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Preview — Handbook of Petroleum Refining Processes by Robert A. Meyers* Offers detailed description of process chemistry and thermodynamics and product by-product specifications of plants * Contributors are drawn from the largest petroleum producers in the world, including Chevron, Mobil, Shell, Exxon, UOP, and Texaco * Covers the very latest technologies in the field of petroleum refining processes * Completely updated 3rd Edition feature..more
Published October 14th 2003 by McGraw-Hill Education
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BOOK: REFINING PROCESSES HANDBOOK
(SỔ TAY VỀ QUY TRÌNH QUY CHẾ)
FEED RATE
Increasing the feed rate requires an increase in average catalyst temperature to maintain the required feed rate conversion. The increased feed rate also causes an increase in the catalyst fouling rate and the hydrogen consumed chemically and dissolved in the high-pressure separator liquid.
The effect of the feed rate on the catalyst fouling rate is shown in Figure 3-9.
FEED CHARACTERIZATION
A heavier feed, as characterized by the ASTM Dl 160 weighted boiling point, requires an increase in average catalyst temperature to maintain the desired level of feed conversion. An increase in the catalyst fouling rate also occurs. Further, a feed having a higher end point for a given weighted boiling point requires an increased temperature for desired conversion over that required by a lower-end point feed.
GAS BLEED RATE
Bleeding minimizes the buildup of light hydrocarbons in the recycling gas, which lowers hydrogen partial pressure. Increasing the gas bleed rate lowers the light hydrocarbon concentration in the recycling gas and increases the hydrogen partial pressure. Decreasing the bleed rate allows light hydrocarbons in the recycle gas to build up to higher concentrations and thus lower hydrogen concentration. The bleed rate is typically kept at about 20% of the hydrogen chemical consumption.
CATALYST SULFIDING AND UNIT STARTUP
The catalyst is sulfided during startup. Before initiating the sulfiding, the distillation and the amine absorber are put into operation.
Sulfiding is the injection of a sulfur-containing chemical such as dimethyl sulfide into the hot circulating gas stream prior to the introduction of liquid feed. The chemical injection is performed with a chemical injection pump from a storage drum under an inert gas blanket. The reactor is first evacuated to 24-26 in. Mercury to remove all air, tested for leaks, and purged with nitrogen a number of times.
The furnace is next purged and fired, and the reactor is heated to 4500
F. When the reactor is ready for sulfiding, the reactor inlet temperature is increased to 500-5250
F. When the catalyst temperature reaches 500-525° at the top bed, this temperature is held until the temperature is at least 500° at the inlet and about 450° at reactor outlet.
The feed heater fire is reduced. With recycle compressor operating, the reactor pressure is adjusted to about 300 psi. At 300psig, the hydrogen is introduced slowly, through the makeup compressor and pressure increased to 700psig at reactor inlet.
Sulfiding chemical or sour gas injection is then added into gas stream at the reactor inlet, at a rate equivalent to 0.5 mol% but no more than 1.0 mol% H2S.
Addition of a sulfiding agent causes two temperature rises in the reactor, first due to reaction of hydrogen with the sulfiding chemical to form H2S, which occurs at the reactor inlet, and second due to reaction of the sulfiding chemical with the catalyst, and this moves down through the catalyst bed. The catalyst temperature is closely monitored during sulfiding, and it is not allowed to exceed 6000 F.
After the sulfiding temperature rise has passed through the reactor, the H2S concentration of gases out of the reactor begin to rise rapidly. When 0.1% H2S is detected in the effluent gas, the recycle gas bleed is stopped and sulfiding continued at a low injection rate until the concentration of H2S in the circulating gas is l-2mol%. At the same time, the reactor inlet temperature is increased to 560° and the reactor outlet temperature to at least 535°F.
When no significant reaction is apparent in the reactor, the system pressure is increased by adding makeup hydrogen until a normal operating pressure is reached at the suction of the recycling compressor. The sulfiding medium is added batchwise to maintain the H2S concentration of l-2mol% in the recycle gas. When the reactor system has remained steady at the design pressure, at reactor inlet/outlet temperature of 560/530° and H2S concentration of 1-2 mol%, for 2 hours, sulfiding is complete. The reactor is slowly cooled by reducing inlet temperature and adding quench between the catalyst beds until reactor temperature reaches about 425°F. No point in the reactor is allowed to cool below 425°F.
The startup temperature is next approached from the lower side by increasing the reactor inlet temperature to 450-475° and outlet temperature to 425-450°, the quench temperature controller is set at 450°F. The recycle gas rate is set at the design rate. Also the HP separator pressure is set at the design value. Condensate and polysulfide injection at the design rate is started.
The reactor is now ready for introduction of the feed. The feed pump starts pumping only 20% of the design feed rate to the reactor, shunting the rest of the feed back to the feed tank.
Heat is released due to adsorption of hydrocarbon when the feed passes over the catalyst for the first time. This shows up as a temperature wave that passes down through the catalyst. When the temperature wave due to hydrocarbon adsorption has passed through the reactor and a liquid level is established in the high pressure separator, the liquid is sent to a lowpressure separator and the distillation section.
As the reactor temperature and feed rate is increased in the steps that follow, amine circulation is established through the recycling gas absorber.
The reactor feed rate is increased by 10-15% of the design at a time, allowing the system to line out for at least 1 hour after each feed rate increase. The process is repeated until the feed is at 50% of the design rate.
Next, the temperature is increased in about 20°F increments or less at the inlet to each reactor bed. When increasing reactor temperature, the top bed should be adjusted first then each succeeding lower bed. The system is allowed to line out for at least 1 hour after each reactor temperature increase until all reactor temperatures are steady. Then, the reactor temperature is increased again until the desired conversion is reached.
When the desired operation (conversion and feed rate) Has been reached and the unit is fully lined out, it is monitored so that recycle gas rate is steady and at the design rate. The H2S absorber bypass is slowly closed, forcing all the recycling gas through the absorber. While closing this bypass, close attention is given to knockout drum level, absorber-packed bed AP, and absorber level to avoid compressor shutdown due to a sudden carryover of amine solution.
NORMAL SHUTDOWN
The following procedures are typical when a run is ended to replace spent catalyst or perform general maintenance. The same procedure is followed when a run is ended for catalyst regeneration, except that the reactor is not opened.
Contents
Preface
Chapter Breakdown
1. Refinery Distillation
Process Variables
Process Design of a Crude Distillation Tower
Characterization of Unit Fractionation
General Properties of Petroleum Fractions
Atmospheric Distillation Unit
Vacuum Distillation Unit
Crude Desalting
2. Distillate Hydrotreating
Naphtha Hydrodesulfurization Process
Kerosene Hydrotreating
Gas Oil Hydrodesulfurization
Atmospheric Residuum Desulfurization
3. Hydrocracking Processes
Hydrocracking Reactions
Process Configuration
Process Flow Scheme
2017 Refining Processes Handbook
Operating Conditions
Catalyst Sulfiding and Unit Startup
Shutdown Procedure
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Catalyst Regeneration
Mild Hydrocracking
Residuum Hydrocracking Extend volume greyed out windows.
4. Gasoline Manufacturing Processes
Catalytic Reforming
Fluid Catalytic Cracking
Alkylation
Isomerization of C5/ C6 Normal Paraffins
Methyl Tertiary Butyl Ether
5. Hydrogen Production and Recovery
Natural Gas Desulfurization
Steam Reforming
Carbon Monoxide Conversion
Carbon Dioxide Removal
Methanation
Pressure Swing Adsorption Route
Partial Oxidation Process
Hydrogen Recovery
6. Residuum Processing
Delayed Coking
Visbreaking
Solvent Deasphalting
Bitumen Blowing
7. Treating Processes
General Principles
FCCU Light Gasoline
Jet Fuel (ATK) Sweetening
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8. Sulfur Recovery and Pollution Control Processes
Sulfur Recovery from Acid Gas
Claus Tail Gas Treatment
Flue Gas Desulfurization
Amine Treatment
9. Refinery Water Systems
Cooling Water System
Sea Water Cooling System
Cooling Towers
Boiler Feedwater System
Utility Water System
Treatment of Oily Water
Wet Slop Oil System
Treatment of Sanitary Sewage
Sour Water Treatment
10. Refinery Off-site Facilities and Utility Systems
Refinery Tankage
Shipping Terminals and Sea Lines
Refinery Tankage Estimation
Product Blending System
Refinery Flare System
Refinery Steam System
Refinery Fuel System
11. Product Blending
Gasoline Octane Blending
ASTM Distillation Blending
Viscosity Blending
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Pour Point Blending
Flash Point Blending
Reid Vapor Pressure Blending for Gasolines and Naphthas
Aniline Point Blending
Crude Oil Assays
12. Refinery Stock Balancing
Data for Model Building
Calculation Procedure
Refinery Material Balance Spreadsheet Program
13. Refinery Linear Programming Modeling
Overview
Development of the Refinery LP Model
The Structure of a Refinery LP Model
Property Propagation to Other Tables
Blending Specifications
Stream Pooling (Recursion Process)
Distributive Recursion
Objective Function
Optimization Step
Solution Convergence
Interpreting the Solution
Report Writer Programs
Delta-based Modeling
Atmospheric Crude Distillation and VDU Modeling
Single-product LP Blender
14. Pricing Petroleum Products
Netback and Formula Pricing for Crude Oil
Pricing Petroleum Products and Intermediate Stocks
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Assigned Crude Yields
15. Definitive Operating Plan
DOPs in Joint-ownership Refineries
Fixed- and Balancing-grade Products
Product Equivalencies
Product Equivalency Determination
Crude Oil Equivalency
Equivalency of Slop
16. Product Allocation
Input Data
Forecaster Changes
Rules for Forecaster Changes
Crude Oil Changes
DOP “Loss” Adjustment
Retrospective DOP
Allocation of Balancing Grades
Reverse Allocation
Final Allocation
Allocation LPs
Process Unit Capacities
Product Prices
Summary of Primary Data Input for LPs
Examination of LP Results
Final Allocation Cycle
Allocation Spreadsheet Program
Product Allocation Problems
17. Available Tankage Capacity
Estimation of Total Available Capacity
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Minimum and Maximum Inventory (LI and HI)
Allocation of Tankage Capacity
Ullage
Ceding of Refinery Capacity
Ceding of Tankage Capacity
18. Shipping Inventory Forecasts
Weekly Production Estimates
Refinery Estimate Schedule
Procedure
Allocation of Deltas
Inventory and Ullage Forcasting System (Joint Ownership
Refineries)
19. Refinery Operating Cost
Allocation of Operating Cost
System Costing Method
Theoretical Sales Realization Valuation Method
Cost Allocation for Actual Usage
Unused Capacity Charge
Appendix: Processing Agreement for Joint-ownership
Refinery
Index
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