Contents
Cover
Title page
Copyright page
Dedication
Preface
Acknowledgments
About the Author
Chapter 1: Introduction
References
Chapter 2: Composition of Crude Oils and Petroleum Products
2.1 Hydrocarbons
2.2 Aromatic Hydrocarbons
2.3 Heteroatomic Organic Compounds
2.4 Thiols
2.5 Oxygen Compounds
2.6 Nitrogen Compounds
2.7 Resins and Asphaltenes
2.8 Salts
2.9 Carbon Dioxide
2.10 Metallic Compounds
2.11 Products Composition
References
Chapter 3: Characterization of Petroleum and Petroleum Fractions
3.1 Introduction
3.2 Crude Oil Assay Data
3.3 Crude Cutting Analysis
3.4 Crude Oil Blending
3.5 Laboratory Testing of Crude Oils
3.6 Octanes
3.7 Cetanes
3.8 Diesel Index
3.9 Determination of the Lower Heating Value of Petroleum Fractions
3.10 Aniline Point Blending
3.11 Correlation Index (CI)
3.12 Chromatographically Simulated Distillations
References
Chapter 4: Thermodynamic Properties of Petroleum and Petroleum Fractions
4.1 K-Factor Hydrocarbon Equilibrium Charts
4.2 Non-Ideal Systems
4.3 Vapor Pressure
4.4 Viscosity
4.5 Refractive Index
4.6 Liquid Density
4.7 Molecular Weight
4.8 Molecular Type Composition
4.9 Critical Temperature, T
c
4.10 Critical Pressure, P
c
4.11 Pseudo-Critical Constants and Acentric Factors
4.12 Enthalpy of Petroleum Fractions
4.13 Compressibility Z Factor of Natural Gases
4.14 Simulation Thermodynamic Software Programs
References
Chapter 5: Process Descriptions of Refinery Processes
5.1 Introduction
5.2 Refinery and Distillation Processes
5.3 Process Description of the Crude Distillation Unit
5.4 Process Variables in the Design of Crude Distillation Column
5.5 Process Simulation
5.6 Process Description of Light Arabian Crude Using UniSim
®
Simulation Software [12]
5.7 Troubleshooting Actual Columns
5.8 Health, Safety and Environment Considerations
References
Chapter 6: Thermal Cracking Processes
6.1 Process Description
6.2 Steam Jet Ejector
6.3 Pressure Survey in a Vacuum Column
6.4 Simulation of Vacuum Distillation Unit
6.5 Coking
6.6 Fluid Coking
6.7 Fractionator Overhead System
6.8 Coke Drum Operations
6.9 Hydraulic Jet Decoking
6.10 Uses of Petroleum Coke
6.11 Use of Gasification
6.12 Sponge Coke
6.13 Safety and Environmental Considerations
6.14 Simulation/Calculations
6.15 Visbreaking
6.16 Process Simulation
6.17 Health, Safety and Environment Considerations
References
Chapter 7: Hydroprocessing
7.1 Catalytic Conversion Processes
7.2 Feed Specifications
7.3 Feed Boiling Range
7.4 Catalyst
7.5 Poor Gas Distribution
7.6 Poor Mixing of Reactants
7.7 The Mechanism of Hydrocracking
7.8 Thermodynamics and Kinetics of Hydrocracking
7.9 Process Design, Rating and Performance
7.10 Increased ΔΡ
7.11 Factors Affecting Reaction Rate
7.12 Measurement of Performance
7.13 Catalyst-Bed Temperature Profiles
7.14 Factors Affecting Hydrocracking Process Operation
7.15 Hydrocracking Correlations
7.16 Hydrocracker Fractionating Unit
7.17 Operating Variables
7.18 Hydrotreating Process
7.19 Thermodynamics of Hydrotreating
7.20 Reaction Kinetics
7.21 Naphtha Hydrotreating
7.22 Atmospheric Residue Desulfurization
7.23 Health, Safety and Environment Considerations
References
Chapter 8: Catalytic Cracking
8.1 Introduction
8.2 Fluidized Bed Catalytic Cracking
8.3 Modes of Fluidization
8.4 Cracking Reactions
8.5 Thermodynamics of FCC
8.6 Process Design Variables
8.7 Material and Energy Balances
8.8 Heat Recovery
8.9 FCC Yield Correlations
8.10 Estimating Potential Yields of FCC Feed
8.11 Pollution Control
8.12 New Technology
8.13 Refining/Petrochemical Integration
8.14 Metallurgy
8.15 Troubleshooting for Fluidized Catalyst Cracking Units
8.16 Health, Safety and Environment Considerations
8.17 Licensors’ Correlations
8.18 Simulation and Modeling Strategy
References
Chapter 9: Catalytic Reforming and Isomerization
9.1 Introduction
9.2 Catalytic Reforming
9.3 Feed Characterization
9.4 Catalytic Reforming Processes
9.5 Operations of the Reformer Process
9.6 Catalytic Reformer Reactors
9.7 Material Balance in Reforming
9.8 Reactions
9.9 Hydrocracking Reactions
9.10 Reforming Catalyst
9.11 Coke Deposition
9.12 Thermodynamics
9.13 Kinetic Models
9.14 The Reactor Model
9.15 Modeling of Naphtha Catalytic Reforming Process
9.16 Isomerization
9.17 Sulfolane Extraction Process
9.18 Aromatic Complex
9.19 Hydrodealkylation Process
References
Chapter 10: Alkylation and Polymerization Processes
10.1 Introduction
10.2 Chemistry of Alkylation
10.3 Catalysts
10.4 Process Variables
10.5 Alkylation Feedstocks
10.6 Alkylation Products
10.7 Sulfuric Acid Alkylation Process
10.8 HF Alkylation
10.9 Kinetics and Thermodynamics of Alkylation
10.10 Polymerization
10.11 HF and H
2
SO
4
Mitigating Releases
10.12 Corrosion Problems
10.13 A New Technology of Alkylation Process Using Ionic Liquid
10.14 Chevron – Honeywell UOP Ionic liquid Alkylation
10.15 Chemical Release and Flash Fire: A Case Study of the Alkylation Unit at the Delaware City Refining Company (DCRC) Involving Equipment Maintenance Incident.
References
Chapter 11: Hydrogen Production and Purification
11.1 Hydrogen Requirements in a Refinery
11.2 Process Chemistry
11.3 High-Temperature Shift Conversion
11.4 Low-Temperature Shift Conversion
11.5 Gas Purification
11.6 Purification of Hydrogen Product
11.7 Hydrogen Distribution System
11.8 Off-Gas Hydrogen Recovery
11.9 Pressure Swing Adsorption (PSA) Unit
11.10 Refinery Hydrogen Management
11.11 Hydrogen Pinch Studies
References
Chapter 12: Gas Processing and Acid Gas Removal
12.1 Introduction
12.2 Diesel Hydrodesulfurization (DHDS)
12.3 Hydrotreating Reactions
12.4 Gas Processing
12.5 Sulfur Management
12.6 Physical Solvent Gas Processes
12.7 Carbonate Process
12.8 Solution Batch Process
12.9 Process Description of Gas Processing using UniSim
®
Simulation
12.10 Gas Dryer (Dehydration) Design
12.11 Kremser-Brown-Sherwood Method-No Heat of Absorption [14]
12.12 Absorption: Edmister Method
12.13 Gas Treating Troubleshooting
12.14 Cause – Loss of Glycol Out of Still Column
12.15 The ADIP Process
12.16 Sour Water Stripping Process
References
Glossary of Petroleum and Technical Terminology
Appendix A: Equilibrium K values
Appendix B: Analytical Techniques
B.1 Useful Integrals
B.2 General and Trigonometric Functions
B.3 Liebnitz’s Rule – Higher Derivatives of Products
B.4 Definition of a Derivative
B.5 Product Rule
B.6 Quotient Rule
B.7 Chain Rule
B.8 Exponential / Logarithmic Functions
B.9 Taylor’s and Maclaurin’s Theorems
B.10 Differential Equations
B.11 Linear Equations
B.12 Exact Differential Equation
B.13 Homogeneous Second Order Linear Differential Equation with Constant Coefficients
B.14 Table Of Laplace Transform
B.15 CUBIC EQUATIONS
Appendix C: Physical and Chemical Characteristics of Major Hydrocarbons
Appendix D: A List of Engineering Process Flow Diagrams and Process Data Sheets
Index
End User License Agreement
Guide
Cover
Copyright
Table of Contents
Begin Reading
List of Illustrations
Chapter 1
Figure 1.1
Quarterly global demand outlook 2014 – 2015 (Source: Gelder, Alan, pp 25.
Hydrocarbon Processing,
February 2015 [4]).
Figure 1.2
Regional gross refining margins, US$/bbl. (Source: Gelder, Alan,
Hydrocarbon Processing,
pp 25, February 2015 [4]).
Figure 1.3
World oil reserves. (Source: OPEC Annual Statistical Bulletin, 2012).
Figure 1.4
Refining flow scheme (source: UOP – A Honeywell Co.)
Figure 1.5
Petrochemical flow scheme (Source: UOP – A Honeywell Co.)
Chapter 2
Figure 2.1
Classification of hydrocarbons.
Figure 2.1a
Straight chain hydrocarbon compounds.
Figure 2.2
Branched chain aliphatic compounds.
Figure 2.3
Naphthenes.
Figure 2.4
Benzene ring illustrated in Kekule’s formula.
Figure 2.5
Aromatics.
Figure 2.6
Structural formulas of xylene.
Figure 2.7
Substitution by other aromatics.
Figure 2.8
Substitution by a naphthenic ring.
Figure 2.9
Poly nuclear aromatic hydrocarbons.
Figure 2.10
Reactions of hydrocarbon sulfur compounds with hydrogen
Figure 2.11
Relationship of nitrogen content of crude oils to °API gravity.
Figure 2.12
Reactions of nitrogen compounds with hydrogen.
Figure 2.13
Principal petroleum products with carbon numbers and boiling ranges.
Chapter 3
Figure 3.1
Plots of °API, Pounds per cu ft. and Pounds per U.S. gal vs. specific gravity (Source: API Technical Data Book).
Figure 3.2
Specific Gravity of Petroleum Fractions. Used by permission,
Gas Processors Suppliers Association Book Data,
12
th
ed., v.1 and 2 (2004).
Figure 3.3
Snapshot of liquid volume (%) vs. Temperature (°C) of TBP and ASTM D86 plots of distillation blend (Courtesy of Honeywell UniSim software, Honeywell (R) and UniSim (R) are registered trademarks of Honeywell International Inc.).
Figure 3.4
Snapshot of liquid volume (%) vs. Temperature (°C) of TBP, ASTM D86, D86 (Crack reduced), ASTM D1160 (Vac), ASTM D1160 (Am) and ASTM D2887 of distillation blend (Courtesy of Honeywell UniSim software, Honeywell (R) and UniSim (R) are registered trademarks of Honeywell International Inc.).
Figure 3.5
The True Boiling Point (TBP) distillation apparatus.
Figure 3.6
Characterizing Boiling Points of Petroleum Fractions (From API Technical Data Book). Used by permission,
Gas Processing Suppliers Association Book Data,
12
th
ed., v.1 and 2. (2004).
Figure 3.6a
Correlations between MeABP SpGr and Mol. Wt.
Figure 3.7
shows the Excel plots from Tables 3.10 and 3.11 (Example 3-1a.xlsx).
Figure 3.8a
Conversion of ASTM D86 to TBP
Figure 3.8b
The relationship between ASMT D86 and TBP (Daubert’s method) for percent volume distilled.
Figure 3.9
Extrapolation of TBP curve.
Figure 3.10
Volume (%) vs. specific gravity of TBP curve.
Figure 3.11
Representation of TBP curve by pseudo-components.
Figure 3.12
ASTM distillation blending practice (Source: Parkash, R.,
Refining Processes Handbook,
Elsevier, Gulf Professional Publishing 2003).
Figure 3.13
Vapor pressures of gasolines and finished petroleum products, 1–20 psi RVP (Source: Physical and Engineering Data, Shell, January 1978).
Chapter 4
Figure 4.1
Photography of Vapor-Liquid Equilibrium apparatus.
Figure 4.2
Laboratory distillation column with controls and accessories.
Figure 4.3
Schematics of a pilot plant distillation column plates showing liquid and vapor movements (Courtesy of Armfield, U.K).
Figure 4.4a
Convergence pressures of hydrocarbons (critical locus). Used permission, Gas Processors Suppliers Association Data Book, 12th Ed., V.1 and 2 (2004), Tulsa, Okla.
Figure 4.4b
Pressure vs. K for Methane (CH4) at convergence pressure of 3000 psia (20700kPa). Used by permission, Gas Processors Suppliers Association Data Book, 12th Ed., V. 1 and 2 (2004), Tulsa, Okla.
Figure 4.4c
Pressure vs. K for n-Pentane (n-C5H12) at convergence pressure of 3000 psia (20700 kPa). Used by permission, Gas Processors Suppliers Association Data Book, 12th Ed., V. 1 and 2 (2004), Tulsa, Okla.
Figure 4.4d
Pressure vs. K for Methane-Ethane binary. Used by permission, Gas Processors Suppliers Association Data Book, 12th Ed., V. 1 and 2, (2004), Tulsa, Okla.
Figure 4.5
(a) DePriester Charts; K-Values of light hydrocarbon systems, generalized correlations, low-temperature range. Used by permission, DePriester, C. L., The American Institute of Chemical Engineers, Chemical Eng. Prog. Ser., 49, No. 7 (1953), all rights reserved. (b) DePriester Charts; K-Values of light hydrocarbon systems, generalized correlations, high-temperature range. Used by permission, DePriester, C. L., The American Institute of Chemical Engineers, Chemical Eng. Prog. Ser., 49, No. 7 (1953), all rights reserved. (c) Modified DePriester Chart (in S.I. units) at low temperature (D. B. Dadyburjor, Chem. Eng. Prog., 85, April 1978; copyright 1978, AIChE; reproduced by permission of the American Institute of Chemical Engineers). (d) Modified DePriester Chart (in S.I. units) at high temperature (D. B. Dadyburjor, Chem. Eng. Prog., 85, April 1978; copyright 1978, AIChE; reproduced by permission of the American Institute of Chemical Engineers).
Figure 4.6
Cox chart vapor pressure plots. (Source: A. S. Foust
et al.,
Principles of Unit Operations, Wiley New York, p550, 1960). (a) Low-temperature vapor for light hydrocarbons. Used by permission, Gas Processors Suppliers Association Data Book, 12th Ed., V. 1 and 2 (2004), Tulsa, Okla. (b) High-temperature vapor for light hydrocarbons. Used by permission, Gas Processors Suppliers Association Data Book, 12th Ed., V. 1 and 2 (2004), Tulsa, Okla.
Figure 4.7
Vapor pressure of Acetone vs. temperature.
Figure 4.8
(a) Snapshot of the Excel spreadsheet for calculating the vapor-pressure using SRK method and Antoine’s Equation (Example 4.1). (b) Snapshot of the Excel spreadsheet for calculating the vapor-pressure using SRK method and Antoine’s Equation (Example 4.1). (c) Snapshot of the Excel spreadsheet for calculating the vapor-pressure using SRK method and Antoine’s Equation (Example 4.1).
Figure 4.9
A plot of ln P
vap
versus 1/T of 2,2,4 trimethyl pentane
Figure 4.10
Snapshot of liquid volume (%) vs. viscosity of petroleum blend (Courtesy of Honeywell UniSim software), Honeywell (R) and UniSim (R) are registered trademarks of Honeywell International Inc.
Figure 4.11
Kinematic viscosity-temperature chart for Kuwait crude oil and crude fractions (Source: Shell Technical Data Book).
Figure 4.12
Viscosity of hydrocarbon vapors at 760 mm Hg (Source: API Technical Data Book).
Figure 4.13
Viscosity of liquid hydrocarbons vs. temperature (Source: API Technical Data Book).
Figure 4.14
Viscosity of liquid solvents (Source: API Technical Data Book).
Figure 4.15
Hydrocarbon gas viscosity. (Adapted from Crane Technical Paper No. 410, Fig. A-5. Reproduced by courtesy of the Crane Company).
Figure 4.16
Viscosity of non-hydrocarbon vapors at 760 mm Hg (Source: API Technical Data Book).
Figure 4.17
Specific gravity of petroleum fractions (Plotted from data in J. B. Maxwell, “Crude Oil Density Curves”,
Data Book on Hydrocarbon,
D. Van Nostran, Princeton, NJ, 1957, pp. 136–154.)
Figure 4.18
Density of liq uid hydrocarbons (Source: API Technical Data Book)
Figure 4.19
Density of liquid solvents (Source: API Technical Data Book).
Figure 4.20
Density of ideal gases. (Source: API Technical Data Book)
Figure 4.21
Plots of Compressibility factor of natural gas at 60 °F, and specific gravities of between 0.5 to 0.8.
Figure 4.22
Generalized compressibility factor chart.
Figure 4.23
Snapshot of Microsoft Excel worksheet of Example 4–8.
Figure 4.24
Snapshot of the raw crude, vapor and liquid phases from Honeywell UniSim Design Suite software, (Courtesy of Honeywell Process Solutions, Calgary, Alberta, Canada), Honeywell (R) and UniSim (R) are registered trademarks of Honeywell International Inc.
Figure 4.25
Snap-shot of compositions of the raw crude and petroleum fractions from Honeywell UniSim Design Suite software, (Courtesy of Honeywell Process Solutions, Calgary, Alberta, Canada), Honeywell (R) and UniSim (R) are registered trademarks of Honeywell International Inc.
Figure 4.26
Snap-shot of Thermodynamic physical properties compositions of the raw crude liquid and vapor phases from Honeywell UniSim Design Suite software, (Courtesy of Honeywell Process Solutions, Calgary, Alberta, Canada Honeywell (R) and UniSim (R) are registered trademarks of Honeywell International Inc.).
Figure 4.27
Flow chart to select the bestthermodynamic model. The abbreviation BIP is used to mean binary interaction parameters (Source: Elliot, J.R., and Carl, T. Lira, Introductory Chemical Engineering Thermodynamics, Prentice Hall Int. Series, 1999).
Chapter 5
Figure 5.1
Basic refinery operations of topping, vacuum distillation, thermal cracking, catalytic reforming and catalyticcracking.
Figure 5.2
Types of refinery processin. (a) Topping or skimming processing (catalytic reforming), (b) Cracking processing (vacuum distillation and catalytic cracking) and (c). Lubricating oil processing (solvent treating and dewaxing).
Figure 5.3
Boiling range of refinery products (31.7 °API Texas mixed-base crude oil) (Source: Nelson, W. L.,
Petroleum Refinery Engineering,
4
th
ed., McGraw-Hill Series in Chemical Engineering, 1958).
Figure 5.4
Flow diagram of a refinery facility for light oils (mainly gasoline, kerosene and distillates).
Figure 5.5
Process flow diagram of a refinery facility.
Figure 5.6
Overall flow diagram of a typical refinery facility.
Figure 5.7
(a) Photograph of a refinery with fractionating columns, associated piping and ancillary equipment. (b) Photograph of the naphtha stabilizer column equipped with two vertical reboilers in the crude distillation unit.
Figure 5.8
Atmospheric crude column with pumparound and pumparound reflux.
Figure 5.9
Two-stage desalter.
Figure 5.10
(a) An electrostatic desalter (Source: Ptak,
et al.
[4]). (b) Process & Instrument (P &ID) flow diagram of crude charge preheating, desalting and secondary preheating.
Figure 5.11
(a) Typical atmospheric crude distillation unit. (b) Pump back reflux. (c) Pump around reflux.
Figure 5.11
(d) A pumparound or circulating internal reflux. (e) Ways of removing heat from a tower. (f) Pumparound trays do fractionate (Source: Lieberman, N. P., and Lieberman, E. T [16]). (g) The incipient flood point (Source: Lieberman, N. P., and Lieberman, E. T [16]).
Figure 5.12
Crude column overhead arrangement.
Figure 5.13
A photograph showing the crude distillation column, a pre-flash vessel and pre-heater shell and tube heat exchangers in series.
Figure 5.14
True Boiling Point and cut point.
Figure 5.15
ASTM gap.
Figure 5.16
Gap and overlap (Source; Ptak
et al.
[3]).
Figure 5.17
F-factor and ASTM gaps [8].
Figure 5.18
Overall tray efficiencies: Refinery columns correlation of Drickamer and Bradford [10].
Figure 5.19
Overall tray efficiencies–Correlation of O’Connell [11].
Figure 5.20
True boiling point distillation-Arab Extra Light 36.7.
Figure 5.21
Snapshot of process flow diagram of the crude distillation unit (Courtesy of UniSim Design R443, Honeywell Process Honeywell (R) and UniSim (R) are registered trademarks of Honeywell International Inc.).
Figure 5.22
A snapshot of crude distillation unit with pumparounds and side strippers (Courtesy of UniSim Design R443, Honeywell Process Solutions, Honeywell(R) and UniSim(R) are registered trademarks of Honeywell International Inc.).
Figure 5.23
Temperature vs. tray position from top.
Figure 5.24
Pressure vs. tray position from top.
Chapter 6
Figure 6.1
Wet and dry vacuum units (Source: Keas, Gerald L., Refinery Process Modeling-
A Practical Guide to Steady State Modeling of Petroleum Processes,
1
st
ed., The Athens Printing Company, Athens, Georgia, 2000).
Figure 6.2
Process flow diagram of the vacuum distillation unit.
Figure 6.3
A convergent-divergent steam jet (Source: Norman P. Lieberman and Elizabeth T. Lieberman,
A Working Guide to Process Equipment,
McGraw-Hill Companies, Inc., 2008).
Figure 6.4
A schematic of high vacuum unit.
Figure 6.5
Vacuum unit feed and True Boiling Point distillations (Source: Keas, Gerald L.,
Refinery Process Modeling – A Practical Guide to Steady State Modeling of Petroleum Processes,
1
st
ed., The Athens Printing Company, Athens, Georgia, 2000).
Figure 6.6
Process flow diagram of vacuum distillation unit. CW = cooling water, OVHD = overhead. (Source: Surinder Parkash,
Refining Processes Handbook,
Gulf Professional Publishing, 2003).
Figure 6.7
A photograph of the mild vacuum column, crude distillation tower with associated pumps, accumulators and piping.
Figure 6.7a
A typical vacuum column (Source: Norman P. Lieberman,
Troubleshooting Process Operations,
2
nd
ed., PennWell, 1985).
Figure 6.7b
Pressure survey in troubleshooting high flash-zone pressure (Source: Norman P. Lieberman,
Troubleshooting Process Operations,
2
nd
ed., PennWell, 1985).
Figure 6.8
Process flow diagram of the delayed coking unit.
Figure 6.9
Process flow diagram of a typical delayed coking furnace/fractionation sections [7].
Figure 6.10
Mass balance of delayed coking.
Figure 6.11
Process flow diagram of fluidic coking unit.
Figure 6.12
Process flow diagram of flexi-coking.
Figure 6.13
Block diagram for flexicoking.
Figure 6.14
Mass balance of flexi-coking.
Figure 6.15
Coke drum system. (Source: Srikumar Koyikkal,
Chemical Process Technology and Simulation
, PHI Learning Private Ltd., Delhi, 2013).
Figure 6.16
Typical coker fractionator system (Source: Srikumar Koyikkal,
Chemical Process Technology and Simulation,
PHI Learning Private Ltd., Delhi, 2013).
Figure 6.17
Wet gas compressor separators.
Figure 6.18
A simplified closed blowdown system process flow diagram [7].
Figure 6.19
Snapshot of simulation flow diagram (Courtesy of UniSim Design R443, Honeywell Process Solutions, Honeywell (R) and UniSim (R) are trademarks of Honeywell International Inc.).
Figure 6.20
Snapshot of the Connections of the Design column Window (Courtesy of UniSim Design R443, Honeywell Process Solutions, Honeywell (R) and UniSim (R) are registered trademarks of Honeywell International Inc.).
Figure 6.21
A snapshot of the Monitor of the Design column Window (Courtesy of UniSim Design R443, Honeywell Process Solutions, Honeywell (R) and UniSim (R) are registered trademarks of Honeywell International Inc.).
Figure 6.22
Temperature vs. stage position profile of the column (Courtesy: Honeywell Process Solution, UniSim Design R433).
Figure 6.23
Pressure vs. Tray position profile of the column (Courtesy: Honeywell Process Solution, UniSim Design R433).
Figure 6.24
Process flow diagram of a visbreaker [1].
Figure 6.25
Process flow diagram of a typical visbreaker unit [9].
Figure 6.26
Process flow diagram of a typical visbreaker with vacuum flasher [9].
Figure 6.27
Process flow diagram of a combination of visbreaker and thermal cracker [9].
Figure 6.28
Mass balance of visbreaking.
Chapter 7
Figure 7.1
Role of the hydrocracker in the refinery (Source: Fahim, M. A.,
et al., Fundamentals of Petroleum Refining,
Elsevier 2010).
Figure 7.2
Classification of hydrocracking catalyst (Source: Secherzer, J., and A. J. Gruia,
Hydrocracking Science and Technology,
Marcel Dekker, New York, 1996).
Figure 7.3
Temperature rise at different times in a bed of catalyst that is subject to sintering.
Figure 7.4
Variation of temperature profile with time for the poisoning of low temperature shift catalyst. A front slowly progresses through the reactor.
Figure 7.5
Flow through a plug flow system.
Figure 7.6
Sherzer and Gruia (Source:
Hydrocracking Science and Technology,
Marcel Dekker, New York 1996).
Figure 7.7
Schematic representation of the process steps for design of catalytic reactors (Source: Martyn V. Twigg,
Catalyst Handbook,
2
nd
ed., Mason Publishing Ltd., 1996).
Figure 7.8
Relationship between ΔΡ and gas linear velocity.
Figure 7.9
Design dimensions of catalyst vessels.
Figure 7.10
Profiles of Conversions and pressure drop against Catalyst weight.
Figure 7.11
Reaction rate constants for the decomposition of hydrocarbons and petroleum fractions into various products (Source: W. L. Nelson,
Petroleum Refinery Engineering,
4
th
ed., McGraw-Hill Series in Chemical Engineering, 1958).
Figure 7.12
Relative rates of reactions under hydrocracking conditions (Source: Filimonov, A. V.,
et al.
The rates of reaction of individual groups of hydrocarbons in hydrocracking,
Int. Chem. Eng.,
12 (1), 7521, 1972.)
Figure 7.13
Possible arrangements of thermocouple sheaths in catalyst beds. (a) single vertical thermosheath; (b) single diagonal thermosheath; (c) multiple horizontal thermosheaths. Traveling thermocouples are often used in (a) and (b).
Figure 7.14
Relationship between yields of C
5–
180 °F and 180–400 °F hydrocrackates (Source: Gary James H.,
et al., Petroleum Refining – Technology and Economics,
5
th
ed., CRC Press, Taylor & Francis Group, 2007).
Figure 7.15
Characterization factor of hydrocracker products (Source: Gary James H.,
et al., Petroleum Refining – Technology and Economics,
5
th
ed., CRC Press, Taylor & Francis Group, 2007).
Figure 7.16
Hydrogen content of hydrocarbons (Source: Gary James H.,
et al., Petroleum Refining – Technology and Economics,
5
th
ed., CRC Press, Taylor & Francis Group, 2007).
Figure 7.17
Flow diagram of a hydrocracking process with and without recycle.
Figure 7.18
Two-stage hydrocracking process.
Figure 7.19
Main reactions in the two-stage hydrocracking process.
Figure 7.20
Schematic of the two-stage hydrocracking process with a hydrotreating reactor.
Figure 7.21
Comparison of products obtained by mild and conventional hydrocracker (Source: Secherzer, J., and A. J. Gruia,
Hydrocracking Science and Technology,
Marcel Dekker, New York, 1996).
Figure 7.22
A schematic block diagram of hydrocracking unit with other processing units.
Figure 7.23
Process flow diagram of hydrocracking unit of a facility.
Figure 7.24
Typical fixed-bed downflow catalytic reactor (Source: Gary, James H.,
et al., Petroleum Refining Technology and Economics,
5
th
ed., CRC Press, Taylor & Francis Group, 2007).
Figure 7.25
1
st
stage fixed-bed hydrocracking reactor with waxy distillate as feed from VGU.
Figure 7.26
Separation by distillation from hydrocracker unit.
Figure 7.27
Schematic of hydrocracking process.
Figure 7.28
A snapshot of process flow diagram of hydrocracking simulation (Courtesy of Honeywell Process Solution, UniSim Design R443 (R) Honeywell (R) and UniSim (R) are registered trademarks of Honeywell International, Inc).
Figure 7.29
Role of hydrotreating (HT) in the refinery.
Figure 7.30
Examples of FBR, MBR, EBR and SPR for catalytic hydrotreating (Source: Jorge Ancheyta,
Modeling and Simulation of Catalytic Reactors for Petroleum Refining,
John Wiley & Sons, Inc., 2011).
Figure 7.31
Process flow diagram of hydrotreating.
Figure 7.32
General relationship between vanadium and sulfur removal for different Co-Mo catalyst (Source: Raseev, S., Thermal and Catalytic Processes in Petroleum Refining, Marcel Dekker, New York, 2003).
Figure 7.33
Thermodynamic limitations of hydrodesulfurization reactions.
Figure 7.34
Kinetic rate and thermodynamic equilibrium effects on aromatic reduction [5].
Figure 7.35
Observed and calculated percentage (%) aromatic hydrogenation at various operating conditions Arabian light gas oil (Source: Yui and Sandford [10]).
Figure 7.36
Process flow diagram of naphtha hydrotreating process.
Figure 7.37
Diesel fuel hydrotreating process.
Figure 7.38
A photograph of kerosene hydrodesulfurizer reactor with feed/effluent shell and tube heat exchangers in series.
Figure 7.39
Atmospheric residue desulfurization process.
Figure 7.40
Heavy gas oil hydrodesulfurizer reactor with feed/effluent shell and tube heat exchangers.
Figure 7.41
Schematic of Atmospheric residue desulfurization (ARDS) process.
Figure 7.42
A snapshot of process flow diagram of ARDS simulation (Courtesy of Honeywell Process Solution, UniSim Design R433), Honeywell (R) and UniSim (R) are registered trademarks of Honeywell International Inc.)
Figure 7.43
Profile of Temperature vs. Tray position of the distillation column of ARDS simulation (Courtesy of Honeywell Process Solution, UniSim Design R433).
Figure 7.44
Pressure vs. Tray position of the distillation column of ARDS simulation of ARDS simulation (Courtesy of Honeywell Process Solution, UniSim Design R433).
Chapter 8
Figure 8.1
FCC type configurations.
Figure 8.2
Role of fluid catalytic cracking in refining operation.
Figure 8.3
Schematic of FCC unit.
Figure 8.4
A schematic flow diagram of a fluid catalytic cracking unit as used in petroleum refineries. (Source: Mbeychok, : http://en.wikipedia.org/wiki/Fluid_catalytic_cracking)
Figure 8.5
(a) FCC regenerator (Source: Gary, James, H.
et al. Petroleum Refining-Technology and Economics
5
th
ed., CRC Press, Taylor & Francis Group, 2007). (b) Typical two-stage cyclone (Source: Lieberman, Norman P.,
Troubleshooting Process Operations,
2
nd
ed., PennWell Publishing Co., 1985).
Figure 8.6
(a) Example of a Model II cat cracker with enhanced RMS design internals (Source: Sadeghbeigi, Reza,
Fluid Catalytic Cracking Handbook,
3
rd
ed., Elsevier, 2012.). (b) Example of a UOP stack design FCC unit (Source: Sadeghbeigi, Reza,
Fluid Catalytic Cracking Handbook,
3
rd
ed., Elsevier, 2012.). (c) Example of a Model IV design FCC unit (Source: Sadeghbeigi, Reza,
Fluid Catalytic Cracking Handbook,
3
rd
ed., Elsevier, 2012.). Figure 8.6 (d) Example of KBR Orthoflow design FCC unit (Source: Sadeghbeigi, Reza,
Fluid Catalytic Cracking Handbook,
3
rd
ed., Elsevier, 2012.). (e) Example of a side-by-side design FCC unit (Source: Sadeghbeigi, Reza,
Fluid Catalytic Cracking Handbook,
3
rd
ed., Elsevier, 2012.). (f) Example of a UOP high-efficiency design FCC unit (Source: Sadeghbeigi, Reza,
Fluid Catalytic Cracking Handbook,
3
rd
ed., Elsevier, 2012.).
Figure 8.6
(g) Example of a flexicracker (Source: Sadeghbeigi, Reza,
Fluid Catalytic Cracking Handbook,
3
rd
ed., Elsevier, 2012.). (h) Example of the Shaw Group Inc. design FCC unit (Source: Sadeghbeigi, Reza,
Fluid Catalytic Cracking Handbook,
3
rd
ed., Elsevier, 2012.). (i) Example of Lummus Technology Inc. FCC unit (Source: Sadeghbeigi, Reza,
Fluid Catalytic Cracking Handbook,
3
rd
ed., Elsevier, 2012.)
Figure 8.7
A photograph of an FCC. (Source: http://en.wikipedia.org/wiki/Fluid_catalytic_cracking).
Figure 8.8
FCC gas plant unit.
Figure 8.9
Modes of fluidization.
Figure 8.10
Typical steps of a catalytic reaction process (Source: Froment and Bischoff [17]).
Figure 8.11
(a) Three-lump kinetic model (Source: Weekman and Nace [18]). (b) Four-lump kinetic model (Source: Fahim, M. A.,
et al.
[10]). (c). Five-lump model (Source: Ancheytta-Juarez,
et al.
[19]). (d) Seven-lump model (e.g, Maya-Yescas,
et al.
[20]).
Figure 8.12
(a) Profiles of VGO, gasoline, gas + coke vs. time. (b) Plots of VGO, gasoline, gas + coke vs. conversion.
Figure 8.13
Typical Process & Instrumentation diagram of an FCC unit. [FV = flow control valve, FT = flow transmitter, KO = knock out drum, LI = level indicator, LV = level control valve, MF = main fractionator, OVHD = overhead, PDT = pressure differential transmitter, PT = pressure transmitter, TV = temperature control valve.] (Source, Sadeghbeigi, Reza,
Fluid Catalytic Cracking Handbook,
3
rd
ed., Elsevier, 2012.)
Figure 8.14
Input and output streams for reactor and regenerator in FCC unit.
Figure 8.15
Feed classification.
Figure 8.16
Saturate content.
Figure 8.17
Gasoline selectivity vs. kinetic conversion.
Figure 8.18
Maximum conversion vs. H
2
content, %.
Figure 8.19
Maximum gasoline yield vs. correlation index.
Figure 8.20
Reactor input and output streams.
Figure 8.21
Regenerator.
Figure 8.22
Deep catalytic cracking process flow diagram (Courtesy of Stone & Webster Engineering Corporation © 1977 Stone & Webster Engineering Co.)
Figure 8.23
DCC plant petrochemicals integration. (Courtesy of Stone & Webster Engineering Corporation, © 1977 Stone & Webster Engineering Corporation).
Figure 8.24
Shell’s Fluid catalytic cracking (Source: Gulf Publishing Co., 2011).
Figure 8.25
HS-FCC unit. (Source: Gulf Publishing Co., 2011).
Figure 8.26
The Indmax FCC process (Source: Gulf Publishing Co., 2011).
Figure 8.27
ASTM D-86 distillation for the product diesel from the main fractionator (VALID -1) ([Source: Chang, Ai-Fu.,
et al.
(21)].
Figure 8.28
ASTM D-86 distillation for the product gasoline from debutanizer column (VALID-1) [Source: Chang, Ai-Fu.,
et al.
(21)].
Figure 8.29
UniSim flow diagram of the FCC unit.
Figure 8.30
A snapshot of process flow diagram of the FCC unit. (Courtesy of Honeywell Process Solution, UniSim Design R433, Honeywell (R) and UniSim (R) are registered trademarks of Honeywell International Inc.).
Figure 8.31
Profile of Temperature vs. Tray position of the distillation column of FCC simulation (Courtesy of Honeywell Process Solution, UniSim Design R433).
Figure 8.32
Pressure vs. Tray position of the distillation column of FCC simulation (Courtesy of Honeywell Process Solution, UniSim Design R433).
Chapter 9
Figure 9.1
Schematic of catalytic reforming process.
Figure 9.2
Catalytic reforming semi-regenerative process.
Figure 9.3
Process flow diagram of the reformer in the refinery facility.
Figure 9.4
(a) Fixed-bed UOP Platforming process. (b) Continuous catalyst regeneration (CCR) reformer, UOP Platforming process.
Figure 9.5
Typical reforming yield relationship.
Figure 9.6
Reactor types used in reforming processes.
Figure 9.7
Basic kinetic networks.
Figure 9.8
Flow diagram of PenexTM isomerization unit (Source:
Hydrocarbon Processing 2011 Refining Process Handbook
).
Figure 9.9
Thermodynamic equilibrium with and without recycle normal paraffin.
Figure 9.10
Sulfolane process concept (Source: Thomas, J. Stoodt and Antoine Negiz, Chapter 2.2. UOP Sulfolane Process, Robert A. Meyers,
Handbook of Petroleum Refining Processes,
3
rd
ed., McGraw-Hill Handbooks, 2003).
Figure 9.11
Sulfolane process flow diagram. (Source: Thomas, J. Stoodt and Antoine Negiz, Chapter 2.2. UOP Sulfolane Process, Robert A. Meyers,
Handbook of Petroleum Refining Processes,
3
rd
ed., McGraw-Hill Handbooks, 2003).
Figure 9.12
Aromatic production (Source: Indra Deo Mall,
Petroleum Refining Technology,
CBS Publishers & Distributors Pvt Ltd., 2015).
Figure 9.13
Process flow diagram of producing xylene (C
8
H
10
) aromatics.
Figure 9.14
A block diagrams of hydrodealkylation process.
Chapter 10
Figure 10.1
Typical solid catalyst (SAC) process.
Figure 10.2
Key variables that influence the design and operation of an alkylation process (Source: Mukherjee and Nehlsen,
Hydrocarbon Processing
[4]).
Figure 10.3
Block diagram of sulfuric acid (H
2
SO
4
) alkylation process.
Figure 10.4
Conventional sulfuric acid alkylation process.
Figure 10.5
Auto-refrigeration sulfuric acid alkylation unit.
Figure 10.6
Stratco contactor.
Figure 10.7
A block diagram of AlkyClean process.
Figure 10.8
UOP HF alkylation process (Feed: butene).
Figure 10.9
Process flow diagram of alkylation using UOP solid phosphoric acid.
Figure 10.10
Photograph of an Alkylation unit (Source: www.phxequip.com/Multimedia/images/plant/original/refinery-alkylation-unit-390.jpj. All rights reserved.).
Figure 10.11
Effect of dilution ratio d on conversion for different equilibrium constants (K
xeq
).
Figure 10.12
Polymerization process for polygasoline.
Figure 10.13
Process flow diagram of composite ionic liquid Alkylation (CILA).
Figure 10.14
Simplified process flow diagram of depropanizer caustic wash system (Source: csb.gov).
Figure 10.15
20-foot replacement piping (Source: csb.gov).
Figure 10.16
Original isolation plan shown in red (Source: csb.gov).
Figure 10.17
Expanded isolation plan shown in red (Source: csb.gov).
Figure 10.18
Photography of drain pipes associated with DCRC incident (Source: csb.gov).
Figure 10.19
Diagram (not to scale) of depropanizer caustic wash system and associated equipment (Source: CBS.gov).
Figure 10.20
Burner on furnace (Source: csb.gov).
Figure 10.21
Typical pump drain to Oil Water Sewer (OWS) (Source: csb.gov).
Figure 10.22
Proximity of furnace to Oil Water Sewer (Source: csb.gov).
Figure 10.23
Photograph of DCRC Alkylation unit during maintenance (Source: csb.gov)
Chapter 11
Figure 11.1
Hydrogen production from steam reforming of natural gas.
Figure 11.2
Hydrogen plant (reforming and shift conversion). H.T. = high temperature; L.T. – low temperature; B.F.W = boiler feed water.
Figure 11.3
Chemical reactions involved in hydrogen production.
Figure 11.4
Highly volatile compounds with low polarity are not adsorbed onto the adsorbent material in a pressure swing adsorption process.
Figure 11.5
Adsorption isotherms show the relationship between partial pressure of a gas molecule and its equilibrium loading on the adsorbent material at a given temperature. (Source: Keller, Tobias, and Goutam Shahani, PSA Technology: Beyond Hydrogen Purification,
Chemical Engineering,
CE Focus on Petroleum Refining & Petrochemicals, 2017).
Figure 11.6
The main process steps of a typical PSA process, including adsorption, desorption and pressure equalization. (Source: Keller, Tobias, and Goutam Shahani, PSA Technology: Beyond Hydrogen Purification,
Chemical Engineering,
CE Focus on Petroleum Refining & Petrochemicals, 2017).
Figure 11.7
A hydrogen consumer process flow diagram.
Figure 11.8
The hydrogen composite curves.
Figure 11.9
Hydrogen pinch overview [17].
Chapter 12
Figure 12.1
Major sources of sulfur and recovery processes in refinery facility [26].
Figure 12.2
Hydrotreating process in the refinery.
Figure 12.3
Process flow diagram of diesel hydrodesulfurization unit.
Figure 12.4
Process flow diagram of diesel hydrodesulfurization with treating and upgrading reactors for diesel upgrading.
Figure 12.5
A typical Ultra-low-sulfur diesel unit (ULSD), with a fixed-bed reactor on the right.
Figure 12.6
Guide for selecting gas sweetening processes (Source: Branan, Carl, R.,
Rules of Thumb for Chemical Engineers,
Gulf Publishing Co., 1994).
Figure 12.7
Flow diagram of Merox mercaptan-extraction unit.
Figure 12.8
Fixed-bed Merox sweetening unit.
Figure 12.9
Sulfur recovery unit.
Figure 12.10
removal process.
Figure 12.11
Typical Tail gas clean-up scheme [27].
Figure 12.12
Typical gas sweetening by chemical reaction.
Figure 12.13
Process flow diagram of a gas processing unit (Courtesy, Honeywell Process Solution, UniSim Design R443, Honeywell (R) and UniSim (R) are registered trademarks of Honeywell International, Inc.)
Figure 12.14
Phase envelope of natural gas feed.
Figure 12.15
Phase envelope of natural gas feed.
Figure 12.16
Phase envelope of Sales gas.
Figure 12.17
Phase envelope of Sales gas.
Figure 12.18
A snapshot of the results from Print Datasheet sub-menu. (Courtesy of Honeywell Process Solution, UniSim Design R443, Honeywell (R) and UniSim (R) are registered trademarks of Honeywell International, Inc.)
Figure 12.19
Solid desiccant dehydrator twin tower system.
Figure 12.20
Geometry of a typical solid desiccant dryer.
Figure 12.21
Pressure drop for an 8 mesh silica gel desiccant (Source: Wunder, J. W., “How to Design a Natural Gas Drier”,
Oil & Gas Journ.,
Aug. 6, pp 137–148, 1962).
Figure 12.22
Flow diagram of absorption-stripping for hydrocarbon recovery from gaseous mixture. (Used by permission, Edmister, W. C.,
Petroleum Engr.,
Sept. (1947) to January (1948).
Figure 12.24
Empirical correlations of overall efficiencies for fractionation and absorption.
Figure 12.23
Absorption and stripping factors, E
a
or E
s
vs. effective values A
e
or S
e
(efficiency functions). Used by permission, Gas Processing Suppliers Association,
Engineering Data Book,
vol. 12, 12
th
ed., Tulsa, Oklahoma (2004).
Figure 12.25
Effective absorption and stripping factors used in absorption, stripping and fractionation as functions of effective factors. Source: Edmister, W. C.,
Petroleum Eng.
Sept., (1947) to Jan. (1948).
Figure 12.26
Component heats of absorption, Source: Hall, R. J., and K. Raymond,
Oil & Gas Journ.,
Nov. 9, (1953) thru Mar. 15 (1954).
Figure 12.27
Hydrocarbons systems, overhead gas minus lean oil temperature for components absorbed in top. “theoretical” tray (or top actual three trays.) Used by permission, Hall, R. J., and K. Raymond,
Oil & Gas Journ.
Nov. 9 (1953) thru Mar. 15 (1954).
Figure 12.28
Absorption equilibrium curve. (Source: Hutchison, A. J. L.,
Petroleum Refiner,
V. 29 (1950), p. 100, Gulf Pub. Co.)
Figure 12.29
Process flow diagram of a sour water stripping unit. (Courtesy of Honeywell Process Solution, UniSim Design R443, Honeywell (R) and UniSIm (R) are registered trademarks of Honeywell International, Inc.)
Figure 12.30
Adip Regenerators and Sour Water Strippers. (Courtesy of Honeywell UniSim Design R443, all rights reserved), Honeywell (R) and UniSim (R) are registered trademarks of Honeywell International Inc.
Figure 12.31
Snapshot of printing the results of the Sour Water Stripping unit, (Courtesy of Honeywell Process Solution, UniSim Design R443, Honeywell (R) and UniSim (R) are registered trademarks of Honeywell International Inc.)
Glossary of Petroleum and Technical Terminology
Figure 1
(a) A plot of °API vs. specific gravity of hydrocarbons compounds. (b) Specific gravity vs. °API of hydrocarbons (Source: EngineeringToolBox.com)
Figure 2
ALARP determination process overview. DEP = Design Engineering Practice.
Figure 3
Distribution of fluid energy in a pipeline.
Figure 4
The Bow-Tie – Analysis.
Figure 5
A Bubble cap tray.
Figure 6
A consequence.
Figure 7
Moody diagram.
Figure 8
Diagram of a fire triangle.
Figure 9
(a)Flow patterns for horizontal two-phase flow (Based on data from 1, 2, and 4 in. pipe by Baker, O.,
Oil & Gas J.,
Nov. 10, p. 156, 1958.). (b) Representative forms of horizontal two-phase flow patterns as indicated in Figure 9a.
Figure 10
Coal.
Figure 11
Economic efficiency of fossil fuel usage.
Figure 12
TBP and gravity – mid percent curves.
Figure 13
A hazard.
Figure 14
Diagram of a cylinder as found in 4-stroke gasoline engines.
Figure 15
Figure 16
Figure 17
Figure 18
Figure 19
Orifice Meter with Vena contracta formation.
Figure 20
Phase diagram (Phase Envelope).
Figure 21
The plus-minus principle guides process design to reduce utility consumption (Source: Smith, R. and Linnhoff, B., Trans. IChemE ChERD, 66, 195, 1988).
Figure 22
Piping and instrumentation diagram.
Figure 23
Lockhart-Martinelli two-phase multiplier.
Figure 24
Relief valve Safety valve.
Figure 25
Process flow diagram (Feed and fuel desulfurization section).
Figure 26
This new process design work process implements process integration effectively. (Source: Stephen W. Morgan, “Use Process Integration to Improve Process Designs and the Design Process”, Chemical Engineering Process, p 62, September 1992 [5]).
Figure 27
Process integration starts with the synthesis of a process to convert raw materials into desired products.
Figure 28
General service centrifugal pump.
Figure 29
General service duplex steam-driven piston pump.
Figure 30
(a) Reid vapor test gauge (b) Vapor pressure vs. temperature (c) Reid vapor pressure vs. Temperature.
Figure 31
A shell and tube heat exchanger showing the direction of flow of fluids in the shell and tube sides.
Figure 32
A sieve plate.
Figure 33
Figure 34
Symbols of chemical apparatus and equipment.
Figure 35
The Onion model (LOC = Loss of containment).
Figure 36
A threat.
Figure 37
Top event.
Figure 38
A diaphragm valve.
Figure 39
A gate valve.
Figure 40
A globe valve away section of a globe valve.
Figure 41
Plug valves Cutaway section of a plug valve.
Figure 42
A Control valve.
Figure 43
Relief valves.
Figure 44
A valve tray.
Appendix A
Figure A.1.
Pressure vs. K for nitrogen at convergence pressure of 2000 psia (13,800 kPa). Used by permission, Gas Processors Suppliers Association Data Book, 12
th
Ed., V. 1 and 2, (2004), Tulsa, Okla.
Figure A.2.
Pressure vs. K for ethane (C
2
H
6
) at convergence pressure of 3000 psia (20,700 kPa). Used by permission, Gas Processors Suppliers Association Data Book, 12
th
Ed., V. 1 and 2, (2004), Tulsa, Okla.
Figure A.3.
Pressure vs. K for propane (C
3
H
8
) at convergence pressure of 3000 psia (20,700 kPa). Used by permission, Gas Processors Suppliers Association Data Book, 12
th
Ed., V. 1 and 2, (2004), Tulsa, Okla.
Figure A.4.
Pressure vs. K for i-Butane (i–C
4
H
10
) at convergence pressure of 3000 psia (20,700 kPa). Used by permission, Gas Processors Suppliers Association Data Book, 12
th
Ed., V. 1 and 2, (2004), Tulsa, Okla.
Figure A.5.
Pressure vs. K for n-Butane (nC
4
H
10
) at convergence pressure of 3000 psia (20,700 kPa). Used by permission, Gas Processors Suppliers Association Data Book, 12
th
Ed., V. 1 and 2, (2004), Tulsa, Okla.
Figure A.6.
Pressure vs. K for i-Pentane (i–C
5
H
12
) at convergence pressure of 3000 psia (20,700 kPa). Used by permission, Gas Processors Suppliers Association Data Book, 12
th
Ed., V. 1 and 2, (2004), Tulsa, Okla.
Figure A.7.
Pressure vs. K for Hexane (C
6
H
14
) at convergence pressure of 3000 psia (20,700 kPa). Used by permission, Gas Processors Suppliers Association Data Book, 12
th
Ed., V. 1 and 2, (2004), Tulsa, Okla.
Figure A.8.
Pressure vs. K for Heptane (C
7
H
16
) at convergence pressure of 3000 psia (20,700 kPa). Used by permission, Gas Processors Suppliers Association Data Book, 12
th
Ed., V. 1 and 2, (2004), Tulsa, Okla.
Figure A.9.
Pressure vs. K for Octane (C
8
H
18
) at convergence pressure of 3000 psia (20,700 kPa). Used by permission, Gas Processors Suppliers Association Data Book, 12
th
Ed., V. 1 and 2, (2004), Tulsa, Okla.
Figure A.10.
Pressure vs. K for Nonane at convergence pressure of 3000 psia (20,700 kPa). Used by permission, Gas Processors Suppliers Association Data Book, 12
th
Ed., V. 1 and 2, (2004), Tulsa, Okla.
Figure A.11.
Pressure vs. K for Decane at convergence pressure of 3000 psia (20,700 kPa). Used by permission, Gas Processors Suppliers Association Data Book, 12
th
Ed., V. 1 and 2, (2004), Tulsa, Okla.
Figure A.12.
Pressure vs. K for Hydrogen sulphide (H
2
S) at convergence pressure of 3000 psia (20,700 kPa). Used by permission, Gas Processors Suppliers Association Data Book, 12
th
Ed., V. 1 and 2, (2004), Tulsa, Okla.
Appendix D
Figure D-1
Process flow diagram (Feed and fuel desulfurization section).
Figure D-2
Typical process flow diagram for the production of Methyl Tertiary Butyl Ether (MTBE).
Figure D-3
Piping & Instrumentation Diagram for Ammonia Plant CO2 Removal.
Figure D-4
Piping and instrumentation diagram: Ammonia synthesis and refrigeration unit.