United States
Environmental Protection
Agency
EPA-430/R-06/006
July 2006
Final Report
Environmental Footprints and Costs of
Coal-Based Integrated Gasification
Combined Cycle and Pulverized Coal
Technologies
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FOREWORD
Currently, over 50 percent of electricity in the U.S. is generated from coal. Given that coal
reserves in the U.S. are estimated to meet our energy needs over the next 250 years, coal is
expected to continue to play a major role in the generation of electricity in this country. With
dwindling supplies and high prices of natural gas and oil, a large proportion of the new power
generation facilities built in the U.S. can be expected to use coal as the main fuel. The
environmental impact of these facilities can only be minimized by innovations in technology that
allow for efficient burning of coal, along with an increased capture of the air pollutants that are an
inherent part of coal combustion.
EPA considers integrated gasification combined cycle (IGCC) as one of the most promising
technologies in reducing environmental consequences of generating electricity from coal. EPA
has undertaken several initiatives to facilitate and incentivize development and deployment of this
technology. This report is the result of one of these initiatives and it represents the combined
efforts of a joint EPA/DOE team formed to advance the IGCC technology. The various offices
within DOE that participated in the development/review of this report were the Office of Fossil
Energy, including the Clean Coal Office and the National Energy Technology Laboratory.
IGCC is a dynamic and rapidly evolving technology. The economic and environmental
information related to IGCC and other advanced combustion systems is changing quickly. The
data and analysis presented in this report is an evaluation of information available as of February
2006. The report provides a snapshot of conditions in a changing industry and makes technical
and cost information for the IGCC technology available to environmental professionals belonging
to Federal and state organizations and other stakeholders. Detailed comparisons of the IGCC and
pulverized-coal technologies are also provided, enabling the reader to observe and compare the
capabilities of these technologies in relation to each other. The overall goal of this effort is to
develop and compile technical and economic information to be used in connection with the
development of EPA's policies, as well as to provide technical support and information transfer
to ensure effective implementation of environmental regulations and strategies. EPA believes it
is useful to examine these technologies as part of an ongoing effort to evaluate IGCC and other
advanced coal systems.
EPA REVIEW NOTICE
This report has been peer and administratively reviewed by the U.S. Environmental Protection
Agency, and approved for publication. This publication provides technical and economic
information to support the goals and purposes described in the report. The report does not
establish, prescribe, or change any EPA policy or legal interpretation with respect to the
regulation and permitting of IGCC or pulverized-coal facilities. Emissions limitations and
permit conditions for such facilities should be determined by permitting authorities on the basis of
applicable EPA and state regulations and the record in each permit proceeding. EPA retains the
discretion to promulgate or amend regulations and policy concerning the control of emissions
from such sources on the basis of this report and additional information or public comment in the
record of an Agency action. Mention of trade names or commercial products in this publication
does not constitute endorsement or recommendation for use.
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EPA-430/R-06/006
July 2006
Environmental Footprints and Costs of Coal-Based
Integrated Gasification Combined Cycle and
Pulverized Coal Technologies
Prepared by:
Nexant, Inc.
101 Second Street
San Francisco, CA 94105
Subcontractor of
The Cadmus Group, Inc.
57 Water Street
Watertown, MA 02472
EPA Contract No. 68-W-03-33, Work Assignment 2-02
EPA Work Assignment Manager: Sikander R. Khan
EPA Project Officer: Gene-Hua Sun
Clean Air Markets Division, Office of Atmospheric Programs
Washington, DC 20005
Prepared for:
U.S. Environmental Protection Agency
Office of Air and Radiation
Washington, DC 20460
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ABSTRACT
The report presents the results of a study conducted to establish the environmental
footprint and costs of the coal-based integrated gasification combined cycle (IGCC)
technology relative to the conventional pulverized coal (PC) technologies. The
technology options evaluated are restricted to those that are projected by the authors to be
commercially applied by 2010. The IGCC plant configurations include coal slurry-based
and dry coal-based, oxygen-blown gasifiers. The PC plant configurations include
subcritical, supercritical, and ultra-supercritical boiler designs. Even though the ultra-
supercritical design has not been applied in the U.S., it was included based on its
commercial experience in Japan and Europe.
All study evaluations are based on the use of three different coals: bituminous, sub-
bituminous, and lignite. In addition, the same electric generating capacity of 500 MW is
used for each plant configuration. State-of-the-art environmental controls are also
included as part of the design of each plant.
The environmental comparisons of IGCC and PC plants are based on thermal
performance, emissions of criteria and non-criteria air pollutants, solid waste generation
rates, and water consumption and wastewater discharge rates associated with each plant.
The IGCC plants in these comparisons include NOx and SC>2 controls considered viable
for 2010 deployment. In addition, the potential for use of other advanced controls,
specifically the selective catalytic reduction system for NOx reduction and the ultra-
efficient Selexol and Rectisol systems for SC>2 reduction, is also investigated.
The cost estimates presented in the report include capital and operating costs for each
IGCC and PC plant configuration. Cost impacts of using the advanced NOX and 862
controls are likewise included.
The report also provides an assessment of the CO2 capture and sequestration potential for
the IGCC and PC plants. A review of the technical and economic aspects of CC>2 capture
technologies that are currently in various stages of development is included.
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ACKNOWLEDGEMENTS
Nexant and Cadmus wish to acknowledge the U.S. Environmental Protection Agency
work assignment manager, Sikander Khan, and Denny Smith from the U.S. Department
of Energy for their comprehensive guidance and periodic reviews of emission estimates
and power generation performance. Their inputs added significant value to the report
results and are greatly appreciated.
in
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TABLE OF CONTENTS
EXECUTIVE SUMMARY ES-1
Section 1 Process Design
1.1 Introduction 1-1
1.2 Design Basis 1-1
Section 2 Process Description
2.1 Process Description 2-1
2.1.1 IGCC Plants 2-2
2.1.2 PC Plants 2-10
2.1.3 Process Maturity and Data Availability 2-17
Section 3 Technical Analyses
3.1 Power Generation Performance 3-1
3.2 Integrated Gasification Combined Cycle Emissions 3-4
3.3 Pulverized Coal Plant Emissions 3-13
3.4 Air Permit Data 3-25
3.4.1 Criteria Pollutants 3-26
3.4.2 Non-Criteria Pollutants 3-27
3.5 Emission and Air Pollution Data from the Literature 3-27
3.6 PC Solid Wastes and Liquid Effluents 3-29
3.7 IGCC Solid Wastes and Liquid Effluents 3-34
Section 4 Special Studies
4.1 Technical and Economic Assessment of SCR for
Gasification Combined Cycle NOX Control 4-1
4.1.1 Combustion NOx Control Technologies 4-2
4.1.2 Post-Combustion NOX Control 4-3
4.1.3 Cost Estimates for SCR Addition 4-5
4.2 Assessment of Sulfur Removal Technologies
- Selexol and Rectisol 4-8
4.2.1 Sulfur Removal and Recovery Technologies 4-10
4.2.2 Cost and Economic Estimates 4-13
IV
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Section 5 Carbon Management
5.1 CO2 Separation, Capture and Sequestration
Background 5-1
5.2 SCS Technologies for Pulverized Coal Plants 5-2
5.2.1 Gas Absorption 5-2
5.2.2 MEA Absorption 5-3
5.2.3 MEA CO2 Absorption Performance 5-5
5.2.4 MEA Technology Status 5-6
5.3 Oxygen Combustion Technology 5-8
5.4 Coal Gasification with CO2 Removal 5-9
5.5 Power Generation Systems with and without
CO2 Removal 5-10
5.6 Coal Quality and CO2 Removal 5-14
5.7 Note on Avoided Costs 5-15
5.8 CO2 Pipeline Transport 5-16
5.9 Geological Sequestration 5-17
5.9.1 Potential Storage Formations 5-18
5.10 CO2 Sequestration Regional Partnerships 5-20
Reference List
Appendix A Cost Estimate Data
Appendix B Air Permit Raw Data
Appendix C Energy and Material Balances
EXHIBITS
Exhibit ES-1, Generation Performance Comparison ES-7
Exhibit ES-2, Environmental Impact Comparison ES-8
Exhibit ES-3, Technology Cost Comparison ES-10
Exhibit 1-la, Study Coal Proximate Analyses 1-2
Exhibit 1-lb, Study Coal Ultimate Analyses 1-2
Exhibit 1-2, Mineral Analysis Data 1-3
Exhibit 1-3, EPA Criteria and Non-Criteria/Hazardous Pollutants 1-4
Exhibit 2-1, Summary of Plant Design Features 2-1
Exhibit 2-2, Integrated Gasification Combined Cycle Block Diagram 2-3
Exhibit 2-3, Major Gasification System Types 2-5
Exhibit 2-4, Pulverized Coal Power Plant Block Diagrams 2-12
Exhibit 2-5, Example of SCR in a Pulverized Coal Boiler System 2-14
Exhibit 3-1, Integrated Gasification Combined Cycle Performance 3-1
Estimates - Bituminous and Subbituminous Coals
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EXHIBITS
Exhibit 3-2, Integrated Gasification Combined Cycle Performance 3-2
Estimates - Lignite Coal
Exhibit 3-3, Typical IGCC Auxiliary Power Consumption 3-2
Breakdown
Exhibit 3-4, Subcritical Pulverized Coal Unit Performance Estimates 3-3
Exhibit 3-5, Supercritical Pulverized Coal Unit Performance 3-3
Estimates
Exhibit 3-6, Ultra-Supercritical Pulverized Coal Unit Performance 3-4
Estimates
Exhibit 3-7, Typical PC Plant Auxiliary Power Consumption 3-4
Breakdown
Exhibit 3-8, IGCC Trace Metal Reporting Within the Process 3-8
Exhibit 3-9, Estimates of IGCC Trace Element Emissions 3-9
Exhibit 3-10, IGCC Environmental Impacts, Slurry Feed Gasifier 3-10
Exhibit 3-11, IGCC Environmental Impacts, Solids Feed Gasifier 3-11
Exhibit 3-12, Estimates for PC Plant Mercury Removal with 3-18
conventional controls
Exhibit 3-13, Subcritical Pulverized Coal Plant Environmental 3-21
Impacts
Exhibit 3-14, Supercritical Pulverized Coal Plant Environmental 3-22
Impacts
Exhibit 3-15, Ultra Supercritical Pulverized Coal Plant 3-23
Environmental Impacts
Exhibit 3-16, Air Permit Data and Estimates for Criteria Pollutants 3-26
Pounds per Million Btu (except lead)
Exhibit 3-17, Summary of IGCC and PC Environmental Controls 3-27
Exhibit 3-18, Emission Data from the Literature 3-29
Exhibit 3-19, PC Plant Solid Waste Estimate 3-30
Exhibit 3-20, Summary of PC Plant Water Balances U.S. 3-32
DOE/NETL Study Results
Exhibit 3-21, Estimated Water Balances for PC Plants and Coals 3-33
Gallon per Minute
Exhibit 3-22, IGCC and Supercritical PC Solid Wastes 3-34
Exhibit 3-23, Summary of IGCC Plant Water Balances U.S. 3-35
DOE/NETL Study Results
VI
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EXHIBITS
Exhibit 3-24, Estimated Water Balances for IGCC Plants and Coals 3-36
Gallon per Minute
Exhibit 3-25, Summary Comparison of IGCC and SCPC Water 3-37
Losses
Exhibit 3-26, Non-Criteria Pollutant Estimates, Air Permit Data (1 of 3-38
3 Tables)
Exhibit 3-26, Non-Criteria Pollutant Estimates, Air Permit Data (2 of 3-39
3 Tables)
Exhibit 3-26, Non-Criteria Pollutant Estimates, Air Permit Data (3 of 3-40
3 Tables)
Exhibit 4-1, SCR Installation for IGCC Technology 4-3
Exhibit 4-2, NOX Emissions for Bituminous Coal IGCC - with and 4-6
without SCR
Exhibit 4-3, Cost Effectiveness Estimate for SCR NOX Reduction 4-7
Exhibit 4-4, Comparison of Sulfur Removal Technologies for IGCC 4-9
Exhibit 4-5, Rectisol Process Block Diagram 4-10
Exhibit 4-6, Selexol Process Block Diagram 4-12
Exhibit 4-7, Sulfur Recover Block Diagram 4-13
Exhibit 5-1, Gas Absorption Processes Used for CO2 Removal 5-3
Exhibit 5-2, CO2 Removal by MEA Absorber/Stripper 5-5
Exhibit 5-3, U.S. DOE/NETL Study, CO2 Removal Impacts - A 5-6
Supercritical PC Plant
Exhibit 5-4, Natural Gas Combined Cycle CO2 Capture Progress 5-7
Exhibit 5-5, Solvents for CO2 Removal 5-7
Exhibit 5-6, IGCC with CO2 Separation and Capture 5-10
Exhibit 5-7, Carbon Management Comparison, U.S. DOE, EPRI, 5-11
Parsons Study
Exhibit 5-8, Gasification Carbon Management Data, IEA GHG 2003 5-12
Exhibit 5-9, CCPC Summary Data for Plants with CO2 Removal 5-14
Exhibit 5-10, Illustration of Avoided Cost for CO2 Capture 5-15
Exhibit 5-11, Pipeline Size and CO2 Flows 5-16
Exhibit 5-12, CO2 Transportation Cost Data 5-17
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EXHIBITS
APPENDIX A
Exhibit A-l, Total Capital Requirement and Operating Cost A-2
Exhibit A-2, Summary of Costs A-2
Exhibit A-3, Subcritical Pulverized Coal Estimates, 1,000s 2004 A-6
Price and Wage Level
Exhibit A-4, Supercritical Pulverized Coal Estimates, 1,000s 2004 A-7
Price and Wage Level
Exhibit A-5, Ultra Supercritical Pulverized Coal Estimates, 1,000s A-8
2004 Price and Wage Level
Exhibit A-6, Comparison of Cost Estimates from Published Sources A-9
Exhibit A-7, Comparison of Coal Quality, Cost and Performance A-10
Exhibit A-8, Annual Operating and Maintenance Costs, $ 1,000s A-l 1
Exhibit A-8, 2004 Coal Price Data EIA Coal Price Data 2004; cost A-12
per million Btus calculated
Exhibit A-9, Summary of IGCC Cost Estimates A-13
Exhibit A-10, GE Energy (Ex-Texaco) IGCC Costs, $ 1,000s A-14
Exhibit A-11, ConocoPhillips (Ex-EGas) IGCC Costs, $ 1,000s A-15
Exhibit A-12, Comparison of IGCC Cost Data, $ 1,000s A-17
Exhibit A-13, IGCC Costs and Coal Quality A-19
Exhibit A-14, Annual Operating and Maintenance Costs, $ 1,000s A-20
APPENDIX B
Exhibit A, Criteria Pollutants from Air Permits and Other Documents B-2 to 6
Exhibit B, Non-Criteria Pollutants from Air Permits and Other B-7tol9
Documents
Vlll
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LIST OF ACRONYMS AND SYMBOLS
As
ASU
bbl
Be
BOP
Btu/kWh
C2He
CaSO3
CaSO4
CCPC
CCS
Cents/kWh
Cd
CH4
CO
CO2
COE
COPHAC
COS
Cr
CSC
CS-ESP
daf
DOE
E&M
EIA
EPRI
ESP
FF
FGD
GE
GtCO2
H2
H2O
H2S
H2SO4
HC1
HF
Hg
HHV
HRSG
HS-ESP
1C
IDC
IGCC
kW
Ib/MMBtu
Ib/MWh
Arsenic
Air Separation Unit
Barrel
Beryllium
Balance of Plant
British Thermal Units per Kilowatt Hour
Ethane
Calcium Sulfite
Calcium Sulfate
Canadian Clean Power Coalition
Carbon Capture and Storage
Cents per Kilowatt Hour
Cadmium
Methane
Carbon Monoxide
Carbon Dioxide
Cost of Electricity
Compact Hybrid Particle Collector
Carbonyl Sulfide
Chromium
Convective Syngas Cooler
Cold Side Electrostatic Precipitator
Dry Ash Free
Department of Energy
Energy and Material
Energy Information Administration
Electric Power Research Institute
Electrostatic Precipitator
Fabric Filter
Flue Gas Desulfurization
General Electric
Giga tons of CO2
Hydrogen
Water
Hydrogen Sulfide
Sulfuric Acid
Hydrochloric Acid
Hydrofluoric Acid
Mercury
Higher Heating Value
Heat Recovery Steam Generator
Hot Side Electrostatic Precipitator
Installed Cost
Interest during Construction
Integrated Gasification Combined Cycle
Kilowatt
Pounds per Million British Thermal Units
Pounds per Megawatt Hour
IX
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Ib/TBtu Pounds per Trillion British Thermal Units
LHV Lower Heating Value
MDEA Methyldiethanolamine
MMBtu/hr Million British Thermal Units per Hour
MMBtu/lb Million British Thermal Units per Pound
Mn Manganese
MW Megawatts (Electric)
N2 Nitrogen
n/a Not Applicable
NH3 Ammonia
Ni Nickel
NO2 Nitrogen Dioxide
NOX Nitrogen Oxides
O2 Oxygen
O&M Operating and Maintenance
PAC Powdered Activated Carbon
Pb Lead
PC Pulverized Coal
PM Particulate Matter
ppmvd Parts Per Million By Volume Dry
PS Particulate Scrubber
psia Pounds Per Square Inch Absolute
psig Pounds Per Square Inch Gauge
RSC Radiant Syngas Cooler
SCOT Shell Claus Off-Gas Treatment
SCR Selective Catalytic Reduction
SCS Separate, Capture, and Sequester
SDA Spray Dryer Absorber
Se Selenium
Si Silica
SO2 Sulfur Dioxide
SO3 Sulfur Trioxide
TCC Total Constructed Cost
t/MWh Tons per Megawatt Hour
TPC Total Plant Cost
TRS Total Reduced Sulfur
V Vanadium
VOC Volatile Organic Compounds
WL-FGD Wet Limestone Flue Gas Desulfurization
$/kW Dollars per Kilowatt
$/kWh Dollars per Kilowatt Hour
$-kW-yr Dollars per Kilowatt Year
$/MMBtu Dollars per Million British Thermal Units
$/MWh Dollars per Megawatt Hour
$/ton Dollars per Ton
x
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Executive Summary
This report compares the environmental impacts and costs of integrated gasification
combined cycle (IGCC) and pulverized coal (PC) fired power generation plants. The
fuels and feedstocks for each type of plant studied include bituminous, subbituminous,
and lignite coals. The PC plant configurations include subcritical, supercritical, and
ultra-supercritical boiler designs. A coal-water slurry feed type of gasifier (typified by
the Texaco, now GE Energy technology) is selected for the bituminous and
subbituminous feedstocks. A solid feed gasifier (such as the Shell technology) is used
with lignite. The technology options included in the IGCC and PC plant designs are
restricted to those that are projected by the authors to be commercially applied by 2010.
The power generation technologies and emission control systems examined in this report
continue to evolve in response to changes in market considerations and regulatory
requirements. The report is a snapshot of conditions in the changing industry as of
February 2006. Additional information on IGCC power plants proposed for development
can be found at http://www.netl.doe.gov/coal/refshelf/ncp.pdf (accessed on June 21,
2006), which shows 24 proposed coal-fired power plants using gasification technology.
The report contents are intended to serve as a broad screening tool consistent with the
scope of work and project criteria established with EPA. Plant and site specific
assessments will require more detailed engineering studies prior to technical or economic
decision making. Individual facility permitting requirements will depend on the
applicable regulations and the record before the permitting authority.
Introduction
IGCC and PC fired boilers are the primary competing technologies for coal-based power
generation. Fluidized bed combustion is another technology that may have a significant
role in the industry.
Development and implementation of the IGCC technology is relatively immature
compared with the PC technology that has hundreds or thousands of units in operation
globally. While there are a number of gasification units installed at petroleum and
chemical plants, there are only a few installations using coal to make electric power as
the primary product.1 Most of these IGCC installations were installed with government
subsidies and have experienced technical and commercial problems common to the
startup of new technologies. While many of the problems with operability and
maintainability have been mitigated, successful application of the IGCC technology at
additional commercial installations is needed to address any remaining concerns.
Relatively little research or commercial work has been done to investigate gasification of
low rank coals, including subbituminous and lignite, for electric generation purposes.
The existing IGCC plants use bituminous coals as feedstocks. Almost four million tons
of subbituminous coal was gasified at the Louisiana Gasification Technology Inc. facility
located at Dow's Plaquemine, Louisiana chemical plant under a Synfuels Corporation
1 Gasification Technologies Council World Gasification Survey Database. GTC website
http://www.gasification.org/. accessed on February 21, 2006.
ES-1
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Executive Summary
Contract from 1987 to 1995. However, without additional research or commercial
experience with the gasification of low rank coals, it is difficult to compare the
gasification technology development with low rank coals to that of bituminous coal.
The ultra-supercritical PC technology used in this study has a few operating installations
in Japan and Europe. Thermal performance of plants using this technology may match or
exceed IGCC performance. However, this technology has no commercial experience in
the U.S. Therefore, for application in this country, the technology is considered
unproven with potential technical and economic risks.
Advanced technologies are also being developed to improve the IGCC performance: new
technologies for air separation and oxygen production, higher temperature gas cleaning
methods, advanced gas turbines, and fuel cells. These technologies are being developed
with the goal of raising thermal efficiency (higher heating value) to 50 - 60 percent.
However, these advances are not likely to be accomplished in the 2010 timeframe for this
study.
Power Generation Performance Comparison
Exhibit ES-1 summarizes the results of the performance estimates for the IGCC and PC
plants. The IGCC plant performance in particular can vary depending on design and site
specific factors, and the estimates for IGCC plants using subbituminous and lignite coals
are based on process models which were developed with limited test or other actual data.
The ultra-supercritical plant performance is also estimated from modeling calculations
and values found in the literature.
Based on the data presented in Exhibit ES-1, the IGCC has significantly better thermal
performance than the subcritical and supercritical PC plants in commercial applications
within the U.S. The estimates developed from limited data on ultra-supercritical
technology show its thermal performance to exceed that of the IGCC for bituminous and
sub-bituminous coal cases.
Environmental Impact Comparison
With the exception of controls for CC>2, the control systems included in this report for
reducing emissions of air pollutants from IGCC plants have been demonstrated at the two
existing coal- and petroleum coke-based U.S. plants, and very similar systems are
broadly used within the petroleum and chemical industries. The one remaining
uncertainty appears to be the long-term, continuous operational proof for the generation
industry that the emission control processes/equipment will work in the IGCC power
generation context. Such proof would involve the use of coal, which has physical and
chemical properties that tend to be much more heterogenic than refinery feedstocks, and
the individual plant's capability to generate baseload power without significant planned
or unplanned interruptions. Partly this uncertainty is related to the more general lack of
information about IGCC system upsets, reliability, and a well-engineered definition of
redundancy requirements.
ES-2
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Executive Summary
Compared with the PC plants, the IGCC more closely resembles a chemical plant than
one for power generation. However, the power industry has incorporated and learned to
use chemical processes for flue gas desulfurization, ammonia-based selective catalytic
NOx reduction processes, and a variety of water treatment and cleanup operations, so
operation of an IGCC plant by the power industry is possible.
Based on the investigations conducted for this study, the IGCC technology can offer
environmental advantages over the PC technologies in most emission areas. In addition
to the reduced air emissions from the IGCC technology, the plants typically consume
significantly less water and generate less solid waste in comparison to the PC technology,
depending on coal properties and whether or not the solid waste streams are sold as
industrial byproducts.
Exhibit ES-2 presents environmental impact estimates for the specific control
technologies and coals utilized for various study cases. The estimates are based on
literature review, including recent air permits and related documents, contacts with
certain potential suppliers of the control technologies, and power generation modeling
software. In general, the estimates represent typical control technology capabilities,
which, in many cases, reflect the levels determined through best available control
technology reviews conducted during the processing of air permits for recent power
plants. In some cases, such as the subbituminous coal- and lignite-based IGCC plants,
relevant air permit or operating data were not available. For these plants, information
from other study sources, including vendor contacts, were used to develop the emission
estimates.
The emissions and (in parallel) the removal capabilities are similar across the
technologies and coals with the clearest distinction being that IGCC emissions are less
than for PC plants for all pollutants. The IGCC cases studied do not include SCR for the
syngas turbines. MDEA amine type acid gas cleaning is used along with a system for
sulfur recovery. The PC plants have wet limestone flue gas desulfurization (WL-FGD)
for the bituminous and lignite coals; a lime spray dryer absorber (SDA) desulfurization
for the low-sulfur subbituminous coal; and all the PC plants have selective catalytic
reduction (SCR) post-combustion NOX controls.
The coal characteristics and types of control technologies used for the study plants
influence the estimates in Exhibit ES-2. Changes in design assumptions can result in
different estimates. In addition, new developments continue to take place for both the PC
and IGCC technologies. Therefore, the data presented in this report are subject to change
in the future.
The Exhibit ES-2 data also show the IGCC plants generating less solid waste than the PC
plants. This comparison assumes that no waste is sold for industrial use, except for the
relatively small amount of sulfur produced from IGCC. IGCC plants can also produce
sulfuric acid as an alternative to sulfur, should the market conditions require this change.
ES-3
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Executive Summary
All solid waste products from both PC and IGCC plants have varying degrees of potential
for industrial use. Therefore, if it is assumed that these plants can sell some or all of their
solid wastes, the differences between the amounts of solid waste generated as shown in
Exhibit ES-2 would either reduce or be eliminated. The study investigations show that
while approximately 24 percent of the PC plants were able to sell the gypsum produced
from the wet FGD systems in 2004, only five percent were able to do so for the SC>2
wastes from the SDA systems. So, even though the industrial use of PC solid wastes is
projected to increase in the future, it appears that a large number of such plants may not
be able to sell their wastes. If an IGCC plant cannot sell its sulfur byproduct, it would
have to be disposed of as a waste.
The study investigations included a comparison of major non-criteria and hazardous air
pollutant emissions for the PC and IGCC technologies. In most cases, these emissions
are heavily influenced by the concentration of impurities in the coal being used.
Therefore, emissions of certain pollutants can vary over a wide range, depending on the
coal characteristics. The estimates of the emissions of non-criteria and hazardous air
pollutants are presented within the report in Exhibits 3-10, 3-11, 3-13, 3-14, 3-15, and 3-
26.
Industry and government organizations have recently begun considering the application
of the SCR technology to reduce NOX from syngas-fired turbines at IGCC plants.
Section 4 includes a topical study of the issue. Industry is reluctant to install SCR units
because of impacts on the overall operation, performance uncertainties and marginal cost.
The study estimated a cost of $7,290 to $13,120 per ton of NOx removed based on the
difference between 15 parts per million by volume, dry basis (ppmvd) emissions with
syngas dilution combustion controls, and three ppmvd after the SCR is added. The wide
range of cost estimates results from uncertainty for the degree of sulfur control
installation required to operate the catalytic NOx control technology.
The use of a SCR with the coal-based IGCC synthesis gas-fired turbine combined cycle
system has no commercial operating experience and is still evolving, which makes the
evaluation difficult and necessarily limited to the present level of understanding and
criteria defined for the study. SCR performance and the quality of the synthesis gas
going to the turbine are issues that are being continually examined to determine the limits
of contaminants in the synthesis gas, especially sulfur, which causes fouling in the
downstream heat recovery steam generator. The technology to remove sulfur from the
synthesis gas and the removal requirement strongly impacts costs and introduces the
major uncertainty about cost estimates. A second major economic uncertainty is the SCR
catalyst life and replacement costs over time.
Also, the SCR operation uses ammonia as the means to reduce NOX emissions, and
depending on how the SCR is operated some ammonia will be released (termed
"ammonia slip") to the atmosphere and is a pollutant. The methods to balance NOx
reduction and ammonia slip in the presence of sulfur in the flue gas and thus minimize
total emission impacts are not yet well defined for the IGCC technologies. Despite the
present uncertainties, and perhaps as an indicator of future installations, it is noted that
ES-4
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Executive Summary
the "reference" IGCC plant being engineered by GE Energy and Bechtel Corporation
includes SCR2. In addition, certain recently filed or amended IGCC permit applications
propose use of SCR technology. These applications are not covered in the report, since
the information on the applications became available after the study investigations were
completed.
Cosf and Availability Comparisons
Cost and availability are issues of uncertainty for the IGCC technology. Even given
higher thermal efficiency and lower emissions, the cost and availability differences
between IGCC and PC plants continue to be a major hurdle to commercial applications.
While the differences in cost estimates for new plants reported by several sources are not
that great, less than $100 per kilowatt in some cases, the actual cost disparities for IGCC
demonstration facilities have been much greater. The IGCC estimates presented here are
for plants that assume commercial performance, and unfortunately the cost for the first
generation of plants is bound to be more than for the "Nth plant". Similarly, the
availability of the currently operating IGCC plants has been around 80 percent (higher
availability levels were achieved only by operating the combined cycle portion of the
plant on natural gas or oil). These plants were designed with single-gasifier trains and it
is expected that the future commercial facilities, designed with a spare gasifier train,
would achieve availability levels of 85 percent and higher. In comparison, the subcritical
and supercritical PC can generally achieve greater than 90 percent availability levels.
Capital and annual operating costs estimated for the plants are shown in Exhibit ES-3.
While the capital costs for IGCC plants are higher than the costs for all three PC plant
configurations, there are only small differences between the operating costs for all plants.
Further cost details and discussion of the estimating basis and methodology are in
Appendix A. The risk and uncertainty issues noted for the technologies' performance
estimates apply equally to the cost estimates. Only limited information is available from
operating plants showing the impact of coal quality on the IGCC and PC generation
technologies. Even conceptual engineering work is much less available for IGCC plants
using low rank coals than for the plants using bituminous coal.
The costs reported here are derived from recent literature and experience with similar PC
and IGCC studies conducted by Nexant. References for the cost data are noted in
Appendix A of the report. New, study-specific cost estimates were not within the scope
of the current EPA/DOE assessment, which is focused on environmental impacts of the
modeled operations. As a general statement, the cost data is from U.S. DOE, the Electric
Power Research Institute (EPRI), and international publications. These costs were
examined and revised to reflect a 4th Quarter 2004 price and wage level and the nominal
plant capacity of 500 MW.
Accounting for the variability in the overall scope of each plant using different
technologies and three ranks of coal adds another element of cost (and performance)
uncertainty. The results presented in the report again utilize the review and adjustment of
2 Gas Turbine World, Sept - Oct 2005 Volume 35 Number 4; "IGCC Closing the $/kW Cost Gap".
ES-5
-------
Executive Summary
several data sources to estimate the costs associated with these variables. If the cost
uncertainty is to be reduced, a more detailed engineering and design project would be
required with site- and technology-specific criteria.
Carbon Dioxide Capture and Sequestration
The IGCC technology has received renewed attention from the perspective of greenhouse
gas issues and carbon management. Section 5 contains a more detailed discussion of
carbon management technologies. Applications of such technologies exist in industries
other than power sector. A significant amount of research and development work is
being done to address the technical and economic feasibility issues pertaining to the
commercial application of these and other emerging technologies to IGCC and PC plants.
Demonstration of the feasibility of permanently sequestering CC>2 in underground
geological formations is part of these efforts.
The currently available carbon management technologies for IGCC are much more cost
effective than similar technologies for removing CC>2 from PC plant flue gases. The
major performance and economic impacts of applying these technologies to IGCC and
supercritical PC plants for achieving approximately 90 percent CC>2 capture are reported
as follows:
IGCC Supercritical PC
Net plant output (pre CO2 capture), MW 425 462
Plant output derating, % 14 29
Heat rate increase, % 17 40
Total capital cost increase, % 47 73
Cost of electricity increase, % 38 66
CO2 capture cost, $/ton 24 35
The above comparison highlights the potential advantage for IGCC to capture and
sequester CO2 at significantly lower costs than PC technologies.
Future Actions
Improvement of the knowledge database for PC and IGCC technologies, especially for a
complete range of North American coals, will require substantially more detailed process
engineering and coordination with the technology developers. The limited contacts with
technology developers for this study confirmed their willingness to work with industry
and government, but they were not prepared to provide detailed information without a
complete design basis from which to work, and in some cases this work would have to be
compensated.
ES-6
-------
Executive Summary
Exhibit ES-1, Generation Performance Comparison
Performance
Net Thermal Efficiency, %
(HHV)
Net Heat Rate, Btu/kWh (HHV)
Gross Power, MW
Internal Power, MW
Fuel Required, Ib/h
Net Power, MW
Performance
Net Thermal Efficiency, %
(HHV)
Net Heat Rate, Btu/kWh (HHV)
Gross Power, MW
Internal Power, MW
Fuel Required, Ib/h
Net Power, MW
Bituminous Coal
IGCC Slurry
Feed
Gasifier
41.8
8,167
564
64
349,744
500
Sub-
critical
PC
35.9
9,500
540
40
407,143
500
Super-
critical PC
38.3
8,900
540
40
381,418
500
Ultra
Super-
critical PC
42.7
8,000
543
43
342,863
500
Lignite Coal
IGCC Solid
Feed
Gasifier
39.2
8,707
580
80
689,720
500
Sub-
critical
PC
33.1
10,300
544
44
815,906
500
Super-
critical PC
35.9
9,500
544
44
752,535
500
Ultra
Super-
critical PC
37.6
9,065
546
46
720,849
500
Subbituminous Coal
IGCC „ , „ Ultra
C1 y, , Sub- Super- „
S1^.fFeed critical PC critical PC Stup(;<>
Gasifier cntical PC
40.0 34.8 37.9 41.9
8,520 9,800 9,000 8,146
575 541 541 543
75 41 41 43
484,089 556,818 517045 460,227
500 500 500 500
ES-7
-------
Executive Summary
Exhibit ES-2, Environmental Impact Comparison
Environmental Impact
Ib/MWh
NOX (NO2)
SO2
CO
Particulate Matter1
Volatile Organic Compounds (VOC)
Solid Waste3
Raw Water Use
SO2 Removal Basis, %
NOX Removal Basis2
Bituminous Coal
IGCC
Slurry Feed
Gasifier
0.355
0.311
0.217
0.051
0.012
65
4,960
99
15 ppmvd
at 15% O2
Sub-
Critical PC
0.528
0.757
0.880
0.106
0.021
176
9,260
98
0.06
Ib/MMBtu
Super-
critical PC
0.494
0.709
0.824
0.099
0.020
165
8,640
98
0.06
Ib/MMBtu
Ultra
Super-
critical PC
0.442
0.634
0.737
0.088
0.018
155
7,730
98
0.06
Ib/MMBtu
Subbituminous Coal
IGCC
Slurry Feed
Gasifier
0.326
0.089
0.222
0.052
0.013
45
5,010
97.5
15 ppmvd
at 15% O2
Sub-
critical PC
0.543
0.589
0.906
0.109
0.025
73
9,520
874
0.06
Ib/MMBtu
Super-
critical PC
0.500
0.541
0.832
0.100
0.023
67
8,830
874
0.06
Ib/MMBtu
Ultra
Super-
critical PC
0.450
0.488
0.750
0.090
0.020
60
7,870
874
0.06
Ib/MMBtu
NOTES:
1. Particulate removal is 99.9% or greater for the IGCC cases and 99.8% for bituminous coal, 99.7% for subbituminous, and 99.9% for
lignite for the PC cases. Particulate matter emission rates shown include the overall filterable particulate matter only.
2. A percent removal for NOX can not be calculated without a basis, i.e. an uncontrolled unit, for the comparison. Also, the PC and IGCC
technologies use multiple technologies (e.g., combustion controls, SCR). The NOX emission comparisons are based on emission levels
expressed in ppmvd at!5% oxygen for IGCC and Ib/MMBtu for PC cases.
3. Solid Waste includes slag (not the sulfur product) from the gasifier and coal ash plus the gypsum or lime wastes from the PC system.
4. A relatively low SO2 removal efficiency of 87% represents low subbituminous coal sulfur content of only 0.22%. Higher removal
efficiencies are possible with increased coal sulfur content.
ES-8
-------
Executive Summary
Exhibit ES-2, Environmental Impact Comparison, continued
Environmental Impact
Ib/MWh
NOX (NO2)
SO2
CO
Participate Matter1
Volatile Organic Compounds (VOC)
Solid Waste3
Raw Water Use
SO2 Removal Basis, %
NOX Removal Basis2
Lignite Coal
IGCC
Solid Feed
Gasifier
0.375
0.150
0.225
0.053
0.013
218
5,270
99
15 ppmvd
at!5%O2
Sub-
Critical PC
0.568
0.814
0.947
0.114
0.026
331
9,960
95. 84
0.06
Ib/MMBtu
Super-
critical PC
0.524
0.751
0.873
0.105
0.024
306
9,200
95. 84
0.06
Ib/MMBtu
Ultra
Super-
critical PC
0.498
0.714
0.830
0.100
0.022
291
8,710
95. 84
0.06
Ib/MMBtu
NOTES:
1. Particulate removal is 99.9% or greater for the IGCC cases and 99.8% for bituminous coal, 99.7% for subbituminous, and 99.9% for
lignite for the PC cases. The emission rates shown include the overall filterable particulate matter only.
2. A percent removal for NOX can not be calculated without a basis, i.e. an uncontrolled unit, for the comparison. Also, the PC and IGCC
technologies use multiple technologies (e.g., combustion controls, SCR). The NOX emission comparisons are based on emission levels
expressed in ppmvd at!5% oxygen for IGCC and Ib/MMBtu for PC cases.
3. Solid Waste includes slag (not the sulfur product) from the gasifier and coal ash plus the gypsum or lime wastes from the PC system.
4. A relatively low SO2 removal efficiency of 95.8% represents low lignite sulfur content of only 0.64%. Higher removal efficiencies are
possible with increased coal sulfur content.
ES-9
-------
Executive Summary
Exhibit ES-3, Technology Cost Comparison
Costs*
Total Plant Cost $/ kW
Total Plant Investment
$/kW
Total Capital Requirement
$/kW
Annual Operating Cost
$l,OOOs
Costs*
Total Plant Cost $/ kW
Total Plant Investment
$/kW
Total Capital Requirement
$/kW
Annual Operating Cost
$l,OOOs
Bituminous Coal
IGCC
Slurry Feed
Gasifier
1,430
1,610
1,670
27,310
Sub-
critical PC
1,187
1,303
1,347
27,700
Super-
critical PC
1,261
1,384
1,431
29,000
Ultra
Super-
critical PC
1,355
1,482
1,529
30,400
Lignite Coal
IGCC
Solid Feed
Gasifier
2,000
2,260
2,350
34,000
Sub-
critical PC
1,255
1,378
1,424
29,640
Super-
critical PC
1,333
1,463
1,511
30,940
Ultra
Super-
critical PC
1,432
1,566
1,617
32,440
Subbituminous Coal
IGCC „ , „ Ultra
C1 y, , Sub- Super- „
S1^.fFeed critical PC critical PC Stup(;<>
Gasifier cntical PC
1,630 1,223 1,299 1,395
1,840 1,343 1,426 1,526
1,910 1,387 1,473 1,575
29,700 28,300 29,600 31,100
th
* All costs are based on 4 Quarter 2004 dollars.
ES-10
-------
Section 1 Process Design
Section 1 presents the design criteria and methodologies used in evaluating various
processes and technologies discussed in this report.
1.1 Introduction
The U.S. Environmental Protection Agency (EPA) sponsored this study to evaluate and
compare environmental impacts and costs of integrated gasification combined cycle
(IGCC) and pulverized coal (PC) power plants. These estimated impacts and costs for
the technologies will assist various government agencies to better understand the
potential effects of rulemaking and regulatory actions on application of the technologies
in practical, real-world conditions.
Results are based upon information collected in one of two ways. First, in-house Nexant
software, experience with similar evaluations, and literature were used to estimate
performance and costs of the two technologies. Second, equipment and process suppliers
were contacted for updated information specific to the environmental control aspects of
the plants. The suppliers' data were used to refine the first estimates and improve the
performance and cost estimates of the environmental controls. Seeking new data from
gasification technology developers was not within the scope of this report; it was judged
that sufficient published and in-house data was available to assess gasification technology
performance and cost.
1.2 Design Basis
The study examines five power generation technologies and three different coals. All the
modeled power plants are sized for a net power generation of 500 MW. They are
configured with equipment and processes that are judged available for deployment in
power generation plants in the 2010 time period. The modeled plants include the
following design features:
• IGCC plants with steam conditions of 1,800 psig and 1,000/1,000 °F. The coal-water
slurry feed type of gasifier represented by GE Energy (ex-ChevronTexaco) is used
with two coals, and a solid feed gasifier such as Shell gasification is used with lignite.
• PC plants with subcritical steam conditions of 2,400 psig and 1,000/1,000°F single
reheat.
• PC plants with supercritical steam conditions of 3,500 psig and 1,050/1,050 °F double
reheat.
• PC plants with ultra-supercritical steam conditions of 4,500 psig and 1,100/1,100 °F
double reheat.
1-1
-------
Section 1
Process Design
• Ambient conditions are 60 °F dry bulb, 60% relative humidity, and sea level
elevation. Heat rejection uses wet cooling tower technology.
Three coals were chosen by EPA for the study. The coal characteristics and ash mineral
properties are shown in Exhibits 1-la, 1-lb, and 1-2.
Exhibit 1-la, Study Coal Proximate Analyses
Coal Property
Proximate Analysis,
Weight %
Moisture
Ash
Volatile matter
Fixed carbon
Total
High-Sulfur
Bituminous
11.12
9.70
34.99
44.19
100.00
Low-Sulfur
Subbituminous
27.40
4.50
31.40
36.70
100.00
Lignite
31.24
17.92
28.08
22.76
100.00
Exhibit 1-lb, Study Coal Ultimate Analyses
Coal Property, Ultimate
Analysis, Weight%
Carbon
Hydrogen
Nitrogen
Oxygen
Sulfur
Ash
Moisture
Undetermined
Total
Higher heating value (HHV),
Btu/lb
HHV, KJ/kg
High-Sulfur
Bituminous
As
Received
63.74
4.50
1.25
6.89
2.51
9.70
11.12
0.29
100.00
11,667
27,137
Dry
Basis
71.71
5.06
1.41
7.75
2.82
11.24
100.00
Low-Sulfur
Subbituminous
As
Received
50.25
3.41
0.65
13.55
0.22
4.50
27.40
0.02
100.00
8,800
20,469
Dry
Basis
69.21
4.70
0.90
18.66
0.30
6.23
100.00
Lignite
As
Received
36.27
2.42
0.71
10.76
0.64
17.92
31.24
0.04
100.00
6,312
14,682
Dry
Basis
52.75
3.52
1.03
15.65
0.93
26.12
100.00
Note: Dry Basis - calculated. Undetermined added to ash.
1-2
-------
Section 1
Process Design
Exhibit 1-2, Mineral Analysis Data
Mineral Analysis, Weight %
Silica
Ferric oxide
Alumina
Titania
Lime
Magnesia
Sulfur trioxide
Potassium oxide
Sodium oxide
Phosphorus pentoxide
Undetermined
Total
High- Sulfur
Bituminous
43.95
22.79
20.89
1.00
4.05
0.79
2.87
1.97
1.15
0.12
0.42
100.00
Low-Sulfur
Subbituminous
33.40
5.20
16.30
1.20
21.50
6.40
11.70
0.35
1.90
1.20
0.85
100.00
Lignite
56.96
3.49
19.01
1.25
8.39
1.88
5.49
0.74
0.36
0.05
2.38
100.00
The PC power plants are evaluated with each of the coals. The IGCC plants are similarly
evaluated except the type of gasifier is dependent on the type of coal used.
The EPA design basis also specifies the criteria and non-criteria pollutants considered in
the environmental assessment. The items are shown in Exhibit 1-3.
1-2
-------
Section 1
Process Design
Exhibit 1-3, EPA Criteria and Non-Criteria/Hazardous Pollutants
Criteria Air Pollutants
Non-Criteria/Hazardous Air Pollutants
Nitrogen Oxides (NOX)
Sulfur Dioxide (SO2)
Carbon Monoxide (CO)
Particulate Matter (PM10)
Fine Particulate Matter
(PM25)
Lead (Pb)
Mercury (Hg)
Volatile Organic Compounds (VOC)
Chlorides (HC1)
Fluorides (HF)
Sulfur Trioxide (SO3)
Hydrogen Sulfide (H2S)
Sulfuric acid
Ammonia (NH3)
Arsenic (As)
Beryllium (Be)
Manganese (Mn)
Cadmium (Cd)
Chromium (Cr)
Formaldehyde
Nickel (Ni)
Silica (Si)
Selenium (Se)
Vanadium (V)
Total Reduced Sulfur (TRS)
Reduced sulfur compounds
1-4
-------
Section 2
Process Description
Section 2 describes the major processes and components of various IGCC and PC plant
configurations included in this report.
2.1 Process Description
The PC and IGCC plants used for the study are relatively "conventional" plants. With
the exception of the ultra-supercritical PC technology, the equipment is commercial or
near-commercial. (Ultra supercritical technology with conditions similar to the study
criteria is deployed in Japan and Europe to a limited extent. Major manufacturers are
working to develop the technology for use in the U.S. Research is being pursued to
increase the temperature beyond 1,100 °F.) While the focus of the study is the
environmental performance of the plants, a brief description of the plants is provided to
illustrate the overall plant configuration. In general, Sections 2 and 3 of the study
describe technologies that can be commercially deployed. Sections 4 and 5 describe
technologies that can still potentially be deployed but have no direct commercial
experience with the power generation technologies considered in this study. Exhibit 2-1
lists major features of each type of plant with emphasis on their differences.
Exhibit 2-1, Summary of Plant Design Features
Plant Features
Pulverized Coal Plants
Gasification Combined Cycle Plants
Generation All coals, boiler and steam
Method turbine cycle.
A. Bituminous and subbituminous coals,
coal slurry feed gasifier combined cycle.
B. Lignite coal, solid feed gasifier
combined cycle.
Particulate
Control
All coals, fabric filter baghouse.
All coals, high temperature metal filters.
(The wet processing of the gas cleaning
process adds to particulate removal
downstream of the filters.)
NOX Control
Combustion controls & SCR.
All coals, combustion controls with
nitrogen dilution.
2-1
-------
Section 2
Process Description
Plant Features
Pulverized Coal Plants
Gasification Combined Cycle Plants
SO2 Control
A. Bituminous and lignite
coals, wet limestone flue gas
desulfurization and
production of gypsum.
B. Subbituminous coal, lime
spray dryer desulfurization
followed by fabric filter
baghouse and production of
solid waste containing SC>2
reaction products and ash
All coals, methyldiethanolamine
(MDEA) gas cleaning and production of
elemental sulfur.
In addition to the controls listed in Exhibit 2-1, the PC plants firing bituminous coal and
lignite are equipped with a wet electrostatic precipitator (ESP) for controlling emissions
of sulfuric acid mist. The cobenefits of a wet ESP may also include removal of other
pollutants, such as particulate matter and mercury. The emissions and generation
performance estimates presented for PC and IGCC plants are for "normal" operating
conditions. All the plants will require a startup operation, often using oil or natural gas
and generating emissions different from baseload design operations. Conditions may also
change during shutdown operations and certainly during unplanned operating upsets
where the plant or components may need to be shutdown or operated off-design without
notice. Emissions from off-design operations are not addressed in this report. In
addition, only the air emissions associated with the exhaust from the main stack are
addressed for each plant. Other sources of air emissions, such as from an auxiliary boiler
or IGCC flare, have not been reported, since they are considered to be minor in
comparison to the main stack emissions.
2.1.1 IGCC Plants
The IGCC power plant processes are summarized in this section; more detailed
descriptions of the environmental control systems are presented later. Exhibit 2-2
illustrates the nominal 500 MW IGCC plant. The material and energy balance tables
related to the numbered major flow streams are presented in Appendix C. As noted with
the balance tables, the calculations are derived from Nexant's spreadsheet power plant
model, and are used primarily to estimate plant performance across the technologies and
three coal ranks. The emission results may not be exactly the same as provided in other
parts of the report due to rounding, calculation differences and the use of other sources,
mainly air permit data, to define the emissions.
2-2
-------
Section 2
Process Description
Exhibit 2-2, Integrated Gasification Combined Cycle Block Diagram
Coal Receiving Storage
and Reclaiming
Coal Feed
To
Air Separation Plant
I
Steam Turbine
Generator
Nitrogen for
GTNOX
Dilution
Coal Feed Preparation
Gasification
Gasification Slag
Solid Waste
I
Syngas Cooling and
Acid Gas Removal
1
¥
I
Net Power
Production
•>T >~
Steam Cycle
Energy Input
Heat Recovery Steam
Generator
-------
Section 2 Process Description
the basis for performance estimates. As will be discussed later, the IGCC environmental
control areas were evaluated by contacting potential suppliers for those components.
The performance levels reported in this study for various IGCC plant configurations are
based on current technologies. Based on ongoing research and development activities, a
potential exists for considerable improvements in the IGCC performance levels. The
goals of these activities are to achieve overall plant thermal efficiency levels of 45 to 50
percent by 2010 and 50 to 60 percent by 20204.
In gasification's simplest form, coal is heated and partially oxidized with oxygen and
steam and the resulting synthesis gas, or syngas (primarily hydrogen and carbon
monoxide), is cooled, cleaned and fired in a gas turbine-generator. Oxygen for the
gasifier is produced in an air separation plant. The gas turbine exhaust goes to a heat
recovery steam generator (HRSG), producing steam that is sent to a steam turbine-
generator. Power is produced from both the turbine-generators. It is generally accepted
that the IGCC system, by removing most pollutants from the syngas prior to combustion,
is capable of meeting more stringent emission standards than PC technologies. It is also
generally accepted that IGCC costs are higher and more uncertain than for PC plants,
because PC technology has been demonstrated at many more installations. At present,
the IGCC system also has greater promise to incorporate CO2 capture for sequestration
without large cost and energy penalties.
There are many variations on the basic IGCC scheme, especially in the degree of process
integration. Three major types of gasification systems are used today: moving bed;
fluidized bed; and entrained flow. The figure from EPRI in Exhibit 2-3 shows major
characteristics of the three gasifiers.5
In a moving-bed gasifier, a bed of crushed coal is supported by a grate and the reactions
between coal, oxygen, and steam take place within this bed. The gasifier operates at
temperatures below the ash slagging temperature.
Fluidized-bed gasifiers also have a discrete bed of crushed coal. However, the coal
particles are kept in a constant motion by the upward gas flow. The fluidized bed is
maintained below the ash fusion temperature.
In entrained-flow gasifiers, finely pulverized coal particles concurrently react with steam
and oxygen with very short residence time. These gasifiers operate at high temperature
where the coal ash becomes a liquid slag. These units form the majority of IGCC project
applications and include the coal/water-slurry-fed processes of GE Energy and
ConocoPhillips, and the dry-coal-fed Shell process. A major advantage of the high-
4 H. Morehead, et al,"Improving IGCC Flexibility through Gas Turbine Enhancement," Gasification
Technologies Conference, October 4-5, 2004, Washington, DC.
5 Neville Holt, "Gasification Process Selection - Trade-offs and Ironies", Gasification Technologies
Conference, October 4-55, 2004, Washington, DC.
2-4
-------
Section 2
Process Description
Exhibit 2-3, Major Gasification System Types
Co-ai
I
Oxygen
or A,;r
Ccal
team.,
Enlrained-Ftew j
Gasifier
Gaafie-
Bottom
Gasifisr
Top
0 2 SO 500 750 'OOC 12SC ISCC
Temperance - '"€
Seam
or AT. » _ _ .
Bottom r<
JL_L2±1L J
250 500 750 ' 000 ' 25^ 1503
Ternoe*atufe - >;C
— * P— OK y fen
f 4 or AT C.as!f«f
^-^'f-^ Tec-
. ';
ws Od f3
^ ' r^ G*ifW
1 ir i t i t
Oxygen 1
e*" Air |
1
1
1
1
i
1
1
Gas1
1 1 i 1 if
1
SI;
r i
0 250 500 750 1300 1250 1500
Temperature - "C
2-5
-------
Section 2 Process Description
temperature entrained-flow gasifiers is that they avoid tar formation and its related
problems.
Another variation in gasifier design involves use of air, instead of oxygen, to accomplish
partial oxidation of fuel in a gasifier. This design eliminates the need for using an
expensive air separator required for oxygen-blown gasifiers. The syngas produced from
an air-blown gasifier has a lower calorific value, compared to the syngas produced from
an oxygen-blown gasifier. Research and development work done both in the U.S. and
Japan shows certain cost and performance advantages associated with the use of air-
blown gasifiers, especially for low-rank coals. An IGCC demonstration plant, partially
funded by DOE and using an air-blown Transport gasifier design, has recently been
proposed to be built in Florida.6
All of the currently operating IGCC plants utilize oxygen-blown, entrained-flow gasifier
designs. Therefore, this gasifier design is used for the IGCC plants in the present study.
IGCC operations have environmental benefits compared to PC units. Gasification occurs
in a low-oxygen environment and the coal's sulfur converts to hydrogen sulfide (H^S),
instead of SO2 as it does in the PC flue gas. The H2S from gasification can be more easily
captured and removed than the 862 in PC flue gas. Removal rates of 99% and higher for
H2S have been obtained with petrochemical industry cleanup technologies.7
NOX emissions are an issue of special importance in the study of IGCC technology. Due
to high flame temperature, the syngas can generate high NOx emissions in the exhaust.
However, IGCC units can be configured to operate with low NOx emissions by saturating
the syngas with steam or using nitrogen from the oxygen plant to dilute the fuel in the
combustor. The base cases in this study use nitrogen dilution and saturation to control
NOx. A special analysis is presented later in this report, which examines the potential for
including a SCR control device to further decrease the NOx emission. An advantage of
adding extra mass from the water and nitrogen is that additional power is generated in the
gas turbine and steam cycle.
The IGCC concept was first demonstrated at the Cool Water Project in Southern
California from 1984 to 1989. There are currently two commercial-scale, coal-based
IGCC plants in the U.S. and two in Europe. The U.S. projects were supported by the
DOE's Clean Coal Technology demonstration program.
The 262 MW Wabash River IGCC repowering project in Indiana started operations in
6 "Demonstration of a 285-MW Coal-Based Transport Gasifier," Project Facts, May 2005, NETL/DOE
Internet Site, http://www.ncil.doc.gov/piiblications/facishccts/faci toe.html accessed 5/2/2006.
7 Major Environmental Aspects of Gasification-Based Power Generation Technologies. Final Report by:
Jay Ratafia-Brown, Lynn Manfredo, Jeffrey Hoffmann, & Massood Ramezan for National Energy
Technology Laboratory, U.S. Department of Energy, December 2002.
2-6
-------
Section 2 Process Description
1995 and uses the ConocoPhillips E-Gas gasification technology. The 250 MW Polk
Power Station IGCC project in Florida started in 1996 and uses the GE Energy
gasification technology. Both plants have operated on bituminous coals and petroleum
cokes; no use of low-rank coal is known. These plants reported the following emission
data on USDOE/NETL fact sheets8'9
Wabash River
• SO2 capture efficiency greater than 99%, or emissions below 0.1 Ib per million Btu.
An MDEA acid gas removal system is used at Wabash.
• NOX emissions were 25 ppmvd at 15% O2 (0.15 Ib/MMBtu).
• Particulate emissions were below detectable limits. After experimenting with a
ceramic filter, Wabash switched to metallic filters for particulate control. The wet
downstream operations also remove any remaining solids from the syngas.
• CO emissions averaged 0.05 Ib/MMBtu.
Tampa Electric Polk Power Station
• Sulfur removal was over 97%. An amine-based (MDEA + COS conversion) acid gas
removal system is used. Sulfur recovery includes sulfuric acid production.
• NOx emissions were 15 ppmvd at 15% O2 (0.055 Ib/MMBtu). Nitrogen injection is
used to control NOx.
• Particulates were 0.007 Ib/MMBtu. Particulate removal is in a water-wash synthesis
gas scrubber.
• CO emissions averaged 7.2 pounds per hour.
The Wabash River and Polk plants are low emission, coal-based power technologies.
New IGCC technologies are forecast to achieve 99% or more sulfur removal10,
essentially total volatile mercury removal (greater than 90-95% removal11), and
particulate emission levels of less than 0.015 Ib per million Btu12. An IGCC plant will
also produce less solid waste, and will use less total water than a PC plant. These
emission levels of performance are likely to be available in the 2010 timeframe set for the
study, but electric generation market conditions and financial/technical risk make their
implementation by that time uncertain, especially with low-rank coals.
8 U.S. DOE Fact Sheet at Internet Site:
http://www.netl.doe.gov/techiiologies/coalpower/cctc/siininiaries/taiTipa/tanipaedenio.htiiil, accessed
2/28/06.
9 U.S. DOE Fact Sheet at internet Site:
http://www.netl.doe.gov/technologies/coalpower/ccto/sunnna.ries/wabsh/wabasrirdeino.htnil, accessed
2/28/06.
10 Evaluation of Innovative Fossil fuel Power Plants with CO2 Removal. U.S. DOE/NETL and EPRI,
Prepared by ParsonsEnergy and Chemicals Group, December 2000 - updated 2002.
11 Major Environmental Aspects of Gasification-Based Power Generation Technologies. Final Report by:
Jay Ratafia-Brown, Lynn Manfredo, Jeffrey Hoffmann, & Massood Ramezan for National Energy
Technology Laboratory, U.S. Department of Energy, December 2002.
12 R. Brown, et. al., "An Environmental Assessment of IGCC Power Systems," 19th Annual Pittsburgh Coal
Conference, September 2002.
2-7
-------
Section 2 Process Description
For this study, the design basis includes use of two gasifiers for each plant configuration.
This is intended to result in a design that can provide commercially acceptable plant
availability. Based on experience from existing IGCC installations, the plant availability
goals can also be achieved by using a standby fuel, natural gas or oil, for the gas turbines,
in lieu of two gasifiers. The disadvantages to this approach include increased operating
costs due to the use of expensive standby fuels as well as increased NOx emissions from
the gas turbines, which have been designed to handle syngas.
GE Energy Type Coal Slurry Feed Gasification
The coal is crushed and mixed with water to produce pumpable slurry that is 65 to 70 %
coal by weight. Slurry is pumped into the gasifier with oxygen. The gasifier operates in a
pressurized, down-flow, entrained design and gasification proceeds rapidly at
temperatures in excess of 2,300 °F. The raw gas is mainly composed of H2, CO, CO2,
and H2O. The hot syngas leaves the gasifier at the bottom and enters a radiant syngas
cooler (RSC) where it is cooled to about 1,400 °F, and in the process produces high
pressure steam. The molten slag falls to the quench bath at the bottom of the cooler
where it is solidified and removed with a lock hopper system. The syngas from the RSC
is sent to a convective syngas cooler (CSC) for additional steam generation. The cooled
gas is sent to the acid gas removal plant.
Air Separation Plant. A high-pressure cryogenic oxygen plant is used. The air for this
plant is supplied in equal amounts from two sources: a bleed from the gas turbine
compressor exhaust and an air stream supplied directly using a booster compressor. The
gas turbine compressor bleed air preheats a nitrogen recycle stream sent to the gas turbine
for NOx control.
Particulates. Metal candle filters are used to remove ash particulates from the
gasification process. Particulate emission from the IGCC process is usually termed
negligible because the wet scrubbing devices employed with the acid gas cleaning and
other operations remove all the measurable solids. Soot and other fine particulate may be
emitted from auxiliary furnaces or other combustion devices if these are installed, and
these emissions may need to be controlled.
Gas Cooling/Heat Recovery/Hydrolysis/Gas Saturation. The raw fuel gas is cooled in a
series of heat exchangers and sent to acid gas removal. Any hydrogen chloride and
ammonia is assumed to be in the condensate from these heat exchangers, which is then
sent to an ammonia_strip unit for further treatment. A catalytic hydrolyzer converts the
carbonyl sulfide to hydrogen sulfide. Heat recovery is used for generating stripping
steam and boiler feed water heating.
Acid Gas Removal (AGR). The MDEA/Claus/SCOT process is used for acid gas removal
and sulfur recovery. In the MDEA process, the cooled gas enters an absorber where it
comes into_contact with the MDEA solvent. As it moves through the absorber, almost all
of the H2S and some of the CO2 are removed. The solute-rich MDEA exits the absorber
and is heated in a heat exchanger before entering the stripping unit. Acid gases from the
2-8
-------
Section 2 Process Description
top of the stripper are sent to the Claus/SCOT unit for sulfur recovery. The lean MDEA
solvent exits the bottom of the stripper and is cooled through several heat_exchangers. It
is then filtered and sent to a storage tank for the next cycle.
The Claus process occurs in two stages. In the first stage, about one-quarter of the gases
from the MDEA unit are mixed with the recycle acid gases from the SCOT unit and are
burned in the first furnace. The remaining acid gases are added to the second stage
furnace, where the H2S and SO2 react in the presence of a catalyst to form elemental
sulfur. The gas is cooled in a waste heat boiler and then sent through a series of reactors
where more sulfur is formed. The sulfur is condensed and removed between each
reactor. A tail gas stream containing unreacted sulfur, SC>2, H^S, and COS is sent for
processing in the SCOT unit.
Gas Turbine and Steam Cycle. A General Electric F type of gas turbine is partly
integrated with the Air Separation Unit (ASU). From the turbine compressor exhaust, a
bleed stream supplies half of the air needed for the ASU. The remainder of the
compressor discharge air is used to combust the clean fuel gas. The ASU returns a
nitrogen stream to the gas turbine combustor for NOx control.
The steam cycle's major components include a heat recovery steam generator (HRSG),
steam turbine, condenser, steam bleed for gas turbine cooling, recycle water heater,
deaerator, and cooling tower for condenser cooling.
Balance of Plant (BOP). The BOP includes the following major components:
• Piping and Valves
• Ducting and Stack
• Waste Water Treatment
• Accessory Electric Plant
• Instrumentation and Control
• Buildings and Structures
Shell Type Solid Feed Gasification
The gasifier is a dry-feed, pressurized, oxygen-blown, entrained-flow slagging reactor.
The coal is pulverized and dried prior to being fed into the gasifier. Nitrogen is used as
the coal transport gas. Coal, oxygen and steam enter the gasifier through the burners.
Raw fuel gas is produced from high temperature gasification reactions and flows
upwardly with some entrained particulates. The high reactor temperature converts the
remaining ash into a molten slag, which flows down the walls of the gasifier and passes
into a slag quench bath. The fuel gas is quenched at the reactor exit with cooled recycled
fuel gas to avoid sticky solids entering the raw gas cooler. The raw gas cooler further
cools the gas and generates high-pressure steam for the steam cycle. Solids are recovered
in the paniculate filter and recycled back to the reactor.
2-9
-------
Section 2 Process Description
Air Separation Plant (ASU). The ASU is similar to the operation described for the slurry-
feed gasifier.
Particulates. Metal candle filters are used to remove ash particulates from the
gasification process. Particulate emission from the IGCC process is usually termed
negligible because the wet scrubbing devices employed with the acid gas cleaning and
other operations remove all the measurable solids. Soot and other fine particulate may be
emitted from auxiliary furnaces or other combustion devices if these are installed, and
these emissions may need to be controlled.
Gas Cooling Section. The raw fuel gas from the particulate filter enters a gas-cooling
section with several heat exchangers, a catalytic hydrolyzer, and a water scrubber. The
raw fuel gas is cooled and sent to the hydrolyzer, which converts the carbonyl sulfide
(COS) to hydrogen sulfide. The gas stream is further cooled before entering a water
scrubber. Hydrogen chloride and ammonia are assumed to be in the scrubber water
discharge, which is sent to a water treatment unit. About 30% of the cooled fuel gas
stream is recycled to quench the hot raw fuel gas stream exiting the gasifier. The
remaining fuel gas is sent to the cold gas cleanup for sulfur removal. The heat recovered
is used for reheating the cleaned fuel gas and for heating boiler feed water in the steam
cycle.
Cold Gas Cleanup Unit. The MDEA/Claus/SCOT process is used for cold gas cleanup
and sulfur recovery and is similar to the earlier description.
Gas Turbine and Steam Cycle. The gas turbine is an F type machine similar to the
previous case. The steam cycle major components include a heat recovery steam
generator (HRSG), steam turbine, condenser, steam bleed for gas turbine cooling, recycle
water heater, cooling tower, and deaerator.
Balance of Plant. The BOP includes the following major components:
• Piping and Valves
• Ducting and Stack
• Waste Water Treatment
• Accessory Electric Plant
• Instrumentation and Control
• Buildings and Structures
2.1.2 PC Plants
The pulverized coal plants are briefly described in this section. The overall scope for the
PC plants includes the following major systems:
• Solids Material Handling
2-10
-------
Section 2 Process Description
• Steam Generation
• NOX Controls
• Particulate Collection
• Flue Gas Desulfurization, either a wet limestone FGD (WL-FGD) for the bituminous
and lignite coals or a lime spray dry absorber (SDA) for the low-sulfur subbituminous
coal
• Steam Turbine Generator
• Condensate and Feedwater Systems
• Balance of Plant
Simple block diagrams of the PC plants are shown as Exhibit 2-4 for plants firing the
three coals. The major difference between plants is the type of flue gas desulfurization.
Material and energy balance tables related to the block diagram stream numbers are
presented in Appendix C. The environmental controls and performance are examined in
more detail later. While not shown in the block diagrams, the PC plants firing
bituminous coal and lignite are to be equipped with wet ESP units to enhance removal of
acid mist.
Subcritical PC Plant
Solid Materials Handling. Solids handling includes receiving, conveying, storing and
reclaiming coal, limestone or lime and the removal and disposal of coal ash and SCh
reaction products. While there could be significant design differences between the three
types of coals, the overall impact on generation and environmental performance would be
small. For example, the lignite fuel is very likely to be used at a mine-mouth power plant
and delivered by truck or conveyor. The bituminous and subbituminous coal options
could be mine-mouth operations or not, with truck, conveyor, railroad, barge or some
combination of delivery systems. Coal is reclaimed as needed from the storage; it is
crushed and conveyed to short-term storage silos before being sent to the coal mills
where it is pulverized for firing in the boiler.
Limestone for the WL-FGD unit is also delivered, stored and prepared on site. For the
subbituminous coal plant with lime SDA SC>2 control, the lime is delivered, stored and
slaked for use on site.
The ash handling system includes the equipment for conveying, preparing, storing, and
disposing the fly ash and bottom ash produced on a daily basis by the boiler. Fly ash is
conveyed to the fly ash storage silo from which it is loaded into trucks and sent to
2-11
-------
Section 2
Process Description
Exhibit 2-4, Pulverized Coal Power Plant Block Diagrams
Bituminous and Lignite Coal-Fired Plant Diagram
Coal Receiving, Storage
and Reclaiming
Coal Feed
Coal Crushing and
Pulverization
Combustion
Air
U
Limestone
Gypsum
Subbituminous Coal-Fired Plant Diagram
Steam Cycle
Energy Input
Internal Power
Requirements
Net Power
Production
\4/ I Bottom Ash
1
Cleaned Flue
Gas to Stack
Selective
(SC
t
Catalytic
ction
R)
i
<£>
1-^
Lime
Reagent
Lime Spray Dryer Flue
Gas Desulfurization
1
Fabric Filter Particulate
Removal
ISDA
Ash&
Compounds
2-12
-------
Section 2 Process Description
disposal. The bottom ash from the boiler is collected via a separate system and sent to
disposal.
WL-FGD wastes (from processes using bituminous and lignite coals) are formed into
gypsum and sent to dewatering and storage by placement in gypsum piles. Depending on
market conditions and transportation costs, some plants may have the potential to
produce salable gypsum and thus reduce their solid waste.
For the subbituminous coal and lime SDA sulfur control, the waste stream is a fine dry
material that can be landfilled and disposed of with the coal fly ash. The potential for
byproduct use of this desulfurization solid waste is limited, as discussed later in Section
3.6.
Steam Generation. This system includes the air handling and preheating systems, the
coal burners, steam generation boiler and reheat, and soot and ash removal. The boiler is
staged for low NOX formation and is also equipped with a SCR as noted below. A drum-
type steam generator is used to power a single-reheat subcritical steam turbine. The
steam turbine conditions correspond to 2,400 psig and 1,000 °F at the throttle with 1,000
°F reheat.
NOx Controls. The NOx controls for all three fuels consist of combustion controls and a
selective catalytic reduction (SCR) system. The combustion controls include low-NOx
burners and overfire air. The SCR reactor is installed at the boiler economizer outlet,
upstream of the air heater, as shown in Exhibit 2-5. These systems are described later in
Section 3.
Particulate Collection. Particulate matter collection for all three coals is accomplished
with the use of fabric filters. As an alternative, an electrostatic precipitator can also be
used. However, a fabric filter was selected for this study, because it reduces reagent
consumption when used in conjunction with a lime SDA system and it has better fine
particulate and trace metal collection efficiencies.
Flue Gas Desulfurization. A WL-FGD is used with the high sulfur bituminous coal and
the lignite. A lime SDA is used for the low-sulfur subbituminous coal. While the WL-
FGD system is located after the fabric filter, the SDA unit is located downstream of the
air preheater, followed by the fabric filter. The wet ESP used for the PC plants firing
bituminous coal and lignite is located downstream of the WL FGD system (not shown in
Exhibit 2-4).
Steam Turbine Generator. The turbine is tandem compound type, comprised of high
pressure, intermediate pressure, two low pressure sections, and a final stage. The turbine
drives a hydrogen-cooled generator. The throttle pressure at the design point is 2,400
psig. The exhaust pressure is 2.0/2.4 inch Hg in the dual pressure condenser. There are
seven extraction points; the condenser is two shell, transverse, dual pressure type.
2-13
-------
Section 2
Process Description
Exhibit 2-5, Example of SCR in a Pulverized Coal Boiler System
m
o*
AIR
4,4
t
All
Condensate and Feedwater Systems. The condensate system moves condensate from the
condenser to the deaerator, through the gland steam condenser and the low pressure
feedwater heaters. The system consists of one main condenser; two 50 percent capacity
condensate pumps; one gland steam condenser; four low pressure heaters; and one
deaerator with a storage tank. The function of the feedwater system is to pump the
feedwater from the deaerator storage tank through the high pressure feedwater heaters to
the boiler economizer. Two 50 percent turbine-driven boiler feed pumps are installed to
pump feedwater through the high pressure feedwater heaters.
Balance of Plant. The BOP includes the following major components.
• Steam Piping and Valves
• Circulating Water System with Evaporative Cooling Tower
• Ducting and Stack
• Waste Water Treatment
2-14
-------
Section 2 Process Description
• Accessory Electric Plant
• Instrumentation and Control
• Buildings and Structures
Supercritical PC Plant
Solids Material Handling. The material handling systems are similar in scope to the
subcritical plant discussion. Component sizes may be different because of higher
efficiency of the supercritical plant (assuming equal generating capacity), but the impacts
of this difference on performance and cost are small, especially compared to the impacts
of specific site conditions, which can vary widely.
Steam Generation. The boiler is staged for low NOx formation and is also equipped with
a SCR. A once-through steam generator is used to power a double-reheat supercritical
steam turbine. The steam turbine conditions correspond to 3,500 psig and 1,050°F at the
throttle with 1,050°F at both reheats.
NOx Controls. The controls used are the same as in the previous plant.
Particulate Collection. Fabric filters used are similar to the subcritical unit.
Flue Gas Desulfurization. The control technologies are the same as installed for the
subcritical unit. Bituminous coal and lignite use WL-FGD systems preceded by the
fabric filter, and the subbituminous coal uses a SDA followed by the fabric filter.
Steam Turbine Generator. The turbine consists of a very high pressure section, high
pressure section, intermediate pressure section, and two low pressure sections, all
connected to the generator by a common shaft. Main steam from the boiler passes
through piping and valves and enters the turbine at 3,500 psig and 1,050 °F. The steam
initially enters the turbine near the middle of the high-pressure span, flows through the
turbine, and returns to the boiler for reheating. The first reheat steam flows through the
reheat and enters the HP section at 955 psig and 1,050 °F. The second reheat steam flows
through the reheat and enters the IP section at 270 psig and 1,050 °F. After passing
through the IP section, the steam enters a crossover pipe, which transports the steam to
the two LP sections. The steam is split into four paths which flow through LP sections
exhausting downward into the condenser.
Condensate and Feedwater Systems and Balance of Plant. These operations are the same
as discussed for the subcritical unit.
Balance of Plant. The BOP includes the following major components.
• Piping and Valves
• Circulating Water System with Evaporative Cooling Tower
• Ducting and Stack
2-15
-------
Section 2 Process Description
• Waste Water Treatment
• Accessory Electric Plant
• Instrumentation and Control
• Buildings and Structures
Ultra-Supercritical Plant
The ultra-supercritical plant level of technology maturity differs from that of the two
technologies discussed previously, and it is relatively rarely used, especially in North
America. There are more than 500 supercritical PC plants throughout the world
(primarily in Europe with a majority of them in the former Soviet Union and Japan)
operating at pressures 3,500 psig and above and at temperatures up to 1,050 °F. There are
ultra-supercritical commercial plants in Japan and Denmark and all belong to the 1,100 °F
class. Two ultra-supercritical plants currently operated by Danish power companies are in
the 250-400 MW range. One of these plants, the Evader unit, has steam conditions of
4,350 psig and 1,112 °F giving an efficiency of 47 percent. The Kawagoe plant in Japan,
consisting of two 700 MW units and operated by Chubu Electric since 1989, has steam
conditions of 4,500 psig and 1,050 °F with double reheat. Its efficiency is 45 percent.
Currently the leading companies offering the 1,100 °F class ultra-supercritical plants are
mostly in Japan, such as Hitachi, IHI, MHI, and Mitsui. They are actively promoting the
commercial use of this class of plants in the world, often in the form of joint companies,
such as Bab cock-Hitachi, and Mitsui-Babcock.
The available data for the Japanese and Danish plants do not state the basis for efficiency
calculations, but the efficiencies are likely based on lower heating values of the fuels.
Also, Denmark has banned coal and the units have been switched to accommodate
natural gas and biomass fuels.
The relative immaturity of the ultra-supercritical technology also means that there are
fewer sources of data, and the performance estimates made for this study are likely to
have a wider variability than for the better known subcritical and supercritical
technologies.
Solids Material Handling. The material handling systems are similar in scope to the
other two plant descriptions. Component sizes may be different because of higher
efficiency of the ultra-supercritical plant (assuming equal generating capacity), but the
impacts of this difference on performance and cost are small, especially compared to
specific site conditions, which can vary widely.
Steam Generation. The boiler is staged for low NOx formation and is also equipped with
a SCR. A once-through steam generator is used to power a double-reheat ultra-
supercritical steam turbine. The steam turbine conditions correspond to 4,500 psig and
1,100°F at the throttle with 1,110°F at both reheats.
NOx Controls. The controls used are the same as in the previous plants.
2-16
-------
Section 2 Process Description
Particulate Collection. Fabric filters used are similar to the subcritical unit.
Flue Gas Desulfurization. The control technologies are the same as installed for the other
PC technologies.
Steam Turbine Generator. The turbine consists of a very high pressure section, high
pressure section, intermediate pressure section, and two low pressure sections, all
connected to the generator by a common shaft. The ultra-supercritical conditions are
4,500 psig and 1,100 °F with double reheat.
Condensate and Feedwater Systems and Balance of Plant. These operations are the same
as discussed for the previous plants.
Balance of Plant. The BOP includes the following major components.
• Steam Piping and Valves
• Circulating Water System with Evaporative Cooling Tower
• Ducting and Stack
• Waste Water Treatment
• Accessory Electric Plant
• Instrumentation and Control
• Buildings and Structures
2.1.3 Process Maturity and Data Availability
The comparisons made for this study are intended to be on an equal basis for all the
technologies. However, decision makers using the report should recognize that the
technical and cost data come from different sources that may not be using exactly the
same basis or criteria. The quantity of available data varies among the technologies and
coals. It is also noted the IGCC technology is still developing (and advancing) while the
PC technology is much more mature.
Except for the ultra-supercritical technology, the PC systems are well-defined and
understood. Costs for PC plants can be estimated with relative certainty provided there is
sufficient preliminary engineering to determine site and owner specific costs. The power
generation industry is familiar with the PC plant operations and understands their
reliability, load following and other operating features.
There are a large number of gasification units in operation globally too, but as noted
before, there are very few gasification plants using coal to generate electric power as
envisioned for IGCC installations. Most of the gasification units are at petroleum or
chemical plants where special conditions favor the gasification of solids or liquids as part
of an integrated process. Coal-based IGCC plants have uncertain costs and concerns with
operating reliability. The power generation industry views the IGCC operations as
2-17
-------
Section 2 Process Description
"chemical plants", and has historically been reluctant to own and operate them. One of
the concerns is the attainment of commercially acceptable levels of plant availability.
The plant availability levels with existing single gasifier-train IGCC plants have been
below the design availability targets of 85 percent13. It is expected that such targets can
be met with the use of a spare IGCC train, which is the design basis for the IGCC plants
in this study. In comparison, plant availability levels exceeding 90 percent can be
achieved with the mature subcritical and supercritical PC technologies.
The ultra-supercritical plant data are less available than data for the IGCC technologies.
A great amount of engineering and process design work has been done for gasification in
the last few years with increasing emphasis on the potential for the technology to more
effectively incorporate carbon management processes. For the ultra-supercritical
technology, most of the work appears to be with advanced materials to construct the units
to make them more attractive from cost and performance aspects. Much of the advanced
PC work also is in Europe and Japan, where fuel prices have for a long time been
relatively expensive, and increases in efficiency have greater impacts on costs of electric
power than in the U.S. Except for the carbon management issue, plant efficiency in the
U.S. has historically not been regarded as a major benefit that justifies the expenditure of
additional capital for equipment or process improvements.
Another area of uncertainty and difference among the technologies is the refinery or
chemical plant type of operations required by the IGCC technologies. While not absent
from PC plants, operational upsets and off-design operations seem potentially more likely
at the more complicated IGCC plants. Such upsets and off-design conditions can
presumably be minimized by careful engineering, possibly installation of spare or special
equipment, and a well-trained plant staff. The emissions of a well-run IGCC plant should
be lower than for other coal systems, but there is an element of uncertainty because the
long-term commercial experience does not yet exist, especially for the applications on
low-rank coals.
13 N. Holt,"Coal-Based IGCC Plant - Recent Operating Experience and Lessons Learned," Gasification
Technologies Conference, October 5, 2004, Washington, DC.
2-18
-------
Section 3
Technical Analyses
Section 3 presents the results from the thermal and environmental performance
assessments.
3.1 Power Generation Performance
The IGCC plant performance, based on the coal higher heating value (HHV), is
summarized in Exhibit 3-1 for the bituminous and subbituminous coals. The slurry-feed
type gasifier used for these coals is not well-suited to the high-moisture, high-ash lignite
coal, and the subbituminous coal may be a difficult fuel to use for practical applications.
High amounts of coal ash interfere with the radiant heat exchanger's ability to recover
energy and generate steam. Also, high-ash slurry from the gasifier bottom is another
source of heat losses. This has significant impact on the gasifier thermal efficiency. The
Shell gasifier is more able to handle high-ash coals without heat loss penalties.
Gasification developers, such as GE Energy, have declined in the past to offer their
technology for high moisture coals. On the other hand, ConnocoPhillips, who also offers
a slurry-feed type system, has past subbituminous coal experience and would offer its
gasifier for subbituminous coals in general. The Canadian Clean Power Coalition (CCPC)
has examined low-rank coal gasification, but only reported summary level results.14 In
the CCPC summary, the efficiency for all the gasification cases was about 38%. It
cannot be determined from this data whether, for example, the performance impacts of
coal drying or increased oxygen demand were accounted for in the calculations. The
CCPC study used GE Energy gasifiers for the bituminous and subbituminous coals, and
Shell for the lignite. However, the Canadian subbituminous coal has less moisture, 20%
compared to more than 27% for this study. Despite the uncertainty of low rank gasifier
selection, the impacts on environmental issues would not be significantly different as all
the IGCC technologies use very similar cleanup and control processes.
Exhibit 3-1, Integrated Gasification Combined Cycle Performance Estimates - Bituminous
and Subbituminous Coals
GE-Energy Slurry Feed Gasifier
and F-type Gas Turbine
Net Thermal Efficiency (HHV), %
Net Heat Rate (HHV), Btu/kWh
Gross Power, MW
Internal Power, MW
Fuel required, Ib/h
Net Power, MW
Bituminous
41.8
8,167
564
64
349,744
500
Subbituminous
40.0
8,520
575
75
484,089
500
14
G. Morrison, "Summary of Canadian Clean Power Coalition work on CO2 capture and storage." IEA
Clean Coal Centre, August 2004.
5-1
-------
Section 3
Technical Analyses
Exhibit 3-2 presents summary performance data for the Shell solid feed type of gasifier
and the lignite coal.
Exhibit 3-2, Integrated Gasification Combined Cycle Performance Estimates - Lignite Coal
Shell Solid Feed Gasifier
and F-type Gas Turbine
Net Thermal Efficiency (HHV), %
Net Heat Rate (HHV), Btu/kWh
Gross Power, MW
Internal Power, MW
Fuel required, Ib/h
Net Power, MW
Lignite
39.2
8,707
580
80
689,720
500
Exhibit 3-3 lists the typical consumers of internal power at the IGCC plants. The impact
of the air separation plant and oxygen compression is highlighted. The coal preparation
(thermal drying) component of the Shell technology is an area of performance and
emission uncertainty. Limited public data is available to support engineering estimates,
and the cost of detailed engineering needed to create and validate new data would be
significant.
Exhibit 3-3, Typical IGCC Auxiliary Power Consumption Breakdown
Plant Component
Coal Handling and Conveying
Coal Milling
Coal Slurry Pumps
Slag Handling and Dewatering
Scrubber Pumps
Recycle Gas Blower
Air Separation Plant
Oxygen Boost Compressor
Amine Units
Claus/TGTU
Tail Gas Recycle
% of Total
Aux. Power
0.7%
1.5%
0.4%
0.3%
0.6%
1.2%
47.1%
24.1%
2.6%
0.2%
2.8%
Plant Component
Humidification Tower Pump
Humidifier Makeup Pump
Condensate Pumps
Boiler Feedwater Pump
Miscellaneous Balance of Plant
Gas Turbine Auxiliaries
Steam Turbine Auxiliaries
Circulating Water Pumps
Cooling Tower Fans
Flash Bottoms Pump
Transformer Loss
% of Total
Aux. Power
0.2%
0.1%
0.6%
5.9%
2.0%
1.2%
0.4%
3.6%
2.2%
0.1%
2.2%
5-2
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Section 3
Technical Analyses
The high amount of ash (slag) in lignite makes it unsuitable for GE Energy's entrained
flow gasifier, because heavy slagging of the radiant heat exchanger slows heat removal
and exchange. Also, the need for high ash content slurry to be removed from the bottom
of the gasifier which retains significant heat energy is another major source of heat loss.
These two factors have significant impact on the thermal efficiency of the gasifier and
overall IGCC plant. Although the GE Energy gasifier can handle high moisture coal, the
efficiency loss from the ash content of lignite is significant enough to make it
unattractive.
The Shell gasifier has a refractory-lined water wall for syngas heat removal which can
handle high loading of ash and still be effective in heat transfer. There is no significant
loss in efficiency in Shell gasifier.
Greater details of energy and material balances for the IGCC plants are included in
Appendix C of this report.
Exhibits 3-4, 3-5, and 3-6 present summary performance data for the PC units and the
three coals.
Exhibit 3-4 Subcritical Pulverized Coal Unit Performance Estimates
Subcritical PC
Net Thermal Efficiency, % HHV
Net Heat Rate, Btu/kWh (HHV)
Gross Power, MW
Internal Power, MW
Fuel required, Ib/h
Net Power, MW
Bituminous
35.9
9,500
540
40
407,143
500
Subbituminous
34.8
9,800
541
41
556,818
500
Lignite
33.1
10,300
544
44
815,906
500
Exhibit 3-5 Supercritical Pulverized Coal Unit Performance Estimates
Supercritical PC
Net Thermal Efficiency, % HHV
Net Heat Rate, Btu/kWh (HHV)
Gross Power, MW
Internal Power, MW
Fuel required, Ib/h
Net Power, MW
Bituminous
38.3
8,900
540
40
381,418
500
Subbituminous
37.9
9,000
541
41
517,045
500
Lignite
35.9
9,500
544
44
752,535
500
-------
Section 3
Technical Analyses
Exhibit 3-6 Ultra Supercritical Pulverized Coal Unit Performance Estimates
Ultra Supercritical PC
Net Thermal Efficiency, % HHV
Net Heat Rate, Btu/kWh (HHV)
Gross Power, MW
Internal Power, MW
Fuel required, Ib/h
Net Power, MW
Bituminous
42.7
8,000
543
43
342,863
500
Subbituminous
41.9
8,146
543
43
460,227
500
Lignite
37.6
9,065
546
46
720,849
500
Greater details of energy and material balances for the PC plants are included in
Appendix C of this report. Exhibit 3-7 shows the typical auxiliary power consumers at
the PC plants.
Exhibit 3-7, Typical PC Plant Auxiliary Power Consumption Breakdown
Plant Component
Coal Handling and Conveying
Limestone Handling & Reagent
Preparation
Pulverizers
Ash Handling
Primary Air Fans
Forced Draft Fans
Induced Draft Fans
SCR
Seal Air Blowers
% of Total
Aux. Power
1.3%
3.2%
6.4%
5.7%
4.2%
3.3%
17.4%
0.3%
0.2%
Plant Component
Precipitators
FGD Pumps and Agitators
Condensate Pumps
Boiler Feed Water Pumps
Miscellaneous Balance of
Plant
Steam Turbine Auxiliaries
Circulating Water Pumps
Cooling Tower Fans
Transformer Loss
% of Total
Aux. Power
3.4%
11.9%
2.0%
9.2%
6.9%
1.4%
12.2%
7.1%
3.9%
3.2 Integrated Gasification Combined Cycle Emissions
Emission controls for IGCC systems are described extensively in several of the
references included elsewhere in this report. For most of the conceptual design studies,
emissions are assumed to be equal to a regulation or otherwise selected standard. Brief
5-4
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Section 3 Technical Analyses
summaries of the emission controls are presented in this report, which, as noted, focuses
on estimates for typical emission reduction capabilities available with state-of-the-art
versions of these controls. The emission estimates reflected below are provided for
informational purposes only. Publication of such estimates in this report does not
establish the estimates as emissions limitations for any source or require that such
estimates be used as emissions limitations in any permit. Emission limitations and permit
conditions should be determined by permitting authorities on a case-by-case basis
considering applicable EPA and State regulations and the record in each permit
proceeding.
Particulates
Solid particulates from the gasifier must be removed prior to downstream cleanup
processes and syngas combustion. Solids removal is accomplished with metal filters
followed by wet scrubbing. The removal of the solids as dry materials with the upstream
filter minimizes dewatering and waste disposal issues. The scrubbers remove ammonia,
chlorides, and other trace organic and inorganic components from the synthesis gas. The
scrubber reject (blowdown) stream is flashed to a vapor and disposed of in a high
temperature furnace. The remaining slurry goes to a solid-liquids separation step before
disposal.
Acid Gas Cleanup/Sulfur Recovery
After removal of the particulates, the synthesis gas is further cleaned in preparation for
combustion in the gas turbine. Acid gas cleanup processes similar to those widely
applied in the petroleum and chemical industries are used for the IGCC plants.
Commercial alternatives for IGCC acid gas cleaning are the chemical solvent processes
based on amines and physical solvent-based processes. The aqueous
methyldiethanolamine (MDEA) is used in this study. The MDEA processes are preceded
by carbonyl sulfide (COS) hydrolysis units to convert the COS to H2S. This allows more
total sulfur removal. Selexol™ (dimethylether or polyethylene glycol) and Rectisol™
(cold methanol) are examples of physical solvents. The physical solvent technologies are
commonly used in the chemical or petroleum industries when deep sulfur removal is
needed for products or downstream processes. In one coal-based application, Rectisol
process has removed greater than 99.9% sulfur from syngas15. The physical solvents are
examined later in the study for use with SCR and NOx reduction.
For the study, the acid gas removal process uses an amine solvent, MDEA, which
chemically reacts with the H2S and CO2. The reacted amine is sent to a stripper where
heat (steam) is used to separate the gases and regenerate the MDEA for recycle to the
cleaning process. Acid gas cleanup processes are commercial and widely used by the
petroleum and chemical industries. Sulfur removal and recovery approaches 100%, with
99% removal efficiency assumed for this study. Discussions with the MDEA and acid
gas removal suppliers confirm that the level of sulfur removal is very much an economic
15 M. Rutkowski, et al, "The Cost of Mercury Removal in an IGCC Plant," Gasification Technologies
Public Policy Workshop, October 1, 2002, Washington, DC.
5-5
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Section 3 Technical Analyses
tradeoff between the surface area of absorber materials, amine recirculation and stripping
rates and sulfur removal. There are many site- and coal- specific factors that will impact
the MDEA process details and costs, and detailed engineering is required for the MDEA
system to be fully specified. The 99% removal value selected for the study is consistent
with inputs from the permit documents (see Appendix B) available from recent IGCC
projects as well as with inputs from technology suppliers and serves as a reasonable near-
term target for the study.
The acid gas removal system includes a sulfur recovery process where elemental sulfur or
sulfuric acid can be made. A decision on the final design configuration for the acid gas
removal system for an IGCC plant will be based on whether the byproduct produced is
salable and a long-term market for it exists. A sulfur recovery process is selected for this
study, which is a two-step process; a Claus process followed by a Shell Claus off-gas
treatment (SCOT) tail-gas cleaning. The Claus sulfur recovery unit produces elemental
sulfur from the H^S. The Claus process removes about 98% of the sulfur. The Claus tail-
gas is sent to a SCOT process for further sulfur recovery. SCOT is an amine-based
process and can remove 99.8% of the sulfur.
Mercury
The details for what happens to the mercury in the coal at a gasification plant are not well
understood. The relatively small amounts of the element present in the gas streams are
difficult to measure and make tracking the material through the gasification process very
difficult. From plant experience16'17, it does appear that plants without carbon beds for
mercury capture will release 50 to 60 percent of the coal-derived mercury in the flue gas.
However, addition of relatively inexpensive carbon bed filters will remove 90 to 95% of
the emitted mercury.18 The Eastman gasification plant in Tennessee uses such controls for
their chemical production and reports excellent results.19
The Eastman gasification plant feedstock consists of medium- to high-sulfur bituminous
coals. Based on this experience, it is assumed that use of the carbon-bed technology on
all three study coals would result in 90% mercury removal efficiency. While the
Eastman experience validates this assumption for the bituminous coal case, the lack of
experience with carbon-bed application on low-rank coals raises the potential for less
than 90% mercury removal for such applications.
16 Major Environmental Aspects of Gasification-Based Power Generation Technologies. Final Report by:
Jay Ratafia-Brown, Lynn Manfredo, Jeffrey Hoffmann, & Massood Ramezan for National Energy
Technology Laboratory, U.S. Department of Energy, December 2002.
17 The Cost of Mercury Removal in an IGCC Plant Final Report Prepared for Department
of Energy National Energy Technology Laboratory by Parsons Infrastructure and
Technology Group Inc. September 2002.
18 Personal contact between Nexant and ConocoPhillips, August 15, 05.
19 Gas Turbine World, Sept - Oct 2005 Volume 35 Number 4; "IGCC Closing the $/kW Cost Gap".
5-6
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Section 3 Technical Analyses
The Federal New Source Performance Standards currently require a mercury limit of
20 x 10"6 Ib/MWh for new IGCC plants.20 Any future changes to this requirement can be
seen on the referenced EPA's website.
Turbine Combustion Impacts
While some initial discussions about the environmental impacts from the syngas
combustion turbines indicated them to be the same, or similar to those of natural gas-fired
turbines, the technical and regulatory communities have largely recognized that the
combustion characteristics of syngas and natural gas are different, and require different
consideration of control technologies.
Syngas has a different calorific value, gas composition, flammability characteristics, and
presence of contaminants than natural gas. The GE Energy and Shell type gasifier plants
produce syngas with a heating value from 250 to 400 Btu per standard cubic foot
compared to about 1,000 Btu per standard cubic foot for natural gas. The composition of
natural gas is primarily methane, and the syngas components are primarily carbon
monoxide and hydrogen. The H2 causes a high flame speed and temperature. The
syngas will also contain some low level of sulfur contaminants, which may impact the
reliability and effectiveness of post-combustion NOx control technologies.
A diluent, steam or nitrogen, is used to lower flame temperature and minimize NOx
creation. Nitrogen can be taken from the air separation plant and integrated with the
turbine. As a byproduct of the addition of mass to the gas flow, the turbine generating
capacity will increase. Section 4 discusses the use of SCR with the syngas turbine to
further reduce NOx, but for the study base IGCC cases, at this time the state-of-the-art
control for syngas-fired turbines is the addition of nitrogen that reduces NOx emission to
15 ppmvd (at 15% oxygen and ISO conditions). GE hopes to develop combustors to
achieve less than 10 ppmvd NOX with syngas.
Non-Criteria and Hazardous Air Pollutants
Depending on the coal characteristics, the non-criteria and inorganic hazardous air
pollutants (HAPs) with the most environmental concerns in IGCC systems are the trace
metals: arsenic, cadmium, lead, mercury, and selenium. Exhibit 1-3 shows a more
complete list of EPA non-criteria pollutants and HAPS. Measurement of HAPS has
proven to be difficult with existing instrumentation used for the IGCC system.
Computer-based thermodynamic equilibrium studies have been reported that show these
metals are volatile and will be hard to control.21 Less volatile trace metals will likely
remain with the ash or be removed by downstream gas cleaning. Mercury, which
primarily remains in the vapor-phase, is a special case discussed earlier. Indications are
20 Code of Federal Regulations, 40 CFR, Part 60, Subpart Da, http://www.epa.gov/epacfr40/chapt-
T.info/chi-loc.htm. accessed 5/2/06.
21 Major Environmental Aspects of Gasification-Based Power Generation Technologies. Final Report by:
Jay Ratafia-Brown, Lynn Manfredo, Jeffrey Hoffmann, & Massood Ramezan for National Energy
Technology Laboratory, U.S. Department of Energy, December 2002.
5-7
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Section 3
Technical Analyses
that most of the elemental, vapor phase mercury is emitted from the gasification process.
However, effective control methods with carbon filters are in commercial use for other
applications, and should be available to the IGCC cases at reasonable economic costs. It
is estimated that installation of carbon bed filters will reduce mercury by 90 to 95%.
The energy and material balance for HAPS and the measurement of HAP emissions is
complex and difficult to forecast accurately until more operating data becomes available.
Trace elements can be divided into three classifications depending on volatility and the
volatility of their simple compounds, such as oxides, sulfides and chlorides. Class I
elements are the least volatile and remain in the ash. Class II elements are more volatile
and report to both the ash and the gaseous phases, with condensation of vaporized species
on the surface of ash particles as the gas cools. Class III elements are highly volatile.
Elements that exit the gasifier as vapor will further separate downstream as condensation
occurs. The thermodynamic models indicate that the metals are more volatile under the
reducing gasification environment than in oxidizing combustion environments.
Detailed field measurements for trace metals were conducted at the 160 MW Louisiana
Gasification Technology Inc. The reported results are shown in Exhibit 3-8.22
Exhibit 3-8, IGCC Trace Metal Reporting within the Process
200
150
Q.
C
0)
£
0)
o_
100
50
Sb Cl F As Be Cd Cr Co Pb Mn Hg Mo Ni Se
D Gasifier Slag • Sweet Water • Turbine Stack m Incinerator Stack
Major Environmental Aspects of Gasification-Based Power Generation Technologies. Final Report by:
Jay Ratafia-Brown, Lynn Manfredo, Jeffrey Hoffmann, & Massood Ramezan for National Energy
Technology Laboratory, U.S. Department of Energy, December 2002.
-------
Section 3
Technical Analyses
The graph in Exhibit 3-8 shows the partitioning of the trace elements among the major
outlet streams - gasifier slag, processed "sweet" water, turbine stack gas, and incinerator
stack gas. The report cautions that many of the elements are present at extremely low
levels and may partially accumulate within an IGCC process, it is not unusual to obtain
material balance closures of less than (or more than) 100%.
Trace element emission factors (lb/1012 Btu input basis), calculated for total stack
emissions from the Louisiana gasification plant, are presented in Exhibit 3-9, and are
from the same DOE/NETL final report.
Exhibit 3-9, Estimates of IGCC Trace Element Emissions
TRACE ELEMENT
Antimony
Arsenic
Beryllium
Cadmium
Chloride
Chromium
Cobalt
Fluoride
Lead
Manganese
Mercury
Nickel
Selenium
EMISSION FACTOR, lb/1012 Btu
Average
4
2.1
0.09
2.9
740
2.7
0.57
38
2.9
3.1
1.7
3.9
2.9
95% Confidence Level*
4.7
1.9
0.03
3.8
180
0.63
0.58
22
1.5
6.5
0.43
3.6
1.3
* Mean value of the confidence interval in which there is a 95% probability that the value occurs
Trace element stack emissions are a function of their concentrations in the coal. Higher
coal concentrations generally result in higher stack emissions, since the reduction levels
within controls may stay the same. For the study cases, emission estimates are provided
for only a few important trace elements, and these estimates either use a range of
emission values or are based on coal concentrations. Exhibit 3-26 and Appendix B
present a comparison of trace element limits from air permit documents for recent IGCC
and PC plants.
Air Emission and Other Environmental Impact Estimates for IGCC Plants
Exhibits 3-10 and 3-11 present the environmental impact estimates for the two gasifier
cases and three coals. The emission values for key air pollutants are provided in
Ib/MMBtu, Ib/MWh, and ppmvd at 15%O2. Lb/MWh values are based on MW gross.
5-9
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Section 3
Technical Analyses
Exhibit 3-10, IGCC Environmental Impacts, Slurry Feed Gasifier
GE Energy Slurry Feed
Gasifier
Air Pollutants
NOX (NO2)
SO2
CO
Volatile Organic
Compounds
Particulate Matter (overall)
Particulate Matter (PM10)
Lead (Pb)
Ib/MMBtu
Mercury
Acid Mist
Other Environmental
Impacts
CO2
Solid Waste (gasifier slag)
Raw Water Use
Sulfur Production, Ib/h
Sulfur Removal
NOX Removal
Particulates
500
Ppmvd
(@ 15%
02)
15
10
15
~
~
MW Net Capacity
Bituminous
Ib/MWh
0.355
0.311
0.217
0.012
0.051
Ib/MMBtu
0.049
0.043
0.030
0.0017
0.007
With the Overall Particulate Matter
1.0x10
Ppmvd
(@ 15%
02)
-6 to 2.4x10
below)
5.50xlO-6
0.030
Lb/MWh
1,441
65
4,960
8,679
99%
"6 (see text
0.76xlO-6
0.0042
Ib/MMBtu
199
g
685
To 15 ppmvd
99.9% or greater. Typical value
for IGCC is "negligible" emissions
500
ppmvd
(@ 15%
02)
15
3
17
~
MW Net Capacity
Subbituminous
Ib/MWh
0.326
0.089
0.222
0.013
0.052
Ib/MMBtu
0.044
0.012
0.030
0.0017
0.007
With the Overall Particulate Matter
1.0x10
ppmvd
(@ 15%
02)
-6 to 2.4 xlO'6 (see text
below)
3.11xlO-6
0.004
Ib/MWh
1,541
45
5,010
1,044
97.5%
0.42xlO-6
0.0005
Ib/MMBtu
208
6
676
To 15 ppmvd
99.9% or greater. Typical value for
IGCC is "negligible" emissions
3-10
-------
Section 3
Technical Analyses
Exhibit 3-11, IGCC Environmental Impacts,
Solids Feed Gasifier
Shell Solid Feed Gasifier
Criteria Pollutants
NOX (NO2)
SO2
CO
Volatile Organic Compounds
Particulate Matter (overall)
Particulate Matter (PM10)
Lead (Pb), Ib/MMBtu
Mercury
Acid Mist
Other Environmental
Impacts
C02
Solid Waste (gasifier slag)
Raw Water Use
Sulfur Production, Ib/h
Sulfur Removal
NOX Removal
Particulates
500 MW Net Capacity Lignite
ppmvd
@15% Ib/MWh Ib/MMBtu
02
15 0.375 0.050
4 0.150 0.020
15 0.225 0.030
0.013 0.0017
0.053 0.007
With the Overall Particulate Matter
1.0 x 10"6 to 2.4 x 10"6 (see text below)
5.48X10'6 0.73X10'6
0.015 0.002
ppmvd
@15% Ib/MWh Lb/MMBtu
O2
1,584 211
218 29
5,270 700
4,370
99%
To 15 ppmvd
99.9% or greater. Typical value for
IGCC is "negligible" emissions
The emissions for IGCC units listed above were estimated from energy and material
balance calculations and other methods as noted below.
• The emission estimates have generally been based on air permit data (see Appendix
B) and discussions with control technology suppliers. Only IGCC plants utilizing
bituminous coal are included in the permit data available for this study. Also, only a
small amount of operating data is available for IGCC application on low-rank coals.23
23 H. Frey and E. Rubin, "Integration of Coal Utilization and Environmental Control in Integrated
Gasification Combined Cycle Systems," Environment Science Technology, Volume 26, No. 10, 1992.
3-11
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Section 3 Technical Analyses
The suppliers have indicated that the performance capabilities of control technologies
would remain the same for all three types of study coals. This is based on experience
with gasifier applications in the petroleum and chemical industries. Therefore, the
emission estimates for subbituminous coal and lignite cases have been based on
reduction levels similar to those used for the bituminous coal case. Because of the
lack of relevant air permit or operating data for the subbituminous coal and lignite
cases, some uncertainty still remains for these two estimates.
• NOx is controlled by dilution of the gas turbine fuel-air mixture with steam and
nitrogen. Utilizing existing technology and design considerations, the achievable
concentration is 15 ppmvd at 15% oxygen. This was estimated from a discussion
between Nexant and GE and reviews of recent air permit data and literature.
• SC>2 is controlled by the MDEA-based acid gas cleaning system and sulfur
production. This system removes 99% of the total sulfur at the IGCC plants using
bituminous coal and lignite, which is based on recent air permit data and discussions
with MDEA process providers. The subbituminous coal selected for this study has a
relatively low sulfur content of 0.22%. The total sulfur removal rate selected for the
IGCC plant using this coal is 97.5%, which is based on a sulfur concentration in the
syngas of 20 ppm and that in the stack flue gas of 3 ppm24.
• CO is controlled by good combustion practices and the limit of 0.03 Ib/MMBtu is
estimated from the review of recent air permit data.
• The overall Particulate Matter, including PMi0, is controlled by the paniculate
removal filters and the acid gas removal wet scrubbing of the synthesis gas. It
includes filterable particulate matter only. The removal rate is nearly 100%, which is
based on the review of recent air permit data.
• Fine Particulate Matter (PM2 5) - no data was found for the fine particulate emissions.
• VOCs are controlled by good combustion practices, i.e., efficient and stable
gasification. The emission limit of 0.0017 Ib/MMBtu is based on the review of recent
air permit data.
• Lead emissions are estimated by review of recent air permit data. This limit is
expected to vary significantly with the coal, depending on the coal lead content and as
more is learned about its presence in the IGCC systems. From operating experience,
it appears that about 5% of the lead in the coal is emitted. The remainder is left with
gasifier slag and other parts of the gas cleaning systems.
24 Process Screening Analysis Of Alternative Gas Treating And Sulfur Removal For Gasification, Revised
Final Report, December 2002, Prepared by SFA Pacific, Inc., U.S. DOE Task Order No. 739656-00100.
3-12
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Section 3 Technical Analyses
• Mercury limits are based on 90% removal within the controls provided specifically
for mercury removal and controls for other pollutants. The uncontrolled mercury
emission is based on an assumed average mercury content of each coal type, which
was taken from a published source.25 The reported emission will vary with the coal
mercury content.
• Acid mist limits are based on air permit data for the bituminous coal case. For the
subbituminous coal and lignite cases, the generation and removal rates used are the
same as for the bituminous case.
• CC>2 is calculated with the assumption that all the carbon in the coal is converted to
C02.
• Solid Waste is calculated using the ash content of the coals.
• Water losses are based on the USDOE/NETL report and Nexant performance
spreadsheet calculations26.
• Sulfur production is calculated based on the sulfur content of the coals.
3.3 Pulverized Coal Plant Emissions
The primary PC plant emission control devices are briefly described below. The
technologies are commercially available, and are prevalent in many operating plants and
in published data. The emission estimates reflected below are provided for informational
purposes only. Publication of such estimates in this report does not establish the
estimates as emissions limitations for any source or require that such estimates be used as
emissions limitations in any permit. Emissions limitations and permit conditions should
be determined by permitting authorities on a case-by-case basis considering applicable
EPA and state regulations and the record in each permit proceeding.
The two most widely used flue gas desulfurization (FGD) technologies for PC plants are
the wet FGD systems and dry FGD systems. In general, the wet FGD system is located
downstream of the particulate control device, the flue gas is fully saturated with water,
and the SO2 reaction products are removed in a wet solid waste form. The dry FGD
systems are located upstream of the particulate collection device, the flue gas is partially
saturated, and the dry SO2 reaction products are collected along with fly ash in the
particulate collection device. Different types of wet and dry FGD systems are available,
using different reagents. For this study, a wet limestone flue gas desulfurization (WL-
FGD) system utilizing a scrubber with forced oxidation is used for the bituminous coal
and lignite cases, and a lime spray dryer absorber (SDA) is used for the subbituminous
25 Coal Analysis Results, hUp://www.cpa.gov/itii/atw/combiist/utiltox/ntoxpg.html#DA2. accessed on
February 21, 2006.
26 Power Plant Water Usage and Loss Study. U.S. DOE NETL, August 2005.
3-13
-------
Section 3 Technical Analyses
case. Most coal-fired power plants equipped with 862 controls use these two
technologies, described below:
Flue Gas Desulfurization - Low-Sulfur Subbituminous Coal
Lime SDA is generally used to control SC>2 emissions from PC plants firing low-sulfur
coal. The systems are located after the air preheaters, and the wastes are collected in a
baghouse or fabric filter to achieve high rates of SC>2 removal (an electrostatic
precipitator may also be used, in lieu of the fabric filter, but it requires a higher lime
injection rate to achieve similar levels of 862 removal). The SDA treats the flue gas by
injecting atomized lime slurry. The fine droplets absorb SC>2 from the flue gas and the
SC>2 reacts with the lime to mostly form calcium sulfite. The cleaned flue gas, the
reaction products, any unreacted lime, and the fly ash are all collected in the filters. The
waste product contains CaSO3, CaSO4, calcium hydroxide, and ash.
SDA systems are commercial and range in size from less than 10 MW to 500 MW.
Applications include commercial units with coal sulfur content as high as 2.0%. These
systems are available from a number of vendors including: Alstom Environmental
Systems, Babcock & Wilcox (B&W), Babcock Power, Hamon Research Cottrell,
Marsulex Environmental Technologies, and Wheelabrator Air Pollution Control.
SDA systems have generally been applied to units which use low sulfur coals, including
Powder River Basin and other western coals with inlet SC>2 less than 2.0 Ib/MMBtu and
low sulfur eastern bituminous coal with inlet 862 concentrations as high as 3.0
Ib/MMBtu. Babcock & Wilcox installed SDA units at U.S. Operating Services' 285 MW
Chamber Works Unit, which utilizes bituminous coal, in 1993 and achieved 93% removal
efficiency. B&W also achieved similar efficiency at Eastman Kodak's 110 MW boiler
#31, which uses bituminous coal. Alstom has achieved 95% removal efficiency at
Pacific Gas and Electric Company's 330 MW Indiantown plant and South Carolina
Electric and Gas Company's 385 MW Cope Unit #1, both installed in 1995.
Unlike WL-FGD absorbers, which must be constructed of expensive corrosion-resistant
metals or other materials, SDA systems can be constructed of less expensive carbon steel
due to the absence of water-saturated gas. Dry systems are able to efficiently capture
SOs, they efficiently remove oxidized forms of mercury from flue gas, and they consume
less energy than wet systems. The SDA process has the other following advantages
compared to WL-FGD technology:
• Waste products are in a dry form and can be handled with conventional pneumatic fly
ash handling equipment. The waste is suitable for landfill and can be disposed of
with fly ash.
• The dry system uses less equipment than does the WL-FGD system.
3-14
-------
Section 3 Technical Analyses
• Sulfur trioxide (SO3) in the vapor form is removed efficiently with a SDA and fabric
filter. Wet scrubbers capture up to 50% of SO3 and require additional processing to
avoid visible plume from the stack. New plants are likely to install wet ESP systems
with the WL-FGD scrubbers to enhance SOs control.
• There are no liquid effluents from a dry system. Water used to slurry the lime is
evaporated in the SDA process.
The dry process has the following disadvantages when compared to WL-FGD
technology.
• For systems larger than about 300 MW, multiple trains of process equipment may be
required.
• Lime is a more expensive reagent than the limestone used with the WL-FGD, and
reagent utilization is lower for the dry system.
• The SDA waste has a few useful or commercial applications at this time. In some
cases, the WL-FGD wastes can be converted to salable gypsum if there is a market.
• For the study, using coal with a sulfur content of only 0.22%, the SDA technology's
862 removal efficiency is 87%. If a higher sulfur coal was used, a higher removal
rate would be possible.
Wet Limestone Flue Gas Desulfurization - Bituminous and Lignite Coals
WL-FGD technology is the most widely applied 862 removal technology for PC boilers.
The forced-oxidation version of this technology produces oxidized solid waste (mostly
calcium sulfate or gypsum), which is a stable compound that can be readily landfilled or
sold for industrial applications, if a market exists. Another version of the WL-FGD
technology produces un-oxidized solid waste (mostly calcium sulfite), which is less
stable and must be mixed with other compounds, such as portland cement, to make it
suitable for landfilling. The current industry trend is to use the forced oxidation system.
The main WL-FGD scrubber vessel is located after the plant's paniculate removal
system. The cleaned gas is then sent to the stack. The WL-FGD uses limestone or lime
as a reagent. The lime is a magnesium enhanced reagent. Cost and economics will
dictate the choice of reagents.
The system operation is similar for both reagents. The flue gas is treated in a limestone
or lime slurry spray. Designs vary, but commonly the gas flows upward, countercurrent
to the spray liquor. The slurry is atomized to fine droplets for uniform gas contact. The
droplets absorb 862 which reacts with reagent in the slurry. Hydrogen chloride present
in the flue gas is also absorbed and neutralized with reagent. Water in the spray droplets
evaporates, cooling the gas to its saturated temperature (generally, 120 to 130°F). The
desulfurized flue gas passes through mist eliminators to remove entrained droplets before
3-15
-------
Section 3 Technical Analyses
the flue gas is sent to the stack. In some systems the clean flue gas is reheated to avoid
acidic condensation in the stack. The choice of a "wet" or "dry" stack is another cost
trade-off decision.
For the study, a limestone-based, forced-oxidation WL-FGD system is selected. The
system 862 removal efficiency with bituminous coal is 98%. Due to lack of specific
data, the same SO2 mass emission rate achieved with bituminous coal is used for lignite.
NOX Controls
The most widely applied NOx controls for coal-fired boilers include combustion control
and selective catalytic reduction (SCR) technologies. Both technologies can be applied
simultaneously to maximize NOX reduction.
Combustion controls consist of a low-NOx burner (LNB) and the use of overfire air
(OFA). These technologies utilize staged combustion techniques to reduce NOx
formation in the boiler primary combustion zone and a plant may opt to use one or both
of these. An LNB limits NOx formation by controlling the stoichiometric and
temperature profiles of the combustion process. This control is achieved by design
features that regulate the aerodynamic distribution and mixing of the fuel and air. OFA,
also referred to as air staging, is a combustion control technology in which a fraction, 5 to
20%, of the total combustion air is diverted from the burners and injected through ports
located downstream of the top burner level. OFA is used in conjunction with operating
the burners at a lower-than-normal air-to-fuel ratio, which reduces NOx formation. The
OFA is then added to achieve complete combustion.
SCR is a post-combustion NOx control technology capable of reductions in excess of 90
percent. Because NOx reduction methods are commonly a combination of combustion
controls (special burners, air and firing operations), it is difficult to specify a percent
removal for SCR without a comparable case without SCR. In this report NOx emission
comparisons for the plant will be stated in units of ppmvd - parts per million by volume
dry basis. Also, all the NOx concentration estimates are adjusted to 15% oxygen so the
PC and IGCC emissions can be better compared. NOX reductions are achieved by
injecting ammonia (NH3) into the flue gas, which then goes through a catalyst. The NH3
and NOx react at the catalyst, forming nitrogen and water. The technology has been
widely used for coal-fired applications for more than 30 years in Japan, Europe, and the
United States. It has been applied to large utility and industrial boilers, process heaters,
and combined cycle gas turbines. In the SCR process, NH3 is injected into the flue gas
within a temperature range of about 600 to 750 °F, upstream of the catalyst.
Subsequently, as the flue gas contacts the SCR catalyst NOx is chemically reduced when
the flue gas contacts the SCR catalyst. The simple reaction is:
2NO + 2NH3 + V2O2 -> 2N2 + 3H2O
Exhibit 2-5 illustrates the location of the SCR in a typical PC boiler system. The catalyst
is located between the economizer and the air preheater; this is termed a hot-side SCR
3-16
-------
Section 3 Technical Analyses
and is the most commonly used configuration. Theoretically one mole of NH? is required
to reduce one mole of NO. It is important to keep the operation close to the theoretical
limit because unreacted NH?, or ammonia slip, will combine with SC>2 and SOs present in
the flue gas to form ammonium sulfate and bisulfate compounds, which may cause
fouling of downstream equipment.
Particulate Controls
Solid particulates are controlled by the installation of electrostatic precipitators (ESP) or
fabric filters. Removal rates approach 100% with values of 99.7 to 99.9% used in the
study, depending on the coal ash content and based on utilizing fabric filters. A practical
system that will measure and monitor total particulates and the fine particulates,
especially PM2.5 materials, still needs to be developed by the industry.
Air Pollution Control Technology Advancements
There are ongoing activities in the industry that are concentrating on improving the
performance of existing air pollution control technologies or developing new
technologies. The data reported by the industry show several new technologies that are
in various stages of development, with the potential to reduce costs and improve
performance of controlling air pollution from coal-fired power plants.27 Some of these
technologies control more than one pollutant within the same system. These technologies
were not considered for this study, as they were not considered to be commercial and
available in the timeframe relevant to this study.
Non-Criteria and Hazardous Air Pollutants
HAPS from the PC plant operations are controlled by the flue gas desulfurization
systems, particulate collection fabric filters and the SCR technology. The recent air
permit data show the emission limits that can be achieved for certain HAPs (see
Appendix B). The PC units have oxidizing combustion conditions, which help to reduce
some of the HAP emissions by converting the metals to oxides that report to the ash
materials. Currently, the coal ash wastes are not considered hazardous and can be
disposed off in a landfill.
The potential for mercury removal with conventional controls used for criteria pollutants
at PC plants was reported as shown in Exhibit 3-12.28 The data presented in Exhibit 3-12
result in the following observations. The air pollution control technologies used on PC
utility boilers exhibit average levels of mercury control that widely range in
effectiveness, from 0 to 98 percent. The best levels of control are by emission control
systems that use fabric filters. The amount of mercury captured by a control technology is
higher for bituminous coal than for either subbituminous coal or lignite. The lower levels
27 Multipollutant Emission Control Technology Options for Coal-Fired Power Plants, EPA-600/R-05/034,
March 2005.
28 Control Of Mercury Emissions From Coal-Fired Electric Utility Boilers( Including Update): Original
Report Dated 2-2002 and Update Dated 2-18-2005, U.S. EPA Office Of Research and Development,
Prepared by National Risk Management Research Laboratory Research Triangle Park, NC 27711.
3-17
-------
Section 3
Technical Analyses
Exhibit 3-12, Estimates for PC Plant Mercury Removal with Conventional Controls
Post-combustion
Control Strategy
PM Control
Only
PM Control and
Spray Dryer
Absorber
PM Control and
Wet FGD
System(a)
Post-combustion
Emission Control
Device
Configuration
CS-ESP
HS-ESP
FF
PS
SDA+CS-ESP
SDA+FF
SDA+FF+SCR
PS+FGD
CS-ESP+FGD
HS-ESP+FGD
FF+FGD
Average Mercury Capture by Control
Configuration
Coal Burned in Pulverized-coal-fired Boiler
Bituminous
36%
9%
90%
not tested
not tested
98%
98%
12%
75%
49%
98%
Subbituminous
3%
6%
72%
9%
35%
24%
Not tested
0%
29%
29%
Not tested
Lignite
0%
not tested
not tested
not tested
not tested
0%
not tested
33%
44%
not tested
not tested
Notes: (a) Estimated capture across both control devices
CS-ESP = Cold side electrostatic precipitator
HS-ESP = Hot side ESP
FF = Fabric filter
PS = Particulate scrubber
SDA = Spray dryer absorber
SCR = Selective catalytic reduction
FGD= Wet limestone flue gas desulfurization (WL-FGD)
of capture at subbituminous and lignite plants are attributed to low coal chlorine content
and low fly ash carbon content and higher relative amounts of elemental mercury, instead
of oxidized mercury, in the flue gas.
Plants that only use particulate controls display average mercury emission reductions
ranging from 0 to 90 percent, with the highest levels of control achieved by fabric filters.
Mercury control at units equipped with SDA plus ESP or fabric filters ranges from 98
percent for bituminous coals to 24 percent for subbituminous coal. The relatively low
removal rates for subbituminous and lignite coals are attributed again to the small
amounts of oxidized mercury in the flue gas.
Mercury removal in units equipped with wet scrubbers is dependent on the relative
amount of oxidized mercury in the inlet flue gas and on the particulate control technology
used. Average removal in wet scrubbers ranged from 29 percent for one PC plant with a
hot-side ESP and subbituminous coal to 98 percent in a plant with a fabric filter and wet
3-18
-------
Section 3 Technical Analyses
scrubber burning bituminous coal. The high removal in this unit is attributed to increased
oxidization of the mercury and its capture in the fabric filter.
In general, mercury removal in PC units with SDA and WL-FGD appears to provide
similar levels of control on a percentage reduction basis. However, this observation is
based on a small number of short-term tests at a limited number of plants. The
subbituminous coals pose a special issue: The coal's mercury exists primarily as
elemental mercury, which remains a vapor in the flue gas and mostly passes through
FGD and SCR controls.
Unlike the technologies described above, where mercury removal is achieved as a
cobenefit with removal of other pollutants, injection of dry sorbent, specifically
powdered activated carbon (PAC), has been tested for mercury control at several coal-
fired utility plants in the U.S. These tests included short-term, full-scale tests, with the
PAC injected into the ductwork upstream of a particulate control device, such as an ESP
or fabric filter. Other short- and long-term tests are planned for the future. Results from
certain major tests using optimal PAC injection rates are summarized below:29
• Two PC boiler plants firing low-sulfur, bituminous coals: PAC injected upstream of
CS-ESPs captured approximately 94 percent mercury.
• PC boiler plant equipped with a HS-ESP and firing low-sulfur, bituminous coals:
PAC injected upstream of a small fabric filter (compact hybrid particle collector or
COPHAC) captured greater than 90 percent mercury.
• PC boiler plant firing high-sulfur, bituminous coals: PAC injected upstream of a CS-
ESP captured 73 percent mercury.
• PC boiler plant firing a subbituminous coals: PAC injected upstream of a CS-ESP
captured 65 percent mercury.
The above data show that mercury removal was higher with PAC injection for low-sulfur
bituminous coals than for subbituminous or high-sulfur bituminous coals. It is believed
that higher amounts of chlorine present in bituminous coals promote oxidation of
elemental mercury, thus facilitating its removal by PAC. Also, higher SOs content of
high-sulfur coal flue gas may interfere with the capture of mercury by PAC.
In addition to the above tests with conventional PAC, other short-term tests have also
been conducted using enhanced or halogenated PAC. The results from these tests show
more encouraging results, especially for low-rank coals, as explained below.29
29 Control Of Mercury Emissions From Coal-Fired Electric Utility Boilers( Including Update): Original
Report Dated 2-2002 and Update Dated 2-18-2005, U.S. EPA Office Of Research and Development,
Prepared by National Risk Management Research Laboratory Research Triangle Park, NC 27711.
3-19
-------
Section 3 Technical Analyses
• PC boiler plants firing subbituminous or blended subbituminous coals: halogenated
PAC injected upstream of CS-ESPs captured 80 to 94 percent mercury.
• PC boiler plant equipped with SDA and firing subbituminous coals: halogenated PAC
injected upstream of a fabric filter captured 93 percent mercury.
• PC boiler plant firing high-sulfur bituminous coals: halogenated PAC injected
upstream of a CS-ESP captured 70 percent mercury.
• PC boiler plant firing low-sulfur bituminous coals: halogenated PAC injected
upstream of a HS-ESP captured greater than 80 percent mercury.
• PC boiler plant equipped with SDA and firing lignite: halogenated PAC injected
upstream of a fabric filter captured 95 percent mercury.
Based on the above data, the following controls and mercury reduction levels were
assumed for this study (since the data are based on short-term test results, uncertainties
exist with the assumed reduction levels, and it is recognized that these levels may not be
attainable for all new PC plants in the time frame selected for the study):
• With bituminous coal cases, where WL-FGD, SCR, fabric filter, and wet ESP are
used, mercury removal is 90%.
• For subbituminous and lignite coals, the conventional controls reduce mercury by
70%. Activated carbon injection is added to achieve an overall 90% reduction.
The Federal NSPS require the following mercury emission limits for new PC plants (see
EPA website for specific requirements or any future changes to these requirements):30
- For PC plants firing bituminous coals: 20 x 10"6 Ib/MWh
- For PC plants firing sub-bituminous coals in county-level geographical areas
with greater than 25 inches/year mean annual rain: 66 x 10"6 Ib/MWh
- For PC plants firing sub-bituminous coals in county-level geographical areas
with less than or equal to 25 inches/year mean annual rain: 97 x 10"6 Ib/MWh
- For PC plants firing lignite: 175 x 10"6 Ib/MWh
Air Emission and Other Effluent Estimates for PC Plants
Exhibits 3-13, 3-14, and 3-15 list the environmental impact estimates for PC plants and
the three coals. The emission values for key air pollutants are provided in Ib/MMBtu,
Ib/MWh, and ppmvd at 15%O2. Lb/MWh values are based on MW gross. Following the
exhibits, there is a brief discussion of how the emission values were obtained.
30 Code of Federal Regulations, 40 CFR, Part 60, Subpart Da, hUp://www.cpa.gov/cpacfr40/chapl-
T.info/chi-loc.htm. accessed 7/6/06.
3-20
-------
Section 3
Environmental Impacts
Exhibit 3-13, Subcritical Pulverized Coal Plant Environmental Impacts
Subcritical PC
Air Pollutants
NOX (NO2) l
SO21
CO2
Volatile Organic Compounds2
Particulate Matter (overall) :
Particulate Matter (PM10) :
Lead (Pb) 2
Mercury
Acid Mist
Other Environmental
Impacts
COj1
Solid Waste (ash/FGD waste)
Raw Water Use
Sulfur Removal, %
Particulate s, Removal, %
ppmvd
@15%O2
14
15
39
Bituminous
Ib/MWh
0.528
0.757
0.880
0.021
0.106
0.106
3.40xlO'5
to 18xlO'5
6.69X10'6
0.088
Ib/MWh
1,777
176
9,260
98
99.8
Ib/MMBtu
0.06
0.086
0.10
0.0024
0.012
0.012
3.86.X10'6
to 20x1 0'6
0.76X10'6
0.010
Ib/MMBtu
202
20
1,050
(
ppmvd
@15%O2
15
11
40
subbituminous
Ib/MWh
0.543
0.589
0.906
0.025
0.109
0.109
IS.lxlO'5
to 23xO'5
3.80X10'6
0.018
Ib/MWh
1,893
73
9,520
87
99.7
Ib/MMBtu
0.06
0.065
0.10
0.0027
0.012
0.012
20xlO-6to
25.6X10'6
0.42X10'6
0.002
Ib/MMBtu
209
8
1,050
Ppmvd
@15%O2
20
10
55
Lignite
Ib/MWh
0.568
0.814
0.947
0.026
0.114
0.114
18.9xlO-5to
24x1 0'5
6.9X10'6
0.038
Ib/MWh
1,998
331
9,960
95.8
99.9
Ib/MMBtu
0.06
0.086
0.10
0.0027
0.012
0.012
20x1 0'6 to
25.6xlO'6
0.73X10'6
0.004
Ib/MMBtu
211
35
1,050
1. Calculated based on air permit data,
2. Estimated from review of air permit
discussions with equipment suppliers,
data.
literature, and process model software.
5-21
-------
Section 3
Environmental Impacts
Exhibit 3-14, Supercritical Pulverized Coal Plant Environmental Impacts
Supercritical PC
Criteria Pollutants
NOX (NO2) l
so,1
CO2
Volatile Organic Compounds2
Particulate Matter (overall) :
Particulate Matter (PM10) :
Lead (Pb) 2
Mercury
Acid Mist
Other Environmental
Impacts
COj1
Solid Waste (ash/FGD wastes)
Raw Water Use
Sulfur Removal, %
Particulate s Removal, %
ppmvd
@15% O2
14
15
39
Bituminous
Ib/MWh
0.494
0.709
0.824
0.020
0.099
0.099
3.18xlO'5
to 17xlO'5
6.26xlQ-6
0.082
Ib/MWh
1,665
165
8,640
98
99.8
Ib/MMBtu
0.06
0.086
0.10
0.0024
0.012
0.012
3.86.X10'6
to 20x1 0'6
0.76xlO-6
0.010
Ib/MMBtu
202
20
1,050
c.
ppmvd
@15%O2
15
11
40
jubbituminou
Ib/MWh
0.500
0.541
0.832
0.023
0.100
0.100
16.6xlO'5
to21xlO-5
3.49xlQ-6
0.017
Ib/MWh
1,739
67
8,830
87
99.7
s
Ib/MMBtu
0.06
0.065
0.10
0.0027
0.012
0.012
20xlO-6to
25.6X10'6
0.42xlO-6
0.002
Ib/MMBtu
209
8
1,060
ppmvd
@15%O2
14
7
39
Lignite
Ib/MWh
0.524
0.751
0.873
0.024
0.105
0.105
17.5xlO'5
to 22x1 0'5
6.37xlQ-6
0.035
Ib/MWh
1,842
306
9,200
95.8
99.9
Ib/MMBtu
0.06
0.086
0.10
0.0027
0.012
0.012
20xlO-6to
25.6X10'6
0.73xlO-6
0.004
Ib/MMBtu
211
35
1,055
1. Calculated based on air permit data, discussions with equipment suppliers, literature, and process model software.
2. Estimated from review of air permit data.
5-22
-------
Section 3
Environmental Impacts
Exhibit 3-15, Ultra Supercritical Pulverized Coal Plant Environmental Impacts
Ultra Supercritical PC
Criteria Pollutants
NOX (NO2) l
SO21
CO2
Volatile Organic Compounds2
Particulate Matter (overall) :
Particulate Matter (PM10) :
Lead (Pb) 2
Mercury
Acid Mist
Other Environmental
Impacts
COj1
Solid Waste (ash/FGD wastes)
Raw Water Use
Sulfur Removal, %
Particulates removal, %
Bituminous
ppmvd
@15%O2
14
15
39
Ib/MWh
0.442
0.634
0.737
0.018
0.088
0.088
2.84xlO'5
to 15xlO'5
5.60xlO'6
0.074
Ib/MWh
1,488
155
7,730
Ib/MMBtu
0.06
0.086
0.10
0.0024
0.012
0.012
3.86.X10'6
to 20x1 0'6
0.76X10'6
0.010
Ib/MMBtu
202
21
1,050
98
99.8
Subbituminous
ppmvd
@15%O2
15
11
40
Ib/MWh
0.450
0.488
0.750
0.020
0.090
0.090
IS.OxlO'5
to 19xlO'5
3.15X10'6
0.015
Ib/MWh
1,568
60
7,870
Ib/MMBtu
0.06
0.065
0.10
0.0027
0.012
0.012
20xlO-6to
25.6X10'6
0.42X10'6
0.002
Ib/MMBtu
209
8
1,050
87
99.7
Lignite
ppmvd
@15% O2
14
rj
39
Ib/MWh
0.498
0.714
0.830
0.022
0.100
0.100
16.6xlO'5
to 2 1x1 0'5
6.06X10'6
0.033
Ib/MWh
1752
291
8,710
Ib/MMBtu
0.06
0.086
0.10
0.0027
0.012
0.012
20xlO-6to
25.6X10'6
0.73X10'6
0.004
Ib/MMBtu
211
35
1,050
95.8
99.9
1. Calculated based on air permits, discussions with equipment suppliers, literature, and process model software.
2. Estimated from review of air permit data.
5-23
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Section 3 Environmental Impacts
The emissions from the PC units listed above were estimated from energy and material
balance calculations and other methods as noted below.
• The emission limits for various pollutants have generally been based on air permit
data (see Appendix B) and discussions with control technology suppliers.
• NOX is reduced through use of combustion controls and SCR. The emission rate is
estimated at 0.06 Ib per MMBtu for all the plants. These estimates use air permit
data, data from contacts with SCR suppliers, and data available from literature31.
• SC>2 is controlled by a WL-FGD for the bituminous coal and lignite. The estimated
removal rates are 98 and 95.8% for bituminous coal and lignite, respectively. The
subbituminous coal plants use lime SDA technology and the removal efficiency is
87%. The SC>2 removal rates selected for both technologies are from air permit data,
10 11
vendor contacts, and the literature ' . The SDA system treats flue gases originating
from a coal with a sulfur content of only 0.22%. Based on the air permit data (see
Appendix B), a controlled SC>2 emission rate of 0.065 Ib/MMBtu was selected for this
system, which results in the relatively low removal efficiency of 87%. With higher
coal sulfur content, higher removal efficiencies can be expected from the SDA system
of the type used in this study. Due to lack of recent data, the SC>2 mass emission rate
with lignite firing is assumed to be the same as for bituminous coal.
• CO emissions are controlled by good combustion practices and estimated by reviews
of the air permit data.
• The overall particulate matter and PMio removal rates approach 100% and removal
rates of 99.7 to 99.9% are used in this study, depending on the coal ash content and
based on utilizing fabric filters. These removal rates are from air permit data and
discussions with filter providers. The emissions rates include filterable particulate
matter only.
• Fine Particulate Matter (PM2.5) - no data was found for the fine particulate emissions.
• VOCs are controlled by good combustion practices, i.e. efficient and stable
combustion. The limits listed in the exhibit are from recent air permit data.
• Lead is estimated by review of recent air permit data. It is expected to vary
significantly based on site and fuel specifics, especially the coal lead content.
31 M. Oliva, et al., "Performance Analysis Of SCR Installations On Coal-Fired Boilers," Pittsburgh Coal
Conference, September 2005, Pittsburgh, PA.
32 Wet Flue Gas Desulfurization Technology Evaluation. Project Number 11311-000 Prepared for
National Lime Association by Sargent & Lundy, January 2003.
33 Dry Flue Gas Desulfurization Technology Evaluation. Project Number 11311-000 Prepared for
National Lime Association by Sargent & Lundy, September 2002.
3-24
-------
Section 3 Environmental Impacts
• Mercury limits are based on 90% removal within the controls provided specifically
for mercury removal and controls for other pollutants. The uncontrolled mercury
emissions are based on an assumed average mercury content of each coal type, which
was taken from a published source.34 The reported emissions will vary with the coal
mercury contents.
• Acid mist limits are based on 95% removal within the combined WL-FGD and wet
ESP systems and 90% removal in the lime SDA system.
• CC>2 emissions are calculated, and it is assumed that all the carbon in the coal is
converted to CC>2.
• Solid waste is calculated using the ash content of the coals and the FGD gypsum or
lime wastes.
• Water losses are calculated based on the USDOE/NETL report and Nexant' s
performance software.
3.4 Air Permit Data
35
Air permit data for the following facilities were examined. Information about a diversity
of technologies and coals was sought.
1. Elm Road, Wisconsin: Two 615 MW Supercritical Pulverized Coal (PC) Units
2. Comanche Generating Station Unit 3, Colorado: One 7,421 MMBtu/hr Supercritical
PC Unit
3. Longview Power, LLC, West Virginia: One 600 MW Subcritical PC Unit
4. Prairie State Generating Station, Illinois: Two 750 MW Subcritical PC Units
5. Intermountain Power Generating Station Unit 3, Utah: One 900 MW Subcritical PC
Unit
6. Indeck-Elwood Energy Center, Illinois: Two 330 MW Circulating Fluidized Bed
(CFB) Boiler Units
7. Plum Point Energy Station, Arkansas: One 550-800 MW PC Unit
8. Thoroughbred Generating Station, Kentucky: Two 750 MW PC Units
9. TS Power Plant, Nevada: One 200 MW PC Unit
10. Santee Cooper Cross Generating Station Units 3 and 4, South Carolina: Two 5,700
MMBtu/hr PC Units
11. Holocomb Unit 2, Kansas: One 660 MW PC Unit
12. Limestone Electric Generating Station Units 1 and 2, Texas: Two 7,863 MMBtu/hr
PC Units
34 Coal Analysis Results, lUtp://www.cpa.gov/Un/at\v/combusl/uliltox/utoxpg.html#DA2. accessed on
February 21, 2006.
35 Power Plant Water Usage and Loss Study. U.S. DOE NETL, August 2005.
3-25
-------
Section 3
Environmental Impacts
13. Elm Road, Wisconsin: One 600 MW IGCC Unit
14. Kentucky Pioneer Energy Facility, Kentucky: One 540 MW IGCC Unit
15. Polk Power Station, Florida: One 260 MW IGCC Unit
16. Southern Illinois Clean Energy Center, Illinois: One 544 MW IGCC Unit
17. Cash Creek, Kentucky: One 677 MW IGCC Unit
Appendix B provides a detailed list of data from the permit documents for the above-
listed facilities on air emission limits for the criteria and non-criteria pollutants. It also
lists these permit documents. The following sections summarize these data.
3.4.1 Criteria Pollutants
Exhibit 3-16 summarizes the data from the permit documents on criteria pollutants. The
data point column shows the number of plants for that type of plant and fuel which were
reviewed. Data points in the third and last rows document how many of the pollutants
were regulated in the permits. For example, all five PC unit permits had data for NOX,
SO2, CO and overall particulates; only four permits provided PMio data, and none
specified PM2 5 limits.
Exhibit 3-16, Air Permit Data and Estimates for Criteria Pollutants
Pounds per Million Btu (except lead)
Data
Points
6
5
1
12
1
Fuel (some
plants may use
more than one,
or blend)
PC Units
Bituminous
Coal
PC Units
Subbituminous
Coal
PC Units
Lignite
Data Points
All Pulverized
Coal Units
High Sulfur
Bituminous
Coal
CFB Unit
Nitrogen
Oxides
(NOx)
0.07 to
0.08
0.067 to
0.09
0.5
12
0.10
Sulfur
Dioxide
(S02)
0.1 to
0.182(95
to 98%
reduction)
0.065 to
0.12 (one
unit with
94%
reduction)
0.82
12
0.15
Carbon
Monoxide
(CO)
0.1 to
0.16
0.13 to
0.16
0.11
12
0.10
Paniculate
Matter
(overall)
0.012 to
0.018
0.012 to
0.020
0.03
10
0.015
Paniculate
Matter
(PM10)
0.018
0.012 to
0.020
No Data
9
No Data
Fine
Paniculate
Matter
(PM25)
No Data
No Data
No Data
0
No Data
Lead
(Pb)
lb/1012
Btu
3.86
to 20
20 to
25.6
33
9
No
Data
3-26
-------
Section 3
Environmental Impacts
Exhibit 3-16, Air Permit Data and Estimates for Criteria Pollutants
Pounds per Million Btu (except lead), Cont'd
Data
Points
5
5
Fuel (some
plants may use
more than one,
or blend)
IGCC Units
Bituminous
Coal
Data Points
IGCC Units
Nitrogen
Oxides
(NOx)
0.055 to
0 10
(15 to 25
ppmvd@
15%O2)
5
Sulfur
Dioxide
(S02)
0.03 to
0.17(97
to 99.36%
reduction)
5
Carbon
Monoxide
(CO)
0.03 to
0.046
5
Paniculate
Matter
(overall)
0.007 to
0.011
5
Paniculate
Matter
(PM10)
0.007 to
0.011
5
Fine
Paniculate
Matter
(PM25)
No Data
Q
Lead
(Pb)
lb/1012
Btu
1.0 to
25.7
4
3.4.2 Non-Criteria Pollutants
Much less data was found in the literature to help estimate the environmental impacts of
non-criteria pollutants. Data from recent power plant air permits were selected as a
primary source of data. While permit limits can vary across States and may depend upon
site- and fuel-specific considerations, relatively consistent values were found in the air
permit data. The results are summarized in Exhibit 3-26 at the end of Section 3.
3.5 Emission and Air Pollution Control Data from the Literature
A reference list is included at the end of the report. Several of the most recent and useful
documents are discussed here. Exhibit 3-17 is a helpful summary from a December 2002
U.S. DOE/NETL report. While the technologies are still developing and changing, the
information is a good summation of IGCC and PC plant environmental impacts.
Exhibit 3-17 Summary of IGCC and PC Environmental Controls
,36
Integrated Gasification Combined Cycle
Pulverized Coal Power Plant
Sulfur Control
and Sulfur
Byproducts
Greater than 98% sulfur control. H2S and COS are
removed from the syngas in an amine-based
scrubber prior to combustion and recovered as
elemental sulfur or sulfuric acid. Both are salable
industrial commodities.
Up to 98% sulfur control. SO2 is
usually removed in a flue gas
desulfurization process, such as a wet
limestone scrubber. Advanced
limestone FGD scrubbers typically
produce a gypsum byproduct. Gypsum
can be safely landfilled or sold for
production of wallboard or utilized for
other purposes.
36 Major Environmental Aspects of Gasification-Based Power Generation Technologies. Final Report by:
Jay Ratafia-Brown, Lynn Manfredo, Jeffrey Hoffmann, & Massood Ramezan for National Energy
Technology Laboratory, U.S. Department of Energy, December 2002.
3-27
-------
Section 3
Environmental Impacts
Exhibit 3-17 Summary of IGCC and PC Environmental Controls, Cont'd
Nitrogen Oxides
Control
Fuel nitrogen mainly converted to N2 and small
amount of NH3 and HCN, with the latter removed
via syngas cleaning. Diluents, such as nitrogen and
steam, are used in the gas turbine to lower the
combustion flame temperature to minimize NOX
generation. Use of add-on control technologies,
such as SCR, at this time has not been
demonstrated for coal-based syngas-fired turbines.
Fuel nitrogen converted to NOX. Low-
NOX burners are used to minimize
conversion to NOX. The NOX formed
may be removed with additional
control technology, such as SCR. SCR
unit can be installed between
economizer and air heater. NH3
preferentially adsorbs onto fly ash.
Sulfates and bisulfates captured in
paniculate control equipment
downstream of SCR.
Paniculate
Control
Virtually all paniculate is removed. Fly ash
entrained with syngas is removed downstream in
wet scrubber. No acid mist problem.
Very high levels of paniculate control.
Fly ash is efficiently collected in a
control device, such as an ESP or
fabric filter. Acid mist may be a
problem from FGD unit. A wet ESP
can be installed downstream of the
FGD to remove acid mist.
Trace Substance
Control (metals
and organics)
Most semi-volatile and volatile trace metals
condensed and removed in syngas cleaning
equipment. Elemental mercury emissions may exit
with flue gas. Other metals exit with wastewater
blowdown and wastewater treatment material.
Trace organic emissions are extremely low.
Activated carbon beds have been commercially
demonstrated to remove more than 90% of syngas
mercury.
Most semi-volatile and volatile trace
metals condense on fly ash particles
and are effectively removed with fly
ash. Elemental mercury emissions
may exit with flue gas. Other elements
exit with ash and FGD byproduct.
Trace organic emissions are extremely
low. Hg emissions may depend on
coal type and presence of FGD.
system. Activated carbon injection
upstream of a fabric filter can be
added to remove 90% of mercury.
Solid Waste
Disposal/
Utilization
Slag material is environmentally benign and can
be safely landfilled. Slag can also be safely
utilized for various applications, such as drainage
material or roofing granules. Similar to material
produced by wet-bottom PC plants.
Bottom ash and fly ash can be safely
landfilled. Leaching of trace metals
adsorbed by fly ash is more likely than
with slag material. Ash can be utilized
for a variety of applications, such as
cement/concrete production and waste
stabilization or solidification.
Carbon Dioxide
Control Potential
Higher thermodynamic efficiency of IGCC cycle
minimizes CO2 emissions relative to other
technologies. High pressure and high CO2
concentration in synfuel provides optimum
conditions for CO2 removal prior to combustion, if
required.
Generally higher CO2 emissions than
IGCC due to lower cycle efficiency.
CO2 removal from flue gas more
technically challenging and more
expensive than IGCC, based on
existing technology.
3-28
-------
Section 3
Environmental Impacts
Exhibit 3-18 compares IGCC and PC plant emission projections from various literature sources.
Exhibit 3-18, Emission Data from the Literature
Pollutant
S02
NOX (as NO2))
PM10,
Paniculate and
Sulfuric Acid
Mist
C02
Hg
IGCC Plant37
0.08
Ib/MMBtu
0.7 Ib/MWh
0.09
Ib/MMBtu
0.8 Ib/MWh
O.015
Ib/MMBtu
<0.141b/MWh
PC Plant38
0.3 Ib/MMBtu
0.09 Ib/MMBtu
0.03 Ib/MMBtu
2.0 Ib/kWh
80 - 90% removal
EPRI Report
PC and IGCC
Plants39
99.5% removal
15 to 20
ppmvd
0.004
Ib/MMBtu or
less
Generic
IGCC
Plant40
0.08
Ib/MMBtu
0.06
Ib/MMBtu
0.006
Ib/MMBtu
1.76-1.6
Ib/kWh
90 - 95%
removal
3.6 PC Solid Wastes and Liquid Effluents
Estimates of solid wastes are summarized in Exhibit 3-19 for the PC plants and coals.
Estimated values are shown in terms of pounds per hour and per million Btu of coal
input. Estimates for the coal-ash wastes are relatively clear and leave little uncertainty;
except for adjustments for unburned carbon and the small amounts of ash that are not
captured, coal ash wastes are approximately "coal ash in = coal ash out".
37 R. Brown, et al., "An Environmental Assessment of IGCC Power Systems," 19th Annual Pittsburgh Coal
Conference, September 2002.
38 D. Radcliffe, "IGCC- An Important Part of Our Future Generation Mix," Workshop on Gasification
Technologies, Knoxville, TN, April 12, 2005.
39
Pulverized Coal And IGCC Plant Cost And Performance Estimates, George Booras & Neville Holt
EPRI, Gasification Technologies 2004, Washington, DC, October 3-6, 2004.
40 Major Environmental Aspects of Gasification-Based Power Generation Technologies. Final Report by:
Jay Ratafia-Brown, Lynn Manfredo, Jeffrey Hoffmann, & Massood Ramezan for National Energy
Technology Laboratory, U.S. Department of Energy, December 2002.
3-29
-------
Section 3
Environmental Impacts
Exhibit 3-19, PC Plant Solid Waste Estimate
PC Technology
500 MW Net
Study Coal
Sulfur Control
UNITS
Total Coal Ash
Bottom Ash
Fly Ash (with
unburned carbon)
Desulfurization
Products -dry basis
Total Solid Waste
UNITS
Total Coal Ash
Bottom Ash
Fly Ash (with
unburned carbon)
Desulfurization
Products -dry basis
Total Solid Waste
Subcritical Boiler
High Sulfur
Bituminous
WL-FGD
Ibs/hr dry
40,674
8,427
33,707
54,086
96,220
Ib/MMBtu
8.6
1.8
7.1
11.4
20.3
Low Sulfur
Sub-
Bituminous
SDA+ Filter
Ibs/hr dry
25,168
5,421
With SDA
Filter Waste
34,656
40,077
Ib/MMBtu
5.1
1.1
With SDA
Filter Waste
7.1
8.2
Lignite
WL-FGD
Ibs/hr dry
146,537
29,738
118,461
30,741
Supercritical Boiler
High Sulfur
Bituminous
WL-FGD
Ibs/hr dry
38,104
7,894
31,132
51,802
178,940 90,828
Ib/MMBtu
28.5
5.8
23.0
6.0
Ib/MMBtu
8.6
1.8
7.0
11.6
34.7 20.4
Low Sulfur
Sub-
Bituminous
SDA+ Filter
Ibs/hr dry
23,370
5,034
With SDA
Filter Waste
32,181
37,215
Lb/MMBtu
5.1
1.1
With SDA
Filter Waste
7.1
8.2
Lignite
WL-FGD
Ibs/hr dry
135,155
27,428
109,260
29,432
Ultra Supercritical Boiler
High Sulfur
Bituminous
WL-FGD
Ibs/hr dry
34,252
7,096
27,985
49,395
166,120 84,476
Ib/MMBtu
28.5
5.8
23.0
6.2
Ib/MMBtu
8.6
1.8
7.0
12.3
35.0 21.1
Low Sulfur
Sub-
Bituminous
SDA+ Filter
Ibs/hr dry
20,802
4,481
With SDA
Filter Waste
28,644
33,125
Ib/MMBtu
5.1
1.1
With SDA
Filter Waste
7.1
8.2
Lignite
WL-FGD
Ibs/hr dry
129,465
26,273
104,660
28,066
158,999
Ib/MMBtu
28.5
5.8
23.0
6.2
34.9
-------
Section 3 Environmental Impacts
Waste estimates from the two sulfur removal processes are more uncertain and dependent
on the amounts of limestone or lime used to capture the sulfur, and other engineering
factors. The estimates here are calculated by Nexant's PC plant process model.
The solid wastes generated from PC plants have several industrial uses, including
gypsum wallboard, cement additive, concrete admixture, flowable fill material,
autoclaved aerated concrete blocks, waste stabilization, roadway/runway construction,
mine reclamation, and agriculture applications. The salability of each of the four
different types of PC solid wastes, including fly ash, bottom ash, gypsum from the wet
FGD system, and waste from the dry FGD system, generally depends on whether a
market exists for its use near the plant. If any of these wastes cannot be sold, they would
typically be disposed off in an on-site or off-site landfill.
Experience from existing coal-fired plant operations in the U.S. shows that some of these
plants are able to sell their solid waste products for industrial use, especially fly ash and
FGD gypsum41. The reported data show that while 20 percent of these plants sold fly
ash, only 16 percent were able to sell bottom ash. Similarly, 26 percent of the 268 units
equipped with wet FGD systems sold their gypsum, while only 5 percent of the 234 units
equipped with dry FGD systems were able sell their FGD wastes. For the purpose of this
study, no credit has been taken for the sale of any solid wastes, since the data show the
majority of the plants disposing of their wastes in landfills.
There are several on-going programs in the industry to encourage use of coal combustion
and FGD products. As an example, government organizations, such as EPA and DOE,
have formed partnerships with other government and industry stakeholders to increase
the amount of coal byproduct utilization.42 A future increase in the use of solid wastes
generated from the PC plants can be expected. Such an increase would result in a
reduction of the solid waste volumes required to be landfilled.
A report from DOE examines in relative detail the water usage and losses at PC and
IGCC plants.43 The DOE report is used here as the basis for water balance assessments.
It is noted however that water balances vary significantly because of raw water quality
and design criteria, such as the number of cycles for the cooling tower water to be
circulated. The number of cooling water cycles may vary from 2 to 6 cycles, which by
itself can strongly impact the amounts of makeup water required. The DOE report
assumes 3 cycles for PC and IGCC cooling water systems and thus provides a consistent
source of data for comparison.
41 EIA website, EIA-767 Data Files for 2004, http://www.eia.doe.gov/cneaf/electricity/page/eia767.html.
accessed January 27, 2006.
42 U.S. EPA Coal Combustion Products Partnership,
www.cpa.gov/cpaoswcr/osw/conscrvc/c2p2/indcx.Mm. accessed February 14, 2006.
43 Power Plant Water Usage and Loss Study. U.S. DOE NETL, August 2005.
3-31
-------
Section 3
Environmental Impacts
The DOE water study is for nominal 500 MW PC and IGCC plants. This study examines
GE Energy, ConocoPhillips and Shell gasification, and subcritical and supercritical PC
plants. A high sulfur bituminous coal (Pittsburgh #8 seam) is used for all the plants. The
study does not examine an ultra-supercritical technology plant.
For reference, the subcritical and supercritical plant water balance estimates are presented
(with rounding) from the DOE study in Exhibit 3-20.
Exhibit 3-20, Summary of PC Plant Water Balances
U.S. DOE/NETL Study Results
Plant Gross Output, MW
Plant Net Heat Rate (HHV),
Btu/kWh
Water Source
Coal Moisture
Conversion of Coal Hydrogen
Combustion Air Moisture
AirtoWLFGD
Raw Water Use
TOTAL
Water Loss
Flue Gas Exhaust
Water with FGD Gypsum
Cooling Tower Evaporation
Cooling Tower Blowdown
TOTAL
Subcritical PC
554
9,638
Supercritical PC
550
8,564
Flowrate, Gallon per Minute
48
326
63
0.4
10,146
10,584
928
81
6,415
3,160
10,584
43
288
57
0.3
8,990
9,378
818
71
5,688
2,801
9,378
The water balance estimates for the present study PC plants and coals are shown in
Exhibit 3-21. In these estimate, the cooling tower losses from evaporation and blowdown
are by far the largest. Evaporative losses basically correspond to the size of the steam
generation system, and blowdown is required periodically to limit the buildup of solids
and other contaminants in the water system. Blowdowns from all the other parts of the
plant, being relatively uncontaminated, are used as part of the cooling water makeup.
Notes on the estimating procedures used with Exhibit 3-21 are listed below.
• Coal Moisture is calculated from the properties of each study coal.
• Conversions of Coal Hydrogen, Combustion Air Moisture, and Air to WL-FGD are
calculated using the heat rate and gross output adjustment factors of the U.S. DOE
study and the present study to estimate water flowrates.
3-32
-------
Section 3
Environmental Impacts
Exhibit 3-21, Estimated Water Balances for PC Plants and Coals
Gallon per Minute
PC Technology
500 MW Net
Study Coal
Plant Gross Output, MW
Plant Net Heat Rate (HHV),
Btu/kWh
Water Source
Coal Moisture
Conversion of Coal Hydrogen
Combustion Air Moisture
AirtoWLFGD
Raw Water Use
TOTAL
Water Loss
Flue Gas Exhaust
Water with FGD Gypsum
Spray Dry Absorption
Evaporation
Cooling Tower Evaporation
Cooling Tower Blowdown
TOTAL
Subcritical Boiler
High Sulfur
Bituminous
540
9,500
94
313
61
0.4
9,701
10,169
892
78
6,163
3,036
10,169
Low Sulfur
Sub-
Bituminous
541
9,800
318
324
63
-
9,772
10,477
922
48
6,369
3,138
10,477
Lignite
544
10,300
531
342
66
0.4
10,168
11,107
974
85
6,732
3,316
11,107
Supercritical Boiler
High Sulfur
Bituminous
540
8,900
88
294
58
0.3
9,129
9,569
835
72
5,804
2,858
9,569
Low Sulfur
Sub-
Bituminous
541
9,000
295
298
59
-
9,015
9,667
846
46
5,880
2,895
9,667
Lignite
544
9,500
490
316
63
0.3
9,421
10,290
898
78
6,241
3,073
10,290
Ultra
High Sulfur
Bituminous
543
8,000
79
266
53
0.3
8,251
8,649
754
66
5,246
2,583
8,649
Supercritical Boiler
Low Sulfur
Sub-
Bituminous
543
8,146
263
271
54
-
8,196
8,784
768
44
5,342
2,630
8,784
Lignite
546
9,065
469
303
60
0.3
9,023
9,855
860
75
5,977
2,943
9,855
-------
Section 3
Environmental Impacts
• Flue Gas Exhaust, Water with FGD Gypsum, Cooling Tower Evaporation, and
Cooling Tower Blowdown are similarly calculated by the heat rate and gross output
relationships.
• Spray Dry Absorption Evaporation is estimated from the process material balance
sheets for the subbituminous coal cases.
• Raw Water is calculated as the difference between the total of water sources and the
total of water losses in the items above.
The final PC plant blowdown/waste stream is typically sent to a pond or other
evaporation system or is discharged to an outside source, after proper treatment. After
evaporation, the remaining solid materials are secured in place or may be disposed off in
other ways. Some of the water may be used for dust control or other plant operations,
depending on the water quality.
3.7 IGCC Solid Wastes and Liquid Effluents
Exhibit 3-22 shows estimates of the IGCC plant solid wastes. The wastes are estimated
by calculations in Nexant's gasification model. The gasifier slag consists of the coal ash,
unburned carbon or char left with the ash. The sulfur product may or may not be a waste
depending on the plant's ability to market and sell the sulfur. The gasifier slag can also
be sold for industrial use, such as to cement industry. However, it is shown as a waste
product in Exhibit 3-22.
Exhibit 3-22, IGCC and Supercritical PC Solid Wastes
Gasification
Technology
Study Coal
Unit Rating MW Net
Gross Generation MW
Net Efficiency %
UNITS
Gasifier Slag
Sulfur Product
UNITS
Gasifier Slag
Sulfur Product
Slurry Fed
Gasifier
High Sulfur
Bituminous
500
564
41.8
Ibs/hr, dry
36,054
8,679
Ib/MMBtu
8.8
2.1
Slurry Fed
Gasifier
Low Sulfur
Sub-Bituminous
500
575
40
Ibs/hr, dry
25,185
1,044
Ib/MMBtu
5.9
0.2
Dry Fed
Gasifier
Lignite
500
580
39.2
Ibs/hr, dry
124,099
4,370
Ib/MMBtu
28.5
1.0
Supercritical PC Total Solid Waste
High
Sulfur
Bituminous
Ibs/hr, dry
96,220
Ib/MMBtu
20.3
Low Sulfur
Sub-
Bituminous
Ibs/hr, dry
40,077
Ib/MMBtu
8.2
Lignite
Ibs/hr, dry
178,940
Ib/MMBtu
34.7
The three columns on the right show the supercritical PC plant total waste estimates. In
comparison with the supercritical PC plants, the gasifier slag is approximately 40%, 60%
and 80% by weight of the total solid PC wastes for bituminous, subbituminous and lignite
3-34
-------
Section 3
Environmental Impacts
coals respectively. However, it should be noted that this difference in the solid waste
volumes would be reduced or eliminated, if the plants are able to sell some or most of
their wastes for industrial use.
Consistent with the PC plants, the water balance is estimated for IGCC plants using the
DOE report as the basis.44 Exhibit 3-23 presents the results for two gasifiers from the
DOE report. The results are rounded, and in the GE Energy case the DOE totals did not
match. The GE Energy DOE case is for the radiant-convective gasifier option. The
alternative GE quench technology is a less efficient, lower cost version of the technology,
which was not used.
Exhibit 3-23, Summary of IGCC Plant Water Balances
U.S. DOE/NETL Study Results
Plant Gross Output, MW
Plant Heat Rate (HHV) , Btu/kWh
Water Source
Coal Moisture
Combustion of Hydrogen in GT
Combustion of Hydrogen in Incinerator
Combustion Air for GT
Combustion Air for Incinerator
Raw Water Use
TOTAL
Water Loss
Coal Drying Moisture
Gasification Shift
Ash Handling Blowdown
Water With Slag
COS Hydrolysis
GT Flue Gas
Incinerator Flue Gas
Sour Water Blowdown
Water Treatment Discharge
Cooling Tower Blowdown
Cooling Tower Evaporation
Hot Water Blowdown
Moisture in Air Separation Vent
TOTAL
GE Energy
673.85
8,668
Shell
633.54
8,503
Gallon per Minute
48
483
NA
78
21
7,143
7,772
NA
159
80
32
0.3
743
NA
NA
5
2,222
4,511
10
21
7,782
44
332
17
84
0.7
6,668
7,145
30
54
70
33
2
675
14
41
NA
2,055
4,172
NA
NA
7,144
44
Power Plant Water Usage and Loss Study. U.S. DOE NETL, August 2005.
3-35
-------
Section 3
Environmental Impacts
Exhibit 3-24 presents the water balances for the present study IGCC technologies and
coals. Consistent with the PC plant estimates, the DOE data was adjusted using the heat
rates and gross outputs of the several plants. Coal moisture and for Shell, coal drying
moisture, is based on the study coal properties.
Exhibit 3-24, Estimated Water Balances for IGCC Plants and Coals
Gallon per Minute
Gasification Technology
Study Coal
Plant Gross Output, MW
Plant Heat Rate Btu/kWh
Water Source
Coal Moisture
Combustion of Hydrogen in GT
Combustion of Hydrogen in Incinerator
Combustion Air for GT
Combustion Air for Incinerator
Raw Water Use
TOTAL
Water Loss
Coal Drying Moisture
Gasification Shift
Ash Handling Blowdown
Water With Slag
COS Hydrolysis
GT Flue Gas
Incinerator Flue Gas
Sour Water Blowdown
Water Treatment Discharge
Cooling Tower Blowdown
Cooling Tower Evaporation
Hot Water Blowdown
Moisture in Air Separation Vent
TOTAL
Slurry Fed
Gasifier
High Sulfur
Bituminous
564
8,167
Slurry Fed Gasifier
Low Sulfur Sub-
Bituminous
575
8,520
Dry Fed Gasifier
Lignite
580
8,707
Gallon per Minute
81
381
NA
62
17
5,596
6,137
276
405
NA
65
18
5,764
6,528
449
311
16
79
0.7
6,119
6,975
NA
125
63
25
0.2
586
NA
NA
4
1,752
3,557
8
17
6,137
NA
133
67
27
0.3
623
NA
NA
4
1,864
3,784
8
18
6,528
305
51
66
31
2
633
13
38
NA
1,926
3,910
NA
NA
6,975
In comparison with the supercritical PC units, the IGCC water loss is only about 64 to
68% as great, or a saving of about 32 to 36%. Exhibit 3-25 summarizes the losses for the
two technologies and the percent ratio of IGCC to the supercritical PC plant water loss.
3-36
-------
Section 3
Environmental Impacts
Exhibit :
i-25, Summary Comparison of IGCC and Supercritical PC Water Losses
Supercritical PC,
Water Loss GPM
IGCC Water Loss,
GPM
Percent
IGCC/SCPC
Bituminous
9,569
6,137
64%
Subbituminous
9,667
6,528
68%
Lignite
10,290
6,975
68%
Exhibit 3-26 presents the air permit data collected and used during the study.
3-37
-------
Section 3
Environmental Impacts
Exhibit 3-26, Non-Criteria Pollutant Estimates, Air Permit Data (1 of 3 Tables)
Data
Points
6
5
1
12
1
5
5
Fuel (some plants may
use more than one coal,
or blend)
PC Units
Bituminous Coal
PC Units
Subbituminous Coal
PC Units
Lignite
Data Points All
Pulverized Coal Units
High Sulfur Bituminous
Coal
CFB Unit
IGCC Units
Bituminous Coal
Data Points IGCC Units
Mercury (Hg)
0.14 to 3.2
Ib/TBtu
0.45 to 13.1
Ib/TBtu
511b/TBtu
10
0.000002
Ib/MMBtu
0.55 to 1.9
Ib/trillion Btu
5
Volatile
Organic
Compounds
(VOC)
0.0024 to
0.004
Ib/MMBtu
0.0027 to
0.02
Ib/MMBtu
0.0067
Ib/MMBtu
11
0.004
Ib/MMBtu
0.0017 to
0.006
Ib/MMBtu
5
Chlorides
(HC1)
0.0001 to
0.0042
Ib/MMBtu
0.00064 to
0.0131
Ib/MMBtu
0.0155
Ib/MMBtu
10
0.006
Ib/MMBtu
0.00112
Ib/MMBtu
1
Fluorides
(HF)
0.0001 to
0.00088
Ib/MMBtu
0.00049 to
1.17
Ib/MMBtu
0.01
Ib/MMBtu
10
No Data
0.000092
Ib/MMBtu
1
Sulfur
Trioxide
(S03)
No Data
No Data
No Data
0
No Data
No Data
0
Hydrogen Reduced
Sulfide sulfur
(H2S) compounds
XT _. t 0.00073
No Data ,, „. „ _.,_
Ib/MMBtu
XT _. . 0.00073
No Data „» „ m .
Ib/MMBtu
No Data No Data
0 1
No Data No Data
No Data No Data
0 0
Ammonia
(NH3)
5 ppm
No Data
No Data
1
No Data
No Data
0
-------
Section 3
Environmental Impacts
Exhibit 3-26, Non-Criteria Pollutant Estimates, Air Permit Data (2 of 3 Tables)
Data
Points
6
5
1
12
1
5
5
Fuel (some plants may
use more than one coal,
or blend)
PC Units
Bituminous Coal
PC Units
Subbituminous Coal
PC Units
Lignite
Data Points All
Pulverized Coal Units
High Sulfur Bituminous
Coal
CFB Unit
IGCC Units
Bituminous Coal
Data Points IGCC Units
. . ,. . Beryllium Manganese
Arsenic (As) ,-L . ,,B, .
v ' (Be) (Mn)
i\ ooo i £• rvrv 0.35 tO 12.3 tO
0.883 to 5.99 l ^ 2Q ^
lb/TBtu lb/TBtu lb/TBtu
25.0 lb/TBtu ,, ^ iJi^l
lb/TBtu lb/TBtu
22.0 lb/TBtu ,, ?£. ,, ]^.
lb/TBtu lb/TBtu
3 63
No Data No Data No Data
0.457 to 6.0 °'°6^ t0 4.0 to 7.02
lb/TBtU lb/TBtu lb/TBtU
3 32
Cadmium
(Cd)
0.365 to
1.1
lb/TBtu
3.1
lb/TBtu
7.6
lb/TBtu
3
No Data
0.415 to
5.0
lb/TBtu
2
Chromium _ . , . , Nickel
(Cr) Formaldehyde (M)
lb/TBtu ' tU lb/TBtu
16.67 15.48 16.67
lb/TBtu lb/TBtu lb/TBtu
6.2 lb/TBtu Not Data ^
3 22
No Data No Data J^*
Data
,,,,,.„ 4.51 to
il™ NoData 31°
lb/TBtu lb/TBtu
2 02
Silica (Si)
No Data
No Data
No Data
0
No Data
No Data
0
-------
Section 3
Environmental Impacts
Exhibit 3-26, Non-Criteria Pollutant Estimates, Air Permit Data (3 of 3 Tables)
Data
Points
6
5
1
12
1
5
5
Fuel (some plants
may use more than
one coal, or blend)
PC Units
Bituminous Coal
WetFGD
PC Units
Subbituminous Coal
Spray Dryer
PC Units
Lignite
Data Points All
Pulverized Coal Units
High Sulfur
Bituminous Coal
CFB Unit
IGCC Units
Bituminous Coal
Data Points IGCC
Units
Selenium Vanadium
(Se) (V)
48.54 XT _ t
Ib/TBtu N°Data
No Data No Data
1,370 267.0
Ib/TBtu Ib/TBtu
2 1
No Data No Data
1.4 to 12.5 XT _ .
,, __. No Data
Ib/TBtu
2 0
Total Reduced
Sulfur (TRS)
0.00073
Ib/MMBtu
0.00073
Ib/MMBtu
No Data
1
No Data
No Data
0
_. . . Sulfuric acid mist
°PaClty emissions
10 to 0.0044 to 0.014
20% Ib/MMBtu
0.0042 to
10% 0.0061
Ib/MMBtu
15% No Data
5 10
20% No Data
„ . 0.0005 to
^ 0.0042
Ib/MMBtu
3 3
5-40
-------
Section 4 Special Studies
Section 4 presents two special studies which consider the IGCC technology. The first
study examines the option for including a SCR with the syngas turbine to improve NOx
control; the second examines ultra-low sulfur removal with physical solvents such as
Selexol and Rectisol. The present study is a "snapshot" of the technologies at one point
of time. The limits on operating experience and data for the SCR technology with IGCC
synthesis gas and the potential for cost variations are documented in this section and
other parts of the report. It is emphasized that any decision about SCR use and the
systems required to implement that use will require detailed site-specific engineering and
process design to optimize economic tradeoffs and the overall emissions including a
balance between gas turbine NOx and ammonia from the SCR. The choice between
MDEA, Selexol, and Rectisol in the context of SCR for the synthesis gas is uncertain
until more experience and more detailed engineering is available. This report does not
express a view as to whether or when such technologies should be required in permits to
construct and operate IGCC facilities.
4.1 Technical and Economic Assessment of SCR for Gasification Combined
Cycle NOX Control
The NOx emissions from syngas-burning gas turbines are in the range of 15 to 18 ppmvd,
considering the use of steam and nitrogen for diluents in the combustion process.45 Based
on this and other investigations, this study assumed 15 ppmvd as the current maximum
achievable limit, for modeling purposes, but takes no position on whether this level
should be required in any particular permit. GE is currently in the process of modifying
the combustor design, which could lower the level of NOx emission to upper single digit
ppmvd. If a lower emission level is required, e.g., in the two to three ppmvd range, then
it would only be achievable through the use of a post-combustion control method, such as
SCR.
Informal discussions with SCR providers confirm that the SCR system could reduce NOX
emissions from the IGCC system to about three ppmvd without a major impact on other
IGCC performance. This study uses three ppmvd as the maximum achievable limit for
syngas turbines with SCR, but takes no position on whether this level should be required
in any particular permit. Sulfur content in the syngas is a concern for SCR installations
and from the discussions with SCR suppliers, acceptable sulfur content at the inlet of the
SCR would be in the 15 to 20 ppmvd range or lower. A high efficiency sulfur removal
process, such as Selexol, can achieve this level provided there is a COS Hydrolysis Unit
upstream. If a SCR is not used, the suppliers recommend sulfur content around 40 ppmvd
is acceptable in the syngas for the combined cycle. Without a SCR, the sulfur content
limit will depend on the HRSG design exit temperature and other factors that could cause
corrosion or fouling in the cool, back end of the HRSG. The base case MDEA process
should be able to limit the syngas sulfur content to 40 ppmvd. The MDEA process is also
the least costly option and thus more likely to be acceptable from an economic
standpoint.
45 Discussions between Nexant and GE Energy, July 2005.
4-1
-------
Section 4 Special Studies
There are no existing coal-fired IGCC plants with SCR installed. The Japanese have a
ConnocoPhillips based IGCC fueled by refinery bottoms (asphalt) that does include a
SCR with the combined cycle. Several recent studies have reported and the consolidated
results indicate that the SCR would increase total NOx removal and lower the emissions
from about 15 to three ppmvd.46' 47
PC Plant Note on SCR
In telephone discussions for this study (9/2005) with Babcock and Wilcox (B&W), they
indicated a demonstrated peak NOx removal efficiency of 95% at an undisclosed PC
plant, which is significantly different than the gasification combined cycle conditions. In
the same discussion B&W also provided estimates of costs for the SCR ranging from $80
to $90/kW installed at a greenfield PC plant, and $90 to $175/kW for a retrofit
installation.
4.1.1 Combustion NOx Control Technologies
Although NOx emissions from operating IGCC power plants are quite low, stricter
regulations may require control to lower levels. Available combustion-based NOx
control options for syngas-fired turbines are more limited than those available for natural
gas-fired turbines. Differences between syngas and natural gas composition and
combustion characteristics cause the dry low-NOx (DLN) technology, which permits the
natural gas-fired turbines to achieve emissions as low as nine ppmvd (at 15% 02), to be
inapplicable to IGCC syngas turbines. Gasification syngas differs from natural gas in
terms of calorific value, gas composition, flammability characteristics, and contaminants.
An IGCC plant will typically produce syngas with a heating value ranging from 250 to
400 Btu/ft3 (HHV basis), which is considerably lower than the approximately 1,000
Btu/ft3 for natural gas. This yields a flow rate increase compared with natural gas
(approximately 14%). Also, the combustible composition of natural gas is primarily
methane (CH4), and the syngas combustible components are carbon monoxide (CO) and
hydrogen (ftz). Finally, coal-derived syngas will contain higher concentrations of sulfur
in the form of H2S, which will impact use of post-combustion NOX control.
The current NOx control with the IGCC technology adds diluents such as steam and/or
nitrogen to lower flame temperature to prevent formation of thermal NOx. Nitrogen is
available from the air separation unit at partial oxidation IGGC plants. Syngas dilution
can reduce NOx emissions levels from syngas-fired turbines to approximately 15 to 18
ppmvd (at 15% ©2). As noted earlier, GE is working to lower emissions to single digit
values by improved turbine designs.
46 Major Environmental Aspects of Gasification-Based Power Generation Technologies. Final Report by:
Jay Ratafia-Brown, Lynn Manfredo, Jeffrey Hoffmann, & Massood Ramezan for National Energy
Technology Laboratory, U.S. Department of Energy, December 2002.
47 Southern Illinois Clean Energy Center. Integrated Gasification Combined Cycle Plant and Substitute
Natural Gas Methanation Plant. BACT Evaluation prepared for Steelhead Energy, LLC by Sargent &
Lundy, October 2004.
4-2
-------
Section 4
Special Studies
4.1.2 Post-Combustion NOX Control
The currently available technology to achieve single-digit NOx concentrations in the
stack gas is post-combustion treatment of the flue gas which chemically reduces the NOx
to nitrogen. Selective catalytic reduction or SCR is a fully commercial technology used
with natural gas-fired turbines. Variations of the natural gas SCR technology have also
been installed with a number of coal-fired boilers. As noted above, there are fundamental
differences between the natural gas and syngas-fired turbines that make the use of SCR
with IGCC technologies more uncertain, and there are no installations at present at IGCC
facilities firing coal.
Exhibit 4-1 shows how a SCR could be installed for post-combustion control at the IGCC
facility. The SCR selectively reduces NOx emissions by injecting ammonia (NH3) into
the flue gas upstream of a catalyst. The NOx reacts with NHa and O2 to form N2 and
H2O. The SCR installation would be part of the HRSG, to allow for operation in the
optimum range of temperature, about 600 to 750 °F.
In a typical SCR ammonia injection system, anhydrous ammonia is drawn from a storage
tank and evaporated using a steam- or electric-heated vaporizer. The vapor is mixed with
a pressurized carrier gas to provide both sufficient momentum through the injection
nozzles and effective mixing of the ammonia with the flue gases. The carrier gas is
usually compressed air or steam, and the ammonia concentration in the carrier gas is
about five percent. An alternative to using anhydrous ammonia is to use aqueous
ammonia. The reduced ammonia concentration in an aqueous solution reduces safety
concerns associated with anhydrous ammonia.
Exhibit 4-1, SCR Installation for IGCC Technology
Stack
-------
Section 4 Special Studies
In the informal telephone discussions with SCR suppliers, they remarked that the system
could reduce NOx below three ppmvd depending on economic considerations for the
system, and also ammonia slip control. The ammonia-to-NOx ratio can be varied to
achieve the desired level of NOx reduction. One mole of ammonia reduces one mole of
NO, and two moles of ammonia reduces one mole of NO2. Higher NH3:NOx ratios
achieve higher NOx emission reductions, but can result in increased un-reacted ammonia
being emitted into the atmosphere. This un-reacted ammonia is known as ammonia slip.
Also, SCR catalysts degrade over time, which changes the quantity of NH3 slip. Catalyst
life typically ranges from three to 10 years depending on the specific application. IGCC
applications, with exhaust gas that is expected to be relatively free of contaminants,
should yield a significantly longer catalyst lifetime than for a conventional coal-fired
application. In the economic estimate below, four years catalyst life is set as criteria for
the calculation. The four year criteria are based on engineering judgment, since no direct
SCR experience with IGCC installations exist.
Installation of SCR in an IGCC's HRSG requires consideration of the environmental
impacts of ammonia slip. Ammonia slip is typically limited to less than five ppmvd in
most natural gas SCR applications, but may be higher if the NOx level entering the
catalyst bed is very low. Tradeoffs between NOx and ammonia emissions show limited
data, but subjectively represent problems as both emissions are pollutants and both are
greenhouse gases.
There are operational impacts from the installation of a SCR system at the IGCC plant.
First, the pressure loss across the SCR catalyst bed decreases gas turbine power output by
approximately one-half percent and the ammonia storage and transfer equipment
consumes some additional power. Second, chemical reactions may interfere with the
operation of the plant. Any sulfur left in the syngas will oxidize to SO2 and SO3. If the
sulfur in the syngas is not limited to 20 ppmvd or less and substantial levels of SO3 are
present in the flue gas, ammonia from the SCR can react with SO3 to form ammonium
salts. These salts are corrosive and sticky materials that can plug heat transfer equipment,
reducing performance and increasing maintenance. Any fouling will also add to pressure
drop power losses. The ammonium salts, if not deposited in the system remain in the flue
gas as fine paniculate matter (PM2.5). Since a typical plant will not have particulate
controls after the HRSG, the particulate emissions also need to be evaluated in the NOx
emission assessment.
In order to limit ammonium salt formation, either the ammonia slip or the SO3 must be
minimized. Some ammonia slip is inevitable, and discussions with SCR suppliers
recommend a maximum of 20 ppmvd SO2 in the syngas, or about two to three ppmvd in
the flue gas going to the HRSG. While the IGCC case for the study can reduce sulfur in
the syngas to about 40 ppmvd, additional cleaning such as with a physical solvent
(Selexol, Rectisol) is needed to meet the 20 ppmvd sulfur limit for the syngas. Designs to
balance the emissions of NOx and ammonia slip require more detailed engineering, and
the process providers were not willing to provide more data without specific design
specifications.
4-4
-------
Section 4 Special Studies
A key factor in SCR operations is the frequency with which catalyst must be replaced to
meet NOx reduction and residual NH? performance targets. Until recently, catalyst
replacement frequency was a source of debate between SCR control equipment suppliers
and utility users. However, recent catalyst technology has made substantial advances, and
catalyst suppliers are now willing to subject their product life cycles to rigorous, lengthy
commercial guarantees for natural gas turbines and PC units. While there is no
commercial experience with SCR and coal-fired IGCC systems, if IGCC sulfur removal
is accomplished as discussed above, catalyst life cycle issues are likely to be very similar
as experienced with PC units. The crucial question for IGCC will be the impact on
HRSG performance of adding the SCR. This issue does not present itself for PC
installations.
Although misleading, it is convenient to express the catalyst replacement frequency in
terms of a single number reflecting useful catalyst life in years. In practice, a catalyst
management strategy is employed to minimize the cumulative cost over the plant lifetime
of providing for replacement and disposal of catalyst. Generally, a SCR unit when
initially commissioned into service contains only a portion of the ultimate catalyst
inventory, which after a number of years is gradually augmented with new catalyst to
compensate for gradual deactivation. Ultimately, the original catalyst elements are
considered "spent" and replaced with fresh catalyst, which in turn augments the older
catalyst in the reactor. Specific strategies vary with site-specific design considerations.
While not completely equivalent to the issue of IGCC and SCR installations, European
experience indicates that coal-fired boilers employing a proper catalyst management
strategy will enjoy an average catalyst lifetime of six tolO years.48 Vendors for Public
Services New Hampshire (PSNH) Merrimack station commercial SCR installation
guaranteed a catalyst life of six years; PSNH itself anticipates an eight-year life. New
coal-fired boilers (e.g., U.S. Generating—Carneys Point and Stations in New Jersey) are
securing vendor guarantees of a 10-year catalyst life. As noted above there is no
experience with IGCC with SCR installations at this time; this is one reason for the
relatively conservative life criteria selected for economic calculations. However, it
appears that the operating environment for the IGCC's SCR catalyst should be less
aggressive than that for the PC units and, therefore, the life may be significantly more
than the four years allowed in the economic calculations.
4.1.3 Cost Estimates for SCR Addition
To consider the costs for increased NOx control by adding the SCR to the system, the
performance criteria is defined as follows based on Nexant's discussions with SCR
suppliers and literature. The criteria are the basis for calculations; they are not guarantees
of performance.
48 States' Report on Electric Utility Nitrogen Oxides Reduction - Nitrogen Oxides Reduction Technology
Options for Application By the Ozone Transport Assessment Group, April 1996.
4-5
-------
Section 4
Special Studies
• The SCR evaluation is based on the IGCC case with bituminous coal. Anhydrous
ammonia is used as the SCR reagent.
• The SCR reduces NOx from 15 to three ppmvd.
• The base performance case (15 ppmvd) is the IGCC with steam and nitrogen dilution.
• With SCR, the gas turbine gross output is assumed to be reduced by one-half percent.
The SCR system also consumes additional power in vaporizing anhydrous ammonia
and in ammonia pumps and blowers, which is estimated at 60 kW.
• In addition to the SCR equipment, a physical solvent system such as Selexol is
assumed to be provided to meet the 20 ppmvd sulfur limit to the SCR given by the
SCR suppliers. The costs for SCR addition are reported both with and without a
Selexol system.
• The installed cost of the SCR is $12/kW; the total capital requirement cost is $15/kW.
Cost data is from the previously referenced Southern Illinois Clean Energy Center
BACT evaluation. The generating capacity at this plant would be 544 MW net.
• The plant capacity factor is assumed at 85%.
NOx emissions for the bituminous coal IGCC case with and without SCR are
summarized in Exhibit 4-2.
Exhibit 4-2, NOX Emissions for Bituminous Coal IGCC- with and without SCR
Emission Units
ppmvd at 15%O2
Ib/MMBtu
Ib/MWh
Tons per year
NOX Emissions -
Syngas Dilution
15
0.049
0.36
729
NOX Emissions -
SCR Installed
3
0.01
0.07
146
Exhibit 4-3 shows the results from estimates of the cost per ton of NOx for installing the
SCR for lower NOx emission. A cost per ton of NOx reduced is shown for cases with
and without considering a cost for lost power generation from the added SCR power
consumption. With the MDEA acid gas removal system, the cost is $7,290 per ton of
NOx removed. When Selexol technology is used to replace the MDEA process for sulfur
removal, the cost per ton approximately doubles.
4-6
-------
Section 4
Special Studies
Exhibit 4-3, Cost Effectiveness Estimate for SCR NOX Reduction
Cost Items
SCR Capital Cost
O&M Costs
Ammonia
Catalyst Replacement
Disposal Cost
Labor
Maintenance
Total O&M
Total O&M + Annualized Capital
Cost per Delta Ton Removed
Auxiliary Power Consumption
Cost per Delta Ton Removed
When Aux. Power Included
Cost per Delta Ton Removed
Aux. Power & Selexol Included
$ 7,500,000
Annualized
Cost
$ 900,000
$ 107,400
$ 2,048,700
$ 200,000
$ 130,800
$ 196,200
$ 2,683,100
$ 3,583,100
$ 6,145
$ 668,000
$ 7,290
$ 13,120
Notes
Capital recovery at 12%
and 30 year investment
term
Based on $363/ton of
anhydrous ammonia49
Based on 4 year catalyst
life and a catalyst
replacement cost of
$396/cu.ft.50
Based on $0.04 per KWh
Due to the lack of experience with SCR application on coal-based IGCC units at this
time, there are several unresolved issues that may have additional cost impacts, resulting
in increases in the costs shown in Exhibit 4-3. Some of these issues are outlined below:
• Modifications to the HRSG design may become necessary to minimize adverse
effects of ammonium salts formed from reaction between ammonia slip and SOs.
Such modifications have not been accounted for in the above estimates.
Potash Corp Website,
http://\vw\v.potashcorp.com/invcslor_rclalions/iTiarkcts information/ammonia margins/, accessed on
February 21, 2006.
50 Catalyst cost factor used in the EPA's IPM Model, Documentation for EPA Base Case 2004 (V.2.19),
EPA430-R-05-011, September 2005.
4-7
-------
Section 4 Special Studies
• Without proven experience, it may not be possible to obtain proper performance
guarantees and warranties for the overall SCR/HRSG installation or such
guarantees/warranties may be offered at higher costs.
• The catalyst suppliers may offer catalyst life guarantees below the levels assumed for
this study.
• Uncertainty exists regarding optimal ammonia slip and syngas sulfur content levels
required to mitigate HRSG effects. Selection of conservative levels can have an
impact on the overall costs.
The impact of the above issues would vary with the operating conditions associated with
each IGCC installation. Some of these issues can have a substantial impact on the SCR
costs. As an example of cost sensitivity, if the catalyst life is reduced from 4 to 3 years,
the cost per ton removed will increase from $7,290 to $8,460, about a 16% change.
The Selexol process suppliers were unwilling to provide cost data without more detailed
design information and payment for their efforts. However cost data is available in the
literature, and from Nexant experience with other gasification projects.51 If Selexol is
required to reduce the sulfur content below the limits of an MDEA acid gas cleaning
process, the increased capital cost is estimated to be $20 million. The increased
annualized capital cost would be $2.40 million; increased annual O&M costs are
estimated to be $lmillion and the cost per delta ton increases to $13,120. Costs for the
MDEA system from the Texaco study were used as a check against the published Selexol
incremental costs.52
The need to replace the amine acid gas removal system with a more effective physical
solvent technology is still uncertain. From the discussions with technology suppliers,
technology selection requires more detailed examination for specific coals and plant
designs. In some cases, the MDEA process may be able to reduce the syngas sulfur
sufficiently for the SCR (about 20 ppmvd); also, the SCR technology for coal is still
evolving and may become more sulfur tolerant.
4.2 Assessment of Sulfur Removal Technologies - Selexol and Rectisol
The uncertainties associated with SCR use with IGCC syngas or more stringent SC>2
removal requirements could lead to a need for deeper cleaning of the syngas. The
removal capability of the amine-based MDEA chemical sorbent acid gas cleaning process
is limited by economic trade-offs, so alternative sulfur removal processes, Selexol and
Rectisol, are evaluated in this section for the deeper cleaning option.
51 Process Screening Analysis Of Alternative Gas Treating And Sulfur Removal For Gasification, Revised
Final Report, December 2002, Prepared by SFA Pacific, Inc., U.S. DOE Task Order No. 739656-00100.
52 Texaco Gasifier IGCC Base Cases. U.S. DOE/NETL, PED-IGCC-98-001 Latest Revision June 2000.
4-8
-------
Section 4
Special Studies
A major advantage of the Rectisol process is its removal of COS, so that no upstream
COS hydrolysis step is necessary. The major cost issue for Rectisol is its requirement for
refrigeration to cool the methanol in the process to low temperature. Rectisol can reduce
the syngas sulfur content to as low as two ppmvd in the treated gas. Such low levels of
sulfur concentration are not needed for SCR operation discussed earlier and unless there
is another technical or regulatory reason, the added costs may not be justified.
The Selexol process cannot achieve the same low sulfur concentration as Rectisol, and
requires COS hydrolysis. A typical coal syngas contains five percent of its total sulfur as
COS, and the physical solvents are only about half as effective removing COS compared
to H2S. However, the Selexol process may be less complex and does not require
cryogenic operating temperature as the Rectisol process does. To obtain sulfur removal
for the SCR addition, Selexol may not need refrigeration equipment. The low
temperature criterion adds to the energy penalty associated with the Rectisol process.
Exhibit 4-4 shows a comparison of the three technologies described above from the
previously referenced Southern Illinois Clean Energy Center BACT evaluation based on
an Illinois #6, high sulfur bituminous coal similar to this study's bituminous coal case.
Exhibit 4-4, Comparison of Sulfur Removal Technologies for IGCC
Sulfur Removal
Technology
MDEA Chemical
Solvent
Selexol Physical
Solvent
Rectisol Physical
Solvent
Syngas Sulfur
Compounds
Concentration
ppmvd
SO2 Emissions
Ib/MMBtu
Percent Reduction
from Uncontrolled
Emission
%
75 0.033 99.37
20 0.009 99.83
10 0.0045 99.91
While the differences in Exhibit 4-4 appear small, for a point of reference if the
uncontrolled SO2 emissions were 100,000 tons per year, the emissions after applying
each of the above technologies would be 630, 170 and 80 tons per year - the reductions
achieved improve by a factor of eight, comparing the lowest controlled emission rates to
the highest.
While the process developers would not provide cost data without a detailed design basis,
according to the Rectisol (Linde) and Selexol (UOP) suppliers, sulfur content of the coal
and thus the raw syngas is not a significant factor for removal efficiency and has a limited
impact on costs.
4-9
-------
Section 4
Special Studies
4.2.1 Sulfur Removal and Recovery Technologies
As mentioned earlier, in an acid gas removal process syngas is treated via contact with a
solvent to remove H2S and some CC>2. Physical solvents, such as Rectisol and Selexol are
favored over chemical solvents when the sulfur content of the clean gas must be very
low, such as for chemical plant operations. The removed IH^S is treated in a Claus process
to recover sulfur similar to the other IGCC cases.
Rectisol Process
A simplified flow diagram of the Rectisol process is shown in Exhibit 4-5. The Rectisol
process uses methanol as a physical solvent operating at cryogenic temperature for
removal of acid gases. The feed gas is pre-cooled. The injected methanol plus water is
separated from the gas, which is given into the wash column. H2S and some CC>2 are
physically absorbed from the raw gas by the cooled solvent. Sulfur is removed in this
column down to < 10 ppmvd; the CO2 slip is approximately 60-65%, meaning that
approximately 35 - 40% of the incoming CC>2 is removed. H2S is then desorbed by re-
boiling the solvent. The CO2-laden solvent is recycled back to the Rectisol unit. The
released H^S-loaded gas is sent to the sulfur recovery process (Claus process).
Raw Syngas
Exhibit 4-5, Rectisol Process Block Diagram
Sweet Syngas To Gas Turbine
Recuperator
1 *
Cryogenic f^\
Cooler \~^J
Clays Gas To Sulfur Recovery |
Heater
^
-^
/\
4.
V T J
~~^
Ov
^
1'
^\
1 ]
Desulfurization
Acid Gas Removal
Rectisol Unit
Pre-wash
^r~S
Hot
Regeneration
CO2-Laden Solvent
^
4-10
-------
Section 4 Special Studies
Selexol Process
Selexol is a liquid physical solvent developed by Allied Signal in the 1950s, and is used
for treating natural and synthesis gas streams. The solvent is used in more than 100
applications for the removal of H2S, CO2, mercaptans, and for both hydrocarbon and
water-dew point control. The Selexol technology is currently owned by Union Carbide
Corporation. Union Carbide has granted exclusive rights to UOP for licensing Selexol
technology in the field of partial oxidation. In December 2005, Honeywell completed
acquisition of UOP.
A simplified flow diagram of the Selexol process is shown in Exhibit 4-6. Untreated
syngas is sent to the absorber, where it contacts cooled regenerated solvent, which enters
at the top of the tower. In the absorber, H2S, COS, CO2 and other gases such as hydrogen,
are transferred from the gas phase to the liquid phase. The treated gas exits the absorber
and is sent out of the Selexol unit battery limits. The solvent streams from the absorber
and re-absorber are treated rich solvent, and are combined and sent to the lean/rich
exchanger. The solvent from the re-absorber is sent via the rich pump.
In the lean/rich exchanger the temperature of the rich solvent is increased by heat
exchange with the lean solvent. The rich solvent is then sent to the H2S concentrator,
where a portion of the CO2, CO, H2 and other gases are stripped from the solvent.
Nitrogen from the air separation unit is the stripping medium. The temperature of the
overhead stream from the H2S concentrator is reduced in the stripped gas cooler, and is
sent to the re-absorber, where H2S, COS and a portion of the other gases are transferred
to the liquid phase. The stream from the re-absorber exits the unit battery limits.
The rich solvent from the re-absorber is combined with rich solvent from the absorber, as
described above. The partially regenerated solvent exits the H2S concentrator and is sent
to the stripper, where the solvent is regenerated. The lean solvent is then sent to the other
side of the lean/rich exchanger via the lean pump. The temperature of the lean solvent is
further reduced in the lean solvent cooler. A portion of the lean solvent is then sent to the
re-absorber, while the remainder is sent to the top of the absorber via the lean booster
pump. Hydrogenated tail gas from the sulfur recovery unit is recycled back to the acid
gas removal unit and enters with the feed to the re-absorber (not shown).
4-11
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Section 4
Special Studies
Exhibit 4-6, Selexol Process Block Diagram
Claus Gas To Sulfur Recovery
Sulfur Recovery
A simplified flow diagram of the Claus sulfur recovery process is shown in Exhibit 4-7.
The Claus process produces elemental sulfur by burning in a furnace part of the H2S to
form SO2; and by reacting un-combusted H2S with SO2. One-third of H2S in the feed gas
is oxidized to SO2. Simultaneously, an un-catalyzed reaction occurs between the SO2 and
unburned H2S, which are in stoichiometric ratio, converting about 60% of each to sulfur
vapor. The gas, upon leaving the furnace, is then cooled to condense sulfur, reheated, and
passed through a catalytic converter. A three-converter system recovers about 98% of the
sulfur. The gas leaving the catalytic converter is sent to a tail gas cleaning unit (TGCU),
which is generally a Shell Claus Off-gas Treatment (SCOT) process.
The SCOT process consists of two sections. In the first section, the tail gas is heated and
reacted with H2 over a catalyst. All sulfur compounds are converted to H2S. The off-gas
is then cooled in a waste heat boiler followed by a water quench. Finally, H2S is
selectively absorbed by an MDEA. The rich amine solution is stripped and the H2S-rich
stream is recycled to the front end of the Claus plant. The treated gas from the SCOT
absorber is incinerated and the incinerated gas is discharged through a high stack.
4-12
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Section 4
Special Studies
Exhibit 4-7, Sulfur Recovery Block Diagram
Steam Steam
Acid Gas /
—
i
A
\
Acid Gas Furnace
\
--
Tail Gas Incinerator
WW
^ ^
Vaste Heat Boiler
L
[ail Ga
k
-^
3 Cleaner
1
WW
Sulfur Condens
(
Steam
i i
™
ww
k.
Hea
3r
Catalytic
Reactor
ter
1
J
r <
<
<
L <
^^yyrfj*.
%
* 1
^
^
^~
>
>
>
%_
i
!
Sulfur Condenser
r
1 V
Sulfur Storage
4.2.2 Cost and Economic Estimates
The Selexol and Rectisol technology suppliers, UOP LLC and Linde Group respectively,
were not able to provide cost information without a more detailed design basis and
compensation for their efforts.
Other sources for costs were pursued and the results are reported below.
• Eastman Gasification Services Company in an October 2003 presentation to the
Eastern Tennessee section of the AIChE, "Coal Gasification - Today's Technology of
Choice and Tomorrow's Bright Promise" reported estimated costs of $20 million for
Selexol and $40 million for Rectisol. Plant size is not given, so only the cost factor of
2 in estimating the difference between Selexol and Rectisol is useful. However, an
article in Power magazine reports similar information and describes the cost for an
IGCC of approximately 500 MW.53 The absolute cost values are for costs above
what is estimated for an MDEA alternative system.
• The previously referenced Southern Illinois Clean Energy Center BACT evaluation
also provides estimates for a Selexol system to be installed on a 544 MW IGCC plant.
All costs are provided as incremental costs (over an MDEA system). The total capital
Steam
53 Vol. 148, No. 2 March 2004 Power Magazine, "Coal Gasification: Ready for Prime Time" - Available at
URL: http://www.biisincsswcck.coni/pdf/240648PWRcPrint.pdf. accessed February 23, 2006.
4-13
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Section 4 Special Studies
cost for the Selexol system addition is estimated at approximately $40 million
($75/kW). The annual operating costs are estimated at approximately $6 million.
The overall cost effectiveness is estimated at approximately $22,000 to $30,000 per
ton of NOx removed, compared to the base case MDEA.
The above BACT evaluation also includes addition of a Rectisol system to the same
544 MW IGCC plant. The incremental cost estimates provided show a capital cost of
$81 million ($149/kW) and operating costs of $8.3 million.
4-14
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Section 5 Carbon Management
As part of the study scope of work, a summary of technologies and current status for
carbon dioxide (€62) separation, capture and sequestration was prepared and
documented in this section.
5.1 COi Separation, Capture and Sequestration Background
While CC>2 is not a regulated power plant emission, the strong scientific and political
focus on how CO2 impacts global climate has initiated a number of technical and
economic assessments of technologies that could be installed to separate, capture and
sequester (SCS) the gas for hundreds or thousands of years. SCS technologies and
estimates of their performance and economics are discussed in this section of the report.
The discussion focuses upon technologies that are likely to be commercially
demonstrated in the 2010 time period.
While industry and government research is working diligently to reduce the cost and
improve performance of SCS technologies, the timing of their wide-spread introduction
into the commercial market is highly uncertain. Aside from economic considerations, the
major implementation issue is the location, definition and justification of geological
sequestration formations. The task of convincing the public, government and industry
stakeholders that sequestration is safe and environmentally sound is difficult. Except for
limited opportunities for enhanced oil or gas recovery operations in existing and
geologically well defined-sites, the storage of very large amounts of CC>2 for hundreds of
years will need to be carefully tested, demonstrated and monitored before the technology
is accepted by enough stakeholders to allow the technology to move forward at the scale
that is needed for serious power generation carbon management.
The CC>2 separation and capture technologies for power generation systems are
traditionally split into "post-combustion and pre-combustion" categories. Capture of CO2
from flue gases produced from combustion of fossil fuels, such as in a PC boiler, is
referred to as post-combustion capture. A chemical sorbent process would normally be
used for CC>2 capture for this purpose.
The concept of combusting coals (or other fuels) with oxygen instead of air can be
classified as a SCS process that falls in the post-combustion category. This process is
applicable to PC boilers and is in early stages of development. The process results in a
flue gas stream that is mainly CO2 and H2O, making it possible to capture and sequester
CC>2 at relatively low cost.
Pre-combustion usually means the application of gasification to produce a synthetic gas
and then treatment of this gas to produce and capture CO2, resulting in a stream of
hydrogen-rich fuel that can be used for various applications, including power generation.
Capturing of CC>2 is generally accomplished using a physical or chemical absorption
process.
5-1
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Section 5 Carbon Management
5.2 SCS Technologies for Pulverized Coal Power Plants
Post-combustion CC>2 separation and capture from PC plant flue gas (mainly by amine
chemical absorption) is currently being examined by industry. While the amine process
is technically proven in small-scale commercial operations, the economics and scale-up
issues associated with a 500 MW or larger power plant are substantial.
5.2.1 Gas Ab sorption
Gas absorption processes are commonly used in commercial industrial operations to
remove CO2 from mixed-gas streams. Gas absorption can treat streams at widely ranging
pressures and CO2 concentrations. Typically gas absorption works by contacting the
mixed-gas stream containing CC>2 with a liquid solvent in which CC>2 is soluble. Two
types of solvents are used for CC>2 removal: physical solvents and chemically reactive
solvents. Physical solvents follow Henry's law such that the mass of a gas that will
dissolve into a solution is directly proportional to the partial pressure of that gas above
the solution. Therefore, physical solvents are more suitable for gas streams that are under
high pressure; resulting in an elevated CC>2 partial pressure. This increases CC>2
solubility, which, in turn, reduces the solvent circulation rate. Chemically reactive
solvents first dissolve CO2 and then react with it. Pressure has a secondary effect on the
performance of chemically reactive solvents.
If the mixed-gas stream containing CC>2 is at elevated pressure, the physical solvent can
be recovered and the CO2 separated by simply flashing the gases to a lower pressure.
Chemically reactive solvents require energy to reverse the chemical reaction to recover
the dissolved gases. Commercial experience indicates that the physical solvent process is
more economical if the CC>2 partial pressure is above 200 psia. At low-inlet CC>2 partial
pressure such as a PC plant flue gas, chemically reactive solvent processes are required.
Some of the commonly used commercial gas absorption processes are listed in Exhibit 5-
1. The first four processes use solvents that physically absorb the CC>2 and are applied to
mixed gas streams under high pressure that contain a high concentration of CO2. The
solvent circulation rates for these processes are generally higher than for chemical
absorption. For the three other processes, a chemically reactive solvent is used.
Alkanolamines are a group of amines that are used for CO2 removal. They include
monoethanolamine (MEA), diethanolamine (DEA), diglycolamine (DGA),
diisopropanolamine (DIPA), and triethanolamine (TEA). Of these, MEA is the most
alkaline; it has the highest dissociation constant and the highest pH in water solution. The
others are progressively less alkaline in the order listed. Other properties that bear on the
use of these amines follow in the same order as their alkalinities. The primary amines
(MEA) form the most stable bond with the acid gas, followed by the secondary amines.
The least stable bond is formed by the tertiary amines. Therefore, amine-based processes
are the most common and are considered to be the best technology for the removal of
CO2 from PC flue gas with low CO2 partial pressure.
5-2
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Section 5
Carbon Management
Exhibit 5-1, Gas Absorption Processes Used for CO2 Removal
Process
Owner
Application
Physical Solvents
Sulfmol
Selexol
Rectisol
Pun sol
Shell Oil Company
Universal Oil Products
Lurgi GmbH and
Linde AG
Lurgi GmbH
Natural gas, refinery gases
and synthesis gases
Natural gas, refinery gases,
and synthesis gases
Heavy oil partial oxidation
process of Shell and Texaco;
also Lurgi gasification
Natural gas, hydrogen, and
synthesis gases
Chemical Solvents
Catacarb
Benfield
Amines
(alkanolamines and
hindered amines)
Eickmeyer &
Associates, Kansas
Universal Oil Products
Both generic solvents
and proprietary
formulations with
additives
Any mixed-gas stream
Synthesis gas, hydrogen,
natural gas, town gas, and
others
Any mixed-gas stream
In addition to the primary commercial process of absorption with MEA, there are other
separation technologies under research and development including:
• Cryogenic Cooling
• Gas Separation Membranes
• Gas Absorption Membranes
• Gas Adsorption
None of the processes have been used at or near the scale of CO2 removal required by
large power generation plants, and most of the R&D is focused on natural gas-fired
systems. The MEA process is judged the only process likely to be available in the
study's timeframe for coal-fired plants and is discussed in more detail below.
5.2.2 MEA Absorption
For removal of CO2 from low-pressure, low-CO2 concentration pulverized coal flue
gases, MEA scrubbing is considered state-of-the-art for fossil fuel-fired systems such as
coal-fired boilers and gas turbines. A few commercial facilities use MEA-based solvents
to capture CO2 from coal, fuel oil, and natural gas flue gas streams for use in the food
5O
-------
Section 5 Carbon Management
industry. However, these plant capacities are roughly 100 to 1,000 tons/day compared to
more than 5,000 tons/day for a 500-MW coal-fired plant.
The low CC>2 partial pressure necessitates the use of MEA-based systems, and while
MEA has the advantage of fast reaction rate with CC>2 at low partial pressures compared
to other commercially available amines, there are significant disadvantages such as high
heat of reaction, limited capacity and significant corrosion problems. Oxygen present in
the flue gas causes rapid degradation of alkanolamines. The degradation byproducts lead
to corrosion problems and cause significant deterioration in the overall separation
performance. To counter the influence of oxygen, the approach currently practiced is the
use of chemical inhibitors. For example, the processes licensed by Kerr-McGee/ABB
Lummus Global Inc. and by Fluor Daniel use inhibited monoethanolamine solutions.54'55
Commercial providers of MEA technology also include Praxair and Mitsubishi Heavy
Industries (MHI). Recent advances in chemical solvents have included the commercial
introduction of the KS-family of hindered amines by MHI. Their different molecular
structures allow enhanced reactivity toward a specific gas component, in this instance
CC>2. Benefits of these advanced amines in addition to extensive heat integration include
the following: 1.) Higher absorption capacity (only one mole of hindered amine is
required to react with 1 mol CO2 compared with two moles MEA), 2.) 90% less solvent
degradation, 3.) 20% lower regeneration energy, 4.) 15% less power, 5.) 40% lower
solvent recirculation rates due to higher net absorption capacity, 6.) Lower regeneration
temperature, 7.) less corrosion in the presence of dissolved oxygen, and 8.) Lower
chemical additive cost. An example of a coal-fired power plant system employing an
MEA process for CC>2 capture is presented in Exhibit 5-2 and briefly described below.
The flue gas is partially compressed to 17.5 psia by a centrifugal blower to overcome the
gas-path pressure drop. The flue gas enters the absorber and flows upward and counter to
the lean MEA solution. CC>2 is removed from the flue gas in the packed-bed absorber
column through direct contact with MEA. The CCVdepleted flue gas is exhausted to the
atmosphere. The CO2-rich solution is heated in a MEA rich/lean heat exchanger and sent
to the stripper unit where low-pressure steam from the steam turbine (in a power plant)
provides the thermal energy to liberate the CC>2. The CC>2 vapor is cooled to condense
water and then sent to a multistage compressor where the CC>2 is compressed to a super-
critical state of about 1,200 psia for pipeline transport. The CC>2 laden stream is further
dehydrated using glycol or molecular sieve processes.
54 Barchas, R. and Davis, R. The Kerr-McGee/ABB Lummus Crest Technology for the Recovery of CO2
from Stack Gases. Energy Conversion Management, 33(5-8), p. 333, 1992.
55 Sander, M.T. and Mariz, C.L. 1992. The Fluor Daniel Econamine FG Process: Past Experience and
Present Day Focus. Energy Conversion Management, 33(5- 8), p. 341, 1992.
5-4
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Section 5
Carbon Management
Low Pressure Steam
for Stripping
Oxygen Inhibited
MEA Absorber
CO2 Compressor
Exhibit 5-2, CO2 Removal by MEA Absorber/Stripper
5.2.3 MEA CC>2 Absorption Performance
The MEA process can practically achieve recoveries of 85% to 95%, with CC>2 purities
over 99% by volume. However, the MEA process requires large amounts of thermal
energy (heat/steam) as well as auxiliary power to operate pumps and blowers for gas and
solvent circulation. Depending on the exact concentration of the solution, the steam
consumption can vary from 1,200 to 1,620 Btu per pound of CC>2 recovered. To prevent
corrosion, the flue gas is treated so that SC>2 is below 10 ppmvd, NC>2 is below 20 ppmvd,
and NOx is below 400 ppmvd. Solvent degradation and losses also occur during the
regeneration operation.
Recent U.S. DOE NETL and other studies indicate that the overall energy penalty
associated with CC>2 separation and capture with an amine solution plus compression of
the CC>2 gas ranges from 10 to 15% of the design capacity of a PC power plant without
5-5
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Section 5
Carbon Management
CO2 SCS.56 For supercritical PC (SCPC) plants with and without CO2 removal examined
in the DOE study the major performance differences are illustrated in Exhibit 5-3.
Exhibit 5-3, U.S. DOE/NETL Study, CO2 Removal Impacts - A Supercritical PC Plant
Performance
Gross Plant Power, MW
Total Auxiliary Power
Requirement, MW
Net Plant Power, MW
Net Efficiency, % HHV
Net Heat Rate, Btu/kWh
Coal Feed, Ib/hour
SCPC without
CO2 Removal
491.1
29.1
462
40.5
8,421
333,542
SCPC with CO2
Removal
402.3
72.7
329.3
28.9
11,816
333,542
The main systems requiring increased auxiliary power are the larger induced draft flue
gas blower (some 20 MW) required for the MEA removal process, and the CO2
compression (about 30 MW). In addition, the large decrease in net efficiency is a result
of amine solvent regeneration via steam stripping. This requires a significant amount of
low pressure steam to be by-passed from the low pressure steam turbine, thereby
preventing power generation. In the industry methodology for comparing technologies,
this is accounted for in costs for equipment, and by calculating the "avoided cost" for
CO2 removal, which includes costs to replace the power lost by installing the removal
system.
5.2.4 MEA Technology Status
Most of the new work and advances to the amine absorption technology have focused on
natural gas-fired systems57'58. Other sources provide data for natural gas-fired systems
and some of that information is summarized here in exhibits 5-4 and 5-5.59 The
performance data in Exhibit 5-4 is based on the fuel lower heating value (LHV). While
this work has indicated significantly reduced costs and improved performance, the
development of similar systems for PC plants does not appear to be progressing very
rapidly.
Evaluation of Innovative Fossil fuel Power Plants with CO2 Removal U.S. DOE/NETL and EPRI,
Prepared by ParsonsEnergy and Chemicals Group, December 2000 - updated 2002.
57 Daniel Chinn, Dag Eimer, and Paul Hurst, CO2 Capture Project: Post-Combustion "Best Integrated
Technology" (BIT) Overview, presented at the Third National Conference on Carbon Capture and
Sequestration, National Energy Technology Laboratory/Department of Energy, Alexandria, VA, May 3-7,
2004.
58 M. Simmonds, et al., "Post Combustion Technologies for CO2 Capture: A Techno-Economic Overview
Of Selected Options", uregina.ca/ghgt7/PDF/papers/nonpeer/471.pdf, Accessed June 28, 2006.
59 Gasification Plant Cost and Performance Optimization Project. U.S. DOE/NETL Contract No. DE-
AC26-99FT40342, September 2003, prepared by Nexant, Inc., Bechtel Corporation and Global Energy.
5-6
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Section 5
Carbon Management
Exhibit 5-4, Natural Gas Combined Cycle CO2 Capture Progress
Study Basis
Natural Gas Combined
Cycle Without CO2
Capture
Baseline Capture Study
Low-cost Capture Study
Low-cost Integrated
Capture Study
Best Integration (BIT)
Study
Net
Power,
MW
392
322
332
335
357
Efficiency,
T HV %
1 1 1 XV / U
57.6
47.3
48.8
50.6
52.5
Capital
Cost, $
millions
284
418
366
345
352
Operating
Cost
$ millions
13
26
24
24
21
CO2
Avoided
Cost $/ton
NA
60
45
35
28
Exhibit 5-5, Solvents for CO2 Removal
Supplier
Non Proprietary
Econamine, Fluor
KS-1, MHI
PSR, Amit Chakma
Solvent
MEA
MEA plus
Inhibitors
Hindered
Amines
Amine Mix
Solvent
Loss,
Ib/ton of
C02
2 to 6
3.2
0.7
0.2 to 1.8
Solvent
Cost,
$/lb
M'/ \.\J
0.60
0.70
2.30
unknown
Solvent
Cost,
$ per ton of
C02
1.20 to 3. 50
2.30
1.55
unknown
Steam
Use,
ton per
tonofCO2
2
2.3
1.5
1.1 to 1.7
Research organizations, including U.S. DOE and industry, are concentrating efforts on
non-amine processes such as ammonia scrubbing, membrane separation and oxygen
combustion as possible methods to separate and capture CO2 at PC plants. The following
is from the DOE web site and indicates the difficulty of sequestration of CO2 at coal-fire
plants.60 "Pulverized coal (PC) plants, which are 99 percent of all coal-fired power
plants in the United States, burn coal in air to raise steam. CO2 is exhausted in the flue
gas at atmospheric pressure and a concentration of 10-15 volume percent. This is a
challenging application for CO 2 capture because:
• The low pressure and dilute concentration dictate a high actual volume of gas to be
treated
• Trace impurities in the flue gas tend to reduce the effectiveness of the CO2 adsorbing
processes
60 NETL Website, Carbon Sequestration,
http://www.ncil.doc.gov/tcdmologics/ca.rbon scq/corc rd/co2caplurc.html. accessed February 13, 2006.
5-7
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Section 5 Carbon Management
• Compressing captured CO2 from atmospheric pressure to pipeline pressure (1,200 -
2,000 pounds per square inch (psi)) represents a large parasitic load.
Aqueous amines are the state-of-the-art technology for CO2 capture for PC power
plants. Analysis conducted at NETL shows that CO2 capture and compression using
amines raises the cost of electricity from a newly-built supercritical PC power plant by
84 percent, from 4.9 cents/kWh to 9.0 cents/kWh. The goal for advanced CO2 capture
systems is that CO 2 capture and compression added to a newly constructed power plant
increases the cost of electricity by no more than 20 percent compared to a no-capture
case."
Results from a 2000 DOE/Alstom Power study showed that capturing 90% of the flue gas
CC>2 from an existing pulverized coal power plant (using conventional amines) has
significant performance and economic impacts.61 The results of the study show plant
efficiency dropping from 35% to 21% with MEA and to 23% with combined MEA -
MDEA, all based on the coal higher heating values.
5.3 Oxygen Combustion Technology
Substitution of oxygen for all or part of the combustion air for PC boiler (and other
combustion devices including fluid bed furnaces and gas turbines) has been proposed in
some concepts as a method to produce a CCVrich flue gas requiring no separation and
that could be directly sequestered. Conventional air combustion processes in boilers or
gas turbines produce flue gases that contain predominantly nitrogen (>80 vol%) and
excess oxygen in addition to CC>2 and water. If oxygen rather than air is used as the
combustion source and nitrogen is replaced with re-circulated CC>2, the nitrogen content
of the flue gas approaches zero (assuming minimal air leakage into the system) and the
flue gas contains predominantly CO2 with a small amount of excess oxygen and water.
Circulating a part of the recovered CC>2 controls the adiabatic flame temperature.
While schemes for oxygen combustion (or oxycombustion), usually with the recycle of
flue gas for combustion control, have been conceptually examined, there are no units in
operation. Commercial plant feasibility may be difficult to justify under most conditions
because of the auxiliary power consumption of the air separation unit needed to produce
the oxygen. The Canadian Clean Power Coalition (CCPC) and other Canadian
organizations have performed significant study and tests with oxygen combustion.62' 63
These investigations show higher costs and reduced performance compared to both
gasification with CC>2 removal and amine CC>2 removal options.
61 Engineering Feasibility and Economics of CO2 Capture on an Existing Coal-Fired Power Plant, Alstom
Power, ABB Lummus Global, and American Electric Power; prepared for the Ohio Coal Development
Office and U.S. DOE contract DE-FC26-99FT40576, June 2001.
62 CCPC Phase I Executive Summary, Summary Report on the Phase I Feasibility Studies conducted by the
Canadian Clean Power Coalition, May 2004.
63 Summary of Canadian Clean Power Coalition work on CO2 capture and storage by Geoffrey F Morrison,
August 2004. IEA Clean Coal Centre.
5-S
-------
Section 5 Carbon Management
One of the goals of research being conducted on oxycombustion technology is to lower
the cost of air separation, which is expected to bring the overall cost of this technology
closer to the carbon capture costs with gasification64. U.S. DOE just recently (November
2005) announced awards for two oxygen combustion related projects totaling nearly $10
million65. These projects are expected to help expedite the timeline for
commercialization of oxycombustion technology through slip stream or pilot plant
testing.
5.4 Coal Gasification with CO2 Removal
Gasification technology developers and other proponents of coal gasification for
production of electric power and co-production concepts are strongly focused on the
potential advantages of gasification when combined with requirements for CO2
separation, capture and treatment for transport to sequestration sites. Technology
developers hope that the CO2 issue will lead to greater introduction of gasification
combine cycle (GCC) technology into the power generation market than has occurred in
the past. A number of large scale gasification units have been installed globally, but the
great preponderance of the installations are at petroleum refinery operations or chemical
plants where often inexpensive fuels, a process need for synthesis gas (CO and
hydrogen), and the in-plant need for power and thermal energy may all exist. Despite
demonstrations of IGCC power plants in North America and internationally, industry has
resisted commercial applications for some 30 years. The major issues preventing wider
acceptance are high cost, uncertainty of technology performance - especially gasifier
reliability, and the traditional power generation industry's reluctance to operate what they
view as more of a chemical plant than a power plant.
Exhibit 5-6 is a simplified diagram to illustrate a process for IGCC with CO2 removal.
The process is similar to the IGCC cases without CO2 removal except that the gas from
the gasifier is sent to a CO shift converter prior to cooling, and the acid gas removal
system (shown here as Selexol technology) removes CO2 as well as the sulfur
compounds.
The other significant difference between the IGCC processes with and without CO2
removal is the compression and drying of the product CO2, which is assumed to be made
ready for pipeline transportation.
64 F. Allix, "Today's Technologies, Tomorrow's Potential," Opening Plenary Session, 2005 Clean Coal &
Power Conference, November 21-22, 2005, Washington, DC.
65 NETL Website, Announcements,
http://www.nctJ.doc.gov/piiblications/prcss/2005/tJ oxycombustion award.hlml. Accessed on February 13,
2006.
5-9
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Section 5
Carbon Management
Exhibit 5-6, IGCC with CO2 Separation and Capture
Shifted Raw
Syngas
Gasification Slag
Solid Waste
CO2 For
Transport
Low Temperature
Heat Recovery, Fuel
Gas Saturation
Blowdown
None of the installed gasification plants are designed for the purpose of producing
electric power and removing CC>2. The processes required to remove CC>2 from an IGCC
plant are commercial in other gasification applications. Some work will be required to
test the ability of gas turbines to use the more hydrogen rich fuel that will result from the
CC>2 removal operation. Additionally, there are unique issues with the gasification of
higher moisture subbituminous and lignite coals that need to be solved before these
energy resources can become IGCC feedstocks.
Under the current and near-term state of power generation technologies, the IGCC
concept is attractive because the gasification technology suffers significantly less of an
energy penalty than alternatives, such as pulverized coal boilers or gas turbine combined
cycle power plants, if carbon capture was added. Whatever the technology, the addition
of carbon management will increase costs of electricity, and while there may be niche
markets for CC>2 in enhanced oil/gas recovery operations, the vast majority of CC>2
generated will be a waste product and will incur disposal costs.
5.5 Power Generation Systems with and without CO2 Removal
The original and updated Parsons reports sponsored by the U.S. DOE and EPRI are the
most detailed engineering comparisons in the public literature.66 Exhibit 5-7 presents
information from the study for IGCC and two PC units. The gasifier used in this study is
66 Evaluation of Innovative Fossil fuel Power Plants with CO2 Removal US DOE/NETL and EPRI,
Prepared by ParsonsEnergy and Chemicals Group, December 2000 - updated 2002.
5-10
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Section 5
Carbon Management
different from the GE-Energy (ex-Texaco) reactor used in the body of the report to
calculate energy and material balances, but the relative comparison between systems with
and without CO2 removal would be consistent across types of gasifiers.
Exhibit 5-7, Carbon Management Comparison, U.S. DOE, EPRI, Parsons Study
Description
Carbon Management
Net Plant Size (MW)
CO2 Capture Efficiency
Heat Rate (Btu/kWh) (HHV)
Efficiency (%,HHV)
Derating
IGCC-
ConocoPhillips
r, + NO
Capture „ .
^ Capture
404 425
91% 0%
9,226 7,915
37% 43%
14%
Supercritical PC
r, + NO
Capture „ .
^ Capture
329 462
90% n/a
11,816 8,421
29% 41%
29%
Ultra
Supercritical PC
r, + NO
Capture „ .
^ Capture
367 506
90% n/a
10,999 7,984
31% 43%
27%
Economic Criteria
Cost-year basis
Capacity Factor
Fuel Cost ($/MMBtu)
(HHV)
Book life (years)
Fixed Carrying Charge
2000 2000
65% 65%
$1.24 $1.24
20 20
13.80% 13.80%
2000 2000
65% 65%
$1.24 $1.24
20 20
13.80% 13.80%
2000 2000
65% 65%
$1.24 $1.24
20 20
13.80% 13.80%
Capital Costs ($/kW)
Total Plant Cost
Total Plant Investment
Total Capital Requirement
$1,642 $1,111
$1,787 $1,209
$1,844 $1,251
$1,981 $1,143
$2,142 $1,235
$2,219 $1,281
$1,943 $1,161
$2,101 $1,256
$2,175 $1,301
Operation and Maintenance Costs
Total O&M ($/kW-yr)
Fixed O&M ($/kW-yr)
Variable O&M (cents/kWh)
Fuel (cents/kWh)
52.1 41
33 27.5
0.4 0.3
1.1 1
49.2 28.7
33.3 20.2
1.1 0.6
1.5 1
46.3 27.7
30.8 19.1
1.1 0.6
1.4 1
Levelized Costs (cents/kWh)
Capital
Total O&M
Fixed O&M
Variable O&M
Fuel
Total Cost of Electricity
COE increase for capture
4.47 3.03
0.96 0.76
0.58 0.48
0.38 0.28
1.14 0.98
6.58 4.77
1.8
5.38 3.11
1.71 1
0.58 0.35
1.13 0.64
1.47 1.04
8.56 5.15
3.41
5.27 3.15
1.61 0.95
0.54 0.33
1.07 0.62
1.36 0.99
8.24 5.1
3.14
CO2 Costs ($/ton)
CO2 Emission rate (t/MWh)
0.07 0.72
0.11 0.77
0.11 0.77
5-11
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Section 5
Carbon Management
Description
Cost of CO2 Captured
($/ton)*
Cost of CO2 Avoided
($/ton)*
IGCC-
ConocoPhillips
23.63 n/a
27.98 n/a
Supercritical PC
35.09 n/a
51.22 n/a
Ultra
Supercritical PC
32.35 n/a
47.22 n/a
* See Section 5.7 for differences between CO2 avoided and captured costs.
Exhibit 5-8 presents similar literature data from the International Energy Agency (IEA)
Greenhouse Gas program (circa 2003). Here the two cases are for Shell and GE-Energy
gasifiers.
Exhibit 5-8, Gasification Carbon Management Data, IEA GHG 2003
Description
Carbon Management
Net Plant Size (MW)
CO2 Capture Efficiency
Heat Rate (Btu/kWh)
(HHV)
Efficiency (%,HHV)
Derating
IGCC - Shell
r, + NO
Capture „ .
^ Capture
676 776
85% 0%
9,890 7,916
35% 43%
20%
IGCC - GE
Energy
r, + NO
Capture „ .
^ Capture
730 827
85% 0%
10,832 8,979
32% 38%
17%
Economic Criteria
Cost-year basis
Capacity Factor
Fuel Cost ($/MMBtu)
(HHV)
Book life (years)
Fixed Carrying Charge
2002 2002
85% 85%
$1.50 $1.50
25 25
11.00% 11.00%
2002 2002
85% 85%
$1.50 $1.50
25 25
11.00% 11.00%
Capital Costs ($/kW)
Total Plant Cost
Total Plant Investment
Operation
Total O&M ($/kW-yr)
Fuel (cents/kWh)
Levelize
Capital
Total O&M
Fuel
Total Cost of Electricity
COE increase for capture
$1,744 $1,287
$1,859 $1,371
and Maintenance Co
60.3 57.6
1.6 1.3
d Costs (cents/kWh)
3.69 2.76
0.96 0.84
1.59 1.27
6.23 4.87
1.37
$1,402 $1,114
$1,494 $1,187
sts
59.7 52.5
1.7 1.4
3.04 2.4
1 0.84
1.72 1.42
5.76 4.67
1.09
5-12
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Section 5
Carbon Management
Description
IGCC - Shell
IGCC - GE
Energy
CO2 Costs ($/ton)
CO2 Emission rate
(t/MWh)
Cost of CO2 Captured
($/ton)
Cost of CO2 Avoided
($/ton)
0.14 0.76
16.89 n/a
22 n/a
0.15 0.83
12.81 n/a
16.01 n/a
In Exhibit 5-8, the TEA data is not clear about which version of the GE-Energy gasifier
(quench or heat recovery) was studied, or if there is an installed spare unit for this GHG
case. Even without describing the details of the studies further, several important
conclusions can be made from the data.
• The added cost for CO2 removal is significant regardless of the technology.
Examining the Total Plant Cost (TPC), which should be the most consistent value of
the capital cost items because fewer add-on factors are applied as percents to the basic
estimate, the delta IGCC cost ranges from about $300 (GE-Energy) to more than
$500 (ConocoPhillips) per kW. The two pulverized coal plants increase about $800
per kW when CO2 removal is added.
• Gasification cost and performance, when CO2 removal is installed, are much more
favorably compared to the PC cases. The improved economic performance results
largely from the lower energy penalty incurred by IGCC than for PC when CO2
removal is required.
• The difference in costs for systems with CO2 removal is strongest when avoided costs
are calculated; this is attributed to higher efficiency for gasification over pulverized
coal units.
• The costs per ton of CO2 sequestration remain high for all cases, and the range of
estimates indicates a level of uncertainty that can only be reduced by the real-world
construction of several plants.
• As with all developing technology comparisons, the technologies are changing - for
PC plants new and improved amines are being researched; the U.S. DOE and others
are moving forward with oxygen combustion research; gasification developers are
investigating optimization of the processes for CO2 removal possibly eliminating
some operations to save costs and increase performance. Thus, the situation will
require review as the technologies advance.
• Nearly all of the engineering assessments of power generation carbon management
5-13
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Section 5
Carbon Management
have used bituminous coals as the feedstock for PC and gasifier units. Investigators
are starting to explore power and CC>2 removal systems fueled by subbituminous and
lignite coals. Australia is expanding the knowledge base with work on high moisture
brown coals.67 Canada has also performed significant work with low rank coals,
some of which is available in the literature. The available information is summarized
below.
5.6 Coal Quality and COi Removal
The Canadian Clean Power Coalition (CCPC) reported the results from the first phase of
its work.68 Exhibit 5-9 summarized the data for three types of coal being gasified and for
a pulverized coal plant with CO2 separation using amine absorption and stripping.
Exhibit 5-9, CCPC Summary Data for Plants with CO2 Removal
Coal
Technology
Net power (MW)
Efficiency, % (LHV)
Efficiency, % (HHV)1
CO2 captured (%)
CO2 emitted, g/kWh
Capital cost (U.S.
$/kW)
COE(U.S. cents/kWh)
Bituminous
Subbituminous
Lignite
Gasification Plants
GE-Energy
Gasification
444.5
32.97
30
87
130
1,917
6.84
GE-Energy
Gasification
436.8
27.71
25
92
102
2,190
6.21
Shell
Gasification
361.1
30
26
85.7
182
2,828
8.39
Lignite
Pulverized
Coal Plant
Amine
Absorption
310.9
31.8
27
95
60
2,824
7.43
Note 1. HHV efficiencies estimated; LHV results stated in the report.
The U.S. and TEA efficiency and cost results compare fairly closely for bituminous coals.
The new data from the Canadian work is the relative comparison of the three coals.
Some of the conclusions which can be made from this data include:
• The efficiency difference between systems using bituminous and
subbituminous/lignite coals is significant (about 5%). The lignite coal efficiency is
greater than that of subbituminous coal because the Shell gasifier is a dry feed unit. It
is not clear that all the impacts of the Shell versus GE-Energy units were considered.
In the report, ChevronTexaco, who owned the gasifier technology at that time, did not
believe that its gasifier could be practically used with lignite.
67 Victorian Government's Greenhouse Challenge for Energy. CRC for Clean Power from Lignite, August
2003.
68 Summary of Canadian Clean Power Coalition Work on CO2 Capture and Storage, by Geoffrey F
Morrison, August 2004.
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Section 5
Carbon Management
• The capital cost difference is notably higher for the lignite gasification case than for
both of the other coals.
• The costs for the lignite PC plant with amine CC>2 removal could be compared to the
capital cost for the supercritical plant in the Parsons report as an indication of coal
rank impacts on PC plants with CC>2 removal. The Parsons capital cost is $2,219
compared to $2,824 per kW for the Canadian lignite PC case. Aside from more
specific differences that could exist between the studies, most of the cost difference is
assumed to be caused by a larger boiler required to fire the low heating value lignite.
• The difference in efficiencies between the Parsons supercritical plant and the CCPC
lignite plant is only about 2%. Much of the difference can likely be accounted for by
the heat needed to evaporate the extra lignite moisture.
5.7 Note on Avoided Costs
The cost of an environmental control system can be discussed in terms of either the cost
per ton of pollutant removed or the cost per ton "avoided." For a CC>2 removal system
like amine scrubbers there is a big difference between the cost per ton CC>2 removed and
the cost per ton CC>2 avoided. All avoided cost calculations require a "reference plant"
without the removal system for a comparison to be made on unit cost avoided basis (see
Exhibit 5-10 below). Avoided cost can be calculated as follows:
% I tonne Avoided = •
Capture
- CO7Emissions
z
Capture
Note: Cost of electricity (COE) in mills/kWh and CC>2 Emissions in kg/kWh
Exhibit 5-10, Illustration of Avoided Cost for CO2 Capture
Reference
Plant
Capture
Plant
CO2 Avoided
CO2 Captured
[~1 CO2 Emitted
I I CO2 Captured
0.2 0.4 0.6 0.8
kg CO2/kWh
5-15
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Section 5
Carbon Management
Some other references perform the calculation by adding lost capacity from a specified
generation source such as a new gas turbine combined cycle plant with emissions of its
own used in the calculation.
5.8 COi Pipeline Transport
Pipeline transportation of CC>2 is a commercial operation in North America with more
than 350 million standard cubic feet being moved significant distances, mainly for
enhanced oil recovery operations.
CC>2 separation processes applied to a fossil fuel-fired power plant result in additional
energy consumption and the direct reduction of power output. Starting with atmospheric
pressure and a desired pipeline pressure of 1,600 psia, the energy requirement for CC>2
liquefaction by inter-cooled 5-stage compression is about 0.05 kWh/lb of CC>2. For 90%
CC>2 removal, the CC>2 liquefaction reduces the efficiency of coal-fired power plants by
about 3 to 5 percentage points. Estimates of pipeline diameter and CO2 flow rates are
shown in Exhibit 5-II.69
Exhibit 5-11 Pipeline Size and CO2 Flows
Diameter, inches
12
16
20
24
28
32
Range of Flow Rate,
millions of tons per year
Ito3
3 to 7
7 to 12
12 to 19
19 to 28
28 to 40
An approximate straight-line cost for pipeline construction is $15,000 per inch-mile.
Annual O&M costs are about $1,500 per mile independent of pipe diameter. The costs
are strongly dependent on site and route specific features. However, transportation costs
are typically viewed as relatively minor components of the overall cost for carbon
management. Exhibit 5-12 shows CC>2 transportation cost estimates from a source,
ranging from $0.50 to $2 per metric ton for a distance of 100 km, or about 220 miles.70
69 Evaluation of Innovative Fossil fuel Power Plants with CO2 Removal US DOE/NETL and EPRI,
Prepared by ParsonsEnergy and Chemicals Group, December 2000 - updated 2002.
70
The Economics of CO2 Storage. Gemma Heddle, Howard Herzog & Michael Klett, MIT. August 2003.
5-16
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Section 5
Carbon Management
Exhibit 5-12, CO2Transportation Cost Data
Total Annual Cost
Construction and O&M
o
o
O
O
o
O
flow rate (Mt CO;/yr)
5.9 Geological Sequestration
Carbon sequestration is the removal and retention of carbon dioxide (CO2) in terrestrial, oceanic,
and geologic environments. Geologic sequestration - also known as carbon capture and storage
(CCS) - is the underground emplacement of anthropogenic CC>2 captured from industrial
facilities, such as power plants and cement manufacturing facilities. Instead of releasing the
captured CC>2 to the atmosphere, CCS operations will compress the gas to a "supercritical" liquid
and send it via a pipeline to an injection well, where it is pumped underground to depths
generally greater than 800 meters to maintain critical pressures and temperatures. Once
underground, the CC>2 occupies pore spaces in the surrounding rock. Candidate sites for geologic
storage include deep saline formations, depleted oil and gas reserves, and unminable coal beds.
Suitable sites have a caprock, or an overlying impermeable layer, that prevents CC>2 from
escaping back towards the surface.
There appear to be no major technical hurdles to implementing geologic sequestration in
the U.S. The various technologies required to implement a CCS project exist today and
several are used in the field routinely by the oil and gas and waste disposal industries.
Although there may be risks associated with large-scale injection and potential leaks of
CC>2, it is anticipated that they can be avoided with proper siting, operation and
maintenance, and long-term monitoring. Capture costs and concerns with long-term
liability for storage sites are major considerations still being addressed by ongoing R&D.
In addition to technical and economic hurdles to commercial deployment, public
awareness and acceptance of projects to store very large volumes of CC>2 will need to be
greatly increased. Also, while there is experience with regulations and permits for
smaller amounts of materials, i.e. hazardous waste and waste injection wells, there is no
set of regulations for CC>2 storage, and in addition to environmental issues, questions
5-17
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Section 5 Carbon Management
remain about ownership and liability for the CC>2 and for ownership of the storage pore
space.
In the U.S., large point sources of CO2 (each emitting more than 100,000 tons of CC>2 per
year) originate from various industrial sectors including coal-fired power plants,
ammonia production, and cement manufacture among others. There are approximately
1,700 of these sources in the U.S. that collectively emit more than 3 gigatons of CO2
(GtCO2) per year.71 Initial assessments show there is an abundance of geologic storage
capacity, well distributed throughout the U.S. Although capacity estimates vary, recent
studies from Battelle estimate storage capacity of more than 3,900 GtCO2
5.9.1 Potential Storage Formations
The geological formations of primary interest to sequestration include:
• Existing oil and gas fields and potential enhanced oil/gas recovery (EOR) conditions
• Depleted oil and gas fields
• Deep saline formations
• Deep unminable coal seams, possibly with coal bed methane recovery
Other possibilities include storage in mafic/basalt rock formations and above ground
conversion of CC>2 to solid carbonate materials. These are much less mature options than
the four bulleted items. The MIT reference noted previously contains details about the
technologies and costs for various sequestration options.
Existing oil and gas fields and enhanced oil/gas recovery (EOR)
Enhanced recovery with CC>2 floods is used commercially in North America. There were
some 70 CO2 floods in the United States in 2000 that resulted in almost 200,000 bbl of oil
per day, which is equivalent to 5 percent of total U.S. oil production during the same
period. Most of these CC>2 floods are located in the southwestern United States within the
Permian basin of western Texas and eastern New Mexico. The majority of the CC>2 for
EOR operations comes from natural sources, because CO2 captured from most
anthropogenic sources is currently too expensive to compete with the naturally occurring
(produced) CO2.
EOR and CO2 sequestration are being studied extensively for the first time in an
international project at the Weyburn field, Saskatchewan Canada. The CO2 source is the
Dakota Gasification plant near Great Plains North Dakota. The Weyburn EOR project
will not conclude with the conventional "blowdown" which may release CO2 back to the
atmosphere. Instead the operators will maintain the site in order to test and monitor
long-term sequestration. Sequestration as part of an EOR operation has the attraction of
being a revenue producing process, and is very likely to be some of the first sequestration
71 "Carbon Dioxide Capture and Geological Storage," Report by JJ Dooley, et al., April 2006, GTSP
Website hitp://www.pnl.gov/gtsp/ncws/. accessed June 5, 2006
5-18
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Section 5 Carbon Management
opportunities to be implemented at large scale. For example, the British Petroleum (BP)
Carson Hydrogen Power project will convert the carbon in petroleum coke, a by-product
of the refining process, and recycled waste water into hydrogen, a clean-burning gas, and
CC>2. The hydrogen gas will be used to fuel a power station capable of providing the
California power grid with 500 MW of electricity. At the same time, about 4 million
tonnes of CC>2 per year will be captured, transported and stored in deep underground oil
reservoirs where it will enhance existing oil production.
If EOR projects are to include a CO2 sequestration component, changes may be needed
to the facility and/or operations. For example, different project goals may necessitate
additional site characterization, the use of multiple geologic formations, or temporary
CO2 storage. A critical component will be monitoring and verifying the volume of CO2
stored and additional site closure practices to ensure CO2 is sequestered for the long time
frames required.
Depleted oil and gas fields
Injection of CC>2 into depleted oil and gas fields would be similar to commercial EOR
experience. While one of the main attractions for using the fields is that large amounts of
geological data will be available, the existing fields will also have numerous old wells
that may no longer be sealed and could leak the CO2 back to the atmosphere. Before
sequestration, the existing field would have to be closely examined and issues such as
concerns regarding old wells would have to be addressed.
Deep saline formations
Sequestration in deep saline deposits has the potential to geologically store the most CC>2.
Along with the Weyburn field tests, the only other commercial-scale projects dedicated to
geologic CC>2 storage are at the Sleipner West field in the North Sea and the In Salah gas
field in Algeria. Sleipner West is a natural gas/condensate field operated by Statoil and is
located about 500 miles off the coast of Norway. The natural gas has a CC>2 content of
about 9 percent which, to meet commercial specifications, must be reduced to 2.5
percent. At Sleipner, the CC>2 is compressed and injected via a single well into the Utsira
Formation, a 500 foot thick, brine saturated formation located at a depth of about 2,000
feet below the seabed. The operation is commercially driven by a carbon tax imposed by
Norway.
In 2004, BP launched a CO2 capture and storage project at the In Salah gas field, in the
Algeria desert. In Salah is a joint venture between Sonatrach, the Algeria national energy
company, BP and Statoil. Approximately 10% of the gas in the reservoir is made up of
CC>2. Rather than venting the CC>2, which is the established practice on other projects of
this type, the project is compressing it and injecting it in wells 1,800 meters deep into a
lower level of the gas reservoir where the reservoir is filled with water. Around one
million tonnes of CC>2 will be injected into the reservoir every year.
The most important trapping mechanism to contain CO2 in deep saline reservoirs is
hydrodynamic trapping, where a caprock prevents upward movement of CC>2. Saline and
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Section 5 Carbon Management
other types of reservoirs also have two additional trapping mechanisms that help contain
the CO2 : solubility and mineral trapping. Solubility trapping is the dissolution of CC>2
into the reservoir fluids; mineral trapping is the reaction of CC>2 with minerals in the host
formation to form carbonates. As the CC>2 moves through the deposit, it comes into
contact with uncarbonated formation water and reactive minerals. A portion of the CC>2
dissolves in the formation water and becomes permanently fixed by reactions with
minerals in the host rock. Over long periods of time, the CC>2 might all dissolve and be
fixed by mineral reactions, essentially becoming permanently sequestered.
DOE and others are testing sequestration in deep saline deposits in the U.S. First round
of tests are completed in the Frio formation, a deep saline deposit in Texas. A discussion
of DOE's Regional Sequestration Partnership and summary of proposed projects follows
in Section 5.10.
Deep unminable coal seams, possibly with coal bed methane recovery
Sequestration into deep coal seams has been proposed as a means to safely store CO2
because the CO2 will both react with the coal materials, and displace methane from the
coal. Some tests have been performed for the purpose of enhancing coal-bed methane
recovery, but little has been done to examine the sequestration issues. As with the other
EOR technologies there is the potential benefit of increased energy production that could
pay for some or all of the CO2 sequestration costs.
5.10 COi Sequestration Regional Partnerships
A very important effort to advance the technical knowledge and acceptance of
sequestration is the U.S. DOE program of Regional Sequestration Partnerships. The
seven partnerships include 40 States and 4 Canadian Provinces. More than 200 industry
and government organizations are participating with the primary contractors. The major
results and data from Phase I can be found at the NETL/DOE website.72 These results
will be used to deploy a geographic information system (GIS) database that will be
available to partnership members and the public. DOE will use the regional data to
develop a National/North American sequestration GIS.
As part of the regional effort to date, the partnerships examined CO2 separation and
capture technologies and have, to varying degrees, compared and matched technologies
with the sources of CO2 and the potential sequestration sites. The objective of this work
was to estimate cost curves for carbon management within the region.
The same regional partnerships have been awarded contracts for a second phase of work.
In Phase II, data collection, public awareness and regulatory assessment will continue,
and fieldwork will inject small amounts of CO2 into selected geological formations.
Tests of terrestrial sequestration in the different regions will also be conducted.
72 NETL/DOE Website, www.nctl.doc.gov/icchnologics/carbon scq/partncrships/partncrships.html.
accessed on May 30, 2006
5-20
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Section 5 Carbon Management
As noted at the beginning of this report, challenges associated with geological
sequestration could be the main obstacle to power generation carbon management. The
DOE roadmap for sequestration includes one large scale sequestration project by 2009,
but it is not clear how this demonstration would be coordinated with the regional
partnerships' second phase, which also runs to about 2009 and DOE's FutureGen
concept, which aims for completion by 2012. Such demonstrations will help reduce
technical uncertainties, especially with regard to potential health, safety, and
environmental impacts of commercial activities.
5-21
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Workshop, Knoxville, TN April 13, 2005
Supercritical Boiler Technology Matures. Mark Richardson Hitachi America, Ltd., Yoshihiro Kidera,
Babcock-Hitachi K.K., Yoshio Shimogori Babcock Hitachi K.K.
Boiler Materials for Ultra Supercritical Coal Power Plants. U.S. DOE NO.: DE-FG26-01NT41175 First
Quarterly Report January 2004.
Wet Scrubbers for SOZ Control. IEA Clean Coal Centre Web site.
New Coal Plant Opposition Draft and Final Permits. EPA Clean Air Task Force.
Supercritical Boiler Technology for Future Market Conditions. Joachim Franke and Rudolf Krai
Siemens Power Generation Presented at Parsons Conference October 2003.
Developments in Pulverized Coal-Fired Boiler Technology. J.B. Kitto Babcock & Wilcox
Presented to the Missouri Valley Electric Association Engineering Conference April 1996
Kansas City, Missouri, U.S.A.
Control of Mercury Emissions from Coal-Fired Electric Utility Boilers: Interim Report Including Errata
Dated 3-21-02 U.S. EPA Office of Air Quality Planning Standards, Prepared by National Risk
Management Research Laboratory Research Triangle Park, NC 27711.
Power Plant Water Usage and Loss Study. U.S. DOE NETL, August 2005.
-------
Appendix A Cost Estimate Data
Appendix A covers the capital and operating cost estimates for IGCC and PC power
plants. The costs are derived from recent published documents and Nexant experience
with similar projects. The estimates specifically prepared for the plant configurations
selected for this study are in the 4th Quarter 2004 dollars.
As noted previously, this study is a snapshot in time and costs as well as performance are
evolving and changing as experience increases and because of more basic changes in the
economy such as price changes (steel and energy are prime examples). The study costs
are conceptually estimated for an Nth plant, i.e. one of many commercial facilities and
not for demonstration or the first of a kind plants needed to obtain commercial viability.
The Nth plant criteria are truer for PC plants than for IGCC plants because of the
numbers built for each technology. There are also costs that can not be fully estimated
such as site differences, warrantees/guarantees or fees for systems treating fuels or other
conditions that are outside of the suppliers' experiences.
The uncertainty of cost estimates sometimes results in values presented as ranges, or with
uncertainties assigned for all or parts of the estimates. The engineering level of this study
did not employ this approach, but the study reader should be aware that the costs will
vary for a number of reasons at the time of the "snapshot", and will also vary with time as
the knowledge base expands.
Summary
Cost data presented in this appendix are drawn from a number of sources. Where
appropriate, the data has been updated by escalation to the end of 2004 price and wage
level, and adjusted to a consistent 500 MW net plant size. The costs are consistent with
the plant performance estimates presented in the body of the report. However, it should
be noted that site and design specific criteria can cause a significant range of costs that
could only be refined with much more detailed engineering, including budgetary quotes
and engineering packages from major technology suppliers.
Exhibits A-l and A-2 summarize the cost estimates developed for the PC and IGCC plant
configurations used in this study. The methodologies and sources for these estimates are
discussed further in this appendix. While data is from several sources, the values have
been adjusted as noted above and consistent factored cost elements such as engineering
services, contingency and other owner's costs are used to calculate the cost categories in
the exhibits.
A-l
-------
Appendix A
Cost Estimate Data
Exhibit A-l, Total Capital Requirement and Operating Cost
Power Plants
Subcritical PC
Total Capital Requirement $/kW
Annual Operating Cost, 1,000s
Supercritical PC
Total Capital Requirement $/kW
Annual Operating Cost, 1,000s
Ultra Supercritical PC
Total Capital Requirement $/ kW
Annual Operating Cost, 1,000s
GE Energy IGCC
Total Capital Requirement $/ kW
Annual Operating Cost, 1,000s
Shell IGCC
Total Capital Requirement $/ kW
Annual Operating Cost, 1,000s
Bituminous Coal
1,347
27,700
1,431
29,000
1,529
30,400
1,670
27,310
1,840
Not Reported
Subbituminous Coal
1,387
28,300
1,473
29,600
1,575
31,100
1,910
29,700
2,100
Not Reported
Lignite Coal
1,424
29,640
1,511
30,940
1,617
32,440
Not Applicable
Not Applicable*
2,350
34,000
* The GE Energy gasification technology is not used with lignite.
Exhibit A-2 Summary of Costs
Power Plants
Subcritical PC
Bituminous Coal
Subbituminous Coal
Lignite
Supercritical PC
Bituminous Coal
Subbituminous Coal
Lignite
Ultra Supercritical PC
Bituminous Coal
Total Plant
Cost $/ kW
1,187
1,223
1,255
1,261
1,299
1,333
1,355
Total Plant
Investment
$/kW
1,303
1,343
1,378
1,384
1,426
1,463
1,482
Total Capital
Requirement
$/kW
1,347
1,387
1,424
1,431
1,473
1,511
1,529
Operating Cost
$l,OOOs
27,700
28,300
29,640
29,000
29,600
30,940
30,400
A-2
-------
Appendix A
Cost Estimate Data
Power Plants
Subbituminous Coal
Lignite
GE Energy IGCC
Bituminous Coal
Subbituminous Coal
Lignite
Shell IGCC
Bituminous Coal
Subbituminous Coal
Lignite
Total Plant
Cost $/ kW
1,395
1,432
1,430
1,630
Not Applicable
1,570
1,790
2,000
Total Plant
Investment
$/kW
1,526
1,566
1,610
1,840
Not
Applicable
1,770
2,020
2,260
Total Capital
Requirement
$/kW
1,575
1,617
1,670
1,910
Not
Applicable
1,840
2,100
2,350
Operating Cost
$l,OOOs
31,100
32,440
27,310
29,700
Not Applicable
Not Reported
Not Reported
34,000
* The GE Energy gasification technology is not used with lignite.
A-2
-------
Appendix A Cost Estimate Data
Pulverized Coal Plant Cost Estimates
Capital Costs
Exhibits A-3, 4, and 5 present cost estimates for the pulverized coal plants with a
capacity of 500 MW net. Exhibit A-3 show subcritical units with three study coal types -
high-sulfur bituminous, low-sulfur subbituminous, and lignite. A breakdown of costs is
shown for the first coal as an example of how costs are distributed among the major plant
sections. Cost breakdowns would be similar for the other coals.
Exhibits A-4 and 5 show the estimates for supercritical and ultra-supercritical units and
the three coals. An allowance for uncertainty (contingency) of 20% is used for the ultra-
supercritical plant as an estimate of its less mature technology development. The
allowance is 15% for other plants. Other cost factors used in the PC capital cost
estimates are as follows:
• Engineering Services, 8% of Total Constructed Cost (TCC)
• Interest During Construction, 12% of TCC
• Startup, 2.5% of TCC
• Spare Parts, Working Capital, & Land, 2% of TCC
• Escalation to 2004 as required using 2% per year cost escalation
Exhibit A-6 presents a comparison of costs found in the literature for PC plants. While
not exactly the same in all critical aspects, these plants are consistent and show the
relatively small variance in costs from subcritical to ultra-supercritical. The differences
in costs from the steam generator choice could easily be overshadowed by site conditions
or owner preferences among the plants.
There is only a limited amount of cost information available in the industry for
comparison of the PC plants fired by the three coals. The Canadian Clean Power
Coalition (CCPC) published an executive summary of work with some information that is
reported below.
Capital costs for supercritical plants in Canadian dollars (not reported, but the year is
about 2002) and the associated heat rates are as follows:
• 300 MW lignite plant $915 million 9,400 Btu/kWh
• 400 MW subbituminous plant $1005 million 8,900 Btu/kWh
• 300 MW bituminous plant $866 million 8,900 Btu/kWh
The above capital costs in $/kW, using 1.56 Canadian to U.S. dollars, are as follows:
• 300 MW lignite plant $1,955
• 400 MW subbituminous plant $1,610
• 300 MW bituminous plant $ 1,850
A-4
-------
Appendix A Cost Estimate Data
There is a question of why the bituminous coal-fired plant is more expensive than the
subbituminous plant. The CCPC has been contacted and asked if the reported values are
correct, and the reason for the seemingly out-of-sequence cost comparison. The 500 MW
bituminous supercritical plant cost developed for the EPA study is about $1,430 /kW.
This is a significant difference with the DOE and EPRI costs, even considering Canadian
conditions and economies of scale. The CCPC considers its work proprietary, and could
not provide details that might explain the differences. The Canadian work, while noted,
is not used in the current study.
An EPRI paper presented at the Gasification Technologies Conference, 2004, "Pulverized
Coal and IGCC Plant Cost and Performance Estimates, George Booras and Neville Holt
showed a graphic relationship between coal quality, cost and performance of PC plants
and IGCC plants. The figure is repeated here as Exhibit A-7.
A-5
-------
Appendix A
Cost Estimate Data
Exhibit A-3 Subcritical Pulverized Coal Estimates, 1,000s
2004 Price and Wage Level
5 00 MW Net
Subcritical Pulverized Coal Plant
PC Boiler and Accessories
Flue Gas Cleanup
Ducting and Stack
Steam T-G Plant, including
Cooling Water System
Accessory Electric Plant
Balance of Plant
Subtotal, Total Constructed Cost
Engineering Services, 8% of TCC
Allowance For Uncertainty, 15% of
TCC
Total Plant Cost
Total Plant Cost - $ per Kilowatt
Interest During Construction (IDC),
12% of TCC
Total Plant Investment
Prepaid Royalties
Initial Catalyst and Chemicals
Startup, 2. 5% of TCC
Spare Parts, Working Capital, &
Land, 2% of TCC
Total Capital Investment
Total Capital Cost - $ per
Kilowatt
High-Sulfur Bituminous Coal
Total
Equipment Materials Installation Installed
Cost
67,200 - 29,400 96,600
45,600 - 26,700 72,300
13,100 400 10,400 23,900
67,100 5,800 26,800 99,700
12,200 3,800 11,100 27,100
61,200 25,200 76,700 163,100
266,400 35,200 181,100 482,700
38,600
72,400
593,700
1,187
57,900
651,600
0
100
12,100
9,700
673,500
1,347
Subbitu-
minous Lignite
Coal
Total Total
Installed Installed
Cost Cost
99,500 102,100
74,500 76,500
24,600 25,300
102,700 105,300
27,900 28,700
168,000 172,400
497,200 510,300
39,800 40,800
74,600 76,500
611,600 627,600
1,223 1,255
59,700 61,200
671,300 688,800
0 0
100 100
12,400 12,800
9,900 10,200
693,700 711,900
1,387 1,424
A-6
-------
Appendix A
Cost Estimate Data
Exhibit A-4 Supercritical Pulverized Coal Estimates, 1,000s
2004 Price and Wage Level
500 MW Net
Supercritical Pulverized Coal
Plant
PC Boiler and Accessories
Flue Gas Cleanup
Ducting and Stack
Steam T-G Plant, including
Cooling Water System
Accessory Electric Plant
Balance of Plant
Subtotal, Total Constructed Cost
Engineering Services, 8% of TCC
Allowance For Uncertainty,
15% of TCC
Total Plant Cost
Total Plant Cost - $ per Kilowatt
Interest During Construction (IDC),
12% of TCC
Total Plant Investment
Prepaid Royalties
Initial Catalyst and Chemicals
Startup, 2.5% of TCC
Spare Parts, Working Capital, &
Land, 2% of TCC
Total Capital Investment
Total Capital Cost - $ per
Kilowatt
High-Sulfur
Bituminous Coal
Total Installed
Cost
129,400
72,600
24,300
109,200
28,600
148,600
512,700
41,000
76,900
630,600
1,261
61,500
692,100
0
100
12,800
10,300
715,300
1,431
Subbituminous
Coal
Total Installed
Cost
133,300
74,800
25,000
112,500
29,400
153,000
528,000
42,200
79,200
649,400
1,299
63,400
712,800
0
100
13,200
10,600
736,700
1,473
Lignite
Total Installed
Cost
136,700
76,700
25,700
115,400
30,200
157,000
541,700
43,300
81,300
666,300
1,333
65,000
731,300
0
100
13,500
10,800
755,700
1,511
A-7
-------
Appendix A
Cost Estimate Data
Exhibit A-5 Ultra Supercritical Pulverized Coal Estimates, 1,000s
2004 Price and Wage Level
500 MW Net
Ultra Supercritical Pulverized
Coal Plant
PC Boiler and Accessories
Flue Gas Cleanup
Ducting and Stack
Steam T-G Plant, including
Cooling Water System
Accessory Electric Plant
Balance of Plant
Subtotal, Total Constructed Cost
Engineering Services, 8% of TCC
Allowance For Uncertainty,
20% of TCC
Total Plant Cost
Total Plant Cost - $ per Kilowatt
Interest During Construction (IDC),
12% of TCC
Total Plant Investment
Prepaid Royalties
Initial Catalyst and Chemicals
Startup, 2.5% of TCC
Spare Parts, Working Capital, &
Land, 2% of TCC
Total Capital Investment
Total Capital Cost - $ per
Kilowatt
High-Sulfur
Bituminous Coal
Total Installed
Cost
138,200
67,500
23,100
130,800
27,200
142,400
529,200
42,300
105,800
677,300
1,355
63,500
740,800
0
100
13,200
10,600
764,700
1,529
Subbituminous
Coal
Total Installed
Cost
142,300
69,500
23,800
134,700
28,000
146,700
545,000
43,600
109,000
697,600
1,395
65,400
763,000
0
100
13,600
10,900
787,600
1,575
Lignite
Total Installed
Cost
146,000
71,400
24,400
138,200
28,800
150,500
559,300
44,700
111,900
715,900
1,432
67,100
783,000
0
100
14,000
11,200
808,300
1,617
A-8
-------
Appendix A
Cost Estimate Data
Exhibit A-6, Comparison of Cost Estimates from Published Sources
Net
Capacity,
MW
Cost
Year
Coal
SO2
Control
NOX Control
Participate
Heat Rate
Btu/kWh
% Efficiency,
HHV
Total
Plant
Cost,
$/kW
Market Based Advanced Coal Power Systems Final Report, May 1999 U.S. DOE/FE-0400
Subcritical PC
Supercritical PC
Ultra Supercritical PC
400 1998 Illinois #6 WL-FGD
400 1998 Illinois #6 WL-FGD
400 1998 Illinois #6 WL-FGD
Low NOX
Burners
Low NOX
Burners, SCR
Low NOX
Burners, SNCR
ESP
Fabric Filter
Fabric Filter
9,077
37.6%
8,568
39.9%
8,251
41.4
Supercritical PC
Ultra Supercritical PC
462 Dec-99 Illinois #6 WL-FGD
506 Dec-99 Illinois #6 WL-FGD
D™
Burners, SCR
D™
Burners, SCR
Fabric Filter
Fabric Filter
8,421
40.5%
7,984
42.7%
Subcritical PC
Subcritical PC
Supercritical PC
Supercritical PC
500
2003 Illinois #6 WL-FGD
Fabric Filter
9,560
500 2003 Illinois #6 WL-FGD
Fabric Filter
8,920
1,129
1,173
1,170
Evaluation of Innovative Fossil Fuel Power Plants with COZ Removal, EPRI, U.S. DOE/NETL 1000316 December 2000
1,143
1,161
Pulverized Coal and IGCC Plant Cost and Performance Estimates, George Booras EPRI October 2004
1,290
500 2003 —""6" WL-FGD D ^ Fabric Filter 9,310 1,230
#8 Burners, SCR
1,340
500 2003 —""6" WL-FGD „""'™D Fabric Filter 8,690 1,290
#8 Burners, SCR
A-9
-------
Appendix A
Cost Estimate Data
Exhibit A-7, Comparison of Coal Quality, Cost and Performance
1,40
1.35
o 1-30
re
re 1.25
U
O
re
DC
*^
re
o
1.20
1.15 -
I 1.10
IT
1.05 -
1.00
—. —
-- : !
PC
- - PC Rate
#6
WY
Coal HHV
A-10
-------
Appendix A Cost Estimate Data
Operating and Maintenance Costs
Operating costs from the DOE/NETL and EPRI report were reviewed and updated for the
study. The costs are presented in Exhibit A-8.
Exhibit A-8, Annual Operating and Maintenance Costs, SlOOOs
High
Nominal 500 MW PC Plants „ . Sul&r
Bituminous
Coal
Subcritical Pulverized Coal
Operating Labor
Maintenance
Administrative & Support Labor
Consumables
TOTAL
Supercritical Pulverized Coal
Operating Labor
Maintenance
Administrative & Support Labor
Consumables
TOTAL
Ultra Supercritical Pulverized Coal
Operating Labor
Maintenance
Administrative & Support Labor
Consumables
TOTAL
Fuel Costs and Credits for Byproducts
5,300
6,800
2,100
13.500
27,700
5,300
7,300
2,100
14.300
29,000
5,300
8,000
2,100
15.000
30,400
are excluded
Subbituminous
Coal
5,300
7,000
2,100
13.900
28,300
5,300
7,500
2,100
14.700
29,600
5,300
8,200
2,100
15.500
31,100
Lignite
5,830
7,200
2,310
14.300
29,640
5,830
7,700
2,310
15.100
30,940
5,830
8,500
2,310
15.800
32,440
As shown by the table, there is not a significant difference in O&M caused by coal type,
or the PC technology. Operating and support labor is judged to be the same for the
bituminous and subbituminous plants and somewhat more for lignite; Maintenance costs
increase as the cost for the plants increase, as does consumables. The consumables
include water, chemicals, miscellaneous consumables, and wastes disposal.
While not shown on the table because it is plant and location dependent, the fuel costs for
the different coals would be a much larger delta of O&M costs. Typical costs and ranges
for the three coals are shown on Exhibit A-9. Illinois and Ohio represent the high sulfur
A-ll
-------
Appendix A
Cost Estimate Data
bituminous coal, North Dakota and Texas represent lignite and Wyoming is the
subbituminous coal. (There is no explanation for the delivered Illinois price being lower
than the mine cost.)
Exhibit A-8, 2004 Coal Price Data
EIA Coal Price Data 2004; cost per million Btus calculated
Illinois
Ohio
North
Dakota
Texas
Wyoming
$/ton
25.72
23.82
9.67
15.39
7.12
$/ton
Delivered
22.05
31.99
10.20
21.82
15.28
$/MMBtu
$ 1.10
$ 1.02
$ 0.77
$ 1.22
$ 0.40
$/MMBtu
Delivered
$ 0.94
$ 1.37
$ 0.81
$ 1.73
$ 0.87
Study Coals
MMBtu/lb
11,667
11,667
6,312
6,312
8,800
A-12
-------
Appendix A
Cost Estimate Data
Integrated Gasification Combined Cycle Cost Estimates
Background
One of the first things to be noted is that costs vary among the alternative gasification and
IGCC systems. The variations in cost are illustrated in later tables. For the present study,
the summary results are limited to 500 MW net generation IGCC plants and three coals.
For the bituminous and subbituminous coals a GE Energy (Ex-ChervonTexaco, Texaco)
gasifier with coal-water slurry feed system is used. The unit includes radiant and
convective heat recovery for higher efficient operations and uses two-50% gasification
trains. For the high moisture lignite coal, a solid feed Shell gasifier is selected with two-
50% gasification trains.
The estimated costs are summarized in Exhibit A-9. Costs are presented for Shell and the
two other coals in addition to the lignite based plant. The costs are for the end of 2004
price and wage levels and 500 MW net IGCC plants. The costs are for plants with two
50% gasification trains, but do not have a spare gasifier.
Exhibit A-9, Summary of IGCC Cost Estimates
IGCC Plants
GE Energy IGCC
Total Plant Cost $/kW
Total Plant Investment
Total Capital
Requirement $/kW
Operating Cost
Shell IGCC
Total Plant Cost $/kW
Total Plant Investment
Total Capital
Requirement $/kW
Operating Cost
Bituminous
Coal
1,430
1,610
1,670
27,310
1,570
1,770
1,840
Not Reported
Subbituminous
Coal
1,630
1,840
1,910
29,700
1,790
2,020
2,100
Not Reported
Lignite Coal
Not Applicable
Not Applicable
Not Applicable
Not Applicable
2,000
2,260
2,350
34,000
While the ConocoPhillips technology has fewer operating installations than the GE
Energy gasifier, estimates for the ConocoPhillips unit are consistently about $100 per kW
less. This is relatively small in comparison to the total costs, and the cost values could
change as site and coal specific designs are prepared for either or both technologies.
A-13
-------
Appendix A
Cost Estimate Data
Cost Data
Two cost estimate tables are presented in Exhibits A-10 and 11. The exhibits show
breakdowns of costs for the selected IGCC data. A later exhibit contains data from a
number of recent publications, and is presented to compare costs across the data set for
types of gasifiers with different types of coals.
Exhibit A-10, GE Energy (Ex-Texaco) IGCC Costs, $l,OOOs
Texaco Gasifier IGCC Base Case
Escalated to 2004; Adjusted to 500 MW
nominal size
Coal Slurry Preparation
Oxygen Plant
Gasifier SINGLE UNIT
Soot Blower Recycle Compression
Gas Cooling Saturation
MDEA
Claus
SCOT
Gas Turbine System
HRSG Steam Turbine
\Water Systems
Civil
Piping
Controls
Electrical
INSTALLED COST (1C)
Engineering, 8% of 1C
Process Contingency, 5% of 1C
Project Contingency, 15% of 1C
TOTAL PLANT COST (TPC)
Total Plant Cost $/kW
Interest During Construction (IDC)
TOTAL PLANT INVESTMENT
Prepaid Royalties
Initial Catalyst and Chemicals
Startup
Spare Parts, Working Capital and Land
TOTAL CAPITAL REQUIREMENT
Total Capital Requirement $/kW
Single Train
Quench
Gasifier
38,100
73,800
45,300
Na
24,100
7,400
14,000
5,900
74,400
62,500
24,400
31,800
24,400
8,900
27,600
462,600
37,000
23,100
69,400
592,100
55,500
647,600
2,310
230
11,570
9,250
670,960
1,342
Illinois #6 coal; Single train of gasification; W501 G turbine;
SCOTT to elemental sulfur)
$/kW
76
148
91
na
48
15
28
12
149
125
49
64
49
18
55
925
74
46
139
1,184
1,184
111
1,295
5
0
23
19
1,342
cold gas
Single Train
Radiant + $/kW
Convective Gasifier
37,500
74,000
108,700
4,800
14,500
7,700
13,900
5,900
74,400
69,900
29,200
37,900
29,200
10,700
32,900
551,200
44,100
27,600
82,700
705,600
66,100
771,700
2,760
280
13,780
11,020
799,540
1,483
cleaning (MDEA,
70
137
202
9
27
14
26
11
138
130
54
70
54
20
61
1,023
82
51
153
1,309
1,309
123
1,432
5
1
26
20
1,483
CLAUS,
Exhibit A-10 data is from the DOE/NETL report "Texaco Gasifier IGCC Base Cases",
PED-IGCC-98-001 latest revision June 2000. It is important to note that the costs are for
a single train of gasification. Using two trains (50% each) or using two 50% trains plus a
A-14
-------
Appendix A
Cost Estimate Data
spare gasifier could increase costs by $150 to $200 per kW. The costs have been
escalated to end of 2004 price levels and adjusted to 500 MW net plant size. Also, the
cost items below the Installed Cost total have been adjusted to be consistent across the
study plants. The plant with radiant and convective heat recovery generates more
electricity and is more efficient, but is also more costly.
Exhibit A-11 shows similar (not as many breakdowns) data for the ConocoPhillips
gasifier (Ex-EGas, Global Energy gasifier).
Exhibit A-ll, ConocoPhillips (Ex-EGas) IGCC Costs, $l,OOOs
ConocoPMllips Gasifier Escalated to 2004;
Adjusted to 500 MW nominal size
2 - 50% Gasifier
Trains with H- $/kW
Type Turbine
Gasifier, ASU & Accessories 206,700 413
Gas Cleanup & Piping 42,400 85
Combustion Turbine and Accessories 77,200 154
HRSG, Ducting and Stack 25,800 52
Steam T-G Plant, including Cooling Water
System
Accessory Electric Plant 28,800 58
Balance of Plant 106,500 213
INSTALLED COST 533,100 1,066
Engineering Services and Fee, 8% 533,100 1,066
Process Contingency, 5% 42,600 85
Project Contingency, 15% 26,700 53
TOTAL PLANT COST (TPC) 80,000 160
Total Plant Cost $/kW 682,400 1,365
Interest During Construction (IDC) 1,365
TOTAL PLANT INVESTMENT 64,000 128
Prepaid Royalties 746,400 1,493
Initial Catalyst and Chemicals 2,700 5
Startup 300 1
Spare Parts 13,300 27
Working Capital
Land 200 Acres 10,700 21
TOTAL CAPITAL REQUIREMENT
Total Capital Requirement $/kW 773,400 1,547
Illinois #6 coal; 2 -50% trains of gasification; Advanced H turbine; cold gas
cleaning (MDEA, GLAUS, SCOTT to elemental sulfur)
Costs shown on Exhibit A-ll are from the DOE/NETL report "Evaluation of Innovative
Fossil Fuel Power Plants with CC>2 Removal", 1000316, December 2000. Co-sponsors
are U.S. DOE/NETL and EPRI. The costs have been escalated to the end of 2004 and
adjusted to 500 MW net generation consistent with the process utilized for data in Exhibit
A-10. From the two exhibits one may concluded that a reasonable Total Capital Cost
would be $1,600 per kW, on a higher heating value basis. The higher cost value
A-15
-------
Appendix A Cost Estimate Data
considers the GE Energy gasifier estimates only having a single gasifier train. The
efficiency value may be optimistic in view of the relatively advanced turbines selected
for the two cases.
Exhibit A-12 presents a compilation of data for the current study. Except for the first two
items, which are summations of data in Exhibits A-10 and 11, the costs are raw data from
the publications; they are not escalated or adjusted for plant size. However, the data is
reasonably recent, and sizes are near the 500 MW nominal scale.
The data illustrates the cost variations for IGCC plants, even within the same category of
gasifier. Design philosophies are important, especially the selection of gasification trains
- a single train versus two 50% trains. Also, because of the relatively immature nature of
the technology, some cases include spare gasification units as backup for planned and
unplanned shutdowns.
Coal Quality and Cost
The great preponderance of engineering assessments for IGCC systems has been
performed using bituminous coals as the feedstock. Because the gasifier vessel typically
operates under pressure - from 400 to 1000 psia, and temperatures in the range of 2,500
F, two of the most widely used technologies have selected a coal/solids and water slurry
feed to facilitate introduction of the solids into the gasifier. The third commercial unit
developed by Shell and it licensee, Uhde, uses a lockhopper system to feed the solid fuel
into the reactor. The feed for the Shell gasifier must be dried to about 5% total moisture
to prevent material handling problems. The drying process for subbituminous and lignite
coals can present technical problems, adds to the cost, and requires emission control.
In addition to the material handling issues and energy losses to evaporate excess water
from the low rank coals, the water also increases the amount of oxygen that must be
produced, again increasing costs and consuming more auxiliary power.
GE Energy has in the past declined to provide data for subbituminous and lignite coals as
a feed for their gasifier. ConocoPhillips has claimed to be able to use subbituminous
coals and are not clear about using lignite. For these various reasons, in this study, the
GE Energy gasifier with radiant and convective heat recovery was chosen for the
bituminous and subbituminous coals, and Shell is used with lignite.
To estimate costs for the three study coals, data shown on Exhibit A-12 from the studies
by the Canadian Clean Power Coalition and EPRI was examined. The EPRI data appears
to be the more consistent with experience at Nexant and Bechtel. The Canadian work is
proprietary and details are not available. It is not clear that all of the impacts of the
lignite, for example, have been accounted for in the cost or performance results. In an
EIA report on the work, some of the results were either misprinted, or do not seem
reasonable.
A-16
-------
Appendix A
Cost Estimate Data
Exhibit A-12, Comparison of IGCC Cost Data $l,OOOs
Data Sources
1, Texaco Gasifier IGCC Base
Case; Escalated to 2004; Adjusted
to 500 MW nominal size:1'2
Quench Heat Recovery
Rad. + Conv. Heat Recovery
2, ConnoeoPMllips with H Turbine
Escalated to 2004; Adjusted to
nominal 500 MW:1"3
3, IGCC Plant Cost and
Performance Estimates:4
ConocoPhillips with Spare
ConocoPhillips w/o Spare
ConocoPhillips with Spare
ConocoPhillips w/o Spare
4, 3/2005 GCEP Presentation,
Neville Holt, EPRI, 2002 Data, all
cases have spare gasifier.
GE Quench (Texaco) 512 MW
GE (Texaco) Radiant 550 MW
ConocoPhillips 520 MW
Shell 530 MW
5. Canadian Clean Power Coalition5
GE Energy Quench,
425 MW Net, Bituminous Coal
Installed Total Plant Total Plant Total Plant
Cost Cost Cost$/kW Investment
462,635 592,173 1,184 665,207
551,058 682,241 1,266 769,321
533,100 682,400 1,365 764,288
1,440
1,330
1,350
1,250
1,300
1,550
1,350
1,650
Not
Reported
Total Capital Total Capital
„ . , Requirement
Requirement $/kw
692,507 1,385
799,521 1,483
795,654 1,591
1,710
1,580
1,610
1,490
Not
Reported
Not
Reported
Not
Reported
Not
Reported
1,410
%
Efficiency
HHV
39.7%
43.5%
43.1%
37.4%
37.4%
39.6%
39.6%
36.7%
39.3%
39.6%
40.7%
37.6%
MW
Net
500
539
500
500
500
500
500
512
550
520
530
425
Feedstock
Illinois #6
Illinois #6
Illinois #6
Illinois #6
Illinois #6
Pittsburgh #8
Pittsburgh #8
Pittsburgh #8
Pittsburgh #8
Pittsburgh #8
Pittsburgh #8
Bituminous
Coal
A-17
-------
Appendix A
Cost Estimate Data
Data Sources
GE Energy Quench,
425 MW Net, Subbituminous Coal
Shell Solid Feed Gasifier
425 MW Net, Lignite
6. IGCC Studies of CO2 Capture for
Sequestration:6
Petroleum coke; 2 x Gasifier
Pittsburgh #8; 2 x Gasifier
Illinois #6; 2 x Gasifier
Powder River Basin Subbituminous;
3 x Gasifier
Lignite; 4 x Gasifier
ConocoPhillips Gasifier
Installed Total Plant Total Plant Total Plant
Cost Cost Cost$/kW Investment
Not
Reported
Not
Reported
1,276
1,254
1,364
1,551
1,738
Total Capital Total Capital
„ . , Requirement
Requirement
-------
Appendix A Cost Estimate Data
Exhibit A-13 presents the cost results for the present study.
Exhibit A-13, IGCC Costs and Coal Quality
Total Plant Cost $/kW
Total Plant Investment
$/kW
Total Capital
Requirement $/kW
Operating Costs $ 1,000s
GE Energy
IGCC
Bituminous
5 00 MW Net
1,430
1,610
1,670
27,310
GE Energy
IGCC
Subbituminous
5 00 MW Net
1,630
1,840
1,910
29,700
Shell IGCC
Lignite
5 00 MW Net
2,000
2,260
2,350
34,000
Costs in Exhibit A-13 are for the GE Energy IGCC with radiant and convective heat
recovery. Two 50% gasification trains are included for both the GE and Shell systems.
While not done for the present study, it could be reasonable to add a higher level of risk,
and thus contingency cost to the Shell and lignite plant. However, the costs are already
so high that the option is unlikely to be commercially feasible. The Canadians appear to
have switched from the assessment of gasification for lignites to the potential use of
supercritical fluidized bed units. SaskPower is conducting a study for one of their plants
that will evaluate the supercritical circulating fluidized bed option.
Cost Uncertainty
In addition to the typical project and process related uncertainties, the gasification
technology costs may also vary because the estimates for permits, licenses, and other
preliminary engineering items are not well defined. For example, gasification developers
may charge significant amounts for coal tests and engineering "packages" that a power
generator might use to evaluate technologies.
The questions about cost and performance guarantees still need to be answered. The
three major gasification developers have teamed with engineering firms and plant
component suppliers in an effort to structure the power plant so that performance and cost
can be firmly established as is tradition for the power industry. Exactly how the
guarantees will be negotiated and accepted by industry remains to be decided, but without
some reasonable agreement on these points, arrangement of project financing will be
difficult.
Gasification developers are presenting their technologies as the best option for carbon
management by the power industry. Potential CC>2 regulations and carbon markets are
A-19
-------
Appendix A Cost Estimate Data
other unknowns that make the costs uncertain and could at the minimum delay
introduction into the power generation market.
Operating Cost
Operating costs from the Texaco Gasification report and other data were reviewed and
updated for the study. The costs are presented in Exhibit A-14.
Exhibit A-14, Annual Operating and Maintenance Costs, $l,OOOs
IGCC O&M Items
Operating Labor
Maintenance
Administrative & Support Labor
Consumables
TOTAL
High Sulfur
Bituminous
Coal
9,400
14,700
1,200
2.010
27,310
Subbituminous
Coal
9,400
16,800
1,200
2.300
29,700
Lignite
(Shell
Technology)
11,300
18,700
1,400
2.600
34,000
As shown by the table, there is not a significant difference in O&M caused by coal type
except that lignite and the Shell technology will be more costly to operate and maintain.
The consumables include water, chemicals for the MDEA, Scott, Claus and other
processes, miscellaneous consumables, and wastes disposal.
While not shown on the table because it is plant and location dependent, the fuel costs for
the different coals would cause a much larger delta between the O&M costs. Typical
costs for the three coals at the mines are approximately $1.50, $0.75, and $0.50 per
million Btu for bituminous, subbituminous and lignite coals respectively. Delivered costs
to the power plant are more varied because of transportation and market competition
impacts.
A-20
-------
Appendix B Air Permit Raw Data
The exhibits in this appendix present the raw data for air emission limits summarized
from recent air permits and other related documents.73 Exhibit A presents criteria
pollutants; Exhibit B has 3 tables and shows non-criteria pollutants. The following items
provide further explanations of the data presented:
• For major pollutants, each emission value has been listed followed by the control
device or method. For example in the first item the notation "0.15 pound per million
Btu, Wet Flue Gas Desulfurization (Wet FGD)" is used in the 862 column.
• Blanks in the tables indicate that no data was found in the documents.
• Emission values listed, especially for criteria pollutants, mostly represent the actual
emission limits provided in the permit documents. For certain emission values, data
provided in the permit documents were used to convert these values to show them in
consistent units for different plants.
• For some plants, more than one emission limit is provided in the permit documents
for the same air pollutant. For example, two 862 emission limits may be provided for
a plant based on different averaging periods (e.g., one based on a 24-hour rolling
average and the other on a 30-day rolling average). In such cases, only the most
stringent emission limit has been shown in the exhibits.
• The permit documents were examined to obtain emission values for all important air
pollutants. However, for certain pollutants, either these documents did not contain
any limits or the information was not provided in terms of actual limits that could be
reported. These pollutants included fine particulate (PM2.s), sulfur trioxide, silica,
and hydrogen sulfide. In lieu of sulfur trioxide, the documents contained limits on
sulfuric acid emissions, which are reported.
73 The permit documents reflect the information available as of February 2006. The reader should refer to
the EPA RACT/BACT/LAER Clearing House Website, http://cfpubl.cpa.gov/rblc/htm/bl02.cfm. and
specific State websites to learn about permits for newly proposed facilities and any changes to the permit
documents presently covered in this report.
B-l
-------
Appendix B
Air Permit Raw Data
Exhibit A, Criteria Pollutants From Air Permits and Other Documents
Projects
Elm Road,
Wisconsin: Two 615
MW Supercritical
Pulverized Coal (PC)
Boilers1'2
Comanche
Generating Station,
Unit 3, Pueblo,
Pueblo County,
Colorado: Super
Critical PC Boiler
Nominally Rated at
7,421 MMBtu/hr4
Longview Power,
LLC Monongalia
County West
Virginia: 6,114
MMBtu/hr PC boiler,
600 MW5
Fuel
Bituminous Coal
Subbituminous
Coal
Bituminous Coal
Nitrogen Oxides
/XTT^ \
(NOx)
0.07 Ib/MMBtu
Selective
Catalytic
Reduction (SCR)
0.08 Ib/MMBtu
SCR
489 Ib/hr (0.08
Ib/MMBtu)3
SCR
Sulfur Dioxide (SO2)
0.1 5 Ib/MMBtu
Wet Limestone Flue
Gas Desulfurization
(WL-FGD)
0.10 Ib/MMBtu
Lime Spray Dryer
917 Ib/hr
(0.151b/MMBtu)
(97% reduction)3
WL-FGD
Carbon
Monoxide
(CO)
0.12
Ib/MMBtu
0.13
Ib/MMBtu
673 Ib/hr
(0.11
Ib/MMBtu)3
Paniculate
Matter
(overall)7
0.018
Ib/MMBtu
Baghouse and
a Wet
Electrostatic
Precipitator
(Wet ESP)
0.020
Ib/MMBtu
Baghouse
110 Ib/hr
(0.018
Ib/MMBtu)3
Baghouse
Paniculate
Matter (PM10)7
0.0 18 Ib/MMBtu
Baghouse and a
Wet ESP
0.0120
Ib/MMBtu
Baghouse
110 Ib/hr (0.018
Ib/MMBtu)3
Baghouse
Lead (Pb)
7.9 Ib/TBtu
0.109 Ib/hr
(17.83
Ib/TBtu3)3
B-2
-------
Appendix B
Air Permit Raw Data
Projects
Prairie State
Generating Station,
Illinois: Two 750
MW PC units6
Intermountain Power
Generating Station
Unit 3, Millard
County, Delta, Utah:
PC Unit, 950-gross
MW (900-net
MW)8'9
Indeck-Elwood
Energy Center,
Elwood, Illinois:
Nominal 660-MW
Plant with two CFB
boilers10
Plum Point Energy
Station, Arkansas:
One PC Boiler 550-
800 MW11'12
Fuel
Bituminous,
Illinois coal
(Herrin No. 6)
Bituminous Coal,
Sub-Bituminous
Coal, and Blend
Bituminous,
Illinois Coal
Subbituminous
Coal
Nitrogen Oxides
/xir^ \
(NOX)
0.07 Ib/MMBtu
SCR
0.07 Ib/MMBtu
SCR
0.10 Ib/MMBtu
CFB boiler
technology and
Selective Non-
Catalytic
Reduction
(SNCR)
0.091b/MMBtu
SCR
Carbon
Sulfur Dioxide (SO2) Monoxide
(CO)
0.182 Ib/MMBtu 0.12
(98% reduction)3 Ib/MMBtu
WL-FGD
0.1 Ib/MMBtu 0.15
WL-FGD Ib/MMBtu
0.15 Ib/MMBtu 0.10
CFB boiler Ib/MMBtu
technology, limestone
addition to the bed,
and Baghouse
0.16 Ib/MMBtu 0.16
Lime Spray Dryer Ib/MMBtu
Paniculate
Matter
(overall)7
0.015
Ib/MMBtu
Dry
Electrostatic
Precipitator
(ESP) and Wet
ESP
0.012
Ib/MMBtu
Baghouse
0.015
Ib/MMBtu
Baghouse
0.018
Ib/MMBtu
Baghouse
Paniculate
Matter (PM10)7
0.035 Ib/MMBtu
(includes
filterable and
condensable; a
limit of as low
as 0.018
Ib/MMBtu may
be set, based on
a field test) ESP
and Wet ESP
0.02 Ib/MMBtu
Baghouse
Lead (Pb)
0.0678 Ib/h
(0.0000091
Ib/MMBtu)3
0.00002
Ib/MMBtu,
2.56xlO"5
Ib/MMBtu
B-3
-------
Appendix B
Air Permit Raw Data
Projects
Thoroughbred
Generating Station,
Central City,
Kentucky: Two PC
Units, 750 MW13'14
TS Power Plant,
Eureka County,
Nevada: One PC
Unit, 200 MW5
Santee Cooper Cross
Generating Station
Units 3 and 4,
Berkeley County,
South Carolina: Two
PC Units, 5,700
MMBtu/hr5
Holocomb Unit 2,
Finney Kansas: One
PC Unit, 660 MW5
Fuel
Bituminous Coal
Subbituminous
Coal
Bituminous Coal
(Petroleum Coke
and Synfuel as
secondary fuels)
Subbituminous
Coal
Nitrogen Oxides
/xir^ \
(NOX)
0.08 Ib/MMBtu
SCR
0.067 Ib/MMBtu
SCR
0.08 Ib/MMBtu
SCR
0.12 Ib/MMBtu
(0.08 Ib/MMBtu
after initial 18
months)
SCR
Carbon Paniculate
Sulfur Dioxide (SO2) Monoxide Matter
(CO) (overall)7
0.167 Ib/MMBtu 0.10 0.018
WL-FGD Ib/MMBtu Ib/MMBtu
ESP and Wet
ESP
0.09 Ib/MMBtu for 0.15
coal with > 0.45% Ib/MMBtu
sulfur content (0.065
Ib/MMBtu for coal
with < 0.45% sulfur
content)
Lime Spray Dryer
0.1 3 Ib/MMBtu (95% 0.16 0.015
reduction)3 WL-FGD Ib/MMBtu Ib/MMBtu
ESP
0. 12 Ib/MMBtu (94% 0. 15
reduction)3 Lime Ib/MMBtu
Spray Dryer
Paniculate
Matter (PM10)7
0.0 18 Ib/MMBtu
ESP and Wet
ESP
0.0 12 Ib/MMBtu
Baghouse
0.018 Ib/MMBtu
ESP
0.0 18 Ib/MMBtu
(99,71%
reduction)3
Baghouse
Lead (Pb)
0.00000386
Ib/MMBtu
0.0000169
Ib/MMBtu
B-4
-------
Appendix B
Air Permit Raw Data
Projects
Limestone Electric
Generating Station
Units 1 and 2,
Limestone County,
Texas: PC Units,
7,863 MMBtu/hr5
Elm Road,
Wisconsin, IGCC
Unit, 600 MW2
Kentucky Pioneer
Energy Facility,
Trapp Kentucky:
IGCC Unit,540 MW
net15'16
Polk Power Station,
Polk County Florida:
IGCC Unit 260 MW
unit17'19'20
Southern Illinois
Clean Energy Center,
Williamson County,
Illinois: IGCC Unit,
544-MW (net)18
Fuel
Lignite
(amendments to
include sub-
bituminous and
petroleum coke)
Bituminous Coal
High-sulfur
Kentucky
bituminous coal
and pelletized
refuse-derived fuel
(RDF)
Bituminous Coal,
Coke, Blends
Bituminous Coal
(Illinois Coal)
Nitrogen Oxides
(NOX)
0.5 lb/MMBtu3
Water Injection
15 ppmvd, 15%
oxygen
Diluent Injection
System
0.0735 lb/MMBtu
based on 15 ppm
by volume at 15
% oxygen
Diluent Injection
System
15 ppmvd
Diluent Injection
System (0.055
lb/MMBtu3)
0.059 lb/MMBtu
based on 15
ppmvd @ 15%O2
Diluent Injection
System
Sulfur Dioxide (SO2)
0.82 lb/MMBtu3
WL-FGD
0.03 lb/MMBtu
Amine-based
Scrubbing System
0.032 lb/MMBtu
(99% reduction3)
Syngas Scrubbing
0.17 lb/MMBtu (97%
reduction3)
Amine-based
Scrubbing System
0.033 lb/MMBtu
(99.36% reduction)
Amine-Based
Scrubbing System
Carbon
Monoxide
(CO)
0.11
lb/MMBtu3
0.030
lb/MMBtu
0.032
lb/MMBtu
Syngas
Cleanup
System
Syngas 25
ppmvd
(0.046
lb/MMBtu3)
0.04
lb/MMBtu
Paniculate
Matter
(overall)7
0.03
lb/MMBtu3
ESP
0.011
lb/MMBtu
Water
Scrubbing
0.011
lb/MMBtu
Syngas
Cleanup
System
0.007
lb/MMBtu
Water
Scrubbing
0.00924
lb/MMBtu
(99.9%
reduction) Dry
Filter
Paniculate
Matter (PM10)7
0.0 11 lb/MMBtu
Water Scrubbing
0.0 11 lb/MMBtu
Syngas Cleanup
System
0.007 lb/MMBtu
Water Scrubbing
0.00924
lb/MMBtu
(99.9%
reduction) Dry
Filter
Lead (Pb)
0.000033
lb/MMBtu3
0.0000257
lb/MMBtu
0.00001
lb/MMBtu3
2.41x 10"6
lb/MMBtu
0.000001
lb/MMBtu
B-5
-------
Appendix B
Air Permit Raw Data
Projects
Cash Creek,
Kentucky: IGCC
Unit, 677 MW4
Fuel
Bituminous Coal
Nitrogen Oxides
(NOX)
0.058 Ib/MMBtu
(0.087 Ib/MMBtu
on natural gas
used as backup
fuel)
Diluent Injection
System
Sulfur Dioxide (SO2)
0.043 Ib/MMBtu
Amine-based
Scrubbing System
Carbon
Monoxide
(CO)
0.036
Ib/MMBtu
Paniculate
Matter
(overall)7
0.007
Ib/MMBtu
Water
Scrubbing
Paniculate
Matter (PM10)7
0.007 Ib/MMBtu
Water Scrubbing
Lead (Pb)
-------
Appendix B
Air Permit Raw Data
Exhibit B 1 of 3, Non-Criteria Pollutants from Air Permits and Other Documents
Projects
Elm Road, Wisconsin:
Two 615 MW
Supercritical Pulverized
Coal (PC) Boilers1'2
Comanche Generating
Station, Unit 3, Pueblo,
Pueblo County,
Colorado: Super Critical
PC Boiler Nominally
Rated at 7,421
MMBtu/hr4
Longview Power, LLC
Monongalia County
West Virginia: 6,114
MMBtu/hr PC boiler,
600 MW5
Mercury (Hg)
1.121b/TBtu
Heat Input
Baghouse,
WL-FGD and
SCR system
20 x 10'6
Ib/MWh
1.46X10'2 Ib/hr
(0.0000024
Ib/MMBtu)3
Volatile Organic „, . ,
„ , „,, ., ^T^,, Fluondes
Compounds Chlorides (HC1) ,„„
(VOC) (ti*>
0.0035 16.2 pounds per Q^QQQ^
Ib/MMBtu h°ur Ib/MMBtu
0.0035 0.00049
Ib/MMBtu luZn^ Ib/MMBtu
Ib/MMBtu,
0 61 Ib/hr
24.5 Ib/hr (0.004 "' 4 0.61 Ib/hr
Ib/MMBtu)3 .unTZn^ x3 (l.OOxlO"4
' Ib/MMBtu) IU/H/TATO* %3
' Ib/MMBtu)
Hydrogen Reduced .
„ ,f.j ,f Ammonia
Sulfide sulfur -^
(H2S) compounds
5 ppm and
20 pounds
per hour.
B-7
-------
Appendix B
Air Permit Raw Data
Projects
Prairie State Generating
Station, Illinois: Two
750 MW PC units6
Intermountain Power
Generating Station Unit
3, Millard County,
Delta, Utah: PC Unit,
950-gross MW (900-net
MW)8'9
Indeck-Elwood Energy
Center, Elwood, Illinois:
Nominal 660-MW Plant
with two CFB boilers10
Mercury (Hg)
0.016 Ib/h
(0.0000021
Ib/MMBtu)3
0.00000014
Ib/MMBtu3 ( 6
x 1Q-6 lb/
MWh)
bituminous
coal; and
0.00000046
Ib/MMBtu (20
x 10'6 lb/
MWh)3
subbituminous
coal
0.000002
Ib/MMBtu
Injection of
powdered
activated
carbon or
other similar
material
Volatile Organic
Compounds Chlorides (HC1)
(VOC)
0.004 Ib/MMBtu 24.4 Ib/h (0.0033
Ib/MMBtu)3
h/MMRtl 0.00421b/MMBtu3,
/lt>/MMBtu (38 13 lb/hr)
0.0 lib/million or
such lower limit,
as low as 0.006
Ib/MMBtu, as set
by the Illinois
0.004 Ib/MMBtu EPA following the
or 11.7 Ibs/hour Permittee's
evaluation of
hydrogen chloride
emissions and the
acid gas control
system
„, ., Hydrogen Reduced .
Fluondes ^ ,f° ,f Ammonia
Sulfide sulfur
(HF) (H2S) compounds (NH3)
0.00026
Ib/MMBtu
0.00073
0.0005 Ib/MMBtu3,
Ib/MMBtu (6.62 Ib/hr)
CFB boiler
technology,
limestone
addition to
the bed and
baghouse
-------
Appendix B
Air Permit Raw Data
Projects
Plum Point Energy
Station, Arkansas: One
PC Boiler 550-800
MW11'12
Thoroughbred
Generating Station,
Central City, Kentucky:
Two PC Units, 750
MW13'14
TS Power Plant, Eureka
County, Nevada: One
PC Unit, 200 MW5
Santee Cooper Cross
Generating Station Units
3 and 4, Berkeley
County, South Carolina:
Two PC Units, 5,700
MMBtu/hr5
Holocomb Unit 2,
Finney Kansas: One PC
Unit, 660 MW5
Limestone Electric
Generating Station Units
1 and 2, Limestone
County, Texas: PC
Units, 7,863 MMBtu/hr5
Mercury (Hg)
0.0000131
lb/MMBtu3
0.00000321
lb/MMBtu
Volatile Organic „, . , Hydrogen Reduced .
p InonnGS AmTnonin
Compounds Chlorides (HC1) ,„„ Sulfide sulfur -^
(VOC) ( ' (H2S) compounds ( 3)
0.00044
lb/MMBtu or
0.02 lb/MMBtu 0.0131 lb/MMBtu3 90%
reduction3
0.0072 0.000825 Ib/lVrMBt
lb/MMBtu lb/MMBtu U
1.17
lb/MMBtu
0.0000036
lb/MMBtu
SCR/WL-
FGD/ESP
00024 °-0003
lb/MMBtu 0.0024 lb/MMBtu lb/MMBtu
0.0035
lb/MMBtu
0.000051
lb/MMBtu3
nnnfi? °-01
,,1 °' t 3 0.0155 lb/MMBtu3 lb/MMBtu3
lb/MMBtu
B-9
-------
Appendix B
Air Permit Raw Data
Projects
Mercury (Hg)
Volatile Organic
Compounds
(VOC)
Chlorides (HC1)
Fluorides
(HF)
Hydrogen
Sulfide
(H2S)
Reduced
sulfur
compounds
Ammonia
(NH3)
Elm Road, Wisconsin,
IGCC Unit, 600 MW2
0.561b/TBtu
Carbon bed or
filter
containing
similar
material
0.004 Ib/MMBtu
Kentucky Pioneer
Energy Facility, Trapp
Kentucky: IGCC
Unit,540MWnet15'16
0.080
milligrams per
dry standard
cubic meter,
corrected to
7% oxygen
(0.0000007
Ib/MMBtu3)
0.0044
Ib/MMBTU.
25 ppm by volume
corrected to 7%
oxygen (dry basis)
Polk Power Station,
Polk County Florida:
IGCC Unit 260 MW
unit17
0.0034 Ib/h
(1.9 lb/TBtu3)
0.0017
Ib/MMBtu
Southern Illinois Clean
Energy Center,
Williamson County,
Illinois: IGCC Unit,
544-MW (net)18
0.547 lb/TBtu
Carbon Bed
0.0031
Ib/MMBtu
1124.3 lb/TBtu
92.09
lb/TBtu
Cash Creek, Kentucky:
IGCC Unit, 677 MW4
0.00687 Ib/hr 0.006 Ib/MMBtu
B-10
-------
Appendix B
Air Permit Raw Data
Exhibit B 2 of 3 Non-Criteria Pollutants from Air Permits and Other Documents
Projects
Arsenic (As)
Beryllium (Be) Manganese (Mn) Cadmium (Cd)
Chromium
(Cr)
Formaldehyde Nickel (Ni) Silica (Si)
Elm Road, Wisconsin: Two
615 MW Supercritical
Pulverized Coal (PC)
Boilers1'2
5.991b/TBtu3 0.351b/TBtu 12.3 lb/TBtu3 1.1 lb/TBtu3
lb/TBtu3
48.0 8.41
lb/TBtu3 lb/TBtu3
Comanche Generating
Station, Unit 3, Pueblo,
Pueblo County, Colorado:
Super Critical PC Boiler
Nominally Rated at 7,421
MMBtu/hr4
Longview Power, LLC
Monongalia County West
Virginia: 6,114 MMBtu/hr
PC boiler, 600 MW5
5.46x1 (F Ib/hr
Prairie State Generating
Station, Illinois: Two 750
MW PC units6
0.0085 Ib/h (1.14
lb/TBtu)
Intermountain Power
Generating Station Unit 3,
Millard County, Delta, Utah:
PC Unit, 950-gross MW
(900-net MW)8'9
B-ll
-------
Appendix B
Air Permit Raw Data
Projects
Indeck-Elwood Energy
Center, Elwood, Illinois:
Nominal 660-MW Plant with
two CFB boilers10
Plum Point Energy Station,
Arkansas: One PC Boiler
550-800 MW11'12
Thoroughbred Generating
Station, Central City,
Kentucky: Two PC Units,
750 MW13'14
TS Power Plant, Eureka
County, Nevada: One PC
Unit, 200 MW5
Santee Cooper Cross
Generating Station Units 3
and 4, Berkeley County,
South Carolina: Two PC
Units, 5,700 MMBtu/hr5
Holocomb Unit 2, Finney
Kansas: One PC Unit, 660
MW5
Arsenic (As) Beryllium (Be) Manganese (Mn) Cadmium (Cd) ,„ . Formaldehyde Nickel (Ni) Silica (Si)
Addressed by
limitation on PM
Baghouse
251b/TBtu3 2.381b/TBtu3 3.57 Ib/TBtu3 3.1 Ib/TBtu3 J™^ J^B J^B
0.883 Ib/TBtu 0.9 Ib/TBtu 20.92 Ib/TBtu 0.365 Ib/TBtu 10.48 Ib/TBtu
0.844 Ib/TBtu
B-12
-------
Appendix B
Air Permit Raw Data
Projects
Limestone Electric
Generating Station Units 1
and 2, Limestone County,
Texas: PC Units, 7,863
MMBtu/hr5
Elm Road, Wisconsin, IGCC
Unit, 600 MW2
Kentucky Pioneer Energy
Facility, Trapp Kentucky:
IGCC Unit,540 MW net15' 16
Polk Power Station, Polk
County Florida: IGCC Unit
260 MW unit17
Southern Illinois Clean
Energy Center, Williamson
County, Illinois: IGCC Unit,
544-MW (net)18
Cash Creek, Kentucky: IGCC
Unit, 677 MW4
Arsenic (As) Beryllium (Be) Manganese (Mn) Cadmium (Cd) ,„ . Formaldehyde Nickel (Ni) Silica (Si)
22.01b/TBtu3 9.01b/TBtu3 1561b/TBtu3 7.6 lb/TBtu3 6.2 lb/TBtu3 62.0 lb/TBtu3
0.020
milligrams per
dry standard
6.0 lb/TBtu3 0.6 lb/TBtu 4.0 lb/TBtu3 cubic meter, 1.1 lb/TBtu3 3 10 lb/TBtu3
corrected to
7% oxygen
(5.0 lb/TBtu3)
0.0006 Ib/h 0.0001 Ib/h
0.457 lb/TBtu 0.062 lb/TBtu 7.02 lb/TBtu 0.415 lb/TBtu 3.48 lb/TBtu 4.51 lb/TBtu
B-13
-------
Appendix B
Air Permit Raw Data
Exhibit B 3 of 3 Non-Criteria Pollutants from Air Permits and Other Documents
Projects
Elm Road,, Wisconsin: Two 615
MW Supercritical Pulverized
Coal (PC) Boilers1'2
Comanche Generating Station,
Unit 3, Pueblo, Pueblo County,
Colorado: Super Critical PC
Boiler Nominally Rated at 7,421
MMBtu/hr4
Longview Power, LLC
Monongalia County West
Virginia: 6, 114 MMBtu/hr PC
boiler, 600 MW5
Prairie State Generating Station,
Illinois: Two 750 MW PC units6
r~ . ,-n , , Sulfunc acid
ci- so -. IT j- ,-irv Total Reduced „
Selenium (Se) Vanadium (V) c ,,, ™nc. Opacity mist
ouiiur ( 1K5>)
emissions
0.010
„„„, Ib/MMBtu
20% or , . .
, , heat input
.0,.li;r__^3 number 1 on _„_ *\
48.54 Ib/TBtu ., FGD system
the , J.
„ . , and wet
Ringlemann , ^
electrostatic
precipitator
0.0042
Ib/mmBtu
10% lime spray
dryer
followed by a
baghouse
45.8 Ib/hr
(0.0075
Ib/MMBtu)
1Q% dry sorbent
injection in
conjunction
with fabric
filter
0.005
Ib/MMBtu
WL-FGD
(WFGD) and
Wet
Electrostatic
Precipitator
(WESP)
B-14
-------
Appendix B
Air Permit Raw Data
Projects
Selenium (Se) Vanadium (V)
Total Reduced
Sulfur (TRS)
Opacity
Sulfuric acid
mist
emissions
Intermountain Power Generating
Station Unit 3, Millard County,
Delta, Utah: PC Unit, 950-gross
MW (900-net MW)8'9
0.00073
Ib/MMBtu3,
(6.62 Ib/hr)
0.0044
Ib/MMBtu
Indeck-Elwood Energy Center,
Elwood, Illinois: Nominal 660-
MW Plant with two CFB
boilers10
20%
Addressed by
limitation on
S02
CFB boiler
technology,
limestone
addition to
the bed, and
baghouse
Plum Point Energy Station,
Arkansas: One PC Boiler 550-
800 MW11'12
0.0061
Ib/MMBtu
Thoroughbred Generating
Station, Central City, Kentucky:
Two PC Units, 750 MW13'14
20%
0.00497
Ib/MMBtu
B-15
-------
Appendix B
Air Permit Raw Data
Projects
Selenium (Se) Vanadium (V)
Total Reduced
Sulfur (TRS)
Opacity
Sulfuric acid
mist
emissions
TS Power Plant, Eureka County,
Nevada: One PC Unit, 200
MW5
2.06 Ib/hr
Santee Cooper Cross Generating
Station Units 3 and 4, Berkeley
County, South Carolina: Two PC
Units, 5,700 MMBtu/hr5
0.0014
Ib/MMBtu
Holocomb Unit 2, Finney
Kansas: One PC Unit, 660 MW5
Limestone Electric Generating
Station Units 1 and 2, Limestone
County, Texas: PC Units, 7,863
MMBtu/hr5
0.00137
Ib/MMBtu
0.000267
Ib/MMBtu
15%
Elm Road, Gasification
Combined Cycle Unit,
Wisconsin: 600 MW2
0%
0.0005
Ib/MMBtu
B-16
-------
Appendix B
Air Permit Raw Data
Projects
Kentucky Pioneer Energy
Facility, Trapp Kentucky: IGCC
Plant,540MWnet15'16
Polk Power Station, Polk County
Florida: IGCC Plant 260 MW
unit
Southern Illinois Clean Energy
Center, Williamson County,
Illinois: IGCC Plant, 544-MW
(net)18
Cash Creek, Kentucky: IGCC
Plant, 677 MW4
r~ . ,-n , , Sulfunc acid
ci- so •> IT j- sir. Total Reduced /->•„.
Selenium (Se) Vanadium (V) c ,,, ™nc. Opacity mist
ouiiur ( 1K5>)
emissions
1.4 Ib/TBtu3
10% 55 Ib/h
12.5 Ib/TBtu 20% iiXiL,,
Ib/MMBtu
References
1. Final Construction Permit, Elm Road Generating Station, Permit No. 03-RV-166, State of Wisconsin, Department of Natural
Resources, January 14, 2004.
2. Analysis And Preliminary Determination For The Construction And Operation Permits For The Proposed Construction Of An
Electric Generation Facility for Elm Road Generating Station, Permit No. Ol-RV-158, 01-RV-158-OP, Wisconsin Department
of Natural Resources, October 2, 2003.
B-17
-------
Appendix B Air Permit Raw Data
3. Estimated numbers developed using boiler heat input and air pollutant rates provided in permit documents referenced for this
plant.
4. National Coal-Fired Utility Data Spreadsheets, http://www.epa.gov/ttn/catc/dirl/natlcoal.xls, Accessed December 30, 2005.
5. EPA RACT/BACT/LAER Cleanringhouse Website,
http://cfpub.epa.gov/RBLC/cfm/basicSearchResult.cfm?RequestTiiTieout=500&CFID=17906179&CFTOKEN=70912132,
Accessed December 30, 2005.
6. Illinois Environmental Protection Agency, Air Pollution Control Permit Record,
http://yosemite.epa.gov/r5/il_permt.nsf/50d44ae9785337bf8625666c0063caf4/68b5945ale2877b085256e3000546221!OpenD
ocument, Accessed January 5, 2006.
7. Filterable PM only, unless otherwise mentioned.
8. Title V Operating Permit, Intermountain Generation Station, Permit No. 2700010002, State of Utah, Department of
Environmental Quality, August 14, 2005.
9. Approval Order: PSD Major Modification to Add New Unit 3 at Intermountain Generating Station, Approval Order Number
DAQE-AN0327010-04, State of Utah, Department of Environmental Quality, October 15, 2004.
10. Construction Permit - PSD Approval, ID No. 197035 AAJ, Indeck Elwood LLC, October 10, 2003.
11. ADEQ Operating Air Permit, Permit No. 1995-AOP-RO, Plum Point Energy Station, Arkansas Department of Environmental
Quality, August 20, 2003.
12. Statement of Basis, Operating Permit No. 1995-AOP-RO, Plum Point Energy Station, Arkansas Department of Environmental
Quality, Submittal Date April 24, 2001.
13. Air Quality Permit, Permit No. V-02-001, Rev. 2, Thoroughbred Generating Station, Kentucky Department of Environmental
Protection, February 17, 2005.
B-18
-------
Appendix B Air Permit Raw Data
14. Permit Statement of Basis, Permit No. V-02-001, Rev. 2, Thoroughbred Generating Station, Kentucky Division of Air Quality,
Review Completion Date April 23, 2001.
15. Air Quality Permit, Permit No. V-00-049, Kentucky Pioneer Energy Facility, Kentucky Department of Environmental
Protection, June 7, 2001
16. PSD Permit Application, Kentucky Pioneer Energy Facility, November 16, 1999.
17. Final permit, Polk Power Station, Tampa Electric Company, Florida Department of Environmental Protection, November 17,
2000.
18. BACT Evaluation, Appendices D and E, Steelhead Energy, LLC, Southern Illinois Clean Air Energy Center, October 2004, by
Sargent & Lundy.
19. The Tampa Electric Integrated Combined-Cycle Project, DOE Topical Report No. 6, October 1996
20. Tampa Electric Integrated Gasification Combined-Cycle Project, DOE/FE-0469, June 2004.
B-19
-------
Appendix C
Energy and Material Balances
Appendix C presents the detailed energy and material (E&M) balance tables produced for
the IGCC and PC plants. These tables were prepared with Nexant's spreadsheet model to
estimate plant performances and validate the emissions values determined from air
permits and other sources. Thus, the E&M balance tables may not equal other values
used in the report either from rounding, differences in calculations, or the value may have
been determined by other methods than the balance table models. The sources for
emission values are documented in the text or footnotes as they are provided in the report.
The E&M balance for each IGCC and PC plant configuration includes a summary of
major plant performance parameters as well as conditions of major flow streams. The
flow stream numbers shown in each E&M correspond to the numbers shown in Exhibit 2-
2, Integrated Gasification Combined Cycle Block Diagram, and Exhibit 2-4, Pulverized
Coal Plant Block Diagram.
The major parameters covered in each E&M balance include the following:
• Plant thermal efficiencies, heat rates, power outputs, fuel consumption, and byproduct
amount (if any)
• Amounts of solids, liquids, and gas constituents present in each flow stream
• Pressure, temperature, and energy content of each flow stream
IGCC Energy and Material Balances
GE Energy Slurry Feed Gasifier and Bituminous Coal - Summary
Cold Gas Efficiency
Net Thermal Efficiency
Net Heat Rate (HHV)
Gross Power
Internal Power
Steam Turbine
Gas Turbine
Fuel Required
Sulfur By-product
% HHV
%HHV
Btu/kWh
MW
MW
MW
MW
Ib/h
Ib/h
77.8
41.8
8,167
564
64
127.5
436.5
349,744
8,679
C-l
-------
Appendix C
Energy and Material Balances
GE Energy Slurry Feed Gasifier and Bituminous Coal - E&M Balance
Stream
Solids
Coal, daf
Bitumen
Carbon/Char
Ash/Slag
Sorb/Flux
CaSO4
Elem. Sulfur
Water
Subtotal
Gas
02
N2
C02
H20
H2
CO
CH4
C2H6
H2S
COS
SO2
NO2
Subtotal
Total
Stream No.
Units
Ib/h
Ib/h
Ib/h
Ib/h
Ib/h
1
Raw
Coal
275,913
0
0
34,939
0
0
0
38,892
349,744
0
349,744
2
Feed to
Gasifier
275,913
0
0
34,939
0
0
0
156,595
467,448
0
467,448
3
Oxygen
271,867
12,527
0
0
0
0
0
0
0
0
0
0
284,393
284,393
4
Raw
Gas
0
16,910
150,553
95,498
22,054
420,949
0
0
8,667
1,149
0
0
715,780
715,780
5
Clean
Fuel Gas
0
16,840
112,291
197,995
21,949
418,954
0
0
87
11
0
768,129
768,129
6
GT
Exhaust
993,116
4,649,773
770,555
432,672
0
122
0
0
0
0
175
200
6,846,612
6,846,612
7
Flue Gas
to Stack
993,116
4,649,773
811,951
432,672
0
122
0
0
0
0
175
200
6,888,008
6,888,008
8
Slag to
Disposal
1,115
34,939
0
0
0
19,414
55,468
0
55,468
9
Sulfur
Product
8,679
8,679
0
8,679
C-2
-------
Appendix C
Energy and Material Balances
Stream
Pressure
Temperature
Total Energy
Stream No.
psia
°F
mmBtu/h
1
Raw
Coal
15
77
4,083
2
Feed to
Gasifier
609
158
4,113
3
Oxygen
537
307
17
4
Raw
Gas
464
2,606
4,050
5
Clean
Fuel Gas
450
572
4,097
6
GT
Exhaust
15
1,107
2,433
7
Flue Gas
to Stack
15
248
838
8
Slag to
Disposal
15
77
18
9
Sulfur
Product
15
77
35
Stream
Solids
Coal, daf
Bitumen
Carbon/Char
Ash/Slag
Sorb/Flux
CaSO4
Elem. Sulfur
Water
Subtotal
Gas
02
N2
CO2
H20
H2
CO
Stream No.
Units
Ib/hr
Ib/hr
Ib/hr
10
Cooling
Water
17,675,601
17,675,601
11
CTMake
Up
Water
1,586,094
1,586,094
12
Waste Water
Discharge
13,328
13,328
C-3
-------
Appendix C
Energy and Material Balances
Stream
CH4
C2H6
H2S
COS
S02
NO2
Subtotal
Total
Pressure
Temperature
Total Energy
Stream No.
Ib/hr
Ib/hr
psia
°F
mmBtu/h
10
Cooling
Water
0
17,675,601
65
115
1,502
11
CTMake
Up
Water
0
1,586,094
50
80
81
12
Waste Water
Discharge
0
13,328
30
80
0.7
C-4
-------
Appendix C
Energy and Material Balances
GE Energy Slurry Feed Gasifier and Subbituminous Coal - Summary
Cold Gas Efficiency
Net Thermal
Efficiency
Net Heat Rate (HHV)
Gross Power
Internal Power
Steam Turbine
Gas Turbine
Fuel Required
Sulfur By-product
% HHV
% HHV
Btu/kWh
MW
MW
MW
MW
Ib/h
Ib/h
69.1
40.0
8,520
575
75
160
415
484,089
1,044
GE Energy Slurry Feed Gasifier and Subbituminous Coal - E&M Balance
Stream
Solids
Coal, daf
Bitumen
Carbon/Char
Ash/Slag
Sorb/Flux
CaSO4
Elem. Sulfur
Water
Subtotal
Stream No.
Units
Ib/h
Ib/h
1
Raw
Coal
329,568
0
0
21,881
0
0
0
132,641
484,089
2
Feed to
Gasifier
329,568
0
0
21,881
0
0
0
298,055
649,503
3
Oxygen
0
4
Raw
Gas
0
5
Clean
Fuel Gas
0
6
GT
Exhaust
0
7
Flue Gas
to Stack
0
8
Slag to
Disposal
1,216
21,881
0
0
0
12,437
35,534
9
Sulfur
Product
1,044
1,044
C-5
-------
Appendix C
Energy and Material Balances
Stream
Gas
O2
N2
C02
H20
H2
CO
CH4
C2H6
H2S
COS
SO2
N02
Subtotal
Total
Pressure
Temperature
Total Energy
Stream No.
Ib/h
Ib/h
Ib/h
psia
°F
mmBtu/h
1
Raw
Coal
0
484,089
15
77
4,260
2
Feed to
Gasifier
0
649,503
609
158
4,309
3
Oxygen
325,115
14,980
0
0
0
0
0
0
0
0
0
0
340,095
340,095
537
307
21
4
Raw
Gas
0
18,143
321,041
243,526
22,557
360,040
0
0
1,042
138
0
0
966,488
966,488
464
2,606
4,257
5
Clean
Fuel Gas
0
18,069
239,462
67,804
22,451
358,346
0
0
10
1
0
706,144
706,144
450
572
2,463
6
GT
Exhaust
934,053
4,355,256
802,488
304,477
0
128
0
0
0
0
51
188
6,396,641
6,396,641
15
1,108
2,143
7
Flue Gas
to Stack
934,053
4,355,256
886,729
304,477
0
128
0
0
0
0
51
188
6,480,882
6,480,882
15
248
671
8
Slag to
Disposal
2,109
2,109
37,643
15
77
19
9
Sulfur
Product
0
1,044
15
77
4
C-6
-------
Appendix C
Energy and Material Balances
Stream
Solids
Coal, daf
Bitumen
Carbon/Char
Ash/Slag
Sorb/Flux
CaSO4
Elem. Sulfur
Water
Subtotal
Gas
02
N2
C02
H20
H2
CO
CH4
C2H6
H2S
COS
S02
NO2
Subtotal
Total
Pressure
Temperature
Total Energy
Stream No.
Units
Ib/hr
Ib/hr
Ib/hr
Ib/hr
Ib/hr
psia
°F
mmBtu/h
10
Cooling
Water
22,195,009
22,195,009
0
22,195,009
65
115
1,887
11
CTMake
Up
Water
1,982,121
1,982,121
0
1,982,121
50
80
100
12
Waste Water
Discharge
10580
10,580
0
10,580
30
80
0.8
C-7
-------
Appendix C
Energy and Material Balances
Shell Solid Feed Gasifier and Lignite Coal - Summary
Cold Gas Efficiency
Net Thermal
Efficiency
Net Heat Rate (HHV)
Gross Power
Internal Power
Steam Turbine
Gas Turbine
Fuel Required
Sulfur By-product
% HHV
% HHV
Btu/kWh
MW
MW
MW
MW
Ib/h
Ib/h
78.4
39.2
8,707
580
80
221
359
689,721
4,370
Shell Solid Feed Gasifier and Lignite Coal - E&M Balance
Stream
Solids
Coal, daf
Bitumen
Carbon/Char
Ash/Slag
Sorb/Flux
CaSO4
Elem. Sulfur
Water
Subtotal
Stream No.
Units
Ib/h
Ib/h
1
Raw
Coal
350,654
123,598
215,469
689,721
2
Feed to
Gasifier
350,654
0
123,598
0
24,961
499,213
3
Oxygen
4
Raw
Gas
5
Clean
Fuel Gas
6
GT
Exhaust
7
Flue Gas
to Stack
8
Slag to
Disposal
501
123,598
0
0
66,822
190,921
9
Sulfur
Product
4,370
4,370
-------
Appendix C
Energy and Material Balances
Stream
Gas
O2
N2
C02
H20
H2
CO
CH4
C2H6
H2S
COS
SO2
N02
Subtotal
Total
Pressure
Temperature
Total Energy
Stream No.
Ib/h
Ib/h
Ib/h
psia
°F
mmBtu/h
1
Raw
Coal
689,721
15
77
4,354
2
Feed to
Gasifier
499,213
537
158
4,371
3
Oxygen
273,807
12,616
0
0
286,423
286,423
464
298
17
4
Raw
Gas
0
55,196
69,698
14,608
17,603
538,044
15
0
4,363
578
700,107
700,107
392
2,939
4,191
5
Clean
Fuel Gas
0
54,596
51,516
230,435
17,401
531,871
15
0
44
6
885,884
885,884
377
572
2,419
6
GT
Exhaust
1,083,611
5,079,109
887,239
427,727
131
87
218
7,476,794
7,476,794
15
1,106
2,596
7
Flue Gas
to Stack
1,083,611
5,079,109
915,121
427,727
131
87
218
7,506,322
7,506,322
15
248
865
8
Slag to
Disposal
8,747
8,747
199,668
15
77
12
9
Sulfur
Product
4,370
15
77
17
Stream
Solids
Coal, daf
Bitumen
Stream No.
Units
Ib/hr
10
Cooling
Water
11
CTMake
Up
Water
12
Waste Water
Discharge
C-9
-------
Appendix C
Energy and Material Balances
Stream
Carbon/Char
Ash/Slag
Sorb/Flux
CaSO4
Elem. Sulfur
Water
Subtotal
Gas
02
N2
C02
H20
H2
CO
CH4
C2H6
H2S
COS
S02
NO2
Subtotal
Total
Pressure
Temperature
Total
Energy
Stream No.
Ib/hr
Ib/hr
Ib/hr
Ib/hr
psia
mmBtu/h
10
Cooling
Water
30,637,708
30,637,708
0
30,637,708
65
115
1,441
11
CTMake
Up
Water
2,848,710
2,848,710
0
2,848,710
50
80
46
12
Waste Water
Discharge
29,494
29,494
0
29,494
30
80
0.6
C-10
-------
Appendix C
Energy and Material Balances
PC Plant Energy and Material Balances
Subcritical PC and Bituminous Coal - Summary
Summary
Net Thermal
Efficiency
Net Heat Rate
(HHV)
Gross Power
Internal Power
Fuel required
Net Power
35.9
9,500
540
40
407,143
500
% HHV
Btu/kWh
MW
MW
Ib/h
MW
Subcritical PC and Bituminous Coal - E&M Balance
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Stream
No.
Units
Ib/h
1
Coal
Feed
321,195
0
40,674
0
2
Combustion
Air
0
0
0
0
3
HP Steam
toT/G
0
0
0
0
4
Bottom
Ash
0
0
8,427
0
5
Flue Gas
to Filter
0
0
33,707
0
6
Ash From
Filter
0
0
33,232
0
7
Flue Gas
toFGD
0
0
475
0
8
Limestone
toFGD
0
36,194
0
0
9
Gypsum
from FGD
0
0
0
54,086
C-ll
-------
Appendix C
Energy and Material Balances
Stream
Water
Subtotal
Gas
O2
N2
C02
H2O
S02
NO2
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
Ib/h
psia
°F
mmBtu/h
1
Coal
Feed
45,274
407,143
0
0
0
0
0
0
0
407,143
14.7
59
4,753
2
Combustion
Air
0
0
1,002,292
3,302,954
0
27,419
0
0
4,332,665
4,332,665
14.7
59
58
3
HP Steam
toT/G
3,571,590
3,571,590
0
0
0
0
0
0
0
3,571,590
2,415
1,000
5,216
4
Bottom
Ash
0
8,427
0
0
0
0
0
0
0
8,427
14.7
2,498
12
5
Flue Gas
to Filter
0
33,707
183,426
3,308,035
946,162
245,089
20,391
285
4,703,387
4,737,094
14.0
288
583
6
Ash From
Filter
0
33,232
0
0
0
0
0
0
0
33,232
14.7
287
18
7
Flue Gas
toFGD
0
475
183,426
3,308,035
946,162
227,859
20,391
285
4,686,158
4,686,633
15.0
302
561
8
Limestone
toFGD
0
36,194
0
0
0
0
0
0
0
36,194
14.7
32
0
9
Gypsum
fromFGD
6,010
60,095
0
0
0
0
0
0
0
60,095
14.7
86
1
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Water
Subtotal
Gas
Stream
No.
Units
Ib/h
Ib/h
10
Flue Gas
to Stack
0
0
57
0
0
57
11
Reheat
Steam
toT/G
3,250,147
3,250,147
12
Turbine
Exhaust
to
Condenser
2,762,625
2,762,625
13
Cooling
Water
to
Condenser
74,518,170
74,518,170
14
Cooling
Tower
Evaporative
Loses
3,058,656
3,058,656
15
Cooling
Tower
Blowdown
1,512,294
1,512,294
16
Waste
Water
(from
Process)
38,461
38,461
C-12
-------
Appendix C
Energy and Material Balances
Stream
02
N2
CO2
H20
S02
NO2
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
psia
°F
mmBtu/h
10
Flue Gas
to Stack
183,426
3,308,035
958,769
429,620
409
285
4,880,543
4,880,600
14.7
128
580
11
Reheat
Steam
toT/G
0
3,250,147
560.0
1,000
4,934
12
Turbine
Exhaust
to
Condenser
0
2,762,625
115
1.50
2,832
13
Cooling
Water
to
Condenser
0
74,518,170
55
80
2,832
14
Cooling
Tower
Evaporative
Loses
0
3,058,656
25
118
3120
15
Cooling
Tower
Blowdown
0
1,512,294
15
80
73
16
Waste
Water
(from
Process)
0
38,461
15
70
2
C-13
-------
Appendix C
Energy and Material Balances
Subcritical PC and Subbituminous Coal - Summary
Summary
Net Thermal
Efficiency
Net Heat Rate
(HHV)
Gross Power
Internal Power
Fuel required
Net Power
34.8
9,800
541
41
556,818
500
% HHV
Btu/kWh
MW
MW
Ib/h
MW
Subcritical PC and Subbituminous Coal - E&M Balance
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Water
Subtotal
Gas
02
N2
C02
H2O
Stream
No.
Units
Ib/h
Ib/h
1
Coal
Feed
379,082
0
25,168
0
152,568
556,818
0
0
0
0
2
Combustion
Air
0
0
0
0
0
0
987,528
3,254,301
0
27,015
3
HP Steam
toT/G
0
0
0
0
3,577,159
3,577,159
0
0
0
0
4
Bottom
Ash
0
0
5,421
0
0
5,421
0
0
0
0
5
Flue Gas
SDA
0
0
21,686
0
0
21,686
180,724
3,257,947
1,026,489
318,550
6
Lime
to SDA
0
4,242
0
0
21,210
25,452
0
0
0
0
7
SDA Filter
Waste
0
0
21,627
13,029
34,656
0
0
0
0
8
Flue Gas
To Stack
0
0
59
0
0
59
180,724
3,257,947
1,028,081
504,140
C-14
-------
Appendix C
Energy and Material Balances
Stream
S02
NO2
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
psia
°F
mmBtu/h
1
Coal
Feed
0
0
0
556,818
14.7
59
4,649
2
Combustion
Air
0
0
4,268,845
4,268,845
14.7
59
57
3
HP Steam
toT/G
0
0
0
3,577,159
2,415
1,000
5,224
4
Bottom
Ash
0
0
0
5,421
14.7
2,498
11
5
Flue Gas
SDA
2,438
2,94
4,786,443
4,808,129
15.0
270
630
6
Lime
to SDA
0
0
0
25,452
14.7
59
0
7
SDA Filter
Waste
0
0
0
34,656
14.7
86
0
8
Flue Gas
To Stack
319
294
4,971,505
4,971,564
14.7
132
699
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Water
Subtotal
Gas
02
N2
C02
H20
Stream
No.
Units
Ib/h
Ib/h
9
Reheat
Steam
toT/G
3,255,214
3,255,214
10
Turbine
Exhaust
to
Condenser
2,766,932
2,766,932
11
Cooling
Water
to
Condenser
74,634,356
74,634,356
12
Cooling
Tower
Evaporative
Loses
3,160,892
3,160,892
13
Cooling
Tower
Blowdown
1,563,107
1,563,107
14
Waste
Water
(from
Process)
7,818
7,818
C-15
-------
Appendix C
Energy and Material Balances
S02
NO2
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
psia
°F
mmBtu/h
9
Reheat
Steam
toT/G
0
3,255,214
560.0
1,000
4,941
10
Turbine
Exhaust
to
Condenser
0
2,766,932
115
1.50
2,836
11
Cooling
Water
to
Condenser
0
74,634,356
55
80
2,836
12
Cooling
Tower
Evaporative
Loses
0
3,160,892
25
118
3,225
13
Cooling
Tower
Blowdown
0
1,563,107
15
80
75
14
Waste
Water
(from
Process)
0
7,818
15
70
0
C-16
-------
Appendix C
Energy and Material Balances
Subcritical PC and Lignite Coal - Summary
Summary
Net Thermal
Efficiency
Net Heat Rate
(HHV)
Gross Power
Internal
Power
Fuel required
Net Power
33.1
10,300
544
44
815,906
500
% HHV
Btu/kWh
MW
MW
Ib/h
MW
Subcritical PC and Lignite Coal - E&M Balance
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Water
Subtotal
Gas
02
N2
C02
H2O
Stream
No.
Units
Ib/h
Ib/h
1
Coal
Feed
414,480
0
146,537
0
254,889
815,906
0
0
0
0
0
2
Combustion
Air
0
0
0
0
0
0
0
1,055,749
3,479,117
0
28,881
3
HP Steam
toT/G
0
0
0
0
3,596,072
3,596,072
0
0
0
0
0
4
Bottom
Ash
0
0
29,738
0
0
29,738
0
0
0
0
0
5
Flue Gas
to Filter
0
0
118,951
0
0
118,951
0
193,209
3,484,871
1,078,921
469,265
6
Ash From
Filter
0
0
118,461
0
0
118,461
0
0
0
0
0
7
Flue Gas
toFGD
0
0
490
0
0
490
0
193,209
3,484,871
1,078,921
449,785
8
Limestone
toFGD
0
18,135
0
0
0
18,135
0
0
0
0
0
9
Gypsum
fromFGD
0
0
0
30,741
3,416
34,156
0
0
0
0
0
C-17
-------
Appendix C
Energy and Material Balances
Stream
S02
NO2
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
psia
°F
mmBtu/h
1
Coal
Feed
0
0
0
815,906
14.7
59
4,903
2
Combustion
Air
0
0
4,563,748
4,563,748
14.7
59
61
3
HP Steam
toT/G
0
0
0
3,596,072
2,415
1,000
5,251
4
Bottom
Ash
0
0
0
29,738
14.7
2,498
34
5
Flue Gas
to Filter
10,424
309
5,237,000
5,355,951
14.0
279
868
6
Ash From
Filter
0
0
0
118,461
14.7
278
30
7
Flue Gas
toFGD
10,424
309
5,217,520
5,218,010
15.0
293
833
8
Limestone
toFGD
0
0
0
18,135
14.7
32
0
9
Gypsum
fromFGD
0
0
0
34,156
14.7
86
1
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Water
Subtotal
Gas
02
N2
CO2
H20
S02
NO2
Stream
No.
Units
Ib/h
Ib/h
10
Flue Gas
to Stack
0
0
62
0
0
62
193,209
3,484,871
1,085,724
657,156
443
309
11
Reheat
Steam
ToT/G
3,272,426
3,272,426
12
Turbine
Exhaust
to
Condenser
2,781,562
2,781,562
13
Cooling
Water
to
Condenser
75,028,976
75,028,976
14
Cooling
Tower
Evaporative
Loses
3,341,047
3,341,047
15
Cooling
Tower
Blowdown
1,651,773
1,651,773
16
Waste
Water
(from
Process)
21,860
21,860
C-18
-------
Appendix C
Energy and Material Balances
Stream
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
psia
°F
mmBtu/h
10
to Stack
5,421,475
5,421,537
14.7
139
857
11
Reheat
Steam
ToT/G
0
3,272,426
560.0
1,000
4,968
12
Turbine
Exhaust
to
Condenser
0
2,781,562
115
1.50
2,851
13
Cooling
Water
to
Condenser
0
75,028,976
55
80
2,851
14
Cooling
Tower
Evaporative
Loses
0
3,341,047
25
118
3,408
15
Cooling
Tower
Blowdown
0
1,651,773
15
80
79
16
Waste
Water
(from
Process)
0
21,860
15
70
1
C-19
-------
Appendix C
Energy and Material Balances
Supercritical PC and Bituminous Coal - Summary
Summary
Net Thermal
Efficiency
Net Heat Rate
(HHV)
Gross Power
Internal Power
Fuel required
Net Power
38.3
8,900
540
40
381,418
500
% HHV
Btu/kWh
MW
MW
Ib/h
MW
Supercritical PC and Bituminous Coal - E&M Balance
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Water
Subtotal
Gas
Stream
No.
Units
Ib/h
Ib/h
1
Coal
Feed
300,901
0
38,104
0
42,414
381,418
2
Combustion
Air
0
0
0
0
0
0
3
HP Steam
toT/G
0
0
0
0
3,576,288
3,576,288
4
Bottom
Ash
0
0
7,894
0
0
7,894
5
Flue Gas
to Filter
0
0
31,577
0
0
31,577
6
Ash From
Filter
0
0
31,132
0
0
31,132
7
Flue Gas
toFGD
0
0
445
0
0
445
8
Limestone
toFGD
0
34,666
0
0
0
34,666
9
Gypsum
fromFGD
0
0
0
51,802
5,756
57,558
C-20
-------
Appendix C
Energy and Material Balances
Stream
02
N2
C02
H2O
S02
NO2
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
psia
°F
mmBtu/h
1
Coal
Feed
0
0
0
0
0
0
0
381,418
14.7
59
4,453
2
Combustion
Air
938,963
3,094,261
0
25,687
0
0
4,058,911
4,058,911
14.7
59
54
3
HP Steam
toT/G
0
0
0
0
0
0
0
3,576,288
3,515
1,050
5,083
4
Bottom
Ash
0
0
0
0
0
0
0
7,894
14.7
2,498
11
5
Flue Gas
to Filter
171,836
3,099,021
886,380
230,135
19,102
267
4,406,742
4,438,319
14.0
288
546
6
Ash From
Filter
0
0
0
0
0
0
0
31,132
14.7
287
17
7
Flue Gas
toFGD
171,836
3,099,021
886,380
213,993
19,102
267
4,390,599
4,391,045
15.0
302
526
8
Limestone
toFGD
0
0
0
0
0
0
0
34,666
14.7
32
0
9
Gypsum
fromFGD
0
0
0
0
0
0
0
57,558
14.7
86
1
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Water
Subtotal
Gas
02
N2
Stream
No.
Units
Ib/h
Ib/h
10
Flue Gas
to Stack
0
0
54
0
0
54
171,836
3,099,021
11
Reheat
Steam
toT/G
3,254,422
3,254,422
12
Turbine
Exhaust
to
Condenser
2,766,259
2,766,259
13
Cooling
Water
to
Condenser
74,616,184
74,616,184
14
Cooling
Tower
Evaporative
Loses
2,880,487
2,880,487
15
Cooling
Tower
Blowdown
1,423,633
1,423,633
16
Waste
Water
(from
Process)
36,837
36,837
C-21
-------
Appendix C
Energy and Material Balances
Stream
C02
H20
SO2
NO2
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
psia
°F
mmBtu/h
10
to Stack
898,191
403,047
383
267
4,572,745
4,572,799
14.7
128
544
11
Reheat
Steam
toT/G
0
3,254,422
560.0
1,000
4,940
12
Turbine
Exhaust
to
Condenser
0
2,766,259
115
1.50
2,835
13
Cooling
Water
to
Condenser
0
74,616,184
55
80
2,835
14
Cooling
Tower
Evaporative
Loses
0
2,880,487
25
118
2,938
15
Cooling
Tower
Blowdown
0
1,423,633
15
80
68
16
Waste
Water
(from
Process)
0
36,837
15
70
2
C-22
-------
Appendix C
Energy and Material Balances
Supercritical PC and Subbituminous Coal - Summary
Summary
Net Thermal
Efficiency
Net Heat Rate
(HHV)
Gross Power
Internal
Power
Fuel required
Net Power
37.9
9,000
541
41
517,045
500
% HHV
Btu/kWh
MW
MW
Ib/h
MW
Supercritical PC and Subbituminous Coal - E&M Balance
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Water
Subtotal
Gas
02
N2
C02
H2O
Stream
No.
Units
Ib/h
Ib/h
1
Coal
Feed
352,005
0
23,370
0
141,670
517,045
0
0
0
0
2
Combustion
Air
0
0
0
0
0
0
916,991
3,021,853
0
25,086
3
HP Steam
toT/G
0
0
0
0
3,581,627
3,581,627
0
0
0
0
4
Bottom
Ash
0
0
5,034
0
0
5,034
0
0
0
0
5
Flue Gas
SDA
0
0
20,137
0
0
20,137
167,815
3,025,239
953,169
312,611
6
Lime
to SDA
0
3,939
0
0
19,695
23,634
0
0
0
0
7
SDA Filter
Waste
0
0
20,082
12,099
0
32,181
0
0
0
0
8
Flue Gas
To Stack
0
0
54
0
0
54
167,815
3,025,239
954,647
471,206
C-23
-------
Appendix C
Energy and Material Balances
Stream
S02
NO2
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
psia
°F
mmBtu/h
1
Coal
Feed
0
0
0
517,045
14.7
59
4,550
2
Combustion
Air
0
0
3,963,930
3,963,930
14.7
59
55
3
HP Steam
toT/G
0
0
0
3,581,627
3,515
1,050
5,091
4
Bottom
Ash
0
0
0
5,034
14.7
2,498
10
5
Flue Gas
SDA
2,264
271
4,461,369
4,481,506
14.0
256
643
6
Lime
to SDA
0
0
0
23,634
14.7
32
0
7
SDA Filter
Waste
0
0
0
32,181
14.7
86
0
8
Flue Gas
To Stack
293
271
4,619,472
4,619,526
14.7
132
635
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Water
Subtotal
Gas
02
N2
CO2
H20
S02
NO2
Stream
No.
Units
Ib/h
Ib/h
9
Reheat
Steam
toT/G
3,259,280
3,259,280
10
Turbine
Exhaust
To
Condenser
2,770,388
2,770,388
11
Cooling
Water
to
Condenser
74,727,581
74,727,581
12
Cooling
Tower
Evaporative
Loses
2,918,205
2,918,205
13
Cooling
Tower
Blowdown
1,442,063
1,442,063
14
Waste
Water
(from
Process)
7,259
7,259
C-24
-------
Appendix C
Energy and Material Balances
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
psia
°F
mmBtu/h
9
Reheat
Steam
toT/G
0
3,259,280
560.0
1,000
4,948
10
Turbine
Exhaust
To
Condenser
0
2,770,388
115
1.50
2,840
11
Cooling
Water
to
Condenser
0
74,727,581
55
80
2,840
12
Cooling
Tower
Evaporative
Loses
0
2,918,205
25
118
2,977
13
Cooling
Tower
Blowdown
0
1,442,063
15
80
69
14
Waste
Water
(from
Process)
0
7,259
15
70
0
C-25
-------
Appendix C
Energy and Material Balances
Supercritical PC and Lignite Coal - Summary
Summary
Net Thermal
Efficiency
Net Heat Rate
(HHV)
Gross Power
Internal Power
Fuel required
Net Power
35.9
9,500
544
44
752,535
500
% HHV
Btu/kWh
MW
MW
Ib/h
MW
Supercritical PC and Lignite Coal - E&M Balance
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Water
Subtotal
Gas
Stream
No.
Units
Ib/h
Ib/h
1
Coal
Feed
382,288
0
135,155
0
235,092
752,535
2
Combustion
Air
0
0
0
0
0
0
3
HP Steam
toT/G
0
0
0
0
3,599,756
3,599,756
4
Bottom
Ash
0
0
27,428
0
0
27,428
5
Flue Gas
to Filter
0
0
109,712
0
0
109,712
6
Ash From
Filter
0
0
109,260
0
0
109,260
7
Flue Gas
toFGD
0
0
452
0
0
452
8
Limestone
toFGD
0
16,727
0
0
0
16,727
9
Gypsum
fromFGD
0
0
0
29,432
3,270
32,702
C-26
-------
Appendix C
Energy and Material Balances
Stream
02
N2
C02
H2O
S02
NO2
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
psia
°F
mmBtu/h
1
Coal
Feed
0
0
0
0
0
0
0
752,535
14.7
59
4,774
2
Combustion
Air
973,749
3,208,895
0
26,638
0
0
4,209,282
4,209,282
14.7
59
59
3
HP Steam
toT/G
0
0
0
0
0
0
0
3,599,756
3,515
1,050
5,117
4
Bottom
Ash
0
0
0
0
0
0
0
27,428
14.7
2,498
33
5
Flue Gas
to Filter
178,202
3,214,201
995,122
433,358
9,615
285
4,830,786
4,940,495
14.0
279
846
6
Ash From
Filter
0
0
0
0
0
0
0
109,260
14.7
278
30
7
Flue Gas
toFGD
178,202
3,214,201
995,122
415,389
9,615
285
4,812,814
4,813,266
15.0
293
812
8
Limestone
toFGD
0
0
0
0
0
0
0
16,727
14.7
32
0
9
Gypsum
fromFGD
0
0
0
0
0
0
0
32,702
14.7
86
1
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Water
Subtotal
Gas
Stream
No.
Units
Ib/h
Ib/h
10
Flue G&s
to Stack
0
0
57
0
0
57
11
Reheat
Steam
ToT/G
3,275,778
3,275,778
12
Turbine
Exhaust
to
Condenser
2,784,411
2,784,411
13
Cooling
Water
to
Condenser
75,105,834
75,105,834
14
Cooling
Tower
Evaporative
Loses
3,097,367
3,097,367
15
Cooling
Tower
Blowdown
1,530,729
1,530,729
16
Waste
Water
(from
Process)
20,929
20,929
C-27
-------
Appendix C
Energy and Material Balances
Stream
02
N2
CO2
H20
S02
NO2
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
psia
°F
mmBtu/h
10
Flue Gas
to Stack
178,202
3,214,201
1,001,396
606,687
409
285
5,000,963
5,001,020
14.7
139
835
11
Reheat
Steam
ToT/G
0
3,275,778
560.0
1,000
4,973
12
Turbine
Exhaust
to
Condenser
0
2,784,411
115
1.50
2,854
13
Cooling
Water
to
Condenser
0
75,105,834
55
80
2,854
14
Cooling
Tower
Evaporative
Loses
0
3,097,367
25
118
3,159
15
Cooling
Tower
Blowdown
0
1,530,729
15
80
73
16
Waste
Water
(from
Process)
0
20,929
15
70
1
C-28
-------
Appendix C
Energy and Material Balances
Ultra Supercritical PC and Bituminous Coal - Summary
Summary
Net Thermal
Efficiency
Net Heat Rate
(HHV)
Gross Power
Internal
Power
Fuel required
Net Power
42.7
8,000
543
43
342,863
500
% HHV
Btu/kWh
MW
MW
Ib/h
MW
Ultra Supercritical PC and Bituminous Coal - E&M Balance
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Water
Subtotal
Gas
02
N2
C02
H2O
Stream
No.
Units
Ib/h
Ib/h
1
Coal
Feed
270,485
0
34,252
0
38,126
342,863
0
0
0
0
2
Combustion
Air
0
0
0
0
0
0
844,050
2,781,483
0
23,090
3
HP Steam
toT/G
0
0
0
0
3,691,197
3,691,197
0
0
0
0
4
Bottom
Ash
0
0
7,096
0
0
7,096
0
0
0
0
5
Flue Gas
to Filter
0
0
28,385
0
0
28,385
154,467
2,785,762
796,782
207,287
6
Ash From
Filter
0
0
27,985
0
0
27,985
0
0
0
0
7
Flue Gas
toFGD
0
0
400
0
0
400
154,467
2,785,762
796,782
191,191
8
Limestone
toFGD
0
33,055
0
0
0
33,055
0
0
0
0
9
Gypsum
fromFGD
0
0
0
49,395
5,488
54,883
0
0
0
0
C-29
-------
Appendix C
Energy and Material Balances
Stream
S02
NO2
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
psia
°F
mmBtu/h
1
Coal
Feed
0
0
0
342,863
14.7
59
4,002
2
Combustion
Air
0
0
3,648,623
3,648,623
14.7
59
48
3
HP Steam
toT/G
0
0
0
3,691,197
4,515
1,100
5,413
4
Bottom
Ash
0
0
0
7,096
14.7
2,498
10
5
Flue Gas
to Filter
17,171
240
3,961,709
3,990,094
13.9
288
492
6
Ash From
Filter
0
0
0
27,985
14.7
287
15
7
Flue Gas
toFGD
17,171
240
3,945,613
3,946,013
15.0
304
473
8
Limestone
toFGD
0
0
0
33,055
14.7
32
0
9
Gypsum
fromFGD
0
0
0
54,883
14.7
86
1
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Water
Subtotal
Gas
02
N2
CO2
H20
S02
NO2
Stream
No.
Units
Ib/h
Ib/h
10
Flue Gas
to Stack
0
0
48
0
0
48
154,467
2,785,762
807,399
362,587
344
240
11
Reheat
Steam
toT/G
3,358,989
3,358,989
12
Turbine
Exhaust
to
Condenser
2,855,141
2,855,141
13
Cooling
Water
to
Condenser
77,013,663
77,013,663
14
Cooling
Tower
Evaporative
Loses
2,603,555
2,603,555
15
Cooling
Tower
Blowdown
1,286,649
1,286,649
16
Waste
Water
(from
Process)
35,125
35,125
C-30
-------
Appendix C
Energy and Material Balances
Stream
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
psia
°F
mmBtu/h
10
Flue Gas
to Stack
4,110,799
4,110,847
14.7
128
490
11
Reheat
Steam
toT/G
0
3,358,989
560.0
1,000
5,099
12
Turbine
Exhaust
to
Condenser
0
2,855,141
115
1.50
2,927
13
Cooling
Water
to
Condenser
0
77,013,663
55
80
2,927
14
Cooling
Tower
Evaporative
Loses
0
2,603,555
25
118
2,656
15
Cooling
Tower
Blowdown
0
1,286,649
15
80
62
16
Waste
Water
(from
Process)
0
35,125
15
70
2
C-31
-------
Appendix C
Energy and Material Balances
Ultra Supercritical PC and Subbituminous Coal - Summary
Summary
Net Thermal
Efficiency
Net Heat Rate
(HHV)
Gross Power
Internal Power
Fuel required
Net Power
41.9
8,146
543
43
460,227
500
% HHV
Btu/kWh
MW
MW
Ib/h
MW
Ultra Supercritical PC and Subbituminous Coal - E&M Balance
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Water
Stream
No.
Units
Ib/h
1
Coal
Feed
313,323
0
20,802
0
126,102
2
Combustion
Air
0
0
0
0
0
3
HP Steam
ToT/G
0
0
0
0
3,696,681
4
Bottom
Ash
0
0
4,481
0
0
5
Flue Gas
SDA
0
0
17,924
0
0
6
Lime
to SDA
0
3,506
0
0
17,531
7
SDA Filter
Waste
0
0
17,875
10,769
0
8
Flue Gas
To Stack
0
0
49
0
0
C-32
-------
Appendix C
Energy and Material Balances
Stream
Subtotal
Gas
02
N2
C02
H2O
S02
N02
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
Ib/h
psia
°F
mmBtu/h
1
Coal
Feed
460,227
0
0
0
0
0
0
0
460,227
14.7
59
4,076
2
Combustion
Air
0
816,223
2,689,782
0
22,329
0
0
3,528,333
3,528,333
14.7
59
50
3
HP Steam
ToT/G
3,696,681
0
0
0
0
0
0
0
3,696,681
4,515
1,100
5,421
4
Bottom
Ash
4,481
0
0
0
0
0
0
0
4,481
14.7
2,498
9
5
Flue Gas
SDA
17,924
149,374
2,692,795
848,425
278,655
2,015
244
3,971,509
3,989,433
13.9
256
576
6
Lime
to SDA
21,037
0
0
0
0
0
0
0
21,037
14.7
32
0
7
SDA Filter
Waste
28,644
0
0
0
0
0
0
0
28,644
14.7
86
0
8
Flue Gas
To Stack
49
149,374
2,692,795
849,741
417,481
265
244
4,109,899
4,109,948
14.7
132
569
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Stream
No.
Units
Ib/h
9
Reheat
Steam
ToT/G
10
Turbine
Exhaust
to
Condenser
11
Cooling
Water
To
Condenser
12
Cooling
Tower
Evaporative
Loses
13
Cooling
Tower
Blowdown
14
Waste
Water
(from
Process)
C-33
-------
Appendix C
Energy and Material Balances
Stream
Water
Subtotal
Gas
02
N2
C02
H20
S02
NO2
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
Ib/h
psia
°F
mmBtu/h
9
Reheat
Steam
ToT/G
3,363,980
3,363,980
0
3,363,980
560.0
1,000
5,107
10
Turbine
Exhaust
to
Condenser
2,859,383
2,859,383
0
2,859,383
115
1.50
2,931
11
Cooling
Water
To
Condenser
77,128,092
77,128,092
0
77,128,092
55
80
2,931
12
Cooling
Tower
Evaporative
Loses
2,651,199
2,651,199
0
2,651,199
25
118
2,704
13
Cooling
Tower
Blowdown
1,310,061
1,310,061
0
1,310,061
15
80
63
14
Waste
Water
(from
Process)
6,461
6,461
0
6,461
15
70
0
C-34
-------
Appendix C
Energy and Material Balances
Ultra Supercritical PC and Lignite Coal - Summary
Summary
Net Thermal
Efficiency
Net Heat Rate
(HHV)
Gross Power
Internal Power
Fuel required
Net Power
37.6
9,065
546
46
720,849
500
% HHV
Btu/kWh
MW
MW
Ib/h
MW
Ultra Supercritical PC and Lignite Coal - E&M Balance
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Water
Subtotal
Gas
Stream
No.
Units
Ib/h
Ib/h
1
Coal
Feed
366,191
0
129,465
0
225,193
720,849
2
Combustion
Air
0
0
0
0
0
0
3
HP Steam
toT/G
0
0
0
0
3,715,590
3,715,590
4
Bottom
Ash
0
0
26,273
0
0
26,273
5
Flue Gas
to Filter
0
0
105,093
0
0
105,093
6
Ash From
Filter
0
0
104,660
0
0
104,660
7
Flue Gas
toFGD
0
0
453
0
0
453
8
Limestone
toFGD
0
16,022
0
0
0
16,022
9
Gypsum
fromFGD
0
0
0
28,066
3,118
31,184
C-35
-------
Appendix C
Energy and Material Balances
Stream
02
N2
C02
H2O
S02
NO2
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
psia
°F
mmBtu/h
1
Coal
Feed
0
0
0
0
0
0
0
720,849
14.7
59
4,538
2
Combustion
Air
932,749
3,073,783
0
25,517
0
0
4,032,049
4,032,049
14.7
59
56
3
HP Steam
toT/G
0
0
0
0
0
0
0
3,715,590
4,515
1,100
5,448
4
Bottom
Ash
0
0
0
0
0
0
0
26,273
14.7
2,498
31
5
Flue Gas
to Filter
170,699
3,078,867
953,222
415,559
9,210
272
4,627,829
4,732,921
13.9
279
805
6
Ash From
Filter
0
0
0
0
0
0
0
104,660
14.7
278
28
7
Flue Gas
toFGD
170,699
3,078,867
953,222
396,467
9,210
272
4,608,736
4,609,190
15.0
295
772
8
Limestone
toFGD
0
0
0
0
0
0
0
16,022
14.7
32
0
9
Gypsum
fromFGD
0
0
0
0
0
0
0
31,184
14.7
86
1
Stream
Solids
Coal, daf
Sorbent
Ash/Slag
CaSO4.2H2O
Water
Subtotal
Gas
02
N2
C02
Stream
No.
Units
Ib/h
Ib/h
10
Flue Gas
to Stack
0
0
55
0
0
55
170,699
3,078,867
959,232
11
Reheat
Steam
toT/G
3,381,187
3,381,187
12
Turbine
Exhaust
to
Condenser
2,874,009
2,874,009
13
Cooling
Water
to
Condenser
77,522,608
77,522,608
14
Cooling
Tower
Evaporative
Loses
2,966,345
2,966,345
15
Cooling
Tower
Blowdown
1,465,973
1,465,973
16
Waste
Water
(from
Process)
19,958
19,958
C-36
-------
Appendix C
Energy and Material Balances
Stream
H20
S02
NO2
Subtotal
TOTAL
Pressure
Temperature
Total Energy
Stream
No.
Ib/h
Ib/h
Psia
°F
mmBtu/h
10
Flue Gas
to Stack
581,479
390
272
4,790,730
4,790,785
14.7
139
794
11
Reheat
Steam
toT/G
0
3,381,187
560.0
1,000
5,133
12
Turbine
Exhaust
to
Condenser
0
2,874,009
115
1.50
2,946
13
Cooling
Water
to
Condenser
0
77,522,608
55
80
2,946
14
Cooling
Tower
Evaporative
Loses
0
2,966,345
25
118
3,026
15
Cooling
Tower
Blowdown
0
1,465,973
15
80
71
16
Waste
Water
(from
Process)
0
19,958
15
70
1
Notes on waste Streams:
Solid Waste:
The solid waste streams from a PC boiler are: furnace bottom ash, fly ash and gypsum or other waste products resulting from the sulfur capture.
The fly ash is captured by fabric filters. The wet FGD process generates gypsum. In the dry FGD process, the calcium waste is captured in the
fabric filter with fly ash.
Liquid Waste:
Liquid waste is primarily from boiler blowdown in drum type subcritical boilers, and from cooling tower blowdown. In addition, the wet FGD
process may generate a bleed waste stream. This waste stream is reported as part of the total waste water discharge. The dry process does not
generate a wastewater stream during the sulfur capture process.
Make-Up Water:
Make-up water includes waste water discharge, as well as losses in the cooling tower.
C-37
------- |