1% to more than 20%.
In the ICAP emission spectrometer method, nickel, iron, and vanadium content
of gas oil samples in the range from 0.1 mg/kg to 100 mg/kg can be determined.
Thus a 10-g sample of gas oil is charred with sulfuric acid and subsequently
combusted to leave the ash residue. The resulting sulfates are then converted to
their corresponding chloride salts to ensure complete solubility. A barium internal
standard is added to the sample before analysis.
The ICAP spectrometer is an instrument routinely used for the analysis of the
dissolved metal composition of aqueous samples. Solid samples are prepared in
such a way (ashing and then fusion) that their final analysis matrix is in the aqueous
dissolved form. The analysis of metals in a hydrocarbon matrix, potentially containing solids important to the analysis, is a problem. The ashing of a hydrocarbon
sample containing metals (whether in organic complexes, elemental, or inorganic
complexes) can lead to analysis errors in that some of the complexes, specifically
the organometallic compounds, are in a volatile form at typical ashing temperatures
(700-80O0C, 1290-14700F). The metals in organic complexes tend to originate in
the high-molecular-weight hydrocarbons found naturally in the feed or generated
in the reactor. The inorganic metal complexes originate naturally in the feed, or
from the breakdown of catalyst or the formation of inorganic complexes under the
reactor conditions. Without ashing and subsequent fusion, any solids present may
not reach the analytical region of the instrument, resulting in analytical errors.
Using the ICAP method for the analysis of nickel, vanadium, and iron counteracts the two basic issues arising from metals analysis. The most serious issue
is the fact that these metals are partly or totally in the form of volatile, chemically stable porphyrin complexes and extreme conditions are needed to destroy
the complexes without losing the metal through volatilization of the complex. The
second issue is that the alternate direct aspiration of the sample introduces large
quantities of carbon into the plasma. This carbon causes marked and somewhat
variable background changes in all direct measurement techniques.
DENSITY, SPECIFIC GRAVITY, AND API GRAVITY
In the early days of the petroleum refining industry, density and specific gravity
data were used to:
1. Indicate crude oil quality.
2. Correlate with aromatic character, naphthenic character, and paraffinic character. The specific gravity is highest for aromatics and lowest for paraffins.
The API gravity reverses this relationship.
Thus the density and specific gravity of crude oil (ASTM D-70, ASTM D-71,
ASTM D-287, ASTM D-941, ASTM D-1217, ASTM D-1298, ASTM D-1480,
ASTM D-1481, ASTM D-1555, ASTM D-1657, ASTM D-4052, IP 235, IP 160,
IP 249, IP 365) are two properties that have found wide use in the industry for
preliminary assessment of the character of the crude oil.
In the early years of the petroleum industry, density was the principal specification for petroleum and refinery products; it was used to give a very approximate
estimation of the gasoline and (more particularly) the kerosene present in the crude
oil. However, the derived relationships between the density of petroleum and its
fractional composition were valid only if they were applied to a certain type of
petroleum and lost some of their significance when applied to different types of
petroleum. Nevertheless, density is still used to give a rough estimation of the
nature of petroleum and petroleum products.
Density is defined as the mass of a unit volume of material at a specified temperature and has the dimensions of grams per cubic centimeter (a close approximation
to grams per milliliter). Density is measured at a standard temperature, mostly 15.6
As indicated elsewhere (Chapter 2), petroleum is an exceedingly complex and
structured mixture consisting predominantly of hydrocarbons and containing sulfur, nitrogen, oxygen, and metals as minor constituents. Although sulfur has been
reported in elemental form in some crude oils, most of the minor constituents occur
in combination with carbon and hydrogen.
The physical and chemical characteristics of crude oils and the yields and
properties of products or fractions prepared from them vary considerably and are
dependent on the concentration of the various types of hydrocarbons and minor constituents present. Some types of petroleum have economic advantages as
sources of fuels and lubricants with highly restrictive characteristics because they
require less specialized processing than that needed for production of the same
products from many types of crude oil. Others may contain unusually low concentrations of components that are desirable fuel or lubricant constituents, and the production of these products from such crude oils may not be economically feasible.
Evaluation of petroleum for use as a feedstock involves an examination of
several of the physical properties of the material. It is no longer sufficient to use
one property only for evaluation purposes. Indeed, the slate of properties required
to produce evaluation data may vary from the more convenient physical inspections
(Chapter 4) to the more complex physical properties, of which some are described
in his chapter. By this means, a set of basic characteristics can be obtained that can
be correlated with utility.
Thus, for the purposes of this chapter, the tests that produce data relating to the
various thermal properties of petroleum, heavy oil, and bitumen are described. It
is these properties that provide valuable information relating to the movement of
feedstocks around a refinery as well as indications of the yields of various products.
The volatility of a liquid or liquefied gas may be defined as its tendency to vaporize,
that is, to change from the liquid to the vapor or gaseous state. Because one of the
three essentials for combustion in a flame is that the fuel be in the gaseous state,
volatility is a primary characteristic of liquid fuels. The distillation profile is also a
measure of the relative amounts of these liquid fuels (albeit unrefined) in a crude oil.
The volatility of petroleum and petroleum products is an important aspect of
safety and quality. It would be unsafe to attempt to store highly volatile materials
in the open sunlight or in an enclosed space where temperature can be in excess
of 37.80C (1000F). And yet, without any indications of when the material might
vaporize and spontaneously ignite, there is no way of even considering the correct
storage and handling conditions.
Similarly, there must also be some estimate of the ability of the constituents
of petroleum to distill from the mixture if refining is to be achieved in the most
effective manner. The distillation of crude oil has been a method of refining since
the beginning of the modern refining industry. The production of kerosene and
then the production of gasoline by distillation were integral (sometimes the only)
parts of the early methods of refining. Thus the volatility of crude oil in terms of
the amounts of the constituents' boiling fractions became a very prominent test
for crude oil quality.
However, before any volatility tests are carried out it must be recognized that
the presence of more than 0.5% water in test samples of crude can cause several
problems during distillation procedures. Water has a high heat of vaporization,
necessitating the application of additional thermal energy to the distillation flask.
Water is relatively easily superheated, and therefore excessive bumping can occur,
leading to erroneous readings and a real potential for destruction of the glass
equipment. Steam formed during distillation can act as a carrier gas and highboiling-point components may end up in the distillate (often referred to as steam
distillation).
Centrifugation can be used to remove water (and sediment) if the sample is not
a tight emulsion. Other methods that are used to remove water include:
heating in a pressure vessel to control loss of light ends;
addition of calcium chloride as recommended in ASTM D-1160;
addition of an azeotroping agent such as zso-propanol or rc-butanol;
removal of water in a preliminary low-efficiency or flash distillation followed
by reblending of the hydrocarbon that codistills with the water into the sample
(see also IP 74); and
5. separation of the water from the hydrocarbon distillate by freezing.
The vaporizing tendencies of petroleum and petroleum products are the basis for
the general characterization of liquid petroleum fuels, such as liquefied petroleum
gas, natural gasoline, motor and aviation gasoline, naphtha, kerosene, gas oil, diesel
fuel, and fuel oil (ASTM D-2715). A test (ASTM D-6; see also IP 45) also exists
for determining the loss of material when crude oil and asphaltic compounds are
heated. Another test (ASTM D-20) is a method for the distillation of road tars
that might also be applied to estimating the volatility of unknown high-molecularweight residues.
For some purposes, it is necessary to have information on the initial stage of
vaporization and the potential hazards that such a property can cause. To supply
this need, flash and fire, vapor pressure, and evaporation methods are available.
The data from the early stages of the several distillation methods are also useful.
For other uses, it is important to know the tendency of a product to partially
vaporize or to completely vaporize and, in some cases, to know whether small
quantities of high-boiling components are present. For such purposes, the chief
reliance is placed on the distillation methods.
The flash point of petroleum or a petroleum product is the temperature to which
the product must be heated under specified conditions to give off sufficient vapor
to form a mixture with air that can be ignited momentarily by a specified flame
(ASTM D-56, ASTM D-92, ASTM D-93, ASTM D-1310, ASTM D-3828, IP 34,
IP 36, IP 170, IP 303, IP 304, IP 403, 404).
The Pensky-Marten apparatus using a closed or open system (ASTM D-93,
IP 34, IP 35) is the standard instrument for flash points above 500C, and the Abel
apparatus (IP 170) is used for more volatile oils with flash points below 500C. The
Cleveland open-cup method (ASTM D-92, IP 36) is also used for the determination
of the fire point (the temperature at which the sample will ignite and burn for at
least 5 s).
The Pensky-Marten apparatus consists of a brass cup mounted in an air bath
and heated by a gas flame. A propeller-type stirrer, operated by a flexible drive,
extends from the center of the cover into the cup. The cover has four openings: one
for a thermometer, and the others fitted with sliding shutters for the introduction
of a pilot flame and for ventilation. The temperature of the oil in the cup is raised
at 5-6C/min (9-1 lF/min). The stirrer is rotated at approximately 60 rpm. When
the temperature has risen to approximately 15C (27F) from the anticipated flash
point, the pilot flame is dipped into the oil vapor for 2 s for every 10C (1.80F) rise in
temperature up to 1050C (221F). Above 1050C (221F), the flame is introduced
every 2C (3.6F) rise in temperature. The flash point is the temperature at which
a distinct flash is observed when the pilot flame meets the vapor in the cup.
The open flash point is determined after the closed flash point by removing the
cover and continuing the heating until a distinct flash occurs across the open cup.
The Abel closed-cup apparatus (IP 170) consists of a brass cup sealed in a small
water bath that is immersed in a second water bath. The cover of the brass cup is
fitted in a manner similar to that in the Pensky-Marten apparatus. For crude oils
and products with flash point < 300C (< 86F), the outer bath is filled with water
at 55C (131F) and is not heated further. The oil under test is then placed inside
the cup. When the temperature reaches 19C (66F), the pilot flame is introduced
every 0.50C (1F) until a flash is obtained. For oils with flash points in excess of
300C (>86F) and less than 500C (<122F), the inner water bath is filled with cold
water to a depth of 35 mm. The outer bath is filled with cold water and heated at
a rate of lC/min (1.8F/min). The flash point is obtained as before.
The fire point is the temperature to which the product must be heated under
the prescribed conditions of the method to burn continuously when the mixture of
vapor and air is ignited by a specified flame (ASTM D-92, IP 36).
From the viewpoint of safety, information about the flash point is of most
significance at or slightly above the maximum temperatures (30-600C, 86-1400F)
that may be encountered in storage, transportation, and use of liquid petroleum
products in either closed or open containers. In this temperature range, the relative
fire and explosion hazard can be estimated from the flash point. For products with
flash point below 400C (1040F) special precautions are necessary for safe handling.
Flash points above 600C (1400F) gradually lose their safety significance until they
become indirect measures of some other quality.
The flash point of a petroleum product is also used to detect contamination. A
substantially lower flash point than expected for a product is a reliable indicator
that a product has become contaminated with a more volatile product, such as
gasoline. The flash point is also an aid in establishing the identity of a particular
petroleum product.
A further aspect of volatility that receives considerable attention is the vapor
pressure of petroleum and its constituent fractions. The vapor pressure is the
force exerted on the walls of a closed container by the vaporized portion of a
liquid. Conversely, it is the force that must be exerted on the liquid to prevent it
from vaporizing further (ASTM D-323, IP 69). The vapor pressure increases with
temperature for any given gasoline, liquefied petroleum gas, or other product. The
temperature at which the vapor pressure of a liquid, either a pure compound or a
mixture of many compounds, equals 1 atmosphere of pressure (14.7 psi, absolute)
is designated as the boiling point of the liquid.
The Reid vapor pressure (ASTM D-323, IP 69, IP 402) is a measure of the
vapor pressure of petroleum or a petroleum product at 37.8C (1000F) expressed
as millimeters of mercury. The apparatus used to determine the Reid vapor pressure
consists of a metal cylinder, or bomb, fitted with an accurate dial pressure gauge
or a mercury manometer. The bomb consists of two parts: an upper expansion
chamber and a lower liquid chamber. The sample is cooled and poured into the
lower chamber until it is full. The temperature of the air in the upper chamber is
taken, and the two chambers are connected together in a gas-tight manner. The
bomb is immersed upright in a water bath at 37.8C (1000F) and shaken repeatedly
until a constant pressure reading is obtained. This is corrected, from tables, for
initial air temperature and pressure.
In each homologous series of hydrocarbons, the boiling point increases with
molecular weight. Structure also has a marked influence, and it is a general rule
that branched paraffin isomers have lower boiling points than the corresponding
Condensed Aromatics
Alkyl
n-Alkanes
Boiling Point,
lsoalkanes
Figure 5.1. Relationship of boiling point to carbon number (from Speight, 1999).
rc-alkane. However, the most dramatic illustration of the variation in boiling point
with carbon number is an actual plot for different hydrocarbons (Fig. 5.1). In any
given series, steric effects notwithstanding, there is an increase in boiling point with
an increase in carbon number of the alkyl side chain (Fig. 5.2). This particularly
applies to alkyl aromatic compounds, where alkyl-substituted aromatic compounds
can have higher boiling points than polycondensed aromatic systems. This fact is
very meaningful when attempts are made to develop hypothetical structures for
asphaltene constituents (Chapters 11 and 14).
The boiling points of petroleum fractions are rarely, if ever, distinct temperatures; it is, in fact, more correct to refer to the boiling range of a particular
fraction. To determine these ranges, the petroleum is tested in various methods of
distillation, either at atmospheric pressure or at reduced pressure. In general, the
limiting molecular weight range for distillation at atmospheric pressure without
n -Tridecylbenzene
Figure 5.2. Effect of alkyl chain length on boiling point (from Speight, 1999).
thermal degradation is 200-250, whereas the limiting molecular weight range for
conventional vacuum distillation is 500-600.
Thus petroleum can be subdivided by distillation into a variety of fractions of
different boiling ranges (cutpoints) using a variety of standard methods specifically
designed for this task, viz.:
ASTM D-86 (IP 123) - Distillation of Petroleum Products;
ASTM D-216 (IP 191) - Distillation of Natural Gasoline;
ASTM D-285 - Distillation of Crude Petroleum;
ASTM D-1160 - Distillation of Petroleum Products at Reduced Pressure;
ASTM D-2887 - Test Method for Boiling Range Distribution of Petroleum
Fractions by Gas Chromatography; and
ASTM D 2892 - Distillation of Crude Petroleum (15 Theoretical Plate Column).
In fact, distillation was at one time the predominant method by which petroleum
feedstocks were evaluated as suitable for various refinery options. It is now one of
several methods used for evaluation purposes.
As an early part of characterization studies, a correlation was observed between
the quality of petroleum products and their hydrogen content because gasoline,
kerosene, diesel fuel, and lubricating oil are made up of hydrocarbon constituents
containing high proportions of hydrogen. Thus it is not surprising that the tests to
determine the volatility of petroleum and petroleum products were among the first
to be defined. Indeed, volatility is one of the major tests for petroleum products,
and it is inevitable that all products will, at some stage of their history, be tested
for volatility characteristics.
Distillation involves the general procedure of vaporizing the petroleum liquid in
a suitable flask either at atmospheric pressure (ASTM D-86, ASTM D-216, ASTM
D-285, ASTM D447, ASTM D-2892, IP 24, IP 123, IP 191) or at reduced pressure
(ASTM D-1160). There are also test methods for the distillation of pitch (ASTM
D-2569) and cutback asphalt (ASTM D-402) that can be applied to heavy oil and
bitumen. However, most of the methods specify an upper atmospheric equivalent
temperature (AET) limit of 3600C (6800F) and therefore are too limited to be of
value in the analysis of tar sand bitumen.
In the simplest case, the distillation method involves using a standard roundbottom distillation flask of 250-ml capacity attached to a water-cooled condenser.
The thermometer bulb is placed at the opening to the side arm of the flask. One
hundred milliliters of sample are placed in the flask and heated by a small gas
flame so as to produce ten milliliters of distillate every 4 or 5 min. The temperature
of initial distillation is recorded; the temperature at which each additional 10 ml
distills and the final boiling point are also recorded.
The four distillation procedures that are commonly used by laboratories, either
singly or in combination, to determine the distillation curve of or produce fractions
from heavy oil and bitumen are:
1. ASTM D-2892: Distillation of Crude Petroleum (15 Theoretical-Plate
Column).
2. ASTM D-1160: Distillation of Petroleum Products at Reduced Pressures.
3. ASTM D-5236: Distillation of Heavy Hydrocarbon Mixtures (Vacuum
Potstill Method).
4. Spinning band distillation.
5. Distillation using a flash still.
The ASTM D-2892 method describes the procedure for distilling crude petroleum up to 4000C (752F) AET. This method is often referred to as the true boiling
point distillation method.
Crude oil samples containing light components must be debutanized in a preliminary step. In the method, a weighed sample of 1-10 liters is distilled in a fractionating column having an efficiency at total reflux of 14-18 theoretical plates.
A reflux ratio of 5:1 is maintained throughout except at the minimum pressure of
2 mm Hg, where a ratio of 2:1 can be used. The mass and density of each fraction
are used to prepare distillation curves either by mass or volume. This method is
often referred to as the 15-5 method.
The ASTM D-1160 method is used to determine the boiling ranges of petroleum
products to a maximum liquid temperature of 4000C (7520F) at pressures as low
as 1 mm Hg. In the method, a 200-ml sample is weighed to the nearest 0.1 g in
a distillation flask. The distillation assembly is evacuated to the desired pressure
and heat is applied to the flask as rapidly as possible using a 750-W heater. When
refluxing liquid appears, the rate of heating is adjusted so that the distillate is
recovered at 4-8 ml/min until the distillation is complete.
Because of the thermal sensitivity of residua, heavy oils, and bitumen, cracking will most likely occur before the liquid temperature reaches 4000C (752F).
An increase in distillation rate accompanied by a drop in head temperature, loss
of vacuum in the system that is restored when heat to the still is reduced, and
production of vapor clouds in the system are all evidence of cracking.
The vacuum potstill method (ASTM D-5236) is a procedure for the distillation
of high-boiling samples with initial boiling points above 1500C (3000F). This
includes heavy crude oil, tar sand bitumen, and residua. The method uses a potstill
with a low-pressure drop entrainment separator. The method also provides for
the determination of standard distillation profiles to the highest AET possible by
conventional distillation.
In the spinning band method (Fig. 5.3), fractions of feedstocks such as residua,
heavy oils, and bitumen with an initial boiling point above room temperature
at atmospheric pressure can be prepared. For such materials, the initial boiling
point of the sample should exceed room temperature at atmospheric pressure. The
distillation is terminated at an AET of 524C (975F). For bitumen samples the
distillation is terminated at a pot temperature of 3600C (6800F).
Samples are distilled under atmospheric and reduced pressures of 20.0 and
0.60 mmHg (2.67 kPa and 80 Pa) in a distillation unit equipped with a spinning
band column. The spinning band, which effectively provides a large contact area
between the liquid phase and the vapor phase, increases the number of theoretical plates in the column and thus its fractionating efficiency. Readings of vapor
temperature (that is convertible to AET) and distillate volume (that is convertible
to percent by volume) are used to plot a distillation curve. Distillate yields for
naphtha, light gas oil, heavy gas oil, and residue fractions are determined on a
gravimetric basis.
When fractionating bitumen, the pot temperature cannot exceed 3600C (6800F).
In this method, samples are distilled under atmospheric and reduced pressures in
a still equipped with a spinning band column. Vapor temperatures are converted
to AETs and can be plotted as a function of volume or weight percent distilled to
yield a distillation profile.
Teflon seal
Solenoid and magnet
Rod to plunger
Band drive motor
To dry ice condenser
(vacuum)
3-way valve
Thermocouple for
vapor temperature
Window and plunger
heating tape temperature
Clamp for ball
and socket joint
Atmosphere or
Fraction cutter
Spring clips
Monel spinning band
Figure 5.3. Schematic representation of the spinning band distillation apparatus (from Wallace, 1988).
Short path distillation produces a single distillate and a single residue fraction
defined by the operating temperature and pressure of the still. This procedure is used
to generate high-boiling-point fractions with end points up to 7000C (12900F) for
further analysis. Because only one cut temperature is used in each run, generation
of a distillation curve using this equipment would be time consuming. In this
method, the material to be fractionated is introduced at a constant rate onto the hot
inner wall of the evaporator under high vacuum. Rotating (Teflon) rollers ensure
that the film on the wall is kept thin. The feedstock is progressively distilled at
the fixed conditions of temperature and pressure. The distillate vapors condense
on a concentric cold surface (600C, 1400F) placed a short distance from the hot
wall inside the still. The condensate then drains by gravity to the base of the cold
finger where it is collected. The residue drains down the hot wall and is collected
through a separate port.
Short path distillation permits collection of deeper-cut distillate and residue
fractions than conventional vacuum distillation methods. AET end points of up
to 6600C (12200F) can be attained without thermal cracking of the material. The
distillation, however, is conducted under nonequilibrium conditions so the cut
point is not as specific as in other vacuum distillation methods.
Generally, the distillation tests are planned so that the data are reported in terms
of one or more of the following items:
1. Initial boiling point is the thermometer reading in the neck of the distillation flask when the first drop of distillate leaves the tip of the condenser tube.
This reading is materially affected by a number of test conditions, namely, room
temperature, rate of heating, and condenser temperature.
2. Distillation temperatures are usually observed when the level of the distillate reaches each 10% mark on the graduated receiver, with the temperatures for
the 5% and 95% marks often included. Conversely, the volume of the distillate
in the receiver, that is, the percentage recovered, is often observed at specified
thermometer readings.
3. End-point or maximum temperature is the highest thermometer reading
observed during distillation. In most cases, it is reached when all of the sample has been vaporized. If a liquid residue remains in the flask after the maximum
permissible adjustments are made in heating rate, this is recorded as indicative of
the presence of very high-boiling compounds.
4. Dry point is the thermometer reading at the instant the flask becomes dry
and is used for special purposes, such as for solvents and for relatively pure hydrocarbons. For these purposes, dry point is considered more indicative of the final
boiling point than end-point or maximum temperature.
5. Recovery is the total volume of distillate recovered in the graduated receiver,
and residue is the liquid material, mostly condensed vapors, left in the flask after
it has been allowed to cool at the end of distillation. The residue is measured by
transferring it to an appropriate small graduated cylinder. Low or abnormally high
residues indicate the absence or presence, respectively, of high-boiling components.
6. Total recovery is the sum of the liquid recovery and residue; distillation loss
is determined by subtracting the total recovery from 100%. It is, of course, the
measure of the portion of the vaporized sample that does not condense under the
conditions of the test. Like the initial boiling point, distillation loss is affected
materially by a number of test conditions, namely, condenser temperature, sampling and receiving temperatures, barometric pressure, heating rate in the early
part of the distillation, and others. Provisions are made for correcting high distillation losses for the effect of low barometric pressure because of the practice
of including distillation loss as one of the items in some specifications for motor
7. Percentage evaporated is the percentage recovered at a specific thermometer
reading or other distillation temperatures, or the converse. The amounts that have
been evaporated are usually obtained by plotting observed thermometer readings
against the corresponding observed recoveries plus, in each case, the distillation
loss. The initial boiling point is plotted with the distillation loss as the percentage
evaporated. Distillation data (Tables 5.1 and 5.2) are considerably reproducible,
particularly for the more volatile products.
One of the main properties of petroleum that serves to indicate the comparative
ease with which the material can be refined is the volatility (Speight, 1999 and
references cited therein). Investigation of the volatility of petroleum is usually
Table 5.1. Distillation Profile of Crude Oil (Leduc, Woodbend, Upper Devonian,
*Distillation at 765 mmHg then at 40 mmHg for fractions 11-15.
(Conradson)
carried out under standard conditions, thereby allowing comparisons to be made
between data obtained from various laboratories. One of the distillation (nondestructive) methods that has been standard, in addition to the ASTM methods, was
developed by the US Bureau of Mines.
If a detailed fractionation of the sample is of secondary importance, 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 (Nelson, 1958).
In the preliminary assay of crude oils, the method of distillation is often used
in the United Kingdom (IP 24) to give a rough indication of the boiling range of
crude oil. The test is very similar to the well-known method for gasoline distillation
(ASTM D-86, IP 123) and is carried out at atmospheric pressure and under conditions of poor fractionation. With crude oils, the distillation is stopped at 3000C
(5700F) to avoid excessive decomposition, and the distillate and residue can be
further examined using tests such as specific gravity, sulfur content (ASTM D-129,
IP 61), and viscosity (ASTM D445, IP 71). The tests give a rough indication of
the quality of the products to be obtained from the crude and have been used to
compare crude oils in respect to quality of the 3000C (5700F) cut point residuum.
For example, the wax content or viscosity gives a pointer to the type of residual
fuels obtainable from the crude oil.
a rigid procedure to be followed in all cases, although there would be considerable
advantages to be gained if this were possible. The procedure is, in essence, that
followed by many companies.
The method is based on a true boiling point (TBP) distillation of the crude,
and sufficient data are obtained to assess the yields and properties of the straightrun products, covering light hydrocarbons, light, middle, and heavy distillates,
lubricants, residual fuel oil, and bitumen. A TBP distillation is one in which the
test sample is physically distilled to produce fractions of the desired cut points.
The actual procedure involves the distillation of the crude oil in 1- to 5-gallon
quantities in a column equivalent to 14 theoretical plates and with reflux adjusted
to obtain a true boiling point versus yield relationship. Narrow fractions can be
taken throughout the distillation, and the still pressure can be reduced as necessary
to avoid decomposition in the higher boiling ranges. The fractionating distillation
is continued to a relatively high temperature such as 3700C (7000F) equivalent
temperature at 760 mm Hg absolute. The actual operating pressure of the still at
this stage would be in the region of 2 mmHg absolute. The distillate fractions up
to this point cover the light and middle distillates, and after the analysis of the
required fractions in this range, curves relating the various properties to yield on
fraction or on crude oil can be drawn. A series of residues can also be prepared
by appropriate blending of distillates with the final residue, and after analysis,
property relationships with yield can also be prepared for the residues.
From the TBP curve, the yields of products of a required boiling range can
be deduced and fractions can be blended to match required products for further
analysis or treatments. The residue (b.p. >370C, >700F) obtained from the TBP
distillation quoted contains the main lubricating oil stock, and by further distillation
under high vacuum a series of distillates can be prepared to cover the various
lubricating oil grades. With a waxy crude oil, it is necessary to remove the wax
from these distillates and further examine the wax-free lubricating oil distillates.
It is often useful in this type of crude oil assay to be able to extend the boiling
point data to higher temperatures than are possible in the fractionating distillation
method previously described, and for this purpose a vacuum distillation in a simple
still, with no fractionating column (similar to the ASTM D-1160) can be carried
out. This distillation, which is done under fractionating conditions equivalent to
one theoretical plate, allows the boiling point data to be extended to about 6000C
(HlO 0 F) (corrected to 760 mm Hg absolute) with many crude oils. Bearing in
mind the limitations in accuracy of the temperature measurements in the high
boiling ranges of crude it is possible to construct a wide-range boiling point curve
for the crude by combining the results of the simple distillation with those of the
main distillation. This method gives useful comparative and reproducible results
that are often accurate enough for engineering purposes.
It is advantageous in any analytical, research, or development organization
dealing with crude oil to collect information by the above methods on a standard
series of distillates or residues from crude oils so that valuable comparisons become
available as the data accumulate. These distillates should be prepared as near
as possible to the boiling ranges that are known to be suitable for marketable
products together with a true boiling point yield curve: The residuum (>370C,
>700F) can be further fractionated, if required, using, however, a high vacuum
still of sufficient capacity to give fractions in suitable quantity for subsequent
There is also another method that is increasing in popularity for application
to a variety of feedstocks, and that is the method commonly known as simulated
distillation (ASTM D-2887).
This is a low-resolution, temperature-programmed gas chromatographic analysis intended to simulate the time-consuming TBP distillation method. It is based
on the observation that hydrocarbons generally are eluted from a nonpolar column in the order of their boiling point, with the retention time being converted to
equivalent distillation temperatures. The accumulated detector response is related
to the amount of sample distilled. In practice, the nonpolar stationary phases do
discriminate to some extent among different classes of hydrocarbon. The retention
time is a function of the adsorptive property of the stationary phase, the vapor pressure, and the heat of vaporization. The empirical correlation between the retention
time and boiling point, usually established by running a series of rc-alkanes, is
not strictly valid for other hydrocarbon classes such as aromatic and cycloalkane
derivatives, which show a tendency to elute earlier than /t-alkanes having the same
boiling points.
The method has been well researched in terms of development and application
(Hickerson, 1975; Green, 1976; Stuckey, 1978; Vercier and Mouton, 1979; Thomas
et al., 1983; Romanowski and Thomas, 1985; MacAllister and DeRuiter, 1985;
Schwartz et al., 1987; Thomas et al., 1987). The benefits of the technique include
good comparisons with other ASTM distillation data as well as application to
higher boiling fractions of petroleum. In fact, data output includes the provision of
the corresponding Engler profile (ASTM D-86) as well as the prediction of other
properties such as vapor pressure and flash point (DeBruine and Ellison, 1973).
When it is necessary to monitor product properties, as is often the case during
refining operations, such data provide a valuable aid to process control and on-line
product testing.
For a more detailed distillation analysis of feedstocks and products, a lowresolution, temperature-programmed gas chromatographic analysis has been developed to simulate the time-consuming TBP distillation. The method relies on the
general observation that hydrocarbons are eluted from a nonpolar adsorbent in the
order of their boiling points. The regularity of the elution order of the hydrocarbon
components allows the retention times to be equated to distillation temperatures
(Green et al., 1964) and the term simulated distillation by gas chromatography (or
simdis) is used throughout the industry to refer to this technique.
Simulated distillation by gas chromatography is often applied in the petroleum
industry to obtain true boiling point data for distillates and crude oils (Butler,
1979). The principle involves gas chromatographic distillation (GCD) as a means
of separating compounds by boiling point to produce a distillation profile.
In comparison to an actual distillation, simulated distillation by gas chromatography requires a very small sample (on the order of several microliters) to produce
a full boiling range distribution profile for prediction of distillate yield and residue.
In addition, simulated distillation by gas chromatography might take as little as
2 h, whereas a full distillation may take 2 days.
Simulated distillation for distillate fractions (ASTM D-2887) is designed predominantly for samples with a final boiling point below 538C (10000F) and is
not suitable for the analysis of higher-boiling residua, heavy oil, or bitumen.
In gas chromatographic distillations, the nonpolar silicone gum stationary phase
tends to bleed from the support in conventional packed columns at temperatures
above 370-3800C (698-716F). High-temperature gas chromatographic distillation offers the possibility of extending the range of the gas chromatographic distillation profile for heavy oil and bitumen.
Good agreement has been reported between the capillary and packed column
methods for residua, heavy oil, and bitumen. The accuracy of the capillary method
is determined by analyzing a mixture of 30% internal standard (a 300-3500C,
572-662F petroleum fraction) with a measured amount (e.g., 70% by weight) of
residuum. The boiling point distribution profile of the residuum, calculated from
the profile for the mixture with the internal standard mathematically subtracted
out, may deviate by less than 0.3% by weight at any temperature from the curve
for the residuum alone.
The capillary method has been used to identify the cut point between a distillate and residuum produced by short-path distillation at an atmospheric boiling
equivalent that could not have been identified using a conventional column.
The test method for the boiling range distribution of petroleum fractions by gas
chromatography (ASTM D-2887) cannot be used to map the distillation profile
of heavy oil and bitumen because it does not provide for the determination of the
proportion of sample having a boiling point in excess of 538C (> 10000F) residue
in sample. The use of internal standards, and combinations of actual distillations
and gas chromatographic distillation that provide a distillate fraction that can then
be analyzed by gas chromatography, has already gained wide acceptance in the
However, the method can be used as one of two standardized methods (ASTM
D-2887, ASTM D-3710) available for the boiling point determination of petroleum
fractions and gasoline, respectively. The former method (ASTM D-2887) utilizes nonpolar packed gas chromatographic columns in conjunction with flame
ionization detection. The upper limit of the boiling range covered by this method
is to approximately 5400C (10000F) atmospheric equivalent boiling point. Recent
efforts in which high-temperature gas chromatography was used have focused on
extending the scope of the method for higher- boiling petroleum materials to 8000C
(14700F) atmospheric equivalent boiling point (Schwartz et al., 1987).
The quality of distillation, that is, the degree of overlap between one fraction
and the next, is important in the evaluation of fractions from a crude. Typically, in
a high-quality distillation, the contamination will be 2-4% of total crude at each
cut temperature.
Flooding of the column and cracking of the feedstock are two serious problems
during a true boiling point distillation. Flooding, which results from an excessive
rate of heating, is the physical transport of liquid up the column and into the
receiver. Cracking is thermal degradation of crude oil caused by high temperatures
in the distillation pot, and it can occur at any temperature above 2500C (482F),
depending on the crude oil. It is indicated by the formation of a "fog" in the
distillation pot or column, a sudden drop of vapor temperature at the top of the
column, or the presence of light components in the heavy fractions as measured
by gas chromatographic distillation.
The measurement of pressure at the top of the distillation column is critical
to valid distillation results because the observed vapor temperature must be corrected to the atmospheric equivalent temperature at standard pressure conditions
(760 mmHg). There is a general belief that the minimum pressure should be
2 mmHg or greater for reasonably accurate measurements and correction to the atmospheric equivalent temperature. At pressures below 2 mm Hg, the pressure
measurement is too inaccurate and a discontinuity can arise in the distillation
curve from atmospheric to vacuum distillation.
The precision and accuracy of the single internal standard method depends on
the accuracy of estimating the area of the internal standard. In addition to the
problems in determining the percentage of sample that elutes from a gas chromatographic column, errors can occur because the components of a sample can
elute at a different time than the standards of the same boiling point.
5.3. LIQUEFACTION AND SOLIDIFICATION
The liquefaction and solidification of petroleum and various fractions seem to draw
little attention in the standard petroleum science textbooks, and yet both properties
are very important in the handling of petroleum and in refinery management. In
fact, petroleum and the majority of petroleum products are liquids at ambient
temperature, and problems that may arise from solidification during normal use
are not common. Nevertheless, the melting point is a test (ASTM D-87, ASTM D127, IP 55, IP 133) that is widely used by suppliers of wax and by wax consumers;
it is particularly applied to the highly paraffinic or crystalline waxes. Quantitative
prediction of the melting point of pure hydrocarbons is difficult, but the melting
point tends to increase qualitatively with the molecular weight and with symmetry
of the molecule.
The softening point (ASTM D-36, ASTM D-2398, IP 58), defined as the temperature at which a disk of the material softens and sags downward a distance of
25 mm under the weight of a steel ball under strictly specified conditions, finds
wider use for residua, asphalt, and bitumen. The dropping point (ASTM D-566,
IP 132) is the near-equivalent test that is used for lubricating greases.
The melting points (cf. ASTM D-87, IP 55, melting point of paraffin wax;
ASTM D-127, IP 133, melting point of petrolatum and microcrystalline wax)
of the normal paraffins (Table 5.3) agree fairly well with the data for the lower
crystalline paraffin waxes when the materials are compared on a molecular weight
Table 5.3. Melting Points of the w-Paraffins
of Carbon Atoms
basis, and this furnishes some of the best evidence for chemical constitution of
macrocrystalline petroleum wax. The effect of symmetry is far greater than that
of molecular weight and often offsets it. The branched-chain hydrocarbon usually
melts far below the straight-chain compound of the same number of carbon atoms.
The branched-chain hydrocarbon will often melt at a lower temperature than the
normal paraffin equivalent to the longest chain in the molecule. Exceptions occur
when the substitution produces a compact, symmetrical molecule, and similar
qualitative rules apply to cyclic compounds.
Unsubstituted and symmetrically substituted compounds (e.g., benzene, cyclohexane, /7-xylene, and naphthalene) melt at higher temperatures relative to the
paraffin compounds of similar molecular weight; the unsymmetrical isomers generally melt at lower temperatures than the aliphatic hydrocarbons of the same
molecular weight.
Unsaturation affects the melting point principally by its alteration of symmetry;
thus ethane (-1720C, -278F) andethylene (-169.50C, -273F) differ only slightly,
but the melting points of cyclohexane (6.2C, 21F) and cyclohexene (-1040C,
-155F) contrast strongly. All types of highly unsymmetrical hydrocarbons are
difficult to crystallize; asymmetrically branched aliphatic hydrocarbons as low
as octane and most substituted cyclic hydrocarbons comprise the greater part of
the lubricating fractions of petroleum, crystallize slowly if at all, and on cooling
merely take the form of glasslike solids.
Although the melting points of petroleum and petroleum products are of limited
usefulness, except to estimate the purity or perhaps the composition of waxes, the
reverse process, solidification, has received some, but again limited, attention in
petroleum chemistry.
For example, the solidification point of paraffin wax (ASTM D-394) is an
important monitor for the behavior and performance of wax. However, the test is
somewhat limited in its application to heavy oil or bitumen because the complexity
of these materials prevents careful and conscientious application of the test. Hence,
more emphasis is placed on the reverse phenomena such as melting point, dropping
point, softening point, and pour point. Indeed, the solidification of petroleum and
petroleum products has been differentiated into four categories: cloud point, pour
point, freezing point, and congealing point.
The cloud point of petroleum or a petroleum product is the temperature at which
paraffin wax or other solidifiable compounds present in the oil appear as a haze
when the sample is chilled under definitely prescribed conditions (ASTM D-2500,
ASTM D-3117, IP 219, IP 444, IP 445, IP 446).
To determine the cloud point and the pour point (ASTM D-97, ASTM D-5327,
ASTM D-5853, ASTM D-5949, ASTM D-5950, ASTM D-5985, IP 15, IP 219,
IP 441) the oil is contained in a glass test tube fitted with a thermometer and
immersed in one of three baths containing coolants. The sample is dehydrated and
filtered at a temperature 250C (450F) higher than the anticipated cloud point. It
is then placed in a test tube and cooled progressively in coolants held at -1 to
+2 0 C (30 to 35F), -18 to -20 0 C (-4 to 00F), and -32 to -35C (-26 to -31 0 F),
respectively. The sample is inspected for cloudiness at temperature intervals of
1C (2F). If conditions or oil properties are such that reduced temperatures are
required to determine the pour point, alternate tests are available that accommodate
the various types of samples.
Related to the cloud point, the wax appearance temperature or wax appearance
point is also determined (ASTM D-3117, IP 389).
The pour point of petroleum or a petroleum product is determined using this
same technique (ASTM D-97, IP 15), and it is the lowest temperature at which
the oil pours or flows. It is actually 2C (3F) above the temperature at which the
oil ceases to flow under these definitely prescribed conditions when it is chilled
without disturbance at a standard rate. To determine the pour point, the sample is
first heated to 46C (115F) and cooled in air to 32C (900F) before the tube is
immersed in the same series of coolants as used for the determination of the cloud
point. The sample is inspected at temperature intervals of 2C (3F) by withdrawal
and holding horizontal for 5 s until no flow is observed during this time interval.
The pour point of a crude oil was originally applied to crude oil that had a high
wax content. More recently, the pour point, like the viscosity, is determined principally for use in pumping and pipeline design calculations. Difficulty occurs in these
determinations with waxy crude oils that begin to exhibit irregular flow behavior
when wax begins to separate. These crude oils possess viscosity relationships that
are difficult to predict in pipeline operations. In addition, some waxy crude oils are
sensitive to heat treatment that can also affect their viscosity characteristics. This
complex behavior limits the value of viscosity and pour point tests on waxy crude
oils. At the present time, long crude oil pipelines and the increasing production
of waxy crude oils make an assessment of the pumpability of a wax-containing
crude oil through a given system a matter of some difficulty that can often only
be resolved after field trials. Consequently, considerable work is in progress to
develop a suitable laboratory pumpability test (such as described in IP 230) that
gives an estimate of minimum handling temperature and minimum line or storage
temperature.
On the issue of wax in crude oil, crude oil having a high wax content presents
difficulties in handling and pumping. Such crude oil produces distillate and residual fuels of high pour point and lubricating oils that are costly to dewax. Thus
considerable study has been made of wax cracking or destruction processes.
All the standard methods for the determination of the wax are empirical. Such
methods involve precipitating the wax from solvents such as methylene chloride,
acetone, and similar solvents under special conditions of solvent-to-oil ratio and
temperature. Measurements such as these give comparative results that are often
useful in characterizing the wax content of crude oil or for investigating factors
involved in flow problems.
More recently, the pour point has also found use as an indicator of the temperature at which crude oil or heavy oil will flow during in situ recovery operations
(Wallace, 1988, p. 183). Under similar conditions, tar sand bitumen is immobile.
For example, for asphaltic crude oils in which paraffin precipitation will not occur,
if 21C (700F) is the pour point of a crude oil in a reservoir where the temperature
is 38C (1000F), the oil is liquid under reservoir conditions and will be mobile and
will flow under those conditions. On the other hand, tar sand bitumen (pour point
600C, 1400F) in a deposit (temperature 100C, 500F) will be solid and immobile.
This state of the oil in the reservoir can also have consequences on the ability of
gases and liquids (e.g., steam, hot water) used for recovery operations to penetrate
the reservoir/deposit. Although pressure can have some influence on the pour point,
the effect is not large and is unlikely to effect any general conclusions. Indeed, for
specific types of petroleum (usually asphaltic and nonwaxy) there is a relationship
between API gravity and pour point. Thus any increase in pour point due to an
increase in pressure (surface compared to reservoir or deposit pressure) will be
most likely be negated as the API gravity decreases with increase in temperature
(600F compared to reservoir temperature).
The solidification characteristics of a petroleum product depend on its grade
or kind. For greases, the temperature of interest is that at which fluidity occurs,
commonly known as the dropping point. The dropping point of grease is the
temperature at which the grease passes from a plastic solid to a liquid state and
begins to flow under the conditions of the test (ASTM D-566, ASTM D-2265, IP
132). For another type of plastic solid, including petrolatum and microcrystalline
wax, both melting point and congealing point are of interest.
The melting point of a wax is the temperature at which the wax becomes sufficiently fluid to drop from the thermometer; the congealing point is the temperature
at which melted petrolatum ceases to flow when allowed to cool under definitely
prescribed conditions (ASTM D-938).
For another type of solid, paraffin wax, the solidification temperature is of interest. For such purposes, melting point is defined as the temperature at which the
melted paraffin wax begins to solidify, as shown by the minimum rate of temperature change, when cooled under prescribed conditions. For pure or essentially pure
hydrocarbons, the solidification temperature is the freezing point, the temperature
at which a hydrocarbon passes from a liquid to a solid state (ASTM D-910, ASTM
D-1015, ASTM D-1016, ASTM D-2386, IP 16, IP 434, IP 435).
The relationship of cloud point, pour point, melting point, and freezing point
to one another varies widely from one petroleum product to another. Hence, their
significance for different types of product also varies. In general, cloud, melting, and freezing points are of more limited value and each has a narrower range
of application than the pour point. Cloud and pour points are useful for predicting the temperature at which the observed viscosity of an oil deviates from the
true (Newtonian) viscosity in the low-temperature range. They are also useful for
identification of oils or when planning the storage of oil supplies, because low
temperatures may cause handling difficulties with some oils.
CARBON RESIDUE
The carbon residue of crude oil and crude oil products is a measure of the propensity
of the sample to form coke when combusted under specific conditions that require
a limited supply of oxygen. The carbon residue of a petroleum sample might be
considered to be analogous to the determination of fixed carbon for coal (ASTM
D-3172, ASTM D-3173, ASTM D-3174, ASTM D-3175).
Petroleum products are mixtures of many compounds that differ widely in their
physical and chemical properties. Some of them may be vaporized in the absence of air at atmospheric pressure without leaving an appreciable residue. Other
nonvolatile compounds leave a carbonaceous residue when destructively distilled
under such conditions. This residue is known as carbon residue when determined
in accordance with prescribed procedures. Thus the term carbon residue is used
here to denote the carbonaceous residue formed after evaporation and pyrolysis of
a petroleum product. The residue is not entirely composed of carbon but is a coke
that can be changed further by heating.
The method was originally devised to determine the carbon-forming tendencies of diesel fuels and lubricating oils in internal combustion engines. Carbon
residue values of various heavy feedstocks are indicative of the coke yields to be
expected from these materials in refinery coking operations (Speight, 1999, 2000
and references cited therein).
There are two older methods for determining the carbon residue of a petroleum
or petroleum product, the Conradson method (ASTM D-189, IP 13) and the Ramsbottom method (ASTM D-524, IP 14). Both are applicable to the relatively nonvolatile portion of petroleum and petroleum products, which partially decompose
when distilled at a pressure of 1 atmosphere. However, oils that contain ash-forming
constituents have erroneously high carbon residues by either method unless the
ash is first removed from the oil; the degree of error is proportional to the amount
of ash.
The Conradson carbon method is the more usual test for determining the amount
of carbon residue left after evaporation and pyrolysis (destructive distillation) of
residua, heavy oil, and bitumen and is intended to provide some indication of
relative coke-forming propensity. The amount of Conradson carbon residue is also
corrected for the presence of mineral matter in the sample.
In this method (ASTM D-189), a weighed quantity of sample is placed in a
crucible and subjected to destructive distillation. The equipment consists of a large
porcelain crucible placed inside two iron crucibles and heated by a gas burner until
all petroleum vapors are driven off. A known weight of oil (e.g., 10 g) is placed
inside the porcelain crucible, and the apparatus is assembled and heated at such a
rate that the vapors start to burn within about 10 min. The flame is then adjusted
so that they burn at the top of the chimney for a further 21-23 min. The crucibles
are then heated to a cherry-red heat for a further 7-8 min, giving a total time of
approximately 30 min.
The residue undergoes a cracking and coking reaction during severe heating for
a fixed period of time. The crucible containing the carbonaceous residue is cooled
in a desiccator and weighed. This residue is subsequently reduced to an ash by
heating in a muffle furnace at 7500C (13800F), allowed to cool, and weighed. The
amount of residue is corrected for the ash content and reported as the Conradson
carbon residue (CCR).
In the Ramsbottom carbon method (ASTM D-524) a known weight of the
petroleum sample (proportional to the anticipated weight of residue) is heated in
a hemispherical glass bulb of standard dimensions by a bath of molten solder at
5500C (10200F) for 20 min. The carbon residue is weighed and recorded as % wt.
Ramsbottom carbon.
Because of the extremely small values of carbon residue obtained by the Conradson and Ramsbottom methods when applied to the lighter distillate fuel oils, it
is customary to distill such products to 10% residual oil and determine the carbon
residue thereof. Such values may be used directly in comparing fuel oils, as long
as it is kept in mind that the values are carbon residues on 10% residual oil and
are not to be compared with straight carbon residues.
The mechanical design and operating conditions of such equipment have such a
profound influence on carbon deposition during service that comparison of carbon
residues between oils should be considered as giving only a rough approximation of
relative deposit-forming tendencies. Recent work has focused on the carbon residue
of the different fractions of crude oils, especially the asphaltenes (Speight, 1999).
A more precise relationship between carbon residue and hydrogen content, H-to-C
atomic ratio, nitrogen content, and sulfur content has been shown to exist (see also
Nelson, 1974). These data can provide more precise information about the anticipated behavior of a variety of feedstocks in thermal processes (Roberts, 1989).
Although there is no exact correlation between the two methods it is possible to
interconnect the data (ASTM D-189, ASTM D-524), but caution is advised when
using that portion of the curve below 0.1% wt/wt CCR.
Recently, a newer method (Noel, 1984) has also been accepted (ASTM
D-4530) that is very appealing to those situations in which only small amounts
of the sample are available. The method only requires small amounts of sample
and was originally developed as a thermogravimetric method. The carbon residue
produced by this method is often referred to as the microcarbon residue (MCR).
Agreements between the data from the three methods are good, making it possible
to interrelate all of the data from carbon residue tests (Long and Speight, 1989).
Like the Conradson carbon residue test and the Ramsbottom carbon residue
test, the microcarbon residue method (ASTM D-4530, IP 398) also provides a
measure of the relative coke-forming propensity of the sample under degradation
conditions that simulate commercial coking operations. Ash-forming constituents
and/or nonvolatile constituents present in the sample will add to the residue value
determined. In the method, a weighed quantity of sample is placed into a glass vial
and heated to 5000C (9300F) under a nitrogen atmosphere for a specific time, during
which the sample undergoes cracking and coking. Nitrogen is used to remove the
volatile materials. The carbonaceous residue is reported as % microcarbon residue
of the original sample.
Even though the three methods have their relative merits, there is a tendency
to advocate use of the more expedient microcarbon method to the exclusion of
the detriment of the Conradson and Ramsbottom methods because of the lesser
amounts required in the microcarbon method., which is somewhat less precise in
practical technique.
There is a relationship between the carbon residue and the atomic H-to-C ratio,
and this can be refined (Roberts, 1989) to a fairly universal linear correlation
between the carbon residue (Conradson) and the H-to-C ratio:
H/C = 171 - 0.0115CR(Conradson).
This equation holds within two limits; at H/C values = 1.71, where the carbon
residue is zero (no coke formation) and H/C = 0.5, where the carbon residue is
100 (all the material converts to coke under test conditions). There is a relationship
between the carbon residue (Conradson) and the nitrogen content.
The carbon residue (ASTM D-189, ASTM D-524, ASTM D-4530, IP 13, IP 14)
is a property that can be correlated with several other properties of petroleum
(Speight, 1999); hence it also presents indications of the volatility of the crude
oil and the coke-forming (or gasoline-producing) propensity. However, tests for
carbon residue are sometimes used to evaluate the carbonaceous depositing characteristics of fuels used in certain types of oil-burning equipment and internal
combustion engines.
The fact that these correlations exist can best be explained in terms of the distribution of chemical species in these materials. In each, there are some molecules
with a higher proportion of aromatic carbon and more heteroatoms that, because
of these characteristics, have low H-to-C ratios and a high propensity for producing coke. The proportion of these coke precursors, of course, is higher in the
higher-boiling fractions than in the lower-boiling fractions.
The application of the Conradson carbon residue determination to heavy feedstocks, such as Athabasca bitumen, requires that a correction be made for inorganic
matter by determining the ash content of the carbon residue. In addition, the high
Conradson carbon residue of such feedstocks allows use of a smaller sample size
together with correspondingly shorter burning and flame times.
5.5. ANILINEPOINT
In the early days of petroleum refining, there was a need to determine the relative
amounts of aromatic compounds and aliphatic compounds in various products.
Thus the aniline point came into being and has been widely used in the past. The
method still finds use, but it is somewhat limited to the popularity of yesteryear.
However, it should not be completely discarded because of age!
The aniline point of petroleum or a petroleum product is actually the critical
solution temperature of the two liquids (aniline and the sample), that is, the minimum temperature at which they are miscible in all proportions. The term is now
most generally applied to the temperature at which exactly equal parts of the two
are miscible. This value is more conveniently measured than the original value and
is only a few tenths of a degree lower for most substances. Thus the aniline point is
an approximate measure of the aromatic content of a mixture of hydrocarbons and
is defined as the lowest temperature at which petroleum is completely miscible
with an equal volume of aniline.
Although it is an arbitrary index, the aniline point (ASTM D-611, IP 2) has
considerable value in the characterization of petroleum products. For oils of a
given type it increases slightly with molecular weight; for those of given molecular
weight it increases rapidly with increasing paraffinic character. As a consequence,
it was one of the first properties proposed for the group analysis of petroleum
products with respect to aromatic and naphthene content. It is used, alternately,
even in one of the more recent methods. The simplicity of the determination
makes it attractive for the rough estimation of aromatic content when that value
is important for functional requirements, as in the case of the solvent power of
naphtha and the combustion characteristics of gasoline and diesel fuel.
Because aromatics dissolve aniline more readily than paraffins or /so-paraffins,
the lower the aniline point the higher the proportion of aromatics in the oil. Because,
also, the higher the aromatic content of an oil, the lower the cetane number the
aniline number can be used to indicate the probable behavior of a petroleum product
in a diesel engine.
Determination of the aniline point requires that 5 ml of a carefully dried sample
and aniline are placed in a test tube fitted with a thermometer and stirrer and enclosed in a larger tube to act as an air jacket. If, on stirring, the sample and aniline are
completely miscible, the apparatus is cooled until the mixture is opaque. The temperature is then raised at lC/min (3F/min) until the thermometer bulb is just visible. The temperature is then recorded as the aniline point. If, at atmospheric temperature, the oil and aniline are not completely miscible, the temperature is raised until
this occurs. The mixture is then cooled at lC/min (3F/min) until the thermometer
bulb is just obscured, when the temperature is recorded as the aniline point.
The aniline point is used in conjunction with the API gravity to determine the
diesel index.
5.6. SPECIFIC HEAT
Specific heat is defined as the quantity of heat required to raise a unit mass of
material through one degree of temperature (ASTM D-2766). Such a definition in
fact describes specific heat capacity, and is not related to the heat capacity of water.
The more common units of Btu/lbF or cal/gC (which are numerically equal, being
effectively the ratio of the heat required to heat the substance to that required to
heat water) are related to the SI unit by 1 Btu/lbF = 1 cal/gC = 4.1868 kJ/kgK.
In addition to the standard method for the determination of specific heat (ASTM
D-2766), differential scanning calorimetry has also been used (ASTM E-1269).
The property is often required in estimating the amount of heat necessary to
preheat a fuel oil or to preheat heavy oil in the reservoir before recovery. Knowledge
of the specific heat of a fraction is of importance in determining net heat fluxes
in all heating and cooling problems. Thus specific heats are extremely important
engineering quantities in refinery practice because they are used in all calculations
on heating and cooling petroleum products.
Many measurements have been made on various hydrocarbon materials, but the
data for most purposes may be summarized by the general equation:
C = l/d(0.388+ 0.000450
where C is the specific heat at t(F) of an oil whose specific gravity 60/600F is d\
thus, specific heat increases with temperature and decreases with specific gravity.
For bitumen and heavy oil the equation has been modified. Thus:
Cp = [0.758 + 0.00339(/ + 273)]/d 05
where Cp is the heat capacity (J/g 0K, 1.0 = 0.24 Btu/lb 0 F ), / is the temperature
(0C), and d is the density (g/cm3). Another relationship (Bland and Davidson,
1967) is:
Cp = (0.6811 - 0.308d) + f(0.000815 - 0.000306d) x (0.055 + 0.35)
where Cp is the heat capacity (J/g 0K, 1.0 = 0.24 Btu/lb 0 F ), t is the temperature
(0F), K is the Watson characterization factor (Chapter 3), and d is the specific
gravity (60F/60F).
On the other hand, after extensive testing of bitumen samples from the Athabasca
deposit (Smith-Magowan et al., 1982), the following temperature-dependent equation was derived for the specific heat of bitumen covering the range 500C to 3000C
(122Fto572F):
Cp = 1.55745.219 x 103^ - 8.686 x IO"6*2
where Cp is the specific heat (heat capacity; J/g 0K, 1.0 = 0.24 Btu/lb 0 F) and tis the
temperature (0C). For most hydrocarbons, specific heat is almost a linear function
of temperature (increasing as temperature increases). It decreases, however, as the
density increases.
For liquids, specific heat normally implies measurements at constant (atmospheric) pressure. The value is not very dependent on pressure, and the value
given is almost identical with the value obtained at constant volume. For gases,
however, the values at constant pressure and constant volume are quite different,
the value at constant pressure being the greater by an amount equal to the specific
gas constant.
5.7. LATENTHEAT
There are two properties that represent phase transformations: the latent heat of
fusion and the latent heat of vaporization. The latent heat of fusion, defined as
the quantity of heat necessary to change a unit weight of solid to a liquid without
any temperature change, has received only intermittent attention but, nevertheless,
some general rules have been formulated.
Phase transformations (melting and vaporization or the reverse processes, etc.)
are not accompanied by a sensible heat change (rise in temperature), although they
are associated with heat absorption or evolution, and these heat effects are called
latent heats. Such changes are normally measured at constant pressure and are
thus enthalpy changes, although values for the constant volume (internal energy)
changes are obtainable in thermodynamic tables. The unit is Btu/lb (1 Btu/lb =
2.326 kJ/kg).
Heat of vaporization is perhaps the most important latent heat in petroleum
engineering. It decreases as the temperature rises and becomes zero at the critical
temperature (this phenomenon forming, in fact, a useful indication of the critical
point). The importance of latent heat has led to many methods of obtaining such
data from temperature and the more readily obtainable physical properties such
as density. These correlations, although they contain a degree of empiricism, are
generally based on the Clausius-Clapeyron equation.
As with specific heat, values of latent heat are needed to calculate heat effects,
particularly for distillation equipment.
Table 5.4. Latent Heat of Fusion of w-Paraffins
C6HH
C7HI6
CgHig
Q0H22
Ci2H26
(0Q
-182.6
of Fusion
(cal/g)
C29H6O
(0C)
For hydrocarbons, latent heats of fusion commerce at approximately 15 cal/g
for methane, rising to 40 cal/g for octane, then gradually approaching a limiting
value of 55 cal/g (Table 5.4). Branched paraffins usually have a lower latent heat
of fusion than the normal isomers (Table 5.5); paraffin wax has a latent heat of
fusion in the range of 50-60 cal/g.
The latent heat of vaporization, defined as the amount of heat required to vaporize a unit weight of a liquid at its atmospheric boiling point, is perhaps the
most important property of the two and has received considerably more attention
because of its connection with equipment design. The latent heat of vaporization
at the atmospheric boiling point generally increases with increasing molecular
weight (Table 5.6) and, for the normal paraffins, generally decreases with increasing temperature and pressure.
The latent heat of vaporization at any temperature can be described in terms of
the latent heat at the normal boiling point:
yLB/(T/TB)
w h e r e L i s t h e l a t e n t h e a t o f v a p o r i z a t i o n a t t h e a b s o l u t e t e m p e r a t u r e T,y i s a
Table 5.5. Latent Heat of Fusion of Various Hydrocarbons
Heat of Fusion
cal/g
cal/mol
Branched Paraffins
2-Methylbutane
2-Methylhexane
3-Ethylpentane
2,2-Dimethylpentane
3,3 -Dimethy lpentane
2,2,3-Trimethylbutane
2,2,4-Trimethylpentane
Hexamethylethane
+ 104.0
Aliphatic Olefins
CgHi 6
Trimethylethylene
Diisobutylene
CgHio
QoHg
oXylene
ra-Xylene
/?-Xylene
Ethylbenzene
Pseudocumene
Camphene
Durene
Isodurene
Prehnitene
/?-Cymene
rc-Butylbenzene
terf-Butylbenzene
(3 -Methy lnaphthalene
Diphenyl
Hexamethylbenzene
Table 5.5. (Continued)
Phenanthrene
Tolane
Stilbene
Dibenzil
Triphenylmethane
Hydroaromatic Hydrocarbons and Naphthenes
CeHi 2
Cyclohexene
Cyclohexane
Methylcyclopentane
1,2-Dimethylcyclopentane
Methylcyclohexane
A2 -Dihydronaphthalene
Dihydrophenanthrene
temperature correction factor obtained from graphical data (Nelson, 1958, p. 174),
and LB is the heat of vaporization at absolute normal boiling point T#.
The latent heat decreases with temperature until it has a value of zero at the
critical temperature. Furthermore, the critical temperature of a high-API gravity crude oil is lower than the critical temperature of a low-API gravity crude
oil. Hence the latent heat curves of various crude oil will exhibit crossover
Table 5.6. Latent Heat of Vaporization of w-Paraffins at the
Atmospheric Equivalent Boiling Point
Heptane
Decane
Tetradecane
Eicosane
^vaporization
Btu/lb
kcal/mol
5.8. ENTHALPY OR HEAT CONTENT
Enthalpy is the heat energy necessary to bring a system from a reference state to
a given state.
Thus enthalpy is a measure of the amount of heat in a quantity of material relative
to a suitable base temperature. It is normally measured at constant pressure and
may thus be referred to as enthalpy. It is the sum of the total latent heat changes
and the product of specific heats and temperatures for the system. The unit used
is the same as that for latent heat (page 152) and its uses are in the preparation of
heat balances.
Enthalpy is a function only of the end states and is the integral of the specific
heats with respect to temperature between the limit states plus any latent heats of
transition that occur within the interval. The usual reference temperature is 00C
(3 2F). Enthalpy data are easily obtained from specific heat data by graphic integration or, if the empirical equation given for specific heat is sufficiently accurate,
from the equation:
H = l/rf(0.388 + 0.000225r2 - 12.65)
Generally, only differences in enthalpy are required in engineering design, that is,
the quantity of heat necessary to heat (or cool) a unit amount of material from one
temperature to another. Such calculations are very simple because the quantities
are arithmetically additive, and the enthalpy for such a change of state is merely
the difference between the enthalpies of the end states.
5.9. THERMAL CONDUCTIVITY
It is often necessary in refining as well as in the application of petroleum products
to establish the optimum conditions for the transfer of heat as well as the cooling
function of these materials. Thus a knowledge of the specific heat (page 151) is
of considerable value in estimating the likely rise in temperature for a given set of
heat transfer conditions. In many heat transfer problems, the viscosity may have a
decided influence over the establishment of convection currents or volume flow if
forced circulation is involved. Thus the thermal conductivity of the oil becomes a
significant factor.
The thermal conductivity K of hydrocarbon oils (in cgs units) is given by the
equation:
K = 0.28/d(/ - 0.00054) x 10" 3
where d is the specific gravity. The units of thermal conductivity have been
Thermal conductivity, W/m/K
Figure 5.4. Thermal conductivity of petroleum liquids.
expressed as W/mK (1.0 W/mK = 0.86 kcal/h m 0 C = 0.58 Btu/h ft 0 F). The
thermal conductivity of a series of feedstocks can be estimated from the API gravity (Fig. 5.4) that shows a variation with temperature. The API gravity of bitumen
and heavy oil varies from 6 to about 20. Thus at reservoir and deposit temperatures
00C to 700C (32C 158F), the value of bitumen thermal conductivity would thus
be approximately 0.11 to about 0.12 (Fig. 5.4).
PRESSURE-VOLUME-TEMPERATURE RELATIONSHIPS
Knowledge of the pressure, volume, and temperature of a system forms the basis of
the calculation of the thermodynamic relationships of the system. These properties
are easily measured, and because they are sufficient to define the thermodynamic
state they are termed the parameters of state. However, they are not independent,
and, in fact, any two are sufficient to define the state of a system of known mass. A
simple treatment of a mathematical model of a gas based on kinetic theory yields
a relationship PV = nRT, where n is the number of moles of gas and R is a
universal constant equal to 8.314 kJ/kmolK. This mathematical model is called
the perfect gas, and real gases that behave in this way are called ideal gases. Most
light petroleum gases, air, flue gases, etc. may be treated as ideal up to pressures of
about 1.5-2 MN/m2 (approximately 250-300 psi) provided the temperature is well
above the critical. For heavier vapors and for lower temperatures a more accurate
equation of state is needed.
Sufficient accuracy is normally obtained for engineering purposes by the use
of the compressibility coefficient (Z), where PV = ZnRT. The compressibility
coefficient is a function of temperature, pressure, and the nature of the gas, but
values can be obtained from generalized charts by use of reduced temperatures
and pressures (pseudo-values in the case of mixtures).
In the calculation of pressure-volume-temperature relationships, it is often useful to use the concept of standard conditions at 00C (32F) and 1 atmosphere
pressure (approximately 105 N/m2); 1 kmol of the perfect gas occupies 22.4 m3
[the corresponding value in British units is 359 fta at 359 ft3 and 1 atmosphere
pressure or 379 ft3 at 600F and 1 atmosphere pressure (both values for 1 Ib mole)].
When using these relationships it is important that both pressure and temperature
be expressed in absolute scales. Gauge pressures and or 0 C or 0 F must not be used.
Hydrocarbon vapors, like other gases, follow the ideal gas law (i.e., 4PV = RT)
only at relatively low pressures and high temperatures, that is, far from the critical
state. Several more empirical equations have been proposed to represent the gas
laws more accurately, such as the well-known van der Waals equation, but they
are either inconvenient for calculation or require the experimental determination
of several constants. A more useful device is to use the simple gas law and to
induce a correction, termed the compressibility factor, so that the equation takes
the form:
PV = tiRT
For hydrocarbons, the compressibility factor is very nearly a function only of
the reduced variables of state, i.e., a function of the pressure and temperature divided by the respective critical values. The compressibility factor method functions
excellently for pure compounds but may become ambiguous for mixtures because
the critical constants have a slightly different significance. However, the use of
pseudo-critical temperature and pressure values that are generally lower than the
true values permits the compressibility factor to be employed in such cases.
5.11. HEATOFCOMBUSTION
The heat of combustion (ASTM D-240, IP 12) is a direct measure of fuel energy
content and is determined as the quantity of heat liberated by the combustion of a
quantity of fuel with oxygen in a standard bomb calorimeter.
Chemically, it is the energy (heat) released when an organic compound is burned
to produce water (H2OiIqUId) carbon dioxide (CO2gas), sulfuric acid (H2SO4iiquid),
and nitric acid (HN03nquid). The value can be calculated using a theoretical
equation based upon the elemental composition of the feedstock:
# g /4.187 = 8400C + 27, 765H + 1500N + 2500S - 2650O
where Hg is given in kilojoules per kilogram (1.0 kJ/kg = 0.43 Btu/lb), C, H, N,
S, and O are the normalized weight fractions for these elements in the sample.
The gross heats of combustion of crude oil and its products are also given with
reasonable accuracy by the equation:
Q = 12,400 - 2100J 2
where d is the 60/600F specific gravity. Deviation is generally less than 1%,
although many highly aromatic crude oils show considerably higher values; the
range for crude oil is 10,000 to 11,600 cal/g (Speight, 1999, p. 341). For gasoline,
the heat of combustion is 11,000 to 11,500 cal/g (1.0 cal/g =1.80 Btu/lb) and for
kerosene (and diesel fuel) it falls in the range 10,500 to 11,200 cal/g. Finally, the
heat of combustion for fuel oil is on the order of 9,500 to 11,200 cal/g. Heavy oil
and bitumen have a heat of combustion of 9,800 to 10,200 cal/g (Table 5.7). Heats
of combustion of petroleum gases may be calculated from the analysis and data
for the pure compounds. Experimental values for gaseous fuels may be obtained
by measurement in a water flow calorimeter, and heats of combustion of liquids
are usually measured in a bomb calorimeter.
For thermodynamic calculation of equilibria useful in hydrocarbon research,
combustion data of extreme accuracy are required because the heats of formation of
water and carbon dioxide are large in comparison with those in the hydrocarbons.
Great accuracy is also required of the specific heat data for the calculation of
free energy or entropy. Much care must be exercised in selecting values from the
Table 5.7. Heats of Combustion of Alberta (Canada) Heavy Oil and Bitumen
or Bitumen
Mildred Lake
Grosmont
kJ/kg
literature for these purposes, because many of the available values were determined
before the development of modern calorimetric techniques.
An alternative criterion of energy content is the aniline gravity product (AGP)
(ASTM D-1405, IP 193), which is in reasonable agreement with the calorific value.
It is the product of the API gravity and the aniline point (ASTM D-611, IP 2) of
the sample.
The combustion characteristics of petroleum and petroleum products can also
be evaluated by the application of several other tests.
Jet fuels of the same class can vary widely in burning quality as measured by
carbon deposition, smoke formation, and flame radiation. This quality aspect is
largely a function of hydrocarbon composition because paraffins have excellent
burning properties in contrast to those of the aromatic compounds (particularly
polynuclear aromatics); naphthenes have intermediate combustion characteristics
nearer to those of the paraffins.
As a control measure the smoke point test (ASTM D-1322 or IP 57) gives the
maximum smokeless flame height in millimeters at which the fuel will burn in a
wick-fed lamp under prescribed conditions. The combustion performance of widecut fuels correlates well with smoke point when a fuel volatility factor is included,
because carbon formation tends to increase with boiling point. A minimum smoke
volatility index (SVI) value is specified:
SVI = -(smoke point) + 0.42(percent distilled below 2040C: 4000F)
The smoke point test is not universally accepted as a completely reliable criterion of combustion performance, and various alternative laboratory test methods
have previously been specified such as the lamp burning test (ASTM D187, IP 10)
and a limit on the polynuclear aromatic content (ASTM D1840). However, the alternative test now generally accepted is the luminometer number (ASTM D1740).
This test was developed to accommodate the shortened combustion chamber in
many jet engines that is due to high liner temperatures caused by the radiant heat
from luminous flames from certain qualities of fuel. The test apparatus is essentially
a smoke point lamp modified to include a photoelectric cell for flame radiation
measurement and a thermocouple arrangement to measure temperature rise across
the flame. The fuel luminometer number (LN) is expressed on an arbitrary scale
on which values of 0 to 100 are given to reference fuels tetralin and isooctane,
CRITICAL PROPERTIES
A study of the pressure, volume, and temperature relationships of a pure component
reveals a particular unique state at which the properties of a liquid and vapor become
indistinguishable from each other. At that state, the latent heat of vaporization
becomes zero and no volume change occurs when the liquid is vaporized. This
state is called the critical state, and the appropriate parameters of state are termed
the critical pressure (PQ), critical volume (Vc), and critical temperature (7c). It
is an important characteristic of the critical state for a pure component that with
values of P or T greater than either Pc or TQ the vapor and liquid states cannot
coexist at equilibrium, and thus Pc and Tc represent the maximum values of P and
T at which phase separation can occur.
Because the critical state of a component is unique, it is perhaps not surprising
that knowledge of PQ, TQ, and Vc allows many predictions to be made concerning
the physical properties of substances. These predictions are based on the law
of corresponding states, which states that substances behave in the same way
when they are in the same state with reference to the critical state. The particular
corresponding state is characterized by its reduced properties, i.e., Tx = T/TQ,
PV = P/PC,VT
V/VC.
The use of this concept permits generalized plots in terms of reduced properties
to be drawn that are then applicable to all substances (which obey the law) and
can be of great value in determining thermodynamic relationships. It is rare in
petroleum engineering to have to deal with pure substances, and unfortunately the
application of the law of corresponding states to mixtures is complicated by the
fact that use of the true critical point for a mixture does not yield correct values of
reduced properties for accurate prediction from generalized charts. For a mixture,
the critical state no longer represents the maximum temperature and pressure at
which a liquid and vapor phase can coexist, and phase separation can occur under
retrograde conditions.
For engineering purposes, this difficulty is resolved by the use of pseudo-critical
conditions, which are based on the molal average critical temperatures and pressures of the compounds of the mixture. Although use of pseudo-reduced conditions
for mixtures of hydrocarbons is generally satisfactory, this is not true for states
near the true critical, nor, in general, for mixtures of vapor and liquid.
The temperature, pressure, and volume at the critical state are of considerable interest in petroleum physics, particularly in connection with modern high-pressure,
high-temperature refinery operations and in correlating pressure-temperaturevolume relationships for other states. Critical data are known for most of the
lower-molecular-weight pure hydrocarbons, and standard methods are generally
used for such determinations.
The critical point of a pure compound is the equilibrium state in which its
gaseous and liquid phases are indistinguishable and coexistent; they have the same
intensive properties. However, localized variations in these phase properties may
be evident experimentally. The definition of the critical point of a mixture is the
same. However, mixtures generally have a maximum temperature or pressure at
other than the true critical point; maximum here denotes the greatest value at which
two phases can coexist in equilibrium.
Thus, when a pure compound is heated at atmospheric pressure, it eventually
reaches its boiling point and is completely vaporized at a constant temperature
unless the pressure is increased. If the pressure is increased, the compound is
completely condensed and cannot be vaporized again unless the temperature is also
increased. This mechanism, alternately increasing the pressure and temperature,
functions until, at some high temperature and pressure, it is found that the material
cannot be condensed regardless of the amount of pressure applied. This point is
called the critical point, and the temperature and pressure at the critical point are
called the critical temperature and critical pressure, respectively.
The liquid phase and vapor phase merge at the critical point so that one phase
cannot be distinguished from the other. No volume change occurs when a liquid
is vaporized at the critical point and no heat is required for vaporization, but the
coefficient of expansion has become large.
Limited information concerning the behavior of complex mixtures has required
that the pseudo-critical temperature and pseudo-critical pressure be used for many
petroleum fractions and products. The pseudo-critical point is defined as the molal
average critical temperature and pressure of the several constituents that make
up a mixture. It may be used as the critical point of a mixture in computing
reduced temperatures and pressures. However, in computing the pressure-volumetemperature relations of mixtures by use of the pseudo critical point, it must be
recognized that the values are not accurate in the region of the critical point-and
that it cannot be applied to mixtures of gas and liquid.
In the correlation of many properties, reduced properties are useful. Reduced
properties are defined as the ratio of the actual value of the property to its critical
value. Thus for volume, temperature, or pressure the relationships are:
reduced volume, VR = V/ Vc
where V is the volume at specified conditions and Vc is the volume at the critical
point. Similarly,
reduced temperature TR = T/ Tc
reduced pressure PR = P/ P0
Where Tand V are the temperature and volume, respectively, at specified conditions
and Tc and Vc are the temperature and volume, respectively, at the critical point.
Bland, W. R, and Davidson, R. L. 1967. Petroleum Processing Handbook. McGraw-Hill,
New York. p. 12-43.
Butler, R. D. 1979. In: Chromatography in Petroleum Analysis. K. H. Altgelt and
T. H. Gouw (Editors). Marcel Dekker, New York.
DeBruine, W., and Ellison, R. J. 1973. J. Petroleum Institute. 59: 146.
Green, L. E. 1976. Hydrocarbon Processing 55(5): 205.
Green, L. E., Schmauch, L. J., and Worman, J. C. 1964. Anal Chem. 36: 1512.
Hickerson, J. F. 1975. In: Special Publication No. STP 577. American Society for Testing
and Materials, Philadelphia, p. 71.
Long, R. B., and Speight, J. G. 1989. Rev. Inst. Francais du Petrole 44: 205. 366: 391.
MacAllister, D. J., and DeRuiter, R. A. 1985. Paper SPE 14335. 60th Annual Technical
Conference. Society of Petroleum Engineers. Las Vegas. September 22-25.
Nelson, W. L. 1974. Oil and Gas Journal 72(6): 72.
Nelson, W. L. 1958. Petroleum Refinery Engineering. McGraw-Hill. New York.
Noel, F. 1984. Fuel 63: 931.
Roberts, I. 1989. Preprints. Div. Petrol. Chem. Am. Chem. Soc. 34(2): 251.
Romanowski, L. J., and Thomas, K. P. 1985. Report No. DOE/FE/60177-2326. United
States Department of Energy, Washington, DC.
Schwartz, H. E., Brownlee, R. G., Boduszynski, M. M., and Su, F. 1987. Anal Chem. 59:
Smith-Magowan, D., Skauge, A., and Hepler, L. 1982. /. Canadian Petroleum Technology.
21: 28.
Speight, J. G. 1999. The Chemistry and Technology of Petroleum. 3 rd Edition. Marcel
Stuckey, C. L. 1978. /. Chromatographic Science. 16: 482.
Suatoni, J. C , and Garber, H. R. 1975. / Chromatographic ScL 13: 367.
Thomas, K. P., Barbour, R. V., Branthaver, J. E, and Dorrence, S. M. 1983. Fuel. 62: 438.
Thomas, K. P., Harnsberger, P. M., and Guffey, F. D. 1987. Report No. DOE/MC/110762451. United States Department of Energy. Washington, DC.
Vercier, P., and Mouton, M. 1979. Oil and Gas Journal 77(38): 121.
Wallace, D (Editor). 1988. A Review of Analytical Methods for Bitumens and Heavy Oils.
Alberta Oil Sands Technology and Research Authority, Edmonton, Alberta, Canada.
ELECTRICAL AND OPTICAL PROPERTIES
By way of introduction and to restate the concept of earlier chapters, petroleum is
a complex mixture of chemical compounds and exhibits a wide range of physical
properties. The standard properties such as viscosity, density, boiling point, and
color of petroleum were the benchmark by which petroleum was identified.
However, as the complexities of refineries increased to meet the demands of
changing feedstocks and included the heavier feedstocks such as heavy oil and
bitumen, the nature and range of the tests carried out to aid in developing behavior profiles for the feedstocks also became more complex. And although the
chemical composition of a feedstock is a much truer indicator of refining behavior (Nelson, 1958; Gruse and Stevens, 1960; Gary and Handwerk, 1984; AIi
et al., 1985; Wallace et al., 1988; Speight, 2000), it is often not applicable to all
of the operations that are a different reflection of feedstock behavior in a refinery. Therefore, the judicious choice of test methods for any refinery feedstock are
just as important as the selection of the feedstock to produce a specific slate of
The physical and chemical characteristics of crude oil and the yields and properties of products or fractions prepared during refining vary considerably and are
dependent on the concentration of the various types of hydrocarbons and other constituents present. Some types of petroleum have economic advantages as sources
of fuels and lubricants with highly restrictive characteristics because they require
less specialized processing than that needed for production of the same products
from many types of crude oil. Others may contain unusually low concentrations
of components that are desirable fuel or lubricant constituents, and the production
of these products from such crude oils may not be economically feasible.
Thus, the inspection or evaluation methods must give as much information as
possible about the complete character of the crude oil to provide information about
the most logical means of feedstock handling before and during refining. Indeed,
careful evaluation of petroleum from physical property data must be a major part
of the study of any crude oil, heavy oil, or bitumen that is destined to be a refinery
feedstock. Proper interpretation of the data resulting from the inspection of crude
oil requires an understanding of their significance.
In this chapter an indication of the additional physical properties not covered
elsewhere (Chapters 4 and 5) that may be applied to petroleum, or even to petroleum
products, is presented. The properties covered here are properties that are not often
given the attention they deserve.
Although the physical properties of petroleum and petroleum products are often
equated with those of the various related hydrocarbons, the electrical and optical
properties of pure hydrocarbons have been investigated to a lesser degree than
the so-called typical physical properties, leaving considerable gaps in knowledge.
Thus very little is known about the electrical and optical properties of crude oil.
For the purposes of this chapter, data relating to various physical properties are
included as illustrative examples where possible but theoretical discussions of the
physical properties of hydrocarbons were deemed irrelevant and are omitted.
The electrical properties of crude oil and crude oil products (especially lubricating
oils) can be of considerable practical significance. The development of electrostatic
charges in pipelines, in refinery equipment, and in machinery is well known. When
electrical discharges occur through an oil film, observable changes in metal surfaces
can be expected and are usually reflected in the occurrence of pitting. On the other
hand, changes in the crude oil (or its products) might result in sediment or gum
formation, causing problems in refining and product use.
This area of petroleum technology has not been researched as thoroughly as
the other more conventional areas. Thus the electrical properties of petroleum and
its products represent a fertile area of investigation for the analytical chemist as a
result of a definite need to establish tests that are representative of the behavior of
crude oil under these conditions.
From the fragmentary evidence available, the electrical conductivity of hydrocarbons is quite small. For example, the normal hydrocarbons (from hexane up) have
an electrical conductivity smaller than 10~16 2/cm; benzene itself has an electrical
conductivity of 4.4 x 10~17 2/cm, and cyclohexane has an electrical conductivity
of 7 x 10~18 2/cm. It is generally recognized that hydrocarbons do not usually
have an electrical conductivity larger than 10~18 2/cm. Thus it is not surprising
that the electrical conductivity of crude oils or crude oil fractions (ASTM D-3114,
IP 274) that are predominantly hydrocarbon in nature is also exceedingly small,
of the order of K T 1 9 - l ( r 1 2 fi/cm.
Available data indicate that the observed conductivity is frequently more dependent on the method of measurement and the presence of trace impurities than
on the chemical type of the oil. Conduction through oils is not ohmic; that is, the
current is not proportional to field strength. In some regions the current is observed
to increase exponentially with the field strength. Time effects are also observed,
the current being at first relatively large and decreasing to a smaller steady value.
This is partly because of electrode polarization and partly because of ions removed
from the solution. Most oils increase in conductivity with rising temperatures.
6.2.2. Dielectric Constant
The dielectric constant (e) of a substance may be defined as the ratio of the capacity
of a condenser with the material between the condenser plates (C) to that with the
condenser empty and under vacuum (Co):
e = C/C o
The dielectric constant of petroleum and petroleum products is also theoretically
equal to the square of the refractive index.
The dielectric constant (ASTM D-924) may be used to indicate the presence
of various constituents, such as asphaltenes, resins, or oxidized materials, i.e.
materials that are polar in nature and more capable of conducting electricity. In
these cases, the dielectric constant may be higher than that calculated using the
square of the refractive index. Furthermore, the dielectric constant of petroleum
products that are used in equipment, such as condensers, may actually affect the
electrical properties and performance of that equipment (ASTM D-877).
The dielectric constant of hydrocarbons, and hence most crude oils and their
products, is usually low and decreases with an increase in temperature (Table 6.1).
It is also noteworthy that for hydrocarbon materials the dielectric constant is approximately equal to the square of the refractive index (Table 6.2). Polar materials
have dielectric constants greater than the square of the refractive index (page 170).
6.2.3. Dielectric Strength
The dielectric strength, or breakdown voltage (ASTM D-877; see also IP 295), is
the greatest potential gradient or potential that an insulator can withstand without
permitting an electric discharge. The property is, in the case of oils as well as other
dielectric materials, somewhat dependent on the method of measurement, that is,
on the length of path through which the breakdown occurs, the composition, shape,
and condition of the electrode surfaces, and the duration of the applied potential
The standard test used in North America is applied to oils of petroleum origin
for use in cables, transformers, oil circuit breakers, and similar apparatus. Oils of
high purity and cleanliness show nearly the same value under standard conditions,
Table 6.1. Dielectric Constants of Hydrocarbons
and Petroleum Products
n-Hexane
n-Heptane
Lubricating oil
generally ranging from 30 to 35 kV. For alkanes, dielectric strength has been shown
to increase linearly with liquid density, and the value for a mineral oil fits the data
well. For ^-heptane, a correlation was found between the dielectric strength and
the density changes with temperature. There are many reasons that the dielectric
strength of an insulator may fail. The most important appears to be the presence
of some type of impurity, produced by corrosion, oxidation, thermal or electrical
cracking, or gaseous discharge; invasion by water is a common trouble.
Table 6.2. Relationship of the Refractive Index to the
Dielectric Constant of Hydrocarbons
Index n
rc-Hexane
rc-Heptane
Dielectric Loss and Power Factor
A condenser insulated with an ideal dielectric shows no dissipation of energy when
an alternating potential is applied. The charging current, technically termed the
circulating current, lags exactly 90 in phase angle behind the applied potential, and
the energy stored in the condenser during each half-cycle is completely recovered
in the next. No real dielectric material exhibits this ideal behavior; that is, some
energy is dissipated under alternating stress and appears as heat. Such a lack of
efficiency is broadly termed dielectric loss.
Ordinary conduction comprises one component of dielectric loss. Here the
capacitance-held charge is partly lost by short circuit through the medium. Other
effects in the presence of an alternating field occur, and a dielectric of zero conductivity may still exhibit losses. Suspended droplets of another phase undergo
spheroidal oscillation by electrostatic induction effects and dissipate energy as
heat as a consequence of the viscosity of the medium. Polar molecules oscillate
as electrets and dissipate energy on collision with others. All such losses are of
practical importance when insulation is used in connection with alternating-current
equipment.
The measure of the dielectric loss is the power factor (ASTM D-877). This is
defined as the factor k in the relation:
k = W/EI
where W is the power in watts dissipated by a circuit portion under voltage E and
passing current/.
From ac theory, the power factory is recognized as the cosine of the phase
angle between the voltage and current where a pure sine wave form exists for
both; it increases with a use in temperature. When an insulating material serves
as the dielectric of a condenser, the power factor is an intrinsic property of the
dielectric. For practical electrical equipment, low-power factors for the insulation
are of course always desirable; petroleum oils are generally excellent in this respect, having values of the order of 0.0005, comparable with fused quartz and
polystyrene resins. The power factor of pure hydrocarbons is extremely small.
Traces of polar impurities, however, cause a striking increase. All electrical oils,
therefore, are drastically refined and handled with care to avoid contamination;
insoluble oxidation products are particularly undesirable.
Static Electrification
Dielectric liquids, particularly light naphtha, may acquire high static charges on
flowing through or being sprayed from metal pipes. The effect seems to be associated with colloidally dispersed contaminants, such as oxidation products, which
can be removed by drastic filtration or adsorption. Because a considerable fire hazard is involved, a method has evolved for obtaining data that will help to minimize
the potential danger (ASTM D-4470).
For large-scale storage, avoidance of surface agitation and use of floating metal
roofs on tanks are beneficial. High humidity in the surrounding atmosphere is
helpful in lowering the static charge, and radioactive materials have been used to try
to induce discharge to ground. A variety of additives have been found that increase
the conductivity of petroleum liquids, thus lowering the degree of electrification;
chromium salts of alkylated salicylic acids and other salts of alkylated sulfosuccinic
acids are used in low concentrations, for example, 0.005%.
OPTICAL PROPERTIES
The most obvious optical property of petroleum and petroleum products is the
color of the material. In these days when heavy oils, residua, and bitumen are
refinery feedstocks and these materials are generally black, the color test has lesser
significance in the preliminary inspection of the feedstock.
However, the color tests continue to play an important role in determining the
purity and/or the stability of petroleum products (Mushrush and Speight, 1995), for
example, tests for the acid or basic nature of petroleum products by color titration
(ASTM D-974, IP 139, 213, IP 431), the Doctor test for sulfur species (ASTM
D-4952), the color of aviation gasoline (ASTM D-2392), the color of petroleum
products using a color scale (ASTM D-1500, IP 17, IP 196), and the color of
petroleum products using the Saybolt chromometer (ASTM D-156). In fact, the
test for the color of petroleum products (ASTM D-1500) can, if desired, be adapted
to heavy oil and bitumen by applying the test to specifically diluted solution of
heavy oil or bitumen in a colorless solvent such as toluene.
The refractive index (ASTM D-1218, ASTM D-1747) is the ratio of the velocity of light in a vacuum to the velocity of light in the substance. The refractive
index can be used to give information about the composition of hydrocarbon mixtures (ASTM D-2140, ASTM E-1303, IP 346, IP 391, IP 436). As with density,
(Chapter 4) low values are typical of paraffins and higher values are typical of
aromatic compounds.
The measurement of the refractive index is very simple (ASTM D-1218). It
requires small quantities of material and, consequently, has found wide use in the
characterization of hydrocarbons and petroleum samples.
This method (ASTM D-1218) covers the measurement of the refractive index of
liquid petroleum and petroleum products in the range of 1.3300-1.6500. Typically,
the measurement is carried out at 200C (68F). Most instruments are capable of
operation from 5C to 400C (4PF to 1040F).
In a critical angle refractometer, light is directed at the interface between
a prism and the sample at a range of angles. At the critical angle, the light
changes from penetrating the sample to being totally reflected back into the
prism from the interface. Knowing the angle at which this happens and the properties of the prism, the refractive index (RI) may be determined. The specified unit measures this angle, applies appropriate corrections if required, and
displays the refractive index directly on a digital display. The temperature of
the prism may also be displayed. The advantage of the critical angle unit is
that the light is not passed through the sample, as in the Abbe refractometer.
This makes the critical angle unit suitable for highly colored liquids as well as
clear liquids, in contrast to the Abbe refractometer, which cannot measure dark
A critical angle refractometer measures the very thin layer of liquid that contacts the prism, typically the continuous phase of the sample. It will frequently
not be influenced by suspended or dispersed material in the sample. Emulsions
and very fine dispersions may influence the unit. A particulate-free, single-phase
sample is far better, but one containing these inclusions is not automatically
excluded.
For closely separated fractions of similar molecular weight, the values increase
in the order paraffin, naphthene, aromatic. For poly cyclic naphthenes and polycyclic aromatics, the refractive index is usually higher than that of the corresponding monocyclic compounds. For a series of hydrocarbons of essentially the same
type the refractive index increases with molecular weight, especially in the paraffin series (Table 6.3). Thus the refractive index can be used to provide valuable
information about the composition of hydrocarbon (petroleum) mixtures; as with
density, low values indicate paraffinic materials and higher values indicate the presence of aromatic compounds. However, the combination of refractive index and
density may be used to provide even more definite information about the nature of
a hydrocarbon mixture and, hence, the use of derived data such as the refractivity
intercept (n - d/2) (Table 6.4) (ASTM D-2140, ASTM D-2159) and the specific
refraction [(n2 I)/(n 2 + 2) x 1/d] as being indicative of the composition of
hydrocarbon mixtures.
The refractive index of viscous materials [including viscous liquids and melted
solids have refractive indices between 1.33 and 1.60 and at temperatures from 800C
to 1000C (176F to 212F)]. However, the method is not applicable to liquids that
have colors darker than ASTM Color No. 4 (ASTM D-1500) or to solids that
melt within 1O0C (180F) of the test temperature. These caveats may disqualify
many types of heavy oil (because of the color) and bitumen (because of the high
Table 6.3. Refractive Indices of Hydrocarbons
Hexane
Nonane
Nonadecane
Cyclopentane
Cycloheptane
Propylbenzene
Tetralin
Decalin
n^a
n$: Refractive index at 200C (68F) at the wavelength of the sodium
D line.
melting point, ASTM D-87 and D-127, or the high pour point, ASTM D-97)
The refractive dispersion of a substance is defined as the difference between its
refractive indices at two specified wavelengths of light (ASTM D-1218). Two lines
commonly used to calculate dispersions are the C (6563 D, red) and F (4861 D,
blue) lines of the hydrogen spectrum. The specific dispersion is the refractive
Table 6.4. Refractivity Intercept for Hydrocarbon Types
Saturated monocyclics
Saturated polycyclics
Diolefins
Conjugated diolefins
Cycloolefins
Conjugated cyclodiolefins
dispersion divided by the density at the same temperature:
specific dispersion = nF nc/d
This equation is of particular significance in petroleum chemistry because all the
saturated hydrocarbons, naphthene and paraffin, have nearly the same value irrespective of molecular weight, whereas aromatics are much higher and unsaturated
aliphatic hydrocarbons are intermediate. The refractive and specific dispersion
(ASTM D-1807) as well as the molecular and specific refraction have all been
advocated for use in the characterization of petroleum and petroleum products.
Specific refraction is the term applied to the quantity defined by the expression:
l/(n2 + 2)d = C
where n is the refractive index, d is the density, and C is a constant independent
of temperature.
Molecular refraction is the specific refraction multiplied by molecular weight;
its particular usefulness lies in the fact that it is very nearly additive for the components of a molecule; that is, numerical values can be assigned to atoms and structural
features, such as double bonds and rings. The value for any pure compound is then
approximately the sum of such component constants for the molecule.
Optical Activity
The occurrence of optical activity in petroleum is universal and is a general phenomenon not restricted to a particular type of crude oil, such as the paraffinic or
naphthenic crude oils. Petroleum is usually dextrorotatory, that is, the plane of
polarized light is rotated to the right, but there are known levorotatory crude oils,
that is, the plane of polarized light is rotated to the left, and some crude oils have
been reported to be optically inactive.
Examination of the individual fractions of optically active crude oils shows
that the rotatory power increases with molecular weight (or boiling point) to pronounced maxima and then decreases again. The rotatory power appears to be
concentrated in certain fractions, the maximum lying at a molecular weight of
about 350-400; this maximum is about the same for all crude oils. The occurrence
of optically active compounds in unaltered natural petroleum has been a strong
argument in favor of a rather low temperature origin of petroleum from organic
raw materials (Speight, 1999).
A magnetic field causes all liquids to exhibit optical rotation, usually in the
same direction as that of the magnetizing current; this phenomenon is known as
the Faraday effect, and it may be expressed by the relation:
0 = pth
where 6 is the total angle of rotation, t is the thickness of substance through which
the light passes, and h is the magnetic field; the constant p is an intrinsic property of
the substance, usually termed the Verdet constant (minutes of arc/cm/gauss). There
have been some attempts to use the Verdet constant in studying the constitution of
hydrocarbons by physical property correlation (Gruse and Stevens, 1960).
AIi, M. R, Hasan, M., Bukhari, A., and Saleem, M. 1985. Oil Gas J. 83(32): 71.
Gary, J. H., and Handwerk, G. E. 1984. Petroleum Refining: Technology and Economics.
Marcel Dekker, New York.
Gruse, W. A., and Stevens, D. R. 1960. Chemical Technology of Petroleum. 3rd Edition.
McGraw-Hill, New York. p. 199.
Mushrush, G. W., and Speight, J. G. 1995. Petroleum Products: Instability and Incompatibility. Taylor & Francis Publishers, Philadelphia, PA.
Nelson, W. L. 1958. Petroleum Refinery Engineering. 4th Edition. McGraw-Hill. New York.
Sand Resources. Alberta Oil Sands Technology and Research Authority, Edmonton, AB,
SPECTROSCOPIC METHODS
The chemical composition of a feedstock, subject to the reservations mentioned
in an earlier chapter (Chapter 2), has always been considered to be a valuable
indicator of refining behavior. Whether or not it is the ultimate indicator of refining
behavior remains to be seen and is audience dependent! More than likely, chemical
composition studies truly complement physical property and physical behavior
studies, and the true picture is a combination of all of these studies.
However, the chemical composition of a feedstock is represented in terms of
compound types and/or in terms of generic compound classes, thus allowing the
analytical chemist, the process chemist, the process engineer, and the refiner to
determine the nature of the reactions. Hence, chemical composition can play a
large part in determining the nature of the products that arise from the refining
operations. It can also play a role in determining the means by which a particular
feedstock should be processed (Nelson, 1958; Gary and Handwerk, 1984; AIi et al.,
1985; Wallace et al., 1988; Speight, 2000). However, proper interpretation of the
data resulting from the composition studies requires an understanding of chemical
structures, their significance, and an open mind!
products from many types of crude oil. Others may contain unusually low concentrations of components that are desirable fuel or lubricant constituents, and
the production of these products from such crude oils may not be economically
feasible.
Spectroscopic studies have played an important role in the evaluation of petroleum and of petroleum products for the last three decades, and many of the methods
are now used as standard methods of analysis for refinery feedstocks and products.
Application of these methods to feedstocks and products is a natural consequence
for the refiner.
The methods include the use of mass spectrometry to determine the (1) hydrocarbon types in middle distillates (ASTM D-2425); (2) hydrocarbon types of
gas oil saturate fractions (ASTM D-2786); (3) hydrocarbon types in low-olefin
gasoline (ASTM D-2789); and (4) aromatic types of gas oil aromatic fractions
(ASTM D-3239). Nuclear magnetic resonance spectroscopy has been developed
as a standard method for the determination of hydrogen types in aviation turbine
fuels (ASTM D-3701). X-ray fluorescence spectrometry has been applied to the determination of lead in gasoline (ASTM D-2599), the analysis of selected elements
(nitrogen, sulfur, nickel, and vanadium) in water-borne oil (ASTM D-3327), the
identification of chemicals in water (ASTM D-4763), as well as the determination
of sulfur in various petroleum products (ASTM D-2622, ASTM D-4294).
Infrared spectroscopy is used for the determination of benzene in motor and/or
aviation gasoline (ASTM D-4053), and ultraviolet spectroscopy is used for the
evaluation of mineral oils (ASTM D-2269) and for determining the naphthalene
content of aviation turbine fuels (ASTM D-1840).
Other techniques include the use of flame emission spectroscopy for determining trace metals in gas turbine fuels (ASTM D-3605) and the use of absorption
spectrophotometry for the determination of the alkyl nitrate content of diesel fuel
(ASTM D-4046). Atomic absorption has been used as a means of analysis of
metals (ASTM D-1971, ASTM D-4698, ASTM D-5056), for measuring the lead
content of gasoline (ASTM D-3237, IP 362), for the manganese content of gasoline (ASTM D-3831), as well as for determining the barium, calcium, magnesium,
and zinc contents of lubricating oils (ASTM D-4628). Flame photometry has been
used as a means of measuring the lithium/sodium content of lubricating greases
(ASTM D-3340) and the sodium content of residual fuel oil (ASTM D-1318).
Nowhere is the contribution of spectroscopic studies more emphatic than in
application to the delineation of structural types in the heavier feedstocks. This has
been necessary because of the unknown nature of these feedstocks. One particular
example is the n.d.M. method (ASTM D-3238) that is designed for the carbon
distribution and structural group analysis of petroleum oils. Later investigators
have taken structural group analysis several steps further than the n.d.M. method.
It is also appropriate at this point to give a brief description of other methods
that are used for the identification of the constituents of petroleum (Yen, 1984).
Although very useful information can be provided about the composition of
high-molecular-weight petroleum fractions by the right combination of separation
and analytical methods, spectroscopic methods can also be applied to the problems
of characterization and identification. For example, information about the nature
of polar functional groups or the elucidation of the way vanadium and nickel are
bound to the molecules is available from a variety of spectroscopy techniques a
well as by use of a variety of chemical techniques (Chapter 8).
It is not intended to convey here that any one of these methods can be used
for complete characterization and identification of the high-molecular-weight
petroleum constituents. Even though any one of these methods may fall short
of complete acceptability as a method 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 molecular types. This is especially
true when the methods are used in conjunction with each other.
In this chapter, an examination of the various spectroscopic and spectrometric
techniques is presented as well as examples of the application of these techniques
to studies of the chemical composition of petroleum, heavy oil, and bitumen.
Infrared spectroscopy is a well-established method that was developed for comparative, semiquantitative analysis leading to the present quantitative analysis
(ASTM E-168, ASTM E-204, ASTM E-334, ASTM E-1252, IP 429; Bellamy,
1975; Nakanishi and Solomon, 1977; Sastri et al, 1995).
Infrared spectra are displayed either as percent transmittance or as adsorptivity
versus frequency (cm" 1 ). Transmittance (T), defined as the ratio of transmitted
light over incident light, or percent transmittance (1007), usually shows more
detail over the entire range and is generally the preferred display. Absorbance (A),
on the other hand, is proportional to the concentration and is, therefore, used for
quantitative measurements. Thus,
A = -loge(r)
It is more common now to record the apparent absorptivity, Aapp,
^app = 1Og 10 (^)
Therefore, at sufficiently low concentration,:
- 1Og10(TX, = cltv
where v is the wavelength of the light, c is the sample concentration, / is the sample
thickness (path length), and 8 is the (apparent) molecular absorption coefficient
at that wavelength. The true molar absorption coefficient is proportional to the
natural logarithm of the transmittance.
Infrared spectroscopy is a simple procedure and provides quick information
about the distribution of several structural and functional groups (Table 7.1). In
combination with nuclear magnetic resonance spectroscopy, it will provide quick
yet fairly detailed data on the distribution of carbon-hydrogen groups (Yen, 1973).
Table 7.1. Band Assignments in the Infrared Spectra of Petroleum Fractions
cm" 1
[x
/OU
1j. iO
Aromatic C - H stretching
Methyl C - H stretching
Methylene C - H stretching
Carbonyl C = O
C = C and C = O (hydrogen-bonded)
C - H bending
C - H bending in methyl groups
Sulfur-oxygen functions
Sulfur-oxygen functions0
Aromatic C - H bending (out of plane)
"Also aromatic ethers.
However, in the context of high-molecular-weight petroleum fractions, conventional infrared spectroscopy yields information about the functional features
of various petroleum constituents. For example, infrared spectroscopy will aid in
the identification of imino (=NH) and hydroxyl (OH) functions, as well as
the nature of the various carbonyl (-C=O) functions.
In the older infrared spectroscopy, light is refracted by a prism or a grating
and scanned by a moving slit that takes several minutes for one measurement. In
Fourier transform infrared (FTIR) spectroscopy, the entire spectrum is obtained by
an interferometer in a fraction of a second. Several hundred measurements can be
taken in a matter of minutes and averaged by computer. This multiplexing leads to
greatly increased (about 100-fold) sensitivity and precision over those achievable
with dispersive instruments.
Thus, with the recent progress of Fourier transform infrared (FTIR) spectroscopy, quantitative estimates of the various functional groups can also be made.
This is particularly important for application to the higher-molecular-weight solid
constituents of petroleum (i.e., the asphaltene fraction) and for group-type analysis
(lob et al., 1996; Michon et al., 1997).
It is also possible to derive structural parameters from infrared spectroscopic
data, and these are (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 next section), structural
parameters such as the fraction of paraffinic methyl groups to aromatic methyl
groups can be obtained.
The newer diffuse reflectance infrared (DRIR) techniques (Fuller and Griffiths,
1978; Christy et al., 1989) seem to give spectra equally as good as those obtained
in conventional ways from solutions in cells or from potassium bromide (KBr)
pellets. Another synonym for this technique is DRIFT (for diffuse reflectance
infrared Fourier transform).
The sample is deposited from solution onto finely ground potassium bromide in
a small cup that is placed into a diffuse reflectance accessory after removal of the
solvent in a vacuum oven. A related technique, variable angle specular reflectance,
allows rotation of the sample holder for optimization.
Increased resolution by band narrowing techniques (Wang and Griffiths, 1985;
Chen et al., 1985) in conjunction with reference spectra allows the distinction
of methylene (CH2) groups next to other groups such as alky Is, aromatic rings,
carbonyls, or alkoxl groups. Carbon-hydrogen (CHn) groups and aromatic carbon
can be identified, measured, and compared. The ratio of the band at 1602 cm" 1
(aromatic C - C stretching) to that at 2920 cm" 1 [aliphatic hydrogen-carbon stretching in methylene groups (P or further away from the aromatic ring] is a good
relative measure for the aromaticity of a sample.
Fourier transform infrared spectroscopy is sufficiently sensitive that it can be
used for detection in high-performance liquid chromatography (HPLC) and even in
gas chromatography (GC) and supercritical fluid chromatography (SFC) (Norton
etal., 1991).
Band assignments (Table 7.1) for infrared spectra were established several
decades ago. Resolution enhancement by Fourier self-deconvolution (band narrowing) led to the recognition and distinction of bands that previously could not
be separated. Examples of such new assignments are methyl (CH3) groups next to
aromatic rings (2948 cm" l ) and next to alkyl groups (2960 cm" 1X methylene (CH2)
groups (together with some methyl groups) next to aromatic rings (2916 cm" 1 )
and in aliphatic chains (2926 cm" 1 ), methylene groups next to an alkoxy function
(2928 cm" 1 ) and next to a carbonyl group (2933 cm" 1 ); and methine (CH) groups
in unspecified environments (2905 cm" 1 and 1897 cm" 1 ). The rocking vibration
band of methylene groups in straight aliphatic chains varies slightly with their
length. For rc-pentyl groups, it is located at 726 cm" 1 , and with longer chains, it
shifts to lower frequencies until it stabilizes at 720 cm" 1 for chains with more than
nine carbon atoms.
In the analysis of the high-molecular-weight petroleum constituents, infrared
spectroscopy has been mostly used for measuring oxygen- and nitrogen-containing
groups and for evaluating shifts in certain bands caused by aggregation or other
interactions such as carboxylic acids, phenols, carbazoles, cyclic amides, as well
as pyridine and acridine variants among the bases (Petersen, 1967; McKay et al.,
1975, 1976; Moschopedis and Speight, 1977; Green et al., 1985; Jacobson and
Gray, 1987).
In the lower-boiling petroleum fractions, parts of the hydrocarbon skeleton can
be assessed by infrared spectroscopy. Specifically, the alkyl substitution of aromatic
rings can be determined from the out-of-plane carbon-hydrogen deformation bands
(Jokuty and Gray, 1991).
7.3. NUCLEAR MAGNETIC RESONANCE
Nuclear magnetic resonance has frequently been used for general studies of hydrogen types in petroleum and petroleum products (ASTM D-4808, IP 392) as
well as for the structural studies of petroleum constituents (ASTM E-386; see also
Bouquet and Bailleul, 1982; Hasan et al., 1989; Speight, 1994). The technique
has recently been adapted to measure the hydrogen content of fuels and other
petroleum products (ASTM D-3701; ASTM D-4808 IP 338) (see also Chapter 4).
In fact, proton magnetic resonance (PMR) 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 petroleum.
Thus nuclear magnetic resonance (NMR) methods have gained a prominent
place in the compositional and structural analysis of petroleum fractions (Speight,
1994). In its basic applications, NMR is fast and relatively inexpensive. Because
of its convenience, speed, and greater wealth of detailed information, particularly
from 13C-NMR, it has displaced the n-d-M and related methods (Chapter 11) in
most laboratories. NMR directly measures aromatic and aliphatic carbon as well
as hydrogen distributions. Beyond these results, both C and H in various structural
groupings in a molecule can be determined.
Proton (1H) and carbon-13 (13C) nuclei are the most common ones used in
NMR spectroscopy; nitrogen (15N and 14N) and sulfur (33S) have been used on
occasion with petroleum fractions for special applications. This section focuses
on the regular NMR techniques (1H and 13C) for the structural group analysis of
petroleum fractions.
Proton magnetic resonance has been widely used in the structural analysis of
petroleum fractions. It is a relatively inexpensive technique, that allows measurement of hydrogen atoms in aromatic and aliphatic groups, even allowing differentiation between hydrogen attached to next to an aromatic ring (a-position) and
those farther removed from the ring. Atoms in single-ring and multiring aromatic
compounds as well as those in olefinic locations can also be identified.
Only a small amount (< 10 mg) of the sample is required, dissolved in a solvent
such as deutero-chloroform, contained in a glass tube of 5-mm diameter and placed
in a highly homogeneous magnetic field where it is surrounded by one or more
coils. The coils serve to subject the sample to a weak radio-frequency (rf) field.
The hydrogen nuclei of the sample can be visualized as magnets, and when the
radio frequency is equal to the processing frequency, resonance occurs between the
two and the spin resonance is detected by a receiver coil. The position of a sample
resonance with that of tetramethylsilane (TMS) as a reference difference is reported
as chemical shift 8, which is a dimensional number that is expressed in terms of
parts per million (ppm) difference from the reference (TMS) (Tables 7.2 and 7.3)
(Bartle et al., 1979b; Snape et al., 1983; Cookson and Smith, 1987; Netzel, 1987).
Quantitative accuracy of proton magnetic resonance for aromatic and aliphatic
hydrogen is about 1% for distillates and 2-3% for residua; that for the distinction
of aliphatic hydrogen atoms a to an aromatic ring from those (3 and farther away
from the ring is somewhat lower. Methyl (CH3), methylene (CH2), and methine
(CH) hydrogen can ordinarily not be distinguished except for methyl hydrogen 7
or farther away from aromatic rings. Even this methyl peak is sometimes difficult to
quantify because of interference by naphthenic methine and methylene hydrogen.
Protons attached to single-ring and multiring aromatic compounds can usually
be distinguished with reasonable accuracy, especially when the sample concentration is 2% or less. At such low concentrations, the dividing line between these
protons is at 7.25 ppm (Cookson and Smith, 1987). In the spectra of samples with
high boiling point, much of the detail is lost and differentiation between group
types is difficult.
Thus, in general, the proton (hydrogen) types in petroleum fractions can be
subdivided into three types (Brown and Ladner, 1960):
1. aromatic ring hydrogen;
2. aliphatic hydrogen adjacent to an aromatic ring; and
3. aliphatic hydrogen remote from an aromatic ring
or into five types (Yen and Erdman, 1962):
aromatic hydrogen;
substituted hydrogen next to an aromatic ring;
naphthenic hydrogen;
methylenic hydrogen; and
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 the carbon backbone obtained from proton spectra are derived by inference but protons at peripheral positions can be obscured by intermolecular interactions. This, of course, can
Table 7.2. Proton Signal Assignments in Organic Compounds
Signal T
Ar-H
Olefinic H
P-CH2
Alrylic CH2
H(eq.)
1-CH 3
H(ax.)
Mesitylene
Fluorene
Dibenzyl
tf-Xylene
Adamantane
2-Phenylbutane
trans-Decalm (strong)
Cyclooctane
ds-Decalin
rc-Octane
TV-Octane
/rans-Decalin (weak)
Tetramethylsilane
Source: Reproduced from Speight, J. G., Fuel 1970,49:79, by permission of the
publisher, IPC Business Press, Ltd. .
Table 7.3. General Hydrogen Group Assignments in the Proton Magnetic Resonance
Spectra of Petroleum Fractions
Symbol Range T Center T
Assignments0
Aromatic protons
HMy
a-Methyl
a-Methylene
a-Methine
Methylene
Methine
as-Peripheral
Naphthenic p -Methyl paraffinic
Methylene other than
(B-Methylparaffinic transa- or p-paraffinic
peripheral bridge
methine-naphthenic
rrans-Peripheral bridge
Methyl other than amethine-naphthenic
or P-paraffinic
OH in phenols
NH in pyrroles
The letters a and (3 indicate positions relative to an aromatic ring.
Source: Reproduced from Speight, J. G., Fuel 1970,49:78, by permission of the publisher, IPC Business
Press, Ltd. .
cause errors in the ratios that can have a substantial influence on the outcome of
the calculations (Ebert et al., 1987; Ebert, 1990).
It is in this regard that carbon-13 magnetic resonance (CMR) can play a useful
role. Because carbon magnetic resonance deals with analyzing the carbon distribution types (Table 7.4; Altgelt and Boduszynski, 1994), the obvious structural
parameter to be determined is the is aromaticity, / a . A direct determination from
the various carbon type environments is one of the better methods for the determination of aromaticity (Snape et al., 1979). Thus, through a combination of
proton and carbon magnetic resonance techniques, refinements can be made on
the structural parameters and, for the solid-state high-resolution CMR technique,
additional structural parameters can be obtained (Weinberg et al., 1981).
The basic instrumentation for carbon-13 magnetic resonance is the same as that
for proton magnetic resonance except that there are two radio frequency fields
orthogonal (at right angles) to the main magnetic field, one for observing the
carbon-13 nuclei and the other for decoupling the proton nuclei. The low abundance
of carbon-13 isotopes (1.1%) and the lower gyromagnetic ratio of the carbon-13
nucleus make the signal weaker by more than two orders of magnitude, and, moreover, the nuclei have longer relaxation times. The effect is that, even with Fourier
Table 7.4. Carbon Assignments in 13C Magnetic Resonance Spectroscopy
(ppm)
24.4-24.65
O)CH3
7,8 CH3 a to CH
8+ CH2 next to CH3
8 CH3 next to CH at end of chain
CH3 on naphthenic groups
8+ CH2 p to two CH groups
7 CH2 P to two CH groups
CH a to two terminal CH3 groups
7 + CH2 in long chains away from branch points
7 CH2 in long chains away from branch points
8+ CH2 2 C removed from CH3
CH in chain next to CH3 (methyl branch)
8+ CH next to CH3 (isolated methyl branch)
8 + CH2 next to CH in chain far from end
e + CH2 next to CH chain near end
transform (FT) data acquisition, carbon-13 magnetic resonance measurements can
take hours to perform.
In contrast to proton magnetic resonance spectroscopy, the peak areas arising from the carbon-13 nuclei in different molecular positions ordinarily are not
proportional to their concentration. Quantitative measurements require that two
effects must be overcome: (1) the different relaxation times of the carbon-13 nuclei in different chemical groups, and (2) the nuclear Overhauser enhancement
(NOE). The latter effect refers to the rise in signal intensity when C - H coupled
protons are saturated by the decoupling field.
One way to do this is to add a small amount of a paramagnetic relaxation
reagent, such as trisacetylacetonatochromium(III) [Cr(AcAc)3], which changes
the dominant relaxation mechanism into one involving the interaction between
unpaired electrons and 13C nuclei. It also reduces the long relaxation times of
some carbons, thus taking care of the first of the two detrimental effects.
In its simplest form, carbon-13 magnetic resonance can distinguish between
aliphatic and aromatic carbon (Bartle et al., 1979a). In the aliphatic region of
petroleum 13C-NMR spectra, several sharp peaks stand out and are used for quantitative evaluation (Bartle et al., 1979a, 1979b; Netzel et al., 1987; Cookson and
Smith, 1985: Breitmaier and Voelter, 1987: Thiel and Gray, 1988; Sastri et al.,
The most prominent peak is usually that at 29.7 ppm. It is attributed to methylene
(CH2) carbon atoms in long alkyl chains, positioned four or more carbons (> 7)
away from an aromatic ring and from terminal methyl CH3 groups.
Normally, the absorption of 29.5-30.3 ppm gives an estimation of the amount
of carbon atoms in long alkyl chains (> C5). Because this band represents methylene (CH2) groups two or more carbons away from an aromatic ring and a terminal group, there must be four more carbons per chain than indicated by the
area under these peaks. The number of long chains (ncm) can be estimated
from the peaks at 14.2 ppm (coCH3) and at 28.1 ppm (CH2) next to a terminal branch point, i.e., a methine (CH) group. On the one hand, the peak at
14.2 ppm gives results too high for this purpose because it also indicates CH3
groups from chain branches. Subtracting half of the 37.6-ppm peak area (CH2
next to CH groups inside a chain) corrects for this feature. On the other hand,
the peak at 14.2 ppm does not cover twin CH3 groups (as in an isopropyl group,).
This is why the 28.1 peak (CH next to 2 terminal methyl groups is
needed. Thus
CH2iong chains = A(14.2) - 1/2A(37.6) + 1/3A(28.1)
The number of methylene groups in long chains is the sum of the by the peak
at 29.7 ppm, the number of methylene groups at the two ends, i.e., six times the
number of long chains for each of the two ends (Fig. 5.8), and the number close
to branch points inside the chain, namely, those next to them and one carbon atom
removed, on both sides of the CH group. Thus the total numbers is:
JlCH2 = C(29.7) + 6rcCH2long chains + 4C(37.6)
The number of methine (CH) groups in long chains can be estimated from the absorbance at 37.6 ppm and at 39.5 ppm. The peak at 37.6 ppm represents methylene
groups next to methane carbon and thus does not represent a direct measurement
of the methane groups. Thus:
"CHlong chains = 1/2C(37.6) + C(39.5)
The methyl groups give rise to at least four peaks in carbon-13 spectra, namely,
the peaks at 11.5, 14.2, 19.5, and 22.7 ppm. The peak 22.7 ppm represents twin
methyl groups as in an isopropyl group, and it also has a contribution from a
methylene group next to a methyl group and does not need to be represented again
by a contribution to the equation from the peak at 14.2 ppm. Thus:
"CH3long chains = C(11.5) + C(19.5) + C(22.7)
The final estimate for carbon atoms in long chains is then the sum of the three types.
The average length of long chains derives from dividing the number of carbon
atoms in long chains by the number of long chains, remembering, of course, that
averages derived from magnetic resonance spectra can be very misleading if the
data are interpreted too literally (Speight, 1999).
The methyl group (CH3) gives rise to several peaks depending on its position
in the molecule. A peak at 14.2 ppm signals such a group positioned at the end of
an unbranched chain segment of at least two or three methylene (CH2) groups. A
methyl group next to a branch point (methine group, CH) at the end of a chain with
at least two methylene groups produces a peak at 22.7 ppm. Farther away from the
end of the chain, such a group gives a peak at or near 19.8 ppm. The methyl group
at the end is also affected by these branch points (Fig. 5.8).
Naphthenic carbon in high-molecular-weight petroleum fractions usually occupies so many slightly different positions that the peaks are unresolved and form a
broad hump in the range 25-60 ppm, under the generally well-resolved paraffinic
peaks.
The evaluation of the hump is the only direct method for the determination of
naphthenic methylene and methane (CHn) groups. However, its measurement may
not always be reliable. In very high-boiling petroleum samples, such as asphaltenes,
the paraffinic resonance may be only partly resolved. Although this leads mainly
to broader peaks, the overlap may in some cases add to the hump and, thus,
cause erroneously high results for naphthenic carbon. The aromatic region of the
C-NMR spectrum can be evaluated by conventional integration of the peaks due
to the main aromatic group types.
Thus proton and carbon-13 magnetic resonance spectroscopic techniques offer
potential information about the molecular types in the nonvolatile fractions of
petroleum. The techniques have, by the application of the estimation of peak areas
and further application of mathematical methods, been used to obtain information
about structural parameters that are then converted to average structures.
In most cases, the average structure of such complex mixtures as petroleum
fractions is not the same as a representative structure. As already noted, average
structures derived from magnetic resonance spectra can be very misleading if the
data are interpreted too literally (Speight, 1999). Even though the average structures
may always be questioned, one must also treat with some caution the structural
parameters because they have been derived using assumptions that themselves are
subject to debate.
7.4. MASSSPECTROMETRY
Mass spectrometry furnishes the molecular weight and chemical formula of compounds and their relative amounts in a mixture and offers nondestructive examination of the sample (ASTM D-2425, ASTM D-2650, ASTM D-2786, ASTM
D-2789, ASTM D- 3239, ASTM E-1316,). The technique can also provide important information about their molecular structure. The earliest and most common
type of mass spectrometry, electron impact mass spectrometry (EI-MS), gives a
fragmentation pattern displaying both parent ion peaks and fragment ion peaks,
characteristic of each molecular type.
Fragmentation is frequently used to differentiate between isomers of pure compounds and of molecules in fairly simple mixtures. However, it is usually avoided
with such complex samples as high-molecular-weight petroleum fractions, which
are composed of such a multitude of closely related compounds that their fragmentation patterns are nondistinctive and cannot be readily interpreted.
Mass spectrometry can play a key role in the identification of the constituents
of feedstocks and products either in the laboratory or on-line (ASTM D-2425;
ASTM D-2786; ASTM D-2789; ASTM D-3239; see also Aczel, 1989; Cook
et al., 1999). The principal advantages of mass spectrometric methods are (1) 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 required for analysis. The ability
of mass spectrometry to identify individual components in complex mixtures is
unmatched by any modern analytical technique, with, perhaps the exception of gas
chromatography.
However, there are disadvantages arising from the use of mass spectrometry
and these are (1) the limitation of the method to organic materials that are volatile
and stable at temperatures up to 3000C (5700F) and (2) the difficulty of separating
isomers for absolute identification. The sample is 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 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.
Mass spectrometry should be used discriminately where a maximum amount of
information can be expected. The heavier nonvolatile feedstocks are, for practical
purposes, beyond the useful range of routine mass spectrometry. At the elevated
temperatures necessary to encourage volatility, thermal decomposition will occur
in the inlet, and any subsequent analysis would be biased to the low-molecularweight end and to the lower-molecular-weight products produced by the thermal
decomposition.
High-voltage electron impact mass spectrometry can cause repeated fragmentation of daughter ions. Considering the repeated fragmentation of even the simplest
hydrocarbons and the fact that the higher-molecular-weight fractions of petroleum
contain such a broad range of molecular weight species (Chapter 12), the patterns
obtained from petroleum fractions are so complex as to almost defy interpretation.
Thus nonfragmenting mass spectrometric methods are preferred.
For high-molecular-weight petroleum fractions, the use of nonfragmenting mass
spectrometry (NF-MS) methods is now preferred. These methods, also called soft
ionization methods, produce predominantly parent ion (molecular ion) peaks and
thus much simpler spectra than methods producing fragments. By rendering the
molecular weight and reasonably well the abundance of each compound in a sample, nonfragmenting mass spectrometry also can be used to determine the molecular
weight distribution, i.e., the molar mass profile of a sample.
Indeed, the great advantage of nonfragmenting mass spectrometry is the relative simplicity of the spectra. A disadvantage is the relatively low signal intensity
of the ions. With low-voltage electron impact ionization, the number of parent
ions formed increases rapidly as the ionizing voltage increases above the ionizing
potential of the molecules in the sample. Thus higher voltage gives a more intense
signal (up to about 20-40 eV, depending on compound type). However, the higher
ionizing voltage transfers more energy to the sample molecules and causes fragmentation to increase. The surplus energy transferred to the molecule in excess of
the ionizing potential is equilibrated and dissipated in various ways, for example,
by increasing the internal energy of the molecule or by breaking atomic bonds.
Thus the challenge in nonfragmenting mass spectrometry is to maximize the
number of parent ions and, at the same time, maintain the number of fragment ions
at acceptable levels.
Paraffins are highly susceptible to fragmentation; an ionizing voltage high
enough to generate a good parent ion spectrum also breaks many (paraffinic)
carbon-carbon bonds, producing a significant number of fragment ions.
Among the most important nonfragmenting mass spectrometric techniques
are field ionization mass spectrometry (FIMS), field desorption mass spectrometry (FDMS), chemical ionization mass spectrometry (CIMS), and low-voltage
(10-20 eV) electron impact mass spectrometry (LVEI-MS). A particularly powerful version of electron impact mass spectrometry is high-resolution electron
impact mass spectrometry (HR-LEVI-MS or LVRH-MS). All of these are "soft"
ionization techniques, designed to generate cold ions of such low excess energy
that they do not undergo fragmentation to any great extent, in contrast to the hot
ions generated by conventional electron impact ionization (70-100 eV). With soft
ionization methods, a compromise must be found between low fragmentation and
sufficiently high sensitivity. Unfortunately, samples rich in aliphatic hydrocarbons
are hard to keep completely from fragmenting, but most other compound types,
especially aromatic compounds, yield clean parent ion spectra.
Field ionization mass spectrometry shows extremely low fragmentation because
the ionization process imparts little excess energy to the formed ion. This is crucial
when ionizing saturates. Both low-voltage electron impact (LVEI) and chemical
ionization (CI) transfer more excess energy than field ionization mass spectrometry,
leading to higher levels of fragmentation with saturates. As long as the analyte is
volatile, the field ionization mass spectrometry experiment is not sample limited.
That is, additional sample can be vaporized as needed to obtain the required signalto-noise ratio. Field desorption mass spectrometry (FDMS) can be considered a
special form of electron impact mass spectrometry (EIMS) where the sample
material is placed on the ionizing surface of the probe before insertion into the
sample chamber of the mass spectrometer. It is, however, sample limited and
subject to experimental artifacts not normally present in electron impact mass
spectrometry.
In the electron impact mass spectrometry technique, the emitting surface is a
cathode consisting of an array of sharp tips on a support such as a wire, a grid, or
a razor blade. This surface is located very close to the anode. The combination of
an extremely small radius of curvature of the tips, the short distance, and the high
electric field creates a very high field gradient. The sample is introduced to this
field gradient by evaporation and diffusion from a heated surface nearby.
Field desorption mass spectrometry is a special form of field ionization mass
spectrometry. The cathode is the same, but here it is coated with the sample before it is placed in the mass spectrometer source. This eliminates the need to
evaporate the sample and any losses on transport to the cathode. Instead, the ions
are desorbed directly from the solid sample. The emitter is heated to the point
where the sample melts and can be drawn by the surface tension to the tip where
the molecules are converted to ions. As the ions are ejected from the surface into
the mass spectrometer, more sample molecules can replace them at the tip. In this
way, labile molecules can be handled without significant fragmentation, and even
conventionally nonvolatile samples can be run. Thus the method is especially suitable for the high-molecular-weight fractions of petroleum residua. Because of the
low thermal energy to which the sample molecules are exposed, the total excess
energy in this process is minimal. Thus, field desorption mass spectrometry is an
even milder method than field ionization mass spectrometry and produces less
fragmentation.
Low-voltage mass spectrometry is a soft electron impact mass spectrometric
method using 10-16 eV instead of the conventional 70-100 eV, thereby avoiding
or greatly mitigating fragmentation for petroleum constituents. The sensitivity of
the method is about the same as that of field ionization mass spectrometry, but
compared to regular electron impact mass spectrometry, it is 10-100 times lower,
and, therefore, the data acquisition time needed for the same signal-to-noise ratio
increases proportionally.
Chemical ionization mass spectrometry (CI-MS), another soft method, has been
used only occasionally for petroleum samples (Dzidic et al., 1991). In this method,
a relatively high-pressure (0.1-1 Torr) reagent gas (e.g., methane, n-butane, isobutane) is ionized and allowed to contact the sample. At such pressures, the reagent
ions undergo many collisions that help them lose excess energy left after ionization.
The ions also exchange charges during collision with one another and with the
sample molecules. The latter is the desired reaction, and the methods works best
when the sample molecules retain the charge better than the reagent molecules.
Fast atom bombardment mass spectrometry (FAB or FABMS) is a method for
special applications, namely, for polar, high-boiling samples when some fragmentation is desired for identification.
In fast atom bombardment mass spectrometry (FAB-MS) the sample is dissolved in a high-boiling polar liquid matrix (such as glycerol or triethanolamine)
and spread on a plate. Rare gas molecules (e.g., Xe or Ar) are ionized, accelerated,
focused at the sample, and stripped of their charge before they hit their target. The
impact of uncharged atoms sputters small amounts of the matrix and sample off
the sample plate. The liquid matrix evaporates, liberating charged sample ions,
which are now propelled by the accelerating voltage into the mass spectrometer.
The method produces substantial amounts of fragments and rarely works for
neutral compounds, two disadvantages for our purpose. Other problems and interferences with fast atom bombardment mass spectrometry are that the matrix
material is ionized along with the sample and that both sample and matrix material
may form cluster ions that complicate the spectrum.
The most useful application of low-voltage mass spectrometry is in combination
with high-resolution conditions. The method not only provides a parent ion spectrum (for fractions free of saturates) as does FIMS or FDMS, but it can distinguish
between molecules of equal nominal mass.
For high-resolution mass spectrometers, precise standardization of operating
conditions is even more important for quantitative measurements than for regular
mass spectrometers. Generally, the higher the resolution, the weaker the signal
and the longer the data acquisition time. Special mass standards, mostly chlorinated hydrocarbon petroleum fractions, are used for mass calibration. The parent
petroleum fractions guarantee a complete mass sequence that is needed for the
large number of heterocompound peaks. Even with such a standard there will still
be several heterocompound peaks between each pair of hydrocarbon peaks. The
chlorocompounds are preferred because of their higher sensitivities at the low
ionization voltage compared to those of the fluorinated standards common with
regular electron impact mass spectrometry.
Gas chromatography coupled with mass spectrometry (GC-MS) is a powerful method for petroleum distillates. Heavy petroleum fractions (345-4500C,
650-8500F) are usually first separated by liquid chromatography into compound
class fractions before application of gas chromatography that separates the sample
by boiling point (Chapter 10). Mass spectrometry, used as a detection method,
gives the molecular weight and, with fragmenting ionization, the compound type
of each peak (Lai and Song, 1995; Boehm et al., 1997).
Petroleum samples boiling higher than about 4500C (8500C), other than wellseparated narrow fractions, are too complex and high boiling for gas chromatography. In these cases, nonfragmenting mass spectrometry should be combined with
liquid chromatography instead of gas chromatography.
Very high-boiling samples (>650C, >1200F) may not be seen with the same
sensitivity as lower-boiling constituents by most mass spectrometric methods. For
these cases, mass spectrometric methods not limited by volatility are now available.
For example, FDMS, laser desorption (LS), fast atom bombardment (FAB), and
electrospray (ES) techniques can be applied to very large (polar) molecules, even of
several thousand molecular weight. However, because FAB and ES work only with
highly polar, easy-to-ionize compounds, their application to petroleum fractions
may be limited.
Liquid chromatography-mass spectrometry is more difficult than gas chromatography-mass spectrometry (Covey et al., 1986) insofar as the solvent needs to
be removed before the eluate can be processed by the mass spectrometer. After
solvent removal, the sample passes through the ionization chamber of the mass
spectrometer where the sample is vaporized and can be ionized by any method,
including fast atom bombardment and electron impact.
One of the applications of mass spectrometry is group-type mass spectrometry.
The method uses fragment patterns and sets of empirical relations to sort the
contributions from different molecules to certain selected peaks and to reconstruct
the molecular distribution from these peak areas.
The ASTM D-2786 method, for instance, measures the concentration of eight
compound types; paraffins, naphthenes with one to six rings, and mono-aromatics
in the saturates fractions. The application of this method is restricted to petroleum
fractions having an average carbon number between 16 and 32. The ASTM D-3239
mass spectrometric group-type method is used to determine aromatic compound
types present in chromatographic fractions of aromatics separated from vacuum gas
oils. Other ASTM group-type methods determine various aliphatic and aromatic
compound types in middle distillates (ASTM D-2425, ASTM D-2625).
Mass spectrometric group-type methods are fast and relatively cheap, and they
require a sample of only a few milligrams. However, they have their limits. They
are restricted to samples free of olefins and, ordinarily, with less than 2-5% S,
N, or O compounds and in some cases, with much more stringent limits. Other
restrictions, for example, to certain boiling (and MW) ranges also apply, depending
on the method. Furthermore, only those compound types are considered in the
calculation for which results are given in the output. If any other compound types
are present in the sample to any large degree, which may easily be the case, major
errors may result.
The mass spectrometric group-type analysis makes use of average fragmentation patterns specific to the different compound types, th^t is, to certain groups of
molecular structures. But the masses, as well as the abundances, of fragment ions
are characteristic of the specific parent molecule.
The sum of all of the peaks gives the average distribution of the parent molecules.
Generally, a limited set of peaks of a molecule is selected for evaluation. Calibration
ensures that the system is operating in a reproducible fashion and a response
factor matrix approach is used for quantitative measurement and to compensate
for overlaps in fragmentation.
Selected fragment peak intensities within the homologous series of compound
types are added together, and the sums are evaluated with a matrix of response
factors to give the concentration of each compound type in the sample.
Mass spectrometric group-type analyses can be expected to have errors in the
order of up to 20%. However, relative changes are ordinarily reported with better
accuracy.
ULTRAVIOLET SPECTROSCOPY
The ultraviolet-visible (UV-Vis) spectrum, although not as specific for chemical
group types as infrared spectroscopy and nuclear magnetic resonance spectroscopy,
can distinguish between aromatic compounds with different ring numbers and configurations (ASTM D-1840, ASTM D-2269). The patterns are not distinct enough
to recognize or distinguish these compounds in complex mixtures, but they can be
useful for their identification in narrow fractions.
Ultraviolet-visible spectroscopy (ASTM E-169) can be used as a detector for the
fractionation of petroleum samples, for example, for the chromatographic separation and/or identification of aromatics by ring number, especially in combination
with a technique such as liquid chromatography (Speight, 1986). Thus ultravioletvisible spectroscopy lends itself to studies of refining processes as an on-line
detector.
X-RAYDIFFRACTION
X-ray diffraction had been used (Yen et al., 1961) for the determination of the
fraction of aromatic carbon (/ a ) in petroleum constituents. This ratio can also
be conveniently and precisely obtained by carbon-13 nuclear magnetic resonance
spectroscopy as well as by infrared spectroscopy. The determination of the fraction
of carbon that is aromatic may be in error (Ebert, 1990) because X-ray diffraction
data can be very misleading (Ebert et al., 1984), especially when the data are used
to translate geometric datameasurements of (aromatic) sheet diameterinto
structural information. On the one hand, not all aromatic atoms contribute to the
stack diameter seen by X-ray diffraction, whereas, on the other hand, nonaromatic
atoms such as hydroaromatic carbons and other substituents on aromatic rings may
contribute to the diffraction pattern. Thus the interpretation of these measurements
is quite arbitrary.
Extended X-ray absorption fine structure (EXAFS) and X-ray absorption nearedge structure (XANES) spectroscopy are tools for the investigation of the immediate chemical environment of X-ray absorbing elements such as metals and
sulfur (Goulon et al., 1984). X-ray absorption near-edge structure and x-ray photoelectron spectroscopy (XPS) have been applied to the determination of sulfur
compounds as well as nickel and vanadium in petroleum samples described by
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CHEMICAL METHODS
As noted in other chapters, in the early days of petroleum processing, the need to
understand the character and behavior of petroleum in the detail that is currently
required did not exist. Refining involved distillation of the valuable kerosene fraction, which was then sold as an illuminant. After the commercialization of the
internal combustion engine, the desired product became gasoline, and it was also
obtained by distillation. Even when crude oil that contained little natural gasoline was used, cracking (i.e., thermal decomposition with simultaneous removal
of distillate) became the modus operandi.
However, with the startling demands on the petroleum industry during and
after World War II and the emergence of the age of petrochemicals and plastics,
the petroleum industry needed to produce materials that were not even considered
as products in the decade before the war. Thus petroleum refining took on the role
of technological innovator as new and better processes were invented and advances
in the use of materials for reactors were developed. In addition, there arose the
necessity to find out more about petroleum so that refiners might be able to enjoy
the luxury of predictability and plan a product slate that was based on market
demanda difficult task when the character of the crude oil was unknown! The
idea that petroleum refining should be a hit or miss affair was not acceptable.
The processing of petroleum requires not only knowledge of its chemical and
physical properties but also knowledge of its chemical and physical reactivity.
The former is dealt with in this chapter; the latter, because of the structure of
petroleum, is dealt with elsewhere in this book (Chapter 14). Because petroleum
varies markedly in its properties and composition according to the source, it also
varies in its chemical and physical reactivity. Thus knowledge of petroleum reactivity is required for optimization of existing processes as well as for the development
and design of new processes.
For example, valuable information can be obtained from the true boiling point
(TBP) curve (Chapter 5), which is a function of percent weight distilled and temperature, that is, a boiling point distribution (Fig. 8.1). However, the boiling range
does not convey much detail about chemical reactivity of crude oil. In addition to
the boiling point distribution, it is possible to measure bulk physical properties,
Highvacuum
Non-distillable material
Cumulative wt. %
Figure 8.1. True boiling point curve (distillation profile) for petroleum.
such as specific gravity and viscosity, that have assisted in the establishment of certain empirical relationships for petroleum processing from the TBP curve. Many of
these relationships include assumptions that are based on experience with a range
of feedstocks. However, the chemical aspects of refining feedstocks that contain
different proportions of chemical species emphasize the need for more definitive
data that would enable more realistic predictions to be made of crude oil behavior
in refinery operations.
The history of analysis of the chemical constituents in petroleum started over
100 years ago, when, in 1865, several aromatic hydrocarbons were identified as
constituents of petroleum. Identification of individual constituents of petroleum
has continued, and the rapid advances in analytical techniques have allowed the
identification of large numbers of petroleum constituents. At this time, the major
chemical types of compounds that exist in crude oil have been identified, and many
members of the various homologous series have been separated or conclusively
identified by various techniques (Chapter 2). This indicates a wealth of organic
compounds that are either resistant to mild hydrogenation (such as paraffins) or
reactive under destructive hydrogenation conditions.
As the boiling points of petroleum fractions increase, the complexity of the constituents in these fractions also increases, and the differences in chemical reactivity
between the main classes of constituents may become less pronounced. Nevertheless, the properties of any material are dictated by its chemical composition, and,
once the chemical composition of a material has been established, it becomes possible to correlate composition and properties. Petroleum is no exception to this
generality.
It is generally recognized that crude oils are composed of four major fractions
(saturates, aromatics, resins, and asphaltenes) that differ from one another sufficiently in character such that identification can be achieved by application of
relevant methods (Chapter 11). Indeed, although these four fractions are chemically complex, the methods of separation have undergone several modifications to
such an extent that the evolution of the separation techniques is a study in itself
(Chapter 10). In addition, because the fractions are in a balanced relationship in
crude oil, the chemical character of these main fractions requires mention in this
Questions may also be raised regarding the usefulness of attempting to determine the exact structure of each complex material, such as asphaltenes, resins, and
nonvolatile oils. Perhaps the answers lie not only in determining the locations of
the heteroatoms (nitrogen, oxygen, and sulfur) but also in understanding the chemical reactions of the various constituents of petroleum. In fact, valuable data can be
derived from chemical reactions; the process of understanding chemical reactions
could result in a complementary evaluation of the structural types present in the
hydrocarbon portions of these molecules in the hope of deriving as much benefit
as possible during processing of these complex materials.
Whether these reasons are sufficiently valid remains to be seen, but considerable
work has been done and is even now in progress to evaluate the influence of these
high-molecular-weight materials during petroleum recovery and during petroleum
refining (Speight, 1994; Yan et al., 1997).
The purpose of this chapter is to review a selection of methods that can be
used for the identification of the chemical reactivity of petroleum constituents.
Particular emphasis is placed on the techniques that have offered ready information
and will continue to provide valuable information about the chemical constituents
of petroleum. In this respect, in the past four decades, the reactions that cause the
removal of the heteroatoms have been of particular interest.
Thus, this chapter presents methods that can be applied to study the makeup
of the feedstock in terms of chemical structures as well as methods that might be
preferred for refining. The chapter deals with the older methods that were used
in the early days of structural group analysis; some of these are used even now.
The evolution of the available spectroscopic techniques that could be applied to
structural group analysis commenced in the 1960s (Chapter 11).
There is a range of chemical and thermal tests that can be applied to the analysis
of petroleum, but the major focus of this chapter is on the actual chemistry of the
various methods. Because the standard tests for such work are extremely limited,
even nonexistent, it is necessary to rely on data from published works other than
those of standards organizations. However, as a final series of thoughts in this
Introduction, the need for control experiments cannot be overstressed. Several
experienced researchers have fallen foul of the lack of a control experiment that
gives a basis for comparison. One might cite the deduction of asphaltenes structure
using potassium naphthalide (a particularly vicious reagent) and asphaltenes. The
researchers omitted to investigate the effect of this reagent on the solvent. Lo and
behold, reaction occurred between the reagent and the solvent! Thus, the product
mix became a very complex mess of pottage that should not have been used to draw
any conclusions whatsoever (see Speight, 1994, for a discussion of this issue).
FUNCTIONAL GROUP ANALYSIS
The chemical analysis of the higher- boiling fractions of petroleum continues
to be a challenge because of the wide variety of molecular types and structures
present. Molecular types in the residua, heavy oil, and bitumen range from nonpolar, nonaromatic species to highly aromatic hydrocarbons, the molecular structures
of which contain varying amounts of heteroatoms (nitrogen, oxygen, and sulfur)
together with parts per million amounts of metals such as vanadium and nickel
(Reynolds, 1998). The heteroatoms are often associated with polar, strongly interacting chemical functionality or functional groups that have a disproportionately
large effect on the properties of each fraction and, therefore, on the whole feedstock
(Speight, 1999, 2000 and references cited therein).
Because the number of molecules in residua, heavy oil, and bitumen with different chemical structures and reactivities is extremely large, determination of
composition by separation of the feedstock into its molecular components is generally considered impractical if not impossible by many of the available techniques.
However, if the different chemical functionalities (ASTM F-1186) that comprise
the heavy feedstocks and therefore dominate their properties are considered, the
number of types of functionalities that need to be considered decreases and becomes identifiable. Indeed, the heavy feedstocks can be safely assumed to contain
these same functionalities, albeit in different proportions, depending on the origin and maturation conditions and the recovery and treatment of the feedstock
(Speight, 1999). In turn, it is the interactions of these functions that can play a
role in the structure of the feedstocks and their behavior under different conditions
(Speight, 1999, 2000).
One of the principal agents in the behavior of heavy feedstocks is the various oxygen functions. These functions also play a major role in the structure of
petroleum (Chapter 14). Thus identifying the presence (or the formation) of highly
polar and strongly interacting chemical functional groups containing oxygen is a
necessary step for assessing the effects of composition on properties and thus the
performance of the feedstock during refining or the performance of asphalt in
During the past several decades, many studies have related to the identification
and characterization of the polar, heteroatom-containing chemical functionality in
various feedstocks. Infrared spectrometry has been a very prominent technique in
this research because it can be applied to complex mixtures without alteration or
destruction of the sample (Chapter 7).
Earlier researchers who explored infrared spectrometry (Chapter 7) for the
characterization of the high-molecular-weight fraction of petroleum found the
technique useful for determining the general chemical structural types present
(Chapter 11). However, the strongly associating polar functionalities present often
required extra and more conscientious effort. The inability to adequately characterize these polar functionalities resulted from inherent problems such as overlapping
and ill-defined absorption bands and the shifting of absorption bands from hydrogen bonding.
These inherent problems have been overcome by the combined use of selective
chemical reactions and differential spectrometry. A selective solvent system is
also used to break up hydrogen bonding, eliminating the complicating effects of
hydrogen bonding on the spectra (Moschopedis and Speight, 1976a).
In this section, the development and the current practice of the functional group
analysis are presented and applications of the technique are described. The chemical functionalities quantitatively determined include carboxylic acids (and, independently, their salts), anhydrides, ketone oxygen, 2-quinolone-type oxygen,
sulfoxide oxygen, pyrrole-type nitrogen, and phenolic oxygen. With the exception
of basic nitrogen compounds (predominantly pyridine-type nitrogen), which do
not yield readily to infrared analysis, these functionalities make up the important polar heteroatom-containing functionalities present (to different extents) in
feedstocks.
As mentioned above, the most polar and strongly interacting functional groups
in residua, heavy oil, and bitumen occur in relatively small amounts and their
infrared absorption bands are often complicated by hydrogen bonding and overlap with other strong absorption bands (Moschopedis and Speight, 1976a), making
their detection difficult and their quantitative assessment virtually impossible without the use of special techniques.
Phenolic and pyrrolic groups in heavy feedstock are hydrogen-bonding functionalities. Thus, in solutions of these feedstocks in typical infrared spectral solvents, an equilibrium exists between the free absorption bands of these functional
groups and their hydrogen-bonding bands (the latter bands overlap); this equilibrium is dependent on the concentration, the solvent characteristics, and the basic
character of the constituents in the feedstock with which the acidic hydrogen of
the functionalities interacts (Moschopedis and Speight, 1976a).
Two other important naturally occurring functionalities are carboxylic acids
and 2-quinolone-type oxygen. These functionalities are extremely strong hydrogen
bonders. Not only do they readily form dimers but they also interact strongly with
each other to form a mixed dimer, yielding six absorption bands, of which five
overlap and become virtually indistinguishable. However, it must be remembered
that sample history can play a major role in the occurrence of such functions in
the feedstock. Oxidation during heavy oil recovery can, and does, cause oxygen
incorporation into the feedstock, and the occurrence of carboxylic acid function in
residua and heavy oil may be diminished by the thermal treatment (even distillation)
used to produce the heavy feedstock. The incorporation of oxygen functions can
have a noticeable influence on the inter- and intramolecular bonding arrangements
in the feedstock (Moschopedis and Speight, 1976b).
To overcome the problems just described and to obtain spectra suitable for
quantitative analysis, several specialized techniques and procedures have been
employed. Tetrahydrofuran (THF) solvent has been used to eliminate interference
from hydrogen bonding on the carbonyl absorption region in the determination
of ketones, carboxylic acids, anhydrides, and 2-quinolones. However, caution is
advised because this solvent is not always capable of dissolving the asphaltene
constituents and may lead to faulty conclusions because of the occurrence of
suspended organic matter.
Whatever solvent is used, advantage can taken of the hydrogen bonding of
phenolic and pyrrolic functionality in the analysis of these functional groups.
However, because the solvent employed may have absorption bands in the frequency ranges used in the determinations, a solvent compensation technique must
Thus, when the problem of hydrogen bonding has been eliminated, the problem of overlapping bands in the carbonyl absorption region (about 1800 cm" 1
to about 1600 cm" 1 ) is addressed by using selective chemical reactions and differential infrared spectrometry. The techniques applied are as follows. To reveal
the absorption band of interest and to eliminate from the spectra other bands
with absorption at the same frequency, the sample is treated with a selective
reagent that eliminates or shifts the absorption band of interest to another frequency.
A differential spectrum is then taken with the treated sample in one beam
and the untreated sample in the other beam of a double-beam infrared spectrophotometer. This procedure reveals the absorption band of the functionality of
interest in the differential spectrum and nulls or cancels out all other absorption bands in the same region. Quantitative analysis can also be applied to the
absorption band of interest using calculations of the areas under the absorption
bands.
The apparent integrated absorption intensity (B), in units of L mol" 1 cm" 2 , of
an infrared absorption band obtained on a spectrophotometer having a monochromatic energy source and finite slit width is defined as follows:
B = -Xjcl In(J 0 /T) v dv
where c is the concentration of functional group type (mol L 1X / is the cell path
length (cm), v is the absorption frequency (cm" 1 ), T0 is the incident radiation, and
T is the transmitted radiation.
The area under the absorbance versus absorption-frequency curve for the absorption bands of interest is represented by the term l n ( r o / r ) v d v . The term
In(T0/T) is equivalent to the commonly used term absorbance, designated by
the notation A.
The band area, Avdv can be estimated by counting squares on the recording
chart paper or by weighing the paper, which represents the respective peak areas.
The concentrations of functional group types in the sample are then estimated by
using the equation
c = AAvdv/Bl
x 1.05/0/0.05
The potential applications of the functional group analysis in compositionrelated technology are numerous. Thus the combined use of differential infrared
spectrometry and selective chemical reactions provided the basis for the development of an analytical method for the quantitative analysis of important chemical
functionality in feedstocks. The method can be applied to the solution of a variety
of composition-related problems in petroleum technology.
Another form of functional group analysis involves measurement of the acidity
of a sample.
The total acidity (usually referred to as the acid number) is the quantity of base,
expressed in milligrams of potassium hydroxide, required to neutralize the acidic
constituents in 1 g of sample under the conditions of the test (ASTM D-664, IP 1,
IP 37, IP 139, IP 177, IP 182, IP 213, IP 354, IP D-431). Acidity generally increases
with viscosity for heavy oil and bitumen, but no reason for this correlation has been
established.
Severely weathered bitumen, such as that found in outcrops, is more acidic than
unoxidized bitumen from deeper within the deposit. In addition, correlations have
been established between the acid number of heavy oils produced in a fireflood
and the location of the fire front. An increase in the acid number of petroleum and
heavy oil can lead to increasing emulsion stability and therefore emulsion-treating
difficulties after recovery operations.
One method (ASTM D-664) involves dissolution of the sample in a toluenewater-isopropanol (50.0:0.5:49.5) solution titrated potentiometrically with 0.1 N
alcoholic potassium (KOH) using a glass indicating electrode and a calomel reference electrode. The end point is determined either graphically or, if no inflections in
the curve are apparent, by titration to a meter reading for a standard buffer solution.
Another standard method (IP 213) involves the determination of the neutralization value of asphalt (bitumen) using a potassium hydroxide solution (0.1 N in
distilled water), standardized by potentiometric titration with potassium hydrogen
phthalate. The sample to be titrated may be dissolved in a toluene-ethanol-water
solution. Excess base is added, and the mixture is backtitrated with 0.1 N standardized hydrochloric acid to an alkali blue end point.
A modification of this method (ASTM D-6441) uses the solvent systems and
reagents as specified (IP 213) but with a direct potentiometric titration using 0.1 N
aqueous potassium. A titroprocessor in combination with a lithium chloride (LiCl)
electrode gives the sensitivity required to identify the end point by inflection.
Two other methods (ASTM D-974 and ASTM D-3339, IP 139) also involve
colorimetric titration to determine the acid number of petroleum products and lubricants by titration with 0.1 N potassium hydroxide in a toluene-isopropyl alcohol
mixture to a p-naptholbenzein indicator end point. The application for titration of
heavy oil and bitumen is hampered because of the difficulty in detecting the color
change from orange to green-brown. A potentiometric perchloric acid titration
method (ASTM D-2896) is also available for the determination of acid number.
In addition, application of any of the methods to heavy oil and bitumen (or
even to whole crude oil) can be influenced by precipitation of asphaltenes on the
electrodes during a potentiometric titration. This effect can delay the response of
the electrode. When the precipitation problem is severe, inflections in the titration
curve cannot be identified and titration to a buffer end point becomes slow and
imprecise.
Indeed, determination of the acid number of heavy oil and bitumen is subject to
uncertainties due to the problem of precipitation of components during titration.
Reduction of test sample size, use of alternate solvent systems, and minimization
of titration time, possibly by using a more concentrated titrant, may improve precision. These factors should be examined to establish a method suitable for these
heavy feedstocks.
There is also a method for the determination of the basic constituents in petroleum products (ASTM D-4739). The data are presented as a base number, which
is defined as the quantity of acid, expressed in milligrams of potassium hydroxide
per gram of sample, required to titrate a sample to a specified end point (IP 139,
IP 276, IP 400, IP 417).
The base number can be used to indicate the relative changes that occur in
petroleum or a petroleum product during use (or storage) under service (or oxidizing) conditions regardless of color or other properties of the resulting product.
The neutralization value either by potentiometric titration (ASTM D-664) or
by color-indicator titration (ASTM D-974) provides base numbers as well as acid
numbers. Further functionality can be determined by use of saponification numbers
using the color-indicator titration method (ASTM D-94) or the potentiometric
titration method (ASTM D-939, IP 2).
The bromine number (ASTM D-1159, IP 129, IP 130) is the number of grams
of bromine consumed by a weighed amount (100 g) of sample when reacted under
specified conditions (ASTM D-1159). In theory, the method gives an indication of
the amount of unsaturation in the sample by assuming that additions of bromine
across multiple carbon-carbon bonds are the only reactions. However, with the
heavier feedstocks, caution is needed in the interpretation of the data because
of the ready reactivity of bitumen constituents with bromine (Moschopedis and
The ASTM method uses a polarized electrode pair. As soon as there is a small
amount of excess bromine, the solution conductivity increases sharply, producing
a large, clearly defined deflection at the end point.
In this method, the sample is initially dissolved in a solvent consisting of glacial
acetic acid, 1,1,1-trichloroethane, methanol, and sulfuric acid. The solution is
titrated with bromide-bromate titrant using dual platinum electrodes and a 1O-JJLA
polarizing current for end-point detection.
Alternatively, the bromine index is the number of milligrams of bromine that
will react with 100 g of the sample (IP 299). This index is used mostly by the
chemical industry for stocks that have an unusually low olefin content.
The purpose of hydrogenating petroleum constituents is (1) to improve existing
petroleum products or develop new products or even new uses, (2) to convert
inferior or low-grade materials into valuable products, and (3) to transform highermolecular-weight constituents into liquid fuels. Indeed, it is generally recognized
that the higher the hydrogen content of a petroleum product, especially the fuel
products, the better the quality of the product. This knowledge has stimulated the
use of hydrogen-adding processes in the refinery.
However, in the context of this chapter, i.e., in the chemical laboratory, the
hydrogenation of petroleum and the heavy feedstocks (heavy oil, bitumen, and
residua) is somewhat limited by the nature or requirements of the reaction conditions. For example, high temperatures and pressures are usually required, which
cause changes to the hydrocarbon skeleton. However there are mild hydrogenating
processes that can be applied to petroleum, thereby providing information about
the constituents. In fact, the focus of hydrogenation in the laboratory tends to be
oriented toward the category often referred to as nondestructive or mild hydrogenation.
The hydrogenation of petroleum has been studied extensively for the past several
decades and to repeat much of the work here would be superfluous. Thus it is the
intent here to discuss only the basic principles of hydrogenation and to point out
the methods that might be used to analyze the products. Such a discussion is more
in keeping with the nature of this book.
The basic chemical concept of the hydrogenation process as applied to petroleum
is to convert the organic constituents to liquid fuels and, at the same time, to
remove the organic heteroatoms in the feedstock by conversion to their hydrogen
analogs.
feedstocksulfur + H2 -> H2S + productssuifur-deficient
feedstOCkoxygen + H2 -> H2O + produCtSOXygen-deficient
feedstOCknitrogen + H2 -> NH3 + produCtSnitrogen-deficient
It is the chemical aspects of this reaction that can be most important as a means of
building the basis for refining.
As an example of the laboratory hydrogenation reaction, reduction by Raney
nickel is a mild degradation method. It may be performed, for example, by reacting
a 10-mg sample with a suspension of 0.5 mg of catalyst in 2.5 ml of refluxing
absolute alcohol for 1-2 h under nitrogen but may require that the sample is
molecularly dissolved. However, there may be drawbacks to the use of such a
method, because solubility of the constituents in the solvent is often necessary.
In addition, the fact that asphaltene constituents form aggregates (Chapter 12)
may cause interference with the method and provide data that are, at best, questionable.
Asphaltenes may also be hydrogenated to produce resins and oils at elevated
temperatures (>250C) (Speight, 1999,2000, and references cited therein). Chemical hydrogenation under much milder conditions, for example with lithium-ethylenediamine or sodium-liquid ammonia, also produces lower-molecular-weight
species together with marked reductions in the sulfur and oxygen contents.
In a more general chemical sense, the effect of hydrogen on naphthenic hydrocarbons is mainly that of ring scission followed by immediate saturation of
each end of the fragment produced. The ring is preferentially broken at favored
positions, although generally all the carbon-carbon bond positions are attacked to
some extent.
Aromatic hydrocarbons are resistant to hydrogenation under mild conditions,
but, under more severe conditions the main reactions are conversion of the aromatic
to naphthenic rings and scissions within the alkyl side chains. The naphthenes may
also be converted to paraffins. Polynuclear aromatic hydrocarbons are more readily
attacked than the single-ring compounds, the reaction proceeding by a stepwise
process in which one ring at a time is saturated and then opened.
Starting in the 1950s, there was considerable focus on hydrogenation as a means
of sulfur removal from crude oil; this will be the focus of the present discussion
because it illustrates many of the aspects of the hydrogenation of petroleum, heavy
oil, and bitumen.
Thus the thermodynamics of the hydrogenation reaction can be evaluated from
the equilibrium constants of typical desulfurization or partial desulfurization reactions such as
1. hydrogenation of model compounds to yield saturated hydrocarbons (R-H)
and hydrogen sulfide (H2S),
2. decomposition of model compounds to yield unsaturated hydrocarbons
( R - C H = C H - R 1 ) and hydrogen sulfide (H2S),
3. decomposition of alkyl sulfides to yield thiols (R-SH) and olefins
(R-CH=CH-R 1 ),
4. condensation of thiols (R-SH) to yield alkyl sulfides (R-SR 1 ) and hydrogen sulfide (H2S), and
5. hydrogenation of disulfides (R-S.SR 1 ) to yield thiols (R-SH, R1SH).
The logarithms of the equilibrium constants for the reduction of sulfur compounds
to saturated hydrocarbons over a wide temperature range (Speight, 2000) are almost all positive, indicating that the reaction can virtually proceed to completion if
hydrogen is present in the stoichiometric quantity. The equilibrium constant does,
however, decrease with increasing temperature for each particular reaction but
still retains a substantially positive value at 425C (795F), which is approaching
the maximum temperature at which many of the hydrodesulfurization (especially
nondestructive) reactions would be attempted. The data also indicate that the decomposition of sulfur compounds to yield unsaturated hydrocarbons and hydrogen
sulfide is not thermodynamically favored at temperatures below 3250C (6150F),
and such a reaction has no guarantee of completion until temperatures of about
625C (1,155F) are reached. However, substantial decomposition of thiols can
occur at temperatures below 3000C (5700F); in fact (with only few exceptions), the
decomposition of all saturated sulfur compounds is thermodynamically favored at
temperatures below 425C (795 0 F).
Kinetic studies using individual compounds, especially for the hydrodesulfurization reaction, have usually indicated that first-order kinetics with respect to
sulfur is the predominant mechanism by which sulfur is removed as hydrogen
The structural differences between the various sulfur-containing molecules
make it impractical to have a single rate expression applicable to all reactions
in hydrodesulfurization. Each sulfur-containing molecule has its own hydrogenolysis kinetics, which is usually complex because several successive equilibrium
stages are involved and these are often controlled by internal diffusion limitations
during refining.
Thiophenic compounds are the most refractory of the sulfur compounds. Consequently, thiophene is frequently chosen as representative of the sulfur compounds
in feedstocks (Speight, 1999, 2000). The hydrogenolysis of thiophene takes place
according to two distinct paths. The first path leads through thiophane to butylmercaptan in equilibrium with butene and dibutylthioether and finally to butene and
hydrogen sulfide. It is considered unlikely that the thiophene and the dibutylsulfide
can undergo direct hydrogenolysis with production of hydrogen sulfide. However,
it is possible that the butyl mercaptan can be decomposed according to the two
parallel paths, namely
1. desulfurization of the mercaptan on the active metal sulfides and acid sites
of alumina followed by hydrogenation of the intermediate butene, and
2. direct hydrogenolysis of the C - S H bond on the active metal sulfides.
As complex as the desulfurization of thiophene might appear, projection of the
kinetic picture to benzothiophene and dibenzothiophene, and to their derivatives,
is even more complex. However, kinetic data derived from model compounds
cannot be expected to include contributions from the various steric effects, which
are a consequence of complex molecules containing three-dimensional structures
(Isodaetal., 1996a,b).
Furthermore, the complexity of the individual reactions occurring in an extremely complex mixture and the interference of the products with those from
other components of the mixture is unpredictable. Or the interference of secondary and tertiary products with the course of a reaction and, hence, with the
formation of primary products may also be cause for concern. Hence, caution is
advised when applying the data from model compound studies to the behavior of
petroleum, especially the molecularly complex heavy oils. These have few, if any,
parallels in organic chemistry. In addition, all such contributions may be missing
from the kinetic data, which must be treated with some degree of caution.
However, there are several generalizations that come from the available thermodynamic data and investigations of pure compounds as well as work carried out
on petroleum fractions (Gray, 1994, and references cited therein). Thus, at room
temperature, hydrogenation of sulfur compounds to hydrogen sulfide is thermodynamically favorable, and the reaction will essentially proceed to completion in
the presence of a stoichiometric amount of hydrogen. Sulfides, simple thiophenes,
and benzothiophenes are generally easier to desulfurize than the dibenzothiophenes
and the higher-molecular-weight condensed thiophenes.
Nevertheless, the development of general kinetic data for the hydrogenation
of different feedstocks is complicated by the presence of a large number of compounds, each of which may react at a different rate because of structural differences
as well as differences in molecular weight and may be reflected in the appearance
of a complicated kinetic picture in which the kinetics is not, apparently, first order
(Scott and Bridge, 1971). The overall reaction may be satisfied by a second-order
kinetic expression when it can, in fact, also be considered as two competing firstorder reactions.
Thus it has become possible to define certain general trends that occur in the
hydrogenation of petroleum feedstocks. One of the more noticeable facets of the
process is that the rate of reaction declines markedly with the molecular weight
of the feedstock (Scott and Bridge, 1971). It should be noted here that, because of
the nature of the reaction, steric influences would be anticipated to play a lesser
role in the hydrocracking process.
Residua hydrogenation is considerably more complex than the hydrodesulfurization of model organic sulfur compounds or, for that matter, narrow-boiling
petroleum fractions. In published studies of the kinetics of residua hydrogenation,
one of three approaches has generally been taken:
1. The reactions can be described in terms of simple first-order expressions.
2. The reactions can be described by use of two simultaneous first-order expressions, one expression for easy-to-hydrogenate systems and a separate
expression for difficult-to-hydrogenate systems, with special reference to
the removed sulfur.
3. The reactions can be described using a pseudo-second-order treatment.
Each of the three approaches has been used to describe hydrogenation of residua
under a variety of conditions with varying degrees of success, but it does appear
that pseudo-second-order kinetics are favored. In this particular treatment, the rate
of hydrogenation (hydrodesulfurization) is expressed by a simple second-order
C/l-C
= (1/LHSV)
where C is the wt% sulfur in product/wt% sulfur in the charge, k is the reaction
rate constant, and LHSV is the liquid hourly space velocity (volume of liquid feed
per hour per volume of catalyst). Application of this model to a residuum desulfurization gave a linear relationship (Beuther and Schmid, 1963; Ozaki et al., 1963).
On this basis, the use of two simultaneous first-order equations may be more
appropriate. The complexity of the constituents tends to increase with an increase in
boiling point, and the reactivity tends to decrease with complexity. It is anticipated
that such an approach is consistent with the relative reactivity of various compound
types observed for model compounds and for the various petroleum fractions that
have been investigated.
Other kinetic work has shown that, for a fixed level of sulfur removal, the order
of a reaction at constant temperature can be defined with respect to pressure:
k = 1/LHSV(Ph)"
where Ph is the hydrogen partial pressure, LHSV is the liquid volume hourly space
velocity, k is a constant, and n is the order of the reaction. It has been concluded, on
the basis of this equation, that the hydrodesulfurization of residuum is first-order
with respect to pressure over the range 800-2,300 psi, although it does appear that
the response to pressure diminishes markedly (and may even be minimal) above
1,000 psi.
Despite all of the work, the kinetics and mechanism of alkyl-substituted dibenzothiophene, in which the sulfur atom may be sterically hindered, are not well
understood and these compounds are in general very refractory to hydrodesulfurization. Other factors that influence the desulfurization process such as catalyst
inhibition or deactivation by hydrogen sulfide, the effect of nitrogen compounds,
and the effect of various solvents must be studied to obtain a comprehensive model
that is independent of the type of model compound or feedstock used.
Throughout this section, the focus has been on the kinetic behavior of various organic molecules during refinery operations and specifically during the hydrodesulfurization process. However, it must be remembered that the kinetic properties
of the catalyst also deteriorate because of deposits on its surface. Such deposits
typically consist of coke and metals that are products of the various chemical
During hydrogenation at higher temperatures, essentially all the initial reactions of catalytic cracking occur, but some of the secondary reactions are inhibited
or stopped by the presence of hydrogen. For example, the yields of olefins and
the secondary reactions that result from the presence of these materials are substantially diminished and branched-chain paraffins undergo demethanation. The
methyl groups attached to secondary carbons are more easily removed than those
attached to tertiary carbon atoms, whereas methyl groups attached to quaternary
carbons are the most resistant to hydrocracking.
On an individual hydrocarbon type basis, and without the effects of hydrodesulfurization, the effect of hydrogen on naphthenic hydrocarbons is mainly that of ring
scission followed by immediate saturation of each end of the fragment produced.
The ring is preferentially broken at favored positions, although generally all the
carbon-carbon bond positions are attacked to some extent. For example, methylcyclopentane is converted (over a platinum-carbon catalyst) to 2-methylpentane,
3-methylpentane, and n-hexane.
but, under more severe conditions, the main reactions are conversion of the aromatic
also be converted to paraffins.
Polynuclear aromatics are more readily attacked than the single-ring compounds, the reaction proceeding by a stepwise process in which one ring at a
time is saturated and then opened.
One might wonder where analytical chemistry fits into all of this. Once the
hydrogenation reaction has been carried out, it is then the focus of the chemist or
analytical chemist to determine the reaction pathway using the various analyses
that can be brought to bear on the issue.
First, there is the analysis of gaseous product such as hydrogen sulfide (ASTM
D-103, ASTM D-2385, ASTM D-2725, ASTM D-4084, ASTM D-4810, IP 401)
or the composition of the gas as might be applied to the analysis of natural gas
(ASTM D-1945, ASTM D-2597, IP 345) and the composition of the liquid in
terms of hydrocarbon types (IP 156). With respect to liquid products, gas chromatographic analysis (Chapter 10) and high-performance liquid chromatographic
analysis (Chapter 10) of the organic liquid products might be the first techniques
to be applied. Simulated distillation (Chapter 10) as well as the determination of
compound class types by adsorption chromatography (Chapter 10) would also be
beneficial. This might be followed by elemental analysis of the individual fractions
as well as by infrared spectroscopy (Chapter 7) and mass spectrometry (Chapter 7)
with the potential for application of nuclear magnetic resonance spectroscopy being very real.
8.4. OXIDATION
The oxidation of petroleum and its fractions has, like hydrogenation, been the object of study for several decades with the focus being predominantly on the chemistry of asphalt oxidation. Because asphalts have high proportions of asphaltenes,
it is not surprising that the oxidation of asphaltenes has been studied widely, not
only from the perspective of asphalt production but also from the perspective of
structural studies.
However, for the most part, the oxidation of petroleum fractions will be dealt
with elsewhere, especially as to how oxidation relates to instability and incompatibility (Chapter 13).
Oxidation of asphaltenes with common oxidizing agents, such as acid and
alkaline peroxide, acid dichromate, and alkaline permanganate, is a slow process.
The occurrence of a broad band centered at 3420 cm" 1 and a band at 1710 cm" 1
in the infrared spectra of the products indicates the formation of phenolic and
carboxyl groups during the oxidation. Elemental analyses of the products indicate
that there are two predominant oxidation routes, notably
1. the oxidation of naphthene moieties to aromatics as well as the oxidation of
active methylene groups to ketones, and
2. severe oxidation of naphthene and aromatic functions, resulting in degradation of these systems to carboxylic acid functions.
Oxidation of asphaltenes in solution by air and in either the presence or absence
of a metal salt is also possible (Moschopedis and Speight, 1978). There is some
oxygen uptake, as can be seen from the increased O-to-C atomic ratios, but the
most obvious effect is the increase in the amount of n-heptane-insoluble material.
In addition, analyses of the data show that it is the higher heteroatoms (more polar
constituents) of the asphaltenes that are more susceptible to oxidation, suggesting
that the polarity of the constituents may be determined by the incorporation of the
heteroatoms into ring systems.
Air blowing of asphaltenes at various temperatures brings about significant oxygen uptake. This is accompanied by a marked decrease in the molecular weight
(vapor pressure osmometry, benzene solution) of the product. This indicates that
intermolecular hydrogen bonding of oxygen functionality may play a part in the observed high molecular weights and physical structure of petroleum (Moschopedis
and Speight, 1978; see also Taft et al., 1996).
It may appear, at first sight, that sulfur and oxygen exist as linkages among
hydrocarbon segments of asphaltene molecules. Although this may be true, in
part, it is also very likely, in view of what has been discussed previously, that the
lower molecular weights reflect changes in molecular association brought about
by the elimination of oxygen and sulfur.
Aromatics undergo condensation with formaldehyde to afford a variety of products. This process can be extended to the introduction of various functions into
the asphaltene molecules, such as sulfomethylation, that is, introduction of the
-CH 2 SO 3 H group. This latter process, however, usually proceeds more readily if
functional groups are present within the asphaltene molecule.
Thus oxidation of asphaltenes produces the necessary functional groups, and
subsequently sulfomethylation can be conveniently achieved. The occurrence of
sulfomethylation of the oxidized asphaltenes can be confirmed from three sources:
1. overall increases in the sulfur contents of the products relative to those of
the starting material,
2. the appearance of a new infrared absorption band at 1030 cm" 1 attributable
to the presence of sulfonic acid group(s) in the molecule(s), and
3. the water solubility of the products, a characteristic of this type of material.
These sulfomethylated oxidized asphaltenes remain in solution even after
parent oxidized asphaltenes can be precipitated from alkaline solution by
acidification to pH 6.5.
The facile sulfomethylation reaction indicates the presence in the starting materials of reactive sites ortho or para to a phenolic hydroxyl group. The related
reaction, sulfonation, is also a feasible process for oxidized asphaltenes. The ease
with which this reaction proceeds suggests the presence of quinoid structures in the
oxidized materials. Alternatively, active methylene groups in the starting materials
facilitate sulfonation, because such groups have been known to remain intact after
prolonged oxidation.
The chemical reactions of the resins have received much less attention than the
reactions of the asphaltenes, and usually only fragmentary reports are available.
Like the chemical reactions of the asphaltene constituents, the chemical reactions
of the resin constituents give indications of the structural types within these constituents. The reactions also indicate the effects that changes in the hydrocarbon
structure or functionality will have on the properties of the resin constituents (see
Speight, 1991, for more detail).
One area of resin chemistry that has received attention is the interaction with
oxygen. Thus the oxidation of resins in benzene solution with air in the presence
or absence of various metal salts proceeds readily to yield asphaltene products
(Moschopedis and Speight, 1978). Substantial uptake of oxygen occurs, and, from
the atomic heteroatom-to-carbon ratios in the starting material and products, it
appears that preferential reaction of the more polar entities occurs. Resins also
undergo condensation with formaldehyde, which is especially rapid after the introduction of oxygen functions by oxidation. Resins can also be sulfonated to
yield water-soluble or oil-soluble sulfonates. Resins react with nitric acid to yield
complex mixtures of oxidation and nitration products. Reactions with sulfur cause
dehydrogenation as well as the formation of complex sulfides. The overall result is the production of higher-molecular-weight material with low hydrogen
Resins also react with diazo compounds, which not only produces asphaltenetype products but also can be used to introduce various functional groups into
the molecule. Resins react with acetic anhydride to afford a variety of acetylated
Just as the asphaltenes and resins react with oxygen at low temperatures
(<100C, <212F), so do the oils Thus oxidation in benzene solution by air,
in either the presence or absence of metal salts, proceeds smoothly to yield asphaltene and resin products (Moschopedis and Speight, 1978). In general, the majority
of the oil recovered after oxidation has lower atomic N-to-C and S-to-C ratios
than the untreated oil; this indicates that it is the more polar components of the
oil fraction that are susceptible to oxidation. It is also evident that the presence of
catalytic amounts of metal salts causes an acceleration in the oxidation rate of the
oil fraction.
Selective oxidation with sodium periodate (NaIC^) catalyzed by ruthenium ions
(Ru 8+ ), can give more specific information on the nature of asphaltene constituents.
This method selectively oxidizes alky 1-substituted aromatic carbons to carbon
dioxide, leaving behind (1) alkyl substituents as monocarboxylic acids, and (2)
polymethylene bridges between aromatic rings as a,a>-dicarboxylic acids. Some
of the condensed aromatic rings survive the treatment as benzene polycarboxylic
acids. The various acids are made volatile by esterification with diazomethane, and
the esters can be analyzed by gas chromatography-mass spectrometry (Mojelsky
This technique provides the distribution of alkyl substituents attached to aromatic rings, that of paraffin chains connecting two aromatic rings or ring systems,
and information on the nature of the aromatic and naphthenic ring systems in the
original sample. The amounts of alkyl chains found this way seem to be reasonably
quantitative. Those of aromatic and naphthenic rings appear more tentative because
the fate of the aromatic heterocompounds is not known except that some of the
sulfur compounds are recovered in the form of sulfones.
Oxidation is also used for the separation of neutral sulfur compounds from
hydrocarbons (see, e.g., Drushel, 1972; Ruiz et al., 1982; Arpino et al., 1987).
The sulfur compounds are converted to sulfoxides and sulfones that are strongly
retained on chromatographic columns and can thus be separated from the hydrocarbons. After recovery, they can be reconverted to the sulfldes by reduction with
lithium aluminum hydride (L1AIH4) for further analysis. By combining such oxidation and reduction procedures, it was possible to distinguish between thiophene
derivatives and three different types of sulfides.
The issue, of course, with any chemical procedure is the occurrence of side
reactions that may occur, especially in such oxidative procedures.
Again, with the results of hydrogenation experiments, one might wonder where
analytical chemistry fits into all of this. Once the oxidation reaction has been
carried to completion or to the desired point, it is then the focus of the chemist or
For example, gas chromatographic analysis (Chapter 10) and high-performance
liquid chromatographic analysis (Chapter 10) of the organic liquid products might
be the first techniques to be applied. Simulated distillation (Chapter 10) as well
as the determination of compound class types by adsorption chromatography
(Chapter 10) would also be beneficial. This might be followed by elemental analysis (Chapter 4) of the individual fractions as well as by infrared spectroscopy
(Chapter 7) and mass spectrometry (Chapter 7), with the potential for application
of nuclear magnetic resonance spectroscopy (Chapter 7) being very real.
Halogenation of petroleum and its fractions occurs readily to afford the corresponding halo-derivatives; the physical properties of the halogenated materials are
markedly different from those of the parent materials. Analysis for the various
halogens is possible (ASTM E-422).
In the case of the asphaltenes, which again have been the recent focal point of
the investigations, for example, the unreacted asphaltenes are dark brown, amorphous, and readily soluble in benzene, nitrobenzene, and carbon tetrachloride,
but the products are black, shiny, and only sparingly soluble, if at all, in these
solvents.
There are also several features that distinguish the individual halogen reactions
from one another. For example, during chlorination of asphaltenes, there is a
cessation of chlorine uptake by the asphaltenes after 4 h. Analytical data indicate
that more than 37% of the total chlorine in the final product is introduced during
the first 0.5 h, reaching the maximum after 4 h. Furthermore, the H-to-C ratio of
1.22 in the parent asphaltenes [(H + Cl)-to-C ratio in the chlorinated materials]
remains constant during the first 2 h of chlorination, by which time chlorination is
88% complete. This is interpreted as substitution of hydrogen atoms by chlorine
in the alkyl moieties of the asphaltenes; the condensed aromatic sheets remain
unaltered because substitution of aryl hydrogen appears to occur readily only in
the presence of a suitable catalyst, such as ferric chloride (FeC^), or at elevated
temperatures. It is only after more or less complete reaction of the alkyl chains
that addition to the aromatic rings occurs, as evidenced by the increased atomic
(H + Cl)-to-C ratios in the final stages of chlorination.
Bromine uptake by the asphaltenes is also complete in a comparatively short
time (<8 h). However, in contrast to the chlorinated products, the atomic (H +
halogen)-to-C ratio remains fairly constant (1.23 and 1.21 in the bromoasphaltenes
or 1.22 in the unreacted asphaltenes) over the prolonged periods (up to 24 h) of
the bromination.
Iodination of asphaltenes is different insofar as a considerable portion of the
iodine, recorded initially as iodine uptake, can be removed by extraction with ether
or with ethanol, whereas very little weight loss is recorded after prolonged exposure
of the material to a high vacuum. The net result is the formation of a product with an
atomic (H + I)-to-C ratio of 1.24 after an 8-h reaction; a more prolonged reaction
period affords a product with a (H + I)-to-C ratio of 1.17. This latter finding may
be the result of iodination of the alkyl or naphthenic moieties of the asphaltenes
with subsequent elimination of hydrogen iodide. Alternatively, dehydrogenation
of naphthene rings to aromatic systems or coupling of aromatic nuclei would also
account for lower (H + I)-to-C ratios. In fact, this latter phenomenon could account,
in part, for the insolubility of the products in solvents that are normally excellent
for dissolving the unchanged asphaltenes. However, it will be appreciated that
these aforementioned reactions are only a few of the many possible reactions that
can occur, and undoubtedly halogenation of the asphaltenes is much more complex
than would appear from the product data.
The iodine value of various oils and their derivatives (ASTM D-1541, ASTM
D-1959, IP 84) can be measured, thereby giving data that will complement the
bromine number. Halogenation of the asphaltenes can also be achieved with the use
of sulfonyl chloride, iodine monochloride, and A^-bromosuccinimide or indirectly
via the Gomberg reaction. As an addition to this segment, it is worthwhile to
note that iodine monochloride is used as the chemical means for detecting lead in
gasoline (ASTM D-3341, IP 270).
Halogens react with the oils relatively slowly, especially if there is no olefinic
(>C=C<) or aromatic unsaturation; essentially, substitution reactions occur. At
elevated temperatures, dehydrohalogenation occurs, giving rise to resin and asphaltene products.
THERMALMETHODS
The simplest thermal methods of analysis of petroleum, heavy oil, bitumen, residua,
and their respective fractions are, of course, the carbon residue tests (Chapter 5).
Briefly, and by way of introduction to this section, the carbon residue of crude
oil and crude oil products is a measure of the propensity of the sample to form coke
when combusted under specific conditions that require a limited supply of oxygen.
The carbon residue of a petroleum sample might be considered to be analogous to
the determination of fixed carbon for coal (ASTM D-3172, ASTM D-3173, ASTM
D-3174, ASTM D-3175).
There is a range of other thermal tests that can also be applied (Chapter 5), but the
major focus of this section is on the actual chemistry of the thermal decomposition
process. Because the standard tests for such work are extremely limited, even
nonexistent, it is necessary to rely on data from published works other than those
of standards organizations.
Asphaltenes can be thermally decomposed under conditions similar to those
employed for visbreaking (viscosity breaking; around 4700C, 8800F) to afford, on
the one hand, light oils that contain higher (to at least C36) paraffins and, on the
other hand, coke:
H2, CO, CO 2 , H 2 S, SO2, H2O +
CH 2 =CH 2 , CH4, CH3 .CH 3 , (CH3)3CH + CH3(CH2X1CH3
The thermal decomposition of asphaltenes provides an excellent example of
inconsistencies in the derivation of structural types from spectroscopic materials (i.e., magnetic resonance) in which alkyl side chains are deduced to contain
approximately four carbon atoms (Speight, 1970, 1971). Asphaltene pyrolysis
(350-8000C, 660-14700F) produces substantial amounts of alkanes (having up to
40 carbon atoms in the molecule) in the distillate, which can only be presumed
to reflect the presence of such chains in the original asphaltene. Transalkylation
studies (Farcasiu et al., 1983) also provide evidence for longer alkyl chains. Obviously, recognition of the inconsistencies of the spectroscopic method with respect
to the paraffinic moieties must lead to the recognition of similar inconsistencies
when considering the aromatic nucleus.
The application of thermal techniques to study the nature of the volatile thermal fragments from petroleum asphaltenes has produced some interesting data
relating to the polynuclear aromatic systems (Speight, 1971; Ritchie et al., 1979;
Schucker and Keweshan, 1980; Gallegos, 1981; Paul, 1982). These thermal techniques have produced strong evidence for the presence of small (1- to 4-ring)
polynuclear aromatic systems (Speight and Pancirov, 1984), and, now, application
of the technique to the various functional fractions has confirmed the general but
unequal distribution of these systems throughout asphaltenes.
Each asphaltene fraction produced the same type of polynuclear aromatic systems (Moschopedis and Speight, 1978) in the volatile matter, but the distribution
was not constant. It was also possible to compute the hydrocarbon distribution; a
noteworthy point here is the overall preponderance of single-ring (cycloparaffin
aromatic material. The preponderance of the low-molecular-weight material in the
volatile products is anticipated on the basis that more complex systems remain
as nonvolatile material and, in fact, are converted to coke. One other noteworthy
point is that the pyrolysis-gas chromatography-mass spectrometry (py/gc/ms) program does not accommodate nitrogen and oxygen species. This matter is resolved,
in part, by the concentration of nitrogen and oxygen in the nonvolatile material
(coke) and the overall low proportions of these heteroatoms originally present in
the asphaltenes.
The major drawback to the application of a py/gc/ms technique to the study
of the polynuclear aromatic systems in petroleum asphaltenes is the amount of
material that remains as a nonvolatile residue. Aside from speculation about the
polynuclear aromatic systems in the residue, it should be noted that the majority of
the nitrogen (>90%), oxygen (>50%), and sulfur (>60%) in the natural asphaltene
remains in the coke (Speight, 1971; Speight and Pancirov, 1984).
Paraffins are not the only hydrocarbon products of the thermal reactions of
asphaltenes. The reaction paths are extremely complex; spectroscopic investigations indicate an overall dealkylation of the aromatics to methyl (predominantly)
or ethyl (minority) groups. This is in keeping with a mass spectroscopic examination of asphaltene fractions (by direct introduction into the ionization chamber),
which indicates a progressive increase with increasing temperature (50-3500C,
120-6600F) of ions attributable to low-molecular-weight hydrocarbons. Higher
temperatures (5000C, 932F) promote the formation of benzene and naphthalene
nuclei as the predominant aromatics in the light oil, but unfortunately an increase
in coke production is noted.
In conclusion, thermal decomposition of asphaltenes affords a light oil having a
similar composition to that from the heavy oil and a hydrocarbon gas composed of
the lower paraffins, which, after the removal of the by-products (water, ammonia,
and hydrogen sulfide) has good burning properties. The formation of these paraffins
can be ascribed to the generation of hydrogen within the system that occurs during
the pyrolysis of condensed aromatic structures.
Although much work has been reported on the thermal decomposition of asphaltenes, a lesser amount of work is reported for the resins. The data that are
available indicate that, like the asphaltenes, the resins can be decomposed thermally to produce, on the one hand, a hydrocarbon-type of distillate and, on the
other hand, cokelike material. The prevalent conditions determine the relative
proportions of the two products.
Data from pyrolysis investigations and from HPLC-UV investigations show
that the condensed aromatic hydrocarbon fragments in the resins and asphaltenes
match those in the gas oil fraction. It now appears that the asphaltene constituents
are not different types (i.e., polynuclear aromatic sheets containing 12 or more
condensed rings) to the remainder of the oil. The asphaltene constituents are compatible with the structural types with the lower-molecular-weight fractions and
also compatible with natural product origins of petroleum (Speight, 1986, 1994).
It is however, in addition to the increasing molecular weight of the resin and asphaltenes constituents, the frequency of occurrence of the heteroatom functions
that increases. This is the main difference between the constituents of the resin
and asphaltenes fractions and the remainder of the constituents in petroleum.
The nonvolatile oil fraction is thermally stable at ordinary temperatures and is
quite resistant to attack by many chemicals. At elevated temperatures, fission of
side chains takes place. In the presence of oxygen (or air), carbon dioxide, water,
and products containing carbonyl >C=O and hydroxyl OH groups are found.
If the temperature is sufficiently high, the products containing oxygen functions
are unstable and dehydrogenation is the overall result.
In pyrolysis, the simplest degradation method, the sample is rapidly heated under exclusion of air to a temperature high enough to break some of the chemical
bonds. Typical reactions are dealkylation and the breakage of (aliphatic) sulfursulfur and sulfur-carbon bonds. The problem here is to find a compromise between
specificity and yield, which means that the temperature and other reaction conditions must be carefully chosen.
A common procedure is to heat the sample in a tube to the desired temperature
for several hours. The tube may be evacuated (Rubinstein and Strausz, 1987) or
swept with an inert gas (Mclntire et al., 1987). Typical temperatures reported
for these procedures are 300-4000C (570-7500F), and sample sizes are in the
order of 100 mg or less. The reaction products are collected in various ways and
usually analyzed afterward. Only with gas-swept arrangements can the products
be analyzed on-line by gas chromatography.
Flash pyrolysis on a thin, electrically heated wire with properly chosen Curie
temperature, for example, 6100C(11300F), ensures rapid warm-up and brief exposure time for suppression of side reactions. In this procedure, a very small amount
(about 100 |JLg) of the sample is pressed onto the wire. Warm-up time is 0.1 s, and
the gaseous products are directly transferred to a gas chromatograph, preferably
with MS as detector.
Another variation of flash pyrolysis has been described (Payzant et al., 1991)
in which the sample (in toluene solution) is dripped from a dropping funnel at a
slow rate (< 1 ml/min) to the bottom of a flask which is heated by a temperaturecontrolled sand bath, typically at 4300C (8000F). A flow of nitrogen sweeps the
reaction products and the solvent to a cooled collection flask for subsequent concentration and analysis. There was no evidence for degradation of the toluene. The
pyrolysis oil can be separated into a number of compound groups by a combination of liquid chromatography with another associated physical identification or
chemical method.
MISCELLANEOUS METHODS
Reactions of asphaltenes with sulfur have also received some attention and have
yielded interesting results. For example, treatment of the asphaltenes with oxygen
or with sulfur at 150-2500C (300-4800F) yields a condensed aromatic product
[H/C = 0.97; H/C (asphaltenes) = 1.20] containing very little additional sulfur.
The predominant reaction here appears to be condensation between the aromatic
and aliphatic moieties of the asphaltenes promoted by elemental sulfur, which
are in turn are converted to hydrogen sulfide. Condensation appears to proceed in
preference to molecular degradation, and treatment of the condensed products at
200-3000C (390-570F) for 1-5 h again affords good-grade cokes (H/C = 0.540.56). In all instances the final products contain only very low amounts of elements
other than carbon and hydrogen (N + O + S < 5 % b y weight), a desirable property
of good-grade coke.
Reductive alkylation is ordinarily used to make asphaltene constituents more
soluble and less prone to aggregation in hydrocarbon solvents. The sample is
dissolved in tetrahydrofuran (although not all asphaltene constituents are soluble
in this solvent), an excess of metallic potassium under exclusion of air. Assuming
no side reactions, this method produces the final alkylated product. However, it has
been demonstrated (Ebert et al., 1989) that petroleum residues contain sufficient
aromatic carbon to make the reaction proceed well without additional naphthalene.
It is preferable to omit this agent because side reactions are then mitigated.
In contrast, it has been claimed (Ignasiak et al., 1977) that the presence of
naphthalene in the reaction mixture increases the number of sulfur atoms removed
and also the number of the alkyl groups inserted into the asphaltenes moieties.
However, the absence or presence of naphthalene was not the only difference in
the reaction conditions, and serious experimental flaws negated the experimental
results (Speight and Moschopedis, 1980).
A principal reaction of this procedure is the conversion of aromatic double
bonds via dianions to naphthenic bonds with alkyl groups inserted on to the corresponding carbon atoms. Two other important reactions are the desulfurization of
thiophene structures and the cleavage and transalkylation of (aliphatic) sulfides.
Such reactions cannot be ignored in the interpretation of the data.
A more elegant two-step reaction sequence has been developed for cleaving
carbon-sulfur bonds (Rose and Francisco, 1987,1988). Some carbon-carbon bonds
are also cleaved by the alkali metal, followed by selectivity labeling the resulting
thiols with carbon-13 and deuterium-enriched groups. Carbon-13 and deuterium
magnetic resonance spectroscopy of the samples before and after cleavage gave
recognizable chemical shift data of the methyl labels, enabling identification of
several types of S compounds in three main classes:
1. diaryl sulfides ranging from dibenzyl to bis(l-naphthylmethyl) sulfide,
2. sulfur compounds that form thiols on reductive protonation, namely, alkylaryl and aryl-aryl sulfides as well as certain hyphened derivatives, and
3. S compounds that resist cleavage by reductive protonation, for example,
dibenzothiophene derivatives and dialkylsulfides.
This procedure allows a more specific identification of the chemistry of the various
sulfur compounds and the means by which they will react under various conditions.
Arpino, P. J., Ignatiadis, L, and De Rycke, G. 1987. /. Chromatog. 390: 329.
Behar, R, and Pelet, Philip, R. P., and Rowland, S. J. 1988. Org. Geochem. 12(1): 33.
Beuther, H., and Schmid, B. K. 1963. Proc. 6th World Petroleum Cong. 3: 297.
Drushel, H. V. 1972. Preprints Div. Petrol Chem. Am. Chem. Soc. 17: F92.
Ebert, L. B., Kastrup, R. V., and Scanlon, J. C. 1989. Fuel ScL Technol. Intl. 7: 377.
Farcasiu, M., Forbus, T. R., and LaPierre, R. B. 1983. Preprints. Div. Petrol. Chem. Am.
Chem. Soc. 28: 279.
Gallegos, E. J. 1981. Chromatogr ScL 19: 177.
Ignasiak, T., Kemp-Jones, A. V., and Strausz, O. P. 1977. /. Org. Chem. 42: 312.
Isoda, T., Nagao, S., Ma, X., Korai, Y., and Mochida, I. 1996a. Energy Fuels 10: 482.
Isoda, T., Nagao, S., Ma, X., Korai, Y, and Mochida, I. 1996b. Energy Fuels 10: 487.
Mclntire, D. D., Montgomery, D. S., Strausz, O. P 1987. AOSTRA J. Res. 2: 251.
Mojelsky, T. W., Ignasiak, T. M., Frakman, Z., Mclntyre, D. D., Lown, E., Montgomery,
D. S., and Strausz, O. P. 1992. Energy Fuels 6: 83.
Moschopedis, S. E., and Speight, J. G. 1971. Fuel 50: 58.
Moschopedis, S. E., and Speight. J. G. 1976a. Fuel 55: 187.
Moschopedis, S-. E., and Speight, J. G. 1976b. Proc. Assoc. Asphalt Paving Technol. 45: 78.
Ozaki, H., Satomi, Y, and Hisamitsu, T. 1963. Proc. 6th World Petroleum Cong. 6: 97.
Paul, P. R. 1982. Trends Anal. Chem. 1: 237.
Payzant, J. D., Lown, E. M., and Strausz, O. P. 1991. Energy Fuels 5: 445.
Reynolds, J. G. 1998. In: Petroleum Chemistry and Refining. Taylor & Francis Publishers,
Philadelphia, PA. Chapter 3.
Ritchie, R. G. S., Roche, R. S., and Steedman, W. 1979. Fuel 58: 523.
Rose, K. D., and Francisco, M. A. 1987. Energy Fuels 1: 233.
Rose, K. D., and Francisco, M. A. 1988. J. Am. Chem. Soc. 110: 637.
Rubinstein, L, and Strausz, O. P. 1987. Geochim. Cosmochim. Acta. 43: 1887.
Rubinstein, L, Spyckerelle, C , and Strausz, O. P. 1987. Geochim. Cosmochim. Acta. 43: 1,
Ruiz, J.-M., Carden, B. M., Lena, L. J., Vincent, E.-J., and Escalier, J. C. 1982. Anal. Chem.
Schucker, R. C , and Keweshan, C. F. 1980. Preprints. Div. Fuel Chem. Am. Chem. Soc. 25:
Scott, J. W., and Bridge, A. G. 1971. In: Origin and Refining of Petroleum. H. G. McGrath
and M. E. Charles (Editors). Advances in Chemistry Series No. 103. Am. Chem. Soc,
Washington, DC. p. 113.
Speight, J. G. 1970. Fuel 49: 76.
Speight, J. G. 1986. Preprints. Div. Petrol. Chem. Am. Chem. Soc. 31(4): 818.
Speight, J. G. 1994. 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., and Moschopedis, S. E. 1980. Fuel 59: 440.
Speight, J. G., and Pancirov, R. J. 1984. Liquid Fuels Technol. 2: 287.
Speight. J. G., Long, R. B., and Trowbridge, T. D. 1982. Preprints. Div. Fuel Chem. Am.
Chem. Soc. 27(3/4): 268.
Taft, R. W., Berthelot, M., Laurence, C , and Leo, A. J. 1996. Chemtech. July. p. 20.
Yan, J., Plancher, H., and Morrow, N. R. 1997. Paper No. SPE 37232. SPE International
Symposium on Oilfield Chemistry. Houston, TX.
FRACTIONAL COMPOSITION
Recognition that refinery behavior is related to the composition of the feedstock
has led to a multiplicity of attempts to establish petroleum and its fractions as compositions of matter. As a result, various analytical techniques have been developed
for the identification and quantification of every molecule in the lower-boiling fractions of petroleum. It is now generally recognized that the name petroleum does
not describe a composition of matter but rather a mixture of various organic compounds that includes a wide range of molecular weights and molecular types that
exist in balance with each other (Speight, 1994; Long and Speight, 1998). There
must also be some questions of the advisability (perhaps futility is a better word)
of attempting to describe every molecule in petroleum. The true focus should be
to what ends these molecules can be used.
Thus investigations of the character of petroleum need to be focused on the
influence of its character on refining operations and the nature of the products that
will be produced. Furthermore, one means by which the character of petroleum
has been studied is through its fractional composition. However, the fractional
composition of petroleum varies markedly with the method of isolation or separation, thereby leading to potential complications (especially in the case of the
heavier feedstocks) in the choice of suitable processing schemes for these feedstocks. Crude oil can be defined (on a relative or standard basis) in terms of three
or four general fractions: asphaltenes, resins, saturates, and aromatics (Fig. 9.1).
Thus it is possible to compare interlaboratory investigations and thereby apply the
concept of predictability to refining sequences and potential products.
Investigations of the character of petroleum through fractionation studies have
been practiced for more than 160 years (Boussingault, 1837), although modern
fractionation techniques are essentially a twentieth century approach to examining petroleum composition (Rostler, 1965; Altgelt and Gouw, 1979; Altgelt and
Boduszynski, 1994; Speight, 1999). In fact, the fractionation of petroleum has
evolved to such an extent that it is now possible to determine with a high degree
of accuracy the types of compounds present in a crude oil.
The fractionation methods available to the petroleum industry recognize the
need to separate the constituents without alteration of their molecular structure,
(n-Heptane)
Deasphaltened oil
(Percolate through alumina)
(lnsolubles)
(Soluble in toluene)
Carbenes/Carboid
(Insoluble in toluene)
Carbenes
(Soluble in CS2)
3: Resins
(Pyridine wash)
2: Aromatics
(Toluene wash)
1: Saturates
(n-Heptane wash)
Carboids
(Insoluble in CS2)
Figure 9.1. A simple fractionation scheme for various feedstocks.
thereby obtaining these constituents in a substantially pure state. Thus the general procedure is to use techniques that segregate the constituents according to
molecular size and molecular type.
It is generally true, however, that the success of any attempted fractionation
procedure involves not only the application of one particular technique but also the
utilization of several integrated techniques, especially those techniques involving
the use of chemical and physical properties to differentiate among the various
constituents. For example, the standard processes of physical fractionation used
in the petroleum industry are those of distillation and solvent treatment, as well as
adsorption by surface-active materials. Chemical procedures depend on specific
reactions, such as the interaction of oleflns with sulfuric acid or the various classes
of adduct formation. Chemical fractionation is often but not always successful
because of the complex nature of crude oil. This complex nature may result in
unprovoked chemical reactions that have an adverse effect on the fractionation
and the resulting data. Indeed, caution is advised when using methods that involve
chemical separation of the constituents.
The order in which the several fractionation methods are used is determined not
only by the nature and/or composition of the crude oil but also by the effectiveness
of a particular process and its compatibility with the other separation procedures
to be employed. Thus, although there are wide variations in the nature of crude oil
(Chapters 1 and 2), there have been many attempts to devise standard methods of
petroleum fractionation. However, the various laboratories are inclined to adhere
firmly to and to promote their own particular methods. Recognition that no one
particular method may satisfy all the requirements of petroleum fractionation is
the first step in any fractionation study. This is mainly because of the complexity
of petroleum, not only from the distribution of the hydrocarbon species but also
from the distribution of the heteroatom (nitrogen, oxygen, and sulfur) species.
It is the purpose of this chapter to present an overview of those methods that have
been applied to the separation of petroleum. This leads not only to an understanding
of the separation of petroleum but also to an understanding of the character of
petroleum. Both factors bear a very strong relationship to the processability of
petroleum (van Nes and van Westen, 1951; Traxler, 1961; Fisher, 1987; Speight,
Distillation is a common method for the fractionation of petroleum that is used
in the laboratory as well as in refineries. The technique of distillation has been
practiced for many centuries, and the stills that have been employed have taken
many forms (Nelson, 1958; Gruse and Stevens, 1960; Speight, 1999). In the early
days of the refining industry, distillation was recognized as a way to produce a
desirable product (kerosene as a lamp oil). Thus it is not surprising that distillation
became the process of choice for petroleum refining; this process has evolved from
the simple distillation units to complex multiplate still used in the refining industry.
Distillation is the most basic separation process in a petroleum refinery. It
has been proposed (Altgelt and Boduszynski, 1994) that distillation should have
a similar place in the laboratory of the analytical petroleum chemist in that it
should precede any other separation methods in most cases. However, the analytical
chemist who focuses on petroleum may not be of a similar opinion when dealing
with heavy oil and tar sand bitumen. There are methods for distillation of heavy
oil or bitumen at very low pressures and, consequently, to a very high atmospheric
equivalent boiling point; however, the gains must be weighed against the effort.
Nevertheless, where applicable, distillation reduces both the molecular weight
range and the variety of chemical groups. However, separation by distillation takes
place according to volatility and not necessarily according to molecular weight.
Comparison of the boiling points of 2-hydroxypyridine (280C/760 mm Hg,
535F/760 mm Hg) and 4-hydroxypyridine (257C/10 mm Hg, 495F/10 mm Hg)
illustrates that molecular structure and the consequences of this structure also influence boiling point. In more general terms, and without any attendant bonding
influences, the boiling point increases with molecular weight in each homologous
series, but the differences between boiling points in the different homologous series
are quite substantial. For example, the two-ring naphthene decahydronaphthalene
(decalin) with 10 carbon atoms (molecular weight 138) boils at 195C (383F),
but the 10-carbon-atom normal paraffin decane (molecular weight 142) boils at
174C (345F).
The theory of distillation has occupied several large texts and is discussed only
briefly here. Thus, if a liquid is contained in a closed space, it emits vapor until a
pressure of the vapor is reached that is related to the temperature of the system;
the vapor is then said to be saturated. The vapor pressure of a liquid substance in
contact with its own liquid is constant and is independent of the amount of liquid
and of the vapor present in the system. The vapor pressure is usually expressed in
terms of the height of a mercury column (in millimeters or inches) that produces
an equivalent pressure.
The vapor pressure of a liquid increases with increasing temperature; when the
vapor pressure is equal to the total pressure exerted on the surface of the liquid, the
liquid boils. Thus the boiling point of a liquid may be defined as the temperature
at which the vapor pressure of the liquid is equal to the external pressure exerted
on the liquid surface. This external pressure may be exerted by atmospheric air,
by other gases, by vapor and air, and so on. The boiling point at a pressure of
760 mm air is usually referred to as the normal boiling point.
The boiling point of a pure liquid has a definite and constant value at a constant
pressure, but the boiling point of an impure liquid depends to some extent on
the nature of the impurities. If the impurities are nonvolatile, the liquid boils at a
constant temperature and the impurities remain behind when the liquid has been
distilled. If, however, the impurities are volatile, the boiling point rises gradually
as the liquid distills or may remain constant at a particular stage of the distillation
because of the formation of a constant boiling point mixture of two or more
components.
The common feature of all distillation processes is the tendency for the concentration of the more volatile component in the vapor phase to be greater than that in
the liquid phase when the two phases have been in contact. In simple distillation,
the enrichment of the more volatile component is achieved by partially vaporizing
a liquid mixture, either by raising the temperature or by reducing the pressure, and
allowing the two phases to separate.
Thus the distribution of a component between vapor and solution may be expressed as a function of temperature and pressure. If an ideal solution contains
components of different vapor pressures at a specific temperature, the vapor phase
in equilibrium with the liquid phase at this temperature is relatively richer in the
more volatile components. The liquid phase is relatively richer in the less volatile
components and the components with lower vapor pressures, and a partial separation of components may be achieved. The vapor phase that separates is said to distill
at this temperature, and a solution of continuous boiling points, such as petroleum,
can be separated by multiple stages of distillation into fractions', each fraction has
a relatively narrow boiling range but may, in fact, contain many constituents.
In the chemical sense, the difference between carbon number (or molecular
weight), boiling point, and chemical composition is obvious. Thus n-paraffins
have, for a given carbon number, the lowest boiling points. Naphthenes boil at
somewhat higher temperatures, and aromatic hydrocarbons have higher boiling
points. Alkyl substitution elevates the corresponding boiling point, and aromatic
polar species have even higher boiling points. Condensed polynuclear aromatic
molecules with several polar groups and no alkyl chains have the highest boiling
points for a given molecular weight.
Thus a narrow distillation fraction can contain a wide range of molecular weight
species. The different intermolecular forces that affect the heat of vaporization and
thus the boiling point of a compound cause this important fact. For a homologous
series of alkanes, the weak Van der Waals dispersion forces prevailing between the
molecules become greater in proportion with increasing carbon number. Aromatic
compounds have additional attractive intermolecular forces acting on them and,
therefore, have higher boiling points than aliphatic molecules of similar molecular
weight and structure. The intermolecular forces are even stronger in polar compounds, which are capable of hydrogen bonding or other types of polar interactions.
Among the prevalent distillation methods, there are two major categories:
(1) column distillation and (2) short-path distillation (Chapter 5).
Column distillation (batch mode) is performed at high pressures, at atmospheric
pressure, and at reduced pressures. High pressures are used mainly in large-scale
refinery distillations with low-boiling distillates and result in higher distillation
In short-path distillation (also called molecular distillation) (continuous mode),
a very high vacuum is applied and the sample passes rapidly as a very thin film over
a heated surface. The lighter molecules evaporate and are condensed on a cooled
surface that is located within 2-3 cm of the condensing surface. The vacuum must
be high enough to ensure that the mean free-path length of a distillate molecule is
shorter than the distance between the heated and the cooled surfaces.
The bulk of the distillation procedures performed in the laboratory (Chapter 5)
is carried out in packed columns. The efficiency of a distillation column is measured in terms of its number of theoretical trays or plates, and the higher this
number, the higher its efficiency. Generally, the number of theoretical plates is
proportional to the column length. For most column packings in laboratory distillations, the height of a theoretical plate is roughly equal to the diameter of the
A theoretical plate in distillation is a hypothetical section of a column that
produces the same difference in composition of the ascending distillate as exists at
equilibrium between a liquid mixture and its vapor. It acts as an ideal bubble-cap
tray would. The packing provides a large surface area for the descending reflux. As
the rising vapor comes in contact with the descending liquid, some of its higherboiling component transfers to the reflux and some of the lower-boiling component
transfers from the liquid to the vapor.
Therefore, the vapor arriving at the top of a theoretical plate section contains a
lower amount of high-boiling material than it had when it came in at the bottom,
and its lighter component is correspondingly enriched. On the other hand, the reflux
leaving the theoretical plate at the bottom contains a higher amount of high-boiling
material than when it came in at the top. Also, comparison of the composition of
the liquid phase at the top with that of the liquid phase at the bottom shows that if
the section indeed has the length of a theoretical plate, then the composition of the
liquid phase at its top is equal to the (theoretical) vapor composition in equilibrium
with the liquid at the bottom.
Distillation has found wide applicability in petroleum science and technology, but
it is generally recognized that the fractions separated by distillation are only rarely,
if at all, suitable for designation as a petroleum product. Each usually requires some
degree of refining, which of course varies with the impurities in the fraction and
the desired properties of the finished product. Nevertheless, distillation is the most
important fractionating process for the separation of petroleum hydrocarbons; it
is an essential part of any refinery operation (Nelson, 1958; Bland and Davidson,
However, insofar as petroleum is a mixture of several thousand (or even more)
individual chemical compounds, there is little commercial emphasis on the isolation of the individual components. The aim of the distillation of petroleum is
predominantly an assessment of the nature and volatility of the material through
separation into several fractions of substantially broad boiling ranges.
The standard laboratory distillation column has a diameter of about 25-60 mm,
a height of 1-1.5 m, and an efficiency of 15-50 theoretical plates. Occasionally,
one may need taller columns or columns with a high-efficiency packing delivering
as many as 70-100 theoretical plates.
Of special interest in the distillation laboratory are the spinning band columns.
These are constructed of precision-bore glass tubing 1-20 mm in diameter and
30-100 cm in length, in which a closely fitted twisted Teflon or metal band rotates
at high speed. The centrifugal force exerted on both the ascending vapors and the
descending reflux brings both into intimate contact on the column walls, achieving
the high mass and heat transfer required for good efficiencies. The major advantage
of these columns is that they have very low pressure drops. They can be used for
high-vacuum distillation of heavy oil and bitumen that have low or zero amounts
of nonvolatile constituents up to boiling points of about 430^80 0 C (800-9000F).
In a refinery operation, there is a tendency to construct columns with a large
number of theoretical plates and to operate them at a low reflux ratio to reduce
heating and cooling costs. In the laboratory, there is the tendency to use less efficient
columns to reduce column holdup and to compensate by running the unit at a higher
reflux ratio. This, however, reduces the throughput. At a reflux-to-distillate ratio
of RA, each distillate molecule travels the column R 4- 1 times up and R times
down on average before it is collected. Hence, a balance must be found between
sufficiently high reflux ratios for good efficiency on the one hand and low enough
reflux ratios for reasonable throughput rates on the other. Reflux ratios of 5:1 to
20:1 are commonly used in the laboratory.
Separation of the reduced crude {atmospheric residuum) into the constituent
fractions requires that the next-stage distillation be carried out under reduced
pressure. The higher boiling constituents undergo thermal decomposition at temperatures above 3500C (6600F). This will result in molecular fragmentation leading
to volatile products (which were not indigenous to the crude oil) and to coke.
In actual refinery practices, higher temperatures are used and, to avoid these
thermal decomposition reactions, it is necessary to reduce the pressure at which
the distillation is performed and to reduce the contact time or residence time of
the feedstock in the hot zones. Because the vapor pressure and temperature are
related, the lowering of the pressure is accompanied by a corresponding decrease
in the boiling points of the individual constituents.
Thus vacuum distillation also allows the laboratory scientist or the refiner to
obtain higher-boiling distillates, leaving a smaller amount of the residuum, without
thermal decomposition. Operational pressures in vacuum distillation with packed
columns generally range from 5 to 200 mm Hg. At lower pressures, the vapor
velocity increases, resulting in greater pressure drops, and there may be little
advantage in going to pressures below 5 mmHg.
For still lower pressures, an empty column or a spinning band column is necessary but not always practical in the refinery. With these columns, the pressure
drop is small enough that low pressures can be maintained in the reboiler. For
instance, with a distillate pressure of 0.1 mm Hg, one may have a pressure of
0.5-1 mm Hg in the reboiler that, theoretically, allows the collection of distillates with an atmospheric equivalent temperature cut point of as high as 5600C
(1,0500F). The actual observed boiling points during this distillation are, of course
much lower. Despite the low pressure, the reboiler may have to be heated as high
as 3700C (7000F) for such high-boiling distillates.
From the actual boiling points, obtained at reduced pressure, the so-called atmospheric equivalent temperatures (AET), at which the material would boil under
atmospheric pressure if it was stable and would not decompose, are calculated.
Thus the concept of vacuum distillation, for which an atmospheric equivalent
temperature is derived, extends the boiling point range of atmospheric distillation
beyond the decomposition limit. It provides a common basis for the categorization
and direct comparison of petroleum components across the entire volatility range
accessible by atmospheric and vacuum distillation.
Within the distillates, the physical and chemical properties are known to change
only gradually with the boiling point, allowing interpolations and even extrapolations with reasonable certainty. Whenever the range of distillates is expanded, first
by vacuum distillation, then by short-path distillation, the new distillate portions
of the previously nondistillable residua follow the same patterns as the previous
distillates. The relationship of carbon number or molecular weight, or of sulfur and
Cumulative wt %
Figure 9.2. Representation of the volatile constituents of petroleum as a continuum.
nitrogen concentrations, could be extended smoothly into the new regions. Such
continuity is no surprise but highly likely, considering the nature of the petroleum
precursors and the maturation chemistry. Thus the data can be extrapolated across
the dividing line between distillates and residua, even into those ranges that are
still beyond exact measurements.
Indeed, the concept that petroleum is a continuum of structural types that may
be further defined in terms of polarity and molecular weight (or boiling point) is not
new and has been generally accepted for several decades (Chapter 15) (Long, 1981;
Speight, 1999 and references cited therein). The initial focus in this concept was on
the hydrocarbon types that occurred in the volatile fractions (Fig. 9.2), leaving the
nature of the nonvolatile fractions open to speculation. Further work on nonvolatile
gas oils has shown that the continuum is ubiquitous, at least sufficient to include
such fractions (Fig. 9.3).
The concept that asphaltene fraction is located at the high-molecular-weight
end of this continuum has also been postulated and is now becoming accepted
(Speight, 1994). Similar reasoning is appropriate to the constituents of the resin
fraction. In addition, there is evidence that the continuum of hydrocarbon types,
or more correctly hydrocarbon fragments, continues from the gas oil fractions into
the resins and asphaltenes.
The atmospheric equivalent temperature that is derived from earlier relationships of the midboiling point of petroleum fractions (Altgelt and Boduszynski,
Figure 9.3. Representation of all of the constituents (volatile and nonvolatile) of petroleum as a
continuum.
1994) can be estimated from the actual boiling points obtained under vacuum by
AET(C) = [(748.1xA)/(l/VT,K) + (0.386IxA) - 0.00051606] - 273
A = [5.9991972 - (0.9774472 x logP)]/[2663.129 - (95.76 x logPO)]
where VT,K is the observed vapor temperature in degrees Kelvin and P is the
pressure of the system in mmHg observed when the vapor temperature was read.
Atmospheric equivalent temperatures can be calculated, and the true boiling point
(TBP) distribution of crude oil {distillation profile) can be derived (ASTM D-2892)
With the use of the atmospheric equivalent boiling point relationship (Altgelt
and Boduszynski, 1994), it is possible to assign numbers to the boiling ranges
of asphaltenes that are dependent on hydrogen-carbon atomic ratio and also on
density (Table 9.1, Fig. 9.4). Similar boiling ranges can be estimated on the basis
of hypothetical structures that have also been assigned to asphaltenes (Speight,
1994). These data show that any attempts at distillation of asphaltene constituents
will present a formidable obstacle.
As an alternative to empty column or spinning band distillations or to cut
even deeper into the stock, high-vacuum short-path distillation can be used. Other
Table 9.1. Calculated Hypothetical Data for the Boiling Points (0F) of Asphaltenes
(see also Fig. 9.4)
H/C In Increments of 0.05 From 1.00 to 1.30
names for this technique are molecular distillation and/or wiped-film distillation,
although the latter is often performed with insufficient vacuum and belongs then
to a different category.
The most important feature of the short-path still is a very high vacuum of at
least 10~3 mmHg that ensures that the mean free-path length of the molecules in
the gas phase is approximately 2-3 cm, which is the distance between the evaporator and the condenser surfaces. These conditions afford much lower distillation
temperatures than possible in regular open columns at the same surface temperature. The sample is spread into a very thin film on the evaporating surface for
quick evaporation and a short residence time. The combination of high vacuum,
short distance, and short residence time allows very deep distillation without decomposition. Modern versions of these short-path stills can fractionate oils up to
atmospheric equivalent boiling points of 700 0 C (1,3000F) with fairly high throughput rates. The small DISTACT laboratory short-path still, for example, has a rate
of about 100-800 ml/h with a residence time of less than 1 min. Large production
plants can operate with throughputs of up to 300 L/m 2 /h.
In short-path stills (Chapter 5), the preheated sample is pumped at a precisely
regulated rate onto the surface of a heated vertical cylinder in the evaporation
Figure 9.4. Representation of the hypothetical boiling points (0F) of asphaltenes (see also Table 9.1).
chamber where it is spread by wipers into a uniform, thin, falling (downward
flowing) film. The lower-boiling components are flash-evaporated and collected
on a condenser, typically a coil inside the feed cylinder, and only two fractions are
produced, the flash distillate and the residue.
Azeotropic and Extractive Distillation
Should the separation of individual components from petroleum itself or from
petroleum products be advantageous, there are means by which this can be accomplished. For example, when a constant-boiling mixture of hydrocarbons contains
components whose vapor pressure is affected differently by the addition of, say,
a nonhydrocarbon compound, distillation of the hydrocarbon mixture in the presence of nonhydrocarbon additive may facilitate separation of the hydrocarbon
In general, the nonhydrocarbon additive is a polar organic compound and
should also have the ability to form a binary minimum constant-boiling (or azeotropic) mixture with each of the hydrocarbons. Thus it is often possible to separate compounds that have very close boiling points by means of azeotropic
distillation.
However, when the added compound is relatively nonvolatile, it exists almost
entirely in the liquid phase, and the process is actually extractive distillation.
The separation of petroleum by distillation into fractions results in a concentration effect in which the heteroatom constituents (metals included) occur for the
most part in the residua (Long and Speight, 1990; Reynolds, 1998). Sulfur, because
of its ubiquitous molecular nature, is often an exception to this generalization and
occurs in most distillation fractions.
SOLVENT TREATMENT
Fractionation of petroleum by distillation is an excellent means by which the
volatile constituents can be isolated and studied. However, the nonvolatile
residuum, which may actually constitute from 1 to 60% of the petroleum, cannot
be fractionated by distillation without the possibility of thermal decomposition; as
a result, alternative methods of fractionation have been developed. However, those
methods, which are designed to estimate sediment in crude oil products, are not
discussed here. They are the subjects of another chapter (Chapter 13).
The treatment of petroleum and petroleum products with solvents varies from
the more simple determination of the precipitation number of lubricating oils
(ASTM D-91) to the more complex fractionation methods by which several constituent fractions are produced using methods that are reproducible and repeatable.
In fact, it is often the simpler methods of testing that have led to the modern complex
fraction procedures.
Solvent methods have also been applied to petroleum fractionation on the basis
of molecular weight. The major molecular weight separation process used in the
laboratory as well as in the refinery is solvent precipitation. Solvent precipitation
occurs in a refinery in a deasphalting unit and is essentially an extension of the
procedure for separation by molecular weight, although some separation by polarity might also be operative. The deasphalting process is usually applied to the
higher-molecular-weight fractions of petroleum such as atmospheric and vacuum
residua.
The simplest application of solvent extraction consists of mixing petroleum
with another liquid, which results in the formation of two phases. This causes
distribution of the petroleum constituents over the two phases; the dissolved portion
is referred to as the extract, and the nondissolved part of the petroleum is referred
to as the raffinate.
The ratio of the concentration of any particular component in the two phases is
known as the distribution coefficient K:
K = CxIC1
where C\ and C1 are the concentrations in the various phases. The distribution
coefficient is usually constant and may vary only slightly, if at all, with the concentration of the other components. In fact, the distribution coefficients may differ
for the various components of the mixture to such an extent that the ratio of the
concentrations of the various components in the solvent phase differs from that in
the original petroleum; this is the basis for solvent extraction procedures.
It is generally molecular type, not molecular size, that is responsible for the solubility of species in various solvents. Thus solvent extraction separates petroleum
fractions according to type, although within any particular series there is a separation according to molecular size. Lower-molecular-weight hydrocarbons of a
series (the light fraction) may well be separated from their higher-molecular-weight
homologues (the heavy fraction) by solvent extraction procedures.
In general, it is advisable that selective extraction be employed with fairly
narrow boiling range fractions. However, the separation achieved after one treatment with the solvent is rarely complete, and several repetitions of the treatment
are required. Such repetitious treatments are normally carried out by movement
of the liquids countercurrently through the extraction equipment (countercurrent
extraction), which affords better yields of the extractable materials.
The list of compounds that have been suggested as selective solvents for the
fractionation of petroleum is very large (Nelson, 1958; Gruse and Stevens, 1960;
Speight, 1999). However, before any extraction process is attempted, it is necessary
to consider the following criteria:
The differences in the solubility of the petroleum constituents in the solvent
should be substantial.
The solvent should be significantly less or more dense than the petroleum
(product) to be separated to allow easier countercurrent flow of the two
Separation of the solvent from the extracted material should be relatively easy.
It may also be advantageous to consider other properties, such as viscosity,
surface tension, and the like, as well as the optimal temperature for the extraction
process. Thus aromatics can be separated from naphthene and paraffinic hydrocarbons by the use of selective solvents. Furthermore, aromatics with differing
numbers of aromatic rings that may exist in various narrow boiling fractions can
also be effectively separated by solvent treatment.
Asphaltene Separation
Influence of Solvent Type
The suggestion arose in 1914 that the systematic separation of petroleum be effected by treatment with solvents. If chosen carefully, solvents effect a separation
between the constituents of residua, bituminous materials, and virgin petroleum
according to differences in molecular weight and aromatic character. The nature
and the quantity of the components separated depend on the conditions of the experiment, namely, the degree of dilution temperature and the nature of the solvent
(Mitchell and Speight, 1973; Speight et al., 1984).
On the basis of the solubility in a variety of solvents, it has become possible to distinguish among the various constituents of petroleum and bitumen
(Fig. 9.1). Crude oil generally does not contain carboids and carbenes. Residua
from cracking processes may contain 2% w/w by weight or more. In fact, some of
the highly paraffinic crude oils may contain only small portions of asphaltenes.
Thus the separation of crude oil into two fractions, asphaltenes and maltenes,
is conveniently brought about by means of low-molecular-weight paraffinic hydrocarbons (ASTM D-2006, ASTM D-2007, ASTM D-3279, ASTM D-4124,
IP 143), which were recognized to have selective solvency for hydrocarbons and
simple, relatively low-molecular-weight heteroatom derivatives. The more complex, higher-molecular-weight compounds are precipitated particularly well by
addition of 40 volumes of n-pentane or n-heptane in the methods generally preferred at present (Speight, et al., 1984; Speight, 1994), although hexane is used on
occasion (Yan et al., 1997). This process is no doubt a separation of the chemical
components with the most complex structures from the mixture, and this fraction,
which should correctly be called n-pentane asphaltenes or n-heptane asphaltenes,
is qualitatively and quantitatively reproducible (Fig. 9.1).
One of the standard methods (ASTM D-2006) has been discontinued as an
ASTM method but still finds use in many laboratories and represents a very convenient method of asphaltene separation.
If the precipitation method (deasphalting) involves the use of a solvent and a
residuum or bitumen and is essentially a leaching of the deasphaltened oil from
the insoluble residue, this process may be referred to as extraction. However,
under the prevailing conditions now in laboratory use, that is, using conventional
petroleum or heavy oil or a solution of the residuum or bitumen in toluene (or
a similar solvent), the term precipitation is more correct and descriptive of the
Variation in the solvent type also causes significant changes in asphaltene yield.
For example, branched-chain paraffins or terminal olefins do not precipitate the
same amount of asphaltenes as the corresponding normal paraffins (Mitchell and
Speight, 1973). The solvent power of the solvents (i.e., the ability of the solvent
to dissolve asphaltenes) increases in the order
2-methylparaffin < n -paraffin < terminal olefln
(wo-paraffin)
Cycloparaffins (naphthenes) have a remarkable effect on asphaltene yield and
give results totally unrelated to those from any other nonaromatic solvent. For example, when cyclopentane, cyclohexane, or their methyl derivatives are employed
as precipitating media, only about 1% of the material remains insoluble.
To explain those differences, it was necessary to consider the solvent power of
the precipitating liquid, which can be related to molecular properties (Hildebrand
Thus the solvent power of nonpolar solvents has been expressed as a solubility
parameter, 8, and equated to the internal pressure of the solvent, that is, the ratio
between the surface tension 7 and the cubic root of the molar volume V:
Alternatively, the solubility parameter of nonpolar solvents can be related to
the energy or vaporization ARy and the molar volume:
82 = (A v /V) 1 / 2
82 = ( A i T -
RT/V)l/2
where A// v is the heat of vaporization, R is the gas constant, and T is the absolute
Consideration of this approach shows that there is indeed a relationship between
the solubility parameters for a variety of solvents and the amount of precipitate
(Mitchell and Speight, 1973). The introduction of a polar group (heteroatom function) into the molecule of the solvent has significant effects on the quantity of
precipitate. For example, treatment of a residuum with a variety of ethers or treatment of asphaltenes with a variety of solvents illustrates this point (Speight, 1979).
In the latter instance, it was not possible to obtain data from addition of the solvent to the whole feedstock per se, because the majority of the nonhydrocarbon
materials were not miscible with the feedstock. It is nevertheless interesting that,
as with the hydrocarbons, the amount of precipitate, or asphaltene solubility, can
be related to the solubility parameter.
The solubility parameter allows an explanation of certain apparent anomalies, for example, the insolubility of asphaltenes in pentane and the near-complete
Table 9.2. Various Methods for Asphaltene Separation
Deasphalting
Volume,
ml/g
ASTM D-893
ASTM D-2006
n-pentane
rc-pentane
solubility of the materials in cyclopentane. Moreover, the solvent power of various
solvents is in agreement with the derivation of the solubility parameter; for any
one series of solvents, the relationship between amount of precipitate (or asphaltene solubility) and the solubility parameter, 8, is quite regular.
In any method used to isolate asphaltenes as a separate fraction, standardization
of the technique is essential. For many years, the method of asphaltene separation was not standardized, and even now it remains subject to the preferences
of the standards organizations of different countries. The use of both rc-pentane
and ^-heptane has been widely advocated, and, although n-heptane is becoming
the deasphalting liquid of choice, this is by no means a hard-and-fast rule. In addition, it must be recognized that large volumes of solvent may be required to
effect a reproducible separation, similar to amounts required for consistent asphaltene separation. It is also preferable that the solvents be of sufficiently low
boiling point that complete removal of the solvent from the fraction can be effected, and, most important, the solvent must not react with the feedstock. Hence,
the preference for hydrocarbon liquids, although the several standard methods that
have been used are not unanimous in the ratio of hydrocarbon liquid to feedstock
/t-Pentane and n -heptane are the solvents of choice in the laboratory (other
solvents can be used; Speight, 1979) and cause the separation of asphaltenes as
brown-to-black powdery materials. In the refinery, supercritical low-molecularweight hydrocarbons (e.g., liquid propane, liquid butane, or mixtures of both) are
the solvents of choice and the product is a semisolid (tacky) to solid asphalt. The
amount of asphalt that settles out of the paraffin-residuum mixture depends on the
size of the paraffin, the temperature, and the paraffin-to-feedstock ratio (Fig. 9.5)
(Girdler, 1965; Corbett and Petrossi, 1978; Speight et al, 1984).
Insofar as industrial solvents are very rarely one compound, it was also of
interest to note that the physical characteristics of two different solvent types, in
this case benzene and w-pentane, are additive on a mole-fraction basis (Mitchell and
Speight, 1973) and also explain the variation of solubility with temperature. The
Amount Precipitated, wt %
Number of Carbon Atoms in Solvent
n- Paraffins
2-Methyl Paraffins
Terminal Olefins
Cycloparaffins
Methylcycloparaffins
Figure 9.5. Variation of asphaltene yield with hydrocarbon liquid type.
data also show the effects of blending a solvent with the bitumen itself and allowing
the resulting solvent-heavy oil blend to control the degree of bitumen solubility.
Varying proportions of the hydrocarbon alter the physical characteristics of the
oil to such an extent that the amount of precipitate (asphaltenes) can be varied
accordingly within a certain range.
9.3.1.2. Influence of Degree of Dilution
One of the asphaltene separation methods (ASTM D-893) was developed for a
specific test to determine the amount of insoluble material in lubricating oil. Another (ASTM D-2007) was designed for use with rubber extending and processing
oils. Both tests recommend use of 10 ml of hydrocarbon liquid per gram of feedstock. This is not recommended in the tests that are now considered standard
forasphaltene separation (ASTM D-3279, ASTM D-4124) (Speight et al., 1984).
Asphaltene Yield, wt %
Volume of Precipitant/Volume of Feedstock
Feedstock:
Precipitant:
Athabasca Bitumen
Figure 9.6. Variation of asphaltene yield with hydrocarbon-to-feedstock ratio.
However, it must be recognized that some of these methods were developed for
use with feedstocks other than heavy oil and bitumen; therefore, adjustments are
At constant temperature, the quantity of precipitate first increases with increasing ratio of solvent to feedstock and then reaches a maximum (Fig. 9.6). Depending
on the feedstock, there is a solvent induction volume in which little or no asphaltenes
are precipitated. Very few data have been reported that relate to this aspect of asphaltene separation. The author has fragmentary evidence to show that the most
polar materials (not necessarily the highest-molecular-weight material) separate
first from the feedstock. This is in keeping with the increased paraffinicity of the
feedstock as the hydrocarbon is added.
9.3.1.3. Influence of Temperature
When pentane and the lower-molecular-weight hydrocarbon solvents are used in
large excess, the quantity of precipitate and the composition of the precipitate
changes with increasing temperature (Mitchell and Speight, 1973; Andersen,
One particular example is the separation of asphaltenes from using rc-pentane.
At ambient temperatures (~21C, 700F), the yield of asphaltenes is 17% w/w;
however, at 35C (95F), 22.5% by weight asphaltenes are produced using the
same feedstock-pentane ratio. This latter precipitate is in fact asphaltenes plus
resins; similar effects have been noted with other hydrocarbon solvents at temperatures up to 700C (1600F). These results are self-explanatory when it is realized that
the heat of vaporization AHy and the surface tension 7, from which the solubility
parameters are derived, both decrease with increasing temperature.
9.3.1.4. Influence of Contact Time
lnsolubles, wt %
Contact time between the hydrocarbon and the feedstock also plays an important
role in asphaltene separation (Fig. 9.7; Speight et al., 1984). Yields of the asphaltenes reach a maximum after approximately 8 h, which may be ascribed to
the time required for the asphaltene particles to agglomerate into particles of a
filterable size as well as the diffusion-controlled nature of the process. Heavier
feedstocks also need time for the hydrocarbon to penetrate their mass.
Time, h
Feedstock: Athabasca Bitumen
Precipitant: n-Pentane
Figure 9.7. Variation of asphaltene yield with hydrocarbon-feedstock contact time.
After removal of the asphaltene fraction, further fractionation of petroleum is also
possible by variation of the hydrocarbon solvent. For example, liquefied gases,
such as propane and butane, precipitate as much as 50% by weight of the residuum
or bitumen. The precipitate is a black, tacky, semisolid material, in contrast to
the pentane-precipitated asphaltenes, which are usually brown, amorphous solids.
Treatment of the propane precipitate with pentane then yields the insoluble brown,
amorphous asphaltenes and soluble, near-black, semisolid resins, which are, as near
as can be determined, equivalent to the resins isolated by adsorption techniques
There are also claims that solvent treatment at low temperatures (4 to 200C,
25 to 4F) brings about fractionation of the maltenes. The hydrocarbon solvents
pentane and hexane have been claimed adequate for this purpose but may not
be successful with maltenes from bitumen or from residua. The author has had
considerable success using acetone at 4 C (25F) for the fractionation of maltenes
from material other than cracked residua.
Other miscellaneous fractionation procedures for the deasphaltened oil involving the use of solvents are available (Speight, 1999). One method includes a procedure using polar solvents for separation into five fractions. These fractions are
1. hard resins, insoluble in 80:20 iso-butyl alcohol-cyclohexane mixture',
2. waxes, insoluble in a 1:2 mixture of acetone and methylene chloride at 00C
(-180F);
3. soft resins, insoluble in iso-butyl alcohol; and
4. an oil fraction, the balance of the sample that remains soluble in iso-butyl
The only drawback to this particular scheme appears to be the use of hexane
as the precipitating medium. Use of this solvent does not completely precipitate
the asphaltenes in a sample, and perhaps the fraction designated hard resins may
contain considerable portions of asphaltenes.
A fractionation procedure was also devised using /2-butanol and acetone as
the solvents, but the preliminary separation of the asphaltenes was incomplete.
The method consisted of (1) separation of an asphaltic fraction by rc-butanol and
(2) separation of the butanol-soluble portion into a paraffinic fraction and a cyclics
fraction by chilling an acetone solution of the two, but it has the unfortunate
result that all three fractions obtained may contain asphaltenes. It is difficult to
compare the method with any other or even establish any correlation with previous
experience. Even precipitation of the asphaltenes with n -pentane and subtraction of
the asphaltenes from the asphaltic fraction, arriving at a fourth fraction (asphaltic
resins), did not appear to correct the faults of the method, because the asphaltic
fraction does not contain all the asphaltenes of the specimen.
Another method of fractionating the deasphaltened oil consisted of stepwise
separation into the following fractions:
1. resins, precipitated with propane and subdivided by fractionation with aniline into soft resins and hard resins,
2. wax, precipitated with methyl iso-butyl ketone, and
3. oils, remaining fraction separated with acetone into paraffinic oils and naphthenic oils.
A strong feature of this method is the subdivision of the resins fraction by solubility
in aniline and the subdivision of the paraffinic fraction into the three components:
wax, paraffinic oils, and naphthenic oils.
It is unfortunate that, with the exception of asphaltene precipitation, no standard
method exists for the fractionation of crude oil, residua, and bitumen, by solvent
treatment. The procedures described here each have their own individual merits,
but there has not been any serious effort to apply these methods to a wide variety of
carbonaceous liquids to assess their general applicability. Fractionation by means
of solvents alone (perhaps with the exception of propane, which requires pressure
equipment) would be convenient indeed, provided that facile separation of the
solvent and the products could be achieved at a later stage.
Another all-solvent procedure involves the use of acetone, which discharges
a resin fraction, and dimethylformamide, which then discharges the saturates
fraction.
The use of all-solvent methods for the separation of petroleum allows the fractionation of feedstocks to be achieved without loss of material (on the adsorbent)
and produces fractions of varying polarity. The obvious benefit of the all-solvent
techniques is the complete recovery of material, thereby allowing a more quantitative and qualitative examination of the feedstocks.
The disadvantages of an all-solvent separation technique are that, first, low
temperatures (e.g., 0 to 100C and the like) are advocated as a means of effecting
oil fractionation with solvents (Rostler, 1965; Speight, 1979). Such requirements
may cause inconvenience in a typical laboratory operation by requiring a permanently cool temperature during the separation. Second, it must be recognized that
large volumes of solvent may be required to effect a reproducible separation in the
same manner as the amounts required for consistent asphaltene separation (ASTM
D-2006, ASTM D-2007, ASTM D-4124, ASTM D-893; IP 143). Finally, it is
also essential that the solvent be of sufficiently low boiling point so that complete
removal of the solvent from the product fraction can be effected. Although not
specifically included in the three main disadvantages of the all-solvent approach,
it should also be recognized that the solvent must not react with the feedstock constituents. In addition, caution is still required to ensure that there is no interaction
between the solvent and the solute.
The analysis of petroleum for the elemental composition or a convenient but meaningful physical property (Chapter 4) is generally considered to be the first step in
characterization. The next step is to separate petroleum into its constituent compound groups and compound classes. Thus separation procedure are an analytical
tool in themselves in that they yield information about feedstock composition in
terms of its main compound groups and compound classes. The concentration of
saturates, aromatics, and polar species (resins and asphaltenes) in a feedstock may
be all the information required. Beyond that point, each of the four fractions may
be further divided, for example, the aromatics by aromatic ring number into the
compound classes of mono-, di-, tri-, tetra-, and penta-aromatics.
An important aspect of the application of separation procedures is the fact
that the separation of a petroleum fraction into compound classes assists subsequent measurements performed for molecular characterization. Some molecular
characterization procedures (Chapter 11) cannot be effectively applied to broad
fractions, and further separation into subfractions is necessary. For example, a
molecular ion peak can represent several compound types or even various compound classes rather than just one compound type, which makes its assignment
difficult or impossible. Only mass peaks from well-defined fractions can be assigned unequivocally.
Careful separation provides such well-defined fractions for good mass spectra
and the additional analytical information necessary for their interpretation. Chromatographic separation into well-defined compound-class fractions also facilitates
the interpretation of other spectra, for example, from nuclear magnetic resonance
and infrared spectroscopy (Chapter 7).
Another advantage of good separations is the mitigation of peak crowding.
Crowded mass spectra are hard to read for two reasons: (1) because of peak overlap
resulting from several different compound type molecules with similar masses and
(2) because of dilution, which prevents some compounds from being seen and distinguished from the background noise. The dilution by other components in broad
fractions is especially severe for molecules of high molecular weight. Although the
latter may have reasonable concentrations in terms of weight percent, their mole
percent, which determines the peak height in mass spectra, may be prohibitively
low. Both advantages of good separations, the gain of complementary information
and the avoidance of the dilution effect, are not restricted to mass spectrometry
but are important when other molecular identification techniques are applied.
As already stated (Chapter 2), petroleum is a complex mixture of paraffin,
naphthene, and aromatic hydrocarbons as well as nitrogen-, oxygen-, and sulfurcontaining compounds, and traces of a variety of metal-containing compounds
and the amounts of nonhydrocarbon compounds increase with molecular weight.
The distribution of the constituents of petroleum varies with the petroleum but
can generally be represented as consisting of the various hydrocarbon species with
varying amounts of heteroatom species (Fig. 9.3).
By definition, the saturate fraction consists of paraffins and cycloparaffins
(naphthenes). The single-ring naphthenes, or cycloparaffins, present in petroleum
are primarily alkyl-substituted cyclopentane and cyclohexane. The alkyl groups
are usually quite short, with methyl, ethyl, and isopropyl groups the predominant
substituents. As the molecular weight of the naphthenes increases, the naphthene
fraction contains more condensed rings, with six-membered rings predominating.
However, five-membered rings are still present in the complex, higher-molecularweight molecules.
The aromatic fraction consists of those compounds containing an aromatic ring
and vary from mono-aromatics (containing one benzene ring in a molecule) to diaromatics (substituted naphthalene) to tri-aromatics (substituted phenanthrene).
Higher condensed ring systems (tetra-aromatics, penta-aromatics) are also known
but are somewhat less prevalent than the lower ring systems, and each aromatic
type will have increasing amounts of condensed ring naphthene attached to the
aromatic ring as molecular weight is increased.
However, depending on the adsorbent employed for the separation, a compound
having an aromatic ring (i.e., 6 aromatic carbon atoms) carrying side chains consisting in toto of more than six carbon atoms (i.e., more than 6 nonaromatic carbon
atoms) will appear in the aromatic fraction.
The typical nitrogen compounds found in petroleum are generally divided into
two groups, basic and nonbasic (Chapter 2), each of which has alkyl chains and
other ring systems. The basic nitrogen compounds cause difficulty with the many
acid-catalyzed processes used in petroleum refining. For example, in catalytic
cracking, the basic nitrogen adsorbs on the catalytic acid sites and reduces the
cracking activity of the catalyst. Furthermore, in reactions catalyzed by liquid
acids, the presence of basic nitrogen compounds in the feed increases acid consumption and thus the cost of the process. Typical of such processes are alkylation,
isomerization, and olefin absorption.
Another type of nitrogen compound is theporphyrins (Chapter 2), which consist
of four pyrrole rings connected together with methylene bridges at the carbons
next to the nitrogen atoms. They are normally found in trace quantities in the
high-molecular-weight fractions of petroleum as metal complexes.
The oxygen compounds found in petroleum fractions are often products of exposure to air. However, some naturally occurring oxygenated compounds do exist
in petroleum; these are typically phenols, naphthenic acids, and esters (Chapter 2).
They increase in quantity and complexity as molecular weight increases, just as
sulfur and nitrogen compounds do.
A variety of sulfur compounds occur in petroleum (Chapter 2) and include
mercaptans (-SH), sulfides ( - S - ) , and disulfides (SS). They are much less
thermally stable than the thiophene derivatives and often lose hydrogen sulfide on
heating. They can also react thermally to form more stable sulfur compounds. In
the chromatographic separation, these sulfur compounds are found in the polar
aromatic fraction, even though they may not all be aromatic. Thiophenes tend to
exhibit aromatic behavior and are collected with the aromatics when adsorption
separation is used on petroleum fractions.
Separation by adsorption chromatography essentially commences with the
preparation of a porous bed of a finely divided solid, the adsorbent. The adsorbent is usually contained in an open tube (column chromatography); the sample
is introduced at one end of the adsorbent bed and induced to flow through the
bed by means of a suitable solvent. As the sample moves through the bed, the
various components are held (adsorbed) to a greater or lesser extent depending on
the chemical nature of the component. Thus those molecules that are strongly adsorbed spend considerable time on the adsorbent surface rather than in the moving
(solvent) phase, but components that are slightly adsorbed move through the bed
comparatively rapidly.
Numerous factors randomly affect the process of migration through a bed; in
fact, the total distance traveled in a given time by different molecules of the same
material is not constant. Nevertheless, the suitable choice of a bed and a moving
(solvent) phase allows adequate separation of even multicomponent mixtures to
be achieved.
The fractionation of petroleum components by adsorption on such materials
as fuller's earth, animal charcoal, and various types of clay dates back to the
beginning of the twentieth century. These materials effect an arbitrary separation
of the material into a number of fractions that have variously been described as oil,
resins, hard resins, and soft resins, to mention only the more commonly used terms.
It is regarded as essential that, before application of the adsorption technique to
the petroleum, the asphaltenes first be completely removed, for example, by any of
the methods outlined in the previous section. The prior removal of the asphaltenes
is essential insofar as they are usually difficult to remove from the earth or clay
and may actually be irreversibly adsorbed on the adsorbent.
Nevertheless, careful monitoring of the experimental procedures and the nature
of the adsorbent have been responsible for the successes achieved with this particular technique. Early procedures consisted of warming solutions of the petroleum
fraction with the adsorbent and subsequent filtration. This procedure has continued
to the present day, and separation by adsorption is used commercially in plant operations in the form of clay treatment of crude oil fractions and products (Speight,
In the laboratory, very little use is made of the technique of warming a solution
of the sample with the adsorbent. Rather, a chromatographic technique is employed
in which the sample is washed through a column of the adsorbent using various
Numerous methods have been employed for the separation of petroleum fractions into the main compound groups such as saturates, aromatics, and polar species
(Altgelt and Gouw, 1979; Altgelt and Boduszynski, 1994; Speight, 1999). However, it is generally recognized that the asphaltenes are first removed by the addition
of a low-boiling liquid hydrocarbon (page 236) after which it is the deasphaltened
oil that is separated by adsorption techniques.
However, if the adsorption technique is performed using only one column (e.g.,
a silica column or an alumina column), separation is poor. There is frequent overlap
of the various fractions. The saturate fraction may be contaminated with substantial
amounts of the constituents of the aromatics, the aromatic fraction may be contaminated with constituents from the polar (resin) fraction, and the polar fraction
may be contaminated with constituents of the aromatic fraction.
Thus procedures have evolved in which, after removal of the asphaltenes, the
polar (resin) fraction is removed from the deasphaltened oil first by use of a lowpolarity adsorbent. This assists subsequent separations of the remaining neutral oil
fraction (the combined aromatic and saturate fractions) using other adsorbents or
clean columns by preventing the columns used in the latter process from being deactivated and destroyed by irreversible adsorption of the (polar) resin constituents.
The neutral oil fraction can then more easily and cleanly be separated into saturates,
aromatics, and (if necessary) into neutral heterocompounds.
ASTM Methods
There are three standard (ASTM) methods that provide for the separation of a
feedstock into four or five constituent fractions (see Figs. 9.8, 9.9, 9.10, 9.11, and
9.12). It is interesting to note that, as the methods have evolved, there has been a
change from the use of pentane (ASTM D-2006 and D-2007) to heptane (ASTM
D-4124) to separate asphaltenes. This is, in fact, in keeping with the production of
a more consistent fraction that represents the higher-molecular-weight, more complex constituents of petroleum (Girdler, 1965; Speight et al., 1984; Speight, 1999).
Two of the methods (ASTM D-2007 and D-4124) use adsorbents to fractionate
the deasphaltened oil, but the third method (ASTM D-2006) advocates the use
of various grades of sulfuric acid to separate the material into compound types.
Caution is advised in the application of this method because the method does not
work well with all feedstocks. For example, when the sulfuric acid method (ASTM
D-2006) is applied to the separation of heavy feedstocks, complex emulsions can
be produced.
(Anion resin)
De-acid oil
(Cation resin)
Hydrocarbon oil
(Silica-alumina)
Polyaromatics
Diaromatics
Neutral Nitrogen compounds
Monoaromatics
Figure 9.8. The USBM-API fractionation procedure.
Obviously, there are precautions that must be taken when attempting to separate
heavy feedstocks or polar feedstocks into constituent fractions. The disadvantages
in using ill-defined adsorbents are that adsorbent performance differs with the same
feed and, in certain instances, may even cause chemical and physical modification
of the feed constituents. The use of a chemical reactant like sulfuric acid should
only be advocated with caution because feeds react differently and may even cause
irreversible chemical changes and/or emulsion formation. These disadvantages
may be of little consequence when it is not, for various reasons, the intention to
recover the various product fractions in toto or in the original state, but, in terms
of the compositional evaluation of different feedstocks, the disadvantages are very
real.
In summary, the terminology used for the identification of the various methods might differ. However, in general terms, group-type analysis of petroleum is
(Solubles: percolate through silica or alumina)
(Benzene/methanol or pyridine)
(Benzene or toluene)
Figure 9.9. A simplified alternate procedure to the USBM-API fractionation method.
(n-Pentane)
(85% sulfuric acid)
Polar compounds
Residual oil
1 st Acidaffins
(30% oleum)
2nd Acidaffins
Figure 9.10. The ASTM D-2006 fractionation procedure.
often identified by the acronyms for the names: PONA (paraffins, olefins, naphthenes, and aromatics), PIONA (paraffins, /s6>-paraffins, olefins, naphthenes, and
aromatics), PNA (paraffins, naphthenes, and aromatics), PINA (paraffins, isoparaffins, naphthenes, and aromatics), or SARA (saturates, aromatics, resins, and
asphaltenes). However, it must be recognized that the fractions produced by the
use of different adsorbents will differ in content and will also be different from
fractions produced by solvent separation techniques.
(Percolate through clay)
(Polar solvent wash)
1: Oils
(n-Pentane wash then percolate
through silica gel)
(Benzene)
2: Polar aromatics (resins)
2: Naphthene-aromatics
(Aromatics)
The variety of fractions isolated by these methods and the potential for the
differences in composition of the fractions make it even more essential that the
method is described accurately and that it is reproducible not only in any one
laboratory but also among various laboratories.
Early investigations involved filtration of crude oils through a column of fuller's
earth, and it was observed that the gasoline components appeared in the initial part
of the filtrate. Subsequent investigations showed that, if light oil is drawn upward
by a pump through a column of earth, the light aliphatic hydrocarbons accumulate
in the top section. The aromatic constituents do not rise as high and the nitrogenand sulfur-containing compounds are largely retained on the adsorbent.
A later chromatographic method involved separation into four principal fractions, asphaltenes, asphaltic resins, dark oils, and water white oils, and a fifth fraction constituting the balance of the specimen. The method consists of precipitation
of asphaltenes with 40 volumes of rc-pentane and elution of the rc-pentane-soluble
fraction from a chromatographic column of fuller's earth. The elution technique
gave a series of fractions
water white oils eluted with rc-pentane,
dark oils eluted with methylene chloride,
resins with methyl ethyl ketone, and
hard resins that were desorbed with an acetone-chloroform mixture.
The proportions of each fraction are subject to the ratio of fuller's earth to
n-pentane-soluble materials. For example, a change in the ratio from 10:1 to 25:1
causes a decrease in the percentage of water white oils by a factor of 3:2, and the
percentage of dark oils and asphaltic resins increases by about the same factor.
The method, like all chromatographic procedures proposed for the fractionation
of crude oils, is dominated by equilibrium conditions and does not give fractions
that are different components but only blends of the same components in different
proportions. Nevertheless, this method, despite this serious shortcoming, remains
one of the best chromatographic methods proposed and has been used extensively
as such or with some slight modification, for example, the subdivision of maltenes
from crude oils into oils (pentane eluate, i.e., saturates fraction plus aromatics
fractions) and resins (pyridine eluate).
Other methods of fractionation by the use of adsorbents include separation of
the maltene fraction by elution with n -heptane from silica gel into two fractions
named aromatics and nonaromatics, which is, in fact, a separation into the two
broad groups called resins and oils in other methods. The silica gel method may also
be modified to produce three fractions: (1) nonaromatics eluted with n-heptane,
(2) aromatics eluted with benzene, and (3) compounds that contain oxygen as well
as sulfur and nitrogen, eluted with pyridine. Prior separation of the asphaltenes
renders the procedure especially suitable and convenient for use with heavy oil and
bitumen. Other modifications include successive elution with w-pentane, benzene,
carbon tetrachloride, and ethanol.
Alumina has also been used as an adsorbent and involves (1) precipitation of
asphaltenes with normal pentane, (2) elution of oils from alumina with pentane,
and (3) elution of resins from alumina with a methanol-benzene mixture. In fact,
the choice of the adsorbent appears to be arbitrary, as does the choice of the various
solvents or solvent blend. The use of ill-defined adsorbents, such as earths or clays
is a disadvantage in that certain components of the petroleum may undergo changes
(for example, polymerization) caused by the catalytic nature of the adsorbent and
can no longer be extracted quantitatively. Furthermore, extraction of the adsorbed
components may require the use of solvents of comparatively high solvent power,
such as chloroform or pyridine, which may be difficult to remove from the product
It is also advisable, once a procedure using an earth or clay has been established,
that the same type of adsorbent be employed for future fractionation, because the
ratio of the product fractions varies from adsorbent to adsorbent. It is also very
necessary that the procedure be used with caution and that not only is the method
be reproducible but quantitative recoveries are guaranteed; reproducibility with
only, say, 85% of the material recoverable is not a criterion of success.
There are two procedures that have received considerable attention over the
years and these are (1) the United States Bureau of Mines-American Petroleum
Institute (USBM-API) method and (2) the saturate-aromatic-resin-asphaltene
(S ARA) method. This latter method is often also called the saturate-aromatic-polarasphaltene (SAPA) method. These two methods represent the standard methods
of petroleum fractionation. Other methods are also noted, especially when the
method has added further meaningful knowledge to compositional studies.
The USBM-API method (Fig. 9.8) employs ion-exchange chromatography and
coordination chromatography with adsorption chromatography to separate heavy
oils and residua into seven broad fractions: acids, bases, neutral nitrogen compounds, saturates, and mono-, di-, and polyaromatic compounds. The acid and
base fractions are isolated by ion-exchange chromatography, the neutral nitrogen
compounds by complexation chromatography using ferric chloride, and the saturates and aromatics by adsorption chromatography on activated alumina (Jewell
et al., 1972a, Altgelt et al., 1979) or on a combined alumina-silica column (Hirsch
et al., 1972; Jewell et al., 1972b).
The feedstock sample can be separated into chemically significant fractions
that are suitable for analysis according to compound type (Jewell et al., 1972b;
McKay et al., 1975). Although originally conceived for the separation of distillates,
this method has been successfully applied to determination of the composition of
heavy oil and bitumen (Cummins et al., 1975; McKay et al., 1976; Bunger, 1977).
Originally, the method required distillation of a feedstock into narrow boiling-point
fractions, but whole feedstocks, such as the bitumen from Utah or Athabasca tar
sands (Selucky et al., 1977), have been separated into classes of compounds without
previous distillation or removal of asphaltenes. The latter finding is supported by
the separation of asphaltenes using ion-exchange materials (McKay et al., 1977;
Francisco and Speight, 1984).
The SARA method (Jewell et al., 1974) is essentially an extension of the API
method that allows more rapid separations by placing the two ion-exchange resins
and the FeCl3 -clay-anion-exchange resin packing into a single column. The adsorption chromatography of the nonpolar part of the same is still performed in a
separation operation. Because the asphaltene content of petroleum (and synthetic
fuel) feedstocks is often an important aspect of processability, an important feature
of the SARA method is that the asphaltenes are separated as a group. Perhaps more
important is that the method is reproducible and applicable to a large variety of
the most difficult feedstocks, such as residue tar sand bitumen, shale oil, and coal
Both the USBM-API and SARA methods require some caution if the asphaltenes are first isolated as a separate fraction. For example, the asphaltene
yield varies with the hydrocarbon used for the separation and with other
factors (Girdler, 1965; Mitchell and Speight, 1973; Speight et al., 1984). An inconsistent separation technique can give rise to problems resulting from residual
asphaltenes in the deasphaltened oil undergoing irreversible adsorption on the solid
adsorbent.
The USBM-API and SARA methods are widely used separation schemes for
studying the composition of heavy petroleum fractions and other fossil fuels, but
several other schemes have also been used successfully and have found common
usage in investigations of feedstock composition. For example, a simple alternative (Fig. 9.9) to the SARA sequence is the chromatographic preseparation of a
deasphaltened sample on deactivated silica or alumina with pentane (or hexane)
into saturated materials followed by elution with benzene for aromatic materials
and with benzene-methanol for polar materials (resins). This allows further chromatography into narrower (more similar) fractions without mutual interference on
the adsorbent.
The selection of any separation procedure depends primarily on the information desired about the feedstock. For example, separation into multiple fractions
to examine the minute details of feedstock composition requires a complex sequence of steps. An example of such a separation scheme (Fig. 9.10) involves
the fractionation of Athabasca tar sand bitumen into four gross fractions and
subfractionation of these four fractions (Boyd and Montgomery, 1963). This allowed the investigators to study the distribution of the functional types within the
Other investigators (Oudin, 1970) have reported that a combination chromatography using alumina and silica gel is suitable for deasphaltened oils. A more complex scheme, also involving the use of silica, resulted in the successful separation
of hexane-deasphalted crude oil. There is also a report (Al-Kashab and Neumann,
1976) of the direct fractionation of hydrocarbon and heterocompounds from deasphaltened residua on a dual alumina-silica column with subsequent treatment of
the polar fraction with cation- and anion-exchange resins into basic, acid, and neutral materials. The method also includes chromatography of the asphaltenes, but
only with highly polar asphaltene samples are the basic and acid compounds first
removed with ion-exchange resins. The remainder of the feedstock is separated
into saturates, aromatics, and heterocompounds using alumina-silica adsorption.
Separation of the saturates into w-alkanes and iso-alkanes plus cycloalkanes is
achieved by the use of urea (H2N.C=O.NH2) and thiourea (H2N.C=S.NH2).
One of the problems of such a fractionation scheme is the initial separation of
the feedstocks into two ill-defined fractions (colloids and dispersant) without first
removing the asphaltenes. As already noted, asphaltenes are specifically defined
by the method of separation. They are less well defined using such liquids as ethyl
acetate in place of the more often used hydrocarbons, such as pentane and heptane
(Speight, 1979). The use of ethyl acetate undoubtedly leads to asphaltene material
in the dispersoids and nonasphaltene material in the colloids. Application of a
more standard deasphalting technique would undoubtedly improve this method
and provide an excellent insight into feedstock composition.
One of the common problems of any adsorption-based fractionation scheme is
the nature of the adsorbent. In the early reports of petroleum fractionation (Pfeiffer,
1950), clays often appeared as an adsorbent to effect the separation of the feedstock
into various constituent fractions. However, clay (fuller's earth, attapulgus clay,
and the like) is often difficult to define with any degree of precision from one batch
to another. Variations in the nature and properties of the clay can, and will, cause
differences not only in the yields of composite fractions but also in the distribution
of the compound types in those fractions. In addition, irreversible adsorption of
the more polar constituent to the clay can be a serious problem when further
investigations of the constituent fractions are planned.
One option for resolving this problem has been the use of more standard adsorbents, such as alumina and silica. These materials are easier to define and are often
accompanied by guarantees of composition and type by various manufacturers.
They also tend to irreversibly adsorb less of the feedstock than a clay. Once the
nature of the adsorbent is guaranteed, reproducibility becomes a reality. Without
reproducibility, the analytic method does not have credibility.
Methods of fractionation using chemical reactants are entirely different in nature
from the methods described in the preceding sections. The basic concept of this
type of separation is the step-wise production of a variety of fractions by treatment
of the petroleum with the chemical reactant until fractionation is complete.
The most common methods that have been used for the separation procedure,
other than the use of ferric chloride on a adsorbent (page 252), involve the use
of sulfuric acid and urea adduction. Although, to be truthful, the urea adduction
method is in reality a physical method, because it provides a separation that is specific to certain constituents of petroleum, it is included here. Many other methods
that have been used for the chemical separation of petroleum are now included
as refinery processes (Kalichevsky and Stagner, 1942; Gruse and Stevens, 1960;
Speight, 1999). These acid treatments (particularly the sulfuric acid method) and
the urea addition method are still widely used in the laboratory, and therefore they
are included here.
Acid Treatment
The method of chemical separation that is commonly applied is treatment with
sulfuric acid. Marcusson and Eickmann made an early reference to the use of
sulfuric acid in 1908 and first precipitated the asphaltenes from asphaltic materials
by treatment of the sample with low-boiling naphtha, followed by fractionation of
the naphtha-soluble material with concentrated sulfuric acid (Fig. 9.13).
The precipitate produced by the sulfuric acid treatment was actually material
that had been converted to an asphaltene type of product by interaction of the
(Naphtha)
Maltenes (deasphaltened oil)
(Treat with concentrated
sulfuric acid)
(Precipitate)
(Immiscible)
Figure 9.13. The Marcusson-Eickmann fractionation procedure.
asphaltic constituents with the sulfuric acid. It is nevertheless possible that some
of the acid-precipitated material originated as asphaltenes that were incompletely
precipitated by the naphtha. The constitution of the naphtha was unknown; most
likely it was not pure n-pentane and it may even have contained hexane(s) or higher
paraffins. The addition of only 20 volumes of solvent to heavy feedstocks is not a
sufficient amount to completely precipitate asphaltene material.
However, the method has served as a demonstration of the type of separation
that can be obtained by means of sulfuric acid. A later refinement of this principle
led to the development of a technique that proposes a resolution of crude oils,
crude oil residua, and asphaltic or bituminous materials into five broad fractions
(ASTM D-2006) (Fig. 9.14). These fractions are distinctly different in chemical
reactivity as measured by response of the fractions to cold sulfuric acid of increasing strength (sulfur trioxide concentration). The fractionation involves, like most
other methods, initial separation of the sample into asphaltenes and the fraction
referred to as maltenes. The fractionation of maltenes into resins and oils is often
too vague for identification purposes, and the nature, or composition, of these two
fractions may differ from one oil to another.
The chemical precipitation method is claimed to provide the needed subdivision
of the resins and the oils to yield chemically related fractions. The names given
to the individual fractions are descriptive of the steps used in the procedure. For
example, the name paraffins is used for the saturated nonreactive fraction, whereas
the next two groups in ascending reactivity are second acidaffins and first acidajfins.
The term second acidajfins denotes the group of hydrocarbons having affinity for
strong acid, as represented by fuming sulfuric acid. The term first acidaffins denotes
that the constituents have an affinity for ordinary concentrated sulfuric acid. The
next fraction, nitrogen bases, separated by sulfuric acid of 85% concentration,
includes the most reactive components and may contain, among other components,
substantially all the nitrogen-containing compounds.
(treat with 85% sulfuric acid)
Nitrogen bases
(Immiscible; treat with
98% sulfuric acid)
1 st Acidaff ins
(Immiscible; treat with oleum)
Figure 9.14. The Rostler-Sternberg fractionation procedure.
The fractionation accomplished by the sulfuric acid method is presumed to be
the subdivision of crude oils or asphaltic materials into five groups of components
by virtue of their chemical makeup. The method was accepted by the American
Society for Testing and Materials as a standard method of test for Characteristic
Groups in Rubber Extender and Processing Oils by the Precipitation Method
(ASTM D-2006). However, there is still some doubt regarding the applicability of
the method to a wide variety of petroleum, petroleum residua, and other bituminous
materials (Speight, 1999), because the potential for stable emulsion formation (by
sulfonation of the constituents), hence leading to difficulties in the separation
procedure, is high.
There is also a relatively simple precipitation of the basic constituents of petroleum (as their hydrochlorides) by passage of dry hydrogen chloride gas through a
solution of the material in a solvent such as carbon disulflde. It therefore appears
that a number of refinements of the sulfuric acid method are desirable because it is
apparent that not all carbonaceous liquids react in the same manner with sulfuric
acid.
Molecular Complex Formation
The formation of crystalline molecular complexes between urea (H2N.C=O.NH2)
or thiourea (H2N.C=S.NH2) and hydrocarbons has been known since the 1940s,
and it is not surprising that the technique has received considerable attention with
respect to its use in petroleum chemistry.
Distillation and adsorption methods of separation differentiate molecules by
class and volatility (or size within any one homologous series), respectively,
whereas adduct formation separates on the basis of molecular shape and, to a lesser
extent, by size and class. When combined with the older fractionation methods,
adduct formation can often be useful for solving separation problems, provided the
limitations of the method are realized. Urea and thiourea adduction are not completely selective, as was first supposed, and there is an overlapping of structural
types that adduct, especially among the higher-molecular-weight hydrocarbons.
Adduct formation may be achieved merely by bringing together the adduct
former and the reagent under a wide range of reaction conditions. Preferably,
the reactant is an inert hydrocarbon solvent, a reagent solvent, referred to as the
activator, present in varying amounts to increase the rate of reaction, and the
crystalline product that precipitates can be conveniently separated by filtration.
Furthermore, the adducts may be decomposed easily, and the adducting material
can be recovered by one of several procedures.
It is generally accepted that, in the urea adducts, the urea molecules are connected into spirals by hydrogen bonds between the oxygen and the amino groups
of adjacent urea molecules, resulting in a channel into which the adducting compound can fit. The size of the channel limits the molecules that may adduct to
those having cross-sectional dimensions equal to, or less than, those of the channel in the urea adduct; however, in certain cases, distortion of the urea lattice
may occur and slightly larger molecules can adduct. The structure of the thiourea
adducts is similar to that of the urea adducts. The larger size of the sulfur atom
results in a channel of somewhat larger cross-sectional dimensions, hence allowing
larger molecules to adduct with thiourea than are able to adduct with urea. In general, urea forms adducts with organic compounds containing a long, unbranched
chain, such as the n-paraffins, whereas thiourea forms complexes with compounds
that contain a moderate amount of branching of cyclization. However, especially
among the higher-molecular-weight hydrocarbons, urea adducts can be formed
from n -paraffins.
The relationship among structure, adductibility, and adduct stability is not as
well defined for the thiourea-adductible compounds as for the urea-reactive hydrocarbons. The stability of any thiourea adduct is quite low, even at 00C, and
corresponds approximately to the stability of the urea completes of the lower
n-paraffins. The high stability of the urea completes of the higher n-paraffins has
no parallel in thiourea completes. Among the higher hydrocarbons containing
a ring or branching and a long chain, there is a lesser tendency for the thiourea
adducts to form than in the lower-molecular-weight homologues, as the alkyl chain
apparently reduces the stability. The higher n -paraffins adduct fairly readily and
become more stable with increasing molecular weight, but the stability of these
adducts is still of the same low order of magnitude as the lower-molecular-weight
/soparaffins and naphthenes.
Analysis of the complexes for their mole ratio of reagent to reactant may be
made by several methods. The urea (or thiourea) content of the crystalline complex
may be established by nitrogen determination (Chapter 4), or the amount of organic
component may be determined from carbon content (Chapter 4) or by the weight
loss on dissociation of the adduct. Also, measurement of concentration changes in
the reaction liquid is applicable to certain mixtures.
For urea adducts of normal hydrocarbons, the mole ratio of urea to hydrocarbon
in the adduct can be represented by the equation
m =0.65n + 1.5
where m is the mole ratio of urea to hydrocarbon and n is the number of carbon
atoms in the hydrocarbon. For all practical purposes, the use of the ratio of 3.3 g of
urea per gram of normal hydrocarbon is more convenient. The greater variety of
hydrocarbon structures adducting with thiourea than with urea adversely affects
development of an equation relating the mole ratio of thiourea to reactant. For a
given number of carbon atoms, the more compact molecules are generally associated with less thiourea in the adduct than are the less compact molecules. The
weight ratio decreases from 2.7 to 2.8 for aliphatic compounds and monocyclic
naphthenes to 2.5 for dicyclic naphthenes and to 2.2-2.3 for condensed ring systems; the weight ratio (or unsaturated compounds) is generally very similar to that
of the corresponding saturated structure.
The most practical method of decomposition of the adducts is by solution, generally with hot water. The adducted hydrocarbons form an immiscible layer on
top of the aqueous urea solution and may be readily separated. Volatile reactants
may be recovered by heating the adduct, either dry or with steam, and collecting
the liberated hydrocarbon as it is released. Actually, a crude fractional dissociation may be accomplished in this manner or by partial solvent extraction. The
least stable adduct formers are released first and may be collected. Separations of
compounds from mixtures are carried out, in effect, on the basis of their stability.
The most desirable results are generally obtained if all the possible material is first
precipitated as the adduct; the recovered adducted material is then fractionally
readducted.
In a narrow molecular weight distillation fraction containing several adductible
hydrocarbon types, separation can be accomplished as a result of the difference
in stability of the adducts of the different hydrocarbon homologous series. With
urea, the n -paraffins react first, followed by the slightly branched /so-paraffins and
by the more highly branched /stf-paraffins and last by the cyclic structures. However, working with a wide molecular weight fraction, such as petroleum waxes, the
stability of the urea adducts of lower n -paraffins present is of the same order of magnitude as that of the adducts of higher zso-paraffins and monocyclic compounds;
a mixture of types is of different molecular weights. Hence, fractional distillation
of the hydrocarbon samples either before or after adduction allows better analysis
of the various fractions.
Fractionation may also be effected by selective decomposition of the adduct
or by selective replacement. In the former method, the adduct is extracted using
a solvent of relatively poor dissociating power, whereby the least stable adducts
tend to dissociate first, In selective replacement, the hydrocarbons of the less stable
adducts are gradually displaced by slightly more stable adductors, and these in turn
are displaced by more stable adduct formers until the most stable n -paraffins are
employed.
The relative instabilities of the thiourea adducts renders the method less useful
than the urea method. In addition, the less selective nature of thiourea adduction
and the fact that large differences in stability exist within a homologous series with
the urea adducts do not apply to the thiourea adducts.
Finally, the urea adduction method is not particularly amenable to tar sand
bitumen because of a general lack of hydrocarbon constituents in the bitumen.
The most amenable feedstock is conventional (paraffinic) petroleum, and there
may be heavy oils that respond to the procedure.
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CHROMATOGRAPHIC ANALYSIS
The history of the use of chromatography goes back to the sixteenth century (1512)
when Brunschwig, a Strasbourg surgeon, purified ethanol by a chromatographic
technique. Day, an American geochemist, separated crude oils on fuller's earth
(1898-1903). The major work was a systematic study carried out by Michael
Tswett, a Russian botanist that is recognized as the beginning of chromatography
(Meloan, 1999).
Historically, the work carried out was what we now refer to as column chromatography, often also referred to as adsorption chromatography (page 273).
Many variations have been developed since the original discovery. The more
common chromatographic procedures are gas chromatography, adsorption chromatography, gel permeation chromatography, ion-exchange chromatography, and
high-performance chromatography, which are discussed in more detail here. Paper
chromatography is used less frequently for petroleum analysis but are also included
in this work (Section 10.9).
With the startling demands on the petroleum industry during and after World
War II and the emergence of the age of petrochemicals and plastics, the industry
needed to produce materials not even considered as products in the decade before
the war. Thus the petroleum refiner took on the role of technological innovator
as new and better processes were invented and advances in the use of materials
for reactors were developed. In addition, it became necessary to find out more
about petroleum so that refiner might be able to enjoy the luxury of predictability
and plan a product slate that was based on market demanda difficult task when
the character of the crude oil was unknown! The idea that petroleum refining
should be a hit and miss affair was not acceptable. The demand arose for a more
detailed inspection of the character of petroleum. Petroleum varies markedly in
properties and composition according to the source, and variations in feedstock
character caused changes for optimization of existing processes as well as for the
development and design of new processes.
(TBP) curve, which is a function of percent weight distilled and temperature,
that is, a boiling point distribution (Chapter 5). However, there are boiling point
limitations on this function that are well below the final boiling point (FBP) of
a crude oil. In addition to the boiling point distribution, bulk physical properties
such as specific gravity and viscosity have assisted in the establishment of certain
empirical relationships for petroleum processing from the TBP curve. Many of
of feedstocks. However, the movement of refining to feedstocks that contain higher
proportions of coke-forming materials emphasizes the need for more definitive data
that would enable more realistic predictions to be made of crude oil behavior in
refinery operations.
However, regardless of the type of chromatography used for separation and
identification of petroleum constituents, the mechanisms involved in the separation
are basically the same. The two major mechanisms at work during a chromatographic separation are displacement and partition. Few instances involve only one
mechanism, but certain types of separations emphasize one mechanism over the
Chromatographic procedures are often referred to as displacement procedures.
In the simplest procedure (which relates more to the historical work), a glass
column is packed tightly with powder-size dry particles, the inert phase. A thin
layer of a sample mixture consisting of weakly adsorbed compounds and strongly
adsorbed compounds is added to the top of the inert phase. A liquid, which is more
strongly adsorbed to the inert phase than any of the compounds in the sample, is
now poured into the top of the column. This is called the mobile phase and serves
to wash the sample down the column, a process called elution.
The inert particles, are mainly silicates and aluminates, contain active sites due
to charge distribution, and molecules of the solute attach themselves to the particles
based on their relative adsorption tendencies derived from size or polarity and pass
down the column as far as necessary until all of the molecules are adsorbed. An
equilibrium is established with the strongly adsorbed molecules remaining on
the column and the weekly-adsorbed molecules passing out at the bottom of the
The analysis of the constituents in petroleum started over 100 years ago, when in
1865 several aromatic hydrocarbons were identified as constituents of petroleum.
Identification of individual constituents of petroleum continued, and the rapid advances in analytic techniques have allowed the identification of large numbers of
petroleum constituents. At this time, the major chemical types of compounds that
exist in crude oil have been identified and many members of the various homologous series have been separated or conclusively identified by various techniques
(see Rossini et al., 1953 for historical details).
It is the purpose of this chapter to review the methods that can be used for the
identification of the constituents of petroleum. Particular emphasis has been placed
on the chromatographic techniques that have offered valuable information in the
past (Altgelt and Gouw, 1975) and will continue in the future to offer valuable
information about the constituents of petroleum. Spectroscopic and spectrometric
methods are not included here (unless there is some mention of use as a detector
system); to emphasize the importance of spectroscopy and spectrometry, they are
included as a separate chapter (Chapter 7) and their use in structural determination
is described elsewhere (Chapter 11). Statistical methods, as applied to analytical
chemistry, are beyond the scope of this chapter and have been omitted; the reader
is referred to other, more comprehensive works on this subject (e.g., Meier and
Ziind, 2000).
As elsewhere in this book, the nature of the subject matter of this chapter dictates
that there is overlap with the subject matter of other chapters. This is inevitable,
and the reader is referred to other relevant chapters to place the subject matter of
all chapters into the proper perspective.
10.2. GAS CHROMATOGRAPHY
Gas chromatography (also referred to as gas-liquid chromatography, GLC) is a
chromatographic method for separating the volatile components of various mixtures in which the mobile phase is a gas (Martin and James, 1952; Fowlis, 1995;
Grob, 1995). It is, in fact, 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.
In this type of application 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
experiencing increasing application in refinery plant control.
The longer compounds remain in a column, the more time they have to diffuse
and remix. It was suggested (Martin and James, 1952) that the best separations
should occur if the stationary phase was very thin and the mobile phase was
changed from a liquid to a gas. This would provide fewer foreign molecules for
the sample molecules to hit, thus reducing the mixing by diffusion. The detectors
available at this time (1952) had poor response, and to separate sufficient material
to be detected, a relatively thick layer of stationary phase was required. However,
the liquid mobile phase could be changed to a gas. Rapid development followed.
The importance of gas-liquid chromatography lies in its powerful separating
ability. Columns can have the equivalent of up to 1,000,000 theoretical plates
compared with conventional distillation, which normally operates in the range of
5-10 theoretical plates.
In the case of gas-liquid chromatography (GLC or GC), the two phases are a
flowing gas phase and a liquid phase held stationary on an inert solid support.
In practice, for the older style using packed columns, a small sample (1-5 |xl)
is injected by means of a syringe or sample loop into a heated injection port,
where the liquid is vaporized into the flowing gas stream (usually nitrogen, helium,
argon). The carrier gas transports the sample through the column (glass, copper, or
stainless steel, 3- to 6-mm diameter, 1-2 m long), which is packed with a solid of
large surface area. This solid support, which is commonly a diatomaceous earth
or crushed firebrick, is impregnated with a nonvolatile liquid phase. Separation
of the injected mixture occurs by partitioning between the gas stream and the
liquid phase. A large number of partitions occur, and even very small differences
in physical and chemical properties allow the components to become separated.
The gas stream, containing the separated compounds, then is passed through
a detector. The simplest type of detector is one that measures the difference in
thermal conductivity between the sample plus helium (He) or nitrogen (N2) gas and
a reference helium or nitrogen gas. The detector signal is monitored continuously
by a recorder that plots the components as a function of time, resulting in gaussian
shaped peaks. More recently, capillary columns, 0.05-0.53 mm in diameter and
10-100 m long, having as many as 4000 plates, are becoming common and finding
use as analytical methods (ASTM D-2268).
The elapsed time between the injection and the center of a peak is called the
retention time of that compound. Although a gas chromatograph separates compounds, the method does not identify them, but the retention time may be used as
corroborating evidence in the identification of a compound by injecting a known
sample under identical conditions and observing identical retention times. Another outcome of the chromatographic method is the identification of individual
components of a mixture as well as the calculation of gas chromatographic response factors for individual compounds (ASTM D-4626). The unknown-known
comparison then should be repeated on another column of different polarity to
substantiate the previous agreement of retention times. Failure to use columns
of different polarities to corroborate the identification of compounds can lead to
embarrassing situations.
The evolution of gas chromatography has been a major factor in the successful
identification of petroleum constituents. It is, however, almost impossible to apply
this technique to the higher-boiling petroleum constituents because of the comparatively low volatility of these materials. It is this comparative lack of volatility
in the higher-molecular-weight, asphaltic constituents of petroleum that brought
about another type of identification procedure, namely, carbon-type analysis.
Thus it is not surprising that gas chromatography has been used extensively
for individual component identification, as well as percentage composition, in the
gaseous boiling ranges (ASTM D-2163, ASTM D-2426, ASTM D-2504, ASTM
D-2505, ASTM D-2593, ASTM D-2597, ASTM D-2712, ASTM D-4424, ASTM
D-4864, ASTM D-5303, ASTM D-6159, IP 264, IP 318, IP 337, IP 345), in
the gasoline boiling range (e.g., ASTM D-2426, ASTM D-2427, ASTM D-3525,
ASTM D-3606, ASTM D-3710, ASTM D-4420, ASTM D-4815, ASTM D-5134,
ASTM D-5623, ASTM D-5845, ASTM D-5986, IP 425), in higher-boiling ranges
such as diesel fuel (ASTM D-3524), aviation gasoline (ASTM D-3606), engine
or motor oil (ASTM D-5480), and wax (ASTM D-5442), as well as in the boiling
range distribution of petroleum fractions (ASTM D-2887, ASTM D-5307), light
hydrocarbons in stabilized crude oil (IP 344), or the purity of solvents using capillary gas chromatography (ASTM D-2268). There are also recommendations for
calibrating and checking gas chromatographic analyzers (IP 353).
Gas chromatography (GC) is the method of choice for light and middle distillates because of its high resolution. However, for high-boiling petroleum distillates,
it has much more limited use because of its propensity to separate primarily by
carbon number and because of the immense number of compound types and homologues in these materials, let alone their low volatility (Altgelt and Boduszynski,
1994). The two main applications here are simulated distillation (page 271) and
the separation and identification of compound types and their homologues in welldefined liquid chromatographic (LC) fractions.
The technique has proved to be an exceptional and versatile instrumental tool for
analyzing compounds that are of low molecular weight and that can be volatilized
without decomposition. However, these constraints limit the principal applicability
in petroleum science to feedstock identification when the composition is known
to be in the low- to medium-boiling range. The use of this technique for direct
component analysis in the heavy fractions of petroleum is not only difficult but
also subject to many limitations.
For example, the number of possible components of a certain molecular weight
range increases geometrically with increasing molecular weight. Furthermore,
there is a corresponding sharp decrease in physical property differences between
isometric structures as the molecular weight increases. Thus it is very difficult,
and on occasion almost impossible, to separate and identify single components in
the heavier fractions of petroleum by gas chromatography. Indeed, the molecular
weights of the constituents dictate that long residence times are inevitable. This
is inevitably accompanied by the requirement of increased column temperature,
which decreases the residence time on the column but, at the same time, increases
the possibility of thermal decomposition.
In all senses, the instrumentation for gas chromatography is fairly straightforward (Fig. 10.1). A carrier gas passes through a controller to the column (packed
with an adsorbent) at the opening of which is a sample injector. The carrier gas
then elutes the components of the mixture through the column to the detector, at
the end of which may be another gas flow monitor.
Any gas, such as helium, argon, nitrogen, or hydrogen, that is easily distinguishable from the components in the mixture may be used as the carrier gas. Column
dimensions vary, but for analytic purposes a packed column may be 6 ft (2 m)
long by 3 in (6 mm) in diameter. It is also necessary to use a dissolving liquid as
part of the column substance. This remains stationary on the adsorbent and effects
Detector-recorder
Carrier gas
Sample injector
Figure 10.1. Representation of gas-liquid chromatographic equipment.
partition of the components of the mixture. The solid support is usually a porous
material that allows passage of the gas. For example, kieselguhr (diatomaceous
earth), which can absorb up to 40% by weight of a liquid without appearing to be
overly moist, is commonly used. The supporting material should not adsorb any
of the components of the mixture and must therefore be inert.
Individual components of mixtures are usually identified by their respective
retention times, that is, the time required for the component to traverse the column
under the specified conditions. Although tables for retention time data are available, it is more common in practice to determine the retention times of the pure
compounds. The retention time of any component is itself a function of the many
variables of column operation, such as the flow rate of the carrier gas and column
temperature, and exact duplication of other operator's conditions may be difficult,
if not impossible.
The sample size used in gas chromatography may vary upward from a microliter,
and there is no theoretical upper limit to the size of the sample that may be handled
if the equipment is built to accommodate it. The technique can be used for the
analysis of mixtures of volatile, vaporizable compounds boiling at any temperature
between absolute zero (-273 0 C, 459F) and 4500C (8400F). Identification of any
substance that can be heated sufficiently without decomposing to give a vapor
pressure of a few millimeters of mercury is also possible.
The components of petroleum have been studied extensively by gas chromatography. This includes the determination of saturated compounds and olefins in
cracked naphtha, as well as the identification of alkylbenzenes and the highermolecular-weight normal paraffins (to at least n-C4o)m higher-boiling petroleum
distillates. Previous methods usually involved the somewhat slow and careful fractional distillation followed by various analyses (physical and spectroscopic) of the
Gas chromatography can also be used to determine the three main hydrocarbon
types in gasoline: saturates, olefins, and aromatics. The procedure has been used
for simple characterization of gasoline and naphtha. This application demonstrates
the use of two techniques, a highly selective column and a chemical reaction to
remove one group of compounds. Sometimes it is advantageous to follow such a
type separation with further separations. For example, the saturate fraction after
separation from aromatics and olefins can be sent to a high-efficiency column for
determination of individual isomers. Determination of individual saturate isomers
is difficult or impossible when olefins and aromatics are present.
Analytic distillation by gas chromatography was an important development
because the demand for distillation analyses in petroleum laboratories is high.
Distillation analyses by gas chromatography depend on the fact that certain nonpolar silicone liquid phases elute hydrocarbons nearly in order of boiling point.
The analyses are made with temperature programming, and boiling point can be
correlated with elution time or with column temperature at the time of emergence.
Thus a distillation curve can be constructed from gas chromatographic data. Analyses by gas chromatography usually can be as accurate as they are by precision
The use of gas chromatography for direct component analysis in the heavier
fractions, such as residua, of petroleum is beset by many problems, not the least
of which is the low volatility and high adsorption tendencies of many of the highmolecular-weight constituents of petroleum. The number of possible components
in any given molecular weight range increases markedly with the molecular weight,
and there is a significant drop in the differences in physical properties among
similar structural entities. This limits the ability of gas chromatography, and unless
the sample has been fractionated by other techniques to reduce the complexity,
complete component analysis is difficult, if not impossible.
In view of the molecular characterizing nature of spectrometric techniques, it
is not surprising that considerable attention has been given to the combined use
of gas chromatography and these techniques. In recent years, the use of the mass
spectrometer to monitor continuously the effluent of a chromatographic column
has been reported, and considerable progress has been made in the development
of rapid-scan infrared spectrometers for this purpose. The mass spectrometer,
however, has the advantage that the quantity of material required for the production
of a spectrum is considerably less than that necessary to produce an infrared
spectrum.
The mass spectrometer identifies chemical compounds principally in terms of
molecular type and molecular weight, and for many problems, therefore, it becomes
necessary to use additional means of identification; the integrated gas chromatography infrared system is a very valuable complement to the mass spectrometer
route.
Considerable attention has also been given to trapping devices to collect gas
chromatographic fractions for examination by one or more of the spectroscopic
techniques. At the same time, developments in preparative gas chromatography
have contributed even more to the compositional studies of petroleum and its
products. With a column size of 4- to 6-in diameter capable of dealing with sample
sizes of 200 ml or more, there is every possibility that gas chromatography will
replace distillation in such areas as standard crude oil assay work.
Gas chromatography also provides a simple and convenient method for determining n-paraffin distribution throughout the petroleum distillate range. In this
method the n -paraffins are first separated by activated chemical destruction of the
sieve with hydrofluoric acid, and the identity of the individual paraffins is determined chromatographically. This allows n-paraffin distribution throughout the
boiling range 170-5000C (340-9300F) to be determined.
Gas chromatography has also been found useful for the preparation of simulated
distillation curves. By integrating increments of the total area of the chromatogram
and relating these to the boiling points of the components within each increment,
which are calculated from the known boiling points of the easily recognizable
n-paraffins, simulated boiling point data are produced.
Gas chromatographic process analyzers have become very important in petroleum refineries. In some refineries, more samples are analyzed automatically by
process chromatographs than are analyzed with laboratory instruments. These
chromatographs are usually fully automatic. In some cases, after an analysis the
instrument even makes automatic adjustments to the refinery unit. The chromatographs usually determine from 1 to 10 components, and the analyses are
repeated at short intervals (15-20 min) over 24 h.
A more recent, very important development in gas chromatography is its combination with a mass spectrometer as the detector. The technique in which gas
chromatography is combined with spectrometry (GC/MS) has proved to be a powerful tool for identifying many compounds at very low levels in a wide range
of boiling matrix (ASTM D-5769) (Poirier and Das, 1984; Lin et al., 1989). By
the combination of the two techniques in one instrument, the onerous trapping of
fractions from the gas chromatographic column is avoided and higher sensitivities
can be attained. In passing through the gas chromatographic column, the sample
is separated more or less according to its boiling point.
Although insufficient component resolution is observed in most cases, the eluting compounds at any time are usually closely related to each other in boiling
point and molecular weight or both and are free from interfering lower- and
higher-molecular-weight species. Because of the reduced complexity of the gas
chromatographic fractions, mass spectrometric scans carried out at regular intervals yield simpler spectra from which compound classes can more easily be
determined.
Pyrolysis gas chromatography can be used for information on the gross composition of heavy petroleum fractions. In this technique, the sample under investigation is pyrolyzed and the products are introduced into a gas chromatography system
for analysis. 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.
In the technique of inverse gas chromatography, the sample under study is
used as the stationary phase and a number of volatile test compounds are chromatographed on this column. The interaction coefficient determined for these
compounds is a measure of certain qualities of the liquid phase. The coefficient
is therefore indicative of the chemical interaction of the solute with the stationary
phase. The technique has been used largely for studies of asphalt (Haines, 1971).
Despite successful applications to certain high-boiling petroleum fractions, gas
chromatography itself is generally inadequate for the primary separation of such
high-molecular-weight materials. Although its temperature range may well be high
enough, the resolution is not sufficient for the large number of compound types and
homologues in these complex materials. Resolution is further impaired by the peak
broadening caused by high-molecular-weight species. For these heavy materials,
liquid chromatography (LC) and supercritical fluid chromatography (SFC) are
superior and are often the methods of choice. The wide choice of mobile phases for
these methods permits adaptation of the methods to the compositional subtleties of
the feedstocks in a manner that is not possible by gas chromatography. In addition,
supercritical fluid chromatography has the additional advantage of performance
with the application of pressure (Richter et al., 1998).
The primary use of gas chromatography in the analysis of heavy petroleum
fractions is in simulated distillation (simdis) with flame ionization detection (FID)
(Trestianu et al., 1985; Quimby and Sullivan, 1990; Thomson and Rynaski, 1992),
in gas chromatography with atomic emission detection (Biggs et al., 1985; Biggs
et al., 1987; Wylie and Quimby, 1989; Buteyn and Kosman, 1990; Kosman, 1992)
and other element-specific detection (Lee et al., 1984; Arpino et al., 1987), and in
combination with mass spectrometry as gas chromatography-mass spectrometry
SIMULATED DISTILLATION
Distillation is the most widely used separation process in the petroleum industry
(Nelson, 1958; Speight, 1999, 2000). 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 various test
methods are noted elsewhere (Chapter 5). 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 (Chapter 5).
There are some limitations to the routine distillation tests. For example, although
heavy crude oils contain volatile constituents, it is not always advisable to use
distillation for identification of these volatile constituents. Thermal decomposition
of the constituents of petroleum is known to occur at approximately 3500C (6600F).
However, thermal decomposition of the constituents of the heavier, but immature,
crude oils has been known to commence at temperatures as low as 2000C (3900F).
Thus thermal alteration of the constituents and erroneous identification of the
decomposition products as natural constituents is always a possibility.
On the other hand, 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 (Nelson, 1958).
A low-resolution, temperature-programmed gas chromatographic analysis has
been developed to simulate the time-consuming true boiling point distillation
(ASTM D-2887). The method relies on the general observation that hydrocarbons are eluted from a nonpolar adsorbent in the order of their boiling points. The
regularity of the elution order of the hydrocarbon components allows the retention
times to be equated to distillation temperatures (Green et al., 1964), and the term
simulated distillation by gas chromatography (or simdis) is used throughout the
industry to refer to this technique (Altgelt and Boduszynski, 1994).
The method has been well researched in terms of method development and
application (Hickerson, 1975; Green, 1976; Stuckey, 1978; Vercier and Mouton,
1979; Thomas et al, 1983; Romanowski and Thomas, 1985; MacAllister and
DeRuiter, 1985; Schwartz et al., 1987; Thomas et al., 1987). The benefits of the
technique include good comparisons with other ASTM distillation data as well as
application to higher-boiling fractions of petroleum. This offers a valuable aid to
process control operations and product testing. In fact, since the introduction of
ASTM D-2887, the method has gained widespread acceptance by process chemists
and process engineers for plant operation control.
The full development of simulated distillation as a routine procedure has been
made possible by the massive expansion in gas chromatographic instrumentation
(such as the introduction of automatic temperature programming) since the 1960s.
In fact, a fully automated simulated distillation system, under computer control, can
operate continuously to provide finished reports in a choice of formats that agree
well with true boiling point data. For example, data output includes the provision
of the corresponding Engler profile (ASTM D-86) as well as the prediction of other
properties, such as vapor pressure and flash point (DeBruine and Ellison, 1973).
Simulated distillation by gas chromatography is applied in the petrochemical industry to obtain true boiling point distributions of distillates and crude oils (Butler,
1979). Two standardized methods, ASTM D-2887 and D-3710, are available for the
boiling point determination of petroleum fractions and gasoline, respectively. The
ASTM D-2887 method utilizes nonpolar packed gas chromatographic columns in
conjunction with flame ionization detection. The upper limit of the boiling range
covered by this method is approximately 5400C (10000F) atmospheric equivalent boiling point. Recent efforts in which high-temperature gas chromatography
was used have focused on extending the scope of the ASTM D-2887 methods
for higher-boiling petroleum materials to 8000C (14700F) atmospheric equivalent
boiling point (Schwartz et al., 1988).
Interestingly, simdis techniques not only have upper temperature limits but also
lower limits. In gas chromatography-simdis, the lower limit is determined by the
resolution of the solvent peak from the first eluting sample peak. For this reason,
the ASTM method D 2887 is restricted to samples of initial boiling points of at
least 38C (1000F). In the supercritical fluid chromatography method, the lower
boiling limit is dependent on the initial column temperature and pressure. The
lowest possible pressure of carbon dioxide (CO2) is about 800 psi, namely, the
vapor pressure in the supply cylinder at room temperature. However, for many
high-boiling samples lacking low-boiling components, a higher initial pressure,
e.g., 850 psi, avoids unnecessarily long analysis times while providing the desirable resolution of the lower members. This restricts the lower boiling temperature of samples to be analyzed by supercritical fluid chromatography to about
1200C (2500F).
This simdis procedure is particularly adaptable to the simulated distillation
of heavy oil and bitumen and samples that contain large amounts of nonvolatile
residue. The procedure may also be applied to heavy gas oil samples that have a
final boiling point in excess of 525C (975F).
For the simulated distillation of heavy oil and bitumen, two chromatographic
analyses are performed to characterize the sample. The volatile components of the
sample are analyzed by a standard simulated distillation procedure, and a separate
assay is performed to determine the amount of volatile material in the sample by
an internal standard technique. The data from the simulated distillation is then
corrected for the nonvolatile residue, and results are reported as percentages of the
total sample.
ADSORPTION CHROMATOGRAPHY
When chemists refer to adsorption chromatography or to column chromatography, they usually mean a glass column with a mobile phase passing through
the inert phase (Table 10.1) by the force of gravity, mild suction, or at most
a few pounds of pressure. The column may or may not be equipped with an
attached solvent reservoir for the mobile phase (Table 10.2) but does not have
an attached stopcock to control the flow rate and should be wide bore to
prevent plugging with viscous mobile phases. Removable bottoms are used for
those separations that require long times. The bottom can be removed and the
column packing pushed out with a plunger. The column packing then can be
Table 10.1. Materials Used as Stationary Phases for
Fuller's earth
Calcium oxide
Sugar(s)
Least active
sectioned and the desired compounds extracted or washed from the inert phase for
further use.
Adsorption chromatography has helped to characterize the group composition of crude oils and hydrocarbon products since the beginning of the twentieth century (Chapter 10) (Altgelt and Guow, 1979; Altgelt and Boduszynski,
1994; Masel, 1995). In fact, it is probably the most used and abused of all of the
Table 10.2. Solvents Used as Mobile Phases for Adsorption Chromatography
Petroleum ether/petroleum naphtha
Benzene or toluene
Chloroform and other chloro-solvents
Various mixtures of the above solvents
Pyridine/water
Least interference with adsorbent
Most interference with adsorbent
chromatographic methods that have been applied to petroleum characterization!
The analytical chemist must chose and rationalize the number of fractions that
are to be the outcome of the separation procedure, and this rationalization must
be based on the manner in which the data will be used. The techniques used to
produce fractions that will be used for process predictability should be approached
differently from the techniques used to search for geochemical markers. The advisability of separating petroleum, heavy oil, and bitumen into a multitude of fractions
must be given serious preapplication consideration. The analytical chemist must
ask himself/herself, and be prepared to advise the process chemist or process
engineer, about the number of fractions necessary to accomplish the goal. Four
fractions might suffice, thus the tendency to proceed and separate the feedstock
into twenty or more discrete fractions is always a dream! Such temptation must
be avoided, and fractionation schemes that are meaningful to the task are to be
The apparatus for the various chromatographic separation schemes usually consists of a glass column 1-5 cm in diameter and 20-100 cm long, packed with a
solid material (called the inert phase, although it seldom is inert) such as silica gel
or diatomaceous earth (ASTM D-2007). The sample is placed as a thin band on
top of the packing and washed down the column with a liquid (mobile phase). As
the compounds move down the column, small differences in their molecular shape
and polarity allow them to become separated.
The method can be applied to conventional petroleum, heavy oils, residua,
and bitumen, but subtle differences may be applied to the procedure depending
on the nature of the material to be separated. For example, when conventional
petroleum is to be separated, the feedstock may first be topped (the volatile constituents removed) before separation. The procedure separates the feedstock into
saturate, aromatic, resin, and asphaltene fractions or specific chemical types such
as petroleum sulfonates (ASTM D-3712).
In general, the method involves deasphaltening the feedstock (Chapter 9), and
the resulting deasphaltened oil is passed through or refluxed on a recycle adsorption
apparatus packed with Attapulgus clay (Fig. 10.2). Resins adsorb on the Attapulgus
clay, whereas the saturates and aromatics are carried to the kettle. The resins are
eluted from the Attapulgus clay with methyl ethyl ketone and tetrahydrofuran
containing 50% water by volume. Separation of the saturates and aromatics is
performed on a chromatographic column packed with alumina and silica gel. The
saturates and aromatics are eluted with n-pentane and benzene, respectively. Any
resin constituents that may have remained are eluted with methyl ethyl ketone. All
fractions are determined gravimetrically after evaporation of the solvent.
The fractions denoted as saturates, aromatics, resins, and asphaltenes in this
procedure are defined operationally by the specific test conditions described in
the method and separations according to molecular type. Instead, the fractions
represent a separation based on solubility and strength of adsorption and must
be identified with the procedure by which they are generated. This operational
definition of the fractions is emphasized because similar terminology for designating fractions is used by methods using different separation conditions.
In practice, the separation is reproducible and hence useful for evaluating similarities and differences among different feedstock samples.
One of the common problems of such a fractionation scheme is the nature of the
adsorbent. In the early reports on petroleum fractionation, clay often appeared as
an adsorbent to effect separation of the feedstock into various constituent fractions.
However, clay {fuller's earth, attapulgus clay, attapulgite, and the like) is often
difficult to define with any degree of precision from one batch to another. Variations
in the nature and properties of the clay can, and will, cause differences not only in
the yields of composite fractions but also in the distribution of the compound types
in those fractions. In addition, irreversible adsorption of the more polar constituents
on the clay can be a serious problem when further investigations of the constituent
fractions are planned.
CHROMATOGRAPHIC
Figure 10.2. Adsorption chromatography using (a) a standard column and (b) a recycle apparatus.
DRIPTIP
ATTAPULGUS
Figure 10.2. (Continued)
One option for resolving this problem has been to use more standard adsorbents
such as alumina and silica. These materials are easier to define and are often
They also tend to adsorb less of the feedstock than a clay. Once the nature of the
adsorbent is guaranteed, reproducibility becomes a reality. Without reproducibility
the analytical method does not have credibility.
The type and relative amount of certain hydrocarbon classes in the matrix can
have a profound effect on the quality and performance of the hydrocarbon product.
The fluorescent indicator adsorption (FIA) method (ASTM D-1319) has served for
over 30 years as the official method of the petroleum industry for measuring the
paraffinic, olefinic, and aromatic content of gasoline and jet fuel. The technique
consists of displacing a sample under /sopropanol pressure through a column
packed with silica gel in the presence of fluorescent indicators specific to each
hydrocarbon family. Despite its widespread use, FIA 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
application of adsorption chromatography in which the adsorbent is either packed
in an open tube (column chromatography) (Altgelt and Guow, 1979) or shaped
in the form of a sheet (thin-layer chromatography, TLC) (Sharma et al., 1998). A
suitable solvent is used to elute from the bed of the adsorbent. Chromatographic
separations are usually performed for the purpose of determining the composition
of a sample (Snyder, 1968). Even with such complex samples as petroleum, much
information about the chemical behavior of a fraction can be gained from the
separation data (Chapter 15).
In the present context, the challenge is the nature of the heteroatomic species in
the heavier feedstocks. It is these constituents that are largely responsible for coke
formation and catalyst deactivation during refining operations. Therefore, it is these
constituents that are the focus of much of the study. An ideal integrated separation
scheme for the analysis of the heteroatomic constituents should therefore meet
several criteria:
The various compound types should be concentrated into a reasonable number
of discrete fractions, and each fraction should contain specific types of the
heteroatomic compounds. It is also necessary that most of the heterocompounds be separated from the hydrocarbons and sulfur compounds that may
constitute the bulk of the sample.
Perhaps most important, the separation should be reproducible such that the
yields of the various fractions and the distribution of the compound types
among the fractions should be constant within the limits of experimental
The separation scheme should be applicable to high-boiling distillates and heavy
feedstocks such as residua because heteroatomic compounds often predominate in these feedstocks.
The separation procedures should be relatively simple to perform and free of
complexity.
Finally, the overall separation procedure should yield quantitative or, at worst,
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. Should chemical alteration occur, it will give misleading data
that have could serious effects on refining predictions or on geochemical
Group type analysis by means of chromatography has been applied to a wide
variety of petroleum types and products. These types of analysis are often abbreviated by the names PONA (paraffins, olefins, naphthenes, and aromatics), PIONA
(paraffins, /so-paraffins, olefins, naphthenes, and aromatics), PNA (paraffins, naphthenes, and aromatics), PINA (paraffins, /so-paraffins, naphthenes, and aromatics),
or SARA (saturates, aromatics, resins, and asphaltenes).
The US Bureau of Mines-American Petroleum Institute (USBM-API) method
allows fractionation of petroleum samples into acids, bases, neutral nitrogen
compounds, saturates, and mono-, di-, and polynuclear aromatic compounds.
Multidimensional techniques, that is, the combination of two or more chromatographic techniques, can be very useful to gain further information about the individual components of chemical groups. Compounds can be isolated and identified
from complex matrices, and detailed fingerprinting of petroleum constituents is
feasible (Altgelt and Gouw, 1975).
In normal phase chromatography (see above), the mobile phase is nonpolar
and the column packing is polar in nature. Separation occurs because sample
molecules dissolved in the mobile phase interact with the packing. The molecules
are temporarily adsorbed and, after some time, returned to the mobile phase. This
process of adsorption-desorption occurs many times for a molecule on its way
through the column. The greater the compound's polarity, the more strongly it
interacts with the sorbent surface, the more it is retained, and the later it elutes
various types of interaction occur, from a weak induced dipole-induced dipole
interaction (London forces) to hydrogen bonding to strong acid-base attraction.
Normal phase partitioning chromatography is a variant of normal phase chromatography. Here the column packing is coated with a layer of polar liquid that
is immiscible with the nonpolar mobile phase and remains on the packing as the
stationary phase. Sample molecules move back and forth between the two phases
and are partitioned between these according to their respective solubility in the
phases. Polar sample molecules ordinarily have a greater solubility ratio in favor
of the stationary phase than less polar ones and spend more time there. Consequently, they elute later than nonpolar molecules. During the last two decades,
so-called bonded phases have replaced the liquid stationary phases in partitioning
Bonded phase packings are usually silica particles with chemically modified
surfaces. The hydroxyl (OH) groups on the silica are either silanized or esterified
and, in effect, replaced by organic groups, mostly paraffinic hydrocarbons of eight
or more carbon atoms. These hydrocarbons are nonpolar and offer no advantage
in normal phase chromatography. However, they are very useful in reversed-phase
chromatography, where the sample is eluted with a very polar solvent such as
acetonitrile and even mixtures of acetonitrile or similar solvents with methanol or
water. Here the sample molecules can partition again between a polar phase and
a nonpolar one, except that the phases are reversed from those in normal phase
chromatography. Here, the nonpolar molecules are more soluble in the stationary
phase than in the polar mobile phase and are, therefore, retained more strongly
than polar molecules.
The advantage of reversed-phase chromatography with its combination of an
inert packing surface and a polar mobile phase is that, theoretically at least, it is a
very mild method and prevents sample loss due to irreversible adsorption of highly
polar molecules, which can be a serious problem in normal phase chromatography
of high-boiling petroleum fractions. Unfortunately, it is difficult to completely
cover the silica surface with the organic phase. Often a small percentage of the
silica hydroxyl groups remains unreacted and is available for interaction with polar
sample molecules that may then be strongly adsorbed.
Fractionation of aromatics by ring number is best done on column packings with
bonded phases, for example, amino-, cyano-, phenyl-, or nitro-derivatized silica
(Altgelt and Boduszynski, 1994). Separation on these packings proceeds only
nominally by ring number, but the method really discriminates by the number of
pi electrons or double bonds in the ring system. For cata-condensed aromatics, this
is equivalent to ring number separation. However, peri-condensed molecules have
fewer double bonds than cata-condensed molecules with the same ring number.
For instance, pyrene (4 rings, 8 double bonds) elutes after phenanthrene (3 rings,
7 double bonds) and before chrysene (4 rings, 9 double bonds).
Molecules with nonplanar aromatic ring systems, usually sterically hindered,
elute before planar ones and long, stretched-out polynuclear aromatic systems
elute later than more compact ones. Generally, molecules with a larger (aromatic)
surface area can interact with more polar groups on the packing surface and will,
therefore, be more strongly retained.
An extension of adsorption chromatography, ligand exchange chromatography (LEC) has been used as a way to separate sulfur compounds from hydrocarbons. The method exploits the specific interactions of sulfur compoundsor other
heteroatomswith specific metal ions. Silver, mercury, copper, and zinc ions, for
example, form coordination complexes with (aliphatic) sulfides, whereas palladium ions interact strongly with (aromatic) thiophenic compounds. These metals,
deposited as chlorides or other salts on silica, can therefore selectively slow down
the elution of sulfur compounds relative to hydrocarbons on a chromatographic
column (Nishioka et al., 1986a, 1986b, 1986c, 1986d).
GEL PERMEATION CHROMATOGRAPHY
Gel permeation chromatography (also referred to as size exclusion chromatography
and on occasion as gel filtration chromatography) is a chromatographic technique
in which the separation is based on differences in the size of the sample molecules.
The column packing is made from beads of a porous gel which separate according
to molecular size.
Large molecules cannot fit into the gel at all and are washed out of the column.
The lowest-molecular-weight molecule that does not enter the gel is called the
exclusion limit, and the volume required to elute the large molecules is called
the void volume. The smaller molecules can permeate the gel; the smaller the
molecule, the farther the penetration and the greater the retardation on or within
the gel. This results in a separation because it requires more solvent to wash the
smaller molecules out of the gel.
The size of the pores determines the molecular weight range of the compounds
that can be separated. Size exclusion is often used to clean up an extracted solution
such as removing waxes from the residua that are produced in a variety of methods.
A general rule is that compounds that differ by 10% in size can be separated in
the same column. A series of columns, each fitted with a different exclusion limit
gel, can be used to separate a multicomponent mixture.
Gel filtration chromatography (GFC), has been successfully applied to aqueous
systems by biochemists for more than three decades (Porath and Flodin, 1959).
This technique was developed using soft, cross-linked dextran beads. The other
technique, gel permeation chromatography (GPC, also called size exclusion chromatography, SEC), uses semirigid, cross-linked polystyrene beads (Moore, 1964).
In either technique, the packing particles swell in the chromatographic solvent and
form a porous gel structure.
The distinction between the methods is based on the degree of swelling of the
packing; 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, or called size exclusion chromatography, in
its simplest representation consists of column(s) packed with gels of varying
pore sizes in a liquid chromatograph (Fig. 10.3) (Otacka, 1973). Under conditions of constant 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. On the other hand, the smaller solute molecules have increasing volume
within the beads, depending on their relative size, and require more time to elute
(Fig. 10.4).
Thus it is possible, with careful flow control, calibration, injection, and detection
(usually by refractive index or UV absorption), to obtain an accurate chromatographic representation of the molecular weight distribution of the solute (Gillyon,
1981). This must of course assume that there is no chemical or physical interaction
between the solute and the gel that negates the concept of solute size and pore size.
Figure 10.3. Representation of gel permeation chromatographic equipment.
For example, highly polar small molecules that could associate in solution and are
difficult to dissociate could conceivably appear in the incorrect molecular weight
range.
In theory, gel permeation chromatography is an attractive technique for the determination of the number average molecular weight (Mn) distribution of petroleum
fractions. However, it is imperative to recognize that petroleum contains constituents of widely differing polarity, including nonpolar paraffins and naphthenes
(alicyclic compounds), moderately polar aromatics (mononuclear and condensed),
Effluent
Figure 10.4. Representation of the separation by gel permeation chromatography.
and polar nitrogen, oxygen, and sulfur species. Each particular compound type
interacts with the gel surface to a different degree. The strength of the interaction increases with increasing polarity of the constituents and with decreasing
polarity of the solvent. It must therefore be anticipated that the ideal linear relationship of log Mn against elution volume Ve that may be operative for nonpolar hydrocarbon species cannot be expected to remain in operation. It must also
be recognized that the lack of realistic standards of known Mn distribution and
of chemical nature similar to that of the constituents of petroleum for calibration purposes may also be an issue. However, gel permeation chromatography
has been used in the study of petroleum constituents, especially the heavier constituents, and has yielded valuable data (Oelert, 1969; Weber and Oelert, 1971;
Albaugh et al., 1971; Reerink and Lijzenga, 1975; Ferguson and O'Brien, 1981;
Aaberg and Tjessem, 1982; Baltus and Anderson, 1984; Guieze and Williams,
1984; Sanchez et al., 1984; Hausler, 1985; Hausler and Carlson, 1985; Reynolds
and Biggs, 1988).
The adoption of gel permeation chromatography represents a novel approach
to the identification of the constituents because the method is not limited by the
vapor pressure of the constituents. However, the situation is different with heavy
petroleum samples. These are not homologous mixtures differing only in molecular
weight. In any particular crude oil a large variety of molecular species, varying from
parafflnic molecules to the polynuclear aromatic ring systems, may not follow the
assumed physical relationships that the method dictates from use with polymers
(Altgelt, 1968, 1970).
Size exclusion chromatography is the separation method that comes closest to
differentiating by molecular weight only and is almost unaffected by chemical
composition. The method actually separates by molecular size and has been used
to measure molecular weights (Altgelt and Guow, 1979; Hagel and Janson, 1992),
although there is some question about the value of the data when the method is
applied to asphaltenes (Speight et al., 1985).
Size exclusion chromatography is usually practiced with refractive index detection and yields a mass profile (concentration vs. time or elution volume) that
can be converted to a mass vs. molecular weight plot by means of a calibration
curve. The combination of size exclusion chromatography with element specific
detection has widened this concept to provide the distribution of heterocompounds
in the sample as a function of elution volume and molecular weight.
The use of size exclusion chromatography with reverse phase high-performance
liquid chromatography (HPLC) with a graphite furnace atomic absorption (GFAA)
detector has been described for measuring the distribution of vanadium and nickel
in high-molecular-weight petroleum fractions, including the asphaltene fraction
(Fish and Komlenic, 1984; Fish et al., 1984; Sarowha et al., 1996; Varotsis et al.,
1998). With the use of variants of this technique, inductively coupled and directcurrent plasma atomic emission spectroscopy (ICP and DCP), the method was
extended and the former size exclusion chromatography-graphite furnace atomic
absorption (SEC-GFAA) method was improved (Biggs et al., 1985,1987), allowing
the separation to be continuously monitored.
The combination of gel permeation chromatography with another separation
technique also allows the fractionation of a sample separately by molecular weight
and by chemical structure. This is particularly advantageous for the characterization of the heavier fractions of petroleum materials because there are limitations
to the use of other methods (Altgelt, 1965, 1968, 1970). Thus it is possible to
obtain a matrix of fractions differing in molecular weight and in chemical structure. It is also considered advisable to first fractionate a feedstock by gel permeation chromatography to avoid overlap of the functionality that might occur
in different molecular weight species in the separation by other chromatographic
In short, the gel permeation chromatographic technique concentrates all of a
specific functional type into one fraction, with the recognition that there will be a
wide range of molecular weight species in that fraction. This is especially true when
the chromatographic feedstock is a whole feed rather than a distillate fraction.
10.6. ION-EXCHANGE CHROMATOGRAPHY
Ion exchange is a process in which one type of ion in a compound is exchanged for a
different type, cation for cation and anion for anion. For example, calcium, iron, and
magnesium ions can be removed from water by being exchanged for sodium ion.
Ion-exchange chromatography is an ion exchange process in which the desired
ions are exchanged in sequence and are eluted from a column much the same as
compounds are eluted from a column in column chromatography.
Ion chromatography is the same as ion exchange chromatography, except that
it includes a provision for removing the ions in the eluting agent, so that sensitive
electrochemical detection is possible. The equipment used in ion-exchange chromatography is similar to that used in column chromatography and can be identical
for most separations.
An interesting historical aside to the use of ion-exchange chromatography
occurs in the biblical account of Moses at Marah (Christian Bible, Exodus,
Chapter 15, Verses 23-25; see also Christian Bible, Numbers, Chapter 33, Verses
8-9), one of the stations of the exodus where the Israelites found bitter water.
Moses reputedly:
was shown a tree which, when he had cast it into the water, the waters were made sweet.
Marah actually means "bitter" and the explanation is that the oxidized cellulose
exchanged with the salt ions that gave the water its peculiar taste. Whether or not
this is true can be questioned but what does matter is that the people of those times
were aware of such effects!
Other records as far back as Aristotle (384-322 B.C.E.) indicate that soils and
sand filters were used to treat impure drinking water. Sir Roger Bacon (1561-1626),
an English philosopher, observed in the early 1600s that:
salt water passed through earth through 10 vessels, one within another, and yet it hath not
lost its saltiness as to become potable, but when drayned through 20 vessels hath become
The first systematic studies were made to determine why ammonium sulfate
[(NH^SC^] and potassium chloride (KCl) did not wash out of soil (Thompson,
1850; Way, 1850). It was observed that if these compounds were passed through
a column of soil, calcium sulfate (CaSC^) and calcium chloride (CaC^) would
be obtained in the filtrate. Two years later (Way, 1852), systematic studies of the
process were commenced and the term base exchange was derived because of the
basic character of the exchanged elements.
Ion-exchange chromatography is widely used in the analyses of petroleum
fractions for the isolation and preliminary separation of acid and basic components.
This technique has the advantage of greatly improving the quality of a complex
operation, but it can be a very time-consuming separation.
Ion-exchange resins are prepared from aluminum silicates, synthetic resins,
and polysaccharides. The most widely used resins have a skeletal structure of
polystyrene cross-linked with varying amounts of divinylbenzene. They have a
loose gel structure of cross-linked polymer chains through which the sample ions
must diffuse to reach most of the exchange sites. Because ion-exchange resins are
usually prepared as beads that are several hundred micrometers in diameter, most
of the exchange sites are located at points quite distant from the surface. Because of
the polyelectrolytic nature of these organic resins, they can absorb large amounts
of water or solvents and swell to volumes considerably larger than the dried gel.
The size of the species that can diffuse through the particle is determined by the
intermolecular spacing between the polymeric chains of the three-dimensional
polyelectrolyte resin.
Although ion-exchange resins have a wide use, the major issue in the petroleum
industry is with nonaqueous chromatography on ion-exchange resins. The technique has found widespread use in fractionating petroleum into fractions that are
comprised of various functional types. Thus acidic and basic components can be
separated from heavy petroleum fractions.
Before a separation procedure is initiated, a column must be flushed with four
void volumes of mobile phase to mitigate bleeding. The sample, dissolved at
about 20 wt% concentration in the appropriate solvent, is introduced into a pair
of columns connected in series, usually with the anion column first and the cation
column second. The neutral fraction is eluted at 400C (1040F) with 2.5 times the
void volume of solvent.
After elution, the resins are transferred from the columns to a Soxhlet apparatus.
The acids are extracted from the anion-exchange resins with a benzene-formic
acid azeotrope and the bases from the cation-exchange resins with benzene plus
propylamine. The amine must be added slowly, in contrast to the formic acid.
Modifications of resin preparation and elution and extraction conditions allow the
separation and isolation of neutrals, weak and strong acids, and weak and strong
bases (Green et al., 1984).
The technique is complex and tedious. The preparation and conditioning of the
resins is critical for their stability as well as for their performance. Bleeding (i.e., the
release of decomposition products from the ion-exchange resins) may be an issue
(Strachan and Johns, 1987). The amphoteric character of certain compounds, which
causes them to be classified either as acids or as bases, depending on the sequence
of the ion-exchange resins the sample has to pass, must also be given consideration.
With anion-exchange resins first, the amphoteric species are collected as part of the
acid fraction, but with cation-exchange resins first, they are collected as part of the
base fraction. By performing the analysis both ways, the amount of amphoteric material can be measured. In fact, the correct sequence of ion exchange columns allows
the amphoteric species fraction to be collected as a distinct and separate fraction.
Ion-exchange chromatography procedures often advocate use of the whole feedstock rather than use of deasphaltened oil thereby foregoing the precipitation of
asphaltenes as a first step in the separation of the feedstock.
The technique can also be used for the separation and isolation of nitrogen
compounds from crude oil fractions. This gives fractions that are, chemically, much
better defined as concentrates of acids and one or several concentrates of bases.
Neutral heterocompounds can also be isolated by charge-transfer chromatography
on Attapulgus clay coated with ferric chloride (FeCl3), and hydrocarbon species
can be subdivided into saturates and aromatics in a separate column.
For example, cation-exchange chromatography has been used successfully to
isolate the nitrogen constituents in a petroleum fraction (Snyder and Buell, 1965;
Drushel and Sommers, 1966; McKay et al., 1974). The relative importance of these
compounds in petroleum has arisen because of their deleterious effects in many
petroleum 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 are nitrogen compounds (Okuno et al., 1967). Anion-exchange
chromatography is used to isolate the acid components (such as carboxylic acids
and phenols) from petroleum fractions.
If no subdivision of the polar species into acid and base fractions is desired,
much simpler methods can be used for the separation of feedstock fractions into
saturates, aromatics, and polars (Section 10.4).
HIGH-PERFORMANCE LIQUID CHROMATOGRAPHY
High-performance liquid chromatography (HPLC) (Fig. 10.5), particularly in the
normal phase mode, has found great utility in separating different hydrocarbon
group types and identifying specific constituent types (IP 343, IP 391, IP 424, IP
436) (Colin and Vion, 1983; Miller et al., 1983; Petryka, 1983; Chartier et al.,
Of particular interest is the application of the high-performance liquid chromatography technique to the identification of the molecular types in nonvolatile
feedstocks such as residua, and the molecular species in the asphaltene fraction
have been of considerable interest (Chmielowiec et al., 1980; Alfredson, 1981;
Bollet et al., 1981; Colin and Vion, 1983; George and Beshai, 1983; Felix et al.,
1985; Coulombe and Sawatzky, 1986; Speight, 1986).
However, a severe shortcoming of most high-performance liquid chromatographic approaches to a hydrocarbon group type of analysis is the difficulty in
obtaining accurate response factors applicable to different distillate products. Unfortunately, accuracy can be compromised when these response factors are used to
analyze hydrotreated and hydrocracked materials having the same boiling range.
In fact, significant changes in the hydrocarbon distribution within a certain group
type cause the analytical results to be misleading for such samples because of the
variation in response with carbon number exhibited by most routinely used HPLC
detectors (Drushel, 1983).
Several recent high-performance liquid chromatographic separation schemes
are particularly interesting because they also incorporate detectors not usually
associated with conventional hydrocarbon group types of analyses (Matsushita
Switching valve
Backflush
Figure 10.5. Representation of high-performance liquid chromatographic equipment.
et al., 1981; Miller et al., 1983; Norris and Rawdon, 1984; Rawdon, 1984;
Lundanes and Greibokk, 1985; Schwartz and Brownlee, 1986). The ideal detector
for a truly versatile and accurate hydrocarbon group type of analysis is one that is
sensitive to hydrocarbons but demonstrates a response independent of carbon number. More recent work (Hayes and Anderson, 1985,1986,1987) has demonstrated
the merits of the dielectric constant detector as an integral part of a hydrocarbon
group analyzer system.
In general, the amount of information that can be derived from any chromatographic separation, however effective the separation, depends on the detectors
(Hayes and Anderson, 1986; Pearson and Gharfeh, 1986). As the field of application for high-performance liquid chromatography has increased, the limitations of
commercially available conventional detectors such as ultraviolet/visible absorption (UV/VIS) and refractive index (RI) have become increasingly restrictive to the
growth of the technique. This has led a search for detectors capable of producing
even more information. The so-called hyphenated techniques are the outcome of
this search.
The general advantages of the high-performance liquid chromatography method
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 of the order of
minutes; and (4) the method can be adapted for on-stream analysis.
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 to the fluid extraction capabilities that
allow the opportunity to improve recovery of a solute (Taylor, 1996).
Thus supercritical fluid chromatography (SFC) combines the advantages of gas
and liquid chromatography in that its mobile phase has the low viscosity of a gas
and the variable solvent strength of liquids. Under the simplest conditions (constant
pressure, only 1 mobile phase), supercritical fluid chromatography has nearly the
resolution of gas chromatography, but its performance can be further enhanced by
the variation of solvent and by pressure programming (in addition to temperature
programming) during a separation (Schoemakers and Uunk, 1992).
In supercritical fluid chromatography, the mobile phase is a substance maintained at a temperature a few degrees above its critical point. The physical properties of this substance are intermediate to those of a liquid and of a gas at ambient
conditions. Hence, it is preferable to designate this condition as the supercritical
phase.
In a chromatographic column, the supercritical fluid usually has a density about
1/3-1/4 that of the corresponding liquid when used as the mobile phase; the
diffusivity is about 1/100 that of a gas and about 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 nonvolatile solutes and, on 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. Nonpolar or low-polarity solvents with moderate critical temperatures (e.g., nitrous oxide, carbon dioxide, ethane, propane, pentane,
xenon, sulfur hexafluoride, and various Freons) 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 (310C, 88F), nontoxic nature, and lack of interference with most
detection methods (Lundanes et al., 1986).
At the high pressure applied with supercritical fluid chromatography, n-butane
and ra-pentane are good solvents even for polar compounds. Carbon dioxide (CO2)
is only a poor to fair solvent for most high-molecular-weight petroleum fractions,
but it has the additional virtue of being easily removed from the fractions. It permits
the use of a flame ionization detector (FID) for supercritical fluid chromatography.
The flame ionization detector provides a uniform response over a wide range
of sample compounds and comes closest to being a true mass detector. Carbon
dioxide is also the solvent of choice for the combination of supercritical fluid
chromatography and mass spectrometry. Commercial equipment for analytical as
well as preparative supercritical fluid chromatography separations is available.
Despite these advantages, supercritical fluid chromatography has only begun
to have its potential realized when applied to petroleum, such as the determination
of aromatic and polynuclear aromatic constituents in diesel fuel (ASTM D-5186).
However, the technique has not yet had its potential realized for application to
heavy oil and bitumen or their respective high-molecular-weight fractions. One
reason is the tendency of the restrictor to plug. The restrictor is needed to maintain
the required high pressure throughout the entire column and consists either of
a short, very fine capillary or a plate with a tiny hole positioned at the outlet.
Even if complete plugging of the restrictors can be prevented, molecular clusters
may still form in it and then cause spikes in the flame ionization detector output.
These annoyances become worse with increasing sample molecular weight and
polarity and, therefore, with increasing sample atmospheric equivalent boiling
point (AEBP).
Although the method (ASTM D-2549) is generally limited to naphtha and
light gas oil samples and to samples having a vapor pressure sufficiently low to
permit sampling at ambient temperatures, the indications are that supercritical fluid
chromatography will find wide applicability to the problems of identification of the
higher-molecular-weight species in petroleum (Campbell and Lee, 1986; Chang
et al., 1988; Schwartz et al., 1988; Smith et al., 1988).
The sample is injected into a supercritical fluid chromatograph (SFC), equipped
with a column of limited efficiency, which separates the hydrocarbons into saturated (nonaromatic) and aromatic compounds. Because of its similar response
to both saturated and aromatic compounds, a flame ionization detector is used to
detect the components. At constant pressure and temperature, the area under the
chromatogram is measured as a function of retention time.
THIN-LAYER CHROMATOGRAPHY
Column chromatography made separations possible that were otherwise impossible at the time, but complete separation usually required from 1 day to several
weeks. However, biochemists and natural product chemists had realized for some
time that a piece of filter paper could be used instead of the column. The glass tube
and the tightly packed columns could be eliminated, and the separation times were
reduced, usually from a day or two to a few hours. One of the difficulties was that
only cellulose could be used as an inert phase. Other difficulties included the fact
that the paper was made of fibers that were thicker in some parts than others, which
caused irregular flow rates and poorer separations, and the fact that the paper could
be destroyed by strong acids or bases, so the color-developing reagents had to be
in mild solutions. These problems severely limited the types of compounds that
could be separated because a paper was needed that was made from uniform-sized
particles, regularly spaced, and capable of withstanding strong acids and bases.
The principle of what we now know as thin-layer chromatography (TLC) was
first developed in 1938 in a method developed as an alternate to paper chromatography. The method involved dusting alumina (AI2O3) on to a glass plate. The
particles were uniform and inert to acids, but the dust would blow or wash away
unless extreme care was taken, so a photograph of the results had to be obtained.
There was no way to store the plates. The method did not receive attention as an
analytical technique until a method was described to produce uniform-thickness,
thin layers of silica gel (S1O2) held onto glass plates with 7-8% of plaster of Paris
(CaSOzO (Stahl et al., 1956). This concept formed the basis of current procedures
and reduced separation times to 10-30 min.
The apparatus commonly used is a small glass jar with a screw-cap lid and may
or may not have filter paper placed around the walls on the inside. The sample, one
to two drops, is placed on a single spot about 2 cm from one end of the plate, and
the spot is indicated with a pencil mark. A scratch mark is made on the coating
12 cm from the bottom end. The developing solvent is added to the developing jar to
a height of about 1 cm. The plate is inserted, sample end down, and the jar is closed
to help maintain a solvent-saturated environment. When the solvent has risen to
the 12 cm mark by capillary action (10-30 min), the plate is removed. The solvent
is allowed to evaporate or is dried with a hair dryer. The plate then is sprayed with a
reagent that will form a color with the desired compounds. After spraying, colored
spots become visible, and the distance they have moved compared to the solvent
front is measured. The mechanism for the separation is most likely a combination
of adsorption and partition. If essentially round spots form that are separated from
each other, then the separation is primarily partitioning. If tailing occurs, then
adsorption is a major factor.
This technique is perhaps one of the most ignored techniques available to the
petroleum analytical chemist. It offers identification of a wide variety of compounds and compound type. Although still widely used by biochemists and by
natural product chemists, its revival by in the field of petroleum analysis is perhaps overdue.
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STRUCTURAL GROUP ANALYSIS
Structural group analysis is the determination of the statistical distribution of
the structural elements in petroleum, heavy oil (and heavy feedstocks such as
bitumen and residua), and their respective fractions, irrespective of the way in
which the elements are combined in molecules. Thus structural group analysis
occupies a position midway between ultimate analysis (Chapter 4), in which atoms
are the components, and molecular analysis (Chapter 2), in which molecules are
the components. A method for structural group analysis seems to be complete only
if structural elements are chosen in such a way that the sum of all elements equals
100% (or unity), for instance, by considering the distribution of carbon in aromatic,
naphthenic, and paraffinic locations in petroleum, its fractions, and products.
Structural group analysis has been widely applied to the analysis of petroleum,
heavy oil, bitumen, residua and their respective fractions. Comparative data have
been collected pertaining to the character of these feedstocks that are often helpful
in identifying products of unknown origin or in giving valuable indications concerning their manufacture. It is also claimed that, when more thorough knowledge
of hydrocarbon types is required, structural group analysis may offer a means of
following physical separation methods, such as distillation, solvent treatment, or
chromatography, as well as the effects of thermal processes. However, structural
group analysis may only provide average structural parameters, leaving much of
the conclusions open to inspired guesswork.
As already noted (Chapter 2) but stated again here to emphasize the complexity
of petroleum, heavy oil, and bitumen, the precursors to petroleum are as diverse as
the plant chemicals themselves, and it must be recognized that there may have been
some evolution of these chemicals over geological time as plants, and their constituents, evolved to modern-day counterparts. This is not to suggest that petroleum
is a collection of plant chemicals and should be considered as a composite of carbohydrates, proteins, fatty acids, and any other chemical that can be derived from
the pages of a natural product textbook!
Indeed, the constituents of the original precursor soup (protopetroleum) have
undergone considerable change through chemical and physical interactions with
their environment. Furthermore, local and regional variations in the nature of
the original plant precursors and in the maturation conditions offer a means of
variation of petroleum from field to field. Thus a derivative of a chemical entity that is predominant in petroleum from one field may be an entity of somewhat lesser importance in another crude oil, even in crude oils of one particular
Although gas-liquid chromatography and other techniques (Chapter 10) have
been applied successfully to the identification of a considerable number of petroleum constituents, they are mainly limited to the so-called front end, that is, the
volatile portion, of petroleum. Because the majority of crude oils and heavy oils
contain significant proportions of a nonvolatile residuum (bitumen being predominantly nonvolatile), it is not possible to identify individual components in this
part of the feedstock by a technique that requires some degree of volatility of the
constituents. It is because of this that other methods of identification have been
pursued. This is where structural group analysis has played a valuable role if not
sometimes a questionable role. To qualify the term questionable role, it is not
the methods of structural group analysis that are at error because of the various
inherent assumptions in each method but it is the means by which the data are
treated by the investigators. Using the data too literally and forgetting that the term
average structure cannot be always representative of the true structure as well as
behavioral characteristics is the major issue. But to continue.
Methods for structural group analysis usually involve the determination of physical constants of the sample. However, because there is no simple relation between
physical properties and chemical composition, a reliable correlation can only be
obtained by studying properties of a great variety of oil fractions or pure compounds
according to exact methods, laborious though that may be. The data collected statistically in this way may form the basis for chemical analysis by physical constants.
The better the representation and the greater the number of these basic data, the
more reliable the resulting method for structural group analysis will be. However,
it should be remembered that structural group analysis is not the ultimate answer
when applied to the heavier petroleum fractions or residua. Nevertheless, its importance lies in the straight correlation existing between the information derived
from such analysis and physical properties; it is often sufficient to get an overall
description of the material in terms of its average structural group composition.
The predominant feedstocks for structural group analysis are the high-boiling
fractions of petroleum, heavy oil, resins and asphaltenes, petroleum products
(asphalt), and residua. The result is the identification of the constituents of petroleum by molecular type may proceed in a variety of ways but generally can be classified into three methods: (1) spectroscopic techniques, (2) chemical techniques,
and (3) physical property methods. Various structural parameters are derived from
a particular property by a sequence of mathematical manipulations. It is difficult to
completely separate these three methods of structural elucidation, and there must,
by virtue of need and relationship, be some overlap.
This leads to analysis of the samples in terms of groups of hydrocarbons, and
four classes are generally recognized:
Aromatic if it contains at least one aromatic ring.
Olefinic if it contains at least one olefinic bond.
Naphthenic if it contains at least one naphthenic ring.
Paraffinic if it contains neither an aromatic, a naphthenic ring, nor an olefinic
double bond.
Aromatic hydrocarbons are also subdivided according to aromatic type, a term
that describes compounds having the same number and grouping of aromatic
rings. If an aromatic hydrocarbon contains two aromatic rings, three types may be
distinguished:
1. The rings may be condensed, that is, fused together, to form the naphthalene
2. The rings may be joined by an inter-ring bond as in the biphenyl nucleus.
3. The rings may be separated by one or more nonaromatic carbon atoms, such
as diphenylmethane (C6H5CH2C6H5) or dibenzyl (C6H5CH2CH2C6H5).
This nomenclature is open to extension to polynuclear aromatic compounds with
more than two aromatic rings. Alkyl chains and naphthene rings are generally not
considered in discussions of aromatic type. The method must also recognize combined hydrocarbon systems such as naphtheno-aromatic compounds, that allow
for the fact that in many cases:
%w/w aromatics H- %w/w olefins + %w/w naphthenes
+ %w/w paraffins = >100%
There are two ways of reporting the results of a structural group analysis. One
method is to determine the number of rings or other structural groups in terms of
the average number of aromatic rings (RA) and naphthene rings (RN), and the total
number of rings (Rx = RA + RN) is designated ring content. The other method is
to determine the number of carbon atoms in aromatic (%CA), naphthenic (%CN),
and paraffinic (%CP) structures, all expressed per 100 carbon atoms in the sample.
These data are designated as the carbon distribution, and if the molecular weight
of the sample is known and if an assumption is made about the type of rings
present, the ring content can be recalculated as carbon distribution; the converse is
also applicable. Thus two terms, carbon distribution and molecular weight (both of
which are averages), can then lead to derivation of a hypothetical average molecule.
It is always the case that when mathematical manipulations are used to derive
average structures, the structures will only be as reliable as the assumptions used
for the mathematical procedure. Then the literal interpretation that leads to the
conclusion, and the insistence, that such structures exist in the sample only leads to
more confusion. Representation is one matter. Adherent belief is another! Indeed,
the complexity of the nonvolatile constituents of petroleum makes the construction
of average structures extremely futile and, perhaps, misleading.
As noted, caution is advised here because such a molecule containing the structural groups in the proportions found by structural group analysis will not exist and
may be difficult to use in determining the behavioral characteristics of the sample.
The end results of these methods are indications of the structural types present in
the material.
This chapter presents methods that can be applied to study the makeup of the
feedstock in terms of chemical structures as well as methods that might be preferred
for refining. The chapter deals with the older physical property methods that were
used in the early days of structural group analysis, some of which are used even
now. The evolution of the available spectroscopic techniques that could be applied
to structural group analysis commenced in the 1960s, and these are included in
the section following the physical property methods. Not all (in fact, very few)
of these methods are recognized as standard methods, but they have received and
continue to receive wide application in the analytical and research laboratories of
the petroleum industry. It is this fact that makes their inclusion here essential.
PHYSICAL PROPERTY METHODS
There have been many proposals for the structural group analysis of petroleum
and petroleum products, which are usually based on inspection of the elemental
analyses and physical properties of the material. The overall result has been the
acceptance of several of these methods on the basis of their convenience and/or
relative simplicity, and these methods are described here.
The direct method (Vlugter et al., 1935a), so called because it involves direct
determination of the required physical properties of the sample, is unlike other
methods insofar as it does not usually require prior separation of the sample into
aromatic and saturated fractions.
Thus, by means of elemental analysis (Chapter 4) and molecular weight determination (Chapter 12) before and after hydrogenation of the sample, the percentage
of carbon in aromatic structures (%CA) and the average number of rings (Rx) can
be estimated. If an oil is hydrogenated so that only aromatic rings are converted
into naphthene rings, each aromatic carbon atom takes up one hydrogen atom.
%C A = 1191(//7M' - //M)/(100 - H)M
where H is the percentage hydrogen of the oil fraction, M is the average molecular
weight, and H' and M' are the corresponding data for the hydrogenated product.
In several' cases the molecular weights can be omitted because the difference
between M and M may be negligible. The hydrogen content of the hydrogenated
product, which is presumed to contain naphthenic and paraffinic carbon only, is
an exact measure of the number of rings. As compared with paraffins, each ring
closure involves a reduction by two hydrogen atoms. If RT is the number of rings
of the hypothetical molecule,
R T = 1 + (0.08326 -
05193H')Mf
To derive a complete set of carbon distribution and ring content figures from
%C A and RT, an assumption must be made about the type of rings present. It is
generally assumed that all rings are six membered and, in the case of the poly cyclic
materials, are kata-condensed; this type of condensation only occurs in such a way
that the rings have two carbon atoms in common, as, for example, naphthalene,
anthracene, or tetracene. However, the natural product origins of petroleum do
not support the occurrence of systems based on anthracene, and tetracene is now
considered less likely than the occurrence of systems based on phenanthrene and
chrysene in crude oil. The natural product precursors of petroleum (Speight, 1999)
are considered more likely to produce the angular- or peri-condensed aromatic
For CR, that is, the average number of ring carbon atoms per molecule, assuming
that only kata-condensed six-membered rings are present,
C R = 4R T + 2R TS
where RTs is the number of substantial rings (RTs = RT if < 1 and RTs = 1 if
R T > 1). In a kata-condensed system, it is possible to differentiate between the
rings insofar as one ring (a substantial ring) has six carbon atoms and the additional
rings contribute only four carbon atoms each.
Thus the percentage carbon in ring structures is given by the expression
%C P = 240,200 (2RT + R T s)/M(100 - H)
and the carbon distribution is
%C P = 100 - %C R
%C N = %C R - % C A
where CN is naphthene carbon and CA is aromatic carbon. Furthermore, because
%C A = 240,200 (2RA + R AS )/M(100 - H)
where RAs is the number of substantial aromatic rings (RAs = RA if RA < 1 and
RAS = 1 if RA > 1), then for RA < 1,
RA = %CAM(100 - #)/720,600
and for RA > 1,
RA = [%CAM(100 - i/)/480,400] - 0.5
The naphthene ring content is deduced from the relationship
It is perhaps unfortunate that the direct method does not require prior separation
into fractions based on hydrocarbon type. It is also unfortunate that the method
is also based on the assumption that heteroelements (e.g., nitrogen, oxygen, and
sulfur) are not present in the petroleum sample. However, if these elements are
present, corrections can be applied, but this detracts from the basis of the method
because rings containing heteroelements may be cleaved during the hydrogenation
process (Speight, 2000). Corrections may also need to be applied to dissociate
the method from the assumption that the polynuclear systems are kata-condensed
systems (e.g., anthracene) rather than peri-condensed systems (e.g., phenanthrene).
Nevertheless, the method does provide a means whereby %CA and RT can be
determined and has been considered one of the more reliable methods for structural
group analysis.
Waterman Ring Analysis
This method (Vlugter et al., 1935b, 1939) requires the determination of the density
(Chapter 4), refractive index (Chapter 6), aniline point (Chapter 5), and molecular
weight (Chapter 12). In essence, the elemental analysis used in the direct method
is replaced by the specific refraction.
Thus, because molecular refraction TM is additive for a hydrocarbon C x H 7 ,
rM = Mr 20 D = xrc = yrH
where r c and rH represent the atomic refraction of carbon and hydrogen, and M is
the molecular weight. Because:
= Af///100.8
x = M(IOO - / / ) / 1 2 0 1 . 0
where H is the percentage of hydrogen, then
%H = (100.8 x 1201.Or20D - 100.8r c )/(1201r h - 100.8rc)
Correlation of hydrogen content and specific refraction for a series of petroleum
fractions leads to the relationship:
% H = 110.48r 2 0 D - 22.078
Because the total number of rings R x is given by
RT = 1 + (0.08326 - 0.005193Hf)Mf
Rx = 1 + (0.2122 - 0.6401r 20 D )M
and because
%CR = 240.200 (2RT + R T s)/M(100 - H)
%CR = 240,200(2Rx + 2R TS )/M(77.922 - 100.48-r20D)
RTS = R x ,
if Rx < 1
RTs = 1 if RT > 1
Thus a relation among specific refraction, molecular weight, and percentage
carbon in naphthene rings for saturated hydrocarbons or atomic- and olefin-free
oil fractions can be defined (Fig. 11.1). Similarly, a graphic relation among aniline
point, specific refraction, and molecular weight of saturated oil fractions has also
been defined (Fig. 11.2).
The sources of error in the Waterman ring analysis are derived from the specific
refraction, the limited molecular weight range (200-500), and the errors that are
'LL
Figure 11.1. Graphical relationship used for the Waterman ring analysis.
Figure 11.2. Alternate graphical relationship used for the Waterman ring analysis.
inherent in the aniline point determination because of the complexity and color of
the sample. Nevertheless, even though the accuracy of the method is questionable,
it has found wide acceptance and use.
11.2.3. Density Method
This method is based on the use of the density d (Chapter 4), specific refraction rLL
(Chapter 6), and the molecular weight M (Chapter 12). This method is based on
correlation of oil composition, determined by the direct method (Section 11.2.1),
and the procedure used for this method is analogous to that employed for the
Waterman ring analysis, but the main difference is that the density is used instead
of the aniline point.
Thus the density corresponding to the observed molecular weight M and specific
refraction r\ is determined (Fig. 11.3); the difference Ad between this value and
the observed value is noted. Thus
%CA = 420AJ/(l + 3.2Ad)
10 3 /M
Figure 11.3. Graphical relationship used for structural analysis by the density method.
and CR is obtained graphically; thence,
%CP = 100 - %CR
%c N = %c R - %c A
The experimental procedure of this method is simplified compared to that of
the Waterman ring analysis and the applicability is more general. In addition, there
seems to be better agreement with data obtained by the direct method. Disadvantages, which are also inherent in the Waterman ring analysis, are that the molecular
weight range is limited to 200-500 and extrapolation of the data to the higher range
is uncertain; indeed, a high aromatic content causes the specific refraction to fall
outside the correlation. The accuracy of the density method is in general fairly
good, although according to the basic data used the application should be limited
to fractions with %CA < 1.5% C N or with RA < 0.5 R x .
11.2.4. n-d-M Method
The n-d-M correlation (ASTM D-3238) uses, as the name implies, the refractive
index n (Chapter 6), density d (Chapter 4), and molecular weight M (Chapter 12)
to estimate the percentage of the total carbon distribution in aromatic rings (%CA),
naphthenic rings (%CN) and paraffin chains (%CP) (Table 11.1). The sulfur content
of the sample should also be determined because there are differences in the
calculation for samples having sulfur contents below or above 0.206% by weight.
The n-d-M method is especially intended for petroleum fractions boiling above
the gasoline range (b.p. >200C, >392F) and for similar samples that result from
extraction, hydrogenation, or thermal treatment.
The validity of the method is good for petroleum fractions with up to %CR
75% (aromatic + naphthenic), provided that %CA (as found by the n-d-M method)
is not higher than 1.5 times %C N . Also, the method is also valid for samples
containing up to four rings per molecule if not more than half of these are aromatic.
Application to samples with a relatively high naphthene ring content may cause
minor, but not serious, errors. Although the presence of heteroelements (nitrogen,
oxygen, and sulfur) influences the accuracy, the method is applicable to samples
containing nitrogen (up to 0.5% by weight), oxygen (oxygen up to 0.5% by weight),
and sulfur (up to 2% by weight).
Dispersion-Refraction Method
This method (Deanesly and Carleton, 1942) is analogous to the direct method, but
the hydrogenation and the examination of the hydrogenated product are replaced
by the determination of the following: carbon and hydrogen content (Chapter 4),
Table 11.1. Formulae for the Calculations Used in the n-d-M Method
Measurements at 700C
Calculate:
jc = 2.42(rc - 1.4600) ~(d- 0.8280)
y = {d- 0.8280) - 1.1l(n - 1.4600)
Measurements at 2O0C
v = 2.51()z - 1.4750) ~(d- 0.8510)
w = (d- 0.8510) - 1.110* - 1.4750)
%CA
if v is positive:
%C A = 43Ov + 3660/M
if u is negative:
%C A = 67Ou + 3660/M
%C A
ifx is positive:
%C A = 41Ox + 3660/M
if x is negative:
%C A = 720* + 3660/M
if y is positive:
%CR = 775y - 3S + 1150/Af
if _y is negative:
%CR = 140Oy - 3S + 12100/Af
%CR
if w is positive:
%CR = 820w - 3S + 10,000/M
if w is negative:
%CR = 144Ou; - 3S + 10,600/M
RA = 0.44 + 0.055Mu
if x is positive:
RA = 0.41 + 0.055Mx
RT = 1.33 + 0.146M(tu - 0.005S)
if iu is negative:
R7 = 1.33 + 0.1 SOM(W - 0.005S)
R7 = 1.55 4- O.U6M(y - 0.005S)
ify is negative:
RT = 1.55 4- 0.180M(J - 0.005S)
RA = 0 . 4 1 + 0 . 0 8 0 M X
S is the sulfur content in wt%.
Source: Reprinted by permission of the publisher from van Nes, K., and H. A. van Westen, Aspects of
the Constitution of Mineral Oils, 1951, p. 344, 1950 by Elsevier-North Holland, Inc.
refractive index (Chapter 6), density (Chapter 4), molecular weight (Chapter 12),
bromine number (Chapter 8), specific dispersion (Chapter 6), and specific refraction (Chapter 6) of the original fraction (Fig. 11.4).
The structural parameters obtained by this method are similar to those derived
from the direct method, except that olefin double bonds (through use of the bromine
number) are also measured (Table 11.2). In addition, the method can be used on
materials derived from cracking processes because determination of the olefin
content is provided for by inclusion of the bromine number.
However, the method is based on data derived from pure hydrocarbons having
fewer than 18 carbon atoms per molecule, and the accuracy or interpretation of
the data must be suspect when applied to systems containing more than 18 carbon
atoms as well as heteroelements (nitrogen, oxygen, and sulfur).
11.2.6. Density-Temperature Coefficient Method
This method utilizes the linear relationship between the temperature coefficient
of density and the density (Chapter 4) for various series of hydrocarbons (Lipkin
et al., 1946). Two calculations are performed and are based on density limitations.
Table 11.2. Calculations Used in the Dispersion-Refraction Method
1. Specific refraction
2. Specific dispersion
3. Corrected hydrogen content
r=
s=
y=
hk =
5. Unsaturation
6. Molecular refraction
7. Olefinic unsaturation
8. Aromatic unsaturation
9. Percentage aromatic carbon %CA
10. Total ring content
11. Number of carbon atoms
per ring nR (Fig. 6.6)
12. Percentage ring carbon
13. Aromatic ring content
%CA = 23.2
%CN = %CR - %CA = 62.7
%CP = 100 - % C S = 14.1
(n2-l)/d(n2 + 2)
(nF
-nc)l04/d
100H/(C + H)
201.6(r - 0.2084 - 0.008421 y)
-i i.4i2
[0.811(S-98)-202J
= hk/h = 3.32/1.72
= bromine number/79.3
h-h0
= 1191/z A /(100- 30
M(2.016- 0.1403y)
%CR = 120,100tfr x n R /M(100 - y)
RA = CA/nR = hAMM/nR 100.8
RT = 2.80
RA = 0.76
RN = R7 - RA
Molecular Refraction Increment k
Number of Carbon Atoms per Ring
Figure 11.4. Graphical relationship used for structural analysis by the dispersion-refraction method.
In the first case, for the analysis of paraffin-naphthene mixtures with a density
below 0.861, it is assumed that in the density-density temperature coefficient diagram the portion of the intercept (at constant density) between the paraffin and
naphthene line is divided by the sample point into parts proportional to paraffin
and naphthene content. In this way the following equation for mixtures of paraffins
and naphthenes in the regions below 0.861 density was derived:
Wt.% rings = [190.Od - 217.9 - 105dd/dt]/(0.593d - 0.249)
where d is the density at 200C (68F) and dd/dt is the change in density per degree
change in temperature.
In the second case, for mixtures having a density above 0.861, it is assumed
that there is an equal distribution of condensed and noncondensed naphthenes. The
sample point was assumed to divide the line between the limiting paraffin point and
a point on the naphthene ring line above 0.861 into parts proportional to paraffin
and naphthene content, and for this region the following formula was derived:
Wt. rings = [102.Sd - 142.8 - 105dd/df]/0.262
Simplification of the experimental procedure could be achieved by deriving the
density coefficient from the molecular weight, which in turn can be estimated from
other physical properties, such as the density (Chapter 4) and mid-boiling point
(Chapter 5), or viscosity at 38C (1000F) and 99C (2100F) (Chapter 4). However,
-10 5 dJ/d^ = 53.5 + 3360/M
if d <0.861,
Wt.% rings = [190.Od - 164.4 + 3360/M](0.593d - 0.249)
and if d > 0.861,
Wt.% rings = (102.8J - 89.3 + 3360M)/0.262
For the analysis of samples containing aromatic compounds and no naphthene
rings, a procedure is followed that is quite analogous to the ring-chain analysis for
naphthenes. The line between the limiting paraffin point and a point of the aromatic
ring line in the density-density temperature coefficient diagram is divided by the
sample point (Fig. 11.5). It is assumed that the parts are proportional to aromatic
ring and paraffinic chain content. The relationship among wt. aromatic ring, density
coefficient, and density is only given graphically; graphs are used for condensed
ring aromatics (Fig. 11.6), for noncondensed ring aromatics (Fig. 11.7), and for
mixtures having an equal distribution of these two types (Fig. 11.8).
A o f / A f , x10 5
Naphthene Rings
Density, d
Figure 11.5. Density-temperature coefficients for various hydrocarbon series.
Density Coefficient x 10'6
Percent Ring
Figure 11.6. Graphical relationship used for structural analysis of polynuclear aromatic systems in
the density-temperature coefficient method of structural group analysis.
Density Coefficient * 10"5
Figure 11.7. Graphical relationship used for structural analysis of noncondensed ring aromatic systems
in the density-temperature coefficient method of structural group analysis.
Density Coefficient x irj'5
Figure 11.8. Graphical relationship used for structural analysis of mixtures of polynuclear aromatic
systems and noncondensed ring aromatic systems in the density-temperature coefficient method of
structural group analysis.
The applicability of the method for analyzing aromatic fractions is limited to
fractions having no naphthene rings along with the aromatic rings, although the
method may be applied to alkylated aromatics.
The Molecular Weight-Refractive Index Method
The samples to be analyzed by the molecular weight-refractive index method
must be separated beforehand into aromatic and paraffin-naphthene fractions by,
for example, silica gel adsorption chromatography (Chapter 10). As the name
indicates, only the molecular weight M (Chapter 12) and the refractive index n20D
(Chapter 6) are the required parameters, and by using data derived from use of
pure hydrocarbons, the following relationships appear to hold:
Aromatic oils, noncondensed rings:
%CA = {l060[(n 20 D - 1.475O)M + 8.79] 085 }/M - 2
+ 1.0l[(n20D - 1.475O)M + 8.79] 085
RA = 0.126[(/z20D - 1.475O)M + 8.79]0"85
Aromatic oils, kata-condensed rings:
%CA = {2150[(rc20D - 1.475O)M + 8.79]>56}/M - 3
+ 2.3[(/220D - 1.475O)M + 8.79] 056
RA = 0.165[(/z20D - 1.475O)M + 8.79]0'74
Mixtures of condensed and noncondensed rings:
%CA = {[l650(/i 20 D - 1.4750) + 8.79]"67}/M - 2
+ 1.65[(/I20D - 1.475O)M + 8.79] 067
RA = 0.15l[(n 20 D - 1.4750)M + 8.79]'78
Nonaromatic oils, condensed and noncondensed rings:
%CR = {2920[(n20D - 1.475O)M + 8.79] 73 }/M - 2
+ 0.57[(n20D - 1.475O)M + 8.79]0'86
Rx = 0.284[(/z20D - 1.475O)M + 8.79]0'86
F(S, M)
Figure 11.9. Graphical method used for structural group analysis.
Application of the M-^20D method to saturated portions of oil fractions gives
results that in general are in good agreement with those obtained by other methods.
There are several additional methods for structural group analysis that have been
proposed but are not known by any specific name. Most are modifications of the
named methods and were divided because of the need to apply such methods to,
in some cases, higher-molecular-weight and/or real-life samples.
One method has also been proposed for determining the number of aromatic
rings RA and naphthenic rings R N in aromatic fractions of petroleum and involves
measurement of the molecular weight M (Chapter 4), density d (Chapter 4), and
refractive dispersion s (Chapter 6). From the measured data, the functions:
F(s, M) = (s-
98) (M + 12) 1(T 3
F(d, M) = (d- 0.854) (M + 12)
are calculated, and RA and RN are estimated graphically (Fig. 11.9).
Indeed, the procedure is simple and rapid, and the method is claimed to be applicable to aromatic concentrates from both nondestructive distillation and cracking
processes. Average deviations of 0.1 of an aromatic ring and about 0.2 of a naphthene ring are usual. If there are more than three aromatic rings per molecule, the
results are uncertain because of a lack of basic data and knowledge concerning
the types of petroleum hydrocarbons with four or more aromatic rings. Saturated
hydrocarbons, olefins, some noncondensed polycyclic aromatics, and nonhydrocarbons are reputed to introduce serious errors into the analysis.
Another methods include the derivation of a linear relation between percentage
carbon in aromatic structure %CA, refractive index n20D (Chapter 6), density ^20,
(Chapter 4), and aniline point (AP) (Chapter 5):
%CA = 1039.4rc20D - 410Ad20 - 0.315AP - 1094.3
This formula holds good only if %CA < 30. When the calculated value for
%CA exceeds 30, a corrected value must be found by using the formula
%CA(corr) = 0.5%CA(calc) + 15
Alternatively, it has been suggested that the molecular weight determination
(Chapter 12) of the n-d-M method be replaced by kinematic viscosity measurements (Chapter 4) leading to a n-d- V method.
An equation has been devised that is applicable to lubricating distillates that have
not been subjected to thermal cracking, temperatures <350C (<660F). If the
naphthenic carbon is of the order of 25-75% of the total carbon, arelationship exists
between the refractivity intercept (Chapter 6) (Kurtz and Ward, 1936, 1937; Kurtz
and Headington, 1937) and the number of carbons in naphthenic locations (CN):
Refractivity intercept = 1.0502 - 0.00020 x %CN
Finally, it has also been proposed that for substances such as asphaltenes, which
contain condensed ring systems, the following relationships be applied:
R = 0.11(9.9C - 3.1H - 3.70 + 1.5N + 14S -
M/d)
where R is the number of rings, C, H, O, N, and S are the numbers of carbon,
hydrogen, oxygen, nitrogen, and sulfur atoms (Chapter 4), M is the molecular
weight (Chapter 12), and d is the density (Chapter 4).
However, if it is not possible to determine the molecular weight, the relationship
has been modified to
C/R = 9.2/(9.9 + 3.1H/C + 3.70/C + 1.5N/C + 14S/C - 1200/%C, d)
where C/R is the ring condensation index, H/C, O/C, N/C, and S/C are the
various atomic ratios calculated from elemental analyses, %C is the percentage of
carbon obtained by elemental analysis, and d is the density.
Unfortunately, the method assumes that atoms other than carbon and hydrogen
are not major components, olefins are absent, the number of rings is greater than
one, and the rings are the fused naphthalene type rather than the biphenyl type.
The molecular weight of petroleum, heavy oil, and bitumen is important in studies of chemical constitution and chemical reactivity. For example, the molecular
weight of any feedstock will give an indication of the amount of hydrogen required to upgrade the feedstock to a particular product or a series of products
(Fig. 12.1). In addition, structural group analysis (Chapter 11) of the various fractions often requires molecular weight data as, for instance, in the characterization of
the various fractions for insertion into the various indices and correlation formulae
As the boiling points of petroleum fractions increase, the complexity of the constituents in these fractions also increases (Fig. 12.2). The high-boiling fractions of
petroleum, and these may include saturated constituents (saturates fraction) and
aromatic constituents (aromatics fraction) (Chapter 9) depending on the boiling
profile (Chapter 5) of the crude oil, have an extremely complicated composition.
In fact, any attempted isolation of individual compounds is a frustrating and impossible task.
For a variety of reasons, of which structural group analysis and process modeling as well as process chemistry are only three, there is a need to determine the
molecular weight of either the original feedstock or the feedstock constituent fractions. Various methods are available for molecular weight determination (Speight
et al., 1985), some of which are claimed to be satisfactory and others less adequate
to the task. However, for those original constituents and products that have little
or no volatility, for example, resins and asphaltenes, vapor pressure osmometry
(VPO) (ASTM D-2503) has been proven to be of considerable value.
The molecular weight and molecular weight distribution have multiple applications in the analysis and characterization of heavy petroleum fractions. Molecular
weight may be determined by a number of methods including (1) vapor pressure
osmometry (VPO), also called vapor phase osmometry, (2) size exclusion chromatography (SEC), which is still often referred to by its older name, gel permeation
chromatography (GPC), and (3) nonfragmenting mass spectrometry, also called
parent ion mass spectrometry. Colligative techniques, such as freezing point depression (cryoscopy), commonly used in the past, have essentially been superseded
H-C. atomic ratio
% Nondistillable
Figure 12.1. Atomic hydrogen-to-carbon ratios of various feedstocks.
by vapor phase osmometry, primarily because the latter is more sensitive and therefore covers a wider molecular weight range.
It is the purpose of this chapter to describe the methods that have been used for
determining the molecular weight of petroleum and petroleum fractions without
advocating one method over the other. The choice of the method is sample dependent. Differentiation between particle size and molecular weight is also necessary.
In this context of this chapter, a particle may be composed of one or (usually) more
molecules, but a molecule is a single entity and is not a particle.
In addition, the molecular weight of a petroleum product appears to be less
in demand. Most products, from gasoline to lubricating oil, will be defined by
distillation profile or by separation and other physical properties such as viscosity,
API gravity, and the like. Therefore, the reader will find that the references in this
chapter are devoted to methods designed for determining the molecular weight
of the whole feedstock and, to a greater extent, the molecular weight of the various fractions insofar as the data assist in the definition of process chemistry and
METHODS FOR MOLECULAR WEIGHT MEASUREMENT
Numerous attempts have been made to measure the molecular weight of petroleum,
heavy oil, and bitumen using a variety of different methods, but there is a noticeable
Boiling Point, 0 C
Figure 12.2. Carbon number-boiling point data for pure compounds.
lack of consensus on the value obtained for a specific sample. This has been irrevocably traced to structural aspects of petroleum, heavy oil, and bitumen and, in
particular, to the behavior of the asphaltene constituents in molecular dispersion
in their own maltenes. In view of the fact that a number of methods used to determine molecular weight information utilize different solvents at different temperatures, the behavior of the component parts such as the resins and the asphaltenes
(Chapter 9) in these solvents must be established if a consistent picture of petroleum
structure and behavior is to emerge (Chapter 14).
With the goal of structural information, the molecular weight of petroleum
fractions has been the subject of much discussion over the past several decades.
The reliability of the method, the meaning of the term average molecular weight,
and the interpretation or usefulness of the data have received considerable attention.
In cases in which only approximate values for molecular weight are required,
use can be made of several physical property correlations (Mills et al., 1946; AIi,
1971) that involve correlations such as a molecular weight-boiling point-density
correlation. This correlation is believed to be satisfactory for determining molecular weights in the range of 240-300 for any petroleum fraction for which a
good 50% boiling point can be obtained. The viscosity correlation (Hirschler,
1946; Mills et al., 1946) was used for lubricating oil fractions of molecular weight
240-700 using correlations for viscosity with gravity and for viscosity at 37.8C
(1000F) with viscosity at 98.9C (2100F). However, for more accurate determinations of molecular weight, direct measurement is necessary.
Currently, of the methods available, several standard methods are recognized as
being useful for determining of the molecular weight of petroleum fractions and
these methods are:
ASTM D-2224: Test Method for Mean Molecular Weight of Mineral Insulating
Oils by the Cryoscopic Method (discontinued in 1989 but still used by some
laboratories for determining the molecular weight of petroleum fractions up
to and including gas oil).
ASTM D-2502: Test Method for Estimation of Molecular Weight (Relative
Molecular Mass) of Petroleum Oils from Viscosity Measurements.
Molecular Mass) of Hydrocarbons by Thermoelectric Measurement of Vapor
Pressure.
ASTM D-2878: Method for Estimating Apparent Vapor Pressures and Molecular Weights of Lubricating Oils.
ASTM D-3593: Test Method for Molecular Weight Averages/Distribution of
Certain Polymers by Liquid Size Exclusion (Gel Permeation Chromatography-GPC) Using Universal Calibration (has also been adapted to the
investigation of molecular weight distribution in petroleum fractions).
Each method has proponents and opponents because of assumptions made in the
use of the method or because of the mere complexity of the sample and the nature
of the inter- and intramolecular interactions.
Methods for molecular weight measurement are also included in other, more
comprehensive standards (ASTM D-128, ASTM D-3712), and there are several
indirect methods have been proposed for the estimation of molecular weight by
correlation with other, more readily measured physical properties. They are satisfactory when dealing with the conventional type of crude oils or their fractions
and products and when approximate values are desired.
Vapor Pressure Osmometry
Vapor pressure osmometry (ASTM D-2503), also called vapor phase osmometry,
is a relatively simple and cheap method for the determination of molecular weight.
Most osmometers can operate over a range of temperature through the use of probes
that cover specific temperature ranges. The method gives the number average
molecular weight and not the molecular weight distribution.
Vapor pressure osmometry is one of a group of techniques that measure properties based on the number concentration of molecules (i.e., colligative properties).
The method measures the degree to which the vapor pressure of a solvent is lowered
by the presence of a solute through a temperature effect.
The measuring elements are two temperature-sensitive thermistors placed in
a closed, heat-insulated chamber. By means of two syringes, a drop of solvent
is placed on one and a drop of the sample in solution in the same solvent is
placed on the other. The chamber is saturated with solvent vapor and carefully
temperature controlled. Because the solution has a lower vapor pressure than the
solvent, solvent from the chamber atmosphere will condense on it. The difference in vapor pressure is proportional to its sample concentration. The heat of
condensation warms the solution drop until its vapor pressure is the same as that
of the surroundings. From then on, a steady state of condensation and warming
is established. The temperature increase is measured and recorded. The solvent
drop on the other thermistor is in equilibrium with the solvent in the chamber
and, theoretically, gives no temperature effect. In reality, convection and other
effects cause minute disturbances in the system, the effect of which can be minimized by subtracting the voltage of the solvent thermistor from that of the solution
thermistor.
The temperature difference, AT, is related to concentration and molecular
weight at infinite dilution by the equation:
AT = Kic/MW
where ^ i is a constant determined by calibration and c is the solute concentration. The effect is measured at several concentrations, and the results are plotted
versus the reciprocal of the molecular weight (1/MW) and extrapolated to zero
concentration (also referred to as unlimited dilution).
In the early days of vapor pressure osmometry, ranges of error were accepted
or at least recognized that made some of the data questionable. For example, at
molecular weight at about or above 5000, the error might be as much as 10%
or even as high as 15%. Modern instruments have reduced experimental errors
severalfold by allowing the application of very small and precisely repeatable
sample and solvent drops on the thermistor beads. Thus measurements of molecular weight up to about 50,000 are now possible. In addition, samples of much
lower concentrations can now be measured, allowing linear extrapolation to zero
concentration, in contrast to those from more concentrated solutions.
However, one of the issues that arises through the use of this method for determining the number average molecular weight is that there can be a shift to the
low values by the presence of low-molecular-weight contaminants. For example,
traces of the solvent (other than that used for the molecular weight measurement)
that remain after the extraction or fractionation process(es). Alternatively, if the
sample is an oil fraction, there may be some inclusion of lower-boiling constituents
that, by rights, belong in the preceding fraction. Residual toluene may not affect
the molecular weight measured in toluene as long as the effect is not due to sample concentration by weight but it would certainly effect the molecular weight as
measured in pyridine, nitrobenzene, or in any other solvent with a shift to lower
than real values.
A common solvent for vapor pressure osmometry is toluene that is satisfactory
for hydrocarbons and moderately polar compounds. However, for the highly polar
fractions, such as asphaltenes, more polar solvents such as pyridine are required.
The molecular weight of such fractions measured by vapor pressure osmometry in
pyridine are distinctly lower than those measured in toluene (Moschopedis et al.,
1976; Speight et al., 1985) indicating a lower degree of aggregation, assuming that
contamination with trace amounts of previously used solvent in the separation of
the samples can truly be excluded.
An aspect of the number average molecular weight by vapor pressure osmometry that also requires consideration is the possibility of some, or even preferential,
aggregation of several small polar molecules with a much larger polar molecule
during sample collection (precipitation) or during fractionation. The aggregates
dissociate in the solvents used for molecular weight measurement, releasing some
or all of the low-molecular-weight species. Such aggregation is favored by precipitation of asphaltenes where occlusion of polar molecules from the maltene fraction
is common (AIi et al., 1985). However, this effect does not even require contamination with foreign material but is possible in any sample containing highly polar
molecules of widely different molecular weights. It slants the resulting number
average molecular weight toward low values because the more numerous small
molecules dominate over the fewer large ones even though their amounts by weight
may be the same or smaller. A number average molecular weight of 5000 thus does
not preclude the presence in that fraction of several weight percent of molecules
at least 10 times larger, i.e., of around 50,000.
Another potential problem with any molecular weight measurement of asphaltenes is their tendency to become less soluble after isolation. In crude oil and its
heavy fractions, the asphaltenes are maintained dispersed in the nonasphaltene material by interaction with the resins (soluble polar molecules) (Chapter 9). However,
once they are isolated by precipitation, the asphaltene constituents can be considered to be denatured, analogous to a hard-boiled egg as opposed to a fresh egg.
Properties may change and, hence, asphaltenes' solubility can be quite different.
The observance of lower than true molecular weights through the influence
of solvent and/or adsorbed lower-molecular-weight species on the asphaltene
constituents is not specific to the vapor pressure osmometry method. It applies to
any method producing number average results. Only further fractionation or other
suitable measurements can provide the molecular weight distribution of these polar fractions. Re-precipitation or further fractionation of asphaltenes mitigates the
preferential solvation of large polar molecules by small ones (Speight et al., 1984).
One technique for reducing the effect of aggregation is to measure the molecular weight of polar species (asphaltenes) at different concentrations and different
temperatures to illustrate and negate any aggregation effects. Thus the molecular
weight is measured at three different concentrations at each of three different temperatures (Speight, 1994). The data are extrapolated to determine the molecular
weight at zero concentration at each temperature, after which they are extrapolated to room temperature to negate concentration and temperature effects. This,
of course, assumes that the extrapolation line is straight!
Thus the molecular weight of pentane-asphaltenes measured by vapor pressure
osmometry in nitrobenzene are even lower than those reported from measurements
in pyridine, with differences ranging from 5 to over 50%. In fact, raising the
temperature of the sample chamber (in which the probe is contained) to 1000C
(212F) and above lowered the results by another few percent. Such behavior
strongly suggests that even nitrobenzene at the regular vapor pressure osmometer
temperature (37.5C, 1000F) was not sufficient to overcome all the intermolecular
aggregation. This not an isolated event but seems to be a common occurrence,
because it was observed with pentane-asphaltenes from a wide variety of crude oils.
The aggregation effect, which has, on occasion, been incorrectly referred to
as an error, describes the fact that the accuracy of the molecular weight value is
influenced by aggregation of the molecular species in solution. In some instances,
this may not be classed as an error insofar as the aggregation is recognized and the
method is used (along with molecular weight determination in a polar solvent) to
determine the maximum aggregation that can occur in the nonpolar solvent. Such
effects are magnified when measuring the molecular weight of the asphaltenes
that consist primarily of polar (heteroatom) constituents. Indeed, from such experiments the aggregation effect can be determined as the ratio of the molecular
weight in a nonpolar solvent (e.g., toluene) to the molecular weight on a polar
solvent (e.g., pyridine or nitrobenzene). Thus:
aggregation factor TV = MWtoiuene/MWpyndme
aggregation factor N = MWtoluene/MWnitrobenzene
Asphaltene constituents naturally aggregate in nonpolar solvents, but it must
also be recognized that another possible reason for finding higher molecular weight
for asphaltenes is caused by the susceptibility of the polar molecules to oxidation
after separation (Moschopedis and Speight, 1978). The inclusion of polar oxygen
functions by oxidation increases the polarity and hence their ability to aggregate.
Therefore, storage of the asphaltenes in an inert atmosphere (nitrogen) and in the
dark is desirable.
Other solvents such as benzene (now in disfavor because of environmental
concerns) have been used, as have a variety of polar solvents. Of the latter, tetrahydrofuran is often cited as a successful solvent. This seemed to arise because of the
solubility of coal-derived asphaltenes in tetrahydrofuran. However, coal-derived
asphaltenes are the products of thermal processes and bear no relationship to
petroleum asphaltenes. Indeed, the use of tetrahydrofuran in the chromatographic
separation processes for petroleum (Chapter 10) is to be approached with caution because of the tendency of tetrahydrofuran to react with the adsorbent and
form by-products. In a summary of the current context, petroleum asphaltenes
often exhibit a somewhat lesser solubility in tetrahydrofuran than in toluene and
in pyridine. However, in the darkness of the solution, the insoluble particles may
be difficult to detect. Indeed, a similar effect has been noted in pyridine and in
tf-dichlorobenzene as well as in a variety of other (supposedly) good polar solvents. Whatever the solvent of choice, care must be taken to ensure compete
solubility of the solute, otherwise anomalous data will be produced that bear little
relationship to accuracy and precision.
As a consequence of the consideration of these effects, a molecular weight
of petroleum asphaltenes that is in excess of 2500 is questionable and the true
molecular weight is likely to be lower (Speight, 1999).
In the author's experience, pyridine and nitrobenzene have proven to be adequate
solvents for molecular weight determination, subject to a thorough premeasurement check showing the lack of any insolubility, and probably provide the best
indicator of the aggregation number for asphaltenes.
However, as a final word to this section, caution is advised in the use of nitrobenzene. Raising the temperature when nitrobenzene is used as the solvent is
not without some risk. In the author's experience, having the probe fly past one's ear
because of the nitrobenzene deciding to expand uncontrollably (explode) under the
conditions of the experiment resulting in the probe being launched violently is not
for the faint hearted! It can be quite a stimulant (not recommended) to the heart rate!
Freezing Point Depression
Many methods exist for determination of the molecular weight of petroleum fractions (Speight et al., 1985; Speight, 1999 and references cited therein). Most of
the early molecular weight determinations on hydrocarbon oils used simple forms
of the cryoscopic (freezing point depression) method (ASTM D-2224).
The average molecular weight of petroleum hydrocarbon mixtures is used in
characterization and correlation studies (Speight, 1999). Also, molecular weight
is used for heat exchange evaluations of distillation columns and for monitoring
the progress of cracking processes.
? SAMPLE
Figure 12.3. Apparatus for molecular weight determination by freezing point depression.
This method using the concept of freezing point depression determines the average molecular weight of various fractions with simple equipment (Fig. 12.3).
The samples must be completely soluble and chemically inert in the solvent (benzene). Molecular weight values represent a number-average molecular weight for
the sample components.
The freezing points for benzene and for a benzene solution containing a known
weight of sample are determined from their cooling curves. From the depression
of the freezing point by the sample, the average molecular weight is calculated
by application of Raoult's law, which states that the vapor pressure lowering of a
solvent is directly proportional to the concentration of the solute:
(Po ~ p)/Po = n2/(nx + H2)
where ^i and n2 are the number of moles of solvent and solute, respectively. Thus,
if W2 g of solute of molecular weight M2 is dissolved in w i g of solvent of molecular
weight Mi, Raoult's law gives:
(Po ~ P)/Po = (W2ZM2)Z(WiM1 + W2M2)
For a dilute solution, n2 may be neglected in favor of n\.
Thus the calculation for molecular weight determination by cryoscopy is:
M = [W(Kf-AT)]/(ATS)
where M is the number average molecular weight, W is the weight of the sample in
grams, Kf is the cryoscopic constant for the solvent (Kf for benzene = 65.6), AT
is the freezing point depression in0 C (i.e., the freezing point of benzene minus the
freezing point of the solution), and S is the moles of solvent. Many solvents have
been tried, but with the best technique an accuracy of 1-2% is to be considered
Boiling Point Elevation
Boiling point elevation (ebullioscopic) methods (Jones and Moote, 1963) are, in
general use, more rapid and equally accurate but tend to fall short when applied
to the higher molecular weight fractions of petroleum, heavy oil, and bitumen.
Molecular weights in the low range (<500) are readily determined by vapor-density
For decades, and even now, of the best-established methods for the determination of the molecular weight of oil fractions boiling above 2500C (4800F) the
measurement of boiling point elevation (ebullioscopic method) has been preferred
(van Nes and van Westen, 1951).
For any one sample, the boiling point elevation is determined at a series of concentrations of solute. Such determinations were carried out in practice by comparing the boiling point of pure solvent, measured in an ebulliometer, with the boiling
points, determined in a second ebulliometer, of a series of solutions prepared by
adding successive portions of the sample to the solvent. The first ebulliometer
serves as the control experiment.
To determine the ebullioscopic constant K, which depends not only on the
solvent used but also to a certain extent on the construction of the apparatus and the
procedure followed, a series of determinations is carried out on a pure hydrocarbon
of known molecular weight, preferably of the same order of magnitude as the
molecular weight under investigation. The ebullioscopic constant calculated for
each concentration is plotted on a graph, just as in the case of a molecular weight
determination, and is extrapolated to zero concentration.
Before attempting to measure molecular weights, care should be taken to ensure
that the oil sample does not contain water or volatile components (boiling below
2000C, 392F), because this would invalidate the basic calculation.
These methods all give number average molecular weights, defined by:
E(/iiMi)/Sni = Mn
where Mn is the number average molecular weight and nx is the number of
molecules having a molecular weight M1.
12.2 A.
Size Exclusion Chromatography
There is a method for determining the molecular weight of petroleum, heavy
oil, bitumen, and their constituent fractions using size exclusion (gel permeation)
chromatography (ASTM D-3593).
The principle of size exclusion chromatography (Chapter 10) is the exclusion
of larger sample molecules from smaller pores in the packing. As a result, larger
molecules cannot reside in the entire column volume but are restricted to smaller regions. In the extreme, the largest molecules are restricted to the interstitial volume,
that is, the space between particles, whereas the smallest ones can penetrate the
entire open column volume, that is, the interstitial and all the pore volume. As a
consequence, the large molecules elute first and the smallest ones last.
However, when the samples contain polar functions (as do resin and asphaltenes
constituents), two complications can arise:
Solute-solute or solute-solvent interaction can result in the formation of larger
particles,and thus part, or all, of the sample elutes earlier than it should.
Adsorption of the solute on the column packing can cause all or part of the
solute to elute later than it should.
Adsorption of the solute on the column packing has continued to have an adverse
effect on the study of asphaltene molecular weights by this method, and permanent
damage to the packing has also been observed (Altgelt and Gouw, 1979). Polynuclear aromatic species have a tendency to adsorb strongly on various adsorbents,
but mixed solvents containing small amounts of a strongly polar component, such
as pyridine, can help resolve much of the adsorption problem.
For the higher-molecular-weight petroleum fractions, such as asphaltenes, column packings of nominal pore sizes between 50-100 and 5000-10,000 A are
used for complete resolution. The bimodal column combinations give good linear calibration curves, and well-characterized polymer samples as well as narrow
polymer fractions, for example, polystyrenes, are available for calibrating column
sets across the entire molecular weight range.
However, these polymers are structurally different from petroleum constituents
and cannot be directly used for accurate calibration. In fact, petroleum fractions,
such as the resin fraction and the asphaltene fraction, differ from polymers in
three ways: (1) the hydrocarbon skeletal structure; (2) the polar nature; and (3) the
varying composition with molecular weight. Therefore, it is preferable to use a
set of narrow subfractions obtained by preparative size exclusion chromatography
from the same or a similar petroleum fraction for calibration. Calibration curves
obtained by polymers should at least be checked with such subfractions and adjusted as necessary.
However, there are disadvantages in the attempt to establish the correct calibration curve for high-molecular-weight petroleum fractions (Reerink and Lijzenga,
1975). The use of petroleum subfractions can be misleading because they are
usually too broad; and in samples with broad distributions, the number average
molecular weight may be quite different from the peak molecular weight. Thus a
good approximation is a calibration curve based on narrow polystyrene fractions
or single compounds and multiplied by a factor of 1.5 across the entire molecular
weight range.
Above all, it is important to remember that size exclusion chromatography
separates by molar volume rather than by molecular weight. The method will,
therefore, differentiate by structure in addition to molecular weight.
Errors may also arise from changes in the response factor with increasing elution
volume. The reason is that petroleum components of different molecular weights
also have different compositions. Ultraviolet detectors respond primarily to differences in aromaticity and the degree of aromatic ring condensation. Refractive index
detectors are affected by color intensity, light scattering by very high-molecularweight aggregates, and also by the change in composition. All must be given due
consideration when data interpretation is undertaken. In solutions of asphaltenes,
the molecules are aggregated in clusters but the cluster may dissociate in very
dilute solutions where the solvents have a degree of polarity. Thus, using the polar
solvent, it may be possible to obtain a true molecular solution, as seems to be the
case when nitrobenzene is used for molecular weight determination by vapor pressure osmometry. However, depending on the nature of the asphaltene constituents
and the solvent, the dissociation process may not be complete and assumptions of
single molecular species may be in error. In addition, the adsorption of the species
in the packing must not be underestimated.
In principle, size exclusion chromatography is a very powerful method for separating petroleum fractions by molecular weight. It is used frequently in petroleum
analysis despite the components tendency to participate in adsorption and aggregation, and other potential problems.
Nonfragmenting mass spectrometry is nearly ideal for petroleum distillates. It
provides a wealth of detail by giving the hydrocarbon types, the formulae, and the
concentration of practically all of the components in a fraction (Chapter 7). From
these data, the molecular weight distribution and the number average molecular
weight can be obtained.
The main mass spectrometric (MS) methods for high-molecular-weight petroleum fractions are field ionization mass spectrometry (FIMS) and field desorption
mass spectrometry (FDMS). These are also called nonfragmenting methods because they produce the parent ion spectra that show only the nonfragmented
molecules. However, whether this is true for asphaltenes constituents is still under
The low volatility of the constituents of the resin fraction and the asphaltene
fraction is a major drawback, although application of the technique to those species
boiling up to the limit of short-path distillation temperatures, that is, to 7050C
(13000F) might be cited in support of the technique. However, the estimated high
boiling range of asphaltene constituents (Chapter 9) may negate application of the
technique to these molecular species.
Petroleum fractions typically gave symmetrical mass spectrometric molar mass
profile (molecular weight distribution) up to a limit of about 2000. However, the
ionization sensitivity changes with molar mass and molecular structure. This molar
mass discrimination can severely impair the application of mass spectrometry to
broad petroleum fractions.
Thus, because of the compositional diversity of the fractions and the differences
in ion sensitivity among alkanes, aromatics, and polar compounds, the actual distribution may be quite different from the mass profile. Therefore, symmetry is uncertain and a quantitative evaluation would be very questionable. Indeed, because
of volatility constraints, quantitative evaluation of the constituents of an asphaltene
fraction would be extremely questionable.
12.2.6. Nuclear Magnetic Resonance Spectroscopy
Nuclear magnetic resonance (NMR) spectroscopy has been suggested to be used
for measuring molecular weight without the limitations incurred by other methods
(see above).
The approach is based on the determination of substituted and total aromatic
carbon atoms per molecule. However, just like the nuclear magnetic resonance
method for structure determination (Chapter 11), there are many assumptions because of the complex nature of asphaltene samples, and these assumptions are
subject to inaccuracy and question. At best, one can hope for minimum and maximum values with a large spread between the minima and the maxima.
It is feared that because of the assumptions, the method becomes little more
than optimistic mathematical manipulation.
MOLECULAR WEIGHTS OF VOLATILE FRACTIONS
Petroleum is not a uniform material because the proportions of the various chemical
constituents can vary not only with the location and age of the oil field but also
with the depth of the individual well. However, on a molecular basis, petroleum
is a complex mixture of hydrocarbons plus organic compounds of sulfur, oxygen,
and nitrogen, as well as compounds containing metallic constituents, particularly
vanadium nickel, iron, and copper. The hydrocarbon content may be as high as
97%, for example, in the lighter paraffinic crude oils, or as low as 50% or less as
illustrated by the heavier asphaltic crude oils. Nevertheless, crude oils with as little
as 50% hydrocarbon components are still assumed to retain most of the essential
characteristics of the hydrocarbons.
The molecular weights of the volatile fractions are determined by one of the
three methods prescribed for the task. Depending upon the feedstock, the range of
molecular weight can vary from approximately 100 to 500. Association effects are
minimal and usually do not occur. Thus the molecular weights for volatile fractions
as determined are considered to be the true molecular weights of the fractions.
12.4. MOLECULAR WEIGHTS OF NONVOLATILE FRACTIONS
The molecular weights of resin fractions (Table 12.1) are substantially lower than
those of asphaltenes and do not usually vary, except for the limits of experimental error, with the nature of the solvent or the temperature of the determination. It may therefore be presumed that the molecular weights of resins, as
determined by various methods, are in fact true molecular weights and that forces
that result in intermolecular association contribute very little, if anything, to their
magnitude.
The asphaltene constituent of a feedstock is primarily responsible for the high
degree of variability in measured molecular weights. The polarity, aromaticity and
concentration of a given solvent and also the temperature of solution govern association to different degrees in different solvents. In addition, the nature or type
of the asphaltene plays a role in determining the degree of association. Consequently, the confidence with which the molecular weight of asphaltenes of a given
feedstock can be determined reflects the confidence in the molecular weight of
the feedstock, but it does not follow that the asphaltene constituents in their native
state in the oil are aggregated to the same degree, if at all, when in their own
maltenes.
Addition of extraneous solvents for measurement of molecular weights often initiates the aggregation process. Thus any method of measurement utilizing
a solvent medium could potentially result in significant errors in the measured
molecular weight of asphaltenes. This dilemma resulted in the application of a considerable research effort to define the structure of whole feedstocks at a molecular
Table 12.1. Elemental Composition of Petroleum Resins
Elemental Composition (wt%)
7.2 trace 3.3
-4. 5 -
Atomic Ratios
Source: From Koots, J. A., and J. G. Speight, Fuel 1975, 54:182, by permission of the publisher, IPC
Business Press Ltd. .
level (Chapter 14) and to determine the conditions of measurement necessary to
obtain reliable values of molecular weights of different samples.
In fact, determining the molecular weights of asphaltenes is a major issue
because the asphaltenes constituents have a low solubility in the liquids often used
for determination. Also, adsorbed resins lead to discrepancies in molecular weight
determination, and precipitated asphaltenes should be reprecipitated several times
before the determination. Thus careful precipitation and careful choice of the
Table 12.2. Methods Used for Measurement of Asphaltene Molecular Weight
Monomolecular
Ebullioscopy
Range of Asphaltene
Molecular Weights
Up to 300,000
80,000 to 140,000
2,500 to 4,000
600 to 6,000
Cryoscopy
Light Absorption
Equal Osmotic
Equal Vapor
Winniford (1963)
Witherspoon (1958)
Ray etal. (1957)
Wales and van der Waarden (1964)
Labout(1950)
Pfeiffer and Saal (1940)
Griffin etal. (1958)
Jones and Moote (1963)
Sakhanov and Vassilieu (1927)
Katz(1934)
Hillman and Barnett (1937)
Grader(1942)
Mack (1932)
Erkert and Weetman (1947)
Fischer and Schram (1959)
Girdler(1965)
Reerink(1973)
Markhasin et al. (1969)
Neumann and Bellstedt (1966)
Altgelt (1968)
Dickson etal. (1969)
Koots and Speight (1975)
Suzuki etal. (1982)
Kirby (1943)
Lever (1934)
determination method are both very important for obtaining meaningful results
(Speight et al., 1985).
A fairly comprehensive review (Table 12.2; Moschopedis et al., 1976) followed by a study of asphaltene molecular weights by vapor pressure osmometry
has been reported and shows that the molecular weights of various asphaltenes are
dependent not only on the nature of the solvent but also on the solution temperature at which the determinations were performed (Table 12.3; Moschopedis and
Table 12.3. Molecular Weights of Asphaltenes Using Vapor Pressure Osmometry
Sample Era
Upper Cretaceous
Lower Cretaceous
Carboniferous
Lower Devonian
C6H5NO2
CeH6
CH2Br2
Solvent temperature (0C). * Extrapolated value.
Source: Reproduced from Moschopedis, S. E., J. F. Fryer, and J. G. Speight, Fuel 1976, 55:228, by
permission of the publisher, IPC Business Press Ltd. .
Speight, 1976a; Moschopedis et al., 1976). Data from later work involving molecular weight determinations by the cryoscopic method (Speight and Moschopedis,
1977), however, indicate that the molecular nature of asphaltenes is not conducive
to the determination of absolute molecular weights by any one method.
Indeed, for any one particular method, the observed molecular weights suggest
that asphaltenes form molecular aggregates, even in dilute solution (Moschopedis
et al., 1976), and this association is influenced by solvent polarity, asphaltene concentration, and the temperature of the determination (Figs. 12.4 and 12.5; Speight
and Moschopedis, 1977; Speight et al., 1985; Speight, 1999). In fact, it is strongly
recommended that, to negate the concentration effects and the temperature effects,
the molecular weight determinations be carried out at each of three different concentrations at each of three different temperatures. The data for each temperature
are then extrapolated to room temperature (Fig. 12.5).
Thus the molecular weights of asphaltenes span a wide range from a few hundred
to several million, leading to speculation about self-association (Sakhanov and
Vassiliev, 1927; Mack, 1932; Katz, 1934; Lerer, 1934; Hillman andBarnett, 1937;
Pfeiffer and Saal, 1940; Grader, 1942; Kirby, 1943; Labout, 1950; Ray et al., 1957;
Griffin et al., 1959; Winniford, 1963; Wales and van der Waarden, 1964; Altgelt,
Solvent: benzene
Solvent: pyridine
Concentration, wt. %
Figure 12.4. Variation of asphaltene molecular weight with concentration and solvent.
Three different
concentrations; extrapolate
to infinite dilution
Extrapolated molecular
weights from three
different temperatures
(above)
Figure 12.5. Method for negating aggregation effect through concentration and temperature studies
in the determination of asphaltene molecular weight.
1968; Markhasin et al., 1969; Reerink, 1973; Koots and Speight, 1975; Speight
The tendency of the asphaltenes to form aggregates in hydrocarbon solution
is one of their most characteristic features and complicates the determination of
molecular weight (Winniford, 1963; Speight and Moschopedis, 1977). The average
molecular weights measured by means of vapor pressure osmometry (VPO) or size
exclusion chromatography (SEC) are significantly influenced by the conditions
of the analysis (temperature, asphaltene concentration, solvent polarity) (Altgelt,
1968; Moschopedis et al., 1976; Speight and Moschopedis, 1980; Speight, 1981;
Speight et al., 1985; Acevedo et al., 1992). For this reason, molecular weights are
reported in the literature as relative values only, and these values may be quite
different from the molecular weights of unassociated molecules.
The influence of the asphaltene concentration on the values of molecular weight
measured is significant, and it is important to use as high a dilution as possible
to measure a molecular weight that at least approaches that of the unassociated
asphaltene molecules, remembering that the asphaltene fraction is a complex mixture of different species and that any molecular weight of unassociated species
will be an average molecular weight of different chemical species.
The existence of asphaltenes aggregates in hydrocarbon solvents has been
demonstrated by means of small-angle neutron scattering (SANS) studies. The
physical dimensions and shape of the aggregates are functions of the solvent used
and the temperature of the investigation (Ravey et al., 1988; Overfield et al. 1989;
Thiyagarajan et al., 1995). In addition, surface tension measurements have been
used to study the self-association of asphaltenes in pyridine and nitrobenzene
(Sheu et al., 1992). A discontinuous transition in the surface tension as a function
of asphaltene concentration was interpreted as the critical asphaltene concentration
above which self-association occurs.
The study of asphaltene molecular weights by vapor pressure osmometry shows
that the molecular weights of various asphaltenes are dependent not only on the nature of the solvent but also on the solute concentration (Fig. 12.4) and the solution
temperature at which the determinations were performed (Table 12.4; Moschopedis et al., 1976; Speight, 1987, 1994, 1999). However, data from later work
involving molecular weight determinations by the cryoscopic method (Speight
and Moschopedis, 1977) indicate that the molecular nature of asphaltenes is not
conducive to the determination of absolute molecular weights by any one method.
For any one method, the observed molecular weights suggest that asphaltenes
form molecular aggregates, even in dilute solution, and this association is influenced by solvent polarity, asphaltene concentration, and the temperature at
which the determination is made. The precise mechanism of the association has
not been conclusively established, but hydrogen bonding and the formation of