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Jenny B. Tennant
Technology Manager, Gasification
April 2013
Gasification Systems Overview
U.S. DOE-NETL / CURC Workshop. NETL Pittsburgh, PA
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Gasification 101
Program Slides
Energy Outlook
Active DOE Cooperative Agreements
NETL In-House R&D (ORD-RUA)
DOE Supported Gasification Demonstration Projects
Systems Analysis
Gasification Systems Program
Bituminous Baseline Study
Bituminous IGCC Pathway Study
Low Rank Coal Baseline Study: IGCC Cases
Low Rank Coal IGCC Pathway Study
Conventional IGCC Compared to PC and NGCC
Commercial IGCC PlantsWorldwide Gasification Database
Closing
Background Slides
Slide LibraryTable of Contents
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Gasification 101
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Gasification converts any carbon-containing material intosynthesis gas, composed primarily of carbon monoxideand hydrogen (referred to as syngas)
Syngas can be used as a fuel to generate electricity or
steam, as a basic chemical building block for a largenumber of uses in the petrochemical and refiningindustries, and for the production of hydrogen
Gasification adds value to low- or negative-valuefeedstocks by converting them to marketable fuels andproducts
What is Gasification?
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Extreme Conditions:
415 psia or more2,600 FCorrosive slag and H2S gas
Products (syngas)
CO (Carbon Monoxide)
H2(Hydrogen)
[CO/H2ratio can be adjusted]
By-products
H2S (Hydrogen Sulfide)CO2(Carbon Dioxide)Slag (Minerals from Coal)
GasClean-Up
beforeProduct
Use
Courtesy: Eastman Chemical
The Gasifier
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Add water and high pressureUse less air or oxygen
Gasification exit gases are at high pressure, so smaller
volume, smaller reactors
Combustion makes heat + CO2+ H2O
Gasification makes less heat + carbon monoxide +
hydrogen (CO + H2); called Syngas
Gasification Differences from Combustion
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CleanElectricity
Transportation Fuels(Hydrogen)
Building Blocks forChemical Industry
So what can you do with CO and H2?
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Dry syngas is ~ 40% CO + 50% H2
For each CO molecule the WGS reaction creates one H2molecule and one CO2
molecule
Water-Gas-Shift (WGS) Reaction
CO + H2O + catalyst CO2 +H2
After the WGS reaction, the CO2and H2can be separated
High pressure CO2results in lower cost sequestration
Hydrogen can be burned to make power
2H2+ O2 2H2O
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Overview of Energy Systems Options
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Acetic Anhydride
Acetic Acid
Courtesy: Eastman Chemical
Methanol
Ammonia
Fertilizer (Urea)
Liquid Fuels (Diesel)
Hydrogen
Syngas
Chemicals and Products from Gasification
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Feedstock flexibility
Wide range of coals, petcoke, liquids, wastes, biomass can be utilized
Product flexibility
Syngas can be converted to high valued products: electricity, steam,
hydrogen, liquid transportation fuels, chemicals, SNG
Environmental superiority
Pollutants can be economically controlled to extremely low levels (SO2, NOX,
CO, Hg, etc.)
Reduced water consumption
Potential solid wastes can be utilized or easily managed
High efficiency / low CO2production
CO2can be easily captured for sale or
geologic storage (sequestration)
Benefits of Gasification
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Program Slides
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Continuing fuel price fluctuation natural gas andtransportation fuels
Energy security the U.S. has a lot of coal
Gasification can be used to make hydrogen (H2), fertilizer,
chemicals, transportation fuels from coal
Can be the lowest cost option to make power with carbondioxide (CO2) capture and storage
Excellent environmental performance for powergeneration
Why the Interest in Coal Gasification?
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Gasification Systems Program Goal
The goal of the Gasification Systems Program is toreduce the cost of electricity, while increasing power
plant availability and efficiency, and maintaining the
highest environmental standards
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Focus to reduce the cost of gasification, while increasing plant
availability and efficiency, and maintaining the highestenvironmental standards
FE Program Target: IGCC with CSS that has less than 10%increase in COE and 90% capture
Increasing focus on low rank coal (LRC) gasification
EIA forecasts significant growth in western coal production; low rankwestern coal cost per Btu predicted to remain at about half that ofeastern coal
Industry interest in cost-sharing LRC R&D
Potential for economic boost to U.S. regions with LRC reserves
Gasification Systems Program
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Low rank: lignite and sub-bituminous coal
About 50% of the U.S. coal reservesNearly 50% of U.S. coal production
Lower sulfur
EIA forecasts significant growth in western coal production;declining eastern coal production
Low rank western coal cost per Btu will stay at about half thatof eastern coal
U.S. Low Rank Coal Resources and Prices
Year
Lignite
Price
($/ST)
PRB
Price
($/ST)
Bitum.
Price
($/ST)
2010 16.77 13.93 53.40
2011 16.41 13.15 51.87
2015 16.67 13.00 48.70
2020 17.31 13.92 48.23
2025 17.83 15.31 49.03
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Program Benefits
U.S. Economic security keeping coal in the mix increasescertainty of stable energy foundation
Global greenhouse gas benefits
Programs Focus
Technologies applicable to:
Gasification: Integrated Gasification Combined Cycle(IGCC) power production with 90% carbon capture
Coal & Coal Biomass to Liquids (C&CBTL)(Fuels):Production of chemicals, fertilizers, hydrogen and/or
liquid fuelsPrograms overlap:
Polygeneration
Fuel flexible technologies that can apply to both
Program Overview
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Feed Systems
Oxygen separation
Expand fuel flexibility
Increase efficiency
Gasifier Optimization and Plant Supporting Systems
Improve reliability
Increase efficiency
Syngas Supporting Systems
Hydrogen and carbon dioxide separation
Control multi-contaminants to extremely low levels
Gasification Systems ProgramKey Technologies
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Feed Systems Oxygen separation
Expand fuel flexibility
Increase efficiency
Syngas Supporting Systems Control multi-contaminants
to extremely low levels Separate CO2from hydrogen
Oxygen
CO2
H2rich streamWaterGas Shift
Key Gasification Systems R&D Areas
Hot Compressed Air
FeedstockClean fuel gas
Gasifier Optimization &Plant Supporting Systems
Improve reliability Increase efficiency
Rawfuelgas
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Gasification Systems ProgramKey 2ndGeneration Technologies
Oxygen Membrane (TRL 4)7 % capital cost reduction
5 % COE reduction
Oxygen
CO2
H2Rich StreamWater
Gas Shiftup to 0.8 % efficiency
increase (preliminary)
Hot Compressed Air
Coal Feed Pump (TRL 4)1% COE reduction
Feedstock
Clean Fuel Gas
Raw
Fuel
Gas
Warm Gas Cleaning (TRL 4)in combination with
H2-CO2Membrane (TRL 4)
2.6 % pt efficiency increase
12 % COE decrease
Improvements in Reliability, Availabil ity, and Maintainability
Refractory durabilitySlag model development
Dynamic simulatorCFD gasifier modeling
Syngas cooler availabilityTemperature control
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Gasification industry interviews show interest in low rank coal
Most projects are cost shared with industry
Industry use is objective of Gasification Program R&D
Low rank coals present unique challenges andopportunities for
gasification and IGCC
High inherent moisture, high in alkali metals (Na, K, Ca)
High oxygen content, high reactivity, low sulfur and Low Cost
NETL systems analysis has shown low rank coal gasification has
the potential to be economically competitive
Altitude vs Shipping
Limited gasifier types
About half of the world, and U.S., coal reserves are low rank a
global market opportunity for advanced IGCC technology
Low Rank Coal Program PathwayWhy Its the Right Time
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Energy Outlook
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Recoverable Reserves
at Active Mines
3,968
1,731
Identified Resources
Measured, Indicated,
and Inferred
483
Demonstrated Reserve Base
Measured and Indicated, SpecifiedDepths and Thicknesses
Estimated
Recoverable
Reserves
Total Resources
Identified and
Undiscovered
258
19.2
U.S. Coal Resourcesbillion short tons
U.S. Fossil Fuel Reservesbillion barrels of oil equivalent
U.S. Fossil Fuel Resources
Bituminous473
Subbituminous325
Lignite78
Anthracite14
0
100
200
300
400
500
600
700
800
900
1000
Oil220
NaturalGas390
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Gas
23%Nuclear
6%
Renewables14%
Oil27%
Coal
30%
Gas
25%
Nuclear
9%
Renewables
14%
Oil
32%
Coal
20%
Gas
21% Nuclear6%
Renewables13%
Oil33%
Coal
27%
Gas
25%
Nuclear
9%
Renewables
8%
Oil
37%
Coal
21%
Sources: U.S. data from EIA, Annual Energy Outlo ok 2012er: World data fro m IEA, World Energy Outloo k 2011
726 QBtu / Year80% Fossil Energy
108 QBtu / Year77% Fossil Energy
+ 14%
Energy Demand 200995 QBtu / Year
83% Fossil Energy
481 QBtu / Year81% Fossil Energy
28,844 mmt CO2 43,320 mmt CO2
5,425 mmt CO2 8,806 mmt CO2
Energy Demand 2035
United States
World
+ 51%
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Low rank: lignite and sub-bituminous coal
About 50% of the U.S. coal reserves
Nearly 50% of U.S. coal production
Lower sulfur
Bituminous coal
About 50% of the U.S. coal reservesHigher heating value
Lower moisture and mineral content
EIA forecasts significant growth in western coal production;
declining eastern coal production
Low rank western coal cost per Btu will stay at about half that
of eastern coal
U.S. Coal Resources
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Oil and Gas Price Comparison
Crude refiners' cost projected to be $13.44/MMBtu greater
than Henry Hub spot price for natural gas in Jan. 2012.
Example:$18.15/MMBtu
$4.71/MMBtu
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Average World Oil Price Projections
0
50
100
150
200
250
2010
$/Barrel
Reference Case
High Oil Price Case
Low Oil Price Case
ProjectionHistorical
Source: EIA AEO 2012 (early release), Figure 5 27
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Source: IEA World Energy Outlook 2010, Current Polic ies Scenario
The European Union are
anticipated to maintain level ofCO2release through 2035;2020 for U.S.
China and India CO2emissions will substantially
increase into 2035
By 2020, Chinas CO2emissions will eclipse U.S.and the European Union,combined
By 2015, China aims to cutCO2emissions per uniteconomic growth by 16percent of 2011 levels
Carbon Capture is a Global Issue
China + 3,873
Million Metric Tonsfrom 2005-2016.
China
U.S.
India
European Union
CO2Emissions
million metric tons
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Active DOE Cooperative Agreements
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RTI Warm Gas CleanupORD Pd Sorbent
APCI Sour PSA - scoping study
TDA Integrated CO2Removal & WGS* -
scoping study
NCCC WGS Optimization
Eltron H2/CO2Membrane
Oxygen
CO2
H2rich streamWaterGas Shift
Gasification Systems Program Projects
FEED SYSTEMSAPCI Ion Transport Membrane
PWR Dry Coal Feed Pump
GE Posimetric Pump*
scoping studyEPRI CO2-Coal Slurry*
scoping study
GASIFIER OPTIMIZATION AND PLANT SUPPORTING SYSTEMS
VPI Temperature SensorREI Syngas Cooler Fouling
NCCC Transport Gasifier Optimization*ORD Low Rank Coal Optimization*
GTI Real-Time Flame Monitor SensorGE Improve Availability and Reduce CostsORD Improve RefractoryORD Conversion and Fouling
*Low-rank Coal Alternative Feedstocks
SYNGAS PROCESSING SYSTEMS
ORD: NETLs Office of Research and Development30
National Carbon Capture Center at the
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Location: Wilsonville, ALSubcontractors
American Electric Power
Arch Coal
Electric Power Research InstituteLuminant
NRG
Peabody Energy
Rio Tinto
Development and commercial scale-up of modular industrialscale gasification-based processes and components
National Carbon Capture Center at the
Power Systems Development FacilitySouthern Company Services
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Goal
Accelerate path to cost-effective CO2capture technology for all 3 major areas
of CO2 Capture; post combustion, pre-combustion, oxy-combustion
Technology
Flexible testing facilities from bench to engineering-scale
Project tasksModifications underway to enhance and enlarge pre-combustion CO2capture
testing infrastructure to enable testing of membranes, sorbents and solvents
National Carbon Capture CenterSouthern Company Services
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Fuel flexibility, filter materials, sensor developmentTwo gasification tests using PRB coal totaling > 1250 hours thru Dec. 2012 Continued evaluating & improving new gasifier temperature control scheme
Continued long-term evaluation of hot gas filter elements
Conducted sensor development involving sapphire thermowell for gasifier service, coal-flowmeasurement device, vibration type level detector, and TDL
Conducted oxygen-blown gasification testing with biomass co-feed
Replaced gasifier standpipe (15 years)
Carbon captureModifications continue to enhance and enlarge pre-combustion CO2capture testinginfrastructure to enable testing of membranes, sorbents, and solvents (upgrade SCU to1000 lb/hr and MTR CO2membrane 10x). Evaluated: Hydrogen and CO2membranes from four developers
CO2capture with new solvents
Water-gas shift catalyst performance
CO2capture sorbents
National Carbon Capture Center (NCCC)Advanced Gasification and H2Separation Results in 2012
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Accomplishments through 2012 include:
30 major gasification test campaignsOver 18,100 hours of gasification operation
Successful engineering scale demonstration of advanced power systems technologies, includinghot gas filtration and high-pressure solids handling systems
Developed gasifier suitable for low-rank fuels use; modified gasifier to improve carbon conversionand syngas heating value
Extensive successful operation on a variety of coals including: lignite, subbituminous, and
bituminousIdentified suitable filter elements to achieve the long-term high collection efficiency required bycommercial turbines (routinely operated filtration system with outlet solids concentrations in thesyngas less than 0.1 ppmw)
Identified failsafe devices that reliably seal off failed filter elements, thus enhancing reliability andprotecting downstream components
TRIGTMtechnology being used in CCPI demonstration, Kemper County, MS
Supported DOEs SOFC development programs with fuel cell tests on syngasConducted air- and oxygen- blown gasification testing with biomass/coal co-feed
Demonstrated advanced syngas cleanup technologies such as mercury sorbents
National Carbon Capture Center (NCCC)Advanced Gasification and H2Separation
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Power Systems Development Facility (PSDF)
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History - Established by DOE in early 90s
To accelerate development of more efficient advanced
coal-based power plant technologies
Research centered around high-temperature, high-
pressure filtrationSigned over 115 non-disclosure agreements (NDA)s with
developers to support advancement of their
technologies
Air-blown Transport Gasifier commenced operation in
1999
Power Systems Development Facility (PSDF)Project History - Accomplishments
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Current Technology: Cryogenic oxygen
ITM oxygen production uses ceramic membranes to selectively separate
oxygen in air from nitrogen
Benefits: 25% oxygen plant capital cost reduction; 2% decrease in IGCC COE
Status:
APCI completed lab scale and small pilot testing (5 TPD) 100 TPD test system & module manufacturing facility under construction
(TRL 4)
Current ARRA project will end with start-up of commercially-capable facilityfor module creation (TRL 7)
This technology may be used by other industries at smaller-scale, substantially
reducing the risk and cost of initial IGCC deployment
R&D focus has been on high pressure oxygen production for IGCC but
Advanced Oxygen Production will also reduce costs in Oxyfuel applications
Advanced Oxygen Production
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Ion Transport Membrane (ITM)Development of ITM Oxygen Technology
0.5 TPDStackProgression to commercial
size wafers
1.0 TPD Stack
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-TPD module(multiple membranes)
Ion Transport Membrane (ITM)
Supported thin-film, ceramic planar devicesFast, solid state electrochemical transport of oxygen
Pressure-driven; compact
All the layers are composed of the same ceramic material
Ion Transport Membrane (ITM)Air Products and Chemicals, Inc. (APCI)
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Membrane Air Separation AdvantagesCryo-ASU vs. ITM in IGCC
G-Class cases include full air-side integration of advanced gas turbine and oxygen plant
Improved Efficiency
Better Economics
Source: Air Products and Chemicals, Inc.
IGCC
Efficiency
Cryo-ASUITM with
F-Class GT
ITM with
G-Class GT
No CCS BASE 0.8% 2.9%With CCS BASE 0.3% 2.2%
Oxygen PlantCost
Cryo-ASUITM with
F-Class GTITM with
G-Class GT
No CCS BASE -24.9% -34.8%With CCS BASE -24.5% -36.3%
Levelized Cost
of Electricity
Cryo-ASUITM with
F-Class GTITM with
G-Class GT
No CCS BASE -1.6% -5.0%With CCS BASE -2.1% -4.9%
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Goal: Reliable and consistent dry feed for high pressure IGCC, leading to
lower cost
Technology: Bulk solids form multiple stable bridges between parallel
moving walls to feed dry solids across 1,000+ psi pressure gradient
Project tasks:
Complete initial test series on nominal 600 tpd prototype pilot-scale drysolids pump and complete economic analysis
Team Members:
Pratt & Whitney Rocketdyne, Albany Research Center, University of North
Dakota Energy & Environmental Research Center, Oak Ridge NationalLaboratory
High Pressure Solids PumpPratt & Whitney Rocketdyne
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Pump operation relies on ability of bulk
solids to form multiple stable bridgesor arch between parallel wall structure,bridges can support very large loads
Increasing load is transferred tosidewalls, making the bridge more stable,further increasing load will ultimately failthe sidewall
Extrusion or pumping occurs whensidewalls are moved mechanically andmaterial is released by separating thewalls
High Pressure Solids PumpPratt & Whitney Rocketdyne
Normal
Loads
Normal
Loads
CoalPlug
Load +Friction
Coal PlugGas Load+ Friction
NormalLoads
ShearLoad
NormalLoads
TractiveForce
In lock-up there is no slip or relative motion between material and moving
walls, device exhibits positive displacement with a volumetric displacement
of unity
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B fi f D F d S
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Goal: Evaluate and demonstrate the benefits of novel dry-feed technologiesto effectively, reliably, and economically feed low-rank coal into commercial
IGCC systems
Technology: The advanced technologies analyses will be based around the
Posimetric pump currently under development by GE
Project tasks:
Complete report on test data supporting the potential value of theadvanced technologies
Complete performance for Posimetric Feed System
Complete performance and economic calculations for baseline plant.Team Members: General Electric Company
Benefits of Dry Feed SystemGeneral Electric Company
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Hi h P S lid F d S
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Current Technology: Dry feed w/ lock hoppers or slurry feed
Frictional forces between the dry feedstock particles form multiple stable bridges that
act as pressure barriersBenefits:
Reliable and consistent dry feed for high pressure IGCC leading to lower cost (1%reduction in COE)
Potential to significantly improve the efficiency of gasification by enabling two newgasification configurations: Slurry-fed gasifiers (such as the GE gasifier) on low rank coal
Dry-fed gasifiers at high pressure currently these gasifiers (such as Shell) are limited to about500 psi
Status:
Pratt Whitney Rocketdyne (PWR) 400-600 TPD prototype testing has begun
Systems analysis using LRC and quench cooler with the GE Posimetric pump is ongoing
Team Members: Pratt & Whitney Rocketdyne, Albany Research Center, University of North
Dakota Energy & Environmental Research Center, Oakridge National Laboratory, General
Electric Company
High Pressure Solid Feed Systems
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Goal: Reduce the cost and improve the efficiency of IGCC with carbon capture
Technology:High purity CO2stream as the carrier fluid to feed low rank coal
into the gasifier
Project tasks:
Complete plant-wide technical and economic analyses of low rank coalsusing both liquid CO2and water slurry feeds
Complete Technology Development Roadmap on the novel technologydesigned to reduce the cost of low rank coal gasification
Team Members: Electric Power Research Institute, Dooher Institute of Physicsand Energy, Worley Parsons Group, Inc., Columbia University
CO2Slurry FeedElectric Power Research Institute, Inc. (EPRI)
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Goal: Develop and demonstrate a reliable, practical, and cost effective
prototype sensor capable of monitoring gasifier interior temperature and
other operational conditions in real time
Technology: Further development and demonstration of the Real Time Flame
Monitoring of Gasifier Burner and Injectors sensor technologyProject tasks:
Complete design of the purging system, complete sensor soft
Prepare and test sensor software package, confirm sensor accuracy is
30 F
Design, build, and install sensor purging system
Team Members: Gas Technology Institute, Wabash River, ConocoPhillips
Company, North Carolina State University
Development of Prototype Commercial Gasifier
SensorGas Technology Institute
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Goal: Develop an accurate temperature measurement system capable ofwithstanding harsh conditions for use in commercial, full-scale gasification
systems
Technology: A broadband polarimetric differential interferometric
temperature sensor with a single-crystal sapphire to make an optically-based
measurement
Project tasks:
Recipient plan includes two additional test campaigns to demonstrateviability of the sensor as well as the packaging
Team Members:Virginia Polytechnic Institute, Eastman Chemical Company
Single Point Sapphire Temperature SensorVirginia Polytechnic Institute
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Miti ti f S C l Pl i & F li
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Goal: Improve the availability of IGCC plants through improving the
performance of the syngas cooler through reduced plugging and fouling
Technology:Combination of laboratory scale experiments to evaluate deposit
strength and computational fluid dynamic modeling to evaluate designs to
mitigate fouling and plugging
Project tasks:
Perform deposit bond strength test using ash from gasifier Complete computational fluid dynamic modeling of strategies to mitigate
syngas cooler plugging and fouling for 5 scenarios
Team Members: Reaction Engineering International, University of Utah, SaltLake City
Mitigation of Syngas Cooler Plugging & FoulingReaction Engineering International
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IGCC Aff d bilit d A il bilit
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Goal: Reduce the time to technological maturity and enable IGCC plants to
reach higher values of availability in a shorter period of time at a lowerinstalled cost
Technology: Studies for identification and technical evaluation of concepts to
reduce total installed cost and improve availability with broad applicability to
the IGCCC industry including; integrated operations philosophy,
modularization of gasification /IGCC plant, active fouling removal, improvedslag handling
Project tasks:
Develop a conceptual design for improved slag handling
Develop a conceptual design for an improved slip form structure Prepare two preliminary designs
Team Members: General Electric Company
IGCC Affordability and AvailabilityGeneral Electric Company
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N Z E i i S Cl i
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Current Technology: Rectisol or Selexol
RTIs high-temperature syngas cleanup removes the most significant coalcontaminants from syngas
Benefits(in combination with hydrogen membranes):
2.6% pt increase in efficiency ; 12% decrease COE
Status:
Completed pilot-scale testing (0.3 MW scale) (TRL 4-5) ARRA test system (50 MW scale) construction underway (TRL 6-7) Mechanical completion and operational startup in FY14 Current project will end after system operation of ~5,000 hours (TRL 6)
Chemical-grade trace contaminant levels are expected to exceed current and
future EPA requirements, enabling IGCC to be the cleanest option for turning
coal into power
Near-Zero Emissions Syngas Cleaning
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Warm Gas Cleanup RTI
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RTI Warm Gas Cleanup Technologies
Cleans multi-contaminants from coal-derived
syngas while creating pure sulfur product
High Temperature Desulfurization Process
> 99.9 % removal of both H2S and COS(to < 5 ppmv levels)
> 3,000 hours of operation at 0.3 Mwe
Direct Sulfur Recovery Process
> 99.8 % SO2conversion to elemental sulfur96 % ammonia removal
90 % mercury and arsenic removal
Warm Gas Cleanup RTIPrevious Testing at Eastman Chemical
Pilot Plant Operation atEastmans Gasification Facility,
Kingsport, TN
50
Multi-contaminantControl Test System
High TemperatureDesulfurization
Process
Direct SulfurRecoveryProcess
Advanced CO Capture Technology for
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Goal: Demonstrate technical and economic potential for an integrated CO2
scrubber/ water gas shift catalyst
Technology: Highly reactive sorbent in an integrated transport reactor system
Project tasks:
Test sorbents/catalysts to determine working capacity and plantefficiency
Complete testing with protoype unit
Complete techno-economic analysis
Team Members: TDA Research, Inc., University of California at Irvine,
Southern Company, ConocoPhillips
Advanced CO2Capture Technology for
Low Rank Coal IGCC SystemsTDA Research, Inc
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Hydrogen Membranes
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Current Technology: Pressure Swing Adsorption
Hydrogen transport membrane uses dense metal to separate H2from
shifted syngas leaving CO2at high pressure produces ~100% hydrogenstream
Benefits:in combination with RTI high-temperature syngas cleanup
2.6% pt increase in efficiency; 12% decrease COE
Status:
Eltron conducted lab scale and small pilot testing on coal derived syngas(1.5lb/day)
WPI and Praxair selected for Phase II work (20 - 50 lb/day) to testprototype membrane with coal-derived syngas (TRL 4)
Team Members: Eltron Research, Inc., Worcester Polytechnic Institute,Praxair, Inc.
Hydrogen membranes make chemical-grade hydrogen, useable in IGCC,
chemical and liquids production and for polygeneration applications.
Hydrogen Membranes
52
Hydrogen Transport Membrane (HTM)
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Hydrogen Transport Membrane
High CO2retentate pressure
Allows capture of high pressure CO2
High hydrogen recoveries >90%
Essentially 100% pure hydrogen
Low cost, long membrane life
Hydrogen Transport Membrane (HTM)Eltron Research, Inc.
Eltron Research & Development Tech Briefhttp://www.eltronresearch.com/docs/Hydrogen_Membrane_Technology_Summary.pdf
Conceptual design ofcommercial membrane unit
53
Reliability Availability & Maintenance Improvements
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Reliability, Availability & Maintenance Improvements
Current Technology: IGCC RAM is too low and too unpredictable (financing and
profit risk); improving it is too costly
GE is determining the feasibility of improving plant availability and reducing
total installed cost in IGCC power plants.
Benefits: 1% availability improvements = ~1% COE reduction ($1/tonne
cost of capture reduction)
Status: Techno economic studies ongoing: Integrated Operations Philosophy,
Modularization of Plant, Fouling Removal System, Improved Blow Down
System for Slag Handling (TRL 2)
Current project will end with study results for plant design, construction andoperations improvements. (TRL 4)
Other Research:
NETL ORD: refractory improvement, fundamental slag and ash behaviorstudies from inside the gasifier to syngas cooler fouling
NCCC long-term refractory and candle filter durability tests
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Refractory Improvement
Develop improved performance refractory liners
Model gasifier slag
Manage slag viscosity and refractory wear, evaluate additives
Conversion and Fouling:
In slagging gasifiers using coal, petcoke or blends
Improve the carbon conversion efficiency to syngas
Reduce convective syngas cooler fouling
Low-Rank Coal Optimization
Pretreatment and kinetic co-feed experimental efforts
Demonstrate the models the NCCC/TRIG under co-feed conditions
Warm Syngas Cleanup
Conduct both lab and pilot-scale R&D for cost efficient sorbents for trace contaminant
capture
Advanced Virtual Energy Simulation Training And Research (AVESTARTM) Center
Establish the world-class center for addressing key operational and control challenges
arising in IGCC plants with carbon capture
NETL Office of Research & DevelopmentGasification Projects
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NETL In-House R&D (ORD-RUA)
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Refractory Improvement
Develop improved performance refractory liners that arecarbon feedstock flexible (coal, western coal, petcoke)
Model gasifier slag for refractory interactions, downstreamphases and material interactions (syngas coolers)
Manage slag viscosity and refractory wear, evaluate additives
Conversion and Fouling
In slagging gasifiers using coal, petcoke or mixtures ofthem to:
Improve the carbon conversion efficiency to syngas Reduce convective syngas cooler fouling
Collaborate with industry to ensure proper technology development andtransfer
NETL Office of Research & DevelopmentGasification Projects
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NETL Office of Research & Development
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Low-Rank Coal Optimization
Pretreatment and kinetic co-feed experimental efforts tosupport and validate the development of a hierarchy of
device scale gasifier models with uncertainty quantification
Demonstrate the models with UQ for the NCCC/TRIG underco-feed conditions and optimize co-feed performance
Warm Syngas Cleanup
Conduct both lab and pilot-scale R&D for cost efficientsorbents for trace contaminant capture of high efficiency
coal gasification plant
Advanced Virtual Energy Simulation Training and Research
(AVESTARTM) Center
Training Center: 3D virtual simulation of IGCC plant
Establish the world-class center for addressing key operationaland control challenges arising in IGCC plants with carbon capture
NETL Office of Research & DevelopmentGasification Projects
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Refractory Improvement
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Refractory Development for Mixed Feedstock Use
Determine mechanisms of wear in NETL refractory materialsunder development.
Determine refractory corrosion mechanisms in current generationcommercial refractory liner materials exposed to coal slag,
important for understanding how to overcome limitations in current
refractory liner materials
Slag Management (Current Emphasis)
Determine critical information needed for slag management in gasifiers,
which will be tracked in commercial gasifiers and predicted in models toincrease gasifier RAM
Refractory ImprovementNETL Office of Research and Development
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Advanced Refractory For Gasifiers
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New refractory chemistry
Increases mechanical durabilityReduces slag penetration
Advanced Refractory For Gasifiers
Phosphate modified high-chromeoxide refractory material
Conventional refractory afterrotary slag testing
Rotary Slag Test
60
Advanced Refractories for Gasifiers
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Cr+6formation in high Cr2O3refractories is thermodynamically predicted
not to be an issue with current carbon feedstock
Low oxygen partial pressure results in low Cr+6formation Gasification environment has O2 partial pressure about 10
-8
NETL Office of Research and Development
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Current refractory goal is to refine/evaluate composit ion in commercial gasifiers
Conversion and Fouling
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Modeling
Evaluate and validate sub-models for particle-slag interaction,particle fragmentation, and mineral matter chemistry
(sulfur release) and implement into CFD model
Develop and evaluate reduced order model to predict mineral
matter split between slag and fly ash for entrained-flow gasifier
Convective Syngas Cooler Fouling
Literature survey of deposition models
Investigate gasifier ash deposits to determine problematic ash characteristics
Kinetics
Effect of pressure on pyrolysis kinetics
Preliminary gasification kinetics at high pressureSlag Characterization
Continue to characterize coal and petcoke blends, characterize ash and slag, begin
studies of FeS and VOx behavior in slag
Conversion and FoulingNETL Office of Research and Development
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Control of Ash in IGCC
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Goal: Solutions to IGCC Ash Management Problems
Unconverted carbon in gasification flyash
Syngas cooler fouling
Development of Models and Techniques to improve
IGCC plant operations
Adaption of Particle Population Model usedfor predicting CFB ash splits
Inorganic transformations and char/slag interactions
Particle trajectories and deposition modeling
Gasification kinetics
Coordinate and leverage R&D at NETL and
three universities (PSU, CMU and WVU)
Control of Ash in IGCCRegional University Alliance
1. Particles contact and
coalesce with slag2. Particles do not contact slag3. Particles contact but do not
coalesce with slag
FuelOxygenWater
Syngas + Flyash
1
23
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Low Rank Coal Optimization
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Kinetics:
Development of NETLs Carbonaceous Chemistry for Computational Modeling(C3M) software to bridge coal kinetics software (PCCL, CPD, etc) and available
kinetic experiments with CFD software (MFIX, Fluent, Barracuda), other
models
Provide modelers and experimentalist with a virtual kinetic laboratory
Fuel Pretreatment:
Expand and further test the grinding laws developed in FY11
Correlate the NETL lab scale results with large scale grinding energies
Multiphase Models:
NETLs open source suite of multiphase solvers such as MFIX-DEM, MFIXcontinuum, MFIX-PIC and multiphase Reduced Order Models will be used to
aid in the design and optimization of operating conditions and establishing
performance trends in the NCCC/TRIG with uncertainty quantification
Low Rank Coal OptimizationNETL Office of Research and Development
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Warm Syngas Cleanup
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Elevated temperatures result in higher IGCC thermal efficiency
Palladium-based sorbents are currently among the most promisingcandidates for high-temperature capture of mercury, arsenic, selenium,
phosphorus and the other trace elements
Progress:
2007- License agreement between the NETL and sorbent manufacturer
Johnson Matthey
2008- Warm Syngas Cleanup received the R&D 100 award
2009 to 2013 - Over 99% removal of mercury, arsenic, and selenium from
syngas slipstreams at 550oF over several weeks testing at the
National Carbon Capture Center
Present- Identifying an optimum form of the palladium sorbent (loading,
support, alloy)
Warm Syngas CleanupNETL Office of Research and Development
65
Advanced Virtual Energy Simulation Training And
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Features
R&D, Training, and Education for the Operation and Control of Advanced Energy Systems with CO2Capture and Storage
Real-time Dynamic Simulators with Operator Training
System (OTS) Capabilities
3D Virtual Immersive Training Systems (ITS)
BenefitsOTS for normal and faulted operations, plant
start-up, shutdown, and load following/shedding
ITS for added dimension of plant realism
OTS/ITS for training both control room and
plant field operators, promoting teamworkWork force development in IGCC plant and CO2capture operations
Advanced R&D in process dynamics, model predictive control,
sensors, RT optimization, 3D virtual plants, and more
gy g
Research (AVESTAR)
CenterNETL Office of Research and Development
For more information on AVESTAR and IGCC training courses, please send email to [email protected] 66
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DOE Supported GasificationDemonstration Projects
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DOE Supported IGCC Demonstration ProjectsCl C l P I iti ti I d t i l C t & St
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Summit TX Clean Energy, CCPI-3Commercial Demo of Advanced IGCC
w/ Full Carbon Capture~$1.7B Total, $450M DOE
EOR 3M TPY 2018 start
HECA, CCPI-3
Commercial Demoof Advanced IGCCw/ Full Carbon Capture
~$4B Total, $408M DOEEOR 3M TPY 2018 start
Clean Coal Power Initiative, Industrial Capture & Storage
68
Southern Company, CCPI-2 Kemper CountyIGCC-Transport Gasifier w/Carbon Capture ~$2.67B
Total; $270M DOE EOR 3 M TPY 2014 start
CCPI Pre-combustion
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CCPI Pre combustion
Capture and Storage Approaches
Plant Type SequestrationFeedstock
Power Industrial Saline EOR Rate*
Pre-combustion
HECA (IGCC-Polygen) X X X 2.55NM Sub-bituminousCoal/Petcoke Blend
Southern-Kemper Co. (IGCC) X X 3.0 MS Lignite
Summit Texas (IGCC-Polygen) X X X 2.2WY Sub-bituminous
Coal
*Rate in mi llion metric tons per year
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CCPI Gasification Projects
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CCPIRound
ProjectCO2 CaptureTechnology
StorageReservoir
CO2 Seq.MM TPY
Seq.Start
2 Southern: Kemper Selexol EOR 3.0 2014
3b Summit: TCEP Rectisol EOR 2.7 2017
3a HECA Rectisol EOR 3.0 2019
CCPI Gasification Projects
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Southern Company Services, Inc. CCPI-2
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Southern Company Services, Inc. CCPI 2Advanced IGCC with CO2Capture
Plant SitePlant Site
Status
Plant construction >50% complete
CO2off-take agreements signed
Lignite mine under development
Subsystems (water treatment, cooling towers,etc.) to begin pre-commissioning
Combustion turbine startup: Jul 2013
Gasifier heat-up: Dec 2013
Key Dates
Project Awarded: Jan 30, 2006 Project moved to MS: Dec 5, 2008
NEPA Record of Decision: Aug 19, 2010
Initiate excavation work: Sept 27, 2010
Operations: May 2014
Kemper County, MS
582 MWe (net); 58 MWe duct firing; 2 TRIGTM
gasifiers, 2 Siemens combustion turbines, 1Toshiba steam turbine
Fuel: Mississippi lignite
~67-69% CO2capture (Selexol process);
3,000,000 tons CO2/year
EOR; Denbury Onshore LLC, Treetop Midstream
Services LLC Total DOE Project: $2.01 billion;
DOE Share: $270 million (13%)
Total estimated plant cost: ~ $3 billion
71
Summit Texas Clean Energy, LLC CCPI-3
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Penwell, Ector County, TX 200 MW (net), 0.7 MMT/yr Urea; greenfield IGCC
with Siemens gasification & power Block
SFG-500 gasifiers (2 x 50%) High H2SGCC6-5000F combined cycle (1 x 1)
Fuel: PRB sub bituminous coal 90% CO2capture ~2,700,000 tons CO2/year
2.2 MM tonnes EOR; 0.5 MM to Urea production
2-stage Water Gas Shift, Linde RectisolAGR
EOR: Permian Basin Oilfields Total DOE Project: $1.727 billion; DOE Share: $450 million (26%) Total Plant Cost ~$2.6 billion
gy,Advanced IGCC-Polygen
Key Dates
Project Awarded: Jan 2010
Air Permit; Dec 2010 NEPA Record of Decision: Sep 2011
Financial Close: Jun 2013
Construction: 3rdQ2013
Operation: Nov 2017
Status
Urea contract: Jan 2011
CO2contract(s): Nov 2011 Power off-take contract: Dec 2011
Chexim signed for debt financing MOU:Sep 2012
Sinopec signed EPC agreement: Dec2012
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Hydrogen Energy California CCPI-3
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Hydrogen Energy California CCPI 3Advanced IGCC-Polygen
Kern County, CA Up to 300 MWe (net) with load following; greenfield
IGCC, 1.0 MMT/yr Urea/UAN MHI oxygen-blown gasifier (1 x 100%) MHI G-class air cooled combustion turbine (1)
Fuel: Sub-bituminous coal/petcoke 90% CO2capture 3,020,000 tonnes CO2/year
2.57 MM tonnes EOR; 0.45 MM Urea production 2-stage Water Gas Shift, Linde RectisolAGR
EOR: Elk Hills oilfield Use of brackish water for power production; ZLD Total DOE Project: $4 billion; DOE: $408 million (10%)
Total Plant Cost: ~$5 billion
IGCC Poly-generation withIntegrated Carbon Capture & Sequestration
Key Dates
Project Awarded: Sep 2009 New Owner, SCS Energy: Sep 2011
Financial Close: Dec 2013
Start of Construction: Sep 2014
Start of Operation: Apr 2019
Status
NEPA public scoping meeting: Jul 2012
Power/Fertilizer/CO2/EPC discussions inprogress
Draft PSA/EIS: Mar/Apr 2013
FEED completion: Jun 2013
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Systems Analysis
Gasification Systems Program
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NETLs Program Analysis Support
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Low Rank Coal:
Parallel screening studies for Gasification FY11 awardsCost and Performance Baseline for TRIG
PRB and ND Lignite Air Blown IGCC Texas Lignite Air and Oxygen Blown IGCC
Co-feeding of biomass to meet 90% equivalent CCS
IGCC with CCS Pathway Study: Low Rank Coal
Co-production assessmentsAltitude versus shipping sensitivity analysis
IGCC availability studies:
Identifying gaps for conventional technologies
Setting targets for advanced technologies
General advanced technology assessments:
IGCC with CCS Pathway: Bituminous Coal, Updates DOE IGCC portfolio + PWR compact gasifier assessment Pressure sensitivity analysisUpdated WGCU assessment - learnings from TECO design
g y ppOn-going and Planned Gasification Studies
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Technical Approach
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1. Extensive Process Simulation (ASPEN)All major chemical processes and equipment are simulated
Detailed mass and energy balancesPerformance calculations (auxiliary power, gross/net power output)
2. Cost EstimationInputs from process simulation(FlowRates/Gas Composition/Pressure/Temp.)
Sources for cost estimationIn-house dataVendor sources where available
Follow DOE Analysis Guidelines
pp
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Systems Analysis
Bituminous Baseline StudyFull presentation available at:
http://www.netl.doe.gov/energy-analyses/baseline_studies.html
77
Study Matrix
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y
Plant
Type
ST Cond.
(psig/F/F)
GTGasifier/
Boiler
Acid Gas Removal/
CO2
Separation / SulfurRecovery
CO2
Cap
IGCC
1800/1050/1050(non-CO2
capture cases)
1800/1000/1000
(CO2capturecases)
FClass
GEESelexol / - / Claus
Selexol / Selexol / Claus 90%
CoP
E-Gas
MDEA / - / Claus
Selexol / Selexol / Claus 90%
Shell Sulfinol -M / - / Claus
Selexol / Selexol / Claus 90%
PC
2400/1050/1050 SubcriticalWet FGD / - / Gypsum
Wet FGD / Econamine / Gypsum 90%
3500/1100/1100 SupercriticalWet FGD / - / Gypsum
Wet FGD / Econamine / Gypsum 90%
NGCC 2400/1050/1050F
ClassHRSG
- / Econamine / - 90%
GEE GE Energy
CoP Conoco Phillips
78
IGCC Performance Results
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GE Energy E-Gas Shell
CO2Capture NO YES NO YES NO YES
Gross Power (MW) 748 734 738 704 737 673
Auxi liary Power (MW)
Base Plant Load 25 26 24 28 22 25
Air Separation Unit 98 115 86 111 85 103
Gas Cleanup/CO2Capture 3 19 3 20 1 19
CO2Compression - 31 - 31 - 30
Total Aux. Power (MW) 126 191 113 190 108 177
Net Power (MW) 622 543 625 514 629 497
Heat Rate (Btu/kWh) 8,756 10,458 8,585 10,998 8,099 10,924
Effic iency (HHV) 39.0 32.6 39.7 31.0 42.1 31.2
Energy Penalty1 - 6.4 - 8.7 - 10.91CO2Capture Energy Penalty = Percent points decrease in net powerplant efficiency due to CO2Capture
79
PC and NGCC Performance Results
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Subcritical Supercr itical NGCC
CO2Capture NO YES NO YES NO YES
Gross Power (MW) 583 673 580 663 565 511
Base Plant Load 28 45 25 41 10 12
Gas Cleanup/CO2Capture 5 29 5 27 0 10
CO2Compression - 49 - 45 - 15
Total Aux. Power (MW) 33 123 30 113 10 37
Net Power (MW) 550 550 550 550 555 474
Heat Rate (Btu/kWh) 9,277 13,046 8,687 12,002 6,798 7,968
Effic iency (HHV) 36.8 26.2 39.3 28.4 50.2 42.8
Energy Penalty1 - 10.6 - 10.9 - 7.41CO2Capture Energy Penalty = Percent points decrease in net powerplant efficiency due to CO2Capture
80
IGCC Economic Results
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GE Energy E-Gas Shell
CO2Capture NO YES NO YES NO YES
Plant Cost ($/kWe)1
Base Plant 1,426 1,708 1,423 1,804 1,719 2,164
Air Separation Unit 312 429 281 437 285 421
Gas Cleanup/CO2Capture 249 503 209 500 213 521
CO2Compression - 71 - 76 - 75
Total Plant Cost ($/kWe) 1,987 2,711 1,913 2,817 2,217 3,181
Capital COE ($/MWh) 43.4 59.1 41.7 61.5 48.2 69.2
Fixed COE ($/MWh) 11.3 14.8 11.1 15.5 12.1 16.7
Variable COE ($/MWh) 7.3 9.3 7.2 9.8 7.8 9.9
Fuel COE ($/MWh) 14.3 17.1 14.0 18.0 13.3 17.9
CO2TS&M COE ($/MWh) 0.0 5.2 0.0 5.5 0.0 5.6
Total COE2 ($/MWh) 76.3 105.6 74.0 110.3 81.3 119.4
CO2Avoided B v A ($/ton) - 54 - 68 - 77
CO2Avoided B v SCPC ($/ton) - 82 - 91 - 108
1Total Plant Capital Cost (Includes contingencies and engineering fees but not owners costs)280% Capacity Factor, 17.73% Capital Charge Factor, Coal cost $1.64/106Btu
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Plant Cost Comparison
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2,447
3,334
2,351
3,466
2,716
3,904
1,996
3,610
2,024
3,570
718
1,497
2,789
3,801
2,680
3,952
3,097
4,451
2,264
4,115
2,296
4,070
771
1,614
0
1,000
2,000
3,000
4,000
5,000
6,000
TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC TOC TASC
GEE GEE w/ CO2
Capture
CoP CoP w/ CO2
Capture
Shell Shell w/ CO2
Capture
Subcritical PC Subcritical PC w/
CO2 Capture
Supercritical PC Supercritical PC
w/ CO2 Capture
NGCC NGCC w/ CO2
Capture
TOCo
rTASC,$
/kW
TASC
Owner's Cost
Process Contingency
Project Contingency
Home Office Expense
Bare Erected Cost
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Cost of Electricity Comparison
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Coal cost $1.64/106Btu, Gas cost $6.55/106Btu
43.4
59.1
41.7
61.5
48.2
69.2
31.2
60.2
31.7
59.6
10.122.3
11.3
14.8
11.1
15.5
12.1
16.7
7.8
13.1
8.0
13.0
3.0
5.7
7.3
9.3
7.2
9.8
7.8
9.9
5.1
9.2
5.0
8.7
1.3
2.6
14.3
17.1
14.0
18.0
13.3
17.9
15.2
21.3
14.2
19.6
44.5
52.2
5.35.6
5.7
5.95.7
3.276.3
105.7
74.0
110.4
81.3
119.5
59.4
109.7
58.9
106.6
58.9
85.9
0
20
40
60
80
100
120
140
160
GEE GEE w/CO2
Capture
CoP CoP w/ CO2
Capture
Shell Shell w/
CO2
Capture
Subcritical
PC
Subcritical
PC w/ CO2
Capture
Supercritical
PC
Supercritical
PC w/ CO2
Capture
NGCC NGCC w/
CO2
Capture
FYCOE,mills/kWh
CO2 TS&M Costs
Fuel Costs
Variable Costs
Fixed Costs
Capital Costs
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CO2Avoided Costs
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43
54
61
68 69
84
66
73
86
75
69
36
0
10
20
30
40
50
60
70
80
90
100
GEE CoP Shell Subcritical PC Supercritical PC NGCC
FirstYearCO2AvoidedCost,$
/tonne
Avoided Cost (Analogous Technology w/o Capture Reference)
Avoided Cost (SC PC w/o Capture Reference)
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Systems Analysis
Bituminous IGCC Pathway Study
85
IGCC Advanced Technology Assessments
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Technology Advancements
Coal Feed System Slurry Feed Coal Feed Pump
Oxygen Production Cryogenic Air Separation Ion Transport Membrane
Gas Cleanup Selexol Warm Gas Cleanup
Turbine Adv F Turbine Adv H2Turbine Next Gen Adv Turbine
CO2Separation Selexol H2Membrane
Capacity Factor 80% 85% 90%
SteamBottoming
Cycle
OxygenProduction
HydrogenTurbine
Flue GasTo Stack
HotFlueGas
H2Fuel
N2
O2
Air Air
Gasifierand Syngas
Cooling
GasCleanupand Shift
CO2Separation
CO2Compression
CoalFeed
RawSyngas
CO2Transport,
Storage andMonitoring
CO2
86
Advanced IGCC Systems
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CO2transport,storage andmonitoring cost
Driving Down the Cost
25
30
35
40
45
50
CurrentState-of-the-Art
CoalPump
85%Availability
Warm
GasCleanup
HydrogenMembrane
Adv
.H2Turbine
IonTranspor
tMembrane
ConventionalFinancing
Efficiency (% HHV)
Supercritical PC
without capture
IGCC with Carbon Capture
IGCC without Capture
1800
2000
2200
2400
2600
2800
3000
3200
3400
3600
3800
CurrentState-of-the-Art
CoalPump
85%Availability
Warm
GasCleanup
HydrogenMembrane
Adv.H2Turbine
IonTranspor
tMembrane
ConventionalFinancing
Total Overnight Capital ($/kW)
Supercritical PC
without capture
IGCC with Carbon Capture
IGCC without
Capture
40
50
60
70
80
90
100
110
120
CurrentState-of-the-Art
CoalPump
85%Availability
Warm
GasCleanup
HydrogenMembrane
Adv
.H2Turbine
IonTranspor
tMembrane
ConventionalFinancing
First-Year COE ($/MWh)
Supercritical PC
without capture
IGCC with Carbon Capture
IGCC without
Capture
PRELIMINARY RESULTS SUBJECT TO CHANGE
87
Advanced IGCC Systems
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CO2emissions value toincentivize CCS drops from
$65 to $10 per tonne with
successful R&D Measured by cost of CO2
avoided with CO2TS&M
CO2power plant gate sales
price for CO2-EOR to
incentivize CCUS drops
from $50 to $5 per tonne
with successful R&D Measured by cost of CO2
removed excluding CO2TS&M
CO2transport,storage andmonitoring cost
Driving Down the Cost
0
10
20
30
40
50
60
70
Curr
entState-of-the-Art
CoalPump
85%Availability
WarmGasCleanup
H
ydrogenMembrane
Adv.H2Turbine
IonTransportMembrane
ConventionalFinancing
Cost of CO2 Avoided ($/tonne)
Relative to:
Supercritical PC
without capture
IGCC with Carbon Capture
0
10
20
30
40
50
60
Curr
entState-of-the-Art
CoalPump
85%Availability
WarmGasCleanup
H
ydrogenMembrane
Adv.H2Turbine
IonTr
ansportMembrane
Con
ventionalFinancing
Cost of CO2 Removed ($/tonne)
Relative to
Supercritical PC
without capture
IGCC with Carbon Capture
PRELIMINARY RESULTS SUBJECT TO CHANGE
TS&M: Transportation, storage, and monitoring 88
Lowest Cost Power Generation OptionsMIDWEST (sea level): Todays NGCC versus Todays Coal (Bituminous)
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( ) y y ( )
Assumes capacity factor = availability (i.e. all plants including NGCC are base load).Assumes bituminous coal at delivered price of $1.64/MMBtu
0
2
4
6
8
10
12
14
0 10 20 30 40 50 60 70 80 90 100 110
NaturalGasPr
ice,
$/MMBtu
CO2 Emissions Price, $/tonne
COE
par
itybetween
SCPCwithoutCCS
andIGCC
withCCS
NGCC
with CCS
has lowest COE
IGCC
with CCS
has lowest COE
NGCC
without CCS
has lowest COE
Supercritical PCwithout CCS
has lowest COE
USC PC was not included in this comparativeanalysis of bituminous coal options.
89
Lowest Cost Power Generation OptionsMIDWEST (sea level): Todays NGCC versus 2ndGeneration Coal (Bituminous)
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COE parity betweenNGCC with CCSand 2ndGen IGCC with CCS
NGCC
with CCS
has lowest COE
Assumes capacity factor = availability (i.e. all plants including NGCC are base load).Assumes coal price of $1.64/MMBtu
0
2
4
6
8
10
12
14
0 10 20 30 40 50 60 70 80 90 100 110
NaturalGasPrice,
$/MMBtu
CO2 Emissions Price, $/tonne
2ndGen PC
without
CCS
has lowestCOE
2nd
Gen IGCCwith CCS
has lowest COE
Todays NGCC
without CCS
has lowest COE
Given a first-year
CO2emission pricebetween $0 and $60/tonne,
and using 2nd-Gentechnology:
CCS becomes economically viable
Coal with CCS is preferred at first-year CO2
prices of $15/tonne or higher
Coal is preferred over natural gas at gas
prices above $7/MMBtu (instead
of $11/MMBtu)
2nd-Gen technology for natural gas could
increase CCS market space
PRELIMINARY RESULTS SUBJECT TO CHANGE
90
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Systems AnalysisLow Rank Coal Baseline Study:
IGCC Cases
Full presentation available at:
http://www.netl.doe.gov/energy-analyses/baseline_studies.html
91
IGCC Cases:
T h i l
Fuel Gas
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Technical
Design
BasisSouthern Company
TRIG
ConocoPhillips E-
Gas
Shell
SCGP
Siemens
(GSP/Noell)
Gasifier Transport Slurry; entrained Dry-fed entrained
Coal Type PRB PRB & ND Lignite
Location/Elevation Montana/3400 ftPRB: Montana/3400 ft
Lignite: ND/1900 ft
Coal DryingIndirectly heated
fluidized bedNA WTA process
Oxidant Oxygen
AGR for CO2 capture plants 2-Stage Selexol
Gas Turbine Advanced F-class (Nitrogen dilution and air integration maximized)
Steam Cycle (psig/F/F) 1800/1050/1050 (non-CO2capture cases) 1800/1000/1000 (CO2capture cases)
Carbon Capture 83% 90%
Availability 80%
Slag
Dry Coal
O2
HPSteam
92
IGCC Efficiency: Bituminous Coal Comparison
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40%
37%
42%
38%
32%30%
32%31%
42%
38%
32%30%
0%
10%
20%
30%
40%
50%
TRIG
CoP
Shell
Siemens
TRIG
CoP
Shell
Siemens
Shell
Siemens
Shell
Siemens
No Carbon Capture With Carbon Capture No CarbonCapture
With CarbonCapture
Efficiency%(HHV)
Montana Site:Powder River Basin Coal
3,400 ft Elevation
North Dakota Site:ND Lignite Coal
1,900 ft Elevation
Midwest Site:Bituminous Coal
0 ft Elevation
93
IGCC Plant Cost: Bituminous Coal Comparison
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2,728 2,771
3,056 3,185
3,691 3,851
4,253 4,318
3,094 3,239
4,378 4,430
0
1000
2000
3000
4000
5000
6000
TRIG
CoP
Shell
Siemens
TRIG
CoP
Shell
Siemens
Shell
Siemens
Shell
Siemens
No Carbon Capture With Carbon Capture No CarbonCapture
With CarbonCapture
TotalOvern
ightCost($/kW)
Montana Site:Powder River Basin Coal
3,400 ft Elevation
North Dakota Site:ND Lignite Coal
1,900 ft Elevation
Midwest Site:Bituminous Coal
0 ft Elevation
94
Conventional IGCC: COE
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75 79
83 87
105112
120 122
83 87
122 124
0
25
50
75
100
125
150
TRIG
CoP
Shell
Siemens
TRIG
CoP
Shell
Siemens
Shell
Siemens
Shell
Siemens
No Carbon Capture With Carbon Capture No CarbonCapture
With CarbonCapture
CostofEle
ctricity($/MWh)
CO2 TS&M
Fuel
Variable O&M
Fixed O&M
Capital
Montana Site:Powder River Basin Coal
3,400 ft Elevation
North Dakota Site:ND Lignite Coal
1,900 ft Elevation
95
IGCC COE: Bituminous CoalComparison
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75 79
83 87
105
112
120 122
83 87
122 124
0
25
50
75
100
125
150
TRIG
CoP
Shell
Siemens
TRIG
CoP
Shell
Siemens
Shell
Siemens
Shell
Siemens
No Carbon Capture With Carbon Capture No CarbonCapture
With CarbonCapture
CostofEle
ctricity($/MWh)
Montana Site:Powder River Basin Coal
3,400 ft Elevation
North Dakota Site:ND Lignite Coal
1,900 ft Elevation
Midwest Site:Bituminous Coal
0 ft Elevation
96
IGCC COE: Comparison to PC Plants
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75 79
83 87
105
112
120 122
83 87
122 124
0
25
50
75
100
125
150
TRIG
CoP
Shell
Siemens
TRIG
CoP
Shell
Siemens
Shell
Siemens
Shell
Siemens
No Carbon Capture With Carbon Capture No CarbonCapture
With CarbonCapture
CostofEle
ctricity($/MWh)
Montana Site:Powder River Basin Coal
3,400 ft Elevation
North Dakota Site:ND Lignite Coal
1,900 ft Elevation
Low Rank CoalPC Combustion
97
Conventional IGCC: CO2Capture Cost
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7073
82
85
74 77
48 50
60 59 60 58
0
20
40
60
80
100
TRIG
CoP
She
ll
Siemen
s
TRIG
CoP
She
ll
Siemen
s
She
ll
Siemen
s
She
ll
Siemen
s
CO2 Emissions Value toIncentivize CCS
CO2 Sales Price to IncentivizeCCUS
CO2 EmissionsValue to
Incentivize CCS
CO2 Sales Priceto Incentivize
CCUS
CO2
Value($/tonne)
Montana Site:Powder River Basin Coal
3,400 ft Elevation
North Dakota Site:ND Lignite Coal
1,900 ft Elevation
Relative to NewSupercritical PCwithout capture
CCUS = Carbon capture, utilization and storage 98
Lowest Cost Power Generation OptionsWestern (3400 ft): Todays NGCC versus Todays Coal (PRB)
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Western (3400 ft): Today s NGCC versus Today s Coal (PRB)
Assumes capacity factor = availability (i.e. all plants including NGCC are base load).
0
2
4
6
8
10
12
14
0 10 20 30 40 50 60 70 80 90 100 110
NaturalGasP
rice,
$/MMBtu
CO2 Emissions Value, $/tonne
NGCC
with CCS
has lowest COE
IGCC
with CCShas lowest COE
NGCC
without CCS
has lowest COE
Supercritical PCwithout CCS
has lowest COE
99
Key Findings & Next Steps
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Transport gasifier provides low cost IGCC power
Slurry-fed gasification still competitive for high-moisture PRB coal Western location/low rank coal gasification COE on par with
midwest/bituminous coal gasification
IGCC with carbon capture COE essentially equivalent to PC PRB
All coal systems, with and without carbon capture, face challengescompeting in todays U.S. market
No carbon policy
Current natural gas prices
Opportunities for IGCC
State-of-the-Art: Co-production, CO2utilization via enhanced oilrecovery
2ndGen: R&D and demonstration for advanced technologies
100
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Systems Analysis
Low Rank Coal IGCC
Pathway Study
101
Systems Analyses for Advanced IGCC
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Objectives:
Evaluate improved performance and cost resulting from DOE-funded
R&D
Identify enabling technologies within the portfolio
Show relative contribution of different R&D efforts
Identify/highlight gaps for low rank coal R&D pathway
Approach:
Begin with established cost and performance of conventional IGCC
CoP E-Gas selected as reference plant
Substitute conventional technologies with advanced technologies in acumulative fashion assuming successful R&D
Evaluate cost and performance in a manner consistent with baseline
studies
102
102
Advanced Technology Progression
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Technology Progression
Gas Cleanup Physical Solvent Warm Gas Cleanup (WGCU)
CO2Separation Physical Solvent H2Membrane
Gas Turbine Advanced F-Class Advanced Hydrogen Turbine
Oxygen Production Cryogenic Air Separation Ion Transport Membrane (ITM)
Availability 80% 85% 90%
Oxygen
Production
Gasifier
and Syngas
Cooling
Gas
Cleanup
and Shift
Hydrogen
Turbine
Steam
Bottoming
Cycle
Coal
FeedRaw
Syngas
O2
Air Air
Hot
Flue
Gas Flue Gas
To Stack
H2Fuel
N2
CO2
Compression
CO2CO2
Separation
CO2Transport,
Storage and
Monitoring
103
Advanced IGCC Systems PRB CoalDriving Down the Cost
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40
50
60
70
80
90
100
110
120
CurrentSta
te-of-the-Art
85
%Availability
Warm
GasCleanup
+H2
Membrane
Ad
v.H2Turbine
IonTransportMembrane
Conventio
nalFinancing
First-Year COE ($/MWh)
Supercritical PC
without capture
IGCC with Carbon Capture
IGCC without
Capture
CO2transport,storage andmonitoring cost
Driving Down the Cost
PRELIMINARY RESULTS SUBJECT TO CHANGE
2000
2200
2400
2600
2800
3000
3200
3400
3600
3800
4000
CurrentSta
te-of-the-Art
85
%Availability
Warm
GasCleanup
+H2
Membrane
Ad
v.H2Turbine
IonTransportMembrane
Conventio
nalFinancing
Total Overnight Capital ($/kW)
Supercritical PC
without capture
IGCC with Carbon Capture
IGCC without
Capture
25
30
35
40
45
CurrentSta
te-of-the-Art
85
%Availability
Warm
GasCleanup
+H2
Membrane
Ad
v.H2Turbine
IonTransportMembrane
Conventio
nalFinancing
Efficiency (% HHV)
Supercritical PC
without capture
IGCC with Carbon Capture
IGCC without
Capture
104
Advanced IGCC Systems PRB CoalDriving Down the Cost
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CO2emissions value to
incentivize CCS drops from$70/tonne to $25/tonne with
successful R&D
Measured by cost of CO2
avoided with CO2TS&M
CO2power plant gate salesprice for CO2-EOR to incentivize
CCUS drops from $50/tonne to
$25/tonne with successful R&D
Measured by cost of CO2
removed excluding CO2TS&M
Driving Down the Cost
PRELIMINARY RESULTS SUBJECT TO CHANGE
0
10
20
30
40
50
60
70
Cur
rentState-of-the-Art
85%Availability
WarmGasCleanup
+H2Membrane
Adv.H2Turbine
IonT
ransportMembrane
Co
nventionalFinancing
Cost of CO2 Avoided ($/tonne)
Relative to:Supercritical PC
without capture
IGCC with Carbon Capture
0
10
20
30
40
50
60
CurrentState-of-the-Art
85%Availability
WarmGasCleanup
+H2Membrane
Adv.H2Turbine
IonT
ransportMembrane
Co
nventionalFinancing
Cost of CO2 Removed ($/tonne)
Relative toSupercritical PC
without capture
IGCC with Carbon Capture
105
CO2transport,storage andmonitoring cost
Advanced IGCC SystemsDriving Down the Cost
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25
30
35
40
45
50
CurrentState-of-the-Art
85
%Availability
Warm
GasCleanup
+H2
Membrane
Ad
v.H2Turbine
IonTransportMembrane
Conventio
nalFinancing
Efficiency (% HHV)
Supercritical PC
without capture
IGCC with Carbon Capture
PRB Coal/Western Site
Bituminous Coal/Midwest Site
Driving Down the Cost
PRELIMINARY RESULTS SUBJECT TO CHANGE
40
50
60
70
80
90
100
110
120
CurrentState-of-the-Art
85
%Availability
Warm
GasCleanup
+H2
Membrane
Ad
v.H2Turbine
IonTransportMembrane
Conventio
nalFinancing
First-Year COE ($/MWh)
Supercritical PC
without capture
(PRB Coal)
IGCC with Carbon Capture
PRB Coal/Western SiteBituminous Coal/Midwest Site
2000
2200
2400
2600
2800
3000
3200
3400
3600
38004000
4200
CurrentState-of-the-Art
85
%Availability
Warm
GasCleanup
+H2
Membrane
Ad
v.H2Turbine
IonTransportMembrane
Conventio
nalFinancing
Total Overnight Capital ($/kW)
Supercritical PC
without capture
(PRB Coal)
IGCC with Carbon Capture
PRB Coal/Western SiteBituminous Coal/Midwest Site
106
CO2transport,storage andmonitoring cost
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CO2emissions value to
incentivize CCS drops from
$70/tonne to $10-25/tonne
with successful R&D
Measured by cost of CO2
avoided with CO2TS&M
CO2power plant gate sales
price for CO2-EOR to incentivizeCCUS drops from $50/tonne to
$10-25/tonne with successful
R&D
Measured by cost of CO2
removed excluding CO2 TS&M
CO2transport,storage andmonitoring cost
Driving Down the Cost
PRELIMINARY RESULTS SUBJECT TO CHANGE
0
10
20
30
40
50
60
70
Cur
rentState-of-the-Art
85%Availability
WarmGasCleanup
+H2Membrane
Adv.H2Turbine
IonT
ransportMembrane
Co
nventionalFinancing
Cost of CO2 Avoided ($/tonne)
Relative to:Supercritical PC
without capture
IGCC with Carbon Capture
PRB Coal/Western SiteBituminous Coal/Midwest Site
0
10
20
30
40
50
60
Cur
rentState-of-the-Art
85%Availability
WarmGasCleanup
+H2Membrane
Adv.H2Turbine
IonT
ransportMembrane
Co
nventionalFinancing
Cost of CO2 Removed ($/tonne)
Relative toSupercritical PC
without capture
IGCC with Carbon Capture
PRB Coal/Western SiteBituminous Coal/Midwest Site
107
Lowest Cost Power Generation OptionsWestern (3400 ft): Todays NGCC versus Todays Coal (PRB)
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Western (3400 ft): Today s NGCC versus Today s Coal (PRB)
Assumes capacity factor = availability (i.e. all plants including NGCC are base load)
0
2
4
6
8
10
12
14
0 10 20 30 40 50 60 70 80 90 100 110
NaturalGasPrice,
$/MMBtu
CO2 Emissions Value, $/tonne
NGCC
with capture
has lowest COE
IGCC
with capturehas lowest COE
NGCC
without capture
has lowest COE
Supercritical PC
without capture
has lowest COE
108
Lowest Cost Power Generation OptionsWestern (3400 ft): Todays NGCC versus 2ndGen IGCC (PRB)
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Western (3400 ft): Today s NGCC versus 2 Gen IGCC (PRB)
Assumes capacity factor = availability (i.e. all plants including NGCC are base load).
0
2
4
6
8
10
12
14
0 10 20 30 40 50 60 70 80 90 100 110
NaturalGasPrice,
$/MMBtu
CO2Emissions Price, $/tonne
Todays NGCC
with capture
has lowest COE
2ndGen
IGCC
with carbon capture
has lowest COE
Todays NGCC
without capture
has lowest COE
TodaysPC
without
capture
has
lowest
COE
109
Findings of Study and Gaps
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Current DOE portfolio provides 5 points efficiency gain,
30% reduction in COE relative to todays IGCC with CCSHigh pressure gasification may be needed to enable
advanced technologies in current R&D portfolio
Managing WGCU pressure drop, hydrogen membrane
driving force, meeting fuel gas pressure needs for
advanced hydrogen turbine
Evaluation of alternatives to slurry-fed gasification for
2ndGen IGCC recommended
110
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Conventional IGCC Compared
to PC and NGCC
111
Fundamental Comparison of
IGCC with Advanced PC Fired Plant
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IGCC PCOperating Principles Partial Oxidation Full Oxidation
Fuel Oxidant Oxygen Air
Temperature 3000 F 3200 F
Pressure 415-1000 psia Atmospheric
Sulfur Control Concentrate Gas Dilute Gas
Nitrogen Control Not Needed Pre/Post
Combustion
Ash Control Low Vol. Slag Fly/Bottom Ash
Trace Elements Slag Capture ESP/StackWastes/By-products Several Markets Limited Markets
Efficiency (HHV) 39-42% 37-40%
IGCC with Advanced PC-Fired Plant
112
Comparison of Air Emission Controls:
PC vs IGCC
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Sulfur NOx PM Mercury
PCPost
Combustion
FGDsystem
Low-NOxburners
and
SCR
ESP
or
baghouse
Inject
activated
carbon
IGCCPre
Combustion
Chemicaland/or
physicalsolvents
Syngas saturation
and
N2diluent
for
GT and SCR
Wet scrubber,
high temperaturecyclone,
barrier filter
Pre-sulfidedactivated
carbon bed
PC vs. IGCC
Steve Jenkins 2009 GTC Workshop http://www.gasification.org/uploads/downloads/Workshops/2009/Kingsport/02Jenkins.pdf
113
Effect of Coal Quality on PC and IGCC Plant
Heat Rates and Capital Costs
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Heat Rates and Capital Costs
Source: EPRI (Booras and Holt), Pulverized Coal and IGCC Plant Cost and Performance Estimates, GTC Conference, October 2004 114
Conventional Coal Plant(Illustration only)
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(Illustration only)
Source: EPRI
River or Reservoir
BoilerCondenser
Generator
TurbineSteam Line 40 MW
electricitygenerated
15 MWlost to stack
45 MWlost to cooling water
Net Coal to Power
40 MW / 100 MW =
40% Efficiency
100 MWfuel input coal
115
Natural Gas Combined Cycle(Illustration only)
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Net Natural Gas to Power(19 +38) MW / 100 MW =
57% Efficiency22 MWlost to stack
Heat RecoverySteam Generator
21 MWlost to condenser
Gas Turbine & Generator
19 MWelectricitygenerated
SteamSteam
38 MWelectricitygenerated
(Illustration only)
100 MWfuel input
natural gas
Steam Turbine & Generator
116
Coal-Based IGCC Power Plant
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Steam Turbine & Generator
Gasification Island Converts coal to synthesis gas Cleans & conditions synthesis gas
Heat RecoverySteam Generator
Gas Turbine & Generator
SteamSteam
Natural gas is replacedby coal-based fuel gas
Synthesis gas
117
Coal-Based IGCC Power PlantNet Coal to Power
-
5/27/2018 DOE Gasification Program Overview
118/147
Steam Turb ine & GeneratorHeat Recovery
Steam Generator Gas Turbine & Generator
Steam
Steam
SlagBy-product
Net Coal to Power(30+21-10) MW / 100 MW =
41% Efficiency
Steam
18 MWlost to
stack
10 MWelectricityto ASU
100 MWfuel input coa