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- Herausgeber: John Wiley & Sons
- Kategorie: Fachliteratur
- Sprache: Englisch
Provides a holistic approach that looks at changing process conditions, possible process design changes, and process technology upgrades
- Includes process integration techniques for improving process designs and for applying optimization techniques for improving operations focusing on hydroprocessing units.
- Discusses in details all important aspects of hydroprocessing – including catalytic materials, reaction mechanism, as well as process design, operation and control, troubleshooting and optimization
- Methods and tools are introduced that have a successful application track record at UOP and many industrial plants in recent years
- Includes relevant calculations/software/technologies hosted online for purchasers of the book
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Seitenzahl: 896
Veröffentlichungsjahr: 2016
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Table of Contents
Cover
Title Page
Copyright
Preface
Part 1: Fundamentals
Chapter 1: Overview of This Book
1.1 Energy Sustainability
1.2 ULSD – Important Part of the Energy Mix
1.3 Technical Challenges for Making ULSD
1.4 What is the Book Written for
References
Chapter 2: Refinery Feeds, Products, and Processes
2.1 Introduction
2.2 ASTM Standard for Crude Characterization
2.3 Important Terminologies in Crude Characterization
2.4 Refining Processes
2.5 Products and Properties
2.6 Biofuel
Chapter 3: Diesel Hydrotreating Process
3.1 Why Diesel Hydrotreating?
3.2 Basic Process Flowsheeting
3.3 Feeds
3.4 Products
3.5 Reaction Mechanisms
3.6 Hydrotreating Catalysts
3.7 Key Process Conditions
3.8 Different Types of Process Designs
References
Chapter 4: Description of Hydrocracking Process
4.1 Why Hydrocracking
4.2 Basic Processing Blocks
4.3 Feeds
4.4 Products
4.5 Reaction Mechanism and Catalysts
4.6 Catalysts
4.7 Key Process Conditions
4.8 Typical Process Designs
References
Part 2: Hydroprocessing Design
Chapter 5: Process Design Considerations
5.1 Introduction
5.2 Reactor Design
5.3 Recycle Gas Purity
5.4 Wash Water
5.5 Separator Design
5.6 Makeup Gas Compression
References
Chapter 6: Distillate Hydrotreating Unit Design
6.1 Introduction
6.2 Number of Separators
6.3 Stripper Design
6.4 Debutanizer Design
6.5 Integrated Design
References
Chapter 7: Hydrocracking Unit Design
7.1 Introduction
7.2 Single-stage Hydrocracking Reactor Section
7.3 Two-stage Hydrocracking Reactor Section
7.4 Use of a Hot Separator in Hydrocracking Unit Design
7.5 Use of Flash Drums
7.6 Hydrocracking Unit Fractionation Section Design
7.7 Fractionator First Flow scheme
7.8 Debutanizer First Flow scheme
7.9 Stripper First Fractionation Flow scheme
7.10 Dual Zone Stripper Fractionation Flow scheme
7.11 Dual Zone Stripper – Dual Fractionator Flow scheme
7.12 Hot Separator Operating Temperature
7.13 Hydrogen Recovery
7.14 LPG Recovery
7.15 HPNA Rejection
7.16 Hydrocracking Unit Integrated Design
References
Part 3: Energy and Process Integration
Chapter 8: Heat Integration for Better Energy Efficiency
8.1 Introduction
8.2 Energy Targeting
8.3 Grassroots Heat Exchanger Network (Hen) Design
8.4 Network Pinch for Energy Retrofit
Nomenclature
References
Chapter 9: Process Integration for Low-Cost Design
9.1 Introduction
9.2 Definition of Process Integration
9.3 Grand Composite Curves (GCC)
9.4 Appropriate Placement Principle for Process Changes
9.5 Dividing Wall Distillation Column
9.6 Systematic Approach for Process Integration
9.7 Applications of the Process Integration Methodology
9.8 Summary of Potential Energy Efficiency Improvements
References
Chapter 10: Distillation Column Operating Window
10.1 Introduction
10.2 What is Distillation?
10.3 Why Distillation is the Most Widely Used?
10.4 Distillation Efficiency
10.5 Definition of Feasible Operating Window
10.6 Understanding Operating Window
10.7 Typical Capacity Limits
10.8 Effects of Design Parameters
10.9 Design Checklist
10.11 Concluding Remarks
Nomenclature
References
Part 4: Process Equipment Assessment
Chapter 11: Fired Heater Assessment
11.1 Introduction
11.2 Fired Heater Design for High Reliability
11.3 Fired Heater Operation for High Reliability
11.4 Efficient Fired Heater Operation
11.5 Fired Heater Revamp
Nomenclature
References
Chapter 12: Pump Assessment
12.1 Introduction
12.2 Understanding Pump Head
12.3 Define Pump Head – Bernoulli Equation
12.4 Calculate Pump Head
12.5 Total Head Calculation Examples
12.6 Pump System Characteristics – System Curve
12.7 Pump Characteristics – Pump Curve
12.8 Best Efficiency Point (Bep)
12.9 Pump Curves for Different Pump Arrangement
12.10 Npsh
12.11 Spillback
12.12 Reliability Operating Envelope (ROE)
12.13 Pump Control
12.14 Pump Selection and Sizing
Nomenclature
References
Chapter 13: Compressor Assessment
13.1 Introduction
13.2 Types of Compressors
13.3 Impeller Configurations
13.4 Type of Blades
13.5 How a Compressor Works
13.6 Fundamentals of Centrifugal Compressors
13.7 Performance Curves
13.8 Partial Load Control
13.9 Inlet Throttle Valve
13.10 Process Context for a Centrifugal Compressor
13.11 Compressor Selection
Nomenclature
References
Chapter 14: Heat Exchanger Assessment
14.1 Introduction
14.2 Basic Concepts and Calculations
14.3 Understand Performance Criterion –
U
Values
14.4 Understand Fouling
14.5 Understand Pressure Drop
14.6 Effects of Velocity on Heat Transfer, Pressure Drop, and Fouling
14.7 Heat Exchanger Rating Assessment
14.8 Improving Heat Exchanger Performance
Nomenclature
References
Chapter 15: Distillation Column Assessment
15.1 Introduction
15.2 Define a Base Case
15.3 Calculations for Missing and Incomplete Data
15.4 Building Process Simulation
15.5 Heat and Material Balance Assessment
15.6 Tower Efficiency Assessment
15.7 Operating Profile Assessment
15.8 Tower Rating Assessment
15.9 Guidelines
Nomenclature
References
Part 5: Process System Evaluation
Chapter 16: Energy Benchmarking
16.1 Introduction
16.2 Definition of Energy Intensity for a Process
16.3 The Concept of Fuel Equivalent for steam and Power (FE)
16.4 Data Extraction
16.5 Convert All Energy Usage to Fuel Equivalent
16.6 Energy Balance
16.7 Fuel Equivalent for Steam and Power
16.8 Energy Performance Index (EPI) Method for Energy Benchmarking
16.9 Concluding Remarks
16.10 Nomenclature
References
Chapter 17: Key Indicators and Targets
17.1 Introduction
17.2 Key Indicators Represent Operation Opportunities
17.3 Define Key Indicators
17.4 Set Up Targets for Key Indicators
17.5 Economic Evaluation for Key Indicators
17.6 Application 1: Implementing Key Indicators Into an “Energy Dashboard”
17.7 Application 2: Implementing Key Indicators to Controllers
17.8 It Is Worth the Effort
Nomenclature
References
Chapter 18: Distillation System Optimization
18.1 Introduction
18.2 Tower Optimization Basics
18.3 Energy Optimization for Distillation System
18.4 Overall Process Optimization
18.5 Concluding Remarks
References
Part 6: Operational Guidelines and Troubleshooting
Chapter 19: Common Operating Issues
19.1 Introduction
19.2 Catalyst Activation Problems
19.3 Feedstock Variations and Contaminants
19.4 Operation Upsets
19.5 Treating/Cracking Catalyst Deactivation Imbalance
19.6 Flow Maldistribution
19.7 Temperature Excursion
19.8 Reactor Pressure Drop
19.9 Corrosion
19.10 HPNA
19.11 Conclusion
Chapter 20: Troubleshooting Case Analysis
20.1 Introduction
20.2 Case Study I – Product Selectivity Changes
20.3 Case Study II – Feedstock Changes
20.4 Case Study III – Catalyst Deactivation Balance
20.5 Case Study IV – Catalyst Migration
20.6 Conclusion
Index
End User License Agreement
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Guide
Cover
Table of Contents
Preface
Part 1: Fundamentals
Begin Reading
List of Illustrations
Chapter 3: Diesel Hydrotreating Process
Figure 3.1 Diesel hydrotreating cold separator flow scheme.
Figure 3.2 Diesel hydrotreating hot separator flow scheme.
Figure 3.3 Saturates (paraffin, naphthene, and olefins) and aromatic distribution.
Figure 3.4 Trends of sulfur specification change over time.
Figure 3.5 Hydrotreating catalysts shapes.
Figure 3.6 Simplified process flow diagram.
Figure 3.7 Description of two-stage process pilot plant.
Chapter 4: Description of Hydrocracking Process
Figure 4.1 Where hydrocracking fits in the refinery configuration.
Figure 4.2 Once-through process flow scheme.
Figure 4.3 Single-stage process flow scheme.
Figure 4.4 Two-stage process flow scheme.
Figure 4.5 Dual-function hydrocracking catalyst components.
Figure 4.6 Metal function.
Figure 4.7 Competing pathways for conversion of multiring aromatics.
Figure 4.8 Commonly used Y zeolite structure.
Figure 4.9 Commercial catalyst shapes.
Figure 4.10 Effect of conversion on hydrocracking performance.
Figure 4.11 Relative deactivation rate change for change in pressure.
Figure 4.12 Effect of recycle gas rate.
Figure 4.13 Advanced partial conversion hydrocracking.
Figure 4.14 Mild hydrocracking – incorporates finishing reactor in single gas and pressure loop.
Figure 4.15 One pressure loop and one recycle gas loop for cost-efficient design.
Figure 4.16 Two-stage high conversion design.
Chapter 5: Process Design Considerations
Figure 5.1 Flow map for two-phase packed bed reactor system.
Figure 5.2 Example of gravity flow distributor.
Figure 5.3 Example of vapor lift distributor.
Figure 5.4 Example of quench distributor and mixing system.
Figure 5.5 Example of good catalyst bed distribution.
Figure 5.6 Example of bad catalyst bed distribution.
Figure 5.7 Example of dense loading machine.
Figure 5.8 Example of reactor bed pressure drop buildup due to fines.
Figure 5.9 Distributor basket location.
Figure 5.10 Distributor basket orientation.
Figure 5.11 Examples of graded bed loading.
Figure 5.12 Effect of cold separator temperature on recycle gas hydrogen purity for a single separator hydroprocessing unit.
Figure 5.13 Effect of cold separator temperature on recycle gas hydrogen purity for a hydroprocessing unit with a hot separator.
Figure 5.14 Equilibrium
K
versus temperature for hydrogen, nitrogen, and selected hydrocarbons.
Figure 5.15 Enrichment flow scheme.
Figure 5.16 Effect of enrichment ratio on hydrogen purity.
Figure 5.17 Ammonium bisulfide disassociation curve.
Figure 5.18 Ammonium chloride disassociation curve.
Figure 5.19 Symmetrical piping arrangement.
Figure 5.20 Wash water circulation flow scheme.
Figure 5.21 Example of vertical three-phase separator.
Figure 5.22 Example of horizontal separator.
Figure 5.23 Clearance pocket for a reciprocating compressor.
Figure 5.24 Operation of stepless valve unloading system.
Figure 5.25 Single spillback compressor configuration.
Figure 5.26 Stagewise compressor spillback configuration.
Chapter 6: Distillate Hydrotreating Unit Design
Figure 6.1 Single separator flow scheme.
Figure 6.2 Hot separator flow scheme.
Figure 6.3 Reboiled stripper column.
Figure 6.4 Steam stripped stripper column.
Figure 6.5 Dew point monitor for steam stripped columns.
Figure 6.6 Solubility of water in
n
-octane versus temperature.
Figure 6.7 Water content of distillate product for various operating pressures.
Figure 6.8 Exchanger surface area requirements versus hot separator temperature.
Figure 6.9 Total capital + operating costs versus hot separator operating temperature.
Figure 6.10 Solution loss for a hydrotreating unit with and without a hot separator.
Figure 6.11 Hydrogen recovery without flash drums.
Figure 6.12 Hydrogen recovery with flash drums.
Figure 6.13 Heat recovery ratio (
β
) versus heater duty fraction (
Q
H
).
Chapter 7: Hydrocracking Unit Design
Figure 7.1 Single-stage hydrocracking unit.
Figure 7.2 Relation between distillate selectivity and conversion per pass.
Figure 7.3 Alternative single-stage recycle hydrocracking flow scheme.
Figure 7.4 Two-stage hydrocracking unit.
Figure 7.5 Separate hydrotreat hydrocracking unit.
Figure 7.6 Fractionator first flow scheme.
Figure 7.7 Debutanizer first fractionation flow scheme.
Figure 7.8 Composition profile for a debutanizer column in a debutanizer first flow scheme.
Figure 7.9 Stripper first fractionation flow scheme.
Figure 7.10 Composition profile for stripper column in a stripper first configuration.
Figure 7.11 TBP distillation of hot and cold flash liquid.
Figure 7.12 Dual-zone stripper fractionation flow scheme.
Figure 7.13 Dual-zone stripper dual-fractionator flow scheme.
Figure 7.14 Cold flash liquid temperature requirement versus hot separator operating temperature.
Figure 7.15 Stripping steam requirement versus hot separator operating temperature.
Figure 7.16 Reactor section exchanger surface versus hot separator operating temperature.
Figure 7.17 Total capital + operating costs versus hot separator operating temperature.
Figure 7.18 Solution loss for a hydrocracking unit.
Figure 7.19 LPG recovery flow scheme.
Figure 7.20 Overall LPG recovery versus lean oil rate.
Figure 7.21 Recycle oil sample from a high conversion hydrocracking unit.
Figure 7.22 HPNA adsorption chamber installation.
Figure 7.23 Schematic of HPNA stripping zone.
Figure 7.24 Feed and product from an HPNA stripping zone.
Figure 7.25 Reactor section flow scheme.
Figure 7.26 Light fractionation section.
Figure 7.27 Heavy fractionation section.
Chapter 8: Heat Integration for Better Energy Efficiency
Figure 8.1 Composite curves: heat demand (grey) versus heat availability (dark) profiles. (a) No heat recovery case; (b) heat recovery (hatched area).
Figure 8.2 Process flow diagram as an example of energy targeting.
Figure 8.3 (a)
T
/
H
representation of three hot streams; (b)
T
/
H
representation of a hot composite stream.
Figure 8.4 (a)
T
/
H
representation of two cold streams; (b)
T
/
H
representation of a cold composite stream.
Figure 8.5 Composite curves representing the three hot and two cold streams.
Figure 8.6 Basic concepts of composite curves.
Figure 8.7 (a) Energy targets for a specified Δ
T
min
; (b) energy targets for different Δ
T
min
.
Figure 8.8 Pinch principle: penalty of cross-pinch heat transfer.
Figure 8.9 Calculation of surface area from the composite curves.
Figure 8.10 Capital and energy trade-off.
Figure 8.11 Cost targeting for determining Δ
T
min,opt
.
Figure 8.12 General stream splitting and matching based on the composite curves.
Figure 8.13 Block decomposition.
Figure 8.14 Composite curves for the illustrative example.
Figure 8.15 Initial design for the example:
Q
H
= 139.4 kW, area = 320 m
2
, total cost =$51,188/year.
Figure 8.16 Optimized design for the example:
Q
H
= 144.3 kW, area = 289 m
2
, total cost = $46,786/year.
Figure 8.17 An illustration of a network pinch.
Figure 8.18 Process flow diagram for the crude distillation unit.
Figure 8.19 Base case heat exchanger network.
Figure 8.20 Heat recovery limits in the base case network.
Figure 8.21 Resequence of exchanger 4: min
Q
H
= 98.08; Δ
Q
Rec
= 4.4.
Figure 8.22 Heat recovery limits for the network after resequence of exchanger 4.
Figure 8.23 Stream split: min
Q
H
= 96.3; Δ
Q
Rec
= 1.8.
Figure 8.24 Retrofit design developed by the network pinch method.
Chapter 9: Process Integration for Low-Cost Design
Figure 9.1 The trend of increased refinery complexity over time.
Figure 9.2 Sequential process design: traditional design approach.
Figure 9.3 Construction of grand composite curve. (a) Composite curves. (b) Shifted composite curves. (c) Grand composite curve.
Figure 9.4 Selection of multiple utility. (a) Bad utility selection, (b) proper utility selection, (c) utility involving furnace.
Figure 9.5 Reaction integration against process. (a) Poor reaction integration. (b) Better reaction integration.
Figure 9.6 Construction of column grand composite curve. (a) Converged simulation. (b) Column grand composite. (c) Ideal column.
Figure 9.7 Column integration with process. (a) Inappropriate placement. (b) Using column modification for integration. (c) Appropriate placement.
Figure 4.8 Procedure for column integration with process. (a) Feed stage optimization. (b) Reflux modification. (c) Feed conditioning. (d) Side condensing/reboiling.
Figure 4.9 Feed stage optimization.
Figure 4.10 Thermal inefficiency in direct sequence. (a) Direct distillation sequence. (b) Component profiles for the columns.
Figure 4.11 Thermal efficiency for prefractionator arrangement. (a) Prefractionator arrangement. (b) Component profiles for the columns.
Figure 4.12 From prefractionation to dividing wall. (a) Prefractionator. (b) Thermally coupled columns (Petlyuk column). (c) Dividing wall column.
Figure 4.13 Process integration methodology.
Figure 4.14 Effects of catalyst improvements on process energy efficiency.
Figure 4.15 Single-stripper fractionation scheme.
Figure 4.16 Proposed two-stripper fractionation scheme.
Figure 7.17 Composite curves representing the single-stripper fractionation scheme.
Figure 7.18 Composite curves representing the two-stripper fractionation scheme.
Figure 7.19 Grand composite curve for the single-stripper fractionation scheme.
Figure 7.20 Grand composite curve for the two-stripper fractionation scheme.
Figure 7.21 Stacked two-stripper fractionation scheme.
Figure 7.22 Current design: single column depentanizer with sidedraw.
Figure 7.23 Dividing wall column for the depentanizer.
Figure 7.24 Existing naphtha separation for 2-naphtha products.
Figure 7.25 Typical design scheme of naphtha separation for 4-naphtha products.
Figure 7.26 Separation of three naphtha products. (a) Typical sequence of two splitter columns. (b) Dividing wall column.
Figure 7.27 Applying dividing wall to naphtha separation.
Figure 9.28 Existing hydrocracking unit.
Figure 9.29 Energy-saving projects to remove the heater bottlenecks.
Figure 9.30 Reaction and fractionation projects to remove the process bottlenecks.
Chapter 10: Distillation Column Operating Window
Figure 10.1 A complex configuration of a distillation column.
Figure 10.2 McCabe–Thiele diagram.
Figure 10.3 O'Connell correlation.
Figure 10.4 A typical trend of tower efficiency.
Figure 10.5 Capacity limits for distillation tower.
Figure 10.6 Vapor–liquid flow structure on tray deck.
Figure 10.7 Spray.
Figure 10.8 Downcomer backup flood.
Figure 10.9 Downcomer choke.
Figure 10.10 Fair's
C
F
correlation.
Figure 10.11 Key parameters for tray hydraulics (this graph is used for model illustration).
Figure 10.12 Downcomer design velocity curves in Figure 4 of Glitsch Design Manual (1974).
Figure 10.13 Maximum downcomer velocity correlation based on Glitsch's Figure 4 (1974).
Figure 10.14 Typical capacity diagram.
Figure 10.15 The flow regimes in distillation.
Figure 10.16 Tray design procedure.
Figure 10.17 Derive
A
d
from
w
d
and
r
.
Figure 10.18 Tray layout for the example problem.
Figure 10.19 Operating window for the example problem.
Chapter 11: Fired Heater Assessment
Figure 11.1 Schematic view of a typical process fired heater.
Figure 11.2 Flux profile and heat distribution in a heater.
Figure 11.3 Flux distribution around fired heater tube.
Figure 11.4 Tube thinning follows the flux distribution.
Figure 11.5 Correct and incorrect draft. (a) Proper draft control; (b) too high draft; (c) too low draft; (d) draft representation.
Figure 11.6 An example of flame impingement.
Figure 11.7 Good flame color and height.
Figure 11.8 Poor flame pattern from the first burner.
Figure 11.9 Dollar value for reducing O
2
% by 1%. *Based on fuel price at $3/MMBtu.
Figure 11.10 Optimizing excess air.
Figure 11.11 Determining optimal O
2
% level.
Figure 11.12 Integrated draft and O
2
control. (1) High draft – fire box pressure more negative; (2) low draft – fire box pressure more positive; (3) low or high O
2
% – O
2
% is above or below target.
Chapter 12: Pump Assessment
Figure 12.1 Pump head applies to any liquid (pump operating under no flow condition).
Figure 12.2 A simple process system.
Figure 12.3 A practical process system.
Figure 12.4 Illustration of Bernoulli equation (12.7).
Figure 12.5 Example 12.1 pump system curve.
Figure 12.6 Process system.
Figure 12.7 Pump system curve.
Figure 12.8 System curve for no static lift.
Figure 12.9 System curve for small friction losses.
Figure 12.10 System curve for negative static lift.
Figure 12.11 System curve for double discharges.
Figure 12.12 Pump head versus flow rate.
Figure 12.13 Pump curve for Figure 12.12.
Figure 12.14 Pump normal operating point.
Figure 12.15 Pump curve and system curve could change.
Figure 12.16 Pump curve.
Figure 12.17 Pump curves for single and two pumps in series.
Figure 12.18 Pump curves for single and two pumps in parallel.
Figure 12.19 A typical pump suction system.
Figure 12.20 NPSH
A
expressed in feet for typical pump suction.
Figure 12.21 Pump suction for Example 12.3.
Figure 12.22 Reliability operating envelope.
Figure 12.23 Two flow control options.
Figure 12.24 Optimal pump selection.
Figure 12.25 Pump curves with corresponding impeller diameters and BHP curves.
Chapter 13: Compressor Assessment
Figure 13.1 Basic principles of compressor.
Figure 13.2 Centrifugal multistage horizontal split.
Figure 13.3 Centrifugal multistage radially split compressor.
Figure 13.4 Integrally geared centrifugal compressor.
Figure 13.5 Straight-through compressor.
Figure 13.6 Back-to-back compressor with double flow inlet.
Figure 13.7 2D blades with circular arc shape (a) or 3D blades with complex shape (b).
Figure 13.8 Key components of centrifugal compressor.
Figure 13.9 Different FC impellers: from low at the left to high at the right.
Figure 13.10 Performance curve for a centrifugal compressor.
Figure 13.11 Compressor performance curves.
Figure 13.12 Impeller with higher head coefficient has a smaller rise-to-surge.
Figure 13.13 Typical variable speed control compressor performance curves.
Figure 13.14 Performance curves for inlet guide vane control with constant speed driver.
Figure 13.15 Inlet guide vane control – constant speed driver.
Figure 13.16 Typical process involving a compressor.
Chapter 14: Heat Exchanger Assessment
Figure 14.1 Location of
h
's and
R
's.
Figure 14.2 (a) Countercurrent and (b) cocurrent flows.
Figure 14.3
F
t
factor for 1–2 TEMA E shell-and-tube exchangers.
Figure 14.4 TEMA standard shell types and front and rear-end head types.
Figure 14.5 A parallel arrangement of two 1–2 exchangers.
Chapter 15: Distillation Column Assessment
Figure 15.1 Heat-pumped C3 Splitter.
Figure 15.2 Use of heat/mass balances to obtain missing data.
Figure 15.3 McCabe–Thiele diagram.
Figure 15.4 A typical trend of tower efficiency.
Figure 15.5 Example column flow profile.
Figure 15.6 Example column temperature profile for a benzene–toluene separation.
Figure 15.7 Example composition profile for toluene–ethyl benzene separation.
Chapter 16: Energy Benchmarking
Figure 16.1 Energy flows into and out of the process unit.
Figure 16.2 Energy balance in a visualized form.
Figure 16.3 Steam system for Example problem 16.1.
Chapter 17: Key Indicators and Targets
Figure 17.1 Typical single-stage hydrocracking unit.
Figure 17.2 Debutanizer column in hydrocracking unit.
Figure 17.3 Correlations of debutanizer reboiler duty and other parameters.
Figure 17.4 Two common operating patterns: (a) inconsistent operation; (b) consistent operation but nonoptimal.
Figure 17.5 Operating data: (a) historian; (b) frequency distribution.
Figure 17.6 Operation performance: (a) current operation; (b) reduced variability; (c) increased profit.
Figure 17.7 Convert time series data in Figure 17.6 into normal distribution curves: (a) current; (b) reduced variability; (c) increased profit.
Figure 17.8 Converting the normal distribution curve to economic curve.
Figure 17.9 Economic curves generated based on normal distributions.
Chapter 18: Distillation System Optimization
Figure 18.1 Debutanizer example: energy optimization based on reflux ratio.
Figure 18.2 Operating margin as a function of the bottom composition.
Figure 18.3 Observed composition normal distribution versus operating margin.
Figure 18.4 Improved composition normal distribution versus operating margin.
Figure 18.5 Energy-separation trade-off: energy cost increases linearly as reflux rate while the top product quality improves.
Figure 18.6 Optimum reflux rate depends on energy price.
Figure 18.7 Pressure has significant effect on energy cost.
Figure 18.8 Deisopentanizer flow scheme.
Figure 18.9 Variation of DIP performance.
Figure 18.10 Optimization without Isom capacity constraint.
Figure 18.11 Optimization with Isom capacity constraint.
Figure 18.12 DIP economic improvements.
Chapter 19: Common Operating Issues
Figure 19.1 Example of catalyst NABT and ABT.
Figure 19.2 Pretreat nitrogen slip on pretreat (R1) and cracking (R2) ABT.
Figure 19.3 Effect of pretreat nitrogen slip on pretreat (R1) and cracking (R2) catalyst life.
Figure 19.4 Boy scouts fire and hydroprocessing reaction triangles.
Figure 19.5 Temperature excursion simulation.
Figure 19.6 Two temperature spike excursion.
Figure 19.7 Iron sulfide fine pressure drop problem.
Figure 19.8 REAC system – balanced design.
Figure 19.9 REAC system problem areas.
Figure 19.10 PNAs and HPNAs.
Figure 19.11 Mechanism of HPNA fouling.
Figure 19.12 HPNA management.
Figure 19.13 Unconverted oil color.
Chapter 20: Troubleshooting Case Analysis
Figure 20.1 Hydrocracking operating concerns.
Figure 20.2 Product distribution of different crudes.
Figure 20.3 First-stage cracking catalyst activity loss.
Figure 20.4 Step change in cracking catalyst activity.
Figure 20.5 High-temperature simulated distillation of feedstock.
Figure 20.6 Component analysis.
Figure 20.7 Catalyst performance after diesel flush and hot hydrogen strip.
Figure 20.8 Reactor bed configuration.
Figure 20.9 Pretreat temperature performance.
Figure 20.10 Cracking temperature performance.
Figure 20.11 New ceramic support.
Figure 20.12 Broken ceramic support.
Figure 20.13 R101 migration.
Figure 20.14 R201 migration.
Figure 20.15 Reactor outlet collector.
Figure 20.16 Catalyst migration into feed/effluent exchanger.
Figure 20.17 R101 bed 4 bottoms temperatures (24 points).
Figure 20.18 R101 bed 4 mid and top temperatures (8 points).
Figure 20.19 Catalyst in another feed/effluent exchanger.
Figure 20.20 Deformed first stage outlet collector.
Figure 20.21 Outlet collector – chunks of metal missing near the junction.
List of Tables
Chapter 4: Description of Hydrocracking Process
Table 4.1 FCC and Hydrocracking Process Key Differences
Table 4.2 Nominal Operating Conditions for Typical Hydrocracking Unit
Table 4.3 Hydrocracking Feeds and Products from the Processing
Table 4.4 Product Fractions and the General Use
Table 4.5 Chemical Basis for Product Quality Measurements
Table 4.6 Hydroprocessing Reactions
Chapter 5: Process Design Considerations
Table 5.1 Flux Values for Hydroprocessing Reactors
Table 5.2 Effect of Flux on Reactor Size and Weight
Table 5.3 Typical
K
Values for Mesh Blankets
Chapter 6: Distillate Hydrotreating Unit Design
Table 6.1 Capital and Operating Cost Comparison for Hot Separator Flow Scheme versus Conventional Flow Scheme
Table 6.2 Diesel Fuel Standards for the United States and Europe
Table 6.3 Stripper Operation versus Hot Separator Temperature
Table 6.4 Recoverable Hydrogen in Flash Gas for a Hot Separator Flow Scheme
Table 6.5 Relative LPG Recovery with and without Flash Drums
Table 6.6 Recoverable Hydrogen Solution Loss versus Operating Pressure
Table 6.7 Process Considerations for Hydrogen Purification Technology
Table 6.8 Distillate Hydrotreater Design Comparison
Table 6.9 Utilities Cost Basis
Chapter 7: Hydrocracking Unit Design
Table 7.1 Typical Feedstock and Processing Conditions for VGO Hydrocracking
Table 7.2 Solution and Recoverable Hydrogen via Flash Drums
Table 7.3 Comparison of Capital Cost for Fractionator First and Stripper First Flow scheme
Table 7.4 Utilities Comparison for Fractionator First and Stripper First Flow scheme
Table 7.5 Utilities Comparison for Single Stripper versus Dual-Zone Stripper Designs
Table 7.6 Capital Cost Comparison for Single Stripper Versus Dual-Zone Stripper Designs
Table 7.7 Utilities Comparison for Single Stripper, Dual-Zone Stripper, and Dual-Zone Stripper/Dual-Fractionator Designs
Table 7.8 Typical Yields for a Maximum Distillate Hydrocracking Unit
Table 7.9 Composition of Flash Gas and Stripper Overhead Streams
Chapter 8: Heat Integration for Better Energy Efficiency
Table 8.1 Stream Data for the Illustrative Example
Table 8.2 Design Performance for the Illustrative Example
Chapter 9: Process Integration for Low-Cost Design
Table 9.1 Typical Energy Saving from Different Categories of Opportunities
Chapter 10: Distillation Column Operating Window
Table 10.1 System Factors
Table 10.2 Relation of Weir Loading Limits and Tray Spacing (Nutter Engineering, 1981)
Table 10.3 Example Tower Design Check List
Table 10.4 Column Overhead Conditions
Table 10.5 Trials of Calculating Tray Diameter
Table 10.6 Downcomer Layout for Example Problem
Table 10.7 Tray Design Overall Summary
Table 10.9 Hydraulic Performance Summary
Chapter 11: Fired Heater Assessment
Table 11.1 Maximum Flux Rate Used in an Operating Company, Btu/h ft
2
Chapter 14: Heat Exchanger Assessment
Table 14.1 Gathered Data for a Reaction Air Cooler
Table 14.2 Calculation Results for a Reaction Air Cooler
Table 14.3 Liquid Fouling Factors
Chapter 15: Distillation Column Assessment
Table 15.1 Major Data Set for a Heat-Pumped C3 Splitter
Table 15.2 Heat and Mass Balances for a C2 Splitter
Table 15.3 Mass Balance Around a Fractionation Tower
Chapter 16: Energy Benchmarking
Table 16.1 Example Data Set for Energy Use and Generation
Chapter 18: Distillation System Optimization
Table 18.1 Product Specifications and Prices
Table 18.2 Simulation Results Versus DIP Operating Data
Table 18.3 Simulation Results at Designed Reboiler Duty
Chapter 20: Troubleshooting Case Analysis
Table 20.1 Options to Increase Naphtha Yield
Table 20.2 Feed Analysis – Aromatics Distribution
HYDROPROCESSING FOR CLEAN ENERGY
Design, Operation, and Optimization
FRANK (XIN X.) ZHU
RICHARD HOEHN
VASANT THAKKAR
EDWIN YUH
Copyright © 2017 by the American Institute of Chemical Engineers, Inc. All rights reserved.
A Joint Publication of the American Institute of Chemical Engineers and John Wiley & Sons, Inc.
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Library of Congress Cataloging-in-Publication Data:
Names: Zhu, Frank Xin X., author. | Hoehn, Richard, 1950- author. | Thakkar, Vasant, author. | Yuh, Edwin, 1954- author.
Title: Hydroprocessing for clean energy : design, operation and optimization / Frank (Xin X.) Zhu, Richard Hoehn, Vasant Thakkar, Edwin Yuh.
Description: Hoboken, New Jersey : John Wiley & Sons, Inc., [2017] | Includes bibliographical references and index.
Identifiers: LCCN 2016038243| ISBN 9781118921357 (cloth) | ISBN 9781119328254 (epub) | ISBN 9781119328247 (Adobe PDF)
Subjects: LCSH: Hydrocracking. | Petroleum-Refining. | Green chemistry.
Classification: LCC TP690.4 .Z49 2017 | DDC 660-dc23 LC record available at https://lccn.loc.gov/2016038243
Cover image courtesy: UOP Unicracking Process Unit of the Bangchak Petroleum Public Company Limited, Bangkok, Thailand
Preface
It all started during a conversation between Frank Zhu and Dick Hoehn over a beer while watching the big ships wind their way through the Bosphorus Strait during a trip to Istanbul for a customer meeting in 2009. The conversation centered on how to pass on some of the things that we have learned over the years, and in doing so, pay homage to those who were willing to share their knowledge with us along the way. We decided that a book would be a good medium to do this, and thus the seed was planted.
We eventually settled on a topic currently relevant to refiners: clean energy with a focus on the production of ultra-low-sulfur diesel (ULSD) in particular. The selection of this topic came from realizing that a paradox exists in the world: people want to enjoy life fueled with a sufficient and affordable energy supply and, at the same time, live in a clean environment. There is no magic formula for achieving this, but with a knowledge of fundamentals and appropriate application of technology, the goal can be realized.
ULSD is an important part of the clean energy mix. It is made by hydroprocessing of certain fractions of petroleum crude oil. It is used in cars, trucks, trains, boats, buses, heavy machinery, and off-road vehicles. The bad news is that without adequate processing to produce clean diesel fuel and upgraded engine technology, diesel engines emit sulfur dioxide and particulates. The impact of fuel sulfur on air quality is widely understood and known to be significant.
There are challenges in producing ULSD in an economical and reliable manner. Over the years, a great deal of effort has been poured into developing the catalysts and process technology to accomplish this. It is intended that this book will be a resource for hydroprocessing technology as it relates to hydroprocessing in general and ULSD production in particular and that it will be a useful reference for plant managers, hydroprocessing unit engineers, operators, and entry-level design engineers.
We believe that there is currently no book available to provide relevant knowledge and tools for the process design and operation of facilities to produce ULSD, particularly considering the fact that these guidelines and methods have evolved over time to address the issues with the efficient production of ULSD. To this end, we decided that the book should cover four themes: fundamentals, design, assessment, and troubleshooting. That was the reason why the current team of authors was formed to create this book. The four themes correspond with each individual author's experience and expertise. An R&D specialist, Vasant, has an extensive background in the fundamentals of hydroprocessing catalysis (Chapters 3 and 4); Dick has many years of experience in the field of engineering design and development of hydroprocessing technology (Chapters 5–7); Edwin, a technical service specialist, brings a wealth of knowledge about operations and troubleshooting (Chapters 19 and 20); and Frank has both academic and practical background in process energy efficiency, process integration, and assessment methods (all other 13 chapters). The four authors represent a sum total of over 100 years of experience in the field of hydroprocessing.
The purpose of this book is to bridge the gap between hydroprocessing technology developers and the engineers who design and operate the processes. To accomplish this, 6 parts with 20 chapters in total are provided in this book. Part 1 provides an overview of the refining processes including the feeds and products together with their specifications, in particular, the fundamental aspects for hydroprocessing are discussed in detail. Part 2, mainly discusses on process design aspects for both diesel hydrotreating and hydrocracking processes. The focus of Part 3 is on process and heat integration methods for achieving high energy efficiency in design. In Part 4, the basics and operation assessment for major process equipment are discussed. In contrast, Part 5 focuses on process system optimization for achieving higher energy efficiency and economic margin. Last but not least, Part 6 deals with operation, in which operation guidelines are provided and troubleshooting cases are discussed.
Clearly, it was no small effort to write this book; but it was the desire to provide practical methods for helping people understand the issues involved in improving operations and designing for better energy efficiency and lower capital cost, which motivated us. In this endeavor, we owe an enormous debt of gratitude to many of our colleagues at UOP and Honeywell for their generous support in this effort. First of all, we would like to mention Geoff Miller, former vice president of UOP and now vice president of Honeywell, who has provided encouragement in the beginning of this journey for writing this book. We are very grateful to many colleagues for constructive suggestions and comments on the materials contain in this book. We would especially like to thank the following people for their valuable comments and suggestions: Bettina Marie Patena for Chapters 5 through 7, Zhanping (Ping) Xu for Chapter 10, Darren Le Geyt for Chapter 11, Bruce Lieberthal for Chapters 12 and 13, and Phil Daly for Chapter 14. Our sincere gratitude also goes to Charles Griswold, Mark James, and Rich Rossi for their constructive comments. Jane Shao produced beautiful drawings for many figures in the book. The contributions to this book from people mentioned above are deeply appreciated. I would also like to thank our co-publishers, AIChE and John Wiley for their help. Special thanks go to Steve Smith AIChE and Michael Leventhal for their guidance. The copyediting and typesetting by Vishnu Priya and her team at John Wiley is excellent. Finally, we would like to point out that this book reflects our own opinions but not those of UOP or Honeywell.
Frank (Xin X.) ZhuRichard HoehnVasant ThakkarEdwin Yuh
Des Plaines, Illinois USA
June 1, 2016
Part 1Fundamentals
Chapter 1Overview of This Book
1.1 Energy Sustainability
There is a paradox in this world: people want to enjoy life fueled with sufficient and affordable energy supply. At the same time, people wish to live in a clean environment. This paradox defines the objective of clean energy: provide affordable energy with minimum climate impact. This is a huge challenge technically, economically, geographically, and politically. There is no silver bullet for solving this paradox and the practical path forward is to determine a good mix of different kinds of energy sources. The proportions of this mix depend on the availability of these energy sources and costs of converting them to useful forms in geographic regions.
Energy demand has been increasing significantly over recent years due to the fact that people in emerging regions wish to improve their living standard and enjoy the benefit that energy can bring. Therefore, in the short and middle term, there is more oil and natural gas production to satisfy increased energy demand. To reduce the climate impact, sulfur content for the fossil fuels must be reduced – in particular, ultra-low-sulfur diesel (ULSD) is the focus in the present time. As far as energy efficiency is concerned, cars and trucks have become more fuel efficient and will continue to improve mileage per gallon. Furthermore, electrical and hybrid vehicles will improve energy efficiency even further. On the renewable energy side, the percentage of renewable energy, such as ethanol for gasoline and biodiesel blended into diesel fuel, will gradually increase over time through governmental regulation. Further technology development will make renewable energy such as wind, solar, and biofuels more cost-effective and hence these energy sources will become a sustainable part of the energy mix. These trends will coexist to achieve a balance between increased energy demand and a cleaner environment, and at the same time, less dependence on foreign oil imports. In the long term, the goal is to increase the proportion of alternative energy in the energy mix to reduce gradually the demand for fossil fuels.
In summary, clean energy is the pathway for meeting the increased energy demand with a sustainable environment and the best future for clean energy is to capitalize on all the options: renewable energy, fossil fuels, increased efficiency, and reduced consumption. When these multiple trends and driving forces work together, the transformation becomes more economical and reliable. Technology developments in clean energy will join forces with regulations and market dynamics in the coming decades and beyond.
1.2 ULSD – Important Part of the Energy Mix
ULSD is an important part of clean energy mix. Diesel fuel is made from hydroprocessing of certain fractions of petroleum crude. It is used in cars, trucks, trains, boats, buses, heavy machinery, and off-road vehicles. The bad news is that most diesel engines emit nitrogen oxides that can form ground-level ozone and contribute to acid rain. Diesel engines are also a source of fine particle air pollution. The impact of sulfur on particulate emissions is widely understood and known to be significant. In the European Auto Oil program, detailed study of lower effect on particulate matter (PM) was studied. This study suggests significant benefit from sulfur reductions for heavy-duty trucks. Reductions in fuel sulfur will also provide particulate emission reductions in all engines.
Testing performed on heavy-duty vehicles using the Japanese diesel 13 mode cycle have shown significant PM emission reductions that can be achieved with both catalyst and noncatalyst equipped vehicles. The testing showed that PM emissions from a noncatalyst equipped truck running on 400 ppm sulfur fuel were about double the emissions when operating on 2 ppm fuel (Worldwide Fuel Charter, Sept. 2013).
When sulfur is oxidized during combustion, it forms SO2, which is the primary sulfur compound emitted from the engine. Some of the SO2 is further oxidized – in the engine, exhaust, catalyst, or atmosphere to sulfate (SO4). The sulfate and nearby water molecules often coalesce to form aerosols or engulf nearby carbon to form heavier particulates that have a significant influence on both fine and total PM. Without oxidation catalyst systems, the conversion rate from sulfur to sulfate is very low, typically around 1%, so the historical sulfate contribution to engine-out PM has been negligible. However, oxidation catalysts dramatically increase the conversion rate to as much as 100%, depending on catalyst efficiency. Therefore, for modern vehicle systems, most of which include oxidation catalysts, a large proportion of the engine-out SO2 will be oxidized to SO4, increasing the amount of PM emitted from the vehicle. Thus, fuel sulfur will have a significant impact on fine particulate emissions in direct proportion to the amount of sulfur in the fuel.
In the past, diesel fuel contained higher quantities of sulfur. European emission standards and preferential taxation have forced oil refineries to dramatically reduce the level of sulfur in diesel fuels. Automotive diesel fuel is covered in the European Union by standard EN 590, and the sulfur content has dramatically reduced during the last 20 years. In the 1990s, specifications allowed a content of 2000 ppm maximum of sulfur. Germany introduced 10 ppm sulfur limit for diesel from January 2003. Other European Union countries and Japan introduced diesel fuel with 10 ppm to the market from the year 2008.
In the United States, the acceptable level of sulfur in the highway diesel was first reduced from 2000 to 500 ppm by the Clean Air Act (CAA) amendments in the 1990s, then to 350, 50, and 15 ppm in the years 2000, 2005, and 2006, respectively. The major changeover process began in June 2006, when the EPA enacted a mandate requiring 80% of the highway diesel fuel produced or imported in order to meet the 15 ppm standard. The new ULSD fuel went on sale at most stations nationwide in mid-October 2006 with the goal of a gradual phase out of 500 ppm diesel.
In 2004, the US EPA also issued the clean air-nonroad-Tier 4 final rule, which mandated that starting in 2007, fuel sulfur levels in nonroad diesel fuel should be reduced from 3000 to 500 ppm. This includes fuels used in locomotive and marine applications, with the exception of marine residual fuel used by very large engines on ocean-going vessels. In 2010, fuel sulfur levels in most nonroad diesel fuel were reduced to 15 ppm, although exemptions for small refiners allowed for some 500 ppm diesel to remain in the system until 2014. After 1 December 2014, all highway, nonroad, locomotive, and marine diesel fuel produced and imported has been ULSD.
The allowable sulfur content for ULSD (15 ppm) is much lower than the previous US on-highway standard for low-sulfur diesel (LSD, 500 ppm), which allows advanced emission control systems to be fitted that would otherwise be poisoned by these compounds. EPA, the California Air Resources Board, engine manufacturers, and others have completed tests and demonstration programs showing that using the advanced emissions control devices enabled by the use of ULSD fuel reduces emissions of hydrocarbons and oxides of nitrogen (precursors of ozone), as well as particular matter to near-zero levels. According to EPA estimates, with the implementation of the new fuel standards for diesel, nitrogen oxide emissions will be reduced by 2.6 million tons each year and soot or particulate matter will be reduced by 110,000 tons a year. EPA studies conclude that ozone and particulate matter cause a range of health problems, including those related to breathing, with children and the elderly those most at risk, and therefore estimates that there are significant health benefits associated with this program.
ULSD fuel will work in concert with a new generation of diesel engines to enable the new generation of diesel vehicles to meet the same strict emission standards as gasoline-powered vehicles. The new engines will utilize an emissions-reducing device called a particulate filter. The process is similar to a self-cleaning oven's cycle: a filter traps the tiny particles of soot in the exhaust fumes. The filter uses a sensor that measures back pressure and indicates the force required to push the exhaust gases out of the engine and through to the tailpipes. As the soot particles in the particulate filter accumulate, the back pressure in the exhaust system increases. When the pressure builds to a certain point, the sensor tells the engine management computer to inject more fuel into the engine. This causes heat to build up in the front of the filter, which burns up the accumulated soot particles. The entire cycle occurs within a few minutes and is undetectable by the vehicle's driver.
Diesel-powered engines and vehicles for 2007 and later model year vehicles are designed to operate only with ULSD fuel. Improper fuel use will reduce the efficiency and durability of engines, permanently damage many advanced emissions control systems, reduce fuel economy, and possibly prevent the vehicles from running at all. Manufacturer warranties are likely to be voided by improper fuel use. In addition, burning LSD fuel in 2006 and later model year diesel-powered cars, trucks, and buses is illegal and punishable with civil penalties.
The specifications proposed for clean diesel by Worldwide Fuel Charter (WWFC), which reflects the view of the automobile/engine manufactures concerning the fuel qualities for engines in use and for those yet to be developed, require increased cetane index, significant reduction of polynuclear aromatics (PNA), and lower T95 distillation temperature (i.e., the temperature at which 95% of a sample vaporizes) in addition to ultra-low sulfur levels. Automotive manufactures have concluded that substantial reductions in both gasoline and diesel fuel sulfur levels to quasi sulfur-free levels are essential to enable future vehicle technologies to meet the stringent vehicle emissions control requirements and reduce fuel consumption.
As a summary, to meet emission standards, engine manufactures will be required to produce new engines with advanced emission control technologies similar to those already expected for on-road (highway) heavy trucks and buses. Refiners will be producing and supplying ULSD for both highway and nonhighway diesel vehicles and equipment. Although there are still challenges to overcome, the benefits are clear: ULSD and the new emissions-reducing technology that it facilitates will help make the air cleaner and healthier for everyone.
In parallel, alternative technology such as electrical and hybrid-electric cars as well as biofuels for transportation is sought to address climate change issues and seek less dependence on fossil oil. The main driver for use of electrical and hybrid-electric cars is higher energy efficiency and lower greenhouse emissions; but electrical and hybrid-electric models are more expensive than conventional ones. On the other hand, biodiesel, made mainly from recycled cooking oil, soybean oil, other plant oils, and animal fats, has started to be used as blending stock for diesel. Biodiesel can be blended and used in many different concentrations. The most common are B100 (pure biodiesel), B20 (20% biodiesel, 80% petroleum diesel), B5 (5% biodiesel, 95% petroleum diesel), and B2 (2% biodiesel, 98% petroleum diesel). B20 is the most common biodiesel blend in the United States. B20 is popular because it represents a good balance of cost, emissions, cold-weather performance, materials compatibility, and ability to act as a solvent. Most biodiesel users purchase B20 or lower blends from their normal fuel distributors or from biodiesel marketers. However, not all diesel engine manufacturers cover biodiesel use in their warranties. Users should always consult their vehicle and engine warranty statements before using biodiesel.
There are two challenges to overcome in the use of biodiesel. One is the availability of feedstock and the other is the cost. Government subsidies for biofuels are currently being used to encourage expansion of production capacity. Although the social, economic, and regulatory issues associated with expanded production of biodiesel are outside the scope of this book, it is crucial that future commercialization efforts focus on sustainable and cost-effective methods of producing feedstock. Current and future producers are targeting sustainable production scenarios that, in addition to minimizing impact on land-use change and food and water resources, provide an energy alternative that is economically competitive with current petroleum-based fuels. Future growth will require a coordinated effort between feedstock producers, refiners, and industry regulators to ensure environmental impacts are minimized. If done responsibly, increasing biofuel usage in the transportation sector can significantly reduce greenhouse-gas emissions as well as diversify energy sources, enhance energy security, and stimulate the rural agricultural economy.
1.3 Technical Challenges for Making ULSD
ULSD is mainly produced from hydrocracking and diesel hydrotreating processes with crude oil as the raw feed in the refinery. Technical solutions for ULSD production can be summarized as follows (Stanislaus et al., 2010):
Use of highly active catalysts
Increase of operating severity (e.g., increased temperature, increase in hydrogen pressure, lower LHSV)
Increase catalyst volume (by using additional reactor, dense loading, etc.)
Removal of H
2
S from recycle gas
Improve feed distribution in the reactor by using high-efficiency vapor/liquid distribution trays
Use of easier feeds; reduce feedstock end boiling point
Use of two-stage reaction system design for hydrocrackers
A combination of the above options may be necessary to achieve the target sulfur level cost-effectively. Selection of the most appropriate option or a combination of those is specific for each refinery depending on its configuration, existing process design, feedstock quality, product slate, hydrogen availability, and so on.
Clearly, there are many design parameters to consider during process design. As an example, consider the design choice for the use of one or two reaction stages in a hydrocracking unit. In single-stage hydrocrackers, all catalysts are contained in a single stage (in one or more series or parallel reactors). A single catalyst type might be employed or a stacked-bed arrangement of two different catalysts might be used. In single-stage hydrocracking, all catalysts are exposed to the high levels of H2S and NH3 that are generated during removal of organic sulfur and nitrogen from the feed. Ammonia inhibits the hydrocracking catalyst activity, requiring higher operating temperatures to achieve target conversion, but this generally results in somewhat better liquid yields than would be the case if no ammonia were present. There is no interstage product separation in single-stage or series-flow operation.
However, two-stage hydrocrackers employ interstage separation that removes the H2S and NH3 produced in the first stage. As a consequence, the second-stage hydrocracking catalyst is exposed to lower levels of these gases, especially NH3. Some two-stage hydrocracker designs do result in very high H2S levels in the second stage. Frequently, unconverted product is separated and recycled back to either the pretreat or the cracking reactors.
Understanding of these fundamentals will be paramount and the related design considerations will be provided in details in this book. Apart from discussions of fundamental aspects of design, the book also provides explanation on how to design hydrocracking and distillate hydrotreating units by applying applicable theory and design considerations in order to obtain a practical and economic design with the least capital cost and energy use possible. During operation, the primary goal is to achieve safe, reliable, and economic production. Achieving the operation objectives is another focus of discussions in this book.
1.4 What is the Book Written for
The purpose of this book is to bridge the gap between hydroprocessing technology developers and the engineers who design and operate the processes. To accomplish this, 6 parts with 20 chapters in total are provided in this book. The first part provides an overview of the refining processes including the feeds and products together with their specifications, while the second part mainly discusses process design aspects for both diesel hydrotreating and hydrocracking processes. Part 3 focuses on process and heat integration methods for achieving high energy efficiency in design. With Part 4, the basics and operation assessment for major process equipment are discussed. In contrast, Part 5 focuses on process system optimization for achieving higher energy efficiency and economic margin. Last but not least, in Part 6, operation guidelines are provided and troubleshooting cases are discussed.
References
Stanislaus A, Marafi A, Rana M (2010) Recent advances in the science and technology of ultra-low sulfur diesel (ULSD) production,
Catalysis Today
,
153
(1), 1–68.
5th Worldwide Fuel Charter (2013)
ACEA
, European Automobile Manufacturers Association, Brussels, Belgium.
Chapter 2Refinery Feeds, Products, and Processes
2.1 Introduction
Crude oils are feedstock for producing transportation
