Wabash River Coal Gasification Repowering Project Final Technical Report

Wabash River Coal Gasification Repowering Project Final Technical Report
Wabash River Coal Gasification
Repowering Project
Final Technical Report
August 2000
Work Performed Under
Cooperative Agreement DE-FC21-92MC29310
For:
The U.S. Department of Energy
Office of Fossil Energy
National Energy Technology Laboratory
Morgantown, West Virginia
Prepared by:
The Men and Women of
Wabash River Energy Ltd.
For Further Information Contact:
Roy A. Dowd, CHMM
Environmental Supervisor
Wabash River Coal Gasification Repowering Project
444 West Sandford Avenue
West Terre Haute, IN 47885
LEGAL NOTICE/DISCLAIMER
This report was prepared by the Wabash River Coal Gasification Repowering Project
Joint Venture pursuant to a Cooperative Agreement partially funded by the U.S.
Department of Energy, and neither the Wabash River Coal Gasification Repowering
Project Joint Venture nor any of its subcontractors nor the U.S. Department of Energy,
nor any person acting on behalf of either:
(A). Makes any warranty or representation, express or implied, with respect to the
accuracy, completeness, or usefulness of the information contained in this
report, or that the use of any information, apparatus, method, or process
disclosed in this report may not infringe privately-owned rights; or
(B). Assumes any liabilities with respect to the use of, or for damages resulting from
the use of, any information, apparatus, method or process disclosed in this
report.
Reference herein to any specific commercial product, process, or service by trade name,
trademark, manufacturer, or otherwise, does not necessarily constitute or imply its
endorsement, recommendation, or favoring by the U.S. Department of Energy. The views
and opinions of authors expressed herein do not necessarily state or reflect those of the U.S.
Department of Energy.
Acknowledgement
The Wabash River Coal Gasification Repowering Project Joint Venture would like to
thank the United States Department of Energy for selecting the Wabash River Project as a
participant in its Clean Coal Technology Program. Through this collaborative effort
between government and industry, the Wabash River Project has significantly advanced
the commercialization of clean coal-based power generation. We would like to
particularly acknowledge the contributions of William Langan, whose professional and
personal contributions to an idea, an industry, and to the Wabash River Project helped to
make the vision a reality. In memory of Bill, the Gasification Control and Administration
Building at Wabash was dedicated in his honor on November 7, 1995.
Wabash River Coal Gasification Repowering Project
Final Technical Report
TABLE OF CONTENTS
Contents
Page Number
SECTION I – EXECUTIVE SUMMARY AND PROJECT OVERVIEW
EXECUTIVE SUMMARY......................................................................................... ES-1
i.
ii.
iii.
iv.
v.
vi.
vii.
1.0
General ................................................................................................. ES-1
Process Overview................................................................................. ES-1
Operating Overview............................................................................ ES-3
Significant Findings and Modifications ............................................ ES-5
Environmental ......................................................................... ES-6
Air Separation Unit................................................................. ES-7
Coal Handling.......................................................................... ES-7
Gasification .............................................................................. ES-8
High Temperature Heat Recovery......................................... ES-9
Particulate Removal................................................................ ES-9
Low Temperature Heat Recovery ....................................... ES-10
Acid Gas Removal ................................................................. ES-11
Plant Performance............................................................................. ES-11
Economics and Commercialization ................................................. ES-13
Conclusions ........................................................................................ ES-16
INTRODUCTION..............................................................................................1-1
1.1
Objectives................................................................................................1-3
1.2
General ....................................................................................................1-5
1.3
Project Phase Description......................................................................1-8
1.3.1 Phase I Activities – Engineering and Procurement.................1-8
1.3.2 Phase II Activities – Construction ............................................1-9
1.3.3 Phase III Activities – Demonstration Period .........................1-10
1.4
Project Organization............................................................................1-11
1.5
Project Location and Original Equipment Description ...................1-12
1.6
Permitting and Environmental Activities ..........................................1-14
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2.0
TECHNOLOGY DESCRIPTION ....................................................................2-1
3.0
DETAILED PROCESS DESCRIPTION.........................................................3-1
3.1
Air Separation Unit................................................................................3-2
3.2
Coal Handling.........................................................................................3-3
3.3
Gasification .............................................................................................3-4
3.3.1 Gasification and Slag Handling ................................................3-4
3.3.2 Syngas Cooling, Particulate Removal ......................................3-6
3.3.3 Low Temperature Heat Recovery, Chloride Scrubbing,
and Syngas Moisturization ........................................................3-7
3.3.4 Acid Gas Removal ......................................................................3-8
3.3.5 Sulfur Recovery ..........................................................................3-9
3.3.6 Sour Water Treatment.............................................................3-10
3.4
Power Block ..........................................................................................3-11
SECTION II – OPERATIONS AND ECONOMICS
4.0
DEMONSTRATION PERIOD .........................................................................4-1
4.1
Operation, Maintenance and Technical Impacts ................................4-2
4.1.1 Air Separation Unit....................................................................4-7
4.1.2 Coal Handling...........................................................................4-15
4.1.3 Gasification ...............................................................................4-20
4.1.3.1
Gasification and Slag Handling ............................4-20
4.1.3.2
Syngas Cooling, Particulate Removal And
COS Hydrolysis ......................................................4-32
4.1.3.3
Low Temperature Heat Recovery and Syngas
Moisturization.........................................................4-48
4.1.3.4
Acid Gas Removal ..................................................4-53
4.1.3.5
Sulfur Recovery ......................................................4-58
4.1.3.6
Sour Water Treatment...........................................4-65
4.1.4 Power Block ..............................................................................4-68
4.2
General Information ............................................................................4-71
4.2.1 Stream Data ..............................................................................4-71
4.2.2 Alternative Fuel Testing ..........................................................4-74
4.3
Critical Component Failure Report ...................................................4-85
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5.0
TECHNICAL PERFORMANCE ....................................................................5-1
5.1
Air Separation Unit................................................................................5-4
5.1.1 Air Compression System ...........................................................5-4
5.1.1.1
System Modifications ...............................................5-5
5.1.1.2
Operating Experience Overview.............................5-7
5.1.1.3
Summary and Conclusions......................................5-8
5.1.2 Water Wash System .................................................................5-12
5.1.2.1
System Modifications .............................................5-13
5.1.2.2
Operating Experience Overview...........................5-13
5.1.2.3
Summary and Conclusions....................................5-14
5.1.3 Air Purification System ...........................................................5-15
5.1.3.1
System Modifications .............................................5-16
5.1.3.2
Operating Experience Overview...........................5-16
5.1.3.3
Summary and Conclusions....................................5-18
5.1.4 Air Cooling and Liquefaction System ....................................5-21
5.1.4.1
System Modifications .............................................5-22
5.1.4.2
Operating Experience Overview...........................5-24
5.1.4.3
Summary and Conclusions....................................5-24
5.1.5 Cryogenic Distillation System .................................................5-27
5.1.5.1
System Modifications .............................................5-28
5.1.5.2
Operating Experience Overview...........................5-28
5.1.5.3
Summary and Conclusions....................................5-30
5.1.6 Oxygen Mixing System ............................................................5-32
5.1.6.1
System Modifications .............................................5-33
5.1.6.2
Operating Experience Overview...........................5-33
5.1.6.3
Summary and Conclusions....................................5-35
5.1.7 Nitrogen Handling and Storage System .................................5-36
5.1.7.1
System Modifications .............................................5-38
5.1.7.2
Operating Experience Overview...........................5-38
5.1.7.3
Summary and Conclusions....................................5-40
5.1.8 Oxygen Compression System ..................................................5-42
5.1.8.1
System Modifications .............................................5-42
5.1.8.2
Operating Experience Overview...........................5-44
5.1.8.3
Summary and Conclusions....................................5-46
5.2
Coal Handling.......................................................................................5-48
5.2.1 Coal Hopper System.................................................................5-48
5.2.1.1
System Modifications .............................................5-49
5.2.1.2
Operating Experience Overview...........................5-49
5.1.2.3
Summary and Conclusions....................................5-50
5.2.2 Rod Mill System .......................................................................5-51
5.2.2.1
System Modifications .............................................5-52
5.2.2.2
Operating Experience Overview...........................5-53
5.2.2.3
Summary and Conclusions....................................5-54
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5.2.3
5.2.4
5.3
Slurry Storage Tank System ...................................................5-56
5.2.3.1
System Modifications .............................................5-57
5.2.3.2
Operating Experience Overview...........................5-57
5.2.3.3
Summary and Conclusions....................................5-57
Slurry Feed System ..................................................................5-58
5.2.4.1
System Modifications .............................................5-58
5.2.4.2
Operating Experience Overview...........................5-59
5.2.4.3
Summary and Conclusions....................................5-60
Gasification ...........................................................................................5-61
5.3.1 First Stage Gasifier System .....................................................5-61
5.3.1.1
System Modifications .............................................5-62
5.3.1.2
Operating Experience Overview...........................5-63
5.3.1.3
Summary and Conclusions....................................5-65
5.3.2 Second Stage Gasifier System .................................................5-68
5.3.2.1
System Modifications .............................................5-68
5.3.2.2
Operating Experience Overview...........................5-69
5.3.2.3
Summary and Conclusions....................................5-70
5.3.3 Raw Syngas Conditioning System ..........................................5-71
5.3.3.1
System Modifications .............................................5-71
5.3.3.2
Operating Experience Overview...........................5-72
5.3.3.3
Summary and Conclusions....................................5-73
5.3.4 Slag and Solids Handling System............................................5-74
5.3.4.1
System Modifications .............................................5-76
5.3.4.2
Operating Experience Overview...........................5-76
5.3.4.3
Summary and Conclusions....................................5-78
5.3.5 Syngas Cooling/Steam Generation System ............................5-79
5.3.5.1
System Modifications .............................................5-80
5.3.5.2
Operating Experience Overview...........................5-82
5.3.5.3
Summary and Conclusions ...................................5-83
5.3.6 Particulate Removal System....................................................5-84
5.3.6.1
System Modifications .............................................5-84
5.3.6.2
Operating Experience Overview...........................5-88
5.3.6.3
Summary and Conclusions....................................5-91
5.3.7 Chloride Scrubbing System.....................................................5-93
5.3.7.1
System Modifications .............................................5-94
5.3.7.2
Operating Experience Overview...........................5-94
5.3.7.3
Summary and Conclusions....................................5-96
5.3.8 COS Hydrolysis System ...........................................................5-97
5.3.8.1
System Modifications .............................................5-97
5.3.8.2
Operating Experience Overview...........................5-99
5.3.8.3
Summary and Conclusions....................................5-99
5.3.9 Low Temperature Heat Recovery System ...........................5-100
5.3.9.1
System Modifications ...........................................5-100
5.3.9.2
Operating Experience Overview.........................5-102
5.3.9.3
Summary and Conclusions .................................5-105
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5.3.10 Syngas Moisturization System ..............................................5-106
5.3.10.1 System Modifications ...........................................5-106
5.3.10.2 Operating Experience Overview.........................5-106
5.3.10.3 Summary and Conclusions..................................5-107
5.3.11 Acid Gas Removal System.....................................................5-108
5.3.11.1 System Modifications ...........................................5-109
5.3.11.2 Operating Experience Overview.........................5-113
5.3.11.3 Summary and Conclusions..................................5-116
5.3.12 Sulfur Recovery System.........................................................5-118
5.3.12.1 System Modifications ...........................................5-119
5.3.12.2 Operating Experience Overview.........................5-123
5.3.12.3 Summary and Conclusions..................................5-131
5.3.13 Sour Water Treatment System .............................................5-133
5.3.13.1 System Modifications ...........................................5-134
5.3.13.2 Operating Experience Overview.........................5-135
5.3.13.3 Summary and Conclusions..................................5-139
5.3.14 Cooling Tower System ...........................................................5-141
5.3.14.1 System Modifications ...........................................5-142
5.3.14.2 Operating Experience Overview.........................5-142
5.3.14.3 Summary and Conclusions..................................5-143
5.4
Power Block ........................................................................................5-144
5.4.1
Combustion Turbine .............................................................5-144
5.4.1.1
System Modifications ...........................................5-145
5.4.1.2
Operating Experience Overview.........................5-145
5.4.1.3
Summary and Conclusions..................................5-146
5.4.2 Heat Recovery Steam Generator .........................................5-148
5.4.2.1
System Modifications ...........................................5-148
5.4.2.2
Operating Experience Overview.........................5-148
5.4.2.3
Summary and Conclusions..................................5-148
5.4.3 Water Treatment/Handling System ....................................5-150
5.4.3.1
System Modifications ...........................................5-150
5.4.3.2
Operating Experience Overview.........................5-150
5.4.3.3
Summary and Conclusions..................................5-151
5.4.4 Steam Turbine ........................................................................5-152
5.4.4.1
System Modifications ...........................................5-152
5.4.4.2
Operating Experience ..........................................5-152
5.4.4.3
Summary and Conclusions..................................5-152
6.0
ENVIRONMENTAL PERFORMANCE.........................................................6-1
6.1
Non-Proprietary Streams ......................................................................6-4
6.2
Conclusions ...........................................................................................6-18
6.2.1 Process Waste and Waste Water ............................................6-18
6.2.2 Air Emissions ............................................................................6-19
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7.0
ECONOMICS.....................................................................................................7-1
7.1
Actual Installed Costs for Wabash River.............................................7-1
7.2
Forecast Costs for Year 2000 Installation............................................7-5
7.3
Operational Costs...................................................................................7-6
7.3.1 Fuel Cost .....................................................................................7-6
7.3.2 Non-Fuel Operation and Maintenance Costs ..........................7-6
7.4
Economic Analysis..................................................................................7-7
7.4.1 Historical Perspective ................................................................ 7.7
7.4.2 Evaluation of Future Power Generation Projects...................7-7
SECTION III – COMMERCIALIZATION AND RECOMMENDATIONS
8.0
COMMERCIALIZATION POTENTIAL AND PLANS ............................... 8.1
9.0
CONCLUSIONS AND RECOMMENDATIONS ...........................................9-1
9.1
Success of the Demonstration Project ..................................................9-1
9.2
Commercialization Barriers and Areas of Recommended
Research ..................................................................................................9-5
9.3
Outlook....................................................................................................9-9
APPENDICES
Appendix A – Glossary of Acronyms, Abbreviations, and Symbols ........................ A-1
Appendix B – Monthly Plant Performance Data ....................................................... B-1
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Wabash River Coal Gasification Repowering Project
Final Technical Report
LIST OF FIGURES
Figure
Number
Figure ES-1
Figure ES-2
Figure ES-3
Figure 1.5A
Figure 2.0A
Figure 4.1A
Figure 4.1B
Figure 4.1.3A
Figure 4.1.3B
Figure 4.1.3C
Figure 4.1.3D
Figure 4.1.3E
Figure 4.1.3F
Figure 4.1.3G
Figure 4.1.3H
Figure 4.2.1A
Figure 4.2.2A
Figure 4.2.2B
Figure 4.2.2C
Figure 4.2.2D
Figure 5.1.1A
Figure 5.1.1B
Figure 5.1.2A
Figure 5.1.3A
Figure 5.1.3B
Figure 5.1.4A
Figure 5.1.4B
Figure 5.1.4C
Figure 5.1.4D
Figure 5.1.5A
Figure 5.1.6A
Figure 5.1.7A
Figure 5.1.7B
Figure 5.1.7C
Figure 5.1.8A
Figure 5.2.1A
Figure 5.2.2A
Figure 5.2.2B
Description
Page Number
Gasification Process Simplified Block Flow Diagram ...................... ES-2
Project Syngas Block and Power Block Availability ........................ ES-4
Syngas Production by Year.............................................................. ES-13
Project Site General Location Map.....................................................1-12
Gasification Process Simplified Block Flow Diagram .........................2-1
Project, Syngas Block and Power Block Availability ..........................4-3
Syngas Production by Year...................................................................4-6
Hours of Operation for Demonstration Period....................................4-21
Feed to Gasification Reactor for the Demonstration Period ...............4-24
1600 psig Steam Produced for Demonstration Period........................4-33
Carbonyl Sulfide in Particulate Free Syngas ......................................4-43
Produced Syngas for Demonstration Period .......................................4-49
Hydrogen Sulfide Removal Efficiency for Demonstration Period .....4-54
Sulfur Recovery Efficiency for Demonstration Period.......................4-59
Water Outfall for Demonstration Period.............................................4-66
Monitoring Locations..........................................................................4-73
Wabash River Plant Performance on Pet Coke...................................4-77
Petroleum Coke Test Overall Carbon Conversion..............................4-79
Petroleum Coke Test Flux Content.....................................................4-79
Total Sulfur in Product Syngas ...........................................................4-82
Main Air Compressor ...........................................................................5-4
Close-up of a Newly Installed Guide Vane Actuator ...........................5-9
Water Wash System ............................................................................5-12
Adsorber Beds for the Air Purification System ..................................5-15
Regeneration Heater for the Air Purification System .........................5-16
Nitrogen Vaporizer and Enclosure for Main Exchangers...................5-21
Compressor/Expander Skid ................................................................5-22
Damage Inside Enclosure for Main Exchangers.................................5-25
Derime Header Failed Weld ...............................................................5-25
High-Pressure and Low-Pressure Columns ........................................5-27
Equipment Associated with Oxygen Mixing System .........................5-32
Liquid Nitrogen Pumps.......................................................................5-36
Liquid Nitrogen Pump Skid ................................................................5-37
Liquid Nitrogen Storage Tank and High-pressure Cylinders .............5-37
Oxygen Compressor............................................................................5-42
Weigh Belt Feeder ..............................................................................5-48
Rod Mill ..............................................................................................5-51
Rod Mill Product Tank Pumps ...........................................................5-52
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Figure
Number
Description
Page Number
Figure 5.2.2C
Figure 5.2.3A
Figure 5.2.3B
Figure 5.2.4A
Figure 5.3.1A
Figure 5.3.2B
Figure 5.3.4A
Figure 5.3.4B
Figure 5.3.4C
Figure 5.3.4D
Figure 5.3.5A
Figure 5.3.6A
Figure 5.3.7A
Figure 5.3.8A
Figure 5.3.9A
Figure 5.3.9B
Figure 5.3.11A
Figure 5.3.12A
Figure 5.3.12B
Rod Mill Lube Oil Skid ......................................................................5-53
Slurry Storage Tank Agitator..............................................................5-56
Slurry Recirculation Pumps ................................................................5-56
Typical First Stage Reactor Feed Pump..............................................5-58
First Stage Gasifier Feed Nozzles.......................................................5-61
Second Stage Gasifier Slurry Feed Nozzle.........................................5-70
Slag Dewatering Tank Building and Slag Water Storage Tank..........5-74
Slag Fines Settler ................................................................................5-75
Slag Fines Settler Bottoms Pumps......................................................5-75
Slag Quench Feedwater Pumps ..........................................................5-76
Syngas Cooler & Steam Drum............................................................5-79
Wabash River Plant Downtime Summary ..........................................5-92
Major Equipment Associated with the Chloride Scrubbing System ..5-93
Carbonyl Sulfide Reactors ..................................................................5-97
Heat Exchanger Deck for Low Temperature Heat Recovery ...........5-100
Syngas Recycle Compressor and Knockout Drum ...........................5-104
Acid Gas Removal System Major Equipment ..................................5-109
Sulfur Recovery Unit Major Equipment...........................................5-119
Sulfur in No. 4 Sulfur Condenser as a Result of a Plugged
Seal Leg ............................................................................................5-127
Figure 5.3.12C Tail Gas Recycle Compressors .........................................................5-129
Figure 5.3.13A Sour Water Treatment System Major Equipment.............................5-133
Figure 5.3.14A Cooling Tower Water System...........................................................5-141
Figure 5.4.1A Combustion Turbine .........................................................................5-144
Figure 5.4.3A Water Treatment/Handling System...................................................5-150
Figure 6.0A
Monitoring Locations............................................................................6-3
Figure 8.0A
World Gasification Facility Capacity ................................................... 8.1
Figure 8.0B
Solid Fueled Gasification Facilities Starting Up Before and
After 1995 .............................................................................................8-2
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Wabash River Coal Gasification Repowering Project
Final Technical Report
LIST OF TABLES
Table
Number
Table ES-1
Table ES-2
Table ES-3
Table ES-4
Table ES-5
Table ES-6
Table 4.1A
Table 4.1B
Table 4.1C
Table 4.1.2A
Table 4.1.3A
Table 4.1.4A
Table 4.2.1A
Table 4.2.2A
Table 4.2.2B
Table 4.2.2C
Table 4.3A
Table 4.3B
Table 5.0A
Table 6.0A
Table 6.1A
Table 6.1B
Table 6.1C
Table 6.1D
Table 6.1E
Table 6.1F
Table 6.1G
Table 6.1H
Table 6.1I
Table 6.1J
Table 6.1K
Table 6.1L
Table 6.1M
Description
Page Number
Significant Operating Achievements ................................................. ES-5
Component Emissions in Pounds per MMBtu of Dry Coal Feed...... ES-6
Performance Summary .................................................................... ES-11
Wabash River Coal Gasification Repowering Project Production
Statistics ........................................................................................... ES-12
Wabash River Coal Gasification Repowering Project Costs........... ES-14
Results of Economic Analysis for Wabash River Style IGCC ........ ES-15
Significant Operating Achievements ....................................................4-4
Performance Summary .........................................................................4-5
Wabash River Coal Gasification Repowering Project Production
Statistics ................................................................................................4-6
Feedstock Analysis .............................................................................4-15
Product Syngas Quality ......................................................................4-50
Power Block Production .....................................................................4-68
Key to Monitoring Locations..............................................................4-72
Fuel Analyses......................................................................................4-76
Thermal Performance Summary.........................................................4-78
Product Syngas Analyses.................................................................... 4.80
Summary of Critical Components by Plant Area ...............................4-85.
Downtime Consequences of Critical Components by
Operational Area................................................................................4-88
WRCGRP Operating Period Downtime & Availability .......................5-2
Key to Monitoring Locations................................................................6-2
Coal Slurry Analysis .............................................................................6-4
Tail Gas Incinerator Permit Limits .......................................................6-6
Initial Compliance Stack Testing..........................................................6-6
1997 and 1998 Stack Testing Results ...................................................6-7
Annual Emission Inventory – Tail Gas Incinerator Stack
(Tons/Year) ...........................................................................................6-8
Sweet Syngas Quality ...........................................................................6-9
Flare Permit Limits ...............................................................................6-9
Combustion Turbine Permit Limits ....................................................6-10
Power Block Emissions (Tons/Year)..................................................6-11
Slag Analysis ......................................................................................6-11
Process Waste Water Permit Limits ...................................................6-13
Process Waste Water Discharge .........................................................6-14
Ash Pond Effluent (Outfall 002) Permit Limits..................................6-15
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Table
Number
Table 6.1N
Table 6.2.2A
Table 7.1A
Table 7.2A
Table 7.4A
Table B.1
Table B.2
Table B.3
Table B.4
Description
Page Number
Fugitive Emission – Tons/Year ........................................................... 6-16
Component Emissions in Pounds per MMBtu of Dry Coal Feed........ 6-19
Project Costs .......................................................................................... 7-2
Costs of Near Term IGCC Projects, $/kW .............................................7.5
Results of Economic Analysis for Wabash River Style IGCC
Single Train.......................................................................................... 7-10
1996 Monthly Plant Performance Data .................................................B-1
1997 Monthly Plant Performance Data .................................................B-2
1998 Monthly Plant Performance Data .................................................B-3
1999 Monthly Plant Performance Data .................................................B-4
Wabash River Coal Gasification Repowering Project Final Technical Report
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The following personnel contributed their time, effort, and talent in the compilation of the
information contained in this Final Technical Report:
Mr. Phil Amick
Gasification Engineering Corp.
Mr. Craig Bittle
Wabash River Energy Ltd.
Mr. David Breton
Gasification Engineering Corp.
Mr. Newell Carter
Wabash River Energy Ltd
Mr. Doug Cousins
Wabash River Energy Ltd.
Mr. Steven Douglas
Wabash River Energy Ltd.
Mr. Roy Dowd
Wabash River Energy Ltd.
Mr. Mike Hickey
Wabash River Energy Ltd.
Mr. Mitch Landess
Wabash River Energy Ltd.
Mr. Cliff Keeler
Wabash River Energy Ltd.
Mr. Thomas Lynch
Gasification Engineering Corp.
Mr. Mel Mickelson
Wabash River Energy Ltd.
Mr. H. Lou Miller
Wabash River Energy Ltd.
Mr. David McCleary
Wabash River Energy Ltd.
Mr. Dorian Pacheco
Wabash River Energy Ltd.
Mr. Richard Payonk
Wabash River Energy Ltd.
Mr. Doug Strickland
Gasification Engineering Corp.
Mr. Jack Stultz
Cinergy Corp.
Mr. Don Sturm
Wabash River Energy Ltd.
Mr. E.J. “Chip” Troxclair
Gasification Engineering Corp.
Mr. Albert Tsang
Gasification Engineering Corp.
Mr. Chancellor Williams
Wabash River Energy Ltd.
A special thanks from all the personnel listed above goes out to the Office Administrative
Assistants: Ms. Melissa Brown, Ms. Brenda Junker, and Ms. Samantha O’Dell.
Gasification Engineering Corp. and Wabash River Energy Ltd. are wholly owned subsidiaries of
Global Energy Inc.
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EXECUTIVE SUMMARY
i. General
The close of 1999 marked the completion of the Demonstration Period of the Wabash River Coal
Gasification Repowering Project.
This Final Report summarizes the engineering and
construction phases and details the learning experiences from the first four years of commercial
operation that made up the Demonstration Period under Department of Energy (DOE)
Cooperative Agreement DE-FC21-92MC29310.
This 262 MWe project is a joint venture of Global Energy Inc. (Global acquired Destec Energy’s
gasification assets from Dynegy in 1999) and PSI Energy, a part of Cinergy Corp. The Joint
Venture was formed to participate in the Department of Energy’s Clean Coal Technology (CCT)
program and to demonstrate coal gasification repowering of an existing generating unit impacted
by the Clean Air Act Amendments. The participants jointly developed, separately designed,
constructed, own, and are now operating an integrated coal gasification combined-cycle power
plant, using Global Energy’s E-Gas™ technology (E-Gas™ is the name given to the former
Destec technology developed by Dow, Destec, and Dynegy). The E-Gas™ process is integrated
with a new General Electric 7FA combustion turbine generator and a heat recovery steam
generator in the repowering of a 1950’s-vintage Westinghouse steam turbine generator using
some pre-existing coal handling facilities, interconnections, and other auxiliaries.
The
gasification facility utilizes local high sulfur coals (up to 5.9% sulfur) and produces synthetic gas
(syngas), sulfur and slag by-products. The Project has the distinction of being the largest single
train coal gasification combined-cycle plant in the Western Hemisphere and is the cleanest coalfired plant of any type in the world. The Project was the first of the CCT integrated gasification
combined-cycle (IGCC) projects to achieve commercial operation.
ii. Process Overview
The E-GasTM Process (Figure ES-1) features an oxygen-blown, continuous-slagging, two-stage,
entrained-flow gasifier. Coal is slurried in a rod mill and combined with oxygen in slurry mixers
and injected into the first stage of the gasifier, which operates at 2,600οF and 400 psia. Molten
ash falls through a taphole at the bottom of the first stage into a water quench, forming an inert
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ES-1
vitreous slag. The syngas flows to the second stage, where additional coal slurry is injected.
This coal is pyrolyzed by the hot syngas to enhance the syngas heating value and to improve
overall efficiency. Syngas leaving the gasifier flows to the high temperature heat recovery unit
(HTHRU), also referred to as the boiler, to produce high-pressure saturated steam. After cooling
in the HTHRU, particulates in the syngas are removed in a hot/dry filter and recycled to the
gasifier where the carbon in the particulates is converted into more syngas.
WRCGRP E-Gas
TM
Gasification Process
Recycle Slurry Water
Hot
BFW
Coal
Milling,
Heating &
Feeding
Slurry
Gasification
Air
Slag
Slurry
Air
Separation
Unit
Saturated
HP Steam
High Temp.
Heat
Recovery
Sour
Water
Quench
Water
Slag
Handling
Slag
Product
LTHR, Chloride
Scrubbing, COS
Hydrolysis, &
Moisturization
Particulate
Removal
Char
Oxygen
Nitrogen
Discharge
Water
Sour Water
Treatment
Tail
Gas
Sulfur
Recovery
Unit
Cool
Sour
Syngas
Acid Gas
Product
Syngas
Sweet
Syngas
Acid Gas
Removal
Sulfur
Product
Figure ES-1: Gasification Process Simplified Block Flow Diagram
Following the particulate removal system, the syngas is further cooled in the low temperature
heat recovery (LTHR) area, water-scrubbed to remove chloride, and passed through a catalyst
that hydrolyzes carbonyl sulfide (COS) to hydrogen sulfide (H2S).
H2S is removed using
methyldiethanolamine (MDEA) based absorber/stripper columns. The “sweet” syngas is then
moisturized, preheated, and piped over to the power block, where it is combusted in a General
Electric 7FA high-temperature combustion turbine/generator to produce 192 MW electricity.
The heat recovery steam generator (HRSG) configuration is optimized to utilize both the gas
turbine exhaust energy and the heat energy made available in the gasification process. Steam
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ES-2
from the HRSG and gasification process drives a Westinghouse turbine that produces 104 MW
of electricity. The power from the combustion and steam turbines, less the internally used
power, provides a net of 262 MW to the utility grid. An overall thermal efficiency of 8,900
Btu/kWh (HHV) has been demonstrated.
The gasification facility also produces two commercial by-products.
Sulfur is removed as
99.999 percent pure elemental sulfur and marketed to sulfur users and slag from the process can
be used as aggregate in asphalt roads, as structural fill in various types of construction
applications, as roofing granules, and as blasting grit.
iii. Operating Overview
Commercial operation of the facility began late in 1995.
Within a short time, both the
gasification and combined-cycle plants successfully demonstrated the ability to run at capacity
and within environmental compliance parameters.
However, numerous operating problems
adversely impacted plant reliability and the first year of operation resulted in only a 22%
availability factor. Frequent failure of the ceramic filter elements in the particulate removal
system accounted for nearly 40% of the early facility downtime. Plant reliability was also
significantly hindered by high chloride content in the syngas. The high chlorides contributed to
exchanger tube failures in the low temperature heat recovery area, COS hydrolysis catalyst
degradation and mechanical failures of the syngas recycle compressor. Ash deposits in the post
gasifier pipe spool and HTHRU created high system pressure drop, which forced the plant off
line and required significant downtime to remove. Slurry mixers experienced several failures
and the power block also contributed to appreciable downtime in the early years of operation.
Through a systematic problem-solving approach and a series of appropriate process
modifications, all of the foregoing problems were either eliminated or significantly reduced by
the end of the second operating year. In 1997, the facility availability factor was 44% and, by
1998, the availability factor had improved to 60%. As problems were solved and availability
improved, new improvement opportunities surfaced.
During the third year of commercial
operation, the facility demonstrated operation on a second coal feedstock as well as a blend of
two different Illinois No. 6 coals. The ability to process and blend new coal feedstocks improved
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ES-3
the fuel flexibility for the site, but while learning to process varying feedstocks the plant suffered
some downtime. On two occasions while processing new coals or fuel blends, the taphole in the
gasifier plugged with slag.
In 1998 and 1999 a high percentage of coal interruptions and downtime were caused by the air
separation unit (ASU). Ten coal interruptions in 1998 alone were due to the ASU. In 1999,
failure of a blade in the compressor section of the combustion turbine required a complete rotor
rebuild that idled the Project for 100 days. Run-time in 1999 was also impacted by a syngas leak
in the piping system of the particulate removal system, a main exchanger leak in the air
separation unit, another plugged taphole, and a failure of a ceramic test filter in the particulate
removal system. Consequently, the availability factor for the Project in 1999 dropped to 40%.
100.00%
80.00%
60.00%
40.00%
20.00%
0.00%
1996
Project Availability
1997
1998
Gasification Block Availability
1999
Power Block Availability
Figure ES-2: Project Syngas Block and Power Block Availability
However, 1999 clearly marked significant advances in the application of commercial IGCC as
demonstrated at Wabash River. During the third quarter of 1999, the gasification block produced
a record 2.7 trillion Btu of syngas, operated continuously without any interruption for 54 days
and finished the year at 70% availability. Figure ES-2 demonstrates how the reliability of the
technology has advanced during the Demonstration Period. The continuous improvement trend
for the gasification block, where the majority of the novel technology was demonstrated, is
encouraging and is expected to continue.
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Future operating improvements will continue to advance the technology and eliminate cost and
availability barriers.
Some of the more significant achievements and activities for the
demonstration project are highlighted in Table ES-1.
Table ES-1: Significant Operating Achievements
First coal fire in gasifier
August 17, 1995
Commercial operation begins
December 1, 1995
Start-up of chloride scrubbing system
October 1996
Initiated use of metal filter elements
December 1996
Conducted 10-day test run of petroleum coke
November 1997
1998 Governor’s Award for Excellence in Recycling
May 1998
Began running new coal feed (Miller Creek)
June 1998
Completed 14-month OSHA recordable-free period
September 1998
Surpassed 1,000,000 tons of coal processed
September 1998
Surpassed 10,000 hours of coal operation
September 1998
Surpassed 100,000,000 pounds equivalent of SO2 captured
January 1999
Record quarterly production (2,712,107 MMBtu)
3rd Quarter 1999
Longest continuous uninterrupted run (1,305 hrs)
August 12 – October 6, 1999
Conducted second successful petroleum coke run
September 1999
Record coal hours between gas path vessel entries (2,240 hr)
June to October 1999
nd
Completed 2 14-month OSHA recordable-free period
December 1999
iv. Significant Findings and Modifications
The knowledge gained during the four years of the Demonstration Period has been tremendous
and has been used to make hardware and operating changes that improve the reliability and cost
effectiveness of the facility. Many of these findings and resulting modifications are discussed in
detail in the main body of the Final Report. Some examples of significant learning experiences
have been culled from the detailed report and are briefly described by area in this section of the
Executive Summary.
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Environmental
Under the requirements of the Cooperative Agreement, a comprehensive Environmental
Monitoring Plan (EMP) has been established and followed. The solids, water and gas discharge
points as well as internal streams have been sampled and analyzed. Both on-site laboratory
personnel and contracted independent laboratories were utilized to fulfill the requirements of the
EMP. The EMP has produced a wealth of valuable data and contributed immensely to the
understanding of component partitioning throughout the gasification and combustion processes.
The collective data indicate that arsenic, selenium and cyanide (among others) either fully or
partially partition into the gas phase. Although portions of these components deposit as solids on
equipment surfaces, they typically end up in the condensed vapor stream creating elevated levels
in plant process waste water. As a result, process waste water arising from use of the current
feedstock, remains out of permit compliance due to elevated levels of arsenic, selenium and
cyanide. To rectify these concerns, plant personnel have been working on several potential
equipment modifications and treatment alternatives to bring the discharge back into compliance.
Wabash River is currently obligated to resolve this issue by September of 2001.
Turning to air emissions, WRCGRP has met or exceeded every expectation outlined in the preconstruction literature. The following table represents total air emissions based on all sources
monitored or calculated at the site during the years of 1997 and 1998. These emissions are the
lowest from any commercially sized coal-fired power plant.
Table ES-2: Component Emissions in Pounds per MMBtu of Dry Coal Feed
1997
1998
Sulfur Dioxide
0.13
0.13
Nitrogen Oxides
0.024
0.021
Carbon Monoxide
0.056
0.033
Volatile Organics
0.002
0.0021
PM10
0.012
0.011
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Air Separation Unit
Despite the high availability typical of industrial air separation units (ASU), the 2,060 ton per
day oxygen plant installed for WRCGRP has not been typical and has suffered more than
expected downtime. In 1998 and 1999, the ASU has been responsible for 11 coal interruptions
to the gasifier resulting in more than 30 days of downtime. The root causes for the majority of
these coal interruptions fall into three categories.
First, failures associated with a poorly
designed main air compressor inlet guide vane actuator system. Second, poorly designed and
incorrectly installed control instrument subsystems. Third, critical components not properly
designed for outdoor service such as non-weatherproof motor enclosures for 10,000 and 30,000
horsepower motors. The inlet guide vane system has been replaced with a new design. Many of
the questionable instrument subsystems have been modified and improved. Purges and heater
systems for the motor enclosures have been added and fixed, respectively, and the enclosures
have been made less susceptible to weather. These modifications have improved reliability, but
further enhancements are needed.
The initial performance test of the air separation unit did not meet the design nitrogen production
or power consumption targets. The original equipment manufacturer added an ancillary nitrogen
vaporizer and installed a new high-pressure oxygen recycle line, which improved production.
However, the improvements still fell short of the targeted nitrogen production.
Both the
shortfalls have resulted in higher than expected operating and maintenance cost for imported
nitrogen and power.
Coal Handling
The suction line between the slurry storage tank and the slurry recirculation pumps experienced
numerous plugging incidents, which interrupted coal operation six times during the
Demonstration Period. Investigation revealed that the agitator in the slurry storage tank was
undersized, resulting in coal settling around the perimeter of the tank and in the vicinity of the
suction line to the slurry recirculation pumps. Once the solids around the pump suction reached
a critical mass, the solids would collapse and plug the suction line. The blade length of the
agitator has been optimized to promote thorough mixing without excessive erosion of the tank
walls.
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Gasification
Reliable and direct temperature measurement within the first stage gasifier continues to be a
challenge, requiring a heavy reliance on indirect observations to control temperature of the
gasifier. The gasifier must be hot enough to ensure that molten slag flows from the taphole but
not so hot that excessive syngas is consumed, thereby reducing the heating value of the product
gas. During the Demonstration Period, five taphole-plugging incidents resulted in significant
downtime. These plugging events have occurred as a direct result of learning to process new
coal feeds or blends. Investigations after each plugging event have culminated in feed-specific
operating guidelines that ensure that proper slag flow from the gasifier is maintained.
Ash deposits formed on the walls of the second stage gasifier and downstream piping systems
significantly hampered early plant operation. As the deposit mass increased, either system
differential pressure increased or deposits broke free and plugged downstream lines or the
HTHRU tubes, forcing the plant off line. Downtime in the first two years from ash-related
problems totaled more than 47 days. Study of the ash deposits and formation patterns combined
with computational fluid dynamic modeling provided understanding of ash behavior that
suggested three solutions: first, the refractory of the second stage reactor was replaced with
material that did not form tenacious bonds with the ash. Second, the piping system was replaced
to eliminate high velocity impact zones where ash deposits preferentially formed. Third, a
screen was installed at the inlet to the boiler to catch any remaining deposits that were too big to
pass through the boiler tubes. Since installation of these modifications in 1997, not a single hour
of downtime has resulted from ash deposition.
Failures of slurry mixers have interrupted coal operation 8 times resulting in nearly 24 days of
downtime. An investigation team has studied the failure mechanisms of slurry mixers, how to
properly start-up and shutdown mixers, and how to fabricate mixers for maximum run-time and
enhanced mixing performance. Since the initial slurry mixer design, the mixer life has been
improved by more than four-fold and the average carbon content in the slag (a measure of carbon
conversion and, thus mixer performance) has been reduced more than 50%.
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ES-8
High Temperature Heat Recovery
Fouling of the boiler tubes increases the temperature of the downstream filter elements in the
particulate removal system. The higher temperature accelerates corrosion and increases the
blinding rate of the elements. Operating conditions have been identified that minimize the
fouling rate and maintenance personnel have devised cleaning mechanisms that can remove the
hard and tenacious deposits during scheduled outages, thus restoring the HTHRU to design heat
transfer conditions after outages.
Particulate Removal
Significant knowledge and experience has been gained in the particulate removal area of the
plant because frequent downtime focused plant personnel’s efforts on this challenging unit
operation from the outset of plant operation. In 1996, the particulate removal system caused
more than 100 days of downtime.
Through a significant development effort, this system
accounted for only 7 days of downtime in 1998.
During maintenance, over 10,000 pieces of hardware need to be assembled without error to
ensure that this system is reliable. Consequently, the quality assurance program over the last
four years has grown to encompass filter vendors, hardware suppliers, maintenance contractors,
and Operations personnel. The disciplined adherence to this quality assurance program is a
major contributor to the improved performance of the system.
Solutions for many of the problems associated with the particulate removal system during the
first year of operation were implemented with success, but with each solution a new problem was
discovered. After many attempts to improve the filter hardware system, it became evident that
many of these design problems were quite complex and as a result, the system was retrofitted
with metal filter elements late in 1996. Metal elements immediately improved reliability of the
system and improvement efforts were turned to developing a filter with a lower operating and
maintenance (O&M) cost.
Essentially all applicable commercially available filters for this type service have been tested in
the on-site slipstream unit. Off-line cleaning techniques have been developed and improved.
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Filter blinding and corrosion mechanisms remain an intense area of study. Computational fluid
dynamic models have been employed to optimize the gas distribution systems within the filter
vessels. Hands-on project engineers work directly with metallurgists and vendors to minimize
errors and leverage each other’s expertise. The ejector system that returns the particulates to the
reactor has also been studied and optimized for maximum reliability and lower O&M cost.
Process conditions have been evaluated and modified to minimize element corrosion and provide
a balanced flow of syngas to each cluster of elements. The control system has been improved to
optimize the operation of the pulse cleaning system. A sophisticated control algorithm and alarm
provides operating personnel with advanced warning of potential filter system problems so that
immediate corrective actions can be taken before the filters become inoperable. Indeed, Global
Energy’s filter improvement program is not only wide in its breadth but deep as well.
Low Temperature Heat Recovery
The low temperature heat recovery system accounted for more than 40 days of downtime in the
first year of operation and cost the Project significant dollars to repair or replace failed
exchangers and replace spent catalyst.
Investigation of the root cause revealed that trace
chlorides and metals from the coal remained in the syngas and that these trace components
rapidly poisoned the COS hydrolysis catalyst.
Investigators also determined that water
condensing from the syngas concentrated chlorides in the tubes of the low temperature heat
exchangers resulting in chloride stress-corrosion-cracking of the exchanger tubes. Expensive
catalyst replacement and frequent repairs to exchanger tubes initiated a fast-track project to
install a chloride scrubbing system and replace the failing exchangers with exchangers
manufactured from alloys impervious to chloride attack.
The scrubber project went from
inception to operation in 6 months, and the low temperature heat recovery system has not
experienced a single hour of downtime related to chlorides since the scrubber went into operation
in October of 1996.
Concurrent with the design and installation of the chloride scrubber, a slipstream unit was
installed to test various COS hydrolysis catalysts. The object was to find a catalyst with a
probable 5-year life. An appropriate catalyst was found and installed after start-up of the
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chloride scrubber system. Samples taken of the catalyst after two years of operation indicate that
the 5-year life is easily obtainable.
Acid Gas Removal
One problem that beset this system in the first three years of operations was the build-up of heat
stable salts in the amine solution. Heat stable salts decrease the removal efficiency of the amine
solution, ultimately resulting in higher sulfur emissions from the facility.
Although the
WRCGRP initially included a process to remove heat stable salts, the initial system was
unreliable, costly, and required frequent maintenance. As a result, frequent and costly on-site
vacuum distillation or solution replacement was required during the early operation. Numerous
process improvements and changes improved reliability of the system and then, in August of
1999, a capacity expansion was installed which satisfied all the remaining system limitations.
Since that modification, the system has proved to be very reliable and removes heat stable salts
faster than they are formed.
v. Plant Performance
Despite reliability issues during the first two years of operation, the actual performance of the
plant during coal operation compares favorably with design as indicated in Table ES-3.
Table ES-3: Performance Summary
Design
Actual
1,780
1,690 (1825 max)
Combustion Turbine Capacity, MW
192
192
Steam Turbine Capacity, MW
105
96
Auxiliary Power, MW
35.4
36
Net Power, MW
262
252
9,030
8,900
Sulfur Removal Efficiency, %
>98
>99
SO2 Emissions, lbs/MMBtu
<0.2
<0.1
Syngas Heating Value (HHV)
280
275-280
Syngas Sulfur Content (ppmv)
<100
<100
Syngas Capacity, MMBtu/hr
Plant Heat Rate, Btu/kWh
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The plant has demonstrated a maximum capacity of 1,825 MMBtu/hr but requires only
1,690 MMBtu/hr to satisfy the requirements of the combustion turbine at full load. The noted
steam turbine capacity shortage requires a HRSG feedwater heater modification to bring output
up to design. With this modification, the overall plant heat rate will drop to 8,650 Btu. The air
separation unit was unable to meet the guaranteed power specification, which accounts for the
difference in auxiliary power. As indicated previously, the environmental performance of the
plant has been superior. Sulfur removal efficiencies all exceed design and total demonstrated
sulfur dioxide emissions have been as low as 0.03 lb/MMBtu of dry coal feed. This quantity is
1/40 that of the SO2 emissions limit of 1.2 lb/MMBtu with at least a 90% reduction. Likewise,
NOX, CO and particulate emissions average 0.022, 0.044 and 0.012 lb/MMBtu respectively.
Based on these data, the WRCGRP is the cleanest coal-fired power plant in the world.
Operation in 1998 was highlighted by several months where syngas production exceeded one
trillion Btu of gas produced. This production milestone was met in March, April, October and
November of 1998. As previously indicated, the highest quarterly production of syngas occurred
in the third quarter of 1999 in which 2,712,107 MMBtu of gas were produced.
Syngas
production in September of 1999 was 1,204,573 MMBtu, the highest ever for a month.
Furthermore, the combustion turbine operated at maximum capacity for all but 7 hours in
September. Key production statistics for the Demonstration Period are presented in Table ES-4.
Table ES-4: Wabash River Coal Gasification Repowering Project Production Statistics
On Coal
Time Period
(Hr)
Start-up ‘95
Coal
Processed
(tons)
On Spec.
Gas
(MMBtu)
Steam
Produced
(Mlb)
Power
Produced
(MWh)
Sulfur
Produced
(tons)
505
41,000*
230,784
171,613
71,000*
559
1996
1,902
184,382
2,769,685
820,624
449,919
3,299
1997
3,885
392,822
6,232,545
1,720,229
1,086,877
8,521
1998
5,279
561,495
8,844,902
2,190,393
1,513,629
12,452
1999 3,496
369,862
5,813,151
1,480,908
1,003,853
8,557
15,067
1,549,561
23,891,067
6,383,767
4,125,278
33,388
Overall
* Estimates. Note: The combustion turbine was unavailable from 3/14/99 through 6/22/99.
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Early identification of availability-limiting process problems led to aggressive implementation of
improvement projects which resulted in 224% more syngas produced during the second year
than in year one.
The syngas produced during the third year exceeded the second year’s
production by an additional 42%.
Assuming the availability factor during the combustion
turbine outage was the same as in 1998, the facility production in 1999 would have favorably
matched 1998's output. Figure ES-3 depicts this continuous improvement trend over the last four
Trillion Btu of Syngas Produced
years as measured by total syngas production.
10
8
6
4
2
0
1996
1997
1998
1999 adjusted for
CT outage
Figure ES-3: Syngas Production by Year
vi. Economics and Commercialization
The initial budgeted cost for the construction of the Wabash River facility was $248 million for
the syngas facility (Destec scope) and approximately $122 million for the new power block and
modifications to the existing Wabash River Generating Station (PSI Energy scope).
The
installed cost of the overall IGCC facility including start-up was about $1590/kW (1994$).
Allowing for new equipment that would have been required if this had been a greenfield project
instead of repowering, the installed cost figure on this demonstration project was $1700/kW
(1994$).
As shown in Table ES-5, nearly all cost areas within the syngas facility were completed under
budget, with the exception of the construction cost and the pre-operations management cost of
the syngas facility.
Overruns of the power block budget were in the same areas.
The
construction cost was nearly double the budgeted amount, due to four factors, many beyond the
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control of the Project participants. Weather delays, equipment shipping problems, mechanical
contracting and a prolonged start-up period combined to escalate the construction cost. Despite
the construction delays, start-up of the facility occurred on schedule and only three years and
four months from the DOE award date, significantly shorter than any other IGCC project. Even
with the cost overruns, the Project was by far the least expensive of the first generation coal
gasification combined cycle plants built in the 1992-2000 timeframe. The other coal IGCC’s,
two in the U.S. and two in Europe, all first generation at this scale, have been reported to have
cost $2000/kW and over.
Table ES-5: Wabash River Coal Gasification Repowering Project Costs
Cost Area
Budget
Actual
Engineering & Project Management
29.6
27.3
Equipment Procurement
98.3
84.5
Construction
55.5
106.1
Construction Management
7.9
8.1
ASU
36.9
32.8
Pre-operations Management
19.8
21.7
POWER BLOCK
121.8
136.2
Total $MM, 1994 average
369.8
416.6
SYNGAS FACILITY
Future IGCC facilities based on the E-Gas™ technology will benefit from the lessons learned at
Wabash River. A realistic number for a current generation plant is $1,250 - $1,300/kW (2000$)
with a heat rate of 8,250 Btu/kW (HHV) for a greenfield facility. A new, stand-alone greenfield
IGCC to produce power, but no other products, and utilizing petroleum coke as fuel has an
approximate installed cost of $1100 - $1200/kW (2000$), based on reduced equipment
requirements with petroleum coke feeds.
The IGCC model developed by Nexant LLC for the DOE was used to evaluate the rate of return
for projects financed IGCC’s at today’s fuel and power prices. As evidenced in Table ES-6, the
strongest driver of overall plant economics is fuel cost. The economic analyses of project returns
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with coal as a feedstock reach a credible economic condition of 12% IRR at power pricing of
$38 - $49/MWh, depending on how capital and O&M costs are set and on the availability that is
assumed. Plant design and operation based on petroleum coke is economically stronger, due not
only to the lower fuel cost, but also the incrementally improved capital and operating costs for a
plant designed for petroleum coke initially.
Table ES-6: Results of Economic Analysis for Wabash River Style IGCC
Coal
Petroleum Coke
Plant Net Generation, MW
270
271
Plant Heat Rate, Btu/kWh (HHV)
8910
8790
Plant Capital Cost, $/kW
1275
1150
Plant Operating Cost, % of capital
5.2
4.5
Annual Availability
75%
80%
( 128 )
45
NA
14%
NPV10, Millions $
Internal Rate of Return, at $35/MWh power
Sensitivity Analysis Cases, 12% IRR
Required $/MWh in first year
10% reduction in capital
46
30
10% reduction in O&M
49
32
10% increase in availability
42
27
38
24
10% reduction in capital, O&M
10% increase in availability
O&M costs have been relatively high for IGCC plants compared to conventional coal-fired
plants. Using 1999 budgeted costs as a basis, the non-fuel O&M cost for the syngas facility was
7.1% of installed capital based on a 75% operating rate. Since Global Energy manages the
Wabash River facility as a stand-alone plant, all the infrastructure and support base for labor and
maintenance must be provided at the site. This includes contract administration, accounting,
inventory, human resources, engineering, environmental and safety, laboratory staff and a base
maintenance and operating staff. Since the first year of operation, the syngas facility has reduced
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O&M spending by 30% and further areas for reduction have been identified. Projected O&M for
a mature Wabash River syngas facility is 5.2% of installed capital. O&M savings for future
plants can be realized by sharing infrastructure cost within, for example, a large petrochemical
facility.
Market penetration for gasification technologies is rapidly increasing. Gasification-produced
megawatts will increase ten-fold from 1992 to 2002, based on plants already in operation or
construction. The current opportunities are not primarily in power generation, however. The
opportunities are in co-production facilities, especially those able to use opportunity fuels.
Exploring low-cost feedstocks and high-value products stretches both ends of the economic
equation. These facilities seem to be primarily in the refining sector, and it is expected that most
of the next generation of solid fuel gasification plants will be inside the fences of refineries, as
opposed to the entire first generation of greenfield and repowering applications for power
generation facilities.
vii. Conclusions
Despite firm technical and operating experience gained at Dow’s gasification plant in Louisiana
(LGTI), several operating differences set the Wabash River plant apart from its predecessor. In
addition, Wabash River incorporated several technical advances never attempted at the LGTI
facility.
During the Demonstration Period the operating differences have been resolved and the technical
advances have proven successful. Operation of the E-Gas™ technology on several different high
sulfur bituminous coals and blends has been achieved with the lowest environmental emissions
of any coal-fired power plant. Even though it had never been previously attempted, the Project
repowered a 40 year old utility plant as an IGCC with a high level of integration between the
gasification heat recovery unit, the combustion turbine HRSG and the reheat steam turbine. The
facility initiated use of one of the first ten General Electric “F” class machines and the first such
machine operating on syngas. The Project considerably advanced the technology of particulate
filtration and the Wabash River system represents one of the few systems of this size and with
much higher particulate loading than other operating systems.
Ash deposition, an early
downtime cause, has been completely eliminated. Previous gasification operating expertise has
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been magnified and a new generation of engineers and operators has been developed to operate
the plant safely and reliably, with ever-increasing availability.
Significant challenges were met and overcome in areas outside of the primary demonstration
objectives, including technical, commercial and organizational challenges. The Project also
demonstrated success in some areas that were not planned at the outset – operation on petroleum
coke, for instance, and operation on a blend and combination of coals that sometimes changes
daily. The Project operates today as part of the utility power generation system, competing with
Cinergy’s alternative market options for on-peak and off-peak power. Competitive market-based
pricing allows the syngas facility to run as base load in Cinergy’s system
All of these advances demonstrated at the Wabash River Coal Gasification Repowering Project
are leading to more confidence in the commercialization of the technology in other settings
besides coal and power. These advances in the technology will be leveraged into the next
generation of power and chemical production megaplexes as Global Energy participates in the
DOE’s “Vision 21” program and other viable commercial projects.
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1.0
INTRODUCTION
The Wabash River Coal Gasification Repowering Project (WRCGRP or “Project”) is currently
the largest single-train gasification facility in the United States, as well as the cleanest coal fired
plant of any kind in the world. Its design allows for lower emissions than other high sulfur coal
fired power plants and a resultant heat rate improvement of approximately 20% over the previous
plant configuration.
The Wabash River gasification facility was developed, designed,
constructed, started-up and is currently operated by what are now Wabash River Energy Ltd.
(WREL) personnel. Wabash River Energy Ltd. is a wholly owned subsidiary of Global Energy
Inc. The Project successfully operated through a Demonstration Period from November of 1995
through December of 1999.
The original Project participants, Destec Energy, Inc. (which was later acquired by Dynegy
Power Corporation (Dynegy) of Houston, Texas, and PSI Energy, Inc. (PSI), of Plainfield,
Indiana, formed a Joint Venture (JV) to participate in the United States Department of Energy’s
(DOE) Clean Coal Technology (CCT) program to demonstrate coal gasification repowering of
an existing generating unit impacted by the Clean Air Act Amendments (CAAA).
The
participants jointly developed, separately designed, constructed, own, and are now operating an
integrated coal gasification combined-cycle power plant, using Destec’s coal gasification
technology (now known as E-GasTM Technology) to repower the oldest of the six units at PSI’s
Wabash River Generating Station in West Terre Haute, Indiana.
In 1999, Global Energy
acquired the Project and the gasification technology from Dynegy. The gasification process is
integrated with a new General Electric 7FA combustion turbine generator and a heat recovery
steam generator in the repowering of a 1950’s-vintage Westinghouse steam turbine generator
using some pre-existing coal handling facilities, interconnections and other auxiliaries. The
Project processes locally-mined Indiana high sulfur coal to produce 262 net megawatts of
electricity.
The Project has demonstrated the ability to run at full load capacity while meeting the
environmental requirements for sulfur and NOx emissions. Cinergy, PSI’s parent company,
dispatches power from the Project, with a demonstrated heat rate of under 9,000 Btu/kWh
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(HHV), second only to their hydroelectric facilities on the basis of environmental emissions and
efficiency.
In late 1998, PSI Energy reached agreement to purchase the gasification services contract from
Dynegy subject to regulatory approval. Regulatory approval was granted in September of 1999
and the sale was completed in October of 1999
This agreement allowed PSI to purchase the remaining term of the 25-year contract, which had
become “out-of-market” in comparison to today’s alternate sources for power. WREL explored
alternatives for continued operation of Wabash River in a more “market-based” mode. In June
of 2000, Global Energy Inc. announced that WREL had entered into a competitive market
contract with PSI for the sale of syngas. Syngas, sold under this market-based three year
agreement, is priced to allow the power produced from the syngas to compare favorably yearround to PSI’s alternate sources for on-peak and off-peak power.
This recent development, coupled with efforts to improve the commercial viability of the
Wabash River Coal Gasification Repowering Project, has sharpened the focus to make the
technology competitive in today’s market.
Building on the lessons learned and the many
successes to date, every effort is being made to look past just syngas-to-power and to pursue
value-added uses for syngas produced from coal or other feeds such as is envisioned through
forward-thinking concepts like the Department of Energy’s “Vision 21” initiative. In the face of
the current market for gasification, WREL and Global Energy will pursue the application of this
technology forward as an economically viable tool for converting carbon feedstocks to higher
value products.
Global Energy is an Independent Power Producer (IPP) with gasification technology experience.
A founding member of the Gasification Technologies Council (GTC) in Washington D.C.,
Global Energy is one of the most experienced and innovative companies in the commercial
gasification business. Global Energy will market the E-GasTM technology through its subsidiary,
Gasification Engineering Corp., a company formed by Global Energy after acquiring all the
gasification assets of Dynegy, Inc. in late 1999.
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Gasification Engineering Corp.
and WREL personnel, have over 1000 years of combined
industrial experience. Nearly one third of this experience, about 300 years, is directly related to
the design, implementation and operation of gasification plants.
This expertise is a
complementary addition to Global Energy’s existing gasification experience base, which also
totals approximately 300 years of combined experience.
This group has a wide-ranging theater of operations, from the daily operation of the Wabash
River facility and gasification project development and construction to research and development
in several gasification-related fields. Although the group has a vast network of contacts in
related industries for ceramic, refractory, metallurgy, instrumentation and other technologies
with applications in gasification, most expertise exists in-house in the areas of operations,
process modeling, process design, gasification component design (such as slurry mixers), char
filtration, and mechanical equipment applications.
1.1
Objectives
For CCT Round IV, Public Law 101-121 provided $600 million to conduct cost-shared CCT
projects to demonstrate technologies that are capable of replacing, retrofitting or repowering
existing facilities.
To that end, a Program Opportunity Notice (PON) was issued by the
Department of Energy in January 1991, soliciting proposals to demonstrate innovative energyefficient technologies that were capable of being commercialized in the 1990’s.
These
technologies were to be capable of: (1) achieving significant reductions in the emissions of sulfur
dioxide and/or nitrogen oxides from existing facilities to minimize environmental impacts such
as transboundary and interstate pollution and/or; (2) providing for future energy needs in an
environmentally acceptable manner.
In response to the PON, the DOE received 33 proposals in May 1991. After evaluation, nine
projects were selected for award.
These projects involved both advanced engineering and
pollution control technologies that can be “retrofitted” to existing facilities and “repowering”
technologies that not only reduce air pollution but also increase generating plant capacity and
extend the operating life of the facility.
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In September 1991, the United States Department of Energy selected the Wabash River Coal
Gasification Repowering Project, as one of nine projects, for funding under Round IV of the
DOE’s Clean Coal Technology Demonstration Program. This was followed by nine months of
negotiations and a congressional review period. The DOE executed a Cooperative Agreement on
July 28, 1992. The Project’s sponsors, PSI Energy, Inc., and Global Energy, are demonstrating,
in a fully commercial setting, coal gasification repowering of an existing generating unit affected
by the Clean Air Act Amendments (CAAA). The Project also demonstrates important advances
in the coal gasification process for high sulfur bituminous coal. After receiving the necessary
state, local and federal approvals, this Project began construction in the third quarter of 1993 and
started commercial operations in the third quarter of 1995. This facility, originally scheduled for
a three-year Demonstration Period and 22-year Operating Period (25 years total), extended the
demonstration to span four years and successfully completed this demonstration in December of
1999.
The demonstration confirmed the successful design, construction, and operation of a nominal
2500 ton-per-day, 262 net MWe integrated gasification combined cycle (IGCC) facility using the
advanced two-stage, oxygen blown Destec (now E-GasTM) technology. The DOE’s share of this
Project cost was $219 million.
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1.2
General
The IGCC system consists of:
•
The E-GasTM oxygen-blown, entrained flow, two stage coal gasifier, which is capable of
utilizing high sulfur bituminous coal;
•
An air separation unit;
•
A gas conditioning system for removing sulfur compounds and particulates;
•
Systems or mechanical devices for improved coal feed and all necessary coal handling
equipment;
•
A combined cycle power generation system wherein the gasified coal syngas is
combusted in a combustion turbine generator;
•
A heat recovery steam generator.
The result of repowering is an IGCC power plant with low environmental emissions (SO2 of less
than 0.25 lbs/MMBtu and NOx of less than 0.1 lb/MMBtu) and high net plant efficiency. The
repowering increases unit output, providing a total IGCC capacity of nominal 262 net MWe.
The Project demonstrates important technological advancements in processing high sulfur
bituminous coal.
In addition to the original Joint Venture members, PSI and Destec, the Phase II project team
included Sargent & Lundy, who provided engineering services to PSI, and Dow Engineering,
who provided engineering services to Destec.
The potential market for repowering with the demonstrated technology is large and includes
many existing utility boilers currently fueled by coal, oil or natural gas. In addition to greater,
more cost-effective reduction of SO2 and NOx emissions attainable by using the gasification
technology, net plant heat rate is improved. This improvement is a direct result of the combined
cycle feature of the technology, which integrates a combustion topping cycle with a steam
bottoming cycle. This technology is suitable for repowering applications and can be applied to
any existing steam cycle located at plants with enough land area to accommodate coal handling
and storage and the gasification and power islands.
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One of the Project objectives is to advance the commercialization of coal gasification
technology.
The electric utility industry has traditionally been reluctant to accept coal
gasification technology and other new technologies as demonstrated in the U.S. and abroad
because the industry has no mechanism for differentiating risk/return aspects of new
technologies.
Utility investments in new technologies may be disallowed from rate-base
inclusion if the technologies do not meet performance expectations. Additionally, the rates of
return on these are regulated at the same level as established lower risk technologies. Therefore,
minimal incentives exist for a utility to invest in, or develop, new technologies. Accordingly, the
supplier has traditionally assumed most of the risk in new technologies.
The factors described above are constraints to the development of, and demand for, clean coal
technologies. Constraints to development of new technologies also exist on the supply side.
Developers of new technologies typically self-finance or obtain financing for projects through
lenders or other equity investors.
Lenders will generally not assume performance and
operational risks associated with new technology. The majority of funds available from lending
agencies for energy-producing projects are for technologies with demonstrated histories in
reliability, maintenance costs and environmental performance. Equity investors who invest in
new energy technologies also seek higher returns to accept risk and often require the developer
of the new technology to take performance and operational risks.
Consequently, the overall scenario results in minimum incentives for a commercial size
development of new technologies. Yet without the commercial size test facilities, the majority of
the risk issues remain unresolved.
Addressing these risk issues through utility scale
demonstration projects is one of the primary objectives of DOE’s Clean Coal Technology
Program.
The WRCGRP was developed in order to demonstrate the E-GasTM Coal Gasification
Technology in an environment, and at such a scale, as to prove the commercial viability of the
technology. Those parties affected by the success of this Project include the coal industry,
electric utilities, ratepayers and regulators.
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Also, the financial community, which provides the funds for commercialization, is keenly
interested in the success of this Project. Without a demonstration satisfying all of these interests,
the technology will make little advancement. Factors of relevance to further commercialization
are:
•
The Project scale (262 net MWe) is compatible with all current, commercially available
advanced gas turbines and thus completely resolves the issue of scale-up risks.
•
The operational term of the Project is expected to be approximately 25 years including
the DOE Demonstration Period of the first 3 years (actually 4 years). This should
alleviate any concerns that the demonstration does not define a fully commercial plant
from a cost and operational viewpoint.
•
The Project dispatches on a utility system and is called upon to operate in a manner
similar to other utility generating units.
•
The Project operates under a service agreement that defines guarantees of environmental
performance, capacity, availability, coal to gas conversion efficiency and maximum
auxiliary power consumption.
commercialization of the E-Gas
This agreement serves as a model for future
TM
Coal Gasification Technology and defines the fully
commercial nature of the Project.
•
The Project is designed to accommodate most coals available in Indiana and typical of
those available to midwestern utilities, thereby enabling utilities to judge fuel flexibility.
The Project also enables testing of varying coal types and other feedstocks in support of
future commercialization of the E-GasTM Coal Gasification Technology.
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1.3
Project Phase Description
The Project Cooperative Agreement (CA) was signed on July 28, 1992, with an effective date of
August 1, 1992. Under the terms of the CA, the Project activities were divided into three phases:
•
Phase I
Engineering and Procurement
•
Phase II
Construction and Start-up
•
Phase III Demonstration
1.3.1 Phase I Activities – Engineering and Procurement
Under the provisions of the CA, the work activity in Phase I (engineering and procurement)
focused on detailed engineering of both the syngas and power plant elements of the Project
which included design drawings, construction specifications and bid packages, solicitation
documents for major hardware and the procurement. Site work was undertaken during this time
period to meet the overall construction schedule requirements. The Project team included all
necessary management, administrative and technical support.
The activities completed during this period were those necessary to provide the design basis for
construction of the plant, including capital cost estimates sufficient for financing, and all
necessary permits for construction and subsequent operation of the facility.
The work during Phase I can be broken down into the following main areas:
•
Project Definition Activities
•
Plant Design
•
Permitting and Environmental Activities
Each of these activities is briefly described below. All Phase I activities were complete by 1993.
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Project Definition Activities
This work included the conceptual engineering to establish the Project size, installation
configuration, operating rates and parameters.
Definition of required support services, all
necessary permits, fuel supply, and waste disposal arrangements were also developed as part of
the Project Definitions Activities. From this information, the cost parameters and the Project
economics were established (including capital costs, project development costs and operation
and maintenance costs). Additionally, all project agreements necessary for construction of the
plant were concluded. These include the CA and the Gasification Services Agreement (GSA).
Plant Design
This activity included preparation of design and major equipment specifications along with plant
piping and instrumentation diagrams (P&ID’s), process control releases, process descriptions and
performance criteria. These were prepared in order to obtain firm equipment specifications for
major plant components, which established the basis for detailed engineering and design.
Permitting and Environmental Activities
During Phase I, applications were made and received for the permits and environmental activities
necessary for the construction and subsequent operation of the Project.
1.3.2 Phase II Activities – Construction
Construction activities occurred in Phase II and included the necessary construction planning and
integration with the engineering and procurement effort. Planning the construction of the Project
began early in Phase I. Separate on-site construction staffs for both Destec and PSI were
provided to focus on their respective work for each element of the Project.
Construction
personnel coordinated the site geo-technical surveys, equipment delivery, storage, and lay down
space requirements.
The construction activities included scheduling, equipment delivery,
erection, contractors, security and control.
The detail design phase of the Project included engineering, drawings, equipment lists, plant
layouts, detail equipment specifications, construction specification, bid packages and all
activities necessary for construction, installation, and start-up of the Project.
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Performance and progress during this period were monitored in accordance with previously
established baseline plans.
1.3.3 Phase III Activities – Demonstration Period
Phase III consisted of a three-year (extended to four years) Demonstration Period. The operation
effort for the Project began with the development of the operating plan including integration with
the early engineering and design work of the Project. Plant operation input to engineering was
vital to assure optimum considerations for plant operations and maintenance and to assure high
reliability of the facilities. The operating effort continued with the selection and training of
operating staff, development of the operating manuals, coordination of start-up with
construction, planning and execution of plant commissioning, conduct and documentation of the
plant acceptance test, and continued operation and maintenance of the facility throughout the
Demonstration Period.
Phase III activities were intended to establish the operational aspects of the Project in order to
prove the design, operability and longevity of the plant in a fully commercial utility environment.
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1.4
Project Organization
The WRCGRP Joint Venture (JV) established a Project Office for the execution of the Project.
The Project Office was originally located at Dynegy's corporate offices in Houston, Texas. All
management, reporting and project reviews for the Project are carried out as required by the
Cooperative Agreement. The JV partners, through a JV Agreement, are responsible for the
performance of all engineering, design, construction, operation, financial, legal, public affairs
and other administrative and management functions required to execute the Project. A JV
Manager was designated as responsible for the management of the Project. The JV Manager was
the official point of interface between the JV and the DOE for the execution of the Cost Sharing
Cooperative Agreement. The JV Manager was responsible for assuring that the Project is
conducted in accordance with the cost, schedule, and technical baseline established in the Project
Management Plan (PMP) and subsequent updates.
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1.5
Project Location and Original Equipment Description
The site of the Project is PSI’s Wabash River Generating Station, located on approximately 437
acres northwest of Terre Haute, Indiana in Vigo County. Indianapolis, the state capital, is
located approximately 65 miles to the east-northeast of Terre Haute. The Illinois border is
located approximately 7 miles to the west of Terre Haute. A general location map depicting the
location of the Project, in reference to the existing Wabash River Generating Station Station is
shown in Figure 1.5A. The region surrounding the property may be described as wooded with
gently rolling terrain to the north, west and south and river valley (Wabash River) to the east.
The Project is located within Vigo County, but outside the municipal limits of Terre Haute,
Indiana.
Figure 1.5A: Project Site General Location Map
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PSI’s existing equipment at the Wabash River Station consisted of six pulverized-coal generating
units. Units 1 through 4 boilers were manufactured by Foster-Wheeler, the Unit 5 boiler was
manufactured by Riley Stoker, and the Unit 6 boiler was manufactured by Combustion
Engineering. At the time of initial Project development each unit featured a Research-Cottrell
electrostatic precipitator, shared a common 450-foot tall exhaust stack, and was fueled by
pulverized bituminous coal, while fuel oil was used for start-up and flame stabilization. Natural
gas was not used at the Station, although a main transmission line of Indiana Gas Company was
located approximately 1 mile west of the powerhouse.
The Unit 1 steam turbine, repowered by implementation of the Project, was permitted at 99 MW
under the Station’s existing air quality permit (limited to 90 MW during routine operations).
This unit was put into service in 1953. An electrostatic precipitator (two units in parallel with a
98.5 percent collection efficiency) was used for the control of particulates.
The Wabash River was and is the sole water source for all consumptive and nonconsumptive
water systems at the Station.
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1.6
Permitting and Environmental Activities
During Phase I, applications were made and received for the permits and environmental activities
necessary for the construction and subsequent operation of the Project. The major permits for
the Project included:
•
Indiana Utility Regulatory Commission – The state authority reviewed the Project (under
a petition from PSI for a Certificate of Necessity) to ensure the Project will be beneficial
to the state and PSI ratepayers. The technical and commercial terms of the Project were
reviewed in this process.
•
Air Permit – This permit details the allowable emission levels for air pollutants from the
Project.
It was issued under standards established by the Indiana Department of
Environmental Management (IDEM) and the United States Environmental Protection
Agency (EPA) Region V and administered by Vigo County Air Pollution Control. This
permit also included within it the authority to commence construction.
•
NPDES Permit – This National Pollutant Discharge Elimination System permit details
and controls the quality of waste water discharge from the Project. It was reviewed and
issued by the Indiana Department of Environmental Management. For this Project, this
constituted a modification of the existing permit for PSI’s Wabash River Generating
Station.
•
NEPA Review – The National Environmental Policy Act review was carried out by the
DOE based on Project information provided by the participants. The scope of this review
was comprehensive in addressing all environmental issues associated with potential
Project impacts on air, water, terrestrial, quality, health and safety, and socioeconomic
impacts.
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Miscellaneous permits and approvals necessary for construction and subsequent operation of the
Project included the following.
•
FAA Stack Height/Location Approval
Controlling Authority: Federal Aviation Administration
•
Industrial Waste Generator
Controlling Authority: Indiana Department of Environmental Management
•
Solid Waste
Controlling Authority: Indiana Department of Environmental Management
•
FCC Radio License
Controlling Authority: Federal Communications Commission
•
Spill Prevention Plan
•
Waste Water Pollution Control Device Permit
Controlling Authority: Indiana Department of Environmental Management
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2.0
TECHNOLOGY DESCRIPTION
The E-GasTM (Destec) Gasification Process features an oxygen-blown, continuous-slagging, twostage, entrained-flow gasifier (Figure 2.0A). Coal or coke is milled with water in a rod mill to
form a slurry. The slurry is combined with oxygen in mixer nozzles and injected into the first
stage of the gasifier, which operates at 2600°F and 400 psig. A turnkey 2,060-ton/day lowpressure cryogenic distillation facility that WREL owns and operates supplies 95% pure oxygen.
WRCGRP E-Gas
TM
Gasification Process
Recycle Slurry Water
Hot
BFW
Coal
Milling,
Heating &
Feeding
Slurry
Gasification
Air
Slag
Slurry
Air
Separation
Unit
Saturated
HP Steam
High Temp.
Heat
Recovery
Sour
Water
Quench
Water
Slag
Handling
Slag
Product
LTHR, Chloride
Scrubbing, COS
Hydrolysis, &
Moisturization
Particulate
Removal
Char
Oxygen
Nitrogen
Discharge
Water
Sour Water
Treatment
Tail
Gas
Sulfur
Recovery
Unit
Cool
Sour
Syngas
Acid Gas
Product
Syngas
Sweet
Syngas
Acid Gas
Removal
Sulfur
Product
Figure 2.0A: Gasification Process Simplified Block Flow Diagram
In the first stage, slurry undergoes a partial oxidation reaction at temperatures high enough to
bring the coal’s ash above its melting point. The fluid ash falls through a taphole at the bottom
of the first stage into a water quench, forming an inert vitreous slag. The syngas then flows to
the second stage, where additional coal slurry is injected.
This coal is pyrolyzed in an
endothermic reaction with the hot syngas to enhance syngas heating value and to improve overall
efficiency.
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The syngas then flows to the high-temperature heat-recovery unit (HTHRU), essentially a
firetube steam generator, to produce high-pressure saturated steam.
After cooling in the
HTHRU, particulates in the syngas are removed in a hot/dry filter and recycled to the gasifier
where the carbon in the char is converted to syngas. The syngas is further cooled in a series of
heat exchangers, water-scrubbed to remove chlorides, and passed through a catalyst that
hydrolyzes carbonyl sulfide to hydrogen sulfide.
Hydrogen sulfide is removed using
methyldiethanolamine (MDEA) absorber/stripper columns.
The “sweet” syngas is then
moisturized, preheated and piped over to the power block, where it is burned in a General
Electric 7FA high-temperature combustion turbine/generator to produce 192 MW of electricity.
The HRSG configuration was specifically optimized to utilize both the gas-turbine exhaust
energy and the heat energy made available in the gasification process.
Superheated high-
pressure steam, when fed to the repowered Westinghouse reheat steam turbine, produces 104
MW, by design, of additional electricity.
When combined with the combustion turbine
generator’s 192 MW and the system’s auxiliary load of approximately 34 MW, a net of 262 MW
is produced to feed the Cinergy grid. An overall thermal efficiency of less than 9,000 Btu/kWh
(HHV), which is lower than the design, has been demonstrated. Please note that a lower heat
rate indicates greater thermal efficiency.
The gasification facility also produces two commercial by-products.
Sulfur is removed as
99.999% pure elemental sulfur and marketed to sulfur users. Slag is being marketed as an
aggregate in asphalt roads, as structural fill in various types of construction applications, as
roofing granules, and as blasting grit.
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3.0
DETAILED PROCESS DESCRIPTION
The E-Gas™ gasification process is based on slurry (or liquid) feed utilizing a two-stage gasifier
with total solids recycle and coupled with a unique high temperature heat recovery unit.
Gasification is accomplished by partial combustion of the feedstock with air or high purity
oxygen in the first stage creating hot synthetic gas with the mineral content forming a molten
slag. The slag is continuously removed from the gasifier via E-Gas™’s proprietary low-profile
slag removal system. This avoids expensive, structure-elevating and maintenance-prone lock
hoppers. In the second stage, the heat content of the hot syngas from the first stage is used to
vaporize and gasify additional coal slurry introduced in the second stage. The syngas exiting the
gasifier is cooled and cleaned, and is then moisturized prior to use in an advanced gas turbine for
the generation of power (or conditioned further for the production of chemicals such as
hydrogen, methanol, urea, Fischer-Tropsch products, etc.).
A solid/water slurry approach
minimizes feed preparation and storage cost and allows for safe and accurate control of fuel to
the gasifier. The two-stage gasifier, coupled with E-Gas’s™ unique application of a firetube
syngas cooler design, minimizes the size and temperature level requirements for the high
temperature heat recovery system. This is cost effective and yields high conversion efficiencies
both for thermal and chemical energy. Raw syngas exiting the gasifier contains entrained solids
that are removed and recycled to the first stage of the gasifier. Recycle of these solids also
enhances efficiency and consolidates the solid effluent from the process in one stream, the slag
leaving the gasifier.
The E-Gas™ two-stage entrained flow gasification process offers an environmentally superior
coal-based power generation source with emissions a fraction of the 1990 Clean Air Act
Amendments limits. The process, as demonstrated at Wabash River, can convert coal, petroleum
coke, and other solid as well as liquid fuels or wastes into a clean syngas which is used as a fuel
gas for power generation in the GE 7FA advanced combustion turbine. The conversion of coal
to electric power at Wabash River yields a 38 to 45% overall efficiency. With these high
efficiencies, the emission of carbon dioxide (CO2) is significantly lower than for conventional
coal-based power generation technology.
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Detailed descriptions are given below for the subsystems based on the E-Gas™ technology. The
subsystems included are oxygen supply, slurry preparation, gasification, slag handling, syngas
cooling, particulate removal, syngas scrubbing, low temperature heat recovery, acid gas removal,
sulfur recovery, tank vent collection, sour water treatment and combined cycle power block.
3.1
Air Separation Unit
The Air Separation Unit (ASU), or
oxygen
plant,
compression
contains
system,
an
an
air
air
separation cold box, an oxygen
compression system and a nitrogen
compression system.
Atmospheric air compressed by a
multi-stage centrifugal compressor is cooled to approximately 40°F (5°C) and directed to the
molecular sieve adsorbers where moisture, carbon dioxide and contaminants are removed to
prevent them from freezing in the colder sections of the plant. The dry, carbon dioxide-free air is
filtered before being separated into oxygen, nitrogen and waste gas in the cryogenic distillation
system (cold box). An oxygen stream containing 95% oxygen is discharged from the cold box
and compressed in another multi-stage centrifugal compressor, then fed to the gasifier.
The remaining portion of the air is mainly nitrogen and leaves the separation unit in two nitrogen
streams. A small portion of the nitrogen is high-purity, greater than 99.9%, nitrogen, and is used
in the gasification plant for purging and inert blanketing. The larger portion of the nitrogen
produced, containing 1% to 2% oxygen, can be compressed and sent to the combustion turbine
for NOx control as well as power augmentation. However, at Wabash River, this level of
integration was not implemented, so the balance of the nitrogen is discarded.
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3.2
Coal Handling
In the slurry preparation area,
recycled water and the solid feed
are metered to a grinding mill to
produce
a
slurry
feedstock.
Slurry can be stored in sufficient
quantities
to
accommodate
uninterrupted feedstock for the
gasifier. Slurry feeding allows
for
accurate
and
safe
introduction of the solid fuel into the gasifier. The solid fuel comes into the plant with a twoinch maximum top size and enters the feed hopper. To produce slurry, the solid fuel is placed on
a weigh belt feeder and directed to the rod mill where it is mixed and ground with treated water
and slag fines that are recycled from other areas of the gasification plant. A fluxing agent is
sometimes added to the solid feed to adjust the ash fusion temperature of the mineral content of
the solid. The use of a wet rod mill reduces potential fugitive particulate emissions from the
grinding operations. Collection and reuse of water within the gasification plant minimizes water
consumption and discharge.
Prepared slurry is stored in an agitated tank. The capacity of the tank is sufficiently large to
supply the gasifier needs without interruption while the rod mill and weigh belt feeder undergo
most expected maintenance requirements.
All tanks, drums, and other areas of potential atmospheric exposure of the product slurry or
recycle water are covered and vented into the tank vent collection system for vapor emission
control. The entire slurry preparation facility is paved and curbed to contain spills, leaks, wash
down, and rain water runoff. A trench system carries this water to a sump where it is pumped
into the recycled solids storage tank.
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3.3
Gasification
3.3.1
Gasification and Slag Handling
The
E-Gas™
gasification
process accepts solid feed that
can contain varying amounts
of
fixed
carbon,
volatile
matter and mineral matter
(ash). During the gasification
of the solid fuel, a raw
particulate-laden
syngas
is
produced as well as a residual solid stream containing the ash content of the feed. The ash of the
feedstock exits the bottom of the gasifier as water slurry and is dewatered in the slag handling
system.
The E-Gas™ gasifier consists of two
stages, a slagging first stage, and an
entrained-flow,
stage.
non-slagging
second
The first stage is a horizontal,
refractory-lined
vessel
in
which
carbonaceous fuel is partially combusted
with oxygen at elevated temperature and
pressure, 2500°F/420 psia (1400°C/29
bar).
Oxygen and preheated slurry are
fed to each of two opposing mixing
nozzles, one on each end of the horizontal section of the gasifier. E-Gas™ has developed its
own proprietary design for these slurry mixers. Oxygen feed rate to the mixers is carefully
controlled to maintain the gasification temperature above the ash fusion point to ensure good slag
removal and high carbon conversion. The fuel is almost totally gasified in this environment to
form syngas consisting principally of hydrogen, carbon monoxide, carbon dioxide and water.
Sulfur in the fuel is converted to primarily hydrogen sulfide (H2S) with a small portion converted
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to carbonyl sulfide (COS). With appropriate processing downstream, over 98-99% of the total
sulfur can be removed from the feedstock prior to combustion in the combustion turbine.
Mineral matter in the fuel and any added fluxing agent forms a molten slag that flows
continuously through a taphole in the floor of the horizontal section into a water quench bath,
located below the first stage. The solidified slag exits the bottom of the quench section, is
crushed and flows through a continuous slag removal system as a slag/water slurry. This
continuous slag removal technique eliminates high maintenance, problem-prone lock hoppers
and completely prevents the escape of raw gasification products to the atmosphere during slag
removal. The slag/water slurry is then directed to a dewatering and handling area described as
follows. The slag/water slurry flows continuously into a dewatering bin. The bulk of the slag
settles out in the bin while water overflows into a settler in which the remaining slag fines are
settled. The clear water from the settler is passed through heat exchangers where it is cooled as
the final step before being returned to the gasifier quench section. Dewatered slag is loaded into
a truck or rail car for transport to market or its storage site. The slurry of fine slag particulates
from the bottom of the settler is recycled to the slurry preparation area. This final recycle step
enhances overall carbon utilization from the incoming solid feedstock.
The raw syngas generated in the first stage flows up from the horizontal section into the second
stage of the gasifier. The second stage is a vertical refractory lined vessel in which additional
slurry is reacted with the hot syngas stream exiting the first stage.
The fuel undergoes
devolatilization and pyrolysis thereby generating additional syngas with a higher heating value
since no additional oxygen is introduced into the second stage. This additional fuel serves to
lower the temperature of the syngas exiting the first stage to 1900°F (1030°C) by the
endothermic nature of the devolatilization and pyrolysis reactions. In addition to the above
reactions, the water reacts with a portion of the carbon to produce carbon monoxide, carbon
dioxide and hydrogen. Unreacted fuel (char) is carried overhead with the syngas.
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3.3.2 Syngas Cooling, Particulate Removal
The next two steps in
the E-Gas™ process
are to cool the syngas
CHLORIDE
SCRUBBE
R
and then remove the
particulate for recycle
to
the
gasifier.
Because of the high
temperature
of
the
syngas exiting the second stage of the gasifier, further cooling is accomplished by producing
steam. With cooling preceding the particulate removal step, the filtration of the particulates can
be accomplished in a temperature range more forgiving to the particulate removal unit. The hot
raw syngas with entrained particulate matter exiting the gasifier system is cooled from 1900 to
700°F (1040 to 370°C) in the syngas cooler. The syngas cooler is a vertical firetube heat
recovery boiler system with the hot syngas on the tube side. This unit generates saturated highpressure steam, up to 1600 psia. Steam from the high-temperature heat recovery system is super
heated in the gas turbine heat recovery system for use in power generation. Alternatively, syngas
can be superheated in the syngas cooler.
After cooling the raw syngas, the gas is directed to the particulate removal system. The filter
vessels contain numerous porous filter elements on which the particulate collects and the syngas
flows through the elements and exits the unit as a particulate-free syngas. Particulate removal
efficiency is better than 99.9%. Periodically the elements are back-pulsed with high-pressure
syngas to remove particulate cake formed on the surface of the elements. The particulate cake
falls to the bottom of the vessel and is pneumatically transferred to the first stage of the gasifier
with high-pressure syngas. With the char recycled to the gasifier, nearly complete gasification of
the carbon content of the feedstock is obtained. The particulate-free syngas proceeds to the low
temperature heat recovery system.
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3.3.3
Low Temperature Heat Recovery, Chloride Scrubbing, and Syngas Moisturization
With particulates removed from
the syngas, additional gas cleanup
and cooling steps can be more
easily performed. The syngas is
scrubbed to remove troublesome
chlorides and trace metals. These
components
are
removed
to
reduce the potential of corrosion
within the piping and vessels as
well as reduce the formation of
undesirable products in the acid gas removal (AGR) system. The syngas is cooled further before
being directed to the sulfur removal step.
Before being water-scrubbed, the particulate-free sour syngas (i.e., syngas with a significant
amount of sulfur compounds present) is further cooled. Scrubbing the syngas removes the
chlorides and most of the volatile trace metals released from the feedstock during gasification.
The syngas is scrubbed with sour water (i.e., water with dissolved sulfur compounds) condensed
from the syngas. After scrubbing and reheating, the syngas enters the COS hydrolysis unit
where COS in the gas is converted to H2S for effective removal of sulfur in the AGR system.
The syngas is then cooled through a series of shell and tube heat exchangers to less than 100°F
(35°C) before entering the acid gas removal system. This cooling condenses water from the
syngas. Most of the ammonia (NH3) and some of the carbon dioxide (CO2) and H2S present in
the syngas are absorbed in the water as dissolved gases. The water is collected and sent to the
sour water treatment unit. The low temperature heat removed prior to the AGR system is used to
heat the product syngas, to heat cold condensate, to provide syngas moisturization heat and to
provide process heat in the AGR. The cooled sour syngas is fed to the AGR system where the
sulfur compounds are removed to produce a sweet syngas (i.e. syngas with very few sulfur
compounds present). The sweet syngas is returned to the low temperature heat recovery area
where the syngas is moisturized. The sweet, moisturized syngas is superheated in an exchanger
using heat from hot boiler feedwater prior to use in the combustion turbine.
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3.3.4 Acid Gas Removal
After the syngas has been
sufficiently
cooled,
the
sulfur is removed via the
acid gas removal system.
The principle acid gas
removed at this point is
hydrogen sulfide.
This
process contacts the cool
sour syngas with a solvent
to remove the H2S and produce a product syngas ready to be used as feed to the combustion
turbine. The solvent is continuously regenerated and recycled for reuse. A concentrated acid gas
stream containing the removed H2S and CO2 is produced during the regeneration. This acid gas
is the feed for a sulfur recovery unit (SRU).
For selective and efficient sulfur removal from the syngas, an AGR system was chosen based on
methyldiethanolamine (MDEA), which chemically bonds with H2S, yet the bond can be easily
broken with low-level heat to effect a regeneration of the absorbent. The H2S is absorbed from
the syngas by contacting the gas with MDEA at a system pressure of about 375 psia (25.9 bar)
within the H2S absorber column. A portion of the carbon dioxide is absorbed as well. The H2Srich MDEA from the bottom of the absorber flows under pressure to a cross exchanger to recover
heat from the hot, lean MDEA coming from the stripper. The heated, rich MDEA is then
directed to the H2S stripper where the H2S and CO2 are steam-stripped in a reboiled column at
near atmospheric pressure. A concentrated stream of H2S in CO2 exits the top of the stripper and
flows to the SRU. The lean MDEA is pumped from the bottom of the stripper to the cross
exchanger. The lean amine is further cooled to about 100°F (35°C) to remove residual heat
before being stored and then circulated back to the absorber. The AGR system does not produce
any emissions to the atmosphere.
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3.3.5 Sulfur Recovery
The H2S leaving in the acid
gas from the AGR system is
converted to elemental sulfur
in the sulfur recovery unit
(SRU).
This technology is
based on the Claus process
involving the partial oxidation
of the H2S to sulfur gas and steam. The sulfur is selectively condensed and collected. The
residual gas, or tail gas, has very little sulfur content; nevertheless, this stream is compressed and
recycled to the gasifier, thereby allowing for very high sulfur removal efficiency and, thus,
minimal sulfur emissions.
The H2S stream from the AGR stripper and the CO2 /H2S stripped from the sour water are fed to
the SRU. First, a third of the H2S is combusted with oxygen to thermally produce sulfur gas in a
reaction furnace at about 1950°F. A waste heat boiler is used to recover heat before the furnace
off-gas is cooled to condense the first increment of sulfur. Medium-pressure steam is produced
in the waste heat boiler. Gas exiting this first sulfur condenser is fed to a series of heaters,
catalytic reaction stages, and sulfur condensers where the H2S is incrementally converted to
elemental sulfur. The sulfur is recovered as a molten liquid and sold as a very pure (99.999%)
by-product. The off-gas from the SRU, which is composed mostly of carbon dioxide and
nitrogen, with trace amounts of H2S, exits the last condenser. The SRU off-gas is catalytically
hydrogenated to convert all the remaining sulfur species to H2S. This results in a tail gas that is
cooled to condense the bulk of the water, compressed and then directed to the gasifier. This
allows for a very high overall sulfur removal in the process with minimal recycle requirements.
The overall sulfur removal efficiency for the Wabash River process has been greater than 98%.
An incineration system is used to convert trace acid gas components in the tank vents to oxide
form (SO2, NOx, H2O, CO2). The tank vent stream is primarily composed of air purged through
various in-process storage tanks, and may contain very small amounts of acid gas. The high
temperature produced in the incinerator thermally converts any hydrogen sulfide present in the
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tank vents to SO2 before the gas is vented to the atmosphere. Heat recovery is provided in the
hot exhaust gas of the incinerator to produce medium pressure steam before the vent gas is
directed to a tall stack for dispersion in the atmosphere
.
3.3.6
Sour Water Treatment
Process water produced
within the gasification
process must be treated
to
remove
dissolved
gases before recycling to
the
slurry
preparation
area or being discharged
to
the
water
outfall.
Dissolved gases are driven from the water using steam-stripping techniques. The steam provides
heat and a sweeping medium to expel the gases from the water, resulting in a degree of
purification sufficient for discharge within permissible environmental levels.
Water blown down from the process and condensed during cooling of the sour syngas contains
small amounts of dissolved gases. The gases are stripped out of the sour water in a two-step
process. First, the CO2 and the bulk of the H2S are removed in the CO2 stripper column by steam
stripping. The stripped CO2 is directed to the SRU. The water exits the bottom of this column, is
cooled and a major portion is recycled to slurry preparation. Any excess water is treated in an
ammonia stripper column to remove the ammonia and remaining trace components.
The
stripped ammonia is combined with the recycled slurry water.
Reuse of the water within the gasification plant minimizes water consumption and water
discharge. Recycle of the ammonia in this manner is the simplest approach. The ammonia could
be destroyed via the reaction furnace of the SRU; however, this may require operation of the
furnace at less than optimum conditions to insure complete destruction of the ammonia.
Alternatively, if desired, the gasification plant could be configured to recover ammonia as a
saleable by-product of the process.
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Water from the bottom of the ammonia stripper is purified sufficiently so that it can be
discharged through the permitted outfall. If, for any reason the discharge is out of specification,
the treated water can be stored in holding tanks for further testing and possible recycle before
final disposition.
3.4
Power Block
The combined-cycle system
consists of a combustion
turbine
generator,
heat
recovery
steam
generator,
reheat
steam
turbine
generator, condenser, flash
drums, condensate pumps and
boiler feedwater pumps.
Preheated, moisturized syngas and compressed air are supplied to the combustor. The hot gas
exiting the combustor flows to the turbine, which drives the generator and air compressor section
of the combustion turbine. Hot exhaust gas from the expander is ducted to the heat recovery
steam generator (HRSG).
The HRSG provides superheat to the 1600 psia high-pressure (HP) steam produced from the
gasification process and reheat to the intermediate-pressure (IP) steam. It also generates HP
steam and preheats boiler feedwater for the syngas cooler.
The steam turbine generator is comprised of HP, IP and low-pressure (LP) power turbines and a
generator. Reheated IP steam is supplied to the IP power turbine. The LP power turbine
exhausts to the surface condenser. Process heat from the gasification process is used to preheat
the condensate from the steam turbine condenser before it is returned to the HRSG.
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4.0
DEMONSTRATION PERIOD
In preparation for the start of the Demonstration Period for the Project, the participants
completed the transition from construction to operation through an organized program of
equipment commissioning, system turnover and operator training. The months of preparation by
Operations personnel to systematically prepare each section of the plant for acceptance testing
and operating procedure development led to the plant being turned over from Construction to
Operations system by system. “First-fire” of the combustion turbine on fuel oil occurred on June
6, 1995, followed by first coal slurry to the gasifier on August 17, 1995. For the next three
months, the plant worked through the start-up phase, which culminated in the Project achieving
commercial operations status and entering the Phase III Demonstration Period under the
Cooperative Agreement on November 18, 1995. Significant in the start-up phase was the
successful demonstration of the thermal integration of the combined operations. Except for
minor feedwater control problems, which contributed to early syngas interruptions, there were no
substantial problems integrating the steam and water systems.
The plant completed
demonstration testing to qualify for commercial status on November 18, 1995, and then entered a
short outage from November 18 through early December prior to starting operation under the
Demonstration Period. In December of 1995, the gasification plant operated for a total of 84
hours on coal, with the combustion turbine operating on syngas feed for 49 hours. The following
section details operations and maintenance of the facility for the 1996 through 1999 years
considered as the Demonstration Period.
Section 5.0 Technical Performance of this Final Technical Report analyzes a 12-month period
within the four-year Demonstration Period and provides greater detail on subsystem equipment
reliability, availability and maintainability as defined in Section 5.0. Due to the nature of this
more technical analysis and the fact that it encompasses a portion of the Demonstration Period,
Section 5.0 Technical Performance includes some information similar to that contained in the
following section. This redundancy is intentional, allowing these two sections of the Final
Technical Report to be reviewed independently.
Also within Section 4.0 are special sections that review alternate fuel tests conducted during this
period and also analyze critical components within the gasification system.
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4.1
Operation, Maintenance and Technical Impacts
Commercial operation of the facility began late in 1995.
Within a short time, both the
gasification and combined-cycle plants successfully demonstrated the ability to run at capacity
and within environmental parameters. However, numerous operating problems impacted plant
performance and reliability and the first year of operation resulted in only a 22% availability
factor.
Frequent failure of the ceramic filter elements in the particulate removal system
accounted for nearly 40% of the early facility downtime. Plant reliability was also significantly
hindered by high chloride content in the syngas. The high chlorides contributed to exchanger
tube failures in the low temperature heat recovery area, COS hydrolysis catalyst degradation, and
mechanical failures of the syngas recycle compressor. Ash deposits in the post gasifier pipe
spool and HTHRU created high system pressure drops, which forced the plant off line and
required significant downtime to remove. Slurry mixers experienced several failures and the
power block also contributed to appreciable downtime in the early years of operation.
Through a systematic problem-solving approach and a series of appropriate process
modifications, all of the foregoing problems were either eliminated or significantly reduced by
the end of the second operating year. In 1997, the facility availability factor was 44% and, by
1998, the availability factor had improved to 60%. As problems were solved and availability
improved, new improvement opportunities surfaced.
During the third year of commercial
operation, the facility demonstrated operation on a second coal feedstock as well as a blend of
two different Illinois No. 6 coals. The ability to process and blend new coal feedstocks improved
the fuel flexibility for the site but, while learning to process varying feedstocks, the plant
suffered some downtime. On two occasions while processing new coals or fuel blends, the
taphole in the gasifier plugged with slag.
In 1998 and 1999 a high percentage of coal interruptions and downtime were caused by the air
separation unit (ASU). Ten coal interruptions in 1998 alone were due to the ASU.
In 1999,
failure of a blade in the compressor section of the combustion turbine required a complete rotor
rebuild that idled the Project for 100 days. Run-time in 1999 was also impacted by a syngas leak
in the piping system of the particulate removal system, a main exchanger leak in the air
separation unit, another plugged taphole, and a failure of a ceramic test filter in the particulate
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removal system. Consequently, the availability factor for the facility in 1999 dropped to 40%.
However, 1999 clearly marked significant advances in the application of commercial IGCC as
100.00%
80.00%
60.00%
40.00%
20.00%
0.00%
1996
Project Availability
1997
1998
Syngas Availability
1999
Power Block Availability
Figure 4.1A: Project, Syngas Block and Power Block Availability
demonstrated at Wabash River. During the third quarter of 1999, the gasification block produced
a record 2.7 trillion Btu of syngas, operated continuously without interruption for 54 days and
finished the year at 70% availability. Figure 4.1A demonstrates how the reliability of the
technology has advanced during the Demonstration Period. The continuous improvement trend
for the gasification block, where the majority of the novel technology was demonstrated, is
encouraging and is expected to continue.
Future operating improvements will continue to
advance the technology and eliminate cost and availability barriers.
Some of the more
significant achievements and activities for the Demonstration Project are highlighted in
Table 4.1A.
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Table 4.1A: Significant Operating Achievements
First coal fire in gasifier
August 17, 1995
Commercial operation begins
December 1, 1995
Start-up of chloride scrubbing system
October 1996
Initiated use of metal filter elements
December 1996
Conducted 10-day test run of petroleum coke
November 1997
1998 Governor’s Award for Excellence in Recycling
May 1998
Began running new coal feed (Miller Creek)
June 1998
Completed 14-month OSHA recordable-free period
September 1998
Surpassed 1,000,000 tons of coal processed
September 1998
Surpassed 10,000 hours of coal operation
September 1998
Surpassed 100,000,000 pounds equivalent of SO2 captured
January 1999
Record quarterly production (2,712,107 MMBtu)
3rd Quarter 1999
Longest continuous uninterrupted run (1,305 hrs)
August 12 – October 6, 1999
Conducted second successful petroleum coke run
September 1999
nd
Completed 2 14-month OSHA recordable-free period
December 1999
Record coal hours between gas path vessel entries (2,240 hr)
June to October 1999
Despite reliability issues during the first two years of operation, the actual performance of the
plant during coal operation compares favorably with design as indicated in Table 4.1B. The
plant has demonstrated a maximum capacity of 1825 MMBtu/hr but requires only 1,690
MMBtu/hr to satisfy the requirements of the combustion turbine at full load. The noted steam
turbine capacity shortfall requires a HRSG feedwater heater modification to bring output up to
design. With this modification the overall plant heat rate will drop even lower to 8,650 Btu. The
air separation unit was unable to meet the guaranteed power specification, which accounts for the
difference in auxiliary power.
The environmental performance of the plant has been superior. Sulfur removal efficiencies all
exceed design and total demonstrated sulfur dioxide emissions have been as low as
0.03 lb/MMBtu of dry coal feed. This quantity is 40 times lower than the year 2000 Clean Air
Act Amendment standards. Likewise NOx, CO and particulate emissions average 0.022, 0.044
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and 0.012 lb/MMBtu respectively. The WRCGRP is the cleanest coal-fired power plant in the
world.
Table 4.1B: Performance Summary
Design
Actual
1,780
1,690 (1825 max)
Combustion Turbine Capacity, MW
192
192
Steam Turbine Capacity, MW
105
96
Auxiliary Power, MW
35.4
36
Net Power, MW
262
252
9,030
8,900
Sulfur Removal Efficiencies, %
>98
>99
SO2 Emissions, lbs/MMBtu
<0.2
<0.1 (0.03)
Syngas Heating Value (HHV)
280
275-280
Syngas Sulfur Content (ppmv)
<100
<100
Syngas Capacity, MMBtu/hr
Plant Heat Rate, Btu/kWh
Operation in 1998 was highlighted by several months during which syngas production exceeded
one trillion Btu of gas produced. This production milestone was met in March, April, October
and November of 1998. As previously indicated, the highest quarterly production of syngas
occurred in the third quarter of 1999 in which 2,712,107 MMBtu of gas was produced. Syngas
production in September of 1999 was 1,204,573 MMBtu, the highest ever for a month.
Furthermore, the combustion turbine was at maximum capacity for all but 7 hours in September.
Key production statistics for the Demonstration Period are presented in Table 4.1C.
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Table 4.1C: Wabash River Coal Gasification Repowering Project Production Statistics
Coal
On Spec.
Steam
Power
Sulfur
On Coal Processed
Gas
Produced
Produced Produced
Time Period
(Hr)
(Tons)
(MMBtu)
(Mlb)
(MWh)
(Tons)
Start-up ‘95
505
41,000*
230,784
171,613
1996
1,902
184,382
2,769,685
820,624
1997
3,885
392,822
6,232,545
1998
5,279
561,495
1999 3,496
Overall
15,067
* ESTIMATES.
71,000*
559
449,919
3,299
1,720,229
1,086,877
8,521
8,844,902
2,190,393
1,513,629
12,452
369,862
5,813,151
1,480,908
1,003,853
8,557
1,549,561
23,891,067
6,383,767
4,125,278
33,388
NOTE: THE COMBUSTION TURBINE WAS UNAVAILABLE FROM 3/14/99 THROUGH 6/22/99.
Early identification of availability-limiting process problems led to aggressive implementation of
improvement projects which resulted in 224% more syngas produced during the second year
than in year one.
The syngas produced during the third year exceeded the second year’s
production by an additional 42%. Assuming that the availability factor during the combustion
turbine outage was the same as in 1998, the facility production in 1999 would have matched
1998's output. Figure 4.1B illustrates this continuous improvement trend over the last four years
Trillion Btu of Syngas Produced
as measured by total syngas production.
10
8
6
4
2
0
1996
1997
1998
1999 adjusted for
CT outage
Figure 4.1B: Syngas Production by Year
The remainder of this section of the report will summarize the chronological history of plant
operation by area for the four-year Demonstration Period.
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4.1.1 Air Separation Unit
Opportunities and Improvements
During the first quarter of 1996, prior to contractual performance testing of the Air Separation
Unit (ASU), a production shortfall of nitrogen was identified. Liquid Air Engineering, the
supplier of the ASU, identified a process change to enhance nitrogen production. The change
involved the installation of a new heat exchanger to recover the refrigeration lost during the
vaporization of nitrogen for high-pressure gaseous nitrogen production. The original design used
steam energy to vaporize and heat the liquid nitrogen for continuous delivery to the gasifier
systems. The new exchanger allows more cooling of inlet air to the distillation column, resulting
in higher production of product nitrogen.
One negative side effect of the new exchanger was that the airflow to the main heat exchanger
was reduced, causing liquefaction of the waste nitrogen to occur upstream of the exchanger. A
follow-up project was required to correct this side effect. A second project to re-route a highpressure oxygen recycle stream to the main exchanger was implemented, which served to keep
the waste nitrogen from liquefying, thus eliminating potential damage which can be caused by
two-phase flow. This modification along with the addition of the new exchanger, results in
higher nitrogen production. However, the ASU never achieved the full performance guarantees
for simultaneous delivery of all product streams.
With the frequent plant interruptions and shorter duration runs characteristic of the early
operation, the ASU could not maintain nitrogen production at the rate of consumption in the
gasifier island. This required additional liquid nitrogen to be trucked into the facility at additional
costs. Efforts to identify potential sources for conservation throughout the year resulted in a
decrease in demand. Nitrogen conservation projects, identified during the fourth quarter of 1996,
will be discussed later in this section.
Additional minor issues addressed in the ASU in 1996 included:
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•
A gradual reduction in flow rate from the liquid oxygen pumps during the second quarter
created concern over system reliability. Inspection of the pumps and related equipment
revealed that the suction strainers had been improperly installed during construction
resulting in excessive particulate build-up within the pumps. Following total pump
overhauls within the quarter, performance was restored to design specifications.
•
A manufacturer's inspection in September, following numerous valve failures, uncovered
a design flaw in the bushings of the adsorber bed sequencing valves. The manufacturer
agreed to produce one set of modified valves with a new bushing design, with a plan to
use the extra valves to systematically change out valves and upgrade the bushings over an
18-month period.
•
In December of 1996, the main air compressor surged and shutdown due to a failure of
the third stage guide vane controller. The guide vanes went to the closed position after a
rupture of a connector attached to the third stage actuator. This failure caused a four-day
interruption in syngas delivery to repair the actuator and restore gasifier operation. No
long-term negative effects to the compressor were observed as a result of this compressor
surge.
In 1997, nitrogen production shortfall continued as a critical key production issue. Excessive
nitrogen usage, especially during start-up periods, required supplemental nitrogen to be brought
in via truck to facilitate start-up of the gasification island. Operational procedures were modified
to minimize and balance the usage and high volume uses were targeted for improvement
opportunities addressed as follows:
The heat-up process utilized by the dry char filtration system and the carbonyl sulfide (COS)
catalyst vessels, which require inert heating, were requiring significant time and nitrogen
quantities to heat at start-up.
Corrective measures included the installation of three new heat
exchangers, and the installation of recycle piping, which allows faster heat-up and cool down of
these systems using significantly less nitrogen than the previous once through system.
Optimization of nitrogen purges on various equipment and instrumentation in the gasifier
system.
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By focusing on these critical areas, significant reductions in additional nitrogen purchases were
possible as well as reduction in start-up and shutdown timing. By the end of 1997, nitrogen
demand had been closely matched to nitrogen production.
Deliveries of external nitrogen
decreased from a 1997 high of 15 trucks per month (9 million standard cubic feet) down to two
trucks per month (1.2 million standard cubic feet).
Oxygen production during 1997 was sufficient to meet the demands of the gasification island.
Total annual production was approximately 328,000 tons of 95% purity oxygen. Several trips of
the main air compressor (MAC) caused shutdowns of the gasification process due to the inability
to supply oxygen to the slurry mixers (there is no oxygen storage capability at the facility). The
first, in the second quarter of 1997, was due to an electrical design flaw in the ancillary systems
of the main air compressor. Several of the ancillary systems were not adequately fuse protected.
Therefore, when an over-amperage condition occurred on one of the auxiliary pieces of
equipment it was sufficient to trip the main circuit breaker for the MAC. Corrective action
included inspection and replacement as necessary of all susceptible fuses. During the third
quarter, a loose fuse resulted in the failure of an oxygen vent valve, which subsequently tripped
the main air compressor and the gasification process. It is suspected that the fuse was not
properly seated after the inspection/replacement that occurred during the second quarter. All
fuses were rechecked to prevent recurrence of this problem.
A potential preventative maintenance issue was identified when, in December, the alternate
oxygen pump suffered a failure of the lower impeller shaft bearing. Wabash River personnel
worked with the manufacturer to identify a new lower impeller design for installation at the next
available outage.
Additional upgrades to the ASU during 1998 included the following:
•
A lube oil system upgrade was made to facilitate oil changes to the main air compressor.
•
The main air compressor guide vanes (all stages) were put on a more aggressive preventative
maintenance schedule due to a second stage guide vane failure in December.
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In 1998 the ASU contributed 397 hours of gasification plant downtime (approximately 20.4% of
total downtime) compared to 198 hours (or approximately 7.1%) in 1997. While these hours are
elevated for 1998, it is important to note that oxygen production from the ASU increased from
approximately 328,000 tons in 1997 to over 442,000 tons in 1998. Nitrogen shortfalls, while still
occurring in 1998, were reduced by careful application of operating and start-up procedures
incorporated into the system in 1997 and continuing in 1998.
Several key outages occurred in 1998 which led to the increase in ASU contributions to plant
downtime. Those occurrences were:
•
In January, a control system I/O power supply experienced a blown fuse resulting in loss of
power to multiple automatic operated valves. This, in turn, forced a gasification plant trip via
an oxygen compressor shutdown in the ASU resulting in five hours of lost production.
Evidence suggested the incident was a result of an amperage load imbalance for the control
circuit and a relatively simple redistribution of load proved successful in preventing further
occurrence.
•
A second lost production incident occurred later in January when the anti-surge valve
protecting the MAC failed and ultimately caused the pressure safety valves (PSV's) to open.
The PSV’s which failed to reseat on closing and consequently required repair resulting in 35
lost production hours. The sticking surge valve was related to actuator corrosion due to
extended operation with only minor valve movement. A simple preventative maintenance
plan was implemented which calls for full-stroke actuator operation and lubrication during all
shutdown periods.
•
A third event occurred in January, when the MAC tripped due to excessive vibration
resulting from malfunction of the inlet guide vane electronic positioning system, which loads
the compressor. The net effect was a production loss of 53 hours. Design deficiency was
responsible for the guide vane failure resulting in increased system maintenance (short term)
and a request for proposal to replace the actuator system. Guide vane actuator replacement is
discussed later in this section and in Section 5.0 Technical Performance.
•
In February, a high voltage switchgear fuse (15 kV) failed forcing both the MAC and oxygen
compressors to shutdown resulting in 33 hours of downtime. No apparent cause was found
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for the blown fuse in the high voltage system, so no modifications or predictive measures
could be identified to prevent recurrence of this event.
•
On June 8th and 9th, production delays occurred resulting from packing fires inside the chiller
tower during vessel entry work. A total of 61 hours in start-up delays resulted from this
event. Evidence suggested the incident resulted from inadequate fire barriers and failure to
use a low energy welding technique such as heli-arc versus stick welding.
•
On August 9th, a production interruption occurred when the power card for the MAC inlet
guide vane, programmable logic controller failed. Difficulties in lining out the ASU after the
controller failed prevented gasification operation for 110 hours. A voltage surge consistent
with a probable lightning strike was identified as the root cause for the power card failure.
•
On August 15th, production was lost when a high voltage (15 kV) potential transformer (PT)
blew a primary fuse in the motor control center (MCC) switchgear.
Both the oxygen
compressor and MAC utilize the PT for voltage reference and for under-voltage protection.
Although neither machine suffered a failure, the blown fuse shutdown both compressor
motors instantaneously via the power factor relay. All testing confirmed no problem with the
potential transformer equipment but suggested a problem upstream of the primary side of the
PT fuse itself or the 15 kV system.
The PT was swapped with an identical type from less
critical service, and no repeat failures have occurred.
•
On August 4th, a nine-hour production loss occurred when the oxygen compressor shutdown
from the simultaneous activation of six safety interlocks. The root cause was determined to
be a loose wire on the power supply to the fast digital input card for the oxygen compressor.
•
On October 8th, a five-hour production interruption occurred due to a power disruption to the
vibration monitoring cabinet.
A technician accidentally tripped the power toggle while
working inside the cabinet for installation of a new data collection system. This resulted in
all vibration interlocks “failing safe”, shutting down both MAC and oxygen compressors.
Work within the vibration cabinet was postponed until the next scheduled outage to prevent
further production interruptions. Additionally, a sign was posted on the cabinet door warning
of plant shutdown potential due to unprotected power switching inside the cabinet.
•
A ten-hour interruption occurred on October 27th and followed actuator problems associated
with the adsorption process valves. The actuator worked itself loose from the valve resulting
in a limit switch failure, which prevented the regeneration sequence from completing. This
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halted operation until a full regeneration cycle could be completed for the adsorption bed.
Training was initiated for all ASU operators regarding the maintenance work request policy
and all related aspects of adsorption process control troubleshooting. New and modified
alarms were placed in the distributed control system (DCS) control logic to facilitate problem
identification.
Several projects were implemented in the ASU in 1998 to enhance industrial hygiene and plant
performance. Those projects were:
•
In the second quarter, an ancillary silencer was placed onto the adsorber tower exhaust vents
reducing peak noise levels in the area from 105 dB to below 87 dB.
•
The nitrogen vaporizer bellows trap and condensate pump systems were eliminated in favor
of a float and thermostatic steam trap. Enhanced performance and energy and maintenance
savings have resulted.
•
The adsorber regeneration heater gas distribution system was overhauled with enhanced
stiffening supports. Once installed, the regeneration heat peaks improved approximately
25°F, increasing efficiency and reducing cycle time.
•
The failed water distribution system within the chiller tower was reinforced with stiffening
elements to prevent liquid channeling and inherent performance problems. A temperature
improvement of 5°F is attributed to the better water distribution.
•
In the fourth quarter, both liquid oxygen pumps were fitted with a solids purge system. This
new system will improve oxygen pump bearing life by eliminating the primary source of
bearing wear, namely particulate.
In 1999 the ASU contributed 340 hours of gasification plant downtime (approximately 10.5% of
total downtime) compared to 397 hours (or approximately 20.4%) in 1998. The key occurrences
that contributed to plant downtime were:
•
In January, there was a 15-hour delay of plant start-up when the nitrogen storage tank ran
short of liquid.
Emergency road conditions consisting of ice and snow prevented the
requested nitrogen delivery, which delayed gasifier start-up. In response to this shortfall, two
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new contracts have been negotiated with spot market nitrogen suppliers as a hedge against
delivery and production problems.
•
A second short production delay of 11 hours occurred in February, due to the performance of
a safety test on the ASU’s distillation exchanger to look for evidence of hydrocarbon
accumulation in the cryogenic system. The supplier recommended the test after having two
ASU plant explosions worldwide on similarly designed units. The test results indicated that
the ASU at Wabash River was at very low risk.
•
The failure of an automatic valve to properly seat prevented depressurization of an adsorber
bed that interrupted oxygen supply and resulted in 15 hours of gasifier downtime.
A
temporary fix involving manual operation was implemented until the valve was repaired
during the next scheduled outage.
•
Failure of the derime header inside the main exchanger cold box resulted in 14 days of
downtime in August. The root cause was determined to be insufficient weld penetration at
the socket welds in the header during plant construction. The weld repairs required only two
days but entry into the cold box required the removal of 10,000 cubic feet of insulation and a
subsequent process derime to remove moisture and organics from the system. The repaired
header was dye tested to insure full weld penetration and supports were added to further
enhance reliability.
This repair is covered in more detail in Section 5.0 Technical
Performance.
Several projects were implemented in the ASU in 1999 to enhance plant performance. Those
projects were:
•
The adsorber sequencer valve solenoids, which were not rated for outdoor service, were
upgraded to prevent the actuator from working itself loose from the valve. This problem was
identified in the fourth quarter of 1998 when the actuator separated from the valve and
resulted in a limit switch failure that prevented the regeneration sequence from completing.
Additionally, a new bushing design was implemented on the adsorber system valve to correct
previously identified problems.
•
The inlet guide vane system on the MAC was replaced with upgraded actuators and several
other modifications were made to insure reliability. These improvements are expected to
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eliminate the ASU’s major cause of downtime since 1997 and are discussed further in
Section 5.0 Technical Performance.
•
Modifications to the water distribution trays in the water chiller tower were performed to
address nitrogen production limitations experienced during the summer of 1999.
In addition to these projects, the ASU underwent a complete “derime” during an extended outage
in the second quarter. A derime involves evacuation of all cryogenic liquids and warming the
plant to drive all moisture and impurities from the system. This process is recommended at the
frequency of every two years to ensure safe, reliable operation, free of ice and hydrocarbons.
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4.1.2
Coal Handling
Production Information
Throughout the Demonstration Period, the gasifier operated on two different base coals, both
individually and in a blended mode, as well as petroleum coke on a test basis. The gasifier is
capable of handling feedstocks with a relatively wide range of characteristics; however,
variations too far from the design basis coal could result in syngas and steam production
limitations. Also, sudden changes in feedstocks, and thus their constituents, can be problematic
if undetected; therefore, attempts were made to stay on top of feedstock analysis and blending
activities.
Table 4.1.2A illustrates the average analysis by year for each feedstock during the
Demonstration Period:
Table 4.1.2A: Feedstock Analysis
Dry Analysis
Heating Value
Btu/lb –
Btu/lb -
%
%
%
%
%
%
as
dry
Year
Feedstock
Carbon
Hydrogen
Nitrogen
Oxygen
Sulfur
Ash
received
basis
1996
Hawthorne Coal
70.2
4.56
1.45
7.91
2.42
13.46
10,733
12,483
1997
Hawthorne Coal
70.15
4.84
1.32
8.13
2.57
12.93
10,812
12,652
1997
Pet coke
87.49
2.74
0.99
3.08
5.17
0.52
14,282
15,353
1998
Hawthorne Coal
69.58
4.55
1.08
8.48
2.85
13.5
10,645
12,566
65.89
4.0
1.38
7.06
3.45
12.07
10,765
12,890
69.66
4.85
1.44
8.48
2.95
11.23
10,645
12,566
1998
Miller Creek
Coal
Hawthorne /
1999
Miller Creek
Blended Coal
In 1996, a total of approximately 184,382 tons (as received) of coal was processed through the
rod mill with an equivalent heat rating of approximately 4,341,382 MMBtu.
In 1997, a total of approximately 374,822 tons (moisture free) of coal was processed through the
rod mill. An additional 18,000 tons of petroleum coke (pet coke) were also processed during a
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trial run late in the fourth quarter. This accounted for an equivalent heat rating of approximately
8,910,111 MMBtu processed through the rodmill. Petroleum coke, while having a higher Btu
value and lower ash content than Hawthorne coal, was blended with coal-generated slag to
enhance slag flow characteristics (coal generated slag was used as a fluxing agent). Its effect on
gasifier operation will be discussed later in this report.
In 1998, a total of approximately 561,495 tons (moisture free) of coal was processed through the
rod mill with an equivalent heat rating of approximately 12,071,728 MMBtu.
Hawthorne and Miller Creek coals were fed at various ratios during 1998. Blends ratios were
adjusted as necessary to ensure consistent gasifier performance.
In 1999, a total of approximately 369,589 tons (moisture free) of coal was processed through the
rod mill. Slurry fed to the gasifier totaled approximately 7,772,568 MMBtu.
Opportunities and Improvements
Incoming coal fed to the rod mill is sampled via an automated sampling system. During 1996,
extreme weather conditions contributed to two major mechanical failures of this automated
sampling system. First, heavy snowfall resulted in a wet, sticky coal supply, which caused
plugging problems with the sampler. To solve this problem, mechanical scrapers and vibrators
were installed during the first quarter. With the additional installation of a non-stick coating to
the inlet crusher chute in the second quarter, overall system reliability improved. The second
problem resulted from coal dust during dry periods. Coal dust, dispersed by air movement
generated by the system components, tended to collect around the pulleys of the belt conveyor
and interfere with conveyor movement. To correct this problem, additional seals were installed
in the system to limit air movement thereby limiting the amount of dust accumulation in this
system. During periods when the mechanical samplers were out of service, Operations personnel
hand sampled the coal to ensure feedstock consistency.
The rod mill is designed to crush the coal to a desired particle size distribution to ensure stable
“slurryability” and optimum carbon conversion in the gasifier. In the third quarter of 1996, it
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was determined that the rod mill rod charge was insufficient to generate the optimum grind.
Problems with coal slurry flow variations resulted from large coal particles in the check valves of
the positive displacement gasifier feed pumps. Subsequent analysis of particle size distribution
indicated that there was a significant increase in the distribution of larger particles, which
warranted the addition of rods to the rod mill. Wear rate of the rod mill rods was within the
manufacturer specifications for the number of hours of operation. Operation of the gasifier feed
pumps returned to normal after adding the rods. A program was established to monitor the rod
charge and rod mill performance more frequently for the need to adjust the rod charge. Areas of
localized erosion and corrosion were identified throughout the slurry handling system during the
year. Erosive and corrosive wear affected centrifugal slurry recirculation pumps, stainless steel
pipe fittings, the inlet chute to the rod mill and piping in the slurry handling system. Where
possible, hardened metal internal coatings were placed in the system while, in some cases,
metallurgy had to be changed to improve equipment life.
The primary problems encountered in this area in 1997 centered around foreign material in the
coal which caused rod mill wear and damage, especially on the trommel screen, which is
designed to prevent oversized particles and debris from entering the coal slurry feed tank.
During the second quarter of the year an excessive quantity of oversized limestone and other
foreign material (e.g., metal objects) entered the mill causing an excess of large particles in the
slurry (objects that lodge themselves between the rods during milling prevent effective crushing
of the coal). This foreign material punched holes in the trommel screen allowing the oversized
foreign material to pass to the slurry storage tank. This material eventually ended up partially
plugging the check valves to the slurry feed pumps resulting in a plant shutdown due to
fluctuations in slurry feed to the gasifier.
Fluctuations in slurry feed also caused slag flow problems in the gasifier, which eventually led to
plugging of the taphole. Foreign material in the coal continued to be a problem in the third
quarter, which prompted discussions of this problem with the mine operators. Diligence in the
mining/blending operations and coal handling upgrades (magnetic separators on the belt feeder)
resolved the problems.
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Due to problems encountered in 1997 with foreign material from the coal pile, rod mill rod
charge and discharge trommel screen damage was monitored throughout the year. To reduce the
occurrences of holes in the screen, a steel band was added to the end of the screen. Preventative
maintenance (PM) inspections have been increased on the screen and the incidences of failure
were minimized. Optimum slurry concentration (62-63%) was monitored and rods replaced as
necessary to ensure adequate system performance. In the fourth quarter, a slight increase in
routine rod charge was implemented which led to finer slurry grind than normal. This resulted in
increased reactivity of the slurry in the gasifier, and had a slight positive impact on the cold gas
efficiency for the quarter. Overall, the coal preparation and slurry area was responsible for only
0.3% of the total plant downtime in 1998.
During the first quarter of 1999, the trommel screen was replaced during an outage. The screen
replacement provided the opportunity for some metallurgical improvements and the addition of
erosion-resistant materials in the mill outlet chute. As a result of this project no further rod mill
trommel screen failures were encountered during the Demonstration Period.
The ventilation system from the rod mill trommel screen shroud was upgraded as well. The
ventilation upgrade increased the efficiency of the vent collection system thus lowering the
ammonia (from recycled water) concentration in and around the rod mill building. Data from air
monitoring collected during the second quarter, indicates more than an 80% reduction in
ammonia concentration has been realized since implementation of this improvement.
In 1999, the coal handling area accounted for 61 hours of overall plant downtime (approximately
1.9% of total gasification plant downtime). In comparison, approximately 10 hours of total
downtime was experienced in 1998 in this area. The following is a brief description of the
causation factors and corrective measures that occurred in 1999:
•
During a start-up in early February, the slurry feed system logged 23 hours of downtime due
to problems with pumps and instrumentation. During two transfers to coal operation, a slurry
pressure transmitter failed low, resulting in a slurry mixer trip. The associated shutdown
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alarm code was re-written in the second quarter to require low signals from both of the
redundant pressure transmitters before initiating a slurry mixer trip.
•
Additionally, during the same start-up period, a piston failure occurred on one of the positive
displacement gasifier feed pumps. This resulted in contamination of the piston flush water
with coal slurry, which necessitated shutting down of the remaining positive displacement
pumps on this common flush system, interrupting coal operation for 5 hours. The root cause
of the failure was prolonged use of a hard water supply for the piston flush system. Piston
flush water is now supplied only from soft water sources.
•
In June, July, September and December, failures in the slurry feed system resulted in trips off
of coal operations resulting in a total of 16 hours of plant downtime. In each event, the
suction of the slurry recirculation pump plugged, causing an interruption of slurry to the
positive displacement gasifier feed pumps. The root cause of the problem was identified as
excessive agitator blade wear in the slurry storage tank. The loss of effective agitation
resulted in the accumulation of solids near the pump suction in the tank.
When the
accumulation became significant, the corresponding solids would dislodge and plug the
suction of the recirculation pumps. To correct the problem, the blades on the agitator will be
lengthened and coated with wear-resistant material during the spring outage in 2000. This
issue is discussed in more detail in Section 5.0 Technical Performance.
•
Erosion of slurry piping components was responsible for stopping coal feed three times in
October, which resulted in 22 hours of downtime. Two of the failures were attributed to
inadequate material selection for valves in the coal slurry piping system.
During the
November outage, the failed valves, as well as some others, were upgraded to a more
erosion/corrosion-resistant metallurgy.
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4.1.3
Gasification
4.1.3.1 Gasification And Slag Handling
Production Information
Figure 4.1.3A indicates the hours of operation, by quarter, for the gasifier during the
Demonstration Period. The gasifier and downstream equipment is heated up from a cold start via
the use of natural gas burners, which are referred to throughout the report as methane burners
along with the period of heat-up as methane operations. At Wabash River, the natural gas used
for this heat-up process is primarily composed of methane, hence the term methane operations.
It must be reiterated that syngas generated during heat-up operations is not suitable for use as
fuel for the combustion turbine and that coal/methane mix is simply a measure of transition from
methane heat-up to coal operation. Methane operations presented in each graph indicate the total
methane and coal/methane mix hours for heating of the gasifier and associated equipment and
the transition into full coal operations.
During the operational campaigns in 1996, the gasifier operated on coal for 1,902 hours. During
heat-up operations, the gasifier operated on methane and a blend of coal/methane for 1,990
hours.
In 1997, gasifier operation improved over 1996.
Coal operating hours increased
approximately 200% over the previous year as the gasifier operated on coal for over 3,885 hours.
A 215 hour run on pet coke in November of 1997 is included in the coal hours for 1997. During
heat-up operations, the gasifier operated on methane and a blend of coal/methane for 1,490
hours. During the 1998 operational period the gasifier operated on coal 5,278 hours, which
represented an increase over 1997 operations of 144%. During heat-up operations in 1998, the
gasifier operated on methane and a blend of coal/methane for 976 hours. The 1998 methane
operation hours were substantially reduced from the 1997 total, illustrating increased operator
experience, newly established procedures to limit start-up time, and fewer unscheduled outages.
Finally, in 1999, the gasifier operated on coal 3,496 hours. Included in the coal hours for 1999 is
a 77-hour run on pet coke. During heat-up operations in 1999, the gasifier operated on methane
and a blend of coal/methane for 933 hours.
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Figure 4.1.3A: Hours of Operation for Demonstration Period
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Table 4.1.3B indicates the tons of coal fed to the gasifier by month for the duration of the
Demonstration Period. In 1996, coal to the gasifier totaled over 180,000 tons and oxygen from
the ASU to the gasifier totaled in excess of 160,000 tons. This combined feed was utilized in the
production of over 2,769,600 MMBtu of syngas. By-product slag from the process totaled
approximately 23,288 tons. With the increase of coal operation hours in 1997, coal to the
gasifier also increased, totaling over 374,822 tons for 1997. Additionally, 18,000 tons of pet
coke were processed in the gasifier. Oxygen from the ASU to the gasifier totaled 328,600 tons.
Syngas production topped 6,200,000 MMBtu while 51,417 tons of by-product slag was
produced. The production increase in 1998 was also significant. Coal feed to the gasifier totaled
561,494 tons for 1998 and oxygen feed from the ASU to the gasifier totaled 442,000 tons. The
production of 8,884,902 MMBtu of on-spec syngas represents a significant increase over 1997
production. The amount of by-product slag produced from the process totaled approximately
70,228 tons. Finally, coal and pet coke feed to the gasifier totaled 315,951 tons for 1999 and
oxygen feed from the ASU to the gasifier was 289,930 tons. This combined feed was utilized in
the production of 5,813,151 MMBtu of on-spec syngas. Production was significantly impacted
by a combustion turbine failure in mid-March lasting into June and by failure of a recycle line in
the particulate removal system in November. More detail on these outages is contained in the
following sections. The amount of by-product slag produced from the process in 1999 was
45,216 tons.
Opportunities and Improvements
Three areas of concern in the gasifier system were identified in 1996 that were run limiters or
represented potential reductions of equipment service life. Those three areas were:
•
Burner Longevity
•
Refractory Life
•
System Ash Deposition
In the first quarter of 1996, the plant experienced three failures of slurry mixers on the gasifier.
Investigation revealed that all three failures were similar in nature and were attributed to coal
slurry backing into the oxygen space in the burner during the transition to coal operations. Valve
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sequence timing modifications were completed to prevent recurrence.
No similar failures
occurred during the remainder of 1996.
In an effort to reduce ash deposition and increase gasifier efficiency, new offset mixers were
installed in the fourth quarter of 1996. The offset mixer operation seemed to result in a reduction
in ash deposition downstream of the gasifier; however, the carbon content in the slag was
elevated, indicating possible lower gasification efficiency. Further testing of offset mixers was
discontinued in lieu of alternate initiatives to address ash deposition and mixer efficiency. Later
in the third quarter, a new refractory was tested in the gasifier outlet piping where ash deposition
was a problem. The results showed promising reductions in ash deposition from the previous
refractory, all of the entire outlet pipe refractory was replaced on the next outage. Deposition
occurring in the second stage gasifier and continuing through the high temperature heat recovery
unit (high pressure steam boiler) created difficulty in maintaining operation and extended
scheduled shutdowns due to the necessity to remove the deposits. Plugging of the boiler tubes
by material spalled from ash deposits increased equipment downtime due to the time required to
remove the deposits. Minor changes have occurred through 1996, from varying operational
temperatures in the gasifier and associated equipment, to changes in the type of brick in the
system. The rate of ash deposition is also proportional to the number of thermal cycles (full or
partial load trips) experienced in the system.
In 1996, there were 51 separate trips of the gasifier off of coal operation that contributed to ash
deposition and subsequent spalling of these deposits. With increased run-time on the gasifier,
increased operational experience was gained and more reliable equipment operation was
achieved, thereby reducing the number of thermal cycles on the gasification system and
subsequently reducing the potential for system deposition and associated problems downstream.
During a routine inspection of the first stage gasifier refractory lining, the wear rate was found to
be significantly greater than anticipated.
Core sampling of the lining indicated a failure
associated with the bond matrix of the refractory brick. An alternate refractory brick test panel
was placed in service to evaluate it for future use.
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Figure 4.1.3B: Feed to Gasification Reactor for the Demonstration Period
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In October of 1996, a failure in the gasifier water-cooled nozzle system caused a plant outage.
Several devices on the gasifier are cooled by water contained in a closed-loop system. In the
event of a leak in a device or in the piping, this closed-loop system receives make-up water from
a high-pressure (1,800 psig) boiler feedwater source. Flashing of the 1,800 psig water stream as
it flows into the lower pressure (450 psig) cooling loop caused a piping failure and subsequent
failure of the cooling system. The make-up piping was re-designed to eliminate these problems.
The following modifications took place in 1997 to improve overall performance:
•
As a follow-up to the gasifier nozzle water-cooling system failure in 1996, the source of the
make-up water to this system was changed from high-pressure boiler feedwater to medium
pressure cold condensate. The new make-up source has eliminated the vibration experienced
from the flashing flow of the boiler feedwater.
In addition to the problems associated with the cooling water loop above, failure of tubes in the
cooling water loop heat exchanger also occurred. Shell-side boiling of the cooling water along
with induced vibration, eventually caused damage to the exchanger tubes. Corrective measures
included increasing cooling water flow to the exchanger and installation of a new cold
condensate makeup line.
During a third quarter inspection of the first stage gasifier in 1997, it was noted that there was
substantial refractory wear in certain areas. While the gasifier could have been repaired in the
worn areas and put back into service for the next operational run, the decision was made to swap
to the spare gasifier. The spare gasifier had been equipped with new brick material based on the
information gained from the wear rate data experienced in the “running” gasifier. Re-bricking of
the gasifier that was taken out of service with upgraded materials could now be accomplished
while running on the spare gasifier.
One project, identified to extend run-time by reducing deposition, was implemented in the third
quarter. It involved a redesigned piping arrangement between the gasifier and the post gasifier
residence vessel. The new post-gasifier pipe spool was designed to reduce deposition and help
eliminate stress between the two vessels. By design, the new transition piece created a smoother
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gas flow path between the two vessels for the particulate-laden raw syngas. The old design
utilized a straight piece of transitional piping that connected to the gasifier second stage and the
post gasifier residence vessel just below the tops of both vessels. The abrupt change in the gas
flow direction caused solids impingement resulting in ash deposition. This resulted in problems
related to vessel hot spots and spalling of deposits. The new transition pipe was very successful
in resolving the problems encountered.
Several minor problems were identified in 1997, which led to a decrease in gasifier efficiency or
the shutdown of the operation. Those specific problems and corrective actions are identified
below:
•
During the first quarter of 1997, slag flow was lost due to insufficient flow of extraction gas
(raw syngas utilized during normal operation to enhance slag flow) through the taphole.
Loss of extraction gas flow caused a taphole plug, which eventually led to a shutdown of the
gasifier. An investigation into the problem indicated that there was no mechanical process
that needed evaluation or correction, but the problem existed in the computer control code for
the gasifier. The control code was revised to ensure the presence of adequate extraction gas
flow and to give operators a more accurate means of monitoring flow measurement. Once
the control code was modified, no further problems with gasifier operation were noted due to
extraction gas flow control.
•
In the second quarter, following an inspection of the slag handling system, a significant
amount of scaling was identified in the piping and equipment downstream of the slag
crushers. Following laboratory testing, a scale inhibitor was added to the flow stream to
reduce scale formation and the potential for slag flow reduction due to restriction of the lines.
•
A raw syngas analyzer failed in the third quarter due to erosion from a high velocity of
particulate-laden gas passing through the flow meter and associated piping. The situation
was temporarily corrected by increasing the piping diameter for the flow meter to reduce
velocity. Following a recurrence of the problem in September, it was decided that the
analyzer would have to be isolated from the main gas path if the problem was going to be
corrected. The analyzer inlet configuration was subsequently rearranged, utilizing a side
stream path with less velocity. No further problems were directly associated with this unit.
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During the first operational run in September, the redundant slurry flow meters (measuring
flow to the gasifier) began deviating (from set point) significantly, which reduced the
stability of the slurry flow to the gasifier (which is a primary control point for gasifier
operation). The deviations became so severe that they eventually caused a shutdown of the
gasifier due to the inability of the control system to properly adjust oxygen-to-coal ratios to
the flow deviations. To correct this problem, a more aggressive preventative maintenance
schedule for the flow meters was implemented.
•
In the fourth quarter, an area of the gasifier steel shell developed a “hot spot” that required
the application of cooling water to prevent thermal damage to the shell. When applying the
cooling water spray, the water ran down one side of the gasifier creating unequal thermal
growth between sides of the vessel and subsequent vessel movement. This, in turn, caused a
misalignment of the slag crushers that ultimately caused a failure of one of the crusher
couplings. The cooling water flow was drastically reduced to a “mist” which alleviated the
problem of unequal thermal growth and no further failures were encountered. The hot spot
was repaired internally during the next scheduled outage.
During November of 1997, a successful test run on an alternate feedstock (pet coke) was
completed.
From November 17-26, approximately 18,000 tons of petroleum coke were
successfully gasified and used for power generation. Due to the higher Btu value of the pet coke,
full syngas capacity was achieved at substantially lower slurry feed rates than are necessary with
coal.
Slag production decreased due to the much lower ash content of the feedstock.
Additionally, the sulfur recovery unit operated at peak efficiencies during the trial run due to the
higher sulfur content of the pet coke.
In 1998 the gasification and slag handling area contributed approximately 14.7%, or 286 hours,
of downtime due to associated equipment failures or operational difficulties encountered with the
alternate coal feedstock. Ash deposition from the gasifier to the inlet of the high temperature
heat recovery unit did not contribute to downtime in 1998, an indication that prior actions have
alleviated this problem.
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Slurry Mixers
Slurry mixers continued to be a source of downtime due to the corrosive/erosive nature of the
slurry (and slurry/oxygen mix) and efforts continued throughout 1998 to improve the design and
operation of these units. The following is an overall summary of downtime contributors and the
corrective actions taken, or in progress, for 1998:
•
Two coal runs in early January ended due to slurry mixer failures. A third, similar mixer
failure occurred during the first run of February. Investigation of these incidents revealed
that the slurry flow rate at the time oxygen was introduced to the mixers was 40% higher
than in previous coal start-ups. The oxygen flow controller exceeded the set point at the
higher slurry flow resulting in a high transient temperature during the start-up, which
damaged the mixer. Following these failures, the slurry flow set point for start-up was
lowered and emphasized in operator run plans.
•
Despite the above operating improvements, a fourth slurry mixer failure occurred in early
March. However, unlike the previous three failures, which exhibited excessive cooling
media loss, this failure was traced to a failure in the oxygen feed section of the mixer. The
other mixer was shutdown in a controlled fashion to take the gasifier off line and allow
change out of the failed mixer, which was eroded by the coal/water slurry. Inspections of
these parts are now carried out with greater scrutiny during mixer rebuilds to accurately
identify necessary repairs or component replacements.
•
In early August, following an oxygen compressor trip, some difficulty was experienced
returning to coal operations. As oxygen feed was initiated to the mixer, the gasifier tripped
on high temperature. The root cause was traced to a slag mound in front of the mixer, which
prevented proper mixing of the oxygen and slurry and resulted in high temperatures.
Characteristic of sudden losses of oxygen (as is the case with an oxygen plant trip) slag
quickly freezes in the gasifier and must be heated above melting points on re-start to allow
de-slagging prior to reintroduction of slurry. To remove slag mounds after oxygen plant
trips, a procedural change was implemented, requiring the reactor to be de-slagged longer
before returning to coal operations.
•
Newly designed mixers, intended to enhance slurry/oxygen mixing, were installed in the
gasifier late in the third quarter of 1998. While they were in service, the gasification plant
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was able to make syngas capacity at slurry rates 4-6% lower than normal, indicating
improved conversion efficiency.
•
In early October, an internal cooling media leak was detected on one of the new mixers,
previously mentioned, so both were replaced at the next opportunity. Internal inspection of
the mixers revealed that swirling flow characteristic of the new design, accelerated the
erosion of the mixer, which significantly shortened the mixer life. Standard mixers were
reinstalled and coal operations resumed.
Taphole Plugging
The "taphole" refers to the transition opening located in the center of the horizontal section of the
gasifier that allows slag to flow into the slag quenching section. Plugging becomes a problem
when characteristics of the slag change, which decrease its ability to flow as a liquid. The
following events contributed to downtime in 1998 as a direct result of taphole plugging:
•
An extended outage of 20 days occurred when a gasifier taphole plug forced the unit off of
coal operations in late June. Subsequent de-slagging attempts on methane operations were
unsuccessful so the gasifier was shutdown for manual removal of the plug. Investigation
revealed that slag had not only plugged the taphole but bridged over the grinders as well,
which prevented slag from exiting the gasifier. The root cause of the incident appears to
have been a combination of events. Higher slag viscosity in the Miller Creek coal was the
primary factor, but this was exacerbated by the fact that the gasifier was run slightly cooler
due to fouling problems in the high temperature heat recovery boiler and high-level
excursions in the dry char recovery vessel. Improved knowledge of Miller Creek slag
behavior and new operating guidelines allowed successful gasifier operation on various
blends of Miller Creek and Hawthorn coal for the remainder of the year. Since establishing
new guidelines, no unusual slag flow or ash deposition problems have been noted as a result
of using Miller Creek coal.
•
A taphole plug during methane operation shutdown coal operations in late December.
Preliminary investigation indicates that an ash deposit fell from the second stage gasifier and
blocked the taphole. Maintenance personnel were able to clear the plug within four days and
heat-up operations were reinitiated.
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In 1999, the gasification and slag handling area contributed 806 hours of downtime due to
associated equipment failures or operational difficulties encountered with the alternate coal
feedstock. The following represents some specific equipment and operational issues encountered
and resolved in 1999.
Operations were terminated in January of 1999 due to plugging of the gasifier slag taphole. The
cause of the taphole plug was related to a batch of coal with abnormally high ash fusion
temperature. Increased number of lab analyses of the slurry fed to the gasifier have been
implemented in an effort to catch feed abnormalities and respond more quickly in the future.
Improved guidelines relative to the gasifier operating temperature have also been established.
Testing conducted in the first quarter on scale model mixers resulted in a new mixer design that
was installed in the gasifier during the second quarter. The new mixers demonstrated good
performance from the outset as evidenced by increased cold gas efficiency and lower carbon
content in the slag. By the end of the third quarter, the new mixers had exceeded expectations by
accumulating over 1,800 coal hours with no evidence of degraded performance. In October,
after approximately 1,980 hours of operation, one of the mixers failed due to thermal stress in the
metallic mixer face. At the time of this failure, inspection of the other slurry mixer revealed
minimal wear; however, the mixer was not placed back in service but, was disassembled and
inspected further for learning value. The geometry of future mixer faces was modified to relieve
some of the stress and the metallurgy of the mixer face will be upgraded to better resist stress
cracking.
During 1999 some mechanical difficulties that led to plant downtime were identified in the slag
system and are described below:
•
During the first quarter, a slag precrusher motor trip resulted in transfer off of coal. The root
cause of the problem was identified as reversed wiring of the slag pre-crusher motor causing
it to run backwards. The motor was rewired and no further problems were noted.
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•
Slag crusher packing leaks resulted in 2.5 days of downtime in August. A manufacturer
applied (owner specified) coating on the grinder shafts was found to be incompatible with the
shaft metal, which caused the coating to break loose from the shaft and begin cutting into the
packing.
A packing injection pump was installed in early August to enable packing
additions; but the situation deteriorated until it became impossible to maintain an adequate
seal. Subsequently, an additional packing ring follower and packing was installed over the
existing stuffing box, which minimized leakage so that operations could continue safely
without excessive packing addition.
Due to the time required to facilitate a shaft
replacement, a suitable coating will be applied to the grinder shaft when the on-line gasifier
is taken out of service for re-bricking in 2000. The crusher shafts for the off-line gasifier
have been re-coated with the proper material to ensure that this problem does not recur when
the off-line gasifier is placed back in service.
•
In late December of 1999, the slag crusher began experiencing packing leaks similar to those
encountered on the slag pre-crusher. The addition of an auxiliary packing ring installed over
the stuffing box was not successful in stopping the leak. To properly repair the leak, the
plant was down for 42 hours to add larger packing to the stuffing box. The root cause of this
failure was identified as inappropriate coating on the grinder shaft, as was the case with the
slag pre-crusher.
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4.1.3.2 Syngas Cooling, Particulate Removal And COS Hydrolysis
Syngas Cooling
Figure 4.1.3A indicates total high-pressure steam production from the High Temperature Heat
Recovery Unit (HTHRU) by month for the Demonstration Period. Steam production, as shown
in each graph, tracks the operational run history of the gasifier but is also impacted by deposition
problems in the heat recovery boiler.
Total 1,600 psig steam production for 1996 was approximately 820 million pounds. Total steam
production for 1997 increased over 200% from 1996, as did most other operational parameters.
While the HTHRU continued to experience fouling problems, new methods of cleaning the tubes
were incorporated into the maintenance program allowing operations to come back on line with
an outlet temperature close to design. Steam production for 1998 was approximately 2,190
million pounds. This figure represents a production increase of approximately 129% over 1997
and a production in excess of 269% over 1996 steam production figures. In 1999, total 1600
psig steam production was approximately 1,481 million pounds. This decrease from 1998 was
primarily due to the loss of the availability of the combustion turbine late in the first quarter.
Additionally, production figures were low in November due to a planned outage and the failure
of a recycle line in the particulate removal system and subsequent fire, which caused significant
damage to the electrical circuitry of the main gasifier structure.
Opportunities and Improvements
Ash deposition in the HTHRU and associated equipment was of great concern during the early
operation. As discussed in the gasification section, thermal cycles of the hot gas path were a
leading contributor to HTHRU plugging due to spalling of ash deposits in upstream equipment
and piping. Solids accumulation at the tubesheet causes tube plugging and high differential
pressures. At some point, the solids-laden gas through the open tubes reaches a velocity high
enough to cause erosion. To help control ash deposition in the tubes of the HTHRU, a boiler
inlet screen was installed in the third quarter of 1996 to prevent large particles from reaching the
tubesheet.
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Figure 4.1.3C: 1600 psig Steam Produced for Demonstration Period
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Deposition and corrosion within the HTHRU continued to be addressed in 1997. Several major
projects and improvements occurred during the year to enhance system performance and
improve reliability. Those include:
•
The post gasifier pipe spool was replaced with a long, sweeping, 180 degree ell that provides
significantly lower velocities between the second stage gasifier and the post gasifier
residence vessel. This modification dramatically reduced ash deposition near the exit of the
gasifier, meaning less ash deposits to break loose and plug the HTHRU.
•
Thermal cycles (shutdown and start-up) not only affected deposition in the system but also
served to accentuate installation flaws within the piping scheme. In March of 1997, due to
misalignment of a piping spool during construction/installation, a syngas leak developed in a
spool piece on the outlet of the HTHRU. The released gas combusted as it leaked from the
process causing a small fire and subsequent shutdown of the gasification process. In the
process of purging the system with nitrogen, the flare pilot was extinguished resulting in an
odor noticeable in the surrounding area (due to minor concentrations of hydrogen sulfide in
the purge gas).
After this release, the spool flanges were re-machined and the pipe
reconnected with a new gasket. Later in the Demonstration Period, the flanged pipe spool
was permanently removed and replaced with a welded-in piping section to eliminate this
potential source of leakage.
Into the third year of the Demonstration Period (1998), an upgraded boiler inlet screen was
installed. Due to the corrosive/erosive service, upgraded materials of construction and design
changes were implemented to extend the life of the screen. Following the installation of the new
screen early in the second quarter of 1998, the screen remained in place for the remainder of the
year, experiencing only normal wear while limiting deposition on the boiler inlet.
The post gasifier pipe spool installed in 1997 dramatically reduced ash deposition in the gas path.
However, inlet screen corrosion and the maintenance required to remove boiler tube fouling
resulted in 160 hours of downtime in 1998.
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•
Although not directly responsible for downtime, heavy fouling of the HTHRU tubes during
1998 caused the unit to operate at elevated syngas outlet temperatures. While this does not
pose an imminent problem with the HTHRU, itself, elevated syngas temperatures (in
combination with the acid gas environment) cause accelerated corrosion rates downstream.
Attempts to remove the deposits off line with high-pressure hydro-blast rigs, mechanical
scrapers and knockers were only marginally successful.
•
In the third quarter, chemical cleaning of the boiler tubes was completed with excellent
results. Upon returning to operation, an approximate 100°F decrease in heat recovery boiler
syngas outlet temperature was noted, which essentially restored the heat transfer area to near
new conditions. Although the chemical cleaning was very successful, it was also very costly
and presented an increased risk of chemical exposure to plant personnel. Therefore, an effort
to develop acceptable mechanical cleaning methods is ongoing.
•
Boiler fouling accelerated in June of 1998 while operating with Miller Creek coal as a
primary feedstock. A significant increase in boiler syngas outlet temperature was observed
as the unit continued to operate on this Miller Creek coal feedstock. By the end of June,
when the boiler was opened during an outage, an increased degree of deposition was found
on the tubesheet screen and boiler tubes. The boiler fouling experienced while processing
Miller Creek coal was caused by the higher iron content in the ash. Iron reduces the viscosity
of molten ash entrained in the gas, which increases its tendency to adhere to surfaces such as
the boiler screen and tube walls. It was found that by running the boiler inlet temperature
cooler, the ash viscosity increases, thus minimizing its fouling characteristics.
•
In August of 1998, utilizing modified operating parameters, the plant successfully processed
a 25% Miller Creek/Hawthorne blend with acceptable boiler fouling when compared to the
initial run in June. However, boiler fouling continued to be a run-limiting concern during the
fourth quarter campaign.
During a scheduled December outage, cleaning of the boiler
deposits continued to result in higher-than-desired maintenance cost. Various mechanical
cleaning methods were utilized to clean the boiler tubes. Although improvements to cleaning
methods were noted, continual investigation into improved cleaning methods was necessary
during the fourth year of the Demonstration Period.
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The boiler fouling “opportunity” became a strong focus for plant personnel in 1999. During the
extended outage following the combustion turbine compressor failure in March 1999, a new
process to mechanically clean the boiler tubes was developed. The new process utilizes coredrilling bits and apparatus developed on-site. The new method restored the boiler tubes to “likenew” condition during a planned 3-week outage. The outlet temperature of the boiler, when
returned to operation, was approximately 20-40oF lower than it had been in the previous two
years, which is an indication of significantly improved heat transfer. The lower temperature
should reduce the corrosion rate of the downstream metallic particulate removal system filter
elements and appears to have decreased the filter-blinding rate as well. Modified HTHRU
operating parameters have reduced the fouling rate, such that current projections indicate that six
months of run-time can be achieved before process-side boiler cleaning is required.
During the October 1999 outage, the HTHRU tubes were again successfully cleaned to “likenew” condition, although approximately 8 days of the downtime was required for the cleaning.
Continued optimization of operating and cleaning methods will remain a focus after the
Demonstration Period.
Particulate Removal
During the first quarter of 1996, 5 different interruptions in coal operation occurred due to the
particulate removal system filters. One interruption was caused by erosion in the char recycle
line that transports the filtered char back to the first stage gasifier. Erosion-resistant linings were
used to address this problem. The other four interruptions were due to high blinding rates of the
filter elements. As the filter element pores are permanently blinded, the differential pressure
across the filters increases until the system design constraints are exceeded and the unit must be
shutdown.
During this first year of the Demonstration Period, localized erosion in several areas of the char
filtration system was encountered, including the filter elements, gas distribution piping, char
conveying ejectors, and the char recycle piping. These problems were systematically addressed
as they occurred and began an ongoing improvement effort that would extend well into the
balance of the Demonstration Period.
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The primary cause of char filtration related downtime during this first year of operation stemmed
from repeated problems with leakage of char through the tie-rod candle filter elements. Three
outages were caused directly from either breakage of ceramic candle elements or leakage of
gasketing used in the primary filter system. Although the plant utilized a secondary filter
system, this backup system was not adequate to sustain operation with appreciable leakage of
char through the primary system. Improvements to the particulate removal system in 1996
included the previously mentioned upgrades to manage localized erosion. Other improvements
were: increasing the effectiveness of the primary and secondary pulse gas systems, modifying the
gas distribution system to provide more even flow distribution in the vessels to prevent filter
system erosion and char bridging, and a replacement of the ceramic tie-rod type filter elements
with more robust metal filter elements.
The installation of metal elements in late 1996 immediately improved the reliability of the
particulate removal system and started a learning curve on metal filter elements that would last
for the remainder of the Demonstration Period. In conjunction with the installation of metal
filters, a heat exchanger was installed to increase the temperature of filter pulse gas above the
syngas dew point, thereby reducing the tendency for fouling and corrosion of the elements due to
syngas condensation.
Although the dry char filtering system continued to demonstrate improved performance
throughout 1997, the system was still on a steep improvement curve in the operational area and
in the area of design and metallurgy. Significant events during the year include:
•
During the first quarter 1997, and after installation of first generation metal filter candles in
the fourth quarter of 1996, a single gasifier trip in January was caused by primary filter
failure. The failure was due to a combination of corrosion-weakened metal filters and flow
surges through the vessels caused by backpulse valve failures. The failure of the backpulse
valves prevented the cleaning of certain element clusters, causing them to blind off the flow
through the filters. During that time, flow imbalances caused a significantly increased flow
of gas through the clean filters, damaging the already weakened filter elements. Some of the
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experimental metallurgy utilized for filter construction during this run showed evidence of
corrosion after only 523 hours of service and one type was corroded to the extent that the
filters lost strength and ductility. During the ensuing plant outage, all of the filters of this
type were replaced with filters of alternate metallurgies that demonstrated superior resistance
to corrosion. All of the pulse valves were disassembled and many were found to have
extensive seat damage. The valves were rebuilt and the pulse gas heat exchanger was taken
out of service for the next run, since the hotter pulse gas was believed to be contributing to
the valve failures. Leakage of the valve seats effectively stopped after this correction.
Overall, the particulate removal system continued to operate acceptably until additional
problems occurred in the fourth quarter of 1997, when it caused the plant to be brought off
line four times. Three of the four occurrences were caused by flow imbalances between the
two vessels and poor char recycle ejector performance, preventing the flow of char from the
vessels. A dimensional discrepancy in one of the recently-fabricated ejector internal parts
was determined to be the cause of this failure.
•
High primary filter blinding rates continued in the fourth quarter of 1997 and, as a result, the
filters were removed and externally cleaned during an extended plant outage in October. The
high blinding rate was partially caused by a HTHRU tube leak. Filter blinding rates were
again high during the period preceding the pet coke test in September 1997.
Upon
completing this test, the filters were again cleaned in early December, utilizing a new
cleaning procedure that proved more effective. As a result, the primary char filter vessel
differential pressures in December were much lower compared to the October start-up.
Other enhancements to the system in 1997, including a modification to the internal inlet gas
distribution system in the dry char vessels and installation of a new test unit, continued to
provide longer operational time frames. Specifically, those items were:
•
A design change was made to provide more uniform flow distribution throughout the vessel,
thereby reducing both the gas velocity in the high-wear areas of the inlet distributor piping
and the particle impingement velocity on the filters.
•
Initial construction began on a new Dry Char Slipstream unit (DOE Cooperative Agreement
No. DE-FC26-97FT34158), which will provide the opportunity to test filter elements and
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materials of construction outside of the primary filtration vessels. The project was completed
and put into service during the fourth quarter of 1997.
In 1997 the particulate removal system accounted for approximately 25% (706 hours) of total
plant downtime.
In 1998, through an increased understanding of system operation and
continuing research into filter element composition and design, plant downtime due to the
particulate removal system was reduced to 180 hours or only 9.3% of total downtime for the
plant.
The following key areas of operation and mechanical malfunction were responsible for the
majority of the downtime for 1998:
•
The particulate removal system continued to experience high primary filter blinding rates,
initially experienced in the fourth quarter of 1997, until the February 1998 outage. In this
outage, new filter elements with increased resistance to blinding were installed.
The
particulate removal system operated with minimal primary filter blinding until early in the
third quarter when, during an outage, the filter system required cleaning and some
replacements of filter elements. Due to supply constraints of the newer filter elements, older
elements more susceptible to blinding were reinstalled in July. The high blinding rate limited
the length of the subsequent run to 846 hours, forcing a plant outage in early September. A
combination of old and new style elements was installed in September to maximize run-time
and minimize cost.
•
In April 1998, one of the char ejectors was replaced with a modified ejector, designed for
improved erosion-resistance. Later in the run, the ejector failed due to a manufacturing error
during the unit's previous rebuild. The failure resulted in a high level in the dry char vessel
that resulted in fluctuations in the gasifier temperature when char was emptied from the
vessel. These thermal excursions, combined with the high slag viscosity associated with
Miller Creek coal, resulted in gasifier taphole plugging problems that caused a plant outage.
Failed dry char ejectors again contributed to downtime in July and August, however the
downtime was limited to only 3-4 hours in each instance. Further improvements were made
to the dry char ejectors and new ejectors were in service for the remainder of 1998. While
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changing the failed ejector in August, a backpulse valve was also changed due to leak-by
when in the closed position. Upon return to coal operations, a second backpulse valve was
discovered to be leaking. The run was terminated to allow replacement of the valve. The
root cause of the failures was high pulse gas temperatures that resulted when the pulse gas
heater, used during start-up operations, was left in service after coal operation was
established. Operations personnel were re-instructed on the proper use of this heater to
prevent future pulse valve failures.
•
The first run following the third quarter 1998 scheduled outage was terminated due to a leak,
and subsequent fire, on the primary char filter vessel inlet flange. The leak is suspected to
have resulted from pipe movement encountered when new primary char filter vessel inlet
isolation block valves were installed in this system (discussed below). Installation of the new
valves did not include inspection of downstream piping so it is possible that a shift in the
flanges would lead to a breach in the gasket-sealing surface. The leak was wire wrapped and
clamped to allow safe return to operation with a permanent repair made at the next planned
outage. Inspection during a fourth quarter outage confirmed that misalignment of the sealing
surfaces was indeed the root cause of this incident. This was an isolated case that can be
associated with project implementation in a very specific area.
Several projects/equipment enhancements were made to the particulate removal system to
enhance performance and/or to improve operability. The following were accomplished in 1998:
•
A test cluster of ceramic filters, previously tested in the slipstream unit, was installed in one
of the primary vessels for evaluation. To avoid jeopardizing plant availability, fail-safe
devices were installed to prevent char breakthrough if a filter element failed. The fail-safe
devices were installed after extensive testing and evaluation and are used as a back up to the
primary dry char filters. The fail-safe device is a highly porous filter used to capture solids
that might breakthrough the primary filter elements. These devices were installed on all
alloy filter elements that were most susceptible to corrosion-related failures.
•
Additionally, testing continued on several corrosion-resistant filter alloys, which yielded
some promising results. Corrosion rate data suggested that one of these alloys could more
than double the life of the filters currently in service.
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•
The butterfly valves at the inlet to the particulate removal system were replaced with ball
valves during the September outage.
Positive shutoff with the previous valves was
impossible, resulting in extended cooling and heating times for shutdowns and start-ups,
respectively.
•
Initial testing of an improved seat design for primary char filter system backpulse valves was
conducted. The evaluation proved the new design to be much more reliable than the original
style valve seats. Consequently, all backpulse valves were converted to the improved seat
design. This eliminated all of the valve failure problems previously associated with seat
failures.
In 1999, the particulate removal system accounted for approximately 12.9% of total facility
downtime (772 hours) primarily due to the failure of the inlet line and char breakthrough in the
system due to a ceramic element failure. Comparatively, 1999 downtime hours are significantly
higher than the 1998 total of 180 hours and slightly higher than the total 1997 hours of 706.
The following key areas of operation and mechanical malfunction were responsible for the
majority of the downtime for 1999:
•
During the first quarter, a failure of a ceramic filter element in the particulate removal system
resulted in a transfer off of coal and nearly two weeks of downtime. During the December
1998 outage, a test cluster of ceramic filters (previously tested successfully in the slipstream
unit) was installed in one of the primary char filter vessels. A defect in the element support
hardware resulted in a premature failure of one of the filter elements.
•
During the October outage, high-wear areas of the dry char recycle piping were replaced with
erosion-resistant material. Shortly after returning the unit to coal operations in November, a
failure occurred in one of the new segments of erosion-resistant pipe, which resulted in a
syngas leak. The leak ignited and the subsequent fire caused damage to an adjacent cable
tray. The cause of the piping failure was traced to pieces of polyvinyl chloride left in the
piping by the manufacturer during installation of the lining. The material decomposed at
process temperatures and resulted in excessive and rapid chloride stress-corrosion-cracking
of the piping. Subsequently, all of the recently installed piping was replaced with new piping
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in which tighter quality control of the manufacturing process was exercised, including having
a company representative personally witness the assembly of the piping. Approximately 18
days of downtime resulted from the failure and the associated replacement of piping, burned
instrument wiring, and cable tray repairs.
Key positive indicators of particulate removal system performance during 1999 include:
•
The dry char ejectors have shown no evidence of degraded performance since their
installation in 1998.
•
The dry char filter-blinding rate during the initial campaign after the combustion turbine
outage was exceptionally positive. Projections based on third quarter 1999 data indicate that
filter life (limited by blinding) could exceed one year. The blinding rate of the char filters
increased in late September. This increase was attributed to the pet coke test. During the pet
coke test, the char filters were subjected to approximately 100% more char loading which
may have resulted in some element bridging. This bridging can be avoided during future pet
coke operation by increasing the backpulse frequency of the filter elements.
Carbonyl Sulfide Hydrolysis
Figure 4.1.3D depicts ppm levels of COS on a comparative basis between 1996, 1997, 1998 and
1999. As illustrated by this graph, significant progress has been made in the control of COS
from the hydrolysis unit and in operating the system on a more consistent basis. In 1996 the
average ppm level of COS leaving the hydrolysis unit was 102.9 ppm. The 1997 average
increased to 139.4 ppm. This increase was due to catalyst contamination by trace metals and
chlorides in 1996, and to partial degradation in 1997 resulting from a deflagration incident that
reduced the total surface area of the catalyst and promoted channeling through the reactor bed.
The first year of optimum operation occurred in 1998, as is indicated by an average value of 26.8
ppm of COS in the product syngas. This was achieved following catalyst bed replacement in the
fourth quarter of 1997, and illustrates the capabilities of this unit when it is properly operated and
maintained. This trend continued in 1999 with an overall average COS concentration in the
product syngas of 26.2 ppm.
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Carbonyl Sulfide, ppm
In Particulate Free Syngas
1996
1997
1998
DEC
NOV
OCT
SEP
AUG
JUL
JUN
MAY
APR
MAR
FEB
250
200
150
100
50
0
JAN
CARBONYL SULFIDE, ppm
Figure 4.1.3D: Carbonyl Sulfide in Particulate Free Syngas
1999
During runs early in the first quarter of 1996, COS removal efficiency in the catalyst beds began
to decline. It was determined through sampling and analysis that the catalyst was being poisoned
and blinded by trace metals and chlorides present in the syngas system. Catalyst degradation
required the catalyst to be replaced during a February 1996 outage. Slipstream testing was
initiated at this time to determine alternate catalyst selection. Catalyst efficiencies during the
second quarter of 1996 continued to decline indicating the need for an alternate catalyst or a
means of eliminating the contaminating agents. Through the use of the slipstream unit, an
alternate catalyst was selected which showed a greater resistance to poisoning. Additionally, an
improvement project was identified which required the installation of a system to remove
chlorides from the syngas stream.
The project would be beneficial, not only in the COS
hydrolysis system, but also in equipment downstream from the installation (see section 4.1.3.3).
In the third quarter 1996, a new chloride scrubbing system (CSS) was installed along with a new
catalyst for COS hydrolysis. The new catalyst was not only lower in cost, but testing indicated
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that it would be more efficient and less vulnerable to poisoning. While initial start-up and
subsequent operation of this system went smoothly, a later system start-up in November led to a
deflagration event in the system that partially reduced the surface area of the catalyst and
damaged the CSS. The cause of this event was found to be the use of ambient air for pressure
testing which created a spontaneous combustion event within the still-hot core of the COS
catalyst bed.
The investigation and repair of the system was completed and the plant returned to operation in
December 1996. Damage to the catalyst was not enough to warrant replacement; however, some
degradation of activity was seen in an elevation in the amount of COS in the product syngas for
the month of December. COS levels between 50 to 100 ppm were normal during operation, up
from less than 50 ppm previously. However, overall sulfur in the product gas was still well
within environmental and contractual requirements in the product syngas.
The COS catalyst system ran well within limits during the entire year for 1997, although the
damage done in 1996 would require a premature replacement of the catalyst. The catalyst was
replaced in the fourth quarter of 1997 and the system performance was restored to very low
levels of COS in the product syngas.
The CSS, installed in 1996 after chlorides were identified as a contaminant to the COS catalyst,
plays an essential role in syngas preparation prior to COS hydrolysis. By removing a substantial
portion of the chlorides entrained in the syngas, it not only protects the COS catalyst but also
reduces the potential of chloride stress-corrosion-cracking in the low temperature heat recovery
unit (LTHRU). The CSS operated within design specification during 1998 with only minor
problems associated with fouling of the demister pads and associated vessel packing.
The COS hydrolysis unit continued to provide stable operation throughout the Demonstration
Period, and has proven to be a very reliable process operation within the Wabash River
gasification facility.
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Syngas Recycle Compressor
The syngas recycle compressor recycles particulate-free raw syngas back to the dry char
filtration system for use in filter backpulse cleaning, and to the gasifier for use in the second
stage gasifier for syngas quenching. Recycled syngas is also used to atomize coal slurry in the
second stage gasifier slurry nozzle and to prevent nozzle plugging in the methane burners.
Additionally, recycled syngas purges are used to prevent obstruction of gasifier instrumentation.
Syngas production was limited due to difficulties with the recycle syngas compressor in both
January and March of 1996. At the end of January, a steady decline in the machine's second
stage performance necessitated a compressor overhaul.
The source of the problem was
ammonium chloride deposition due to condensate carryover into the compressor during methane
operation. In lieu of re-opening the machine, the deposits were successfully removed using a
water-wash process. Because condensate carryover also occurs at a slower rate during coal
operations, two improvement projects were instituted to minimize the long-term effects of this
problem.
During the third quarter 1996 the compressor tripped on two separate occasions, preventing the
plant from going to coal operations. In early August, a discharge-end labyrinth shaft seal failed.
The cause of the failure was identified as chemical attack of the seal material. The seal was
replaced with a material similar to that used in the inter-stage seals. The shaft sleeve was also
damaged when the seal failed, which required a rotor assembly replacement. Shortly after
restart, the new seal failed and was replaced with an upgraded material, which has operated since
then without failure.
An interruption of coal operation in late August 1996 was caused by the failure of one of the
compressor impellers, which was found to have cracked and moved on the shaft. The cause of
the crack was determined to be mechanical in nature, although it propagated due to chemical
attack. The rotor assembly was replaced and the compressor operated for the rest of the quarter
with no mechanical problems.
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The recycle syngas compressor was disassembled, cleaned and re-assembled during the
October/November 1996 outage. Although the compressor had not affected plant performance
prior to the outage, operational data indicated that it was slightly fouled. After the initial
problems encountered during the first year of the Demonstration Period, the syngas recycle
compressor has not required any major maintenance and has been a very reliable piece of
equipment.
Chloride Scrubbing System
As mentioned earlier, the chloride scrubbing system was installed in the third quarter of 1996 to
remove chlorides and other impurities from the syngas.
Some problems were observed with the chloride scrubber system upon initial operation due to
ammonia accumulation. Due to the scrubbing of hot syngas with sour water, the chloride
scrubber was also functioning as an ammonia stripper. This resulted in ammonia water being
recycled to the sour water receiver, which in turn, was sent back to the CSS. Within two days of
operation, ammonia levels had exceeded 4% (40,000 ppm) in the scrubber water. This reduced
efficiency and created some pluggage problems in the low temperature heat recovery unit due to
the formation of carbonate and bicarbonate salt-based scales. To abate further operational
problems with the system, a blowdown was taken from the sour water tank directly into the sour
water system to provide a purge of ammonia from the system. During the November shutdown,
control of the blow down was automated to provide consistent control of ammonia levels.
The chloride scrubbing system exhibited effective scrubbing from the outset of operation.
However, the demister packing in the top of the vessel began to plug due to coal tar in the raw
syngas. During the second quarter of 1997, the plugging began to cause liquid carry over into
the gas path requiring a shutdown.
The root cause of the incident was determined to be tar deposits on the packing, which impeded
gas and liquid flow through the column. Mitigation of tar accumulation was achieved by
modifying the second stage gasifier operations to maximize tar destruction. The column packing
was cleaned and put back into service prior to the third quarter 1997 run. Towards the end of the
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run the column began exhibiting a high differential pressure, again, as a result of tar plugging.
This time, however, the tar deposition was related to reduced rate gasifier operations.
To correct the problem, manual flushes were periodically implemented during reduced rate
operations.
Additionally, operating guidelines were revised to limit the time spent at low
operating rates during which heat loss from the system is too great to maintain temperatures
sufficient to destroy tars.
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4.1.3.3 Low Temperature Heat Recovery And Syngas Moisturization
Production Information
Figure 4.1.3E illustrates syngas production by month throughout the Demonstration Period.
Syngas production for 1996 totaled 2,769,685 MMBtu and increased considerably in 1997 to
approximately 6,232,545 MMBtu. Production in 1998 further increased to 8,844,902 MMBtu, or
143% of the production record set in 1997. Fourth quarter of 1998 production also set a new
quarterly production record of 2,503,587 MMBtu. This quarter included a scheduled December
outage for maintenance and repair. Product syngas in 1999 totaled 5,813,151 MMBtu. Severely
impacting production for 1999 was the unplanned combustion turbine outage between March and
June. Additionally, failure of the newly installed dry char recycle line in November negatively
impacted production in the fourth quarter. On a more positive note, however, third quarter
syngas production exceeded all previous quarterly results by producing 2,712,107 MMBtu, and
by more than doubling the previous continuous hours-on-coal record by operating 1,304
continuous hours.
Sweet syngas moisturization operated efficiently and provided consistent product gas moisture
content of approximately 20%-23% throughout the Demonstration Period.
Product syngas
quality remained high and can be reviewed for all time periods in the Demonstration Period in
Table 4.1.3A.
Product syngas quality remained relatively consistent throughout 1996. One of the primary
reasons for this was the use of a single coal source for the year. Minor variations during 1996 in
hydrogen sulfide and carbonyl sulfide concentrations (in ppm) were primarily due to equipment
problems in the COS catalyst reactor and acid gas recovery systems. Variations in hydrogen
content, carbon dioxide and carbon monoxide concentrations and methane content were directly
related to operational characteristics of the system (and more specifically to variations in the
oxygen-to-coal ratios of the gasifier feed) and cannot be attributed to variations in coal
feedstock.
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Figure 4.1.3E: Produced Syngas for Demonstration Period
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Table 4.1.3A: Product Syngas Quality
Product Syngas Quality
1996
Hydrogen
Concentration (%)
Carbon Dioxide
Concentration (%)
Carbon Monoxide
Concentration (%)
Methane
Concentration (%)
Hydrogen Sulfide
Concentration (ppmv)
Carbonyl Sulfide
Concentration (ppmv)
1997
1998
1999
Low
High
Low
High
Low
High
Low
High
32.87
34.21
32.9
34.4
32.71
33.82
32.31
33.44
14.89
17.13
16.6
16.9
14.92
16.06
15.25
16.22
42.34
46.03
42.2
46.7
44.25
46.73
44.44
46.31
1.26
1.99
1.04
2.02
1.91
2.29
1.88
2.17
17.28
83.36
43.08
106.5
23.48
107.24
86.32
106.03
36.26
162.13
22.59
111.78
9.03
36.63
11.36
24.22
Syngas quality during 1997 was comparable to 1999; however, some assumptions can be made
for variations in syngas composition due to the petroleum coke trial in the month of November.
Despite the introduction of a new coal feedstock (Miller Creek coal), syngas quality in 1998
remained consistent. The same can be said for quality during 1999 when the gasifier operated on
various blends of Miller Creek and Hawthorne feedstocks.
Opportunities and Improvements
While operations within the low temperature heat recovery unit (LTHRU) were within design
parameters, three of the exchangers suffered tube failures in 1996 due to chloride stresscorrosion-cracking of the stainless steel tubes. Two of these exchangers serve to transfer heat
between sour syngas and water from the syngas moisturizing system. A third exchanger crossexchanges sour syngas with amine from the acid gas removal system.
The plant had to be taken off of coal operation in early April 1996 due to excessive tube leaks
from the syngas/amine exchanger. Leaking tubes were plugged in this exchanger as well as
additional tubes in one of the sour syngas/water exchangers. Replacement exchangers for the
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syngas/amine exchanger and one of the syngas/water exchangers were built on an expedited
basis and were installed during the June 1996 outage. The replacements were constructed of an
upgraded material that is not vulnerable to chloride stress-corrosion-cracking.
Tests were
performed on tubes within the remaining syngas/water exchanger during the outage, and, an
additional 10% of the tubes in this exchanger were deemed suspect to cracking and were plugged
to prevent future tube failures. Later in 1996, with the installation of the chloride scrubbing
system, the potential for chloride stress-corrosion-cracking in the remaining stainless steel
components was effectively minimized.
The syngas flare system is considered part of the overall low temperature heat recovery and
moisturization process. During a syngas leak and subsequent flange fire event in the first quarter
of 1997 (previously mentioned), the flare system malfunctioned by losing flame and causing a
release of purge gas containing a trace quantity of hydrogen sulfide. The malfunction was
attributable to a marginally combustible purge stream being routed to the flare and “snuffing” the
flame on the flare pilot, allowing the purge gas to escape unburned. To correct the problem,
three new “windproof” pilots were installed on the flare tip during the second quarter 1997
outage. The process control program for the flare purge initiation was also upgraded to ensure
that a sufficient volume of natural gas is added to the flare gas to ensure combustion during
system purge.
Another flare modification was implemented during the third quarter of 1997 to reduce noise
levels during flare operation.
Noticeable noise levels were a concern in the surrounding
neighborhood, so a project was implemented to install a larger diameter flare tip, which
effectively reduced the noise to acceptable levels due to reduced exit gas velocity.
The LTHRU contributed a total of 7 hours of plant downtime in 1998. While this is not
significant enough to warrant concern, several key opportunities for operation and maintenance
improvements were identified. The following areas of concern were noted during the 1998
operational period:
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•
Following an off-line cleaning during a maintenance outage, one of the LTHRU exchangers
was hydro-tested for leaking tubes due to suspected failure. Approximately twenty tubes
were found leaking and were subsequently plugged on both ends. One tube was extracted for
failure analysis. The root cause was attributed to vibration, which is suspected to have
occurred during use of a tubesheet spray intended for on-line cleaning. This spray creates
thermal shock on the inlet tubesheet. The tubesheet spray had been used quite frequently in
an attempt to lower the exchanger differential pressure. This activity has been discontinued
due to its limited efficacy and its contribution to tube failures.
•
The plant had to be taken off line during the third quarter of 1998 due to problems associated
with the LTHRU. A temperature transmitter on the outlet of a condensate/syngas cross
exchanger began reading erratically causing syngas flow through the exchanger to be
automatically bypassed. When the reading returned to normal, the bypass valve closed
before the main exchanger inlet valve opened, causing the gasifier system to overpressure
and trip the plant off coal operations. Control program changes were made to prevent this
from recurring.
During 1999, the LTHRU contributed a total of 10 hours of plant downtime when an unused
tubesheet spray nozzle on an exchanger in that section of the plant failed causing a brief release
of syngas. The piping failure was due to chloride stress-corrosion-cracking that developed prior
to installation of the chloride scrubber in 1996. Other than this event, the LTHRU operated
extremely well for the remainder of the Demonstration Period.
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4.1.3.4 Acid Gas Removal
Production Information
Figure 4.1.3F illustrates the hydrogen sulfide (H2S) removal efficiencies for the acid gas removal
(AGR) system, by month, during the Demonstration Period. The efficiency calculation uses total
combustion turbine stack and flare stack syngas emissions (as sulfur) compared to the total sulfur
feed to the gasification plant (sulfur, dry-weight percent) for the most conservative estimate of
performance.
Hydrogen sulfide removal efficiencies remained fairly consistent throughout 1996. A drop in
efficiency can be noted in August of 1996 due to problems with the methyldiethanolamine
(MDEA) reclaim unit, which keeps the amine solvent low in heat stable salts (HSS). High HSS
concentration in the amine causes lower absorption efficiencies. Despite continued high solvent
HSS loading, the AGR system performance increased in the final quarter of 1996 due to cooler
ambient temperatures, which allows cooler amine process temperatures. November had no unit
operating days and contributed nothing to quarterly performance.
Hydrogen sulfide removal efficiencies for 1997 also were consistent. During the fourth quarter,
efficiencies were slightly higher, when compared to the first nine months of 1997, due to a
decrease in activity in the COS reactor catalyst beds and in their ability to convert carbonyl
sulfide to hydrogen sulfide.
Hydrogen sulfide removal efficiencies remained fairly consistent throughout 1998 and 1999 due
to improvements in the system and more consistent operation of the acid gas removal system and
sulfur recovery unit.
Removal efficiency for the first quarter of 1998 decreased slightly
compared to the fourth quarter of 1997 even though the plant processed an impressive 65%
increase in syngas production. A vacuum distillation was performed on the MDEA to remove
HSS in the fourth quarter of 1997.
The distillation effectively restored the H2S removal
efficiency of the amine solution.
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Figure 4.1.3F: Hydrogen Sulfide Removal Efficiency for Demonstration Period
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In June of 1998, H2S removal efficiency dropped to 98.1%.
This small decrease can be
attributed to a combination of factors. First, upon start-up in June, there was a change in the
gasifier coal feedstock to Miller Creek coal. This coal contains higher weight-percent sulfur.
This created a greater load on the AGR system, leading to a slightly higher level of H2S slippage
from the removal system. Second, rising ambient air temperatures during the summer months
increased the average amine solution temperature, which, in turn, decreased its stripping
efficiency.
Opportunities and Improvements
The following small-scale project improvements were completed within the AGR area in 1996:
•
Design oversights for the internals of the acid gas stripper were identified in the first quarter
of 1996. As a result of the deficiency, operation and maintenance costs increased due to
solvent attrition, higher start-up quench water requirements, increased ammonia
breakthrough to the sulfur recovery unit, reduced solvent strength and a slight efficiency
penalty due to reduced solvent inventory. Redesign of the internals incorporated to the
system in May rectified the problem.
•
The lean amine pumps were modified during the second quarter by the addition of automatic
recirculation valves incorporated at each pump discharge in place of a minimum flow orifice.
These valves ensure that each pump has minimum safe flow during all periods of operation.
The minimum flow orifice system was causing pipe erosion at low flow conditions due to
flashing in the piping downstream of the orifice.
•
In the third quarter, a pressure drop reduction project was installed for the lean amine return
piping. An increase in pipe size in one section of the line allowed for a reduction in system
head pressure and corresponding increase in pump flow. The added flow is helpful when
higher amine circulation rates are required, such as during warmer weather.
•
The MDEA reclaim unit, designed to remove HSS from the MDEA, experienced operational
problems throughout the year.
Early in 1996, efforts were undertaken to increase salt
removal capacity through regenerant feed system modifications. By the second quarter, HSS
loading on the MDEA increased to the point where it was necessary to call in an outside
vendor to remove the salts via a transportable vacuum distillation process. This process
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reduced the salts to a satisfactory level and restored the amine absorption capability to an
acceptable level. Feed system modifications completed late in the second quarter were
designed to boost capacity and utilize downtime for solvent reclaim process operation. A
condensate cooler was installed to prevent thermal shock to the resin, resulting from elevated
chemical feed dilution temperatures.
•
During the third quarter, a project was implemented to install chemical feed pulsation
dampeners in the MDEA reclaim unit to improve feed consistency and reduce chemical
attack of the resin by better controlling the added chemicals concentration.
In early January 1997, the acid gas absorber internals sustained damage resulting from excess
loading of the trays. To compensate for the reduced effective contact area, the amine was fed at
a higher level on the column. The tray damage to the column was repaired during the late April
outage and the feed point and the column performance returned to normal.
Reduced efficiencies encountered in the third quarter of 1997, can be directly attributed to the
increase in solvent temperature occurring in the summer months and continued degradation of
the COS catalyst, causing higher levels of COS in the absorber column inlet. A single event also
occurred in the third quarter directly effecting absorber efficiency when column performance
was compromised due to a collapse of a gas-liquid contact tray. Solvent anti-foaming compound
was exhausted, and went unnoticed, ten days prior to this event and consequential solution
foaming created a high differential pressure across the tray causing it to collapse. This event
eventually led to a sulfur dioxide air permit exceedance at the flare when product syngas had to
be flared because the product syngas sulfur limit was exceeded.
In the fourth quarter of 1997, because of an ever-increasing HSS loading of the amine, a vacuum
distillation was performed on the entire absorbent inventory to remove the salts. The distillation
recovered 82% of the solvent while removing the HSS. Efficiency increases can be attributed to
the fresh solvent application.
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The primary system modifications required in the acid gas removal system during 1998 centered
on the MDEA reclaim unit. The following represent key improvement projects developed for
the unit in 1998:
•
In the second quarter of 1998, the canisters containing the ion exchange resin started
experiencing reliability problems. It appeared that the resin canisters were being chemically
attacked by the combination of chemicals used within the unit. A test canister, constructed of
an alternate material, was placed in service for an evaluation period. Also, test coupons were
installed to determine the chemical resistance of other potential alternative materials.
•
In the fourth quarter of 1998, plans for an expansion of the unit were developed. The
expansion included increasing the canister capacity and changing the material of construction
from fiberglass to a metal alloy for increased mechanical integrity. These modifications were
completed in 1999 and enabled the unit to remove HSS at the rate of formation, thus
eliminating the HSS accumulation problem.
The most significant impact on AGR system performance in 1999 was continued project
improvements associated with the MDEA reclaim unit. These improvements will reduce the
operation and maintenance cost of the facility in two ways. First, the amount of amine purchased
annually can be reduced. In the past, HSS accumulation deteriorated the performance of the
amine plant, necessitating the purchase of new amine solution. This additional amine solution
effectively reduced the concentration of HSS allowing the plant to continue operation. Now,
amine should only need to be purchased to replace solution lost due to thermal degradation,
blowdown of the regeneration column, and rinsing of the MDEA reclaim unit. The second cost
reduction will come from the reduced need for third-party amine reclamation, such as the
vacuum distillation process used in the earlier years. The need for these reviews should now be
eliminated.
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4.1.3.5 Sulfur Recovery
Production Information
Figure 4.1.3G indicates the recovery efficiencies for the sulfur recovery unit (SRU), by month,
for the duration of the Demonstration Period. Sulfur recovery efficiencies indicated are split into
two specific areas. The left columns indicate the efficiency of the SRU by comparing total stack
emissions with total sulfur feed to the SRU. Overall plant removal efficiencies (right columns)
compare total Joint Venture emissions (as sulfur) versus total sulfur feed to the gasifier.
Overall, the 1996 graph follows directly with the reduction in reactivity of the COS catalyst and
is representative of degradation and replacement over the course of 1996. Fourth quarter,
following the installation of the chloride scrubbing system and improvements in the AGR
system, shows a significant increase in the removal efficiency of the SRU. A total of 3,289 tons
of sulfur was recovered during 1996.
Again in 1997, sulfur recovery compares directly with the reduction in reactivity of the COS
catalyst and illustrates a clear degradation over the course of the year.
Fourth quarter
replacement of the catalyst resulted in a significant increase in the overall Joint Venture removal
efficiency. A total of 8,568 tons of sulfur was recovered during 1997.
In 1998, there were no major changes to the AGR system that would have a direct effect on the
sulfur recovery efficiencies. Efficiencies remained very consistent throughout the year, thus
sulfur recovery averaged between 97.5 to 98.5%.
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Figure 4.1.3G: Sulfur Recovery Efficiency for Demonstration Period
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In 1999, continuous operation from June to October contributed to consistent sulfur recovery.
Both the SRU sulfur recovery efficiency and the overall sulfur recovery efficiency for the third
quarter increased slightly from the second quarter averages. Much credit for this increase can be
given to continuous operation of the plant. However, the SRU received the highest average acid
gas concentration of any previous quarter. Because the Modified-Claus process is a series of
equilibrium driven reactions, higher acid gas concentrations increase the driving force for the
formation of elemental sulfur, thereby increasing the single pass recovery efficiency.
The
increase in acid gas concentration is a result of lower amine circulation rates and higher sulfur
feedstock to the gasifier such as Miller Creek coal and petroleum coke.
Opportunities and Improvements
As with operation of most new systems, the early operation of the sulfur recovery unit was
characterized by a learning curve, which identified some unit shortcomings and improvement
opportunities. The improvements in 1996 include:
•
A bypass line was installed around the hydrogenation reactor, which allowed re-sulfiding of
the catalyst to take place on line. This alleviated early problems with sulfur formation and
pluggage of the tail gas handling system.
•
Modifications to strainers on the tail gas recycle compressor suction lines allowed
discretionary filtering, permitting small particle passage while retaining machine protection
and reducing the rate of strainer pluggage and compressor downtime. As the tail gas recycle
rate increased, sulfur plant recovery efficiency and production increased.
•
A project to enhance sulfur area safety and storage tank capacity was implemented in the
second quarter 1996. The project consisted of a new vent line to the tail gas incinerator
allowing the sulfur tank to operate at lower pressure. The sulfur storage tank usable capacity
was increased from 40% to 100% in the second quarter with implementation of the new
steam-jacketed vent line.
The new line isolates the tank from SRU process pressures,
resulting in maximum safe capacity.
•
In September, a new project was implemented allowing acid gas feed to the SRU prior to
coal feed to the gasifier. This increases total recovery by allowing high recovery during
start-ups as is reflected in the increase in efficiency for the last month in the third quarter. In
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October, new process-control implementation allowed acid gas feed to the SRU after coal
operations cease, thereby reducing emissions at the acid gas flare.
•
Some projects designed to enhance safety and reduce O&M costs were implemented for the
SRU in the fourth quarter. A rail car level transmitter replaced the originally installed
detection systems, which allows more consistent sulfur rail car loading and reduced the
potential for overfilling. Several lines in the SRU were modified to include double block and
bleed (DBB) isolation in strategic locations. This eliminates significant line blinding efforts
for vessel entry and allows SRU steam and condensate outages without forcing plant-wide
steam outages. Finally, the SRU area steam trap system was reconfigured to eliminate ice
hazards as well as providing a net reduction of 28 obsolete traps.
•
SRU support systems also received project improvements.
The tail gas quench cooler
required installation of upgraded tie rods to minimize tube vibration. The suction vent gas
blower knockout pot level monitoring system was redesigned for earlier high-level warning.
One of the two lower explosive limit (LEL) metering systems within the tank vent system
was relocated to a position where positive blower pressures would not affect accuracy,
reducing nuisance alarming and excessive re-calibration.
These improvements will
positively impact operability and reduce maintenance needs.
During 1996 several incidents in the SRU led to either production turndowns, or complete
shutdowns of the gasification process.
•
In the first quarter, several minor problems associated with a plugged condenser and a
plugged tank vent on the sulfur storage unit caused several hours of reduced production.
Both of these problems were quickly resolved and full production rates restored without
further incident.
Corrective measures were written into the operating procedure and
maintenance guide and no further problems of this nature occurred during the year.
•
In November, the pressure safety valve protecting the acid gas stripping column failed,
relieving at a pressure less than set point. Acid gas from the column was relieved into the
flare header, resulting in an exceedance of permitted limits for sulfur dioxide at the flare.
Investigation into the mechanism of failure revealed that debris in the pilot valve prevented
proper seating. This allowed the main valve to remain open at pressures below the relief set
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point. The pressure safety valve was subsequently removed and an alternate overpressure
protection device has been employed.
Several projects were implemented in 1997 and 1998 in the SRU to improve overall reliability
and maintainability. Those projects were:
•
The steam generator for the tail gas incinerator was improved to lower incidences of leaks in
the low-pressure steam drum safety valves. Rupture disks now isolate the safety selector
valve from the safety valves themselves. This has significantly reduced maintenance costs
associated with repair of the valves.
•
In the second quarter of 1999, a project designed to enhance safety, reduce emissions,
increase availability and lower O&M costs was instituted. A sulfur seal leg was installed at
the hydrogenation pre-heater along with an ancillary heating system.
The project was
designed to ensure liquid flow at the look box and prevent overpressure by not allowing a
solid plug of sulfur to form in that area. Personnel exposure and disposal costs have been
reduced as a direct result of this project.
•
One project in the first quarter of 1998 was intended to lower O&M costs and reduce the risk
of exposing operators to molten sulfur. The seal leg for the first sulfur condenser was
modified to facilitate removal of material causing flow restrictions. The new design allows
for removal of the material collecting in the bottom of the seal leg without cutting apart the
seal leg. Seal leg drain modifications have also been made which will reduce the potential to
expose operators to liquid sulfur.
•
Another project, implemented in the second quarter of 1998, is intended to improve safety
and increase tail gas recycle compressor reliability. The seal legs of the first stage suction
drums on the tail gas recycle compressors continuously over-pressured, allowing tail gas to
escape into a sump where it was recovered by the tank vent system. To prevent the seal legs
from over-pressuring, they were routinely blocked-in, requiring Operations personnel to
manually drain the condensed liquid from the suction drum. Occasionally, the unit would go
unchecked until a high liquid level would trip the compressor. During the June outage, the
seal legs were extended to prevent over-pressuring, thus reducing operator exposure to tail
gas and increasing compressor reliability.
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•
Another project was implemented during the outage in early September. Because of a
hydrogenation bypass valve leak, sulfur dioxide reacted with the H2S in the tail gas quench
column, forming elemental sulfur. This sulfur plugged the column, heat exchanger and
filters within the quench loop. Once the bypass valve was repaired, the entire quench loop
was flushed with a heated 25% caustic solution. The flush was successful and there has been
no more evidence of sulfur formation within the column.
Downtime attributed to the SRU during 1999 is summarized as follows:
•
During the first quarter of 1999, 8 hours of outage time were attributed to the SRU. During a
plant start-up in March, prior to acid gas addition to the SRU, combustion products from the
Claus reaction furnace were released from a sulfur seal leg. The subsequent investigation
concluded that the combination of a vacuum downstream and normal controlled pressure
upstream was sufficient to de-inventory the seal leg.
The vacuum was created while
pumping down the liquid sulfur storage tank. The normal pressure control set point for the
SRU during outages has been reduced to avoid any recurrence of this incident.
•
In July, the gasifier tripped due to slurry feed problems. Shortly after transferring back to
coal operation, the SRU air demand analyzer, the instrument responsible for determining fine
adjustments to the Claus furnace oxygen supply, experienced an undetected plug in the
sample line. Hours later, the accumulating error in the air demand analyzer caused an
elevated SO2 concentration in the catalyst beds, necessitating the addition of supplemental
hydrogen in the tail gas hydrogenation reactor. When the hydrogen was added, the SRU
pressure controller misinterpreted the signal from a pressure transmitter. The controller
opened the SRU pressure control valve, bypassing the tail gas recycle compressors and
allowing tail gas to flow to the tail gas incinerator. As a result, the SO2 flow from the
permitted tail gas incinerator stack reached a reportable level and coal operation was
immediately suspended. Since this incident, the pressure controller has been modified to
prevent a recurrence. Additionally, there is a project currently being implemented that will
give Operations an indication when the air demand analyzer signal is not reliable.
•
In early December of 1999, 69 hours of downtime were attributed to the sulfur recovery unit.
It was determined that the hydrogenation unit bypass valve was damaged and failing to open
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completely. Upon inspection, it was found that a mass of material had accumulated against
the valve, preventing it from opening. The valve then sustained damage when the actuator
attempted to open the valve. The material was a mixture of ammonium sulfate, iron sulfide
and elemental sulfur. The sulfur can be melted with current heat tracing but the other
materials have higher melting points. The reasons that these other materials are present in
this location are still being investigated.
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4.1.3.6 Sour Water Treatment
Production Information
Figure 4.1.3H illustrates the sour water outfall from the sour water treatment system by month
for the duration of the Demonstration Period.
Sour water to the outfall remained fairly consistent in volume from 1996 to 1998, but varied in
1999 from a high in September of 7.2 million gallons to a low in April and May of zero. During
the third quarter of 1998 there was a short period of atypical operation. The lower slurry rates
combined with the lower moisture content of the petroleum coke feed at the end of September
caused the sour condensate conditioning unit to see approximately 40% less flow. Typically, this
reduction in feed causes unfavorable hydraulics within the conditioning columns, resulting in the
production of off-spec water. However, during this period, a process of false loading was
employed. Using existing piping, conditioned water was transferred to the tail gas quench
column and then back to the front of the sour condensate conditioning unit. In doing so, proper
column hydraulics and in-spec water were maintained without upset or addition of supplemental
water.
Opportunities and Improvements
In the third quarter of 1996, operating data revealed the acid degassing and ammonia stripping
columns were exhibiting signs of tray damage. Inspections confirmed the diagnosis and revealed
significant damage, which was likely due to liquid flooding of the columns. In addition, damage
patterns suggested flashing liquid feed flow to the stripping column was responsible for the loss
of about 20% of the column trays. A new liquid feed distributor was installed to control
hammering of the trays. Operating parameters were revised with the inclusion of new control
system alarms to warn of impending flooding.
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Figure 4.1.3H: Water Outfall for Demonstration Period
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In the third quarter of 1997, a sour water carbon-filter vent containment system was installed to
prevent fugitive odors. This project enhances both safety and environmental stewardship by
eliminating another source of fugitive emissions. Fourth quarter enhancements to the system
included the conversion of an existing activated carbon storage tank to serve as a caustic tank.
Caustic has been added to the ammonia stripping column to further reduce the concentration of
ammonia to the permitted outfall. Until this project, the caustic source was the caustic feed to
the MDEA reclaim unit. Recognizing that a lower, less expensive grade of caustic could be
used, a drum was retrofitted to serve as the supply for the ammonia-stripping column. This
project should serve to significantly lower operating costs for the sour water unit.
In the second quarter of 1998, a significant amount of work was done on the carbon beds. High
differential pressures across the beds caused damage to the vessel internals. During the June
outage, structural modifications were made to ensure the vessel could withstand the higher
differential pressures.
The sour water treatment system operated very well except for the aforementioned items.
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4.1.4 Power Block
Table 4.1.4A illustrates power production by quarter for the duration of the Demonstration
Period.
Table 4.1.4A: Power Block Production
Longest
Combined Cycle
Operating Hours Continuous Run
Maximum CT
Maximum ST
Output (MW)
Output (MW)
Total Gross
Generation
On Syngas
Hours On Syngas
1996 1QTR
535
127
192
96
163,088
1996 2QTR
148
115
189
89
45,332
1996 3QTR
289
152
186
92
80,230
1996 4QTR
580
130
180
90
95,710
1996 TOTAL
1,552
(MWHours)
384,360
1997 1 QTR
870
330
192
96
240,000
1997 2QTR
730
185
192
100
205,000
1997 3QTR
1,329
360
192
100
307,274
1997 4QTR
766
230
192
100
189,410
1997 TOTAL
3,695
941,684
1998 1 QTR
1,270
475
192
98
359,689
1998 2QTR
1,449
510
192
98
395,683
1998 3QTR
993
257
192
98
254,000
1998 4QTR
1,427
427
192
98
420,188
1998 TOTAL
5,139
1,429,560
1999 1 QTR
821
425
192
98
229,814
1999 2QTR
199
179
192
98
54,052
1999 3QTR
1,621
1,115
192
98
444,364
1999 4QTR
780
318
192
98
203,713
1999 TOTAL
3,421
931,943
During 1996, the power generation block required no improvement projects or major equipment
modifications.
Equipment operated as designed and the only key area of change was the
identification of proper operating parameters for the combustion turbine and steam turbine
during the first commercial year.
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In 1996, the water treatment systems processed over 420.8 million gallons of water from the
Wabash River for use in the gasification and re-powering areas of the facility. Of this total,
approximately 110.6 million gallons were demineralized for use within the High Temperature
Heat Recovery Unit (HTHRU) of the gasification process and the Heat Recovery Steam
Generator (HRSG) at the exhaust of the combustion turbine.
The third quarter of 1997 produced the largest total power output for that year. In the month of
August, figures for total gross generation exceeded 160,000 megawatts for the first time since
Project start-up.
The months of March, May, July, August, September, November and
December show generation in excess of 60,000 megawatts on the combustion turbine with
syngas. Electricity production for the year realized an increase of over 200% over 1996.
The fourth quarter of 1998 produced the largest total power output for that year. October and
November were back-to-back high peak months, the best two consecutive months accomplished
by the facility since beginning operation in 1995. Additionally, 1998 was another record power
production year for the Project.
During 1999, July, August and September were high peak months of operation. Second quarter
activities were severely curtailed when, on March 13 a vibration alarm was detected on the #1
combustion turbine bearing seismic probe. The unit ultimately tripped 6 minutes later from high
exhaust temperature. Following investigation, it was determined that the compressor had failed.
PSI decided at that time to inspect all machine components due to the level of teardown required.
The inspection for all components, except the compressor, indicated normal wear for the number
of starts and run-time on the machine. The turbine had experienced 412 starts and over 14,000
hours of operation prior to this failure.
The compressor failure actually occurred in the 14th stage stator blades and propagated
downstream. Damage from the 14th stage downstream was catastrophic in nature and required
complete replacement of all rotating and stationary material. Due to schedule considerations and
opportunities to upgrade the compressor, PSI decided to purchase and install a new upgraded
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compressor from General Electric. The unit was returned to service on June 12, 1999 and has
run successfully since that time.
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4.2
General Information
4.2.1 Stream Data
Table 4.2.1A lists the main process streams for the Wabash River Coal Gasification Repowering
Project and their Proprietary/Non-Proprietary classification as agreed to in the Environmental
Monitoring Plan (EMP). Figure 4.2.1A illustrates the location of these streams within the
process. A complete summary discussion and an analysis review of these streams can be found
under Section 6.0 Environmental Performance of this Final Technical Report.
Additional
information, on a year-by-year basis, can be found in the Annual EMP reviews reported to the
DOE for the years 1995-1999.
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Table 4.2.1A: Key to Monitoring Locations
Location
Proprietary (P)
Designator
Non-Proprietary (NP)
Description of Monitoring Location
Status
1
NP
Coal Slurry
2
P
Raw Syngas
3
P
Sour Syngas
4
P
Sour Water
5
P
Acid Gas
6
P
Tail Gas
7
NP
Tail Gas Incinerator Stack Gas
8
NP
Sweet Syngas
9
NP
GT/HRSG Stack Gas
10
NP
Slag
11
NP
Sulfur
12
NP
Non-Contact Cooling Water (Outfall 001)
13
NP
Process Waste Water (Gasification Plant)
14
NP
Treatment Pond Discharge to Ash Pond (Outfall 102)
15
NP
Ash Pond Effluent (Outfall 002)
16
NP
Equipment Leak Fugitive Emissions
17
NP
Slurry Facility Fugitive Emissions
18
NP
Slag Handling Fugitive Emissions
19
NP
Coal Handling Fugitive Emissions
20
NP
Slag Transport and Storage Fugitive Emissions
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Figure 4.2.1A: Monitoring Locations
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4.2.2 Alternative Fuel Testing
This section presents the results from testing of an alternate fuel, petroleum coke (also referred to
as coke or pet coke). Approximately 20,000 tons of a 5% sulfur petroleum coke was processed
in the Wabash River plant with favorable performance and environmental results.
Plant
efficiency, emissions of SO2 and other air contaminants, trace metals balance, performance of the
COS hydrolysis catalyst, and sulfur removal system, are presented. Observations on plant
operation, including slurry preparation, flux addition, ash deposition, and gas stream
metallurgical testing are discussed. Results indicate that future projects that utilize this alternate
fuel could be implemented at a lower cost than Wabash River by reduction in the size or
elimination of some of the equipment. Global Energy believes this demonstration of the inherent
fuel flexibility of its E-Gas™ gasification technology will result in applications with other
opportunity fuels, including coal fines, renewables, or waste materials.
Introduction
Because of the availability of relatively low cost natural gas, coal-based integrated gasification
combined cycle (IGCC) power is not currently economical in areas where natural gas is
available. Low cost natural gas also impacts the use of coal to produce chemicals. For example,
steam reforming of natural gas is the leading source of hydrogen in North America. This has led
to the current trend in the advancement of gasification technology in the global market, to utilize
"low value" or opportunity fuels. Petroleum coke, a main by-product of refineries, is a prime
candidate fuel to link the gasification and refining industries.
Petroleum coke is produced in the processing of oil residue where lighter components are
extracted from the heavier fractions to maximize the yield of high value products such as
gasoline and jet fuel. For many refiners, this is economically more attractive than the alternative
option of selling the heavy fraction as residual fuel oil. Petroleum coke possesses energy content
equivalent to, or higher than, bituminous coal and is sold as a fuel to utilities and cement
producers. Even though petroleum coke is an undesired by-product in the refining process, its
production in the U.S. increased dramatically over the last decade. A dwindling supply of highquality, low-sulfur crude has driven refiners towards heavier and higher sulfur crude.
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According to the Energy Information Administration (EIA), as of January 1, 1997 there were 152
operating refineries in the U.S., with an aggregate total capacity of 16.3 million bbl/d. Of these
refineries, 54 operate coking units, and represent 59% of the total domestic crude oil distillation
capacity. In 1996 they produced 31.7 million tons of coke, which was 95% of total U.S. coke
production and roughly 70% of world coke production. Of this tonnage, 66% (roughly 22
million tons of coke) was exported, with Europe, Japan, Canada, and Turkey being the lead
importers.
Over the ten year period between 1987 and 1996, the trend in feedstock to U.S. refineries has
been toward heavier crude, from an average API gravity of 32.3° to 31°, and higher sulfur
content from an average 1.02 wt. % to 1.2 wt. %. Both of these trends have the impact of
increasing coke production per barrel of oil processed.
It has been estimated that U.S.
petroleum coke production could easily reach 32.9 million tons/year by the year 2000.
As coke production has increased, the coke market has become more constrained due to the
higher sulfur content. There also has been an increase in the number of refineries constructed
and installation of coker units overseas. Environmental restrictions on air emissions, especially
in developed and developing countries where much of the offshore refining capacity exists, has
also become more stringent. These facts lead to the conclusion that the already volatile coke
market is shrinking for U.S. exporters. This presents a unique opportunity for gasification
technology, which can effectively convert the low value petroleum coke to power or higher value
chemicals. Locating a gasification plant adjacent to a refinery also offers many synergistic
advantages to both the power and refining industries.
With these facts in mind, the significance of implementing this test program on the future
marketability of the E-Gas™ gasification process is obvious.
Wabash River Petroleum Coke Test
The idea behind the Wabash River test was to utilize petroleum coke as the primary feed, while
operating in a commercial environment. A rigorous program of preparation for the petroleum
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coke test was followed.
This included: laboratory analysis of coke properties and ash
characteristics; bench scale testing to determine the reactivity, grinding and slurrying
characteristics of the petroleum coke; computer simulations of process and thermal performance;
industrial hygiene review; and development of coke/flux blending equipment.
Eighteen thousand tons of a delayed sponge coke (Table 4.2.2A) were processed from November
17 through November 27, 1997. The plant switched from coal to pet coke feed “on-the-fly”
without interrupting operation. As-received 100% petroleum coke was used with no coal blend.
The coke had a sulfur content of 5%, which is well within the sulfur design limit of the Wabash
River plant. Laboratory ash composition and ash fusion analyses indicated the pet coke would
be difficult to slag-tap at typical gasifier operating temperatures. This necessitated the addition
of a fluxing compound to the feed prior to slurry preparation. Slag from an earlier coal run was
chosen because of its availability and its known ash flow characteristics. In the gasifier, the slag
captures most trace metals such as vanadium and nickel into its matrices. Encapsulated in the
inert, non-leaching slag, these trace metals were rendered safe for non-hazardous disposal or
reuse.
Table 4.2.2A: Fuel Analyses
Typical Coal
Petroleum Coke
15.2
7.0
ASH, %
12.0
0.3
Volatile, %
32.8
12.4
Fixed Carbon, %
39.9
80.4
Sulfur, %
1.9
5.2
NiO, % of ash
Trace
11.8
V2O5, % of ash
Trace
28.4
10,536
14,282
Analyses: Moisture, %
Metals in Ash:
Heating Value, as received, Btu/lb
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Overall Plant Performance
Plant operation was steady during the petroleum coke testing period, although the plant tripped
twice for brief periods: once because of a slurry feed pump trip, and once due to the dry char
particulate filtration system. Neither of these trips was related to the change in feedstock.
Operation at full load was achieved with 100% petroleum coke fuel supply while meeting all
environmental emission criteria. Operation was maintained at approximately 90% of syngas
facility capacity for the greater part of the test to match the combustion turbine fuel requirements
(Figure 4.2.2A).
Overall thermal performance (Table 4.2.2B) was slightly improved during petroleum coke
operation, with overall plant efficiency at 40.2% (HHV). The syngas consumption by the
combustion turbine in the “actual cases” was somewhat lower than predicted by the computer
simulation.
Figure 4.2.2A: Wabash River Plant Performance on Pet Coke
Petroleum Coke Performance Parameters
500
450
400
350
300
250
Wabash Plant Capacity, %
Combustion Turbine Output, MW
Steam Production, Mlb/hr
200
150
100
50
0
11/14/97
0:00
11/16/97
0:00
11/18/97
0:00
11/20/97
0:00
11/22/97
0:00
11/24/97
0:00
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11/28/97
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Table 4.2.2B: Thermal Performance Summary
Design
Actual
Coal
Coal
Pet Coke
Nominal Throughput, tons/day
2550
2450
2000
Syngas Capacity, MMBtu/hr
1780
1690
1690
Combustion Turbine MW
192
192
192
Steam Turbine MW
105
96
96
Auxiliary Power MW
35
36
36
Net Generation, MW
262
252
252
Plant Efficiency, % (HHV)
37.8
39.7
40.2
Sulfur Removal Efficiency, %
>98
>99
>99
Process Observations
Slurry: Grinding of the petroleum coke proceeded with no problem for the duration of the
testing. Slurry with a solids content of approximately 63%, and good flow characteristics for
pumping, was consistently produced.
Additional rods were added to the rod mill midway
through the test to further reduce the particle size of the slurry, but no significant change in the
solids content was noticed.
Reactivity: Laboratory tests prior to on-line operation, showed that the petroleum coke would be
much less reactive than the coal fuels. Initially, an average carbon conversion rate of about
97.5% was seen during the petroleum coke operation. Following the addition of the grinding
rods discussed above, and a resultant smaller particle size, overall carbon conversion improved
to above 99% (Figure 4.2.2B).
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Figure 4.2.2B: Petroleum Coke Test Overall Carbon Conversion
Overall Carbon Conversion
100.0
99.0
98.0
97.0
96.0
95.0
94.0
93.0
92.0
91.0
90.0
11/16/97
11/18/97
11/20/97
11/22/97
11/24/97
11/26/97
11/28/97
Flux Addition and Slag Flow: Based on laboratory ash fusion and high temperature slag viscosity
tests, a range of flux addition of 5 to 10 tons of slag per 100 tons of petroleum coke was targeted
for the test. However, problems with the blending equipment resulted in the test starting at a
ratio of about 20 tons/100 tons, or about 20% flux. This was corrected to the target ratio by the
third day of testing. Near the end of the test, the flux ratio was purposely reduced to about 2
tons/100 tons (Figure 4.2.2C). No slag-tapping problems were encountered during the test.
Figure 4.2.2C: Petroleum Coke Test Flux Content
Blend Ratio, ton of slag / ton of petcoke
Flux Content
0.20
0.18
0.16
0.14
0.12
0.10
0.08
0.06
0.04
0.02
0.00
11/17/97 11/19/97 11/21/97 11/23/97 11/25/97 11/27/97 11/29/97
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Syngas Quality: Product syngas characteristics were very similar to operation utilizing
bituminous coal feeds, as shown in Table 4.2.2C.
Table 4.2.2C: Product Syngas Analyses
Typical Coal
Petroleum Coke
Nitrogen, (N2) Vol. %
1.9
1.9
Argon (Ar), Vol. %
0.6
0.6
Carbon Dioxide (CO2), Vol. %
15.8
15.4
Carbon Monoxide (CO), Vol. %
45.3
48.6
Hydrogen (H2), Vol. %
34.4
33.2
Methane (CH4), Vol. %
1.9
0.5
Total Sulfur, ppmv
68
69
Higher Heating Value, (HHV) Btu/scf
277
268
Trace Metals: The ash component of the petroleum coke contained approximately 12% NiO and
28% V2O5. The nickel and vanadium trace metal species are often of great concern in utility
boiler operation. Vanadium pentoxide has been found to aggressively attack boiler metals, and
nickel vapor is a known toxic even at very low levels. Process samples from solid, liquid and
gas streams were taken at various points in the process during testing in order to quantify trace
metal contents. About 80% of the nickel and 99% of the vanadium were captured in the silicate
matrix of the slag and rendered inactive in the inert, non-leaching solid, as confirmed by the
TCLP environmental leachate test. Some nickel components were found in ash depositions as
expected. Liquid and product gas streams contained less than 1 ppm levels of nickel and
vanadium species. The process, as currently configured, handles the trace metals more than
adequately.
Refractory: Based on analysis of slag samples from the gasifier, refractory wear rate, even at the
elevated temperatures required for pet coke operation, was similar to that while on coal
operation. No unusual chemical interactions were observed.
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Corrosion: No adverse impact on the metallurgy of the existing equipment was observed.
Analysis of test coupons placed throughout the system indicated that corrosion conditions were
not much different than coal operation. In particular, the metallic filters showed approximately
the same corrosion rates as had been evidenced during coal runs.
Ash Deposition: Ash deposition at the boiler inlet was slightly higher than normal operation,
especially when temperatures within the second stage of the gasifier were increased.
No
additional deposition was noted in other areas.
Char and Tar Characteristics: Because of the lower reactivity of the petroleum coke, char
loading to the dry char particulate removal filters was higher than coal operation at similar rates.
No filtration problems due to the higher solids loading were observed. Sampling of the syngas at
the gasifier outlet showed negligible amounts of tar formation. This may indicate that the second
stage of the gasifier could operate at lower temperatures than during the test, which would
enhance conversion efficiencies.
Sulfur Removal: Although designed to operate with up to 5.9% sulfur content coal, most of the
Wabash River plant operation has been with coals having 2-3% sulfur content. As expected,
both H2S and COS levels in the raw syngas were much higher during the petroleum coke test due
to the greater amount of sulfur in the feed. However, total sulfur in the product syngas was
maintained at levels similar to coal operation (Table 4.2.2C and Figure 4.2.2D). No problems
were encountered with sulfur removal or recovery. In particular, the COS catalyst performed
well and higher conversion rates were indicated. No adverse impact on the catalyst was detected
in post-test analysis of catalyst core samples.
Air Emissions: Extensive testing was conducted at two stack locations: the gasification facility
incinerator stack and the combustion turbine HRSG stack. Tests were made during both coal and
petroleum coke operation. Particulate emission levels were low in both coal and coke cases,
totaling about 30 lb/hr for both stacks. No nickel or vanadium components were detected at the
incinerator stack. No testing for these components was done in the HRSG stack since the
product syngas was being tested. Unburned hydrocarbon emissions were nearly identical for
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both coal and coke operation (both were less than 1 ppm). Overall combined sulfur dioxide
emissions were significantly less than 0.2 lb SO2 per MMBtu of coal.
Figure 4.2.2D: Total Sulfur in Product Syngas
Total Sulfur in Product Syngas, ppm
120
100
80
60
40
20
0
11/15/97
11/17/97
11/19/97
11/21/97
11/23/97
11/25/97
11/27/97
Conclusions
The overall conclusion from the testing is that petroleum coke operation was not significantly
different than coal operation, and that the equipment and systems in place at Wabash River were
adequate for this operation without modification. Other observations:
•
Thermal efficiency greater than 40% was demonstrated at Wabash River with an “F” class
combustion turbine and a repowered steam turbine. Future facilities should be able to
approach 42-44% efficiency with the “H” class turbines.
•
Gasifier operation on petroleum coke, although requiring somewhat higher temperatures, was
much simpler than coal operation, primarily due to the reduced volume of ash components.
Gasifier operation was proven down to a level of 2% flux addition.
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•
Trace metal components were captured in the slag, which passed leachate testing and thus is
a non-hazardous material. Nickel and vanadium did not appear in the liquid or gas streams
resulting from gasification of the pet coke.
•
Tar presence in the syngas was negligible.
•
Industrial hygiene considerations were the same as for coal operation.
•
Additional char was produced, but can be handled utilizing dry char particulate removal
systems of the current design.
It appears that future units designed to utilize petroleum coke as their primary fuel source can be
similar to Wabash River, but with some improvements to reduce costs or improve operability.
Low flux requirements demonstrated at Wabash River mean that the slag, ash and flux systems
in future plants can be downsized considerably. The low reactivity of the petroleum coke will
mean elimination of certain equipment at Wabash River intended to minimize tar formation.
Because of the higher energy content and less tonnage requirement for petroleum coke, the coal
handling and slurry preparation systems can be downsized as well. Operation should continue to
be smoother than coal, indicating improved availability and capacity factors for a petroleum coke
facility.
Future Alternative Fuel Testing
Similar tests of other alternative fuels are also being planned. Coal fines, a promising fuel in the
locality of the Wabash River facility, are being produced by existing mine operations and also
are available from surface reserves where the fines have been landfilled in the past. Coal fines
may be available at 40-60% less than the delivered cost of coal to the facility. Major plant
modifications may not be necessary to utilize the coal fines fuel. A survey on coal fines
availability in the area has been completed and initial laboratory analysis has begun.
Biomass or “renewables” and various waste materials are other alternate fuels being investigated.
With concern on global climate changes, there will be more emphasis to reduce emission of
greenhouse gases such as CO2 from fossil fuel use. Materials such as sewage sludge, municipal
solid waste (MSW), refuse derived fuel (RDF), wood residues, railroad ties, and used tires are
potential feedstock candidates. Since most biomass materials are relatively reactive, the twoWabash River Coal Gasification Repowering Project Final Technical Report
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stage design of the Global Energy E-Gas™ gasifier is uniquely suitable for co-feeding with coal.
Coal will still be fed to the high temperature first stage with oxygen, and the alternate fuels will
be fed to the lower temperature and longer residence time second stage. A high conversion of
the reactive alternate fuel will still be achieved utilizing the thermal energy from the first stage.
The biomass feedstock will also be prepared and handled separately from the coal and coal
slurry. Because biomass has characteristics different from coal in terms of handling, a method to
prepare and feed the biomass material to the gasifier is being investigated.
Building on the lessons learned and the many successes to date, the Wabash River Coal
Gasification Repowering Project gasification plant looks forward to continued demonstration of
the viability of the technology in its use of alternate fuels. The advanced gasification technology
demonstrated at the Wabash River facility has met the objectives of the Clean Coal Technology
Program as outlined in this Final Technical Report and is well positioned to provide the solution
to the growing global demand for efficient, environmentally superior, competitive energy
conversion to power from coal or alternate feedstocks. Additionally, efforts are underway to
incorporate and pursue value-added uses for syngas produced, such as is envisioned through
forward-thinking concepts like the DOE’s “Vision 21” initiative.
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4.3
Critical Component Failure Report
A critical component is defined as any piece of equipment whose failure, or failure of the
equipment’s associated piping, valving or instrumentation, has resulted in a coal interruption.
The likelihood of a critical component failure is substantially higher during a transient condition
such as plant start-up or shut-down than during steady operation on coal.
Consequently,
understanding the root cause of a coal interruption is not only key to reducing future occurrences
but also key to reducing other component failures brought on by the transient condition of the
interruption. A summary of the causes for coal interruptions by plant area for the four-year
Demonstration Period is shown in Table 4.3A.
Table 4.3A: Summary of Critical Components by Plant Area
Plant Area
Power Block
Particulate Removal
First Stage Gasifier
Slurry Feed
High Temperature Heat Recovery
Air Separation Unit
Slag and Solids Handling
Low Temperature Heat Recovery
Sulfur Recovery
Chloride Scrubber
Scheduled Maintenance
Acid Gas Removal
Total
Total hrs on Coal
Average coal hours/run
1996
11
10
8
2
8
1
2
6
3
51
1,915
38
Number of Coal Interruptions
1997
1998
1999
12
5
5
6
6
3
5
6
2
3
4
7
7
1
2
10
1
3
3
2
1
1
2
1
1
2
3
1
3
45
39
24
3,886
5,278
3,496
86
135
146
Total
33
25
21
16
16
14
8
8
5
4
6
3
159
The greatest improvements in key component failures have occurred in the areas where the most
attention has been focused, namely the power block, the particulate removal system, the first
stage gasifier, and the high temperature heat recovery unit. Interface problems between the
gasification block and the power block resulting in coal interruptions were frequent in the first
two years of operation. For example, 10 coal interruptions were caused by the loss of boiler
feedwater supply from the power block to the gasification block in the first two years. Only 1
interruption occurred in the subsequent two years. A significant effort to improve the particulate
removal system has resulted in one of the most reliable particulate removal systems in the world.
The reliability of the first stage gasifier continues to improve, and since system modifications in
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the fall of 1997, the high temperature heat recovery unit has been nearly trouble-free. More
detailed information on the improvements in these areas can be found in Section 5.0 of this
report.
Three exceptions to the flat or decreasing number of interruptions for most of the areas are worth
noting. First, the slurry feed system has seen an increasing number of interruptions. Eight of the
eleven interruptions in the last two years have been due to valve failures or a plugged suction
line between the low-pressure slurry pump and the slurry storage tank. By early 2000, both of
these problems should be greatly reduced if not eliminated. The valve failures resulted from
poor material specifications that will be upgraded and the occurrence of plugged suction lines
will be reduced with the installation of a larger diameter agitator in the primary slurry storage
tank. Second, the air separation unit has not been as reliable as anticipated. However, several
improvements, discussed in more detail in Section 5.0, were made in the summer of 1999 that
should increase reliability. Third, the scheduled maintenance interruptions are increasing. This
increase indicates that the process is becoming more predictable. It is not coincidental that the
best production year for the plant was also the year of the most scheduled outages. Had the
combustion turbine rotor failure not occurred, a similar trend in 1999 could have been noted.
The average hours per campaign demonstrate a steady increase and should continue as future
improvements to the process and operating practices are completed.
Coal Interruptions Prioritized by Downtime Severity
Since the duration of the downtime associated with each of the interruptions noted in Table 4.3A
ranged from 46 minutes to 101 days, a second summary, Table 4.3B, prioritizes the downtime
severity for each of the coal interruptions. Table 4.3B divides the downtime associated with a
coal interruption into five types. These types are defined as follows;
A
Coal interruptions that result in downtime greater than two weeks.
B
Coal interruptions that result in downtime greater than one week but less than two.
C
Coal interruptions that result in downtime greater than 72 hours but less than one week.
D
Coal interruptions that result in downtime greater than 24 hours but less than 72 hours.
E
Coal interruptions that result in downtime less than 24 hours.
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In Table 4.3B, as in Table 4.3A, improvement trends are evident.
However, four critical
opportunities are noteworthy, some of which are not obvious from the data presented. These
four areas constitute the primary critical areas where teams have been formed to address the
specific problems mentioned. Although other areas force the plant off line, these interruptions
are addressed primarily by improving the preventative maintenance program or the plant’s
operating discipline.
First Stage Gasifier
First, plugging of the taphole associated with the first stage gasifier must be eliminated. Plugged
tapholes accounted for 4 of the 5 first stage gasifier coal interruptions with downtime severity of
A or B. These incidents are avoidable and improved operating guidelines have been instituted
that should eliminate these occurrences. Second, of the 21 coal interruptions for the first stage
gasifier in the last four years, 11 were due to slurry mixer failures. Fortunately, continuous root
cause investigations into failures, design improvements of the slurry mixer and control logic
enhancements are reducing the trips associated with failed slurry mixers. In 1999, only one coal
interruption was due to a slurry mixer failure.
Particulate Removal
The particulate removal system is a critical component that has driven overall plant availability.
In years such as 1998 and 1999, when the particulate removal system brought the plant down
less than twice per year, overall plant availability was high. An aggressive improvement effort
coupled with a disciplined quality assurance process has contributed to the improved availability
of the particulate removal system. The type A downtime event in 1999 was not associated with
the filter elements, but with the char return piping system to the first stage gasifier. The type B
downtime event was associated with an experimental filter cluster. With the char return piping
system permanently fixed and more conservative risk management with respect to experimental
filters, future coal interruptions attributed to this system should be minimal.
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Table 4.3B: Downtime Consequences of Critical Components by Operational Area
Plant Area
A - Downtime Consequence Greater than 2 weeks
Scheduled Maintenance
Particulate Removal
High Temperature Heat Recovery
Power Block
First Stage Gasifier
Chloride Scrubber
*Forced into an outage early.
Total
B - Downtime Consequences 1 to 2 weeks
First Stage Gasifier
Low Temperature Heat Recovery
Particulate Removal
1996
4
4
1997
2*
1
1
Number of Trips
1998
1999
3
1
1
1
2
1
9
1
1
6
1
5
4
1999
1
1996
1
2
1997
2
1998
3
2
0
C - Downtime Consequences 72 hours -7 days
Air Separation Unit
First Stage Gasifier
High Temperature Heat Recovery
Acid Gas Removal
Low Temperature Heat Recovery
Power Block
Slag and Solids Handling
Slurry Feed
Total
1996
1
1997
1998
4
D – Downtime Consequence 24-72 hours
First Stage Gasifier
Air Separation Unit
Particulate Removal
Slag and Solids Handling
High Temperature Heat Recovery
Power Block
Acid Gas Removal
Chloride Scrubber
Slurry Feed
Low Temperature Heat Recovery
Sulfur Recovery
1996
2
Total
1
1
1
1
1
6
1
1
1
Total
E – Downtime Consequences Less than 24 hours
Power Block
Particulate Removal
Slurry Feed
First Stage Gasifier
High Temperature Heat Recovery
Air Separation Unit
Low Temperature Heat Recovery
Sulfur Recovery
Slag and Solids Handling
Acid Gas Removal
Chloride Scrubber
Total
1996
9
4
1
4
3
2
2
1
26
1
4
1
1997
1998
4
4
1
1999
1
1
1
7
1999
3
2
1
1
2
2
3
2
1
1
1
1
2
1
1
11
9
5
1997
10
5
2
1
2
1
1998
5
4
4
1
1
2
2
1
1999
3
1
1
23
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21
6
1
1
1
12
Total
6
7
5
2
3
1
24
Total
4
2
1
7
Total
5
2
2
1
1
1
1
1
14
Total
6
5
4
4
3
3
1
2
2
1
1
32
Total
27
13
13
6
6
4
4
4
3
1
1
82
4-88
Air Separation Unit
This reliability of this system has not been near that expected. In 1998, the air separation unit
was responsible for 10 coal interruptions and more than 16 days of downtime. Although the air
separation unit caused only one coal interruption in 1999, over 14 days of downtime was
associated with this system. Since the demonstrated industry reliability of air separation units is
relatively high compared to gasification processes, the Project’s air separation unit should cause
no coal interruptions. Although several improvements have been implemented to enhance the
unit’s reliability, this air separation unit is still not up to industry standards and additional
improvements are being pursued.
High Temperature Heat Recovery
Coal interruptions due to this system have been virtually eliminated with only one incident in the
last two years. However, the length of scheduled outages is often determined by the time
required to clean the boiler tubes and perform the associated maintenance. Tube side deposits
are tenacious and very hard. Mechanical and chemical cleaning methods have been improved to
dramatically reduce the cleaning time, but improvements are still needed in this area and are
being pursued.
The team approach utilized to address the four critical components outlined above, coupled with
the plant’s continually improving operating discipline, will ensure that fewer and fewer critical
components show up on future critical component reports.
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